Environmental Protection
Agency
Industry
Washington DC 20460
March 1979
Research and Development
Energy from the
West
Energy Resource
Development
Systems Report
Volume II: Coal
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 fiePds.
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 II: Coal
By
Science and Public Policy Program
University of Oklahoma
Irvin L. White Edward J. Malecki
Michael A. Charlock 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
Washington, D.C. 10460
Project Officer:
Steven E. Plotkin
Office of Energy, Minerals and Industry
Contract Number 68-01-1916
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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'
> n
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. Rejznek
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) .
-------
Chapters 3-7 were prepared by the Radian Corporation, Austin,
Texas, under subcontract to the University of Oklahoma. In each
of these chapters, Radian is primarily responsible for the des-
cription of the resource base and the technologies and S&PP is
primarily responsible for the description of laws and regulations.
The Program Manager at Radian was C. Patrick Bartosh. Clinton E.
Burklin was responsible for preparation of these five chapters.
Other contributors at Radian were: William R. Hearn, Gary D.
Jones, William J. Moltz, and Patrick J. Murin.
Additional assistance in the preparation of the ERDS report
was provided by Martha W. Gilliland, Executive Director, Energy
Policies Studies, Inc., El Paso, Texas; Rodney K. Freed, Attorney,
Shawnee, Oklahoma; and Robert W. Rycroft, Assistant Professor of
Political Science, University of Denver, Denver, Colorado.
vi
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ABSTRACT
This report describes the technologies likely to be used
for development of coal, oil shale, uranium, oil, natural gas,
and geothermal resources in eight western states (Arizona, Color-
ado, Montana, New Mexico, North Dakota, South Dakota, Utah,
and Wyoming). It is part of a three-year "Technology Assess-
ment of Western Energy Resource Development." The study examines
the development of these energy resources in the eight states
from the present to the year 2000. Other reports describe
the analytic structure and conduct of the study, the impacts
likely to result when these resources are developed, and analyze
policy problems and issues likely to result from that develop-
ment. The report is published in six volumes. Volume 1 describes
the study, the technological activities such as exploration,
extraction, and conversion for developing the resource,'and
laws and regulations which affect the development of more
than one of the six resources considered in the study. The
remaining five volumes are resource .specific: Volume 2, Coal;
Volume 3, Oil Shale; Volume 4, Uranium; Volume 5, Oil and Natural
Gas; and Volume 6, Geothermal. Each of these volumes provides
information on input materials and labor requirements, outputs,
residuals, energy requirements, economic costs, and resource
specific state and federal laws and regulations.
vii
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OVERALL TABLE OF CONTENTS
FOR
THE ENERGY RESOURCE DEVELOPMENT SYSTEMS REPORT
VOLUME I: INTRODUCTION AND GENERAL SOCIAL CONTROLS
Chapter 1 ENERGY RESOURCE DEVELOPMENT SYSTEMS
1.1 Introduction
1.2 Objectives of the ERDS Document...
1.3 Organization of the ERDS Document.
1.4 Limitations of the ERDS Document..
PAGE
1
3
4
9
Chapter 2 GENERAL SOCIAL CONTROLS
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 OP CONTENTS
(continued)
VOLUME III: OIL SHALE PAGE
Chapter 4 THE OIL SHALE RESOURCE DEVELOPMENT SYSTEM
4.1
4.2
4.3
4.4
4.5
4.6
4.7
VOLUME IV: URANIUM
Introduction
Summary
Resource Description...
Exploration
Mining and Preparation.
Processing
Land Reclamation
1
4
13
25
37
142
297
Chapter 5
THE URANIUM RESOURCE SYSTEM
5.1
5.2
5.3
5.4
Introduction ,
Uranium Resources,
Exploration ,
Mining.
1
8
31
64
5.5 Uranium Milling 197
VOLUME V: OIL AND NATURAL GAS
Chapter 6 CRUDE OIL RESOURCE DEVELOPMENT SYSTEM
6.1
6.2
6.3
6.4
Introduction
Resource Description of Western
Crude Oil
Exploration.
Crude Oil Production
8
14
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 OP CONTENTS
VOLUME II
CHAPTER 3: THE COAL RESOURCE DEVELOPMENT SYSTEM
lr a(
3 .1 INTRODUCTION 1
3.2 SUMMARY 3
3. 3 COAL RESOURCES 12
3.3.1 Background 12
3.3.2 Total National Resource Endowment 13
3.3.3 Characteristics of the Resources 15
3.3.4 Location of the Resources 19
3.3.5 Recoverability of the Resources 21
3.3.6 Ownership of Resources 24
3.4 A REGIONAL OVERVIEW 27
3.4.1 The Northern Great Plains Province 27
3.4.2 The Rocky Mountain Province 30
3.4.3 Summary 36
3. 5 EXPLORATION 37
3.5.1 Technologies 37
3.5.2 Input Requirements 39
3.5.3 Outputs 42
3.5.4 Social Controls 44
3.6 MINING 52
3.6.1 Surface Mining 52
3.6.1.1 Technology Description 52
3.6.1.2 Input Requirements 65
3.6.1.3 Outputs 78
xi
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TABLE OF CONTENTS (Continued)
VOLUME II
3.6.1.4 Summary 82
3.6.2 Undergrovnd Mining 82
3.6.2.1 Technology Description. 82
3.6.2.2 Input Requirements 93
3.6.2.3 Outputs 106
3.6.3 Social Controls 113
3.6.3.1 Obtaining Minable Land (Leasing) 113
3.6.3.2 Health and Safety 129
3.6.3.3 Mining Permits and Reclamation 132
3.7 BENEFICIATION 139
3.7.1 Technologies 143
3.7.2 Input Requirements . 154
3.7.3 Outputs 164
3.7.4 Social Controls 168
3.8 CONVERSION 174
3.8.1 Gasification 174
3.8.1.1 Technology Description 175
3.8.1.2 Input Requirements 210
3.8.1.3 Outputs 218
3.8.1.4 Summary 260
3.8.2 Liquefaction 263
3.8.2.1 Technology Description. 263
3.8.2.2 Input Requirements 280
3.8.2.3 Outputs 294
3.8.2.4 Summary 319
3.8.3 Electrical Generation 321
xii
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TABLE OF CONTENTS (Continued)
VOLUME II
Fat
3.8.3.1 Technology Description 323
3.8.3.2 Input Requirements 343
3.8.3.3 Outputs 349
3.8.4 Social Controls 356
xiii
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LIST OF FIGURES
VOLUME II
CHAPTER 3: THE COAL RESOURCE DEVELOPMENT SYSTEM
Number Page
3-1 Range in Fixed Carbon Contents of Major Coal Ranks.. 16
3-2 Range in Heat Contents of Major Coal Ranks 17
3-3 Distribution of United States Coal Resources 22
3-4 Distribution of Coal in the Northern Great Plains
Province 28
3-5 Distribution of Coal in the Rocky Mountain Province. 31
3-6 The Sequence of Federal Regulatory Controls Over
Exploration 45
3-7 Increase in Coal Production by Surface Mining 53
3-8 Area Mining 57
3-9 Steps Involved in an Area Mining Operation 58
3 -10 Dragline 61
3-11 Bucket Wheel Excavator 63
3-12 Sketch of Mine Plant 66
3-13 The Three Types of Access Used in Underground Coal
Mines 85
3-14 Illustration of Room and Pillar Mining Using Conven-
tional (Blasting)-and Continuous Mining Techniques.. 86
3-15 Underground Mining Methods 89
3-16 Plan View of Longwall Mining 90
3-17 Overall Mining Project Construction Schedule 96
3-18 Individual Mine Development Schedule 96
3-19 Underground Mine Fatalities 112
3-20 Generalized Coal Cleaning Process 144
3-21 General Coal Gasification Flow Sheet 184
3-22 Overall Lurgi High-Btu Gasification Flow Diagram.... 195
3-23 Overall Synthane High-Btu Gasification Flow Diagram. 196
3-24 Schematic of a Lurgi Gasifier 199
3-25 Schematic Diagram of Lurgi Gasif ier 200
3-26 Schematic Diagram of the Synthane Process 202
3-27 Example Flow Diagram for a SRC-II Coal Liquefaction
Process 271
xiv
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LIST OF FIGURES (Continued)
VOLUME II
Number Page
3-28 Simplified Schematic of a Steam Power Plant 322
3-29 Boiler Air and Flue Gas Circulation Patterns 325
3-30 Pope, Evans, and Robbins Fluidized Bed Boiler
Power Plant 330
3-31 Lime and Limestone Stack Gas Scrubbing Methods 337
3-32 Processing Procedures 359
xv
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LIST OF TABLES
VOLUME II
Number Page
3-1 SUMMARY OF IMPACTS ASSOCIATED WITH THE
EXPLORATION OF A 30,000 TON PER DAY COAL
MINE IN WESTERN U.S 4
3-2 SUMMARY OF IMPACTS ASSOCIATED WITH 12 MM TPY
SURFACE MINE AT NAVAJO 5
3-3 SUMMARY OF IMPACTS ASSOCIATED WITH A 12 MM TPY
UNDERGROUND COAL MINE AT KAIPAROWITS 6
3-4 SUMMARY OF IMPACTS ASSOCIATED WITH A 25,000 TPD
COAL BENEFICIATION PLANT 7
3-5 SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
LURGI COAL GASIFICATION PLANT AT COLSTRIP, MONTANA.. 8
3-6 SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
SYNTHANE COAL GASIFICATION PLANT AT COLSTRIP,
MONTANA 9
3-7 SUMMARY OF IMPACTS ASSOCIATED WITH A 30,000 TPD
SRC-II COAL LIQUEFACTION PLANT AT GILLETTE,
WYOMING 10
3-8 SUMMARY OF IMPACTS ASSOCIATED WITH A 3000 MW
POWER PLANT AT GILLETTE, WYOMING 11
3-9 COAL RESOURCES OF THE U.S. (Billions of Tons) 14
3-10 RANK OF IDENTIFIED U.S. COAL RESOURCES 18
3-11 COMPARISON OF EASTERN AND WESTERN COAL QUALITIES 20
3-12 COAL RESOURCES IN U.S. GEOLOGICAL SURVEY PROVINCES
(Billions of Tons) 23
3-13 SURFACE AND MINERAL OWNERSHIP OF STUDY AREA BY
OWNER AND STATE (In Percent of Total) 26
3-14 COAL RESOURCES IN THE NORTHERN GREAT PLAINS
PROVINCE 29
3-15 COAL RESOURCES IN THE ROCKY MOUNTAIN PROVINCE 32
3-16 WESTERN COAL RESERVES BY STATE (Million Tons) 34
3-17 OUTLINE OR REGIONAL AND DETAILED EXPLORATION
PROGRAM 38
3-18 ESTIMATED MANPOWER REQUIREMENTS FOR GEOLOGIC
TECHNIQUES FOR COAL EXPLORATION 40
3-19 ARIZONA COAL EXPLORATION PERMIT 47
xvi
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LIST OF TABLES (Continued)
VOLUME II
Number Page
3-20 COLORADO COAL EXPLORATION PERMIT 47
3-21 MONTANA COAL EXPLORATION PERMIT 48
3-22 NEW MEXICO COAL PROSPECTING PERMIT 48
3-23 NORTH DAKOTA COAL EXPLORATION PERMIT 49
3-24 SOUTH DAKOTA COAL EXPLORATION PERMIT 50
3-25 UTAH COAL EXPLORATION PERMIT 51
3-26 WYOMING COAL EXPLORATION AND PERMIT 51
3-27 SCHEDULE OF MANPOWER RESOURCES REQUIRED FOR
CONSTRUCTION OF SURFACE WESTERN COAL MINE
REQUIRED TO PRODUCE 12 MM TPY COAL 68
3-28 MANPOWER RESOURCES REQUIRED FOR OPERATION AND
MAINTENANCE OF A SURFACE WESTERN COAL MINE
PRODUCING 12 MM TPY COAL 69
3-29 MAJOR EQUIPMENT ITEMS REQUIRED FOR SURFACE
MINING 12 MM TPY COAL 70
3-30 CONSTRUCTION MATERIALS REQUIRED FOR A 12 MM TPY
SURFACE MINE 71
3-31 COAL MINE EQUIPMENT COSTS AND REPLACEMENT SCHEDULE
(1974 DOLLARS) (13 MILLION TONS/YR) 72
3-32 ANNUAL OPERATING COST SUMMARY (1974 DOLLARS)
(13 MILLION TONS/HR) 73
3-33 COMPARISON OF WESTERN SURFACE MINING COSTS
(1974 DOLLARS) 75
3-34 LAND AREA REQUIREMENTS FOR A 12 MILLION TPY COAL
STRIP MINE " 77
3-35 ANNUAL ANCILLARY ENERGY REQUIREMENTS FOR A
12 MILLION TPY COAL STRIP MINE 78
3-36 AIR EMISSIONS FROM A 12 MILLION TPY COAL SURFACE
MINING OPERATION '. 79
3-37 EMISSION FACTORS FOR MINING EMISSION SOURCES 80
3-38 SUMMARY OF IMPACTS ASSOCIATED WITH 12 MM TPY
SURFACE MINE AT NAVAJO 83
3-39 COMPARISON OF CONVENTIONAL, CONTINUOUS. AND
LONGWALL MINING 92
XV0.1
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LIST OF TABLES (Continued)
VOLUME II
Number Page
3-40 SCHEDULE OF MANPOWER RESOURCES REQUIRED FOR
CONSTRUCTION OF A 12 MM TPY UNDERGROUND COAL MINE... 95
3-41 TOTAL MANPOWER REQUIREMENTS FOR OPERATION OF
FOUR UNDERGROUND COAL MINES (NET PRODUCTION
12 MILLION TPY) 97
3-42 MAJOR EQUIPMENT SUMMARY, FOUR MINES TOTALING
12 MILLION TPY 98
3-43 ESTIMATED WORKING CAPITAL AND TOTAL CAPITAL
INVESTMENT (3 MILLION TPY MINE, 1974) 102
3-44 ESTIMATED ANNUAL PRODUCTION COST (3 MILLION TPY
MINE, 1974) 103
3-45 CAPITAL AND INVESTMENT COST FOR UNDERGROUND
COAL MINING (1974) 104
3-46 POWER REQUIREMENTS FOR A 3 MILLION TPY UNDERGROUND
COAL MINE 107
3-47 SUMMARY OF IMPACTS ASSOCIATED WITH A 12 MM TPY
UNDERGROUND COAL MINE AT KAIPAROWITS 114
3-48 SUMMARY OF SIGNIFICANT PUBLIC LANDS MINERALS
OWNERSHIP LEGISLATION 116
3-49 SUMMARY OF FEDERAL LAND CATEGORIES AND JURISDICTION. 117
3-50 SUMMARY OF LEASING AND LICENSING FEATURES FOR
FEDERAL AND INDIAN LANDS 118
3-51 ARIZONA COAL LEASE FEATURES 122
3-52 COLORADO COAL LEASE FEATURES 122
3-53 MONTANA COAL LEASE FEATURES 123
3-54 NEW MEXICO COAL LEASE FEATURES 124
3-55 NORTH DAKOTA COAL LEASE FEATURES 125
3-56 SOUTH DAKOTA COAL LEASE. . 126
3-57 UTAH COAL LEASE 127
3-58 WYOMING COAL LEASE 128
3-59 SUMMARY OF STATE MINE RECLAMATION LAWS 135
3-60 COLORADO COAL OPEN MINE PERMIT , 136
3-61 MONTANA COAL STRIP AND UNDERGROUND MINING PERMIT.... 137
xviii
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LIST OF TABLES (Continued)
VOLUME II
Number Page
3-62 NORTH DAKOTA COAL LEASE (STRIP MINE PERMIT) 138
3-63 COAL CLEANING EQUIPMENT OPERATING PARAMETERS 153
3-64 COAL RATES - PHYSICAL COAL CLEANING 155
3-65 COAL PREPARATION OPERATING AND MAINTENANCE LABOR... 156
3-66 MAJOR EQUIPMENT SUMMARY - 9 MILLION TPY COAL
BENEFICIATION PLANT 158
3-67 CAPITAL COSTS - 9 MILLION TPY COAL BENEFICIATION
PLANT 161
3-68 ANNUAL OPERATING COSTS - 9 MILLION TPY COAL
BENEFICIATION PLANT 162
3-69 AIR EMISSIONS FROM THERMAL DRYERS AT A 9 MILLION
TPY COAL CLEANING PLANT 165
3-70 SOURCES OF NOISE AT A PHYSICAL COAL CLEANING PLANT. 169
3-71 SUMMARY OF IMPACTS ASSOCIATED WITH A 9 MILLION TPY
COAL BENEFICIATION PLANT 170
3-72 ADVANTAGES AND DISADVANTAGES OF COAL GASIFICATION
PROCESS TYPES 180
3-73 CHARACTERISTICS OF SELECTED COAL GASIFICATION
PROCESSES 182
3-74 SOLVENT BASED PROCESSES 207
3-75 COAL ANALYSIS - COLSTRIP, MONTANA 211
3-76 SNG COMPOSITION 212
3-77 SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED TO CONSTRUCT A 250 MMscfd COAL
GASIFICATION PLANT 213
3-78 MANPOWER RESOURCES REQUIRED FOR OPERATION AND
MAINTENANCE OF A 250 MMscfd COAL GAS-IFICATION
PLANT 215
3-79 SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF A 250 MMscfd COAL
GASIFICATION PLANT 216
3-80 CLEANED FUEL GAS ANALYSIS 223
3-81 ULTIMATE ANALYSIS OF GASIFIER CHAR 223
3-82 BY-PRODUCT STORAGE EMISSION LOSSES - LURGI 225
xix
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LIST OF TABLES (Continued)
VOLUME II
Number Page
3-83 BY-PRODUCT STORAGE EMISSION LOSSES - SYNTHANE 226
3-84 PUMP SEAL EMISSIONS 228
3-85 FUGITIVE EMISSIONS FROM VALVES 228
3-86 TOXIC AND HAZARDOUS SUBSTANCES LIKELY TO BE
EMITTED BY INDUSTRIAL BOILERS 231
3-87 PRINCIPAL COMPOUNDS OBTAINED FROM COAL TAR 232
3-88 COMPOUNDS OBTAINED FROM COAL TAR 232
3-89 COMPOUNDS TENTATIVELY IDENTIFIED IN WASTE EFFLUENTS
OF COAL GASIFICATION PILOT PLANT 234
3-90 COMPONENTS IN SYNTHANE GASIFIER GAS, ppm 235
3-91 TRACE ELEMENT ANALYSIS OF A TYPICAL COAL FEEDSTOCK.. 236
3-92 TRACE ELEMENT CONCENTRATION OF COAL CALCULATED ON
RAW COAL BASIS 238
3-93 VOLATILITY OF TRACE ELEMENTS IN COAL 241
3-94 SUMMARY OF GASEOUS EFFLUENT STREAMS - LURGI COAL
GASIFICATION 243
3-95 SUMMARY OF GASEOUS WASTE EFFLUENTS - SYNTHANE
COAL GASIFICATION 244
3-96 AIR EMISSIONS OF CRITERIA POLLUTANTS FROM A 250
MMscfd LURGI PLANT 245
3-97 AIR EMISSIONS OF CRITERIA POLLUTANTS FROM A 250
MMscfd SYNTHANE PLANT 246
3-98 RAW WATER ANALYSIS 248
3-99 TYPICAL COOLING TOWER SLOWDOWN WATER ANALYSIS 251
3-100 MINERAL CONSTITUENTS OF COAL ASH 253
3-101 SUMMARY OF LIQUID PHASE EFFLUENT STREAMS 255
3-102 COMPOSITION OF LIMESTONE SCRUBBER SLUDGE 256
3-103 SUMMARY OF SOLID PHASE EFFLUENTS - LURGI 258
3-104 SUMMARY OF SOLID WASTE STREAMS - SYNTHANE 258
3-105 SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
LURGI COAL GASIFICATION PLANT AT COLSTRIP, MONTANA.. 261
3-106 SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
SYNTHANE COAL GASIFICATION PLANT AT COLSTRIP,
MONTANA 262
xx
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LIST OF TABLES (Continued)
VOLUME II
Number Page
3-107 ESTIMATED PRODUCT FLOW RATES FOR A TYPICAL
30,000 TPD SRC-II PLANT 281
3-108 SCHEDULE OF MANPOWER REQUIREMENTS FOR CONSTRUCTION
OF A 30,000 TPD COAL LIQUEFACTION FACILITY 282
3-109 MANPOWER REQUIREMENTS FOR OPERATION OF A 30,000
TPD COAL LIQUEFACTION FACILITY 283
3-110 SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF A 30,000 TPD COAL LIQUEFACTION
PLANT 285
3-111 MAJOR MATERIALS REQUIRED FOR OPERATION OF A 30,000
TPD COAL LIQUEFACTION PLANT 286
3-112 CAPITAL INVESTMENT COSTS FOR SRC-II PLANT
(1976 Dollars) 288
3-113 OPERATING COSTS FOR SRC-II PLANT (1976 Dollars) 290
3-114 REQUIRED SELLING PRICE FOR INVESTMENT RETURN
(1976 Dollars) 291
3-115 WATER CONSUMPTION FOR A 30,000 TPD SRC PLANT 292
3-116 COAL ANALYSIS FROM THE POWDER RIVER COAL FIELD;
CAMPBELL COUNTY, WYOMING 296
3-117 AIR EMISSIONS FROM A 30,000 TPD SRC-II COAL
LIQUEFACTION PLANT 298
3-118 SRC-II PLANT FUEL GAS REQUIREMENTS (30,000 tpd) 301
3-119 SRC-II PLANT FUEL GAS COMBUSTION CHARACTERISTICS... 302
3-120 DESIGN BASIS FOR-CALCULATING STORAGE EMISSIONS 305
3-121 TRACE ELEMENT ANALYSIS OF A TYPICAL U.S. COAL 306
3-122 CHEMICAL COMPOSITION OF SOLVENT FRACTION 308
3-123 CHEMICAL COMPOSITION OF SOLVENT FRACTION 309
3-124 WASTEWATER FLOWS FROM A 30,000 TPD SRC PLANT 310
3-125 ANALYSIS OF FOUL PROCESS CONDENSATES FROM PITTSBURG
AND MIDWAY SRC PILOT PLANT 312
3-126 CONCENTRATIONS OF ORGANIC COMPOUNDS IN COAL
CONVERSION PROCESS WASTES 313
3-127 WATER QUALITY OF COAL PILE RUNOFF 314
xxi
-------
LIST OF TABLES (Continued)
VOLUME II
Number Page
3-128 SUMMARY OF IMPACTS ASSOCIATED WITH A 30,000 TPD
SRC-II COAL LIQUEFACTION PLANT AT GILLETTE,
WYOMING 320
3-129 GENERATING CAPACITY UTILIZING FGD SYSTEMS
JUNE 1977 339
3-130 NUMBER AND TOTAL MW OF FGD SYSTEMS JUNE 1977 340
3-131 SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED TO CONSTRUCT A 3,000 MW POWER PLANT 345
3-132 MANPOWER RESOURCES REQUIRED TO OPERATE AND MAINTAIN
A 3 ,000 MW POWER PLANT 346
3-133 SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF A 3,000 MW POWER PLANT 347
3-134 CHARACTERISTICS OF GILLETTE, WYOMING COAL 350
3-135 AIR EMISSIONS - 3,000 MW POWER PLANT BURNING
GILLETTE, WYOMING COAL 353
3-136 SUMMARY OF IMPACTS ASSOCIATED WITH A 3000 MW
POWER PLANT AT GILLETTE, WYOMING 357
3-137 FEDERAL NEW SOURCES OF COAL BURNING EMISSION
STANDARDS 36 1
3-138 OSHA NOISE LEVEL STANDARDS 36 3
xxii
-------
CONVERSION FACTORS
ENGLISH UNITS/METRIC UNITS
To Convert From
To
Multiply By
acre
acre-ft/year
acre-ft/year
Btu
Btu/hr
ft
gpm
hp
Ib
psi
ton
gpm
m3/yr
joules
watts
m
m3/min
watts
kg
pascal
kg
4046.9
0.6200
1233.5
1054.4
0.2931
0.3048
0.003785
745.7
0.4536
6894.8
907.18
xxiii
-------
ACKNOWLEDGEMENTS
Clinton E. Burklin and William J. Moltz of the Radian Corp-
oration had primary responsibility for preparation of this volume
of the Energy Resource Development Systems (ERDS) Report. The
social controls sections were prepared by Rodney K. Freed of the
Science and Public Policy Program at the University of Oklahoma.
Mr. Freed is now an attorney in Shawnee, Oklahoma.
The research reported here could not have been completed with-
out the assistance of a dedicated administrative support staff.
At Radian Corporation, Mary Harris was responsible for typing of
this volume, and at the University of Oklahoma, Janice Whinery,
Assistant to the Director, coordinated assembly of the volumes of
the ERDS Report.
Nancy Ballard, graphics arts consultant, designed the title
page.
Steven E. Plotkin, EPA Project Officer, has provided contin-
uing support and assistance in the preparation of this report.
The individuals listed below participated in the review of
this volume of the ERDS Report and provided information for its
preparation. Although these critiques were extremely helpful,
none of these individuals is responsible for the content of this
volume. This volume is the sole responsibility of the Science
and Public Policy interdisciplinary research team and the Radian
Corporation.
Dr. L.E. Craig Mr. Lionel S. Johns
Director, Energy Information Program Manager
Division Office of Technology Assessment
Kerr-McGee Corporation U.S. Congress
Oklahoma City, Oklahoma Washington, D.C.
Dr. John Hoover Mr. Leo McReynolds
Energy and Environmental Research and Development Depart-
Systerns ment
Argonne National Laboratory Phillips Petroleum Company
Chicago, Illinois Bartlesville, Oklahoma
xxiv
-------
Mr. William L. Rogers
Manager, Environmental Affairs
Gulf Mineral Resources Co.
Denver, Colorado
Prof. Edward S. Rubin
Mechanical Engineering and
Public Affairs
Carnegie-Mellon University
Pittsburgh, Pennsylvania
Dr. M.D. Schlesinger
Pittsburgh Energy Research
Laboratory
Department of Energy
Pittsburgh, Pennsylvania
Mr. Terry Thoem
Office of Energy Activities
Environmental Protection Agency
Region VIII
Denver, Colorado
XXV
-------
CHAPTER 3
THE COAL RESOURCE DEVELOPMENT SYSTEM
3.1 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. This document is issued as Chapter 3 of the "Energy
Resource Development System" (ERDS) report. For each of six
Western energy sources, the ERDS report describes the energy
resource base, the technologies used to develop and utilize 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 coal
resources. The chapter comprises eight major sections which
begin with a general description of the coal resource.
Section 3.2 then presents a summary of the input require-
ments and outputs identified in this study as resulting from the
development and utilization of the Western coal resouce.
-------
Section 3.3, Coal Resources, describes the characteristics
of the Western coal resource. Among the physical characteristics
this section includes coal type, rank, quality and general
composition of western coals. This section also reviews the
location of western coal reserves, their recoverability, and
their ownership.
Section 3.4 is a regional overview of the number, size, and
types of coal mining operations currently conducted in each of
the eight western states of this study.
The remaining sections describe the development of the coal
resource as a basic sequence of activities. These activities
include exploration, mining, benificiation, and conversion. For
each activity, technological alternatives are discussed which
represent potential development options, (e.g. coal can be mined
underground, in open pits, or by strip mining). The discussion
of each activity includes the input requirements, the outputs,
and the social control associated with or affecting the develop-
ment activity. Input requirements include: manpower, materials
and equipment, economics, water, land, and ancillary energy.
The outputs include the residuals from the activity that may
pose environmental hazards such as: air emissions, water
effluents, solid wastes, noise pollution, occupational health
and safety hazards, and odors. Social controls comprise the
laws and regulations, on both the local and national level,
governing the development of coal resources.
Section 3.5 discusses the technologies, inputs, outputs,
and social controls associated with coal exploration activities.
Section 3.5 discusses the same items for the mining of coal
including underground and surface mining technologies. Section
3.7 discusses coal beneficiation technologies and Section 3.8
discusses coal conversion technologies including gasification,
liquefaction, and electrical generation.
-2-
-------
TABLE 3-1. SUMMARY OF IMPACTS ASSOCIATED WITH THE EXPLORATION
OF A 30,000 TON PER DAY COAL MINE IN WESTERN U.S.
Inputs
Manpower
• geological activities
• drilling activities
Materials and Equipment
• vehicles
• drilling rigs
• well logging
Economics3
• geological activities
• drilling activities
Water
Land
Ancillary Energy
Outputs
Air Emissions
Water Effluents
Solid Wastes
Noise
Occupational Health and Safety
15.5 man-years
1.5 man-years
supplied by
contractor
$600,000/mine
$200,000/mine
negligible
temporary and negligible
minor
minor
5 acre-ft/mine (6170 m3/mine)
minor
temporary
negligible
a!977 dollars
-3-
-------
3.2 SUMMARY
The input requirements and outputs associated with each
phase of the coal resource development system are summarized in
Tables 3-1 through 3-8. The input requirements include manpower,
materials and equipment, economics, water, land, and ancillary
energy. The outputs include air, water, and solid waste
emissions, noise, odor, and occupational safety and health.
These tables present typical values for a given design
basis. The input requirements and outputs will vary signifi-
cantly with the mode and size of operation, location, specific
resource quality, and choice of technology option. The design
basis and assumptions applied to develop these tables are
described in detail in their respective section of the text.
-4-
-------
TABLE 3-2.
SUMMARY OF IMPACTS ASSOCIATED WITH 12 MM TPY
SURFACE MINE AT NAVAJO
Inputs
Manpower
• construction
• operating
Materials and Equipment
• stripping shovels (140 cu yd)
• cement
• structured steel
• draglines
Economics
• capital cost (estimated)
• annual operating cost (estimated)
Water (reclamation)
Land
Ancillary Energy
• electricity
• diesel fuel
Outputs
Air Emissions
• hydrocarbons
• particulates
• S02
• NOX
• CO
• C02
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
• deaths
• injuries
• lost man-days
832 man-years
552 men
62,800 tons (57 Mkg)
940 tons (0.85 Mkg)
10,400 tons (9.4 Mkg)
$104 million
$ 46 million
4,000 acre-ft/yr (9.4 m3/min)
20,000 acres (30 yr total) (80.9 Mm2)
240 acres (at a time) (0.97 Mm2)
55 x 106 kwhr/yr (59 TJ/yr)
1.8 x 10s gal/yr (0.013 m3/min)
8 Ib/hr (3.6 kg/hr)
1700 Ib/hr (773 kg/hr)
8 Ib/hr (3.6 kg/hr)
100 Ib/hr (45 kg/hr)
23 Ib/hr (10 kg/hr)
5500 Ib/hr (2500 kg/hr)
recycled
returned to mine
insignificant
0.6 deaths/yr
19 injuries/yr
1300 man-days/yr
a
1974 dollars
-5-
-------
TABLE 3-3. SUMMARY OF IMPACTS ASSOCIATED WITH A 12 MM TPY
UNDERGROUND COAL MINE AT KAIPAROWITS
Inputs
Manpower
• construction
• operat ing
Materials and Equipment
• continuous miners
• loading machines
• ready mixed concrete
• structural steel
• reinforcing bars
• piping
Economics3
• capital costs
• operating costs
Water
Land
• at any given time
• 30 year total
Ancillary Energy
Outputs
Air Emissions
• particulates
• hydrocarbons
Water Effluents
Solid Wastes
Noise
Occupational Health and Safety
• fatalities
injuries
• lost man-days
2,330 man-years
2,384 men
64
64
92,000 tons (83.5 Mkg)
6,000 tons (5.4 Mkg)
6,800 tons (6.2 Mkg)
4,600 tons (4.2 Mkg)
$308 million
$100 million
None
2,750 acres (11.1 Mm2)
36,000 acres (145.7 Mm2)
3.5 x 1012 Btu/yr (3.7 PJ/yr)
0.35 ton/day (317 kg/day)
144 ton/day (131 Kkg/day)
highly site dependent
78 tons/day
insignificant
7.2 deaths/yr
370 injuries/yr
210,000 man-days
a!974 dollars
-6-
-------
TABLE 3-4. SUMMARY OF IMPACTS ASSOCIATED WITH A
25,000 TPD COAL BENEFICIATION PLANT
Inputs
Manpower
• construction
• operating
Materials and Equipment
Economics
• capital cost
• operating cost
Water
Land
Ancillary Energy
Outputs
Air Emissions
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
• deaths
• injuries
• man-days lost
258 man-years
22 men
Table 3-58
$36.5 million
$2.8 million/yr
1400 gpm (5 m3/min)
90 acres (364 Km2)
1.7 x 109 Btu/day (0.65 PJ/yr)
7 Ib/hr (3.2 kg/hr)
none
8,000 ton/day (7 Mkg/day)
negligible
0.56 deaths/yr
11 injuries/yr
4,900 man-days/yr
1974 dollars
-7-
-------
TABLE 3-5.
SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
LURGI COAL GASIFICATION PLANT AT COLSTRIP, MONTANA
Input Requirements
Manpower
• construction
• operating
Materials and Equipment
• structural steel
• piping
• ready mixed concrete
Economics
• capital costs
• operating costs
Water
Land
Ancillary Energy
Outputs
Air Emissions
• particulates
• S02
• NOX
• HC
• CO
Water Effluent (plant)
• to ash ponds
• to evaporation ponds
Solid Wastes
• ash
• water treatment sludge
spent catalyst
Noise Pollution
Occupational Health and Safety
fatalities
• accidents
• man-days lost
10,781 man-years
589 men
14,000 tons (12.7 Mkg)
58,000 tons (52.6 Mkg)
180,000 tons (163.3 Mkg)
$750 million
$9.8 million
9,263 acre-ft/yr (21.7 mVmin)
800 acres (3.2 Mm2)
none
negligible
516 Ib/hr (234 kg/hr)
495 Ib/hr (225 kg/hr)
953 Ib/hr (433 kg/hr)
negligible
310 gpm (1.1 m3/min)
820 gpm (3.1 mVmin)
225,000 Ib/hr (102 Kkg/hr)
500 Ib/hr (227 kg/hr)
intermittent
negligible
0.45 deaths/yr
15 injuries/yr
4,200 man-days yr
^hird-quarter 1974 dollars
-8-
-------
TABLE 3-6. SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
SYNTHANE COAL GASIFICATION PLANT AT COLSTRIP, MONTANA
Input Requirements
Manpower
* construction
• operating
Materials and Equipment
• structural steel
• piping
* ready mixed concrete
Economics3
• capital costs
• operating costs
Water
Land
Ancillary Energy
Outputs
Air Emissions
• particulates
• S02
• NOX
• HC
• CO
Water Effluent (plant)
• to ash ponds
• to evaporation ponds
Solid Wastes
• ash
• limestone sludge
• spent catalyst
Noise Pollution
Occupational Health and Safety
• fatalities
• accidents
• man-days lost
10,781 man-years
689 men
14,000 tons (12.7 Mkg)
58,000 tons (52.6 Mkg)
180,000 tons (163.3 Mkg)
$750 million
$9.8 million
29,036 acre-ft/yr (68 m3/min)
800 acres (3.2 Mm2)
none
8 Ib/hr (3.6 kg/hr)
3524 Ib/hr (1602 kg/hr)
5052 Ib/hr (2296 kg/hr)
1047 Ib/hr (476 kg/hr)
176 Ib/hr (80 kg/hr)
310 gpm (1.1 m3/min)
820 gpo (3.1 mVmin)
180,000 Ib/hr (82 Kkg/hr)
110,000 Ib/hr (50 Kkg/hr)
intermittent
negligible
0.45 deaths/yr
15 injuries/yr
4,200 man-days/yr
^hird-quarter 1974 dollars
-9-
-------
TABLE 3-7. SUMMARY OF IMPACTS ASSOCIATED WITH A 30,000 TPD
SRC-II COAL LIQUEFACTION PLANT AT GILLETTE, WYOMING
Input Requirements
Manpower
• construction
• operating
Materials and Equipment
• fabricated steel
• concrete
• refined products
Operating Reagents
Economics
• capital costs
• operating costs (excluding coal costs)
Water
• @ 100% reuse and recycle
• @ current development plans
Land
Ancillary Energy
Outputs
Air Emissions
• particulates
• SO,
• total organics
• CO
• NOX
• NH3
• C02
Water Effluents
Solid Wastes
Noise
Odor
Occupational Health and Safety
• fatalities
• injuries
• man-days lost
21,900 man-years
1,600 men
200,000 tons (181 Mkg)
288,000 tons (261 Mkg)
50,000 tons (45 Mkg)
40 tons/day (36 Kkg/day)
$1.2 - $1.3 billion
$219 million/year
4 million gal/day (10.5 mVmin)
17 million gal/day (45 m3/min)
1800 acres (7.3 Mm2)
41 MW (1.3 PJ/yr)
475 Ib/hr (216 kg/hr)
248 Ib/hr (113 kg/hr)
1,067 Ib/hr (485 kg/hr)
126 Ib/hr (57 kg/hr)
1,280 Ib/hr (582 kg/hr)
12 Ib/hr (5 kg/hr)
858,000 Ib/hr (390,000 kg/hr)
negligible
2,500 tons/day (2.3 Mkg/day)
negligible
trace
0.32 deaths/yr
6.2 injuries/yr
1494 man-days/yr
1976 dollars
-10-
-------
TABLE 3-8. SUMMARY OF IMPACTS ASSOCIATED WITH A 3000 MW POWER
PLANT AT GILLETTE, WYOMING
Input Requirements
Manpower
• construction phase
• operation and maintenance
Materials and Equipment
9,960 man-years
436 people
• refined products
• ready mix concrete
• piping
• steel
» steam turbogenerators
• boilers
Economics
• capital cost
• operating cost (excluding coal)
Water
Land
Ancillary Energy
Outputs
Air Emissions
• particulates
• sox
• NOX
• CO
• HC
• aldehydes
• C02
Water Effluents
• to zero discharge solar evap. ponds
Solid Wastes
• ash
• FGD scrubber sludge
Noise Pollution
Occupational Safety and Health
• fatalities
• injuries
• lost time
72,000 tons (65 Mkg)
456,000 tons (414 Mkg)
13,000 tons (12 Mkg)
26,000 tons (24 Mkg)
4 million hp
28 billion Btu/hr
$880 million
$11 million
42,000 acre-ft/year (98 m3/min)
2,400 acres (9.7 Mm2)
none
14 ton/day (12.7 Kkg/day)
77 ton/day (69.9 Kkg/day)
316 ton/day (286.7 Kkg/day)
18 ton/day (16.3 Kkg/day)
5 ton/day (4.5 Kkg/day)
0.1 ton/day (90 kg/day)
76,800 ton/day (70 Mkg/day)
2,096 acre-ft/year (4.9 m3/min)
1,745 ton/day (1.58 Mkg/day)
1,488 ton/day (1.35 Mkg/day)
minimal
0.77 deaths/yr
3.2 injuries/yr
1200 man-days/yr
^hird-quarter 1974 dollars
-11-
-------
3.3 COAL RESOURCES
Coal is a combustible natural solid formed from fossilized
plants. It is dark brown to black in color and consists pri-
marily of carbon (more than 50 percent by weight) in the form
of numerous complex organic compounds. The composition of coal
varies considerably from region to region and within given de-
posits.
Coal is generally found as a layer in sedimentary rock.
These layers, called seams or beds, differ greatly in thickness,
depth below the surface, and areal extent. In this section,
western coal resources are described in terms of quantity, char-
acteristics, location, and ownership.
3.3.1 Background
Although native Americans have apparently used western coal
for centuries, the first recorded coal production in the West
was in Colorado in 1864.1 By then, coal was already becoming
the principal energy source for the entire U.S., a position
which it maintained from the 1880 *s until shortly after World
War II.2 The high point for coal came in 1910, when it supplied
approximately 75 percent of the total U.S. energy demand. From
that time until 1972, coal supplied a decreasing percentage of
U.S. energy; and in 1975 it supplied only 18 percent of total
^eilson, George F., ed. 1974 Keystone Coal Industry Manual
New York: McGraw-Hill Mining Publications, 1974, p. 535.
