234
Enhanced Oil Recovery Potential in the United States January 1978 NTIS order #PB-276594
Enhanced Oil Recovery Potential in theUnited 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 OfficeWashington, DC. 20402 Stock No. 052-003-00503-4
TECHNOLOGY ASSESSMENT BOARD DANIEL De SIMONEEDwARD M. KENNEDY, MASS., CHAIRMAN Acting DIRECTOR
LARRY WINN, JR., KANS., VICE CHA IR MAN O FFICE OF T E C H N O L O G Y A S S E S S M E N T
ERNEST F. HOLLINGS, S.C. OLIN E. TEAGUE, TEX.HUBERT H. HUMPHREY, MINN. MORRIS K. UDALL, ARIZ. W ASHINGTON , D.C. 2 0 5 1 0CLIFFORD P. CASE, N.J. GEORGE E. BROWN, JR., CALIF.TED STEVENS, ALASKA CLARENCE E. MILLER, OHIOORRIN G. HATCH. UTAH JOHN W. WYDLER, N.Y.
January 6, 1978
The Honorable Ted StevensTechnology Assessment BoardOffice of Technology AssessmentUnited States SenateWashington, 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 yourequested of the potential of enhanced recovery of oil andDevonian gas in the United States.
This report, Enhanced Recovery of Oil coincides with the recentlyreleased Status Report on the Potential for Gas Production Fromthe Devonian Shales of the Appalachian Basin.
These assessments will provide additional perspective on futureU.S. energy supplies and we hope that they will be helpful as theCongress 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 remainin the United States. However, conventional techniques of extraction candeliver only 10 percent of that oil economically, or about 30 billion bar-rels. What about the remaining 270 bilIion barrels?
This report assesses the potential of enhanced recovery techniquesfor freeing more of this oil from the sandstone and limestone formationsin 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 upor make it easier to flow. The question is at what price?
At current world oil prices, enhanced oil recovery methods couldyield from 11 to 29 billion additional barrels of that trapped oil. And at oilprices comparable to those required to produce synthetic oil from coal,enhanced recovery methods could increase the yield to as much as 42billion extra barrels of oil. At the utmost, about 51 billion barrels might berecoverable, assuming the most favorable economic factors and tech-nologies that can now be foreseen.
This report discusses the uncertainties in these estimates and assessespolicy options available to Congress for recovering more of America’s oilresources.
This assessment is another in the series of energy policy projects thatthe Off ice of Technology Assessment is conducting for the Congress.
DANIEL DeSIMONEActing DirectorOffice of Technology Assessment
OTA EnergyAdvisory Committee
Milton Katz, ChairmanDirector, International Legal Studies, Harvard Law School
Thomas C. Ayers George E. MuellerPresident and Chairman President and Chairman
of the Board of the BoardCommonwealth Edison Company System Development Corporation
Kenneth E. BouldingProfessor of EconomicsInstitute of Behavioral Science University of Colorado
Eugene G. FubiniFubini Consultants, Ltd.
Levi (J. M.) LeathersExecutive Vice PresidentDow Chemical USA
Wassily LeontiefDepartment of EconomicsNew York University
Gerard PielPublisher, Scientific American
John F. Redmond, RetiredShell Oil Company
John C. SawhillPresidentNew York University
Chauncey StarrPresident, Electric Power
Research Institute
vi i
Enhanced Oiland Gas RecoveryAdvisory Panel
Richard Perrine, ChairmanUniversity of California
Gerard Brannon Walter Mead
Georgetown University University of California
Frank Collins Fred H. Poettmann
Oil Chemical and Atomic Workers Marathon Oil CompanyInternational 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, McCollamand 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 EnergyProgram Staff
OTA Energy Program
Lionel S. Johns, Program ManagerRobert J. Rebel, Project Leader
Thomas A. Cotton, Asst. Project Leader
Major Contributors
Russell F. DarrDon W. GreenRobert J. KalterPatrick H. MartinFloyd W. PrestonWallace E. TynerG. 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.
OTAPublicationsStaff
Administrat iveStaff
Lisa JacobsonLinda ParkerCindy pierceJoanne Seder
john C. Holmes, Publications OfficerKathie S. Boss Joanne Heming Cynthia M. Stern
ix
Contents
Chapter Page
1. EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
lntroduction and Summary of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Method of Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Data Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Economic Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Rate of lnitiationof EOR Projects . . . . . . . . . . . . . . . . . . . . . . . . . . 5Cases Examined . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Oil Recovery Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Ultimate Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Rate of Oil Production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Major Uncertainties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Resource Availability and Process Performance . . . . . . . . . . . 8Availability and Cost of Injection Materials. . . . . . . . . . . . . . . 8Rate of lnvestment in EOR Projects . . . . . . . . . . . . . . . . . . . . . 9Marketability of Heavy Crudes . . . . . . . . . . . . . . . . . . . . . . . . 9Combinations of Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . 9
lmpact of Price and Tax Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Special Tax Treatment for EOR Projects . . . . . . . . . . . . . . . . . . . . . 10Price Guarantees and Subsidies for EOR Production. . . . . . . . . . . . 11Alternate OCS Leasing Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . II
Legal Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Environmental Effects.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Il. AN ASSESSMENT OF THE POTENTIAL OF ENHANCED OILRECOVERY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
I l l . OIL RECOVERY POTENTIAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
The Resource Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Original Oil In Place... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Petroleum Reservoirs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Primary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Secondary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Enhanced Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Thermal Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Miscible rocesses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29Chemical Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Other EOR Processes.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
xi
Contents: Chapter /// – Continued
Chapter Page
Oil Resource for Enhanced Oil Recovery processes . . . . . . . . . . . . . . . . 33Data Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Uncertainty in the Oil Resource. . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Methodology for Calculating Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . 35Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Calculation of Reservoir Production and Economics . . . . . . . . . . . . 35Final EOR Process Selection for Reservoirs Passing More Than
One Technical Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Ultimate Recovery for the Nation . . . . . . . . . . . . . . . . . . . . . . . . . . 35Rate of Production for the Nation . . . . . . . . . . . . . . . . . . . . . . . . . . 37Exclusion o Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Estimated Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Definition of Cases . . . . . . . . . . . . .......:. . . . . . . . . . . . . . . . . 38
Case I: Advancing Technology– High-Process Performance. . 38Case ll:Advancing Technology– Low-Process Performance. . 39
Calculation Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39Low-and High-Process Performance Cases . . . . . . . . . . . . . . . 39
Ultimate Oil Recovery by EOR Processes . . . . . . . . . . . . . . . . . . . . 44
Discussion of Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Projected Results for the United States . . . . . . . . . . . . . . . . . . . . . . 46
Ultimate Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Production Rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Uncertainties in Projections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Uncertainties in Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . 47Uncertainties in Projected Production Rates . . . . . . . . . . . . . . 49
Effect of Uncertainty in the Residual Oil Saturation andVolumetric Sweep on Projected Results . . . . . . . . . . . . . . 50
Residual Oil Saturation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Volumetric Sweep.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
Maximum Oil Recovery by EOR Processes . . . . . . . . . . . . . . . . . . . 51
Comparison With Other Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52OTA-NPC Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54OTA-FEA, ERDA Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Technological Constraintson EOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Resource Availability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Process Performance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Process Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Volumetric Sweep Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . 60Brine-Compatible Injection Fluids . . . . . . . . . . . . . . . . . . . . . . 60Development of Additional Processes Applicable to
Carbonate Reservoirs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 60Operating Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61Process Field Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
x i 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 OptionsReservoir Sample. . . . . . . . . . . . . .
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. . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .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. . . . . . . . . . .
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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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Contents: Chapter VI – Continued
Chapter Page
Air Pollution Impacts of Chemical Recovery Methods. . . . . . . 97Surface Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Ground Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100Land Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100Geologic Hazards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101Biota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
Process lndependent lmpacts . . . . . . . . . . . . . . . . . . . . . . . . . 101Process Dependent Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . 102
APPENDIXES
A. Oil Resource for Enhanced Recovery Projections . . . . . . . . . . . . . . . . . . 109
B. Supporting Materials for Oil Recovery Projections From Applicationof Enhanced Oil Recovery Processes . . . . . . . . . . . . . . . . . . . . . . . . 143
C. Legal Aspects of Enhanced Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . 197
GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................235
LIST OF TABLES
TableNumber Page
1.
2.3.4.5.
6.
7.8.9.
10.
11.
12.
Estimates of Ultimate Recoverable Oil and Daily Production RatesFrom EOR: Advancing Technology Case With 10-Percent inimumAcceptable Rate of Return . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Proved Reserves of Crude Oil in the United States,1959-76 . . . . . . . . . .......18U.S. Domestic Production and imports of Oil,1959-76. . . . . . . . . . . . . .......18Estimates of Enhanced Oil Recovery Potential. . . . . . . . . . . . . . . . . . . . . .....19Historical Record f Production, Proved Reserves, Ultimate Recovery, andOriginal Oil in Place, Cumulatively by Year Total United Statesa. . . . .......26Extent of the Reservoir Data Base Utilized in This Assessment of EnhancedOil Recovery Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....34Technical Screen —Enhanced Oil Recovery Processes. . . . . . . . . . . . . . . . . . . .36Schedule of Starting Dates Based on Rate of-Return Criterion. . . . . . . .......37Estimated Recoveries for Advancing Technology–Low-and High-ProcessPerformance Cases–All Processes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....40Estimated Recoveries for Advancing Technology–Low-and High-ProcessPerformance Cases–Steam Drive Process. . . . . . . . . . . . . . . . . . . . . . .......40Estimated Recoveries for Advancing Technology–Low-and High-ProcessPerformance Cases–In Situ Combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4IEstimated Recoveries for Advancing Technology–Low- and High-ProcessPerformance Cases— Surfactant/Polymer . . . . . . . . . . . . . . . . . . . . . . .......41
xiv
List of Tab/es – Continued
TableNumber 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- ProcessPerformance Cases –Carbon Dioxide Miscible . . . . . . . . . . . . . . . . . . . . .. ...42Estimated Recoveries for Advancing Technology– Low- and High-ProcessPerformance Cases — Polymer-Augmented Waterflooding . . . . . . . . . .......43Ultimate Recovery by State– High-Process Performance . . . . . . . . . . .......43Extrapolation of Ultimate Oil Recovery From Data Base Calculations tothe Nation–World Oil Price ($13.75/bbl). . . . . . . . . . . . . . . . . . . . . . . .......44Summary of Oil Recovery Evaluations— Data Base Reservoirs . . . . . . . . . . . ..45Projected Distribution of Known Oil in the United States . . . . . . . . . . .......46Uncertainty in Projections of Ultimate Recovery for AdvancingTechnology Cases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .....46Comparison of Technological Assumptions for the Surfactant/PolymerProcess . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......48Comparison of Ultimate Recovery Under Two Technological Scenarios,Both Assuming High-Process Performance— Surfactant/Polymer Process . . . . .48High-Process Performance at World Oil Price ($13.75/bbl). . . . . . . . . . .......50Impact of Technological Advances in Emission Control in CaliforniaThermal Recovery Projects on Projected Rates for the United StatesUnited States at World Oil Price ($13.75/bbl) . . . . . . . . . . . . . . . . . . . . .. .....50Projections of Ultimate Recovery and Production Rate From the Applicationof Enhanced Oil Recovery Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53Field Activity in Enhanced Oil Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62Number and Percent of Reservoirs Sampled by EOR Process. . . . . . . . . . . . . . .72EOR Reservoir Development Production by Process and Price Level . . .......72Price Elasticity of Supply Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74EOR Development by Process and Policy Option. . . . . . . . . . . . . . . . . . . . . . . .75Input Variables and Subjective Probability Distributions Used for MonteCarlo Simulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76Monte Carlo Simulation of Policy Option Impacts in Reducing Uncertainty .. .77Monte Carlo Simulation of EOR Oil Price Deregulation. . . . . . . . . . . . . . . . . . .79Monte Carlo Simulation of OCS Leasing Systems and EOR Potential. . .......81Comparative Chart of Aspects of Unitization Statutes. . . . . . . . . . . . . .......87Matrix Evaluation of Relative Potential for Environmental Impacts forEnhanced Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .93Potential Distribution of Environmental Impacts for Enhanced Oil Recovery . .94Cross Plot of Environmental Impacts for Enhanced Oil Recovery . . . . . . . . . . .94Emission Factors for Fuel Oil Combustion . . . . . . . . . . . . . . . . . . . . . . .......95Steam Generator Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95Projected Emissions from Steam Flooding of a Major Oil Field Compared toLos Angeles County Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .96Potential Biological Impacts Resulting From EOR . . . . . . . . . . . . . . . . . . . . .. 101
xv
LIST OF FIGURES
FigureNumber 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......17Closeup of Oil Between Grains of Rock . . . . . . . . . . . . . . . . . . . . . . . . .......23Oil Accumulation in the Top of a Dome. . . . . . . . . . . . . . . . . . . . . . . . .......25Oil Accumulation in a Dome at the Top of a Salt Dome and Also in a Regionon the Side of the Dome . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Oil Accumulation Caused by a Fault . . . . . . . . . . . . . . . . . . . . . . . . . . .......25Oil Trapped by Overlying Impervious Cap Rock , . . . . . . . . . . . . . . . . . . . . .. .25Oil Trapped Within Larger Body of Impervious Shale . . . . . . . . . . . . . . . . . . . . 25Cyclic Steam Stimulation Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......28Steam Drive Process (Steam Flood). . . . . . . . . . . . . . . . . . . . . . . . . . . . .......29In Situ Combustion Process—Wet Combustion . . . . . . . . . . . . . . . . . . . . . . . . .30Carbon Dioxide Miscible Flooding Process. . . . . . . . . . . . . . . . . . . . . . .......32Surfactant Flooding Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......32Projected 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 reserveshave declined by an average 3.8 percent a year asdiscoveries of new oil continued to lag behinddomestic production. During that same period,domestic production has declined steadily fromits 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 Organiza-tion of Petroleum Exporting Countries (OPEC) oilembargo and a four-fold increase in world oilprices, have not yet depressed demand for oil inthe United States. Except for a temporary drop inconsumption in 1975, the United States has con-tinued to increase its demand each year and im-ports have climbed steadily to make up thedifference between domestic supplies anddomestic demand.
Unless steps are taken to reduce demand, in-crease domestic production, or achieve somecombination of both, the United States will beobliged to continue to increase its imports, whichaveraged 8.8 million barrels a day during the first8 months of 1977. The United States would re-main vulnerable to future embargoes or arbitraryprice increases. increased U.S. oil imports couldcontribute to imbalances between supply anddemand on a world scale in the early 1980’s thatwould mean even sharper increases in worldprices.
There are only two ways to increase domesticproduction:
●
●
accelerate exploration for new oil supplies,particularly along the Outer ContinentalShelf; and
develop more efficient methods for recover-ing oil” which remains in the ground inknown reservoirs after the first and secondphases of conventional oil production.
This report concentrates on the second ap-proach and assesses the potential for increasingdomestic production from such known reservoirs
with five technologies and methods, known col-lectively as enhanced oil recovery (EOR) tech-niques.
The target for these EOR techniques is some298 billion barrels of oil that will remain trappedin known sandstone and limestone reservoirs inthe United States after producers have pumpedall of the oil that can be taken with primary andsecondary production methods. The EOR proc-esses use heat or chemical fluids which are in-jected into reservoirs to sweep additionalamounts of oil from the sandstone and limestonepore spaces and force it to the surface.
Recent studies of the potential productionpossible with EOR techniques have arrived atestimates that range all the way from 7 billion to76 billion barrels of oil at prices ranging from $10to $15 per barrel, Estimates of the rate of produc-tion as of 1985 range from 0.9 MMBD to 2.3MMBD.
The major findings of the Office of TechnologyAssessment study are:
At current world oil prices ($1 3.75 per barrelin 1976 dollars1), EOR techniques could addbetween 11 billion and 29 billion barrels ofoil to existing domestic reserves. Annualproduction rates could range from o sMMBD to 1.0 MMBD in 1985 and from 0.7MMBD to 1.7 MMBD in 1990.
At the price at which synthetic oil or otheralternate sources might become available($22 per barrel), the potential for EOR ap-pears to be between 25 billion and 42billion 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 toJ u l y 1 , 1976. O n l y t h e 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 tromprlmarv and S(K orrdary method~ was assumed to be at prlc clevels existing In 1976.
.3
4 0
●
●
●
●
Ch, /-Executive Summary
of between 0.9 MMBD and 1.3 MMBD in1985 and 1.8 MMBD to 2.8 MMBD in 1990.
A v igorous program of research anddevelopment, with many field tests sup-ported by laboratory investigations, must beundertaken to achieve significant EOR pro-duction. Even with such a program, eventualproduction would depend on the effective-ness of EOR processes and the validity ofestimates of the amounts of oil remaining inthe known reservoirs.
Estimates of the daily rates of EOR oil pro-duction are much less certain than those forultimate oil production, partly because therate of development of EOR technology isuncertain and partly because EOR opera-tions will have to compete for funds withother investment opportunities. Enhancedoil recovery processes are relatively newand the investment risk is high compared tomore familiar oil exploration and productionmethods. If the oil industry hesitates to in-vest large amounts of capital in EOR proc-esses in the next few years, the productionof oil with enhanced methods would bedelayed.
Estimates of EOR potential presume theavailability of very large quantities of injec-tion materials, such as carbon dioxide (C02)and surfactant. A 50-percent increase in thereal cost of these two materials could limitpotential EOR production to 6 billion to 12billion barrels at the world oil price, or 1 6billion to 33 billion barrels at the alternatefuels price.
The responsiveness of EOR potential to in-creases in the real price of oil drops offabove $22 per barrel. An increase in price to$30 per barrel has the potential of increas-ing the production only about 17 percent,from 42 billion barrels to 49 billion barrels(assuming high process performance).Removing all economic constraints mightadd about 2 billion barrels more. Thus, it isdoubtful that more than about 51 billion ofthe remaining 300 billion barrels of oil canbe recovered under any economic condi-t ions us ing current and foreseeableenhanced recovery technology.
Investment tax incentives (a change from 10to 12 percent in the investment tax creditand accelerated depreciation) appear tohave relatively little effect on investor deci-sions to use EOR processes, but an InternalRevenue Service interpretation that the costof injection chemicals must be depreciatedrather than treated as an expense couldseriously inhibit the use of the high-poten-tial surfactant/polymer and CO2 miscibleprocesses.
Neither a guarantee of $13.7s per barrel nora 15-percent investment subsidy wouldsubstantially reduce the element of risk inEOR decisions for investors.
If investors expect real oil prices to rise at anaverage annual rate of 5 percent, decontrol-ling the price of oil produced by EOR tech-niques would reduce risk and increase po-tential production more than all other taxand price policies examined, including a $3per barrel subsidy.
Any effort to permit a higher price for oilproduced by EOR processes than thatallowed for other oil produced from thesame reservoir would require a fairly precisedetermination of the fraction of total oilproduction that resulted from EOR opera-tions. Highly technical judgments would beinvolved, and there is some doubt thatqualified personnel would be available atthe Federal or State levels to undertake thistask.
In general, the environmental impacts ofEOR techniques are not expected to be sig-nificantly different from those of primaryand secondary production operations. Thereare two main exceptions. First, combustionof oil in thermal processes produces at-mospheric pollutants. Until technology isimplemented to control these emissions, airquality standards are expected to limit ex-pansion of thermal processes already beingused in California. Second, some EOR proc-esses may require large volumes of freshwater, which could strain the capacity oflocal water supplies. Application of EORtechnology which allows the use of salinewater could reduce this problem.
● In order to undertake fieldwide oil recoveryoperations (waterf lood or EOR), i t i sgenerally necessary to secure the consent of .all parties with an interest in the fieldthrough a unitization agreement. Owners ofrelatively small interests can effectively pre-vent the initiation of an enhanced projectby refusing to accept the risks and expensesassociated with a joint EOR venture. Themagnitude of this problem was not deter-mined, but it could be reduced through
Ch. 1—Executivc Summary . 5
compulsory unitization statutes if it provedto be a serious block to EOR operations.Proposed regulations being promulgated bythe Environmental Protection Agency (EPA)pursuant to the Safe Drinking Water Actcould adversely affect EOR development.These proposed regulations cover injectionof materials into the ground. Many pro-ducers believe the proposed regulations willsignificantly restrict or hinder enhancedrecovery of oil,
Method of Analysis
Data Base
This assessment of EOR potential is based on areservoir-by-reservoir analysis of the anticipatedperformance of EOR processes. The data base forthe analysis comprises 385 fields (835 reservoirs)in 19 States, and includes the 245 onshore reser-voirs used in recent studies of EOR potentialpublished by the Federal Energy Administration(FEA) and the National Petroleum Council (NPC).The 385 fields used in the OTA assessment in-clude 24 offshore fields (372 reservoirs) and con-tain 52 percent of the known remaining oil inplace (ROIP) in the United States. Results ob-
tained from the data base were extrapolated on aState-by-State basis to obtain national totals.Alaskan reservoirs were not analyzed becausethere was not enough cost data on EOR opera-tions in a hostile environment.
Technical Screen
Five EOR processes were examined for techni-cal applicability to each reservoir in the database:
in situ combustion,steam injection,C O2 miscible flooding,surfactant/polymer flooding, andpolymer-augmented waterflooding.
Physical properties of each reservoir werecompared with a set of technical criteria basedon an assessment of current technology and ex-pected technological advances. In the first stagein the analysis, a reservoir could qualify for morethan one process. Reservoirs representing about76 billion barrels of oil remaining in place (when
extrapolated for the Nation) were determined tobe unsuited for any known EOR process becauseof physical properties of the reservoir.
Economic Screen
Reservoirs that qualified for one or more EORprocess during the technical screening were thenanalyzed to determine the amount of oil thatwould be produced and the rate of return thatwould result at various oil prices for each applica-ble process. Where reservoirs qualified for morethan one EOR process, the results of this analysiswere compared for each acceptable process.Because the purpose of the assessment was todetermine the maximum amount of oil that couldprofitably be produced under various economicconditions, the process selected for each reser-voir was the one which yielded the greatest ulti-mate oil recovery. In cases where none of the fiveprocesses could show a 10-percent return from agiven reservoir at the world oil price, the pro-cedure was repeated at the alternate fuels priceof $22 per barrel. Reservoirs that did not yield 10percent for any process at the alternate fuelsprice were assigned to the process that appearedto have the best economic chance, or weredropped from consideration if no economicdevelopment seemed likely.
Rate of Initiation of EOR Projects
Because worldwide oil supplies may be limitedstarting in the 1980’s, the daily rates of produc-tion that are possible with EOR operations be-tween 1985 and 2000 may be more important tonational energy policy than the ultimate potential
6 ● Ch. l-Executive Summary
production. However, the potential productionrates are more difficult to estimate than ultimateoil production because the rates depend on thepace of technological development and thespeed with which investors are willing to initiateEOR projects. Initiation of EOR projects dependson availability of capital, willingness of investorsto accept high risks of new and relatively un-tested technologies, and the availability of moreattractive investment opportunities. Because ananalysis of the likely rate of investments in EORwas beyond the scope of this assessment, OTApostulated that EOR projects would becomeeconomically acceptable as investment risksdecreased. Under this assumption, high potentialrates of return (30 percent in 1977) would beneeded in the early years of EOR development tocompensate for the high risks of EOR projects; asfield experience reduces investment risk, lowerrates of return (1 O percent in 1989) wouldbecome attractive.
Cases Examined
Estimates of the technical and economic per-formance of each EOR process were based on anoptimistic but realistic forecast of technological
advances. Such technological advances are ex-pected to result from an ambitious research anddevelopment program involving many field testssupported by basic research. Incorporating apostulated schedule of technology advancement,each EOR process was analyzed using high andlow estimates of process performance. Theresulting high- and low-process performance esti-mates represent OTA’s judgment of the likelyrange of uncertainty in EOR potential. No at-tempt was made to determine the most probablevalue within this range.
Each case was evaluated at three oil prices(using constant 1976 dollars): FEA’s upper tierprice of $11.62 per barrel, the current world oilprice of $13.75 per barrel, and an alternate fuelsprice of $22 per barrel, at which petroleum fromcoal might become available. The effects of high-er costs for injection chemicals, of air qualitystandards, and of a s wer than anticipated rateof investment-risk reduction were determined forthe high- and low-process ‘performance cases. Inaddition, the effects of a sec of price, tax, andleasing options were determined by using a sam-ple of reservoirs representing about 25 percent ofthe data base reservoirs that qualified for an EOR
Oil Recovery
process,
Estimates of the amount of oil that can berecovered using enhanced methods must be in-terpreted with caution. Enhanced methods, ex-cept for thermal processes, have not been exten-sively field tested. The Office of TechnologyAssessment assumed that results obtained fromcontrolled laboratory experiments and carefullyconducted field tests were representative ofwhat would happen in each of the 835 reservoirsin the OTA data base. The uncertainties inherentin this assumption must be considered whenevaluating OTA’s estimates of EOR potential. Bymeans of reviews of existing field and laboratoryEOR data, specific reservoir characteristics,petroleum engineering principles, and reservoirmechanics, OTA has attempted to develop oilrecovery estimates that are realistic. The majoruncertainties in these estimates are identifiedand, where possible, are included in the analysis.
Potential
Ultimate OilProved oil reserves are
Recoverydefined as oil that can
be produced with current technology underspecified economic conditions (usually currentcosts and prices). Consequently, estimates of po-tential additions to proved reserves resultingfrom the application of EOR techniques vary withthe price of the oil. The results of OTA’s analysisare summarized in table 1.
At the FEA upper tier price of $11,62 per bar-rel, the likely range for EOR production is 8billion to 21 billion barrels, depending on processperformance. The results represent an increase inproved and indicated reserves from primary andsecondary production of between 23 and 60 per-cent.
At the FEA upper tier price of $11.62 per barrelIikely range of EOR production is 11 billion to 29
Ch I—FxccutIve Surnmarv . 7
Table 1Estimates 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)
H i g h - p r ( x e s s p e r f o r m a n c e ’ Upper t ier : $ 1 1 . 6 2
Wor ld Oi l : $ 1 3 . 7 5a ’
A l ternate fuels : $ 2 2 . 0 0 ”
5 3 0 . 0 0
M o r e t h a n . s 3 0 . 0 0
Low-process performance Upper tier: $11.62World 011: $13.75Alternate fuels : $ 2 2 . 0 0
a$13.75 IS the January 1977 average price ($14.32 per barrel) oftor(’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 InteragencyTask F( )r( [ I (L.t Imattd t h a t pt,[r~)l(~urn IIquId\ ( OUICI hec{)mt~ avalla-bl[> trtjm ( fkll
billion barrels, representing a 31- to 83-percentincrease in proved and indicated reserves fromprimary and secondary production. increasing theprice to the alternate fuels price of $22 per barrelyields a range of 25 billion to 42 billion barrels,an increase of 71 to 120 percent in proved andindicated reserves.
The high-process performance case was usedto estimate the amount of oil that could beeconomically produced at a price of $30 per bar-rel. This increase in price might yield an addi-tional 7 billion barrels, a 17-percent increase overthe 42 billion barrels estimated to be available at$22 per barrel in the high-process performancecase. The 49 bil l ion barrels that might berecoverable at $30 per barrel represent about 96percent of the 51 billion barrels technologicallyrecoverable (assuming high-process performance)with no economic constraints. While it is possi-ble that new technologies with greater recoverypotential could be developed if oil prices rose ashigh as $30 per barrel, it is not likely that thiswould occur before the end of this century; thispossibil ity would therefore not significantlyaffect the policy implications of this assessment.
Rate of Oil Production
Current (mid-1977) oil production from knownreservoirs using conventional techniques in theUnited States is about 8 MMBD. Daily oil produc-
2 1 . 2
2 9 . 4
4 1 . 6
4 9 . 2
5 1 . 1
8 . 0
1 1 . 1
2 5 . 3
Production rates(millions of barrels/day)
1985 1990 2 0 0 0
0 . 4 1.1 2 . 9
1 . 0 1 . 7 5 . 2
1 . 3 2 , 8 8 . 2d
0 , 4 0 . 5 1.1
0 , 5 0 . 7 1 . 7
0 . 9 1 . 8 5.1
]ndl(,] tt>d r(~~ervt)s“Produt I Ion rate$ 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 MMBDby 1980, including production from Alaska’sPrudhoe Bay; by 1990 production could be aslow as 4.2 MMBD. This assessment indicates thatEOR has the potential of significantly reducingthe decline in domestic production from knownreservoirs, particularly after 1990, if investors in-itiate EOR projects on the schedule assumed inthis analysis. it is anticipated that EOR could addbetween 0.4 MMBD and 1.3 MMBD to domesticproduction by 1985. The lower figure representslow price ($1 1.62 per barrel) and low-processperformance, while the upper figure reflects ahigher price ($22 per barrel) and high-processperformance. At the current world oil price($1 3.75 per barrel) the range would be 0 .5MMBD to 1.0 MMBD.
The potential contribution to domestic pro-duction could increase rapidly after 1985. By1990, the extremes of potential production areestimated to be 0.5 MMBD and 2.8 MMBD, witha range of 0.7 MMBD to 1.7 MMBD at the worldoil price. By the year 2000, possible productioncould be as low as 1.1 MMBD or as high as 8.2MMBD. This higher rate of potential productionexceeds the current rate of domestic oil produc-tion using conventional techniques.
Major Uncertainties
Enhanced oil recovery methodsdeveloping and relatively unproven
represent atechnology.
8 . Ch. l-Executive Summary
For example, the two processes which representover half of the total EOR potential-C02 misci-ble flooding and surfactant/polymer flooding—have received only limited field testing. Conse-quently there are many uncertainties that mustbe considered when interpreting the results ofassessments of the potential of EOR. The follow-ing is a brief discussion of the major areas of un-certainty.
Resource Availability and ProcessPerformance
There is an uncertainty of 15 to 25 percent (ormore) jn the amount of oil remaining in reservoirsafter primary and secondary recovery, In addi-tion, there is uncertainty about the fraction of theremaining oil that can be recovered by an EORprocess even after the process has been suc-cessfully pilot tested. Analysis of the low- andhigh-process performance cases shows that arelatively small reduction in process performancecan lead to a much larger reduction in potentialEOR production; a 12- to 30-percent reduction inthe amount of oil recovered (depending on theprocess) produces a 64-percent reduction in ulti-mate production at $22 per barrel, and a 163-per-cent reduction at $13.75 per barrel. Similar reduc-tions result for the 15- to 25-percent uncertaintyin remaining oil. This disproportionate effect oc-curs because a relatively small decrease in ex-pected production can reduce the rate of returnfrom many reservoirs to below the 10 percentneeded to make EOR operations an attractive in-
process performance case at $13.75 per barrel)would require a total of about 53 trillion cubicfeet (Tcf) of C02, a volume nearly three times theannual consumption of natural gas in the UnitedStates. The estimates of the production potentialof the CO2 miscible process are based on theassumption that most of the C02 would be pro-vided from natural deposits. Natural CO2 can bedelivered 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 EnergyResearch and Development Administration(ERDA) is currently conducting a study of theavai labi l i ty of natural CO 2 for use in EOR.However, even if deposits of sufficient mag-nitude are found, it is possible that the CO2
would be sold at prices considerably above theproduction costs assumed in this study. Highercosts could significantly reduce the amount of oileconomically recoverable using the CO2 miscibleprocess. For example, a 50-percent increase inprice of CO2 could reduce the potential produc-tion from the CO2 miscible process by 49 per-cent, from 13.8 bil l ion to 7.1 bil l ion barrels($13.75 per barrel and high-process perform-ance).
Chemical costs are also important variables inthe surfactant process, the EOR process whichOTA estimates might provide 13 to 34 percent ofthe ultimate EOR production. This process is ex-tremely sensitive to the costs of the injectionchemicals (surfactant and polymer) used. A 5O-
vestment. percent increase in price of surfactants and
Availability and Cost of Injection Materials polymers over the level assumed in this studywould practically eliminate the potential of this
The OTA estimates of EOR potential presume process - at the world oil price, reducing produc-the availability of large quantities of injection tion in the high-process performance case frommaterials. Limitations in availability and/or in- 10.0 billion to 0.2 billion barrels. However, thiscreases in real prices above the level’s assumed in oil could eventually be produced at the alternatethis analysis could significantly reduce both the fuels price, with an ultimate recovery of an esti-ultimate 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 watertotal potential EOR production; requires ex- could ultimately constrain EOR development,tremely large quantities of C02. Production of because EOR processes have a large potential in13.8 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 pre-dicted to be more severe by the year 2000.Achievement of the full potential of EOR will re-quire the development of means for using waterof higher salinities in EOR processes.
Rate of Investment in EOR Projects
As noted, OTA’s estimates of the potentialdaily production from EOR processes are basedon the assumption that EOR projects will be initi-ated according to a postulated schedule relatedto expected rates of return. However, difficultiesin forecasting actual investor behavior suggestthat the estimates of daily production rates areless certain than the estimates of ultimate oilrecovery. Enhanced oil recovery investments willhave to compete for funds with other investmentopportunities. Enhanced oil recovery processesare relatively new, and the investment risk is highcompared to more familiar oil exploration andproduction methods. The oi l industry maytherefore be reluctant to invest large amounts ofcapital in EOR processes in the next few years,which would delay the production of oil bymeans of enhanced recovery methods.
Marketability of Heavy Crudes
Market constraints could limit the develop-ment of thermal methods in California where themarket for the heavy crudes is limited primarilybecause heavy oil requires more processing thanlighter oils, Crude oil from Prudhoe Bay mayfurther reduce the market for California heavy
crude for a short period. A real or perceived weakmarket for heavy oils produced by thermalmethods in California will be a deterrent to ther-mal EOR development in that State. This delaymay well be temporary, but it could result inlower rates of oil production from thermal EORmethods in the 1980’s than those estimated inthis report.
Combinations of Uncertainties
The effects of uncertainties have been evalu-ated independently. Reductions in ultimaterecovery and/or changes in timing of productionresulting from altered assumptions in each ofthese uncertain areas are presented above and inmore detail in chapter III. Changes in ultimaterecovery or timing of production have not beenevaluated for combinations of uncertainties. it ispossible that two or more uncertainties couldsimultaneously reduce EOR potential. In fact, it isremotely possible that resource availability couldbe lower than expected, low-process perform-ance prevail, supply of injection materials beconstrained or costly, and EOR investments re-main relatively risky-all at the same time.Should this occur, EOR potential would be verylow, and EOR production would never make asignificant contribution to national production.
The Office of Technology Assessment doesnot believe this combination of circumstances islikely. The lower bounds presented in this studyrepresent a more realistic estimate of theminimum production which could be expectedfrom EOR techniques,
Impact of Price and Tax Policies
Price
The OTA analysis has assumed that the pricebeing tested would apply only to the incrementof production from a well that could be directlyattributed to the EOR process, while oil beingproduced by primary and secondary methodsfrom the same well would continue to receivethe price for which it is qualified under currentprice control regulations. The same assumptionwas used in independent analyses of EOR poten-tial conducted for FEA and ERDA.
Both the amounts and timing of potential EORproduction are sensitive to the price that will bereceived for the oil. In both the low- and high-process performance cases, the two possibleprice increases considered ($1 1.62 per barrel to$13.75 per barrel and $13.75 per barrel to $22per barrel) produced more than proportional in-creases in potential recovery. Increases in pricehad an even greater effect on the rate at whichEOR production might be brought on-line.
———— ————
70 ● Ch. 1-Executive Summary
In 1976, Congress amended the EmergencyPetroleum Allocation Act to provide additionalprice incentives for bona fide “tertiary enhancedrecovery” (EOR) techniques. Since then, FEA haspublished proposed regulations and has heldpublic hearings on price incentives for oil pro-duced by enhanced techniques. In addition, thePresident recommended decontrolling the priceof EOR oil in his National Energy Plan.
The effects of decontrol of oil produced byEOR methods were tested using a sample ofabout 25 percent of the OTA data base reservoirsthat technically qualified for an EOR process. im-pacts of decontrol depend primarily on investorexpectations about the future market price of oil,It was assumed that investors expected the realprice of oil to rise at an average annual rate of 5percent. With this assumption, more reservoirscould be profitably developed (34 percent morein the sample) with prices decontrolled than ifprices were held at a $13.75 constant real price,At the same time, decontrol would significantlydecrease the risk for investors in all EOR proc-esses except in situ combustion. Decontrol of oilprice was more effective at stimulating develop-ment than any of the other price and tax optionsconsidered. As long as investors expect themarket price of oil to rise, decontrol will reducethe risk of EOR investments compared to a con-trolled-price policy.
The OTA analysis presumes that oil producedby EOR operations will be priced differently fromoil produced by primary and secondary methodsfrom the same well at the same time. The FederalEnergy Administration proposed the same ap-proach in applying price incentives for EOR pro-duction. This policy creates the problem ofdeciding what fraction of total oil productionshould be attributed to EOR when primary andsecondary methods are being used at the samereservoir. The challenge is to define this incre-ment in such a way as to encourage the applica-tion of EOR processes without significantly dis-torting decisions concerning primary and second-ary production.
The FEA proposal involves case-by-case judg-ments concerning the production that would nor-mally be expected using primary and secondarymethods. But that proposal raises questions
about whether the technical expertise for makingsuch decisions would be available at the Federaland/or State levels. An alternative approach, sup-ported by industry in comments on FEA’s pricingproposals, would be to apply the same price in-centives to all oil produced from a field to whichan EOR process was applied. While this wouldavoid the problem of defining EOR incrementaloil, it would leave the problem of defining thelevel of effort required for a project to qualify as abona fide EOR process, and would requiremonitoring to ensure that the effort is main-tained.
A more detailed analysis of the advantagesand disadvantages of these and other incentivepricing options was beyond the scope of OTA’sassessment of the potential contribution of EORprocesses to national reserves. Because of the im-portance and complexity of the associated issues,Congress may wish to examine the problem ofdefining and monitoring EOR operations, andpossibly hold oversight hearings on the proposedFEA pricing regulations for EOR production. Ifdefining EOR incremental oil production andmonitoring EOR operations are found to be criti-cal issues, a mechanism could be developedwhereby bona fide EOR projects could be cer-tified and monitored. Certification and monitor-ing of EOR operations could be performed by theoperator, a State regulatory group, a Federalagency, or a combination of State, Federal, andproducer interests.
Special Tax Treatment for EOR Projects
The impacts of several tax incentives for EORinvestments were analyzed at the world oil price.The options included an increase in the invest-ment tax credit from 10 to 12 percent, acceler-ated depreciation, and an option in which injec-tion costs were depreciated over the life of theproject rather than treated as expenses during theyear they were incurred. Neither the investmenttax credit nor accelerated depreciation had mucheffect on the development of reservoirs usingEOR methods, On the other hand, a requirementthat injection costs be depreciated rather thantreated as expenses led to a large decrease (29percent) in total production. Depreciating rather
than expensing costs of injection materials couldgreatly inhibit the development of the surfactantand CO2 miscible processes, which have the po-tential of providing well over half of the totalEOR production at prices at or above $13.75 perbarrel.
Price Guarantees and Subsidiesfor EOR Production
Three forms of explicit and implicit subsidieswere evaluated: a price guarantee at $13.75 perbarrel; a 15-percent subsidy of EOR investmentcosts (excluding costs of injection materials); anda $3 per barrel price subsidy of EOR oil. Theeffectiveness of a price guarantee dependsalmost entirely on the probability that the worldmarket price of oil will decline below the currentlevel in real terms. Assuming that this probabilityis quite low, a $13.75 per barrel price guaranteewould probably have little effect on the risk ofEOR investments. The 15-percent investmentsubsidy also exhibited little impact on risk or onpotential production, although its effects mightbe somewhat greater than the tax options thatwere considered.
A $3 per barrel price subsidy would be moreeffective than the tax and subsidy optionsanalyzed, and could result in a 6-percent increasein ultimate EOR production and substantiallyreduce the risk to investors. Because the cost ofthe subsidy would be offset to some extent byincreased Government tax revenues from in-creased production, the actual cost of the sub-sidy would be somewhat less than $3 per barrel.
Alternative OCS Leasing Systems
Because a large part of future oil discoveriesare expected to be on the Outer ContinentalShelf (OCS), the effects of several OCS leasingpolicies were tested on a 25-reservoir sample ofthe 294 offshore reservoirs in the OTA data basewhich were amenable to EOR processes. TheUnited States currently uses, almost exclusively, acash-bonus bidding system in which explorationand development rights on an OCS tract aregranted to the group offering the highest front-end payment, or bonus bid. In addition to the
Ch. 1-Executive Summary . 11
cash bonus, a 16.7-percent royalty on gross pro-duction is collected by the Government. The pre-ceding analysis of policy options assumed thatthis method would be in use for the offshore CO2
cases.
Recent discussions of alternate leasing systemshave included proposals for greater use of con-tingency payments (royalties or profit shares,which collect Government revenue based uponthe value of actual production), which are in-tended to reduce front-end capital requirementsand shift a greater share of risk to the Govern-ment. The impacts on EOR production potentialof two such systems were analyzed by OTA: cashbonus plus a 40-percent royalty, and a cashbonus plus a 50-percent net profit share. The 40-percent royalty was shown to increase the invest-ment risk and to make some fields uneconomicfor EOR, a result that confirms earlier studies ofthe impact of high royalties on primary and sec-ondary OCS production. While the profit-sharesystem did not eliminate any fields from con-sideration, it did tend to increase the risk of EORinvestments and could therefore tend to delayEOR implementation. This is contrary to previousresults on primary and secondary production, andsuggests that a profit-share rate of 50 percentwould be too high for EOR development onmarginal fields.
A possible option would be the use of a varia-ble-rate royalty or profit-share approach, inwhich rates would automatically be reduced formarginal fields. Alternatively, the contingencypayment could be waived when that becamenecessary to enable further production, a provi-sion included in proposed amendments to theOuter Continental Shelf Lands Act (S.9 and H.R,1614). While this option was not tested directly,the $3 per barrel price subsidy approximates theremoval of the 16.7-percent royalty at an oil priceof $13.75 per barrel. The $3 per barrel price sub-sidy increased the number of offshore reservoirsin which EOR methods might be economical,These results may somewhat exaggerate thepossible effect of eliminating the royalty becausethe $3 per barrel subsidy is about 30 percentgreater than the current 16.7-percent royalty on$13.75 per barrel oil, and because the policysample of reservoirs contained a higher propor-tion of marginal fields which would be moreaffected 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 toState and Federal regulatory authorities, and astudy was made of pertinent laws, treatises,special reports, and periodical literature. Themost significant existing or potential legal con-straints identified were Federal price controls oncrude oil, weakness or absence of compulsoryunitization statutes in several crucial States, andexisting and proposed environmental protectionregulations. These legal constraints have an im-pact on secondary (waterflood) methods as wellas on EOR.
The issue of price controls and alternative pric-ing policies has been discussed in an earlier sec-tion. The second legal constraint involves unitiza-tion, the joining of interest holders in a reservoirfor the purpose of sharing the costs and benefitsof an efficient development plan for the reservoiras a whole. Unitization is usually desirable; itoften would be essential to make application ofsecondary and enhanced recovery techniques toa reservoir possible. Most producing States pro-vide for compulsory joinder of interest owners ina unit once a certain percentage of interestholders have agreed to unitization. In the ab-sence of such legislation, or where the necessarypercentage of voluntary participation cannot beachieved, secondary and enhanced recoveryoperations can result in substantial liability forthe operator if non joiners suffer damage.
While most States have compulsory unitiza-tion statutes, Texas does not, and the statutes inCalifornia are so limited as to be rather ineffec-tive. These States together represent about halfof the total national EOR potential, and thedifficulties of forming unit agreements maytherefore be a significant obstacle to large-scaledevelopment of EOR production. A field-by-fieldanalysis of ownership patterns is needed todetermine whether difficulties with unitizationmight prove to be a major obstacle to thedevelopment of a significant fraction of EOR po-tential, Such an analysis was beyond the scope ofthis study.
[If unitization problems were found to beserious constraints on EOR production, severalactions could be considered. The FederalGovernment could recommend that each Stateadopt a statute that makes unitization compulso-ry when 60 percent of the working interest androyalty owners consent to unitized operations.The Federal Government could also recommendthat the States adopt statutes to exempt pro-ducers from liability for any damages caused byState-approved enhanced recovery operationsnot involving negligence on the part of the pro-ducer. This would remove a significant constraintto unit operations in the absence of full participa-tion by all the interest owners. Finally, theGovernment could require that States have ap-propriate compulsory unitization statutes in orderto qualify for Federal administrative support, orto avoid having a Federal agency become respon-sible for unitization and enhanced recoveryregulation.
The primary environmental regulatory con-straints on EOR relate to air quality standards inCalifornia and EPA’s proposed regulations underthe Safe Drinking Water Act to control under-ground injections. Current Federal and State en-vironmental regulations under the Clean Air Actlimit total emissions in California to the pollutionlevels which existed in 1976. Therefore, use ofadditional steam generators and air compressorsfor thermal recovery operations in California maybe significantly constrained. Using existinggenerators and compressors, the maximum in-crease in the production rate from thermalmethods in California (the area where thermalprocesses have the greatest potential) will proba-bly be no more than 110,000 barrels per day,about half of the estimated 1990 potential rate ofproduction at the world oil price. Expansion ofthermal production will require application ofemission control technology capable of meetingair quality standards.
The Safe Drinking Water Act, passed in 1974,directs EPA to issue regulations to control under-ground injection of fluids that may threaten the
quality of water in aquifers that are or may beused for public water supply. The act specificallyprovides that requirements in these regulationsmust not interfere with or impede any under-ground injection for the secondary or tertiaryrecovery of oil or natural gas unless such require-ments are essential to ensure that undergroundsources of drinking water will not be endangeredby such injection. However, reaction to EPA’sproposed regulations by such groups as the inter-state Oil Compact Commission, the American
Ch. 1-Executive Summary . 13
petroleum Institute, individual oil producers, andothers indicate that the regulations are perceivedas likely to have an adverse impact on enhancedrecovery operations. Because EOR processes areexpected to pose no greater threat to drinkingwater than waterflooding, which has a goodsafety record, Congress may wish to hold over-sight hearings to determine if the proposedregulations would unduly inhibit the applicationof EOR techniques.
Environmental Effects
In general, the environmental impacts of EORoperations are not expected to be significantlydifferent in type or magnitude than those fromprimary and secondary oil production activities.The major differences are air emissions from ther-mal processes, and increases in consumption offresh, or relatively fresh, water.
Thermal EOR processes produce atmosphericpollutants from the combustion of large quan-tities of oil, either in steam generators (the steaminjection process) or in the reservoir itself (the insitu combustion process). These types of emis-sion are likely to have localized impacts and areexpected to be highly significant in areas that arealready in violation of Federal ambient air qualitystandards. Air quality standards are expected tolimit expansion of thermal processes in Californiaunless effective emission control devices are
used or compensating reductions in emissions aremade elsewhere in the affected area.
As noted in the discussion of resource con-straints, EOR processes in general required signifi-cant quantities of fresh, or relatively fresh, water,whereas secondary waterflooding can use salinewater. This consumption of fresh water not onlywill compete directly with domestic, agricultural,and other industrial uses, but also could result ina drawdown of surface water, which could, inturn, severely affect aquatic flora and fauna in thearea of the drawdown. However, this impactusually would be localized and of short duration.The consumption of fresh water by EOR proc-esses has the greatest potential impact in Califor-nia, Texas, and western. Louisiana, where watersupplies are limited. Development of EOR tech-nologies to allow use of saline water couldreduce this potential problem.
IL An Assessment of the Potentialof Enhanced Oil Recovery
Il. An
The United States must have reliable sourcesof energy to maintain stability. in its energy-inten-s ive economic base —a fact dramaticalIyemphasized in October 1973, when Arab oil pro-ducers imposed a 5-month embargo on oil ship-ments to the United States, and again in the
record-cold winter of 1976-77, when natural gassupplies fell short of demand. Until the oil em-bargo, most Americans took it for granted thattheir energy needs would be met despite declin-ing domestic production of oil and gas, whichtogether provide 75 percent of the Nation’senergy. The embargo and curtailments of naturalgas supplies have made it clear that steady flowsof energy cannot be taken for granted and havedriven policy makers to a search for a nationalpolicy which will make the United States lessreliant on foreign energy sources.
Because of congressional concerns over declin-ing domestic supplies of oil and natural gas, andthe possibility that new technologies can in-crease the Nation’s oil and gas reserves, theOffice of Technology Assessment (OTA) wasasked to assess the potential of the technologyassociated with enhanced oil recovery (EOR).This report is in response to that request.
Proved reserves of crude oil (recoverable withcurrent technology under current economics) inthe United States increased from 20 billion bar-rels in 1946 to 30 billion barrels in 1959. Addi-tions to reserves about equalled withdrawalsfrom domestic reservoirs between 1959 and1970. The discovery of oil in Alaska increased theproved U.S. oil reserve to 39 billion barrels in1970. However, since 1970, the domestic provedoil reserve has declined at a 2- to 5-percent an-nual rate (table 2), annual production from old oil-fields has fallen each year, and the United Stateshas become increasingly dependent on importedoil (table 3). Unless these trends can be reversed,the gap between supplies of domestic oil andU.S. demand will widen within the next 10 to 15
Assessment of the Potentialof Enhanced Oil Recovery
years (figure 1). There are two approaches to in-creasing proved reserves of oil: (1) find additionaloil through increased exploration; and (2) usemore efficient methods to recover oil fromknown reservoirs. Enhanced oil recovery proc-esses fall into the second category.
Figure 1. Projected Oil Production byConventional Methods From Known
U.S. Reservoirs, 1976-95
1976 1980 1985 1990 1995
NOTE: The Decline Curves for Proved and Indicated Reserves, and InferredResetves Do Not Include Enhanced Oil Recoveries Recorded withinthese Categories.
SOURCES: ‘ American Petroleum Institute, Reserves of Crude 0//, NaturalGas Liquids, and Natural Gas m the U.S. and Canada as ofDecember 30, 1975: Lewin & Wsoclates, Inc. for Federal EnergyAdministration, 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 (naturalflow and flushing the oil reservoir with water)recover on average only about one-third of theoil 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 2Proved 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 reservesat beginning
of year
30.531.731.631.831.431.031.031.431.531.430.729.639.038.136.335.334.332.7
Proved reservesat
end of year
31.731.631.831.431.031.031.431.531.430.729.639,038.136.335.334.332.730,9
Net changefrom
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 asofDecembcr 31, 7975, Joint pubhcation by the American Gas Assoctatlon, American Petroleum Institute, andCanadian Petroleum Association, Vol 30, May 1976,
Table3U.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 . . . . . . . . . . . . . . . . . . . . . .
ProductionAnnual
(billions ofbarrels)
2.62.62.62.72.82.82.83.03.23.33.43.53.53.53.43.23.13.0
Daily(millions of
barrels)
7.17.57.27.37.57.67.88.38,89.19.29.69,59.59.28.88.48.1
ImAnnual
(billions ofbarrels)
0.70.70$70.80.80.80.90.90.91,01.21.21.41.72.32.22.22.7
rtsDaily
(millions ofbarrels)
1.81.81.92.12.12.32.52.62.52.83.23.43.94.76.26.16.07.3
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 berecovered from a reservoir increase the provedreserves of that reservoir. Recent studies usingdiffering assumptions indicate that our oilreserves could be increased by as much as 76billion barrels (table 4) by application of EORmethods. Large disparities not only of total futureproduction but of daily production rates fromEOR projects exist in these estimates.
This report assesses the magnitude of the in-creased oil reserves which may result from use of
EOR in an effort to reduce the uncertaintiesposed by earlier studies, and determines reasona-ble limits of ultimate recovery and productionrates under different sets of assumptions abouttechnology, price, and investment climate. Anassessment also has been made of the impact onEOR activity of various policies that could be im-plemented by Congress to increase total recoveryand/or accelerate oil production.
Table 4Estimates of Enhanced Oil Recovery Potential
Source
NPC Studya
- - - - - $ 5- - - - - $10- - - - - $15 (1 976 dollars)- - - - - $20- - - - - $25
G U R Cb (
- - - - $10- - - $ 1 5
(1 974 dollars)
FEA/PIR d
- - - - -- - - - -
EPA”- - - - -- - - - -
business as usual, $11accelerated 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 r e c o v e r )(billions of barrels)
2.27.2
13.220.524.0
18-3651-76
——
716
—
30.5h
15.6’
Production in 1985(millions of barrels/day)
0.30.40.91.51.7
1.1—
1.82.3
——
0.9
21
aTotal U. S.; base case performance and costs; minimum DCFROR requirement of 10 percent; moderatetax case.
bplann,ng Cr,ter,a Re/at;ve 10 a Afa(lona/ RDT & D Program to the Enhanced Recovery of crude Ofl andNa(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 yTesf/ng, Gulf Universttles Research Consortium Report Number 148, Feb. 28, 1976.
dpro,ect /dependence Repor(, Federal Energy Administration, November 1974e 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 thatas of December 31, 1975, about 442 billion bar-rels of oil had been discovered in the UnitedStates, including the North Slope of Alaska.1 O fthat amount, 109 billion barrels had been pro-duced and an additional 37.7 billion barrels re-mained to be produced at current economic con-ditions and with existing technology. This figureincludes 32.7 billion barrels of proved reservesand 5.0 billion barrels of indicated reserves. Thetotal, 37.7 billion barrels, also includes 1.0 billionbarrels of proved EOR reserves and 1.7 billionbarrels of indicated EOR reserves.2 The remaining295 billion barrels represents the resource basefor enhanced oil recovery (EOR). (The resourcebase includes 11 billion barrels in the North Slopeof Alaska but does not include tar sands and oilshale. Technologies to obtain petroleum fromthese sources are sufficiently different from EORprocesses to deserve separate study.)
Petroleum Reservoirs
Oil is found in porous sedimentary rocks(sandstones and limestones) that were depositedunder water and later overlain by formations thatare impervious to these fluids. Localized ac-cumulations of oil occur in traps (reservoirs) with-in these underground formations, or oil pools. Anoil field is the surface region underlain by one ormore of these separate oil reservoirs or pools.
I Reserves of Crude Oil, Natural Gas liquids, and NaturalGas in the United States and Canada as of December 37,7975. Joint publication by the American Gas Association,American Petroleum Institute, and Canadian PetroleumAssociation, Vol. 30, May 1976.
2Enhanced 0// f/ecov~ry, National petroleum CounclltDecember 1976
Oil is found in such traps at depths of from lessthan 100 feet to more than 17,000 feet.3 A reser-voir may be small enough that a single well issufficient to deplete it economically, or largeenough to cover many square miles and requireseveral thousand wells.
Oil is not found in underground lakes, but inopen spaces between grains of rock; oil is held inthese spaces much as water is held in a sponge,Almost invariably, water is mixed with oil in thisopen space between the grains; natural gas isfound in the same kinds of formations. The dis-tribution of fluids in one type of oil reservoir isdisplayed in figure 2.
Because oil is lighter than water, it tends toconcentrate 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 sur-face of the rock grains. This water occupies part of thespace 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 thatforms a trap. Common traps include domes(figure 3), faults (figure 4), and salt domes (figure5). An overlying cap rock can also seal off a for-mation in the manner shown in figure 6. Oil occa-sionally lies within sand bodies enclosed within alarger 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 con-tain and conduct fluids. This lack of uniformityinfluences both the amount of oil present invarious regions of a reservoir and the degree towhich injected fluids can sweep through a forma-tion, collect oil, and force or carry it toward pro-ducing wells. It is this lack of a common patternthat introduces significant economic risk in everyoil recovery project, including EOR.
Oil Recovery
Primary Recovery
The initial stage in producing oil from a reser-voir is called primary production. During thisstage oil is forced to the surface by such naturalforces as: (a) expansion of oil, expansion of thecontained gas, or both; (b) displacement bymigration of naturally pressurized water from acommunicating zone (i.e., a natural water drive);and (c) drainage downward from a high elevationin a reservoir to wells penetrating lower eleva-tions.
The natural expulsive forces present in a givenreservoir depend on rock and fluid properties,geologic structure and geometry of the reservoir,and to some degree on the rate of oil and gasproduction. Several of the forces may be presentin a given reservoir. Recovery efficiencies in theprimary stage vary from less than 10 percent toslightly more than 50 percent of the oil in place.Estimates of cumulative oil production, cumula-tive ultimate oil recovery, and cumulativeoriginal oil in place for 1959-75 are given in table5.
Secondary Recovery
Most of a reservoir’s oil remains in place afterthe natural energy pressurizing the reservoir has
been dissipated. Several techniques for injectingfluids into an oil reservoir to augment the naturalforces have been widely used for many years.Such fluid injection is generally known as sec-ondary recovery. Fluids, most commonly naturalgas and water, are injected through one series ofwells to force oil toward another series of wells.The pattern of injection and production wellsmost appropriate to a reservoir are a matter oftechnical and economic judgment.
There is nothing inherent in fluid injectionprocesses that requires their use only after thenatural energy in a reservoir is exhausted. Indeed,it is frequently desirable to initiate such proc-esses as soon as sufficient knowledge is availableof the geology of the reservoir and the type ofnatural expulsive forces that are operative.
When water is the injection fluid, the processis commonly called waterflooding. If water isused to supplement a partially active naturalwater drive, the process is classified as a pressuremaintenance project. When natural gas is in-jected, the operation is also called a pressuremaintenance project. Injection of natural gas waswidely used in the era of abundant low-cost gas,but the practice has decreased as the price of gashas increased.
Ch III—Oil Recovery Potential 25
Types of Traps for Oil Accumulation*
Figure 3.
W a t e r
0il accumulation in the top of a dome. Rock overlylng thedome is Impervious.
Figure 5.
h i m p e r v l o u s / Gas
011 accumulation caused by a fault. The block to the righthas moved upward so the oil formation is opposite the im-pervious shale, forming a trap.
Figure 4.+ ~ C a p R o c k
Oil accumulation in a dome at the top of a salt dome andalso in a region on the side of the dome. Salt is Imperviousto the oil.
Figure 6.
ImperviousCap Rock
.
Water
Figure 7.
Oil trapped by overlying impervious cap-rock that inter-rupts lower lying formation of sandstone or limestone.
Oil trapped within larger body of impervious shale. -
“Illustra[lons redrawn and printed with permission of the AmericanPetroleum Instilute I American Petroleum Institute 1971
26 . Ch ///-01/ Recovery Potential
Table 5Historicai 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 . . . . . . . . . . . . . . .
Cumulativeproduction
62.364.767.269.872.475.177.880.683.786.890.093.396.699.9
103.1106.1109.0
1975 estimate ofcumulative
ultimate recovery**
122.3123.3123.7124.7125.3126.2127,6128.0128.7139.2139.8140.4140.9141.1141.4141.6141.7
1975 estimate ofcumulative
original oil in place**
384.7387.8389.8392.5394.7397.8402.4404.4407.0432.5434.8437.1438.7439.6440.9441.4441.9
● “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, andCanadian Petroleum Association, Vol. 30, May 1976
Secondary recovery is proven technology; in-deed, a recent study indicates that 50 percent ofall domestic crude oil comes from secondaryrecovery operations.4
Waterflooding is inherently more efficientthan gas displacement in pressure-maintenanceprojects and is the preferred process where feasi-ble. Cumulative recoveries by primary and sec-ondary production, where the secondary produc-tion is waterflooding, average between 38 and 43percent of the original oil in place.
Some reservoirs, principally those containingheavy oil that flows only with great difficulty, notonly provide poor primary recovery but often arenot susceptible to waterflooding. Enhanced oil
4Enhanced Oil Recovery, National Petroleum Council,December 1976.
recovery would be especially useful in some ofthese reservoirs.
Enhanced Recovery
Processes that inject fluids other than naturalgas and water to augment a reservoir’s ability toproduce oil have been designated “improved,”“tertiary,” and “enhanced” oil recovery proc-esses. The term used in this assessment isenhanced oil recovery (EOR).
According to American Petroleum Instituteestimates of original oil in place and ultimaterecovery, approximately two-thirds of the oil dis-covered will remain in an average reservoir afterprimary and secondary production. This ineffi-ciency of oil recovery processes has long beenknown and the knowledge has stimulatedlaboratory and field testing of new processes for
more than 50 years. Early experiments with un-conventional fluids to improve oil recovery in-volved the use of steam (1920’s)5 and air for com-bustion to create heat (1935).6
Current EOR processes may be divided intofour categories: (a) thermal, (b) miscible, ( c )
chemical, and (d) other. Most EOR processesrepresent essentially untried, high-risk tech-nology. One thermal process has achievedmoderately widespread commercialization. Themechanisms of miscible processes are reasonablywell understood, but it is still difficult to predictwhether they will work and be profitable in anygiven reservoir. The chemical processes are themost technically complex, but they also couldproduce the highest recovery efficiencies.
The potential applicability of all EOR proc-esses is limited not only by technological con-straints, but by economic, material, and institu-tional constraints as well.
Thermal Processes
Viscosity, a measure of a liquid’s ability toflow, varies widely among crude oils. Somecrudes flow like road tar, others as readily aswater. High viscosity makes oil difficult torecover with primary or secondary productionmethods.
The viscosity of most oi l s dramatical lydecreases as temperature increases, and the pur-pose of all thermal oil-recovery processes istherefore to heat the oil to make it flow or makeit easier to drive with injected fluids. An injectedfluid may be steam or hot water (steam injec-tion), or air (combustion processes).
Steam Injection. —Steam injection is the mostadvanced and most widely used EOR process. ithas been successfully used in some reservoirs inCalifornia since the mid-1960’s. There are twoversions 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 steamor steam and hot water is injected into a well fora period of days or weeks. The injection isstopped and the reservoir is allowed to “soak.”After a few days or weeks, the well is allowed tobackflow to the surface. Pressure in the produc-ing well is allowed to decrease and some of thewater that condensed from steam during injec-tion or that was injected as hot water then vapor-izes and drives heated oil toward the producingwell. When oil production has declined apprecia-bly, the process is repeated. Because of its cyclicnature, this process is occasionally referred to asthe “huff and puff” method.
The second method, steam drive or steamflooding, involves continuous injection of steamor steam and hot water in much the same waythat water is injected in waterflooding. A reser-voir or a portion thereof is developed with in-terlocking patterns of injection and productionwells. During this process, a series of zonesdevelop as the fluids move from injection well toproducing well. Nearest the injection well is asteam zone, ahead of this is a zone of steam con-densate (water), and in front of the condensedwater is a band or region of oil being moved bythe water. The steam and hot water zonetogether remove the oil and force it ahead of thewater.
Cyclic steam injection is usually attempted ina reservoir before a full-scale steam drive is initi-ated, partially as a means of determining thetechnical feasibility of the process for a particularreservoir and partly to improve the efficiency ofthe subsequent steam drive. A steam drive,where applicable, will recover more oil thancyclic steam injection and is one of the five EORmethods used in this study of the national poten-tial for EOR processes. Illustrations of the opera-tion of cyclic steam injection and steam drive aregiven in figures 8 and 9, respectively.
CornbustiorI Processes. -Combustion projectsare technologically complex, and difficult to pre-dict and control. Interest in the process hasdeclined within the last 6 years relative to otherEOR processes. Active field tests declined from30 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
LEGEND8
Hot Water Zone
“Ilhmtraticms radrswn and printad with parmkaion of tha NationalPetroisum Council. @ National Patrokum Council, 1976.
I ]Oi l 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 oilwithin a reservoir. Although some oil is lost byburning, the hot combustion product gases moveahead of the combustion zone to distill oil andpush it toward producing wells. Air is injectedthrough one pattern of wells and oil is producedfrom another interlocking pattern of wells in amanner similar to waterflooding. This process isreferred to as fire flooding, in situ (in place) com-bustion, or forward combustion. Althoughoriginally conceived to apply to very viscouscrude oils not susceptible to waterflooding, themethod is theoretically applicable to a relativelywide range of crude oils.
An important modification of forward combus-tion is the wet combustion process. Much of theheat generated in forward combustion is leftbehind the burning front. This heat was used toraise the temperature of the rock to the tem-perature of the combustion. Some of this heatmay be recovered by injection of alternate slugsof water and air. The water is vaporized when ittouches the hot formation. The vapor movesthrough the combustion zone heating the oilahead of it and assists the production of oil. Withproper regulation of the proportion of water andair, the combustion can proceed at a higher ther-mal efficiency than under forward combustionwithout water injection.
Combustion processes compete, at least tech-nologically, with steam and some other EORprocesses, and the choice depends upon oil andreservoir characteristics. The wet combustionprocess is illustrated in figure 10. It is the com-bustion process selected for technical andeconomic modeling in this study.
Miscible Processes
Miscible processes are those in which an in-jected fluid dissolves in the oil it contacts, form-ing a single oil-like liquid that can flow throughthe reservoir more easily then the original crude.A variety of such processes have been developedusing different fluids that can mix with oil, in-cluding alcohols, carbon dioxide, petroleum hy -
7Management p/an for Enhanced Oil Recovery, ERDA77-1 5/2, Vol. 2 (of 2), D . B-7, Februarv 1977.
drocarbons such as propane or propane-butanemixtures, and petroleum gases rich in ethane,propane, butane, and pentane.
The fluid must be carefully selected for eachreservoir and type of crude to ensure that the oiland injected fluid will mix. The cost of the in-jected fluid is quite high in all known processes,and therefore either the process must include asupplementary operation to recover expensiveinjected fluid, or the injected material must beused sparingly. In this process, a “slug,” whichvaries from 5 to 50 percent of the reservoirvolume, is pushed through the reservoir by gas,water (brine), or chemically treated brine to con-tact and displace the mixture of fluid and oil.
Miscible processes involve only moderatelycomplex technology compared with other EORprocesses. Although many miscible fluids havebeen field tested, much remains to be deter-mined about the proper formulation of variouschemical systems to effect complete volubilityand to maintain this volubility in the reservoir asthe solvent slug is pushed through it.
One large (50,000 acre) commercial project inTexas uses carbon dioxide (C02) as the miscibleagent, Eight other C02 projects covering 9,400acres are. in early stages of development.8
Because of the high value of hydrocarbons andchemicals derived from hydrocarbons, it isgenerally felt that such materials would not makedesirable injection fluids under current or futureeconomic conditions. For this reason, attentionhas turned to C02 as a solvent. Conditions forcomplete mixing of C02 with crude oil dependon reservoir temperature and pressure and on thechemical nature and density of the oil.
A l though there are many poss ib le CO2
sources, the largest source should be naturallyoccurring deposits. Currently known sources ofnaturally occurring CO2 are described in publica-tions of the U.S. Bureau of Mines. A summary ofC O2 source locations is presented by the Na-tional petroleum Council,9 although the actual
8Managemen[ plan for Enhanced Oil Recovery, ERDA77-1 5/2, Vol. 2 (of 2) p. B-4, February 1977.
gEnhanced 0;/ Recovery, Nat ional 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 Gtth8MionatPetmbum CotmciL @ National Petroleum Council, 1976.
amount of CO2 at these locations is unknown.The potential demand for C0 2 is such thatgeological exploration is in progress.
A pictorial representation of a C02 miscibleflood is shown in figure 11. In the past, CO2 hassometimes, been injected into reservoirs in quan-tities and at pressures less than those necessaryto achieve complete miscibility, resulting in lessoil recovery than when complete mixing isachieved. In this assessment, quantities andpressures of CO 2 injected are designed toachieve complete miscibility.
Chemical Processes
Three EOR processes involve the use of chemi-cals—surfactant/polymer, polymer, and alkalineflooding.
Surfactant/Polyrner Flooding.—Surfactant/poIy-mer flooding, also known as microemulsionflooding or micellar flooding, is the newest andmost complex of the EOR processes, While it hasa potential for superior oil recovery, few majorfield tests have been completed or evaluated.Several major tests are now under way to deter-mine its technical and economic feasibility.
Surfactant/polymer flooding can be any one ofseveral processes in which detergent-l ikematerials are injected as a slug of fluid to modifythe chemical interaction of oil with its surround-ings. These processes emulsify or otherwise dis-solve or partly dissolve the oil within the forma-tion. Because of the cost of such agents, thevolume of a slug can represent only a small per-centage of the reservoir volume. To preserve theintegrity of the slug as it moves through the reser-voir, it is pushed by water to which a polymer hasbeen added. The surfactant/polymer process is il-lustrated in figure 12.
The chemical composition of a slug and its sizemust be carefully selected for each reser-voir/crude oil system. Not all parameters for thisdesign process are well understood.
polymer Flooding. -Polymer flooding is achemically augmented waterflood in which smallc o n c e n t r a t i o n s o f c h e m i c a l s , s u c h a spolyacrylamides or polysaccharides, are added toinjected water to increase the effectiveness ofthe water in displacing oil. The change in recov-
Ch. //I--Oil Recovery Potent/a/ . 31
ery effectiveness is achieved by several differentmechanisms, not all of which are completely un-derstood. Improvement in the efficiency ofwaterflood recovery with the use of polymers isrelatively modest, but it is large enough for theprocess to be in limited commercial use. If otherEOR processes are technically possible they offera possibility of both greater oil recovery andgreater economic return than polymer flooding,although each reservoir must be evaluated in-dividually to select the most effective process. Asit is currently in use, polymer flooding is evalu-ated in this assessment.
Alkaline Flooding.—Water solutions of certainchemicals such as sodium hydroxide, sodium sili-cate, and sodium carbonate are strongly alkaline.These solutions will react with constituents pres-ent in some crude oils or present at therock/crude oil interface to form detergent-likematerials which reduce the ability of the forma-tion to retain the oil. The few tests which havebeen reported are technically encouraging, butthe technology is not nearly so well developed asthose described previously. Alkaline floodingwas not quantitatively evaluated in the presentstudy, largely because there is too little informa-tion about key oil characteristics in the OTAreservoir data base which are crucial to a deter-mination of the feasibility of alkaline flooding.Reservoirs not considered for alkaline floodingbecame candidates for other processes.
Other EOR Processes
Over the years, many processes for improvingoil recovery have been developed, a large num-ber of patents have been issued, and a significantnumber of processes have been field tested. Inevaluating a conceptual process, it should berecognized that a single field test or patent repre-sents but a small step toward commercial use ona scale large enough to influence the Nation’ssupply of crude oil. Some known processes havevery limited application, For example, if thincoalbeds lay under an oil reservoir this coal couldbe ignited, the oil above it would be heated, itsviscosity would be reduced, and it would beeasier to recover. This relationship between oiland coal is rare, however, and the process is notimportant 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 permiaaion of the NationalPetrokum Council. @ National Petroleum Counci{, 1976.
energy to fracture an oil-bearing formation andform a carbon track or band between wells. This
band would then be used as a high-resistanceelectrical pathway through which electric currentwould be applied, causing the “resistor” to heatthe formation, reduce oil viscosity, and increaseoil recovery. The process was conceived over 25years ago and has been tested sporadically, butdoes not appear to have significant potential. Athird process in this category is the use of bac-teria for recovery of oil. Several variations havebeen conceived. These include use of bacteriawithin a reservoir to generate surface-active(detergent-like) materials that would performmuch the same function as a surfactant/polymer
Ch. III—0il Recovery Potential . 33
flood. Although some bacteria are able to with-stand temperatures and pressure found in oilreservoirs, none have been found that will bothsuccessfully generate useful modifying chemicalsin sufficient amounts and also tolerate the chemi-cal and thermal environments in most reservoirs.It is uncertain whether nutrients to keep themalive could be provided. Further, any strain ofbacteria developed would need to be carefullyscreened for potential environmental impacts.Finally, even should the concept prove feasible, itis unlikely that the bacteria could be developed,tested, and used in commercial operation in timeto influence oil recovery by the year 2000.
