EP 600/7
79-06 Oe
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2, Environmental Protection Technology
3 Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9 Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects, assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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Energy From the West
Energy Resource Development
Systems Report
Volume V: Oil and Natural Gas
By
Science and Public Policy Program
University of Oklahoma
IrvinL. White Edward J. Malecki
Michael A. Chartock Edward B. Rappaport
R. Leon Leonard Robert W. Rycroft
Steven C. Ballard Rodney K. Freed
Martha Gilliland Gary D. Miller
Timothy A. Hall
Managers,
Energy Resource Development Systems
R. Leon Leonard, Science and Public Policy
University of Oklahoma
Clinton E. Burklin, The Radian Corporation
C. Patrick Bartosh Gary D. Jones
Clinton E. Burklin William J. Moltz
William R. Hearn Patrick J. Murin
Prepared for:
Office of Research and Development
U. S. Environmental Protection Agency
Washington, D.C. 10460
Project Officer:
Steven E. Plotkin
Office of Energy, Minerals and Industry
Contract Number 68-01-1916
.1
Vfcsf
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DISCLAIMER
This report has been reviewed by the Office of Energy,
Minerals and Industry, U.S. Environmental Protection Agency,
and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the
U.S. Environmental Protection Agency, nor does mention of trade
names or commercial products constitute endorsement or recommen-
dation for use.
11
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FORWARD
The production of electricity and fossil fuels inevitably
impacts Man and his environment. The nature of these impacts
must be thoroughly understood if balanced judgements concerning
future energy development in the United States are to be made.
The Office of Energy, Minerals and Industry (OEMI), in its role
as coordinator of the Federal Energy/Environment Research and
Development Program, is responsible for producing the informa-
tion on health and ecological effects - and methods for miti-
gating the adverse effects - that is critical to developing the
Nation's environmental and energy policy. OEMI's Integrated
Assessment Program combines the results of research projects
within the Energy/Environment Program with research on the
socioeconomic and political/institutional aspects of energy
development, and conducts policy - oriented studies to identify
the tradeoffs among alternative energy technologies, development
patterns, and impact mitigation measures.
The Integrated Assessment Program has supported several
"technology assessments" in fulfilling its mission. Assess-
ments have been supported which explore the impact of future
energy development on both a nationwide and a regional scale.
Current assessments include national assessments of future
development of the electric utility industry and of advanced
coal technologies (such as fluidized bed combustion). Also,
the Program is conducting assessments concerned with multiple-
resource development in two "energy resource areas":
o Western coal states
o Lower Ohio River Basin
This report, which describes the technologies likely to be
used for developing six energy resources in eight western
states, is one of three major reports produced by the "Tech-
nology Assessment of Western Energy Resource Development"
study. (The other two reports are an impact analysis report
and a policy analysis report.) The report is divided into six
volumes. The first volume describes the study, the organization
of this report and briefly outlines laws and regulations which
affect the development of more than one of the six resources
considered in the study. The remaining five volumes are resource
specific and describe the resource base, the technological
activities such as exploration, extraction and conversion for
developing the resource, and resource specific laws and regula-
iii
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tions. This report is both a compendium of information and a
planning handbook. The descriptions of the various energy
development technologies and the extensive compilations of
technical baseline information are written to be easily under-
stood by laypersons. Both professional planners and interested
citizens should find it quite easy to use the information
presented in this report to make general but useful comparisons
of energy technologies and energy development alternatives,
especially when this report is used in conjunction with the
impact and policy analysis reports mentioned above.
Your review and comments on these reports are welcome.
Such comments will help us to improve the usefulness of the
products produced by our Integrated Assessment Program.
Steven R. Reznek
Acting Deputy Assistant Administrator
for Energy, Minerals and Industry
iv
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PREFACE
This Energy Resource Development System (ERDS) report has
been prepared as part of "A Technology Assessment of Western
Energy Resource Development" being conducted by an interdisciplin-
ary research team from the Science and Public Policy Program
(S&PP) of the University of Oklahoma for the Office of Energy/
Minerals and Industry (OEMI), Office of Research and Development,
U.S. Environmental Protection Agency (EPA). This study is one of
several conducted under the Integrated Assessment Program estab-
lished by OEMI in 1975. Recommended by an interagency task
force, the purpose of the Program is to identify economically,
environmentally, and socially acceptable energy development
alternatives. The overall purposes of this particular study were
to identify and analyze a broad range of consequences of energy
resource development in the western U.S. and to evaluate and
compare alternative courses of action for dealing with the pro-
blems and issues either raised or likely to be raised by develop-
ment of these resources.
The Project Director was Irvin L.(Jack) White, Assistant
Director of S&PP and Professor of Political Science at the Univers-
ity of Oklahoma. White is now Special Assistant to Dr. Stephen
J. Gage, EPA's Assistant Administrator for Research and Develop-
ment. R. Leon Leonard, now a senior scientist with Radian Corpora-
tion in Austin, Texas, was a Co-Director of the research team,
Associate Professor of Aeronautical, Mechanical, and Nuclear
Engineering and a Research Fellow in S&PP at the University of
Oklahoma. Leonard was responsible for editing and managing the
production of this report. EPA Project Officer was Steven E.
Plotkin, Office of Energy, Minerals and Industry, Office of
Research and Development. Plotkin is now with the Office of
Technology Assessment. Other S&PP team members are: Michael A.
Chartock, Assistant Professor of Zoology and Research Fellow in
S&PP and the other Co-Director of the team; Steven C. Ballard,
Assistant Professor of Political Science and Research Fellow in
S&PP; Edward J. Malecki, Assistant Professor of Geography and
Research Fellow in S&PP; Edward B. Rappaport, Visiting Assistant
Professor of Economics and Research Fellow in S&PP; Frank J.
Calzonetti, Research Associate (Geography) in S&PP; Timothy A.
Hall, Research Associate (Political Science); Gary D. Miller,
Graduate Research Assistant (Civil Engineering and Environmental
Sciences); and Mark S. Eckert, Graduate Research Assistant (Geo-
graphy) .
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Chapters 3-7 were prepared by the Radian Corporation, Austin,
Texas, under subcontract to the University of Oklahoma. In each
of these chapters, Radian is primarily responsible for the des-
cription of the resource base and the technologies and S&PP is
primarily responsible for the description of laws and regulations.
The Program Manager at Radian was C. Patrick Bartosh. Clinton
E. Burklin was responsible for preparation of these five chapters.
Other contributors at Radian were: William R. Hearn, Gary D.
Jones, William J. Moltz, and Patrick J. Murin.
Additional assistance in the preparation of the ERDS report
was provided by Martha W. Gilliland, Executive Director, Energy
Policies Studies, Inc., El Paso, Texas; Rodney K. Freed, Attorney,
Shawnee, Oklahoma; and Robert W. Rycroft, Assistant Professor of
Political Science, University of Denver, Denver, Colorado.
VI
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ABSTRACT
This report describes the technologies likely to be used
for development of coal, oil shale, uranium, oil, natural gas,
and geothermal resources in eight western states (Arizona, Color-
ado, Montana, New Mexico, North Dakota, South Dakota, Utah,
and Wyoming). It is part of a three-year "Technology Assess-
ment of Western Energy Resource Development." The study examines
the development of these energy resources in the eight states
from the present to the year 2000. Other reports describe
the analytic structure and conduct of the study, the impacts
likely to result when these resources are developed, and analyze
policy problems and issues likely to result from that develop-
ment. The report is published in six volumes. Volume 1 describes
the study, the technological activities such as exploration,
extraction, and conversion for developing the resource, and
laws and regulations which affect the development of more
than one of the six resources considered in the study. The
remaining five volumes are resource specific: Volume 2, Coal;
Volume 3, Oil Shale; Volume 4, Uranium; Volume 5, Oil and Natural
Gas; and Volume 6, Geothermal. Each of these volumes provides
information on input materials and labor requirements, outputs,
residuals, energy requirements, economic costs, and resource
specific state and federal laws and regulations.
vii
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OVERALL TABLE OF CONTENTS
FOR
THE ENERGY RESOURCE DEVELOPMENT SYSTEMS REPORT
VOLUME I: INTRODUCTION AND GENERAL SOCIAL CONTROLS
Chapter 1 ENERGY RESOURCE DEVELOPMENT SYSTEMS
1.1 Introduction
1.2 Objectives of the ERDS Document....
1.3 Organization of the ERDS Document..
1.4 Limitations of the ERDS Document...
Chapter 2 GENERAL SOCIAL CONTROLS
PAGE
1
3
4
9
2.1 Introduction 11
2.2 Environmental Impact Statements.... 11
2. 3 Siting and Land Use 19
2. 4 Resource Exploration 29
2.5 Resource Acquisition 38
2.6 Resource Extraction 48
2.7 Occupational Safety and Health 59
2.8 Air Quality 65
2.9 Water Quality 95
2.10 Water Use 109
2.11 Solid Waste Disposal 135
2.12 Noise Pollution 139
2.13 Transportation and Distribution.... 145
2.14 Conclusions 153
VOLUME II: COAL
Chapter 3 THE COAL RESOURCE DEVELOPMENT SYSTEM
3.1 Introduction 1
3.2 Summary 3
3. 3 Coal Resources 12
3.4 A Regional Overview 27
3.5 Exploration 37
3.6 Mining 52
3.7 Beneficiation 139
3.8 Conversion 174
viii
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OVERALL TABLE OF CONTENTS
(continued)
VOLUME III: OIL SHALE PAGE
Chapter 4 THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM
4.1
4.2
4.3
4.4
4.5
4.6
Introduction
Summary
Resource Description...
Exploration
Mining and Preparation.
Processing,
1
4
13
25
37
142
4.7 Land Reclamation 297
VOLUME IV: URANIUM
Chapter 5
THE URANIUM RESOURCE SYSTEM
5.1 Introduction 1
5. 2 Uranium Resources 8
5.3 Exploration 31
5.4 Mining 64
5. 5 Uranium Milling 197
VOLUME V: OIL AND NATURAL GAS
Chapter 6 CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
6.1 Introduction 1
6.2 Resource Description of Western
Crude Oil 8
6. 3 Exploration 14
6.4 Crude Oil Production 57
6. 5 Transportation 144
Chapter 7 THE NATURAL GAS RESOURCE DEVELOPMENT SYSTEM
7.1 Introduction 146
7.2 Resource Description of the Western
Natural Gas 151
7. 3 Exploration 157
7.4 Natural Gas Production 165
7. 5 Transportation 201
ix
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OVERALL TABLE OF CONTENTS
(continued)
VOLUME VI: GEOTHERMAL PAGE
Chapter 8 THE GEOTHERMAL RESOURCE DEVELOPMENT SYSTEM
8.1 Introduction 1
8.2 Summary 6
8. 3 Resource Characteristics 13
8.4 Exploration 40
8.5 Extraction: Drilling 68
8.6 Extraction: Production 113
8.7 Uses of Geothermal Energy 146
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TABLE OF CONTENTS
VOLUME V
CHAPTER 6: THE CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
Page
6 .1 INTRODUCTION 1
6.1.1 Background 1
6.1.2 Summary 3
6.2 RESOURCE DESCRIPTION OF WESTERN CRUDE OIL 8
6.2.1 Reserves and Resources 8
6.2.2 Characteristics of the Resources 8
6.2.3 Quantity and Location of Western Oil
Reserves 9
6.2.4 Ownership of Resources 12
6. 3 EXPLORATION 14
6.3.1 Technologies 14
6.3.2 Input Requirements 20
6.3.3 Outputs 25
6.3.4 Social Controls 28
6.3.4.1 Oil Exploration Regulation 28
6.3.4.2 Leasing 40
6.4 CRUDE OIL PRODUCTION 57
6.4.1 Conventional Production Technologies 57
6.4.1.1 Input Requirement s 76
6.4.1.2 Outputs 90
6.4.2 Enhanced Oil Recovery 98
6.4.2.1 Steam Flooding 100
6.4.2.1.1 Technologies 100
6.4.2.1.2 Inputs 105
6.4.2.1.2 'Outputs 114
xi
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TABLE OF CONTENTS (Continued)
VOLUME V
Page
6.4.2.2 C02 Miscible Flooding 121
6.4.2.2.1 Technologies 121
6.4.2.2.2 Inputs 123
6.4.2.2.3 Outputs 129
6.4.3 Production Social Controls
6.4.3.1 Federal 135
6.4.3.1.1 Conservation on the
Public Domain 135
6.4.3.1.2 Air Pollution 137
6.4.3.1.3 Water Effluent
Controls 137
6.4.3.2 State 140
6.4.3.2.1 State Conservation
Laws and Regulations.. 140
6.4.3.2.2 Injection 142
6.4.3.2.3 Air Pollution 142
6.4.3.2.4 Plugging and Sealing.. 143
6 . 5 TRANSPORTATION ' 144
6.5.1 Social Controls 144
6.5.1.1 Federal 144
6.5.1.1.1 'Oil Spills 144
xii
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TABLE OF CONTENTS (Continued)
VOLUME V
7.1 INTRODUCTION 146
7.1.1 Background 146
7.1.2 Summary 148
7.2 RESOURCE DESCRIPTION OF WESTERN NATURAL GAS 151
7. 2.1 Characteristics of the Resource 151
7.2.2 Quantity and Location of the Resources 152
7.2.3 Ownership of Resources 155
7.3 EXPLORATION
7.3.1 Technologies 157
7.3.2 Input Requirements 157
7.3.2.1 Manpower Requirements 157
7.3.2.2 Materials and Equipment 158
7.3.2.3 Economics 158
7.3.2.4 Water Requirements 158
7.3.2.5 Land Requirements 160
7.3.2.6 Ancillary Energy 160
7.3.3 Outputs 161
7.3.3.1 Air Emissions 161
7.3.3.2 Water Effluents 161
7.3.3.3 Solid Wastes 163
7.3.3.4 Noise Pollution 163
7.3.3.5 Occupational Health and-Safety 163
7.3.3.6 Odor 164
7.3.4 Social Controls 164
7.3.4.1 Exploration Permits 164
7.3.4.2 Leasing 164
7 .4 NATURAL GAS PRODUCTION 165
7.4.1 Technologies 165
7.4.1.1 Development Drilling 165
xiii
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TABLE OF CONTENTS (Continued)
VOLUME V
Page
7.4.1.2 Completion 165
7.4.1.3 Natural Gas Processing 166
7.4.2 Input Requirements 181
7.4.2.1 Manpower Requirements 181
7.4.2.2 Materials and Equipment 184
7.4.2.3 Economics 184
7.4.2.4 Water Requirements 184
7.4.2.5 Land Requirements 186
7.4.2.6 Ancillary Energy 186
7.4.3 Outputs 186
7.4.3.1 Air Emissions 187
7.4.3.2 Water Effluents 187
7.4.3.3 Solid Wastes 189
7.4.3.4 Noise Pollution 189
7.4.3.5 Occupational Health and Safety 189
7.4.3.6 Odor 189
7.4.4 Production Social Controls 190
7.4.4.1 Federal Laws and Regulations 190
7.4.4.2 State Laws and Regulations 193
7.5 TRANSPORTATION OF NATURAL GAS 201
7.5.1 Technologies 201
7.5.2 Social Controls 203
7.5.2.1 Federal Laws and Regulations 204
xiv
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LIST OF FIGURES
VOLUME V
CHAPTER 6: THE CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
Number Page
6-1 Locations of Major Crude Oil Deposits in the
Western States 10
6-2 Rotary Rig Hoisting System 15
6-3 Rotary Rig Fluid Circulation and Mud Treating
System 16
6-4 Casing Strings and Pipe Used in an Oil Well 21
6-5 Open-Hole Completion 59
6-6 Perforated Casing Completion 60
6-7 Water-Drive Reservoir 63
6-8 Oil Production Operation Options 66
6-9 Cutaway of Electrostatic Treater 68
6-10 Cutaway of Vertical Heater Treater 70
6-11 Oil-Gas Separators 71
6-12 Vapor Recovery System 73
6-13 Waterflood Secondary Recovery System 77
6-14 Crude Oil Production 80
6-15 Sites of Thermal Recovery Field Tests in Montana
and Wyoming 102
6-16 Schematic of Steam Flooding Operation 104
6-17 Oil Field Steam Generator 107
6-18 Cost/Standard Tank Barrel of Oil for Steam
Flooding - Basis : Price of Oil - S3/Bbl 110
6-19 Cost/Standard Tank Barrel of Oil for Steam
Flooding - Basis: Price of Oil - $10/Bbl Ill
6-20 Costs of Oil Recovered by C02 Miscible Flooding
(Exclusive of Purchase Price of COz) 127
XV
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LIST OF FIGURES (Continued)
VOLUME V
CHAPTER 7: THE NATURAL OIL RESOURCE DEVELOPMENT SYSTEM
Number Page
7-1 Selected Samples of Natural Gas 153
7-2 Three-Stage Wellhead Separation Unit 168
7-3 Natural Gas Processing Plant 171
7-4 Typical Amine Treating Unit 173
7-5 Glaus Sulfur Recovery Unit 175
7-6 Two Bed Solid Adsorbent Treater 177
7-7 Typical Glycol Dehydration Unit 178
xvi
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LIST OF TABLES
VOLUME V
CHAPTER 6: THE CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
Number Page
6-1 SUMMARY OF IMPACTS ASSOCIATED WITH THE EXPLORATION
FOR A 100,000 BARREL/DAY OIL FIELD 4
6-2 SUMMARY OF IMPACTS ASSOCIATED WITH THE DEVELOPMENT
AND OPERATION OF A 100,000 BARREL/DAY OIL FIELD... 5
6-3 SUMMARY OF IMPACTS ASSOCIATED WITH STEAM FLOODING. 6
6-4 SUMMARY OF IMPACTS ASSOCIATED WITH C02 FLOODING... 7
6-5 WESTERN OIL RESERVE ESTIMATES 11
6-6 AVERAGE ROTARY-RIG ACTIVITY IN THE WESTERN STATES. 13
6-7 MATERIALS AND EQUIPMENT REQUIRED FOR A 100,000
BPD OILFIELD 23
6-8 AIR EMISSIONS FROM DRILLING RIGS 26
6-9 SUMMARY OF STATE LAND EXPLORATION PERMITS 31
6-10 ARIZONA OIL EXPLORATION PERMIT 32
6-11 COLORADO OIL EXPLORATION PERMIT 33
6-12 MONTANA OIL EXPLORATION PERMIT 34
6-13 NEW MEXICO OIL EXPLORATION PERMIT 35
6-14 NORTH DAKOTA OIL EXPLORATION PERMIT 36
6-15 SOUTH DAKOTA OIL EXPLORATION PERMIT 37
6-16 UTAH OIL EXPLORATION PERMIT 38
6-17 WYOMING OIL EXPLORATION PERMIT 39
6-18 SUMMARY OF TERMS FOR OIL LEASES ON STATE LANDS..... 47
6-19 ARIZONA OIL LEASE FEATURES (UNKNOWN LANDS) 48
6-20 ARIZONA OIL LEASE FEATURES (KNOWN LANDS) 49
6-21 COLORADO OIL LEASE FEATURES 50
6-22 MONTANA OIL LEASE FEATURES 51
6-23 NEW MEXICO OIL LEASE FEATURES 52
6-24 NORTH DAKOTA OIL LEASE FEATURES 53
6-25 SOUTH DAKOTA OIL LEASE FEATURES 54
6-26 UTAH OIL LEASE FEATURES 55
6-27 WYOMING OIL LEASE FEATURES 56
6-28 CLASSIFICATION OF PRIME MOVERS 64
6-29 SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS) REQUIRED
FOR CONSTRUCTION OF ONSHORE OIL PRODUCTION 81
xvii
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LIST OF TABLES (Continued)
VOLUME V
Number Page
6-30 SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED FOR OPERATION AND MAINTENANCE OF
ONSHORE OIL PRODUCTION 83
6-31 SCHEDULE OF SELECTED MAJOR MATERIALS AND EQUIPMENT
REQUIRED FOR CONSTRUCTION OF ONSHORE OIL PRODUC-
TION 84
6-32 SCHEDULE OF CAPITAL RESOURCES (MILLION DOLLARS,
THIRD QUARTER 1974) REQUIRED FOR CONSTRUCTION OF
ONSHORE OIL PRODUCTION 85
6-33 SCHEDULE OF MATERIALS AND EQUIPMENT RESOURCES
(MILLION DOLLARS, THIRD QUARTER 1974) REQUIRED
FOR OPERATION AND MAINTENANCE OF ONSHORE OIL
PRODUCTION 87
6-34 WATER REQUIREMENTS FOR SECONDARY RECOVERY 87
6-35 HEATER TREATER ENERGY REQUIREMENTS 89
6-36 CRUDE OIL ANALYSIS - RANGELY FIELD, RIO BLANCO
COUNTY, COLORADO 91
6-37 AIR EMISSIONS - 100,000 BPD PRIMARY PRODUCTION... 92
6-38 AIR EMISSION FACTORS FOR THE COMBUSTION OF
NATURAL GAS AND FUEL OIL 93
6-39 MISCELLANEOUS OIL PRODUCTION EMISSION FACTORS ... 95
6-40 WATERFLOOD OPERATION CONTRIBUTION TO TOTAL
EMISSIONS 95
6-41 WATER POLLUTANTS FROM OIL EXTRACTION 96
6-42 COST OF OIL RECOVERED BY STEAM FLOODING 112
6-43 AIR EMISSIONS FROM STEAM GENERATORS 116
6-44 TRACE METAL EMISSIONS FROM STEAM FLOODING 117
6-45 ESTIMATED FUGITIVE EMISSIONS FROM STEAM
FLOODING 118
6-46 OCCUPATIONAL HEALTH AND SAFETY DATA FOR OIL
PRODUCTION OPERATIONS 120
6-47 COSTS ASSOCIATED WITH C02 FLOODING 126
6-48 AIR EMISSIONS OF MAJOR POLLUTANTS FOR C02 FLOOD-
ING OPERATIONS (ASSUMES 107, OF PRODUCED OIL
IS BURNED 131
6-49 TRACE METAL EMISSIONS FOR C02 FLOODING OPERATIONS
(ASSUMES 10% OF PRODUCED OIL IS BURNED) 132
xviii
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LIST OF TABLES (Continued)
VOLUME V
Number Page
6-50 FUGITIVE EMISSION FACTORS FOR CO2 FLOODING
OPERATIONS 133
6-51 SUMMARY OF OIL AND GAS EXTRACTION EFFLUENT
GUIDELINES 139
CHAPTER 7: THE NATURAL OIL RESOURCE DEVELOPMENT SYSTEM
Number Page
7-1 SUMMARY OF IMPACTS ASSOCIATED WITH EXPLORATION
FOR A 250,000 CUBIC FEET/DAY GAS FIELD 149
7-2 SUMMARY OF IMPACTS ASSOCIATED WITH THE
PRODUCTION FOR A 250,000 CUBIC FOOT/DAY NATURAL
GAS FIELD 150
7-3 WESTERN NATURAL GAS RESERVE ESTIMATES 154
7-4 MARKETED PRODUCTION OF NATURAL GAS 156
7-5 MATERIALS AND EQUIPMENT REQUIRED FOR A
250 MM scfd NATURAL GAS FIELD 159
7-6 AIR EMISSION FROM DRILLING RIGS 162
7-7 AVAILABLE GAS TREATING PROCESSES 172
7-8 SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED FOR CONSTRUCTION OF ONSHORE GAS
PRODUCTION FACILITIES TO PRODUCE 250 MM scfd
NATURAL GAS 182
7-9 MANPOWER RESOURCES (MAN-YEARS) REQUIRED FOR
OPERATION AND MAINTENANCE OF A 250 MM scfd
ONSHORE GAS PRODUCTION FACILITY 183
7-10 SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF ONSHORE GAS PRODUCTION
REQUIRED TO SUPPLY 250 MM scfd OF PIPELINE
QUALITY GAS ....'. 185
7-11 AIR EMISSIONS FROM 250 MM scfd PRODUCTION/
PROCESSING FACILITY (LB/DAY) 188
7-12 STATE REGULATION OF NATURAL GAS FLARING 195
7-13 REQUIRED STACK HEIGHT FOR GAS PROCESSING
PLANTS IN NEW MEXICO 199
7-14 OIL AND GAS STATUTORY DUTIES 202
xix
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CONVERSION FACTORS
ENGLISH UNITS/METRIC UNITS
To Convert From
acre-ft/yr
acre-ft/yr
gpm
acre
Btu
Btu
tons
Ib
ft
barrels
bbls/day
metric tons
To
m3 /yr
gpm
liters/min
m2
Cal (gin)
joules
kg
kg
m
gal
gpm
kg
Multiply By
1233.5
0.6200
3.785
4046.9
252.0
1054.4
907.18
0.4536
0.3048
42.0
0.02917
1000
xx
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ACKNOWLEDGEMENTS
Gary D. Jones and William R. Hearn of the Radian Corporation
had primary responsibility for preparation of this volume of the
Energy Resource Development Systems (ERDS) Report. The social
controls sections were prepared by Rodney K. Freed of the Science
and Public Policy Program at the University of Oklahoma. Mr. Freed
is now an attorney in Shawnee, Oklahoma.
The research reported here could not have been completed with-
out the assistance of a dedicated administrative support staff.
At Radian Corporation, Mary Harris was responsible for typing of
this volume, and at the University of Oklahoma, Janice Whinery,
Assistant to the Director, coordinated assembly of the volumes of
the ERDS Report.
Nancy Ballard, graphics arts consultant, designed the title
page.
Steven E. Plotkin, EPA Project Officer, has provided contin-
uing support and assistance in the preparation of this report.
The individuals listed below participated in the review of
this volume of the ERDS Report and provided information for its
preparation. Although these critiques were extremely helpful,
none of these individuals is responsible for the content of this
volume. This volume is the sole responsibility of the Science
and Public Policy interdisciplinary research team and the Radian
Corporation.
Mr. Owen Anderson
Chief Counsel
North Dakota State Land
Department
Bismarck, North Dakota
Dr. John Hoover
Energy and Environmental
Systems
Argonne National Laboratory
Chicago, Illinois
Mr. Lionel S. Johns
Program Manager
Office of Technology Assessment
U.S. Congress
Washington, D.C.
Mr. Leo McReynolds
Research and Development
Department
Phillips Petroleum Company
Bartlesville, Oklahoma
xxi
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Mr. Terry Thoem
Office of Energy Activities
Environmental Protection Agency
Region VIII
Denver, Colorado
xxii
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CHAPTER 6
THE CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
6.1 INTRODUCTION
6.1.1 Background
This document is one of several reports issued in support
of a "Technology Assessment of Western Energy Resource Develop-
ment," a project jointly conducted by the Science and Public
Policy Program of the University of Oklahoma and Radian
Corporation of Austin, Texas. The project is funded by the
Office of Energy, Minerals, and Industry, Office of Research
and Development, Environmental Protection Agency under Contract
68-01-1916. This document is issued as Chapter 6 of the "Energy
Resource Development System" (ERDS) report. For each of six
energy resources, the ERDS report describes the energy resource
base, the technologies used to develop the resources, the inputs
and outputs for each development technology, and the laws and
regulations applying to the deployment and operation of each
technology. Resources described in the ERDS report are: coal,
oil shale, uranium, crude oil, natural gas, and geothermal
energy.
Since its discovery'in 1859, oil has been a significant
factor in our national growth and development. Although it did
not supplant coal as the primary energy source until the late
1940's, oil was important well before that, in large part because
of its key role in the development and mass production of the
automobile - and the fundamental changes in life style which
followed.
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In more recent times oil has become the base for many of
our necessities, including medicinal drugs, clothing, fibers,
plastic and rubber products, etc.; and it is a major substitute
for other sources of energy. This end use flexibility makes
oil a particularly valuable resource in all industrialized
countries.
The oil industry has grown from a -uniquely American business
into a worldwide operation. Six of the 10 largest U.S. corpora-
tions are oil companies, and technologies developed to produce
U.S. oil resources have been the basis for all free world oil
development.
The U.S. was a net oil exporter until 1948, when U.S.
consumption exceeded supply for the first time. Although the
change from exporter to importer created a number of economic
and political problems, dependence on oil imports will undoubtedly
continue for the foreseeable future.
