Enhanced Oil Recovery Potential in the

United States

January 1978

NTIS order #PB-276594
Library of Congress Catalog Card Number 77-600063

For sale by the Superintendent of Documents, U.S. Government Printing Office

Washington, DC. 20402 Stock No. 052-003-00503-4
TECHNOLOGY ASSESSMENT BOARD DANIEL De SIMONE

EDwARD M. KENNEDY, MASS., CHAIRMAN Acting DIRECTOR

LARRY WINN, JR., KANS., VICE C HAIR MAN O FFICE OF T ECHNOLOGY A SSESSMENT

ERNEST F. HOLLINGS, S.C. OLIN E. TEAGUE, TEX.

HUBERT H. HUMPHREY, MINN. MORRIS K. UDALL, ARIZ. W ASHINGTON , D.C. 2051 0

CLIFFORD P. CASE, N.J. GEORGE E. BROWN, JR., CALIF.

TED STEVENS, ALASKA CLARENCE E. MILLER, OHIO

ORRIN G. HATCH. UTAH JOHN W. WYDLER, N.Y.

January 6, 1978

The Honorable Ted Stevens

Technology Assessment Board

Office of Technology Assessment

United States Senate

Washington, D. C. 20510

Dear Senator Stevens :

On behalf of the Board of the Office of Technology Assessment,

we are pleased to forward the results of the assessment you

requested of the potential of enhanced recovery of oil and

Devonian gas in the United States.

This report, Enhanced Recovery of Oil coincides with the recently

released Status Report on the Potential for Gas Production From

the Devonian Shales of the Appalachian Basin.

These assessments will provide additional perspective on future

U.S. energy supplies and we hope that they will be helpful as the

Congress continues its review of national energy policy.

Vice Chairman

Enclosure

. . .

I l l
Foreword

It is estimated that about 300 billion barrels of discovered oil remain

in the United States. However, conventional techniques of extraction can

deliver only 10 percent of that oil economically, or about 30 billion barrels. What about the remaining 270 bilIion barrels?

This report assesses the potential of enhanced recovery techniques

for freeing more of this oil from the sandstone and limestone formations

in which it is trapped. The methods for doing this include injecting steam,

chemicals, or carbon dioxide to either break the oil loose and push it up

or make it easier to flow. The question is at what price?

At current world oil prices, enhanced oil recovery methods could

yield from 11 to 29 billion additional barrels of that trapped oil. And at oil

prices comparable to those required to produce synthetic oil from coal,

enhanced recovery methods could increase the yield to as much as 42

billion extra barrels of oil. At the utmost, about 51 billion barrels might be

recoverable, assuming the most favorable economic factors and technologies that can now be foreseen.

This report discusses the uncertainties in these estimates and assesses

policy options available to Congress for recovering more of America’s oil

resources.

This assessment is another in the series of energy policy projects that

the Off ice of Technology Assessment is conducting for the Congress.

DANIEL DeSIMONE

Acting Director

Office of Technology Assessment
OTA Energy

Advisory Committee

Milton Katz, Chairman

Director, International Legal Studies, Harvard Law School

Thomas C. Ayers George E. Mueller

President and Chairman President and Chairman

of the Board of the Board

Commonwealth Edison Company System Development Corporation

Kenneth E. Boulding

Professor of Economics

Institute of Behavioral Science

 University of Colorado

Eugene G. Fubini

Fubini Consultants, Ltd.

Levi (J. M.) Leathers

Executive Vice President

Dow Chemical USA

Wassily Leontief

Department of Economics

New York University

Gerard Piel

Publisher, Scientific American

John F. Redmond, Retired

Shell Oil Company

John C. Sawhill

President

New York University

Chauncey Starr

President, Electric Power

Research Institute

vii
Enhanced Oil

and Gas Recovery

Advisory Panel

Richard Perrine, Chairman

University of California

Gerard Brannon Walter Mead

Georgetown University University of California

Frank Collins Fred H. Poettmann

Oil Chemical and Atomic Workers Marathon Oil Company

International Union Lyle St. Amant

Robert Earlougher Louisiana Wildlife and

Godsey-Earlougher, Inc. Fisheries Commission

Lloyd Elkins Hal Scott

Amoco Production Company Florida Audubon Society

Robert M. Forrest A. B. Waters

Columbia Gas System Service Corp. Halliburton Services

Claude Hocott Ex officio

University of Texas John Redmond, Retired

John M. McCollam Shell Oil Company

Gordon, Arata, McCollam

and Watters

NOTE: The Advisory Panel provided advice, critique, and material assistance throughout this assessment, for which the

OTA staff IS deeply grateful The panel, however does not not necessarily approve, disapprove or endorse this report OTA assumes

full responsibility for the report and the accuracy of its content.

,..

Vlll
OTA Energy

Program Staff

OTA Energy Program

Lionel S. Johns, Program Manager

Robert J. Rebel, Project Leader

Thomas A. Cotton, Asst. Project Leader

Major Contributors

Russell F. Darr

Don W. Green

Robert J. Kalter

Patrick H. Martin

Floyd W. Preston

Wallace E. Tyner

G. Paul Willhite

External Support

John Eldon, Martin Frey,

Joy Jones, Colleen Knehans,

Edward La Roe, Cindy Pierce,

Raj Raghaven, Roy Savoian,

James Smith, and Marcia Wolf

Analytical Contractors:

Lewin & Associates, Inc.

National Energy Law and Policy Inst.

Wright Water Engineers., Inc.

OTA

Publications

Staff

Administrative

Staff

Lisa Jacobson

Linda Parker

Cindy pierce

Joanne Seder

john C. Holmes, Publications Officer

Kathie S. Boss Joanne Heming Cynthia M. Stern

ix
Contents

Chapter Page

1. EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

lntroduction and Summary of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Method of Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Data Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Economic Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Rate of lnitiationof EOR Projects . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Cases Examined . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Oil Recovery Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Ultimate Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Rate of Oil Production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Major Uncertainties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Resource Availability and Process Performance . . . . . . . . . . . 8

Availability and Cost of Injection Materials. . . . . . . . . . . . . . . 8

Rate of lnvestment in EOR Projects . . . . . . . . . . . . . . . . . . . . . 9

Marketability of Heavy Crudes . . . . . . . . . . . . . . . . . . . . . . . . 9

Combinations of Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . 9

lmpact of Price and Tax Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Special Tax Treatment for EOR Projects . . . . . . . . . . . . . . . . . . . . . 10

Price Guarantees and Subsidies for EOR Production. . . . . . . . . . . . 11

Alternate OCS Leasing Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . II

Legal Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Environmental Effects.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Il. AN ASSESSMENT OF THE POTENTIAL OF ENHANCED OIL

RECOVERY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Ill . OIL RECOVERY POTENTIAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

The Resource Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Original Oil In Place... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Petroleum Reservoirs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Primary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Secondary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Enhanced Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Thermal Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Miscible rocesses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Chemical Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Other EOR Processes.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

xi
Contents: Chapter /// – Continued

Chapter Page

Oil Resource for Enhanced Oil Recovery processes . . . . . . . . . . . . . . . . 33

Data Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Uncertainty in the Oil Resource. . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Methodology for Calculating Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . 35

Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Calculation of Reservoir Production and Economics . . . . . . . . . . . . 35

Final EOR Process Selection for Reservoirs Passing More Than

One Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Ultimate Recovery for the Nation . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Rate of Production for the Nation . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Exclusion o Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Estimated Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Definition of Cases . . . . . . . . . . . . .......:. . . . . . . . . . . . . . . . . 38

Case I: Advancing Technology– High-Process Performance. . 38

Case ll:Advancing Technology– Low-Process Performance. . 39

Calculation Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Low-and High-Process Performance Cases . . . . . . . . . . . . . . . 39

Ultimate Oil Recovery by EOR Processes . . . . . . . . . . . . . . . . . . . . 44

Discussion of Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Projected Results for the United States . . . . . . . . . . . . . . . . . . . . . . 46

Ultimate Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Production Rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Uncertainties in Projections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Uncertainties in Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . 47

Uncertainties in Projected Production Rates . . . . . . . . . . . . . . 49

Effect of Uncertainty in the Residual Oil Saturation and

Volumetric Sweep on Projected Results . . . . . . . . . . . . . . 50

Residual Oil Saturation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Volumetric Sweep.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Maximum Oil Recovery by EOR Processes . . . . . . . . . . . . . . . . . . . 51

Comparison With Other Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

OTA-NPC Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

OTA-FEA, ERDA Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Technological Constraintson EOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Resource Availability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Process Performance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Process Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Volumetric Sweep Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Brine-Compatible Injection Fluids . . . . . . . . . . . . . . . . . . . . . . 60

Development of Additional Processes Applicable to

Carbonate Reservoirs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Operating Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Process Field Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

xi i
Contents: Chapter /// – Continued

Chapter

Iv.

v.

VI.

Reservoir Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Raw Material Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Human Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Rate of Technology Evolution. . . . . . . . . . . . . . . . . . . . . . . .

The ERDA Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IMPACTS OF PRICE AND TAX POLICIES ON OIL RECOVERY. . . . . . . .

Policy Considerations . . . . . . . . . . . . . .

Policy Options. . . . . . . . . . , . . . . . . . . .

Analytical Approach. . . . . . . . . . . . . . .

Analysis of Government Policy Options

Reservoir Sample. . . . . . . . . . . . . .

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

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

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

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

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

Analysis Assuming Information Certainty . . . . . . . . . . . . . . . . . . . .

Price Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Analysis of Other Policy Options. . . . . . . . . . . . . . . . . . .

Analysis Assuming Information Uncertainty. . . . . . . . . . . . . . . . . .

Option Designed To Alleviate Uncertainty . . . . . . . . . . . . . .

Analysis Assuming a Rising Real Price .

lmpact of Alternative OCS Leasing Systems . . . . .

Administrative Issues . . . . . . . . . .

LEGAL ASPECTS OF ENHANCED OI

Method o fApproach. . . . . . . . . . . .

Legal Issues in EOR Development. .

Policy Options. . . . . . . . . . . . . . . . .

ENVIRONMENTAL ISSUES. . . . . . .

Physiographic Regions. . . . . . . . . . .

. . . . . . . . . . .

L RECOVERY

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. . . . . . . . . . .

. . . . . . . . . . . Continental Shelf. . . . . . . . . . . . . . . . . . . . . .

Coastal Plains . . . . . . . . . . . . . . . . . . . . . . . .

Interior Basins . . . . . . . . . . . . . . . . . . . . . . .

Mountain Ranges. . . . . . . . . . . . . . . . . . . . . .

Causes of Environmental Effects. . . . . . . . . . . . . .

Potential Impacts on the Environment . . . . . . . . .

Air Quality Impacts . . . . . . . . . . . . . . . . . . . .

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

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

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

‘Air Pollution Impacts of Thermal Recovery Methods . . . . .

Air Pollution Impacts of Miscible Flooding Recovery

Methods . . . . . . . . . . . . . . . . . . . . ... , . . . . . . . . . . . . . .

Page

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,.. xll/
Contents: Chapter VI – Continued

Chapter Page

Air Pollution Impacts of Chemical Recovery Methods. . . . . . . 97

Surface Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Ground Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Land Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Geologic Hazards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Biota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Process lndependent lmpacts . . . . . . . . . . . . . . . . . . . . . . . . . 101

Process Dependent Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . 102

APPENDIXES

A. Oil Resource for Enhanced Recovery Projections . . . . . . . . . . . . . . . . . . 109

B. Supporting Materials for Oil Recovery Projections From Application

of Enhanced Oil Recovery Processes . . . . . . . . . . . . . . . . . . . . . . . . 143

C. Legal Aspects of Enhanced Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . 197

GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................235

LIST OF TABLES

Table

Number Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

Estimates of Ultimate Recoverable Oil and Daily Production Rates

From EOR: Advancing Technology Case With 10-Percent inimum

Acceptable Rate of Return . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Proved Reserves of Crude Oil in the United States,1959-76 . . . . . . . . . .......18

U.S. Domestic Production and imports of Oil,1959-76. . . . . . . . . . . . . .......18

Estimates of Enhanced Oil Recovery Potential. . . . . . . . . . . . . . . . . . . . . .....19

Historical Record f Production, Proved Reserves, Ultimate Recovery, and

Original Oil in Place, Cumulatively by Year Total United Statesa

. . . . .......26

Extent of the Reservoir Data Base Utilized in This Assessment of Enhanced

Oil Recovery Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....34

Technical Screen —Enhanced Oil Recovery Processes. . . . . . . . . . . . . . . . . . . .36

Schedule of Starting Dates Based on Rate of-Return Criterion. . . . . . . .......37

Estimated Recoveries for Advancing Technology–Low-and High-Process

Performance Cases–All Processes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....40

Estimated Recoveries for Advancing Technology–Low-and High-Process

Performance Cases–Steam Drive Process. . . . . . . . . . . . . . . . . . . . . . .......40

Estimated Recoveries for Advancing Technology–Low-and High-Process

Performance Cases–In Situ Combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4I

Estimated Recoveries for Advancing Technology–Low- and High-Process

Performance Cases— Surfactant/Polymer . . . . . . . . . . . . . . . . . . . . . . .......41

xiv
List of Tab/es – Continued

Table

Number Page

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

32.

33.

34.

35.

36.

37.

38.

39.

40.

41.

Estimated Recoveries for Advancing Technology– Low- and High- Process

Performance Cases –Carbon Dioxide Miscible . . . . . . . . . . . . . . . . . . . . .. ...42

Estimated Recoveries for Advancing Technology– Low- and High-Process

Performance Cases — Polymer-Augmented Waterflooding . . . . . . . . . .......43

Ultimate Recovery by State– High-Process Performance . . . . . . . . . . .......43

Extrapolation of Ultimate Oil Recovery From Data Base Calculations to

the Nation–World Oil Price ($13.75/bbl). . . . . . . . . . . . . . . . . . . . . . . .......44

Summary of Oil Recovery Evaluations— Data Base Reservoirs . . . . . . . . . . . ..45

Projected Distribution of Known Oil in the United States . . . . . . . . . . .......46

Uncertainty in Projections of Ultimate Recovery for Advancing

Technology Cases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .....46

Comparison of Technological Assumptions for the Surfactant/Polymer

Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......48

Comparison of Ultimate Recovery Under Two Technological Scenarios,

Both Assuming High-Process Performance— Surfactant/Polymer Process . . . . .48

High-Process Performance at World Oil Price ($13.75/bbl). . . . . . . . . . .......50

Impact of Technological Advances in Emission Control in California

Thermal Recovery Projects on Projected Rates for the United States

United States at World Oil Price ($13.75/bbl) . . . . . . . . . . . . . . . . . . . . .. .....50

Projections of Ultimate Recovery and Production Rate From the Application

of Enhanced Oil Recovery Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Field Activity in Enhanced Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62

Number and Percent of Reservoirs Sampled by EOR Process. . . . . . . . . . . . . . .72

EOR Reservoir Development Production by Process and Price Level . . .......72

Price Elasticity of Supply Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

EOR Development by Process and Policy Option. . . . . . . . . . . . . . . . . . . . . . . .75

Input Variables and Subjective Probability Distributions Used for Monte

Carlo Simulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76

Monte Carlo Simulation of Policy Option Impacts in Reducing Uncertainty .. .77

Monte Carlo Simulation of EOR Oil Price Deregulation. . . . . . . . . . . . . . . . . . .79

Monte Carlo Simulation of OCS Leasing Systems and EOR Potential. . .......81

Comparative Chart of Aspects of Unitization Statutes. . . . . . . . . . . . . .......87

Matrix Evaluation of Relative Potential for Environmental Impacts for

Enhanced Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .93

Potential Distribution of Environmental Impacts for Enhanced Oil Recovery . .94

Cross Plot of Environmental Impacts for Enhanced Oil Recovery . . . . . . . . . . .94

Emission Factors for Fuel Oil Combustion . . . . . . . . . . . . . . . . . . . . . . .......95

Steam Generator Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Projected Emissions from Steam Flooding of a Major Oil Field Compared to

Los Angeles County Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .96

Potential Biological Impacts Resulting From EOR . . . . . . . . . . . . . . . . . . . . .. 101

xv
LIST OF FIGURES

Figure

Number Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

Projected Oil Production by Conventional Methods From Known U.S.

Reservoirs, 1976-95 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......17

Closeup of Oil Between Grains of Rock . . . . . . . . . . . . . . . . . . . . . . . . .......23

Oil Accumulation in the Top of a Dome. . . . . . . . . . . . . . . . . . . . . . . . .......25

Oil Accumulation in a Dome at the Top of a Salt Dome and Also in a Region

on the Side of the Dome . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Oil Accumulation Caused by a Fault . . . . . . . . . . . . . . . . . . . . . . . . . . .......25

Oil Trapped by Overlying Impervious Cap Rock , . . . . . . . . . . . . . . . . . . . . .. .25

Oil Trapped Within Larger Body of Impervious Shale . . . . . . . . . . . . . . . . . . . . 25

Cyclic Steam Stimulation Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......28

Steam Drive Process (Steam Flood). . . . . . . . . . . . . . . . . . . . . . . . . . . . .......29

In Situ Combustion Process—Wet Combustion . . . . . . . . . . . . . . . . . . . . . . . . .30

Carbon Dioxide Miscible Flooding Process. . . . . . . . . . . . . . . . . . . . . . .......32

Surfactant Flooding Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......32

Projected Production From Known U.S. Reservoirs, 1976-95, by Conventional .

Methods and by Enhanced Oil Recovery at World Oil Price . . . . . . . . .......47

Water Use and Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......99

xvi
1. Executive Summary
1. Executive Summary

Introduction and Summary of Findings

Since 1970, the Nation’s known oil reserves

have declined by an average 3.8 percent a year as

discoveries of new oil continued to lag behind

domestic production. During that same period,

domestic production has declined steadily from

its 1970 peak of 9,6 million barrels a day (MMBD)

to 8.0 MMBD in early 1977. These declines,

coupled with the disruptive 1973-74 Organization of Petroleum Exporting Countries (OPEC) oil

embargo and a four-fold increase in world oil

prices, have not yet depressed demand for oil in

the United States. Except for a temporary drop in

consumption in 1975, the United States has continued to increase its demand each year and imports have climbed steadily to make up the

difference between domestic supplies and

domestic demand.

Unless steps are taken to reduce demand, increase domestic production, or achieve some

combination of both, the United States will be

obliged to continue to increase its imports, which

averaged 8.8 million barrels a day during the first

8 months of 1977. The United States would remain vulnerable to future embargoes or arbitrary

price increases. increased U.S. oil imports could

contribute to imbalances between supply and

demand on a world scale in the early 1980’s that

would mean even sharper increases in world

prices.

There are only two ways to increase domestic

production:

●

●

accelerate exploration for new oil supplies,

particularly along the Outer Continental

Shelf; and

develop more efficient methods for recovering oil” which remains in the ground in

known reservoirs after the first and second

phases of conventional oil production.

This report concentrates on the second approach and assesses the potential for increasing

domestic production from such known reservoirs

with five technologies and methods, known collectively as enhanced oil recovery (EOR) techniques.

The target for these EOR techniques is some

298 billion barrels of oil that will remain trapped

in known sandstone and limestone reservoirs in

the United States after producers have pumped

all of the oil that can be taken with primary and

secondary production methods. The EOR processes use heat or chemical fluids which are injected into reservoirs to sweep additional

amounts of oil from the sandstone and limestone

pore spaces and force it to the surface.

Recent studies of the potential production

possible with EOR techniques have arrived at

estimates that range all the way from 7 billion to

76 billion barrels of oil at prices ranging from $10

to $15 per barrel, Estimates of the rate of production as of 1985 range from 0.9 MMBD to 2.3

MMBD.

The major findings of the Office of Technology

Assessment study are:

At current world oil prices ($1 3.75 per barrel

in 1976 dollars1

), EOR techniques could add

between 11 billion and 29 billion barrels of

oil to existing domestic reserves. Annual

production rates could range from o s

MMBD to 1.0 MMBD in 1985 and from 0.7

MMBD to 1.7 MMBD in 1990.

At the price at which synthetic oil or other

alternate sources might become available

($22 per barrel), the potential for EOR appears to be between 25 billion and 42

billion barrels, with daily production rates

1

$13.75 is the January 1977 average prl( e ($14, 32/per

barrel) of foreign oil dellvered to the (last ( (m~t, deflated to

July 1, 1976. Only the in( remental oIl resultlng from EOR

trc h n IclLI(’\ wOU Id he [II IgI blo for the prl( es used I n t h Is

asses sm(~n t, c urrcn t and future 01 I produc t Ion resu I t I ng trom

prlmarv and S(K orrdary method~ was assumed to be at prlc c

levels existing In 1976.

.3
4 0

●

●

●

●

Ch, /-Executive Summary

of between 0.9 MMBD and 1.3 MMBD in

1985 and 1.8 MMBD to 2.8 MMBD in 1990.

A vigorous program of research and

development, with many field tests supported by laboratory investigations, must be

undertaken to achieve significant EOR production. Even with such a program, eventual

production would depend on the effectiveness of EOR processes and the validity of

estimates of the amounts of oil remaining in

the known reservoirs.

Estimates of the daily rates of EOR oil production are much less certain than those for

ultimate oil production, partly because the

rate of development of EOR technology is

uncertain and partly because EOR operations will have to compete for funds with

other investment opportunities. Enhanced

oil recovery processes are relatively new

and the investment risk is high compared to

more familiar oil exploration and production

methods. If the oil industry hesitates to invest large amounts of capital in EOR processes in the next few years, the production

of oil with enhanced methods would be

delayed.

Estimates of EOR potential presume the

availability of very large quantities of injection materials, such as carbon dioxide (C02

)

and surfactant. A 50-percent increase in the

real cost of these two materials could limit

potential EOR production to 6 billion to 12

billion barrels at the world oil price, or 1 6

billion to 33 billion barrels at the alternate

fuels price.

The responsiveness of EOR potential to increases in the real price of oil drops off

above $22 per barrel. An increase in price to

$30 per barrel has the potential of increasing the production only about 17 percent,

from 42 billion barrels to 49 billion barrels

(assuming high process performance).

Removing all economic constraints might

add about 2 billion barrels more. Thus, it is

doubtful that more than about 51 billion of

the remaining 300 billion barrels of oil can

be recovered under any economic conditions using current and foreseeable

enhanced recovery technology.

Investment tax incentives (a change from 10

to 12 percent in the investment tax credit

and accelerated depreciation) appear to

have relatively little effect on investor decisions to use EOR processes, but an Internal

Revenue Service interpretation that the cost

of injection chemicals must be depreciated

rather than treated as an expense could

seriously inhibit the use of the high-potential surfactant/polymer and CO2 miscible

processes.

Neither a guarantee of $13.7s per barrel nor

a 15-percent investment subsidy would

substantially reduce the element of risk in

EOR decisions for investors.

If investors expect real oil prices to rise at an

average annual rate of 5 percent, decontrolling the price of oil produced by EOR techniques would reduce risk and increase potential production more than all other tax

and price policies examined, including a $3

per barrel subsidy.

Any effort to permit a higher price for oil

produced by EOR processes than that

allowed for other oil produced from the

same reservoir would require a fairly precise

determination of the fraction of total oil

production that resulted from EOR operations. Highly technical judgments would be

involved, and there is some doubt that

qualified personnel would be available at

the Federal or State levels to undertake this

task.

In general, the environmental impacts of

EOR techniques are not expected to be significantly different from those of primary

and secondary production operations. There

are two main exceptions. First, combustion

of oil in thermal processes produces atmospheric pollutants. Until technology is

implemented to control these emissions, air

quality standards are expected to limit expansion of thermal processes already being

used in California. Second, some EOR processes may require large volumes of fresh

water, which could strain the capacity of

local water supplies. Application of EOR

technology which allows the use of saline

water could reduce this problem.
● In order to undertake fieldwide oil recovery

operations (waterflood or EOR), it is

generally necessary to secure the consent of .

all parties with an interest in the field

through a unitization agreement. Owners of

relatively small interests can effectively prevent the initiation of an enhanced project

by refusing to accept the risks and expenses

associated with a joint EOR venture. The

magnitude of this problem was not determined, but it could be reduced through

Ch. 1—Executivc Summary . 5

compulsory unitization statutes if it proved

to be a serious block to EOR operations.

Proposed regulations being promulgated by

the Environmental Protection Agency (EPA)

pursuant to the Safe Drinking Water Act

could adversely affect EOR development.

These proposed regulations cover injection

of materials into the ground. Many producers believe the proposed regulations will

significantly restrict or hinder enhanced

recovery of oil,

Method of Analysis

Data Base

This assessment of EOR potential is based on a

reservoir-by-reservoir analysis of the anticipated

performance of EOR processes. The data base for

the analysis comprises 385 fields (835 reservoirs)

in 19 States, and includes the 245 onshore reservoirs used in recent studies of EOR potential

published by the Federal Energy Administration

(FEA) and the National Petroleum Council (NPC).

The 385 fields used in the OTA assessment include 24 offshore fields (372 reservoirs) and contain 52 percent of the known remaining oil in

place (ROIP) in the United States. Results obtained from the data base were extrapolated on a

State-by-State basis to obtain national totals.

Alaskan reservoirs were not analyzed because

there was not enough cost data on EOR operations in a hostile environment.

Technical Screen

Five EOR processes were examined for technical applicability to each reservoir in the data

base:

in situ combustion,

steam injection,

C O2 miscible flooding,

surfactant/polymer flooding, and

polymer-augmented waterflooding.

Physical properties of each reservoir were

compared with a set of technical criteria based

on an assessment of current technology and expected technological advances. In the first stage

in the analysis, a reservoir could qualify for more

than one process. Reservoirs representing about

76 billion barrels of oil remaining in place (when

extrapolated for the Nation) were determined to

be unsuited for any known EOR process because

of physical properties of the reservoir.

Economic Screen

Reservoirs that qualified for one or more EOR

process during the technical screening were then

analyzed to determine the amount of oil that

would be produced and the rate of return that

would result at various oil prices for each applicable process. Where reservoirs qualified for more

than one EOR process, the results of this analysis

were compared for each acceptable process.

Because the purpose of the assessment was to

determine the maximum amount of oil that could

profitably be produced under various economic

conditions, the process selected for each reservoir was the one which yielded the greatest ultimate oil recovery. In cases where none of the five

processes could show a 10-percent return from a

given reservoir at the world oil price, the procedure was repeated at the alternate fuels price

of $22 per barrel. Reservoirs that did not yield 10

percent for any process at the alternate fuels

price were assigned to the process that appeared

to have the best economic chance, or were

dropped from consideration if no economic

development seemed likely.

Rate of Initiation of EOR Projects

Because worldwide oil supplies may be limited

starting in the 1980’s, the daily rates of production that are possible with EOR operations between 1985 and 2000 may be more important to

national energy policy than the ultimate potential
6 ● Ch. l-Executive Summary

production. However, the potential production

rates are more difficult to estimate than ultimate

oil production because the rates depend on the

pace of technological development and the

speed with which investors are willing to initiate

EOR projects. Initiation of EOR projects depends

on availability of capital, willingness of investors

to accept high risks of new and relatively untested technologies, and the availability of more

attractive investment opportunities. Because an

analysis of the likely rate of investments in EOR

was beyond the scope of this assessment, OTA

postulated that EOR projects would become

economically acceptable as investment risks

decreased. Under this assumption, high potential

rates of return (30 percent in 1977) would be

needed in the early years of EOR development to

compensate for the high risks of EOR projects; as

field experience reduces investment risk, lower

rates of return (1 O percent in 1989) would

become attractive.

Cases Examined

Estimates of the technical and economic performance of each EOR process were based on an

optimistic but realistic forecast of technological

advances. Such technological advances are expected to result from an ambitious research and

development program involving many field tests

supported by basic research. Incorporating a

postulated schedule of technology advancement,

each EOR process was analyzed using high and

low estimates of process performance. The

resulting high- and low-process performance estimates represent OTA’s judgment of the likely

range of uncertainty in EOR potential. No attempt was made to determine the most probable

value within this range.

Each case was evaluated at three oil prices

(using constant 1976 dollars): FEA’s upper tier

price of $11.62 per barrel, the current world oil

price of $13.75 per barrel, and an alternate fuels

price of $22 per barrel, at which petroleum from

coal might become available. The effects of higher costs for injection chemicals, of air quality

standards, and of a s wer than anticipated rate

of investment-risk reduction were determined for

the high- and low-process ‘performance cases. In

addition, the effects of a sec of price, tax, and

leasing options were determined by using a sample of reservoirs representing about 25 percent of

the data base reservoirs that qualified for an EOR

Oil Recovery

process,

Estimates of the amount of oil that can be

recovered using enhanced methods must be interpreted with caution. Enhanced methods, except for thermal processes, have not been extensively field tested. The Office of Technology

Assessment assumed that results obtained from

controlled laboratory experiments and carefully

conducted field tests were representative of

what would happen in each of the 835 reservoirs

in the OTA data base. The uncertainties inherent

in this assumption must be considered when

evaluating OTA’s estimates of EOR potential. By

means of reviews of existing field and laboratory

EOR data, specific reservoir characteristics,

petroleum engineering principles, and reservoir

mechanics, OTA has attempted to develop oil

recovery estimates that are realistic. The major

uncertainties in these estimates are identified

and, where possible, are included in the analysis.

Potential

Ultimate Oil

Proved oil reserves are

Recovery

defined as oil that can

be produced with current technology under

specified economic conditions (usually current

costs and prices). Consequently, estimates of potential additions to proved reserves resulting

from the application of EOR techniques vary with

the price of the oil. The results of OTA’s analysis

are summarized in table 1.

At the FEA upper tier price of $11,62 per barrel, the likely range for EOR production is 8

billion to 21 billion barrels, depending on process

performance. The results represent an increase in

proved and indicated reserves from primary and

secondary production of between 23 and 60 percent.

At the FEA upper tier price of $11.62 per barrel

Iikely range of EOR production is 11 billion to 29
Ch I—FxccutIve Surnmarv . 7

Table 1

Estimates of Ultimate Recoverable Oil and Daily Production Rates From EOR:

Advancing Technology Case With 10 Percent Minimum Acceptable Rate of Return

Price Ultimate recovery{

per barrel (billions of barrels)

High-pr(xess performance’ Upper tier: $11.6 2

World Oil: $13.7 5

a

’

Alternate fuels: $22.00 ”

530.0 0

More than .s30.0 0

Low-process performance Upper tier: $11.62

World 011: $13.75

Alternate fuels: $22.0 0

a

$13.75 IS the January 1977 average price ($14.32 per barrel) of

tor(’lgn 011 (1(11 Ivf’r[’d to th[’ (Las! c ( ),iit, dot Iclt(’d to Illiv 1, 1 ~=(>

‘$22.00 per barrel IS the price at which the Synfueis Interagency

Task F( )r( [ I (L.t Imattd that pt,[r~)l(~urn IIquId\ ( OUICI hec{)mt~ avallabl[> trtjm ( fkll

billion barrels, representing a 31- to 83-percent

increase in proved and indicated reserves from

primary and secondary production. increasing the

price to the alternate fuels price of $22 per barrel

yields a range of 25 billion to 42 billion barrels,

an increase of 71 to 120 percent in proved and

indicated reserves.

The high-process performance case was used

to estimate the amount of oil that could be

economically produced at a price of $30 per barrel. This increase in price might yield an additional 7 billion barrels, a 17-percent increase over

the 42 billion barrels estimated to be available at

$22 per barrel in the high-process performance

case. The 49 billion barrels that might be

recoverable at $30 per barrel represent about 96

percent of the 51 billion barrels technologically

recoverable (assuming high-process performance)

with no economic constraints. While it is possible that new technologies with greater recovery

potential could be developed if oil prices rose as

high as $30 per barrel, it is not likely that this

would occur before the end of this century; this

possibility would therefore not significantly

affect the policy implications of this assessment.

Rate of Oil Production

Current (mid-1977) oil production from known

reservoirs using conventional techniques in the

United States is about 8 MMBD. Daily oil produc21. 2

29. 4

41. 6

49. 2

51. 1

8 . 0

11. 1

25. 3

Production rates

(millions of barrels/day)

1985 1990 200 0

0 . 4 1.1 2 . 9

1 . 0 1 . 7 5 . 2

1 . 3 2 , 8 8 . 2

d

0 , 4 0 . 5 1.1

0 , 5 0 . 7 1 . 7

0 . 9 1 . 8 5.1

]ndl(,] tt>d r(~~ervt)s

“Produt I Ion rate$ were nr)t c .~lc u]dt[’d for 011 at prlc f~i of $30 per

bdrrel (x hl~tler

tion is expected to decline to about 7.5 MMBD

by 1980, including production from Alaska’s

Prudhoe Bay; by 1990 production could be as

low as 4.2 MMBD. This assessment indicates that

EOR has the potential of significantly reducing

the decline in domestic production from known

reservoirs, particularly after 1990, if investors initiate EOR projects on the schedule assumed in

this analysis. it is anticipated that EOR could add

between 0.4 MMBD and 1.3 MMBD to domestic

production by 1985. The lower figure represents

low price ($1 1.62 per barrel) and low-process

performance, while the upper figure reflects a

higher price ($22 per barrel) and high-process

performance. At the current world oil price

($1 3.75 per barrel) the range would be 0.5

MMBD to 1.0 MMBD.

The potential contribution to domestic production could increase rapidly after 1985. By

1990, the extremes of potential production are

estimated to be 0.5 MMBD and 2.8 MMBD, with

a range of 0.7 MMBD to 1.7 MMBD at the world

oil price. By the year 2000, possible production

could be as low as 1.1 MMBD or as high as 8.2

MMBD. This higher rate of potential production

exceeds the current rate of domestic oil production using conventional techniques.

Major Uncertainties

Enhanced oil recovery methods

developing and relatively unproven

represent a

technology.
8 . Ch. l-Executive Summary

For example, the two processes which represent

over half of the total EOR potential-C02 miscible flooding and surfactant/polymer flooding—

have received only limited field testing. Consequently there are many uncertainties that must

be considered when interpreting the results of

assessments of the potential of EOR. The following is a brief discussion of the major areas of uncertainty.

Resource Availability and Process

Performance

There is an uncertainty of 15 to 25 percent (or

more) jn the amount of oil remaining in reservoirs

after primary and secondary recovery, In addition, there is uncertainty about the fraction of the

remaining oil that can be recovered by an EOR

process even after the process has been successfully pilot tested. Analysis of the low- and

high-process performance cases shows that a

relatively small reduction in process performance

can lead to a much larger reduction in potential

EOR production; a 12- to 30-percent reduction in

the amount of oil recovered (depending on the

process) produces a 64-percent reduction in ultimate production at $22 per barrel, and a 163-percent reduction at $13.75 per barrel. Similar reductions result for the 15- to 25-percent uncertainty

in remaining oil. This disproportionate effect occurs because a relatively small decrease in expected production can reduce the rate of return

from many reservoirs to below the 10 percent

needed to make EOR operations an attractive inprocess performance case at $13.75 per barrel)

would require a total of about 53 trillion cubic

feet (Tcf) of C02

, a volume nearly three times the

annual consumption of natural gas in the United

States. The estimates of the production potential

of the CO2 miscible process are based on the

assumption that most of the C02 would be provided from natural deposits. Natural CO2 can be

delivered to reservoirs by pipeline at lower cost

(from about $.60 to $.90 per thousand cubic feet

(Mcf)) than manufactured CO2 delivered by truck

(on the order of $2.75 per Mcf). The Energy

Research and Development Administration

(ERDA) is currently conducting a study of the

availability of natural CO2 for use in EOR.

However, even if deposits of sufficient magnitude are found, it is possible that the CO2

would be sold at prices considerably above the

production costs assumed in this study. Higher

costs could significantly reduce the amount of oil

economically recoverable using the CO2 miscible

process. For example, a 50-percent increase in

price of CO2 could reduce the potential production from the CO2 miscible process by 49 percent, from 13.8 billion to 7.1 billion barrels

($13.75 per barrel and high-process performance).

Chemical costs are also important variables in

the surfactant process, the EOR process which

OTA estimates might provide 13 to 34 percent of

the ultimate EOR production. This process is extremely sensitive to the costs of the injection

chemicals (surfactant and polymer) used. A 5Ovestment. percent increase in price of surfactants and

Availability and Cost of Injection Materials polymers over the level assumed in this study

would practically eliminate the potential of this

The OTA estimates of EOR potential presume process- at the world oil price, reducing producthe availability of large quantities of injection tion in the high-process performance case from

materials. Limitations in availability and/or in- 10.0 billion to 0.2 billion barrels. However, this

creases in real prices above the level’s assumed in oil could eventually be produced at the alternate

this analysis could significantly reduce both the fuels price, with an ultimate recovery of an estiultimate oil recoverable by EOR methods and the mated 9 billion barrels.

rate at which EOR oil might be produced. The The final critical injection material is water. most important materials in this regard are C02

, While secondary oil production (waterflooding)

surfactant, and fresh water. already requires significant quantities of water,

The C02 miscible process, which is expected existing EOR methods require relatively fresh

to provide- between 41 and 51 percent “of the water. Availability of fresh or nearly fresh water

total potential EOR production; requires ex- could ultimately constrain EOR development,

tremely large quantities of C02

. Production of because EOR processes have a large potential in

13.8 billion barrels of oil (estimated for the high- Texas, western Louisiana, and California-areas
Ch. 1-Executive Summary ● 9

where water shortages already exist and are predicted to be more severe by the year 2000.

Achievement of the full potential of EOR will require the development of means for using water

of higher salinities in EOR processes.

Rate of Investment in EOR Projects

As noted, OTA’s estimates of the potential

daily production from EOR processes are based

on the assumption that EOR projects will be initiated according to a postulated schedule related

to expected rates of return. However, difficulties

in forecasting actual investor behavior suggest

that the estimates of daily production rates are

less certain than the estimates of ultimate oil

recovery. Enhanced oil recovery investments will

have to compete for funds with other investment

opportunities. Enhanced oil recovery processes

are relatively new, and the investment risk is high

compared to more familiar oil exploration and

production methods. The oil industry may

therefore be reluctant to invest large amounts of

capital in EOR processes in the next few years,

which would delay the production of oil by

means of enhanced recovery methods.

Marketability of Heavy Crudes

Market constraints could limit the development of thermal methods in California where the

market for the heavy crudes is limited primarily

because heavy oil requires more processing than

lighter oils, Crude oil from Prudhoe Bay may

further reduce the market for California heavy

crude for a short period. A real or perceived weak

market for heavy oils produced by thermal

methods in California will be a deterrent to thermal EOR development in that State. This delay

may well be temporary, but it could result in

lower rates of oil production from thermal EOR

methods in the 1980’s than those estimated in

this report.

Combinations of Uncertainties

The effects of uncertainties have been evaluated independently. Reductions in ultimate

recovery and/or changes in timing of production

resulting from altered assumptions in each of

these uncertain areas are presented above and in

more detail in chapter III. Changes in ultimate

recovery or timing of production have not been

evaluated for combinations of uncertainties. it is

possible that two or more uncertainties could

simultaneously reduce EOR potential. In fact, it is

remotely possible that resource availability could

be lower than expected, low-process performance prevail, supply of injection materials be

constrained or costly, and EOR investments remain relatively risky-all at the same time.

Should this occur, EOR potential would be very

low, and EOR production would never make a

significant contribution to national production.

The Office of Technology Assessment does

not believe this combination of circumstances is

likely. The lower bounds presented in this study

represent a more realistic estimate of the

minimum production which could be expected

from EOR techniques,

Impact of Price and Tax Policies

Price

The OTA analysis has assumed that the price

being tested would apply only to the increment

of production from a well that could be directly

attributed to the EOR process, while oil being

produced by primary and secondary methods

from the same well would continue to receive

the price for which it is qualified under current

price control regulations. The same assumption

was used in independent analyses of EOR potential conducted for FEA and ERDA.

Both the amounts and timing of potential EOR

production are sensitive to the price that will be

received for the oil. In both the low- and highprocess performance cases, the two possible

price increases considered ($1 1.62 per barrel to

$13.75 per barrel and $13.75 per barrel to $22

per barrel) produced more than proportional increases in potential recovery. Increases in price

had an even greater effect on the rate at which

EOR production might be brought on-line.
———— ————

70 ● Ch. 1-Executive Summary

In 1976, Congress amended the Emergency

Petroleum Allocation Act to provide additional

price incentives for bona fide “tertiary enhanced

recovery” (EOR) techniques. Since then, FEA has

published proposed regulations and has held

public hearings on price incentives for oil produced by enhanced techniques. In addition, the

President recommended decontrolling the price

of EOR oil in his National Energy Plan.

The effects of decontrol of oil produced by

EOR methods were tested using a sample of

about 25 percent of the OTA data base reservoirs

that technically qualified for an EOR process. impacts of decontrol depend primarily on investor

expectations about the future market price of oil,

It was assumed that investors expected the real

price of oil to rise at an average annual rate of 5

percent. With this assumption, more reservoirs

could be profitably developed (34 percent more

in the sample) with prices decontrolled than if

prices were held at a $13.75 constant real price,

At the same time, decontrol would significantly

decrease the risk for investors in all EOR processes except in situ combustion. Decontrol of oil

price was more effective at stimulating development than any of the other price and tax options

considered. As long as investors expect the

market price of oil to rise, decontrol will reduce

the risk of EOR investments compared to a controlled-price policy.

The OTA analysis presumes that oil produced

by EOR operations will be priced differently from

oil produced by primary and secondary methods

from the same well at the same time. The Federal

Energy Administration proposed the same approach in applying price incentives for EOR production. This policy creates the problem of

deciding what fraction of total oil production

should be attributed to EOR when primary and

secondary methods are being used at the same

reservoir. The challenge is to define this increment in such a way as to encourage the application of EOR processes without significantly distorting decisions concerning primary and secondary production.

The FEA proposal involves case-by-case judgments concerning the production that would normally be expected using primary and secondary

methods. But that proposal raises questions

about whether the technical expertise for making

such decisions would be available at the Federal

and/or State levels. An alternative approach, supported by industry in comments on FEA’s pricing

proposals, would be to apply the same price incentives to all oil produced from a field to which

an EOR process was applied. While this would

avoid the problem of defining EOR incremental

oil, it would leave the problem of defining the

level of effort required for a project to qualify as a

bona fide EOR process, and would require

monitoring to ensure that the effort is maintained.

A more detailed analysis of the advantages

and disadvantages of these and other incentive

pricing options was beyond the scope of OTA’s

assessment of the potential contribution of EOR

processes to national reserves. Because of the importance and complexity of the associated issues,

Congress may wish to examine the problem of

defining and monitoring EOR operations, and

possibly hold oversight hearings on the proposed

FEA pricing regulations for EOR production. If

defining EOR incremental oil production and

monitoring EOR operations are found to be critical issues, a mechanism could be developed

whereby bona fide EOR projects could be certified and monitored. Certification and monitoring of EOR operations could be performed by the

operator, a State regulatory group, a Federal

agency, or a combination of State, Federal, and

producer interests.

Special Tax Treatment for EOR Projects

The impacts of several tax incentives for EOR

investments were analyzed at the world oil price.

The options included an increase in the investment tax credit from 10 to 12 percent, accelerated depreciation, and an option in which injection costs were depreciated over the life of the

project rather than treated as expenses during the

year they were incurred. Neither the investment

tax credit nor accelerated depreciation had much

effect on the development of reservoirs using

EOR methods, On the other hand, a requirement

that injection costs be depreciated rather than

treated as expenses led to a large decrease (29

percent) in total production. Depreciating rather
than expensing costs of injection materials could

greatly inhibit the development of the surfactant

and CO2 miscible processes, which have the potential of providing well over half of the total

EOR production at prices at or above $13.75 per

barrel.

Price Guarantees and Subsidies

for EOR Production

Three forms of explicit and implicit subsidies

were evaluated: a price guarantee at $13.75 per

barrel; a 15-percent subsidy of EOR investment

costs (excluding costs of injection materials); and

a $3 per barrel price subsidy of EOR oil. The

effectiveness of a price guarantee depends

almost entirely on the probability that the world

market price of oil will decline below the current

level in real terms. Assuming that this probability

is quite low, a $13.75 per barrel price guarantee

would probably have little effect on the risk of

EOR investments. The 15-percent investment

subsidy also exhibited little impact on risk or on

potential production, although its effects might

be somewhat greater than the tax options that

were considered.

A $3 per barrel price subsidy would be more

effective than the tax and subsidy options

analyzed, and could result in a 6-percent increase

in ultimate EOR production and substantially

reduce the risk to investors. Because the cost of

the subsidy would be offset to some extent by

increased Government tax revenues from increased production, the actual cost of the subsidy would be somewhat less than $3 per barrel.

Alternative OCS Leasing Systems

Because a large part of future oil discoveries

are expected to be on the Outer Continental

Shelf (OCS), the effects of several OCS leasing

policies were tested on a 25-reservoir sample of

the 294 offshore reservoirs in the OTA data base

which were amenable to EOR processes. The

United States currently uses, almost exclusively, a

cash-bonus bidding system in which exploration

and development rights on an OCS tract are

granted to the group offering the highest frontend payment, or bonus bid. In addition to the

Ch. 1-Executive Summary . 11

cash bonus, a 16.7-percent royalty on gross production is collected by the Government. The preceding analysis of policy options assumed that

this method would be in use for the offshore CO2

cases.

Recent discussions of alternate leasing systems

have included proposals for greater use of contingency payments (royalties or profit shares,

which collect Government revenue based upon

the value of actual production), which are intended to reduce front-end capital requirements

and shift a greater share of risk to the Government. The impacts on EOR production potential

of two such systems were analyzed by OTA: cash

bonus plus a 40-percent royalty, and a cash

bonus plus a 50-percent net profit share. The 40-

percent royalty was shown to increase the investment risk and to make some fields uneconomic

for EOR, a result that confirms earlier studies of

the impact of high royalties on primary and secondary OCS production. While the profit-share

system did not eliminate any fields from consideration, it did tend to increase the risk of EOR

investments and could therefore tend to delay

EOR implementation. This is contrary to previous

results on primary and secondary production, and

suggests that a profit-share rate of 50 percent

would be too high for EOR development on

marginal fields.

A possible option would be the use of a variable-rate royalty or profit-share approach, in

which rates would automatically be reduced for

marginal fields. Alternatively, the contingency

payment could be waived when that became

necessary to enable further production, a provision included in proposed amendments to the

Outer Continental Shelf Lands Act (S.9 and H.R,

1614). While this option was not tested directly,

the $3 per barrel price subsidy approximates the

removal of the 16.7-percent royalty at an oil price

of $13.75 per barrel. The $3 per barrel price subsidy increased the number of offshore reservoirs

in which EOR methods might be economical,

These results may somewhat exaggerate the

possible effect of eliminating the royalty because

the $3 per barrel subsidy is about 30 percent

greater than the current 16.7-percent royalty on

$13.75 per barrel oil, and because the policy

sample of reservoirs contained a higher proportion of marginal fields which would be more

affected than the entire data base.
12 . Ch. l-Executive Summary

Legal Issues

To identify potential legal obstacles to EOR,

questionnaires were sent to oil producers and to

State and Federal regulatory authorities, and a

study was made of pertinent laws, treatises,

special reports, and periodical literature. The

most significant existing or potential legal constraints identified were Federal price controls on

crude oil, weakness or absence of compulsory

unitization statutes in several crucial States, and

existing and proposed environmental protection

regulations. These legal constraints have an impact on secondary (waterflood) methods as well

as on EOR.

The issue of price controls and alternative pricing policies has been discussed in an earlier section. The second legal constraint involves unitization, the joining of interest holders in a reservoir

for the purpose of sharing the costs and benefits

of an efficient development plan for the reservoir

as a whole. Unitization is usually desirable; it

often would be essential to make application of

secondary and enhanced recovery techniques to

a reservoir possible. Most producing States provide for compulsory joinder of interest owners in

a unit once a certain percentage of interest

holders have agreed to unitization. In the absence of such legislation, or where the necessary

percentage of voluntary participation cannot be

achieved, secondary and enhanced recovery

operations can result in substantial liability for

the operator if non joiners suffer damage.

While most States have compulsory unitization statutes, Texas does not, and the statutes in

California are so limited as to be rather ineffective. These States together represent about half

of the total national EOR potential, and the

difficulties of forming unit agreements may

therefore be a significant obstacle to large-scale

development of EOR production. A field-by-field

analysis of ownership patterns is needed to

determine whether difficulties with unitization

might prove to be a major obstacle to the

development of a significant fraction of EOR potential, Such an analysis was beyond the scope of

this study.

[If unitization problems were found to be

serious constraints on EOR production, several

actions could be considered. The Federal

Government could recommend that each State

adopt a statute that makes unitization compulsory when 60 percent of the working interest and

royalty owners consent to unitized operations.

The Federal Government could also recommend

that the States adopt statutes to exempt producers from liability for any damages caused by

State-approved enhanced recovery operations

not involving negligence on the part of the producer. This would remove a significant constraint

to unit operations in the absence of full participation by all the interest owners. Finally, the

Government could require that States have appropriate compulsory unitization statutes in order

to qualify for Federal administrative support, or

to avoid having a Federal agency become responsible for unitization and enhanced recovery

regulation.

The primary environmental regulatory constraints on EOR relate to air quality standards in

California and EPA’s proposed regulations under

the Safe Drinking Water Act to control underground injections. Current Federal and State environmental regulations under the Clean Air Act

limit total emissions in California to the pollution

levels which existed in 1976. Therefore, use of

additional steam generators and air compressors

for thermal recovery operations in California may

be significantly constrained. Using existing

generators and compressors, the maximum increase in the production rate from thermal

methods in California (the area where thermal

processes have the greatest potential) will probably be no more than 110,000 barrels per day,

about half of the estimated 1990 potential rate of

production at the world oil price. Expansion of

thermal production will require application of

emission control technology capable of meeting

air quality standards.

The Safe Drinking Water Act, passed in 1974,

directs EPA to issue regulations to control underground injection of fluids that may threaten the
quality of water in aquifers that are or may be

used for public water supply. The act specifically

provides that requirements in these regulations

must not interfere with or impede any underground injection for the secondary or tertiary

recovery of oil or natural gas unless such requirements are essential to ensure that underground

sources of drinking water will not be endangered

by such injection. However, reaction to EPA’s

proposed regulations by such groups as the interstate Oil Compact Commission, the American

Ch. 1-Executive Summary . 13

petroleum Institute, individual oil producers, and

others indicate that the regulations are perceived

as likely to have an adverse impact on enhanced

recovery operations. Because EOR processes are

expected to pose no greater threat to drinking

water than waterflooding, which has a good

safety record, Congress may wish to hold oversight hearings to determine if the proposed

regulations would unduly inhibit the application

of EOR techniques.

Environmental Effects

In general, the environmental impacts of EOR

operations are not expected to be significantly

different in type or magnitude than those from

primary and secondary oil production activities.

The major differences are air emissions from thermal processes, and increases in consumption of

fresh, or relatively fresh, water.

Thermal EOR processes produce atmospheric

pollutants from the combustion of large quantities of oil, either in steam generators (the steam

injection process) or in the reservoir itself (the in

situ combustion process). These types of emission are likely to have localized impacts and are

expected to be highly significant in areas that are

already in violation of Federal ambient air quality

standards. Air quality standards are expected to

limit expansion of thermal processes in California

unless effective emission control devices are

used or compensating reductions in emissions are

made elsewhere in the affected area.

As noted in the discussion of resource constraints, EOR processes in general required significant quantities of fresh, or relatively fresh, water,

whereas secondary waterflooding can use saline

water. This consumption of fresh water not only

will compete directly with domestic, agricultural,

and other industrial uses, but also could result in

a drawdown of surface water, which could, in

turn, severely affect aquatic flora and fauna in the

area of the drawdown. However, this impact

usually would be localized and of short duration.

The consumption of fresh water by EOR processes has the greatest potential impact in California, Texas, and western. Louisiana, where water

supplies are limited. Development of EOR technologies to allow use of saline water could

reduce this potential problem.
IL An Assessment of the Potential

of Enhanced Oil Recovery
Il. An

The United States must have reliable sources

of energy to maintain stability. in its energy-intensive economic base —a fact dramaticalIy

emphasized in October 1973, when Arab oil producers imposed a 5-month embargo on oil shipments to the United States, and again in the

record-cold winter of 1976-77, when natural gas

supplies fell short of demand. Until the oil embargo, most Americans took it for granted that

their energy needs would be met despite declining domestic production of oil and gas, which

together provide 75 percent of the Nation’s

energy. The embargo and curtailments of natural

gas supplies have made it clear that steady flows

of energy cannot be taken for granted and have

driven policy makers to a search for a national

policy which will make the United States less

reliant on foreign energy sources.

Because of congressional concerns over declining domestic supplies of oil and natural gas, and

the possibility that new technologies can increase the Nation’s oil and gas reserves, the

Office of Technology Assessment (OTA) was

asked to assess the potential of the technology

associated with enhanced oil recovery (EOR).

This report is in response to that request.

Proved reserves of crude oil (recoverable with

current technology under current economics) in

the United States increased from 20 billion barrels in 1946 to 30 billion barrels in 1959. Additions to reserves about equalled withdrawals

from domestic reservoirs between 1959 and

1970. The discovery of oil in Alaska increased the

proved U.S. oil reserve to 39 billion barrels in

1970. However, since 1970, the domestic proved

oil reserve has declined at a 2- to 5-percent annual rate (table 2), annual production from old oilfields has fallen each year, and the United States

has become increasingly dependent on imported

oil (table 3). Unless these trends can be reversed,

the gap between supplies of domestic oil and

U.S. demand will widen within the next 10 to 15

Assessment of the Potential

of Enhanced Oil Recovery

years (figure 1). There are two approaches to increasing proved reserves of oil: (1) find additional

oil through increased exploration; and (2) use

more efficient methods to recover oil from

known reservoirs. Enhanced oil recovery processes fall into the second category.

Figure 1. Projected Oil Production by

Conventional Methods From Known

U.S. Reservoirs, 1976-95

1976 1980 1985 1990 1995

NOTE: The Decline Curves for Proved and Indicated Reserves, and Inferred

Resetves Do Not Include Enhanced Oil Recoveries Recorded within

these Categories.

SOURCES: ‘ American Petroleum Institute, Reserves of Crude 0//, Natural

Gas Liquids, and Natural Gas m the U.S. and Canada as of

December 30, 1975: Lewin & Wsoclates, Inc. for Federal Energy

Administration, Dee/me Curve Arra/ysm, 1976.

z U. S. Geological Survey, C/rcu/ar 725, 1975.

3 Federal Energy Administration, Nat/ona/ Energy Out/ook, 1976.

Traditional methods of oil production (natural

flow and flushing the oil reservoir with water)

recover on average only about one-third of the

oil present in a producing formation. Methods

17

96-594 0 - 78 - 3
18 . Ch. 1—An Assessment of the Potential of Enhanced Oil Recovery

Table 2

Proved Reserves of Crude Oil in the United States, 1959-76

(Billions of Barrels of 42 U.S. Gallcms)

Year

1959 ..., , . . . . . . . . . . . . . . . . . . . . . .

1960 . . . . . . . . . . , . . . . . . . . . . . . . . . .

1961 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1962 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1963 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1964 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1965 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1966 . . . . . . . . . . . . . . . . . . . . . . ..,,,

1967 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1968 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1969 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1970 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1971 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1972 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1973 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1974 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1975 . . . . . . . . . . . . . . . . . . . . . . . . . . .

1976 . . . . . . . . . . . . . . . . . . . . . . . . . . .

Proved reserves

at beginning

of year

30.5

31.7

31.6

31.8

31.4

31.0

31.0

31.4

31.5

31.4

30.7

29.6

39.0

38.1

36.3

35.3

34.3

32.7

Proved reserves

at

end of year

31.7

31.6

31.8

31.4

31.0

31.0

31.4

31.5

31.4

30.7

29.6

39,0

38.1

36.3

35.3

34.3

32.7

30,9

Net change

from

previous year

+1.2

-0.1

+0.2

-0.4

-0.4

+0. 0

+0. 4

+0.1

-0.1

-0.7

–1,1

+9,4

-0.9

–1.7

–1.0

–1.1

–1.6

–1.7

Note: 1970 figures reflect the addition of Prudhoe Bay Alaska reserves.

Source: Reserves of Crude Oil Na(ura/Cas Liqu/ds, and Na(ural Gas in fkUn/ted S(ates and Canada asof

Decembcr 31, 7975, Joint pubhcation by the American Gas Assoctatlon, American Petroleum Institute, and

Canadian Petroleum Association, Vol 30, May 1976,

Table3

U.S. Domestic Production and lmports of Oil, 1959-76

(Barrels of 42 U.S. Gallons)

Year

1959 . . . . . . . . . . . . . . . . . . . . . .

1960 . . . . . . . . . . . . . . . . . . . . . .

1961 . . . . . . . . . . . . . . . . . . . . . .

1962 . . . . . . . . . . . . . . . . . . . . . .

1963 . . . . . . . . . . . . . . . . . . . . . .

1964 . . . . . . . . . . . . . . . . . . . . . .

1965 . . . . . . . . . . . . . . . . . . . . . .

1966 . . . . . . . . . . . . . . . . . . . . . .

1967 . . . . . . . . . . . . . . . . . . . . . .

1968 . . . . . . . . . . . . . . . . . . . . . .

1969 . . . . . . . . . . . . . . . . . . . . . .

1970 . . . . . . . . . . . . . . . . . . . . . .

1971 . . . . . . . . . . . . . . . . . . . . . .

1972 . . . . . . . . . . . . . . . . . . . . . .

1973 . . . . . . . . . . . . . . . . . . . . . .

1974 ..............,.. . . . . .

1975 . . . . . . . . . . . . . . . . . . . . . .

1976 . . . . . . . . . . . . . . . . . . . . . .

Production

Annual

(billions of

barrels)

2.6

2.6

2.6

2.7

2.8

2.8

2.8

3.0

3.2

3.3

3.4

3.5

3.5

3.5

3.4

3.2

3.1

3.0

Daily

(millions of

barrels)

7.1

7.5

7.2

7.3

7.5

7.6

7.8

8.3

8,8

9.1

9.2

9.6

9,5

9.5

9.2

8.8

8.4

8.1

Im

Annual

(billions of

barrels)

0.7

0.7

0$7

0.8

0.8

0.8

0.9

0.9

0.9

1,0

1.2

1.2

1.4

1.7

2.3

2.2

2.2

2.7

rts

Daily

(millions of

barrels)

1.8

1.8

1.9

2.1

2.1

2.3

2.5

2.6

2.5

2.8

3.2

3.4

3.9

4.7

6.2

6.1

6.0

7.3

Source: U.S. Bureau of Mines.
Ch //—An Assessment of the Potential of Enhanced Oil Recovery . 79

which increase the amount of oil that can be

recovered from a reservoir increase the proved

reserves of that reservoir. Recent studies using

differing assumptions indicate that our oil

reserves could be increased by as much as 76

billion barrels (table 4) by application of EOR

methods. Large disparities not only of total future

production but of daily production rates from

EOR projects exist in these estimates.

This report assesses the magnitude of the increased oil reserves which may result from use of

EOR in an effort to reduce the uncertainties

posed by earlier studies, and determines reasonable limits of ultimate recovery and production

rates under different sets of assumptions about

technology, price, and investment climate. An

assessment also has been made of the impact on

EOR activity of various policies that could be implemented by Congress to increase total recovery

and/or accelerate oil production.

Table 4

Estimates of Enhanced Oil Recovery Potential

Source

NPC Studya

- - - --$ 5

---- - $10

---- - $15 (1 976 dollars)

---- - $20

---- - $25

GUR C

b (

---- $10

---$1 5

(1 974 dollars)

FEA/PIR d

---- -

---- -

EPA”

---- -

---- -

business as usual, $11

accelerated development, $11

$ 8-12

$12-16

(1975 dollars)

FEA/Energy Outlook’

---- - $12

FEA (3 States)g

---u - upper bound, $11.28 (1975 dollars)

---- - lower bound, $11,28

Potential EOR recover)

(billions of barrels)

2.2

7.2

13.2

20.5

24.0

18-36

51-76

—

—

7

16

—

30.5

h

15.6’

Production in 1985

(millions of barrels/day)

0.3

0.4

0.9

1.5

1.7

1.1 —

1.8

2.3

—

—

0.9

2

1

a

Total U. S.; base case performance and costs; minimum DCFROR requirement of 10 percent; moderate

tax case.

bplann,ng Cr,ter,a Re/at;ve 10 a Afa(lona/ RDT & D Program to the Enhanced Recovery of crude Ofl and

Na(ura/ Gas, Gulf Universities Research Consortium Report Number 130, November 1973.

( Prellrn/nary F/e/d Test Recommendations and Prospective Crude 01/ F/eIds or Reservoirs for High Prfor/t y

Tesf/ng, Gulf Universttles Research Consortium Report Number 148, Feb. 28, 1976.

dpro,ect /dependence Repor(, Federal Energy Administration, November 1974

e The Estimated Recovery Potent/a/ of Convention/ Source Domestic Crude 011, Mathematical, Inc., for

the US. Environmental ProtectIon Agency, May 1975.

f I g76 Nat;ona/ Energy Out/ook, Federal Energy Administration.

11 The potentla/ and Economics 0/ Enhanced 01/ Recovery, Avirl & Associates, Inc. for the Federal Energy

Admlnlstration, April 1976.

hReserves added by t he year 2000 if projects return DCFROR of 8 percent or greater.

1 Reserves added by the year 2000 If projects return DCFROR of 20 percent or greater.

Reprinted by permission of the National Petroleum Council Copyright @ National Petroleum Council,

1976
Ill. Oil Recovery Potential
Ill. Oil Recovery Potential

The Resource Base

Original Oil In Place

The American Petroleum Institute reports that

as of December 31, 1975, about 442 billion barrels of oil had been discovered in the United

States, including the North Slope of Alaska. 1 O f

that amount, 109 billion barrels had been produced and an additional 37.7 billion barrels remained to be produced at current economic conditions and with existing technology. This figure

includes 32.7 billion barrels of proved reserves

and 5.0 billion barrels of indicated reserves. The

total, 37.7 billion barrels, also includes 1.0 billion

barrels of proved EOR reserves and 1.7 billion

barrels of indicated EOR reserves.2 The remaining

295 billion barrels represents the resource base

for enhanced oil recovery (EOR). (The resource

base includes 11 billion barrels in the North Slope

of Alaska but does not include tar sands and oil

shale. Technologies to obtain petroleum from

these sources are sufficiently different from EOR

processes to deserve separate study.)

Petroleum Reservoirs

Oil is found in porous sedimentary rocks

(sandstones and limestones) that were deposited

under water and later overlain by formations that

are impervious to these fluids. Localized accumulations of oil occur in traps (reservoirs) within these underground formations, or oil pools. An

oil field is the surface region underlain by one or

more of these separate oil reservoirs or pools.

I Reserves of Crude Oil, Natural Gas liquids, and Natural

Gas in the United States and Canada as of December 37,

7975. Joint publication by the American Gas Association,

American Petroleum Institute, and Canadian Petroleum

Association, Vol. 30, May 1976.

2Enhanced 0// f/ecov~ry, National petroleum Councllt

December 1976

Oil is found in such traps at depths of from less

than 100 feet to more than 17,000 feet.3 A reservoir may be small enough that a single well is

sufficient to deplete it economically, or large

enough to cover many square miles and require

several thousand wells.

Oil is not found in underground lakes, but in

open spaces between grains of rock; oil is held in

these spaces much as water is held in a sponge,

Almost invariably, water is mixed with oil in this

open space between the grains; natural gas is

found in the same kinds of formations. The distribution of fluids in one type of oil reservoir is

displayed in figure 2.

Because oil is lighter than water, it tends to

concentrate in the upper portions of a formation,

Figure 2. Close-up of Oil Between Grains of Rock

A thin film of water called connate water clings to the surface of the rock grains. This water occupies part of the

space in the rock along with the oil.

Reprinted by permission of the Society of Petroleum Engineers of Al ME

J~~production Depth Records Set in Three Areas, World

oil, p. 103, February 1975.

2.?
24 . Ch. Ill—Oil Recovery Potential

rising until it reaches an impervious barrier that

forms a trap. Common traps include domes

(figure 3), faults (figure 4), and salt domes (figure

5). An overlying cap rock can also seal off a formation in the manner shown in figure 6. Oil occasionally lies within sand bodies enclosed within a

larger body of impervious shale (figure 7).

Regardless of rock type (sandstone, limestone)

or trapping mechanism, there is little uniformity

in the pattern in which different reservoirs contain and conduct fluids. This lack of uniformity

influences both the amount of oil present in

various regions of a reservoir and the degree to

which injected fluids can sweep through a formation, collect oil, and force or carry it toward producing wells. It is this lack of a common pattern

that introduces significant economic risk in every

oil recovery project, including EOR.

Oil Recovery

Primary Recovery

The initial stage in producing oil from a reservoir is called primary production. During this

stage oil is forced to the surface by such natural

forces as: (a) expansion of oil, expansion of the

contained gas, or both; (b) displacement by

migration of naturally pressurized water from a

communicating zone (i.e., a natural water drive);

and (c) drainage downward from a high elevation

in a reservoir to wells penetrating lower elevations.

The natural expulsive forces present in a given

reservoir depend on rock and fluid properties,

geologic structure and geometry of the reservoir,

and to some degree on the rate of oil and gas

production. Several of the forces may be present

in a given reservoir. Recovery efficiencies in the

primary stage vary from less than 10 percent to

slightly more than 50 percent of the oil in place.

Estimates of cumulative oil production, cumulative ultimate oil recovery, and cumulative

original oil in place for 1959-75 are given in table

5.

Secondary Recovery

Most of a reservoir’s oil remains in place after

the natural energy pressurizing the reservoir has

been dissipated. Several techniques for injecting

fluids into an oil reservoir to augment the natural

forces have been widely used for many years.

Such fluid injection is generally known as secondary recovery. Fluids, most commonly natural

gas and water, are injected through one series of

wells to force oil toward another series of wells.

The pattern of injection and production wells

most appropriate to a reservoir are a matter of

technical and economic judgment.

There is nothing inherent in fluid injection

processes that requires their use only after the

natural energy in a reservoir is exhausted. Indeed,

it is frequently desirable to initiate such processes as soon as sufficient knowledge is available

of the geology of the reservoir and the type of

natural expulsive forces that are operative.

When water is the injection fluid, the process

is commonly called waterflooding. If water is

used to supplement a partially active natural

water drive, the process is classified as a pressure

maintenance project. When natural gas is injected, the operation is also called a pressure

maintenance project. Injection of natural gas was

widely used in the era of abundant low-cost gas,

but the practice has decreased as the price of gas

has increased.
Ch III—Oil Recovery Potential 25

Types of Traps for Oil Accumulation*

Figure 3.

Wate r

0il accumulation in the top of a dome. Rock overlylng the

dome is Impervious.

Figure 5.

h

impervlous / Gas

011 accumulation caused by a fault. The block to the right

has moved upward so the oil formation is opposite the impervious shale, forming a trap.

Figure 4.

+~Cap Roc k

Oil accumulation in a dome at the top of a salt dome and

also in a region on the side of the dome. Salt is Impervious

to the oil.

Figure 6.

Impervious

Cap Rock

.

Water

Figure 7.

Oil trapped by overlying impervious cap-rock that interrupts lower lying formation of sandstone or limestone.

Oil trapped within larger body of impervious shale. -

“Illustra[lons redrawn and printed with permission of the American

Petroleum Instilute I American Petroleum Institute 1971
26 . Ch ///-01/ Recovery Potential

Table 5

Historicai Record of Production, Proved Reserves, Uitimate Recovery, and Original Oil

in Place, Cumulatively by Year, Total United States.

(Billions of Barrels of 42 U.S. Gallons)

Year

1959 . . . . . . . . . . . . . . .

1960 . . . . . . . . . . . . . . .

1961 . . . . . . . . . . . . . . .

1962 . . . . . . . . . . . . . . .

1963 . . . . . . . . . . . . . . .

1964 . . . . . . . . . . . . . . .

1965 . . . . . . . . . . . . . . .

1966 . . . . . . . . . . . . . . .

1967 . . . . . . . . . . . . . . .

1968 . . . . . . . . . . . . . . .

1969 ...., . . . . . . . . . .

1970 . . . . . . . . . . . . . . .

1971 . . . . . . . . . . . . . . .

1972 . . . . . . . . . . . . . . .

1973 . . . . . . . . . . . . . . .

1974 . . . . . . . . . . . . . . .

1975 . . . . . . . . . . . . . . .

Cumulative

production

62.3

64.7

67.2

69.8

72.4

75.1

77.8

80.6

83.7

86.8

90.0

93.3

96.6

99.9

103.1

106.1

109.0

1975 estimate of

cumulative

ultimate recovery**

122.3

123.3

123.7

124.7

125.3

126.2

127,6

128.0

128.7

139.2

139.8

140.4

140.9

141.1

141.4

141.6

141.7

1975 estimate of

cumulative

original oil in place**

384.7

387.8

389.8

392.5

394.7

397.8

402.4

404.4

407.0

432.5

434.8

437.1

438.7

439.6

440.9

441.4

441.9

● “For all fields discovered prior to the indicated year in Column 1.

“Reserves of Crude OIL Natural Gas Llqu/ds, and Natural Gas in the Uniled States and Canada as of

December 37, 7975, joint publicationby the American Cas Association, American Petroleum Institute, and

Canadian Petroleum Association, Vol. 30, May 1976

Secondary recovery is proven technology; indeed, a recent study indicates that 50 percent of

all domestic crude oil comes from secondary

recovery operations.4

Waterflooding is inherently more efficient

than gas displacement in pressure-maintenance

projects and is the preferred process where feasible. Cumulative recoveries by primary and secondary production, where the secondary production is waterflooding, average between 38 and 43

percent of the original oil in place.

Some reservoirs, principally those containing

heavy oil that flows only with great difficulty, not

only provide poor primary recovery but often are

not susceptible to waterflooding. Enhanced oil

4

Enhanced Oil Recovery, National Petroleum Council,

December 1976.

recovery would be especially useful in some of

these reservoirs.

Enhanced Recovery

Processes that inject fluids other than natural

gas and water to augment a reservoir’s ability to

produce oil have been designated “improved,”

“tertiary,” and “enhanced” oil recovery processes. The term used in this assessment is

enhanced oil recovery (EOR).

According to American Petroleum Institute

estimates of original oil in place and ultimate

recovery, approximately two-thirds of the oil discovered will remain in an average reservoir after

primary and secondary production. This inefficiency of oil recovery processes has long been

known and the knowledge has stimulated

laboratory and field testing of new processes for
more than 50 years. Early experiments with unconventional fluids to improve oil recovery involved the use of steam (1920’s)5 and air for combustion to create heat (1935).6

Current EOR processes may be divided into

four categories: (a) thermal, (b) miscible, ( c)

chemical, and (d) other. Most EOR processes

represent essentially untried, high-risk technology. One thermal process has achieved

moderately widespread commercialization. The

mechanisms of miscible processes are reasonably

well understood, but it is still difficult to predict

whether they will work and be profitable in any

given reservoir. The chemical processes are the

most technically complex, but they also could

produce the highest recovery efficiencies.

The potential applicability of all EOR processes is limited not only by technological constraints, but by economic, material, and institutional constraints as well.

Thermal Processes

Viscosity, a measure of a liquid’s ability to

flow, varies widely among crude oils. Some

crudes flow like road tar, others as readily as

water. High viscosity makes oil difficult to

recover with primary or secondary production

methods.

The viscosity of most oils dramatically

decreases as temperature increases, and the purpose of all thermal oil-recovery processes is

therefore to heat the oil to make it flow or make

it easier to drive with injected fluids. An injected

fluid may be steam or hot water (steam injection), or air (combustion processes).

Steam Injection.—Steam injection is the most

advanced and most widely used EOR process. it

has been successfully used in some reservoirs in

California since the mid-1960’s. There are two

versions of the process: cyclic steam injection

sseco~~ary anfj Tertiary Oil Recovery Processes, k@-

state Oil Compact Commission, Oklahoma City, Okla., p.

127, September 1974.

blbid., p. 94.

Ch. Ill--oil Recovery Potential . 27

and steam drive. In the first, high-pressure steam

or steam and hot water is injected into a well for

a period of days or weeks. The injection is

stopped and the reservoir is allowed to “soak.”

After a few days or weeks, the well is allowed to

backflow to the surface. Pressure in the producing well is allowed to decrease and some of the

water that condensed from steam during injection or that was injected as hot water then vaporizes and drives heated oil toward the producing

well. When oil production has declined appreciably, the process is repeated. Because of its cyclic

nature, this process is occasionally referred to as

the “huff and puff” method.

The second method, steam drive or steam

flooding, involves continuous injection of steam

or steam and hot water in much the same way

that water is injected in waterflooding. A reservoir or a portion thereof is developed with interlocking patterns of injection and production

wells. During this process, a series of zones

develop as the fluids move from injection well to

producing well. Nearest the injection well is a

steam zone, ahead of this is a zone of steam condensate (water), and in front of the condensed

water is a band or region of oil being moved by

the water. The steam and hot water zone

together remove the oil and force it ahead of the

water.

Cyclic steam injection is usually attempted in

a reservoir before a full-scale steam drive is initiated, partially as a means of determining the

technical feasibility of the process for a particular

reservoir and partly to improve the efficiency of

the subsequent steam drive. A steam drive,

where applicable, will recover more oil than

cyclic steam injection and is one of the five EOR

methods used in this study of the national potential for EOR processes. Illustrations of the operation of cyclic steam injection and steam drive are

given in figures 8 and 9, respectively.

CornbustiorI Processes. -Combustion projects

are technologically complex, and difficult to predict and control. Interest in the process has

declined within the last 6 years relative to other

EOR processes. Active field tests declined from

30 in 1970 to 21 in 1976. Eight of the projects
28 . Ch 111—0o; Recovery Potential

Figure 8. Cyclic Steam Stimulation Process*

HUFF PUFF

(Production Phase)

OIL AND WATER

(Shut-in Phase)

(Days to Weeks) (Days)

LEGEND

Steam Zone

w

Hot Oil, Water and Steam Zone

(weeks to Months)

I ICold oil and Water Zone

STEAM

Figure 9. Steam Drive Process (Steam Flood)*

OIL AND WATER

LEGEND 8

Hot Water Zone

“Ilhmtraticms radrswn and printad with parmkaion of tha National

Petroisum Council. @ National Patrokum Council, 1976.

I ]Oil andWaterZcme
Cit. ///—Oil Recovery Potential ● 29

have been termed successful, nine unsuccessful

and four have not yet been evaluated.7

Injection of hot air will cause ignition of oil

within a reservoir. Although some oil is lost by

burning, the hot combustion product gases move

ahead of the combustion zone to distill oil and

push it toward producing wells. Air is injected

through one pattern of wells and oil is produced

from another interlocking pattern of wells in a

manner similar to waterflooding. This process is

referred to as fire flooding, in situ (in place) combustion, or forward combustion. Although

originally conceived to apply to very viscous

crude oils not susceptible to waterflooding, the

method is theoretically applicable to a relatively

wide range of crude oils.

An important modification of forward combustion is the wet combustion process. Much of the

heat generated in forward combustion is left

behind the burning front. This heat was used to

raise the temperature of the rock to the temperature of the combustion. Some of this heat

may be recovered by injection of alternate slugs

of water and air. The water is vaporized when it

touches the hot formation. The vapor moves

through the combustion zone heating the oil

ahead of it and assists the production of oil. With

proper regulation of the proportion of water and

air, the combustion can proceed at a higher thermal efficiency than under forward combustion

without water injection.

Combustion processes compete, at least technologically, with steam and some other EOR

processes, and the choice depends upon oil and

reservoir characteristics. The wet combustion

process is illustrated in figure 10. It is the combustion process selected for technical and

economic modeling in this study.

Miscible Processes

Miscible processes are those in which an injected fluid dissolves in the oil it contacts, forming a single oil-like liquid that can flow through

the reservoir more easily then the original crude.

A variety of such processes have been developed

using different fluids that can mix with oil, including alcohols, carbon dioxide, petroleum hy -

7Management p/an for Enhanced Oil Recovery, ERDA

77-1 5/2, Vol. 2 (of 2), D . B-7, Februarv 1977.

drocarbons such as propane or propane-butane

mixtures, and petroleum gases rich in ethane,

propane, butane, and pentane.

The fluid must be carefully selected for each

reservoir and type of crude to ensure that the oil

and injected fluid will mix. The cost of the injected fluid is quite high in all known processes,

and therefore either the process must include a

supplementary operation to recover expensive

injected fluid, or the injected material must be

used sparingly. In this process, a “slug,” which

varies from 5 to 50 percent of the reservoir

volume, is pushed through the reservoir by gas,

water (brine), or chemically treated brine to contact and displace the mixture of fluid and oil.

Miscible processes involve only moderately

complex technology compared with other EOR

processes. Although many miscible fluids have

been field tested, much remains to be determined about the proper formulation of various

chemical systems to effect complete volubility

and to maintain this volubility in the reservoir as

the solvent slug is pushed through it.

One large (50,000 acre) commercial project in

Texas uses carbon dioxide (C02

) as the miscible

agent, Eight other C02 projects covering 9,400

acres are. in early stages of development.8

Because of the high value of hydrocarbons and

chemicals derived from hydrocarbons, it is

generally felt that such materials would not make

desirable injection fluids under current or future

economic conditions. For this reason, attention

has turned to C02 as a solvent. Conditions for

complete mixing of C02 with crude oil depend

on reservoir temperature and pressure and on the

chemical nature and density of the oil.

Although there are many possible CO2

sources, the largest source should be naturally

occurring deposits. Currently known sources of

naturally occurring CO2 are described in publications of the U.S. Bureau of Mines. A summary of

C O2 source locations is presented by the National petroleum Council,9 although the actual

8Managemen[ plan for Enhanced Oil Recovery, ERDA

77-1 5/2, Vol. 2 (of 2) p. B-4, February 1977.

gEnhanced 0;/ Recovery, National petroleum COUnCil,

December 1976.

,, I
—.

30 . Ch. Ill—Oil Recovery Potential

Figure 10. In-Situ Combustion Process-Wet Combustion*

OIL AND WATER

Injected Air and Water Zone

Air and Vaporized Water Zone

Cornbustlon Zone [ ‘“J

Steam zone

Hot Water Zone

Oil and Water Zone

“Mwml@nn redrawn 8fKtprklt9dwktl pem8don Gtth8Mionat

Petmbum CotmciL @ National Petroleum Council, 1976.
amount of CO2 at these locations is unknown.

The potential demand for C02 is such that

geological exploration is in progress.

A pictorial representation of a C02 miscible

flood is shown in figure 11. In the past, CO2 has

sometimes, been injected into reservoirs in quantities and at pressures less than those necessary

to achieve complete miscibility, resulting in less

oil recovery than when complete mixing is

achieved. In this assessment, quantities and

pressures of CO2

injected are designed to

achieve complete miscibility.

Chemical Processes

Three EOR processes involve the use of chemicals—surfactant/polymer, polymer, and alkaline

flooding.

Surfactant/Polyrner Flooding.—Surfactant/poIymer flooding, also known as microemulsion

flooding or micellar flooding, is the newest and

most complex of the EOR processes, While it has

a potential for superior oil recovery, few major

field tests have been completed or evaluated.

Several major tests are now under way to determine its technical and economic feasibility.

Surfactant/polymer flooding can be any one of

several processes in which detergent-like

materials are injected as a slug of fluid to modify

the chemical interaction of oil with its surroundings. These processes emulsify or otherwise dissolve or partly dissolve the oil within the formation. Because of the cost of such agents, the

volume of a slug can represent only a small percentage of the reservoir volume. To preserve the

integrity of the slug as it moves through the reservoir, it is pushed by water to which a polymer has

been added. The surfactant/polymer process is illustrated in figure 12.