2U.S. Congress, Senate Committee on Interior and Insular
Affairs. A National Fuels and Energy Policy Study. Hearings.
92d Cong., 1st sess., October 20, 19/1 (pp. 94-102, reprinted
from Scientific American, Vol. 225, September 1971).
-12-
-------
U.S. consumption.* During 1975, coal consumption and production
increased slightly. Given a national energy policy which
emphasizes decreased dependence on external sources, coal
production is expected to increase even further. Some forecasts
now suggest that western coal production may more than double
by 1985.2
3.3.2 Total National Resource Endowment
The U.S. Geological Survey (USGS) estimates the total re-
maining coal resources of the U.S. to be more than three tril-
lion tons;3 however, as indicated in Table 3-9, the proportionk
of this estimate, classified as identified and recoverable, is
substantially less than the total. In fact, only about 195 bil-
lion tons are classified as reserves, meaning they are (1) known
in location, quantity, and quality from geologic evidence sup-
ported by engineering measurements, and (2) economically recover-
able based upon currently available technologies, and current
market value.
Almost 1.2 trillion tons of identified coal resources can-
not be economically mined at present, and an additional 1.6
1Enzer, Hermann, Walter Dupree, and Stanley Miller. Energy
Perspectives; A Presentation of Major Energy and Energy-Related
Data.Washington:U.S. Dept. of the Interior, 1975, p. 36.
2U.S., Federal Energy Administration. National Energy
Outlook. Washington: FEA, 1976, pp. 200-203":
3The estimates are 2.9 trillion tons within 3,000 feet and
3.2 trillion tons within 6,000 feet of the surface. All esti-
mates are in short (2,000-pound) tons.
-13-
-------
TABLE 3-9. COAL RESOURCES OF THE U.S.a (Billions of Tons)
Feasibility
of
Recovery
Recoverable
Submarginal
Discovered
0-3,000 feet
overburden
956
1,2858
Knowledge of Resource
Undiscovered
0-3,000 feet
overburden
0
1,300
Resources
3,000-6,000 feet
overburden
0
340
Reliability of estimates decreases downward and to the right.
Unspecified bodies of mineral-bearing material surmised to exist on the
basis of broad geologic knowledge and theory.
f*
Resources which are both identified and recoverable are termed "reserves"
Coal in beds 42 inches or more thick for bituminous coal and anthracite and
10 feet or more thick for subbituminous coal and lignite; over burden not
more than 1,000 feet.
6
Additional coal recoverable in beds 28 to 42 inches thick for bituminous
coal and anthracite and 3 to 5 feet thick for subbituminous coal and lignite;
overburden not more than 1,000 feet.
Resources which are technically possible but not economic to mine; a sub-
stantially higher price (more than 1.5 times the price at the time of the
estimate) or a major cost-reducing advance in technology would be required
for these resources to become reserves.
g
Additional coal recoverable in beds at least 14 inches thick for bituminous
coal and anthracite and 2-1/2 feet thick for subbituminous coal and lignite;
overburden not more than 3,000 feet.
Sources: Averitt, Paul. "Coal," Donald A. Brobst and Walden P. Pratt, eds.
United States Mineral Resources, U.S. Geological Survey Pro-
fessional Paper 820. Washington: Government Printing Office,
1973, pp. 133-142.
Theobald, P. K., S. P. Schweinfurth, and D. C. Duncan, eds.
Energy Resources of the United States, U.S. Geological Survey
Circular 650. Washington: Government Printing Office, 1972, p. 3.
-14-
-------
trillion tons have not actually been identified but are surmised
to exist on the basis of broad geologic knowledge and theory.
Assuming an average heating value of 10,000 Btu's per
pound, U.S. coal resources have an energy value equivalent to
850 times the total U.S. energy consumption in 1970.l The 195
billion tons of coal "reserves" are equivalent to 55 times the
total U.S. energy consumption for that year.
U.S. coal resources account for approximately 32 percent of
world coal resources.2 The Sino-Soviet Bloc possesses a very
large share of the remaining 68 percent.
3.3.3 Characteristics of the Resources
Coals are classified on the basis of specific compositional
characteristics such as carbon content, heating value, and impu-
rities. Anthracite and bituminous coals are primarily ranked on
the basis of fixed carbon content (Figure 3-1) .3 Subbituminous
coals and lignite, which contain less fixed carbon, are ranked
on the basis of heating value (Figure 3-2). As indicated in
Table 3-10, approximately 70 percent of all U.S. coal is bitumi-
nous or subbituminous, while only about one percent is anthracite.
In addition to being ranked, coals are graded on the basis
of the impurities that they contain. Certain impurities
aTotal U.S. energy consumption in 1970 was 69 x 101 s Btu's,
2Averitt, Paul. "Coal," in Donald A. Brobst and Walden P.
Pratt, eds. United States Mineral Resources, U.S. Geological
Survey Provessional Paper 820.Washington: Government Print-
ing Office, 1973, pp. 133-142.
3Fixed carbon is the solid, nonvolatile portion of coal
that is combustible. Rank is one method of categorizing the
degree of chemical transformation from ancient plant deposits.
-15-
-------
100
80
o
o
o
CO
os
5
o
LU
X
o
LU
Q.
60
40
20
LU
CO
CO
CO
CO
ra
o
CO
RANK
Figure 3-1. Range in Fixed Carbon Contents of Major Coal Ranks
-16-
-------
o
=5
C£
LU
O.
CO
00
CO
0
16
14
12
10
8
0
- UJ
CD
nsi
%K
Svi
CO
co
CO
CO
CO
o
CO
LU
I—
I—I
O
RANK
Figure 3-2. Range in Heat Contents of Major Coal Ranks
-17-
-------
TABLE 3-10. RANK OF IDENTIFIED U.S. COAL RESOURCES
Rank Identified Resources
(Billions of Tons)*
Anthracite 21
Bituminous 686
Subbituminous 424
Lignite 449
TOTAL 1,580
aln short tons (2,000 pounds).
Source: Averitt, Paul. "Coal," Donald A. Brobst and
Walden P. Pratt, eds. United States Mineral
Resources, U.S. Geological Survey Professional
Paper 820. Washington: Government Printing
Office, 1973, pp. 133-142.
-------
(including moisture, ash, and sulfur) present problems when
coal is processed and utilized. Moisture ranges from one per-
cent in some anthracites to more than 40 percent in some
lignites.1
The ash content of coal (the amount of noncombustible in-
organic materials the coal contains) varies considerably even
within a single seam, making proportional generalization dif-
ficult. For example, in a 1942 study of 642 typical U.S. coals,
investigators found that ash content ranged from 2,5 to 32.6
percent.2
One impurity that causes great difficulty is sulfur. The
sulfur content of U.S. coals ranges from 0.2 to 7.0 percent,
varying considerably between geographic regions. Most of the
low-sulfur coal (coal with a sulfur content of one percent or
less) is located in the western U.S.3 On an equivalent Btu
basis, however, the contrast in sulfur contents between western
and eastern coals is often diminished because western coals
generally have a lower heating value then do eastern coals. A
comparison of sulfur content and heating value for various
coals is shown in Table 3-11.
3.3.4 Location of the Resources
Coal occurs in many parts of the U.S.: bituminous in
Appalachia and the drainage basin of the Mississippi River; a
1U.S., Department of the Interior, Bureau of Land Manage-
ment . Draft Environmental Impact Statement: Proposed Federal
Coal Leasing Program. 2 vols.Washington:Government Printing
Office, 1974.
2 Ibid.
3Ibid., Vol. I, p. 1-57.
-19-
-------
TABLE 3-11. COMPARISON OF EASTERN AND WESTERN COAL QUALITIES
O
I
Maximum Allow-
able Sulfur
Concent Under
New Source
Heat Content Performance Moisture
Btu/lb Sulfur Content Standards Content8
A. "Typical" Eastern Coals
1. Anthracite (Pennsylvania) 14,000
2. Bituminous (Appalachian, 13,000
Central States)
B. "Typical" Western Coals
1. Bituminous (deep) . 13,000
(Colorado, Utah,
Wyoming, 'New Mexico)
2. Sub-Bituminous 8,000
(Montana, Wyoming, to
Colorado, New Mexico) 9,500
3. Lignite (Montana, North 6,000
and South Dakota)
0.72 or less 1Z 5Z
less than 0.7Z 0.78Z 5Z
to over 4Z
less than 0.7Z 0.78Z 5Z
to l.OZ, with
minor quantities
up to and over
4Z
less than 0.7Z 0.48Z 2SZ
to 2Z to
0.57Z
less than 0.7Z 0.36Z 40Z
to 1.5Z
Amount Mined
to Obtain
1x10* Btu's
71 Ibs
77 Ibs
77 Ibs
125 Ibs
to
105 Ibs
167 Ibs
Moisture content is a function primarily of local and regional hydrology; sub-bituminous and lignite deposits
in the west typically function as aquifers.
Source for Chart: Environmental Policy Center. Facts About Coal in the United States.
mental Policy Center, 1974 Data, USGS and U.S. Bureau of Mines.
Washington: Environ-
-------
mixture of ranks in the Northern Great Plains and Rocky Moun-
tains; and scattered deposits elsewhere (Figure 3-3). However,
almost 90 percent of all coal resources in the contiguous 48
states are located in four USGS coal provinces: the Eastern,
Interior, Northern Great Plains, and Rocky Mountain (Table 3-12).
The provinces1 located in the western states are described in
the following regional overview; Section 3.4.
3.3.5 Recoverability of the Resources
Two of the most important factors in the recoverability of
coal are bed depth and seam thickness. Although both are major
economic factors, bed depth is often the more important because
of the lower cost and relatively greater safety of surface mining,
In 1965, the average depth of coal being mined from the surface
was 55 feet and the average seam thickness was 5.2 feet, giving
a ratio of overburden-to-seam thickness of roughly 10:1.2 This
ratio has been increasing as mining technologies have advanced,
and a 30:1 ratio is now estimated to be reasonable for the mid-
*
1970's.3 Whether or not a 30:1 ratio is generally reached,
*A province, the largest unit used by USGS to define the
areal extent of coal resources, is made up of regions of the
basis of similarity in the physical features of coal fields,
coal quality, and contiguity. Regions are made up-of fields
which are made up of districts. A field is a recognizable
single coal-bearing territory; a district is an identifiable
center of coal mining operations. These four terms provide a
convenient means for aggregating and disaggregating data on
coal resources and production.
2Young, W. H. Thickness of Bituminous 'Coal and Lignite
Seams Mined in 1965, Bureau of Mines Information Circular 8345.
Washington: Government Printing Office, 1967, p. 18.
3Averitt, Paul. Stripping-Coal Resources of the United
States—January 1, 1970, U.S. Geological Survey Bulletin 1322.
Washington: Government Printing Office, 1970. Note: Selected
thin seams of coal for metallurgical use are presently mined at
a 40:1 ratio in Oklahoma (Johnson, 1974).
-21-
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'Coast Province
'Rocky Mountain Province
'Northern Great Plains Province
Interior Province
Anthracite
Bituminous coal
Subbituminous coal
Lignite
Eastern Province
Figure 3-3. Distribution of United States Coal Resources.
Source: U.S., Department of the Interior, Bureau of Land
Management. Draft Environmental Impact Statement:
Proposed Federal Coal Leasing Program. 2 vols.
Washington:Government Printing Office. 1974.
-------
TABLE 3-12. COAL RESOURCES IN U.S. GEOLOGICAL SURVEY
PROVINCESa (Billions of Tons)
Province Identified Undiscovered Total
Eastern 276 45 321
Interior 277 259 536
Northern Great 695 763 1,458
Plains
Rocky Mountains 187 395 582
Other 146 181 327
aBecause available estimates are by state and USGS Provinces
cross state boundaries, the figures for these provinces are
only approximate.
Source: Averitt, Paul. "Coal," Donald A. Brobst and Walden P,
Pratt, eds. United States Mineral Resources, U.S.
Geological Survey Professional Paper 820.Washington:
Government Printing Office, 1973, pp. 133-142.
-23-
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approximately 45 billion tons of coal are now considered
economically recoverable using available surface mining tech-
nologies. l
3.3.6 Ownership of Resources
The development of a coal, regardless of its compositional
characteristics, depth, and seam thickness, depends in large
part on the ownership of the lands and/or mineral rights. The
federal government owns approximately 48 percent of all coal
lands located in Alaska, Colorado, Montana, North Dakota,
Oklahoma, Utah, and Wyoming.2 Although overall data are not
available, apparently the federal government owns less than four
percent of the coal lands in each of the other states. In any
case, the major coal lands in the eastern and midwestern U.S.
are privately owned.
Most U.S. coal is mined from privately-owned lands. In
1971, only about three percent of the coal produced in the U.S.
was mined from lands owned by the federal government or Indians .3
In part, this is because only about 800.000 acres of federal
coal lands (one percent of the more than 85 million acres of
coal lands that are federally owned) have been leased for de-
velopment. This pattern will change as more mines are opened
in the Northern Great Plains and Rocky Mountain provinces.
^.S., Department of the Interior, Bureau of Mines.
Strippable Reserves of Bituminous Coal and Lignite in the
United States, Information Circular 8351.Washington:G~overn-
ment Printing Office, 1974, Vol. 1, p. V-208.
2U.S., Department of the Interior, Bureau of Land Manage-
ment, Draft Environmental Impact Statement; Proposed Federal
Coal Leasing Program, 2 vols.Washington:Government Printing
Office, 1974, 2 vols. Washington: Government Printing Office,
1974, Vol. 1, p. V-208.
3ibid., Vol. I, p. 1-64.
-24-
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Reserves presently committed under lease and preference
right lease application are not well defined. Surface and
mineral ownership for the Northern Great Plains Province is
shown in Table 3-13. The issue of surface and mineral owner-
ship and how it affects coal leasing and development is dis-
cussed in the social controls, leasing section following.
-25-
-------
I
to
TABLE 3-13. SURFACE AND MINERAL OWNERSHIP OF STUDY AREA BY OWNER
AND STATE (In Percent of Total)
Owner
State
Montana
North Dakota
South Dakota
Wyoming
Type of
Ownership
Surface
Mineral
Surface
Mineral
Surface
Mineral
Surface
Mineral
Federal
Acres
17.0
33.0
7.3
20.3
5.6
12.1
22.9
42.6
Indian
Acres
8.2
7.9
.2.7
3.8
16.6
18.0
0
0
County
Municipal
and Private
acres3
69.0
53.3
87.5
73.4
71.9
57.0
68.5
48.7
State
Acres
5.8
5.8
2.5
2.5
12.0
8.7
Total
Acres
Million
34,5
26.7
11.7
18.6
Included substantial surface and mineral rights held by the Bur lington*-Nor them
Railroad.
Source: Northern Great Plains Resources Program. Surface Resources Work Group »
Impact Analysis, Discussion Draft. Denver";Northern Great Plains
Resources Program, 1974.
-------
3.4 A REGIONAL OVERVIEW
3.4.1 The Northern Great Plains Province
As illustrated in Figure 3-4, the Northern Great Plains
Province, which contains 45 percent of the remaining coal re-
sources in the U.S., is made up of six regions. The two largest
regions, Fort Union and Powder River, contain almost 1.5 tril-
lion tons of coal or approximately 5070 of total estimated U.S.
reserves (Table 3-14), most of which is owned by the federal
government. Indian tribes and railroads are also large owners.
Most of the coal within the province is relatively low in
rank, lignite in the Fort Union Region and thick deposits of
subbituminous in the Powder River Region. Near the edge of the
Rocky Mountains, the coal is somewhat higher in rank. The
moisture and volatile matter content of both Fort Union and
Powder River coals are relatively high and, as indictated by
their low rank, both tend to be low in energy value. However,
more than 657 billion tons or about 44 percent of the province's
coal is low sulfur.
Although seam depth and thickness in the province vary
considerably, some beds are quite thick and near enough to the
surface to allow surface mining.
Much of the surface area of the province is still covered
by native vegetation. However, some parts of the province,
particularly the areas along the Missouri River, are farmed
intensively.
Water supplies are not abundant, and most of the surface
water is found in the Northern Missouri River drainage basin.
-27-
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ASSINIBOINE REGION
FORT UNION REGION
: PlatteR.
NEB.
Si PlatteR.
JUDITH
BASIN
REGION
POWDER
RIVER REGION
COLO.
f
DENVER REGION
RATON MESA REGION
Figure 3-4. Distribution of Coal in the Northern
Great Plains Province .
Source: U.S., Department of the Interior, Bureau of
Land Management. Draft Environmental Impact
Statement: Proposed FederaT Coal Leasing
"
Program 2 vols.
Printing Office.
Washington: Government
1974. p. 11-132.
-28-
-------
TABLE 3-14. COAL RESOURCES IN THE NORTHERN
GREAT PLAINS PROVINCE
Amount
Depth Status (Billion
(feet) Tons)
0-1,000 Recoverable 106a
0-3,000 Thin bed and 589
identified
0-3,000 Undiscovered 663
3,000-6,000 Undiscovered 100
TOTAL 1,458
aDoes not include mining losses. Coal out-of-the-ground would
be approximately 50 percent of this value.
Sources: U.S. Department of the Interior, Bureau of Land
Management. Draft Environmental Impact Statement:
Proposed Federal Coal Leasing Program, 2 vols.
Cashington:Government Printing Office, 1974,
pp. 1-69.
Averitt, Paul. "Coal," Donald A. Brobst and Walden
P'. Pratt, eds. United States Mineral Resources,
U.S. Geological Survey Professional Paper 820.
Washington: Government Printing Office, 1973, p. 137,
-29-
-------
Much of this water comes from runoff from the mountains to the
west. The average annual runoff for the Northern Great Plains
Province ranges from less than 1 inch up to 10 inches.
3.4.2 The Rocky Mountain Province
The largest three of the Rocky Mountain Province's eight
regions (Figure 3-5) are the Green River, Uinta, and San Juan
River. As shown in Table 3-15, estimated remaining resources in
the province are more than 580 billion tons, 187 billion of
which have been identified. Resource ownership in the province
is largely shared by the federal government, Indian tribes, and
railroads.
This province has the greatest variety in ranks and geologic
setting of any province in the U.S. Coals of greatest current
interest are subbituminous and low-grade bituminous, found
mainly in the southern part of the province and in the Green
River and Uinta Regions. Moisutre content tends to be low and
volatile matter content relatively high. Heating values range
from 5,000 to more than 14,000 Btu's per pound.1 Sulfur con-
tent is generally low, with almost 90 percent of identified re-
sources having a sulfur content of one percent or less.
The depth and thickness of coal seams in the province vary
greatly. A number of thick seams are being surface mined at
the present time; other, deeper seams are not.
^.S., Department of the Interior, Bureau of Land Manage-
ment . Draft Environmental Impact Statement: Proposed Federal
Coal Leasing Program, 2 vols. Washington:Government Printing
Office, iy/4, Vol. I, p. 1-57.
-30-
-------
HAMS FORK
REGION
SOUTHWESTERN
UTAH REGION
YELLOWSTONE
MONT.
BIGHORN
RIVER
REGION
WIND RIVER
REGION
Plalle R.
GREEN
RIVER REGION
Figure 3-5. Distribution of Coal in the Rocky Mountain Province
Source: U.S., Department of the Interior, Bureau of Land Manage-
ment. Draft Environmental Impact Statement: Proposed
Federal Coal Leasing Program. 2 vols. Washington:
Government Printing Office. 1974.
-31-
-------
TABLE 3-15. COAL RESOURCES IN THE ROCKY
MOUNTAIN PROVINCE
Amount
Depth Status CBillions of
(feet) Short Tons)
0-1,000 Recoverable 37a
0-3,000 Thin bed and 150
identified
0-3,000 Undiscovered 194
3,000-6,000 Undiscovered 201
TOTAL 582
aDoes not include mining losses. Coal out-of-the-ground
would be approximately 50 percent of this value.
Source: U.S. Department of the Interior, Bureau of Land
Management. Draft Environmental Impact Statement:
Proposed Federal Coal Leasing Program. 2 vols.
Washington:Government Printing Office, 1974,
p. 1-69.
Averitt, Paul. "Coal," Donald A. Brobst and
Walden P. Pratt, eds. United States Mineral Re-
sources . U.S. Geological Survey Professional Paper
820.Washington: Government Printing Office, 1973,
p. 137.
-32-
-------
Much of the province is still covered by natural vegetation,
and grazing is a major land use. Mining, logging, ranching, and
farming are other uses.
Except for the high mountains, precipitation averages less
than 16 inches a year, and large semidesert areas receive less
than eight inches. As a consequence, water is almost universally
scarce in the province.
The breakdown by states of the western coal reserve base is
given in Table 3-16. The total reserves in the western states
differ from that summed from Tables 3-14 and 3-15 because of the
omission of the Pacific Province (about one percent of the total
in the state of Washington), because the totals in Table 3-16
do not specify the seam thickness and depth of reserves, and
because a 100 percent recovery factor was included.
Coal production by state in 1976 was as follows:1
ARIZONA - One strip mine at Black Mesa in Navajo County
produced 10.2 million short tons (MMst) which was shipped
by slurry pipeline.
COLORADO2 - Twenty-one underground mines, two of which
produced more than one-half MMst each, in ten counties
produced a total of 4.2 MMst. Thirteen surface mines,
three of which produced over one-half MMst, in four
^eilson, George F., ed. 1977 Keystone Coal Industry Man-
ual. New York, New York: McGraw-Hill Mining Publications, 1977,
2Kimball, Dan, EPA Region VIII Coal Mine Report, Denver,
Colorado, Environmental Protection Agency, Forthcoming.
-33-
-------
TABLE 3-16. WESTERN COAL RESERVES BY STATE3 (Million Tons)
Potential Mining Method
Arizona
Colorado
Montana
New Mexico
North Dakota
South Dakota
Utah
Wyoming
TOTAL WESTERN STATES
TOTAL U.S.
Underground
0
14,000
65,165
2,136
0
3,780
27,554
114,082
297,235
Surface
350
870
42,562
2,258
16,003
428
262
23,674
86,915
136,713
Total
350
14,870
107,727
4,394
16,003
428
4,042
51,228
200,997
433,948
£*
Includes measured and indicated categories as defined by the
USBM and USGS and represents 100 percent of the coal in place.
Source: Dupree, Walter G., Jr. and John S. Corsentino. United
States Energy Through the Year 2000, Revised.
Washington: Bureau of Mines, 1975, p. 5 .
counties produced 7.7 MMst. Total production for Colorado
in 1977 was 11.9 MMst. Shipment of this coal was pre-
dominantly (78 percent) by rail.
MONTANA1 - Six strip mines, two of which produced about 10
MMst each and two of which produced over two MMst each, in
lKimball, Dan, EPA Region VIII Coal Mine Report, Denver,
Colorado, Environmental Protection Agency, Forthcoming.
-34-
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three counties produced 27 MMst of bituminous coal which
was shipped by rail. Two strip mines in two counties pro-
duced 320,000 tons of lignite which was also shipped by
rail.
NEW MEXICO - One underground mine which had approximately
one MMst production, and five strip mines, one of which
produced over six MMst, all of which were confined to
three counties produced 9.8 MMst, most of which is used
i
in mine mouth power generation. The remainder is shipped
by rail.
NORTH DAKOTA1 - Twelve strip mines, five of which pro-
duced over one MMst, in nine counties produced 12 MMst
of lignite, the major portion of which was either used
in mine mouth power generation or shipped by rail to
nearby South Dakota and Western Minnesota.
SOUTH DAKOTA - No coal production in 1976.
UTAH2 - Sixteen underground mines, only one of which pro-
duced over one MMst, in three counties produced 8.8 MMst,
most of which was shipped by rail and some by truck.
WYOMING3 - Four underground mines in three counties pro-
duce .62 MMst. Fifteen strip mines, twelve of which pro-
duce over one MMst each, in six counties produce 43.4
MMst of coal. Of that, approximately half is shipped out
of state by rail and one-fourth is used instate by generat-
ing plants. Total state production is 44.0 MMst.
^imball, Dan, EPA Region VIII Coal Mine Report, Denver,
Colorado, Environmental Protection Agency, Forthcoming.
2Ibid.
-35-
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3.4.3 SUMMARY
A number of important points emerge from this brief
description of U.S. coal resources. Four major provinces--
Rocky Mountain, Northern Great Plains, Interior, and Eastern—
contain more than 90 percent of all coal resources in the con-
tiguous 48 states. There are major differences between these
provinces in terms of the quantity and quality of their coal,
ownership, bed depth, seam thickness, availability of water
resources, and competition for surface area usage. Further,
these differences will become increasingly important as tech-
nologies are developed to make coal a more acceptable, less
environmentally threatening source of energy.
The Northern Great Plains and Rocky Mountain Provinces con-
tain approximately 70 percent of the coal resources in the four
major provinces and most of the nation's low-sulfur coal. Other
characteristics of these two provinces are:
1. Much of the coal likely to be developed in the
near future can be surface mined,
2. Competition for surface area usage is relatively
low,
3. The federal government controls the majority of
the coal lands,
4. The coals are relatively low in energy value per
unit weight, and
5. Water resources are not plentiful.
These points should be kept in mind when reading the remaining
sections in this chapter.
-36-
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3.5 EXPLORATION
Coal in the western U.S. occurs in sedimentary rocks that,
for the most part, are composed of ancient river and delta de-
posits. The location and distribution of coal that is shallow
enough for conventional surface or underground mining are rela-
tively well known. Consequently, most of tne exploration effort
involves finding and evaluating known deposits that are econom-
ically and environmentally attractive for a specific energy need
rather than locating new deposits.
3.5.1 Technologies
An exploration strategy for locating a coal mine site
typically consists of four stages. These four stages are out-
lined in Table 3-17.
Two different but related technologies are used in coal
exploration: geologic techniques and drilling. Borehole geo-
physics are also usually used in conjunction with a drilling
program. A team of geologists and support personnel are re-
quired to conduct geologic studies, and a drilling crew.is
necessary to operate equipment during the drilling program.
Geological techniques are used in all steps of the explora-
tion strategy, including outlining and conducting the drilling
program. The most important geologic subdiscipline in coal ex-
ploration is stratigraphy because western coals are found in
sedimentary rocks. Economic geology and structural geology are
also essential. The specific geologic methods used are pri-
marily surface and subsurface mapping of geologic parameters
that are significant to the occurrence of coal. Examples of
useful maps are coal thickness maps, overburden thickness maps,
and structural geology maps.
-37-
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TABLE 3-17. OUTLINE OR REGIONAL AND DETAILED
EXPLORATION PROGRAM
Exploration Stages
Search for a New Coal Deposit
in Western U.S.A.
Stage 1
Stage 2
Stage 3
Stage 4
Regional
Appraisal
Detailed
Reconnaissance
Detailed Surface
Investigation of
Target Area
Detailed Three
Dimensional
Physical
Sampling of
Target Area
0 - Geologic Compilation for "marketing area.
F - Field check of sections containing coal
seams.
F - Reconnaissance drilling for stratigraphy
and coal thickness.
F - Chemical and calorific check of outcrops
or drill samples (not badly burned).
F - Field check of sections containing coal
seams.
F - Drilling - Logging
L - Mineralogical, chemical analyses and
physical tests on samples, cores and
cuttings.
F - Down-hole geophysical surveys.
*
0 - Reserves computations.
*
0 - Preliminary valuation.
F - Investigation of water problems and water
availability for facilities.*
F - Investigation of suitability of ground for
plant, dump, and town sites.
F - Punch mine to obtain bulk samples.
L - Bulk tests.
Legend
0 - Office study
F - Field investigation
L - Laboratory tests
- Activity or method which is indispensable
-38-
-------
Two types of drilling methods are most frequently used in
coal exploration: standard rotary drilling and coring. When
the standard rotary drilling is used, samples are taken from
the drill cuttings as the borehole progresses. Coring yields a
much better and more complete sample (a nearly complete cylinder
of relatively undisturbed rock) from the borehole, but this
method is much more expensive. Diamond coring bits are some-
times used in core drilling. A rig capable of routinely drilling
holes one thousand feet deep usually requires a crew of three:
a driller and two assistants. Borehole geophysical logs for
lithological interpretation and correlation purposes are
usually run under contract by companies specializing in this
field.
For an area in which no previous exploration has occurred,
the regional appraisal might begin with drilling on a five-mile
spacing, and narrow to a one-mile spacing in areas with good
prospects.
3.5.2 Input Requirements
This section presents the input requirements for exploring
and characterizing a new coal deposit in the Western United States
An area of 625 square miles will be explored for the proper
site to locate a 65-square mile coal mine. A mine this size
could produce over 30 thousand tons of coal per day for thirty
years. It is assumed that a 25-hole drilling program will be
required in the exploration.
3.5.2a Manpower Requirements
Professional geologists and a support staff are required
at all stages of the exploration for coal deposits. Table 3-18
-39-
-------
presents a gross estimate of the manpower requirements for the
various stages of the exploration effort.
TABLE 3-18. ESTIMATED MANPOWER REQUIREMENTS FOR GEOLOGIC
TECHNIQUES FOR COAL EXPLORATION
Activity Geologists (2) Support Personnel (3)
Review of existing data 2.0 man-years 3.0 man-years
Field work for site evaluations 1.0 man-years 1.5 man-years
Preparation of preliminary report 0.5 man-years 1.0 man-years
Outline and conduct drilling 1.5 man-years 2.5 man-years
program
Interpretation of results, final 1.0 man-years j.5 man-years
reports, and recommendations
TOTAL 6.0 man-years 9.5 man-years
Assuming a crew size of three for a 1000-foot capacity
drilling rig and a drilling rate of one hole per week, the man-
power requirements for the drilling activities are an additional
1. 5 man-years.
3.5.2b Materials and Equipment
The materials and equipment required for geologic explora-
tion 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 drilling parts of the exploration program,
field vehicles and equipment are also required.
Generally, the materials and equipment required for drill-
ing activities will not be provided by those conducting the
-40-
-------
exploration, but will be provided by a contractor who is commis-
sioned 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 equip-
ment must also be provided for the well-site geologist, includ-
ing a logging trailer, and sample description and collection
material. Borehole geophysical equipment, including a logging
truck and appropriate sondes (probes) are usually provided by a
contractor specializing in well logging.
3.5.2 c Economics
The costs of exploration relate directly to the manpower
and the materials and equipment requirements. The manpower re-
quirements of Table 3-18 can be translated into manpower costs
by assuming a man-year cost of $50,000 for professional geolo-
gists and $30,000 for supporting personnel as follows:
Personnel Man-Year Cost Man-Years Total-Cost
Geologists $50,000 6.0 $300,000
Support $30,000 10.0 300.000
$600,000
Materials and equipment associated with the geological activities
are assumed to be available from existing facilities. Their
costs will, in any case, be relatively small.
Assuming a man-year cost of about $30,000-each for the
three-man crew of a drilling rig, the manpower costs for the
drilling program should be about $45,000 for 1.5 man-years.
Equipment rental costs should be about $6000 per week for 25
weeks, or about $150,000. Total costs for the drilling portion
of the exploration program are expected to be approximately
$200,000. An unknown and probably small cost is associated with
borehole geophysical logs.
-41-
-------
3.5.2d Water Requirements
The water needs for geologic methods are negligible.
Drilling by the rotary method may require as much as five acre-
feet of water for the projected 25 holes, but this quantity is
not large enough to be significant to a large coal mining opera-
tion.
3.5.2e Land Requirements
No land is required for the geologic techniques. Some land
must be cleared for drill sites during the drilling program, but
this area is small and only occupied for about a week.
3.5.2f Ancillary Energy
Small quantities of fuel for field vehicles are required
during the field work part of geologic techniques. Larger but
still relatively minor amounts of fuel are used to drill explo-
ration holes and to move between drill sites.
3.5.3 Outputs
Only a few minor residuals are associated with exploration
activities for locating a new coal mine. Much larger quantities
of each of three residuals will be associated with the construc-
tion and operation of the coal mine itself.
3.5.3a Air Emissions
Small quantities of motor vehicle exhaust are generated
by field vehicles and drilling equipment during exploration.
Both gasoline and diesel engines are used on this equipment.
There may also be small quantities of dust generated by ex-
ploration vehicles traveling on dirt roads.
-42-
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3.5.3b Water Effluents
Small quantities of water effluent are produced by geologic
techniques. As much as five acre-feet of drilling fluid may be
generated during rotary drilling operations, but this quantity is
relatively small and the surface and subsurface pollution poten-
tial is minimal and highly localized. There may also be local-
ized increases in stream turbidity associated with drainage
changes caused by access roads and cuttings piles.
Where drill holes traverse multiple aquifers, care must be
taken to seal and plug the drill holes to prevent aquifer con-
tamination or depletion through interconnection.
3.5.3c Solid Waste
Very little solid waste is produced during the geologic in-
vestigation and the drilling phases of exploration. These solid
wastes consist of spent drilling mud and drilling cuttings. The
actual volume of these wastes is very small and they can be
plowed into the local soil for disposal.
3.5.3d Noise Pollution
Very little noise is generated by the geological activities.
However, some local and temporary noise is produced by rig opera-
tions during the drilling activities of exploration. In recent
years equipment has been developed to reduce and muffle the noise
from drilling machinery. This equipment can be used if found
necessary.
3.5.3e Occupational Health and Safety
During the field work, work parties are exposed to such
hazards as falls, snakebite, and heat prostration. Drilling
-43-
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operations pose larger but nevertheless relatively small hazards
to crew personnel. Injury associated with equipment operation
is not an infrequent occurrence on drill rigs.
3.5.4 Social Controls
In the following section, federal, Indian and state regula-
tion of exploration are described. The process of obtaining the
lands for subsequent mining operations will be described in
Section 3.6.3 on coal mining and reclamation social controls.
Administrative controls such as the environmental impact state-
ment process have been described in Chapter 2.
3.5.4a Exploration Permits on Federal Land1
For both the federal and state governments, the explora-
tion process begins with the issuance of prospecting permit as
shown in Figure 3-6.
Application for federal prospecting permits are made to
the Secretary of the Interior, usually through the local USGS
Office. A description of the exploratory plan, an estimate of
the costs, and a timetable for diligent development must accompany
the application. Following approval of the plan and prelimi-
nary environmental assessment by USGS, USGS has broad discretion-
ary authority to establish terms under which exploration will
take place.
le permit is issued for two-year periods and may be ex-
for periods of two years if the permit&ee has, with th<
*New regulations concerning exploration are being promul-
gated as a result of the Surface Mining Control and Reclamation
Act of 1977, Pub. L. 95-87, 30 USC 1201. These regulations were
not final as of the date of publication of this document.
-44-
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Request Prospecting Permit
by Submitting Exploration
Plans and Costs to USGS
Environmental Analysis
by USGS
Prospecting
Permit Issued
Exploration
—drilling
--outcrops
Periodic Reports
and
Inspection by USGS
Application for
Competitive Lease
Figure 3-6.
The Sequence of Federal Regulatory
Controls Over Exploration.
-45-
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exercise of reasonable diligence, been unable to determine
whether the deposit was workable.1
3.5.4b Exploration Permits on Indian Lands
Procedures for obtaining exploration permits for Indian
lands are the same as those for federal lands, except that per-
mission from the appropriate Indian agency or authority is also
required. However, Indian prospecting permits are not limited
in duration.
3.5.4c Exploration Permits on State Lands
Terms of most state permits generally range from ninety
days to two years, and are usually renewable. The exploration
permit requirements for the eight western states upon which
this study 'is focused are summarized in Tables 3-19 through
3-26.
^U.S., Congress, Senate, Committee on Interior and Insular
Affairs. Federal Leasing and Disposal Policies. Hearing Pur-
suant to S. Res.
-------
TABLE 3-19. ARIZONA COAL EXPLORATION PERMIT3
Item
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Descretionary
Actions
Other Information
§ 27-251 State Land Department, State Land
Commissioner
8 27-251 $25 filing fee
8 27-251 $2 per acre up to 640 acres. Permittee
must expend at least $10 per acre per
year for two years and $20 per acre per
year after that
I 27-252 One year, renewable to a total of five
years
Required, see S 27-255
§ 27-255 Bond amount determined by Commissioner
to cover surface damage
8Arizona Revised Statutes Annotated, 1956.
TABLE 3-20. COLORADO COAL EXPLORATION PERMIT3
Item Statutes
Agency 1 36-1-140
Special § 36-1-140
Requirements
Fees
Rental
Duration ! 36-1-140
Bond
Discretionary
Actions
Other Information S 36-1-140
Summary
State Board of Land Commissioners
Discovery, posting of notice of discovery
on site, notify board within ten days of
discovery
Sixty days, but extension possible
At expiration of permit the locator may
be required to lease upon agreed-to-
tems
aColorado Revised Statutes, 1973.
-47-
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TABLE 3-21. MONTANA COAL EXPLORATION PERMIT'
(For Use of Explosives)
Item
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Discretionary
Actions
Other Information
i 69-3301 . County Clerk and Recorder
! 69-330* $5
S 69-3304 $10,000
Any person desiring to do seismographic
exploration (with explosives) of any
lands in state must apply for this
permit
"Applies to all ainable resources. Revised Codes of Montana, 1947. State
land exploration is regulated by leasing procedures explained in Section
1.4.2.3.
TABLE 3-22. NEW MEXICO COAL PROSPECTING PERMIT3
Ite
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Discretionary
Actions
Other Information
S 7-10-1
i 7-8-2
i 7-10-1
i 7-10-1
Commissioner of Public Lands
Fees to be set by Commissioner
Not less than 40 acres, not more than
640 acres
Not more than one year
i 7-10-3
The prospector receives a preferential
right to lease
*Hew Mexico Statutes, 1953.
-48-
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TABLE 3-23. NORTH DAKOTA COAL EXPLORATION PERMITa
Item
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Discretionary
Actions
§ 38-12.1-04
§ 38-12.1-05
§ 38-12.1-04
§ 38-12.1-04
§ 38-12.1-04
Other Information § 38-12.1-04
i 38-12.1-04
Industrial Commission of the State of
North Dakota
If drilling, a permit is required
from State Geologist at fee of $100
(if drilling is not required by
other state agency)
Two years with one year extensions to
a total of seven years
A reasonable bond may be required by
Commission
See Bond Requirements
Applies to all lands in state whether
public or private and applies only to
coal
Commission has authority to require
drilling data from exploration to be
delivered to state geologist but kept
confidential and may require plugging
of all exploratory holes and excava-
tions
North Dakota Century Code, 1960.
-49-
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TABLE 3-24. SOUTH DAKOTA COAL EXPLORATION PERMIT*
Item
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Discretionary
Actions
§ 5-7-1
Commissioner of School and Public Lands
§ 5-7-7
§ 5-7-9
§ 5-7-7
§ 5-7-7
§ 5-7-9
§ 5-7-7
Other Information § 45-7A-3
§ 45-7A-2
§ 5-7-8
§ 5-7-10
§ 45-6A-16
§ 45-7A-2
$.50 per acre
$.50 per acre per year, maximum of 640
acres
One year, renewable to total of three
years
The Commissioner, at his discretion, may
refuse to issue permit if in best in-
terests of state
A report of any exploratory well drilled
must be sent to Department of Natural
Resources (will be kept confidential)
Priority of issue to earliest applica-
tion date
Permittee may not remove any minerals
Although South Dakota requires a special
permit (at a fee of $25)"to use heavy
equipment in exploration of the surface;
this section specifically exempts state
lands from that requirement. (The
permit is issued by the State Conser-
vation Commission)
Wells must be capped, sealed, or plugged
South Dakota Compiled Laws, 1967.