This chapter describes the technologies, inputs, outputs,
laws, and regulations associated with the development of crude
oil resources. There are five main sections to the chapter and
they are briefly described below.
Section 6.2 describes the characteristics of the crude oil
resource in the eight state region, discusses the quantity and
location of the resources, and treats the ownership of the land
and resource.
Sections 6.3 and 6.4 describe the development of crude oil
from exploration to treatment of finished product and enhanced
recovery techniques. For each activity the interactions of the
resource itself with the attempt to produce the resource for
-2-
-------
man's use are described. When available, the inputs and outputs
for each activity are presented. Inputs discussed include:
manpower, materials and equipment, economics, water, land, and
ancillary energy. The outputs are air emissions, water effluents,
solid wastes, noise pollution, occupational safety and health,
and odors. Laws and regulations affecting the activities are
described.
Section 6.3 discusses the technologies, inputs and outputs,
and social controls associated with crude oil exploration.
Section 6.4 discusses the same items for conventional crude oil
production and for enhanced oil recovery. Section 6.5 discusses
the social controls for crude oil transportation.
It is important that the reader have a thorough understand-
ing of this entire chapter before applying any of the contained
information. Typical technologies were chosen for the basis
of the data, and it is important to note that the parameters
can vary greatly depending upon the specific basis chosen. The
reader is advised to note any changes in bases between the
different technologies in the chapter.
6.1.2 Summary
Tables 6-1 through 6-4 summarize the input requirements
and outputs associated with development of the crude oil
resources.
-3-
-------
TABLE 6-1. SUMMARY OF IMPACTS ASSOCIATED WITH THE EXPLORATION
FOR A 100,000 BARREL/DAY OIL FIELD
Inputs
Manpower
Materials and Equipment
Casing and tubing
Rig-years
Cement
Economics1
Water (over life of
exploration)
Land
Ancillary Energy (total)
Outputs
Air Emissions
Particulates
S02
CO
Hydrocarbons
Nitrogen Oxides
Aldehydes
Organic Acids
C02
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
Deaths
Injuries
Lost Time
6,250 Tons
18
18,000 Tons
$125,000,000
5.0 x 106 Barrels
150 Acres
3.0 x 1012 Btu
80 Ib/day
168 Ib/day
1434 Ib/day
233 Ib/day
2329 Ib/day
19 Ib/day
19 Ib/day
130,625 Ib/day
Negligible
Negligible
5669 m. tons
18
16,327 m. tons
$125,000,000
7.95 x 10s m3
6.0 x 10s m2
3.1 x 101S J.
36 kg/day
76 kg/day
,650 kg/day
105 kg/day
1056 kg/day
8.6 kg/day
8.6 kg/day
59,240 kg/day
0.45/yr
43/yr
7154 man-days/yr
!1974 Dollars
-4-
-------
TABLE 6-2.
SUMMARY OF IMPACTS ASSOCIATED WITH THE DEVELOPMENT
AND OPERATION OF A 100,000 BARREL/DAY OIL FIELD
Inputs
Manpower
Construction
Operation and Maintenance
Materials and Equipment
Pipe and Tubing
Pumps and Drives
Drill Rigs
Ready-mix Concrete
Economics
Water
Waterflooding
Land
Ancillary Energy
Conventional
Waterflooding
Outputs
Air Emissions
Particulates
SOX
CO
Total Organics
NOX
Water Effluents
Solid Wastes
Noise Pollution
19,544 Man-years
6,143 Man-years
72,000 Tons
8,000 Items
12 Items
20,000 Tons
$2,040 million
2500-4100
acre-ft/yr
5.0 x 108 Btu/day
3.5 x 108 Btu/day
3.1 ton/yr
190 ton/yr
11.4 ton/yr
37.7 ton/yr
154 ton/yr
Undetermined
None
19,544 Man-years
6,143 Man-years
32,652 m. tons
8000 Items
12 Items
9070 m. tons
$2,040 million
3.1-5.0 x 10s
mVyr
5.2 x 1011 J./day
3.7 x 1011 J./day
2.8 m. tons/yr
172 m. tons/yr
10.3 m. tons/yr
34.2 m. tons/yr
140 m. tons/yr
For heater treaters only (oil production is 5% brine)
-5-
-------
TABLE 6-3. SUMMARY OF IMPACTS ASSOCIATED WITH STEAM FLOODING
Inputs
Manpower
Materials and Equipment
Oil Field Boilers
Economics
Water
Land
Ancillary Energy
Outputs
Air Emissions
Particulates
S02
S03
CO
Hydrocarbon
NOX
Water Effluents
2,000 Persons
250-650 Items
860-2850 Ib/day
24,000 Ib/day
300 Ib/day
500 Ib/day
260 Ib/day
740 Ib/day
2,000 Persons
250-650 Items
390-1292 kg/day
10,844 kg/day
136 kg/day
227 kg/day
118 kg/day
336 kg/day
-6-
-------
TABLE 6-4. SUMMARY OF IMPACTS ASSOCIATED WITH C02 FLOODING
Inputs
Manpower
Materials and Equipment
a
Economics
Water (life of field)
Land
Ancillary Energy
Outputs
Air Emissions
Particulates
S02
S03
CO
Hydrocarbon
NOX
Water Effluents
Solid Wastes
Noise
Occupational and Health Safety
Deaths
Injuries
Lost Time
$13.5 x 10 /yr
1.6-3.6 x 10s acre-ft
25-50 acres
3.8 x 109 Btu/hr
290 Ib/day
8100 Ib/day
110 Ib/day
170 Ib/day
84 Ib/day
2500 Ib/day
Negligible
$13.5 x 10s/yr
2.0-4.4 x 108 mVyr
1.0-2.0 x 105 m2
4.0 x 1012 J./hr
132 kg/day
3673 kg/day
50 kg/day
77 kg/day
38 kg/day
1134 kg/day
0.5
43.8
7300 man-hours
1976 dollars
-7-
-------
6.2 RESOURCE DESCRIPTION OF WESTERN CRUDE OIL
6.2.1 Reserves and Resources
The terms "reserves" and "resources" are often used in des-
criptions of the volume of petroleum deposits. In this chapter
resources are the petroleum deposits that are ultimately recover-
ables with present or advanced technology. By this definition,
resources include all the identified and yet-to-be discovered
deposits whether they are economically recoverable or not.
Reserves are economically recoverable resources that are identi-
fied on the basis of current geological evidence. "Proven
reserves" are those reserves that are measured and marketable
under current economic conditions.
6.2.2 Characteristics of the Resources
Crude oil is a naturally occurring oil consisting mostly of
hydrocarbons, although oxygen, nitrogen, and sulfur-containing
compounds are invariably present. It is usually found in sedi-
mentary rock deposited in both freshwater and saltwater environ-
ments. Crude oil contains a number of organic compounds that
are separated into various fuel and lubricating forms through
refining processes. The refined products include gasoline,
kerosene, distillate and residual fuel oils, lubricating oils,
light hydrocarbon liquids, and others. An average heat content
for crude oil is approximately 5.8 million Btu per barrel. The
refined liquid petroleum products are characterized by their
heat contents which range from 5.2 million Btu per bbl for gaso-
line to 6.3 million Btu per bbl for residual fuel oil.1
American Petroleum Institute. Petroleum Facts and Figures
Washington, D.C.: American Petroleum Institute, 1971, p~. 589.
-8-
-------
Crude oil is usually characterized by density. Most domes-
tic crude oils range from 22°API (0.922 specific gravity) to
42°API (0.816 S.G.) with the average gravity near 35°API
(0.850 S.G.).
The quality of a given crude may also be judged by its
sulfur content. Crudes with more than 1 percent sulfur are
usually considered sour. Domestic crudes vary greatly in sulfur
content (0.37. - 3.0% by weight).
6.2.3 Quantity and Location of Western Oil Reserves
According to recent estimates, proven reserves in the eight
western mountain states1 account for approximately seven percent
of the total U.S. reserves estimated to be about 34 billion
barrels.2'3'1* The ultimate recoverable production for these
states is 21 percent of the total U.S., suggesting that the moun-
tain states will probably play a larger role in supplying the
country's fuel needs in the years to come.
Within the eight state region, crudes are produced primarily
in a broad area stretching from the San Juan Basin in Northeast
New Mexico to the Big Horn Basin in Wyoming and Montana. Figure
6-1 gives the location of various basinal areas that contain
reservoirs. Table 6-5 shows reserve estimates of western crudes
broken down by states, along with the cumulative productions
Arizona, Colorado, Utah, New Mexico, Wyoming, Montana,
North Dakota, and South Dakota.
2U.S. Geological Survey. Geological Estimates of Undiscovered
Recoverable Oil and Gas Reserves in the United States,Circular
-725"! Washington, D.C. : U.S. Geological Survey, 1975.
3FEA Lists Higher U.S. Reserves Figures, Oil and Gas Journal
73(27) July 7, 1975, p. 32. '
"Gay, William F. Energy Statistics. A Supplement to the
Summary of National Transportation Statistics, Final Report. Cam-
bridge, Maryland:U.S.Department of Transportation, August 1975.
-9-
-------
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through 1972 and the ultimately producible quantities. The non-
producing states are not entered in the table.
The average rotary-rig activities in the past ten years are
listed by state in Table 6-6. The ratios given in the bottom
line of the table indicate that the trend of rotary-rig opera-
tion in the western states has been roughly the same as that in
the U.S. as a whole.
6.2.4 Ownership of Resources
Ownership of the western crude resources has not been iden-
tified at this time. Only federal ownership on a national level
is known: 4 percent of onshore reserves and 8 percent of off-
shore resources.1
1 Ford Foundation. Energy Policy Project. A Time to Choose
America's Energy Future. Cambridge, Massachusetts:Bellinger
Publishing Co., 1974.
-12-
-------
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-13-
-------
6.3 EXPLORATION
6.3.1 Technologies
Exploratory drilling for oil is done with a rotary drill
bit connected to the surface by a length of pipe called a drill
string. A series of sequential operations must be performed
before the actual drilling proceeds, the first of which is site
preparation. This involves clearing the land, digging pits to
serve as holding ponds for circulating fluid (mud) and brine,
and constructing the necessary access roads. Water must be
made available at the site by completing water wells or install-
ing water lines. The next step is bringing the drilling equip-
ment to the site and "rigging up." Rigging up involves placing
the drilling machinery in working position, then assembling and
connecting the units which make up the drilling rig.
The three basic parts of the drilling rig are the hoisting
system (Figure 6-2), the rotary system, and the fluid circula-
tion system (Figure 6-3) . The hoisting system is used to raise
and lower the drill string and to regulate the weight on the
drill bit by holding up the drill string. Hoisting systems at
a deep well are capable of raising and lowering long drill
strings which weigh up to 500,000 pounds.1 The capacity of
derricks supporting the hoist varies from 250,000 to 1,500,000
pounds.
The rotary system begins at the hook on the hoisting system
which is attached to the rotary system by a swivel. The swivel
1 Petroleum Extension Service, University of Texas. A Primer
of Oil Well Drilling, 3rd Edition. Austin, Texas: University
of Texas, 1970.
-14-
-------
FAST
LINE
CROWN
"BLOCK
DEAD LINE
WIRE LINE
(& LINES ARE STRUNG)
TRAVELING BLOCK
DRILLING HOOK
DEADLINE
WORKS
'DRUM BRAKE
STORAGE
REEL
Figure 6-2. Rotary Rig Hoisting System.
Source.-' Petroleum Extension Service, University of
Texas. A Primer of Oil Well Drilling, 3rd
Edition.Austin,Texas:University of Texas,
1970.
-15-
-------
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-------
sustains the weight of the drill string, affords a passageway
for entry of the circulation fluid into the drill string and
permits rotation of the drill string. The link between the
swivel and the drill pipe, the kelly, is a square or octagonal
shaft which fits through a square or octagonal hole in the rotary
table and is connected to the drill pipe on the lower end and to
the swivel on top. When the rotary table turns, it causes the
kelly to rotate, which in turn causes the drill pipe and bit to
rotate. The swivel, however, allows the hoist to remain sta-
tionary.
When the drill string needs lengthening, the drill string
is raised by the hoist until the kelly is out of the hole. The
kelly is then removed and the end of the drill pipe raised far
enough to allow insertion of a new piece of drill pipe onto the
top of the existing pipe. After the new pipe is inserted, the
kelly is replaced and the entire assembly is lowered into the
hole. To remove the entire drill string for bit changing, this
process is reversed and the drill pipe is removed one piece at
a t ime.
The fluid circulation system allows removal of the cuttings
made by the bit and provides hydrostatic pressure to prevent a
blowout. (A blowout is the unconstrained flow of liquids or
gases from the well caused by high pressures in the penetrated
reservoir.) The viscosity and density of the fluid must be
maintained at a level sufficient to insure protection from blow-
outs. The circulated fluid, usually referred to as drilling
mud, is a water-based slurry which contains a mixture of weight-
ing material, clays, chemicals, and oil. Maintaining the quality
and quantity of this drilling mud accounts for a major portion
of both equipment and drilling costs.1
Petroleum Extension Service, University of Texas. A Primer
of Oil Well Drilling, 3rd Edition. Austin, Texas: University
of Texas, 1970.
-17-
-------
As shown in Figure 6-3, the drilling mud enters the drill
pipe, flows out of the bit, entrains the cuttings, and rises in
the annular space between the drill pipe and the hole wall.
The cuttings are then removed from the mud and the mud is recir-
culated down through the drill pipe. The cuttings are periodi-
cally analyzed to determine the geological nature of the forma-
tions and to determine whether a zone capable of production has
been located.
In addition to the drilling mud, a number of other safe-
guards are used to minimize the likelihood of a blowout. These
include setting casing and installing blowout preventer (BOP)
valves. Before the deep drilling is begun, a relatively shallow
hole is made and casing is usually inserted. This short length
of casing, usually 10 to 20 feet in length, is referred to as
conductor pipe. It is cemented into the hole and the BOP valves
attached. A BOP valve will seal off the annular space abound
the drill pipe to prevent the drilling fluid from being pushed
from the hole. The valve can be closed by an automatic hydrau-
lic system or manually.
The direction in which the hole is proceeding must also be
monitored and controlled. As the drill string becomes very
long, it becomes somewhat flexible, but gravity pulls the bit
back in line if it begins to vary from a vertical attitude.
This is known as the pendulum effect. The movement is monitored
by a drift survey instrument positioned above the bit. If a
non-vertical hole is desired, directional drilling is employed.
This type of drilling requires special equipment for boring the
hole and performing the directional survey for monitoring the
course of the drilling.
-18-
-------
Once the hole is drilled to the desired depth, an analysis
of the production capabilities is required. If the well is
deemed to be capable of profitable production, it is developed
further. Developing activities are discussed in Section 6.4.
After the contractor has drilled the hole to final depth,
taken electric logs, and evaluated potentially productive
intervals, a decision will be made by the operating company
whether to set casing or to plug the well. These decisions are
sometimes difficult, for there may be considerable doubt that
a well may produce enough oil or gas to pay for the casing and
completion of operations. Completion costs can exceed $50,000
for even a moderate depth well.1
If the well is judged to be a dry hole, i.e., not capable
of producing oil or gas in commercial quantities, the well will
be plugged before abandonment. Cost for plugging may be only
a few thousand dollars; state regulatory authorities usually
indicate the manner of plugging a well.
If the operating company decides to set casing, pipe will
be hauled to the job, tested, and other preparations made to
run it into the well. Before the casing is run, the bit is
usually put back into the hole to check for possible bridging
and settling of cuttings to bottom.
The operating company may elect to install centralizers
and scratchers on the casing just prior to the running of
Petroleum Extension Service, University of Texas. A Primer
of Oil Well Drilling, 3rd Edition. Austin, Texas: University
of Texas, 1970.
-19-
-------
the casing. Their purpose is to obtain a good cement job, i.e.,
to better restrict fluid movement behind the casing between
formations, to support the casing, and prevent corrosion. A
centralizer secured around the casing prevents the pipe from
touching the hole wall so that the cement sheath around the
pipe will be uniform. Scratchers are moved during the cementing
operations to scratch the mud cake off the wall of the hole
so that the cement will make a better bond with the formation.
The movement of the casing and the presence of the centralizers
and scratchers lessen the chance that the cement will channel
between the casing and wall of the hole. A diagram of a well
with the casing installed is shown in Figure 6-4.
The drilling portion of the oil well operations is complete
when the hole has been drilled to its final depth and the casing
has been set. Further operations to allow production from the
well are discussed in Section 6.4 on production.
6.3.2 Input Requirements
The inputs required for drilling the wells which will
ultimately produce 100,000 barrels per day of crude oil are
discussed in this section. Exploratory drilling means search-
ing for the geologic strata containing petroleum in sufficient
quantities to justify recovery. Once the oil is found, develop-
mental wells are drilled to recover the maximum amount of oil
over the life of the field. Other recovery techniques must
also be considered in planning a developmental well program.
As a basis for the inputs for this field, 400 producing
wells, each rated at 250 barrels/day, will supply the crude oil.
-20-
-------
CONDUCTOR
SURFACE SOIL
SHALE OR
CLAY
m
fH'.r^i^nnr.?
W/V
iPfrSSS
SURFACE-
SHALE
INTERMEDIATE
LIMESTONE
PRODUCTION
CASING
CEMENT
WATER
CASING
SHOE
SHALE
Figure 6-4. Casing Strings and Pipe Used in an Oil Well.
Source: Petroleum Extension Service, University of Texas
A Primer of Oil Well Drilling, 3rd Edition.
Austin, Texas:University of Texas, 1970.
-21-
-------
Three hundred dry holes will have been drilled by the end of
the seven year time frame of this project.
6.3.2a Manpower Requirements
The Bechtel Corporation1 has estimated manpower required
for developing and producing a domestic oil field and gathering
system. The total manpower requirements for developing the
example field are included in Section 6.4.3.2a.
6.3.2b Materials and Equipment
The Federal Energy Administration has estimated the major
material requirements for both dry holes and producing holes.2
The estimates per well and for a field producing 100,000 BPD
are shown in Table 6-7.
6.3.2c Economics
Only the costs incurred with the drilling operation are
considered in this section. Drilling costs vary greatly with
location, depth, and nature of the local substrata, but by
using average costs for drilling in the western U.S. at 5,000-
10,000 foot depths, a total cost of approximately $125 million
is derived.3
^arasso, M., et ai. Energy Supply Model, Computer Tape.
San Francisco, California: Bechtel Corporation, 1975.
2Federal Energy Administration, Interagency Task Force on
Natural Gas. Project Independence Blueprint, Final Task Force
Report, Natural Gas.Washington, D.C.:Federal Energy
Administration, November 1974.
3 Ibid.
-22-
-------
TABLE 6-7. MATERIALS AND EQUIPMENT
REQUIRED FOR A 100,000
BPD OILFIELD
Requirements for
300 Dry Holes 400 Successful Holes Total
Casing and Tubing
(Tons) 6,250 15,200 21,450
Surface and Sub-
surface Equipment
(Tons) --- 30,800 30,800
Number of Rig-Years
(6 Year Duration) 18 24 42
Steel Tonnage Per
Rig (Tons) 250 250
Cement (Tons)* 18,000 24,000 42,000
^Assuming each well is 5,000 feet deep.
Source: Federal Energy Administration, Interagency Task Force
on Natural Gas. Project Independence Blueprint, Final
Task Force Report, Natural Gas"! Washington, D.C.:
Federal Energy Administration. November, 1974.
-23-
-------
6.3.2d Water Requirements
Drilling fluid make-up is the major requirement for
fresh water at a drilling site. Between 200 and 500 barrels
per day are needed for a conventional drilling rig.1 Approxi-
mately 7500 barrels are required for the drilling of one well;
about 5,000,000 barrels are consumed over the life of the
drilling project.
6.3.2e Land Requirements
About 2 acres of land are cleared and used around a
typical exploratory well.2 After drilling is complete, some of
this land is retained for workover rig purposes, and can be
sodded or surfaced as local conditions dictate. Any area not
needed for workover can be restored to its original condition.
About 150 acres are used permanently for drilling locations
and roads for the exploration wells (300 dry holes). Land
associated with producing wells is included in Section 6.4.2e.
6.3.2f Ancillary Energy
Most energy required for drilling oil wells is provided by
diesel fuel. Energy is used to operate the drilling equipment,
generate an electrical system in remote areas, and operate
mobile vehicles around the drilling site. The quantity depends
on well depth, rig size, time on the well, and type of
geologic formation drilled.
1 Federal Power Commission. National Gas Survey, Vol. II.
Washington, B.C.: Federal Power Commission,1974, pp.73-75.
2 Ibid.
-24-
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The consumption of diesel fuel varies from 900 to 1800
gallons per day.! Total fuel consumption for the entire drilling
program is approximately 20 million gallons , or the energy equiva-
lent of 3.0 x 1012 Btu.
6.3.3 Outputs
The outputs associated with the exploratory phase of crude
oil production are discussed in the following sections.
6.3.3a Air Emissions
The large internal combustion engines used to power the
drilling equipment are the major source of air emissions during
exploratory and developmental drilling. Table 6-8 contains
emission factors, air emission per rig, and entire oil field
emissions averaged over the seven years in which drilling
takes place. Drilling will be more intensive near the middle
of the period, and emissions will be somewhat greater than the
average.
6.3.3b Water Effluents
A negligible amount of water used in the drilling operation
is lost to the surroundings due to the circulating mud system
being closed. Some water may escape from the well by mechanical
failure or human error, and some water from the holding pond may
seep into the ground water. This loss is considered minimal.
'Federal Power Commission. National Gas Survey, Vol. II.
Washington, D.C.: Federal Power Commission,1974, pp.73-75.
2Environmental Protection Agency. Compilation of Air
Pollution Emission Factors, 2nd Edition with Supplements, AP-42.
Research Triangle Park, North Carolina: Environmental Protection
Agency, April 1977.
-25-
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Drainage patterns of surface waters and rain runoff may be
disturbed by the construction of roads into the area of a drilling
rig. This disturbance may cause increased turbidity and suspended
solids in the fresh water and erosion.
6.3.3c Solid Wastes
Exploratory drilling brings drill cuttings from the hole to
the surface. These cuttings are mixed with the mud containing
additives such as barite, bentonite, and phosphate. They will
dry in the reserve pit and are plowed into the native soil when
drilling is complete. Although some soils may be improved by
the addition of these compounds,1 they will have an adverse
effect in most instances.
6.3.3d Noise Pollution
Associated with drilling activities, there is a substantial
noise level which may be annoying to wildlife or nearby residents.
In congested areas, such as Southern California, some drilling
rigs have been soundproofed, and purchased electricity has re-
placed internal combustion engines. These solutions seemed to
prevent a disturbance to the environment.
6.3.3e Occupational Health and Safety
Occupational health and safety data are obtained from
information for oil and gas production.2 Values for deaths,
federal Power Commission. National Gas Survey, Vol. II.
Washington, B.C.: Federal Power Commission,1974,pp.73-75.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus and Pacific Northwest Laboratories,
1973.-
-27-
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injuries, and working time lost are presented in multiples of
106 Btu. Scaling this information for 100,000 bbl/day oil
production, the results are as follows: 0.45 deaths/year,
43 injuries/year, and 7,154 man-days/year are expected to be
lost.
6.3.3f Odor
There are no odor problems associated with the drilling of
oil wells.
6.3.4 Social Controls
6.3.4.1 Oil Exploration Regulation
Exploration for oil or gas is usually controlled by statute
and regulation at the level of government having control over
the land proper. Federal and Indian land is regulated by
federal laws and regulations and state laws apply usually to
state and private lands. The discussion below will be divided
into those categories. In most cases the state law on exploration
will have limited application to private lands.
6.3.4.la Exploration on Federal Lands
The oil and gas sections of the Mineral Leasing Act of 19201
allow the Secretary of the Interior to lease the lands for devel-
opment. If the lands are in a known geologic structure (KGS)
of a producing oil and gas field, only a competitive (by bidding)
Mineral Leasing Act of 1920, 30 W.S.C.A. §§ 223-228 (1970).
The Mineral Leasing Act of 1920 is the main source for this
regulation although other sources of federal control are discussed
in Chapter 2 (e.g., The Acquired Lands Act of 1947, 30 U.S.C.A.
§§ 351-359 (1970)).
-28-
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lease is allowed.l The exploration of "unknown" lands was
previously regulated by a permitting process administrered by
the Bureau of Land Management (BLM), but the present regulation
allows a non-competitive lease for such lands.2 Leases issued
for exploration can be for between 640 and 2,500 acres.3 Even
the "unknown" lease must contain a royalty provision equal to
that of the KGS for 12% percent.1* The terms of the lease can
also include specifications for conservation* and environmental
protection.5 The exploring developer who does not want to lease
lands even under the non-competitive provision may still explore
public lands, but only if he files a notice of intent with the
U.S. Geological Survey (U.S.G.S.).6
6.3.2.1b Exploration on Indian Lands
Under the Omnibus Mineral Leasing Act of 1938, the leasing
of unallotted or tribal and ceded lands for mining purposes is
authorized.7 The only provision for exploration with the
statutory framework seems to be lease itself. 3
'30 U.S.C.A. § 226 (b) (1970) .
230 U.S.C.A. § 226 (c) (1970).
343 C.F.R. § 3110. 1-3 (1972).
"30 U.S.C.A. § 226 (c) (1970).
530 U.S.C.A. § 226 (j) (1970). See also Section 6.4.4.la
below for a more detailed discussion.
643 C.F.R. 3045.1-1 (1972).
70mnibus Mineral Leasing Act of 1938 and subsequent amend-
ments codified as 25 U.S.C.A. §§ 396-401 (1970).
8But see Proposed Regulations - 25 C.F.R. Part 177, as
discussed by Simonds, Jerome H. "The Acquisition of Rights to
Prospect for and Mine Coal from Tribal and Allotted Indian Lands
pp. 159-162, in Rocky Mountain Mineral Law Foundation. Rocky
Mountain Mineral Law Institute: Proceedings of the Twenty First
Annual Institute. July 17-19, 1975. Albany, N.Y.: Matthew
Bender, 1975, where prospecting permits are included.
-29-
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Because the later section (6.3.4.2b) on leasing explains the
recent changes in leasing procedures, the exploration will not
be discussed here but should be viewed as a part of the leasing
procedure described there.
6.3.4.1c Exploration on State Lands
Exploration for oil on state lands is generally controlled
by the terms of the lease. Only Colorado allows for a separate
permit for oil exploration outside the lease. A developer in
the remaining seven states must obtain a lease under the appro-
priate statute and perform any necessary exploration within that
lease (leasing of state lands for oil development is discussed
in Section 6.3.4.2c). Arizona has a system which allows explor-
ation on "unknown lands" under a lease; whereas the state's
"known lands" must be competitively leased. In summary the
general rule in the western states is to allow a non-competitive
lease (to allow exploration) of unknown lands and to require a
competitive (without exploration) lease of known lands.
Under the above described system, a preference to the dis-
coverer is built into the lease since the royalty provisions,
etc., are specified prior to a "discovery." Once the initial
lease expires (although this would be rare since all states
save Colorado build in the term "continues as long as producing"
into their leases) or once an area is not considered unknown,
then there is only a preference to re-lease in New Mexico.
Table 6-9 summarizes the exploration procedures in the
eight states and Tables 6-10 through 6-17 give a detailed
explanation for each state.
-30-
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TABLE 6-9.
ND
SD
UT
WY
SUMMARY OF STATE LAND EXPLORATION
PERMITS
AZ
CO
MT
NM
Method of
Exploration
Separate Exploration
Permit Within Lease
x1
x2
X
X
Term of
Permit or
Lease
5 Years3
60 Days
Extensions
available.
10 Years3
5 Years3
Renewable.
Preference
Given to Additional
Explorer/ Permits May
Discoverer Be Required1*
X
Upon Expira-
tion of permit
the holder may
be required to
lease.
X
Preference is
given to pre-
X
X
X
c
X"
vious lessee
to re-lease.
5 Years
10 Years'
10 Years'
10 Years'
Exploration for oil in Arizona on state lands is only available on "unknown
lands"; the remaining "known" lands must be leased competitively.