The chemical composition of a slug and its size

must be carefully selected for each reservoir/crude oil system. Not all parameters for this

design process are well understood.

polymer Flooding. -Polymer flooding is a

chemically augmented waterflood in which small

concentrations of chemicals, such as

polyacrylamides or polysaccharides, are added to

injected water to increase the effectiveness of

the water in displacing oil. The change in recovCh. //I--Oil Recovery Potent/a/ . 31

ery effectiveness is achieved by several different

mechanisms, not all of which are completely understood. Improvement in the efficiency of

waterflood recovery with the use of polymers is

relatively modest, but it is large enough for the

process to be in limited commercial use. If other

EOR processes are technically possible they offer

a possibility of both greater oil recovery and

greater economic return than polymer flooding,

although each reservoir must be evaluated individually to select the most effective process. As

it is currently in use, polymer flooding is evaluated in this assessment.

Alkaline Flooding.—Water solutions of certain

chemicals such as sodium hydroxide, sodium silicate, and sodium carbonate are strongly alkaline.

These solutions will react with constituents present in some crude oils or present at the

rock/crude oil interface to form detergent-like

materials which reduce the ability of the formation to retain the oil. The few tests which have

been reported are technically encouraging, but

the technology is not nearly so well developed as

those described previously. Alkaline flooding

was not quantitatively evaluated in the present

study, largely because there is too little information about key oil characteristics in the OTA

reservoir data base which are crucial to a determination of the feasibility of alkaline flooding.

Reservoirs not considered for alkaline flooding

became candidates for other processes.

Other EOR Processes

Over the years, many processes for improving

oil recovery have been developed, a large number of patents have been issued, and a significant

number of processes have been field tested. In

evaluating a conceptual process, it should be

recognized that a single field test or patent represents but a small step toward commercial use on

a scale large enough to influence the Nation’s

supply of crude oil. Some known processes have

very limited application, For example, if thin

coalbeds lay under an oil reservoir this coal could

be ignited, the oil above it would be heated, its

viscosity would be reduced, and it would be

easier to recover. This relationship between oil

and coal is rare, however, and the process is not

important to total national energy production.

Another example involves use of electrical
32 . Ch. Ill—Oil Recovery Potential

Figure 11. Carbon Dioxide Miscible Flooding Process*

CO2 AND WATER OIL AND WATER

v 4

LEGEND

I I

Injected CO2 and Water Zone

CO2

-Crude Oil Miscible Zone

Oil and Water Zone

Figure 12. Surfactant Flooding Process

INJECTION FLUIDS

w

w

OIL AND WATER

4

LEGEND

I

Drive Water Zone Surfactant Slug Zone

Water/Polymer Zone [ “ I Oil and Water Zone

“Illustrations redrawn and printed with permiaaionof the National

Petrokum Council. @ National Petroleum Counci{, 1976.
energy to fracture an oil-bearing formation and

form a carbon track or band between wells. This

band would then be used as a high-resistance

electrical pathway through which electric current

would be applied, causing the “resistor” to heat

the formation, reduce oil viscosity, and increase

oil recovery. The process was conceived over 25

years ago and has been tested sporadically, but

does not appear to have significant potential. A

third process in this category is the use of bacteria for recovery of oil. Several variations have

been conceived. These include use of bacteria

within a reservoir to generate surface-active

(detergent-like) materials that would perform

much the same function as a surfactant/polymer

Ch. III—0il Recovery Potential . 33

flood. Although some bacteria are able to withstand temperatures and pressure found in oil

reservoirs, none have been found that will both

successfully generate useful modifying chemicals

in sufficient amounts and also tolerate the chemical and thermal environments in most reservoirs.

It is uncertain whether nutrients to keep them

alive could be provided. Further, any strain of

bacteria developed would need to be carefully

screened for potential environmental impacts.

Finally, even should the concept prove feasible, it

is unlikely that the bacteria could be developed,

tested, and used in commercial operation in time

to influence oil recovery by the year 2000.

Oil Resource

Data Base

The analytic approach used in

for Enhanced Oil

The

eludes

Recovery Processes

resulting data base for the assessment in385 fields from 19 States (table 6). These

this assessment

of EOR potential relies on reservoir-by-reservoir

simulations. The accuracy of this approach depends on the extent, representativeness, and precision of the reservoir data file. Earlier reports10 11

have been based on data from 245 large onshore

reservoirs in California, Louisiana, and Texas. For

this assessment, additional data were collected

for onshore reservoirs in those States, for reservoirs in other producing areas of the United

States, and for reservoirs in offshore areas (primarily the Gulf of Mexico). The expanded data

base for this assessment was acquired from

Federal, State, and private sources. After all

available data were examined and cataloged,

they were edited for volumetric consistency.

These data were reviewed by OTA as other

sources of information became available. Additional data led to reductions in estimates of remaining oil in place (ROIP) in California reservoirs

which contained oil with gravities above 25° API.

lfJThe potentja/ and [conomics of Enhanced Oil Recovery,

Lewin and Associates, Inc., for the Federal Energy A d -

ministration, April 1976.

II Enhanced 0;/ Recovery, National petroleum council,

December 1976.

385 fields (835 reservoirs) contain 52 percent of

the known ROIP in the United States. The reservoir data in the OTA data base are representative

of the known oil reservoirs in the United States.

Uncertainty in the Oil Resource

Two EOR processes, surfactant/polymer and

C02 miscible, are generally applied after a reservoir has been waterflooded. A large portion of

the resource for these processes will be located

in the reservoir volume which was contacted by

water. The oil remaining in this region is termed

the residual oil saturation.

There is uncertainty in the estimates of

residual oil saturation and hence in the oil which

is potentially recoverable with surfactant/

polymer and CO2 miscible processes. A review of

the technical literature and discussions with

knowledgeable personnel in the oil industry led

to the following observations:

a

b

There are few reservoirs whose estimates of

residual oil have been confirmed by independent measurement.

The uncertainty in the aggregate estimate is

due to a lack of confidence in measurement
34 . Ch. ///—Oil Recovery Potential

State

Table 6

Extent of the Reservoir Data Base Utilized in This

Assessment of Enhanced Oil Recovery Potential

Alabama ... , . . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . . . . .

Arkansas . . . . . . . . . . . . . . . . . . . . .

California. . . . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . .

Florida . . . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . . . . . . . . . . .

Louisiana

Onshore. . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . .

New Mexico . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . .

Texas . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . .

Total States covered (MMB) . . . . .

Remaining oil

in place

(MMB)

519

14,827

2,768

62,926

3,002

556

5,726

10,403

13,696

7,349

2,988

3,796

11,241

1,849

25,406

5,344

100,591

2,725

2,064

10,628

288,404

Fields

2

6

3

41

21

3

8

28

24

24

11

15

15

6

33

5

111

6

2

21

385

OTA database

Remaining oil

Reservoirs

2

9

3

67

21

3

9

28

47

372

12

15

18

7

35

6

146

6

2

27

835

in place

(MMB)

354

14,601

1,328

45,125

1,490

465

2,421

3,345

6,731

2,983

1,187

1,443

4,960

548

6,548

1,077

54,221

1,734

194

4,543

115,298

Percent of

State

68

98

48

72

50

84

42

32

49

41

40

38

44

30

26

20

54

6 4

9

43

54

Total U.S. (MMB) 300,338a

OTA database is 52 percent of remaining oil in place in the United States.

“This value includes 3.3 billion barrels of oil which are included ln APl lndlcated reserves as recoverable by secondary methods. it does

not include 1.0 billion barrels of enhanced 011 in the API proven reserves.

techniques compounded by a limited ap- d. Estimates of the oil recoverable by surfacplication of those methods. tant/polymer and C02 miscible processes

will have a large range of uncertainty

c. The estimates of residual oil saturation may because of the uncertainties in the estibe off by as much as 15 to 25 percent (or mates of residual oil saturation.

more).
Ch. //l—Oil Recovery Potential ● 35

Methodology for Calculating Oil Recovery

Estimates of the amount of oil that can be

recovered by the different EOR processes were

based upon an individual analysis of each reservoir in the data file. Results from the individual

reservoir calculations were then compiled and

extrapolated to a national total. In outline form,

the procedure consisted of the following steps.

Technical Screen

A technical screen was established for each

process. Reservoir rock and crude oil properties

were screened against standards which had to be

met before an EOR process could be considered

applicable to that reservoir. The technical screens

for all processes are shown in table 7. These

screening parameters were established after an

assessment of current technology and incorporation of expected technological advances. Each

reservoir was compared to the technical screen

for every process and either accepted or rejected

for each process. A reservoir could be a candidate for more than one EOR process.

Calculation of Reservoir Production

and Economics

Reservoirs which passed the technical screen

were then analyzed to determine probable production performance and economics. Those

reservoirs eligible for more than one EOR process

were analyzed for all processes for which they

were technically acceptable. For each process,

both an oil recovery model and an economic

model were established, Oil recovery models,

described in appendix B, were used to predict the

amount of oil which would be recovered and the

rate at which the oil would be produced. These

recovery models all incorporate features which

made the calculations dependent upon the particular characteristics of the reservoirs.

The economic model described in appendix B

was used to compute, at a specified oil price, a

rate of return on investment which would result

from application of a selected EOR process to a

particular reservoir. The economic model

allowed for different operating and drilling costs

in different geographic regions, different well

spacings, variable EOR process costs, etc. The

model also incorporated a field development

scheme. This scheme allowed a specified number

of years for pilot tests and economic and

engineering evaluations. It also provided for

development of a field on a set time schedule

rather than for simultaneous implementation of

an EOR process over the entire field.12

Final EOR Process Selection for

Reservoirs Passing More Than One

Technical Screen

For reservoirs passing more than one technical

screen, production resulting from application of a

recovery technique and economic models for

each acceptable EOR process were compared.

The process selected was the one which yielded

the greatest ultimate oil recovery, as long as the

process earned at least a 10-percent rate of return

on investment at the world oil price of $13.7s

per barrel. If no process earned 10 percent at the

world oil price, then the alternate fuels price of

$22 per barrel was used, again selecting the process which yielded the greatest amount of oil.

Reservoirs not yielding 10 percent for any process

at the alternate fuels price of $22 per barrel were

placed in the process which appeared to have the

best economic potential. Reservoirs were deleted

from consideration if the computations at the

alternate fuels price resulted in a negative return

on investment.

Ultimate Recovery for the Nation

Ultimate recovery for the Nation was estimated by extrapolating the individual reservoir

I ~Our analysis assurnecf that enhanced recovery operations would be installed before producing wells are plugged

and abandoned. If enhanced recovery operations are begun

after producing wells are plugged and abandoned, oil recovery will be slightly more costly ($1 to $3 per barrel) and

most likely delayed because of economics.
36 . Ch. ///—Oil Recovery Potential

o

1 o ’

‘ VI ‘

t

t

,

1 1

1 1

I I

c. -

I

1

t

,

,

o

0

0

In

18 t

11 v ‘8 ‘1’ ‘

I 1= 1,1 1

It o #

o

‘ Al ‘ ‘ ‘ ‘

m

A

1

I

1

1

#

I

. .

● ✎ ✎ u“0
Ch. ///—Oil Recovery Potential . 37

performances. Because a significant amount of

the oil in each oil-producing State was represented in the data base, extrapolations were

made on a district or State basis. Total recovery

for each State or district, for a selected oil price

and rate of return, was calculated in the following

manner: The oil recovered from reservoirs in the

data base for that State or district was multiplied

by the ratio of total oil remaining in the State or

district to oil remaining in the State or district

data-base reservoirs. (The one exception to this

rule was for West Virginia, where the sample included only 9 percent of the total oil in the State.

For West Virginia, only the oil in the data base

was included in the composite results. Deletion

of West Virginia from the extrapolation process

has no significant effect on ultimate recovery

estimates because oil remaining in those reservoirs constitutes less than 1 percent of the oil remaining in U.S. reservoirs. ) “Oil remaining, ” as

used here, refers to oil remaining after ultimate

primary and secondary recovery. State and district productions were summed to obtain national production.

Rate of Production for the Nation

The starting date for the development of each

reservoir was determined with the use of a rateof-return criterion, Reservoirs earning the highest

rates of return were assumed to be developed

first. The schedule shown in table 8 was used to

establish starting dates for reservoir evaluation,

i.e., starting dates for pilot tests and economic

and engineering evaluations, which were then

followed by commercial development. Extrapolation of production rates from individual reservoirs to a State and then to the Nation was accomplished in the same manner as described for

ultimate recovery.

This plan for reservoir development recognizes

two factors which influence the application of

improved oil recovery processes. First, it accounts in part for risk in that the highest rate-ofreturn projects will be initiated earliest when the

technology is least certain. Lower rate-of-return

projects would not be started until later dates, at

which time the technological and economic risk

should be reduced as a result of experience

gained from field tests and commercial operations. Secondly, the timing plan in some measure

simulates actual industry decisionmaking. As a

Table 8

Schedule of Starting Dates

Based on Rate-of-Return Criterion

Continuations of

ongoing projects New starts

Date rate of return rate of return

1977 . . . . . . . . . . . 1 00/0 30 ”/0

1978 ......., . . .

1979 . . . . . . . . . . .

1980 . . . . . . . . . . .

1981 . . . . . . . . . . .

1982 , . . . . . . . . . .

1983 . . . . . . . . . . .

1984 . . . . . . . . . . .

1985 . . . . . . . . . . .

1986 . . . . . . . . . . .

1987 ......., . . .

1988 . . . . . . . . . . .

1989 . . . . . . . . . . .

1990-2000 . . . . . .

1 00/0

10“/0

“10“/0

10%

10“/0

10%

10%

10%

10%

1 0 %

10%

10%

10%

250/o

20 ”/0

19 ”/0

18%

17’YO

160/0

15 ”/0

14%

13“/0

12“/0

11 ”/0

10“/0

10“/0

Note: In the production models, after It has been decided to

develop a reservoir, time IS allowed to study the reservoir,

conduct pilot tests and do engineering and economic

analyses. These studies and evaluations are completed

before initiating commercial production.

general rule, the most promising projects are initiated first by industry.

While OTA believes the timing plan is

reasonable, it still is only an approximation of

what will actually occur. Other factors such as

level of technological risk, alternative investment

opportunities, availability of resources required

for the processes, etc., will significantly influence

the implementation rate of EOR.

Exclusion of Alaska

The EOR potential of Alaska was not examined, for several reasons. A large portion of

that State’s oil resource was included in the data

base (table 6). However, OTA felt that the

economic data base required for the E O R

economic models was not sufficiently well

established. Alaska is a relatively young producing area and most of its oil fields are in a hostile

environment. Costs are known to be high and

difficult to estimate for future EOR projects. Also,

because Alaska is a young producing area and

because costs are high, EOR projects probably

will not be considered to any significant degree

for several years.
— -——

38 . Ch. Ill—Oil Recovery Potential

Estimated Oil Recovery

Definition of Cases

It is not possible to predict with certainty how

much oil can be recovered in the future with EOR

processes. Therefore, two principal cases were

established, covering a range in the technological

performance of the different processes. The more

optimistic of these was labeled the “advancing

technology —high-process performance case. ”

The less optimistic was termed the “advancing

technology —low-process performance case. ”

These cases were designed in an effort to calculate realistic estimates of future recovery and at

the same time reflect the uncertainty which exists

in OTA’s projection.

In addition to these two principal cases, estimates were made of the effects of variations in

key parameters, such as injected chemical (CO2

,

surfactant) costs, minimum specified acceptable

rate of return, and resource availability, on recovery. These estimates, in essence, involved extensions and modifications of the two principal

cases.

A description of the principal cases follows.

Case I: Advancing Technology—

High-Process Performance

It was assumed for this case that the EOR processes which are now in their developmental stage

(C02 miscible, surfactant/polymer, polymer-augmented waterflooding, and in situ combustion)

would work as now generally envisioned by the

petroleum industry. The production models for

these processes, which are described in appendix

B, were based largely on reported laboratory

results with limited data from field tests. The

steam process is the only technique that can currently be classified as a commercial process and

as a result its production model is based on more

field experience than the others.

Because of the nature of surfactant/polymer

and polymer-augmented waterflood processes

and their early stage of development, OTA

assumed that certain technological advances

would occur between now and the year 2000.

In the case of surfactant/polymer flooding, it

was assumed that research and field testing

would lead to a reduction in the volume of oil

used in the surfactant slug and the volume of

polymer needed to displace the surfactant slug

through the reservoir. Reductions by a factor of

two were assumed for both oil and polymer

volumes from values representative of current

technology. Current surfactant formulations are

tolerant of total dissolved salt content of about

20,000 parts per million (ppm). It was also

assumed that developments in the formulation of

surfactant and polymer systems would extend

salinity tolerance to 200,000 ppm. Finally, it was

assumed that technological advances would occur in surfactant/polymer and polymer-augmented waterflooding processes which would

raise the temperature constraint to 250° F. The

timing of the advances is shown in table 7.

A major technological assumption for the CO2

miscible process was that between 4 and 6 thousand cubic feet (Mcf) of C02 would be injected

per barrel of EOR oil recovered. Although current

pilot tests with CO2 indicate that this injectionvolume ratio may be on the order of 10 Mcf per

barrel of oil, it was assumed that a technological

advance to the above-stated injection efficiency

would be achieved.

The advancing technology-high-process performance case was considered to be unconstrained by chemical resource availability.

This assumption is also of paramount importance. For example, the amount of CO2 required

at the world oil price recovery is 53 trillion cubic

feet (Tcf) (not including recycled CO2

). This is a

very large quantity of C02

, which simply may not

be available at CO2 prices used in the calculation. Chemical availability was also assumed for

surfactant/polymer and polymer-augmented

waterflooding processes.

Technological advances were assumed in the

field application of steam and in situ combustion

processes. Well-completion technology, which

permitted selective depletion of each major zone

within a reservoir, was assumed. All major zones

were developed sequentially. Methods for con-
Ch I//—Oil Recovery Potential . 39

trolling volumetric sweep efficiency of both

processes were assumed to develop so that the

processes could be applied to 80 percent of the

reservoir acreage.

It was assumed in this case that the EOR processes could be made to operate without damage

to the environment and that this could be done

at no additional cost. For the thermal processes,

in particular, this is an important assumption. For

example, air pollution limitations now existing in

California would allow little or no new steam

recovery in that State without technological advances to reduce pollutant levels from steam

generation.

In California, a limited number of refineries

capable of processing heavy oil, an entitlements

program, and a prospect of competing crude supplies from Prudhoe Bay combine to reduce the

State demand for heavy oil production. The OTA

study assumes that a market exists for all heavy

oil produced in California.

Enhanced oil recovery production was

assumed to occur in any reservoir if the rate of

return after taxes was greater than 10 percent.

This further implies advances in technology to

reduce risk of failure, because investments at interest rates of 10 percent will only be made for

relatively low-risk projects. Risk has been taken

into account, as explained in a previous section,

in that the production timing plan was based on

rate of return with the “best” projects being initiated first, However, in the calculations a large

amount of oil is recovered at rate-of-return values

just slightly above 10 percent,

The advancing technology-high-process performance case implies a significant commitment

to a research and development program which

would be carried out in concert with the commercial implementation. The technological advances will not be made, nor will risk be reduced

to the level assumed, without such an effort.

Case II: Advancing TechnologyLow-Process Performance

Case II is a conservative estimate of future

recoveries which assumes that no EOR process

wilI work as successfulIy as it does in the advancing technology-high-process performance case.

Changes were made in the production models

which led to reductions in recoveries averaging

between 12 and 30 percent for the different EOR

processes. The details of the low-process performance case for each process are given in appendix B.

Case II essentially assumed that less oil would

be recovered by the EOR processes using as large

a dollar investment as was assumed in the highperformance case. Resource constraints were not

imposed, and the assumption was made that the

processes would operate without environmental

damage.

Calculation Results

Low- and High-Process Performance Cases

The results of the high-process performance

and low-process performance cases are shown in

tables 9 through 14, Table 15 presents ultimate

recovery by State while table 16 shows extrapolation proportions for each process under

high- and low-process performance assumptions. Table 9 gives the cumulative figures for all

processes. Individual process recoveries are

shown in the other tables. Results are shown for

three oil prices: upper tier ($11.62 per barrel),

world oil ($13.75 per barrel), and alternate fuels

($22.00 per barrel).

These two cases represent the range of recoveries considered feasible for EOR technology. For

these cases, recoveries were not restricted by

resource availability and technology to meet environmental protection standards. Markets were

assumed for heavy oiI in California. The

difference between the cases thus results from

differences in assumptions about the technological performance of the processes.

For the high-process performance case at the

upper tier price, it is estimated that approximately 21.2 billion barrels of oil could be

recovered. The recovery increases to about 29.4

billion barrels at the world oil price and 41.6

billion barrels at the selected alternate fuels

price, Corresponding uitimate recoveries for the

low-process performance case are 8.0 billion,

11.1 billion, and 25.3 billion barrels, respectively.
40 . Ch. 111—011 Recovery Potential

Table 9

Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

Aii Processes

Low-process performance case High-process performance case

Upper tier

price

($11.62/bbl)

8 0

0.3

0.4

0.5

0,5

1,1

400

1,200

2,000

2,800

4,200

World oil

price

($13.75/bbl)

Alternate fuels

price

($22.00/bbl)

Upper tier

price

($11.62/bbl)

World oil

price

($13.75/bbl)

Alternate fuels

price

($22.00/bbl)

Ultimate recovery:

(billion barrels) . . . . . . . . . . .

Production rate in:

(million barrels/day)

1980. , . . . . ... . . . . . . .

1985. ., ., . . . . . . . . . . . . .

1990. . . . . . . . . . . . . . . .

1995. . . . . . . . . . . .

2000. . . . . . . . . . . . . . . . . .

Cumulative production by:

(million barrels)

1980. ...., . . . . . . . . .

1985. . . . . . . . . . . . . . . . .

1990, ., . . . . . . . .

1995. . . . . . . . . . . . . . . . . .

2000. , . . ... , . . . . . . . . .

11.1

0.3

0.5

0.7

1.2

1.7

400

1,300

2( 300

3,800

6,900

2 5 3

0.3

0.9

1.8

2.5

5.1

400

1,700

4,200

7,500

‘1 6,000

— —

21.2

0.4

0.5

1.1

1.7

2.9

500

1,700

3,300

5,60 0

10,400

29.4

0.4

1.0

1.7

3.1

5.2

500

2,000

4,700

8,700

17,300

41.6

0.4

1.3

2.8

6.0

8.2

500

2,400

6,200

12,800

29,200

Table 10

Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

Steam Drive Process

Low-process performance case High-process performance case

Upper tier

price

$11.62/bbl)

2.1

0.1

0 2

0,2

0.2

0.2

200

500

800

1,200

1,600

World oil

price

[$13.75/bbl)

A1ternate fuels

price

($22.00/bbl)

Upper tier

price

($11.62/bbl)

World oil

price

($13.75/bbl)

Alternate fuels

price

($22.00/bbl)

Ultimate recovery:

(billion barrels) . . . . . . . . . . .

Production rate in:

(million barrels/day)

1980. . . . . ., . . . . .

1985. .., . . . . . . . . . . .

1990, . . . . . . . . ., . .

1995. . . . . . . . . . . . .

2000, , . . . . . ., . . . . . . . .

Cumulative production by:

(million barrels)

1980. . . . . . . . . . . ., . . . .

1985. ., . . . ., . . . . . . . .,

1990. ...., ., . . . . . . . . . .

1995. , . . . . . . . . . . . . . . . .

2000. ..., ... . . . . . . . .

2.5

0 1

0.2

0.2

0.3

0.3

200

500

800

1,300

1,800

— .

4.0 2.8

o.2

0.2

0.2

0.2

0,3

300

3..3

0.2

0.2

0.3

0.3

0.4

300

800

1,100

1,700

2,400

6.0

0.2

0.3

0.5

0.4

0.4

0.3

0.4

0.7

0.7

0.6

200 I 400

1,100

2,000

3,300

4,600

700

1,400

2,300

3,100

800

1,100

1,400

1,900
Ch ///—Oil Recovery Potential . 4 1

Table 11

Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

In Situ Combustion

Ultimate recovery:

(billion barrels) . . . . . . . . . . . . .

Production rate in:

(million barrels/day)

1980. . . . . . . . . . . . . . . . . .

1985. . . . . . . . . . . . . . . . . . .

1990. . . . . . . . . . . . . . . . .

1995 .., . . . . . . . . . . . . . . .

2000. . . . . . . . . . . . . . .

Cumulative production by:

(million barrels)

1980. . . . . . . . . . . . . . . . .

1985. . . . . . . . . . . . . . . . . .

1990. . . . . . . . . . . . . . . . . .

1995. . . . . . . . . . . . . . . . . .

2000. . . . . . . . . . . . . . . . . .

Low-process performance case

Upper tier

price

$11.62/bbl)

—

1.2

0.1

0.1

0.2

0.1

0.1

*

300

600

900

1,000

World oil

price

($13.75/bbi)

1.4

0.1

0.2

0.3

0.1

0.1

*

300

700

1,100

1,200

Alternate fuels

price

($22.00/bbl)

1.6

0.1

0.2

0.3

0,2

0.1

●

300

800

1,200

1,400

High-process performance case

Upper tier

price

($ll.62/bbl)

1.7

0.1

0.2

0.3

0.2

0.1

●

300

800

1,200

1,400

world Oil

price

($13,75/bbl)

1.9

0.1

0.2

0.3

0.2

0.1

●

400

900

1,400

1,600

•le\~ than 005 mllllon barrels of dally production, or less than 50 mlllmn bwels of cumulative production.

Table 12

Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

Ultimate recovery:

(billion barrels) . . . . . . . . . . .

Production rate in:

(million barrels/day)

1980. . . . . . . . . . . . . . . . . .

1985. . . . . . . . . . . . . . . .

1990. . . . . . . . . . . . . . . . .

1995, , . . . . . . . . . . . . . . . .

2000. . . . . . . . . . . . . . . . . .

Cumulative production by:

(million barrels)

1980. . . . . . . . . . . . . . . . . .

1985. . . . . . . . . . . . .

1990. . . . . . . . . . . .

1995. . . . . . . . . . . . . . . . .

2000. . . . . . . . . . . . . . . . .

Surfactant/Polymer

Low-process performance case

Upper tier

price

$11.62/bbl)

1 .0

*

+

●

*

0.2

*

100

100

100

300

World oil

price

($13.75/bbl)

2,3

*

*

*

0.1

0.2

*

100

100

200

500

A1ternate fuels

price

($22.00/bbl)

— —

7.1

●

0.1

0.4

0.2

1.3

*

200

600

900

2,700

Alternate fuels

price

($22,00/bbll

1.9

0.1

0.2

0.4

0.2

0.1

*

400

1,000

1,500

1,700

High-process performance case

Upper tier

price

$11.62/bbl)

7.2

●

☛

0.2

0.2

0.9

●

1 0 0

400

700

1,800

- <

World–oil

price

($13.75‘bbl)

10.0 ~

●

0.2

0.4

0.8

1.9

●

300

900

1,800

4,400

Alternate fuels

price

($22.00/bbl)

12.2

●

0.2

().7

1,3

2.5

*

300

1,000

2,000

6,200

● less than 0.05 million barrels of daily production, or less than 50 million b.irrc~ls of ( umul,ltlve produ~~ion
—-

42 . Ch. Ill—Oil Recovery Potential

ri ● ☛☛ 0 0

m

r -

0000 0

0000 0

F a G m V,

. . .

6

0 ● ☛☛ 0 0

— —

r -

2 . :
Ch. ///—Oil Recovery Potential . 43

Table 14

Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

Polymer-Augmented Waterflooding

I

Low-process performance case

Upper tier

price

($11.62/bbl)

Ultimate recovery:

(billion barrels) . . . . . . . . . . . . .

Production rate in:

(million barrels/day)

1980. ........, ... , . . . .

1985. . . . . . . . . . . . . . . . . .

1990, . . . . . . . . . . . . . . . . .

1995. ......., . . . . . . . . .

2000. . . . . . . . . . . . . . . . .

Cumulative production by:

(mill Ion barrels)

1980. , . . . . . . . . . . . . . . . .

1985. . . . . . . . . . . . . . . . . .

1990. . . . . . . . . . . . . . . . . .

1995. . . . . . . . . . . . . . . . . .

2000. . . . . . . . . . . . . . . . . .

0.2

*

●

0.1

*

●

100

200

200

200

World oil

price

($13.75/bbl)

0.3

●

●

0.1

*

*

●

100

200

300

300

Alternate fuels

price

($22.00/bbl)

0.3

●

☛

0.1

*

●

*

100

200

300

300

High-process performance case

Upper tier

price

($11.62/bbl)

0.4

*

*

0.1

*

*

*

100

200

300

400

World oil

price

($13.75/bbl)

0.4

*

*

0.1

*

+

.

100

200

400

400

● Less than 0,05 mlllmn barrels of dally production, or less than sO million barrels ofcurnulatlve product~m.

Table 15

Ultimate Recovery by State

High-Process Performance

State

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Illinois. . . . . . . . . . . . . . . .

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore Gulf ot Mexico . . . . . . . . . . . . . . . . . . . . . . . . . .

Totals J 

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

Alternate fuels

price

($22.00/bbl)

0,4

●

☛

0.1

*

●

●

100

300

400

400

Upper tier

price

($11.62/bbl)

6.8

1.1

4.7

1 . 2

3 . 3

1 . 6

0 . 3

0 , 2

0 , 0

0 . 0

0 . 0

0 . 0

0 . 6

0 . 0

0 . 4

0 . 2

0 . 1

0 . 6

21.2

Ultimate recovery

(billions of barrels)

world oil

price

($13.75/bbl)

7,8

1 . 2

7 . 9

1 . 7

4 . 0

2 . 3

0 . 4

0 . 3

0 . 2

0 . 0

0 . 4

0 . 0

1 . 3

0 . 0

0.5

0,5

0.1

0.9

29.4

Alternate fuels

price

($2200/bbl )

11.4

2.0

11.6

1.7

4.8

2.7

0.4

0.4

0.2

0.1

0.4

0.2

1 . 4

0 . 2

0 . 8

0 . 5

0.1

2 . 6

41. 6

“Columns may not add due to roundlng
44 . Ch. 111—011 Recovery Potential

Table 16

Extrapolation of Ultimate Oil Recovery From Data Base Calculations to the Nation

World Oil Price ($13.75/bbl)

(Billions of Barrels)

Low-process performance

Process Data base/

Nation

Data base Nation percent

Steam drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

In situ combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Carbon dioxide miscible . . . . . . . . . . . . . . . . . . . . . : . . .

Surfactant/polymer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Polymer-augmented waterflood . . . . . . . . . . . . . . . . . . .

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

1.40

0.78

2.11

0.73

0.15

5.17

As indicated in table 9, all of this oil would not

be recovered by the year 2000. For example, in

the high-process performance case at the upper

tier price, the production rate increases from

slightly more than 0.5 MMBD in 1985 to nearly

3.0 MMBD in the year 2000. The daily production

pattern shown results in a cumulative production

by the year 2000 of 10.4 billion barrels, or sO percent of the projected ultimate recovery. At the

other two oil prices, the production rate also increases through the year 2000. The cumulative

productions by 2000 are 59 and 70 percent of

ultimate recovery at the world oil and alternate

fuels prices, respectively.

The five EOR processes examined yield

markedly different amounts of oil as indicated in

tables 10 through 14. This is illustrated by the

high-process performance case. The COZ miscible process contributes about half of the ultimate

recovery at the world oil and alternate fuels

prices. The surfactant/polymer process is estimated to contribute about 30 percent of the total

ultimate recovery and the thermal processes

about 20 percent.

The only process found to be generally

economical in the offshore reservoirs at the world

oil price was CO2 miscible. Other processes were

found to be economical in only a very few reservoirs, Therefore, C02 miscible flooding was applied exclusively. The results are shown, along

with the onshore recoveries, in table 13 for the

high-process performance case. For low-process

performance, offshore development was taken to

I I

High-proc

Data base

1.83

1.08

6.65

4.54

0.19

14.29

Nation

3.3

1.9

13.8

10.0

0.4

29.4

formance

Data base/

Nation

percent

55

57

48

45

48

49

be marginally economical and therefore unattractive.

Both the high- and low-process performance

cases place great demands on resource requirements. For example, the amount of CO2 that

would be consumed in reaching the ultimate

recovery at the world oil price is about 53 Tcf in

the high-process performance case. This does not

include about 18 Tcf of recycled C02

. This is a

very large amount of CO2

, and it is not known

whether such a supply will be available

costs assumed in the economic model.

Ultimate Oil Recovery by

EOR Processes

Estimates of ultimate recovery were

at the

determined by extrapolating results from the 835

reservoirs in 19 States. Of the 835 reservoirs in

the OTA data base, 636 were assigned to one of

the five oil recovery processes. Nine reservoirs in

Alaska were not evaluated for enhanced oil

recovery processes due to insufficient cost data.

Enhanced oil recovery processes were not technically feasible in the remaining 190 reservoirs.

The remaining oil in place (ROIP) in the 835

reservoirs is 155.3 billion barrels, which represents about 52 percent of the ROIP in the United

States. About 14.6 billion barrels of this amount

are in Alaskan reservoirs which were not considered for EOR processes. The ROIP in data base

reservoirs which were evaluated for enhanced oil

recovery processes was 140.7 billion barrels.
Net oil recovered from data base reservoirs by

application of high-process performance models

is 22.3 billion barrels at $30 per barrel. In estimating the net oil that can be recovered by enhanced

oil processes, a reservoir was considered

economic if it could be developed and yield a

10-percent rate of return at prices of $30 per barrel or less. This is about 95.5 percent of the oil

considered technically recoverable using these

models. Oil not recoverable under the high-process performance models is 133 billion barrels.

Distribution of the potential recoverable and

unrecoverable oil by process is shown in table

17.

Table 18 extends these results to the United

States using the extrapolation procedure

described in the section on Ultimate Recovery for

the Nation on page 35.

The 49.2 billion barrels indicated as net oil

recoverable by enhanced oil processes is an estiCh. 111—011 Recovery Potential .

mate of the upper limit of potential recovery

45

at

oil prices of $30 per barrel” or less. This is 95.6

percent of the oil considered to be recoverable.

The estimate assumes successful application of

EOR processes to all applicable reservoirs in the

United States. If the EOR processes perform as

assumed in the low-process performance case,

the net potential EOR oil would be considerably

less.

Unrecoverable oil in table 18 is estimated to

be 248.8 billion barrels or 56.3 percent of the initial oil in place. About 76 billion barrels of oil will

be left in reservoirs where no enhanced oil recovery process was considered applicable in the

OTA study. Some portion of the 14.8 billion barrels which will remain in Alaskan reservoirs not

evaluated in the OTA study may be recoverable

at $30 per barrel. The approximately 170.4 billion

barrels which remain in reservoirs after EOR processes are applied represent their inherent inefficiencies.

Table 17

Summary of Oil Recovery Evaluations

Data Base Resevoirs

Process

Steam drive. . . . . . . . . . . . . . . . . . . . . . . . . .

In situ combustion . . . . . . . . . . . . . . . . . . . .

C O2 miscible

Onshore . . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . . . . . .

Surfactant/Polymer . . . . . . . . . . . . . . . . . . .

polymer augmented waterflood . . . . . . . . .

No EOR . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Reservoirs

assigneda

to process

20

20

190

294

92

20

199

835

Remaining

oil in place

(millions of barrels)

21,10 7

7,58 5

53,25 4

2,69 5

24,38 6

3,94 9

42,32 2

155,29 8

Net oilb

recoverable

(millions of barrels)

at $30/barrel

4,053

1,126

9,704

1,298

5,898

189

0

22,268

‘Process selected yielded maximum oil recovery at 10-percent rate of return or better at world oil price

Oil considered

not recoverable

(millions of barrels)

17,054

6,459

43,550

1,397

18,488

3,760

42,322

133,030

ho,] used as fuel O’r Inlected as part Of the displacement process was deducted from gross Production ‘ 0

find net production.

‘Includes nine reservoirs in Alaska containing 14.6 billion barrels of remaining oil which were not evaluated due to msufflclent cost data.
. —

46 . Ch. Ill-oil Recovery Potential

Discussion of Results

Table 18 Table 19

Projected Distribution of Uncertainty in Projections of Ultimate Recovery for

Known Oil in the United States Advancing Technology Cases

Produced (December 31, 1975) . .

Proven reserve (including North

Slope Alaskaa 

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

Indicated reserveb 

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

Net oil recoverable by

Enhanced oil processes in highprocess performance case at

$30/barrel. Not included in

API proven or indicated

reserves. . . . . . . . . . . . . . .

Unrecoverable oil

Recoverable at price greater

than $30/barreI . . . . . . . . . .

Oil left in reservoirs after

enhanced oil recovery processes were applied and oil

consumed as part of the

recovery process . . . . . . . . .

Oil in reservoirs where no

enhanced oil recovery process was applicable at prices

of $30/barreld

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

‘API Proven Reserve (December 31,

Billions

of

barrels

109.0

32.7

5.0

46.5

2.3

170.4

76.1

442.0

Percentage

of original

oil in

place

24.7

7.4

1.1

10.5

0.5

38.6

17.2

100.0

1975) includes 1.0 billion

barrels from enhanced oil recovery processes.

bApl Indicated Reserve (December 31, 1975) includes 1.7 billlon

barrels from enhanced oil recovery processes.

‘Net 011 recoverable in the high-process performance case IS 49.2

billlon barrels. The 2.7 billion barrels included in API Proven and indicated Reserves as of December 31, 197s were deducted from

computed net EOR oil.

‘{Reservoirs In Alaska which will contain 14.8 billlon barrels of oil

after deduction of Proven and Indicated Reserves were not evaluated In this study due to insufficient cost data.

Projections of this study are based on application of EOR processes to reservoirs in the lower

48 States.

I Ultimate recovery

,

(billions of barrels )

Oil price Low- High-

$/barrel I

process process

performance performance

Upper tier ($11.62/bbl) . . . . . 8.0 21.2

World oil ($13.75/bbl) . . . . . 11.1 29.4

Alternate fuels ($22.00/bbl) . 25.3 41.6

lower and upper bounds of the volumes of oil

which are potentially recoverable at upper tier,

world oil and alternate fuels prices. These

volumes, ranging from 8 billion to 42 billion barrels, are significant when compared to the

American Petroleum Institute (API) proven oil

reserves (December 31, 1975) of 32.7 billion barrels which remained to be produced from existing fields.13

The wide range in estimates is caused primarily

by uncertainties in projecting oil recovery from

application of the surfactant/polymer and C02

miscible flooding processes. Both processes are

in early stages of development.

Production Rate

Daily production rates for the advancing technology cases at world oil prices are superimposed on the projected U.S. decline curve in

figure 13. peak production rates are projected to

be the same order of magnitude as the projected

production rate from API proven, indicated, and

inferred reserves in existing fields. Production

rates in the mid-1980’s are projected to vary between 8 and 17 percent of the projected producProjected Results for the United States

Ultimate Recovery

Results of the advancing technology cases,

summarized in table 19, are estimates of the

I JAn additional s billion barrels are recognized by the Apl

as Indicated Additional Reserves. About 3.3 billion barrels

are projected from secondary recovery. The remainder (1.7

billion barrels) are attributed to enhanced oil recovery processes. A total of 31.7 billion barrels of the proven oil reserve

will be produced by primary and secondary methods. One

billion barrels will be produced by EOR techniques at current economics.
tion from existing fields by conventional

methods.

Oil produced by improved oil recovery processes could become an important part of the Nation’s oil supply for the period beginning in 1985

and extending beyond the year 2000. However,

application of EOR technology would not offset

the decline from existing fields until after 1990.

Uncertainties in Projections

The range of projections for ultimate recovery

in table 19 and production rates in figure 13

represents OTA’s judgment of the range of uncertainty which exists in the projections, Although

uncertainties are present in projections of both

ultimate recovery and production rate, the estimates of ultimate recovery are considered to be

Figure 13. Projected Production From Known

U.S. Reservoirs, 1976-95, by Conventional

Methods and by Enhanced Oil Recovery

at World Oil Price

Increased Production of High-Process Performance

~ , Case Over Low-Process Performance Case

7

2

1

Production Based

on Low-Process

Performance Case

Production From - Inferred Reserves

(Extensions and

Revisions) 2 

Proved and Indicated Reserves1

I I I f

1976 1980 1985 1990 1995

SOURCES 1 American Petroleum Institute, Reserves of Crude 0//, Natural

Gas L/qu/ds, and Natural Gas m the U. S. and Canada as of

December 30, 1975 Lewin & Associates, Inc for Federal Energy

Admlnlstratlon, Oec//rre Curve Ana/ys/s, 1976

z U S Geological Survey, C/rcu/ar 725, 1975

3 Federal Energy Admlnlstratlon, Nat/ona/ Energy Outlook, 1976

Ch. Ill—Oil Recovery Potential . 47

more certain than those for daily production

rates.

Uncertainty in Ultimate Recovery

Projections of ultimate recovery at a specified

oil price are uncertain because:

1)

2)

3)

Estimates of ROIP volume and distribution

within a reservoir may be as much as 25

percent (or more) in error. Further discussion of this problem is included in the section on the Effect of Uncertainty in the

Residual Oil Saturation and Volumetric

Sweep on Projected Results on page 50.

The ability to predict the oil recovery and

the quantities of injected materials needed

to obtain this recovery is different for each

process and has wide ranges of uncertainty.

Materials used in the surfactant/polymer

process are either derived from crude oil or

compete with products derived from crude

oil. Therefore, the costs of these components were increased for the purposes of

this assessment as the price of crude oil increased. The cost of carbon dioxide was

not varied with oil price. Because none of

these materials is produced commercially

in the volumes projected for this study, the

cost estimates have some uncertainty. Sensitivity calculations described in appendix

B show that both processes are extremely

sensitive to costs of injected materials. A

50-percent increase in the estimated cost

of chemicals would reduce the oil recovery

from the surfactant/polymer process at

$13.75 per barrel (high-process performance) from 10 billion barrels to 0.2 billion

barrels. About 9 billion barrels of this oil

would be recoverable at the alternate fuels

price.

The demand for natural CO2 may be high

enough for owners of these deposits to

negotiate prices considerably above the

production costs assumed in this study. For

example, a 50-percent increase in the price

of C02 would reduce the potential production from the C02 process from 13.8
48 . Ch. Ill—Oil Recovery Potential

4)

5)

billion barrels at $13.75 per barrel (highprocess performance) to 7.0 billion barrels.

It is not known whether large volumes of

injection fluids, particularly C02

, will be

available. 14 A comprehensive report of

C OZ availability in the United States has

not been published, although ERDA is currently conducting such a study.

The level of uncertainty is influenced by

the stage of technological development of

each process. Steam displacement technology has been proven in portions of

several California reservoirs. In situ combustion and polymer flooding have been

tested extensively with mixed results. Surfactant/polymer flooding and C02 miscible displacement are still being investigated in laboratory and field tests.

Projected ultimate recoveries for steam displacement and in situ combustion are based on

selective development of each major zone in a

reservoir and application of the processes to 80

percent of each reservoir area. Selective completion has been used successfully in portions of a

few reservoirs in California. There is no reservoir

in the OTA data base where steam displacement

or in situ combustion has been applied to 80 percent of the total reservoir acreage.

The CO2 miscible process model is based on

laboratory data and a number of field tests. Recent indications from the field tests are that the

ratio of C02 injected to oil recovered may range

above 10 Mcf of CO2 per barrel of oil.15 T h e

assumption used in the present study for the

high-process performance case was that this ratio

would generally be reduced to 4 to 6 Mcf of C02

per barrel of oil, with 25 percent of the injection

material being recycled C02

. The average value

for the high-process performance case was 5. I

Mcf. For the low-process performance case, the

average ratio was 5.4 Mcf per barrel of oil.

The effect of using a lower CO2 injection ratio

is to reduce chemical costs and thereby improve

the economics. As an example, if the cost of in14EC)R Workshop on Carbon Dioxide, Sponsored by

ERDA Houston, Tex., April 1977.

15[bldt

jected CO2 were increased by a factor of 1.5 for

the high-process performance case, the ultimate

recovery by CO2 miscible at world oil prices

would be reduced from 13.8 billion barrels to 7.0

billion barrels. Additional discussion is presented

in appendix B.

Significant technological advances were

assumed in application of the surfactant/polymer

process. Specific assumptions are compared in

table 20. The effect of the assumed technological

advances on ultimate recovery for the surfactant/polymer process (shown in table 21) results

in an increase in ultimate recovery from 2.9

billion barrels under current technology to 10.0

billion barrels at high-process performance at

world oil prices.

Table 20

Comparison of Technological Assumptions

for the Surfactant/Polymer Process

Reservoir temperature . . . . . .

Oil viscosity, cp. . . . . . . . . . .

Salinity, ppm. . . . . . . . . . . . . .

Oil content in surfactant slug,

vol. percent. ... , . . . . . . . .

Size of surfactant slug, fraction of volume swept by

preceding waterflood . . . .

Size of polymer bank, fraction

of (region) volume swept

by preceding waterflood. .

Current

Technology

<20 0

o

F

—<20,000”

20

10

1.0

Advancing

technology

<25 0

0

F

< 3 0

<200,000* —

10

10

0.50

*Constraint which could not be applied due to absence of

salinlty data,

Table 21

Comparison of Ultimate Recovery Under Two

Technological Scenarios,

Both Assuming High-Process Performance

Surfactant/Polymer Process

Ultimate recovery

(billions of barrels)

Oil price Current Advancing

$/barrel technology technology

Upper tier ($11.62/bbl) . . . . . 0.2 7.2

World oil ($13.75/bbl) . . . . . 2.9 10.0

Alternate fuels ($22.00/bbl) . 8.8 12.2
Ch. Ill—Oil Recovery Potential ● 4 9

Uncertainty in Projected Production Rates

Production rate projections are influenced by

the following factors:

1)

2)

A vigorous successful research and development and commercial exploitation program

was assumed in the advancing technology

cases. Time was allotted in the economic

model for technical and economic pilot

testing, which is necessary for fieldwide

development. Each stage of testing was

considered successful within a specified

time frame. Development of the field was

planned on a time schedule corresponding

to normal oilfield development.

partial success in initial field tests, low

discovery rates for natural C02

, and a

slower rate of technological advance in the

surfactant/polymer process are examples of

factors which could delay or reduce the production rates projected in this study.

Production rates presented in tables 9

through 14 come from reservoirs which

have a minimum discounted cash flow rate

of return of 10 percent. Full-scale application of a process in a reservoir was done in a

manner which approximates the pattern of

industry investment decisions. In general,

high-risk projects are undertaken early in a

stage of technical development when the

rate of return is high. Projects with 10-percent rate of return are undertaken when the

risk of technical and economic failure is

relatively low.

The timing plan used to construct production rates for the Nation is dependent

upon the projected rate of return for each

reservoir. The economic model assumes

that the reduction of technical and

economic risk will occur at a rate (table 8)

which initiates development of low rate-ofreturn (1 O percent) reservoirs in 1989. A

result of this approximation is that a large

volume of oil is produced after the year

2000 at the world oil price. Earlier or later

reduction of risk could alter the annual production rates appreciably.

The price of oil affects production rates in

two ways. Higher oil prices encourage initia3)

tion of projects at earlier dates. Consequently, production from a reservoir which

comes onstream in 1989 can be obtained at

an earlier date and at a higher price if the

technology is developed. A second effect of

oil price is to add reservoirs at a higher price

which cannot be developed economically

at lower prices.

The rate-of-return criterion is a measure of

risk in an advancing technology where the

risks of technological and economic failures

are high. In these instances, a high rate of

return is required in order for the successful

projects to carry those high-risk projects

which fail.

Failures of a recovery process are not explicitly accounted for in this study. Thus,

the projections of ultimate recovery and

production rates assume a successful application of the process to every reservoir

which meets the technical screen and the

minimum after-tax rate of return. Thus, the

projections have a built-in, but unknown,

measure of optimism.

This optimism is offset to some extent by

the fact that (1) the cost of failure in technical or economic pilot testing is comparatively small, and (2) no attempt was

made to optimize process performance.

Failure of a process in a reservoir at this

stage would reduce the ultimate recovery

and the predicted production rate. Overall

economics for the process would not be significantly affected, provided other projects

were economically successful.

If risk is reduced at a rate slower than that

projected in table 8, only those projects and

processes which have high rates of return

will be pursued. For example, the majority

of the surfactant/polymer flooding candidates have rates of return after taxes of between 10 and 15 percent at the world oil

price for the high-process performance case,

The technology is not proven and a 20-percent rate of return could be required by investors to offset the possibility of process

failure in a given reservoir. If a 20-percent

rate of return is required, few surfactant/polymer projects would be initiated.

!36-594 O - 78 - 5
50 . Ch. 111—011 Recovery Potential

By contrast, steam displacement is a

relatively proven process. Continued

development and use of steam would be

expected at rates of return of between 10

and 20 percent. The impact of high technical and economic risk on the ultimate recovery and production rates for all processes is

illustrated by the comparison in table 22 for

world oil prices. Reductions of 61 percent in

ultimate production and 60 percent in

average production rate for the time period

from 1980 to 2000 are projected under

high-risk conditions.

4) The production rate for the Nation is

affected by environmental regulations and

market conditions in California. Current environmental regulations limit the total emissions from steam generators and air compressors to pollution levels which existed in

1976. Under existing laws, the maximum incremental production rate from thermal

methods in California will be 110,000 barrels per day. The impact of this constraint

on the production rate is shown in table 23

for the advancing technology cases at world

oil prices, Production rates for the Nation

are reduced up to 29 percent for the period

from 1980 to 1995 when constraints are applied. Ultimate recovery is not affected as

the remaining oil will be produced after the

year 2000.

A second factor limiting the development

of thermal methods in California is the

availability of refinery capacity to handle

heavy oil. Heavy oil requires more processing to produce marketable products than do

lighter oils such as Saudi Arabian light or

Prudhoe Bay feedstocks. Ample supplies of

these feedstocks on the west coast could

suppress the development of heavy oil production even if environmental constraints

were removed.

Effect of Uncertainty in Residual Oil

Saturation and Volumetric Sweep on

Projected Results

Residual Oil Saturation

The residual oil saturation in a reservoir following primary and secondary production sets an upper limit to the total amount of oil that could be

produced using any EOR technique, no matter

how good its performance may be. Thus, uncertainty about the residual oil saturation will lead

to comparable uncertainty in the projected production from an EOR project, independent of uncertainty about process performance.

Table 22

High-Process Performance at World Oil Price

($13.75/bbl)

Ultimate recovery

(billion barrels) . . . . . . . . .

Production rate in:

(million barrels/day)

1980 . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . .

2000 . . . . . . . . . . . . . . .

Cumulative production

(million barrels)

1980 . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . .

1990 ... . . . . ., . . . .

1995 . . . . . . . . . . . . . . .

2000, . . . . . . . . . . . . . .

Standard

(1 O-percent

rate of

return)

29.4

0.4

1.0

1.6

3.1

5.2

500

2,000

4,700

8,700

17,300

High risk

(20-percent

rate of

return)

9.5

0.4

0.5

0.7

1.0

1.4

500

1,600

2,700

4,100

6,800

Table 23

Impact of Technological Advances in Emission

Control in California Thermal Recovery Projects on

Projected Rates for the United States at World Oil

Price ($13.75/bbl)

+ + +

Low-process per- High-process perstrained strained strained strained

Ultimate recovery:

(billion barrels) . . . . .

Production rate:

(million barrels/day)

1980 ....., . . . . . .

1985, . . . . .,

1990 . . . . . . . . . . . .

1995 . . . . . . . . . . . .

2000 . . . . . . . . . . . .

11.1 11.1 29.4

0.3

0.5

0.7

1.2

1.7

0.3

0.4

0.5

1.0

1.5

0.4

1.0

1.7

3.1

5.2

29,4

0.3

0.8

1.4

2.8

4.9
The variations in parameters used to compare

the high- and low-process performance cases for

the surfactant/polymer and C02 miscible processes can also be used to simulate the effects of

uncertainties in residual oil saturation.

Specifically, the low-process performance case

approximates a high-process performance case

when the uncertainty in the residual oiI saturation

varies from 15 to 25 percent. As discussed in the

section on Uncertainty in the Oil Resource o n

page 33, these figures represent the range of uncertainty which presently exists in the estimates

of the process parameters.

Volumetric Sweep

The fraction of the reservoir which can be

swept by the surfactant/polymer and C02 miscible processes was assumed to be the region

which was previously contacted during

waterflooding. 16 The volume of this region was

assumed to be known with less certainty than

residual oil saturation.

Two methods have been used to estimate the

fraction of the volume of a reservoir that has

been swept by earlier waterflooding. One

method assigns values to reservoirs based on experience in the geographical region, The second

method, used in the OTA study, is based on a

material balance involving the oil initially present

and the oil produced by primary and secondary

methods.

The effect of these methods of determining

sweep efficiencies was compared for the highprocess performance case for a set of reservoirs

consisting of 59 surfactant/polymer candidates

lbother possible interpretations are discussed in appendix B.

Ch. Ill—Oil Recovery Potential ● 5-1

and 211 onshore CO2 miscible candidates. Use of

estimated volumetric sweep efficiencies yielded

1.1 billion additional barrels of oil at the world oil

price for the surfactant/polymer process. No significant difference was noted for onshore C02

results.

Maximum Oil Recovery by

EOR Processes

Results of all cases show increased ultimate oil

recovery with increased oil price. Further computations for the high-process performance case

revealed that 95.6 percent of the oil considered

technically recoverable would be produced at oil

prices of $30 per barrel or less. Based on these

estimates of technological advances, the

volumes of oil which may be recoverable by

enhanced oil process will not exceed 49.2 billion

barrels for the United States (excluding Alaska).

Thus, of the remaining 283 billion barrels of oil in

the United States, excluding Alaska, 234 billion

barrels are not recoverable under the technological advances assumed in the high-process

performance case, Lower-process performance

would reduce the ultimate recovery appreciably.

Process improvements such as optimization of

well spacing (i. e., infill drilling) and slug size were

not considered in the OTA projections of ultimate recovery for the Nation, The effects of these

improvements are expected to influence the projections less than the uncertainty in process performance. This assessment does not consider the

potential of new processes or process modifications which might be developed at prices of $30

per barrel. These possibilities are not likely to

have an impact on the Nation’s crude oil supply

during the period between 1976 and 2000.
52 . Ch. IlI—Oil Recovery Potential

Comparison With Other Studies

Estimates of the potential oil recovery and/or

production rates resulting from the application of

EOR processes have been published in seven

documents.

17,18,19,20,21,22,23 Four of these 24,25,26,27 a r e

based on surveys and other subjective methods

and, as such, are considered preliminary estimates of the EOR potential for the Nation and not

comparable to the OTA study in methodology,

depth of investigation, or policy analysis.

Three of the studies28,29,30 used a methodology

similar to that used in the OTA study to estimate

17 ~~e ~stj~dtecj Recovery Potentia/ of conventional

Source Domestic Crude Oi/, Mathematical, Inc., for the Environmental Protection Agency, May 1975.

IBpro~ect /ndepenc/ence Report, Federal Energy Administration, November 1974.

lgP/ann/ng criteria Relative to a National RD T& D Program

to the Enhanced Recovery of Crude Oi/ and Natura/ Gas, Gulf

Universities Research Consortium Report Number 130,

November 1973.

zOPre//m/naryFje/d Test Recommendations and ~fOSpeCtive Crude Oil Fields or Reservoirs for High Priority Testing,

Gulf Universities Research Consortium Report Number 148,

Feb. 28, 1976.

21 Tbe Potentia/ and Economics of Enhanced Oil Recovery,

Lewin and Associates, Inc., for the Federal Energy Administration, April 1976.

zzResearch and Development in Enhanced Oil Recovery,

Lewin and Associates, Inc., Washington, D. C., November

1976.

ZjEnhanced Oil Recovery, National Petroleum council,

December 1976.

ZqThe Estimated Recovery Potentia/ of Convention/

Source Domestic Crude Oil, Mathematical, Inc., for the Environmental Protection Agency, May 1975.

25 Project, /dependence Report, Federal Energy Administration, November 1974.

26~/ann/ng criteria Relative to a Nat;ona/ RDT&D Program

to the Enhanced Recovery of Crude Oil and Natural Gas, Gulf

Universities Research Consortium Report Number 130,

November 1973.

ZTPre//mjnary Fie/d Test Recommendations and Prospective Crude Oil Fields or Reservoirs for High Priority Testing,

Gulf Universities Research Consortium Report Number 148,

Feb. 28, 1976.

Z19 The poCentia/ and Economics of Enhanced Oil Recovery,

Lewin and Associates, Inc., for the Federal Energy Administration, April 1976.

2qResearch and Development in Enhanced Oil Recovery,

Lewin and Associates, Inc., Washington, D. C., November

1976.

jOEnhanced 0// Recovery, National petrO!eUWI COUnCil,

December 1976.

EOR potential. These studies are (1) the projections of enhanced oil recovery for California,

Texas, and Louisiana, prepared by Lewin and

Associates, Inc., for the Federal Energy Administration (FEA) (April 1976);31 (2) the research

and development program prepared by Lewin

and Associates, Inc., for the Energy Research and

Development Administration (ERDA) (November

1976); 32 and (3) an analysis of the potential for

EOR from known fields in the United States prepared by the National Petroleum Council (NPC)

for the Department of the Interior (December

1976).33

The methodologies of these studies are

analogous in that the potential oil resource was

determined using a reservoir-by-reservoir

analysis. Each reservoir in the respective data

base was considered for a possible EOR project.

One or more EOR process was assigned to the

reservoir. Oil recovery and economic simulations

were made in a manner closely approximating

commercial development in the oil industry. Ultimate production and production rates from

economically acceptable reservoirs were used to

extrapolate to the State and national totals.

Data bases varied somewhat between studies.

The Lewin FEA and NPC studies used a common

data base consisting of 245 reservoirs from

California, Texas, and Louisiana. This data base

was expanded to 352 reservoirs in 17 oil-producing States by Lewin and Associates, Inc., for their

ERDA study. The OTA study incorporated,

revised, and expanded the Lewin ERDA data base

to 835 reservoirs containing 52 percent of the

ROIP in the United States, as described in the

section Original Oil in Place on page 23.

Cost data for development and operation of

typical oilfields were obtained from the U.S.

M The potentja/ and Economics of Enhanced Oi/ Recovery,

Lewin and Associates, Inc., for the Federal Energy Administration, April 1976.

jzResearch and Deve/oprnent in Enhanced Oi/ Recovery,

Lewin and Associates, Inc., Washington, D. C., November

1976.

jjEnhanced 0// Recovery, National petrOleum CoUnc il,

December 1976.
Ch. III--Oil Recovery Potential . 53

Bureau of Mines34 for all studies. Adjustments

were incorporated to account for price changes

between the reference dates for each study.

Results of these studies are compared with

OTA projected results in table 24 for 1976 upper

tier and world oil prices. There is agreement In

the order of magnitude of the ultimate recovery

among all the studies. The NPC projections include a base case which represents best estiJqResearch and Development in Enhanced Oil Recovery,

Lewin and Associates, Inc., Washington, D. C., November

1976 .

mates of process performance and associated

process costs, and a range of uncertainty in the

base case estimates due to poorer or better than

expected process performance. Estimates from

the OTA low-process performance case are within the NPC range of uncertainty for all oil prices.

The OTA high-process performance case estimates more oil recovery than the upper estimates

of the NPC study. At the world oil price, the OTA

estimate is about 24 percent higher. The Lewin

ERDA cases for upper tier price and $13 per barrel

are close to the range of OTA values. The OTA

projections are lower than the Lewin FEA results

for California, Texas, and Louisiana, even if oil

Table 24

Projections of Ultimate Recovery and Production Rate From the

Application of Enhanced Oil Recovery Processes

Study

O T A

Low-process performance. . . . . . . . . . . . . .

High-process performance . . . . . . . . . . . . .

NPC’

Poor performance . . . . . . . . . . . . . . . . . . . .

Expected performance (base case) . . . . . . .

Better performance . . . . . . . . . . . . . . . . . . .

Poor performance . . . . . . . . . . . . . . . . . . . .

Expected performance (base case) . . . . . . .

Better performance . . . . . . . . . . . . . . . . . . .

ERD A

b

Industry base case**. . . . . . . . . . . . . . . . . . .

Industry base case w/ERDA R&D** . . . . . . .

FEA

California, Texas, and Louisiana . . . . . . . . .

Lower Bound, . . . . . . . . . . . . . . . . . . . . . .

Upper Bound. . . . . . . . . . . . . . . . . . . . . . .

Reference

date

1976

1976

1976

1975

Minimum

rate of

return for

projection

10 %

10 %

00/0

20%

80/0

Oil

price

($/bbl)

11.62

13.75

11.62

13.75

10.00

15,00

11.63

13.00

11.63

13.00

11.28

11.28

Potential

ultimate

recovery

(billion

barrels)

8.0

11.1

21.2

29.4

3.1

7.2

13.4

6.3

13.2

26.9

11.9

13.1

26.2

30.1

15.6***

30.5.

Potential

production

rate in 1985

(million

barrels/day)

0.4

0.5

0.5

1.0

0.4

0.4

0.9

1.6

0.6

0.6

1.7

2.1

1.0

2.0

‘“current tax case, 10-percent investment credit and expensing of injection materials and intangibles, with current environmental constraints,

“**Reserves added by the year 2000.

‘Enhanced Oil Recovery, National Petroleum Council, Decemberl 976.

h~e~earchand Deve/oPmenl in ~nhanced Oi/ Recovery, Lewin and Associates, Inc., for the Energy Research and Development Administ

ration I

November 1976.

‘ The Potential andEconomtcs of ErrbarrcedOllRecovery, Lewinand Associates, Inc., for the Federal Energy Administration, April 1976.
54 . Ch. Ill—Oil Recovery Potential

price, rate of return, and costs were placed on the

same basis.

Estimates of producing rates in 1985 vary

widely between studies. In general, the OTA

projections are within the range of the NPC basecase study results and the Lewin industry basecase simulation. The OTA results are lower than

the Lewin ERDA research and development case

and the Lewin FEA projection for California,

Texas, and Louisiana. The apparent agreement in

producing rates between the OTA high-performance case and the Lewin ERDA case does not

constitute confirmation of projections from independent studies for reasons outlined in a later

section.

OTA-NPC Results

The OTA study team was provided access to

all reports, oil recovery models, cost data, and

results from the NPC study. Comparisons of projected ultimate recovery and production rates

were made on a reservoir-by-reservoir basis. The

same reservoirs which were included in the NPC

base case for C02

, surfactant/polymer, steam,

and in situ combustion processes were studied in

detail using NPC models and OTA models. All

differences between OTA and NPC results can be

traced to differences in recovery models, supplies

of injected materials, costs of injected materials,

and, in some cases, the timing plan used in the

simulation to initiate projects.

The NPC study included a geological screen in

which individual reservoirs were judged as good,

fair, poor, or no EOR, based on qualitative information on the geology of each reservoir gathered

from industry sources. The OTA study assumed

all reservoirs had the same quality since geological information was available on only a small portion of the reservoirs in the data base. No reservoir was rejected for geological reasons, with the

exception of those with a large gas cap which

might prevent waterflooding.

The distribution of oil in a reservoir was

treated differently in the OTA models. The OTA

models assume 95 percent of the remaining oil is

located in 80 percent of the reservoir acreage. All

oil produced by. EOR processes is developed

from the reduced portion of the acreage. This

assumption was implemented by increasing the

net thickness in the region developed. The use of

economic models to determine the EOR process

when two or more processes were possible led to

different assignments of many reservoirs in the

OTA study.

Major differences between the NPC and OTA

results are:

a. Recovery from application of C02 displacement in the OTA high-process performance

case exceeds NPC estimates by a factor of

about two at all oil prices for which calculations were made. Comparable recovery

models were used and the agreement in

ultimate recovery for reservoirs common to

both studies is reasonably close, In Texas,

the OTA recovery at world oil price by C02

flooding is about 5.6 billion barrels. The corresponding NPC recovery is a little over 4.0

billion barrels.

The NPC geological screen eliminated

certain reservoirs in Texas from their study

which OTA’s study calculated would produce about 0.5 billion barrels of oil with the

C02 process. When extrapolation was made

to the entire State, this amounted to about

0.9 billion barrels. Considering the Texas

results, as well as the entire Nation, the NPC

geological screen accounts for part of the

difference but is not considered the major

factor,

Expansion of the data base to other oilproducing States and offshore Louisiana

resulted in more reservoirs as potential candidates for C02

. A result was that considerably more oil was produced from States other

than Texas, California, and Louisiana in the

OTA study than was projected in the NPC

report. In addition, in the OTA study at the

world oil price, an ultimate recovery of 0.9

billion barrels was projected to be produced

from offshore reservoirs that were not in the

NPC data base (table 13).

Oil recovery for the NPC C02 models

varied according to geologic classifications

of good, fair, and poor. The OTA recovery

models were designed to represent an
“average” reservoir. The use of this

“average” reservoir in the OTA study may

account for a significant portion of the

difference in results for the three States of

California, Texas, and Louisiana.

Significantly different pricing plans for the

C O2 resource were used by OTA and NPC,

Prices used were similar in geographical

areas such as western Texas, which have a

high probability of obtaining supplies of

natural C02 by pipeline. However, for other

areas such as Oklahoma and Kansas there is

less certainty of carbon dioxide pipelines

and the pricing plans were quite different. In

general, the NPC study used a significantly

higher cost for C 02 in these areas. This is

considered to be a major reason for the

difference in results for the Nation. The

OTA C 02 pricing model is given in appen -

dix B.

b. Oil recovery from OTA surfactant/polymer

projections for the low-process performance case at $13.75 Per barrel (2.3 billion

barrels) is bounded by the NPC base case

(2.1 billion barrels) and the NPC 5-year project life case (5.6 billion barrels) at $15 per

barrel. (The NPC base case used a 10-year

life while OTA models assumed a 7-year

life.) The OTA high-process performance

case at world oil price (10.0 billion barrels)

projects about 1.0 billion barrels Iess oi l

recovery than the NPC better-than-expected performance projections (1 1.2

billion barrels) at $15 per barrel.

Two factors are the primary contributors

to the slight differences in results of the two

studies. First, more than twice as many OTA

reservoirs were assigned to the surfactant/polymer process as in the NPC study.

Forty-five percent of these reservoirs were

not in the Lewin FEA data base used by NPC.

A second difference in the results was

due to NPC’s assignment of higher chemical

costs to reservoirs which were ranked poor

in the geologic screen. The OTA study

assumed all reservoirs were of the same

quality. Comparable projections of ultimate

c.

Ch. ///—Oil Recovery Potential . 55

recovery at a specified oil price were obtained on individual reservoirs which had

the same geological ranking and swept

volume in both studies. Sensitivity analyses

show agreement of the low-process

performance projections and projections

made by increasing chemical costs so that

all reservoirs were “poor.”

Some differences were attributed to the

approaches used to estimate the volume of

each reservoir swept by the surfactant

flood. A discussion of this is included in the

section on Volumetric Sweep on page 51.

No offshore reservoirs were found to be

economically feasible for application of the

surfactant/polymer process in the OTA

study. The NPC results included an estimate

of 261 million barrels from offshore Louisiana reservoirs at $15 per barrel,

The OTA estimates of oil recoverable by

thermal methods are within the range of uncertainty projected in the NPC study. The

OTA low-process performance estimates

are within 0.4 billion barrels (12 percent) of

NPC base-case projections at prices between $10 per barrel and $15 per barrel.

Projections for the OTA high-process performance case at these prices are about 1.0

billion barrels less than performance from

the NPC high-recovery estimates. Comparisons by process are included in appendix B.

Oil recovery models for thermal processes in the NPC study were developed for

areas with uniform reservoir properties.

Projected recoveries from reservoir-wide

application of these models were adjusted

to account for variation of reservoir properties and process performance. This was

done by reducing the ultimate recovery for

uniform reservoir and process performance

by factors of 0.7, 0.6, and 0.5, corresponding to the NPC geological screen of good,

fair, or poor. Large reservoirs were subdivided into two or three areas judged to

have different quality. Multiple-zone reservoirs were developed simultaneously.

Crude oil consumed as fuel was deducted
56 ●

d .

e.

Ch. 111—011 Recovery Potential

from gross production prior to computation

of royalty and severance taxes.

The OTA thermal recovery models were

developed to represent the average reservoir performance. Reservoirs were not

assigned geological rankings based on reservoir quality. Multiple-zone reservoirs were

developed zone by zone. Royalty and

severance taxes were paid on lease crude

consumed as fuel. This is a significant cost,

as about one-third of the production in

steam displacement projects is consumed as

fuel.

polymer flooding models in both studies

produce comparable results when polymer

injection is initiated at the beginning of a

waterflood. Some differences exist for

waterfloods which have been underway for

some period of time. The NPC recovery

model projects a decline in oil recovery

with age of waterflood, while the OTA

study does not. Polymer flooding does not

contribute much oil in either study.

The NPC study projected recovery from

alkaline flooding. The OTA stud y

acknowledges the potential of alkaline

flooding for selected reservoirs but did not

include the process for detailed study.

Reservoirs which were alkaline-flood candidates in the NPC study became candidates

for other processes in the OTA study.

OTA-FEA, ERDA Results

The OTA study used the economic programs

and timing plans for reservoir development

which were used to produce the results for the

Lewin and Associates, Inc., studies for FEA and

ERDA. Oil prices and a minimum acceptable rate

of return (1 O percent) were selected for the OTA

study. Costs of injected materials were obtained

from both Lewin and NPC studies. Oil recovery

models for the OTA study were developed independently of previous Lewin studies. The FEA

study reported projections for three States;

California, Texas, and Louisiana. The ERDA results

include data from 17 oil-producing States while

the OTA results use data from 18 oil-producing

States. Projections for the Nation in the OTA and

ERDA studies were obtained by summing State

totals.

The OTA advancing technology cases assume

a vigorous research and development program,

although the stimulus for the program was not

identified. Lewin and Associates, Inc., ERDA

program assumes all improvements in recovery

over an industry base case comes from an extensive ERDA R&D program which removes environmental and market constraints for thermal operations in California, results in improved recovery

efficiencies for processes, and extends the processes to reservoirs not considered candidates in

the industry base case. Targeted R&D projects

were identified for specific reservoirs.

The documentation of anticipated improvement in the various processes is described in the

report. 35Incremental process costs and process

performance associated with proposed process

improvements were not identified. Consequently, there is no basis for a direct comparison

with the Lewin ERDA projections resulting from

an extensive R&D program. The agreement between OTA projections and the Lewin ERDA

projections should not be considered confirmation of either study by independen t

methodology.

Although the ultimate recoveries and rates

from the Lewin studies are close to the OTA

results, there are significant differences in the

assumptions which were used to develop the

results. Distributions of oil recovery by process

are also different. Principal differences between

the OTA and Lewin studies involve the projected

recovery for each process.

The Oil recovery models used by Lewin and

Associates, Inc., for the FEA and ERDA studies

were reviewed on a reservoir-by-reservoir basis.

Comparisons between OTA recovery models and

Lewin models produced the following observations:

a. Recoveries from the C02 flooding process

are comparable in specific reservoirs. The

jSResearch and Development in Enhanced Oil Recovery,

Lewin and Associates, Inc., Washington, D. C., November

1976.
OTA high-process performance case, at the

world oil price, projects about a 40 percent

greater ultimate recovery from CO2 than the

total for the Lewin ERDA research and

development case plus the industry base

case. A primary reason is the presence of additional reservoirs in the extended data base

of the OTA study. The OTA low-process

performance result is about half the Lewin

ERDA value at world oil price. Costs of

manufactured COZ in some areas are higher

than in the Lewin study and this contributes

in a minor way to the differences.

There are large differences between projections of ultimate recovery from the steam

displacement process. The ERDA industry

base case estimates ultimate recovery to be

66 billion barrels at $13 per barrel. lncrementaI oil expected from proposed ERDA

R&D,, , programs 8.2 billion barrels at the

same price. Thus, an ultimate recovery of

14.8 billion barrels is projected from steam

displacement as a result of ongoing industry

activity and proposed ERDA R&D programs.

The OTA study projects an ultimate

recovery of 3.3 billion barrels from steam

displacement processes at $13,7’5 per barrel. This projection is lower than the ERDA

industry base case by a factor of 2, and is

lower than the ERDA industry base case

with ERDA R&D by a factor of 4.5. The OTA

and ERDA projections of ultimate recovery

from steam displacement vary over a large

range because of differences in specific

technological advances which were incorporated in the displacement models. Major

differences are discussed in the following

paragraphs.

About one-third of the oil produced in a

steam displacement process is consumed to

generate steam. The amount of steam produced by burning a barrel of lease crude is

not known with certainty. The OTA computations assumed 12 barrels of steam were

produced per barrel of oil consumed, while

the ERDA models assume 16 barrels of

steam per barrel of oil. Applying the ERDA

factor to OTA computations would increase

the ultimate recovery about 10 to 15 perCh. ///—Oil Recovery Potential ● 57

cent. Differences of this order of magnitude

are not considered significant.

Replacement of crude oil by a cheaper

source of energy such as coal is a proposed

ERDA steam program. Incremental production of 1.0 billion barrels was expected from

this program. A successful program could increase the net crude oil produced by a factor of one-third in fields where it could be

impIemented. However, widespread

substitution of coal for lease crude would

have to be done in a manner which would

satisfy environmental constraints. 36 T h e

OTA study doe s not evaluate this

possibility.

One ERDA program for steam projects an

ultimate recovery of 1.8 billion barrels from

light-oil reservoirs (less than 25oAPI) in

Texas, Louisiana, and the midcontinent by a

steam distillation process. This process was

not considered in the OTA study. implementation of steam distillation on an

economic scale requires development of a

fuel for steam generation which is less expensive than lease crude oil. These reservoirs were assigned to other processes in

the OTA study.

The principal difference between ERDA

and OTA projections is in the recovery

models for the steam displacement process.

The ERDA steam model was developed

using data from current field operations

which are generally conducted in the best

zones of a reservoir. Every part of the reservoir is considered to perform like the

regions now under development. Steam

drive was limited to depths of 2,500 feet in

the ERDA industry base case. Increase in the

depth to 5,000 feet added 1.6 billion barrels

in the ERDA R&D case. The ERDA R&D

program includes anticipated improvements

in recovery efficiency for reservoirs which

are less than 2,500 feet deep. The eventual

MERDA Workshops on Thermal Recovery of Crude Oil,

University of Southern California, Mar. 29-30, 1977.

~71bid.
58 . Ch. 111—011 Recovery Potential

R&D goal for these reservoirs was to improve the overall recovery efficiency of

steam drive by 50 percent. Incremental ultimate recovery for this program was expected to be 2.3 billion barrels.

The OTA steam displacement models are

based on development of the entire reservoir using average oil saturations and recovery efficiencies. All reservoirs 5,000 feet in

depth or less were developed. The OTA

models underestimate recoveries from the

better sections of a reservoir and overstate

recoveries from poorer zones. OveralI

recovery from the OTA models is believed

to be representative of the average reservoir

performance.

Closer agreement between the ERDA industry base case and the OTA projections at

the world oil price can be obtained by

reducing the ratio of injection wells to production wells, thereby reducing the capital

investment. The ERDA industry base case

assumes fieldwide development on the

basis of 0.8 injection well per production

well. The OTA advancing technology cases

used 1.0 injection well per production well.

Reduction of the number of injection wells

to 0.3 per production well in the OTA computations makes steam displacement

economic in several large California reservoirs at the world oil price. Ultimate recovery at this price increases from 3,3 billion

barrels (one injection well/production well)

to 5.3 billion barrels (0.3 injection

weIl/production well). Producing rates increase correspondingly. This comparison indicates potential improvements could result

from optimizing well spacing. Additional

results are included in appendix B.

In summary, steam displacement projections in the ERDA industry base case and

ERDA R&D case assume more technological

advances than judged to be attainable in the

OTA study.

c. OTA surfactant/polymer projections for

both low- and high-process performance

cases fall between the projections from

Lewin’s ERDA industry base case and

Lewin’s FEA results for California, Texas, and

Louisiana, for different reasons. Projected

surfactant recoveries in the Lewin FEA study

ranged between 3.8 billion barrels and 8.8

billion barrels at $11 per barrel. These projections are larger than OTA projections

under the same economic conditions

because the recovery models are based on

different representations of the displacement process.

The industry base case for ERDA limits application of the surfactant/polymer process

to shallow homogeneous reservoirs in the

midcontinent. Ultimate recovery was estimated to be 0.6 billion barrels at $13 per

barrel. This corresponds to the OTA projected recovery of 2.3 billion barrels at the

world oil price for the low-process performance case and 10 billion barrels for the

high-process performance case. The ERDA

R&D program for the surfactant/polymer

process projects an ultimate recovery of 1.4

billion barrels at the world oil price.

California reservoirs, which are major surfactant/polymer contributors in the OTA

study, were excluded from the ERDA industry base case by assuming that technology

would not be developed in the absence of

the ERDA R&D program. The OT A

methodology resulted in assignment of

more reservoirs to the surfactant/polymer

process than in the ERDA cases. A major

difference exists in volumes and costs of

chemicals used in the ERDA calculations.

These volumes approximate those which

have been tested extensively in shallow

reservoirs in Illinois. The OTA advancing

technology cases project technological advances which would reduce the volumes of

chemicals required. This has a profound

effect on the development of the surfactant/polymer process, as the projected

recovery for the high-process performance

case at the world oil price is reduced from

10 billion barrels to 2.9 billion barrels when

OTA current technology surfactant and

polymer slugs are used in the economic

model.
d

Ch. ///—Oil Recovery Potential . 59

Ultimate recovery from polymer flooding polymer model projects less recovery than

varies from 0.2 billion to 0.4 billion barrels the Lewin mod-cl ‘for specific reservoirs.

at the upper tier price in the OTA pro- There were more reservoirs assigned to the

jections compared to 0.1 billion barrels in polymer process in the OTA methodology.

the ERDA industry base case. The OTA

Technological Constraints to EOR

Technological constraints are only one of

several barriers to widespread commercialization

of EOR38 that include economic risks, capital

availability, and institutional constraints. These

constraints are coupled, and all must be removed

or reduced to achieve major oil production from

EOR processes.

The following section identifies and discusses

the technological constraints that must be addressed in order to achieve the rate of progress

that is postulated in the advancing technology

case.

The technological constraints on EOR have

been grouped in the following categories:

1. Resource availability.

2. Process performance,

3. Reservoir characteristics.

4. Materials availability.

5. Human resources.

6. Environmental impact.

7. Rate of technological evolution.

Resource Availability

The magnitude of the oil resource for EOR is

not certain. The uncertainty is estimated to be 15

to 25 percent. Although this range may not seem

large for the national resource, variation among

reservoirs probably is larger. Furthermore, a small

reduction in remaining oil in a reservoir may

make it uneconomical to apply a high-cost EOR

process at all, thereby leading to a disproportionate reduction in economically recoverable oil,

The difference may be as high as the difference

between the advancing technology-high- and

38&janagement plan for Enhanced Oil Recovery, ERDA,

Petroleum and Natural Gas Plan, ERDA 77-15/1, p. 11-1,

February 1977.

low-process performance

to 18 billion barrels at

cases, which amounts

the world oil price,

equivalent to about half the current U.S. proved

reserves.

Resource uncertainty represents a major technical and economic risk for any EOR project in

any reservoir. Reduction of this risk would need

high priority in any national program to stimulate

EOR production.

Sampling a reservoir through core drilling, logging, and other well testing is an expensive, inexact, developing technology. The problem is that

of finding methods which will probe outward a

sufficient distance from a well bore to determine

oil content in a large fraction of the region

drained by the well. A further complication exists

in that oil saturation variations occur both

horizontally and vertically within a reservoir.

Determinations at one well may not be applicable at other well sites.

A program to stimulate EOR production should

contain a major effort to promote measurement

of residual oil saturations in key reservoirs until

confidence is gained in methods to extrapolate

such data to other locations in the same reservoir and other reservoirs. Equal emphasis should

be placed on the gathering of such data and on

the improvement of measurement methods.