Oil Resource
Data Base
The analytic approach used in
for Enhanced Oil
Theeludes
Recovery Processes
resulting data base for the assessment in-385 fields from 19 States (table 6). These
this assessmentof EOR potential relies on reservoir-by-reservoirsimulations. The accuracy of this approach de-pends on the extent, representativeness, and pre-cision of the reservoir data file. Earlier reports10 11
have been based on data from 245 large onshorereservoirs in California, Louisiana, and Texas. Forthis assessment, additional data were collectedfor onshore reservoirs in those States, for reser-voirs in other producing areas of the UnitedStates, and for reservoirs in offshore areas (pri-marily the Gulf of Mexico). The expanded database for this assessment was acquired fromFederal, State, and private sources. After allavailable data were examined and cataloged,they were edited for volumetric consistency.These data were reviewed by OTA as othersources of information became available. Addi-tional data led to reductions in estimates of re-maining oil in place (ROIP) in California reservoirswhich contained oil with gravities above 25° API.
lfJThe potentja/ and [conomics of Enhanced Oil Recovery,Lewin a n d A s s o c i a t e s , I n c . , f o r t h e F e d e r a l E n e r g y A d -ministration, April 1976.
II Enhanced 0;/ Recovery, National petroleum council,
December 1976.
385 fields (835 reservoirs) contain 52 percent ofthe known ROIP in the United States. The reser-voir data in the OTA data base are representativeof the known oil reservoirs in the United States.
Uncertainty in the Oil Resource
Two EOR processes, surfactant/polymer andC02 miscible, are generally applied after a reser-voir has been waterflooded. A large portion ofthe resource for these processes will be locatedin the reservoir volume which was contacted bywater. The oil remaining in this region is termedthe residual oil saturation.
There is uncertainty in the estimates ofresidual oil saturation and hence in the oil whichis potentially recoverable with surfactant/polymer and CO2 miscible processes. A review ofthe technical literature and discussions withknowledgeable personnel in the oil industry ledto the following observations:
a
b
There are few reservoirs whose estimates ofresidual oil have been confirmed by inde-pendent measurement.
The uncertainty in the aggregate estimate isdue to a lack of confidence in measurement
34 . Ch. ///—Oil Recovery Potential
State
Table 6Extent of the Reservoir Data Base Utilized in ThisAssessment 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 oilin place(MMB)
51914,827
2,76862,926
3,002556
5,72610,403
13,6967,3492,9883,796
11,2411,849
25,4065,344
100,5912,7252,064
10,628
288,404
Fields
263
4121
38
28
2424111515
633
5111
62
21
385
OTA databaseRemaining oil
Reservoirs
293
6721
39
28
47372
121518
735
6146
62
27
835
in place(MMB)
35414,601
1,32845,125
1,490465
2,4213,345
6,7312,9831,1871,4434,960
5486,5481,077
54,2211,734
1944,543
115,298
Percent ofState
6898487250844232
4941403844302620546 4
943
54
Total U.S. (MMB) 300,338aOTA 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 doesnot 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 surfac-plication of those methods. tant/polymer and C02 miscible processes
will have a large range of uncertaintyc. The estimates of residual oil saturation may
because of the uncertainties in the esti-be 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 berecovered by the different EOR processes werebased upon an individual analysis of each reser-voir in the data file. Results from the individualreservoir calculations were then compiled andextrapolated to a national total. In outline form,the procedure consisted of the following steps.
Technical Screen
A technical screen was established for eachprocess. Reservoir rock and crude oil propertieswere screened against standards which had to bemet before an EOR process could be consideredapplicable to that reservoir. The technical screensfor all processes are shown in table 7. Thesescreening parameters were established after anassessment of current technology and incorpora-tion of expected technological advances. Eachreservoir was compared to the technical screenfor every process and either accepted or rejectedfor each process. A reservoir could be a candi-date for more than one EOR process.
Calculation of Reservoir Productionand Economics
Reservoirs which passed the technical screenwere then analyzed to determine probable pro-duction performance and economics. Thosereservoirs eligible for more than one EOR processwere analyzed for all processes for which theywere technically acceptable. For each process,both an oil recovery model and an economicmodel were established, Oil recovery models,described in appendix B, were used to predict theamount of oil which would be recovered and therate at which the oil would be produced. Theserecovery models all incorporate features whichmade the calculations dependent upon the par-ticular characteristics of the reservoirs.
The economic model described in appendix Bwas used to compute, at a specified oil price, arate of return on investment which would resultfrom application of a selected EOR process to aparticular reservoir. The economic model
allowed for different operating and drilling costsin different geographic regions, different wellspacings, variable EOR process costs, etc. Themodel also incorporated a field developmentscheme. This scheme allowed a specified numberof years for pilot tests and economic andengineering evaluations. It also provided fordevelopment of a field on a set time schedulerather than for simultaneous implementation ofan EOR process over the entire field.12
Final EOR Process Selection forReservoirs Passing More Than One
Technical Screen
For reservoirs passing more than one technicalscreen, production resulting from application of arecovery technique and economic models foreach acceptable EOR process were compared.The process selected was the one which yieldedthe greatest ultimate oil recovery, as long as theprocess earned at least a 10-percent rate of returnon investment at the world oil price of $13.7sper barrel. If no process earned 10 percent at theworld oil price, then the alternate fuels price of$22 per barrel was used, again selecting the proc-ess which yielded the greatest amount of oil.Reservoirs not yielding 10 percent for any processat the alternate fuels price of $22 per barrel wereplaced in the process which appeared to have thebest economic potential. Reservoirs were deletedfrom consideration if the computations at thealternate fuels price resulted in a negative returnon investment.
Ultimate Recovery for the Nation
Ultimate recovery for the Nation was esti-mated by extrapolating the individual reservoir
I ~Our analysis assurnecf that enhanced recovery opera-
tions would be installed before producing wells are pluggedand abandoned. If enhanced recovery operations are begunafter producing wells are plugged and abandoned, oil recov-ery will be slightly more costly ($1 to $3 per barrel) andmost likely delayed because of economics.
36 . Ch. ///—Oil Recovery Potential
o1 o ’
‘ VI ‘t
t, 1 1
1 1
I I
c. -
I
1
t
,,
o00In
18 t
11 v ‘8 ‘1’ ‘I 1= 1,1 1
It o #o ‘ Al ‘ ‘ ‘ ‘mA
1
I
1
1
#
I
. .● ✎ ✎u“0
Ch. ///—Oil Recovery Potential . 37
performances. Because a significant amount ofthe oil in each oil-producing State was repre-sented in the data base, extrapolations weremade on a district or State basis. Total recoveryfor each State or district, for a selected oil priceand rate of return, was calculated in the followingmanner: The oil recovered from reservoirs in thedata base for that State or district was multipliedby the ratio of total oil remaining in the State ordistrict to oil remaining in the State or districtdata-base reservoirs. (The one exception to thisrule was for West Virginia, where the sample in-cluded only 9 percent of the total oil in the State.For West Virginia, only the oil in the data basewas included in the composite results. Deletionof West Virginia from the extrapolation processhas no significant effect on ultimate recoveryestimates because oil remaining in those reser-voirs constitutes less than 1 percent of the oil re-maining in U.S. reservoirs. ) “Oil remaining, ” asused here, refers to oil remaining after ultimateprimary and secondary recovery. State and dis-trict productions were summed to obtain na-tional production.
Rate of Production for the Nation
The starting date for the development of eachreservoir was determined with the use of a rate-of-return criterion, Reservoirs earning the highestrates of return were assumed to be developedfirst. The schedule shown in table 8 was used toestablish starting dates for reservoir evaluation,i.e., starting dates for pilot tests and economicand engineering evaluations, which were thenfollowed by commercial development. Extrapola-tion of production rates from individual reser-voirs to a State and then to the Nation was ac-complished in the same manner as described forultimate recovery.
This plan for reservoir development recognizestwo factors which influence the application ofimproved oil recovery processes. First, it ac-counts in part for risk in that the highest rate-of-return projects will be initiated earliest when thetechnology is least certain. Lower rate-of-returnprojects would not be started until later dates, atwhich time the technological and economic riskshould be reduced as a result of experiencegained from field tests and commercial opera-tions. Secondly, the timing plan in some measuresimulates actual industry decisionmaking. As a
Table 8Schedule of Starting Dates
Based on Rate-of-Return Criterion
Continuations ofongoing projects New starts
Date rate of return rate of return1977 . . . . . . . . . . . 1 00/0 30 ”/01978 .. . . . . . , . . .1979 . . . . . . . . . . .1980 . . . . . . . . . . .1981 . . . . . . . . . . .1982 , . . . . . . . . . .1983 . . . . . . . . . . .1984 . . . . . . . . . . .1985 . . . . . . . . . . .1986 . . . . . . . . . . .1987 .. . . . . . , . . .1988 . . . . . . . . . . .1989 . . . . . . . . . . .1990-2000 . . . . . .
1 00/010“/0“10“/010%10“/010%10%10%10%1 0 %
10%10%10%
250/o20 ”/019 ”/018%17’YO160/015 ”/014%13“/012“/011 ”/010“/010“/0
Note: In the production models, after It has been decided todevelop a reservoir, time IS allowed to study the reservoir,conduct p i lot tests and do engineer ing and economicanalyses. These studies and evaluations are completedbefore initiating commercial production.
general rule, the most promising projects are ini-tiated first by industry.
Whi le OTA bel ieves the t iming plan i sreasonable, it still is only an approximation ofwhat will actually occur. Other factors such aslevel of technological risk, alternative investmentopportunities, availability of resources requiredfor the processes, etc., will significantly influencethe implementation rate of EOR.
Exclusion of Alaska
The EOR potential of Alaska was not ex-amined, for several reasons. A large portion ofthat State’s oil resource was included in the database (table 6). However, OTA felt that theeconomic data base required for the E O R
economic models was not sufficiently wellestablished. Alaska is a relatively young produc-ing area and most of its oil fields are in a hostileenvironment. Costs are known to be high anddifficult to estimate for future EOR projects. Also,because Alaska is a young producing area andbecause costs are high, EOR projects probablywill not be considered to any significant degreefor several years.
— -——
38 . Ch. Ill—Oil Recovery Potential
Estimated Oil Recovery
Definition of Cases
It is not possible to predict with certainty howmuch oil can be recovered in the future with EORprocesses. Therefore, two principal cases wereestablished, covering a range in the technologicalperformance of the different processes. The moreoptimistic of these was labeled the “advancingtechnology —high-process performance case. ”The less optimistic was termed the “advancingtechnology —low-process performance case. ”These cases were designed in an effort to calcu-late realistic estimates of future recovery and atthe same time reflect the uncertainty which existsin OTA’s projection.
In addition to these two principal cases, esti-mates were made of the effects of variations inkey parameters, such as injected chemical (CO2,surfactant) costs, minimum specified acceptablerate of return, and resource availability, on recov-ery. These estimates, in essence, involved exten-sions and modifications of the two principalcases.
A description of the principal cases follows.
Case I: Advancing Technology—High-Process Performance
It was assumed for this case that the EOR proc-esses which are now in their developmental stage(C02 miscible, surfactant/polymer, polymer-aug-mented waterflooding, and in situ combustion)would work as now generally envisioned by thepetroleum industry. The production models forthese processes, which are described in appendixB, were based largely on reported laboratoryresults with limited data from field tests. Thesteam process is the only technique that can cur-rently be classified as a commercial process andas a result its production model is based on morefield experience than the others.
Because of the nature of surfactant/polymerand polymer-augmented waterflood processesand their early stage of development, OTAassumed that certain technological advanceswould occur between now and the year 2000.
In the case of surfactant/polymer flooding, itwas assumed that research and field testingwould lead to a reduction in the volume of oilused in the surfactant slug and the volume ofpolymer needed to displace the surfactant slugthrough the reservoir. Reductions by a factor oftwo were assumed for both oil and polymervolumes from values representative of currenttechnology. Current surfactant formulations aretolerant of total dissolved salt content of about20,000 parts per mill ion (ppm). It was alsoassumed that developments in the formulation ofsurfactant and polymer systems would extendsalinity tolerance to 200,000 ppm. Finally, it wasassumed that technological advances would oc-cur in surfactant/polymer and polymer-aug-mented waterflooding processes which wouldraise the temperature constraint to 250° F. Thetiming of the advances is shown in table 7.
A major technological assumption for the CO2
miscible process was that between 4 and 6 thou-sand cubic feet (Mcf) of C02 would be injectedper barrel of EOR oil recovered. Although currentpilot tests with CO2 indicate that this injection-volume ratio may be on the order of 10 Mcf perbarrel of oil, it was assumed that a technologicaladvance to the above-stated injection efficiencywould be achieved.
The advancing technology-high-process per-formance case was considered to be un-constrained by chemical resource availability.This assumption is also of paramount impor-tance. For example, the amount of CO2 requiredat the world oil price recovery is 53 trillion cubicfeet (Tcf) (not including recycled CO2). This is avery large quantity of C02, which simply may notbe available at CO2 prices used in the calcula-tion. Chemical availability was also assumed forsurfactant/polymer and polymer-augmentedwaterflooding processes.
Technological advances were assumed in thefield application of steam and in situ combustionprocesses. Well-completion technology, whichpermitted selective depletion of each major zonewithin a reservoir, was assumed. All major zoneswere developed sequentially. Methods for con-
Ch I//—Oil Recovery Potential . 39
trolling volumetric sweep efficiency of bothprocesses were assumed to develop so that theprocesses could be applied to 80 percent of thereservoir acreage.
It was assumed in this case that the EOR proc-esses could be made to operate without damageto the environment and that this could be doneat no additional cost. For the thermal processes,in particular, this is an important assumption. Forexample, air pollution limitations now existing inCalifornia would allow little or no new steamrecovery in that State without technological ad-vances to reduce pollutant levels from steamgeneration.
In California, a limited number of refineriescapable of processing heavy oil, an entitlementsprogram, and a prospect of competing crude sup-plies from Prudhoe Bay combine to reduce theState demand for heavy oil production. The OTAstudy assumes that a market exists for all heavyoil produced in California.
Enhanced oi l recovery product ion wasassumed to occur in any reservoir if the rate ofreturn after taxes was greater than 10 percent.This further implies advances in technology toreduce risk of failure, because investments at in-terest rates of 10 percent will only be made forrelatively low-risk projects. Risk has been takeninto account, as explained in a previous section,in that the production timing plan was based onrate of return with the “best” projects being initi-ated first, However, in the calculations a largeamount of oil is recovered at rate-of-return valuesjust slightly above 10 percent,
The advancing technology-high-process per-formance case implies a significant commitmentto a research and development program whichwould be carried out in concert with the com-mercial implementation. The technological ad-vances will not be made, nor will risk be reducedto the level assumed, without such an effort.
Case II: Advancing Technology-Low-Process Performance
Case II is a conservative estimate of futurerecoveries which assumes that no EOR processwilI work as successfulIy as it does in the advanc-ing technology-high-process performance case.
Changes were made in the production modelswhich led to reductions in recoveries averagingbetween 12 and 30 percent for the different EORprocesses. The details of the low-process per-formance case for each process are given in appen-dix B.
Case II essentially assumed that less oil wouldbe recovered by the EOR processes using as largea dollar investment as was assumed in the high-performance case. Resource constraints were notimposed, and the assumption was made that theprocesses would operate without environmentaldamage.
Calculation Results
Low- and High-Process Performance Cases
The results of the high-process performanceand low-process performance cases are shown intables 9 through 14, Table 15 presents ultimaterecovery by State while table 16 shows ex-trapolation proportions for each process underhigh- and low-process performance assump-tions. Table 9 gives the cumulative figures for allprocesses. Individual process recoveries areshown in the other tables. Results are shown forthree 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 recov-eries considered feasible for EOR technology. Forthese cases, recoveries were not restricted byresource availability and technology to meet en-vironmental protection standards. Markets wereassumed for heavy oi I in Cal i fornia. Thedifference between the cases thus results fromdifferences in assumptions about the technologi-cal performance of the processes.
For the high-process performance case at theupper tier price, it is estimated that approx-imately 21.2 bil l ion barrels of oil could berecovered. The recovery increases to about 29.4billion barrels at the world oil price and 41.6billion barrels at the selected alternate fuelsprice, Corresponding uitimate recoveries for thelow-process performance case are 8.0 billion,11.1 billion, and 25.3 billion barrels, respectively.
40 . Ch. 111—011 Recovery Potential
Table 9Estimated Recoveries for
Advancing Technology-Low- and High-Process Performance Cases
Aii Processes
Low-process performance case High-process performance case
Upper tierprice
($11.62/bbl)
8 0
0.30.40.50,51,1
4001,2002,0002,8004,200
World oilprice
($13.75/bbl)
Alternate fuelsprice
($22.00/bbl)
Upper tierprice
($11.62/bbl)
World oilprice
($13.75/bbl)
Alternate fuelsprice
($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
0.30.50.71.21.7
4001,3002 ( 3003,8006,900
2 5 3
0.30.91.82.55.1
4001,7004,2007,500
‘1 6,000
— —
21.2
0.40.51.11.72.9
5001,7003,3005 , 6 0 0
10,400
29.4
0.41.01.73.15.2
5002,0004,7008,700
17,300
41.6
0.41.32.86.08.2
5002,4006,200
12,80029,200
Table 10Estimated Recoveries for
Advancing Technology-Low- and High-Process Performance Cases
Steam Drive Process
Low-process performance case High-process performance case
Upper tierprice
$11.62/bbl)
2.1
0.10 20,20.20.2
200500800
1,2001,600
World oilprice
[$13.75/bbl)
A1ternate fuelsprice
($22.00/bbl)
Upper tierprice
($11.62/bbl)
World oilprice
($13.75/bbl)
Alternate fuelsprice
($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 10.20.20.30.3
200
500800
1,3001,800
— .
4.0 2.8
o.2
0.20.20.20,3
300
3..3
0.20.20.30.30.4
300800
1,1001,7002,400
6.0
0.20.30.50.40.4
0.30.40.70.70.6
200 I 4001,1002,0003,3004,600
7001,4002,3003,100
8001,1001,4001,900
Ch ///—Oil Recovery Potential . 4 1
Table 11Estimated 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 tierprice
$11.62/bbl)—
1.2
0.10.10.20.10.1
*
300600900
1,000
World oilprice
($13.75/bbi)
1.4
0.10.20.30.10.1
*
300700
1,1001,200
Alternate fuelsprice
($22.00/bbl)
1.6
0.10.20.30,20.1
●
300800
1,2001,400
High-process performance case
Upper tierprice
($ll .62/bbl)
1.7
0.10.20.30.20.1
●
300800
1,2001,400
world Oi l
price($13,75/bbl)
1.9
0.10.20.30.20.1
●
400900
1,4001,600
•le\~ than 005 mllllon barrels of dally production, or less than 50 mlllmn bwels of cumulat ive product ion.
Table 12Estimated 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 tierprice
$11.62/bbl)
1 .0
*+●
*
0.2
*
100100100300
World oilprice
($13.75/bbl)
2,3
***
0.10.2
*
100100200
500
A1ternate fuelsprice
($22.00/bbl)— —
7.1
●
0.10.40.2
1.3
*
200600900
2,700
Alternate fuelsprice
($22,00/bbll
1.9
0.10.20.40.20.1
*400
1,0001,5001,700
High-process performance case
Upper tierprice
$11.62/bbl)
7.2
●
☛
0.20.20.9
●
1 0 0
400700
1,800
- <
W o r l d – o i l
pr ice
( $ 1 3 . 7 5 ‘ b b l )
10.0 ~
●
0.20.40.81.9
●
300900
1,8004,400
Alternate fuels
price
( $ 2 2 . 0 0 / b b l )
12.2
●
0.2().71,32.5
*300
1,0002,0006,200
● 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
mr -
0 0 0 0 00 0 0 0 0F a G m V,
. . .
6
0 ● ☛☛ 0 0
— —
r -
2 . :
Ch. ///—Oil Recovery Potential . 43
Table 14Estimated Recoveries for
Advancing Technology-Low- and High-Process Performance Cases
Polymer-Augmented Waterflooding
I Low-process per formance case
Upper tierprice
($11.62/bbl)
Ultimate recovery:(billion barrels) . . . . . . . . . . . . .
Product ion rate in :
(mi l l ion bar re l s/day)
1 9 8 0 . . . . . . . . . , . . . , . . . .
1985. . . . . . . . . . . . . . . . . .
1990, . . . . . . . . . . . . . . . . .
1995. ......., . . . . . . . . .
2000. . . . . . . . . . . . . . . . .
Cumulative production by:(mill Ion barrels)
1980. , . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . . . .1995. . . . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . . . . .
0.2
*●
0.1*●
100200200200
World oilprice
($13.75/bbl)
0.3
●
●
0.1**
●
100200300300
Alternate fuelsprice
($22.00/bbl)
0.3
●
☛
0.1*●
*100200300300
High-process performance case
Upper tierprice
($11.62/bbl)
0.4
**
0.1**
*
100200300400
World oilprice
($13.75/bbl)
0.4
**
0.1*+
.
100200400400
● Less than 0,05 mlllmn barrels of dally production, or less than sO million barrels ofcurnulatlve product~m.
Table 15Ultimate 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 fuelsprice
($22.00/bbl)
0,4
●
☛
0.1*●
●
100300400400
U p p e r t i e r
pr ice( $ 1 1 . 6 2 / b b l )
6.81.14.71 . 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
U l t i m a t e r e c o v e r y
(billions of barrels)
world oilprice
($13.75/bbl)
7,81 . 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
0.50,50.10.9
29.4
Alternate fuels
price
( $ 2 2 0 0 / b b l )
11.42.0
11.61.74.82.70.40.40.20.10.40.21 . 4
0 . 20 . 8
0 . 5
0.1
2 . 6
4 1 . 6
“Columns may not add due to roundlng
44 . Ch. 111—011 Recovery Potential
Table 16Extrapolation of Ultimate Oil Recovery From Data Base Calculations to the Nation
World Oil Price ($13.75/bbl)
(Billions of Barrels)
Low-process performanceProcess Data base/
NationData base Nation percent
Steam drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .In situ combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Carbon dioxide miscible . . . . . . . . . . . . . . . . . . . . . : . . .Surfactant/polymer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Polymer-augmented waterflood . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.400.782.110.730.15
5.17
As indicated in table 9, all of this oil would notbe recovered by the year 2000. For example, inthe high-process performance case at the uppertier price, the production rate increases fromslightly more than 0.5 MMBD in 1985 to nearly3.0 MMBD in the year 2000. The daily productionpattern shown results in a cumulative productionby the year 2000 of 10.4 billion barrels, or sO per-cent of the projected ultimate recovery. At theother two oil prices, the production rate also in-creases through the year 2000. The cumulativeproductions by 2000 are 59 and 70 percent ofultimate recovery at the world oil and alternatefuels prices, respectively.
The f ive EOR processes examined y ie ldmarkedly different amounts of oil as indicated intables 10 through 14. This is illustrated by thehigh-process performance case. The COZ misci-ble process contributes about half of the ultimaterecovery at the world oil and alternate fuelsprices. The surfactant/polymer process is esti-mated to contribute about 30 percent of the totalultimate recovery and the thermal processesabout 20 percent.
The only process found to be generallyeconomical in the offshore reservoirs at the worldoil price was CO2 miscible. Other processes werefound to be economical in only a very few reser-voirs, Therefore, C02 miscible flooding was ap-plied exclusively. The results are shown, alongwith the onshore recoveries, in table 13 for thehigh-process performance case. For low-processperformance, offshore development was taken to
I I
High-proc
Data base
1.831.086.654.540.19
14.29
Nation
3.31.9
13.810.00.4
29.4
formanceData base/
Nationpercent
5557484548
49
be marginally economical and therefore unattrac-tive.
Both the high- and low-process performancecases place great demands on resource require-ments. For example, the amount of CO2 thatwould be consumed in reaching the ultimaterecovery at the world oil price is about 53 Tcf inthe high-process performance case. This does notinclude about 18 Tcf of recycled C02. This is avery large amount of CO2, and it is not knownwhether such a supply will be availablecosts assumed in the economic model.
Ultimate Oil Recovery byEOR Processes
Estimates of ultimate recovery were
at the
deter-mined by extrapolating results from the 835reservoirs in 19 States. Of the 835 reservoirs inthe OTA data base, 636 were assigned to one ofthe five oil recovery processes. Nine reservoirs inAlaska were not evaluated for enhanced oilrecovery processes due to insufficient cost data.Enhanced oil recovery processes were not techni-cally feasible in the remaining 190 reservoirs.
The remaining oil in place (ROIP) in the 835reservoirs is 155.3 billion barrels, which repre-sents about 52 percent of the ROIP in the UnitedStates. About 14.6 billion barrels of this amountare in Alaskan reservoirs which were not con-sidered for EOR processes. The ROIP in data basereservoirs which were evaluated for enhanced oilrecovery processes was 140.7 billion barrels.
Net oil recovered from data base reservoirs byapplication of high-process performance modelsis 22.3 billion barrels at $30 per barrel. In estimat-ing the net oil that can be recovered by enhancedoil processes, a reservoir was consideredeconomic if it could be developed and yield a10-percent rate of return at prices of $30 per bar-rel or less. This is about 95.5 percent of the oilconsidered technically recoverable using thesemodels. Oil not recoverable under the high-proc-ess performance models is 133 billion barrels.Distribution of the potential recoverable andunrecoverable oil by process is shown in table17.
Table 18 extends these results to the UnitedStates us ing the extrapolat ion proceduredescribed in the section on Ultimate Recovery forthe Nation on page 35.
The 49.2 billion barrels indicated as net oilrecoverable by enhanced oil processes is an esti-
Ch. 111—011 Recovery Potential .
mate of the upper limit of potential recovery
45
atoil prices of $30 per barrel” or less. This is 95.6percent of the oil considered to be recoverable.The estimate assumes successful application ofEOR processes to all applicable reservoirs in theUnited States. If the EOR processes perform asassumed in the low-process performance case,the net potential EOR oil would be considerablyless.
Unrecoverable oil in table 18 is estimated tobe 248.8 billion barrels or 56.3 percent of the ini-tial oil in place. About 76 billion barrels of oil willbe left in reservoirs where no enhanced oil recov-ery process was considered applicable in theOTA study. Some portion of the 14.8 billion bar-rels which will remain in Alaskan reservoirs notevaluated in the OTA study may be recoverableat $30 per barrel. The approximately 170.4 billionbarrels which remain in reservoirs after EOR proc-esses are applied represent their inherent ineffi-ciencies.
Table 17Summary 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 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reservoirsassigneda
to process
2020
190294
9220
199
835
Remainingoil in place
(millions of barrels)
2 1 , 1 0 7
7 , 5 8 5
5 3 , 2 5 4
2 , 6 9 5
2 4 , 3 8 6
3 , 9 4 9
4 2 , 3 2 2
1 5 5 , 2 9 8
Net oilb
recoverable(millions of barrels)
at $30/barrel
4,0531,126
9,7041,2985,898
1890
22,268
‘Process selected yielded maximum oil recovery at 10-percent rate of return or better at world oil price
Oil considerednot recoverable
(millions of barrels)
17,0546,459
43,5501,397
18,4883,760
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 evalu-
ated due to msufflclent cost data.
.—
46 . Ch. Ill-oil Recovery Potential
Discussion of Results
Table 18 Table 19Projected 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 high-process performance case at$30/barrel. Not included inAPI proven or indicatedreserves. . . . . . . . . . . . . . .
Unrecoverable oilRecoverable at price greater
than $30/barreI . . . . . . . . . .O i l l e f t i n re se rvo i r s a f te r
enhanced oil recovery proc-esses were applied and oilconsumed as part of therecovery process . . . . . . . . .
O i l i n rese rvo i r s where noenhanced oil recovery proc-ess was applicable at pricesof $30/barreld. . . . . . . . . . . .
‘API Proven Reserve (December 31,
Billionsof
barrels
109.0
32.75.0
46.5
2.3
170.4
76.1
442.0
Percentageof original
oil inplace
24.7
7.41.1
10.5
0.5
38.6
17.2
100.0
1975) includes 1.0 billionbarrels from enhanced oil recovery processes.
bApl Indicated Reserve (December 31, 1975) includes 1.7 billlon
barrels from enhanced oil recovery processes.‘Net 011 recoverable in the high-process performance case IS 49.2
billlon barrels. The 2.7 billion barrels included in API Proven and in-dicated Reserves as of December 31, 197s were deducted f romcomputed net EOR oil.
‘{Reservoirs In Alaska which will contain 14.8 billlon barrels of oilafter deduction of Proven and Indicated Reserves were not evalu-ated In this study due to insufficient cost data.
Projections of this study are based on applica-tion of EOR processes to reservoirs in the lower48 States.
I Ultimate recovery
, (bil l ions of b a r r e l s )Oil price Low- High-$/barrel I process process
performance performance
Upper tier ($11.62/bbl) . . . . . 8.0 21.2World oil ($13.75/bbl) . . . . . 11.1 29.4Alternate fuels ($22.00/bbl) . 25.3 41.6
lower and upper bounds of the volumes of oilwhich are potentially recoverable at upper tier,world oil and alternate fuels prices. Thesevolumes, ranging from 8 billion to 42 billion bar-rels, are significant when compared to theAmerican Petroleum Institute (API) proven oilreserves (December 31, 1975) of 32.7 billion bar-rels which remained to be produced from exist-ing fields.13
The wide range in estimates is caused primarilyby uncertainties in projecting oil recovery fromapplication of the surfactant/polymer and C02
miscible flooding processes. Both processes arein early stages of development.
Production Rate
Daily production rates for the advancing tech-nology cases at world oil prices are superim-posed on the projected U.S. decline curve infigure 13. peak production rates are projected tobe the same order of magnitude as the projectedproduction rate from API proven, indicated, andinferred reserves in existing fields. Productionrates in the mid-1980’s are projected to vary be-tween 8 and 17 percent of the projected produc-
Projected Results for the United States
Ultimate RecoveryResults 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 barrelsare projected from secondary recovery. The remainder (1.7billion barrels) are attributed to enhanced oil recovery proc-esses. A total of 31.7 billion barrels of the proven oil reservewill be produced by primary and secondary methods. Onebillion barrels will be produced by EOR techniques at cur-rent economics.
t ion f rom exis t ing f ie lds by convent ionalmethods.
Oil produced by improved oil recovery proc-esses could become an important part of the Na-tion’s oil supply for the period beginning in 1985and extending beyond the year 2000. However,application of EOR technology would not offsetthe decline from existing fields until after 1990.
Uncertainties in Projections
The range of projections for ultimate recoveryin table 19 and production rates in figure 13represents OTA’s judgment of the range of uncer-tainty which exists in the projections, Althoughuncertainties are present in projections of bothultimate recovery and production rate, the esti-mates of ultimate recovery are considered to be
Figure 13. Projected Production From KnownU.S. Reservoirs, 1976-95, by ConventionalMethods 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 Basedon Low-ProcessPerformance Case
Production From- Inferred Reserves
(Extensions andRevisions) 2
Proved and Indicated Reserves1
I I I f1976 1980 1985 1990 1995
SOURCES 1 American Petroleum Institute, Reserves of Crude 0//, NaturalGas L/qu/ds, and Natural Gas m the U. S. and Canada as ofDecember 30, 1975 Lewin & Associates, Inc for Federal EnergyAdmlnlstratlon, 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 productionrates.
Uncertainty in Ultimate Recovery
Projections of ultimate recovery at a specifiedoil price are uncertain because:
1)
2)
3)
Estimates of ROIP volume and distributionwithin a reservoir may be as much as 25percent (or more) in error. Further discus-sion of this problem is included in the sec-tion on the Effect of Uncertainty in theResidual Oil Saturation and VolumetricSweep on Projected Results on page 50.
The ability to predict the oil recovery andthe quantities of injected materials neededto obtain this recovery is different for eachprocess and has wide ranges of uncertain-ty.
Materials used in the surfactant/polymerprocess are either derived from crude oil orcompete with products derived from crudeoil. Therefore, the costs of these compo-nents were increased for the purposes ofthis assessment as the price of crude oil in-creased. The cost of carbon dioxide wasnot varied with oil price. Because none ofthese materials is produced commerciallyin the volumes projected for this study, thecost estimates have some uncertainty. Sen-sitivity calculations described in appendixB show that both processes are extremelysensitive to costs of injected materials. A50-percent increase in the estimated costof chemicals would reduce the oil recoveryfrom the surfactant/polymer process at$13.75 per barrel (high-process perform-ance) from 10 billion barrels to 0.2 billionbarrels. About 9 billion barrels of this oilwould be recoverable at the alternate fuelsprice.
The demand for natural CO2 may be highenough for owners of these deposits tonegotiate prices considerably above theproduction costs assumed in this study. Forexample, a 50-percent increase in the priceof C02 would reduce the potential pro-duction from the C02 process from 13.8
48 . Ch. Ill—Oil Recovery Potential
4)
5)
billion barrels at $13.75 per barrel (high-process performance) to 7.0 billion barrels.
It is not known whether large volumes ofinjection fluids, particularly C02, will beavailable. 14 A comprehensive report ofC OZ availability in the United States hasnot been published, although ERDA is cur-rently conducting such a study.
The level of uncertainty is influenced bythe stage of technological development ofeach process. Steam displacement tech-nology has been proven in portions ofseveral California reservoirs. In situ com-bustion and polymer flooding have beentested extensively with mixed results. Sur-factant/polymer flooding and C02 misci-ble displacement are still being investig-ated in laboratory and field tests.
Projected ultimate recoveries for steam dis-placement and in situ combustion are based onselective development of each major zone in areservoir and application of the processes to 80percent of each reservoir area. Selective comple-tion has been used successfully in portions of afew reservoirs in California. There is no reservoirin the OTA data base where steam displacementor in situ combustion has been applied to 80 per-cent of the total reservoir acreage.
The CO2 miscible process model is based onlaboratory data and a number of field tests. Re-cent indications from the field tests are that theratio of C02 injected to oil recovered may rangeabove 10 Mcf of CO 2 per barrel of oil.15 T h eassumption used in the present study for thehigh-process performance case was that this ratiowould generally be reduced to 4 to 6 Mcf of C02
per barrel of oil, with 25 percent of the injectionmaterial being recycled C02. The average valuefor the high-process performance case was 5. IMcf. For the low-process performance case, theaverage ratio was 5.4 Mcf per barrel of oil.
The effect of using a lower CO2 injection ratiois to reduce chemical costs and thereby improvethe economics. As an example, if the cost of in-
14EC)R Workshop on Carbon Dioxide, Sponsored by
ERDA Houston, Tex., April 1977.15[bldt
jected CO2 were increased by a factor of 1.5 forthe high-process performance case, the ultimaterecovery by CO2 miscible at world oil priceswould be reduced from 13.8 billion barrels to 7.0billion barrels. Additional discussion is presentedin appendix B.
Significant technological advances wereassumed in application of the surfactant/polymerprocess. Specific assumptions are compared intable 20. The effect of the assumed technologicaladvances on ultimate recovery for the surfac-tant/polymer process (shown in table 21) resultsin an increase in ultimate recovery from 2.9billion barrels under current technology to 10.0billion barrels at high-process performance atworld oil prices.
Table 20Comparison 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, frac-
tion of volume swept bypreceding waterflood . . . .
Size of polymer bank, fractionof (region) volume sweptby preceding waterflood. .
CurrentTechnology
< 2 0 0oF
<20,000”—
20
10
1.0
Advancingtechnology
< 2 5 00F< 3 0<200,000*—
10
10
0.50
*Constraint which could not be applied due to absence ofsalinlty data,
Table 21Comparison 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 7.2World oil ($13.75/bbl) . . . . . 2.9 10.0Alternate fuels ($22.00/bbl) . 8.8 12.2
Ch. Ill—Oil Recovery Potential ● 4 9
Uncertainty in Projected Production RatesProduction rate projections are influenced by
the following factors:
1)
2)
A vigorous successful research and develop-ment and commercial exploitation programwas assumed in the advancing technologycases. Time was allotted in the economicmodel for technical and economic pilottesting, which is necessary for fieldwidedevelopment. Each stage of testing wasconsidered successful within a specifiedtime frame. Development of the field wasplanned on a time schedule correspondingto normal oilfield development.
partial success in initial field tests, lowdiscovery rates for natural C0 2, and aslower rate of technological advance in thesurfactant/polymer process are examples offactors which could delay or reduce the pro-duction rates projected in this study.
Production rates presented in tables 9through 14 come from reservoirs whichhave a minimum discounted cash flow rateof return of 10 percent. Full-scale applica-tion of a process in a reservoir was done in amanner which approximates the pattern ofindustry investment decisions. In general,high-risk projects are undertaken early in astage of technical development when therate of return is high. Projects with 10-per-cent rate of return are undertaken when therisk of technical and economic failure isrelatively low.
The timing plan used to construct pro-duction rates for the Nation is dependentupon the projected rate of return for eachreservoir. The economic model assumesthat the reduct ion of technical andeconomic risk will occur at a rate (table 8)which initiates development of low rate-of-return (1 O percent) reservoirs in 1989. Aresult of this approximation is that a largevolume of oil is produced after the year2000 at the world oil price. Earlier or laterreduction of risk could alter the annual pro-duction rates appreciably.
The price of oil affects production rates intwo ways. Higher oil prices encourage initia-
3)
tion of projects at earlier dates. Conse-quently, production from a reservoir whichcomes onstream in 1989 can be obtained atan earlier date and at a higher price if thetechnology is developed. A second effect ofoil price is to add reservoirs at a higher pricewhich cannot be developed economicallyat lower prices.
The rate-of-return criterion is a measure ofrisk in an advancing technology where therisks of technological and economic failuresare high. In these instances, a high rate ofreturn is required in order for the successfulprojects to carry those high-risk projectswhich fail.
Failures of a recovery process are not ex-plicitly accounted for in this study. Thus,the projections of ultimate recovery andproduction rates assume a successful ap-plication of the process to every reservoirwhich meets the technical screen and theminimum after-tax rate of return. Thus, theprojections have a built-in, but unknown,measure of optimism.
This optimism is offset to some extent bythe fact that (1) the cost of failure in techni-cal or economic pilot testing is com-paratively small, and (2) no attempt wasmade to optimize process performance.Failure of a process in a reservoir at thisstage would reduce the ultimate recoveryand the predicted production rate. Overalleconomics for the process would not be sig-nificantly affected, provided other projectswere economically successful.
If risk is reduced at a rate slower than thatprojected in table 8, only those projects andprocesses which have high rates of returnwill be pursued. For example, the majorityof the surfactant/polymer flooding candi-dates have rates of return after taxes of be-tween 10 and 15 percent at the world oilprice for the high-process performance case,The technology is not proven and a 20-per-cent rate of return could be required by in-vestors to offset the possibility of processfailure in a given reservoir. If a 20-percentrate of return is required, few surfac-tant/polymer projects would be initiated.
!36-594 O - 78 - 5
50 . Ch. 111—011 Recovery Potential
By contrast, steam displacement is arelat ively proven process. Cont inueddevelopment and use of steam would beexpected at rates of return of between 10and 20 percent. The impact of high techni-cal and economic risk on the ultimate recov-ery and production rates for all processes isillustrated by the comparison in table 22 forworld oil prices. Reductions of 61 percent inultimate production and 60 percent inaverage production rate for the time periodfrom 1980 to 2000 are projected underhigh-risk conditions.
4) The production rate for the Nation isaffected by environmental regulations andmarket conditions in California. Current en-vironmental regulations limit the total emis-sions from steam generators and air com-pressors to pollution levels which existed in1976. Under existing laws, the maximum in-cremental production rate from thermalmethods in California will be 110,000 bar-rels per day. The impact of this constrainton the production rate is shown in table 23for the advancing technology cases at worldoil prices, Production rates for the Nationare reduced up to 29 percent for the periodfrom 1980 to 1995 when constraints are ap-plied. Ultimate recovery is not affected asthe remaining oil will be produced after theyear 2000.
A second factor limiting the developmentof thermal methods in California is theavailability of refinery capacity to handleheavy oil. Heavy oil requires more process-ing to produce marketable products than dolighter oils such as Saudi Arabian light orPrudhoe Bay feedstocks. Ample supplies ofthese feedstocks on the west coast couldsuppress the development of heavy oil pro-duction even if environmental constraintswere removed.
Effect of Uncertainty in Residual OilSaturation and Volumetric Sweep on
Projected Results
Residual Oil Saturation
The residual oil saturation in a reservoir follow-ing primary and secondary production sets an up-
per limit to the total amount of oil that could beproduced using any EOR technique, no matterhow good its performance may be. Thus, uncer-tainty about the residual oil saturation will leadto comparable uncertainty in the projected pro-duction from an EOR project, independent of un-certainty about process performance.
Table 22High-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 ofreturn)
29.4
0.41.01.63.15.2
5002,0004,7008,700
17,300
High risk(20-percent
rate ofreturn)
9.5
0.40.50.71.01.4
5001,6002,7004,1006,800
Table 23Impact of Technological Advances in Emission
Control in California Thermal Recovery Projects onProjected Rates for the United States at World Oil
Price ($13.75/bbl)
+ + +
Low-process per- High-process per-
strained strained strained strained
Ultimate recovery:(billion barrels) . . . . .
Production rate:(million barrels/day)
1980 ....., . . . . . .1985, . . . . .,1990 . . . . . . . . . . . .1995 . . . . . . . . . . . .2000 . . . . . . . . . . . .
11.1 11.1 29.4
0.30.50.71.21.7
0.30.40.51.01.5
0.41.01.73.15.2
29,4
0.30.81.42.84.9
The variations in parameters used to comparethe high- and low-process performance cases forthe surfactant/polymer and C02 miscible proc-esses can also be used to simulate the effects ofuncer ta in t ie s in res idua l o i l sa tu rat ion .Specifically, the low-process performance caseapproximates a high-process performance casewhen the uncertainty in the residual oiI saturationvaries from 15 to 25 percent. As discussed in thesection on Uncertainty in the Oil Resource o npage 33, these figures represent the range of un-certainty which presently exists in the estimatesof the process parameters.
Volumetric Sweep
The fraction of the reservoir which can beswept by the surfactant/polymer and C02 misci-ble processes was assumed to be the regionwh ich was p rev ious l y contacted dur ingwaterflooding. 16 The volume of this region wasassumed to be known with less certainty thanresidual oil saturation.
Two methods have been used to estimate thefraction of the volume of a reservoir that hasbeen swept by earlier waterflooding. Onemethod assigns values to reservoirs based on ex-perience in the geographical region, The secondmethod, used in the OTA study, is based on amaterial balance involving the oil initially presentand the oil produced by primary and secondarymethods.
The effect of these methods of determiningsweep efficiencies was compared for the high-process performance case for a set of reservoirsconsisting of 59 surfactant/polymer candidates
lbother possible interpretations are discussed in appen-
dix B.
Ch. Ill—Oil Recovery Potential ● 5-1
and 211 onshore CO2 miscible candidates. Use ofestimated volumetric sweep efficiencies yielded1.1 billion additional barrels of oil at the world oilprice for the surfactant/polymer process. No sig-nificant difference was noted for onshore C02
results.
Maximum Oil Recovery byEOR Processes
Results of all cases show increased ultimate oilrecovery with increased oil price. Further com-putations for the high-process performance caserevealed that 95.6 percent of the oil consideredtechnically recoverable would be produced at oilprices of $30 per barrel or less. Based on theseestimates of technological advances, thevolumes of oil which may be recoverable byenhanced oil process will not exceed 49.2 billionbarrels for the United States (excluding Alaska).Thus, of the remaining 283 billion barrels of oil inthe United States, excluding Alaska, 234 billionbarrels are not recoverable under the technologi-cal advances assumed in the high-processperformance case, Lower-process performancewould reduce the ultimate recovery appreciably.Process improvements such as optimization ofwell spacing (i. e., infill drilling) and slug size werenot considered in the OTA projections of ulti-mate recovery for the Nation, The effects of theseimprovements are expected to influence the pro-jections less than the uncertainty in process per-formance. This assessment does not consider thepotential of new processes or process modifica-tions which might be developed at prices of $30per barrel. These possibilities are not likely tohave an impact on the Nation’s crude oil supplyduring the period between 1976 and 2000.
52 . Ch. IlI—Oil Recovery Potential
Comparison With Other Studies
Estimates of the potential oil recovery and/orproduction rates resulting from the application ofEOR processes have been published in sevendocument s . 17,18,19,20,21,22,23 Four of these 24,25,26,27 a r ebased on surveys and other subjective methodsand, as such, are considered preliminary esti-mates of the EOR potential for the Nation and notcomparable to the OTA study in methodology,depth of investigation, or policy analysis.
Three of the studies28,29,30 used a methodologysimilar to that used in the OTA study to estimate
1 7 ~~e ~stj~dtecj Recovery Potentia/ o f conventionalSource Domestic Crude Oi/, Mathematical, Inc., for the En-vironmental Protection Agency, May 1975.
IBpro~ect /ndepenc/ence Report , Federa l Ene rgy Ad-ministration, November 1974.
lgP/ann/ng criteria Relative to a National RD T& D Programto the Enhanced Recovery of Crude Oi/ and Natura/ Gas, GulfUniversities Research Consortium Report Number 130,November 1973.
zOPre//m/nary Fje/d Test Recommendations and ~fOSpeC-
tive 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 Ad-ministration, April 1976.
zzResearch and Development in Enhanced Oil Recovery,
Lewin and Associates, Inc., Washington, D. C., November1976.
ZjEnhanced Oil Recovery, National Petroleum council,December 1976.
ZqThe Est imated Recovery Potentia/ of Convention/
Source Domestic Crude Oil, Mathematical, Inc., for the En-vironmental Protection Agency, May 1975.
25 Project, /dependence Report, Federal Energy Ad-ministration, November 1974.
26~/ann/ng criteria Relative to a Nat;ona/ RDT&D Programto the Enhanced Recovery of Crude Oil and Natural Gas, GulfUniversities Research Consortium Report Number 130,November 1973.
ZTPre//mjnary Fie/d Test Recommendations and Prospec-
tive 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 Ad-ministration, April 1976.
2qResearch and Development in Enhanced Oil Recovery,
Lewin and Associates, Inc., Washington, D. C., November1976.
jOEnhanced 0// Recovery, National petrO!eUWI COUnCil,
December 1976.
EOR potential. These studies are (1) the pro-jections of enhanced oil recovery for California,Texas, and Louisiana, prepared by Lewin andAssociates, Inc., for the Federal Energy Ad-ministration (FEA) (April 1976);31 (2) the researchand development program prepared by Lewinand Associates, Inc., for the Energy Research andDevelopment Administration (ERDA) (November1976); 32 and (3) an analysis of the potential forEOR from known fields in the United States pre-pared by the National Petroleum Council (NPC)for the Department of the Interior (December1976).33
The methodologies of these studies areanalogous in that the potential oil resource wasdetermined us ing a reservoir-by-reservoiranalysis. Each reservoir in the respective database was considered for a possible EOR project.One or more EOR process was assigned to thereservoir. Oil recovery and economic simulationswere made in a manner closely approximatingcommercial development in the oil industry. Ulti-mate production and production rates fromeconomically acceptable reservoirs were used toextrapolate to the State and national totals.
Data bases varied somewhat between studies.The Lewin FEA and NPC studies used a commondata base consisting of 245 reservoirs fromCalifornia, Texas, and Louisiana. This data basewas expanded to 352 reservoirs in 17 oil-produc-ing States by Lewin and Associates, Inc., for theirERDA study. The OTA study incorporated,revised, and expanded the Lewin ERDA data baseto 835 reservoirs containing 52 percent of theROIP in the United States, as described in thesection Original Oil in Place on page 23.
Cost data for development and operation oftypical oilfields were obtained from the U.S.
M The potentja/ and Economics of Enhanced Oi/ Recovery,
Lewin and Associates, Inc., for the Federal Energy Ad-ministration, April 1976.
jzResearch and Deve/oprnent in Enhanced Oi/ Recovery,
Lewin and Associates, Inc., Washington, D. C., November1976.
jjEnhanced 0// Recovery, National petrOleum CoUnc il,
December 1976.
Ch. III--Oil Recovery Potential . 53
Bureau of Mines34 for all studies. Adjustmentswere incorporated to account for price changesbetween the reference dates for each study.
Results of these studies are compared withOTA projected results in table 24 for 1976 uppertier and world oil prices. There is agreement Inthe order of magnitude of the ultimate recoveryamong all the studies. The NPC projections in-clude a base case which represents best esti-
JqResearch and Development in Enhanced Oil Recovery,Lewin a n d A s s o c i a t e s , I n c . , W a s h i n g t o n , D . C . , N o v e m b e r
1 9 7 6 .
mates of process performance and associatedprocess costs, and a range of uncertainty in thebase case estimates due to poorer or better thanexpected process performance. Estimates fromthe OTA low-process performance case are with-in the NPC range of uncertainty for all oil prices.The OTA high-process performance case esti-mates more oil recovery than the upper estimatesof the NPC study. At the world oil price, the OTAestimate is about 24 percent higher. The LewinERDA cases for upper tier price and $13 per barrelare close to the range of OTA values. The OTAprojections are lower than the Lewin FEA resultsfor California, Texas, and Louisiana, even if oil
Table 24Projections of Ultimate Recovery and Production Rate From the
Application of Enhanced Oil Recovery Processes
Study
O T ALow-process performance. . . . . . . . . . . . . .
High-process performance . . . . . . . . . . . . .
NPC’Poor performance . . . . . . . . . . . . . . . . . . . .Expected performance (base case) . . . . . . .Better performance . . . . . . . . . . . . . . . . . . .
Poor performance . . . . . . . . . . . . . . . . . . . .
Expected performance (base case) . . . . . . .
Better performance . . . . . . . . . . . . . . . . . . .
E R D Ab
Industry base case**. . . . . . . . . . . . . . . . . . .
Industry base case w/ERDA R&D** . . . . . . .
FEACalifornia, Texas, and Louisiana . . . . . . . . .
Lower Bound, . . . . . . . . . . . . . . . . . . . . . .Upper Bound. . . . . . . . . . . . . . . . . . . . . . .
Referencedate
1976
1976
1976
1975
Minimumrate of
return forprojection
10 %
10 %
00/0
20%80/0
Oilprice
($/bbl)
11.6213.75
11.6213.75
10.00
15,00
11.6313.00
11.6313.00
11.2811.28
Potentialultimaterecovery(billionbarrels)
8.011.1
21.229.4
3.17.2
13.4
6.313.226.9
11.913.1
26.230.1
15.6***30.5.
Potentialproduction
rate in 1985(million
barrels/day)
0.40.5
0.51.0
0.4
0.40.91.6
0.60.6
1.72.1
1.02.0
‘“current tax case, 10-percent investment credit and expensing of injection materials and intangibles, with current environmental con-straints,
“**Reserves added by the year 2000.‘Enhanced Oil Recovery, National Petroleum Council, Decemberl 976.h~e~earch and Deve/oPmenl in ~nhanced Oi/ Recovery, Lewin and Associates, Inc., for the Energy Research and Development Administration
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 thesame basis.
Estimates of producing rates in 1985 varywidely between studies. In general, the OTAprojections are within the range of the NPC base-case study results and the Lewin industry base-case simulation. The OTA results are lower thanthe Lewin ERDA research and development caseand the Lewin FEA projection for California,Texas, and Louisiana. The apparent agreement inproducing rates between the OTA high-perform-ance case and the Lewin ERDA case does notconstitute confirmation of projections from inde-pendent studies for reasons outlined in a latersection.
OTA-NPC Results
The OTA study team was provided access toall reports, oil recovery models, cost data, andresults from the NPC study. Comparisons of pro-jected ultimate recovery and production rateswere made on a reservoir-by-reservoir basis. Thesame reservoirs which were included in the NPCbase case for C02, surfactant/polymer, steam,and in situ combustion processes were studied indetail using NPC models and OTA models. Alldifferences between OTA and NPC results can betraced to differences in recovery models, suppliesof injected materials, costs of injected materials,and, in some cases, the timing plan used in thesimulation to initiate projects.
The NPC study included a geological screen inwhich individual reservoirs were judged as good,fair, poor, or no EOR, based on qualitative infor-mation on the geology of each reservoir gatheredfrom industry sources. The OTA study assumedall reservoirs had the same quality since geologi-cal information was available on only a small por-tion of the reservoirs in the data base. No reser-voir was rejected for geological reasons, with theexception of those with a large gas cap whichmight prevent waterflooding.
The distribution of oil in a reservoir wastreated differently in the OTA models. The OTAmodels assume 95 percent of the remaining oil islocated in 80 percent of the reservoir acreage. Alloil produced by. EOR processes is developed
from the reduced portion of the acreage. Thisassumption was implemented by increasing thenet thickness in the region developed. The use ofeconomic models to determine the EOR processwhen two or more processes were possible led todifferent assignments of many reservoirs in theOTA study.
Major differences between the NPC and OTAresults are:
a. Recovery from application of C02 displace-ment in the OTA high-process performancecase exceeds NPC estimates by a factor ofabout two at all oil prices for which calcula-tions were made. Comparable recoverymodels were used and the agreement inultimate recovery for reservoirs common toboth studies is reasonably close, In Texas,the OTA recovery at world oil price by C02
flooding is about 5.6 billion barrels. The cor-responding NPC recovery is a little over 4.0billion barrels.
The NPC geological screen eliminatedcertain reservoirs in Texas from their studywhich OTA’s study calculated would pro-duce about 0.5 billion barrels of oil with theC02 process. When extrapolation was madeto the entire State, this amounted to about0.9 billion barrels. Considering the Texasresults, as well as the entire Nation, the NPCgeological screen accounts for part of thedifference but is not considered the majorfactor,
Expansion of the data base to other oil-producing States and offshore Louisianaresulted in more reservoirs as potential can-didates for C02. A result was that considera-bly more oil was produced from States otherthan Texas, California, and Louisiana in theOTA study than was projected in the NPCreport. In addition, in the OTA study at theworld oil price, an ultimate recovery of 0.9billion barrels was projected to be producedfrom offshore reservoirs that were not in theNPC data base (table 13).
Oil recovery for the NPC C0 2 m o d e l svaried according to geologic classificationsof good, fair, and poor. The OTA recoverymodels were designed to represent an
“average” reservoi r . The use of th is“average” reservoir in the OTA study mayaccount for a significant portion of thedifference in results for the three States ofCalifornia, Texas, and Louisiana.
Significantly different pricing plans for theC O2 resource were used by OTA and NPC,Prices used were similar in geographicalareas such as western Texas, which have ahigh probability of obtaining supplies ofnatural C02 by pipeline. However, for otherareas such as Oklahoma and Kansas there isless certainty of carbon dioxide pipelinesand the pricing plans were quite different. Ingeneral, the NPC study used a significantlyhigher cost for C 02 in these areas. This isconsidered to be a major reason for thedifference in results for the Nation. TheOTA C 0 2 pricing model is given in a p p e n -
dix B.
b. Oil recovery from OTA surfactant/polymerprojections for the low-process perform-ance case at $13.75 Per barrel (2.3 billionbarrels) is bounded by the NPC base case(2.1 billion barrels) and the NPC 5-year proj-ect life case (5.6 billion barrels) at $15 perbarrel. (The NPC base case used a 10-yearlife while OTA models assumed a 7-yearlife.) The OTA high-process performancecase at world oil price (10.0 billion barrels)p r o j e c t s a b o u t 1 . 0 b i l l i o n b a r r e l s I e s s o i l
recovery than the NPC better-than-ex-pected performance projections (1 1.2billion barrels) at $15 per barrel.
Two factors are the primary contributorsto the slight differences in results of the twostudies. First, more than twice as many OTAreservoirs were assigned to the surfac-tant/polymer process as in the NPC study.Forty-five percent of these reservoirs werenot in the Lewin FEA data base used by NPC.
A second difference in the results wasdue to NPC’s assignment of higher chemicalcosts to reservoirs which were ranked poorin the geologic screen. The OTA studyassumed all reservoirs were of the samequality. Comparable projections of ultimate
c.
Ch. ///—Oil Recovery Potential . 55
recovery at a specified oil price were ob-tained on individual reservoirs which hadthe same geological ranking and sweptvolume in both studies. Sensitivity analysesshow agreement of the low-processperformance projections and projectionsmade by increasing chemical costs so thatall reservoirs were “poor.”
Some differences were attributed to theapproaches used to estimate the volume ofeach reservoir swept by the surfactantflood. A discussion of this is included in thesection on Volumetric Sweep on page 51.No offshore reservoirs were found to beeconomically feasible for application of thesurfactant/polymer process in the OTAstudy. The NPC results included an estimateof 261 million barrels from offshore Loui-siana reservoirs at $15 per barrel,
The OTA estimates of oil recoverable bythermal methods are within the range of un-certainty projected in the NPC study. TheOTA low-process performance estimatesare within 0.4 billion barrels (12 percent) ofNPC base-case projections at prices be-tween $10 per barrel and $15 per barrel.Projections for the OTA high-process per-formance case at these prices are about 1.0billion barrels less than performance fromthe NPC high-recovery estimates. Com-parisons by process are included in appen-dix B.
Oil recovery models for thermal proc-esses in the NPC study were developed forareas with uniform reservoir properties.Projected recoveries from reservoir-wideapplication of these models were adjustedto account for variation of reservoir proper-ties and process performance. This wasdone by reducing the ultimate recovery foruniform reservoir and process performanceby factors of 0.7, 0.6, and 0.5, correspond-ing to the NPC geological screen of good,fair, or poor. Large reservoirs were sub-divided into two or three areas judged tohave different quality. Multiple-zone reser-voi rs were developed s imultaneously.Crude oil consumed as fuel was deducted
56 ●
d .
e.
Ch. 111—011 Recovery Potential
from gross production prior to computationof royalty and severance taxes.
The OTA thermal recovery models weredeveloped to represent the average reser-voir performance. Reservoirs were notassigned geological rankings based on reser-voir quality. Multiple-zone reservoirs weredeveloped zone by zone. Royalty andseverance taxes were paid on lease crudeconsumed as fuel. This is a significant cost,as about one-third of the production insteam displacement projects is consumed asfuel.
polymer flooding models in both studiesproduce comparable results when polymerinjection is initiated at the beginning of awaterflood. Some differences exist forwaterfloods which have been underway forsome period of time. The NPC recoverymodel projects a decline in oil recoverywith age of waterflood, while the OTAstudy does not. Polymer flooding does notcontribute much oil in either study.
The NPC study projected recovery froma l k a l i n e f l o o d i n g . T h e O T A s t u d yacknowledges the potential of alkalineflooding for selected reservoirs but did notinclude the process for detailed study.Reservoirs which were alkaline-flood candi-dates in the NPC study became candidatesfor other processes in the OTA study.
OTA-FEA, ERDA Results
The OTA study used the economic programsand timing plans for reservoir developmentwhich were used to produce the results for theLewin and Associates, Inc., studies for FEA andERDA. Oil prices and a minimum acceptable rateof return (1 O percent) were selected for the OTAstudy. Costs of injected materials were obtainedfrom both Lewin and NPC studies. Oil recoverymodels for the OTA study were developed inde-pendently of previous Lewin studies. The FEAstudy reported projections for three States;California, Texas, and Louisiana. The ERDA resultsinclude data from 17 oil-producing States whilethe OTA results use data from 18 oil-producing
States. Projections for the Nation in the OTA andERDA studies were obtained by summing Statetotals.
The OTA advancing technology cases assumea vigorous research and development program,although the stimulus for the program was notidentified. Lewin and Associates, Inc., ERDAprogram assumes all improvements in recoveryover an industry base case comes from an exten-sive ERDA R&D program which removes environ-mental and market constraints for thermal opera-tions in California, results in improved recoveryefficiencies for processes, and extends the proc-esses to reservoirs not considered candidates inthe industry base case. Targeted R&D projectswere identified for specific reservoirs.
The documentation of anticipated improve-ment in the various processes is described in thereport. 35Incremental process costs and processperformance associated with proposed processimprovements were not identified. Conse-quently, there is no basis for a direct comparisonwith the Lewin ERDA projections resulting froman extensive R&D program. The agreement be-tween OTA projections and the Lewin ERDAprojections should not be considered confirma-t i o n o f e i t h e r s t u d y b y i n d e p e n d e n tmethodology.
Although the ultimate recoveries and ratesfrom the Lewin studies are close to the OTAresults, there are significant differences in theassumptions which were used to develop theresults. Distributions of oil recovery by processare also different. Principal differences betweenthe OTA and Lewin studies involve the projectedrecovery for each process.
The Oil recovery models used by Lewin andAssociates, Inc., for the FEA and ERDA studieswere reviewed on a reservoir-by-reservoir basis.Comparisons between OTA recovery models andLewin models produced the following observa-tions:
a. Recoveries from the C02 flooding processare comparable in specific reservoirs. The
jSResearch and Development in Enhanced Oil Recovery,
Lewin and Associates, Inc., Washington, D. C., November1976.
OTA high-process performance case, at theworld oil price, projects about a 40 percentgreater ultimate recovery from CO2 than thetotal for the Lewin ERDA research anddevelopment case plus the industry basecase. A primary reason is the presence of ad-ditional reservoirs in the extended data baseof the OTA study. The OTA low-processperformance result is about half the LewinERDA value at world oil price. Costs ofmanufactured COZ in some areas are higherthan in the Lewin study and this contributesin a minor way to the differences.
There are large differences between pro-jections of ultimate recovery from the steamdisplacement process. The ERDA industrybase case estimates ultimate recovery to be66 billion barrels at $13 per barrel. lncre-mentaI oil expected from proposed ERDAR&D,, , programs 8.2 billion barrels at thesame price. Thus, an ultimate recovery of14.8 billion barrels is projected from steamdisplacement as a result of ongoing industryactivity and proposed ERDA R&D programs.
The OTA study projects an ultimaterecovery of 3.3 billion barrels from steamdisplacement processes at $13,7’5 per bar-rel. This projection is lower than the ERDAindustry base case by a factor of 2, and islower than the ERDA industry base casewith ERDA R&D by a factor of 4.5. The OTAand ERDA projections of ultimate recoveryfrom steam displacement vary over a largerange because of differences in specifictechnological advances which were incor-porated in the displacement models. Majordifferences are discussed in the followingparagraphs.
About one-third of the oil produced in asteam displacement process is consumed togenerate steam. The amount of steam pro-duced by burning a barrel of lease crude isnot known with certainty. The OTA com-putations assumed 12 barrels of steam wereproduced per barrel of oil consumed, whilethe ERDA models assume 16 barrels ofsteam per barrel of oil. Applying the ERDAfactor to OTA computations would increasethe ultimate recovery about 10 to 15 per-
Ch. ///—Oil Recovery Potential ● 57
cent. Differences of this order of magnitudeare not considered significant.
Replacement of crude oil by a cheapersource of energy such as coal is a proposedERDA steam program. Incremental produc-tion of 1.0 billion barrels was expected fromthis program. A successful program could in-crease the net crude oil produced by a fac-tor of one-third in fields where it could beimpIemented. However , w idespreadsubstitution of coal for lease crude wouldhave to be done in a manner which wouldsatisfy environmental constraints. 36 T h eO T A s t u d y d o e s not eva luate th i spossibility.
One ERDA program for steam projects anultimate recovery of 1.8 billion barrels fromlight-oil reservoirs (less than 25oAPI) inTexas, Louisiana, and the midcontinent by asteam distillation process. This process wasnot considered in the OTA study. imple-mentation of steam disti l lation on aneconomic scale requires development of afuel for steam generation which is less ex-pensive than lease crude oil. These reser-voirs were assigned to other processes inthe OTA study.
The principal difference between ERDAand OTA projections is in the recoverymodels for the steam displacement process.The ERDA steam model was developedusing data from current field operationswhich are generally conducted in the bestzones of a reservoir. Every part of the reser-voir is considered to perform like theregions now under development. Steamdrive was limited to depths of 2,500 feet inthe ERDA industry base case. Increase in thedepth to 5,000 feet added 1.6 billion barrelsin the ERDA R&D case. The ERDA R&Dprogram includes anticipated improvementsin recovery efficiency for reservoirs whichare 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 im-prove the overall recovery efficiency ofsteam drive by 50 percent. Incremental ulti-mate recovery for this program was ex-pected to be 2.3 billion barrels.
The OTA steam displacement models arebased on development of the entire reser-voir using average oil saturations and recov-ery efficiencies. All reservoirs 5,000 feet indepth or less were developed. The OTAmodels underestimate recoveries from thebetter sections of a reservoir and overstaterecoveries from poorer zones. OveralIrecovery from the OTA models is believedto be representative of the average reservoirperformance.
Closer agreement between the ERDA in-dustry base case and the OTA projections atthe world oil price can be obtained byreducing the ratio of injection wells to pro-duction wells, thereby reducing the capitalinvestment. The ERDA industry base caseassumes fieldwide development on thebasis of 0.8 injection well per productionwell. The OTA advancing technology casesused 1.0 injection well per production well.Reduction of the number of injection wellsto 0.3 per production well in the OTA com-putat ions makes steam displacementeconomic in several large California reser-voirs at the world oil price. Ultimate recov-ery at this price increases from 3,3 billionbarrels (one injection well/production well)to 5 .3 b i l l ion bar re l s (0 .3 in ject ionweIl/production well). Producing rates in-crease correspondingly. This comparison in-dicates potential improvements could resultfrom optimizing well spacing. Additionalresults are included in appendix B.
In summary, steam displacement pro-jections in the ERDA industry base case andERDA R&D case assume more technologicaladvances than judged to be attainable in theOTA study.
c. OTA surfactant/polymer projections forboth low- and high-process performancecases fall between the projections from
Lewin’s ERDA industry base case andLewin’s FEA results for California, Texas, andLouisiana, for different reasons. Projectedsurfactant recoveries in the Lewin FEA studyranged between 3.8 billion barrels and 8.8billion barrels at $11 per barrel. These pro-jections are larger than OTA projectionsunder the same economic conditionsbecause the recovery models are based ondifferent representations of the displace-ment process.
The industry base case for ERDA limits ap-plication of the surfactant/polymer processto shallow homogeneous reservoirs in themidcontinent. Ultimate recovery was esti-mated to be 0.6 billion barrels at $13 perbarrel. This corresponds to the OTA pro-jected recovery of 2.3 billion barrels at theworld oil price for the low-process per-formance case and 10 billion barrels for thehigh-process performance case. The ERDAR&D program for the surfactant/polymerprocess projects an ultimate recovery of 1.4billion barrels at the world oil price.
California reservoirs, which are major sur-factant/polymer contributors in the OTAstudy, were excluded from the ERDA indus-try base case by assuming that technologywould not be developed in the absence oft h e E R D A R & D p r o g r a m . T h e O T Amethodology resulted in assignment ofmore reservoirs to the surfactant/polymerprocess than in the ERDA cases. A majordifference exists in volumes and costs ofchemicals used in the ERDA calculations.These volumes approximate those whichhave been tested extensively in shallowreservoirs in Illinois. The OTA advancingtechnology cases project technological ad-vances which would reduce the volumes ofchemicals required. This has a profoundeffect on the development of the surfac-tant/polymer process, as the projectedrecovery for the high-process performancecase at the world oil price is reduced from10 billion barrels to 2.9 billion barrels whenOTA current technology surfactant andpolymer slugs are used in the economicmodel.
d
Ch. ///—Oil Recovery Potential . 59
Ultimate recovery from polymer flooding polymer model projects less recovery thanvaries 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 thejections 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 ofseveral barriers to widespread commercializationof EOR38 that include economic risks, capitalavailability, and institutional constraints. Theseconstraints are coupled, and all must be removedor reduced to achieve major oil production fromEOR processes.
The following section identifies and discussesthe technological constraints that must be ad-dressed in order to achieve the rate of progressthat is postulated in the advancing technologycase.
The technological constraints on EOR havebeen 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 isnot certain. The uncertainty is estimated to be 15to 25 percent. Although this range may not seemlarge for the national resource, variation amongreservoirs probably is larger. Furthermore, a smallreduction in remaining oil in a reservoir maymake it uneconomical to apply a high-cost EORprocess at all, thereby leading to a disproportion-ate reduction in economically recoverable oil,The difference may be as high as the differencebetween 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 performanceto 18 bill ion barrels at
cases, which amountsthe world oil price,
equivalent to about half the current U.S. provedreserves.
Resource uncertainty represents a major tech-nical and economic risk for any EOR project inany reservoir. Reduction of this risk would needhigh priority in any national program to stimulateEOR production.
Sampling a reservoir through core drilling, log-ging, and other well testing is an expensive, inex-act, developing technology. The problem is thatof finding methods which will probe outward asufficient distance from a well bore to determineoil content in a large fraction of the regiondrained by the well. A further complication existsin that oil saturation variations occur bothhorizontally and vertically within a reservoir.Determinations at one well may not be applica-ble at other well sites.
A program to stimulate EOR production shouldcontain a major effort to promote measurementof residual oil saturations in key reservoirs untilconfidence is gained in methods to extrapolatesuch data to other locations in the same reser-voir and other reservoirs. Equal emphasis shouldbe placed on the gathering of such data and onthe improvement of measurement methods.
Process Performance
Process Mechanisms
Enhanced oil recovery processes are in variousstages of technological development. Eventhough steam drive is in limited commercialdevelopment, the outer limits of its applicabilityare not well understood. Steam drive can proba-bly be extended to light oil reservoirs but it has
60 . Ch. ///—Oil Recovery P o t e n t i a l
not been tested extensively. Larger gaps inknowledge exist for other processes and processmodifications which are in earlier stages ofdevelopment. Field tests have consistently beenundertaken with incomplete knowledge of theprocess mechanism. Most laboratory tests ofprocesses are done on systems of simple geome-try (generally linear or one-dimensional flow),leaving the problems that occur because of themore complex flow geometry to field testing.
As indicated in the section on Process FieldTests on page 61, extensive field testing of EORprocesses will be required. As more field projectsare undertaken, the tendency of industry is toshift research personnel from basic and theoreti-cal studies to development activities. If this effortis widespread it may limit the ability of com-panies to undertake fundamental EOR research. Ifthis trend continues, additional public supportfor basic research applicable to EOR may becomeadvisable.
A major industry /Government coordinatedeffort is needed to thoroughly define the processmechanisms for each of the recognized basic EORprocesses and process modifications, This effortwould need to be initiated immediately and toproceed at a high level of activity for at least 5years if the postulated rate of EOR applications isto be achieved.
Volumetric Sweep Efficiency
Recovery efficiency of all processes dependsupon the fraction of the reservoir volume whichcan be swept by the process, i.e., sweep efficien-cy. Thus a strong economic incentive exists forimprovement of volumetric sweep. Research inthis area has been carried out for a number ofyears by many sectors of the oil production, oilservice, and chemical industries. The importanceto EOR success of improving sweep efficiencyhas been confirmed in a recent assessment ofresearch 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 ProgramTo Suppor t Deve lopment and field Demons t ra t ion o fEnhanced Oil Recovery, for U.S. Energy Research & Develop-ment 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 notavailable for each process. Improvements areneeded for each individual process and eachprocess variation as well as for major classes ofreservoirs. Progress will be difficult and will re-quire major field testing supported by extensiveprior laboratory work. This research effort, bothbasic and applied, must be significantly stimu-lated in the next 3 to 6 years in order to approachthe estimated EOR production potential for theperiod between 1976 and the year 2000.