2Although this is a permit type of exploration, many of the requirements,
(e.g., posting of notice on site) of claim filing method are retained.
3Continues for "so long as producing."
^For example: Intent to drill, explosive use, open mine, etc.
5Wyoming statutes do not provide for exploration for oil on state lands,
but presumably the lease holder could explore as needed.
-31-
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TABLE 6-10. ARIZONA OIL EXPLORATION PERMIT'
Item
Statutes
Summary
Agency 8 27-553
Special b § 27-513
Requirements
Fees § 27-555
Rental § 27-555
Royalty § 27-555
Duration § 27-555
Bond
Discretionary
Actions
Other
Information
State Land Department, State Land
Commissioner
All wells in state require a drilling
permit at a fee of $25 from commis-
sioner
$25
$1.25 per acre per year for a maximum
of 2,560 acres
12 1/2%
Five years and so long as producing
aArizona Revised Statutes Annotated, L956.
The second item in each table indicates special requirements for
issuing the permit. A blank in this category reflects a ne-
cessity of filing an application with a minimum of information
to include the applicant's name, address, and location of the
land involved.
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TABLE 6-11. COLORADO OIL EXPLORATION PERMIT4
Item
Statutes
Summary
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Bond
Discretionary
Actions
Other
Information
§ 36-1-140
§ 36-1-140
State Board of Land Commissioners
1. Discovery. 2. Posting of notice
of discovery on site. 3. Notify
board within ten days of discovery
§ 36-1-140 Sixty days, but extension possible.
36-1-140 At expiration of permit the locator
may be required to lease upon agreed-
to-terms
Colorado Revised Statutes, 1973.
'The second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location of
the land involved.
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TABLE 6-12. MONTANA OIL EXPLORATION PERMIT'
Item
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Statutes
§ 81-1701
§ 69-33
§ 81-108
§ 81-1702
§ 81-1702.1
§ 81-1704
§ 81-1702
Summary
State Board of Land Commissioners
See Chapter 2 for Montana Geo-
physical Exploration Permit
Set by State Land Department
Minimum of $1.50 per acre, but not
Less than $100 per year per lease.
Maximum area of 640 acres per lease
and per person.
12 1/2 percent
10 years and so long as producing.
Bond
Discretionary
Actions
Other
Information
§ 81-1715
§ 81-1702.2
81-2612
Competitive re-lease of producing
lands.
Delay drilling penalty shall be
$1.25 per acre per year.
If there is a conflict between coal,
oil, gas, or geothermal developers
on state lands, the first issued
lease has priority, but the board
may amend to fit the situation
Revised Codes of Montana, 1974.
The second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location
of the land involved.
-34-
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TABLE 6-13. NEW MEXICO OIL EXPLORATION PERMIT'
Item
Statutes
Summary
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Bond
Discretionary
Actions
Other
Information
§ 7-11-1
§ 65-3-11
§ 7-11-1
§ 7-11-9
§ 7-11-3
§ 7-11-3.4
§ 7-11-3
§ 7-11-3.4
§ 7-11-63
§ 7-11-10
Commissioner of Public Lands
The Oil Conservation Commission
has authority to require bond of
$10,000 to insure plugging, con-
servation of oil and gas resources
The Commissioner may set terms and
fees
Not more than 6400 acres per lease
at not less than $100 per year for
primary term or not less than 50 per
acre nor more than $1.00 per acre
during secondary term
Not less than 1/8 nor more than 1/6,
also the Commissioner may cancel
secondary term (possible in kind
royalty)
5 years primary and so long there-
after as producing with one 5 year
extension possible
Cancellation of secondary term
Preference to previous lessee on
re-lease
Certain lands herein specified
can only be leased by competitive
bids
New Mexico Statutes, 1953.
5The second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location
of the land involved.
-35-
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TABLE 6-14. NORTH DAKOTA OIL EXPLORATION PERMIT^
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Discretionary
Actions
Other
Information
§ 38-09-14
§ 38-08-04
§ 38-09-18
§ 38-09-18
I 38-09-18
i 38-15-03
§ 38-09-14
§ 38-09-20
Any department or agency of the
state
Industrial commission requires a
bond for repair of surface and
charges $25.00 for a drilling permit
Permittee (without bond) required
to file notice of intent to drill
with county register of deeds
Not less than 250 per acre per
year
Not less than 1/8 of lessor's
interest
Not less than 5 years and for so
long as producing
The industrial commission may re-
quire a bond to satisfy conflicts
between mining or oil and gas
developers on same land
The procedure above is for
exploration. Leasing must be
competitive bid (38-09-15)
Any county, city, etc., may also
lease their lands for oil and gas
and they have the authority to
establish their leasing regulations
aNorth Dakota Century Code, 1960 (as amended).
The second item in each table indicates special requirements for
issuing the permit. A blank in this category reflects a ne-
cessity of filing an application with a minimum of information
to include the applicant's name, address, and location of the
land involved.
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TABLE 6-15. SOUTH DAKOTA OIL EXPLORATION PERMIT'
Item
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Statutes
§
§
§
§
§
§
5-7-1
5-7-2
5-7-27
5-7-24
5-7-24
5-7-23
Summary
Commissioner of School and Public
Lands
This lease goes to the highest bid-
der in oral bids
The Board of School and Public
Lands may set reasonable fees
Not less than IOC per acre per year
Royalty shall be 1/8 of production
Not more than ten years and for so
long as producing
Bond
Discretionary
Actions
Other
Information
§ 5-7-22
§ 45-9-4
I 45-9-15
§ 45-7A-3
§ 5-7-6
5-7-2
Commissioner may withhold lands
from lease if in best interests of
state
A permit to drill from the State
Oil and Gas Board for a fee of
$100. A bond required from $5,000
to $20,000 for restoration
(discretionary)
This section may additionally re-
quire a report of any exploratory
well sent to the Department of
Natural Resources (confidential).
Also, that all such wells be
capped, sealed, or plugged
Exempts oil and gas from the pr"o-
visions concerning mineral pro-
specting and leasing (see Coal
Exploration and Leasing for South
Dakota § § 5-7-3 to 5-7-17)
Specifically allows for prospecting
and production in the lease
lSouth Dakota Compiled Laws, 1967.
The second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location
of the land involved.
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TABLE 6-16. UTAH OIL EXPLORATION PERMIT'
Item
Statutes
Summary
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Bond
Discretionary
Actions
Other
Information
§ 65-1-18 State Land Board
§ 40-6-5 The Board of Oil, Gas and Mining
has the authority to require:
security (for plugging), notice of
intent to drill, cont'd; and filing
of a well log (for any drilling)
§ 65-1-24 15c per acre
§ 65-1-18 Not less than 50c per acre per year
nor more than $1.00 per acre per
year
§ 65-1-18 Not more than 12 1/2 percent of
gross
§ 65-1-18 Not less than ten years and for so
long as producing
§ 65-1-90 Required only to reinstate lease
after failure to pay for damage
to surface
I 65-1-90 Amount of bond in item no. 7 above
65-1-45 Newly acquired lands and lands with
an expiring lease must be let
through competitive bids, all
other leased to first applicant
Utah Code Annotated, 1953.
second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location
of the land involved.
-38-
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TABLE 6-17. WYOMING OIL EXPLORATION PERMIT"
Item
Statutes
Summary
Agency
Special ,
Requirements
Fees
Rental
Royalty
Duration
Bond
Discretionary
Actions
Other
Information
§ 36-74
§ 36-42
§ 36-74
§ 36-74
36-74
§ 36-79
§ 36-34
Board of Land Commissioners,
Commissioner of Public Lands
Fee for filing a lease application
is $15
Not less than 5 percent of gross
A primary term of 10 years and to
continue so long as production
realized
The agency above has authority to
set rates and terms in its rules
and regulations within the confines
of specific statutes noted above
This section allows the counties,
cities, and school districts to
lease their lands (if owned in fee)
for oil or gas production
For a fee of $10 you can be put on
the mailing list of lands open to
file upon (appears to be non-
competitive)
Wyoming Statutes of 1957.
The second item in each table indicates special requirements
for issuing the permit. A blank in this category reflects a
necessity of filing an application with a minimum of informa-
tion to include the applicant's name, address, and location
of the land involved.
-39-
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6.3.4.2 Leasing
After exploration, the procedures for obtaining leases vary
according to the ownership status of the land and what is known
about the mineral deposits of the proposed tract. These procedures
will be discussed in the following order: federal laws governing
development, federal lease types, Indian lands and state lands.
6.3.4.2a Leasing on Federal Lands
Since the federal laws applicable to the leasing of oil
lands are primarily the same ones applicable to coal, gas, and
oil shale, they were discussed in Chapter 2. The following
discussion will note the key provisions applicable only to oil.
Two types of leases may be issued, depending upon what is
known about the mineral deposits of the proposed lease section.
A competitive lease has a publicly announced invitation to bid
and the bidder with the highest bonus bid is awarded the lease.
Lands of known geological structure (KGS, lands whose mineral
characteristics are known or can be reasonably estimated) must
be submitted to competitive bidding.: A prospecting permit may
be issued or a non-competitive lease may be awarded for lands
whose mineral characteristics have not been determined.2 A
J43 C.F.R. , 3120'.1-3120.4-2.
2Section 3, a, 1, Order No. 2948, U.S. Department of Interior,
Division of Responsibility Between Bureau of Land Management
and Geological Survey for Administration of Mineral Leasing Laws -
(Onshore) in U.S. Congress, Senate, Committee on Interior and
Insular Affairs, Federal Leasing and Disposal Policies, Hearings,
92nd Congress, 2nd Session, June 19, 1972, p. 175-176; 43 C.F.R.
3110.1-2112.5-2.
-40-
-------
prospecting permit grants the holder authority to explore the
land covered and preferential rights on possible leases. The
non-competitive lease is entered into by the BLM and the leasee,
and conditions are negotiated between the two parties.
A minimum bonus (cash deposit) is required for competitive
bids on federal onshore lands. The minimum is discretionary
and is determined through an evaluation made by the Geological
Survey. This is used to indicate whether or not the high bid
received represents an estimation of the fair market value of
the tract leased. Non-competitive leases for oil and gas
bearing lands are issued without a bonus.
Differences also exist in the time limitations applicable
for the two lease types. Competitive leases are issued for five
years and non-competitive leases are for ten years. In both
cases the lease may be continued after the initial period if
oil or gas is being produced in paying quantities. (This
standard has not been specifically defined.) If drilling opera-
tions are underway at the lease's expiration it may be extended
for two years and thereafter, if producing, may be continued as
with the original lease.1
Non-competitive leases for either public or acquired lands
must lie within a six-mile square or an area not exceeding six
surveyed sections in length or width. The lease may not be for
an area of less than 640 acres or more than 2,560. Exceptions
may be granted if the lands are in an approved unit or
cooperative plan or the land is surrounded by lands which are
LFederal Leasing and Disposal Policies, p. 122.
-41-
-------
not available for leasing. Competitive leases, on the other
hand, may not exceed 640 acres and should be as compact as
possible.l
Total acreage limitations also exist. No individual asso-
ciation or corporation may hold more than 264,080 acres in any
single state; of that figure, no more than 200,000 acres may be
held under option. The computations are made separately for
public domain and acquired lands; neither category can be applied
to the other to determine total acreage held.
The lease agreements obligate the developer to pay rentals
on the land and royalties on the production. Rental rates for
non-competitive leases are not less than $0.50 per year per
acre. For competitive leases the rate is not less than $2.00
per year per acre.2 Royalty rates differ for oil and gas wells.
For oil wells the rate begins at 12.5 percent if average produc-
tion is under 110 barrels per day and advances up a scale to
25 percent for wells producing over 400 barrels per day. For
gas wells the rate is 12.5 percent if average production is less
than 5,000,000 cubic feet per day and is 16.5 percent if produc-
tion exceeds that level. These rates apply to both public domain
and acquired lands.
6.3.4.2b Leasing on Indian Lands
Procedures for acquiring Indian lands are generally the same
as those for federal lands, although Indian authorities do have
1Landman's Legal Handbook, p. 33-34; 43 C.F.R. 3123.1 and
43 C.F.R. 3122.1, 3124.1
243 C.F.R. 3103.3-4 (i).
-42-
-------
veto power over leasing decisions. Indian lands are administered
in a cooperative trusteeship. Although Indian lands are not an
integral part of the public domain, neither do the Indians have
complete legal title. Indian lands are divided into two principal
categories: allotted where title has been partially transferred
to individual Indian landowners; and tribal where the lands are
collectively owned.
The Bureau of Indian Affairs (BIA) acts as a trustee, both
for individual Indians and tribes on reservations. The stated
goal is to protect Indian interests from overzealous government
policies and to provide assistance and service in granting permits
and making leases. Both the federal government and the Indian
tribes have veto power over a lease.
The Omnibus Mineral Leasing Act of 1938 authorized the
leasing of unallotted or tribal and ceded lands for mining
purposes.1 Under this Act, the tribal council or other authorized
spokesman for the tribe may, with the approval of the Secretary
of the Interior, enter into a lease*not to exceed ten years "and
so long thereafter as minerals are produced in paying quantities.":
1 Omnibus Mineral Leasing Act of 1938, 25 U.S.C. 396, 52 Stat,
2Unallotted or tribal lands are held in trust by the federal
government for an entire tribe; allotted lands are held in trust
for individual Indians; and ceded lands are those which were
ceded to the federal government and settled by non-Indians while
the tribe retained the mineral rights. Authorization to lease
allotted lands was legislated in 1909 (Indian Department Appro-
priations Act of 1909, 25 U.S.C. 396, 35 Stat. 783). While there
are differences because in one case lands are held in common
and in the other by individuals, the regulations and procedures
for allotted lands discussed here are essentially the same.
Regulations implementing the Act are contained in Title 25, Code
of Federal Regulations, Part 171 (25 C.F.R. Part 171).
-43-
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Current regulations require competitive bidding on oil and
gas leases unless the Commissioner of Indian Affairs grants the
tribe written permission to negotiate for a lease.1 Lease size
is limited to 2,560 acres unless the Commissioner finds that
larger acreage is in the interest of the tribe and required "....
to permit the establishment or construction of thermal electric
power plants or other industrial facilities on or near the
reservation."2
Rents and royalties are also established by regulation: for
oil and gas the rent is $1.25 per acre per year and the minimum
royalty is 12.5 percent of the value of all oil and gas actually
produced.3
Regulations require diligent development. In the case of
oil and gas, the regulation simply states that lessees are to
exercise diligence in drilling and operating wells.1* There is
also a conservation requirement for oil and gas.5
Under the current system, leasing is the sole mechanism
emphasized in the regulations and the initiative for minerals
development (for example, in initiating a lease sale) is
with the Secretary of the Interior. The theme throughout the
regulations is one of management by the federal trustee for
125 C.F.R. 171.2 and 171.3.
2C.F.R. 171.9.
325 C.F.R. 171.14 and 171.15.
"25 C.F.R. 171.14.
525 C.F.R. 171.19 and 171.21. Other regulations cover
assignment (transfer) of leases, penalties, prospecting permits,
inspection, prior approval for starting operations, and cancel-
lations. 26 C.F.R. 171.18, 171.19, 171.20, 171.25, and 171.27.
-44-
-------
Indians. As noted earlier, many individual Indians and Indian
tribes wish to have a more active role in managing their own
affairs. Some tribes have, in fact, departed from current
regulations and dealt directly with energy companies without
the prior approval of the Secretary of the Interior.1
Some tribes have shown considerable int'erest in alternatives
to leasing. The Jicarilla Apaches, for example, are preparing
a proposal for joint ventures in oil and gas resource development.2
Other alternatives being discussed are modified leases (with
variable rather than fixed royalty, for example), production
sharing agreements, and service contracts.
6.3.4.2c Leasing on State Lands
Leasing of state lands is controlled by statute in seven of
the eight states. Colorado controls its state lands through
agency regulation. For a general discussion of leasing pro-
cedures see Chapter 2; the following paragraphs will note the
special provisions. Because the statutes written to control oil
have been on the books longer than for other resources they are
generally more specific. Hence, an oil developer in the western
states will usually find an established procedure for leasing
state lands.
LFor example, the Navajos dealt directly with Exxon in
negotiating a uranium lease in 1972. Although bypassing the
Secretary violates existing regulations, such an agreement
would be valid if he subsequently approved it. Although the
purpose of these so-called "joint ventures" is to secure a
competitive advantage in the leasing market, it appears that this
one agreement has had little effect on competition for resources.
See U.S. Federal Trade Commission, Bureau of Competition, Report
to the Federal Trade Commission on Mineral Leasing on Indian
Lands. Washington: Federal Trade Commission, 1975, pp. 163-171.
2The tribal council considers the standard lease to be
unacceptable, and does not intend to use it in the future.
-45-
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In all states, responsibility for managing and leasing state
lands and minerals is located in a single state agency, except
for oil and gas in North Dakota where each state agency may lease
land it controls. The administrative head of the agency may be
authorized to accept or reject prospecting and lease applications.
It is not unusual, however, for leasing approval to require the
consent of more than one state agency.
If the state lands are known to contain commercially valuable
oil reserves, they will usually be leased competitively. If they
are unknown lands, the procedure varies from competitive to
first-come-first-served. The terms of leases are usually 5 or
10 years while production of oil keeps the lease in operation
indefinitely.
Generally, the leases are required by statutes to set
specific rental and royalty rates, although some states allow
discretion (e.g., New Mexico and Colorado) or some states set a
maximum or minimum level for the rates.
Table 6-18 summarizes the key terms for the eight states
and Tables 6-19 through 6-27 show the detailed statutory
requirements.
-46-
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TABLE 6-18.
SUMMARY OF TERMS FOR OIL LEASES
ON STATE LANDS
Duration
of Lease
Preference to
Lease Giver
Must Lease be Issued Under
Competitive Bid
AZ 5 years (continues
while producing)
CO Not specified by
statute
MT 10 years (continues
while producing)
NM 5 years (continues
while producing)^-
ND 5 years (continues
while producing)
SD 10 years (continues
while producing)
UT 10 years (continues
while producing)
WY 10 years (continues
while producing)
Yes, for lands of known
commercial value
Not specified by statute.
Yes, for re-lease of producing
lands.
To previous Yes, for lands within a
lessee statutorily described geo-
graphic region.
Yes
Yes
Yes, for newly acquired lands
and for lands with an expiring
lease
Not specified, but state has
mailing list of lands
available.
New Mexico also allows for one, 5-year extension on the lease if not
producing.
-47-
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TABLE 6-19. ARIZONA OIL LEASE FEATURES
(UNKNOWN LANDS)a
Item
Agency
Requirements
Fees
Rental
Royalty
Duration
Statutes
§
§
§
§
§
27-553
27-555
27-555
27-555
27-555
Summary
State Land Department, State
Land Commissioner
$25
$1.25 per acre per year for a
maximum of 2,560 acres
12 1/2 percent
Five years and so long as
producing
Bond
Other
Information
§ 27-513
All wells in state require a
drilling permit at a fee of
$25 from commissioner
Arizona Revised Statutes Annotated, 1956.
-48-
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TABLE 6-20. ARIZONA OIL LEASE FEATURES
(KNOWN LANDS)3
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§ 27-553
§ 27-556
I 27-556
§ 27-556
§ 27-556
§ 27-513
State Land Department, State
Land Commissioner
Must be leased by competitive
bids
$1.00 per acre per year for a
minimum of 160 acres and a
maximum of 1,280 acres
12 1/2 percent
Five years and so long as
producing
All wells in state require a
drilling permit at a fee of
$25 from commissioner
Arizona Revised Statutes Annotated, 1956.
-49-
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TABLE 6-21. COLORADO OIL LEASE FEATURES'
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§ 36-1-113
§ 36-1-112
I 36-1-114
State Board of Land Commissioners
Application - $.50
Lease - $1.00
Lease Service Fee - $5.00
Board may adjust rentals to
get maximum revenue
Colorado Revised Statutes, 1973.
-50-
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TABLE 6-22. MONTANA OIL LEASE FEATURES'
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
81-1701
§ 81-108
§ 81-1702
§ 81-1704
§ 81-1702
§ 69-33
§ 81-1715
§ 81-1702.2
§ 81-2612
State Board of Land
Commissioners
Set by state Land Department
Minimum of $1.50 per acre, but
not less than $100 per year
per lease. Maximum area of
640 acres per lease and per
person
12 1/2 percent minimum
10 years and so long as pro-
ducing
Geophysical Exploration Permit
may be required (see Chapter
2)
Competitive re-lease of pro-
ducing lands
Delay drilling penalty shall
be $1.25 per acre per year
If there is a conflict between
coal, oil, gas, or geothermal
developers on state lands,
the first issued lease has
priority, but the board may
amend to fit the situation
Revised Codes of Montana, 1947.
-51-
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TABLE 6-23. NEW MEXICO OIL LEASE FEATURES;
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
1 7-11-1
§ 7-11-1
§ 7-11-9
§ 7-11-3.4
§ 7-11-3
§ 65-3-11
§ 7-11-63
§ 7-11-10
Commissioner of Public Lands
The commissioner may set terms
and fees
Not more than 6400 acres per
lease at not less than $100
per year for primary term or
not less than 5C per acre
nor more than $1.00 per acre
during secondary term
Not: less than 1/8 nor more than
1/1 also the commissioner may
cancel secondary term
5 years primary and so long
thereafter as producing with one
5 year extension possible
The Oil Conservation Commis-
sion has authority to require
bond of $10,000 to insure
plugging, conservation, etc.,
of oil and gas resources
Preference to previous lessee
on re-lease
Certain lands herein specified
can only be leased by com-
petitive bids
*New Mexico Statutes, 1953.
-52-
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TABLE 6-24. NORTH DAKOTA OIL LEASE FEATURES'
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
38-09-14 Any department or agency of the
state
§ 38-09-18
§ 38-09-18
I 38-09-18
§ 38-15-03
Other
Information
Not less than 25C per acre
per year
Not less than 1/8 of lessor's
interest
Not less than 5 years and for
so long as producing
The industrial commission may
require a bond to satisfy
conflicts between mining or
oil and gas developers on
same land
38-08-04 Industrial commission requires
a bond for repair of surface
and charges $25 for a dril-
ling permit. Permittee
cont'd (without bond) required
to file notice of intent to
drill with county register
of deeds
38-09-14 The procedure above is for
both exploration and production,
Leasing must be competitively
bid (38-09-15)
38-09-20 Any county, city, etc. may
also lease their lands for
oil and gas and they have the
authority to establish their
leasing regulations
North Dakota Century Code, 1960 (as amended).
-53-
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TABLE 6-25. SOUTH DAKOTA OIL LEASE FEATURES*
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
1 5-7-1
§ 5-7-2
§ 5-7-27
§ 5-7-24
§ 5-7-24
§ 5-7-23
§ 5-7-22
§ 45-9-4
§ 45-9-15
45-7A-3
45-7A-2
5-7-6
Commissioner of School and
Public Lands
This lease goes to the highest
bidder in oral bids. Allows
for prospecting and/or pro-
duction within the lease
The Board of School and Public
Lands may set reasonable fees
Not less than IOC per acre per
year
Royalty shall be 1/8
Not more than ten years and
for so long as producing
Commissioner may withhold
lands from lease if in best
interests of state
A permit to drill from the
State Oil and Gas Board for
a fee of $100. A bond re-
quired from $5,000 to $20,000
for restoration (discretionary)
This section may additionally
require a report of any explora-
tory well sent to the Department
of Natural Resources (confiden-
tial) . Also that all such
wells be capped, sealed, or
plugged.
Exempts oil and gas from the
provisions concerning mineral
prospecting and leasing (see
Coal Exploration and Leasing
for South Dakota § § 5-7-3 to
5-7-17)
South Dakota Compiled Laws, 1967.
-54-
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TABLE 6-26. UTAH OIL LEASE FEATURES'
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§ 65-1-18
§ 65-1-24
§ 65-1-18
§ 65-1-18
§ 65-1-18
§ 65-1-90
§ 65-1-90
§ 40-6-5
65-1-45
State Land Board
15c per acre
Not less than 50C per acre per
year nor more than $1.00 per
acre per year
Not more than 12 1/2 percent of
gross
Not less than ten years and
for so long as producing
Required only to reinstate
lease after failure to pay
for damage to surface
Amount of bond in item no. 7
above
The Board of Oil, Gas and
Mining has the authority to
require: security (for
plugging), notice of intent
to drill, and filing of a
well log (for any drilling)
Newly acquired lands and lands
with an expiring lease must
be let through competitive
bids, all other leased to
first applicant
Utah Code Annotated, 1953.
-55-
-------
TABLE 6-27. WYOMING OIL LEASE FEATURES'
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§ 36-74
§ 36-42
§ 36-74
§ 36-74
§ 36-74
§ 36-79
36-34
Board of Land Commissioners,
Commissioner of Public Lands
Fee for filing a lease applica-
tion is $15
Not less than 5 percent of
gross
A primary term of 10 years and
to continue so long as pro-
duction realized
The agency above has authority
to set rates and terms in
its rules and regulations
within the confines of spe-
cific statutes noted above.
This section allows the coun-
ties, cities, and school dis-
tricts to lease their lands
(if owned in fee) for oil or
gas production.
For a fee of $10 you can be put
on the mailing list of lands
open to file upon (appears
to be non-competitive)
Wyoming Statutes of 1957.
-56-
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6.4 CRUDE OIL PRODUCTION
6.4.1 Conventional Production Technologies
The crude oil development technologies discussed in this
section are grouped into four categories: development drilling,
completion, processing, and improved recovery.
Development Drilling
Once oil is discovered by exploratory drilling, the well is
tested to determine the possible oil flow rate and size of the
reservoir. If the reserves calculated from these data and other
geological information are large enough to warrant commercial
production, the reservoir is developed. Development includes
drilling a number of wells to drain the reservoir as efficiently
as possible, completing these wells so that flow occurs and can
be controlled, installing field processing equipment, and install-
ing gathering pipelines.
Development drilling is carried out in the same manner as
exploratory drilling, except that the spacing of wells and loca-
tion of the bottoms of the holes are more carefully cont-rolled.
Once the development well is drilled, casing is set in a manner
similar to that discussed in Section 6.3.1.
Completion
Well completion encompasses all those activities required
for preparing the well for production. The four basic types of
completion are open hole, liner, perforated casing, and multizone
-57-
-------
Open hole completion is used when the production zone is
firm and not in danger of caving. It involves setting the casing
to a depth just above the production zone and leaving the bottom
open. An example of this is shown in Figure 6-5. Liner comple-
tion is accomplished by setting a screen liner opposite the
producing layer to hold the sand or shale from caving.
The third type of completion, perforated casing, accounts
for over 95 percent of all completions.1 It is accomplished by
putting holes in the casing at the production zone. This is done
by either using a perforating gun which fires steel bullets
through the casing or by using a jet type perforator which blasts
holes in the casing with a high temperature, high velocity gas
generated by a shaped charge explosive. An example of a perfo-
rated casing completion is shown in Figure 6-6. The fourth type
of completion, multizone completion, produces two or more sepa-
rate zones simultaneously through the same wellbore without mix-
ing the fluids. This type completion is used not only to permit
separate monitoring of the wells, but is also made compulsory by
many state regulations.
Another aspect of the completion process is installing the
production tubing. Production tubing is the pipe string inside
the casing through which the produced fluids flow to the surface.
The diameter of this pipe is small, relative to the casing diam-
eter. The annular space between the tubing and the casing is
blocked off above the producing zone by packers to force the
fluid into the tubing. In the case of a multicompletion well,
the annular space is blocked off both above and below the pro-
ducing zone. Tubing and packers are shown in Figure 6-6.
Petroleum Extension Service, University of Texas. A Primer
of Oil Well Drilling, 3rd Edition. Austin, Texas: University of
Texas, 1970.
-58-
-------
CEMENT
CASING
Figure 6-5. Open-Hole Completion.
Source: Petroleum Extension Service. University of Texas. A
Primer of Oilwell Drilling, 3rd ed. Austin, TX:
University of Texas,Petroleum Extension Service, 1970
-59-
-------
VSLL HEAD
PERFOKATtOHS
CAS1XC
SHOE
Figure 6-6. Perforated Casing Completion.