Process Performance

Process Mechanisms

Enhanced oil recovery processes are in various

stages of technological development. Even

though steam drive is in limited commercial

development, the outer limits of its applicability

are not well understood. Steam drive can probably be extended to light oil reservoirs but it has
60 . Ch. ///—Oil Recovery Potential

not been tested extensively. Larger gaps in

knowledge exist for other processes and process

modifications which are in earlier stages of

development. Field tests have consistently been

undertaken with incomplete knowledge of the

process mechanism. Most laboratory tests of

processes are done on systems of simple geometry (generally linear or one-dimensional flow),

leaving the problems that occur because of the

more complex flow geometry to field testing.

As indicated in the section on Process Field

Tests on page 61, extensive field testing of EOR

processes will be required. As more field projects

are undertaken, the tendency of industry is to

shift research personnel from basic and theoretical studies to development activities. If this effort

is widespread it may limit the ability of companies to undertake fundamental EOR research. If

this trend continues, additional public support

for basic research applicable to EOR may become

advisable.

A major industry /Government coordinated

effort is needed to thoroughly define the process

mechanisms for each of the recognized basic EOR

processes and process modifications, This effort

would need to be initiated immediately and to

proceed at a high level of activity for at least 5

years if the postulated rate of EOR applications is

to be achieved.

Volumetric Sweep Efficiency

Recovery efficiency of all processes depends

upon the fraction of the reservoir volume which

can be swept by the process, i.e., sweep efficiency. Thus a strong economic incentive exists for

improvement of volumetric sweep. Research in

this area has been carried out for a number of

years by many sectors of the oil production, oil

service, and chemical industries. The importance

to EOR success of improving sweep efficiency

has been confirmed in a recent assessment of

research needs.40

MERDA workshops on Thermal Recovery of Crude oil,

University of Southern California, Mar. 29-30, 1977.

JO~eC~~jCa/ plan for a Supplementary Research Program

To Support Development and field Demonstration of

Enhanced Oil Recovery, for U.S. Energy Research & Development Administration, Washington, D. C., GURC Report No.

154, Mar. 17, 1977.

Despite the long-term effort on this problem,

success has been limited. Solutions are not

available for each process. Improvements are

needed for each individual process and each

process variation as well as for major classes of

reservoirs. Progress will be difficult and will require major field testing supported by extensive

prior laboratory work. This research effort, both

basic and applied, must be significantly stimulated in the next 3 to 6 years in order to approach

the estimated EOR production potential for the

period between 1976 and the year 2000.

Brine-Compatible Injection Fluids

Enhanced oil recovery processes will be used

largely in those parts of the country that face increasing shortages of fresh water. For surfactant/polymer and polymer flooding, relatively

fresh water is still needed both for the polymer

and surfactant solutions and for reservoir

preflushing. Even where fresh water is available

for preflushing, it is often not efficient in displacing brine. Consequently, injected fluids in such

reservoirs must be brine compatible. Continued

laboratory and field research is needed to

develop surfactants and other oil-recovery agents

which are brine compatible.

In the present study, brine compatibility of injected fluids was assumed in the advancing technology cases. Data were not available in the OTA

data base to assess the importance of this

assumption, but it is known to be significant.

Development of Additional Processes

Applicable to Carbonate Reservoirs

Although carbonate reservoirs represent approximately 28 percent of the initial oil in place

in the United States,41 the C02 miscible process is

the only EOR process currently applied to such

reservoirs, There is a possibility of using steam

flooding in some carbonate reservoirs, 42 a n d

other processes or process modifications should

41 Reserves of Crurje Oi/, Natural Gas Liquids, and Natural

Gas in the United States and Canada as of December 31,

7975, Joint publication by the American Gas Association,

American Petroleum Institute, and Canadian Petroleum

Association, Vol. 30, May 1976.

JZEnhanced Oi/ Recovery, National Petroleum COUncil,

December 1976.
Ch. III-Oil Recovery Potential ● 6 7

be tested for carbonate reservoirs because of the

possibility of C02 shortages and because of the

high cost of delivering CO2 to areas that might

not be served by pipelines.

Operating Problems

Operating problems of EOR are more severe,

less predictable, and certainly less easily controlled than operating problems one faces in a

plant making a new chemical product, but the industrial sector is equipped to solve such

problems. For example, steam is now generated

from high-salinity brines, a process that once

seemed to pose serious technical problems. Most

such problems, however, must be solved within

the next 6 to 8 years if the potential production

represented by OTA’s advancing technology

case is to be achieved.

Some problems exist where Government

assistance could be beneficial. Design of steam

generators for steam-drive projects that will meet

environmental pollution-control standards and

use cheaper alternate fuels (heavy crudes, coal,

etc.), as well as large-scale steam generation, are

areas that have been recently highlighted. 43

Equipment for retrofitting existing generators to

permit them to meet new standards and lower

their unit pollution level is also needed.

Process Field Tests

The current ERDA field testing program is a

vital step in accelerating EOR process commercialization, If the upper targets of any of the recent predictions of EOR potential are to be

achieved, a significant increase is needed in the

rate of technical progress. To achieve this, the

level of field tests needs to be significantly increased. While OTA did not attempt to estimate

the optimal number, a study by the Gulf Universities Research Consortium (GURC) estimated

100 as a target group.44 It is important that ERDAsponsored field tests be part of an EOR research

strategy designed to complement industry’s

AJERDA Workshops on Thermal Recovery of Crude Oil,

University of Southern California, Mar. 29-30, 1977.

44A Survey of ~je/cf Tests of [nhanced Recovery Methods

for Crude Oil, for FEA and the National Science Foundation,

Washington, D. C., GURC Report No. 140-S, Nov. 11, 1974.

efforts and to provide information that can be

generalized to a variety of classes of reservoirs,

The status of current field tests taken from the

Lewin ERDA report45 is shown in table 25.

There are at least three levels of field tests:

minitests, single- or multi pattern-pilot tests, and

fieldwide commercial testing.

Single- and multipattern-pilot tests should be

directed at determining potential economic success and to thoroughly defining the technical performance. To maximize the value of such field

tests, extensive pre- and post-test well coring,

logging, fluid analysis, and laboratory tests are required to understand the process well enough to

provide a strong knowledge base for operating at

full scale in test reservoirs. Data acquisition is expensive and time consuming, and the record indicates that too little data are being gathered.

Government support for such activities may be

required if the postulated rate of technological

advance is to be achieved.

Special consideration should be given to testing more than one process in a reservoir and to

undertaking processes in reservoirs that offer new

ranges of application of the process.

There is some current concern about the relative merits of minitests (one to two well tests at

small well spacing) compared with larger singleor multipattern-pilot tests. Both can be helpful.

The minitest is faster, less expensive, and may be

helpful in initial process or reservoir screening.

However, its lower cost and greater simplicity do

not substitute for the greater degree of understanding that can come from multi pattern tests.

The number of projects that should be undertaken for fieldwide commercial demonstration is

not easily determined. A case can be made for at

least one such test for every major process that

has not yet reached commercialization. The options of cost sharing, risk sharing, and/or support

through special price or tax provisions should all

be considered. Considerations of the merits of

such alternatives, the scale of operations, and the

applicable processes were outside the scope of

ASReSearCh and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D.C. Part 1, p. III-2,

November 1976.
—.

62 . Ch. Ill—Oil Recovery Potential

Table 25

Field Activity in Enhanced Oii Recovery

Technique

Steam drive. ., . . . . . . . .

In situ combustion . . . . .

C O2 miscible and

nonmiscible. . . . . . . . .

Surfactant/polymer. . . . .

polymer-augmented

waterflooding . . . . . . .

Caustic-augmented

waterfloodlng . . . . . . .

Hydrocarbon miscible . .

Totals. . . . . . . . . . . .

Technical

1

Total

17

17

5

12

3

5

9

68

lots

Current

13

3

4

10

0

1

7

44

Number of EOR Proiects

Economic

pil

Total

15

6

6

7

14

2

6

57

ots

Current

14

5

6

7

9

0

5

47

Fieldwlde

devel

Total

15

19

2

2

14

0

10

62

]ment

Current

15

10

2

2

11

0

8

48

Acreage under

current

development

15,682

4,548

38,618

1,418

14,624

63

56,782

131,735

“From Research and Development in Enhanced Oil Recovery, Final Report, Lewin & Associates, Inc., Washington, D. C., ERDA 77-20/1,2,3,

December 1976.

this study. However, the issue needs to be addressed within the next year or two. This test

program is a facet of the Government program

that deserves a major emphasis.

Reservoir Characteristics

Uncertainty concerning the physical and

chemical nature of an oil reservoir is one of the

most severe technological barriers to EOR processes.

46 Not only are reservoirs significantly

different among themselves, even within the

same geological class, but the place-to-place

variations in thickness, porosity, permeability,

fluid saturation, and chemical nature can be discouragingly large. The present ability to describe,

measure, and predict such variability is extremely

limited. Knowledge to measure and predict this

variability within a reservoir is vitally important

for forecasting fluid movement and oil recovery

efficiency. Research efforts have so far been

directed toward studying portions of individual

reservoirs intensively, with little attention given

to generic solutions.

46 Technjca/ p/an for a Supplementary Research prOgram

To Support Development and Field Demonstration of

Enhanced Oil Recovery, for U.S. Energy Research and

Development Administration, Washington, D. C., GURC

Report No. 154, Mar. 17, 1977.

Any major governmental research effort to accelerate oil production from EOR processes

should include development of methods to

measure, describe, and predict variations in properties throughout a reservoir. Extensive field and

laboratory studies are warranted.

Raw Materials Availability

Enhanced oil recovery processes use both

natural and manufactured raw materials.. Shortterm shortages of manufactured materials could

exist for all EOR processes if a vigorous national

program were launched to produce EOR oil.

The supply of two natural resources, fresh

water and C02

, may limit ultimate recovery from

steam injection, surfactant/polymer, and C02

miscible processes. Local shortages may develop

for adequate supplies of fresh or nearly fresh

water in some areas in which polymer flooding or

surfactant/polymer flooding is initiated. Most

areas of known fresh water shortage either have

or are developing criteria for allocation of the

scarce supply among competing classes of use. A

major technological challenge for EOR lies in

development of economic means for using water

with higher saline content for all processes in

which water is needed. The problem seems to

have been solved for steam generation. Brine of

up to 20,000 ppm can be used successfully.
Carbon dioxide availability is central to any

major expansion of C02 flooding. As mentioned

previously, the quantity needed (a total of 53 Tcf

in the advancing technology-high-process performance case at world oil prices) is a volume

almost three times the annual volume of natural

gas consumed in the United States.

The economic potential of C02 flooding is so

great that a Government effort to accelerate EOR

production should include not only locating

natural sources of carbon dioxide but also exploring ways to produce it economically from largescale commercial sources. Locations of known,

naturally occurring C O2 sources are summarized

in the recent NPC study of EOR.47 The magnitude

of the reserves of CO2 at these locations is not

known. ERDA is currently involved in a nationwide survey of CO2 availability.

Human Resources

Shortages of technically trained people to

operate EOR projects may exist temporarily if a

major national EOR effort is undertaken. National

projections of needs for technically trained people have not been highly accurate. Data are not

readily available on industrial needs since many

firms do not make formal, continuing, long-range

personnel forecasts. The efforts of ERDA and

other agencies in national manpower forecasting

could be encouraged.

All EOR processes are extremely complex compared to conventional oil recovery operations.

Because of this technical complexity, highly competent personnel must be directly involved in

each EOR project on a continuous basis at the

managerial, developmental, and field operations

level. Without close monitoring by qualified

technologists, the odds for success of EOR projects will be lower, There currently is a mild shortterm shortage of persons to work on EOR projects. National forecasts48 of the number of available college-age students (all disciplines) indicate

qTf~~a~Cecj 0;1 Recovery, National petroleum Council,

December 1976.

qa~rojectfon of [durational Sta[lstics to 7985-86, National

Center for Educational Statistics, Publ. NCES 77/402, p. 32,

1977.

Ch. ///—Oil Recovery Potential ● 63

a significant enrollment decline over the period

of greatest potential EOR activity. The supply of

technical people (engineering, science, and business) available for EOR operations will crucially

depend upon the economic climate in other sectors of the economy. In a generally favorable

economic climate, increasing competition for

qualified personnel could develop.

Environmental Effects

For most EOR processes and in mos t

geographical areas, accommodation to environmental protection regulations will not be a critically restrictive requirement. Details of environmental impacts and an estimate of their severity

and magnitude are described in chapter VI of this

report. The environmental effects that pose major

technological problems include the need for

emission controls in California thermal EOR projects, the possibility of fresh water shortages, and

the need to protect ground water.

The need to develop an economically acceptable means of meeting the air pollution requirements for thermal processes has become critical

in California. Further expansion of the thermal

process in California awaits this development.

The requirements placed on EOR processes by

the Safe Drinking Water Act (P.L. 93-593) are

critical for their long-term development. Accommodation to the Safe Drinking Water Act is not

so much a technological problem as it is a human

and administrative matter. The need is one of

establishing acceptable guidelines that will protect fresh water sources and still allow EOR processes to proceed. The record of compatibility of

these two goals through the long period of secondary recovery in the United States suggests

that this can be accomplished. This is discussed

further in chapter VI.

The Rate of Technological Evolution

All estimates of potential recovery from application of EOR processes are based on a postulated rate of technological evolution. There is

consensus among personnel in industry, Government, and academic institutions who are
64 ● Ch. Ill—Oil Recovery Potential

knowledgeable in enhanced oil recovery processes that much research and field testing is

necessary to bring EOR technology to the point

where commercialization is possible for all processes except steam displacement.

The suggested components of research and

development programs to stimulate EOR production have received significant appraisal and

modification within the last 4 years. Between

1973 and March 1977, the Gulf Universities

Research Consortium (GURC) issued a series of

five reports 49,50,51,52,53 detailing the need for field

tests, their number and character, and the basic

research needs. In addition, Lewin and Associates, lnc,54 prepared a major study for ERDA

which recommends specific research targets

(process/reservoir type). Further details of the

ERDA program are outlined in the ERDA Management Plan for EOR.55

The GURC and Lewin documents represent

compilations of existing industrial viewpoints

concerning research targets and types of

programs that are appropriate. This gathered consensus has been supplemented by a series of

ERDA-sponsored workshops on ERDA research

targets 56,57 at which modifications to the program

were suggested through public forums.

Although there is agreement concerning

general research and development needs, there is

a decided difference of opinion regarding the factors which will stimulate this needed research

and development. The Lewin ERDA study 58 proposed an extensive Government research and

development program, justified in part by results

of an industry survey which indicated that

research would not be greatly accelerated within

the current set of constraints (economic, technical, and institutional). The National Petroleum

Council’s EOR study concluded that “Government policy with respect to oil price and other

factors influencing EOR profitability is the dominant factor in establishing the level of R&D funding and the rate of evolution of technology. ”

The OTA assessment did not attempt to

resolve these positions because there appeared

to be no meaningful way to predict what industry

would do a) if the price of oil produced by some

EOR processes was allowed to rise to free market

prices as proposed by FEA, orb) if the price of all

EOR oil were decontrolled. as proposed in the

President’s National Energy Plan.

The ERDA Programs

The Energy Research and” Development Ad- ment of EOR processes. The general thrust of the

ministration has developed programs which are ERDA programs, including field testing and condirected at stimulation of research and develop- tinued industry/Government interaction, is good.

i’~P/arm i ng Cri(erla Relative to a Nationa/ RDT&E Program

Directed to the [nhanced Re(okery of Crude Oil and Natural

Gas, for U.S. Atomic Energy Commission, Washingtcm, D. C.,

GURC Report No. 130, Nov. 30, 1973.

~OAn /investigation of Prirnw-y Factors Affecting Federal Participation in R&D Pertaining to [he Accelerated Production

of Crude Oil, for the National Science Foundation, Washing-’

ton, D. C., GURC Report #1 40, Sept. 15, 1974.

51A Survey Of flcld Tests of Enhanced Recovery Methods

for Crude Oil (supplement to GURC Report No. 140), for the

National Science [oundation and the Federal Energy Administration, Washington, D. C., GURC Report No. 140-S,

Nov. 11, 1974.

Szpreliminary Fie/d Tes( R~~cornrnendatlons and prospective Crude Oil Fields or Reservoirs for High Priority F/e/d

Testing, for (J.S. Energy Research and Development Administration, Washington, D. C., GURC Report No. 148, Feb.

28, 1976.

53 Technica/ Plans for a Supplementary Research program

to Support Dcveloprnent and Field Demonstration of

Enhanced Oil Recovery, for U.S. Energy Research and

Development Administration, Washington, D. C., Gl_JRC

Report No. 154, Mar, 17, 1977.

jiResedrch and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D.C. Part 1, p. III-2.

ss~~anagement P/an for Enhanced 0// Recovery, ERDA,

Petroleum and Natural Gas Plan, ERDA 77-15/1, p. 11-1,

February 1977.

56ERDA workshops on Thermal Recovery of Crude oil,

University of Southern California, Mar. 29-30, 1977.

5TEOR Workshop on Carbon Dioxide, sponsored by

ERDA, Houston, Texas, April 1977.

~8Research and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D. C., Part 1, p. III-2.
Ch. III—Oil Recovery Potentlal . 65

The ERDA management plan for EOR59 is

directed at maximizing production in the

mid-1980’s. However, short-term needs should

not overshadow long-term national needs of increasing oil recovery. The OTA analysis indicates

that a long-range program is needed to stimulate

the development of processes, such as the surfactant/polymer process, which have the potential

for greater oil recovery in the mid-1990’s,

There does not seem to be adequate basic and

applied research in the ongoing ERDA program.

This has been recognized by ERDA, and an extensive research program has recently been outlined

by GURC60 for ERDA. This research program supplements the programs outlined in the ERDA

management plan.61

The largest amount of basic and applied

research has come from the integrated major oil

companies and the service sector of the

petroleum industry. The largest amount of expertise also resides in the industry. Basic and applied

research done by industry and research institutions should be coordinated so that Government

programs complement rather than duplicate

programs underway in industry. This subject does

not seem to be covered formally in the ERDA

documents, and is particularly crucial since even

under Government sponsorship a large portion of

the basic and applied research is likely to be

done in industry laboratories and oilfields.

The OTA assessment did not determine the

level of ERDA or industry effort required to

achieve the postulated technological advances or

the cost of the necessary research and development. (Other studies have shown that the cost of

research and development is on the order of a

few cents per barrel of ultimate recovery.)

However, the level of effort and funding in R&D

must clearly be significantly increased over current levels by both industry and Government in

order for the evolution of technology to approach the technological advances postulated in

this assessment.

sgManagemen[ p/an for Enhanced 0// Recovery, ERDA,

Petroleum and Natural Gas Plan, ERDA 77-1 5/1, p, 11-1,

February 1977.

60 Tecbn;caj Plans for a Supplementary Research Pmgrm

to Support Development and Field Demon5(ratlon of

Enhanced Oil Recovery, for 1.1.S. Energy Research an d

Development Administration, Washington, D. C., CiURC

Report No. 154, Mar. 17, 1977.

61 ~anagement p/dlJ for Enhanced 0// Recovery, ERDA,

Petroleum and Naturdl Gas Plan, ERDA 77-1 5/1, p. 11-1,

February 1977.

95-594 0 - 78 - 6
IV. Impacts of Price and

Tax Policies on Oil Recovery
IV. Impacts of Price and

Tax Policies on Oil Recovery

Policy Considerations

With the advent of a new technology like

enhanced oil recovery (EOR), two related factors

often inhibit expansion of output. First, even with

certainty of information about prices, costs, and

production, careful analysis may indicate that

production will not be profitable for early operators. prices may be too low or production experience may have been inadequate to reduce

costs or increase efficiency sufficient to yield an

acceptable return on invested capital. Second, as

in any market situation, there will be uncertainty

about many variables that can affect profitability.

In the case of EOR, technical and economic uncertainty, coupled with some degree of aversion

to risk by potential operators, can inhibit the

speed and extent of process development.

Proposed public policy alternatives are, in essence, attempts to reduce the effects of these

two factors on the private decision process,

modify private market decisions, and remove barriers to EOR development. Although these two

factors are obviously interdependent, the artificial distinction will be maintained for purposes of this analysis. First, the report evaluates

alternative public policy options designed to

foster private-sector development of enhanced

recovery processes under the assumption of information certainty. Point projections of production, price, and cost profiles for selected reservoirs will be used. A second analysis, using subjective probability distributions of key input

variables, describes the impact of policy alternatives designed to alleviate economic uncertainty.

Policy Options

A number of public policy alternatives have

been suggested which could influence the

development of EOR techniques, Implementation

of these alternatives may affect private sector

decisions on the development of specific EOR

reservoirs or modify decisions regarding which

process should be installed. Some policy options

also may alter constraints which would limit the

amount of EOR production nationally. Regardless

of their specific focus, most public policy

changes can be expected to influence the degree

of uncertainty perceived by the private sector in

future EOR activities.

A number of these potential public policy actions will be analyzed and evaluated. The principal proposals can be classified as:

1)

2)

alternative regulated and/or market price

levels;

price and/or purchase guarantees for EOR

over the lifetime of a producing facility;

3)

4)

In

alternative taxation policies, including

changes in depreciation methods, investment tax credit rates, and expensing rules

for various categories of investment and

operating costs; and

public investment subsidies-Government

payment of a percentage of private investment costs.

addition, the effects of these alternative

strategies can be determined under alternative

leasing systems when the reservoirs being considered are located on the public domain.1 For

IAnother policy option which could be considered for

reservoirs located on the public domain is altering the lease

terms to encourage enfianced oil recovery installations at an

optimal point in the production time horizon. Analysis of

this option, however, requires data not only on EOR costs

and production profiles but on the synergistic effects with

primary and secondary production. Since little experience is

available on these elements, evaluation of the option would

be difficult, if not impossible, at this time.

69
—

70 . Ch. IV—impacts of Price and Tax Policies on Oil Recovery

analytical purposes, OTA examined the various

options in conjunction with several leasing

systems, including the current system and others

that could be used in the future. These systems

include:

1 ) The current cash bonus system;

2) Higher fixed royalty rate plus cash bonus;

and

3) Fixed-rate profit share plus cash bonus.

The analysis was conducted under five

different price assumptions for enhanced oil production:

1) The current regulated upper tier (new oil)

price of $11.62 per barrel;

2) The current price of foreign crude oil landed

in the Eastern United States—$1 3.75 per

barrel (in 1976 dollars);

3) A price approaching the estimated cost of

synthetic fuels—$22 per barrel;2

4) An intermediate price between the world

oil ‘price and the synthetic fuels price—$1 7

per barrel; and

5) A rising real world oil price initially set at

$13.75 per barrel and projected to rise at a

5-percent annual rate.

The first four alternatives assume a constant real

price and the fifth alternative assumes a rising

real price.

For each EOR process, baseline evaluations

were carried out using these alternative price

Analytical

All reservoirs in a selected sample were tested,

using cost and production profiles from the highprocess performance case discussed in chapter III.

As a check on these results, data from the low2This price was obtained from the report of the Synfuels

Interagency Task Force.

levels and currently permitted tax procedures (including the 10-percent investment tax credit, expensing of injection chemicals, and Unit of production depreciation). Then, the following policy

alternatives were analyzed:

1)

2)

3)

4)

Price subsidies of $1 and $3 per barrel;

Price guarantees of $13.75 per barrel;

Investment tax credit of 12 percent compared with the current 10 percent;

Capitalization and subsequent depreciation

of injection chemical costs;

5) Use of an augmented accelerated depreciation method; and

6) Government investment subsidy of 15 percent of initial capital investment.

Since several of these options (price subsidies

and guarantees) are designed to reduce uncertainty, they were not evaluated under the

assumption of information certainty.

Alternative leasing systems for public domain

lands were tested with various options, including

the current cash bonus—fixed royalty system, a

cash bonus system with a 40-percent fixed

royalty, and an annuity capital recovery-profit

share system with a cash bonus bid. In this profit

share system, investment costs are converted to

an annuity over 8 years of 8-percent interest, and

the annuity is subtracted from net profits before

the Government share of 50 percent is taken. j

Approach

process performance case were also analyzed. individual EOR processes were evaluated sepa-

‘Other leasing systems have been suggested and could

be evaluated. For example, variable rate options for both

royalty and profit share systems may be desirable alternatives. However, the systems chosen appear to cover a range

of possible results.
Ch. IV—Irnpacts of Price and Tax Policies on Oil Recovery . 77

rately using baseline values and then using the counted cash flow simulation model (Tyner and

policy options discussed above. 4 The entire Kalter, 1976), modified to

analysis was conducted using a Monte Carlo dis- sion process as viewed by

Analysis of Government Policy Options

handle the EOR decithe private sector.

Reservoir Sample

For purposes of policy analysis, a sample of up

to 50 of the reservoirs assigned to each EOR process (see previous discussion) was selected for initial evaluation. Separate samples for onshore and

offshore areas were drawn from reservoirs

assigned to the C O2 process. Sample selection

was based upon a number of criteria including

regional location, reservoir depth, residual barrels

of oil per acre (available for tertiary production),

reservoir size in acres, and, in the case of offshore

fields, water depth, For each EOR process evaluated, fields covering a broad range of these

characteristics were included.

After reviewing the range of values taken on

by the various selection criteria, it was decided

that a sample of 25 reservoirs for each EOR process would be adequate to cover the circumstances affecting economical development and

provide an appropriate test of the various policy

options. The only exception to a sample number

of 25 was the case of onshore C02 where substantial EOR production was expected. Table 26

4Reservoirs subject to more than one EOR process were

not evaluated with respect to the impact of policy options

on each process or on process selection. The impact of alternative price levels and decision criteria on process selection

was discussed in a previous section but data were not

available to carry out a detailed analysis here. Since most

policy options were analyzed at the world oil prices, this

procedure should not affect the results (process selection

was generally carried out at this price level).

displays the number of reservoirs assigned to

each process, the number selected for the sample, and the percentage of the reservoir data base

sampled.

Analysis Assuming Information Certainty

Price analysis

Given the sample selection, the first step in the

analysis was to test the potential for profitable

EOR development at various price levels under

conditions of information certainty. Using production profiles, investment costs (and timing),

and operating costs developed for the high-process performance case, these tests were conducted under the assumptions that private industry would require a 10-percent net after tax, rate

of return on invested capital and that currently

permitted tax procedures (State and Federal)

would be governing. Thus, a 10-percent investment tax credit, expensing of EOR injection costs,

depreciation based on the rate of resource depletion, and current State and Federal income tax

rates were used.

Table 27 displays the number and percent of

each EOR process sample that would be

developed at various price levels under these

conditions, as well as the percentage of potential

EOR production (gross production less that used

for EOR purposes) that would result from those

developed. For example, development ranges

from 6 percent of the fields at $11.62 per barrel

for steam to 95 percent of all fields assigned to
72 ● Ch. IV—impacts of Price and Tax Policies on Oil Recovery

Table 26

Number and Percent of Reservoirs Sampled by EOR Process

Onshore Offshore*

Steam In Situ Surfactant Polymer Co2 co,

Total reservoirs assigned. . . . . . 20 20 92 20 190 294

Sample size . . . . . . . . . . . . . . . . 20 20 25 20 50 25

Percent sampled . . . . . . . . . . . . 100 100 27 100 26 9

● All offshore reservoirs were assigned to the CO2 recovery process.

Tabie 27

EOR Reservoir Development and Production by Process and Price Levei

Process

and

price range

(per barrel)

Steam

$11.62 . . . . . .

13.75 . . . . . . .

17.00 . . . . . . .

22.00 . . . . . .

In Situ

$11.62 . . . . . . .

13.75 . . . . . . .

17.00 . . . . . .

22.00 . . . . . . .

Surfactan t

$11.62, . . . . . .

13.75 . . . . . . .

17.00. , ., . .

22.00 . . . . . . .

Polyme r

$11.62 . . . . . . .

13.75 . . . . . . .

17.00 . . . . . . .

22.00 . . . . . . .

C O2 --Onshor e

$11.62 . . . . . . .

13.75 . . . . . .

17.00 . . . . . . .

22.00. , . . . . .

CO2-Offshore

$1“1 .62 . . . . . . .

13.75 . . . . . . .

17.00 . . . . . . .

22,00 . . . . . . .

Total

$11.62 . . . . . . .

13.75 . . . . . .

17.00 . . . . . . .

22.00 . . . . . . .

Sample

size

20

20

20

20

20

20

20

20

25

25

25

25

20

20

20

20

50

50

50

50

25

25

25

25

160

160

160

160

Numbe r

developed

—.— —

6

9

11

14

14

16

18

18

1 4

1 9

1 9

2 2

14

17

17

19

12

22

32

37

9

9

15

19

69

92

112

129

Percent

developed

30

45

55

70

70

80

90

90

56

76

76

88

70

85

85

95

24

44

64

74

36

36

60

76

43

58

70

81

Percent

potential

production

developed

4 1

4 7

7 5

8 5

89

96

100

100

77

85

85

94

94

99

99

100

22

27

50

71

24

24

‘35

50

46

52

69

82

Sample

price

elasticity

of supply

.99

3.10

,62

.52

.19

.00

.70

.00

.46

.32

.00

.05

1.52

4.26

1.87

.00

2.21

1.99

.88

1.78

.81
Ch. IV—impacts of Price and Tax Policies on Oil Recovery . 73

polymer at $22 per barrel. production ranges

from 22 percent of the total possible for onshore

C 02 at $11.62 per barrel to 100 percent for

polymer and in situ at $22 per barrel. Current

world prices of $13.75 per barrel result in up to

99 percent of possible production from the

polymer process, and up to 24 percent of possible EOR offshore oil production for those reservoirs assigned to the C02 process. Overall, 43 to

81 percen t of the sample reservoirs are

developed over the price range analyzed, with 46

to 82 percent of possible EOR oil being produced, 5

Of perhaps greater interest, however, is the

price elasticity of supply (i.e., the percentage

change in production for each 1 -percent change

in price) Table 27 also lists these values (arc

elasticities) for the sample over the price range

analyzed. 6 Individual EOR processes, as well as

total production from all processes, are shown. It

is obvious that the price elasticities vary across

both the process and the range of price changes.

in the $11.62 to $22 per barrel range, the C O2

and steam processes are price elastic. This is also

true of all processes combined. In situ, surfactant,

and polymer are, however, price inelastic to the

point where higher prices will have little impact

on production.

All processes, except offshore C02

, exhibit the

greatest price elasticity in the Iow and/or middle

price ranges (to $17 per barrel). Offshore C02 exhibits its greatest elasticity over the middle price

5Using production estimates based upon the low-process

performance case would substantially reduce these values.

For example, the surfactant process at world oil prices

would be implemented on only two reservoirs in the sample

(8 percent) and result in 7 p~r~ent of the potential net production. Similar calculations could be shown for other processes and price levels. However, the object ot this section is

an evaluation of policy options. For this purpose, the highprocess performance case is used as a basis with digressions

to other cases only if policy conclusions would be affected.

Also, the values change considerably when the analysis is

conducted at the lower tier (old oil) price of $5.25 per barrel. At this price only 8 percent of the reservoirs with 14 percent of total possible production were developed.

6The elasticity formula used for all calculations was

(Q ,- Q( l) /Q,, + (P I-P,, /P,. Note that these value> relate to

ultimate net production and, thus, give no indication of the

sensitivity of production profiles (or timing) to price.

range ($13.75 to $17 per barrel), with substantial

elasticity above $17 per barrel. These results suggest the greatest price impact on production will

take place in the range of real prices from $11.62

per barrel to approximately $17 per barrel, except

in the high-cost offshore regions. With real oil

prices expected to increase in the future, an

effective method for encouraging EOR development would be to allow prices for EOR oil to rise

with the world price. This conclusion is further

supported by the fact that those EOR processes

with the greatest production potential also have

the highest price elasticity.

Of the 31 fields (31 of 160 sample reservoirs)

which did not develop at a $22 per barrel price,

21 developed at $27.50 per barrel or below, 6

between $27.50 and $50 per barrel, 2 between

$50 and $75 per barrel, and 2 could not be

developed unless price exceeded $75 per barrel.

As a result, 94 percent of the potential EOR reservoirs in the sample can be developed at prices

below $27.50 per barrel. Overall price elasticity

is positive (1 .35) in the range of $22 to $27.50

per barrel, but almost zero above $27.50 per barrel. Some fields in the steam, in situ, and surfactant processes could not be developed at prices

below $50 per barrel. These processes use a portion of the recovered oil in the recovery process,

so higher product price also means higher production cost.

It could be dangerous to generalize from the

sample (although the steam and in situ samples

included almost all assigned reservoirs), and the

supply elasticities calculated from the sample

were therefore compared with those based upon

all reservoirs assigned to EOR processes in both

the low- and high-process performance cases.

Such a comparison cannot be precise because of

the different approach used in the overall analysis

to address economic calculations. Furthermore,

the policy sample contains a greater proportion

of marginal fields than does the total data set.

In general, the results displayed in table 28 indicate that the tendencies apparent from the

sample are supported when looking at the entire

high-process performance data base, Surfactant

becomes price elastic, along with CO2 and steam,

but onshore CO2 appears somewhat less price

sensitive and offshore CO2 somewhat more price
.-

74 . Ch. IV—impacts of Price and Tax Policies on Oil Recover)’

sensitive than in the sample. No evidence is apparent which would argue for a change in the

previously discussed conclusions. As would be

expected, the low-process performance case

showed higher price elasticities for a number of

the processes. Only in situ remained price inelastic overall, while the price elasticity of steam

dropped.

Analysis of Other Policy Options

Given the potential impacts of price on EOR

development, the next question under the

assumption of information certainty is whether

other public policy options would change EOR

economics. To answer this question, OTA

analyzed four possible policy changes (three tax

considerations and a public investment subsidy

to encourage EOR development).

The tax options include the use of a 12-percent investment tax credit (2 percent more than

the current rate), accelerated depreciation using

the double declining balance method, and an option in which injection costs are 100 percent

depreciated rather than expensed. The latter option was conducted to evaluate industry’s contention that the Internal Revenue Service must

Table 28

Price Elasticity of Supply Comparison

Process and

price range

(per barrel)

Steam

Overall ($11 .62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

In situ

Overall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

Surfactant

Overall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

Polymer

Overall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

C O2-Onshor e

Overall ($11.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

C O2-Offshor e

Overall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 ..., . . . . . . . . . . . . . . . . . . . . . .

All processes

Overall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .

$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .

$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .

Policy analysis

sample

High-process

performance

case

2.32

.99

2.18

.25

.52

.10

.48

.70

.28

.11

.32

.06

4.64

1.52

4.22

2.26

.00

2.84

1.70

.88

1.56

OTA total reservoir assignment

High-process

performance

case

2.42

1.15

2.18

.25

.76

.00

1.47

2,51

.59

.00

.00

.00

2.49

3.34

1.16

7.06

3.23

5.04

2.02

2.46

1.10

Low-process

performance

case

1.92

1.23

1.60

.71

1.08

.38

12.93

8.39

5.57

1.06

3.23

.00

5.33

2.03

4.46

—

—

.

4.50

2.42

3.39
Ch. IV—Impacts of Price and Tax Policies on Oil Recovery . 75

Table 29

EOR Development by Process and Policy Option

Process

Steam . . . . . . . .

In situ . . . . . . . . . . .

Surfactant ... . . . . . . .

Polymer. . . . . .

C O2-Onshore . . . . . .

C O2-Offshore ., . . .

Total . . . . . . . . . .

I I

Number of Reservoirs Developed

Sample

size

20

20

25

20

50

25

160

$13.75

per barrel

9

16

1 9

1 7

2 2

9

92

permit the expensing of injection costs if EOR is

to be economically viable. Depreciation was

assumed to take place over the remaining production period in proportion to production. The

investment subsidy option calls for the Government to pay 15 percent of all initial EOR capital

investments (deferred investments and injection

costs are paid fully by the producer).

Table 29 displays the result of these tests. All

evaluations assumed current world market prices

($1 3.75 per barrel). As can be seen, the various

options have relatively minor impacts on

development and, consequently, on production.

In fact, the 12-percent investment tax credit

results in no new development, while the accelerated depreciation option adds one reservoir

to the in situ process and increases total net production by only two-tenths of 1 percent. On the

other hand, the requirement that EOR injection

costs be 100-percent depreciated results in 30

(32 percent) fewer sample reservoirs being

developed with a 29-percent reduction in total

production. The reduced production is concentrated in surfactant, with some impact on the

steam, polymer, and onshore CO2 processes. The

only policy option at all effective in encouraging

development appears to be a 15-percent investment subsidy which would add three developed

reservoirs at current world prices and result in a

1 -percent increase in net production. T

The various options do change the amount of

above normal (1 O-percent rate of return) profit

that can be expected from developed fields.

12-percent I I Depreciate I 1 5-percent

investment I

Accelerated Iinjection

I

investment

credit depreciation costs subsidy

9 9 6 9

16 17 16 18

19 19 4 19

17 17 15 17

22 22 13 22

9 9 9 10

92 I

93 I63 I95

Depreciation of injection costs would tend to

reduce rates of return and the other options

would increase them. If the introduction of EOR

to potential reservoirs is paced on the basis of

rates of return (as assumed previously), this

change could have an impact on aggregate production profiles and the timing of recovery. The

exact impact is impossible to quantify since firms

will have different decision criteria and schedules

for EOR initiation based on those criteria.

For policy analysis, these results need to be

compared with the costs of the respective

policies. In the case of a 12-percent investment

tax credit, the Government revenue loss is not

offset by additional tax revenues because no new

output results. The accelerated depreciation option adds one additional reservoir, increasing production by more than 28 million barrels. At the

same time, Government revenue actually increases due to the higher production and resulting tax receipts. The increase per barrel of production, however, is slight-less than 1 cent per

barrel.

7Similar results were obtained when analyzing the lowprocess performance case. The number of reservoirs that

developed at a 10-percent rate of return was obviously

reduced by a substantial degree. However, the various

policy options have little impact on changing these decisions. Taking surfactant as an example of a process which is

often marginal, the various options resulted in only one addition to the two fields developed under free market conditions (see footnote 4). That development occurred when a

15 percent investment subsidy was introduced. Required

depreciation of Injection costs, however, did not affect the

decision to develop.
76 . Ch. IV—impacts of Price and Tax Policies on Oil Recovery

As would be expected, requiring the depreciation of injection costs increased Government

revenue while the 15-percent investment subsidy

reduced it. However, the impacts per barrel of incremental production were quite small.

In summary, it appears that no policy option is

either very powerful in encouraging new production or very expensive in terms of Government

cost per barrel produced. In fact, little appears to

be gained (or lost) by attempting to accelerate

EOR development at a pace faster than that likely

to occur in current institutional setting. The question remains, however, whether such policy options are worth potential distortions in efficiency

under conditions of information uncertainty. This

question is explored in the next section.

Analysis Assuming

Information Uncertainty

To evaluate the question of uncertainty in production, cost, and price values, the same sample

of reservoirs was used in conjunction with subjective probability distributions on the key input

variables. Table 30 lists the variables and the distributions used. The resulting range in production

from the reservoirs was substantially less than

that resulting from the high- and low-process perTable 30

Input Variables and Subjective Probability

Distributions Used for Monte Cario Simulations

Variable

Price

Original value ($/bbl.) . . . . . . . . . . . . . . . . . .

Mean of price change distribution . . . . . .

Standard deviation of price change

distribution. . . . . . . . . . . . . . . . . . . . . . . . . . .

Production

Triangular contingency distributions. . . . . . .

Minimum . . . . . . . . . . . . . . . . . . . . ., . . . . .

Most likely . . . . . . . . . . . . . . . . . . . . . . . . .

Maximum . . . . . . . . . . . . . . . . . . . . . . . . . . .

Investment and operating cost

Triangular contingency distributions

Minimum . . . . . . . . . . . . . . . . . . . . . . . . . . .

Most Likely. . . . . . . . . . . . . . . . . . . . . . . . . .

Maximum . . . . . . . . . . . . . . . . . . . . . . . . . . .

Value

13.75

0.00

0.01

-.3 0

-.1 0

0.05

-.0 5

0.00

0.10

formance assumptions discussed in chapter Ill.

This result indicates that the degree of uncertainty implicit in the cost and production distributions was less than that incorporated in the two

advancing technology cases. As a result, the

policy tests can be considered conservative, in

that a policy which will not affect development

under these assumptions is unlikely to have any

impact in practice.

Options Designed To Alleviate Uncertainty

The effects of uncertainty were evaluated at

the current world oil price. Because of the minor

impacts exhibited by the tax options in the previous analysis, they were dropped from further

consideration. Two other options, designed to

reduce uncertainty, were added: (1) a price

guarantee whereby the Government would

assure a market price that did not fall below

$13.75 per barrel; and (2) an actual price subsidy

(payment by the Government over and above

market price) of $3 per barrel of EOR oil produced. 8 In all evaluations, current tax rules and a

10-percent rate of return were assumed. Table 31

summarizes these evaluations.

The simulations provide interesting insight

into the potential profitability of EOR development. Overall, it appears that up to 23 percent of

the developable EOR reservoirs (and 23 percent

of the producible oil) would be available at current market prices with very low risk of a lessthan-normal profit to the operator. The remainder

of the fields with some chance of profitability are

spread more or less uniformly over the probability range of less-than-normal profit categories.

However, because of variations in reservoir size,

the remaining recoverable oil is not distributed

uniformly, but is concentrated in the 26 to 50

percent and 75 to 99 percent chance-of-loss

categories. Only 66 percent of the sample’s producible EOR oil has some probability of being

profitably exploited under the conditions simulated.

The policy options analyzed have little effect

on these results. Only the $3 price subsidy adds a

8A $1 per barrel subsidy was also evaluated but is not

displayed because of its neglible impact. (Number of Monte Carlo Iterations: 200)
Ch. IV—impacts of Price and Tax Policies on Oil Recovery ● 77

—

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . .%

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . .%

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . . &

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . . &

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . .

. . . h

*

. . . 6. -

-u

c

lx

c m t-
.

78 ● Ch. IV—impacts of Price and Tax Policies on Oil Recovery

significant number of reservoirs to those potentially developed (20 percent), but this results in

only a 6-percent increase in potential oil production. The impact is concentrated in the C02

,

steam, and surfactant processes. The 15-percent

investment subsidy adds 5 percent to the potential reservoir development but only 4 percent additional oil. Only C02 processes were affected,

however. In most cases, reservoirs added to those

that would be potentially developed are in the

high-risk (76 to 99 percent chance of loss)

category.

All options, however, have some impact on

reducing the risk of development for those reservoirs that are potential candidates under current

market conditions. Again, the most successful

policy in this regard is the $3 per barrel price subsidy with 55 percent of the potential production

classified below 50-percent probability of a less

than normal profit. This is a 31 -percent improvement over the base case and compares to a 2-

percent improvement for the price guarantee option and a 21 -percent gain for the investment

subsidy.

The impacts of the various policy options on

individual EOR processes are similar to the overall results, with the greatest addition to potential

EOR reservoirs and total production resulting

from the price subsidy option. The reduction in

risk for potential production (from the base case)

is greatest for the onshore C02 process, followed

by in situ combustion and surfactant flooding.

Although increases in potential EOR production (from all risk categories) do not appear substantial for any of the options designed to reduce

uncertainty, the possibility of changing the risk of

development for those reservoirs included in the

base case warrants further investigation of a price

subsidy. To accurately assess this option the potential benefits of increased EOR production

must be balanced against Government costs.

However, both the extent of increased production and the corresponding costs are difficult to

quantify. Since the decision to recover EOR oil

depends on a producer’s risk-preference function, one must ascertain the appropriate decision

rule used by the private sector in making

development decisions before an accurate

assessment can be made. Given that these decision rules will vary among firms and may change

for a given firm with implementation of a policy

subsidy, Government cost is difficult, if not impossible, to quantify. The cost of the $3 subsidy

to all produced EOR oil will be offset to some extent by an increase in Federal tax revenue and, in

the case of offshore fields, higher royalty collections. Without knowledge of the impacts under

varying risk conditions and decision criteria, the

magnitude of this change can only be an educated guess, For a range of possible conditions,

the net present value cost of the subsidy appears

to be in the area of $1.50 to $2 per barrel.

Analysis Assuming a Rising Real Price

The preceding analysis assumes that EOR oil

will be priced at $13.75 per barrel and that such a

price will continue, in real terms, throughout the

productive life of an EOR project. Evaluation of

this assumption could lead to the conclusion that

the results discussed above are an inaccurate

representation of future reality, If EOR oil prices

are deregulated and world market prices maintain

a moderate, but consistent, real growth rate,

much of the uncertainty exhibited in the

profitability of EOR projects may be eliminated.

To test this possibility, an analysis was performed on the sample which assumed an average

annual real price increase of 5 percent (randomly

selected from a normal price change distribution

with a standard deviation of 3 percent). Table 32

displays the price deregulation impact and, compares it to the $13.7s price base case and the $3

price subsidy situation (from table 31). It can be

seen that the rising price scenario test equal led or

exceeded the results of the price subsidy in

reducing uncertainty for all EOR processes. Overall, price deregulation led to a 34-percent increase in field development over the base case

and an 11 -percent increase over the price subsidy

analysis. Moreover, substantial shifts in the uncertainty category occurred for fields which were

formerly in high-risk categories (greater than 50-

percent chance of loss). Price deregulation has a

significant impact in all EOR processes except in

situ combustion.

Thus, if a moderate annual increase in real oil

prices obtained for EOR production could be ex-
Ch. IV—impacts of Price and Tax Policies on Oil Recovery . 79

pected with a high degree of assurance, special not be required. An equal or greater impact could

Government policies to reduce uncertainty may be obtained with simple price deregulation.

Table 32

Monte Carlo Simulation of EOR Oii Price Deregulation

(fixed $13.75 per barrel price, and a $3.00 per barrel subsidy)

EOR

process

and

policy

Steam

Base case. . . . . . . . . . . . .

Price subsidy. ... , . . . . .

Price deregulation*. . . . .

In situ

Base case. . . . . . . . . . . . .

Price subsidy. . . . . . . . . .

Price deregulation*. . . . .

Surfactant

Base case. . . . . . . . . . . . .

Price subsidy. . . . . . . . . .

Price deregulation*. . . . .

Polymer

Base case. . . . . . . . . . . . .

Price subsidy. . . . . . . . . .

Price deregulation*. . . . .

C 02onshor e

Base case . . . . . . . . . . . . .

Price subsidy . . . . . . . . . .

Price deregulation* . . . . .

C O2-Offshor e

Base case . . . . . . . . . . . . .

Price subsidy . . . . . . . . .

Price deregulation* . . . . .

Total

Base case . . . . . . . . . . . .

Price subsidy . . . . . . . . . .

Price deregulation* . .

Sample

size

20

20

20

20

20

20

25

25

25

20

20

20

50

50

50

25

25

25

160

160

160

Number of reservoirs developed

Probability of less than normal refit

o

percent

3

3

3

10

11

11

2

2

6

11

14

14

4

9

18

7

9

9

37

48

61

1-25

percent

1

3

5

2

2

5

4

12

13

3

2

3

3

11

5

2

—

—

15

30

31

26-50

percent

2

2

3

—

3

—

6

4

—

—

1—

4

2

4

—

—

—

12

12

7

51-75

percent

—

1

2

2

2

2

3

1

1

1—

—

4

2

6

—

3

3

10

9

14

76-99

percent

4

3

—

4

—

—

4

1

2

2

—

2

7

7

4

—

4

6

21

15

14

\

Total

percent

10

12

13

18

18

18

19

20

22

17

17

19

22

31

37

9

16

18

95

114

127

*Assumes an annual price change distribution which IS normal with a S-percent mean and a 3-percent standard deviation

Impact of Alternative OCS Leasing Systems

With the current widespread interest in OCS ment for exploration and development rights (the

leasing activity, increased attention has been cash bonus). This bid amount is not refundable if

focused on alternative leasing systems. The recoverable resources are not found and,

United States currently uses, almost exclusively, a therefore, has no impact on subsequent developcash bonus leasing procedure in which the win- ment and production decisions (including the use

ning bidder for an OCS lease is the firm which of EOR technology). In addition to the cash

offers the Government the highest front-end pay- bonus, a royalty on gross production value of

a
80 . Ch. IV—impacts of Price and Tax Policies on Oil Recove

16.67 percent is paid to the Government by the

producer. The previous analysis of policy options

assumed this leasing method was in use for

offshore C02 cases.

However, because of the substantial uncertainty that exists in offshore development and the

capital requirements of cash bonus bidding, alternative systems have been proposed that would

shift some of the risk to the Government, reduce

capital requirements, and encourage competition. 9 As a result, Government revenue could increase with little or no loss in production. Such

alternative leasing systems make greater use of

contingency payments (which produce Government revenues based on the value of production)

and usually employ a higher royalty rate or a

profit-share technique. The cash bonus is retained as the bid variable to alleviate problems of

speculation. The higher contingency payments,

however, act to reduce the magnitude and importance of the bonus.

r y

profit share and higher royalty rate systems

described above with the current system. Table

33 details the results of this analysis. It is clear

that high fixed royalties will inhibit EOR development by increasing the risk of less-than-normal

profits and by making some fields uneconomical

for EOR development. These results confirm

earlier studies on the impact of high royalties for

primary and secondary production.10 However,

the profit-share system also has a tendency to increase the risk of a less-than-normal profit. This

result is at variance with previous results on primary and secondary production and indicates

that a profit-share rate of so percent is too high

for EOR development on marginal fields. One option in both situations would be the use of a

variable-rate royalty or profit-share approach, so

that rates would be reduced automatically for

marginal fields and increased in situations of

higher productivity. If experiments with new

leasing systems are contemplated, the effects of

leasing systems on EOR production as well as priThe viability of EOR under the alternative leas- mary and secondary production should be evaluing systems was evaluated by comparing the ated.

Administrative Issues

All of the policy options analyzed in this section would provide special incentives for production of oil using enhanced recovery techniques.

The implementation of any such incentives will

require administrative decisions concerning the

qualification of particular projects or types of

projects for the incentives. Those policies involving special price incentives will also require a

further judgment about what portion of the oil

produced from a field can be attributed to the

EOR process, and what part would have been

produced anyway by the continuation of primary

and secondary techniques. The problem is to

define this EOR increment in such a way that

special incentives will encourage the application

of EOR processes without significantly distorting

decisions concerning primary and secondary production.

9Robert j. Kalter and Wallace E. Tyner, An Analysis of

Selected OCS Leasing Options. Report to the Office of

Technology Assessment, U.S. Congress, June 1975.

These problems will have to be dealt with if

proposed price incentive policies are to be

adopted. In 1976, Congress amended the

Emergency Petroleum Allocation Act (through

provisions in the Energy Conservation and Production Act) to direct the President to modify oil

pricing regulations to provide additional price incentives for bona fide EOR techniques. Since

then, FEA has published proposed regulations for

comment and has held several public hearings on

the subject. The basic approach proposed by FEA

is to apply price incentives only to the increment

of production attributable to an EOR process.

The same approach is implied in the president’s

April 1977 National Energy Plan, which called for

decontrol of the price of oil produced with EOR

techniques.

IORobert j. Kalter, Wallace E. Tyner, and Daniel W.

Hughes, Alternative Energy Leasing Strategies and Schedules

for the Outer Continental Shelf, Department of Agricultural

Economics Research Paper 75-33, Cornell University, 1975.
Ch. IV—impacts of Price and Tax PolIcIes on Oil Recovery . 81

Decisions concerning the qualification of processes and production levels for special incentives

involve highly technical judgments which will require personnel competent in EOR techniques.

Such personnel do not at present exist in Government in the numbers required. The number of

people available in the job market is quite limited

and industry demand is large. While consultants

might be used, this practice could raise potential

conflict of interest problems, because consultants must, in the long run, depend upon industry

for their support. An alternative approach, supported by industry in comments on FEA proposals, would be simply to apply price incentives

to all oil produced from a field to which an EOR

process was applied. While this would avoid the

problem of defining an EOR increment, there

would remain the problem of defining the level

of effort required for a project to qualify as a

bona fide EOR process, and monitoring to ensure

that that effort is in fact maintained.

A more detailed analysis of the advantages

and disadvantages of these and other incentive

pricing options was beyond the scope of OTA’s

assessment of the potential contribution of EOR

processes to national reserves. Because of the importance and complexity of the associated issues,

however, Congress may wish to examine the

problem of defining and monitoring EOR operations, and possibly hold oversight hearings on the

proposed FEA pricing regulations for EOR production. If defining EOR incremental oil production

and monitoring EOR operations are found to be

critical issues, a mechanism could be developed

whereby bona fide EOR projects could be certified and monitored. Certification and monitoring of EOR operations could be performed by the

operator, a State regulatory group, a Federal

agency, or a combination of Federal, State, and

producer interests.

Table 33

Monte Carlo Simulation of OCS Leasing Systems and EOR Potential

Probability of less-than-normal profit

EOR process

and OCS leasing system Sample o 1-25 26-50 51-75 76-99 Total

size percent percent percent percent percent percent

Number of fields developed

C O2-Offshor e

Current. . . . . . . . . . . . . . . 25 7 2 — — — 9

40-percent royalty . . . . . 25 2 1 1 1 3 8

50-percent profit share 24 4 3 2 — — 9

Percent potential net production developed

C O2-Offshor e

Current. . . . . . . . . . . . . . . 25 21 4 — — — 25

40-percent royalty . . . . . 25 3 6 4 1 9 23

50-percent profit share . 25 13 8 4 — — 25
,.. +

V. Legal Aspects

of Enhanced Oil Recovery
V. Legal Aspects

of Enhanced Oil Recovery

Method of

This chapter of OTA’s assessment of enhanced

oil recovery (EOR) examines legal impacts on

EOR processes arising from Federal and State

statutes, regulations, and other laws. It seeks to

identify existing and potential constraints on the

employment of EOR techniques to obtain additional oil beyond primary and secondary production.

Federal and State laws and regulations were

collected and studied in detail; the legal

literature relating to enhanced recovery in

treatises and law reviews were reviewed; and the

recent studies for, or by, the Energy Research and

Development Administration (ERDA), the Federal

Energy Administration (FEA), the National

Petroleum Council (NPC), the Environmental Protection Agency (EPA), the Gulf Universities

Research Consortium (GURC), and the Interstate

Legal Issues

The law affects enhanced recovery of

operations in many ways. Based upon

responses to questionnaires, price controls

Approach

Oil Compact Commission-together with other

technical literature—were examined. With the

cooperation of the Interstate Oil Compact Commission, questionnaires regarding EOR regulation

and associated problems were sent to 18 large

producing companies, about 240 smaller producers, 34 State regulatory commissions, and to

appropriate officials in the Department of the interior. Responses were received from 15 of the

large producers, 67 of the smaller producers, and

32 of the State commissions. In addition, calls

were made to or personal discussions were held

with selected individuals with knowledge in the

field of enhanced recovery. Information from all

of these sources was used in completing this segment of the EOR assessment. A more detailed

discussion of legal aspects of EOR activity is presented in appendix C of this report.

in EOR Development

oil

the

on

crude oil constitute the most significant legal

constraint to enhanced recovery operations. Approximately 65 percent of all producers responding to the questionnaire indicated that removal of

price controls would make more projects

economically feasible or more attractive.

A second important problem area for

enhanced recovery appears to be the establishment of operating units. In order to be able to

treat a reservoir without regard to property lines,

it is necessary that a single party have control

over the entire reservoir or that the various parties who own interests in the reservoir integrate

their interests either voluntarily or through a requirement by the State. Integration of these interests is referred to as unitization, and problems

with unitization were cited by producers with the

second greatest frequency after price controls as

an EOR constraint. The difficulties surrounding

unitization can be better explained by providing

a brief background on the basic principles of oil

and gas law. It should be noted that most

problems associated with enhanced recovery

methods apply to waterflooding as well.

Therefore, problems with unitization agreements

and possible contamination of ground water are

not unique to enhanced oil recovery.

The right to develop subsurface minerals in the

United States originally coincides with the

ownership of the surface. The owner of land may,

however, sever the ownership of the surface from

85
86 . Ch. V—Legal Aspects of Enhanced Oil Recovery

ownership of the minerals. A variety of interests

may be created, including mineral and royalty interests on all or part of a tract, undivided fractions of such interests, and leasehold interests.

The owner of the minerals normally does this

because he is unable to undertake the development of the minerals himself because of the great

expense and risk of development operations. To

obtain development without entirely giving up

his interest he will lease to another party the right

to explore for and produce the minerals. The

lessee will pay a sum of money for the lease and

will promise to drill or make other payments, and

if there is petroleum to pay the value of a portion of the production to the lessor. Should certain of the terms of the lease not be met, the

lease will terminate and the interest will revert to

the lessor.

In the lease transaction the lessee has both express and implied rights and duties. These often

have a significant impact on enhanced recovery

activities. Among these rights of the lessee is the

right to use such methods and so much of the

surface as may be reasonably necessary to effectuate the purposes of the lease, having due

regard for the rights of the owner of the surface

estate. This would generally include the right to

undertake enhanced recovery operations. Some

authorities have asserted that there is a duty for a

lessee to undertake enhanced recovery. In

general, the lessee has a duty to develop the

lease as a prudent operator and to do nothing to

harm the interest of the lessor. Without the express consent of the lessor, the lessee does not

have the right or the power to unitize the interest

of the lessor.

In order to undertake fieldwide recovery

operations (waterflood or EOR), it is generally

necessary to secure the consent of all or most of

the various interest owners in the field through a

unitization agreement. It may take many months

or even years for the parties to reach such agreement. The principal difficulty lies in determining

the shares of risk and/or production from the

operations. The producing State governments

allow voluntary unitization and provide the parties an exemption from possible application of

the antitrust laws. Most producing States also

provide for compulsory joinder of interest

owners in the unit once a certain percentage of

interest owners have agreed to unitization. This

percentage ranges from a low of 50 percent to a

high of 85 percent as shown in table 34. In the

absence of such legislation, or where the necessary percentage of voluntary participation cannot

be achieved, the undertaking of enhanced recovery operations can result in substantial liability

for the operator due to possible damage to conjoiners.

Once agreement for unit operations has been

reached, it is necessary for the operator or other

parties to go before a State commission for approval of the unit. The commission will require

the submission of a detailed application describing the unit and its operations, the furnishing of

notice of the application to other parties who

might have an ‘interest in the unit operation, the

opportunity for hearing on the application, and

the entry of an order establishing the unit when

the other steps have been completed. The

problems with unitization arise from the

difficulties in securing the voluntary agreement of

different interest owners, and generally not from

the State regulatory procedures.

Prior to undertaking injection programs for

enhancing production of oil, each State requires

the operator to secure a permit for the operation.

The procedure for this is similar to the procedure

for approval of unitization and sometimes may

be accomplished in the same proceedings. There

is little indication that these regulatory activities

significantly restrict or hinder enhanced recovery

of oil with the possible exception of one or two

jurisdictions. The procedures could well change

under regulations promulgated by the Environmental Protection Agency pursuant to the Safe

Drinking Water Act. Producers and others have

indicated that such Federal regulations could

have an important adverse impact on enhanced

recovery.

Once enhanced recovery projects have commenced, a variety of legal problems can arise.

Operators in some States will face the prospect

of liability to parties who refuse to join a unit

when enhanced project operations reduce the

production of such non joiners. There is also the

prospect of liability to governmental agencies
Ch. V—Legal Aspects of Enhanced Oil Recovery

and the possibility of shutting down of opera- doctrines followed in some States. Problems

● 87

such

tions for environmental offenses. Operators- may as these can interfere with the operation of

have difficulty in acquiring adequate water sup- enhanced recovery projects or even prevent their

plies for EOR projects or be subject to a cutting being started.

off of supplies owing to the water rights

Table 34

Comparative Chart of Aspects of Unitization Statutes

State

Percent working or

royalty int. req’d. (vol.

= voluntary only)

Alabama . . . . ...

Alaska . . .

Arizona . .

Arkansas . . .

Cdllfornia Subdence.

California Townsite *

Colorado . . . . . . . . . . .

Florida . . . . . . . . . . . . .

Georgia . . . . . . . . . . . . .

Idaho ... , . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . .

Indiana ., . . . . . . . . .

Kansas . . . . . . . . . . . . . . .

Kentucky. . . . . . . . . . .

Louisiana Subsection B.

Louisiana Subsection C

Maine . . . . . . . . . . . . .

Michigan. . . . . . . . . . . .

Mississippi . . . . . . . . . . .

Missouri . . . . . . . . . .

Montana . . . . . . . . . . . .

Nebraska. . . . . . . .

Nevada..,......,., .

New Mexico . . . . . . ., . .

New York . . . . . . . . . . .

North Dakota . . . . . . . . .

Ohio . . . . . . . . . . . . . . . .

Oklahoma. . . . . . . . . . . .

Oregon . . . . . . . . . . . . . .

South Dakota . . . . . . . . .

Tennessee . . . . . . . . . . .

Texas. . . . . . . . . . . . . . . .

Utah. . . . . . . . . . . . . . . . .

Washington . . . . . . . . . .

West Virginia . . . . . . . . .

Wyoming . . . . . . . . . . . .

75

62.5

63

75

65

75

80

75

None

vol.

75

None

75

75

None

75

85-W - 65-R

75

85

75

80

75

62.5

75

6 0

80

65

6.3

75

75

50

vol.

80

None

75

80

Proof or findings required Water rights

doctrine

Unit area R-riparian

Add. cost Part or All of

Inc. ult. Prevent Protect corr. not over -

Single or

PA-prior

recovery waste rights add. recov. Multip,

appropriate ion

D-dual

-pools system

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

No No Yes

Yes — Yes

Yes — Yes

Yes Yes Yes

. — —

— Yes or Yes

Yes Yes Yes

Yes or Yes

Yes Yes Yes

Yes Yes Yes

Yes

Yes Yes Yes

Yes — —

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

Yes — Yes

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

Yes — Yes

Yes Yes Yes

Yes — Yes

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

— Yes Yes

— Yes Yes

Yes Yes Yes

Yes Yes Yes

Yes Yes Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

—

—

Yes

Yes

Yes

YeS

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

PAM

PAS

PAS

PAS

PAM

AS

PAM

PAM

PAS

PAM

PAM

PAS

PAS

PAM

PAS

A M

PAM

PAM

PAM

PAS

PAM

PAM

PAS

PAS

PAS

PAM

PAS

PAS

PAM

PAM

PAM

PAS

AM

AS

PAM

R

PA

PA

R

D

D

PA

R

R

PA

R

R

D

R

R

R

R

R

D

R

PA

D

PA

PA

R

D

R

D

D

D

R

D

PA

D

R

PA

“See appwrdlx C

Adapted In part from Eckman, 6 Nat Res. LdW)@r 384 (1973).
88 . Ch. V—Legal Aspects of Enhanced Oil Recovery

Policy Options

The factor most often identified by producers

as a constraint to EOR activities was Federal price

controls. A large majority of both independent

and large producers felt that price controls were

inhibiting EOR projects. For example, one

Oklahoma independent stated: “We see no

point in ‘enhancing’ anything until it reaches the

stripper qualification [exempt from price controls]. This makes no engineering sense, but this

is what has been forced upon us by a myriad of

political decisions.” Although price options are

taken up in another segment of the EOR assessment, the price constraint is mentioned in order

to place the other factors identified in perspective. However, it should be noted that differing

treatment of interest owners producing from the

same reservoir does act to discourage unitization.

Because of current price regulations (upper- and

lower-tier prices), producers in the same unit may

not receive the same price for their oil. To avoid

this, it is suggested that whatever price, taxation,

or subsidy determinations are made should not

place an interest owner in a worse position than

before unit operations were undertaken, and

should operate in such a way that each interest

owner will receive the same benefits that other

similarly situated interest owners in the field

receive.

The second most important area now causing

problems for enhanced recovery operations is the

difficulty in joinder of parties for fieldwide operations. Owners of relatively small interests in a

reservoir in many States can effectively prevent

the majority from undertaking enhanced recovery

operations. The problem appears to be greatest

in Texas, which has no compulsory unitization

statute. In other major producing States which

have compulsory unitization statutes, the percentage of voluntary participation required may be

so high as to make unitization of some reservoirs

difficult or impossible. To overcome these

problems, the Federal Government could recommend that each State adopt a compulsory

unitization statute requiring that 60 percent of

the working interest and royalty owners consent

to unitized operations before the remaining’ interest owners would be compelled to participate.

This could be easily incorporated in existing

unitization legislation in each State.

Alternatively, the Federal Government could

require that States adopt such features in their

unitization statutes before the States can qualify

for administrative support or to avoid having a

Federal agency take responsibility for unitization

and enhanced recovery regulation,

While it is likely that this would be a constitutional exercise of Federal authority under the

commerce clause, such a major step probably

would encounter considerable opposition at the

State level. In any case, the desirability of strong

regulations to encourage unitization would depend on a more detailed reservoir-by-reservoir

analysis of the extent to which unitization

problems are in fact an obstacle to a significant

amount of potential EOR activity.

The Federal Government could also recommend to the States that they, by statute, exempt

producers from liability for any damages caused

by State-approved enhanced recovery operations

not involving negligence on the part of the producer. This would remove a constraint to the

operations and would act as an incentive to unitize for parties who might otherwise remain out of

the unit.

As to regulatory requirements and practices,

there were only two important areas of concern

for producers: environmental requirements in

California and the potential impact of the regulations issued by EPA under the Safe Drinking

Water Act. Congress might consider reviewing

the effects of various environmental laws and

regulations on the production of petroleum. Congress might also consider reviewing EPA’s

authority and actions under the Safe Drinking

Water Act to see if the proposed regulations

would unduly restrict enhanced recovery projects. producers did not complain of State EOR

practices and a number indicated that State commissions are most helpful. With respect to

Federal lands, several producers indicated that

the Bureau of Indian Affairs and the U.S. Geological Survey had delayed the initiation of projects

for long periods of time. Congress might consider

directing the Department of the Interior to survey

Federal lands for their EOR potential and to

review its policies on EOR.
VI. Environmental Issues
VI. Environmental Issues

Physiographic Regions

For the purpose of this assessment, the continental United States was divided into four

general types of physiographic regions, each of

which has certain specific characteristics and

vulnerabilities to environmental damage. The

four physiographic regions are: 1 ) the Continental

Shelf which includes the broad, shallow gulf

coast shelf, the steeper sloping Atlantic shelf, and

the narrow steep-edged pacific coast shelf; 2) the

Coastal Plains adjoining the Pacific Ocean, Atlantic Ocean, and the Gulf of Mexico, particularly

those of California, Texas, and Louisiana; 3) the

Interior Basins, such as the Great Plains, Great

Lakes, and the central valley of California; and 4)

the Rocky Mountains and other mountainous

regions.

Continental Shelf

The Continental Shelf, a shallow, flat, submerged land area at the margin of the continent,

slopes gently downward away from the

shoreline. The width of the shelf ranges from less

than 5 miles along portions of the southern

California coastline, to a few hundred miles along

parts of the gulf coast. The topography of a shelf

is highly dependent on its location; the Atlantic

Continental Shelf is relatively flat and shallow

compared to the deeper southern California borderland which has a series of parallel steepwalled ridges and subsea canyons.

Hazards common to all Continental Shelf oil

recovery operations include tidal action, wave

action, storm waves, and collisions with ships. In

addition, hurricanes in the gulf and Atlantic

coasts, landslides and earthquakes in the

southern California borderland, difficulty of control, and unstable bottom substrate pose further

hazards.

Coastal Plains

The Coastal Plains along the Atlantic and gulf

coasts are as much as 100 to 200 miles wide, and

make up nearly 10 percent of the land in the contiguous 48 states. With minor exceptions, the

variance in elevation is less than 500 feet and for

more than half of the Coastal Plains is less than

100 feet. This low topographic relief results in extensive marshy areas. Coastal marshes, estuaries,

and near-shore waters are all considered part of

the Coastal plains area. In contrast, the coastal

plain in California is narrow, limited by the

coastal mountains, and has a poorly developed

marsh system.1

The geologic formations are quite young,

usually Cretaceus, Tertiary, and Quaternary in

age. These sedimentary deposits represent

various onshore, nearshore, and offshore environmental depositions. The formations generally dip

gently seaward and outcrop in belts roughly

parallel to the inner and outer edges of the

Coastal Plains.2

Although many coastal wetlands have been

designated as wildlife refuges and recreation

areas, large parts of the Nation’s Coastal Plains

are covered by major population centers. In the

arid Southwest, Coastal Plain inhabitants rely

heavily on local ground water supplies. The U.S.

Coastal Plains which have the potential for the

greatest EOR activity are those of southern

California, Louisiana, and Texas.3

Interior Basins

The Interior Basins include all land areas of the

United States except the mountainous areas and

the Coastal Plains. Within the interior drainage

basins, there are geologic basins which may contain large quantities of oil entrapped beneath the

surface. Generally; the geologic formations are

older than those in the Coastal Plains.

Ichar[es B. Hunt, /%ys;ograph y of the United states, W.

H. Freeman and Company, San Francisco, Calif. 1967.

Zlbid.

~Enhanced 0;/ Recovery, National petroleum COUIIC il,

December 1976.

91
92 . Ch. VI-Environmental Issues

Some EOR activity is expected to take place in

the Interior Basins, particularly those of the midcontinent and central California. Typically, the

urban centers and farm areas of these basins depend heavily on local ground water supplies. The

ground water aquifers of these basins are

recharged by local rivers and by runoff from bordering mountains.

Mountain Ranges

The mountainous areas are rich in timber and

minerals. Some EOR operations are anticipated in

the Rocky Mountains, particularly in Wyoming.

These mountain areas offer diverse benefits to

society since they are prime wildlife and recreational areas; with their relatively high snowpack,

they are frequently a major source of ground

water for adjacent plains. These generally are

remote unpopulated areas, where direct EOR impacts on the human population are limited but

where adverse impacts on the natural environment can be significant.

Causes of Environmental Effects

The following elements and processes are

common to all EOR methods: a recovery fluid; an

injection system; surface processing; and disposal of spent materials.

The processes and the materials used within

the confines of the system pose no environmental threat. Environmental problems result only

when the materials are allowed to escape. The

following mechanics may be responsible for such

escape:

1)

2)

3)

4)

5)

Transit Spills—Spills which may occur

when material is being prepared at or

transported to the field site.

Onsite Spills—Spills which may occur at

the field site from surface lines and/or

storage facilities.

Well System Failure--Escape of materials

which may occur from failure of the injection or producing well due to casing leaks

or channeling.

Reservoir Migration--Fluid may migrate

outside of the confining limits of a reservoir through fractures or through a well

bore which interconnects reservoirs.

Operations —The effects caused by

routine activities and by the support

facilities and activities associated with

EOR production. To determine environmental problems during operations, the

effect of each of the following must be

considered: disposal of spent material;

consumption of site-associated natural

resources; discharge emissions; fugitive

emissions; and off site supply and support

efforts.

A simple matrix model was developed to compare the relative significance of environmental

impacts from spills, well failure, reservoir leaks,

and operations from thermal, miscible, and

chemical EOR methods in each of the four

physiographic regions. The matrix reflects a subjective assessment and relative ranking of the significance of potential impacts from negligible or

nonexistent (1), to potentially significant (4). The

values assigned on table 35 are comparable only

when applied to a specific EOR process and environmental component such as thermal and air.

Table 35 relates to potential hazards from each

EOR project by physiographic area. To suggest

possible total impact of each EOR process, table

36 was developed. This matrix attempts to predict the relative degree of development of the

EOR method as a function of the physiographic

area. Should time and/or experience indicate

different values, they could be substituted without invalidating the matrix presented.

By selecting the appropriate value from table

36 and multiplying it by the value for the same

process and physiographic area on table 35, an

estimate of the weighted environmental impact

of any or all effects can be calculated. Table 37 is
Ch. VI-Envionmental Issues . 93

—

—

--v . l-- .-l-n --- -

-

cm m

u

c

.5

--- - l- l-!-m ~-- m

--- - --- - .-- r

—

m

— —

—

m

o

5

—
94 . Ch. VI-Environmental Issues

the sum of each environmental component in a

physiographic area times the appropriate value

from table 36. After determining the value for

each of the physiographic areas for an EOR process, they are total led and the value transferred to

table 37.

The values in table 37 suggest possible relative

environmental impacts. For example, chemical

Tabie 36

Potential Distribution of Environmental Impacts for

Enhanced Oii Recovery

(Prediction of the Relative Degree of Development of the

EOR Method as a Function of Physiographic Areas)

Physiographic Area

Continental ] Coastal I

Interior I

Method Shelf Plain Basin Mountains

Thermal. . . 1 4 2 2

Miscible . . 1 3 3 2

Chemical. . 1 3 4 2

SCALE UNITS: 1 - Improbable; 2- Negligible;

4- Significant; 5- Extensive

Potential

There are at least seven media in

3- Moderate;

Impacts

which EOR

operations could have environmental impacts:

air, surface water, ground water, land use, seismic

disturbances and subsidence, noise, and biological and public health. While each of the four

physiographic regions can experience environmental repercussions in these seven media, certain types of impacts will be far more important

in some regions than in others. For example, air

pollution is a concern primarily in urbanized portions of the Coastal Plains and in Interior Basins

where air quality is already in violation of Clean

Air Act standards.4 Similarly, land-use conflicts

arise in heavily populated areas where land

values tend to be high and multiple-potential

uses exist for a given parcel of land. Ground

water use and pollution is a grave concern in

areas where ground water is a principal component of the water supply, such as in central and

i~onicoring and Air Quality Trends Re~orf, U.S. Environmental Protection Agency, Office of Air and Waste Management, 1976.

EOR projects may have the greatest potential for

environmental impacts and thermal the least, or

the biota may be the most impacted and land the

least. Sweeping conclusions should be drawn

with caution, however, because individual sites

and production conditions for EOR, and thus

possible environmental impacts, vary significantly from setting to setting.

Table 37

Cross Plot of Environmental Impacts for Enhanced Oil

Recovery

(This Model Cross Plots the Impact Matrix With the

Distribution Model To Obtain a Relative Analysis of the

Total Process Impacts)

Environmental Components

Method Air I Water I

Land !

Biota !

Total

Chemical 50 112 50 117 329

Total. . . . 178 258 132 272

I I I 1 I

on the Environment

coastal California. Surface water pollution is important in areas with high surface runoff and at

sites adjacent to surface water bodies. Noise is a

concern in both urban and open areas, although

natural ecosystems differ widely in their sensitivity to noise.

The matrix described previously attempts to

identify the physiographic regions most likely to

experience each type of environmental impact.

The most likely means of generating these impacts are discussed below. Although some effort

is made to quantify these impacts, it is not possible to do so precisely with the data available.

Air Quality Impacts

While all EOR methods (thermal, miscible, and

chemical) can cause air pollution, thermal

methods are most likely to generate air pollution

impacts. Steam and hot-water flooding rely on

steam generators. These generators usually use

the fuel supply available on location (oil being
Ch. VI-Environmental Issues . 95

the most common fuel source), and emit sulfur

dioxide (S02

), oxides of nitrogen (NOX), hydrocarbons, carbon monoxide (CO), carbon dioxide (CO2

, and other combustion products from

exhaust pipes, In situ combustion can release

these same compounds as fugitive emissions and

as exhaust from high volume air compressors.

These types of impacts from thermal EOR activities are likely to be localized and to be significant primarily in areas that are already in violation of, or are near the limits of, the Federal Ambient Air Quality Standards. In addition, NOX

released together with hydrocarbons escaping

from the oil production process constitute a mixture with the potential to generate oxidant far

downwind from the point of release. Further,

nondegradation requirements may become important in remote areas.

The following sections discuss the mechanisms by which air quality impacts are generated

and attempts to assess environmental air quality

effects of various EOR methods in the four

physiographic regions. The impact estimates are

based on data which are now available. As more

data become available, more meaningful projections of air pollution impacts will be possible.

Air Pollution Impacts of

Thermal Recovery Methods

Although some estimates of the air pollutant

emissions from steam flooding projects are

available, there are very few quantitative data.

Estimates of air pollution impacts of steam flooding can be made if both the amount of fuel to be

burned and the emissions per unit volume of the

fuel burned are known. Emissions from the oil

production, (i.e., hydrocarbons, hydrogen sulfide

(H2S), and other emissions escaping from the production wells), are in addition to these exhaust

gases.

Emission factors for fuel oil combustion are

shown on table 38. Most thermal EOR processes

will burn fuel oil or comparable petroleum products and will fall into the residual oil classification. The powerplant classification would apply

only to the largest boilers used in EOR. Oxides of

nitrogen (NOX

) emissions from powerplants and

other large sources are higher because of the

higher combustion temperatures encountered,

while hydrocarbon and particulate emissions are

lower because of better combustion regulation

and more efficient burner designs

Table 38

Emission Factors for Fuel Oil Combustion

(Pounds Emitted per 1,000 Gallons Burned)

Aldehydes, ., . . . . . . . . 1 1 2

Hydrocarbons . . . . . . . . 2 3 3

co. . . . . . . . . . . . . . . . . 3 4 5

NO X (as NO2 . . . . . . . . 105 40-80 12

SO* . . . . . . . . . . . . . . . . 157 S* 157 s“ 142 S*

Particulate . . . . . . . . . . 8 23 10

s ● = Percent sulfur in oil

Steam generator emissions in pounds emitted

per 1,000 barrels of oil produced can be calculated from table 38 using the values given for

residual oil. The results of this calculation are

given in table 39. Estimates in table 39 are based

on the consumption of 0.3 barrel of oil for every

1.0 barrel of gross production. This level of consumption approximates commercial-scale steam

generator operations in the San Joaquin Valley in

California. The emission factors presented in table 39 are estimates only and do not necessarily

portray accurate emissions of in-field EOR steam

generators. The figures in the table can be linearly

scaled to account for variations in consumption.

Recently, there has been serious consideration

of use of coal as an inexpensive fuel to provide

steam for thermal recovery, including use in

California. Use of coal could cause somewhat

higher emissions in every category.

Table 39

Steam Generator Emissions

[Pollutants Emitted per 1,000 Barrels of Gross Oil Produced)

Hydrocarbons . . . . . . . . . . . . . . . . . . . . 40 Ibs

SO* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,OOO Ibs

NO,. . . . . . , . . . . . . . . . . . . . . . . . . . . . . . 800 Ibs

Particulate. , , , ... , , ... , ., ... , . . . . . 280 Ibs

● For crude containing 2 percent sulfur, without flue gas desulfurization.

NOTE: This table assumes that 0.3 barrel of fuel oil IS burned for every 1.0 barrel of gross production. Due to a shortage of data,

fugitive emissions are excluded for the analysis.

‘j. A. Eldon and J. A. Hill, “Impacts of OCS Oil Development on Los Angeles Air Quality, ” In Southern California

Outer Continental Shelf Oil Development: Analysis of Key

/ssues, U. C.L.A. Environmental Science and Engineering

Program, Los Angeles, Calif., 1976.
96 . Ch. V/—Environmental Issues

The new performance standards for fuel oil

combustion were not used in making this calculation because oilfield steam generators rarely exceed the 250 million British Thermal Units (Btu)

per hour capacity covered by these regulations.

A probable density of steam generators, and a

level of steam generation required for a given

well production rate, must be considered in order

to estimate the overall pollution impact of a

steam flood project.

The total emission rates from a field can be

calculated using data in table 39. The resulting

emission estimates can then be used in the

evaluation of the impact of steam flood EOR on

any specific region. As an example, the

Wilmington Oil Field produced 67 million barrels

of crude oil in 19736 by primary production; the

field may eventually be a candidate for EOR.

Steam flooding may be applicable due to the low

American Petroleum Institute (API) gravity (high

density) and high viscosity of California crude,

and the considerable thickness of the oil-bearing

stratum. The production of 30 million barrels per

year by steam flooding (a potential for the

Wilmington field) would involve the combustion

of some 9 million barrels per year of fuel in the

field steam generators. With the emission factors

developed above, this combustion rate corresponds to the air pollutant emissions rate given in

table 40.

