Environmental Protection
Agency I
Research] and Development
Office of Energy, Minerals, and t I'A BOO /
Industry M.ncli 11)/!
Washington DC 20460
Erjergy from the
Energy Resource
Development
Systems Report
Volume III: Oil Shale
Interagency
Energy/Environment
R&D Program
Report
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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 III: Oil Shale
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
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
Project Officer:
Steven E. Plotkin
Office of Energy, Minerals and Industry
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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. Reztfiek
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) .
v
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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
specifiq, 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
Chapter 2
1.1 Introduction ,
1.2 Objectives of the ERDS Document...
1.3 Organization of the ERDS Document.
1.4 Limitations of the ERDS Document..
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 Benef iciation 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 Introduction 1
4. 2 Summary 4
4.3 Resource Description 13
4. 4 Exploration 25
4.5 Mining and Preparation 37
4.6 Processing 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 III
CHAPTER 4: THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM PaSe
4.1 INTRODUCTION 1
4.2 SUMMARY 4
4.3 RESOURCE DESCRIPTION 13
4.3.1 Resource Endowment 14
4.3.2 Ownership of the Resources 23
4.4 EXPLORATION 25
4.4.1 Technologies 25
4.4.2 Input Requirements 27
4.4.3 Outputs 30
4.4.4 Social Controls 33
4.5 MINING AND PREPARATION 37
4.5.1 Underground Mining 39
4.5.1.1 Technologies 39
4.5.1.2 Input Requirements 50
4.5.1.3 Outputs 61
4.5.2 Surface Mining 75
4.5.2.1 Technologies 75
4.5.2.2 Input Requirements 80
4.5.2.3 Outputs- 88
4.5.3 Mining for In-Situ Processing 100
4.5.3.1 Technologies 100
4.5.3.2 Input Requirements 108
4.5.3.3 Outputs 119
4.5.4 Social Controls 127
xi
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TABLE OF CONTENTS (Continued)
VOLUME III
Page
4. 6 PROCESSING 142
4.6.1 Surface Processing 142
4.6.1.1 Technologies 143
4.6.1.2 Input Requirements./ 189
4.6.1.3 Outputs 211
4.6.2 In-Situ Processing 238
4.6.2.1 Technologies 238
4.6.2.2 Input Requirements 255
4.6.2.3 Outputs 265
4.6.3 Modified In-Situ Processing with Surface
Processing of Mined Shale 278
4.6.3.1 Technology 278
4.6.3.2 Input Requirements 281
4.6.3.3 Outputs 284
4.6.4 Processing Social Controls 293
4. 7 LAND RECLAMATION 297
4.7.1 Characteristics of Processed Shale 298
4.7.2 Disposal and Reclamation of Processed
Shale : . . 300
xii
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LIST OF FIGURES
VOLUME III
CHAPTER 4: THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM
Number Page
4-1 Distribution of U.S. Oil Shale Resources 18
4-2 Oil Shale Areas in Colorado, Utah, and Wyoming.... 20
4-3 Diagrammatic Cross-Section of Green River
Formation 22
4-4 Oil Shale Development Schemes 38
4-5 Room-And-Pillar Mining 43
4-6 Shale Sizing Operations 48
4-7 Project Manpower Estimate 53
4-8 Hypothetical Open Pit Oil Shale Mine 78
4-9 Plan View of Retort Arrangement 101
4-10 Cross-Section of In-Situ Complex: Retort
Operation and Development 103
4-11 An In-Situ Retort Being Developed By The
Vertical Slot Development Method 105
4-12 An In-Situ Report Being Developed By The Multiple
Level Development Method 105
4-13 Modified Sublevel Caving Method Proposed For
Use in Rise Process 109
4-14 Manpower Projections 113
4-15 Classification of Retorting Methods 144
4-16 Pyrolysis and Oil Recovery Unit TOSCO II Process.. 146
4-17 Flow Diagram of Institute of Gas Technology Oil
Shale Process 153
4-18 Paraho Direct Mode Flow Diagram 158
4-19 Paraho Indirect Mode Flow Diagram 159
4-20 Union Retort B 164
xiii
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LIST OF FIGURES (Continued)
VOLUME III
Number Page
4-21 Union Retort B Flow Diagram 165
4-22 The Lurgi-Ruhrgas Process for the Retorting of
Oil Shale 171
4-23 Cross-Section of Circular Grate Retort 178
4-24 Plan View of Circular Grate Retort Showing
Movement of Charge through Various Zones 179
4-25 Upgrading and By-Product Recovery Facilities 186
4-26 Water System Flow Diagram of TOSCO II Oil Shale
Process 202
4-27 Simplified Schematic of LERC True In-Situ Process. 243
4-28 Simplified Drawing of an Operating Retort 247
4-29 Flow Diagram of Oil Shale Processing Facility
Featuring Modified In-Situ and Surface Retorting.. 279
xiv
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LIST OF TABLES
VOLUME III
CHAPTER 4: THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM
Number Page
4-1 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
THE EXPLORATION OF OIL SHALE IN THE WESTERN U.S.. 5
4-2 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH AN
UNDERGROUND MINE PRODUCING 66,000 TPD OF CRUSHED
OIL SHALE 6
4-3 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
SURFACE MINE PRODUCING 66,000 TPD OF CRUSHED OIL
SHALE 7
4-4 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MINE EXCAVATING 41,000 TPD OF OIL SHALE FOR A
MODIFIED IN-SITU DEVELOPMENT 8
4-5 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
SURFACE RETORTING/PROCESSING PLANT PRODUCING
50 ,000 BPD OF SHALE OIL PRODUCTS 9
4-6 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU PROCESSING PLANT PRODUCING
57,000 BPD OF SHALE OIL 11
4-7 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU AND SURFACE PROCESSING PLANT
PRODUCING 76,000 BPD OF SHALE OIL 12
4-8 TYPICAL COMPOSITION OF OIL SHALE SECTIONS IN THE
MAHOGANY ZONE OF COLORADO AND UTAH AVERAGING
25 GALLONS OF OIL PER -TON 15
4-9 OIL SHALE RESOURCES OF THE U.S 16
4-10 LOCATION OF OIL SHALE RESOURCES 19
4-11 OIL SHALE RESOURCES IN THE GREEN RIVER FORMATION. 21
4-12 OWNERSHIP OF GREEN RIVER FORMATION OIL SHALE
LANDS 24
4-13 OIL SHALE OWNERSHIP BY MAJOR OIL COMPANIES 24
4-14 ESTIMATED MANPOWER REQUIREMENTS FOR GEOLOGIC
EXPLORATION TECHNIQUES 28
xv
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LIST OF TABLES (Continued)
VOLUME III
Number Page
4-15 ESTIMATED MANPOWER COSTS FOR GEOLOGIC EXPLORA-
TION TECHNIQUES 29
4-16 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
THE EXPLORATION OF OIL SHALE IN THE- WESTERN U.S.. 33
4-17 OIL SHALE EXPLORATION PERMIT FOR UTAH 36
4-18 MANPOWER REQUIREMENTS FOR ROOM-AND-PILLAR
UNDERGROUND MINING 51
4-19 DESCRIPTION OF COMMERCIAL MINING EQUIPMENT 54
4-20 ESTIMATED EQUIPMENT LIST FOR UNDERGROUND MINING
OF 66,000 TPD 55
4-21 CAPITAL COST ESTIMATES FOR AN UNDERGROUND SHALE
MINE 57
4-22 ANNUALIZED OPERATING COSTS FOR AN UNDERGROUND
SHALE MINE 59
4-23 SURFACE AREAS DISTURBED BY AN UNDERGROUND MINING
DEVELOPMENT EXTRACTING 66,000 TPD 61
4-24 ANCILLARY ENERGY REQUIREMENTS FOR UNDERGROUND
SHALE MINING 62
4-25 MINE VENT EMISSIONS, LB/HR FROM UNDERGROUND SHALE
MINE EXCAVATING 66,000 TPD 64
4-26 PARTICULATE EMISSIONS FROM 'CRUSHING AND CONVEYING
FOR AN UNDERGROUND SHALE MINE EXCAVATING 66,000 TPD 65
4-27 CONCENTRATIONS (MG/L) FOR DISSOLVED CONSTITUENTS
IN GROUNDWATER IN THE PICEANCE CREEK BASIN 68
4-28 NOISE LEVELS ENCOUNTERED BY MINE WORKERS 71
4-29 POLYCYCLIC AROMATIC HYDROCARBONS DETECTED IN RAW
OIL SHALE 73
4-30 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH AN
UNDERGROUND MINE PRODUCING 66,000 TPD OF CRUSHED
OIL SHALE 74
xvi
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LIST OF TABLES (Continued)
VOLUME III
Number Page
4-31 ESTIMATED EQUIPMENT LIST FOR A SURFACE MINE
EXCAVATING 66 , 000 TPD OIL SHALE 83
4-32 UNIT ANNUALIZED COSTS FOR THE OPEN PIT MINING
OF OIL SHALE 85
4-33 PRELIMINARY ANNUALIZED COSTS ESTIMATES FOR THE
OPEN PIT MINING OF OIL SHALE. 87
4-34 AVERAGE OF SURFACE DISTURBANCES ASSOCIATED WITH
A 66,000 TPD SURFACE MINING OPERATION 89
4-35 ANCILLARY ENERGY REQUIREMENTS FOR SURFACE SHALE
MINING AND CRUSHING 90
4-36 ATMOSPHERIC EMISSIONS FROM OIL SHALE SURFACE
MINING 92
4-37 NOISE LEVELS ENCOUNTERED BY MINE WORKERS 98
4-38 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
SURFACE MINE PRODUCING 66,000 TPD OF CRUSHED OIL
SHALE 99
4-39 MANPOWER REQUIREMENTS FOR IN-SITU MINING
OPERATIONS Ill
4-40 ESTIMATED EQUIPMENT LIST FOR MINING OF 41,000 TPD
FROM IN-SITU OIL SHALE COMPLEX 115
4-41 MINING CAPITAL COST ESTIMATES FOR AN IN-SITU OIL
SHALE COMPLEX 116
4-42 ANNUALIZED OPERATING COSTS FOR MINING AT AN
IN-SITU OIL SHALE COMPLEX 118
4-43 ANCILLARY ENERGY REQUIREMENTS FOR MINING IN AN
IN-SITU OIL SHALE FACILITY 120
4-44 MINE VENT EMISSIONS FROM MINING IN AN IN-SITU
OIL SHALE FACILITY PRODUCING 57,000 BPD 122
4-45 PARTICULATE EMISSIONS FROM TRANSPORTATION AND
DISPOSAL OF MINED-OUT SHALE 123
4-46 NOISE LEVELS ENCOUNTERED BY MINE WORKERS 126
xvii
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LIST OF TABLES (Continued)
VOLUME III
Number Page
4-47 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MINE EXCAVATING 41,000 TPD OF OIL SHALE FOR A
MODIFIED IN-SITU DEVELOPMENT 128
4-48 WYOMING OIL SHALE LEASE 136
4-49 UTAH OIL SHALE LEASE 136
4-50 SUMMARY OF PROPERTIES OF CRUDE SHALE OIL PRODUCED
BY TOSCO II PROCESS 150
4-51 PROPERTIES OF CRUDE SHALE OIL PRODUCED BY TOSCO II
PROCESS 151
4-52 TOSCO II SEMIWORKS PLANT COMPOSITION OF C* AND
LIGHTER GAS 152
4-53 PROPERTIES OF SHALE OIL OBTAINED FROM HYDRORETORT-
ING IN IGT' S BENCH-SCALE UNIT 155
4-54 PROPERTIES OF PROCESSED SHALE RESIDUE OBTAINED
FROM HYDRORETORTING IN IGT'S BENCH-SCALE UNIT.... 155
4-55 PROPERTIES OF PARAHO SHALE OILS 162
4-56 COMPOSITION OF PARAHO RETORT GASES 163
4-57 PROPERTIES OF UNION RETORT B CRUDE OIL 169
4-58 CHARACTERISTICS OF OIL PRODUCTS OF THE LURGI-
RUHRGAS RETORTING PROCESS 174
4-59 PROPERTIES OF DISTILLATION GAS FROM LURGI-RUHRGAS
RETORTING PROCESS 175
4-60 PRODUCTS OF THE LURGI-RUHRGAS RETORTING PROCESS.. 176
4-61 PRODUCTS FROM THE SUPERIOR MULTIMINERAL RECOVERY
PROCESS 181
4-62 SUMMARY OF "ON-SITE" SHALE OIL UPGRADING BY
SEVERAL OIL SHALE DEVELOPERS 184
4-63 MANPOWER REQUIREMENTS FOR 50,000 BPD TOSCO II
SURFACE PROCESSING 191
xviii
-------
LIST OF TABLES (Continued)
VOLUME III
Number Page
4-64 CONSTRUCTION PHASE ESTIMATE OF CRAFT LABOR 193
4-65 PRODUCT AND INTERMEDIATE TANKAGE FOR A 50,000 BPD
FACILITY 195
4-66 DETAILED EQUIPMENT LIST FOR A 100,000 BPD OIL SHALE
RETORTING AND UPGRADING FACILITY 196
4-67 CAPITAL COST ESTIMATES FOR TOSCO II RETORTING AND
UPGRADING FACILITIES 198
4-68 ANNUALIZED OPERATING COSTS FOR A 50,000 BPD TOSCO
II PROCESSING FACILITY 200
4-69 USES OF WATER BY TOSCO II SHALE PROCESS PRODUCING
50,000 BPD SHALE OIL 203
4-70 WATER REQUIREMENTS OF A 50,000 BPD PARAHO SHALE
OIL PLANT 205
4-71 SURFACE AREAS DISTURBED BY A TOSCO II PROCESS
PRODUCING 50,000 BPD SHALE OIL 207
4-72 HEAT LOADS TO PROCESSING UNITS AT A TOSCO II
FACILITY PRODUCING 50,000 BPD 209
4-73 SUMMARY OF AIR EMISSIONS FROM A TOSCO II PROCESS-
ING FACILITY PRODUCING 50,000 BPD SHALE OIL
PRODUCTS 212
4-74 ELEMENTAL CONCENTRATIONS IN TOSCO II SURFACE-
RETORTED OIL SHALE 215
4-75 MINERAL CONSTITUENTS IN TYPICAL RETORTED OIL
SHALES 216
4-76 POLYCYCLIC AROMATIC HYDROCARBONS DETECTED IN
TOSCO II SURFACE-RETORTED SHALE 217
4-77 AIR EMISSIONS FROM THE PARAHO AND UNION B RETORTS 222
4-78 APPROXIMATE COMPOSITION OF TOSCO II COMBINED PRO-
CESS WASTEWATER 224
4-79 ANALYSIS OF PARAHO PROCESS WASTEWATER 225
xix
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LIST OF TABLES (Continued)
VOLUME III
Number Page
4-80 INORGANIC IONS LEACHABLE FROM FRESHLY RETORTED
SHALES 227
4-81 MAJOR SOLID WASTES FROM A TOSCO II COMPLEX PRO-
DUCING 50,000 BPD 229
4-82 POSSIBLE USES OF PROCESSED SHALE 231
4-83 COMPARABLE CARCINOGENIC POTENCY OF COMPLEX
MIXTURES 234'
4-84 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
SURFACE RETORTING/PROCESSING PLANT PRODUCING
50,000 BPD OF SHALE OIL PRODUCTS 236
4-85 PROPERTIES OF CRUDE SHALE OIL PRODUCED FROM THE
OCCIDENTAL IN-SITU PROCESS 250
4-86 MANPOWER REQUIREMENTS FOR IN-SITU RETORTING AND
PROCESSING OPERATIONS PRODUCING 57,000 BPD 257
4-87 CAPITAL COST ESTIMATES FOR AN IN-SITU OIL SHALE
COMPLEX PRODUCING 57,000 BPD 260
4-88 ANNUALIZED OPERATING COSTS FOR AN IN-SITU OIL
SHALE COMPLEX PRODUCING 57,000 BPD . . 262
4-89 SUMMARY OF WATER REQUIREMENTS FOR A MODIFIED IN-
SITU FACILITY PRODUCING 57,000 BBL OF SHALE OIL
PER DAY 264
4-90 ANCILLARY ENERGY REQUIREMENTS FOR AN IN-SITU OIL
SHALE FACILITY PRODUCING 57,000 BPD 266
4-91 RETORTING/PROCESSING EMISSIONS FROM AN IN-SITU
OIL SHALE COMPLEX, LB/HR 268
4-92 APPROXIMATE COMPOSITIONS OF FREE AND BOUND WATER
CO-PRODUCED WITH SHALE OIL, MG/L 271
4-93 CHARACTERISTICS OF COOLING TOWER AND BOILER WATER
SLOWDOWNS 273
4-94 NOISE LEVELS ENCOUNTERED BY NON-MINING PERSONNEL. 276
xx
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LIST OF TABLES (Continued)
VOLUME III
Number Page
4-95 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU PROCESSING PLANT PRODUCING
57,000 BPD OF SHALE OIL 277
4-96 WATER BALANCE DURING NORMAL OPERATIONS OF COMBINED
RETORTING FACILITIES 283
4-97 ELECTRIC POWER PRODUCTION AND CONSUMPTION FOR
COMBINED RETORTING 285
4-98 ESTIMATED FUEL BALANCE FOR COMBINED RETORTING 286
4-99 ESTIMATED EMISSIONS FROM COMBINED RETORTING
DEVELOPMENT 288
4-100 NON-SHALE SOLID WASTES 291
4-101 SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU AND SURFACE PROCESSING PLANT
PRODUCING 76 ,000 BPD OF SHALE OIL 292
4-102 NOISE POLLUTION CONTROL STANDARDS 296
4-103 PROPERTIES OF RETORTED SHALES 299
xxi
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CONVERSION FACTORS
To Convert From
acre
acre-ft/year
acre-ft/year
barrel
barrel
BPD
Btu
Btu
Btu/hour
Btu/pound
degrees API
foot
gallon
gpm
8Pt
grain/scf
Ib
Ib/hr
psi
SUS
ton
TPD
To
m2
gpm
m3/yr
gal
m3
m3/s
joule
cal
watt
joule /gram
specific gravity
m
m3
m3/s
m3/metric ton
gram/Nin3
kg
kg/s
pascal
centistokes
kg
metric ton/d
o
To convert from "API to specific gravity,
sum of 131.5 and the degrees API.
To convert from Saybolt Universal seconds
(e.g., see CRC Handbook of Chemistry and
p. F-43) or approximate
equations (e.g. ,
Multiply By
4046.9
0.6200
1233.5
42
0.1590
1.84 x 10"6
1054.4
252
0.2931
2.32
_a
0.3048
0.003785
6.309 x 10"5
0.00416
2.16
0 . 45 36
0.00756
6894.8
_b
907.18
0.907
divide 141.5 by the
, refer to tables
Physics, 54th Edition,
see Chemical Engineers '
Handbook, Perry and Chilton, eds., 5th Edition, p.1-27).
xxii
-------
ACKNOWLEDGEMENTS
Patrick J. Murin of the Radian Corporation had primary respon-
sibility 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 attor-
ney in Shawnee, Oklahoma.
The research reported here could not have been completed
without 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.
Dr. John Hoover Mr. R.D. Kerr
Energy and Environmental Laramie Energy Research Center
Systems Department of Energy
Argonne National Laboratory Laramie, Wyoming
Chicago, Illinois
Mr. Lionel S. Johns Dr. Charles H. Prien
Program Manager Senior Research Fellow
Office of Technology Assessment Chemical Division
U.S. Congress Denver Research Institute
Washington, D.C. Denver, Colorado
xxiii
-------
CHAPTER 4
THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM
4.1 INTRODUCTION
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 the 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. The "Technology Assessment of Western Energy
Resource Development" describes the development of energy
resources in eight western states. These states are: Arizona,
Colorado, Montana, New Mexico, North Dakota, South Dakota, Utah,
and Wyoming.
This document is issued as Chapter 4 of the "energy re-
source development system" (ERDS) report. For each of six
energy resources, the ERDS report describes the energy resource
base, the technologies used to develop the resource, 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, oil, natural gas, and geothermal energy.
This chapter describes the technologies, inputs, outputs,
laws, and regulations associated with the development of oil
shale resources. The chapter comprises five major sections
which begin with a general description of the oil shale resource.
The remaining sections describe the steps or activities involved
in developing oil shale resources.
-------
Section 4.2 summarizes the input requirements and outputs
identified in this study as resulting from the development and
utilization of the western oil shale resource.
Section 4.3, Resource Description, describes the charac-
teristics of the oil shale resource and gives estimates of total
resources and reserves. Section 4.3 also discusses the oil
shale resource in terms of location and ownership.
The remaining sections describe the development of the oil
shale resource as a basic sequence of "activities". In the
development of the oil shale resource, these activities include
exploration, mining, processing, and reclamation. For each ac-
tivity, "technological alternatives" are discussed which repre-
sent potential development options (e.g., shale can be mined on
the surface or mined underground). When available, input re-
quirements and outputs for each technological alternative or
activity are presented. Input requirements discussed in this
report include: manpower, materials and equipment, economics,
water, land, and ancillary energy. The outputs include the
residuals that may pose environmental hazards such as: air
emissions, water effluents, solid wastes, noise pollution,
occupational health and safety hazards, and odors.
Section 4.4 discusses the technologies, inputs, outputs,
laws, and regulations associated with oil shale exploration.
Section 4.5 discusses the same items for the mining and prepa-
ration of oil shale, including discussions of underground
mining, surface mining, and mining for "in-situ" processing.
Section 4.6 describes oil shale processing, including discus-
sions of surface and in-situ processing. Section 4.7 is a
brief description of the reclamation of processed shale.
-2-
-------
The report is largely based on development plans and
environmental impact statements prepared by oil shale developers.
Certain inputs and outputs have not been defined by developers
(e.g., materials and equipment requirements and operating costs).
Estimates of these inputs and outputs are presented, but the
reader should recognize that large discrepancies are possible.
Inputs and outputs describing surface oil shale processing
are mainly derived from published development plans featuring
the TOSCO II retorting process. Data for other surface process-
ing technologies are mostly unavailable. However, limited data
for these other surface processes are presented in this report.
Data describing modified in-situ processing are derived
from published development plans for the Occidental process.
Other data are provided from development plans featuring both
a modified in-situ process (the RISE process) and a surface
retorting process (the TOSCO II process).
Two principal options are available for producing marketable
shale oil. One is to minimize upgrading and market the raw shale
oil as a synthetic heavy crude oil or No. 6 fuel oil. The second
option is to upgrade or pre-refine shale oil on-site. In this
report, data describing the TOSCO II surface retorting process
include significant upgrading on-site to produce a low-sulfur
oil, liquefied petroleum gas, and coke. Data describing the
in-situ process developments include only those upgrading steps
needed to yield a crude shale oil that can be pipelined to a
refinery.
-3-
-------
4.2 SUMMARY
The input requirements and outputs associated with each
step of the oil shale resource development system are summarized
in Tables 4-1 through 4-7. The input requirements include man-
power, materials and equipment, economics, water, land, and
ancillary energy. The outputs include air, water, and solid
waste emissions, noise, odors, and occupational health and
safety hazards.
These summary tables present typical values for various
oil shale development options. The inputs and outputs are
based on little experience and should be interpreted only as
preliminary estimates. The assumptions used to develop these
tables are described in detail in their respective sections of
the text.
-4-
-------
TABLE 4-1.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH THE EXPLORATION OF OIL SHALE
IN THE WESTERN U.S.
Inputs
Outputs
Manpower
geological activities
drilling activities
Materials and Equipment
vehicles
drilling rigs
well logging
Economics
geological activities
drilling activities
Water
Land
Ancillary Energy
Air Emissions
Water Effluents
Solid Wastes
Noise
Occupational Health and Safety
Odors
10 man-years
1.5 man-years
Supplied by
contractor
$400,000
$200,000
Negligible
Temporary and negligible
Minor
Minor
Minor
Minor
Temporary
Negligible
Temporary and negligible
1977 dollars
c:
-------
TABLE 4-2.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH AN UNDERGROUND MINE PRODUCING
66,000 TPD OF CRUSHED OIL SHALE
Inputs
Outputs
Manpower
operating
Materials and Equipment
jumbo drills
powder trucks
scaling and roof bolting rigs
front end loaders
haulage trucks
bulldozers
steel
Economics3
capital
annualized operating
Water
Land
Ancillary Energy
electricity
diesel fuelb
Air Emissions
particulates
hydrocarbons
NOX
CO
S02
C02
Water Effluents
Solid Wastes
from opening mine
other
Noise Pollution
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
743 men
9
5
5
7
20
10
7300 tons
$190,000,000
$74,000,000
600 gpm
300-500 acres
6.2 x 108 kwh/yr
10,000 gal/yr
125 Ib/hr
54 Ib/hr
270 Ib/hr
480 Ib/hr
Negligible
9000 Ib/hr
Extremely site dependent
150,000 tons
Returned to mine
Negligible
0.8/yr
34 /yr
Confined to mine site
31977 dollars
be supplied by upgraded shale oil
-6-
-------
TABLE 4-3.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH A SURFACE MINE PRODUCING
66,000 TPD OF CRUSHED OIL SHALE
Inputs
Outputs
Manpower
operating
Materials and Equipment
loading shovels
trucks
drills
bulldozers
front-end loaders
explosives truck
steel
Economics
capital
annualized operating
Water
Land
Ancillary Energy
electricity
diesel fuelb
Air Emissions
particulates
hydrocarbons
NOX
CO
S02
C02
Water Effluents
Solid Wastes
overburden
Noise
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
410 men
4
12
4
3
2
1
7400 tons
Over $200,000,000
$61,000,000
600 gpm
800-1200 acres
2.7 x 108 kwh/yr
22,000 gal/d
510 Ib/hr
92 Ib/hr
800 Ib/hr
480 Ib/hr
59 Ib/hr
19,000 Ib/hr
Extremely site dependent
71,000 TPD
Negligible
0.2/yr
10/yr
Confined to mine site
a!977 dollars
be supplied by upgraded shale oil
-7-
-------
TABLE 4-4.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH A MINE EXCAVATING 41,000 TPD OF OIL
SHALE FOR A MODIFIED IN-SITU DEVELOPMENT
Inputs
Outputs
Manpower
operating
Materials and Equipment
jumbo drills
powder trucks
scaling and roof bolting rigs
front-end loaders
haulage trucks
bulldozers
Economics3
capital
annualized operating
Water
Land
mine shafts, support
structures, roads
mined-out shale
Ancillary Energy
electricity
diesel fuel
Air Emissions
particulates
hydrocarbons
NOx
CO
S02
C02
Water Effluents
Solid Wastes
raw shale
Noise Pollution
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
1039 men
6
4
4
4
12
4
$140,000,000
$56,000,000
450 gpm
100 acres
100 acres/yr
2.3 x 108 kwh/yr
7000 gaL/d
382 Ib/hr
12 Ib/hr
300 Ib/hr
260 Ib/hr
2 Ib/hr
6200 Ib/hr
Extremely site dependent
41,000 TPD
Negligible
0.5/yr
21/yr
Confined to mine site
a!977 dollars
-8-
-------
TABLE 4-5.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A SURFACE RETORTING/PROCESSING PLANT PRODUCING
50,000 BPD OF SHALE OIL PRODUCTS3
Inputs
Manpower
operating
peak construction13
Materials and Equipment
pyrolysis and oil recovery units
gas recovery and treating units
hydrogen production units
gas-oil and naphtha
hydrogenation units
ammonia separation and sulfur
recovery units
delayed coker
foul water stripping units
cement
structural steel
reinforcing bars and piping
valves
Economics0
capital
annualized operating
Water
TOSCO II
Parahod
Union Bd
Lurgi-Ruhrgasd
Superior
Land
Ancillary Energy
TOSCO II
Paraho
d
429 men
3300 men
Union Ba
Lurgi-Ruhrgasc
9000 tons
6000 tons
2000 tons
2000
$827,000,000
$126,000,000
5030 gpm
3130-4150 gpm
2600 gpm
1470 gpm
3500 gpm
1200-1500 acres
7 x 108 kwh/yr
4.5 x 108 kwh/yr
6 x 10s kwh/yr
3 x 108 kwh/yr
(Continued)
-9-
-------
TABLE 4-5. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A SURFACE RETORTING/PROCESSING PLANT PRODUCING
50,000 BPD OF SHALE OIL PRODUCTS3 (Continued)
Outputs
Air Emissions6
particulates 720-860 Ib/hr
hydrocarbons 950-1000 Ib/hr
NOX 1630-1900 Ib/hr
CO 60-80 Ib/hr
S02 270-350 Ib/hr
C02 580,000 Ib/hr
Water Effluents No direct discharge
Solid Wastes
TOSCO II processed shale 53,000 TPD
catalysts, sludges, etc. 1800 TPD
Noise Pollution
at plant boundaries Negligible
Occupational Health and Safety
deaths 0.15/yr
injuries 15/yr
man-days lost 15/yr
Odors Confined to plant site
alnputs and outputs are based primarily on the TOSCO II process. When
possible, inputs/outputs for other surface retorting technologies are
presented. The plant produces a full range of products, as discussed in
the text.
for all phases (including mine construction)
C1977 dollars
^Water and energy requirements for Paraho, Union B, Lurgi-Ruhrgas, and
Superior processes describe complexes with less extensive processing of
the product shale oil than specified by TOSCO II developers. Please see
the appropriate sections in the text for a discussion of these differences.
^These air emissions describe the TOSCO II processing complex; estimates
for emissions from the Union B and Paraho retorts only are found in the
text.
-10-
-------
TABLE 4-6.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A MODIFIED IN-SITU PROCESSING PLANT PRODUCING
57,000 BPD OF SHALE OIL
Inputs
Outputs
Manpower
operating
peak construction3
Materials and Equipment
gas and water treatment units
oil/water separators
product gas boilers
Economics
capital
annualized operating
Water
Land
Ancillary Energy0
Air Emissions
particulates
hydrocarbons
NOX
CO
S02
C02
Water Effluents
Solid Wastes
Noise Pollution
at plant boundaries
/
Occupational Health and Safety
Odors
at plant boundaries
561 men
2900 men
$306,000,000
$76,000,000
2500 gpm
80 acres
6.7 x 108 kwh/yr
74 Ib/hr
120 Ib/hr
588 Ib/hr
84 Ib/hr
174 Ib/hr
2,400,000 Ib/hr
No direct discharge
Minor
Negligible
Unknown
Negligible
aPeak for all phases (including mine construction)
b!977 dollars
Potentially supplied on-site
-11-
-------
TABLE 4-7. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU AND SURFACE PROCESSING PLANT
PRODUCING 76,000 BPD OF SHALE OIL
Inputs
Outputs
Manpower
operating
peak construction3
Materials and Equipment
TOSCO II retorts
oil and oil-gas recovery units
gas purification and sulfur
recovery units
foul water stripper
oil fractionation and high Btu
gas units
oil upgrading and blending units
Economics
Water
Land
surface processing facilities
shale disposal (over 30 years)
corridors (including mine)
Ancillary Energy
Air Emissions
particulates
hydrocarbons
' NOX
CO
S02
C02
Water Effluents
Solid Wastes
processed shale
catalysts and sludges
Noise Pollution
at plant boundaries
Occupational Health and Safety
Odors
at plant boundaries
1000
2500
Unknown
2750 gpm
240 acres
900 acres
280 acres
3.2 x 108 kwh/yr
483 Ib/hr
174 Ib/hr
2370 Ib/hr
458 Ib/hr
2,250,000 Ib/hr
No direct discharge
36,000 TPD
'820 TPY
Negligible
Unknown
Negligible
aPeak for all phases (including mine construction)
-12-
-------
4.3 RESOURCE DESCRIPTION
Oil shale is a marIstone-type inorganic material containing
organic matter known as kerogen. Kerogen is only slightly
soluble in conventional organic solvents. When the shale is
heated to about 900°F, the kerogen decomposes to yield hydro-
carbon gases and liquids. These hydrocarbon products can be
refined and processed in much the same manner as petroleum.
Deposits of oil shale are usually found in a layer or series of
layers, known as a "zone," sandwiched between other layers of
sedimentary rock.
Oil shale resources can be described by determining the
average oil yields obtainable by heating the shale. A stan-
dardized laboratory technique called a Fischer Assay is common-
ly used to evaluate the oil shale yield. High-grade shale is
normally defined as a deposit that averages 30 or more gallons
of oil per ton of shale. Shale with an average yield of less
than 10 gallons per ton is normally omitted from U.S. Geologi-
cal Survey resource estimates. Since an oil shale zone is often
composed of a large number of thin layers with different yields,
a zone average may be composed of widely varying yields.
In addition to yield, several other factors are significant
in determining the desirability for recovering hydrocarbon
products from an oil shale deposit. These include zone thick-
ness, overburden thickness, and the presence of other valuable
materials in the shale. In practice, the minimum zone thickness
considered for recovery is ten to fifteen feet. Many high-
quality deposits are known to be well over 100 feet thick.
The amount of overburden determines the economic feasibil-
ity of both surface and underground mining of oil shale. As with
-13-
-------
coal, the largest amount of overburden that can be economically
removed to recover oil shale is determined by the thickness of
the target shale zone. Most high quality oil shale lies below
a thick overburden containing little or no kerogen. There are
some areas, however, where oil shale lies close enough to the
surface to permit surface mining.
The presence of materials in the shale other than kerogen
is of interest when the materials might themselves be recoverable
and marketable. Some of the western oil shales are known to
contain nahcolite (sodium bicarbonate), trona (sodium sesqui-
carbonate), soda ash (sodium carbonate), halite (sodium
chloride), dawsonite (alumina), and others. Eastern deposits
contain small amounts of phosphate and metals such as uranium
and vanadium. Typical organic and mineral contents for an oil
shale containing 25 gallons of oil per ton of shale are given
in Table 4-8.
4.3.1 Resource Endowment
Table 4-9 contains estimates of the total oil shale
resources of the United States. These and other estimates are
highly uncertain. The estimates have been classed into several
categories based upon the reliability of the estimate and
quality of the shale. The U.S. Geological Survey (USGS)
identified oil shale deposits containing more than two trillion
barrels of oil. The USGS also estimated that as yet undis-
covered deposits may contain an additional 25 trillion barrels.
Although no oil shale was previously regarded as recoverable
by the USGS, 418 billion barrels were thought to border on
being economically producible or were not producible solely
because of legal or political circumstances. The portion of
the 418 billion barrels that can be classified as "reserves"
-14-
-------
TABLE 4-8. TYPICAL COMPOSITION OF OIL SHALE SECTIONS
IN THE MAHOGANY ZONE OF COLORADO AND UTAH
AVERAGING 25 GALLONS OF OIL PER TON
Weight-Percent
Organic Matter:
Content of raw shale 13.8
Ultimate composition:
Carbon 80.5
Hydrogen 10.3
Nitrogen 2.4
Sulfur 1.0
Oxygen 5.8
Total 100.0
Mineral Matter:
Content of raw shale 86.2
Estimated mineral constituents:
Carbonates, principally dolomite 48.0
Feldspars 21.0
Quartz 13.0
Clays, principally illite 13.0
Analcite 4.0
Pyrite 1.0
Total 100.0 100.0
Reference: U.S. Department of the Interior. Final Environmental
Statement for the Prototype Oil Shale Leasing Program,
6 vols, Washington, D.C., 1973.
-15-
-------
TABLE 4-9. OIL SHALE RESOURCES OF THE U.S.a
(BILLIONS OF BARRELS OF OIL YIELD)
Feasibility Knowledge of Resource
of , Undiscovered0
it)
Recovery Identified Hypothetical"1 Speculative6
Recoverable
Paramarginal
Submarginal5
0
418
1,600
0
300
1,600
0
600
23,000
Reliability of estimate decreases downward and to the right.
Specific bodies known from geological evidence supported by
engineering measurements.
f\
Unspecified bodies of mineral-leasing material surmised to exist
on the basis of broad geologic knowledge and theory.
Undiscovered materials that may reasonably be expected to exist
in a known mining district.
o
Undiscovered materials that may occur either in known types of
deposits in a favorable geologic setting where no discoveries
are made or in as yet unknown types of deposits that remain to
be recognized.
That portion of subeconomic resources that (1) borders on being
economically producible or (2) is not commercially available
solely because of legal or political circumstances.
8The portion of subeconomic resources which would require a
substantially higher price (more than 1.5 times the price at
the time of determination) or a major cost-reducing advance in
technology.
Sources: Culbertson, William C., and Janet K. Pitman. "Oil
Shale." In: D. A. Brobst and W. P. Pratt (eds.)
United States Mineral Resources, U.S. Geological
Survey Professional Paper 820, Washington, D.C.:
Government Printing Office, 1973, pp. 495-503.
Duncan, D. C., and V. E. Swanson. Organic-Rich Shale
of the United States and World Land Areas, U.S.
Geological Survey Circular 523, Washington, D.C.:
Government Printing Office, 1965.
-16-
-------
(i.e., both known to exist and economically recoverable using
currently available technologies) depends on assumptions about
the costs of alternate energy sources. The U.S. Department of
the Interior estimated that 80 billion barrels of oil were ac-
tually recoverable under 1973 conditions.1 The National Petrol-
eum Council estimated that 129 billion barrels were recoverable
under 1972 conditions.2 By either of these estimates, oil shale
reserves contain more energy than the total U.S. reserves of oil
and natural gas. The reserve estimates can also be compared to
the U.S. consumption of about six billion barrels of crude oil
in 1976.
About 90 percent of the identified oil shale resources of
the U.S. are located in a single geological formation in western
Colorado, Utah, and Wyoming known as the Green River Formation
Figure 4-1 and Table 4-10). Other oil shales underlie large
areas in the eastern and central parts of the 48 contiguous
states and the northern part of Alaska.
The Green River Formation underlies 25,000 square miles of
land, some 17,000 of which are believed to contain oil shale
deposits with commercial development potential. These deposits
occur in several geologic basins (Figure 4-2) and, in many
instances, are exposed at the basin edges but slant deeply
underground toward the centers of the deposits. Although sub-
stantial deposits are found in all three states, about 80 per-
cent of the higher grade zones are in Colorado, mostly in the
Piceance Basin (Table 4-11). Figure 4-3 ic a schematic
^.S. Department of the Interior. Final Environmental State-
ment for the Prototype Oil Shale Leasing Program,6 vols.,
Washington, B.C., Government Printing Office7 1973.
2National Petroleum Council. U.S. Energy Outlook, A report
of the National Petroleum Council's Committee on U.S. Energy
Outlook, Washington, D.C., 1972.
-17-
-------
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SAND
WASH
BASIN
GRAND JUNCTION
MILES
AREA OF OIL SHALE
DEPOSITS
AREA OF 25 QAL./TON
OR RICHER OIL SHALE
10 FT. OR MORE THICK
LOCATION OF FEDERAL
LEASE TRACTS
25
50
Figure 4-2. Oil Shale Areas in Colorado, Utah, and Wyoming.
Source: U.S. Department of the Interior. Final Environmental
Statement for the Prototype Oil Shale Leasing Program,
6 vols., Washington, D.C., Government Printing Office
1973.
-20-
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TABLE 4-11. OIL SHALE RESOURCES IN THE GREEN RIVER FORMATION
(BILLIONS OF BARRELS)
Location
Resource Class3
Class 1 Class 2 Class 3 Class 4
Total
Ficeance Basin
Colorado
Unita Basin
Colorado and Utah
Wyoming
Total
34
0
0
34
83
12
0
95
167
15
4
186
916
294
256
1,466
1,200
321
260
1,781
Classes 1,2: Resources satisfying a basic assumption limiting resources
to deposits at least 30 feet thick and averaging 30 gallons of oil per ton
of shale, by assay. Only the most accessible and better defined deposits
are included. Class 1 indicates the portion of these resources which would
average 35 gallons per ton over a continuous interval of at least 30 feet.
Class 3: Although matching Classes 1 and 2 in richness, more poorly defined
and not as favorably located.
Class 4:
per ton.
Source:
Lower grade, poorly defined deposits ranging down to 15 gallons
National Petroleum Council. U.S. Energy Outlook, A report of the
National Petroleum Councils Committee on U.S. Energy Outlook,
Washington, D.C., 1972, pp. 207-208.
-21-
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c
o
H
4J
OB
§1
C
<1)
CO
I
CO
CO
o
00
I
0)
00
I-l
u
-------
cross-section of the Green River Formation as it occurs in the
Piceance Basin.
"About 84% of the known high grade reserves
(25 gal/ton or greater) are located in Colorado, 10%
in Utah and 6% in Wyoming. Even though Colorado has
the smallest geographical area of oil shale, it has
the richest, thickest and best defined deposits. It
is likely that oil shale development will be, there-
fore, greatest in Colorado."1
4.3.2 Ownership of the Resources
About 80 percent of the high-grade shale lands in the Green
River Formation are owned by the federal government.2 Private
lands extend almost uninterrupted along the southern margin of
the Piceance Basin, but federal ownership predominates elsewhere.
The title to much of the federal land is under challenge on the
basis of unpatented mining claims not yet litigated (Table 4-12).
As of 1973 about 85 percent of the federal oil shale land had a
clouded title, including 95 percent of the lands in the rich
Piceance Creek Basin. Although many claims have been cleared,
no recent estimates of the amount of land cleared are available.
More than 75 percent of the private acreage is controlled by
seven firms (Table 4-13).3
federal Energy Administration, Interagency Task Force on
Oil Shale. Project Independence Blueprint, Final Task Force
Report, Potential Future Role of Oil Shale Prospects and Con-
straints, November, 1974.
2House Committee on Science and Astronautics, Subcommittee
on Energy. Energy^from Oil Shale: Technical, Environmental,
Economic, Legislative, and Policy Aspects of an Undeveloped
Energy Source, Washington, D.C., Government Printing Office,
1973.
3Federal Energy Administration, Interagency Task Force on
Oil Shale, op.cit., p. 100.
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TABLE 4-12. OWNERSHIP OF GREEN RIVER FORMATION OIL SHALE LANDS
(THOUSANDS OF ACRES)
Ownership
Colorado
Utah
Wyoming
Total
Federal oil shale land
(clear title)
Federal oil shale land
(clouded title)
Nonfederal oil shale
lands including
Indian and state
lands
Total
320
1,100
380
780
3,000
1,120
70
2,600
1,630
1,170
6,700
3,130
1,800
4,900
4,300
11,000
Source: U.S. Department of the Interior. Final Environmental Statement
for the Prototype Oil Shale Leasing Program, 6 vols., Washington,
D.C., Government Printing Office, 1973, Vol. I, pp. 11-104 - 11-106,
TABLE 4-13. OIL SHALE OWNERSHIP BY MAJOR OIL COMPANIES
Companies
Standard
of California
Union Oil
Texaco
Getty
Atlantic
Mobil
Sohio
*Number
Source:
Richfield
of noncontiguous
Colorado
Utah
Total
Acres Tracts* Acres Tracts Acres Tracts
40,950
29,630
19,170
24,300
19,730
19,280
9,620
tracts.
4
3
3
1
13
2
12
Federal Energy Administration
Independence Blueprint, Final
0
0
8,300
0
2,570
0
8,970
0
0
1
0
1
0
5
, Interagency Task
Task Force Report
40
29
27
24
22
19
18
,950
,630
,470
,300
,300
,280
,590
4
3
4
1
14
2
17
Force on Oil Shale
, Potential Future
Role of Oil Shale Prospects and Constraints, November
1974,
p. 101
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4.4 EXPLORATION
The location and distribution of oil shale deposits in the
Green River Formation have been thoroughly documented. Future
exploration efforts will emphasize defining known deposits to
find those most suitable for a particular mining/processing
scheme rather than locating new deposits.
4.4.1 Technologies
A typical exploration strategy for defining oil shale
deposits for a proposed recovery operation consists of the
following steps:
1. Review of existing data and outlining of
potential areas,
2. Field work for evaluation of the areas,
followed by a preliminary report,
3. Organization and conduct of a drilling
program to define the rock mechanics of the
target shale deposit, and
4. Interpretation of results, formulation of
recommendations, and final report writing.
Two different but related technologies are used in explora-
tion: geologic techniques and drilling. Borehole geophysics
are also usually applied with a drilling program. A team of
geologists and support personnel are required to conduct the
geologic studies. A drilling crew is required to operate
equipment during the drilling program.
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The geologic techniques serve as the backbone of the
exploration effort, including the organization and direction
of the drilling program. The specific geologic methods used
are primarily surface and subsurface mapping of geologic
parameters significant to the occurence of oil shale.
The target area of most oil shale exploration is much
smaller than for many other energy resources such as coal or
crude oil. A review of existing data should delineate deposits
having the proper ranges of kerogen content, oil shale thickness,
and overburden thickness. Field work may then be needed to
confirm the results of the office study. This field work
typically comprises surface study of outcrops and geologic
mapping. The information gathered during the review of existing
data and the field work serves as the basis for initiating the
drilling program. Geophysical methods, such as seismic surveys,
may be used to supplement the surface geological studies, but
they are not likely to be cost-effective since the structural
geology of the deposits is already well known.
Drilling is required to define the rock mechanics of the
target shale deposit. Data gathered during drilling is used to
define the suitability of a shale deposit to a particular mining/
processing scheme. These data are subsequently used in the design
of the shale mine (or other recovery method).