Brine-Compatible Injection Fluids
Enhanced oil recovery processes will be usedlargely in those parts of the country that face in-creasing shortages of fresh water. For surfac-tant/polymer and polymer flooding, relativelyfresh water is still needed both for the polymerand surfactant solut ions and for reservoi rpreflushing. Even where fresh water is availablefor preflushing, it is often not efficient in displac-ing brine. Consequently, injected fluids in suchreservoirs must be brine compatible. Continuedlaboratory and field research is needed todevelop surfactants and other oil-recovery agentswhich are brine compatible.
In the present study, brine compatibility of in-jected fluids was assumed in the advancing tech-nology cases. Data were not available in the OTAdata base to assess the importance of thisassumption, but it is known to be significant.
Development of Additional ProcessesApplicable to Carbonate Reservoirs
Although carbonate reservoirs represent ap-proximately 28 percent of the initial oil in placein the United States,41 the C02 miscible process isthe only EOR process currently applied to suchreservoirs, There is a possibility of using steamflooding in some carbonate reservoirs,42 a n dother processes or process modifications should
41 Reserves of Crurje Oi/, Natural Gas Liquids, and Natural
Gas in the United States and Canada as of D e c e m b e r 31,7975, Joint publication by the American Gas Association,American Petroleum Institute, and Canadian PetroleumAssociation, 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 thepossibility of C02 shortages and because of thehigh cost of delivering CO2 to areas that mightnot be served by pipelines.
Operating Problems
Operating problems of EOR are more severe,less predictable, and certainly less easily con-trolled than operating problems one faces in aplant making a new chemical product, but the in-dustr ial sector i s equipped to solve suchproblems. For example, steam is now generatedfrom high-salinity brines, a process that onceseemed to pose serious technical problems. Mostsuch problems, however, must be solved withinthe next 6 to 8 years if the potential productionrepresented by OTA’s advancing technologycase is to be achieved.
Some problems exist where Governmentassistance could be beneficial. Design of steamgenerators for steam-drive projects that will meetenvironmental pollution-control standards anduse cheaper alternate fuels (heavy crudes, coal,etc.), as well as large-scale steam generation, areareas that have been recently highlighted.43
Equipment for retrofitting existing generators topermit them to meet new standards and lowertheir unit pollution level is also needed.
Process Field Tests
The current ERDA field testing program is avital step in accelerating EOR process commer-cialization, If the upper targets of any of the re-cent predictions of EOR potential are to beachieved, a significant increase is needed in therate of technical progress. To achieve this, thelevel of field tests needs to be significantly in-creased. While OTA did not attempt to estimatethe optimal number, a study by the Gulf Univer-sities Research Consortium (GURC) estimated100 as a target group.44 It is important that ERDA-sponsored field tests be part of an EOR researchstrategy 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 begeneralized to a variety of classes of reservoirs,The status of current field tests taken from theLewin ERDA report45 is shown in table 25.
There are at least three levels of field tests:minitests, single- or multi pattern-pilot tests, andfieldwide commercial testing.
Single- and multipattern-pilot tests should bedirected at determining potential economic suc-cess and to thoroughly defining the technical per-formance. To maximize the value of such fieldtests, extensive pre- and post-test well coring,logging, fluid analysis, and laboratory tests are re-quired to understand the process well enough toprovide a strong knowledge base for operating atfull scale in test reservoirs. Data acquisition is ex-pensive and time consuming, and the record indi-cates that too little data are being gathered.Government support for such activities may berequired if the postulated rate of technologicaladvance is to be achieved.
Special consideration should be given to test-ing more than one process in a reservoir and toundertaking processes in reservoirs that offer newranges of application of the process.
There is some current concern about the rela-tive merits of minitests (one to two well tests atsmall well spacing) compared with larger single-or multipattern-pilot tests. Both can be helpful.The minitest is faster, less expensive, and may behelpful in initial process or reservoir screening.However, its lower cost and greater simplicity donot substitute for the greater degree of under-standing that can come from multi pattern tests.
The number of projects that should be under-taken for fieldwide commercial demonstration isnot easily determined. A case can be made for atleast one such test for every major process thathas not yet reached commercialization. The op-tions of cost sharing, risk sharing, and/or supportthrough special price or tax provisions should allbe considered. Considerations of the merits ofsuch alternatives, the scale of operations, and theapplicable 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 25Field 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
1Total
1717
512
3
59
68
lots
Current
133
410
0
17
44
Number of EOR Proiects
Economicpil
Total
156
67
14
26
57
ots
Current
145
67
9
05
47
Fieldwldedevel
Total
1519
22
14
010
62
]ment
Current
1510
22
11
08
48
Acreage undercurrent
development
15,6824,548
38,6181,418
14,624
6356,782
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 ad-dressed within the next year or two. This testprogram is a facet of the Government programthat deserves a major emphasis.
Reservoir Characteristics
Uncertainty concerning the physical andchemical nature of an oil reservoir is one of themost severe technological barriers to EOR proc-esses . 46 Not only are reservoirs significantlydifferent among themselves, even within thesame geological class, but the place-to-placevariations in thickness, porosity, permeability,fluid saturation, and chemical nature can be dis-couragingly large. The present ability to describe,measure, and predict such variability is extremelylimited. Knowledge to measure and predict thisvariability within a reservoir is vitally importantfor forecasting fluid movement and oil recoveryefficiency. Research efforts have so far beendirected toward studying portions of individualreservoirs intensively, with little attention givento generic solutions.
46 Technjca/ p/an for a Supplementary Research prOgram
To Support Development and Field Demonstrat ion ofEnhanced Oil Recovery, for U.S. Energy Research andDevelopment Administration, Washington, D. C., GURCReport No. 154, Mar. 17, 1977.
Any major governmental research effort to ac-celerate oil production from EOR processesshould include development of methods tomeasure, describe, and predict variations in prop-erties throughout a reservoir. Extensive field andlaboratory studies are warranted.
Raw Materials Availability
Enhanced oil recovery processes use bothnatural and manufactured raw materials.. Short-term shortages of manufactured materials couldexist for all EOR processes if a vigorous nationalprogram were launched to produce EOR oil.
The supply of two natural resources, freshwater and C02, may limit ultimate recovery fromsteam injection, surfactant/polymer, and C02
miscible processes. Local shortages may developfor adequate supplies of fresh or nearly freshwater in some areas in which polymer flooding orsurfactant/polymer flooding is initiated. Mostareas of known fresh water shortage either haveor are developing criteria for allocation of thescarce supply among competing classes of use. Amajor technological challenge for EOR lies indevelopment of economic means for using waterwith higher saline content for all processes inwhich water is needed. The problem seems tohave been solved for steam generation. Brine ofup to 20,000 ppm can be used successfully.
Carbon dioxide availability is central to anymajor expansion of C02 flooding. As mentionedpreviously, the quantity needed (a total of 53 Tcfin the advancing technology-high-process per-formance case at world oil prices) is a volumealmost three times the annual volume of naturalgas consumed in the United States.
The economic potential of C02 flooding is sogreat that a Government effort to accelerate EORproduction should include not only locatingnatural sources of carbon dioxide but also explor-ing ways to produce it economically from large-scale commercial sources. Locations of known,naturally occurring C O2 sources are summarizedin the recent NPC study of EOR.47 The magnitudeof the reserves of CO2 at these locations is notknown. ERDA is currently involved in a nation-wide survey of CO2 availability.
Human Resources
Shortages of technically trained people tooperate EOR projects may exist temporarily if amajor national EOR effort is undertaken. Nationalprojections of needs for technically trained peo-ple have not been highly accurate. Data are notreadily available on industrial needs since manyfirms do not make formal, continuing, long-rangepersonnel forecasts. The efforts of ERDA andother agencies in national manpower forecastingcould be encouraged.
All EOR processes are extremely complex com-pared to conventional oil recovery operations.Because of this technical complexity, highly com-petent personnel must be directly involved ineach EOR project on a continuous basis at themanagerial, developmental, and field operationslevel. Without close monitoring by qualifiedtechnologists, the odds for success of EOR proj-ects will be lower, There currently is a mild short-term shortage of persons to work on EOR proj-ects. National forecasts48 of the number of availa-ble college-age students (all disciplines) indicate
qTf~~a~Cecj 0;1 Recovery, N a t i o n a l p e t r o l e u m Council,
D e c e m b e r 1 9 7 6 .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 periodof greatest potential EOR activity. The supply oftechnical people (engineering, science, and busi-ness) available for EOR operations will cruciallydepend upon the economic climate in other sec-tors of the economy. In a generally favorableeconomic climate, increasing competition forqualified personnel could develop.
Environmental Effects
For most EOR p r o c e s s e s a n d i n m o s tgeographical areas, accommodation to environ-mental protection regulations will not be a criti-cally restrictive requirement. Details of environ-mental impacts and an estimate of their severityand magnitude are described in chapter VI of this
r e p o r t . T h e e n v i r o n m e n t a l e f f e c t s t h a t p o s e m a j o r
t e c h n o l o g i c a l p r o b l e m s i n c l u d e the need fo remission controls in California thermal EOR proj-ects, the possibility of fresh water shortages, andthe need to protect ground water.
The need to develop an economically accepta-ble means of meeting the air pollution require-ments for thermal processes has become criticalin California. Further expansion of the thermalprocess in California awaits this development.
The requirements placed on EOR processes bythe Safe Drinking Water Act (P.L. 93-593) arecritical for their long-term development. Accom-modation to the Safe Drinking Water Act is notso much a technological problem as it is a humanand administrative matter. The need is one ofestablishing acceptable guidelines that will pro-tect fresh water sources and still allow EOR proc-esses to proceed. The record of compatibility ofthese two goals through the long period of sec-ondary recovery in the United States suggeststhat this can be accomplished. This is discussedfurther in chapter VI.
The Rate of Technological Evolution
All estimates of potential recovery from ap-plication of EOR processes are based on a postu-lated rate of technological evolution. There isconsensus among personnel in industry, Govern-ment, and academic institutions who are
64 ● Ch. Ill—Oil Recovery Potential
knowledgeable in enhanced oil recovery proc-esses that much research and field testing isnecessary to bring EOR technology to the pointwhere commercialization is possible for all proc-esses except steam displacement.
The suggested components of research anddevelopment programs to stimulate EOR produc-tion have received significant appraisal andmodification within the last 4 years. Between1973 and March 1977, the Gulf UniversitiesResearch Consortium (GURC) issued a series offive reports 49,50,51,52,53 detailing the need for fieldtests, their number and character, and the basicresearch needs. In addition, Lewin and Associ-ates, lnc,54 prepared a major study for ERDAwhich recommends specific research targets(process/reservoir type). Further details of theERDA program are outlined in the ERDA Manage-ment Plan for EOR.55
The GURC and Lewin documents representcompilations of existing industrial viewpointsconcerning research targets and types ofprograms that are appropriate. This gathered con-sensus has been supplemented by a series ofERDA-sponsored workshops on ERDA research
targets 56,57 at which modifications to the programwere suggested through public forums.
Although there is agreement concerninggeneral research and development needs, there isa decided difference of opinion regarding the fac-tors which will stimulate this needed researchand development. The Lewin ERDA study58 pro-posed an extensive Government research anddevelopment program, justified in part by resultsof an industry survey which indicated thatresearch would not be greatly accelerated withinthe current set of constraints (economic, techni-cal, and institutional). The National PetroleumCouncil’s EOR study concluded that “Govern-ment policy with respect to oil price and otherfactors influencing EOR profitability is the domi-nant factor in establishing the level of R&D fund-ing and the rate of evolution of technology. ”
The OTA assessment did not attempt toresolve these positions because there appearedto be no meaningful way to predict what industrywould do a) if the price of oil produced by someEOR processes was allowed to rise to free marketprices as proposed by FEA, orb) if the price of allEOR oil were decontrolled. as proposed in thePresident’s National Energy Plan.
The ERDA Programs
The Energy Research and” Development Ad- ment of EOR processes. The general thrust of theministration has developed programs which are ERDA programs, including field testing and con-directed at stimulation of research and develop- tinued industry/Government interaction, is good.
i ’ ~P/a r m ing Cri(erla Relative to a Nationa/ RDT&E ProgramDirected to the [nhanced Re(okery of Crude Oil and NaturalGas, for U.S. Atomic Energy Commission, Washingtcm, D. C.,GURC Report No. 130, Nov. 30, 1973.
~OAn /investigation of Prirnw-y Factors Affecting Federal Par-
ticipation in R&D Pertaining to [he Accelerated Productionof 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 Methodsfor Crude Oil (supplement to GURC Report No. 140), for theNational Science [oundation and the Federal Energy Ad-ministration, Washington, D. C., GURC Report No. 140-S,Nov. 11, 1974.
Szpreliminary Fie/d Tes( R~~cornrnendatlons and prospec-
tive Crude Oil Fields or Reservoirs for High Priority F/e/dTesting, for (J.S. Energy Research and Development Ad-ministration, Washington, D. C., GURC Report No. 148, Feb.28, 1976.
53 Technica/ Plans for a Supplementary Research program
to Support Dcveloprnent and F ie ld Demons t ra t ion o fEnhanced Oil Recovery, for U.S. Energy Research andDevelopment Administration, Washington, D. C., Gl_JRCReport 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 byERDA, 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 EOR 59 i sdirected at maximizing production in themid-1980’s. However, short-term needs shouldnot overshadow long-term national needs of in-creasing oil recovery. The OTA analysis indicates
that a long-range program is needed to st imulate
the development of processes, such as the surfac-tant/polymer process, which have the potentialfor greater oil recovery in the mid-1990’s,
There does not seem to be adequate basic andapplied research in the ongoing ERDA program.This has been recognized by ERDA, and an exten-sive research program has recently been outlinedby GURC60 for ERDA. This research program sup-plements the programs outlined in the ERDAmanagement plan.61
The largest amount of basic and appliedresearch has come from the integrated major oilcompanies and the serv ice sector of thepetroleum industry. The largest amount of exper-tise also resides in the industry. Basic and applied
research done by industry and research institu-tions should be coordinated so that Governmentprograms complement rather than duplicateprograms underway in industry. This subject doesnot seem to be covered formally in the ERDAdocuments, and is particularly crucial since evenunder Government sponsorship a large portion ofthe basic and applied research is likely to bedone in industry laboratories and oilfields.
The OTA assessment did not determine thelevel of ERDA or industry effort required toachieve the postulated technological advances orthe cost of the necessary research and develop-ment. (Other studies have shown that the cost ofresearch and development is on the order of afew cents per barrel of ultimate recovery.)However, the level of effort and funding in R&Dmust clearly be significantly increased over cur-rent levels by both industry and Government inorder for the evolution of technology to ap-proach the technological advances postulated inthis 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 Pmgrmto Support Development and Field Demon5(ratlon ofEnhanced Oil Recovery, f o r 1.1.S. E n e r g y R e s e a r c h a n d
D e v e l o p m e n t A d m i n i s t r a t i o n , W a s h i n g t o n , D . C . , CiURC
R e p o r t N o . 1 5 4 , M a r . 1 7 , 1 9 7 7 .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 andTax Policies on Oil Recovery
IV. Impacts of Price andTax Policies on Oil Recovery
Policy Considerations
With the advent of a new technology likeenhanced oil recovery (EOR), two related factorsoften inhibit expansion of output. First, even withcertainty of information about prices, costs, andproduction, careful analysis may indicate thatproduction will not be profitable for early opera-tors. prices may be too low or production ex-perience may have been inadequate to reducecosts or increase efficiency sufficient to yield anacceptable return on invested capital. Second, asin any market situation, there will be uncertaintyabout many variables that can affect profitability.In the case of EOR, technical and economic un-certainty, coupled with some degree of aversionto risk by potential operators, can inhibit thespeed and extent of process development.
Proposed public policy alternatives are, in es-sence, attempts to reduce the effects of thesetwo factors on the private decision process,modify private market decisions, and remove bar-riers to EOR development. Although these twofactors are obviously interdependent, the ar-tificial distinction will be maintained for pur-poses of this analysis. First, the report evaluatesalternative public policy options designed tofoster private-sector development of enhancedrecovery processes under the assumption of in-formation certainty. Point projections of produc-tion, price, and cost profiles for selected reser-voirs will be used. A second analysis, using sub-jective probability distributions of key inputvariables, describes the impact of policy alterna-tives designed to alleviate economic uncertainty.
Policy Options
A number of public policy alternatives havebeen suggested which could influence thedevelopment of EOR techniques, Implementationof these alternatives may affect private sectordecisions on the development of specific EORreservoirs or modify decisions regarding whichprocess should be installed. Some policy optionsalso may alter constraints which would limit theamount of EOR production nationally. Regardlessof their specific focus, most public policychanges can be expected to influence the degreeof uncertainty perceived by the private sector infuture EOR activities.
A number of these potential public policy ac-tions will be analyzed and evaluated. The prin-cipal proposals can be classified as:
1)
2)
alternative regulated and/or market pricelevels;
price and/or purchase guarantees for EORover the lifetime of a producing facility;
3)
4)
In
alternative taxation policies, includingchanges in depreciation methods, invest-ment tax credit rates, and expensing rulesfor various categories of investment andoperating costs; and
public investment subsidies-Governmentpayment of a percentage of private invest-ment costs.
addition, the effects of these alternativestrategies can be determined under alternativeleasing systems when the reservoirs being con-sidered 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 leaseterms to encourage enfianced oil recovery installations at anoptimal point in the production time horizon. Analysis ofthis option, however, requires data not only on EOR costsand production profiles but on the synergistic effects withprimary and secondary production. Since little experience isavailable on these elements, evaluation of the option wouldbe 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 variousoptions in conjunction with several leasingsystems, including the current system and othersthat could be used in the future. These systemsinclude:
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 fivedifferent price assumptions for enhanced oil pro-duction:
1) The current regulated upper tier (new oil)price of $11.62 per barrel;
2) The current price of foreign crude oil landedin the Eastern United States—$1 3.75 perbarrel (in 1976 dollars);
3) A price approaching the estimated cost ofsynthetic fuels—$22 per barrel;2
4) An intermediate price between the worldoil ‘price and the synthetic fuels price—$1 7per barrel; and
5) A rising real world oil price initially set at$13.75 per barrel and projected to rise at a5-percent annual rate.
The first four alternatives assume a constant realprice and the fifth alternative assumes a risingreal price.
For each EOR process, baseline evaluationswere carried out using these alternative price
Analytical
All reservoirs in a selected sample were tested,using cost and production profiles from the high-process performance case discussed in chapter III.As a check on these results, data from the low-
2This price was obtained from the report of the Synfuels
Interagency Task Force.
levels and currently permitted tax procedures (in-cluding the 10-percent investment tax credit, ex-pensing of injection chemicals, and Unit of pro-duction depreciation). Then, the following policyalternatives 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 com-pared with the current 10 percent;
Capitalization and subsequent depreciationof injection chemical costs;
5) Use of an augmented accelerated deprecia-tion method; and
6) Government investment subsidy of 15 per-cent of initial capital investment.
Since several of these options (price subsidiesand guarantees) are designed to reduce uncer-tainty, they were not evaluated under theassumption of information certainty.
Alternative leasing systems for public domainlands were tested with various options, includingthe current cash bonus—fixed royalty system, acash bonus system with a 40-percent fixedroyalty, and an annuity capital recovery-profitshare system with a cash bonus bid. In this profitshare system, investment costs are converted toan annuity over 8 years of 8-percent interest, andthe annuity is subtracted from net profits beforethe Government share of 50 percent is taken. j
Approach
process performance case were also analyzed. in-dividual EOR processes were evaluated sepa-
‘Other leasing systems have been suggested and couldbe evaluated. For example, variable rate options for bothroyalty and profit share systems may be desirable alterna-tives. However, the systems chosen appear to cover a rangeof 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 andpolicy options discussed above. 4 The entire Kalter, 1976), modified toanalysis was conducted using a Monte Carlo dis- sion process as viewed by
Analysis of Government Policy Options
handle the EOR deci-the private sector.
Reservoir Sample
For purposes of policy analysis, a sample of upto 50 of the reservoirs assigned to each EOR proc-ess (see previous discussion) was selected for ini-tial evaluation. Separate samples for onshore andoffshore areas were drawn from reservoirsassigned to the CO2 process. Sample selectionwas based upon a number of criteria includingregional location, reservoir depth, residual barrelsof oil per acre (available for tertiary production),reservoir size in acres, and, in the case of offshorefields, water depth, For each EOR process evalu-ated, fields covering a broad range of thesecharacteristics were included.
After reviewing the range of values taken onby the various selection criteria, it was decidedthat a sample of 25 reservoirs for each EOR proc-ess would be adequate to cover the circum-stances affecting economical development andprovide an appropriate test of the various policyoptions. The only exception to a sample numberof 25 was the case of onshore C02 where sub-stantial EOR production was expected. Table 26
4Reservoirs subject to more than one EOR process were
not evaluated with respect to the impact of policy optionson each process or on process selection. The impact of alter-native price levels and decision criteria on process selectionwas discussed in a previous section but data were notavailable to carry out a detailed analysis here. Since mostpolicy options were analyzed at the world oil prices, thisprocedure should not affect the results (process selectionwas generally carried out at this price level).
displays the number of reservoirs assigned toeach process, the number selected for the sam-ple, and the percentage of the reservoir data basesampled.
Analysis Assuming Information Certainty
Price analysis
Given the sample selection, the first step in theanalysis was to test the potential for profitableEOR development at various price levels underconditions of information certainty. Using pro-duction profiles, investment costs (and timing),and operating costs developed for the high-proc-ess performance case, these tests were con-ducted under the assumptions that private indus-try would require a 10-percent net after tax, rateof return on invested capital and that currentlypermitted tax procedures (State and Federal)would be governing. Thus, a 10-percent invest-ment tax credit, expensing of EOR injection costs,depreciation based on the rate of resource deple-tion, and current State and Federal income taxrates were used.
Table 27 displays the number and percent ofeach EOR process sample that would bedeveloped at various price levels under theseconditions, as well as the percentage of potentialEOR production (gross production less that usedfor EOR purposes) that would result from thosedeveloped. For example, development rangesfrom 6 percent of the fields at $11.62 per barrelfor steam to 95 percent of all fields assigned to
72 ● Ch. IV—impacts of Price and Tax Policies on Oil Recovery
Table 26Number 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 294Sample size . . . . . . . . . . . . . . . . 20 20 25 20 50 25Percent sampled . . . . . . . . . . . . 100 100 27 100 26 9
● All offshore reservoirs were assigned to the CO2 recovery process.
Tabie 27EOR Reservoir Development and Production by Process and Price Levei
Processandprice range(per barrel)
Steam$11.62 . . . . . .
13.75 . . . . . . .
17.00 . . . . . . .
22.00 . . . . . .
In Si tu
$11.62 . . . . . . .
13.75 . . . . . . .
17.00 . . . . . .
22.00 . . . . . . .
S u r f a c t a n t
$11.62, . . . . . .
13.75 . . . . . . .
17.00. , ., . .
22.00 . . . . . . .
P o l y m e r
$11.62 . . . . . . .
13.75 . . . . . . .
17.00 . . . . . . .
22.00 . . . . . . .
C O2 - - O n s h o r 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 . . . . . . .
Samplesize
20202020
20202020
25252525
20202020
50505050
25252525
160160160160
N u m b e r
d e v e l o p e d— . — —
69
1114
14161818
1 4
1 9
1 9
2 2
14171719
12223237
99
1519
6992
112129
Percentdeveloped
30455570
70809090
56767688
70858595
24446474
36366076
43587081
Percentpotential
productiondeveloped
4 1
4 7
7 5
8 5
8996
100100
77858594
949999
100
22275071
2424‘3550
46526982
Sampleprice
elasticityof supply
.993.10
,62
.52
.19
.00
.70
.00
.46
.32
.00
.05
1.524.261.87
.002.211.99
.881.78
.81
Ch. IV—impacts of Price and Tax Policies on Oil Recovery . 73
polymer at $22 per barrel. production rangesfrom 22 percent of the total possible for onshoreC 02 at $11.62 per barrel to 100 percent forpolymer and in situ at $22 per barrel. Currentworld prices of $13.75 per barrel result in up to99 percent of possible production from thepolymer process, and up to 24 percent of possi-ble EOR offshore oil production for those reser-voirs assigned to the C02 process. Overall, 43 to81 p e r c e n t of the sample reservoirs aredeveloped over the price range analyzed, with 46to 82 percent of possible EOR oil being pro-duced, 5
Of perhaps greater interest, however, is theprice elasticity of supply (i.e., the percentagechange in production for each 1 -percent changein price) Table 27 also lists these values (arcelasticities) for the sample over the price rangeanalyzed. 6 Individual EOR processes, as well astotal production from all processes, are shown. Itis obvious that the price elasticities vary acrossboth 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 alsotrue of all processes combined. In situ, surfactant,and polymer are, however, price inelastic to thepoint where higher prices will have little impacton production.
All processes, except offshore C02, exhibit thegreatest price elasticity in the Iow and/or middleprice ranges (to $17 per barrel). Offshore C02 ex-hibits 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 priceswould be implemented on only two reservoirs in the sample(8 percent) and result in 7 p~r~ent of the potential net pro-duction. Similar calculations could be shown for other proc-esses and price levels. However, the object ot this section isan evaluation of policy options. For this purpose, the high-process performance case is used as a basis with digressionsto other cases only if policy conclusions would be affected.Also, the values change considerably when the analysis isconducted at the lower tier (old oil) price of $5.25 per bar-rel. At this price only 8 percent of the reservoirs with 14 per-cent of total possible production were developed.
6The elasticity formula u s e d for all calculations was
( Q , - Q( l) /Q, , + (P I-P,, / P , . N o t e t h a t these value> relate to
ul t imate net product ion and, thus , g ive no indicat ion of the
sens i t iv i ty o f product ion pro f i les (or t iming) to pr ice.
range ($13.75 to $17 per barrel), with substantial
elasticity above $17 per barrel. These results sug-gest the greatest price impact on production willtake place in the range of real prices from $11.62per barrel to approximately $17 per barrel, exceptin the high-cost offshore regions. With real oilprices expected to increase in the future, aneffective method for encouraging EOR develop-ment would be to allow prices for EOR oil to risewith the world price. This conclusion is furthersupported by the fact that those EOR processeswith the greatest production potential also havethe 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, 6between $27.50 and $50 per barrel, 2 between$50 and $75 per barrel, and 2 could not bedeveloped unless price exceeded $75 per barrel.As a result, 94 percent of the potential EOR reser-voirs in the sample can be developed at pricesbelow $27.50 per barrel. Overall price elasticityis positive (1 .35) in the range of $22 to $27.50per barrel, but almost zero above $27.50 per bar-rel. Some fields in the steam, in situ, and surfac-tant processes could not be developed at pricesbelow $50 per barrel. These processes use a por-tion of the recovered oil in the recovery process,so higher product price also means higher pro-duction cost.
It could be dangerous to generalize from thesample (although the steam and in situ samplesincluded almost all assigned reservoirs), and thesupply elasticities calculated from the sample were therefore compared with those based uponall reservoirs assigned to EOR processes in boththe low- and high-process performance cases.Such a comparison cannot be precise because ofthe different approach used in the overall analysisto address economic calculations. Furthermore,the policy sample contains a greater proportionof marginal fields than does the total data set.
In general, the results displayed in table 28 in-dicate that the tendencies apparent from thesample are supported when looking at the entirehigh-process performance data base, Surfactantbecomes price elastic, along with CO2 and steam,but onshore CO2 appears somewhat less pricesensitive 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 ap-parent which would argue for a change in thepreviously discussed conclusions. As would beexpected, the low-process performance caseshowed higher price elasticities for a number ofthe processes. Only in situ remained price in-elastic overall, while the price elasticity of steamdropped.
Analysis of Other Policy Options
Given the potential impacts of price on EORdevelopment, the next question under theassumption of information certainty is whether
other public policy options would change EOReconomics. To answer th is quest ion, OTAanalyzed four possible policy changes (three taxconsiderations and a public investment subsidyto encourage EOR development).
The tax options include the use of a 12-per-cent investment tax credit (2 percent more thanthe current rate), accelerated depreciation usingthe double declining balance method, and an op-tion in which injection costs are 100 percentdepreciated rather than expensed. The latter op-tion was conducted to evaluate industry’s con-tention that the Internal Revenue Service must
Table 28Price Elasticity of Supply Comparison
Process andprice range(per barrel)
SteamOverall ($11 .62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
In situOverall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
SurfactantOverall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
PolymerOverall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
C O2- O n s h o r eOverall ($11.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
C O2- O f f s h o r eOverall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 ..., . . . . . . . . . . . . . . . . . . . . . .
All processesOverall ($1 1.62-22.00) . . . . . . . . . . . . . . . . . .$11.62 -13.75 . . . . . . . . . . . . . . . . . . . . . . . . . .$13.75 -22.00 . . . . . . . . . . . . . . . . . . . . . . . . . .
Policy analysissample
High-processperformance
case
2.32.99
2.18
.25
.52
.10
.48
.70
.28
.11
.32
.06
4.641.524.22
2.26.00
2.84
1.70.88
1.56
OTA total reservoir assignment
High-processperformance
case
2.421.152.18
.25
.76
.00
1.472,51
.59
.00
.00
.00
2.493.341.16
7.063.235.04
2.022.461.10
Low-processperformance
case
1.921.231.60
.711.08
.38
12.938.395.57
1.063.23
.00
5.332.034.46
——.
4.502.423.39
Ch. IV—Impacts of Price and Tax Policies on Oil Recovery . 75
Table 29EOR 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
Samplesize
202025205025
160
$13.75per barrel
9161 9
1 7
2 2
9
92
permit the expensing of injection costs if EOR isto be economically viable. Depreciation wasassumed to take place over the remaining pro-duction period in proportion to production. Theinvestment subsidy option calls for the Govern-ment to pay 15 percent of all initial EOR capitalinvestments (deferred investments and injectioncosts are paid fully by the producer).
Table 29 displays the result of these tests. Allevaluations assumed current world market prices($1 3.75 per barrel). As can be seen, the variousopt ions have relat ively minor impacts ondevelopment and, consequently, on production.In fact, the 12-percent investment tax creditresults in no new development, while the ac-celerated depreciation option adds one reservoirto the in situ process and increases total net pro-duction by only two-tenths of 1 percent. On theother hand, the requirement that EOR injectioncosts be 100-percent depreciated results in 30(32 percent) fewer sample reservoirs beingdeveloped with a 29-percent reduction in totalproduction. The reduced production is concen-trated in surfactant, with some impact on thesteam, polymer, and onshore CO2 processes. Theonly policy option at all effective in encouragingdevelopment appears to be a 15-percent invest-ment subsidy which would add three developedreservoirs at current world prices and result in a1 -percent increase in net production. T
The various options do change the amount ofabove normal (1 O-percent rate of return) profitthat can be expected from developed fields.
12-percent I I Depreciate I 1 5-percentinvestment I Accelerated I injection
I
investmentcredit depreciation costs subsidy
9 9 6 916 17 16 1819 19 4 1917 17 15 1722 22 13 22
9 9 9 10
92 I 93 I 63 I 95
Depreciation of injection costs would tend toreduce rates of return and the other optionswould increase them. If the introduction of EORto potential reservoirs is paced on the basis ofrates of return (as assumed previously), thischange could have an impact on aggregate pro-duction profiles and the timing of recovery. Theexact impact is impossible to quantify since firmswill have different decision criteria and schedulesfor EOR initiation based on those criteria.
For policy analysis, these results need to becompared with the costs of the respectivepolicies. In the case of a 12-percent investmenttax credit, the Government revenue loss is notoffset by additional tax revenues because no newoutput results. The accelerated depreciation op-tion adds one additional reservoir, increasing pro-duction by more than 28 million barrels. At thesame time, Government revenue actually in-creases due to the higher production and result-ing tax receipts. The increase per barrel of pro-duction, however, is slight-less than 1 cent perbarrel.
7Similar results were obtained when analyzing the low-process per formance case. The number of reservoirs thatdeveloped at a 10-percent rate of return was obviouslyreduced by a substantial degree. However, the variouspolicy options have little impact on changing these deci-sions. Taking surfactant as an example of a process which isoften marginal, the various options resulted in only one ad-dition to the two fields developed under free market condi-tions (see footnote 4). That development occurred when a15 percent investment subsidy was introduced. Requireddepreciation of Injection costs, however, did not affect thedecision to develop.
76 . Ch. IV—impacts of Price and Tax Policies on Oil Recovery
As would be expected, requiring the deprecia-tion of injection costs increased Governmentrevenue while the 15-percent investment subsidyreduced it. However, the impacts per barrel of in-cremental production were quite small.
In summary, it appears that no policy option iseither very powerful in encouraging new produc-tion or very expensive in terms of Governmentcost per barrel produced. In fact, little appears tobe gained (or lost) by attempting to accelerateEOR development at a pace faster than that likelyto occur in current institutional setting. The ques-tion remains, however, whether such policy op-tions are worth potential distortions in efficiencyunder conditions of information uncertainty. Thisquestion is explored in the next section.
Analysis AssumingInformation Uncertainty
To evaluate the question of uncertainty in pro-duction, cost, and price values, the same sampleof reservoirs was used in conjunction with sub-jective probability distributions on the key inputvariables. Table 30 lists the variables and the dis-tributions used. The resulting range in productionfrom the reservoirs was substantially less thanthat resulting from the high- and low-process per-
Table 30Input Variables and Subjective Probability
Distributions Used for Monte Cario Simulations
Variable
PriceOriginal value ($/bbl.) . . . . . . . . . . . . . . . . . .Mean of price change distribution . . . . . .Standard deviation of price change
distribution. . . . . . . . . . . . . . . . . . . . . . . . . . .
ProductionTriangular contingency distributions. . . . . . .
Minimum . . . . . . . . . . . . . . . . . . . . ., . . . . .Most likely . . . . . . . . . . . . . . . . . . . . . . . . .Maximum . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment and operating costTriangular contingency distributions
Minimum . . . . . . . . . . . . . . . . . . . . . . . . . . .Most Likely. . . . . . . . . . . . . . . . . . . . . . . . . .Maximum . . . . . . . . . . . . . . . . . . . . . . . . . . .
Value
13.750.00
0.01
- . 3 0- . 1 00.05
- . 0 50.000.10
formance assumptions discussed in chapter Ill.This result indicates that the degree of uncertain-ty implicit in the cost and production distribu-tions was less than that incorporated in the twoadvancing technology cases. As a result, thepolicy tests can be considered conservative, inthat a policy which will not affect developmentunder these assumptions is unlikely to have anyimpact in practice.
Options Designed To Alleviate UncertaintyThe effects of uncertainty were evaluated at
the current world oil price. Because of the minorimpacts exhibited by the tax options in the pre-vious analysis, they were dropped from furtherconsideration. Two other options, designed toreduce uncertainty, were added: (1) a priceguarantee whereby the Government wouldassure a market price that did not fall below$13.75 per barrel; and (2) an actual price subsidy(payment by the Government over and abovemarket price) of $3 per barrel of EOR oil pro-duced. 8 In all evaluations, current tax rules and a10-percent rate of return were assumed. Table 31summarizes these evaluations.
The simulations provide interesting insightinto the potential profitability of EOR develop-ment. Overall, it appears that up to 23 percent ofthe developable EOR reservoirs (and 23 percentof the producible oil) would be available at cur-rent market prices with very low risk of a less-than-normal profit to the operator. The remainderof the fields with some chance of profitability arespread more or less uniformly over the probabil-ity range of less-than-normal profit categories.However, because of variations in reservoir size,the remaining recoverable oil is not distributeduniformly, but is concentrated in the 26 to 50percent and 75 to 99 percent chance-of-losscategories. Only 66 percent of the sample’s pro-ducible EOR oil has some probability of beingprofitably exploited under the conditions simu-lated.
The policy options analyzed have little effecton these results. Only the $3 price subsidy adds a
8A $1 per barrel subsidy was also evaluated but is notdisplayed 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. -
-uclx
cm t-
.
78 ● Ch. IV—impacts of Price and Tax Policies on Oil Recovery
significant number of reservoirs to those poten-tially developed (20 percent), but this results inonly a 6-percent increase in potential oil produc-tion. The impact is concentrated in the C02,steam, and surfactant processes. The 15-percentinvestment subsidy adds 5 percent to the poten-tial reservoir development but only 4 percent ad-ditional oil. Only C02 processes were affected,however. In most cases, reservoirs added to thosethat would be potentially developed are in thehigh-risk (76 to 99 percent chance of loss)category.
All options, however, have some impact onreducing the risk of development for those reser-voirs that are potential candidates under currentmarket conditions. Again, the most successfulpolicy in this regard is the $3 per barrel price sub-sidy with 55 percent of the potential productionclassified below 50-percent probability of a lessthan normal profit. This is a 31 -percent improve-ment over the base case and compares to a 2-percent improvement for the price guarantee op-tion and a 21 -percent gain for the investmentsubsidy.
The impacts of the various policy options onindividual EOR processes are similar to the over-all results, with the greatest addition to potentialEOR reservoirs and total production resultingfrom the price subsidy option. The reduction inrisk for potential production (from the base case)is greatest for the onshore C02 process, followedby in situ combustion and surfactant flooding.
Although increases in potential EOR produc-tion (from all risk categories) do not appear sub-stantial for any of the options designed to reduceuncertainty, the possibility of changing the risk ofdevelopment for those reservoirs included in thebase case warrants further investigation of a pricesubsidy. To accurately assess this option the po-tential benefits of increased EOR productionmust be balanced against Government costs.However, both the extent of increased produc-tion and the corresponding costs are difficult toquantify. Since the decision to recover EOR oildepends on a producer’s risk-preference func-tion, one must ascertain the appropriate decisionrule used by the private sector in makingdevelopment decisions before an accurateassessment can be made. Given that these deci-
sion rules will vary among firms and may changefor a given firm with implementation of a policysubsidy, Government cost is difficult, if not im-possible, to quantify. The cost of the $3 subsidyto all produced EOR oil will be offset to some ex-tent by an increase in Federal tax revenue and, inthe case of offshore fields, higher royalty collec-tions. Without knowledge of the impacts undervarying risk conditions and decision criteria, themagnitude of this change can only be an edu-cated guess, For a range of possible conditions,the net present value cost of the subsidy appearsto be in the area of $1.50 to $2 per barrel.
Analysis Assuming a Rising Real Price
The preceding analysis assumes that EOR oilwill be priced at $13.75 per barrel and that such aprice will continue, in real terms, throughout theproductive life of an EOR project. Evaluation ofthis assumption could lead to the conclusion thatthe results discussed above are an inaccuraterepresentation of future reality, If EOR oil pricesare deregulated and world market prices maintaina moderate, but consistent, real growth rate,much of the uncertainty exhibited in theprofitability of EOR projects may be eliminated.
To test this possibility, an analysis was per-formed on the sample which assumed an averageannual real price increase of 5 percent (randomlyselected from a normal price change distributionwith a standard deviation of 3 percent). Table 32displays the price deregulation impact and, com-pares it to the $13.7s price base case and the $3price subsidy situation (from table 31). It can beseen that the rising price scenario test equal led orexceeded the results of the price subsidy inreducing uncertainty for all EOR processes. Over-all, price deregulation led to a 34-percent in-crease in field development over the base caseand an 11 -percent increase over the price subsidyanalysis. Moreover, substantial shifts in the un-certainty category occurred for fields which wereformerly in high-risk categories (greater than 50-percent chance of loss). Price deregulation has asignificant impact in all EOR processes except insitu combustion.
Thus, if a moderate annual increase in real oilprices 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 couldGovernment policies to reduce uncertainty may be obtained with simple price deregulation.
Table 32Monte Carlo Simulation of EOR Oii Price Deregulation
(fixed $13.75 per barrel price, and a $3.00 per barrel subsidy)
EORprocessandpolicy
SteamBase case. . . . . . . . . . . . .Price subsidy. ... , . . . . .Price deregulation*. . . . .
In situBase case. . . . . . . . . . . . .Price subsidy. . . . . . . . . .Price deregulation*. . . . .
SurfactantBase case. . . . . . . . . . . . .Price subsidy. . . . . . . . . .Price deregulation*. . . . .
PolymerBase case. . . . . . . . . . . . .Price subsidy. . . . . . . . . .Price deregulation*. . . . .
C 02o n s h o r eBase case . . . . . . . . . . . . .Price subsidy . . . . . . . . . .Price deregulation* . . . . .
C O2- O f f s h o r eBase case . . . . . . . . . . . . .Price subsidy . . . . . . . . .Price deregulation* . . . . .
TotalBase case . . . . . . . . . . . .Price subsidy . . . . . . . . . .Price deregulation* . .
Samplesize
202020
202020
252525
202020
505050
252525
160160160
Number of reservoirs developedProbability of less than normal refit
opercent
333
101111
226
111414
49
18
799
374861
1-25percent
135
225
41213
323
311
5
2——
153031
26-50percent
223
—3
—
64
—
—1
—
424
———
1212
7
51-75percent
—
12
222
311
1——
426
—33
109
14
76-99percent
43
—
4——
412
2—2
774
—46
211514
\Total
percent
101213
181818
192022
171719
223137
91618
95114127
*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 (theleasing activity, increased attention has been cash bonus). This bid amount is not refundable iffocused on alternative leasing systems. The recoverable resources are not found and,United States currently uses, almost exclusively, a therefore, has no impact on subsequent develop-cash bonus leasing procedure in which the win- ment and production decisions (including the usening bidder for an OCS lease is the firm which of EOR technology). In addition to the cashoffers the Government the highest front-end pay- bonus, a royalty on gross production value ofa
80 . Ch. IV—impacts of Price and Tax Policies on Oil Recove
16.67 percent is paid to the Government by theproducer. The previous analysis of policy optionsassumed this leasing method was in use foroffshore C02 cases.
However, because of the substantial uncertain-ty that exists in offshore development and thecapital requirements of cash bonus bidding, alter-native systems have been proposed that wouldshift some of the risk to the Government, reducecapital requirements, and encourage competi-tion.9 As a result, Government revenue could in-crease with little or no loss in production. Suchalternative leasing systems make greater use ofcontingency payments (which produce Govern-ment revenues based on the value of production)and usually employ a higher royalty rate or aprofit-share technique. The cash bonus is re-tained as the bid variable to alleviate problems ofspeculation. The higher contingency payments,however, act to reduce the magnitude and im-portance of the bonus.
r y
profit share and higher royalty rate systemsdescribed above with the current system. Table33 details the results of this analysis. It is clearthat high fixed royalties will inhibit EOR develop-ment by increasing the risk of less-than-normalprofits and by making some fields uneconomicalfor EOR development. These results confirmearlier studies on the impact of high royalties forprimary and secondary production.10 However,the profit-share system also has a tendency to in-crease the risk of a less-than-normal profit. Thisresult is at variance with previous results on pri-mary and secondary production and indicatesthat a profit-share rate of so percent is too highfor EOR development on marginal fields. One op-tion in both situations would be the use of avariable-rate royalty or profit-share approach, sothat rates would be reduced automatically formarginal fields and increased in situations ofhigher productivity. If experiments with newleasing systems are contemplated, the effects ofleasing systems on EOR production as well as pri-
The viability of EOR under the alternative leas- mary and secondary production should be evalu-ing systems was evaluated by comparing the ated.
Administrative Issues
All of the policy options analyzed in this sec-tion would provide special incentives for produc-tion of oil using enhanced recovery techniques.The implementation of any such incentives willrequire administrative decisions concerning thequalification of particular projects or types ofprojects for the incentives. Those policies involv-ing special price incentives will also require afurther judgment about what portion of the oilproduced from a field can be attributed to theEOR process, and what part would have beenproduced anyway by the continuation of primaryand secondary techniques. The problem is todefine this EOR increment in such a way thatspecial incentives will encourage the applicationof EOR processes without significantly distortingdecisions concerning primary and secondary pro-duction.
9Robert j. Kalter and Wallace E. Tyner, An Analysis of
Selected OCS Leasing Options. Report to the Office ofTechnology Assessment, U.S. Congress, June 1975.
These problems will have to be dealt with ifproposed price incentive policies are to beadopted. In 1976, Congress amended theEmergency Petroleum Allocation Act (throughprovisions in the Energy Conservation and Pro-duction Act) to direct the President to modify oilpricing regulations to provide additional price in-centives for bona fide EOR techniques. Sincethen, FEA has published proposed regulations forcomment and has held several public hearings onthe subject. The basic approach proposed by FEAis to apply price incentives only to the incrementof production attributable to an EOR process.The same approach is implied in the president’sApril 1977 National Energy Plan, which called fordecontrol of the price of oil produced with EORtechniques.
IORobert j. Kalter, Wa l lace E . Tyner, and Dan ie l W.Hughes, Alternative Energy Leasing Strategies and Schedulesfor the Outer Continental Shelf, Department of AgriculturalEconomics Research Paper 75-33, Cornell University, 1975.
Ch. IV—impacts of Price and Tax PolIcIes on Oil Recovery . 81
Decisions concerning the qualification of proc-esses and production levels for special incentivesinvolve highly technical judgments which will re-quire personnel competent in EOR techniques.Such personnel do not at present exist in Govern-ment in the numbers required. The number ofpeople available in the job market is quite limitedand industry demand is large. While consultantsmight be used, this practice could raise potentialconflict of interest problems, because consult-ants must, in the long run, depend upon industryfor their support. An alternative approach, sup-ported by industry in comments on FEA pro-posals, would be simply to apply price incentivesto all oil produced from a field to which an EORprocess was applied. While this would avoid theproblem of defining an EOR increment, therewould remain the problem of defining the levelof effort required for a project to qualify as abona fide EOR process, and monitoring to ensurethat that effort is in fact maintained.
A more detailed analysis of the advantagesand disadvantages of these and other incentivepricing options was beyond the scope of OTA’sassessment of the potential contribution of EORprocesses to national reserves. Because of the im-portance and complexity of the associated issues,however, Congress may wish to examine theproblem of defining and monitoring EOR opera-tions, and possibly hold oversight hearings on theproposed FEA pricing regulations for EOR produc-tion. If defining EOR incremental oil productionand monitoring EOR operations are found to becritical issues, a mechanism could be developedwhereby bona fide EOR projects could be cer-tified and monitored. Certification and monitor-ing of EOR operations could be performed by theoperator, a State regulatory group, a Federalagency, or a combination of Federal, State, andproducer interests.
Table 33Monte Carlo Simulation of OCS Leasing Systems and EOR Potential
Probability of less-than-normal profitEOR process
and OCS leasing system Sample o 1-25 26-50 51-75 76-99 Totalsize percent percent percent percent percent percent
Number of fields developed
C O2- O f f s h o r eCurrent. . . . . . . . . . . . . . . 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- O f f s h o r eCurrent. . . . . . . . . . . . . . . 25 21 4 — — — 2540-percent royalty . . . . . 25 3 6 4 1 9 2350-percent profit share . 25 13 8 4 — — 25
,.. +
V. Legal Aspectsof Enhanced Oil Recovery
V. Legal Aspectsof Enhanced Oil Recovery
Method of
This chapter of OTA’s assessment of enhancedoil recovery (EOR) examines legal impacts onEOR processes arising from Federal and Statestatutes, regulations, and other laws. It seeks toidentify existing and potential constraints on theemployment of EOR techniques to obtain addi-tional oil beyond primary and secondary produc-tion.
Federal and State laws and regulations werecollected and studied in detail; the legalliterature relating to enhanced recovery intreatises and law reviews were reviewed; and therecent studies for, or by, the Energy Research andDevelopment Administration (ERDA), the FederalEnergy Adminis t rat ion (FEA), the Nat ionalPetroleum Council (NPC), the Environmental Pro-tection Agency (EPA), the Gulf Universit iesResearch Consortium (GURC), and the Interstate
Legal Issues
The law affects enhanced recovery ofoperations in many ways. Based uponresponses to questionnaires, price controls
Approach
Oil Compact Commission-together with othertechnical literature—were examined. With thecooperation of the Interstate Oil Compact Com-mission, questionnaires regarding EOR regulationand associated problems were sent to 18 largeproducing companies, about 240 smaller pro-ducers, 34 State regulatory commissions, and toappropriate officials in the Department of the in-terior. Responses were received from 15 of thelarge producers, 67 of the smaller producers, and32 of the State commissions. In addition, callswere made to or personal discussions were heldwith selected individuals with knowledge in thefield of enhanced recovery. Information from allof these sources was used in completing this seg-ment of the EOR assessment. A more detaileddiscussion of legal aspects of EOR activity is pre-sented in appendix C of this report.
in EOR Development
oiltheon
crude oil constitute the most significant legalconstraint to enhanced recovery operations. Ap-proximately 65 percent of all producers respond-ing to the questionnaire indicated that removal ofpr ice controls would make more projectseconomically feasible or more attractive.
A second important problem area forenhanced recovery appears to be the establish-ment of operating units. In order to be able totreat a reservoir without regard to property lines,it is necessary that a single party have controlover the entire reservoir or that the various par-ties who own interests in the reservoir integratetheir interests either voluntarily or through a re-
quirement by the State. Integration of these in-terests is referred to as unitization, and problemswith unitization were cited by producers with thesecond greatest frequency after price controls asan EOR constraint. The difficulties surroundingunitization can be better explained by providinga brief background on the basic principles of oiland gas law. It should be noted that mostproblems associated with enhanced recoverymethods apply to waterf looding as wel l .Therefore, problems with unitization agreementsand possible contamination of ground water arenot unique to enhanced oil recovery.
The right to develop subsurface minerals in theUnited States originally coincides with theownership 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 interestsmay be created, including mineral and royalty in-terests on all or part of a tract, undivided frac-tions of such interests, and leasehold interests.The owner of the minerals normally does thisbecause he is unable to undertake the develop-ment of the minerals himself because of the greatexpense and risk of development operations. Toobtain development without entirely giving uphis interest he will lease to another party the rightto explore for and produce the minerals. Thelessee will pay a sum of money for the lease andwill promise to drill or make other payments, andif there is petroleum to pay the value of a por-tion of the production to the lessor. Should cer-tain of the terms of the lease not be met, thelease will terminate and the interest will revert tothe lessor.
In the lease transaction the lessee has both ex-press and implied rights and duties. These oftenhave a significant impact on enhanced recoveryactivities. Among these rights of the lessee is theright to use such methods and so much of thesurface as may be reasonably necessary to effec-tuate the purposes of the lease, having dueregard for the rights of the owner of the surfaceestate. This would generally include the right toundertake enhanced recovery operations. Someauthorities have asserted that there is a duty for alessee to undertake enhanced recovery. Ingeneral, the lessee has a duty to develop thelease as a prudent operator and to do nothing toharm the interest of the lessor. Without the ex-press consent of the lessor, the lessee does nothave the right or the power to unitize the interestof the lessor.
In order to undertake fieldwide recoveryoperations (waterflood or EOR), it is generallynecessary to secure the consent of all or most ofthe various interest owners in the field through aunitization agreement. It may take many monthsor even years for the parties to reach such agree-ment. The principal difficulty lies in determiningthe shares of risk and/or production from theoperations. The producing State governmentsallow voluntary unitization and provide the par-ties an exemption from possible application ofthe antitrust laws. Most producing States alsoprovide for compulsory joinder of interest
owners in the unit once a certain percentage ofinterest owners have agreed to unitization. Thispercentage ranges from a low of 50 percent to ahigh of 85 percent as shown in table 34. In theabsence of such legislation, or where the neces-sary percentage of voluntary participation cannotbe achieved, the undertaking of enhanced recov-ery operations can result in substantial liabilityfor the operator due to possible damage to con-joiners.
Once agreement for unit operations has beenreached, it is necessary for the operator or otherparties to go before a State commission for ap-proval of the unit. The commission will requirethe submission of a detailed application describ-ing the unit and its operations, the furnishing ofnotice of the application to other parties whomight have an ‘interest in the unit operation, theopportunity for hearing on the application, andthe entry of an order establishing the unit whenthe other steps have been completed. Theproblems w i th un i t i za t ion a r i se f rom thedifficulties in securing the voluntary agreement ofdifferent interest owners, and generally not fromthe State regulatory procedures.
Prior to undertaking injection programs forenhancing production of oil, each State requiresthe operator to secure a permit for the operation.The procedure for this is similar to the procedurefor approval of unitization and sometimes maybe accomplished in the same proceedings. Thereis little indication that these regulatory activitiessignificantly restrict or hinder enhanced recoveryof oil with the possible exception of one or twojurisdictions. The procedures could well changeunder regulations promulgated by the Environ-mental Protection Agency pursuant to the SafeDrinking Water Act. Producers and others haveindicated that such Federal regulations couldhave an important adverse impact on enhancedrecovery.
Once enhanced recovery projects have com-menced, a variety of legal problems can arise.Operators in some States will face the prospectof liability to parties who refuse to join a unitwhen enhanced project operations reduce theproduction of such non joiners. There is also theprospect 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
suchtions for environmental offenses. Operators- may as these can interfere with the operation ofhave difficulty in acquiring adequate water sup- enhanced recovery projects or even prevent theirplies for EOR projects or be subject to a cutting being started.off of suppl ies owing to the water r ights
Table 34Comparative Chart of Aspects of Unitization Statutes
State
Percent working orroyalty int. req’d. (vol.
= voluntary only)
Alabama . . . . ...Alaska . . .Arizona . .Arkansas . . .Cdllfornia Subdence.
C a l i f o r n i a T o w n s i t e *Colorado . . . . . . . . . . .Florida . . . . . . . . . . . . .Georgia . . . . . . . . . . . . .Idaho ... , . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . .Indiana ., . . . . . . . . .Kansas . . . . . . . . . . . . . . .Kentucky. . . . . . . . . . .Louisiana Subsection B.Louisiana Subsection CMaine . . . . . . . . . . . . .Michigan. . . . . . . . . . . .Mississippi . . . . . . . . . . .Missouri . . . . . . . . . .Montana . . . . . . . . . . . .Nebraska. . . . . . . .Nevada..,......,., .New Mexico . . . . . . ., . .New York . . . . . . . . . . .North Dakota . . . . . . . . .Ohio . . . . . . . . . . . . . . . .Oklahoma. . . . . . . . . . . .Oregon . . . . . . . . . . . . . .South Dakota . . . . . . . . .Tennessee . . . . . . . . . . .Texas. . . . . . . . . . . . . . . .Utah. . . . . . . . . . . . . . . . .Washington . . . . . . . . . .West Virginia . . . . . . . . .Wyoming . . . . . . . . . . . .
7562.5637565758075
Nonevol.75
None7575
None75
85-W - 65-R7585758075
62.5756 080656.3757550
vol.80
None7580
Proof or findings required Water rightsdoctrine
Unit area R-riparianAdd. cost Part or All of
Inc. ult. Prevent Protect corr. not over - Single orPA-prior
recovery waste rights add. recov. Mu l t ip ,appropriate ion
D-dual-pools system
Yes Yes YesYes Yes YesYes Yes YesYes Yes YesNo No YesYes — YesYes — YesYes Yes Yes. — —— Yes or YesYes Yes Yes
Yes or YesYes Yes YesYes Yes Yes
YesYes Yes YesYes — —
Yes Yes YesYes Yes YesYes Yes YesYes — YesYes Yes YesYes Yes YesYes Yes YesYes — YesYes Yes YesYes — YesYes Yes YesYes Yes YesYes Yes Yes
— Yes Yes— Yes YesYes Yes YesYes Yes YesYes Yes Yes
YesYesYesYesYesYesYesYes——
YesYesYesYeS
YesYesYesYesYesYesYesYesYesYesYesYesYesYesYes
YesYesYesYesYes
PAMPASPASPASPAMAS
PAMPAMPASPAMPAMPASPASPAMPASA M
PAMPAMPAMPASPAMPAMPASPASPASPAMPASPASPAMPAM
PAMPASAMAS
PAM
RPAPARDD
PARR
PARRDRRRRRDR
PAD
PAPARDRDDDRD
PADR
PA
“See appwrdlx CAdapted 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 producersas a constraint to EOR activities was Federal pricecontrols. A large majority of both independentand large producers felt that price controls wereinhibiting EOR projects. For example, oneOklahoma independent stated: “We see nopoint in ‘enhancing’ anything until it reaches thestripper qualification [exempt from price con-trols]. This makes no engineering sense, but thisis what has been forced upon us by a myriad ofpolitical decisions.” Although price options aretaken up in another segment of the EOR assess-ment, the price constraint is mentioned in orderto place the other factors identified in perspec-tive. However, it should be noted that differingtreatment of interest owners producing from thesame reservoir does act to discourage unitization.Because of current price regulations (upper- andlower-tier prices), producers in the same unit maynot receive the same price for their oil. To avoidthis, it is suggested that whatever price, taxation,or subsidy determinations are made should notplace an interest owner in a worse position thanbefore unit operations were undertaken, andshould operate in such a way that each interestowner will receive the same benefits that othersimilarly situated interest owners in the fieldreceive.
The second most important area now causingproblems for enhanced recovery operations is thedifficulty in joinder of parties for fieldwide opera-tions. Owners of relatively small interests in areservoir in many States can effectively preventthe majority from undertaking enhanced recoveryoperations. The problem appears to be greatestin Texas, which has no compulsory unitizationstatute. In other major producing States whichhave compulsory unitization statutes, the percen-tage of voluntary participation required may beso high as to make unitization of some reservoirsdifficult or impossible. To overcome theseproblems, the Federal Government could recom-mend that each State adopt a compulsoryunitization statute requiring that 60 percent ofthe working interest and royalty owners consentto unitized operations before the remaining’ in-terest owners would be compelled to participate.This could be easily incorporated in existingunitization legislation in each State.
Alternatively, the Federal Government couldrequire that States adopt such features in theirunitization statutes before the States can qualifyfor administrative support or to avoid having aFederal agency take responsibility for unitizationand enhanced recovery regulation,
While it is likely that this would be a constitu-tional exercise of Federal authority under thecommerce clause, such a major step probablywould encounter considerable opposition at theState level. In any case, the desirability of strongregulations to encourage unitization would de-pend on a more detailed reservoir-by-reservoiranalysis of the extent to which unitizationproblems are in fact an obstacle to a significantamount of potential EOR activity.
The Federal Government could also recom-mend to the States that they, by statute, exemptproducers from liability for any damages causedby State-approved enhanced recovery operationsnot involving negligence on the part of the pro-ducer. This would remove a constraint to theoperations and would act as an incentive to unit-ize for parties who might otherwise remain out ofthe unit.
As to regulatory requirements and practices,there were only two important areas of concernfor producers: environmental requirements inCalifornia and the potential impact of the regula-tions issued by EPA under the Safe DrinkingWater Act. Congress might consider reviewingthe effects of various environmental laws andregulations on the production of petroleum. Con-gress might also consider reviewing EPA’sauthority and actions under the Safe DrinkingWater Act to see if the proposed regulationswould unduly restrict enhanced recovery proj-ects. producers did not complain of State EORpractices and a number indicated that State com-missions are most helpful. With respect toFederal lands, several producers indicated thatthe Bureau of Indian Affairs and the U.S. Geologi-cal Survey had delayed the initiation of projectsfor long periods of time. Congress might considerdirecting the Department of the Interior to surveyFederal lands for their EOR potential and toreview its policies on EOR.
VI. Environmental Issues
VI. Environmental Issues
Physiographic Regions
For the purpose of this assessment, the conti-nental United States was divided into fourgeneral types of physiographic regions, each ofwhich has certain specific characteristics andvulnerabilities to environmental damage. Thefour physiographic regions are: 1 ) the ContinentalShelf which includes the broad, shallow gulfcoast shelf, the steeper sloping Atlantic shelf, andthe narrow steep-edged pacific coast shelf; 2) theCoastal Plains adjoining the Pacific Ocean, Atlan-tic Ocean, and the Gulf of Mexico, particularlythose of California, Texas, and Louisiana; 3) theInterior Basins, such as the Great Plains, GreatLakes, and the central valley of California; and 4)the Rocky Mountains and other mountainousregions.
Continental Shelf
The Continental Shelf, a shallow, flat, sub-merged land area at the margin of the continent,s lopes gent l y downward away f rom theshoreline. The width of the shelf ranges from lessthan 5 miles along portions of the southernCalifornia coastline, to a few hundred miles alongparts of the gulf coast. The topography of a shelfis highly dependent on its location; the AtlanticContinental Shelf is relatively flat and shallowcompared to the deeper southern California bor-derland which has a series of parallel steep-walled ridges and subsea canyons.
Hazards common to all Continental Shelf oilrecovery operations include tidal action, waveaction, storm waves, and collisions with ships. Inaddition, hurricanes in the gulf and Atlanticcoasts, landslides and earthquakes in thesouthern California borderland, difficulty of con-trol, and unstable bottom substrate pose furtherhazards.
Coastal Plains
The Coastal Plains along the Atlantic and gulfcoasts are as much as 100 to 200 miles wide, and
make up nearly 10 percent of the land in the con-tiguous 48 states. With minor exceptions, thevariance in elevation is less than 500 feet and formore than half of the Coastal Plains is less than100 feet. This low topographic relief results in ex-tensive marshy areas. Coastal marshes, estuaries,and near-shore waters are all considered part ofthe Coastal plains area. In contrast, the coastalplain in California is narrow, limited by thecoastal mountains, and has a poorly developedmarsh system.1
The geologic formations are quite young,usually Cretaceus, Tertiary, and Quaternary inage. These sedimentary deposits representvarious onshore, nearshore, and offshore environ-mental depositions. The formations generally dipgently seaward and outcrop in belts roughlyparallel to the inner and outer edges of theCoastal Plains.2
Although many coastal wetlands have beendesignated as wildlife refuges and recreationareas, large parts of the Nation’s Coastal Plainsare covered by major population centers. In thearid Southwest, Coastal Plain inhabitants relyheavily on local ground water supplies. The U.S.Coastal Plains which have the potential for thegreatest EOR activity are those of southernCalifornia, Louisiana, and Texas.3
Interior Basins
The Interior Basins include all land areas of theUnited States except the mountainous areas andthe Coastal Plains. Within the interior drainagebasins, there are geologic basins which may con-tain large quantities of oil entrapped beneath thesurface. Generally; the geologic formations areolder 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, Nat ional petroleum COUIIC il,
December 1976.
91
92 . Ch. VI-Environmental Issues
Some EOR activity is expected to take place inthe Interior Basins, particularly those of the mid-continent and central California. Typically, theurban centers and farm areas of these basins de-pend heavily on local ground water supplies. Theground water aquifers of these basins arerecharged by local rivers and by runoff from bor-dering mountains.
Mountain Ranges
The mountainous areas are rich in timber andminerals. Some EOR operations are anticipated in
the Rocky Mountains, particularly in Wyoming.These mountain areas offer diverse benefits tosociety since they are prime wildlife and recrea-tional areas; with their relatively high snowpack,they are frequently a major source of groundwater for adjacent plains. These generally areremote unpopulated areas, where direct EOR im-pacts on the human population are limited butwhere adverse impacts on the natural environ-ment can be significant.
Causes of Environmental Effects
The following elements and processes arecommon to all EOR methods: a recovery fluid; aninjection system; surface processing; and dis-posal of spent materials.
The processes and the materials used withinthe confines of the system pose no environmen-tal threat. Environmental problems result onlywhen the materials are allowed to escape. Thefollowing mechanics may be responsible for suchescape:
1)
2)
3)
4)
5)
Transit Spil ls—Spills which may occurwhen material is being prepared at ortransported to the field site.
Onsite Spills—Spills which may occur atthe field site from surface lines and/orstorage facilities.
Well System Failure--Escape of materialswhich may occur from failure of the injec-tion or producing well due to casing leaksor channeling.
Reservoir Migration--Fluid may migrateoutside of the confining limits of a reser-voir through fractures or through a wellbore which interconnects reservoirs.
Operat ions —The e f fect s caused byroutine activities and by the supportfacilities and activities associated withEOR production. To determine environ-mental problems during operations, theeffect of each of the following must be
considered: disposal of spent material;consumption of site-associated naturalresources; discharge emissions; fugitiveemissions; and off site supply and supportefforts.
A simple matrix model was developed to com-pare the relative significance of environmentalimpacts from spills, well failure, reservoir leaks,and operations from thermal, miscible, andchemical EOR methods in each of the fourphysiographic regions. The matrix reflects a sub-jective assessment and relative ranking of the sig-nificance of potential impacts from negligible ornonexistent (1), to potentially significant (4). Thevalues assigned on table 35 are comparable onlywhen applied to a specific EOR process and en-vironmental component such as thermal and air.
Table 35 relates to potential hazards from eachEOR project by physiographic area. To suggestpossible total impact of each EOR process, table36 was developed. This matrix attempts to pre-dict the relative degree of development of theEOR method as a function of the physiographicarea. Should time and/or experience indicatedifferent values, they could be substituted with-out invalidating the matrix presented.
By selecting the appropriate value from table36 and multiplying it by the value for the sameprocess and physiographic area on table 35, anestimate of the weighted environmental impactof any or all effects can be calculated. Table 37 is
Ch. VI-Envionmental Issues . 93
—
—
- - v . l-- .-l-n - - - -
-cm
muc.5
- - - - l- l-!-m ~ - - m
- - - - - - - - . - - r
—m
— —
—m
o5
—
94 . Ch. VI-Environmental Issues
the sum of each environmental component in aphysiographic area times the appropriate valuefrom table 36. After determining the value foreach of the physiographic areas for an EOR proc-ess, they are total led and the value transferred totable 37.
The values in table 37 suggest possible relativeenvironmental impacts. For example, chemical
Tabie 36Potential Distribution of Environmental Impacts for
Enhanced Oii Recovery
(Prediction of the Relative Degree of Development of theEOR Method as a Function of Physiographic Areas)
Physiographic Area
Continental ] Coastal I Interior IMethod Shelf Plain Basin Mountains
Thermal. . . 1 4 2 2Miscible . . 1 3 3 2Chemical. . 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 EORoperations could have environmental impacts:air, surface water, ground water, land use, seismicdisturbances and subsidence, noise, and biologi-cal and public health. While each of the fourphysiographic regions can experience environ-mental repercussions in these seven media, cer-tain types of impacts will be far more importantin some regions than in others. For example, airpollution is a concern primarily in urbanized por-tions of the Coastal Plains and in Interior Basinswhere air quality is already in violation of CleanAir Act standards.4 Similarly, land-use conflictsarise in heavily populated areas where landvalues tend to be high and multiple-potentialuses exist for a given parcel of land. Groundwater use and pollution is a grave concern inareas where ground water is a principal compo-nent of the water supply, such as in central and
i~onicoring and Air Quality Trends Re~orf, U.S. Environ-mental Protection Agency, Office of Air and Waste Manage-ment, 1976.
EOR projects may have the greatest potential forenvironmental impacts and thermal the least, orthe biota may be the most impacted and land theleast. Sweeping conclusions should be drawnwith caution, however, because individual sitesand production conditions for EOR, and thuspossible environmental impacts, vary signifi-cantly from setting to setting.
Table 37Cross Plot of Environmental Impacts for Enhanced Oil
Recovery
(This Model Cross Plots the Impact Matrix With theDistribution Model To Obtain a Relative Analysis of the
Total Process Impacts)
Environmental ComponentsMethod Air I Water I Land ! Biota ! Total
Chemical 50 112 50 117 329Total. . . . 178 258 132 272
I I I 1 I
on the Environment
coastal California. Surface water pollution is im-portant in areas with high surface runoff and atsites adjacent to surface water bodies. Noise is aconcern in both urban and open areas, althoughnatural ecosystems differ widely in their sen-sitivity to noise.
The matrix described previously attempts toidentify the physiographic regions most likely toexperience each type of environmental impact.The most likely means of generating these im-pacts are discussed below. Although some effortis made to quantify these impacts, it is not possi-ble to do so precisely with the data available.
Air Quality Impacts
While all EOR methods (thermal, miscible, andchemical) can cause air pollution, thermalmethods are most likely to generate air pollutionimpacts. Steam and hot-water flooding rely onsteam generators. These generators usually usethe fuel supply available on location (oil being
Ch. VI-Environmental Issues . 95
the most common fuel source), and emit sulfurdioxide (S02), oxides of nitrogen (NO X), hy-drocarbons, carbon monoxide (CO), carbon diox-ide (CO2, and other combustion products fromexhaust pipes, In situ combustion can releasethese same compounds as fugitive emissions andas exhaust from high volume air compressors.These types of impacts from thermal EOR ac-tivities are likely to be localized and to be signifi-cant primarily in areas that are already in viola-tion of, or are near the limits of, the Federal Am-bient Air Quality Standards. In addition, NO X
released together with hydrocarbons escapingfrom the oil production process constitute a mix-ture with the potential to generate oxidant fardownwind from the point of release. Further,nondegradation requirements may become im-portant in remote areas.
The following sections discuss the mecha-nisms by which air quality impacts are generatedand attempts to assess environmental air qualityeffects of various EOR methods in the fourphysiographic regions. The impact estimates arebased on data which are now available. As moredata become available, more meaningful pro-jections of air pollution impacts will be possible.
Air Pollution Impacts ofThermal Recovery Methods
Although some estimates of the air pollutantemissions from steam flooding projects areavailable, there are very few quantitative data.Estimates of air pollution impacts of steam flood-ing can be made if both the amount of fuel to beburned and the emissions per unit volume of thefuel burned are known. Emissions from the oilproduction, (i.e., hydrocarbons, hydrogen sulfide(H2S), and other emissions escaping from the pro-duction wells), are in addition to these exhaustgases.
Emission factors for fuel oil combustion areshown on table 38. Most thermal EOR processeswill burn fuel oil or comparable petroleum prod-ucts and will fall into the residual oil classifica-tion. The powerplant classification would applyonly to the largest boilers used in EOR. Oxides ofnitrogen (NOX) emissions from powerplants andother large sources are higher because of thehigher combustion temperatures encountered,while hydrocarbon and particulate emissions are
lower because of better combustion regulationand more efficient burner designs
Table 38Emission Factors for Fuel Oil Combustion(Pounds Emitted per 1,000 Gallons Burned)
Aldehydes, ., . . . . . . . . 1 1 2Hydrocarbons . . . . . . . . 2 3 3co. . . . . . . . . . . . . . . . . 3 4 5NO X (as NO2 . . . . . . . . 105 40-80 12SO* . . . . . . . . . . . . . . . . 157 S* 157 s“ 142 S*Particulate . . . . . . . . . . 8 23 10
s ● = Percent sulfur in oil
Steam generator emissions in pounds emittedper 1,000 barrels of oil produced can be calcu-lated from table 38 using the values given forresidual oil. The results of this calculation aregiven in table 39. Estimates in table 39 are basedon the consumption of 0.3 barrel of oil for every1.0 barrel of gross production. This level of con-sumption approximates commercial-scale steamgenerator operations in the San Joaquin Valley inCalifornia. The emission factors presented in ta-ble 39 are estimates only and do not necessarilyportray accurate emissions of in-field EOR steamgenerators. The figures in the table can be linearlyscaled to account for variations in consumption.
Recently, there has been serious considerationof use of coal as an inexpensive fuel to providesteam for thermal recovery, including use inCalifornia. Use of coal could cause somewhathigher emissions in every category.
Table 39Steam Generator Emissions
[Pollutants Emitted per 1,000 Barrels of Gross Oil Produced)
Hydrocarbons . . . . . . . . . . . . . . . . . . . . 40 IbsSO* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,OOO IbsNO,. . . . . . , . . . . . . . . . . . . . . . . . . . . . . . 800 IbsParticulate. , , , ... , , ... , ., ... , . . . . . 280 Ibs
● For crude containing 2 percent sulfur, without flue gas desulfuriza-tion.
NOTE: This table assumes that 0.3 barrel of fuel oil IS burned for ev-ery 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 Develop-ment on Los Angeles Air Quality, ” In Southern CaliforniaOuter Continental Shelf Oil Development: Analysis of Key/ssues, U. C.L.A. Environmental Science and EngineeringProgram, Los Angeles, Calif., 1976.