Source: Petroleum Extension Service, University of Texas.
A Primer of Oilwell Drilling, 3rd ed. Austin, TX:
University of Texas, Petroleum Extension Service, 1970
-60-
-------
At the wellhead, the tubing is attached to a series of
valves which regulate the flow of oil from the well. These
valves are known as the "Christmas tree." In those wells where
there is danger of wellhead damage (such as in seismically active
areas), a valve is placed near the bottom of the production tub-
ing string. This downhole safety valve, commonly called a Storm
Choke (the trade name for one brand), is designed to close when
the flow through the valve exceeds a set limit. Recent modifi-
cations have made these valves much more reliable than earlier
versions, which were responsible for some serious accidents.
Once the well has been completed, the crude oil is forced*
into the well by either of two reservoir forces: depletion
drive or water drive.1 Depletion drive causes the oil movement
when the reservoir is closed; that is, the hydrocarbons are not
in contact with a large body of water-bearing sand. Expansion
of the hydrocarbons and other reservoir materials that occurs
as the fluid is removed furnishes the energy to force the crude
oil into the well. This depletion drive in an oil reservoir
can be of two types: solution-gas drive and gas-cap drive.2
In the solution-gas drive, a gas is dissolved in the oil
providing pressure. In the gas-cap drive, the oil reservoir
has a pocket of gas trapped above it. This pressurized gas
forces the movement of the oil.
In a reservoir with water drive, the oil is in contact with
a large body of water. The water is free to move into the reser-
voir and displace the hydrocarbons as they are withdrawn; thus,
the reservoir pressure remains essentially constant. Since the
water in this type drive has a greater displacement efficiency
1 Petroleum Extension Service, University of Texas. Field
Handling of Natural Gas, 3rd Edition. Austin, Texas: University
of Texas, 1972.
2 Ibid.
-61-
-------
than the gas in the depletion drive reservoirs, the oil recovery
from a water drive reservoir is usually significantly higher
than from either of the depletion drives. Optimistic recovery
from a depletion drive may be 50-60 percent of the oil in place,
whereas recovery from a water drive may be around 75 percent. :
An example of a water drive reservoir is shown in Figure 6-7.
Production
Once the oil is in the well it must be brought to the well-
head. This is accomplished by one of three methods: natural
flow (if reservoir pressure is great enough), plunger lift, or
gas lift. Natural flow is the process by which either the
depletion or water drive is sufficient to push the oil to the
surface. Natural flow involves no prime mover and hence gene-
rates no emissions and effluents other than fugitive losses
characteristic of hydrocarbons in the crude oil.
Plunger lift, which includes the sucker-rod or submersible
pump, and gas lift will require a prime mover for either pumping
or compressing. A list of available prime movers is shown in
Table 6-28. The electric motor is the most convenient, and it
is emission free. Electricity may not be available, however,
in which case internal combustion-type engines are used. Common
fuels used in internal combustion-type engines are natural gas,
refinery gas, liquified petroleum gases (butane and propane),
diesel fuel, and light fuel oils. Direct well natural gas which
contains heavier hydrocarbons or gases which contain over two
percent sulfur are not suitable. 2 Most fuels require some
Petroleum Extension Service, University of Texas. Field
Handling of Natural Gas, 3rd Edition. Austin, Texas: University
of Texas, 1972.
2Frick, Thomas C. and R. William Taylor, Editors. Petroleum
Production Handbook, 2 Vols. New York: McGraw-Hill, 1962.
-62-
-------
Original Conditions
Figure 6-7.' Water-Drive Reservoir.
Source: Petroleum Extension Service, University of Texas.
Field handling of natural gas, 3rd ed. Austin, TX:
University of Texas,Petroleum Extension Service, 1972
-63-
-------
TABLE 6-28. CLASSIFICATION OF PRIME MOVERS
1. Slow-speed* single-or twin-cylinder two-cycle
gas engines.
2. Slow-speed single cylinder four-cycle gas engines
3. High-speed** multiple-cylinder four-cycle gas
engines.
4. Slow-speed diesel or oil-burning engines.
5. High-speed diesel engines.
6. Electric motors.
*Slow-speed is 750 rpm or less.
**High-speed is 750 rpm or greater.
Source: Frick, Thomas C. and R. William Taylor, eds
Petroleum Production Handbook, 2 vols. NY:
McGraw-Hill, 1962.
-64-
-------
type of on-site storage. The operations which are performed
subsequent to wellhead production are discussed in the proces-
ing section.
Processing
Before the oil can be delivered for refining it must be pro-
cessed to remove undesired components. An overall view of the
processing options is shown in Figure 6-8. First, the oil from
the wellheads is brought together to a central oil-water-gas
separation facility by a gathering system consisting of piping
from the wellheads and a central collection manifold. The sim-
plest gathering system is a direct flow system where oil from
the wells is merely piped to a common manifold and then on to the
separation facility. This system works for wells with essentially
equal producing pressures. If pressures are not equal, a gather-
ing system which provides for pressure reduction before entering
the manifold is employed. If the wells are producing heavy
crudes, and especially if steam injection is being used, the
gathering system may have to be heated by some means such as
steam tracing to keep liquids flowing in the lines.
The brine and oil from the oil field is usually in an emul-
sion form. This emulsion must be broken and the brine content
in the crude reduced to an acceptable level of about two weight
percent. This operation consists of destabilizing the film
between the oil and water droplets, coalescence of the oil drop-
lets, and gravitational separation of the oil and water phases.
The four methods used in dehydrating emulsions are 1) heating,
2) chemical treating, 3) electricity, and 4) gravity settling.
The application of heat to break emulsions is usually an
auxiliary process to speed up separation. A heater is usually
-65-
-------
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used as an integral part of a single vessel in which heating
and treating are both accomplished.l It is sometimes necessary
to use separate heaters in the treatment of certain emulsions,
but this is seldom done.
Chemical treatment is accomplished by the deactivation of
the emulsifying agent that surrounds the dispersed water drop-
lets. The emulsion breaking chemical is soluble in oil and
surface active (work on the surfaces of the water droplets and
cause them to break). Separation is enhanced by the addition
of heat and is completed in some type of gravity settler.
Electricity is often an effective means of breaking an
oil-water emulsion. The crude oil is usually pre-heated and
subjected to a high voltage, alternating circuit electric
field which increases the random motion of the polar water
molecules. The droplets collide with each other with enough
force to coalesce into larger and larger droplets until gravity
causes a separation. The use of electricity means less preheat
and therefore less fuel consumption. An electrostatic treater
is shown in Figure 6-9.
Gravity settling is usually performed in a wash tank. The
wash tank has three parts: 1) a bulk separator for free gas,
2) a bulk separator for free water, and 3) a quiescent tank for
settling of suspended solids and water droplets. The bulk gas
separator is usually a gas "boot" located in the inlet line to
the wash tank. The bulk separator for free water is the lower
Petroleum Extension Service, University of Texas. Treating
Oil Field Emulsions, 3rd Edition. Austin, Texas: University of
Texas, 1974.
-67-
-------
Eject.ri eg 1. .Coalesc'ine" Section
Emulsion Inlet
Water
Outlet
Gas Outlet
Grid Transformer
f
\
Oi
Drain
Water
" Emulsion
Spreader
Drain
Figure 6-9. Cutaway of Electrostatic Treater.
Source: Petroleum Extension Service, University of Texas.
Treating Oil Field Emulsions, 3rd ed. Austin Texas
University of Texas,1974.
-68-
-------
section of the wash tank, while the quiescent tank for settling
of suspended solids and water droplets is the upper section. A
wash tank may be used as a knock-out tank before or after a
heater treater, chemical dehydrator or electrical dehydrator.
A heater treater combines all the various emulsion break-
ing features in one vessel. There are many different kinds of
heater treaters and the selection of the right one for any
given set of conditions is a complex engineering decision. A
typical vertical heater treater is shown in Figure 6-10.
After the brine has been removed to an acceptable level,
the oil and gas are separated. Oil and gas separators are
classified as to the number of stages, the shape, and the number
of phases separated. The number of stages is determined by the
pressure of the incoming oil and gas mixture. For high-pressure
fluids a greater number of stages will be required. Very low-
pressure crudes may be routed directly to a storage tank which
is considered as one stage of oil and gas separation.
Separators are horizontal, vertical, or spherical. The
shape is determined by the oil-to-gas ratio. Horizontal separa-
tors are used for high oil-to-gas ratios, and vertical separators
for low ratios. Spherical separators are used for intermediate
ratios. All three types of separators are shown in Figure 6-11.
Separators are either two- or three-phase units. In two-phase
units only oil and gas are separated, while in three-phase
units, oil, gas, and water are separated. The gases recovered
can be segregated by pressure or by "wetness" ("wet" gases are
those containing condensable hydrocarbons). The recovered gas
is piped to a gas treating plant for further sweetening and
purification. In remote areas, the off-gas may be reinjected
or flared.
-69-
-------
GAS OUT
EMULSION
SIPHON --
FIRE
WATER
OUT
EMULSION OIL
IN OUT
Figure 6-10. Cutaway of Vertical Heater Treater.
Source: Petroleum Extension Service, University of Texas,
Treating Oil Field Emulsions, 3rd ed. Austin, TX:
University of Texas,1974.
-70-
-------
2"-SAFETYPOP
VALVE
MIST EXTRACTOR
CENTRIFUGAL-TYPE
INLET DEFLECTOR
FLOAT
DRAIN
OIL
OUTLET
Schematic diagram of typical spherical two-phase oil and gas separator with
fioat-operated lever-type oil control valve.
FLUID
IN
Schematic diai(rain of typi-
cal vertical twu-pltaae oil and ica«
rparalor.
CASBPV
-J^S >
GAS OUT
FLOAT NOZZLE
VANE-TYPE MIST EXTRACTOR
OIL OUT
-NONWtlGHTED FLOAT
SECTION'A-A'
Schemilic diagram of typical '
INLET SEPARATING
ELEMENT
oil ...d K« «-P
Figure 6-11. Oil-Gas Separators.
Source: Frick, Thomas C. and R. William Taylor, ed. Petroleum
Production Handbook, 2 vols. N.Y.: McGraw-Hill, 1962.
-71-
-------
The final dehydrated and gasified crude is held in surge
or storage tanks to await shipment via pipeline, train, barge,
or tank truck. The most common storage tank is the bolted steel
tank. It can be easily transported, dismantled, and repaired.
Other types of tanks are wooden, welded steel, plastic, and cone-
bottom tanks. A tank battery should contain at least two tanks
and usually have a capacity equal to four days' production.1
With the increase in value of lighter hydrocarbons, the
recovery of these hydrocarbons has become economically feasible.
Installation of floating roof tanks or some type of floating
covers reduces hydrocarbon emissions from tanks. Vapor recovery
systems can also be used to recover vapors but are more expen-
sive than floating roofs. Vapor recovery systems have the ad-
vantage of being able to recover vapors from other sources such
as dehydration or loading facilities. A schematic flowsheet for
a typical vapor recovery system is shown in Figure 6-12.2
If the crude is to be transported by pipeline, the crude
from the storage tanks is transferred by a lease automatic
custody transfer (LACT) system. There are two types of transfer
units: the meter type and the volumetric dump. In the meter
type the oil is deaerated and then run through a metering system
to determine the volume. The volumetric dump determines the oil
volume by alternately filling and dumping calibrated tanks.
:Frick, Thomas C. and R. William Taylor, editors. Petroleum
Production Handbook, 2 Vols. New York: McGraw-Hill, 1962.
2Cavanaugh, E. C. , et al. Atmospheric Environmental Problem
Definition of Facilities for Extraction, On-Site Processing, and
Transportation of Fuel Resources. Austin, Texas: Radian Corpora-
tion, July 1975.
-72-
-------
HEATER TREATER
.REGULATORS
XL
SCRUBBER
COMPRESSOR
CONDENSER,,
DRY GAS
STORAGE
COMPENSATE RETURN LINE
FUEL GAS
FOR
HEATER
TREATER
Figure 6-12. Vapor Recovery System.
Source: Cavanaugh, E.G., et al. Atmospheric environmental prob-
lem definition of facilities for extraction, on-site
processing, and transportation of fuel resources.
Austin, TX: Radian Corporation, July 1975.
-73-
-------
Both units also automatically sample the crude for residual
basic sediment, water content, and oil gravity.*
The water from the dehydrator, knock-out tanks, and three
phase separators, if used, must be further treated before being
discharged as wastewater or reinjected back into the well as
steam injectors or water flooding. The flotation cell, type
wastewater treater is a commonly used primary water treating
facility. This system involves air or gas injection upstream
of the main wastewater process dump. The air and the chemical
coagulants, if required, are thoroughly mixed inside the pump.
The discharge flow from the pump enters the retention tank where
air is dissolved under 2-3 atmospheres of pressure. As the
wastewater enters the flotation cell, the pressure is released
to atmospheric pressure and the air comes out of solution. Small
sludge and oil particles become flotable on the bubbles or foam
and pass to the top where the rotating skimming arm sweeps the
oil sludge into a compartment for removal. The same drive shaft
also rotates a bottom grit scraper arm for the separate removal
of settleable solids to the grit collecting box.
Other possible wastewater treatment methods include sedimen-
tation followed by aeration, aerated lagoons, or evaporation
ponds. The type system employed is determined primarily by the
ultimate use of the wastewater.
If the treated water is to be further used for either steam
generation or water flooding, it must be filtered to remove the
suspended solids. A sand filter or a diatomaceous earth filter
may be used. The solids concentration must be lowered as much
as possible to eliminate particulate buildup in the injection well.
^hilingar, George V. and Beeson, Carrol M. Surface Opera-
tions in Petroleum Production. New York: American Elsevier, T3"69,
-74-
-------
The wastewater must often also be Created for removal of
dissolved HaS. This can be accomplished by one of the following
methods: 1) aeration, 2) vacuum degassing, 3) countercurrent gas
stripping, or 4) chemical treatment.1
Improved Recovery
When the natural flow of the crude oil into the well has
diminished, additional oil may be recovered by the use of various
improved recovery techniques. These techniques are of two gen-
eral types: secondary recovery and tertiary recovery. Secondary
recovery techniques are those which improve recovery by augment-
ing the natural reservoir energy.2 Waterflooding, a secondary
recovery method, is discussed in this section. Two tertiary
recovery techniques are discussed in greater detail in later
sections.
The most common type of secondary recovery is waterflooding.
As was discussed earlier, the natural reservoir drive is caused
by pressure on the reservoir from expansion of gases (depletion
drive). After this pressure has decreased, due to removal of
the crude, it is replaced by a similar pressure induced by in-
jected water. Each well which will continue to produce oil is
encircled by injection wells. These can either be existing wells
which will be converted from producing to injection or newly
drilled wells specifically for injection. Water is then injected
into the reservoir through the injection wells. As the water
OR
El
1Chilingar, George V. and Beeson, Carrol M. Surface
erations in Petroleum Production. New York: American
sevier, 1969.
2Thermal Recovery Handbook, Reprint. Oil and Gas Journal.
Tulsa, Oklahoma: Petroleum Publishing, ~
-75-
-------
flows through the reservoir it pushes the oil out of the pore
spaces where it had been trapped and into the producing well.
Generally, waterflooding requires injection of several barrels
of water for each barrel of oil recovered, the amount dependent
on the nature of the reservoir. A typical waterflooding system
is shown in Figure 6-13.
Present oil field recovery practices usually employ a
recovery technique, like waterflooding, followed by an enhanced
method such as steam injection or C02 miscible, the two tech-
niques discussed later. In the future it may become economically
feasible to incorporate enhanced recovery methods earlier in the
life of an oil field.
6.4.1.1 Input Requirements
For the following analysis, a total crude oil production
of 100,000 barrels per day was chosen. The site of this opera-
tion is assumed to be in Rio Blanco County, Colorado. Each well
is assumed to produce 250 BPD of crude oil requiring a total of
400 wells. The construction of the 100,000 BPD facility is
scheduled to last seven years. All 400 wells are scheduled to
be on line by the end of the seventh year.
The module for oil production is based on one gathering
system fed by several oil wells. The wellheads are the plunger
lift type equipped with primer movers which operate on electric-
ity. From the gathering system, the oil-brine emulsion is fed
into a water knock-out tank. To enhance the oil-water separation
in the knock-out tanks, the oil-brine emulsion is pretreated in
a heater treater which destabilizes the emulsion. The light
-76-
-------
.Wfllir t1abil!:at!on and
( clariricelien lank Filler
Surge tank /
Figure 6-13. Waterflood Secondary Recovery System.
Source: U.S. Bureau of Mines. Potential Oil Recovery by
Waterflooding Reservoirs Being Produced by Primary
Methods, I.C. 8455.' Washington, B.C.: Bureau of
Mines, 1970.
-77-
-------
hydrocarbon gases are then removed in an oil-gas separation
section consisting of three spherical separation tanks operating
at progressively decreasing pressures. The released gas is
sent directly to a gas treating plant.
The brine from the emulsion breaking system is combined
with the brine from the water knock-out tank and run through a
flotation cell wastewater treater. The flotation cell treater
removes sludge, grit, and oil particles from the wastewater.
The treated water is used for either steam generation or water
flooding. It must be filtered to remove the suspended solids.
The solids concentration is lowered as much as possible to
eliminate particulate buildup in the injection well. A sand
filter is normally used for this purpose. The water is also
treated for removal of dissolved H2S, which contributes to cor-
rosion in the pipes and machinery, and which is an atmospheric
emission problem. H2S removal from the wastewater is usually
accomplished by countercurrent stripping, with the offgas being
routed along with the associated gas to a nearby gas treating
plant.l
The storage facility for crude oil from the separation unit
is equipped with a vapor recovery system. The vapor recovery
system is also tied in with the heater treater to capture any
vapor emissions from that unit. The crude oil is transferred
from the storage tanks to the pipeline by a lease automatic
custody transfer pumping system. This unit also automatically
^hilingar, George V. and Carrol M. Beeson. Surface
Operations in Petroleum Production. New York: American Elsevier
1969.
-78-
-------
samples the crude for analysis of sediment, water content and
oil gravity.
In addition to the descriptions of primary production the
injection system for waterflooding consists of a central high-
pressure water pump and a distribution system. Waterflooding,
where described, is based on 10 percent of the total production
(10,000 bpd).
The flow sheet for this oil production operation is shown
in Figure 6-14.
6.4.1.la Manpower Requirements
Construction
The construction of the 100,000 bpd oil producting facility
is scheduled to take 7 years. The required manpower for this
construction is shown in Table 6-29. l Manpower is required for
drilling the 400 wells and the 300 dry holes, as well as for the
construction of gathering, separation, and reinjection facilities
Each well produces 250 barrels per day. A great deal of engi-
neering manpower is required to make all the construction possi-
ble.
Operation and Maintenance
The schedule of required manpower for operation and
maintenance of the 100,000 bpd crude oil operation is shown in
^arasso, M. , et al. Energy-Supply Model, Computer Tape
San Francisco, California: Bechtel Corporation, 1975.
-79-
-------
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begin during construction year 4 and that required manpower in-
creases in subsequent years as more wells start producing. The
manpower shown for the seventh year represents requirements for
the full 100,000 bpd production and should remain relatively con-
stant in the subsequent years.
6.4.1.1b Materials and Equipment
A schedule of the needed materials and equipment for the
seven years of construction is shown in Table 6-31.
6.4.1.1c Economics
Construction
The total capital cost of the seven year construction pro-
ject is estimated at $2,040 million (third quarter 1974 dollars).
This estimate excludes owner's costs (land costs, interest during
construction, etc.). A schedule of these construction costs is
shown in Table 6-32.2
Operation and Maintenance
The estimated annual operation and maintenance costs.start-
ing in year 4, when the first wells become operational, are
'Carasso, M. , et al. Energy Supply Model, Computer Tape
San Francisco, California: Bechtel Corporation, 1975-
2 Ibid.
-82-
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are shown in Table 6-33 to be $18 million.1 This cost should
represent the cost of operation and maintenance for the life of
the field and remain fairly constant in 1974 dollars.
6.4.1.Id Water Requirements
The facility considered in this report will have no water
requirement if waterflooding is not used. Since the produced
oil contains a significant quantity of brine (connate water) and
there are no significant uses of water in primary production,
there will be an excess of water and a disposal problem (see
Section 6.4.1.2b), but no water needs. Water needed, in the
drilling process for the drilling mud was discussed in Section
6.3.2b.
If waterflooding is used to a significant extent as a
recovery technique, there is definitely a need for additional
water. A case study has been developed to show the requirements
for the example 100,000 barrel per day field. The total addi-
tional water requirement has been calculated as a function of
the connate water (brine) produced with the crude oil. Table
6-34 reports water requirements for crudes containing 1070. 20%,
and 30% free water. Although these values are in the range
which might be expected from these assumptions, they are subject
to wide variation and are used as inputs to a water balance
only to show possible water needs. The water balance assumed
that all water produced with the crude oil is treated and used
as make-up in the waterflood program.
^arasso. M. , et al. Energy Supply Model, Computer Tape,
San Francisco, California: Bechtel Corporation, 1975.
-86-
-------
TABLE 6-33. SCHEDULE OF MATERIALS AND EQUIPMENT RESOURCES
(MILLION DOLLARS, THIRD QUARTER 1974) REQUIRED
FOR OPERATION AND MAINTENANCE OF ONSHORE OIL
PRODUCTION (100,000 bpd)
Resources Cost ($ million)
Metal Products 3
Non-Electrical Machinery 2
Electrical Equipment 1
Transportation Equipment 5
Instruments and Controls 1
Miscellaneous 6
GRAND TOTAL 18
Basis: 400 wells producing 250 bpd each.
TABLE 6-34. WATER REQUIREMENTS FOR SECONDARY RECOVERY
Water in crude, vol %
Waterflood injection rate,1
bbl H20/bbl oil recovered
Water production, bbl/day
Additional water requirement
acre-ft/yr
^hilingar, George V. and Beeson
Case I
10
10
11,000
4,175
, Carrol M.
Case II
20
10
25,000
3,520
Surface
Case III
30
10
43,000
2,675
Operations
in Petroleum Production. New York: American Elsevier, 1969.
-87-
-------
6.4.1.1e Land Usage
Total permanent land usage for an oil field with a capa-
city of 100,000 barrels per day is approximately 2000 acres.
This assumes five acres per well for cleared area around pro-
ducing well, pipeline right-of-ways, separation facilities,
and roads.l Another estimate of the amount of land required
for the oil production is 0.06 acres per 106 Btu/hr.2 For a
crude oil heat content of 5.6 x 106 Btu, 1400 acres would be
required for the 100,000 bpd operation. The reservoir is esti-
mated to be 20 square miles with assumptions for depth of for-
mation, nature of formation, life of field, etc. This is an
average well spacing of 32 acres.
6.4.1.If Ancillary Energy
Energy in the example 100,000 bpd oil field is consumed
in two major areas: the heater treaters and the prime movers
of the oil. Table 6-35 lists energy requirements for a typical
heater treater system of a field this size as a function of the
amount of brine produced with the crude oil. Electricity powers
the plunger pumps at the wellhead as well as other miscellaneous
pumps. Assuming a value of 20 hp for the average electric motor,
a daily power consumption of approximately 150,000 kilowatt-hr
is realized. Converted to heat equivalents, this energy is
about 500 million Btu/day.
federal Power Commission. National Gas Survey, Vol. II.
Washington, D.C.: Federal Power Commission,1974, pp.73-75.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus and Pacific Northwest Laboratories,
1973.
-------
TABLE 6-35. HEATER TREATER ENERGY REQUIREMENTS*
Heat Requirements
Brine Vol % (Btu/day)
5 3.67 x 109
50 1.88 x 1010
85 4.20 x 1010
Fuel Gas Requirement
(scf /day)
3.67 x 106
1.88 x 107
4.20 x 107
Basis: 100,000 bpd crude oil production.
^Scaled up from values reported for 1000 bpd production.
Source: Cavanaugh, E. C., et al. Atmospheric Environmental
Problem Definition of Facilities for Extraction, On
Site Processing, and Transportation of Fuel Resources
Contract No. 68-02-1319, Task 19.Austin, TX:
Radian Corporation, July 1975.
-89-
-------
If improved recovery techniques are used in addition ~to the
primary production, there are additional ancillary energy needs
for the large waterflooding pumping system required. It is
assumed that 10 gallons of injection water are required per
gallon of oil recovered.1 The injection rate for 10,000 bbl/
day crude oil production should be about 3000 gpm. The injection
pressure required is around 1500 psig. From these data it was
determined that the module would require a 4000 hp pumping system.
The pump was assumed to have a diesel drive which consumes 1920
gallons of diesel fuel per day. The total energy required is
3.4 x 108 Btu/day.
6.4.1.2 Outputs
The outputs described below are based on a total production
of 100,000 bpd of crude oil. The process design and other
parameters are the same as those described in Section 6.4.1.1
for the Input Requirements. The operations considered here have
a total crude oil output of 100,000 barrels per day. The crude
oil produced for these operations in Rifle, Colorado, is assumed
to be identical to the crude produced from the Rangely field in
Rio Blanco County, Colorado. The detailed analysis of this
crude oil is shown in Table 6-36. For a heat content of 5.6 x
106 Btu/bbl, the energy output of the production facility is
5.6 x 10J1 Btu/day.
6.4.1.2a Air Emissions
The air pollutants from the 100,000 bbl/day primary
production operation are emitted from the following sources:
^hilingar, George V. and Beeson, Carrol M. Surface Opera-
tions in Petroleum Production. New York: American Elsevier,
1969.
-90-
-------
TABLE 6-36. CRUDE OIL ANALYSIS - RANGELY FIELD,
RIO BLANCO COUNTY, COLORADO
Tests
Gravity, °API 34.8
Gravity, Specific 0.851
Viscosity, SUS @ 100°F 48.0
Pour Point, °F +10
Color Greenish black
Sulfur, wt % 0.56
Source: McKinney, C. M., E. P. Ferrero, and W. J. Wenger.
Analyses of Crude Oil from 546 Important Oilfields
in the United States, R.I. 6819.Washington, D.C.
Bureau of Mines, 1966.
burning of fuel (natural gas) in heater treater, crude oil
storate tanks, fugitive losses from various sources, and
intermittent flaring due to unusual conditions. The use of
waterflooding requires an extensive pumping system whose
diesel engines produce additional emissions. Table 6-37 pre-
sents a summary of most emissions from the crude oil production
module.
The heater treaters associated with the separation equipment
contain a direct-fired heater which burns a natural gas with
about 2000 ppm total sulfur. The crude emulsion is preheated
by the exit crude oil, and the treater is operated at 210°F.
The emission factors for fuel gas combustion are given in
Table 6-38. The heat requirements are given in Section 6.4.1.If.
-91-
-------
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-92-
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TABLE 6-38. AIR EMISSION FACTORS FOR THE COMBUSTION OF NATURAL
GAS AND FUEL OIL
.._ «' ' - -- ' j-- ,-_-gg^._ _f_ . _._ - ,.-,.ig... J-I...J i-.-^,-f-
Natural Gas Fuel Oil
lb/1000 scf lb/1000 bbl
Particulates
Sulfur Oxides
CO
Hydrocarbons
(as S02)
Nitrogen Oxides (as N02)
Aldehydes (as
HCHO)
0.02
2V
0.017
0.027
0.23
0.003
970
6,729 SQ**
0.168
126
1,680
42
* S is the sulfur concentration in the fuel gas (lb/1000 ft3)
&
**S is the sulfur weight fraction in the fuel oil.
Source: Cavanaugh, E.G., et al. Atmospheric Environmental
Problem Definition of Facilities for Extraction,
On-Site Processing, and Transportation of Fue^
Resources"! Contract No. 68-02-1319, Task 19.
Austin,TX: Radian Corporation, July 1975.
-93-
-------
Fugitive and miscellaneous emission factors are shown in
Table 6-35. These are emissions from wastewater separation,
seals, and valves. Also miscellaneous flaring is estimated
to occur at the rate of 2 x 10 5 bbl flared/bbl oil produced.1
Two assumptions for storage emissions are the use of float-
ing roof tanks and storage of six days production. Using the
UFA emission factor for storage of 0.029 lb/day-103 gal,2 a
hydrocarbon emission of 30.5 Ib/hr is calculated.