Two drilling methods - the conventional rotary and the
coring methods - will likely be used in the drilling phase of
the exploration program. The coring method uses mud or water
circulation exclusively, but the conventional rotary method may
use either liquid or air circulation. Borehole geophysical logs
(electric logs, gamma-ray logs, and acoustic logs) are usually
run after the borehole is completed. Because the grade (kerogen
-26-
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content) of oil shale is of utmost importance in determining
the value of oil shale, and because the grade may vary laterally
over short distances, a relatively intense drilling effort is
required.
4.4.2 Input Requirements
As a basis for the input requirements and outputs, the
target of exploration is assumed to be a shale deposit that can
support the operation of a 50,000 barrel-per-day processing
facility for 30 years. The total oil required from the shale
amounts to about 550 million barrels.
The magnitude of the exploratory effort can be estimated
with data from the Gulf-Standard core-hole program for federal
oil shale tract C-a. In defining a tract comprising 8 square
miles, Gulf-Standard initiated the drilling of 13 core holes in
addition to 12 previously drilled on the tract.1 Drilling
efforts required to define the target shale deposit are thus
assumed to be the drilling of 25 core holes.
4.4.2a Manpower
Professional geologists and support personnel are required
at all stages of the oil shale exploration. Table 4-14 presents
a gross estimate of the manpower requirements for the application
of geologic techniques in the various stages of the hypothetical
exploration effort. For this analysis, a team of two geologists
and three support personnel is assumed.
JGulf Oil Corporation and Standard Oil Company. Detailed
Development Plan for Tract C-a. Volume 2. Prepared for Area
Oil Shale Supervisor.March 1976. pp. 3-3-7 to 3-3-8.
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TABLE 4-14. ESTIMATED MANPOWER REQUIREMENTS FOR GEOLOGIC
EXPLORATION TECHNIQUES (TWO YEAR PROGRAM)
Geologists Support Personnel
1. Review of existing data 1 1.5
2. Field work and outlining of
potential areas 1 1.5
3. Formulation and conduct of
drilling program 1 1.5
4. Interpretation of results,
recommendations, and final
report writing
Total Man-Years
1
4.0
1.5
6.0
A total of about 25 exploratory holes averaging about 1,500
feet, in depth is anticipated to define the potential shale
deposit. An exploratory hole having a depth of 1,500 feet
normally requires about a week to drill, so an exploration
program involving the drilling of 25 holes requires about 6
months to complete. A drill rig capable of routinely drilling
1,500-feet exploration holes normally requires a crew of three.
Total manpower requirements for 6 months of drilling thus
amount to about one and one-half man-years.
4.4.2b Materials and Equipment
The materials and equipment required for geologic techniques
are standard for geologic exploration, and include office space
and supplies, appropriate maps, access to a properly stocked
library and well log file, drafting and map-making facilities,
and materials for report writing. For the field work and drill-
ing parts of the exploration program, field vehicles and equip-
ment are also required.
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Most of the materials and equipment for drilling methods
will not generally be provided by those conducting the explora-
tion, but will be provided by a contractor who is commissioned
for the drilling. This equipment includes such items as a drill
rig, water truck and/or air compressor, drill pipe and bits, and
core barrel (if applicable). Facilities and equipment must also
be provided for the well-site geologist, including a logging
trailer, and samples description and collection material. Bore-
hole geophysical equipment, including a logging truck and appro-
priate sondes (probes) are usually provided by a contractor
specializing in well logging.
4.4.2c Economics
The costs of exploration can be derived from the manpower,
materials, and equipment requirements. Order-of-magnitude costs
for geologic exploration personnel are shown in Table 4-15. These
costs assume unit costs of $60,000 per man-year for professionals
(geologists) and $40,000 per man-year for non-professionals (sup-
port personnel. Materials and equipment for geologic exploration
are assumed to be available from existing facilities. In any
case, materials and equipment costs for geologic exploration are
negligible compared to the personnel costs.
TABLE 4-15. ESTIMATED MANPOWER COSTS FOR
GEOLOGIC EXPLORATION TECHNIQUES
Personnel Man-years Manpower Costs
Geologists
Support
4.0
6.0
$ 240,000a
$ 240,000b
Total $ 480,000
o
Assumes cost for professionals of $60,000 per man-year; cost includes
overhead.
^Assumes cost for non-professionals of $40,000 per man-year.
-29-
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Assuming a man-year cost of $40,000, the manpower costs for
the drilling program total $60,000. Equipment rental and operat-
ing costs amount to about $6,000 per week for 25 weeks, totaling
$150,000, Total cost for the drilling program thus amounts to
approximately $200,000. An unknown and probably negligible cost
is associated with bore hole geophysical logs.
4.4.2d Water Requirements
The water requirements for the application of geologic tech-
neques are insignificant. A small quantity of water may be needed
for the drilling program, but this amount is insignificant in the
total water requirements of an oil shale mining and processing
operation.
«
4.4.2e Land Requirements
No permanent commitments of land are required for either
geologic techniques or the drilling program. Small amounts of
land are temporarily devoted to drill sites during drilling
operations. Areas serving as drill pads must subsequently be
revegetated.
4.4.2f Ancillary Energy
Small quantities of fuel for field vehicles are required
during geologic 'field work. Larger but still relatively minor
amounts of fuel are used for operating drill rigs during the
drilling program.
4.4.3 Outputs
Only a few minor residuals are associated with exploration
activities for oil shale.
-30-
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4.4.3a Air Emissions
Some air pollutants are generated by field vehicles and
drilling equipment during exploration, but the quantities are
small. The major pollutant is dust generated during drilling
and from other land disturbances.
4.4.3b Water Effluents
No significant quantities of water effluents are produced
by geologic techniques. A small quantity of drilling fluid may
be generated during rotary drilling operations. This effluent is
disposed in a small pond. The potential for surface and subsur-
face pollution is minimal and highly localized. However, the
site of the exploration activities will suffer increased sediment
runoff from the various land disturbances.
Small quantities of ground water may be intercepted during
drilling. The environmental hazard associated with discharging
these small quantities is likely to be minor. Alternately, the
intercepted ground water may be ponded and subsequently evaporated.
4.4.3c Solid Wastes
Little solid waste is produced during either the geologic
investigation or drilling phases of exploration. Small quantities
of drill cuttings are generated, and disposed in a pond with
drilling fluid.
4.4.3d Noise Pollution
No significant noise is generated by activities associated
with geologic investigations. Only local and temporary noise
is produced by rig operations during the exploratory drilling.
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4.4.3e Occupational Health and Safety
During geologic field work, personnel are exposed to some
very minor hazards such as falls and heat prostration. Drilling
operations pose greater but nevertheless minor hazards to crew
personnel. Injuries associated with equipment operation occur
frequently on drill rigs.
4.4.3f Odors
Odors generated during exploration are associated with the
operation of diesel equipment and field vehicles. These odors
are chiefly associated with the production of sulfur dioxide and
nitrogen oxides. The odors are local and temporary and are thus
not likely to be a nuisance.
The inputs and outputs of oil shale exploration are
summarized in Table 4-16.
4.4.4 Social Controls
As noted in Section 4.3, most oil shale lands (approximately
8570) are under federal title; therefore, the discussions that
follow will primarily be devoted to controls over activities
related to exploration on federal lands. Further, since most
oil shale lands have been identified for many years, the follow-
ing discussion will not include laws or regulations for juris-
dictions that have no oil shale to regulate. Regulations for
states with jurisdiction over oil shale (Wyoming, Colorado, and
Utah) are discussed below.
-32-
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TABLE 4-16.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH THE EXPLORATION OF OIL SHALE
IN THE WESTERN U.S.
Inputs
Outputs
Manpower
geological activities
drilling activities
Materials and Equipment
vehicles
drilling rigs
well logging
Economics
geological activities
drilling activities
Water
Land
Ancillary Energy
Air Emissions
Water Effluents
Solid Wastes
Noise
Occupational Health and Safety
Odors
10 man-years
1.5 man-years
Supplied by
contractor
$400,000
$200,000
Negligible
Temporary and negligible
Minor
Minor
Minor
Minor
Temporary
Negligible
*
Temporary and negligible
1977 dollars
-33-
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4.4.4a Exploration on Federal Lands
Because most oil shale resource locations are known, there
are no regulations in effect now which control oil shale
exploration. Section 4.5.4.1 will discuss the prototype lease
used in 1973, although there are no guarantees that a similar
procedure will be used for future leases.
4.4.4b Exploration on Indian Land
No Indian lands are covered by the six prototype leases.
An Indian Reservation in Utah, the Uintah and Ouray Reservation,
is near the oil shale lease land. The leasing procedure for
Indian oil shale land will probably be the same as for other
energy resources on Indian land described in Chapter 2.
4.4.4c Exploration on State Land
Because the rich oil shale resources are located primarily
in Colorado, Utah and Wyoming, only social controls related to
oil shale development in those states will be discussed. Each
state's oil shale development program is described below.
The state of Colorado has no oil shale exploration or
leasing program for its state lands because the State owns
very little if any oil shale.1 Therefore, no statutes or
regulations specifically apply to oil shale exploration.
Phillips, David F. "Legal Mechanisms for Access to Coal
and Oil Shale", Stanford Research Institute, p. 7-47 (1975).
-34-
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Statutes in Wyoming allow the State Board of Land
Commissioners of Wyoming to lease the state lands for mining
purposes.1 Also under state law, when patents of state lands
are issued to individuals, the minerals are reserved by the
state. Therefore, leasing is the only method available for
acquiring minerals, including oil shale, on state lands.
The Board of Land Commissioners is given wide discretion in
its regulation of leasing. The only available method of acquir-
ing land for exploration is to file a lease application on
vacant land. The applicant then has priority on that land until
the Board decides whether to lease or not. New regulations for
oil shale leasing are being written and it is not known whether
there will be new exploration provisions.
Utah appears to allow oil shale exploration under two
separate systems. The exploration permit generally available
for minerals on state lands in Utah is described below; the
method of exploration under the oil shale lease will be described
in section 4.5.4.1. The feasibility of the general permit is
questionable for oil shale because of its limitation to a
maximum of 160 acres per township per person. Table 4-17
summarizes the permit in Utah.
1 During the Depression the Wyoming Farm Board acquired
ownership of some farm land through foreclosures. State
regulations allow both Boards to administer the leasing
provisions, but in practice, the Board of Land Commissioners
handles all of it. See reference on previous page.
-35-
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TABLE 4-17. OIL SHALE EXPLORATION PERMIT FOR UTAH
Item
Statutes
Summary
Agency
Rental
Duration
Other
Information
§65-1-18 State Land Board
§40-1-13 160 acres maximum per township per
person, with $250 worth of work com-
pleted every six months per township.
No ore to be removed.
§40-1-13 One year maximum, with yearly renewals
available
§40-6-5 If developer plans to drill (either
exploratory or production) the Board
of Oil, Gas, and Mining has the
authority to require:
a) security (for plugging)
b) notice of intent to drill
c) filing of well log
§65-1-18 Note: This section also allows for
prospecting under the lease itself--
see Utah Oil Shale leasing for terms
of section.
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4.5 MINING AND PREPARATION
Two major options are available for oil shale development.
These are:
1) mining of the shale deposit, followed by surface
processing of the mined-out shale, and
2) underground or in-situ processing.
These development options are illustrated in Figure 4-4. This
section describes those mining operations required for each
processing scheme. Processing technologies are discussed in
Section 4.6. Reclamation activities associated with mining and
processing operations are discussed in Section 4.7.
Mining operations are required for both surface and (some)
underground processing schemes. As illustrated in Figure 4-4,
surface or underground mines can supply shale for surface shale
processing. Shale excavated during modified in-situ development
mining can also be processed on the surface. Underground and
surface mining are discussed in Sections 4.5.1 and 4.5.2, respec-
tively. In-situ development mining is discussed in Section 4.5.3
Social controls for mining are discussed in Section 4.5.4.
Associated with the mining of oil shale are crushing and
screening operations required to prepare shale for surface
processing. These operations are described in Section 4.5.1,
Underground Mining. The same crushing and screening operations
are required to prepare shale supplied from surface mines.
The following three sub-sections contain descriptions of
the various mining technologies, and report the input require-
ments and outputs associated with each technology. Input
-37-
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DOMESTIC
RESOURCE
BASE
EXPLORATION
SURFACE
MINING
AREA
UNDERGROUND
MINING:
ROOM AND
PILLAR
i
MINING FOR
IN-SITU
PROCESSING
MINED-OUT SHALE
FOR SURFACE
RETORTING
RECLAMATION
PREPARATION:
CRUSHING AND
SCREENING
I
MINED-OUT SHALE
TO RECLAMATION
RETORTED SHALE
SURFACE
RETORTING
IN-SITU
RETORTING
-J
UPGRADING
UPGRADING
GASEOUS AND
LIQUID PRODUCTS
GASEOUS AND
LIQUID PRODUCTS
o
Figure 4-4. Oil Shale Development Schemes.
o
Dashed lines show process options, e.g., shale mined
during modified in-situ developments can be processed
on the surface or disposed.
-38-
02-2369-1
-------
requirements discussed in this report include: manpower re-
quirements, materials and equipment requirements, economics,
water requirements, land requirements, and ancillary energy
requirements. The outputs described in this report are air
emissions, water effluents, solid wastes, noise pollution, odors,
and occupational health and safety hazards.
4.5.1 Underground Mining
4.5.1.1 Technologies
Most actual experience in oil shale mining has involved
underground mining techniques. Early development of underground
mining was undertaken by the Bureau of Mines in its oil shale
program during 1944-1956. A demonstration mine was opened at
Anvil Points, Colorado, in a 73-foot section of the Mahogany
zone to demonstrate the feasibility of room-and-pillar mining
methods, to develop and test equipments, and to determine mining
costs and resource recovery. Subsequent work by industry has
utilized the mining method demonstrated by the Bureau, but has
incorporated equipment modernization and improvements in tech-
niques . *
Union Oil operated a mine from 1955 through 1958 on a
property located on the east fork of Parachute Creek in Colorado.
Their efforts produced over 70,000 tons of shale for Union's
retort development programs.2
^chramm, L. W. "Shale Oil", Section from Bureau of Mines
Bulletin No. 650, U.S. Department of the Interior. Mineral
Facts and Problems. 1970. pp. 185-202.
2Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 10.
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The Colony Development Operation initiated a prototype
mining development in 1964. Colony had successfully mined shale
at rates of 1200 tons/day (and higher) before suspending opera-
tions in 1973.l'2 Colony later proposed construction of a
commercial shale oil mine and plant near Parachute Creek,
Colorado. Underground mining was to remove 61,000 tons of
shale daily via conventional room-and-pillar mining.3 A draft
environment impact statement (EIS) on the proposed development
was made available to the public on December 12, 1975." The
final EIS was completed in 1977.
The early development plans for oil shale development on
federal oil shale lease tract C-b in Colorado anticipated the
room-and-pillar mining of 66,000 tons per day (TPD). The ex-
cavated shale would have supported the production of 50,000
barrels of oil per day (BPD).5
Crawford, K. W. , et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development^Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 10.
2Interagency Task Force on Oil Shale. Potential Future
Role of Oil Shale: Prospects and Constraints"! Federal Energy
Administration. November 1974. p~. 260.
3Colony Development Operation. An Environmental Impact
Analysis for a Shale Oil Complex at Parachute Creek, Colorado,
Vol. 1.Atlantic Richfield Company (Operator),Denver,Colorado
1974.
''U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the'Colony Development Operation in
Colorado. Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
5Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Prepared
for Area Oil Shale Supervisor.February 1976.
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The White River Shale Project earlier anticipated the room-
and-pillar mining of 80,000 TPD on tracts U-a and U-b,1 with the
eventual mining of 160,000 TPD. These shale excavation rates
would have supported the production of 50,000 and 100,000 BPD.2'3
In 1976, developers of both tracts C-b and U-a/U-b requested
suspension of their oil shale leases. Developers of tract C-b
later rejected their earlier plan for underground mining of oil
shale. Instead, the C-b developers planned for the in-situ
processing of the shale resource. That in-situ development
is discussed in Sections 4.5.3 and 4. 6.2.1."4
^
The status of the White River Shale Project is uncertain due
to the continuing litigation involving unpatented mining claims
on tracts U-a and U-b.
To date, underground mine developments have emphasized the
use of room-and-pillar mining techniques. A description of
room-and-pillar mining is found below. This description conforms
to those plans originally proposed for the development of oil
shale tract C-b.
JThe leasees of tracts U-a (Phillips Petroleum, Sun Oil)
and U-b (phillips, Sun, Sohio) proposed joint development!
of the two adjoining tracts.
2White River Shale Project. Detailed Development Plan for
Oil Shale Tracts U-a and U-b, as cited in:Crawford, K. W.,
et al.A Preliminary Assessment of the Environmental Impacts
from Oil Shale Development.Prepared for U.S.Environmental
Protection Agency. Contract No. 68-02-1881. Denver Research
Institute and TRW Environmental Engineering Division. June 1976.
p. 54.
Differences in shale excavation requirements for develop-
ments producing the same quantities of shale oil are attributable
to-differences in oil contents of the shale resources.
"Novak, Alys. "Oil Shale - 1976/1977," Shale Country 2 (12):
2-6, December 1976.
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Various mining systems have been suggested as alternates
to room-and-pillar mining. An abbreviated discussion of several
of these techniques follows the room-and-pillar mining description.
In room-and-pillar mining, pillars of shale are left in
place at appropriate intervals within the mine to provide roof
support. The room-and-pillar mining technique is illustrated
in Figure 4-5.
If the height of the mining zone is 60 or 75 feet, at least
two passes are required to mine the oil shale. In that case,
the mining cycle involves one pass using upper-level or face-
mining equipment, followed by one or more passes with lower-
level or bench-mining equipment. If the mining zone is 35 feet
high, only one pass is required using upper-level equipment.
If the height of the mining zone is 45 feet, either a single or
multiple-pass may be used.1
The optimum mining zone thickness depends upon the geotech-
nical properties of the rock mass and upon mining and retorting
costs. For example, the maximum extraction ratio for a 75-foot
mining zone using room-and-pillar techniques has been estimated
to be from 30 to 50%. For a 35-foot mining zone, this ratio
may be 40 to 60% or higher. Cameron Engineers has estimated
overall resource recovery for a 40-foot mining zone to be 65%.2
This difference in extraction efficiency is largely attributable
to the difference in rock properties of each interval. In
1 Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. 11-22
2Hoskins, W. N., et al. "A Technical and Economic Study of
Candidate Underground Mining Systems for Deep, Thick Oil Shale
Deposits", Quarterly of the Colorado School of Mines 71 (4):
199-234.
-42-
-------
Reference:
Figure 4-5. Room-And-Piliar Mining.
Ashland Oil, Inc. and Shell Oil Co. Detailed Devel-
opment Plan and Related Materials for Oil Shale Tract
C-b.VolumeI, Prepared for Area Oil Shale Supervisor,
FeFruary 1976. P. II-23.
(Originally reported in: Colony Development Operation.
An Environmental Impact Analysis for a Shale Oil
Complex at Parachute Creek, Colorado.Volume T7 1974.
P. 11)
-43-
-------
going from a thinner to thicker mining zone, some zones of
weaker rock must be included and support pillars must be
larger. It is possible that more oil shale could be recovered
from the target shale resource by mining a thinner and richer
zone than could be obtained by mining a thicker and leaner zone.1
The upper-level mining cycle proceeds as follows. First,
the face is drilled using a face-drill jumbo. An upper-level
charging rig then loads the drilled round with explosives. The
round is then blasted during the next shift change. Fly rock
from the blast is removed by a front-end loader and the
blasted rock or muck is wetted by a water truck to control
dust. The rock is then loaded into trucks by a front-end
loader for haulage to the primary crusher. When the distance
to the crusher is small, a front-end loader hauls directly
to the crusher without using trucks. After the blasted rock
is completely removed, the ribs (sides), back (roof) and face
are scaled to remove any loose rock. The mining zones being
considered are bounded at the top by distinct parting planes.
As these parting planes normally pull well, minimal scaling is
required and scaling can safely follow loading in the work
cycle.2
Following the scaling operation, a front-end loader removes
the scaled material. The back exposed by the blast is then
roof-bolted in accordance with accepted safety standards. If
needed, drain holes to relieve hydrostatic pressures above the
roof and below the floor are drilled. Instruments to monitor
1 Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-2.
2 Ibid.
-44-
-------
rock behavior are installed as required. When this is done,
the cycle is completed and the face is readied for drilling of
the next round.l
i
The lower-level cycle, if used, begins when sufficient
upper-level mining is completed to allow both cycles to proceed
without interference. The lower-level cycle starts with the
drilling of multiple vertical holes from the top of the mine
bench. These holes are then loaded with explosives and blasted
during a shift change. This is followed by fly rock clean up
and muck pile wetting. The muck is loaded using the same
method as in upper-level loading. The area is then scaled and
the scaled rock removed. After installation of any rock
mechanics instrumentation, the bench is ready for the cycle
to begin again.2
Future underground mining may utilize continuous mining
machines. The machines have not yet been developed but are
potentially desirable for oil shale excavation. The contin-
uous miners allow mining to proceed more rapidly, are less
labor-intensive, and produce more stable mine tunnels than
conventional equipment. However, continuous mining machines
are more capital-intensive and less versatile than conventional
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan for Oil Shale Tract C-b, Prepared for Area Oil Shale Super-
visor]February 1977.p. 11-22.
zlbid.
-45-
-------
mining equipment. The first application of continuous miners
will probably be a modification of room-and-pillar mining.1'2'3'"
Generally, most ore bodies that can be mined with the room-
and-pillar mining method can be extracted by the longwall method.
This method consists of mining a straight face for 80 yards or
more, allowing controlled subsidence into the mined-out space.
Nearly 100 percent resource recovery is possible. Surface
subsidence and consequent disruption of aquifers and surface
streams are likely.5 Longwall mining has been demonstrated only
on thin seams.
Other alternate mining systems have been studied by Cameron
Engineers. Mining methods evaluated for the Bureau of Mines
included: square-set stoping, shrinkage stoping, cut-and-fill
stoping, sublevel caving, sublevel stoping, room-and-pillar,
longwall, and block caving.6 Of those systems selected for cost
evaluation, room-and-pillar mining was shown to have the lowest
^.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado,Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975, pp. IX-6,7.
2U.S. Congress, Senate Committee on Interior and Insular
Affairs. Legislative Authority on Federal Agencies with Respect
to Fuels and Energy"! Washington, B.C.: Government Printing
Office, 1973.
3University of Oklahoma, Science and Public Policy Program.
Energy Alternatives: A Comparative Analysis. Council on
Environmental Quality. University of Oklahoma. May 1975.
14East, J. H. , Jr. , and E. D. Gardner. Oil Shale Mining,
Rifle, Colorado, 1944-56. Bureau of Mines Bulletin 611.
Washington, D.C.: Government Printing Office, 1964, p. 127.
5U.S. Bureau of Land Management, op.cit., pp. IX-4,5.
6Stoping is a mining method removing rock via a series of
steps either at or below the mining level.
-46-
-------
annualized production cost. Cameron reports contain more de-
tailed descriptions of the various mining techniques.1'2
The oil content within the extracted shale may vary widely
because shale zones contain layers of varying quality. Generally,
the target zone for mining consists of 30 gallons oil per ton
or higher. Lower yield layers of oil shale abo,ve the mineral
zone are treated as overburden. However, there is no separation
of shale within the zone into high- and low-quality seams.
Much of the mined oil shale will require crushing and
sizing prior to processing. Sizing operations performed on
oil shale may include primary, secondary, and tertiary crushing;
screening; and briquetting. The required size of the crushed
oil shale depends on the specific processing technology being
applied. TOSCO processing requires that the shale be ground
to less than 1.2 cm while the Union and Paraho processes can
accomodate shale up to 8.5 cm. Typical operations in a shale
sizing facility are shown in Figure 4-6. The throughputs shown
in Figure 4-6 correspond to the excavation of 66,000 TPD. That
level of excavation can supply a surface processing facility
producing 50,000 BPD assuming an average grade shale containing
35 gallons of oil per ton.3
Joskins, W. N., et al. "A Technical and Economic Study
of Candidate Underground Mining Systems for Deep, Thick Oil
Shale Deposits", Quarterly of the Colorado School of Mines 71 (4)
199-234. 1976.
2Cameron Engineers. A Technical and Economic Study of
Candidate Underground Mining Systems for Deep, Thick Oil Shale
Deposits^NTIS, PB 249-884/AS.July 1975.
3Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, TX: Radian Corporation, September 1977, p. 22.
-.47-
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To minimize the costs of transporting raw shale, the
crushers are located close to the blasting operation, usually
within the room-and-pillar mine or in the surface mining pit.
From the primary crushers the shale is conveyed to secondary
and tertiary crushers outside the mine or pit. The remaining
sizing operations may be performed at the mine site or at the
processing site.1
After secondary and tertiary crushing, the shale is
conveyed to shale storage hoppers. From the storage hoppers,
the shale may be fed directly to the processing facility. If
the processor cannot accept fine particles, the fines are
separated from the shale by a screening process and compacted
and formed into briquettes. These briquettes are suitable
for routing to the processor along with other shale feedstock
or are discarded.2
The crushing operation is designed to maintain a continuous
feed to the retort. This objective will be accomplished in
part by maintaining a storage pile of coarse ore and a storage
bin of fine ore. No storage facility for run-of-mine ore will
be needed. The mine haulage operation is entirely dependent
on the operation of the primary crusher. Should a breakdown
occur in the primary crusher or the conveyor to the coarse
ore storage, haulage from the mine will be interrupted. To
avoid shutdown of the retorting and upgrading facilities,
sufficient storage of coarse ore will be maintained to allow
uninterrupted operation of the downstream processing facilities
for about one month. If the final crusher breaks down, the
'Colley, J. D. , W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977, p. 24.
2lbid., pp. 24-26.
-49-
-------
amount of stored fine ore will be enough to operate the retort
for approximately 5 hours.1
4.5.1.2 Input Requirements
This section reports inputs required for the operation and
maintenance of a room-and-pillar underground mine. The various
manpower, equipment, water, land, and energy requirements are
largely based on data reported by Ashland Oil, Inc. and Shell
Oil Company in the 1976 Detailed Development Plan (DDP) for
Oil Shale Tract C-b.2 Generally similar data were reported by
the U.S. Department of the Interior in the EIS for the Colony
Development Operation (December, 1975).3 Estimates of capital
requirements and annualized operating costs are likewise based
on data reported in the DDP and in the EIS.
The inputs described in this section are representative of
a room-and-pillar underground mine supplying shale to surface
facilities producing 50,000 barrels of shale oil per day. The
mine extracts approximately 66,000 TPD. This production equals
the demand of the processing plant, assuming that the plant
operates at approximately 90 percent capacity on a yearly basis.
The average oil content of the extracted shale is 35 gal/ton.
Inputs for alternate underground mining techniques will
differ from those reported below.
Volley, J. D. , W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977, p. 26.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b. Volume I.
Prepared for Area Oil Shale Supervisor. February 1976. p. IV-10
3U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement. p~. 11-97.
-50-
-------
4.5.1.2a Manpower
Manpower requirements for mining operations supplying
66,000 TPD to a surface processing plant have been reported by
Ashland and Shell in the DDP for oil shale tract C-b. These
requirements are tabulated in Table 4-18 and reflect the most
recent data available from documents available to the public.*
Earlier estimates from the Colony EIA and EIS were lower than
those reported in the DDP.2'3
TABLE 4-18. MANPOWER REQUIREMENTS FOR ROOM-AND-PILLAR
UNDERGROUND MININGa'b
Personnel Number Required
Mine Operators 346
Mine Maintenance 179
Mine Salary Management 53
Mine Supervisors and Clerical 22
Crushing/Disposal Support 143
Total 743
Production Capacity of Surface Complex: 50,000 BPD
Excavation Requirements: 66,000 TPD
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Develop-
ment Plan and Related Materials for Oil Shale Tract
C-b,Volume I,Prepared for Area Oil Shale Supervisor.
February 1976. p. IV-10.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-10.
2Colony Development Operation. An Environmental Impact
Analysis for a Shale Oil Complex at Parachute Creek, Colorado,
Volume 1.Atlantic Richfield Company (Operator),Denver,Colorado
1974
3U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Draft Environmental Impact Statement. p~. 11-97.
-51-
-------
The manpower requirements in Table 4-18 relate only the
personnel required for full-scale commercial operations.
Accurate estimates of the skill breakdowns for the construction
personnel required to establish the site are unavailable. How-
ever, total manpower requirements to develop the entire oil
shale complex have been reported by Ashland and Shell and are
shown in Figure 4-7. Peak construction employment is approxi-
mately 3300.l
4.5.1.2b Materials and Equipment
Detailed materials and equipment requirements have not
been prepared by potential underground mine developers. However,
Ashland and Shell have described the mining equipment likely
to be used in a commercial development. Their description is
reproduced in Table 4-19.2
The Federal Energy Administration has estimated equipment
requirements for an underground mine excavating 140,000 TPD
oil shale. While the data in the FEA report are now somewhat
outdated, a 66,000 TPD mine may be assumed to require about
half of the equipment required for the 140,000 TPD mine. The
equipment required for the 66,000 TPD mine are scaled from the
data in the FEA report and are presented in Table 4-20. The
equipment list is not complete and may be based on outdated
information. Crushing and screening apparatus are omitted from
the equipment list.3
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. Figure
IV-3.
2Ibid. , p. IV-21.
3Interagency Task Force on Oil Shale. Potential Future
Role of Oil Shale: Prospects and Constraints"! Federal Energy
Administration. November 1974. p~. H-168.
-52-
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-53-
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TABLE 4-19. DESCRIPTION OF COMMERCIAL MINING EQUIPMENT
Item
Description
1) Haulage Trucks
2) Face Drills
3) Down Hole Bench Drills
4) Front End Loader
5) Sealer
6) Roof Bolter
7) Explosive Loader
8) Explosive Trucks
9) Haul Road Maintenance
Equipment
10) Field Mechanics and Super-
visory Vehicles
End dump rock trucks, 30, to 100 ton.
Large, self-propelled 2 to 4 boom jumbo
with 15 to 30 foot booms.
Standard self-propelled, open-pit down
hold drill.
Bucket capacity of 5 to 15 cubic yards.
Standard backhoe with scaling pick
mounted on end of boom arm.
Self-propelled, two-boom roof bolt drill
with personnel platform.
Self-propelled explosive-charging machine.
Trailer mounted explosive magazines.
Grader and water trucks.
Diesel powered pickups, 3/4 ton.
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan
and Related Materials for Oil Shale Tract C-b, Volume I, Prepared
for Area Oil Shale Supervisor. February 1976. p. IV 21.
-54-
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-55-
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As estimated for use in a Battelle computer model, steel
requirements during plant construction amount to:
Crushing and Screening 3700 tons
Mining 3300 tons
Briquetting 300 tons
These values were extrapolated from data in the FEA report and
may not be accurate.1
4.5.1.2c Economics
Preliminary capital cost estimates for a mine associated
with a 50,000 BPD shale oil complex are shown in Table 4-21.
The costs are those reported by Ashland and Shell in the DDP
for oil shale tract C-b. The estimates are based only on pre-
liminary engineering design and project scheduling, and do
not include interest during construction and deferred capital
expenditures. The capital cost estimates reported in Table
4-21 include only those costs directly related to the mine,
and exclude costs for general facilities, indirect costs, and
working capital. Miscellaneous capital requirements (i.e.,
costs for general facilities, indirects, and working capital)
for the entire oil shale complex are reported in Section 4.6-1.2,
Surface Retorting Technologies. The costs in Table 4-21 are
indexed to 1977 from the October 1975 costs reported in the
DDP. Costs for the processed shale disposal are. included in
!Interagency Task Force on Oil Shale. Potential Future
Role of Oil Shale: Prospects and Constraint!"! Federal Energy
Administration. November 1974. p~! F-109.
-56-
-------
TABLE 4-21. CAPITAL COST ESTIMATES FOR AN
UNDERGROUND SHALE MINEa'b
Plant Design and Construction
Mining, Crushing, and Processed $110,000,000
Shale Disposal
Site Development, Roads and Dams 31,000,000
Commercial Mine Pre-Development 10,000,000
Mining and Disposal Mobile Equipment 21,000,000
Development Mining 17,000,000
TOTAL $190,000,000
aShale oil production capacity of 50,000 BPD; shale excavation
of 66,000 TPD.
Costs are in 1977 dollars, and are indexed from those reported
by Ashland and Shell by 1.10. General facilities costs, indirect
costs, and working capital are reported for the entire facility
in Section 4.6.1.2.
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Develop-
ment Plan and Related Materials for Oil Shale Tract C-b,
Volume I, Prepared for Area Oil Shale Supervisor.
February 1976. p. 1-22.
-57-
-------
Table 4-21 ,but are more closely associated with processing
activities.1
Operating cost estimates have not been prepared by potential
underground mine developers. However, data reported in the DDP
and EIS are sufficient to construct preliminary cost estimates.
The labor costs are estimated from the labor requirements
reported by Ashland and Shell in the DDP. Utilities' costs are
estimated from the power and fuel requirements reported in the
DDP and in the EIS. All other costs are estimated as percentages
of the capital or labor costs. These estimates are shown in
Table 4-22, and are based on preliminary, incomplete data.2'3'1*
4.5.1.2d Water Requirements
Most of the water required for an underground mining
operation is needed for dust control. Ashland and Shell have
estimated mining water requirements as 450 gpm (730 acre-ft/
year) for a 66,000 TPD mine. About 350 gpm of untreated mine-
water can be used for road wetting and muck pile dust control.
About 100 gpm of treated minewater are required for dust
control spray systems.5 An additional 150 gpm (240 acre-ft/
year) are required for dust control for primary crushing and
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. 1-22
2 ibid.
3U.S. Bureau of Land Management. Proposed Development
of Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
''Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b,
Prepared for Area Oil Shale Supervisor.February 1977.
5Ashland Oil, Inc. and Shell Oil Co., op. ait. , p. IV-22.
-58-
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TABLE 4-22.
ANNUALIZED OPERATING COSTS FOR AN
UNDERGROUND SHALE MINEa>b
Component
Cost
Direct Coses
Mine Operators c
Mine Maintenance c
Crushing/Disposal Supporg
Miners Salary Management ,
Mine Supervisors and Clerical
Total Personnel Costs
Operating Supplies f
Maintenance Materials
Utilities
Electricity*
Water
Diesel Fuel
J
Fixed Costs
Depreciation*1 .
Taxes and Insurance
Plant Overhead
Total
$ 5,200,000
2,700,000
2,200,000
1,100,000
440.000
12,000,000
1,900,000
2,700,000
25,000,000
1,800,000
19,000,000
5,700,000
6.000.000
$74,000,000 $4.05/bbl
Calculated <§ $0.04/kwh.
Essentially all water requirements
are met by use of minewater.
Calculated @ $0.50/gal.
^Calculated @ 10Z of fixed capital.
'Calculated @ 3Z of fixed capital.
Calculated 9 50Z of total labor costs.
k;
Shale oil production capacity of
50,000 BPD; shale excavation of
66,000 TPD.
Costs are in 1977 dollars and
include only those costs directly
attributed to the mining operation.
Calculated @ $15,000/man/year.
Calculated @ $20,000/man/year.
Calculated (§ 1Z of the fixed
capital costs.
Calculated @ 100Z of maintenance
labor.
Note: Rates for calculating fixed costs, plant overhead, and costs for
operating supplies and maintenance materials are largely based on
Peters, M. S. and K. D. Timmerhaus. Plant Design and Economics for
Chemical Engineers. 2nd. Ed. (New York: McGraw-Hill Book Co., 1968),
pp. 132-141.
Source: U.S. Bureau of Land Management. Proposed Development of Oil Shale
Resources by the Colony Development Operation in Colorado, Draft
Environmental Impact Statement. DES-75-62. Washington, D.C.:
December 1975.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan and
Related Materials for Oil Shale Tract C-b. Volume 1, Prepared for
Area Oil Shale Supervisor. February 1976.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications to
Detailed Development Plan for Oil Shale Tract C-b. Prepared for
Area Oil Shale Supervisor. February 1977.
-59-
-------
coarse ore storage.1 Personnel requirements are not significant,
Total water usage for mining and crushing amounts to 600 gpm.
(970 acre-ft/year).
Consumptive uses during construction include concrete manu-
facture, dust control, fill compaction, and personnel uses.
Quantities for these uses amount to 500-700 gpm (800-1100 acre-
ft/year) . The entire requirement can probably be met by water
from dewatering operations but water treatment may be required.2
4.5.1.2e Land Requirements
Ashland and Shell have projected surface disturbances asso-
ciated with an underground shale mining development. Estimates
of the acreage disturbed by underground mining are reported in
Table 4-21. Areas required for the disposal of processed shale
are associated with shale processing and are discussed in Sec-
tion 4.6.1.2.
4.5.1.2f Ancillary Energy Requirements
Ancillary energy requirements for an underground mine have
been reported by developers in the DDP and EIS, and are tabula-
ted in Table 4-24. The energy recovery ratio for underground
mining can be determined by dividing the total heating value
of the oil shale by the sum of this number and the above ancil-
lary energy requirements. The energy recovery ratio is deter-
mined to be 0.99.
1 Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-63
2ibid., p. IV-62.
-60-
-------
TABLE 4-23. SURFACE AREAS DISTURBED BY AN UNDERGROUND
MINING DEVELOPMENT EXTRACTING 66,000 TPDa
Disturbance Area Disturbed (Acres)
Mine Surface Facilities 25-35
Coarse Ore Conveyor 5-10
Coarse Ore Stockpile 40-55 (temporary)
35-40 (initial)
Road Construction15 82-115
Water in Damsb 150-270°
aAreas required for processed-shale disposal are discussed in
Section 4.6.1.2
As estimated for entire oil shale complex.
cLand areas required for water storage or ponding vary from
site to site. Most developers use the natural terrain to
create large reservoirs. The quantity of minewater requiring
ponding also varies from site to site.
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Develop-
ment Plan and Related Materials for Oil Shale Tract C'-b,
Volume I, Prepared for Area Oil Shale Supervisor.
February 1976. p. IV-9.
4.5.1.3 Outputs
This section reports the various outputs associated with
the operation of an underground mine excavating 66,000 TPD.
Discussions of air emissions, water effluents, solid wastes,
and noise pollution are largely based on information reported
-61-
-------
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by Ashland and Shell in the 1976 DDP and by the U.S. Department
of the Interior in the EIS (December 1975).1>2
The outputs are reported for room-and-pillar underground
mining. Outputs for alternate mining technologies will differ
from those reported below.
4.5.1.3a Air Emissions
Air emissions from underground mining operations originate
from the mine ventilation system, the shale conveyor system, and
the shale crushers. Mine vent emissions are shown in Table 4-25
and discussed below. Emissions from crushing and conveying are
shown in Table 4-26. Air emissions are those reported in the
Draft EIS.
Emissions from underground mining operations exit the mine
vent; these emissions are tabulated in Table 4-25. The mine vent
emissions originate from conventional mining operations (i.e.,
mining, blasting and hauling) and diesel equipment operation.
Catalytic scrubbers mounted on mobile mine equipment remove es-
sentially all of the hydrocarbons, CO, and S02 emitted in diesel
exhaust fumes. No control devices are placed on the mine vent.
In-mine watering will control dust to some extent.3'1*
XU.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado,Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976.
3U.S.' Bureau of Land Management, op.cit., p. 11-16.
"Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
From Synthetic Fuel Production Facilities, Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, TX: Radian Corporation, September 1977.
-63-
-------
TABLE 4-25. MINE VENT EMISSIONS, LB/HR FROM UNDERGROUND
SHALE MINE EXCAVATING 66,000 TPD
Pollutant Emission Rate
Particulates 61
Hydrocarbons 54
NOx 270
CO 480
S02 Negligible
CO 2 9000a
Estimated from diesel fuel requirement; assumes complete com-
bustion of carbon compounds in fuel to C02
Source: U.S. Bureau of Land Management. Proposed Development
of Oil Shale Resources by the Colony" Development Op'era-
tion in Colorado,Draft Environmental Impact Statement.
DES-75-62.Washington, D.C.: December 1975, p. 11-16.
Colley, J.D., W. A. Gathman, and M. L. Owen. Emissions
From Synthetic Fuel Production Facilities, Prepared for
U.S.Environmental Protection Agency.EPA Contract No.
68-01-3535. Austin, Tex.: Radian Corporation, Septem-
ber 1977.
-64-
-------
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-65-
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Approximately 22-33 Ib/hr of particulates enter the mine
atmosphere from drilling, hauling, and loading and are drawn
into the ventilation system. For three 1-hour periods each
day, blasting releases an estimated 220-330 Ib/hr of particulates
into the mine atmosphere. The particulates emission rate
shown in Table 4-25 is an average rate (61 Ib/hr).1'2
NOx emissions are largely generated by mobile mine equip-
ment. CO and hydrocarbons are produced during mining operations
and during diesel equipment operation.3'" COa emissions mainly
originate from the combustion of diesel fuel.
Air emissions from shale sizing operations originate from
crushing and screening facilities, belt conveyor transfer points,
and fine ore storage silos. Table 4-26 summarizes the emissions
from these sources. Emissions from the primary crusher, the
fine ore crusher, the belt conveyor transfer points, and the
larger storage silos are controlled by fabric filters with assumed
collection efficiencies of greater than 99 percent.5
Emissions from the raw shale stockpile have not been
estimated, but are on the order of 50 Ibs/hr with wet suppression
dust control.6
^.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado"] Draft Environmental Impact Statement. DES-75-62.
Washington, D.C.: December 1975, p. 11-16.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
From Synthetic Fuel Production Facilities, Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.-. Radian Corporation, September 1977.
3U.S. Bureau of Land Management, op.ait.
"Colley, J. D., W. A. Gathman, and M. L. Owen, op.ait.
5U.S. Bureau of Land Management, op.ait., pp. 11-17 to 11-22.
6See Section 4.5.3, Mining for In-Situ Processing.
-66-
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4.5.1.3b Water Effluents
Potential water effluents from mining operations include:
excess minewater, runoff from raw shale stockpiles, and sanitary
wastewaters. Volumes of these potential water effluents have
not been estimated. Quantities and qualities of excess mine-
water and runoffs are largely dependent on the site of the mine
development.
Excess minewater can be treated for use in processing
operations or routed to an evaporation pond. The desirability
of treating minewater for process use depends on the minewater
quality and on the required quality of process water. Ground-
water quality data for oil shale tracts C-a and C-b are presented
in Table 4-27. These data represent a limited number of
analyses for many constituents and may not be completely
representative.1 Quantities of excess minewater are dependent
on the site of the mine development and may range from small
amounts to several thousand gallons per minute. A certain portion
of poor quality water can be used for surface requirements such
as dust control and moisturizing of processed shale. These
requirements can be met by untreated minewater.2
Runoffs from raw shale stockpiles can be contained in
catchment ponds. These runoffs are likely to contain inorganic
salts, toxic metals, and some toxic organics (including carcino-
gens) that have been leached from the raw shale. However, if
the catchment ponds are properly designed, the runoffs are not
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil SHale Development. Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials, Volume I, Prepared for Area Oil
Shale Supervisor.February 1976. p. IV-22.
-67-
-------
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likely to enter natural water systems. Some developers
anticipate using water from catchment ponds for shale dust
control and compaction.1
Sanitary wastes can be treated onsite, with recovery of
the liquid effluent for re-use. Expected volumes of these
sanitary wastes have not been reported but are probably insignif-
icant.
4.5.1.3c Solid Wastes
Negligible solid wastes are created as a direct result of
mine operation.2 Some overburden removal is required to open
the mine. According to Hittman, the overburden excavated during
mine development amounts to approximately 150,000 tons for a
50,000 BPD oil shale operation.3 The wasted material resembles
the natural talus material and its disposal does not have a
severe impact on the visual or aesthetic quality of the site.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract'C-b,
Prepared for Area Oil Shale Supervisor. February 1977. p~III-
43.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities, Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
3Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologies.Draft
Report on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boiler
Combustion). Prepared for Council on Environmental Quality,
National Science Foundation, and Environmental Protection
Agency. Contract EQC 308. Columbia, Maryland. May 1974.
-69-
-------
Minimal solid wastes are generated from oil shale sizing
operations for the TOSCO process. However, for the Union and
Paraho processes, the fines must be disposed or consumed by
briquetting or by using a combination of retorts that consume
the fines. Approximately 3300 TPD of fines are produced from
the Union and the Paraho processes.1'2
Water treatment sludges result from upgrading minewater
for processing, and are discussed in Section 4.6.
4.5.1.3d Noise Pollution
Noise at the underground mine originates from normal mining
operations. Sound levels within the mine are similar to those
encountered in underground coal mines. Typical ranges of sound
levels at worker positions are shown in Table 4-28.
4.5.1.3e Occupational Health and Safety
Health and safety hazards associated with underground shale
mining have not been extensively examined. Safety hazards are
those hazards chiefly associated with mining accidents. Health
hazards are those dangers associated with work exposure to
toxic substances. Each of these hazards is discussed below.
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Texas: Radian Corporation, September 1977.