96 . Ch. V/—Environmental Issues
The new performance standards for fuel oilcombustion were not used in making this calcula-tion because oilfield steam generators rarely ex-ceed the 250 million British Thermal Units (Btu)per hour capacity covered by these regulations.
A probable density of steam generators, and alevel of steam generation required for a givenwell production rate, must be considered in orderto estimate the overall pollution impact of asteam flood project.
The total emission rates from a field can becalculated using data in table 39. The resultingemission estimates can then be used in theevaluation of the impact of steam flood EOR onany specif ic region. As an example, theWilmington Oil Field produced 67 million barrelsof crude oil in 19736 by primary production; thefield may eventually be a candidate for EOR.Steam flooding may be applicable due to the lowAmerican Petroleum Institute (API) gravity (highdensity) and high viscosity of California crude,and the considerable thickness of the oil-bearingstratum. The production of 30 million barrels peryear by steam flooding (a potential for theWilmington field) would involve the combustionof some 9 million barrels per year of fuel in thefield steam generators. With the emission factorsdeveloped above, this combustion rate corre-sponds to the air pollutant emissions rate given intable 40.
Table 40Projected Emissions from Steam Flooding of a MajorOil Field Compared to Los Angeles County Emissions
I Emissions from a 3 0 I Los AngelesPollutant million bbl/year field County Total
NO X . . . . . . . . 32 tons/day 1,000 tons/dayParticulate . . 12 tons/day 120 tons/dayso 2 . . . . . . . . . 81 tons/day* 300 tons/dayHydrocarbons. 2 tons/day 1,000 tons/day
*An 011 sulfur content of 2 percent was assumed
Table 40 also shows the total current emis-sions for Los Angeles County. Enhanced oilrecovery emissions calculated for this example,with the exceptions of hydrocarbons and oxidesof 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, Extensiveexhaust gas scrubbing, consumption of low-sulfurfuel oil, and reduced scale of operation would benecessary in order to reduce S02 emissions to ac-ceptable levels. Although these processes couldreduce the emissions to lower levels, the result-ant emissions will still be significant, at least on alocal scale, since they are released into a heavilypolluted airshed. Furthermore, they are releasedfrom a relatively small source area by comparisonwith the entire county, and could produce sub-stantial impacts along a downward trajectoryover a heavily populated region.
Emissions from in situ combustion are highlydependent on the oil formation, the type ofcrude oil, and the manner in which the project isoperated. The high density of the crude oil inCalifornia and low economic returns experiencedthus far indicate a low potential for in situ com-bustion, even though most oilfields in Californiacan be spontaneously ignited by unheated air in-jections alone. To date, there are very few dataavailable regarding the emissions from in situcombustion projects. It is anticipated that inorder to meet air-quality pollution-control stand-ards, especially in some areas of southern Califor-nia, gas collection and treatment systems will berequired,
In situ combustion and steam flooding are ex-pected to have the greatest air-quality impacts inregions of low inversions, low wind speeds, andalready polluted air, such as California’s coastalplains and central valley. In remote mountainousregions, if background air quality is generallygood and meteorological dispersion is favorable,a smaller impact may be expected. It should benoted, however, that high mountain valleys oftenexperience severe inversions and air stagnation.Furthermore, nondegradation standards may ap-ply for mountainous recreational areas. Thus airpollution impacts cannot be disregarded for suchareas. While light air-pollution emission over theContinental Shelf would normally be consideredinconsequential, there are areas in which theseemissions must be carefully controlled, as in thesouthern California borderland. Any emissionsreleased there have a high probability of beingtransported to shore, where they will contribute
Ch. V/—Environmental Issues ● 97
to an already serious air pollution problem.7 Dueto the low thermal and mechanical turbulence ofair over water, dispersion of air pollutants overwater is much slower than over land.8 The Atlan-tic coast is just the reverse of the California situa-tion in that the prevailing winds are from thewest, so that emissions generated along the coastusually would be transported out over the Atlan-tic Ocean. The gulf coast tends to be a combina-tion of the Atlantic and Pacific coast situations;depending upon the time of the year, the prevail-ing wind direction can be either from the north orthe south.
Air Pollution Impact ofMiscible Flooding Recovery Methods
Because miscible flooding does not involvehigh rates of either fuel combustion or in situcombustion, it is probable that C02 injection willhave a much smaller air-quality impact than willthe thermal methods discussed earlier. However,if hydrogen sulfide (H2S) is injected into a reser-voir and subsequently escapes, poisoning ofhumans and wildlife could result. There havebeen instances of this in the past. However, it isvery unlikely that H2S will be used as a primaryconstituent in any future major gas injection proj-ects. Carbon dioxide is nontoxic, but capable ofcausing suffocation if concentrations are highenough. It will most likely be obtained from in-dustrial activities (coal gasification), or naturalreservoirs. The main air pollution impact resultingfrom C02 recovery methods will be the releaseof hydrocarbons and H2S from formations intowhich C02 is injected. An important air qualityconcern is that C02 combined with H2S in a gasmixture might have inadequate buoyance to dis-perse quickly, With the reduced buoyance, H2Sremains concentrated at ground level longenough to pose a threat to human and animal lifebecause of its toxicity. Such effects are difficult
7J. A. Eldon and J. A. Hill, “Impacts of OCS Oil Develop-ment on Los Angeles Air Quality, ” In Southern CaliforniaOuter Continental Shelf Oil Development: Analysis of Key/ssues, U. C.L.A. Environmental Science and EngineeringProgram, Los Angeles, Calif., 1976.
Ep. Michael, C, S, Raynor, and R. M. Brown, “AtmosphericDispersion from an Offshore Site,” in Physical Behavior O f
Radioactive Contaminants in the Atmosphere, p. 91, interna-tional Atomic Energy Agency, Vienna, 1974.
to quantify without detailed information con-cerning concentrations of H 2S and C02 t h a twould be emitted from gas injection recoveryprojects.
Because there has been considerable concernand a large degree of misunderstanding aboutH2S and its potential safety and health threat tohumans, the environment, and to equipment,further discussion is warranted. Concern has beengenerated to a large degree from an incident thatoccured at Denver City, Tex., in 1975, whichresulted in nine fatalities. Hydrogen sulfide istoxic, flammable, explosive, corrosive, and maybe naturally present in reservoirs. The concentra-tion of H2S which constitutes a harmful quantitydepends upon the subject being considered,whether humans, the environment, or equip-ment. Therefore, regulations have been adoptedby various governmental agencies to require allstages of H2S operations to conform to safety andenvironmental standards.9 Smith, the principalauthor of Texas Rule 36 which regulates this in-jection method, states that a dangerous condi-tion would prevail if leaks of a certain volume ex-ist, weather conditions complimentary to gascloud ground accumulation exist, and personsunaware of the situation are present.10 Texas Rule36 and regulations adopted by other States havebeen formulated to prevent the above conditionsfrom occurring. Hydrogen sulfide emission can beassociated with normal oil production and is notnecessarily complicated by any of the EOR proc-esses, although the amounts encountered wouldbe amplified by increased production. Therefore,while the H2S problem exists for oil production ingeneral, excessive concern for magnified H$problems related to EOR is unwarranted.
Air Pollution Impacts ofChemical Recovery Methods
Chemical recovery methods do not produceemissions during application. Any air qualityemissions from chemical EOR methods would be
‘Enhanced Oil Recovery, National Petroleum Council,December 1976.
IOC. D. Fhrhardt, Jr., “Environmental and Safety Regula-tions In Sour Gas and Crude Operations, ” in Society ofPetroleum Engineers of AIME Paper Number SPE 5191, 1974.
98 . Ch, VI-Environmcnldl Issues
indirect, in that they would occur from the pro-duction of various chemicals and the powergeneration required in the pumping process. Inthe case of the chemicals, air pollution impactsfrom production plants are already covered byexisting air quality control regulations. Some lighthydrocarbons, ethers, or alcohols are expected tobe used in chemical recovery methods. Thesewould presumably be derived from petroleumrefineries whose air pollution emissions are ofconcern, but these may not be new emissionsarising solely from EOR. If EOR were not utilized,the same refineries would very possibly manufac-ture other petrochemical products from the sameraw materials. Therefore, the air pollution im-pacts of the chemical recovery methods “will besecondary in nature and covered by existing EPAState regulations.
Surface Water
Enhanced oil recovery methods will requiresignificant quantities of water over and aboveprimary recovery methods. It is anticipated thatthe EOR fresh water requirements would be high-er than the demand in present techniques ofwaterflooding. A review of the literature did notprovide firm data on the amount of water re-quired for EOR. In order to quantify the water re-quirement, it is assumed in this assessment thatone to six barrels of fresh water is needed foreach barrel of oil recovered, This quantity ofwater consumption would have a greater effecton the environment in most regions than anyother EOR impact.
As shown in figure 14, California, Texas, andwestern Louisiana are areas where water use ishigh and supplies short.11 In fact, severe short-ages are predicted by the year 2000. Althoughlarge quantities of water are required for EOR, theenvironmental impact on surface waters fromEOR activities is anticipated to be only slightlygreater than that from secondary recovery(waterflood) methods. The extent of hydrologicenvironmental effects will depend upon the
I lwater Information Center Publication, Water Atlas ofthe United States, Water Information Center, Inc., PortWashington, N. Y,, 1973.
characteristics and previous development of areservoir. Geographic location, reservoir depth,and condition of the wells are factors whichdetermine the potential adverse impacts of EORactivity on the hydrologic environment. The mainenvironmental impact on the surface waters willbe the actual consumptive use of the water. Insemiarid areas, water may be required which isnow being used for agriculture or other purposes.
Of the three EOR methods considered, chemi-cal methods have the greatest potential for ad-verse impacts on surface water resources becausewater consumed (fresh water) 1 ) would be equalto or greater than for miscible or thermal EORmethods used, and 2) spills of concentratedchemicals would be environmentally more detri-mental to water supplies than spills or emissionsfrom other EOR processes. The likelihood thatwell failures or reservoir leakage due to break-down of the reservoir would lead to contamina-tion of surface waters is considered to beminimal.
The environmental effects on surface water ofthermal EOR methods will be greater than thoseof miscible methods but less than those fromchemical processes. As with chemical EORmethods, fresh water consumption in routineoperations will have the greatest impact on theenvironment. Past experience has shown thatspills, well fractures, and reservoir leakage are in-frequent and basically nondetrimental duringthermal EOR operations.
Miscible EOR methods will have the smallestenvironmental effect on surface water. As withthe previous two methods, the quantities ofwater consumed in this EOR process—whichpresumably would be diverted from farming andother activities—would constitute the greatestenvironmental impact.
Surface water requirements will be largest forEOR activity in the Interior Basins, smaller in theCoastal Plains, and smallest on the ContinentalShelf where few EOR projects are expected to oc-cur.
Within the Continental Shelf area, it is antici-pated that routine operations would cause themost 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 environmentaleffects would occur other than those which are apart of routine operations.
On the Coastal Plains, consumptive water usewould frequently have the greatest environmen-tal impact from EOR production. One exceptionto this would be chemical spills which could oc-cur in this environmentally sensitive phys-iographic area. Thermal EOR methods might havea slightly greater environmental impact thanmiscible EOR methods. For regions where airquality already is poor, of course, air pollutionimpacts from thermal methods could be substan-tial.
Interior Basins would most likely be affectedby chemical EOR methods. Miscible EORmethods would have the least environmental im-pact of the three EOR methods. Almost withoutexception, the greatest environmental effect onthe Interior Basins would be water use. As withthe Coastal Plains, the Interior Basins could alsoexperience a significant environmental impactfrom chemical spills, primarily in transit to the in-jection well sites. The mountainous geographicareas might be relatively less affected eventhough they are environmentally sensitive areas.
Ground Water
potential for ground water contaminationresulting from fluid injections associated withEOR operations appears minimal. This conclusionis supported by the lack of ground water con-tamination problems associated with conven-tional waterfloods. Only 74 ground water injec-tion problems resulted from operating 44,000 in-jection. wells in Texas between 1960 and 1975(an incidence rate of 1.1/10,000 per year); only 3of these occurred during the last decade (an inci-dence rate of .02/10,000 per year). Similar safeoperating records exist in the other major oil-pro-ducing States with large numbers of waterfloods.Because EOR injection operations are basicallythe same as waterfloods, often using the same in-jection wells in the same formations, an increasein the rate of ground water contamination is notexpected. In fact, it is anticipated that the safetyrecord will improve because EOR injection fluidsare more costly than the water now used in
waterfloods and operators could be expected totake additional precautions to prevent loss ofthese fluids during the EOR process.
As with surface waters, use of water fromaquifers for EOR operations could put a strain onfreshwater supplies in areas where reserves werelimited. In areas where the rate of consumptionexceeds the rate of recharge, the impacts wouldbe severe. Recent field tests indicate that brine-tolerant EOR processes are feasible, and couldsignificantly reduce the impact of EOR operationson freshwater aquifers if used.
Land Use
The impact of EOR operations on land use willnot be significant. Additional surface facilities re-quired for EOR activities will be relatively small,even for large projects. Relatively few additionalflow lines and pipelines will be needed outsideof the reservoir area, except in the case of C02
injections. Where large quantities of C02 are re-quired, pipelines will be required to delivereconomically the C02 to the project sites. Con-struction of these pipelines poses potential en-vironmental hazards.
For some EOR projects additional wells will bedrilled, and redrilling of wells will occur in olderfields. These activities will cause minor distur-bances for short periods but no long-term im-pacts will be evident, provided care is taken inthe field development.
Geologic Hazards
Potential geologic hazards connected withEOR methods are subsidence and possibleseismic activity. A great deal of subsidence dataassociated with primary oil recovery have beencollected in the Long Beach, Calif., area.12 Whencompared with primary recovery methods, it isanticipated that subsidence actually will bereduced during EOR operations. The reason forthis reduction is that fluids will be left in the
IZM. N. Mayuga, and D. R . A l l e n , “Long Beach Subsid-
ence,” Focus on Environmental Geology, R. W, Pank, Ox-ford University Press, New York, N. Y., p. 347, 1973.
reservoir after the oil is removed, except when insitu thermal methods are used.
There has been some research relating seismicactivity to the use of secondary recoverymethods. Results of this research imply thatseismic activity will not be increased by EORmethods. The Rocky Mountain Arsenal nearDenver, Colo., conducted deep well injectionswhich resulted in an increase in seismic activityin the Denver A rea13 I t should be noted,however, that these injections were generallymade into deep crystalline rock which did not or-dinarily contain fluids. Injected fluid acted as alubricant to the existing stress zone which isbelieved to have caused the increased seismicactivity. Obviously, oil recovery from reservoirswould not be considered analogous to the RockyMountain Arsenal situation.
Noise
Although the compressors and other equip-ment used in EOR generate high levels of noise, itis unlikely that this noise will cause any seriousenvironmental impact. The loudest noises, suchas those which would accompany preparation forthe fracturing of the reservoir or injection ofsteam in a cyclic steam process, are of short dura-tion. In regions where the local biota or humanpopulation would be adversely affected by noise,maximum muffling and noise abatement pro-cedures will need to be imposed. OccupationalSafety and Health Act (OSHA) regulations willserve as a standard for safeguarding humans.14
Biota
Enhanced oil recovery technologies present avariety of potential biological effects. These aresummarized according to relative significance intable 35, and most do not appear very serious.While some do pose potentially significant
“’’Geophysical and Geological Studies of the Relation-ships between the Denver Earthquakes and the RockyMountain ARsenal Well-Part A,” Quarterly of the ColoradoSchool of Mines, Vol. 63, No. 1, 1968.
14A. p. G. peters~n and E, E. Cross, Jr. Handbook Of NO;5eMeasurement, General Radio Corp, 7th Ed., 1974.
Ch. Vi–-Environmental Issues . 101
problems, most can be adequately addressed andavoided.
Many areas where EOR activities would takeplace have already undergone primary and sec-ondary development, and environmental impactswil l therefore not result from EOR activitiesalone. Some of the potential impacts are com-mon-to all processes, while others are the resultof or dependent upon a particular process. Table41 identifies the activities that might be expectedto create biological impacts.
Table 41Potential Biological Impacts Resulting From EOR
Process - Independent ImpactsConsumption of waterNew well drilling (land-use/habitat impacts)Extended time frame of activitiesPipeline to provide waterIncreased refinery effluents
Process - Dependent ImpactsThermal: Air emissions
Cooling and consumptive water useEnergy source
Miscible: Air emissionsPipeline and source of CO2
pH changesChemical: Manufacturing, handling, and disposal of
chemicals
Process Independent Impacts
Probably the most significant potential adversebiological impact of EOR will result from the in-creased water consumption associated with thistechnology. Because fresh water (rather thansaline water) is generally required, EOR processconsumption of water will not only competedirectly with domestic, agricultural, and other in-dustrial uses, but could result in a localizeddrawdown of surface water, severely affectingaquatic flora and fauna within the area of thedrawdown.
The Interior Basin and Mountain regions maybe the most seriously affected by this consumpt-ive use of water. Interior Basin areas already facesome of the most serious water allocationproblems, and wetland or aquatic ecosystemshave already been substantially affected in many
parts of this zone. While they have not ex-perienced the same demands for water use,Mountain wetland areas are comparatively more
102 . Ch. V/-Environmental Issues
fragile and vulnerable to drawdown. Also, con-sumptive use of water in the Coastal Plains couldincrease salt water intrusion, and significantlyalter coastal wetland communities.
Potentially serious impacts may also resultfrom new well drilling activity. Because EORtechniques will always be applied in areas of pre-vious drilling activity, support facilities and ac-cess roads will generally be available. However,depending on the density of facilities needed forEOR, new construction may be significant. In thepast, significant impacts have resulted from welldrilling activities in wetland and aquatic areas,particularly in the Coastal Plains and mountainareas. These impacts have generally resulted fromloss of habitat associated with a well drilling site,or from alterations (such as canals, ditches, androads) to provide access. Canals used as accessfor drilling operations in coastal areas havecaused significant adverse effects on shallowaquatic habitat and on marsh wetlands. Theseimpacts have largely been caused by alteration ofthe hydroperiod and the fresh water—salt waterinterface. The changed salinity regimes whichhave resulted have caused severe alteration ofwetland types as well as the fauna inhabitingthem. The activities associated with constructionof access to sites in the Coastal Plains, par-ticularly dredging and filling, have also createdsubstantial impacts.’ 5 The resulting changes maybe permanent.
Because of the fragile nature of mountainecosystems and the long times they frequentlyneed to recover from impacts, road constructionin Mountain regions also poses a threat of signifi-cant impact.
“These impacts are not a necessary conse-quence of new well drilling activity. Althoughpotentially significant, most can be avoided by athorough initial understanding of the systemwhich may be disturbed, followed by carefulconstruction and drilling practices. Because EORactivity occurs in areas of previous activity,economics dictate that maximum usage will
I $[dward T. LaRoe, Effects oi Dredging, F1//ing, and Chan-nellzatfon on Estuarine Resources, pp. 134-1 44; “Proceed-ings, Fish and Wildlife Values of the Estuarine Habitat, ASeminar for the Petroleum Industry, ” p. 184, U.S. Depart-ment 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 willgenerally extend the time during which produc-tion activities take place by 10 to 20 years. Thiswill result in continued traffic, noise, dust and airemissions, and other actions of potential impacton biota. These will not usually be important,since the areas will already have been subject toprimary recovery activity and because the re-maining biota often will have adapted to man’sroutine activities after an initial period of dis-placement or disturbance. Some exceptions in-clude activities adjacent to or otherwise affectingbreeding and nesting areas or migratory routes.Some particular species (frequently endangeredspecies) are not compatible with man’s activities.Continued operations might preclude their returnor survival in localized areas, although this wouldbe an infrequent occurrence.
Because EOR processes will often require newor increased supplies of water, or water ofdifferent quality, the construction of water sup-ply pipelines could also affect the biological en-vironment. Such activity will result in direct lossof some habitat, and could affect the biota inother ways. For example, construction ofpipelines across wetlands may be accompaniedby the digging of a ditch, canal, or diked road;these would interrupt or alter the surficialsheetflow of water. Again, these impacts can bereduced through careful route selection andmethods of construction. Frequently, pipelineswill already exist to deliver water to productionfields. It may be possible to use the opportunitycreated by new construction to rectify problemscaused by existing pipelines.
Process Dependent Impacts
Each EOR process could have some specificbiological impact. It appears that some of thesewill be of less significance than the potential im-pacts previously described. All of the EOR proc-esses will result in air and water emissions, whichmust be controlled to be in compliance with theapplicable air and water quality standards.However, it is important to recognize that attain-ment of standards will not avoid all biological im-pacts.
Ch VI—Environmental lssue~ ● 103#
Therrnal.-Steam injection processes will havelarge demands for water, creating a potential forincreased impacts caused by water consumptionand the need for water pipelines.16 Steam injec-tion will also require substantial energy for steamgenerators and compressors. Existing facilities areusually powered by onsite generators fueled bypetroleum products (oil or gas) produced at thewell. These are noisy and air polluting. If EORoperations become widespread, the industrymight desire to switch to electrically powered aircompressors and other equipment. The off siteproduction and supply of electricity (very likelyfrom coal) could result in off site biological effectswhich would vary in significance with the typeand location of power generation.
The air emissions produced by both steam in-jection and in situ combustion thermal EOR tech-niques WIII pose potentially slgnificant biologicalimpacts. If uncontrolled, the impacts of theseemissions could be most severe in the Californiacoastal plain and Interior Basin areas becausethese areas not only appear the most likelyregions for use of thermal EOR techniques butalso have dirtier air than most other regions. Themost critical effects would be on humans andvegetation, although the chronic effects onwiIdlife could also be significant. Air polIutantsfrom EOR operations can probably be controlled;however, there has been little applied research inthis direction to date. It is reasonable to expectthat a serious research effort would make possi-ble considerably reduced impacts.
Thermal projects also need to dispose otheated water after it has been used for coo!ing. Ifdischarged into surface waters, hot water canlead to changes in marsh and aquatic plant andanirnaI Iife and promote the growth o fphytoplankton algae, including blue-green algae,which can harm natural flora, fish, and wildlife.The thermal impact could be avoided by the useof cooling ponds, which could create localizedair impacts of generally small consequence. Wellfailures or reservoir leakage could also result inthe 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 verylocalized and of little significance.
Thermal EOR processes frequently result inrecovery of large amounts of oil-associatedwater, which is usually reinfected.1’ However, ifthe water is not reinfected and is dischargedwithout treatment, the chronic release of thiswater, with entrained oil and traces of heavymetals, could adversely affect aquatic biota.
Thermal processes will also produce solidwaste material, including fly ash from scrubbersused to control air emissions. The most direct im-pact will be in the need for land area to disposeof solid wastes (and the loss of habitat which thatmay cause). Shipment of material to suitable siteswill cause some adverse impacts. Biological im-pacts of an efficiently designed and operatedsystem can be kept small.
Miscible.--+robably the most significant po-tential biological impacts resulting from the C02
miscible EOR process will be those relating to thesupply and transportation of C02. For EOR use,C 02 wi l l o r ig inate f rom C02 wel ls , or as abyproduct of other industrial activity. It willusually be transported to the field by pipelines,although in s m a l l p r o j e c t s C 02 m a y b e
transported by refrigerated truck or tank car.While C02 itself is not toxic, the activities associ-ated with its collection and transportation mayhave adverse biological impacts. Carbon dioxidepipelines can have the same biological impactsdiscussed for water pipelines above. The primaryareas presently identified for C02 production arethe Four Corners area, the northeast New Mex-ico-southeast Colorado area, central Mississippi,Texas, Utah, and Wyoming. These areas, andplaces along the pipeline routes to Texas, willhave the most significant potential for impact,but the impacts will be localized That is, theywill be restricted to the immediate area of C02
production and the pipeline route.
As with thermal processes, miscible processeswiII result in increased air emissions. The releaseof C02 itself would not have adverse biologicaleffects, 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 aquaticsystems, as might occur with well failures orreservoir leakage, could result in a decrease in pHof the water body. The biological significance ofthis pH change would depend on the size of thewater body, amount of C02 released, and theduration of release. However, aquatic l ife,especially freshwater fish, is particularly suscepti-ble to increased acidity. While the potential forsuch an occurrence is extremely small, the im-pact, if it occurred, could be locally significant.
Chemical.-Although several chemicals thatcould be used in EOR processes have beendescribed in literature, it appears in practice thatonly a few will actually have extensive use. Table42 lists chemicals described in patent literature.Chemicals commonly used include broadspectrum petroleum and synthetic petroleumsulfonates; alcohols ; polyacrylamide andpolysaccharide polymers; sodiumdichlorophenol and sodium pentachtorophenol;sodium hydroxide and sodium silicate.18 Thesedo not appear particularly hazardous in the con-centrations used, nor do they become concen-trated in food chains. However, the manufactur-ing, handling, and disposal of these chemicalspose potential biological impacts.
If chemical flooding methods are widelyadopted, there must be a substantial increase inthe production of some of these chemicals,especially the surfactants. Expanded manufactur-ing capacity could result in localized adverse im-
Table 42Potential 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
FormaldehydeGluteraldehydeParaformaldehydeAlkyl phosphatesAlkylaminesAcetate salts of coco diaminesAcetate salts of coco aminesAcetate salts of tallow diaminesAlkyIdlmethl ammonium chlorideCOCO dlmethyl ammonium chlorideSodium salts of phenolsSubstituted phenolsSodium hydroxideCalcium sulfate
Chemicals Proposed for Alkdline Flooding:* Sodium hydroxide* Sodium silicate
Ammonium hydroxideSodium carbonatePotassium Hydroxlde
Chemicals Proposed for Mobility Control:* Polyacrylamide* Polysaccharide
Aldoses B SeriesAldoses L SeriesCar boxy methylcelIuloseCarboxyvinyl polymerDextrdnsDeoxyribonucleic acidKetoses B SeriesKetoses L SeriesPolyethylene oxidePolyisobutylene in benzeneConjugated saccharidesDisaccharidesMonoosaccharidesTetrasaccharldes
pacts through loss of habitat and potential air and”water emissions.
Transportation of the chemicals commonlyused for EOR operations is not likely to pose amajor hazard. Many are frequently shipped as
Chemicals Proposed as Oxygen Scavengers:solids, which reduces the potential for a spill. Sodium hydrosulfiteSmall 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 thebiological impact will be limited since they areprimarily of low toxicity.
Even though tests have shown that chemicalscommon I y used i n EOR processes have a 10 wacute toxicity, the long-term effect of suchchemicals on the environment has not beenevaluated. Not until such long-term studies havebeen conducted on the chemicals used in EORprocesses can the potential for adverse environ-mental impacts be dismissed.
Disposal of produced water containing thechemicals will pose another potential water-
quality impact. Most chemicals will be absorbedwithin the reservoir and the amount producedwilI be small. Although the chemicals are not par-ticularly toxic, some (particularly the polysac-charide polymers) could act to increase biologi-cal oxygen demand (BOD) in the receiving waterand this would adversely affect fish species. Po-tential biological impact can be avoided by dis-posing of chemically Iaden produced water byeither relnjecting it into the oil-producing reser-voir, injecting it into other saline aquifers, ortreating it to remove contaminants before dis-posal 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 AMOUNTAND 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
1111131 1 3
1 1 3
11.3
1 1 8
1 2 2
1 2 9
1 3 9
1 3 91 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 Effi-ciency 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 oilrecovery (EOR) processes were determined fromthe results of reservoir-by-reservoir simulations.The accuracy of this approach depends on theextent, representativeness, and accuracy of thereservoir data file. In earlier work, Lewin andAssociates, Inc., collected detailed data on 245reservoirs in three States, California, Louisianaand Texas. The Office of Technology Assessment(OTA) contracted with Lewln and Associates,Inc., to expand this data base to include all majoroil-producing States and at least 50 percent ofthe remaining oil resources. The expanded database, referred to as the OTA data base, covers abroad range of geographic locations and reservoirtypes as well as the largest 300 domestic reser-voirs on which public data are available.
This appendix describes the development andcontent of the OTA data base. Sources of dataare documented by geographic region.
Reservoir Selection
A list of the largest oilfields (measured bycumulative production plus remaining reserves)was constructed from available data.1 The expo-nential distribution of the size of the Nation’s oil-fields—the largest 300 fields provide over two-thirds of the Nation’s production-suggests thatthe preponderance of tertiary recovery oppor-tunities lies in the major fields.
Data collection, therefore, began by focusingon the largest fields and the largest reservoirswithin these fields. Smaller fields and reservoirswere added to the file to increase the proportionof each State’s oil covered by the data base.Thus, the OTA data base contains reservoirs andfields of varying size, although the prepon-derance of the reservoirs is quite large (over 50million barrels cumulative production plus re-maining reservoirs). An analysis was conductedto ascertain whether the preponderance of largefields renders the data base unrepresentative. Nosystematic bias was introduced by the number oflarger fields.
Selection of Data Items
The data items included in the file wereestablished by the three key tasks involved inEOR analysis, namely to:
1. Screen fields and reservoirs at two levels: (a)
2
3
favorable or unfavorable to tertiary recov-ery; and (b) for the favorable reservoirs, themost preferred tertiary technique.
Calculate the oil in place and amount to berecovered through primary, secondary, andtertiary methods-based on actual reservoirparameters and production histories.
Calculate investment and operating costs ofthe preferred tertiary technique--based onregion, reservoir, and crude oil charac-teristics.
Detailed data were collected concerning for-mation and crude oil characteristics, productionhistories, and original (OOIP) and remaining oil inplace (ROIP). Figure A-1 is a copy of the formused to display data for each field and its produc-ing reservoir(s). Complete reservoir data (asshown on the form) were avaiIable for only a fewreservoirs. Although there are many data missing,complete volumetric and production data wereavailable for each reservoir in the OTA data base.
Data Collection
A three-step approach was used in collectingthe reservoir data:
1, Identification of Data Sources
National level data were available for fieldsthrough the American Petroleum Institute (API)and the U.S. Geological Survey (USGS)-sponsoredOil Information Center. However, l itt le wasavailable for reservoirs within these fields.Detailed data on reservoirs were gathered fromState agencies, State-level private organizations,and general publications. In this step, the availa-ble data sources were cataloged and evaluated as
112 ● Appendix A
2
9. -Lasn
dm&
>
a ●
‘4
**
Appendix A . 1 l.?
to their completeness and reliability. From thisevaluation, priorities were assigned to the iden-tified sources.
2. State Procedures
For each State, detailed procedures weredeveloped which described the data to be col-lected from each source, the sequence of usingthe sources, and decision rules for any estimatesor averaging necessary to complete the data col-lection forms.
3. Estimation and Calculation of MissingData Items
After’ rigorously examining and cataloging allavailable data sources, some of the data re-mained missing. When these data were critical tothe analysis, they were estimated using engineer-ing formulas and empirical correlations. All datawere edited for volumetric consistency, a re-quirement of later steps in the analysis.
Appl icat ion of th is procedure requirednumerous followup contacts with Federal andState sources to elicit additional data, to verifyinterpretations, or to procure additional sugges-tions regarding data sources.
Data Coverage
Table 6 in Chapter Ill shows the scope andcoverage of the OTA data base. The 19 States in-cluded account for 96 percent of the oil remain-ing in domestic reservoirs. The individual reser-voirs in the data base account for over half of theNation’s remaining oil, The percentage coverageof each State is also relatively high. In only onecase was the coverage less than 20 percent of theState’s residual oil. For only two States did thecoverage fail to reach 30 percent. Thirteen of the19 States had coverage of 40 percent or greater.Based on the coverage and diversity of the reser-voirs in the OTA data base, an extrapolation tothe full United States appears justified.
The States for which the coverage is lowest,especially Kansas, Oklahoma, Pennsylvania, andWest Virginia, are States which collect onlylimited information,
Fields and Reservoirs in theOTA Data Base
Field Reservoir
AlabamaCitronella . . . . . . . . . . . . . . . RodessaGilbertown . . . . . . . . . . . . . . Eutaw
AlaskaGranite Point ., ., . . . . . . . . Middle KenaiMcArthur River. . . . . . . . . . . HemlockMiddle Ground Shoal . . . . . Hemlock E,F,G PoolsPrudhoe Bay . . . . . . . . . . . . . Kuparuk River
LisburnePrudhoe Oil Pool
Swanson River . . . . . . . . . . . HemlockTrading Bay . . . . . . . . . . . . . Middle Kenai
Middle Kenai G–Hemlock,North
ArkansasMagnolia. . . . . . . . . . . . . . . . SmackoverSmackover . . . . . . . . . . . . . . OldSchuler . . . . . . . . . . . . . . . . . Jones
CaliforniaCoastalCat Canyon . . . . . . . . . . . . . Old Area Pliocene
Sisquoc Area OthersLos Flores
Dos Cuadras. . . . . . . . . . . . . Federal OffshoreElwood . . . . . . . ., . . . . . . . . VaquerosOrcutt. ... , . . . . . . . . . . . . . Monterey Point SalRincon. . . . . . . . . . . . . . . . . . Hobson-Tomson-Miley
Padre Canyon OthersOak Grove Others
San Ardo. . . . . . . . . . . . . . . . LombardiSanta Maria Valley . . . . . . . MainSouth Mountain. . . . . . . . . . Sespe MainVentura. . . . . . . . . . . . . . . . . C Block
D-5, D-6 EastVentura. . . . . . . . . . . . . . . . . D-5, D-6 North
D-7, D-8
Los AngelesBeverly Hills . . . . . . . . . . . . . East Area MioceneBrea Olinda . . . . . . . . . . . . . Olinda Area
Brea AreaCoyote East . . . . . . . . . . . . . AnaheimCoyote West . . . . . . . . . . . . Main 99 Upper West
Main 99 Upper EastDominquez. . . . . . . . . . . . . . First East (Abandoned)
First East CentralFirst West CentralEast Cooperative3 and 4 NW Central3-4-5 EastWest Unit
96-594 0- 78 - ~
— —. .-
114 . Appendix A
Field Reservoir
Huntington Beach . . . . . . . . North Area Tar BolsaSouth Area Upper Main
Inglewood. . . . . . . . . . . . . . . VickersLong Beach. . . . . . . . . . . . . . Old Area Upper PoolsMontebello, . . . . . . . . . . . . . BaldwinRichfield . . . . . . . . . . . . . . . . East and West AreaSanta Fe Springs. . . . . . . . . . Main Area OthersSeal Beach . . . . . . . . . . . . . . South Block Wasam
AlamitosNorth Block McGrath
Torrance . . . . . . . . . . . . . . . . MainWilmington . . . . . . . . . . . . . Tar
Upper TerminalRangerLower TerminalFord
San JoaquinBelridge South . . . . . . . . . . . TulareBuena Vista , . . . . . . . . . . . . Upper Hills
Front AreaCoalinga . . . . . . . . . . . . . . . . TemblorColes Levee North. . . . . . . . Richfield Main WesternCuyama South . . . . . . . . . . . Main Area HomanCymric . . . . . . . . . . . . . . . . . Tulare
CarnerosOceanic (all)
Edison , . . . . . . . . . . . . . . . . . Schist Main UpperVedder Freeman
Elk Hills. . . . . . . . . . . . . . . . . Upper MainFruitvale . . . . . . . . . . . . . . . . Chanac-Kernco MainGreeley . . . . . . . . . . . . . . . . . Rio Bravo-VedderKern Front. . . . . . . . . . . . . . . MainKern River. . . . . . . . . . . . . . . Kern River SandsKettleman Dome North. . . . TemblorLost Hills. . . . . . . . . . . . . . . . MainMcKittrick. . . . . . . . . . . . . . . Upper MainMidway-Sunset . . . . . . . . . . PotterMt. Peso . . . . . . . . . . . . . . . . VedderRio Bravo . . . . . . . . . . . . . . . Vedder-Osborne-Rio Bravo
ColoradoAdena . . . . . . . . . . . . . . . . . . J-SandAkron, East ... , . . . . . . . . . . D-SandAzure. . . . . . . . . . . . . . . . . . . D-SandBadger Creek . . . . . . . . . . . . D-SandBijou . . . . . . . . . . . . . . . . . . . D-SandBijou, West, . . . . . . . . . . . . . D-SandBlack Hollow . . . . . . . . . , . . LyonsBobcat. . . . . . . . . . . . . . . . . . D-SandBoxer. . . . . . . . . . . . . . . . . . . D-SandBuckingham . . . . . . . . . . . . . D-SandDivide . . . . . . . . . . . . . . . . . . D-SandGraylin, NE . . . . . . . . . . . . . . D-SandJackpot . . . . . . . . . . . . . . . . . D-SandLittle Beaver . . . . . . . . . . . . . D-SandLittle Beaver, East. , , . . . . . . D-Sand
Field Reservoir
Phegley . . . . . . . . . . . . . . . . . D-SandPierce . . . . . . . . . . . . . . . . . . LyonsPlum Brush Creek . . . . . . . . J-SandRangely . . . . . . . . . . . . . . . . . WeberSaber. . . . . . . . . . . . . . . . . . . D-Sand
FloridaSunoco-Felda . . . . . . . . . . . . RobertsJay ., . . . . . . . . . . . . . . . . . . . SmackoverBlackjack Creek . . . . . . . . . . Smackover
IllinoisClay City Consolidated. . . . Aux Vases
McCloskyDale Consolidated. . . . . . . . Aux VasesLawrence . . . . . . . . . . . . . . . CypressLouden . . . . . . . . . . . . . . . . . CypressMain Consolidated . . . . . . . PennsylvanianNew Harmony . . . . . . . . . . . CypressSalem Consolidated . . . . . . BenoistRobinson, . . . . . . . . . . . . . . . Robinson
KansasBemis-Shutts. . . . . . . . . . . . . ArbuckleBlankenship . . . . . . . . . . . . . BartlesvilleBig Sandy . . . . . . . . . . . . . . . BartlesvilleBurket . . . . . . . . . . . . . . . . . . BartlesvilleBush City . . . . . . . . . . . . . . . SquirrelChase Silica . . . . . . . . . . . . . ArbuckleCunningham. . . . . . . . . . . . . Lansing-Kansas CityEdna. . . . . . . . . . . . . . . . . . . . BartlesvilleEl Dorado . . . . . . . . . . . . . . . AdmireFairport . . . . . . . . . . . . . . . . . ArbuckleFox-Bush-Couch. . . . . . . . . . BartlesvilleGorham. . . . . . . . . . . . . . . . . ArbuckleHall-Gurney . . . . . . . . . . . . . Lansing-Kansas cityHep[er . . . . . . . . . . . . . . . . . . BartlesvilleHollow-Nikkei . . . . . . . . . . . HuntonHumboldt-Chanute . . . . . . . BartlesvilleIola . . . . . . . . . . . . . . . . . . . . BartlesvilleKraft-Prusa . . . . . . . . . . . . . . ArbuckleLament . . . . . . . . . . . . . . . . . BartlesvilleMadison . . . . . . . . . . . . . . . . BartlesvilleMcCune . . . . . . . . . . . . . . . . BartlesvilleMoran, Southwest . . . . . . . . BartlesvilleRainbow Bend . . . . . . . . . . . BurgessRitz-Canton . . . . . . . . . . . . . MississippianSallyards . . . . . . . . . . . . . . . . BartlesvilleThrall-Aagard . . . . . . . . . . . . BartlesvilleTrapp. . . . . . . . . . . . . . . . . . . ArbuckleVirgil . . . . . . . . . . . . . . . . . . . Bartlesville
Louisiana (North)Caddo Pine. . . . . . . . . . . . . . Nacatoch
AnnonaPaluxy
Field Reservoir
Haynesvil[e. . . . . . . . . . . . . . BuckPettit LimeCampSmackover
Homer. . . . . . . . . . . . . . . . . . Homer (all)Rodessa. . . . . . . . . . . . . . . . . Rodessa (all)Delhi . . . . . . . . . . . . . . . . . . . Delhi (all)
Louisiana (South)Avery Island . . . . . . . . . . . . . Medium
DeepBay St. Elaine . . . . . . . . . . . . Deep
DeepBayou Sale . . . . . . . . . . . . . . DeepCaillou Island. . . . . . . . . . . . Medium
MediumDeep
Cote Blanche Bay West MediumMedium
Cote Blanche Island. . . . . . . DeepDeep
Garden Island Bay . . . . . . . . ShallowShallowMediumMedium
Grand Bay. . . . . . . . . . . . . . . MediumMedium
Hackberry West. . . . . . . . . . MediumLake Barre. . . . . . . . . . . . . . . Deep
DeepRomere Pass. . . . . . . . . . . . . MediumTimbalier Bay . . . . . . . . . . . . MediumLake Pelto. . . . . . . . . . . . . . . Deep
DeepLake Washington. . . . . . . . . Shallow
MediumDeep
Paradis. . . . . . . . . . . . . . . . . . DeepWest Bay . . . . . . . . . . . . . . . MediumWeeks Island . . . . . . . . . . . . Deep
DeepQuarantine Bay . . . . . . . . . . Medium
MediumVenice. . . . . . . . . . . . . . . . . . Medium
Medium
MississippiBaxterville. . . . . . . . . . . . . . . Lower Tuscaloosa MassiveBay Springs. . . . . . . . . . . . . . Lower Cotton ValleyCranfield. . . . . . . . . . . . . . . . Lower TuscaloosaEucutta East . . . . . . . . . . . . . EutawHeidelberg . . . . . . . . . . . . . . East Eutaw, (2) West EutawLittle Creek. . . . . . . . . . . . . . Lower TuscaloosaMallalieu, West . . . . . . . . . . Lower TuscaloosaMcComb. . . . . . . . . . . . . . . . Lower Tuscaloosasoso. . . . . . . . . . . . . . . . . . . . BaileyTinsley. . . . . . . . . . . . . . . . . . Woodruff SandYellow Creek, West . . . . . . Eutaw
Field
Appendix A . 175
Reservoir
MontanaBell Creek. . . . . . . . . . . . . . . MuddyCabin Creek. . . . . . . . . . . . . lnterlake-Red RiverCut Bank. . . . . . . . . . . . . . . . KootenaiDeer Creek. . . . . . . . . . . . . . InterlakeGas City . . . . . . . . . . . . . . . . Red RiverGlendive. . . . . . . . . . . . . . . . Red RiverLittle Beaver . . . . . . . . . . . . . Red RiverLittle Beaver, East. , . . . . . . . Red RiverMonarch . . . . . . . . . . . . . . . . lnterlake-Red RiverOutlook . . . . . . . . . . . . . . . . Winnepegosis-lntedakePennel. . . . . . . . . . . . . . . . . . lnterlake-Red Riverpine. ., . . . . . . . . . . . . . . . . . InterlakePoplar, East. . . . . . . . . . . . . . MadisonRicheu, Southwest. . . . . . . . lnterlake-Red RiverSand Creek. . . . . . . . . . . . . . lnterlake-Red River
New MexicoAllison. . . . . . . . . . . . . . . . . . PennsylvanianCaprock . . . . . . . . . . . . . . . . QueenCaprock, East . . . . . . . . . . . . DevonianCato . . . . . . . . . . . . . . . . . . . San AndresChaveroo . . . . . . . . . . . . . . . San AndresCorbin. . . . . . . . . . . . . . . . . . AboDenton . . . . . . . . . . . . . . . . . Wolfcamp
DevonianEmpire-Abe. . . . . . . . . . . . . . AboEunice-Monument . . . . . . . . Gray burg-San AndresHobbs . . . . . . . . . . . . . . . . . . San Andres-GrayburgLea. . . . . . . . . . . . . . . . . . . . . DevonianLusk. . . . . . . . . . . . . . . . . . . . StrawnMaljamar. . . . . . . . . . ., . . . . Gray burg-San AndresMilnesand. . . . . . . . . . . . . . . San AndresVacuum . . . . . . . . . . . . . . . . Gray burg-San Andres
GlorietaAbo Reef
North DakotaAntelope. . . . . . . . . . . . . . . . MadisonBeaver Lodge . . . . . . . . . . . . Madison
DevonianBlue Buttes . . . . . . . . . . . . . . MadisonCapa . . . . . . . . . . . . . . . . . . . MadisonCharlson . . . . . . . . . . . . . . . . MadisonTioga. . . . . . . . . . . . . . . . . . . Madison
OklahomaStar . . . . . . . . . . . . . . . . . . . . Upper Misener-HuntonWashington, East-Goldsby,
West . . . . . . . . . . . . . . . . . . OsborneSho-vel-tum . . . . . . . . . . . . . Pennsylvanian-DeeseElmwood, West . . . . . . . . . . Upper Morrow “A”Elk City . . . . . . . . . . . . . . . . . HoxbarSalt Fork, Southeast. . . . . . . SkinnerDover Hennessey. . . . . . . . . Meramec
ManningRed Bank. . . . . . . . . . . . . . . . DutcherPutnam . . . . . . . . . . . . . . . . . Oswego
116 . Appendix A
Field Reservoir
Stroud . . . . . . . . . . . . . . . . . . PrueEola-Robberson . . . . . . ... , PontotocAvant & West . . . . . . . . . . . BartlesvilleBowlegs. . . . . . . . . . . . . . . . . GilcreaseBurbank, North. . . . . . . . . . . BurbankCarleton, Northeast. . . . . . . Atoka-MorrowCement. . . . . . . . . . . . . . . . . Medrano Sand, WestCheyenne Valley . . . . . . . . . Red ForkCushing. . . . . . . . . . . . . . . . . BartlesvilleDibble, North. . . . . . . . . . . . OsborneDelaware-Childers . . . . . . . . BartlesvilleEarlsboro. . . . . . . . . . . . . . . . EarlsboroEdmond, West . . . . . . . . . . . HuntonFlat Rock. . . . . . . . . . . . . . . BartlesvilleHealdton. . . . . . . . . . . . . . . . HoxbarLindsay, North . . . . . . . . . . . BromideMustang . . . . . . . . . . . . . . . . Hunton Bois D’ArcNorth Northwest-Verden ., MarchandOakdale Northwest. . . . . . . Red ForkOconee, East . . . . . . . . . . . . Oil CreekOklahoma City . . . . . . . . . . Wilcox
Oil Creek-Lower SimpsonRed River, West. . . . . . . . . . GunsightSeminole. . . . . . . . . . . . . . . . Upper WilcoxStanley Stringer, North . . . . Burbank
PennsylvaniaBradford . . . . . . . . . . . . . . . . Third BradfordFork Run . . . . . . . . . . . . . . . . CooperFoster-Reno-Oil City ., . . . . Venago FirstKane . . . . . . . . . . . . . . . . . . . KaneSartwell. . . . . . . . . . . . . . . . . Third Bradford
Sartwell
TexasDistrict 1Big Wells. . . . . . . . . . . . . . . . San MiguelDarst Creek . . . . . . . . . . . . . Buda-EdwardsLuling-Branyon . . . . . . . . . . . EdwardsSalt Flat. . . . . . . . . . . . . . . . . Edwards
District 2Greta (a l l ) . . . . . . . . . . . . . . . 4400Lake Pasture . . . . . . . . . . . . . H-440
569Refugio . . . . . . . . . . . . . . . . . Refugio-FoxTom Oconnor . . . . . . . . . . . Catahoula-Frio-MioceneWest Ranch . . . . . . . . . . . . . 41-A
District 3Thompson. . . . . . . . . . . . . . . FrioBarbers Hills . . . . . . . . . . . . . Frio-MioceneColumbia West . . . . . . . . . . MioceneConroe . . . . . . . . . . . . . . . . . First Main CockfieIdDickinson-Gillock . . . . . . . . Frio 8300-8800
Frio 9000-9300Goose Creek. . . . . . . . . . . . . MioceneHastings East & West . . . . . FrioHigh Island . . . . . . . . . . . . . . Miocene
Field Reservoir
Hull Merchant . . . . . . . . . . . YeguaHumble (all) . . . . . . . . . . . . . MioceneOld Ocean . . . . . . . . . . . . . . ArmstrongOyster Bayou . . . . . . . . . . . . Frio-SearbreezePierce Junction. . . . . . . . . . . FrioSour Lake . . . . . . . . . . . . . . . FrioSpindletop . . . . . . . . . . . . . . Caprock-Miocene-FrioTomball. . . . . . . . . . . . . . . . . CockfieldWebster . . . . . . . . . . . . . . . . FrioMagnet Withers. . . . . . . . . . FrioAnahuac . . . . . . . . . . . . . . . . Frio
District 4Alazan North . . . . . . . . . . . . FrioAqua Dulce-Stratton . . . . . . Frio-VicksburgBorregos . . . . . . . . . . . . . . . . Combined ZonesGovernment Wells North . . NorthKelsey , . . . . . . . . . . . . . . . . . Multiple Zones 5400-6400Plymouth . . . . . . . . . . . . . . . FrioSaxet . . . . . . . . . . . . . . . . . . . Het.-MioSeeligson. . . . . . . . . . . . . . . . Combined ZonesT-C-B. . . . . . . . . . . . . . . . . . . Zone 21 -BWhite Point East . . . . . . . . . Frio
District 5Mexia . . . . . . . . . . . . . . . . . . WoodbinePowell . . . . . . . . . . . . . . . . . . WoodbineVan . . . . . . . . . . . . . . . . . . . . Woodbine
District 6Fairway . . . . . . . . . . . . . . . . . LimeNeches . . . . . . . . . . . . . . . . . WoodbineNew Hope . . . . . . . . . . . . . . Bacon Lime
PittsburgQuit Man . . . . . . . . . . . . . . . PaluxyTalco. . . . . . . . . . . . . . . . . . . PaluxyEast Texas. . . . . . . . . . . . . . . WoodbineHawkins . . . . . . . . . . . . . . . . Woodbine
District 7-BEastland Co . . . . . . . . . . . . . StrawnStephens Co. . . . . . . . . . . . . Caddo
District 7-CBig Lake. . . . . . . . . . . . . . . . . QueenJameson . . . . . . . . . . . . . . . . Strawn
PennsylvanianMcCamey . . . . . . . . . . . . . . . GrayburgPegasus . . . . . . . . . . . . . . . . . Pennsylvania
Ellen burger
District 8Andector. . . . . . . . . . . . . , . . Ellen burgerBlock 31 . . . . . . . . . . . . . . . . Crayburg
DevonianEllen burger
Cowden North. . . . . . . . . . . GrayburgDeep
Cowden South. . . . . . . . . . . San Andres-GrayburgCanyonEllen burger
Appendix A ● 117
Field Reservoir
Crossett. . . . . . . . . . . . . . . . . DevonianDollarhide. . . . . . . . . . . . . . . Ellen burger
DevonianDora Roberts . . . . . . . . . . . . EllenburgerDune . . . . . . . . . . . . . . . . . . . Permian-San AndresEmma . . . . . . . . . . . . . . . . . . Gray burg-San Andres
Ellen burgerFoster , . . . . . . . . . . . . . . . . . Gray burg-San AndresFullerton . . . . . . . . . . . . . . . . San Andres
Clear Fork8500
Goldsmith. . . . . . . . . . . . . . . San Andres-Grayburg5600 Clear Fork
Harper. . . . . . . . . . . . . . . . . . PermianDevonianEllenburger
Headlee. . . . . . . . . . . . . . . . . Ellen burgerHendrick . . . . . . . . . . . . . . . . Yates-Seven RiversHoward-Glasscock. . . . . . . . Yates-Seven Rivers-Queen
San Andres-GrayburgGlorieta
Iatan East . . . . . . . . . . . . . . . San AndresJohnson. . . . . . . . . . . . . . . . . Gray burg-San AndresJordan . . . . . . . . . . . . . . . . . . Permian
EllenburgerKermit . . . . . . . . . . . . . . . . . . Permian-YatesKeystone. . . . . . . . . . . . . . . . Colby
EllenburgerMcElroy. . . . . . . . . . . . . . . . . CrayburgMeans . . . . . . . . . . . . . . . . . . Gray burg-San AndresMidland Farms . . . . . . . . . . . Grayburg
EllenburgerParks . . . . . . . . . . . . . . . . . . . PennsylvanianPenwell. . . . . . . . . . . . . . . . . San Andres
GlorietaSand Hills . . . . . . . . . . . . . . . TubbsShafter Lake . . . . . . . . . . . . . San Andres
Devonian-WolfcampEllenburger
Spraberry Trend . . . . . . . . . . SpraberryTXL . . . . . . . . . . . . . . . . . . . . Tubb
PennsylvanianUniversity Waddell . . . . . . . DevonianWaddell . . . . . . . . . . . . . . . . Gray burg-San AndresWard Estes North. . . . . . . . . Yates-Seven RiversWard South . . . . . . . . . . . . . Yates-Seven RiversYates . . . . . . . . . . . . . . . . . . . Gray burg-San Andres
District 8-AAnton Irish . . . . . . . . . . . . . . ClearforkCogdell . . . . . . . . . . . . . . . . . Canyon ReefDiamond M . . . . . . . . . . . . . Canyon LimeKelly Snyder. . . . . . . . . . . . . Cicso
Canyon Reef (Watered)Canyon Reef
Levelland . . . . . . . . . . . . . . . San AndresPrentice. . . . . . . . . . . . . . . . . Glorieta
Clearfork 6700
Field
Russell. . . . . . . . . . .
Salt Creek. . . . . . . .Seminole. . . . . . . . .Slaughter. . . . . . . . .Wasson. . . . . . . . . .
Welch ... , . . . . . . .
District 9Archer Co. Reg. . . .Cooke Co. Reg. ., .Hull Silk Sikes. ... ,KMA . . . . . . . . . . . .Walnut Bend . . . . .
Wichita Co. Reg. . .Wilbarger Co. Reg.Young Co. Reg. . . .
District 10Panhandle. . . . . . . .
UtahAltamount-BluebellAneth . . . . . . . . . . .McElmo Creek . . . .Ratherford. . . . . . . .White Mesa . . . . . .Bridger Lake . . . . . .
Reservoir
. . . . . . . GlorietaClearforkDevonian
. . . . . . . Canyon Reef
. . . . . . . San Andres
. . . . . . . San Andres
. . . . . . . San AndresClearfork
. . . . . . . San Andres
. . . . . . . Strawn-Gunsight
. . . . . . . Strawn
. . . . . . . Strawn 4300
. . . . . . . Strawn
. . . . . . . HuspethWalnut BendWinger
. . . . . . . 0-2100
. . . . . . . Dyson-Milham
. . . . . . . Gunsight
. . . . . . .
. . . . . .
. . . . . . .
. . . . . . .,. .,...,. ...,,,. .,..,
West VirginiaGreenwood. . . . . . . . . . . . . .Griffithsville . . . . . . . . . . . . .
WyomingBig Muddy . . . . . . . . . . . . . .Big Sand Draw . . . . . . . . . . .Bonanpa . . . . . . . . . . . . . . . .C-H Field. . . . . . . . . . . . . . . .Cottonwood Creek . . . . . . .Dillinger Ranch. . . . . . . . . . .Elk Basin . . . . . . . . . . . . . . . .Frannie . . . . . . . . . . . . . . . . .Gailand . . . . . . . . . . . . . . . . .
Grass Creek . . . . . . . . . . . . .
CarsonGrayHutch inson
Green RiverDesert CreekDesert CreekDesert CreekDesert CreekDakota
Big InjunBerea
Wall CreekTensleepTensleepMinnelusaPhosphoricUpper Minnelusa BEmbar-TensleepTensleepCombinedTensleepCurtisEmbar-TensleepFrontier
Hamilton Dome . . . . . . . . . . Tensleep
Hilight ~ “ . . ~+• “ “ “ “ ‘ “ “ “ “ MuddY-MinnellJsaLance Creek . . . . . . . . . . . . . Leo
Sundance
118 . Appendix A
Field Reservoir
Little Buffalo Basin. . . . . . . . TensleepLost Soldier. . . . . . . . . . . . . . Combined
TensleepOregon Basin . . . . . . . . . . . . North Tensleep
South TensleepSalt Creek. . . . . . . . . . . . . . . Wall CreekSmemlek, West . . . . . . . . . . Minnelusa BSteamboat Butte . . . . . . . . . TensleepWertz . . . . . . . . . . . . . . . . . . TensleepWinkleman Dome . . . . . . . . Tensleep
Offshore Fields
Field
Bay Marchand 002 . . .
Bay Marchand Block 2.
n Louisiana
Reservoir
. . . . . . 3600’ D3650’ (L) D3650’ (U) D4900’ D7100’ F7600’ MS7900’ D81 75’ B8200’ F8200’ BUQ8300’ BU8300’ EE8500’ B8550’ B8700’ BU8750’ BUW9100’ c9200’ B9600’ BRARAR D
BM 4350 D VUBM 4500 MLD VUBM 5000 D VUBM 4800 RD VU4800 AB VU
Eugene Island 126. . . . . . . . . . . 2A-RF-B2A-RF-c2B (1) RF A2B (1) RF-BVU2B (U) RJ2B (U) RL-CC-1 RFC-1 RND-1 RF AD-1 RF SUE-2 RF SUF-1 RF SUIM RF-BIM RL-AIM RL-SU
Field Reservoir
Eugene Island 175. . . . . . . . . . . RARARARBR DRBFB-DFB-DFB-ARBRCRA
Eugene Island 276. .., . . . ., . . P RA SU 1 WP RA SU IWU RA SU 1 WU3 RA SU 1 WVH 10 DE* 1Crist Sub 3A RATex (P) 1 RF
Eugene Island Block 330 . . . . . LF FBB 17300 S1 ● 1FBBRAFBAFBARASeg. ASeg. 1Seg. 3GA-2HB-1Seb. I
BFBAFBBFBBFBFCFSIL RAL RBL RCL REL RFLF FBA 1
Grand Isle Block 16 . . . . . . . . . B-2 RC 1AB-2 RE 1 WB-4 RCB-4 REB-4 RTBF-2 RE UCC-1 REF lWC-4 A RN
Grand Isle Block 43 . . . . . . . . . G-1F-2c - lR-2c-1G-2
Appendix A ● 119
Field Reservoir
s-1R5D-1R-1s-1R1l-lF-1R-6F-1I-8E-6
Grand Isle Block 47 . . . . . . . . . A-6A-6A-3A-2A-1
Main Pass Block 35. . . . . . . . . . G2 RA SUK2 RA SULO RA SUL2 RA SUN RA SUO RA SUR2 RA SU
Main Pass Block 41 . . . . . . . . . . RD SURA SURA SURB SURA SURB SU
Main Pass 41 . . . . . . . . . . . . . . . ADDAAAAtAFA
Main Pass Block 69. . . . . . . . . . RB SURA VURC VURH SURB SU
Main Pass 144. . . . . . . . . . . . . . RI62506250L6900725075007525
Main Pass 306 . . . . . . . . . . . . . . AB 28/29C45B 44/45AB444/45A-213
Field Reservoir
A-4A-FB-1A-2A-35AF8144/45FB-IFB-1112/34294244/45
Ship Shoal 204 . . . . . . . . . . . . . D-1FB5FB4FB5RABRARA & BRARB
Ship Shoal 207 . . . . . . . . . . . . . AlRARARERBRGRARARFRARCRG
Ship Shoal 208 . . . . . . . . . . . . . RCPAARARAFB-3FB-4FB-3FB-4FB-4FB-3FB-4FB-3FB-4FB-4RARC
South Pass Block 24 . ........4 RB SU8200 T SU8400 RA SU8600 RA SU8800 RD SUM2 RA SUNA RA SU02 RA SUP-Q RA SUQ RA SU
120 . Appendix A
Field Reservoir
Q RB SUQ RC SUQ RE SUR2 RA SUSRA SUS RC SUT RA SUT RB SUT RC SUT RD SUT1 RB SU
South Pass Block 24 . . . . . . . . . T1 A RB SUTIA RB SUU2 RA SU
South Pass Block 27 . . . . . . . . . RA SUv uRB SURA SURA SURA SURB SURC SURD SURB SURC SURD SURE SURC SURA SURB SURA SURA SURB SURA SURA SURB SURC SURD SU
South Pass 27 . . . . . . . . . . . . . . Pliocene10 DF 32 UPF 32 UPF 13 AUp
F 13 ADRBSU10 U PRESURASU6 UPRESURESUF 13 AU
South Pass 61 ... , . . . . . . . . . . RMRNRQRRRNRMRA
Field Reservoir
RCRBRCRD
South Pass 62 . . . . . . . . . . . . . . RARARBRCRARARARCRARD
South Pass 65 . . . . . . . . . . . . . . RARGRBRCRBRCR DRERARB
Ship Shoal 208 . . . . . . . . . . . . . RASouth Marsh Island 73 . . . . . . . B-35-K
B-65-GC-5-6
Timbalier Bay Block 21. . . . . . . DCS uIIIIBZ X 33X2DCClcBIDBSCDCDCDCDCEBT EBSUDCDC
W. Delta Block 30 . . . . . . . . . . A-1 Res. FA-2 Res. DA-3 Res. DC-45 and Res. QD-6 Res. BBE RASUG RASUG-4 Res. C-1C-4. Res. E-1I RASUIF Res. C-2IM Res. C-10
Appendix A . 121
Field Reservoir
P-1 Res. FP-2 Res. FP-45 Res. FP-6 Res. F6100 Res. E6300’ Res. G-A-2 Res. F6400’ Res. G-A-3 Res. F71 50’ Res. E8500 Res, C
W. Delta 73. . . . . . . . . . . . . . . . RAFBIFB2RA
Field Reservoir
RARARA
W. Delta 79. ., . . . . . . . . . . . . . D2R6SSFFONFFNFFIIIIIllI v
122 . Appendix A
Documentation of Data Sources
Data needed for individual reservoirs were ob-tained from many sources. Sources of data aresummarized by State in the Bibliography begin-ning on page 129. The entries in this bibliographyinclude 10 categories of data. Specific data itemsin each category are identified in the followingsection. These categories indicate the type of in-formation sought. As indicated in the Selection ofData Items on page 111, there are many gaps inthe specific data items under each category. Datawhich were available for essentially all reservoirsin the data base are indicated with an asterisk.
Geology* Structure name
Geologic ageLithologyFracturesFaultingComplexityContinuityLenticularityHeterogeneityClay contentTurbidities
Reservoir condit ion
* Depth* Bottom hole temperature
PressureDip
* permeabilityGas cap
Reservoir volume
* Net pay thickness* Number of zones* Porosity* Acres
Saturations
* Connate water saturation* Initial oil saturation
Current oil saturationResidual oil saturation after primary and sec-
ondary recovery
Water characteristics
( il/***
O i l*
*
*
O i l**
SalinityCalciumMagnesium
characteristics
GravityViscosity (reservoir conditions)
Formation volume factorsGas/oil ratio
volume - resources/reserves
Original oil in placeEstimated primary/secondary recoveryRemaining reserves
volume - production history
Cumulative productionAnnual productionProduction decline rate
Field development - conventional●
☛
☛
☛
☛
☛
Discovery yearprimary drive typeType of secondary recoveryYear of secondary initiationTotal wells drilledLatest active wellsCurrent operator(s)
Field development - E O RType of EOR processYear of initiationCurrent stage of developmentAcres under development
Bibliography
Following the State-by-State charts is abibliography providing the full citation for eachsource by State.
Appendix A ● 123
Documentation of Data Sources for Big Fields Reservoir File
1
~1
4
567
12i
4
5b7
8910
11
12
3
4
5
67
1
2
14
5
67
8
9
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t ion
history
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Field Development
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EOR
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124 . Appendix A
State and Source
10
11
l?
12
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
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W a t e r
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terist ics
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Field Development
Conventional
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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.
B u r e a u o f M i n e s — h
Energy Research and Development
Administration
International Oil Scouts
Association
Kansas Geological Survey — a
Kansas Geological Survey — b
K a n s a s G e o l o g i c a l S u r v e y — 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
Miscel laneous Petroleum
P e r i o d i c a l s
Louisiana (Onshore)Amerlcan Petroleum Institute — a
a n d b
8ureau of Mines
Louisiana Department ot
Conservation — a
Louisiana Department of
Conservation — b
011 and Gas journal — a
0 1 1 a n d G a s j o u r n a l — b
Society of Petroleum Engineers of
AlME — a
Society of Petroleum Englneers of
AIME — b
Society of Product Ion Well
Analysts
N a t i o n a l P e t r o l e u m C o u n c i l
Louisiana (Offshore)U S Geologlcal Survey
MississippiAmerican Association of
Petroleum Geologists
American Petroleum Inst i tute
Bureau of Mines — a
Bureau of Mines — b
Federal Energy Administrat ion
Gulf Universlties Research
C o n s o r t i u m
International Oil Scouts
A s s o c i a t i o n
MIssissippi State 011 and Gas
Board
011 and Gas jou rna l — a
011 and Gas Journal — b
Society of Petroleum Engineers o fAIME
MontanaAmerican Association of
P e t r o l e u m G e o l o g i s t s
B u r e a u o f M i n e s
GuIf Universities Research
C o n s o r t i u m
Appendix A . 725
Geology
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terist ics
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.,
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126 . Appendix A
State and Source
4
5
6
7
8
9.
10
1.
234
5
6
789
101112
13
1
2
3
4
5
6
7
1
2
3
4
5
b
7
8
9
Geology
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terist ics
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State and Source
1011
1213
1.23
4
567
8
9
10
1
2
\45
6
7
8
Y
10
11
1
23.
Appendix A ● 127
Geology
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128 . Appendix A
State and Source
4
5.
6
7
8
9
10
12.
3.
4.5.
6.
1.2.3.4
5
67
8.
9.10
11
WyomingA m e r i c a n P e t r o l e u m I n s t i t u t e
8 u r e a u o f M i n e s
F e d e r a l E n e r g y A d m i n i s t r a t i o n
Gulf Universities Research
C o n s o r t i u m
International Oil Scouts
A s s o c i a t i o n
N a t i o n a l P e t r o l e u m C o u n c i l .
0 1 1 a n d G a s J o u r n a l — a .
O i l a n d G a s j o u r n a l — b .
Society of Petroleum Engineers of
A I M E — a , . .
Society of Petroleum Engineers of
AlME — b . . .
Society of Petroleum Engineers of
A I M E — c
Wyoming Geological Associat ion.
Wyoming 011 and Gas
C o n s e r v a t i o n C o m m i s s i o n
Miscel laneous Petroleum
P e r i o d i c a l s .
Geology
●
✎
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condit ion
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.,
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vo lume
, ,
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Satura-
tions
, . .
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W a t e r
charac-
terist ics
. ,
●
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terist ics
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Oil volume
Resources/
reserves
●
, .
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.
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Produc-
t ion
history
●
●
●
. , .
●
, .
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, .
. .
, ,
●
. .
F ield Development
●
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EOR
●
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●
Appendix A . 129
BibliographyAlabama
1.
2.
3.
4.
5.
6.
7.
Halbouty, Michael T . (Ed.) , Geology of GiantPe(ro/eum Fields, A m e r i c a n A s s o c i a t i o n o f
Petroleum Geologists, Tulsa, okla., Memoir 14,1 9 7 0 .
The One Hundred Largest Fields in (he UnitedStates with R e m a i n i n g Es (irnated P r o v e dReserves of Crude Oil and “Ninety Day” Prod-uctive Capacity Estimated as of December .31,7974, American Petroleum Institute, Washing-ton, D. C., June 11, 1975.
Hawkins, M. E., et. al., Analyses of Brines FromOil-Productive Formations in Mississippi andAlabama, U.S. Department of the Interior,Bureau of Mines, Washington, D. C., 1963.
/nternationa/ 0;/ and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Mesozoic -Paleozoic Producing Areas ofMississippi and Alabama, Mississippi GeologicalSociety, Jackson, Miss., 1963.
“Here Are The Big U.S. Reserves,” Oil and Gasjournal, Jan. 27, 1975, pp. 116-118.
Frick, Thomas C. (Ed.), Petroleum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
Alaska
1.
2.
3.
4.a
4.b
96-594
Statistical Report, State of Alaska, Division ofOil and Gas, Anchorage, Alaska, 1976.
Alaska Geological Survey, Anchorage, Alaska.
Halbouty, Michael T. (Ed.), Geo/ogy of GiactPetro/eum Fields, American Association ofPetroleum Geologists, Tulsa, Okla., Memoir 14,1970.
Reserves of Crude Oil, Natural Gas Liquids. andNatura/ Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 1974. Joint publication by theAmerican Gas Association, the Americanpetroleum Inst itute, and the C a n a d i a nPetroleum Associat ion, Vol. 29, May 1975.
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Day” DailyProductive Capacity Estimated as of December31, ? 974, American Petroleum Institute, Wash-ington, D. C., June 11, 1975.
3- 78 - 10
5.
6.
7.
8.
9.
Blaske, Donald P., et. al., Oil Fields and CrudeOil Characteristics— C o o k 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 Produc-tive Capacities, Federal Energy Administration,Washington, D. C., Vol. 2, 1975.
/international Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Determination of Equitable Price Levels forNorth Slope Alaskan Crude Oi/, Mortada inter-national, Dallas, Text, 1976.
“Here Are The Big U.S. Reserves,” Oi/ and Gas)ournal, Jan. 27, 1975, pp. 116-118.
Arkansas1.
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 nArkansas, U.S. Department of the Interior,Bureau of Mines, Washington, D. C., informa-tion Circular No. 8428, 1969.
Hawkins, M. E., et. al., Analyses of Brines FromOil Productive Formations in South Arkansasand North Louisiana, U.S. Department of the in-terior, Bureau of Mines, Washington, D. C.,Report of Investigations No. 6282, 1963.
Carpenter, Charles B., and Schroeder, H. J., Mag-nolia Oil Field, U.S. Department of the Interior,Bureau of Mines, Washington, D. C., Report ofInvestigations No. 3720, 1944.
Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Field Testing, Gulf Universit iesResearch Consortium, Houston, Tex.,~ ReportNo. 148, 1976.
/nterna(iona/ Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part1[, vol. 44, 1974.
Summary of Secondary Recovery Operations inArkansas During 7953, Interstate Oil CompactCommission, 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 ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
730 . Appendix A
7.b Socie(Y of Petroleum Engineers Symposium onhnpro;ed Oil Recovery, - Society of PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
California1 .a
1.b
2.
3.
4.
5.a
S.b
6.
7.
8.a
8.b
Reserves of Crude Oil, Natural Gas Liquids andNatura/ Gas is the United States and Canada,and United States Productive Capacity as ofDecember 37, 7974. Joint publication by theAmerican Gas Association, the Americanpet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Day” DailyProductive Capacity Estimated as of December37, 1974, American Petroleum Institute, Wash-ington, D. C., June 11, 1975.
Halbouty, Michael T. (Ed.), Geology of GiantPetroleum Fields, American Association ofPetroleum Geologists, Tulsa, Okla., Memoir 14,1970.
California Oil and Gas Fields, California Divisionof Oil and Gas, Sacramento, Calif., 1974.
Annua/ Review of California Oil and Gas Pro-duction, Conservation Commission of Califor-nia Oil Producers, Los Angeles, Calif., 1974.
Contracts and Grants for Cooperation Researchon Enhancement of Recovery of Oil and Gas,U.S. Energy Research and Development Ad-ministration, Wash ington, D. C., ProgressReview Series Nos. 1-5, 1975-76.
Engineering correlation obtained from theEnergy Research and Development Administra-tion, San Francisco Operations Division.
Oil and Gas Resources, Reserves, and Prod-uctive Capacities, Federal Energy Administra-
tion, Washington, D. C., Vol. 2, 1975.
Preliminary Field Test Recommendations andProspective Crude Oil Fie/ds or Reservoirs forHigh Priority Field Testing, Gulf Universit iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
National Petroleum Council review of Big FieldsReservoir Data File.