-50-
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TABLE 3-25. UTAH COAL EXPLORATION PERMIT'
Itc
Statutes
Summary
Agency
Special
Requirements
Fees
Rental
Duration
i 65-1-18
I 40-1-13
I 140-1-13
Bond
Other Information i 40-6-5
State Land Board
160 acres mmtlntimi per township, per
person, with $250 worth of work completed
every six months per township. No ore
to be removed
One year maximum, with yearly renewals
available
If developer plans to drill (either
exploratory or production), the Board of
Oil, Gas and Mining has Che authority to
require: (1) security (for plugging),
(2) notice of intent to drill, and
(3) filing of well logs
*Utah Code Annotated, 1953.
TABLE 3-26. WYOMING COAL EXPLORATION LICENSE'
Itc
Status
Agency
Special
Requirements
Fees
Rental
Duration
Bond
Discretionary
Actions
Other Information
Department of Environmental Quality
One year, renewable by letter
$10,000 minimum
All holes and aquifers must be plugged and dozer
trails and drill pods oust be completely reclaimed
tfyoming Environmental Quality Act of 1973
-51-
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3.6 MINING
There are two basic types of mining used to extract coal:
surface mining and underground mining. Section 3.6.1 discusses
the technologies used in surface mining and presents the input
requirements and outputs associated with surface mining techno-
logies. Section 3.6.2 discusses underground mining technologies
in a like manner.
3.6.1 Surface Mining
Surface mining operations are increasing at a rate faster
than that of total coal production. Total 1976 coal production
increased 2.6 percent over 1975 production, while surface mining
operations increased 4.8 percent during the same period. Nation-
wide surface mining accounted for 373 million tons during 1976
or 56 percent of total production.1 In the western states, sur-
face mining accounts for almost 90 percent of mining operations.
The relative growth rate of surface mining operations is depicted
in Figure 3-7.
In 1976, total bituminous and lignite coal production in the
United States was 665 million tons. Approximately 24.4 percent
was produced by the top 50 mines. This is up from 23.1 percent
in 1975, thus verifying the trend toward fewer, but larger coal
mines, as reported by the Keystone Coal Industry Manual.2
.3.6.1.1 Technology Description
Surface mining is a general term which refers to any mining
method involving the removal of surface material (overburden) to
lNielsen, George F., ed. 1977 Keystone Coal Industry Manual
New York, New York: McGraw-Hill Mining Publications. 1977.
2 ibid.
-52-
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1920
1930
1940
1950
1960
1970
1980
Figure 3-7. Increase in Coal Production by Surface Mining.
Source: Gouse, S. William, Jr. and Edward S. Rubin. A Program
of Research, Development and Demonstration for"Enhancing
Coal Utilization- to Meet National Energy Needs. Results
of the Carnegie-MellorT University Workshop on Advanced
Coal Technology, 1973.
Reprinted from University of Oklahoma, Science and
Public Policy Program. Energy Alternatives. A Com-
5arative Analysis. Washington, D.C.:Government
rinting Office, 1975.
Extended to 1977 from Nielsen, George F., ed. 1977
Keystone Coal Industry Manual. New York: McGraw-Hill
Mining Publications. 1977.
-53-
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expose an underground resource deposit. There are several factors
which must be considered before construction of a surface mine.
Probably the most important is the overburden-to-seam thickness
ratio. Until about 1965 surface mining of coal was not considered
feasible unless the overburden-to-seam thickness ratio was 10:1
or less. Thus, to justify removing 50 feet of overburden, the
coal seam would have to be five or more feet thick. Since 1965,
this ratio has been increasing and most coal within 150 feet of
the surface is now considered economically recoverable, even
when the overburden-to-seam thickness ratio is as much as 30:1.
3.6.1.la Strip Mining (Area Mining)
There are two major types of surface mining: strip mining
and contour mining. The conventional strip or area mine is used
mainly in relatively flat terrain where the coal seam is parallel
to the surface. This technique is ideal for western coals.
Before actual excavation can begin, a certain amount of
surface preparation must be performed. The surface preparation
phase requires construction of access roads, and maintenance
and personnel facilities. Also, utilities must be brought to
the site and, in most regions, vegetation must be removed from
the area to be mined. Even after the mine is established,
additional vegetation removal may be required as the overburden
stripping operation advances. After vegetation removal, the top
soil is carefully removed and saved for use in the reclamation
of the site.1
The equipment used in surface preparation consists primarily
of bulldozers, scrapers, and loaders and trucks. The trucks are
1 University of Oklahoma, Science and Public Policy Program
Energy Alternatives: A Comparative Analysis. Washington: Gov-
ernment Printing Office. 19/5.
-54-
-------
required to transport the salvaged top soil to a stockpile or to
an area being reclaimed.
After completing surface preparation, the actual mining
operations begin. The strip mine (or area mine) is started with
a box-cut or trench extending from one side of the coal field
to the other. If the overburden is hard rock or shale, it will
have to be fractured by blasting. Six-inch blasting holes are
drilled into the rock in a square grid with 15 to 25 foot spac-
ing. A typical blasting charge of 300 pounds of ammonium nitrate
and fuel oil packaged in tubes is placed in holes.1 The blasting
material is detonated with electric blasting caps. Larger holes,
up to 15 inches in diameter, may be used for harder overburden.
A truck or tractor mounted electric rotary drill (or in cases of
extremely hard formations, a pneumatic drill) is used to drill
the blasting holes. In populated areas, noise control is
attempted by covering the explosive cord used in detonating and
by introducing milli-second delays in explosion sequences.2 For
safety, blast areas may be covered by mats to minimize the scatter-
ing of rock fragments .3
Overburden is removed by electric- or diesel-powered strip-
ping shovels or draglines. The uncovered coal is loaded by
loading shovels into trucks or conveyors and transported out of
the mine, after which the coal is crushed and may be mechanically
cleaned. The overburden from each successive parallel cut by the
stripping shovel or dragline is deposited on a spoil bank located
'Stefanko, Robert R. , V. Ramani, and Michael R. Ferko.
An Analysis of Strip Mining Methods and Equipment Selection.
OCR R&D61, Int. Rept. 7.University Park, PA:Pennsylvania
State University, College of Earth and Mineral Sciences. 1973.
2Grim, Elmore C. and Ronald D. Hill. Environmental Protec-
tion in Surface Mining of Coal. Washington"! Environmental
Protection Agency. 1974.
•Ibid.
-55-
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in the preceding trench. Strip mining has a recovery rate of 80
to 90 percent with coal losses mainly due to spillage and losses
in transit.1 An overall view of the operation is shown in Figure
3-82 and an outline of the steps involved in an area mining
operation is shown in Figure 3-9.
The depth of overburden which can be removed economically
will depend on the thickness of the coal seam. As a rule, area
mining can be performed where overburdens are not more than 200
feet thick.3 Greater depths may become economically feasible in
the future depending on technology, economics, and environmental
concerns.
3.6.1.Ib Contour and Auger Mining
Contour and auger mining are performed in hilly terrains
that are not amenable to strip mining. The initial surface
preparation activities are essentially the same as for strip
mining. The main difference is that in contour mining, the mine
is excavated in a path following the terrain of the particular
area. The mining equipment used in contour mining is generally
smaller than that used for strip mining.1* When the high wall
of the mine becomes too high for strip mining, augers are used
to recover additional coal. In auger mining large augers are
driven horizontally about 200 feet into a coal seam.5 Coal is
recovered in the form of chips similar to wood chips from a
'Stefanko, Robert R., V. Ramani, and Michael R. Ferko. An
Analysis of Strip Mining Methods and Equipment Selection. OCR
R&D61, Int. Rept. 7.University Park, PA: Pennsylvania State
University, College of Earth and Mineral Sciences. 1973.
2U.S. Environmental Protection Agency. Processes, Proce-
dures, and Methods to Control Pollution from Mining Activities.
Washington:Government Printing Office.1973 .
3Stefanko, Robert R., op.cit.
"ibid.
5U.S. Environmental Protection Agency, op.cit.
-56-
-------
Original Ground ^g-^_g:==^v. ^ Highwall
Surface S3??^—j
—-^--^^^ Mtnwal Seam ^-~=^t-^~
:==^^=^^^ strip Bench
Figure 3-8. Area Mining.
Source: U.S. Environmental Protection Agency. Processes, Pro-
cedures, and Methods to Control Pollution from Mining
Activities"! Washington: Government Printing Office,
1973.
-57-
-------
VEGETATION
STRIPPING
TOPSOIL
REMOVAL
OVERBURDEN
REMOVAL
OVERBURDEN
REPLACEMENT
GRADI
TUP
REPLA
HG AND
SOIL
CEMENT
COAL
EXTRACTION
>
\,
MINE
DRAINAGE
REVEGETATIOti
CRUSHING
AND
GRINDING
WASTE
WATER
TREATMENT
1
RECLAIMED
WATER
COAL PRODUCT
1 STORAGE * COAL
£
COAL PILE
RUNOFF
Figure 3*9. Steps Involved in an Area Mining Operation.
-------
drill bit. The introduction of dual and multiple augers has
helped increase the percent recovery of coal from thin seams.
The auger holes are backfilled and plugged by special compaction
techniques. Recovery rates for auger mining are thought to be
around 50 percent but may be as low as 30 percent in actual opera-
tion.l The major losses are from coal left between the auger
holes. Although these two mining methods are not widely used out-
side of the Appalachian coal region of this country, they are now
receiving consideration in some western regions.
3.6.1.1c Excavation Techniques
With the advent of larger surface mining operations, special-
ized pieces of equipment have evolved to cope with the various
surface mining methods. Although overburden removal was discussed
in the section on strip mining, a number of technological alter-
natives are available for this removal and should be discussed
further.
Four kinds of equipment are used in typical surface mining
operations: small, mobile tractors, including bulldozers,
scrapers, and front-end loaders; shovels; draglines; and wheel
excavators.
Most mining operations will use several of these equipment
items in varying combinations, although one or two usually domi-
nate the operation. Item selection and combination are gener-
ally based on the nature and quantity of the material to be
moved, distance and transport surface conditions, and flexibility
'Stefanko, Robert R., V. Ramani, and Hichael R. Ferko. An
Analysis of Strip Mining Methods and Equipment Selection. OCR
R&D60, Int. Rept. 7.University Park, PA:Pennsylvania State
University, College of Earth and Mineral Sciences. 1973.
-59-
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of the equipment for other applications.1 Descriptions of the
major mining equipment items follow:
Tractors. Tractors or front end loaders are typically
used either in small mines or in conjunction with
larger, more specialized equipment in large mines.
The principal advantages of tractors are their maneuver-
ability, ability to negotiate steep grades, and capa-
bility to dig and transport their own loads.2 Tractors
are used for a variety of tasks, including clearing,
preparing benches, leveling spoil piles, and construct-
ing roads.
Shovels. Large diesel or electrically powered strip-
ping shovels have been used in surface mines for a
number of years and are often designed for a particular
mine application. These machines progress along a bench
scooping up the fragmented overburden or coal in buckets
with capacities of up to 130 cubic yards. In the largest
surface mines, shovels are often used in conjunction
with draglines, primarily to load coal.
Draglines. Electrically powered draglines, such as the
one shown in Figure 3-10 are capable of moving larger
amounts of materials in a single bite than any other
equipment item currently being used in surface mines.
Bucket capacity of these machines ranges from 10 to
220 cubic yards. The dragline moves along the bench,
positions its bucket on the overburden to be removed,
^illebrew, Clarence E. "Tractor Shovels, Tractor Dozers,
Tractor Scrapers." In E.P. Pfleider, ed. Surface Mining. New
York: American Institute of Mining, Metallurgical and Petroleum
Engineers. 1968. pp. 463-477.
2
Ibid.
-60-
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r-r
Figure 3-10. Dragline.
Source: National Petroleum Council, Committee on U.S. Energy
Outlook, Other Energy Resources Subcommittee. U^S.
Energy Outlook: An Initial Appraisal by the Oil Shale
Task Group, 1971-1985. Washington:NPC, 1972.
-------
and loads it by dragging it toward the machine. The
loaded bucket is then lifted, the machine rotated,
and the bucket dumped in an area that has already been
mined.
Bucket Wheel Excavators. Another type of excavator,
although seldom used in the U.S., has a rotating
bucket wheel mounted at the end 'of the boom. This
bucket wheel can be 50 or more feet in diameter and
the boom up to 400 feet long.1 As shown in Figure 3-11,
rotating the wheel loads the buckets from the cut and
empties the material onto a conveyor which then trans-
ports it to whatever in-mine transportation system is
being used.
Only the largest mines with suitably soft materials
justify the expense associated with this type of exca-
vator. Currently bucket wheel excavators have not
been used with success in western coal mining. The
bucket wheel excavator has been used fairly extensively
in Europe, generally in deep surface mines where the
overburden is several hundred feet thick.2 In this
type of mine, the excavator can make high cuts, thus
•
requiring fewer levels in the mine, and can cut seams
that have a high slope angle.3
*Aiken, George E., and Reinhard P. Wohlbier. "Continuous
Excavators (Bucket Wheel and Chart Diggers)." E.P. Pfleider, ed.
Surface Mining. New York: American Institute of Mining, Metal-
lurgical and Petroleum Engineers. 1968. pp. 478-502.
2Gartner, Ing. E. H. Ervin. "Garsdorf Lignite Strip Mine--
Operations to Unusual Depths." In Howard L. Hartman, ed. Case
Studies of Surface Mining: Proceedings of the II International
Surface Mining Conference, Minneapolis, Minn., September 18-20,
1968.New York:American Institute of Mining, Metallurgical
and Petroleum Engineers. 1969. pp. 12-35.
3jjbid.
-62-
-------
I
Ol
U)
Figure 3-11. Bucket Wheel Excavator.
Source: Weimer, W. Henry, and Wilbur A. Weimer. "Surface Coal
Mines," Arthur B. Cummins and Ivan A. Given, eds.
SHE Mining Engineering Handbook. New York: American
Institute of Mining, Metallurgical and Petroleum
Engineers, 1973, pp. 17-151.
Reprinted from Energy Alternatives. A Comparative
Analysis by the University of Oklahoma, Science and
Public Policy Program with permission of the author.
-------
Whatever the method used, area and contour mines require
large energy inputs for equipment operation and have high ma-
terials outputs.
3.6.1.Id Reclamation
Reclamation is an integral part of surface mining operations.
As coal extraction of a mining area is completed, that area be-
comes the receptacle for the tops oil and overburden that must be
removed from the active mining site. The overburden is replaced
first and graded to original contours, followed by topsoil re-
placement. Thus, reclamation continues at the same pace as the
mining operation, lagging behind the mining activities by a fixed
time period, probably on the order of two or more months. This
section will discuss the common items that must be considered when
planning reclamation activities.
Natural constraints on reclamation, particularly as it
applies to revegetation, include climatic factors, soil conditions,
overburden characteristics, and vegetation ecology. Many of the
technologies presently available to cope with these constraints
are still in the experimental stage and have not been applied
at the scale at which they would ultimately have to be applied
in practice. Furthermore, these techniques have not yet been
developed to a point where successful revegetation can always be
assured. The present "state-of-the-art" permits mine operators
to improve the suitability of spoil material as a plant growth
medium, but local conditions beyond the operator's control
determine whether this improvement is sufficient to permit the
establishment of a self-perpetuating plant cover.
The available choices of potential land use after mining
are greatest in those areas with the best soils and most favor-
able soil moisture conditions-. In general, the reclamation goals
most often cited are: approximate original contour; restore
-64-
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texture and fertility for use as cropland; establish improved
wildlife habitat; develop recreational amenities, usually with
the inclusion of water-based recreation; and convert to urban
or industrial use, which does not require extensive rehabilitation.1
3.6.1.2 Input Requirements
The construction and operation of a surface coal mine requires
an influx of labor, material and equipment, capital, water, land
availability, and outside energy. Each of these input require-
ments will be discussed in the following sections for an example
coal mine. The example coal mine is being surface mined at an
annual production rate of 12 million tons - enough to supply a
3000 MW power plant or a 30,000 ton/day coal conversion plant.
The example mine is assumed to be located in the San Juan river
basin with a 70 foot overburden and a 10 foot seam thickness.
For a 12 million tons/year mine, there will be three separate
active mining sites, each producing 4 million tons of coal per
year. A general layout of the mine showing the three separate
mining areas is shown in Figure 3-12.
3.6.1.2a Manpower Requirements
For any operation there are two distinct phases; the con-
struction phase, followed by the continuous mining operations.
Manpower requirements for both phases depend on the size and
type of mining operation involved. Manpower requirements for
the construction phase will also depend on the duration of the
construction activity. The longer the construction time, the
•fewer the number of construction personnel needed. A surface
Reclamation of strip-mined lands is discussed as an impact
of coal resource development in: White, I.L., et ai. Energy
From the West: A Progress Report of a Technology Assessment
of Western Energy Resource Development.Washington:U.S.
Environmental Protection Agency. 1977. Chapter 12.
-65-
-------
J
^•fc—
MINING AREA NO. 1
GROUND
SURFACE
-cm
h-
ACCESS
D
c
CC
o
UJ
0
o
<
CC
<
o
Z
2
»•
•£
3y
./STRIPPING SHOVEL
MINING ARE A NO. 2
£ XCOAL CRUSHER
CC
£ GROUND
% SURFACE
<
ac
COAL PREPARATION
PLANT
Figure 3-12. Sketch of Mine Plant.
-66-
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mine could be prepared and producing within one year from date
field work begins. However, since most processing/conversion
facilities in a mine-mouth operation will take five or more
years to construct, construction of the surface mine is defined
to take 5 years as well. Assuming a five year construction
schedule, Bechtel Corporation has estimated that a maximum of
approximately 210 workers will be employed during the second,
third, and fourth years of construction.1 The schedule and
number of workers to be employed, by skill, is reflected in
Table 3-27.
Manpower requirements for operating the example 12 MM TPY
surface mine described above are shown in Table 3-28. These
requirements were estimated using Bechtel Corporation's Energy
Supply Model, a computer program based on Bechtel Corporation's
construction and engineering experience.2
3.6.1.2b Materials and Equipment
Table 3-29 lists the major construction materials required
for construction of a 12 million ton per year strip mine, based
on Bechtel Corporation's Energy Supply Model.3 Major equipment
items required for the operation of a 12 million ton per year
strip mine are presented in Table 3-30." The operating equipment
^arasso, M. et al. Energy Supply Model, Computer Program.
San Francisco: Bechtel Corporation.1975.
2ibid.
3 Ibid.
"Ralph M. Parsons Co. Commercial Complex Conceptual Design/
Economic Analysis, Oil and Power by COED Based CoaT Conversion.
Pasadena, CA: Ralph M. Parsons Co.1975.p. 10-2.
-67-
-------
TABLE 3-27. SCHEDULE OF MANPOWER RESOURCES REQUIRED FOR CON-
STRUCTION OF SURFACE WESTERN COAL MINE REQUIRED TO
PRODUCE 12 MM TPY COAL
Manpower Requirements (man-years)
Resources
Civil Engineers
Electrical Engineers
Mechanical Engineers
Mining Engineers
Geological Engineers
Other Engineers
TOTAL ENGINEERS
TOTAL DESIGNERS + DRAFTSMEN
TOTAL SUPERVISORS + MANAGERS
TOTAL' TECHNICAL
TOTAL NON-TECH (NON-MANUAL)
Pipefitter /Welders
Electricians
Iron Workers
Carpenters
Operating Engineers
Other Major Skills
TOTAL MAJOR SKILLS
OTHER CRAFTSMEN
TOTAL CRAFTSMEN
TOTAL TEAMSTERS + LABORERS
GRAND TOTALS
Source: Carasso, M., et al. Energy
yr i
3
1
1
1
0
0
7
5
2
14
2
0
1
3
1
6
3
14
2
16
4
36
Supply
yr 2
16
5
6
8
1
2
38
27
13
78
10
1
6
20
9
38
16
89
9
99
24
211
Model,
yr 3
11
4
4
6
1
1
27
19
9
55
10
1
7
22
10
43
18
102
11
113
27
205
Computer
yr 4
16
5
6
8
1
2
38
27
13
78
10
1
6
20
9
38
16
89
9
99
24
211
Tape. San
yr 5
9
3
3
4
0
1
20
14
7
41
8
1
6
1?
8
37
16
88
9
97
23
169
Fran-
cisco: Bechtel Corporation, 1975.
-68-
-------
TABLE 3-28. MANPOWER RESOURCES REQUIRED FOR OPERATION AND MAIN-
TENANCE OF A SURFACE WESTERN COAL MINE PRODUCING
12 MM TPY COAL
Classification Number Required
Electrical Engineers 1
Mechanical Engineers 1
Mining Engineers 3
Other Engineers 2
Total Engineers 6
Total Designers 4- Draftsmen 4
Total Supervisors + Managers 43
Total Other Technical 38
Total Technical 92
Total Non-Tech (Non-Manual) 31
Electricians 34
Equipment Operators 101
Other Operators 10
Other Major Skills 182
Total Major Skills 327
Total Craftsmen 327
Total Teamsters 4- Laborers 102
GRAND TOTAL 552
Source: Carasso, M. , et al. Energy Supply Model, Computer
Tape. San Francisco:Bechtel Corporation, 1975.
-69-
-------
TABLE 3-29. MAJOR EQUIPMENT ITEMS REQUIRED FOR SURFACE MINING
12 MM TPY COAL
Number
Description
Size
13
3
3
3
3
13
3
3
3
3
3
3
16
7
3
3
3
3
3
3
3
3
3
1
1
16
6
6
Portable Light Towers
Mine Pumping Systems
Hydraulic Cranes
Mobil Cranes
Screw Compressors
Rotary Blasthole Drills
Track Drills
Stripping Shovels
Holland Loaders
DDOGs
Coal Shovels
Front-End Loaders
Coal Haulers
D-9s with Ripper & Dozer
D-8s with Dozer
Wheel Dozer
Grader
Lube-Fuel Trucks
Water Sprinkler Trucks
ANFO Trucks
Trucks
'Trucks
Lowboy with Tractor
Passenger Bus
Fire Truck
Pickup Trucks
Flat Bed Trucks
Flat Bed Trucks
15 ton
50 ton
600 cu ft
140 cu yd
12 cu yd
10 cu yd
120 ton
3 ton
5 ton
50 ton
40 passenger
3 ton
5 ton
Source; Ralph M. Parsons Co. Commercial Complex Conceptual
Design/Economic Analysis. Oil and Power by COED"
Based Coal Conversion. Pasadena, CA:
Parsons Co., 1975.p. 10-2.
2f
il
Ralph M.
-70-
-------
estimates are based on a conceptual design by Ralph M. Parsons
Co. of a strip mine mining 13 million tons per year which
reduces to 12 million tons per year after coal cleaning.
TABLE 3-30. CONSTRUCTION MATERIALS REQUIRED FOR
A 12 MM TPY SURFACE MINE
Resources Quantity
Cement (tons) 62800
Pipe + Tubing (less than 24 inch) (tons) 608
Structural Steel (tons) 940
Reinforcing Bar (tons) 1130
Draglines (net capacity, cu yds) 180
Draglines (net capacity, tons) 10400
Source: Carasso, M., et al. Energy Supply Model. Computer
Tape. San Francisco:Bechtel Corporation. 1975.
3.6.1.2c Economics
An itemized list of the capital costs associated with the
development of a 13 million ton per year coal strip mining opera-
tion is presented in Table 3-31. Table 3-32 presents the annual
operating costs associated with the same mining operation.
These costs are in 1974 dollars, and were developed by Ralph M.
Parsons Co. based upon the detailed conceptual design of a coal
liquefaction complex located in the Illinois-Kentucky coal region.1
Based on these cost estimates a 12 million ton per year strip
mine would require a total capital investment of approximately
105 million dollars and an annual operating cost of 46 million
dollars.
Larsons, Ralph M., Company. Commercial Complex Conceptual
Design/Economic Analysis, Oil and Power by COED Based Coal
Conversion. R&D Report for Energy Research and Development Ad-
ministration Contract E(49-18)-1775, Pasadena, CA: U.S. Govern-
ment Printing Office. September 1975. p. 12-12.
-71-
-------
TABLE 3-31.
COAL MINE EQUIPMENT COSTS AND REPLACEMENT SCHEDULE
(1974 DOLLARS) (13 MILLION TONS/YR)
Equipment: Item
Stripping Shovels (3)
Holland Loaders (3)
OD9G-S for Holland Loaders (3)
Coal Shovels, 12 cu yd (3)
Coal Haulers, 120 Con (15)
Front -End Loaders, 19 cu yd (3)
0-9 's w/Ripper and Dozer (6)
D-9's w/Dozer (6)
Q-i's w/Dozer (3)
Wheel Dozer (3)
Grader (3)
Rotary Blast-Hole Drills (12)
Portable Light: Towers (12)
Track-Drill* (3)
Screw Compressors, 600 cu ft (3)
Lube-Fuel Truck (3)
Water Sprinkler Truck (3)
AN/FO Trucks (3)
Trucks , 3 con
Trucks, 5 con
Mine Pumping Systems
Hydraulic Cranes, 15 con (3)
Mobile Crane, 50 Con (3)
Lowboy w/Tractor, 50 con (1)
Bus, 40 Passenger (1)
Tire Truck (1)
Pickup Trucks (15)
Flatbed Trucks, 3 con (8)
Flatbed Trucks, 5 ton (8)
Total Equipment
Preproduetion Costs
Subtotal
Home Office Engineering and
Sales Tax
TOTAL Equipment Ccsts
Scar: up Coses
Construction Financing
Total Depreciable Investment*
*Tocal depreciable investment is
Source: Parsons, Ralph M. . Comp
Economic Analysis, Oil
Delivered
Cost
(3000)
52,770
614
74<»
2,136
3.391
530
950
859
302
405
182
3,878
72
106
85
90
423
35
16
19
150
207
431
37
21
51
53
26
68.719
27.581
96.300
7.700
104.000
1,000
3,500
113.500
equivalent to 3,
any. Commercial
Useful
Life
(yr)
20
5
4
7
4
3
3
3
3
3
3
5
5
3
3
1
3
4
5
5
10
4
20
20
7
7
3
5
5
10
10
.7 $/ton
Complex
Annual
Depreciation
2.633.5CO
122.600
Io7,000
305,143
347.750
193,333
316,667
286,333
100,667
135,000
60.667
775.600
14.400
35.333
28,333
30,000
141.000
21.250
3,200
3,300
15,000
51,750
21.550
1.550
3.000
7.285
17.667
5,200
6,400
6.376,478
2,758.100
9.134,573
770,000
9.904,578
Conceptual Design/
and Power by CCED Sased Coal Conversion,
R&D Report ror Energy Research and Development Adainistracion Con-
Cract E(49-18)-1775. Pasadena. CA: U.S. Government Printing
Office. September 1975. ?. 12-12.
-72-
-------
TABLE 3-32. ANNUAL OPERATING COST SUMMARY (1974 DOLLARS)
(13 MILLION TONS/YR)
Cost
Item $ million/yr
Mine Royalty 11.781
Materials and Supplies
Operating Supplies 2.817
Equipment Operation 10.520
Total Materials and Supplies 13.337
Labor
Operating Labor and Supervision 6.159
Maintenance Labor and Supervision 1.537
Plant Overhead 1.924
Payroll Burden 3.367
Union Welfare 7.234
Total Labor Costs 20.221
G and A Overhead 0.743
Miscellaneous Costs
Reclamation 0.042
Permits and Bonds 0.275
Miscellaneous 0.030
Total Miscellaneous Costs 0.347
Taxes and Insurance 3.120
Total Operating Costsa 49.549
aTotal operating costs excluding depreciation are equivalent
to 3.8 $/ton.
Source: Parsons, Ralph M., Company. Commercial Complex Con-
ceptual Design/Economics Analysis, Oil and Power by
COED Based Coal Conversion, R&D Report for Energy Re-
search and Development Administration Contract £(49-
18)-1775, Pasadena, CA: U.S. Government Printing
Office, Sept. 1975'. p. 12-12.
-73-
-------
Table 3-33 presents a comparison of surface mining costs
at four Western mines. These costs were developed by Skelly
and Loy in a detailed study of mining and reclamation costs for
the Bureau of Mines.1 In this study it was determined that typi-
cal operating costs for mining in the western states ranged from
$4.29 to $6.84 per ton of coal (1974 dollars). In addition, min-
ing costs were found to be most dependent on mine size, overburden
thickness, seam thickness, and topography. Coal heating value is
also important when considering costs per unit energy.
The coal costs presented in Table 3-33 include the costs
associated with top soil removal and reclamation activities.
As envisioned in this assessment by Skelly and Loy, reclamation
costs range from 0.1 to 0.3 $/ton of coal, and depend on the
same factors listed above for coal costs.
3.6.1.2d Water Requirements
The process water requirements of the mining operations
primarily consists of water used for dust control in the crush-
ing plant and along haulage roads. Personnel water requirements
are generally negligible. All of the water required to satisfy
these demands is normally available in the form of reclaimed
water collected as mine drainage or surface run-off. Another
source of water for this use is wastewater from power plants or
coal conversion plants. Many of their wastewaters are highly
suitable for dust control. Low quality ground waters are also
excellent mine water sources.
Skelly and Loy. Economic Engineering Analysis of U.S.
Surface Coal Mines and Effective Land Reclamation.Final Report
for U.S. Bureau of Mines, Contract 50241049.Harrisburg, PA:
U.S. Government Printing Office, PB-245315. February 1975.
p. 9-220.
-74-
-------
TABLE 3-33. COMPARISON OF WESTERN SURFACE MINING COSTS (1974 DOLLARS)
ui
I
Item
State
Type
Production (million ton/yr)
Overburden (ft)
Seam Thickness (ft)
Capital Investment
(S million)
($/ton)
Operating Costsa
Excluding depreciation ($/ton)
Including depreciation ($/ton)
Mine 1
Colorado
strip
1.8
70
7
20.7
11.50
5.16
6.34
Mine 2
Wyoming
open pit
3.0
100
27
25.0
8.33
3.39
4.72
Mine 3
Montana
strip
5.0
65
52
30.2
6.04
3.41
4.29
Mine 4
North
strip
2.0
60
20
17.1
8.55
3.23
4.62
Dakota
Cost basis is 20 yr equipment life and 15% interest on investment.
Source: Skelly and Loy. Economic Engineering Analysis of U.S. Surface Coal Mines and
Effective Land Reclamation, Final report for U.S. Bureau of Mines Contract
50241049, Harrisburg PA:U.S. Government Printing Office PB-245315, Feb.
1975. p. 9-220.
-------
Water requirements for reclamation have been estimated to
vary from 0.5 to 0.75 acre feet per acre per year.1 Reclamation
water requirements are highly variable, depending on soil condi-
tions, climate, and vegetation. Water used for reclamation
must also be of higher quality than water used for dust control.
Assuming that reclaimed land will be irrigated for ten years,
then based on a land disturbance of 670 acres/year (see following
Land Requirement Section), 3350 to 5025 acre-feet/year of water
will be required for reclamation.
3.6.1.2e Land Requirements
There are two categories of land requirements for a surface
coal mine: 1) the incremental or active land area required by
the stripping of the overburden and the actual mining of the
coal, and 2) the fixed land area required for the permanent
facilities at the mine. For a western strip mine with a coal
seam thickness of 10 feet, approximately 1.8 acres/day is dis-
turbed to produce 12 million tons of coal per year. Generally
reclamation activities will commence 100 days after topsoil
and overburden removal activities are initiated at any given
location.2 As a result, at any given time the land area desig-
nated as the active working area is estimated to be equal to the
land area disturbed in 100 days of mining activity. For the
example strip mine used in this study, the active working compo-
nent of the land area requirements is 180 acres. Over the 30
year mine life, the total acreage of land consumed is about
20,000 acres.
National Academy of Engineering. Rehabilitation Potential
of Western Coal Lands. A Report to the Energy Policy Project
of the Ford Foundation. Cambridge, MA: Ballinger. 1974.
2 ibid.
-76-
-------
The fixed land requirements include the space occupied
by the processing and loading facilities, the land needed to
store the initial cut refuse, and the land area occupied by the
water containment facility. Haulage roads have been estimated
to occupy from 6 to 12 acres, and processing and loading facili-
ties have been estimated to occupy approximately 43 acres.l
Although not actually considered a land requirement, addi-
tional land area will be continuously undergoing reclamation.
Currently, the Surface Mining Control and Reclamation Act re-
quires that reclamation activities be conducted for ten years
after an area is mined.2 Under this requirement approximately
6700 acres of land will be involved in reclamation activities
after the mine is established.
Surface mining land requirements are summarized in Table
3-34. As the table indicates, surface mines with thicker coal
seams will have lower land requirements, for the same output.
TABLE 3-34. LAND AREA REQUIREMENTS FOR
A 12 MILLION TPY COAL STRIP MINE
Usage
Coal Seam Thickness (ft)
Active Working Area (acres)
Reclamation Area (acres)
Fixed Land Requirement
Haulage roads (acres)
Processing and loading (acres)
Mine 1
10
180
6700
6-12
43
Mine 2
20
90
3350
6-12
43
National Academy of Engineering. Rehabilitation Potential
of Western Coal Lands. A Report to the Energy Policy Project of
the Ford Foundation. Cambridge, MA: Ballinger. 1974.
2Surface Mining Control and Reclamation Act of 1977, Pub. L,
95-87, 91 Stat. 445.
-77-
-------
3.6.1.2f Ancillary Energy
Two forms of ancillary energy are required for surface
mining operations; electricity and diesel fuel. The larger
draglines and the coal crushers are electrically powered. The
smaller earth movers and trucks are diesel engine powered.
Hittman has reported energy requirements for several surface
mining activities.1 The values reported in Table 3-35 have been
extrapolated from the Hittman data to a 12 million TPY surface
mine in the Western United States.
TABLE 3-35.
ANNUAL ANCILLARY ENERGY REQUIREMENTS FOR A
12 MILLION TPY COAL STRIP MINE
Operation
Mining
Hauling
Crushing
Reclamation
Total
Electricity
(10$ kWh/yr)
10-20
40
50-60
Diesel Fuel
(103 gal/yr)
700-1300
300-600
450
10-40
1700-2000
Total Energy3
(109 Btu/yr)
200-400
40-30
450
2-6
700-900
3.6.1.3 Outputs
The outputs associated with a coal surface mine are very
site and size dependent. Overburden and seam thickness have a
direct effect on the quantity and quality of outputs from a
surface mine. This section presents the outputs from an example
12 million ton per year coal mine located in the Western United
States. The overburden is assumed to be 70 feet thick and the
coal seam is assumed to be 10 feet thick.
1Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use. Final Report: Vol. I, 1974;
Vol. II, 1975.Columbia, MD:Hittman Associates, Inc. 1974 and
1975.
-78-
-------
The various outputs associated with surface mining include
air emissions, water effluents, solid wastes, and noise. Each
of these is examined in the following sections. Occupational
safety is also considered a form of output and will be examined
at the end of this section. No odors have been identified as
being associated with strip mining activities. This output will
not be discussed.
3.6.1.3a Air Emissions
Potential sources of airborne emissions from surface mining
activities include dust and other materials emitted during the
blasting and materials handling operations, major combustion
products released by the diesel oil-fueled equipment used in
mining operations, and wind-blown dust from mines and waste piles
In some surface mining operations, waste piles ignite spontaneous-
ly and burn, releasing products of combustion and other unburned
materials into the atmosphere. A summary of the airborne emis-
sions in a western mine is found in Table 3-36.
TABLE 3-36. AIR EMISSIONS FROM A 12 MILLION TPY COAL SURFACE
MINING OPERATION1
Emission Source
Diesel engines
Fugitive dust
Coal mining
i
Reclamation
Coal crushing
Production
Rate
250 gal/hr
1375 ton/hr
180 acres
1375 ton/hr
1 U . S . Environmental
Emission Rate Ibs/hr
Particulates CO
6
1100
600
7
Protection
23
—
—
Agency
NOV SO 2 Hydrocarbons
?N
CO 2
100 8 8 5500
• • •
— — —
Compilation of Air
^*
•"
Pollutant Emission Factors. EPA Publication AP-42. Research
triangle Park, NC:U.S. Government Printing Office. 1977.
p. 3.2.7.
-79-
-------
The diesel fuel emissions are based upon the ancillary fuel
requirements presented in Table 3-35 and calculated by using EPA
emission factors for heavy duty construction equipment. Parti-
culate emission rates from materials handling and wind erosion
are difficult to quantify. Very little data is available on
these sources. Coal mining and reclamation emission rates
presented in Table 3-36 are based upon general fugitive dust
emission factors developed by EPA. These .are presented in Table
3-37. Actual dust emissions are highly dependent on wind and
rain rates, soil conditions, and dust suppression measures. A
dust control efficiency of 4079 was assumed for mine area dust
suppression activities such as watering. The emission factors
for coal crushing were also developed by EPA and include an
emission control efficiency of 99% (crusher enclosures and bag
filters).1
TABLE 3-37. EMISSION FACTORS FOR MINING EMISSION SOURCES
Source Particulates CO NO SOa Hydrocarbons
X
Diesel engines (lb/103 gal)a 25 90 400 31 31 22,000
Fugitive dust (Ib/ton) .8
«
Reclamation (ton/acre-mo) .7
Coal crushing (Ib/ton) .005
^.S. Environmental Protection Agency. Compilation of Air Pollutant Emission
Factors . EPA publication AP-42, Research Triangle Park, NC: U.S. Government
Printing Office. 1977. p. 3.2.7.
blbid., p. 11.2.3
CjMd., p. 11.2.4
dJMd., p. 8.20
"U.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. EPA Publication AP-42.Research
Triangle Park, NC:U.S. Government Printing Office. 1977.
p. 3.2.7
-80-
-------
3.6.1.3b Water Effluents
Potential pollutants of streams and underground water sup-
plies from coal surface mining operations include iron, silt and
trace metals such as arsenic, copper, lead, manganese, zinc, ni-
trates and sulfates. Due to the alkalinity of the subsurface rock
in the western coal fields and the low sulfur levels in the coal,
pollution by dissolved acids such as sulfuric is not a problem.
Surface mining pollutants are eroded from the solid waste piles,
or spoil, and leached from the exposed underlying rock by rain
runoff. Fortunate] , very few mining areas yet found in New
Mexico or Wyoming have intersected groundwater. This is expected
to be the rule throughout the western states. Also, due to the
limited rainfall in this area, most mine drainage and surface run-
off is recovered and used to satisfy mining operation water re-
quirements such as dust control in the crushing plant and along
haulage roads. Therefore, no significant effluent streams are
anticipated from future western mines.
3.6.1.3c Solid Wastes
Solid wastes from mining vary considerably as a function of
surface mining technique, and overburden depth. In area strip
mining, solid wastes are produced only by the initial box cut
made to open the mine (five acres). Subsequently, removed over-
burden is deposited in spoil banks in the excavated area. The
quantity of the initial overburden, if 70 feet thick, is 15x10s ft3
or approximately 750xl03 tons.
Although surface mines are used for the disposal of addi-
tional solid wastes such as fly ash and waste sludges from bene-
ficiation, these solid wastes are not attributable to the coal
mine itself.
-81-
-------
3.6.1.3d Noise Pollution
Noise will be a problem within the plant due to use of
heavy machinery and explosives in breaking and loading the over-
burden. However, the plant is large enough (20,000 acres) that
noise is not considered a problem at the plant boundary.
3.6.1.3e Occupational Health and Safety
Hittman1 has estimated occupational health statistics for
a surface mine in the Powder River Basin to be: 9.91 deaths,
34.1 injuries, 2252 lost man-days for every 10 e Btu of coal ex-
tracted. Adjusting these figures to a 12 MM TPY mine in Colstrip,
Montana, one might expect the annual health statistics to be:
19 injuries, 1300 lost man-days, and one death every two years.