Table 40

Projected Emissions from Steam Flooding of a Major

Oil Field Compared to Los Angeles County Emissions

I

Emissions from a 3 0

I

Los Angeles

Pollutant million bbl/year field County Total

NO X . . . . . . . . 32 tons/day 1,000 tons/day

Particulate . . 12 tons/day 120 tons/day

so2 . . . . . . . . . 81 tons/day* 300 tons/day

Hydrocarbons. 2 tons/day 1,000 tons/day

*An 011 sulfur content of 2 percent was assumed

Table 40 also shows the total current emissions for Los Angeles County. Enhanced oil

recovery emissions calculated for this example,

with the exceptions of hydrocarbons and oxides

of nitrogen, would be a significant fraction of the

6Ca/jfornja 0;/ and Cas F;elds, Vol. 2, cat Ifornla Division

of Oil and Gas, Report No. TR12, 1974.

total emissions of Los Angeles County, Extensive

exhaust gas scrubbing, consumption of low-sulfur

fuel oil, and reduced scale of operation would be

necessary in order to reduce S02 emissions to acceptable levels. Although these processes could

reduce the emissions to lower levels, the resultant emissions will still be significant, at least on a

local scale, since they are released into a heavily

polluted airshed. Furthermore, they are released

from a relatively small source area by comparison

with the entire county, and could produce substantial impacts along a downward trajectory

over a heavily populated region.

Emissions from in situ combustion are highly

dependent on the oil formation, the type of

crude oil, and the manner in which the project is

operated. The high density of the crude oil in

California and low economic returns experienced

thus far indicate a low potential for in situ combustion, even though most oilfields in California

can be spontaneously ignited by unheated air injections alone. To date, there are very few data

available regarding the emissions from in situ

combustion projects. It is anticipated that in

order to meet air-quality pollution-control standards, especially in some areas of southern California, gas collection and treatment systems will be

required,

In situ combustion and steam flooding are expected to have the greatest air-quality impacts in

regions of low inversions, low wind speeds, and

already polluted air, such as California’s coastal

plains and central valley. In remote mountainous

regions, if background air quality is generally

good and meteorological dispersion is favorable,

a smaller impact may be expected. It should be

noted, however, that high mountain valleys often

experience severe inversions and air stagnation.

Furthermore, nondegradation standards may apply for mountainous recreational areas. Thus air

pollution impacts cannot be disregarded for such

areas. While light air-pollution emission over the

Continental Shelf would normally be considered

inconsequential, there are areas in which these

emissions must be carefully controlled, as in the

southern California borderland. Any emissions

released there have a high probability of being

transported to shore, where they will contribute
Ch. V/—Environmental Issues ● 97

to an already serious air pollution problem.7 Due

to the low thermal and mechanical turbulence of

air over water, dispersion of air pollutants over

water is much slower than over land.8 The Atlantic coast is just the reverse of the California situation in that the prevailing winds are from the

west, so that emissions generated along the coast

usually would be transported out over the Atlantic Ocean. The gulf coast tends to be a combination of the Atlantic and Pacific coast situations;

depending upon the time of the year, the prevailing wind direction can be either from the north or

the south.

Air Pollution Impact of

Miscible Flooding Recovery Methods

Because miscible flooding does not involve

high rates of either fuel combustion or in situ

combustion, it is probable that C02 injection will

have a much smaller air-quality impact than will

the thermal methods discussed earlier. However,

if hydrogen sulfide (H2S) is injected into a reservoir and subsequently escapes, poisoning of

humans and wildlife could result. There have

been instances of this in the past. However, it is

very unlikely that H2S will be used as a primary

constituent in any future major gas injection projects. Carbon dioxide is nontoxic, but capable of

causing suffocation if concentrations are high

enough. It will most likely be obtained from industrial activities (coal gasification), or natural

reservoirs. The main air pollution impact resulting

from C02 recovery methods will be the release

of hydrocarbons and H2S from formations into

which C02 is injected. An important air quality

concern is that C02 combined with H2S in a gas

mixture might have inadequate buoyance to disperse quickly, With the reduced buoyance, H2S

remains concentrated at ground level long

enough to pose a threat to human and animal life

because of its toxicity. Such effects are difficult

7J. A. Eldon and J. A. Hill, “Impacts of OCS Oil Development on Los Angeles Air Quality, ” In Southern California

Outer Continental Shelf Oil Development: Analysis of Key

/ssues, U. C.L.A. Environmental Science and Engineering

Program, Los Angeles, Calif., 1976.

Ep. Michael, C, S, Raynor, and R. M. Brown, “Atmospheric

Dispersion from an Offshore Site,” in Physical Behavior O f

Radioactive Contaminants in the Atmosphere, p. 91, international Atomic Energy Agency, Vienna, 1974.

to quantify without detailed information concerning concentrations of H2S and C02 that

would be emitted from gas injection recovery

projects.

Because there has been considerable concern

and a large degree of misunderstanding about

H2S and its potential safety and health threat to

humans, the environment, and to equipment,

further discussion is warranted. Concern has been

generated to a large degree from an incident that

occured at Denver City, Tex., in 1975, which

resulted in nine fatalities. Hydrogen sulfide is

toxic, flammable, explosive, corrosive, and may

be naturally present in reservoirs. The concentration of H2S which constitutes a harmful quantity

depends upon the subject being considered,

whether humans, the environment, or equipment. Therefore, regulations have been adopted

by various governmental agencies to require all

stages of H2S operations to conform to safety and

environmental standards.9 Smith, the principal

author of Texas Rule 36 which regulates this injection method, states that a dangerous condition would prevail if leaks of a certain volume exist, weather conditions complimentary to gas

cloud ground accumulation exist, and persons

unaware of the situation are present.10 Texas Rule

36 and regulations adopted by other States have

been formulated to prevent the above conditions

from occurring. Hydrogen sulfide emission can be

associated with normal oil production and is not

necessarily complicated by any of the EOR processes, although the amounts encountered would

be amplified by increased production. Therefore,

while the H2S problem exists for oil production in

general, excessive concern for magnified H$

problems related to EOR is unwarranted.

Air Pollution Impacts of

Chemical Recovery Methods

Chemical recovery methods do not produce

emissions during application. Any air quality

emissions from chemical EOR methods would be

‘Enhanced Oil Recovery, National Petroleum Council,

December 1976.

IOC. D. Fhrhardt, Jr., “Environmental and Safety Regulations In Sour Gas and Crude Operations, ” in Society of

Petroleum Engineers of AIME Paper Number SPE 5191, 1974.
98 . Ch, VI-Environmcnldl Issues

indirect, in that they would occur from the production of various chemicals and the power

generation required in the pumping process. In

the case of the chemicals, air pollution impacts

from production plants are already covered by

existing air quality control regulations. Some light

hydrocarbons, ethers, or alcohols are expected to

be used in chemical recovery methods. These

would presumably be derived from petroleum

refineries whose air pollution emissions are of

concern, but these may not be new emissions

arising solely from EOR. If EOR were not utilized,

the same refineries would very possibly manufacture other petrochemical products from the same

raw materials. Therefore, the air pollution impacts of the chemical recovery methods “will be

secondary in nature and covered by existing EPA

State regulations.

Surface Water

Enhanced oil recovery methods will require

significant quantities of water over and above

primary recovery methods. It is anticipated that

the EOR fresh water requirements would be higher than the demand in present techniques of

waterflooding. A review of the literature did not

provide firm data on the amount of water required for EOR. In order to quantify the water requirement, it is assumed in this assessment that

one to six barrels of fresh water is needed for

each barrel of oil recovered, This quantity of

water consumption would have a greater effect

on the environment in most regions than any

other EOR impact.

As shown in figure 14, California, Texas, and

western Louisiana are areas where water use is

high and supplies short.11 In fact, severe shortages are predicted by the year 2000. Although

large quantities of water are required for EOR, the

environmental impact on surface waters from

EOR activities is anticipated to be only slightly

greater than that from secondary recovery

(waterflood) methods. The extent of hydrologic

environmental effects will depend upon the

I lwater Information Center Publication, Water Atlas of

the United States, Water Information Center, Inc., Port

Washington, N. Y,, 1973.

characteristics and previous development of a

reservoir. Geographic location, reservoir depth,

and condition of the wells are factors which

determine the potential adverse impacts of EOR

activity on the hydrologic environment. The main

environmental impact on the surface waters will

be the actual consumptive use of the water. In

semiarid areas, water may be required which is

now being used for agriculture or other purposes.

Of the three EOR methods considered, chemical methods have the greatest potential for adverse impacts on surface water resources because

water consumed (fresh water) 1 ) would be equal

to or greater than for miscible or thermal EOR

methods used, and 2) spills of concentrated

chemicals would be environmentally more detrimental to water supplies than spills or emissions

from other EOR processes. The likelihood that

well failures or reservoir leakage due to breakdown of the reservoir would lead to contamination of surface waters is considered to be

minimal.

The environmental effects on surface water of

thermal EOR methods will be greater than those

of miscible methods but less than those from

chemical processes. As with chemical EOR

methods, fresh water consumption in routine

operations will have the greatest impact on the

environment. Past experience has shown that

spills, well fractures, and reservoir leakage are infrequent and basically nondetrimental during

thermal EOR operations.

Miscible EOR methods will have the smallest

environmental effect on surface water. As with

the previous two methods, the quantities of

water consumed in this EOR process—which

presumably would be diverted from farming and

other activities—would constitute the greatest

environmental impact.

Surface water requirements will be largest for

EOR activity in the Interior Basins, smaller in the

Coastal Plains, and smallest on the Continental

Shelf where few EOR projects are expected to occur.

Within the Continental Shelf area, it is anticipated that routine operations would cause the

most environmental damage. Chemical spills,

well failure, and reservoir leakage are thought to
Ch. VI—Envfronmental Issues ● 99

i’

I’y -

1

!’

0

-

%.
100 . Ch. V/-Environmental Issues

be the only mechanisms by which environmental

effects would occur other than those which are a

part of routine operations.

On the Coastal Plains, consumptive water use

would frequently have the greatest environmental impact from EOR production. One exception

to this would be chemical spills which could occur in this environmentally sensitive physiographic area. Thermal EOR methods might have

a slightly greater environmental impact than

miscible EOR methods. For regions where air

quality already is poor, of course, air pollution

impacts from thermal methods could be substantial.

Interior Basins would most likely be affected

by chemical EOR methods. Miscible EOR

methods would have the least environmental impact of the three EOR methods. Almost without

exception, the greatest environmental effect on

the Interior Basins would be water use. As with

the Coastal Plains, the Interior Basins could also

experience a significant environmental impact

from chemical spills, primarily in transit to the injection well sites. The mountainous geographic

areas might be relatively less affected even

though they are environmentally sensitive areas.

Ground Water

potential for ground water contamination

resulting from fluid injections associated with

EOR operations appears minimal. This conclusion

is supported by the lack of ground water contamination problems associated with conventional waterfloods. Only 74 ground water injection problems resulted from operating 44,000 injection. wells in Texas between 1960 and 1975

(an incidence rate of 1.1/10,000 per year); only 3

of these occurred during the last decade (an incidence rate of .02/10,000 per year). Similar safe

operating records exist in the other major oil-producing States with large numbers of waterfloods.

Because EOR injection operations are basically

the same as waterfloods, often using the same injection wells in the same formations, an increase

in the rate of ground water contamination is not

expected. In fact, it is anticipated that the safety

record will improve because EOR injection fluids

are more costly than the water now used in

waterfloods and operators could be expected to

take additional precautions to prevent loss of

these fluids during the EOR process.

As with surface waters, use of water from

aquifers for EOR operations could put a strain on

freshwater supplies in areas where reserves were

limited. In areas where the rate of consumption

exceeds the rate of recharge, the impacts would

be severe. Recent field tests indicate that brinetolerant EOR processes are feasible, and could

significantly reduce the impact of EOR operations

on freshwater aquifers if used.

Land Use

The impact of EOR operations on land use will

not be significant. Additional surface facilities required for EOR activities will be relatively small,

even for large projects. Relatively few additional

flow lines and pipelines will be needed outside

of the reservoir area, except in the case of C02

injections. Where large quantities of C02 are required, pipelines will be required to deliver

economically the C02 to the project sites. Construction of these pipelines poses potential environmental hazards.

For some EOR projects additional wells will be

drilled, and redrilling of wells will occur in older

fields. These activities will cause minor disturbances for short periods but no long-term impacts will be evident, provided care is taken in

the field development.

Geologic Hazards

Potential geologic hazards connected with

EOR methods are subsidence and possible

seismic activity. A great deal of subsidence data

associated with primary oil recovery have been

collected in the Long Beach, Calif., area.12 When

compared with primary recovery methods, it is

anticipated that subsidence actually will be

reduced during EOR operations. The reason for

this reduction is that fluids will be left in the

IZM. N. Mayuga, and D. R. Allen, “Long Beach Subsidence,” Focus on Environmental Geology, R. W, Pank, Oxford University Press, New York, N. Y., p. 347, 1973.
reservoir after the oil is removed, except when in

situ thermal methods are used.

There has been some research relating seismic

activity to the use of secondary recovery

methods. Results of this research imply that

seismic activity will not be increased by EOR

methods. The Rocky Mountain Arsenal near

Denver, Colo., conducted deep well injections

which resulted in an increase in seismic activity

in the Denver Area

13 It should be noted,

however, that these injections were generally

made into deep crystalline rock which did not ordinarily contain fluids. Injected fluid acted as a

lubricant to the existing stress zone which is

believed to have caused the increased seismic

activity. Obviously, oil recovery from reservoirs

would not be considered analogous to the Rocky

Mountain Arsenal situation.

Noise

Although the compressors and other equipment used in EOR generate high levels of noise, it

is unlikely that this noise will cause any serious

environmental impact. The loudest noises, such

as those which would accompany preparation for

the fracturing of the reservoir or injection of

steam in a cyclic steam process, are of short duration. In regions where the local biota or human

population would be adversely affected by noise,

maximum muffling and noise abatement procedures will need to be imposed. Occupational

Safety and Health Act (OSHA) regulations will

serve as a standard for safeguarding humans.14

Biota

Enhanced oil recovery technologies present a

variety of potential biological effects. These are

summarized according to relative significance in

table 35, and most do not appear very serious.

While some do pose potentially significant

“’’Geophysical and Geological Studies of the Relationships between the Denver Earthquakes and the Rocky

Mountain ARsenal Well-Part A,” Quarterly of the Colorado

School of Mines, Vol. 63, No. 1, 1968.

14A. p. G. peters~n and E, E. Cross, Jr. Handbook Of NO;5e

Measurement, General Radio Corp, 7th Ed., 1974.

Ch. Vi–-Environmental Issues . 101

problems, most can be adequately addressed and

avoided.

Many areas where EOR activities would take

place have already undergone primary and secondary development, and environmental impacts

will therefore not result from EOR activities

alone. Some of the potential impacts are common-to all processes, while others are the result

of or dependent upon a particular process. Table

41 identifies the activities that might be expected

to create biological impacts.

Table 41

Potential Biological Impacts Resulting From EOR

Process - Independent Impacts

Consumption of water

New well drilling (land-use/habitat impacts)

Extended time frame of activities

Pipeline to provide water

Increased refinery effluents

Process - Dependent Impacts

Thermal: Air emissions

Cooling and consumptive water use

Energy source

Miscible: Air emissions

Pipeline and source of CO2

pH changes

Chemical: Manufacturing, handling, and disposal of

chemicals

Process Independent Impacts

Probably the most significant potential adverse

biological impact of EOR will result from the increased water consumption associated with this

technology. Because fresh water (rather than

saline water) is generally required, EOR process

consumption of water will not only compete

directly with domestic, agricultural, and other industrial uses, but could result in a localized

drawdown of surface water, severely affecting

aquatic flora and fauna within the area of the

drawdown.

The Interior Basin and Mountain regions may

be the most seriously affected by this consumptive use of water. Interior Basin areas already face

some of the most serious water allocation

problems, and wetland or aquatic ecosystems

have already been substantially affected in many

parts of this zone. While they have not experienced the same demands for water use,

Mountain wetland areas are comparatively more
102 . Ch. V/-Environmental Issues

fragile and vulnerable to drawdown. Also, consumptive use of water in the Coastal Plains could

increase salt water intrusion, and significantly

alter coastal wetland communities.

Potentially serious impacts may also result

from new well drilling activity. Because EOR

techniques will always be applied in areas of previous drilling activity, support facilities and access roads will generally be available. However,

depending on the density of facilities needed for

EOR, new construction may be significant. In the

past, significant impacts have resulted from well

drilling activities in wetland and aquatic areas,

particularly in the Coastal Plains and mountain

areas. These impacts have generally resulted from

loss of habitat associated with a well drilling site,

or from alterations (such as canals, ditches, and

roads) to provide access. Canals used as access

for drilling operations in coastal areas have

caused significant adverse effects on shallow

aquatic habitat and on marsh wetlands. These

impacts have largely been caused by alteration of

the hydroperiod and the fresh water—salt water

interface. The changed salinity regimes which

have resulted have caused severe alteration of

wetland types as well as the fauna inhabiting

them. The activities associated with construction

of access to sites in the Coastal Plains, particularly dredging and filling, have also created

substantial impacts.’ 5 The resulting changes may

be permanent.

Because of the fragile nature of mountain

ecosystems and the long times they frequently

need to recover from impacts, road construction

in Mountain regions also poses a threat of significant impact.

“These impacts are not a necessary consequence of new well drilling activity. Although

potentially significant, most can be avoided by a

thorough initial understanding of the system

which may be disturbed, followed by careful

construction and drilling practices. Because EOR

activity occurs in areas of previous activity,

economics dictate that maximum usage will

I $[dward T. LaRoe, Effects oi Dredging, F1//ing, and Channellzatfon on Estuarine Resources, pp. 134-1 44; “Proceedings, Fish and Wildlife Values of the Estuarine Habitat, A

Seminar for the Petroleum Industry, ” p. 184, U.S. Department oi the Intenor, Fish and Wildlife Service, 1973.

generally be made of existing roads, facilities,

and other structures,

Although EOR techniques may, on occasion,

permit more rapid production of oil, they will

generally extend the time during which production activities take place by 10 to 20 years. This

will result in continued traffic, noise, dust and air

emissions, and other actions of potential impact

on biota. These will not usually be important,

since the areas will already have been subject to

primary recovery activity and because the remaining biota often will have adapted to man’s

routine activities after an initial period of displacement or disturbance. Some exceptions include activities adjacent to or otherwise affecting

breeding and nesting areas or migratory routes.

Some particular species (frequently endangered

species) are not compatible with man’s activities.

Continued operations might preclude their return

or survival in localized areas, although this would

be an infrequent occurrence.

Because EOR processes will often require new

or increased supplies of water, or water of

different quality, the construction of water supply pipelines could also affect the biological environment. Such activity will result in direct loss

of some habitat, and could affect the biota in

other ways. For example, construction of

pipelines across wetlands may be accompanied

by the digging of a ditch, canal, or diked road;

these would interrupt or alter the surficial

sheetflow of water. Again, these impacts can be

reduced through careful route selection and

methods of construction. Frequently, pipelines

will already exist to deliver water to production

fields. It may be possible to use the opportunity

created by new construction to rectify problems

caused by existing pipelines.

Process Dependent Impacts

Each EOR process could have some specific

biological impact. It appears that some of these

will be of less significance than the potential impacts previously described. All of the EOR processes will result in air and water emissions, which

must be controlled to be in compliance with the

applicable air and water quality standards.

However, it is important to recognize that attainment of standards will not avoid all biological impacts.
Ch VI—Environmental lssue~ ● 103 #

Therrnal.-Steam injection processes will have

large demands for water, creating a potential for

increased impacts caused by water consumption

and the need for water pipelines.16 Steam injection will also require substantial energy for steam

generators and compressors. Existing facilities are

usually powered by onsite generators fueled by

petroleum products (oil or gas) produced at the

well. These are noisy and air polluting. If EOR

operations become widespread, the industry

might desire to switch to electrically powered air

compressors and other equipment. The off site

production and supply of electricity (very likely

from coal) could result in off site biological effects

which would vary in significance with the type

and location of power generation.

The air emissions produced by both steam injection and in situ combustion thermal EOR techniques WIII pose potentially slgnificant biological

impacts. If uncontrolled, the impacts of these

emissions could be most severe in the California

coastal plain and Interior Basin areas because

these areas not only appear the most likely

regions for use of thermal EOR techniques but

also have dirtier air than most other regions. The

most critical effects would be on humans and

vegetation, although the chronic effects on

wiIdlife could also be significant. Air polIutants

from EOR operations can probably be controlled;

however, there has been little applied research in

this direction to date. It is reasonable to expect

that a serious research effort would make possible considerably reduced impacts.

Thermal projects also need to dispose ot

heated water after it has been used for coo!ing. If

discharged into surface waters, hot water can

lead to changes in marsh and aquatic plant and

anirnaI Iife and promote the growth o f

phytoplankton algae, including blue-green algae,

which can harm natural flora, fish, and wildlife.

The thermal impact could be avoided by the use

of cooling ponds, which could create localized

air impacts of generally small consequence. Well

failures or reservoir leakage could also result in

the release of thermal pollutants; however, the

“)tnhanccd Of: R(I( (Jv(rv, Vdt lonal Petroleum Counc I I,

December 1976.

impact of such discharge would generally be very

localized and of little significance.

Thermal EOR processes frequently result in

recovery of large amounts of oil-associated

water, which is usually reinfected.1’ However, if

the water is not reinfected and is discharged

without treatment, the chronic release of this

water, with entrained oil and traces of heavy

metals, could adversely affect aquatic biota.

Thermal processes will also produce solid

waste material, including fly ash from scrubbers

used to control air emissions. The most direct impact will be in the need for land area to dispose

of solid wastes (and the loss of habitat which that

may cause). Shipment of material to suitable sites

will cause some adverse impacts. Biological impacts of an efficiently designed and operated

system can be kept small.

Miscible.--+robably the most significant potential biological impacts resulting from the C02

miscible EOR process will be those relating to the

supply and transportation of C02

. For EOR use,

C 02 will originate from C02 wells, or as a

byproduct of other industrial activity. It will

usually be transported to the field by pipelines,

although in small projects C 02 may b e

transported by refrigerated truck or tank car.

While C02 itself is not toxic, the activities associated with its collection and transportation may

have adverse biological impacts. Carbon dioxide

pipelines can have the same biological impacts

discussed for water pipelines above. The primary

areas presently identified for C02 production are

the Four Corners area, the northeast New Mexico-southeast Colorado area, central Mississippi,

Texas, Utah, and Wyoming. These areas, and

places along the pipeline routes to Texas, will

have the most significant potential for impact,

but the impacts will be localized That is, they

will be restricted to the immediate area of C02

production and the pipeline route.

As with thermal processes, miscible processes

wiII result in increased air emissions. The release

of C02 itself would not have adverse biological

effects, although adverse effects could result

-—.—

1“Ibid
104 . Ch. VI—Environmental lssues~

from the release of other gaseous contaminants,

such as H2S. If properly treated, or if reinfected,

these emissions will have insignificant impacts.

1 he release of C02 under pressure to aquatic

systems, as might occur with well failures or

reservoir leakage, could result in a decrease in pH

of the water body. The biological significance of

this pH change would depend on the size of the

water body, amount of C02 released, and the

duration of release. However, aquatic life,

especially freshwater fish, is particularly susceptible to increased acidity. While the potential for

such an occurrence is extremely small, the impact, if it occurred, could be locally significant.

Chemical.-Although several chemicals that

could be used in EOR processes have been

described in literature, it appears in practice that

only a few will actually have extensive use. Table

42 lists chemicals described in patent literature.

Chemicals commonly used include broad

spectrum petroleum and synthetic petroleum

sulfonates; alcohols; polyacrylamide and

polysaccharide polymers; sodium

dichlorophenol and sodium pentachtorophenol;

sodium hydroxide and sodium silicate.18 These

do not appear particularly hazardous in the concentrations used, nor do they become concentrated in food chains. However, the manufacturing, handling, and disposal of these chemicals

pose potential biological impacts.

If chemical flooding methods are widely

adopted, there must be a substantial increase in

the production of some of these chemicals,

especially the surfactants. Expanded manufacturing capacity could result in localized adverse imTable 42

Potential Chemicals Used in Chemical Flooding

Chemicals Proposed for Surfactant Flooding:

● Broad spectrum petroleum sulfonates

● Synthetic petroleum sulfonates

* Sulfated ethoxylated alcohols

* Alcohols

“ Ethoxylated alcohols

Chemicals Proposed as Bactericldes:

* Sodium dichlorophenol

* Sodium pentachlorophenol

Formaldehyde

Gluteraldehyde

Paraformaldehyde

Alkyl phosphates

Alkylamines

Acetate salts of coco diamines

Acetate salts of coco amines

Acetate salts of tallow diamines

AlkyIdlmethl ammonium chloride

COCO dlmethyl ammonium chloride

Sodium salts of phenols

Substituted phenols

Sodium hydroxide

Calcium sulfate

Chemicals Proposed for Alkdline Flooding:

* Sodium hydroxide

* Sodium silicate

Ammonium hydroxide

Sodium carbonate

Potassium Hydroxlde

Chemicals Proposed for Mobility Control:

* Polyacrylamide

* Polysaccharide

Aldoses B Series

Aldoses L Series

Car boxy methylcelIulose

Carboxyvinyl polymer

Dextrdns

Deoxyribonucleic acid

Ketoses B Series

Ketoses L Series

Polyethylene oxide

Polyisobutylene in benzene

Conjugated saccharides

Disaccharides

Monoosaccharides

Tetrasaccharldes

pacts through loss of habitat and potential air and”

water emissions.

Transportation of the chemicals commonly

used for EOR operations is not likely to pose a

major hazard. Many are frequently shipped as Chemicals Proposed as Oxygen Scavengers:

solids, which reduces the potential for a spill. Sodium hydrosulfite

Small spills of Iiquids, both during transportation Hydrazine

Salts of bisulfite

“Most c ommmrly used

! 8Enh~n~ eo (Jjl R {>( ovi’ry, National Petroleuln Council, Tlve above tdble was modified from [nharrced 011 Rec owry,

December 1976. National Petroleum Council, December 1976.
and onsite use, are to be expected, but the

biological impact will be limited since they are

primarily of low toxicity.

Even though tests have shown that chemicals

common I y used i n EOR processes have a 10 w

acute toxicity, the long-term effect of such

chemicals on the environment has not been

evaluated. Not until such long-term studies have

been conducted on the chemicals used in EOR

processes can the potential for adverse environmental impacts be dismissed.

Disposal of produced water containing the

chemicals will pose another potential waterquality impact. Most chemicals will be absorbed

within the reservoir and the amount produced

wilI be small. Although the chemicals are not particularly toxic, some (particularly the polysaccharide polymers) could act to increase biological oxygen demand (BOD) in the receiving water

and this would adversely affect fish species. Potential biological impact can be avoided by disposing of chemically Iaden produced water by

either relnjecting it into the oil-producing reservoir, injecting it into other saline aquifers, or

treating it to remove contaminants before disposal into surface waters.
Appendixes
—

Appendix A

Oil Resource for Enhanced Recovery Projections

Contents

OTA DATA BASE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reservoir Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Selection of Data Items. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Data Collection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1. Identification of Data Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2. State Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3. Estimation and Calculation of Missing Data Items . . . . . . . . . . . . .

Data Coverage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . :

Fields and Reservoirs in the OTA Data Base. , , , . . . . . . . . . . . . . . . . . . . . . . . .

Offshore Fields in Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Documentation of Data Sources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ANALYSIS OF RESERVOIRS IN DATA BASE TO DETERMINE AMOUNT

AND DISTRIBUTION OF REMAINING OIL.... . . . . . . . . . . . . . . . . . . . . . . .

Distribution of the Original Oil in Place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Volume of Remaining Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Distribution of the Remaining Oil Resource . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reservoirs With Limited Waterflood Response . . . . . . . . . . . . . . . . . . . . .

Reservoirs Under Natural Water Drive or the Waterflooding Process. . .

Consistency of Oil Resource Estimates With Those Implied by Other

Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

LIST OF TABLES

Table

Number

A-1. Average Oil Saturation in the Region Swept by Waterflood . . . . . . . . . .

Page

111

111

111

111

111

113

1 1 3

1 1 3

11.3

1 1 8

1 2 2

1 2 9

1 3 9

1 3 9

1 3 9

1 3 9

1 3 9

1 4 0

141

141

A-2. Comparison of lnitial Oil in Place Computed for Estimates of Sweep Efficiency and Residual Oil Saturations . . . . . . . . . . . . . . . . . . . . . . . . . . 142

LIST OF FIGURES

Figure

Number

A-1. Big Fields Reservoir Data File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

109
Appendix A ● 111

OTA Data Base

The oil recovery projections for enhanced oil

recovery (EOR) processes were determined from

the results of reservoir-by-reservoir simulations.

The accuracy of this approach depends on the

extent, representativeness, and accuracy of the

reservoir data file. In earlier work, Lewin and

Associates, Inc., collected detailed data on 245

reservoirs in three States, California, Louisiana

and Texas. The Office of Technology Assessment

(OTA) contracted with Lewln and Associates,

Inc., to expand this data base to include all major

oil-producing States and at least 50 percent of

the remaining oil resources. The expanded data

base, referred to as the OTA data base, covers a

broad range of geographic locations and reservoir

types as well as the largest 300 domestic reservoirs on which public data are available.

This appendix describes the development and

content of the OTA data base. Sources of data

are documented by geographic region.

Reservoir Selection

A list of the largest oilfields (measured by

cumulative production plus remaining reserves)

was constructed from available data.1 The exponential distribution of the size of the Nation’s oilfields—the largest 300 fields provide over twothirds of the Nation’s production-suggests that

the preponderance of tertiary recovery opportunities lies in the major fields.

Data collection, therefore, began by focusing

on the largest fields and the largest reservoirs

within these fields. Smaller fields and reservoirs

were added to the file to increase the proportion

of each State’s oil covered by the data base.

Thus, the OTA data base contains reservoirs and

fields of varying size, although the preponderance of the reservoirs is quite large (over 50

million barrels cumulative production plus remaining reservoirs). An analysis was conducted

to ascertain whether the preponderance of large

fields renders the data base unrepresentative. No

systematic bias was introduced by the number of

larger fields.

Selection of Data Items

The data items included in the file were

established by the three key tasks involved in

EOR analysis, namely to:

1. Screen fields and reservoirs at two levels: (a)

2

3

favorable or unfavorable to tertiary recovery; and (b) for the favorable reservoirs, the

most preferred tertiary technique.

Calculate the oil in place and amount to be

recovered through primary, secondary, and

tertiary methods-based on actual reservoir

parameters and production histories.

Calculate investment and operating costs of

the preferred tertiary technique--based on

region, reservoir, and crude oil characteristics.

Detailed data were collected concerning formation and crude oil characteristics, production

histories, and original (OOIP) and remaining oil in

place (ROIP). Figure A-1 is a copy of the form

used to display data for each field and its producing reservoir(s). Complete reservoir data (as

shown on the form) were avaiIable for only a few

reservoirs. Although there are many data missing,

complete volumetric and production data were

available for each reservoir in the OTA data base.

Data Collection

A three-step approach was used in collecting

the reservoir data:

1, Identification of Data Sources

National level data were available for fields

through the American Petroleum Institute (API)

and the U.S. Geological Survey (USGS)-sponsored

Oil Information Center. However, little was

available for reservoirs within these fields.

Detailed data on reservoirs were gathered from

State agencies, State-level private organizations,

and general publications. In this step, the available data sources were cataloged and evaluated as
112 ● Appendix A

2

9. -

L

a

s

n

d

m

&

>

a ●

‘4

**
Appendix A . 1 l.?

to their completeness and reliability. From this

evaluation, priorities were assigned to the identified sources.

2. State Procedures

For each State, detailed procedures were

developed which described the data to be collected from each source, the sequence of using

the sources, and decision rules for any estimates

or averaging necessary to complete the data collection forms.

3. Estimation and Calculation of Missing

Data Items

After’ rigorously examining and cataloging all

available data sources, some of the data remained missing. When these data were critical to

the analysis, they were estimated using engineering formulas and empirical correlations. All data

were edited for volumetric consistency, a requirement of later steps in the analysis.

Application of this procedure required

numerous followup contacts with Federal and

State sources to elicit additional data, to verify

interpretations, or to procure additional suggestions regarding data sources.

Data Coverage

Table 6 in Chapter Ill shows the scope and

coverage of the OTA data base. The 19 States included account for 96 percent of the oil remaining in domestic reservoirs. The individual reservoirs in the data base account for over half of the

Nation’s remaining oil, The percentage coverage

of each State is also relatively high. In only one

case was the coverage less than 20 percent of the

State’s residual oil. For only two States did the

coverage fail to reach 30 percent. Thirteen of the

19 States had coverage of 40 percent or greater.

Based on the coverage and diversity of the reservoirs in the OTA data base, an extrapolation to

the full United States appears justified.

The States for which the coverage is lowest,

especially Kansas, Oklahoma, Pennsylvania, and

West Virginia, are States which collect only

limited information,

Fields and Reservoirs in the

OTA Data Base

Field Reservoir

Alabama

Citronella . . . . . . . . . . . . . . . Rodessa

Gilbertown . . . . . . . . . . . . . . Eutaw

Alaska

Granite Point ., ., . . . . . . . . Middle Kenai

McArthur River. . . . . . . . . . . Hemlock

Middle Ground Shoal . . . . . Hemlock E,F,G Pools

Prudhoe Bay . . . . . . . . . . . . . Kuparuk River

Lisburne

Prudhoe Oil Pool

Swanson River . . . . . . . . . . . Hemlock

Trading Bay . . . . . . . . . . . . . Middle Kenai

Middle Kenai G–Hemlock,

North

Arkansas

Magnolia. . . . . . . . . . . . . . . . Smackover

Smackover . . . . . . . . . . . . . . Old

Schuler . . . . . . . . . . . . . . . . . Jones

California

Coastal

Cat Canyon . . . . . . . . . . . . . Old Area Pliocene

Sisquoc Area Others

Los Flores

Dos Cuadras. . . . . . . . . . . . . Federal Offshore

Elwood . . . . . . . ., . . . . . . . . Vaqueros

Orcutt. ... , . . . . . . . . . . . . . Monterey Point Sal

Rincon. . . . . . . . . . . . . . . . . . Hobson-Tomson-Miley

Padre Canyon Others

Oak Grove Others

San Ardo. . . . . . . . . . . . . . . . Lombardi

Santa Maria Valley . . . . . . . Main

South Mountain. . . . . . . . . . Sespe Main

Ventura. . . . . . . . . . . . . . . . . C Block

D-5, D-6 East

Ventura. . . . . . . . . . . . . . . . . D-5, D-6 North

D-7, D-8

Los Angeles

Beverly Hills . . . . . . . . . . . . . East Area Miocene

Brea Olinda . . . . . . . . . . . . . Olinda Area

Brea Area

Coyote East . . . . . . . . . . . . . Anaheim

Coyote West . . . . . . . . . . . . Main 99 Upper West

Main 99 Upper East

Dominquez. . . . . . . . . . . . . . First East (Abandoned)

First East Central

First West Central

East Cooperative

3 and 4 NW Central

3-4-5 East

West Unit

96-594 0- 78 - ~
— — . .-

114 . Appendix A

Field Reservoir

Huntington Beach . . . . . . . . North Area Tar Bolsa

South Area Upper Main

Inglewood. . . . . . . . . . . . . . . Vickers

Long Beach. . . . . . . . . . . . . . Old Area Upper Pools

Montebello, . . . . . . . . . . . . . Baldwin

Richfield . . . . . . . . . . . . . . . . East and West Area

Santa Fe Springs. . . . . . . . . . Main Area Others

Seal Beach . . . . . . . . . . . . . . South Block Wasam

Alamitos

North Block McGrath

Torrance . . . . . . . . . . . . . . . . Main

Wilmington . . . . . . . . . . . . . Tar

Upper Terminal

Ranger

Lower Terminal

Ford

San Joaquin

Belridge South . . . . . . . . . . . Tulare

Buena Vista , . . . . . . . . . . . . Upper Hills

Front Area

Coalinga . . . . . . . . . . . . . . . . Temblor

Coles Levee North. . . . . . . . Richfield Main Western

Cuyama South . . . . . . . . . . . Main Area Homan

Cymric . . . . . . . . . . . . . . . . . Tulare

Carneros

Oceanic (all)

Edison , . . . . . . . . . . . . . . . . . Schist Main Upper

Vedder Freeman

Elk Hills. . . . . . . . . . . . . . . . . Upper Main

Fruitvale . . . . . . . . . . . . . . . . Chanac-Kernco Main

Greeley . . . . . . . . . . . . . . . . . Rio Bravo-Vedder

Kern Front. . . . . . . . . . . . . . . Main

Kern River. . . . . . . . . . . . . . . Kern River Sands

Kettleman Dome North. . . . Temblor

Lost Hills. . . . . . . . . . . . . . . . Main

McKittrick. . . . . . . . . . . . . . . Upper Main

Midway-Sunset . . . . . . . . . . Potter

Mt. Peso . . . . . . . . . . . . . . . . Vedder

Rio Bravo . . . . . . . . . . . . . . . Vedder-Osborne-Rio Bravo

Colorado

Adena . . . . . . . . . . . . . . . . . . J-Sand

Akron, East ... , . . . . . . . . . . D-Sand

Azure. . . . . . . . . . . . . . . . . . . D-Sand

Badger Creek . . . . . . . . . . . . D-Sand

Bijou . . . . . . . . . . . . . . . . . . . D-Sand

Bijou, West, . . . . . . . . . . . . . D-Sand

Black Hollow . . . . . . . . . , . . Lyons

Bobcat. . . . . . . . . . . . . . . . . . D-Sand

Boxer. . . . . . . . . . . . . . . . . . . D-Sand

Buckingham . . . . . . . . . . . . . D-Sand

Divide . . . . . . . . . . . . . . . . . . D-Sand

Graylin, NE . . . . . . . . . . . . . . D-Sand

Jackpot . . . . . . . . . . . . . . . . . D-Sand

Little Beaver . . . . . . . . . . . . . D-Sand

Little Beaver, East. , , . . . . . . D-Sand

Field Reservoir

Phegley . . . . . . . . . . . . . . . . . D-Sand

Pierce . . . . . . . . . . . . . . . . . . Lyons

Plum Brush Creek . . . . . . . . J-Sand

Rangely . . . . . . . . . . . . . . . . . Weber

Saber. . . . . . . . . . . . . . . . . . . D-Sand

Florida

Sunoco-Felda . . . . . . . . . . . . Roberts

Jay ., . . . . . . . . . . . . . . . . . . . Smackover

Blackjack Creek . . . . . . . . . . Smackover

Illinois

Clay City Consolidated. . . . Aux Vases

McClosky

Dale Consolidated. . . . . . . . Aux Vases

Lawrence . . . . . . . . . . . . . . . Cypress

Louden . . . . . . . . . . . . . . . . . Cypress

Main Consolidated . . . . . . . Pennsylvanian

New Harmony . . . . . . . . . . . Cypress

Salem Consolidated . . . . . . Benoist

Robinson, . . . . . . . . . . . . . . . Robinson

Kansas

Bemis-Shutts. . . . . . . . . . . . . Arbuckle

Blankenship . . . . . . . . . . . . . Bartlesville

Big Sandy . . . . . . . . . . . . . . . Bartlesville

Burket . . . . . . . . . . . . . . . . . . Bartlesville

Bush City . . . . . . . . . . . . . . . Squirrel

Chase Silica . . . . . . . . . . . . . Arbuckle

Cunningham. . . . . . . . . . . . . Lansing-Kansas City

Edna. . . . . . . . . . . . . . . . . . . . Bartlesville

El Dorado . . . . . . . . . . . . . . . Admire

Fairport . . . . . . . . . . . . . . . . . Arbuckle

Fox-Bush-Couch. . . . . . . . . . Bartlesville

Gorham. . . . . . . . . . . . . . . . . Arbuckle

Hall-Gurney . . . . . . . . . . . . . Lansing-Kansas city

Hep[er . . . . . . . . . . . . . . . . . . Bartlesville

Hollow-Nikkei . . . . . . . . . . . Hunton

Humboldt-Chanute . . . . . . . Bartlesville

Iola . . . . . . . . . . . . . . . . . . . . Bartlesville

Kraft-Prusa . . . . . . . . . . . . . . Arbuckle

Lament . . . . . . . . . . . . . . . . . Bartlesville

Madison . . . . . . . . . . . . . . . . Bartlesville

McCune . . . . . . . . . . . . . . . . Bartlesville

Moran, Southwest . . . . . . . . Bartlesville

Rainbow Bend . . . . . . . . . . . Burgess

Ritz-Canton . . . . . . . . . . . . . Mississippian

Sallyards . . . . . . . . . . . . . . . . Bartlesville

Thrall-Aagard . . . . . . . . . . . . Bartlesville

Trapp. . . . . . . . . . . . . . . . . . . Arbuckle

Virgil . . . . . . . . . . . . . . . . . . . Bartlesville

Louisiana (North)

Caddo Pine. . . . . . . . . . . . . . Nacatoch

Annona

Paluxy
Field Reservoir

Haynesvil[e. . . . . . . . . . . . . . Buck

Pettit Lime

Camp

Smackover

Homer. . . . . . . . . . . . . . . . . . Homer (all)

Rodessa. . . . . . . . . . . . . . . . . Rodessa (all)

Delhi . . . . . . . . . . . . . . . . . . . Delhi (all)

Louisiana (South)

Avery Island . . . . . . . . . . . . . Medium

Deep

Bay St. Elaine . . . . . . . . . . . . Deep

Deep

Bayou Sale . . . . . . . . . . . . . . Deep

Caillou Island. . . . . . . . . . . . Medium

Medium

Deep

Cote Blanche Bay West Medium

Medium

Cote Blanche Island. . . . . . . Deep

Deep

Garden Island Bay . . . . . . . . Shallow

Shallow

Medium

Medium

Grand Bay. . . . . . . . . . . . . . . Medium

Medium

Hackberry West. . . . . . . . . . Medium

Lake Barre. . . . . . . . . . . . . . . Deep

Deep

Romere Pass. . . . . . . . . . . . . Medium

Timbalier Bay . . . . . . . . . . . . Medium

Lake Pelto. . . . . . . . . . . . . . . Deep

Deep

Lake Washington. . . . . . . . . Shallow

Medium

Deep

Paradis. . . . . . . . . . . . . . . . . . Deep

West Bay . . . . . . . . . . . . . . . Medium

Weeks Island . . . . . . . . . . . . Deep

Deep

Quarantine Bay . . . . . . . . . . Medium

Medium

Venice. . . . . . . . . . . . . . . . . . Medium

Medium

Mississippi

Baxterville. . . . . . . . . . . . . . . Lower Tuscaloosa Massive

Bay Springs. . . . . . . . . . . . . . Lower Cotton Valley

Cranfield. . . . . . . . . . . . . . . . Lower Tuscaloosa

Eucutta East . . . . . . . . . . . . . Eutaw

Heidelberg . . . . . . . . . . . . . . East Eutaw, (2) West Eutaw

Little Creek. . . . . . . . . . . . . . Lower Tuscaloosa

Mallalieu, West . . . . . . . . . . Lower Tuscaloosa

McComb. . . . . . . . . . . . . . . . Lower Tuscaloosa

soso. . . . . . . . . . . . . . . . . . . . Bailey

Tinsley. . . . . . . . . . . . . . . . . . Woodruff Sand

Yellow Creek, West . . . . . . Eutaw

Field

Appendix A . 175

Reservoir

Montana

Bell Creek. . . . . . . . . . . . . . . Muddy

Cabin Creek. . . . . . . . . . . . . lnterlake-Red River

Cut Bank. . . . . . . . . . . . . . . . Kootenai

Deer Creek. . . . . . . . . . . . . . Interlake

Gas City . . . . . . . . . . . . . . . . Red River

Glendive. . . . . . . . . . . . . . . . Red River

Little Beaver . . . . . . . . . . . . . Red River

Little Beaver, East. , . . . . . . . Red River

Monarch . . . . . . . . . . . . . . . . lnterlake-Red River

Outlook . . . . . . . . . . . . . . . . Winnepegosis-lntedake

Pennel. . . . . . . . . . . . . . . . . . lnterlake-Red River

pine. ., . . . . . . . . . . . . . . . . . Interlake

Poplar, East. . . . . . . . . . . . . . Madison

Richeu, Southwest. . . . . . . . lnterlake-Red River

Sand Creek. . . . . . . . . . . . . . lnterlake-Red River

New Mexico

Allison. . . . . . . . . . . . . . . . . . Pennsylvanian

Caprock . . . . . . . . . . . . . . . . Queen

Caprock, East . . . . . . . . . . . . Devonian

Cato . . . . . . . . . . . . . . . . . . . San Andres

Chaveroo . . . . . . . . . . . . . . . San Andres

Corbin. . . . . . . . . . . . . . . . . . Abo

Denton . . . . . . . . . . . . . . . . . Wolfcamp

Devonian

Empire-Abe. . . . . . . . . . . . . . Abo

Eunice-Monument . . . . . . . . Gray burg-San Andres

Hobbs . . . . . . . . . . . . . . . . . . San Andres-Grayburg

Lea. . . . . . . . . . . . . . . . . . . . . Devonian

Lusk. . . . . . . . . . . . . . . . . . . . Strawn

Maljamar. . . . . . . . . . ., . . . . Gray burg-San Andres

Milnesand. . . . . . . . . . . . . . . San Andres

Vacuum . . . . . . . . . . . . . . . . Gray burg-San Andres

Glorieta

Abo Reef

North Dakota

Antelope. . . . . . . . . . . . . . . . Madison

Beaver Lodge . . . . . . . . . . . . Madison

Devonian

Blue Buttes . . . . . . . . . . . . . . Madison

Capa . . . . . . . . . . . . . . . . . . . Madison

Charlson . . . . . . . . . . . . . . . . Madison

Tioga. . . . . . . . . . . . . . . . . . . Madison

Oklahoma

Star . . . . . . . . . . . . . . . . . . . . Upper Misener-Hunton

Washington, East-Goldsby,

West . . . . . . . . . . . . . . . . . . Osborne

Sho-vel-tum . . . . . . . . . . . . . Pennsylvanian-Deese

Elmwood, West . . . . . . . . . . Upper Morrow “A”

Elk City . . . . . . . . . . . . . . . . . Hoxbar

Salt Fork, Southeast. . . . . . . Skinner

Dover Hennessey. . . . . . . . . Meramec

Manning

Red Bank. . . . . . . . . . . . . . . . Dutcher

Putnam . . . . . . . . . . . . . . . . . Oswego
116 . Appendix A

Field Reservoir

Stroud . . . . . . . . . . . . . . . . . . Prue

Eola-Robberson . . . . . . ... , Pontotoc

Avant & West . . . . . . . . . . . Bartlesville

Bowlegs. . . . . . . . . . . . . . . . . Gilcrease

Burbank, North. . . . . . . . . . . Burbank

Carleton, Northeast. . . . . . . Atoka-Morrow

Cement. . . . . . . . . . . . . . . . . Medrano Sand, West

Cheyenne Valley . . . . . . . . . Red Fork

Cushing. . . . . . . . . . . . . . . . . Bartlesville

Dibble, North. . . . . . . . . . . . Osborne

Delaware-Childers . . . . . . . . Bartlesville

Earlsboro. . . . . . . . . . . . . . . . Earlsboro

Edmond, West . . . . . . . . . . . Hunton

Flat Rock. . . . . . . . . . . . . . . Bartlesville

Healdton. . . . . . . . . . . . . . . . Hoxbar

Lindsay, North . . . . . . . . . . . Bromide

Mustang . . . . . . . . . . . . . . . . Hunton Bois D’Arc

North Northwest-Verden ., Marchand

Oakdale Northwest. . . . . . . Red Fork

Oconee, East . . . . . . . . . . . . Oil Creek

Oklahoma City . . . . . . . . . . Wilcox

Oil Creek-Lower Simpson

Red River, West. . . . . . . . . . Gunsight

Seminole. . . . . . . . . . . . . . . . Upper Wilcox

Stanley Stringer, North . . . . Burbank

Pennsylvania

Bradford . . . . . . . . . . . . . . . . Third Bradford

Fork Run . . . . . . . . . . . . . . . . Cooper

Foster-Reno-Oil City ., . . . . Venago First

Kane . . . . . . . . . . . . . . . . . . . Kane

Sartwell. . . . . . . . . . . . . . . . . Third Bradford

Sartwell

Texas

District 1

Big Wells. . . . . . . . . . . . . . . . San Miguel

Darst Creek . . . . . . . . . . . . . Buda-Edwards

Luling-Branyon . . . . . . . . . . . Edwards

Salt Flat. . . . . . . . . . . . . . . . . Edwards

District 2

Greta (all) . ..............4400

Lake Pasture . . . . . . . . . . . . . H-440

569

Refugio . . . . . . . . . . . . . . . . . Refugio-Fox

Tom Oconnor . . . . . . . . . . . Catahoula-Frio-Miocene

West Ranch . . . . . . . . . . . . . 41-A

District 3

Thompson. . . . . . . . . . . . . . . Frio

Barbers Hills . . . . . . . . . . . . . Frio-Miocene

Columbia West . . . . . . . . . . Miocene

Conroe . . . . . . . . . . . . . . . . . First Main CockfieId

Dickinson-Gillock . . . . . . . . Frio 8300-8800

Frio 9000-9300

Goose Creek. . . . . . . . . . . . . Miocene

Hastings East & West . . . . . Frio

High Island . . . . . . . . . . . . . . Miocene

Field Reservoir

Hull Merchant . . . . . . . . . . . Yegua

Humble (all) . . . . . . . . . . . . . Miocene

Old Ocean . . . . . . . . . . . . . . Armstrong

Oyster Bayou . . . . . . . . . . . . Frio-Searbreeze

Pierce Junction. . . . . . . . . . . Frio

Sour Lake . . . . . . . . . . . . . . . Frio

Spindletop . . . . . . . . . . . . . . Caprock-Miocene-Frio

Tomball. . . . . . . . . . . . . . . . . Cockfield

Webster . . . . . . . . . . . . . . . . Frio

Magnet Withers. . . . . . . . . . Frio

Anahuac . . . . . . . . . . . . . . . . Frio

District 4

Alazan North . . . . . . . . . . . . Frio

Aqua Dulce-Stratton . . . . . . Frio-Vicksburg

Borregos . . . . . . . . . . . . . . . . Combined Zones

Government Wells North . . North

Kelsey , . . . . . . . . . . . . . . . . . Multiple Zones 5400-6400

Plymouth . . . . . . . . . . . . . . . Frio

Saxet . . . . . . . . . . . . . . . . . . . Het.-Mio

Seeligson. . . . . . . . . . . . . . . . Combined Zones

T-C-B. . . . . . . . . . . . . . . . . . . Zone 21 -B

White Point East . . . . . . . . . Frio

District 5

Mexia . . . . . . . . . . . . . . . . . . Woodbine

Powell . . . . . . . . . . . . . . . . . . Woodbine

Van . . . . . . . . . . . . . . . . . . . . Woodbine

District 6

Fairway . . . . . . . . . . . . . . . . . Lime

Neches . . . . . . . . . . . . . . . . . Woodbine

New Hope . . . . . . . . . . . . . . Bacon Lime

Pittsburg

Quit Man . . . . . . . . . . . . . . . Paluxy

Talco. . . . . . . . . . . . . . . . . . . Paluxy

East Texas. . . . . . . . . . . . . . . Woodbine

Hawkins . . . . . . . . . . . . . . . . Woodbine

District 7-B

Eastland Co . . . . . . . . . . . . . Strawn

Stephens Co. . . . . . . . . . . . . Caddo

District 7-C

Big Lake. . . . . . . . . . . . . . . . . Queen

Jameson . . . . . . . . . . . . . . . . Strawn

Pennsylvanian

McCamey . . . . . . . . . . . . . . . Grayburg

Pegasus . . . . . . . . . . . . . . . . . Pennsylvania

Ellen burger

District 8

Andector. . . . . . . . . . . . . , . . Ellen burger

Block 31 . . . . . . . . . . . . . . . . Crayburg

Devonian

Ellen burger

Cowden North. . . . . . . . . . . Grayburg

Deep

Cowden South. . . . . . . . . . . San Andres-Grayburg

Canyon

Ellen burger
Appendix A ● 117

Field Reservoir

Crossett. . . . . . . . . . . . . . . . . Devonian

Dollarhide. . . . . . . . . . . . . . . Ellen burger

Devonian

Dora Roberts . . . . . . . . . . . . Ellenburger

Dune . . . . . . . . . . . . . . . . . . . Permian-San Andres

Emma . . . . . . . . . . . . . . . . . . Gray burg-San Andres

Ellen burger

Foster , . . . . . . . . . . . . . . . . . Gray burg-San Andres

Fullerton . . . . . . . . . . . . . . . . San Andres

Clear Fork

8500

Goldsmith. . . . . . . . . . . . . . . San Andres-Grayburg

5600 Clear Fork

Harper. . . . . . . . . . . . . . . . . . Permian

Devonian

Ellenburger

Headlee. . . . . . . . . . . . . . . . . Ellen burger

Hendrick . . . . . . . . . . . . . . . . Yates-Seven Rivers

Howard-Glasscock. . . . . . . . Yates-Seven Rivers-Queen

San Andres-Grayburg

Glorieta

Iatan East . . . . . . . . . . . . . . . San Andres

Johnson. . . . . . . . . . . . . . . . . Gray burg-San Andres

Jordan . . . . . . . . . . . . . . . . . . Permian

Ellenburger

Kermit . . . . . . . . . . . . . . . . . . Permian-Yates

Keystone. . . . . . . . . . . . . . . . Colby

Ellenburger

McElroy. . . . . . . . . . . . . . . . . Crayburg

Means . . . . . . . . . . . . . . . . . . Gray burg-San Andres

Midland Farms . . . . . . . . . . . Grayburg

Ellenburger

Parks . . . . . . . . . . . . . . . . . . . Pennsylvanian

Penwell. . . . . . . . . . . . . . . . . San Andres

Glorieta

Sand Hills . . . . . . . . . . . . . . . Tubbs

Shafter Lake . . . . . . . . . . . . . San Andres

Devonian-Wolfcamp

Ellenburger

Spraberry Trend . . . . . . . . . . Spraberry

TXL . . . . . . . . . . . . . . . . . . . . Tubb

Pennsylvanian

University Waddell . . . . . . . Devonian

Waddell . . . . . . . . . . . . . . . . Gray burg-San Andres

Ward Estes North. . . . . . . . . Yates-Seven Rivers

Ward South . . . . . . . . . . . . . Yates-Seven Rivers

Yates . . . . . . . . . . . . . . . . . . . Gray burg-San Andres

District 8-A

Anton Irish . . . . . . . . . . . . . . Clearfork

Cogdell . . . . . . . . . . . . . . . . . Canyon Reef

Diamond M . . . . . . . . . . . . . Canyon Lime

Kelly Snyder. . . . . . . . . . . . . Cicso

Canyon Reef (Watered)

Canyon Reef

Levelland . . . . . . . . . . . . . . . San Andres

Prentice. . . . . . . . . . . . . . . . . Glorieta

Clearfork 6700

Field

Russell. . . . . . . . . . .

Salt Creek. . . . . . . .

Seminole. . . . . . . . .

Slaughter. . . . . . . . .

Wasson. . . . . . . . . .

Welch ... , . . . . . . .

District 9

Archer Co. Reg. . . .

Cooke Co. Reg. ., .

Hull Silk Sikes. ... ,

KMA . . . . . . . . . . . .

Walnut Bend . . . . .

Wichita Co. Reg. . .

Wilbarger Co. Reg.

Young Co. Reg. . . .

District 10

Panhandle. . . . . . . .

Utah

Altamount-Bluebell

Aneth . . . . . . . . . . .

McElmo Creek . . . .

Ratherford. . . . . . . .

White Mesa . . . . . .

Bridger Lake . . . . . .

Reservoir

. . . . . . . Glorieta

Clearfork

Devonian

. . . . . . . Canyon Reef

. . . . . . . San Andres

. . . . . . . San Andres

. . . . . . . San Andres

Clearfork

. . . . . . . San Andres

. . . . . . . Strawn-Gunsight

. . . . . . . Strawn

. . . . . . . Strawn 4300

. . . . . . . Strawn

. . . . . . . Huspeth

Walnut Bend

Winger

. . . . . . . 0-2100

. . . . . . . Dyson-Milham

. . . . . . . Gunsight

. . . . . . .

. . . . . .

. . . . . . .

. . . . . . .

,. .,...

,. ...,,

,. .,..,

West Virginia

Greenwood. . . . . . . . . . . . . .

Griffithsville . . . . . . . . . . . . .

Wyoming

Big Muddy . . . . . . . . . . . . . .

Big Sand Draw . . . . . . . . . . .

Bonanpa . . . . . . . . . . . . . . . .

C-H Field. . . . . . . . . . . . . . . .

Cottonwood Creek . . . . . . .

Dillinger Ranch. . . . . . . . . . .

Elk Basin . . . . . . . . . . . . . . . .

Frannie . . . . . . . . . . . . . . . . .

Gailand . . . . . . . . . . . . . . . . .

Grass Creek . . . . . . . . . . . . .

Carson

Gray

Hutch inson

Green River

Desert Creek

Desert Creek

Desert Creek

Desert Creek

Dakota

Big Injun

Berea

Wall Creek

Tensleep

Tensleep

Minnelusa

Phosphoric

Upper Minnelusa B

Embar-Tensleep

Tensleep

Combined

Tensleep

Curtis

Embar-Tensleep

Frontier

Hamilton Dome . . . . . . . . . . Tensleep

Hilight ~ “ . . ~+• “ “ “ “ ‘ “ “ “ “ MuddY-MinnellJsa

Lance Creek . . . . . . . . . . . . . Leo

Sundance
118 . Appendix A

Field Reservoir

Little Buffalo Basin. . . . . . . . Tensleep

Lost Soldier. . . . . . . . . . . . . . Combined

Tensleep

Oregon Basin . . . . . . . . . . . . North Tensleep

South Tensleep

Salt Creek. . . . . . . . . . . . . . . Wall Creek

Smemlek, West . . . . . . . . . . Minnelusa B

Steamboat Butte . . . . . . . . . Tensleep

Wertz . . . . . . . . . . . . . . . . . . Tensleep

Winkleman Dome . . . . . . . . Tensleep

Offshore Fields

Field

Bay Marchand 002 . . .

Bay Marchand Block 2.

n Louisiana

Reservoir

. . . . . . 3600’ D

3650’ (L) D

3650’ (U) D

4900’ D

7100’ F

7600’ MS

7900’ D

81 75’ B

8200’ F

8200’ BUQ

8300’ BU

8300’ EE

8500’ B

8550’ B

8700’ BU

8750’ BUW

9100’ c

9200’ B

9600’ B

RA

RA

R D

BM 4350 D VU

BM 4500 MLD VU

BM 5000 D VU

BM 4800 RD VU

4800 AB VU

Eugene Island 126. . . . . . . . . . . 2A-RF-B

2A-RF-c

2B (1) RF A

2B (1) RF-BVU

2B (U) RJ

2B (U) RL-C

C-1 RF

C-1 RN

D-1 RF A

D-1 RF SU

E-2 RF SU

F-1 RF SU

IM RF-B

IM RL-A

IM RL-SU

Field Reservoir

Eugene Island 175. . . . . . . . . . . RA

RA

RA

RB

R D

RB

FB-D

FB-D

FB-A

RB

RC

RA

Eugene Island 276. .., . . . ., . . P RA SU 1 W

P RA SU IW

U RA SU 1 W

U3 RA SU 1 W

VH 10 DE* 1

Crist Sub 3A RA

Tex (P) 1 RF

Eugene Island Block 330 . . . . . LF FBB 1

7300 S1 ● 1

FBB

RA

FBA

FBA

RA

Seg. A

Seg. 1

Seg. 3

GA-2

HB-1

Seb. I

B

FBA

FBB

FBB

FB

FC

FSI

L RA

L RB

L RC

L RE

L RF

LF FBA 1

Grand Isle Block 16 . . . . . . . . . B-2 RC 1A

B-2 RE 1 W

B-4 RC

B-4 RE

B-4 RT

BF-2 RE UC

C-1 REF lW

C-4 A RN

Grand Isle Block 43 . . . . . . . . . G-1

F-2

c - l

R-2

c-1

G-2
Appendix A ● 119

Field Reservoir

s-1

R5

D-1

R-1

s-1

R1

l-l

F-1

R-6

F-1

I-8

E-6

Grand Isle Block 47 . . . . . . . . . A-6

A-6

A-3

A-2

A-1

Main Pass Block 35. . . . . . . . . . G2 RA SU

K2 RA SU

LO RA SU

L2 RA SU

N RA SU

O RA SU

R2 RA SU

Main Pass Block 41 . . . . . . . . . . RD SU

RA SU

RA SU

RB SU

RA SU

RB SU

Main Pass 41 . . . . . . . . . . . . . . . A

D

D

A

A

A

A

t

A

F

A

Main Pass Block 69. . . . . . . . . . RB SU

RA VU

RC VU

RH SU

RB SU

Main Pass 144. . . . . . . . . . . . . . RI

6250

6250L

6900

7250

7500

7525

Main Pass 306 . . . . . . . . . . . . . . AB 28/29

C45

B 44/45

AB4

44/45

A-213

Field Reservoir

A-4

A-FB-1

A-2

A-3

5AF81

44/45

FB-I

FB-111

2/3

4

29

42

44/45

Ship Shoal 204 . . . . . . . . . . . . . D-1

FB5

FB4

FB5

RA

BRA

RA & BRA

RB

Ship Shoal 207 . . . . . . . . . . . . . Al

RA

RA

RE

RB

RG

RA

RA

RF

RA

RC

RG

Ship Shoal 208 . . . . . . . . . . . . . RC

PA

ARA

RA

FB-3

FB-4

FB-3

FB-4

FB-4

FB-3

FB-4

FB-3

FB-4

FB-4

RA

RC

South Pass Block 24 . ........4 RB SU

8200 T SU

8400 RA SU

8600 RA SU

8800 RD SU

M2 RA SU

NA RA SU

02 RA SU

P-Q RA SU

Q RA SU
120 . Appendix A

Field Reservoir

Q RB SU

Q RC SU

Q RE SU

R2 RA SU

SRA SU

S RC SU

T RA SU

T RB SU

T RC SU

T RD SU

T1 RB SU

South Pass Block 24 . . . . . . . . . T1 A RB SU

TIA RB SU

U2 RA SU

South Pass Block 27 . . . . . . . . . RA SU

v u

RB SU

RA SU

RA SU

RA SU

RB SU

RC SU

RD SU

RB SU

RC SU

RD SU

RE SU

RC SU

RA SU

RB SU

RA SU

RA SU

RB SU

RA SU

RA SU

RB SU

RC SU

RD SU

South Pass 27 . . . . . . . . . . . . . . Pliocene

10 D

F 32 UP

F 32 UP

F 13 AUp

F 13 AD

RBSU

10 UP

RESU

RASU

6 UP

RESU

RESU

F 13 AU

South Pass 61 ... , . . . . . . . . . . RM

RN

RQ

RR

RN

RM

RA

Field Reservoir

RC

RB

RC

RD

South Pass 62 . . . . . . . . . . . . . . RA

RA

RB

RC

RA

RA

RA

RC

RA

RD

South Pass 65 . . . . . . . . . . . . . . RA

RG

RB

RC

RB

RC

R D

RE

RA

RB

Ship Shoal 208 . . . . . . . . . . . . . RA

South Marsh Island 73 . . . . . . . B-35-K

B-65-G

C-5-6

Timbalier Bay Block 21. . . . . . . DC

S u

I

IIIB

Z X3

3X2

DC

Clc

BID

BSC

DC

DC

DC

DC

EB

T E

BSU

DC

DC

W. Delta Block 30 . . . . . . . . . . A-1 Res. F

A-2 Res. D

A-3 Res. D

C-45 and Res. Q

D-6 Res. BB

E RASU

G RASU

G-4 Res. C-1

C-4. Res. E-1

I RASU

IF Res. C-2

IM Res. C-10
Appendix A . 121

Field Reservoir

P-1 Res. F

P-2 Res. F

P-45 Res. F

P-6 Res. F

6100 Res. E

6300’ Res. G-A-2 Res. F

6400’ Res. G-A-3 Res. F

71 50’ Res. E

8500 Res, C

W. Delta 73. . . . . . . . . . . . . . . . RA

FBI

FB2

RA

Field Reservoir

RA

RA

RA

W. Delta 79. ., . . . . . . . . . . . . . D2R6S

SFFO

NFF

NFF

I

I

II

Ill

I v
122 . Appendix A

Documentation of Data Sources

Data needed for individual reservoirs were obtained from many sources. Sources of data are

summarized by State in the Bibliography beginning on page 129. The entries in this bibliography

include 10 categories of data. Specific data items

in each category are identified in the following

section. These categories indicate the type of information sought. As indicated in the Selection of

Data Items on page 111, there are many gaps in

the specific data items under each category. Data

which were available for essentially all reservoirs

in the data base are indicated with an asterisk.

Geology

* Structure name

Geologic age

Lithology

Fractures

Faulting

Complexity

Continuity

Lenticularity

Heterogeneity

Clay content

Turbidities

Reservoir condition

* Depth

* Bottom hole temperature

Pressure

Dip

* permeability

Gas cap

Reservoir volume

* Net pay thickness

* Number of zones

* Porosity

* Acres

Saturations

* Connate water saturation

* Initial oil saturation

Current oil saturation

Residual oil saturation after primary and secondary recovery

Water characteristics

( il/

*

*

*

O i l

*

*

*

O i l

*

*

Salinity

Calcium

Magnesium

characteristics

Gravity

Viscosity (reservoir conditions)

Formation volume factors

Gas/oil ratio

volume - resources/reserves

Original oil in place

Estimated primary/secondary recovery

Remaining reserves

volume - production history

Cumulative production

Annual production

Production decline rate

Field development - conventional

●

☛

☛

☛

☛

☛

Discovery year

primary drive type

Type of secondary recovery

Year of secondary initiation

Total wells drilled

Latest active wells

Current operator(s)

Field development - E O R

Type of EOR process

Year of initiation

Current stage of development

Acres under development

Bibliography

Following the State-by-State charts is a

bibliography providing the full citation for each

source by State.
Appendix A ● 123

Documentation of Data Sources for Big Fields Reservoir File

1

~

1

4

5

6

7

1

2

i

4

5

b

7

8

9

10

11

1

2

3

4

5

6

7

1

2

1

4

5

6

7

8

9

Geologv

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Reservoir

Condition

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Reservolr

volume

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Saturations

●

●

●

●

●

●

●

●

●

●

✎

●

●

✌✎✌

✌✎

●

Type of Data

Wate r

c harac -

teristics

Oil

characteristics

●

●

●

●

●

●

●

●

●

●

✌ ✎

●

●

●

●

●

●

●

✎

●

●

●

●

●

011 volume

Resources/

reserves

●

•

●

●

●

●

●

●

●

●

●

●

●

●

●

●

.

●

●

●

●

Production

history

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Field Development

Conventlonal

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

✎ ✌

EOR

●

●

●

●

●
124 . Appendix A

State and Source

10

11

l?

1

2

3

4

5

6

1

2

3

4

5

6.

1

2

3

4

5,

6.

7.

8

1

2

Petroleum Data System of North

America

Society ot Petoleum Engineers ot

AlME — a

Society of Petroleum Engineers of

AlME — b

Society of Petroleum Engineers of

AIME — C

Society of Petroleum Engineers of

AIME — d

12. Miscellaneous Petroleum

Periodicals

Geology

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Reservoir

Condition

●

●

●

●

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Reservoir

volume

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●

●

●

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●

●

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●

●

●

●

●

●

●

●

●

●

●

●

●

Saturations

●

●

●

●

●

●

●

●

●

●

●

●

✌✎✎

Wate r

characteristics

Oil

charac -

teristics

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

✎ ✌

●

●

●

●

011 volume

Resources/

reserves

●

●

●

●

●

●

✌✎

●

●

●

●

●

●

✎ ✌

●

●

Produc -

tion

history

●

●

●

. ,

●

●

●

●

. ,

●

●

●

.,

Field Development

Conventional

●

●

●

●

●

●

●

●

●

●

●

●

●

✌✎✌

✌ ✎ ✌

●

✎ ✎

●

●

EOR

●

●

✌✎

●

●

●

●
State and Source

3

4

5

6

7

8

9

10

11

1

2

3 .

4

5

6

7

1

1

2

3

4

5

6.

7

8

9

1

2

3

Bureau of Mines — a.

Bureau of Mines — h

Energy Research and Development

Administration

International Oil Scouts

Association

Kansas Geological Survey — a

Kansas Geological Survey — b

Kansas Geological Survey —c

Kansas Geological Survey — d

National Petroleum CounciI

0il and Gas journal — a

011 and Gas Journal — b

Petroleum Data System of North

America

Society ot Petroleum Engineers of

AlME — a

Society of Petroleum Engineers of

AIME — b

Soclity of Petroleum Englneers of

AlME — C

Miscellaneous Petroleum

Periodical s

Louisiana (Onshore)

Amerlcan Petroleum Institute — a

and b

8ureau of Mines

Louisiana Department ot

Conservation — a

Louisiana Department of

Conservation — b

011 and Gas journal — a

011 and Gas journal — b

Society of Petroleum Engineers of

AlME — a

Society of Petroleum Englneers of

AIME — b

Society of Product Ion Well

Analysts

National Petroleum Council

Louisiana (Offshore)

U S Geologlcal Survey

Mississippi

American Association of

Petroleum Geologists

American Petroleum Institute

Bureau of Mines — a

Bureau of Mines — b

Federal Energy Administration

Gulf Universlties Research

Consortiu m

International Oil Scouts

Associatio n

MIssissippi State 011 and Gas

Board

011 and Gas journal — a

011 and Gas Journal — b

Society of Petroleum Engineers of

AIME

Montana

American Association of

Petroleum Geologist s

Bureau of Mine s

GuIf Universities Research

Consortiu m

Appendix A . 725

Geology

●

●

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●

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●

●

●

●

●

●

Reservoir

condition

●

●

●

●

●

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●

●

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●

●

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●

●

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●

●

✎

●

●

●

●

●

●

●

Reservoir

volume

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●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

Q

●

●

Saturations

●

●

●

✌✌

●

✎

●

●

●

●

●

●

✎

●

●

●

●

Wate r

characteristics

Oil

characteristics

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

011 volume

Resources/

reserves

.,

●

✎✌✎

●

●

●

✎✌

●

●

✎✌

●

●

●

●

●

✎ ✌

✎ ✎ ✎ ✎ ✎

●

●

✌✎

Production

history

●

●

●

●

●

●

●

●

●

●

✎✌

●

●

●

●

●

●

Field Development

Conventional

●

●

●

●

●

●

●

●

✎ ✎ ✎ ✎

●

●

●

●

●

●

●

●

●

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●

✎ ✎ ✎ ✎

●

●

EOR

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●

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●

●

ž

●

●

●
126 . Appendix A

State and Source

4

5

6

7

8

9.

10

1.

2

3

4

5

6

7

8

9

10

11

12

13

1

2

3

4

5

6

7

1

2

3

4

5

b

7

8

9

Geology

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Reservoir

condition

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✎✌

Reservoir

volume

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●

●

●

●

●

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●

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●

●

●

●

, 0

●

Saturations

●

●

✌✎

●

●

●

●

●

●

●

✌ ✌

●

●

●

●

●

●

Wate r

characteristics

Oil

characteristics

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

011 volume

Resources/

reserves

●

●

●

●

●

●

●

●

●

●

●

●

Production

history

●

●

●

●

●

●

●

●

●

●

●

●

●

Field Development

Conventional

●

●

●

●

✎ ✌

●

●

✎✌

●

●

●

●

●

●

●

●

●

●

●

●

●

EOR

●

●

●

●
State and Source

10

11

12

13

1

.2

3

4

5

6

7

8

9

10

1

2

\

4

5

6

7

8

Y

10

11

1

2

3.

Appendix A ● 127

Geology

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Reservoir

condition

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●

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●

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Reservoir

volume

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●

●

●

●

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●

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●

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●

Saturations

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●

●

●

Oil

characteristics

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●

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●

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●

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●

●

011 volume

Resources/

reserves

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●

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●

●

●

●

●

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●

Production

history

●

●

●

●

●

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●

●

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●

●

●

●

●

●

●

●

●

Field Development

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

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●

●

●

●

●

●

●

EOR

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●

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●

●

●

●
128 . Appendix A

State and Source

4

5.

6

7

8

9

10

1

2.

3.

4.

5.

6.

1.

2.

3.

4

5

6

7

8.

9.

10

11

Wyoming

American Petroleum Institute

8ureau of Mine s

Federal Energy Administration

Gulf Universities Research

Consortiu m

International Oil Scouts

Associatio n

National Petroleum Council.

011 and Gas Journal —a .

Oil and Gas journal — b .

Society of Petroleum Engineers of

AIME — a , . .

Society of Petroleum Engineers of

AlME — b . . .

Society of Petroleum Engineers of

AIME — c

Wyoming Geological Association.

Wyoming 011 and Gas

Conservation Commissio n

Miscellaneous Petroleum

Periodicals .

Geology

●

✎

●

✎✌ ✌✎

●

●

●

●

●

●

●

●

Reservoir

condition

●

●

●

●

●

●

●

, . .

●

●

●

●

●

●

.,

●

●

●

●

●

Reservoir

volume

, ,

●

●

●

●

●

●

●

●

●

✎✌

●

●

●

●

●

●

●

●

Saturations

, . .

●

●

●

●

●

●

✎✌

●

●

●

●

Wate r

characteristics

. ,

●

●

●

, . .

●

●

Oil

characteristics

●

●

●

●

✎

●

●

✎✌

●

●

●

●

●

●

●

Oil volume

Resources/

reserves

●

, .

●

●

●

●

●

●

.

●

●

Production

history

●

●

●

. , .

●

, .

●

●

, .

. .

, ,

●

. .

Field Development

●

●

●

●

●

●

✎ ✎ ✎ ✎

●

●

●

✌ ✎

●

●

✎ ✎ ✎ ✎

●

●

✎✎✌ ✎ ✎

●

●

●

EOR

●

●

●

●
Appendix A . 129

Bibliography

Alabama

1.

2.

3.

4.

5.

6.

7.

Halbouty, Michael T. (Ed.), Geology of Giant

Pe(ro/eum Fields, American Association o f

Petroleum Geologists, Tulsa, okla., Memoir 14,

1970 .

The One Hundred Largest Fields in (he United

States with Remaining Es (irnated Prove d

Reserves of Crude Oil and “Ninety Day” Productive Capacity Estimated as of December .31,

7974, American Petroleum Institute, Washington, D. C., June 11, 1975.

Hawkins, M. E., et. al., Analyses of Brines From

Oil-Productive Formations in Mississippi and

Alabama, U.S. Department of the Interior,

Bureau of Mines, Washington, D. C., 1963.

/nternationa/ 0;/ and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Mesozoic -Paleozoic Producing Areas of

Mississippi and Alabama, Mississippi Geological

Society, Jackson, Miss., 1963.

“Here Are The Big U.S. Reserves,” Oil and Gas

journal, Jan. 27, 1975, pp. 116-118.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

Alaska

1.

2.

3.

4.a

4.b

96-594

Statistical Report, State of Alaska, Division of

Oil and Gas, Anchorage, Alaska, 1976.

Alaska Geological Survey, Anchorage, Alaska.

Halbouty, Michael T. (Ed.), Geo/ogy of Giact

Petro/eum Fields, American Association of

Petroleum Geologists, Tulsa, Okla., Memoir 14,

1970.

Reserves of Crude Oil, Natural Gas Liquids. and

Natura/ Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 1974. Joint publication by the

American Gas Association, the American

petroleum Institute, and the Canadia n

Petroleum Association, Vol. 29, May 1975.

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Daily

Productive Capacity Estimated as of December

31, ? 974, American Petroleum Institute, Washington, D. C., June 11, 1975.

3- 78 - 10

5.

6.

7.

8.

9.

Blaske, Donald P., et. al., Oil Fields and Crude

Oil Characteristics— Cook Inlet Basin, U.S .

Department of the Interior, Bureau of Mines,

Washington, D. C., Report of Investigations No.

7688, 1972.

Oil and Gas Resources, Reserves, and Productive Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

/international Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Determination of Equitable Price Levels for

North Slope Alaskan Crude Oi/, Mortada international, Dallas, Text, 1976.

“Here Are The Big U.S. Reserves,” Oi/ and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Arkansas

1.

2.a

2.b

2.C

3.

4.

5.

6.

7.a

Annual Oil and Gas Report, State of Arkansas,

Oil and Gas Commission, El Dorado, Ark., 1975.

Park, W, G., et, al., Heavy Oil Reservoirs i n

Arkansas, U.S. Department of the Interior,

Bureau of Mines, Washington, D. C., information Circular No. 8428, 1969.

Hawkins, M. E., et. al., Analyses of Brines From

Oil Productive Formations in South Arkansas

and North Louisiana, U.S. Department of the interior, Bureau of Mines, Washington, D. C.,

Report of Investigations No. 6282, 1963.

Carpenter, Charles B., and Schroeder, H. J., Magnolia Oil Field, U.S. Department of the Interior,

Bureau of Mines, Washington, D. C., Report of

Investigations No. 3720, 1944.

Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Field Testing, Gulf Universities

Research Consortium, Houston, Tex.,~ Report

No. 148, 1976.

/nterna(iona/ Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

1[, vol. 44, 1974.

Summary of Secondary Recovery Operations in

Arkansas During 7953, Interstate Oil Compact

Commission, Oklahoma City, Okla., 1954.

“Here Are The Big U.S. Reserves, ” Oi/ and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Frick, Thomas C. (Ed.), Petro/eum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.
730 . Appendix A

7.b Socie(Y of Petroleum Engineers Symposium on

hnpro;ed Oil Recovery,- Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

California

1 .a

1.b

2.

3.

4.

5.a

S.b

6.

7.

8.a

8.b

Reserves of Crude Oil, Natural Gas Liquids and

Natura/ Gas is the United States and Canada,

and United States Productive Capacity as of

December 37, 7974. Joint publication by the

American Gas Association, the American

petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Daily

Productive Capacity Estimated as of December

37, 1974, American Petroleum Institute, Washington, D. C., June 11, 1975.

Halbouty, Michael T. (Ed.), Geology of Giant

Petroleum Fields, American Association of

Petroleum Geologists, Tulsa, Okla., Memoir 14,

1970.

California Oil and Gas Fields, California Division

of Oil and Gas, Sacramento, Calif., 1974.

Annua/ Review of California Oil and Gas Production, Conservation Commission of California Oil Producers, Los Angeles, Calif., 1974.

Contracts and Grants for Cooperation Research

on Enhancement of Recovery of Oil and Gas,

U.S. Energy Research and Development Administration, Wash ington, D. C., Progress

Review Series Nos. 1-5, 1975-76.

Engineering correlation obtained from the

Energy Research and Development Administration, San Francisco Operations Division.

Oil and Gas Resources, Reserves, and Productive Capacities, Federal Energy Administration, Washington, D. C., Vol. 2, 1975.

Preliminary Field Test Recommendations and

Prospective Crude Oil Fie/ds or Reservoirs for

High Priority Field Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

National Petroleum Council review of Big Fields

Reservoir Data File.

U.S. Crude Oil Data, 1860-1944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

9.a

9.b

10.

11 .a

11 .b

11 .C

11 .d

12.

“Here are the Big U.S. Reserves,” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

“Enhanced Recovery Production Report, ” Oil

and Gas )ournal, Apr. 5, 1976, pp. 108-122.

Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

Field Case Histories, Oil and Gas Reservoirs,

Society of Petroleum Engineers, American institute of Mining, Metallurgical, and Petroleum

Engineers, Inc., Dallas, Tex., SPE Reprint Series

Nos. 4 and 4a, 1974-75.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol 2,

1962.

/reproved Oil-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Society of Petroleum Engineers Symposium on

/reproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Selected articles from journal of Petroleum

Technology, Oil and Gas )ournal, Oil Daily, Producer’s Monthly, and World Oil.

Colorado

1.

2.

3.

4.

5.a

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Productive Capacity Estimated as of December 31,

1974, American Petroleum Institute, Washington, D. C., June 11, 1975.