U.S. Crude Oil Data, 1860-1944, N a t i o n a lPetroleum 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, ” Oiland Gas )ournal, Apr. 5, 1976, pp. 108-122.
Special Computer Analysis from PetroleumData System of North America, University ofOklahoma, Norman, Okla.
Field Case Histories, Oil and Gas Reservoirs,Society of Petroleum Engineers, American in-stitute of Mining, Metallurgical, and PetroleumEngineers, Inc., Dallas, Tex., SPE Reprint SeriesNos. 4 and 4a, 1974-75.
Frick, Thomas C. (Ed.), Petroleum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol 2,1962.
/reproved Oil-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, 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 PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
Selected articles from journal of PetroleumTechnology, Oil and Gas )ournal, Oil Daily, Pro-ducer’s Monthly, and World Oil.
Colorado1.
2.
3.
4.
5.a
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Day” Prod-uctive Capacity Estimated as of December 31,1974, American Petroleum Institute, Washing-ton, D. C., June 11, 1975.
Biggs, Paul, and Koch, Charles A., Waterflood-ing of Oil Fields in Colorado, U.S. Dept. of theInterior, Bureau of Mines, Washington, D. C.,1974.
/nternationa/ Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Special Computer Analysis from PetroleumData System of North America, University ofOklahoma, Norman, Okla.
Parker, J. M. (Ed.), Colorado - Nebraska Oil andGas Field Volume, Rocky Mountain Associationof Geologists, Denver, Colo., 1962.
5.b Jensen, Fred S. (Ed.), The Oil and Gas Fields ofColorado—A Symposium, Rocky MountainAssociation of Geologists, Denver, Colo., 1955.
6. Frick, Thomas C. (Ed.), Petroleum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
Florida
1.
2.
3.
4.
5.
6.a
6.b
Braunstein, Jules (Ed.), North American 0;/ andGas Fields, American Association of PetroleumGeologists, Tulsa, Okla., Memoir 24, 1976.
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Day” DailyProductive Capacity Estimated as of December31, 1974, American Petroleum Institute, Wash-ington, D. C., June 11, 1975,
Oil and Gas Resources, Reserves and ProductiveCapacities, Federal Energy Administration,Washington, D. C., Vol 2, 1975.
/international Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, 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 ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
Society of Petroleum Engineers Symposium onhnproved 0;/ Recovery, Society of PetroleumEngineers, American Institute of Mining,Metallurgical and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
Illinois
1. Report of Investigations No. 3534, U.S. Bureauof Mines, Washington, D.C.
2. Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Fie/d Testing, Gulf Universit iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
3. Geology and Petroleum Production of the /lli-nois Basin, I l l i no i s and I n d i a n a - K e n t u c k 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 Propertiesof ///inois Oil Fields, Ill inois State GeologicalSurvey, Urbana, Ill., 1970.
P e t r o l e u m /ndustry in /1/inois, Il l inois S t a t eGeological Survey, Urbana, Ill., 1975.
/nternationa/ Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, 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 Gasjournal, Jan. 27, 1975, pp. 116-118.
Special Computer Analysis from PetroleumData System of North America, University ofOklahoma, Norman, Okla.
/reproved Oi/-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, 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 PetroleumEngineers, 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 GiantPetroleum Fields, American Association ofPetroleum Geologists, Tulsa, Okla., Memoir 14,1970.
Levorensen, A. 1. (Ed.), Stratigraphic Type OilFields, American Association of PetroleumGeologists, Tulsa, Okla., 1941.
Structure of Typical American Oil F ields,American Association of Petroleum Geologists,Tulsa, Okla., 1929.
Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 1974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum 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 Researchon Enhancement of Recovery of Oil and Gas,U.S. Energy Research and Development Ad-ministration, Wash ington, D. C., ProgressReview Series Nos. 1-5, 1975-76.
/nterna(iona/ Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Beene, Douglas, L., 1974 Oil and Gas Produc-tion in Kansas, Kansas Geological Survey, TheUniversity of Kansas, Lawrence, Kans., 1976.
Ebanks, W. J., Kansas Oil For Enhanced Recov-ery—A Resource Appraisal, Kansas GeologicalSurvey, The University of Kansas, Lawrence,Kans., 1975.
Communications with Kansas GeologicalSurvey.
Ores, Margaret O., a n d Saile, Donna K . ,Enhanced Oil-Recovery Operations in Kansas,Kansas Geological Survey, The University ofKansas, Lawrence, Kans., 1974.
U.S. Crude Oil Data, 7860-1944, N a t i o n a lPetroleum Council, Washington, D. C., Vol. 1,1970.
“Enhanced Recovery Production Report,” Oiland (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 PetroleumData System of North America, University ofOklahoma, Norman, Okla.
Frick, Thomas C. (Ed.), Petroleum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol 2,1962.
hnproved Oil-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, Metallurgical, and Petroleum Engineers,Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.
Society of Petroleum Engineers Symposium onhnproved Oil Recovery, Society of PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
Selected art icles from )ourna/ of Petro/eurnTechnology, Oi/ and Gas )ournal, Oi/ Dai/y, Pro-ducer’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 andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 37, 7974, Joint publication by theAmerican Gas Association, the Americanpet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Day” DailyProductive Capacity Estimated as of December31, 7974, American Petroleum Institute, Wash-ington, D. C., Jun~ 11, 1975.
M. E. Hawkins, et. al., Analyses of Brines FromOil Productive Formations in South Arkansasand North Louisiana, U.S. Department of the in-terior, Bureau of Mines, Washington, D. C.,Report of Investigations No. 6282, 1963.
Secondary Recovery and Pressure MaintenanceOperations in Louisiana, Louisiana Departmentof Conservation, Baton Rouge, La., 1973, 1974.
Summary of Field Statistics and Drilling Opera-tions, State of Louisiana, Department of Conser-vation, Baton Rouge, La., 1974.
“Enhanced Recovery Production Report,” Oiland Gas )ourna/, Apr. 5, 1976, pp. 108-127.
“Here Are The Big U.S. Reserves,” Oil and Gasjournal, Jan. 27, 1975, pp. 116-118.
/reproved Oil-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, 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 PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, inc.,Dallas, Tex., Preprint Series.
Formation Water Resistivity Data: South Loui-siana, Offshore and Adjacent Area, Society ofProduction Well Log Analysts, Lafayette, La.
National Petroleum Council Review of BigFields 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 andAmerican Association of PetroleumTulsa, Okla., Memoir 24, 1976.
Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 37, j 974, Joint publication by theAmerican Gas Association, the Americanpet ro leum ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
Hawkins, M. E., et. al., Analyses of Brines fromOil Productive Formations in Mississippi andAlabama, U.S. Department of the Interior,Bureau of Mines, Washington, D. C., Report ofInvestigations No. 6167, 1963.
Personal files of W. Dietzman, U.S. Bureau ofMines, Dallas, Tex.
Oil and Gas Resources, Reserves and ProductiveCapacities, Federal Energy Administration,Washington, D. C., Vol. 2, 1975.
Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Field Testing, Gulf UniversitiesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
/n(ernational Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Miss iss ippi Oi l and Gas Bu//etin, Mi s s i s s ipp iState Oil and Gas Board, Jackson, Miss., April1975.
“Enhanced Recovery Production Report,” Oiland 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 ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
Montana
1. Braunstein, Jules (Ed.), North American Oil andGas Fiefds, American Association of PetroleumGeologists, Tulsa, Okla., Memoir 24, 1976.
2. Hamke, J. R., et. al. Oil Fields in the WillistonBasin in Montana, North Dakota, and SouthDakota, U.S. Department of the Interior, Bureau
3.
4.a
4.b
5.
6.
7.
8.
9.
-1o.
of Mines, Washington,1966.
Preliminary Field TestProspective Crude Oil
Appendix A ● 133
D. C., Bulletin No. 629,
Recommendations andFields or Reservoirs for
l-lig~ Priority Fie/d Testing, Gulf Un ivers i t iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
/international Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
Society of Petroleum Engineers Symposium on/reproved Oil Recovery, Society of PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
Annual Review for the Year 7975, State of Mon-tana Oil and Gas Conservation Divis ion,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 ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum 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 theUnited 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 andGas Fields, American Association of PetroleumGeologists, Tulsa, Okla., Memoir 24, 1976.
2. Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 37, 7974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
3. Oil and Gas Resources, Reserves and ProductiveCapacities, Federal Energy Administration,Washington, D. C., Vol. 2, 1975.
4. Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Field Testing, Gulf Universit ies
134 ●
5.
6.
7.
8.
9.
10.
11.
12.a
12.b
13.
Appendix A
Research Consor t ium, R e p o r t No. 1 4 8 ,
Houston, Tex., 1976.
Secondary Recovery and Pressure MaintenanceProjects in New Mexico, Interstate Oil CompactCommission, Oklahoma City, Okla., 1970.
/international Oil and Gas Development, lntj2rna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
U.S. C r u d e Oil Data, 7860-7944, N a t i o n a lPetroleum 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 PetroleumData System of North America, University ofOklahoma, Norman, Okla.
Phifer, Robert L . , New Mexico Petroleum
Review, Phifer Petroleum Publication, Dallas,Tex., 1956.
A Sympos ium of O i l and Gas F ie lds o fSoutheastern New Mexico, Roswell GeologicalSociety, Roswell, N. Mex., 1957, 1960, 1966.
Frick, Thomas C. (Ed.), Petro/eum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol 2,1962.
/reproved Oil-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, Metallurgical, and Petroleum Engineers,Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.
C o m m u n i c a t i o n s w i t h S t a t e P e t r o l e u mGeologists.
North Dakota
1. Halbouty, Michael T. (Ed.), Geology of GiantPetroleum Fie/ds, American Association ofPetroleum Geologists, Tulsa, Okla., Memoir 14,1970.
2. Hamke, J. R., et. al., Oil Fields in the Wi//istonBasin in Montana, North Dakota and SouthDakota, U.S. Department of the Interior, Bureauof Mines, Washington, D. C., Bulletin No. 629,1966.
3. /international Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Te’k., PartIi, vol. 44, 1974.
4.a Oil and Gas Fields of North Dakota , N o r t hDakota Geological Survey, 1962.
4.b
5.a
5.b
6.
7.
0;1 production Statistics for 7974, North DakotaGeological 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 andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 7974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
C o m m u n i c a t i o n s w i t h S t a t e P e t r o l e u mGeologists.
Oklahoma1.
2.a
2.b
3.
4.
5.
6.
Geology of Giant Petroleum Fields, AmericanAssociation of Petroleum Geologists, Tulsa,Okla., Memoir 14, 1970.
Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 37, 1974, Joint publication by theAmerican Gas Association, the Americanpet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
The One Hundred Largest Fields in the UnitedStates with Remaining Est imated ProvedReserves of Crude Oil and “Ninety Days” DailyProductive Capacity Estimated as of December.37, 7974, American Petroleum Institute, Wash-ington, D. C., June 11, 1975.
Report of Investigations Nos. 2997, 3180, 4450,4917, 5018, 5134, 5316, and 5415, U.S. Bureauof Mines, Washington, D.C.
Contracts and Grants for Cooperative Researchon Enhancement of Recovery of Oil and Gas,U.S. Energy Research and Development Ad-ministrat ion, Wash ington, D. C., ProgressReview Series Nos. 1-5, 1975-76.
Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Field Testing, Gulf Universit iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
/nternationa/ Oi/ and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, 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 MaintenanceOperations, The Interstate Oil Compact Com-mission, Oklahoma City, Okla., 1975.
U.S. Crude O;l Data, 1860-1944, N a t i o n a lPetroleum Council, Washington, D. C., Vol. 1,1970.
“Enhanced Recovery Production Report, ” Oiland 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 ofOklahoma, Oklahoma Geological Survey,Oklahoma City, Okla., 1963.
Special Computer Analysis from PetroleumData System of North American, University ofOklahoma, Norman, Okla.
Special Analysis by Petroleum Information, Inc.,Tulsa, Okla.
Frick, Thomas C. (Ed.), Petroleum ProductionHandbook , Society of Petroleum Engineers,American institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dal las, Tex., Vol. 2,
1 9 6 2 .
Improved Oil-Recovery Field Reports, Societyof Petroleum Engineers, American Institute ofMining, 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 PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
Pennsylvania
1. Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 7974, Joint publication by theAmerican Gas Association, the Americanpet ro leum Ins t i tu te , and the CanadianPetroleum 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 Researchon Enhancement of Recovery of Oil and Gas,U.S. Energy Research and Development Ad-ministrat ion, Wash ington, D. C., ProgressReview Series Nos. 1-5, 1975-76.
4. Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Field Testing, Gulf Un ivers i t iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
5. U.S. Crude Oil Data, 1860-1944, N a t i o n a lPetroleum 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 ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
/reproved Oil Recovery Field Reports, Society ofPetroleum Engineers, American Institute of Min-ing, Metallurgical, and Petroleum Engineers,Inc., Dallas, Tex., Vol. 1, Nos. 1-4, 1975-76.
8. V e r Wiebe, W. A. , N o r t h A m e r i c a n
Petro/eurn, Wichita, Kans., 1952.
9. Selected articles from journal of PetroleumTechnology, Oil Daily, Oil and Gas journal, Pro-ducer’s Monthly, and World Oil.
10. C o m m u n i c a t i o n s w i t h S t a t e P e t r o l e u mGeologists.
Texas
1 .a Halbouty, Michael T. (Ed.), Geology of GiantPetroleum Fie/ds, American Association ofPetroleum Geologists, Tulsa, Okla., Memoir 14,1970.
1.b Braunstein, Jules (Ed.), North American Oil andGas Fields, American Association of PetroleumGeologists, Tulsa, Okla., Memoir 24, 1976.
2.a Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, ?974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
2.b The One Hundred Largest Fields in the UnitedStates with Remain ing Es t imated ProvedReserves of Crude Oil and “Ninety Day” DailyProductive Capacity Estimated as of December37, 1974, American Petroleum Institute, Wash-ington, D. C., June 11, 1975.
136 . Appendix A
3. Hawkins, M. E., et. al., Chernica/ Ana/yses andElectrica/ Resistivities of Oil Field Brines FromFie/ds in East Texas, U.S. Department of the in-terior, Bureau of Mines, Washington, D. C.,Report of Investigations No. 6422, 1964.
4. Oil and Gas Resources, Reserves and ProductiveCapacities, Federal Energy Administration,Washington, D. C., Vol. 2, 1975.
5,a Preliminary Field Test Recommendations andProspective Crude Oil Fields or Reservoirs forHigh Priority Fie/d Testing, Gulf Universit iesResearch Consortium, Houston, Tex., ReportNo. 148, 1976.
5.b Assessment of Enhanced Recovery Technologyas a Means /or /ncreasing Total Crude Oi/Recovery in Texas, Gulf Universities ResearchConsortium, The State of Texas, Governor’sEnergy Council.
6. /nternationa/ Oi/ and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, vol. 44, 1974.
7.a U.S. Crude Oil Data, 1860-7944, N a t i o n a lPetroleum Council, Washington, D. C., Vol. 1,1970.
7.b National Petroleum Council review of Big FieldsReservoir Data File.
8.a “Enhanced Recovery Production Report, ” Oiland 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 PetroleumData System of North America, University ofOklahoma, Norman, Okla.
10.a Frick, Thomas C. (Ed.), Petro/eum Product ionHandbook, Society of Petroleum Engineers,American Institute of ,Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex,, Vol. 2,1962.
10.b. /reproved Oi/-Recovery Fie/d Reports, Societyof Petroleum Engineers, American Institute ofMining, 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 in-stitute of Mining, Metallurgical, and PetroleumEngineers, 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 GasDivision, Austin, Tex., 1974.
11 .b Maximum Efficiency Rate (MER) Hearing Summ-aries, Texas Railroad Commission, The TexasState House Reporter, Austin, Tex., 1975.
11 .C Secondary Recovery Application Summaries,Texas Railroad Commission, The Texas StateHouse Reporter, Austin, Tex., 1973, 1974.
11 .d A Survey of Enhanced Recovery Operations inTexas, Texas Railroad Commission, Oil and GasDivision, Austin, Tex., 1972.
Utah
1. Braunstein, Jules (Ed.), North American Oil andGas Fields, American Association of PetroleumGeologists, Tulsa, Okla., Memoir 24, 1976.
2. Reserves of Crude oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 7974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum 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 ProductiveCapacities, Federal Energy Administration,Washington, D. C., Vol. 2, 1975.
5. A Symposium of the Oil and Gas Fields of Utah,In termounta in Associat ion of Pet ro leumGeologists, 1961.
6. /nternationa/ Oi/ and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part11, 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 PetroleumData System of North America, University ofOklahoma, Norman, Okla.
9. Halbouty, Michael T. (Ed.), Geo/ogy of GiantPetroleum Fields, American Association ofPetroleum Geologists, Tulsa, C)kla., Memoir 14,1970.
10. Plain Facts About Oil and Gas in Utah, UtahGeological and Mineral Survey, 1965.
West
1.
2.
3.
4.
5.
6.
Virginia
Reserves of Crude Oil Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 7974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
Contracts and Grants for Cooperative Researchon Enhancement of Recovery of Oi/ and Gas,U.S. Energy Research and Development Ad-ministrat ion, Wash ington, D. C., ProgressReview Series Nos. 1-5, 1975-76.
Secondary Recovery Operations West Virginiato )anuary 7, 1960, Interstate Cil CompactCommission, Oklahoma City, Okla., 1961.
U.S. Crude Oil Data, 1860-7944, N a t i o n a lPetroleum Council, Washington, D. C., Vol. 1,1970.
Selected articles from )ourna/ of PetroleumTechnology, Oil and Gas )ournal, Oil Daily, Pro-ducer’s Monthly, and World Oil.
C o m m u n i c a t i o n s w i t h S t a t e P e t r o l e u mGeologists.
W y o m i n g
1. Reserves of Crude Oil, Natural Gas Liquids andNatural Gas in the United States and Canada,and United States Productive Capacity as ofDecember 31, 1974, Joint publication by theAmerican Gas Association, the AmericanPet ro leum Ins t i tu te , and the CanadianPetroleum Association, Vol. 29, May 1975.
2. Biggs, Paul and Espach, Ralph H., Petro/eum andNatural Gas Fie/ds in Wyoming, U.S. Depart-ment of the Interior, Bureau of Mines, Pt’ashing-ton, D.C. Bulletin No. 582, 1960.
3. Oil and Gas Resources, Reserves and ProductiveCapacities, 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 andProspective Crude Oil Fields or Reservoirs forHigh Priority Fie/d Testing, Gulf Un ivers i t iesR e s e a r c h C o n s o r t i u m , R e p o r t No. 148,Houston, Tex., 1976.
/nterna(ional Oil and Gas Development, interna-tional Oil Scouts Association, Austin, Tex., Part1[, vol. 44, 1974.
U.S. Crude Oil Data, 7860-7944, N a t i o n a lPetroleum Council, Washington, D. C., Vol. 1,1970.
“Here Are The Big U.S. Reserves,” Oil and Gaslourna/, Jan. 27, 1975, pp. 116-118.
“Enhanced Recovery Production Report,” TheOil and Gas /ourna/, Vol. 74, No. 14, Apr. S,1976, pp. 108-127.
Frick, Thomas C. (Ed.), Petro/eum ProductionHandbook, Society of Petroleum Engineers,American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., Dallas, Tex., Vol. 2,1962.
Field Case Histories, Oi/ and Gas Reservoirs,Society of Petroleum Engineers, American in-stitute of Mining, Metallurgical, and PetroleumEngineers, Inc., Dallas, Tex., SPE Reprint SeriesNos. 4 and 4a, 1974-75.
Society of Petroleum Engineers Symposium on/reproved Oil Recovery, Society of PetroleumEngineers, American Institute of Mining,Metallurgical, and Petroleum Engineers, Inc.,Dallas, Tex., Preprint Series.
W y o m i n g Oil and Gas Fie/ds Sympos;um,Wyoming Geological Association, Caspar,Wyo. 1957, 1961, 1969.
Wyoming 0// and Gas Stat/sties, The WyomingOil and Gas Conservation Commission, Caspar,Wyo., 1975.
Selected art icles from journal of petro/eumTechnology, Oil and Gas )ournal, Oil Daily, Pro-ducer’s Monthly, and Wor/d Oi/.
138 ● Appendix A
Analysis of Reservoirs in Data Base To DetermineAmount and Distribution of Remaining Oil
Distribution of the Original Oil in Place
Reservoirs frequently taper out near theperimeter of the productive acreage. The OTAdata base did not contain data which would ap-proximate variation of thickness or oil saturationwith a real position. For the purposes of this studyit was assumed that 95 percent of the original oilin place was contained in 80 percent of the reser-voir acreage. 2 All enhanced oil recovery (EOR)projects were developed in this “richer” portionof the reservoir. This assumption was imple-mented in individual reservoir calculations by in-creasing the net oil sand in the richer portion ofthe reservoir.
Volume of Oil Remaining
The oil resource for EOR processes is the oilwhich is not recovered by primary and secondarymethods. The OTA data contained estimates ofthe original oil in place as well as the reserves at-tributed to current operations. Reserves wereconsidered to be the maximum attainable fromeach reservoir without application of enhancedrecovery methods. It was assumed that regions
which could be waterflooded economically havebeen or are now under development. Thus, infilldrilling would be considered to accelerate theproduction of known reserves rather than to addnew reserves.
Distribution of the RemainingOil Resource
Two models were used to approximate thedistribution of the oil resource which remains forpotential recovery processes.
Reservoirs With Limited WaterfloodResponse
Reservoirs which were candidates for thermalr e c o v e r y p r o c e s s e s w e r e t h o s e w h e r ewaterflooding has not been applied successfullyover an appreciable portion of the reservoir. Theoil resource at the beginning of thermal recoveryoperations was assumed to be distributeduniformly throughout each reservoir. The averageoil saturation at this point was computed usingequation 1A, which represents a material balanceover the reservoir volume.
where
S 0 2 = material balance, average oil saturationS o i = oil saturation in the reservoir at discov-
eryN =estimated initial oil in place, stock-tank
barrelsN P = ultimate oil recovery by primary and
secondary methods in stock-tank barrelsBoi = oil formation volume factor at initial
pressure. Ratio of volume occupied bythe oil at reservoir conditions to thev o l u m e o f o i l w h i c h w o u l d b erecovered at the surface at stock-tankconditions
BO = oil formation volume factor at the reser-voir pressure which exists when N P
stock-tank barrels are produced.
The OTA data base did not contain values ofB 0 for every reservoir but since reservoir tem-peratures were available the value of BO was setat the value corresponding to thermal expansionat reservoir temperature. Equations 2A and 3Aderived from the correlations of Katz3 were usedto estimate BO:
~R~~search and Development In Enhanced 0;/ Recovery,Final Report, The Methodology, U.S. Energy Research andDevelopment Administration, Part 3 of 3, p. V-4, E R D A77-.?07 1, December 1976.
‘1. W. Amyx, D.M. Bass, a n d R.L. Whit ing, Petro/eumReservoir Engineering p. 429, McGraw Hill Book Company(1 960).
Appendix A . 739
2A
3A
where
API = stock-tank oil gravity in degrees APIT R = reservoir temperature, “F.
There were insufficient data to estimate changesin BO from dissolved gas.
Several large reservoirs in California do nothave uniform oil saturation in all portions of thereservoir. Reservoirs which were known to haveoil saturation distributions were identified bymembers of the Technology Task Force of theNational Petroleum Council (NPC) study. Thesedata were available for the OTA study. However,it was not feasible to subdivide the reservoirs inthe economic model. Subdivision of the reser-voirs would change the price versus ultimaterecovery projections but would not alter the ulti-mate recovery.
Reservoirs Under Natural Water Drive or theWaterflooding Process
The carbon dioxide (CO2 miscible processand the surfactant/polymer process will probablybe applied in reservoirs where waterflooding—either through natural water influx or water injec-tion-has been successful. The entire reservoirvolume is not swept by a waterflood. Conse-quently, there is a distribution of oil saturationwhich varies from essentially initial oil saturationin regions not swept by water to a residual oilsaturation in the volume swept by the water.
The oil recovery models for both CO2 miscibleand surfactant/polymer processes assume thatthe processes will be contacting residual oil insome portions of the volume swept by thewaterflood. It is necessary to estimate thevolume of this region as well as the residual oilsaturation. Although these two parameters arenot known for every reservoir, it is possible todevelop a relationship between them for certainsituations.
The data base contains estimates of the initialoil in place, oil recovered by primary and second-
ary processes, and the formation volume factorsat initiation and end of primary and secondaryrecovery. If these data are considered correct, thevolumetric sweep efficiency and the averageresidual saturation in the region swept by waterare related by equation 4A.
— .
4A
where
E vm = volumetric sweep efficiency of ther
waterflood, fraction of the reservoirswept by the waterflood
s orw = average oil saturation in the reservoirvolume swept by the waterflood
Other terms were defined in equation 1A.
Equation 4A was derived from an overallmaterial balance on the reservoir in which 1 ) allportions of the reservoir are considered hy-draulically connected, 2) regions not swept bythe waterflood are resaturated to the initial oilsaturation at the current reservoir pressure, and 3)the rock pore volume is invariant with pressure.
Neither SO rw nor Evm were available in the database. Estimates of Sorw on a geological andregional basis were made in the NPC study onenhanced oil recovery using the study group’sgeneral knowledge of the reservoirs in the Lewindata base and experience in similar reservoirswhich were not included in the data base. Basedon this knowledge, a residual oil saturation of 20,25, or 30 percent was assigned to each reservoirin Texas, Louisiana, or California which was acandidate for surfactant/polymer or C02 miscibleprocesses.
The Office of Technology Assessment in-vestigated the validity of these estimates throughdiscussion with members of the NPC study groupand review of the technical literature. Additionaldata were obtained from a committee preparing abook on residual oil saturations for the InterstateOil Compact Commission. 4 Personal inquiries
~Personal communicatifm with Lincoln Elkins, November1976.
140 . Appendix A
were made to companies and/or personnel whodid not participate in the selection of specificvalues for the NPC study but who had knowledgeof the properties of reservoirs in the NPC/Lewindata base.
The following conclusions were reached:
●
●
●
●
There are a relatively small number of reser-voirs where estimated values of the residualoil saturation have been confirmed with in-dependent methods of measurement.
Values of the residual oil saturation assignedby the NPC study group are consistent withthe information which was available in thepublic literature and obtained through per-sonal inquiry. Specific reservoirs within aregion are likely to vary from the assignedvalues, but this variation is believed to bewithin the uncertainty of the estimates.
The uncertainty in the residual oil saturationestimates is significant. The uncertainty isprimarily due to inadequate measurementtechniques and limited application of exist-ing methods. As a result, it is not uncom-mon to find technical personnel in differentoperating divisions of the same companywhose estimates of the residual oil satura-tion in a particular reservoir differ by 5saturation percentage points.
Residual oil saturations in the region sweptby water are judged to be known with morecertainty than the volumetric sweep effi-ciency, The OTA study group accepted theNPC assignment of residual oil saturation forthose reservoirs which were also in the NPCbase case. Reservoirs not in this categorywere assigned saturations indicated in tableA-1 .
Two const ra ints were imposed on thevolumetric sweep efficiencies computed fromequation 4A using the residual oil saturations in ta-ble A-1.
The maximum sweep efficiency of awaterflood was considered to be 90 percentof the reservoir volume. If the computed Evm
was larger than 0.9, the value of Evm was setto 0,9 and the value of SORW was computedfrom equation 4A for the reservoir.
Table A-1Average Oil Saturation in the Region Swept by
WaterfloodRegion s orwTexas District 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.20South Louisiana, Offshore Texas Districts
1,2,4,5, and 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.25California, North Louisiana, the balance of Texas, and
all other States. . . . . . . , . . . . . . . . . . . . . . . . . . . . . . 0.30
The minimum volumetric sweep efficien-
cy of a waterflood was considered to be 40
percent in California and 50 percent in allother reservoirs. If the computed EVm w a sless than the minimum value, the appropri-ate minimum was assigned to Evm and the
value of Sorw computed from equation 4A wasassigned to the reservoir.
Consistency of Oil Resource Estimates WithThose Implied by Other Studies
The approach used in the NPC study involvedassignment of both volumetric sweep efficiencyand residual oil saturation for each reservoir. Thisled to overstatement of the resource when theultimate production data were also known.However, ultimate production data were notavailable to the NPC Technology Task Force forevery reservoir in the NPC data base.
The initial oil in place (N) for reservoirs used inthe NPC study was computed by OTA by insert-ing NPC-assigned sweep efficiencies and residualoil saturations in equation 4A. Ultimate productionfor each reservoir was included in the data base sothat the initial oil in place could be computed fromequation 4A. The resulting values of the ini-tial oil in place were significantly different from
values in the data base. Differences were par-ticularly large (>10 percent) in California. Thedifference could be attributed to either over-statement of the initial oil in place or understate-ment of the ultimate production. Informationgained from contacts with oil industry personnelfamiliar with certain reservoirs was used toreevaluate the methods used by Lewin andAssociates, Inc., to determine the initial oil satura-tions. Revisions of this analysis led to the reductionof oil-in-place estimates by 3.5 billion barrels inCalifornia.
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 init ial oi l- in-place esti-
mates in the data base and those computed byusing NPC sweep eff iciencies and residual oi l
saturations in equation 4A. Results extrapolated
to national totals are summarized in table A-2.
The comparison in table A-2 indicates adifference of about 10 percent between esti-mates for the surfactant/polymer reservoirs. Thisis within the range of uncertainty. The differenceapproaches 30 percent for reservoirs which wereC 02 candidates. However, as indicated in thesection on Discussion 01 Results (page 46) inchapter III, the effect on calculated oil recoveryby the CO2 miscible process was minimal.
Table A-2Comparison of initial Oil in Place Computed forEstimates of Sweep Efficiency and Residual Oil
Saturations
Reservoirs in Surfactant/Polymer Economic Evaluation
Original oil in place from OTA database . . . . . . . . . . . . . . . ~ . . . . . . . . . . 51.2 billion barrels
Original oil in place determined frommaterial balance calculations usingNPC sweep efficiency and residualoil saturations . . . . . . . . 46.4 billion barrels
Difference—surfactant/polymer reser-voirs . . . . . . . . . . . . . . . . 4.8 billion barrels
Reservoirs in CO2 Miscible Economic Evaluation
Original oil in place in OTA data base 93. s billion barrelsOriginal oil in place determined from
material balance calculations usingNPC sweep efficiency and residualoil saturations . . . . . . 130.0 billion barrels
Difference-CO 2 miscible reservoirs . . 36.5 billion barrels
Appendix B
Supporting Materials for Oil Recovery ProjectionsFrom Application of Enhanced Recovery
ProcessesPage
TECHNOLOGICAL PROJECTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147Surfactant/Polymer Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 147Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150Composition and Costs of Injected Materials . . . . . . . . . . . . . . . . . . . . . . . . IS3Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
Polymer Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 154Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156Effect of Polymer Flooding on Subsequent Application
of Surfactant/Polymer or Carbon Dioxide Miscible Processes . . . . . . . . . 157Steam Displacement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157
State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 157Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........158Steam Requirements and Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160Sensitivity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161
In Situ Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 162Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164
Carbon Dioxide Miscible . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165State of the Art—Technological Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 165Oil Recovery Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166Carbon Dioxide Costs.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168Results of Carbon Dioxide Cost Calculations . . . . . . . . . . . . . . . . . . . . . . . . 169Calculation Method and Details-Carbon Dioxide Costs . . . . . . . . . . . . . . 171Sensitivity Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174
ECONOMIC MODEL.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175Structure of the Model.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175
Specific Economic Assumptions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176Economic Data-General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178Offshore Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190
Costs That Do Not Vary With Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . 190Cost That Vary With Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191
143
144 . Appendix B
LIST OF TABLES
TableNumber 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 theSurfactant/Polymer Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary of Surfactant Field Tests Being Conducted by Industry WithoutERDA 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 ProcessCarbon 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 WellsIncremental Injection Operating and Maintenance Costs. . . . . . . . . . . . . . . .State and Local production Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .State Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
148
149152153153
154156157160161161
162
163164
164167168168168172172173173
174175175177177178179180182
184186188190190
Appendix B . 145
B-38. Offshore Costs That Do Not Vary by Water Depth . . . . . . . . . . . . . . . . . . . . . 191B-39. Offshore Costs That Vary by Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . . . . 191B-40. Drilling and Completion Cost Bases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192
LIST OF FIGURES
FigureNumber Page
B-1 . Historical Incremental production Therm Recovery-California ... , . . . . . . . . 159B-2. Pipeline Cost Versus Capacity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171B-3. Variable C02 Transportation Costs Versus Pipeline Capacity. . . . . . . . . . . . . 172B-4, Transportation of CO2– Break-Even Analysis . . . . . . . . . . . . . . . . . . . . . . . 173
Th i s append ix p resent s supp lementarymaterials which were used to prepare oil recov-ery projections and to compute the costs to pro-duce enhanced oil. It is organized into two sec-tions, the first describing the technologicalassumptions for each enhanced oil recovery
(EOR) process. For each process the “state of theart” of the technology is assessed. Models used
to compute recoveries and production rates are
Appendix B . 147
presented in detail. Cost data which are specificto a process are documented. Results of calcula-tions not presented in the body of the report aregiven.
The second section describes the economicmodel used in the OTA study. Cost data whichare independent of the process are documentedin this section.
Technological Projections
Surfactant/Polymer Flooding
State of the Art—Technological Assessment
The surfactant/polymer process involves twotechnologies. The first is the art of formulating achemical slug which can displace oil effectivelyover a wide range of crude oil compositions, for-mation water characteristics, and reservoir rockproperties. As used in this section the termchemical slug refers to all injected fluids whichcontain a surfactant mixed with hydrocarbons,alcohols, and other chemicals. Excluded from thisdefinition is alkaline flooding,1 a process in whichsurfactants are generated in situ by reaction ofcertain crude oils with caustic soda.
The second technology is the displacement ofthe injected chemical slug through the reservoir.This technology is governed by economic andgeologic constraints. The cost of the chemicalslug dictates use of small volumes in order tomake the process economically feasible. Thetechnology for displacement of the chemical slugthrough a reservoir relies on controlling the rela-tive rate of movement of the drive water to thechemical slug. Effective control (termed mobilitycontrol) through process design prevents ex-cessive dilution of the chemical slug. If mixedwith displaced oil or drive water, the chemicalslug would become ineffective as an oil-displac-ing agent. Control of the mobility of the chemicalslug or drive water is accomplished by alteringthe viscosities or resistance to flow of these fluidswhen they are formulated. z
NOTE: All references to footnotes in this appendix appearon page 193.
Research to find chemicals which displace oilfrom reservoir rocks has been conducted inGovernment, industry, and university laboratoriesfor the past 25 years. Research activity in theperiod from 1952 to about 1959 was based onthe injection of dilute solutions of surfactantwithout mobility control .-3 Activity peaked withthe advent of each new chemical formulation inthe laboratory and declined following disap-pointing field results. In some tests, surfactantswere injected into reservoirs with no observableresponse. in other tests, the response was sosmal l that the amount of incremental o i lrecovered was almost unmeasurable. The cost ofwhatever incremental oil was produced wasclearly uneconomic.
The period beginning in the late 1950’s andextending into the present is characterized bymajor advances in formulation of the chemicalslug and control of slug movement through areservoir. Several laboratories developed for-mulations based on petroleum sulfonates whichmay displace as much as 95 percent of the oil insome portions of the reservoir which are sweptby the chemical slug.4,5 Addition of water-solublepolymer to drive water has led to mobility con-trol between the drive water and chemical slug.6
Field tests of the different processes have pro-duced mixed results. About 400,000 barrels of oilhave been produced from reservoirs which havebeen previously waterflooded to their economicI imit . 7,8,9 Oil from one test was considered~economic. All other oil was produced under con-ditions where operations were uneconomic.Offsetting these technically successful tests10 areseveral field tests which yielded considerably less
148 ● Appendix B
incremental oil than anticipated. ” 11,12,13 The stateof technology is such that honest differences ofopinion exist concerning the reasons for disap-pointing field test results.14,15
The current ERDA program includes six large-scale, cooperative, field-demonstration tests. Thefields and locations are summarized in table B-1.The first five projects are in fields which havebeen intensively waterflooded. In these tests, theprincipal objectives are to demonstrate the effi-ciency and economics of recovery from a suc-cessfully depleted waterflood using the surfac-tant/polymer process. The Wilmington reservoircontains a viscous oil. An objective of this proj-ect is the development of a surfactant/polymers y s t e m w h i c h w i l l d i s p l a c e v i s c o u s o i leconomically.
Table B-1ERDA Cooperative Field-Demonstration Tests of EOR
Using the Surfactant/Polymer Process
Field Location
El Dorado. . . . . . . . . . . . . . . . . . . . . . . . . . KansasNorth Burbank. . . . . . . . . . . . . . . . . . . . . OklahomaBradford . . . . . . . . . . . . . . . . . . . . . . . . . . . PennsylvaniaBell Creek. . . . . . . . . . . . . . . . . . . . . . . . . . MontanaRobinson . . . . . . . . . . . . . . . . . . . . . . . . . . IllinoisWilmington . . . . . . . . . . . . . . . . . . . . . . . . California
Screening Criteria. —The screening criteria intable 7 of the main text reflect estimates of tech-nological advances in the next 20 years as well ascurrent technology inferred from past and ongo-ing field tests. For example, technological ad-vances in temperature tolerance are projected sothat reservoirs which have a temperature of200° F can have a technical field test in 1985.
The OTA screening criteria coincide withthose used by the National Petroleum Council(NPC)16 with one exception. The OTA data basedid not contain adequate water-quality data forall reservoirs. Consequently, reservoirs were notscreened with respect to water quality.
The screening criteria were reviewed prior toacceptance. The review process included infor-mal contacts with personnel who did not partici-pate in the NPC study and an examination of thetechnical literature. The principal variables arediscussed in the following sections.
The screening criteria are judged to be repre-sentative of the present and future technologicallimits. As discussed later, it is recognized thatpermeability and viscosity criteria have economiccounterparts. However, the number of reservoirseliminated as candidates for the surfac -tant/polymer process by either of these screeningcriteria was insignificant.
Current Technology (1976).--Current limits oftechnology are reflected by field tests whichhave been conducted or are in an advanced stageof testing. These are summarized in table B-2.17
Field tests are generally conducted in reservoirswhere variation in rock properties is not largeenough to obscure the results of the displace-ment test due to reservoir heterogeneities. Thesereservoirs tend to be relatively clean sandstonewith moderate clay content. A crude oil viscosityless than 10 centipoise is characteristic of mostsurfactant/polymer field tests. Reservoir tem-peratures range from 55° F to 169° F.
Reservoir Temperature.—Surfactants andpolymers are available which tolerate tem-peratures up to about 170° F. Research onsystems which will be stable at 200° F is under-way in several laboratories. The rate of tech-nological advance in this area will probably berelated to the success of field tests of the surfac-tant/polymer process in lower-temperature reser-voirs . Successful f ie ld tests wi l l s t imulatedevelopment of fluids for higher-temperaturedeeper reservoirs as potential applications inthose reservoirs become a reality. The assumedtiming of technological advances in temperaturelimitations appears attainable.
Permeability and Crude Oil Viscosity. -Per-meability of the reservoir rock is both a tech-nological and an economic factor. The surfac-tant/polymer process will displace oil from lowpermeability reservoir rock.18 A minimum per-meability based on technical performance of theprocess has not been established. Low per-meability may correlate with high-clay content ofthe reservoir rock and corresponding high-surfac-tant losses through adsorption. The surfactantslug must be designed so that its integrity can bemaintained in the presence of large adsorption
Table B-2Summary of Surfactant Field Tests Being Conducted by
Industry Without ERDA Assistance
Process Area Porosity Perm. Depth Reservoir Oil Temp. SalinityField State County Operator Type* (Acres) Start Pay (%) (Md) (ft) o APl) (Cp) (°F) (ppm) Comment
0.75-40
4.30.75-45
10
1-160
0.65
8.231
0.8
209
1.25
2.02.52.52.5S.o
5.810.0
2.51.7
200
82
69
103
50052
75
53
*400
2,50090
457394
8793
950450
1,000 35-36 7 72 HPW 18,150 ppm 6 testsTDS (1 19-R)
11 /62
5/7012/68
5/71
11/67
9/70
Robinson 20
18
19
21
22.919.2
20
22
21
331821.724.2
14.817.13126
Robinson Ill. Crawford Marathon MSF
MSFMSF
MSF
Aqueous
AqueoussolutionSOFSF
SF
LTWF
AqueoussolutionSFMSFSFSFSF
LTWFSFLTWFSF
MarathonPennzoii
Aux VasesBradford
3,0001,860
Ill.Bingham Pa. McKean 5
4.5
4
68 2,800 Cl – 2 tests
600 40 55Goodwill Pa. WaxyenHill
Benton Ill. Franklin
Quaker St. First Venongo
86 77,000 ppm TDS 2 testsShell Tar Springs 2,100
Est.9595114
64,000 Cl –
104,000 TDS54,000 cl–7,700 TDS,20 ppm fractured,CA+ Mg
Exxon ChesterCypressBluff CreekSecondWall CreekUpperCypressGunsight
1,460 4Loudon Ill.
8/698/73
11 /73
7/73
4.35.6
1,8703,100
3734
Higgs Unit Tex. JonesBig Muddy Wyo. Converse
UnionConoco
37Griffin Ind. GibsonConsol.Wichita Tex. WichitaCo. RegularBorregos Tex. Kleberg
2,400Conoco
2.2 89 160,000 TDS1,750 42Mobil
33,000 TDSmid60’s
Frio 5,000 42 0.4 165Exxon
20,000 TDSJacksonKirkwoodFlappenCisco
2,2701,5001,9001,200
3638:39
3827
1.65.5
12272
Guerra Tex. StarBridgeport Ill. LawrenceSayles Tex. JonesMontague Tex. MontagueLoma NoviaTex. Duval
SunMarathonConocoConocoMobil
9/69/63/63
mid60’s4/741 /756J741/75
150,000 TDS4% kaolinitc
5.5% montmorillonite40,000cl–2,457 TDS60,000Cl –
1,017 Ca++ and Mg++
3.60.80.717
0.8516516960
TexacoAmocoMobilTexaco
U. BenoistMuddy J.41AAlmy
1,7506,2505,700
700
38343226
Salem Ill. MarionSloss Nebr. KimballWest RanchTex. JacksonLa 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 littleoil in slug; MSF–micellar surfactant flood; SOF–normally considered “oil external” chemical slug; SF and LTWF–surfactint flood and low-tension waterflood normally similar toaqueous systems.
Source: Enhanced 0// Recovery, National Petroleum Council, December 1976, p. 97.
150 . Appendix B
losses. As a result, larger slugs or higher con-centrations may be needed with correspondingincreases in costs.
Permeability, fluid viscosities, well spacing,and maximum injection pressure affect the rate atwhich a chemical slug can displace oil from areservoir. Low permeability translates to low dis-placement rates or increased well density tomaintain a specific rate. Both lead to higher proc-ess costs.
The same reasoning applies to crude oilviscosity. As viscosity increases, displacementrates decrease or well density increases. Mobilitycontrol in the surfactant/polymer process is at-tained by increasing the viscosities of the chemi-cal slug and the drive water. Both of thesechanges require addition of expensive constit-uents to these fluids. Therefore both permeabilityand viscosity are constrained by economics.
It is known from laboratory tests that oil recov-ery by the surfactant/polymer process is a func-tion of displacement rate. For example, more oilis recovered at an average displacement rate of 5ft per day than at the rate of 1 ft per day19 whichexists in a typical reservoir. Rate effects in fieldsize patterns may be revealed in the Marathon-ERDA commercial demonstration test.20
Water Quality .-Composition of the formationwater i s a cr i t ical var iable in the surfac-tant/polymer process. Fluids under field tests cantolerate salinities of 10,000 to 20,000 ppm withmoderate concentrations of calcium and mag-nesium, although reservoirs containing low-salinity flu ids are preferred. Some field tests are inprogress in which preflushes are used to reducesalinity to levels which can be tolerated by theinjected chemicals. 21,22 However, in one largefield test23 the inability to attain a satisfactorypreflush was considered to be a major contribu-tor to poor flood performance. Potential short-ages of fresh water for preflushing and uncertain-ty in effectiveness of preflushes have stimulatedresearch to improve salinity tolerance.
Technological advances were projected in theNPC study which would increase the salinitytolerance from 20,000 ppm in 1976 to 150,000ppm in 1980 and 200,000 ppm in 1995. The OTAtechnical screen does not contain a similar
scenario because salinity data were not availablefor all the reservoirs in the OTA data base. It doesnot appear that results would have been affectedappreciably if the data were available in the database to schedule technological advances insalinity tolerance.
Rock Type. —The surfactant/polymer processis considered to be applicable to sandstone reser-voirs. Carbonate reservoirs are less attractive can-didates because 1 ) the formulation of compatiblefluids is more difficult due to interaction withcalcium and magnesium in the rocks; 2) carbon-ate reservoirs frequently produce through small-and large-fracture systems in which maintenanceof an effective surfactant slug would be difficult;and 3) there is a consensus among technical per-sonnel that the C02 miscible displacement proc-ess is a superior process for carbonate reservoirs.
Reservoir Constraints. —Reservoirs with largegas caps which could not be waterflooded eitherby natural water drive or water injection are likelyto be unacceptable. Also, reservoirs which pro-duce primarily through a fracture system fall inthe same category. However, there is thepossibil ity of technological developments 24
which would restrict flow in the fracture systemand perm t displacement of the surfactant slugthrough the porous matrix.
Oil Recovery Projections
The surfactant/polymer process is applied in ar e s e r v o i r w h i c h h a s b e e n p r e v i o u s l ywaterflooded, There are different opinionsamong technical personnel concerning thevolume of the reservoir which may be swept bythe process. Some consider that the sweptvolume will be less than the volume swept by thewaterflood, while others envision more volumeswept by the surfactant/polymer process. Thereasoning behind these viewpoints is summa-rized in the following subsections.
Swept Volume Less Than Water flood Sweep.—
Residual oil saturations and volumetric sweepefficiencies attributed to waterflooding are fre-quently the result of displacing many porevolumes of water through the pore space. In con-trast, the surfactant/polymer process can be ap-proximated as a 1- to 2-pore volume process
which may lead to a smaller fraction of the reser-voir being contacted by the surfactant/polymerprocess.
Many reservoirs are heterogeneous. It can bedemonstrated that heterogeneities in the verticaldirection of a reservoir which have relativelysmall effect on the sweep efficiency of awaterflood may have large effects on the sweepefficiency of the surfactant/polymer process.25
For instance, in a layered reservoir it may not bepossible to inject enough surfactant into all layersto effectively contact the regions which werepreviously waterflooded.
Surfactant/Polynmer Swept Volume Outside ofWaterflood Region. —The region outside of thevolume swept by the waterflood contains a highoil saturation. in many surfactant processes, theviscosity of the injected fluids is much higherthan water used in the previous waterflood. Thiscould lead to increased volumetric sweep effi-ciency for the surfactant/polymer process.D a v i s 26 has presented data from a Maraflood T M
oil recovery process test in the Bradford ThirdSand of Pennsylvania. An increase of 7 to 10 per-cent in the volumetric sweep efficiency for thesurfactant process over the previous waterfloodwas indicated in his interpretation of the data.
OTA Model.-The OTA model is based on theassumption that the region contacted by the sur-factant/polymer process in most reservoirs is theregion swept by the previous waterflood. Thesurfactant/polymer process displaces oil from thepreviously water-swept region by reducing theoil saturation following the waterflood (Sorw) to alower saturation, termed SOf, which representsthe residual oil saturation after a region is sweptby the surfactant/polymter process. The oil recov-ery using this representation of the process wascomputed using equation 1 B for each patternarea,
B.
where
Npc
= oil displaced bystock-tank barrels
A p = 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 volumewhich is pore space
E vm = fraction of the reservoir volume whichwas contacted by water and surfac-tant/polymer process determined bymaterial balance calculations
BO = ratio of the volume of oil at reservoirtemperature and pressure to the volumeof the oil recovered at stock-tank condi-tions (60° F, atmospheric pressure)
Residual oil saturations left by the chemicalflood (SOf ranging from 0.05 to 0.15 have beenreported in laboratory 27,28 and field tests. 29 Avalue of 0.08 was selected for the OTA computa-tions.
T h e r e s i d u a l o i I s a t u r a t i o n f o l l o w i n gwaterflood (SOrw for the high-process perform-ance case was the oil saturation corresponding tothe particular geographic region in table A-1modified by the material balance calculation asdescribed in appendix A, in the section on Dis-
tribution of (the Remaining Oil Resource on page139. In the low-process performance model, theresidual oil saturations following waterflood(SORW) were reduced by 5 saturation percent fromthe values in table A-1. This caused a decrease inrecoverable oil which averaged 28.6 percent forall surfactant/polymer reservoirs. Due to themethod of analysis, the process performance of asmall number of reservoirs was not affected bythis saturation change. Some reservoirs whichhad 90-percent volumetric sweep imposed bythe material balance discussed on page 139 forthe high-process performance case also had 90-percent volumetric sweep efficiency under low-process performance.
Pattern Area and Injection Rate.—Each reser-voir was developed by subdividing the reservoirarea into five-spot patterns with equal areas. Thesize of a pattern was determined using the pro-cedure developed in the NPC study.30 A patternlife of 7 years was selected. Then, the patternarea and injection rates were chosen so that 1.Sswept-pore volumes of fluids could be injectedinto the pattern over the period of 7 years. Therelationship between pattern area and the injec-
tion rate is defined by equation 2B.
—.
152 . Appendix B
injection rate, barrels per dayporositythickness, feetpattern area, acres
Maximum pattern area was limited to 40 acres.
Injection rates were constrained by two condi-tions. In Texas, California, and Louisiana, it wasassumed that maximum rates were limited bywell-bore hydraulics to 1,000 barrels per day,1,500 barrels per day, and 2,000 barrels per day,respectively. Rate constraints in the reservoirwere also computed from the steady-state equa-tion for single-phase flow in a five-spot patterngiven in equation 3B. The viscosity of the surfac-tant/polymer slug was assumed to be 20 timesthe viscosity of water at formation temperature.The lowest injection rate was selected. otherparameters are identified after the definition ofthe equation.
completion of wells and installation of surfacefacilities were done in the first 2 years. The sur-factant slug was injected during the third yearwith the polymer injected as a tapered slug fromyears 4 through 6. The oil displaced by the sur-factant/polymer process as computed from equa-tion IB was produced in years 5 through 9according to the schedule in table B-3.
Table B-3Development of a Five-Spot Pattern
Surfactant/Polymer Process
Year of Annual oil productionpattern % of
development Activity incremental recovery
1
2
3
456
3B
where
i = injection rate, barrels per dayk = average permeability, millidarciesh = average thickness, feetAP = pressure drop from injection to produc-
ing well, taken to equal depth/2
µeff = effective viscosity of surfactant/polymerslug, or 20 times viscosity of water atreservoir temperature
In = natural logarithmd = distance between the injection and pro-
duction well, feet, or 147.58 ~~A P = pattern area, acres
RW = radius of the well bore
Development of Pattern.-Development ofeach five-spot pattern took place according tothe schedule shown in table B-3. Drilling and
789
Drill and completeinjection wells. Re-work productionwell.
I n s t a l l s u r f a c eequipment.
Inject surfactantslug.
Inject polymer slugwith average con-centration of 600ppm. Polymer con-c e n t r a t i o ntapered.
Injection of brine.
o
0
0
01026
322012
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 volumePolymer Bank, . . . 0.5 swept pore volume
● The swept pore volume of a pattern is defined by equa-tion 4B.
V p
= Ev~ AP h o (7,758) 4B
= volume of pattern swept bythe surfactant/polymer proc-ess, barrels
The volumes of surfactant and polymer approxi-mate quantities which are being used in fieldtests. Volume of the surfactant slug needed tosweep the pattern is affected by adsorption ofsurfactant on the reservoir rock. The slug of 0.1swept-pore volume contains about 36 percentmore sulfonate than needed to compensate forloss of surfactant that would occur in a reservoirrock with porosity of 25 percent and a surfactantretention of 0.4 mg per gm rock. The OTA database contained insufficient information to con-sider differences in adsorption in individual reser-voirs. The effect of higher retention (and thushigher chemical costs) than assumed in the ad-vanced technology cases is examined in the high-chemical cost sensitivity runs.
Composition and Costs of Injected Materials
The surfactant slug for all cases except the cur-rent technology case contained 5-wt percentpetroleum sulfonate (100-percent active), 1-wtpercent alcohol, and 10-volume percent leasecrude oil. In the current technology case, the sur-factant slug contained 20 percent lease crude oil.The concentration of the polymer solution was600 ppm for reservoir oils with viscosities lessthan or equal to 10 centipoise. Concentration ofpolymer was increased with viscosity for oilsabove 10 centipoise according to the multipliergiven in equation 5B.
Concentration Multiplier =(1 +32- API
) 5B10
Equation 5B is valid for API gravities greater than10. A polysaccharide polymer was used.
Table B-4 summarizes surfactant slug andpolymer costs as a function of oil price. Costs ofsurfactant and alcohol based on data from theNPC study are presented in table B-5.
Net Oil, -Projected oil recovery from the sur-factant/polymer process was reported as net bar-rels. The oil used in the surfactant slug and an
Appendix B ● 153
estimate of the oil equivalent to the surfactantwas deducted from the gross oilproduction.
Table B-4Chemical Coats
Surfactant
slug cost -10-percent
Oil price lease crude$/bbl $/bbl
10 . . . . . . . . 7.6915 . . . . . . . . 9.7320 . . . . . . . . 11.7425 . . . . . . . . 13.78
to determine net
Surfactant
slug cost -20-percentlease crude
$/bbl
8.6911.2313.7416.28
‘Polymer cost*polysaccharide
$/lb
2.302.402.492.58
● Source: Enhanced Oil Recovery, National Petroleum Council,December 1976, p. 100.
Table B-5Component Costs*
Surfactant costOil price 100-percent active Alcohol cost
$/bbl $/lb $/lb
5 . . . . . . . . 0.29 0.1310 ....., . . 0.35 0.1615 . . . . . . . . 0.43 0.2020 . . . . . . . . 0.51 0.2325 . . . . . . . . 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 thelow- and high-process performance models todetermine sensitivity to changes in chemicalcosts. Cost sensitivity analysis was accomplishedby altering the volumes of surfactant andpolymer used in the displacement process. Thelow-chemical cost case assumes a 40 percentreduction in the volume of the surfactant slugwhile the high-chemical cost case assumes that40 percent more surfactant and 50 percent more
polymer would be required than used in thebase-chemical cost case.
154 . Appendix B
Ultimate recoveries of oil using the surfac-tant/poIymer process with high- and low-chemi-cal cost assumptions are summarized in table B-6for the advancing technology cases. With highchemical costs, there would be a negligiblevolume of oil produced at world oil price. Thecombination of both high-process performanceand oil prices approaching the alternate fuelsprice would be needed to offset high chemicalcosts if the surfactant/polymer process is to con-tribute substantial volumes of oil to the Nation’sreserves.
Low chemical costs have the largest impact onthe low-process performance case where sub-stantial increases in ultimate recovery could oc-cur at both upper tier and world oil price. Theeffect of lower chemical costs on the high-proc-ess performance case is to reduce the oil price re-quired to call forth a fairly constant level of pro-duction. For example, if chemical costs are low,the ultimate recovery projected at alternate fuelsprice is about the same as ultimate recovery atupper tier price. However, low chemical costshave a low probability of occurring unless a ma-jor technological breakthrough occurs.
The sensitivity analyses in this study weredesigned to bracket the extremes which might beexpected assuming technology develops aspostulated in the advancing technology cases.There are other process and economic variables
which would beindividual field
considered in the analysis of anproject which could not be
analyzed in a study of this magnitude.
Polymer FloodingState of the Art—Technological Assessment
The concept of mobility control and its rela-tionship to the sweep efficiency of a waterfloodevolved in the early to mid-1950’s.31,32 It wasfound that the sweep efficiency could be im-proved if the viscosity of the injected watercould be increased. Thickening agents were ac-tively sought. Numerous chemicals were evalu-ated but none which had economic potentialwere found until the early 1960’s.
During this period, development in the fieldof polymer chemistry provided new moleculeswhich had unique properties. High-molecularweight polymers were developed which in-creased the apparent viscosity of water by factorsof 10 to 100 when as little as 0.1 percent (by
weight) was d i s so lved in the water . The f i r s t
polymers investigated were partially hydrolyzed
polyacrylamides with average molecular weight
ranging from 3 million to 10 million.
The discovery of a potential low-cost methodto “slow down” the flow of water and improvesweep efficiency of the waterflood led to manyfield tests in the 1960’s. Nearly all field tests used
Tabie B-6Surfactant/Polymer Process-Uitimate Recovery
Summary of Computed Results-Process and Economic Variations(billions of barrels)
Advancing technology casesOil 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 f ield tests had been init iated 33 a n d b y
1975 the number of polymer field tests exceeded100. Although most f ield tests were relatively
small, two were substantial. These were the Pem-
bina 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. Suc-cessful use of polymers has been reported inseveral projects 3536 where incremental oilabove that expected from waterflooding hasbeen produced. At least 2 million barrels of oilhave been attributed to polymer flooding fromsuccessful projects. 37 Continuation of some proj-ects and expansion of others indicate commercialoperation is possible. However, polymer floodinghas not been widely adopted. Many field testsyielded marginal volumes of oil. Response topolymer flooding was not significant in either thePembina Flood or the Wilmington Flood.
Reasons for mixed field performance are notcompletely understood. polymer floods initiatedearly in the life of a waterflood are more likely tobe successful than those initiated toward the endof a project. Reservoirs which have beenwaterflooded to their economic limit have notresponded to polymer flooding as a tertiary proc-ess. Recent research 38 has demonstrated that par-tially hydrolyzed polyacrylamides degrade whensheared under conditions which may be presentin injection well bores. Thus, it is not certain inprevious field tests that a reservoir flooded withpolymer solution was contacted with the samefluid used in laboratory tests.
Further research and development produced apolysaccharide biopolymer 39 which has im-proved properties. Polysaccharides are relativelyinsensitive to mechanical shear and have hightolerance to salt, calcium, and magnesium ions.Solutions containing polysaccharides must befiltered prior to injection to remove bacterialdebris which may plug the injection wells. Sincethe polysaccharide is a product of a biologicalprocess, it is susceptible to further biological at-tack in the reservoir unless adequate biocide isincluded in the injected solution. Few field testshave been conducted using polysaccharidepolymers.
polymer flooding has economic potentialbecause it uses materials which are relatively lowcost. Field application is similar to waterfloodingwith minor changes to permit mixing and properhandling of the polymer solutions. Widespreaduse by most operators would be possible withoutextensive technical support. Performance ofpolymer floods cannot be predicted accurately,and well-documented demonstration projectssuch as those being conducted in the N. BurbankStanley Stringer40 and the Coalinga41 fields are es-sential to the widespread use of polymer flood-ing.
Screening Criteria. --Polymer flooding is not apotential process for all reservoirs which can bewaterflooded. Geologic constraints, properties ofthe reservoir rock and oil, and stage of thewaterflood are all critical parameters. Reservoirswhich produce primarily through large fracturesystems and reservoirs with large gas caps whichcould not be waterflooded were excluded. Inthese reservoirs, the polymer slug is likely tobypass much of the reservoir rock. A permeabilityconstraint of 20 millidarcies was selected. Whilethe lower limit of permeability is not known pre-cisely, there is a range of permeabilities wherethe polymer molecules are filtered out of the in-jected solution and cannot be propagatedthrough a reservoir. Selection of the correctmolecular weight distribution of the polymerreduces the minimum permeability.
Field experience indicates that polymer floodshave not been successful when applied after thewaterflood has been completed. Reservoirs underwaterflood which have volumetric sweep effi-ciency greater than 80 percent and low residualoil saturations are not good polymer candidates.Consequently, reservoirs with no ongoingwaterflood and reservoirs with high volumetricsweep efficiency and low oil saturation werescreened from the polymer flooding candidates.
Water quality was not used to screen reser-voirs because salinity and divalent ion content donot determine whether a reservoir can be floodedwith polymer solutions. These parameters do in-dicate the type of polymer which may be used.For example, par t ia l l y hydro lyzed po ly -acrylamides are frequently preferred in low-salinity systems. Polysaccharides are relatively in-
-— — — . —
156 . Appendix B
sensitive to salinity and may be required in orderto flood successfully a reservoir which containshigh-salinity fluids.
The use of polymers is limited by temperaturestability. Proven temperature stability is about200° F. This limit is expected to be 250° F by1995. The same temperature limits used in thesurfactant/polymer process screen apply topolymer flooding.
Crude oil viscosity was the final screeningparameter. Field tests suggest an upper limit ofabout 200 centipoise. However, there is littlepublished literature which shows that polymerso lu t ions w i l l not d i sp lace o i l a t h igherviscosities. Other factors enter in the determina-tion of the upper viscosity limit. Steam displace-ment and in situ combustion are consideredsuperior processes because both can potentiallyrecover more oil. As crude oil viscosity increases,higher polymer concentrations are required tomaintain mobility control. Oil-displacement ratesdecline for a fixed pattern size. Both of these fac-tors operate in the direction of reducing the rateof return at fixed oil price or requiring a higher oilprice to produce a fixed rate of return. Then thecrude oil viscosity becomes an economic factorrather than a technical factor.
Most reservoirs which were polymer candi-dates yielded more oil when developed as C02,surfactant/polymer, steam, or in situ combustioncandidates. Thus, the OTA method of processselection, i.e., maximum oil if profitable at 10percent rate of return and world oil price, led toassignment of the poorest reservoirs to polymerflooding.
Oil Recovery Projections
Estimates of oil recovery from the applicationof polymer-augmented waterflooding to reser-voirs which satisfied the technical screen weremade using an empirical model. Incrementalrecovery for the low-process performance casewas assumed to be 2.5 percent of the original oilin place. The incremental recovery for the high-process performance case was assumed to be 3percent of the original oil in place. These esti-mates closely approximate recent projections forthe N. Burbank Stanley Stringer and Coalinga field
demonstration tests. They also approximate theaverage performance of published field tests.42
Each reservoir was developed on 40-acre spac-ing with a ratio of 0.5 injection well per produc-tion well. Injection of polymer was continuedover the first 4 years of the project at a rate of0.05 pore volumes per year. Average polymerconcentration was 250 ppm. The polymer usedwas polysaccharide. Costs of polymer at variousoil prices were identical to those used for the sur-factant/polymer process (table B-4).
The recoverable oil was produced over an 11-year period according to the schedule in tableB-7.
Table B-7Production Schedule
for Polymer-Augmented Waterflood
Incremental oilYear percent of total
1-2 . . . . . . . . . . . . . . . . . . . . . . .3 . . . . . . . . . . . . . . . . . . . . . . . .4 . . . . . . . . . . . . . . . . . . . . . . . .5 . . . . . . . . . . . . . . . . . . . . . . . .
o5
102020151010
55
Total. . . . . . . . . ., . . . . . . . 100
Sensitivity Analyses
The effects of changes in polymer costs and/orvolumes were examined for low- and high-polymer costs for both low- and high-processperformance cases. Bases for cost variation were+/- 25 percent change in polymer cost. Results ofthe economic evaluations are presented in tableB-8.
There is essentially no effect of chemical costson oil production from polymer flooding at theupper tier, world oil, and alternate fuels prices.The sensitivity analyses show that uncertainty inprocess performance is larger than uncertaintiesintroduced by chemical costs.
Appendix B . 757
Table B-8Polymer-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 casesoil 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 SubsequentApplication of Surfactant/Polymer or CarbonDioxide Miscible Processes
The OTA analysis assumes a single processwould be applied to a reservoir. The possibilityof sequential application of two processes wasnot analyzed. Some reservoirs assigned to thesurfactant/polymer process or the C02 miscibleprocess would also be economic (rate of returngreater than 10 percent at world oil price) aspolymer floods. However, the decision rules forprocess assignment placed these reservoirs in theprocess which yielded the largest ultimate recov-ery.
One concern caused by this assignment pro-cedure was whether or not the low costs and low fi-nancial risk from the polymer projections wouldcause operators to use polymerflooding as the finalrecovery process for a reservoir, precluding use ofmethods which potentially recover more oil.
The principal displacement mechanism inpolymer flooding is an increase in the volume ofthe reservoir which is swept by the injected fluid.No reduction in residual oil saturation over thatexpected from waterflooding is anticipatedbecause the viscosities of the oils in these reser-voirs are low enough to make the residual oilsaturations relatively insensitive to the viscosityof the displacing fluid.
A successful polymer flood in the OTA high-process performance would recover 3 percent ofthe original oil in place. This corresponds roughlyto improved volumetric sweep efficiencies of 2to 7 percent. Both OTA models for surfac-tant/polymer and CO2 miscible processes arebased on recovery of the residual oil from somepercentage of the volume displaced by the pre-ceding waterflood. Polymer flooding increasesthis contacted volume. Slightly more oil wouldbe recovered from reservoirs which had beenpolymer flooded prior to surfactant flooding orC 02 flooding if the OTA models of these dis-placement processes are substantially correct.Therefore, the application of polymer floodingwill not prevent subsequent surfactant/polymeror C02 floods under the conditions postulated inthe OTA study.
Finally, polymer flooding prior to surfac-tant/polymer flooding has been proposed as amethod to improve volumetric sweep efficiencyby increasing the flow resistance in more permea-ble paths in the reservoir.43
Steam Displacement
State of the Art—Technological Assessment
Steam displacement is a process which has pri-marily evolved in the last 10 to 15 years.
158 . Appendix B
Development of the process was motivated bypoor recovery efficiency of waterfloods in reser-voirs containing viscous oil and by low producingrates in fields which were producing by primaryenergy sources. Most of the development oc-curred in California and Venezuela, where largevolumes of heavy oil are located. Steam displace-ment has potential application in heavy oil reser-voirs in other oil-producing States.
Large-scale field tests of steam injection beganin the late 1950's 44,45 with field testing of hotwater injection underway at the same time46,47,48
in an attempt to improve the recovery efficiencyof the conventional waterflood. Early steam andhot water injection tests were not successful. in-jected fluids quickly broke through into the pro-ducing wells, resulting in low producing rates andcirculation of large volumes of heated fluids.
The process of cyclic steam injection was dis-covered accidentally in Venezuela in 19s9 andwas developed in California. 49 Cyclic injection ofsmall volumes of steam into producing wellsresulted in dramatic increases in oil production,particularly in California where incremental oildue to cyclic steam injection was about 130,000barrels per day in 1968.50 By 1971 about 53 per-cent of all wells in California had been steamedat least once.
Cyclic steam injection demonstrated that sig-nificant increases in production rate could be ob-tained by heating the reservoirs in the vicinity ofa producing well. However, the process is pri-marily a stimulation process because naturalreservoir energy sources like solution-gas drive orgravity drainage cause the oil to move from thereservoir to the producing well, Depletion of thisnatural reservoir energy with repeated applica-tion of cyclic steam injection will diminish thenumber of cyclic steam projects. Many of theseprojects will be converted to steam displace-ment.
The success of the steam displacement proc-ess is due to the high displacement efficiency ofsteam and the evolution of methods to heat areservoir using steam. Development of the steamdisplacement process in the United States can betraced to large-scale projects which began in theYorba Linda Field in 196051 and the Kern RiverField in 1964.52 Estimates of ultimate recoveries
(primary, secondary, cyclic steam, and steam dis-placement) from 30 to 55 percent of the originaloil in place have been reported for several fields.
A comparison 53 of trends in incremental oilproduction from cyclic steam and steam injectionfor California is shown in figure B-1. Cyclic steaminjection is expected to decline in importance asnatural reservoir energy is depleted. Productionfrom steam displacement could increase as cyclicprojects are converted to continuous steam injec-tion. The rate of conversion will be controlled byenvironmental constraints imposed on exhaustemissions from steam generators. Incremental oilfrom steam displacement will be limited to110,000 barrels per day in California, the levelwhich currently exists, unless technological ad-vances occur to reduce emissions.
Commercial steam-displacement projects arealso in operation in Wyoming,54 Arkansas, 55 andTexas.56 A large portion of the incremental oilnow produced by application of EOR processes isproduced by the steam displacement process.
Screen/rig Criteria. —Steam displacement wasconsidered applicable in reservoirs which werelocated at depths between 500 and 5,000 feet.The upper depth limitation was imposed in orderto maintain sufficient steam injection pressure.The lower depth of 5,000 feet is determined bywell-bore heat losses in the injection wells. Atdepths approaching 5,000 feet, heat losses canbecome excessive even with insulated injectionstrings. In addition, as depth increases the injec-tion pressure increases, but the fraction of the in-jected fluid which is condensable decreases.Reduction in displacement efficiencies is ex-pected to occur under these conditions.
T h e s e c o n d s c r e e n i n g c r i t e r i o n w a st ransmi s s ib i I i t y . The t ransmi s s ib i l i t y (pe r -meability x thickness/oil viscosity) is a measureof the rate that the oil moves through a reservoirrock. A transmissibility of about 100 millidarcyfeet/centipoise is required for steam and hot-water injection processes in order to keep heatlosses from the reservoir to overlying and un-derlying formations from becoming excessive. ST
Oil Recovery Projections
Recovery Models.—Although steam displace-ment 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 ap-plied to an entire reservoir. The OTA data base aswell as the Lewin data bases used in the NPC andERDA reports contained little information onreservoir variability. Review of the technicalliterature and personal contacts with companiesoperating in fields with major steam displace-ment projects revealed considerable variability inthickness and oil saturation. It became apparentthat most steam displacement projects werebeing conducted in the best zones of a reservoir,where oil saturations were higher than theaverage values in the data base. Thus, OTA con-cluded that empirical recovery models based onthe results of these displacement tests could notbe extrapolated to poorer sections of larger reser-voirs with the available information. Subdivisionof several large reservoirs into smaller segmentsof different properties as done in the NPC studywas considered, but could not be done with theavailable computer program.
Recovery models were developed by OTA toestimate the recovery based on development ofthe 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 therecovery from poorer sections will be overstated.However, this approach was preferable to over-statement of recovery caused by applying empiri-cal recovery models from the better zones58 t oother intervals and areas of a reservoir, or ap-plication of recovery adjustment factors to ex-trapolate single-pattern performance to total-project performance. 59
Each reservoi r with mult ip le zones wasdeveloped zone by zone. The technology neces-sary to complete each zone selectively wasassumed to evolve through research anddevelopment. The average thickness per zonewas determined by dividing the net thickness bythe number of zones. Two displacement modelswere used based on the thickness of the zone.Single zone reservoirs were handled in the sameway-according to thickness of the zone.
High-Process Performance Case.—Zone Thick-ness Less Than or Equal to 75 Feet. -Gross oilrecoverable by primary and secondary produc-tion 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. –Oilzone, 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 verticalAreal 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 spacingwas increased to 5 acres. Gross oil displaced bysteam was 80 percent of the amount estimatedfor the high-process performance case.
Timing of Production. —The incremental oilfrom the steam-displacement process was pro-duced according to the production schedule intable B-9.
Table B-9Production Schedule for
Steam Displacement Process
Annualincremental oil
Year percentage total
1-2 . . . . . . . . . . . . . . . . . ~ ~ ~ ~€ . 03 12. . . . . . . . . . . . . . . . . . . . . . . .4 . . . . . . . . . . . . . . . . 225 : : : : : : : : . . . . . . . . . . . . . . . . 226 . . . . . . . . . . . . . . . . . . . . . . . . 207 . . . . . . . . . . . . . . . . . . . . . . . . 148 . . . . . . . . . . . . . . . . . . . . . . . . 10
Total . . . . . . . . . . . . . . . . . . 100
The same schedule was used for low- andhigh-process performance models.