2McKee, J. M. and S. K. Kunchal. "Energy and Water
Requirements for an Oil Shale Plant Based on the Paraho Processes
Presented at the Ninth Oil Shale Symposium, Colorado School of
Mines, Golden, Colorado. April 1976.
3U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado"]Draft Environmental Impact Statement. DES-75-62.
Washington, D.C.: December 1975. p. 11-48.
-70-
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TABLE 4-28. NOISE LEVELS ENCOUNTERED BY MINE WORKERS'
Noise Source Sound Level, dbA
Roofbolter/Scaler 107 - 118b
92 - 101°
Drill 80 - 104
Air Pump/Fan 90 - 105
Conveyor 90 - 105
75 - 85e
Crusher/Feeder 90 - 105
LHD 90 - 108
Sump 93-98
Hoist 85 - 95
Diesel Trucks 74 - 109
Primary Crushing 72 - 111
Data assumes that underground shale mines and underground coal mines have
similar noise sources and characteristics.
Pneumatic roofbolter.
£
Rotary roofbolter.
Flighted conveyor.
Belter conveyor.
Source: U.S. Department of the Interior. Noise Control Proceedings:
Bureau of Mines Technology Transfer Seminar, Pittsburgh, PA.
January 22, 1975, pp. 6, 95.
Down, C. G. and J. Stocks. Environmental Impact of Mining.
(New York: Halsted Press) 1977. p. 154.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan
and Related Materials for Oil Shale Tract C-b, Volume I, Prepared
for Area Oil Shale Suprevisor. February 1977. p. V-53.
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Safety hazards for an underground shale mine are described
as "safety statistics" in the Hittman report. Using data
estimated in Hittman for an underground shale mine, on the
average, about 34 nonfatal injuries and 0.8 deaths will occur
annually in a mine excavating 66,000 TPD.1
Health hazards for an underground shaXe mine are chiefly
associated with worker exposure to shale dust, raw shale, and
toxic gases. Shale dust and raw shale contain silica, inorganic
salts, toxic metals, and some toxic organics. Free silica in
the dust is a recognized hazard resulting in occupational
silicosis. Conflicting results have been obtained in analyses'
of oil shale dust for free crystalline (alpha-quartz) silica.
While some results have indicated approximately 10% silica in
oil shale, one analysis has found no free silica in dust
particles in the respirable size range.2
Included among the toxic organics in shale dust and raw
shale are those compounds shown in Table 4-29. All of the
compounds in Table 4-29 are known or suspected animal carcino-
gens, and may be carcinogenic to man. However, the concentra-
tions of these compounds encountered by mine workers have not
yet been determined.
Gases produced during mining operations have been previously
described in Section 4.5.1.3a. Worker exposure to those
gases has not been delineated.
Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologies.Draft
Report on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boiler
Combusion). Prepared for Council on Environmental Quality,
National Science Foundation, and Environmental Protection Agency.
Contract EQC 308. Columbia, Maryland. May 1974.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Superviosr.February 1977. p. V-77.
-72-
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TABLE 4-29. POLYCYCLIC AROMATIC HYDROCARBONS
DETECTED IN RAW OIL SHALE
Benzo (a) pyrene (BaP)
Alkyl I (BaP)
Benzo (ghi) fluoranthene
Benzo (e) pyrene
Perylene
Benzo (ghi) perylene
Anthracene
Pyrene
Fluoranthene
Benz (a) anthracene
Triphenylene
Phenanthrene
7, 12-Dimethylbenz (a) anthracene
3-Methylcholanthrene
Coronene
Chrysene
Reference: Coomes, R.M. "Health Effects of Oil Shale Processing" Quarterly
of the Colorado School of Mines 71(4): 101-123, October 1976.
4.5.1.3f Odors
Odors at an underground mine are chiefly associated with
nitrogen oxides emitted during the operation of diesel equip-
ment. Some odors associated with the presence of hydrogen
sulfide may also be detected. The odors are likely to be
confined to the mine site.
The inputs and outputs associated with an underground mine
are summarized in Table 4-30.
-73-
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TABLE 4-30.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH AN UNDERGROUND MINE PRODUCING
66,000 TPD OF CRUSHED OIL SHALE
Inputs
Outputs
Manpower
operating
Materials and Equipment
jumbo drills
powder trucks
scaling and roof bolting rigs
front end loaders
haulage trucks
bulldozers
steel
Economics3
capital
annualized operating
Water
Land
Ancillary Energy
electricity
diesel fuelb
Air Emissions
particulates
hydrocarbons
NOx
CO
S02
C02
Water Effluents
Solid Wastes
from opening mine
other
Noise Pollution
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
743 men
9
5
5
7
20
10
7300 tons
$190,000,000
$74,000,000
600 gpm
300-500 acres
6.2 x 108 kwh/yr
10,000 gal/yr
125 Ib/hr
54 Ib/hr
270 Ib/hr
480 Ib/hr
Negligible
9000 Ib/hr
Extremely site dependent
150,000 tons
Returned to mine
Negligible
0.8/yr
34/yr
Confined to mine site
&1977 dollars
be supplied by upgraded shale oil
-74-
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4.5.2 Surface Mining
4.5.2.1 Technologies
Most high quality oil shale lies beneath a thick layer of
overburden containing little or no kerogen. Underground mining
techniques will primarily be used to extract these resources.
There are some areas, however, where oil shale lies close enough
to the surface to justify surface mining.1 Prien has estimated
that surface mining may be applicable to 15-20 percent of the
minable oil shale resources.2
Factors affecting the suitability of oil shale surface
mining are the amount of overburden that must be removed in
order to mine the shale and the availability of a disposal area
for the overburden.3 Prien has asserted that surface mining
would be limited to areas where the overburden-to-shale ratio
was less than 2.5:1."
In comparison with underground mining, surface mining has
several economic advantages: surface mining is capable of shale
Volley, J. D. , W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities, Prepared for U.S.
Environmental Protection Agency.Austin, Tex.: Radian Corp.,
September 1977, p. 5.
2Prien, Charles. Testimony before the Subcommittee on
Energy, Committee on Science and Astronautics, U.S. House of
Representatives, May 1974. As cited in: Interagency Task Force
on Oil Shale. Potential Future Role of Oil Shale: Prospects and
Constraints. Federal Energy Administration. November 1974. p~. 260
3Schramm, L. W. "Shale Oil", Section from Bureau of Mines
Bulletin No. 650, U.S. Department of the Interior. Mineral Facts
and Problems. 1970. pp. 185-202.
"*Prien, Charles, op.cit.
-75-
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extraction at a lower cost with lower manpower requirements.1
In addition, a greater resource extraction per unit land area is
achievable. Surface mining is also inherently safer than under-
ground mining. The main disadvantage is a high land impact asso-
ciated with the initial disposal of solid wastes on the surface.
Mine back-filling can begin only after many years of surface
disposal at off-mine sites.2
Little experience has been gained in surface oil shale min-
ing. However, methods used for surface mining oil shale should
be comparable to those used in coal strip-mining or hard-rock
open-pit mining.3 For the very lowest overburden-to-shale
ratios (less than about 0.5), strip mining is the more appropriate,
method of resource recovery. In this type of surface mining,
explosives are used to loosen overburden. The overburden is then
removed from the mines by large draglines. Power shovels are
used to load the rock onto trucks for transport to a disposal area
Strip mining is suitable only for oil shale deposits lying
near the surface. Open pit mining is more appropriate for deeper
JHittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologies,Draft Re-
port on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boilec Com-
bustion) . Prepared for Council on Environmental Quality, National
Science Foundation and Environmental Protection Agency. Contract
EQC 308. Columbia, Maryland. May 1974.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions from
Synthetic Fuel Production Facilities. Prepared for U.S~. Environ-
mental Protection Agency.EPA Contract No. 68-01-3535. Austin,
Tex.: Radian Corporation, September 1977.
3Conkle, Nick, et al. Environmental Considerations for Oil
Shale Development. Battelle Columbus Laboratories.Prepared for
U.S. Environmental Protection Agency. October 1974. p. 15.
"Dickson, E. M, et al. Synthetic Liquid Fuels Development:
Assessment of Critical Factors', Volume II - Analysis, Prepared for
U.S. ERDA and U.S. Environmental Protection Agency. ERDA 76-129/2.
Stanford Research Institute, pp. 458-460.
-76-
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deposits. Since deposits are most often found beneath thick
overburdens, surface mining will likely develop via open pit
mining.1 The following discussion emphasizes the open pit min-
ing technique.
Only one oil shale development specified surface mining of
the shale deposit. The Rio Blanco Oil Shale Project (Gulf Oil
Corp. and Standard Oil Co.) originally planned for an open-pit
mine/processing development producing 56,000 barrels of shale
oil per day. The developers submitted a Detailed Development
Plan to the Area Oil Shale Office in March 1976. Revised de-
velopment plans have rejected the surface mining/processing
scheme in favor of an in-situ development.2'3
Overburden at potential surface mining sites ranges from
100-800 feet in depth, averaging approximately 450 feet. Due to
the required mine depth, several bench levels must be provided
to develop sufficient working forces to meet production rates,
as shown in Figure 4-8. An average mine slope of 45° with a
working slope of 35° is typical.14
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency. EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
2Rio Blanco Oil Shale Project. Detailed Development Plan for
Oil Shale Tract C-a, Prepared for Area Oil Shale Supervisor.
March 1976.As cited in: Crawford, K. W., et al. A Preliminary
Assessment of the Environmental^Impacts from Oil Shale Development.
TRW Environmental Engineering Division and Denver Research Insti-
tute. June 1976. pp. 48-50.
3Gulf Oil Corp. and Standard Oil Co. Revised Detailed De-
velopment Plan for Oil Shale Tract C-a, Prepared for Area Oil Shale
Supervisor, 3 Volumes.May 1977.
"U.S. Department of the Interior. Final Environmental State-
ment for the Prototype Oil Shale Leasing Program. 6 Volumes.
Washington, D.C.: 1973.
-77-
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The steps involved in the surface mining of oil shale in-
clude topsoil removal and storage; overburden drilling, blasting,
and removal; and oil shale drilling, blasting, and extraction.
These steps resemble those for coal surface mining; however, the
pit is much deeper for oil shale surface mining. Oil shale is
also considerably harder than coal.1
Overburden and shale are extracted by drilling and blasting.
Blasted raw shale is loaded by large shovels (usually electrically-
powered) into diesel trucks having capacities of up to 120 tons.
The raw shale is then hauled to primary crushers in the pit.
Road graders and water trucks are required to maintain hard
roads.2
Shale from the primary crusher is removed from the mine by
conveyor to secondary crushing and screening facilities. The
secondary crushing and screening facilities may be located at
the shale processing plant.3 Crushing operations have been pre-
viously described in Section 4.5.1.1.
Both the safety of the pit and economics of open pit mining
are highly dependent upon the steepness of the side slopes that
can be maintained in the pit. If the slope stability cannot be
maintained at a fairly steep angle, hazardous slides may occur.
Volley, J. D., W. A. Gathman, and M. L. Owen, Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
2Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale DevelopmentPrepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
3Colley, J. D., W. A. Gathman, and M. L. Owen, op.ait. , p. 6.
-79-
-------
If it is necessary to maintain the slope at low angles to avoid
slides, the cost of removing overburden may prohibit the surface
mining of the shale deposit.*
4.5.2.2 Input Requirements
This section reports inputs required for the operation and
maintenance of a surface oil shale mine. Since little experience
has been achieved in surface oil shale mining, the various inputs
should be interpreted as preliminary estimates. The various
input requirements are based on data from a variety of sources.
The inputs described in this section are representative of
an oil shale surface mining/processing facility producing 50,000
barrels of shale oil per day.
4.5.2.2a Manpower
Employment projections for a surface mining/processing
facility were estimated in the original DDP for Oil Shale Tract
C-a. On tract C-a, approximately 56,000 barrels of oil were to
be produced from 120,000 tons of shale.2 Manpower required to
operate the entire mining/processing facility were estimated at
1100. The number of personnel at the height of construction
was estimated to be 2200.3 If the processing facility required
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development"! Prepared for
U.S. Environmental Protection Agency, Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
2The mined shale had an average oil content of about 22 gal/ton,
3Rio Blanco Oil Shale Project. Detailed Development Plan for
Oil Shale Tract C-a, Prepared for Area Oil Shale Supervisor.March
1976.As cited in: Crawford, K. W., et al. A Preliminary Assess-
ment of the Environmental Impacts from Oil Shale Development.TRW
Environmental Engineering Division and Denver Research Institute.
June 1976. pp. 48-50.
-80-
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about 430 men1 (see Section 4.6.1.3, Surface Retorting), then
the manpower required to operate mining and crushing equipment
amounted to about 670.
Fewer personnel are required for the mining and crushing of
richer shale deposits. For example, for a shale deposit having
an average oil content of 35 gal/ton, a 50,000 BPD processing
facility can be supplied by a mine producing 66,000 tons of shale
per day. (This production equals the demand of the processing
plant, assuming that the plant operates at approximately 90 per-
cent capacity on a yearly basis.)2 Using scaling factors de-
veloped for the Battelle Oil Shale Model, manpower requirements
for a 66,000 TPD facility amount to about 410.3»"
Accurate skills breakdowns of construction and operation
personnel are unavailable.
4.5.2.2b Materials and Equipment
Detailed materials and equipment requirements have not been
prepared by any potential surface mine developers. However, the
Federal Energy Administration has estimated equipment requirements
for a surface mine excavating 140,000 TPD oil shale. While the
Ashland Oil, Inc. and Shell Oil. Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I, Pre-
pared for Area Oil Shale Supervisor.February 1976. p. IV-10.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency. EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
3Interagency Task Force on Oil Shale. Potential Future Role
of Oil Shale: Prospects and Constraints. Federal Energy Adminis-
tration.November 1974. p~. D-34.
* The labor scaling factor in line 6 of Table D-2 (in the FEA
report) was used in this analysis: a doubling of capacity in-
creases labor requirements by 62.57».
-81-
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data in the FEA report are now somewhat outdated, a mine removing
66,000 TPD may be assumed to require about half of the equipment
required for the 140,000 TPD mine. The equipment list given in
Table 4-31 is not complete and may be based on outdated informa-
tion. Crushing and screening apparatus are omitted from the
equipment list.1
As estimated for use in a Battelle computer model, steel
requirements during plant construction amount to:
Crushing, Screening, and Briquetting 3700 tons
Mining 4700 tons
These values were extrapolated from data in the FEA report and
may not be accurate.
4.5.2.2c Economics
Current costs estimates for a surface mining/crushing opera-
tion are unavailable. Battelle made preliminary estimates of
surface mining costs in the FEA's Project Independence Blueprint
report on the potential development of oil shale. A surface mine
extracting 140,000 tons of oil shale per day had the following
costs (mid-1974 dollars):
Capital $101,000,000
Operating $ 39,000,000
(Costs for sizing operations were not included in the costs for
mining operations.)2
^nteragency Task Force on Oil Shale. Potential Future Role
of Oil Shale; Prospects and Constraints. Federal Energy Adminis-
tration.November 1974. p. H-179..
2 Ibid. , p. H-173.
-82-
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Current estimates of the capital costs of surface mining/
crushing cannot be accurately determined from the literature.
According to Battelle's early estimates, the capital costs of
underground mining are exceeded by the capital costs of surface
mining.1'2 If we accept published data for underground mining,
then the capital costs for a 66,000 TPD surface shale mine are
expected to exceed $190,000,000 (1977 dollars). (See Section
4.5.1, Underground Mining.)3-"
The U.S. Bureau of Mines contracted Sun Oil Company to
perform a technical and economic study on the open pit mining
of deep shale oil deposits. Preliminary cost data for surface
mining operations were reported in the Phase I report to the
U.S. Bureau of Mines.5 These data are presented in Table 4-32.
The costs include both fixed and operating cost components for
various surface mining operations.
^nteragency Task Force on Oil Shale. Potential Future Role
of Oil Shale: Prospects and Constraints. Federal Energy Adminis-
tration.November 1974.p. H-172.
2This statement is based on a comparison of the costs for
100,000 BPD underground and surface mining facilities. At the
100,000 BPD production level, capital costs for underground mining
are only about half of those for surface mining. Crushing plant
capital costs are the same for both mining methods. At other pro-
duction rates, the surface mine may have costs more nearly akin
to those for the underground mine.
3Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract" C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. 1-22.
""The reported capital cost includes costs for mining, crush-
ing, and processed shale disposal.
5Banks, C. E., et al. Technical and Economic Study of an
Integrated Single Pass Mining System for Open Pit Mining of 15e"ep
Oil Shale Deposits,Phase I Report.Sun Oil Company.Prepared
for U.S. Bureau of Mines. BuMines OFR 22-76.
-84-
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TABLE 4-32.
UNIT ANNUALIZED COSTS FOR THE OPEN PIT
MINING OF OIL SHALE
Activity
Mid-1974
1977
Drilling
Overburden
Oil Shale
Blasting
Overburden
Oil Shale
Loading
Overburden
Oil Shale
Haulage
Trucks
Conveyors
Primary Crushing
Waste Disposal
Spreader-Stripper
Mine Dewatering
$0.013/ton
$0.016/ton
$0.063/ton
$0.068/ton
$0.064/ton
$0.057/ton
$0.11/ton-mile
$0.05/ton-mile
$ .059/ton
$ .022/ton
$ .00035/gal
$0.016/ton
$0.019/ton
$0.076/ton
$0.082/ton
$0.077/ton
$0.068/ton
$0.13/ton-mile
$0.06/ton-mile
$ .071/ton
$ .026/ton
$ .00042/gal
Note: Costs are typical costs encountered at open pit
mines; when range of costs reported in reference,
costs in table are averages. The indexing factor
to 1977 is 1.2. Costs for miscellaneous equipment
are not reported on a usable basis.
Source:
Banks, C. E., et al. Technical and Economic Study of an
Integrated Single Pass Mining System for Open Pit Mining
of Deep Oil Shale Deposits, Phase I Report. Sun Oil Conipany.
Prepared for U.S. Bureau of Mines.BU Mines OFR 22-76.
pp. 5-13, 26, 43-44, 62, 73-75, 93, 99, 104.
-85-
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Preliminary estimates of the annualized operating costs
for a surface mine producing 66,000 TPD are shown in Table 4-33.
These costs have been constructed from the labor, power, and
fuel requirements described in this report. Other costs are
estimated as percentages of the capital or labor costs. Total
operating costs are shown in Table 4-33 as $61,000,000, and
are based on preliminary incomplete data.l' 2
4.5.2.2d Water
Most of the water required for a surface mining operation
is needed for dust control. The FEA has estimated that similar-
sized surface and underground mines have similar water require-
ments.3 Mining water requirements for a 66,000 TPD shale surface
mine are estimated to be 450 pgm (730 acre-ft/year).1*'5 An addi-
tional 150 gpm (240 acre-ft/year) are required for dust control
for primary crushing and coarse ore storage.5 Total water usage
for mining and crushing amounts to 600 gpm (970 acre-ft/year).
!Interagency Task Force on Oil Shale. Potential Future
Role of Oil Shale: Prospects and Constraints"! Federal Energy
Administration.November 1974.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume 1,
Prepared for Area Oil Shale Supervisor.February 1976.
3Interagency Task Force on Oil Shale, op.dt., p. 154.
"Ashland Oil, Inc. and Shell Oil Co., op.dt., p. IV-22.
5This quantity assumes that surface mining and underground
mining have similar water requirements.
6Ashland Oil, Inc. and Shell Oil Co., op.dt., p. IV-22.
-86-
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TABLE 4-33. PRELIMINARY ANNUALIZED COSTS ESTIMATES FOR
THE OPEN PIT MINING OF OIL SHALE
a , b
Component
Direct Costs
Personnel ,
Operating Supplies
Maintenance Materials
Utilities -
f
Electricity
Water *
Diesel Fuel
Fixed Costs
Depreciation .
Taxes and Insurance
Cost
$ 6,600,000
2,500,000
1,500,000
11,000,000
4,000,000
25,000,000
7,500,000
Plant Overhead
Total
3.300.000
$ 61,000,000 $3.34/bbl
aShale oil production capacity of 50,000 BPD; shale excavation requirement
of 66,000 TPD; overburden excavation requirements of 72,000 TPD.
bcosts are in 1977 dollars and include only those costs directly attributed
to mining and crushing operations.
Calculated @ $15,000/man/year for labor, $20,000/man/year for supervision.
"Calculated @ 1% of the fixed capital costs which are conservatively
estimated at $250,000,000.
Calculated @ 100% of maintenance labor.
Calculated @ $0.04/kwh.
^Water requirements are met by mine dewatering.
Calculated <§ $0.50/gal.
Calculated @ 10% of fixed capital.
JCalculated @ 3% of fixed capital.
Calculated @ 50% of total labor costs.
Note: Rates for calculating fixed costs, plant overhead, and costs for
operating supplies and maintenance materials are largely based on
Peters, M. S. and K. D. Tlmmerhaus. Plant Design and Economics for
Chemical Engineers. 2nd,Ed. (New York: McGraw-Hill Book Co., 1968),
pp. 132-141.
Source: Interagency Task Force on Oil Shale. Potential Future Role of
Oil Shale: Prospects and Constraints. Federal Energy Administra-
tion. November 1974.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan and
Related Materials for Oil Shale Tract C-b, Volume 1, Prepared for
Area Oil Shale Supervisor. February 1976.
-87-
-------
Consumptive uses during construction include dust control,
fill compaction, and personnel uses. Quantities for these uses
amount to 500-700 (800-1100 acre-ft/year) during the construction
of an underground mine. l Similar quantities can probably be
anticipated for a surface mine.
4.5.2.2e Land
The Federal Energy Administration has estimated the magnitude
of surface disturbances associated with a surface mining operation,
These are reported in Table 4-34.2 Areas required for the dis-
posal of processed shale are associated with shale processing and
are discussed in Section 4.6.1.2.
4.5.2.2f Ancillary Energy
Ancillary energy requirements for surface mining/crushing
operations are tabulated in Table 4-35. The energy recovery
ratio is determined to be 0.99.
4.5.2.3 Outputs
This section reports the various outputs associated with
the operation of a surface oil shale mine. However, no informa-
tion is available from actual surface shale mining operations.
Discussions of air emissions, water effluents, solid wastes, noise
1 Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume 1,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-62,
2Interagency Task Force on Oil Shale. Potential Future
Role of Oil Shale: Prospects and Constraints^Federal Energy
Administration. November 1974. p~! 139.
-88-
-------
TABLE 4-34. AVERAGE OF SURFACE DISTURBANCES ASSOCIATED
WITH A 66,000 TPD SURFACE MINING OPERATION3
Mine Development 15-45 acres per year
Permanent disposal of overburden 500 acres (total)
Temporary storage of raw shale 50-100 acres (total)
Water in dams 150-270 acres (total)0
Other 90-300 acres (total)d
a
Estimates are scaled from data in FEA report; area required
for shale crushing is not separable from the area reported
for shale processing in the FEA report.
Area required is dependent on the thicknesses of the over-
burden and oil shale at the site. Acres shown are for a
Piceance Creek Basin site, with 550 feet of overburden
and 450 feet of 30 gal/ton shale.
water storage for entire mining/processing complex is
based on requirements for an underground mine. The land
areas required for water storage or ponding vary from site
to site. Most developers use natural terrain to create
large reservoirs.
Required areas include access roads, power and transmission
facilities, water lines, natural gas and oil pipelines for
entire mining/processing complex. A 60 ft right-of-way for
roads requires a surface area of about 8 acres per mile.
Utility and pipeline corridors require 2.4 acres per mile.
o
Areas required for processed shale disposal are discussed
in Section 4.6.1.
Source:
Interagency Task Force on Oil Shale. Potential Future Role of
Oil Shale: Prospects and Constraints. Federal Energy
Administration. November 1974. p~. 3~9~.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan
and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976.
p. IV-9.
-89-
-------
TABLE 4-35. ANCILLARY ENERGY REQUIREMENTS FOR SURFACE
SHALE MINING AND CRUSHING3
Category
Power or Fuel Requirements
Energy Usage
Electricity
Pit Crushing and Conveying
Dewatering0
Loading
Crushing and Screening
General Services
TOTAL
Diesel Fuel
5500 hp 2.9 x 10 7 kwh/yearb
4000 hp 2.6 x 10 7 kwh/year d
2.0 x 10 7 kwh/yeare
1.5 x 10* kwh/year
4 x 10 7 kwh/year
2.7 x 10' kwh/yearf
22,000 gal/d 1.1 x 1012 Btu/yearg
aShale oil production capacity of 50,000 BPD; overburden excavation requirement of
72,000 TPD; shale excavation requirement of 66,000 TPD.
Assumes mine operates 350 days/year, 3 shifts/day, 6.5 hours (eff.)/shift.
cDewatering requirements vary from site to site and are different for different
mining techniques. Value is that reported by Occidental (see References).
Assumes dewatering requirements occur 365 days/year.
eLarge electric quarry shovels with energy consumption of 0.6 kwh/cy. Shovels
load overburden and raw shale.
Figure represents electricity directly used in mining. Gross power plant energy
requirements can be estimated by using power plant heat rate of 9750 Btu/kwh
(power generation efficiency of 357.).
^Assumes mine operates 350 days/year; heating value for diesel fuel of 140,000 Btu/gal.
Sources:
Colley, J. D. W. A. Gathman, and M. L. Owen. Emissions from Synthetic Fuel Production
Facilities. Prepared for U.S. Environmental Protection Agency.EPA Contract No. 68-
01-3535.Austin, Tex.: Radian Corporation, September 1977.
Ashland Oil, Inc. and Shell Oil Company. Detailed Development Plan and Related Materials
for Oil Shale Tract C-b, Volume I. Prepared for Area Oil Shale Supervisor.February
T3W. p. IV-28.
Ashland Oil, Inc. and Occidental Shale, Inc. Modifications to Detailed Development Plan
for Oil Shale Tract C-b, Prepared for Area Oil Shale Supervisor.February 1977,
p. 111-39.
Hittman Associates, Inc. Environmental Impacts, Efficiency and Cost of Energy Supplied
by Emerging Technologies. Draft Report on Task 7 (Oil Shale) and Task 8 (Fluidized
Bed Boiler Combustion).Prepared for Council on Environmental Quality, National Science
Foundation, and Environmental Protection Agency. Contract EQC 308. Columbia, Maryland.
May 1974.
-90-
-------
pollution, occupational health and safety, and odors are based
on information from a variety of sources other than actual mines.
The surface mine extracts 66,000 TPD oil shale and 72,000
TPD overburden. This mine production is sufficient to supply
a 50,000 BPD processing facility with shale having an average
oil content of 30 gal/ton. (The production equals the demand of
the processing plant, assuming that the plant operates at approxi-
mately 90 percent capacity on a yearly basis.)1
4.5.2.3a Air Emissions
Air emission sources associated with the surface mining
facilities include excavation blasting, road dust from transporta-
tion of oil shale and overburden, combustion emissions from
diesel-powered equipment, primary and secondary crushing opera-
tions, and wind blown dust. Air emissions from crushing opera-
tions have been previously described in Section 4.5.1.3 and are
not discussed in this section. Estimates of the remaining air
emissions are summarized in Table 4-36 and are described below.
The estimates do not include the effect of control measures
beyond basic requirements. The basic requirements assumed in-
clude hard surfacing major mine access roads and periodic water
spraying of secondary roads as conditions require.2
Primary sources of information for this section include
the Environmental Assessment for a Proposed Coal Gasification
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
2 Ibid., p. 6, 12.
-91-
-------
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-92-
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Project by Wyoming Coal Gas Co. and Rochelle Coal Co. as
prepared by SERNCO,1 and the Draft Environmental Statement
for the El Paso Coal Gasification Project.2
Wind erosion results in the discharge of particulates from
the exposed mine areas. Using a wind erosion equation developed
by PEDCo-Environmental, an emission factor of 0.60 metric tons/
acre-year is calculated. Assuming 30 acres per year are dis-
turbed during mining, approximately 4 Ibs/hr of particulates
are emitted. 3 ' "*
Topsoil removal and its storage is the first operation in
overburden excavation. SERNCO estimated that topsoil removal
discharges roughly 76 kg/acre-yr of topsoil disturbed. This
amounts to less than 1 Ib/hr of dust emitted to the air from this
operation, assuming 30 acres per year are disturbed due to mine
development.5»6 > 7
1 Wyoming Coal Gas Company and Rochelle Coal Company.
Applicants' Environmental Assessment for a Proposed Coal Gasifi-
cation Project, Campbell and Converse Counties, Wyoming"!
October 1974.
2U.S. Department of the Interior, Bureau of Reclamation,
Upper Colorado Region. El Paso Gasification Project, San Juan
County, NM, Draft Environmental Statement.DES-74-77, 1974.
3 Cowherd, Charlten, Jr., et al. Development of Emission
Factors for Fugitive Dust Sources, Final Report.EPA-450/3-74-037,
Contract No.68-02-0619.Kansas City, Mo.: Midwest Research
Institute, June 1974.
"U.S. Department of the Interior. Final Environmental
Statement for the Prototype Oil Shale Leasing Program,6 Vols.
Washington, D.C.:1973
5 Ibid.
5Wyoming Coal Gas Company and Rochelle Coal Company, op.cit.
7Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities, Prepared for U.S.
Environmental Protection Agency.Austin, Tex.: Radian Corp.,
September 1977, p. 13.
-93-
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Blast hole preparation by drilling releases noticeable
amounts of particulates during overburden removal. Scaling the
quantity given by SERNCO for overburden drilling emissions to
the overburden removal rate in this analysis, it is estimated
that 9.5 Ibs/hr of particulates are emitted.1'2
The blasting of the overburden discharges significant
quantities of dirt and dust into the air; however, this operation
occurs only periodically. Scaling the estimates by SERNCO for
overburden blasting, roughly 70 Ibs/hr of particulates less than
lOy in diameter are discharged to the atmosphere. This number
is based on the assumption that the large diameter particles
settle out in the immediate vicinity of the mine. 3 ' "*
Following blasting, the overburden is loaded for removal
from the pit area. This phase of mining is the largest single
source of particulates in the extraction operation. SERNCO esti-
mates that approximately 0.035 kg of dust is emitted per metric
ton of overburden removed. Assuming a daily removal rate of
72,000 TPD, the resulting emissions will be about 210 lb/hr.5.6
Wyoming Coal Gas Company and Rochelle Coal Company. Appli-
cants ' Environmental Assessment for a Proposed Coal Gasification
Project, Campbell and Converse Counties, Wyoming.October 1974.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
3Wyoming Coal Gas Company and Rochelle Coal Company, op.ait.
^Colley, J. D., W. A. Gathman, and M. L. Owen, op.cit.
f
5Wyoming Coal Gas Company and Rochelle Coal Company, op.ait.
6Colley, J. D. , W. A. Gathman, and M. L. Owen, op.ait., p. 14.
-94-
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The fragmenting of the oil shale by blasting periodically
releases some dust to the air. Assuming the same amount of dust
is emitted for the blasting of the oil shale as for coal (0.0016
kg/MT of material mined), then 9.6 Ibs/hr of dust are emitted.1'2
The diesel-powered vehicles operating in the pit emit signif-
icant quantities of pollutants. The equipment consumes approxi-
mately 22,000 gal/day of diesel fuel (scaled value obtained from
Hittman Report).3 The emissions were determined by applying EPA
emission factors for heavy duty diesel engines."'5
Hauling the extracted shale and overburden on mine roads
results in the dispersion of dust from both payloads and road sur-
faces. Scaling emission estimates reported by SERNCO for coal
mine road dust give a total particulate discharge rate of
roughly 120 Ibs/hr for the hauling of the oil shale and over-
burden. 6 7
lWyoming Coal Gas Company and Rochelle Coal Company. Appli-
cants ' Environmental Assessment for a Proposed Coal Gasification
Project"Campbell and Converse Counties, Wyoming.October 1974.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
3Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologies. Draft Re-
port on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boiler Com-
bustion) . Prepared for Council on Environmental Quality, National
Science Foundation, and Environmental Protection Agency. Contract
EQC 308. Columbia, Maryland. May 1974.
"Environmental Protection Agency. Compilation of Air Pollu-
tant Emission Factors, 2nd Ed. AP-42. Research Triangle Park,
N.C.:May 1973.
5Colley, J. D., W. A. Gatham, and M. L. Owen, op.cit.
6Wyoming Coal Gas Company and Rochelle Company, op.sit.
7Colley, J. D., W. A. Gathman, and M. L. Owen, op.ait.
-95-
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4.5.2.3b Water Effluents
Potential water effluents from mining operations include:
excess minewater, runoff from raw shale stockpiles, and sanitary
wastewaters. Volumes of these potential water effluents have
not been estimated. Quantities and qualities of excess minewater
and runoffs are largely dependent on the site of the mine develop-
ment. Characteristics and disposal of these water effluents have
been discussed in Section 4.5.1.3.
4.5.2.3c Solid Wastes
A major environmental problem associated with surface mining
is solids disposal. Initially, overburden must be hauled off-
site to some containment area. Only after mined-out areas of
the pit become available can back filling begin. This is expected
to be a long time period: up to 30 years for open pit mines, one
year for strip mines. Since solid waste cannot be disposed of
underground, the land impact associated with surface mining is
higher than with underground mining. For a surface mine pro-
ducing 66,000 TPD of raw shale, approximately 71,000 TPD of over-
burden must be disposed of.1 The wasted material resembles the
natural talus material and its disposal does not have a severe
impact on the visual or aesthetic quality of the site.
Solid wastes generated from shale sizing operations are
discussed in Section 4.5.1.3. Water treatment sludges result
from upgrading minewater for processing and are discussed in
Section 4.6.
Volley, J. D., W. A. Gathman, and M. L. Owen, Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, Tex.: Radian Corporation, September 1977.
-96-
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4.5.2.3d Noise
Noise at surface mines originates from normal mining opera-
tions. Typical levels of sound levels at worker positions are
shown in Table 4-37.
4.5.2.3e Occupational Health and Safety
Health and safety hazards associated with surface shale
mining have not been extensively examined. Safety hazards for a
surface shale mine are described as "safety statistics" in the
Hittman report. Using data estimated in Hittman for an under- *
ground shale mine, on the average, about 10 nonfatal injuries
and 0.2 deaths will occur annually in mining accidents at a mine
excavating 66,000 TPD.l Health hazards for a surface mine are
chiefly associated with worker exposure to shale dust, raw shale,
and toxic gases. These hazards have been discussed in Section
4.5.1.3.
4.5.2.3f Odors
Odors at a shale surface mine are chiefly associated with
nitrogen oxides emitted during the operation of diesel -equipment.
Some odors associated with the presence of hydrogen sulfide may
also be detected. The odors are likely to be confined to the
mine site.
The inputs and outputs associated with a surface mine are
summarized in Table 4-38.
Hittman Associates, Inc., Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologic"?"! Draft Re-
port on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boiler
Combustion). Prepared for Council on Environmental Quality,
National Science Foundation, and Environmental Protection Agency.
Contract EQC 308. Columbia, Maryland. May 1974.
-97-
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TABLE 4-37. NOISE LEVELS ENCOUNTERED BY MINE WORKERS
Noise Source Sound Level, dBA
Diesel Trucks 74-109
Electric Shovels 78-101
Graders 76-104
Dozers 84-107
Rotary Drills 72-100
Front-end Loaders 83-101
Scrapers 92-104
Belted Conveyor 75-85
Primary Crushing 72-111
Source: Down, C. G. and J. Stocks. Environmental Impact of
Mining (New York: Halsted Press) 1977. p. 154.
U.S. Department of the Interior. Noise Control
Proceedings: Bureau of Mines Technology Transfer
Seminar, Pittsburgh, PA.January 22, 1975.
pp. 6, 95.
-98-
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TABLE 4-38.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH A SURFACE MINE PRODUCING
66,000 TPD OF CRUSHED OIL SHALE
Inputs
Outputs
Manpower
operating
Materials and Equipment
loading shovels
trucks
drills
bulldozers
front-end loaders
explosives truck
steel
Economics3
capital
annualized operating
Water
Land
Ancillary Energy
electricity
diesel fuelb
Air Emissions
particulates
hydrocarbons
NOX
CO
S02
CQ~2
Water Effluents
Solid Wastes
overburden
Noise
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
410 men
4
12
4
3
2
1
7400 tons
Over $200,000,000
$61,000,000
600 gpm
800-1200 acres
2.7 x 108 kwh/yr
22,000 gal/d
510 Ib/hr
92 Ib/hr
800 Ib/hr
480 Ib/hr
59 Ib/hr
19,000 Ib/hr
Extremely site dependent
71,000 TPD
Negligible
0.2/yr
10/yr
Confined to mine site
a!977 dollars
"May be supplied by upgraded shale oil
-99-
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4.5.3 Mining for In-Situ Processing
4.5.3.1 Technologies
The various, proposed in-situ oil shale processes are
largely differentiated by mining requirements or techniques.
True in-situ processes do not require any mining of the oil
shale deposits. Modified in-situ processes require underground
mining of a portion of the oil shale, followed by fracturing of
the remaining shale to form an underground rubble-filled retort.
Discussions of true in-situ processes are presented in Section
4.6.2.1, In-Situ Retorting Technologies. Mining operations re-
quired in modified in-situ processes are discussed in this sec-
tion. Retorting operations in modified in-situ processes are
discussed in Section 4.6.2.1.
Occidental Oil Shale, Inc. and the Lawrence Livermore
Laboratory at the University of California are developing
modified in-situ processes on federal oil shale lease tracts
C-a and C-b. Occidental's process has been most extensively
developed, with commercial operations (57,000 barrels of shale
oil per day) expected to commence on tract C-b in 1983. Law-
rence Livermore Laboratory's process for Rubble In-Situ Extrac-
tion (RISE) of shale oil is being developed for use on tract C-a.
Commercial operation of the RISE process is likely to commence
in 1986. Descriptions of the mining procedures of both processes
are found below. Occidental's process is the more developed
of the two processes, and is described in greater detail.
As envisioned by Occidental, an in-situ complex is mined
by developing successive geographic areas called panels . Each
panel comprises groups or clusters of retorts (as shown in
Figure 4-9). Occidental's preliminary plans anticipate panels
composed of 32 retort clusters. The retort clusters are in turn
-100-
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PANEL
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i _
RETORT CLUSTER
NOTE UNDISTURBED SHALE ZONES (PILLARS) BETWEEN RETORTS
MAY BE THICKER THAN SHOWN ON PLAN VIEW.
Figure 4-9. Plan View of Retort Arrangement.
Reference: Ashland Oil, Inc. and Occidental Oil
Shale, Inc. Modification to Detailed
Development Plan for Tract C-B.Pre-
pared for Area Oil Shale Supervisor.
February, 1977.
-101-
-------
composed of eight in-situ retorts. About 20% of the shale in a
retort is mined using classic underground techniques with the
remainder blasted into the void(s) created by the mining. The
rubble-filled zones are then retorted in place (as described in
Section 4.6.2.1). Clusters of retorts are retorted concurrently
with undisturbed shale zones serving as control partitions be-
tween operating retorts. Within each panel, some retort clus-
ters are being retorted while others are being mined and developed,
At Occidental's proposed production rate of 57,000 barrels of
shale oil per day, each panel is expected to have a production
lifetime of about 4 years.1
A simplified cross-sectional view of the in-situ complex
is shown in Figure 4-10. Each of the levels and shafts illus-
trated in Figure 4-10 is described below.
Occidental envisions accessing mining levels through three
concrete-lined 34-foot-diameter shafts: a production shaft,
a service shaft, and a product gas shaft. The production shaft
is used to convey minewater to the surface and also serves as
the main ventilation exhaust shaft for mining operations. Mined
rock (or muck) is transported to the surface through the .produc-
tion shaft by a hoist. The production shaft is also used to
convey liquid retorting products (i.e., oil and water) to the
surface. Occidental's plans call for the shaft to be sunk 2100
feet to a position about 250 feet below the production level.
Pumping and loading facilities are located at the foot of the
shaft below the production level.2
1Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b,
prepared for Area Oil Shale Supervisor.February 1977.p. III-l,
111-22.
2Ibid., p. III-5.
-102-
-------
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-103-
-------
The service shaft serves as an intake for both process air
(for retorting) and ventilation air (for mining). The shaft
is also used to convey minewater and liquid retorting products
to the surface. Occidental's plans for developing oil shale
tract C-b call for the service shaft to be sunk 1850 feet to the
production level. A hoist raises a cage for transport of heavy
equipment items.l
The sole purpose of the product gas shaft is to convey
retort off gas to surface treatment and steam generation facili-
ties. The shaft is to be sunk 1900 feet to the gas level.2
Smaller shafts used in initial retort development are used
during full-scale mining operations for ventilation, escape ways
and mine dewatering.3
Two retort development methods have been proposed by Occiden-
tal: vertical slot development and multiple level development.
The mining levels and plan for each development scheme are shown in
Figures 4-11 and 4-12. ** The process air level is located above
the retorts and carries process air to operating retorts and mine
ventilation air to mine headings under development. The air
level also contains steam distribution lines, startup burners,
air dampers, and related equipment for operating the retorts.
:Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C-b,pre-
pared for Area Oil Shale Supervisor. February 1977. p~! III-5 to 6
2 Ibid., p. III-6.
3ibid., p. III-4 to 5.
''Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supple-
mental Material to Detailed Development Plan Modifications for
Oil Shale Tract C-b, prepared for Area Oil Shale Supervisor,
July 21, 1977.
-104-
-------
AIR LEVEL
MINED ROCK IS TRANSPORTED
TO THE PRODUCTION SHAFT
FOR HOISTING TO THE SURFACE
PRODUCTION LEVEL
Figure 4-11.
An In-Situ Retort Being Developed By The
Vertical Slot Development Method.
Source: Ashland Oil, Inc. and Occidental Oil Shale, Inc.
Supplemental Material to Modifications to Detailed
Development Plan for Oil Shale Tract C-b. Prepared
for Area Oil Shale Supervisor.July 21, 1977.
AIR LEVEL
ACCESS LEVEL
MINED ROCK IS TRANSPORTED
TO THE PRODUCTION SHAFT
FOR HOISTING TO THE SURFACE
PRODUCTION LEVEL
Figure 4-12.
An In-Situ Report Being Developed By The
Multiple Level Development Method.
Source: Ashland Oil, Inc. and Occidental Oil Shale, Inc.
Supplemental Material to Modifications to Detailed
Development Plan for Oil Shale Tract C-b!Prepared
for Area Oil Shale Supervisor.July 21, 1977.
-105-
-------
Occidental's development plans provide for tunnels (called
drifts) on the air level to be 30 feet wide and 20 feet high.1
Access levels within the vertical retort interval are used
to evacuate voids in the retort. Access drifts (or tunnels) are
generally similar and parallel to other levels above and below.2
As retort clusters are being developed., the production
level receives and transports mined-out shale from the mine to
the production shaft. Under retorting conditions, the lateral
drifts under the retort act as conduits for product oil, water
and gas. Drifts on the production level contain oil/water
gathering and pumping systems and other process operating equip-
ment. Occidental's development plans anticipate production
drifts 30 feet high and 20 feet wide.3
The product gas level (shown in Figure 4-10) conveys the
product gas from the operating retorts to the product gas shaft
and then to the surface. The gas level is located below the
production level and is totally isolated from other mining
drifts. Occidental anticipates gas level drifts to be 30 feet
high and 30 feet wide.1*
The mining of the various levels proceeds by the conventional
room-and-pillar mining cycle of drilling, charging the drilled
face, blasting, wetting the blasted rock pile, loading, hauling,
scaling, and roof bolting. Drilling is performed with large-
scale electric-powered hydraulic rotary drills. The holes are
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b
prepared for Area Oil Shale Supervisor, February 1977, p~. TTl-23
2ibid., p. 111-23 to 24.
3 Ibid.
"ibid., p. 111-24.
106-
-------
then loaded with an explosive mixture (e.g., ammonium nitrate/
fuel oil) and blasted into a pile of broken rock. The rock
pile is wetted to minimize dust and conveyed to the production
shaft. An orepass system is used to transfer rock from the
upper mining level(s) to the loading pocket below the production
level. All rock is then hoisted to the surface for disposal
or surface retorting.1
After the rock pile has been removed from the work area,
loose rock is removed from the sides and roof of the mine by
mechanical scaling equipment. The sides and floor of the mine
are then wetted to control dust (if necessary).2
After the rooms within the retorts have been excavated,
holes are drilled in the remainder of the shale in the retort.
These holes are then loaded and blasted, thus rubbling the shale
column.3 Retorts developed by the vertical slot method are 150-
feet by 405-feet by 290-feet high. Retorts developed by the
multiple level method are 200-feet square by 310-feet high.
Occidental's choice of a retort development scheme is apparently
still under study. **
The RISE process is conceptually similar to the process
envisioned by Occidental. As in the OXY process, about 20 per-
cent of the oil shale is mined underground. Retorts formed by
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b
prepared for Area Oil Shale Supervisor,February 1977, p.TTl-26
2 Ibid.
3 ibid., p. 111-26 to 27.
''Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supple-
mental Material to Modifications to Detailed Development Plan
for Oil Shale Tract C-b,prepared for Area Oil Shale Supervisor,
July 21, 1977.