Biggs, Paul, and Koch, Charles A., Waterflooding of Oil Fields in Colorado, U.S. Dept. of the

Interior, Bureau of Mines, Washington, D. C.,

1974.

/nternationa/ Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

Parker, J. M. (Ed.), Colorado - Nebraska Oil and

Gas Field Volume, Rocky Mountain Association

of Geologists, Denver, Colo., 1962.
5.b Jensen, Fred S. (Ed.), The Oil and Gas Fields of

Colorado—A Symposium, Rocky Mountain

Association of Geologists, Denver, Colo., 1955.

6. Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

Florida

1.

2.

3.

4.

5.

6.a

6.b

Braunstein, Jules (Ed.), North American 0;/ and

Gas Fields, American Association of Petroleum

Geologists, Tulsa, Okla., Memoir 24, 1976.

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Daily

Productive Capacity Estimated as of December

31, 1974, American Petroleum Institute, Washington, D. C., June 11, 1975,

Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol 2, 1975.

/international Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

“Here Are The Big U.S. Reserves, ” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

Society of Petroleum Engineers Symposium on

hnproved 0;/ Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Illinois

1. Report of Investigations No. 3534, U.S. Bureau

of Mines, Washington, D.C.

2. Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Fie/d Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

3. Geology and Petroleum Production of the /llinois Basin, Illinois and Indiana-Kentuck y

Geological Societies, 1968.

4.a

4.b

5.

6.a

6.b

7.

8.a

8.b

Appendix A ● 131

Mast, R. F., Size, Development, and Properties

of ///inois Oil Fields, Illinois State Geological

Survey, Urbana, Ill., 1970.

Petroleum /ndustry in /1/inois, Illinois Stat e

Geological Survey, Urbana, Ill., 1975.

/nternationa/ Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

“Enhanced Recovery Production Report, ” Oi/

and Gas /ourna/, Apr. 5, 1976, pp. 108-127.

“Here Are The Big U.S. Reserves,” Oil and Gas

journal, Jan. 27, 1975, pp. 116-118.

Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

/reproved Oi/-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Society of Petro/eum Engineers Symposium on

/rnproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Kansas

1 .a

1.b

1 .C

2.

3.a

3.b

Halbouty, Michael T. (Ed.), Geology of Giant

Petroleum Fields, American Association of

Petroleum Geologists, Tulsa, Okla., Memoir 14,

1970.

Levorensen, A. 1. (Ed.), Stratigraphic Type Oil

Fields, American Association of Petroleum

Geologists, Tulsa, Okla., 1941.

Structure of Typical American Oil Fields,

American Association of Petroleum Geologists,

Tulsa, Okla., 1929.

Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 1974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

Information Circular Nos. 7750 and 7873, U.S.

Bureau of Mines, Washington, D.C.

Report of Investigations Nos. 1963 and 6134,

U.S. Bureau of Mines, Washington, D.C.
132 ●

4.

5.

6.a

6.b

6.c

6.d

7.

8.a

8.b

9.

1 O.a

1().b

1 O.c

11.

Appendix A

Contracts and Grants for Cooperative Research

on Enhancement of Recovery of Oil and Gas,

U.S. Energy Research and Development Administration, Wash ington, D. C., Progress

Review Series Nos. 1-5, 1975-76.

/nterna(iona/ Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Beene, Douglas, L., 1974 Oil and Gas Production in Kansas, Kansas Geological Survey, The

University of Kansas, Lawrence, Kans., 1976.

Ebanks, W. J., Kansas Oil For Enhanced Recovery—A Resource Appraisal, Kansas Geological

Survey, The University of Kansas, Lawrence,

Kans., 1975.

Communications with Kansas Geological

Survey.

Ores, Margaret O., and Saile, Donna K.,

Enhanced Oil-Recovery Operations in Kansas,

Kansas Geological Survey, The University of

Kansas, Lawrence, Kans., 1974.

U.S. Crude Oil Data, 7860-1944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

“Enhanced Recovery Production Report,” Oil

and (2Js )ournal, Apr. 5, 1976, pp. 108-127.

“Here Are The Big U.S. Reserves, ” Oi/ and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol 2,

1962.

hnproved Oil-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Society of Petroleum Engineers Symposium on

hnproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Selected articles from )ourna/ of Petro/eurn

Technology, Oi/ and Gas )ournal, Oi/ Dai/y, Producer’s Monthly, and World Oil.

Louisiana (Onshore)

1 .a

1.b

2.

3.a

3.b

4.a

4.b

5.a

5.b

6.

7.

Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 37, 7974, Joint publication by the

American Gas Association, the American

petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Daily

Productive Capacity Estimated as of December

31, 7974, American Petroleum Institute, Washington, D. C., Jun~ 11, 1975.

M. E. Hawkins, et. al., Analyses of Brines From

Oil Productive Formations in South Arkansas

and North Louisiana, U.S. Department of the interior, Bureau of Mines, Washington, D. C.,

Report of Investigations No. 6282, 1963.

Secondary Recovery and Pressure Maintenance

Operations in Louisiana, Louisiana Department

of Conservation, Baton Rouge, La., 1973, 1974.

Summary of Field Statistics and Drilling Operations, State of Louisiana, Department of Conservation, Baton Rouge, La., 1974.

“Enhanced Recovery Production Report,” Oil

and Gas )ourna/, Apr. 5, 1976, pp. 108-127.

“Here Are The Big U.S. Reserves,” Oil and Gas

journal, Jan. 27, 1975, pp. 116-118.

/reproved Oil-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Society of Petroleum Engineers Symposium on

/reproved Oi/ Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, inc.,

Dallas, Tex., Preprint Series.

Formation Water Resistivity Data: South Louisiana, Offshore and Adjacent Area, Society of

Production Well Log Analysts, Lafayette, La.

National Petroleum Council Review of Big

Fields Reservoir Data File.

Louisiana (Offshore)

1. U.S. Geological Survey, Metairie, La.
Mississippi

1.

2.

3.a

3.b

4.

5.

6.

7.

8.a

8.b

9.

Braunstein,

Gas Fields,

Geologists,

Jules (Ed.), North American Oil and

American Association of Petroleum

Tulsa, Okla., Memoir 24, 1976.

Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 37, j 974, Joint publication by the

American Gas Association, the American

petroleum institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

Hawkins, M. E., et. al., Analyses of Brines from

Oil Productive Formations in Mississippi and

Alabama, U.S. Department of the Interior,

Bureau of Mines, Washington, D. C., Report of

Investigations No. 6167, 1963.

Personal files of W. Dietzman, U.S. Bureau of

Mines, Dallas, Tex.

Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Field Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

/n(ernational Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Mississippi Oil and Gas Bu//etin, Mississippi

State Oil and Gas Board, Jackson, Miss., April

1975.

“Enhanced Recovery Production Report,” Oil

and Gas )ourna/, Apr. 5, 1976, pp. 108-127.

“Here Are The Big U.S. Reserves,” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Frick, Thomas C. (Ed.), Petro/eurn Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

Montana

1. Braunstein, Jules (Ed.), North American Oil and

Gas Fiefds, American Association of Petroleum

Geologists, Tulsa, Okla., Memoir 24, 1976.

2. Hamke, J. R., et. al. Oil Fields in the Williston

Basin in Montana, North Dakota, and South

Dakota, U.S. Department of the Interior, Bureau

3.

4.a

4.b

5.

6.

7.

8.

9.

-1o.

of Mines, Washington,

1966.

Preliminary Field Test

Prospective Crude Oil

Appendix A ● 133

D. C., Bulletin No. 629,

Recommendations and

Fields or Reservoirs for

l-lig~ Priority Fie/d Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

/international Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

Society of Petroleum Engineers Symposium on

/reproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Annual Review for the Year 7975, State of Montana Oil and Gas Conservation Division,

Helena, Mont., 1973, 1976.

“Here Are the Big U.S. Reserves, ” Oil and Gas

/ourna/, Apr. 5, 1976, pp. 108-127.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

United States Petroleum Through 7980, U.S.

Office of Oil and Gas, Washington, D. C., 1968.

Landes, Kenneth K., Petroleum Geology of the

United States, Wiley -lnterscience, New York,

N. Y., 1970.

Ver Wiebe, W. A., North American Petroleum,

Wichita, Kans., 1952.

New Mexico

1. Braunstein, Jules (Ed.), North American Oil and

Gas Fields, American Association of Petroleum

Geologists, Tulsa, Okla., Memoir 24, 1976.

2. Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 37, 7974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

3. Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

4. Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Field Testing, Gulf Universities
134 ●

5.

6.

7.

8.

9.

10.

11.

12.a

12.b

13.

Appendix A

Research Consortium, Report No. 148 ,

Houston, Tex., 1976.

Secondary Recovery and Pressure Maintenance

Projects in New Mexico, Interstate Oil Compact

Commission, Oklahoma City, Okla., 1970.

/international Oil and Gas Development, lntj2rnational Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

U.S. Crude Oil Data, 7860-7944, Nationa l

Petroleum Council, Washington, D. C., Vol 1,

1970.

“Here Are The Big U.S. Reserves, ” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

Phifer, Robert L., New Mexico Petroleum

Review, Phifer Petroleum Publication, Dallas,

Tex., 1956.

A Symposium of Oil and Gas Fields of

Southeastern New Mexico, Roswell Geological

Society, Roswell, N. Mex., 1957, 1960, 1966.

Frick, Thomas C. (Ed.), Petro/eum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol 2,

1962.

/reproved Oil-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Communications with State Petroleum

Geologists.

North Dakota

1. Halbouty, Michael T. (Ed.), Geology of Giant

Petroleum Fie/ds, American Association of

Petroleum Geologists, Tulsa, Okla., Memoir 14,

1970.

2. Hamke, J. R., et. al., Oil Fields in the Wi//iston

Basin in Montana, North Dakota and South

Dakota, U.S. Department of the Interior, Bureau

of Mines, Washington, D. C., Bulletin No. 629,

1966.

3. /international Oil and Gas Development, international Oil Scouts Association, Austin, Te’k., Part

Ii, vol. 44, 1974.

4.a Oil and Gas Fields of North Dakota, Nort h

Dakota Geological Survey, 1962.

4.b

5.a

5.b

6.

7.

0;1 production Statistics for 7974, North Dakota

Geological Society, 1952.

“Enhanced Recovery Production Report, ” 0;/

and Gas )ournal, Vol. 74, No. 14, Apr. 5, 1976,

pp. 108-127.

“Enhanced Recovery Production Report,” Oi/

and Gas )ourna/, Vol. 74, No. 14, Apr. 5, 1976,

pp. 108-127.

Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 7974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

Communications with State Petroleum

Geologists.

Oklahoma

1.

2.a

2.b

3.

4.

5.

6.

Geology of Giant Petroleum Fields, American

Association of Petroleum Geologists, Tulsa,

Okla., Memoir 14, 1970.

Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 37, 1974, Joint publication by the

American Gas Association, the American

petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Days” Daily

Productive Capacity Estimated as of December

.37, 7974, American Petroleum Institute, Washington, D. C., June 11, 1975.

Report of Investigations Nos. 2997, 3180, 4450,

4917, 5018, 5134, 5316, and 5415, U.S. Bureau

of Mines, Washington, D.C.

Contracts and Grants for Cooperative Research

on Enhancement of Recovery of Oil and Gas,

U.S. Energy Research and Development Administration, Wash ington, D. C., Progress

Review Series Nos. 1-5, 1975-76.

Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Field Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

/nternationa/ Oi/ and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.
Appendix A . 735

7.

8.

9.a

9.b

10.

11.

12,

13.a

13.b

13.C

Secondary Recovery and Pressure Maintenance

Operations, The Interstate Oil Compact Commission, Oklahoma City, Okla., 1975.

U.S. Crude O;l Data, 1860-1944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

“Enhanced Recovery Production Report, ” Oil

and Gas /ourna/, Apr. 5, 1976, pp. 108-127.

“Here Are The Big U.S. Reserves, ” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

Cramer, Richard D., et. al., 0;/ and Gas Fields of

Oklahoma, Oklahoma Geological Survey,

Oklahoma City, Okla., 1963.

Special Computer Analysis from Petroleum

Data System of North American, University of

Oklahoma, Norman, Okla.

Special Analysis by Petroleum Information, Inc.,

Tulsa, Okla.

Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962 .

Improved Oil-Recovery Field Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

Society of Petroleum Engineers Symposium on

/reproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Pennsylvania

1. Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 7974, Joint publication by the

American Gas Association, the American

petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

2. Report of Investigations, Nos. 6917, 6942,

6943, 7272, U.S. Bureau of Mines, Washington,

D.C.

3. Contracts and Grants for Cooperative Research

on Enhancement of Recovery of Oil and Gas,

U.S. Energy Research and Development Administration, Wash ington, D. C., Progress

Review Series Nos. 1-5, 1975-76.

4. Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Field Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

5. U.S. Crude Oil Data, 1860-1944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

6. “Here Are The Big U.S. Reserves, ” Oil and Gas

)ournal, Jan. 27, 1975, pp. 116-118.

7. Frick, Thomas C. (Ed.), Petroleum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

/reproved Oil Recovery Field Reports, Society of

Petroleum Engineers, American Institute of Mining, Metallurgical, and Petroleum Engineers,

Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

8. Ver Wiebe, W. A., North America n

Petro/eurn, Wichita, Kans., 1952.

9. Selected articles from journal of Petroleum

Technology, Oil Daily, Oil and Gas journal, Producer’s Monthly, and World Oil.

10. Communications with State Petroleum

Geologists.

Texas

1 .a Halbouty, Michael T. (Ed.), Geology of Giant

Petroleum Fie/ds, American Association of

Petroleum Geologists, Tulsa, Okla., Memoir 14,

1970.

1.b Braunstein, Jules (Ed.), North American Oil and

Gas Fields, American Association of Petroleum

Geologists, Tulsa, Okla., Memoir 24, 1976.

2.a Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, ?974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

2.b The One Hundred Largest Fields in the United

States with Remaining Estimated Proved

Reserves of Crude Oil and “Ninety Day” Daily

Productive Capacity Estimated as of December

37, 1974, American Petroleum Institute, Washington, D. C., June 11, 1975.
136 . Appendix A

3. Hawkins, M. E., et. al., Chernica/ Ana/yses and

Electrica/ Resistivities of Oil Field Brines From

Fie/ds in East Texas, U.S. Department of the interior, Bureau of Mines, Washington, D. C.,

Report of Investigations No. 6422, 1964.

4. Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

5,a Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Fie/d Testing, Gulf Universities

Research Consortium, Houston, Tex., Report

No. 148, 1976.

5.b Assessment of Enhanced Recovery Technology

as a Means /or /ncreasing Total Crude Oi/

Recovery in Texas, Gulf Universities Research

Consortium, The State of Texas, Governor’s

Energy Council.

6. /nternationa/ Oi/ and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

7.a U.S. Crude Oil Data, 1860-7944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

7.b National Petroleum Council review of Big Fields

Reservoir Data File.

8.a “Enhanced Recovery Production Report, ” Oil

and Gas Journal, Apr. 5, 1976, pp. 108-127.

8.b “Here Are The Big U.S. Reserves,” Oi/ and Gas

)ourna/, Jan. 27, 1975, pp. 116-118.

9. Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

10.a Frick, Thomas C. (Ed.), Petro/eum Production

Handbook, Society of Petroleum Engineers,

American Institute of ,Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex,, Vol. 2,

1962.

10.b. /reproved Oi/-Recovery Fie/d Reports, Society

of Petroleum Engineers, American Institute of

Mining, Metallurgical, and Petroleum Engineers,

inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.

1 O.c Field Case Histories, Oil and Gas Reservoirs,

Society of Petroleum Engineers, American institute of Mining, Metallurgical, and Petroleum

Engineers, Inc., Dallas, Tex., Reprint Series Nos.

4 and 4a, 1974-75.

Io.d Society of Petroleum Engineers Symposium on

/reproved Oi/ Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

11 .a Annual Production by Active (and /nactive)

Fields, Texas Railroad Commission, Oil and Gas

Division, Austin, Tex., 1974.

11 .b Maximum Efficiency Rate (MER) Hearing Summaries, Texas Railroad Commission, The Texas

State House Reporter, Austin, Tex., 1975.

11 .C Secondary Recovery Application Summaries,

Texas Railroad Commission, The Texas State

House Reporter, Austin, Tex., 1973, 1974.

11 .d A Survey of Enhanced Recovery Operations in

Texas, Texas Railroad Commission, Oil and Gas

Division, Austin, Tex., 1972.

Utah

1. Braunstein, Jules (Ed.), North American Oil and

Gas Fields, American Association of Petroleum

Geologists, Tulsa, Okla., Memoir 24, 1976.

2. Reserves of Crude oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 7974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

3. Report of Investigations No. 5511 and 6196,

U.S. Bureau of Mines, Washington, D.C.

4. Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

5. A Symposium of the Oil and Gas Fields of Utah,

Intermountain Association of Petroleum

Geologists, 1961.

6. /nternationa/ Oi/ and Gas Development, international Oil Scouts Association, Austin, Tex., Part

11, vol. 44, 1974.

7. “Here Are the Big U.S. Reserves, ” Oi/ and Gas

/ourna/, Jan. 27, 1975, pp. 116-118.

8. Special Computer Analysis from Petroleum

Data System of North America, University of

Oklahoma, Norman, Okla.

9. Halbouty, Michael T. (Ed.), Geo/ogy of Giant

Petroleum Fields, American Association of

Petroleum Geologists, Tulsa, C)kla., Memoir 14,

1970.

10. Plain Facts About Oil and Gas in Utah, Utah

Geological and Mineral Survey, 1965.
West

1.

2.

3.

4.

5.

6.

Virginia

Reserves of Crude Oil Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 7974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

Contracts and Grants for Cooperative Research

on Enhancement of Recovery of Oi/ and Gas,

U.S. Energy Research and Development Administration, Wash ington, D. C., Progress

Review Series Nos. 1-5, 1975-76.

Secondary Recovery Operations West Virginia

to )anuary 7, 1960, Interstate Cil Compact

Commission, Oklahoma City, Okla., 1961.

U.S. Crude Oil Data, 1860-7944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

Selected articles from )ourna/ of Petroleum

Technology, Oil and Gas )ournal, Oil Daily, Producer’s Monthly, and World Oil.

Communications with State Petroleum

Geologists.

Wyomin g

1. Reserves of Crude Oil, Natural Gas Liquids and

Natural Gas in the United States and Canada,

and United States Productive Capacity as of

December 31, 1974, Joint publication by the

American Gas Association, the American

Petroleum Institute, and the Canadian

Petroleum Association, Vol. 29, May 1975.

2. Biggs, Paul and Espach, Ralph H., Petro/eum and

Natural Gas Fie/ds in Wyoming, U.S. Department of the Interior, Bureau of Mines, Pt’ashington, D.C. Bulletin No. 582, 1960.

3. Oil and Gas Resources, Reserves and Productive

Capacities, Federal Energy Administration,

Washington, D. C., Vol. 2, 1975.

4.

5.

6.

7.a

7.b

8.a

8.b

8.c

9.

10.

11.

Appendix A ● 137

Preliminary Field Test Recommendations and

Prospective Crude Oil Fields or Reservoirs for

High Priority Fie/d Testing, Gulf Universities

Research Consortium, Report No. 148,

Houston, Tex., 1976.

/nterna(ional Oil and Gas Development, international Oil Scouts Association, Austin, Tex., Part

1[, vol. 44, 1974.

U.S. Crude Oil Data, 7860-7944, National

Petroleum Council, Washington, D. C., Vol. 1,

1970.

“Here Are The Big U.S. Reserves,” Oil and Gas

lourna/, Jan. 27, 1975, pp. 116-118.

“Enhanced Recovery Production Report,” The

Oil and Gas /ourna/, Vol. 74, No. 14, Apr. S,

1976, pp. 108-127.

Frick, Thomas C. (Ed.), Petro/eum Production

Handbook, Society of Petroleum Engineers,

American Institute of Mining, Metallurgical, and

Petroleum Engineers, Inc., Dallas, Tex., Vol. 2,

1962.

Field Case Histories, Oi/ and Gas Reservoirs,

Society of Petroleum Engineers, American institute of Mining, Metallurgical, and Petroleum

Engineers, Inc., Dallas, Tex., SPE Reprint Series

Nos. 4 and 4a, 1974-75.

Society of Petroleum Engineers Symposium on

/reproved Oil Recovery, Society of Petroleum

Engineers, American Institute of Mining,

Metallurgical, and Petroleum Engineers, Inc.,

Dallas, Tex., Preprint Series.

Wyoming Oil and Gas Fie/ds Sympos;um,

Wyoming Geological Association, Caspar,

Wyo. 1957, 1961, 1969.

Wyoming 0// and Gas Stat/sties, The Wyoming

Oil and Gas Conservation Commission, Caspar,

Wyo., 1975.

Selected articles from journal of petro/eum

Technology, Oil and Gas )ournal, Oil Daily, Producer’s Monthly, and Wor/d Oi/.
138 ● Appendix A

Analysis of Reservoirs in Data Base To Determine

Amount and Distribution of Remaining Oil

Distribution of the Original Oil in Place

Reservoirs frequently taper out near the

perimeter of the productive acreage. The OTA

data base did not contain data which would approximate variation of thickness or oil saturation

with a real position. For the purposes of this study

it was assumed that 95 percent of the original oil

in place was contained in 80 percent of the reservoir acreage. 2 All enhanced oil recovery (EOR)

projects were developed in this “richer” portion

of the reservoir. This assumption was implemented in individual reservoir calculations by increasing the net oil sand in the richer portion of

the reservoir.

Volume of Oil Remaining

The oil resource for EOR processes is the oil

which is not recovered by primary and secondary

methods. The OTA data contained estimates of

the original oil in place as well as the reserves attributed to current operations. Reserves were

considered to be the maximum attainable from

each reservoir without application of enhanced

recovery methods. It was assumed that regions

which could be waterflooded economically have

been or are now under development. Thus, infill

drilling would be considered to accelerate the

production of known reserves rather than to add

new reserves.

Distribution of the Remaining

Oil Resource

Two models were used to approximate the

distribution of the oil resource which remains for

potential recovery processes.

Reservoirs With Limited Waterflood

Response

Reservoirs which were candidates for thermal

recovery processes were those where

waterflooding has not been applied successfully

over an appreciable portion of the reservoir. The

oil resource at the beginning of thermal recovery

operations was assumed to be distributed

uniformly throughout each reservoir. The average

oil saturation at this point was computed using

equation 1A, which represents a material balance

over the reservoir volume.

where

S 0 2 = material balance, average oil saturation

S o i = oil saturation in the reservoir at discovery

N =estimated initial oil in place, stock-tank

barrels

N P = ultimate oil recovery by primary and

secondary methods in stock-tank barrels

Boi = oil formation volume factor at initial

pressure. Ratio of volume occupied by

the oil at reservoir conditions to the

volume of oil which would be

recovered at the surface at stock-tank

conditions

BO = oil formation volume factor at the reservoir pressure which exists when NP

stock-tank barrels are produced.

The OTA data base did not contain values of

B0 for every reservoir but since reservoir temperatures were available the value of BO was set

at the value corresponding to thermal expansion

at reservoir temperature. Equations 2A and 3A

derived from the correlations of Katz3 were used

to estimate BO

:

~R~~search and Development In Enhanced 0;/ Recovery,

Final Report, The Methodology, U.S. Energy Research and

Development Administration, Part 3 of 3, p. V-4, ERD A

77-.?07 1, December 1976.

‘1. W. Amyx, D.M. Bass, and R.L. Whiting, Petro/eum

Reservoir Engineering p. 429, McGraw Hill Book Company

(1 960).
Appendix A . 739

2A

3A

where

API = stock-tank oil gravity in degrees API

T R = reservoir temperature, “F.

There were insufficient data to estimate changes

in BO from dissolved gas.

Several large reservoirs in California do not

have uniform oil saturation in all portions of the

reservoir. Reservoirs which were known to have

oil saturation distributions were identified by

members of the Technology Task Force of the

National Petroleum Council (NPC) study. These

data were available for the OTA study. However,

it was not feasible to subdivide the reservoirs in

the economic model. Subdivision of the reservoirs would change the price versus ultimate

recovery projections but would not alter the ultimate recovery.

Reservoirs Under Natural Water Drive or the

Waterflooding Process

The carbon dioxide (CO2 miscible process

and the surfactant/polymer process will probably

be applied in reservoirs where waterflooding—

either through natural water influx or water injection-has been successful. The entire reservoir

volume is not swept by a waterflood. Consequently, there is a distribution of oil saturation

which varies from essentially initial oil saturation

in regions not swept by water to a residual oil

saturation in the volume swept by the water.

The oil recovery models for both CO2 miscible

and surfactant/polymer processes assume that

the processes will be contacting residual oil in

some portions of the volume swept by the

waterflood. It is necessary to estimate the

volume of this region as well as the residual oil

saturation. Although these two parameters are

not known for every reservoir, it is possible to

develop a relationship between them for certain

situations.

The data base contains estimates of the initial

oil in place, oil recovered by primary and secondary processes, and the formation volume factors

at initiation and end of primary and secondary

recovery. If these data are considered correct, the

volumetric sweep efficiency and the average

residual saturation in the region swept by water

are related by equation 4A.

— .

4A

where

E vm = volumetric sweep efficiency of the r

waterflood, fraction of the reservoir

swept by the waterflood

s orw = average oil saturation in the reservoir

volume swept by the waterflood

Other terms were defined in equation 1A.

Equation 4A was derived from an overall

material balance on the reservoir in which 1 ) all

portions of the reservoir are considered hydraulically connected, 2) regions not swept by

the waterflood are resaturated to the initial oil

saturation at the current reservoir pressure, and 3)

the rock pore volume is invariant with pressure.

Neither SOrw nor Evm were available in the data

base. Estimates of Sorw on a geological and

regional basis were made in the NPC study on

enhanced oil recovery using the study group’s

general knowledge of the reservoirs in the Lewin

data base and experience in similar reservoirs

which were not included in the data base. Based

on this knowledge, a residual oil saturation of 20,

25, or 30 percent was assigned to each reservoir

in Texas, Louisiana, or California which was a

candidate for surfactant/polymer or C02 miscible

processes.

The Office of Technology Assessment investigated the validity of these estimates through

discussion with members of the NPC study group

and review of the technical literature. Additional

data were obtained from a committee preparing a

book on residual oil saturations for the Interstate

Oil Compact Commission. 4 Personal inquiries

~Personal communicatifm with Lincoln Elkins, November

1976.
140 . Appendix A

were made to companies and/or personnel who

did not participate in the selection of specific

values for the NPC study but who had knowledge

of the properties of reservoirs in the NPC/Lewin

data base.

The following conclusions were reached:

●

●

●

●

There are a relatively small number of reservoirs where estimated values of the residual

oil saturation have been confirmed with independent methods of measurement.

Values of the residual oil saturation assigned

by the NPC study group are consistent with

the information which was available in the

public literature and obtained through personal inquiry. Specific reservoirs within a

region are likely to vary from the assigned

values, but this variation is believed to be

within the uncertainty of the estimates.

The uncertainty in the residual oil saturation

estimates is significant. The uncertainty is

primarily due to inadequate measurement

techniques and limited application of existing methods. As a result, it is not uncommon to find technical personnel in different

operating divisions of the same company

whose estimates of the residual oil saturation in a particular reservoir differ by 5

saturation percentage points.

Residual oil saturations in the region swept

by water are judged to be known with more

certainty than the volumetric sweep efficiency, The OTA study group accepted the

NPC assignment of residual oil saturation for

those reservoirs which were also in the NPC

base case. Reservoirs not in this category

were assigned saturations indicated in table

A-1 .

Two constraints were imposed on the

volumetric sweep efficiencies computed from

equation 4A using the residual oil saturations in table A-1.

The maximum sweep efficiency of a

waterflood was considered to be 90 percent

of the reservoir volume. If the computed Evm

was larger than 0.9, the value of Evm was set

to 0,9 and the value of SORW was computed

from equation 4A for the reservoir.

Table A-1

Average Oil Saturation in the Region Swept by

Waterflood

Region s orw

Texas District 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.20

South Louisiana, Offshore Texas Districts

1,2,4,5, and 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.25

California, North Louisiana, the balance of Texas, and

all other States. . . . . . . , . . . . . . . . . . . . . . . . . . . . . . 0.30

The minimum volumetric sweep efficiency of a waterflood was considered to be 40

percent in California and 50 percent in all

other reservoirs. If the computed EVm w as

less than the minimum value, the appropriate minimum was assigned to Evm and the

value of Sorw computed from equation 4A was

assigned to the reservoir.

Consistency of Oil Resource Estimates With

Those Implied by Other Studies

The approach used in the NPC study involved

assignment of both volumetric sweep efficiency

and residual oil saturation for each reservoir. This

led to overstatement of the resource when the

ultimate production data were also known.

However, ultimate production data were not

available to the NPC Technology Task Force for

every reservoir in the NPC data base.

The initial oil in place (N) for reservoirs used in

the NPC study was computed by OTA by inserting NPC-assigned sweep efficiencies and residual

oil saturations in equation 4A. Ultimate production

for each reservoir was included in the data base so

that the initial oil in place could be computed from

equation 4A. The resulting values of the initial oil in place were significantly different from

values in the data base. Differences were particularly large (>10 percent) in California. The

difference could be attributed to either overstatement of the initial oil in place or understatement of the ultimate production. Information

gained from contacts with oil industry personnel

familiar with certain reservoirs was used to

reevaluate the methods used by Lewin and

Associates, Inc., to determine the initial oil saturations. Revisions of this analysis led to the reduction

of oil-in-place estimates by 3.5 billion barrels in

California.
Appendix A ● 141

Reservoirs assigned to one set of OTA runs for

C 02 miscible and surfactant/polymer processes

were analyzed to determine if there were large

differences between the initial oil-in-place estimates in the data base and those computed by

using NPC sweep efficiencies and residual oil

saturations in equation 4A. Results extrapolated

to national totals are summarized in table A-2.

The comparison in table A-2 indicates a

difference of about 10 percent between estimates for the surfactant/polymer reservoirs. This

is within the range of uncertainty. The difference

approaches 30 percent for reservoirs which were

C 02 candidates. However, as indicated in the

section on Discussion 01 Results (page 46) in

chapter III, the effect on calculated oil recovery

by the CO2 miscible process was minimal.

Table A-2

Comparison of initial Oil in Place Computed for

Estimates of Sweep Efficiency and Residual Oil

Saturations

Reservoirs in Surfactant/Polymer Economic Evaluation

Original oil in place from OTA data

base . . . . . . . . . . . . . . . ~ . . . . . . . . . . 51.2 billion barrels

Original oil in place determined from

material balance calculations using

NPC sweep efficiency and residual

oil saturations . . . . . . . . 46.4 billion barrels

Difference—surfactant/polymer reservoirs . . . . . . . . . . . . . . . . 4.8 billion barrels

Reservoirs in CO2 Miscible Economic Evaluation

Original oil in place in OTA data base 93. s billion barrels

Original oil in place determined from

material balance calculations using

NPC sweep efficiency and residual

oil saturations . . . . . . 130.0 billion barrels

Difference-CO 2 miscible reservoirs . . 36.5 billion barrels
Appendix B

Supporting Materials for Oil Recovery Projections

From Application of Enhanced Recovery

Processes

Page

TECHNOLOGICAL PROJECTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Surfactant/Polymer Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 147

Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

Composition and Costs of Injected Materials . . . . . . . . . . . . . . . . . . . . . . . . IS3

Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Polymer Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 154

Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

Effect of Polymer Flooding on Subsequent Application

of Surfactant/Polymer or Carbon Dioxide Miscible Processes . . . . . . . . . 157

Steam Displacement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 157

Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........158

Steam Requirements and Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160

Sensitivity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161

In Situ Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162

State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 162

Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

Carbon Dioxide Miscible . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 165

Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166

Carbon Dioxide Costs.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

Results of Carbon Dioxide Cost Calculations . . . . . . . . . . . . . . . . . . . . . . . . 169

Calculation Method and Details-Carbon Dioxide Costs . . . . . . . . . . . . . . 171

Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174

ECONOMIC MODEL.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175

Structure of the Model.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175

Specific Economic Assumptions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176

Economic Data-General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

Offshore Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190

Costs That Do Not Vary With Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . 190

Cost That Vary With Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191

143
144 . Appendix B

LIST OF TABLES

Table

Number Page

B-1 .

B-2.

B-3.

B-4.

B-5.

B-6.

B-7.

B-8.

B-9,

B-10.

B-1 1.

B-1 2.

B-1 3,

B-1 4.

B-1 5.

B-1 6.

B-1 7.

B-1 8.

B-1 9.

B-20.

B-21 .

B-22.

B-23.

B-24,

B-25.

B-26.

B-27.

B-28.

B-29.

B-30.

B-31 .

B-32.

B-33.

B-34.

B-35.

B-36.

B-37.

ERDA Cooperative Field-Demonstration Tests of EOR Using the

Surfactant/Polymer Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Summary of Surfactant Field Tests Being Conducted by Industry Without

ERDA Assistance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Development of a Five-Spot Pattern—Surfactant/Polymer Process . . . . . . . .

Chemical Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Component Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Surfactant/Polymer Process-Ultimate Recovery, Summary of Computed

Results-Process and Economic Variations . . . . . . . . . . . . . . . . . . . . . . . . .

Production Schedule for Polymer-Augmented Waterflood. . . . . . . . . . . . . . .

Polymer-Augmented Waterflooding– Ultimate Recovery, . . . . . . . . . . . .

production Schedule for Steam Displacement Process . . . . . . . . . . . . . . . . . .

Recovery Uncertainties Effecting Steam Displacement Results . . . . . . . .

Effect of Uncertainties in Overall Recovery on Ultimate Production . . . . . . .

Effect of Well Spacing on Ultimate Recovery of Oil Using the Steam

Displacement Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Advancing Technology Cases-Oil Displacement Model—Wet

Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

production Schedule—Wet Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Effect of Changes in Compressor Operating Costs and Displacement

Efficiency in Ultimate Oil Recovery Using the In Situ Combustion Process

Carbon Dioxide Injection Schedule. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

production Rate Schedule for Carbon Dioxide Miscible . . . . . . . . . . . . . . . . .

Gas Injection Schedule-Offshore Carbon Dioxide Miscible . . . . . . . . . . . . .

Oil Production Schedule-Offshore Carbon Dioxide Miscible. . . . . . . . . . . .

Pipeline Capacity Versus Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lateral Lines Associated With Pipeline Capacity . . . . . . . . . . . . . . . . . . . . . . .

Total Costs per Mcf of C02

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . “ “ . “ o “

Pipeline Capacity as a Function of Field Size . . . . . . . . . . . . . . . . . . . . . . . . . . .

Estimated Recoveries for Advancing Technology--High-Process

Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sensitivity of Ultimate Recovery to Carbon Dioxide Cost. . . . . . . . . . . . . . . .

Sensitivity of Ultimate Recovery to Carbon Dioxide Cost. . . . . . . . . . . . . . . .

Production Unit Size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Schedule of Starting Dates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Timing of Reservoir Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Drilling and Completion Costs for production and Injection Wells . . . . . . . .

Well, Lease, and Field Production Equipment Costs-Production Wells. . . .

Costs of New Injection Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Well Workover and Conversion Costs for Production and Injection Wells,

Parts A and B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Basic Operating and Maintenance Costs for Production and Injection Wells

Incremental Injection Operating and Maintenance Costs. . . . . . . . . . . . . . . .

State and Local production Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

State Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

148

149

152

153

153

154

156

157

160

161

161

162

163

164

164

167

168

168

168

172

172

173

173

174

175

175

177

177

178

179

180

182

184

186

188

190

190
Appendix B . 145

B-38. Offshore Costs That Do Not Vary by Water Depth . . . . . . . . . . . . . . . . . . . . . 191

B-39. Offshore Costs That Vary by Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . . . . 191

B-40. Drilling and Completion Cost Bases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192

LIST OF FIGURES

Figure

Number Page

B-1 . Historical Incremental production Therm Recovery-California ... , . . . . . . . . 159

B-2. Pipeline Cost Versus Capacity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171

B-3. Variable C02 Transportation Costs Versus Pipeline Capacity. . . . . . . . . . . . . 172

B-4, Transportation of CO2– Break-Even Analysis . . . . . . . . . . . . . . . . . . . . . . . 173
This appendix presents supplementary

materials which were used to prepare oil recovery projections and to compute the costs to produce enhanced oil. It is organized into two sections, the first describing the technological

assumptions for each enhanced oil recovery

(EOR) process. For each process the “state of the

art” of the technology is assessed. Models used

to compute recoveries and production rates are

Appendix B . 147

presented in detail. Cost data which are specific

to a process are documented. Results of calculations not presented in the body of the report are

given.

The second section describes the economic

model used in the OTA study. Cost data which

are independent of the process are documented

in this section.

Technological Projections

Surfactant/Polymer Flooding

State of the Art—Technological Assessment

The surfactant/polymer process involves two

technologies. The first is the art of formulating a

chemical slug which can displace oil effectively

over a wide range of crude oil compositions, formation water characteristics, and reservoir rock

properties. As used in this section the term

chemical slug refers to all injected fluids which

contain a surfactant mixed with hydrocarbons,

alcohols, and other chemicals. Excluded from this

definition is alkaline flooding,1 a process in which

surfactants are generated in situ by reaction of

certain crude oils with caustic soda.

The second technology is the displacement of

the injected chemical slug through the reservoir.

This technology is governed by economic and

geologic constraints. The cost of the chemical

slug dictates use of small volumes in order to

make the process economically feasible. The

technology for displacement of the chemical slug

through a reservoir relies on controlling the relative rate of movement of the drive water to the

chemical slug. Effective control (termed mobility

control) through process design prevents excessive dilution of the chemical slug. If mixed

with displaced oil or drive water, the chemical

slug would become ineffective as an oil-displacing agent. Control of the mobility of the chemical

slug or drive water is accomplished by altering

the viscosities or resistance to flow of these fluids

when they are formulated. z

NOTE: All references to footnotes in this appendix appear

on page 193.

Research to find chemicals which displace oil

from reservoir rocks has been conducted in

Government, industry, and university laboratories

for the past 25 years. Research activity in the

period from 1952 to about 1959 was based on

the injection of dilute solutions of surfactant

without mobility control .-3 Activity peaked with

the advent of each new chemical formulation in

the laboratory and declined following disappointing field results. In some tests, surfactants

were injected into reservoirs with no observable

response. in other tests, the response was so

small that the amount of incremental oi l

recovered was almost unmeasurable. The cost of

whatever incremental oil was produced was

clearly uneconomic.

The period beginning in the late 1950’s and

extending into the present is characterized by

major advances in formulation of the chemical

slug and control of slug movement through a

reservoir. Several laboratories developed formulations based on petroleum sulfonates which

may displace as much as 95 percent of the oil in

some portions of the reservoir which are swept

by the chemical slug.4,5 Addition of water-soluble

polymer to drive water has led to mobility control between the drive water and chemical slug.6

Field tests of the different processes have produced mixed results. About 400,000 barrels of oil

have been produced from reservoirs which have

been previously waterflooded to their economic

Iimit.

7,8,9 Oil from one test was considered~

economic. All other oil was produced under conditions where operations were uneconomic.

Offsetting these technically successful tests10 are

several field tests which yielded considerably less
148 ● Appendix B

incremental oil than anticipated. ” 11,12,13 The state

of technology is such that honest differences of

opinion exist concerning the reasons for disappointing field test results.14,15

The current ERDA program includes six largescale, cooperative, field-demonstration tests. The

fields and locations are summarized in table B-1.

The first five projects are in fields which have

been intensively waterflooded. In these tests, the

principal objectives are to demonstrate the efficiency and economics of recovery from a successfully depleted waterflood using the surfactant/polymer process. The Wilmington reservoir

contains a viscous oil. An objective of this project is the development of a surfactant/polymer

system which will displace viscous oi l

economically.

Table B-1

ERDA Cooperative Field-Demonstration Tests of EOR

Using the Surfactant/Polymer Process

Field Location

El Dorado. . . . . . . . . . . . . . . . . . . . . . . . . . Kansas

North Burbank. . . . . . . . . . . . . . . . . . . . . Oklahoma

Bradford . . . . . . . . . . . . . . . . . . . . . . . . . . . Pennsylvania

Bell Creek. . . . . . . . . . . . . . . . . . . . . . . . . . Montana

Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . Illinois

Wilmington . . . . . . . . . . . . . . . . . . . . . . . . California

Screening Criteria. —The screening criteria in

table 7 of the main text reflect estimates of technological advances in the next 20 years as well as

current technology inferred from past and ongoing field tests. For example, technological advances in temperature tolerance are projected so

that reservoirs which have a temperature of

200° F can have a technical field test in 1985.

The OTA screening criteria coincide with

those used by the National Petroleum Council

(NPC) 16 with one exception. The OTA data base

did not contain adequate water-quality data for

all reservoirs. Consequently, reservoirs were not

screened with respect to water quality.

The screening criteria were reviewed prior to

acceptance. The review process included informal contacts with personnel who did not participate in the NPC study and an examination of the

technical literature. The principal variables are

discussed in the following sections.

The screening criteria are judged to be representative of the present and future technological

limits. As discussed later, it is recognized that

permeability and viscosity criteria have economic

counterparts. However, the number of reservoirs

eliminated as candidates for the surfac -

tant/polymer process by either of these screening

criteria was insignificant.

Current Technology (1976).--Current limits of

technology are reflected by field tests which

have been conducted or are in an advanced stage

of testing. These are summarized in table B-2.17

Field tests are generally conducted in reservoirs

where variation in rock properties is not large

enough to obscure the results of the displacement test due to reservoir heterogeneities. These

reservoirs tend to be relatively clean sandstone

with moderate clay content. A crude oil viscosity

less than 10 centipoise is characteristic of most

surfactant/polymer field tests. Reservoir temperatures range from 55° F to 169° F.

Reservoir Temperature.—Surfactants and

polymers are available which tolerate temperatures up to about 170° F. Research on

systems which will be stable at 200° F is underway in several laboratories. The rate of technological advance in this area will probably be

related to the success of field tests of the surfactant/polymer process in lower-temperature reservoirs. Successful field tests will stimulate

development of fluids for higher-temperature

deeper reservoirs as potential applications in

those reservoirs become a reality. The assumed

timing of technological advances in temperature

limitations appears attainable.

Permeability and Crude Oil Viscosity. -Permeability of the reservoir rock is both a technological and an economic factor. The surfactant/polymer process will displace oil from low

permeability reservoir rock.18 A minimum permeability based on technical performance of the

process has not been established. Low permeability may correlate with high-clay content of

the reservoir rock and corresponding high-surfactant losses through adsorption. The surfactant

slug must be designed so that its integrity can be

maintained in the presence of large adsorption
Table B-2

Summary of Surfactant Field Tests Being Conducted by

Industry Without ERDA Assistance

Process Area Porosity Perm. Depth Reservoir Oil Temp. Salinity

Field State County Operator Type* (Acres) Start Pay (%) (Md) (ft) o APl) (Cp) (°F) (ppm) Comment

0.75-40

4.3

0.75-45

10

1-160

0.65

8.23

1

0.8

209

1.25

2.0

2.5

2.5

2.5

S.o

5.8

10.0

2.5

1.7

200

82

69

103

500

52

75

53

*400

2,500

90

457

394

87

93

950

450

1,000 35-36 7 72 HPW 18,150 ppm 6 tests

TDS (1 19-R)

11 /62

5/70

12/68

5/71

11/67

9/70

Robinson 20

18

19

21

22.9

19.2

20

22

21

33

18

21.7

24.2

14.8

17.1

31

26

Robinson Ill. Crawford Marathon MSF

MSF

MSF

MSF

Aqueous

Aqueous

solution

SOF

SF

SF

LTWF

Aqueous

solution

SF

MSF

SF

SF

SF

LTWF

SF

LTWF

SF

Marathon

Pennzoii

Aux Vases

Bradford

3,000

1,860

Ill.

Bingham Pa. McKean 5

4.5

4

68 2,800 Cl –

2 tests

Goodwill Pa. Waxyen 600 40 55

Hill

Benton Ill. Franklin

Quaker St. First Venongo

Shell Tar Springs 2,100 86 77,000 ppm TDS 2 tests

Est.

95

95

114

64,000 Cl –

104,000 TDS

54,000 cl–

7,700 TDS,

20 ppm fractured,

CA+ Mg

Exxon Chester

Cypress

Bluff Creek

Second

Wall Creek

Upper

Cypress

Gunsight

Loudon Ill. 1,460 4

8/69

8/73

11 /73

7/73

4.3

5.6

1,870

3,100

37

34

Higgs Unit Tex. Jones

Big Muddy Wyo. Converse

Union

Conoco

Griffin Ind. Gibson 37

Consol.

Wichita Tex. Wichita

Co. Regular

Borregos Tex. Kleberg

Conoco 2,400

Mobil 1,750 42 2.2 89 160,000 TDS

mid 33,000 TDS

60’s

Exxon Frio 5,000 42 0.4 165

Jackson 20,000 TDS

Kirkwood

Flappen

Cisco

2,270

1,500

1,900

1,200

36

38:39

38

27

1.6

5.5

122

72

Guerra Tex. Star

Bridgeport Ill. Lawrence

Sayles Tex. Jones

Montague Tex. Montague

Loma NoviaTex. Duval

Sun

Marathon

Conoco

Conoco

Mobil

9/69

/63

/63

mid

60’s

4/74

1 /75

6J74

1/75

150,000 TDS

4% kaolinitc

5.5% montmorillonite

40,000cl–

2,457 TDS

60,000Cl –

1,017 Ca++ and Mg++

3.6

0.8

0.7

17

0.85

165

169

60

Texaco

Amoco

Mobil

Texaco

U. Benoist

Muddy J.

41A

Almy

1,750

6,250

5,700

700

38

34

32

26

Salem Ill. Marion

Sloss Nebr. Kimball

West RanchTex. Jackson

La Barge Wyo. Sublette

* Process Type normally refers to specific surfactant floods used, but is not intended to characterize actual differences: Aqueous-dispersion of sulfonate in water with very little

oil in slug; MSF–micellar surfactant flood; SOF–normally considered “oil external” chemical slug; SF and LTWF–surfactint flood and low-tension waterflood normally similar to

aqueous systems.

Source: Enhanced 0// Recovery, National Petroleum Council, December 1976, p. 97.
150 . Appendix B

losses. As a result, larger slugs or higher concentrations may be needed with corresponding

increases in costs.

Permeability, fluid viscosities, well spacing,

and maximum injection pressure affect the rate at

which a chemical slug can displace oil from a

reservoir. Low permeability translates to low displacement rates or increased well density to

maintain a specific rate. Both lead to higher process costs.

The same reasoning applies to crude oil

viscosity. As viscosity increases, displacement

rates decrease or well density increases. Mobility

control in the surfactant/polymer process is attained by increasing the viscosities of the chemical slug and the drive water. Both of these

changes require addition of expensive constituents to these fluids. Therefore both permeability

and viscosity are constrained by economics.

It is known from laboratory tests that oil recovery by the surfactant/polymer process is a function of displacement rate. For example, more oil

is recovered at an average displacement rate of 5

ft per day than at the rate of 1 ft per day19 which

exists in a typical reservoir. Rate effects in field

size patterns may be revealed in the MarathonERDA commercial demonstration test.20

Water Quality .-Composition of the formation

water is a critical variable in the surfactant/polymer process. Fluids under field tests can

tolerate salinities of 10,000 to 20,000 ppm with

moderate concentrations of calcium and magnesium, although reservoirs containing lowsalinity flu ids are preferred. Some field tests are in

progress in which preflushes are used to reduce

salinity to levels which can be tolerated by the

injected chemicals. 21,22 However, in one large

field test23 the inability to attain a satisfactory

preflush was considered to be a major contributor to poor flood performance. Potential shortages of fresh water for preflushing and uncertainty in effectiveness of preflushes have stimulated

research to improve salinity tolerance.

Technological advances were projected in the

NPC study which would increase the salinity

tolerance from 20,000 ppm in 1976 to 150,000

ppm in 1980 and 200,000 ppm in 1995. The OTA

technical screen does not contain a similar

scenario because salinity data were not available

for all the reservoirs in the OTA data base. It does

not appear that results would have been affected

appreciably if the data were available in the data

base to schedule technological advances in

salinity tolerance.

Rock Type. —The surfactant/polymer process

is considered to be applicable to sandstone reservoirs. Carbonate reservoirs are less attractive candidates because 1 ) the formulation of compatible

fluids is more difficult due to interaction with

calcium and magnesium in the rocks; 2) carbonate reservoirs frequently produce through smalland large-fracture systems in which maintenance

of an effective surfactant slug would be difficult;

and 3) there is a consensus among technical personnel that the C02 miscible displacement process is a superior process for carbonate reservoirs.

Reservoir Constraints. —Reservoirs with large

gas caps which could not be waterflooded either

by natural water drive or water injection are likely

to be unacceptable. Also, reservoirs which produce primarily through a fracture system fall in

the same category. However, there is the

possibility of technological developments 24

which would restrict flow in the fracture system

and perm t displacement of the surfactant slug

through the porous matrix.

Oil Recovery Projections

The surfactant/polymer process is applied in a

reservoir which has been previousl y

waterflooded, There are different opinions

among technical personnel concerning the

volume of the reservoir which may be swept by

the process. Some consider that the swept

volume will be less than the volume swept by the

waterflood, while others envision more volume

swept by the surfactant/polymer process. The

reasoning behind these viewpoints is summarized in the following subsections.

Swept Volume Less Than Water flood Sweep.—

Residual oil saturations and volumetric sweep

efficiencies attributed to waterflooding are frequently the result of displacing many pore

volumes of water through the pore space. In contrast, the surfactant/polymer process can be approximated as a 1- to 2-pore volume process
which may lead to a smaller fraction of the reservoir being contacted by the surfactant/polymer

process.

Many reservoirs are heterogeneous. It can be

demonstrated that heterogeneities in the vertical

direction of a reservoir which have relatively

small effect on the sweep efficiency of a

waterflood may have large effects on the sweep

efficiency of the surfactant/polymer process.25

For instance, in a layered reservoir it may not be

possible to inject enough surfactant into all layers

to effectively contact the regions which were

previously waterflooded.

Surfactant/Polynmer Swept Volume Outside of

Waterflood Region.—The region outside of the

volume swept by the waterflood contains a high

oil saturation. in many surfactant processes, the

viscosity of the injected fluids is much higher

than water used in the previous waterflood. This

could lead to increased volumetric sweep efficiency for the surfactant/polymer process.

Davis

26 has presented data from a MarafloodT M

oil recovery process test in the Bradford Third

Sand of Pennsylvania. An increase of 7 to 10 percent in the volumetric sweep efficiency for the

surfactant process over the previous waterflood

was indicated in his interpretation of the data.

OTA Model.-The OTA model is based on the

assumption that the region contacted by the surfactant/polymer process in most reservoirs is the

region swept by the previous waterflood. The

surfactant/polymer process displaces oil from the

previously water-swept region by reducing the

oil saturation following the waterflood (Sorw) to a

lower saturation, termed SOf, which represents

the residual oil saturation after a region is swept

by the surfactant/polymter process. The oil recovery using this representation of the process was

computed using equation 1 B for each pattern

area,

B.

where

N pc

= oil displaced by

stock-tank barrels

Ap = area of the pattern

r- N (s

the chemical flood,

Appendix B . 151

h = net thickness of pay

9 = porosity, the fraction of the rock volume

which is pore space

E vm = fraction of the reservoir volume which

was contacted by water and surfactant/polymer process determined by

material balance calculations

BO = ratio of the volume of oil at reservoir

temperature and pressure to the volume

of the oil recovered at stock-tank conditions (60° F, atmospheric pressure)

Residual oil saturations left by the chemical

flood (SOf ranging from 0.05 to 0.15 have been

reported in laboratory 27,28 and field tests. 29 A

value of 0.08 was selected for the OTA computations.

The residual oiI saturation following

waterflood (SOrw for the high-process performance case was the oil saturation corresponding to

the particular geographic region in table A-1

modified by the material balance calculation as

described in appendix A, in the section on Distribution of (the Remaining Oil Resource on page

139. In the low-process performance model, the

residual oil saturations following waterflood

(SORW) were reduced by 5 saturation percent from

the values in table A-1. This caused a decrease in

recoverable oil which averaged 28.6 percent for

all surfactant/polymer reservoirs. Due to the

method of analysis, the process performance of a

small number of reservoirs was not affected by

this saturation change. Some reservoirs which

had 90-percent volumetric sweep imposed by

the material balance discussed on page 139 for

the high-process performance case also had 90-

percent volumetric sweep efficiency under lowprocess performance.

Pattern Area and Injection Rate.—Each reservoir was developed by subdividing the reservoir

area into five-spot patterns with equal areas. The

size of a pattern was determined using the procedure developed in the NPC study.30 A pattern

life of 7 years was selected. Then, the pattern

area and injection rates were chosen so that 1.S

swept-pore volumes of fluids could be injected

into the pattern over the period of 7 years. The

relationship between pattern area and the injection rate is defined by equation 2B.
—.

152 . Appendix B

injection rate, barrels per day

porosity

thickness, feet

pattern area, acres

Maximum pattern area was limited to 40 acres.

Injection rates were constrained by two conditions. In Texas, California, and Louisiana, it was

assumed that maximum rates were limited by

well-bore hydraulics to 1,000 barrels per day,

1,500 barrels per day, and 2,000 barrels per day,

respectively. Rate constraints in the reservoir

were also computed from the steady-state equation for single-phase flow in a five-spot pattern

given in equation 3B. The viscosity of the surfactant/polymer slug was assumed to be 20 times

the viscosity of water at formation temperature.

The lowest injection rate was selected. other

parameters are identified after the definition of

the equation.

completion of wells and installation of surface

facilities were done in the first 2 years. The surfactant slug was injected during the third year

with the polymer injected as a tapered slug from

years 4 through 6. The oil displaced by the surfactant/polymer process as computed from equation IB was produced in years 5 through 9

according to the schedule in table B-3.

Table B-3

Development of a Five-Spot Pattern

Surfactant/Polymer Process

Year of Annual oil production

pattern % of

development Activity incremental recovery

1

2

3

4

5

6

3B

where

i = injection rate, barrels per day

k = average permeability, millidarcies

h = average thickness, feet

AP = pressure drop from injection to producing well, taken to equal depth/2

μeff = effective viscosity of surfactant/polymer

slug, or 20 times viscosity of water at

reservoir temperature

In = natural logarithm

d = distance between the injection and production well, feet, or 147.58 ~~

A P = pattern area, acres

RW = radius of the well bore

Development of Pattern.-Development of

each five-spot pattern took place according to

the schedule shown in table B-3. Drilling and

7

8

9

Drill and complete

injection wells. Rework production

well.

Install surfac e

equipment.

Inject surfactant

slug.

Inject polymer slug

with average concentration of 600

ppm. Polymer concentratio n

tapered.

Injection of brine.

o

0

0

0

10

26

32

20

12

Total . . . . . . . 100

Volumes of Injected Materials.—

Current technology

Surfactant Slug, . . 0.1 swept pore volume*

Polymer Bank. . . . 1.0 swept pore volume

Advancing technology case

Surfactant Slug. . . 0.1 swept pore volume

Polymer Bank, . . . 0.5 swept pore volume

● The swept pore volume of a pattern is defined by equation 4B.
V p 

=

Ev~ AP h o (7,758) 4B

= volume of pattern swept by

the surfactant/polymer process, barrels

The volumes of surfactant and polymer approximate quantities which are being used in field

tests. Volume of the surfactant slug needed to

sweep the pattern is affected by adsorption of

surfactant on the reservoir rock. The slug of 0.1

swept-pore volume contains about 36 percent

more sulfonate than needed to compensate for

loss of surfactant that would occur in a reservoir

rock with porosity of 25 percent and a surfactant

retention of 0.4 mg per gm rock. The OTA data

base contained insufficient information to consider differences in adsorption in individual reservoirs. The effect of higher retention (and thus

higher chemical costs) than assumed in the advanced technology cases is examined in the highchemical cost sensitivity runs.

Composition and Costs of Injected Materials

The surfactant slug for all cases except the current technology case contained 5-wt percent

petroleum sulfonate (100-percent active), 1-wt

percent alcohol, and 10-volume percent lease

crude oil. In the current technology case, the surfactant slug contained 20 percent lease crude oil.

The concentration of the polymer solution was

600 ppm for reservoir oils with viscosities less

than or equal to 10 centipoise. Concentration of

polymer was increased with viscosity for oils

above 10 centipoise according to the multiplier

given in equation 5B.

Concentration Multiplier =(1 +

32- API

) 5B

10

Equation 5B is valid for API gravities greater than

10. A polysaccharide polymer was used.

Table B-4 summarizes surfactant slug and

polymer costs as a function of oil price. Costs of

surfactant and alcohol based on data from the

NPC study are presented in table B-5.

Net Oil, -Projected oil recovery from the surfactant/polymer process was reported as net barrels. The oil used in the surfactant slug and an

Appendix B ● 153

estimate of the oil equivalent to the surfactant

was deducted from the gross oil

production.

Table B-4

Chemical Coats

Surfactant

slug cost -

10-percent

Oil price lease crude

$/bbl $/bbl

10 . . . . . . . . 7.69

15 . . . . . . . . 9.73

20 . . . . . . . . 11.74

25 . . . . . . . . 13.78

to determine net

Surfactant

slug cost -

20-percent

lease crude

$/bbl

8.69

11.23

13.74

16.28

‘Polymer cost*

polysaccharide

$/lb

2.30

2.40

2.49

2.58

● Source: Enhanced Oil Recovery, National Petroleum Council,

December 1976, p. 100.

Table B-5

Component Costs*

Surfactant cost

Oil price 100-percent active Alcohol cost

$/bbl $/lb $/lb

5 . . . . . . . . 0.29 0.13

10 ....., . . 0.35 0.16

15 . . . . . . . . 0.43 0.20

20 . . . . . . . . 0.51 0.23

25 . . . . . . . . 0.59 0.27

*Includlng tax and transportation.

Source: Enhanced 011 Recovery,

December 1976, p. 99.

National Petroleum Council,

Sensitivity Analyses

Additional computations were made using the

low- and high-process performance models to

determine sensitivity to changes in chemical

costs. Cost sensitivity analysis was accomplished

by altering the volumes of surfactant and

polymer used in the displacement process. The

low-chemical cost case assumes a 40 percent

reduction in the volume of the surfactant slug

while the high-chemical cost case assumes that

40 percent more surfactant and 50 percent more

polymer would be required than used in the

base-chemical cost case.
154 . Appendix B

Ultimate recoveries of oil using the surfactant/poIymer process with high- and low-chemical cost assumptions are summarized in table B-6

for the advancing technology cases. With high

chemical costs, there would be a negligible

volume of oil produced at world oil price. The

combination of both high-process performance

and oil prices approaching the alternate fuels

price would be needed to offset high chemical

costs if the surfactant/polymer process is to contribute substantial volumes of oil to the Nation’s

reserves.

Low chemical costs have the largest impact on

the low-process performance case where substantial increases in ultimate recovery could occur at both upper tier and world oil price. The

effect of lower chemical costs on the high-process performance case is to reduce the oil price required to call forth a fairly constant level of production. For example, if chemical costs are low,

the ultimate recovery projected at alternate fuels

price is about the same as ultimate recovery at

upper tier price. However, low chemical costs

have a low probability of occurring unless a major technological breakthrough occurs.

The sensitivity analyses in this study were

designed to bracket the extremes which might be

expected assuming technology develops as

postulated in the advancing technology cases.

There are other process and economic variables

which would be

individual field

considered in the analysis of an

project which could not be

analyzed in a study of this magnitude.

Polymer Flooding

State of the Art—Technological Assessment

The concept of mobility control and its relationship to the sweep efficiency of a waterflood

evolved in the early to mid-1950’s.31,32 It was

found that the sweep efficiency could be improved if the viscosity of the injected water

could be increased. Thickening agents were actively sought. Numerous chemicals were evaluated but none which had economic potential

were found until the early 1960’s.

During this period, development in the field

of polymer chemistry provided new molecules

which had unique properties. High-molecular

weight polymers were developed which increased the apparent viscosity of water by factors

of 10 to 100 when as little as 0.1 percent (by

weight) was dissolved in the water. The first

polymers investigated were partially hydrolyzed

polyacrylamides with average molecular weight

ranging from 3 million to 10 million.

The discovery of a potential low-cost method

to “slow down” the flow of water and improve

sweep efficiency of the waterflood led to many

field tests in the 1960’s. Nearly all field tests used

Tabie B-6

Surfactant/Polymer Process-Uitimate Recovery

Summary of Computed Results-Process and Economic Variations

(billions of barrels)

Advancing technology cases

Oil price $/bbl

Case Low-process performance High-process performance

11.62 13.75 22.00 11.62 13.75 22.00

High chemical costs . . . . . . . . . 0.1 0.1 1.0 0.2 0.2 9,0

Base chemical costs . . . . . . . . . 1.0 2.3 7.1 7.2 10.0 12.2

Low chemical costs . . . . . . . . . 5,8 7.5 8.8 12.0 12.4 14.5
Appendix B• 155

partially hydrolyzed polyacrylamides. By 1970 at

least 61 field tests had been initiated33 and by

1975 the number of polymer field tests exceeded

100. Although most field tests were relatively

small, two were substantial. These were the Pembina test in the Pembina Field in Alberta and the

Wilmington test in the Ranger V interval of the

Wilmington Field in California.

Results of field tests have been mixed. Successful use of polymers has been reported in

several projects 3536 where incremental oil

above that expected from waterflooding has

been produced. At least 2 million barrels of oil

have been attributed to polymer flooding from

successful projects. 37 Continuation of some projects and expansion of others indicate commercial

operation is possible. However, polymer flooding

has not been widely adopted. Many field tests

yielded marginal volumes of oil. Response to

polymer flooding was not significant in either the

Pembina Flood or the Wilmington Flood.

Reasons for mixed field performance are not

completely understood. polymer floods initiated

early in the life of a waterflood are more likely to

be successful than those initiated toward the end

of a project. Reservoirs which have been

waterflooded to their economic limit have not

responded to polymer flooding as a tertiary process. Recent research 38 has demonstrated that partially hydrolyzed polyacrylamides degrade when

sheared under conditions which may be present

in injection well bores. Thus, it is not certain in

previous field tests that a reservoir flooded with

polymer solution was contacted with the same

fluid used in laboratory tests.

Further research and development produced a

polysaccharide biopolymer 39 which has improved properties. Polysaccharides are relatively

insensitive to mechanical shear and have high

tolerance to salt, calcium, and magnesium ions.

Solutions containing polysaccharides must be

filtered prior to injection to remove bacterial

debris which may plug the injection wells. Since

the polysaccharide is a product of a biological

process, it is susceptible to further biological attack in the reservoir unless adequate biocide is

included in the injected solution. Few field tests

have been conducted using polysaccharide

polymers.

polymer flooding has economic potential

because it uses materials which are relatively low

cost. Field application is similar to waterflooding

with minor changes to permit mixing and proper

handling of the polymer solutions. Widespread

use by most operators would be possible without

extensive technical support. Performance of

polymer floods cannot be predicted accurately,

and well-documented demonstration projects

such as those being conducted in the N. Burbank

Stanley Stringer40 and the Coalinga41 fields are essential to the widespread use of polymer flooding.

Screening Criteria. --Polymer flooding is not a

potential process for all reservoirs which can be

waterflooded. Geologic constraints, properties of

the reservoir rock and oil, and stage of the

waterflood are all critical parameters. Reservoirs

which produce primarily through large fracture

systems and reservoirs with large gas caps which

could not be waterflooded were excluded. In

these reservoirs, the polymer slug is likely to

bypass much of the reservoir rock. A permeability

constraint of 20 millidarcies was selected. While

the lower limit of permeability is not known precisely, there is a range of permeabilities where

the polymer molecules are filtered out of the injected solution and cannot be propagated

through a reservoir. Selection of the correct

molecular weight distribution of the polymer

reduces the minimum permeability.

Field experience indicates that polymer floods

have not been successful when applied after the

waterflood has been completed. Reservoirs under

waterflood which have volumetric sweep efficiency greater than 80 percent and low residual

oil saturations are not good polymer candidates.

Consequently, reservoirs with no ongoing

waterflood and reservoirs with high volumetric

sweep efficiency and low oil saturation were

screened from the polymer flooding candidates.

Water quality was not used to screen reservoirs because salinity and divalent ion content do

not determine whether a reservoir can be flooded

with polymer solutions. These parameters do indicate the type of polymer which may be used.

For example, partially hydrolyzed polyacrylamides are frequently preferred in lowsalinity systems. Polysaccharides are relatively in-
-— ——. —

156 . Appendix B

sensitive to salinity and may be required in order

to flood successfully a reservoir which contains

high-salinity fluids.

The use of polymers is limited by temperature

stability. Proven temperature stability is about

200° F. This limit is expected to be 250° F by

1995. The same temperature limits used in the

surfactant/polymer process screen apply to

polymer flooding.

Crude oil viscosity was the final screening

parameter. Field tests suggest an upper limit of

about 200 centipoise. However, there is little

published literature which shows that polymer

solutions will not displace oil at higher

viscosities. Other factors enter in the determination of the upper viscosity limit. Steam displacement and in situ combustion are considered

superior processes because both can potentially

recover more oil. As crude oil viscosity increases,

higher polymer concentrations are required to

maintain mobility control. Oil-displacement rates

decline for a fixed pattern size. Both of these factors operate in the direction of reducing the rate

of return at fixed oil price or requiring a higher oil

price to produce a fixed rate of return. Then the

crude oil viscosity becomes an economic factor

rather than a technical factor.

Most reservoirs which were polymer candidates yielded more oil when developed as C02

,

surfactant/polymer, steam, or in situ combustion

candidates. Thus, the OTA method of process

selection, i.e., maximum oil if profitable at 10

percent rate of return and world oil price, led to

assignment of the poorest reservoirs to polymer

flooding.

Oil Recovery Projections

Estimates of oil recovery from the application

of polymer-augmented waterflooding to reservoirs which satisfied the technical screen were

made using an empirical model. Incremental

recovery for the low-process performance case

was assumed to be 2.5 percent of the original oil

in place. The incremental recovery for the highprocess performance case was assumed to be 3

percent of the original oil in place. These estimates closely approximate recent projections for

the N. Burbank Stanley Stringer and Coalinga field

demonstration tests. They also approximate the

average performance of published field tests.42

Each reservoir was developed on 40-acre spacing with a ratio of 0.5 injection well per production well. Injection of polymer was continued

over the first 4 years of the project at a rate of

0.05 pore volumes per year. Average polymer

concentration was 250 ppm. The polymer used

was polysaccharide. Costs of polymer at various

oil prices were identical to those used for the surfactant/polymer process (table B-4).

The recoverable oil was produced over an 11-

year period according to the schedule in table

B-7.

Table B-7

Production Schedule

for Polymer-Augmented Waterflood

Incremental oil

Year percent of total

1-2 . . . . . . . . . . . . . . . . . . . . . . .

3 . . . . . . . . . . . . . . . . . . . . . . . .

4 . . . . . . . . . . . . . . . . . . . . . . . .

5 . . . . . . . . . . . . . . . . . . . . . . . .

o

5

10

20

20

15

10

10

5

5

Total. . . . . . . . . ., . . . . . . . 100

Sensitivity Analyses

The effects of changes in polymer costs and/or

volumes were examined for low- and highpolymer costs for both low- and high-process

performance cases. Bases for cost variation were

+/- 25 percent change in polymer cost. Results of

the economic evaluations are presented in table

B-8.

There is essentially no effect of chemical costs

on oil production from polymer flooding at the

upper tier, world oil, and alternate fuels prices.

The sensitivity analyses show that uncertainty in

process performance is larger than uncertainties

introduced by chemical costs.
Appendix B . 757

Table B-8

Polymer-Augmented Waterflooding

Ultimate Recovery

(billions of barrels)

Case

High polymer cost

(+25°/0 over base) . . . . . . . . . . . . .

Base polymer cost. . . . . . . . . . . . .

Low chemical cost

(-25°/0 from base). . . . . . . . . . . . .

Advancing technology cases

oil price $/bbl

Low-process performance

11.62

0.2

0.2

0.3

13.75

0.2

0.3

0.3

22.00

0.3

0.3

0.3

High-process performance

11.62

0.4

0.4

0.4

13.75

0.4

0.4

0.4

22.00

0.4

0.4

0.4

Effect of Polymer Flooding on Subsequent

Application of Surfactant/Polymer or Carbon

Dioxide Miscible Processes

The OTA analysis assumes a single process

would be applied to a reservoir. The possibility

of sequential application of two processes was

not analyzed. Some reservoirs assigned to the

surfactant/polymer process or the C02 miscible

process would also be economic (rate of return

greater than 10 percent at world oil price) as

polymer floods. However, the decision rules for

process assignment placed these reservoirs in the

process which yielded the largest ultimate recovery.

One concern caused by this assignment procedure was whether or not the low costs and low financial risk from the polymer projections would

cause operators to use polymerflooding as the final

recovery process for a reservoir, precluding use of

methods which potentially recover more oil.

The principal displacement mechanism in

polymer flooding is an increase in the volume of

the reservoir which is swept by the injected fluid.

No reduction in residual oil saturation over that

expected from waterflooding is anticipated

because the viscosities of the oils in these reservoirs are low enough to make the residual oil

saturations relatively insensitive to the viscosity

of the displacing fluid.

A successful polymer flood in the OTA highprocess performance would recover 3 percent of

the original oil in place. This corresponds roughly

to improved volumetric sweep efficiencies of 2

to 7 percent. Both OTA models for surfactant/polymer and CO2 miscible processes are

based on recovery of the residual oil from some

percentage of the volume displaced by the preceding waterflood. Polymer flooding increases

this contacted volume. Slightly more oil would

be recovered from reservoirs which had been

polymer flooded prior to surfactant flooding or

C 02 flooding if the OTA models of these displacement processes are substantially correct.

Therefore, the application of polymer flooding

will not prevent subsequent surfactant/polymer

or C02 floods under the conditions postulated in

the OTA study.

Finally, polymer flooding prior to surfactant/polymer flooding has been proposed as a

method to improve volumetric sweep efficiency

by increasing the flow resistance in more permeable paths in the reservoir.43

Steam Displacement

State of the Art—Technological Assessment

Steam displacement is a process which has primarily evolved in the last 10 to 15 years.
158 . Appendix B

Development of the process was motivated by

poor recovery efficiency of waterfloods in reservoirs containing viscous oil and by low producing

rates in fields which were producing by primary

energy sources. Most of the development occurred in California and Venezuela, where large

volumes of heavy oil are located. Steam displacement has potential application in heavy oil reservoirs in other oil-producing States.

Large-scale field tests of steam injection began

in the late 1950's 44,45 with field testing of hot

water injection underway at the same time46,47,48

in an attempt to improve the recovery efficiency

of the conventional waterflood. Early steam and

hot water injection tests were not successful. injected fluids quickly broke through into the producing wells, resulting in low producing rates and

circulation of large volumes of heated fluids.

The process of cyclic steam injection was discovered accidentally in Venezuela in 19s9 and

was developed in California. 49 Cyclic injection of

small volumes of steam into producing wells

resulted in dramatic increases in oil production,

particularly in California where incremental oil

due to cyclic steam injection was about 130,000

barrels per day in 1968.50 By 1971 about 53 percent of all wells in California had been steamed

at least once.

Cyclic steam injection demonstrated that significant increases in production rate could be obtained by heating the reservoirs in the vicinity of

a producing well. However, the process is primarily a stimulation process because natural

reservoir energy sources like solution-gas drive or

gravity drainage cause the oil to move from the

reservoir to the producing well, Depletion of this

natural reservoir energy with repeated application of cyclic steam injection will diminish the

number of cyclic steam projects. Many of these

projects will be converted to steam displacement.

The success of the steam displacement process is due to the high displacement efficiency of

steam and the evolution of methods to heat a

reservoir using steam. Development of the steam

displacement process in the United States can be

traced to large-scale projects which began in the

Yorba Linda Field in 196051 and the Kern River

Field in 1964.52 Estimates of ultimate recoveries

(primary, secondary, cyclic steam, and steam displacement) from 30 to 55 percent of the original

oil in place have been reported for several fields.

A comparison 53 of trends in incremental oil

production from cyclic steam and steam injection

for California is shown in figure B-1. Cyclic steam

injection is expected to decline in importance as

natural reservoir energy is depleted. Production

from steam displacement could increase as cyclic

projects are converted to continuous steam injection. The rate of conversion will be controlled by

environmental constraints imposed on exhaust

emissions from steam generators. Incremental oil

from steam displacement will be limited to

110,000 barrels per day in California, the level

which currently exists, unless technological advances occur to reduce emissions.

Commercial steam-displacement projects are

also in operation in Wyoming,54 Arkansas, 55 and

Texas.

56 A large portion of the incremental oil

now produced by application of EOR processes is

produced by the steam displacement process.

Screen/rig Criteria.—Steam displacement was

considered applicable in reservoirs which were

located at depths between 500 and 5,000 feet.

The upper depth limitation was imposed in order

to maintain sufficient steam injection pressure.

The lower depth of 5,000 feet is determined by

well-bore heat losses in the injection wells. At

depths approaching 5,000 feet, heat losses can

become excessive even with insulated injection

strings. In addition, as depth increases the injection pressure increases, but the fraction of the injected fluid which is condensable decreases.

Reduction in displacement efficiencies is expected to occur under these conditions.

The second screening criterion was

transmissibiIity. The transmissibility (permeability x thickness/oil viscosity) is a measure

of the rate that the oil moves through a reservoir

rock. A transmissibility of about 100 millidarcy

feet/centipoise is required for steam and hotwater injection processes in order to keep heat

losses from the reservoir to overlying and underlying formations from becoming excessive. ST

Oil Recovery Projections

Recovery Models.—Although steam displacement is the most advanced EOR process, it was
Appendix B . 159

Figure B-1. Historical Incremental Production Thermal Recovery-California

1968 1970

difficult to develop recovery models which applied to an entire reservoir. The OTA data base as

well as the Lewin data bases used in the NPC and

ERDA reports contained little information on

reservoir variability. Review of the technical

literature and personal contacts with companies

operating in fields with major steam displacement projects revealed considerable variability in

thickness and oil saturation. It became apparent

that most steam displacement projects were

being conducted in the best zones of a reservoir,

where oil saturations were higher than the

average values in the data base. Thus, OTA concluded that empirical recovery models based on

the results of these displacement tests could not

be extrapolated to poorer sections of larger reservoirs with the available information. Subdivision

of several large reservoirs into smaller segments

of different properties as done in the NPC study

was considered, but could not be done with the

available computer program.

Recovery models were developed by OTA to

estimate the recovery based on development of

the entire reservoir. In taking this approach, it is

--— 1972 1974 1976

Acknowledged that recovery from the better sec--

tions of a reservoir will be understated and the

recovery from poorer sections will be overstated.

However, this approach was preferable to overstatement of recovery caused by applying empirical recovery models from the better zones 58 to

other intervals and areas of a reservoir, or application of recovery adjustment factors to extrapolate single-pattern performance to totalproject performance. 59

Each reservoir with multiple zones was

developed zone by zone. The technology necessary to complete each zone selectively was

assumed to evolve through research and

development. The average thickness per zone

was determined by dividing the net thickness by

the number of zones. Two displacement models

were used based on the thickness of the zone.

Single zone reservoirs were handled in the same

way-according to thickness of the zone.

High-Process Performance Case.—Zone Thickness Less Than or Equal to 75 Feet. -Gross oil

recoverable by primary and secondary production followed by steam was considered to be 50
160 . Appendix B

percent of the original oil in place. Thus in each Zone Thickness Greater Than 75 Feet. –Oil

zone, displacement in thick reservoirs is based on the

Steam Displacement Oil = Original Oil – (Primary + following model of the displacement process.

2 Secondary) Steam displacement patterns were developed

on 2.5-acre spacing with one injection well per

producing well.

Maximum vertical

Areal sweep thickness of Residual oil

Region efficiency swept zone, feet saturation

Steam Zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.75 25 0.10

Hot Water Zone . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.90 35 0.25

Low-Process Performance Case. —Well spacing

was increased to 5 acres. Gross oil displaced by

steam was 80 percent of the amount estimated

for the high-process performance case.

Timing of Production. —The incremental oil

from the steam-displacement process was produced according to the production schedule in

table B-9.

Table B-9

Production Schedule for

Steam Displacement Process

Annual

incremental oil

Year percentage total

1-2 . . . . . . . . . . . . . . . . . ~ ~ ~ ~€ . 0

3 . . . . . . . . . . . . . . . . . . . . . . . . 12

4 . . . . . . . . . . . . . . . . 22

5 : : : : : : : : . . . . . . . . . . . . . . . . 22

6 . . . . . . . . . . . . . . . . . . . . . . . . 20

7 . . . . . . . . . . . . . . . . . . . . . . . . 14

8 . . . . . . . . . . . . . . . . . . . . . . . . 10

Total . . . . . . . . . . . . . . . . . . 100

The same schedule was used for low- and

high-process performance models.

Steam Requirements and Costs

Steam requirement was 1 pore volume based

on net heated thickness. That is the volume occupied by the combined steam and hot water

zones considering the areal sweep efficiency to

be 100 percent. Zones with thicknesses less than

or equal to 75 feet were assumed to be heated in

the entire vertical cross section. Steam was injected over a 5-year period beginning in the third

year of field development at the rate of 0.2 pore

volume per year.

Lease crude was used as fuel for the steam

generators. Twelve barrels of steam were produced per barrel of lease crude consumed. The

full cost of the lease crude was charged as an

operating cost to the project. Oil consumed as

fuel was deducted from the gross production to

obtain the net production. Cost of steam generation in addition to the fuel charge was $0.08 per

barrel of steam generated to cover incremental

operating and maintenance costs for the generator and water treatment.

Other Costs. —The costs of installed steam

generation equipment were scaled from a 50

million Btu per hour steam generator costing

$300,000.

60 A 1 million Btu per hour unit was

assumed to generate 20,000 barrels of steam

(water equivalent) per year. The number (possibly fractional) of generators required per pattern

was determined from the pore volume of the pattern. Since the steam generator life was longer

than pattern life, it was possible to use the same

generator on two patterns in the field. The cost of

moving a generator was assumed to be 30 percent of the initial cost. Thus the effective cost for

the steam generator per pattern was 65 percent

of the initial generator cost.

Reservoirs with multiple zones required

workovers in production and, injection wells to

close the zone just steamed and open the next

zone. These costs are discussed in the section on

Economic Data—General on page 178 of this appendix.
Case

Low recovery . . . . . . . . ... . . .

High-process performance ...

High recovery. . . . . . . . . . . . . . . .

Appendix Be 161

Table B-10

Recovery Uncertainties Effecting Steam Displacement Results

Production well

spacing, acres

2.5

2.5

2.5

Recovery Modela

Zone thickness

<75 ft.

Gross recovery

(primary, secondary

and steam

displacement) as

fraction of original

oil in place

0.45

0.50

0.55

Zone thickness

>

Maximum

steam zone

thickness

25

25

30

75 ft.

Maximum

hot water zone

thickness

30

35

35

aAll other ~Odel parameters were the same as in the high-process Performance case

Sensitivity Analyses These extremes in recovery performance are

Projections of oil recovery by steam displacement contain uncertainties which are primarily

related to the recovery efficiency of the process.

Additional analyses were made to determine the

range of variation in oil recovery due to uncertainties in process performance (table B-10).

One set of projections was based on variations

of recovery for a well spacing of 2.5 acres p e r

production well. Projections for low recovery (45

percent) and high recovery (55 percent) are compared with the high-process performance case

(50 percent recovery) in table B-11. Results from

the low recovery case are essentially the same as

the low-process performance case. The projections from the high recovery case are appreciably higher than the high-process performance

case.