Steam Requirements and Costs
Steam requirement was 1 pore volume basedon net heated thickness. That is the volume oc-cupied by the combined steam and hot waterzones considering the areal sweep efficiency tobe 100 percent. Zones with thicknesses less thanor equal to 75 feet were assumed to be heated inthe entire vertical cross section. Steam was in-
jected over a 5-year period beginning in the thirdyear of field development at the rate of 0.2 porevolume per year.
Lease crude was used as fuel for the steamgenerators. Twelve barrels of steam were pro-duced per barrel of lease crude consumed. Thefull cost of the lease crude was charged as anoperating cost to the project. Oil consumed asfuel was deducted from the gross production toobtain the net production. Cost of steam genera-tion in addition to the fuel charge was $0.08 per
barrel of steam generated to cover incremental
operating and maintenance costs for the genera-
tor and water treatment.
Other Costs. —The costs of installed steamgeneration equipment were scaled from a 50million Btu per hour steam generator costing$300,000 .60 A 1 million Btu per hour unit wasassumed to generate 20,000 barrels of steam(water equivalent) per year. The number (possi-bly fractional) of generators required per patternwas determined from the pore volume of the pat-tern. Since the steam generator life was longerthan pattern life, it was possible to use the samegenerator on two patterns in the field. The cost ofmoving a generator was assumed to be 30 per-cent of the initial cost. Thus the effective cost forthe steam generator per pattern was 65 percentof the initial generator cost.
Reservoi rs with mult ip le zones requiredworkovers in production and, injection wells toclose the zone just steamed and open the nextzone. These costs are discussed in the section onEconomic Data—General on page 178 of this ap-pendix.
Case
Low recovery . . . . . . . . ... . . .High-process performance ...High recovery. . . . . . . . . . . . . . . .
Appendix Be 161
Table B-10Recovery Uncertainties Effecting Steam Displacement Results
Production wellspacing, acres
2.52.52.5
Recovery Modela
Zone thickness<75 f t .
Gross recovery(primary, secondary
and steamdisplacement) as
fraction of originaloil in place
0.450.500.55
Zone thickness>
Maximumsteam zone
thickness
252530
75 ft.
Maximumhot water zone
thickness
303535
aAll other ~Odel parameters were the same as in the high-process Performance case
These extremes in recovery performance areSensitivity Analyses
Projections of oil recovery by steam displace-
ment contain uncertainties which are primari ly
related to the recovery efficiency of the process.Additional analyses were made to determine therange of variation in oil recovery due to uncer-tainties 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 rproduction well. Projections for low recovery (45percent) and high recovery (55 percent) are com-pared with the high-process performance case(50 percent recovery) in table B-11. Results fromthe low recovery case are essentially the same asthe low-process per formance case. The pro-
jections from the high recovery case are apprecia-bly higher than the high-process performance
case.
Table B-nEffect of Uncertainties in OverallRecovery on Ultimate Production
Steam Displacement Process(billions of barrels)
Upper World Alternatetier oil fuels
Case price price price($1 1.62/ ($1 3.75/ ($22.00/
bbl) bbl) bbl)
Low recovery . . . . . . . 2.1 2.5 3.4High-processp e r f o r m a n c e 2.8 3.3 6.0
High recovery. . . . . . . 3.9 5.9 8.8
also measures of energy efficiency. Crude oil isburned to produce steam. The amount of crudeconsumed is proportional to the volume of steamrequired to heat the reservoir. Nearly the samevolume of steam and consequently the sameamount of lease crude is consumed for each ofthe three cases. Slight variations occur for zoneswith thicknesses greater than 75 feet, Most of theadditional oil projected in the high recovery caseis produced with little additional lease crude re-quired for steam generation. In contrast, a largerfraction of the produced oil is consumed in thelow recovery case because about the sameamount of crude is consumed to produce steamwhile a smaller amount of oil is produced by thedisplacement process.
Pattern size is the second variable which wasinvestigated in sensitivity calculations. Oil recov-ery was estimated for two additional well spac-ings using the high-process performance model.Results are summarized in table B-12. If recovery
i s u n a f f e c t e d b y w e l l s p a c i n g , t h e r e i s a n
economic incentive to increase well spacing over
the 2.5-acre spacing used in the OTA study.Results are sensitive to spacing primarily becausethe costs to work over both injection and pro-duction wells in order to move from zone to zoneare significant.
Increasing well spacing reduces these costs inproducing wells by a margin which permitsseveral large reservoirs to meet the 10-percent
CJb-sn 4 (3 - 7 H - 12
162 . Appendix B
Table B-12Effect of Well Spacing on Ultimate Recovery of
Oil Using the Steam Displacement Process
Incremental 011(billions of barrels)
Production Upper tier World oil Alternate fuelswell 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 6.0High-process performance ., . . . . . . ., 3.3 3.5 5.3 6.8H i g h - p r o c e s s p e r f o r m a n c e . . . . . 5.0 5.6 6.4 7.0
rate-of-return criteria at lower prices. This is a po-tential area for technological advances beyondthose which were assumed in this study.
In Situ Combustion
State of the Art—Technological Assessment
In s itu combustion has been investigated in
t h e u n i t e d S t a t e s s i n c e 1 9 4 8 .6 1 B y t h emid-1950’s, two pilot tests had been conducted.One test was done in a reservoir containing alight oil (35° API) with a low viscosity (6 cp).62
The second reservoir tested contained 18.4° APIoil which had a viscosity of 5,000 cp.63 These ini-tial pilot tests demonstrated that a combustionfront could be initiated and propagated in oilreservoirs over a wide range of crude oil proper-ties.
The initial demonstrations of the technicalfeasibil ity of in situ combustion stimulatedresearch and development of the process both inthe laboratory and in the field. Over 100 fieldtests of in situ combustion have been conductedin the United States.64
Field testing developed considerable tech-nology. Methods were developed to initiatecombustion, control production from hot wells,and treat the emulsions produced in the process.Improved process efficiency evolved withresearch and field testing of methods to inject airand water simultaneously.65,66 The wet combus-tion process was found to have the potential ofreducing the air requirements by as much as 30 toso percent over dry combustion.
Many field tests have been conducted but fewhave resulted in projects which are commercially
successful. Economic information was not availa-ble on current in situ combustion projects. Con-tinued operation over a several-year period withf ie ldw ide expans ion imp l ie s sa t i s facto ryeconomics. California fields include the MocoUnit in the Midway Sunset.67 West Newport, 68
San Ardo, South Belridge, Lost Hills, and Brea-Olinda.69 Successful operations have also beenreported in the Glen Hummel, Gloriana, and TrixLiz Fields in Texas,70 and the Bellevue Field inLouisiana. 71 The number of commercial opera-tions in the United States is estimated to be 10.72
In situ combustion has not been appliedwidely because of marginal economics at existingoil prices, poor volumetric sweep efficiency insome reservoirs, and competition with steam dis-placement processes. Some field tests showed anet operating gain but could not generateenough income to return the large investment re-quired for an air compressor. The phrase “a tech-nical success but an economic failure” bestdescribes many projects.
The movement of the in situ combustion zonethrough a reservoir is controlled in part by varia-tions in reservoir properties. Directional move-ment has been observed in most in situ combus-tion projects. There has been limited success incontrolling the volume of the reservoir which isswept by the process. This is a major area forresearch and development.
Reservoirs which are candidates for steam dis-placement are also candidates for in situ combus-tion. Experience indicates that steam displace-ment is generally a superior process from theviewpoint of oil recovery, simplicity of opera-tion, and economics. Thus, applications of in situ
combustion have been limited by the develop-ment of the steam displacement process.
In situ combustion has one unique charac-teristic. It is the only process which may be ap-plicable over a wide range of crude gravities andviscosities.
Screening Criteria.--In situ combustion is ap-plicable to a wide range of oil gravities andviscosities. No constraints were placed on oilviscosity. The maximum permissible API gravityis determined by the capability of a particularreservoir rock/crude oil combination to depositenough coke to sustain combustion. Low-gravityoils which are composed of relatively large frac-tions of asphaltic-type components meet this re-quirement. It is also known that some mineralscatalyze in situ combustion, allowing high gravityoils to become candidates for in situ combus-tion. 73 The maximum oiI gravity which might be acandidate with catalytic effects was estimated tobe 45° API.
Minimum reservoir depth was set at 500 feet.74
Adequate reservoir transmissibility, i.e.,
Permeabilitv x thicknessoil viscosity
is necessary to prevent excessive heat losses tooverlying and underlying formations. Theminimum acceptable transmissibility for in situc o m b u s t i o n is about 20 miIIidarcyfeet/centipoise. 75 Carbonate reservoirs were notconsidered to be candidates for in situ combus-tion.
Oil Recovery Projections
The wet combustion process was used for theOTA study. All projects were developed as 20-
Appendix B . 163
acre patterns. In the wet combustion process,three distinct displacement zones are formed: aburned zone, a steam zone, and a hot waterzone. Gross oiI recovered from each pattern wascomputed from the sum of the volumes dis-placed from each zone. Areal sweep efficiency,maximum zone thickness, and residual oil satura-tion for each zone are included in table B-13 forthe advancing technology cases.
Fuel consumption was 200 barrels per acrefoot. 76 The equivalent oil saturation consumed inthe burned zone is Sob, where Sob = 200/7,758 X0); @ is the porosity of the rock, and 7,758 is bar-rels per acre foot.
The initial oil saturation was S,,,, the materialbalance average oil saturation computed fromequation 1. The volume of oil displaced wasdetermined in the following manner. The actualthickness of each zone was determined byallocating the net pay between the three zones inthe order shown in table B-13. A reservoir 20 feetthick would have a burned zone and a steamzone while a reservoir 100 feet thick would ex-perience the effects of three zones in a 50-footinterval. The volume of oil displaced from eachzone was computed from the product of the pat-tern area, areal sweep efficiency, zone thickness,porosity, and displaceable oil in the swept inter-val. All oil displaced from the swept zones wasconsidered captured by the producing well.
Timing of Production.—The life of each pat-tern was 8 years. Drilling, completion, and otherdevelopment was completed in the first 2 years.Air and water injection began in year 3 and con-tinued through year 8 for a total productive life of6 years. The displaced oil was produced accord-ing to the schedule in table B-14.
Table B-13Advancing Technology Cases
Oil Displacement ModelWet Combustion
Areal sweepRegion efficiency
Burned zone ... . . 0.55S t e a m z o n e . . , 0.60H o t w a t e r z o n e 0 8 0
I Residualoil saturation
Max. vertical Low-process High-processthickness, ft. performance performance
10 0 010 (),20 0.1530 0.30 0.25
164 . Appendix B
Table B-14Production Schedule
Wet Combustion
Annual production ofincremental oil
Year Percentage of total
1 - 2, . . . . . . . . . . . . . . . . . . . . o3 . . . . . . . . . . . . . . . . . 104: : ::::. . . . . . . . . . . . . . . . . 165 . . . . . . . . , . . . . . . . . . . . . . , 226... . . . . . . . . . . . . . . . . . . . . 207 188 : : : : : : : : : : : : : : : : : : : : : : : 14
Total . . . . . . . . . . . . . . . . 100
Operating Costs
Air required was computed on the basis of110-acre feet burned per 20-acre pattern (if thereservoir is at least 10 feet thick) and a fuel con-sumption of 200 barrels per acre foot. If theair/oil ratio was less than 7,500 standard cubicfeet (Scf) per stock-tank barrel (STB), air require-ments were increased to yield 7,500. Air re-quirements were then used to size compressorsand to determine the equivalent amount of oilwhich would be consumed as compressor fuel.
The amount of oil used to fuel the com-pressors was computed as a Btu equivalent basedon 10,000 Btu per horsepower hour. Energy con-tent of the oil was 6,3 million Btu per barrel. Thisoil was deducted from the gross production.
The corresponding equations for the price ofair as the price per thousand standard cubic feet($/MScf) were derived from data used in the NPCstudy. 77
Depth Cost Equationfeet $/MScf
O - 2,500 0.08 + 0.01108 P2 ,500- 5 ,000 0.08 + 0.01299 P5,000-10,000 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 isthe barrels of oil consumed to compress 1MScf of air to the pressure needed to in-ject into a reservoir at the specifieddepth.
Compressed air was supplied by a six-stagebank of compressors with 1 horsepower provid-ing 2.0 MScf per day.78 Compressor costs werecomputed on the basis of $40()/installed horse-power.
Sensitivity Analyses
The effect of uncertainties in operating costswas examined using the high-process perform-ance model. A low-cost case was analyzed byreducing the compressor maintenance cost from$0.08/MScf to $0.07/MScf. A high-cost case in-creased the compressor maintenance to$0.10/MScf. Results of these cases are comparedin table B-1 5. Cost reduction had little effect onthe projected results while the 25-percent in-crease in maintenance cost reduced the ultimaterecovery by 19 percent at upper tier price and 8percent at world oil price for the high-processperformance case,
A case was also simulated in which the dis-placement efficiency in the steam and hot waterzones was increased by changing the residual oilsaturation in the steam zone to 0.10 and in thehot water zone to 0.20, Results of this case are in-dicated as high-displacement efficiency in tableB-1 S. The effect of assumed improvement in dis-placement efficiency resulted in a 17- to 20-per-cent increase in ultimate recovery but littlechange in price elasticity.
Table B-15Effect of Changes in Compressor Operating Costs
and Displacement Efficiency in Ultimate OilRecovery Using the In Situ Combustion Process
Case
I Incremental oil(billions of barrels)
Uppertier
price($1 1.62/
bbl)
Worldoil
price($1 3.75/
bbl)
Alternatefuelsprice
($22.00/bbl)
High cost. . . . . . . . . . . .High-process
performance . . . . . . . .Low cost . . . . . . . . . . . .High-displacement
efficiency . . . . . . . .
1.4
1.71.7
2.1
1.7
1.91.9
2.2
1.9
1.91.9
2.3
Carbon Dioxide Miscible
State of the Art—Technological Assessment
It has been known for many years that oil canbe displaced from a reservoir by injection of asolvent that is miscible with the oil. Because suchsolvents are generally expensive, it is necessaryto use a “slug” of the solvent to displace the oiland then to drive the slug through the reservoirwith a cheaper fluid, This process was shown tobe feasible at least 20 years ago.79 An overviewof the various kinds of miscible displacements isgiven by Clark, et al.80
Hydrocarbon miscible processes have beendeveloped and studied fairly extensively. A num-ber of field tests have been conducted.81 While ithas been established that hydrocarbon miscibleprocesses are technically feasible, the high costof hydrocarbons used in a slug often makes theeconomics unattractive. Recently, attention hasfocused on carbon d iox ide (C02) as themiscibility agent.82
In the OTA study it was assumed that, ingeneral, economics and solvent availabilitywould favor the use of C02. The C02 processwas therefore used exclusively as the miscibledisplacement process in the study.
Carbon dioxide has several properties whichcan be used to promote the recovery of crude oilwhen it is brought into contact with the oil.These properties include: 1 ) volubility in oil withresultant swelling of oil volume; 2) reduction ofoil viscosity; 3) acidic effect on rock; and 4)ability to vaporize and extract portions of thecrude oil under certain conditions of composi-tion, pressure, and temperature.
Because of these properties, C02 can be usedin different ways to increase oil recovery, i.e.,different displacement mechanisms can be ex-ploited. The three primary mechanisms are solu-tion gas drive, immiscible displacement, anddynamic miscible displacement.
Solution-gas-drive recovery results from thefact that C0 2 is highly soluble in oil. When C02
is brought into contact with oil under pressure,the C02 goes into solution. When the pressure islowered, part of the C02 will evolve and serve asan energy source to drive oil to producing wells.
Appendix B . 165
The mechanism is similar to the solution-gas-drive primary recovery mechanism and can beoperative in either immiscible or miscible dis-placement processes.
Helm and Josendalal83 have shown that C02 canbe used to displace oil immiscible. In experi-ments conducted with liquid C02 below thecritical temperature, residual oil saturations weresignificantly lower after flooding with C02 thanafter a waterflood. The improved recovery wasattributed primarily to viscosity reduction and oilswelling with resultant improvement in the rela-tive permeability. It was noted that the C02 dis-placement was not as ef f ic ient when awaterflood preceded the C02.
Carbon dioxide, at reservoir conditions, is notdirectly miscible with crude oil. However,because C02 dissolves in the oil phase and alsoextracts hydrocarbons from the crude, it is possi-ble to create a displacing phase composition inthe reservoir that is miscible with the crude oil.
Menzie and Nielson, in an early paper,84 pre-sented data indicating that when C02 is broughtinto contact with crude oil, part of the oil vapor-izes into the gaseous phase. Under certain condi-tions of pressure and temperature, the extractionof the hydrocarbons is significant, especially ex-traction of the intermediate molecular weight hy-drocarbons (C5 to C30). Helm and Josendahl85 alsoshowed that C02 injected into an oil-saturatedcore extracts intermediate hydrocarbons from theoil phase and establishes a slug mixture which ismiscible with the original crude oil. Thus, whiledirect contact miscibility between crude oil andC02 does not occur, a miscible displacement canbe created in situ. The displacement process,termed dynamic miscibility, results in recoveriesfrom linear laboratory cores which are compara-ble to direct contact miscible displacement.
HoIm 86 has pointed out that the C02 miscibledisplacement process is similar to a dynamicmiscible displacement using high-pressure drygas. However, important differences are that C02
extracts heavier hydrocarbons from the crude oiland does not depend upon the existence of lighthydrocarbons, such as propane and butanes, inthe oil. Miscible displacements can thus beachieved with COZ at much lower pressures than
166 . Appendix B
with a dry gas. Methods of estimating miscibilitypressure have been presented.87,88
The CO2 miscible process is being examined ina number of field pilot tests.89,90 The largest ofthese is the SACROC unit in the Kelly-SnyderField. 91 Different variations of the process arebeing tested. In one, a slug of CO2 is injectedfollowed by water injection. In another, CO2 andwater are injected alternatively in an attempt toimprove mobility control. 92
The preliminary indication from laboratory ex-periments and these field tests is that the C02
process has significant potential. However, thefield experience is quite limited to date and somedifficulties have arisen. Early CO2 breakthroughhas occurred in some cases and the amount ofCO, required to be circulated through the reser-voir- has been greater than previously thought .93Operating problems such as corrosion and scal-ing can be more severe than with normalwaterflooding. Greater attention must be givento reservoir flow problems such as the effects ofreservoir heterogeneities and the potential forgravity override.
in general, the operating efficiency of the proc-ess or the economics have not been firmlyestablished. In the OTA study, the reportedlaboratory investigations and preliminary fieldresults were used as the basis for the recoverymodels and the economic calculations.
Screening Criteria.—Technical screening cri-teria 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 psi27° - 30” API 3,000 psi> 30° API 1,200 psi—
Temperature correction to miscibility pressureO 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 tem-perature corrected):
< 27° API 7,200 ft27° - 30° API 5,500 ft> 30° API 2,500 ft—
This was the same correlation as used in the NPCstudy.94 It is noted that the general validity of thiscorrelation has not been established. Crude oilsin particular reservoirs may or may not establishmiscibility with CO2 at the pressures and tem-peratures indicated. Other correlations havebeen presented in the literature, but they arebased on a knowledge of the crude oil composi-tion. Data on composition were not available inthe data base used in the OTA study, and ageneralized correlation of the type indicatedabove was therefore required.
Oil Recovery Projections
Onshore Reservoirs .—The recovery modelused was as follows:
where
R = recovery by CO2 process, stock-tank barrels
s =orm residual oi l saturat ion in zone
swept by CO2. Set at 0.08, Nodistinction was made betweensandstone and carbonate reser-voirs.
E m = sweep efficiency of C02 misci-ble displacement. (Em/Evm) wasset at 0.70.
E =v m volumetric sweep efficiency of
the waterflood computed fromprocedure described in appendixA.
The sweep efficiency for CO2 miscible (Em
was determined by making example calculationson CO2 field tests. Field tests used were thefollowing:
SlaughterWassonLevel landKelly-Snyder (SACROC)
Appendix B . 167
Cowden-NorthCrosset
All projects except the Wasson test werereported in the SPE Field Reports. 95 Data onWasson were obtained from a private com-munication from Lewin and Associates, Inc.Based upon reported data and reported estimatesof the tertiary recovery for each field test, sweepefficiency values were calculated. The ratioEm/Evm averaged 0.87. Discarding the high andlow, the average was 0.80. It was judged that thenational average recovery would be less,therefore a value of EmE vm of 0.70 was used forall reservoirs in the OTA calculations.
The high-process performance model assumesthe waterflood residual (SOrw for each reservoir isdetermined f rom table A-1 according togeographic region. This value was used unlessthe volumetr ic sweep eff ic iency for thewaterflood (EVJ fell outside the limits describedin appendix A. The low-process performance wassimulated by reducing the SOrW values in tableA-1 by 5 saturation percent. The same limits onthe calculated values of Evm were used in thelow-process performance model. The recoverymodel (equation 6B) was unchanged except forEvm and SO:W.
The low-process performance model reducedthe EOR for those reservoirs in which the calcu-lated Evm fell within the prescribed limits. WhereE vm was outside the limits, SO ,W was recalculated
using the l imit ing E v m value. Therefore, for theselatter reservoirs the recovery results were thesame in both the high- and low-process perform-ance models. For C02 miscible, this was the casefor about one-third of the total reservoirs. Theaverage recovery for all reservoirs was 20 percentless in the low-process performance case than inthe high-process performance case.
Volurnes of Injected Materials.—The CO Z r e -
quirement was established as follows:
Sandstone Reservoirs—26 percent of pore volumeCarbonate Reservoirs—22 percent of pore volume
Conversion of CO 2 from surface conditions toreservoir 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 require-ment was assumed to be from recovered, com-pressed, and reinfected gas. Seventy-five percentwas purchased.
The C02 injection schedule was as shown intable B-1 6. The water alternating gas process wasused. The ratios were:
S a n d s t o n e s I: 2 C O2H 2O
C a r b o n a t e s 1 : 1 C O2: H2O
Table B-16Carbon Dioxide Injection Schedule
I Purchased COZ I Recycled C02
Year percent of total* percent of total*
1-2 . . . . . . . . . . . 0 03 . . . . . . . . . . . . . 20 04 . . . . . . . . . . . . . 20 05 16 46 : : : : : : : : : : : : : 13 77 . . . . . . . . . . . . . 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 thirdyear of the period, along with purchased COZ.
Timing of Production. —The production profilewas set at a fixed percentage of the total recov-ery (as computed by the recovery model above).The schedule is shown in table B-17. All reser-
voirs were developed on 40-acre spacing.
Offshore Reservoirs.--Offshore CO2 miscibledisplacement was calculated using a differentmodel than the onshore model. The reservoirs ofthe gulf offshore are steeply dipping becausethey are nearly universally associated with saltdome formations. This has limited effect on theother processes but great impact on CO2 misci-ble. Due to the dip, the CO), with small quan-tities of CH4 can be injected at the top of the dipand gravity stabilized. No production is noteduntil the oil bank ahead of the miscible slugreaches the first producers down dip. The bank isproduced until the slug breaks through, at whichtime the producer is shut in and the slug pro-ceeds further down dip, creating a new bankwhich is produced in like manner at the next pro-ducer further down. The process continues until
168 . Appendix B
Table B-17Production Rate Schedule
for Carbon Dioxide Miscible
Table B-18Gas Injection Schedule
Offshore Carbon Dioxide Miscible
PercentYear of EOR
Carbonates1-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
lo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 . . . . . . . . . . . . . . . . . . . . . .fi. ......,12,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
059
1317191410
6421
Total . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sandstones
100
06
19262113
96
Total . . . . . . . . . . . . . . . . . . . . . . . . . 100
the final bank has been produced at the bottomof the formation. Because the integrity of themiscible slug must be maintained, no water injec-tion is contemplated. However, air is compressedand used to push the CO2-CH4 mixture after arelatively large volume of the mixture has beeninjected. Residual oil saturation after miscibledisplacement, S
Orm, was set at 0.08. Sweep effi-c iency , Em, was set at O.80 (i.e (Em/Evm) x Ev m
=
0.80). This is a significantly higher sweep efficien-cy than used, on the average, for onshore reser-voirs.
The fluid injection schedule for offshore reser-voirs is shown in table B-18 and the oil produc-tion schedule is given in table B-19.
Carbon Dioxide Costs
Well Drilling and Completion Costs.-Becauseof special requirements created by C02flooding,
Year I C02 -CH, I Air
1 . . . . . . . . . . . . . . 0 02 . . . . . . . . . . . . . . 0.25PV o3 . . . . . . . . . . . . . . 0.25PV o4 . . . . . . . . . . . . . . 0 0.15PV5 . . . . . . . . . . . . . . 0 0.15PV
Table B-19Oil Production Schedule
Offshore Carbon Dioxide Miscible
ProductionYear percent of total
1 . . . . . . . . . . . . . . . . . . . . . . . o2 . . . . . . . . . . . . . . . . . . . . . . . o3 . . . . . . . . . . . . . . . . . . . . . . . o4 . . . . . . . . . . . . . . . . . . . . . . . 505 . . . . . . . . . . . . . . . . . . . . . . . 50
Total . . . . . . . . . . . . . . . . 100
the base drilling and completion cost was in-creased by a factor of 1.25 for injection wells.
Compression Costs. —Twenty-five percent ofthe CO2 requirement was met from recycledC O2. Compression equipment was purchasedand fuel costs were charged to this recompres-sion.
Carbon Dioxide Pricing Method.—The cost ofC 02 is a variable of major importance. Costs ofCO 2 can vary widely depending on whether thesource is natural or manufactured gas and de-pending on the transportation method and dis-tance. In fact, this EOR technique probably hasthe greatest potential for economies of scalebecause of the variability of these costs.
The cost algorithm used in the OTA study was
developed by Lewin and Associates, Inc., and asummary of this analysis follows. Reservoirs wereplaced into one of four categories. These catego-ries are:
●
●
Concentrations of large reservoirs adequateto support the construction of a major C02
pipeline.
Concentrations of smaller reservoirs wherethe bulk of COZ transportation would be by
major pipeline but where lateral lines wouldbe required to deliver COZ to the numeroussmaller fields,
. Smaller concentrations of large (and small)reservoirs where a smaller pipeline or alter-native means for transporting COZ could beused.
. Individual, small reservoirs to be served bylateral pipeline or tanker trucks, where theamounts of required C02 would not justifythe building of a new pipeline.
Results of the analysis of each of thesecategories is provided in the section below. Thefollowing subsection contains the details of thecalculations.
Results of Carbon Dioxide Cost Calculations
Concentrations of Large Reservoirs. Giventhe indicated locations of natural C02 and theconcentration of large candidate reservoirs such
Appendix B . 169
as in western Texas, eastern New Mexico, andsouthern Louisiana, it appears that the reservoirsin these areas could be served by major C02
pipelines.
T h e C 02 cost model uses the fol Iowingalgorithms for assigning C02 costs to reservoirs:
● $0.22 per Mcf for producing C02,
. $0.24 per Mcf for compression and opera-tion costs, and
. $0.08 per 100 miles of pipeline distance, in-cluding small amounts of lateral l ines,assuming a 200 MMcf per day of pipelinecapacity.
Under these assumptions, the base cost for C02
delivered to concentrations of large reservoirareas would be according to the following chart.A l l rese rvo i r s , large and smal l , in thesegeographic areas would be able to take advan-tage of the economies of scale offered by thebasic concentration of large reservoirs.
Geographic areaApproximate
truckline distance(miles)
Louisiana—South . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Texas-District 76 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .District 7C,8,8A,9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .District 10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New Mexico East and West . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .“. . .
200400
300300300500
200
300
Adequate Concentration of Large and SmallReservoirs Served by Lateral Lines.—The secondclass of reservoirs would be the large and smallreservoi rs in c lose proximity to the majortrunklines. These reservoirs could be serviced byusing short distance lateral lines. Carbon dioxidecosts were assigned as follows:
● $0.46 per Mcf for producing and compress-ing the C02, and
● $0.20 per Mcf per 100 miles for transporta-tion.
The C02 model assumes that reservoirs in thefollowing geographic areas could be served byshort distance trunklines or linking lateral lines to
Laterals(miles)
100200
100100100100
100
—
Carbon dioxidecost per Mcf
(dollars)
0.700.94
0.780.780.780.94
0.70
0.70
the main trunklines, using pipelines of 50 MMcfper day capacity.
Geographic area
Colorado . . . . . . . .
Mississippi. . . . . . .
Oklahoma . . . . . . .
Utah. . . . . . . . . . . .
Approximatedistance 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 tonatu ra l C02 sou rces where on ly m in imum
170 ● Appendix B
transportation charges would be required todeliver the C02 to the field.
The first question is what size of pipeline canbe justified. This was examined for the twosmaller potential States of Alabama and Florida.It was assumed that both of these States wouldjustify a 100 MMcf pipeline under a 10-yeardevelopment plan and a 50 MMcf pipeline undera 20-year development plan. For a 50 MMcfpipeline the costs were assumed to be asfollows:
. $0.46 per Mcf for producing and compress-ing the COZ, and
● $0.20 per Mcf per 100 miles for transporta-tion, including laterals.
The CO Z model assumes that the followinggeographic areas are close to natural CO2 sourcesand could be served by small pipelines, having50 MMcf/day capacity.
Geographic areaApproximate Carbon dioxide
pipeline distance cost per Mcf(miles) (dollars)
Alabama . . . . . . . . .Arkansas . . . . . . . . .Florida . . . . . . . . . . .Kansas . . . . . . . . . . .Montana . . . . . . . . .West Virginia . . . . .
200200300200200100
0.860.861.020.860.860.70
An alternative to this third class of reservoirsare those similar reservoirs that are not close tonatural COZ sources. The reservoirs in thesegeographic locations would need to be served byC OZ extracted from industrial waste products(e.g., from chemical complexes, ammonia plants,gasoline plants, combined powerplants, etc.).
An analysis of minimum required pipeline sizeindicated that each of these areas could supporta 200+ MMcf per day pipeline under a 10-yeardevelopment plan and a 100 MMcf per daypipeline under a 20-year development plan. Thefollowing costs were used for these reservoirs:
●
●
●
●
$0.90 per Mcf for extracting the manufac-tured CO2,
$0.25 per Mcf for compression and opera-tion,
$0.08 per Mcf for 100 mi les of t runkpipeline (200 MMcf per day capacity), plus
$0.30 per Mcf for three 50-mile lateral lines(50 MMcf per day capacity) connecting theCO2 source to the trunkline.
Under these assumptions, the base cost forC O2 for the geographic areas in this categorywould 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
200200200
1.45
1.45
1.451.451.45
1.61
1,61
1.611.611.61
Low Concentration, Small Reservoirs.—Thefinal category of reservoirs considered in theanalysis are the small reservoirs located in themoderate- and low-concentration geographicareas. The alternatives here are to construct asmall pipeline to the trunkline or to deliver theC O2 via truck. Large trunkline construction forlow concentration reservoirs is infeasible.
For those geographic regions where the largereservoirs are already served by a pipeline, it ap-pears likely that additional small lateral linescould be added to extend the C02 delivery tosmall fields. These fields would only need to paythe marginal costs of delivery. Because of this,rather small CO 2 lateral lines could be con-structed (as small as 5 MMcf per day), which
Appendix B . 171
would serve an area with as little as 5 million bar-rels of recoverable oil. it was thus assumed thatthe average C02 costs for the small fields in aregion already served by a pipeline would be thesame as base costs for that region.
For concent rat ions lack ing such ex i s t i ngtrunklines, i.e., the remaining States, tanker-
trucks would deliver CO2. These would include:
Illinois North DakotaIndiana OhioKentucky PennsylvaniaMichigan South DakotaNew 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 isbriefly outlined in this section. The analysisfollowed a seven-step sequence:
●
●
●
●
●
●
●
calculate the relationship of pipelinecapacity to unit costs,
translate pipeline capacity–cost relation-ship to pipeline investment costs per Mcf,for various pipeline capacities,
calculate the pipeline delivery costs per Mcfthat vary by distance,
calculate the C02 purchase and deliverycosts per Mcf that do not vary by distance,
calculate full costs per Mcf for natural andmanufactured CO2,
translate pipeline capacity to minimum re-quired field size, and
complete the breakeven analysis of usingpipeline versus truck for delivering CO2 t othe field.
Relationship of Capacity to C o s t s . — T h efollowing were assumed for calculating pipelineinvestment costs:
• $330,000 per mile for 200 MMcf per daycapacity,
. investmentfactor, 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, ando variable costs = $600 per MMcf/day per
mile.
This relationship of costs to capacity hasthe 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 perMcf (per 100 miles) graph by dividing costs bycapacity, as follows:
For the 200 MMcf/day capacity at $330,000per mile, the cost per Mcf per 100 miles with nodiscounting 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 isimposed, and it is assumed that no return resultsuntil the fourth year, the costs would be raisedto:
- P
L.08(1 .08) 16
JC = $0.07 per Mcf per 100 miles
172 . Appendix B
Similarly, the pipeline investment cost per Mcfcan be generated as shown in table B-20.
labia 6-20Pipeiine Capacity Versus investment
(8-percent rate of return)
Pipeline investmentPipeline capacity cost per Mcf
(MMcf/day) ($ per 100 miles)
300 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.05200 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.07100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.11
50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.37lo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.89
5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.79
Pipeline Delivery Costs Variable by Distance.—The pipeline investment cost was added topipeline operating costs to develop pipelinecosts per Mcf that are variable by distance. Thefollowing was assumed:
. pipeline operating costs are $O.01 per Mcfper 100 miles, and
● the pipeline capital costs from table 6-20are applicable,
● with these assumptions, the variable costper Mcf per lOO miles can redeveloped asshown in figure B-3.
Figure B-3. Variable CO2 TransportationCosts Versus Pipeline Capacity
100 300”Pipeline capacity (in MMcf/day)
Carbon Dioxide Costs Not Variable by Dis-tance.—The following was assumed:
. repressurizing operating costs are $0.16 perMcf
repressurizing capital costs are $0.08 perMcfbased on the following:
$700 per hp280 hp required to pressurize 1,000
Mcf per dayCompressors will last 20 years8-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, andadditional lateral lines will be required togather and transport manufactured C02.
Based on the preceding, the fixed costs formanufactured C0 2 will be $1.14 per Mcf withlateral lines as shown in table B-21.
Table B-21Lateral Lines Associated With Pipeline Capacity
Pipeline capacity Amount and size of
(MMcf/day) lateral lines
300 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 50 MMcf/day200 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 50 MMcf/day100 . . . . . . . . . . . . . . . . . . . . . 3 to 50 mile @ 25 MMcf/day
50 . . . . . . . . . . . . . . . . . . . . . 2 to 50 mile @ 10 MMcf/day25 . . . . . . . . . . . . . . . . . . . . . 1 to 50 mile @ 10 MMcf/day10 . . . . . . . . . . . . . . . . . . . . . 1 to 50 mile @ 5 MMcf/day
5 . . . . . . . . . . . . . . . . . . . . . None
Total Costs per Mcf. —The investment andoperating costs were then added to the purchaseprice for natural CO2 and extraction and gather-ing costs for manufactured CO2 to obtain thetotal cost per Mcf. These are shown for variousconditions in table B-22.
Relationship of Pipeline Capacity to FieldSize.—The pipeline capacity was related to fieldsize
●
●
●
using the following assumptions:
5 Mcf are required per barrel of recoveredoil,CO2 is injected over 10 years, andC 02 recovers 30 percent of the oil left afterprimary/secondary recovery.
Then the conversions of pipeline capacity tofield size shown in table B-23 were used.
Break-Even Analysis.-Using $2.75 per Mcf asthe trucked-in cost for C02, two curves were
Appendix B . 173
Table B-22Total Costs per Mcf of CO=
(dollars).
Pipelinecapacity
(MMcf/day)
300 . . .
200 . . .
100 . . .
50 . . .
2 5
1 0
5 . . .
Distance
(miles)
100200300400
100200300400
100200300400
50100200300400
50100200300
50100200
50100200
Transp.costs
0.060.120.180.24
0.080.160.240.32
0.120.240.360,48
0.100,210.420.630.84
0.190.380.761.14
0.450.901.80
0.881.763.52
Fixedoperating
0.240.240.240.24
0.240.240.240.24
0.240.240.240.24
0.240.240240.240.24
0240.240.240.24
0.240.240.24
0.240.240.24
Table B-23Pipeline Capacity as a Function of Field Size
Pipeline capacity(MMcf/day)
300 . . . . . . . . . . . .200 . . . . . . . . . . . .100 . . . . . . . . . . . .
50 . . . . . . . . . . . .25 . . . . . . . . . . . .10 . . . . . . . . . . . .
5 . . . . . . . . . . . .
Purchase
(natural)
0.220.220.220.22
0.220.220.220.22
0.220.220.220.22
0.220.220.220.220.22
0.220.220.220.22
0.220.220.22
0.220.220.22
Minimum required concentration(or field size)
Incremental oil I Residual oilrecovered by C02 in place
(million barrels) (million barrels)
219 730146 490
73 24036 12018 60
9 305 17
determined: one for natural and one for manufac-tured CO2. These curves, shown in figure B-4, in-dicate the field size (oil concentration) and dis-
Extractfrom
manuf.
0.900.900.900.90
0.900.900.900.90
0.900.900.900.90
0.900.900.900.900.90
0.900.900.900.90
0.900.900.90
0.900.900.90
Gatherfrom
manuf.
0.300.300.300.30
0.300.300.300.30
0.570.570.570.57
0.900.900.900.900,90
0.900.900.900.90
0.880.880.88
———
Full costfor natural
0.520.580.640.70
0.540.620.700.78
0.580.700.820.94
0.560.671.881.091.30
0.650.841.221.60
0.911.362.20
1.342.223.98
Full cost formanufactured
1.501.561.621.68
1.521.601.681.76
1,831.952.072.19
2.142.252,462.672.88
2.232.422.803.18
2.492.943.84
2.022.904.66
Figure B-4. Transportationof C02— Break-Even Analysis
. Use Pipeline
I I I 1“ t I I Itance 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 ofparameters than those presented in the mainbody of the report. In general, these additionalcalculations were done to determine the sen-sitivity of the results to certain of the importantvariables. For CO2 miscible, two important con-siderations were the minimum acceptable rate ofreturn and the price of the injected CO2. Resultsof calculations in which these parameters werevaried are given in this section.
High-Process Performance—High-Risk Case.—A calculation was made in which the minimumacceptable rate of return was set at 20 percent.The rate of implementation of projects wasgoverned by the rate of return earned in a manneranalogous to that given by table 8 in chapter Ill.The schedule of starting dates based on rate ofreturn is given in the section on the economicmodel (p. 35).
Results of this calculation, considering the casein which the process is viewed as a high risk tech-
nology, are given in table B-24 for the world oilprice. Ultimate recovery is dramatically reducedfrom the conventional risk case (lo-percent rateof return) presented in the body of the report. Atlo-percent rate of return, the ultimate recovery is13.8 billion barrels compared to 4.7 billion bar-rels with a 20-percent minimum rate of return.Production rates are correspondingly reduced.
This result strongly suggests that a great dealof research and development work must be doneto establish the processes, and that economic in-centives must be provided if the projections pre-sented in the body of the report are to bereached,
Sensitivity to Carbon Dioxide Costs. -Calculi-tions were made in which the purchase cost ofC 02 was increased by factors of 1.5 and 2.5. Asignificant uncertainty exists relative to COZ costsand variations of these magnitudes are con-sidered feasible.
Results for the high- and low-process perform-ance cases are shown in table B-25 and B-26,
Table B-24Estimated 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
0.10.10.10.60.9
100300400900
2,700
World oil price($13.75/bbl)
Offshore
0.6
**●
0.10.1
●
☛
100200500
● Less than O. I million barrels of daily production, or less than 100 million barrels of cumulative production.
Total
4.7
0.10.10.10.71.1
100300600
1,1003,200
● “Daily production figures rounded to 0.1 million barrels, cumulative production figures rounded to 100 million barrels; row totals may notadd due to rounding.
Appendix B . 175
Tabie B-25Sensitivity of Ultimate Recovery to Carbon Dioxide Cost
Advancing Technology-High-Process Performance Case(billions of barrels)
Upper tier price World 011 price Alternate fuels priceCost 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 11.5 : 3.9 01 4.0 6.7 0.3 7.0 15.9 19 1782.5 . 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-26Sensitivity of Ultimate Recovery to Carbon Dioxide Cost
Advancing Technology—Low-Process Performance Case(billions of barrels)
tcost 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 12.31.5 . . . . . . . . . . . . . . . . . ., . . . . . . . . . . . . . . . . . . 0.8 1.8 8.92.5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 in-cost of CO2 by a factor of 1.5 reduces ultimate crease of CO2 cost by a factor of 2.5 reduces ulti-recovery by a factor of about 2 at upper tier and mate recovery to about 0.3 billion barrels atworld oil prices. The effect is not so pronounced world oil price, and to about 4 billion barrels atat the alternate fuels price. Increase of the cost by the alternate fuels price.a factor of 2.5 essentially eliminates productionat the upper tier price and reduces recovery toless than 2 billion barrels at world oil price.
Economic Model
The economic model was developed by Lewinand Associates, Inc.96 In this section the structureof the basic model will be described, followed bytabulations of the economic parameters.
Structure of the Model
The model uses a standard discounted cash-flow analysis. The unit of analysis is the reservoirwith economic calculations being made for asingle “average” five-spot pattern within thereservoir. Results of the single-pattern calculation
are then aggregated according to a reservoirdevelopment plan (described below) to deter-mine total reservoir economic and productionperformance.
Cash inflows are determined using the specificoil recovery models previously described foreach process. Recovery models are applied usingthe reservoir parameters from the data base. Anassumption was made that 95 percent of the oil
remaining in a reservoir was contained within 80percent of the area. This “best” 80 percent wasthen developed in the model. An adjustment of
176 ● Appendix B
reservoir thickness was made to distribute the 95percent of the remaining oil over an acreageequal to 80 percent of the total acreage. Timingand amounts of oil production are dependent onthe particular EOR process applied as previouslydescribed.
Cash outflows are based on several differentkinds of costs and investments. These are: 1)field development costs, 2) equipment invest-ments, 3) operating and maintenance (O & M)costs, 4) injection chemical costs, and 5)miscellaneous costs, such as overhead. Listingsand descriptions of the costs follow.
Using the cash inflows and outflows, an annualoverall cash-flow calculation is made consideringFederal and State taxes. Appropriate State taxrules are incorporated for each reservoir. Cashflows are then discounted at selected interestrates to determine present worth as a function ofinterest rate. Rate of return is also calculated.
The discounted cash-flow analysis was madeat three different oil prices. These included uppertier price ($1 1.62 per barrel), world oil price($1 3.75 per barrel), and an estimated price atwhich alternate fuels would become competitive($22.00 per barrel). All costs were in 1976 realdollars with no adjustment for inflation.
Reservoirs were developed if they earned arate of return of at least 10 percent by one of theEOR processes. In situations where more thanone EOR process was applicable to a reservoir,the EOR process yielding the greatest ultimaterecovery was selected as long as a rate of returnof at least 10 percent was earned.
Specific Economic Assumptions
Date of Calculations.—Ail calculations weremade as of a date of July 1, 1976. Cost data wereprojected to that date. No attempt was made tobuild inflation factors into the calculations offuture behavior.
Sharing of Operating and Maintenance Costs.—Well operating and maintenance costs wereshared between primary and secondary produc-tion and enhanced oil production. A declinecurve for primary and secondary production wasgenerated for each reservoir. This was based onspecific reservoir data, if available, or on regional
decline curve data if reservoir data did not exist.Well operating costs were assigned annually toenhanced oil operations in direct proportion tothe fraction of the oil production that was due tothe EOR process.
General and Administrative (Overhead)Costs.—These costs were set at 20 percent of theoperating and maintenance costs plus 4 percentof investments (excluding any capitalized chemi-cal costs). Where O & M costs were shared be-tween primary and secondary and enhancedrecovery, only that fraction assigned to EOR wasused as a basis for the overhead charge.
Intangible and Tangible Drilling and Comple-tion Costs. —Intangible costs were expensed inthe year incurred in all cases (no carryback or car-ry forward was used in the tax treatment). Thesecosts were set at 70 percent of drilling and com-pletion costs for new wells and 100 percent ofworkover costs.
Tangible costs were “recovered” by deprecia-tion. Thirty percent of drilling and completioncosts were capitalized plus any other lease orwell investments. A unit of production deprecia-tion method was applied.
Royalty Rate.—A rate of 12.5 percent of grossproduction was used in all cases.*
Income Taxes. —The Federal income tax ratewas set at 48 percent. The income tax rate foreach State was applied to reservoirs within theState. An investment tax credit of 10 percent oftangible investments was used to reduce the taxliability. If a negative tax were computed in anyyear, this was applied against other income in thecompany to reduce tax liabilities.
Chemical Costs—Tax Treatment.—For tax pur-poses, chemicals, such as CO 2, surfactant,polymer, and so on, were expensed in the year ofinjection. Tax treatment of the chemical cost isan important consideration. The effect of having
“In most current leases, a royalty is charged on net pro-duction. However, there is a trend to charge a royalty ongross production in some Federal leases and because thistrend could extend into the private sector in the future,OTA calculations assessed royalty charges against gross pro-duction.
Appendix B . 177
to capitalize chemicals (and recover the invest-ment via depreciation) was treated as a part ofthe policy considerations. This is discussed in themain body of the report.
Size of Production Units--For purposes of theeconomic calculations, a production unit wasassumed to consist of the acreage associatedwith one production well. This varied from proc-ess to process. The spacing used is shown intable B-27.
Table B-27Production Unit Size
I I ProductionProcess Acres
C O2 miscible . . . . . 40Steam drive . . . . . . 2.5-5.0In situ combustion . 20Surfactant/polymer Variable
(Max= 40)Polymer. . . . . . . . . . 40
wells
1.01.01.01.0
1.0
Injectionwells
1.01.01.01.0
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 overas required according to their age and condition,
As previously indicated, an assumption wasmade that 95 percent of the remaining oil inplace was located under 80 percent of the reser-voir acreage. The oil in this “best” acreage wasassumed to be uniformly distributed.
Timing of Reservoir Development. -Reservoi r s
were developed according to a plan designed to
simulate industry implementation of EOR proc-esses in a reservoir. The first part of the timingplan consists of a schedule of starting datesbased on rate-of-return criteria. This was dis-cussed in the main body of the report, and theschedule is given in table 8 in chapter Ill. Thisschedule is for the conventional risk situationwith a 10-percent rate of return taken as theminimum acceptable rate,
A “high-risk” case was also considered inwhich the minimum acceptable rate of return wasset at 20 percent. The schedule of starting dateswas altered for this high-risk case as shown intable B-28.
The second part of the timing plan consists ofthe elements of the specific reservoir develop-
Table B-28Schedule of Starting Dates
High-Risk Case
I Continuations of
Iongoing projects New starts
Date rate of return rate of return
1977 . . . . . . . . . . .1978 . . . . . . . . . . .1979 . . . . . . . . . . .1980 . . . . . . . . . . .1981 . . . . . . . . . . .1982 . . . . . . . . . . .1983 . . . . . . . . . . .1984 . . . . . . . . . . .1985 . . . . . . . . . . .1986 . . . . . . . . . . .1987 -2000 . . . . . .
>20%
> 2 0 %> 2 0 %> 2 0 %> 2 0 %> 2 0 %> 2 0 %> 2 0 %> 2 0 %—
%60%> 4 5 %> 4 0 %> 3 5 %> 3 0 %> 2 8 %> 2 6 %> 2 4 %> 2 2 %> 2 0 %> 2 0 %—
ment scheme, once a starting date is assigned.The seven elements of the reservoir developmentplan are as follows:
Reservoir study. Preliminary engineeringstudies and laboratory tests are conducted.A decision is made whether or not to under-take a technical pilot.
Technical pilot. Pilot consists of one or twofive-spot patterns on close spacing. Techni-cal parameters are evaluated.
Evaluate pilot, planning. Pilot results are evalu-ated and plans are made for economic pilot.Budgeting occurs.
Economic pi/et. Pilot consists of four to eight
f ive-spot patterns on normal spacing. Pur-
pose is to evaluate economic and technical
potential.
Evaluation and planning, Results of pilots areevaluated. Plans are made for full-scaledevelopment.
Pipeline construction (CO, miscible only).Pipeline necessary to carry C02 from sourceto reservoir is constructed.
Development of complete reservoir. The re-maining part of the reservoir is developedaccording to a set time schedule.
The time devoted to each of the seven stepsfor each process is shown in table B-29.
Extrapolation to Nation.—To obtain the na-tional potential for EOR, calculated reservoir
q6-5q4 () - 78 - 13
178 . Appendix B
Table B-29Timing 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
12131—
10
12122—
1 o“
18 18
Technique
C02
121412
5
16
Surfactant/polymer Polymer
1 12 01 04 51 1— —
10 2
19 9
*ln situ proceeds in four separate segments introduced 3 years apart.
recoveries were first extrapolated to the State ordistrict level and then summed to yield the na-tional total. The State or district extrapolationfactor was the ratio of remaining oil in place(ROIP) (after secondary recovery) in the State ordistrict divided by the ROIP in the data basereservoirs in the State or district.
An example calculation for the State ofWyoming follows (for world oil price).
Calculated EOR Recovery. . . . . . . . . . . . . . 0.56 billion bbls(from reservoirs in data base)
Percent of ROIP in data base. . . . . . . . . . . . . . . . . . . . . 43.0ROIP in data base . . . . . . . . . . . . . . . . . 10,628 million bblsROIP in State. . . . . . . . . . . . . . . . . . . . . 24,700 million bblsS ta te EOR =0 .56 x 1 09x 24 .7 x 10’ .. ....1.3 bi l l ion bb ls
10.6x1 O’
The State and district subdivisions used for ex-trapolation are shown in the tables of economicparameters (Table B-30 for example).
Economic Data— General
This subsection is taken directly from thereport of Lewin and Associates, Inc., to the EnergyResearch and Development Administration.97
Much of the mater ia l i s quoted di rect ly .Economic parameters are given which are used inthe model previously described. In the analysis,specific values of the parameters are calculatedbased on geographic location, reservoir depth,condition of the wells, and the existence ofwaterflooding or other secondary recovery. Alarge number of geographic areas have beenestablished. In many cases these correspond to aState, but in other cases (such as Texas) several
districts are defined within a State. Four depthcategories have been defined. Condition of thewells in a reservoir is judged by the year of mostrecent development. Existence of secondaryrecovery in a reservoir is noted from Statereports.
The general economic parameters are pre-sented through a series of tables as follows:
Table B-30
Table B-31
Table B-32Table B-33
Table B-34
Table B-35
Table B-36Table B-37
Drilling and Completion Costs forProduction and Injection WellsWell, Lease, and Field ProductionEquipment Costs—ProductionWel lsCosts of New Injection EquipmentWell Workover and ConversionCosts for Production and InjectionWel lsBasic Operating and MaintenanceCosts for Production and InjectionWel lsIncremental Injection Operatingand Maintenance CostsState and Local Production TaxesState Income Taxes.
Each exhibit presents the parameters actuallyused in the models. The first six tables are accom-panied by attachments that explain or illustratethe derivation of the parameters. All the tablesare stated in 1976 prices.
Parameters in the above tables are for onshorereservoirs. Additional economic parameters foroffshore reservoirs follow.
Appendix B ● 179
Table B-30Drilling and Completion Costs for Production and Injection Wells
(dollars per foot of drilling and completion)
State/district
CaliforniaEast central. . . . . . . . . . . . . . . . . .Central coast . . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
</ 200’wD . . . . . . . . . . . . . .201 -400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>800’WD . . . . . . . . . . . .
LouisianaNorth. . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’wD. . . . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401-800’WD. . . . . . . . . . . . . .>=800’WD. . . , . . . . . . . . . . .
Texasl... . . . . . . . . . . . . . . . . . . . . . . .2 . . . . . . . . . . . . . . . . . . . . .3::::. . . . . . . . . . . . . . . . . . . . . .4... . . . . . . . . . . . . . . . . . . . . . . .5... . . . . . . . . . . . . . . . . . . . . . . .6... . . . . . . . . . . . . . . . . . . . . . . .70 . . . . . . . . . . . . . . . . . . . . . . . . .7C . , , , , , , , . . . . . . . .8... . . . . . . . . . . . . . . . . . . . . . . .8A . . . . . . . . . . . . . . . . . . . . . . . . .9... . . . . . . . . . . . . . . . . . . . . . . .lo . . . . . . . . . . . . . . . . . . . . . . . . .Offshore. . . . . . . . . . . . . . . . . . . .
<=200’wD. . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401-800’WD. . . . . . . . . . . . . .>=800’WD. . . . . . . . . . . . . . . .
New MexicoEast . . . . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . .Kansas
West. . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth . . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
1234
567
89
1011121314151617181920
232425
3031
323334
3536
4041
0-2,500’
31.6042.6139.7175.88
N.A.N.A.N.A.N.A.
21.8460.99
112.32N.A.N.A.N.A.N.A.
17.9418.0032.2828.2316,7132.6613.3030.9130.8617.4914.7224.77
112.32N.A.N.A.N.A.N.A.
35.1545.3820.37
15.7215.72
17.7417.7420.57
20.3745.38
23.3223.32
Depth category
2500-5,000’
28.0342.7049.7459.99
N.A.N.A.N.A.N.A.
21.6253.00
110.32N.A.N.A.N.A.N.A.
23.9127.1537.0924.1726.2319.1919.9420.6023.1518.0023.3818.68
110.32N.A.N.A.N.A.N.A.
31.2522.5725.10
20.0720.07
20.0420.04
‘25.10
25.1022.57
23.3223.32
5,000-10,000’
50.0245.3546.8156.38
N.A.N.A.N.A,N.A.
37.9846.95
109.42N.A.N.A.N.A.N.A.
31.3428.3634.1223.4632.5131.5120.9926.5031.6624.8728.3227.27
109.42N.A.N.A.N.A.N.A.
34.0025.2730.59
23.0323.03
26.4826.4830.59
30.5925.27
23.6923.69
1o,ooo-15,000’
93.6274.7170.1064.59
N.A.N.A.N.A,N.A.
33.9357.62
103.20N.A.N.A.N.A.N.A.
35.0033.4063.7577.6755.9660.96
N.A.43.4243.8541.5833.0048.41
103.20N.A.N.A.N.A.N.A.
50.0134.0049.61
34.0034.00
33.5033,5049.61
49.6134.00
56.2556.25
180 . Appendix B
Table B-3 Cont.—
State/district
AlabamaHi sulphur. . . . . . . . . . . . . . . . . . .Lo sulphur. . . . . . . . . . . . . . . . . . .
FloridaHi sulphur. . . . . . . . . . . . . . . . . . .Lo sulphur. . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana. ........, . . . . . . . . . . . . . . . . .Ohio
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
KentuckyWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania. . . . . . . . . . . . . . . . . . . . . .New York . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .Alaska
North Slope . . . . . . . . . . . . . . . . .Cook Inlet . . . . . . . . . . . . . . . . . . .
Geographicunit
4243
44455053555758596061
6263
6465
666770717273
8031
0-2,500’
28.2628.26
28.2628.2645.3839.1842.2415.9826.0026.0024.4624.46
24.4615.38
24.4615.38
24.4615.3815.3815.3815,3815.38
N.A.N.A.
N.A. = not applicable.
Tabie B-31
State/district
Depth category
2,500-5,000’
27.9427.94
27.9427.9422,5742.0047.0730.0531.0531.0526.4326.43
26.4319.09
26.4319.09
26.4319.0919.0919.0919.0919.09
N.A.N.A.
5,000-10,000’
Weii,Lease,and Fieid Production Equipment Costs-Production Wells
(dollars per production well)
CaliforniaEast Central . . . . . . . . . . . . . . . . .Central Coast... . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’wD. . . . . . . . . . . . . . . .201-400’WD. . . . . . . . . . . . . .401-800’WD . . . . . . . . . . . . . .>800’WD . . . . . . . . . . . . . . .
LouisianaNorth . . . . . . . . . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .
N.A. = nonapplicable.
Geographicunit
1234
90919293
56
40.0040.00
40.0040.0025.2745.1334.8136.8037.8737.8732.7432.74
32.7418.14
32.7418.14
32.7418.1418.1418.1418.1418.14
370.00190.00
1o,ooo-15,000’
55.6955.69
55.6955.6934.0093.48
104.6948.9845,1045.1050.0050.00
50.0030.00
50.0030.00
50.0030.0030.0030.0030.0030.00
340.00180.00
Depth category
0-2,500’
33,30033,30033,300
300,000300,000300,000
N.A.N.A.
23,50024,700
2,500-5,000’
51,90051,90051,900
300,000300,000300,000
N.A.N.A.
45,60047,300
5,000-10,000’
47,20047,20047,200
300,000300,000300,000
N.A.N.A.
50,50052,900
1o,ooo-15,000’
51,20051,20051,200
300,000300,000300,000
N.A.N.A.
44,40048,800
Appendix B ● 181
Table B-31—Cent.
State/district
Offshore . . . . . . . . . . . . . . . . . . . .<=200’WD” . . . . . . . . . . .
201 -400’WD . . . . . . . . . . . . . .401-800’WD . . . . . . . . . . . . . .>=800WD . . . . . . . . . . .
Texasl . . . . . . . . . . . . . . . . . . . . . . . . . .2 . . . . . .3 : : : : : : : : : : : : : : : : : : : : . . . . . .4 . . . . . . . . . . . . . . . . . . . . . . . .5::. . . . . . . . . . . . . . . . . . . . . . . .6 . . . . . . . . . . . . . . . . . . . . . . . .7B” : . . . . . . . . . . . . . . . . . . . . . . . .7C . . . . . . . . . . . . . . . . . . . . . . . . .88 A : : : : : : : : : : : : : : : : : : : : : : : : :9... . . . . . . . . . . . . . . . . . . . . . . .lo . . . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’wD . . . . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401-800’WD . . . . . . . . . . . . . .>=800’WD. . . . . . . . . . . . . . . .
New MexicoEast . . . . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .Kansas
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth. . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
AlabamaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
FloridaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah. . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming. . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana. . . . , . . . . . . . . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
795969798
89
101112131415161718192095969798
232425
3031
323334
3536
4041
4243
44455053555758596061
.
0-2,500’
300,000300,000300,000
N.A.N.A.
23,50023,50023,50023,50023,50023,50023,10023,10023,10023,10023,10024,900
300,000300,000300,000
N.A.N.A.
23,10035,60024,900
24,90024,900
24,90023,50024,900
24,90035,600
23,50023,500
N.A.23,500
N.A.23,50035,60035,60035,60035,60035,60035,60024,90024,900
Depth category
2,500-5,000’
300,000300,000300,000
N.A.N.A.
45,60045,60045,60045,60045,60045,60032,90032,90032,90032,90032,90037,100
300,000300,000300,000
N.A.N.A.
32,90045,40037,100
37,10037,100
37,10045,60037,700
37,10045,400
45,60045,600
N.A.45,600
N.A.45,60045,40045,40045,40045,40045,40045,40037,10037,100
5,000-10,000’
300,000300,000300,000
N.A.N.A.
50,50050,50050,50050,50050,50050,50052,40052,40052,40052,40052,40049,100
300,000300,000300,000
N.A.N.A.
52,40076,90049,100
49,10049,100
49,10050,50049,100
49,10075,900
50,50050,500
N.A.50,500
N.A.50,50076,90076,90076,90076,90076,90076,90049,10049,100
1o,ooo-15,000’
300,000300,000300,000
N.A.N.A.
44,40044,40044,40044,40044,40044,40045,20045,20045,20045,20045,20058,200
300,000300,000300,000
N.A.N.A.
45,20068,20058,200
58,20058,200’
58,20044,40058,200
58,20068,200
44,40044,400
N.A.44,400
N.A.44,40068,20068,20068,20068,20068 ,20068,20058,20058,200
182 . Appendix B
Table B-31-Cent.
Depth category
10,000-1 5,000’
Geographicunit
2,500-5,000’
5,000-1 0,000’State/district
OhioWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
KentuckyWest . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania. . . . . . . . . . . . . . . . . . . . . .New York . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .Alaska
North Slope . . . . . . . . . . . . . . . . .Cook Inlet . . . . . . . . . . . . . . . . . . .
0-2,500’
6263
6465
666770717273
8081
24,9008,400
24,9008,400
24,9008,4008,4008,4008,4008,400
N.A.N.A.
37,10017,000
49,100N.A.
58,200N.A.
N.A.N.A.
N.A.N.A.N.A.N.A.N.A.N.A.
N.A.N.A.
37,10017,000
N.A.N.A.
37,10017,00017,00017,00017,00017,000
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 equip-Well, lease, and field production equipment designed for sec-
ondary but excluding Injection equipment Includes all items excepttubing and wellheads (which are Included In JAS drilling costs) re-quired to lift the fluid to the surface at the producing wellhead byartiflcial lift, Including rod pump, gas Iift, or hydraulic lift, depending
ment to process the produced fluids prior to custody transfer. Themajor items included are: heater-treater, separator, well testingsystem, tanks, flow levers from producing wells, water disposalsystems, and, when applicable, crude desulphurizatlon facilities.These are average costs per production well.
Table B-32Costs of New Injection Equipment
(dollars per injection well)
Depth category
2,500-5,000’
Geographicunit
5,000-1 0,000’
10,000-1 5,000’State/district 0-2,500’
CaliforniaEast Central . . . . . . . . . . ... , . . .Central Coast. . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<= 200’wD . . . . . . . . . . . . . . . .
201 -400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>=800’WD . . . . . . . . . . . . .
LouisianaNorth. . . . . . . . . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<= 200’wD . . . . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401 -800’WD , . . . . . . . . . . . . .>=800W D . . . . . . . . . . . . . . . .
1234
90919293
567
95969798
30,50030,50030,500
100,000N.A.N.A.N.A.N.A.
28,50031,100
100,000100,000100,000
N.A.N.A.
30,50030,50030,500
100,000N.A.N.A.N.A.N.A.
28,50031,100
100,000100,000100,000
N.A.N.A.
48,50048,50048,500
150,000N.A.N.A.N.A.N.A.
45,30052,300
150,000150,000150,000
N.A.N.A.
48,50048,50048,500
150,000N.A.N.A.N.A.N.A.
45,30052,300
150,000150,000150,000
N.A.N.A.
N.A. = not applicable.
Table B-32-Cent.
State/district
Texas1 . . . . . . . . . . . . . . . . . . . . . . . . . .23 : : : : : : : : : : : : : : : : : : ” : : : : : : :45 : : : : : : : : : : : : : : : : : : : : : : : : : :6... . . . . . . . . . . . . . . . . . . . . . . .70 . . . . . . . . . . . . . . . . . . . . . . . . .7C . . . . . . . . . . . . . . . . . . . . . . . . .8... . . . . . . . . . . . . . . . . . . . . . . .8A . . . . . . . . . . . . . . . . . . . . . . . .9.....,....., . . . . . . . . . . . . . .10 . . . . . . . . . . . . . . . . . . . . . . . . .Offshore. . . . . . . . . . . . . . . . . . . .
<=200’WID . . . . . . . .201-400’WD. . . . . . . . . . . . . .401-800’WD. . . . . . . . . . . . .>=800WD. . . . . . . . . . . . . . .
New MexicoEast . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . .
Oklahoma. . . . . . . . . . . . . . . . . . . . . . . .Kansas
West . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth. . . . . . . . . . . . . . . . . . . . . .South, . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .west . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
AlabamaHiSulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
FloridaHiSulphur. . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . ., . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .Ohio
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Geographicunit
89
101112131415161718192095969798
232425
3031
323334
3536
4041
4243
44455053555758596061
6263
Appendix B• 18.3
0-2,500’
28,50028,50028,50028,50028,50028,50027,70027,70027,70P27,70027,70030,000
100,000100,000100,000
N.A.N.A.
27,70042,80030,000
30,00030,000
30,00028,50030,000
30,00042,800
28,50028,500
28,50028,500
28,50028,50042,80042,80042,80042,80042,80042,80030,00030,000
30,00012,200
“Depth category
2,500-5,000’
28,50028,50028,50028,50028,50028,50027,70027,70027,70027,70027,70030,000
100,000100,000100,000
N.A.N.A.
27,70042,80030,000
30,00030,000
30,00028,50030,000
30,00042,800
28,50028,500
28,50028,500
28,50028,50042,80042,80042,80042,80042,80042,80030,00030,000
30,00012,200
5,000-10,000’
45,30045,30045,30045,30045,30045,30044,10044,10044,10044,10044,10064,100
150,000150,000150,000
N.A.N.A.
44,10074,70064,100
64,10064,100
64,10045,30064,100
64,10074,700
45,30045,300
45,30045,300
45,30045,30074,70074,70074,70074,70074,70074,70064,10064,100
64,100N.A.
1o,ooo-15,000’
45,30045,30045,30045,30045,30045,30044,10044,10044,10044,10044,10064,100
150,000150,000150,000
N.A.N.A.
44,10074,70064,100
64,10064,100
64,10045,30064,100
64,10074,700
45,30045,300
45,300451300
45,30045,30074,70074,70074,70074,70074,70074,70064,10064,100
64,100N.A.
N,A. = not applicable
—-
184 . Appendix B
Tabie B-32--Cent.
State/districtGeographic
unit
KentuckyWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania. . . . . . . . . . . . . . . . . . . . . .New York . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .Alaska
North Slope . . . . . . . . . . . . . . . . .Cook Inlet . . . . . . . . . . . . . . . . . . .
6465
666770717273
8081
N.A
Note:Cost of
eludes the
“Depth category
2,500-0-2,500’ 5,000’
30,00012,200
30,00012,20012,20012,20012,2(-)012,200
N.A.N.A.
30,00012,200
30,00012,20012,00012,00012,20012,000
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,ooo-15,000’
N.A.N.A.
N.A.N.A.N.A.N.A.N.A.N.A.
N.A.N.A,
= not applicable.
water injection equipmentequipment 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 AWell 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 costrecovery process over (conversion percent
costs)
More than 25 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 100 10016 to 25. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 80 406 to 15. ...., . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 64 161 to 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 0
Table B-33: Part BWell Workover and Conversion Costs for Production and injection Wells
(dollars per well)
State/district
CaliforniaEast Central . . . . . . . . . . . . . . . . .Central Coast. . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore. . . . . . . . . . . . . . . . . . . .
<=200’WD . . . . . . . . . . . . . . . .
201 -400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>800’WD . . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
1234
90919293
0-2,500’
20,40020,40020,400
150,000N.A.N.A.N.A.N.A.
Depth category
2,500-5,000’
50,20050,20050,200
150,000N.A.N.A.N.A.N.A.
5,000-1 0,000’
103,400103,400103,400170,000
N.A.N.A.N.A.N.A.
10,000-1 5,000’
220,000220,000220,000225,000
N.A.N.A.N.A.N.A.
Appendix B . 185Table B-33: Part B-Cent.
State/district
LouisianaNorth. ... , . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’WD. . . . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401-800’WD. . . . . . . . . . . . . .>800'WD . . . . . . . . . . . . . . .
Texasl . . . . . . . . . . . . . . . . . . . . . . . . . .2 . . . . . . . . . . . . . . . . . . . . . . . . . .3 . . . . . . . . . . . . . . . . . . . . . . . . . .4 . . . . . . . . . . . . . . . . . . . . . . . . . .5 . . . . . . . . . . . . . . . . . . . . . . . . . .6 . . . . . . . . . . . . . . . . . . . . . . . .70” : . . . . . . . . . . . . . . . . . . . . . . . .7C . . . . . . . . . . . . . . . . . . . . . . . . .88 A : : : : : : : : : : : : : : : : : : : : : : : : :9 . . . . . . . . . . . . . . . . . . . . . . . . . .lo . . . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=2()()’wD. . . . . . . . . . . . . . , .201-400’WD . . . . . . . . . . . . . .401-800’WD. ..,, . . . . . . . . .>=800'WD. . . . . . . . . . . . . .
New MexicoEast . . . . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .Kansas
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth . . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
AlabamaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
FloridaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah. . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
567
95969798
89
101112131415161718192095969798
232425
3031
323334
3536
4041
4243
44455053555758
0-2,500’
21,70035,400
150,000150,000150,000
N.A.N.A.
21,70021,70021,70021,70021,70021,70016,90016,90016,90016,90016,90017,400
150,000150,000150,000
N.A.N.A.
16,90034,70017,400
17,40017,400
17,40021,70017,400
17,40034,700
30,00021,700
30,00021,700
30,00021,70034,70034,70034,70034,70034,700
Depth category
2,500-5,000’
38,20069,000
150,000150,000150,000
N.A.N.A.
38,20038,20038,20038,20038,20038,20027,40027,40027,40027,40027,40029,700
150,000150,000150,000
N.A.N.A.
27,40050,90029,700
29,70029,700
29,70038,20029,700
29,70050,900
50,00038,200
50,00038,200
50,00038,20050,90050,90050,90050,90050,900
5,000-10,000’
64,10094,000
170,000170,000170,000
N.A.N.A.
64,10064,10064,10064,10064,10064,10057,50057,50057,50057,50057,50059,800
170,000170,000170,000
N.A.N.A.
57,50076,90059,800
59,80059,800
59,80064,10059,800
59,80076,900
100,00064,100
100,00064,100
100,00064,10076,90076,90076,90076,90076,900
1o,ooo-15,000’
135,000139,700225,000225,000225,000
N.A.N.A.
135,000135,000135,000135,000135,000135,000133,400133,400133,400133,400133,400132,500225,000225,000225,000
N.A.N.A.
133,400147,500132,500
132,500132,500
132,500135,000132,500
132,500147,500
200,000135,000
200,000135,000
200,000135,000147,500147,500147,500147,500147,500
186 . Appendix B
Table B-33: Part B-Cent.
State/district
South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .Ohio
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
KentuckyWest. . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania. . . . . . . . . . . . . . . . . . . . . .New York . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .Alaska
North Slope . . . . . . . . . . . . . . . . .Cook Inlet . . . . . . . . . . . . . . . . . . .
Geographicunit
596061
6263
6465
666770717273
8081
Depth category
0-2,500’
34,70017,40017,400
17,4008,900
17,4008,900
17,4008,9008,9008,9008,9008,900
N.A.N.A.
2,500-5,000’
50,90029,70029,700
29,70029,500
29,70029,500
29,70029,50029,50029,50029,50029,500
N.A.N.A.
5,000-10,000’
76,90059,80059,800
59,800N.A.
N.A.N.A.
N.A.N.A.N.A.N.A.N.A.N.A.
N.A.N.A.
1o,ooo-15,000’
147,500132,500132,500
132,500N.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 orwells and equipment for production or injection service for EOR. conversion.
Table B-34Bask Operating and Maintenance Coats for Production and Injection Wells
(dollars per well per year)
State/district
CaliforniaEast Central . . . . . . . . . . . . . . . . .Central Coast. . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’WD . . . . . . . . . . . . . . . .
201-400’WD . . . . . . . . . . . . . .401-800’WD . . . . . . . . . . . . . .>=800’WD . . . . . . . . . . . . . . . .
LouisianaNorth. . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<= 200’wD . . . . . . . . . . . . . .
201 -400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>=800’WD . . . . . , . . . . . . . . . .