3.6.1.A Summary
Table 3-38 presents a summary of the direct impacts from a
12 MM TPY surface mine located at the Navajo scenario.
3.6.2 Underground Mining
3.6.2.1 Technology Description
The two basic underground mining methods used in the United
States are: room and pillar, and longwall. In both types of
mining, the initial step is to prepare the surface facilities,
including the constructing of access roads and structures,
bringing the necessary utilities to the site, clearing vegeta-
tion from the construction site, and locating tunnels and shafts.
Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use, Final Report:Vol. I,
1974; Vol. II, 1975. Columbia, MD:Hittman Associates, Inc.
1974 and 1975.
-82-
-------
TABLE 3-38. SUMMARY OF IMPACTS ASSOCIATED WITH 12 MM TPY SURFACE
MINE AT NAVAJO
Inputs
Manpower
construction
• operating
832 man-years
552 men
Materials and Equipment
• stripping shovels (140 cu yd)
• cement (tons)
• structured steel (tons)
draglines (tons)
a
Economics
<*'
• capital cost (estimated)
• annual operating cost (estimated)
Water (reclamation)
Land
Ancillary Energy
• electricity
• diesel fuel
Outputs,
Air Emissions
• hydrocarbons
• particulates
• S02
• N0x
• CO
• C02
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
• • deaths
• injuries
lost nan-days
3
62,800
940
10,400
$104 million
$ 46 million
4,000 acre-ft/yr
20,000 acres (30 yr total)
240 acres (at a time)
55 x 106 kwhr/yr
1.8 x 10s gal/yr
8 Ib/hr
1700 Ib/hr
8 Ib/hr
100 Ib/hr
23 Ib/hr
5500 Ib/hr
Recycled
Returned to mine
Insignificant
0.6 deaths/yr
19 injuries/yr
1300 man-days/yr
1974 dollars
-83-
-------
The equipment used" for these tasks basically is the same as that
used for surface mines.
The development of the mine itself for either mining methods
follows the same procedure. First, at least three main access
shafts are strategically bored into the coal bed. The accesses
can be of three types: drift, slope, or shaft.1 These types of
accesses are shown in Figure 3-13. Once the main access has
been constructed, two parallel main entries into the coal bed
are made in the direction of the mining operation. From the
main entries, a network of panel and butt entries is developed
which leaves columns of unmined coal termed "pillars" which
t
support the roof. This is the room and pillar or advance type
mine.
The room and pillar mining will recover approximately 50
percent of the coal. If the ground can be allowed to subside,
an additional 35 percent of the total amount of coal can be
removed by mining the pillars. This is retreat mining.
Instead of the butt entries/ a longwall technique can be
used in which the entire side of the panel is mined at once,
leaving no pillar. Longwall mining removes 80 to 85 percent of
the coal in the mine.2
3.6.2.la Room and pillar
Room and pillar mining is performed either by conventional
methods or by continuous miners. Figure 3-14 illustrates both
of these methods.3 In conventional methods the coal seam is
*TRW Systems Group. Underground Coal Mining in the United
States. Research and Development Programs^Springfield, VAl
National Technical Inrormation Service.T970. PB-193 934.
2Ibid.
3Ibid.
-84-
-------
LESS THAN:
;30 DEG
DRIFT
SLOPE
SHAFT
Figure 3-13. The Three Types of Access Used in Underground
Coal Mines
-85-
-------
s. toonoir
(A) CONVtNTIONAL
MINING
Figure 3-14. Illustration of Room and Pillar Mining Using
Conventional (Blasting) and Continuous Mining
Techniques
-86-
-------
blasted and then loaded by electric loaders on shuttle cars or
conveyors and hauled to the main conveyor or mine rail car train.
Portions of the coal are left in place to act as support pillars
for the strata overlying the rooms. With the electric continuous
miner, the coal is scraped from the seam and loaded directly on
a conveyor or shuttle car. The coal is transported to the main
conveyor or mine rail car train, and from there out of the mine.
Room size depends on the geology of the strata being mined,
the governing factors being the seam thickness, the strength of
the coal, and the strength of the overlying and underlying strata.
In typical U. S. underground mines (which are mostly in the
Eastern province), the coal and surrounding material strengths
are low, and the coal seams range from two to six feet thick.
As a consequence, the rooms are long and narrow, typically 10 to
20 feet wide and several hundred feet long. The rooms must be
kept this small even though mechanical supports are used to
increase the load-bearing capacity of the mine roof.
Roof support must be provided for the rooms excavated by
either room and pillar mining method. The support system most
frequently used involves drilling holes in the roof and insert-
ing bolts equipped with either expansion heads or another fasten-
ing system.1 Roof bolts generate compressive stresses to strenghen
the roof and permit excavating larger rooms than would otherwise
be possible. Recently, epoxy has been used to cement roof bolts
into place.
Leaving pillars,in place to support the roof significantly
decreases the portion of the coal that can be mined. On the
S. William, Jr. and Edward S. Rubin. A Program of
Research, Development and Demonstration for Enhancing Coal Utili-
zation to Meet National Energy Needs. Results of the Camegie-
Mellon University Workshop on Advanced Coal Technology. 1973.
-87-
-------
average, about 45 to 50 percent of the coal in place is recovered
in room and pillar mines. This percentage can be increased by
removing additional coal when the mine is being closed down and
roof support is no longer a problem. Possibly as much as 80
percent of the coal in place can eventually be recovered by the
room and pillar method.1
As might be expected, underground mining methods are becom-
ing more automated. Figure 3-15 reflects the growing use of
machines. The continuous miner has shown the most dramatic ap-
plication increase in recent years. One reason for this is that
continuous mining is considerably less labor intensive than is
conventional mining.
3.6.2.1b Longwall
Longwall mining has been very popular in Europe and is now
gaining acceptance in the United States. The longwall process
is shown in Figure 3-16. The electric longwall miner advances
laterally down the panel, scraping and shearing the coal from
*
the seam. The coal is automatically loaded on a self-advancing
conveyor and transported to the main conveyor or mine rail car
train. The roof is supported at the mine face by self-advancing
hydraulic roof supports. As the supports are moved, the roof in
the area from which the coal has been mined is allowed to collapse
The subsidence is sometimes enhanced by blasting to ensure a more
controlled cave-in rate.2
:Gouse, S. William, Hr. and Edward S. Rubin. A Program of
Research, Development and Demonstration for Enhancing Coal Utili-
zation to Meet National Energy Needs.Results of the Carnegie-
Mellon University Workshop on Advanced Coal Technology. 1973.
2TRW Systems Group. Underground Coal Mining in the United
States. Research and Development Programs"Springfield, VA:
National Technical Information Service.T970. PB-193 934.
-88-
-------
1-33
o
o
o
M-
o
a
o
fc
50
40
n 30
20
10
U'
1950
if
2»
1960
o'o
1971
HAND CUT
AND LOADED
MACHINE CUT
HAND LOADED
CONVENTIONAL
MINING
CONTINUOUS
MINER
Figure 3-15. Underground Mining Methods
Source: Gouse, S. William, Jr. and Edward S. Rubin. A Program
of Research, Development and^Demonstration for Enhancing
Coal" Utriization to Meet National Energy Need's"! Results
HI the Carnegie-Mellon University Workshop on Advanced
Coal Technology, 1973.
-89-
-------
conveyor
direction of advancement
COAL
shearer
face conveyor
roof support
collapsed
* roof »•
Figure 3-16. Plan View of Longwall Mining
Source: Gouse, S. William, Jr. and Edward S. Rubin. A Program
of Research. Development and Demonstration for Enhancing
Coal Utilization to'Meet National Energy Need's"! Results
of the Carnegie-Mellon University Workshop on Advanced
Coal Technology, 1973.
-90-
-------
The advantages and disadvantages of the various mining
methods are given in Table 3-39. The major advantages offered
by longwall mining is recovery of a higher percentage of the coal
in place than is possible with the room and pillar method and its
much greater safety factor. It is also less labor intensive
than some of the other techniques. On the other hand, capital
costs for longwall mining systems are generally greater than for
room and pillar mining.1
3.6.2.1c Underground Mine Reclamation
The reclamation problems associated with underground mines
vary somewhat from those of surface mines. A major problem is
the disposal of rock and earth mined with the coal. Often the
coal is cleaned at the surface to remove these materials. How-
ever, these materials cannot be simply piled up and left uncovered
because they may produce toxic water runoff which is high in
metals and salts dissolved from the coal by rain. One alterna-
tive is to treat the wastes with lime and dispose in sealed land
fills. Materials removed to gain access to underground coal
seams also require disposal in a similar manner.
Drainage, groundwater contamination, and subsidence of the
surface area overlying underground mines also constitute
reclamation problems. Generally, the surface will subside,
limiting subsequent surface usage.
'Gouse, S. William, Jr. and Edward S. Rubin. ^A Program of
Research. Development and Demonstration for Enhancing Coal
Utilization to Meet National Energy Needs.Results of the
Carnegie-Mellon University Workshop on Advanced Coal Technology.
1973.
-91-
-------
TABLE 3-39. COMPARISON OF CONVENTIONAL, CONTINUOUS, AND LONGWALL MINING
Longwall
Continuous Room
and Pillar
Conventional
Room and Pillar
Advantages • Increased production.
• Eliminates some permanent
roof support cost.
• Cuts cost of ventiliation,
storage, and rock, dusting
by 45%.
• Provides better ventilation,
roof support.
• Requires less supervision.
• Safer-superior method where
roof conditions are poor.
Involves fewer work cycles, less
equipment, and normally produces
more per man than conventional
mining.
Permits more concentrated mining
with fewer supervisory and venti-
lation problems.
Effective in coalbeds with
high hardness ratings,
large partings and varying
dimensions.
Produces leas fine coal.
Efficient where roof and
floor planes undulate.
I
to
to
Disadvantages • Requires large, level
straight blocks of coal free
from obstructions with scam
height minimum of 39".
Requires high capital invest-
ment for equipment.
• Involves costly equipment
moves (30-150 man-shifts
to move 300 tons of equip-
ment).
Not effective where hardness
ratings are high, partings large,
floor and celling planes undulate,
and roof conditions are poor.
Not effective where seam heights
vary greatly.
Cannot be used where coal size
is critical.
Provides inefficient face haulage.
Requires numerous work
cycles.
Involves larger crew and
more equipment with
attendant supervisory and
maintenance problems.
Produces less per man.
Provides inefficient face
haulage.
Hot efficient where roof
conditions are poor.
Partings are impure bands in coalbeds.
Source: TRW Systems Group. Under
ground Coal Mining in the United States. Res
Springfield, VA: National Technical Information Service, 1970. PB-193
Research and Development Programs.
-------
3.6.2.2 Input Requirements
The various inputs required for construction and operation
of an underground coal mine will be discussed in the following
sections. These inputs include labor, material and equipment,
capital, water, land, and any outside energy. Specific assump-
tions regarding size and location must be made in order to quan-
tify these input variables.
The underground mines considered in this discussion are
located at the Kaiparowits Plateau in Southern Utah. The size
of the operation considered is a 12 million TPY mine. A large
underground mine is one that produces 3 million TPY. Therefore,
for purposes of discussion, the 12 million TPY mining operation
is assumed to consist of four separate mines, each producing
approximately 3 million TPY.
3.6.2.2a Manpower Requirements
Construction Phase
The first phase of a mining operation is the construction
phase. Although an underground mine can be built and producing
within three years, this technology assessment is evaluating
impacts of mines on the Kaiparowits Plateau in Southern Utah;
an area for which an Environmental Impact Statement has been pub-
lished. l In order to aline this assessment as closely with the
EIS as possible, a proposed construction duration of six years
*U.S. Department of the Interior, Bureau of Land Management
Draft Environmental Impact Statement: Kaiparowits Project.
5 vols.Salt Lake City:Bureau of Land Management. 1975.
-93-
-------
is used to evaluate impacts from mine development. The estimated
technical and nontechnical manpower requirements are given by
man-years in Table 3-40. These estimates were made using Bechtel
Corporation's Energy Supply Model; a computer simulation routine
developed upon Bechtel Corporation's extensive construction
experience. A shorter construction period would have little
impact on the net manpower requirements of 2330 man-years.
The proposed mining construction schedule for all four mines
is depicted in Figures 3-17 and 3-18.
Operating Phase
Manpower requirements, for underground mining of a 72-inch
coal bed have been estimated by the U.S. Bureau of Mines for a
3.18 million TPY mine.1 Total manpower requirements for a 12
million TPY mining facility consisting of four separate 3 million
TPY mines is a direct scale-up of these figures. Table 3-41
presents total manpower requirements for operation of all four
underground coal mines.
3.6.2.2b Materials and Equipment
The Bureau of Mines has estimated capital costs for opera-
tion of various underground coal mines.2 In so doing, the Bureau
of Mines itemized and priced out the major pieces of equipment
required for operation of a 3.18 MM TPY underground mine. Table
3-42 presents this listing but the numbers have been adjusted to
reflect operation of a 12 million TPY mine - essentially four 3
million TPY facilities operating separately.
Sidney, E.L. Hemingway, and L.H. Berkshire. Basic
Estimated Capital Investment and Operating Costs for Underground
Bituminous Coal Mines; Mines With Annual Production of 1.03 to~
3.09 Million Tons From a 48 Inch Coal Bed.Bureau of Mines Infor-
mation Circular 8641.Morgantown, WV:Bureau of Mines. 1975.
2Ibid.
-94-
-------
TABLE 3-40.
SCHEDULE OF MANPOWER RESOURCES REQUIRED FOR CON-
STRUCTION OF A 12 MM TPY UNDERGROUND COAL MINE
Manpower (man-years)
Discipline
Civil Engineers
Electrical Engineers
Mechanical Engineers
Mining Engineers
Other Engineers
TOTAL ENGINEERS
TOTAL DESIGNERS + DRAFTSMEN
TOTAL SUPERVISORS + MANAGERS
TOTAL TECHNICAL
TOTAL NON-TECH (NON-MANUAL)
Pipefitters
Electricians
Iron Workers
Carpenters
Operating Engineers
Other Major Skills
Total Craftsmen
Total Teamsters + Laborers
GRAND TOTAL
Yr
1
1
1
0
1
4
2
0
6
1
1
1
1
1
3
4
11
_4
22
Source: Carasso, M. . et al. Energy
1 Yr 2
12
7
11
5
10
45
19
5
69
8
19
21
13
10
40
65
167
61
305
Yr 3
21
12
19
9
17
78
33
9
119
13
31
35
21
16
66
106
274
101
507
Yr 4
33
20
29
14
26
123
52
14
188
20
50
56
34
26
106
172
444
164
816
Supply Model, Computer
Yr 5
21
12
18
9
16
76
32
9
116
15
37
41
25
19
77
125
323
119
573
Tape.
Yr 6
5
3
4
2
4
17
7
2
26
3
6
7
4
3
14
22
57
21
107
San
Francisco: Bechtel Corporation, 1975.
-95-
-------
FIELD CONSTRUCTION
CONSTRUCT MINE NO. ONE
CONSTRUCT MINE NO. TWO
CONSTRUCT MINE NO. THREE
CONSTRUCT MINE NO. FOUR
CONSTRUCT WASHERY
CONSTRUCT CONVEYOR
CONSTRUCT TUNNEL
CONSTRUCT OFFICE & SHOPS
UTILITIES
YEAR
ONE
TWO
THREE
FOUR
FIVE
SIX
i i i !
— *M
4
Figure 3-13. Overall Mining Project Construction Schedule
Mor
ACCESS ROAD
UTILITIES
ROCK SLOPES
SINK SHAFTS
U.G. OPENINGS
INSTALLATIONS
SURFACE PLANT
VENTILATION FANS
MAIN ACCESS ROAD
MAIN POWER LINES
MAIN WATER LINES
OVERLAND BELT
MAIN PRODUCTION9
JTH
1
H-
2
-H
3
4
5
6
7
8
9
h-
10
-
11
12
-^
Phased into full production
equipment is assembled and
of three million tons
installed underground.
per year as
Figure 3-18. Individual Mine Development Schedule
Source: U.S. Department of the Interior, Bureau of Land Manage-
ment. Final Environmental Impact Statement: Kaiparowits
Project"5 vols.Salt Lake City:Bureau of Land Manage-
ment, 1975. p. 1-207.
-96-
-------
TABLE 3-41. TOTAL MANPOWER REQUIREMENTS FOR OPERATION OF FOUR
UNDERGROUND COAL MINES (NET PRODUCTION 12 MILLION
TPY)
Personnel Total
Underground:
Continuous miner operation 158
Loading machine operation 158
Machine operator helper 158
Shuttle car operator 317
Roof bolter 317
Bratticeman 158
Utility man 158
Mechanic (section) 158
Supply motorman 45
Beltman 102
Trackman 45
Wireman 45
Mason (precision) 68
Pumper 11
Utility crew 91
Roving mechanic 45
Fireboss (union) 15
Outside:
Lampman 11
Front-end loader operator 11
Shop mechanic 45
Salary:
Superintendent 4
General mine foreman 4
Assistant mine foreman 11
Section foreman 158
Maintenance superintendent 4
General shop foreman 4
Mine maintenance foreman 11
Chief mine engineer 4
Draftsman 4
Survey crew 11
Safety director 4
Safety inspector 11
Dust sampler 11
Office manager H
Timekeeper and bookkeeper 4
Purchasing supervisor £
Warehouseman .- Arf
TOTAL LABOR AND SUPERVISION 2,384
Source: Katell, Sidney, E.L. Hemingway, and L.H. Berkshire.
Basic Estimated Capital Investment and Operating Cost
for Underground Bituminous Coal Mines.Information
Circular 3682, Morgantow, wV:Bureau of Mines, 1975.
-9-7-
-------
TABLE 3-42. MAJOR EQUIPMENT SUMMARY, FOUR MINES TOTALING 12
MILLION TPY
Item Quantity
Continuous miner 64
Loading machine 64
Shuttle car 129
Roof bolter 64
Ratia feeder 64
Auxiliary fan 64
Mantrip Jeep 64
Mechanic Jeep 23
Personnel Jeep 30
Trickle rock duster 64
Triple duty rock duster 50
Supply motor 23
Supply car 265
42-inch rope-type mainline belt conveyor 34,000 ft
36-inch rope-type secondary and panel belts 136,000 ft
Mainline belt power center (300 kV-A) 23
Section belt power center (150 kV-A) 53
Section power center (1,000 kV-A) 64
Section rectifier (200 kW) 64
Section switch house 64
Sectionalizing switch house 38
HV cable (300 MCM AL) 61,000 ft
PLM coupler 68
Section cable and coupler
Rectifier for truck haulage 11
Trolley wire 193,000 ft
Track (60-Ib) 193,000 ft
Freshwater line 193,000 ft
(Continued)
-98-
-------
TABLE 3-42. (Continued)
Item Quantity
Pumps and lines
Telephone (page phones)
Conveyor fire protection
Automatic controls and alarms
Scoop tractor 64
Battery charger 64
All service mask 136
Breathing apparatus 136
Self rescuer 2,462
Stretcher set 76
Safety light 1,137
Methanometer 1,137
Fire chemical car 38
Lamp (including accessories) 2,462
Dust sampler 190
Concrete portal 19
Bulk rock dust facility 4
Substation and distribution 4
Bathhouse, office, and lamp house 4
Shop and warehouse 4-
Powder and cap house 4
Front-end loader 4-
Forklift *
Bulldozer 4
Utility truck 7
Pickup truck 7
Oil storage 4
Water tank 4
Supply yard 4
-99-
-------
Source: Katell, Sidney and E.L. Hemingway. Basic Estimated
Capital Investment and Operating Costs for Underground
Bituminous Coal Mines; Mines with Annual Production of
1.03 to 3.09 Million Tons from a 48-Inch Coal Bed.
Bureau of Mines Information Circular 8641, Morgantown,
WV: Bureau of Mines, 1975.
-100-
-------
Bechtel Corporation1 has estimated the material required
for construction of a 12 million TPY mine based on previous
construction experience. Their estimates indicate that 92,000
tons of ready mixed concrete, 4600 tons of piping, 6000 tons of
structural steel, and 6800 tons of reinforcing bars will be
required to build the underground mine.
3.6.2.2c Economics
The capital investment and annual operating cost for a 3
million TPY underground coal mine are presented in Tables 3-43
and 3-44. These were developed by the Bureau of Mines based on
1974 costs.2 As summarized in Table 3-45, the total capital
investment for four such mines producing a net 12 million TPY
is $308 million and the total annual operating cost is $100
million. The resulting coal selling price is $11.68/ton in 1974
dollars. By 1976 these costs had risen to approximately $20/ton.3
3.6.2.2d Water Requirements
The only process water requirements of the mining operations
considered here would consist of the water used for dust control
in the crushing plant and along haulage roads. All of the water
required to satisfy these demands is assumed to be available in
the form of reclaimed water collected as mine drainage. For this
reason, no water requirements are acknowledged for an underground
mine.
^arasso, M., et ai. Energy Supply Model. Computer Tape.
San Francisco: Techtel Corporation, 1975.
2Katell, Sidney, E.L. Hemingway, and L.H. Berkshire. Basic
Estimated Capital Investment and Operating Costs for Underground
Bituminous Coal Mines: Mines With Annual Production of 1.06 to~
4.99 Million Tons From a 72-Inch Coalbed.Bureau of Mines Infor-
mation Circular 8682.Morgantown, WV:Bureau of Mines. 1975.
p. 5.
3Nielson, George F., ed. 1977 Keystone Coal Industry Manual.
New York, New York: McGraw-Hill Mining Publication.1977.p. 545
-101-
-------
TABLE 3-43. ESTIMATED WORKING CAPITAL AND TOTAL CAPITAL INVEST-
MENT (3 MILLION TPY MINE, 1974)
Cost
Item ($ million)
Estimated working capital:
Direct labor 3 months 1.8
Operating supplies 3 months 1.4
Payroll overhead 3 months .7
Indirect cost 4 months .6
Fixed cost 0.5 percent of insurance base .2
Spare parts .6
Miscellaneous .1
Total working capital 5.4
Total estimated capital Investment:
Total mine cost (insurance, tax base) 44.7
Interest during development 2.0
Subtotal 46.7
Working Capital 5.4
Estimated capital investment 52.1
Estimated deferred capital investment 24.9
Total capital investment and deferred investment 77.0
Source: Katell, Sidney, E.L. Hemingway, and L.H. Berkshire. Basic Esti-
mated Capital Investment and Operating Costs for Underground
Bituminous Coal Mines; Mines with Annual Production of 1.06
to 4.99 Million Tons From a 72-Inch Coalbed. Bureau of Mines
Information Circular 8682, Morgantown WV: Bureau of Mines, 1975.
p. 5.
-102-
-------
TABLE 3-44. ESTIMATED ANNUAL PRODUCTION COST (3 MILLION TPY
MINE, 1974)
Item
Direct cost:
Production:
Labor
Supervision
Maintenance:
Labor
Supervision
Operating supplies:
Mining machine parts
Lubrication and hydraulic oil
Roof bolts and timber
Rock dust
Ventilation
Bits
Cables
Miscellaneous
Power
Annual Cost
($ Million)
5.34
.87
6.28
.75
.09
.84
1.89
.75
.93
.39
.57
.36
.18
.45
5.52
.96
Cost per ton
($/ton)
1.78
.29
2.07
.25
.03
.28
.63
.25
.31
.13
.19
.12
.06
.15
1.84
.32
Water
Payroll overhead (40 percent of 2.82 .94
payroll)
Union welfare3 3.06 1.02
Indirect cost:
15 percent of labor, supervision,
and supplies 1.89 .63
Fixed cost:
Taxes and insurance, 2 percent of
mine cost
Depreciation
TOTAL
.90
2.34
3.24
24.54
.30
.78
1.08
8.18
Effective Dec. 6, 19t4, under the Bituminous Wage Agreement of 1974.
Source: Katell, Sidney, E.L. Hemingway, and L.H. Berkshire. Basic Esti-
mated Capital Investment and Operating Costs for Underground Bitu-
minous Coal Mines: Mines with Annual Production of 1.06 to 4.99
Million Tons From a 72-Inch Coalbed. Bureau of Mines Information
Circular 8682, Morgantown WV:Bureau of Mines, 1975. p. 5.
-103-
-------
TABLE 3-45. CAPITAL AND INVESTMENT COST FOR UNDERGROUND COAL
MINING (1974)
Cost
Item 1 mine 4 mines
Production (million tons/year) 3 12
Initial Capital Investment ($ million) 52 208
Deferred Capital Investment ($ million) 25_ 100
Total Capital Investment ($ million) 77 308
Total Capital Investment/Annual Production ($/ton) 25.48 25.48
Annual Operating Cost ($ million) 25 100
($/ton) 8.18 8.18
Required Selling Price (§15% DFC ($/ton) 11.63 11.63
Source: Katell, Sidney, E.L. Hemingway, and L.H. Berkshire. Basic Estimated
Capital Investment and Operating Costs for Underground Bituminous
Coal Mines: Mines with Annual Production of 1.06 to 4.99 Million
Tons from a 72-Inch Coalbed. Bureau of Mines Information Circular
8682, Morgantown, WV: Bureau of Mines, 1975. p. 5.
-104-
-------
3.6.2.2e Land Requirements
In addition to the mine itself, land requirements for
underground mining operations include the areas occupied by coal
processing and loading facilities. Estimated total land require-
ments for typical western and midwestern mining operations are
summarized as follows:
Mine Site:
Active Working Area (acres) 322
Land Being Reclaimed (acres) 2,350
Haulage Road (acres) 5
Processing and Loading (acres) 75
TOTAL ACRES 2,752
The land area designated as the active working area was
assumed to be equal to the land disturbed or undermined in 100
days of mining activity. Reclamation land requirements were
determined by assuming that two years are required to allow for
subsidence prior to the start of reclamation activities. The
haulage road requirements were taken from Hittman.1 The 75 acres
allocated to the aboveground processing facilities (crushing,
loading, and water treatment) was an assumed figure.
At any given time approximately 2800 acres will be in use
by the mining operation. Throughout the 30 year life of the mine,
a total of 36,000 acres will have been occupied by the mine.
By far the largest portion of this land requirement can be
reclaimed and returned to other production uses.
1Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use.Final Report:Vol. I,
1974; Vol. II, 1975. Columbia, MD:Hittman Associates, Inc.
1974 and 1975.
-105-
-------
3.6.2.2f Ancillary Energy
Ancillary energy requirements for a 3.18 million TPY
underground coal mine are presented in Table 3-46. These
estimates were developed by the Bureau of Mines based on an
Appalachian room and pillar mine.1 A single 3 million TPY mine
would require approximately 246,000 kwh and four such mines
producing 12 million TPY would require approximately 960,000
kwh/d. Assuming a 33 percent power plant efficiency, the net
energy requirement for the production of 12 million TPY of coal
is 3.5 x 1012 Btu/year.
3.6.2.3 Outputs
Outputs from underground mining activities depend on the
size of the mine which in turn depends on the demand for energy
from that particular mine. Outputs will also depend on the type
of underground mining method employed. Since continuous room
and pillar mining is by far the most prevalent form of under-
ground mining in the U.S., accounting for over 62 percent of the
total underground bituminous and lignite production, it will be
the extraction method for which the emissions and other outputs
will be presented in this section.
The underground mines considered in this discussion are
located at the Kaiparowits Plateau in Southern Utah. The size
of the operation considered is a 12 million TPY mining operation
consisting of four 3 million TPY units.
lKatell, Sidney, E. L. Hemingway, and L. H. Berkshire.
Basic Estimated Capital Investment and Operating Costs for Under-
ground Bituminous Coal Mines; Mines With Annual Production 6T
1.06 to 4.99 Million Tons From a 72-Inch Coalbed.Bureau of
Mines Information Circular 8682.Morgantown, WV: Bureau of
Mines. 1975. p. 28.
-106-
-------
TABLE 3-46.
POWER REQUIREMENTS FOR A 3 MILLION TPY UNDERGROUND
COAL MINE
Number
of
units
14
14
28
14
14
14
14
6
8
14
6
3
12
1
Source:
Operation
Continuous miner
Loading machine
Shuttle car
Roof bolter
Ratio feeder
Auxiliary fan
Mantrip Jeep
Mechanic Jeep
Personnel Jeep
Rock duster
Supply motor
42- inch conveyor
36-inch conveyor
Ventilation fan
Extra for pumps,
tools, lights, etc
TOTAL
Katell, Sidney, E.
Capital Investment
Coal Mines: Mines
HP Hp,
per total
unit load
600 8,400
160 2,240
135 3,780
50 700
125 1,750
30 420
15 210
15 90
7.5 60
30 420
80 480
200 600
150 750
500
500
L. Hemingway,
and Operating
Hr per
day, full
load
15
15
15
18
15
18
6
15
15
12
12
15
15
24
10
KW,
total
load
6,266
1,671
2,820
522
1,305
313
156
67
45
313
358
447
560
373
373
Total kW-hr
requirement
93,900
25,065
42,300
9,396
19,575
5,634
936
1,005
675
3,756
4,296
6,705
8,400
8,952
3,730
234,415
and L.H. Berkshire. Basic Estimated
Costs for Underground
with Annual Production of
Tons from a 72-Inch Coalbed. Bureau of Mines
1.06 to 4
Bituminous
.99 Million
Information Circular
8682, Morgantown, WV: Bureau of Mines, 1975. p. 28.
-107-
-------
3.6.2.3a Air Emissions
The vented air from the mine is calculated to have a flow
of one million cubic feet per minute. This value is based on a
design criteria set to keep the methane concentrations below 0.1
vol percent of the air in the mine.1 The methane production rate
in the underground mine module is 200 cubic feet per ton of coal
mined.2 Therefore, the methane emission rate is calculated as
3000 Ibs/hr per mine or 12,000 Ibs/hr for the total complex.
The ventilation air in the mine is supplied by an induced draft
system equipped with a large electric exhaust fan. The venti-
lated air and methane are exhausted to the atmosphere with no
further treating.
Particulate emission levels in the mine are maintained at
the federal standard of 2.0 mg per cubic meter by the ventilation
system.3 Particulate emissions from the continuous miners at the
mine face may reach levels as high as 40 mg per cubic meter.1*
The particulate matter generated by the continuous miners are,
however, controlled by air scrubbing systems equipped on the
miners. The air scrubbing systems are Venturi-type scrubbers
with mini-cyclones and water spraying apparatus.5 Ventilation
air rates at the mine face are maintained between 6,000 and
20,000 scfm to dilute any methane that is produced from the
'TRW Systems Group. Underground Coal Mining in the United
States. Research and Development Programs.Springfield, VA:
National Technical Information Service.T970. PB-193 934.
2"Degasification of Coalbeds - A Commercial Source of Pipe-
line Gas." A.G.A. Monthly 56 (1), 4 (1974).
3Hill, Robert W. "Dust Control With Collectors on Continuous
Miners." Mining Cong. J. 60 (7), 46 (1974).
"*TRW Systems Group, op.cit.
5Hill, Robert W., op.cit.
-108-
-------
mining operation.1 Fugitive dust within the mine also results
from primary crushing. The module primary crusher has a dust
emission factor of 0.1 Ib of suspended solids per ton crushed.2
This factor is assumed to be reduced 80 percent by use of water
sprays. The final quantity of suspended dust is diluted in the
ventilation air and exits the mine in the ventilation system.
Since all equipment is assumed to be electric, the major
source of atmospheric emissions is the exhaust air from the ven-
tilating system. For the example four underground coal mines,
700 Ibs of particulates and 288,000 Ibs of hydrocarbons are
emitted each day.
3.6.2.3b Water Effluents
Mine drainage and surface runoff is assumed to be collected,
treated, and used to satisfy mine site water demands: dust supres'
sion and reclamation. However, mine drainage and surface runoff
can exceed mine site water demands. In these instances, mine
effluent water must be held in settling ponds for suspended
solids removal. Following treatment, the mine drainage is
suitable for use in coal processing facilities, power plants,
or release into water systems. If flows are small enough and
no reuse alternatives are available, mine drainage can be dis-
posed in evaporation ponds.
*TRW Systems Group. Underground Coal Mining in the United
States. Research and Development Programs.Springfield, VA:
National Technical Information Service.T970. PB-193 934.
2Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2nd ed. , with supplements.
Research Triangle Park, NC: Environmental Protection Agency.
1973.
-109-
-------
3.6.2.3c Solid Wastes
Mine disposal of underground mining refuse is generally not
practiced. According to Hittman,1 solid wastes are produced in
an Illinois underground mining operation at a rate of 99.3 tons
per 1012 Btu coal extracted. Therefore, the mines in this dis-
cussion will be assumed to produce 78 tons of solid wastes per
day which must be disposed of on the surface. However, this
material cannot be simply piled up and left uncovered, because
it may produce toxic water runoff when dissolved by rain. One
alternative is to dispose of the wastes in sealed land fills and
valley fills.
3.6.2.3d Noise Pollution
The only noise that will affect the surrounding environment
is noise associated with the surface equipment, such as truck
loading, railcar loading, conveyor transportation, etc. Due to
the remoteness of western coal mines, these noise effects are
generally negligible for the public.
3.6.2.3e Occupational Health and Safety
Mine safety, a continuing problem, is more critical in under-
ground than in surface mining. In surface mines, safety problems
are much the same as those associated with any activity involv-
ing heavy equipment and the use of explosives. In underground
mines, ventilation, methane control, general fire and explosion
control, and roof support are additional problems. Despite these
formidable safety problems, underground mine safety has been
improving since the Bureau of Mines began keeping records in
1Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use, Final Report: Vol. T~,
1974; Vol. II, 19/5. Columbia, MD:Hittman Associates, Inc.
1974 and 1975.
-110-
-------
1910 and, as Figure 3-19 indicates, fatalities have decreased
since that time.
Mines are usually ventilated by positively managing airflow
patterns throughout the mine. This may include erecting tempo-
rary partitions, establishing airwall barriers, and installing
fans to circulate air. Ventilation systems typically include
several techniques, together with dust collectors and monitor-
ing equipment.
Methane has always been a problem in underground mines.
Most current attempts to deal with this problem use conventional
ventilation methods. However, degasification (including drilling
holes to drain methane pockets or introducing gases which have
a higher affinity for methane than does coal) is now receiving
R&D attention.1 Although at least one large coal company is pur-
suing seismic technologies to locate methane pockets, it is not
clear whether this is an operational procedure in all of the
company's underground mines (Interview with industry engineer,
June 1974).
In addition to methane/drainage, fire and explosion control
includes installing fire quenching systems, dust suppressors,
explosion and fire barriers, inflatable seals, and monitoring
systems. Rigid inspection, testing, and approval procedures
have helped make mine equipment safer. Based on mine safety
records, Hittman Associates have also estimated that yearly
injuries in a 12 million TPY mine will likely total 370 and
there will be approximately 210,000 man-days lost.2
S. William, Jr., and Edward S. Rubin. A Program of
Research, Development Demonstration.for Enhancing Coal Utilization
to Meet National Energy Needs,Results of the Carnegie-Melion
University Workshop on Advanced Coal Technology. 1973.
2Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use.Final Report: Vol I, 1974,
5f
>Ti
Vol II, 1975.Columbia, MD:Hittman Associates, Inc. 1974, 1975.
-Ill-
-------
Kl
I
3
i
I
er million tons
_ Per million man hours
1
1
1910
1920
1930
1940 1950
I960 1970
Figure 3-19. Underground Mine Fatalities
Source: Gouse, S. William, Jr., and Edward S. Rubin. A Program
of Research. Development and Demonstration for Enhancing
Coal Utilization to Meet National Energy Needs.Results
of the Carnegie-Mellon University Workshop on Advanced
Coal Technology, 1973.
-------
Table 3-47 presents a summary of the direct.impacts from a
12 MM TPY underground coal mine located at the Kaiparowits scenario.
3.6.3 Social Controls
Coal mining and reclamation are subject to regulation by both
the federal and state governments. Both have developed laws,
regulations, rules, and policies that either directly or indirectly
affect the deployment of mining technologies. These control how
lands are obtained for mining and procedures to ensure safety and
environmental protection and reclamation. These are described
in several jurisdictional levels in the following sections.
3.6.3.1 Obtaining Minable Land (Leasing)
Following exploration, or when deposits are known to exist,
a number of procedures are followed to obtain rights to the
minerals so that mining can begin. As described in the general
social control chapter, if mineral rights are separated from
surface rights, which is commonly the case, the mineral owner may
sell or lease his right to remove the coal. If the mineral
rights have not yet been severed from the surface, the surface
owner would still own the rights to minerals and could sell or
lease his rights to a portion or all of the minerals. For
example, the owner may sell or lease only the right to coal.
Generally, coal developers have acquired rights by leasing
rather than outright purchase from owners. The general situation
as described above, is applicable to surface and mineral owner-
ship whether federal, state, Indian or private. However, some
variations exist when either the federal or state governments
owen mineral or surface rights.
-113-
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TABLE 3-47.
SUMMARY OF IMPACTS ASSOCIATED WITH A 12 MM TPY
UNDERGROUND COAL MINE AT KAIPAROWITS
Inputs
Manpower
• construction
• operating
Materials and Equipment
continuous miners
loading machines
ready mixed concrete
structural steel
reinforcing bars
piping
Economics3
capital costs
operating costs
Water
Land
at any given time
30 year total
Ancillary Energy
Outputs
Air Emissions
particulates
hydrocarbons
Water Effluents
Solid Wastes
Noise
Occupational Health and Safety
fatalaties
injuries
• lost man-days
2,330 man-years
2,384 men
64
64
92,000 tons
6,000 tons
6,800 tons
4,600 tons
$308 million
$100 million
None
2,750 acres
36,000 acres
3.5 x 1012 Btu/yr
0.35 ton/day
144 ton/day
Highly site dependent
78 tons/day
Insignificant
7.2 deaths/yr
370 injuries/yr
210,000 man-days
a!974 dollars
-114-
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3.6.3.la Federal Lands1
Policies regarding the development of coal on federal lands
have changed substantially over the past 200 years. (See the sum-
mary of significant legislation in Table 3-48.) Coal development
was suspended in 1973 when the Secretary of the Interior announced
that the coal prospecting and leasing program was temporarily sus-
pended. Following the suspension, preference right leasing was
eliminated, and all leasing is now competitive. The federal gov-
ernment has developed three categories of lands, and to some ex-
tent the jurisdiction over coal development on these lands vary.
(See Table 3-49.) The procedures for leasing or licensing these
lands are summarized in Table 3-50.l
3.6.3.1b Indian Lands
Procedures for acquiring Indian lands are generally the same
as those for federal lands, although Indian authorities do have
veto power over leasing decisions. Indian lands are administered
in a cooperative trusteeship. Although Indian lands are not an
integral part of the public domain, Indians do not have complete
legal title.
There are three principal categories of Indian lands: allot-
ted, where title has been partially transferred to individial
Indian landowners; tribal, where the lands are collectively owned,
and ceded, where surface rights are privately held and mineral
rights are held by a tribe.
The Bureau of Indian Affairs (BIA) acts as a trustee, both
for individual Indians and tribes. The stated goal is to protect
Indian interests from overzealous government policies and to
federal leasing procedures are currently in a state of flux.
See U.S. Department of Interior, Coal Leasing Programmatic Impact
Statement, 1975.
-115-
-------
TABLE 3-48.
SUMMARY OF SIGNIFICANT PUBLIC LANDS
MINERALS OWNERSHIP LEGISLATION
Year
Act
Significant Point*
H
-------
TABLE 3-49. SUMMARY OF FEDERAL LAND CATEGORIES AND JURISDICTION
Predominant
Land Category Agency
Public Domain; Lands subject to disposal or sale under the BLM
general land laws of the U.S. but not including either reserved
lands, withdrawn lands, or coastal lands below the low water mark.
Reserved: Lands that have been set apart by the congressional BLM
or executive branches for a special public use such as national BIA
forests, Indian and military reservations, etc. DOD
DOA
Withdrawn; Lands temporarily removed from the public domain by BLM
special legislation usually for conservation purposes.
Acquired; Lands that were never a part of the public domain or BLM
that were once public but owned either privately or by a state
government when acquired or reacquired by the federal government.