-107-
-------
the mining are expected to be 750 feet high with a base 150
by 300 feet. The rubble column is created by a continuous
mining process using a modified sublevel caving technique (as
shown in Figure 4-13) . This procedure presumably prepares
rubble of more uniform size than the OXY process. The proposed
mining technique also permits continual measurement of rubble
size. Obviously, a thick oil shale formation is required for
this process. No field testing of the RISE process has yet been
performed.:'2
4.5.3.2 Input Requirements
This section reports inputs required for the operation and
maintenance of a mine developing in-situ retorts. The various
manpower, equipment, water, land, and energy requirements are
largely based on data reported by Occidental in the 1977 Modifi-
cations to the Detailed Development Plan (MDDP) for Oil Shale
Tract C-b. Estimates of capital requirements and annualized
operating costs are likewise based on data reported by Occidental
in the MDDP and its supplement.
The inputs described in this section are representative of
an in-situ facility producing 57,000 barrels of shale oil per
day (as planned by Occidental). While Occidental's plan was
specifically contrived for development on tract C-b, input
requirements for facilities at other sites are not likely to be
significantly different.
^othman, A.J. "Research and Development on Rubble In-Situ
Extraction of Oil Shale (RISE) At Lawrence Livermore Laboratory",
Colorado School of Mines Quarterly. 70(3) 159-78 (1975) .
2Schora, F.C., P.B. Tarman and H.L. Feldkirchner, "In-Situ
Oil Shale Processing", Hydrocarbon Processing, March 1977, p. 12.
-108-
-------
:
4 Storting slot
j SKal*
SP^^^.0""'^"
- ' - - " -
Drift-,
1
«.» \-
Level A
a
Level 8
»i
1. DEVELOPMENT BEGINS AT TOP OF
RETORT. HORIZONTAL DRIFTS ARE
DRIVEN THE WIDTH OF THE BLOCK.
A VERTICAL STARTING BLOCK IS
DRIVEN TO PROVIDE A FREE
BLASTING SURFACE FOR
SUBSEQUENT DRILLING AND BLASTING.
*V.£dll] *
'"JVC°TX. ,?bz> ^°" ^filling
Sublevel
Starting ilof
SHole
Level A
1-ffC^ Development ] ]
Level B
2. SHALE IS LOADED AFTER EACH
BLASTING OPERATION APPROXIMATELY
20% OF THE BROKEN SHALE IS
EXTRACTED. THE REMAINDER FORMS
THE RUBBLIZED RETORT.
^^-'^lOo.O.^
^oJ.lubbliMdjhal.'O,};
^ Looding [ ]
V\?.o
....
\
Level A
P'C^ ^ fan dr. I ling | f ]
Sublevel
- Starting
Level S
Development
3. DEVELOPMENT PROCEEDS
SIMULTANEOUSLY ON MULTIPLE
SUBLEVELS.
Figure 4-13. Modified Sublevel Caving Method Proposed
For the Use in Rise Process.
Reference:
Lewis, Arthur E., et. ai. Rubble In-Situ
Extraction (Rise): A Proposed Program For
Recovery of Oil From Oil Shale"! Lawrence
Livermore Laboratory. March 5, 1975. p. 4.
-109-
-------
4.5.3.2a Manpower
For Occidental's proposed complex producing 57,000 barrels
of shale oil per day, mining operations are required to remove
approximately 41,000 tons of low-quality oil shale per day.1 Man-
power requirements for a mining operation removing 41,000 TPD have
been reported by Occidental and are shown in Table 4-39.2
The manpower requirements in Table 4-39 relate only the
personnel requirements for full-scale commercial operations.
Occidental has not reported skill breakdowns for the construc-
tion personnel required to establish the site prior to full-
scale operations. However, total manpower requirements for
developing the entire oil shale complex (including surface pro-
cessing) have been reported by Occidental and are shown in
Figure 4-14.3
4.5.3.2b Materials and Equipment
Detailed materials and equipment requirements have not yet
been prepared by Occidental. However, equipment requirements for
operating an in-situ mining development are generally similar to
those for an underground mine. The Federal Energy Administration
has estimated equipment requirements for an underground mine
excavating 140,000 TPD oil shale. While the data in the FEA
report are now somewhat outdated, an in-situ development removing
1Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C-b~pre-
pared for Area Oil Shale Supervisor. February 1977. p. 111-35 .
2Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supple-
mental Material to Modifications to Detailed Development Plan for
Oil Shale Tract C-b"prepared for Area Oil Shale Supervisor.
July 21, 1977.
3Ashland Oil, Inc. and Occidental Oil Shale, Inc., op.cit.,
Figure 1-6.
-110-
-------
TABLE 4-39. MANPOWER REQUIREMENTS FOR IN-SITU MINING OPERATIONS3
Skill Number of Personnel
Production Staff
Mine Superintendent 1
Assistant Mine Superintendent 1
General Mine Foreman 1
Shift Foreman 16
Chief Clerk 1
Mine Clerk 2
Mine Warehouseman 1
Warehouse Clerk 8
Conveyor Foreman (Surface) 4
Conveyor Foreman (Underground) 4
Technical Staff
Chief Mine Engineer 1
Mine Engineer 3
Rock Mechanics Engineer 1
Assistant Engineer 8
Ventilation and Safety Engineer 1
Assistant Ventilation and Safety Engineer 4
Chief Surveyor 1
Mine Surveyor 8
Surveyor Helper 8
Chief Geologist 1
Geologist 2
Draftsman, Mine 2
Draftsman, Geology 1
Engineering Clerk 2
Maintenance Staff
Maintenance Superintendent 1
Mechanic Foreman 8
Electrical Foreman 4
Maintenance Clerk 4
Direct Mine Labor
Driller 132
Driller Helper 132
LHD Operator 24
Powderman 32
Powderman Helper 32
Powderman (Cap) 32
Powderman (Cap) Helper 32
Hoistman 8
(Continued)
-111-
-------
TABLE 4-39. MANPOWER REQUIREMENTS FOR IN-SITU MINING OPERATIONS
(Continued)
Skill Number of Personnel
Direct Mine Labor (Cont'd)
Skip Tender 4
Crusher/Feeder Operator 20
Conveyor Operator (Surface) 8
Conveyor Operator (Underground) 8
Dozer Operator (Surface) 12
Utility Mine Labor
Rockbolter/Scaler Operator 28
Rockbolter/Scaler Helper 28
Full Truck Driver 4
Full Truck Helper 4
Lube Truck Driver 4
Utility Truck Driver 48
Dozer Operator (Barricade) 4
Motor Grader Operator 8
Mine Labor 100
Conveyor Patrol (Surface) 24
Conveyor Patrol (Underground) 40
Toplander 8
Cage Tender 4
Janitor (Dry) 4
Maintenance Labor
Hoister Oiler 8
Drill Doctor 16
Mine Mechanic 32
Mechanics Helper 32
Mine Electrician 32
Electrician Helper 32
Lampman (Dry) 4_
TOTAL 1039
Production capacity of in-situ complex of 57,000 BPD; excavation require-
ment of 41,000 TPD.
Reference: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supplemental
Material to Modifications to Detailed Development Plans for Oil
Shale Tract C-b, prepared for Area Oil Shale Supervisor.
July 21, 1977.
-112-
-------
o
(0
cc
o
g
o
CO
o
o
3500
3000
2500
2000
1500
1000
500
2900 PEAK SITE PERSONNEL
START OPERATION
FULL-SCALE PANEL
1600 FULL-SCALE COMMERCIAL
MODIFIED IN SITU OPERATIONS
157,000 BBL/D)
START CONSTRUCTION
FULL-SCALE PLANT
-t-
45678
NTH YEAR OF DEVELOPMENT
Ji A
9
10
11
12
DEVELOPMENT OF
INITIAL TEST RETORTS
DEVELOPMENT
OF TEST
RETORT
CLUSTER AND
CONSTRUCTION
OF FULL-SCALE
FACILITY
FULL-SCALE OPERATION
Reference:
Figure 4-14. Manpower Projections.
Occidental Oil Shale, Inc. and Ashland Oil Inc.
Modified Detailed Development Plans for Oil Shale
Tract C-B.Prepared for Area Oil Shale Supervisor.
February, 1977.
-113-
-------
41,000 TPD may be assumed to require about a third of the equip-
ment required for the 140,000 TPD mine. The equipment required
for the in-situ development are scaled from data in the FEA report
and are presented in Table 4-40. The equipment list is not com-
plete and may be based on outdated information.1
4.5.3.2c Economics
Preliminary capital cost estimates for a mine associated
with a 57,000 bbl/d shale oil complex are shown in Table 4-41.
These preliminary costs have been reported by Occidental in the
MDDP for oil shale tract C-b, and should not be construed as defi-
nitive cost estimates. The estimates are based only on prelimi-
nary engineering design and project scheduling, and do not include
interest during construction and deferred capital expenditures.
The capital cost estimates reported in Table 4-41 include only
those costs directly related to the mine, and exclude costs for
general facilities, indirect costs, and working capital which were
shared by the entire in-situ complex. Miscellaneous capital re-
quirements (i.e., costs for general facilities, indirects, and
working capital) for the entire in-situ complex are discussed in
Section 4.6.2.2.2
Operating costs estimates for the OXY process were not re-
ported in the MDDP or in the Supplement to the MDDP. However,
data reported in the MDDP (and its supplement) can be used to
contrive preliminary cost estimates. The labor costs are esti-
mated from the labor requirements reported by Occidental in the
federal Energy Administration, Interagency Task Force on
Oil Shale, Project Independence Blueprint. Final Task Force
Report, Potential Future Role of Oil Shale Prospects and Con-
straint's"!November, 1974. p"! a-168.
2Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plans for Oil Shale Tract C-b.
Prepared for Area Oil Shale Supervisor. February 1977. p"! I-11
-114-
-------
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TABLE 4-41. MINING CAPITAL COST ESTIMATES FOR
AN IN-SITU OIL SHALE COMPLEXa>b>c
Shafts, Hoist, Appurtenances $ 38,053,000
Mobilization 9,537,000
Equipment and Spares 21,450,000
Conveyors and Materials Handling 19,003,000
Labor 18,360,000
Other Materials 29,328,000
Taxes 965,000
$136,696,000d
<3
Costs are in 1977 dollars.
Costs are those reported by Occidental.
°Shale oil production capacity of 57,000 BPD, excavation
requirement of 41,000 TPD.
General facilities costs, indirect costs, and working capital
are reported for entire facility in Section 4.6.2.2.
Reference: Ashland Oil, Inc. and Occidental Oil Shale, Inc.
Modifications to Detailed Development Plans for Oil
Shale Tract C-b^Prepared for Area Oil Shale Super-
visor. February 1977. p. 1-11.
-116-
-------
Supplement to the MDDP. Utilities' costs are estimated from
the power and fuel requirements reported in the MDDP and its
supplement. All other costs are estimated as percentages of the
capital or labor costs. These estimates are shown in Table 4-42,
and are based on preliminary, incomplete data.
4.5.3.2d Water
Most of the water required for an underground mining opera-
tion is needed for dust control. Occidental has estimated water
requirements to be 450 gpm (730 acre-ft/year) for mining in a
57,000 bbl/d shale oil complex. Essentially the entire water
requirement could be met with readily-available untreated mine-
water. Water requirements for revegetation of mined-out shale
are discussed in Section 4.7, Reclamation.1
Occidental has also estimated the water required during
construction of the in-situ facility. Consumptive uses during
construction include concrete manufacture, dust control, and
fill compaction. Quantities for these uses amount to 500-700 gpm
(800-1100 acre-ft/year). The entire requirement could be met by
water from dewatering operations.2
4.5.3.2e Land
Occidental has made estimates of the land areas disturbed
by an in-situ development. In the development of a 57,000 bbl/d
facility, approximately 40 acres are required for mine shafts
1Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plans for Oil Shale Tract C-b.
Prepared for Area Oil Shale Supervisor. February 1977. p~! Til-29
2ibid., p. 111-42 to 44.
-117-
-------
TABLE 4-42.
ANNUALIZED OPERATING COSTS FOR MINING
AT AN IN-SITU OIL SHALE COMPLEX3>b
Direct Costs
Mine Labor
Maintenance Labor
Maintenance Staff
Technical and Production Staffs
Total Labor and Supervision
Operating Supplies
Maintenance Materials
Utilities
Electricity
Waterh
Diesel Fuel
Fixed Costs
Depreciation
Taxes and Insurance
Plant Overhead
TOTAL
$12,000,000°
2,300,000°
350,000*:
1.600.000
16,000,000
1,400,000*
2,300,000
9,200,000g
14,000,000^
4,100,000
8.OOP.OOP1
$56,000,000 $2.70/bbl
Costs are in 1977 dollars and include
only those costs directly attributed
to the mining operation.
Shale oil production capacity of
57,000 BPD; excavation requirement
of 41,000 TPD.
Calculated @ $15,000/man/year.
Calculated @ $20,000/man/year.
Calculated @ 1% of the fixed capital
costs.
Calculated @ 100% of maintenance
labor.
Calculated @ $0.04/kwh.
Essentially all water requirements
are met by use of minewater.
Calculated @ $0.50/gal.
-'Calculated @ 10% of fixed capital.
Calculated @ 3% of fixed capital.
Calculated @ 50% of total labor costs.
NOTE: Rates for calculating fixed costs, plant overhead, and costs for oper-
ating supplies and maintenance materials are largely based on Peters,
M.S. and K.D. Timmerhaus. Plant Design and Economics for Chemical
Engineers, 2nd. Ed. (New York: McGraw-Hill Book Co., 1968). pp. 132-141,
References: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications
to Detailed Development Plans for Oil Shale Tract C-b. Prepared
for Area Oil Shale Supervisor. February 1977. p. 1-11.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supplemental
Material to Modifications to Detailed Development Plans for Oil
Shale Tract C-b. Prepared for Area Oil Shale Supervisor. July
21, 1977.
-118-
-------
and related support structures. Road construction for the entire
complex requires about 60 acres. Land requirements for holding
ponds for excess minewater have not been specified. Total land
requirements for fixed surface facilities are on the order of
100 acres.1
If mined-out shale is not retorted on the surface, about
100 additional acres will be required each year for the disposal
of mined-out shale.2
4.5.3.2f Ancillary Energy
Ancillary energy requirements for an underground mine have
bee.n reported by Occidental, and are tabulated in Table 4-43 3 ' *
The energy recovery ratio of mining for in-situ processing is
included in the value reported in Section 4.6.2.2 for the
overall modified in-situ processing development.
4.5.3.3 Outputs
This section reports the various outputs associated with
the operation of a mine developing in-situ retorts. Discussions
of air emissions, water effluents, solid wastes, and noise
pollution are largely based on information reported by Occidental
in the MDDP and its supplement. Although Occidental's data are
1Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plans for Oil Shale Tract C-b,
prepared for Area Oil Shale Supervisor, February 1977, p. 1-13.
2Ibid.
3 Ibid. , p. 111-39.
^Ashland Oil, Inc. and Occidental Oil Shale, Inc., Supple-
mental Material to Modifications to Detailed Development Plan
for Oil Shale Tract C-b, prepared for Area Oil Shale Supervisor,
July 1977.
-119-
-------
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specific to oil shale tract C-b, outputs for in-situ development
at other locations are probably very similar. However, the
environmental impacts from these outputs do vary from site to site
4.5.3.3a Air Emissions
Air emissions from mining operations originate from the
production shaft mine vent, the shale conveyor, and the shale
disposal area. Mine vent emissions are shown in Table 4-44
and are discussed below. Emissions resulting from the trans-
portation and disposal of mined-out shale are shown in Table
4-45. Air emissions from mining operations are those reported
by Occidental for a 57,000 bbl/d facility in the supplement to
the MDDP.
Emissions arising from underground mining operations exit
the mine vent and are shown in Table 4-44. Conventional mining
operations (i.e., mining, blasting, hauling, and crushing) are
the largest sou' ^°s of particulates. Blasting operations re-
quired to rubble the shale formation are the largest sources of
sulfur dioxide, Carbon monoxide, and nitrogen oxides. Diesel
equipment is the largest source of hydrocarbon emissions. The
emissions data in Table 4-44 assume a baghouse 99% efficient in
controlling particulate emissions originating from the mine vent.
Diesel equipment is assumed to be equipped with catalytic con-
verters 90% efficient in controlling carbon monoxide and hydro-
carbon emissions.1 Emissions from the transportation and disposal
of mined-out shale have also been estimated by Occidental, and
are shown in Table 4-45. Estimates of both uncontrolled and
controlled particulates emissions are reported, with possible
control technologies reported at the bottom of the table.
1 Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supple-
mental Material to Modifications to Detailed Development Plan for
Oil Shale Tract C-b~prepared for Area Oil Shale Supervisor,
July 1977.
-121-
-------
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4.5.3.3b Water Effluents
Potential water effluents from mining operations include:
excess minewater, runoff from raw shale piles, and sanitary
wastewaters. Volumes of these potential water effluents have
not been estimated. Quantities and qualities of excess mine-
water and runoffs are largely dependent on the site of the in-
situ development. Characteristics and disposal of these water
effluents have been discussed in Section 4.5.1.3.
4.5.3.3c Solid Wastes
Mining operations for Occidental's 57,000 bbl/d facility
excavate about 41,000 tons of raw oil shale per day. Nearly
all of the mined-out shale can be disposed of on the mine pro-
perty. The area required for shale disposal is estimated at
100 acres per year. If the mined-out shale is surface retorted,
somewhat larger disposal areas are required. Inorganic salts,
toxic metals, and some toxic organics are contained in both
raw and retorted shale. Some potential exists for back-filling
the underground complex. However, disposal of shale by back-
filling has not been demonstrated and will not consume all of
the shale.l
Water treatment sludges result from upgrading minewater
for retorting/processing, and are discussed in Section 4.6.2.3.
1Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b.
Prepared for Area Oil Shale Supervisor.February 1977.
p. 111-43.
-124-
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4.5.3.3d Noise Pollution
Noise at the underground mine originates from normal min-
ing operations and from the large blasts required to rubble
retorts. Sound levels within the mine during mining operations
are similar to those encountered in underground coal mines.
Typical ranges of sound levels at worker positions are shown in
Table 4-46.
Noise levels that exist during blasting have not been
measured or estimated. Hazards to workers can be minimized by
evacuating personnel from those areas most affected by the
blasts. The rubbling blast is not usually heard at distances
farther away than 500 to 600 yards from the blast.1
4.5.3.3e Occupational Health and Safety
Health and safety hazards associated with the mining of an
in-situ complex have not been extensively examined. Safety
hazards for an in-situ mining operation are probably similar
to those for standard underground mines. Using data estimated
for an underground shale mine, approximately 21 injuries and 0.5
fatalities will occur annually in a mine excavating 41,000 tons
of shale per day. (That shale excavation rate corresponds to
an in-situ complex producing 57,000 bbl/d.)2
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to Detailed Development Plan for Oil Shale Tract C-b.
Prepared for Area Oil Shale Supervisor.February 1977.p. V-4.
2Hittman Associates, Inc. Environmental Impacts, Efficiency
and Cost of Energy Supplied by Emerging Technologies.Draft Report
on Task 7 (Oil Shale) and Task 8 (Fluiaized Bed Boiler Combustion).
Prepared for Council on Environmental Quality. National Science
Foundation and Environmental Protection Agency. Contract EQC 308.
Columbia, MD. May 1974.
-125-
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TABLE 4-46. NOISE LEVELS ENCOUNTERED BY MINE WORKERS3
Noise Source Sound Level, dbA
Roofbolter/Scaler 107 - 118b
92 - 101°
Drill 80 - 104
Air Pump/Fan 90 - 105
Conveyor 90 - 105
75 - 85e
Crusher/Feeder 90 - 105
LHD 90 - 108
Sump 93-98
Hoist 85 - 95
a
Data assumes that underground shale mines and underground coal mines have
similar noise sources and characteristics.
Pneumatic roofbolter.
£
Rotary roofbolter.
Flighted conveyor.
eBelted
conveyor,
Source: U.S. Department of the Interior. Noise Control Proceedings:
Bureau of Mines Technology Transfer Seminar, Pittsburgh, PA.
January 22, 1975, pp. 6, 95.
-126-
-------
Health hazards for an in-situ mining operation are chiefly
associated with worker exposure to shale dust, raw shale, and
toxic gases. These hazards have been discussed in Section 4.5.1.3
Another potential hazard is worker exposure to off gas from
operating retorts. This hazard can be avoided by conveying the
off gas through gas drifts completely isolated from all mine
workings (as planned by Occidental).
4.5.3.3f Odors
Odors at the mine are chiefly associated with nitrogen
oxides, sulfur dioxide, and hydrogen sulfide emitted during
mining operations. These odors are likely to be confined to the
mine site.
The inputs and outputs associated with a modified in-situ
mining development are summarized in Table 4-47.
4.5.4 Social Controls
After a feasible potential oil shale deposit has been
located, the land and the approval of the regulating bodies must
be obtained. Both the acquisition of the lands and the required
permits to mine will be discussed in the following sections.
In addition to the regulation of the procedure to obtain
the lands for mining, some jurisdictions will also regulate
mine safety. The following sections describe both.
-127-
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TABLE 4-47.
SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED
WITH A MINE EXCAVATING 41,000 TPD OF OIL
SHALE FOR A MODIFIED IN-SITU DEVELOPMENT
Inputs
Outputs
Manpower
operating
Materials and Equipment
jumbo drills
powder trucks
scaling and roof bolting rigs
front-end loaders
haulage trucks
bulldozers
Economics3
capital
annualized operating
Water
Land
mine shafts, support
structures, roads
mined-out shale
Ancillary Energy
electricity
diesel fuel
Air Emissions
particulates
hydrocarbons
NOx
CO
S02
C02
Water Effluents
Solid Wastes
raw shale
Noise Pollution
at mine boundary
Occupational Health and Safety
deaths
injuries
Odors
1039 men
6
4 '
4
4
12
4
$140,000,000
$56,000,000
450 gpm
100 acres
100 acres/yr
2.3 x 108 kwh/yr
7000 gal/d
382 Ib/hr
12 Ib/hr
300 Ib/hr
260 Ib/hr
2 Ib/hr
6200 Ib/hr
Extremely site dependent
41,000 TPD
Negligible
0.5/yr
21/yr
Confined to mine site
a!977 dollars
-128-
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4.5-4.1 Obtaining Lands
The land may be owned by the federal government, individual
Indian or Indian tribes, or private corporations or individuals.
Leasing procedures vary according to who owns the land. The
following sections describe procedures for obtaining lands for
oil shale development in these categories.
4.5.4.la Federal Lands
At the present time, no federal oil shale leases are being
granted. The most recent leasing, in 1973, was the prototype
lease sale which will be described below.
In 1968, the Department of the Interior undertook a review
of federally owned oil shale resources, including the formula-
tion of environmental impact analyses, and the development of a
new prototype leasing program. The result of this review, the
Prototype Oil Shale Leasing Program, was announced by Interior
in 1971 and approved for implementation in 1973.
Under the prototype lease program, six tracts of approxi-
mately 5,000 acres each were to be leased under a bonus bid
system. Sale of the six tracts began in January 1974, and was
completed by mid-1974. Only four of the six were leased, two
each in Colorado and Utah: no bids were received for the two
Wyoming tracts.
According to Interior, the Prototype Program is intended
to:
-129-
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1) Provide a new energy source by stimulating private
commercial technological development;
2) Insure the environmental integrity of affected
areas;
3) Permit an equitable return to the parties that
develop the resources; and
4) Develop management and supervisory expertise in oil
shale leasing for the future.l
Some federal lands are excluded from oil shale development
under the Prototype Program, including: 1) all national forests;
2) all Naval Oil Shale Reserves; 3) designated fish and game
experimental or management areas; 4) designated historical land-
marks, 5) oil shale experimental sites, and 6) lands reserved for
other minerals.2
The Department of Interior's overall responsibility for
federally owned oil shale lands and resources is comparable to
that for coal lands. The Secretary has discretionary authority
to lease and manage these lands and may withdraw certain lands
from leasing or modify previous withdrawals to permit leasing
mineral rights on public lands. Only the Department of the
Interior may initiate the leasing process for oil shale, although
^.S. Congress, House. Science and Astronautics Committee.
Energy from Oil Shale. 1973. p. 54.
2U.S. Department of the Interior. Final Environmental State-
ment for the Prototype Oil Shale Leasing Program. 6 vols. Wash-
ington, D.C.1973.
-130-
-------
the Department may invite private parties to nominate tracts.
But regardless of how nominated, USGS evaluates the resource
potential.
Sealed bids together with 20 percent of the bonus bid amount
must be submitted before the scheduled sale date. Usually a
lease will be awarded to the qualified party offering the highest
bonus bid; however, the Secretary does have the discretionary
authority to reject any bid.
The purchaser pays the remaining 80 percent of his bonus
bid in four equal annual installments.1 However, certain expen-
ditures such as capital costs for mining and processing equipment
can be credited against the last two payments.
Bonus bids were quite high on the four tracts sold in the
Program. The first tract bid was $210 million, a per-acre bonus
of almost $42,000. Winning bids on the other three tracts were
lower.
The minimum rental fee, fixed by statute, is 50 cents per
acre per year. Royalty rates were left to the discretion of the
Secretary. In the Prototype Program, royalty rates were fixed at
12 cents per ton for oil shale containing 30 gallons of oil per
ton, and at varying rates for other grades of shale. Royalty rates
may be adjusted as crude oil prices change, and additional pay-
ments may be required for minerals other than oil recovered dur-
ing oil shale operations. For the Prototype Program, the minimum
^.S. Congress, House. Science and Astronautics Committee.
Energy from Oil Shale. 1973. p. 54.
-131-
-------
royalty is $16 million for each 1.5 billion barrels of recover-
able oil, over the twenty year lease period. A reduction of
royalty of one-half the difference between minimum and actual
royalty will be given in the eighth year of the lease. And, at
his discretion, the Secretary may charge "unanticipated environ-
mental costs" or some other expenditures against royalty
payments.
The Secretary is authorized to issue the lease for an
"indeterminate" period. In the Prototype Program the term is
fixed at twenty years or for "as long as the lease is producing
commercial quantities of oil." At the discretion of the
Secretary, the terms of the lease may also be readjusted at the
end of the initial twenty years.
Holdings are limited to approximately 5,120 acres by the
Prototype Program. Not more than one lease may be granted per
person, association, or corporation; however, indirect ownership
of more than one lease is permitted as long as the 5,120 acre
total is not violated.
An important factor is the environmental controls which are
stipulated to by the energy developer. The stipulations are
included by reference in the lease itself making the developer
bound by contract law rather than criminal or civil sanctions.1
These stipulations are quite comprehensive and include the follow-
ing categories: general, access and service plans, fire preven-
tion and control, fish and wildlife, health and safety, historic
and scientific values, oil and hazardous materials, air pollution,
Phillips, David F. "Legal Mechanisms for Access to Coal
and Oil Shale." Stanford Research Institute. 1976. pp. 7-37
through 7-38.
-13.2-
-------
water pollution, noise pollution, rehabilitation, scenic values,
vegetation, and waste disposal.1
4.5.4.1b Indian Lands
Procedures for acquiring Indian lands for oil shale develop-
ment are similar to those for coal development on federal lands;
both the federal government and the appropriate Indian authorities
have veto power over leasing decisions.
Although Indian lands are not an integral part of the pub-
lic domain, Indians do not have complete legal title. There are
two principal categories of Indian lands: 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, its stated goal being to protect Indian
interests by providing assistance and service in granting permits
and making leases.
The general provisions and procedures for leasing Indian
lands for oil shale are listed as follows:
1) Interest initiated by tribes or private individuals.
2) Nominations approved by Indians and BIA.
3) EIS process if applicable.
4) Lease sale held.
4.5.4.1c State Lands
As noted earlier, most states have reserved their minerals,
making a lease with royalty to the state the only method available
^.S. Department of the Interior. Final Environmental
Statement for the Prototype Oil Shale Leasing Program. 6 vo1s.
Washington, D.C.1973.
-133-
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for mineral (including oil shale) development. As noted in
Section 4.4.4 Colorado has no state lands in the oil shale area;
hence, this section will discuss the leasing of lands from the
states of Utah and Wyoming only.
The state of Utah has adopted an attitude favoring oil shale
development on its state lands. Statutes provide that there
shall be no royalty (which could be up to 12% percent) on the
first 200,000 barrels of commercial production from oil shale
from state lands.1 Another provision allows the State Land Board
to credit a meritorious oil shale plan against future rentals
to an amount designed not to reduce rentals below 50c per acre
per year.2
Although many states entered the Union with grants of one
or two sections of land per township to the state for the support
of common schools, Utah, along with some other states, entered
the Union with a grant of four sections per township.3 Because
of potential claimant conflicts on the granted lands, title would
not vest in the state until a survey was complete and there were
no third party claims. When a prior transfer of the title of the
school lands to a third party had occurred, the states were allowed
to make "indemnity selections" or exchanges of those sections for
others within federal lands. The enabling legislation for the
states also specified that the selected land not be "mineral" in
character. This was amended in 1958 and 1966 to allow the states
'Utah Code Annotated § 65-1-109 (Cum. Supp. 1975).
2Utah Code Annotated § 65-1-113 (Cum. Supp. 1975).
3The thought was that the arid nature of the land required
more of it to provide an equal footing. Utah and the other arid
states received sections 2, 16, 32, and 36. See Enabling Act of
July 18, 1894, ch. 138, § 6, 28 Stat. 107, 109.
-134-
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to select mineral lands in exchange for mineral lands which were
owned by a third party.l
Utah has agressively pursued this exchange procedure and by
1975 had acquired an acreage subject to in-lieu selection of
200,000 acres and further had shown that 160,000 acres of that
should be "mineral" in nature.2 Between 1965 and 1971, Utah made
application to have 157,255.90 acres of its mineral selection
lands picked from federal lands in Uintah County, Utah - the
location of the federal oil shale leases. The application by
Utah resulted in repeated delays by Interior and consequently
Utah proceeded to court for a declaratory judgment.3 If Utah is
upheld in its request for title, its leasing policy toward
state lands for oil shale development would be a major factor in
encouraging oil shale development.
Although Wyoming has oil shale within its boundaries and
the state does own some school sections (640 acre tracts), the
feasibility of developing such small tracts is minimal. There
was hope that the federal leases on tracts W-a and W-b in Wyoming
(for in-situ recovery) would also lease the contiguous state
lands. When the federal leases failed to draw any bidders,
Wyoming decided to write a new set of regulations specifically
for oil shale leasing.1*
Presently existing statutory procedures for leasing state
lands for oil shale development in Utah and Wyoming are summarized
in Tables 4-48 and 4-49.
:72 Stat. 928 and 80 Stat. 220, respectively.
2Eliason, Max D. "Land Exchanges and State In-Lieu Selec-
tions as They Affect Mineral Resource Development." In: Rocky
Mountain Mineral Law Foundation, p. 640.
3Utah v. Hathaway. Civil No. C-74-64, (D. Ut. Mar. 4, 1974).
"Phillips, David F. "Legal Mechanisms for Access to Coal and
Oil Shale." Stanford Research Institute. 1976. pp. 7-37 through
7-38.
-135-
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TABLE 4-48. WYOMING OIL SHALE LEASE
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§36-74 Board of land commissioners, Commissioner of
public lands
None
§36-42 Fee for filing a lease application is $15
None
None
§36-74 Not more than 10 years, with preferential right
to renew for 10 year periods
None
§36-74 The agency above has authority to set rates and
terms in its rules and regulations within con-
fines of specific statues noted above
Source: Wyoming Statues of 1857.
TABLE 4-49. UTAH OIL SHALE LEASE
Item
Statutes
Summary
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
§65-1-18 State Land Board
None
§65-1-24 15
-------
4.5.4.1.d Private Lands
Sizeable blocks of land are needed to make the oil shale con-
version process economically feasible. At present in Utah there
is one block of private land known as the Watson Property which
is economically feasible and which has been estimated to contain
500-700 million barrels of shale oil.
The statutes which control oil shale development at the
mineral acquisition stage on private land are state laws concern-
ing contracts and case law that has developed under mineral lease
clauses. Of course, with the promise that individuals are free
to contract as they wish, the only input from state law would be
that arising if the contracts-leases were taken to court for
enforcement.
To acquire a large block of single-owner oil shale land, a
private owner may exchange land with the federal government.1
The Bureau of Land Management is authorized to make such exchanges
of federal land for private land if and only if the "public inter-
ests will be benefited thereby." Additional requirements for
the exchange are that the value of federal lands given up not
exceed the value of the exchanged land and that the exchanged
lands not be more than fifty miles from the base lands if located
in another state. If they are within the same state they may be
any distance apart.
In 1974 because of the importance of land exchanges and oil
shale development the Department of Interior issued a "Department
Policy for Exchange of Oil Shale Lands" which stated:2
'43 U.S.C. 315g (c) (1970). This process is currently
being undertaken by Superior Oil Company.
2Eliason, Max D. "Land Exchanges and State In-Lieu
Selections as They Affect Mineral Resource Development." In:
Rocky Mountain Mineral Law Foundation, Vol. 21, p. 640.
-137-
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...The Department'of Interior recognized that oil shale
resources could contribute significantly to the domestic
energy supply by 1980-1985... It is the policy of the
Department to the Interior to facilitate efficient and
environmentally safe development of both private and
public oil shale lands and to encourage the development
of new technology through a program of land exchanges
designed to consolidate land ownerships, thereby elimi-
nating intermingled ownership land patterns.
The procedures for exchanging privately owned oil shale
lands for Federal oil shale lands is prescribed in the Code of
Federal Regulations.1 The application must include a descrip-
tion of both lands, a list of the reservations and exceptions to
the titles of the lands involved, a description of water resources
on both lands, a statement of the purpose of the exchange and
the public interest factor, information on the value of the lands,
and a petititon to the Secretary of Interior to allow the exchange
of withdrawn lands (if necessary).2
In order to determine whether the lands exchanged are of
equal value, the U.S.G.S. is required to consider the whole of
the oil shale development plan to weigh its feasibility. A docu-
ment entitled Exchange of Oil Shale Lands - Appraisal Proceedings,
was published in 1975 by the Colorado BLM Office and the Central
Region U.S.G.S. Office and suggested the following factors be
considered:3
1) The current market value of the offered lands must
be equal to or exceed the current market value of
the selected lands. This must include all resource
values.
:43 C.F.R. §§ 2200 et.seg. (1974).
243 C.F.R. §§ 2400 et.seg. (1974).
3Eliason, Max D. "Land Exchanges and State In-Lieu Selections
as They Affect Mineral Resource Development." In: Rocky Mountain
Mineral Law Foundation, Vol. 21, p. 640.
-138-
-------
2) The proposed use of the lands to be exchanged must
not result in an unacceptable impact on the environment.
3) The exchange must be in the public interest.
As always in the West, the burden on the title of private
lands by mining claims must be considered. The Department of the
Interior seems willing to accept such lands, but procedures to
identify the claimants and purchase their rights must be followed.1
4.5.4.2 Health and Safety
Health and safety regulations for oil shale mining, whether
underground or surface, are no different from the general safety
regulations described in Chapter 2 of this report.
4.5.4.3 Mining Permits and Reclamation
Both federal and state regulations control mining and/or
reclamation associated with oil shale development. Federal con-
trols are those stemming from federal ownership of the land
environmental stipulations of the Prototype Oil Shale Leasing
Program. Both of these federal controls are described below.
State laws also will be noted below along with a discussion of
the application of state laws to federal land.
Max D. "Land Exchanges and State In-Lieu Selections
as They Affect Mineral Resource Development." Rocky Mountain
Mineral Law Foundation, Vol. 21, p. 834.
-139-
-------
4.5.4.3a Federal Controls
The regulations set out in the Code of Federal Regulations1
are the same as those applicable to coal reclamation and are
described in Chapter 2.
Those reclamation controls set out in the federal leases under
the Prototype Oil Shale Leasing Program require generally that the
lessee shall:2
backfill and/or reclaim excavated material and processed
shale and compact it thoroughly; design slope faces of
waste piles to insure slope stability; revegetate slope
faces and other areas in accordance with the rehabilita-
tion plan; and comply with numerous requirements for the
restoration of disturbed land.
More specifically, Section 11 of the environmental regulations
controls reclamation.
Three separate bonds must be executed if the oil shale devel-
oper is working on a federally owned and leased land. First a com-
pliance bond of $20,000 is required.3 Secondly a reclamation bond,
set initially at $2,000 per acre for spent shale disposal sites and
$500 per acre for other areas, is required."* Last there is an addi-
tional compliance bond of not less than $20,000 conditioned on com-
pliance with 30 C.F.R. Part 231 (Mine Operation Regulations), 43
C.F.R. Part 23 (Reclamation), the environmental stipulations, the
'43 C.F.R. Part 23.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials. Prepared for Area Oil Shale Supervisor
for Tract C-b.February 1976. p. V-96.
3Phillips, David F. "Legal Mechanisms for Access to Coal
and Oil Shale." Stanford Research Institute. 1976. p. 7-41.
"ibid. , p. 7-42.
-140-
-------
development plan, and anything else which may affect the
environment.1 The amount of the bond is negotiated in the terms
of each lease.
4.5.4.3b State Controls
State reclamation controls discussed in Chapter 2 including
mine permits would be applicable to oil shale reclamation on
private and state lands. Note also that Wyoming has succeeded
in having the state reclamation laws applicable to coal mining
on federal land with the state.2 Whether this will be true of
oil shale development is not known at this time.
Phillips, David F. "Legal Mechanisms for Access to Coal
and Oil Shale." Stanford Research Institute. 1976. p. 7-42.
2 See Chapter 2 ERDS.
-141-
-------
4.6 PROCESSING
As previously described in Section 4.5, two major options
are available for oil shale development. These are:
1) mining of the shale deposit, followed by surface
processing of the mined-out shale, and
2) underground or in-situ processing.
Sections 4.6.1 and 4.6.2 discuss surface and in-situ processing.
Section 4.6.3 briefly discusses a scheme combining both pro-
cessing technologies.
Oil shale processing comprises two distinct activities:
retorting and upgrading. Retorting is the pyrolysis reaction
in which kerogen is decomposed and stripped from shale to yield
hydrocarbon gases, liquids, and a carbonaceous residue. "Pyroly-
sis" is the heating of organic material in an oxygen lean atmo-
sphere that inhibits complete oxidation. Retorting temperatures
generally exceed 900°F.
Upgrading improves the characteristics of retorting gaseous
and liquid products. Liquid products can be upgraded for trans-
portation to refineries or for consumer use. Gaseous products
are usually upgraded for use as fuel by the processing facility.
Major technology choices involve the selection of a retorting
process, and the determination of the degree of upgrading to be
performed on site. Shale oil upgrading is discussed in Section
4.6.1.1.
4.6.1 Surface Processing
-142-
-------
4.6.1-1 Technologies
Figure 4-15 is a classification of in-situ and surface
retorting technologies. Current surface retorting processes
involve either solid-solid or solid-gas heat transfer. Processes
which involve solid-solid heat transfer rely on heated solids
such as ceramic balls, sand, or processed shale to supply the
heat required for retorting. Such processes heat the particles
in an external heater and then mix them with the raw shale in
the retort. After retorting, the heat-carrying solids must be
separated from the processed shale for recycle to the retort.
Product gases and condensible vapors are taken overhead.
Surface processes which involve gas-solid heat transfer use
either internal gas combustion or external heat generation.
Processes using internal gas combustion inject air directly
into the retort. The heat liberated from the resulting com-
bustion of both carbon residue on the shale and recycled retort
gas provides the heat required for retorting. Processes using
external heat generation rely on external heaters to provide a
high-temperature recycle gas which is then routed to the retort.
The heat contained in the recycle gas raises the temperature of
the shale to that required for retorting. Combustion of carbon
residue on the processed shale does not occur in the retort.
The following sections describe six of the major surface
retorting processes.
4. 6.1.la TOSCO II Oil Shale Process
The TOSCO II process is an improved version of the ASPECO
process, which The Oil Shale Corporation (TOSCO) purchased in
1952. Initial development work was conducted under TOSCO
sponsorship by the Denver Research Institute in a 24-ton per day
(TPD) pilot plant during 1955-1966. In 1964, a joint venture of
-143-
-------
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Standard Oil Company of Ohio, Cleveland Cliffs Iron Company,
and TOSCO, known as Che Colony Development Company, was formed
to commercialize the process. The Colony Development Operation1
conducted field tests until 1972 in a 1,000 TPD semiworks plant.
A full-scale 66,000 TPD commercial plant producing 47,000 BPD
of low sulfur fuel oil and 4300 BPD of LPG has been designed.
The plant would be located on the Dow West property of the
Middle Fork of Parachute Creek. Plans for commercialization
have not matured since 1974.2'3 At one time, TOSCO II technology
was envisioned for each of the four federal oil shale tracts.
As envisioned by TOSCO for a 66,000 TPD facility, the
pyrolysis and oil recovery unit comprises six individual retorting
trains, each capable of processing 11,000 TPD of raw shale. A
schematic drawing of a single retorting train is shown in
Figure 4-16.*
Crushed raw shale feed of particles less than one-half inch
in size are conveyed from fine-crushed-ore storage to surge
hoppers in the retort section. From the surge hoppers, the raw
shale is fed to a dilute phase fluidized bed where it is pre-
heated to about 500°F by direct heat exchange with hot flue gas
:The venture name was changed to the Colony Development Oper-
ation when Atlantic Richfield joined the venture in 1969. Later,
Ashland Oil Company and Shell Oil Company replaced Sohio and Cliffs
2Prien, C. H. "TOSCO II Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes. Prepared
for U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. December 1976. p. 37.
3Schora, F. C., P. B..Tarman and H. L. Feldkirchner. "State-
of-the-Art - Above Ground Shale Processing", Hydrocarbon Processing
56 (2): 113-119, February 1977.
"*Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor. February 1976. pp. IV-42
to IV-44.
-145-
-------
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from the ball heater. The preheated raw shale is separated from
the flue gas in settling chambers and cyclones and sent to a
rotating drum retort.1'2
Hot flue gas is incinerated within the preheat system to
reduce trace hydrocarbons to less than 90 parts per million in
the discharge flue gas. After heat exchange with the raw shale,
the cooled flue gas is passed through dry cyclones and a high-
energy venturi wet scrubber to remove shale dust. The cooled
flue gas is then vented to the atmosphere at a temperature of
approximately 125°F to 130°F. The venturi scrubbers produce
an effluent stream of raw shale dust in water. This stream is
clarified, with a portion of the water recycled to the scrubbers.
Thickened sludge produced in the clarifier is placed on the
processed-shale conveyor for disposal in the processed-shale
embankment.3
Pyrolysis occurs in the retort by solid-to-solid heat
exchange between the preheated shale and hot ceramic balls.
The balls are heated to about 1300°F in a vertical ball heater
and then fed to the retort to mix with the preheated shale.
About one and one-half to two tons of ceramic balls are mixed
with every ton of preheated shale. The mixture of balls and
shale flows through the retort, where the shale is pyrolyzed at
a temperature of about 900°F. An internal pressure of 5 psig
is maintained to prevent the entrance of air. Hydrocarbon vapors
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b. Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. pp. IV-42
to IV-44.
2Prien, C. H. "TOSCO II Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery ProcessedPrepared
for U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. December 1976. p. 37.
3Ashland Oil, Inc. and Shell Oil Co., op.ait.
-147-
-------
produced from pyrolysis are recovered in an oil recovery
system, leaving a residual mixture of balls and processed
shale.1'2
The rotating retort is essentially a ball mill: as the
kerogen decomposes, the oil shale loses strength and is disinte-
grated by the ceramic balls. Approximately 4-570 carbonaceous
material remains on the shale. The mixture of balls and shale
leaves the retort and passes over a rotating trommel screen which
separates the balls from the processed shale.3
Flue gas from the stack of a steam superheater is used to
entrain residual dust from the balls before they are recycled.
The dust is removed from the flue gas with cyclones and a high-
energy venturi wet scrubber. The ceramic balls are then recycled
to the vertical ball heater by a bucket elevator. "*
The processed shale is cooled to about 300°F in a rotating
drum steam generator. The product steam enters the plant utility
system. The cooled processed shale is moisturized to approximately
14 weight percent moisture in a rotating-drum moisturizer to min-
imize fugitive dust and insure proper handling and compaction
'Prien, C. H. "TOSCO II Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes. Prepared
for U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. December 1976. p. 37.
2Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. June 1976. p. 24
3Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Mateials for Oil Shale Tract C-b, Volume I, Pre-
pared for Area Oil Shale Supervisor.February 1976. pp. IV-42
to IV-44.
"ibid.
-148-
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characteristics. Wastewater can be used to moisturize the pro-
cessed shale. Steam produced during moisturizing contains shale
dust which is recovered in a venturi wet scrubber before the
steam is discharged to the atmosphere. The processed shale is
then conveyed to a disposal site. Dust collected from the various
venturi scrubbers throughout the process is also routed to a
disposal site with the processed shale.1
In the oil recovery section of this unit, hydrocarbon vapors
are separated by fractionation into gas, naphtha, gas oil, bottoms
oil and water. The gas and naphtha streams are sent to the gas
recovery and treating unit for gas treating and naphtha stabili-
zation. The gas oil is sent to the gas-oil hydrogenation unit.
The bottoms oil is sent to the delayed-coker unit. Moisture in
the gas stream is condensed and sent to the foul-water stripping
unit for the removal of absorbed ammonia and hydrogen sulfide.