Texas1 . . . . . . . . . . . . . . . . . . . . . . . . . .2 . . . . . . . . . . . . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
1234
90919293
567
95969798
89
0-2,500’
11,60011,60011,60060,00060,00060,00060,00060,000
9,9008,800
60,00060,00060,00060,00060,000
9,9009,900
Depth category
2,500-5,000’
15,70015,70015,70060,00060,00069,00072,00084,000
13,90012,20060,00060,00069,00072,00084,000
13,90013,900
5,000-1 0,000’
17,50017,50017,50075,00075,00084,00090,000
105,000
16,50015,20075,00075,00084,00090,000
105,000
16,50016,500
10,000-1 5,000’
19,80019,80019,80075,00075,00084,00090,000
105,000
16,90015,80075,00075,00084,00090,000
105,000
16,90016,900
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 MexicoEast . . . . . . . . . . . . . . . . . . . . . . . .West. . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .Kansas
West. . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth . . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
AlabamaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
FloridaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . .Ohio
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
KentuckyWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Geographicunit
101112131415161718192095969798
232425
3031
323334
3536
4041
42”43
44455053555758596061
6263
6465
6667
0-2,500’
9,9009,9009,9009,9008,0008,0008,0008,0008,000
10,00060,00060,00070,00072,00084,000
8,0008,700
10,000
10,00010,000
10,0009,900
10,000
10,0008,700
15,0009,900
15,0009,900
15,0009,9008,7008,7008,7008,7008,7008,7006,0006,000
6,0002,300
6,0002,300
6,0002,300
Depth category
2,500-5,000’
13,90013,90013,90013,900
8,6008,6008,6008,6008,600
11,10060,00060,00070,00072,00084,000
8,60014,40011,100
11,10011,100
11,10013,90011,100
11,10014,400
21,00013,900
21,00013,900
21,00013,90014,40014,40014,40014,40014,40014,400.6,7006,700
6,7002,600
6,7002,600
6,7002,600
5,000-10,000’
16,50016,50016,50016,50011,70011,70011,70011,70011,70015,50075,00075,00084,00090,000
105,000
11,70025,50015,500
15,50015,500
15,50016,50015,500
15,50025,500
24,60016,500
24,60016,500
24,60016,50025,50025,50025,50025,50025,50025,000
9,9009,900
9,900N.A.
N.A.N.A.
N.A.N.A.
1o,ooo-15,000’
16,90016,90016,90016,90013,00013,00013,00013,00013,00018,00075,00075,00084,00090,000
105,000
13,00041,80018,000
18,00018,000
18,00016,90018,000
18,00041,800
27,00016,900
27,00016,900
27,00016,90041,80041,80041,80041,80041,80041,80010,80010,800
10,800N.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 . . . . . . . . . . . . . . . . . . .
Geographicunit
70717273
8081
“Depth category
2,500- 5,000- 1o,ooo-0-2,500’ 5,000’ 10,000’ 15,000’
2,3002,3002,3002,300
2,6002,6002,6002,600
N.A.N.A.N.A.N.A.
N.A.N.A.N.A.N.A.
N.A. I N.A. I N.A. I N.A.N.A. N.A. N.A. N.A.
N.A. = not applicable.Note: normal daily operating expense, surface repair and maintenance ex-
Direct annual operating expense, including waterflooding, in- pense, and subsurface repair; maintenance and services. These areeludes expenditures for operating producing wells and operating a average expenditures per producttin we//, and include the expend-water injection system. These operating expenditures include the itures of operating an injection system,
Table B-35Incremental Injection Operating and Maintenance Cost*
(dollars for injection well per year), ,
State/district
CaliforniaEast Central . . . . . . . . . . . . . . . . .Central Coast. . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’wD . . . . . . . . . . . . . . . .
201-400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>800’WD . . . . . . . . . . . . . . . .
LouisianaNorth. . . . . . . . . . . . . . . . . . . . . . .South. . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<= 200’WD . . . . , . . . . , . . . . . .201 -400’WD . . . . . . . . . . . . . .401 -800’WD . . . . . . . . . . . . . .>=800’WD . . . . . . . . . . . . . . . .
Texas1 . . . . . . . . . . . . . . . . . . . . . . . . . .2 . . . . . . . . . . . . . . . . . . . . . . . . . .3 . . . . . . . . . . . . . . . . . . . . . . . . . .4 . . . . . . . . . . . . . . . . . . . . . . . . . .5 . . . . . . . . . . . . . . . . . . . . . . . . . .6 . . . . . . . . . . . . . . . . . . . . . .7B” : : : . . . . . . . . . . . . . . . . . . . . . .7C . . . . . . . . . . . . . . . . . . . . . . . . .88 A : : : : : : : : : : : : : : : : : : : : : : : : :9 . . . . . . . . . . . . . . . . . . . . . . . . . .lo . . . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . .
<=200’wD. . . . . . . . . . . . . . . .201-400’WD . . . . . . . . . . . . . .401-800’WD . . . . . . . . . . . . . .>=800'WD . . . . . . . . . . . . . . .
N.A. = not applicable.
Geographicunit
1234
90919293
567
95969798
89
101112131415161718192095969798
0-2,500’
7,7007,7007,700
40,00040,00040,00040,00040,000
6,6006,000
40,00040,00040,00040,00040,000
6,6006,6006,6006,6006,6006,6005,4005,4005,4005,4005,4006,700
40,00040,00045,00048,00056,000
Depth category
2,500-5,000’
6,9006,9006,900
40,00040,00056,00048,00056,000
9,3008,100
40,00040,00056,00048,00056,000
9,3009,3009,3009,3009,3009,3005,8005,8005,8005,8005,8007,400
40,00040,00045,00048,00056,000
5,000-10,000’
11,60011,60011,60050,00050,00056,00060,00070,000
11,00010,10050,00050,00056,00060,00070,000
11,00011,00011,00011,00011,00011,000
7,8007,8007,8007,8007,800
10,30050,00050,00056,00060,00070,000
1o,ooo-15,000’
13,20013,20013,20050,00050,00056,00060,00070,000
11,30010,60050,00050,00056,00060,00070,000
11,30011,30011,30011,30011,30011,300
8,6008,6008,6008,6008,600
12,00050,00050,00056,00060,00070,000
—
Appendix B . 189
Table B-35-Cent.
State/district
New MexicoEast . . . . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . .Kansas
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
ArkansasNorth . . . . . . . . . . . . . . . . . . . . . . .South . . . . . . . . . . . . . . . . . . . . . . .
Missouri. . . . . . . . . . . . . . . . . . . . . . . . . .Nebraska
Central . . . . . . . . . . . . . . . . . . . . .West . . . . . . . . . . . . . . . . . . . . . . .
MississippiHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
AlabamaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
FloridaHi Sulphur. . . . . . . . . . . . . . . . . . .Lo Sulphur . . . . . . . . . . . . . . . . . .
Colorado . . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . . . . . .South Dakota . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . .Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . .Ohio
West . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . .
KentuckyWest . . . . . . . . . . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
TennesseeWest ...,..... . . . . . . . . . . . . . .East . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania. . . . . . . . . . . . . . . . . . . . . .New York . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . . . . . . . . . . .Alaska
North Slope . . . . . . . . . . . . . . . . .Cook inlet . . . . . . . . . . . . . . . . . . .
N.A. = not applicable.
Note:
Geographicunit
232425
3031
323334
3536
4041
4243
44455053555758596061
6263
6465
666770717273
8081
Direct annual operating expense, including waterflooding, in-eludes expenditures for operatlng produclng 011 wells and operatinga water injection system, These operating expenditures Include the
0-2,500’
5,4005,8006,700
6,7006,700
6,7006,6006,700
6,7005,800
10,0006,600
10,0006,600
10,0006,6005,8005,8005,8005,8005,8005,8004,0004,000
4,0001,600
4,0001,600
4,0001,6001,6001,6001,6001,600
N.A.N.A.
Depth category
2,500-5,000’
5,8009,6007,400
7,4007,400
7,4009,3007,400
7,4009,600
14,0009,300
14,0009,300
14,0009,3009,6009,6009,6009,6009,6009,6004,4004,400
4,4001,800
4,4001,800
4,4001,8001,8001,8001,8001,800
N,A.N.A.
5,000-10,000’
7,80017,00010,300
10,30010,300
10,30011,00010,300
10,30017,000
16,40011,000
16,40011,000
16,40011,00017,00017,00017,00017,00017,00017,000
6,2006,200
6,200N,A.
N.A.N.A.
N.A.N.A.N.A.N.A.N.A.N.A.
N.A.N.A.
1o,ooo-15,000’
8,60027,90012,000
12,00012,000
12,00011,30012,000
12,00027,900
18,00011,300
18,00011,300
18,00011,30027,90027,90027,90027,90027,90027,900
7,2007,200
7,200N.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 malntenanceex-pense, and subsurface repair; maintenance and services These areaverage expenditures perproduc(iorrwel~ and include the expend-Itures of operating an injection system,
190 . Appendix B
Table B-36State and Local Production Taxes
Includes Severance, Ad Valorem, and Other Local Taxes.
GeographicState/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 . . . . . . . . . . . . . . . . . . .
1-45-7
8-1923-24
2530-3132-33
3435-3640-4142-4344-45
5053555758596061
62-6364-6566-67
6970717273
80-81
0.0800.1290.0820.0900.0710.0500.0600.0500.0460.0600.0610.0500.1000.0500.1000.0500.0500.0000.0200.0500.0500.0500.0500.0500.0500.0500.0500.0500.080
Source: State tax records.
Offshore Costs
Basic offshore developmentcosts were placed in one of two
and operatingcategories, de-
pending on whether the costs varied or not withwater depth. They were derived from U.S. Bureauof Mines data and a Lewin and Associates, Inc.,study for OTA. All costs were updated tomid-1976 using similar inflation indices as ap-piied for the onshore cost models.
Costs That Do Not Vary With Water Depth
Three cost items within basic developmentand operating costs, while varying by reservoir
Table B-37State Income Taxes
State Income Tax Rates for Corporations.
GeographicState/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 . . . . . . . . . . . . . . . . . . .
1-45-78-19
23-2425
30-3132-33
3435-3640-4142-4344-45
5053555758596061
62-6364-6566-67
6970717273
80-81
0.090.04—
0.030.040.040.050.050.050.030.050.050.050.040.05—
0.060.04—
0.050.050.050.050.050.050.100.050.050.05
‘Percent of value of gross production, paid in year incurred.
Source: Local and State tax records verified by production comp-any data,
depth, are not materially affected by waterdepth. These are:
●
●
●
well, lease, and field equipment costs forproducing wells;
New injection equipment for injectionwells;and
Well workover and conversion costs.
These cost data are presented in table B-38.
Air costs (for injection) were set at the samevalue as in the in situ combustion cost model.
Appendix B . 191
Table B-38Offshore Costs That Do Not Vary by Water Depth
(costs in dollars)
I Reservoir depth categories
Activity0- 2,400-
15,000- 10,000-
2,500’ 5,000’ 1 0,000’ 1 5,000’
Well, lease, and field equipment costs per productionwell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New injection equipment per injection well . . . . . . .Well workover and conversion costs per well. . . . . .
300,000100,000150,000
300,000100,000150,000
300,000150,000170,000
300,000150,000225,000
Costs That Vary With Water Depth . Incremental injection, operating, and main-
The remaining three offshore developmenttenance 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 thedrilling and completion costs by water depth.
Basic operating and maintenance costs,
Table B-39Offshore Costs That Vary by Water Depth
(costs in dollars)
Activity
Drilling and completion costs per foot per well, bywater depth:
<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic operating and maintenance costs per well peryear, by water depth:
<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,
Incremental injection operating and maintenancecosts per injection well per year, by water depth:
<200 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .201-400 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .401-800 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .>800 ft.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0-2,500”
112.32112.32112.32112.32
60,00060,00060,00060,000
40,00040,00040,00040,000
—Reservoir depth categories
2,500-5,000’
96.87130.64225.82522.30
60,00069,00072,00084,000
40,00046,00048,00056,000
5,000-1 00,000’
101.44121.49178.00354.04
75,00084,00090,000
105,000
50,00056,00060,00070,000
100,000-1 50,000’
97.87111.24148.92266.27
75,00084,00090,000
105,000
50,00056,00060,00070,000
“No reservoirs in this depth category-average figure used in water depth categories.
192 . Appendix B
Tabie B-40Driiiing 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 @ $8.7million / 18 dots 1/2@ $11./mil l ion / 24 slots . . . . . . . . .Line (8) / Line (2) (wght. av. depth) = Av. platformcost/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
110.324,760
524,020
7,000,000388,900
135,12028.45
325,00068.4296.87
28.45
485,400
102.19130.64
28.45937,500
197.37225.82
28.452,345,800
493.85522.30
Depth category
5.000-10.000
109.428,000
875 ,360
7,000,000388,900
486,46060.81
325,00040.63
101.44
60.81
485,400
60.68121.49
60.81937,500
117.19178.00
60.812,345,800
293.23354.04
10,000-15,000
103.2012,000
1,238,400
7,000,000388,900
849,50070.79
325,00027.0897.87
70.79
485,400
40.45111.24
70.79937,500
78.13148.92
70.792,345,800
195.48266.27
Appendix B . 793
Appendix BFootnotes
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 WaterfloodsUsing 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,” P r o d u c e r sMonth/y, December 1953, pp. 20-29.
4W.B. Gogarty and W.C. Tosch, “ M i s c i b l e - T y p evVaterflooding: Oil Recovery with Micellar Solut ions,” ).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.
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bW. B. Gogarty, “Mobility Control with Polymer Solu-tion,” 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 Mara-floodTM Process,” Proceedings, Tertiary Oil Recovery Con-ference, 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 BradfordField, ” SP[ 4753, Improved Oil Recovery Symposium ofSPE of AlME, Tulsa, Okla., Apr. 22-24, 1974.
I ISA. pursley, R.N . Healy, and El. Sandvik, “A Field Testof 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 SurfactantSystem for Oil Recovery, Benton Field, Ill.” /. Pet. Tech.,February 1973, p. 195.
IIR,H, Wlcjmyer, A. Satter, G.D. Frazier, and R.H. Croves,
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1‘Ibid.
15L.K, Strange ancf A.W. Talash, “Analysis of Salem L o wTension Waterflood Test, ” SP[ 5885, Improved Oil Recov-
ery 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 onEnhanced Oil, Gas Recovery, and Improved DrillingMethods, Aug. 30-Sept. 1, 1977, p. A-5.
19R.N. Healy, R.L. Reed, and C.W. Carpen te r , “ALaboratory 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, April1977.
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ZZS/oss Fie/d, Amoco Production Co., Improved Oil
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23s. A. Pursley, R.N . Healy, and El. Sandvik, “A Field Testof Surfactant Flooding, Loudon, Ill. ” ). Pet. Tech., July 1973,.p. 793.
Z’Lloyd Elkins, HOW Might the /dependent Move fromSpectator to Participant in the Enhanced Oil RecoveryGame?, Second Tertiary Oil Recovery Conference, TertiaryOil Recovery Project, University of Kansas, Apr. 20-21,1977.
25C.A. Kossack, and H.L. Bilhartz, jr., “The sensitivity of
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2SJ.A. Davis, Jr., Sweep Efficiency In Micel/ar FloodingProcesses, submitted to SPE of AlME, January 1977.
27W. B Gogarty, and W.C. Tosch, “Miscible-Type
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Z6Marathon Oil Cofnpdny; Commercial Scale Demonstra-
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zgEnhanced Oi/ Recovery, N a t i o n a l f%XrOleUm COUnCil,
December 1976, p. 98.
JOEnhanced Oil Recovery, National Petroleum COUnCll,
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q6-594 O - 78 - 14
194 . Appendix B
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. .
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sjEnhanced Oi/ Recovery, National Petroleum COUncil,
37H. ]. Agnew, “Here’s How 56 Polymer Oil Recovery Proj-ects Shape Up, ” Oil and Gas /ourna/, May 1, 1972, pp.109-112.
38J.H. Maerker, “Shear Degradation of Partially Hy-drolyzed Polyacrylamide Solutions, ” Soc. Pet. Eng. )., 15, No.4, pp. 311-322.
39G. Kelco, “Kelzan MF for Viscous Waterflooding,”Technical Bulletin X2, 1973.
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Polymer Flood-Preparation and Initiation at North Stanley,Osage County, Okla.,” Paper B-2, Second ERDA Symposiumon Enhanced Oil and Gas Recovery, Tulsa, Okla, Sept. 9-10,1976.
December 1976, p. 170.
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56A.L. Hall and R.W. Bowman, “Operation and Perfor-mance 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
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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
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44v.v. Valleroy, B.T. Willman, J.B. Cambell, a n d L.W.Powers, “Deerfield Pilot Test of Recovery by Steam Drive, ”). Pet. Tech., July 1967, p. 956.
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61B.F. Grant and S.E. Szasz, “Development of an Under-ground Heat Wave for Oil Recovery,” Trans. A/ME, 207, p.108, 1954.
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45H,J, DeHaan A j. Van Lockeren, “Early Results of the Final Report, The Methodology, Energy Research and
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Gqfnhanced 0;/ Recovery, National petroleum COUnCll,
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67C.F. Gates and 1. Sklar, “Combustion As A PrimaryRecovery Process—Midway Sunset Field, ” ). Pet. Tech.,August 1971, pp. 981-986.
G8H.j. R a m e y , j., /r-r-Situ Combustion, 8th WorldPetroleum Congress, 1971, p. 260.
69w. E. Showalter ancj M.A. Maclean, “Fireflood at Brea -Ollnda Field, Orange County, Calif., ” SPE 4763, ImprovedOil 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-Si tu Combust ion Projects, ” /. Pet.TL’Ch., ]Uly 1973, pp. 784-792.
‘lBellevue Field, Getty Oil Co., Update Report, improvedOil Recovery Field Reports, SPE of AlME, Vol. 3, No. 1, June1977.
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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, NationalPetroleum Council EOR Study, Apr. 21, 1976.
T8Research and Development In Enhanced Oil RecoveryFinal Report, The Methodology, Energy Research andDevelopment 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.
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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, “StatusOil Recovery Methods, ”Meeting of Society ofSep. 1 -Oct. 28, 1975.
83L, w. Helm and V.A.
Appendix B . 195
of COl and Hydrocarbon MiscibleSPE 5560, presented at 50th AnnualPetroleum Engineers, Dallas, Tex.
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134D. F. lvkrrzie and R.F. Nielson, “Study of Vaporizationof Crude Oil by Carbon Dioxide Repressuring, ” /. Pef. Tech,,November 1963, p. 1247.
85L.W. Helm and VA. josendal, “Mechanisms of oil Dis-
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WL W, Helm, “status of Coz and Hydrocarbon Miscible
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87L. W. Helm and VA Josendal, “Mechanisms of oil Dis-
placement by Carbon Dioxide,” ). Pet. Tech., D e c e m b e r1974, p. 1147.
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agResearCh and Development in Enhanced Oil RecoveryERDA 77/20, Lewin and Associates, Inc., December 1975,Part 1, pp. III-2.
90F.1. Stalkup, “An Introduction to Carbon Dioxide Flood-ing,” Proceedings, Tertiary Oil Recovery Conference, Terti-ary Oil Recovery Project, University of Kansas, April 1977.
91R.M. Dicharry, T.L. P e r r y m a n , a n d J.D. Ronqullle,“Evaluation and Design of a COl Miscible Flood Project OSACROC Unit, Kelly-Snyder Fiefd,” /. Pet. Tech., November1973, p. 1309.
9ZR.M. Dicharry, T.L. P e r r y m a n , a n d J.D. Ronquille,“Evaluation and Design of a COl Miscible Flood Project O
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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 F ield Reports , Society of
Petroleum Engineers of AlME.
%Research and Development In Enhanced oil Recovery
Final Report, The Methodology, Energy Research andDevelopment Administration, Part 3 of 3, ERDA 77-2013,December 1976, pp. V-1 9, 20.
g~Research and Development In Enhanced oil RecoveryFinal Report: The Methodology, Energy Research andDevelopment Administration, Part 3 of 3, ERDA 77-2013,December 1976, pp. V-1 9, 20.
Appendix C
Legal Aspects of EnhancedOil Recovery
Page
INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......................199
U N I T I Z A T I O N : VOLUNTARY AND Compulsory . . . . . . . . . . . . . . . . . . . . . . . . . . .199Basic principles of Oil and Gas Law. . . . . . . . . . . . . . . . . . . .................199
The Rule of Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............201Conservation Regulation: Well Spacing and Prorationing. . . . ... ... ....202
pooling and Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............202Pooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........202Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203
Voluntary Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............203Time of Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............203Who May Unitize . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....203Negotiation of Unit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...204
Compulsory Unitization . . . . . . .. .. .. . . $ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211Procedure for Fieldwide Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212
Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................213Proof of Findings Required . . . . . . . . . . . . . . . . . . . . . . . ................213Entry of the Order for Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214Amendment and Enlargement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....215Effect of Unitization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215Allowables and Well Spacing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...216Administrative and Judicial Encouragement to Unitization . . . . . . . .. ....216
APPROVAL OF ENHANCED RECOVERY PROJECTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217Permit Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................217
Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .217Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................218Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218Order . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........................219
Injection Regulations Under the Safe Drinking Water Act. . ................219
OPERATIONAL ASPECTS OF ENHANCED OIL RECOVERY . . . . . . . . . . . . . . . . . . . . . . 221Potential Liability to Conjoining Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221Environmental Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223
Environmental Impact Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...223
197
Page
Air Pollution, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224Other Environmental Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225
Water Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225Lessor-Lessee Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225Riparian and Appropriation Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226State Regulation of Water Use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227
LIST OF TABLES
TableNumber Page
c-1 Unitization Statutes: Voluntary and Compulsory . . . . . . . . . . . . . . . . . . . . . . . 228c-2 Comparative Chart of Aspects of State Unitization Statutes. . . . . . . . . . . . . . 229
198
Appendix C . 199
Introduction
The purpose of this appendix is to providedetails of legal issues associated with enhancedoil recovery (EOR). The term “enhanced oilrecovery” refers to any method of oil production
in which gases and/or liquids are injected intothe reservoir to maintain or increase the energy ofthe reservoir or react chemically with the oil toimprove recovery. Thus, enhanced recovery en-compasses the techniques referred to as pressuremaintenance, secondary recovery, and tertiaryrecovery. The reason for the broader use of theterm in this section is the fact that the legalproblems are much the same for any technique ofoil recovery beyond primary methods. There hasbeen relatively little commercial application oftertiary recovery techniques, so no body of caselaw specifically regarding it has developed; thelaw in this area must draw upon experience inpressure maintenance and established methodsof secondary recovery. Secondly, the regulatoryschemes of most States do not distinguish amongthe different types of recovery beyond primarymethods. Distinctions among the various tech-
niques of enhancing recovery will be made onlywhen necessary.
To assess fully how the law encourages, hin-ders, limits, or prevents employment of EORtechniques, it would be necessary to examine indetail each reservoir in which such techniques areor might be used. Such was beyond the scope ofthis assessment. The approach used here iden-tifies existing or possible constraints without at-tempting to suggest how much more or less oilcould be produced with or without particularconstraints. Statutes, regulations, and rules of lawaffecting EOR are described in a general waywithout discussing their applicability to particularfields, not only because the complex interplayamong various factors makes specific judgmentsabout individual fields very difficult, but alsobecause the law on some important points is un-decided or very uncertain in most jurisdictions.The views of producers and State regulatory per-sonnel are discussed when appropriate, as are theobservations and comments of legal authoritieson particular subjects.
Unitization: Voluntary and Compulsory
Basic Principles of Oil and Gas Law
The most efficient means of utilizing EOR tech-niques is generally to treat the entire oil reservoiras though it were a single producing mechanismor entity. There is no problem with this when theoperator of the field owns the leasehold ormineral interest throughout the entire reservoir;in this case obtaining the consent of any otherowner of an interest in the minerals in order toundertake enhanced recovery operations is un-necessary. However, where there are otherowners of interests in the same field, obtainingconsent may be necessary before fieldwideoperations may be commenced. In order to bet-ter understand the problems that may be in-volved in securing this consent or cooperation, itwould be useful to describe briefly the basic legalframework in which oil and gas operations takeplace.
The right to develop subsurface minerals in theUnited States belongs originally with the owner-ship of the surface. The different States whichhave fugacious minerals within their jurisdictionare divided as to whether such minerals areowned in place or whether the surface o w n e rowns only a right to produce the minerals thatmay lie beneath his land. For present purposesthe distinction has little significance. It is suffi-cient to point out that the ownership of the sur-face carries with it, as a normal incident ofownership, the right to develop the mineralsbeneath the surface.
The owner of the land may, however, sever theownership of the surface from ownership of theminerals. He may convey away all or a part of hisinterest in the development of the minerals andin 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 (orcompany) all of the mineral under the land ab-solutely. Or he may convey to that person a one-half interest, or some other percentage of in-terest, in all of the minerals beneath the section.Or again, he may convey to another all or a partof the minerals beneath a specific 40-acre tractcarved out of the section. Each of these interestswould be described as a mineral interest. Unlessotherwise restricted by the instrument creating it,the ownership of a mineral interest carries with itthe right to explore for, develop, and produce theminerals beneath the land.
Another type of interest that may be createdby a landowner or mineral interest owner is aleasehold interest. The owner of the minerals isnormally unable to undertake the developmentof the minerals himself because of the great ex-pense and risk of drilling. in order to obtaindevelopment without entirely giving up his in-terest in the minerals he will lease the right to ex-plore for and produce the minerals to another. Inreturn the lessee will pay a sum of money as abonus for the granting of the lease and will prom-ise to pay the lessor a royalty, generally one-eighth, on all oil and gas produced. Typically, thelessee will be granted the lease for a period of 1to 5 years (the primary term), subject to anobligation to pay delay rentals if a well is notdrilled in the first year, and so long thereafter asoil and gas or either of them is produced from theleased land (the secondary term). In addition to aroyalty interest of one-eighth, the lessor will re-tain a possibility of reverter; that is, if the delayrentals are not paid on time or production is notobtained within the primary term, or if produc-tion ceases on anything other than a temporarybasis in the secondary term, the interest leasedreverts automatically back to the lessor.1 Whenthe interest reverts, the lessor may then enter intoa new lease with another party or may undertakeor continue development himself.
The power to grant leases is often described asthe executive right, and a mineral interest may becreated with the executive power being grantedto another person. To illustrate, A as father of a
NOTE: All references to footnotes in this appendix appearon page 230.
family and owner of a tract of land may give bywill to child B a one-quarter undivided interest inthe minerals in the land, to child C a one-quarterundivided interest in the minerals, and to child Dan undivided one-half interest in the mineralstogether with the executive right to lease all theminerals. This would mean that only D could ex-ecute leases for the development of the minerals.D would be under a duty to exercise the rightwith the utmost good faith and fair dealing. Eachchild would receive a share of the proceeds fromthe development of the land (i.e., a share of thebonus, rental, and royalties), but it would beupon the terms established by D in his dealingswith the lessee in granting the lease. Under well-established principles of law, D must exercise thisright in such a manner that it does not unfairly ad-vantage him nor unfairly disadvantage theowners of the nonexecutive interests, children Band C. The duties owed by lessees to lessors androyalty owners, and the duties owed by execu-tive right owners to nonexecutive right owners,can impact upon the unitization of mineral landsfor enhanced recovery purposes. This is becausethe lessee or executive right owner must considernot only his own interest but the interests ofthose to whom he owes a duty in entering intoagreements for unitized operations.
In addition to duties, the lessee has certainrights arising from a lease that have significancefor EOR, These rights may be express or they maybe implied. They are express if the parties to thelease or deed have specifically recognized orgranted them in the conveyance. For example,the parties may explicitly provide that the lesseeshall have the right to conduct certain activitiessuch as laying pipelines on the surface of the landwithout being liable in damages. The rights areimplied if the parties have not expressly providedfor them, but the law recognizes that they existby virtue of the nature of the transaction be-tween or among the parties. Thus, the lessor andlessee may fail to provide expressly that thelessee has the right to come upon the leased landor to build a road for carrying equipment to a drillsite. The law will imply that the lessee has theright to do this when it would not be reasonablypossible to develop the minerals without under-taking such activity.
Appendix C . 201
Briefly stated, the law recognizes that evenwithout express grant, the lessee has the right touse such methods and so much of the surface asmay be reasonably necessary to effectuate thepurposes of the lease, having due regard for therights of the owner of the surface estate. It is wellestablished that the lessee does have suchrights. 2 However, the question may arise whethersuch rights are limited to those activities, eithersurface or subsurface, that could be contem-plated at the time of the execution of the lease ordeed. The same answer should be given for themore exotic methods of enhanced recovery thatthe courts have given for traditional waterfloodoperations when these were not provided for inthe lease. In allowing a waterflood project to goforward, the Appellate Court of Illinois stated in a1950 case:3
The mere fact that this method of production ismodern is no, reason to prevent its use by a ruleof law. It is true the contract of the parties doesnot specifically provide for this process, butneither does it specify any other process. Thecontract being silent as to methods of produc-tion, it must be presumed to permit any methodreasonably designed to accomplish the purposeof the lease: the recovery of the oil and the pay-ment of royalty. The court would violate funda-mental principles of conservation to insert by im-plication a provision that lessee is limited to pro-duction of such oil as can be obtained by oldfashioned means, or by so-called “primary opera-tions.”
The same rationale would apply to moremodern methods of enhanced recovery, eventhough these methods might involve somewhatgreater use of the surface and different types ofinjection substances.
A closely related question is the extent towhich the lessee or mineral grantee may usewater located on the property for purposes ofenhanced recovery. This has been an area ofsome controversy and will be taken up in a latersection because it involves matters going beyondlease and deed relationships.
F ina l l y , i t shou ld be noted that someauthorities have contended that there is not onlya right for the lessee to unitize or to undertakeenhanced recovery activities but also a duty todo so. The implied covenant of reasonable
development is well recognized in oil and gaslaw.5 It is to the effect that the lessee has theduty, where the existence of oil in paying quan-tities is made apparent, to continue the develop-ment of the property and put down as manywells as may be reasonably necessary to securethe oil for the common advantage of both thelessor and lessee. The lessee is expected to act asa prudent operator would in the same circum-stances. With increas ing exper ience withenhanced recovery, it can be argued that a pru-dent operator would, when it appears profitable,undertake enhanced recovery operations. Thus,where the lessee is reluctant to do so, the lessormight be able to require the lessee to engage insuch operations or give up the lease. Probablybecause of the difficulty or proof of profitabilityand feasibility for a particular reservoir there hasbeen little litigation on the point. However, onecourt has noted that there is “respectableauthority to the effect that there is an impliedcovenant in oil and gas leases that a lesseeshould resort to a secondary recovery methodshown to be practical and presumably profitableas a means of getting additional return from theIease .” 6 In another case the court similarlydeclared that “the Lessee not only had a right,but had a duty to waterflood the premises for therecovery of oil for the benefit of the mineralowners should it be determined by a prudentoperator to be profitable. ”7 Lessors then couldencourage enhanced recovery by making de-mands on their lessees.
The Rule of Capture
One of the most important and fundamentalprinciples of oil and gas law is the rule of capture.It stems from the fact that oil and gas arefugacious minerals; that is, they have the proper-ty of being able to move about within the reser-voir in which they are found. Followed by everyjurisdiction within the United States, the rule ofcapture is to the effect that a landowner may pro-duce oil or gas from a well located on his landeven if the oil or gas was originally in place underthe surface of another landowner, so long as theproducer does not physically trespass on theother’s land. The other landowner’s recourseagainst drainage of the petroleum under his prop-erty is the rule of capture itself: he may himselfdrill a well and produce the hydrocarbons and
202 . Appendix C
thereby prevent their migration to the property ofanother.
The problem with the rule of capture has beenthat it encouraged too rapid development of oiland gas. A landowner or his lessee must drill torecover the oil and gas beneath his property orthey will be recovered by a neighbor and lostforever to the landowner. The problem becameespecially acute when there were many smallparcels of land over a single reservoir. Overdrill-ing resulted from the rush to recover the oil andgas before it is produced by another, and theoverdrilling caused the natural pressure of thereservoir to be depleted too rapidly, therebyleaving oil in the ground that could have beenrecovered with sounder engineering practices.
Conservation Regulation: Well Spacing andProrationing
Recognizing that the rule of capture was result-ing in great loss of resources and excessive pro-duction of oil, the producing States began enact-ing legislation to modify it in the mid-1930’s. Toprevent excessive drilling the States authorizedregulatory commissions to promulgate well spac-ing rules, limiting the number of wells that can bedrilled in a given area.8 For example, the TexasRailroad Commission in Rule 37 allows, as ageneral rule, only one well every 40 acres. Ingeneral, in each major producing State specialspacing rules may be established for eachdifferent field and exceptions may be grantedupon showing of good cause.9
Well spacing alone would not be enough toovercome the problem of excessive production,for a producer might continue to produce at anexcessive rate in such a manner as to deplete pre-maturely the natural drive of the reservoir or inquantities that the market could not absorb. Toovercome this, the States established wellallowable; that is, they set a limit to the amountof oil or gas that could be produced in any 1month from a field or well. This is also known asprorationing of production. Well allowable havebeen set in two different ways. The first is knownas MER regulation: allowable are established forproduction at the maximum (or most) efficient
rate of recovery.10 The maximum efficient rate fora reservoir is established before a regulatory com-mission by expert testimony as to what would in-jure the reservoir and produce waste. This rate isnot constant, but changes with the age of thefield, and is not generally capable of exact com-putation. The second basic type of regulation ofwell allowable is known as market demandregulation: MER remains as the maximum rate ofproduction, but the rate actually allowed may belowered to a level which the commissionbelieves is the maximum amount of productionthat the market will bear for that month. This isgenerally established by the commission after ithas heard from producers as to the amount thatthey would like to produce. The commission maywish to give special incentives to certain types ofactivity and will establish allowable with morebeing allowed for one type of production thananother. To encourage drilling the commissionmay allow new wells to produce at the reservoir’smaximum efficient rate of recovery, while olderfields must produce at a lower rate, so that totalproduction from the State does not exceed theanticipated reasonable market demand. Withthe exception of Texas in recent months, themarket-demand type States have set allowablefor wells at the maximum efficient rate for every
month since 1973.
Pooling and Unitization
Pooling
State regulation of well spacing and produc-tion can cause significant problems that must beovercome by the producers themselves or by ad-ditional regulations. If there can be only one wellwithin a given area and there are several parcelsof land with different owners, some determina-tion must be made as to who will be able to drilla well and who will be entitled to receive pro-ceeds from the production from the well. The in-tegration of the various interests within the areafor the purpose of creating a drilling unit fordevelopment of a well and sharing of the pro-ceeds is known as pooling.11 It may be voluntaryif the interest owners come together and agreeby contract upon the drilling and sharing of the
production from the unit well. It may be com-pulsory if the State forces interest owners to par-ticipate on a basis established by the Stateregulatory commission when there is an applicantwho wishes to drill and some of the interestowners are unwilling or unable to reach an agree-ment upon sharing of development cost and/orproduction. Pooling then refers to the bringingtogether of the different interests in a given areaso as to integrate the acreage necessary forestablishing a drilling unit, and it may be volun-tary or compulsory. Virtually all States with pro-duction of oil or gas have compulsory poolingstatutes which can apply when the parties areunable to reach an agreement for voluntary pool-ing.
Unitization
Pooling does not result in the reservoir beingtreated as a single entity; it does reduce the num-ber of competitive properties within a reservoir,but there will still be competitive operationsamong the enlarged units to the extent permittedby law.
The mo efficient and productive method ofproducing oil may be achieved only if the entirereservoir can be treated as a single producingmechanism, i.e., when the reservoir may be oper-ated without regard to property l ines. Thisbecomes possible when one owner or lesseeowns or leases the rights to the entire reservoir orwhen all the interest holders in the reservoir unitefor a cooperative plan of development. Whenowners of interest do come together for such apurpose for development of most or all of a reser-voir this is referred to as unitization.12 It is muchthe same in principle as pooling, for it is an in-tegration of interests, and as with pooling it maybe voluntary or compulsory; but it is much morecomplex than pooling in attempting to reachagreement on cost and production sharing, andthe statutory schemes for compulsory unitizationare more difficult to comply with than for com-pulsory pooling. Unitization of most or all of areservoir is usually very desirable or is required inorder for there to be application of enhancedrecovery techniques to a reservoir.
Voluntary
Time of Unitization
Appendix C ● 203
Unitization
Ideally, unitization should take place at thefirst discovery of a reservoir capable of producinghydrocarbons in commercial quantities, or evenduring the exploration phase. However, this isnot feasible for it is only through drilling a num-ber of wells—with production from the first welland subsequent welIs going on—that theparameters of the reservoir can be established.Only when the characteristics and the limits ofthe field are generally known will the parties withan interest in the field be willing to unitize. Priorto that time they would possibly agree to shareproduction of petroleum from under their landswith parties who had no petroleum under theirs.It is only after extensive drilling that it is possibleto make an intelligent assessment of the basisupon which participation in the production fromthe reservoir should be established. Because ofthis, unitization has generally come about afterthe primary drive of the reservoir has begun todecline measurably, and it has appeared to in-terest owners that it may be desirable to unitizein order to undertakerecovery beyond themethods of recovery.
Who May Unitize
operations to enhancefield’s l ife by primary
Once it is clear to some of the parties with in-terest in the reservoir that unitization is desirable,there is the problem of determining who may un-dertake the uni t i zat ion. W i thout exp res sauthorization, either in the lease or by separate
agreement, the lessee is not able to unitize the
interest of the royalty owners to whom it mustpay royalty. The lessee may unitize its own in-terest—that is, agree to share with another theseven-eighths of production that it normallyowns-but without the consent of the royaltyowner(s) it may not agree with others to treat thepotential production attributable to the royaltyinterest from the leased acreage on any basisother 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 field-wide unitization agreements on behalf of thelessor, but the noted authority on unitization,Raymond M. Myers, has stated that “[d]ue to thecomplexity of the modern unitization agreement,a clause authorizing the unitization of the entirefield, or a substantial portion thereof, has notgenerally appeared in oil and gas leases. Lessorshave not generally been willing to grant suchbroad powers to lessees as such authorizationwould entail. ”13 Even with authorization the pru-dent lessee will gain the express consent of thelessor. Whether the executive right owner mayunitize, or authorize the lessee to unitize, the in-terests of the nonexecutive interests are open toquestion in most jurisdictions because there hasbeen little litigation on the point.14 The rule inTexas is that the executive does not have thispower; the rule in Louisiana is that he does. Ingeneral, it may be stated that it is desirable ornecessary to get the express consent of eachroyalty owner in order to effectuate voluntaryunitization.
Reaching agreement on unitization is a com-plex and drawn out undertaking often involvingdozens or hundreds of parties. To understand thisand to place in perspective the State’s role inunitization of property for purposes of enhancedrecovery, it would be useful to examine in somedetail the manner in which unitization is agreedupon.
Negotiation of Unit Agreement
The integrat ion of separate and oftendivergent ownership interests necessarily re-quires careful negotiation which may extend overseveral years. The best way to describe effec-tively the nature of and the problems inherent inthe voluntary unitization process is to relate theactual experiences of companies. The discussionof the process which follows draws in part fromthe case history of the McComb Field Unit in PikeCounty, Miss., 15 and from the Seeligson Field Unitin Jim Wells and Kleberg Counties, Tex.16
In the evolution of a voluntary unit, eachnegotiation has its own unique problems and cir-cumstances which affect the ability of principalsto achieve fieldwide unitization in a reasonableperiod of time. Even though no two unit opera-
tions are alike in every respect, there appear tobe 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 withthe discussion of these four stages and their in-tegration during the formation of a voluntary unitoperation.
Initiation of Joint Organization.—The first stagein the unitization process involves the initiationof a joint organization of operating interests whorecognize the necessity for a fieldwide unit inorder to increase the ultimate recovery of oil andgas. A major operator or Ieaseowner will usuallyinitiate the process by informing other ownershipinterests that a unit operation may be desirablefor undertaking a particular fieldwide project forenhanced recovery.
For example, shortly after primary productionwas undertaken in the McComb Field, thecoowner of the discovery well and majorleaseowner (Sun Oil Co.) began accumulating ad-ditional technical information and data withrespect to the parameters of the reservoir. Thedata revealed an alarming condition in the reser-voir-a rapid decline in reservoir pressure whichcould bring premature abandonment with a tre-mendous loss in recoverable oil reserves. It wasapparent that a fieldwide gas- or water-pressuremaintenance project was needed to arrest thedeterioration of the reservoir and increase ulti-mate recovery. This pressure maintenance proj-ect required fieldwide unitization which, in turn,required full-field participation. A meeting washeld in February 1960, at the urging of the SunOil Co., and the preliminary evidence was pre-sented to 70 operating interests.
The initial stage of the Seeligson Field Unitnegotiation involved a different set of circum-stances. Numerous tracts in the field containedgas, oil, or both. A gas-unit operation had existedsince 1948, and the current problem was to unit-ize both oil and gas under one set of agreements.In particular, the proposed new unit operation
was primarily concerned with the increased oilproduction that would result both from thetransfer of allowable and from a pressure main-tenance program. Thus, operators having hadprevious negotiation experience could facilitatematters with the negotiation of a new unit agree-ment. A meeting was called in February 1952, todiscuss just such a possibility.
In specific terms, the initiation of a jointorganization entails three primary steps. First,after a discussion of the preliminary technical in-formation and data, operators reach a generalagreement on the “problem” giving rise to thenecessity for a unit operation. Once the problemis identified and clearly defined, then possiblesolutions for consideration can be enumerated.
During this initial step and the steps thatfollow, obstacles or delays may be encounteredwhen the joint organization involves a large num-ber of participants. If an inordinate number ofoperators have had little or no first-hand unitiza-tion experience or technical knowledge of theproposed solution projects, or where misunder-standings or suspicions develop, then unneces-sary delays may occur in the formation of a jointorganization.
The next step encompasses the acceptance ofthe articles of organization which establish theorganizational framework and procedural rulesfor the initial operating committee (UnitizationCommittee) and ancillary subcommittees. TheUnitization Committee is a temporary bodycharged with supervising the collection of exten-sive information and data germane to the forma-tion of the unit as well as presiding over thegeneral negotiations prior to the approval of theunitization agreements. The composition of theUnitization Committee and the various subcom-mittees requires an acceptable representation ofmajor and independent leaseowners. This willprovide a major step in spreading the respon-sibilities for unit formation among all parties in-terested in the fieldwide operation and also tominimize the potential misconceptions andmistrust which may develop among operating in-terests.
The final step in the initiation of the jointorganization involves financing of the temporary
organizational structure. Rather than the major
Appendix C ● 205
leaseowner bearing the full costs, financialresponsibility is generally shared according tosome acceptable method of cost allocation. Inthe McComb Field, expenses were shared jointlyon a well basis.
Generally, the initial stage in the negotiationprocess does not require more than a few meet-ings to finalize the temporary procedures for thejoint organization. Given sufficient preliminaryevidence, most operators recognize the necessityfor careful planning and thorough investigation inthe development of a fieldwide unitizationoperation.
Planning Period.—The second stage in thenegotiation process centers around the planningperiod, which culminates in the unitization agree-ments. This stage involves the activities ofvarious subcommittees who are responsible forcollecting extensive data and information and fordeveloping the details for the unit operation. Ingeneral, there are four main areas of concern:technical, legal, land, and accounting.
Technical. The gathering of technical data andinformation is the jo int responsibi l i tyof a Geologic Subcommittee and anEngineering Subcommittee.
The Geologic Subcommittee prepares thevarious geological maps and accumulatesfield data necessary for study by the jointorganization. In particular, their dutiescenter around ascertaining the extent of thereservoir in terms of its size, shape, andgeological limits. Aside from the extent ofthe reservoir, this subcommittee is con-cerned with mapping the thickness, struc-tural position, and extent of the “pro-ductive” pay of the reservoir. informationgathered by the Geologic Subcommittee ismade available to the Engineering Subcom-mittee for the evaluation of the various proj-ects under consideration and to operatorsfor determining oil recovery factors undervarious operating conditions. This is an im-portant phase in the negotiation process,due primarily to the fact that the technicalfeasibility and economic profitability ofvarious projects are evaluated and recomm-endations submitted to the UnitizationCommittee for consideration by the jointorganization.
206 . Appendix C
The task of this subcommittee is bestillustrated by the Engineering Subcommit-tee of the McComb Field Unit. As the reser-voir data were assembled, oil recovery fac-tors were derived under five operating con-ditions:
1.
2.
3.
4.
5.
Primary recovery (18 percent recoveryfactor);
Injection of produced gas (increaseultimate recovery to 23 percent);
Gas pressure maintenance (increaseultimate recovery to 30 percent);
Water pressure maintenance (increaseultimate recovery to 39 percent); and
High-pressure miscible gas injection(increase ultimate recovery to 54 per-cent).
Based on these oil recovery factors thewater pressure maintenance and high--pressure miscible gas injection projectswere selected for further feasibility analysis,where the advantages and disadvantages ofeach project were then evaluated.
While the miscible gas injection projectoffered the highest oil recovery factor, itsdisadvantages were extremely critical: thesupply of extraneous gas was available butat prohibit ive costs ; the process wasrelatively unproven in terms of general in-dustry-wide use; there existed possible cor-rosion problems as well as contamination ofreservoir gas; the project would require along period of time to implement andwould require expensive plant expansion;and, finally, there was a greater risk offailure. Furthermore, the rate of return forthe capital investment was calculated to be31 percent per year.
The advantages of the waterflood projectwere numerous: ample supply of salt waterin the reservoir; relatively lower initial in-vestment expenditure; proven method ofrecovery with a low risk of failure; minimumtime required to implement the project; andundertaking the waterflood project did notpreclude the adoption of miscible injection
at a later date. In addition, the capital in-vestment was calculated to earn a 72-per-cent annual rate of return. Finally, the pri-mary disadvantage of waterflooding was therelatively lower oil recovery factor.
After careful cons iderat ion of theeconomic feasibility and advantages anddisadvantages of each project, the technicalsubcommittees recommended the selectionof the water pressure maintenance projectfor the McComb Field Unit Operation.Aside from the higher rate of return oncapital investment, the major factors whichled to the waterflood selection involved theminimum risk of failure and the short imple-mentation time associated with the project.These factors were extremely crucial, giventhe rapidly declining pressure in the reser-voir.
Once the extensive geologic data andengineering information are accumulatedand project recommendations set forth, thefinal task of the technical subcommittees in-volves a preliminary determination of theparticipation formula whereby lessors andlessees share in unit production. The rele-vant aspects of the participation formulawill be considered later in this appendix,but it should be noted that the time framefor the work of the technical subcommitteescan vary considerably. For the SeeligsonField Unit, the Unitization Committee ap-pointed working interest representatives tothe technical subcommittees in February1952, and the Engineering Subcommitteeoffered recommendations (with respect tothe most feasible project and the tentativeparticipation formula) to a meeting ofoperators in January 1955. Hence, nearly 3years had elapsed during which time themajor technical groundwork for the unitoperation was completed. For the McCombField Unit, the work of the technical sub-committees was initiated in February 1960and recommendations and findings werepresented approximately 9 months later,
Therefore, the time required for collectingand evaluating detailed technical informa-tion and the subsequent recommendations
Appendix C . 207
which follow can consume from severalmonths to a few years during the unitizationprocess, In general, a number of factors suchas the geological complexity of the reser-voir, the number of development wellsnecessary for assessing the characteristics ofthe reservoir, the nature of the unitizationprojects under consideration, and whetherthe field is in the development phase or pro-duction phase may all contribute to thelength of time required for the planningperiod.
Legal. During the planning of a fieldwide unit,
the Legal Subcommittee handles the legalaspects assoc iated wi th the un i t i zat ion
process and the subsequent negotiation and
d r a f t i n g o f a g r e e m e n t s . T h i s c h a r g enecessarily requires an understanding of thedesired goal of the unit operation and themanner in which this goal impacts on landtitles, overriding royalties, operating leases,and other factors. In particular, the Legal
Subcommit tee determines whether thereare 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 Subcommit tee to adv i se
lessees that they continue their lease obliga-
tions to lessors. The Legal Subcommitteemust ensure that the implied as well as ex-pressed obligations of lessees are satisfiedduring the negotiation and execution of aunitization agreement.
The Legai Subcommittee is also responsi-ble for submitting to the appropriate Stateregulatory agency all requisite documentsand instruments which pertain to the unitoperation. Such procedures will be dis-cussed in a subsequent section.
Land. The Land Subcommittee is generallycomprised of land agents whose function iti s t o i d e n t i f y r o y a l t y o w n e r s a n dleaseholders for the purpose of com-municating information to the various in-terest owners and facilitating the accept-ance of the unitization agreements. Whileoperating interests may be readily identifia-ble, a widespread distribution of royalty in-terests can make the task of the Land Sub-committee difficult and time consuming.
Frequently, overriding royalties, varioustypes of working-interest arrangements, androyalty interests involving estates or trustsmay add both time and expense to the com-plexity of forming a unit.
Once the majority, if not all, of the in-terested parties are identified, the landagents are responsible for conveying to theownership interests, information withregard to the nature of the unit operation(in terms of the project to be instituted aswell as each owner’s share in unit produc-tion). The work of the Land Subcommitteebegins in the planning stage of the unitiza-tion process and ends with the obtainingof signatures for the unit agreements.
Accounting. The initial concern of the Ac-counting Subcommittee involves the ac-counting for expenses incurred prior to theunit agreement. The work performed by thetechnical subcommittees and, to a lesser ex-tent, the other subcommittees operatingduring the planning period generatesexpenditures which must be underwrittenby the operating interests. Accounts aremaintained by the Accounting Subcommit-tee and subsequent billings to operators ona predetermined share basis are made forpurchases of supplies and field equipmentas well as the overhead costs of the tempo-rary joint organization.
The primary charge of the AccountingSubcommittee, however, is to prepare thejoint operation accounting procedureswhich establish the method of accountingand the allocational rules to be used in theunit operation. The accounting proceduresappear as an exhibit to the proposed unitagreement and specify the items to becharged to the joint account, the dispositionof lease equipment and material, the treat-ment of inventories, and the method ofallocating joint costs and revenues amongunit participants.
An important role of the Accounting Sub-committee entails the explanation and, insome cases, the determination of specifictax considerations which impact on owner-ship interests as well as the general field-wide operation. For example, tax legislation
. . .
208 . Appendix C
and tax court interpretations with respect toEOR projects are ever-changing, and the ap-plication of future tax law to EOR projectsis in a state of uncertainty. Therefore, thetax treatment applied to EOR projects mightaffect the incentive among participants of aproposed unit operation to engage in a par-ticular EOR project or it could affect the in-centive of an individual ownership interestto commit its property rights to the unitoperation.
An example where a possible disincentiveexists for joining a unit operation can beseen in the Income Tax Reduction Act of1975, which eliminated the percentage oil-depletion allowance for major companies.However, an exemption to this is providedfor independent producers and royaltyowners where an independent producer isdefined as one whose total retail sales is lessthan 5 percent of its total sales. When thisexemption is applied, the independent pro-ducer can apply the. 22-percent oil-deple-tion allowance to the market value of amaximum 1,800 barrels per day (for 1976,and declines to 1,000 barrels per day by1980). 17 When confronted with a choice ofjoining a unit operation which wouldenhance the producer’s recovery of oilabove the limit of 1,800 barrels per day andthus lose the exemption, the independentproducer would necessarily be concernedwith its participation factor in the unitiza-tion agreement. If the independent’s shareof unit production did not compensate forthe exemption loss or ensure at least a com-parable return for joining the unit, then thenegotiations of the unit operation couldface an obstacle to the attainment of fullfield participation. This situation mightcreate costly delays in the unitization proc-ess.
Another example can be seen in the ques-tions arising with respect to the tax treat-ment of costs associated with EOR projects,where costs relevant to the discussion in-clude intangible drilling and developmentcosts (lDC), cost of physical facilities re-quired in the EOR project, and the cost ofinjected material .18 According to the inter-
nal Revenue Code enacted in 1954, an IDCrefers to costs (i.e., labor, fuel, transporta-tion, supplies, and other items having nosalvage value) associated with installingequipment “incident to and necessary forthe drilling of wells and the preparation ofwells for production of oil and gas.” 1 9
Hence, the cost of installing injection wells,production wells, water source wells (in thecase of waterflooding), and converting pro-duction wells to input wells are treated asIDC and subject to the tax option of eitherexpensing these cost items or capitalizingthem. The generally accepted accountingpractice is to expense IDC, which allowsthem to be written off in the year that theyoccur.
The cost of physical facilities (i.e., storagetanks, pipelines and valves, waste-watertreatment equipment, etc.) must, by law, becapitalized and depreciated over the ex-pected useful l i fe of the equipment.However, the method of depreciation mayimpact on the incentive to undertake a par-ticular EOR project. A straight-line methodof depreciation (20 percent per year for 5years) would provide a “quick” writeoff andenable the full cost of the investment ex-penditure to be recovered in the first 5 yearsof the equipment’s useful life. With thesum-of-year’s digits method (over an 11-year period), only 68 percent of the full costof the equipment would be recovered dur-ing the first 5 years. The allowable deprecia-tion is greater for the straight-line method,and use of this method could improve theeconomic incentive of the EOR program. 20Furthermore, the tax treatment advice of theAccounting Subcommittee would be ex-tremely valuable at this point in evaluatingthe feasibility of projects under considera-tion by the joint organization.
The cost of the injected material may alsobe a relevant tax consideration. When high-cost materials are injected into a reservoirand a portion of the injected material can-not be recovered from the reservoir, thenthe total cost of the unrecoverable materialcan be expensed during the year in which itwas injected, or it can be capitalized and
depreciated (using the straight-line method)over the life of the reservoir. In addition, “ifit can be demonstrated, in any year, that aparticular injection project is a failure (i.e.,the injection of this material did not benefitproduction), a loss may be claimed for theundepreciated cos t o f the i n jec tedmaterial. ”21 At the margin, these tax optionsmay be an important consideration whenchoosing among EOR projects which requirethe 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, itrepresents the principal point of contentionamong the parties negotiating the voluntary for-mation of a unit operation. According to thenoted authority Raymond Myers, “The ideal isthat each operator’s share of production from theunit shall be in exact proportion to the contribu-tion which he makes to the unit. ”22 However, thedetermination of the “exact proportion” con-tributed by each operator to unit production isdifficult to determine and has led to long andlabored negotiations.
In the early days of unitization, participationwas based solely on surface area. The criteria wasfound to be wanting since, as Myers observes, itassumed “un i fo rm qua! i t y and th icknes sthroughout the [reservoir] with each tract havingbeneath it the same amount of reserves per acre.This rarely, if ever, happened.”23 More recently,shares are often determined in direct proportionto the amount of productive acre-feet of payzone which lies beneath the surface of each tract.However, this determination may be derivedonly after a series of development wells haveascertained the parameters of the reservoir. Theeffective procedure which is frequently utilized isto initially establish participation factors on thebasis of surface area and preliminary acre-feet ofpay zone criteria, then after the commencementof unit production (usually 6 months), the par-ticipation factors are adjusted in accordance withmore reliable or updated pay zone values.
Based on geologic studies of the McCombField, it was determined that the average payzone thickness was approximately 15 feet per
Appendix C . 209
acre for each 40-acre tract. This value providedthe basis for allocating unit production amongthe various ownership interests during the initialproduction phase in which approximately 18 per-cent oil recovery would occur. In the secondphase of the formula, secondary oil reserves wereallocated among the unitized interests on thebasis of 75-percent credit for net acre-feet of oilzone plus 25-percent credit for the participationfactor used in the first phase. This second phaseadjustment of participation factors was designedto take into consideration more technical aspects(actual pay zone) and thereby give some tractsadditional credit for their relatively larger con-tribution to unit production.
There are a number of obstacles, delays, or dis-incentives which tend to affect the acceptance ofthe participation formula as well as the subse-quent negotiations in drafting and approving theunitization agreements. A few of these have beenpreviously discussed and others are worth a briefmention.
Some of the ownership interests may be of theopinion that they should have a “fair advantage”with respect to their participation factor. In par-ticular, some parties may contribute more surfaceacreage to the fieldwide operation or a portion ofthe unit’s plant and equipment (such as injectionwells, storage facilities, and the like) may be lo-cated on their property. Hence, by virtue of thelarge surface acreage contribution or operationstaking place on their property, these ownershipinterests may argue for preferential treatment andthe adjustment of their proposed participationfactor to reflect this “fair advantage. ” The debateover this issue may create delays in the deter-mination of an acceptable participation formulaand, if left unresolved, could have a detrimentaleffect on the ability of all parties to form a volun-tary unit operation.
Pride of property ownership and/or controlover individual operations may affect the willing-ness of an individual ownership interest (royaltyas well as operating) to join a unit and committheir property and operational control to jointdecisions. When such strong feelings are held(and they may surface with participation factordissatisfaction), acceptance of the participationformula or general approval of the unitizationagreements may be difficult to achieve.
210 . Appendix C
A final consideration, which might well impacton the incentive for accepting the participationformula and entering a unit operation, involvesthe effect of FEA regulations. The domestic priceof crude oil is controlled at specific levels by FEA.However, the anticipation of future pricederegulation might prompt some producers toleave oil in place until the price of oil increases.This could be particularly critical when the pro-ducer feels that its return (based on the participa-tion factor) from the joint operation is marginal,at best.
In general, the acceptance of the participationformula by operators and royalty owners reflectstheir satisfaction with the unit operation and itsabil ity to ultimately increase profits whilesafeguarding property rights. Fieldwide unitiza-tion is initiated in order to increase the ultimaterecovery of oil and gas while reducing the riski-ness and costs associated with individual opera-tions. Through a joint effort, higher rates of returncan thus be realized with the retention of owner-ship interests in the recovery of oil and gas.
Drafting and Approval of Agreements.—Thefourth stage in the voluntary unitization processinvolves the drafting and approval of agreementsby participants engaged in a fieldwide operation.This stage represents the culmination of theefforts and responsibilities undertaken by thevarious subcommittees with the supervision ofthe Unitization Committee.
The Legal Subcommittee assumes the task ofdrafting the unitization agreements for the ap-proval of the ownership interests. The unitizationagreements are the legal instruments for the unitoperation, and there are generally two types ofdocuments: the Operating Agreement for theoperators or working-interest owners, and theRoyalty Owners Agreement for the royalty in-terests. It is customary to distinguish between thetwo ownership interests in order to facilitate theapproval of the unit operation. While operatinginterests share in the proceeds and costs of theunit operation, royalty owners share only in theproceeds from unit production and do not sharein the obligations incurred by the operators.Therefore, separate documents are desirablesince the Royalty Owners Agreement containsmaterial only of interest to the royalty owner.
The Operating Agreement contains a legalstatement of matters containing the participationformula and adjustments thereof, provisions forenlarging the unit operation, cost allocation,operational procedures, and matters pertaining totitles, easements, and term. Furthermore, theselection of the Unit Operation is specified inthis document where the Unit Operator is usuallythe largest leaseholder in the unit and is responsi-ble for the general supervision of the unit opera-tion. The execution of the Operating Agreementoccurs when the signature of the operators havebeen obtained. This generally requires approx-imately 6 to 8 months, as in the cases of both theMcComb and Seeligson Field Units.
As previously stated, the Royalty OwnersAgreement consists of material germane only toroyalty interests; as such, this instrument is con-siderably shorter and less difficult than theOperating Agreement. The Royalty OwnersAgreement must be presented to all the ownersof mineral interests in the unit area includingunleased lands, royalties, overriding royalties, gaspayments, and oil payments. The agreementmust be acceptable to the various royalty ownersbefore the unit operation becomes effective.Naturally, the primary concern among royaltyowners involves their share of the proceeds fromunit production and, to a lesser extent, their par-ticipation in plant products (gas, condensates,and others) and questions dealing with ease-ments. Therefore, in order to allay any apprehen-sions or misconceptions, great care has to be ex-ercised by operators in drafting the RoyaltyOwners Agreement and conveying to royalty in-terests the nature of the unit operation and howroyalty owners would benefit from unitizationwhile retaining their ownership rights. Myers ob-serves that “the interests of the lessee and lessorare for the most part identical, and this fact is ofcourse considered by the royalty owner in ac-cepting the decisions of his lessee. ”24
In order to achieve the maximum objectives ofvoluntary unitization, it is necessary that all par-ties having an interest in the unit area becomesubject to the unit agreements. However, in theabsence of compulsory unitization, this may beimpossible to obtain when some lessors orlessees refuse to participate in the unit. Evenwhen non joining parties cannot complain about
financial losses incident to the unit operation, theland of a non joining lessor or lessee may not beused to achieve the maximum effectiveness ofthe unitization program.
As a final note, the first four stages in thenegotiation and execution of a voluntary unitoperation demand much effort and planning onthe part of interested parties. The time that isnecessary to effect the fieldwide operation variesin accordance with the complexity and frequencyof the problems involved. Smaller units which in-volve fewer ownership interests will generallyestablish unitization in a relatively shorter timethan larger units with numerous and diverseownership interests. The larger the number of in-terested parties, the more difficult it is to coordi-nate and reconcile individual interests with theobjectives of the joint organization.
Based on the case histories of the McComband Seeligson Field Units, the time necessary forvoluntary unitization can be quite variable. Whenthe McComb Field agreement was submitted forregulatory approval, signatures of ownership in-terests had been secured for approximately 68percent of the royalty owners and nearly 84 per-cent of the operators. The time required for thecompletion of the first four stages involved lessthan 1 l/z years-a relatively short period for aunit operation encompassing over 300 tracts andthousands of ownership interests. On the otherhand, the Seeligson Field Unit initiated negotia-tions in February 1952; by November 1955, sig-natures of working-interest owners were ob-tained for the Operating Agreement. In the springof 1956, the Royalty Owners Agreement becameeffective and, after nearly 4 years of negotiation,the unit operation for the Seeligson Field becamea reality.
Compulsory Unitization
Compulsory unitization begins with voluntaryunitization of a majority of the interests withinthe field. It differs from voluntary unitization inthat all States with petroleum allow unitizationwhen most or all of the interested parties agreeto it, but not all States will force unwilling partiesto have their interests included in the unit opera-tions. Most States, however, do authorize the
Appendix C . 211
State commission to enter an order compelling allinterests in a field to participate in the unit oncethere has been voluntary agreement among aspecified percentage of interests in the field.25
This required percentage varies from 60 percentin New York and 63 percent in Oklahoma to ahigh of 85 percent in Mississippi. Texas is themost significant State without a compulsoryunitization statute, but it should also be pointedout that the effect of the statutes in California isso limited in application that they are rather in-effective: the California Subsidence statute pro-vides for compulsory unitization only in areas inwhich subsidence is injuring or imperiling com-merce or safety, while the California Townsitestatute applies only to fields over 75 percent ofwhich lie within incorporated areas and whichhave been producing for more than 20 years.
Without unitization of all interests, unit opera-tors may be liable to nonunitized interests fornon-negligent operations, and will have to ac-count to nonunitized interests as though therewere no unit. If a lessee in a unit has a royalty in-terest 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 royaltyowner on the basis of the production from theleased land, not on the basis of the productionattributable to the leased land under the unitoperations plan. The lessee may have to engagein additional drilling in order to maintain thevalidity of the lease against non joining reversion-ary interest owners; such drilling may be com-pletely unnecessary for maximum recovery fromthe reservoir and, indeed, may be harmful to thatmaximum recovery. Lack of compulsory unitiza-tion or the requirement of a high percentage ofvoluntary participation could be a significantrestraint on unit operations, which in turn couldhave a significant impact on enhanced recovery.
In response to questionnaires sent to regula-tors and producers, several State commissionsand a significant number of producers identifiedthe inability of getting joinder of the necessaryparties in a field for unitization as inhibiting orpreventing the initiation of enhanced recoveryprojects. It was indicated that there probably areseveral hundred projects in the State of Texasthat cannot be undertaken because of the in-ability 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 proj-
ects in Texas. Producers in 10 States indicated
that enhanced recovery projects would be en-couraged by compulsory unitization or a loweredvoluntary percentage required to invoke com-pulsory unitization. For example, a Louisiana in-dependent declared “1 think 75-percent royaltyowner approval in Louisiana too high. A goodproject that benefits operator must necessari ly
benefit royalty owner.”
There appears to be little or no difficulty in re-quiring unitization and enhanced recovery ac-tivities on Federal lands. The major pieces ofFederal legislation for mineral development onFederal land provide ample authority to theSecretary of the Interior to make such require-ments. The Outer Continental Shelf Lands Act,for example, provides that for Federal leases the“Secretary may at any time prescribe and amendsuch rules and regulations as he determines to benecessary and proper in order to provide for theprevention of waste and conservation of thenatural resources of the Outer Continental Shelf(OCS). . . .Without limiting the generality of theforegoing provisions of this section, the rules andregulat ions prescr ibed by the S e c r e t a r ythereunder may provide for. . .unitization. . . .“26
Pursuant to this authority, the U.S. GeologicalSurvey in establishing operating orders for theOCS, Gulf of Mexico area, has provided that“Development and production operations in acompetitive reservoir [having more than onelessee] may be required to be conducted undereither pooling and drilling agreements or unitiza-tion agreements when the Conservation Managerdetermines. . that such agreements are practica-ble and necessary or advisable and in the interestof conservation. ”27 The same OCS order requiresthat operators “timely initiate enhanced oil andgas recovery operations for all competitive andnoncompetitive reservoirs where such operationswould result in an increased ultimate recovery ofoil or gas under sound engineering and economicprinciples.” 28 While Interior’s authority does notappear to be quite so ‘extensive under the MineralLeasing Act of 1920, the difficulties for unitiza-tion and enhanced recovery on Federal landonshore nevertheless appear minimal when com-pared with development on private lands.
Procedure for Fieldwide Unitization
The procedure for obtaining commission ap-proval for unitization or for compelling joinder ofparties in the unit is similar in most States,although by no means identical. Common ele-ments found in almost all States include the needfor application or petition by an interested party(normally the prospective operator), notice toother parties, a hearing, proof of matters requiredby the pertinent State statute, and entry of anorder by the commission defining the unit, andthe terms of the unitization. The entire procedureusually takes only a matter of weeks, althoughthere may be a delay or denial of the permitbecause of inequities in the participation for-mula. The description of the general procedureinvolved is intended to be suggestive only, withdetailed explanation of the procedure in severalof the more important States with enhancedrecovery activities. For other treatments, andspecific requirements for each State, referenceshould be made to the work cited29 and to tablec-1 .
Application
The application form and the information re-quired to be contained in it vary from State toState, but five common requirements are presentin whole or in part in most statutes. These arethat 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 com-position,
the expense and production allocation for-mula, and
the duration of the unit.
Some States require prior notice to be given tothe affected parties and several require that theapplicant furnish the regulatory commission witha list of the names and addresses of affected par-ties.
Who may initiate the regulatory process alsovaries from State to State. In many States any in-terested party may submit a petition for unitiza-tion, while in others only a working interest
owner may start the process. In a number ofStates the commission may initiate the procedureon its own motion, but this generally is not usedexcept with application by a party. Usually, it isthe unit operator who has been selected by theparticipants in the unit who initiates the process.
As described earlier, the expense and produc-tion allocation formula is tediously and carefullynegotiated by the parties to the unitizationagreement. Agreement with this information willnormally be submitted to the commission withthe petition or application. When compulsoryjoinder of other parties is sought, there will be astatement that such parties have been offered theopportunity to join the unit on the same basis asall others. The application will generally alsocover the matters which are required by thestatute to be found before the commission mayenter an order, as discussed under “Proof of Find-ings Required. ”
Notice
Both voluntary and compulsory unitizationstatutes generally require that notice and an op-portunity for a hearing be given prior to the entryof an order establishing or approving the unit.Louisiana, for example, provides that wheneverany application shall be made to the commis-sioner of conservation for the creation, revision,or modification of any unit: the applicant shall berequired to file two copies of a map of the unitwith the application; the applicant shall be re-quired to give at least 30 days notice of the hear-ing to be held on the unit in the mannerprescribed by the commissioner; and a copy ofthe plat shall remain on file in the office of thecommissioner in Baton Rouge and in the office ofthe district manager of the conservation districtin which the property is located, and be open forpublic inspection at least 30 days prior to suchhearing. JO Other States typically require a shortertime period for notice, but also require that it begiven by personal notice and/or by publication inthe State register or in a newspaper. Failure tocomply with a statutory notice provision mayresult in the order being declared invalid as toparties who were not given notice.31
Appendix C . 213
Hearing
Opportunity for hearing is required in all Statesprior to the entry of an order for unitization, butin some States, such as Alaska, no formal hearingneed be held if no party objects to the unitizationproposal after the notice is given.32 Hearings aregenerally conducted without rigid formality andare usually governed by the rules of civil pro-cedure of the State and/or such rules as may bepromulgated by the State commission pursuantto its delegated authority. Decisions are based onthe record evidence and a general right to rehear-ing and/or appeal is accorded.33
Proof of Findings Required
Prior to approval of any unit plan or entry of anorder requiring unitization in most States, theState commission must make certain findings.These generally are that unit operations arenecessary to increase ultimate recovery from thereservoir or prevent waste, that correlative rightsof interest owners are protected, and that the ad-ditional cost involved does not exceed the addi-tional recovery anticipated. The Texas statute, forexample, provides that unit agreements shall notbecome lawful or effective until the TexasRailroad Commission finds that:34
1)
2)
such agreement is necessary to accomplish[secondary recovery operations] or [con-servation and utilization of gas] or both;that it is in the interest of the public welfareas being reasonably necessary to preventwaste, and to promote the conservation ofoil or gas or both; and that the rights of theowners of all the interests in the field,whether signers of the unit agreement ornot, would be protected under its opera-tion;
the estimated additional cost, if any, of con-ducting such operations will not exceed thevalue of additional oil and gas so recoveredby or on behalf of the several personsaffected, including royalty owners, ownersof overriding royalties, oil and gas pay-ments, carried interests, lien claimants, and
others as well as lessees;
214 . Appendix C
3)
4)
other available or existing methods orfacilities for secondary recovery operationsand/or for the conservation and utilizationof gas in the particular area or field con-cerned are inadequate for such purposes;and
the area covered by the unit agreement con-tains only such part of the - field as hasreasonably been defined by development,and that the owners of interests in the oiland gas under each tract of land within thearea reasonably defined by developmentare given an opportunity to enter into suchunit upon the same yardstick basis as theowner of interests in the oil and gas underthe other tracts in the unit.
The Louisiana statute, to cite a compulsoryunitization statute, provides that an order for unitoperation shall be issued only after notice andhearing and shall be based on findings that:35
1)
2)
3)
4)
the order is reasonably necessary for theprevention of waste and the drilling of un-necessary wells, and will appreciably in-crease the ultimate recovery of oil or gasfrom the affected pool or combination oftwo pools;
the proposed unit operation is economicallyfeasible;
the order will provide for the allocation toeach separate tract within the unit of a pro-portionate share of the unit productionwhich shall insure the recovery by theowners of that tract of their just and equita-ble share of the recoverable oil or gas in theunitized pool or combination of two pools;and
at least three-fourths of the owners andthree-fourths of the royalty owners,. . shallhave approved the plan and terms of unitoperation, such approval to be evidencedby a written contract or contracts coveringthe terms and operation of said unitization
signed and executed by said three-fourths ininterest of said owners and three-fourths ininterest of the said royalty owners and filedwith the commissioner on or before the dayset for said hearing.
As indicated previously, different States withcompulsory unitization provisions have varyingrequirements as to the percentage of partiesvoluntarily entering into the unitization prior toinvoking the compulsory features.