-------
TABLE 3-50. SUMMARY OF LEASING AND LICENSING FEATURES FOR FEDERAL AND INDIAN LANDS
00
I
Method Period Acreage
Preference* Indeterminate 46,080
Lease (non acres
competitive) per
state
Competitive Indeterminate 46,080
Lease acres
per
state
Indian Lands Ten Years 2,560
acres
Rental or
Royalty
Rent and
royalty
set by
uses
USGS sets
minimum ,
amount
competitively
determined
Flexible,
based on com-
parisons with
local markets
1.
2.
3.
4.
5.
1.
2.
3.
4.
5.
6.
7.
8.
1.
2.
3.
4.
Procedures
Initiated by private individuals
or BLM
Documentation of workable deposits
reviewed by BLM and USGS
EIS process if applicable
Lease sold
Diligent development required
Federal coal lands review by BLM
Initiated by private individuals
or by BLM
Nominations (private)
BLM nomination reviewed by USGS
EIS if applicable prepared by BLM
Special lease terms and conditions
prepared by BLM
Lease sale
Diligent development required
Initiated by tribes to private
individuals
Nominations approved by Indians
and BIA
EIS process if applicable
Lease sale
*New leases (under this category) are no longer made,
applicable to existing preference leases,
However, preference lease features are
-------
provide assistance and service in granting permits and making
leases. Both the federal government and the Indian tribes have
veto power over a lease.
3.6.3.1c State Lands
Most states have constitutional provisions authorizing the
sale of state-owned lands. However, there has been a trend
toward reserving mineral rights to the states. States usually
have a goal of effecting a policy "to promote the discovery and
« •
development of the mineral resources of the state for the benefit
of the public through a system of licensing on a royalty basis.1
By 1970, most of the western states had enacted legislation pro-
viding for leasing state-owned lands. These lands include:
1) Public lands that were still under the state's
sovereign power at the time of admission to the
Union;
2) Land grants to the state from the federal govern-
ment at the time the state was created;
3) Lands in the beds of rivers and streams that were
navigable at the time the state was created; and
4) Lands acquired by the state, such as lands con-
fiscated for nonpayment of taxes.2
The states have only limited control over land grants since
the Congress specified the purposes for which they could be used.
In addition, many of the states sold the lands transferred to
them by the federal government without reserving the mineral
rights to themselves.
1 Verity, Victor, John Lacy, and Joseph Geraud. "Mineral
Laws of State and Government Bodies." American Law of Mining
Vol. II, Title XII. pp. 627-638.
ilbid.
-119-
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In all western states, responsibility for managing the
leasing state lands and minerals is located in a single state
agency. The administrative head of the agency may be authorized
to accept or reject prospecting and lease applications. It is
not unusual, however, for leasing approval to require the con-
sent of more than one state agency.
If state lands are known to contain commercially valuable
coal deposits, they will usually be leased competitively. If it
is unknown whether the lands contain commercially valuable
deposits, systems range from first-come-first-served to competi-
tive bidding.
In the western states leases are commonly for an initial
term of up to 10 years, with a preferential right for renewal.
However, some states offer an initial term of as little as five
years while others offer as many as 20. When the initial term
is short, the lease usually remains in force as long as the mine
continues to produce in paying quantities or as long as the
development operation is continued in good faith.
Rental rates for state mineral leases are usually fixed,
whereas royalties are usually calculated as a percentage of the
value of production. Some states require rent only, others re-
quire both rent and royalties, and some require only royalties.
At least two states have statutes requiring at least some
competitive leasing of state coal lands (Montana and Utah),
although in Utah the requirement is only on newly acquired lands
of the state. It is possible for the state leasing agency in
the remainder of the states to require competitive leasing in
their own regulations. At least two states give a preference
(by statute) to the prospector or permit holder (Arizona, New
Mexico).
-120-
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Tables 3-51 through 3-58 summarize state leasing features.
The second item on each table, Requirements, is usually left
blank indicating an application with a minimum of information
(applicant's name, address, and location of the land involved).
If there are requirements beyond the minimum above, the statute
will be listed in that category.
3.6.3.Id Private Lands
Contracts for developing coal on privately owned lands are
of three principal types: sale, lease, and license. Leases
differ from sale primarily by being limited to a fixed time
period; but a lease does effectively transfer ownership of the
resource for the time period specified in the contact. Licenses
do not, and they may be revoked.
State laws govern all three types of contracts. While there
is a great deal of diversity among the states, there also have
been some similarities in the content of private coal contracts,
and the most common type of contract is the lease. In this
arrangement most state laws are similar in terms of:
1) The ways in which rights are transferred and defined,
particularly in the granting clause that describes
the coal to be mined;
2) The definition of limitations in the lease, such as
the duration, which is almost always for a fixed term;
3) Express covenants outlining requirements for
development and marketing, including the lessee's
duty to mine "merchantable coal" in a "proper
manner"; and
-121-
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TABLE 3-51. ARIZONA COAL LEASE FEATURES'
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Rental
5. Royalty
6. Duration
7. Bond
8. Other
Information
§ 27-254 State Land Department, State Land Com-
missioner.
§ 27-254 1. Discovery under exploration permit.
2. Proof of valuable mineral deposit.
§ 27-234 $15.00 per year for each 20 acres.
§ 27-234 50 percent of net value of production.
§ 27-235 20 years, with renewal of successive 20
year terms.
Arizona Revised Statutes Annotated, 1956
TABLE 3-52. COLORADO COAL LEASE FEATURES*
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Rental
5. Royalty
6. Duration
7. Bond
8. Other
§ 36-1-113 State Board of Land Commissioners.
§ 36-1-112 Application - 500
Lease - $1.00
Lease service fee - $5.00
§ 36-1-114 Board may adjust rentals to get maximum
revenue
§ 36-1-139 15c per ton
§ 34-32-109 See Section 1.6.2.3.2 for open mine per-
mit if required
Colorado Revised Statutes, 1973.
-122-
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TABLE 3-53. MONTANA COAL LEASE FEATURES4
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Rental
5. Royalty
6. Duration
7. Bond
8. Other
§ 81-501
§ 81-503
§ 81-503
§ 81-502
§ 50-10
§ 50-16
§ 69-33
§ 81-501
I 81-2612
State Board of Land Commissioners
Rent set by board, but not less than
$2.00 per acre.
Set by board, but not less than 10 percent
Ten years, renewable every five years
See Section 1.6.2.3.2 for Strip and Under-
ground Mining Act, Mine Siting Act, for
geophysical exploration permit.
This leasing or exploration agreement
must be executed by competitive bid to
return at least the fair market value.
If there is a conflict between coal, oil,
gas, or geothermal developers on state
lands, the first issued lease has priori-
ty, but the board may amend to fit the
situation.
Revised Codes of Montana, 1947; this is also the procedure for coal ex-
ploration in Montana.
-123-
-------
TABLE 3-54. NEW MEXICO COAL LEASE FEATURES'
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Rental
5. Royalty
6. Duration
7. Bond
8. Other
Information
§ 7-10-1
§ 7-10-1
§ 7-10-2
§ 7-10-2
§ 7-10-2
§ 7-10-3
Comissioner of Public Lands.
Fees to be set by commissioner.
See Item #5, Royalty.
Not less than $0.08 per ton and not less
than $3.00 per acre for first year,
$4.00 per acre second year or $5.00 per
acre year after third year.
Not over five years.
Preferential right to lease to previous
leasee or previous prospect permit holder.
aNew Mexico Statutes, 1953
-124-
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TABLE 3-55. NORTH DAKOTA COAL LEASE FEATURES
a
Item
Statutes
Summary
1. Agency
S 38-11
§ 38-15-05
2. Requirements
3. Fees § 38-15-05
A. Rental § 38-15-05
5. Royalty
6. Duration
7. Bond
8. Other
§ 38-15-05
38-15-03
§ 38-14
§ 38-17
§ 38-18
The Board of University and School Lands
is the only state agency which has
leased lands, and it has broad authority
to regulate leasing by other state
agencies.
$10 for lease application for trust lands.
Not less than $1.00 per acre for trust
lands.
Not less than 6%. Current policy is
between 10 and 12.5%.
The industrial commission may require a
bond to satisfy conflicts between all
mineral developers on the same land -
whether coal, oil, gas or otherwise.
See Section 1.6.2.3.2 for additional
permit requirements.
itate that it appears only general leasing procedures control state lands of
North Dakota for coal leases; coal is specifically exempted from detailed
procedures affecting oil and gas leasing and from such detailed procedures
affecting uranium and other minerals. Also see § 39-09-02 above.
-125-
-------
TABLE 3- 56. SOUTH DAKOTA COAL LEASE
a
1.
2.
3.
4.
5.
6.
7.
8.
Item
Agency
Requirements
Fees
Rental
Royalty
Duration
Bond
Other
Information
Statutes
§ 5-7-1
§ 5-7-13
§ 5-7-12
§ 5-7-12
§ 5-7-12
§ 5-7-15
§ 5-7-13
§ 45-7A-3
§ 45-7A-2
Summary
Comissioner of school and public lands.
A reclamation plan.
$25.00 for application.
Fixed by Board of School and Public Lands,
but not less than five percent.
Not more than five years, with renewal
available for five year terms.
Required for payment of royalties. Amount
of bond at discretion of commissioner.
A report of any exploratory well drilled
must be sent to Department of Natural
Resources (will be kept confidential).
Well must be plugged, capped or sealed.
§ 5-7-2 This section specifically exempts coal and
uranium from a required lease by competi-
tive bidding.
§ 5-7-11 This section says the permittee may apply
for a license (lease). (But says nothing
of preference to permittee.)
§ 45-6A-16 This section exempts state lands from the
requirement of a surface mining permit
(fee - $50.00) issued by the state con-
servation commission.
lSouth Dakota Compiled Laws, 1967
-126-
-------
TABLE 3-57. UTAH COAL LEASE*
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Rental
5. Royalty
6. Duration
7. Bond
8. Other
Information
§ 65-1-18 State Land Board.
§ 65-1-24 $0.15 per acre
§ 65-1-18 Not less than $0.50 per acre per year nor
more than $1.00 per acre per year.
§ 65-1-18 Not more than 12*s percent of gross.
§ 65-1-18 Not less than 10 years and for so long as
producing.
§ 65-1-90 Required only to reinstate lease after
failure to pay for damages to surface.
Amount of bond discretionary.
§ 40-8-13 If this is a mining operation (surface)
§ 40-8-14 the developer must submit a plan of recla-
mation and before operations start also
execute a bond, for surface damage. The
Board of Oil, Gas, and Mining controls
this aspect. The board determines the
amount of bond.
§ 40-6-5 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 a well log (for any
drilling).
§ 65-1-45 Newly acquired lands and lands with an
expiring lease must be let through com-
petitive bids, all others leased to first
applicant.
3Utah Goad Annotated, 1953
-127-
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TABLE 3-58. WYOMING COAL LEASE1
Item
Statutes
Summary
1. Agency § 36-74
2. Requirements
3. Fees § 36-42
4. Rental
5. Royalty § 36-74
6. Duration § 36-74
7. Bond
8. Other § 36-74
Board of land commissioners, Commissioner
of public lands.
Fee for filing a lease application is
$15.00.
Not less than $0.05 per ton.
Not more than 10 years, with preferential
right to renew for 10 year periods.
The agency above has authority to set
rates and terms in its rules and regula-
tions within confines of specific statutes
noted above.
Wyoming Statutes of 1957
-128-
-------
4) Implied covenants, including the obligation to
begin operation, exhibit diligence, protect other
coal seams, and comply with abandonment require-
ments . l
3.6.3.2 Health and Safety
The earliest rules and regulations promoting health and
safety during mining originated with states.2 By 1900, most
mines in the U.S. were subject to state or territorial regula-
tions of some type. However, these were not always adequately
enforced. A series of mine disasters shortly after the turn of
the century led to the enactment in 1910 of the first federal
legislation calling for an inquiry into the cause of occupational
hazards. This led to the establishment of the Bureau of Mines
(BuMines) as an investigatory agency—but gave the Bureau no
authority to make inspections.
It was not until the Federal Coal Mine Safety Act of 19413
that authority providing for inspection of coal mines was enacted,
and this was limited to mines engaged in interstate commerce.1*
This Act also required miners to furnish accident information to
BuMines inspectors, and authorized the Bureau to make recommenda-
tions following its inspections. However, BuMines still was not
given enforcement authority.
Robert T. "Coal Leases," in Rocky Mountain Mineral
Law Foundation, ed. , The American Law of Mining, New York, N.Y. :
Matthew Bender, Vol. 3, pp. 301-341 (1967).
2Pennsylvania, for example, enacted legislation establishing
basic health and safety standards for anthracite coal mines in 1869
'Federal Coal Mine Safety Act, Title I. Pub. L-77-49, 55
Stat. 177 (1941).
Treehling, Robert J. "Health and Safety Regulations," in
Rocky Mountain Mineral Law Foundation, ed., The American Law of
Mining. New York, N.Y.: Matthew Bender, Vol. 3, pp. 714-716 (1967).
-129-
-------
In 1952, the Bureau was given its first enforcement authority
The Act passed in that year provided that the Bureau could enforce
compliance with underground mining standards in mines employing
more than 14 miners.1 And in 1965, the federal government pre-
empted from the states jurisdiction for health and safety.2
By 1966, then, the federal government had assumed overall
inspection and enforcement authority in this area. However, in
practice, state agencies continued to regulate coal mine health
and safety on a day-to-day basis. Finding this unsatisfactory,
the federal government enacted the 1969 Federal Coal Mine Health
and Safety Act, an all inclusive act preempting for the federal
government the entire scope of coal mine health and safety.3
The Act established separate specific requirements for sur-
face and underground mines, including specifying maximum dust
and noise levels, standards for blasting and explosives, programs
for medical examinations and chest x-rays, benefits for disabled
miners, and cooperative research programs between the Department
of the Interior and the Departaent of Health, Education and Wel-
fare (HEW) . *
Passage of the 1970 Occupational Safety and Health Act did
not supersede the standards established under the 1969 Act.5
^reehling, Robert J. "Health and Safety Regulations."
American Law of Mining. Vol. 3, pp. 714-716.
2Ibid.
3Federal Coal Mine Health & Safety Act of 1969. 30 CFR 70-100
''U.S., Congress, Senate, Committee on Interior and Insular
Affairs. Legislative Authority of Federal Agencies with Respect
to Fuels and Energy.Staff Analysis.Washington:Government
Printing Office. 1973. p. 11.
5U.S., Department of Labor, Occupational Safety and Health
Administration. "Occupational Safety and Health Standards."
Federal Register 37 (October 18, 1972): 22102.
-130-
-------
However, the formation of a national policy of occupational
health and safety covering all forms of employment necessitated
cooperation between BuMines in Interior and the Labor Depart-
ment's Occupational Safety and Health Administration (OSHA). By
1972, the agencies had eliminated most of the gaps in coverage,
duplications of effort, and problems at interagency cooperation,
although agreements on jurisdiction were not final.1 As was the
case with the 1969 Act, the Occupational Safety and Health Act
limited state participation to areas in which no federal standard
was in effect and required approval of state plans by the Secre-
tary. 2
The Federal Mine Safety and Health Act of 19773 combined the
standards of the Coal Mine Health and Safety Act of 1969" with
those set by the Metallic and Nonmetallic Mine Safety Act of 1966,5
and gave the Secretary of Labor, through his Assistant Secretary
for Occupational Safety and Health, overall administration through
the Mine Safety and Health Administration (MSHA). Thus, OSHA and
MSHA were in the same department, and closer coordination of pro-
grams could be accomplished.
Throughout this description, federal agencies have been
identified with specific responsibilities. These include USGS,
^.S., President. Report on Occupational Safety and Health.
Washington: Government Printing Office.1972.pp. 11-12.
2Pogson, Stephen W. "Federal Health and Safety Laws Affect-
ing Mining, Milling and Smelting Operations." Rocky Mountain
Mineral Law Institute 17 (1972): 242.
3Federal Mine Safety and Health Act of 1977, Pub. L. 95-164,
91 Stat. 1290.
"Coal Mine Health and Safety Act of 1969, 30 CRF 70-100.
5Federal Metallic and Nonmetallic Mine Safety Act of 1966,
Pub. L. 89-557, 80 Stat. 772.
-131-
-------
BuMines, and MSHA. In brief summary, their responsibilities
for mining health and safety are:
1) USGS: Supervising coal mining on federal lands
and mineral rights by the federal government on
private lands.
2) BuMines: Minimizing occupational hazards for
miners through R&D.
3) MSHA: Administering the provisions of the 1977
Federal Mine Safety and Health Act, and coordinat-
ing enforcement of the Occupational Safety and
Health Act with OSHA.
3.6.3.3. Mining Permits and Reclamation
3.6.3.3a Federal Regulation
Under provisions of the Surface Mining Control and Reclama-
tion Act of 1977,l the Office of Surface Mining (OSM) in the
Department of Interior is the regulatory agency primarily re-
sponsible for receiving mining plans and insuring that rules and
regulations established under the Act concerning land reclamation2
are enforced.
The purposes of the Act include establishing a nationwide
program to protect society and the environment from the adverse
effects of surface coal mining operations, assuring that the
rights of surface landowners are fully protected from such opera-
tions, assuring that surface mining operations are not conducted
:Public Law 95-87, 30 USC 1201 et seq., 91 Stat. 445
230 CFR Chapter VII
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where reclamation as required under the Act is not feasible, as-
suring that surface coal mining operations are so conducted as
to protect the environment, assuring that adequate procedures are
undertaken to reclaim surface areas as contemporaneously as pos-
sible with the surface coal mining operations, and other purposes
to support these and deal with related topics.1
OSM regulations include air emission and water effluent
standards for surface mining which satisfy the Clean Air Act as
amended2 and the Federal Water Pollution Control Act as amended.3
3.6.3.3b State Regulation
The Federal Surface Mining Control and Reclamation Act of
1977 (SMCRA) applies to all coal mining operations. Provisions
of the Act can be administered by state agencies, with plans ap-
proved by OSM, The states of Wyoming and North Dakota both have
approved plans. The discussion below refers to reclamation plans
established by the states prior to implementation of the SMCRA.
These plans in most states are currently being revised.
Some states require that reclamation be integrated into the
mining operation. Others require that the lands be reclaimed
.after the coal has been mined, and since about 1969, some states
have begun to specify the uses to which the land should be re-
stored. Prior to 1969, the usual standard was to require that
the land be returned to productive use.
»P.L. 95-87, Sec. 102
242 USC 1857 et seq.
333 USC 1151-1175
"U.S., Congress, Senate, Committee on Interior and Insular
Affairs. Coal Surface Mining and Reclamation: An Environmental
and Economic Assessment of Alternatives.By Council on Environ-
mental Quality, Committee Print.Washington: Government Print-
ing Office. 1973. p. 41.
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A major concern here is in reclamation of the surface and
that some surfaces do not lend themselves to an acceptable restora-
tion program. Although these are primarily aimed at the control
of coal mines, some are also directed at surface mines in
general and therefore applicable in this study to those resources
having a mining technology which calls for surface disturbance
(i.e., coal, uranium, and oil shale).
Table 3-59 summarizes the state reclamation laws by identi-
fying which surface disturbance is to be controlled, what type of
controlling mechanism is used, and the agency in charge. The
administering agencies listed in the following table are usually
given wide discretion in their approval or disapproval of the
applicant's reclamation plan and site location. Some statutes
list certain factors the agency must consider in making its deci-
sion.
Most western states have a permit procedure that requires
a reclamation plan be submitted together with evidence of a
bond. Bond requirements vary among the states, but generally the
bond is determined in relation to the amount necessary to com-
plete the reclamation plan. Some states have statutes specify-
ing the upper and lower limits of the bond. The lowest among
the states is $200.00 per acre; $10,000.00 per acre the highest.
Tables 3-60 through 3-62 summarize the open mine permits,
as discussed above, in greater detail. As can be seen from the
table, the reclamation plan is the key factor in the permit.
Although 7 of the 8 states have such permits, only three (Colorado,
Montana, and North Dakota) are shown in detail, with the idea
being to give a sample of what is generally found in the permits.
It is important to note the surface owner in North Dakota, can
refuse a strip mine on his surface.
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TABLE 3-59. SUMMARY OF STATE MINE RECLAMATION LAWS
U>
cn
I
APPLICABILITY
Surface Hlnea
Underground
General Coal Uranium Mines
AZ
CO X
XT XXX1
HD X
NX X
SD X*
UT X X
WT X X
CONTROL MECHANISMS
Type Requirements
Surface Controlling
Permit Owner Reclamation Public Ajency
Duration Approval Bond Permission Plsn Hearing
5 year* X X Department of Natural Resource*.
Land Reclamation Board
1 year XX X Department of State Lands,
State Board of Land
Commissioners
1 years XX XX Public Service Cuonlaaion
See X X Coal Surfaceulnlng Commission
Footnote 2
1 year X X State Conservation Commission
XX X Division of Oil. Cas, and
Mining, Board of Oil, C»a
and Mining
See X X Environmental Quality Council,
Footnote 2 Administration of Land Quality
'Applies to coal and uranlua only.
'Permit valid for life of operation.
'Does not apply to mines or state lands, only private lands.
-------
TABLE 3-60. COLORADO COAL OPEN MINE PERMIT
a
Item
Statutes
Summary
1. Agency
2. Requi rements
3. Fees
§ 34-32-109
I 34-32-115(4)(a)
§ 34-32-112(6)
4. Duration
5. Bond
6. Discretionary
Actions
7. Other
Requirements
8. Other
Information
§ 34-32-115
Department of Natural Resources (Land
Reclamation Board). Division of
Mined Land Reclamation.
Compliance with Colorado Mined Land
Reclamation Act of 1976 and Rules and
Regulations of Division of Mined Land
Reclamation.
$50.00 plus $15.00 per acre for first
50 acres, $10.00 per acre for second
50 acres, $5.00 per acre for third
50 acres, $1.00 per acre for addi-
tional acres up to a maximum of
$2000.
Valid for life of mine.
Surity of $2000 per acre or sufficient
to complete reclamation
Developer has five years to complete
reclamation once he starts.
Colorado Mined Land Reclamation Act of 1976 and regulations, May, 1977; this
same permit is used for any open mine.
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TABLE 3-61. MONTANA COAL STRIP AND UNDERGROUND MINING PERMIT*
Item
Statutes
Summary
1. Agency
3. Fees
4. Duration
5. Bond
6. Discretionary
Actions
7. Other
Requirements
8. Other
§ 50-1039
2. Requirements § 50-1039
§ 50-1039
§ 50-1039
§ 50-1039
§ 50-1041
Department of State lands, State Board of
Land Commissioners.
1. A reclamation plan
2. Proof of right to land
3. Bond (see #5 below)
$50.00
1 year, renewable each year.
$200.00 to $2,500.00 per acre, but mini-
mum of $2,000.00.
A prospecting permit is available also
(developer must have one or the other)
and its fee is $100.00; also requires a
reclamation plan and a bond. This permit
is good for 1 year, but again renewable.
Revised Codes of Montana, 1947 (applies to all lands in state)
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TABLE 3-62. NORTH DAKOTA COAL LEASE (STRIP MINE PERMIT)'
Item
Statutes
Summary
1. Agency
2. Requirements
3. Fees
4. Duration
5. Bond
6. Discretionary § 38-14-05.1
7. Other
Requirements
8. Other
Information
§ 38-14-03 Public Service Commission
§ -38-14-04 1. Reclamation plan with number of acres
to be consumed in three years.
§ 38-14-04 $250.00 plus $10.00 per acre for each
acre over 50.
§ 38-14-04 Three years for reclamation.
§ 38-17-05 Ten years renewable.
§ 38-14-07 $1,500.00 per acre or larger if necessary,
(developer must pay cost of reclamation
regardless of bond limit).
The commission may decline to issure per-
mit for certain lands (i.e. , lands im-
possible to reclaim).
§ 38-18-06 The surface owner's consent is required;
if he refuses, the courts will have to
decide rights of parties.
Dakota Century Code, Chapter 38-14 as amended 1975 (applies to all
lands in state)
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3.7 BENEFICIATION
Beneficiation is the process of upgrading or preparing coal
from the mine for subsequent use. The processes included in this
category of coal use technology include crushing and screening,
physical cleaning, chemical cleaning, drying, and others. After
coal has been extracted from the ground, it almost always must be
crushed prior to use or sale. This crushing is normally done at
the mine site. In addition, many processes requiring a specific
size coal may utilize crushing and screening at the process site
to ensure that the feed coal is properly sized. The technologies
and residuals associated with crushing and screening operations
at the mine or process site are included in other sections of
this report dealing with the mine or coal processes.
The beneficiation process other than crushing and screening
which is most likely to be used in the development of western
coal is physical coal cleaning. This process has been utilized
in the United States since 1880 and its technology is well
established. At present, nearly 50 percent of the annual U.S.
coal production is physically cleaned. This amounts to nearly
300 million metric tons annually from over 400 cleaning plants.1'2
The decision whether or not to utilize physical coal clean-
ing is based on many factors. Some of the more important consid-
erations are as follows: purpose of cleaning; air pollution
regulations; cost of cleaning; and alternatives to cleaning.
lLowry, H. H. ed. Chemistry of Coal Utilization, 2 vols.
and supplementary volume"New York: Wiley, 1945, 1963 (sup-
plementary volume).
2Nielsen, George F., ed. 1974 Keystone Coal Industry
Manual. New York: McGraw-Hill, Mining Publications, 1974.
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The purpose of cleaning the coal is important in that the
end use of the coal may dictate whether cleaning will be bene-
ficial. For example, if the coal is to be used as a feed for a
high-Btu coal gasification facility, cleaning will be of limited
value. This is because sulfur removal processes are included in
the design of the gasification plant and would be needed even if
clean coal were used. Coal cleaning, therefore, would introduce
an unnecessary step in the coal use scheme. If, however, the
coal is to be used as fuel for boilers in the production of elec-
tricity, physical cleaning might be desirable. This is because
S02 emissions from the power plant can be controlled either by
reducing the sulfur in the coal or by using flue gas desulfuri-
zation techniques. It must be decided, therefore, whether*desul-
furization by physical coal cleaning or flue gas cleaning should
be practiced.
An important factor in this decision is air pollution regu-
lations. That is, will the sulfur removal accomplished by phys-
ical cleaning adequately protect air quality and meet all legal
standards? This determination is primarily dependent on the
characteristics of the coal to be cleaned and the regulation in-
volved.
The type of coal is important in that, as will be discussed
in Section 3.7.1, physical cleaning can only remove pyritic sul-
fur from coal. In a low sulfur western coal where total sulfur
content may be approximately one percent, the percent pyritic
sulfur in the coal can be as low as 0.05 percent.1 The removal
of even 100 percent of the pyritic sulfur from this coal would
not significantly affect S02 emissions upon combustion. If,
however, the coal contained 0.6 percent pyritic sulfur, S02
^eilsen, George F., ed. 1977 Keystone Coal Industry
Manual. New York: McGraw-Hill Mining Publications, 1977.
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emissions could possibly be reduced by about 50 percent (assuming
80 percent removal of pyritic sulfur in the cleaning process).
This degree of cleaning, however, would most likely result in a
significantly reduced coal yield.l
Another important coal characteristic which must be consid-
ered in this regard is the size distribution of the pyritic sul-
fur particles in the coal. Smaller particles of pyritic sulfur
in the coal result in reduced cleaning efficiency.2
After the potential level of cleaning has been determined
from the coal characteristics, the affect on compliance with
regulations must be determined. For example, under the current
Federal New Source Performance Standards, a new power plant
boiler must not cause S02 emissions greater than 1.2 lb/106 Btu
heat input.3 Physical coal cleaning may not be able to meet
this requirement. In addition, under the 1977 Amendments to the
Clean Air Act1* a specific percentage reduction in emissions will
be required at new facilities. Considering that physical coal
cleaning has limited capabilities for reducing the total sulfur
percent, these future regulations will become an important con-
sideration. s
:Deurbrouck, A. W. Sulfur Reduction Potential of the Coals
of the United States. Report of Investigations 7633. ' Pittsburgh,
TaT:Pittsburgh Energy Research Center, 1972. Washington,
Bureau of Mines, Dept. of Interior.
2McCartney, J. T., H. J. O'Donnell, and Sabri Ergun. Pyrite
Size Distribution and Coal-Pyritic Particle Association in Steam
Coals.Correlation with Fyrite Removal by float-Sink Methods?
O. 7231.—Washington: Bureau of Mines/1969.
340 CFR Part 60
H2 U.S.C. , 1857 et seq.
5It is not the intent of this section to list all applicable
regulations or suggest any compliance scheme or philosophy. In-
stead, the section is to merely point out that regulations must
be considered.
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The third general consideration, cost of cleaning, is
important for two reasons. First, as is discussed further in
Section 3.7.1, the higher the percent sulfur removal, the
lower the overall yield. That is, operating the cleaning facility
to effect a higher sulfur removal will cause high coal losses.
If, for example, the desired sulfur level can only be achieved
with a 50 percent coal loss, the cost might be prohibitive. The
second cost analysis involves a determination of the savings by
the end user relative to the cost of cleaning. If flue gas
desulfurization is less expensive than cleaning or would be
required even if cleaning was used, the cost of cleaning might
exceed the benefit.
The fourth consideration, alternatives, must be considered
in light of the factors discussed above. Since there are several
methods to accomplish the desired end result of reduced S02
emissions, each alternative must be considered in light of the
specific circumstances and conditions at the proposed facility.
These available alternatives include flue gas desulfurization,
alternative fuels, alternative combustion techniques, synthetic
fuel production, chemical cleaning and others.
As can be seen from the above discussion, the decision
whether or not to utilize physical coal cleaning is dependent on
many considerations. These considerations change from one site
to another and even with time as economics and regulations
change. It is, therefore, impossible to make a generalized
decision as to the use of physical coal cleaning with western
coal. Instead, the following sections present a description of
a typical physical coal cleaning plant and a quantification of
residuals associated with the process.
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3.7.1 Technologies
Physical coal cleaning removes impurities, such as pyrite
(FeS2), ash, and rock, from coal by a mechanical separation pro-
cess based on a gravity difference between coal (which is rela-
tively light) and contaminants (which are heavier). * One of
the primary advantages of coal cleaning is that is removes much
of the sulfur from coal, thereby reducing or eliminating the
need for a flue gas desulfurization system at a coal-fired fac-
ility.
Sulfur occurs in raw coal in three forms: pyritic, organic
and sulfate. The quantity of sulfates is almost always neglig-
ible. The organic sulfur compounds are chemically bound in the
coal, but the pyritic sulfur, although sometimes widely dispersed
throughout the coal, is separate from the coal itself. Physical
coal cleaning is limited to the removal of the pyritic sulfur
which accounts for between 5 and 60 percent of the sulfur in the
coal.
The exact processes and equipment which can be used for
physical coal cleaning vary widely. Although it is not possible
to describe a universally applicable coal cleaning process,
within most plants there are generalized processing areas which
can be identified. These include initial coal preparation, fine
coal processing, coarse coal processing and water management, and
final coal preparation. Figure 3-20 shows a generalized flow
diagram for this type of plant.
*Paul Weir Company, Inc. An Economic Feasibility Study
of Coal Desulfurization, Volume~T! Chicago, 111. : October,
~~
-143-
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ROM COAL
STORAGE
Ml 1*1
Of
1IATF.D
J-LANT
CAPACITY
'
ROUOH
CLEAMNO
r
REMOVAL
if
PrtMAfiY
nn£AKwa
1AW
SIZ
COAL OVEnSUE
INQ
_ j
UNOEnSIZE
nvEnrj7P
MAKE-UP WATER
(D
0 imriAL COAL REPARATION
@ fee COAL pnoctostNQ
Q .COAUSt COAL PnOCESS»4Q
0 WAItll MAHACEMCNT AND
lltlAL COAL PREPARATION
rnoctsn AIIEAS
nec«cuLATwo PLANT WATER
®
r
I
)H
COADSE COAL
CLEAMTM
flEJtCT STREAMS
I. COAL sLunrtr
FLOWS
COAL FLOWS
FIME COALJ CLEANING
DflY t WET
PROCESS I PROCESS
I
t
Figure 3-20. Generalized Coal Cleaning Process.
-------
3.7.la Initial Preparation
The first operation in coal cleaning, initial preparation,
involves crushing and screening of the raw coal. The coal is
first subjected to primary crushing to release large particles
of impurities such as clay, rock and pyrite. This crushed coal
is then screened and the larger portions are sometimes recrushed.
After all crushing, the coal is screened to produce a coarse
coal fraction and a fine coal fraction which are fed to separate
cleaning processes.
The final coal processing area of a cleaning plant can em-
ploy both wet and dry cleaning operations. In plants using a
dry coal cleaning process, fine coal from the initial prepara-
tion step flows to a feed hopper and then to an air cleaning op-
eration. This cleaning operation can employ one of several de-
vices which rely on an upward current of air traveling through a
fluidized bed of crushed coal to effect separation by particle
size and density. The lighter coal particles are carried out
the top of the fluidized bed in the air stream and the heavier
sulfur and ash particles are taken out the bottom. Product coal
streams from a dry cleaning process are sent directly to the final
coal preparation step while reject ash and pyrite streams are
usually processed further in wet cleaning operations.1
3.7.1b Fine Coal Processing
Traditionally, fine coal processing operations employ wet
cleaning equipment since the design and operation of wet cleaning
devices is a more established technology.2 However, the limited
1"Fine-Coal Treatment and Water Handling/1 Coal Age 66
(12), 67 (1961).
2Leonard, Joseph W. and David R. Mitchell, eds. Coal Prep-
aration. 3rd edition. New York: The American Institute of""
Mining, Metallurgica., and Petroleum Engineers, Inc., 1968.
-145-
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availability of water in the west has discouraged the use of wet
cleaning processes. At present, there are many wet cleaning de-
signs used for fine coal cleaning. These include: jigs, heavy-
medium cyclones, water tables, spiral classifiers, hydrocyclones,
froth floatation, and numerous variations on these basic designs.
The underlying principal in all these designs is gravity separa-
tion. The specific gravity of coal is approximately 1.27 while
the specific gravity of most impurities ranges from 2.0 to 5.0.
The cleaning process effects a separation by first creating a
slurry with water and the crushed coal. The coal and impurities
are then separated, utilizing the differences in specific gravity
between the coal and the impurities. This separation can either
be effectuated by pulsating the water through the solids causing
the heavier materials to settle to the bottom (jigs and water
tables) or by utilizing centrifugal force as in a cyclone to
separate out the heavier materials (heavy-medium cyclones, hy-
drocyclones, and spiral classifiers).
A third mechanism used in separation is froth floatation.
In this process ultrafine coal particles are separated from the
remaining solids by causing them to rise to the top of the water/
coal slurry in a froth. This is accomplished by treating the
coal with a frothing agent (usually an alcohol) which renders
the coal air adsorbent and water repellant but does not affect
the impurities. This slurry is then subjected to vigorous agi-
tation and aeration causing the coal to attract air bubbles and
float to the top where it is withdrawn.
3.7.1c Coarse Coal Processing
In coal cleaning practice, coarse coal is processed inde-
pendently of the fines. In many cases, the equipment used to
process coarse material is identical to that used for fines,
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although operating parameters vary. Advantages of separating
the fine from the coarse cleaning operations include improved
removal of pyrite and ash impurities, higher plant yield, and
higher cleaning equipment throughput.
Feed to the coarse coal processing area of the plant con-
sists of oversize material (76 x 6.5 mm particles) from the
initial preparation area. This feed stream is slurried with
water prior to cleaning since coarse coal cleaning operations
generally employ wet processing equipment to remove impurities
from the coal. The coarse coal slurry is fed to one of the
many types of process equipment currently employed in coarse
coal cleaning. Here, impurities are separated from the coal
by differences in their densities. It is also common practice
to remove a middling fraction from the separation operation and
process it further by means of recycle or by feed to another
cleaning process. Two streams are removed from the coarse coal
processing area: a product coal stream and reject stream.
In actual practice, there are usually several types of
coarse coal cleaning devices used in a single plant. These in-
clude jigs, tables, heavy media separation equipment, launders,
and hydrocyclones. Typically, sizing of coarse coal may be used
to isolate feed streams for individual cleaning operations, or
the reject from one type of cleaning device may serve as the
feed to another. Jigs are the most common cleaning devices em-
ployed by the industry. In many instances they represent the
only type of cleaning device operation in a cleaning plant.
The jigs used for coarse cleaning are nearly identical to those
used for fines cleaning. As was described previously, jigs ef-
fect coal cleaning by the use of pulsating water in a bed of raw
coal. The lighter coal particles move to the top of the bed
while the heavier impurities move to the bottom.
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Another cleaning mechanism which is coming into widespread
use is heavy media separation. Heavy media separation employs
a suspension of magnetite and water to produce a liquid with a
specific gravity in the range 1.3 to 1.6. There are numerous
types of heavy-medium devices, all of which operate by floating
the clean coal (specific gravity of 1.27) in the heavy media and
sinking the impurities (specific gravity of 1.3 to 5.0). This
method of coal cleaning is the best suited to optimizing sulfur
reduction in coal cleaning practice.1'2'3
The third type of coarse coal cleaning equipment used is
the table. Water tables are commonly employed to process coarse
material in a coal cleaning plant, although air tables are some-
times used. The principals of table operation are identical to
that discussed previously for fines cleaning. Operating exper-
ience with tables handling unclassified material has proven that
tables are highly efficient in making separations at specific
gravities higher than 1.50. However, at lower specific gravities,
which are desirable for attaining maximum sulfur reduction, table
efficiency decreases. Therefore, if maximum sulfur reduction in
desired, it is necessary to reprocess the product and reject
streams from table operations in some other type of cleaning
equipment. **
1Battelle-Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. EPA
Contract No. 68-01-0470.Columbus, Ohio:1973.
2Terchick, A. A. "Sulphur Reduction Through Improved Coal
Washing Practices," Mining Congress Journal 57(7). 48-55 (1971).
3Hudy, J., Jr. Performance Characteristics of Coal-Washing
Equipment, Dense-Medium uoarse-Goal Vessels. RTTT/ii4. Bureau
ot Mines, 1968.
**Terchick, A. A., op. ait.
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Another type of process used to clean coarse coal is a
launderer. They are simple to install and operate, although
they do not effect as clean a separation between coal and its
impurities as do most other devices. Launderers employ a flowing
current of water in a channel to separate coal and refuse. A
fluidized bed is formed in the channel with the coal stratifying
according to density: the lighter particles at the top of the
bed and the heavier particles on the bottom. Refuse is removed
from a port in the bottom of the channel while the product
flows to the dewatering and drying area of the plant.
The hydrocyclone is often used to clean very coarse coal.
As was discussed earlier, a hydrocyclone cleans the coal through
the use of centrifugal force. Although hydrocyclones are employed
in both coarse and fine processing, the former is a more limited
application. Hydrocyclone processing of coarse coal does not
produce an acceptable clean coal product. A significant quantity
of impurities still contaminates the product stream from a hydro-
cyclone and a large fraction of the uncontaminated coal is re-
moved with the ash and pyrite reject.
3.7.Id Coal Dewatering and Drying
After the raw coal has been crushed and cleaned by the wet
cleaning methods described above, the clean coal product must be
dewatered and dried. Dewatering and drying equipment are used on
the product flows from both the fine and coarse coal preparation
areas. Typically, cleaning plants employ mechanical dewatering
operations to separate coal slurries into a low-moisture solid
and a clarified liquid. The solid coal sludge produced in the
dewatering step can then be mechanically or thermally dried to
further reduce the wet cleaning operations in the plant. Common-
ly, fine clean coal is not processed in the same dewatering/dry-
ing equipment as the coarse product.