The stripped water is used in the pyrolysis unit for moisturizing
processed shale.2
Process heaters in the pyrolysis unit can be designed to
burn either treated fuel gas, liquid Ci/s, or fuel oil produced
in the plant.3
Crude shale oil produced via the TOSCO II process has prop-
erties similar to those shown in Table 4-50. The properties of
component shale oils are shown in Table 4-51. The TOSCO II pro-
cess recovers substantially 100% of the recoverable hydrocarbon
in oil shale as determined by Fischer assay.
:Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b. Volume I,
Prepared for Area Oil Shale Supervisor. February 1976. pp. IV-42
to IV-44.
Ibid.
-149-
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TABLE 4-50. SUMMARY OF PROPERTIES OF CRUDE SHALE OIL
PRODUCED BY TOSCO II PROCESS
Gravity 21.2"API
Specific Gravity (60°F/60°F) 0.927
Pour Point 80'F
27°C
Viscosity 22 centistokes
106 SUS at 100°F
Elemental Composition (by weight)
Carbon 85.1%
Hydrogen 11.6%
Nitrogen 1.9%
Oxygen 0.8%
Sulfur 0.9%
C/H Ratio 7.34
Oil Recovery (% of Fischer) 100
ASTM Distillation
Initial Boiling Point,°F 100
10% over 200
20% over 275
30% over 500
40% over 620
60% over 775
70% over 850
80% over 920
Source: Hendrickson, T.A. "Oil Shale Processing Methods."
Quarterly of the Colorado School of Mines. No. 69,
April 1974, pp. 45-69.
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Pre-
pared for U.S.Environmental Protection Agency. Contract
No. 68-02-1881. Denver Research Institute and TRW Engin-
eering Division. June 1976. p. 153.
-150-
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TABLE 4-51. PROPERTIES OF CRUDE SHALE OIL PRODUCED BY
TOSCO II PROCESS
Wt %
Component Vol. % API S N
C5-400
400-950
950 +
17
60
23
51
20
6.5
0.7
0.8
0.7
0.4
2.0
2.9
Total 100 21 0.7 1.9
Note: Properties shown in total row are those for composite crude
shale oil.
Source: Whitcombe, J. S. and R. G. Vawter "The TOSCO II Oil Shale
Process." In: Science and Technology of Oil Shale.
T. F. Yen (ed.) (Ann Arbor, Michigan:Ann Arbor Science
Publishers, Inc., 1976) p. 51.
An advantage of indirect heating rather than direct gas com-
bustion is that the fuel gas is not diluted by combustion products
and consequently has a higher heating value. Approximately 900 scf
of gas per barrel of product oil are produced from the TOSCO II
retort. The gas has an approximate heating value of 900 Btu/scf.
Gas produced in the TOSCO II retorting process has a composition
comparable to that shown in Table 4-52.*
4.6.1.1b Institute of Gas Technology Hydrogasification Process
The Institute of Gas Technology (IGT) began work on their
current process in 1972 with laboratory and bench-scale work.
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, TX.: Radian Corporation, September 1977. p. 40.
-151-
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TABLE 4-52. TOSCO II SEMIWORKS PLANT COMPOSITION
OF Ci, AND LIGHTER GAS
Component
H2
CO
H2S
C02
ClU
CaHi,
C2H6
C3H6
GS H8
(Vs
Total
Weight Percent
1.50
3.15
5.16
33.08
11.93
8.67
8.43
11.08
5.45
11.19
100.00
Source: Whitcombe, J. A. and R. G. Vawter. "The TOSCO-II Oil
Shale Process". In: Science and Technology of Oil
Shale. T. F. Yen (ed.J"! (Ann Arbor, Michigan: Ann
Arbor Science Publishers, Inc. 1976) p.52
Work now includes laboratory and large-scale work in a 1 "ton/hour
shale feed process development. Earlier laboratory and bench-scale
work was performed from 1959 to 1964 on a predecessor process.1
A flow diagram of the IGT process is shown in Figure 4-17.
The key feature of the IGT retort is a moderate-pressure hydrogen
atmosphere. Existing screw feed-discharge systems can feed shale
^chora, F. C., P. B. Tarman and H. L. Feldkirchner. "State-
of-the-Art - Above Ground Shale Processing", Hydrocarbon Processing.
56 (2): 113-119, February 1977.
-152-
-------
HTMOUN KtCTCU
Figure 4-17. Flow Diagram of Institute of Gas Technology
Oil Shale Process.
Source: Jones, D. C., et al. Monitoring Environmental Impacts
of the Coal and Oil Shale Industries:Research and
Development Needs.Austin, TX.:Radian Corporation.
Prepared for Environmental Monitoring and Support
Laboratory, U.S. Environmental Protection Agency.
February 1977.
-153-
-------
particles as large as one-half inch. The vertical retort is
internally divided into three zones. Shale passing downward is
prehydrogenated and preheated in the top zone, hydrotreated in
the middle zone, and cooled in the bottom zone. One hydrogen
stream picks up some heat from the processed shale and, after
additional heating, is used to preheat incoming raw shale. A
second hydrogen stream is internally heated and passes through
the middle retorting zone to hydroretort the kerogen. Varying
the reaction temperature varies the ratio of liquid to gaseous
products. If the temperature is maintained below 1200°F, the
principal product will be oil with a boiling point below 730°F.
Properties of the oil product obtained at 1400°F are shown in
Table 4-53. Properties of the processed shale residue are shown
in Table 4-54.1>2
4.6.1.1c Paraho Oil Shale Process
Development Engineering, Inc. (DEI) developed the Paraho
process, and served as the operating company of the Paraho Devel-
opment Corporation. A Paraho Oil Shale Project was launched in
1973 with funds provided by 17 participating companies. DEI con-
continued as the operating company. 3
1Jones, D. C., et al. Monitoring Environmental Impacts of
the Coal and Oil Shale Industries;Research and Development
Needs,Prepared for Environmental Monitoring and Support Labora-
tory, U.S. Environmental Protection Agency. Austin, TX.: Radian
Corp., February 1977. p. 75.
2Schora, F. C., et al. "Process Shale to SNG," Hydrocarbon
Processing. April 1977. pp. 107-110.
3Nevens, T. D. and C. H. Prien. "Paraho Oil Shale Process",
Technological Overview Reports for Eight Shale Oil Recovery Pro-
cesses. Prepared for U.S. Environmental Protection Agency.Con-
tract No. 68-02-1881. Denver Research Institute and TRW Environ-
mental Engineering Division. December 1976. pp. 17-36.
-154-
-------
TABLE 4-53. PROPERTIES OF SHALE OIL OBTAINED FROM
HYDRORETORTING IN IGT'S BENCH-SCALE UNIT
Reactor pressure, psig 500
Product oil properties
Ultimate analysis, wt70 (dry and
solids-free basis)
Carbon 84.44
Hydrogen 11.64
Sulfur 0.50
Nitrogen 1.74
Ash 0.00
C/H weight ratio 7.25
Density, °API 24.0
Distillation, °F
Initial boiling point 234
End point 761
Recovery, 7. 89
Source: Schora, F. C., et al. "Process Shale to SNG," Hydro-
carbon Processing. April 1977. pp 107-110.
TABLE 4-54. PROPERTIES OF PROCESSED SHALE RESIDUE OBTAINED
FROM HYDRORETORTING IN IGT'S BENCH-SCALE UNIT
Ultimate Analysis (dry) , wt?0
Organic carbon 1.18
Mineral carbon 2.10
Hydrogen 0.13
Nitrogen 0.50
Oxygen 5.19
Sulfur 0.25
Ash 91.10
Source: Schora, F. C. et al. "Process Shale to SNG," Hydro-
carbon Processing. April 1977. pp 107-110.
-155-
-------
The Paraho retort is a variant of a gas combustion retort
developed by the U.S. Bureau of Mines from 1945-1955. Six
petroleum companies operated a large-scale development of the
U.S.B.M. gas combustion retort in 1964-1967 through a lease
agreement with the Colorado School of Mines. The consortium of
petroleum companies concluded that commercial scale-up of the
U.S.B.M. retort was unjustified. Specific difficulties were
encountered with small shale sizes, high rates of gas and shale
throughput, and bridging due to rich shales.1 The Paraho and
Petrosix2 retorts were conceived to overcome problems encountered
during testing of the U.S.B.M. retort.
Two newly-designed Paraho retorts have been operated on an
intermittent basis from mid-1974 to the present. These include a
small pilot plant for rapid investigation of operating parameters,
and a 450 TPD semi-works unit for large-scale testing under pro-
duction conditions.3 An Environmental Impact Statement is now
being completed for the construction of a full-scale 7,000 TPD
modular Paraho retort and supporting facilities.
C. H. "USBM Gas Combustion Process". Technological
Overview Reports for Eight Shale Oil Recovery Processes. Prepared
for U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. December 1976. pp. 73-85.
2Schora, F. C., P. B. Tarman, and H. L. Feldkirchner.
"State of the Art - Above Ground Shale Processing," Hydrocarbon
Processing 56 (2): 113-119, February 1977.
3Nevens, T. D. and C. H. Prien. "Paraho Oil Shale Process",
Technological Overview Reports for -Eight Shale Oil Recovery Pro-
cesses .Prepared for U.S.Environmental Protection Agency.Con-
tract No. 68-02-1881. Denver Research Institute and TRW Environ-
mental Engineering Division. December 1976. pp. 17-36.
-156-
-------
The Paraho retort is capable of using either internal or
external heating to achieve the required retorting temperature.
In the "direct mode" (i.e., using internal gas combustion) the
carabonaceous residue on the retorted shale is burned in the
combustion zone of the retort to provide the principal heat for
the process. Low-Btu gases and air are recycled to both the com-
bustion zone and the residue and gas preheating zone (as shown
in Figure 4-18).1
In the indirect mode (i.e., using external heat generation),
heat for retorting is supplied by hot retort gases heated in an
outside furnace (a shown in Figure 4-19). Off-gas produced
during retorting has a high heating value (about 900 Btu/scf).2
In either mode of operation, raw shale sized one-quarter to
three inches is fed into the top of the retort by a rotary pant-
leg distributor, and passes downward by gravity successively
through a mist formation and preheating zone, a retorting zone,
either a combustion zone (direct mode) or heating zone (indirect
mode), and finally, a residue cooling and gas preheating zone.
The shale is discharged through a hydraulically-operated grate
which controls the downward velocity and maintains even flow across
the retort. This grate, the rotary feed mechanism, and the multi-
levels of heat input are among the unique contributions of Paraho
technology toward improving the retorting principle in vertical-
kiln type retorts.3
Sevens, T. D. and C. H. Prien. "Paraho Oil Shale Process";
Technological Overview Reports for Eight Shale Oil Recovery Pro-
cesses .Prepared for U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. pp. 17-36.
2Ibid.
-157-
-------
RAW
SHALE
OIL MIST
SEPARATORS
MIST
FORMATION
AND
PREHEATING
RETORTING
ZONE
COMBUSTION
ZONE
RESIDUE
COOLING
AND
GAS
PREHEATING
OIL
PRODUCT
GAS
GH
ELECTROSTATIC
PRECIPITATOR
RECYCLE GAS
BLOWER
AIR BLOWER
GATE
SPEED
CONTROLLER
RESIDUE
Figure 4-18. Paraho Direct Mode Flow Diagram.
Source: Nevens, T. D. and C. H. Prien. "Paraho Oil Shale
Process", Technological Overview Reports for Eight
Shale Oil Recovery Processed!Prepared for U.S.
Environmental Protection Agency. Contract No. 68-
02-1881. Denver Research Institute and TRW Environ-
mental Engineering Division. December 1976. pp. 17-36,
-158,-
-------
RAW
SHALE
OIL MIST
SEPARATORS
MIST
FORMATION
AND
PREHEATING
RETORTING
ZONE
HEATING
RESIDUE
COOLING
AND
GAS
PREHEATING
1
OIL
STACK
-GAS
-H HEATER
CjH
ELECTROSTATIC-
PRECIPITATOR
RECYCLE GAS
BLOWER
COOLER
PRODUCT GAS
AIR BLOWER
RESIDUE
Figure 4-19. Paraho Indirect Mode Flow Diagram.
Source: Nevens, T. D. and C. H. Prien. "Paraho Oil Shale
Process", Technological Overview Reports for Eight
Shale Oil Recovery Processes'! Prepared for U.S.
Environmental Protection Agency. Contract No.
68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976.
pp. 17-36.
-159-
-------
The retorted shale, containing about 2% carbon (direct mode)
to 4.5% carbon (indirect mode), is discharged from the retort at
about 300°F. The processed shale is then moisturized and sent
to a disposal area.1
The shale vapors produced in the retorting zone are cooled
to a stable mist by the incoming raw shale (which is thereby
preheated), and leave the retort at approximately 140°F. This
mist is sent to a roughing cyclone, a condenser, and finally a
wet electrostatic precipitator for oil separation. The resulting
shale oil is transported to storage.2
In the direct mode, the remaining cooled, oil-free retort
gases (approximately 100 Btu/scf) are, in part, used to cool the
retorted shale on the grate in the lower "residue cooling and gas
preheating zone." Some of the remaining gases are recycled to
several levels to dilute the air entering the retort, for com-
bustion. The remaining portion of the retort gases are cleaned
of H2S and NH3 and used as plant fuel or for power generation in
low-Btu turbines. From 28 gal/ton shale, 6200 scf of product gases
are produced per ton of shale.3
In the indirect heating mode the mist-laden off-gases leave
the retort at 280°F. After oil separation, the oil-free recycle
gases have a high heating value (about 900 Btu/scf). Part of
these gases are reheated in an outside heater and distributed
lNevens, T. D. and C. H. Prien. "Paraho Oil Shale Process"
Technological Overview Reports for Eight Shale Oil Recovery Pro-
cessesPrepared for U.S. Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. pp. 17-36.
2Ibid.
-160-
-------
to the retort at several levels. These hot gases supply the
necessary heat for retorting the shale. No residual carbon on
the retorted shale or gas is burned in the retort. There is,
therefore, no dilution of off-gases with combustion products and
resulting reduction in retort-gas heating value.1
The fuel for the external recycle-gas heater may be a side-
stream of the recycle gas itself, or an outside fuel. If the
recycle gas is used as fuel, there is a net production of 500
scf/ton of high-Btu gas from 28 gal/ton shale.2
Selected properties of the Paraho shale oils from both
direct and indirect modes of operation are shown in Table 4-55.
Oil produced via the direct mode has essentially the character-
istics of conventional gas combustion-type raw shale oil. Oil
produced via the indirect mode has a somewhat lower pour point
than that reported for other indirectly-heated retorts. Further
lowering of the pour point would require coking.3
The composition of the retort gases from direct and indirect
modes of operation are shown in Table 4-56.
Sevens, T. D., and C. H. Prien. "Paraho Oil Shale Process",
Technological Overview Reports for Eight Shale Oil Recovery Pro-
cesses.Prepared tor U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. pp. 17-36.
2Ibid.
3Ibid.
-161-
-------
TABLE 4-55. PROPERTIES OF PARAHO SHALE OILS
Gravity, °A.P.I.
Viscosity, SUS @ 130°F
SUS @ 210°F
Pour Point, °F
Ramsbottom carbon, wt %
Water Content, vol %
Solids, B.S.-, wt %
Heating
Direct
21.4
90
46
85
1.7
1.5
.5
Mode
Indirect
21.7
68
42
65
1.3
1.4
.6
Note: Data from semi-works retorting of 28 GPT shale, at
977» Fischer assay yield.
Source: Jones, John B., "The Paraho Oil Shale Retort," 81st Nat.
Mtg., A.I.Ch.E., Kansas City, Mo., April 11-14, 1976.
4.6.1.Id Union Oil Shale Retorting Process
The development of Union's oil shale technology was initiated
in the early 1940's. Several versions of a vertical kiln retort-
ing process with upward flow of shale and countercurrent downward
flow of gases and liquids have been developed. The first concept,
the Retort A process, was demonstrated at rates of 700-1000 TPD,
with a peak rate of 1200 TPD. Although the demonstration of the
Retort A process was successful, the Union Oil work was suspended
due to a plentiful supply of low-cost Middle East oil and natural
gas. An improved version of the Union Oil process, the Retort B
prcess, has been developed through the pilot plant stage. Union
Oil has proposed the construction and demonstration of the Retort
B process on a commercial plant processing 10,000 TPD shale.1
'Shih, C. C. "Union Oil Shale Retorting Process", Techno-
logical Overview Reports for Eight Shale Oil Recovery Processes.
Prepared tor U.S. Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976. pp. 5-15.
-162-
-------
TABLE 4-56. COMPOSITION OF PARAHO RETORT GASES
Direct Mode
Component
H2
N2
02
CO
CO 2
OU
C2Hi»
C2H6
C3
C*
H2S
NH3
High Heating Value,
(Btu/scf)
High Heating Value,
(kcal/m3)
Retort Gas Yield,
(scf/ton)
Retort Gas Yield,
(m3/103kg)
Note: Data from semi -works
at 97% Fischer assay
Composition by
2.57,
65 . 770
0 %
2.5%
24.2%
2.2%
0.7%
0.6%
0.7%
0.4%
2660ppm
2490ppm
102
908
6200
193
retorting of 28 GPT
yield.
Source: Jones, John B. , "The Paraho Oil Shale
Nat. Mtg., A.I.Ch.E., Kansas City, Mo.
1976.
Indirect Mode
Volume
24.8%
0.7%
0 %
2.6%
15 . 1%
28.7%
9.0%
6.9%
5.3%
2.0%
3.5%
1.2%
885
7560
500
15.6
oil shale,
Retort", 81st
, April 11-14,
-163-
-------
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-165-
-------
An auxiliary process, SGR (Steam Gas Recirculation), has
also been examined by Union. Processed shale from Retort B
contains a nominal 4 wt. 70 carbonaceous deposit. In SGR, the
hot processed shale is sent to a separate vessel where the car-
bonaceous deposti is removed by reacting with steam and air to
produce low-Btu gas or with steam and oxygen to produce high-Btu
gas. Marginal economics has stopped further work on this process
The Union Retort B is illustrated in Figure 4-20. A flow
diagram of the Union Retort B process is found in Figure 4-21.
A detailed description of the Retort B process, as presented by
Hopkins (et al)2, follows.
Oil shale (sized from one-eighth to two inches) from the
feed bin flows through two...chutes to the solids pump.
Shale oil product acts as a hydraulic seal in the feed
chutes to maintain the retort pressure. The solids
(rock) pump is mounted on a movable carriage...and
consists of two piston and cylinder assemblies which
alternately feed shale to the retort.
The shale is retorted as it rises through the retort
cone. (Heat is supplied by a countercurrent flow of
hot recycle gas.)
The space above the cone is enclosed by the dome. The
(processed) shale slides down chutes and through the
dome wall at the (processed) shale outlets. Hot recycle
gas is introduced into the space between the (processed)
shale pile and the dome. It flows downward into the
rising shale to provide the heat required for retort-
ing.... The bulk of the liquid product trickles down
through the cool, incoming shale and the balance, in
the form of a mist, is carried from the retort by the
(cooled) gases. The gas and liquid are separated from
the shale in the lower slotted wall section of the
retort cone.
Hopkins, J. M., H. C. Huffman, A. Kelley, and J. R. Pownall
"Development of Union Oil Company Upflow Retorting Technology",
Presented at 81st A.I.Ch.E. National Meeting, April 11-14, 1976,
Kansas City, Mo.
zloid.
-166-
-------
The shale particles which fall through the slots into
the disengaging section are recycled to the feed chutes.
The retorted shale is conveyed in pipes to one of the
two retorted shale cooling vessels. As shown in Figure
(4-21), a level of shale is maintained above the level
of water in the quench vessel. A drag chain conveyor
removes the cooled shale from under the water level.
A water level is maintained in the conveyor to seal
the retort from the atmosphere. Generated steam is
condensed and returned to the cooling vessel. The
cooled and (moistened) processed shale is sent to
disposal.
Gases from the disengaging section are scrubbed and
cooled in a venturi scrubber. Agglomerated mist plus
light ends and water produced by cooling are sent to
an oil-water separator. The oil is recycled to the
retort through the oil shale feed line and the water
is sent to the water seal after stripping to remove
ammonia. The scrubbed gas is divided into a make
stream and a recycle stream. The recycle stream is
compressed and heated prior to injection into the top
of the retort.
The make gas is processed by compression and scrubbing
to remove heavy ends and hydrogen sulfide. Oil is
used to scrub out the heavy hydrocarbons and Stretford
solution is used to remove hydrogen sulfide. The
sweetened make gas is used as plant fuel.
The liquid product from the retort is treated sequentially
to remove solids, arsenic and light ends. Solids removal
is accomplished by two stages "of water washing. The
shale fines are collected in the water phase which is
recycled to the water seal.
The liquid product contains 50 ppm of chemically
combined arsenic. (The arsenic concentration is)
reduced to about 2 ppm in a proprietary Union Oil
process. (The process uses) an absorbent which picks
up arsenic to about 80 percent of its weight. About
50 tons of spent absorbent will be placed in the
retorted shale disposal area per year. The dearsenated
shale oil is sent to a stripping column for stabili-
zation and sweetening prior to upgrading.
-167-
-------
Make gas production from the retort will exceed plant
fuel requirements. To avoid flaring the excess, the
system will be balanced by absorbing the heavy ends of
the make gas into the oil product. This will be
accomplished by varying the operating conditions of
the stripping column and a related debutanizer.
Properties of shale oil produced from the Retort B process
are shown in Table 4-57. Union Oil indicates that a high-
quality crude shale oil is obtained in the Retort B process
because oil vapor evolved in the retort is quickly forced
downward by the gas toward the cooler shale, thus quenching the
polymerization reactions which form difficult-to-refine heavy
oil. In addition, the use of an indirectly heated recycle gas
in the Retort B process appears to cause a lower oxygen content
in crude shale oil. This is desirable because the presence of
oxygen compounds contributes to gum formation and enhances
corrosion rates in certain situations.1
Upgraded product gas from the Union B retort has a heating
value of about 800 Btu/scf.2
4.6.1.1e Lurgi-Ruhrgas Process for Oil Shale Retorting
Lurgi has been developing oil shale processing technology
for the past 40 years. Two kilns were designed and installed
Hopkins, J. M., H. C. Huffman, A. Kelley, and J. R. Pownall
"Development of Union Oil Company Upflow Retorting Technology",
Presented at 81st AIChE National Meeting, April 11-14, 1976,
Kansas City, Mo.
2Shih, C. C. "Union Oil Shale Retorting Process", Techno-
logical Overview Reports for Eight Shale Oil Recovery Processes.
Prepared for U.S.Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976. pp. 5-15.
168-
-------
TABLE 4-57. PROPERTIES OF UNION RETORT B CRUDE OIL
Gravity (60 F/60°F) 0.918
22.7"API
Pour Point 60°F
Viscosity at 100°F 20 centistokes
98.2 SUS
Elemental Composition (by weight)
Carbon 84.8%
Hydrogen 11.61%
Nitrogen 1.74%
Oxygen 0.90%
Sulfur 0.81%
C/H Ratio 7.30
Fischer Assay of Feed (gpt) 24.2
Oil Recovery (% of Fischer Assay) 91.0
ASTM Distillation
Initial Boiling Point 139°F
10% Over 400°F
50% Over 731°F
90% Over 960°F
End Point 1077°F
Source: Hendrickson, T. A., Comp. Synthetic Fuels Data Handbook
Denver, Colorado: Cameron Engineers,Inc.1975
-169-
-------
for an Estonian Shale Oil Company in the late 1930's. Several
other oil shale retorting processes were also developed by Lurgi
to the commercial stage.1
The Lurgi-Ruhrgas Process was developed in the 1950's for
the low-temperature carbonization of subbituminous coal. It has
also been used for olefin production using sand as the heat
carrier. The process was demonstrated commercially in two units
built in Yugoslavia in 1963. Tests on oil shale have been per-
formed in equipment processing 16 TPD. American Lurgi has pro-
posed scale-up to 8000 TPD commercial-size retorts. Eight such
plants can provide capacity for the production of 50,000 BPD
shale oil.2> 3
The Lurgi-Ruhrgas process is illustrated in Figure 4-22.
Oil shale crushed to sizes less than 1/3 in. is fed to the
screw mixer. The raw shale is heated to about 9908F by mixing
with six times as much hot processed shale from the separating
bin. Retorting occurs in the screw mixer. The shale mixture
is then dropped from the screw mixer into a surge hopper where
residual oil components are distilled off. "*' 5
C. C. "The Lurgi-Ruhrgas Process for Oil Shale
Retorting", Technological Overview Reports for Eight Shale Oil
Recovery Processes. Prepared for U.S. Environmental Protection
Agency. Contract No. 68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division. December 1976. pp. 55-61
2Schora, F. C. , P. B. Tarman and H. L. Feldkirchner.
"State-of-the-Art - Above Ground Shale Processing", Hydrocarbon
Processing. 56 (2): 113-119, February 1977.
3Mamell, P. "Lurgi/ Ruhrgas Shale Oil Process", Hydrocarbon
Processing 55 (9): 269-271, September 1976.
Shih, C. C., op.cit.
-170-
-------
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-171-
-------
The shale mixture is passed through to the lower section of
the lift pipe where combustion air at 750°F is introduced,
raising the mixture pneumatically to the collecting bin, while
simultaneously burning the carbon contained on the processed
shale. Combustion gas and heated processed shale at about 1200°F
are separated in the collecting bin. Heated shale is then returned
to the screw mixer.l'2
The volatile gas product stream from retorting is then
passed through two series-connected cyclones. Dust separated
in these cyclones is returned to the recycle system. The first
gas scrubber-cooler operates at a high temperature to remove
residual dust from the gas stream by washing with circulating
condensed heavy oil. In the next scrubber-cooler, major con-
densation of the oil occurs at a temperature above the dew
point of water to recover a water-free heavy oil. Final cooling
uses circulating condensate in the last scrubber-cooler, after
the condensate has been cooled in air and water coolers. The
condensate is then separated into a middle oil and gas liquor.
Finally, the gas is treated with light oil in a scrubber for
the recovery of naphtha. By compressing the gas and cooling
it to lower temperatures, LPG can also be recovered.3'4
C. C. "The Lurgi-Ruhrgas Process for Oil Shale
Retorting", Technological Overview Reports for Eight Shale Oil
Recovery Processes. Prepared for U.S. Environmental Protection
Agency. Contract No. 68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division. December 1976. pp. 55-61
2Marnell, P. "Lurgi/Ruhrgas Shale Oil Process", Hydrocarbon
Processing 55 (9): 269-271, September 1976.
3 Ibid.
"Shih, C. C., op.cit.
-172-
-------
Combustion gases evolved in the lift pipe are cleaned in
a cyclone after leaving the collecting bin. Part of the entrained
dust can be returned to the collecting bin (if necessary). The
gas stream is then routed through a heat exchanger (for the
preheating of combustion air), a waste heat boiler, a feedwater
preheater, another cyclone, a humidifier and an electrostatic
precipitator before discharge to the atmosphere. In the humidi-
fier, the flue gas is cooled from 600°F to 300°F by water injec-
tion. A portion of the shale dust entrained in the gas is
separated and discharged onto a chain conveyor. Residual dust
is removed from the flue gas in the electrostatic precipitator
and discharged onto another chain conveyor. The two chain
conveyors carry the fine dust from the cyclone ana the heavy oil
dust from heavy oil dust removal. Moistening water and gas
liquor are added to the dust in a mixer. The final processed
shale residue has a moisture content of 10 to 1270 water and a
temperature of 150°F.1>2
Final products of the Lurgi-Ruhrgas process include a dust-
free heavy oil, a middle oil, a gas naphtha, and a naphtha-free
distillation gas. Properties of the products are summarized in
Tables 4-58 and 4-59. Quantities of the products are shown in
Tables 4-60.
4.6.1.If Superior Oil Shale Process
The Superior Oil Shale process is unique among current U.S.
shale processing methods in two respects, namely, its recovery
of .-9 line minerals and its use of a circular grate retort.
1 Marnell, P. "Lurgi/Ruhrgas Shale Oil Process", Hydrocarbon
Processing 55 (9): 269-271, September 1976.
2 Shih, C. C. "The Lurgi-Ruhrgas Process for Oil Shale
Retorting", Technological Overview Reports for Eight Shale Oil
Recovery Processes.Prepared for U.S.Environmental Protection
Agency. Contract No. 68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division. December 1976. pp. 55-61
-173-
-------
TABLE 4-58.
CHARACTERISTICS OF OIL PRODUCTS OF THE
LURGI-RUHRGAS RETORTING PROCESS
Heavy Oil
(dust free)
Middle Oil
Naphtha
Gravity
Viscosity, SUS
0.96 (122°F)
0.94 (176°F)
530.0 (122°F)
0.82 (68°F)
33.0 (68°F)
0.70 (68°F)
120.0 (176°F)
Flash point, °F
Settling point, °F
Conradson, wt %
Ultimate analysis,
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
309.0
75.0
8.1
wt %
85.6
10.7
1.0
1.5
1.2
<70
<-40
0.43
85.3
12.5
0.7
0.5
0.8
--
--
--
84.2
13.2
2,
Source: Rurak, J. R., et al: U.S. Bureau of Mines Report of
Investigation Number 7540, 1971.
-174-
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TABLE 4-59. PROPERTIES OF DISTILLATION GAS FROM
LURGI-RUHRGAS RETORTING PROCESS
Composition (by volume)
CO 2 28.87.
CO 3.17.
H2 21.37.
N2 8.970
Ci 13.77.
C2 13.87.
C3 10.37.
Other
H2S 2.28g/Nra3(0.94gr/scf)
S02 0.07g/Nm3(0.03gr/scf)
Net calorific value 7150 Kcal/Nm3(760 Btu/scf)
Source: Schmalfeld, P. "The Use of the Lurgi-Ruhrgas Process
for the Distillation of Oil Shale." Quarterly of the
Colorado School of Mines. 70(3): 129-145, July 1975.
-175-
-------
TABLE 4-60. PRODUCTS OF THE LURGI-RUHRGAS
RETORTING PROCESS
Basis: Shale Oil Production - 50,000 BPD
Oil Shale Quality - 30 gal/ton
Oil Yield - 104.5% Fischer Assay
Feed
Shale Feed 2931 tons/hr
Products
Heavy oil (dedusted) 449 barrels/hr
Middle oil 1405 barrels/hr
Naphtha 259 barrels/hr
Gas (640 Btu/ft3) 2.12 MM ft3 /hr
Waste Products
Processed Shale 2428 tons/hr
Gas Liquor 51 tons/hr
Note: Gas liquor can be treated to remove phenols, ammonia,
and other impurities and used in the retort section
to moisten the processed shale.
Source: Ruark, J. R. , et al: U.S. Bureau of Mines Report" of
Investigation Number 7540, 1971.
-176-
-------
Superior Oil began development of its process in 1967 to exploit
its privately owned shale deposits which contain, in addition to
oil shale, nahcolite (NaHC03), and dawsonite (NaAl(OH)2C03).
A pilot plant has been operated at about 100 TPD. Superior plans
to build three 20,000 TPD demonstration modules with private
funding.1>2'3
The basis of the separation of nahcolite from shale is a
difference in friability. Crushing and screening yields nahcolite
of about 80% purity. With additional processing, including
photosorting of the residue from crushing and screening, purity
can be increased to more than 90%. Nahcolite remaining in the
shale continues through the retorting process. "*
The dawsonitic shale from nahcolite recovery is fed to a
traveling circular grate retort (see Figures 4-23 and 4-24).
The doughnut-shaped retort has five separately-divided sections
through which the shale travels in sequence. These are a
loading zone, retorting zone, residual carbon recovery zone,
cooling zone, and unloading zone. In the retorting zone, shale
is pyrolyzed by hot gases to produce liquid and gaseous hydro-
carbons. These products are then drawn off and piped to further
processing. Any sour water produced in this stage is collected
and disposed with processed shale.5
'Schora, F. C. , P. B. Tarman and H. L. Feldkirchner .
"State-of-the-Art - Above Ground Shale Processing", Hydrocarbon
Processing 56 (2): 113-119, February 1977.
2Prien, C. H. "Superior Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes. Prepared
for U.S. Environmental Protection Agency7. Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering Divi-
sion. December 1976. pp. 63-74.
3 "Prognosis Good for New Shale Oil Process", Chemical and
Engineering News. January 10, 1977. pp. 27-28.
"Ibid.
-177-
-------
SHALE BED
OPERATING FUXHt
, HOOO
WATER SEALS
SUPPORTING
IDLER WHEEL
Figure 4-23, Cross Section of Circular Grate Retort.
(Courtesy Arthur G. McKee & Co.)
Source: Prien, C. H. "Superior Oil Shale Process".
Technological Overview Reports for Eight Oil
Shale Recovery Processes.Prepared for U.S.
Environmental Protection Agency. Contract
No. 68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division, December
1976. p. 69.
-178-
-------
Figure 4-24.
Plan VieW of Circular Grate Retort Showing
Movement of Charge through Various Zones.
Source: Prien, C. H. "Superior Oil Shale Process".
Technological Overview Reports for Eight Oil
Shale Recovery Processes.Prepared for U.S.
Environmental Protection Agency. Contract No.
68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division, December
1976. p. 70.
-179-
-------
The retorted shale travels from the retorting zone to the
residual carbon recovery (or combustion) zone. There, the shale
is contacted with steam and air to form producer gas by reaction
with the carbon residue. The gas is used locally for plant
fuel.1'2
The retorted shale then travels to the cooling zone. After
cooling, the shale is discharged from the retort and sent to a
leaching plant for the recovery of alumina and soda ash.3
During retorting, dawsonite in the shale is converted to
alumina and soda ash. Residual nahcolite in the shale is
calcined during retorting to soda ash. Cooled retorted shale
containing alumina and soda ash is then crushed and fed to
countercurrent decanters where it is dissolved in an alkaline
leach solution. Both dawsonite and nahcolite dissolve readily
in alkaline solutions to yield solutions of sodium aluminate
and sodium carbonate. "*
Aluminum hydroxide is crystallized from the aluminate liquor,
filtered, and calcined into cell-grade alumina. Soda ash is
recovered by triple-effect evaporation and centrifugation. Any
«
remaining liquor is recycled.5
C. H. "Superior Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes. Pre-
pared for U.S.Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976. pp. 63-74.
2"Prognosis Good for New Shale Oil Process", Chemical and
Engineering News. January 10, 1977. pp. 27-28.
3Prien, C. H., op.cit.
^"Prognosis Good for New Shale Oil Process", op.cit.
5Ibid.
-180-
-------
Products from a 25,000 TPD plant are summarized in Table
4-61. Oil is expected to have a gravity of 26"API and a pour
point of 70°F. The oil typically contains 2% nitrogen and 0.8%
sulfur.l
TABLE 4-61. PRODUCTS FROM THE SUPERIOR MULTIMINERAL
RECOVERY PROCESS
Basis: 25,000 TPD of mined shale
Products
Shale oil 10,000 - 15,000 BPD
Nahcolite 4,500 TPD
Cell-Grade Alumina 500 - 800 TPD
Soda Ash 800 - 1300 TPD
Source: Prien, C. H. "Superior Oil Shale Process",
Technological Overview Reports for Eight Shale
Oil Recovery ProcessiT!Prepared for U.S.
Environmental Protection Agency. Contract No.
68-02-1881. Denver Research Institute and
TRW Environmental Engineering Division. December
1976. pp. 63-74.
4.6.1.1g Shale Oil Upgrading
Crude shale oils have relatively higher nitrogen contents,
viscosities, and pour points than do conventional crude oils.
Oxygen and sulfur contents of crude shale oils are comparable to
C. H. "Superior Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes.Pre-
pared for U.S. Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976. pp. 63-74.
-181-
-------
those of conventional crudes. Most crude shale oils also con-
tain a large fraction of unsaturated and aromatic compounds, and
tend to form gums during storage. Compared to most conventional
crude oils, shale oils yield less light ends upon distillation.1
Crude shale oils also contain ash in the form of raw and
retorted shale fines. Most trace elements in shale oil are
associated with ash, and concentrate in higher boiling point
fractions.2'3
Because of the above properties, crude shale oil is not
readily marketable. Upgrading facilities are required to
produce an oil product having reduced sulfur and nitrogen con-
tents. In addition, upgrading is required to reduce the pour
point and viscosity of the oil to make it easier to transport
by pipeline. **
Current oil shale developments do not plan to process crude
shale oil into a full range of refined products as is the case
Crawford, K. W. , et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development^Prepared for
U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division, June 1976.
2Ibid.
3Arsenic is found in essentially all distillate cuts.
14Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-38
-182-
-------
with petroleum crude in modern petroleum refineries. Planned
upgrading ranges from simple oil/water separation to the pro-
duction of finished fuels or premium refinery feedstocks. The
choice of upgrading schemes depends primarily on economic and
market conditions,1'2 and on the quality of shale oil produced in
the process. Table 4-62 summarizes pre-refining or upgrading
operations planned by several oil shale developers.
Two principal options are available for producing marketable
shale oil. One is to minimize upgrading and market the raw
shale oil as a "synthetic" heavy crude oil or No. 6 fuel oil. The
second option is to upgrade or pre-refine shale oil on-site.
This would produce an oil suitable for marketing as a No. 2 fuel
oil or suitable for direct conversion to finished products (such
as gasoline, turbine fuel, home heating oil and petrochemical
feedstocks).3
Each option has its own slate of by-products. Minimal re-
fining could yield LPG, coke, and small amounts of sulfur as
by-products. More extensive refining could yield LPG, coke,
larger quantities of sulfur, and ammonia."
The remainder of this sec.tion describes the production of
finished fuels to premium feedstocks. Such an upgrading scheme
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development"! Prepared for
U.S. Environmental Protection Agency, Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division, June 1976.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-38
3Ibid.
"Ibid.
-183-
-------
TABLE 4-62.
SUMMARY OF "ON-SITE" SHALE OIL UPGRADING BY SEVERAL
OIL SHALE DEVELOPERS
Developer
Colony Development
Operation - Parachute
Creek
Occidental Oil
Shale and Ashland
Oil
Union Oil
Superior
Rio Blanco
Paraho
Lurgi-Ruhrgas
Source: Crawiord, ;<-
Retort Steps of Upgrading or
Technology Pre-refining
TOSCO II Distillation followed by delayed
cooking of residue
Dearsenation of naphtha and gas
oil factions
Catalytic hydrogenation of naphtha
and gas oil fractions
Hydrogen production by catalytic
reforming of naphtha followed by
steam, reforming shift conversion,
CO: removal
Occidental modified Ho upgrading indicated, company
in-situ indicates oil can be transported
directly to refinery
Union Retort B Solids/fines removal via filtration
and water washing
Catalytic dearsenation
Stripping/stabilization
Superior Company indicates that blending,
with petroleum crudes will be
attempted.
RISE * No upgrading, pipeline quality
modified in situ oil produced by blending oil from
and surface retort surface retort with oil from in-situ
(e.g., TOSCO II) retort
Parano Delayed coking
Hyarogenat'lon ot naphtha and
gas oil fractions
Lurgi-Ruhrgas Oils fractionated in scrubbing
W., et ai. A Preliminarv Assessment or the Environmental Inoacts from
Products
Low sulfur fuel
oil
LPG
Coke
Sulfur
Crude shale oil
Sulfur from
gas treatment
Sulfur
Ammonia
Coke
Prerefined shale
oil
Shale
Crude shale oil
Sodium bicarbon-
ate
Alumina
Crude shale oil
Sulfur
Crude shale oil
Ammonia
Sulfur
Coke
Gas naphtha
Heavy oil
Middle oil
Oil Shale
Development. Prepared for U.S. Environmental Protection Agency. Contract No. o)S-02-L381.
Denver Research Institute and TRW Environmental Engineering Division, June 1976.
-184-
-------
is preferred by Colony Development Operation, and was selected
in the original development plan for oil shale tract C-b.1'2
As originally envisioned by the developers of oil shale
tract C-b, retorting and upgrading operations produce 45,000
barrels of low-sulfur oil, 4200 barrels of liquefied petroleum
gas (LPG), 180 tons of sulfur, and 800 tons of coke from a raw
shale feed of 66,000 tons per stream-day. Fuels produced by the
plant for internal consumption include treated high-Btu gas, a
C4 liquid (containing butanes, butenes, and some C3's), fuel oil,
and diesel fuel. Upgrading operations which produce this pro-
duct slate are described below, as reported in the most recent
document describing a TOSCO II retorting and upgrading complex.3
Process units in the upgrading section are 1) Gas Recovery and
Treating; 2) Hydrogen Production; 3) Gas-Oil Hydrogenation;
4) Naphtha Hydrogenation; 5) Ammonia Separation; 6) Sulfur Re-
covery; 7) Delayed Coker; and 8) Foul-water Stripping. A flow-
sheet of this upgrading sequence is shown in Figure 4-25. Each
of the upgrading units are discussed in turn.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976.
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorad^Draft Environmental Impact Statement.
3Ashland Oil, Inc. and Shell Oil Co., op.ait., pp. IV-38
to IV-59.
-185-
-------
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-51
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§
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-------
1) Gas Recovery and Treating
In the gas recovery and treating unit, gas and raw
naphtha produced in the oil recovery, coker, naphtha
hydrotreater and gas-oil hydrotreater units are
separated into fuel gas, liquified petroleum gas (LPG),
butanes and a stabilized naphtha. Hydrogen sulfide
is removed from fuel gas, LPG and butanes as required
for environmental and process considerations. Fuel
gas is used as plant fuel and hydrogen plant feed.
LPG is a blend of propane and propylene and can be
sold as a product. The butane stream is a mixture of
butane and butylene and can be used as plant fuel.
Stabilized naphtha is sent to the naphtha hydrotreater
for further processing. Process operations in this
unit include oil absorption, diethanolamine (DEA)
contact, and amine regeneration.
2) Hydrogen Production
Hydrogen is used in the hydrogenation units to
remove nitrogen and sulfur from the naphtha and
gas-oil streams. The required hydrogen is produced
from fuel gas and steam in a conventional steam reform-
ing process.
3) Gas Oil Hydrogenation
The gas-oil hydrogenation unit treats a mixture of
gas oil from the pyrolysis and delayed-coker units
with hydrogen in the presence of a catalyst to produce
a low-nitrogen, low-sulfur gas oil. The treated gas-
oil product is blended with treated naphtha product
from the naphtha hydrogenation unit to form low-sulfur
fuel oil, which can be pipelined from the complex. This
unit also produces diesel fuel which is used for
mobile equipment in the,mine and processed-shale
disposal areas.
4) Naphtha Hydrogenation
The naphtha hydrogenation unit treats a stabilized
naphtha blend from the gas recovery and treating unit
with hydrogen in the presence of a catalyst to produce
a low-sulfur, low-nitrogen naphtha. The treated
naphtha product is blended with treated gas-oil
product from the gas-oil hydrogenation unit to form
low-sulfur oil, which can be pipelined from the
complex. This unit is quite similar to the gas-oil
-187-
-------
hydrogenation unit; however, the lighter naphtha
requires less severe hydrogenation conditions than
needed for the gas oil.
5) Ammonia Separation
The ammonia separation unit processes sour water
from the naphtha and gas oil hydrotreaters. Liquid
anhydrous ammonia is produced as a marketable by-
product. Gaseous hydrogen sulfide is removed and
sent to the sulfur recovery unit and the. stripped
water is recycled to the hydrotreaters.
6) Sulfur Recovery
The sulfur recovery unit removes and recovers sul-
fur from the hydrogen sulfide-rich acid-gas streams
which emanate from the ammonia separation unit, the
foul-water stripper and the gas recovery and treating
unit. The function of this unit is to prevent the
direct release of sulfur compounds to the atmosphere
or the release of SQ2 by open flaring of acid gases.
The unit converts these sulfur compounds into marketable
liquid sulfur by-products.
Sulfur recovery involves a combination of two units.
A Glaus unit converts hydrogen sulfide to elemental
sulfur, which is recovered. A tail-gas unit oxidizes
unconverted hydrogen sulfide and other unrecovered
sulfur compounds from the Glaus unit to sulfur dioxide,
which is then recycled to the Glaus plant for further
treatment. This tail-gas unit vents to the atmosphere.
7) Delayed Coker
The delayed-coker unit is an upgrading unit which
cracks the heaviest oil, known as bottoms oil,
from the pyrolysis and oil recovery unit into
lighter hydrocarbon products and by-product coke
by thermal decomposition. The lighter products are
fractionated into gas, naphtha and gas oil. Foul
water is also produced from this unit. This water
is removed in the fractionator. The major product
of this unit is gas oil which is sent to the gas-oil
hydrogenation unit for further upgrading. Approxi-
mately 35 percent of the bottoms oil is converted
to coke.
-188-
-------
8) Foul-Water Stripping
The foul-water stripping unit removes HaS and minor
amounts of ammonia (NHa) from foul-water streams
collected from the pyrolysis and oil recovery unit,
the gas recovery and treating unit, and the delayed-
coker unit. The HaS and NHa are sent to the sulfur
recovery unit, where HaS is converted to elemental
sulfur and ammonia is converted to nitrogen. The
stripped water is returned to the pyrolysis unit
for moisturizing processed shale. The foul-water
stripper is a conventional-distillation column with
a steam-heated reboiler.1
The following summarizes the upgrading sequence: Gas from
the retort is routed to gas recovery and treating and then
recycled to the retort for gas combustion, or sent to the
hydrogen production unit. Naphtha is normally stabilized and
then hydrotreated. Gas oil streams are also hydrotreated.