Entry of the Order for Unitization
After application, notice, hearing, and pres-entation of evidence and findings by the commis-sion, the commission, if approving the unitiza-tion, will enter a formal order for the unitizationwhich will become a matter of public record. InOklahoma, for instance, the order of unitizationissued by the Oklahoma Corporation Commis-sion will provide for:36 1 ) the management orcontrol of the unit area by an operator who isdesignated by vote of the lessees; 2) the alloca-tion of production; 3) the apportionment ofoperational costs; 4) the manner of taking overthe wells and equipment of the several lesseeswithin the unit area and the method of compen-sation therefore; 5) creation of an operating com-mittee; 6) time of the plan’s effectiveness; and 7)time and conditions of unit dissolution. OtherStates are similar. Unit members dissatisfied bythe unitization order may appeal directly to theOklahoma Supreme Court.37
Interests joined in the unit through compulsionmay be allowed to choose prior to commence-ment of unit operations whether to participate ascotenants sharing in expenses and profits or totake a fair and reasonable bonus and royaltywhich is expense free. Several States including,among others, Alaska, Colorado, New Mexico,Utah, and Wyoming provide for or require financ-ing programs for nonconsenting parties withlimited cash outlay capabilities to defer unit ex-penses until production is obtained with reasona-ble risk assessments added.
The problem of determining a fair and equita-ble basis for allocation of production among theunit members can be an extremely difficult one,as was brought out in the discussion of theproblems of negotiating voluntary agreements forunitization. Claims may be made that productionshould be allocated on the basis of surfaceacreage, productive acre feet, productive porespace, prior production history, and other
grounds. The State commission may use a com-bination of these. For example, the OklahomaCorporation Commission for the West CacheCreek Unit in Cotton County, Okla., used a splitformula based first upon the estimated remainingnet economically recoverable primary productionof the unit, and secondly on the floodable acrefeet of the unit. The Oklahoma Supreme Courtupheld this approach against a chalIenge by a dis-satisfied party who claimed that the formulashould, in its second phase, take into account thecurrent production from the claimant’s well; thecommission’s order was, the court ruled, sup-ported by substantial evidence and so the courtwould not overrule the commission.38
State commissions have set formulae on avariety of base: and have generally been upheldby the courts regardless of the formula used.39
Statues do occasionally provide some stand-ards, but as one authority has stated, “Viewingpresent statutory standards, shed of all frills, theparties must look for real protection to the in-tegrity of the regulatory agency and of the partiespresenting evidence, as well as to careful scrutinyof the information by those who expressly con-sent to the allocation.”4° Both the sparsity oflitigation on the subject and statements concern-ing the regulatory commissions in response toOTA’s questionnaires indicate that the Statecommissions are effectively protecting the in-terests of the parties to unitization proceedings.
Amendment and Enlargement
Under most statutes for unitization, it is possi-ble to enlarge the unit and/or amend the unitagreement(s) following the same procedures thatwere used in creating the unit in the first in-stance. This may occur if additional parties wishto participate in the agreement or if it is learnedthat the reservoir has different parameters thanoriginally believed.
Effect of Unitization
Each State authorizes the establishment ofvoluntary fieldwide units, although formal Stateapproval may not be required for the creation ofsuch a unit. There are distinct advantages to get-ting such approval even when it is not a require-ment. 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 Sec-ond, it may serve to protect the participants fromapplication of the Federal antitrust laws to theunit operations. The argument can be made thatunitization reduces competition and can serve asa means of limiting production and controllingprice. However, the general weight of authority isthat, so long as there is no collusion in refiningand marketing, the mere joint production of oildoes not create antitrust problems.42 W h e r eunitization is necessary to increase total produc-tion it would appear that unitization would ac-tually promote competition by increasing theamount of oil available to all the parties. The roleof State approval in Federal antitrust considera-tions (if they should be raised) is that it can beargued that the approval and order of the Statecommission gives rise to the well-recognizedParker v. Brown43 exemption from the operationof the Federal antitrust laws. That is, in the caseof Parker v. Brown, the U.S. Supreme Court heldthat State approval of a raisin marketing programprovided the cooperative activities of the raisingrowers with immunity from the Federal antitrustlaws. The same rationale would apply to unitoperations approved by a State commission. 44
Only one Federal case45 has attempted to applythe Federal antitrust statutes to unit operations,and was terminated through a carefully negoti-ated consent degree.
Another reason for getting State approval for avoluntary unit even if not required is that it mayprovide protection from l iabi l i ty for non-negligent operations to other parties in the reser-voir who have not joined in the unit. This is animportant subject in itself, and is taken up in alater section. Suffice it to say at this point the ele-ment of State approval of the enhanced recoveryprogram has been enough for some courts toestablish immunity from such Iiability for opera-tors. And, of course, where the requisite percent-age approval is achieved in a State with a com-pulsory unitization statute, the entry of acommission order for a unit will result in unitizingthe field and all interests in the field may betreated as members of the unit; no separate ac-counting or operations on a nonunit basis will benecessary.
One more point should be brought out, andthat is that under the terms of an oil and gas lease
216 . Appendix C
in some instances and by statute in others theestablishment of the unit will sever the unitizedportion of the leasehold from the rest of theIease. 46 Depending on the wording of the leaseclause (known generally as a “Pugh clause”because of the person purportedly creating itoriginally) or of the applicable statute, such as inMississippi, Louisiana, and Wyoming, additionalactivity on the severed part of the leasehold maybe necessary to keep the lease in force as to theportion of the lease not included in the unit. Suchlease and statutory provisions can serve as a dis-incentive to lessees to participation in unit opera-tions.
Allowable and Well Spacing
In order for an enhanced recovery project tobe successful, it is necessary to be able to pro-duce the oil. The fixing of allowable in market-demand type States could discourage enhancedrecovery if the production rates were set at alevel below the optimum rate for the reservoir.The regulat ions of the State commiss ionsgenerally do make provision for the setting ofallowable for enhanced recovery operations. Forexample, Oklahoma provides that “An” approvedand qualified waterflood project shall be entitledto produce an allowable of forty-five (45) barrelsof oil per well per day including producing andinjection wells on a project basis upon theacreage developed for waterflooding. The com-mission may increase the allowable for awaterflood project for good cause shown afternotice and hearing. ”47 In other States, similar pro-vision is made and/or allowable may be trans-ferred among interest owners for the encourage-ment of enhanced recovery.48 Because of special
t reatment and encouragement of enhancedrecovery projects, it does not appear that the set-
ting of allowable wou ld impede enhancedrecovery operations. No producer responding toOTA’s questionnaires indicated that there was aproblem of establishing adequate allowable forenhanced recovery. The same is true of wellspacing.
Administrative and Judicial Encouragementto Unitization
A number of State commissions and courtshave recognized the benefits that result from un-
dertaking unit operations to enhance recoveryand accordingly have attempted to encourageunitization. They have done this in several ways.
One has been to deny to non joining partiesthe benefits they might have expected to obtainby their refusal to join. Production allowablehave been set at a higher rate on occasion for unitmembers than for those who decline to enter theunit.49 To cite another example, an agency haslimited the royalty payable to a non joiningroyalty owner to the royalty that would havebeen paid had the allowable not been increasedfor the enhanced recovery operations.50 Such ac-tions have been upheld by the courts. 51
Another method of encouraging unitizationhas been for agencies to use their authority overwell spacing or the prevention of waste to makeunitization more attractive to interest owners.Thus in one well known case,52 the Colorado Oiland Gas Conservation Commission prohibitedthe production of gas from a large reservoirunless the gas was returned to the reservoir, usedin lease or plant operations, or used for domesticor municipal needs in or near the field. The oilcould not be produced without production of thegas, and the gas could not be reinfected withoutunitization of the field. Although sympathizingwith the commission’s goal, the ColoradoSupreme Court struck down the order on theground that it was beyond the authority of thecommission. Subsequently, Colorado enacted acompulsory unitization statute. A recent effort bythe Oklahoma Corporation Commission to re-quire separate owners of interests to developtheir land as a unit was struck down as beingbeyond the statutory authority of the commis-s ion.53
Finally, the courts have encouraged unitizationby denying damages to a non joining interestowner who has asserted that his production hassuffered by virtue of the unit operation of theparty against whom the claim is brought. Suchcases are taken up in a later section.
It should be observed that while agencies andcourts have expressed support for enhancedrecovery, they are l imited to the statutoryauthority they possess. There is only limited op-portunity for them to use their discretion for en-couragement 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 recov-ery projects require underground injections), theparty responsible must obtain approval from theproper State commission. Often this may be doneat the same time that approval of unitization issought; much the same information is requiredand a similar procedure is employed. The twoshould be treated separately, however, becausethey are separate legal requirements involvingdifferent considerations and because an operatormust get a permit for enhanced recovery opera-t ions even when a unit ization procedure is notnecessary, as when the operator owns the entire
area covered by the reservoir.
As with the unit ization statutes, the require-
ments for enhanced recovery operations permitsvary from State to State.54 What is attempted hereis to highlight the general features of the regula-tory procedures that are similar in most Stateswith detailed references to the regulations of thelarger producing States. The procedure typicallyrequires the filing of an application or petition bythe party responsible for the project whichdescribes the activity proposed. Depending onthe jurisdiction, notice of the proposed actionmay have to be given to interested parties beforeapplication or it may be given subsequent to theapplication, either by the regulatory commissionor by the operator. A hearing upon the applicationwill be held if timely objection is made by an in-terested party or on the commission’s own initia-tive.
Application
Applications for enhanced recovery permitstypically require four elements of information tobe included, and these may be specified either bystatute or by rule of the regulatory agency: 1 )geographic description of the area covered by theoperation; 2) identification of parties affected orwho may be affected by implementation of theproposed project; 3) data concerning the forma-
tions underlying the area of operation; and 4) ex-planation of the recovery program.
Geographic descriptions required generally in-clude a plat of all leases in the affected area withlocations given for all present, abandoned, andproposed wells. New Mexico, for example, re-quires a plat showing the locations of all wellswithin a 2-mile radius of existing and proposedinjection wells and the formation from which thewells are producing or have produced. 55
To facilitate the giving of notice to affected par-ties, and to enable the States to prepare conserva-tion plans, the States generally require the ap-plication to include one or more of the following:the names and addresses of operators within thearea, the names of all operators within the unit,
the names of al l owners of property interests
within one-half mile of injection wells, and the
names of all lessees within 2 miles of injectionwells.
Data concerning subsurface formations that aregenerally required under the statutes or regula-tions include full descriptions of the formations inthe area and specific delineation of the reservoirto be flooded. Other such information may be re-quired. Kansas, for example, requires not only thename, description, and depth of the formations tobe flooded, but also the open-hole depths ofeach such formation, the elevations of the top ofthe oil- or gas-bearing formation in the injectionwell, the wells producing from the same forma-tion within one-half mile radius of the injectionwell, and the log of the injection well (if a com-plete log does not exist, such information regard-ing the well as is available). 56
The data concerning development plans thatare generally required include specific descriptionof injection methods, identification of the sub-stance(s) to be injected, the source of the sub-stance, and the daily amounts of the injection. in-formation pertaining to casing and casing testsmust similarly be submitted along with such loginformation as is available to the operator. SomeStates require additional data on oil to gas ratios
218 . Appendix C
and oil to water ratios on production obtained tothe date of the application. Separate applicationrequirements exist in some states for waterfloodmethods, repressurization, disposal wells and theuse of hydrogen sulfides’
Because it is typical of the requirements ofState commissions for enhanced recovery applica-tions, section 3-30I (b) of the General Rules andRegulations of the Oil and Gas Conservation Divi-sion of the Oklahoma Corporation Commission isset forth:
The application for an order authorizing apressure maintenance or secondary recoveryproject shall contain the following:
(1) The names and addresses of the operatoror operators of the project.
(2) A plat showing the lease, groups of leasesor unit included within the proposed project; thelocation of the proposed injection well or wellsand the location of all oil and gas wells, includingabandoned and drilling wells and dry holes; andthe names of all operators offsetting the area en-compassed within the project.
(3) The common source of supply in which allwells are currently completed;
(4) The name, description, and depth of eachcommon source of supply to be affected;
(5) A log of a representative well completed inthe common source of supply;
(6) A description of the existing or proposedcasing program for injection wells, and the pro-posed method of testing casing;
(7) A description of the injection medium tobe used, its source and the estimated amounts tobe injected daily;
(8) For a project within an allocated pool, atabulation showing recent gas-oil ratio and oiland water production tests for each of the pro-ducing oil and gas wells; and
(9) The proposed plan of development of thearea included within the project.
Notice
Because enhanced recovery operations mayaffect in one way or another virtually all parties inthe vicinity of the operation, the notice require-ment and opportunity given for a hearing reflect aliberal attitude toward notification of nearby tractowners and operators. Service of notice must bepersonal, by mail, or by publication in a readilyavailable or official publication. Generally, noticemust be given by the applicant himself to the
other parties, and it will have to be given some 10to 15 days before the application or just after fil-ing of the application. Notice commonly must beextended to owners and operators of the reservoirand all those with interests in property withinone-half mile of the injection well(s). Protestagainst the application must be lodged within 15days of service of notice or of the application, de-pending on the jurisdiction, In many jurisdic-tions no hearing need be held if no party objectsto the application or if the commission does notorder one on its own motion.
An example of the notice requirements can begiven by reference to Alaska’s rules58 which re-quire a copy of the application to be mailed ordelivered by the applicant to each affected opera-tor on or before the date the application is filedwith the Oil and Gas Division of the Departmentof Natural Resources. Statements must be at-tached to the application showing the parties towhom copies have been mailed or delivered. Inthe absence of any objection within 15 days fromthe date of mailing, the division’s committee mayapprove the application. If objection is made, thecommittee shall set the matter for hearing aftergiving additional notice to the affected parties.Other States are similar in their provisions.
Hearing
Once a protest is made to an application or thecommission on its own initiative requires one, ahearing will be held on the application. The func-tion of the hearing will be to determine whetherthe injection program is reasonably necessary forthe prevention of waste and to obtain greaterrecovery from the common source, whether therecovery costs will be less than the proceeds fromrecoverable oil and gas, and whether the rights ofother interested parties are adequately protected.Hearings are governed by the State’s rules of civilprocedure and/or rules promulgated by the com-mission pursuant to authority delegated to it. Evi-dence introduced at the hearings will normally bescientific information and data brought outthrough the testimony of geologists and engineersunder questioning by the operator’s attorney orthe opponent’s attorney. A right to rehearingand/or a court review of a commission decision isgenerally provided upon timely application.
Appendix C . 219
Order
In general, an application for any type of injec-tion program may be denied by the State commis-sion for good cause; the commission will haveconsiderable discretion allowed by State statute.If the application is approved, an order will beissued by the commission giving the operatorauthority to proceed. The order will be a matter ofpublic record and can be rescinded for any goodcause. The injection program will be subject toadditional requirements while it is being imple-merited. 59 The operator will normally be requiredto complete reports before or at the time of com-mencement of injection, to issue periodic reportsregarding the program, and will be subject to in-spection of operations by the State regulatoryagency. Additional notice to other State agenciesmay be required after issuance of the order. Theappropriate State agency will also have to benotified of the termination of the injectionprogram.
Injection Regulations Under the SafeDrinking Water Act
Acting under the authority of the Safe DrinkingWater Act, 60 the Envi ronmental Protect ionAgency (EPA) has issued proposed regulations61
that would be applicable to underground injec-tions for EOR purposes. While these regulationswere not final at the preparation of this report, it is
useful to examine them in the context of the SafeDrinking Water Act and current State controlprograms. Some type of regulation wil l beforthcoming from EPA, even if not in the preciseform of the present proposals.
The Safe Drinking Water Act was passed intolaw as an amendment to the Public Health ServiceAct in 1974. Its purpose is to establish nationaldrinking water standards and ensure minimumprotection against contamination of drinkingwater supplies by well-injection practices. It at-tempts to accomplish this by having EPA issueregulations specifying minimum requirements forState programs to control underground injectionof fluids that may threaten the quality of water inaquifers that are or may be used for public supply.Section 1421 (b) (1)62 of the Act itself sets out theminimum requirements for State programs to con-
trol underground injection. They are, 1 ) onlyState-authorized injections may be continuedafter 3 years from the date of enactment; 2) the in-jector must satisfy the State that his operationdoes not endanger the drinking water; 3) the Stateprogram must have procedures for inspection,monitoring, recordkeeping, and reporting for in-jection operations; and 4) the regulations mustapply to all persons including Federal agencies.
With specific respect to oil and natural gas pro-duction, the Safe Drinking Water Act providesfurther in section 1421 (b)(2) 63 that:
Regulations of the [EPA] Administrator under thissection for State underground injection controlprograms may not prescribe requirements whichinterfere with or impede—(A) the underground injection of brine or otherfluids which are brought to the surface in connec-tion with oil or natural gas production, or(B) any underground injection for the secondaryor tertiary recovery of oil or natural gas, unlesssuch requirements are essential to assure that un-derground sources of drinking water will not beendangered by such injection.
In promulgating regulations setting requirementsfor State programs, it is the interpretation of theAct by EPA that the “Administrator need notdemonstrate that a particular requirement is es-sential unless it can be first shown that the re-quirement interferes with or impedes oil or gasproduction.” 64 Thus, the burden is upon the Stateor the enhanced recovery operator to prove thatthe requirement in question does interfere with orimpede production, and EPA further places theburden on the operator to show that the require-ment is not essential, That is, EPA has stated thatan alternative method of protection of drinkingwater may be approved by the State commission“if the operator clearly demonstrates that (i) therequirement would stop or substantially delay oilor natural gas production at his site; and (ii) therequirement is not necessary to assure the protec-tion of an existing or potential source of under-ground drinking water.”65
it should be observed that EPA does take noteof the fact that oil-producing States have regu-lated injections for years, and does set the re-quirements applicable to injection wells relatedto oil and gas production in a subpart separatefrom requirements for other types of injections.
220 . Appendix C
While EPA-required procedures are similar to ex-isting State procedures for injection permit regula-tion, the proposed regulations would imposemuch more detailed requirements than do currentState procedures. For example, the application re-quirements for new underground injection underthe proposed regulations66 set forth immediatelybelow should be compared with the Oklahomaregulations concerning application quoted onpage 218 of this appendix.
(a) The application form for any new under-ground injection shall include the following:
(1) Ownership and Location Data. The ap-plication shall identify the owner and operator ofthe proposed underground injection facility, andthe location of the facility.
(2) Engineering Data.(i) A detailed casing and cementing
program, or a schematic showing: diameter ofhole, total depth of well and ground surfaceelevation; surface, conductor, and long string cas-ing size and weight, setting depth, top of cement,method used to determine top; tubing size, andsetting depth, and method of completion (openhole or perforated);
(ii) A map showing name and locationof all producing wells, injection wells, abandonedwells, dry holes, and water wells of record withina one-half-mile radius of the proposed injectionwell; and
(iii) A tabulation of all wells requestedunder (ii) penetrating the proposed injectionzone, showing: operator; lease; well number;surface casing size and weight, depth and ce-menting data; intermediate casing size andweight, depth and cementing data; long stringsize and weight, depth and cementing data; andplugging 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. Ap-
propriate geologic data on the injection zone andconfining beds including such data as geologicnames, thickness, and areal extent of the zone.
(5) Underground Sources of DrinkingWater Which May be Affected by the Injection.Geologic name and depth (below land surface) ofaquifers above and below the injection zone con-
taining water of 3,000 mg/I total dissolved solidsor less and aquifers containing water of 10,000mg/I total dissolved solids or less.
(6) An electric log on all new wells and onexisting wells where available.
The regulations could broaden the number of per-sons or agencies who could challenge the ap-plication and insist upon a public hearing. Newrequirements would be made for record keepingat several different levels (by governmental agen-cies and operators); there would be a 5-yearlimitation on permits; new standards could be re-quired to be met after an injection program hascommenced under a properly issued permit; andthe specific well requirements go beyond thoseof many States.
A number of parties have objected strenuouslyto these proposed regulations or similar prior pro-posals, and to the general approach taken by EPAunder the Safe Drinking Water Act on the groundsthat this will significantly hinder EOR operationswithout corresponding benefits in the protectionof drinking water. A resolution of the InterstateOil Compact Commission of June 30, 1976, forexample, declared: “The State regulatory agenciesestimate that if the recent draft regulations wentinto effect it would cause a loss of production ofover 500,000 barrels of oil per day and in excessof 2.5 billion cubic feet of gas per day. All of thisis from existing wells that have been producingfor a number of years with virtually no adverse im-pact on the environment.67 While this resolutionreferred specifically to the immediate predecessorof the currently proposed regulation, personnelwith the Interstate Oil Compact Commission indi-cated in personal contact that the current regula-tions could still substantially interfere with or im-pede enhanced recovery of oil.
The Council on Wage and Price Stability re-cently criticized EPA’s proposed regulations onthe grounds that EPA may have both underesti-mated the costs of conducting the State regula-tory programs and misjudged the health benefitsto be gained by the regulations.68 Specifically, theCouncil stated that “EPA’s data regarding benefitsand costs offered in support of the regulations aretoo fragmentary, subjective, and inconclusive toenable an informed decision to be made on thisissue, ” and urged that further evaluations be madebefore putting regulations into effect.69
Finally, both producers and State commissionsidentified the contemplated EPA regulations asbeing likely to hinder or discourage enhancedrecovery operations. Of the responses from pro-ducers, four independent and six large producersstated specifically that the proposed EPA regula-tions would have an adverse effect on operations.An example of such responses was the followingcomment of one independent producer from theState of New York: “EPA-proposed rules andregulations regarding existing underground injec-
tion wells--could have a very negative effect on
enhanced recovery. ” One of the large companiesresponding similar ly stated: “The recently pro-
posed EPA rules concerning secondary recoveryoperations could essent ial ly prohibit newenhanced projects. ” One State agency which hasauthority over several hundred enhanced recov-
Appendix C . 221
ery projects with many more potential projects inthe State said that no permit had been denied forsuch projects but that “Many may be denied nextyear if the Federal UIC [underground injectioncontrol] Regulation is administered as written. ”The American Petroleum Institute has also con-ducted a survey of major and independent pro-ducers and has concluded that “Without doubtthe proposed regulations will interfere with andimpede underground injections and substantiallydecrease the ultimate production and recovery ofhydrocarbons.” 70
In light of the number of such comments, it isclear that EPA-proposed regulations are perceivedas having, or as likely to have, an adverse impacton enhanced recovery operations.
Operational Aspects of Enhanced Oil Recovery
Potential Liability to Nonjoining InterestsRelatively few reported cases have arisen in
which non joining interests have made claims fordamages against unit operators for enhancedrecovery activit ies, a n d fewer sti l l in whichdamages have been awarded. However, the issueis 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 notreveal 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 coopera-tion. 72 For this reason, it is important to examinebriefly the legal theories upon which claims orliability might be based, the treatment of these bythe courts in the past, and possible approaches tothe problem in the future.
The legal theory upon which a claim fordamages may be based will depend in part uponthe relationship between the claimant who hasnot joined the unit and the operator responsiblefor the enhanced recovery project. If the claimantis a lessor or cotenant of the operator, the claim inmost circumstances will be that the operator hasbreached a duty owed to the claimant or that the
operator has caused waste of property jointlyowned by both the operator and the cotenant. Ifthe claimant is a neighbor owning an interest inthe reservoir, the claim may be based on a theoryof trespass, strict liability (ultrahazardous activity),nuisance, or fault. In general, the courts haveshown a disinclination to award damages on anyof these grounds except the very last—fault.
As discussed in an earlier section, the lease it-self governs most relations between lessor andlessee. Most leases are silent with respect toenhanced recovery, however, and it is necessaryto examine implied rights and obligations thatarise out of the basic relationship. These can beput under many headings, but the general princi-ple that is most important is that the lessee mustact in good faith and do nothing to injure thevalue of the leasehold. While the same relation-ship is not present in a cotenancy situation, it isnevertheless well recognized that one cotenantshould do nothing to reduce the value of the jointproperty without the consent of the other. Ineither circumstance, the most likely claim to beraised by a non joining lessor or cotenant is thatthe lessee/operator is causing or permitting oil
and/or gas to be drained away from the property.Cases have been adjudicated in several jurisdic-tions 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 un-dertaken with the approval of the Texas RailroadCommission by the lessee of the claimants. Thelessors (claimants) refused to join in the unit. Thelessee was also the lessee on other nearby tractsand maintained its lease on the lessors’ lands bycontinuing to conduct primary operations there.The lessors sued the lessee on the theory that itwas causing drainage of “wet” gas from undertheir tracts to the other tracts operated by thelessees. The Fifth Circuit Court of Appeals held infavor of the lessee, saying that there was noliability to the nonconsenting lessors becausethey had been given an opportunity to join in theunit operations on a fair basis.
In the case of Carter Oil Co. v. Dees,74 a lesseesought a declaratory judgment allowing it to con-vert an oil production well to a gas injection wellfor enhanced recovery operations. The lessor op-posed this, claiming it would cause drainage of oilfrom underneath his property. Despite a contraryruling on an identical case the previous year bythe Seventh Circuit Court of Appeals,75 the Ap-pellate Court of Illinois held for the lessee on theground that the additional oil gained by the proj-ect through drainage from other land would morethan compensate for the loss from the lessor’sland.
After the Dees case, the Illinois legislaturepassed an act that expressly stated that enhancedrecovery was in the public interest. When a groupof nonconsenting lessors and cotenants at-tempted to block a waterflood operation in thecase of Reed v. Texas Company, 76 the IllinoisSupreme Court relied upon the legislation to holdfor the operator. The court held that the claimantshad been offered an opportunity to participate inthe program on a fair basis, that the State miningboard had approved the project, and the projectwas in the public interest; it stated:
If a minority of one or more persons affected bythe operation could prevent it by refusing to joinin the agreement, they could then force theothers to choose between leaving a large part ofthe oil underground, or consent to granting thedissidents an unreasonably large percentage ofthe oil. in other words, the power to block arepressure program by refusing to sign theunitization agreement, would be the power to in-
sist upon unjust enrichment. Surely a court ofequity would not support such a rule.
In somewhat similar cases, the North Dakota77 andMississippi 78 Supreme Courts followed the sameline of reasoning in holding for the operators ofother enhanced recovery projects.
It should be observed that despite the denial ofdamages to lessors, the lessee-operators in casessuch as the Stott case must still satisfy other re-quirements of their leases to keep them valid.Thus in Stott the operator had to maintain sepa-rate production activities on the leases and had toaccount to the claimants separately from the unitoperation. However, the courts have shown awillingness to support enhanced recovery despitecompeting claims of property rights in minerals.An express statement by the legislature in favor ofenhanced recovery can be of considerable sup-port for this predisposition in litigation of thisnature.
When it is a neighboring interest owner who isclaiming damages the theories asserted in supportof liability are different. By and large, however,the courts have tended to support enhancedrecovery and, with certain exceptions which willbe noted, have denied liability.
In injection programs, the fluid injected sweepsfrom the injection well towards the productionwell (s). The migration of the fluid can cross prop-erty lines, and this fact has led to claims oftrespass by neighboring interest owners who havenot joined in the unit or enhanced recoveryprogram when they have felt the production fromtheir land was reduced by the fluid sweep. Themost important case dealing with this claim oftrespass is a Texas case, Railroad Commission v.Manziel. 79 In rejecting the neighbor’s claim oftrespass, the Texas Supreme Court adopted thetheory advanced by Professor Howard Williamsand Dean Charles Meyers of a negative rule ofcapture. 80 Just as one may produce oil or gas eventhough it migrates from the property of another,so too may one inject a substance into the groundfor production purposes even though it migratesand causes loss of production for a neighbor. Thecourt also supported its denial of liability by not-ing that enhanced recovery is in the public in-terest. No case involving enhanced recovery hasbeen found which has granted damages on a
Appendix C . 223
theory of subsur face t respass by in ject ion of
fluids.
For some types of ultrahazardous activitiesthere is strict liability (liability without a showingof negligent operations) for damages flowing fromthe activity. This legal theory overlaps with theprinciple of nuisance, and the two may be treatedtogether even though one does not usually thinkof enhanced recovery as being ultrahazardous. 81
In an important recent case arising in Oklahoma,the Tenth Circuit Court of Appeals upheld a deci-sion in favor of a claimant for damages for a non-negligent waterflood project. The court, inGreyhound Leasing and Financial Corporation v.
Joiner City Unit,82 relied upon a nuisance provi-sion in the Oklahoma Constitution which statesthat no private property shall be taken ordamaged for private use unless by consent of theowner. Although the unit operator had had theproject approved by the Corporation Commissionand had offered the claimant an opportunity toparticipate in the unit, the court found liability. Itis possible that the court in another jurisdictionmight hold in this manner even without such aState constitutional provision. Because the moreexotic methods of enhanced recovery arerelatively new and untried, there is a greaterpossibility that a court might find them ultrahazard-ous than with normal waterflood operations. Thepossibility of liability on this ground could be adisincentive to operations even though a numberof authorities have expressed disfavor with such aresult. Producers in five States indicated that theyhave enhanced recovery projects being inhibitedby fear of such liability.
The final basis for liability for enhanced recov-ery operations is fault, which includes negligentactions, wanton disregard of the rights of others,and intentional harm. Liability arising from suchactions is well recognized whether primary orenhanced recovery operations are involved. In vir-tually all instances the actions of the operator willbe beyond those included in the order of theState commission. Few would contend thatoperators should have their negligent or inten-tionally harmful acts excused simply because theyare engaged in enhanced recovery operations,although questions might be raised about thestandard of care that should be applied to opera-tors in such projects.
In general, the courts have looked with disfavorupon claimants who have been offered an oppor-tunity to join in an enhanced recovery operationon a fair and equitable basis and have refused tojoin. The commission approval of the projects andpublic interest in enhanced recovery of oil tend tonegate the possibility of liability for non-negligentoperations and lend support to the other legaltheories —such as the negative rule of capture—upon which a court might decide a claim fordamages from a nonconsenting interest owner. AState statute expressing encouragement forenhanced recovery will also tend to negateliability. However, the uncertainty of the law inmany jurisdictions makes the undertaking ofenhanced recovery without joinder of all the in-terests in the unit either voluntarily or throughcompulsory unitization a risky business. Not onlymay operations result in liability, but the merepossibility that a court might so hold could dis-courage unitization by recalcitrant minority in-terests and could provide them strong leverage inbargaining over the participation formula.
Environmental Requirements
Both State and Federal environmental require-ments might affect enhanced recovery in severalways. First, they may cause delay in the approvaland initiation of projects. Second, they may makeenhanced recovery projects a greater economicrisk because they could increase costs, couldcause liability for violations of the requirements,or could force the shutting down of projects. Suchpossibilities could discourage efforts to undertakeEOR projects. It should be noted that present en-vironmental requirements seem to be restrictingonly with respect to enhanced recovery inCalifornia, and EPA’s proposed underground in-jection regulations discussed in a previous sec-tion. The areas of environmental regulations thatmay be of significance for present or future opera-tions relate to requirements for environmental im-pact statements, air quality standards, and limita-tions on water pollution.
Environmental Impact Statements
Environmental impact statements are now re-quired for certain State activities in several States
224 . Appendix C
and for all Federal actions and, proposals signifi-cantly affecting the quality of the human environ-ment. In 1970, the California Legislature enactedthe Environmental Quality Act,83 which requiresvarious State and local governmental entities tosubmit environmental impact reports before un-dertaking certain activities. The affected State andlocal agencies are compelled to consider thepossible adverse environmental consequences ofthe proposed activity and to record such impactsin writing. At least one producer has reported thatthis California requirement has caused “delay inwaterflood projects due to delay in permitsbecause of environmental assessment studies.”These and other requirements had, said the pro-ducer, resulted in “presently over 1-year delay inobtaining permits. ”
The National Environmental Policy Act of 1969in section 102 (2) (c)84 requires an environmentalimpact statement to be completed for everyrecommendation or report on proposals forlegislation and other major Federal actions signifi-cantly affecting the quality of the human environ-ment. Since the Federal Government is now in-volved with enhanced recovery only in limitedareas on Federal lands, this Act does not havemuch effect on enhanced recovery. However,should the Federal Government become involvedin regulation of enhanced recovery, an environ-mental impact statement would probably have tobe filed to meet the requirements of section102(2) (c).
Air Pollution
Air quality requirements are primarily of sig-nificance for thermal recovery projects. Thelegislation of greatest importance in this area isthe Federal Clean Air Act of 1970,85 and the Stateimplementation plans enacted pursuant to it,
Under the Clean Air Act, EPA has establishedprimary and secondary ambient air quality stand-ards. The primary standards are designed to pro-tect the public health and the secondary stand-ards are to protect the public welfare. It is theresponsibility of the States to promulgate plansto attain these standards for each of the pollut-ants for which the EPA has set standards. Limita-tions for air pollution from new sources of pollu-tion are established by EPA itself. In addition, the
Clean Air Act has been interpreted by the courtsas requiring agencies to prevent any significantdeterioration in air quality in areas already meet-ing the standards. Both State and Federal govern-ments can enforce the Clean Air Act, and stiffpenalties may be assessed for violation of regula-tions.
The precise applicability of the Federal andState requirements under the Clean Air Act de-pends upon the size and type of equipment usedin steam generation, the quality of the fuel usedfor providing a heat source, and the quality of theair in the State and region where the operationstake place. Since most ongoing thermal projectsare located in California, it is the State in whichthere is an indication as to the impact of such airrequirements. One producer there indicated thatan application for a number of enhanced recov-ery projects was being delayed while EPA soughtadditional data on the air quality impact of theequipment to be used. The same producer sug-gested that some 25 projects were being delayeddue to present and pending air-quality and land-use regulations. “Thermal recovery projects,” itstated, “have been delayed due to EPA andCounty Air Pollution Control District regulationsand permit requirements. ” At least three otherlarge and small producers stated that they hadmultiple projects being delayed by California air-quality requirements. Hydrogen sulfide regula-tions in Texas have been made more stringent inrecent years, but no producer indicated that thishas had an adverse impact on enhanced recov-ery.
Water Pollution
The most important aspect of water pollution,namely pollution of ground water throughseepage from flooding operations, is governedunder State and Federal law by the Safe DrinkingWater Act as previously discussed. Additionally,the Federal Water Pollution Control Act Amend-ments of 197286 (FWPCA) regulate water quality.Under the FWPCA the discharge of pollutantsinto navigable waters without a permit isprohibited. The term “navigable waters” is verybroadly defined. Severe penalties are providedfor violation of the requirements of the Act.
Appendix C ● 225
Other Environmental Regulation
There are other local, State, and Federal regula-tions that can affect enhanced recovery. Land-useplanning restrictions and zoning, toxic substanceregulation, noise level limits, occupational healthand safety requirements, and other measures mayimpact upon enhanced recovery operations inone way or another. However, the degree of im-pact is highly speculative at this point.
Water Rights
All types of enhanced recovery, as previouslynoted, require water either for flooding purposesor for steam generation. Water of low quality hasseemed adequate in the past, but for some of themore sophisticated techniques of enhancedrecovery, fresh water will be more desirable.Questions of water rights for enhanced recoveryhave generated problems and litigation in thepast, and it can be expected that such issuescould become more important in the future. Abrief treatment of the principles that have guidedthe courts with respect to water rights suggeststhe problems that may be faced in acquiringwater for enhanced recovery.
Before discussing the law applicable to water,it is necessary to mention some of the classifica-tions of water that are made, for the rights mayturn on the classification. Water, of course, maybe found on the surface of the earth or under-
ground. Sur face waters may be c lass i f ied as
diffused (having no defined channel or cour sesuch as a marsh), water courses, lakes, springs, orwaste water. Underground waters may beclassified as underground streams or as percolat-ing waters (having no flow or water course) .87
The right to own or use water can presentquestions in three basic areas. First, there may becontroversy arising between lessor and lessee, orbetween surface owner and mineral interestowner, as to water found on or adjacent to theland where the oil is located. Second, questionscan arise between those who wish to use waterfor enhanced recovery and others who assertrights to the water but have no relationship withthe enhanced recovery project or land on whichit is located. Third, and perhaps overlapping the
other two, will be matters of regulation of wateruse by the States.
Lessor-Lessee Rights
The litigation that has arisen in the past withrespect to water rights for enhanced recovery hasdealt primarily with the respective rights of lessorand lessee, or surface owners and owners ofmineral interests beneath the surface. Forsimplification, reference will be made simply tolessor and lessee. In such litigation, it has beenpresumed that the original owner of the surfaceowned the right to the water and could disposeof it for enhanced recovery purposes; the ques-tion litigated has been whether there was such adisposition, either expressed or implied.
The first type of issue that has arisen iswhether a grant of “oil, gas, and other minerals”(or a similar phrase) has included water as amineral. Courts have held that freshwater is not amineral within the meaning of this clause in an oiland gas lease or deed.88 instead, the courts treatfresh water as belonging to the surface estatewhether the water occurs at the surface or mustbe brought from the underground. Therefore, thelease or deed from the surface owner must ex-pressly grant rights to use of this water, or therights to the water must arise as part of an im-plied right to use of the surface for the develop-ment of the mineral estate. One Texas courtmade a distinction between fresh water and saltwater, holding that salt water is part of themineral estate,89 but the Texas Supreme Courthas since said that salt water and fresh water alikeshould be treated as belonging to the surfaceestate.90
Many oil and gas leases do contain an expressgrant of right to the lessee to use water from thelease premises. They often contain a provisionsuch as the following:91
The lessee shall have the right to use, free ofcost, water, gas and oil found or located on saidland for its operations thereon, except waterfrom the wells of the lessor.
Does this provision, which does not mentionenhanced recovery, authorize the use of waterfrom the land for enhanced recovery purposeswhen such techniques were not known in the
96-594 0 - 7fj . 1 ~
226 . Appendix C
area or to the industry when the lease wasgranted? It is generally treated as authorizing theuse of water on the leased premises for enhancedrecovery, but a notable Texas case, Sun Oil Co. v.Whitaker, 92 to be discussed shortly, declined torule on this question when given the opportunity.A problem with a clause such as the one quotedis that the water for enhanced recovery may haveto be used on other lands and this is not permit-ted by the provision. However, the royaltyowners agreement will include a provision forthis when there is unitization. if a nonroyalty in-terest owner is the owner of the surface, otheragreement will have to be made to authorize theuse of the water off the leased property.
Finally, even if there is no express provision foruse of water for enhanced recovery, there willgenerally be an implied right to use of the water.As stated in a previous section, the lessee has theright to use so much of the surface as may bereasonably necessary to effectuate the purposesof the lease having due regard for the rights of theowner of the surface. This will include water, andseveral courts have expressly applied this impliedright doctrine to water (both fresh and salt) foruse in enhanced recovery operations. 93
The most recent and important of these deci-sions is Sun 0il Co. v. Whitaker.94 In this Texascase, one Gann gave a lease to Sun Oil in 1946and then conveyed away the surface rights toWhitaker in 1948. The lease had an express pro-v i s ion fo r the use o f wate r subs tan t ia l l y l i ke the
one quoted above . A f te r year s o f p roduct ion by
primary methods, Sun decided to waterflood theformation. It received authority from the TexasRailroad Commission to use fresh water for thispurpose, and began producing water from a non-replenishable water formation for the program.The owner of the surface, Whitaker, was usingfresh water from the same formation for irrigationof farmland. Sun sought to prevent Whitakerfrom interfering with i t s product ion, andWhitaker in the same suit sought to prevent Sunfrom using the water for enhanced recovery. Thecourt held, without ruling on the extent of the ex-press provision, that the oil and gas lessee’sestate was the dominant estate, that the lesseehad an implied grant of free use of such part andso much of the premises as was reasonablynecessary to effectuate the purpose of the lease,
that the implied grant extended to and includedthe right to use water in such amounts as wouldbe reasonably necessary to carry out its opera-tions under the lease, and that the waterfloodoperation was reasonably necessary to carry outthe purposes of the lease. It should be noted thatthe court found that no other source of usablewater on the leased tract was available, and thatthe decision was by a narrow majority of five tofour. With only a slight change of facts this courtand any other could easily hold to the contrary,so that an enhanced recovery project operator iscertain of his rights to water only if they havebeen expressly granted for enhanced recoverypurposes .95
Riparian and Appropriation Rights
When the rights to water of parties other thanthe lessor and lessee are considered, several rulesof ownership of rights must be taken up. Theseare the doctrines of riparian rights and rights ofprior appropriation, and some States follow acombination of these two.96 Which rule appliesto a particular State has largely been determinedby the climate and geographical region in whichthe State is located. Generally speaking, thesedoctrines apply to watercourses with under-ground waters being governed by a theory of ab-solute ownership or a reasonable use limitationonly. However, in some States, the rightsdoctrines will apply to underground water as wellas surface water.
Riparian Rights. —The doctrine of riparianrights is found to apply in some 31 States (tableC-2) located primarily in the eastern half of theUnited States, where there is more water. Underthis principle, the owner of land adjacent to awatercourse (the riparian owner) is entitled toreasonable use of such amount of water as he canput to a beneficial purpose. A reasonable use issuch that it will not unduly disturb a lowerriparian’s right to some minimum flow of waterand which is suitable to the character and size ofthe particular watercourse. A limitation on theright is that the water must be used on theriparian owner’s premises, or at least within thewatershed. In States following this principle, per-colating waters are generally treated as beingsubject to absolute ownership by the surfaceowner or a principle like the rule of capture is ap-
plied, so that the underground waters may besold and transported away from the watershed.
The significance for enhanced recovery underthe riparian rights approach is that production ofoil is a beneficial use as is required under thedoctrine, and water generally will be availablefrom one source or another. However, whether
the water is from a watercourse or from under-ground it may be necessary for the operator tocontract for the water. Use of the water forwaterflooding can be enjoined by lower riparianowners only if they can show that there has beenan excessive or unreasonable taking of the water,leaving them with less than their fair share.
Rights of Prior Appropriation.—The doctrine ofprior appropriation developed in the more aridregions of the United States and presently appliesin nine States, commonly designated as theRocky Mountain States. Prior appropriation is thetaking of a portion of a natural supply of water, inaccordance with law, with the intent to apply itto some beneficial use within a reasonable time.As before, enhanced recovery operations do con-stitute a beneficial use of the water.97 The right tothe water is fixed by time, not by location on the
watercourse . Thus , an upst ream appropr iator
who is later in time (junior appropriator) in his ap-propriate ion i s subord inate in r igh t to adownstream prior (senior) appropriator’s right tothe water. Appropriation is a vested right then totake or divert and consume the same quantity ofwater forever.
Ownership of land is generally a prerequisiteto appropriation. However, as has been stated byone authority that “[i] n the absence of statute, ithas always been the rule in States following theappropriation doctrine that an appropriator maychange the use and place of use so long as thechange does not injure other appropriators. 98 Thismeans that, subject to State regulation, a partymay acquire or dispose of his appropriationrights. The importance of this is that operators arefaced with the problem that with prior appropria-tion the right is perpetual with no provisions forshort term appropriation of water. The ability tobuy and sell rights is significant, for the use ofwater for enhanced recovery is of limited amountand duration; the operator must buy on a short-term 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 issubject to having his water diminish or cease en-tirely in times of shortage.
Dual System. —Some 10 States apply a com-bination of the two principles described aboveknown as the California doctrine. That is, theyfollow a rule that a riparian owner may take waterfrom a source but only as much as he can put to areasonable beneficial use. Surplus water is sub-ject to appropriation by nonriparian owners or toexport by riparian owners to nonriparian lands;but this appropriation or export is junior to theprior rights of the riparian appropriators. Beyondthis, generalization is very difficult, for the Stateshave gone in different directions through courtdecisions and legislation.
As stated previously, EOR is regarded as abeneficial use of water. While a nonriparianoperator may acquire rights for water in the dual-system States, his rights will be subject to priorappropriation by those senior in rights to him.Ground water is likely to be the subject of speciallegislation in such States.
State Regulation of Water Use
The trend in the current development of waterlaw has been, as noted by the leading authorityon the subject, “toward more public regulationsthrough permit systems, accompanied by newlegislative efforts in some States to recognize theinterrelationship between many surface andground water sources and to combine the con-trols and management under one statute.99
Regulation is more comprehensive generally inthe more arid Western States than in the morehumid Eastern States, although the Eastern Statesdo regulate pollution of waters. A number ofWestern States following the prior appropriationdoctrine have agencies which regulate the ac-quisition, transfer, or change of appropriationrights. Because regulation of ground water is ofrelatively recent date in most States, its treatmentin statutes tends to be more comprehensive thanfor surface waters, and the permit systems aremore extensive.
Whether surface waters or ground waters areto be used in enhanced recovery, it is likely, par-ticularly in the western half of the United States,
—
228 . Appendix C
that an operator will have to be issued a permitacknowledging his right to the water prior tousing the water he has acquired for the EOR proj-ect. This will probably be done through the officeof a State engineer, a commission, or a waterresources board in a proceeding separate fromthe one for a permit to inject the water. The pro-cedure is similar to that for getting approval forthe EOR project. There have been few cases aris-
ing from administrative problems involvingenhanced recovery projects, and little or no in-dication from the literature or the questionnairesthat State regulation of water rights has causedany problems for enhanced recovery. The poten-tial for problems exists, however, because theagencies might likely become focal points forcompeting claims over the uses to which freshwater should be put.
Table C-1Unitization 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. $31.05.110Arizona. . . . . . . . . . . . . . . . . . . . . . . Ariz. Rev. Stat. $$27-531 to 27-539Arkansas. . . . . . . . . . . . . . . . . . . . . . Ark, Stat. Ann. 1947, $53-115, C-1 to C-8California Subsidence. . . . . . . . . . . Calif. Pub. Res. Code $$3321 to 3342California Townsite . . . . . . . . . . . . Calif. Pub. Res. Code Q$ 3630 to 3690Colorado . . . . . . . . . . . . . . . . . . . . . Colo. Rev. Stat. 1963, 100-6-16Florida. . . . . . . . . . . . . . . . . . . . . . . . Fla. Stat. Ann. ~ 377.28 (1) and (2)Georgia. . . . . . . . . . . . . . . . . . . . . . . Ga. Code Ann. $43-717 (b) and (c)Idaho . . . . . . . . . . . . . . . . . . . . . . . . Idaho Code ~ 47-323Illinois, . . . . . . . . . . . . . . . . . . . . . . . Smith-Hurd, Ill. Rev. Stat. Ch. 104$84 b, cIndiana . . . . . . . . . . . . . . . . . . . . . . . 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. $$55-1301 to 15-1315La. Rev. Stat. 1950, Tit. 30, # 5BLa. Rev. Stat. 1950, Tit. 30, $ 5CMe, Rev. Stat. ~ 2159Mich. Comp. Laws Ann. 3$319.351 et seq.Miss. Code 1972 ~$ 53-3-101 to 53-3-110Rev. Stat. Mo. 1969, $259,120Rev. Code of Mont. 1947, $$ 60.131.1 to 60.131.9Re. Rev. Stat. Neb. 1943, $57-910Nev. Rev. Stat. 522.070N.M. Stat. Ann $$ 65-14-1 to 65-14-21N.Y, Environ. Conserv. Law $23-090, subdivs. 1, 3-12No. Dak. Cent. Code $$ 38-08-09.1 to 38-08-09.17Ohio Rev. Code $1509.2852 Okla. Stat. Ann. $~ 287.1 to 287.15Ore. Rev. Stat. 520.270 to 520.330So. Dak. Comp. Laws 45-9-37 to 45-9-51Term. Code Ann. 60-104 (d) (13)Vernon’s Civ. Stat. Tex. Ann., Article 6008bUtah Code Ann. 40-6-17Rev. Code Wash. ~~ 78.52.340 to 78.52.460W. Va. Code 1931 $4 22-4 A-8 to 22-4 A-9Wyo. Stat, ~ 30-222
Appendix C . 229
Table C-2Comparative 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 CMaine . . . . . . . . . . . .
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 orroyalty int. req’d
vol. = voluntary only:
7562.5637565758075Nonevol.75
None7575None75
85-W -65-R758575807562.57560806563757550vol.80None7580
Inc. ult.recovery
YesYesYesYesNoYesYesYes——
YesYes
YesYes
YesYesYesYesYesYesYesYesYesYesYesYesYesYesYes
——
YesYesYes
Proof or findings required
Preventwaste
YesYesYesYesNo——
Yes—
YesYes
YesYesYesYesYes—
YesYesYes—
YesYesYes—
Yes—
YesYesYes
YesYesYesYesYes
Protect corr.
rights
YesYesYesYesYesYesYesYes—
orYesYes
YesYes
Yes—
YesYesYesYesYesYesYesYesYesYesYesYesYes
YesYesYesYesYes
Add.costnot over
add. recov
YesYesYesYesYesYesYesYes——YesYesYesYes
YesYesYesYesYesYesYesYesYesYesYesYesYesYesYes
YesYesYesYesYes
Unit areaPart or All ofSingle orMultip.pools
PAMPASPASPASPAM
ASPAMPAMPASPAMPAMPASPASPAMPASAM
PAMPAMPAMPASPAMPAMPASPASPASPAMPASPASPAMPAM
PAMPASA MAS
PAM
Water rights
doctrineR-riparianPA-prior
appropriationD-dualsystem
RPAPARDD
PARR
PARRDRRRRRDR
PAD
PAPARDRDDDRD
PADR
PA
● See text, page 211.Adapted in part from Eckman,6Nat Res. Lawyer 384(1973).
—
230 . Appendix C
APPENDIX CFOOTNOTES
I The description here is of what 15 known as the “unless”type lease, the type In use in most States. A slightly differenttype lease, an “or” lea5e, is In use In Cal ifornla, T h ed i f f e r e n c e b e t w e e n t h e t w o r e l a t e s pr{marily to theautomatic termination of the lease in the primary term forthe “unless” lease. H. Willlams and C. Meyers, 0// and GasLam, $601.5 (1975).
‘Gray, “A New Appraisal of the Rights of Lessees Under011 and Gas Leases to Use and Occupy the Surf ace,” 20Ro( 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 tothe Acqulsltlon, Use and Disposal of Repressuring Sub-stances Used In Secondary Rec f)very Opera tions, ” 6 RockyAl[. $lin L lns[ 273 ( 1 9 6 1 ) ; see also, H. Wllllams .lnd C .
M e y e r s , 0/1 and Cm Law $ 935 (1 975), and cases andauthorities cited therein.
‘) Martin, “A Modern Look at Implied Covenants to Ex-plore, 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, AStudy 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 Oiland (jas Conservation Commission, to cite another exam-ple, provide that an 80-acre spacing will apply for oil wellsin the absence of an order by the Comrnlsslon providing forthe spac Ing of wells and establishing dralhage or drillingunits for a reservoir.
10A recent treatment O( the subject is Bruce, ‘‘Maximum
Efficient Rate—Its Use and Misuse In Production Regula-ti~~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 Na-oonal lrr~(. for P(’troleum Landn-ten 77 (1 964).
I ~JDesc rlptlon of the establ i shment of th is uni t is Con-
tained in R. Myers, The Law of Pooling and Unitization Ch. IV(2d ed. 1967) and the discussion of unit formation whichfollows 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 (2ded. 1967).
231bid.
Wbid. ~ 4.06,
“)Appendix C gives the citation to each State’s compul-sory unitization statute and the basic requirements of eachState’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: AReview for Future Agreements, ” 6 Nat, R(JJ, Lawyer 339(1 973); Lawson, “Recent Developments in Pooling andUnitization, ” 23rd Oil & Gas ln~[, 145 (1 972); R. Myers, TheLaw 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 disposi-tion of the application for rehearing, “may appeal therefromthe district court of the county wherein IS located any prop-erty of such party affected by the decision, by filing a peti-tion for the review of the action of the commission withintwenty 120] days after the entry of the order followingrehearing or after the refusal for rehearing as the case maybe, ” 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 , M e y e r s , 0// and Gaj LJJV $ 9 7 0(1 975), and c ases disc ussed therein.
‘“EC kman “Statutorv Fleldwlde O i l a n d Gas U n i t s : ARev Iew for Future Agrtwments, ” 6 hat. R(I$ la~$i [’r 339, 360(1 973).
‘l E.g., Wyomlrrg Statutes Annotated, $30-222.
‘JH. Wtlllam$ a n d C. M e y e r s , 0// anc] Ga$ Lati $ 9 1 1(l 977); R Myt~rs, The L~Iv ol Pool ing a n d UmfIza(Ion, Ch.X11, (2d ed. 19671
~! J1 7 u s. 341 (1 943).
-lJR M y e r s , Th(I / ail oi P(x)//n,g a n d Un~/~/al/on $12.() j (1 J , I Jd cd 19671.
‘; Unl((Id 5[al(’~ v. ( [~lfon Vallc! operators C o m m i t t e e ,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 andRegu I at lon~ of (1 I I and G a s C o n s crvdt Ion DI v i s ion , $2-261 (d]
‘fiE.g , Texa~ Railroad Commrssltm, 011 ~nd Gas Divtsrcm;Rule 48, New M[)XICO OIi Conservat ion Commlsslon, Rule7 0 1 [, 3
“I IJ{J(I \l’a/(lr Alsjo( Mt(Id 0// C(), v Stott, 159 F, 2 d 1 7 4
[5th Clr. 1946), cert. denied 331 U.S. 817 (1 947).
‘Iof)ob$on” v, Arkdr?sa\ 0// drr~ Gaj (-cm~mJ$$Ion, 2 3 5S E1’.2d 33 (Ark 1 9 5 0 ) .
‘ l O t h e r example~ inc Iude R(Ipubl/( Natural (hs C O v,B~L(Ir, 197 F 2d 647 (1 Oth Clr. 1952); Cor/(Iy v. M)sslsslppiS/att C)II an(l Gaf B(xard, 105 $ 2d 633 (M I S S. 1958); f3arrr -
I%J(III, In( v. )[ In ()// Co , 162 S 2 d 6 3 5 ( M i s s . 1 9 6 4 ) S e eg[>nerdlly, Ii W IIllams and C. Meyers, 01~ and G~\ la~v $933(1 975)
-’ ( )m( )n R,] f/roc?d Co v. 011 dnd Ca\ Conserkd(lon Com-
rn /$$ /e r r , 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 Com-
pact Commission, Summdr) 0/ .%~cond<]r) Recoh(’ry a~)d
Pro$sur(] ~la~n(erranco Ru/(Is ,]nd Regulallfm$ In t i r e Um(~JcfS/a~(’\ (S~~ptember 1969).
> INCW M e x i c o (JII C o n s e r v a t i o n Commissl(~n, R u l e701 B 1,
“ {) Kansas Corporatl[~n Commlssitm, (;enf~r,ll Rule\ andRegulat ions, $ 82-2-502, A well log IS the writ ten recordd(~s[ rl blng the strata, water, oil or Has encountered I n drll I -
Append;x C . 231
ln~ a well with such addit ional information as to gasvolumes, pressures rate of fill-up, water depths, cavingstrata, and casing record as is usually recorded in the normalprocedure 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 requirethe locating, drilling, deepening, redrilling or reopening, c ds-ing, sealing, operating and plugging of wells drflled for 01 Iand gas or for secondary recovery projects, or wells for thedisposal of salt water, brine or other oil field wastes to bedone in such manner or by such means as to prevent theescape of oil or gas out of one stratum into another, or ofwater or brines into oil or gas strata; to prevent pollutlondamage to or destruction of fresh water supplles Includinginland lakes and streams and the Great Lakes and connect-ing waters, and valuable brines by oil, gas or other waters, toprevent the escape of oil, gas or water into workable coal orother mineral deposits; to require the disposa I of 5.11 t w,, ter
and brines and oily wastes produced Inc Idcntal to oIl andgas operations, in such manner and by such methods andmeans that no unnecessary damage or danger to or destruc-tion of surface or underground resour( es, to neighboringproperties or rights, or to life, shalAnn $ 319.6(c).
(1042 USC, $$ 300 f-300j-9.
~~140 CFR Part 146, 41 Fed. Reg.
‘):42 U, S.C.$ 300h (b)(1).
bJ[bid. $! 300h (b) (2).
~IA41 Fed, Reg. 36731.
bjlbid.
result. ” M Ich. Comp Lavv
36730 (August 31, 1976)
~blbid. 36744. 40 CFR $ 146.47.
““35 0 1 / & Gas Comp<l( / Bu//ef/n, ]unt~ I 976 p 1 3 ,
‘nCouncil on Wage and Price Stabi lit y Release CM’ PS-204IO(t. 27, 1976).
w Ibid. at 23-24.
‘~JLetter of Roy F. Ca I son, Production D I ret tor, Amc) rl c a n
Petroleum lnstitut[~, Dall~s, Tex., to Office ot Water Supplv,Environmental Protection Agency, W~shlngton, D C,, underdate of Jan, 12, 1977.
~ I A I ist of these is contal ned I n H. W I [ I lams and CMeyers, (JII and Ga\ Law, $ 204.5 (1 975 I,
‘JLynch, “Liability for Secondary Rec oierv (){wr,~tlons,”22nd 0// & Ca\ /ns[, 37, 79( I 97 I ),
-‘1 59 F, 2d 174 (5th C ir. 1946), cert. deni[d, 3 I I u $ 817
( 1 947),
“J92 N E 2d 519 III I app, 1 9 5 0 ) .
232 . Appendix C
“;Ramsey v. Carter Oil Co., 74 F. Supp. 481 (E. D. Ill.1947), affm’d 172 F.2d 622 (7th Cir.), cert. denied 337 U.S.958 (1949), reh. denied, 338 U.S. 842 (1949).
‘[,1 59 N . E . 2d 641 (1 I I 1959) .
“7Svverson v. North Dakota State Industrial Commission,111 N.W.2d 128 (N.D. 1961).
‘HCallfornia Co. v. Britt, 154 So.2d 144 (Miss. 1963 ) .
“361 S,W.2d 560 (Tex. 1962).
HOH, Will lams and C. Meyers, 0// and Gas 1.Jw, $ 2 0 4 . 5
(1 975).
. ~lLynch, “Liablllty for Secondary Recovery Operations, ”2 2 n d 0// & Gas /nst 39, 65 (1971).
w444 F.2d 439 (1 Oth Clr. 1971 ).
~ ICa] ifornld Publ IC Resources Code $$ 21000-21151.
M42 LJ. S.C. S 4 3 3 2
“;42 IJ. S.C $$ 1857 e( seq
l i 033 u ,s ,C $$ 1151 (’~ $W
‘“These c Iassitications by Hutchins have been critic Izedbut they remain useful and have been important in thedevelopment of water law. See R. Clark, VIatcrs and WaterR@ I/s $ 3.1 (1 967).
88Vogei V. Cobb, 141 P.2d 276 (Okla. 1943) ; Mack oilCo v. Laurence, 389 P.2d 955 (Olka. 1964); H. Willlams andC. Meyers, 0// and GI$ Law $219.6 (l 975).
~~An]~)<]h~ador C)II c o , v, Robertjon, 3 8 4 S.W 2 d 7 5 2
(Tex. Civ. App. 1964).
Y~JRob/nson V. Robbin \ Pe(roleum Corp , 501 S. W. 2d
865 (Tex. 1973).
‘[l Walker, “Problems Incident to the Acquisition, Use andDisposal of Repressuring Substances Used in SecondaryRec every Operations, ” 6 t h R o c k y Mt. M/n. L. /nsr 2 7 3(1 961).
“:483 S.W.2d 808 (Tex. 1972).
‘~E.g., HoI( V . SoLIthIve$/ ArrtIoc h S a n d UrrIt, FifthEnlarged, 292 P,2d 998 (Okla. 1955).
w483 S,W.2d 808 (Tex. 1972).
9:A subsequent Texas case held the implied right to usewater from the surface of the leasehold did not extend touse of the water for operations otf the leased premisesRobinson v. RobbIns P((rolcum Corp., 501 S.W,2d 865 (Tex.1 973).
“fiThe discu~sion which follows IS drawn primarily fromthe following sources: R. Clark \f’ater and \Va(er RiglI(spaSSIrTI (1 967); Losee, “Le~al Problems of a Water Supply forthe Oil and Gas Industry, ” 20 th Oil & Gas Inst. 55 (1969);Trelease, “The Use of Fresh Water for Secondary Re[ everyof 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 Acqulsl-tlon, Use and D!sposal of Repressuring Substances Used inSecondary 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 011and Gas Industry,: 20th 0// & Gas Inst. 55, 81 (1 969).
Glossary
Glossary l
Accelerated depreciation—Any of a number offorms of depreciation which allow the write-off of capital investments more rapidly thanstraight I ine depreciat ion. St ra ight I inedepreciation consists of depreciating an equalfraction each year over the useful life of theasset. With accelerated depreciation, largerfractions are depreciated in earlier years andsmaller fractions in later years.
API gravity—The standard American PetroleumInstitute (API) method for specifying the den-sity of oil:
141.5degrees API = –131 .5
specific gravity
Barrel—A liquid volume measure equal to 42U.S. gallons.
Brine—Water saturated with or containing a highconcentration of sodium chloride and othersalts.
Btu—British thermal unit; the amount of heatneeded to raise the temperature of 1 pound ofwater 10 F at or near 39.2° F; a measure of
energy.
Capitalized cost —A cost which is capitalized isnot deducted from taxable income in the yearit is incurred; rather it is depreciated over theuseful life of the investment.
Cash bonus leasing —The leasing system cur-rently being used for most offshore lease salesby the U.S. Government. A fixed roya l ty ,
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 0.01poise. A poise equals 1 dynesecond per squarecentimeter. The viscosity of water at 20° C is1.005 centipoise.
Connate water—Water that was laid down andentrapped with sedimentary deposits, as dis-tinguished from migratory waters that haveflowed into deposits after they were laiddown.
C o n s t a n t 1 9 7 6 do l la r s—Dol la r s w i th thepurchasing power of the U.S. dollar in the year1976. This term is used to provide a measureof comparability to project costs, revenues,rates of return, and capital requirements whichmight otherwise be distorted by varying esti-mates of the unpredictable factor of inflationor deflation in future years.
Core—A sample of material taken from a well bymeans of a hollow drilling bit. Cores areanalyzed to determine their water and oiI con-tent, porosity, permeability, etc.
Darcy—A unit of permeability. A porous mediumhas a permeability of 1 darcy when a pressureof 1 atm on a sample 1 cm long and 1 sq cm incross section will force a liquid of 1-cpviscosity through the sample at the rate of 1 cucm/sec.
Depreciation —A deduction from the taxable in-come base each year to account for wear andtear and obsolescence of capital equipment.
Depreciat ion-double decl ining balance—Aform of accelerated depreciation in whichtwice the normal straight line depreciation rateis applied each year to the remaining deprecia-tion base.
Depreciation-unit of production—Depreciationbased upon the fraction of total estimatedreserves that are produced each year.
235
236 . Glossary
Discounted cash flow rate of return—A particu-lar measurement of investment profitabilitythat accounts for costs, revenues and the timevalue of money.
Emulsion—A suspension of one finely dividedliquid phase in another.
Enhanced oil recovery (EOR)—That recovery ofoil from a petroleum reservoir resulting fromapplication of an enhanced recovery process.
Enhanced recovery process—A known tech-nique for recovering additional oil from apetroleum reservoir beyond that economicallyrecoverable by conventional primary and sec-ondary recovery methods. Three such processes are discussed in this assessment:
Thermal recovery process: Injection of steaminto a petroleum reservoir or propagation ofa combustion zone through a reservoir byair injection into the reservoir.
Miscible flooding process: Injection of amaterial into a petroleum reservoir that ismiscible, or nearly so, with the oil in thereservoir. In this assessment, carbon dioxide(CO2) is the only such material considered.
Chernical flooding process: Injection of waterwith added chemicals into a petroleumreservoir. In this assessment, two chemicaltypes are considered:a. surfactantsb. polymers
EOR---Enhanced oil recovery.
Evolution of technology-Presumed future im-provements in EOR techniques as a result ofresearch and experience.
Expensed cost—A cost item which is expensedis written-off (deducted from the taxable in-come base) in the year the cost is incurred.
Fireflooding—A synonym for in situ combustion.
Forward combustion —Air is injected and igni-tion is obtained at the well bore in an injectionwell. Continued injection of air drives thecombustion front toward producing wells.
Fracture—A general term to include any kind ofdiscontinuity in a body of rock if produced bymechanical 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 itsu
mobility by decreasing its viscosity. Heat is ap-plied by igniting the oil sand or tar sand andkeeping the combustion zone active by the in-jection of air.
Interracial tension —The contractile force of aninterface between two phases.
Investment tax credit—A credit on taxes paya-ble for capital investment. The credit is a frac-tion of the cost of the capital investment (cur-rently .1) and is received for the year theinvestment is placed in service.
Known oil fields-Oil fields in the United Statesthat have produced petroleum before 1976.
Lease—A part of a field belonging to one owneror owner group; an owner commonly “leases”the (mineral) rights to an operator who pro-duces oil, and normally gas, and pays for the“lease” with part of the production (royalty).
On occasion, the owner (Ieasor) and theoperator (lessee) is the same person.
Micelle (and micellar fluid)—A molecular ag-gregate, generally of molecules that have anoil-seeking end and a water-seeking end. Anoriented layer of such molecules on the sur-face of a colloidal droplet stabilizes oil-in-water or water-in-oil emulsions, making oiland water quasi-miscible.
Miscible—Refers to liquids and their ability tomix. Liquids that are not miscible separate intolayers according to their specific gravity.
Miscible agents—A third substance that pro-motes miscibility between water and oil, suchas natural gas, hydrocarbon gas enriched withLPG, or compounds that are miscible with oiland with water.
Miscible displacement —When oil is contactedwith a fluid with which it is miscible, they dis-solve each into the other and form a singlephase. There is no interface between the fluidsand hence there are no capillary forces active.
Miscible displacement recovery—The use ofvarious solvents to increase the flow of crudeoil through reservoir rock.
Mobility—A measure of the ease with which afluid moves through reservoir rock; the ratio ofrock permeability to fluid viscosity.
Monte Carlo simulation-A method for estimat-ing the extent to which uncertainty about theinput 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 distr ibu-
tions of the likely values of each input variable.
This process is repeated many times (several
hundred or more), giving a large sample of out-put values based on a wide range of combina-tions of values of input variables. These calcu-lated results are then combined to give anestimate of the mean value and range ofuncertainty for each output variable.
Oil recovery—A procedure whereby petroleumis removed from a petroleum reservoir throughwells. Three kinds of oil recovery are referredto in this assessment:
Primary recovery: Oil recovery utilizing onlynaturally occurring forces or mechanical orphysical pumping methods.
Secondary recovery: Oil recovery resultingfrom injection of water or natural gas into apetroleum reservoir.
Enhanced recovery: See separate entry.
Oil saturation—The extent to which the voids inrock contain oil, usually expressed in percentrelated to total void.
Original oil-in-place (OOIP)-Petroleum exist-ing in a reservoir before oil recovery.
Permeability—The permeability (or pervious-ness) of rock is its capacity for transmitting afluid. Degree of permeability depends uponthe size and shape of the pores, the size andshape of the interconnections, and the extentof the latter. The unit of permeability is thedarcy.
Petroleum —A natural ly occurr ing mater ia l(gaseous, liquid, or solid) composed mainly ofchemical 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
proc-
Polymer—A type of organic chemical, charac-terized by large molecules, that is added towater for polymer flooding.
Polysaccharide—A type of polymer.
Porosity—The fraction of the total volume of amaterial that is made up of empty space, orpore space. It is expressed in terms of thevolume of pore space per unit volume of thematerial. Porosity is a measure of the materialability to absorb liquids, since it measures theempty space available to hold liquids.
Present value—The current worth of a flow of in-come. Income in future periods is discountedby the interest between the current period andeach future period. Present value is the sum ofthe discounted values for all future periods asshown below:
T
where Vt is the income (or loss) in year t and ris the rate of interest.
Price elasticity of supply—The responsivenessof quantity supplied to changes in price.Specifically, elasticity is the percentage changein quantity divided by the percentage changein price.
Primary recovery—See oil recovery.
Rate of return—The rate of interest yielded b yinvestments in a project. Specifically, the rateof return is the rate of interest which equatesthe stream of revenues and costs to zero asshown below:
To =
where Vt is after tax value in year t and i is therate of interest which equates the time streamof values to zero. Vt may be positive or nega-tive-usually it will be negative in early yearsduring investment and positive during lateryears.
238 . Glossary
Reserves—The amount of a mineral expected tobe recovered by present day methods andunder present economic conditions.
Reservoir—A discrete section of porous rockcontaining an accumulation or oil or gas, eitherseparately or as a mixture.
Reservoir fluids—Fluids contained within thereservoir under conditions of reservoir pressureand temperatures; because of this fact theircharacteristics are different from the charac-teristics of the same fluids existing under nor-mal atmospheric conditions.
Residual oil—The amount of liquid petroleumremaining in the formation at the end of aspecified production process.
Resource base—Total petroleum in place whichmay be subjected to attempted oil recovery,
Resources—The estimated total quantity of amineral in the ground.
Reverse combustion—in this process, the forma-tion is ignited at the producing well and thecombustion zone moves countercurrent to theinjected air and reservoir fluid stream. Because
the oil flows into a zone already heated, thereis no tendency for it to congeal and decreasepermeability.
Royalty—A share of production from a leasereserved for the mineral rights owner.
Saturation—Ratio of volume of pore fluid to porevolume, expressed as percent and usually ap-plied to water, oil or gas separately. Sum of thesaturations of each fluid in a pore volume is100 percent.
Screen—A list of conditions that need to be metif a process is to qualify for oil recovery.
Screening process—The steps of determining ifa process passes or qualifies under a screen.
Secondary recovery—see oil recovery.
Steamflooding —Steam displacement (or steamdrive) follows, the same basic principle as thewaterflood. Steam under pressure is fed intospecial injection wells, both to heat the oil inplace and to drive it to producing wells.
Steam soaking—Steam is used as a stimulationmedium to heat the area of the reservoir
around the well bore (also called steamstimulation, huff-and-puff, or cyclic steam in-jection). Steam under pressure is injecteddown the casing or tubing of a producing well.A typical steam injection lasts for 5 to 8 days.Following the injection period, the well isreturned to production.
Sulfonates—Surfactants formed by the reactionof sulfuric acid (or sulfur trioxide) with organicmolecules. The sulfonate group in its acid formis S03H, and the sulfur atom is linked directlyto a carbon. In use, sulfonates are neutralizedwith bases and used in the ionic form.
Surface tension—The tension forces existing inthe extreme surface film of an exposed liquidsurface due to unbalanced cohesive forceswithin the body of the liquid.
Surfactant—A material which tends to concen-trate at an interface, used to control the degreeof emulsification, aggregation, dispersion,interracial tension, wetting, etc.
Sweep efficiency—The ratio of the volume ofrock contacted by the displacing fluid to thetotal volume of rock subject to invasion by thedisplacing fluid.
Tertiary-Refers to a recovery process that is im-plemented following secondary recovery; athird recovery phase following primary recov-ery and secondary recovery. All tertiary recov-ery is enhanced recovery, but the reverse doesnot always hold.
Thermal recovery —See enhanced recovery proc-ess.
Ultimate recovery —The quantity of oil or gasthat a well, pool, field, or property will pro-duce. It is the total obtained or to be obtainedfrom the beginning to final abandonment.
Viscosity—The internal resistance offered by afluid to flow.
Waterflooding—A secondary-recovery opera-t ion in which water i s in jected into apetroleum reservoir to create a water drive toincrease production.
Well logging—The detailed record of the rockspassed through in drilling.
U. S. COVER NMENT PRINTING OFFICE : 1’378 O - 96-5!j 4