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Dewatering equipment may consist of one or more of the
following: dewatering screens, thickeners, and cyclones. In
dewatering service, screens are used primarily for fine proces-
sing, while thickeners and centrifuges process both coarse and
fine coal.1 It should be noted that coal cleaned by the dry
processes, such as air tables, does not require dewatering.
The drying operation is usually the final processing step
in treating the cleaned coal product. Drying operations may
employ equipment such as filters, centrifuges and thermal dryers
The former are mechanical devices which do not completely dry
the coal (3 to 6 percent remaining moisture) while the latter
uses combustion air to remove 97 to 100 percent of the moisture.
Drying is practiced for one or more of the following reasons:
(1) to avoid freezing difficulties and to facilitate handling
during shipment, storage, and transfer to the points of use;
(2) to maintain high pulverizer efficiency; (3) to increase
the heating value of the coal; and (4) to decrease transporta-
tion costs.
Centrifuges are mechanical devices which use strong centri-
fugal force to dry fine coal products from primary dewatering
units. Coal slurry is fed to the centrifuge where it is sub-
jected to the high acceleration and centrifugal force of a rap-
idly spinning conical basket. Water flows out of minute perfor-
ations in the basket while the coal slides from the apex to the
base and is removed as a dewatered cake.2'3
*Reid, George W. and Leale E. Streebin. Evaluation of
Waste Waters from Petroleum and Coal Processing~iPB 214 610.
££'1.23/2:72.001.University of Oklahoma, School of Civil En-
gineering & Environmental Science, 1972.
2 Ibid.
3Leonard, Joseph W. and David R. Mitchell, eds. Coal
Preparation, 3rd edition. New York: The American Institute of
Mining, Metallurgica., and Petroleum Engineers, Inc., 1968.
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Filters take a suspension with a high percentage of solids
and separate the water to produce a compact wet cake of coal
solids. This process is performed by placing a filter with a
cloth or screen surface in the suspension. The filter has a suc-
tion behind the surface so that water and solids are drawn into
the filter. The solids are trapped on the surface: the water
is drawn through the filter and separated from the solids. The
solids trapped on the filtering surface are removed from the
suspension as a cake and air is drawn through them into the
filter to remove as much of the surface moisture as possible.
To complete the continuous cycle the air pressure in the filter
is increased to greater than atmospheric. The solids are blown
from the surface of the filter and removed.*
The thermal dryers used in coal cleaning plants are contin-
uous direct contact dryers which employ convection as the major
principal of heat transfer. In direct contact dryers, hot com-
bustion gases and wet coal are brought into intimate contact
with each other on a continuous gas flow/coal feed basis. The
hot gases are generated in a combustion chamber and fed to the
drying chamber via a fan or blower. Typically, there are par-
ticulate emissions associated with thermal dryers because fine
coal is entrained in the hot drying gases. They usually neces-
sitate addition of a particulate control device.2 Also, some
sulfur oxides, nitrogen oxides, and hydrocarbons will be present
in the combustion gases.
rReid, George W. and Leale E. Streebin. Evaluation of
Waste Waters from Petroleum and Coal Processing"! PB 214 610.
EP1.23/2:72.001.University of Oklahoma, School of Civil En-
gineering & Environmental Science, 1972.
2 Ibid.
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3.7.le Water Management
The final processing area in the coal cleaning plant is
the water management area which separates plant water from the
refuse. This area is needed due to the large amounts of recir-
culating water used in the wet cleaning processes. Equipment
employed to dewater the refuse includes dewatering screens and
*
thickeners. Efficient water management is essential for mini-
mizing the quantity of makeup water that must be added to the
circulating plant water. Close quality control on the quantity
of suspended solids is also needed to promote efficient opera-
tion of the cleaning plant.
The solids product from the refuse dewatering is dried,
commonly by filtration, and discarded in refuse piles. The
water from these operations is pumped to settling ponds to
remove finely suspended solids. This operation often requires
the addition of flocculating.agents to accelerate and enhance
settling.
As can be seen from the above discussion, the primary
difference between physical coal cleaning plants is the equip-
ment used for the cleaning. The purpose and principles of
operation of most of the alternatives are very similar. Table
3-63 shows the operating parameters of these various alterna-
tives. The major differences in residuals produced by these
facilities will be caused by the choice of whether to use the
dry process or the wet process and whether or not to use ther-
mal dryers.
For the subsequent analysis, it is assumed that wet clean-
ing and centrifugal dryers are used. Thermal dryers are not
used since the major considerations involved (transportation
-152-
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TABLE 3-63. COAL CLEANING EQUIPMENT OPERATING PARAMETERS
Type of
Cleaner
Separating Feed Size Capacity Relative Cleaning
Gravity Range (Metric tons per hour) Costs
Oi
u>
Airflow Cleaner*
Air Tables*
Centrifugal/Electrostatic
Separator
Jigs*
Heavy-Medium Cyclones*
Water Tables*
Hydrocyclones*
Spiral Classifiers*
Froth Flotation*
Heavy-Medium Separators
Launders
1.5 to 1.6
1.5 to 1.6
Not available
1.5 to 1.6
1.3 to 1.6
1.5 to 1.6
1.4 to 1.6
1.5 to 1.6
Not available
1.3 to 1.6
1.5 to 1.6
6.3 mm to 14 mesh
6.3 mm to 40 mesh
60 to 400
150 mm to 40 mesh
38 mm to 35 mesh
38 mm to 48 mesh
6.3 mm to 0
10 to 200 mesh
28 to 325 mesh
150 mm to 35 mesh
150 mm to 60 mesh
15 to 320
10 to 14
Not available
5 to 640
45 to 70
10 to 14
4 to 62
.5 to 2.0
2.5 to 15
10 to 820
26 to 115
Medium
Medium
Not available
Low
High
Low/medium
Low
Low/medium
High
Medium
Low
^Requires close-sized feed. Actual range depends on coal and operating conditions.
-------
costs and process operations) do not mandate their use. That
is, the coal use facilities considered subsequently are mine
mouth operations and there would be little if any improved
overall efficienty associated with thermal drying.
However, the coal conversion facilities discussed in Sectio
Section 3.8 may require dried coal but the drying is included
in the process designs. In addition, in some of the northern
states thermal drying may help prevent freezing of the coal
while in storage or transport during colder periods.
3.7.2 Input Requirements
The beneficiation plant which was chosen for quantification
of input requirements for physical coal cleaning was based on
the capacity required to clean the coal from a 12 MMTPY mine.
The coal which is mined is assumed to have a heating value of
8600 Btu/lb. This is a typical value for western subbituminous
coal. For example, the coal mined at both Farmington, New Mexico,
and Colstrip, Montana, has this heating value. It is also assumed
that the beneficiation plant uses the wet process to physically
clean the coal and has an overall yield of 75% and a heat
recovery of 90%. That is, 25% of the input coal is lost as
impurities and 10% of the heating value is lost as residual coal
in the impurities. The actual yield in facilities currently
operating ranges from 65 to 90%.:
The coal rates and heating values on this basis are shown
in Table 3-64. It should also be noted that this coal cleaning
rate would provide approximately enough coal to operate a 3000
MW generation facility operating at a 34% efficiency and a load
factor of 0.7.
Hoffman, L., et al. The Physical Desulfurization of Coal.
Major Considerations of SO2~Emission Control*.McLean7 Virginia:
Mitre Corp., 1970.Pb 210 273.
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TABLE 3-64. COAL RATES - PHYSICAL COAL CLEANING
Plant Rate Heating Value Heat Rate
Input Coal (R.O.M.) 12,000,000 TPY 8,600 Btu/lb 23.7 x 10* Btu/hr
Cleaned Coal (Output) 9,000,000 TPY 10,300 Btu/lb 21.4 x 10* Btu/hr
3.7.2a Manpower Requirements
Manpower estimates for this coal cleaning facility were
developed on the basis of a detailed analysis of a coal utiliza-
tion complex which included a physical coal cleaning plant cap-
able of producing 10 million TPY of clean coal from 13 million
TPY of R.O.M. coal.1 To estimate the manpower required for con-
struction of a beneficiation plant, it is assumed that the ratio
between capital costs of a beneficiation plant and capital costs
of a surface mine will be the same as the ratio of beneficiation
plant construction personnel to mine plant construction person-
nel. The capital costs ratio is approximately 1:3.2 Therefore,
scaling down Table 3-27 (Section 3.6.1.2a) by a factor of 3, the
following construction schedule is assumed:
Total Workers Ye?* 1 Yef^ 2 Yea* 3 Year 4 Year 5
lotai wortcers
Manpower requirements for operating the coal cleaning
facility have been estimated by Ralph M. Parsons to be 22 people.
These requirements are itemized in Table 3-65.
1Ralph M. Parsons Co. Commercial Complex Conceptual Design/
Economic Analysis, Oil and Power by COED Based Coal Conversion"
fasadena, Calif.:Ralph M. Parsons Co., 1975.~
2It is assumed in this analysis that the design of the
25,000 TPD physical coal cleaning plant is the same as the design
of the 27,450 TPD plant as reported in: Ralph M. Parsons Co.,
op. ait.
-155-
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TABLE 3-65. COAL PREPARATION OPERATING AND
MAINTENANCE LABOR
Number of Employees
Category Per Shift Total
Operating Labor
• Operator 1 4
• Helper 2 8
TOTAL 3 12
Maintenance Labor 10
Source: Ralph M. Parsons Co. Commercial Complex Conceptual
Design/Economic Analysis, Oil and Power by COED Based
Coal ConyersiojrPasadena, Calif.:Ralph M. Parsons
Co., 1975.
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3.7.2b Materials and Equipment
Table 3-66 lists the major pieces of equipment required
for a 9 million TPY beneficiation plant.1 These estimates are
based on a detailed conceptual design of a commercial coal con-
version complex.
3.7.2c Economics
Table 3-67 lists the estimated capital costs for the 9
million TPY coal cleaning plant.2 These capital costs include
the capital costs, start-up costs, financing and working capi-
tal. Depreciable capital costs total 35 million dollars and an
additional 2 million dollars is required for working capital.
Operating costs have also be estimated by Ralph M. Parsons to
be 2.8 million dollars per year (Table 3-68). These estimates
are in 1974 dollars.
3.7.2d Water Requirements
The coal cleaning plant considered here operates with total
recirculation of the process water. That is, the water used to
wash the coal is reused instead of discharging it from the pro-
cess. The major source of water leaving the wet cleaning pro-
cess considered here is a blowdown which must be removed and re-
placed with clean water to keep the recirculating water below
15 to 20 percent total solids.3 This blowdown is sent to settling
llt is assumed in this analysis that the design of the 9
million TPY physical coal cleaning plant is the same as the de-
sign of the 27,450 TPD plant as reported in: Ralph M. Parsons
Co. , op. ai-t,
2 Ibid.
3Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio: BatteHe-Columbus Laboratories, 19/37
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TABLE 3-66. MAJOR EQUIPMENT SUMMARY - 9 MILLION
TPY COAL BENEFICIATTON PLANT
Number Items
3
4
3
2
2
2
1
1
2
1
1
1
12
2
2
1
1
12
1
1
6
Description
Pumps
Waste Dewatering Screen Undersize Pumps
Clean Coal Fines Pumps
Cyclone Feed Pumps
Tailings Pumps
Recycle Water Pumps
Gland Water Pumps
Other Major Equipment
Recycle Water Tank
Head Tank
Reciprocating Plate Feeders
54" ROM Coal Conveyor
54" Coal Conveyor
54" Rev Conveyor
Vibrating Feeders
36" Jig Feed Conveyors
Middling Recycle Conveyors
Clean Coal Conveyor No. 1
Clean Coal Conveyor No. 2
Vibrating Feeders
Clean Coal Collecting Conveyor
Clean Coal Tripper Conveyor
Belt Feeders
Size
300 gpm ea
15 ft TDK
4,000 gpm ea
100 ft TDH
2,200 gpm ea
55 ft TDH
200 gpm ea
50 ft TDH
5,000 gpm ea
150 ft TDH
50 gpm ea
150 ft TDH
200,000 gal
100,000 gal
750 TPH
1,500 TPH
1,300 TPH
1,300 TPH
200 TPH ea
600 TPH ea
14 TPH ea
800 TPH
800 TPH
135 TPH ea
800 TPH
800 TPH
135 TPH ea
(continued)
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TABLE 3-66. (Continued)
Number Items
Description
Size
2
1
1
1
3
1
1
2
6
1
4
2
1
1
2
2
1
1
4
2
2
16
4
4
24
4
1
Other Major Equipment (Continued)
Drying and Classification Feed Belt
Conveyor
Waste Conveyors
Waste Conveyor
Waste Conveyor
Centrifuge Cake Conveyor
Belt Feeders
Transfer Belt Conveyor to Stockpile
Transfer Belt Conveyor from Stockpile
2-Stage, 4 Roll Crushers
Coal Crushers
10' x 20' Rotary Coal Breaker
Centrifuges
Baum Type Coal Jigs
75' Dia Thickener
ROM Hopper
Unwashed Coal Silos
Clean Coal Silos
Clean Coal Crusher Feed Bin
8' x 16' Scalping Screen
8' x 16' DD Clean Coal Screens
4' x 6' DD Middling Screens
Waste Dewataring Screens
14" Dia Cyclones
6' Stationary Cross-Flow Screens
7' x 16' Single Deck Screens
12' Dia Cyclones.
3' Stationary Cross-Flow Screens
Belt Scale
2,500 TPH
45 TPH ea
90 TPH
150 TPH
310 TPH
105 TPH ea
1,300 TPH
1,300 TPH
7 TPH ea
800 TPH ea
1,500 TPH
500 gpm ea
180 f2, 600 TPH ea
5,000 gpm
300 tons
10,000 tons ea
10,000 tons ea
1,500 tons
1,300 TPH
300 TPH ea
11 TPH ea
45 TPH ea
15,000 gpm total
100 TPH ea
80 TPH ea
4,300 gpm total
3 TPH ea
2,000 TPH
(Continued)
-159-
-------
TABLE 3-66. (Continued)
Number Items Description Size
Other Major Equipment (Continued)
1 Tramp Iron Magnet 54" wide
2 Tramp Metal Detectors
2 Belt Scales 750 TPH ea
2 Automatic Belt Samplers
1 Weight Scale 1,000 TPH
1 . Rail Mounted Stacker/Reclaimer 2,250 TPH Stacking
2 Diesel Engine Bulldozer Heavy Duty
Source: Ralph M. Parsons Co. Commercial Complex Conceptual Design/Economic
Analysis. Oil and Power by COED Based Coal Conversion. Pasadena,
Calif.: Ralph M. Parsons Co., 1975.
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TABLE 3-67. CAPITAL COSTS - 9 MILLION TPY
COAL BENEFICIATION PLANT
Item Cost3 ($ million)
Fixed Capital Investment 29.00
Start-up Costs 2.00
Construction Financing0 3.75
Depreciable Investment 34.75
Working Capital 1.75
Plant Operation Life 20 yr
Useful Life for Depreciation 11 yr
Depreciation Method DDB
aFirst Quarter 1974 dollars.
Includes home office engineering and sales tax.
Applicable to cases usin_ j 657» debt at 970 interest and
0.75% committment fee "only.
Double declining balance.
Source: Ralph M. Parsons Co. Commercial Complex Conceptual
Design/Economic Analysis, Oil and Power by COED Based
Coal Conversio'n"! Pasadena, Calif. : Ralph M. Parsons
Co., 1975.
-161-
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TABLE 3-68. ANNUAL OPERATING COSTS - 9 MILLION TPY
COAL BENEFICIATION PLANT
T Costa
Item ($ Million)
Materials and Supplies
Operating Supplies 0.145
Maintenance Materials and Contract Labor 1.110
Total Materials and Supplies 1.225
Labor
Operating Labor and Supervision 0.137
Maintenance Labor and Supervision 0.250
Plant Overhead 0.099
Payroll Burden 0.172
Total Labor Costs 0.658
G and A Overhead
Taxes and Insurance 0.870
Total Operating Costs 2.825
aFirst Quarter 1974 dollars.
Source: Ralph M. Parsons Co. Commercial Complex Conceptual
Design/Economic Analysis. Oil and Power by COED Based
Coal Conversion"Pasadena, Calif.:Ralph M. Parsons
Co., 1975.
-162-
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ponds where it is treated to facilitate solids settling. The
clear supernatant from these settling ponds is used as a makeup
water to replace part of the blowdown.
The only water actually lost to the process is that which
leaves the plant with the clean coal or evaporates from the pro-
cess. This water must be replaced with a makeup water. This
water consumption is approximately 3.3% of total plant water or
50 to 70 gallons per ton of coal processed. The makeup water
required to clean the 9 million TPY of R.O.M. coal, therefore,
is approximately 1400 gpm.
3.7.2e Land Requirements
The land requirements for a physical coal cleaning facility
of the size considered here have been estimated to be between
40 and 90 acres.1 The larger acreages are required if extensive
lagooning or ponding is undertaken. Since the plant considered
here is assumed to utilize complete water recycle with extensive
use of settling ponds, the maximum acreage of 90 acres was assumed.
3.7.2f Ancillary Energy
Coal cleaning operations employ various mechanical devices
in the processing steps. These include crushers, pumps, compres-
sors, dryers, and other equipment, all of which have ancillary
energy requirements. These have been estimated to be 5.1 x 101*
Btu/ton of coal cleaned2 or approximately 1.7 x 109 Btu/day for
a facility which produces 9 million TPY of cleaned coal.
Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus Laboratories, 19737
2Hittman Associates, Inc. Environmental Impacts.Efficiency,
and Cost of Energy Supplied by Emerging Technologies, Draft Report
HIT-573. Columbia, Md.: 1974.
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The primary source of this energy is electricity which is
either generated at the plant or purchased. It is assumed for
this analysis that the plant does not include facilities for
electric generation.
3.7.3 Outputs
The physical coal cleaning facility used to quantify outputs
is the same facility described previously for quantification of
inputs in Section 3.7.2. As was discussed previously, this fa-
cility uses the wet process to produce 9 million TPY of clean
coal from 12 million TPY of R.O.M. coal. In addition, the fa-
cility considered does not utilize thermal drying of the coal.
3.7.3a Air Emissions
The three potential sources of air emissions at any physical
coal cleaning facility are: particulate coal dust from process
operations; particulate emissions and combustion products from
thermal drying; and combustion products from burning coal refuse
piles.
Process emissions are generated by coal preparation steps
such as crushing or breaking and by cleaning steps such as air
tabling as used in the dry cleaning process. The crushing op-
erations at the facility considered here are enclosed and use
modern control technoloiges to minimize emissions of particulates
Based on EPA emission factors, emissions from controlled coal
crushing are as low as 0.005 Ibs/tons of coal. For a 12 million
TPY coal crushing operation, the particulate emission rate is
approximately 7 Ibs/hr.1 In addition, since the process
^.S. Environmental Protection Agency. Compi1ation of
Air Pollutant Emission Factors. EPA Publication AP-42, Research
Triangle Park, N.C.:U.S. Government Printing Office. 1977.
p. 3.2.7.
-164-
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considered here does not use the dry cleaning process, there are
no process emissions.
The second category of emissions from physical coal cleaning
facilities, thermal drying, is not a factor at the facility con-
sidered here since all drying is done by methods other than ther-
mal dryers. (See Section 3.7.1) It may, however, be necessary
to use this type of drying if freezing of the coal becomes a
problem at some of the colder sites. For this reason, Table 3-69
was included to indicate the level of air emissions which would
be generated by the use of a thermal dryer at a 9 million TPY
coal cleaning plant.
TABLE 3-69, AIR EMISSIONS FROM THERMAL DRYERS
AT A 9 MILLION TPY COAL CLEANING PLANT
Uncontrolled Emissions Controlled Emissions
Contaminant Potential (Ib/hr) (Ib/hr)
SOX 260 4.31
N0x 130 130
Particulates 21,000 210
2
'85% SOV Control
X
299.9% Particulate Control
Source: Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth.
Contract No. 68-01-0470.Columbus, Ohio:1973."
Coal preparation plants also produce refuse piles consisting
mainly of sulfur-rich coal. Improper disposal of the refuse pile
may initiate low-temperature oxidation of the coal with an accom-
panying increase in temperature within the pile. Ultimately,
this can result in the ignition of the refuse pile, from which
significant quantities of combustion gases can be emitted. This
can be prevented by recovering the area with soil and revegetating
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the area during reclamation.1 The air emissions from the 9
million TPY coal cleaning facility, therefore, are assumed to
consist of only 7 Ib/hr of particulates.
3.7.3b Water Effluents
Water effluent contaminants from the coal beneficiation
process consist of suspended solids, which are chiefly fine clay
and coal, and dissolved solids, which may contain iron, aluminum,
calcium, magnesium, sodium, and potassium. Water effluents may
also contain surface-active organic compounds such as alcohols
or kerosene, which are added in some coal cleaning plants to
enhance frothability in the process. Water contaminants in
refuse pile runoff are sulfuric acid, sulfates, manganese, and
iron. However, in a modern plant, all liquid waste streams are
routed to holding ponds to allow settling of the suspended solids
The clear supernatant liquid is then recycled to the process.
In addition, contamination of ground and surface waters by per-
colation of effluent from the settling pond should be minimal
with a properly designed and maintained lined settling pond.2
Water effluents from this coal cleaning plant, therefore, are
essentially negligible.
3.7.3c Solid Wastes
Solid wastes from the physical coal cleaning facility are
generated by removal of impurities from the R.O.M. coal. These
impurities plus any retained coal become solid waste after being
Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Contract
No. 68-01-0470.Columbus, Ohio:1973.
zlbid. See also Gavande, S. A., "Survey of Technological
and Environmental Aspects of Wet Residual Disposal in Evapora-
tive Holding Ponds," Radian Corporation, 1978.
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removed from the process streams by screening and/or settling .
The quantity of these solid wastes depends primarily on the
characteristics of the input coal and the specifications which
the output clean coal must meet. As was discussed previously,
the plant yield as determined by the above factors can range
from 60 to 90 percent. The solid waste production, therefore,
ranges from 10 to 40 percent of the input coal. The quantity
of solid waste generated by the 9 million TPY facility operating
at 75% yield considered here is 8000 TPD. Since the mine is
available for back-filling at the mine-mouth operation consid-
ered here and proper piling and reclamation are assumed to be
practiced, and there should be no problem with solid waste dis-
posal.
3.7.3.d Noise Pollution
Physical coal cleaning facilities use machinery for the
physical handling and processing of coal. One substantial by-
product of solids handling is noise. Worker exposure to noise
varies, but typical in-plant noise levels exceed 90 dbA when
uncontrolled.1 However, since the Coal Mine Health and Safety
Act of 1969 requires that no unprotected worker may be exposed
to noise levels greater than 90 dbA continuously for an 8-hour
shift, it is assumed that noise levels within the plant will be
controlled along with provision for worker protection.
To provide adequate in-plant worker hearing protection,
the plant design and operation will have to include provisions
for noise control on mactiinery and provisions for protective
devices for employees. The actual mix of machinery and protection
Patterson, W. N., E. E. Ungar and G. F. Fox, "Noise Control
in Coal Cleaning Plants", in Noise Control Proceedings: Bureau
of Mines Technology Transfer Seminar, Pittsburgh, PaT, January 22,
1975. U.S. Bureau of Mines, 1975, pp. 86-96.
-167-
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cannot be specified since it would vary with design choices.
If more noise control equipment is used, abnormal operations
can be more easily detected and the danger of permanent hear-
ing damage is lessened. The sources of the in-plant noise and
typical control methods are shown in Table 3-70.
The noise levels which will be present at and beyond the
cleaning facility property boundary are not presently defined.
However, assuming maximum use of in-plant noise control methods
this form of pollution is not expected to constitute a problem.
3.7.3e Occupational Health and Safety
Data on injuries, deaths and man-days lost for a beneficiation
plant are applied directly from Battelle's data to the 9 million
TPY facility as described earlier. This analysis indicates that
0.56 deaths and 11 injuries will occur annually, and 4900 man-
days will be lost each year.1
SUMMARY
Table 3-71 presents a summary of the direct impacts associated
with a 9 million TPY coal beneficiation plant.
3.7.4 Social Controls
Western coals are typically crushed, sized, and stored prior
to being used at the mine site or being shipped to processing/
conversion facilities. Depending on coal type and/or method of
transport, the coal may also be cleaned and dried. Appropriate
^attelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Contract
No. 68-01-0470.Columbus, Ohio:1973.
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TABLE 3-70
SOURCES OF NOISE AT A PHYSICAL
COAL CLEANING PLANT
Equipment
(reciprocating)
Picking table
(reciprocating)
Crushers
Refuse screens
(shaker drive)
Clean coal screens
(shaker drive)
Centrifugal dryers
Disk filters
Vacuum pumps
Roots blowers
Conveyors (flighted)
Conveyors (belt)
Conveyor drive
Chutes
Diester tables
Vibrating feeder
Fans
Typical Noise
Level, dbA
98
100
100
95
95
85
95
95
90
80
95
90
85
90
95
Noise Control Method
Baum jigs
Do
Rotary dump
Scalping screens
100
95
85
98
Mufflers (10)
Damp sides
None
Rubber lining
Damping and partial
enclosure
Enclosures
Rubber lining enclose
drive
Rubber lining enclose
drives
Enclosures
None
Mufflers, lagging
Mufflers, enclosures
Damp trough, blades
None
Enclosures
Ledges, lining, damp
None
Partial enclosures
Muffler
Source: Patterson, W. N., E. E. Ungar and G. Fox. "Noise Control in Coal
Cleaning Plants", in Noise Control Proceedings: Bureau of Mines
Technology Transfer Seminar, Pittsburgh, Pa., January 22, 1975.
U.S. Bureau of Mines, 1975, pp. 86-96.
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TABLE 3-71.
SUMMARY OF IMPACTS ASSOCIATED WITH A
9 MILLION TPY COAL BENEFICIATION PLANT
Inputs
Manpower
construction
operating
Materials and Equipment
Economics
capital cost
operating cost
Water
Land
Ancillary Energy
258 man-year
22 men
Table 3-66
$36.5 million
$ 2.8 million/yr
1400 gpm
90 acres
1.7 x 109 Btu/day
Outputs
Air Emissions
Water Effluents
Solid Wastes
Noise Pollution
Occupational Health and Safety
deaths
injuries
man-days lost
7 Ib/hr
None
8,000 ton/day
Negligible
0.56 deaths/yr
11 injuries/yr
4,900 man-days/yr
1974 dollars
land use, impact statement, right-of-way and other requirements
must be met and procedures followed. A number of these regulations
are described earlier in sections on generally applicable social
controls and coal mining, and processing/conversion. The section
on processing/conversion social controls should also be referred
-170-
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to the identification of applicable water and air quality, solid
waste disposal, and safety regulations. There are no specific
new source performance standards limiting emissions from emis-
sions or effluent discharge standards for beneficiation facili-
ties, and the general air and water quality social controls are
discussed in the section on processing. In the following section,
regulatory activies significant for beneficiation are described.
In the following section, regulatory activities significant for
beneficiation are described.
There are no specific new source performance standards
limiting emissions from beneficiation facilities, but facilities
must comply with prevention of significant deterioration (PSD)
standards for air quality, and must obtain a National Pollutant
Discharge Elimination System (NPDES) permit for water effluents.1
Beneficiation facilities are generally under the jurisdic-
tion of the Mine Safety and Health Administration (MSHA) under
provisions of the Federal Mine Safety and Health Act of 1977.2
3.7.4a Solid Waste
Solid wastes from beneficiation activities are described
generally in the section on mine, reclamation and in the section
on the disposal of processing wastes. In some areas refuse piles
from beneficiation activities may accumulate, and have potential
for becoming a major safety or environmental hazard. Require-
ments exist for weekly inspection of piles that act as dams.
These piles must be of "substantial construction" and must be
designed according to accepted dam engineering criteria.3 In
TThese standards, which are generally applicable, are dis-
cussed in Chapter 2 on General Social Controls.
2Federal Mine Safety and Health Act of 1977, Pub. L. 95-164,
91 Stat. 1290.
330 CFR 77.216.
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addition, the stability of all refuse piles must be maintained,
and appropriate provisions must be made to guard against ex-
plosion or combustion.1
3.7.4b Air, Water and Noise
Beneficiation facilities at both surface and underground
coal mines have controls over worker exposure to pollutants
similar to those in other mine areas. In'addition, however, a
number of specific rules apply to surface working areas and
federal regulations have been developed that apply to specific
pieces of beneficiation equipment.2 Each facility must conduct
sampling, inspection, and compliance to standards as is re-
quired in other areas of federal mine safety law. The following
sections briefly identify selected regulations for crushing and
drying facilities as required by MSHA.
Dust Standards and Airborne Contaminants
Dust standards for beneficiation work areas have received
significant consideration, including the specification of who,
where, when, and how dust samples will be collected, and how
these will be analyzed.3 Violation of acceptable dust levels
(20 milligrams per cubic meter), necessitates methods of further
dust control, and also initiates a more intensive sampling pro-
gram until the deficiency has been corrected.
*New regulations concerning solid waste disposal are being
promulgated as a result of the Surface Mine Control and Reclama-
tion Act of 1977, Pub. L. 95-87, 30 USC 1201. These regulations
were not final as of the date of publication of this document.
230 CFR 77.
330 CFR 71.1.
-------
Drinking Water and Sanitation Facilities
MSHA has established standards of adequacy and location on
the bathing facilities, and toilets (including flush toilets) and
on the quality, distribution and dispensing of drinking water.1
Both installation requirements and maintenance of these facili-
ties are covered in the regulations.
Noise Standards
MSHA requires that beneficiation facilities have periodic
measurements of noise levels, and requires that each working
shift maintain noise levels at or below the current standard.
3.7.4c Equipment Standards
MSHA equipment standards apparently cover both safety and
process equipment used in beneficiation facilities. For example,
dryers, crushers, screeners and other beneficiation equipment are
covered by safety provisions such as proper electrical connection
canopies, guards and safety switches. Thermal driers have receiv-
ed extensive mandatory safety standards.3 Requirements for these
devices include various safety doors and vents, provisions for
adequate access and maintenance, installation and fire protection
provisions, alarm devices, fail-safe monitoring Systems, wet-coal
feed bin level indicators and other automatic monitoring equipment,
Personnel Certification and Safety Standards
A number of personnel working in beneficiation facilities
must be certified by MSHA before performing various functions.
These include testing and maintenance personnel involved in elec-
trical work, methane monitoring, hoistmen, and training activities
'30 CFR 71.
230 CFR 77.
330 CFR 77.300.
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3.8 CONVERSION
Coal can be used in several ways. The most familiar is
direct combustion in a furnace for the production of steam. Two
other methods involve extraction of the small percentage of
hydrocarbons that exist in coal plus chemical alteration of a
large portion of the carbon in the coal to produce hydrocarbons.
These two methods are gasification and liquefaction. This
section will present a process description of several coal
conversion processes, and quantify many of the input requirements
and outputs associated with each process.
Gasification and liquefaction of coal are currently being
investigated in the U.S. as two methods to supplement dwindling
domestic natural gas and crude oil reserves. The technologies
associated with both types of conversion processes have not yet
been demonstrated on a commercial scale in the U.S. The tech-
nologies described in this section are those which are most
advanced and may proceed to commercial operation. Direct
combustion of coal to provide steam for electrical generation
is also considered since it will probably continue to be the
major end use of coal.
3.8.1 Gasification
Coal may be transformed into a gaseous product by heating
the coal to drive off highly volatile constituents and
by partially oxidizing the carbon in the coal to carbon monoxide.
The carbon monoxide formed may then be upgraded to methane by
catalytically reacting carbon monoxide and hydrogen. This is
a simplified explanation to give the reader an overall concept
of the goal of all gasification schemes. The following discussion
will provide more insight into the various gasification schemes.
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3.8.1.1 Technology Description
3.8.1.la Basic Gasification Process
The three primary chemical inputs needed for synthesizing
gas from coal are carbon, hydrogen, and oxygen. Coal provides
the carbon; steam is the most commonly used source of hydrogen
(although hydrogen is sometimes introduced directly from an
external source); and oxygen is usually supplied as either
air or pure oxygen. Heat can be supplied either directly by
combusting coal and oxygen inside the gasifier or indirectly by
hot pebbles or ceramic balls from an external source.
Three combustible gases produced by coal gasification
processes are carbon monoxide (CO), methane (CIU) and hydrogen
(H2). Methane, the primary component of natural gas, is
similar to natural gas in heating value. The heating values of
carbon monoxide and hydrogen are approximately one-third the
methane/natural gas value. Several noncombustible gases are
also produced, including carbon dioxide, hydrogen sulfide and
nitrogen.
A major goal for most coal gasification processes is to
maximize the heating value of the product gas during the initial
gasification stage. The properties of the product gas from each
gasification process are determined primarily by the methods used
to introduce oxygen, hydrogen, and heat into the gasifier. Each
method involves trade-offs. For example, the first requirement,
oxygen supply, can be met by introducing either air or pure
oxygen. If air is used to provide the oxygen, however, nitrogen
is introduced as an undesirable by-product into the gas stream
and dilutes the heating value of the gas to between 100 and 250
Btu/scf. Although pure oxygen is more expensive than air, it
eliminates the nitrogen problem and produces a gas with a heating
value between 250 and 450 Btu/scf.
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The second requirement, hydrogen, can be met by introducing
steam or hydrogen. The use of steam to introduce hydrogen into
the process produces primarily carbon monoxide and hydrogen,
while the direc/t introduction of hydrogen produces methane and
carbon. Since reacting hydrogen directly with coal also
produces heat, hydrogen would seem preferable to steam, but
the amount of methane produced is usually quite small. The
other method of introducing hydrogen, the steam-carbon reaction
(heat + C 4- HfcO -*• CO + HO „ is used more* frequently.
The third requirement, heat, can be supplied either directly
or indirectly. For coal gasification processes, direct heat is
more thermally efficient than indirect heat. However, most
direct heat processes use either air or oxygen as an oxidizer,
producing the products identified above. One alternative direct
heating method feeds hot lime (CaO) into the gasifier where its
exothermic reaction with carbon dioxide produces heat. The
primary gaseous products are carbon monoxide and hydrogen. In-
direct heating using molten salts, dolomite solids, molten metal,
pebbles, etc., have also been proposed, but this introduces
additional materials requirements and makes the gasification more
complicated.
The types and proportions of gases produced are determined
by the design of the specific gasification process. As indicated
above, the basic chemical choices are whether to use hydrogen or
steam, air or oxygen, and direct or indirect heat. On the basis
of the options selected and specific conditions such as tempera-
ture and pressure, reactor vessels can be divided into three
general categories: gasifier, hydrogasifier, and devolatilizer .
Gasification systems employ one or more of these reactor types.
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The gasifier reactor produces some gas through the steam-
carbon reaction (heat + C + H20 •*• CO + H2) and some through
the water-gas shift reaction (CO 4- H20 •* C02 + H2 + heat).
The major differences in gasifier reactor systems are in the
method of providing heat and oxygen.
In the second type of reactor, hydrogasifier, methane is
produced by reacting hydrogen with coal or char under pressure
(C + 2Hz •* CHi, + heat) . Although systems of this type differ
in the method of supplying hydrogen, all hydrogasifiers produce
up to twice as much methane as gasifiers or devolatilizers of
comparable capacity.
In the third possible system, a devolatilizer, the coal
is thermally decomposed. In this system, the raw coal is
heated, and tars, oils, naphthas and other relatively light
hydrocarbons are driven off.
Although these three systems present three distinct methods
of generating hydrocarbons from coal, most reactor designs incor-
porate all three methods to some extent. For example, although
hydrogen is not introduced directly into a gasifier reactor,
the hydrogen produced by the steam-carbon reactions promotes
some hydrogasification. In addition, the heat generated by the
partial oxidation in the gasifier promotes devolatilization.
Gasification systems can also be categorized on the basis
of engineering features, two significant ones being whether the
system is pressurized and the type of coal bed used. Gasifica-
tion systems may be operated either at high pressure (up to
about 1500 psi) or at atmospheric pressure. The main advantages
gained from pressurizing are improved quality of product gas,
maximization of the hydrogasification reaction, reduction of
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equipment size, and elimination of the need to separately
pressurize gas before introducing it into a pipeline.1
There are three basic bed types for gasification systems:
fixed-bed, fluidized-bed, and entrainment.2 In the fixed-bed
system, a grate supports lumps of coal through which the steam
or hydrogen is passed. These gasifiers sometimes include a
mechanism for physically moving the coal through the reactors,
for example, a moving grate. These systems are sometimes referred
to as moving-bed reactors. Conventional fixed-bed systems are
incompatible with caking coals (coals which, when heated, pass
through a plastic stage and cake or agglomerate into a mass).
To expand the range of coals that can be used, the moving-bed
systems are modified to incorporate a rotating grate or stirrer
to prevent caking.
The fluidized-bed system uses finely sized coal. Gas is
passed through the coal, producing a lifting and "boiling"
effect. The result is an agitated bed with more exposed coal
surface area to promote the chemical reactions. Fluidized-bed
systems also have a limited capacity for operating with caking
coals; consequently, these coals are often pretreated to destroy
caking characteristics when the fluidized-bed system is used.
Finely sized coal is also used in entrainment systems. In
this type of system, the coal particles are transported in the gas
(for example, steam and oxygen) prior to introduction into the
^nteragency Synthetic Fuels Task Force. Report to Project
Independence Blueprint. Federal Energy Agency, Supplement 1,_
prepared under the direction of U.S. Department of the Interior,
1974.
2Corey, Richard C. "Coal Technology", pp. 23-61 in Riegels'
Handbook of Industrial Chemistry, 7th Ed. New York: Van Nostrand
Reinhold, 19/4.
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reactor. The chemical reactions occur in the reactor, and the
product gases and ash are taken out separately. There are no
limitations on the types of coal that can be used with the en-
trainment system. A summary of the advantages and disadvantages
of each of these bed types is shown in Table 3-72.
As can be seen from the above discussion, there are many
possible options available in the coal gasification reactor.
In addition to the reactor, however, there are other processing
steps. The choice of reactor design and subsequent processing
will c'ategorize the process into one of three general categories
of gasification schemes: Low-Btu gasification, which produces a
low heat content gas (100-250 Btu/scf); Medium-Btu gasification,
which yields an intermediate quality gas (250-450 Btu/scf); and
High-Btu gasification, which produces a high-Btu gas or pipeline
quality gas (900-1000 Btu/scf).
The basic differences between these three types of gasifica-
tion systems are the source of oxygen for partial oxidation in
the gasifier and whether or not a methanation step is used to
convert the carbon monoxide to methane. A summary of the alter-
native generally used within each category is as follows:
1) Low-Btu gasification: air used as a source of
oxygen; no methanation
2) Medium-Btu gasification: pure oxygen used;
no methanation
3) High-Btu gasification: pure oxygen used,
methanation step included.
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TABLE 3-72.
ADVANTAGES AND DISADVANTAGES OF COAL
GASIFICATION PROCESS TYPES
Process Type
Advantages
Disadvantag
es
Fixed Bed
Fluid Bed
Entrained
Bed
High carbon conversion
efficiency
Low ash carryover
Low temperature
operation
Highest turndown
capability
Turndown capability
High degree of pro-
cess uniformity
Excellent solids gas
contact
Lower residence time-
than fixed bed gasi-
fier (higher coal
throughput per unit
volume of reactor)
• Handles all type coal,
no pretreatment
required
• Excellent solids-gas
contract
• No tar formation
• No phenol formation
• High capacity per unit
volume of reactor
• Produces inert slagged
ash
• Sized coal required
• Coal fines must be briquetted
Produces tars and heavier hydro-
carbons which must be washed
from the gas
• Produces phenols which can cause
pollution problems
• Low capacity-largest number of
gasifiers required
• Low temperature gas produced ser-
iously restricting waste heat
steam generation pressures
• Present experience based on dis-
charging dry ash
• Caking coal technology not commer-
cially proven
• Requires dry coal for feeding
• Requires sized coal
• Requires complicated gas distributor
• Caking coals require pretreatment
• Fluidization requirement sensitive
to fuel characteristics
• Single-stage
• High carbon loss with ash
• Low pressure
Single-stage
Low pressure
• Poor turndown capability
• Air-blown and two-stage gasification
still under development
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A summary of the characteristics of several gasification
processes for the production of each type of gas is shown in
Table 3-73. It should be noted, however, that new technology
in this area is under consideration by many agencies and firms.