Bottoms oil from the fractionator is thermally cracked by use
of a delayed coker, thus recovering additional oil and producing
a coke by-product. All HzS-rich gas streams are routed to the
sulfur recovery unit. Wash water from the hydrotreaters is
stripped at an ammonia separation unit. Water removed from
gas streams is routed to a foul water stripper to remove
ammonia and hydrogen sulfide. The stripped water is used for
moisturizing the spent shale.
4. 6.1.2 Input Requirements
This section reports inputs required for retorting and
upgrading operations at a surface retorting/upgrading facility.
Detailed estimates of economics, and of the various manpower,
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. pp. IV-3S
to IV-59.
-189-
-------
equipment, water, land, and energy requirements are available
only for the TOSCO II oil shale process. These estimates are
largely based on data reported by the U.S. Bureau of Land
Management in the draft Environmental Impact Statement (EIS)
for the Colony Development Operation (December 1975) and by
Ashland Oil and Shell Oil in the Detailed Development Plan
(DDP) for Oil Shale Tract C-b (February 1976)-1 When available,
inputs for other surface retorting processes are reported. Data
for alternate surface retorting technologies are probably less
certain than data reported for the TOSCO II process.
The inputs describe a facility processing 66,000 TPD oil
shale. Approximately 50,000 BPD of shale oil products are
produced by the plant. The inputs are intended to represent
a facility upgrading shale oil to finished fuels or premium
feedstocks.
4.5.1.2.a Manpower
Manpower requirements for the full-scale operation of a
TOSCO II processing facility are reported in Table 4-63. These
requirements include those personnel required for retorting and
upgrading operations. The requirements reflect the most recent
data available in documents open to the public.2 Earlier
1Ashland Oil and Occidental Oil Shale later rejected the
underground mining/TOSCO II retorting scneme and selected
Occidental's own modified in-situ process. Shell Oil withdrew
from the C-b project.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976.
p. IV-10.
-190-
-------
TABLE 4-63. MANPOWER REQUIREMENTS FOR 50,000 BPD TOSCO II
SURFACE PROCESSING
Personnel Requirements
Management and Secretarial 26
Technical Services 40
Administrative Support 25
Refinery Supervisor 16
Maintenance Management 31
Plant Operators 108
Plant Maintenance 183
429
Source: Ashland Oil, Inc. and Shell Oil Company. Detailed
Development Plan and Related Materials for Oil Shale
Tract C-b, Volume I,Prepared for Area Oil Shale
Supervisor. February 1976.p. IV-10.
-191-
-------
estimates from the Colony EIA and EIS are approximately the
same as those tabulated in Table 4-63. :'2
The manpower requirements in Table 4-63 relate only the
personnel required for full-scale commercial operations.
Accurate estimates of the skill breakdowns for construction
personnel required to establish the site are unavailable.
However total manpower requirements have been reported by
Ashland and Shell and have been shown in Figure 4-7. Peak con-
struction employment is approximately 3300.3
An estimate of cumulative craft labor during all construction
phases has been prepared by Ashland and Shell, and is reproduced
as Table 4-64. Table 4-64 includes crafts only and does not in-
clude staff and staff-support requirements, not the development
mine force. In addition, Table 4-64 does not represent the
timing of the required crafts. "
4.6.1.2b Materials and Equipment
Detailed materials and equipment requirements have not
been disclosed by current surface retort developers.
Colony Development Operation. An Environmental Impact
Analysis for a Shale Oil Complex at Parachute Creek, Colorado,
Vol. 1.Atlantic Richfield Company (Operator), Denver, Colorado
1974.
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado,Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975, p. 11-97.
3Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976.
Figure IV-3.
"Ibid., pp. III-2, 111-10.
-192-
-------
TABLE 4-64. CONSTRUCTION PHASE ESTIMATE OF CRAFT LABOR
Crafts
Asbestos
Boilermaker
Bricklayer
Carpenter
Masons
Electrician
Ironworker
Laborer
Millwright
Operator
Painter
Pipefitter
Sheetmetal
Teamster
Totals
Man Hour
Distribution
(%)
8
5
1
10
2
10
9
18
4
5
1
20
4
3
100
Total Craft
Man Months
5,254
3,284
657
6,568
1,314
6,568
5,911
11,822
2,627
3,284
657
13,136
2,627
1,971
65,680
Source: Ashland Oil, Inc. and Shell Oil Company. Detailed
Development Plan and Related Materials for"7JiI Shale
Tract C-b,Volume T". Prepared for Area Oil Shale
Supervisor. February 1976. p. 111-10.
-193-
-------
The facilities required for surface processing vary with
the degree of upgrading performed on site. A complex upgrading
crude shale oil to finished fuels or premium feedstocks requires
the following process units:
1) pyrolysis and oil recovery
2) gas recovery and treating
3) hydrogen production
4) gas-oil hydrogenation
5) naphtha hydrogenation
6) ammonia separation
7) sulfur recovery
8) delayed coker
9) foul water stripping
10) tankage.!'2
Tankage requirements of a 50,000 BPD facility have been reported
and are shown in Table 4- 65.
The FEA previously prepared a preliminary equipment list
for a 100,000 BPD retorting and upgrading facility featuring a
U.S.B.M. Gas Combustion Retort. These equipment requirements
are shown in Table 4-66. The retort design and upgrading
sequence are not current, and are representative of oil shale
technology circa 1973.3 The equipment list is presented to il-
lustrate the kinds of equipment required for surface shale pro-
cessing.
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b. Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-39,
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975, pp. 11-23 to 11-47.
3Interagency Task Force on Oil Shale. Potential Future Role
of Oil Shale: Prospects and Constraints. Federal Energy
Administration. November 1974. pp~.^166, 167, 171.
-194-
-------
TABLE 4-65.
PRODUCT AND INTERMEDIATE TANKAGE
FOR A 50,000 BPD FACILITY
Tank Service
Storage Capacity
*BBt
tank Description
Plant Site
Coker Feed
Gas Oil Hydrotreacer Feed
Naphtha Hydrotreater Feed
Foul Water Stripper Feed
Gas Oil Hydrotreater Product
Naphtha Hydrotreater Product
No. 2 Diesel Fuel
Plant Fuel Oil
"Butanes" Fuel
Oil-Water Separator Tank
LPG
Ammonia
Sulfur
110,000 Cone roof, two tanks @ 55,000 BBL ea.
480,000 Cone roof, two tank 3 240,000 BBL ea.
260,000 Floating roof
100,000 Cone roof
155,000 Cone roof
110,000 Floating roof
4,000 Cone roof, two tanks
2,300 BBL at mine headfraoe
1,700 BBL at plant size
100 Cone roof
3,000 High pressure vessels
2,000 Cone roof
4,000 Two high pressure vessels
8 2,000 BBL ea.
2,800 Two NH3 vessels 3 1,400 BBL ea.
1.500 Enclosed Pit
Off-Tract Terminal
LPG
Ammonia
Sulfur
20,000 High pressure vessels eight
3 2,500 BBL ea.
6,600 High pressure vessels three
3 2,200 BBL ea.
20,000 Cone roof
(3,000 long cons)
*The capacities shown are for net contents and do not include allowances for heel or
vapor space. These capacities are based on production of 50,000 BPD of shale oil.
Higher or lower production rates would modify tank capacities accordingly.
Source: Aahland Oil, Inc. and Shell Oil Company. Detailed Development Plan and
Related Materials for Oil Shale Tract C-b, Volume I. Prepared for Area Oil
Shale Supervisor. February 1976. p. IV-61.
-195-
-------
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-196-
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Construction material requirements for a 50,000 BPD oil
shale facility can be estimated from Bechtel's Energy Supply
Planning Model.1 Materials required during construction include:
Cement 9000 tons
Structural steel 6000 tons
Reinforcing bar 2000 tons
Piping 7000 tons
Valves 2000
These values were extrapolated from Bechtel's data for an
88,000 BPD Petrosix processing plant and may not be accurate.2
4.6.1.2c Economics
Preliminary capital cost estimates for a TOSCO II surface
processing plant are shown in Table 4-67. The costs have been
reported by Ashland and Shell in the DDP for oil shale tract
C-b, and should not be construed as definitive cost estimates.
The estimates are based only on preliminary engineering design
and project scheduling, and do not include interest during
construction and deferred capital expenditures. The capital
cost estimates in Table 4-67 include those costs related to the
surface processing facilities, and also include costs for
general facilities, indirect costs, and working capital. These
miscellaneous capital requirements (i.e., costs for general
facilities, indirects, and working capital) are attributed to
both mining and processing facilities. (Mine capital costs
^arasso, M. , et al. Energy Supply Model, Computer Tape.
San Francisco, CA: Bechtel Corporation, 1975 .
2The values were scaled from values for an 88,000 BPD
Petrosix facility by the following formula:
50 000
Estimated value = Bechtel's value '
This scaling method yields only very approximate estimates.
-197-
-------
TABLE 4-67. CAPITAL COST ESTIMATES FOR TOSCO II RETORTING AND
UPGRADING FACILITIES5'13
Plant Design and Construction
Pyrolysis $154,000,000
Fractionation and Gas Recovery 21,000,000
Oil Upgrading, By-Product Recovery and 113,000,000
Wastewater Treatment
Utilities and General Facilities 77,000,000
Field Costs 96,000,000
Taxes and Insurance 10,000,000
Engineering Services and Fees 78,000,000
Contingency 64,000,000
SUBTOTAL $613,000,000
Ceramics, Catalysts, and Chemicals $ 13,000,000
Prepaid Process Licenses 7,000,000
Employee Recruitment and Training 10,000,000
Project Management 19,000,000
Miscellaneous Other Costs 19,000,000
Environmental Program and Leasehold Costs 29,000,000
Startup and Fixit Allowance 22,000,000
Working Capital 17,000,000
TOTAL NONMINING/GENERAL $750,000,000
TOTAL CAPITAL $940,000,000'
aShale oil production capacity: 50,000 BPD
Costs are in 1977 dollars and are indexed from those reported
by Ashland and Shell by 1.10.
°Total Capital includes capital costs of an underground mine.
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Develop-
ment Plan and Related Materials for Oil Shale Tract
C-b, Volume I.Prepared for Area Oil Shale Supervisor
February 1976. p. 1-22.
-198-
-------
are discussed in Sections 4.5.1.2 and 4.5.2.2.) The costs in
Table 4-67 are indexed to 1977 from the October 1975 costs in
the DDP. Costs for processed shale disposal are included in
mine capital costs (Table 4-21), but are more closely associated
with processing activities.1 Total capital requirements of a
50,000 BPD TOSCO II processing facility and associated underground
mine are shown as $940,000,000.
Preliminary capital costs for a Paraho mining/processing
facility producing 100,000 BPD shale oil have been reported as
$1.200.000,000 (1976 dollars).2 The Paraho upgrading sequence
produces a crude shale oil requiring additional refining, and
thus avoids some of the upgrading costs that have been
reported for the TOSCO II process.
Operating cost estimates have not been disclosed by current
oil shale developers. However, data reported in the DDP and EIS
are sufficient to construct preliminary cost estimates. These
estimates are shown in Table 4-68, and are based on preliminary,
incomplete data.3'1* The labor costs are estimated from the labor
requirements reported by Ashland and Shell in the DDP. Utility
costs are estimated from the power requirements reported in the
EIS. All other costs are estimated as percentages of the capital
or labor costs.
Ashland Oil, Inc., and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. 1-22.
2West, J. "Obstacles to Limit U.S. Shale Production", Oil
and Gas Journal 75 (35): 523-525, August 1977.
3Ashland Oil, Inc. and Shell Oil Co., op.cit.
"U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado^Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
-199-
-------
TABLE 4-68. ANNUALIZED OPERATING COSTS FOR A 50,000 BPD
TOSCO II PROCESSING FACILITY3
Direct Cost!
Management and Secretarial $ 320,000
Technical Services 800,000b
Administrative Support 500,000
Refinery Supervisor 320,000b
Maintenance Management 620,000b
Plant Operators 1,600,000°
Plant Maintenance 2,700.000°
Total Personnel Costs * 7,100,000
Operating Supplies 6,100,000
Maintenance Materials 3,300,000*
Utilities
Electricity 27,000,000£
Water8
Surface Fuel ~~~
Fixed Costa
Depreciation 61,000,000X
Taxes and Insurance 18,000,000J
Plant Overhead 3,500,OOPk
TOTAL 9126,000,000 $6.90/bbl
Costs are in 1977 dollars and include only those costs directly attributed
to the retorting/processing.
Calcualted 8 $20,000/manyear.
Calculated 9 $15,000/man year.
Calculated @ 1" of the fixed capital costs.
'Calculated 8 100Z of maintenance labor.
'calculated 9 $0.04/kvh.
Plater costs have not been specified and are probably not significant.
Pover costs include costs for water treatment.
urface fuel requirements are met by fuel produced during upgrading.
hs
Calculated 9 10Z of fixed capital.
^Calculated 9 3Z of fixed capital.
Calculated 8 50Z of total labor costs.
Note: Rates for calculating fixed costs, plant overhead, and costs for
operating supplies and maintenance materials are largely based on
Petecs, M. S. and K. D. Timmerhaus. Plant Design and Economics
for Chemical Engineers. 2nd. Ed. (New York: McGraw-Hill Book Co.,
1968), pp. 132-141.
Source: U.S. Bureau of Land Management. Proposed Development of Oil Shale
Resources by the Colony Development Operation In Colorado, Draft
Environmental Impact Statement. DES-75-62. Washington, D.C.:
December 1975.
Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan and
Related Materials for Oil Shale Tract C-b. Volume 1, Prepared for
Area Oil Shale Supervisor. February 1976.
-200-
-------
4.6.1.2d Water
A TOSCO II processing facility requires water for mining;
crushing and conveying; coarse-ore storage; retorting and up-
grading; processed shale disposal; and general plant and per-
sonnel use. Figure 4-26 reports the water system flow for a
50,000 BPD TOSCO II processing facility.
Consumptive uses of water during retorting, upgrading, and
shale disposal are summarized in Table 4-69. Net water require-
ments of TOSCO II processing are shown as 5030 gpm (8100 acre-ft/
year) for a shale oil production of 50,000 BPD. Water require-
ments for mining, crushing, conveying, and coarse-ore storage
are discussed in Sections 4.5.1.2 and 4.5.2.2. Revegetation
water requirements are discussed in Section 4.7.
A major use of water is the moisturization of processed
shale. All waste water streams not otherwise recycled are used
for shale moisturization. Water used for moisturizing processed
shale or for dust control on the processed shale embankment will
either evaporate, be incorporated into the wastepile, or drain
into a catchment basin for recycle. Other uses include steam
generation in the reforming process to produce hydrogen for the
hydrotreating units, use as potable water, and evaporation losses
from the cooling tower and the pyrolysis unit.
Water uses during construction include concrete manufacture,
dust control, fill compaction, and personnel uses. Quantities
for these uses amount to 500-700 gpm.2 The entire requirement
can probably be met by water from mine dewatering operations.
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for^Oil Shale Tract C-b, Volume T.
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-62
2Ibid.
-201-
-------
» "^ LIQUID
cmutui
IHKS»C IIII
IE for Oil
IV-6J.
-------
TO PR HART CRUSHER
AW COARSC DUE
STOHAU 'OK
OUST COKTROt
i
_ 1 TO 6FK REVEGCTAUON
OUT
VAT EH
PftOCCSS
DBA IMS
1
i PROCESS
CONSUMPTION SUR
* * LOSS p(>
2«2 GPM
A
1 CPH
1 V
> Un« FiW
PROCESS CO«OENSAT[ "j ^ ""^J"-" "",' ^ GU«
" GP" PROCESS «3 DITCHES ""
CM I DRAINS
X r-U
1 STfAl* yi ovort
flMOGWL SI[A« JM5 GPU US[R5 ' l« .AT
HACHINCRT 1065
(TOO GPM AFTER \Z rCARS)
SIO CPU ^^^^
MAI 1000 GPM ^"^^^
NNF
1
H OH/WTR
10 SEMRATOR CL1AN «A
fc GPM 1 8 Gi»M
(EMERCENCT
ft**) ^ siuocr
PERIOD
PISPQS
OVERFLOW NNF
o mir fc
NMf
' f ?" GP"
NttF
*" * ^|0 GPWW
t 1 W" } 1
L CONDtNSAU y L "iSF
580 GPM f I
| 1 ( RAW SH»LE SURFACE MO
4BO ,P- ;«£ _. _480 GPM ?lLMJ.-».... I » 5M4LC .TR OF R£T
"^ " STRIPPER STRPPtO ^
fOUl »ATE»
450 GPM
UNIT | VTR FROM COMBUSTION
fOlA. VATEff
SLUC^E 50 ',»M 111
1 ' PUMP a (MSTRUMENTATtO*
1(0 GPM
25 GPU
RIVER WATER BIO GPH (SEE NOTE ?)
NOTES
I NNF-NORMALLY NO FLOW
2 RIVER WATER MAKE UP TO PYROLYSIS
WILL DECREASE WHEN OTHER WATER
SOURCES SUCH AS PRECIPITATION RUN
OFF ARE AVAILABLE
of TOSCO ii on Shale
-------
Figure 4-26. Water System F
Source: Ashland Oil, Inc. and Shell Oil Company.
Shale Tract C-b, Volume I. Prepared for
-------
TABLE 4-69. USES OF WATER BY TOSCO II SHALE PROCESS PRODUCING
50,000 BPD SHALE OILa
Use
Quantity
Cooling Tower: Evaporation and Drift 1530 gpm
Hydrogen Plant 448 gpm
Steam Users and Loss 282 gpm
Coker 70 gpm
Evaporation from Pyrolysis Unit 1620 gpm
Shale Moisturization 1500 gpm
Utility 250 gpm
Potable Water 15 gpm
TOTAL GROSS CONSUMPTION 5720 gpm
Water Entering System with Raw Shale or
Co-produced with Shale Oil 685 gpm
NET CONSUMPTIVE WATER USE 5030 gpm
o
Does not include mine consumption, crusher/ore storage uses,
or revegetation
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Develop-
ment Plan and P.elated Materials for OTl Shale Supervisor.
February 1976.p. IV-63.
-203-
-------
McKee and Kunchal have examined the water requirements for
a full-scale Paraho oil shale plant operating with direct or
indirect heating. Their data are summarized in Table 4-70, as
linearly scaled to a facility producing 50,000 BPD shale oil.
Indirect heating consumes about 33% more water than direct heating,
due to increased revegetation water needs. The consumption values
in Table 4-70 are not comparable to those in Table 4-69 for
TOSCO II processing due to differing upgrading schemes.1
Total water requirements for the Union Retort B process
producing 50,000 BPD shale oil are approximately 2600 gpm. In-
cluded are requirements for retorting, cooling, gas treatment,
deasher, scrubber, processed shale moisturizing and disposal.
The reported requirement does not include any water requirements
for upgrading.2
The total water consumption for a Lurgi-Ruhrgas process
producing 50,000 BPD shale oil has been estimated as 1470 gpm.
Water requirements for gas recovery and treatment, and for shale
oil upgrading are not included in the reported value.3
The net consumption of water for a Superior process pro-
ducing 10,000-15,000 BPD shale oil is reported to be 880 gpm.
This amounts to a net requirement of 3500 gpm for a facility
J. M., and E. K. Kunchal. "Energy and Water Re-
quirements for an Oil Shale Plant Based on the Paraho Process",
9th Oil Shale Symposium, Colorado School of Mines, April 29, 1976
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency. EPA Contract No. 68-02-3535.
Austin, TX: Radian Corporation, September 1977. p. 76.
3"Development of the Lurgi-Ruhrgas Retort for the Distilla-
tion of Oil Shale", Lurgi Mineralotechinek GMBH, October 1973.
-204-
-------
TABLE 4-70. WATER REQUIREMENTS OF A 50,000 BPD PARAHO SHALE OIL
PLANT
a,b
Use
Water Requirements (gpm)
Direct Mode
Indirect Mode
Evaporation from cooling
tower
1990
1990
Pre-refining and power
generation
220
220
Retorting (dust control)
Revegetation
50
870
3130
50
1890
4150
yt
Basis: 30 gal/ton oil shale.
Does not include water requirements of mining and crushing.
£
More akin to moisturization rather than revegetation. This re-
quirement varies for each mode of operation due to varying pro-
cessed shale compositions.
Source: McKee, J.M., and E.K. Kunchal, "Energy and Water Re-
quirements for an Oil Shale Plant Based on the Paraho
Process." 9th Oil Shale Symposium, Colorado School of
Mines, April 29, 1976.
-205-
-------
producing 40,000-60,000 BPD. All water requirements can probably
be satisfied with saline water from a "leached" zone aquifer.
4.6.1.2e Land
Ashland and Shell have projected surface disturbances asso-
ciated with a TOSCO II processing facility. Estimates of the
acreage disturbed by a 50,000 BPD facility are reported in Table
4-71. The largest disturbance is associated with the disposal of
processed shale. Ashland and Shell expected a processed shale
pile to eventually cover 1000-1200 acres on the tract. Back-
filling the mine with processed shale could reduce the amount
of processed shale disposed of on the surface. It has been es-
timated that backfilling can begin within 5-10 years after the
start of production.2
4.6.1.2f Ancillary Energy
Energy requirements of a TOSCO II processing facility
include:
1) gas, liquid, and diesel fuels
2) steam
3) electric power.
'Prien, C. H. "Superior Oil Shale Process", Technological
Overview Reports for Eight Shale Oil Recovery Processes. Pre-
pared for U.S.Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b. Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. pp.
V-96, V-110.
-206-
-------
TABLE 4-71. SURFACE AREAS DISTURBED BY A TOSCO II PROCESS
PRODUCING 50,000 BPD SHALE OIL
Disturbance Area Disturbed (Acres)
Truck Maintenance Facility 10-15
Plant Site 150-200
Processed Shale Handling System 15-20
Power R-O-W 5-15
Pipeline Corridor R-O-W 10-20
Auxiliary Buildings 28-35
Processed Shale Disposal 1000-1200
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed
Development Plan and Related Materials for
Oil Shale Trace c-b,Volume I,Prepared for
Area Oil Shale Supervisor. February 1976.
p IV-9.
-207-
-------
The TOSCO II processing complex is self-sufficient in gas
and liquid fuels after it commences operations. During initial
start-up, purchased fuel oil is burned. Three fuels are used
in the plant: a treated fuel gas, a treated liquid mixture of
butanes and butenes, and a distillate fuel oil. All of the
fuel gas and butane-butene liquid mixture produced in the plant
are consumed internally. The fuel oil can be gas oil or a
blend of gas oil and naphtha. Fuel gas is used as a feed gas
in the production of hydrogen. Heat loads to the various
processing units are summarized in Table 4-72. These energy
demands are not ancillary energy requirements since the demands
can be met by fuels produced in the process.1
Diesel fuel produced in the gas-oil hydrogenation unit can
be used in mine and processed-shale disposal operations. Approxi-
mately 17,000>-21,000 gallons of diesel fuel are required each
day for these operations at a complex producing 50,000 BPD.
Once again, these energy demands are not ancillary energy
requirements.2
Most of the plant requirements for steam are met by using
process waste-heat boilers.3
The required electric load for a TOSCO II processing facility
producing 50,000 BPD amounts to about 100,000 KVA, with an
estimated operating load of about 80,000 KVA.4 This energy demand
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-63.
2Ibid.
3Ibid.
-208-
-------
TABLE 4-72. HEAT LOADS TO PROCESSING UNITS AT A TOSCO II
FACILITY PRODUCING 50,000 BPDa'b
Processing Unit Firing Duty
(MM Btu/hr)
Pyrolysis and Oil Recovery
Preheat System 2046
Steam Superheater 126
Hydrogen Production 604
Gas Oil Hydrogenation
Reactor Feed Heater 20
Fired Reboiler 63
Naphtha Hydrogenation 7
Utility Boilers 200
Delayed Coker 88
Sulfur Recovery 10
g,
These heat loads are not ancillary energy requirements since the demands
can be met by fuels produced in the process.
Heat loads for delayed coking are those reported in the Colony Development
Operation EIA; all other duties are those reported in the Bureau of Land
Management's EIS.
Sources: U.S. Bureau of Land Management. Proposed Development of Oil Shale
Resources by the Colony Development Operation in Colorado, Draft
Environmental Impact Statement. DES-75-62. Washington, D.C.
December, 1975. pp. 11-28 to 11-45.
Colony Development Operation. An Environmental Impact Analysis
for a Shale Oil Complex at Parachute Creek, Colorado. Vol. I.
Atlantic Richfield Company (Operator), Denver, Colorado, 1974.
p. 201.
-209-
-------
properly represents ancillary energy requirements, and is equal
to an energy consumption of 7 x 108 kwh/year. The energy recovery
ratio for TOSCO II retorting/processing is determined to be 0.62.
This energy recovery ratio is defined as the ratio of the heating
value of all products to the heating value of all inputs. The
heating value of the products includes the net liquid and gas
fuels produced along with the coke produced. Sulfur and ammonia
are not included. The input heating value includes the gross
heating value of the raw shale and the ancillary electrical inputs.
Power demands for a Union Retort B process are similar to
those reported for a TOSCO II process. Power requirements for a
50,000 BPD complex amount to 70,000 kw.l This figure represents
a yearly consumption of about 6 x 108 kwh.
Energy requirements for the Paraho process are scaled from
those reported for a 100,000 BPD facility. These requirements
amount to 36 megawatts for retorting and 15 megawatts for pre-
refining. In the direct mode, potentially 200 megawatts of elec-
trical power can be exported for sale. Only 40 megawatts are
available for export if the retort is operated in the indirect
mode.2
The power requirement for a Lurgi-Ruhrgas producing 50,000
BPD shale oil has been reported as 29,000 kw.3 This amounts to
a yearly consumption of about 3 x 109 kwh. Power demands of
gas recovery and treating and shale oil upgrading are not
included in this estimate.'
C. C. "Union Oil Shale Retorting Process ", Techno-
logical Overview Reports for Eight Oil Shale Recovery Processes.
Prepared for U.S.Environmental Protection Agency.Contract No.
68-02-1881. Denver Research Institute and TRW Environmental
Engineering Division. December 1976.
2McKee, J. M., and E. K. Kunchal. "Energy and Water Re-
quirements for an Oil Shale Plant Based on the Paraho Process-.,
9th Oil Shale Symposium, Colorado School of Mines, April 29, 1976
3"Development of the Lurgi-Ruhrgas Retort for the Distilla-
tion of Oil Shale." Lurgi Mineraloltechninek GMBH, October 1972
-210-
-------
4.6.1.3 Outputs
This section reports the various outputs associated with the
operation of a surface processing facility producing 50,000 BPD.
Discussions of air emissions, water effluents, solid wastes, noise
pollution, occupational health and safety, and odor are largely
based on information reported by developers of the TOSCO II pro-
cess in a published development plan and in an environmental
impact statement.1'2 These emission estimates do not necessarily
represent those achievable with best available control technology
(BACT). Outputs reported for other surface retorting processes
are based on more preliminary engineering designs.
The data reported below assume the upgrading of crude shale
oil to finished fuels or premium refinery feedstocks.
4.6.1.3a Air Emissions
Air emissions from surface retorting/processing operations
originate from: retorting and upgrading operations, shale oil
storage, steam generation, processed-shale disposal, and waste-
water treatment. Emissions from these sources are described
below. Quantitative estimates are not available for emissions
from wastewater treatment.
A summary of the estimated ranges of emissions from retort-
ing and upgrading operations, steam generation, and shale oil
storage is presented in Table 4-73. The summary represents the
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil^Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976.
2U.S. Bureau of Land Management. Proposed Development
of Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
-211-
-------
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-212-
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most recent presentation of TOSCO II emissions as reported in
the DDP for oil shale trace C-b.1 Emissions reported in the
EIS for the Colony Development Operation2 are essentially simi-
lar to those reported in the DDP. These emissions agree reason-
ably well with EPA emissions factors for combustion sources.
Specific air contaminants are discussed below.
Sulfur dioxide is emitted from combustion processes and
from the tail-gas unit in the sulfur recovery plant. Hydrogen
sulfide is present in retort gases and is thus a potential con-
taminant from process spills and leaks. However, most of the H2S
in fuel gas and plant fuel oil is oxidized to sulfur dioxide in
various process burners. Sulfur dioxide emissions from diesel
trucks required for processed shale disposal are negligible.3
Estimated S02 emissions from the plant combustion sources are
based on the sulfur contents of the plant fuel gas and fuel oil,
and on the observed emissions from 25 TPD and 1000 TPD pilot and
semi-works plant operations.* A Glaus plant recovers about 95%
of the sulfur in the acid gas feed to the sulfur recovery unit.
The tail gas stream from the Claus plant contains approximately
5% of the original sulfur and is routed to a tail gas treating
unit. Performances of tail gas treating units vary; however, ap-
proximately 95% of the remaining sulfur should be removed.5
Ashland Oil, Inc. and Shell Oil Co., op.cit., p. V-7.
U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in CpTo-
raclcs Draft Environmental Impact Statement. DES-75-62. Washing-
ton, D.C.: December 1975. pp. 11-28 to 11-49.
3Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for the U.S.
Environmental Protection Agency]EPA Contract No. 68-01-3535.
Austin,TX:Radian Corporation, September 1977.
''Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale "Supervisor.February 1976.
pp. V-6 to V-8.
5Colley, J. D., W. A. Gathman, and M. L. Owen, op.ait.,
p. 33.
-213-
-------
Solid particulates are emitted from raw-shale preheating,
processed-shale moisturization, ball-circulation system opera-
tions, processed-shale disposal and processed-shael piles. Ac-
cording to Colorado regulations, condensible hydrocarbons are
considered particulates. Particulate emissions in Table 4-73 are
based on EPA emission factors for gas, butane, and distillate oil
combustion.1 During occasional soot blowing, boiler "lancing",
and fuel swtiching, additional particulates may be released.
Venturi wet scrubbers remove 95.8 to 99.8 percent of the
shale dust from the preheat and ball circulation systems. Wet
scrubbers remove about 93% of the processed shale dust from the
shale moisturizer.2
Particles emitted from the plant contain the same elements
and compounds found in retorted shale. Analyses of the elemental
concentrations in TOSCO II-retorted shale are shown in Table
4-74. These concentrations depend on the composition of raw
shale being retorted. The mineral constituents of several sur-
face retorted shales are shown in Table 4-75.
Polycyclic aromatic hydrocarbons are also found in par-
ticulate emissions from the processing plant. Those PAH detec-
ted in TOSCO II surface-retorted shale are reported in Table 4-76.
All of the compounds in Table 4-76 are known or suspected
Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2nd Ed. AP-42.Research Triangle
Park, NC:1973.
2Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, TX: Radian Corporation, September 1977. pp. 53-54.
-214-
-------
TABLE 4-74.
ELEMENTAL CONCENTRATIONS IN TOSCO II
SURFACE-RETORTED OIL SHALE
Element
Li
Be
B
F
CI
Sc
Ti
V
Cr
Mn
Co
Ni
Cu
Zn
Ga
Ge
As
Se
Br
Rb
Sr
Y
Source:
Concentration
(wt . ppm)
850
35
140
1,700
72
2.4
570
29
49
34
39
11
15
13
2.2
0.40
7.2
0.08
0.01
29
69
1.2
Element
Zr
Nb
Mo
Ru
Rh
Pd
Ag
Cd
In
Sn
Sb
Te
I
Cs
Ba
La
Ce
Pr
Nd
Sm
Eu
Colony Development Operation
Concentration
(wt . ppm)
9.3
3.4
4.9
<0.1
<0.1
<0.1
<0.01
0.14
Standard
0.11
0.39
<0.1
<0.01
1.2
32
1.4
1.6
0.25
1.2
0.44
0.12
Element
Gd
Tb
Dy
Ho
Er
Yb
Lu
Hf
Ta
W
Re
Os
Ir
Pt
Au
Hg
TI
Pb
Bi
Th
U
An Environmental Impact
for a Shale Oil Complex at Parachute Creek,
Colorado,
Concentration
(wt . ppm)
0.40
0.07
0.40
0.07
0.27
0.25
<0.1
<0.1
0.04
0.42
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.14
10
0.36
0.77
0.99
Analysis
Volume I.
Atlantic Richfield Company (Operator), Denver, Colorado. 1974.
p. 208.
-215-
-------
TABLE 4-75. MINERAL CONSTITUENTS IN TYPICAL RETORTED OIL SHALES
Component
Si02
Fe203
A1203
CaO
MgO
SO 3
Na20
K20
TOSCO IIa
wt %
33.0
2.5
6.8
15.8
5.3
-
8.7
3.3
Union Bb
wt %
31.5
2.8
6.9
19.6
5.7
1.9
2.2
1.6
USBMC
wt%
43.8
4.6
12.2
22.1
9.3
2.2
3.4
2.4
a
Colony Environmental Impact Analysis, 1974. Data represent
Mahogany zone shale (^35 gal/ton) from Parachute Creek area.
Lipman, S.C., Union Oil Co. Revegetation Studies. Data repre-
sent Mahogany zone shale (^35 gal/ton) from Parachute Creek
area.
Q
Stanfield, et.al., Data represent Mahogany zone shale (^30
gal/ton) from Anvil Points.
Sources: Colony Development Operation. An Environmental Impact
Analysis for a Shale Oil Complex at Parachute CreekT
Colorado, Vol. ~T.Atlantic Richfield Company (Opera-
tor) , Denver, CO. 1974. p. 207.
Lipman, S.C. "Union Oil Company Revegetation Studies."
Environmental Oil Shale Symposium. Colorado School of
Mines, October 9-10, 1975.
Stanfield, K.W., et. al. "Properties of Colorado Oil
Shale." USBM, Report of Investigations No, 4825, 1951.
-216-
-------
TABLE 4-76. POLYCYCLIC AROMATIC HYDROCARBONS DETECTED IN
TOSCO II SURFACE-RETORTED SHALE
Benzo(a)pyrene (BaP)
Alkyl I (BaP)
Alkyl II (BaP)
Benzo(ghi)fluoranthene
Benzo(e)pyrene
Perylene
Benzo(ghi)perylene
Anthanthrene
Pyrene
Fluoranthene
Benz(a)anthracene
Triphenylene
Phenanthrene
7,12-Dimethylbenz(a)anthracene
3-Methylcholanthrene
Coronene
Chrysene
Source: Coomes, R.M. "Health Effects of Oil Shale Processing."
Quarterly of the Colorado School of Mines 71(4):
101-123, October 1976.
-217-
-------
animal carcinogens and may be carcinogenic to man. Concentrations
of these compounds have not been reported.
Using an emission factor reported by PEDCo-Environmental,
fugitive dust emissions from the processed shale pile are
estimated as 1.6 tons/acre/year, assuming 8070 dust control by
a chemical stabilizer.1 If 160 acres are disturbed each year,
dust emissions amount to about 60 Ibs/hr. Emissions during
transport of the processed shale have not been estimated. Coke
cutting, dumping, and loading are other potential sources of
fugitive dust.2
Hydrocarbons at concentrations of about 90 ppm are contained
in flue gases from the retort preheat systems. About half of
the hydrocarbons are condensible at exhaust conditions and are
therefore classed as particulates. Minor quantities of hydro-
carbons are produced in all combustion operations. Diesel equip-
ment operated during processed shale disposal emits unburned hydro-
carbons, aldehydes, organic acids, and smoke. Under upset condi-
tions, if retorting is incomplete because of insufficient tempera-
tures or residence time, the resulting processed shale may emit
hydrocarbons. However, these conditions occur infrequently.3
The following assumptions based on literature, data, and
experience are formulated to calculate the hydrocarbon emissions
from petroleum storage:
Cowherd, Charlten, Jr., et al. Development of Emission
Factors for Fugitive Dust Sources, Final Report.EPA-450/3-74-037,
Contract No. 68-02-0619.Kansas City, Mo.: Midwest Research
Institute, June 1974.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. pp.
V-8 to V-9.
3 Ibid.
-218-
-------
1) All product storage is in floating roof tanks.
2) Storage capacity is 10 days' production.1
3) Combined hydrocarbon product is equivalent to
crude oil.
Using petroleum storage emission factors for storing crude oil
in floating roof tanks, hydrocarbon emissions from storage are
calculated to be 24 Ib/hr. Floating roof tanks provide approxi-
mately 90-95% control of hydrocarbon emissions from storage.2
There are numerous hydrocarbon emissions in the shale oil
upgrading facilities from sources such as valve stems, flanges,
loading racks, equipment leaks, pump seals, sumps, and API
separators. These losses are discussed in Radian Corporation's
Refinery Siting Report.3 Based on literature data, Radian found
that the miscellaneous hydrocarbon emissions amount to about
0.1 wt % of refinery capacity for a new well-designed, well-
maintained refinery. This value of 0.1 wt 7, is used to determine
miscellaneous emissions from the shale oil up-grading facilities.
Upgrading capacity is considered to be the feed to the distilla-
tion tower (50,000 bbl/day). Hydrocarbon emissions from miscel-
laneous sources are calculated to be 680 Ib/hr. The composition
of these hydrocarbons can be expected to be a composite of all
^ittman Associates, Inc. Environmental Impacts, Efficiency
and Cost of Energy Supplied by Emerging Technologies, Draft Re-
port on Task 7 (till Shale) and Task 8 (Fluidized Bed Boiler
Combustion). Columbia, MD: May 1974.
2Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2nd Ed. AP-42.Research Triangle
Park, NC:TT7T
3Radian Corporation. A Program to Investigate Various
Factors in Refinery Siting. Prepared for Council on Environ-
mental Quality and U.S.Environmental Protection Agency. Austin,
TX: 1974.
-219-
-------
volatile intermediate and refined products. The emissions are
assumed to occur at an average height of 5 feet.1'2
Estimates of plant carbon monoxide emissions are based on
EPA emission factors for gas, butane, and distillate oil
combustion.3 Emissions of carbon monoxide from diesel equipment
used in processed shale disposal have not been estimated.
Evaporation and holding ponds are possible sources of the
volatile compounds found in the various wastewaters. Atmospheric
emissions from ponds have not been characterized but are likely
to contain ammonia and hydrogen sulfide.1* Hydrocarbon emissions
from ponds are included in miscellaneous hydrocarbon emissions.
Since the complex produces ammonia as a by-product, ammonia
may be released to the atmosphere from spills and leaks.
Temperatures and redox conditions during retorting are not
severe enough to volatilize most metallic elements. With notable
exceptions such as arsenic, selenium, and antimony, most trace
elements remain with the processed shale or are found in shale
solids entrained in retort gases.5
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-01-3535.
Austin, TX: Radian Corporation, September 1977. p. 55.
2Radian Corporation. A Program to Investigate Various Fac-
tors in Refinery Siting. Prepared for Council on Environmental
Quality and U.S. Envir onmenta1 Protection Agency. Austin, TX: 1974,
Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2nd Ed. AP-42\Research Triangle
Park, NC: WJT.
"Crawford, K. W. , et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development^Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 74.
5Ibid., >p. ,67.
-220-
-------
Air emissions for pyrolysis and oil recovery units of
Paraho and Union Retort B processes are summarized in Table
4-77.
4.6.1.3b Water Effluents
Direct wastewater discharge from a TOSCO II retorting and
upgrading operation is not anticipated. All wastewater is re-
used in plant operations and ultimately consumed in moisturizing
processed shale.*'2'3
Plant process wastewaters are collected, processed to
reclaim useful components, and combined for in-plant treatment
before re-use. Major sources of wastewater are:
1) pyrolysis and oil recovery units - blowdown water
that is produced from the venturi scrubbers used
to remove shale dust from flue gas;
2) gas oil and naphtha hydrogenation units - sour
water that is produced by the washing operation;
3) ammonia separation and sulfur recovery units -
ammonia-stripped water and an acidic wastewater;
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development"! Prepared for
U.S.Environmental Protection Agency.contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 81.
2Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976.
3U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
"Crawford, K. W. , et al. , op. ait.
-221-
-------
TABLE 4-77. AIR EMISSIONS FROM THE PARAHO
AND UNION B RETORTSa>b
Paraho Union B
Particulates 91 Ib/hr 63 Ib/hr
S02 114 Ib/hr 140 Ib/hr
Total Organics 24 Ib/hr 30 Ib/hr
CO 39 Ib/hr 66 Ib/hr
NOX 1140 Ib/hr 622 Ib/hr
Rate 1,300,000 scfm
rt
Data describe emissions from the pyrolysis and oil recovery
unit only.
Based on production of 50,000 BPD.
Source: Colley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for
U.S. Environmental Protection Agency.EPA Contract No.
68-01-3535. Austin, TX: Radian Corporation, September
1977. pp. 65, 78.
-222-
-------
4) delayed coker units - foul water;
5) utilities - boiler and cooling water blowdowns;
6) Wellman-Lord unit - blowdown of alkaline
sulfate/sulfite wastewaters.*
The composition of the combined process wastewater stream
is shown in Table 4-78. Major constituents in the combined pro-
cess water are organic acids, neutral oils, amines and phenols,
and mineral salts such as sodium, calcium, and magnesium sul-
fates, chlorides, and carbonates. High molecular weight poly-
cyclic organics may also be present. Twenty-two trace elements
have also been identified in combined wastewater; none of these
is present in quantities greater than 1 mg/£.
Table 4-79 is a summary of the maj.or constituents present
in Paraho retort wastewater. Because of the significant amounts
of organic materials present in the wastewater, the biochemical
oxygen demand (BOD) and chemical oxygen demand (COD) are high.
The data in Table 4-79 include no downstream upgrading operations.2
The major wastewater streams from Union Oil's retorting
process are:
1) water from gas compression and cooling,
2) water from ammonia absorption,
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 81.
zlbid.3 p. 83.
-223-
-------
TABLE 4-78
APPROXIMATE COMPOSITION OF TOSCO II COMBINED
PROCESS WASTEWATER (50,000 BPD UPGRADED SHALE
OIL PRODUCTION)
Component
Ca+2
Mg+2
Na+1
NH/1
Zn+2
As+5
Cr+5
C03"2
HCOs"1
so,T2
S203"2
PO.T3
Cl"1
CN~!
Phenols
Amines
Organic Acids
Neutral Oils
Chelate
TOTALS (Rounded)
Concentration in Water (ppm)
Added to Spent Shale
280
100
670
16
5
.015 - 0.3
2
360
100
850
90
5
570
5
315
410
1,330
960
5
6,100
Ib/hr
190
70
450
10
4
0.01 - 0.2
1
240
70
575
60
4
385
4
215
280
900
650
4
1,870
In addition to above, elements present in trace quantities (less than 1 ppm)
are Pb, Ce, Ag, Mo, Zr, Sr, Rb, Br, Se, Cu, Ni, Co, Fe, Mn, V, Ti, K, P, Al,
F, 3, Li.
Source: U.S. Bureau of Land Management. Proposed Development of Oil Shale
Resources by the Colony Development Operation in Colorado, Draft
Environmental Impact Statement. DES-75-62. Washington, B.C.
December 1975. p. 11-29
-224-
-------
TABLE 4-79. ANALYSIS OF PARAHO PROCESS WASTEWATER
Concentration (mg/«,')
Constituents
Ammonia nitrogen 2,000 - 20,000
Organic carbon 10,000 - 29,000
Organic nitrogen 4,000 - 12,000
Carbonates 2,000 - 24,000
Bicarbonates 5,000 - 26,000
Parameters
BOD 5,000 - 12,000
COD 17,000 - 20,000
Sources: Hendrickson, T. A., comp. Synthetic Fuels Data Hand-
book. Denver, CO: Cameron Engineers,Inc.1975.
Jones, J. B. "The Paraho Oil Shale Retort." 9th Oil
Shale Symposium, Colorado School of Mines. Golden,
Colorado. April 29-30, 1976.
Data collected by TRW/DRI during sampling at Paraho
facility. Anvil Points, Colorado. March 1976.
-225-
-------
3) water from oil-water separator,
4) water from first stage solids removal, and
5) water from oil stripper condensate drum.
These wastewaters are combined, stored, and re-used for processed
shale cooling and some water stripping. Little data has been
disclosed on the composition and quantities of these waste
streams.l
Wastewater treatment systems are generally similar to those
employed at oil refineries, and are summarized in Chapter 6,
Crude Oil Resource Development System.2
Runoff water from processed shale will contain higher con-
centrations of dissolved solids than runoff waters from undis-
turbed areas. Laboratory and field experiments have shown that
sodium, calcium, magnesium, potassium, bicarbonate, sulfate,
and chloride are present in waters contacted with freshly
processed shale. Table 4-80 presents results of laboratory
experiments on raw and retorted shales. TOSCO II and USBM
retorted shales contain about 20 Ib/ton of readily leachable
salts, roughly 4 times that from raw shale. The total soluble
salts depend heavily on the extent of carbon combustion and min-
eral decomposition that occur in the combustion zone of a gas
combustion retort.3 Other compounds and elements potentially
leachable from processed shale are shown in Tables 4-74 and 4-76.
Crawford, K. W. et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development. Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. p. 83.