Table B-n

Effect of Uncertainties in Overall

Recovery on Ultimate Production

Steam Displacement Process

(billions of barrels)

Upper World Alternate

tier oil fuels

Case price price price

($1 1.62/ ($1 3.75/ ($22.00/

bbl) bbl) bbl)

Low recovery . . . . . . . 2.1 2.5 3.4

High-process

performanc e 2.8 3.3 6.0

High recovery. . . . . . . 3.9 5.9 8.8

also measures of energy efficiency. Crude oil is

burned to produce steam. The amount of crude

consumed is proportional to the volume of steam

required to heat the reservoir. Nearly the same

volume of steam and consequently the same

amount of lease crude is consumed for each of

the three cases. Slight variations occur for zones

with thicknesses greater than 75 feet, Most of the

additional oil projected in the high recovery case

is produced with little additional lease crude required for steam generation. In contrast, a larger

fraction of the produced oil is consumed in the

low recovery case because about the same

amount of crude is consumed to produce steam

while a smaller amount of oil is produced by the

displacement process.

Pattern size is the second variable which was

investigated in sensitivity calculations. Oil recovery was estimated for two additional well spacings using the high-process performance model.

Results are summarized in table B-12. If recovery

is unaffected by well spacing, there is an

economic incentive to increase well spacing over

the 2.5-acre spacing used in the OTA study.

Results are sensitive to spacing primarily because

the costs to work over both injection and production wells in order to move from zone to zone

are significant.

Increasing well spacing reduces these costs in

producing wells by a margin which permits

several large reservoirs to meet the 10-percent

CJb-sn 4 (3 - 7 H - 12
162 . Appendix B

Table B-12

Effect of Well Spacing on Ultimate Recovery of

Oil Using the Steam Displacement Process

Incremental 011

(billions of barrels)

Production Upper tier World oil Alternate fuels

well spacing price price price

Case acres ($11.62/bbl) ($1 3.75/bbl) ($22.00/bbl)

High-process performance . . . . . . . . . . . . 2.5 2.8 3.3 6.0

High-process performance ., . . . . . . ., 3.3 3.5 5.3 6.8

High-process performance . ... . 5.0 5.6 6.4 7.0

rate-of-return criteria at lower prices. This is a potential area for technological advances beyond

those which were assumed in this study.

In Situ Combustion

State of the Art—Technological Assessment

In situ combustion has been investigated in

the united States since 1948 .

61 By th e

mid-1950’s, two pilot tests had been conducted.

One test was done in a reservoir containing a

light oil (35° API) with a low viscosity (6 cp).62

The second reservoir tested contained 18.4° API

oil which had a viscosity of 5,000 cp.63 These initial pilot tests demonstrated that a combustion

front could be initiated and propagated in oil

reservoirs over a wide range of crude oil properties.

The initial demonstrations of the technical

feasibility of in situ combustion stimulated

research and development of the process both in

the laboratory and in the field. Over 100 field

tests of in situ combustion have been conducted

in the United States.64

Field testing developed considerable technology. Methods were developed to initiate

combustion, control production from hot wells,

and treat the emulsions produced in the process.

Improved process efficiency evolved with

research and field testing of methods to inject air

and water simultaneously.65,66 The wet combustion process was found to have the potential of

reducing the air requirements by as much as 30 to

so percent over dry combustion.

Many field tests have been conducted but few

have resulted in projects which are commercially

successful. Economic information was not available on current in situ combustion projects. Continued operation over a several-year period with

fieldwide expansion implies satisfactory

economics. California fields include the Moco

Unit in the Midway Sunset. 67 West Newport, 68

San Ardo, South Belridge, Lost Hills, and BreaOlinda. 69 Successful operations have also been

reported in the Glen Hummel, Gloriana, and Trix

Liz Fields in Texas,70 and the Bellevue Field in

Louisiana. 71 The number of commercial operations in the United States is estimated to be 10.72

In situ combustion has not been applied

widely because of marginal economics at existing

oil prices, poor volumetric sweep efficiency in

some reservoirs, and competition with steam displacement processes. Some field tests showed a

net operating gain but could not generate

enough income to return the large investment required for an air compressor. The phrase “a technical success but an economic failure” best

describes many projects.

The movement of the in situ combustion zone

through a reservoir is controlled in part by variations in reservoir properties. Directional movement has been observed in most in situ combustion projects. There has been limited success in

controlling the volume of the reservoir which is

swept by the process. This is a major area for

research and development.

Reservoirs which are candidates for steam displacement are also candidates for in situ combustion. Experience indicates that steam displacement is generally a superior process from the

viewpoint of oil recovery, simplicity of operation, and economics. Thus, applications of in situ
combustion have been limited by the development of the steam displacement process.

In situ combustion has one unique characteristic. It is the only process which may be applicable over a wide range of crude gravities and

viscosities.

Screening Criteria.--In situ combustion is applicable to a wide range of oil gravities and

viscosities. No constraints were placed on oil

viscosity. The maximum permissible API gravity

is determined by the capability of a particular

reservoir rock/crude oil combination to deposit

enough coke to sustain combustion. Low-gravity

oils which are composed of relatively large fractions of asphaltic-type components meet this requirement. It is also known that some minerals

catalyze in situ combustion, allowing high gravity

oils to become candidates for in situ combustion. 73 The maximum oiI gravity which might be a

candidate with catalytic effects was estimated to

be 45° API.

Minimum reservoir depth was set at 500 feet.74

Adequate reservoir transmissibility, i.e.,

Permeabilitv x thickness

oil viscosity

is necessary to prevent excessive heat losses to

overlying and underlying formations. The

minimum acceptable transmissibility for in situ

combustio n is about 20 miIIidarcy

feet/centipoise. 75 Carbonate reservoirs were not

considered to be candidates for in situ combustion.

Oil Recovery Projections

The wet combustion process was used for the

OTA study. All projects were developed as 20-

Appendix B . 163

acre patterns. In the wet combustion process,

three distinct displacement zones are formed: a

burned zone, a steam zone, and a hot water

zone. Gross oiI recovered from each pattern was

computed from the sum of the volumes displaced from each zone. Areal sweep efficiency,

maximum zone thickness, and residual oil saturation for each zone are included in table B-13 for

the advancing technology cases.

Fuel consumption was 200 barrels per acre

foot. 76 The equivalent oil saturation consumed in

the burned zone is Sob, where Sob = 200/7,758 X

0); @ is the porosity of the rock, and 7,758 is barrels per acre foot.

The initial oil saturation was S,,,, the material

balance average oil saturation computed from

equation 1. The volume of oil displaced was

determined in the following manner. The actual

thickness of each zone was determined by

allocating the net pay between the three zones in

the order shown in table B-13. A reservoir 20 feet

thick would have a burned zone and a steam

zone while a reservoir 100 feet thick would experience the effects of three zones in a 50-foot

interval. The volume of oil displaced from each

zone was computed from the product of the pattern area, areal sweep efficiency, zone thickness,

porosity, and displaceable oil in the swept interval. All oil displaced from the swept zones was

considered captured by the producing well.

Timing of Production.—The life of each pattern was 8 years. Drilling, completion, and other

development was completed in the first 2 years.

Air and water injection began in year 3 and continued through year 8 for a total productive life of

6 years. The displaced oil was produced according to the schedule in table B-14.

Table B-13

Advancing Technology Cases

Oil Displacement Model

Wet Combustion

Areal sweep

Region efficiency

Burned zone ... . . 0.55

Steam zone. . , 0.60

Hot water zon e 0 8 0

I Residual

oil saturation

Max. vertical Low-process High-process

thickness, ft. performance performance

10 0 0

10 (),20 0.15

30 0.30 0.25
164 . Appendix B

Table B-14

Production Schedule

Wet Combustion

Annual production of

incremental oil

Year Percentage of total

1 - 2, . . . . . . . . . . . . . . . . . . . . o

3 . . . . . . . . . . . . . . . . . 10

4: : ::::. . . . . . . . . . . . . . . . . 16

5........,............. , 22

6... . . . . . . . . . . . . . . . . . . . . 20

7 18

8:::::::::::::::::::::: : 14

Total . . . . . . . . . . . . . . . . 100

Operating Costs

Air required was computed on the basis of

110-acre feet burned per 20-acre pattern (if the

reservoir is at least 10 feet thick) and a fuel consumption of 200 barrels per acre foot. If the

air/oil ratio was less than 7,500 standard cubic

feet (Scf) per stock-tank barrel (STB), air requirements were increased to yield 7,500. Air requirements were then used to size compressors

and to determine the equivalent amount of oil

which would be consumed as compressor fuel.

The amount of oil used to fuel the compressors was computed as a Btu equivalent based

on 10,000 Btu per horsepower hour. Energy content of the oil was 6,3 million Btu per barrel. This

oil was deducted from the gross production.

The corresponding equations for the price of

air as the price per thousand standard cubic feet

($/MScf) were derived from data used in the NPC

study. 77

Depth Cost Equation

feet $/MScf

O - 2,500 0.08 + 0.01108 P

2,500- 5,000 0.08 + 0.01299 P

5,000-10,000 0.08 + 0.01863 P

10,000-15,000 0.08 + 0.02051 P

where

P = oil price in $/bbl and the multiplier of P is

the barrels of oil consumed to compress 1

MScf of air to the pressure needed to inject into a reservoir at the specified

depth.

Compressed air was supplied by a six-stage

bank of compressors with 1 horsepower providing 2.0 MScf per day.78 Compressor costs were

computed on the basis of $40()/installed horsepower.

Sensitivity Analyses

The effect of uncertainties in operating costs

was examined using the high-process performance model. A low-cost case was analyzed by

reducing the compressor maintenance cost from

$0.08/MScf to $0.07/MScf. A high-cost case increased the compressor maintenance to

$0.10/MScf. Results of these cases are compared

in table B-1 5. Cost reduction had little effect on

the projected results while the 25-percent increase in maintenance cost reduced the ultimate

recovery by 19 percent at upper tier price and 8

percent at world oil price for the high-process

performance case,

A case was also simulated in which the displacement efficiency in the steam and hot water

zones was increased by changing the residual oil

saturation in the steam zone to 0.10 and in the

hot water zone to 0.20, Results of this case are indicated as high-displacement efficiency in table

B-1 S. The effect of assumed improvement in displacement efficiency resulted in a 17- to 20-percent increase in ultimate recovery but little

change in price elasticity.

Table B-15

Effect of Changes in Compressor Operating Costs

and Displacement Efficiency in Ultimate Oil

Recovery Using the In Situ Combustion Process

Case

I

Incremental oil

(billions of barrels)

Upper

tier

price

($1 1.62/

bbl)

World

oil

price

($1 3.75/

bbl)

Alternate

fuels

price

($22.00/

bbl)

High cost. . . . . . . . . . . .

High-process

performance . . . . . . . .

Low cost . . . . . . . . . . . .

High-displacement

efficiency . . . . . . . .

1.4

1.7

1.7

2.1

1.7

1.9

1.9

2.2

1.9

1.9

1.9

2.3
Carbon Dioxide Miscible

State of the Art—Technological Assessment

It has been known for many years that oil can

be displaced from a reservoir by injection of a

solvent that is miscible with the oil. Because such

solvents are generally expensive, it is necessary

to use a “slug” of the solvent to displace the oil

and then to drive the slug through the reservoir

with a cheaper fluid, This process was shown to

be feasible at least 20 years ago.79 An overview

of the various kinds of miscible displacements is

given by Clark, et al.80

Hydrocarbon miscible processes have been

developed and studied fairly extensively. A number of field tests have been conducted.81 While it

has been established that hydrocarbon miscible

processes are technically feasible, the high cost

of hydrocarbons used in a slug often makes the

economics unattractive. Recently, attention has

focused on carbon dioxide (C02

) as the

miscibility agent.82

In the OTA study it was assumed that, in

general, economics and solvent availability

would favor the use of C02

. The C02 process

was therefore used exclusively as the miscible

displacement process in the study.

Carbon dioxide has several properties which

can be used to promote the recovery of crude oil

when it is brought into contact with the oil.

These properties include: 1 ) volubility in oil with

resultant swelling of oil volume; 2) reduction of

oil viscosity; 3) acidic effect on rock; and 4)

ability to vaporize and extract portions of the

crude oil under certain conditions of composition, pressure, and temperature.

Because of these properties, C02 can be used

in different ways to increase oil recovery, i.e.,

different displacement mechanisms can be exploited. The three primary mechanisms are solution gas drive, immiscible displacement, and

dynamic miscible displacement.

Solution-gas-drive recovery results from the

fact that C02 is highly soluble in oil. When C02

is brought into contact with oil under pressure,

the C02 goes into solution. When the pressure is

lowered, part of the C02 will evolve and serve as

an energy source to drive oil to producing wells.

Appendix B . 165

The mechanism is similar to the solution-gasdrive primary recovery mechanism and can be

operative in either immiscible or miscible displacement processes.

Helm and Josendalal83 have shown that C02 can

be used to displace oil immiscible. In experiments conducted with liquid C02 below the

critical temperature, residual oil saturations were

significantly lower after flooding with C02 than

after a waterflood. The improved recovery was

attributed primarily to viscosity reduction and oil

swelling with resultant improvement in the relative permeability. It was noted that the C02 displacement was not as efficient when a

waterflood preceded the C02

.

Carbon dioxide, at reservoir conditions, is not

directly miscible with crude oil. However,

because C02 dissolves in the oil phase and also

extracts hydrocarbons from the crude, it is possible to create a displacing phase composition in

the reservoir that is miscible with the crude oil.

Menzie and Nielson, in an early paper,84 presented data indicating that when C02 is brought

into contact with crude oil, part of the oil vaporizes into the gaseous phase. Under certain conditions of pressure and temperature, the extraction

of the hydrocarbons is significant, especially extraction of the intermediate molecular weight hydrocarbons (C5 to C30). Helm and Josendahl85 also

showed that C02 injected into an oil-saturated

core extracts intermediate hydrocarbons from the

oil phase and establishes a slug mixture which is

miscible with the original crude oil. Thus, while

direct contact miscibility between crude oil and

C02 does not occur, a miscible displacement can

be created in situ. The displacement process,

termed dynamic miscibility, results in recoveries

from linear laboratory cores which are comparable to direct contact miscible displacement.

HoIm86 has pointed out that the C02 miscible

displacement process is similar to a dynamic

miscible displacement using high-pressure dry

gas. However, important differences are that C02

extracts heavier hydrocarbons from the crude oil

and does not depend upon the existence of light

hydrocarbons, such as propane and butanes, in

the oil. Miscible displacements can thus be

achieved with COZ at much lower pressures than
166 . Appendix B

with a dry gas. Methods of estimating miscibility

pressure have been presented.87,88

The CO2 miscible process is being examined in

a number of field pilot tests.89,90 The largest of

these is the SACROC unit in the Kelly-Snyder

Field. 91 Different variations of the process are

being tested. In one, a slug of CO2 is injected

followed by water injection. In another, CO2 and

water are injected alternatively in an attempt to

improve mobility control. 92

The preliminary indication from laboratory experiments and these field tests is that the C02

process has significant potential. However, the

field experience is quite limited to date and some

difficulties have arisen. Early CO2 breakthrough

has occurred in some cases and the amount of

CO, required to be circulated through the reservoir- has been greater than previously thought .93

Operating problems such as corrosion and scaling can be more severe than with normal

waterflooding. Greater attention must be given

to reservoir flow problems such as the effects of

reservoir heterogeneities and the potential for

gravity override.

in general, the operating efficiency of the process or the economics have not been firmly

established. In the OTA study, the reported

laboratory investigations and preliminary field

results were used as the basis for the recovery

models and the economic calculations.

Screening Criteria.—Technical screening criteria were set in accordance with the following:

Oil viscosity

<12 Cp

Attainable pressure assumed to be =

.6 x depth -300 psi

Miscibility pressure

< 27° API 4,000 psi

27° - 30” API 3,000 psi

—> 30° API 1,200 psi

Temperature correction to miscibility pressure

O psi if T < 120° F.

200 psi if T = 120- 150° F.

350 psi if T = 150- 200° F.

500 psi if T > 200° F.

This leads to depth criteria as follows (not temperature corrected):

< 27° API 7,200 ft

27° - 30° API 5,500 ft

> 30° API — 2,500 ft

This was the same correlation as used in the NPC

study.94 It is noted that the general validity of this

correlation has not been established. Crude oils

in particular reservoirs may or may not establish

miscibility with CO2 at the pressures and temperatures indicated. Other correlations have

been presented in the literature, but they are

based on a knowledge of the crude oil composition. Data on composition were not available in

the data base used in the OTA study, and a

generalized correlation of the type indicated

above was therefore required.

Oil Recovery Projections

Onshore Reservoirs .—The recovery model

used was as follows:

where

R = recovery by CO2 process, stocktank barrels

s =

orm residual oil saturation in zone

swept by CO2

. Set at 0.08, No

distinction was made between

sandstone and carbonate reservoirs.

E m = sweep efficiency of C02 miscible displacement. (Em/Evm) was

set at 0.70.

E =

v m

volumetric sweep efficiency of

the waterflood computed from

procedure described in appendix

A.

The sweep efficiency for CO2 miscible (E m

was determined by making example calculations

on CO2 field tests. Field tests used were the

following:

Slaughter

Wasson

Level land

Kelly-Snyder (SACROC)
Appendix B . 167

Cowden-North

Crosset

All projects except the Wasson test were

reported in the SPE Field Reports. 95 Data on

Wasson were obtained from a private communication from Lewin and Associates, Inc.

Based upon reported data and reported estimates

of the tertiary recovery for each field test, sweep

efficiency values were calculated. The ratio

E m/Evm averaged 0.87. Discarding the high and

low, the average was 0.80. It was judged that the

national average recovery would be less,

therefore a value of EmE vm of 0.70 was used for

all reservoirs in the OTA calculations.

The high-process performance model assumes

the waterflood residual (SOrw for each reservoir is

determined from table A-1 according to

geographic region. This value was used unless

the volumetric sweep efficiency for the

waterflood (EVJ fell outside the limits described

in appendix A. The low-process performance was

simulated by reducing the SOrW values in table

A-1 by 5 saturation percent. The same limits on

the calculated values of Evm were used in the

low-process performance model. The recovery

model (equation 6B) was unchanged except for

Evm and SO:W.

The low-process performance model reduced

the EOR for those reservoirs in which the calculated Evm fell within the prescribed limits. Where

E vm was outside the limits, S O ,W was recalculated

using the limiting E v m value. Therefore, for these

latter reservoirs the recovery results were the

same in both the high- and low-process performance models. For C02 miscible, this was the case

for about one-third of the total reservoirs. The

average recovery for all reservoirs was 20 percent

less in the low-process performance case than in

the high-process performance case.

Volurnes of Injected Materials.—The COZ r equirement was established as follows:

Sandstone Reservoirs—26 percent of pore volume

Carbonate Reservoirs—22 percent of pore volume

Conversion of CO2 from surface conditions to

reservoir conditions was assumed to be:

2 Mcf C02 (std. cond.) per 1.0 reservoir bbl

(A constant value was used.)

Twenty-five percent of the total CO2 requirement was assumed to be from recovered, compressed, and reinfected gas. Seventy-five percent

was purchased.

The C02 injection schedule was as shown in

table B-1 6. The water alternating gas process was

used. The ratios were:

Sandstones I: 2 C O2H 2O

Carbonates 1: 1 C O2:H2O

Table B-16

Carbon Dioxide Injection Schedule

I

Purchased COZ

I

Recycled C02

Year percent of total* percent of total*

1-2 . . . . . . . . . . . 0 0

3 . . . . . . . . . . . . . 20 0

4 . . . . . . . . . . . . . 20 0

5 16 4

6:::::::::::: : 13 7

7 . . . . . . . . . . . . . 6 14

● Total refers to total volume of C02 Injected over Ilfc t)t pattern,

Fluid injection occurred over a 5-year period;

reinfected C02 was used beginning in the third

year of the period, along with purchased COZ

.

Timing of Production. —The production profile

was set at a fixed percentage of the total recovery (as computed by the recovery model above).

The schedule is shown in table B-17. All reservoirs were developed on 40-acre spacing.

Offshore Reservoirs.--Offshore CO2 miscible

displacement was calculated using a different

model than the onshore model. The reservoirs of

the gulf offshore are steeply dipping because

they are nearly universally associated with salt

dome formations. This has limited effect on the

other processes but great impact on CO2 miscible. Due to the dip, the CO), with small quantities of CH4 can be injected at the top of the dip

and gravity stabilized. No production is noted

until the oil bank ahead of the miscible slug

reaches the first producers down dip. The bank is

produced until the slug breaks through, at which

time the producer is shut in and the slug proceeds further down dip, creating a new bank

which is produced in like manner at the next producer further down. The process continues until
168 . Appendix B

Table B-17

Production Rate Schedule

for Carbon Dioxide Miscible

Table B-18

Gas Injection Schedule

Offshore Carbon Dioxide Miscible

Percent

Year of EOR

Carbonates

1-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

11 . . . . . . . . . . . . . . . . . . . . . .fi. ......,

12,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

0

5

9

13

17

19

14

10

6

4

2

1

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

Sandstones

100

0

6

19

26

21

13

9

6

Total . . . . . . . . . . . . . . . . . . . . . . . . . 100

the final bank has been produced at the bottom

of the formation. Because the integrity of the

miscible slug must be maintained, no water injection is contemplated. However, air is compressed

and used to push the CO2

-CH4 mixture after a

relatively large volume of the mixture has been

injected. Residual oil saturation after miscible

displacement, S Orm, was set at 0.08. Sweep effic iency , Em, was set at O.80 (i.e (Em/Evm) x Ev m

=

0.80). This is a significantly higher sweep efficiency than used, on the average, for onshore reservoirs.

The fluid injection schedule for offshore reservoirs is shown in table B-18 and the oil production schedule is given in table B-19.

Carbon Dioxide Costs

Well Drilling and Completion Costs.-Because

of special requirements created by C02

flooding,

Year I C02 -CH, I Air

1 . . . . . . . . . . . . . . 0 0

2 . . . . . . . . . . . . . . 0.25PV o

3 . . . . . . . . . . . . . . 0.25PV o

4 . . . . . . . . . . . . . . 0 0.15PV

5 . . . . . . . . . . . . . . 0 0.15PV

Table B-19

Oil Production Schedule

Offshore Carbon Dioxide Miscible

Production

Year percent of total

1 . . . . . . . . . . . . . . . . . . . . . . . o

2 . . . . . . . . . . . . . . . . . . . . . . . o

3 . . . . . . . . . . . . . . . . . . . . . . . o

4 . . . . . . . . . . . . . . . . . . . . . . . 50

5 . . . . . . . . . . . . . . . . . . . . . . . 50

Total . . . . . . . . . . . . . . . . 100

the base drilling and completion cost was increased by a factor of 1.25 for injection wells.

Compression Costs.—Twenty-five percent of

the CO2 requirement was met from recycled

C O2

. Compression equipment was purchased

and fuel costs were charged to this recompression.

Carbon Dioxide Pricing Method.—The cost of

C 02 is a variable of major importance. Costs of

CO2 can vary widely depending on whether the

source is natural or manufactured gas and depending on the transportation method and distance. In fact, this EOR technique probably has

the greatest potential for economies of scale

because of the variability of these costs.

The cost algorithm used in the OTA study was

developed by Lewin and Associates, Inc., and a

summary of this analysis follows. Reservoirs were

placed into one of four categories. These categories are:

●

●

Concentrations of large reservoirs adequate

to support the construction of a major C02

pipeline.

Concentrations of smaller reservoirs where

the bulk of COZ transportation would be by
major pipeline but where lateral lines would

be required to deliver COZ to the numerous

smaller fields,

. Smaller concentrations of large (and small)

reservoirs where a smaller pipeline or alternative means for transporting COZ could be

used.

. Individual, small reservoirs to be served by

lateral pipeline or tanker trucks, where the

amounts of required C02 would not justify

the building of a new pipeline.

Results of the analysis of each of these

categories is provided in the section below. The

following subsection contains the details of the

calculations.

Results of Carbon Dioxide Cost Calculations

Concentrations of Large Reservoirs. Given

the indicated locations of natural C02 and the

concentration of large candidate reservoirs such

Appendix B . 169

as in western Texas, eastern New Mexico, and

southern Louisiana, it appears that the reservoirs

in these areas could be served by major C02

pipelines.

The C 02 cost model uses the folIowing

algorithms for assigning C02 costs to reservoirs:

● $0.22 per Mcf for producing C02,

. $0.24 per Mcf for compression and operation costs, and

. $0.08 per 100 miles of pipeline distance, including small amounts of lateral lines,

assuming a 200 MMcf per day of pipeline

capacity.

Under these assumptions, the base cost for C02

delivered to concentrations of large reservoir

areas would be according to the following chart.

All reservoirs, large and small, in these

geographic areas would be able to take advantage of the economies of scale offered by the

basic concentration of large reservoirs.

Geographic area

Approximate

truckline distance

(miles)

Louisiana—South . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Texas-District 76 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

District 7C,8,8A,9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

District 10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New Mexico East and West . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .“. . .

200

400

300

300

300

500

200

300

Adequate Concentration of Large and Small

Reservoirs Served by Lateral Lines.—The second

class of reservoirs would be the large and small

reservoirs in close proximity to the major

trunklines. These reservoirs could be serviced by

using short distance lateral lines. Carbon dioxide

costs were assigned as follows:

● $0.46 per Mcf for producing and compressing the C02

, and

● $0.20 per Mcf per 100 miles for transportation.

The C02 model assumes that reservoirs in the

following geographic areas could be served by

short distance trunklines or linking lateral lines to

Laterals

(miles)

100

200

100

100

100

100

100

—

Carbon dioxide

cost per Mcf

(dollars)

0.70

0.94

0.78

0.78

0.78

0.94

0.70

0.70

the main trunklines, using pipelines of 50 MMcf

per day capacity.

Geographic area

Colorado . . . . . . . .

Mississippi. . . . . . .

Oklahoma . . . . . . .

Utah. . . . . . . . . . . .

Approximate

distance Carbon dioxide

trunklines or laterals cost per Mcf

(miles) (dollars)

100 0.70

100 0.70

150 0.78

100 0.70

Low Concentration, Large and Small Reservoirs,

Close to Natural Sources of Carbon Dioxide.—

The third class of reservoirs are those close to

natural C02 sources where only minimum
170 ● Appendix B

transportation charges would be required to

deliver the C02 to the field.

The first question is what size of pipeline can

be justified. This was examined for the two

smaller potential States of Alabama and Florida.

It was assumed that both of these States would

justify a 100 MMcf pipeline under a 10-year

development plan and a 50 MMcf pipeline under

a 20-year development plan. For a 50 MMcf

pipeline the costs were assumed to be as

follows:

. $0.46 per Mcf for producing and compressing the COZ

, and

● $0.20 per Mcf per 100 miles for transportation, including laterals.

The COZ model assumes that the following

geographic areas are close to natural CO2 sources

and could be served by small pipelines, having

50 MMcf/day capacity.

Geographic area

Approximate Carbon dioxide

pipeline distance cost per Mcf

(miles) (dollars)

Alabama . . . . . . . . .

Arkansas . . . . . . . . .

Florida . . . . . . . . . . .

Kansas . . . . . . . . . . .

Montana . . . . . . . . .

West Virginia . . . . .

200

200

300

200

200

100

0.86

0.86

1.02

0.86

0.86

0.70

An alternative to this third class of reservoirs

are those similar reservoirs that are not close to

natural COZ sources. The reservoirs in these

geographic locations would need to be served by

C OZ extracted from industrial waste products

(e.g., from chemical complexes, ammonia plants,

gasoline plants, combined powerplants, etc.).

An analysis of minimum required pipeline size

indicated that each of these areas could support

a 200+ MMcf per day pipeline under a 10-year

development plan and a 100 MMcf per day

pipeline under a 20-year development plan. The

following costs were used for these reservoirs:

●

●

●

●

$0.90 per Mcf for extracting the manufactured CO2

,

$0.25 per Mcf for compression and operation,

$0.08 per Mcf for 100 miles of trunk

pipeline (200 MMcf per day capacity), plus

$0.30 per Mcf for three 50-mile lateral lines

(50 MMcf per day capacity) connecting the

CO2 source to the trunkline.

Under these assumptions, the base cost for

C O2 for the geographic areas in this category

would be as follows:

Purchasing, operating,

Approximate and gathering costs c o ,

Geographic area pipeline distance per Mcf cost per Mcf

(miles) (dollars) (dollars)

California-Central Coastal, L.A. Basin,

and offshore . . . . . . . . . . . . . . . . . . .

Louisiana—North . . . . . . . . . . . . . . . . . . . . . . . . . .

Texas--District 1 . . . . . . . . . . . . . . . . . . . . . . . . . .

Districts 2,3,4 . . . . . . . . . . . . . . . . . . . . . . .

Districts 5,6. . . . . . . . . . . . . . . . . . . . . . . . .

200

200

200

200

200

1.45

1.45

1.45

1.45

1.45

1.61

1,61

1.61

1.61

1.61

Low Concentration, Small Reservoirs.—The

final category of reservoirs considered in the

analysis are the small reservoirs located in the

moderate- and low-concentration geographic

areas. The alternatives here are to construct a

small pipeline to the trunkline or to deliver the

C O2 via truck. Large trunkline construction for

low concentration reservoirs is infeasible.

For those geographic regions where the large

reservoirs are already served by a pipeline, it appears likely that additional small lateral lines

could be added to extend the C02 delivery to

small fields. These fields would only need to pay

the marginal costs of delivery. Because of this,

rather small CO2 lateral lines could be constructed (as small as 5 MMcf per day), which
Appendix B . 171

would serve an area with as little as 5 million barrels of recoverable oil. it was thus assumed that

the average C02 costs for the small fields in a

region already served by a pipeline would be the

same as base costs for that region.

For concentrations lacking such existing

trunklines, i.e., the remaining States, tankertrucks would deliver CO2

. These would include:

Illinois North Dakota

Indiana Ohio

Kentucky Pennsylvania

Michigan South Dakota

New York Tennessee

Virginia

The cost in these States was set at $2.75 per Mcf.

Calculation Method and Details—

Carbon Dioxide Costs

The method used to derive the C02 costs is

briefly outlined in this section. The analysis

followed a seven-step sequence:

●

●

●

●

●

●

●

calculate the relationship of pipeline

capacity to unit costs,

translate pipeline capacity–cost relationship to pipeline investment costs per Mcf,

for various pipeline capacities,

calculate the pipeline delivery costs per Mcf

that vary by distance,

calculate the C02 purchase and delivery

costs per Mcf that do not vary by distance,

calculate full costs per Mcf for natural and

manufactured CO2

,

translate pipeline capacity to minimum required field size, and

complete the breakeven analysis of using

pipeline versus truck for delivering CO2 t o

the field.

Relationship of Capacity to Costs.—The

following were assumed for calculating pipeline

investment costs:

• $330,000 per mile for 200 MMcf per day

capacity,

. investment

factor, and

. pipeline wi

is scaled for capacity by a 0.6

lI last 20 years.

Fixed and variable costs were set as follows:

● fixed costs plus variable cost exponent

(capacity) = total

Using the above data:

. fixed costs + 0.6 (200,000 Mcf/day) =

$330,000 per mile,

. fixed costs = $210,000 per mile, and

o variable costs = $600 per MMcf/day per

mile.

This relationship of costs to capacity has

the general form shown in figure B-2.

Figure B-2. Pipeline Cost Versus Capacity

400 —

300 -

100

t

100 200 300

Pipeline capacity (in MMcf/day)

Pipeline Investment Costs per Mcf.—The cost

–capacity graph was translated into a cost per

Mcf (per 100 miles) graph by dividing costs by

capacity, as follows:

For the 200 MMcf/day capacity at $330,000

per mile, the cost per Mcf per 100 miles with no

discounting of capital is:

($330,000 X 100)/(200,000 X 365 X 20) = $0,023 per Mcl

If an 8-percent rate-of-return requirement is

imposed, and it is assumed that no return results

until the fourth year, the costs would be raised

to:

- P

L.08(1 .08) 16J

C = $0.07 per Mcf per 100 miles
172 . Appendix B

Similarly, the pipeline investment cost per Mcf

can be generated as shown in table B-20.

labia 6-20

Pipeiine Capacity Versus investment

(8-percent rate of return)

Pipeline investment

Pipeline capacity cost per Mcf

(MMcf/day) ($ per 100 miles)

300 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.05

200 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.07

100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.11

50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.20

25 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.37

lo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.89

5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.79

Pipeline Delivery Costs Variable by Distance.—

The pipeline investment cost was added to

pipeline operating costs to develop pipeline

costs per Mcf that are variable by distance. The

following was assumed:

. pipeline operating costs are $O.01 per Mcf

per 100 miles, and

● the pipeline capital costs from table 6-20

are applicable,

● with these assumptions, the variable cost

per Mcf per lOO miles can redeveloped as

shown in figure B-3.

Figure B-3. Variable CO2 Transportation

Costs Versus Pipeline Capacity

100 300”

Pipeline capacity (in MMcf/day)

Carbon Dioxide Costs Not Variable by Distance.—The following was assumed:

. repressurizing operating costs are $0.16 per

Mcf

repressurizing capital costs are $0.08 per

Mcfbased on the following:

$700 per hp

280 hp required to pressurize 1,000

Mcf per day

Compressors will last 20 years

8-percent discount rate,

the purchase cost of naturally occurring C02

is $0.22 per Mcf,

extraction costs for manufactured C02 are

$0.90 per Mcf, and

additional lateral lines will be required to

gather and transport manufactured C02

.

Based on the preceding, the fixed costs for

manufactured C02 will be $1.14 per Mcf with

lateral lines as shown in table B-21.

Table B-21

Lateral Lines Associated With Pipeline Capacity

Pipeline capacity Amount and size of

(MMcf/day) lateral lines

300 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 50 MMcf/day

200 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 50 MMcf/day

100 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 25 MMcf/day

50 . . . . . . . . . . . . . . . . . . . . . 2 to 50 mile @ 10 MMcf/day

25 . . . . . . . . . . . . . . . . . . . . . 1 to 50 mile @ 10 MMcf/day

10 . . . . . . . . . . . . . . . . . . . . . 1 to 50 mile @ 5 MMcf/day

5 . . . . . . . . . . . . . . . . . . . . . None

Total Costs per Mcf. —The investment and

operating costs were then added to the purchase

price for natural CO2 and extraction and gathering costs for manufactured CO2 to obtain the

total cost per Mcf. These are shown for various

conditions in table B-22.

Relationship of Pipeline Capacity to Field

Size.—The pipeline capacity was related to field

size

●

●

●

using the following assumptions:

5 Mcf are required per barrel of recovered

oil,

CO2 is injected over 10 years, and

C 02 recovers 30 percent of the oil left after

primary/secondary recovery.

Then the conversions of pipeline capacity to

field size shown in table B-23 were used.

Break-Even Analysis.-Using $2.75 per Mcf as

the trucked-in cost for C02

, two curves were
Appendix B . 173

Table B-22

Total Costs per Mcf of CO=

(dollars)

.

Pipeline

capacity

(MMcf/day)

300 . . .

200 . . .

100 . . .

50 . . .

2 5

1 0

5 . . .

Distance

(miles)

100

200

300

400

100

200

300

400

100

200

300

400

50

100

200

300

400

50

100

200

300

50

100

200

50

100

200

Transp.

costs

0.06

0.12

0.18

0.24

0.08

0.16

0.24

0.32

0.12

0.24

0.36

0,48

0.10

0,21

0.42

0.63

0.84

0.19

0.38

0.76

1.14

0.45

0.90

1.80

0.88

1.76

3.52

Fixed

operating

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

024

0.24

0.24

024

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

0.24

Table B-23

Pipeline Capacity as a Function of Field Size

Pipeline capacity

(MMcf/day)

300 . . . . . . . . . . . .

200 . . . . . . . . . . . .

100 . . . . . . . . . . . .

50 . . . . . . . . . . . .

25 . . . . . . . . . . . .

10 . . . . . . . . . . . .

5 . . . . . . . . . . . .

Purchase

(natural)

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

0.22

Minimum required concentration

(or field size)

Incremental oil I Residual oil

recovered by C02 in place

(million barrels) (million barrels)

219 730

146 490

73 240

36 120

18 60

9 30

5 17

determined: one for natural and one for manufactured CO2

. These curves, shown in figure B-4, indicate the field size (oil concentration) and disExtract

from

manuf.

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

0.90

Gather

from

manuf.

0.30

0.30

0.30

0.30

0.30

0.30

0.30

0.30

0.57

0.57

0.57

0.57

0.90

0.90

0.90

0.90

0,90

0.90

0.90

0.90

0.90

0.88

0.88

0.88

—

—

—

Full cost

for natural

0.52

0.58

0.64

0.70

0.54

0.62

0.70

0.78

0.58

0.70

0.82

0.94

0.56

0.67

1.88

1.09

1.30

0.65

0.84

1.22

1.60

0.91

1.36

2.20

1.34

2.22

3.98

Full cost for

manufactured

1.50

1.56

1.62

1.68

1.52

1.60

1.68

1.76

1,83

1.95

2.07

2.19

2.14

2.25

2,46

2.67

2.88

2.23

2.42

2.80

3.18

2.49

2.94

3.84

2.02

2.90

4.66

Figure B-4. Transportation

of C02— Break-Even Analysis

. Use Pipeline

I I I 1“ t I I I

tance combinations where either pipeline or 5 10 15 20 25 30 35 -

trucked CO2 would be more economic. (Million Barrels of Recoverable Oil)
174 . Appendix B

Sensitivity Analyses

Calculations were made with different sets of

parameters than those presented in the main

body of the report. In general, these additional

calculations were done to determine the sensitivity of the results to certain of the important

variables. For CO2 miscible, two important considerations were the minimum acceptable rate of

return and the price of the injected CO2

. Results

of calculations in which these parameters were

varied are given in this section.

High-Process Performance—High-Risk Case.—

A calculation was made in which the minimum

acceptable rate of return was set at 20 percent.

The rate of implementation of projects was

governed by the rate of return earned in a manner

analogous to that given by table 8 in chapter Ill.

The schedule of starting dates based on rate of

return is given in the section on the economic

model (p. 35).

Results of this calculation, considering the case

in which the process is viewed as a high risk technology, are given in table B-24 for the world oil

price. Ultimate recovery is dramatically reduced

from the conventional risk case (lo-percent rate

of return) presented in the body of the report. At

lo-percent rate of return, the ultimate recovery is

13.8 billion barrels compared to 4.7 billion barrels with a 20-percent minimum rate of return.

Production rates are correspondingly reduced.

This result strongly suggests that a great deal

of research and development work must be done

to establish the processes, and that economic incentives must be provided if the projections presented in the body of the report are to be

reached,

Sensitivity to Carbon Dioxide Costs. -Calculitions were made in which the purchase cost of

C 02 was increased by factors of 1.5 and 2.5. A

significant uncertainty exists relative to COZ costs

and variations of these magnitudes are considered feasible.

Results for the high- and low-process performance cases are shown in table B-25 and B-26,

Table B-24

Estimated Recoveries for Advancing Technology—

High-Process Performance

High Risk (20-percent rate of return)

Carbon Dioxide Miscible

Ultimate recovery:

(billion barrels) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Production rate in:

(million barrels/day)**

1980 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cumulative production by:

(million barrels)**

1980 . . . . . . . . . . . . . . . . ., . . . . . . . . . . . . . . . . . . . . . . . . . .

1985, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . ... , . . . . . . . . . . . . . . . . . . . . . . . .

2000 .., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Onshore

4.1

0.1

0.1

0.1

0.6

0.9

100

300

400

900

2,700

World oil price

($13.75/bbl)

Offshore

0.6

*

*

●

0.1

0.1

●

☛

100

200

500

● Less than O. I million barrels of daily production, or less than 100 million barrels of cumulative production.

Total

4.7

0.1

0.1

0.1

0.7

1.1

100

300

600

1,100

3,200

● “Daily production figures rounded to 0.1 million barrels, cumulative production figures rounded to 100 million barrels; row totals may not

add due to rounding.
Appendix B . 175

Tabie B-25

Sensitivity of Ultimate Recovery to Carbon Dioxide Cost

Advancing Technology-High-Process Performance Case

(billions of barrels)

Upper tier price World 011 price Alternate fuels price

Cost factor ($11.62/bbl) [$1 3.75/bbl) ($22 .00/bbl)

Onshore Offshore Total Onshore Offshore Total Onshore Offshore Total

1.0 ” 8 5 0,6 9.1 129 0.9 13.8 18.5 2.6 21 1

1.5 : 3.9 01 4.0 6.7 0.3 7.0 15.9 19 178

2.5 . 0.4 0.0 0.4 18 0.0 1.8 11.5 0 6 12 .1

“Case reported In body of report

Table B-26

Sensitivity of Ultimate Recovery to Carbon Dioxide Cost

Advancing Technology—Low-Process Performance Case

(billions of barrels)

t

cost Upper tier World oil Alternate fuels

factor price price price

($11.62/bbl) ($1 3.75/bbl) ($22.00/bbl)

1 .0” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 4.6 12.3

1.5 . . . . . . . . . . . . . . . . . ., . . . . . . . . . . . . . . . . . . 0.8 1.8 8.9

2.5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3 0.3 4.2

“Case reported in body of report

respectively. As seen in table B-25, increasing the For the low-process performance case, an incost of CO2 by a factor of 1.5 reduces ultimate crease of CO2 cost by a factor of 2.5 reduces ultirecovery by a factor of about 2 at upper tier and mate recovery to about 0.3 billion barrels at

world oil prices. The effect is not so pronounced world oil price, and to about 4 billion barrels at

at the alternate fuels price. Increase of the cost by the alternate fuels price.

a factor of 2.5 essentially eliminates production

at the upper tier price and reduces recovery to

less than 2 billion barrels at world oil price.

Economic Model

The economic model was developed by Lewin

and Associates, Inc.96 In this section the structure

of the basic model will be described, followed by

tabulations of the economic parameters.

Structure of the Model

The model uses a standard discounted cashflow analysis. The unit of analysis is the reservoir

with economic calculations being made for a

single “average” five-spot pattern within the

reservoir. Results of the single-pattern calculation

are then aggregated according to a reservoir

development plan (described below) to determine total reservoir economic and production

performance.

Cash inflows are determined using the specific

oil recovery models previously described for

each process. Recovery models are applied using

the reservoir parameters from the data base. An

assumption was made that 95 percent of the oil

remaining in a reservoir was contained within 80

percent of the area. This “best” 80 percent was

then developed in the model. An adjustment of
176 ● Appendix B

reservoir thickness was made to distribute the 95

percent of the remaining oil over an acreage

equal to 80 percent of the total acreage. Timing

and amounts of oil production are dependent on

the particular EOR process applied as previously

described.

Cash outflows are based on several different

kinds of costs and investments. These are: 1)

field development costs, 2) equipment investments, 3) operating and maintenance (O & M)

costs, 4) injection chemical costs, and 5)

miscellaneous costs, such as overhead. Listings

and descriptions of the costs follow.

Using the cash inflows and outflows, an annual

overall cash-flow calculation is made considering

Federal and State taxes. Appropriate State tax

rules are incorporated for each reservoir. Cash

flows are then discounted at selected interest

rates to determine present worth as a function of

interest rate. Rate of return is also calculated.

The discounted cash-flow analysis was made

at three different oil prices. These included upper

tier price ($1 1.62 per barrel), world oil price

($1 3.75 per barrel), and an estimated price at

which alternate fuels would become competitive

($22.00 per barrel). All costs were in 1976 real

dollars with no adjustment for inflation.

Reservoirs were developed if they earned a

rate of return of at least 10 percent by one of the

EOR processes. In situations where more than

one EOR process was applicable to a reservoir,

the EOR process yielding the greatest ultimate

recovery was selected as long as a rate of return

of at least 10 percent was earned.

Specific Economic Assumptions

Date of Calculations.—Ail calculations were

made as of a date of July 1, 1976. Cost data were

projected to that date. No attempt was made to

build inflation factors into the calculations of

future behavior.

Sharing of Operating and Maintenance Costs.—

Well operating and maintenance costs were

shared between primary and secondary production and enhanced oil production. A decline

curve for primary and secondary production was

generated for each reservoir. This was based on

specific reservoir data, if available, or on regional

decline curve data if reservoir data did not exist.

Well operating costs were assigned annually to

enhanced oil operations in direct proportion to

the fraction of the oil production that was due to

the EOR process.

General and Administrative (Overhead)

Costs.—These costs were set at 20 percent of the

operating and maintenance costs plus 4 percent

of investments (excluding any capitalized chemical costs). Where O & M costs were shared between primary and secondary and enhanced

recovery, only that fraction assigned to EOR was

used as a basis for the overhead charge.

Intangible and Tangible Drilling and Completion Costs.—Intangible costs were expensed in

the year incurred in all cases (no carryback or carry forward was used in the tax treatment). These

costs were set at 70 percent of drilling and completion costs for new wells and 100 percent of

workover costs.

Tangible costs were “recovered” by depreciation. Thirty percent of drilling and completion

costs were capitalized plus any other lease or

well investments. A unit of production depreciation method was applied.

Royalty Rate.—A rate of 12.5 percent of gross

production was used in all cases.*

Income Taxes. —The Federal income tax rate

was set at 48 percent. The income tax rate for

each State was applied to reservoirs within the

State. An investment tax credit of 10 percent of

tangible investments was used to reduce the tax

liability. If a negative tax were computed in any

year, this was applied against other income in the

company to reduce tax liabilities.

Chemical Costs—Tax Treatment.—For tax purposes, chemicals, such as CO2

, surfactant,

polymer, and so on, were expensed in the year of

injection. Tax treatment of the chemical cost is

an important consideration. The effect of having

“In most current leases, a royalty is charged on net production. However, there is a trend to charge a royalty on

gross production in some Federal leases and because this

trend could extend into the private sector in the future,

OTA calculations assessed royalty charges against gross production.
Appendix B . 177

to capitalize chemicals (and recover the investment via depreciation) was treated as a part of

the policy considerations. This is discussed in the

main body of the report.

Size of Production Units--For purposes of the

economic calculations, a production unit was

assumed to consist of the acreage associated

with one production well. This varied from process to process. The spacing used is shown in

table B-27.

Table B-27

Production Unit Size

I I Production

Process Acres

C O2 miscible . . . . . 40

Steam drive . . . . . . 2.5-5.0

In situ combustion . 20

Surfactant/polymer Variable

(Max= 40)

Polymer. . . . . . . . . . 40

wells

1.0

1.0

1.0

1.0

1.0

Injection

wells

1.0

1.0

1.0

1.0

0.5

Information on number and age of production

and injection wells was input as part of the data

base. Existing wells were used and worked over

as required according to their age and condition,

As previously indicated, an assumption was

made that 95 percent of the remaining oil in

place was located under 80 percent of the reservoir acreage. The oil in this “best” acreage was

assumed to be uniformly distributed.

Timing of Reservoir Development.-Reservoirs

were developed according to a plan designed to

simulate industry implementation of EOR processes in a reservoir. The first part of the timing

plan consists of a schedule of starting dates

based on rate-of-return criteria. This was discussed in the main body of the report, and the

schedule is given in table 8 in chapter Ill. This

schedule is for the conventional risk situation

with a 10-percent rate of return taken as the

minimum acceptable rate,

A “high-risk” case was also considered in

which the minimum acceptable rate of return was

set at 20 percent. The schedule of starting dates

was altered for this high-risk case as shown in

table B-28.

The second part of the timing plan consists of

the elements of the specific reservoir developTable B-28

Schedule of Starting Dates

High-Risk Case

I Continuations of

I

ongoing projects New starts

Date rate of return rate of return

1977 . . . . . . . . . . .

1978 . . . . . . . . . . .

1979 . . . . . . . . . . .

1980 . . . . . . . . . . .

1981 . . . . . . . . . . .

1982 . . . . . . . . . . .

1983 . . . . . . . . . . .

1984 . . . . . . . . . . .

1985 . . . . . . . . . . .

1986 . . . . . . . . . . .

1987 -2000 . . . . . .

>20%

>20 %

>20 %

>20 %

>20 %

>20 %

>20 %

>20 %

>20 — %

%60%

>45 %

>40 %

>35 %

>30 %

>28 %

>26 %

>24 %

>22 %

>20 %

>20 — %

ment scheme, once a starting date is assigned.

The seven elements of the reservoir development

plan are as follows:

Reservoir study. Preliminary engineering

studies and laboratory tests are conducted.

A decision is made whether or not to undertake a technical pilot.

Technical pilot. Pilot consists of one or two

five-spot patterns on close spacing. Technical parameters are evaluated.

Evaluate pilot, planning. Pilot results are evaluated and plans are made for economic pilot.

Budgeting occurs.

Economic pi/et. Pilot consists of four to eight

five-spot patterns on normal spacing. Purpose is to evaluate economic and technical

potential.

Evaluation and planning, Results of pilots are

evaluated. Plans are made for full-scale

development.

Pipeline construction (CO, miscible only).

Pipeline necessary to carry C02 from source

to reservoir is constructed.

Development of complete reservoir. The remaining part of the reservoir is developed

according to a set time schedule.

The time devoted to each of the seven steps

for each process is shown in table B-29.

Extrapolation to Nation.—To obtain the national potential for EOR, calculated reservoir

q6-5q4 () - 78 - 13
178 . Appendix B

Table B-29

Timing of Reservoir Development

I

Years of Elapsed Time by EOR

Step

Reservoir study . . . . . . . . . .

Technical pilot . . . . . . . . . .

Evaluate pilot, planning . . .

Economic pilot . . . . . . . . . .

Evaluation and planning. . .

Pipeline construction . . . . .

Development of

reservoir. . . . . . . . . . . . . .

. Total

Steam In situ

1

2

1

3

1

—

10

1

2

1

2

2

—

1 o“

18 18

Technique

C02

1

2

1

4

1

2

5

16

Surfactant/

polymer Polymer

1 1

2 0

1 0

4 5

1 1 — —

10 2

19 9

*ln situ proceeds in four separate segments introduced 3 years apart.

recoveries were first extrapolated to the State or

district level and then summed to yield the national total. The State or district extrapolation

factor was the ratio of remaining oil in place

(ROIP) (after secondary recovery) in the State or

district divided by the ROIP in the data base

reservoirs in the State or district.

An example calculation for the State of

Wyoming follows (for world oil price).

Calculated EOR Recovery. . . . . . . . . . . . . . 0.56 billion bbls

(from reservoirs in data base)

Percent of ROIP in data base. . . . . . . . . . . . . . . . . . . . . 43.0

ROIP in data base . . . . . . . . . . . . . . . . . 10,628 million bbls

ROIP in State. . . . . . . . . . . . . . . . . . . . . 24,700 million bbls

State EOR =0.56 x 1 0

9

x 24.7 x 10’ .. ....1.3 billion bbls

10.6x1 O’

The State and district subdivisions used for extrapolation are shown in the tables of economic

parameters (Table B-30 for example).

Economic Data— General

This subsection is taken directly from the

report of Lewin and Associates, Inc., to the Energy

Research and Development Administration. 97

Much of the material is quoted directly.

Economic parameters are given which are used in

the model previously described. In the analysis,

specific values of the parameters are calculated

based on geographic location, reservoir depth,

condition of the wells, and the existence of

waterflooding or other secondary recovery. A

large number of geographic areas have been

established. In many cases these correspond to a

State, but in other cases (such as Texas) several

districts are defined within a State. Four depth

categories have been defined. Condition of the

wells in a reservoir is judged by the year of most

recent development. Existence of secondary

recovery in a reservoir is noted from State

reports.

The general economic parameters are presented through a series of tables as follows:

Table B-30

Table B-31

Table B-32

Table B-33

Table B-34

Table B-35

Table B-36

Table B-37

Drilling and Completion Costs for

Production and Injection Wells

Well, Lease, and Field Production

Equipment Costs—Production

Wells

Costs of New Injection Equipment

Well Workover and Conversion

Costs for Production and Injection

Wells

Basic Operating and Maintenance

Costs for Production and Injection

Wells

Incremental Injection Operating

and Maintenance Costs

State and Local Production Taxes

State Income Taxes.

Each exhibit presents the parameters actually

used in the models. The first six tables are accompanied by attachments that explain or illustrate

the derivation of the parameters. All the tables

are stated in 1976 prices.

Parameters in the above tables are for onshore

reservoirs. Additional economic parameters for

offshore reservoirs follow.
Appendix B ● 179

Table B-30

Drilling and Completion Costs for Production and Injection Wells

(dollars per foot of drilling and completion)

State/district

California

East central. . . . . . . . . . . . . . . . . .

Central coast . . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

</ 200’wD . . . . . . . . . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>800’WD . . . . . . . . . . . .

Louisiana

North. . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’wD. . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD. . . . . . . . . . . . . .

>=800’WD. . . , . . . . . . . . . . .

Texas

l... . . . . . . . . . . . . . . . . . . . . . . .

2 . . . . . . . . . . . . . . . . . . . . .

3::::. . . . . . . . . . . . . . . . . . . . . .

4... . . . . . . . . . . . . . . . . . . . . . . .

5... . . . . . . . . . . . . . . . . . . . . . . .

6... . . . . . . . . . . . . . . . . . . . . . . .

70 . . . . . . . . . . . . . . . . . . . . . . . . .

7C .,, ,,,,, . . . . . . . .

8... . . . . . . . . . . . . . . . . . . . . . . .

8A . . . . . . . . . . . . . . . . . . . . . . . . .

9... . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore. . . . . . . . . . . . . . . . . . . .

<=200’wD. . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD. . . . . . . . . . . . . .

>=800’WD. . . . . . . . . . . . . . . .

New Mexico

East . . . . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West. . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North . . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

23

24

25

30

31

32

33

34

35

36

40

41

0-2,500’

31.60

42.61

39.71

75.88

N.A.

N.A.

N.A.

N.A.

21.84

60.99

112.32

N.A.

N.A.

N.A.

N.A.

17.94

18.00

32.28

28.23

16,71

32.66

13.30

30.91

30.86

17.49

14.72

24.77

112.32

N.A.

N.A.

N.A.

N.A.

35.15

45.38

20.37

15.72

15.72

17.74

17.74

20.57

20.37

45.38

23.32

23.32

Depth category

2500-

5,000’

28.03

42.70

49.74

59.99

N.A.

N.A.

N.A.

N.A.

21.62

53.00

110.32

N.A.

N.A.

N.A.

N.A.

23.91

27.15

37.09

24.17

26.23

19.19

19.94

20.60

23.15

18.00

23.38

18.68

110.32

N.A.

N.A.

N.A.

N.A.

31.25

22.57

25.10

20.07

20.07

20.04

20.04

‘25.10

25.10

22.57

23.32

23.32

5,000-

10,000’

50.02

45.35

46.81

56.38

N.A.

N.A.

N.A,

N.A.

37.98

46.95

109.42

N.A.

N.A.

N.A.

N.A.

31.34

28.36

34.12

23.46

32.51

31.51

20.99

26.50

31.66

24.87

28.32

27.27

109.42

N.A.

N.A.

N.A.

N.A.

34.00

25.27

30.59

23.03

23.03

26.48

26.48

30.59

30.59

25.27

23.69

23.69

1o,ooo15,000’

93.62

74.71

70.10

64.59

N.A.

N.A.

N.A,

N.A.

33.93

57.62

103.20

N.A.

N.A.

N.A.

N.A.

35.00

33.40

63.75

77.67

55.96

60.96

N.A.

43.42

43.85

41.58

33.00

48.41

103.20

N.A.

N.A.

N.A.

N.A.

50.01

34.00

49.61

34.00

34.00

33.50

33,50

49.61

49.61

34.00

56.25

56.25
180 . Appendix B

Table B-3 Cont. —

State/district

Alabama

Hi sulphur. . . . . . . . . . . . . . . . . . .

Lo sulphur. . . . . . . . . . . . . . . . . . .

Florida

Hi sulphur. . . . . . . . . . . . . . . . . . .

Lo sulphur. . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana. ........, . . . . . . . . . . . . . . . . .

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Kentucky

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook Inlet . . . . . . . . . . . . . . . . . . .

Geographic

unit

42

43

44

45

50

53

55

57

58

59

60

61

62

63

64

65

66

67

70

71

72

73

80

31

0-2,500’

28.26

28.26

28.26

28.26

45.38

39.18

42.24

15.98

26.00

26.00

24.46

24.46

24.46

15.38

24.46

15.38

24.46

15.38

15.38

15.38

15,38

15.38

N.A.

N.A.

N.A. = not applicable.

Tabie B-31

State/district

Depth category

2,500-

5,000’

27.94

27.94

27.94

27.94

22,57

42.00

47.07

30.05

31.05

31.05

26.43

26.43

26.43

19.09

26.43

19.09

26.43

19.09

19.09

19.09

19.09

19.09

N.A.

N.A.

5,000-

10,000’

Weii,Lease,and Fieid Production Equipment Costs-Production Wells

(dollars per production well)

California

East Central . . . . . . . . . . . . . . . . .

Central Coast... . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’wD. . . . . . . . . . . . . . . .

201-400’WD. . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>800’WD . . . . . . . . . . . . . . .

Louisiana

North . . . . . . . . . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

N.A. = nonapplicable.

Geographic

unit

1

2

3

4

90

91

92

93

5

6

40.00

40.00

40.00

40.00

25.27

45.13

34.81

36.80

37.87

37.87

32.74

32.74

32.74

18.14

32.74

18.14

32.74

18.14

18.14

18.14

18.14

18.14

370.00

190.00

1o,ooo15,000’

55.69

55.69

55.69

55.69

34.00

93.48

104.69

48.98

45,10

45.10

50.00

50.00

50.00

30.00

50.00

30.00

50.00

30.00

30.00

30.00

30.00

30.00

340.00

180.00

Depth category

0-2,500’

33,300

33,300

33,300

300,000

300,000

300,000

N.A.

N.A.

23,500

24,700

2,500-

5,000’

51,900

51,900

51,900

300,000

300,000

300,000

N.A.

N.A.

45,600

47,300

5,000-

10,000’

47,200

47,200

47,200

300,000

300,000

300,000

N.A.

N.A.

50,500

52,900

1o,ooo15,000’

51,200

51,200

51,200

300,000

300,000

300,000

N.A.

N.A.

44,400

48,800
Appendix B ● 181

Table B-31—Cent.

State/district

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’WD” . . . . . . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>=800WD . . . . . . . . . . .

Texas

l . . . . . . . . . . . . . . . . . . . . . . . . . .

2 . . . . . .

3::::::::::::::::::::... . . .

4 . . . . . . . . . . . . . . . . . . . . . . . .

5::. . . . . . . . . . . . . . . . . . . . . . . .

6 . . . . . . . . . . . . . . . . . . . . . . . .

7B” : . . . . . . . . . . . . . . . . . . . . . . . .

7C . . . . . . . . . . . . . . . . . . . . . . . . .

8

8A::::::::::::::::::: ::::: :

9... . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’wD . . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>=800’WD. . . . . . . . . . . . . . . .

New Mexico

East . . . . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North. . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Alabama

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Florida

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming. . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana. . . . , . . . . . . . . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

7

95

96

97

98

8

9

10

11

12

13

14

15

16

17

18

19

20

95

96

97

98

23

24

25

30

31

32

33

34

35

36

40

41

42

43

44

45

50

53

55

57

58

59

60

61

.

0-2,500’

300,000

300,000

300,000

N.A.

N.A.

23,500

23,500

23,500

23,500

23,500

23,500

23,100

23,100

23,100

23,100

23,100

24,900

300,000

300,000

300,000

N.A.

N.A.

23,100

35,600

24,900

24,900

24,900

24,900

23,500

24,900

24,900

35,600

23,500

23,500

N.A.

23,500

N.A.

23,500

35,600

35,600

35,600

35,600

35,600

35,600

24,900

24,900

Depth category

2,500-

5,000’

300,000

300,000

300,000

N.A.

N.A.

45,600

45,600

45,600

45,600

45,600

45,600

32,900

32,900

32,900

32,900

32,900

37,100

300,000

300,000

300,000

N.A.

N.A.

32,900

45,400

37,100

37,100

37,100

37,100

45,600

37,700

37,100

45,400

45,600

45,600

N.A.

45,600

N.A.

45,600

45,400

45,400

45,400

45,400

45,400

45,400

37,100

37,100

5,000-

10,000’

300,000

300,000

300,000

N.A.

N.A.

50,500

50,500

50,500

50,500

50,500

50,500

52,400

52,400

52,400

52,400

52,400

49,100

300,000

300,000

300,000

N.A.

N.A.

52,400

76,900

49,100

49,100

49,100

49,100

50,500

49,100

49,100

75,900

50,500

50,500

N.A.

50,500

N.A.

50,500

76,900

76,900

76,900

76,900

76,900

76,900

49,100

49,100

1o,ooo15,000’

300,000

300,000

300,000

N.A.

N.A.

44,400

44,400

44,400

44,400

44,400

44,400

45,200

45,200

45,200

45,200

45,200

58,200

300,000

300,000

300,000

N.A.

N.A.

45,200

68,200

58,200

58,200

58,200’

58,200

44,400

58,200

58,200

68,200

44,400

44,400

N.A.

44,400

N.A.

44,400

68,200

68,200

68,200

68,200

68,200

68,200

58,200

58,200
182 . Appendix B

Table B-31-Cent.

Depth category

10,000-

1 5,000’

Geographic

unit

2,500-

5,000’

5,000-

1 0,000’ State/district

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Kentucky

West . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook Inlet . . . . . . . . . . . . . . . . . . .

0-2,500’

62

63

64

65

66

67

70

71

72

73

80

81

24,900

8,400

24,900

8,400

24,900

8,400

8,400

8,400

8,400

8,400

N.A.

N.A.

37,100

17,000

49,100

N.A.

58,200

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

37,100

17,000

N.A.

N.A.

37,100

17,000

17,000

17,000

17,000

17,000

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A. = not applicable.

NOTE: on geographic area and depth. These costs also Include all equipWell, lease, and field production equipment designed for secondary but excluding Injection equipment Includes all items except

tubing and wellheads (which are Included In JAS drilling costs) required to lift the fluid to the surface at the producing wellhead by

artiflcial lift, Including rod pump, gas Iift, or hydraulic lift, depending

ment to process the produced fluids prior to custody transfer. The

major items included are: heater-treater, separator, well testing

system, tanks, flow levers from producing wells, water disposal

systems, and, when applicable, crude desulphurizatlon facilities.

These are average costs per production well.

Table B-32

Costs of New Injection Equipment

(dollars per injection well)

Depth category

2,500-

5,000’

Geographic

unit

5,000-

1 0,000’

10,000-

1 5,000’ State/district 0-2,500’

California

East Central . . . . . . . . . . ... , . . .

Central Coast. . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<= 200’wD . . . . . . . . . . . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>=800’WD . . . . . . . . . . . . .

Louisiana

North. . . . . . . . . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<= 200’wD . . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401 -800’WD , . . . . . . . . . . . . .

>=800W D . . . . . . . . . . . . . . . .

1

2

3

4

90

91

92

93

5

6

7

95

96

97

98

30,500

30,500

30,500

100,000

N.A.

N.A.

N.A.

N.A.

28,500

31,100

100,000

100,000

100,000

N.A.

N.A.

30,500

30,500

30,500

100,000

N.A.

N.A.

N.A.

N.A.

28,500

31,100

100,000

100,000

100,000

N.A.

N.A.

48,500

48,500

48,500

150,000

N.A.

N.A.

N.A.

N.A.

45,300

52,300

150,000

150,000

150,000

N.A.

N.A.

48,500

48,500

48,500

150,000

N.A.

N.A.

N.A.

N.A.

45,300

52,300

150,000

150,000

150,000

N.A.

N.A.

N.A. = not applicable.
Table B-32-Cent.

State/district

Texas

1 . . . . . . . . . . . . . . . . . . . . . . . . . .

2

3::::::::::::::::::”:::: :: :

4

5 ::::::::::::::::::::::::: :

6... . . . . . . . . . . . . . . . . . . . . . . .

70 . . . . . . . . . . . . . . . . . . . . . . . . .

7C . . . . . . . . . . . . . . . . . . . . . . . . .

8... . . . . . . . . . . . . . . . . . . . . . . .

8A . . . . . . . . . . . . . . . . . . . . . . . .

9.....,....., . . . . . . . . . . . . . .

10 . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore. . . . . . . . . . . . . . . . . . . .

<=200’WID . . . . . . . .

201-400’WD. . . . . . . . . . . . . .

401-800’WD. . . . . . . . . . . . .

>=800WD. . . . . . . . . . . . . . .

New Mexico

East . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . .

Oklahoma. . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North. . . . . . . . . . . . . . . . . . . . . .

South, . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

west . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Alabama

HiSulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Florida

HiSulphur. . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . ., . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Geographic

unit

8

9

10

11

12

13

14

15

16

17

18

19

20

95

96

97

98

23

24

25

30

31

32

33

34

35

36

40

41

42

43

44

45

50

53

55

57

58

59

60

61

62

63

Appendix B• 18.3

0-2,500’

28,500

28,500

28,500

28,500

28,500

28,500

27,700

27,700

27,70P

27,700

27,700

30,000

100,000

100,000

100,000

N.A.

N.A.

27,700

42,800

30,000

30,000

30,000

30,000

28,500

30,000

30,000

42,800

28,500

28,500

28,500

28,500

28,500

28,500

42,800

42,800

42,800

42,800

42,800

42,800

30,000

30,000

30,000

12,200

“Depth category

2,500-

5,000’

28,500

28,500

28,500

28,500

28,500

28,500

27,700

27,700

27,700

27,700

27,700

30,000

100,000

100,000

100,000

N.A.

N.A.

27,700

42,800

30,000

30,000

30,000

30,000

28,500

30,000

30,000

42,800

28,500

28,500

28,500

28,500

28,500

28,500

42,800

42,800

42,800

42,800

42,800

42,800

30,000

30,000

30,000

12,200

5,000-

10,000’

45,300

45,300

45,300

45,300

45,300

45,300

44,100

44,100

44,100

44,100

44,100

64,100

150,000

150,000

150,000

N.A.

N.A.

44,100

74,700

64,100

64,100

64,100

64,100

45,300

64,100

64,100

74,700

45,300

45,300

45,300

45,300

45,300

45,300

74,700

74,700

74,700

74,700

74,700

74,700

64,100

64,100

64,100

N.A.

1o,ooo15,000’

45,300

45,300

45,300

45,300

45,300

45,300

44,100

44,100

44,100

44,100

44,100

64,100

150,000

150,000

150,000

N.A.

N.A.

44,100

74,700

64,100

64,100

64,100

64,100

45,300

64,100

64,100

74,700

45,300

45,300

45,300

451300

45,300

45,300

74,700

74,700

74,700

74,700

74,700

74,700

64,100

64,100

64,100

N.A.

N,A. = not applicable
— -

184 . Appendix B

Tabie B-32--Cent.

State/district

Geographic

unit

Kentucky

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook Inlet . . . . . . . . . . . . . . . . . . .

64

65

66

67

70

71

72

73

80

81

N.A

Note:

Cost of

eludes the

“Depth category

2,500-

0-2,500’ 5,000’

30,000

12,200

30,000

12,200

12,200

12,200

12,2(-)0

12,200

N.A.

N.A.

30,000

12,200

30,000

12,200

12,000

12,000

12,200

12,000

N.A.

N.A.

5,000-

10,000’

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

1o,ooo15,000’

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A,

= not applicable.

water injection equipment

equipment necessary to

depleted primary producing field. The malor items included are:

for waterflood projects in- water supply wells, water tankage, injection plant and accessories,

install a waterflood in a injection heads, water injection lines, and electrification.

Table B-33: Part A

Well Workover and Conversion Costs for Production and injection Wells

Workover and/or Conversion Costs for Enhanced Recovery

Years field has been operated underexisting wells worked over 25-years old— conversion cost

recovery process over (conversion percent

costs)

More than 25 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 100 100

16 to 25. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 80 40

6 to 15. ...., . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 64 16

1 to 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 0

Table B-33: Part B

Well Workover and Conversion Costs for Production and injection Wells

(dollars per well)

State/district

California

East Central . . . . . . . . . . . . . . . . .

Central Coast. . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore. . . . . . . . . . . . . . . . . . . .

<=200’WD . . . . . . . . . . . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>800’WD . . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

1

2

3

4

90

91

92

93

0-2,500’

20,400

20,400

20,400

150,000

N.A.

N.A.

N.A.

N.A.

Depth category

2,500-

5,000’

50,200

50,200

50,200

150,000

N.A.

N.A.

N.A.

N.A.

5,000-

1 0,000’

103,400

103,400

103,400

170,000

N.A.

N.A.

N.A.

N.A.

10,000-

1 5,000’

220,000

220,000

220,000

225,000

N.A.

N.A.

N.A.

N.A.
Appendix B . 185

Table B-33: Part B-Cent.

State/district

Louisiana

North. ... , . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’WD. . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD. . . . . . . . . . . . . .

>800'WD . . . . . . . . . . . . . . .

Texas

l . . . . . . . . . . . . . . . . . . . . . . . . . .

2 . . . . . . . . . . . . . . . . . . . . . . . . . .

3 . . . . . . . . . . . . . . . . . . . . . . . . . .

4 . . . . . . . . . . . . . . . . . . . . . . . . . .

5 . . . . . . . . . . . . . . . . . . . . . . . . . .

6 . . . . . . . . . . . . . . . . . . . . . . . .

70” : . . . . . . . . . . . . . . . . . . . . . . . .

7C . . . . . . . . . . . . . . . . . . . . . . . . .

8

8A::::::::::::: ::::::::::: :

9 . . . . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=2()()’wD. . . . . . . . . . . . . . , .

201-400’WD . . . . . . . . . . . . . .

401-800’WD. ..,, . . . . . . . . .

>=800'WD. . . . . . . . . . . . . .

New Mexico

East . . . . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North . . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Alabama

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Florida

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

5

6

7

95

96

97

98

8

9

10

11

12

13

14

15

16

17

18

19

20

95

96

97

98

23

24

25

30

31

32

33

34

35

36

40

41

42

43

44

45

50

53

55

57

58

0-2,500’

21,700

35,400

150,000

150,000

150,000

N.A.

N.A.

21,700

21,700

21,700

21,700

21,700

21,700

16,900

16,900

16,900

16,900

16,900

17,400

150,000

150,000

150,000

N.A.

N.A.

16,900

34,700

17,400

17,400

17,400

17,400

21,700

17,400

17,400

34,700

30,000

21,700

30,000

21,700

30,000

21,700

34,700

34,700

34,700

34,700

34,700

Depth category

2,500-

5,000’

38,200

69,000

150,000

150,000

150,000

N.A.

N.A.

38,200

38,200

38,200

38,200

38,200

38,200

27,400

27,400

27,400

27,400

27,400

29,700

150,000

150,000

150,000

N.A.

N.A.

27,400

50,900

29,700

29,700

29,700

29,700

38,200

29,700

29,700

50,900

50,000

38,200

50,000

38,200

50,000

38,200

50,900

50,900

50,900

50,900

50,900

5,000-

10,000’

64,100

94,000

170,000

170,000

170,000

N.A.

N.A.

64,100

64,100

64,100

64,100

64,100

64,100

57,500

57,500

57,500

57,500

57,500

59,800

170,000

170,000

170,000

N.A.

N.A.

57,500

76,900

59,800

59,800

59,800

59,800

64,100

59,800

59,800

76,900

100,000

64,100

100,000

64,100

100,000

64,100

76,900

76,900

76,900

76,900

76,900

1o,ooo15,000’

135,000

139,700

225,000

225,000

225,000

N.A.

N.A.

135,000

135,000

135,000

135,000

135,000

135,000

133,400

133,400

133,400

133,400

133,400

132,500

225,000

225,000

225,000

N.A.

N.A.

133,400

147,500

132,500

132,500

132,500

132,500

135,000

132,500

132,500

147,500

200,000

135,000

200,000

135,000

200,000

135,000

147,500

147,500

147,500

147,500

147,500
186 . Appendix B

Table B-33: Part B-Cent.

State/district

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Kentucky

West. . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook Inlet . . . . . . . . . . . . . . . . . . .

Geographic

unit

59

60

61

62

63

64

65

66

67

70

71

72

73

80

81

Depth category

0-2,500’

34,700

17,400

17,400

17,400

8,900

17,400

8,900

17,400

8,900

8,900

8,900

8,900

8,900

N.A.

N.A.

2,500-

5,000’

50,900

29,700

29,700

29,700

29,500

29,700

29,500

29,700

29,500

29,500

29,500

29,500

29,500

N.A.

N.A.

5,000-

10,000’

76,900

59,800

59,800

59,800

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

1o,ooo15,000’

147,500

132,500

132,500

132,500

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A. = not applicable.

Note: Costs are averaEes ofcosts for woduction wells and infection wells

Costs of conversion of existing producing or injection well to and are calculated based on percentages of applicable items of new

“new” producing or injection well include those to workover old well drilling costs and equipment costs required for workover or

wells and equipment for production or injection service for EOR. conversion.

Table B-34

Bask Operating and Maintenance Coats for Production and Injection Wells

(dollars per well per year)

State/district

California

East Central . . . . . . . . . . . . . . . . .

Central Coast. . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’WD . . . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>=800’WD . . . . . . . . . . . . . . . .

Louisiana

North. . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<= 200’wD . . . . . . . . . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>=800’WD . . . . . , . . . . . . . . . .

Texas

1 . . . . . . . . . . . . . . . . . . . . . . . . . .

2 . . . . . . . . . . . . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

1

2

3

4

90

91

92

93

5

6

7

95

96

97

98

8

9

0-2,500’

11,600

11,600

11,600

60,000

60,000

60,000

60,000

60,000

9,900

8,800

60,000

60,000

60,000

60,000

60,000

9,900

9,900

Depth category

2,500-

5,000’

15,700

15,700

15,700

60,000

60,000

69,000

72,000

84,000

13,900

12,200

60,000

60,000

69,000

72,000

84,000

13,900

13,900

5,000-

1 0,000’

17,500

17,500

17,500

75,000

75,000

84,000

90,000

105,000

16,500

15,200

75,000

75,000

84,000

90,000

105,000

16,500

16,500

10,000-

1 5,000’

19,800

19,800

19,800

75,000

75,000

84,000

90,000

105,000

16,900

15,800

75,000

75,000

84,000

90,000

105,000

16,900

16,900
Appendix B . 187

Table B-34-Cent.

State/district

3 . . . . . . . . . . . . . . . . . . . . . . . . . .

4 . . . . . . . . . . . . . . . . . . . . . . . . . .

5... . . . . . . . . . . . . . . . . . . . . . . .

6... . . . . . . . . . . . . . . . . . . . . . . .

70 . . . . . . . . . . . . . . . . . . . . . . . . .

7C, .,, , ., . ., ..,...., . . . . . . .

8... . . . . . . . . . . . . . . . . . . . . . . .

8A . . . . . . . . . . . . . . . . . . . . . . . . .

9... . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200'WD. . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>=800'WD. . . . . . . . . . . . . . .

New Mexico

East . . . . . . . . . . . . . . . . . . . . . . . .

West. . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West. . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North . . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Alabama

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Florida

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Kentucky

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Geographic

unit

10

11

12

13

14

15

16

17

18

19

20

95

96

97

98

23

24

25

30

31

32

33

34

35

36

40

41

42”

43

44

45

50

53

55

57

58

59

60

61

62

63

64

65

66

67

0-2,500’

9,900

9,900

9,900

9,900

8,000

8,000

8,000

8,000

8,000

10,000

60,000

60,000

70,000

72,000

84,000

8,000

8,700

10,000

10,000

10,000

10,000

9,900

10,000

10,000

8,700

15,000

9,900

15,000

9,900

15,000

9,900

8,700

8,700

8,700

8,700

8,700

8,700

6,000

6,000

6,000

2,300

6,000

2,300

6,000

2,300

Depth category

2,500-

5,000’

13,900

13,900

13,900

13,900

8,600

8,600

8,600

8,600

8,600

11,100

60,000

60,000

70,000

72,000

84,000

8,600

14,400

11,100

11,100

11,100

11,100

13,900

11,100

11,100

14,400

21,000

13,900

21,000

13,900

21,000

13,900

14,400

14,400

14,400

14,400

14,400

14,400

.6,700

6,700

6,700

2,600

6,700

2,600

6,700

2,600

5,000-

10,000’

16,500

16,500

16,500

16,500

11,700

11,700

11,700

11,700

11,700

15,500

75,000

75,000

84,000

90,000

105,000

11,700

25,500

15,500

15,500

15,500

15,500

16,500

15,500

15,500

25,500

24,600

16,500

24,600

16,500

24,600

16,500

25,500

25,500

25,500

25,500

25,500

25,000

9,900

9,900

9,900

N.A.

N.A.

N.A.

N.A.

N.A.

1o,ooo15,000’

16,900

16,900

16,900

16,900

13,000

13,000

13,000

13,000

13,000

18,000

75,000

75,000

84,000

90,000

105,000

13,000

41,800

18,000

18,000

18,000

18,000

16,900

18,000

18,000

41,800

27,000

16,900

27,000

16,900

27,000

16,900

41,800

41,800

41,800

41,800

41,800

41,800

10,800

10,800

10,800

N.A.

N.A.

N.A.

N.A.

N.A.

N.A. = nonapplicable.
188 . Appendix B

Table B-*Cont.

State/district

Pennsylvania . . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook Inlet . . . . . . . . . . . . . . . . . . .

Geographic

unit

70

71

72

73

80

81

“Depth category

2,500- 5,000- 1o,ooo0-2,500’ 5,000’ 10,000’ 15,000’

2,300

2,300

2,300

2,300

2,600

2,600

2,600

2,600

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A. I

N.A. IN.A. IN.A.

N.A. N.A. N.A. N.A.

N.A. = not applicable.

Note: normal daily operating expense, surface repair and maintenance exDirect annual operating expense, including waterflooding, in- pense, and subsurface repair; maintenance and services. These are

eludes expenditures for operating producing wells and operating a average expenditures per producttin we//, and include the expendwater injection system. These operating expenditures include the itures of operating an injection system,

Table B-35

Incremental Injection Operating and Maintenance Cost*

(dollars for injection well per year) , ,

State/district

California

East Central . . . . . . . . . . . . . . . . .

Central Coast. . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’wD . . . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>800’WD . . . . . . . . . . . . . . . .

Louisiana

North. . . . . . . . . . . . . . . . . . . . . . .

South. . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<= 200’WD . . . . , . . . . , . . . . . .

201 -400’WD . . . . . . . . . . . . . .

401 -800’WD . . . . . . . . . . . . . .

>=800’WD . . . . . . . . . . . . . . . .

Texas

1 . . . . . . . . . . . . . . . . . . . . . . . . . .

2 . . . . . . . . . . . . . . . . . . . . . . . . . .

3 . . . . . . . . . . . . . . . . . . . . . . . . . .

4 . . . . . . . . . . . . . . . . . . . . . . . . . .

5 . . . . . . . . . . . . . . . . . . . . . . . . . .

6 . . . . . . . . . . . . . . . . . . . . . .

7B” : : : . . . . . . . . . . . . . . . . . . . . . .

7C . . . . . . . . . . . . . . . . . . . . . . . . .

8

8A:::::::::::: :::::::::::: :

9 . . . . . . . . . . . . . . . . . . . . . . . . . .

lo . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore . . . . . . . . . . . . . . . . . . . .

<=200’wD. . . . . . . . . . . . . . . .

201-400’WD . . . . . . . . . . . . . .

401-800’WD . . . . . . . . . . . . . .

>=800'WD . . . . . . . . . . . . . . .

N.A. = not applicable.

Geographic

unit

1

2

3

4

90

91

92

93

5

6

7

95

96

97

98

8

9

10

11

12

13

14

15

16

17

18

19

20

95

96

97

98

0-2,500’

7,700

7,700

7,700

40,000

40,000

40,000

40,000

40,000

6,600

6,000

40,000

40,000

40,000

40,000

40,000

6,600

6,600

6,600

6,600

6,600

6,600

5,400

5,400

5,400

5,400

5,400

6,700

40,000

40,000

45,000

48,000

56,000

Depth category

2,500-

5,000’

6,900

6,900

6,900

40,000

40,000

56,000

48,000

56,000

9,300

8,100

40,000

40,000

56,000

48,000

56,000

9,300

9,300

9,300

9,300

9,300

9,300

5,800

5,800

5,800

5,800

5,800

7,400

40,000

40,000

45,000

48,000

56,000

5,000-

10,000’

11,600

11,600

11,600

50,000

50,000

56,000

60,000

70,000

11,000

10,100

50,000

50,000

56,000

60,000

70,000

11,000

11,000

11,000

11,000

11,000

11,000

7,800

7,800

7,800

7,800

7,800

10,300

50,000

50,000

56,000

60,000

70,000

1o,ooo15,000’

13,200

13,200

13,200

50,000

50,000

56,000

60,000

70,000

11,300

10,600

50,000

50,000

56,000

60,000

70,000

11,300

11,300

11,300

11,300

11,300

11,300

8,600

8,600

8,600

8,600

8,600

12,000

50,000

50,000

56,000

60,000

70,000
—

Appendix B . 189

Table B-35-Cent.