There are, therefore, other processes in various stages of de-
velopment and other processes which will probably be developed
in the future. The processes considered here are those gasifi-
cation processes which are advanced enough to allow an adequate
technological description and analysis. In addition to these
gasification processes, there are several hydrogasification
processes which are in various stages of development. These
processes are not considered in detail.
The reactions involved for the production of all three
categories of product gas will be discussed and the process
schemes defined. However, only the High-Btu gasification process
will be examined thoroughly since it is the one that is most
likely to be employed in western coal development. The reasons
is that transporation costs (pipeline pumping costs) are inversely
proportional to the quality of the gas. For example, three
cubic feet of 300 Btu/scf gas must be delivered to meet the
same energy demand as can be supplied by one cubic foot of 900
Btu/scf gas. Therefore, low and medium Btu gas will be produced
only if there is a local demand. For completeness, low and
medium gasification are briefly discussed, followed by a thorough
analysis of high Btu gasification.
3.8.1b Low and Medium Btu Gasification
Low Btu gas (150-250 Btu/scf) can be used as fuel in either
a conventional boiler or a combined cycle generation plant.
Medium Btu gas (250-450 Btu/scf) can be used either as a chemical
feedstock or as fuel in a conventional boiler or combined cycle
generating plant. Medium Btu gas can be produced in a low Btu
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TABLE 3-73. CHARACTERISTICS OF SELECTED COAL GASIFICATION PROCESSES
oo
N»
I
Heating Value of
the Product Gas Type of Reactor Operating Pressure _
Processes
ATGAS
CO 2 Acceptor
Koppers-Totzek
Lurgi
Molten Salt
Syntliane
Texaco
U-CAS ®
Union Carbide
Wellman-Galusha
West ingliouse
W Inkier
Developer
Applied Technology Corp.
Conoco. Coal Development Co.
Helnrlch Koppera GmbH of Essen
Lurgi Mineralotechnlk GmbH
H. W. Kellogg Company
U.S. Bureau of Mines
Texaco Development Corp.
Institute of Gas Technology
Union Carbide Corp.
Uellman Engineering Co.
Westlnghouse Research
Laboratories
Davy Powergas Inc.
Low
X
X
X
X
X
X
X
X
High/Medium Fluid-Bed Entralned-Bed Moving-Bed Lou1 Medium? High'
X Molten-Iron Bath < X
XX X
X XX
X XX
X . . Molten-Salt Bath X
XX. X
XX X
X X
XX X
X XX
X X
XX X
Typically 0 - 15 pslg
100 - 500 pslg
1000 - 1500 psig
Adapted from: Botlle, W. W. K. C. Vyas and A. T. Talwalkar. "Clean Fuels From Coal - Technical-Historical Background and Principles of
Modern Technology" In Clean Fuels From Coal Symposium II Papers. Sponsored by Institute of Gas Technology, June 23-27,
1975, pp. 11-51.
-------
gasification plant by substituting 98+7» oxygen for air as the
source of oxygen to the gasifier. Because the processing steps
necessary to produce medium Btu gas are identical to those
required for low Btu gasification, the following sections, which
describe the low Btu process features, will apply to medium Btu
gasification as well.
The processing steps in a low or medium Btu gasification
plant are (1) coal pretreatment and gasification, (2) cooling
and solids removal, (3) acid gas removal, (4) sulfur recovery,
and (5) product drying and compressing. Figure 3-21 shows the
general flow for these processes. The gasification step is
the major distinguishing feature among various designs. In
each gasifier, coal is reacted with oxygen to produce a raw gas
rich in CO and H2 which can be purified and used as a boiler
fuel. The differences between the processes are found in the
operating temperatures, pressures and mechanical characteristics
of the gasifier.
The reactions taking place in the gasifier are given by
Equations 3-1 to 3-3.
coal •* CH., -I- char + heat (3-1)
C + H20 + heat -»• CO + H2 (3'2>
2C + 02 * 2CO + heat (3~3)
The design for each gas'ifier listed in Table 3-73 which is
capable of producing low- and/or medium-Btu gas except Lurgi
and Synthane is briefly discussed below. The designs of the
Lurgi and Synthane processes are discussed in detail subsequently
in Section 3.8.1.1c.
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AIR
COAL
COAL
PREPARATION
O3
H2O
POWER AND
STEAM PLANT
POWER TO
PLANT USERS
OXYGEN PLANT
OXYGEN/AIR
GASIFIER
STEAM
CONDENSATE
RECLAIMED WATER.
TO 4N-PLANT USERS
-»- NITROGEN
GAS
COOLING
i
L.
GAS LIQUOR i
SEPARATION f
J
GAS LIQUOR
AND EFFLUENT
WATER
TREATMENT
C02 S, S02
VENT OR H2S04
SULFUR
RECOVERY
UNIT
GAS
PURIFICATION
(CO2/H2S
REMOVAL)
FUEL GAS
i 1
-I NAPHTHA !
I !
r • ~ \
JTAR AND TAR OILS I
r i
-•-] AMMONIA !
t J
i 1
-J PHENOLS [
I 1
Figure 3-21. General Coal Gasification Flow Sheet
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ATGAS Gasifier
This type of gasification process can be broken down into
two basic types: Two-Stage process (low-Btu) and PATGAS (medium-
Btu). In each type, crushed C-1/^ in), dried (470 moisture) coal
is injected into a molten iron bath. The low-Btu process uses
compressed air for coal injection while the medium-Btu process
uses a steam lance. The coal dissolves in the molten iron where
the coal volatiles crack and are converted into carbon monoxide
and hydrogen. The fixed carbon in the coal reacts with oxygen
and steam, producing more carbon monoxide and hydrogen. Sulfur
from coal migrates to a lime slag floating on the molten iron
and forms calcium sulfide. The slag containing ash and sulfur
is continuously withdrawn from the gasifier and desulfurized with
steam to yield elemental sulfur and desulfurized slag. A portion
of the desulfurized slag is recycled to the reactor. The condi-
tions of operation of the gasifier are about 2600°F and 5 psig.
The same type of.gasifier can be used in conjunction with a
shift conversion, methanation and compression to produce a high-
Btu gas.
The composition and heat content of low- and medium-Btu
gases are as follows:1
Low-Btu gas: 30% CO, 15% H;, 55% N2;
190 Btu/scf
Medium-Btu gas: 64.5% CO, 35% H2, o.5% N2;
315 Btu/scf.
'Bodle, W. W., and K. C. Vyas. "Clean Fuels From Coal-
Introduction To Modern Processes" in Clean Fuels From Coal
Symposium II Papers. Sponsored by Institute or Gas Tecnnology,
June 23-27, 1975, pp. 11-51.
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C02 Acceptor
The C02 acceptor utilizes two fluidized bed reactors. One
reactor is used for gasification of the coal and the other is
used to regenerate spent acceptor (limestone or dolomite) used
in the process. This system is different from most gasification
processes in that the heat required for the gasification reactions
is generated inside the gasifier but not by partial oxidation of
the coal. Instead, heat is provided by introducing the acceptor
into the reactor where it exothermically reacts with C02. The
C02 for this reaction is provided by the water-CO shift reaction
(Equation 3-4 below).
After the acceptor reacts according to the Equation 3-5,
it is removed from the gasifier and introduced to the second
reactor where it is calcined according to Equation 3-6. The
calcined acceptor is then recirculated to the gasifier.
CO + H20 * C02 + H2 (3-4)
CaO + C02 -•• CaC03 + Heat (3-5)
CaC03 -* CaO + C02 (3-6)
The coal feed for the gasifier is first crushed (+100 -8
mesh), dried and preheated. It is then fed to the gasifier
from lock hoppers by gravity feed near the bottom of the gasifier.
Steam is injected at about this same level. Hot recirculating
acceptor from the regenerator reactor is showered through the
fluidized bed and collects at the bottom. Thus, the fluidized
bed is a mixture of coal, char and acceptor. Steam is injected
near the bottom of the gasifier to strip the char from the
acceptor and the spent acceptor is then removed to the regenerator
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The heating value of the medium-Btu gas produced by this
process is expected to be about 440 Btu/scf (dry basis).
Koppers-Totzek Gasifier
The Koppers-Totzek gasifier is an entrained flow gasifier
capable of treating all types of coal. Coal pulverized to 70%
through a 200-mesh screen is fed to the gasifier with steam and
air or oxygen through coaxial burners at each end of the gasifier.
Coal, oxygen and steam react at about 3300°F to produce the raw
gas. Part of the coal ash is slagged and removed from the bottom
of the gasifier. The remaining ash and raw gas leave the top
of the gasifier and are processed by the downstream equipment
described subsequently. The gasifier pressure is approximately
atmospheric. The typical composition of the medium-Btu raw gas
(in mole %) and its heating value are as follows: 50.4% CO, 5.6%
C02, 33.1% H2, 9.6% H20, 0.3% H2S + COS and 1.0% N2; heating
value - 298 Btu/scf.1
Molten Salt Gasifier
In this process, dried, crushed (12 mesh) coal is picked up
from lock hoppers by a preheated steam and oxygen stream and
fed into the gasifier along with sodium carbonate. The coal
steam reaction (see Equation 3-2) is catalyzed by the molten salt
(sodium carbonate) contained in the reactor so that a gas free
of tars is produced at a sufficiently low temperature and
appreciable methane production can also take place. The use
of the molten salt reaction medium also makes pretreatment of
:Bodle, W. W., and K. C. Vyas. "Clean Fuels From Coal-
Introduction to Modern Processes" in Clean Fuels From Coal
Symposium II Papers. Sponsored by Institute of Gas Technology.
June 23-27, 1975, pp. 11-51.
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caking coals unnecessary. A bleed stream of molten salt con-
taining the coal ash in solution is withdrawn from the bottom of
the gasifier, and is contacted with water to dissolve sodium
carbonate. Ash is separated by filtration. Sodium carbonate
solution is carbonated to precipitate bicarbonate. The bicarbon-
ate is filtered out and calcined to restore the carbonate salt
which is then recycled to the gasifier.
The composition (in mole%) and heating value of the typical
raw medium-Btu gas from the process is as follows: 26% CO,
10.3% C02, 5.8% OU. 34.8% H2, 0.2% H2S, 0.3% N2 and 22.6%
heating value - 329 Btu/scf.1
Texaco Gasifier2'3'1"5
The coal for this process is first pulverized to 70% through
200 mesh. It is then mixed with water and this coal-water slurry
is heated to about 10008F. The resulting steam-coal mixture is
then fed into the top of the gasifier. Heated oxygen is fed
to the gasifier at the periphery of the vessel to produce a medium
Btu gas. Temperatures in the reaction zone range from 2000 to 2500°F
, W. W. , and K. C. Vyas. "Clean Fuels From Coal-
Introduction To Modern Processes" in Clean Fuels From Coal
Symposium II Papers. Sponsored by Institute of Gas Technology,
June 23-27, 1975, pp. 11-51.
2Howard-Smith, I., and G. J. Werner. Coal Conversion Tech-
nology. Chemical Technology Review#66, Park Ridge, N.J., Noyes
Data" 1976.
3Hendrickson, Thomas, comp. Synthetic Fuels Data Handbook.
Denver, Colorado, Cameron Engineers, Inc., 1975.
"Katz, Donald L., et al. Evaluation of Coal Conversion
Processes to Provide Clean Fuels, Final Report.EPRI 206-0-0.
Ann Arbor, Mich., Univ. of Michigan, College of Engineering, 1974.
5Hall, E. H., et al. Fuels Technology: A State-of-the-Art
Review. EPA 650/2-75-034, EPA Contract No. 68-02-1323, Task 14.
Columbus, Ohio, Battelle Columbus Labs., April 1975.
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and the operating pressure is about 400 psi. The gasifier can
also be blown with air to produce a low-Btu gas. Ash is removed
from the bottom of the gasifier as a molten slag and is water
quenched.
The composition (in volume %, dry) and heat content of the
resulting gas has been estimated as follows: 38.77, H2 , 46.6%
CO, 11.5% C02, 0.7% CIU, 2.0% N2 and 0.7% H2S; heat content =
270 Btu/scf.
U-GAS Gasifier
In this gasifier design, crushed coal is fed through lock
hoppers to a pretreater (necessary for caking coals only) which
operates at 350 psi and 800°F. Air introduced into the pretreater
partially oxidizes the coal to destroy its caking tendencies.
From the pretreater the coal is fed directly to the fluid-bed
gasifier that operates at 350 psi and 1900°F. Air and steam are
introduced to the bottom of the gasifier. Dry ash is removed
from the gasifier through lock hoppers.
The composition (in mole 7») of the raw gas from the gasifier
is as follows: 17.0% CO, 8.8% C02, 11.6% H2, 12.0% H20, 4.1%
CH*, 45.4% N2 and 0.6% H2S. The approximate heating value of
this gas is 150 Btu/scf (dry basis).1
Union Carbide Gasifier
This gasification process involves a two-stage fluidized-bed
system. In the first stage, coal is fed to a fluidized bed
burner where it is combusted with air to form hot pelletized
W. W., and K. C. Vyas. "Clean Fuels From Coal-
Introduction To Modern Processes" in Clean Fuels From Coal
Symposium II Papers. Sponsored by Institute ot Gas Technology,
June 23-27, 1975, pp. 11-51.
-189-
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coal ash. This ash is fed to the gasifier along with crushed
(minus 35 mesh) coal and steam. The ash from the burner provides
the heat for the gasifier. Thus, air rather than oxygen can be
used for combustion without dilution of the gasifier off gas
with nitrogen. The hot ash enters the gasifier at about 2000°F
and is cooled to about 1000°F within the gasifier. The raw gas
leaves the gasifier at about 1600 to 1800°F. The heating value
of this gas is expected to be about 300+ Btu/scf.1
Wellman-Galusha Gasifier
The Wellman-Galusha gasifier is a moving bed, steam-air
gasifier. Coal crushed and sized to Vis to Vis-inch diameter is
fed to the gasifier through a lock hopper and distributed over
the coal bed by a rotating arm. The coal bed moves downward
through the gasification zone, undergoing reaction 3-1. As the
resulting char leaves the gasification zone and enters the com-
bustion zone, it contacts steam and oxygen injected at the
bottom of the gasifier and undergoes reactions 3-2 and 3-3. Air is
injected for low-Btu gas. A revolving eccentric grate at the
bottom of the gasifier allows for bed support and ash removal.
A rotating agitator arm, located just below the coal bed, is
used when handling slightly caking coals.
Strongly caking coals must be pretreated to destroy their
caking tendencies before gasification can be accomplished. The
gas flows counter-currently to the coal bed and is removed from
the top of the gasifier at 1000-1200°F. The gasifier operates
at essentially atmospheric pressure.2
^endrickson, Thomas, comp. Synthetic Fuels Data Handbook.
Denver, Colorado, Cameron Engineers, Inc., 1975.
2Ball, D., et al. Study of Potential Problems and Optimum
Opportunities in Retrofitting Industrial Processes to Low and
Intermediate finergy Gas from Coal, Final Report.Columbus, Ohio,
Battelle Columbus Labs, 1974.
-190-
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The heating value of the medium-Btu gas produced in this
process is approximately 270 Btu/scf.1 The heating value of the
low-Btu gas is 120 to 168 Btu/scf.1'2
Westinghouse Gasifier
In this gasification process, dry coal is first fed to the
bottom of a devolitizer/desulfurizer reactor while dolomite is
fed into the top. The reactor is a fluidized bed reactor operat-
ing at 1600 to 1800°F. It produces a low-Btu off-gas rich in
CO, Hz and Na with smaller amounts of CH^. The sulfur is removed
by a reaction of the H2S and the dolomite to form calcium sulfide.
The char produced in this reactor is then gasified with steam
and air in a combustor/gasifier operating at about 2100°F. kThe
off-gas from this vessel is reintroduced into the bottom of the
devolitizer/desulfurizer. Both vessels operate at between 150
and 250 psi.3
Winkler Gasifier
The Winkler gasifier is a fluid bed, steam-air (low-Btu) or
steam-oxygen (medium-Btu) gasifier. Coal crushed to a 3/8-inch
maximum diameter is dried and fed by screw conveyors to the
gasifier. The coal undergoes reactions 3-1 to 3-3 to yield a raw
gas rich in CO and Hz. The gasifier reaction temperature is
Howard-Smith, I., and G. J. Werner, Coal Conversion Tech-
nology. Chemical Technology Review #66, Park Ridge, N.J., Noyes
Data, 1976.
2Ball, D. A., et al. Environmental Aspects of Retrofitting
Two Industries to Low- and Intermediate-Energy Gas from Coal.
EPA-600/2-76-102, EPA Contract Wo. 68-02-1843.Columbus, Ohio,
Battelle-Columbus Laboratories, April 1976.
3Chemical Engineering Progress. Coal Processing Technology,
Vol. 2. N.Y., AIChE, 1975.
-191-
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1500-1850°F and the pressure is about atmospheric. Thirty
percent of the coal ash is removed from the bottom of the
gasifier while about 70 percent is carried overhead with the
raw gas. Above the fluid bed, additional steam and air or
oxygen are injected to react with the remaining carbon. The
resultant gas is processed by the equipment described under
common processing steps.
The composition (in mole 7,) and heating value of the
resulting medium-Btu gas are as follows: 25.77, CO, 15.87. C02 ,
32.27. H2, 23.17, H20, 2.47, CIU and 0.87, N2 ; heating value -
275 Btu/scf (dry basis).1
The composition (in mole 7,) and heating value of the
resulting low-Btu gas are as follows: 19% CO, 6.27, C02, 11.77,
H2, 11.57, H20, 0.57. CH* and 51.17. N2; heating value = 118 Btu/
scf (dry basis).l
The above discussions are intended to give the reader an
introduction into the technologies of low- and medium-Btu
gasification processes. In each process except U-GAS and
Westinghouse, a high-Btu gas can be produced by using the gasifi-
cation techniques to produce a medium-Btu raw gas and then
further processing this gas to increase heating value by the
methods described in Section 3.8.1.1c for the Lurgi and
Synthane high-Btu processes.
Once the raw low- or medium-Btu gas is produced by one of
the gasification systems described above, it must undergo two
'Bodle, W. W., and K. C. Vyas. "Clean Fuels From Coal-
Introduction To Modern Processes" in Clean Fuels From Coal
Symposium II Papers. Sponsored by Institute of Gas Technology,
June 23-27, 1975, pp. 11-51.
-192-
-------
additional processing steps to make it usable as a fuel. Common
technology is used in all processes downstream of the gasifier
and is briefly discussed in the following paragraphs.
First, entrained solids and/or liquids must be removed by
cooling and/or washing. This may be accomplished by many methods,
of which cyclones, venturi scrubbers or direct quenches are a
few examples. Following cooling and solids removal, COa and/or
H2S must be removed. There are many proven industrial techniques
available for removing C02 and H2S.
In addition to the gas cleaning equipment just described,
facilities must also be provided for the treatment of liquid
and solid waste streams and recovery of ammonia and hydrocarbon
by-products. Included in these facilities are a primary water
treatment unit, a gas liquor treatment unit, an ammonia still,
coal and by-product storage facilities, and in the case of medium
Btu gasification, an oxygen plant.
3.8.1.1c High-Btu Gasification
High Btu gasification is the process by which coal is
converted to a high-B.tu gas (900-1000 Btu/ft3) called substitute
natural gas, SNG. SNG can be freely substituted for natural gas
and transported in the existing maze of natural gas pipelines
which cross the U.S. Unfortunately, a commercial size plant
has not yet been built in the U.S.
However, several designs have been proposed and some are in
the pilot and demonstration plant stage. Candidate systems for the
production of SNG include those gasifiers discussed in Section
3.8.Lib as being capable of producing a high-Btu gas (See Table 3-73)
plus several hydrogasifiers such as the Institute for Gas Technology
-193-
-------
HYGAS® process, the Bituminous Coal Research BI-GAS process, the
U.S. Bureau of Mines Hydrane process and others.
In order to define emissions, energy requirements, and other
residual impacts, specific processes must be analyzed. To this
end, the Lurgi Process and Synthane Process have been selected
as examples to quantify residual information associated with
the production of SNG.
All high-Btu gasification processes include the following
steps:
1) coal pretreatment
2) gasification
3) cooling and solids removal
4) catalytic shifting
5) acid gas removal
6) sulfur recovery
7) catalytic methanation
8) product drying and compressing.
In addition to the above facilities, an auxiliary boiler, a
steam superheater, a water treatment unit, oxygen plant and by-
product storage facilities are required. While specific operating
conditions are assumed for some of the processing units, it is
felt that there are other alternatives available which could
meet the process requirements. Moreover, these alternatives
should exhibit environmental impacts similar to the conditions
assumed. Figure 3-22 and Figure 3-23 show the typical overfall flow
diagrams for the Lurgi and Synthane processes analyzed here.
As is the case with low- and medium-Btu gasification, the
distinguishing characteristic between high Btu gasification
-194-
-------
AIR 1
OXYQEN PLANT
NITROGEN
OXVQEN
BY-PASS QA3
CftAi fe. COAL
1 PREPARATION
1
(— ' , , .
VO POWER
*•" WATER *- *ND STEAM ."'"
1 PnOOUCTION
ELECTRICITY
TO PLANT
USERS
A
AM
n — *•
*
QASIFIERS
1
ASH
~1
1
QASIFIERS
ASH
SM
CONVI
i
FT
•nstoN
1
QA3 LIQUOR n
SEPARATION EXTF
<
. FUEL
COO
•\
OAS
UNO
h_ r»*$ 1 fc| n»3
COOLINQ 1 ""I PURIFICATION
, ,
IENOL ) QAS LIQUOR SULFUR ~
UCTION | STRIPPER RECOVERY —
1 II f
t f T
1
FUEL
QAS
^. FUEL QAS
PURIFICATION
...to. ..,-.,,,..,,„,.,.. ^w^ cnupnession
*• MEIHANA1IUN ""+' AND
, , OFHVDRATION
1 t
CONDENSATE CONDENSATE
*- TAIL OA8
*- SULFUR
*" OY-PROOUCT STORAGE
SNO
Figure 3-22. Overall lurgi high-Btu gasification flow diagram,
-------
AH).
COAL
I
h*
VO
ON
I
OXYGEN PLANT I »~ NITROGEN
OXYGEN
*
COAL (U9IFIFH8 h. QA9 °°
HlbPARATIGN *" w*81'161"1 »- ANO ctE
CHAR
STEAM
STEAM
WATER *" POWI
WATE" PROOUCTIO
CHAR
AND
:R
N PLANT
\ \
ASH ELECTRICITY
TO PLANT
USERS
BY-PASS QAS
1 SULFUR r-
RECOVERV |-
1
QLINQ L w SHIFT
ANINQ | CONVERSION
l_f-J OA8
|~*"1 PURIFICATION
t r^
WATER QAS LIQUOR
SEPARATION
L_
HYDHOCAnOON
TO STORAGE
QAS LIQUOR
AND EFFLUENT
WATER TREATMENT
fr-TAIL QAS TO CLEAN-UP
SULFUR
- J
METHANATION
I - *.
COMPRESSION
AND
DEHYDRATION
CONOENSATE
CONOENSATE
AMMONIA WATER TO
TO STORAGE COOLINQ
TOWER
~ SNQ
Figure 3-23. Overall synthane high-Btu gasification flow diagram.
-------
processes is the mechanism and equipment used for gasification
of the coal. All other process units are essentially the same.
The following sections, therefore, present the design and
operating conditions used within this phase of the Lurgi and
Synthane processes. A fourth section describing the remaining
common processing steps for the designs is then presented.
Lurgi Gasifier
Before coal can be fed to the Lurgi gasifier it must be
reduced in size. Noncaking or slightly caking coal is crushed
to two coal sizes, 8 mm x 2 mm and 45 mm x 8 mm. A mixture of
the two coal sizes is fed to the top of the gasifier through a
lock hopper. Cooled synthesis gas from the gas cooling area
is used as the pressurizing fluid to bring the lock hopper up
to the 445 psig operating pressure of the gasifier. The gasifier
may be designed to operate anywhere between 300 and 500 psi.1
After the lock hopper has emptied, the,remaining high pressure
lock gases are collected in a holding tank, recompressed and
combined with the main process stream in the gas cooling area.
The residual atmospheric lock gas that is displaced when the
hopper receives its next coal charge is directed to the incinera-
tion area for disposal.
The crushed coal is fed into the gasifier and distributed
by a revolving grate. The Lurgi gasifier is a moving bed, steam-
oxygen gasifier. The main operating difference between the
high-Btu Lurgi gasifier and the low-Btu gasifier is the purity
of the oxygen feed. The low-Btu gasifier uses air while the
high-Btu gasifier uses oxygen.
aU.S. Federal Power Commission, Synthetic Gas-Coal Task
Force. Final Report: The Supply-Technical Advisory Task Force-
Synthetic Gas-Coal.Washington, D.C., Federal Power Commission,
-197-
-------
The steam and oxygen are injected at the bottom of the
gasifier and are distributed through a second revolving grate
which also provides bed support and regulates the ash removal
rate. Ash is removed from the gasifier by a lock hopper and
water quenched. Figure 3-24 shows the Lurgi gasifier.
Figure 3-25 presents a schematic of the Lurgi gasifier showing
the various reaction zones.
The steam and oxygen react with char in the reaction zone
of the gasifier according to Equations 3-8 and 3-9 to produce
heat and a medium-Btu gas. As this hot gas rises through the
downward moving coal bed, the coal entering the gasifier is de-
volatilized according to Equation 3-7. The hot gas mixture
leaving the top of the reactor is called a synthesis gas. The
temperature at the top of the gasifier is about 10008F while the
temperature at the.bottom is about 1800°F.
Coal * CH., + Char + Heat (3-7)
C + H20 + Heat * CO + H2 (3-8)
2C + 02 -»• 2CO + Heat (3-9)
The char may react according to Equation 3-10 to produce methane
directly. The synthesis gas may also undergo various other
reactions such as Equations 3-11 and 3-12 to yield C02 and methane
C + 2H2 t CH* + Heat (3-10)
CO + H20 t C02 + H2 + Heat (3-11)
CO + 3H2 t CH* + H20 + Heat (3-12)
-198-
-------
FEED COAL
DRIVE
GRATE\
DRIVE
STEAM
& OXYGEN
SCRUBBING
COOLER
GAS
WATER JACKET
Figure 3-24. Schematic of a Lurgi Gasifier
-199-
-------
COAL
HYD&AULlt
MOTOR
COAL
PREHEAT
ZOA/fi
REACTION
ZOA/E
ASH 20A/E-
OXYGEN AMD
HYDRAULIC
OPERATED
A VALVES
BUNKER
TO EXHAUST
COAL LOCK
'CHAMBER
CRUDE GAS OUTLET
COAL DISTRIBUTOR
JACKETED G-AS
/PRODUCER.
ISA/ GRATE
ASH LOCK
CHAMSER
ASH QUEMCH WATER-
ASH QUEUCH
CHAM&ER
Figure 3-25. Schematic diagram of lurgi gasifier,
-200-
-------
These reactions illustrate that the coal is initially
subjected to a reducing atmosphere. It subsequently enters an
oxidizing atmosphere as discussed above. The effect of these
regimes is discussed under environmental considerations relative
to the fate of trace compounds.
Synthane Gasifier
In the Synthane Process, coal sized to pass through a 200
mesh screen is mixed with steam and oxygen in a fluidized bed
pretreatment pressure vessel at 1,000 psi and 800°F1 where the
coal is partially devolitized and its caking tendency destroyed.
About 1270 of the total steam and oxygen necessary for the Synthane
process is fed to the pretreater. From this pretreatment stage,
the coal and gases enter the top of the gasifier. A schematic
of the Synthane Gasifier is presented in Figure 3-26.
The Synthane Process utilizes a two-stage, fluidized bed
gasifier. The coal enters the hydrogasification stage of the
gasifier and then the gasification section. Both of these
stages operate as a fluidized bed. At the bottom of the gasifier,
steam and oxygen are injected and char and ash removed. The
steam, oxygen, and char react according to Equations 3-13 to 3-16
producing a synthesis gas. The gasification stage operates at
1750-1850°F and the hydrogasification stage at 1100-1450°F.
The entire gasifier is under 600-1000 psi pressure. The reactions
which take place in the gasifier are as follows:
Coal -»• Cm + Char + Heat (3-13)
C + 2H2 •»• CIU + Heat (3-14)
University of Oklahoma, Science and Public Policy Program.
Energy Alternatives; A Comparative Analysis. Washington
Government Printing Office, 1975.
-201-
-------
Coal
oieum i-*-! r—
Oxygen H
1 s
nT
Tar o
Steam w ^
s^lvVIIII ^^ ^^r
Oxygen y^^
Char Gas
pray Shift Scrubber
ower — * -*
t .*
md Oust H2S
COS
C02
Methanator
^
i
t
I
H2S
Figure 3-26. Schematic diagram of the Synthane Process.
Source: Adapted from BuMines, 1974c: 11.
-------
C + H20 + Heat * CO + H2 (3-15)
2C + 02 ->- 2CO + Heat (3-16)
Common Processing Steps
This section describes the remaining process units in a
high-Btu gasification facility. The starting point is the
synthesis gas from the gasifier. Synthesis gas produced during
coal gasification can contain dust, coal fines, carbon char,
tars, oils, and phenols. To prevent plugging of the shift reactor
and poisoning of downstream catalysts, the synthesis gas is
cleaned of all solids. Conventional processing equipment can
be used to accomplish this, but may have to be refined to ensure
essentially 1007, solids removal. Typical methods would include
dry cyclones, wet cyclones, venturi scrubbers, quenchers, and
bag filters.1
In addition to solids removal before the shift reactor, the
synthesis gas is cooled to 550-650°F. This is necessary to
avoid excessively high temperatures in the shift reactor due to
the exothermic water gas reaction. The use of water wash
columns, direct quenches, venturi scrubbers and/or heat exchangers
has been proposed for cooling the synthesis gas prior to its
entering the shift reactor.
Synthesis gas is upgraded to SNG by the catalytic methanation
reaction shown below:
1 Radian Corporation. A Western Regional Energy Development
Study. Final Report, 4 vols~Austin, Tex. : Radian Corp. , 1975.
-203-
-------
CO + 3H2 * CH* 4- H20 + Heat (3-17)
This requires a 3:1 ratio of hydrogen to carbon monoxide.
However, this ratio in most synthesis gases is about 1:1 or
lower. To obtain the desired ratio of H2:CO, steam is added
to the synthesis gas and the gas is catalytically shifted
according to the water/gas reaction given by Equation 3-18 to
give the 3:1 ratio.
CO + H20 t C02 + H2 + Heat (3-18)
The water/gas reaction has been proven for several industrial
applications, for example, the production of ammonia. However,
in the ammonia system, the CO content of the gas is much lower
than that found in coal gasification synthesis gas. Work has
been done and still needs to be done to develop new shift reactor
catalysts and methods of operating the shift reactor.
The need to find a new catalyst arises because of the
reducing tendencies of the high CO content of the synthesis gas.
This causes the metal oxide catalysts employed to be reduced to
the elemental metal which will then catalyze the methanation
reaction, Equation 3-17. This reaction is highly exothermic and
will cause hot spots in the reactor bed and damage the catalyst.
To offset the reducing effect of CO, large quantities of steam,
which has an oxidation effect, are added. However, steam has
adverse effects on the mechanical strength of the catalyst. A
1:1 ratio of steam to dry gas has been recommended by catalyst
manufacturers as the best shift reactor feed.l
*Air Products and Chemicals, Inc. Engineering Study and
Technical Evaluation of the Bituminous Coal Researcht IncT
Two-Stage Super Pressure Gasification Process!Washington:
Office of Coal Research, undated.
-204-
-------
The sulfurous compounds, to be removed during acid-gas
treatment, are generated during the gasification of the coal.
A primary purpose of gasification processes is to convert a
high-sulfur fuel, such as coal, into a low-sulfur energy source,
such as substitute natural gas. The sulfur which occurs naturally
in the feedstock, therefore, must be eliminated from the system.
The primary sulfur compound which exists in the synthesis
gas stream is hydrogen sulfide (H2S). When carbon monoxide is
present in the process gas stream, carbonyl sulfide (COS) will
also be generated. If a portion of the process exists at
relatively high temperatures, carbon disulfide (CSa) will be
formed. If the hydrogen and carbon monoxide concentrations in
t
the primary reaction stage are approximately equal, the thermo-
dynamically expected carbonyl sulfide concentration is about
1/30 of the hydrogen sulfide concentration, and the carbon
disulfide concentration will be even lower. As will be shown
later, however, hydrogen sulfide is more readily removed from
the process gas stream than COS or CSa. Therefore, the pro-
cessing conditions which affect the manufacture and conversion
of COS and CSa must be examined to determine the overall pollutant
discharge from the facility.
Other forms of sulfur such as organic sulfides, mercaptans,
and thiophenes, are also produced in the primary reaction step
during the devolitization of coal. These heavier sulfur com-
pounds will be collected with the tars and oils from the process
and can be converted to H2S if the tars and oils are hydrode-
sulfurized. The HaS, COS, and CS2 are the primary sulfur types
to be found in the synthesis gas as it reaches the acid-gas
treatment section of the facility.
-205-
-------
The acid-gas containing these compounds is generally
removed from the product gas by physical absorption with an
organic solvent. In these processes, the product gas undergoes
countercurrent scrubbing at high pressures with a solvent which
will absorb the acid-gas. The solvent is then stripped of the
acid-gas and recirculated to the adsorbers. Some of the well-
known solvent-based processes are defined in Table 3-74.
In addition to these solvent-based processes there are
other systems which could be used for acid-gas removal. These
include processes which remove the gas by reactions with alka-
line salts or amines or by indirect oxidation. For the analysis
reported herein, it is assumed that the solvent based Rectisol
process is used in the Lurgi process and the Benfield hot car-
bonate process is used in the Synthane process.
The off-gases from these acid-gas removal processes must be
further treated for sulfur removal before they can be vented to
the atmosphere. This is generally accomplished by a Glaus and/or
a Stretford unit. In a Glaus unit, the sulfur is recovered as
elemental sulfur by first oxidizing one third of the HaS
according to Equation 3-19. The S02 from this reaction is then
reacted with the remaining H2S according to Equation 3-20 to
produce elemental sulfur and water.
2H2S + 302 * 2S02 + 2H20 (3-19)
2H2S + S02 t 3S + 2H20 (3-20)
The Glaus process is discussed in more detail in Section 7.4.1.3
where its use in natural gas processing is described. In the
Stretford unit, the H2S in the acid-gas is oxidized directly to
elemental sulfur and water by utilizing a vanadium catalyst.
For this analysis, it is assumed that the Stretford unit is used
-206-
-------
TABLE 3-74. SOLVENT BASED PROCESSES
to
o
Typical Treated
Gas Purity
Process
Purisol
Fluor
Selexol
Rectisol
Sulfinol
Developer
Lurgi
Fluor
Allied
Lurgi
Shell
Solvent
N-Methyl-2
pyrrolidone
Propylene carbonate
Dimethyl ether
polyethylene glycol
Methanol
Tetrahydrothiopene
H2S
4 ppra
>4 ppm
4 ppm
3 ppm
4 ppm
CO 2
2-3%
1-2%
2-4%
60 ppm
<0.5%
Attainable Treated
Gas Purity
H2S C02
2 ppm 10 ppm
0.5%
10 ppm
200 ppm
1-1 dioxide (Sulfolene)
plus diisopropanolamine
(DIPA)
-------
for acid-gas cleaning with incineration of the off-gas to remove
hydrocarbons.
After the product gas has been treated for acid-gas removal
by these processes, it must be catalytically methanated to yield
pipeline quality SNG. The methanation reaction was given in
Equation 3-17. This reaction is strongly exothermic, giving off
88,700 Btu/lb-mole. Two important considerations in the design
of the methanator are 1) a heat removal technique to limit the
gas exit temperature to around 850°F and 2) a suitable catalyst to
methanate a feed stream that contains substantial carbon monoxide.
Several possible systems for methanation have been proposed.
The first involves spraying the catalyst on the outside of tubes,
with cooling fluid being circulated inside the tubes. The
synthesis gas passes over the catalyst and undergoes methanation.
The heat of reaction liberated is carried away by the cooling
fluid. Problems have occurred in retaining catalyst activity for
sufficient periods of time. A second method employs a system of
catalytic reactors with intercooling equipment. A major drawback
to this method arises because the location of the intercoolers
changes during startup, shutdown, and periods of reduced gas
flow. A third system utilizes a large recycle stream of cooled
product to increase the heat capacity of the gas stream. This
method has economic ramifications due to the large recirculation
rate of product gas. Methanation reactors have been proposed
which use a fixed or fluidized catalyst bed.
The methanation reaction is a well-known reaction with
widespread use in the ammonia synthesis industry. However, the
coal gasification synthesis gas which must be methanated is
considerably more concentrated with CO and Ha than in any pre-
vious application. Studies are needed to demonstrate the re-
liability of the methanation catalyst. Catalysts proposed for
use contain nickel and molybdenum.
-208-
-------
The SNG product from the methanator contains water which
must be removed to meet pipeline specifications. Technology in
this area is industrially proven and any of several methods are
acceptable, such as glycol absorption. The dry SNG is then
compressed and is available for use, transport, or storage.
Many of the processing units of a SNG-from-coal plant are
new technology and have yet to be industrially proven. In
addition, the water-gas shift reactor and methanation reactor
have not been proven for handling streams with carbon monoxide
and hydrogen content as great as those found in gasification
synthesis gases.
In addition to the processing equipment discussed previously,
both the Synthane and Lurgi facilities require steam and electri-
city. The steam is generally produced on-site with high-pressure
boilers and steam superheaters. These steam production facilities
can be fired by coal or other externally supplied fuel or by
synthetic fuel generated at the facility. The Lurgi facility
considered here is assumed to burn a low-Btu fuel gas produced
on-site. The Synthane facility is assumed to burn char produced
in the gasifier for steam production.
The electricity necessary to operate the facilities can
either be purchased or produced on-site. Electricity generated
on-site is generally produced through the use of turbines and
generators. The facilities 'considered here use this approach:
the Lurgi facility uses gas turbines fired with low-Btu fuel
gas and the Synthane uses steam turbines with steam provided
by the utility boiler.
-209-
-------
3.8.1.2 Input Requirements
Input Requirements are discussed for Lurgi and Synthane
facilities producing 250 million standard cubic feet per day
(250 MMscfd) of high-Btu gas. When necessary to assume values
in order to quantify the inputs, i.e., manpower requirements,
material and equipment needed, capital costs, water requirements,
land usage, or ancillary energy, these assumptions are stated.
The following sections will address each of the above inputs
for the 250 MMscfd facilities.
The inputs and outputs associated with these facilities will
vary somewhat with the characteristics of the coal which is used.
Where necessary, the coal composition used in this analysis is
that shown in Table 3-75 for coal produced near Colstrip, Montana.
This coal is consumed in the gasification processes at a rate
of 24,520 TPD at the Lurgi facility and 21,530 TPD at the Synthane
facility. The composition of the SNG produced by the processes
is shown in Table 3-76. The heat content of the SNG is approximately
950 Btu/scf for each process. The difference in coal feed rates
between the two processes is attributable to differences in pro-
cess efficiency and in the overall mix of products from each
process.