2Ibid.J pp. 84, 86.
zlbid., pp. 90, 91.
-226-
-------
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Potential shale developers plan to collect shale pile runoff
water in catchment ponds. The developers of tract C-b planned an
impoundment sufficient to withstand a 100-year flood. Water col-
lected in the pond can be re-cycled to the shale processing plant.
Groundwater is also potentially contaminated by leachate from the
processed shale pile.
4.6.1.3c Solid Wastes
Solid wastes associated with a 50,000 BPD TOSCO II processing
facility are tabulated in Table 4-81. Table 4-81 is based on
data reported in the EIS for the Colony Development Operation.
Data reported in the DDP for oil shale tract C-b are generally
similar to those reported in Table 4-81.
One of the major environmental problems associated with
oil shale development is the disposal of large quantities of
processed shale. A facility producing 50,000 BPD shale oil
from shale containing 30 gal/ton must dispose of over 53,000
tons of processed shale per day.2 This shale contains toxic
elements, metals, and organic compounds that can be leached from
the shale (See Tables 4-74 through 4-76). Potential backfilling
of surface and underground mines is no panacea: toxic substances
within the shale may be leached by underground water. Backfilling
of an underground mine can begin only after 5-10 years of opera-
tion. 3 Backfilling of surface mines may not be feasible for
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. pp. V-47,48
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975, p. 11-48.
3Ashland Oil, Inc. and Shell Oil Co., op.cit., p. V-110.
-228-
-------
TABLE 4-81. MAJOR SOLID WASTES FROM A TOSCO II COMPLEX
PRODUCING 50,000 BPD
Source of Solid Waste
Approximate
Quantity
Annual
Production
Major Constituent
Pyrolysis Unit
Processed Shale
Clarifier Sludge from
Set Scrubbers-
Preheat System
Ball Circulation System
Processed Shale
Moisturizing System
Total
860 T/D*
i 65 T/D*
43 T/D*
313,900 T
23,725 T
15,695 T
54,168 T/D
Upgrading Units (Hydrotreaters)
Naphtha 0- 75 T/2 yrs (max)
Naphtha 60 T/yr
Gas Oil 0-260 T/yrs (max)
Gas Oil 350-475 T/yr
Hydrogen Unit
Hydrodesulfurizer
Caustic Wash
Guard Bed
Shift Converter
(High Temp.)
Shift Converter
(Low Temp.)
Sulfur Unit
Glaus Unit
Tail Gas
Hydrotreater
Gas Treating Unit
DEA Filter
DEA Filter
Coker Unit
Water Treatment
53,200 T/D* 19,418,000 T Processed Shale
Raw Shale Dust
Processed Shale Dust
Processed Shale Dust
Spent HDN Catalyst
Proprietary Solid
Spent HDN Catalyst
Proprietary Solid
Spent HDS Catalyst
Spent Aqueous Caustic
Spent ZnS Catalyst
Spent Fe-Cr Catalyst
Spent Cu-Zn Catalyst
Spent Bauxite Catalyst
Spent Co, Ni-Mo Catalyst
Diatomaceous Earth
Deactivated Carbon
135 T/3-5 yrs
2.4 T/D
15 T/l-3 yrs
50 T/5 yrs
50 T/3 yrs
150 T/2 yrs
10 T/5 yrs
8.25 T/2 weeks
8.25 T/2 weeks
800 T/D
1,200 IBs/day
50 Ibs/day
0- 75 T
60 T
0-130 T
350-475 T
34 T
876 T
7 T
10 T
, 16 T
75 T
2 T
429 T
429 T
292,000 T Green Coke
219 T Lime & Alum Flocculants
9 T Proprietary Coagulant Aid
*Water Excluded.
Source: U.S. Bureau of Land Management. Proposed Development of Oil Shale
Resources by the Colony Development Operation in Colorado. Draft
Environmental Impact Statement. DES-75-62. Washington, D.C.
December 1975. p. 11-48.
-229-
-------
up to 30 years after initial operations.1 The processed shale
may have some commercial value: possible uses of processed
shale are reported in Table 4-82.
Some of the other solid wastes from a surface processing
facility may contain highly toxic substances such as arsenic,
and could result in emission of hazardous materials during
handling, disposal, or reprocessing. Hydrodenitrification
catalyst, for example, may contain 8-1070 sulfur and up to 778
arsenic after exhaustion. Regeneration or safe disposal is
required.2
4.6.1.3d Noise Pollution
Noise levels within a shale processing facility have not
been estimated. In general, retorting and upgrading processes
produce noises similar to those produced during petroleum re-
fining. The level of such noise depends on the specific retorting
technology and upgrading sequence employed on site.3
Solids handling in the retort is probably one of the most
significant noise-producing operations. Other noise sources in
Volley, J. D., W. A. Gathman, and M. L. Owen. Emissions
from Synthetic Fuel Production Facilities. Prepared for U.S.
Environmental Protection Agency.EPA Contract No. 68-02-3535.
Austin, TX: Radian Corporation, September 1977. p. 6.
2Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. pp. 92-94.
3Conkel, N., V. Ellzey, and K. Murphy. Environmental Con-
siderations for Oil Shale Development. Battelle Columbus Lab-
oratories. Prepared for U.S. Environmental Protection Agency.
October 1974. p. 81.
-230-
-------
TABLE 4-82. POSSIBLE USES OF PROCESSED SHALE
A.
B.
C.
D.
E.
F.
G.
H.
I.
J.
K.
L.
Source
Uses
Asphaltic concrete
Mineral wool
Lightweight aggregate - highway use
Lightweight aggregate - structural
concrete and concrete blocks
Rubber filler
Road base and sub-base materials
Drilling mud
Oil well cements
Catalysts
Mineral fillers
Building brick
Portland cement
: Ashland Oil, Inc. and Shell Oil Co.
ment Plan and Related Materials for
Tons/Yr by 1980
300
0
10,000
250,000
1,000
40,000
0
0
0
0
20,000
250,000
571,300
Detailed Develop-
Oil Shale Tract C-b.
Volume I. Prepared for Area Oil Shale Supervisor.
February 1976. p. V-113.
-231-
-------
the retort and upgrading facility include compressors, pumps,
gearboxes, electric motors, and conduits. Administrative and
engineering controls can insure that worker exposure to high
sound pressure levels is within the limits established by the
Occupational Health and Safety Administration. Noise levels
at the boundaries of a shale processing facility are not expected
to be "a nuisance".1'z
4.6.1.3e Occupational Health and Safety
Health and safety hazards associated with retorting and
processing operations have not been extensively examined.
Safety hazards are described as "safety statistics" in the
Hittman report. Using data estimated in Hittman for processing
facilities employing USBM Gas Combustion or TOSCO II retorts,
approximately 0.15 deaths and 15 injuries can be expected to
occur annually at a 50,000 BPD processing facility. Lost working
time can be expected to amount to 15 man-days for a TOSCO II
processing facility to 40 man-days for a facility featuring the
USBM Gas Combustion retort.3
Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. pp.
V-51 to V-54.
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975, pp. IV-172 to IV-174.
3Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supplied by Emerging Technologies.Draft
Report on Task 7 (Oil Shale) and Task 8 (Fluidized Bed Boiler
Combustion). Prepared for Council on Environmental Quality,
National Science Foundation, and Environmental Protection Agency.
Contract EQC 308. Comumbia, MD, May 1974. p. V-27.
-232-
-------
Health hazards for a processing facility are chiefly asso-
ciated with worker exposure to raw and processed shale, shale
oil and shale oil products, and toxic gases. Raw and processed
shale contain silica, inorganic salts, toxic metals, and some
toxic gases (as shown in Table 4-29 for raw shale, and Tables
4-74 through 4-76 for processed shale). Included among the
organics are compounds that are known or suspected animal car-
cinogens, and that may be carcinogenic to man. Worker exposure
to raw and retorted shale particulates has not been reported.
Another potential hazard is exposure to arsenic-bearing dust.
Early awareness of the potential carcinogenicity of shale
oils occurred in the British cotton industry. A high incidence
of scrotal cancer was attributed to direct worker contact with
shale oil lubricants used on spinning machings. Studies of
workers in the Scottish oil shale industry during the same
period did not reveal a particularly high cancer incidence.
Studies of cancer incidence among Estonian shale workers also
reported "normal" incidences of cancer. The National Institute
of Occupational Safety and Health (NIOSH) is currently sponsoring
a study of workers involved in the production of oil from Colo-
rado oil shale.l
Table 4-83 shows a comparison of the relative carcinogenic
potency of several petroleum and oil shale derived materials.
The indices suggest that shale-derived oils are similar to
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976. pp. 156-157.
-233-
-------
TABLE 4-83. COMPARABLE CARCINOGENIC POTENCY
OF COMPLEX MIXTURES
Potency Index Based on
Oil Product Mouse Skin Tests
Industrial Fuel Oil 0.17
Naphthenic Distillate 0.06
Dewaxed Paraffin Distillate from 0.06
Petroleum
Cracked Sidestream 0.26
Coke Oven Coal Tar 0.54
Crude Shale Oil 0.10
Upgraded Shale Oil 0.03
3-methylcholanthrene 1.0
(reference compound)
Note: Index compares carcinogenic potency to a reference compound
For example, upgraded shale is impotent compared to coke
oven coal tar.
Source: Coomes, R. M. "Health Effects of Oil Shale Processing",
9th Oil Shale Symposium, Colorado School of Mines,
April 29-30, 1976.
-234-
-------
petroleum oils of comparable boiling range or intended use.
Hydrotreating or upgrading shale oils reduces the carcinogenic
potency.l
Toxic gaseous emissions produced during retorting/upgrading
operations have been previously described in Section 4.6.1.3a.
Worker exposure to these gases has not been delineated.
4.6.1.3f Odor
Odors from shale retorting and processing include odors
from sulfur oxides, nitrogen oxides, shale oil, and processed
shale. Fumes from various distillates and chemicals are present
from leaks in the upgrading plant. Some of these odors, par-
ticularly those associated with retorting, are similar to the
odors of mined rock and local talus formations.2'3
Some hydrogen sulfide is emitted, particularly during plant
start-up and turnaround when high concentrations of HzS are being
flared. These odors are likely to be confined to the plant
complex.
Inputs and outputs associated with a surface retorting/
processing plant are summarized in Table 4-8A.
^oomes, R. M. "Health Effects of Oil Shale Processing;
9th Oil Shale Symposium, Colorado School of Mines, April 29-30,
1976.
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado, Draft Environmental Impact Statement.DES-75-62.
Washington, B.C.: December 1975, p. IV-48.
3 Based on semi-works operations.
-235-
-------
TABLE 4-84. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A SURFACE RETORTING/PROCESSING PLANT PRODUCING
50,000 BPD OF SHALE OIL PRODUCTS3
Inputs
Manpower
operating
peak construction"
Materials and Equipment
pyrolysis and oil recovery units
gas recovery and treating units
hydrogen production units
gas-oil and naphtha
hydrogenation units
ammonia separation and sulfur
recovery units
delayed coker
foul water stripping units
cement
structural steel
reinforcing bars and piping
valves
Economics0
capital
annualized operating
Water
. TOSCO II
Paraho
Union Bd
Lurgi-Ruhrgas"
Superior"
Land
429 men
3300 men
9000 tons
6000 tons
2000 tons
2000
$827,000,000
$126,000,000
5030 gpm
3130-4150 gpm
2600 gpm
1470 gpm
3500 gpm
1200-1500 acres
Ancillary Energy
. TOSCO II
Paraho
Union Bd
Lurgi-Ruhrgas
7 x 10 8 kwh/yr
4.5 x 108 kwh/yr
6 x 10 8 kwh/yr
3 x 108 kwh/yr
(Continued)
-236-
-------
TABLE 4-84. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A SURFACE RETORTING/PROCESSING PLANT PRODUCING
50,000 BPD OF SHALE OIL PRODUCTS3 (Continued)
Outputs
Air Emissions6
particulates 720-860 Ib/hr
hydrocarbons 950-1000 Ib/hr
NOX 1630-1900 Ib/hr
CO 60-80 Ib/hr
S02 270-350 Ib/hr
C02 580,000 Ib/hr
Water Effluents No direct discharge
Solid Wastes
TOSCO II processed shale 53,000 TPD
catalysts, sludges, etc. 1800 TPD
Noise Pollution
at plant boundaries Negligible
Occupational Health and Safety
deaths 0.15/yr
injuries 15/yr
man-days lost 15/yr
Odors Confined to plant site
alnputs and outputs are based primarily on the TOSCO II process. When
possible, inputs/outputs for other surface retorting technologies are
presented. The plant produces a full range of products, as discussed in
the text.
"Peak for all phases (including mine construction)
C1977 dollars
dWater and energy requirements for Paraho, Union B, Lurgi-Ruhrgas, and
Superior processes describe complexes with less extensive processing of the
product shale oil than specified by TOSCO II developers. Please see the
appropriate sections in the text for a discussion of these differences.
eThese air emissions describe the TOSCO II processing complex; estimates
for emissions from the Union B and Paraho retorts only are found in the
text.
-237-
-------
4.6.2 In-Situ Processing
4.6.2.1 Technologies
An alternative to surface preparation and retorting is
underground or in-situ processing. In-situ processing includes
fracturing the oil shale underground, introducing heat to cause
pyrolysis underground, and conveying the product shale oil to
the surface. As discussed in Section 4.5.3, modified in-situ
processes fracture the oil shale by mining a portion of the
shale, and blasting the remaining shale into the mined out void.
True in-situ processes fracture the oil shale with one of several
non-mining techniques. True in-situ processes proposed by the
Laramie Energy Research Center and TRW, Inc. are discussed in
Sections 4.6.2.la and 4.6.2.Id. Modified in-situ processes
developed by Occidental Oil Shale, Inc. and the Lawrence Livermore
Laboratory are discussed in Sections 4.6.2.1b and 4.6.2.1c. A
summary of other processes and activities is found below.
Reportedly the first attempt at in-situ oil shale process-
ing was undertaken in the 1940's by the Estonians, who obtained
products from a bed of Baltic Kukersite oil shale. During the
same period (1944) the Swedes field tested a process (the
Ljungstrom method) using electrical resistance heating in a
Kvarntorp shale bed. These investigations were discontinued in
the 1950's.1
During World War II, Germany developed a modified in-situ
process for the horizontal retorting of Wurtternburg oil shale.
Shale oil yields seldom exceeded 30% of the Fischer assay.2
C. H. "LERC/ERDA In-Situ Oil Shale Research Program."
In: Technological Overview Reports for Eight Shale Oil Recovery
Processes.Prepared for U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. p. 99.
2
Ibid.
-238-
-------
In the early 1950's, Equity oil field tested several frac-
turing methods for developing in-situ retorts. One method com-
bined hydrofracing (fracturing oil shale with water under pres-
sure) with electrofracing (fracturing oil shale with electrical
discharges) and explosive-fracing. The fractured shale bed was
then retorted by hot natural gas injection. While this (and
other methods) did produce oil, commercial development was not
economically warranted.l Between 1965 and 1967 Equity conducted
experiments in a naturally fractured shale zone deep in the center
of the Piceance Creek Basin in Colorado using hot circulating
methane gas. A -20°F pour point oil was produced, but methane
loss was excessive. Atlantic Richfield reactivated the venture
in 1968 and later (1970) used steam as the heat transfer medium.
The project was terminated in 1971, but may be resumed.2
The Sinclair Oil and Gas Company conducted field studies
in shallow oil shales (up to 300 feet deep) on the southern rim
of the Piceance Creek Basin in 1953-54. A 31° API gravity, 2°C
pour point oil was obtained. Field experiments in deeper shales
were conducted in 1965. Results from and descriptions of these
later efforts have not been published.3
Shell Oil has attempted solution mining of the minerals in
oil shale to create permeability for retorting. No results from
these efforts have been published and Shell appears to have dis-
continued this approach.1* Mobil Oil and Humble Oil have also
McCarthy, H. E. and C. Y. Cha. "OXY Modified In-Situ Process
Process Development and Update." Quarterly of the Colorado School
of Mines. 71(4): 87, October 1976^
2Prien, C. K. "LERC/ERDA In-Situ Oil Shale Research Program."
In: Technological Overview Reports for Eight Shale Oil Recovery
Processes.Prepared for U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. p. 100.
3 Ibid.
^McCarthy, H. E. and C. Y. Cha, op.cit., p. 87.
-239-
-------
conducted field experiments in the Piceance Creek Basin using
hot miscible fluids containing H2S and/or other solubilizing
agents. No results from any of these efforts have been published.1
Dow Chemical conducted tests on an undescribed in-situ con-
cept between 1956 and 1965.2 Also, field tests have been con-
ducted since 1975 on a true in-situ process for retorting low
quality Michigan Devonian oil shales (typical, yields of 10 or
less gallons per ton of rock). The shale formation was frac-
tured with chemical explosives detonated in two wells drilled
60 feet apart. Dow concluded that the detonation produced a
relatively small amount of highly broken rock and left large
volumes of rock untouched even very near the shot. Sustained
combustion of the shale was not attained and the product off gas
had a negligible heating value. No shale oil was recovered.3
Beginning in 1964 CER Geonuclear and a consortium of pri-
vate companies proposed in-situ nuclear rubblization of shale
and subsequent retorting at a Piceance Creek Basin site. A simi-
lar experiment was proposed for the Utah Oil Shales . "* The
Lawrence Livermore Laboratories also considered detonating a
'Prien, C.H. "LERC/ERDA In-Situ Oil Shale Research Program."
In: Technological Overview Reports for Eight Shale^Oil Recovery
Processes.Prepared for U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. p. 100
2Musser, W.N. and J.H. Humphrey. "In-Situ Combustion of
Michigan Oil Shale: Current Field Studies." llth Intersociety
Energy Conversion Engineering Conference Proceedings, v 1,
pp. 341-348, 1976.
3Schora, F.C., P.M. Tarman and H.L. Feldkirchner. "State of
the Art: In-Situ Shale Processing." Hydrocarbon Processing.
March 1977, pp. 127-128.
"Prien, C.H., op.cit., p. 100.
-240-
-------
nuclear device to create a chimney of oil shale rubble.1 Public
opposition to the proposed nuclear experiments forced their can-
cellation.
Geokinetics, Inc. has begun field tests of its true
horizontal in-situ process in the Uinta Basin (about 15 miles
south of the federal lease oil shale tracts). Talley-Frac
Corporation of Mesa, Arizona is considering an in-situ process
with explosive fracturing of the shale formation. Geokinetics
and Talley-Frac are two of four firms selected for cost-share
funding under the Federal Non-Nuclear Energy Act of 1974. The
other two firms are Equity Oil and Occidental Oil Shale.2
In 1975, Western Oil Shale Corporation and a 10-company
consortium proposed a modified vertical in-situ project involving
three underground retorts at a site in the Uinta Basin near
Bonanza, Utah.3 A project involving a 3 year field test program
costing $25 to $30 million has been proposed.1*
4.6.2.la LERC True In-Situ Process
In late 1965, the Laramie Energy Research Center of the U.S.
Bureau of Mines (later LERC/ERDA) began a series of field experi-
ments on in-situ fracturing and retorting of oil shale at sites
1McCarthy, H.E. and C.Y. Cha. "OXY Modified In-Situ Process
Development and Update." Quarterly of the Colorado School of
Mines. 71(4): 88, October 1976.
2Prien, C.H. "LERC/ERDA In-Situ Oil Shale Research Program."
In: Technological Overview Reports for Eight Shale Oil Recovery
Processes. Prepared for U.S. Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976. pp. 100, 108.
3ibid., p. 100.
"*Schora, F.C., P.M. Tarman andH.L. Feldkirchner. "State
of the Art: In-Situ Shale Processing." Hydrocarbon Processing.
March 1977, pp. 127-128.
-241-
-------
near Rock Springs, Wyoming. Various combinations of electro-
fracing, (fracturing with electrical discharges), hydrofracing
(fracturing with water under pressure), and explosive-fracing
were used to fracture the shale formations. Concurrent with the
field tests, LERC conducted simulated in-situ tests using large
shale pieces in a 10-ton batch scale retorts (beginning in 1965)
and a 150-ton retort (beginning 1969). These batch retorts are
still used for evaluation of in-situ engineering parameters.1
Figure 4-27 is a schematic of the LERC process. The process
involves first boring injection and production wells into the
oil shale formation. The shale is then fractured by a combina-
tion of electrofracing, hydrofracing and/or explosive-fracing.
Fracturing occurs along horizontal planes. In LERC's latest
test, retorting is initiated by heating the edge of the shale
formation with the flame formed by combustion of compressed
air and propane. When the temperature is high enough to combust
the carbonaceous residue in the retorted shale, compressed air
alone is injected to the formation. Heat from the combustion
of the carbonaceous reside decomposes the kerogen into gases,
water vapor, and shale oil mist. Pressure from the injection
wells forces the oil along the fracture lines toward the pro-
duction wells, through which the oil is recovered.2
In theory, the process operates like a horizontal retort,
with a retorting zone advancing across the formation ahead of
a combustion zone. The latest test produced oil with a gravity
of 26°API and a pour point of 4°C. The off gas had a net heating
'Prien, C. H. "LERC/ERDA In-Situ Oil Shale Research Program.
In: Technological Overview Reports for Eight Shale^Oil Recovery
Processes.Prepared for U.S.Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976.
2ibid., P. 101-105.
-242-
-------
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-243-
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value of 30-40 Btu/ft3 (267-356 kcal/m3). Oil yields from the
process were low due to poor fracturing of the shale bed.1
4.6.2.1b Occidental Process
The OXY process was conceived by Occidental Petroleum's
in-house research firm, Garrett Research and Development Co., in
the late 1960's. During May of 1972, US Patent 3,661,423,
"In-Situ Process for Recovery of Carbonaceous Materials from
Subterranean Deposits", was assigned to Occidental Petroleum.
Site development for field testing commenced in July 1972 at
the head of Logan Wash, outside of Debaque, Colorado. In the
ensuing months, three research retorts were prepared and ignited.
At the end of 1974, the project was transferred to Occidental
Oil Shale, Inc. upon its establishment as a subsidiary of the
Occidental Oil and Gas Production Division.2'3
The original test program consisted of mining and retorting
three in-situ retorts, each approximately 1,000 square feet in
cross-section and varying in height from 72 to 114 feet. By the
end of the test program, total production from the three retorts
had amounted to ove.r 4,000 barrels of shale oil.1*
'Prien, C.H. "LERC/ERDA In-Situ Oil Shale Research Program."
In; Technological Overview Reports for Eight Shale ^Oil Recovery
Processes.Prepared for U.S. Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976.
2Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor. February, 1977.
p. II-l to 4.
3Shih, C.C. "Occidental Modified In-Situ Process." In:
Technological Overview Reports for Eight Shale Oil Recovery Pro-
cesses. Prepared for U.S. Environmental Protection Agency.
Contract No. 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. December 1976.
"*Ashland Oil, Inc., op.cit., p. II-l to 4.
-244-
-------
Development of the first commercial-size retorts commenced
in early 1975. The first retort (No. 4) measured 120 by 120 feet
in cross-section with a height of 270 feet. This retort was
rubbled August 10, 1975 and ignited on December 10, 1975. The
burn was continued successfully until June 1976, and produced
27,500 gallons of shale oil. Two other commercial-size retorts
are currently being developed.1'2
In late 1976, Occidental Oil Shale entered into a partner-
ship with Ashland Oil for the development of oil shale tract C-b
in Rio Blanco County, Colorado. Site preparations for the develop-
ment of initial test retorts commenced in September 1977. Con-
current with the development of two test retorts, Occidental
plans to begin development of a commercial-scale mining complex.
Prior to full-scale operations four or more retorts will be
operated as a retort cluster to gain operating experience.
Ultimately, 57,000 barrels of shale oil are to be produced daily
from 40 operating retorts. Occidental expects full-scale produc-
tion to begin in 1983.3
The U.S. Department of Energy (DOE) is funding a portion of
Occidental's development activities. The DOE is providing 71%
of some $60.5 million estimated for a 53-month project period.
The first phase of this effort, costing $19.4 million, evaluates
Occidental's two retort designs at the Logan Wash test site in
Garfield County, Colorado. (These retort designs are described
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor.February,1977.
p. II-l to 4.
2Shih, C.C. "Occidental Modified In-Situ Process." In:
Technological Overview Reports for Eight Shale Oil Recovery
Processes.Prepared for U.S. Environmental Protection Agency.
Contract No- 68-02-1881. Denver Research Institute and TRW
Environmental Engineering Division. June 1976.
3Ashland Oil, Inc. op.cit.
-245-
-------
in Section 4.5.3.1). One of these designs will then be demon-
strated at oil shale tract C-b in Rio Blanco County Colorado.
In the Occidental process, air is forced into the operating
retorts by gas blowers located on the surface. These blowers
maintain a negative pressure on the entire retort and gas-gathering
system. The air flows to the retorts from the service shaft
via a network of upper-mine-level air "drifts" or tunnels (as
shown in Figure 4-28). Steam is piped to the operating retorts
from steam boilers located on the surface. The process air
and steam are then mixed in individual feed entries connecting
retorts to the air level drifts.l
Retorting is initiated by heating the top of the rubbled
shale column with the flame formed from the combustion of air
and an external source (propane, natural gas or raw shale oil).
Temporary startup burners are set in the feed entries. These
burners are operated until a temperature is attained that is
high enough to combust the carbonaceous residue in the retorted
shale.2
Flame front movement in the OXY process is shown in Figure
4-28. At the top of the retort, the air/steam feed gas is pre-
heated by hot spent shale. In the combustion zone, oxygen from
the air is reacted with residual carbon and oil at temperatures
of 1300-1500°F. Below the combustion zone is the retorting zone
where hot combustion gases heat the raw shale rubble to a tem-
perature of about 900°F. The kerogen or organic material in
the raw shale is decomposed by the heat to bitumen and ultimately
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan_for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor.February,1977.
p. 111-32.
2 Ibid.
-246-
-------
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to gas, oil, and solid residue. In the vapor condensation zone,
the combustion and retorting gases are cooled by unretorted shale,
and oil and water are condensed.1'2
The product gas, oil, and water flow out the bottom of the
operating retorts. The product gas is collected in lateral
drifts on the mine production level. These drifts are isolated
from fresh air drifts. Each lateral drift is connected to a
totally isolated main-gas-collection drift located below the
production level. This drift conveys all of the product gas to
the surface via the gas shaft.3
At the surface, gas is discharged to the gas treatment units.
Hydrogen sulfide is removed from the gas stream in gas treatment
units by using a Stretford-type or equivalent process. In the Stret-
ford process, hydrogen sulfide is absorbed in an alkaline liquid
and directly oxidized to elemental sulfur by dissolved vanadium
compounds and an oxidation catalyst.1*
The gas leaves the gas treatment units and is burned in
boilers similar to those used in refineries to burn carbon
monoxide. These product gas boilers are specially designed for
firing with low-heating-value gas. All steam requirements- for
the OXY process are met by steam produced from the product gas
boilers. Heat from the combustion of the product off-gas can
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor.February,1977.
p. 111-32.
2Chew, R.T. "Operations and Environmental Considerations,
Occidental Petroleum Corporation In-Situ Operations." In: Science
and Technology of Oil Shale, T.F. Yen (ed.). Ann Arbor Science
Publishers, Ann Arbor, Michigan, 1976, pp. 73-81.
3Ashland Oil, Inc., op.cat., p. 111-33.
* Ibid.
-248-
-------
also be used for electricity generation. (Although the potential
has not been determined, Occidental has suggested that all steam
and electricity requirements of the process can be fulfilled by
combustion of the off gas.) Product gas flaring capacity is
also required for process startup and upset conditions.1
The spent Stretford liquor from the gas treatment units con-
tains suspended particles of elemental sulfur. This spent liquor
is regenerated in an aeration basin by reoxidation of the vanadium
with air. Sulfur floats to the surface of the basin in a foam
which can be skimmed off into a froth basin. From the froth
basin the separated sulfur slurry is pumped through a sulfur
melter into a decanter where liquid sulfur product is withdrawn.
The Stretford liquid from the decanter is then returned to the
oxidizer basin.2
The oil and water from operating retort clusters flow
through a sloped conduit by gravity to a central oil/water collec-
tion sump. Oil and water are then pumped up the production and
service shafts to oil/water separation facilities on the surface.3
On the surface, free water is separated from the product oil
by gravity in a primary separator. The "wet" oil is then pumped
to heater/treaters for secondary water separation. Essentially
water-free oil is withdrawn from the heater/treater and routed
to product storage. Recovered water is routed to treatment
facilities or ponds.1* Crude shale oil withdrawn from the heater/
treater has properties similar to those shown in Table 4-85.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor.February,1977.
p. 111-34.
2ibid., p. 111-33 to 34.
3 ibid., p. 111-33.
"ibid
-249-
-------
TABLE 4-85. PROPERTIES OF CRUDE SHALE OIL PRODUCED FROM THE
OCCIDENTAL IN-SITU PROCESS
Gravity 24-25°API
Specific Gravity (60°F/60°F) 0.9
Pour Point 65-70°F
18-21°C
Viscosity (100°F) 70-116 SUS
Elemental Composition (by weight)
Carbon 84.86%
Hydrogen 11.80%
Nitrogen 1.50%
Oxygen 1.13%
Sulfur 0.71%
C/H Ratio 7.19
Oil Composition (by Volume)
Naphtha, IBP to 400°F 4.6%
Light Distillate, 400-600°F 25.4%
Light Gas Oil, 600-800°F 45.0%
Heavy Gas Oil, 800-1000°F 20.0%
Residium, over 1000°F 5%
References: McCarthy, H.E., and C.Y. Cha. "OXY Modified In-Situ Process
Development and Update." Quarterly of the Colorado School of
Mines. 71(4): 85-100, October 1976.
McCarthy, H.E., and C.Y. Cha. "Development of the Occidental
Modified In-Situ Oil Shale Process" 68th AIChE Annual Meeting,
Los Angeles, California, November 16-20, 1975.
-250-
-------
Oil produced from in-situ retorting has a lower pour point and
viscosity than oils produced from surface retorting, and can be
pipelined without further treatment. Oil produced from in-situ
retorting is also more highly saturated than oils produced from
surface retorting. Crude shale oil produced from in-situ retort-
ing also contains less nitrogen than oils produced from ex-situ
retorting.
Oil yields for the OXY process range from 60 to 70 percent
of the Fisher assay of the rubbled shale. The target shale
interval in oil shale tract C-b contains about 3.0 billion
barrels of oil in place. Of this, about 1.2 billion barrels
are to be recovered by the OXY In-Situ Process. An additional
0.45 billion barrels can be recovered by surface retorting mined-
out shale. Overall resource recovery without surface retorting
amounts to 407» of the oil in place. Overall recovery with surface
retorting amounts to 55% of the oil initially in place.1
4.6.2.1c RISE (Rubble In-Situ Extraction) Process
The RISE process was conceived by the Lawrence Livermore
Laboratory (at the University of California) in the early 1970's.
Large-scale tests to simulate below-ground processing have been
conducted along with a variety of small-scale tests and mathema-
tical modeling programs. The process has not yet been field-
tested. 2
1 Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifi-
cations to the Detailed Development Plan for Oil Shale Tract C-b
Prepared for the Area Oil Shale Supervisor.February,1977.
p. 1-9.
2Schora, F.C., P.M. Tarman andH.L. Feldkirchner. "State
of the Art: In-Situ Shale Processing." Hydrocarbon Processing.
March 1977. pp. 127-128.
-251-
-------
The RISE process is a modified in-situ process conceptually
similar to the OXY process. As reported in Section 4.5.3.1, the
RISE rubble column is created by a continuous mining process
using a modified sublevel caving technique. This procedure pre-
sumably prepares rubble of more uniform size than the OXY process
The proposed mining technique also permits continual measurement
of rubble size. Commercial-size retorts formed by the mining
process are expected to be 150 feet wide by 300 feet long by a
nominal 750 feet high.1 The RISE process is thus more desirable
for thick oil shale formations.2'3'1* A diagram of the proposed
mining technique is found in Section 4.5.3.1.
The rubble column is retorted by heating the oil shale with
a hot gas. This hot gas can be continuously generated by com-
busting a portion of the oil shale with an air stream (as in the
OXY process). It is also possible to heat a gas by external
combustion and circulate it through the oil shale rubble.5
Detailed plans for the development of the RISE process were
approved by the U.S. Department of the Interior in late 1977.
*Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a.
3 Volumes. Prepared for Area Oil Shale Supervisor. May 1977.
2Shora, F.C., P.M. Tarman and H.L. Feldkirchner. "State of
the Art: In-Situ Shale Processing." Hydrocarbon Processing.
March 1977. pp. 127-128.
3Rothman, A.J. "Research and Development on Rubble In-Situ
Extraction of Oil Shale (RISE) at Lawrence Livermore Laboratory.1
Colorado School of Mines Quarterly. 70(3) 159-78 (1975).
"Lewis, A.E., et al. "Rubble In-Situ Extraction (RISE): A
Proposed Program For Recovery of Oil From Oil Shale." Lawrence
Livermore Laboratory. UCRL-51768. March 5, 1975. p. 26.
5ibid.
-252-
-------
Initial development of the Rise process will be undertaken
by Gulf Oil Corporation and Standard Oil Company (Indiana) on
oil shale tract C-a in Rio Blanco County, Colorado. Commercial
operations are tentatively expected to begin in 1987.l
Preliminary development plans anticipate the surface pro-
cessing of mined-out shale. This development option is discussed
further in Section 4.6.3, Modified In-Situ and Surface Processing.
4.6.2.Id In-Situ Retorting with Mineral Recovery
A novel process for the in-situ recovery of oil and minerals
from Piceance Creek Basin (Colorado) oil shale has been proposed
by the Energy Systems Group of TRW, Inc. The process is designed
to recover nahcolite, alumina, and shale oil from the salt-
capped shale deposit at the center of the Piceance Creek Basin.
The shale formation at the center is gas tight, free of aquifers,
and rich in dissolved minerals, but lies beneath a thick over-
burden. Although the process has not been field-tested, small-
scale laboratory data indicate that the process is conceptually
feasible. TRW has proposed a development program to assess the
commercial feasibility of the process.2
*Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detialed Development Plan for Oil Shale Tract C-a,
3 Volumes.Prepared for Area Oil Shale Supervisor.May 1977.
2Cowles, J. 0. and E. M. Boughton. "In-Situ Recovery of
Oil and Minerals from Piceance Creek Basin Oil Shale." llth
Inter-society Energy Conversion Engineering Conference Proceedings
1976.VI, pp. 336-340.
-253-
-------
The TRW process comprises several steps: solution mining,
retorting, alumina extraction, and residue combustion. Solution
mining of nahcolite (NaHCOa) is accomplished by injecting steam
into the top of the shale formation. Condensed water saturated
with sodium salts is then collected at the bottom of the forma-
tion. After nahcolite removal, the shale deposit is full of
heated and rubblized oil shale with about 20 percent intercon-
nected void space.1'2
Hot gas is then forced into the shale formation to retort
the kerogen in the oil shale. Lighter retorting products are
swept to the surface in the vapor phase. Heavier liquids
accumulate at the bottom of the retorted zone and are subse-
quently pumped to the surface.3
At the temperatures required to decompose the kerogen,
natural dawsonite (NaAL(OH)2C03) is converted to a soluble form
of alumina (AL203'2H20). The next process step (following
retorting) is extracting this soluble alumina from the residual
shale rubble. The alumina-rich solution is then brought to the
surface. A1(OH)3 is precipitated by pumping carbon dioxide
Bowles, J. 0. and E. M. Boughton. "In-Situ Recovery of Oil
and Minerals from Piceance Creek Basin Oil Shale." llth Inter-
society Energy Conversion Engineering Conference Proceedings.
1976. VI, pp. 336-340.
2Beard, N. T. "A Process for Solution Mining Nahcolite",
U.S. Patent 3779602 and "Method of Producing Hydrocarbons from
an Oil Shale Formation:, U.S. Patent 3759574. As cited in: "In-
Situ Recovery of Oil and Minerals from Piceance Creek Basin Oil
Shale." llth Intersociety Energy Conversion Engineering Confer-
ence Proceedings.1976. VI.pp. 336-340.
3Cowles, J. 0. and E. M. Boughton, op.cit.
-254-
-------
into the saturated solution. The alumina extraction step has
been demonstrated in the laboratory by the USBM.1'2
The leached, retorted zone will contain some residual oil,
char and unretorted kerogen. A final combustion step may provide
enough low grade heat to supply all other process energy needs,
and possibly some carbon dioxide for the precipitation of alumina.3
4.6.2.2 Input Requirements
This section reports inputs required for retorting and pro-
cessing operations at a modified in-situ facility. Detailed
estimates of the various manpower, equipment, water, land, and
energy requirements are largely based on data reported by
Occidental Oil Shale in the 1977 Modifications to the Detailed
Development Plan (MDDP) for Oil Shale Trace C-b. Estimates of
the capital requirements and annualized operating costs are
likewise based on data reported by Occidental in the MDDP. The
inputs reported for the OXY process are probably similar to
those inputs required for other modified in-situ processes (e.g.,
the RISE process). While Occidental's plan was specifically
contrived for development on tract C-b, input requirements for
facilities at other locations are probably not significantly
different.
Bowles, J. 0. and E. M. Boughton. "In-Situ Recovery of Oil
and Minerals from Piceance Creek Basin Oil Shale." llth Inter-
society Energy Conversion Engineering Conference Proceedings.
1976. VI, pp. 336-340.
2Smith, J. W. and N. B. Young. "Dawsonite: Geochemistry,
Thermal Behavior and Extraction from Green River Oil Shale."
Quarterly of the Colorado School of Mines. 70(3): 69-94. As
cited in: Cowles, J. 0., op.cit.
3Cowles, J. 0. and E. M. Boughton, op.cit.
-255-
-------
The inputs presented below describe a modified in-situ
process simply disposing of raw mined-out shale. Inputs required
for a modified in-situ process with the surface retorting of
mined-out shale are discussed in Section 4.6.3.2.
4.6.2,2a Manpower
Manpower requirements for the full scale operation of an
in-situ facility are reported in Table 4-86. These requirements
include those personnel required for retorting and processing
operations. Manpower requirements for mining operations are
reported in Section 4.5.3.2, Mining for In-Situ Processing. The
manpower requirements are those reported by Occidental for
57,000 bbl/d facility.
The manpower requirements in Table 4-86 relate only those
requirements for full-scale commercial operations. Occidental
has not reported skill breakdowns for the construction personnel
required to establish the site prior to commercial operation.
However, construction manpower requirements have been included
in the total program manpower requirements previously shown
in Figure 4-14. The manpower requirements in Figure 4-14 assume
a three-stage development of the in-situ complex. The first
stage involves the construction and operation of initial'test
retorts. The second stage includes construction and operation
of one or two retort clusters to train operating personnel
and confirm operating techniques. Construction of the full-scale
complex also begins in this stage. The final stage is the full-
scale commercial operation of the in-situ facility. After
initial demonstration of the OXY process, the development stages
may be shortened to take advantage of previous developments.
-256-
-------
TABLE 4-86. MANPOWER REQUIREMENTS FOR IN-SITU
RETORTING AND PROCESSING OPERATIONS
PRODUCING 57,000 BPD
PERSONNEL NUMBER REQUIRED
Process Operators
Operations Superintendent 1
Assistant Superintendent 1
Chief Supervisor (Underground) 1
Chief Supervisor (Surface) 1
Shift Supervisor (Underground) 4
Shift Supervisor (Surface) 4
Operations Engineer 2
Area Engineer 6
Safety Supervisor 1
Laboratory Supervisor 1
Chemist 1
Laboratory Technician 8
Chief Clerk 1
Assistant Clerk 1
Secretarial/Clerical 10
Lead Operator 36
Operator 72
Construction/Startup Operator 67
Maintenance and Utilities Personnel
Machinist 6
Electrician 20
Pipe Fitter 12
Mechanics-Auto 15
Sheet Metal 15
Instrument Technician 14
Welder 20
Tool Crib 8
Laborers 20
Mobile Equipment 10
Bus Driver 45
Area Maintenance Mechanic 70
Boiler Plant Operator 4
Warehouseman 12
Machine Shop Foreman 1
Electrical Foreman 1
Pipe Fitter Foreman 1
Instrument Foreman 1
Welder Foreman 1
Area Maintenance Foreman 1
Warehouse Foreman 1
Machine Shop Assistant Foreman 1
(Continued)
-257-
-------
TABLE 4-86. MANPOWER REQUIREMENTS FOR IN-SITU
RETORTING AND PROCESSING OPERATIONS
PRODUCING 57,000 BPD (don't)
PERSONNEL NUMBER REQUIRED
Maintenance and Utilities Personnel (Cont'd.)
Electrical Assistant Foreman 1
Pipe Fitter Assistant Foreman 2
Instrument Assistant Foreman 4
Welder Assistant Foreman 1
Area Maintenance Assistant Foreman 1
Warehouse Assistant Foreman 1
Security Chief 1
Security Guards 24
Instrument Superintendent 1
Instrument Engineer 2
Clerks 10
General Administration and Support Personnel 16
TOTAL 561
Reference: Ashland Oil, Inc. and Occidental Oil Shale, Inc.
Supplemental Material to Modifications to Detailed
Development Plans for Oil Shale Tract C-b, prepared
for Area Oil Shale Supervisor, July 21, 1977.
-258-
-------
4.6.2.2b Materials and Equipment
Detailed materials and equipment requirements have not yet
been prepared by Occidental. Facilities required for operation
of the in-situ complex include: gas treatment unit(s), product
gas boilers, oil/water separation equipment, blowers, water
treatment facilities, and product oil storage tanks. Gas treat-
ment units are required to remove hydrogen sulfide from the pro-
duct off-gas. The product off-gas is then burned in boilers
similar to those used in refineries to burn carbon monoxide.
Oil/water separation includes gravity separation and secondary
separation. Free water is separated from the product oil by
gravity in a primary separator. The "wet" oil is then pumped
to heater/treaters for secondary separation. Gas blowers main-
tain the flow of air and product gas through the retort. Various
water treatment facilities are required to treat the various
wastewater streams in the process (as described in Section
4.6.2.3b).1
4.6.2.2c Economics
Preliminary capital cost estimates for a 57,000 bbl/d shale
oil complex are shown in Table 4-87. These costs have been
reported by Occidental in the MDDP for oil shale tract C-b, and
should not be misconstrued as definitive cost estimates. The
estimates are based only on preliminary engineering design and
process scheduling. The costs shown in Table 4-87 do not include
interest accrued during construction or deferred capital expen-
ditures. The total installed equipment costs include those costs
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor.February,1977.
-259-
-------
TABLE 4-87.
CAPITAL COST ESTIMATES FOR
AN IN-SITU OIL SHALE COMPLEX
PRODUCING 57,000 BPDa
COMPONENT COST
COST
Oil and Gas Processing
Steam Generation Plant
Water Treatment Plant
Gas Treatment Plant and Heater Treater
Other Major Equipment
Other Materials
Taxes, Spare Parts, and Miscellaneous
Field Indirects
Subtotal
General Facilities
Emergency Generating Equipment,
Package Boiler, Hoist, Cranes,
Air Compressors, Storage Tanks,
and Miscellaneous Equipment
Direct Materials, Concrete,
Electrical Insulation, Roads,
and Other Civil Work
Other Direct Costs, Spare Parts,
Taxes, etc.
Field Indirects
Subtotal
TOTAL INSTALLED EQUIPMENT0
Contractors Engineering, Home Office,
Fees, Working Capital, Contingency
TOTAL INVESTMENT
$ 21,060,000
36,250,000
10,200,000
15,568,000
12,405,000
3,036,000
4.519.000
$103,038,000
9,532,000
61,088,000
2,984,000
10.378.000
$ 83,892,000
$323,716,000
118,893,000
$442,609,000
Costs are in 1977 dollars and are those reported by Occidental
Costs include costs for mine equipment
Reference: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications
to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor. February, 1977.
p. 1-11.
-260-
-------
reported in Section 4.5.3.2 for in-situ mining. Miscellaneous
capital requirements (i.e., costs for general facilities, in-
directs, and working capital) for the entire in-situ complex
are also included in Table 4-87.l The total investment (including
mine facilities) for an in-situ facility producing 57,000 bbl/d
is shown as $442,609,000.
Operating costs estimates for the OXY process were not
reported in the MDDP or in the Supplement to the MDDP. However,
data reported in the MDDP (and its supplement) can be used to
contrive preliminary cost estimates. These estimates are shown
in Table 4-88, and are based on preliminary, incomplete data.
The labor costs are estimated from the labor requirements reported
by Occidental in the Supplement to the MDDP. Utilities' costs
are estimated from the power and fuel requirements reported in
the MDDP and its supplement. All other costs are estimated as
percentages of the capital or labor costs. Total annualized
retorting and processing costs are shown as $76,000,000.
4.6.2.2d Water
A modified in-situ process requires water for dust control,
steam and/or power generation, miscellaneous utilities, sanitary
use, and revegetation. Water required for dust control is more
closely associated with mining operations and is discussed in
Section 4.5.3.2. Similarly, water required for the revege-
tation of mined-out shale is discussed in Section 4.7, Recla-
mation. The other major uses of water are described below.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to the Detailed Development Plan for Oil Shale Tract C-b,
Prepared for the Area Oil Shale Supervisor.February 1977.
p. 1-11.