The primary source of additional emissions from waterflood-
ing is the sizable water injection pump system. The injection
rate of 10 bbl water/bbl oil recovered for the 10,000 bbl
additional production is 3000 gallons/min. It is determined
from this rate that a pumping system requiring 4000 horsepower
consuming 1920 gallons of diesel fuel daily is needed. Table
6-40 presents the waterflooding contribution to the total
emissions.
6.4.1.2b Water Effluents
The amount of water effluent from an oil field depends on
the percent water produced with the crude oil and on the extent
that water is used in secondary recovery techniques. Many
fields have no effluent due to the reinjection into the formation
'Battelle Columbus and Pacific Northwest Labs. Environmental
Considerations in Future Energy Growth. Columbus, Ohio:Battelle
Columbus and Pacific Northwest Labs., 1973.
2Environmental Protection Agency. Compilation of Air
Pollution Emission Factors, 2nd Edition with Supplements, AP-42
Research Triangle Park, North Carolina: Environmental Protection
Agency, April 1977.
-------
TABLE 6-39. MISCELLANEOUS OIL PRODUCTION EMISSION FACTORS
Hydrocarbon Emissions
tons/day*lb/10J bbl
Wastewater Separation 0.2 7.9
Pump Seals 1.9 73.8
Compression Seals 0.1 3.8
Relief Valves 0.2 7.9
Pipeline Valves 0.3 11.6
*Based on a production rate of 50,600 bbl/day.
Source: MSA Research Corporation. Hydrocarbon Pollutant
Systems Study, Vol. 1, Stationary Sources, Effects
and Control. PB-219-073, APTD 1499.Evans City,
PA: MSA Research Corporation, 1972.
TABLE 6-40. WATERFLOOD OPERATION CONTRIBUTION TO
TOTAL EMISSIONS
Emission
Particulates
SOX
CO
Hydrocarbons
NOX
CO 2
Source: Cavanaugh, E. C., et
Problem Definition of
Site Processing, and
Ibs/day
25
52
432
77
710
41,150
al. Atmospheric Environmental
Facilities for Extraction, On-
Transportation of Fuel Resources
-95-
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of all water produced; however, some fields will have a net
effluent which will impact the surface water system locally.
Table 6-41 presents available data on the quantity of pollutants
from an oil production operation.
6.4.1.2c Solid Wastes
No appreciable solid wastes are produced by the example
oil field.
6.4.1.2d Noise
Several pieces of equipment in the oil field are potential
emitters of significant noise levels. These include control
valves and pump engines. Most noise would be centered around
central storage areas and waterflood injection pumping facilities.
Perceptible noise should not be heard outside the boundaries of
the facility.
6.4.1.2e Occupational Health and Safety
The information for this section is included in Section
6.3.3e.
6.4.1.2f Odor
Odor may be a problem around the oil-gas separators and the
storage tanks where fugitive emissions from leaks, valves, flanges,
etc. may occur. If the crude contains appreciable sulfur com-
pounds (HaS, mercaptans) odor problems are more likely. Good
housekeeping practice is the best safeguard against odor.
-97-
-------
6.4.2 Enhanced Oil Recovery
Enhanced oil recovery is generally defined as fluid injection
techniques other than natural gas and waterflooding that augment
a reservoir's ability to produce oil. Enhanced oil recovery dif-
fers from primary and secondary oil recovery in that the recovery
technique is aimed at altering the forces trapping the oil in the
porous rock. Secondary recovery maintains the pressure driving
forces extant during primary recovery. Like primary and secondary
recovery, enhanced oil recovery also mobilizes oil by means of a
hydrodynamic pressure gradient that will be described in the fol-
lowing paragraphs.
Following a waterflood, the oil remaining in the reservoir
exists as dispersed oil droplets or globules in water. The amount
of oil remaining after a waterflood is generally 50 to 65 percent
of the original-oil-in-place (OOIP). The oil droplets are trapped
within the pores and channels of the formation and held in place
by both capillary and viscous forces.
If the interfacial tension between the oil and water is re-
duced sufficiently, then the forces due to water pressures will
overcome the capillary forces and move the oil droplet. In the
situation where oil is trapped by viscous forces, reducing the
oil viscosity will allow the droplet to flow at a lower water
pressure. Once droplets move by either of these methods, they
coalesce with other droplets and form an oil bank that moves
through the reservoir.
There are two enhanced recovery techniques which are cur-
rently being used on full scale operations. The most successful
method to date, steam flooding, utilizes the viscosity reduction
principle. The other technique is C02 miscible flooding which
-98-
-------
displaces oil by eliminating the oil/water interfacial tension.
This technique is discussed in Section 6.4.3. Other enhanced
recovery techniques are currently being developed; however, these
two methods have been the most successful to date.
These two recovery methods will be discussed with regard to
the technology involved, raw material and equipment regulations,
and pollutant emissions. Since enhanced oil recovery is currently
at the early stages of commercialization, there are only a limited
number of projects from which data are available. Some of these
data are highly site specific and therefore difficult to repre-
sent with a "typical value". In this report, every attempt has
been made to present data which is representative of the processes
involved. Calculations were made on a consistent basis through-
out the sections and existing data were converted to this basis.
However, due to site-to-site variations and future technological
innovations, it may be difficult to apply the data presented
herein on a general basis. Calculations for both steam flooding
and CO2 flooding were made using the same basic assumptions.
The inputs and outputs sections contain several calculated
values based on a hypothetical "example reservoir". This was
done to put the input and output quantities on a consistent basis.
It is assumed that the rate of oil production can be represented
by some average number. This was assumed to be 100,000 bbl/day.
It is also assumed that oil will be produced at this average rate
for 5 years. Assumptions that pertain to the reservoir are
Reservoir Pore Volume = 2.85 x 109 Bbls
(Volume of the formation that is filled
with gas and liquid)
Porosity = 3070
(Fraction of the formation that is filled
with gas and liquid)
-99-
-------
Initial Oil Saturation =0.64
(6470 of pore volume is oil)
Average Thickness = 100 ft.
Surface Land Area =19.1 square miles
Literature values indicate the first two assumptions are typical
values for real fields.l
A recovery efficiency of 40 percent was assumed for the
waterflood and a literature source showed 10 percent to be an
average recovery efficiency for enhanced recovery techniques.2
These literature values and assumptions can be used to calculate
the following values for the oil contained in the example reser-
voir .
After After Enhanced
Initial Waterflood Recovery Method
Oil Saturation, bbls/acre-ft 1500 900 750
Oil Saturation, relative 0.64 0.41 0.32
BBls of Oil in the Reservoir 1.83 x 10* 1.10 x 10s 9.15 x 108
Recovery Efficiency, % of OOIP 40 10
6.4.2.1 Steam Flooding
6.4.2.1.1 Technologies
Steam flooding or steam displacement comes under the category
of thermal displacement in which there are two other displacement
techniques. These other techniques are cyclic steam injection and
^evanney, J. W., et al. "The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil," EPA Contract No.
68-01-2445, May 1975.
2Ibid.
-100-
-------
in-situ combustion. Steam flooding is currently the most suitable
technique of the three since it has a better oil recovery effi-
ciency than cyclic steam injection and has been more commercially
developed than in-situ combustion. Steam flooding lowers the
viscosity of the oil and allows it to flow at a lower pressure.
Oil viscosity is very sensitive to temperature. Generally speak-
ing, the kinematic viscosity will decrease exponentially as the
temperature is increased linearly. For example, at 300°F a 15"API
oil will have a viscosity similar to that of a 30°API oil at nor-
mal reservoir temperatures.1 Crude oils are generally referred
to as being a certain gravity rather than viscosity. This term-
inology will be used in subsequent discussions of viscosity.
Not all reservoirs are amenable to steam flooding. The
reservoir characteristics necessary for a successful steam flood
have been reported to be:
low API gravity crude oil (10-20° API)
high permeability (>500 md)
shallow depth (<3000 ft)
Most of the reservoirs suitable for steam flooding are in
California, Texas, and Louisiana. However, there are several
field tests being conducted in Wyoming as can be seen in
Figure 6-15.
JDevanney, J. W., et al. The Estimated Recovery Potential
of Conventional Source Domestic Crude Oi.T', EPA Contract No.
68-01-2445.May 1975.
-101-
-------
I
BOWES (S)
MONTANA
FOUR BEAR(I)
BUFFALO BASIN (\ )
WARM SPRINGS (S)
WINKLEMAN (S)
S* STEAM
I =IN SITU COMBUSTION
50 0 50 100 ISO
SCALE, MILES
/HALF MOON(S)
2/,PITCHFORK(S)
rCONOITOOME
RED SPRINGS (S)
°6
LA BARGE(S)
LAK RANCH(S)
NEW CASTLE(S)
N.TISDALE (I )
SHANNON (I )
DIAMOND BACK (S)
OIL MTN (S)
BOLTON CREEK (S)
Figure 6- 15.
Sites of Thermal Recovery Field Tests
in Montana and Wyoming.
-102-
-------
In a typical steam flooding operation, surface water is
passed through a boiler where it is heated to a sufficient pres-
sure to allow it to enter the reservoir. The steam is saturated
at this pressure and is generally about 70 to 80% quality.1 After
entering the reservoir, the steam condenses due to heat loss
through conduction into the formation rock and fluids. It is
this latent heat of vaporization that is primarily responsible
for increasing the temperature of the surrounding oil and water.
At the increased temperature, the viscosity of the oil is reduced
sufficiently to allow it to be displaced. As the frontal edge of
the steam flood passes through the reservoir, the oil and water
cool allowing the viscosity to increase. However, the oil satur-
ation2 at this frontal edge has been increased by the oil that
was displaced initially. The cooler water is still capable of
displacing the oil at this increased saturation and what oil is
left trapped is mobilized by the hot water following the frontal
edge. Figure 6-16 is a schematic of the steam flooding process.
Typically, a steam flood will displace 10 percent of the
OOIP over and above that produced by a waterflood. Steam can be
introduced into the reservoir either before a waterflood has
*
been conducted or before. If, in the future, steam flooding be-
comes well established technology it will probably be used prior
to waterflooding. This would allow more oil to be produced with
less total water. In either case, the costs and equipment re-
quired for steam flooding are similar to those for waterflooding
with the addition of water treatment and steam generation facil-
ities. It is necessary to install steam generators at or near
the injection wells. An oil field will require several generators
to provide the steam requirements. The types of generators in
quality is defined as the weight fraction of vapor.
20il saturation is defined as the fraction of the reservoir
pore volume that contains oil.
-103-
-------
4J
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use today are package boilers with capacities ranging from 20 to
50 million Btu/hr. They are fired with oil produced from the
field. Generally, about 30 percent of the oil produced by a
steam flood is consumed by the steam generators.
A 25 million Btu/hr steam generator will require 1000 barrel
raw and treated water tanks. Water treatment is required for the
boiler feed water to prevent tube scaling and the size of the
treatment equipment will depend on the quality of the available
water. The water produced by the well will also require treat-
ment whether it is to be reinjected or discharged. Water rein-
jection will require less total surface water, but probably will
also require a higher level of water treatment than surface water,
At the production wells, the operations are similar to
those of waterflooding. The produced gas/oil/water mix is pro-
cessed to separate the phases and break the emulsion. The de-
gassed, dewatered oil is sent to storage tanks and the water is
sent to the water treatment section prior to discharge or rein-
jection.
6.4.2.1.2 Inputs
6.4.2.1.2.a Manpower Requirements
Manpower will be required to install boilers and feed water
treatment facilities. Steam flooding has not been applied exten-
sively enough to date for accurate quantitative estimates to be
made. It is likely that construction manpower requirements will
be similar to those for waterflooding. A first approximation
might be 4000 total man-years for 2-3 years.
The manpower requirements for operation of a steam-flooding
operation will be only slightly higher than those for water
-105-
-------
flooding. These were indicated in the section on conventional
recovery to be about 2000 man-years/year. For a steam flood,
the operating manpower requirement is estimated to be 2000 man-
years/year for 5 years.
6.4.2.1.2.b Materials and Equipment
Essentially, the materials and equipment necessary for a
waterflooding operation will also be required for steam flooding.
An exception would be the high pressure pumps used to inject
water which would be replaced by steam injection equipment. The
water supply, production, treating, and storage equipment associ-
ated with waterflooding will be necessary for a steam flood. In
addition, feed water treatment and steam generation equipment
will be necessary.
Consider the steam generation equipment first. Package
steam boilers with capacities ranging from 20 x 106 to 50 x 106
Btu/hr are most common. Larger boilers, up to 250 x 106 Btu/hr,
are available, but create the problem of losing a large portion
of the generating capacity when a single unit goes down. The
smaller units allow a single boiler to go out of service without
significantly affecting the overall steam capacity. The boilers
are essentially smaller versions of watertube boilers used in
steam generation for electrical production. The boilers are de-
signed to operate on crude oil and produce steam of a suitable
quality for injection. Generally, the steam quality is 80 per-
cent. A typical oil field boiler is shown in Figure 6-17. There
are several boilers distributed over the oil field, each serving
one or more injection wells.
By making a few assumptions the boiler density in an oil-
field can be calculated. The assumptions are:
-106-
-------
Figure 6-17. Oil Field Steam Generator.
-107-
-------
2000 psia steam
1 bbl of oil produces 45 barrels of steam
one bbl of oil burned for each 3.33 bbl produced1
oil saturation - 900 bbl/acre-ft
recovery efficienty 10 percent
steam injection rate = 2500 bbl/acre-ft/year2
These values indicate a steam requirement of 1 x 106 Btu/hr per
acre or 1 boiler for every 20 to 50 acres. For the example
reservoir this amounts to a total from 250 to 650 boilers with
the actual number depending on boiler size.
Water used for steam generation must be used to prevent
scale formation on the boiler tubes. Water treatment facili-
ties will probably consist of softening equipment and ion ex-
change equipment. An estimated 120 gal/hr/acre of water treat-
ment capacity is required (equivalent to 5 bbl H20/bbl oil pro-
duced) . Additional water treatment facilities may be required
if water produced with the oil is either discharged or reinjec-
ted.
lln this, and all other references to steam volume in this
section, the indicated volume will be the actual volume occupied
by 80 percent quality steam at 2000 psia.
2This assumption is slightly higher than values used typic-
ally for analyses of steam flooding. This is due to the fact
that recent articles have indicated that steam floods have not
been as productive as was originally anticipated.
-108-
-------
6.4.2.1.2.c Economics
The economics of steam flooding are tied to the price of
crude oil. In the previous section it was assumed that 3.33
bbls of oil will be produced for each bbl burned. Since about
30 percent of the oil produced is consumed by steam generation
the cost of the steam is strongly related to the price of crude
oil. As the price of crude rises, the process becomes more
economical. This can be seen in the following analysis.
There are three major costs associated with steam flooding:
flooding costs, steam generation costs, and fuel costs. Flooding
costs are the typical combination of costs involved in operating
a steam flood. These include well workover, well maintenance and
fluid distribution. They range from $0.50 to $1.50 per barrel of
oil produced.l The capital and operating costs of the steam gen-
eration equipment are also important. These are generally $0.013
to $0.020 per bbl of steam and include the cost of the steam gen-
erator, boiler maintenance, and water treatment.2 Finally, there
is the cost of the oil burned in the steam generator. Since this
is a variable, two cases are considered here: $3 per bbl and
$10 per bbl. Of course, the cost of the oil produced is going
to be affected by the amount of steam injected. Table 6-42 shows
the cost of producing a barrel of oil as a function of fuel costs ,
flooding costs and steam:oil ratio (bbl/bbl). The values presen-
ted in the table reflect the fact that oil burned in steam gener-
ation must be subtracted from the amount produced in order to in-
dicate the real cost per standard tank barrel. These costs are
plotted as a function of steam:oil ratio in Figures 6-18 and 6-19.
^evanney, J. W., et al. The Estimated Recovery Potential
of Conventional Source Domestic Crude Oi^l, EFA Contract No.
68-01-2445.May 1975.
2Ibid.
-109-
-------
12 i
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High Flooding Costs
Low Flooding Costs
20
Figure 6-18.
40 60
Steam:0il Ratio (Bbl/bbl)
Cost/Standard Tank Barrel of Oil
For Steam Flooding.
Basis: Price of Oil - $3/Bbl
80
100
-110-
-------
12-1
High Flooding Costs
Low Flooding Costs
0
20 40 60
Steam:0il Ratio (Bbl/bbl)
Figure 6-19. Cost/Standard Tank Barrel of Oil
For Steam Flooding.
Basis: Price of Oil = $10/Bbl
100
-111-
-------
Figure 6-18 considers oil at $3/bbl while Figure 6-19 is based
on the price of oil being $10/bbl. It can be seen from the
figures that the breakeven steam:oil ratio in the $3/bbl case
is about 26 to 44 bbl/bbl. With $10/bbl oil the breakeven ratio
is about 58 to 64 bbl/bbl indicating that steam flooding is more
profitable at higher crude prices. In addition, higher crude
prices allow a more rigorous recovery operation to be conducted
since higher steam:oil ratios may be economically applied.
TABLE 6-42. COST OF OIL RECOVERED BY STEAM FLOODING
Fuel Cost Flooding Costs
$/bbl $/bbl produced
3 0
3 1
10 0
10 1
.50
.50
.50
.50
Total Cost
at Various
1
3
3
4
30
.99
.24
.68
.92
3
4
6
8
per Standard Tank Barrel1
Steam:0il Ratios (Bbl/bbl)
50
.45
.96
.81
.30
5
7
11
13
70
.61
.50
.45
.28
9
11
18
21
90
.11
.61
.94
.35
6.4.2.1.2.d Water Requirements
The water requirement can also be calculated from the steam
injection rate and a feedwater requirement of 120 gal/hr/acre is
indicated. This results in a feed water requirement of about 5
bbl of water per bbl oil produced. This value is consistent with
recent estimates of water requirements of 1 to 6 bbl of water per
bbl of oil.2 The actual quantity of water used will depend on the
steamtoil ratio required for a successful displacement. Therefore,
*A "Standard Tank Barrel" refers to oil that has production
and oil field treating operations. Due to losses in these oper-
ations only part of bbl that is produced appears in the product
tank.
2U.S. Congress, Office of Technology Assessment. Enhanced
Recovery of Oil and Devonian Gas. June 1977.
-112-
-------
water usage for steam generation can vary from field to field.
It is possible to treat produced water and use it to produce
steam. Produced water requires more treatment than surface
water and, for this reason, would probably not be used unless
shortages of surface water existed. For the example reservoir,
without reinjection of produced water, the total water require-
ment would be 9 x 108 bbl for the 1.85 x 108 bbls of oil pro-
duced by the steam flood.
Water requirements for uses other than steam generation
are assumed to be small in comparison to those for steam
generation. For this reason, ancillary water requirements were
not quantified.
6.4.2.1.2e Land Usage
Land usage in steam flooding will be similar to that necessary
for waterflooding. This will include areas for steam generators,
water treatment, fluid distribution, and product treatment. The
steam generators will be distributed over the entire oil field
to allow injection at various locations with a minimum of high
pressure piping. Water and product treatment will most likely
be performed at single locations rather than using several smaller
units.
Land usage will be affected by the disposal technique used
to handle the produced water. One option is to treat the water
sufficiently to allow discharge. Alternatively, produced water
can be treated less rigorously and sent to an evaporation pond.
Use of evaporation ponds will require more land area than treat-
ment and discharge. The applicability and size of evaporation
ponds will depend upon the environmental conditions existing at
each oil field location but over the range of evaporation rates
typical in the west will be between 20 and 80 acres/Mbbl
evaporated/day).
-113-
-------
6.4.2.1.2f Ancillary Energy
Steam flooding is a very energy intensive process primarily
due to the high energy requirements of steam generation. Ancil-
lary energy requirements other than steam generation will be
similar to those of waterflooding. Most of these are associated
with the heater treaters. On the basis of waterflood heater
treater requirements and the production values presented in the
previous sections, the energy requirements are about 10s Btu/hr
per reservoir acre. This is about 10% of the steam generation
energy requirements.
6.4.2.1.3 Outputs
The example reservoir described at the beginning of the
inputs section will also be used as a basis for calculations in
this section.
6.4.2.1.3a Air Emissions
Air emissions of criteria pollutants will come primarily
from the boilers and heater treaters. There will also be some
fugitive emissions from well heads, oil/water separators, valves,
pumps, and storage tanks.
Air emissions from steam generators have been reported in
the literature1'2 and these are presented in Table 6-43. Several
assumptions were made in order to arrive at the numbers shown in
the table. A fuel sulfur content of 1.23 wt % was assumed. This
^evanney, J. W., et al. The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil,EPA Contract 68-01-
2445. May 1975.
2U.S. Congress, Office of Technology Assessment. Enhanced
Recovery of Oil and Devonian Gas'. June 1977.
-114-
-------
is a typical value for Wyoming crudes. Published values for NOX
were used; however, NOX emissions can vary with the nitrogen
content of the fuel. As discussed in previous sections, this
value can vary. Higher steam:oil ratios will result in increased
emission rates.
It is also possible to estimate trace metal emissions.
Table 6-44 shows values for California, Louisiana and Texas
crudes. If Wyoming crudes are assumed to be similar, these
values would represent guidelines for trace metal emissions.
Specific data for fugitive emissions from steam flooding
operations have not been developed yet. Fugitive emission data
for similar sources in a waterflood operation will probably
be approximately the same and are available. Oil produced
from a steam flood is at a higher temperature which increases
the vapor pressure of volatile components. However, crudes
recovered by steam flooding are generally high boiling mixtures.
These two facts have offsetting effects on the vapor pressure
of the crude. For this reason, fugitive emission factors for
steam flooding are assumed to be similar to those for water-
flooding. Table 6-45 shows estimated fugitive emissions for
an average system. The values presented in the table were
calculated from those in the literature source to make them
consistent with the data used elsewhere in this section. These
emissions can be significantly reduced with a strict equipment
maintenance and housekeeping program. A study by MRI1 indicated
that fugitive emissions can be as low as two orders of magnitude
less for a highly maintained operation than for an operation
that receives average maintenance.
'Hundly, J. B. Total Hydrocarbon Emission Measurements of
Values and Compressors at Arco' s Ellwood Facility"! January 21,
1076, p. 14."
-115-
-------
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-118-
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6.4.2.1.3b Water Effluents
Currently, water effluents from commercial steam flooding
operations have not been quantified. This is due to the
technology being in the early stages of development. Data are
available for waterflooding operations and it is assumed here
that they are similar to those for steam flooding.
There are two major pollutants in water produced from an
oilfield: salts and hydrocarbons. Reservoir fluids generally
contain from 5 to 50 wt % of brine. The actual concentration
will vary among different formations. Hydrocarbon effluents
were estimated from data from studies by Teknekron1 and Battelle2
to be about 9 to 45 Ibs per 1000 bbl of oil produced. On the
basis of 5 bbl of water used per bbl of oil produced, calculations
show that 1.8 to 9 Ibs of hydrocarbons per bbl of water used.
Hydrocarbon concentrations could be higher in water produced by
a steam flood due to the higher temperature increasing the
hydrocarbon solubility.
6.4.2.1.3c Solid Effluents
There are two potential solid effluents from a steam flood.
One is the sludge that is produced during wastewater treatment
operations. A second potential effluent would be sludge from
an SOz scrubber if these are used to treat the boiler flue gas.
The latter is a potential effluent. S02 scrubbers can be used
but are only required for steam flooding boilers greater than
Teknekron, Inc. Fuel Cycles for Electrical Power Generation
Phase I: Towards Comprehensive Standards: The Electric Power"
Case, report for the Office of Research and Monitoring,Environ-
mental Protection Agency. Berkeley, Calif: Teknekron, 1973.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future^Energy Growth, Vol. 1:
Fuel/Energy Systems: Technical Summaries and Associated*
Environmental Burdens, for the Office of Research and Development,
Environmental Protection Agency. Columbus, Ohio: Bactelle
Columbus Laboratories. 1975.
-119-
-------
250 million Btu per hour heat input with high sulfur fuel.1'2
The quantities of sludge produced in each case will be highly
process and site specific.
6.4.2.1.3d Noise
No data were found describing noise associated with steam
flooding. It is assumed that the steam generators will produce
more noise than waterflooding equipment. The flow of high
pressure steam in the boiler and injection equipment would be
the major source of noise.
6.4.2.1.3e Occupational Health and Safety
Figures on occupational health and safety appear in Table
6-26. These values are based on published data that are tabulated
for oilfield operations on an incidents-per-million-Btu basis.
TABLE 6-46. OCCUPATIONAL HEALTH AND SAFETY DATA FOR OIL
PRODUCTION OPERATIONS
Q
Type of Incident Occurance per 1000 bbls produced
Deaths 1.2 x 10"5
Nonfatal Injuries 1.2 x 10"3
Man-days Lost 2.0 x 10~l
Calculated based on 5.6 x 106 Btu/bbl of oil
Source: Batell Columbus & Pacific Northwest Labs, Environmen-
tal Considerations in Future Energy Growth, EPA No.
68-01-0470, Columbus, OH, 1973.
'40 CFR 60.40 New Source Performance Standards for Fossil-
Fired Steam Generators.
240 CFE 60.43 Where discharge into the atmosphere of sulfur
dioxide in excess of 0.80 pounds per million Btu heat input,
maximum 2 hour average, when liquid fossil fuel is burned.
-120-
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6.4.2.2 C02 Miscible Flooding
6.4.2.2.1 Technologies
Flooding with COa displaces trapped oil by eliminating the
interface between the oil droplets and the displacing fluid and
produces a miscible flood. In addition, there are several
other effects of COa on the oil. C02 also
reduces the oil viscosity
swells the oil thereby increasing the
pressure
increases the bulk and relative per-
meability.
All of these effects aid in displacing oil, although miscibility
is the most important.
C02 is injected into the reservoir as a slug of about 15
to 30 percent of the total pure volume which is followed by
water. When the CO; slug contacts the oil there is transfer
of oil components into the C02 phase. This transfer creates
the miscible zone between the two phases. The water drive then
pushes both phases through the reservoir.
In practice, COa flooding can only be applied to reservoirs
that exhibit the following characteristics:1
^evanney, J. W., et al. "The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil," EPA Contract No.
68-01-2445, May 1975.
-121-
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API gravity = 32° to 42°
Depth = 4500 to 9000 ft.
Permeability = 2 to 10 millidarcies
COz miscibility is favored by the high gravity crudes and deep
formations that are necessary to keep the COa in liquid form.
There are several injection techniques that can be used
with a COa flood; however, the most promising technique involves
injecting a C02 slug followed by alternate water and C02 injec-
tion.1 In this method, a 5 percent pore volume slug is injected
initially. Then water and COz are alternatively injected until
the cumulative amount of COa injected has reached 15 to 30
percent pore volume, after which water is injected continuously.
This method gives the best mobility and thereby reduces the
chances of premature water breakthrough at the production wells.
Breakthrough occurs at the drivewater channels through the COa
slugs and appears at the producing wells. The overall best
performance is with undipping reservoirs where gravity reduces
the extent of fingering by the drive water.
In a previously waterflooded reservoir, a COa flood will
typically recover about 10 percent of the original-oil-in-place
(OOIP).2 When used before waterflooding, a COa flood would be
expected to recover 50 percent of the OOIP rather than the 40
percent that is typical of a waterflood. If C02 flooding
^erbeck, E. F., et al. Petroleum Engineer, May 1976,
pp. 114-120.
2Devanney, J. W., et al. "The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil," EPA Contract No.
68-01-2445, May 1975.
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becomes an established, economical technology in the future,
it is likely to be applied prior to waterflooding.
6.4.2.2.2 Inputs
6.4.2.2.2a Manpower Requirements
Accurate data on manpower requirements for C02 flooding
are not currently available. It is assumed that they will be
similar to those for waterflooding, but for a fewer number of
years. The magnitude and type of manpower resources necessary
for COa supply will depend on the COa source. There are two
potential sources of COz: geologic and chemical by-products.
Use of geologic sources of COa will require manpower for
exploration, production and transportation. Once a suitable
formation is discovered, a production facility must be con-
structed and operated. A pipeline to transport the high
pressure C02 to the oil field will also have to be built and
operated. Where the source of C02 is a relatively pure by-
product of a chemical process, manpower will be required for
construction and operation of both a compression facility and
a pipeline to the oil field.