State/district

New Mexico

East . . . . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .

Kansas

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Arkansas

North . . . . . . . . . . . . . . . . . . . . . . .

South . . . . . . . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .

Nebraska

Central . . . . . . . . . . . . . . . . . . . . .

West . . . . . . . . . . . . . . . . . . . . . . .

Mississippi

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Alabama

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Florida

Hi Sulphur. . . . . . . . . . . . . . . . . . .

Lo Sulphur . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ohio

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . .

Kentucky

West . . . . . . . . . . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Tennessee

West ...,..... . . . . . . . . . . . . . .

East . . . . . . . . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaska

North Slope . . . . . . . . . . . . . . . . .

Cook inlet . . . . . . . . . . . . . . . . . . .

N.A. = not applicable.

Note:

Geographic

unit

23

24

25

30

31

32

33

34

35

36

40

41

42

43

44

45

50

53

55

57

58

59

60

61

62

63

64

65

66

67

70

71

72

73

80

81

Direct annual operating expense, including waterflooding, ineludes expenditures for operatlng produclng 011 wells and operating

a water injection system, These operating expenditures Include the

0-2,500’

5,400

5,800

6,700

6,700

6,700

6,700

6,600

6,700

6,700

5,800

10,000

6,600

10,000

6,600

10,000

6,600

5,800

5,800

5,800

5,800

5,800

5,800

4,000

4,000

4,000

1,600

4,000

1,600

4,000

1,600

1,600

1,600

1,600

1,600

N.A.

N.A.

Depth category

2,500-

5,000’

5,800

9,600

7,400

7,400

7,400

7,400

9,300

7,400

7,400

9,600

14,000

9,300

14,000

9,300

14,000

9,300

9,600

9,600

9,600

9,600

9,600

9,600

4,400

4,400

4,400

1,800

4,400

1,800

4,400

1,800

1,800

1,800

1,800

1,800

N,A.

N.A.

5,000-

10,000’

7,800

17,000

10,300

10,300

10,300

10,300

11,000

10,300

10,300

17,000

16,400

11,000

16,400

11,000

16,400

11,000

17,000

17,000

17,000

17,000

17,000

17,000

6,200

6,200

6,200

N,A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

1o,ooo15,000’

8,600

27,900

12,000

12,000

12,000

12,000

11,300

12,000

12,000

27,900

18,000

11,300

18,000

11,300

18,000

11,300

27,900

27,900

27,900

27,900

27,900

27,900

7,200

7,200

7,200

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

N.A.

normal daily operating expense, surface repair and malntenanceexpense, and subsurface repair; maintenance and services These are

average expenditures perproduc(iorrwel~ and include the expendItures of operating an injection system,
190 . Appendix B

Table B-36

State and Local Production Taxes

Includes Severance, Ad Valorem, and Other Local Taxes.

Geographic

State/district unit Tax rate

California. . . . . . . . . . . . . . . .

Louisiana . . . . . . . . . . . . . . . . .

Texas . . . . . . . . . . . . . . . . . . . .

New Mexico . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . .

Kansas , . . . . . . . . . . . . . . . . . .

Arkansas . . . . . . . . . . . . . . . . .

Missouri . . . . . . . . . . . . . . . . . .

Nebraska . . . . . . . . . . . . . . . . .

Mississippi. . . . . . . . . . . . . . . .

Alabama . . . . . . . . . . . . . . . . .

Florida . . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . .

Wyoming. . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . .

Indiana. . . . . . . . . . . . . . . . . . .

Ohio . . . . . . . . . . . . . . . . . . . .

Kentucky. . . . . . . . . . . . . . . . .

Tennessee . . . . . . . . . . . . . . . .

Michigan . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . .

1-4

5-7

8-19

23-24

25

30-31

32-33

34

35-36

40-41

42-43

44-45

50

53

55

57

58

59

60

61

62-63

64-65

66-67

69

70

71

72

73

80-81

0.080

0.129

0.082

0.090

0.071

0.050

0.060

0.050

0.046

0.060

0.061

0.050

0.100

0.050

0.100

0.050

0.050

0.000

0.020

0.050

0.050

0.050

0.050

0.050

0.050

0.050

0.050

0.050

0.080

Source: State tax records.

Offshore Costs

Basic offshore development

costs were placed in one of two

and operating

categories, depending on whether the costs varied or not with

water depth. They were derived from U.S. Bureau

of Mines data and a Lewin and Associates, Inc.,

study for OTA. All costs were updated to

mid-1976 using similar inflation indices as appiied for the onshore cost models.

Costs That Do Not Vary With Water Depth

Three cost items within basic development

and operating costs, while varying by reservoir

Table B-37

State Income Taxes

State Income Tax Rates for Corporations.

Geographic

State/District unit Tax Rated

California . . . . . . . . . . . . . . . . .

Louisiana . . . . . . . . . . . . . . . . .

Texas . . . . . . . . . . . . . . . . . . . .

New Mexico. . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . . . . . . .

Arkansas . . . . . . . . . . . . . . . . .

Missouri. . . . . . . . . . . . . . . . . .

Nebraska . . . . . . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . . . . .

Alabama . . . . . . . . . . . . . . . . .

Florida . . . . . . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . . . . .

‘Utah . . . . . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . . . . . .

North Dakota . . . . . . . . . . . . .

South Dakota . . . . . . . . . . . . .

Illinois . . . . . . . . . . . . . . . . . . .

Indiana . . . . . . . . . . . . . . . . . . .

Ohio . . . . . . . . . . . . . . . . . . . .

Kentucky. ...;.. . . . . . . . . . .

Tennessee. . . . . . . . . . . . . . . .

Michigan . . . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . . . . .

New York . . . . . . . . . . . . . . . .

West Virginia . . . . . . . . . . . . .

Virginia . . . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . .

1-4

5-7

8-19

23-24

25

30-31

32-33

34

35-36

40-41

42-43

44-45

50

53

55

57

58

59

60

61

62-63

64-65

66-67

69

70

71

72

73

80-81

0.09

0.04

—

0.03

0.04

0.04

0.05

0.05

0.05

0.03

0.05

0.05

0.05

0.04

0.05

—

0.06

0.04

—

0.05

0.05

0.05

0.05

0.05

0.05

0.10

0.05

0.05

0.05

‘Percent of value of gross production, paid in year incurred.

Source: Local and State tax records verified by production company data,

depth, are not materially affected by water

depth. These are:

●

●

●

well, lease, and field equipment costs for

producing wells;

New injection equipment for injection

wells;and

Well workover and conversion costs.

These cost data are presented in table B-38.

Air costs (for injection) were set at the same

value as in the in situ combustion cost model.
Appendix B . 191

Table B-38

Offshore Costs That Do Not Vary by Water Depth

(costs in dollars)

I Reservoir depth categories

Activity

0- 2,400-

1

5,000- 10,000-

2,500’ 5,000’ 1 0,000’ 1 5,000’

Well, lease, and field equipment costs per production

well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New injection equipment per injection well . . . . . . .

Well workover and conversion costs per well. . . . . .

300,000

100,000

150,000

300,000

100,000

150,000

300,000

150,000

170,000

300,000

150,000

225,000

Costs That Vary With Water Depth . Incremental injection, operating, and mainThe remaining three offshore development tenance costs.

and operating costs do vary by water depth. These are presented on table B-39. The bases of

These are: the drilling and completion costs are shown in ta-

●

●

Drilling and completion costs,

ble B-40.-This table gives a breakdown of the

drilling and completion costs by water depth.

Basic operating and maintenance costs,

Table B-39

Offshore Costs That Vary by Water Depth

(costs in dollars)

Activity

Drilling and completion costs per foot per well, by

water depth:

<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Basic operating and maintenance costs per well per

year, by water depth:

<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,

Incremental injection operating and maintenance

costs per injection well per year, by water depth:

<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

0-2,500”

112.32

112.32

112.32

112.32

60,000

60,000

60,000

60,000

40,000

40,000

40,000

40,000

— Reservoir depth categories

2,500-

5,000’

96.87

130.64

225.82

522.30

60,000

69,000

72,000

84,000

40,000

46,000

48,000

56,000

5,000-

1 00,000’

101.44

121.49

178.00

354.04

75,000

84,000

90,000

105,000

50,000

56,000

60,000

70,000

100,000-

1 50,000’

97.87

111.24

148.92

266.27

75,000

84,000

90,000

105,000

50,000

56,000

60,000

70,000

“No reservoirs in this depth category-average figure used in water depth categories.
192 . Appendix B

Tabie B-40

Driiiing and Completion Cost Bases

(costs in dollars)

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(lo)

(9)

(lo)

(9)

(lo)

(9)

(lo)

A. 0-200’ WATER DEPTH

(Mean = 100’ WD)

Av. Cost/ft. (Incl. av. platform), JAS, updated . . . . . . . . .

x wghtd. av. depth (JAS) . . . . . . . . . . . . . . . . . . . . . . . . . .

= Av. total cost/well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Av. platform cost (assume 18-slot, 1/2 at 100’, 1/2 at 300’

WD) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

/ Av. No. wells (Assume 18) = Av. platform cost/well. . .

Line (3) – Line (5) = Av. Drilling and completion (D&C)

costs per well ... , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Line (6) / (2) = Av. Drilling cost/ft. (ex. platform) . . . .

Av. platform for depth (1 2-slot) @ $3.9 million / 12 slots

= Platform cost/well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Line (8) / Line (2) = Av. Platform cost/f t.. . . . . . . . . . . . . .

Line (9) + Line (7) “= Av. D&C cost incl. platform . . . . . . .

B. 201-400’ WATER DEPTH

(Mean = 300’ WD)

Line (1) – (6) – See Section A

Line (7) Average drilling cost/ft. (ex. platform) . . . . . . . . .

,Line (8) Av. platform for depth (half 18, half 24, 1/2 @ $8.7

million / 18 dots 1/2@ $11./million / 24 slots . . . . . . . . .

Line (8) / Line (2) (wght. av. depth) = Av. platform

cost/ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Line (9) + Line (7) = Av. D&C cost incl. platform . . . . . . .

C. 401-800’ WATER DEPTH

(Mean = 600’ WD)

Lines (1) – (6) – See Section A

Line (7) Av. drilling cost/ft. (ex. platform). . . . . . . . . . . . . .

Line (8) Av. platform. @ $22.5 million / 24 slots . . . . . .

Line (8) / (2) – Av. platform. cost/ft. , . . . . . . . . . . . . . . . .

Av. D&C costs incl. platform . . . . . . . . . . . . . . . . . . . . . . . .

D. Greater Than 800’ WATER DEPTH

(Mean = 1,000’ WD)

Lines (1) – (6) – See Section A

Line (7) Av. drilling cost/ft (ex. platform) . . . . . . . . . . . . . .

Line (8) Av. platform @ $56.3mm / 24 slots ... , . . . . . . .

Line (8) / Line (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Av. D&C costs incl. platform. . . . . . . . . . . . . . . . . . . . . . . .

2,500-5,000

110.32

4,760

524,020

7,000,000

388,900

135,120

28.45

325,000

68.42

96.87

28.45

485,400

102.19

130.64

28.45

937,500

197.37

225.82

28.45

2,345,800

493.85

522.30

Depth category

5.000-10.000

109.42

8,000

875,360

7,000,000

388,900

486,460

60.81

325,000

40.63

101.44

60.81

485,400

60.68

121.49

60.81

937,500

117.19

178.00

60.81

2,345,800

293.23

354.04

10,000-15,000

103.20

12,000

1,238,400

7,000,000

388,900

849,500

70.79

325,000

27.08

97.87

70.79

485,400

40.45

111.24

70.79

937,500

78.13

148.92

70.79

2,345,800

195.48

266.27
Appendix B . 793

Appendix B

Footnotes

lf~~ar)ce~ Oil Recovery, National Petroleum Council,

December 1976, p. 114.

2VVJ3. cOgartY, Hp. Meabon, and H.W. Milton, Jr.,

“Mobility Control Design for Miscible-Type Waterfloods

Using Micellar Solutions, ” ). Pet. Tech., February 1970, Vol.

22, pp. 141-147.

3E. ojeda, F. Preston, and j.C. Calhoun, “correlation of

Oil Residuals Following Surfactant Floods,” Producers

Month/y, December 1953, pp. 20-29.

4W.B. Gogarty and W.C. Tosch, “Miscible-Typ e

vVaterflooding: Oil Recovery with Micellar Solutions,” ).

Pet. Tech., December 1968, Vol. 20, pp. 1407-1 414; Trans.

AlME, vol. 243.

5L.L. Helm, “use of So[uble Oils for Oil Recovery, ” /. pet.

Tech., December 1971, Vol. 23, pp. 1475-2483; Trans.

A/ME, Vol. 251.

bW. B. Gogarty, “Mobility Control with Polymer Solution,” Soc. Pet. Eng. /., june 1967, Vol. 7, pp. 161-173.

TEnhanced oil Recovery, National Petroleum Council,

December 1976, p. 98.

8J. A. Davis, jr., “Field Project Results with the MarafloodTM Process,” Proceedings, Tertiary Oil Recovery Conference, Tertiary Oil Recovery Project, University of Kansas,

Oct. 23-24, 1975.

9L.w, Helm and R.K. Knight, “Soluble Oil Flooding, ”

Petroleuni Engineer, November 1976, pp. 19-22.

loHH. Danielson, WT. Paynter, and H.W. Milton, Jr.,

“Tertiary Recovery by the Maraflood Process in the Bradford

Field, ” SP[ 4753, Improved Oil Recovery Symposium of

SPE of AlME, Tulsa, Okla., Apr. 22-24, 1974.

I ISA. pursley, R.N. Healy, and El. Sandvik, “A Field Test

of Surfactant Flooding, Loudon, Ill., ” /. Pet. Tech., july 1973,

p. 793.

12M. s, French, G.W. Keys, G.L. Stegemeir, R.C. Ueber, A.

Abrams, and H.j. Hill, “Field Test of an Aqueous Surfactant

System for Oil Recovery, Benton Field, Ill.” /. Pet. Tech.,

February 1973, p. 195.

IIR,H, Wlcjmyer, A. Satter, G.D. Frazier, and R.H. Croves,

“Low Tension Waterflood Pilot at the Salem Unit, Marion

County, Ill. -Part 2: Performance Evaluation,” ). Pet. Tech.,

August 1977, pp. 933-938.

1‘Ibid.

15L.K, Strange ancf A.W. Talash, “Analysis of Salem Lo w

Tension Waterflood Test, ” SP[ 5885, Improved Oil Recovery Symposium of SPE of AlME, Tulsa, Okla., Mar. 22-24,

1976, Preprint.

lsf~~ance~ Oi/ Recovery, National Petroleum Council,

December 1976, p. 98.

ITEn~a~cecf Oil Recovery, National Petroleum Councii,

December 1976, p. 97.

18H.H. Danielson and W.T. Paynter, Bradford Sand M;cel-

/ar-Polymer Flood, Bradford, Pa., Third ERDA Symposium on

Enhanced Oil, Gas Recovery, and Improved Drilling

Methods, Aug. 30-Sept. 1, 1977, p. A-5.

19R.N. Healy, R.L. Reed, and C.W. Carpenter, “A

Laboratory Study of Microemulsion Flooding, ” Soc. Pet. Eng.

]., February 1975, Vol. 15, pp. 87-103, Trans. A/ME, 1975.

ZOMarat~on Oi/ Company: crXTtf7K?rC/d ~ca/e DefT?OnStra -

tion, Enhanced Oil Recovery By Mice/lar-Po/ymer Flooding,

M-7 Project-Design Report, BERC/TPR-77/1, ERDA, April

1977.

ZIC. L. Coffman, “Chesney-Hegberg Micellar-Polymer

Project, El Dorado, Kans.,” Paper A-4, Proceedings, Second

ERDA Symposium on Enhanced Oil and Gas Recovery, Tulsa,

Okla., Sept. 9-10, 1976.

ZZS/oss Fie/d, Amoco Production Co., Improved Oil

Recovery Field Reports, Society of Petroleum Engineers of

AlME, Vol. 1, No. 4, March 1976.

23s. A. Pursley, R.N. Healy, and El. Sandvik, “A Field Test

of Surfactant Flooding, Loudon, Ill. ” ). Pet. Tech., July 1973,

.

p. 793.

Z’Lloyd Elkins, HOW Might the /dependent Move from

Spectator to Participant in the Enhanced Oil Recovery

Game?, Second Tertiary Oil Recovery Conference, Tertiary

Oil Recovery Project, University of Kansas, Apr. 20-21,

1977.

25C.A. Kossack, and H.L. Bilhartz, jr., “The sensitivity of

Micellar Flooding to Reservoir Heterogeneities,” SPE 5808,

Improved Oil Recovery Symposium, SPE of AlME, Tulsa,

Okla., Mar. 22-24, 1976.

2SJ.A. Davis, Jr., Sweep Efficiency In Micel/ar Flooding

Processes, submitted to SPE of AlME, January 1977.

27W. B Gogarty, and W.C. Tosch, “Miscible-Type

Waterflooding: Oil Recovery with Micellar Solutions, ” ).

Pet. Tech., December 1968, Vol. 20, pp. 1407-1 414; Trans.

AlME, Vol. 243.

Z6Marathon Oil Cofnpdny; Commercial Scale Demonstration, Enhanced Oil Recovery By Micellar-Polymer Flooding,

M-7 Project-Design Report, BERC/TPR-77/l, ERDA, April

1977.

zgEnhanced Oi/ Recovery, National f%XrOleUm COUnCil,

December 1976, p. 98.

JOEnhanced Oil Recovery, National Petroleum COUnCll,

December 1976, p. 114.

q6-594 O - 78 - 14
194 . Appendix B

IIA. B. Dyes, B.H. Caudle, md R.A. Erickson, “Oil f%oduc - WC.C+ Bursell, H.J. Taggart, and H.A. De Mirjian, The~ma/

tion After Breakthrough—As Influenced By Mobility Ratio, ” Displacement Tests and Results, Kern River Field, Calif.,

Trans. AlME, 207, 1954, pp. 81-86. Petroleum Industry Conference on Thermal Recovery, Los

Angeles r Calif., June 6, 1966.

3~F. F. Craig, jr., T.M. Geffen, and R.A. Morse, “Oil Recovery Performance of Pattern Gas or Water Injection Opera- 4BW.L. Martin, ).N. Oew, M.L. Powers, and H.B. Steves,

tions From Model Tests,” Trans. A/ME 204, 1955, pp. 7-15. Results of a Tertiary Hot Waterflood in a Thin Sand Reservoir.

IJR. L. Jewett, and G.F. Schurz, “Polymer Flooding—A 49DOD. stokes and T.M. Doscher, “Shell Makes a Success

Current Appraisal, ” ~. Pet, Tech., 22, 675, 1970. of Steam Flood at Yorba Linda, ” Oil and Gas )ourna/, Sept. z,

“E. K. Stevenson, “The Dow Flooding Process: An 1974, pp. 71-76, 78.

Economical Method For Increasing Oil Recovery From

Waterflooding,” Proceedings, Tertiary Oil Recovery Con- $OEn~anced0// Recovery, National Petroleum Cc)unc il,

ference, Tertiary Oil Recovery Project, University of Kansas, December 1976, p. 169.

Oct. 23-24, 1975, p. 79. slD. D. Stokes and T.M. Doscher, “Shell Makes a Success

35H.J. Agnew, “Here’s How 56 Polymer Oil Recovery Proj- of Steam Flood at Yorba Linda, ” Oil and Gas )ournal, Sept. 2,

ects Shape Up, ” Oil and Gas journal, May 1, 1972, pp. 1974, Pp. 71-76,78.

109-112.

. .

S2C.G. Bursell and G.M. Pittman, “Performance of Steam

J6B. Sloat, “oil Production Response From Polymer Treat- Displacement in the Kern River Field, ” /. Pet. Tech., August

ment Urtder Varying Reservoir Conditions, ” Paper 45f, 71st 1975, p. 997.

National Meeting, AIChE, February 1972. sjEnhanced Oi/ Recovery, National Petroleum COUncil,

37H. ]. Agnew, “Here’s How 56 Polymer Oil Recovery Projects Shape Up, ” Oil and Gas /ourna/, May 1, 1972, pp.

109-112.

38J.H. Maerker, “Shear Degradation of Partially Hydrolyzed Polyacrylamide Solutions, ” Soc. Pet. Eng. )., 15, No.

4, pp. 311-322.

39G. Kelco, “Kelzan MF for Viscous Waterflooding,”

Technical Bulletin X2, 1973.

goj. p. Johnson, J.W. Cunningham, and B.M. DuBois, “A

Polymer Flood-Preparation and Initiation at North Stanley,

Osage County, Okla.,” Paper B-2, Second ERDA Symposium

on Enhanced Oil and Gas Recovery, Tulsa, Okla, Sept. 9-10,

1976.

December 1976, p. 170.

S4C.V. Pollack and T.X. Buxton, “Performance of a Forward Steam Drive Project—Nugget Reservoir, Winkleman

Dome Field, Wyo., ” ). Pet. Tech., ]anuary 1969, p. 35.

5~R.V. Smith, A.F. Bertuzzi, E.E. Templeton, and R.L. Clampitt, “Recovery of Oil by Steam Injection in the Smackover

Field, Ark.,” SW 3779, IORS, Tulsa, Okla., Apr. 16-19, 1972.

56A.L. Hall and R.W. Bowman, “Operation and Performance of the Slocum Thermal Recovery Project, ” /. Pet.

Tech., April 1973, p. 402.

szEnhanced c)i/ Recovery, National petroklllll Council,

December 1976, p. 175.

41C.E Tinker, “Coalinga Demonstration Project, Oil SBResearch and Development [n Enhanced oil Recovery

Recovery by Polymer Flooding,” Paper B-3, Second ERDA Final Report, The Methodology, Energy Research and

Symposium on Enhanced Oil and Gas Recovery, Tulsa, Development Administration, Part 3 of 3, ERDA 77-2013,

Okla., Sept. 9-10, 1976. December 1976, pp. V-1 9, 20.

42H.J. Agnew, “Here’s How 56 Polymer Oil Recovery Proj -

sg~nbanced Oi/ Recovery, National petroleum COUnCil,

ects Shape Up, ” Oil and Gas )ournal, May 1, 1972, pp. December 1976, p. 180.

109-112.

OM. K. Dabbous and L.E. Elkins, “Preinjection of polymers

to Increase Reservoir Flooding Efficiency, ” SPE 5836, improved Oil Recovery Symposium, SPE of AlME, Tulsa, Okla.,

Mar. 22-24, 1976.

44v.v. Valleroy, B.T. Willman, J.B. Cambell, and L.W.

Powers, “Deerfield Pilot Test of Recovery by Steam Drive, ”

). Pet. Tech., July 1967, p. 956.

bOResearch and Development In Enhanced oil Recovery

Final Report, The Methodology, Energy Research and

Development Administration, Part 3 of 3, ERDA 77-2013,

December 1976, pp. V-23.

61B.F. Grant and S.E. Szasz, “Development of an Underground Heat Wave for Oil Recovery,” Trans. A/ME, 207, p.

108, 1954.

blResearch and Development In Enhanced oii Recovery

45H,J, DeHaan A j. Van Lockeren, “Early Results of the Final Report, The Methodology, Energy Research and

First Large Scale Steam Soak Project in the Tia juana Field, Development Administration, Part 3 of 3, ERDA 77-2013,

Western Venezuela,” ~. Pet. Tech., 1969, 21 (1), pp. 101-10. December 1976, pp. V-23.

MID. N. Dietz, “1-fot Water Drive, ” Proceedings, 7th World 6JC.S. Kuhn and R.L. Koch, “In-Situ Combustion—Newest

Petroleum Congress, 3, pp. 451-7, Barking, 1967, Elsevier, Method of Increasing Oil Recovery,” Oil and Gas )ournal,

Publ. Co., Ltd. Aug. 10, 1953, pp. 92-96, 113-114.
Gqfnhanced 0;/ Recovery, National petroleum COUnCll,

December 1976, p. 170.

G5D.N. Dietz and j. Weijdemna, “Wet and Partiall y

Quenched Combustion,” ). Pet. Tech., April 1968, p. 411.

GGD.R. parrish and F.F. Craig, jr., “Laboratory Study of a

Combination of Forward Combustion and Waterflooding—

The COFCAW Process,” ). Pet. Tech., June 1969, p. 753.

67C.F. Gates and 1. Sklar, “Combustion As A Primary

Recovery Process—Midway Sunset Field, ” ). Pet. Tech.,

August 1971, pp. 981-986.

G8H.j. Ramey, j., /r-r-Situ Combustion, 8th World

Petroleum Congress, 1971, p. 260.

69w. E. Showalter ancj M.A. Maclean, “Fireflood at Brea -

Ollnda Field, Orange County, Calif., ” SPE 4763, Improved

Oil Recovery Symposium, SPE of AlME, Tulsa, Okla. Apr.

22-24, 1974.

70R w . . Buchwald, W.C, Hardy, and G.S. Neinast, “case

Hlstorles of Three In-Situ Combustion Projects, ” /. Pet.

TL’Ch., ]Uly 1973, pp. 784-792.

‘lBellevue Field, Getty Oil Co., Update Report, improved

Oil Recovery Field Reports, SPE of AlME, Vol. 3, No. 1, June

1977.

TzResearch and Development In Enhanced Oii Recovery,

Final Report, Overview, Part 1 of 3, Energy Research and

Development Administration, ERDA 77-20/1, December

1976, p. 111-2.

‘3W.C. Hardy, P.B. Fletcher, j.C. Shepard, E.W. Dittman,

and D.W. Zadow, “In-Situ Combustion in a Thin Reservoir

Containing High-Gravity Oil,” ), Pet. Tec6., February 1972,

pp. 199-208.

TqEnhanced 0;/ Recovery, National petroieum coUllCll,

December 1976, p. 175.

TSEnhanced 0;/ Recovery, National petroleum coUllCil,

December 1976, p. 175.

76 Enhance~ 0;/ Recovery, National petroleum COUnCll,

December 1976, p. 179.

TTworking Pa Pers’ Technology Task Force, National

Petroleum Council EOR Study, Apr. 21, 1976.

T8Research and Development In Enhanced Oil Recovery

Final Report, The Methodology, Energy Research and

Development Administration, Part 3 of 3, ERDA 77-2013,

December 1976, p. V-31.

79H A. Koch, Jr., and R.L. Slobad, “Miscible Slug PrOCeSS, ”

/. Pet. “Tech., February 1957, p. 40.

BON,j. Clark, H.M. Sheaun, W.P. Schultz, K. Gaines, and

J.L. Moore, “Miscible Dr~ve—lts Theory and Application, ” /.

Pet. Tech., June 1958, p. 11.

81~e$earch and f)eve/opment in Enhanced 0// Recovery,

ERDA 77/20, Lewin and Associates, Inc., December 1976,

Part 1, pp. III-2.

8ZL.W. Helm, “Status

Oil Recovery Methods, ”

Meeting of Society of

Sep. 1 -Oct. 28, 1975.

83L, w. Helm and V.A.

Appendix B . 195

of COl and Hydrocarbon Miscible

SPE 5560, presented at 50th Annual

Petroleum Engineers, Dallas, Tex.

josendal, “Mechanisms of Oil Displacement by Carbon Dioxide,” /. Pet. Tech., December

1974, p. 1147.

134D. F. lvkrrzie and R.F. Nielson, “Study of Vaporization

of Crude Oil by Carbon Dioxide Repressuring, ” /. Pef. Tech,,

November 1963, p. 1247.

85L.W. Helm and VA. josendal, “Mechanisms of oil Displacement by Carbon Dioxide, ” ). Pet. Tech., December

1974, p. 1147,

WL W, Helm, “status of Coz and Hydrocarbon Miscible

Oil Recovery Methods, ” 5f’E .5560, presented at 50th Annual

Meeting of Society of Petroleum Engineers, Dallas, Tex.

Sep. 1 -Oct. 28, 1975.

87L. W. Helm and VA Josendal, “Mechanisms of oil Displacement by Carbon Dioxide,” ). Pet. Tech., December

1974, p. 1147.

‘8J.J. Rathmell, F.i. Stalkup, and R.c. Hassinger, “A

Laboratory Investigation of Miscible Displacement by Carbon Dioxide, ” SPE 3483, 46th National Meeting, Society of

Petroleum Engineers, New Orleans, La., Oct. 3-6, 1971.

agResearCh and Development in Enhanced Oil Recovery

ERDA 77/20, Lewin and Associates, Inc., December 1975,

Part 1, pp. III-2.

90F.1. Stalkup, “An Introduction to Carbon Dioxide Flooding,” Proceedings, Tertiary Oil Recovery Conference, Tertiary Oil Recovery Project, University of Kansas, April 1977.

91R.M. Dicharry, T.L. Perryman, and J.D. Ronqullle,

“Evaluation and Design of a COl Miscible Flood Project O

SACROC Unit, Kelly-Snyder Fiefd,” /. Pet. Tech., November

1973, p. 1309.

9ZR.M. Dicharry, T.L. Perryman , and J.D. Ronquille,

“Evaluation and Design of a COl Miscible Flood Project O

SACROC Unit, Kelly-Snyder Field, ” ). Pet. Tech., November

1973, p. 1309.

93E0R workshop on Carbon Dioxide, Sponsored by

ERDA, Houston, Tex., Apr. 12, 1977.

gqEnhanced Oi/ Recovery, National Petroleum Council,

December 1975, p. 144.

gslmproved 011 Recovery Field Reports, Society of

Petroleum Engineers of AlME.

%Research and Development In Enhanced oil Recovery

Final Report, The Methodology, Energy Research and

Development Administration, Part 3 of 3, ERDA 77-2013,

December 1976, pp. V-1 9, 20.

g~Research and Development In Enhanced oil Recovery

Final Report: The Methodology, Energy Research and

Development Administration, Part 3 of 3, ERDA 77-2013,

December 1976, pp. V-1 9, 20.
Appendix C

Legal Aspects of Enhanced

Oil Recovery

Page

INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......................199

UNITIZATION: VOLUNTARY AND Compulsory . ..........................199

Basic principles of Oil and Gas Law. . . . . . . . . . . . . . . . . . . .................199

The Rule of Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............201

Conservation Regulation: Well Spacing and Prorationing. . . . ... ... ....202

pooling and Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............202

Pooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........202

Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203

Voluntary Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............203

Time of Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............203

Who May Unitize . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....203

Negotiation of Unit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...204

Compulsory Unitization . . . . . . .. .. .. . . $ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211

Procedure for Fieldwide Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213

Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................213

Proof of Findings Required . . . . . . . . . . . . . . . . . . . . . . . ................213

Entry of the Order for Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214

Amendment and Enlargement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....215

Effect of Unitization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215

Allowables and Well Spacing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...216

Administrative and Judicial Encouragement to Unitization . . . . . . . .. ....216

APPROVAL OF ENHANCED RECOVERY PROJECTS. . ..........................217

Permit Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................217

Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .217

Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................218

Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218

Order . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........................219

Injection Regulations Under the Safe Drinking Water Act. . ................219

OPERATIONAL ASPECTS OF ENHANCED OIL RECOVERY . . . . . . . . . . . . . . . . . . . . . . 221

Potential Liability to Conjoining Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

Environmental Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223

Environmental Impact Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...223

197
Page

Air Pollution, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224

Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224

Other Environmental Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

Water Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

Lessor-Lessee Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

Riparian and Appropriation Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226

State Regulation of Water Use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227

LIST OF TABLES

Table

Number Page

c-1 Unitization Statutes: Voluntary and Compulsory . . . . . . . . . . . . . . . . . . . . . . . 228

c-2 Comparative Chart of Aspects of State Unitization Statutes. . . . . . . . . . . . . . 229

198
Appendix C . 199

Introduction

The purpose of this appendix is to provide

details of legal issues associated with enhanced

oil recovery (EOR). The term “enhanced oil

recovery” refers to any method of oil production

in which gases and/or liquids are injected into

the reservoir to maintain or increase the energy of

the reservoir or react chemically with the oil to

improve recovery. Thus, enhanced recovery encompasses the techniques referred to as pressure

maintenance, secondary recovery, and tertiary

recovery. The reason for the broader use of the

term in this section is the fact that the legal

problems are much the same for any technique of

oil recovery beyond primary methods. There has

been relatively little commercial application of

tertiary recovery techniques, so no body of case

law specifically regarding it has developed; the

law in this area must draw upon experience in

pressure maintenance and established methods

of secondary recovery. Secondly, the regulatory

schemes of most States do not distinguish among

the different types of recovery beyond primary

methods. Distinctions among the various techniques of enhancing recovery will be made only

when necessary.

To assess fully how the law encourages, hinders, limits, or prevents employment of EOR

techniques, it would be necessary to examine in

detail each reservoir in which such techniques are

or might be used. Such was beyond the scope of

this assessment. The approach used here identifies existing or possible constraints without attempting to suggest how much more or less oil

could be produced with or without particular

constraints. Statutes, regulations, and rules of law

affecting EOR are described in a general way

without discussing their applicability to particular

fields, not only because the complex interplay

among various factors makes specific judgments

about individual fields very difficult, but also

because the law on some important points is undecided or very uncertain in most jurisdictions.

The views of producers and State regulatory personnel are discussed when appropriate, as are the

observations and comments of legal authorities

on particular subjects.

Unitization: Voluntary and Compulsory

Basic Principles of Oil and Gas Law

The most efficient means of utilizing EOR techniques is generally to treat the entire oil reservoir

as though it were a single producing mechanism

or entity. There is no problem with this when the

operator of the field owns the leasehold or

mineral interest throughout the entire reservoir;

in this case obtaining the consent of any other

owner of an interest in the minerals in order to

undertake enhanced recovery operations is unnecessary. However, where there are other

owners of interests in the same field, obtaining

consent may be necessary before fieldwide

operations may be commenced. In order to better understand the problems that may be involved in securing this consent or cooperation, it

would be useful to describe briefly the basic legal

framework in which oil and gas operations take

place.

The right to develop subsurface minerals in the

United States belongs originally with the ownership of the surface. The different States which

have fugacious minerals within their jurisdiction

are divided as to whether such minerals are

owned in place or whether the surface owne r

owns only a right to produce the minerals that

may lie beneath his land. For present purposes

the distinction has little significance. It is sufficient to point out that the ownership of the surface carries with it, as a normal incident of

ownership, the right to develop the minerals

beneath the surface.

The owner of the land may, however, sever the

ownership of the surface from ownership of the

minerals. He may convey away all or a part of his

interest in the development of the minerals and

in so doing may create a variety of estates, Thus,

for example, the owner of a 640-acre tract of land
200 . Appendix C

(one section) may convey to another person (or

company) all of the mineral under the land absolutely. Or he may convey to that person a onehalf interest, or some other percentage of interest, in all of the minerals beneath the section.

Or again, he may convey to another all or a part

of the minerals beneath a specific 40-acre tract

carved out of the section. Each of these interests

would be described as a mineral interest. Unless

otherwise restricted by the instrument creating it,

the ownership of a mineral interest carries with it

the right to explore for, develop, and produce the

minerals beneath the land.

Another type of interest that may be created

by a landowner or mineral interest owner is a

leasehold interest. The owner of the minerals is

normally unable to undertake the development

of the minerals himself because of the great expense and risk of drilling. in order to obtain

development without entirely giving up his interest in the minerals he will lease the right to explore for and produce the minerals to another. In

return the lessee will pay a sum of money as a

bonus for the granting of the lease and will promise to pay the lessor a royalty, generally oneeighth, on all oil and gas produced. Typically, the

lessee will be granted the lease for a period of 1

to 5 years (the primary term), subject to an

obligation to pay delay rentals if a well is not

drilled in the first year, and so long thereafter as

oil and gas or either of them is produced from the

leased land (the secondary term). In addition to a

royalty interest of one-eighth, the lessor will retain a possibility of reverter; that is, if the delay

rentals are not paid on time or production is not

obtained within the primary term, or if production ceases on anything other than a temporary

basis in the secondary term, the interest leased

reverts automatically back to the lessor.1 When

the interest reverts, the lessor may then enter into

a new lease with another party or may undertake

or continue development himself.

The power to grant leases is often described as

the executive right, and a mineral interest may be

created with the executive power being granted

to another person. To illustrate, A as father of a

NOTE: All references to footnotes in this appendix appear

on page 230.

family and owner of a tract of land may give by

will to child B a one-quarter undivided interest in

the minerals in the land, to child C a one-quarter

undivided interest in the minerals, and to child D

an undivided one-half interest in the minerals

together with the executive right to lease all the

minerals. This would mean that only D could execute leases for the development of the minerals.

D would be under a duty to exercise the right

with the utmost good faith and fair dealing. Each

child would receive a share of the proceeds from

the development of the land (i.e., a share of the

bonus, rental, and royalties), but it would be

upon the terms established by D in his dealings

with the lessee in granting the lease. Under wellestablished principles of law, D must exercise this

right in such a manner that it does not unfairly advantage him nor unfairly disadvantage the

owners of the nonexecutive interests, children B

and C. The duties owed by lessees to lessors and

royalty owners, and the duties owed by executive right owners to nonexecutive right owners,

can impact upon the unitization of mineral lands

for enhanced recovery purposes. This is because

the lessee or executive right owner must consider

not only his own interest but the interests of

those to whom he owes a duty in entering into

agreements for unitized operations.

In addition to duties, the lessee has certain

rights arising from a lease that have significance

for EOR, These rights may be express or they may

be implied. They are express if the parties to the

lease or deed have specifically recognized or

granted them in the conveyance. For example,

the parties may explicitly provide that the lessee

shall have the right to conduct certain activities

such as laying pipelines on the surface of the land

without being liable in damages. The rights are

implied if the parties have not expressly provided

for them, but the law recognizes that they exist

by virtue of the nature of the transaction between or among the parties. Thus, the lessor and

lessee may fail to provide expressly that the

lessee has the right to come upon the leased land

or to build a road for carrying equipment to a drill

site. The law will imply that the lessee has the

right to do this when it would not be reasonably

possible to develop the minerals without undertaking such activity.
Appendix C . 201

Briefly stated, the law recognizes that even

without express grant, the lessee has the right to

use such methods and so much of the surface as

may be reasonably necessary to effectuate the

purposes of the lease, having due regard for the

rights of the owner of the surface estate. It is well

established that the lessee does have such

rights. 2 However, the question may arise whether

such rights are limited to those activities, either

surface or subsurface, that could be contemplated at the time of the execution of the lease or

deed. The same answer should be given for the

more exotic methods of enhanced recovery that

the courts have given for traditional waterflood

operations when these were not provided for in

the lease. In allowing a waterflood project to go

forward, the Appellate Court of Illinois stated in a

1950 case:3

The mere fact that this method of production is

modern is no, reason to prevent its use by a rule

of law. It is true the contract of the parties does

not specifically provide for this process, but

neither does it specify any other process. The

contract being silent as to methods of production, it must be presumed to permit any method

reasonably designed to accomplish the purpose

of the lease: the recovery of the oil and the payment of royalty. The court would violate fundamental principles of conservation to insert by implication a provision that lessee is limited to production of such oil as can be obtained by old

fashioned means, or by so-called “primary operations.”

The same rationale would apply to more

modern methods of enhanced recovery, even

though these methods might involve somewhat

greater use of the surface and different types of

injection substances.

A closely related question is the extent to

which the lessee or mineral grantee may use

water located on the property for purposes of

enhanced recovery. This has been an area of

some controversy and will be taken up in a later

section because it involves matters going beyond

lease and deed relationships.

Finally, it should be noted that some

authorities have contended that there is not only

a right for the lessee to unitize or to undertake

enhanced recovery activities but also a duty to

do so. The implied covenant of reasonable

development is well recognized in oil and gas

law.

5 It is to the effect that the lessee has the

duty, where the existence of oil in paying quantities is made apparent, to continue the development of the property and put down as many

wells as may be reasonably necessary to secure

the oil for the common advantage of both the

lessor and lessee. The lessee is expected to act as

a prudent operator would in the same circumstances. With increasing experience with

enhanced recovery, it can be argued that a prudent operator would, when it appears profitable,

undertake enhanced recovery operations. Thus,

where the lessee is reluctant to do so, the lessor

might be able to require the lessee to engage in

such operations or give up the lease. Probably

because of the difficulty or proof of profitability

and feasibility for a particular reservoir there has

been little litigation on the point. However, one

court has noted that there is “respectable

authority to the effect that there is an implied

covenant in oil and gas leases that a lessee

should resort to a secondary recovery method

shown to be practical and presumably profitable

as a means of getting additional return from the

Iease. ”

6 In another case the court similarly

declared that “the Lessee not only had a right,

but had a duty to waterflood the premises for the

recovery of oil for the benefit of the mineral

owners should it be determined by a prudent

operator to be profitable. ”7 Lessors then could

encourage enhanced recovery by making demands on their lessees.

The Rule of Capture

One of the most important and fundamental

principles of oil and gas law is the rule of capture.

It stems from the fact that oil and gas are

fugacious minerals; that is, they have the property of being able to move about within the reservoir in which they are found. Followed by every

jurisdiction within the United States, the rule of

capture is to the effect that a landowner may produce oil or gas from a well located on his land

even if the oil or gas was originally in place under

the surface of another landowner, so long as the

producer does not physically trespass on the

other’s land. The other landowner’s recourse

against drainage of the petroleum under his property is the rule of capture itself: he may himself

drill a well and produce the hydrocarbons and
202 . Appendix C

thereby prevent their migration to the property of

another.

The problem with the rule of capture has been

that it encouraged too rapid development of oil

and gas. A landowner or his lessee must drill to

recover the oil and gas beneath his property or

they will be recovered by a neighbor and lost

forever to the landowner. The problem became

especially acute when there were many small

parcels of land over a single reservoir. Overdrilling resulted from the rush to recover the oil and

gas before it is produced by another, and the

overdrilling caused the natural pressure of the

reservoir to be depleted too rapidly, thereby

leaving oil in the ground that could have been

recovered with sounder engineering practices.

Conservation Regulation: Well Spacing and

Prorationing

Recognizing that the rule of capture was resulting in great loss of resources and excessive production of oil, the producing States began enacting legislation to modify it in the mid-1930’s. To

prevent excessive drilling the States authorized

regulatory commissions to promulgate well spacing rules, limiting the number of wells that can be

drilled in a given area.8 For example, the Texas

Railroad Commission in Rule 37 allows, as a

general rule, only one well every 40 acres. In

general, in each major producing State special

spacing rules may be established for each

different field and exceptions may be granted

upon showing of good cause.9

Well spacing alone would not be enough to

overcome the problem of excessive production,

for a producer might continue to produce at an

excessive rate in such a manner as to deplete prematurely the natural drive of the reservoir or in

quantities that the market could not absorb. To

overcome this, the States established well

allowable; that is, they set a limit to the amount

of oil or gas that could be produced in any 1

month from a field or well. This is also known as

prorationing of production. Well allowable have

been set in two different ways. The first is known

as MER regulation: allowable are established for

production at the maximum (or most) efficient

rate of recovery.10 The maximum efficient rate for

a reservoir is established before a regulatory commission by expert testimony as to what would injure the reservoir and produce waste. This rate is

not constant, but changes with the age of the

field, and is not generally capable of exact computation. The second basic type of regulation of

well allowable is known as market demand

regulation: MER remains as the maximum rate of

production, but the rate actually allowed may be

lowered to a level which the commission

believes is the maximum amount of production

that the market will bear for that month. This is

generally established by the commission after it

has heard from producers as to the amount that

they would like to produce. The commission may

wish to give special incentives to certain types of

activity and will establish allowable with more

being allowed for one type of production than

another. To encourage drilling the commission

may allow new wells to produce at the reservoir’s

maximum efficient rate of recovery, while older

fields must produce at a lower rate, so that total

production from the State does not exceed the

anticipated reasonable market demand. With

the exception of Texas in recent months, the

market-demand type States have set allowable

for wells at the maximum efficient rate for every

month since 1973.

Pooling and Unitization

Pooling

State regulation of well spacing and production can cause significant problems that must be

overcome by the producers themselves or by additional regulations. If there can be only one well

within a given area and there are several parcels

of land with different owners, some determination must be made as to who will be able to drill

a well and who will be entitled to receive proceeds from the production from the well. The integration of the various interests within the area

for the purpose of creating a drilling unit for

development of a well and sharing of the proceeds is known as pooling.11 It may be voluntary

if the interest owners come together and agree

by contract upon the drilling and sharing of the
production from the unit well. It may be compulsory if the State forces interest owners to participate on a basis established by the State

regulatory commission when there is an applicant

who wishes to drill and some of the interest

owners are unwilling or unable to reach an agreement upon sharing of development cost and/or

production. Pooling then refers to the bringing

together of the different interests in a given area

so as to integrate the acreage necessary for

establishing a drilling unit, and it may be voluntary or compulsory. Virtually all States with production of oil or gas have compulsory pooling

statutes which can apply when the parties are

unable to reach an agreement for voluntary pooling.

Unitization

Pooling does not result in the reservoir being

treated as a single entity; it does reduce the number of competitive properties within a reservoir,

but there will still be competitive operations

among the enlarged units to the extent permitted

by law.

The mo efficient and productive method of

producing oil may be achieved only if the entire

reservoir can be treated as a single producing

mechanism, i.e., when the reservoir may be operated without regard to property lines. This

becomes possible when one owner or lessee

owns or leases the rights to the entire reservoir or

when all the interest holders in the reservoir unite

for a cooperative plan of development. When

owners of interest do come together for such a

purpose for development of most or all of a reservoir this is referred to as unitization.12 It is much

the same in principle as pooling, for it is an integration of interests, and as with pooling it may

be voluntary or compulsory; but it is much more

complex than pooling in attempting to reach

agreement on cost and production sharing, and

the statutory schemes for compulsory unitization

are more difficult to comply with than for compulsory pooling. Unitization of most or all of a

reservoir is usually very desirable or is required in

order for there to be application of enhanced

recovery techniques to a reservoir.

Voluntary

Time of Unitization

Appendix C ● 203

Unitization

Ideally, unitization should take place at the

first discovery of a reservoir capable of producing

hydrocarbons in commercial quantities, or even

during the exploration phase. However, this is

not feasible for it is only through drilling a number of wells—with production from the first well

and subsequent welIs going on—that the

parameters of the reservoir can be established.

Only when the characteristics and the limits of

the field are generally known will the parties with

an interest in the field be willing to unitize. Prior

to that time they would possibly agree to share

production of petroleum from under their lands

with parties who had no petroleum under theirs.

It is only after extensive drilling that it is possible

to make an intelligent assessment of the basis

upon which participation in the production from

the reservoir should be established. Because of

this, unitization has generally come about after

the primary drive of the reservoir has begun to

decline measurably, and it has appeared to interest owners that it may be desirable to unitize

in order to undertake

recovery beyond the

methods of recovery.

Who May Unitize

operations to enhance

field’s life by primary

Once it is clear to some of the parties with interest in the reservoir that unitization is desirable,

there is the problem of determining who may undertake the unitization. Without express

authorization, either in the lease or by separate

agreement, the lessee is not able to unitize the

interest of the royalty owners to whom it must

pay royalty. The lessee may unitize its own interest—that is, agree to share with another the

seven-eighths of production that it normally

owns-but without the consent of the royalty

owner(s) it may not agree with others to treat the

potential production attributable to the royalty

interest from the leased acreage on any basis

other than the one-eighth (or other fraction)

going to the royalty owners. Some leases will
— .— — —

204 . Appendix C

contain authority to the lessee to enter into fieldwide unitization agreements on behalf of the

lessor, but the noted authority on unitization,

Raymond M. Myers, has stated that “[d]ue to the

complexity of the modern unitization agreement,

a clause authorizing the unitization of the entire

field, or a substantial portion thereof, has not

generally appeared in oil and gas leases. Lessors

have not generally been willing to grant such

broad powers to lessees as such authorization

would entail. ”13 Even with authorization the prudent lessee will gain the express consent of the

lessor. Whether the executive right owner may

unitize, or authorize the lessee to unitize, the interests of the nonexecutive interests are open to

question in most jurisdictions because there has

been little litigation on the point.14 The rule in

Texas is that the executive does not have this

power; the rule in Louisiana is that he does. In

general, it may be stated that it is desirable or

necessary to get the express consent of each

royalty owner in order to effectuate voluntary

unitization.

Reaching agreement on unitization is a complex and drawn out undertaking often involving

dozens or hundreds of parties. To understand this

and to place in perspective the State’s role in

unitization of property for purposes of enhanced

recovery, it would be useful to examine in some

detail the manner in which unitization is agreed

upon.

Negotiation of Unit Agreement

The integration of separate and often

divergent ownership interests necessarily requires careful negotiation which may extend over

several years. The best way to describe effectively the nature of and the problems inherent in

the voluntary unitization process is to relate the

actual experiences of companies. The discussion

of the process which follows draws in part from

the case history of the McComb Field Unit in Pike

County, Miss., 15 and from the Seeligson Field Unit

in Jim Wells and Kleberg Counties, Tex.16

In the evolution of a voluntary unit, each

negotiation has its own unique problems and circumstances which affect the ability of principals

to achieve fieldwide unitization in a reasonable

period of time. Even though no two unit operations are alike in every respect, there appear to

be four general stages in the negotiation process:

. Initiation of joint organization,

● planning period,

. Determination of participation formula, and

. Drafting and approval of agreements.

The remainder of this appendix is concerned with

the discussion of these four stages and their integration during the formation of a voluntary unit

operation.

Initiation of Joint Organization.—The first stage

in the unitization process involves the initiation

of a joint organization of operating interests who

recognize the necessity for a fieldwide unit in

order to increase the ultimate recovery of oil and

gas. A major operator or Ieaseowner will usually

initiate the process by informing other ownership

interests that a unit operation may be desirable

for undertaking a particular fieldwide project for

enhanced recovery.

For example, shortly after primary production

was undertaken in the McComb Field, the

coowner of the discovery well and major

leaseowner (Sun Oil Co.) began accumulating additional technical information and data with

respect to the parameters of the reservoir. The

data revealed an alarming condition in the reservoir-a rapid decline in reservoir pressure which

could bring premature abandonment with a tremendous loss in recoverable oil reserves. It was

apparent that a fieldwide gas- or water-pressure

maintenance project was needed to arrest the

deterioration of the reservoir and increase ultimate recovery. This pressure maintenance project required fieldwide unitization which, in turn,

required full-field participation. A meeting was

held in February 1960, at the urging of the Sun

Oil Co., and the preliminary evidence was presented to 70 operating interests.

The initial stage of the Seeligson Field Unit

negotiation involved a different set of circumstances. Numerous tracts in the field contained

gas, oil, or both. A gas-unit operation had existed

since 1948, and the current problem was to unitize both oil and gas under one set of agreements.

In particular, the proposed new unit operation
was primarily concerned with the increased oil

production that would result both from the

transfer of allowable and from a pressure maintenance program. Thus, operators having had

previous negotiation experience could facilitate

matters with the negotiation of a new unit agreement. A meeting was called in February 1952, to

discuss just such a possibility.

In specific terms, the initiation of a joint

organization entails three primary steps. First,

after a discussion of the preliminary technical information and data, operators reach a general

agreement on the “problem” giving rise to the

necessity for a unit operation. Once the problem

is identified and clearly defined, then possible

solutions for consideration can be enumerated.

During this initial step and the steps that

follow, obstacles or delays may be encountered

when the joint organization involves a large number of participants. If an inordinate number of

operators have had little or no first-hand unitization experience or technical knowledge of the

proposed solution projects, or where misunderstandings or suspicions develop, then unnecessary delays may occur in the formation of a joint

organization.

The next step encompasses the acceptance of

the articles of organization which establish the

organizational framework and procedural rules

for the initial operating committee (Unitization

Committee) and ancillary subcommittees. The

Unitization Committee is a temporary body

charged with supervising the collection of extensive information and data germane to the formation of the unit as well as presiding over the

general negotiations prior to the approval of the

unitization agreements. The composition of the

Unitization Committee and the various subcommittees requires an acceptable representation of

major and independent leaseowners. This will

provide a major step in spreading the responsibilities for unit formation among all parties interested in the fieldwide operation and also to

minimize the potential misconceptions and

mistrust which may develop among operating interests.

The final step in the initiation of the joint

organization involves financing of the temporary

organizational structure. Rather than the major

Appendix C ● 205

leaseowner bearing the full costs, financial

responsibility is generally shared according to

some acceptable method of cost allocation. In

the McComb Field, expenses were shared jointly

on a well basis.

Generally, the initial stage in the negotiation

process does not require more than a few meetings to finalize the temporary procedures for the

joint organization. Given sufficient preliminary

evidence, most operators recognize the necessity

for careful planning and thorough investigation in

the development of a fieldwide unitization

operation.

Planning Period.—The second stage in the

negotiation process centers around the planning

period, which culminates in the unitization agreements. This stage involves the activities of

various subcommittees who are responsible for

collecting extensive data and information and for

developing the details for the unit operation. In

general, there are four main areas of concern:

technical, legal, land, and accounting.

Technical. The gathering of technical data and

information is the joint responsibility

of a Geologic Subcommittee and an

Engineering Subcommittee.

The Geologic Subcommittee prepares the

various geological maps and accumulates

field data necessary for study by the joint

organization. In particular, their duties

center around ascertaining the extent of the

reservoir in terms of its size, shape, and

geological limits. Aside from the extent of

the reservoir, this subcommittee is concerned with mapping the thickness, structural position, and extent of the “productive” pay of the reservoir. information

gathered by the Geologic Subcommittee is

made available to the Engineering Subcommittee for the evaluation of the various projects under consideration and to operators

for determining oil recovery factors under

various operating conditions. This is an important phase in the negotiation process,

due primarily to the fact that the technical

feasibility and economic profitability of

various projects are evaluated and recommendations submitted to the Unitization

Committee for consideration by the joint

organization.
206 . Appendix C

The task of this subcommittee is best

illustrated by the Engineering Subcommittee of the McComb Field Unit. As the reservoir data were assembled, oil recovery factors were derived under five operating conditions:

1.

2.

3.

4.

5.

Primary recovery (18 percent recovery

factor);

Injection of produced gas (increase

ultimate recovery to 23 percent);

Gas pressure maintenance (increase

ultimate recovery to 30 percent);

Water pressure maintenance (increase

ultimate recovery to 39 percent); and

High-pressure miscible gas injection

(increase ultimate recovery to 54 percent).

Based on these oil recovery factors the

water pressure maintenance and high-

-pressure miscible gas injection projects

were selected for further feasibility analysis,

where the advantages and disadvantages of

each project were then evaluated.

While the miscible gas injection project

offered the highest oil recovery factor, its

disadvantages were extremely critical: the

supply of extraneous gas was available but

at prohibitive costs; the process was

relatively unproven in terms of general industry-wide use; there existed possible corrosion problems as well as contamination of

reservoir gas; the project would require a

long period of time to implement and

would require expensive plant expansion;

and, finally, there was a greater risk of

failure. Furthermore, the rate of return for

the capital investment was calculated to be

31 percent per year.

The advantages of the waterflood project

were numerous: ample supply of salt water

in the reservoir; relatively lower initial investment expenditure; proven method of

recovery with a low risk of failure; minimum

time required to implement the project; and

undertaking the waterflood project did not

preclude the adoption of miscible injection

at a later date. In addition, the capital investment was calculated to earn a 72-percent annual rate of return. Finally, the primary disadvantage of waterflooding was the

relatively lower oil recovery factor.

After careful consideration of the

economic feasibility and advantages and

disadvantages of each project, the technical

subcommittees recommended the selection

of the water pressure maintenance project

for the McComb Field Unit Operation.

Aside from the higher rate of return on

capital investment, the major factors which

led to the waterflood selection involved the

minimum risk of failure and the short implementation time associated with the project.

These factors were extremely crucial, given

the rapidly declining pressure in the reservoir.

Once the extensive geologic data and

engineering information are accumulated

and project recommendations set forth, the

final task of the technical subcommittees involves a preliminary determination of the

participation formula whereby lessors and

lessees share in unit production. The relevant aspects of the participation formula

will be considered later in this appendix,

but it should be noted that the time frame

for the work of the technical subcommittees

can vary considerably. For the Seeligson

Field Unit, the Unitization Committee appointed working interest representatives to

the technical subcommittees in February

1952, and the Engineering Subcommittee

offered recommendations (with respect to

the most feasible project and the tentative

participation formula) to a meeting of

operators in January 1955. Hence, nearly 3

years had elapsed during which time the

major technical groundwork for the unit

operation was completed. For the McComb

Field Unit, the work of the technical subcommittees was initiated in February 1960

and recommendations and findings were

presented approximately 9 months later,

Therefore, the time required for collecting

and evaluating detailed technical information and the subsequent recommendations
Appendix C . 207

which follow can consume from several

months to a few years during the unitization

process, In general, a number of factors such

as the geological complexity of the reservoir, the number of development wells

necessary for assessing the characteristics of

the reservoir, the nature of the unitization

projects under consideration, and whether

the field is in the development phase or production phase may all contribute to the

length of time required for the planning

period.

Legal. During the planning of a fieldwide unit,

the Legal Subcommittee handles the legal

aspects associated with the unitization

process and the subsequent negotiation and

drafting of agreements. This charg e

necessarily requires an understanding of the

desired goal of the unit operation and the

manner in which this goal impacts on land

titles, overriding royalties, operating leases,

and other factors. In particular, the Legal

Subcommittee determines whether there

are any legal restrictions or problems related

to property rights and the achievement of

the desired goal of the unit. It is incumbent

upon the Legal Subcommittee to advise

lessees that they continue their lease obligations to lessors. The Legal Subcommittee

must ensure that the implied as well as expressed obligations of lessees are satisfied

during the negotiation and execution of a

unitization agreement.

The Legai Subcommittee is also responsible for submitting to the appropriate State

regulatory agency all requisite documents

and instruments which pertain to the unit

operation. Such procedures will be discussed in a subsequent section.

Land. The Land Subcommittee is generally

comprised of land agents whose function it

is to identify royalty owners and

leaseholders for the purpose of communicating information to the various interest owners and facilitating the acceptance of the unitization agreements. While

operating interests may be readily identifiable, a widespread distribution of royalty interests can make the task of the Land Subcommittee difficult and time consuming.

Frequently, overriding royalties, various

types of working-interest arrangements, and

royalty interests involving estates or trusts

may add both time and expense to the complexity of forming a unit.

Once the majority, if not all, of the interested parties are identified, the land

agents are responsible for conveying to the

ownership interests, information with

regard to the nature of the unit operation

(in terms of the project to be instituted as

well as each owner’s share in unit production). The work of the Land Subcommittee

begins in the planning stage of the unitization process and ends with the obtaining

of signatures for the unit agreements.

Accounting. The initial concern of the Accounting Subcommittee involves the accounting for expenses incurred prior to the

unit agreement. The work performed by the

technical subcommittees and, to a lesser extent, the other subcommittees operating

during the planning period generates

expenditures which must be underwritten

by the operating interests. Accounts are

maintained by the Accounting Subcommittee and subsequent billings to operators on

a predetermined share basis are made for

purchases of supplies and field equipment

as well as the overhead costs of the temporary joint organization.

The primary charge of the Accounting

Subcommittee, however, is to prepare the

joint operation accounting procedures

which establish the method of accounting

and the allocational rules to be used in the

unit operation. The accounting procedures

appear as an exhibit to the proposed unit

agreement and specify the items to be

charged to the joint account, the disposition

of lease equipment and material, the treatment of inventories, and the method of

allocating joint costs and revenues among

unit participants.

An important role of the Accounting Subcommittee entails the explanation and, in

some cases, the determination of specific

tax considerations which impact on ownership interests as well as the general fieldwide operation. For example, tax legislation
. . .

208 . Appendix C

and tax court interpretations with respect to

EOR projects are ever-changing, and the application of future tax law to EOR projects

is in a state of uncertainty. Therefore, the

tax treatment applied to EOR projects might

affect the incentive among participants of a

proposed unit operation to engage in a particular EOR project or it could affect the incentive of an individual ownership interest

to commit its property rights to the unit

operation.

An example where a possible disincentive

exists for joining a unit operation can be

seen in the Income Tax Reduction Act of

1975, which eliminated the percentage oildepletion allowance for major companies.

However, an exemption to this is provided

for independent producers and royalty

owners where an independent producer is

defined as one whose total retail sales is less

than 5 percent of its total sales. When this

exemption is applied, the independent producer can apply the. 22-percent oil-depletion allowance to the market value of a

maximum 1,800 barrels per day (for 1976,

and declines to 1,000 barrels per day by

1980). 17 When confronted with a choice of

joining a unit operation which would

enhance the producer’s recovery of oil

above the limit of 1,800 barrels per day and

thus lose the exemption, the independent

producer would necessarily be concerned

with its participation factor in the unitization agreement. If the independent’s share

of unit production did not compensate for

the exemption loss or ensure at least a comparable return for joining the unit, then the

negotiations of the unit operation could

face an obstacle to the attainment of full

field participation. This situation might

create costly delays in the unitization process.

Another example can be seen in the questions arising with respect to the tax treatment of costs associated with EOR projects,

where costs relevant to the discussion include intangible drilling and development

costs (lDC), cost of physical facilities required in the EOR project, and the cost of

injected material .18 According to the internal Revenue Code enacted in 1954, an IDC

refers to costs (i.e., labor, fuel, transportation, supplies, and other items having no

salvage value) associated with installing

equipment “incident to and necessary for

the drilling of wells and the preparation of

wells for production of oil and gas.” 1 9

Hence, the cost of installing injection wells,

production wells, water source wells (in the

case of waterflooding), and converting production wells to input wells are treated as

IDC and subject to the tax option of either

expensing these cost items or capitalizing

them. The generally accepted accounting

practice is to expense IDC, which allows

them to be written off in the year that they

occur.

The cost of physical facilities (i.e., storage

tanks, pipelines and valves, waste-water

treatment equipment, etc.) must, by law, be

capitalized and depreciated over the expected useful life of the equipment.

However, the method of depreciation may

impact on the incentive to undertake a particular EOR project. A straight-line method

of depreciation (20 percent per year for 5

years) would provide a “quick” writeoff and

enable the full cost of the investment expenditure to be recovered in the first 5 years

of the equipment’s useful life. With the

sum-of-year’s digits method (over an 11-

year period), only 68 percent of the full cost

of the equipment would be recovered during the first 5 years. The allowable depreciation is greater for the straight-line method,

and use of this method could improve the

economic incentive of the EOR program. 20

Furthermore, the tax treatment advice of the

Accounting Subcommittee would be extremely valuable at this point in evaluating

the feasibility of projects under consideration by the joint organization.

The cost of the injected material may also

be a relevant tax consideration. When highcost materials are injected into a reservoir

and a portion of the injected material cannot be recovered from the reservoir, then

the total cost of the unrecoverable material

can be expensed during the year in which it

was injected, or it can be capitalized and
depreciated (using the straight-line method)

over the life of the reservoir. In addition, “if

it can be demonstrated, in any year, that a

particular injection project is a failure (i.e.,

the injection of this material did not benefit

production), a loss may be claimed for the

undepreciated cost of the injected

material. ”21 At the margin, these tax options

may be an important consideration when

choosing among EOR projects which require

the use of high-cost injected material.

Determination of Participation Forrnula.-The

“participation formula” (share of unit production

accruing to the separate ownership interests) is

the heart of the unitization agreement. As such, it

represents the principal point of contention

among the parties negotiating the voluntary formation of a unit operation. According to the

noted authority Raymond Myers, “The ideal is

that each operator’s share of production from the

unit shall be in exact proportion to the contribution which he makes to the unit. ”22 However, the

determination of the “exact proportion” contributed by each operator to unit production is

difficult to determine and has led to long and

labored negotiations.

In the early days of unitization, participation

was based solely on surface area. The criteria was

found to be wanting since, as Myers observes, it

assumed “uniform qua!ity and thickness

throughout the [reservoir] with each tract having

beneath it the same amount of reserves per acre.

This rarely, if ever, happened.”23 More recently,

shares are often determined in direct proportion

to the amount of productive acre-feet of pay

zone which lies beneath the surface of each tract.

However, this determination may be derived

only after a series of development wells have

ascertained the parameters of the reservoir. The

effective procedure which is frequently utilized is

to initially establish participation factors on the

basis of surface area and preliminary acre-feet of

pay zone criteria, then after the commencement

of unit production (usually 6 months), the participation factors are adjusted in accordance with

more reliable or updated pay zone values.

Based on geologic studies of the McComb

Field, it was determined that the average pay

zone thickness was approximately 15 feet per

Appendix C . 209

acre for each 40-acre tract. This value provided

the basis for allocating unit production among

the various ownership interests during the initial

production phase in which approximately 18 percent oil recovery would occur. In the second

phase of the formula, secondary oil reserves were

allocated among the unitized interests on the

basis of 75-percent credit for net acre-feet of oil

zone plus 25-percent credit for the participation

factor used in the first phase. This second phase

adjustment of participation factors was designed

to take into consideration more technical aspects

(actual pay zone) and thereby give some tracts

additional credit for their relatively larger contribution to unit production.

There are a number of obstacles, delays, or disincentives which tend to affect the acceptance of

the participation formula as well as the subsequent negotiations in drafting and approving the

unitization agreements. A few of these have been

previously discussed and others are worth a brief

mention.

Some of the ownership interests may be of the

opinion that they should have a “fair advantage”

with respect to their participation factor. In particular, some parties may contribute more surface

acreage to the fieldwide operation or a portion of

the unit’s plant and equipment (such as injection

wells, storage facilities, and the like) may be located on their property. Hence, by virtue of the

large surface acreage contribution or operations

taking place on their property, these ownership

interests may argue for preferential treatment and

the adjustment of their proposed participation

factor to reflect this “fair advantage. ” The debate

over this issue may create delays in the determination of an acceptable participation formula

and, if left unresolved, could have a detrimental

effect on the ability of all parties to form a voluntary unit operation.

Pride of property ownership and/or control

over individual operations may affect the willingness of an individual ownership interest (royalty

as well as operating) to join a unit and commit

their property and operational control to joint

decisions. When such strong feelings are held

(and they may surface with participation factor

dissatisfaction), acceptance of the participation

formula or general approval of the unitization

agreements may be difficult to achieve.
210 . Appendix C

A final consideration, which might well impact

on the incentive for accepting the participation

formula and entering a unit operation, involves

the effect of FEA regulations. The domestic price

of crude oil is controlled at specific levels by FEA.

However, the anticipation of future price

deregulation might prompt some producers to

leave oil in place until the price of oil increases.

This could be particularly critical when the producer feels that its return (based on the participation factor) from the joint operation is marginal,

at best.

In general, the acceptance of the participation

formula by operators and royalty owners reflects

their satisfaction with the unit operation and its

ability to ultimately increase profits while

safeguarding property rights. Fieldwide unitization is initiated in order to increase the ultimate

recovery of oil and gas while reducing the riskiness and costs associated with individual operations. Through a joint effort, higher rates of return

can thus be realized with the retention of ownership interests in the recovery of oil and gas.

Drafting and Approval of Agreements.—The

fourth stage in the voluntary unitization process

involves the drafting and approval of agreements

by participants engaged in a fieldwide operation.

This stage represents the culmination of the

efforts and responsibilities undertaken by the

various subcommittees with the supervision of

the Unitization Committee.

The Legal Subcommittee assumes the task of

drafting the unitization agreements for the approval of the ownership interests. The unitization

agreements are the legal instruments for the unit

operation, and there are generally two types of

documents: the Operating Agreement for the

operators or working-interest owners, and the

Royalty Owners Agreement for the royalty interests. It is customary to distinguish between the

two ownership interests in order to facilitate the

approval of the unit operation. While operating

interests share in the proceeds and costs of the

unit operation, royalty owners share only in the

proceeds from unit production and do not share

in the obligations incurred by the operators.

Therefore, separate documents are desirable

since the Royalty Owners Agreement contains

material only of interest to the royalty owner.

The Operating Agreement contains a legal

statement of matters containing the participation

formula and adjustments thereof, provisions for

enlarging the unit operation, cost allocation,

operational procedures, and matters pertaining to

titles, easements, and term. Furthermore, the

selection of the Unit Operation is specified in

this document where the Unit Operator is usually

the largest leaseholder in the unit and is responsible for the general supervision of the unit operation. The execution of the Operating Agreement

occurs when the signature of the operators have

been obtained. This generally requires approximately 6 to 8 months, as in the cases of both the

McComb and Seeligson Field Units.

As previously stated, the Royalty Owners

Agreement consists of material germane only to

royalty interests; as such, this instrument is considerably shorter and less difficult than the

Operating Agreement. The Royalty Owners

Agreement must be presented to all the owners

of mineral interests in the unit area including

unleased lands, royalties, overriding royalties, gas

payments, and oil payments. The agreement

must be acceptable to the various royalty owners

before the unit operation becomes effective.

Naturally, the primary concern among royalty

owners involves their share of the proceeds from

unit production and, to a lesser extent, their participation in plant products (gas, condensates,

and others) and questions dealing with easements. Therefore, in order to allay any apprehensions or misconceptions, great care has to be exercised by operators in drafting the Royalty

Owners Agreement and conveying to royalty interests the nature of the unit operation and how

royalty owners would benefit from unitization

while retaining their ownership rights. Myers observes that “the interests of the lessee and lessor

are for the most part identical, and this fact is of

course considered by the royalty owner in accepting the decisions of his lessee. ”24

In order to achieve the maximum objectives of

voluntary unitization, it is necessary that all parties having an interest in the unit area become

subject to the unit agreements. However, in the

absence of compulsory unitization, this may be

impossible to obtain when some lessors or

lessees refuse to participate in the unit. Even

when non joining parties cannot complain about
financial losses incident to the unit operation, the

land of a non joining lessor or lessee may not be

used to achieve the maximum effectiveness of

the unitization program.

As a final note, the first four stages in the

negotiation and execution of a voluntary unit

operation demand much effort and planning on

the part of interested parties. The time that is

necessary to effect the fieldwide operation varies

in accordance with the complexity and frequency

of the problems involved. Smaller units which involve fewer ownership interests will generally

establish unitization in a relatively shorter time

than larger units with numerous and diverse

ownership interests. The larger the number of interested parties, the more difficult it is to coordinate and reconcile individual interests with the

objectives of the joint organization.

Based on the case histories of the McComb

and Seeligson Field Units, the time necessary for

voluntary unitization can be quite variable. When

the McComb Field agreement was submitted for

regulatory approval, signatures of ownership interests had been secured for approximately 68

percent of the royalty owners and nearly 84 percent of the operators. The time required for the

completion of the first four stages involved less

than 1 l/z years-a relatively short period for a

unit operation encompassing over 300 tracts and

thousands of ownership interests. On the other

hand, the Seeligson Field Unit initiated negotiations in February 1952; by November 1955, signatures of working-interest owners were obtained for the Operating Agreement. In the spring

of 1956, the Royalty Owners Agreement became

effective and, after nearly 4 years of negotiation,

the unit operation for the Seeligson Field became

a reality.

Compulsory Unitization

Compulsory unitization begins with voluntary

unitization of a majority of the interests within

the field. It differs from voluntary unitization in

that all States with petroleum allow unitization

when most or all of the interested parties agree

to it, but not all States will force unwilling parties

to have their interests included in the unit operations. Most States, however, do authorize the

Appendix C . 211

State commission to enter an order compelling all

interests in a field to participate in the unit once

there has been voluntary agreement among a

specified percentage of interests in the field.25

This required percentage varies from 60 percent

in New York and 63 percent in Oklahoma to a

high of 85 percent in Mississippi. Texas is the

most significant State without a compulsory

unitization statute, but it should also be pointed

out that the effect of the statutes in California is

so limited in application that they are rather ineffective: the California Subsidence statute provides for compulsory unitization only in areas in

which subsidence is injuring or imperiling commerce or safety, while the California Townsite

statute applies only to fields over 75 percent of

which lie within incorporated areas and which

have been producing for more than 20 years.

Without unitization of all interests, unit operators may be liable to nonunitized interests for

non-negligent operations, and will have to account to nonunitized interests as though there

were no unit. If a lessee in a unit has a royalty interest to which it must account for production,

and that royalty interest is not joined in the unit,

the lessee will have to account to the royalty

owner on the basis of the production from the

leased land, not on the basis of the production

attributable to the leased land under the unit

operations plan. The lessee may have to engage

in additional drilling in order to maintain the

validity of the lease against non joining reversionary interest owners; such drilling may be completely unnecessary for maximum recovery from

the reservoir and, indeed, may be harmful to that

maximum recovery. Lack of compulsory unitization or the requirement of a high percentage of

voluntary participation could be a significant

restraint on unit operations, which in turn could

have a significant impact on enhanced recovery.

In response to questionnaires sent to regulators and producers, several State commissions

and a significant number of producers identified

the inability of getting joinder of the necessary

parties in a field for unitization as inhibiting or

preventing the initiation of enhanced recovery

projects. It was indicated that there probably are

several hundred projects in the State of Texas

that cannot be undertaken because of the inability to join the necessary interests in the unit.
212 . Appendix C

Four small producers and four larger ones stated

that lack of joinder of parties was inhibiting projects in Texas. Producers in 10 States indicated

that enhanced recovery projects would be encouraged by compulsory unitization or a lowered

voluntary percentage required to invoke compulsory unitization. For example, a Louisiana independent declared “1 think 75-percent royalty

owner approval in Louisiana too high. A good

project that benefits operator must necessarily

benefit royalty owner.”

There appears to be little or no difficulty in requiring unitization and enhanced recovery activities on Federal lands. The major pieces of

Federal legislation for mineral development on

Federal land provide ample authority to the

Secretary of the Interior to make such requirements. The Outer Continental Shelf Lands Act,

for example, provides that for Federal leases the

“Secretary may at any time prescribe and amend

such rules and regulations as he determines to be

necessary and proper in order to provide for the

prevention of waste and conservation of the

natural resources of the Outer Continental Shelf

(OCS). . . .Without limiting the generality of the

foregoing provisions of this section, the rules and

regulations prescribed by the Secretary

thereunder may provide for. . .unitization. . . .“26

Pursuant to this authority, the U.S. Geological

Survey in establishing operating orders for the

OCS, Gulf of Mexico area, has provided that

“Development and production operations in a

competitive reservoir [having more than one

lessee] may be required to be conducted under

either pooling and drilling agreements or unitization agreements when the Conservation Manager

determines. . that such agreements are practicable and necessary or advisable and in the interest

of conservation. ”27 The same OCS order requires

that operators “timely initiate enhanced oil and

gas recovery operations for all competitive and

noncompetitive reservoirs where such operations

would result in an increased ultimate recovery of

oil or gas under sound engineering and economic

principles.” 28 While Interior’s authority does not

appear to be quite so ‘extensive under the Mineral

Leasing Act of 1920, the difficulties for unitization and enhanced recovery on Federal land

onshore nevertheless appear minimal when compared with development on private lands.

Procedure for Fieldwide Unitization

The procedure for obtaining commission approval for unitization or for compelling joinder of

parties in the unit is similar in most States,

although by no means identical. Common elements found in almost all States include the need

for application or petition by an interested party

(normally the prospective operator), notice to

other parties, a hearing, proof of matters required

by the pertinent State statute, and entry of an

order by the commission defining the unit, and

the terms of the unitization. The entire procedure

usually takes only a matter of weeks, although

there may be a delay or denial of the permit

because of inequities in the participation formula. The description of the general procedure

involved is intended to be suggestive only, with

detailed explanation of the procedure in several

of the more important States with enhanced

recovery activities. For other treatments, and

specific requirements for each State, reference

should be made to the work cited29 and to table

c-1 .

Application

The application form and the information required to be contained in it vary from State to

State, but five common requirements are present

in whole or in part in most statutes. These are

that the following should appear:

1)

2)

3)

4)

5)

description of the area to be included,

description of the operations contemplated,

a statement of the unit control and composition,

the expense and production allocation formula, and

the duration of the unit.

Some States require prior notice to be given to

the affected parties and several require that the

applicant furnish the regulatory commission with

a list of the names and addresses of affected parties.

Who may initiate the regulatory process also

varies from State to State. In many States any interested party may submit a petition for unitization, while in others only a working interest
owner may start the process. In a number of

States the commission may initiate the procedure

on its own motion, but this generally is not used

except with application by a party. Usually, it is

the unit operator who has been selected by the

participants in the unit who initiates the process.

As described earlier, the expense and production allocation formula is tediously and carefully

negotiated by the parties to the unitization

agreement. Agreement with this information will

normally be submitted to the commission with

the petition or application. When compulsory

joinder of other parties is sought, there will be a

statement that such parties have been offered the

opportunity to join the unit on the same basis as

all others. The application will generally also

cover the matters which are required by the

statute to be found before the commission may

enter an order, as discussed under “Proof of Findings Required. ”

Notice

Both voluntary and compulsory unitization

statutes generally require that notice and an opportunity for a hearing be given prior to the entry

of an order establishing or approving the unit.

Louisiana, for example, provides that whenever

any application shall be made to the commissioner of conservation for the creation, revision,

or modification of any unit: the applicant shall be

required to file two copies of a map of the unit

with the application; the applicant shall be required to give at least 30 days notice of the hearing to be held on the unit in the manner

prescribed by the commissioner; and a copy of

the plat shall remain on file in the office of the

commissioner in Baton Rouge and in the office of

the district manager of the conservation district

in which the property is located, and be open for

public inspection at least 30 days prior to such

hearing. JO Other States typically require a shorter

time period for notice, but also require that it be

given by personal notice and/or by publication in

the State register or in a newspaper. Failure to

comply with a statutory notice provision may

result in the order being declared invalid as to

parties who were not given notice.31 

Appendix C . 213

Hearing

Opportunity for hearing is required in all States

prior to the entry of an order for unitization, but

in some States, such as Alaska, no formal hearing

need be held if no party objects to the unitization

proposal after the notice is given.32 Hearings are

generally conducted without rigid formality and

are usually governed by the rules of civil procedure of the State and/or such rules as may be

promulgated by the State commission pursuant

to its delegated authority. Decisions are based on

the record evidence and a general right to rehearing and/or appeal is accorded.33

Proof of Findings Required

Prior to approval of any unit plan or entry of an

order requiring unitization in most States, the

State commission must make certain findings.

These generally are that unit operations are

necessary to increase ultimate recovery from the

reservoir or prevent waste, that correlative rights

of interest owners are protected, and that the additional cost involved does not exceed the additional recovery anticipated. The Texas statute, for

example, provides that unit agreements shall not

become lawful or effective until the Texas

Railroad Commission finds that:34

1)

2)

such agreement is necessary to accomplish

[secondary recovery operations] or [conservation and utilization of gas] or both;

that it is in the interest of the public welfare

as being reasonably necessary to prevent

waste, and to promote the conservation of

oil or gas or both; and that the rights of the

owners of all the interests in the field,

whether signers of the unit agreement or

not, would be protected under its operation;

the estimated additional cost, if any, of conducting such operations will not exceed the

value of additional oil and gas so recovered

by or on behalf of the several persons

affected, including royalty owners, owners

of overriding royalties, oil and gas payments, carried interests, lien claimants, and

others as well as lessees;
214 . Appendix C

3)

4)

other available or existing methods or

facilities for secondary recovery operations

and/or for the conservation and utilization

of gas in the particular area or field concerned are inadequate for such purposes;

and

the area covered by the unit agreement contains only such part of the- field as has

reasonably been defined by development,

and that the owners of interests in the oil

and gas under each tract of land within the

area reasonably defined by development

are given an opportunity to enter into such

unit upon the same yardstick basis as the

owner of interests in the oil and gas under

the other tracts in the unit.