-261-
-------
TABLE 4-88. ANNUALIZED OPERATING COSTS FOR
AN IN-SITU OIL SHALE COMPLEX
PRODUCING 57,000 BPDa
COMPONENT COST
Direct Costs
Process Operators $ 3,400,000;'
Maintenance and Utilities Personnel 5,000,000
General Administration and Support
Personnel 240,000°
$ 8,600,000
Operating Supplies 1,900,000*:
Maintenance Materials 9,400,000
Utilities
Electricity 27,000,000e
Waterf
Surface Fuel Requirements
Fixed Costs
Depreciation 19,000,000.
Taxes and Insurance 5,600,000
Plant Overhead 4.300,000-*
TOTAL $76,000,000 $3.65/bbl
3Costs are in 1977 dollars
Calculated @ $20,000/man-year for staff, and @ $15,000/man-year for labor
CCalculated @ 1% of fixed capital costs
Calculated @ 5% of fixed capital costs
Calculated @ $0.04/kwh
Water costs have not been specified and are probably not significant. Power
costs include power costs for water treatment
g
"Surface fuel requirements are unknown but are probably insignificant
Calculated @ 10% of fixed capital costs
Calculated @ 3% of fixed capital costs
^Calculated @ 50% of total labor costs
References: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications
to the Detailed Development Plan for Oil Shale Tract C-b.
Prepared for the Area Oil Shale Supervisor. February, 1977.
p. II-l to 4.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supplemental
Material to Detailed Development Plan Modifications for Oil Shale
Tract C-b. Prepared for Area Oil Shale Supervisor, July 21, 1977.
-262-
-------
Major water requirements for a 57,000 bbl/d facility are
summarized in Table 4-89. Occidental's MDDP reports the total
water requirements for the in-situ facility as 2500 gpm. Thus,
the production of 1 barrel of shale oil requires about 1.5
barrels of water. Occidental recently, however, reported that
the production of 1 barrel of oil may require 1.8-1.9 barrels
of water. Total requirements for a 57,000 BPD facility would
then be 3000 to 3200 gpm.1 Most of the water is required for
steam generation. For Occidental's proposed 57,000 bbl/d
facility, steam generation water requirements amount to 1800 gpm.
About 300 gpm are required for miscellaneous utilities (primarily
cooling water). Water requirements for personnel are not sig-
nificant. 2
Groundwater seepage in the underground complex is expected
to supply most of Occidental's process water needs. For example,
groundwater can fulfill steam generation water requirements after
undergoing 1) filtration, 2) addition of chemicals for scale
control, 3) reverse osmosis, and 4) deionization and deaeration.
Filtered and treated groundwater can also be used to meet utility
water requirements. The desirability and availability of ground-
water for these uses are dependent on the site of the in-situ
development.3
Another source of process water is the return condensate
from miscellaneous utilities. Most of the 300 gpm required for
miscellaneous utilities can be recycled for reuse. Net process
makeup water requirements have been estimated as 100-500 gpm."
Conversation with Ms. Marnie Talbert, Occidental Oil Shale,
Inc. October 13, 1977.
2Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C"-b~]
Prepared for Area Oil Shale Supervisor.February, 1977.
pp. 111-43 to 45, Figure III-J.
3 Ibid.
"Ibid.
-263-
-------
TABLE 4-89. SUMMARY OF WATER REQUIREMENTS FOR A MODIFIED IN-SITU
FACILITY PRODUCING 57,000 BBL OF SHALE OIL PER DAY
Steam Generation 1800 gpma
Miscellaneous Utilities 300 gpm
Dust Control 450 gpm°
TOTALS 2500 gpmd
a
Based on 850,000 Ibs of steam produced per hour, with a boiler
water blowdown of 100 gpm.
Primarily cooling water.
°Associated with mining operations; described in Section 4.5 . 3.2.1
References: Ashland Oil, Inc. and Occidental Oil Shale, Inc.'
Modifications to Detailed Development Plan for Oil
Shale Tract C-b~Prepared for Area Oil Shale
Supervisor.February, 1977. pp. 111-43 to 45,
Figure III-J.
-264-
-------
4.6.2.2e Land Requirements
Occidental has estimated the surface land areas disturbed by
an in-situ development. In the development of a 57,000 bbl/d
facility, approximately 80 acres are required for surface
processing facilities.1 The additional land areas required for
shale disposal, mine development and road construction are
delineated in Section 4.5.3, Mining for In-Situ Processing.
4.6.2.2f Ancillary Energy Requirements
Ancillary energy requirements for an in-situ complex have
been reported by Occidental and are tabulated in Table 4-90.
Electricity requirements for retorting/processing operations
amount to approximately 6.7xl08 kwh/year. These estimated
requirements assume that no electric power is generated on-site.
(Although the potential has not been determined, Occidental has
suggested that all steam and electricity requirements can be
fulfilled by combustion of the product off-gas.) More than half
of the power demands are associated with the operation of the
gas blowers. Sixty to 70 percent of the energy of the rubbled
shale is recovered as crude shale oil. Forty percent of the
energy of the target shale interval is recovered as crude shale
oil.2
4.6.2.3 Outputs
This section reports the various outputs associated with
the operation of a modified in-situ facility. Discussions of
air emissions, water effluents, solids wastes, and noise pollution
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C-b.Pre-
pared for Area Oil Shale Supervisor.February, 1977.p. 1-13.
2Ibid., p. 1-9.
-265-
-------
TABLE 4-90.
ANCILLARY ENERGY REQUIREMENTS FOR
AN IN-SITU OIL SHALE FACILITY
PRODUCING 57,000 BPD
Category
Power Requirement
Energy Usage
Electricity
Product Oil/Water Pumps 6,400 hp
Gas Treatment 12,000 hp
Product Oil Treatment 4,000 hp
Steam Generation 800 hp
Process Blowers 66,800 hp
Water Treatment 6,200 hp
Sulfur Recovery 2,000 hp
General Services
TOTAL
4.2x107
7.8xl07
2.6x107
O.SxlO7
4.4x108
4.4xl07
1.3xl07
kwh/year
kwh/yeara
kwh/yeara
kwh/yeara
kwh/year
kwh/yearc
kwh/year
2.1x107 kwh/year
6.7x108 kwh/yeara'b
Diesel Fuel
9. T- i
Assumes operation 8760 hours/year; 1 hp * 7.457x10 kw.
Figure represents electricity directly used in retorting/processing.
Gross power plant energy requirements can be estimated by using power
plant heat rate of 9750 Btu/kwh (power generation efficiency of 35%).
£
Surface fuel requirements are unknown.
Reference: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications
to Detailed Development Plan for Oil Shale Tract C-b. Prepared
for Area Oil Shale Supervisor. February, 1977. p. 111-39.
-266-
-------
ar>e largely based on information reported by Occidental in the
MDDP and its supplement. Although Occidental's data are specific
to oil shale tract C-b (in Rio Blanco County, Colorado), outputs
for in-situ development at other locations are probably very
similar. However, the environmental impacts from these ouputs
do vary from site to site. Outputs for mining and shale disposal
are described in Section 4.5.3.3.
4.6.2.3a Air Emissions
Air emissions from retorting/processing operations at a
modified in-situ complex originate from steam generation,
shale oil storage, gas treatment, and wastewater treatment.
Emissions from these operations are described below. Quantita-
tive estimates are available only for emissions from steam gener-
ation and shale oil storage.
As described previously, product gas from retorting first
undergoes H2S removal in a Stretford-type treatment unit. The
treated gas is then combusted in the fireboxes of the product
gas boilers to generate steam. Emissions from the steam plant
are summarized in Table 4-91. Estimates for the emissions of
non-criteria pollutants have been reported only for mercury and
arsenic. Retorting temperatures and conditions are not severe
enough to volatilize most metals and heavy elements.1
Particulates emitted from the steam plant contain the same
elements and compounds found in retorted shale. Unfortunately,
analyses of the elemental and mineral content in in-situ retorted
shale have not been reported. Analyses of the element
Crawford, K.W. , et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency.ContractTlfo. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
-267-
-------
TABLE 4-91. RETORTING/PROCESSING EMISSIONS FROM AN IN-SITU
OIL SHALE COMPLEX, LB/HRa
Pollutant
Particulate
SO 2
CO
THC
NOX
Hgd
Ase
C02
Steam Plant Flue Gas >C
<74
174
84
15
588
2
_
2,400,000f
Tank Storage
-
-
-
103
-
_
-
a
In-situ complex produces 57,000 barrels of shale oil per day.
The steam plant flow rate is 3454 MM scfd.
£
The Stretford unit(s) preceding the steam plant are assumed to control
levels in the gas stream entering the steam plant to 15 ppmv.
The concentration of mercury in the steam plant flue gas is .027 ppm
(by volume).
*he concentration of arsenic in the steam plant flue gas is .52 ppm
(by weight).
Estimated from combustion of carbon compounds in flue gas, combustion
of carbon residue on processed shale, and decomposition of dolomite.
Presented as an order-of-magnitude estimate only.
References: Ashland Oil, Inc. and Occidental Oil Shale, Inc. Supplemental
Material to Detailed Development Plan Modification for^Oil
Shale Tract C-b. Prepared for Area Oil Shale Supervisor.
July 21, 1977.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifications
to Detailed Development Plan for Oil Shale Tract C-b. Prepared
for Area Oil Shale Supervisor. February, 1977.
-268-
-------
concentrations in TOSCO II surface-retorted shale have been
reported and are shown in Table 4-74. Element concentrations
of in-situ retorted shales probably approximate those shown for
surface-retorted shale. These concentrations are site-specific,
depending on the composition of the raw shale being retorted.
The mineral constituents of TOSCO II surface-retorted shale are
shown in Table 4-75. The same constituents are probably found
in in-situ retorted shale, and thus, in particulates emitted
from the steam plant.
Polycyclic aromatic hydrocarbons are also found in particu-
late emissions from the steam plant. Those PAH detected in TOSCO
II surface-retorted shale are reported in Table 4-76. The same
PAH are likely to be found in in-situ retorted shale and in
particulate emissions from the steam plant. All of the com-
pounds in Table 4-76 are known or suspected animal carcinogens
and may be carcinogenic to man. Concentrations of these com-
pounds have not been reported.
Hydrocarbon emissions from the product shale oil storage
tanks are shown in Table 4-91 as 103 Ibs/hr.
Other emissions originate from the gas and wastewater treat-
ment systems. Likely emission sources from the Stretford gas
treatment units are the aeration basin, the sulfur separation
tank, and the sulfur melter. Particulates and particles of
elemental sulfur are possible emissions from the aeration basin.
Oxidized and reduced vanadium compounds are also potential air
pollutants. Emissions from the sulfur separation tank and the
sulfur melter are largely particles of elemental sulfur. Sulfurous
gases like hydrogen sulfide, carbon disulfide, and carbonyl sulfide
are also potential pollutants.
-269-
-------
Evaporation ponds are possible sources of the volatile
compounds found in the various wastewaters. Atmospheric emis-
sions from evaporation ponds have not been characterized, but
are likely to contain ammonia and hydrogen sulfide.1
Other emissions originate from oil/water separators. These
emissions can be minimized by enclosing all components of the
oil/water separation system.
4.6.2.3b Water Effluents
Water effluents from retorting/processing operations include
water co-produced with the shale oil, cooling tower, boiler,
and gas treatment blowdown waters, raw water treatment system
wastewater, sanitary wastewaters, and underground leachate from
retorted shale. Each of these water effluents is discussed below.
Water co-produced with shale oil comprises both free and
bound water. Free water is easily separated from shale oil by
decanting. Bound water is physically bound with the product
oil in an emulsion, and is separated from the oil in heater/
treaters. Occidental has estimated the amount of water co-produced
with the shale oil to be 770 gpm for a 57,000 bbl/d facility.
This amounts to about 0.50 barrels of water for each barrel of
oil produced. The individual amounts of free and bound water
constituting the 770 gpm have not been estimated. Approximate
compositions of bound and free water are shown in Table 4-92.
Current Occidental plans1 anticipate disposing of the co-produced
Crawford, K.W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S. Environmental Protection Agency. Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
-270-
-------
TABLE 4-92. APPROXIMATE COMPOSITIONS OF FREE AND BOUND
WATER CO-PRODUCED WITH SHALE OIL, MG/L
Anions
Carbonates
Bicarbonates
Sulfate
Sulfide
Chloride
Gross Parameters
BOD
COD
TOC
O&G
Total Solids
Phenols
pH
Free
1 >2
6,300
26,100
1,300
4,050
5,900
30,600
8.0-9.8
Bound3'1*
Cat ions
Calcium
Magnesium
Sodium
Potassium
Ammonium
20
160
650
40
12,200
10-50
50-150
250-650
30-40
4-200
0-100
100-3000
600-5000
100-14,000
1,000-20,000
6-230
2,000-3,000
0-210
8.0-10.2
Trace Elements
Arsenic
Cobalt
Boron
Vanadium
Titantium
Iron
Molybdenum
Tin
Rubidium
Strontium
Nickel
0.3
0.4
0.3
1.2
0.2
0.5
0.5
0.1
0.2
0.1
0.3
-
-
-
-
-
-
-
-
*TRW Environmental Engineering Division and Denver Research Institute.
An Evaluation of Control Technologies for Treating Oil Shale Wastewaters.
Prepared for U.S. Environmental Protection Agency. Contract No. 68-02-1881.
May 1977.
2Based on analyses of retort water from Laramie Energy Research Center's
10-ton simulated in-situ retort.
3TRW, op.cit., p. 6.
"*Bases not reported.
-271-
-------
water in lined evaporation ponds. Extensive treatment would be
required to upgrade the co-produced water for reuse.1
Boiler water blowdowns are necessary to avoid the buildup
of dissolved solids which can lead to scaling in the boiler.
Occidental has estimated boiler water blowdowns for a 57,000
bbl/d facility to be 100 gpm (160 acre ft/year). Typical
characteristics from boiler water blowdown are shown in Table
4-93. The boiler blowdown wastewater is normally routed to
an evaporation pond.2
The composition of typical cooling tower blowdown waste-
waters are presented in Table 4-93. Volumes of wastewater from
cooling tower blowdowns have not been reported.
An undetermined quantity of liquid must be withdrawn from
the Stretford gas treatment units as blowdown. This liquid
contains dissolved and suspended particulates, vanadium compounds,
elemental sulfur, and sulfur compounds. Required treatment
techniques have not been specified, but probably include chemical
treatment and filtration with disposal in an evaporation pond.
Volumes of wastewaters originating from raw water treatment
systems have not been estimated. These wastewaters include
backwash water from filtration, and blowdown from zeolite soften-
ing systems.3 Characteristics of these streams have not been
reported.
!Ashland Oil, Inc. and Occidental Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C-b.
Prepared for Area Oil Shale Supervisor.February,1977.
pp. 111-43 to 45, Figure III-J.
2Ibld.
3Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from^Oil Shale Development.Prepared for
U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
-272-
-------
TABLE 4-93. CHARACTERISTICS OF COOLING TOWER
AND BOILER WATER SLOWDOWNS
Parameter
Total Solids
Suspended Solids
Total Organic Carbon
PCK-P
Cr
Zn
Fe
Concentration, mg/Jl
Cooling Tower Slowdown Boiler
500-1500 1,
10-50
5-15
5-15
50-300 0
20-40 0
0.10-1.5
Water Slowdown
000-10,000
10-50
10-50
5-15
.05-1.0
.10-0.5
0.2-1.0
Source: TRW Environmental Engineering Division and Denver Research
Institute. An Evaluation of Control Technologies for Treating
Oil Shale Wastewaters. Prepared for U.S. Environmental Protection
Agency. Contract No. 68-02-1881. May 1977.
-273-
-------
Sanitary wastewaters can be treated in package treatment
units on-site, with recovery of the liquid effluent for reuse.
Expected volumes of these sanitary wastes have not been reported
but are probably insignificant.1
A potential water pollution problem is the underground
leaching of retorted shale. Inorganic salts, toxic metals, and
some toxic organics (including carcinogens) are contained in the
retorted shale and can be potentially leached from the shale.
(Tables 4-74, 4-75, and 4-76 report the chemicals found in TOSCO
II surface-retorted shale. In-situ retorted shale will have some-
what different characteristics because of the higher in-situ com-
bustion temperature. The actual characteristics of in-situ retorted
shale have not been reported.) Occidental believes that leaching
problems can be avoided by. deliberate leaching of the shale fol-
lowed by treatment and containment of the leachate; diversion of
potential leachate by properly designing the outer areas of the
mined area; or isolating retorted shale from potential leachate.2
None of these techniques has been extensively tested.
4.6.2.3c Solid Wastes
No information has been reported on the quantity of solids
generated from in-situ oil shale retorting/processing. Possibly
the largest volumes of wastes are those of water and wastewater
treatment sludges. These streams include chemical and lime
sludges from the upgrading of water for process use. The sludges
can be ponded for evaporation and/or chemically neutralized, and
either combined with the mined-out shale, conveyed to the spent
retorts, or disposed of offsite.3 The disposal of mined-out
Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modifica-
tions to Detailed Development Plan for Oil Shale Tract C-b. Pre-
pared for Area Oil Shale Supervisor. February, 1977. p~! 111-45
2lbid., p. V-4.
3lbid., p. 111-45.
-274-
-------
shale was discussed in Section 4.5.3.3.
Sanitary wastes can be treated onsite, with recovery of
the liquid effluent for reuse. The solids can then be discarded
with other process solid wastes.1
4.6.2.3d Noise Pollution
Noise at in-situ surface facilities originates from those
sources shown in Table 4-94. Process blowers and steam boilers
generate the highest levels of uncontrolled noise. Noise levels
off-site should not be significantly affected by the in-situ
operation.
Administrative controls can restrict the length of time
workers are exposed to excessive noise. Worker exposure to
noise can also be reduced by enclosing major noise sources
(e.gr., enclosing the process blowers). Other noise control
measures are described in the literature. Surface noises
associated with mining operations are discussed in Section
4.5.3.3.
4.6.2.3e Occupational Health and Safety
Health and safety hazards associated with retorting and
processing operations at an in-situ complex have not been
extensively examined. Safety hazards at the in-situ complex
are similar to some hazards found at refineries. Health
hazards are chiefly associated with worker exposure to raw
1 Ashland Oil, Inc. and Occidental Oil Shale, Inc. Modi-
fications to Detailed Development Plan for Oil Shale Tract
C-b.Prepared for Area Oil Shale Supervisor.February,T977
p. 111-45.
-275-
-------
TABLE 4-94. NOISE LEVELS ENCOUNTERED BY NON-MINING PERSONNEL*
u c
Noise Source Sound Level, dBA '
Process Blowers 95-110
Steam Generation Plant 95-103
Gas Treatment Plant 85-95
Water Treatment Facilities 80-93
Product Oil Treatment Facilities 70-80
Sulfur Recovery Facilities 70-80
a
Assumes acoustically untreated equipment.
At 50' from noise source.
^
Preliminary sound level estimates.
Noise levels estimated by M. Lee Wilson (Radian Corporation)
based on Radian noise files and from American Petroleum
Institute, Guidelines on Noise, Medical Research Report No.
EA7301, 197 J:
and processed shale, shale oil, and toxic gases. These hazards
are the same as those described in Section 4.6.1.3 for surface
retorting.
4.6.2.3f Odors
Odors from shale retorting and processing include odors
from sulfur oxides, nitrogen oxides, shale oil, and processed
shale. These odors are described in Section 4.6.1.3.
The inputs and outputs associated with a modified in-situ
plant are summarized in Table 4-95.
-276-
-------
TABLE 4-95. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH
A MODIFIED IN-SITU PROCESSING PLANT PRODUCING
57,000 BPD OF SHALE OIL
Inputs
Outputs
Manpower
operating
peak construction0
Materials and Equipment
gas and water treatment units
oil/water separators
product gas boilers
Economies'5
capital
annualized operating
Water
Land
Ancillary Energy0
Air Emissions
particulates
hydrocarbons
* NOX
CO
S02
C02
Water Effluents
Solid Wastes
Noise Pollution
at plant boundaries
Occupational Health and Safety
Odors
at plant boundaries
561 men
2900 men
$306,000,000
$76,000,000
2500 gpm
80 acres
6.7 x 10s kwh/yr
74 Ib/hr
120 Ib/hr
588 Ib/hr
84 Ib/hr
174 Ib/hr
2,400,000 Ib/hr
No direct discharge
Minor
Negligible
Unknown
Negligible
aPeak for all phases (including mine construction)
b!977 dollars
Potentially supplied on-site
-277-
-------
4.6.3 Modified In-Situ Processing with Surface Processing
of Mined Shale
4.6.3.1 Technology
An alternate strategy for the recovery of oil shale is the
combination of modified in-situ retorting with surface retorting
of the shale mined to form the in-situ retorts. This strategy
has been selected by developers of oil shale tract C-a, and may
be chosen by developers of oil shale tract C-b. This secf'^n
describes the combined application of modified in-situ and ,- ur-
face retorting technologies as envisioned by the developers of
oil shale tract C-a (Gulf Oil Corporation and Standard Oil
Company of Indiana). Conceptual design of the processing
facility envisions a shale oil product suitable as a refinery
feed. Other upgrading alternatives exist.J
Since both retorting technologies have been discussed pre-
viously, the following discussion is only a summary description
of the combined retorting development. The modified in-situ
process selected by the developers of tract C-a is based on the
RISE (Rubble In-Situ Extraction) process, previously described
in Section 4.6.2.1c. Gulf Oil and Standard have tentatively
selected the TOSCO II process for surface retorting. TOSCO II
retorting technology has been described in Section 4.6.1.la.2
Figure 4-29 is a block flow diagram showing the flow of
major streams through the shale processing facility. After
developmental mining (described in Section 4.5.3.1), air and
:Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols
Prepared for Area Oil Shale Supervisor.May 1977.
2 Ibid.
-278-
-------
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steam are injected into the modified-in-situ (MIS) retorts. In-
situ retorting is accomplished by heating rubblized shale in the
presence of steam. Retorting temperatures are attained by a
combustion of a portion of the oil shale. Oil, water and low-
Btu gas flow from the retorts to the oil-gas recovery plant. The
oil is then fractionated to produce naphtha and heavy oil frac-
tions. The low-Btu gas is compressed to recover condensible hydro-
carbons. The gas is then purified of sulfur compounds and used
as fuel for the production of electricity.1
Preparation of the in-situ retorts requires the removal of
about 20% of the rubbled shale. Shale brought to the surface is
^
retorted in a TOSCO II retort. Oil and high-Btu gas from the
TOSCO II retorts are sent to the raw oil recovery plant where
they are fractionated into gas, naphtha, and heavy oil streams.
The gas is sent to a high-Btu gas recovery plant where conden-
sible hydrocarbons are recovered. Gas from the gas recovery
plant is purified of sulfur compounds in the sulfur recovery
plant and subsequently used for plant fuel.2
Naphtha and heavy oil from surface and in-situ retorting
are sent to the oil upgrading and blending plant. Heavy oil
streams are treated with a flow-improving chemical and^then
blended with naphtha and C* fractions. The pipeline quality
product oil has the following properties:
Gravity 26°API
True Vapor Pressure @ 100°F 11.2 psia
Viscosity @ 30°F 800 SUS (max)
Pour Point 30°F (max)
*Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols
Prepared for Area Oil Shale Supervisor. May 1977. p"!IT3-5.
2 Ibid.
-280-
-------
Elemental sulfur is produced in the gas purification and sulfur
recovery plants.1
Foul waters recovered from retorting operations are steam-
stripped in the foul water stripping plant. The volume of stripped
water is reduced by evaporation and then the water is used to
moisturize processed shale. Distilled water is recycled to steam
generation. Acid gas from the stripping plant is sent to the
sulfur recovery plant.2
4.6.3.2 Input Requirements
Input requirements for the combined in-situ and surface re-
torting development have not been completely specified. Inputs
reported by Gulf Oil and Standard Oil of Indiana are solely based
on a conceptual design: no field testing of the RISE process has
been performed.
Data reported below are based on a processing facility pro-
ducing 76,000 BPD of a pipeline quality oil product. Of the
76,000 BPD, 57,000 BPD are to be produced by in-situ retorting
with the remainder produced by TOSCO II surface retorting. The
target oil shale has an average Fischer assay grade of about
23 gal/ton. Approximately 40,000 tons of shale are mined daily
to create the required void space in the underground retorts.3
4.6.3.2a Manpower
Detailed manpower requirements have not been prepared by
potential developers of the combined retorting facility. Total
'Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols.
Prepared for Area Oil Shale Supervisor. May 1977. pp. 1-3-5 and
1-3-7.
zibid. , p. 3-3-3.
3 Ibid. , p. 1-3-4.
-281-
-------
requirements during commercial operations producing 76,000 BPD
have been estimated at 2075. That employment estimate includes
labor required for mining and shale feed preparation as well as
retorting. Peak employment during construction of the entire
facility has been estimated as 2500.1
4.6.3.2b Materials and Equipment
Estimates of the materials and equipment required for the
combined retorting facility have not been prepared. Plants
comprising the commercial processing facility include TOSCO II
retorts, oil and oil-gas recovery plants, gas purification and
sulfur recovery plants, a foul water stripping plant, an oil
fractionation plant, a power generation facility, a high-Btu gas
plant, and a product oil upgrading and blending plant. These
plants are shown in Figure 4-29.
4.6.3.2c Economics
No costs data have been reported by Gulf Oil and Standard
Oil (Indiana).
4.6.3.2d Water
Table 4-96 summarizes the disposition of water involved in
the normal operation of the combined retorting facility. Approxi-
mately 30% of the total water input is used for moisturizing
processed shale from surface retorting. Evaporation and flue
gas losses use essentially all of the remaining water input.2
Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols
Prepared for Area Oil Shale Supervisor. May 1977. p~ITl-19.
2iJbid. , p. 3-3-31.
-282-
-------
TABLE 4-96. WATER BALANCE DURING NORMAL OPERATIONS
OF COMBINED RETORTING FACILITIES
gpm
Output
Water on Processed Shale 840
Surface Retort Vent Gas Loss 840
Cooling Tower Loss 330
Power Generation Plant Flue
Gas Loss 610
Miscellaneous Loss 130
Total Output 2,750
Make-up Water 820
Water of Combustion 530
Retort Water and Residual
Groundwater Inflow 1,400
Total Input 2,750
Source: Gulf Oil Corporation and Standard Oil Company (Indiana)
Revised Detailed Development Plan for Oil Shale Tract
C-a,3 vols.Prepared for Area Oil Shale Supervisor.
May 1977. p. 3-3-31.
-283-
-------
Approximately 820 gpm must be supplied by a local ground or
surface water system.
4.6.3.2e Land
Land disturbances associated with the processing of shale
include those areas comprising the processed shale disposal pile
and the surface processing plant. Surface processing facilities
require the commitment of approximately 240 acres. Processed
shale disposal requires a total of 880 acres over the 30-year
life of a commercial development. Corridors to the complex (in-
cluding those for the mine) disturb about 280 acres.1
4.6.3.2f Ancillary Energy
Energy requirements of the combined retorting facility have
been estimated by Gulf and Standard Oil. Electric power pro-
duction and consumption is summarized in Table 4-97. The power
generation plant provides most of the requirements of the pro-
cessing facility. Most of the electricity is generated on-site
from low-Btu fuel gas from the in-situ retorts.
An estimated fuel balance is shown in Table 4-88.
Resource and energy recoveries for the combined retorting
facility are approximately the same as those reported for Occi-
dental's proposed development.
4.6.3.3 Outputs
Some residuals of the combined in-situ and surface retorting
development have not been specified. Residuals reported by Gulf
!Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Trace C-a, 3 vols
Prepared for Area Oil Shale Supervisor. May 1977. p~. 1^6-19.
-284-
-------
TABLE 4-97. ELECTRIC POWER PRODUCTION AND CONSUMPTION
FOR COMBINED RETORTING
Electric Power, MW
Plant
Consumed Produced
In Situ Retorting
Retorting 4
Oil-Gas Recovery 7
Oil Fractionation 5
Gas Purification 200
Power Generation 226
Surface Retorting
TOSCO II 30
Raw Oil Recovery 1
High-Btu Gas Plant 7
Sulfur Recovery 1
Product Oil Blending 1
Foul Water Stripping 1
Support Systems 5
Purchased Power - 36
Total 262 262
Source: Gulf Oil Corporation and Standard Oil Company (Indiana)
Revised Detailed Development Plan for Oil Shale Tract
C-a, 3 vols. Prepared^ for Area Qil Shale Supervisor.
Hay 1977. p. 3-3-29.
-285-
-------
TABLE 4-98. ESTIMATED FUEL BALANCE
FOR COMBINED RETORTING
Plant m BTU/H
Produced Consumed
a) High-Btu Fuel Gas
TOSCO II Retorting Plant - 819
High Btu Gas Plant - 27
Sulfur Recovery Plant 882 9
Support Systems - 27
882 882
b) Low-Btu Fuel Gas
In Situ-Produced Gas
Purification Plant 3,260
TOSCO II Retorting Plant
Power Generation Plant
3,260
Total Fuel Gas 4,142
Source: Gulf Oil Corporation and Standard Oil Company (Indiana)
Revised Detailed Development Plan for Oil Shale Tract
C-a,3 vols.Prepared for Area Oil Shale Supervisor.
Hay 1977. p. 3-3-30.
-286-
-------
and Standard (Indiana) are based solely on a preliminary design:
no field testing of the RISE process has been performed.
4.6.3.3a Air Emissions
Atmospheric emissions from the combined retorting develop-
ment originate from:
1) the TOSCO II pyrolysis and oil recovery unit,
2) the high-Btu gas plant reboiler,
3) the thermal oxidizer,
4) the power generation plant,
5) storage tanks, and
6) processed shale disposal.
Emissions from these sources are summarized in Table 4-£9.
Fuel for the processing plant is supplied by purified high-
Btu gas produced by TOSCO II retorting and low-Btu gas produced
by in-situ retorting. About 99% of the ammonia and 98% of the
sulfur compounds are removed from the high-Btu gas. The overall
removals of sulfur compounds and ammonia from the low-Btu gas
are about 98% and 90%, respectively.J
The important emission sources are the TOSCO II retorting
plant and the power generation plant. Flue gases from the pre-
heating systems are scrubbed in high energy venturi scrubbers
*Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, J vols
Prepared for Area Oil Shale Supervisor.May 1977.pT1-6-8.
-287-
-------
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prior to release to the atmosphere. Caustic is injected into the
wet scrubbers to reduce the concentration of sulfur dioxide in
the flue gases to a concentration of 10 ppmv. The TOSCO II pre-
heat system contains an incinerator to remove 90 to 95% of the
hydrocarbon vapors contained in the flue gas.l
Flue gases from the ball circulation and shale moisturizing
systems are also scrubbed before release to the atmosphere. En-
trained shale dust is removed from the flue gas in high energy
venturi scrubbers.2
Emissions from power generation are controlled by the use
of purified fuel gas. This purified gas is prepared from gas
produced during in-situ retorting.3
Hydrocarbon emissions from oil storage tanks are controlled
by using floating roof tanks for the more volatile liquids.1*
4.6.3.3b Water Effluents
The developers of tract C-a expect no discharge of process
wastewater into the environment. A portion of the water produced
is consumed through evaporation, processing needs, dust control
needs, and by adsorption in the processed shale. Most of the
groundwater from mine dewatering is pumped and reinjected into
the aquifer system. Surface waters originating within the
*Gulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols
Prepared for Area Oil Shale Supervisor. May 1977. p~! 1^6-8.
2ibid., p. 1-6-9.
3ibid., p. 1-6-9.
. , p. 1-6-9.
-289-
-------
plant area are controlled by a series of collection ditches and
retention dams. Surface waters are ultimately recycled to the
process water system, used for dust control, or evaporated.1
Groundwater may be fouled by leachate from the underground retorts,
4.6.3.3c Solid Wastes
Moisturized processed shale is produced at the rate of
36,000 TPD.2 The entire production must be disposed on the
surface, unless a portion can be used to backfill the in-situ
retorts.
Other solid wastes are tabulated in Table 4-100. Spent
zeolites and lime sludge from water treatment can be disposed of
in the processed shale disposal pile. The spent catalysts are
recycled to the manufacturer.3
4.6.3.3d Noise Pollution
4.6.3.3e Occupational Health and Safety
4.6.3.3f Odors
These outputs have been extensively discussed in Sections
4.6.1.3 and 4.6.2.3 on surface and in-situ retorting. Similar
discussions describe the combined modified in-situ and surface
retorting developments.
Inputs and outputs associated with the combined in-situ
and surface retorting developments are found in Table 4-101.
xGulf Oil Corporation and Standard Oil Company (Indiana).
Revised Detailed Development Plan for Oil Shale Tract C-a, 3 vols
Prepared for Area Oil Shale Supervisor. May 1977. pp. 5"-6-1,
6-6-2.
2ibid., p. 1-3-7.
3 Ibid. , p. 6-9-4.
-290-
-------
TABLE 4-100. NON-SHALE SOLID WASTES
Process Unit Solid Waste Description Approximate Quantity*
Sulfur Recovery
Glaus Unit Spent oxidation catalyst 45
Tail Gas Unit Spent hydrogenation catalyst 8
Water Treating Spent zeolites 3
Lime sludge 870
*Average over catalyst life.
Source: Gulf Oil Corporation and Standard Oil Company (Indiana). Revised
Detailed Development Plan for Oil Shale Tract C-a, 3 vols.
Prepared for Area Oil Shale Supervisor. May 1977. p. 6-9-4.
-291-
-------
TABLE 4-101. SUMMARY OF INPUTS AND OUTPUTS ASSOCIATED WITH A
MODIFIED IN-SITU AND SURFACE PROCESSING PLANT
PRODUCING 76,000 BPD OF SHALE OIL
Inputs
Outputs
Manpower
operating
peak construction9
Materials and Equipment
TOSCO II retorts
oil and oil-gas recovery units
gas purification and sulfur
recovery units
foul water stripper
oil fractionation and high Btu
gas units
oil upgrading and blending units
Economics
Water
Land
surface processing facilities
shale disposal (over 30 years)
corridors (including mine)
Ancillary Energy
Air Emissions
p articulates
hydrocarbons
CO
S02
C02
Water Effluents
Solid Wastes
processed shale
catalysts and sludges
Noise Pollution
at plant boundaries
Occupational Health and Safety
Odors
at plant boundaries
1000
2500
Unknown
2750 gpm
240 acres
900 acres
280 acres
3.2 x 10" kwh/yr
483 Ib/hr
174 Ib/hr
2370 Ib/hr
458 Ib/hr
2,250,000 Ib/hr
No direct discharge
36,000 TPD
820 TPY
Negligible
Unknown
Negligible
aPeak for all phases (including mine construction)
-292-
-------
4.6.4 Processing Social Controls
Regulations for energy processing facilities are concerned
with environmental impacts, safety and health of employees, and
control of the processed product. This section will discuss the
federal and state regulations which apply to the processing of
oil shale. These regulations consider initial planning and land
use, water quality, air quality, solid wastes, noise, safety,
and the regulation of product output.
4.6.4.1 Plans and Land Use
Under the Prototype Oil Shale Leasing Program, environ-
mental baseline data pertaining to the quantity and quality of
surface water, ground water, the quality of air, and the popula-
tion relationships of flora and fauna must be collected for at
least one year prior to the submission of a detailed development
plan and for one additional year prior to commercial operations.
The lessee is also required to submit the results of environmental
monitoring for public release on an annual basis. Public hear-
ings on the environmental aspects of the detailed development
plan were conducted by the Area Oil Shale Supervisor (AOSS).
The Oil Shale Environmental Advisory Panel acts as a review
body to provide guidance to the AOSS and the appropriate BLM
district managers.
4.6.4.2 Water Quality
Because facilities described in the technological summaries
have no effluents,1 the laws applicable to surface water efflu-
ents, do not apply. Hence, the FWPCA and its respective state
laws will not apply. Laws that do apply are those concerned
Sections 4.6.1.3b, 4.6.2.3b, 4.6.3.3b
-293-
-------
with holding ponds, such as the federal drinking water regulations
and state laws on retaining ponds and groundwater, all of which
are described in the water quality section of Chapter 2.
4.6.4.3 Air Quality
The air quality controls applicable to oil shale processing
are included in the Environmental Stipulations of the Prototype
Oil Shale Leases.1 These include a requirement for compliance
with applicable stipulations of both federal and state air
quality and emission regulations (described in Chapter 2), a
requirement to avoid or minimize dust problems, and a prohibition
against burning waste, timber, or debris unless other methods of
disposal would be more harmful to the environment.2
4.6.4.4 Solid Wastes
The disposal of solid wastes is regulated by the controls
discussed in Section 4.5.4.3. Because oil shale processing will
result in a large solid waste problem, the regulation of that
output starts prior to any production of the waste. The develop-
ment plan, including waste disposal, must be approved prior to
operation.
4.6.4.5 Safety and Health
Health and safety regulation for oil shale processing is
regulated by OSHA at the retort site, although MSHA has authority
1U.S. Department of the Interior. Final Environmental
Impact Statement for the Prototype Oil Shale Leasing Program.
Volume III. pp. V-43 to V-84.
2Ibid., p. V-69.
-294-
-------
over oil shale crushing, pulverizing and sizing of oil shale.
Outside of normal safety and health problems associated
with any processing facility, an additional problem is the
carcinogenic property of the raw shale oil. No specific controls
exist.
4.6.4.6 Noise
Noise control in oil shale processing is generally similar
to noise regulation in most other energy processing (e.g., coal).
As shown in Table 4-102, various agencies and governments are
involved in noise control.1'2 Additionally, it should be noted
that the environmental stipulations require the federal oil
shale lessees to comply with all present and future noise
standards.3
4.6.4.7 Product Regulation
Product regulation of oil shale and its products, which are
in fact oil, should be no different than that discussed in Chap-
ter 6. Pricing, however, is included within the synthetic fuels
entitlement program which provides a subsidy of approximately
$2/bbl." Additional supports of $3/bbl have been proposed by
Senator Talmadge in negotiations on President Carter's energy
package.5
1 Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I,
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-62,
2Note also that the applicable standards for mining and
also the Colorado standards are discussed in Chapter 2.
3Section 10 of the Environmental Stipulations.
"Energy Users Report, May 18, 1978, p. 5.
5Denver Post, September 22, 1977.
-295-
-------
TABLE 4-102. NOISE POLLUTION CONTROL STANDARDS
Government Agency
Applicable Noise Pollution Standard
Federal
Environmental Protection
Agency (EPA)
U.S. Mine Enforcement Safety
Administration (MESA)
Occupational Safety and Health
Administration (OSHA)
OSHA
40 CFR Part 202 - Motor Carriers
Engaged in Interstate Commerce
Effective October 15, 1975
40 CFR Part 204 - Noise Emission
Standard for Construction Equipment
Standards for Air Compressors
Effective January 1, 1978.
30 CFR Part 57 - Health and Safety
Standards, Metal and Non-metallic
Underground Mines
29 CFR Part 1910 - Occupational
Safety and Health Standards
29 CFR Part 1926 - Occupational
Safety and Health Regulations for
Construction
Colorado Revised Statutes, 1973,
§25 - 12 - 101 to §25 - 108 "
Proposed Noise Standards
EPA
40 CFR Part 205 - Transportation
Equipment Noise Emission Controls
Source: Ashland Oil, Inc. and Shell Oil Co. Detailed Development Plan and
Related Materials for Oil Shale Tract C-b, Volume I, Prepared for
Area Oil Shale Supervisor. February 1976. p. IV-62.
-296-
-------
4.7 LAND RECLAMATION
Surface disturbances associated with oil shale development
include those attributed to:
1) construction and operation of surface facilities,
2) mining activities,
3) overburden removal,
4) development of utility corridors, and
5) processed shale disposal.
Reclamation of land disturbed by the first four activities re-
quires reclamation techniques similar to those applied in coal
development. Since these techniques are already commonly used
in the coal industry and have been discussed in Chapter 3, they
are not discussed here.
Reclamation of land disturbed by the disposal of large
quantities of processed shale requires the application of special
reclamation techniques. These techniques are briefly described
in the following sections.
Section 4.7.1 discusses those characteristics of processed
shale that affect its disposal and reclamation. Section 4.7.2
discusses some techniques applicable to the disposal and reclama-
tion of orocessed shale.
-297-
-------
4.7.1 Characteristics of Processed Shale
The various retorting techniques produce processed shales
with varying physical and chemical characteristics. Typical
properties of several shales are shown in Table 4-103. Mineral
compositions of retorted shales have been reported in Table 4-75-
Table 4-74 reports concentrations of elements found in TOSCO II
retorted shale. Table 4-76 identifies certain polycyclic aromatic
hydrocarbons found in TOSCO II retorted shale.
Typical retorted shales from internal combustion gas retorts
have compositions similar to that of Portland cement. These pro-
cessed shales are soft and friable, and have organic carbon
contents of 2 to 3% or lower, depending on the retorting process.
The cement-forming tendency of these processed shales can help to
create a physically and chemically stable disposal pile. Before
setting, the retorted shale behaves like a sandy silt. After
setting, it develops sufficient cohesion to allow the construc-
tion of deep, well-stabilized piles with high slope angles. The
strength of the disposal pile depends on the amount of moisture
added (10-147, is optimum) and the amount of cohesive hydrates pro-
duced. Reduction of particle size increases pile strength.1'2
Retorted shales from indirect-heated retorts (e.g., TOSCO II,
Union B, Paraho Indirect Mode) have organic carbon contents of 4
to 5%. Cementation reactions do not occur during compaction of
these retorted shales, except through the cohesion produced
Crawford, K. W., et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development.Prepared for
U.S.Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
2Nevens, T. D., W. J. Culbertson and R. D. Hollingshead.
"Disposal and Uses of Oil Shale.Ash", USBM Project SWD-8, 1967.
-298-
-------
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by compaction alone. Leaching of soluble salts, metals, and
organics is thus more likely than for direct-heated shales.1
4.7.2 Disposal and Reclamation of Processed Shale
This section briefly describes methods for the disposal and
reclamation of processed shale. The discussion is largely a
summary of a discussion presented by Conkle et al.2
The cooled and moistened shale from surface retorting will
typically be conveyed to adjacent canyons or other topographic
depressions. The processed shale will then be compacted to
maintain stability as the pile is built up. To prevent downstream
pollution by leaching of soluble material from the processed
shale, disposal areas must be safe-guarded by dams, culverts, and/
or diversion ditches.
Erosion of processed shale piles may be lessened to some
extent through physical, chemical, and vegetative methods of
stabilization. Physical methods include covering the processed
shale pile with topsoil. Chemical stabilization methods involve
reacting the shale with a reagent to form a water and air im-
permeable crust or layer. Vegetative stabilization usually
requires the application of six or more inches of topsoil to the
processed shale, but varies with the type of processed shale and
the use of an artificial capillary barrier.
Crawford, K. W. , et al. A Preliminary Assessment of the
Environmental Impacts from Oil Shale Development. Prepared for
U.S. Environmental Protection Agency.Contract No. 68-02-1881.
Denver Research Institute and TRW Environmental Engineering
Division. June 1976.
2Conkle, N., V. Ellzey, and K. Murthy. Environment a1
Considerations for Oil Shale Development. Battelle Columbus
Laboratories.Prepared for U.S. Environmental Protection Agency.
October 1974. pp. 68-71.
-300-
-------
Disposal of the processed shale by slurrying and pumping to
a disposal pond is attractive because of the relative simplicity
and low cost of the system. Such disposal is limited by inade-
quate disposal areas and water availability. This disposal tech-
nique is impractical for the disposal of large quantities (approxi-
mately 53,000 TPD) of processed shale.
Some of the processed shale may be disposed of in mined-out
areas underground. Because the processed shale has a larger
specific volume than raw shale, a maximum of 70 percent of the
total volume of processed shale may be disposed of underground
unless other minerals have been recovered from the shale. Both
conveyor and slurry methods for underground disposal have been
proposed.
The susceptibility of the shale pile to water leaching can
be limited by proper disposal site construction and compaction.
If water and runoff are collected in catchment ponds, pollution
of surface waters can be minimized. Additional protection (pond
lining) must be provided to avoid pollution of groundwater.
Water requirements for revegetation of processed shale dis-
posal piles vary with the type of retorted shale. Developers of
planned 50,000 BPD TOSCO II facilities have indicated that 70 gpm
(110 acre-ft/year) are required during the first twelve years of
shale disposal: most of the water is probably used for dust
suppression. When intensive revegetation efforts commence, up
to 700 gpm (1100 acre-ft/yr) are required.1'2 These water
requirements amount to 2-20 gallons per ton of processed shale.
Little water is required for the revegetation of raw shale piles.
1Ashland Oil, Inc. and Shell Oil Co. Detailed Development
Plan and Related Materials for Oil Shale Tract C-b, Volume I.
Prepared for Area Oil Shale Supervisor.February 1976. p. IV-63,
2U.S. Bureau of Land Management. Proposed Development of
Oil Shale Resources by the Colony Development Operation in
Colorado,Draft Environmental Impact Statement.DES-75-62.
Washington, D.C.: December 1975.
* u.s. GOVBWMEKT nmm onxx. UTS -
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