Construction manpower requirements are assumed to be
4000 man-years/year for 2-3 years. Operational manpower
requirements are estimated at 2000 man-years/year for 5 years.
6.4.2.2.2b Materials and Equipment
A COa flood will use much of the injection, production,
and treatment equipment that is available from waterflooding
operations. This is discussed in detail in a previous section
where conventional recovery techniques are considered. This
-123-
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section will consider the additional material and equipment
requirements necessary for a COz flood.
The most significant material requirement is the C02 which
amounts to 30 percent of the reservoir pore volume. For the
example reservoir, this is equivalent to 1012 standard cubic
feet. The other major material requirement is water which is
discussed in a separate section.
Additional equipment requirements for a CC-2 flood will be
a function of the type of source. With a geologic source
equipment will be necessary for production and transportation
of the C02. Production will involve drilling wells 15,000 or
more feet deep and high pressure production equipment. Since
geologic production of C02 is not a commonly practiced technology,
it is not possible to accurately estimate specific equipment
requirements. Transportation to the oil field will involve
construction of a high pressure pipeline (>3000 psia) between
the source and the injection points. The high pressure pipeline
is required by the fact that C02 is most economically transported
as a liquid.
Chemical process sources will involve compression equipment
necessary to take the C02 from atmospheric pressure to greater
than 3000 psia. This is necessary to be installed at the source
since pipeline economics favor transportation of liquid C02.l
The actual pressure requirement will be 3000 psia plus the
pressure drop occurring in the pipeline. If it is assumed that
the C02 is supplied over 2% years, then the compressor require-
ment will be equal to or greater than 1.1 x 105 horsepower.
Longer transportation distances will require more compression.
^evanney, J. W., et al. "The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil," EPA Contract No.
68-01-2445, May 1975.
-124-
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As mentioned before, a high pressure pipeline between the source
and the injection points will also be necessary.
6.4.2.2.2c Economics
There are three major cost components that affect the cost
of oil produced by C02 flooding. These are.-1
Flooding Costs = $0.50 to 1.50/bbl recovered
Compression Costs = $0.87/bbl recovered
Transportation Costs = function of distance.
These costs have been calculated from literature data and put
on a per-bbl-recovered basis. COa transportation costs, as
indicated, are a function of distance and are potentially the
the largest single factor that will determine the cost of oil
produced by a CQ2 flood. Table 6-47 shows the individual and
cumulative costs as a function of distance between the COa
source and the oil field. The cumulative costs are plotted
as a function of transportation distance in Figure 6-20. The
cumulative costs do not include the purchase price of the COz
since this cost will probably be highly variable and specific
to each application. The price of bulk liquid C02 has averaged
$60-$80/ton from 1974 to present.
6.4.3.2d Water Requirements
No value for the water required for a COa flood was found in
the literature consulted; however, it is possible to make some
:Devanney, J. W., et al. "The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil," EPA Contract No.
68-01-2445, May 1976.
-125-
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TABLE 6-47- COSTS ASSOCIATED WITH CO, FLOODING
Miles Between
CO 2 Source and
Reservoir
CO 2
Transportation
Costs
Flooding
Costs
Compression
Costs
Total Cost
Exclusive of
Purchase Price
of C02
0
100
200
500
1000
$0.50
1.75
1.83
3.84
7.66
$0.50-1.50
0.50-1.50
0.50-1.50
0.50-1.50
0.50-1.50
$0.87
0.87
0.87
0.87
0.87
$1.87-2.87
3.12-4.12
3.20-4.20
5.21-6.21
9.00-10.00
-126-
-------
12.50-
10.00 -
7.50 -
$/bbl
oil
recovered
5.00 -
2.50
0
High Flooding Costs
250
500
0
Low Flooding Costs
750
1000
Distance between reservoir and CO 2 source
Figure 6-20. Costs of Oil Recovered by C02 Miscible Flooding
(Exclusive of Purchase Price of C02)
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assumptions. Assuming that water is injected sufficient to
complete one to two sweeps through the reservoir, then the total
water usage for the flood is 50 to 100 percent of the reservoir
pore volume. For the example reservoir, this translates into
7 to 15 bbls of H20 per bbl of oil recovered or 4000 to 8600
acre-ft total. There may be other water requirements associated
with C02 flooding; however, they are assumed to be minor in
comparision.
6.4.2.2.2e Land Usage
Land usage in the oil field will be the same for C02
flooding as for waterflooding. For the example reservoir,
20 square miles will be required. This will vary with the
reservoir characteristics. Injection and production wells will
be placed at intervals over the land area. Part of the land
will be used for oil storage and water treatment facilities.
Off-site there may be land requirements for C02 production
if a geologic source is used. If a chemical process source is
chosen, then some land will be required to accomodate the
compression equipment. Land will also be necessary to construct
the pipeline between the source and the reservoir.
6.4.2.2.2f Ancillary Energy
Ancillary energy for off-site operations will be required
for either production of C02 from geologic formations or
compression of C02 for transportation and injection. Estimates
of energy requirements for production of C02 from geologic
formations are not available. Compression of COz from
-128-
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atmospheric pressure to 3000 psi requires about 0.015 bbl
of oil per 1000 scf. This is equivalent to 3.8 x 109 Btu/hr
for the example reservoir using the assumptions presented in
previous sections. Using a crude oil heating value of 5.6 x 10s
Btu/bbl, about 8 percent of the produced energy is lost to
CO2 compression.
Heater treaters, if they can be considered as an ancillary
energy requirement, consume about 105 Btu per bbl of oil
recovered.1 This translates to 2 percent of the produced energy.
6.4.2.2.3 Outputs
As in the input section, the example reservoir is the
basis of several of the values shown in the discussion of outputs
6.4.2.2.3a Air Emissions
Since C02 flooding does not involve high fuel combustion
rates, it is expected that the air quality impact will be
less than with thermal recovery. The primary air pollution
impact of a C02 flood will be from hydrocarbons and H2S that
have been absorbed by the C02.2 C02 may also be emitted. The
actual quantities emitted cannot be determined since no detailed
concentration data currently exists. In Section 6.4.2.2.2f on
ancillary energy requirements, crude oil consumption due to C02
compression and heater treater operation amounted to 10 percent
^avanaugh, E. C., et al. Atomospheric Environmental
Problem Definition of Facilities for Extraction, On Site
Processing, and Transportation of Fuel Resources^Contract No.
68-02-1319, Task 19. Austin, Texas:Radian Corporation,
July 1975.
2U.S. Congress, Office of Technology Assessment. "Enhanced
Recovery of Oil and Devonian Gas," June 1977.
-129-
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of the total volume produced. Table 6-48 shows major pollutant
emissions assuming 10 percent of the produced oil is burned.
Table 6-49 shows trace metal emissions calculated using the same
assumption.
As stated above it is impossible to estimate the amount of
fugitive emissions attributable to absorption into the CQ2 phase.
There are also emissions associated with other oil production
operations such as treating, transfer and storage. Emission fac-
tors for these operations exist and are presented in Table 6-50.
6.4.2.2.3b Water Effluents
The primary impacts of effluent water quality will be from
dissolved C02, hydrocarbons, and salts. Published data describ-
ing typical dissolved COa concentrations and treatment techniques
were not found. The range of possible C02 concentrations can
be calculated. COa in contact with water at 3000 psia will
give a dissolved COa concentration of about 5 wt percent.
At the wellhead the concentration will be on the order of 1 wt
percent. Water at equilibrium with the atmosphere will have a
dissolved COa concentration of about lO"1* wt percent. The
actual concentration of C02 in the effluent water will be some-
where between these two values. Water treatment by aeration
or lime addition may be necessary to remove the C02.
Hydrocarbon effluents in the water can be estimated using
published data.1'2 These data indicate that hydrocarbon emissions
1Teknekron, Inc. Fuel Cycles for Electrical Power Generation,
Phase I: Towards Comprehensive Standards: The Electric Power
Case, Report for the Office of Research and Monitoring, Environ-
mental Protection Agency. Berkeley, California: Teknekron, 1973.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth, Vol. 1: Fuel/
Energy Systems: Technical Summaries and Associated Environmental
burdens, for the Office of Research and Development,Environmental
Protection Agency. Columbus, Ohio: Battelle Columbus Laboratories
1975.
-130-
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TABLE 6-48. AIR EMISSIONS OF MAJOR POLLUTANTS FOR CO2 FLOODING
OPERATIONS (ASSUMES 10% OF PRODUCED OIL IS BURNED)
Pollutant
Particulate
so2a
so3a
CO
HC (as CHO
N0x (as N02)b
lbc
1000 gal oil burned
7-23
193
2.5
4
2
60
Ib
1000 bbl recovered
29-27
810
11
17
8.4
250
aAssumes 1.23% S in fuel.
N0x is highly dependent upon fuel N content.
**
Average values based on data from:
Sources: U.S. Congress, Office of Technology Assessment.
"Enhanced Recovery of Oil and Devonian Gas." June
1977.
Environmental Protection Agency. Compilation of Air
Pollutant Emissions'Factors, 2nd ed., with supplements
AP-42.Research Triangle Park, NC, Feb. 1972, April
1973, July 1973, Sept. 1973, July 1974, Jan. 1975,
Dec. 1975, Feb. 1976, April 1977.
-131-
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TABLE 6-49. TRACE METAL EMISSIONS FOR CO2 FLOODING OPERATIONS
(ASSUMES 10% OF PRODUCED OIL IS BURNED)
Trace Metal
Antimony
Arsenic
Barium
Manganese
Nickel
Tin
Vanadium
a
Averages based
Source: Magee,
a
ppm
<0.022
<0.059
<0.097
0.032
3.9-77
0.70
1.5-4.8
on Texas ,
E. M., et
Ib
1000 gal oil burned
<0.015
<0.024
<0.072
0.0095
1.2-2.4
0.45
0.41-13
Lousiana, and California
al. Potential Pollutants
Ib
1000 bbl recovered
<0.063
<0.10
<0.30
0.040
5.0-100
1.9
1.7-55
crudes.
in Fossil Fuels,
Environmental Protection Agency Report No. EPA-R2-73-249,
June 1973.
-132-
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TABLE 6-50- FUGITIVE EMISSION FACTORS FOR CO2 FLOODING OPERATIONS
lb hydrocarbons/
Source 1000 bbl oil produced
Storage Tanks 3.9
Wastewater Separators 7.9
Pumps 74.
Compressors 3.8
Relief Valves 7.9
Pipeline Valves 11.6
Diesel Pump for Waterflooding 7.1
Miscellaneous Flaring & Fires 0.76
Source: Cavanaugh, E. C., et al. Atmospheric Pollution Potential
from Fossil Fuel Resource Extraction, On-Site Processing"
and Transportation.Final Report.Radian Corp., Austin,
Te5TEPA Contract 68-02-1319. 1972.
Burklin, C. E. , et al. Control of Hydrocarbon Emissions
from Petroleum Liquids. Final Report.Radian Corp.,
Austin, Tex.EPA Contract 68-02-1319. 1975.
-133-
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in the effluent water are about 0.01 Ib per 1000 bbls of oil
produced. Using the assumed water usage rate of 7-15 bbls H20
per bbl oil, the concentration of hydrocarbons in the water can
be estimated to be 10~7 wt percent.
Salt concentration will vary as a function of the reservoir
rock type and perhaps other factors, Typically, salt concentra-
tions in the range of 5 to 50 wt percent are encountered.
6.4.2.2.2c Solid Effluents
Solid effluents resulting from C02 flooding operations were
not found in the literature. Most likely, the only solid
effluents will be from water treatment processes where pollutants
are removed as a solid. If evaporation or aeration ponds are
used, there may be some salt precipitation as water evaporates.
6.4.2.2.3d Noise
The major potential source of noise will be the COa
compression facility that is necessary with certain COz sources.
6.4.2.2.3e Occupational Health and Safety
Figures on occupational health and safety appear in
Table 6-46. These values are based on published data that are
tabulated for oilfield operations on an incidents-per-million-
Btu basis.
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6.4.3 Production Social Controls
6.4.3.1 Federal
The following sections will discuss the oil production
social controls at the federal level to include statutes and reg-
ulations. A majority of the controls at the federal level are
broadly applicable and effect energy development whether on pri-
vate or public land; whereas a few controls, which are noted, are
applicable only to development on the public domain.
6.4.3.1.1 Conservation on the Public Domain1
As discussed in Chapter 2 the primary statutory control over
oil and gas leasing on the public domain is the Mineral Leasing
Act of 1920 (MLA).2 Oil (and gas) production operations are reg-
ulated by the USGS under MLA also and subsequently issued regu-
lations.3 The regulatory scheme is directed at controlling the
wasteful extraction of resources.1* Pursuant to such regulation,
the BLM in concert with the USGS is authorized to approve coop-
erative or unit plan agreements and joint operating contracts for
federal lessees when such action is necessary to prevent waste.5
Conservation as used here means both the efforts to con-
serve the resource and to protect the environment. Also note
these controls are only applicable to federal lands.
230 TJ.S.C. § 181 et seg.(1970).
330 U.S.C. § 226 (1970); 30 C.F.R. Part 221 (1974).
4Dolgin, Ernie L. and Thomas G. P. Guilbent, eds. Federal
Environmental Law. St. Paul, Minn.: West, 1974, p. 936.
5Shapiro, Michael E. "Energy Development on the Public Do-
main: Federal/State Cooperation and Conflict Regarding Environ-
mental Land Use Control." Natural Resources Lawyer. Vol. 9, 1976:
401. Note the statutory authority stems from 30 U.S.C.A. § 226
(j) (1970) and regulations are found at 43 C.F.R. subpart 3105
(1974). For complete discussion of federal unitization see:
Churchill, D. 0. "Federal Unitization" pp. 223-256, in Rocky
Mountain Mineral Law Institute: Proceedings of the Twenty-First
Annual Institute. July 17-19, 1975. Albany, N.Y.: Matthew Bender,
1975.
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Since the Secretary is given full discretion to refuse to
accept an offer for an oil and gas lease,1 the BLM under his
authority has rejected leases on environmentally sensitive areas.
The BLM may also impose conditions on lease.2 As can be gathered
from the above there are no specific statutes protecting the
public domain from environmental harm.3
Other controls exist at the federal level but will be pri-
marily discussed in Section 6.4.3.2.1 (State Conservation Laws).
Controls in this area include "market demand prorationing" and
were passed by some states and approved by Congress in 1935 as
the Interstate Oil Compact.1* Basically the Act allows the states
to limit oil production to prevent prices that would be low
enough to allow physical waste of oil. Recently, with the peak-
ing of domestic oil production and respective high prices, the
prorationing controls have lost most of their effect on oil
production.5
The Secretary of the Interior is required to keep his
regulations on oil and gas leasing in line with similar provi-
sions in state laws where the leased land is located. Court
cases interpreting this question have tended toward narrow inter-
pretation of the state's rights. For example, the Interior
J30 U.S.C.A. § 226 (a) (1970).
2Shapiro, Michael E. "Energy Development on the Public
Domain: Federal/State Cooperation and Conflict Regarding
Environmental Land Use Control." Natural Resources Lawyer.
Vol. 9, 1976: 401. Note the statutory authority stems from 30
U.S.C.A. § 226 (j) (1970) and regulations are found at 43 C.F.R.
subpart 3105 (1974). For complete discussion of federal unitiza-
tion see: Churchill, D. 0. "Federal Unitization" pp. 223-256,
in Rocky Mountain Mineral Law Institute: Proceedings of the
Twenty-First Annual Institute. July 17-19, 1975. Albany, N.Y.:
Matthew Bender, 1975.
3 But see Chapter 2 for a-discussion of NEPA's application.
*49 Stat. 20 (1935).
5Dolgin, Ernie L. and Thomas G. P. Gilbert, eds. Federal
Environmental Law. St. Paul, Minn. West, 1974 p. 943.
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Board of Land Appeals (within Department of Interior) has
disapproved a communication agreement affecting federal oil and
gas leases which had been previously approved by a state oil and
gas commission under state conservation statutes.1 The same
problem occurs in attempting to pool Indian land with private
land under state laws. At least one case has held the state laws
are ineffective to force such pooling.2
6.4.3.1.2 Air Pollution
Although new source performance standards have been written
for "Storage Vessels for Petroleum Liquids," it appears that
petroleum storage at the drilling or production facility is not
covered.3 Also, the federal NSPS for steam generators have a
threshold of 250 million BTU's per hour and even steam injection
on a large scale would not approach that limit.1*
6.4.3.1.3 Water Effluent Controls
6.4.3.1.3a Surface Water
Effluent guidelines have been promulgated for oil and gas
extraction point sources.5 EPA, under court order, published the
regulations without a comment period and made the guidelines
Shapiro, Michael Ei "Energy Development on the Public Domain:
Federal/State Cooperation and Conflict Regarding Environmental Land
Use Control." Natural Resources Lawyer, Vol. 9, 1976:418.
2Assimiboine and Sioux Tribes of Fort Peck Indian Reservation,
Montana v. Calvert Exploration Co., 233 F. Supp. 909 (D. Mont:1965).
340 C.F.R. 60.110 (b) (1975), see generally 40 C.F.R. 60.110
for the NSPS for petroleum storage.
440 C.F.R. 60.40 as revised by 41 Fed. Reg. 51397, Nov. 22, 1976
541 Fed. Reg. 44942-44952, Oct. 13, 1976, to be codified at
40 C.F.R. § 435 (1977).
-137-
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effective immediately.1 The regulations are classified interim
and comments will be taken prior to promulgation of final
regulations.
Interim regulations address the following categories of oil
and gas development: onshore, beneficial use, and stripper. The
onshore sub-category is all those categories* not coastal, not
beneficial use and not stripper; therefore, the one applicable to
most western energy development. Table 6-51 will summarize the
effluent guidelines.
%.
6.4.3.1.3.b Underground Water
Underground disposal of brine (injection wells) has his-
torically been controlled by state law and these same laws deal
with injection for secondary recovery. Recently, however, the
federal government, more specifically EPA, has moved into the
field.
Authority for EPA comes from various sources and there is
potential for challenge under each of them.2 The primary basis
for EPA jurisdiction is the Safe Drinking Water Act.3 Congress,
when passing the Pact, included a comprehensive state-federal
system of regulation over underground injection.
Under SDWA, the states must establish a permit program of
rules governing such injection prior to December 1977.4 The EPA
iNRDC v. Train, (CV. No. 1609-73, D.C. Cir.) requiring the
regulations to be promulgated by September 1, 1976.
2Eckert, Allan W. "EPA Jurisdiction over Well Injection Under
the Federal Water Pollution Control Act," Natural Resources Lawyer,
Vol. 9, 1976: pp. 455-465.
3Safe Drinking Water Act, P.L. 93-523, 88 Stat. 660, 42 U.S.C.A.
§ 300 (f) et seg., amending 42 U.S.C.A. § 201 (1970).
uSafe Drinking Water Act, § 1421 (b), 42 U.S.C.A. § (Supp. 1976)
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TABLE 6-51. SUMMARY OF OIL AND GAS EXTRACTION EFFLUENT GUIDELINES
Type of
Regulation
Sub-Categories
Onshore
Beneficial Use''
Stripper0
Interim BPT
No discharge
of pollutants
No discharge
of pollutants1
Not issued
Proposed BAT
(New Sources)
No discharge
of pollutants
No discharge
of pollutants1
Not issued
Pre-treatment
for new sources
Not more than
100 mg/1 of
oil and grease
Not more than
100 mg/1 of
oil and grease
Not issued
Source: 41 Fed. Reg. 44942-44952 (October 13, 1976).
Additional limit of notmore than 45 mg/1 of oil and gas in the discharged
water.
2That category wherein the effluent is applied to livestock or other
agricultural uses.
Those wells producing less than 10 barrels of oil per day.
''Those sources discharging into publicly owned treatment works.
-139-
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administrator must approve the program or develop his own for that
state.1 Not all states will be included initially but all even-
tually will be included.
Potential problems from holding seepage conflicting with
SDWA has been covered in Chapter 2 and is applicable to the sur-
face pond storage of brine, as may also be the case with state
solid waste laws.
Oil production is not free from controls other than those
noted here; for example, there are comprehensive federal laws
within FWPCA controlling oil spills on land as discussed in
Chapter 2.
6.4.3.2 State
State laws affecting the production of oil are aimed
primarily at operations on private lands with some variations for
oil production on state laws which also affect federal land
and will be noted below. Topics discussed herein are conserva-
tion, injection, air emissions, and plugging.
6.4.3.2.1 State Conservation Laws and Regulations
State conservation laws started with Indiana's law of 1893
which made it illegal to allow a well to flow freely for more
than two days after striking oil. The U.S. Supreme Court upheld
the law, stating that the law was proper as one way to protect
the right of others to produce from the pool (common source of
supply), because waste reduced the amount that could be produced
SDWA, § 1422, 42 U.S.C.A. §
-140-
-------
from the common supply, and the wasteful acts of one could result
in "the annihilation of the rights of the remainder."1
The state laws within the category are those for spacing,
compulsory pooling, and compulsory unitization. The spacing
statutes exist in all eight states and allow for administrative
determination of the number of acres per well. These vary from
no more than one well per 20, 40, 80, and 160 acres for oil and
320 and 640 or larger for gas wells.
Pooling is generally defined as the means used to bring to-
gether small tracts of land sufficient for the granting of a
well permit under applicable spacing rules and must be distin-
guished from unitization which is the joint operation of all
or some part of the reservoir.2 Unitization is suggested in
the primary stages of development but is nearly mandatory in
secondary recovery operations. All eight of the states in this
study have enacted compulsory pooling laws allowing the majority
lessee to drill on a spacing unit. The other lessees and
lessors may not hinder but are allowed to share in costs and
profits.3
All states in this study area have statutory authorization
for voluntary unitization except New Mexico.1* The states went
further to encourage unitization when it became apparent that the
Oil Co. v. State of Indiana, 1977 U.S. 190 (1960).
2Williams and Meyers, Oil and Gas Law, Vol. 6, § 901, 1964:
p. 2.
3Williams and Meyers, Oil and Gas Law, Vol. 6, i 901, 1964:
p. 20.
kld. § 911, p. 94.
-141-
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maximum recovery of hydrocarbons from a reservoir would require
the production of the formation as a unit. Under specified cir-
cumstances six of the eight states statutorily provide for com-
pulsory unitization (with New Mexico and South Dakota being the
exceptions).l
Although the unitization statutes vary, the following find-
ings are generally necessary as prerequisites to the adminis-
trative order to unitize:2
(1) Unit operation is reasonably necessary.
(2) The proposed method is feasible.
(3) The cost of unitization will not exceed the
estimated additional revenues.
(4) The proposed operation is for the common good
and is fair and equitable.
(5) The plan has been approved by the specified
percentage of owners.
6.4.3.2.2 Injection
State injection laws have not been included here since the
recently promulgated federal regulations on the subject include
a mechanism for revision of state injection programs (see
Section 6.4.4.1.3.b).
6.4.3.2.3 Air Pollution
(See Section 7.4.4.2.b, State Laws Concerning Storage of
Oil or Gas and Flaring).
lld. § 912, p. 98.
2Id. § 913.4, p. 112.
-142-
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6.4.3.2.4 Plugging and Sealing
Vary by state but usually require sealing the bore hole so
that zones of production do not mingle and that oils and brines
do not migrate to the fresh water strata. For summary by state
see Section 7.4.4.2.d and Table 7-12.
-143-
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6.5 TRANSPORTATION
6.5.1 Social Controls
Transportation social controls were covered generally in
Chapter 2, including rail, highway and electric, hence this
section will be devoted to an analysis of those controls affect-
ing only oil and more specifically oil pipeline problems.
6.5.1.1 Federal
Federal regulation of oil pipelines has been discussed in
Chapter 2, Transportation, but some factors deserve mention here.
Previously discussed were DOT safety regulations for pipelines,
ICC rate regulation, and rights-of-way on public and private
lands. Factors or controls at the federal level noted before
are FWPCA oil spill regulations and Corps permits when crossing
streams or bodies of water.
0.5.1.1.1 Oil Spills
Section 311 of FWPCA holds owners and operators of oil
pipelines responsible for "harmful" oil spills into the navigable
waters of the U.S.1 Liability extends to the cost of removal of
the oil and/or to penalties. Regulations specify and it has been
upheld in court that the amount of spill is harmful if it is
enough to cause a sheen on the waters.2 It appears that EPA has
delegated their authority to the DOT for control of the above.
!See Section 2.9.1 for definition of Navigable Waters.
240 C.F.R. § 110.3 (1972), upheld in U.S. v Boyd, 491F.2d
1163 (9th Cir. 1973) .
-144-
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CHAPTER 7
THE NATURAL GAS RESOURCE DEVELOPMENT SYSTEM
-------
CHAPTER 7
THE NATURAL OIL RESOURCE DEVELOPMENT SYSTEM
7.1 INTRODUCTION
7.1.1 Background
The first recorded use of natural gas in the U.S. was in
Fredonia, New York in 1821. Early usage tended to be localized
and many utilities distributed gas manufactured from coal. In
1947, a major change in the character of the industry occurred
when natural gas from the Southwest reached the East Coast
through two converted liquid pipelines, the "big inch" (crude
oil) and the "little inch" (refined crude oil products). Since
then, the consumption of natural gas in all end-use classifica-
tions (residential, commercial, industrial, and power generation)
has increased rapidly. This growth has resulted from several
factors, including: the development of new markets; replacement
of coal as a fuel for providing space and industrial process
heat; use in making petrochemicals and fertilizers; and the
strong demand for low-sulfur fuels that emerged in the mid-1960's
As a result-of these expanded end uses, total gas utility
mains increased from 218,000 miles in 19451 to 980,000 miles in
1975.: The high-pressure natural gas transmission network was
'Zareski, J.K. "The Gas Supplies of the United States -
Present and Future." Pollution Control and Energy Needs,
Advances in Chemistry Series No. 127.New York, New York:
American Chemical Society. 1973.
2American Gas Association, Department of Statistics. Gas
Facts, 1975 data. Arlington, Virginia: American Gas Associa-
tion, 1976, p. 29.
-146-
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extended into all the lower 48 states and, by 1975, included
261,000 miles of pipe and 12.0 million horsepower of compression.
All phases of development and utilization of gas resources
are provided by private industry and fall within three fairly
well-defined segments: supply, transmission, and distribution.
Although large corporations dominate the individual segments,
the industry is not characterized by vertical integration from
the gas field to the consumer. For the most part, the gas
industry consists of transmission companies that buy -heir gas
from the oil industry and distribution companies that sell the»
gas to the ultimate consumers.
This chapter describes the technologies, inputs, outputs,
laws, and regulations associated with the development of natural
gas resources. There are five main sections to the chapter
and they are briefly described below.
Section 7.2 describes the characteristics of the natural
gas resources found in the eight-state region and also discusses
the quantity and location of the resource.
Section 7.3 discusses the technologies, inputs and outputs,
and social controls associated with exploration for natural gas.
Section 7.4 discusses the same items for convention natural gas
production and field processing. Section 7.5 discusses the tech-
nologies and social controls for transportation of natural gas.
It is important that the reader have a thorough understand-
ing of this entire chapter before applying any of the contained
information. Typical technologies were chosen for the basis
of the data, and it is important to note that the parameters
-147-
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can vary greatly depending upon the specific basis chosen. The
reader is advised to note any changes in bases between the
different technologies in the chapter.
7.1.2 Summary
Tables 7-1 and 7-2 summarize the input requirements and
outputs associated with the development of the resource.
-148-
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TABLE 7-1. SUMMARY OF IMPACTS ASSOCIATED WITH
EXPLORATION FOR A 250,000,000 CUBIC
FEET/DAY GAS FIELD
Inputs
Manpower
Materials and Equipment
Casing and Tubing
Rig-Years
Cement
Economics
Water (lifetime of project)
Land
Ancillary Energy
see Table 7-8
4548 tons
9
8960 tons
25 x 10s dollars
106 barrels
30 acres
5.2 x 1011 Btu
4126 m. tons
9
8128 m. tons
25 x 10s dollars
15,350 m3
121,407 m2
5.4 x 101" J.