The Louisiana statute, to cite a compulsory

unitization statute, provides that an order for unit

operation shall be issued only after notice and

hearing and shall be based on findings that:35

1)

2)

3)

4)

the order is reasonably necessary for the

prevention of waste and the drilling of unnecessary wells, and will appreciably increase the ultimate recovery of oil or gas

from the affected pool or combination of

two pools;

the proposed unit operation is economically

feasible;

the order will provide for the allocation to

each separate tract within the unit of a proportionate share of the unit production

which shall insure the recovery by the

owners of that tract of their just and equitable share of the recoverable oil or gas in the

unitized pool or combination of two pools;

and

at least three-fourths of the owners and

three-fourths of the royalty owners,. . shall

have approved the plan and terms of unit

operation, such approval to be evidenced

by a written contract or contracts covering

the terms and operation of said unitization

signed and executed by said three-fourths in

interest of said owners and three-fourths in

interest of the said royalty owners and filed

with the commissioner on or before the day

set for said hearing.

As indicated previously, different States with

compulsory unitization provisions have varying

requirements as to the percentage of parties

voluntarily entering into the unitization prior to

invoking the compulsory features.

Entry of the Order for Unitization

After application, notice, hearing, and presentation of evidence and findings by the commission, the commission, if approving the unitization, will enter a formal order for the unitization

which will become a matter of public record. In

Oklahoma, for instance, the order of unitization

issued by the Oklahoma Corporation Commission will provide for:36 1 ) the management or

control of the unit area by an operator who is

designated by vote of the lessees; 2) the allocation of production; 3) the apportionment of

operational costs; 4) the manner of taking over

the wells and equipment of the several lessees

within the unit area and the method of compensation therefore; 5) creation of an operating committee; 6) time of the plan’s effectiveness; and 7)

time and conditions of unit dissolution. Other

States are similar. Unit members dissatisfied by

the unitization order may appeal directly to the

Oklahoma Supreme Court.37

Interests joined in the unit through compulsion

may be allowed to choose prior to commencement of unit operations whether to participate as

cotenants sharing in expenses and profits or to

take a fair and reasonable bonus and royalty

which is expense free. Several States including,

among others, Alaska, Colorado, New Mexico,

Utah, and Wyoming provide for or require financing programs for nonconsenting parties with

limited cash outlay capabilities to defer unit expenses until production is obtained with reasonable risk assessments added.

The problem of determining a fair and equitable basis for allocation of production among the

unit members can be an extremely difficult one,

as was brought out in the discussion of the

problems of negotiating voluntary agreements for

unitization. Claims may be made that production

should be allocated on the basis of surface

acreage, productive acre feet, productive pore

space, prior production history, and other
grounds. The State commission may use a combination of these. For example, the Oklahoma

Corporation Commission for the West Cache

Creek Unit in Cotton County, Okla., used a split

formula based first upon the estimated remaining

net economically recoverable primary production

of the unit, and secondly on the floodable acre

feet of the unit. The Oklahoma Supreme Court

upheld this approach against a chalIenge by a dissatisfied party who claimed that the formula

should, in its second phase, take into account the

current production from the claimant’s well; the

commission’s order was, the court ruled, supported by substantial evidence and so the court

would not overrule the commission.38 

State commissions have set formulae on a

variety of base: and have generally been upheld

by the courts regardless of the formula used.39

Statues do occasionally provide some standards, but as one authority has stated, “Viewing

present statutory standards, shed of all frills, the

parties must look for real protection to the integrity of the regulatory agency and of the parties

presenting evidence, as well as to careful scrutiny

of the information by those who expressly consent to the allocation.”4

° Both the sparsity of

litigation on the subject and statements concerning the regulatory commissions in response to

OTA’s questionnaires indicate that the State

commissions are effectively protecting the interests of the parties to unitization proceedings.

Amendment and Enlargement

Under most statutes for unitization, it is possible to enlarge the unit and/or amend the unit

agreement(s) following the same procedures that

were used in creating the unit in the first instance. This may occur if additional parties wish

to participate in the agreement or if it is learned

that the reservoir has different parameters than

originally believed.

Effect of Unitization

Each State authorizes the establishment of

voluntary fieldwide units, although formal State

approval may not be required for the creation of

such a unit. There are distinct advantages to getting such approval even when it is not a requirement. First, the State will generally, by statute,

immunize the participants from application of the

Appendix C . 215

State antitrust laws to the unit operation.41 Second, it may serve to protect the participants from

application of the Federal antitrust laws to the

unit operations. The argument can be made that

unitization reduces competition and can serve as

a means of limiting production and controlling

price. However, the general weight of authority is

that, so long as there is no collusion in refining

and marketing, the mere joint production of oil

does not create antitrust problems. 42 Wher e

unitization is necessary to increase total production it would appear that unitization would actually promote competition by increasing the

amount of oil available to all the parties. The role

of State approval in Federal antitrust considerations (if they should be raised) is that it can be

argued that the approval and order of the State

commission gives rise to the well-recognized

Parker v. Brown43 exemption from the operation

of the Federal antitrust laws. That is, in the case

of Parker v. Brown, the U.S. Supreme Court held

that State approval of a raisin marketing program

provided the cooperative activities of the raisin

growers with immunity from the Federal antitrust

laws. The same rationale would apply to unit

operations approved by a State commission. 44

Only one Federal case45 has attempted to apply

the Federal antitrust statutes to unit operations,

and was terminated through a carefully negotiated consent degree.

Another reason for getting State approval for a

voluntary unit even if not required is that it may

provide protection from liability for nonnegligent operations to other parties in the reservoir who have not joined in the unit. This is an

important subject in itself, and is taken up in a

later section. Suffice it to say at this point the element of State approval of the enhanced recovery

program has been enough for some courts to

establish immunity from such Iiability for operators. And, of course, where the requisite percentage approval is achieved in a State with a compulsory unitization statute, the entry of a

commission order for a unit will result in unitizing

the field and all interests in the field may be

treated as members of the unit; no separate accounting or operations on a nonunit basis will be

necessary.

One more point should be brought out, and

that is that under the terms of an oil and gas lease
216 . Appendix C

in some instances and by statute in others the

establishment of the unit will sever the unitized

portion of the leasehold from the rest of the

Iease. 46 Depending on the wording of the lease

clause (known generally as a “Pugh clause”

because of the person purportedly creating it

originally) or of the applicable statute, such as in

Mississippi, Louisiana, and Wyoming, additional

activity on the severed part of the leasehold may

be necessary to keep the lease in force as to the

portion of the lease not included in the unit. Such

lease and statutory provisions can serve as a disincentive to lessees to participation in unit operations.

Allowable and Well Spacing

In order for an enhanced recovery project to

be successful, it is necessary to be able to produce the oil. The fixing of allowable in marketdemand type States could discourage enhanced

recovery if the production rates were set at a

level below the optimum rate for the reservoir.

The regulations of the State commissions

generally do make provision for the setting of

allowable for enhanced recovery operations. For

example, Oklahoma provides that “An” approved

and qualified waterflood project shall be entitled

to produce an allowable of forty-five (45) barrels

of oil per well per day including producing and

injection wells on a project basis upon the

acreage developed for waterflooding. The commission may increase the allowable for a

waterflood project for good cause shown after

notice and hearing. ”47 In other States, similar provision is made and/or allowable may be transferred among interest owners for the encouragement of enhanced recovery.48 Because of special

treatment and encouragement of enhanced

recovery projects, it does not appear that the setting of allowable would impede enhanced

recovery operations. No producer responding to

OTA’s questionnaires indicated that there was a

problem of establishing adequate allowable for

enhanced recovery. The same is true of well

spacing.

Administrative and Judicial Encouragement

to Unitization

A number of State commissions and courts

have recognized the benefits that result from undertaking unit operations to enhance recovery

and accordingly have attempted to encourage

unitization. They have done this in several ways.

One has been to deny to non joining parties

the benefits they might have expected to obtain

by their refusal to join. Production allowable

have been set at a higher rate on occasion for unit

members than for those who decline to enter the

unit. 49 To cite another example, an agency has

limited the royalty payable to a non joining

royalty owner to the royalty that would have

been paid had the allowable not been increased

for the enhanced recovery operations.50 Such actions have been upheld by the courts. 51

Another method of encouraging unitization

has been for agencies to use their authority over

well spacing or the prevention of waste to make

unitization more attractive to interest owners.

Thus in one well known case,52 the Colorado Oil

and Gas Conservation Commission prohibited

the production of gas from a large reservoir

unless the gas was returned to the reservoir, used

in lease or plant operations, or used for domestic

or municipal needs in or near the field. The oil

could not be produced without production of the

gas, and the gas could not be reinfected without

unitization of the field. Although sympathizing

with the commission’s goal, the Colorado

Supreme Court struck down the order on the

ground that it was beyond the authority of the

commission. Subsequently, Colorado enacted a

compulsory unitization statute. A recent effort by

the Oklahoma Corporation Commission to require separate owners of interests to develop

their land as a unit was struck down as being

beyond the statutory authority of the commission.

53

Finally, the courts have encouraged unitization

by denying damages to a non joining interest

owner who has asserted that his production has

suffered by virtue of the unit operation of the

party against whom the claim is brought. Such

cases are taken up in a later section.

It should be observed that while agencies and

courts have expressed support for enhanced

recovery, they are limited to the statutory

authority they possess. There is only limited opportunity for them to use their discretion for encouragement of enhanced recovery.
Appendix C ● 217

Approval of Enhanced Recovery Projects

Permit Requirements

prior to commencement of any underground

injection for EOR purposes, (all enhanced recovery projects require underground injections), the

party responsible must obtain approval from the

proper State commission. Often this may be done

at the same time that approval of unitization is

sought; much the same information is required

and a similar procedure is employed. The two

should be treated separately, however, because

they are separate legal requirements involving

different considerations and because an operator

must get a permit for enhanced recovery operations even when a unitization procedure is not

necessary, as when the operator owns the entire

area covered by the reservoir.

As with the unitization statutes, the requirements for enhanced recovery operations permits

vary from State to State.54 What is attempted here

is to highlight the general features of the regulatory procedures that are similar in most States

with detailed references to the regulations of the

larger producing States. The procedure typically

requires the filing of an application or petition by

the party responsible for the project which

describes the activity proposed. Depending on

the jurisdiction, notice of the proposed action

may have to be given to interested parties before

application or it may be given subsequent to the

application, either by the regulatory commission

or by the operator. A hearing upon the application

will be held if timely objection is made by an interested party or on the commission’s own initiative.

Application

Applications for enhanced recovery permits

typically require four elements of information to

be included, and these may be specified either by

statute or by rule of the regulatory agency: 1 )

geographic description of the area covered by the

operation; 2) identification of parties affected or

who may be affected by implementation of the

proposed project; 3) data concerning the formations underlying the area of operation; and 4) explanation of the recovery program.

Geographic descriptions required generally include a plat of all leases in the affected area with

locations given for all present, abandoned, and

proposed wells. New Mexico, for example, requires a plat showing the locations of all wells

within a 2-mile radius of existing and proposed

injection wells and the formation from which the

wells are producing or have produced. 55

To facilitate the giving of notice to affected parties, and to enable the States to prepare conservation plans, the States generally require the application to include one or more of the following:

the names and addresses of operators within the

area, the names of all operators within the unit,

the names of all owners of property interests

within one-half mile of injection wells, and the

names of all lessees within 2 miles of injection

wells.

Data concerning subsurface formations that are

generally required under the statutes or regulations include full descriptions of the formations in

the area and specific delineation of the reservoir

to be flooded. Other such information may be required. Kansas, for example, requires not only the

name, description, and depth of the formations to

be flooded, but also the open-hole depths of

each such formation, the elevations of the top of

the oil- or gas-bearing formation in the injection

well, the wells producing from the same formation within one-half mile radius of the injection

well, and the log of the injection well (if a complete log does not exist, such information regarding the well as is available). 56

The data concerning development plans that

are generally required include specific description

of injection methods, identification of the substance(s) to be injected, the source of the substance, and the daily amounts of the injection. information pertaining to casing and casing tests

must similarly be submitted along with such log

information as is available to the operator. Some

States require additional data on oil to gas ratios
218 . Appendix C

and oil to water ratios on production obtained to

the date of the application. Separate application

requirements exist in some states for waterflood

methods, repressurization, disposal wells and the

use of hydrogen sulfides’

Because it is typical of the requirements of

State commissions for enhanced recovery applications, section 3-30I (b) of the General Rules and

Regulations of the Oil and Gas Conservation Division of the Oklahoma Corporation Commission is

set forth:

The application for an order authorizing a

pressure maintenance or secondary recovery

project shall contain the following:

(1) The names and addresses of the operator

or operators of the project.

(2) A plat showing the lease, groups of leases

or unit included within the proposed project; the

location of the proposed injection well or wells

and the location of all oil and gas wells, including

abandoned and drilling wells and dry holes; and

the names of all operators offsetting the area encompassed within the project.

(3) The common source of supply in which all

wells are currently completed;

(4) The name, description, and depth of each

common source of supply to be affected;

(5) A log of a representative well completed in

the common source of supply;

(6) A description of the existing or proposed

casing program for injection wells, and the proposed method of testing casing;

(7) A description of the injection medium to

be used, its source and the estimated amounts to

be injected daily;

(8) For a project within an allocated pool, a

tabulation showing recent gas-oil ratio and oil

and water production tests for each of the producing oil and gas wells; and

(9) The proposed plan of development of the

area included within the project.

Notice

Because enhanced recovery operations may

affect in one way or another virtually all parties in

the vicinity of the operation, the notice requirement and opportunity given for a hearing reflect a

liberal attitude toward notification of nearby tract

owners and operators. Service of notice must be

personal, by mail, or by publication in a readily

available or official publication. Generally, notice

must be given by the applicant himself to the

other parties, and it will have to be given some 10

to 15 days before the application or just after filing of the application. Notice commonly must be

extended to owners and operators of the reservoir

and all those with interests in property within

one-half mile of the injection well(s). Protest

against the application must be lodged within 15

days of service of notice or of the application, depending on the jurisdiction, In many jurisdictions no hearing need be held if no party objects

to the application or if the commission does not

order one on its own motion.

An example of the notice requirements can be

given by reference to Alaska’s rules58 which require a copy of the application to be mailed or

delivered by the applicant to each affected operator on or before the date the application is filed

with the Oil and Gas Division of the Department

of Natural Resources. Statements must be attached to the application showing the parties to

whom copies have been mailed or delivered. In

the absence of any objection within 15 days from

the date of mailing, the division’s committee may

approve the application. If objection is made, the

committee shall set the matter for hearing after

giving additional notice to the affected parties.

Other States are similar in their provisions.

Hearing

Once a protest is made to an application or the

commission on its own initiative requires one, a

hearing will be held on the application. The function of the hearing will be to determine whether

the injection program is reasonably necessary for

the prevention of waste and to obtain greater

recovery from the common source, whether the

recovery costs will be less than the proceeds from

recoverable oil and gas, and whether the rights of

other interested parties are adequately protected.

Hearings are governed by the State’s rules of civil

procedure and/or rules promulgated by the commission pursuant to authority delegated to it. Evidence introduced at the hearings will normally be

scientific information and data brought out

through the testimony of geologists and engineers

under questioning by the operator’s attorney or

the opponent’s attorney. A right to rehearing

and/or a court review of a commission decision is

generally provided upon timely application.
Appendix C . 219

Order

In general, an application for any type of injection program may be denied by the State commission for good cause; the commission will have

considerable discretion allowed by State statute.

If the application is approved, an order will be

issued by the commission giving the operator

authority to proceed. The order will be a matter of

public record and can be rescinded for any good

cause. The injection program will be subject to

additional requirements while it is being implemerited. 59 The operator will normally be required

to complete reports before or at the time of commencement of injection, to issue periodic reports

regarding the program, and will be subject to inspection of operations by the State regulatory

agency. Additional notice to other State agencies

may be required after issuance of the order. The

appropriate State agency will also have to be

notified of the termination of the injection

program.

Injection Regulations Under the Safe

Drinking Water Act

Acting under the authority of the Safe Drinking

Water Act, 60 the Environmental Protection

Agency (EPA) has issued proposed regulations61

that would be applicable to underground injections for EOR purposes. While these regulations

were not final at the preparation of this report, it is

useful to examine them in the context of the Safe

Drinking Water Act and current State control

programs. Some type of regulation will be

forthcoming from EPA, even if not in the precise

form of the present proposals.

The Safe Drinking Water Act was passed into

law as an amendment to the Public Health Service

Act in 1974. Its purpose is to establish national

drinking water standards and ensure minimum

protection against contamination of drinking

water supplies by well-injection practices. It attempts to accomplish this by having EPA issue

regulations specifying minimum requirements for

State programs to control underground injection

of fluids that may threaten the quality of water in

aquifers that are or may be used for public supply.

Section 1421 (b) (1)62 of the Act itself sets out the

minimum requirements for State programs to control underground injection. They are, 1 ) only

State-authorized injections may be continued

after 3 years from the date of enactment; 2) the injector must satisfy the State that his operation

does not endanger the drinking water; 3) the State

program must have procedures for inspection,

monitoring, recordkeeping, and reporting for injection operations; and 4) the regulations must

apply to all persons including Federal agencies.

With specific respect to oil and natural gas production, the Safe Drinking Water Act provides

further in section 1421 (b)(2) 63 that:

Regulations of the [EPA] Administrator under this

section for State underground injection control

programs may not prescribe requirements which

interfere with or impede—

(A) the underground injection of brine or other

fluids which are brought to the surface in connection with oil or natural gas production, or

(B) any underground injection for the secondary

or tertiary recovery of oil or natural gas, unless

such requirements are essential to assure that underground sources of drinking water will not be

endangered by such injection.

In promulgating regulations setting requirements

for State programs, it is the interpretation of the

Act by EPA that the “Administrator need not

demonstrate that a particular requirement is essential unless it can be first shown that the requirement interferes with or impedes oil or gas

production.” 64 Thus, the burden is upon the State

or the enhanced recovery operator to prove that

the requirement in question does interfere with or

impede production, and EPA further places the

burden on the operator to show that the requirement is not essential, That is, EPA has stated that

an alternative method of protection of drinking

water may be approved by the State commission

“if the operator clearly demonstrates that (i) the

requirement would stop or substantially delay oil

or natural gas production at his site; and (ii) the

requirement is not necessary to assure the protection of an existing or potential source of underground drinking water.”65

it should be observed that EPA does take note

of the fact that oil-producing States have regulated injections for years, and does set the requirements applicable to injection wells related

to oil and gas production in a subpart separate

from requirements for other types of injections.
220 . Appendix C

While EPA-required procedures are similar to existing State procedures for injection permit regulation, the proposed regulations would impose

much more detailed requirements than do current

State procedures. For example, the application requirements for new underground injection under

the proposed regulations66 set forth immediately

below should be compared with the Oklahoma

regulations concerning application quoted on

page 218 of this appendix.

(a) The application form for any new underground injection shall include the following:

(1) Ownership and Location Data. The application shall identify the owner and operator of

the proposed underground injection facility, and

the location of the facility.

(2) Engineering Data.

(i) A detailed casing and cementing

program, or a schematic showing: diameter of

hole, total depth of well and ground surface

elevation; surface, conductor, and long string casing size and weight, setting depth, top of cement,

method used to determine top; tubing size, and

setting depth, and method of completion (open

hole or perforated);

(ii) A map showing name and location

of all producing wells, injection wells, abandoned

wells, dry holes, and water wells of record within

a one-half-mile radius of the proposed injection

well; and

(iii) A tabulation of all wells requested

under (ii) penetrating the proposed injection

zone, showing: operator; lease; well number;

surface casing size and weight, depth and cementing data; intermediate casing size and

weight, depth and cementing data; long string

size and weight, depth and cementing data; and

plugging data.

(3) Operating Data.

(i) Depth to top and bottom of injection

zone;

(ii) Anticipated daily injection volume,

minimum and maximum, in barrels;

(iii) Approximate injection pressure; and

(iv) Type, source, and characteristics of

injected fluids.

(4) Geologic Data—Injection Zone. Appropriate geologic data on the injection zone and

confining beds including such data as geologic

names, thickness, and areal extent of the zone.

(5) Underground Sources of Drinking

Water Which May be Affected by the Injection.

Geologic name and depth (below land surface) of

aquifers above and below the injection zone containing water of 3,000 mg/I total dissolved solids

or less and aquifers containing water of 10,000

mg/I total dissolved solids or less.

(6) An electric log on all new wells and on

existing wells where available.

The regulations could broaden the number of persons or agencies who could challenge the application and insist upon a public hearing. New

requirements would be made for record keeping

at several different levels (by governmental agencies and operators); there would be a 5-year

limitation on permits; new standards could be required to be met after an injection program has

commenced under a properly issued permit; and

the specific well requirements go beyond those

of many States.

A number of parties have objected strenuously

to these proposed regulations or similar prior proposals, and to the general approach taken by EPA

under the Safe Drinking Water Act on the grounds

that this will significantly hinder EOR operations

without corresponding benefits in the protection

of drinking water. A resolution of the Interstate

Oil Compact Commission of June 30, 1976, for

example, declared: “The State regulatory agencies

estimate that if the recent draft regulations went

into effect it would cause a loss of production of

over 500,000 barrels of oil per day and in excess

of 2.5 billion cubic feet of gas per day. All of this

is from existing wells that have been producing

for a number of years with virtually no adverse impact on the environment.67 While this resolution

referred specifically to the immediate predecessor

of the currently proposed regulation, personnel

with the Interstate Oil Compact Commission indicated in personal contact that the current regulations could still substantially interfere with or impede enhanced recovery of oil.

The Council on Wage and Price Stability recently criticized EPA’s proposed regulations on

the grounds that EPA may have both underestimated the costs of conducting the State regulatory programs and misjudged the health benefits

to be gained by the regulations.68 Specifically, the

Council stated that “EPA’s data regarding benefits

and costs offered in support of the regulations are

too fragmentary, subjective, and inconclusive to

enable an informed decision to be made on this

issue, ” and urged that further evaluations be made

before putting regulations into effect.69
Finally, both producers and State commissions

identified the contemplated EPA regulations as

being likely to hinder or discourage enhanced

recovery operations. Of the responses from producers, four independent and six large producers

stated specifically that the proposed EPA regulations would have an adverse effect on operations.

An example of such responses was the following

comment of one independent producer from the

State of New York: “EPA-proposed rules and

regulations regarding existing underground injection wells--could have a very negative effect on

enhanced recovery. ” One of the large companies

responding similarly stated: “The recently proposed EPA rules concerning secondary recovery

operations could essentially prohibit new

enhanced projects. ” One State agency which has

authority over several hundred enhanced recovAppendix C . 221

ery projects with many more potential projects in

the State said that no permit had been denied for

such projects but that “Many may be denied next

year if the Federal UIC [underground injection

control] Regulation is administered as written. ”

The American Petroleum Institute has also conducted a survey of major and independent producers and has concluded that “Without doubt

the proposed regulations will interfere with and

impede underground injections and substantially

decrease the ultimate production and recovery of

hydrocarbons.” 70

In light of the number of such comments, it is

clear that EPA-proposed regulations are perceived

as having, or as likely to have, an adverse impact

on enhanced recovery operations.

Operational Aspects of Enhanced Oil Recovery

Potential Liability to Nonjoining Interests

Relatively few reported cases have arisen in

which non joining interests have made claims for

damages against unit operators for enhanced

recovery activities, and fewer still in which

damages have been awarded. However, the issue

is an important one as is suggested by the number

of articles that have been written on the subject.71

As one writer has commented, the small number

of cases is “like the top of an iceberg, it does not

reveal the trouble underneath—the number of

secondary [i.e., enhanced] recovery projects

delayed or hamstrung by threats of litigation, and

the heavy price sometimes exacted by the owners

of minority interests in exchange for cooperation. 72 For this reason, it is important to examine

briefly the legal theories upon which claims or

liability might be based, the treatment of these by

the courts in the past, and possible approaches to

the problem in the future.

The legal theory upon which a claim for

damages may be based will depend in part upon

the relationship between the claimant who has

not joined the unit and the operator responsible

for the enhanced recovery project. If the claimant

is a lessor or cotenant of the operator, the claim in

most circumstances will be that the operator has

breached a duty owed to the claimant or that the

operator has caused waste of property jointly

owned by both the operator and the cotenant. If

the claimant is a neighbor owning an interest in

the reservoir, the claim may be based on a theory

of trespass, strict liability (ultrahazardous activity),

nuisance, or fault. In general, the courts have

shown a disinclination to award damages on any

of these grounds except the very last—fault.

As discussed in an earlier section, the lease itself governs most relations between lessor and

lessee. Most leases are silent with respect to

enhanced recovery, however, and it is necessary

to examine implied rights and obligations that

arise out of the basic relationship. These can be

put under many headings, but the general principle that is most important is that the lessee must

act in good faith and do nothing to injure the

value of the leasehold. While the same relationship is not present in a cotenancy situation, it is

nevertheless well recognized that one cotenant

should do nothing to reduce the value of the joint

property without the consent of the other. In

either circumstance, the most likely claim to be

raised by a non joining lessor or cotenant is that

the lessee/operator is causing or permitting oil

and/or gas to be drained away from the property.

Cases have been adjudicated in several jurisdictions on this basis and will be described briefly.
222 . Appendix C

In the case of Tide Water Associated Oil Co. v.

Stott, 73 a pressure maintenance program was undertaken with the approval of the Texas Railroad

Commission by the lessee of the claimants. The

lessors (claimants) refused to join in the unit. The

lessee was also the lessee on other nearby tracts

and maintained its lease on the lessors’ lands by

continuing to conduct primary operations there.

The lessors sued the lessee on the theory that it

was causing drainage of “wet” gas from under

their tracts to the other tracts operated by the

lessees. The Fifth Circuit Court of Appeals held in

favor of the lessee, saying that there was no

liability to the nonconsenting lessors because

they had been given an opportunity to join in the

unit operations on a fair basis.

In the case of Carter Oil Co. v. Dees,74 a lessee

sought a declaratory judgment allowing it to convert an oil production well to a gas injection well

for enhanced recovery operations. The lessor opposed this, claiming it would cause drainage of oil

from underneath his property. Despite a contrary

ruling on an identical case the previous year by

the Seventh Circuit Court of Appeals,75 the Appellate Court of Illinois held for the lessee on the

ground that the additional oil gained by the project through drainage from other land would more

than compensate for the loss from the lessor’s

land.

After the Dees case, the Illinois legislature

passed an act that expressly stated that enhanced

recovery was in the public interest. When a group

of nonconsenting lessors and cotenants attempted to block a waterflood operation in the

case of Reed v. Texas Company, 76 the Illinois

Supreme Court relied upon the legislation to hold

for the operator. The court held that the claimants

had been offered an opportunity to participate in

the program on a fair basis, that the State mining

board had approved the project, and the project

was in the public interest; it stated:

If a minority of one or more persons affected by

the operation could prevent it by refusing to join

in the agreement, they could then force the

others to choose between leaving a large part of

the oil underground, or consent to granting the

dissidents an unreasonably large percentage of

the oil. in other words, the power to block a

repressure program by refusing to sign the

unitization agreement, would be the power to insist upon unjust enrichment. Surely a court of

equity would not support such a rule.

In somewhat similar cases, the North Dakota77 and

Mississippi 78 Supreme Courts followed the same

line of reasoning in holding for the operators of

other enhanced recovery projects.

It should be observed that despite the denial of

damages to lessors, the lessee-operators in cases

such as the Stott case must still satisfy other requirements of their leases to keep them valid.

Thus in Stott the operator had to maintain separate production activities on the leases and had to

account to the claimants separately from the unit

operation. However, the courts have shown a

willingness to support enhanced recovery despite

competing claims of property rights in minerals.

An express statement by the legislature in favor of

enhanced recovery can be of considerable support for this predisposition in litigation of this

nature.

When it is a neighboring interest owner who is

claiming damages the theories asserted in support

of liability are different. By and large, however,

the courts have tended to support enhanced

recovery and, with certain exceptions which will

be noted, have denied liability.

In injection programs, the fluid injected sweeps

from the injection well towards the production

well (s). The migration of the fluid can cross property lines, and this fact has led to claims of

trespass by neighboring interest owners who have

not joined in the unit or enhanced recovery

program when they have felt the production from

their land was reduced by the fluid sweep. The

most important case dealing with this claim of

trespass is a Texas case, Railroad Commission v.

Manziel. 79 In rejecting the neighbor’s claim of

trespass, the Texas Supreme Court adopted the

theory advanced by Professor Howard Williams

and Dean Charles Meyers of a negative rule of

capture. 80 Just as one may produce oil or gas even

though it migrates from the property of another,

so too may one inject a substance into the ground

for production purposes even though it migrates

and causes loss of production for a neighbor. The

court also supported its denial of liability by noting that enhanced recovery is in the public interest. No case involving enhanced recovery has

been found which has granted damages on a
Appendix C . 223

theory of subsurface trespass by injection of

fluids.

For some types of ultrahazardous activities

there is strict liability (liability without a showing

of negligent operations) for damages flowing from

the activity. This legal theory overlaps with the

principle of nuisance, and the two may be treated

together even though one does not usually think

of enhanced recovery as being ultrahazardous. 81

In an important recent case arising in Oklahoma,

the Tenth Circuit Court of Appeals upheld a decision in favor of a claimant for damages for a nonnegligent waterflood project. The court, in

Greyhound Leasing and Financial Corporation v.

Joiner City Unit,82 relied upon a nuisance provision in the Oklahoma Constitution which states

that no private property shall be taken or

damaged for private use unless by consent of the

owner. Although the unit operator had had the

project approved by the Corporation Commission

and had offered the claimant an opportunity to

participate in the unit, the court found liability. It

is possible that the court in another jurisdiction

might hold in this manner even without such a

State constitutional provision. Because the more

exotic methods of enhanced recovery are

relatively new and untried, there is a greater

possibility that a court might find them ultrahazardous than with normal waterflood operations. The

possibility of liability on this ground could be a

disincentive to operations even though a number

of authorities have expressed disfavor with such a

result. Producers in five States indicated that they

have enhanced recovery projects being inhibited

by fear of such liability.

The final basis for liability for enhanced recovery operations is fault, which includes negligent

actions, wanton disregard of the rights of others,

and intentional harm. Liability arising from such

actions is well recognized whether primary or

enhanced recovery operations are involved. In virtually all instances the actions of the operator will

be beyond those included in the order of the

State commission. Few would contend that

operators should have their negligent or intentionally harmful acts excused simply because they

are engaged in enhanced recovery operations,

although questions might be raised about the

standard of care that should be applied to operators in such projects.

In general, the courts have looked with disfavor

upon claimants who have been offered an opportunity to join in an enhanced recovery operation

on a fair and equitable basis and have refused to

join. The commission approval of the projects and

public interest in enhanced recovery of oil tend to

negate the possibility of liability for non-negligent

operations and lend support to the other legal

theories —such as the negative rule of capture—

upon which a court might decide a claim for

damages from a nonconsenting interest owner. A

State statute expressing encouragement for

enhanced recovery will also tend to negate

liability. However, the uncertainty of the law in

many jurisdictions makes the undertaking of

enhanced recovery without joinder of all the interests in the unit either voluntarily or through

compulsory unitization a risky business. Not only

may operations result in liability, but the mere

possibility that a court might so hold could discourage unitization by recalcitrant minority interests and could provide them strong leverage in

bargaining over the participation formula.

Environmental Requirements

Both State and Federal environmental requirements might affect enhanced recovery in several

ways. First, they may cause delay in the approval

and initiation of projects. Second, they may make

enhanced recovery projects a greater economic

risk because they could increase costs, could

cause liability for violations of the requirements,

or could force the shutting down of projects. Such

possibilities could discourage efforts to undertake

EOR projects. It should be noted that present environmental requirements seem to be restricting

only with respect to enhanced recovery in

California, and EPA’s proposed underground injection regulations discussed in a previous section. The areas of environmental regulations that

may be of significance for present or future operations relate to requirements for environmental impact statements, air quality standards, and limitations on water pollution.

Environmental Impact Statements

Environmental impact statements are now required for certain State activities in several States
224 . Appendix C

and for all Federal actions and, proposals significantly affecting the quality of the human environment. In 1970, the California Legislature enacted

the Environmental Quality Act,83 which requires

various State and local governmental entities to

submit environmental impact reports before undertaking certain activities. The affected State and

local agencies are compelled to consider the

possible adverse environmental consequences of

the proposed activity and to record such impacts

in writing. At least one producer has reported that

this California requirement has caused “delay in

waterflood projects due to delay in permits

because of environmental assessment studies.”

These and other requirements had, said the producer, resulted in “presently over 1-year delay in

obtaining permits. ”

The National Environmental Policy Act of 1969

in section 102 (2) (c)84 requires an environmental

impact statement to be completed for every

recommendation or report on proposals for

legislation and other major Federal actions significantly affecting the quality of the human environment. Since the Federal Government is now involved with enhanced recovery only in limited

areas on Federal lands, this Act does not have

much effect on enhanced recovery. However,

should the Federal Government become involved

in regulation of enhanced recovery, an environmental impact statement would probably have to

be filed to meet the requirements of section

102(2) (c).

Air Pollution

Air quality requirements are primarily of significance for thermal recovery projects. The

legislation of greatest importance in this area is

the Federal Clean Air Act of 1970,85 and the State

implementation plans enacted pursuant to it,

Under the Clean Air Act, EPA has established

primary and secondary ambient air quality standards. The primary standards are designed to protect the public health and the secondary standards are to protect the public welfare. It is the

responsibility of the States to promulgate plans

to attain these standards for each of the pollutants for which the EPA has set standards. Limitations for air pollution from new sources of pollution are established by EPA itself. In addition, the

Clean Air Act has been interpreted by the courts

as requiring agencies to prevent any significant

deterioration in air quality in areas already meeting the standards. Both State and Federal governments can enforce the Clean Air Act, and stiff

penalties may be assessed for violation of regulations.

The precise applicability of the Federal and

State requirements under the Clean Air Act depends upon the size and type of equipment used

in steam generation, the quality of the fuel used

for providing a heat source, and the quality of the

air in the State and region where the operations

take place. Since most ongoing thermal projects

are located in California, it is the State in which

there is an indication as to the impact of such air

requirements. One producer there indicated that

an application for a number of enhanced recovery projects was being delayed while EPA sought

additional data on the air quality impact of the

equipment to be used. The same producer suggested that some 25 projects were being delayed

due to present and pending air-quality and landuse regulations. “Thermal recovery projects,” it

stated, “have been delayed due to EPA and

County Air Pollution Control District regulations

and permit requirements. ” At least three other

large and small producers stated that they had

multiple projects being delayed by California airquality requirements. Hydrogen sulfide regulations in Texas have been made more stringent in

recent years, but no producer indicated that this

has had an adverse impact on enhanced recovery.

Water Pollution

The most important aspect of water pollution,

namely pollution of ground water through

seepage from flooding operations, is governed

under State and Federal law by the Safe Drinking

Water Act as previously discussed. Additionally,

the Federal Water Pollution Control Act Amendments of 197286 (FWPCA) regulate water quality.

Under the FWPCA the discharge of pollutants

into navigable waters without a permit is

prohibited. The term “navigable waters” is very

broadly defined. Severe penalties are provided

for violation of the requirements of the Act.
Appendix C ● 225

Other Environmental Regulation

There are other local, State, and Federal regulations that can affect enhanced recovery. Land-use

planning restrictions and zoning, toxic substance

regulation, noise level limits, occupational health

and safety requirements, and other measures may

impact upon enhanced recovery operations in

one way or another. However, the degree of impact is highly speculative at this point.

Water Rights

All types of enhanced recovery, as previously

noted, require water either for flooding purposes

or for steam generation. Water of low quality has

seemed adequate in the past, but for some of the

more sophisticated techniques of enhanced

recovery, fresh water will be more desirable.

Questions of water rights for enhanced recovery

have generated problems and litigation in the

past, and it can be expected that such issues

could become more important in the future. A

brief treatment of the principles that have guided

the courts with respect to water rights suggests

the problems that may be faced in acquiring

water for enhanced recovery.

Before discussing the law applicable to water,

it is necessary to mention some of the classifications of water that are made, for the rights may

turn on the classification. Water, of course, may

be found on the surface of the earth or underground. Surface waters may be classified as

diffused (having no defined channel or course

such as a marsh), water courses, lakes, springs, or

waste water. Underground waters may be

classified as underground streams or as percolating waters (having no flow or water course) .87

The right to own or use water can present

questions in three basic areas. First, there may be

controversy arising between lessor and lessee, or

between surface owner and mineral interest

owner, as to water found on or adjacent to the

land where the oil is located. Second, questions

can arise between those who wish to use water

for enhanced recovery and others who assert

rights to the water but have no relationship with

the enhanced recovery project or land on which

it is located. Third, and perhaps overlapping the

other two, will be matters of regulation of water

use by the States.

Lessor-Lessee Rights

The litigation that has arisen in the past with

respect to water rights for enhanced recovery has

dealt primarily with the respective rights of lessor

and lessee, or surface owners and owners of

mineral interests beneath the surface. For

simplification, reference will be made simply to

lessor and lessee. In such litigation, it has been

presumed that the original owner of the surface

owned the right to the water and could dispose

of it for enhanced recovery purposes; the question litigated has been whether there was such a

disposition, either expressed or implied.

The first type of issue that has arisen is

whether a grant of “oil, gas, and other minerals”

(or a similar phrase) has included water as a

mineral. Courts have held that freshwater is not a

mineral within the meaning of this clause in an oil

and gas lease or deed.88 instead, the courts treat

fresh water as belonging to the surface estate

whether the water occurs at the surface or must

be brought from the underground. Therefore, the

lease or deed from the surface owner must expressly grant rights to use of this water, or the

rights to the water must arise as part of an implied right to use of the surface for the development of the mineral estate. One Texas court

made a distinction between fresh water and salt

water, holding that salt water is part of the

mineral estate,89 but the Texas Supreme Court

has since said that salt water and fresh water alike

should be treated as belonging to the surface

estate.90

Many oil and gas leases do contain an express

grant of right to the lessee to use water from the

lease premises. They often contain a provision

such as the following:91

The lessee shall have the right to use, free of

cost, water, gas and oil found or located on said

land for its operations thereon, except water

from the wells of the lessor.

Does this provision, which does not mention

enhanced recovery, authorize the use of water

from the land for enhanced recovery purposes

when such techniques were not known in the

96-594 0 - 7fj . 1 ~
226 . Appendix C

area or to the industry when the lease was

granted? It is generally treated as authorizing the

use of water on the leased premises for enhanced

recovery, but a notable Texas case, Sun Oil Co. v.

Whitaker, 92 to be discussed shortly, declined to

rule on this question when given the opportunity.

A problem with a clause such as the one quoted

is that the water for enhanced recovery may have

to be used on other lands and this is not permitted by the provision. However, the royalty

owners agreement will include a provision for

this when there is unitization. if a nonroyalty interest owner is the owner of the surface, other

agreement will have to be made to authorize the

use of the water off the leased property.

Finally, even if there is no express provision for

use of water for enhanced recovery, there will

generally be an implied right to use of the water.

As stated in a previous section, the lessee has the

right to use so much of the surface as may be

reasonably necessary to effectuate the purposes

of the lease having due regard for the rights of the

owner of the surface. This will include water, and

several courts have expressly applied this implied

right doctrine to water (both fresh and salt) for

use in enhanced recovery operations. 93

The most recent and important of these decisions is Sun 0il Co. v. Whitaker.94 In this Texas

case, one Gann gave a lease to Sun Oil in 1946

and then conveyed away the surface rights to

Whitaker in 1948. The lease had an express provision for the use of water substantially like the

one quoted above. After years of production by

primary methods, Sun decided to waterflood the

formation. It received authority from the Texas

Railroad Commission to use fresh water for this

purpose, and began producing water from a nonreplenishable water formation for the program.

The owner of the surface, Whitaker, was using

fresh water from the same formation for irrigation

of farmland. Sun sought to prevent Whitaker

from interfering with its production, and

Whitaker in the same suit sought to prevent Sun

from using the water for enhanced recovery. The

court held, without ruling on the extent of the express provision, that the oil and gas lessee’s

estate was the dominant estate, that the lessee

had an implied grant of free use of such part and

so much of the premises as was reasonably

necessary to effectuate the purpose of the lease,

that the implied grant extended to and included

the right to use water in such amounts as would

be reasonably necessary to carry out its operations under the lease, and that the waterflood

operation was reasonably necessary to carry out

the purposes of the lease. It should be noted that

the court found that no other source of usable

water on the leased tract was available, and that

the decision was by a narrow majority of five to

four. With only a slight change of facts this court

and any other could easily hold to the contrary,

so that an enhanced recovery project operator is

certain of his rights to water only if they have

been expressly granted for enhanced recovery

purposes .95

Riparian and Appropriation Rights

When the rights to water of parties other than

the lessor and lessee are considered, several rules

of ownership of rights must be taken up. These

are the doctrines of riparian rights and rights of

prior appropriation, and some States follow a

combination of these two.96 Which rule applies

to a particular State has largely been determined

by the climate and geographical region in which

the State is located. Generally speaking, these

doctrines apply to watercourses with underground waters being governed by a theory of absolute ownership or a reasonable use limitation

only. However, in some States, the rights

doctrines will apply to underground water as well

as surface water.

Riparian Rights. —The doctrine of riparian

rights is found to apply in some 31 States (table

C-2) located primarily in the eastern half of the

United States, where there is more water. Under

this principle, the owner of land adjacent to a

watercourse (the riparian owner) is entitled to

reasonable use of such amount of water as he can

put to a beneficial purpose. A reasonable use is

such that it will not unduly disturb a lower

riparian’s right to some minimum flow of water

and which is suitable to the character and size of

the particular watercourse. A limitation on the

right is that the water must be used on the

riparian owner’s premises, or at least within the

watershed. In States following this principle, percolating waters are generally treated as being

subject to absolute ownership by the surface

owner or a principle like the rule of capture is ap-
plied, so that the underground waters may be

sold and transported away from the watershed.

The significance for enhanced recovery under

the riparian rights approach is that production of

oil is a beneficial use as is required under the

doctrine, and water generally will be available

from one source or another. However, whether

the water is from a watercourse or from underground it may be necessary for the operator to

contract for the water. Use of the water for

waterflooding can be enjoined by lower riparian

owners only if they can show that there has been

an excessive or unreasonable taking of the water,

leaving them with less than their fair share.

Rights of Prior Appropriation.—The doctrine of

prior appropriation developed in the more arid

regions of the United States and presently applies

in nine States, commonly designated as the

Rocky Mountain States. Prior appropriation is the

taking of a portion of a natural supply of water, in

accordance with law, with the intent to apply it

to some beneficial use within a reasonable time.

As before, enhanced recovery operations do constitute a beneficial use of the water.97 The right to

the water is fixed by time, not by location on the

watercourse. Thus, an upstream appropriator

who is later in time (junior appropriator) in his appropriate ion is subordinate in right to a

downstream prior (senior) appropriator’s right to

the water. Appropriation is a vested right then to

take or divert and consume the same quantity of

water forever.

Ownership of land is generally a prerequisite

to appropriation. However, as has been stated by

one authority that “[i] n the absence of statute, it

has always been the rule in States following the

appropriation doctrine that an appropriator may

change the use and place of use so long as the

change does not injure other appropriators. 98 This

means that, subject to State regulation, a party

may acquire or dispose of his appropriation

rights. The importance of this is that operators are

faced with the problem that with prior appropriation the right is perpetual with no provisions for

short term appropriation of water. The ability to

buy and sell rights is significant, for the use of

water for enhanced recovery is of limited amount

and duration; the operator must buy on a shortterm basis, if possible, or appropriate the water

/

Appendix C . 227

and sell the rights after completion of operations.

Where the operator is a junior appropriator, he is

subject to having his water diminish or cease entirely in times of shortage.

Dual System.—Some 10 States apply a combination of the two principles described above

known as the California doctrine. That is, they

follow a rule that a riparian owner may take water

from a source but only as much as he can put to a

reasonable beneficial use. Surplus water is subject to appropriation by nonriparian owners or to

export by riparian owners to nonriparian lands;

but this appropriation or export is junior to the

prior rights of the riparian appropriators. Beyond

this, generalization is very difficult, for the States

have gone in different directions through court

decisions and legislation.

As stated previously, EOR is regarded as a

beneficial use of water. While a nonriparian

operator may acquire rights for water in the dualsystem States, his rights will be subject to prior

appropriation by those senior in rights to him.

Ground water is likely to be the subject of special

legislation in such States.

State Regulation of Water Use

The trend in the current development of water

law has been, as noted by the leading authority

on the subject, “toward more public regulations

through permit systems, accompanied by new

legislative efforts in some States to recognize the

interrelationship between many surface and

ground water sources and to combine the controls and management under one statute. 99

Regulation is more comprehensive generally in

the more arid Western States than in the more

humid Eastern States, although the Eastern States

do regulate pollution of waters. A number of

Western States following the prior appropriation

doctrine have agencies which regulate the acquisition, transfer, or change of appropriation

rights. Because regulation of ground water is of

relatively recent date in most States, its treatment

in statutes tends to be more comprehensive than

for surface waters, and the permit systems are

more extensive.

Whether surface waters or ground waters are

to be used in enhanced recovery, it is likely, particularly in the western half of the United States,
—

228 . Appendix C

that an operator will have to be issued a permit

acknowledging his right to the water prior to

using the water he has acquired for the EOR project. This will probably be done through the office

of a State engineer, a commission, or a water

resources board in a proceeding separate from

the one for a permit to inject the water. The procedure is similar to that for getting approval for

the EOR project. There have been few cases arising from administrative problems involving

enhanced recovery projects, and little or no indication from the literature or the questionnaires

that State regulation of water rights has caused

any problems for enhanced recovery. The potential for problems exists, however, because the

agencies might likely become focal points for

competing claims over the uses to which fresh

water should be put.

Table C-1

Unitization Statues: Voluntary and Compulsory

[Adapted from Eckman, 6 Nat. Res. Lawyer 382 (1973)]

Statute Citation

Alabama. . . . . . . . . . . . . . . . . . . . . . Code of Ala., Tit. 26, ~fj 179 (70) to 179(79)

Alaska. . . . . . . . . . . . . . . . . . . . . . . . Alas. Stat. $31.05.110

Arizona. . . . . . . . . . . . . . . . . . . . . . . Ariz. Rev. Stat. $$27-531 to 27-539

Arkansas. . . . . . . . . . . . . . . . . . . . . . Ark, Stat. Ann. 1947, $53-115, C-1 to C-8

California Subsidence. . . . . . . . . . . Calif. Pub. Res. Code $$3321 to 3342

California Townsite . . . . . . . . . . . . Calif. Pub. Res. Code Q$ 3630 to 3690

Colorado . . . . . . . . . . . . . . . . . . . . . Colo. Rev. Stat. 1963, 100-6-16

Florida. . . . . . . . . . . . . . . . . . . . . . . . Fla. Stat. Ann. ~ 377.28 (1) and (2)

Georgia. . . . . . . . . . . . . . . . . . . . . . . Ga. Code Ann. $43-717 (b) and (c)

Idaho . . . . . . . . . . . . . . . . . . . . . . . . Idaho Code ~ 47-323

Illinois, . . . . . . . . . . . . . . . . . . . . . . . Smith-Hurd, Ill. Rev. Stat. Ch. 104$84 b, c

Indiana . . . . . . . . . . . . . . . . . . . . . . . Burns Ind. Stat. ~ 46-1714 (b) and (c)

Kansas. . . . . . . . . . . . . . . . . . . . . . . .

Louisiana Subsection B. . . . . . . . . .

Louisiana Subsection C . . . . . . . . .

Maine . . . . . . . . . . . . . . . . . . . . . . . .

Michigan . . . . . . . . . . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . . . . . . . . .

Missouri . . . . . . . . . . . . . . . . . . . . .

Montana. . . . . . . . . . . . . . . . . . . . .

Nebraska . . . . . . . . . . . . . . . . . . . . .

Nevada. ... , . . . . . . . . . . . . . . . . . .

New Mexico . . . . . . . . . . . . . . . . . .

New York. ... , . . . . . . . . . . . . . . . .

North Dakota. . . . . . . . . . . . . . . . . .

Ohio. . . . . . . . . . . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . . . . . . . . . . .

Oregon. . . . . . . . . . . . . . . . . . . . . . .

South Dakota. . . . . . . . . . . . . . . . . .

Tennessee . . . . . . . . . . . . . . . . . . . .

Texas . . . . . . . . . . . . . . . . . . . . . . . .

Utah . . . . . . . . . . . . . . . . . . . . . . . . .

Washington . . . . . . . . . . . . . . . . . . . .

West Virginia. . . . . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . . . . . . . .

Kans. Stat. Ann. $$55-1301 to 15-1315

La. Rev. Stat. 1950, Tit. 30, # 5B

La. Rev. Stat. 1950, Tit. 30, $ 5C

Me, Rev. Stat. ~ 2159

Mich. Comp. Laws Ann. 3$319.351 et seq.

Miss. Code 1972 ~$ 53-3-101 to 53-3-110

Rev. Stat. Mo. 1969, $259,120

Rev. Code of Mont. 1947, $$ 60.131.1 to 60.131.9

Re. Rev. Stat. Neb. 1943, $57-910

Nev. Rev. Stat. 522.070

N.M. Stat. Ann $$ 65-14-1 to 65-14-21

N.Y, Environ. Conserv. Law $23-090, subdivs. 1, 3-12

No. Dak. Cent. Code $$ 38-08-09.1 to 38-08-09.17

Ohio Rev. Code $1509.28

52 Okla. Stat. Ann. $~ 287.1 to 287.15

Ore. Rev. Stat. 520.270 to 520.330

So. Dak. Comp. Laws 45-9-37 to 45-9-51

Term. Code Ann. 60-104 (d) (13)

Vernon’s Civ. Stat. Tex. Ann., Article 6008b

Utah Code Ann. 40-6-17

Rev. Code Wash. ~~ 78.52.340 to 78.52.460

W. Va. Code 1931 $4 22-4 A-8 to 22-4 A-9

Wyo. Stat, ~ 30-222
Appendix C . 229

Table C-2

Comparative Chart of Aspects of Unitization Statutes

State

Alabama . . . . . . ., . . .

Alaska ., . . . . . . . . . . .

Arizona . . . . . . . . . . . .

Arkansas . . . . . . . . .

California Subsidence*

California Townsite* . .

Colorado. . . . . . . . . . . .

Florida . . . . . . ., . .

Georgia .., . . . . . . . . . .

Idaho, . . . . . . . . . . . . .

IIllnols ., . . . . . . . . . . .,

Indiana . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . .

Kentucky. . . . . . . . . . . .

Louisiana Subsection B.

Louisiana Subsection C

Maine . . . . . . . . . . . .

Michigan” ’””’”” ““”’”

Mississippi . . . . . . . . . . .

Missouri . . . . . . . . .

Montana. . . . . . . . . . . .

Nebraska. ., . . . . . . . . .

Nevada . . . . . . . . . . . . .

New Mexico, . . . . . . .

New York . . . . . . . . . . . .

North Dakota . . . . . . . .

Ohio . . . . . . . . . . . . . . .

Oklahoma . . . . . . . . . . .

Oregon . . . . . . . . . . . . . .

South Dakota.. . . . .

Tennessee. ., . . . . . . . .

Texas. ., . . . . . . . . . .

Utah. .,... . . . . . . . .

Washington . . . . . . . . . .

West Virginia . . . . . . . . .

Wyoming . . . . . . . . . . . .

Percent working or

royalty int. req’d

vol. = voluntary only:

75

62.5

63

75

65

75

80

75

None

vol.

75

None

75

75

None

75

85-W -65-R

75

85

75

80

75

62.5

75

60

80

65

63

75

75

50

vol.

80

None

75

80

Inc. ult.

recovery

Yes

Yes

Yes

Yes

No

Yes

Yes

Yes

—

—

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

—

—

Yes

Yes

Yes

Proof or findings required

Prevent

waste

Yes

Yes

Yes

Yes

No

—

—

Yes

—

Yes

Yes

Yes

Yes

Yes

Yes

Yes

—

Yes

Yes

Yes

—

Yes

Yes

Yes

—

Yes

—

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Protect corr.

rights

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

—

orYes

Yes

Yes

Yes

Yes

—

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Add.cost

not over

add. recov

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

—

—

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Unit area

Part or All of

Single or

Multip.

pools

PAM

PAS

PAS

PAS

PAM

AS

PAM

PAM

PAS

PAM

PAM

PAS

PAS

PAM

PAS

AM

PAM

PAM

PAM

PAS

PAM

PAM

PAS

PAS

PAS

PAM

PAS

PAS

PAM

PAM

PAM

PAS

A M

AS

PAM

Water rights

doctrine

R-riparian

PA-prior

appropriation

D-dual

system

R

PA

PA

R

D

D

PA

R

R

PA

R

R

D

R

R

R

R

R

D

R

PA

D

PA

PA

R

D

R

D

D

D

R

D

PA

D

R

PA

● See text, page 211.

Adapted in part from Eckman,6Nat Res. Lawyer 384(1973).
—

230 . Appendix C

APPENDIX C

FOOTNOTES

I The description here is of what 15 known as the “unless”

type lease, the type In use in most States. A slightly different

type lease, an “or” lea5e, is In use In Cal ifornla, Th e

difference between the two relates pr{marily to the

automatic termination of the lease in the primary term for

the “unless” lease. H. Willlams and C. Meyers, 0// and Gas

Lam, $601.5 (1975).

‘Gray, “A New Appraisal of the Rights of Lessees Under

011 and Gas Leases to Use and Occupy the Surf ace,” 20

Ro( ky ,tlt. klIn. L, Inst. 227 (1 975).

‘CarI(Ir 011 V. O(>(’S, 92 N. E.2d, 519 (1 950).

~Merrl I I, ‘‘ Impl led Covenants and Secondary Recovery,

4 OLla, 1. K(IV 177 (1 951); Walker, “Problems Incident to

the Acqulsltlon, Use and Disposal of Repressuring Substances Used In Secondary Rec f)very Opera tions, ” 6 Rocky

Al[. $lin L lns[ 273 (1 961); see also, H. Wllllams .lnd C .

Meyers, 0/1 and Cm Law $ 935 (1 975), and cases and

authorities cited therein.

‘

) Martin, “A Modern Look at Implied Covenants to Explore, Develop, and Market Under Mineral Leases, ” 27th Oil

& Gas In)t 177 (Matthew Bender 1976).

‘Iln re Shaller’s Estate, 266 P.2d 613, 616-617 (Okla.

1 954).

- Tlcf~’w.~(tlr 0// Cc), v. Il>nix, 223 F. Supp. 215, 217 (E.D.

Okla. 1963).

See generally, Interstate Oil Compact Comm isslon, A

Study ol Con\erva(ion of 011 and Gas in (he Unltcd S(a(es,

13-14 (1964).

‘)The rules and regulations (No. 105) of the Arizona Oil

and (jas Conservation Commission, to cite another example, provide that an 80-acre spacing will apply for oil wells

in the absence of an order by the Comrnlsslon providing for

the spac Ing of wells and establishing dralhage or drilling

units for a reservoir.

10A recent treatment O( the subject is Bruce, ‘‘Maximum

Efficient Rate—Its Use and Misuse In Production Regulati~~n,tf 9 Nat, R~~~ Ldwyc’r 441 (1 976)

‘z Ibid,

1‘R, Myers, The Law o) Poo/Ing and Unltlzatlon ~ 3.02(2)

(,2d (’d. 1967).

14H. Wllllams and C. Meyers, Oil and Gas Law $ 339.3,

1975.

1‘For cj i Sc Ussion of th IS unit, OTA has drawn upon prutz -

man et al , “Chronicle ot Creating a Fieldwlde Unit, ” .5th Naoonal lrr~(. for P(’troleum Landn-ten 77 (1 964).

I ~JDesc rlptlon of the establishment of this unit is Contained in R. Myers, The Law of Pooling and Unitization Ch. IV

(2d ed. 1967) and the discussion of unit formation which

follows is largely drawn from this work.

ITlbid, ~ 10.08 (1 976 SUpp. ).

‘aIbid. ~ 10.07.

lgEnhanced Oil Recovery, National Petroleum COUnCi!,

(December 1976), 87.

Wbid. 88,

‘l Ibid. 89,

-“R. Myer~, The LJI$ of Poollng and Unitization $4.02 (2d

ed. 1967).

231bid.

Wbid. ~ 4.06,

“

)Appendix C gives the citation to each State’s compulsory unitization statute and the basic requirements of each

State’s act(s) (tables C-1 and C-2).

-’(’43 U.S.C. $1 334(a) (l).

1’OCS Order 11 (16) (Cult of Mexico Area).

~80CS Order 11 (15) (Gulf of Mexico Area).

1’Eckman, “Statutory Fieldwide Oil and Gas Units: A

Review for Future Agreements, ” 6 Nat, R(JJ, Lawyer 339

(1 973); Lawson, “Recent Developments in Pooling and

Unitization, ” 23rd Oil & Gas ln~[, 145 (1 972); R. Myers, The

Law of Poollng and Uni(iza[ion, Ch. IX (2d ed. 1967); W .

Summers, The Law O( Oil and Cm, Chs. 29, 31 (1 966); H.

Wllllams and C. Meyers, Oil arrd Gas Laws $913 (1 975).

~llLoulsiana Revised Statutes, Title 30, Ch. 1, $ 6(B).

‘lE.g., Moore 0//, /nc. v. Snakard, 150 F. Supp. 250 (W.D.

Okla. 1957), remanded on joint motion of parties, 249 F.2d.

318 ~lOth Cir. 1957).

~11 1 Alaska Administrative Code $ 22.540.

I ~Colcjrado, for example, provides that any party to the

commission’s rehearing who is dissatisfied with the disposition of the application for rehearing, “may appeal therefrom

the district court of the county wherein IS located any property of such party affected by the decision, by filing a petition for the review of the action of the commission within

twenty 120] days after the entry of the order following

rehearing or after the refusal for rehearing as the case may

be, ” Colorado Revised Statutes, Title 65, Article 3$ 22(b).

~~Vernon’5 TeX. Ann. Civ. Stat,, Article 6008b $ 1

1

’Louisiana Revised Statutes, Title 30, Ch. 1, $ 5C.

1“Oklahoma Statutes, Title 52, $287.4.

lzlbid. 5287.6.
$8pr(jdLj( (Jrj lj(~velopm(~nt (-0, v. ,Lfa~na 011 C orp , 371

P.2d 702 ((lkla. 1962).

‘“H. Wlillams dnd C, Meyers, 0// and Gaj LJJV $ 97 0

(1 975), and c ases disc ussed therein.

‘“EC kman “Statutorv Fleldwlde Oil and Gas Units: A

Rev Iew for Future Agrtwments, ” 6 hat. R(I$ la~$i [’r 339, 360

(1 973).

‘l E.g., Wyomlrrg Statutes Annotated, $30-222.

‘JH. Wtlllam$ and C. Meyers, 0// anc] Ga$ Lati $ 91 1

(l 977); R Myt~rs, The L~Iv ol Pooling and UmfIza(Ion, Ch.

X11, (2d ed. 19671

~! J1 7 u s. 341 (1 943).

-lJR Myers, Th(I / ail oi P(x)//n,g and Un~/~/al/on $

12.() j (1 J , I Jd cd 19671.

‘; Unl((Id 5[al(’~ v. ( [~lfon Vallc! operators Committee ,

75 F. $upp. 1, 77 F. Supp 409 ~W D. La, 1948), afi’d 339 U.S.

940 (1 950).

~“H, Wll!lam\ and C. Meyer>, 01/ Jnd Ca$ / a~%f ~ 953

( 1 975).

“-Oklahorn.~ C<~rporatl[m Comml>sion, General Rules and

Regu I at lon~ of (1 I I and Gas Cons crvdt Ion DI vision, $

2-261 (d]

‘fiE.g , Texa~ Railroad Commrssltm, 011 ~nd Gas Divtsrcm;

Rule 48, New M[)XICO OIi Conservation Commlsslon, Rule

701 [, 3

“I IJ{J(I \l’a/(lr Alsjo( Mt(Id 0// C(), v Stott, 159 F, 2d 17 4

[5th Clr. 1946), cert. denied 331 U.S. 817 (1 947).

‘Iof)ob$on” v, Arkdr?sa\ 0// drr~ Gaj (-cm~mJ$$Ion, 23 5

S E1’.2d 33 (Ark 1950) .

‘l Other example~ inc Iude R(Ipubl/( Natural (hs CO v,

B~L(Ir, 197 F 2d 647 (1 Oth Clr. 1952); Cor/(Iy v. M)sslsslppi

S/att C)II an(l Gaf B(xard, 105 $ 2d 633 (MI S S. 1958); f3arrr -

I%J(III, In( v. )[ In ()// Co , 162 S 2d 635 (Miss. 1964) Se e

g[>nerdlly, Ii W IIllams and C. Meyers, 01~ and G~\ la~v $933

(1 975)

-’ ( )m( )n R,] f/roc?d Co v. 011 dnd Ca\ Conserkd(lon Comrn/$$/err, 284 P.2d 242 (COIO, 1955),

‘‘t k~/m(’r/( b & Payne, /nc, v, Colporallon C’ommfsslon,

532 P.2d 419 (Okla. 1975).

IiA State by State brief treatment rs Interstate 011 Compact Commission, Summdr) 0/ .%~cond<]r) Recoh(’ry a~)d

Pro$sur(] ~la~n(erranco Ru/(Is ,]nd Regulallfm$ In tire Um(~Jcf

S/a~(’\ (S~~ptember 1969).

> INCW Mexico (JII Conservation Commissl(~n, Rule

701 B 1,

“

{) Kansas Corporatl[~n Commlssitm, (;enf~r,ll Rule\ and

Regulations, $ 82-2-502, A well log IS the written record

d(~s[ rl blng the strata, water, oil or Has encountered I n drll I -

Append;x C . 231

ln~ a well with such additional information as to gas

volumes, pressures rate of fill-up, water depths, caving

strata, and casing record as is usually recorded in the normal

procedure of drilling. /b/d., $82-2-101,

“E.g. Texas Railroad Commission, 011 and Gas Division,

Rule 36(c) (1 O) pertaining to hydrogen sulfide Injections,

W 1 Alaska Administrative Code $ 22.400(c).

>(lMlch igan, for example, gives the supervisor ~Jt’ wel iS the

authority, as part of his power to prevent waste, “To require

the locating, drilling, deepening, redrilling or reopening, c dsing, sealing, operating and plugging of wells drflled for 01 I

and gas or for secondary recovery projects, or wells for the

disposal of salt water, brine or other oil field wastes to be

done in such manner or by such means as to prevent the

escape of oil or gas out of one stratum into another, or of

water or brines into oil or gas strata; to prevent pollutlon

damage to or destruction of fresh water supplles Including

inland lakes and streams and the Great Lakes and connecting waters, and valuable brines by oil, gas or other waters, to

prevent the escape of oil, gas or water into workable coal or

other mineral deposits; to require the disposa I of 5.11 t w,, ter

and brines and oily wastes produced Inc Idcntal to oIl and

gas operations, in such manner and by such methods and

means that no unnecessary damage or danger to or destruction of surface or underground resour( es, to neighboring

properties or rights, or to life, shal

Ann $ 319.6(c).

(1042 USC, $$ 300 f-300j-9.

~~140 CFR Part 146, 41 Fed. Reg.

‘):42 U, S.C.$ 300h (b)(1).

bJ[bid. $! 300h (b) (2).

~IA41 Fed, Reg. 36731.

bjlbid.

result. ” M Ich. Comp Lavv

36730 (August 31, 1976)

~blbid. 36744. 40 CFR $ 146.47.

““35 01/ & Gas Comp<l( / Bu//ef/n, ]unt~ I 976 p 13 ,

‘nCouncil on Wage and Price Stabi lit y Release CM’ PS-204

IO(t. 27, 1976).

w Ibid. at 23-24.

‘~JLetter of Roy F. Ca I son, Production D I ret tor, Amc) rl c a n

Petroleum lnstitut[~, Dall~s, Tex., to Office ot Water Supplv,

Environmental Protection Agency, W~shlngton, D C,, under

date of Jan, 12, 1977.

~ I A I ist of these is contal ned I n H. W I [ I lams and C

Meyers, (JII and Ga\ Law, $ 204.5 (1 975 I,

‘JLynch, “Liability for Secondary Rec oierv (){wr,~tlons,”

22nd 0// & Ca\ /ns[, 37, 79( I 97 I ),

-

‘1 59 F, 2d 174 (5th C ir. 1946), cert. deni[d, 3 I I u $ 817

( 1 947),

“J92 N E 2d 519 III I app, 1950) .
232 . Appendix C

“;Ramsey v. Carter Oil Co., 74 F. Supp. 481 (E. D. Ill.

1947), affm’d 172 F.2d 622 (7th Cir.), cert. denied 337 U.S.

958 (1949), reh. denied, 338 U.S. 842 (1949).

‘[,1 59 N . E . 2d 641 (1 I I 1959) .

“7Svverson v. North Dakota State Industrial Commission,

111 N.W.2d 128 (N.D. 1961).

‘HCallfornia Co. v. Britt, 154 So.2d 144 (Miss. 1963).

“361 S,W.2d 560 (Tex. 1962).

HOH, Will lams and C. Meyers, 0// and Gas 1.Jw, $ 204. 5

(1 975).

. ~lLynch, “Liablllty for Secondary Recovery Operations, ”

22nd 0// & Gas /nst 39, 65 (1971).

w444 F.2d 439 (1 Oth Clr. 1971 ).

~ ICa] ifornld Publ IC Resources Code $$ 21000-21151.

M42 LJ. S.C. S 433 2

“;42 IJ. S.C $$ 1857 e( seq

l i 03 3 u ,s ,C $$ 1151 (’~ $W

‘“These c Iassitications by Hutchins have been critic Ized

but they remain useful and have been important in the

development of water law. See R. Clark, VIatcrs and Water

R@ I/s $ 3.1 (1 967).

88Vogei V. Cobb, 141 P.2d 276 (Okla. 1943); Mack oil

Co v. Laurence, 389 P.2d 955 (Olka. 1964); H. Willlams and

C. Meyers, 0// and GI$ Law $219.6 (l 975).

~~An]~)<]h~ador C)II co, v, Robertjon, 384 S.W 2d 75 2

(Tex. Civ. App. 1964).

Y~JRob/nson V. Robbin \ Pe(roleum Corp , 501 S. W. 2d

865 (Tex. 1973).

‘[l Walker, “Problems Incident to the Acquisition, Use and

Disposal of Repressuring Substances Used in Secondary

Rec every Operations, ” 6th Rocky Mt. M/n. L. /nsr 27 3

(1 961).

“:483 S.W.2d 808 (Tex. 1972).

‘~E.g., HoI( V . SoLIthIve$/ ArrtIoc h Sand UrrIt, Fifth

Enlarged, 292 P,2d 998 (Okla. 1955).

w483 S,W.2d 808 (Tex. 1972).

9:A subsequent Texas case held the implied right to use

water from the surface of the leasehold did not extend to

use of the water for operations otf the leased premises

Robinson v. RobbIns P((rolcum Corp., 501 S.W,2d 865 (Tex.

1 973).

“fiThe discu~sion which follows IS drawn primarily from

the following sources: R. Clark \f’ater and \Va(er RiglI(s

paSSIrTI (1 967); Losee, “Le~al Problems of a Water Supply for

the Oil and Gas Industry, ” 20th Oil & Gas Inst. 55 (1969);

Trelease, “The Use of Fresh Water for Secondary Re[ every

of O i I in the ROC ky Mountain States, ” 16th R(K ky $4(. Min. L.

/nst, 605 (1 971); Walker, “Problems Incident to the Acqulsltlon, Use and D!sposal of Repressuring Substances Used in

Secondary Re( every operations. ” 6th R(x k v M(. M/n. L.

/rr\f, 273 (1 961).

‘-hlafhc’rs v. Texm o, 421 P.2d. 771 (N. M. 1966)

‘

l}’ Losee, “Legal Problems of a Water Supply for the 011

and Gas Industry,: 20th 0// & Gas Inst. 55, 81 (1 969).
Glossary
Glossaryl

Accelerated depreciation—Any of a number of

forms of depreciation which allow the writeoff of capital investments more rapidly than

straight Iine depreciation. Straight Iine

depreciation consists of depreciating an equal

fraction each year over the useful life of the

asset. With accelerated depreciation, larger

fractions are depreciated in earlier years and

smaller fractions in later years.

API gravity—The standard American Petroleum

Institute (API) method for specifying the density of oil:

141.5

degrees API = –131 .5

specific gravity

Barrel—A liquid volume measure equal to 42

U.S. gallons.

Brine—Water saturated with or containing a high

concentration of sodium chloride and other

salts.

Btu—British thermal unit; the amount of heat

needed to raise the temperature of 1 pound of

water 10 F at or near 39.2° F; a measure of

energy.

Capitalized cost—A cost which is capitalized is

not deducted from taxable income in the year

it is incurred; rather it is depreciated over the

useful life of the investment.

Cash bonus leasing —The leasing system currently being used for most offshore lease sales

by the U.S. Government. A fixed royalty,

usually .1667, is used, and the winning bidder

on each tract is the one with the highest offer

of an advance cash payment (bonus) for rights

to explore and develop the tract.

I Sou rc cs: Energy ReMI~ rc h and DCIVC1 opmen t Ad m I n I stra -

tlon and the National Petroleum Council, with addltlons,

Centipoise— A unit of viscosity equal to 0.01

poise. A poise equals 1 dynesecond per square

centimeter. The viscosity of water at 20° C is

1.005 centipoise.

Connate water—Water that was laid down and

entrapped with sedimentary deposits, as distinguished from migratory waters that have

flowed into deposits after they were laid

down.

Constant 1976 dollars—Dollars with the

purchasing power of the U.S. dollar in the year

1976. This term is used to provide a measure

of comparability to project costs, revenues,

rates of return, and capital requirements which

might otherwise be distorted by varying estimates of the unpredictable factor of inflation

or deflation in future years.

Core—A sample of material taken from a well by

means of a hollow drilling bit. Cores are

analyzed to determine their water and oiI content, porosity, permeability, etc.

Darcy—A unit of permeability. A porous medium

has a permeability of 1 darcy when a pressure

of 1 atm on a sample 1 cm long and 1 sq cm in

cross section will force a liquid of 1-cp

viscosity through the sample at the rate of 1 cu

cm/sec.

Depreciation —A deduction from the taxable income base each year to account for wear and

tear and obsolescence of capital equipment.

Depreciation-double declining balance—A

form of accelerated depreciation in which

twice the normal straight line depreciation rate

is applied each year to the remaining depreciation base.

Depreciation-unit of production—Depreciation

based upon the fraction of total estimated

reserves that are produced each year.

235
236 . Glossary

Discounted cash flow rate of return—A particular measurement of investment profitability

that accounts for costs, revenues and the time

value of money.

Emulsion—A suspension of one finely divided

liquid phase in another.

Enhanced oil recovery (EOR)—That recovery of

oil from a petroleum reservoir resulting from

application of an enhanced recovery process.

Enhanced recovery process—A known technique for recovering additional oil from a

petroleum reservoir beyond that economically

recoverable by conventional primary and secondary recovery methods. Three such proc

esses are discussed in this assessment:

Thermal recovery process: Injection of steam

into a petroleum reservoir or propagation of

a combustion zone through a reservoir by

air injection into the reservoir.

Miscible flooding process: Injection of a

material into a petroleum reservoir that is

miscible, or nearly so, with the oil in the

reservoir. In this assessment, carbon dioxide

(CO2

) is the only such material considered.

Chernical flooding process: Injection of water

with added chemicals into a petroleum

reservoir. In this assessment, two chemical

types are considered:

a. surfactants

b. polymers

EOR---Enhanced oil recovery.

Evolution of technology-Presumed future improvements in EOR techniques as a result of

research and experience.

Expensed cost—A cost item which is expensed

is written-off (deducted from the taxable income base) in the year the cost is incurred.

Fireflooding—A synonym for in situ combustion.

Forward combustion —Air is injected and ignition is obtained at the well bore in an injection

well. Continued injection of air drives the

combustion front toward producing wells.

Fracture—A general term to include any kind of

discontinuity in a body of rock if produced by

mechanical failure, whether by shear stress or

tensile stress. Fractures include faults, shears,

joints, and planes of fracture cleavage.

Injection well—A well in an oil field used for

In

In

putting fluids into a reservoir.

situ—in the reservoir, or, in place.

situ combustion—Heatin~ oil to increase its u

mobility by decreasing its viscosity. Heat is applied by igniting the oil sand or tar sand and

keeping the combustion zone active by the injection of air.

Interracial tension—The contractile force of an

interface between two phases.

Investment tax credit—A credit on taxes payable for capital investment. The credit is a fraction of the cost of the capital investment (currently .1) and is received for the year the

investment is placed in service.

Known oil fields-Oil fields in the United States

that have produced petroleum before 1976.

Lease—A part of a field belonging to one owner

or owner group; an owner commonly “leases”

the (mineral) rights to an operator who produces oil, and normally gas, and pays for the

“lease” with part of the production (royalty).

On occasion, the owner (Ieasor) and the

operator (lessee) is the same person.

Micelle (and micellar fluid)—A molecular aggregate, generally of molecules that have an

oil-seeking end and a water-seeking end. An

oriented layer of such molecules on the surface of a colloidal droplet stabilizes oil-inwater or water-in-oil emulsions, making oil

and water quasi-miscible.

Miscible—Refers to liquids and their ability to

mix. Liquids that are not miscible separate into

layers according to their specific gravity.

Miscible agents—A third substance that promotes miscibility between water and oil, such

as natural gas, hydrocarbon gas enriched with

LPG, or compounds that are miscible with oil

and with water.

Miscible displacement—When oil is contacted

with a fluid with which it is miscible, they dissolve each into the other and form a single

phase. There is no interface between the fluids

and hence there are no capillary forces active.
Miscible displacement recovery—The use of

various solvents to increase the flow of crude

oil through reservoir rock.

Mobility—A measure of the ease with which a

fluid moves through reservoir rock; the ratio of

rock permeability to fluid viscosity.

Monte Carlo simulation-A method for estimating the extent to which uncertainty about the

input variables in a complex mathematical

model produces uncertainty in the outputs of

the model. The model is operated using values

selected at random from estimated distributions of the likely values of each input variable.

This process is repeated many times (several

hundred or more), giving a large sample of output values based on a wide range of combinations of values of input variables. These calculated results are then combined to give an

estimate of the mean value and range of

uncertainty for each output variable.

Oil recovery—A procedure whereby petroleum

is removed from a petroleum reservoir through

wells. Three kinds of oil recovery are referred

to in this assessment:

Primary recovery: Oil recovery utilizing only

naturally occurring forces or mechanical or

physical pumping methods.

Secondary recovery: Oil recovery resulting

from injection of water or natural gas into a

petroleum reservoir.

Enhanced recovery: See separate entry.

Oil saturation—The extent to which the voids in

rock contain oil, usually expressed in percent

related to total void.

Original oil-in-place (OOIP)-Petroleum existing in a reservoir before oil recovery.

Permeability—The permeability (or perviousness) of rock is its capacity for transmitting a

fluid. Degree of permeability depends upon

the size and shape of the pores, the size and

shape of the interconnections, and the extent

of the latter. The unit of permeability is the

darcy.

Petroleum —A naturally occurring material

(gaseous, liquid, or solid) composed mainly of

chemical compounds of carbon and hydrogen.

Glossary

Pilot test—An experimental test of an EOR

ess in a small part of a field.

Polyacrylamide-—A type of polymer.

● 2 3 7

procPolymer—A type of organic chemical, characterized by large molecules, that is added to

water for polymer flooding.

Polysaccharide—A type of polymer.

Porosity—The fraction of the total volume of a

material that is made up of empty space, or

pore space. It is expressed in terms of the

volume of pore space per unit volume of the

material. Porosity is a measure of the material

ability to absorb liquids, since it measures the

empty space available to hold liquids.

Present value—The current worth of a flow of income. Income in future periods is discounted

by the interest between the current period and

each future period. Present value is the sum of

the discounted values for all future periods as

shown below:

T

where Vt is the income (or loss) in year t and r

is the rate of interest.

Price elasticity of supply—The responsiveness

of quantity supplied to changes in price.

Specifically, elasticity is the percentage change

in quantity divided by the percentage change

in price.

Primary recovery—See oil recovery.

Rate of return—The rate of interest yielded b y

investments in a project. Specifically, the rate

of return is the rate of interest which equates

the stream of revenues and costs to zero as

shown below:

T

o =

where Vt is after tax value in year t and i is the

rate of interest which equates the time stream

of values to zero. Vt may be positive or negative-usually it will be negative in early years

during investment and positive during later

years.
238 . Glossary

Reserves—The amount of a mineral expected to

be recovered by present day methods and

under present economic conditions.

Reservoir—A discrete section of porous rock

containing an accumulation or oil or gas, either

separately or as a mixture.

Reservoir fluids—Fluids contained within the

reservoir under conditions of reservoir pressure

and temperatures; because of this fact their

characteristics are different from the characteristics of the same fluids existing under normal atmospheric conditions.

Residual oil—The amount of liquid petroleum

remaining in the formation at the end of a

specified production process.

Resource base—Total petroleum in place which

may be subjected to attempted oil recovery,

Resources—The estimated total quantity of a

mineral in the ground.

Reverse combustion—in this process, the formation is ignited at the producing well and the

combustion zone moves countercurrent to the

injected air and reservoir fluid stream. Because

the oil flows into a zone already heated, there

is no tendency for it to congeal and decrease

permeability.

Royalty—A share of production from a lease

reserved for the mineral rights owner.

Saturation—Ratio of volume of pore fluid to pore

volume, expressed as percent and usually applied to water, oil or gas separately. Sum of the

saturations of each fluid in a pore volume is

100 percent.

Screen—A list of conditions that need to be met

if a process is to qualify for oil recovery.

Screening process—The steps of determining if

a process passes or qualifies under a screen.

Secondary recovery—see oil recovery.

Steamflooding —Steam displacement (or steam

drive) follows, the same basic principle as the

waterflood. Steam under pressure is fed into

special injection wells, both to heat the oil in

place and to drive it to producing wells.

Steam soaking—Steam is used as a stimulation

medium to heat the area of the reservoir

around the well bore (also called steam

stimulation, huff-and-puff, or cyclic steam injection). Steam under pressure is injected

down the casing or tubing of a producing well.

A typical steam injection lasts for 5 to 8 days.

Following the injection period, the well is

returned to production.

Sulfonates—Surfactants formed by the reaction

of sulfuric acid (or sulfur trioxide) with organic

molecules. The sulfonate group in its acid form

is S03H, and the sulfur atom is linked directly

to a carbon. In use, sulfonates are neutralized

with bases and used in the ionic form.

Surface tension—The tension forces existing in

the extreme surface film of an exposed liquid

surface due to unbalanced cohesive forces

within the body of the liquid.

Surfactant—A material which tends to concentrate at an interface, used to control the degree

of emulsification, aggregation, dispersion,

interracial tension, wetting, etc.

Sweep efficiency—The ratio of the volume of

rock contacted by the displacing fluid to the

total volume of rock subject to invasion by the

displacing fluid.

Tertiary-Refers to a recovery process that is implemented following secondary recovery; a

third recovery phase following primary recovery and secondary recovery. All tertiary recovery is enhanced recovery, but the reverse does

not always hold.

Thermal recovery —See enhanced recovery process.

Ultimate recovery —The quantity of oil or gas

that a well, pool, field, or property will produce. It is the total obtained or to be obtained

from the beginning to final abandonment.

Viscosity—The internal resistance offered by a

fluid to flow.

Waterflooding—A secondary-recovery operation in which water is injected into a

petroleum reservoir to create a water drive to

increase production.

Well logging—The detailed record of the rocks

passed through in drilling.

U. S. COVER NMENT PRINTING OFFICE : 1’378 O - 96-5!j 4