Outputs
Air Emissions
Particulates
S02
CO
Hydrocarbons
Nitrogen Oxides
Aldehydes
Organic Acids
C02
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
deaths
injuries
lost time
24 Ibs/day
50 Ibs/day
431 Ibs/day
70 Ibs/day
700 Ibs/day
6 Ibs/day
6 Ibs/day
39,265 Ibs/day
negligible
66,000 ft
variable
.0.2/year
19/year
3200 man-days/year
10.9 kg/day
22.7 kg/day
195.5 kg/day
31.7 kg/day
317.4 kg/day
2.72 kg/day
2.72 kg/day
17,807 kg/day
1869 m
-149-
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TABLE 7-2. SUMMARY OF IMPACTS ASSOCIATED WITH THE
PRODUCTION FOR A 250,000,000 CUBIC FOOT/
DAY NATURAL GAS FIELD
Inputs
Manpower
Materials and Equipment
Refined Products
Cement
Pipe and Tubing
Heat Exchangers
Economics
Waters
Land
Ancillary Energy
See Table 7-8, 9
128,650 tons
75,000 tons
15,000 tons
116,708 m. tons
68,038 m. tons
1.3,608 m. tons
83,000 ft2 of surface 7710 m2 of surface
400 million dollars
380 acre ft/yr 468,730 m3/yr
850 acres 3.44 x 10s m2
3% of gas produced
Outputs
Air Emissions
Particulates
S02
* NOX
HC
CO
Triethylene glycol
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
Odor
50 Ib/day
11,233 Ib/day
15,741 Ib/day
19 Ib/day
47.5 Ib/day
240 Ib/day
22.7 kg/day
5095 kg/day
7140 kg/day
8.6 kg/day
21.5 kg/day
108.8 kg/day
negligible
none
no data
See Table 7-1
no data
-150-
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7.2 RESOURCE DESCRIPTION OF WESTERN NATURAL GAS
7.2.1 Characteristics of the Resource
Natural gas is a degradation product resulting from the
decomposition of buried organic matter. It is found in recent
sediments deposited in both fresh water and salt water environ-
ments, in ancient sedimentary rocks, in subsurface aquifers, in
fine fractures in coal seams, and even in metamorphic rocks.
As of 1975, there were approximately 131,000 wells producing
gas from such formations.1 The determining factor in classify-
ing a well with respect to type of production is the ratio of
oil/gas produced. The different states have statutes defining
an oil or gas well, and most are similar to Texas law. It
defines an oil well as "... any well which produces one (1)
barrel or more of crude petroleum oil to each one hundred
thousand (100,000) cubic feet of natural gas."2
Unprocessed natural gas is a mixture of hydrocarbons with
methane as the major component. The mixture also includes
ethane (C2H5), propane (C3H8), butane (Ci*Hio), and some heavier
hydrocarbons. Most of the ethane and heavier hydrocarbons are
removed through liquefaction and are sold as separate products
for a multitude of uses. Other components found in natural gas
are water, hydrogen sulfide, nitrogen, carbon dioxide, and
others, which for the most part are removed during gas processing
The heat content of dry natural gas in the U.S. averages 1,032
Btu per cubic foot measured at 14.7 psia and 60°F.
3
1American Gas Association, Department of Statistics. Gas
Facts. 1975 Data. Arlington, Virginia: American Gas Association.
1976, p. 29.
2Processes Research, Inc. Industrial Planning and Research.
Screening Report. Crude Oil and Natural Gas Production Processes.
Final Report.Cincinnati,Ohio:Processes Research,Inc.1972.
3American Petroleum Institute. Petroleum Facts and Figures.
Washington, D.C.: American Petroleum Institute. 1971.
-151-
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However, the heat content as well as the composition of unpro-
cessed natural gas varies considerably with different wells as
illustrated in Figure 7-1.l
Natural gas may also be classified in terms of the level of
association with crude oil in its natural occurrence underground.
Nonassociated gas is gas occurring by itself in reservoirs, while
associated gas is produced along with crude oil. Natural gas may
also exist in a dissolved state in crude oil. In deep reservoirs
(e.g., 15,000 feet or deeper), crude oil may exist in a gaseous
state (called gas condensate) due to the high temperatures.
7.2.2 Quantity and Location of the Resources
Total proved gas reserves for the western regions as of
December, 1975, have been estimated to be 19.6 trillion cubic
feet (tcf).2 The figure for the entire U.S., onshore and off-
shore, is 228 tcf. This total figure has been dropping each
year since the peak year of 1967 which saw proven reserves of
approximately 290 tcf. Since that time the annual consumption
has far outstripped the discovery rate for natural gas. In
terms of recoverable, but yet-to-be-discovered resources the
western region has a potential of 56 tcf compared to 484 tcf for
on and offshore U.S.3
Table 7-3 presents a breakdown of proven and ultimate re-
serves of natural gas by states. It is seen in the table that
the natural gas reserves in the western states account for only
federal Power Commission. National Gas Survey, Vol. I.
Washington, D.C.: Federal Power Commission.1974. Chapter 2.
2American Gas Association, Department of Statistics. Gas
Facts. 1975 Data. Arlington, Virginia: American Gas Associa-
tion";1976, p. 29.
3U.S. Geological Survey. Geological Estimates of Undiscovered
Recoverable Oil and Gas Resources in the United States,Circular
725.Washington, D.C.:U.S. Geological Survey.1975.
-152-
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TABLE 7-3.
WESTERN NATURAL GAS RESERVE ESTIMATES1
(In billions of cubic feet)
USGS
AGA Identified
Colorado
Montana
New Mexico
North Dakota
Utah
Wyoming
Total Western
Total U.S.
r,M- - Western
Ratiu ~ u.s.
^.S. Geological
Proved
Reserves3
1,893
930
11,759
417
917
3,703
19,619
But Not
Proved
1,344
577
6,364
368
876
3,412
12,941
228,200 202,548
0.09
Survey. Geological
able Oil and Gas Resources in the United
0.09
AGA
Cumulative
Production2
2,233
1,371
23,134
658
979
6,296
34,677
436,896
0.08
USGS
Ultimate
Production2
5,232
3,012
41,833
1,467
2,877
13,797
68,218
904,576
0.08
Estimates of Undiscovered Recover-
States.
Circular 725.
Washington,
D.C.: U.S. Geological Survey. 1973.
2Based on American Gas Association reports as of December 31, 1972.
3Based on American Gas Association reports as of December 31, 1975.
-154-
-------
about ten percent of the whole U.S. reserves. Table 7-4 pre-
sents the production record for the western states for a ten
year period.
7.2.3 Ownership of Resources
No data has been collected on the ownership of the western
natural gas resources. On a national level six percent of on-
shore reserves are federally owned,l but the figure is considered
somewhat higher for the western U.S.
JFord Foundation. Energy Policy Project. A Time to Choose
America's Energy Future. Cambridge, Massachusetts"! Ballinger
Publishing Co., 1974.
-155-
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7.3 EXPLORATION
7.3.1 Technologies
The technologies used in gas well drilling are essentially
the same as in oil well drilling. The reader is referred to
Section 6.3.1 for a description of exploration drilling.
7.3.2 Input Requirements
The inputs associated with drilling the gas wells which
will ultimately produce 250 MM scfd are discussed in this section
With respect to drilling operations, there are two types of gas
wells, exploratory and developmental. Exploratory drilling
means searching for the geologic strata containing petroleum
in sufficient quantities to justify recovery. Once the natural
gas is found, developmental wells are drilled in strategic
areas which will produce the maximum amount of product over the
life of the gas field.
As a basis for the inputs, a gas field was designed
consisting of 83 wells each producing 3 MM scfd. For the
example field, the assumption is made that for every 10 producing
wells 8 additional dry holes will have been drilled. Both
operations, a total of 149 wells, and construction of gathering
and processing facilities are scheduled for a 5 year program.
7.3.2.1 Manpower Requirements
The Bechtel Corporation has estimated the manpower required
to develop and produce a domestic gas field.1 The total manpower
^arasso, M. , et. al. The Energy Supply Model, computer
tape. San Francisco, California:Bechtei Corporation. 1975.
-157-
-------
requirements for developing the example field and also for
constructing gathering and processing facilities are found in
Section 7.4.2.1.
7.3.2.2 Materials and Equipment
Major equipment requirements for development and production
of a 250 MM scfd gas field includes casing, tubing, drilling
rigs/associated equipment, and cement. The data in Table 7-5
is a compilation of material requirements estimated by the
Federal Energy Administration.1 The average depth of the wells
drilled in this study is approximately 5000 ft. If wells are
to be drilled into "tight gas" formations found in some areas
of Colorado, Wyoming, and Utah at depths greater than 10,000 ft.,
the materials requirements will be somewhat larger.
7.3.2.3 Economics
Assuming the costs of developing this example gas field
are represented by drilling costs along, the development phase
of the gas field will cost approximately $25 million before the
first gas is recovered. Drilling costs vary widely depending
on the depth, location, and the nature of the geologic substrata.
The cost data are derived from cost per foot drilled in the
western U.S. using 1974 dollars.2
7.3.2.4 Water Requirements
The freshwater requirements for a drilling well are almost
exclusively for use in the drilling mud. A conventional drilling
1 Federal Energy Administration, Interagency Task Force on
Natural Gas. Project Independence Blueprint, Final Task Force
Report, Natural Gas. Washington, D.C.: Federal Energy Admini-
stration. November, 1974.
-158-
-------
TABLE 7-5. MATERIALS AND EQUIPMENT REQUIRED FOR A
250 MM scfd NATURAL GAS FIELD
Requirements for
66 Dry Holes83 Successful HolesTotal
Casing & Tubing 1394 3154 4548
(tons)
Surface & Subsurface - 6391 6391
Equipment (tons)
Number of rigs-year 4 59
(5 year duration)
Steel tonnage per rig 250 250
(tons)
Cement (tons)* 3980 4980 8960
^Assuming each well is 5000' deep
Source: Federal Energy Administration, Interagency Task Force
on Natural Gas. Project Independence Blueprint, Final
Task Force Report, Natural Gas. Washington, D.C.:
Federal Energy Administration. November, 1974.
-159-
-------
rig consumes from 200 to 500 barrels per day of water.1 For a
14 to 21 day stay at a drilling site, from 5000 to 7500 barrels
are used per rig. The total consumption over the drilling
phase of this project is approximately 1,000,000 barrels of
water.
7.3.2.5 Land Requirements
Two acres of land are cleared and used around a typical
exploratory well.2 Some of this land is retained for workover
purposes after the drilling is completed and can be sodded or
surfaced as local conditions dictate. Any area not needed
for a workover rig can be restored to its original condition.
Permanent land usage for the exploratory drilling phases
(66 dry wells) is about 30 acres for drilling sites and roads.
Land associated with the producing wells is accounted for in
the production section.
7.3.2.6 Ancillary Energy
Energy required for drilling oil. and gas wells varies with
rig size, type of formation drilled, well depth, and the time
on the well. Diesel fuel and natural gas are used as fuel.
Diesel fuel is normally used in internal combustion engines for
drilling exploratory wells.
The consumption of diesel fuel per rig varies from 900 to
1800 gallons per day.3 Total fuel used for drilling purposes
federal Power Commission. National Gas Survey, Vol. II.
Washington, D.C.: Federal Power Commission.1974, pg~73-75.
2Ibid.
3 Ibid.
-160-
-------
during the 5 year program will be approximately 3.5 million
gallons (5.2 x 10n Btu) of diesel fuel.
7.3.3 Outputs
The outputs associated with the exploratory phase of
natural gas production are discussed in the following sections.
7.3.3.1 Air Emissions
The large internal combustion engines used to power the
drilling equipment are the major source of air emissions during
exploration. Table 7-6 is a tabulation of emissions factors,
air emissions per rig, and air emission for the entire gas
field averaged over the five-year development period. Some-
times drilling is more intense than these average figures and
the emissions are somewhat higher. Periodically, usually near
the completion of drilling, wells are tested to evaluate the
ultimate producibility of the well. Some gas is brought to
the surface and is usually burned. By-products are emitted
to the atmosphere. This burning is very infrequent, and there
is no data on the quantity of emission.
7.3.3.2 Water Effluents
During normal exploration drilling operations, loss of
pollutants to fresh water is negligible. The largest use of
water is the circulating drilling mud which is a closed system
allowing for no water effluent except for mechanical failure
or human error.
Drainage patterns of surface waters and rain runoff may be
disturbed by the construction of roads into exploration areas.
-161-
-------
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This disturbance may cause increased turbidity and suspended
solids in the fresh water. Erosion may also be a possible
result.
7.3.3.3 Solid Wastes
Exploratory drilling brings drill cuttings from the well
to the surface. These cuttings are mixed with the drilling mud
which contains additives such as barite bentonite, inert clays,
and phosphate. They will dry in the reserve pit and are plowed
into the native soil when drilling is complete. Although some
soils may be improved by the addition of these compounds1, these
materials will have an adverse effect in most instances.
7.3.3.4 Noise Pollution
Associated with drilling activities there is a substantial
noise level which may be annoying to wildlife or nearby resi-
dents. This has occurred most often in Southern California.
The rigs are soundproofed, and purchased electric power replaces
internal combustion drilling equipment. These solutions seemed
to prevent a disturbance to the environment.
7.3.3.5 Occupational Health and Safety
Data on injuries, deaths, and man-days lost for the natural
gas exploration, producing, and processing of a 250 MM scfd
field are taken directly from Battelle.2 These numbers are
converted from Battelle's basis of producing 10s Btu of natural
federal Power Commission. National Gas Survey, Vo1. II.
Washington, D.C.: Federal Power Commission.1974, p. 73-75.
2Battelle-Columbus and Pacific Northwest Labs. Environ-
mental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle-Columbus and Pacific Northwest Labs. 1973.
-163-
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gas to a basis of production of 250 MM scfd of natural gas. The
results are as follows: 0.2 deaths/year, 19 injuries/year, and
3200 man-days/year are expected to be lost.
7.3.3.6 Odor
There are no odor problems associated with drilling of gas
wells .
7.3.4 Social Controls
Social controls for natural gas development are not sub-
stantively different from oil development controls in most
areas. Specifically the controls over exploration and leasing
are so similar that the sections below will refer the reader
to the respective sections in Chapter 6.
7.3.4.1 Exploration Permits; see 6.3,4.1.
7.3.4.1.a Exploration Permits on Federal Land; see 6.3.4.1.a.
7.3.4.1.b Exploration Permits on Indian Land; see 6.3.4.1.b.
7.3.4.1.C Exploration Permits on State Land; see 6.3.4.I.e.
7.3.4.2 Leasing; see 6.3.4.2.
7.3.4.2.a Leasing on Federal Land; see 6.3.4.3.a.
7.3.4.2.b Leasing on Indian Land; see 6.3.4.2.b.
7.3.4.2.C Leasing on State Land; see 6.3.4.2.C.
Utah does allow a variation in rental on its state lands
for shut-in gas as opposed to normal oil and gas rental. The
statute provides for double the rent in such situations requir-
ing rates to be between $1.00 and $2.00 per acre.1
'Utah Code Annotated. §65-l-18 (1953).
-164-
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7.4 NATURAL GAS PRODUCTION
7.4.1 Technologies
Natural gas production technologies discussed in this section
are grouped in three general categories: development drilling,
well completion, and processing.
7.4.1.1 Development Drilling
Once gas is discovered by exploratory drilling, the well is
tested to determine the possible gas flow rate and size of the
reservoir. If the reserves calculated from these data and other
geological information are large enough to warrant commercial
production, the reservoir is developed. Development includes
drilling a number of wells to drain the reservoir as efficiently
as possible, completing these wells so that flow occurs and can
be controlled, installing field processing equipment, and instal-
ling transportation pipelines.
Development drilling is similar to exploratory drilling,
except that the spacing of wells and location of the bottoms
of the holes are more carefully controlled. Once the develop-
ment well is drilled, casing is set in a manner similar to that
discussed in Section 6.4.1.
7.4.1.2 Completion
Well completion encompasses all those activities required
to prepare the well for production. A discussion of well
completion is found in Section 6.4.1. Oil wells and gas wells
are completed in a similar manner.
-165-
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7.4.1.3 Natural Gas Processing
As pointed out in the introductory section, wells are
classified as gas wells or oil wells depending on the ratio of
oil/gas produced. In this section, only those operations involved
in producing natural gas from basically pure gas reservoirs are
discussed. Gases extracted from different producing fields have
widely varying compositions. Most field gases contain some
undesirable compounds such as COz, H2S, H20, and combined sulfur
compounds which must be removed prior to sales. Typical proces-
sing facilities for upgrading the gas to market specifications
are described. These facilities include field separation, com-
pression, and natural gas plants.
The processing method selected for a particular gas depends
on factors such as its type and composition, the geographic
location of the source, and the proximity of natural gas trans-
mission lines. For example, different, processing methods may
be used for similar gas produced from onshore and offshore wells.
Also, some processing may be done to make the gas suitable for
pipeline transmission or sales, while other processing is done
to recover valuable products, including a wide range of hydro-
carbon liquids.
7.4.1.3.a Field Separation
Two basic types of fields exist from which gas is produced.
One is the "dry" gas field in which no hydrocarbons heavier than
methane and ethane are produced and the only processing required
is dehydration and acid-gas removal. The other type is the "wet"
or "condensate" field where a clear hydrocarbon conderisate is pro-
duced with the gas. Separation of these heavier hydrocarbons is
a necessary step in achieving acceptable natural gas specifications
This operation is often accomplished in the field.
-166-
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Generally, fluids from gas x^ells are first treated to
remove water and sand, then passed through a single separator
or a sequence of separators, depending on the composition
and the nature of the produced fluids. Both water and water vapor
must be removed from the gas to prevent formation of hydrates
(solid snow-like compounds of water and methane). Hydrates form
as the result of the cooling which accompanies gas expansion
and can plug wellhead valves, metering equipment, and pipelines.
If formation of hydrates is a problem in a particular field, the
produced fluids may be heated at the wellheads prior to flow into
any gas processing equipment to deter hydrate formation before
treatment.
Normally, the stream produced from a gas reservoir is
separated in a single stage by passing it through a free water
knockout separator to remove water and sand and then through a
low-pressure separator to split the gas and condensate streams.
The separation of associated gas and condensates may also be done
in several stages to increase the recovery of liquid hydrocarbons.
In the three-stage separation process shown in Figure 7-2, the
first stage (a high-pressure separator) separates the liquid
hydrocarbons from the gas by expanding the stream of well fluids.
Liquid from the first stage separator is partially vaporized in
the second stage (an intermediate-pressure separator) and addi-
tional gas is recovered. The remaining liquid then passes to
the third stage ( a low-pressure separator) for additional
vaporization and gas removal. The liquid remaining after the
third separation stage is transferred to storage. Three-stage
separation is frequently hard to justify economically and is
not as commonly used for gas wells as two-stage separation.
-167-
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7.4.1.3.b Compression
Since pressures are normally high in the early production
life of a gas reservoir, compression to transmit the gas through
the gathering system and into the high-pressure transmission line
may be needed only in later reservoir stages. In oil-gas
reservoirs, however, compression is required throughout the life
of the reservoirs to repressure gases that have been processed
through low-pressure separators. Thus, depending on the type
and stage of the reservoir, a range of compressor facilities
from individual wellhead compressors to a central compressor sta-
tion may be required. Individual wellhead compressors are
flexible, whereas a central compressor station is economical.
7.4.1.3.c Natural Gas Plants
The partially dehydrated, raw natural gas is sent to a gas
processing plant which is usually located near the field. Here
the field gas is processed to meet sales specifications of
utility gas distributors and transmission companies. Some typical
specifications are as follows.-1
(1) A hydrogen sulfide content of less than
0.25 grains per 100 cubic feet (about 4
ppm) and a total sulfur content of less
than 3 grains per 100 cubic feet are
usually required.
(2) Water and hydrocarbon dew point temperatures
may range from as high as 50°F in the south
to as low as 0°F in cold areas.
^hilingar, George V. and Carrol M. Beeson. Surface
Operations in Petroleum Production. New York: American
Elsevier, 1969.
-169-
-------
(3) Air content is usually limited to 1 to
57o by volume.
(4) Carbon dioxide is usually limited to 1
to 5% by volume.
(5) Gross heating value range is specified. A
minimum might be 1000 Btu per standard cubic
foot. Often gas is sold on a Btu basis with
a penalty or credit for each 50 Btu per cubic
foot change in heating value above or below
some base value.
The processing plant has three distinct sections: (1) acid
gas removal usually followed by a Glaus sulfur recovery plant;
(2) gas dehydration; and (3) heavy hydrocarbon separation. A
typical arrangement of these processes is shown in Figure 7-3.
The following sections describe more fully these gas plant
operations.
Acid Gas Removal
Over thirty methods are available for the removal of acid
gas constituents, carbon dioxide, and hydrogen sulfide. Methods
developed range from the simple water-wash techniques to the
molecular sieve removal methods. Most acid gas removal procedures
used in gas plants are characterized by the processes listed in
Table 7-7.
A frequently used method for separation of acid gas is by
absorption with an amine solution. The basic flow is shown in
Figure 7-4. Other common treating absorbents are aqueous
solutions of the ethanol amines or alkali carbonates. In these
-170-
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TABLE 7-7. AVAILABLE GAS TREATING PROCESSES
1 > 2
Chemical Solvents
Amines - Monoethanolamine, diethanolamine, trietholamine,
diglycolamine, diisopropylamine
Activated hot potassium carbonate - Benfield, Catacarb,
Lurgi, Vetrocoke
Others - Alkazid, ammonia, copper liquor, Scott, Stretford,
tripotassium phosphate
Lesser Known - Ferrox, Konox, Manchester, Seaboard, Sulfox,
Thylox, sodium phenolate
Physical Solvents
Fluor solvent, Purisol, Rectisol, Selexol, Sulfinol, water
Solid Bed
Activated carbon, iron oxide, molecular sieves, zinc oxide
Other
Distillation
1 Tennyson, R.N. and Schaff, R.P., "Guidelines can help choose
proper process for gas-treating plants" Oil and Gas Journal
75 (2): p 79.
2 Only a partial list. New technologies are being developed
at all times.
-172-
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processes the sour natural gas is passed countercurrent to a
stream of the absorbent solution in a packed or tray tower. The
H2S and C02 are absorbed by the solution, sweetening the gas.
After leaving the absorber, the rich solution enters a regenerator
where the acid gases are stripped from the solution usually by
heating, but also by pressure reduction in flash vessels, or
by an inert gas stripping. The regenerated solution is then
pumped back to the absorber where a new cycle begins. The H2S
rich stream is usually routed to a Glaus unit.
Molecular sieves are dry bed absorbers. This technology
has been receiving increasing attention in the gas industry.
Advantages of molecular sieves include simplified operation,
reliability, and a wide range of cleanup capabilities. The
molecular sieve can be used for removal of all polar contami-
nants present in the gas, including, water vapor, sulfur- and
oxygen-bearing compounds.
Sulfur Recovery Plant
In a sulfur recovery plant the H2S removed in the acid gas
removal unit is normally converted into more disposable by-
products such as elemental sulfur. The most commonly used
process is the Claus process shown in Figure 7-5.
In the reaction furnace, one third of the H2S is combusted
with a substoichiometric air supply to form S02.J Some sulfur
is formed here and removed, while the rest of the gases pass
to a series of two or three catalytic converters. In these
converters unreacted H2S combines with the S02 formed in the
reaction furnace, producing elemental sulfur which is then
Petroleum Extension Service, University of Texas. Plant
Processing of Natural Gas. Austin, Texas: University of Texas
1974.
-174-
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-175-
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removed by condensation from the process. Efficiencies for
the unit range from 80 to 98 weight percent sulfur recovery.
An overall control efficiency of 96.0 percent may be achieved
with a three-stage Glaus unit.1 Efficiencies attainable are
dependent on the HaS concentration in the feed, the quality of
the catalyst used, and the number of catalytic stages.
Dehydration
Water is the most common impurity in natural gas. Its
removal is accomplished by dehydration with a dry desiccant or
glycol solution. Desiccants commonly used are activated alumina,
silica gel, and molecular sieves. Figure 7-6 shows a typical
two-bed solid adsorbent treater used for dehydration. While
one desiccant bed is removing water from process gas, the other
is being regenerated by heat and then cooled. Frequently a
three-bed system is installed. One unit is adsorbing, one is
being heated or regenerated, and the third is being cooled.
Another gas dehydrating method involves contacting the
wet gas with hygroscopic substances such as diethylene glycol
(DEC) and triethylene glycol (TEG). These chemicals are efficient
drying media, chemically stable and readily available at a
moderate cost.
A typical glycol dehydration plant is presented in Figure
7-7. Water vapor is continuously absorbed from the wet gas
stream by countercurrent contact with a glycol solution. The
dried gas passes out the top of the column. Wet glycol passes
to a regenerator section where the glycol is dehydrated by air
stripping and sent back to the absorber.
T., and J. Dale. "The Effect of the Clean Air Act
Amendments on the Field Processing Units." Twenty-Eighth Annual
Gas Conditioning Conference, Norman, Oklahoma: March 7, 1978.
-176-
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The gas stream may also be dried by glycol injection.1
Lean glycol is injected upstream of a gas chiller. The glycol
mixes with the condensed water and keeps it from freezing. The
stream enters a glycol separator in which the dry gas passes
overhead and the glycol-water mixture leaves from the bottom of
the vessel to be regenerated. This process further reduces the
danger of hydrate formation, and enables the gas to meet the
minimum water specification for sales.
Heavy Hydrocarbon Stripping
Several processes are currently used in the United States
to achieve heavy hydrocarbon separation from the natural gas.
These processes involve various combinations of absorption,
refrigeration, compression, adsorption, fractionation, cryogenic
separation, and turboexpansion. With the exception of the
fractionation process, heavy hydrocarbon stripping processes are
usually identified by the method used to separate ethane and
heavier hydrocarbons from the raw natural gas feed. Brief
descriptions of commonly used separation processes are given
in this section. Included are absorption, refrigerated absorp-
tion, refrigeration, compression, and adsorption.2
In an absorption process the wet field gas is contacted
with an absorber oil in a packed or bubble tray column. Propane
and heavier hydrocarbons are absorbed by the oil while most of
the ethane and methane pass through the absorber. The enriched
Petroleum Extension Service, University of Texas. Plant
Processing of Natural Gas. Austin, Texas: University of Texas.
1974.
2Process Research, Inc., Industrial Planning and Research.
Screening Report, Crude Oil and Natural Gas Production Processes,
Final Report. Cincinnati, Ohio-. Processes Research, Inc., 1972
-179-
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absorber oil is routed to a stripper where the propane and other
hydrocarbons are separated from the absorption oil. The gas stream
of propane and heavier hydrocarbons goes to a stabilizer tower
where any methane and ethane are removed overhead and recycled.
The bottoms product is usually routed to a series of distillation
columns which separate the propane, butane, and natural gasoline
for sales.
The natural gas feed to a refrigerated absorption process
must be dehydrated to a -40°F dew point. An absorption oil cooled
to -40°F or cooler removes all hydrocarbons heavier than methane
from the natural gas. The heavier products are usually separated
by distillation and sold separately.
In the refrigeration process, molecular sieve beds are
used to remove as much water as possible. The dry gas is
cooled to -35°F (-37°C) and then to -135°F (-93°C) with liquid
hydrocarbons being condensed in each stage. The condensed
liquids are then separated by distillation; and the gas,
essentially methane, is ready for transmission.
A compression process uses two stages of compression, each
followed by cooling and gas-liquid separation, to produce a "wet"
natural gas product (still containing some heavy hydrocarbons)
and natural gasoline. Less than 3% of the gas processing plants
in the United States are using compression only for gas separation.
The adsorption system usually consists of two or three
activated carbon beds which alternatively adsorb all hydrocarbons
except methane. The regeneration is effected by steam which
removes the adsorbed hydrocarbons as vapor. These are condensed,
separated from the water, and usually distilled into separate
products. Approximately 12 percent of the existing natural gas
plants in the United States use an adsorptive process.
-180-
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7.4.2 Input Requirements
Input requirements have been estimated for a 250 MM scfd
natural gas production facility. The site of the gas field is
assumed to be Rio Blanco county in western Colorado. The input
requirements have been calculated for some production facilities,
gathering facilities, and a natural gas plant. Inputs examined
include manpower, materials and equipment, economics, water,
land, and ancillary energy. The following discussions outline
and quantify the above input requirements.
7.4.2.1 Manpower Requirements
The construction of a 250 MM scfd gas production collection,
and processing facility is scheduled to take five years. The
required manpower for this construction has been estimated by
Bechtel1 and is shown in Table 7-8. This data is based on the
construction of 83 producing wells each capable of supplying
3 MM scfd of natural gas and the construction of 66 dry holes.
Bechtel assumes that 8 out of every 18 wells will be unsuccessful.
These figures also include the manpower required to design and
construct a natural gas plant to prepare the gas for transmission.
Estimates for the number of men required to operate the 83
wells and natural gas plant have also been made.2 These are
shown in Table 7-9.
^arasso, M., et. al. The Energy Supply Model, computer
tape. San Francisco, California:Bechtel Corporation, 1975.
2Ibid.
-181-
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TABLE 7-8.
SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED FOR CONSTRUCTION OF ONSHORE GAS PRO-
DUCTION FACILITIES TO PRODUCE 250 MMscfd
NATURAL GAS
Skill
Civil Engineers
Electrical Engineers
Mechanical Engineers
Geological Engineers
Petroleum Engineers
Total Engineers
Total Designers & Draftsmen
Total Supervisors & Managers
Total Technical
Total Non-Tech (Non-Manual)
Pipefitters
Pipefitter /Welders
Electricians
Operating Engineers
Other Major Skills
Total Major Skills
Other Craftsmen
Total Craftsmen
Total Teamsters & Laborers
GRAND TOTAL
Source: Carasso, M. , et.al. The
Year
0
0
0
1
1
1
0
0
2
0
0
0
0
1
3
5
0
5
0
7
Energy
Number
Required
1 Year 2 Year 3
1
1
2
9
9
21
6
6
34
5
7
6
1
20
59
92
6
98
7
143
Supply Model,
5
5
10
38
38
95
29
29
153
25
37
29
7
103
308
485
29
514
37
729
Year 4
10
10
19
78
78
195
58
58
311
56
89
71
18
248
744
1168
71
1239
89
1695
Year 5
6
6
12
48
48
119
36
36
191
43
84
67
17
234
702
1103
67
1170
84
1488
computer tape.
San Francisco, California: Bechtel Corporation, 1975.
-182-
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TABLE 7-9. MANPOWER RESOURCES (MAN-YEARS) REQUIRED FOR
OPERATION AND MAINTENANCE OF A 250 MMscfd
ONSHORE GAS PRODUCTION FACILITY
Skill Number Required
Chemical Engineers 2
Civil Engineers 9
Electrical Engineers 2
Mechanical Engineers 9
Geological Engineers 76
Petroleum Engineers 76
Total Engineers 174
Total Designers & Draftsmen 54
Total Supervisors & Managers 36
Total Other Technical 0
Total Technical 264
Total Non-Tech (Non-Manual) 52
Pipefitters 19
Pipefitter/Welders 16
Electricians 3
Operators 19
Other Major Skills 6
Total Major Skills 63
Other Craftsmen 348
Total Craftsmen 411
Total Teamsters & Laborers 63
GRAND TOTAL 790
Source: Carasso, M., et.al. The Energy Supply Model, computer
tape. San Francisco, California:Bechtel Corporation,
1975.
-183-
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7.4.2.2 Materials and Equipment
Bechtel has also estimated the total materials required for
construction of a gathering network and a natural gas plant large
enough to produce 250 MM scfd. These estimates are shown in
Table 7-10.
7.4.2.3 Economics
Bechtel Corporation estimates a total capital requirement
of $400 million (3rd quarter, 1974 dollars) for the drilling
and development of the gas wells, construction of gathering fa*-
cilities, and construction and operation of a 250 MM scfd gas
processing plant.1 This includes a large number of contingency
items. Manpower for conceptual planning and construction costs
for equipment and materials used in development are included in
the total cost. The total cost also includes $25 million for
gas well drilling expenses previously listed in Section 7.3.2.3.
The uncertainty of the resource data estimates vary widely.
Some are classified as accurate; other estimates are only
"rough approximations."2 The cost data should be used for
estimation purposes only.
7.4.2.4 Water Requirements
Water will be used to cool the compressed gases and process
streams much as in any other hydrocarbon process industry. The
major use will be for makeup water for an evaporative cooling
tower. Other water requirements, will be minor. Total water
^arasso, M. , et. al. The Energy Supply Model, computer
tape. San Francisco, California: Bechtel Corporation, 1975.
2Carasso, M., et. al. Energy Supply Model, Vol. I. San
Francisco, California: Bechtel Corporation, 1975. p. 6-29.
-184-
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TABLE 7-10. SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF ONSHORE GAS PRODUCTION
REQUIRED TO SUPPLY 250 MMscfd OF PIPELINE
QUALITY GAS
Resources Quantity
Refined Products (Tons) 128,650
Cement (Tons) 75,000
Ready Mixed Concrete (Tons) 4,150
Pipe & Tubing (Less than 24 inch) (Tons) 15,000
Oil Country Tubular Goods (Tons) 103,750
Reinforcing Bars (Tons) 830
Heat Exchangers (1000 sq. ft. surface) 83
Source: Carasso, M., et. al. The Energy Supply Model, computer
tape. San Francisco, California-. Becntel Corporation,
1975.
-185-
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requirements have been estimated and converted to a plant size
capable of producing 250 MMscfd of natural gas. Water require-
ments for this size plant are estimated to be 380 acre-ft/year.
7.4.2.5 Land Requirements
Approximately 850 acres are required for a gas field and
processing plant with a capacity of 250 MMscfd. Assumptions
used for this data were a total of seven acres per well for
cleared area around producing wells, pipeline right-of-ways,
and roads and 250 acres for plant site.1 Many land owners con-
sider the land usage a significant land improvement allowing
better access for farming and grazing. In wilderness areas,
wildlife frequently use these roads and right-of-ways as better
access to forage.
7.4.2.6 Ancillary Energy
Energy requirements for producing, gathering, maintaining
deliverability, and processing natural gas are net almost ex-
clusively by using a portion of the product gas as fuel. An
estimate of the fuel required expressed in terms of total gas
handled is 3%.2 In areas where electric power is readily avail-
able and cheap, purchased electricity may be attractive.
7.4.3 Outputs
Outputs potentially associated with a natural gas plant
include air emissions, water effluents, solid wastes, noise
pollution, and occupational health and safety aspects. Each of
these will be examined individually.
federal Power Commission: National Gas Survey, Vol. II.
Washington, D.C.: Federal Power Commission,1974.p. 73-75.
2Ibid.
-186-
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7.4.3.1 Air Emissions
Table 7-11 contains air emission rates from the various
sources within the gas field and processing plant. The emission
factors were scaled to a facility processing 250 MM scfd.1
There are several emission sources in the gas production/
process model. Fugitive hydrocarbons and combustion products
result from booster compressors in the field maintaining deliver-
ability of the natural gas to the processing plant. At the
plant, air emissions result from fuel combustion in the glycol
dehydration unit, acid gas removal unit, and the refrigerated
absorption unit. S02 is emitted from Glaus plants and gas
flaring. Miscellaneous fugitive hydrocarbon leaks from valves,
flanges, and equipment seals account for a great deal of the
hydrocarbon emission.2
7.4.3.2 Water Effluents
No water streams leave a processing plant; thus, water
pollution from such a facility is negligible. Rain or storm
water runoff may pick up a small amount of liquid hydrocarbon
resulting from spills, human error, or equipment failure, but
not data is available on this subject.
Environmental Protection Agency. Compilation of Air Pol-
lution Emission Factors, 2nd edition with supplements.AP-42.
Research Triangle Park, North Carolina: Environmental Protection
Agency. April, 1977.
2Cavanaugh, E.G., et. al. Atmospheric Pollution Potential
from Fossil Fuel Resource Extraction, On-Site Processing, and
Transportation.EPA Contract No.68-02-1319.Austin, Texas:
Radian Corporation. March, 1976.
-187-
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-188-
-------
7.4.3.3 Solid Wastes
There are no significant solid wastes generated by the
natural gas processing facility.
7.4.3.4 Noise Pollution
Several pieces of equipment used in gathering systems and
processing plants are potential sources of high noise levels.
These include control valves, engines, compressors, and turbines.
However, noise control is required in plants to meet Occupational
Safety and Health (OSHA) standards. Normally the local area
around a plant or production facility has very few noise pollu-
tion problems. Noise suppression programs have reduced noise
from gas flow through meters and regulations and also from com-
pressors and auxiliary equipment.1
7.4.3.5 Occupational Health and Safety
The information for this section is included in Section 7.3.3.5
7.4.3.6 Odor
A producing well usually has no associated odor problems be-
cause the odor-causing compounds (H2S, mercaptans, and others) are
fairly dilute and any gas leak will be easily dissipated below
the odor threshold for these impurities in air. At the plant
where more concentrated streams of these compounds are found,
odor does present a pollution problem. Good housekeeping practice
and preventive maintenance are the best safeguards against odor.
federal Power Commission. Natural Gas Survey, Vol II.
Washington, D.C.: Federal Power Commission.19747 pT73-75.
-189-
-------
7.4.4 Production Social Controls
Some of the social controls for oil production are applic-
able to natural gas production and will be noted below in the
specific sections; where controls are applicable only to gas pro-
duction, they will be described in detail. As with oil controls,
some federal lands (public or acquired) and others (e.g., FPC
rate regulation)l apply to gas production irrespective of place
of production. Likewise some state laws apply to some produc-
tion and not to other production.
7.4.4.1 Federal Laws and Regulations
7.4.4.1.a Conservation of the Public Domain
Conservation laws applicable to gas production on the public
domain are identical to those for oil production and are described
in Section 6.4.2.1.1 of Chapter 6. However, variations may occur.
For example, the federal laws were written to allow some state
regulation for conservation on the public 'domain lands within that
state; hence the state has some input into the spacing of wells
which is different for oil than gas. Recent court decisions have
modified this by saying - although the state may set the "con-
servation tone" the federal agency must give its approval of the
2
arrangement.
Although there is no doubt the rate regulation affects pro-
duction and therefore deserves discussion here, certain factors
make it better to discuss it in the transportation sections. One
such factor, for example, is the interstate/instrastate determination,
by the FPC. Such a determination, inherently a transportation
question, also sets the pre-determined rate. See Section 7.5.2.1.1.
2E.g., Texas Oil and Gas Corp. v. Phillips Petroleum Co.,
277 F. Supp. 366 (W.D. Okla. 1967), affirmed per curiam, 406 F.
2dl303 (10th Cir.), cert denied, 396 U.S. 829 (1969). See also,
Sharpiro, Mickael E. "Energy Development on the Public Domain:
Federal/State Cooperation and Conflict Regarding Environmental
Land Use Control." Natural Resources Lawver, Vol. 9 (No. 3,
1976), pp. 429-31.
-190-
-------
7.4.4.1.b Air Quality - Federal
Federal air pollution laws and regulations affecting gas
production are not significantly different from those affecting
oil production. As noted in Chapter 6, the NSPS that have been
promulgated address only petroleum refineries and liquid petro-
leum storage facilities.1 NSPS are being prepared for crude oil
and natural gas field processing units which will place limits on
hydrogen sulfide content of any gaseous fuel burned at a field
processing facility, on sulfur dioxide or total reduced sulfur
emissions of sulfur recovery facilities, and on hydrocarbon
emissions on petroleum storage vessels.2 Until those NSPS are
promulgated, gas production facilities are only bound by federal
ambient standards as discussed in Chapter 6, or state laws and
regulations as discussed in Section 7.4.4.2.b.
7.4.4.1.C Water Quality - Federal
Water effluents from gas production are either injected into
underground formations or held in storage ponds. As noted in
Section 6.4.2.1.3, the applicable laws have been identified in
the water quality section of Chapter 2 as to surface and under-
ground regulation. Additionally in Section 6.4.4.1.C it was
noted that EPA was moving into the area under the Safe Drinking
Water Act of 1974.3 Proposed regulations have been published
and will be summarized below for only the oil and gas operations
subpart. **
1 See Section 6.4.4.1.b Air Pollution; also note that Petroleum
Refineries are not included in these ERDS and that the storage
facilities NSPS specifically exempt production or drilling faci-
lities (40 C.F.R. 60.110(b) and 60.110 (h)).
2Thoem, T. and Dale, J., "The Effect of the Clean Air Act
Amendments on Field Processing Units," Twenty-Eighth Annual Gas
Conditioning Conference, Norman, Oklahoma: March 7, 1978.
3 Safe Drinking Water Act of 1974, 1421, 1422, and 1450,
42 U.S.C.A. (Supp. 1976).
"41 Federal Register 36730 (Aug. 31, 1976).
-191-
-------
As with the prior environmental laws (e.g., the FWPCA or
CAA), those regulations under SDWA list minimums for state in-
jection control programs and make provisions for turning the
enforcement over to the state. More specifically as to oil and
gas, the SDWA prohibits EPA from regulating injection (i.e.,
either disposal or secondary and tertiary recovery) where such
regulation will interfere with oil or gas production, unless such
regulation is essential to protection of drinking water sources.1
However, EPA's proposed regulations require first that the dis-
charger (injector) prove his oil or gas operation is interfered
with before the Administrator prove his regulations are essential.2
Generally the proposed oil and gas regulations allow for:
(1) Existing injection wells to be controlled by
existing rules for 5 years if no endangerment
(2) New injection wells to be controlled by
permits
(3) Public notice and hearing on permits
(4) New well aquifers, other wells, pressures,
soils, "etc.
The comment period on the proposed regulations was extended
until Jan. 14, 1977.3
federal Register, Vol. 41 (August 31, 1976), p. 36731.
2Ibid.
'Federal Register, Vol. 41 (November 19. 1976), p. 50701
-192-
-------
7.4.4.2 State Laws and Regulations
7.4.4.2.a Conservation
State conservation laws attempting to protect the supplies
of natural gas by requiring efficient production techniques have
not been as strongly supported in the courts as have similar laws
for oil production. Essentially the state regulation of natural
gas pricing for conservation purposes has lost when brought to
court and has been opposed by the broad powers given the FPC over
natural gas pricing. The line of cases and authorities dispute
how far the states can go to regulate natural gas production
but it appears to be only as long as it does not affect price.
States can at a minimum regulate the production of natural
gas from gas fields by a process called "ratable taking". In
this process each producer in a common zone is required to hold
his production to a percentage of the maximum possible production,
based on his ownership, structure, and natural flow. (Still to
be answered are the state laws on this question. It may not be
of value since it only restricts the producers in an area from
taking more than their share, but does not change total produc-
tion from zone. In fact the law is designed to get maximum total
production from the zones.)
7.4.4.2.b State Air Quality Laws
Although in Section 7.4.4.1.2 Air Quality Federal, it was
states that the New Source Performance Standards (i.e., for
Petroleum Refineries) were not applicable to the production
-193-
-------
technologies described, some of the states have modified the
standards to make them applicable. The states are allowed to
do such under the provisions of the Act.1 Treatment of the
specific air pollution problems of natural gas production has
been attampted by various methods in states. Below are recorded
the states' laws and regulations on natural gas flaring. Equip-
ment used in gas recovery operations (e.g., high horsepower
pumps) are regulated for air pollution no differently than
other engines and such regulations can be found in Chapter 2.
Generally under their respective air pollution laws and
regulations each state prohibits open burning. But: each state
also provides for various exemptions from those regulations.
Sometimes the flaring of natural gas at production facilities
is authorized, sometimes prohibited, and sometimes required.
Unless noted specifically the regulations described below apply
generally to any natural gas flaring whether as a by-product
of oil production or of gas production. Most gas flaring occurs
as a by-product of oil production.
The following table summarizes and divides the state regu-
lations into two categories - the general and specific incin-
eration bans. Although Montana and Colorado have a ban on the
incineration of wastes, the more specific regulations detailing
the limitation have varied probable controls and are recorded
(Table 7-12).
1 See Chapter 2, Section 2.8.3.a. The reader is reminded
again that all aspects of the Clean Air Act as described in
Chapter 2, Section 2.8 must be complied with (e.g., ambient air
standards, etc.) and that this section will only point out the
specifics of each state's laws that are aimed directly at the
air pollution problems caused by natural gas production.
-194-
-------
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-196-
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New Mexico has some very specific air quality regulations
which deserve extra attention in addition to those already de-
scribed. For the gas resource, the regulations listed in Section
6.4.4.2.C are also applicable where the gas is produced together
with oil. The only regulations in New Mexico applicable to gas
production alone are those for Natural Gas Processing Plants -
Sulfur Emission Limitations.
In summary those regulations require new natural gas proces-
sing plants to comply with the following:1
G. No person owning or operating a new natural gas
processing plant that is governed by a sulfur emission
limitation of an Air Quality Control Regulation shall
permit, cause, suffer or allow gas coming off any off-
gas sweetening regeneration unit or other sulfur
releasing unit to be sent to a facility other than
the natural gas processing plant for the purpose of
sulfur recovery or disposal:
1. unless all the gas coming off the gas sweetening
regeneration unit or other sulfur releasing unit is
sent to the facilities other than the natural gas
processing plant, except mercaptan gas, and the amount
of sulfur in the off-gas stream from fuel burning
equipment does not exceed the quantity of sulfur that
would exist if the sulfur content of the gas used for
fuel was 10 grains of sulfur per 100 standard cubic
of fuel gas; or
2. unless only a portion of the gas coming off the
gas sweetening regeneration unit or other sulfur
releasing unit is sent to the facility other than the
natural gas processing plant, and:
(a) if the natural gas processing plant is a new
natural gas processing plant that releases an average
of five or more tons a day but less than twenty tons
a day of sulfur in plant processes, sulfur emissions
from the new natural gas processing plant do not
exceed 10 pounds of sulfur for every 100 pounds of
sulfur that are released in plant processes but not
LNew Mexico Air Quality Regs., #621. as reprinted in BNA,
State Air Laws, pp. 72-77, May 23, 1975.
-197-
-------
sent for sulfur recovery or disposal to another
facility; or
(b) if the natural gas processing plant is a new
natural gas processing plant that releases an average
of twenty tons a day or greater of sulfur in plant
processes, sulfur emissions from the new natural gas
processing plant do not exceed 2 pounds of sulfur for
every 100 pounds of sulfur in plant processes but not
sent for sulfur recovery or disposal to another facility.
H. No person owning or operating a natural gas processing
plant shall permit, cause, suffer or allow sulfur
compounds to be emitted to the atmosphere unless the
sulfur compound emission is from a stack of a suffi-
cient physical height to prevent concentrations of
sulfur compounds near ground level equal to any
state or federal ambient air standard.
1. The necessary physical stack height shall be
determined by the following graph. (Table 7-13) .
I. No person owning or operating a new natural gas
processing plant that releases an average of five or
more tons a day and less than twenty tons a day of
sulfur in plant processes shall permit, cause, suffer
or allow sulfur emissions to the atmosphere in excess
of 10 pounds of sulfur for every 100 pounds of sulfur
released in plant processes.
J. No person owning or operating a new natural gas
processing plant that releases an average of 50 tons a
day or greater of sulfur in plant processes shall permit,
cause, suffer or allow sulfur emissions to the atmosphere
in excess of 2 pounds of sulfur for every 100 pounds of
sulfur released in plant processes.
L. To aid the department in determining compliance
with this section, the owner or operator of a natural
gas processing plant to which this section applies
shall submit to the department quarterly reports in
the months of January, April, July, and October of
each year containing the following information:
1. the sulfur content of feedstock entering the natural
gas processing plant determined no less frequently
than three times per week and no more frequently than
once every twenty-four hours;
2. the sulfur content of all fuel burned in the plant
and the amount of each type of fuel burned determined
no less frequently than quarterly;
-198-
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TABLE 7-13.
REQUIRED STACK HEIGHT FOR GAS PROCESSING PLANTS
IN NEW MEXICO
2 3 4 56789 10 15
Hydrogen Sulfide Combusted, 1000 Pounds
20
/Day
Source: New Mexico Air Quality Regulations #621. As reprinted
in BNA, State Air Laws, p. 75, May 23, 1975.
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3. the sulfur content of the products produced by
the natural gas processing plant determined no less
frequently than weekly;
4. the sulfur content of the inlet and outlet gas
stream or streams of the sulfur recovery plant determined
no less frequently than quarterly; and
5. the weight of the recovered sulfur determined no
less frequently than weekly.
If it appears necessary, the department may require reports
on a more frequent basis, but no more frequently than monthly.
The department may, upon the request of the owner or operator
of a natural gas processing plant, alter the sampling periods
specified in this subsection.
The above is not a complete discussion of controls over gas
production since a large portion of the regulations are written
for the production of oil and gas together. Therefore a pro-
duction facility producing both oil and gas would have to comply
with air quality regulations associated with both.
7.4.4.2.C State Water Quality Laws
Water effluents are controlled by both federal and state
laws and as described in Section 7.4.4.1.C, new injection regula-
tions are being written to modify and expand the present state
laws. At this time the present state laws are not described
(again see Section 7.4.4.1.c). The federal minimum regulations
took effect in December 1977. It is possible that because the ini-
tial regulations are aimed selectively at the states having greater
injection problems perhaps not all of the eight western states will
initially be brought under the new underground injection program.1
Determination of which states have not yet been made, but
the criteria include reliance on underground sources for drinking
water and magnitude of the injection operations in the state.
41 Fed. Reg. 36731 (Aug. 31, 1976).
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7.4.4.2.d Miscellaneous State Laws Affecting Production
There are numerous state laws affecting oil and gas opera-
tions (Table 7-14). The laws have various purposes but generally
reflect a states' concern over protecting the public interest
(e.g., in preventing pollution of a drinking water source) or
in protection of the correlative rights of other resource pro-
ducers (e.g., regulating the oil and gas ratio to prevent rapid
dissipation of reservoir pressure). The states which have
statutory duties are listed in Table 7-14.
7.5 TRANSPORTATION OF NATURAL GAS
7.5.1 Technologies
Transportation of natural gas throughout the nation's gas
system, from field to market, is accomplished primarily by
pipelines. Pipelines collect the gas from individual wells and
deliver it to a processing plant or treating facility. This is
called the field and gathering system, and was discussed in
Section 7.4 with the production and processing technologies.
After processing, the salable natural gas is compressed and
moved in relatively large lines in a network which covers the en-
tire country. Compressors placed along the length of the pipe-
lines provide the driving force to keep the gas moving. Smaller
pipeline branches provide the means of delivery to the ultimate
consumer whether industries, business, or residences.
Total natural gas pipeline mileage in the United States at
the end of 1975 was 980,000 miles with approximately two-thirds
of the mileage being used as the smaller distribution mains to
consumers. Total mileage in the eight mountain states is
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-202-
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approximately 81,000 miles,1 about eight percent of the U.S.
mileage.
Transmission lines are usually 24, 30, 36, and 42-inch
diameter systems with the 30-inch being the most popular. Main-
tenance of the 750 psig pressure, the usual operating pressure
of a long distance line, is performed by compression stations
spaced strategically along the length of the line. Average
spacing for compressor station of 50 to 75 miles.2 Compressors
are driven by gas engines, gas turbines, and electric power.
The size of compressor stations varies widely, but most of the
new construction in stations ranges from 2,500 to 10,000 horse-
power. 3
Energy consumption for a compressor station system averages
4.1 percent of the throughput of the stations." Most of the
fuel is natural gas, although more and more electrically powered
stations are being installed.
7.5.2 Social Controls
Pipeline social controls for gas are the same as those oil
concerning such subjects as rights-of-way and are discussed in
Chapter 6. There are variations though between oil and gas when
1American Gas Association, Department of Statistics. Gas
Facts, 1975 Data. Arlington, Virginia: American Gas Association.
19W. p. 29.
2Cavanaugh, E.G., et. al. Atmospheric Pollution Potential
from Fossil Fuel Resource Extraction, On-Site Processing, and
Transportation. EPA Contract No . 68-02-1319 . Austin, Texa~s :
Radian Corporation. March, 1976.
3Congram, G.E. "U.S. Pipeline Investment Expands by $4.26
Billion," Oil and Gas Journal, 75 (34), p. 78.
^Battelle-Columbus and Pacific Northwest Labs. Environmental
Considerations in Future Energy Growth. Columbus, Ohio: Bat-
telle-Columbus and Pacific Northwest Labs. 1973.
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describing the controls over rate setting and safety and those
will be described below.
7.5.2.1 Federal Laws and Regulations
7.5.2.1.a Federal Power Commission (FPC)
Natural gas pipelines operating in interstate commerce are
required to obtain a license from the Federal Power Commission.r
Naturally the right-of-way must be obtained from the proper
authority, for example from the Secretary of Interior for public
domain lands. A complete discussion of right-of-way procedures
is located in Section 2.14.
A primary function of the FPC for natural gas regulation
is the interstate/intrastate price rate determination. The FPC
derives authority for such action from the Natural Gas Act,
wherein the FPC was given the power to regulate the wellhead
price of natural gas dedicated to interstate commerce to pro-
tect consumers.2 Other functions of the FPC are regulating the
profits and prices of natural gas pipeline companies and coor-
dinating planning among firms engaged in interstate electric
power transmission.3
'Natural Gas Act of 1938, § 7, 15 U.S.C.A. § 717 (f) (19 ).
A Corps of Engineers permit is also required if the pipeline
crosses navigable waters - permits are discussed in Section
2Dolgin and Guilbert, Federal Environmental Law, West, St.
Paul: 1974 p. 942. See Phillips Petroleum Co. v. Wisconsin,
347 U.S. 672 (1954) wherein the U.S. Supreme Court held such
authority for the FPC existed.
3Breyer, Stephen G., and Mactvoy, Paul W. Energy Regulation
by Federal Power Commission, Brookings Institute"Washington,
1974:p. 4.
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The regulation of a natural gas pipeline company by the
FPC begins with the issuance of a certificate of public con-
venience and necessity to the company allowing it to provide
service into a new market area. The FPC must determine the suf-
ficiency of the demand for the proposed service and the ability
of the company to provide the service. If the certificate is
granted, then prices to be charged are reviewed and differences
of opinion between the company and the FPC pipeline division are
settled by a hearing examiner. Pricing appeals may be taken to
the FPC itself and then to the federal courts.1
Natural gas production regulation started with the U.S.
Supreme Court ruling in 1954 that the FPC had authority to set
prices charged by producers on sales to interstate pipeline.2
Initial attempts at rate setting were frustrated when cost of
service determinations varied widely; subsequently the FPC
adopted an area-wide average cost basis for price setting and
was upheld in the Permian Basin Area Cases.3 Under this system
the regulation is in the form of a ceiling price for an area of
production. Unfortunately the varied situations (i.e., higher
costs for some exploration) and long time delay in area-wide
price hearings has resulted in a continued and growing use of
cerfiticates issued to individual producers. "* Again, it should
be noted that intrastate gas sales are exempt from FPC regula-
tion but that such a determination will only come into play where
the natural gas consumer would be a utility buying within a state
hence possibly buying at unregulated prices.
Greyer, Stephen G., and Mactvoy, Paul W. Energy Regulation
by Federal Power Commission, Brookings Institute, Washington,
1974: p. 5.
2Phillips Petroleum Company v. Wisconsin, 347 &.S. 672(1954)
3390 U.S. 747 (1968).
"Breyer, op.cit. p. 9.
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7.5.2.1.b Department of Transportation
Under the provisions of the Natural Gas Pipeline Safety Act
of 1968,1 natural gas pipelines must comply with the regulations
promulgated by the Department of Transportation's Office of
Pipeline Safety (OPS).2
Natural Gas Pipeline Safety Act of 1968, 82 Stat. 720 42
U.S.C.A. 1671 e£ seg_. (1970).
2Dolgin and Guilbert, Federal Environmental Law, West, St
Paul: 1974 p. 972.
i>U.S.a)yB»IMOnHimTIIIGOFriCE 1979 -281-U7/60
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