3.8.1. 2a Manpower Requirements
There are two labor phases required for all facilities: the
construction phase and the operating phase. The Bechtel Corpora-
tion has estimated the manpower required for construction and op-
eration of a 250 MMscfd Lurgi high-Btu gasification facility.1
It is assumed that these manpower requirements are roughly the
same for the Synthane high-Btu gasification facility. Table 3-77
presents the construction manpower and the proper timing sequence
^arasso, M., et al. Energy Supply Model, Computer Tape
San Francisco: Bechtel Corporation, 1975.
-210-
-------
TABLE 3-75. COAL ANALYSIS - COLSTRIP, MONTANA
Rosebud County
Fort Union Region
Colstrip Field
Proximate Analysis, 7o
Moisture: 22.3 - 25.6
Volatile: 36.8 - 41.4
Fixed C: 47.7-54.4
Ash: 8.8 - 11.1
Ultimate Analysis, 70
Ash: 8.8 - 11.1
S: 0.8 - 1.2
H : 3.8 - 5.0
C: 62.9 - 70.6
N: 1.0 - 1.1
0: 13.0 - 20.1
Btu/lb (as received): 7,910 - 9,290
Btu/lb (dry): 10,390 - 12,040
Source: Evaluation of Low-Sulfur Western Coal. EPA-650/2-75-046.
May 1975.
-211-
-------
TABLE 3-76. SNG COMPOSITION
Lurgi SNG1 Synthane SNG
Component (Vol %) (Vol %)
2
-------
TABLE 3-77. SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED TO CONSTRUCT A 250 MMscfd COAL GASIFICATION PLANT
Skill
Chemical Engineers
Civil Engineers
Electrical Engineers
Mechanical Engineers
Other Engineers
Total Engineers
Total Designers & Draftsmen
Total Supervisors & Managers
Total Technical
Total Non-Tech (Non-Manual)
Pipefitters
Pipefitter /Welders
Electricians
Boilermakers
Boilermaker /Welders
Iron Workers
Carpenters
Operating Engineers
Other Major Skills
Total Major Skills
Other Craftsmen
Total Craftsmen
Total Teamsters & Laborers
GRAND TOTALS
Source: Carasso, M. , et al. Energy
1
3
4
4
5
1
17
12
3
32
4
0
0
0
0
0
0
0
0
0
0
0
0
0
36
Supply
2
42
49
45
61
17
214
155
41
410
55
49
17
16
7
1
6
10
10
3
119
1
121
23
609
Model,
Year
3
68
79
74
99
27
348
252
67
666
81
4
57
66
61
82
22
289
210
55
554
49
656 1410
234
211
100
18
82
135
129
47
1611
18
1629
316
2692
Computer
503
453
214
38
176
289
277
101
3461
38
3499
680
4782
Tape.
5
27
32
29
39
11
138
100
26
265
19
802
285
258
122
21
100
165
158
57
1969
21
1991
387
2662
San Francisco: Bechtel Corporation, 1975.
-213-
-------
to efficiently build a gasification plant. Table 3-78 represents
the manpower required to operate a 250 MMscfd facility.
3.8.1.2b Materials and Equipment
Table 3-79 lists the major materials and equipment required
to construct a 250 MMscfd gasification plant,
3.8.1.2c Economics
Bechtel's "Energy Supply Planning Model"1 gives the total
capital costs of a 250 MMscfd coal gasification plant as $750^
million (third-quarter-1974 dollars). Bechtel has also estimated
annual utility costs as $1 million. Using the manpower figures
in Table 3-78 and assuming an average annual wage of $15,000,
total operating costs are $9.8 million per year.
3.8.1.2d Water Requirements
Water must be supplied to the gasification facilities to
replace the water lost and/or used in the coal conversion.
The primary source of water loss is evaporation from the cool-
ing tower, evaporation ponds, and processing equipment. Water
is also used in the process. For example, both the gasifier
and the shift converter consume significant quantities of
water in reactions. The make-up water requirements for the 250
MMscfd Lurgi plant are estimated to be 5742 gpm (9262 acre-ft/
yd)2'3 while water requirements for a 250 MMscfd Synthane plant
^arasso, M., et al. Energy Supply Model. Computer Tape.
San Francisco: Bechtel Corporation, 19/5.
2U.S. Dept. of the Interior, Bureau of Reclamation, Upper
Colorado Region, El Paso Gasification Project, San Juan County,
N.M. DES-74-77. 1974.
3Radian Corporation. Characterization of Waste Effluents
From A Lurgi Gasification Plant, Technical Note.Austin, Tex.:
Radian Corp., 1975.
-214-
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TABLE 3-78. MANPOWER RESOURCES REQUIRED FOR OPERATION AND
MAINTENANCE OF A 250 MMscfd COAL GASIFICATION PLANT
Skill Number Required
Chemical Engineers 16
Civil Engineers 4
Electrical.Engineers 2
Mechanical Engineers 6
Other Engineers 1
Total Engineers 29
Total Designers & Draftsmen 3
Total Supervisors & Managers 5
Total Other Technical 19
Total Technical 56
Total Non-Tech (Non-Manual) 46
Pipefitters 28
Electricians 16
Boilermakers 10
Carpenters 7
Other Operators 212
Welders, Unclassified 19
Other Major Skills 83
Total Major Skills 375
Other Craftsmen 46
Total Craftsmen 421
Total Teamsters & Laborers 66
GRAND TOTAL 589
Source: Carasso, M., et al. Energy Supply Model, Computer Tape.
San Francisco: Bechtel Corporation, 1975.
-215-
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TABLE 3-79: SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF A 250 MMscfd COAL GASIFICATION PLANT
Resource Number
Refined Products (Tons) 225
Cement (Tons) 30
Ready Mixed Concrete (Tons) 180,000
Pipe & Tubing (Less than 24" D) (Tons) 45,000
Pipe & Tubing (24" D & Greater) (Tons) 13,000
Structural Steel (Tons) 14,000
Reinforcing Bars (Tons) 3,300
Valves (24" D & Greater) (Items) 2,000
Valves (24" D & Greater) (Tons) 2,000
Steam Turbogenerator Sets (1000 HP) 70
Pumps & Drives (100 HP) (Items) 250
Pumps & Drives (100 HP) (Tons) 2,000
Compressors & Drives (1000 HP) (Items) 23
Compressors & Drives (1000 HP) (Tons) 4,300
Heat Exchangers (1000 Sq. Ft. Surface) 380
Pressure Vessels (!%" Plate) (Tons) 19,700
Boilers (1,000,000 Btu/Hr) 25,000
Source: Carasso, M., et al. Energy Supply Model. Computer Tape.
San Francisco: Bechtel Corporation, 1975.
-216-
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are estimated to be 18,000 gpra (29,036 acre-ft/yr).l These
values, of course, will vary with allowances for water reuse
and conservation designed into any specific facility.
3.8.1.2e Land Requirements
Land requirements for an SNG from coal plants can include
areas for processing equipment, coal storage, solar evaporation
ponds and solid waste disposal. It has been estimated that 165
acres are required for a plant capable of producing 236 x 10s
scf/day of SNG.2 On a 250 x 106scf/day basis, plant land re-
quirements are approximately 175 acres. From The National
Atlas of the United States, the average class A pan evaporation
for the western states is approximately 50 in/yr. With the as-
sumption that true evaporation from a pond saturated with dis-
solved solids is 507e of pan data, 25 in/yr of pond evaporation
is available. Based on 400,000 Ib/hr of liquid wastes to the
evaporation pond, 630 acres of evaporation ponds are required
to handle the liquid wastes of a 250 x,106 scf/day plant in
these states. The total land required, therefore, is approxi-
mately 800 acres.
3.8.1.2f Ancillary Energy
Since the gasification facilities considered in this analysis
will be self-sustaining with process heat and electricity require-
ments generated on-site, the ancillary energy requirements are
zero.
^alfadelis, C. D. and E. M. Magee. Evaluation of Pollution
Control in Fossil Fuel Conversion Processes; Gasification. Section
1; Synthane Process, final report.EPA 650/2-74-009b.Linden,
N.J., Esso Research & Engineering Co., 1974.
2Air Products and Chemicals, Inc. Engineering Study and
Technical Evaluation of the Bituminous Coal Research, Inc. Two-
Stage Super Pressure Gasification Process.Washington:Office
of Coal Research, undated"
-217-
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3.8.1.3 Outputs
The outputs associated with Lurgi and Synthane gasification
facilities are discussed in the following sections. The air,
water and solid waste effluents for the Lurgi facility were
determined from data reported by El Paso Natural Gas for a pro-
posed 288 MMscf/day gasification facility.1'2 This data was
scaled to a 250 MMscf/day facility by assuming outputs were di-
rectly proportional to SNG production. Where process changes
are assumed or data is obtained by analysis of a different fa-
cility, such variations are noted in the text.
The analysis of the Synthane facility is based on laboratory
gasifier data3 as incorporated into the design of a 255 MMscfd
facility.* Data for this facility was scaled to the 250 MMscfd
facility by assuming outputs are directly proportional to SNG
production. Where assumptions were made with regard to this
facility, they are noted in the text.
3.8.1.3a Air Emissions
Cue potential air emission generated by both coal gasifica-
tion facilities is particulate emissions from solids handling
^.S. Department of the Interior, Bureau of Reclamation,
Upper Colorado Region. El Paso Gasification Project. San Juan
County, N.M. DES-74-77.T973T
2E1 Paso Natural Gas Co., Application of El Paso Natural Gas
Co. for a Certificate of Public Convenience and Necessity.Docket
No. CP73-131.El Paso, Tex., 1973.
3M. W. Kellogg Co. Engineering Evaluation and Study of the
Bureau of Mines "Synthane" Process, Draft report.Contract No.
30101374.Unpublished, 1970.
""Radian Corporation. Characterization of Waste Effluents
From A Synthane Gasification Plant, Technical Note. Austin, Tex. :
Radian Corp.,1976.
-218^
-------
operations. The facilities considered here are designed to
minimize these emissions by the following methods:
1) Coal grinding and screening operations are enclosed
and wet scrubbers are used where necessary.
2) Coal piles are protected from wind erosion by wind
barriers and proper pile orientation.
3) Dust suppression sprays are used at coal transfer
points where necessary.
4) Dust suppression and collections systems are used on
all coal storage bunkers and ash locks.
The fugitive dust generated at the facilities is suppressed at
other sources by pavement and surface sprays. Proper maintenance
of these systems should reduce particulate emissions from these
sources to a negligible level.
In addition to these coal handling emissions, the Synthane
facility has a potential of producing emissions from coal dryers.
The dryers may be necessary since the Synthane process will op-
erate more efficiently with a coal of less than 1470 moisture and
the coal may have a higher moisture content (e.g., Colstrip,
Montana, coal ranges from 22.3 to 25.6% moisture). It is as-
sumed for this analysis, however, the the coal is dried by using
the waste heat in the combustion stack gases.1 Therefore, no
additional combustion is necessary and any particulates generated
Associates, Inc. Environmental Impacts. Efficiency,
and Cost of Energy Supplied by Emerging Technologies, Phase z,
Draft final report, Tasks 1-11.HIT-573, Contract No. EQC 308.
Columbia, Md., 1973.
-219-
-------
are assumed to be controlled by a high efficiency electrostatic
precipitator. The emissions, therefore, are negligible.
The gasifier coal lock is a second potential source of air
emissions at these facilities. The coal lock allows introduc-
tion of air into the pressurized gasifier by first being charged
with coal at atmospheric pressure, closing the vessel, pressur-
izing with product gas to gasifier pressure, charging the coal
to the gasifier and then being depressurized. A potential for
air emissions exists when the gas used to pressurize the coal
lock is released during depressurization. However, in most
current plant designs, the gas used in this process is collec-
ted in a holding tank, recompressed and combined with the main
process stream in the gas cooling area. The residual atmospheric
lock gas that is displaced when the next coal charge is intro-
duced is directed to the incineration area for disposal. The
emissions, therefore, are limited to negligible levels.
Process vent and stack gases are another source of air emis-
sions from these facilities. The potential sources of air
emissions within this category are essentially limited to off-
gases from oxygen production and sulfur recovery. The quantity
of contaminants emitted from the oxygen production area is
considered to be negligible for both facilities. As was
discussed previously, the sulfur recovery system in the Lurgi
design consists of a Rectisol solvent adsorption acid-gas removal
process followed by a Stretford sulfur recovery system. In
addition, it is assumed that the sulfur recovery vent gases are
incinerated in order to minimize hydrocarbon emissions. It is
also assumed that this incineration converts all hydrocarbons
to COa and water and all sulfur compounds to SOz, C02 and water.
-220-
-------
The Synthane process uses the Benfield process for acid-gas
removal to reduce the H2S concentration in the SNG to about 3
vppm. The acid gas streams produced by depressurization of the
contaminated condensate and regeneration of the Benfield solution
are sent to a Stretford unit for removal of H2S and recovery of
elemental sulfur. The sulfur content of the acid gases is
reduced to about 1 vppm. The off-gas from the Stretford oxidizer
is combined with the desulfurized gas for disposal by incinera-
tion. This incineration step reduces the CO and hydrocarbons
by 99+7,.
Another possible source of air emissions from these facili-
ties is the cooling towers. The gaseous effluents from the
cooling towers consist of water vapor, entrained water and any
gases that are air stripped from the recirculating cooling water.
The cooling towers at the Lurgi facility are designed to dissipate
1.1 x 109 Btu/hr with a water recirculation rate of 69.9 x 10s
Ib/hr. The cooling towers at the Synthane facility are designed
to dissipate 3.7 x 109 Btu/hr with a water recirculation rate
of 148 x 10s Ib/hr.
The major source of make-up water to the cooling system
is treated oily gas liquor. Since this stream was originally
in intimate contact with unpurified synthesis gas, it can con-
tain any of the synthesis gas constituents as dissolved or sus-
pended compounds. In the gas liquor treating areas the gas
liquor contaminants are removed to very small or trace concen-
trations by separation and stripping processes. Therefore, the
cooling system make-up water should be fairly clean with respect
to dissolved or volatile components. However, 100% contaminant
removal in the gas liquor treating areas cannot be expected and
some air stripping of NH2, H2S, C02 and trace organics and inor-
ganics is possible in the cooling tower.
-221-
-------
As can be seen from the previous discussion, the various
processes used in the gasification train do not produce signifi-
cant quantities of air emissions. The major source of these
emissions, therefore, is the stack gases from production of
steam for process use and electricity generation. As was dis-
cussed previously, the Lurgi facility is assumed to utilize
steam boilers and gas turbines fired by a low-Btu fuel gas
produced on-site. In addition, a fuel gas. fired steam super-
heater and free standing boiler provide high temperature steam
and emergency steam capacity, respectively. Fuel gas is produced
on-site at the rate of 12.2 MMscfh for these purposes. An
analysis of this fuel gas is shown in Table 3-80. Since the
boiler fuel is cleaned fuel gas, no particulate or sulfur
dioxide control methods are required. NOX emissions are con-
trolled by combustion modifications such as low excess air
firing and reduced peak flame temperatures.
The utilities for the Synthane facility are produced by
combustion of gasifier char. This gasifier char is utilized at
a rate of approximately 337,000 Ib/hr as boiler fuel to produce
steam for motive and process uses and for electricity production.
A typical ultimate analysis of gasifier char is given in Table
3-81. Particulate emissions from the combustion of char are
controlled by electrostatic precipitators while sulfur"oxide
emissions are controlled by limestone wet scrubbers. The EPA
criteria pollutants present in the combustion gases are estimated
from EPA emission factors.1
Environmental Protection Agency. Compilation of Air Pollutant
Emission Factors, 2nd ed. , with supplements. AF-42.Research
Triangle Park, N.C., Feb. 1972, April 1973, July 1973, Sept. 1973,
July 1974, Jan. 1975, Dec. 1975, Feb. 1976, April 1977.
-222-
-------
TABLE 3-80. CLEANED FUEL GAS ANALYSIS
Component Vol.
C02 14.83
H2S 0.01
C21U 0.25
CO 17.44
H2 23.25
CIU 5.08
C2H6 0.38
N2 38.51
H20 0.25
Heating Value - 194 Btu/scf (dry basis)
The fuel gas contains a small quantity of naphtha,
TABLE 3-81. ULTIMATE ANALYSIS OF GASIFIER CHAR
wt %
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Ash
55.9
1.0
2.6
0.7
4.0
35.8
100.0
Heating Value - 8700 Btu/lb
-223-
-------
There are also fugitive air emissions at the Lurgi and
Synthane gasification facilities. Fugitive air emissions from
the facilities arise from leaks around pump seals, valves,
flanges, storage facilities, etc. High pressures like those
encountered in many of the processing operations also enhance
fugitive leaks from equipment. For this study it is assumed
that the fugitive emission losses are minimized by use of the
best available control techniques, including mechanical seals
on pumps, vapor recovery systems on storage facilities, etc.
In addition, good maintenance practices help to minimize equip-
ment leaks.
By-product storage losses are calculated using the method
outline in API Bulletin No. 2523* and Compilation of Air Pollutant
Emission Factors. 2 Vapor recovery systems with a 957. recovery
efficiency are assumed to be used for emission control on the
by-product hydrocarbon and ammonia storage vessels. Tables 3-82
and 3-83 list the input parameters for and the result of the
storage emissions calculations for the Lurgi and Synthane facil-
ities .
Estimates of the fugitive emissions from valves and pump
seals are calculated from an emission factor of 0.5 Ib/day for
these pieces of equipment used in refinery services.3 However,
the pump seal emission factors were doubled if the pump handled
'American Conference of Governmental Industrial Hygienists.
Documentation of the Threshold Limit Values for Substances in
Workroom Air, 3rd eoTCincinnati, Ohio, 1971.
2Environmental Protectiona Agency. Compilation of Air
Pollutant Emission Factors, 2nd ed., with supplements.AP-42.
Research triangle Park, N.C., Feb. 1972, April 1973, July 1973,
Sept. 1973, July 1974, Jan. 1975, Dec. 1975, Feb. 1976, April 1977.
3Danielson, John A., comp. and ed. Air Pollution Engineering
Manual, 2nd ed. AP-40. Research Triangle Park, N.C., EPA,
Office of Air & Water Programs, 1973.
-224-
-------
TABLE 3-82. BY-PRODUCT STORAGE EMISSION LOSSES - LURGI
Symbol
W
K
V
P
D
H
AT
Fp
B
m
N
Ff
Liquid density,
Ib/gal
K factor
Tank Capacity,
bbl.
Vapor pressure,
psia
Tank diameter,
ft.
Avg. Vapor space,
ft.
Avg. Daily temp.
change , F
Paint factor
Breathing losses,
Ib/hr
n factor
Yearly turnovers
Working losses,
Ib/hr
Naphtha
6.41
0.024
13,000(2)
5.8
48
20
20
1.0
18.4
3 x 10~*
22.5
52s 1
Tar Oil
7.41
0.023
27,000(2)
1.5
62
25
20
1.0
9.2
3.24 x 1Q-"
22.8
28.1
Tar
8.91
0.019
40,000(2)
M>.5
76
25
20
1.0
6.9
2.76 x 10-"
23.4
17.8
Phenols
8.33
0.019
5,500(2)
•V0.6
36
15
20
1.0
1.6
2.9 x 10'*
23.1
2.9
Ammon ia
7.48
^-0.023
56,000(1)
4.76
90
25
20
1.0
27.8
•V3.2 x 10-*
46.4
299.3
Total Losses,
Ib/hr
M/W factor,
gal/lb-oole
Corrected Loss,
Ib/hr
TOTAL Losses employ-
ing vapor recovery,
Ib/hr
70.5
NA
70.5
3.53
37.3
NA
37.3
1.86
24.7
NA
24.7
1.23
4.5
NA
4.5
0.22
327.1
3.309
86.6
4.16*
*lb/hr of NH3 based on vapors being 96Z NH3
2.74 x W x K x 4
f\
L8°6^ N j w
B " 24 x 1000
Ff- HmPTr"".:. "\ where T
throughput
NA- Not Applicable
Source: Radian Corporation. Characterization of Waste Effluents From A
Lurgi Gasification Plant, Technical Note. Austin, Tex.: Radian
Corp., 1975.
-225-
-------
TABLE 3-83. BY-PRODUCT STORAGE EMISSION LOSSES - SYNTHANE
Symbol B-T-X1
Tar
W Liquid density,
Ib/gal 6.41 8.91
K K factor 0.024 0.019
V Tank Capacity, bbl. 13,000(2) 40,000(2)
P Vapor pressure,
psia 5.8 ~0.5
D Tank diameter, ft. 48 76
H Avg. Vapor space,
ft? 20 25
AT Avg. Daily temp.
change, F 20 20
F Paint factor 1.0 1.0
P
B Breathing losses,
Ib/hr 18.4 6.9
m m factor 3 x 10"* 2.76 x 10"*
N Yearly turnovers 13.6 21.0
Ff Working losses,
* Ib/hr 44.7 15.8
Total Losses, Ib/hr 63.1 22.7
M/W factor, gal/lb-
mole NA NA
Corrected Loss,
Ib/hr 63.1 22.7
TOTAL Losses employ-
ing vapor recovery,
Ib/hr 3.2 1.1
'Benzene, Toluene, Xylene
1 Ib/hr of NH based on vapors being 96%
D 2.74 x W x K x 42, / P \0'«'
24 x 1000 ^14.7-P/
(\
6N / hr
NA - Not Applicable
Corrected Loss - Total Loss x 0.8 x
Source: Radian Corporation. Characti
From A Synthane Gasification
NH
throughput
M
W
erization of
Ammonia
7.48
0.023
56,000(1)
4.76
90
25
20
1.0
27.8
•v-3.2 x 10"*
25.0
104.3
132.1
3.309
35.0
FP
Waste Effluents
Plant, Technical Note.
Austin, Tex.: Radian Corp., 1976.
-226-
-------
high pressure streams and halved if they handled water/hydrocarbon
streams. Table 3-84 lists the adjusted pump seal emission factors,
the estimated number of pumps for each type service and the pump
seal emissions. All pumps are assumed to use mechanical seals.
Table 3-85 lists the valve emission factors, the estimated number
of valves and the valve emissions.
The composition of the fugitive emissions from valves and
pump seals is a mixture of the various streams found in the gasi-
fication plants. No attempt is made to identify or quantify the
compounds present in the fugitive emissions. However, in addi-
tion to the assumptions regarding number and types of valves
and pumps and emission factors for estimating losses, it was
also assumed that the emissions were primarily hydrocarbons.
The actual fugitive hydrocarbon emissions, however, could vary
substantially at an operating gasification facility. The values
reported in Tables 3-83, 3-84, and 3-85 are intended only as an
order of magnitude estimate.
Air emissions from facilities for the storage of NH3 and
the hydrocarbons (Table 3-83) are calculated by using storage
capacity and emissions factors from the Compilation of Air Pol-
lutant Emission Factors1, assuming use of best available control
techniques.
The ability of a gasification process to limit its air emis-
sions to those given above will depend to a large extent on the
prevention of fugitive emissions from pump seals, joints, flanges,
etc. Proper maintenance should allow fugitive emissions to be
controlled.
1Environmental Protection Agency. Compilation of Air Pollu-
tant Emission Factors, 2nd ed., with supplements.AP-42.Research
Triangle Park, N.C., Feb. 1972, April 1973, July 1973, Sept. 1973,
July 1974, Jan. 1975, Dec. 1975, Feb. 1976, April 1977.
-227-
-------
TABLE 3-84. PUMP SEAL EMISSIONS
Type of Stream Number of Emission Factor, Air Emission
Handled by Pump Pumps Ib/day Ib/day
Water/Hydrocarbon
Stream (low pressure) 18 0.25 4.5
Hydrocarbon Stream
(low pressure)
or 48 0.50 24.0
Water/Hydrocarbon
Stream (high
pressure)
Gaseous Stream
(high pressure) 12 1.0 12.0
TOTAL 40.5
TABLE 3-85. FUGITIVE.EMISSIONS FROM VALVES
Type of Service in Number of Emission Factor, Air Emission,
Which Valve is Used Valves Ib/day Ib/day
Gaseous 930 0.486 757
Liquid 1360 0.108 147
TOTAL 904
-228-
-------
Trace Organics
One of the concerns and potential dangers of coal gasification
plants is the trace organics and inorganics that may be emitted.
Literature data concerning the formation and fate of trace organics
and inorganics in coal gasification processes are very limited.
However, limited analogies can be drawn between the gasification
process and the conventional coking and coal combustion processes
to give insight into the identification, quantification, and ulti-
mate face of trace compounds produced in the gasification process.
There are two major sources of the organic materials from
coal processing: those originally present in the coal which
are released through volatilization and those formed by chemical
reaction in the gasifier and associated equipment. A considerable
body of information exists concerning the identity of individual
components in coals, and a significant amount of work has been
done toward defining the products from coal pyrolysis or
thermolysis. However, each coal has a unique composition. As
a result the available data cannot be generalized and applied
for all cases, but must be evaluated in terms of the coal com-
position and the process (reaction and operating conditions)
involved.
Although the molecular composition cannot be specified
precisely, a number of functional groups are found in coal, and
a similar functional group pattern is probably followed in the
plant effluents. In all processes which gasify coal at inter-
mediate temperatures, the gasifier output may contain all of
the products commonly associated with pyrolysis, carbonization,
and coking of coals in addition to oxygenated products associated
with partial combustion. As it is unlikely that gasification
conditions will result in complete conversion of all components,
-229-
-------
the possibility exists that traces of any of the organic compounds
-------
TABLE 3-86.
TOXIC AND HAZARDOUS SUBSTANCES LIKELY TO BE
EMITTED BY INDUSTRIAL BOILERS
Organic Materials
7,12-Dimethyl Benz(a)anthracene
3-methyIcholanthrene
Dib enz ( a, h) an thr acene
Benz (c) phenanthrene
Benz(a)pyrene
Dibenz(a,h)pyrene
Dibenz(a,i)pyrene
Dibenz(c,g)carbazole
Dibenz(a,j)anthracene
Dibenz(a,g)fluorene
Indeno(1,2,3-cd)pyrene
Dibenzo(a,1)pyrene
Benz(a)anthracene
Chrysene
Dibenz (a, c) f luorene.
Dibenz(a,h)fluorene
4-Aminob ipheny1
Benzidine
1-Naphthylamine
4-Nitrobiphenyl
PhenyIhydr az ine
Dibenz(a,i)carbazole
Benz(a)carbazole
Dibenz(c,h)acridine
Picene
Dibenz(a,g)carbazole
Methyl-phenylhydrazine
Dibenz(a,j)acridine
Dibenz(a,h)acridine
Cholanthrene
Benzoquinoldine
Piridine
Acridine
Aniline
Benz(j)fluoranthene
Benz(b)fluoranthene
Dibenz(a)anthracene
Dibenz(a,c)anthracene
Phenol
Benzthiophenes
Dibenzthiophenes
Thiophene
Source: Barrett, R. E., et al. Assessment of Industrial Boiler
Toxic and Hazardous EmissTons Control Needs, Final
Report. Columbus"]Ohio: Battelle Columbus Laboratories,
1974.
-231-
-------
TABLE 3-87. PRINCIPAL COMPOUNDS OBTAINED FROM COAL TAR
Hydrocarbons
Nitrogen Compounds
Oxygen Compounds
Naphthalenes
Acenapthene
Fluorene
Anthracene
Phenanthrene
Chrysene
Pyrene
Fluor anthene
Pyridines
Quinoline
Carbazole
Acridine
Picoline
Phenols
Cresols
Xylenol
Naphthols
Source: Roberts, John D. and Marjorie C. Caserio. Basic
Principles of Organic Chemistry. N.Y.: W. A. Benjamin,
1965.
TABLE 3-88. COMPOUNDS OBTAINED FROM COAL TAR
Benzene
Toluene
Xylenes
Phenols
Cresols
Naphthalenes
Anthracene
Phenanthrene
Thiophrene
Thiophene
Pynole
Pyridine
Quinoline
Source: Morrison, Robert Thornton, and Robert N. Boyd.
Organic Chemistry. 2nd ed. Boston, Mass.:
Allyn & Bacon, 1966.
-232-
-------
Results indicated benzpyrene is present in concentrations ranging
from less than 260 ppm to 18,000 ppm. The combination of mass
spectra and chromatographic data resulting from the above samples
clearly indicated the presence of benz(c)-phenanthrene (potent
carcinogen), benz(a)anthracene (carcinogen), a benzfluoranthene
isomer (possible carcinogen), benz(a)pyrene (potent carcinogen)
and/or benz(e)pyrene, and cholanthrene (carcinogen).
In a study of the effluents from an experimental coal gasi-
fication plant, certain organic components were extracted and
tentatively identified (Table 3-89). The particular distribution
of organic compounds present in raw gasifier gas will depend on
the composition of the feed coal and on the operating conditions
of the gasifier. The range of sulfur and benzene-toluene-xylene
components which might be expected from the Synthane Process are
given in Table 3-90 for six coal feeds.
It should be noted that conclusions as to the ultimate fate
of trace organics in a coal gasification plant depend primarily
upon emissions of particulate tars which high efficiency collec-
tion equipment could control. This discussion, therefore, is
intended to present only the "potential" dangers.
Trace Inorganics
Elements present in concentrations of 0.1 percent (1,000 ppm)
or less are usually referred to as trace elements. The main
source of the trace elements found in coal is the mineral matter
associated with living plant tissues. Table 3-91 lists the trace
element analysis of a typical coal feedstock.
The potential hazards of trace elements present a definite
incentive for determining the ultimate fate of these various
species in coal conversion systems. Unfortunately, very little
-233-
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TABLE 3-89. COMPOUNDS TENTATIVELY IDENTIFIED IN WASTE
EFFLUENTS OF COAL GASIFICATION PILOT PLANT
Restructured
Gas
Chromatograph
Peak
Best Match
Second Best Match
1
2
3
4
5
6
7
Phenol
o-Cresol
m-Cresol
2,5-Dimethylphenol
3,4-Dimethylphenol
2,4-Dimethylphenol
a-Naphthol
Phenol
m-Cresol
o-Cresol
2,6-Dimethylphenol
3,4-Dimethylphenol
3,4-Dimethylphenol
1,2-Dihydroxy-
naphthalene
Source: McGuire, J. M. , A. L. Alford, and M. H. Carter.
Organic Pollutant Identification Utilizing Mass
Spectrometry.Athens, Ga.:Environmental Protection
Agency, Southeast Environmental Research Laboratories,
1973.
-234-
-------
TABLE 3-90. COMPONENTS IN SYNTHANE GASIFIER GAS, ppm
i
N>
W
Ui
H2S
COS
Thiophene
Methyl thiophene
Dimethyl
Benzene
Toluene
thiophene
C8 aromatics
S02
CS2
Methyl mercaptan
Source:
Illinois
No. 6
Coal
9,800
151
31
10
10
340
94
24
10
10
60
Forney, Albert J. , et
in Effluents From the
Report 76.
Kalfadelis,
Fossil Fuel
Pittsburgh
C . D . and
Conversion
Process, Final report.
Wyoming Pitts-
Subbi- Western North burgh
Illinois tuminous Kentucky Dakota Seam
Char Coal Coal Lignite Coal
186
2
.4
.4
.5
10
3
2
1
--
.1
2,480 2,530 1
32
10
-•-
--
434
59
27
6
.
.4
119
5
--
--
100 1
22
4
2
--
33
al. Analyses of Tars, Chars t Gases
Syn thane
, Pa.:
E. M. Ma
Process
Linden
Process, Bureau
Pittsburgh Energy
gee. Evaluation
es; Gasification.
,750
65
13
--
11
,727
167
73
10
--
10
860
11
42
7
6
1,050
185
27
10
--
8
, and Water Found
of Mines Technical Progress
Research Center, 1974.
of Pollution Control in
Section
1 : Synthane
, N.J. : Esso Research & Engineering
Co. ,
1974.
-------
TABLE 3-91. TRACE ELEMENT ANALYSIS OF A TYPICAL COAL FEEDSTOCK
Element ppm by Weight
Antimony 0.3 - 1.2
Arsenic 0.1 - 3.0
Bismuth 0.0 - 0.2
Boron 60.0 - 150.0
Bromine 0.4 - 18.0
Cadmium 0.2 - 0.4
Fluorine 200.0 - 780.0
Gallium 0.5 - 8.0
Germanium 0.1 - 0.5
Lead 1.4 - 4.0
Mercury 0.2 - 0.3
Nickel 3.0 - 30.0
Selenium 0.1 - 0.2
Zinc 1.1 - 27.0
Source: U.S., Dept. of the Interior, Bureau of Reclamation.
El Paso Gasification Project. N.M.: Draft Environmental
Statement"! Salt Lake City: Bureau of Reclamation,
Upper Colorado Region, 1974.
-236-
-------
data on the fate of trace elements in coal processing facilities
have been published. Attari1 has reported some data in connection
with the IGT HYGAS pilot plant. The purpose of this work was to
measure the concentrations of 11 trace elements found in the
solid streams entering and leaving the various stages of the
HYGAS pilot plant.
Because the pilot plant was not operational during the
period when the analytical work was performed, coal and char
samples accumulated over several years of bench-scale research
were used in the analysis. The emphasis of the project was
placed on trace element analytical methods since sampling and
operating criteria of the pilot plant were not involved. The
relative amounts of the trace elements found in the overhead
gas and the spent char from the electrothermal gasifier arc
presented in Table 3-92. The amount of each element assumed to
be in the overhead gas was calculated,by difference. It can be
seen from these data that most of-the Hg, Se, As, Te, Pb and
Cd which entered the gasifier in the coal feed apparently left
the gasifier in the vapor phase. Most of the Sb, V, Ni, Be and
Cr remained in the solid phase.
In addition to this data, analogies may be drawn between a
coal gasification plant and a coal-fired power plant since the
same trace elements are present in the coal and the coal will
pass through an oxidizing atmosphere similar to that present in
a boiler. One such analogy can be drawn from the results of a
material balance for 17 trace elements carried out on a pul-
verized-coal-fired power plant.2 In this study it was found that
1Attari, A. Fate of Trace Constituents of Coal During
Gasification, Final Report.Chicago:Institute of Gas Technology,
1973.
2Kaakinen, John W., Roger M. Jorden, and Ronald E. West.
"Trace Element Study in a Pulverized-Coal Fired Power Plant."
Denver: June 1974.
-237-
-------
TABLE 3-92,
TRACE ELEMENT CONCENTRATION OF COAL
CALCULATED ON RAW COAL BASIS
Trace Gas*
Element Overhead
Hg 96
Se 74
As 65
Te 64
Pb 63
Cd 62
Sb 33
V 30
Ni 24
Be 18
Cr 0
Spent Char
Bottom
(I)
4
26
35
36
37
38
67
70
76
82
100
* The 7o of the trace element in the overhead gas was calculated
by difference as only solid analysis was done.
Source: Attari, A. Fate of Trace Constituents of Coal During
Gasification, Final report.Chicago:Institute of Gas
Technology, 1973.
-238-
-------
alumium, iron, rubidium, strontium, yttrium, and niobium con-
centrations are essentially constant in all outlet ash streams
(fly ash and bottom ash). Copper, zinc, arsenic, molybdenum,
antimony, lead, and the radioisotopes lead-210 and polonium-210
were found in progressively higher concentrations in fly ash
fractions collected downstream of the firebox. These trace
elements were in their lowest concentrations in the bottom ash.
The bulk of the trace elements found in both of these groups
were retained in the solid phase.
The inability to close the mass balances for mercury and
selenium based only on solid and liquid samples suggested that
portions of these two elements existed as vapors and/or very
fine aerosols in flue gas which passed through the sampling
equipment. Also, the enrichment of certain trace elements in
successive fly ash fractions collected in the downstream direc-
tion is probably due to volatilization of these elements or
their compounds in the furnace and their subsequent condensa-
tion or adsorption onto suspended fly ash particles. Natush,
Wallace, and Evans1 likewise reported that the trace elements
arsenic, antimony, cadmium, lead, selenium, and thallium prob-
ably volatilize in the furnace and recondense on small ash par-
ticles as the flue gas cools. .Due to the similarity between a
coal gasification reactor and a power plant boiler, this data
suggests one possible fate of trace elements in a gasification
system. This analogy is limited, however, in that coal fed into
a power plant boiler encounters only an oxidizing atmosphere and
the coal combustion products are either gaseous or solid. In a
gasifier, however, part of the coal is vaporized and leaves the
system while the char which remains enters the combustion zone
at the bottom of the gasifier. In this oxidizing atmosphere,
:Natusch, D. F. S., J. R. Wallace, and C. A. Evans, Jr.
"Toxic Trace Elements: Preferential Concentration in Respirable
Particles." Science 183 (January 18, 1974): 202-204.
-239-
-------
the char is combusted with oxygen in the presence of steam to
produce a gas mixture containing hydrogen which is fed to the
top section of the gasifier. Because trace elements in a Lurgi
gasifier first encounter a reducing atmosphere, then an oxidizing
atmosphere with possible recycle through the reducing atmosphere,
it is difficult to predict the possible distributions of specific
trace elements among the gasifier effluent streams.
Based on the recent studies of trace elements in a coal-
fired power plant1 and in a coal gasification system2, only
limited conclusions can be made as to the ultimate fate of trace
elements in a gasification plant. The HYGAS data cannot neces-
sarily be related to the Lurgi or Synthane gasification system.
Furthermore, the samples analyzed (solids only) were from bench-
scale work, and therefore may not be representative of commercial
scale operation. Nevertheless, it is obvious from these studies
that certain trace elements have a tendency to volatilize while
others tend to remain in the^ ash or char. Data on the volatility
of trace elements in coal as reported by Ruch, Gluskoter, and
Shimp3 are given in Table 3-93.
There seems to be some agreement that portions of the Hg
and Se exist as vapors and/or fine aerosols in the.gas stream.
The gasification data indicate that As, Te, Pb, and Cd volatilize
to some degree and that a portion of the trace elements would
leave the gasifier in the overhead gas stream. Also, the power
1Kaakinen> John W., Roger M. Jorden, and Ronald E. West.
"Trace Element Study in a Pulverized-Coal Fired Power Plant."
Denver: June 1974.
2Attari, A. Fate of Trace Constituents of Coal During
Gasification. Final Report.Chicago:Institute of Gas Technology,
T57T.
3Ruch, R. R. , H. J. Gluskoter, and N. F. Shimp. Occurrence
and Distribution of Potentially Volatile Trace Elements in Coal.
Urbana, 111.:Illinois State Geological Survey, 1974.
-240-
-------
TABLE 3-93. VOLATILITY OF TRACE ELEMENTS IN COAL
i
Ni
Low-Temperature Ash
Retained (>95%) Lost
Ga Cu
Se Pb
As V
Zn Mn
Ni Cr
Co Cd
Be
Hg (up to 90%)
Br (100%)
Sb (up to 50%)
F (untested but
presumed lost)
High-Temperature Ash
Retained*
Zn
Ni
Co
Cu
Pb
B
Cd
Mn
Cr
Be
Ge
Sn
Se (untested
presumed
Lost
Mo (33%)
V (possibly up
to 25%)
but
retained)
* No significant losses observed in coal ash from 300° to 700° C or between results
from whole coal and low-temperature ash or high -temperature ash (~450°C).
Source: Ruch, R. R. , H. J. Gluskoter,
of Potentially Volatile Trace
and N. F.
Elements
Shimp. Occurrence and Distribution
in Coal. Urbana, 11.: Illinois
-------
plant study concluded that Cu, Zn, As, Pb, Mo, and Sb were at
least partially volatilized in the furnace and then condensed
or adsorbed onto suspended fly ash particles.
These data clearly indicate the loss of certain trace
elements during gasification. However, no conclusion as to the
final disposition of all of the trace elements leaving the gasifier
was possible. In addition, the chemical forms in which the trace
elements occurred were not examined in any of the streams.
As can be seen from the previous discussion, the primary
sources of air emissions from the gasification facilities are
combustion and process losses. Tables 3-94 and 3-95 summarize
the sources of air contaminants from a Lurgi and Synthane facility,
respectively. Tables 3-96 and 3-97 summarize emission rates
of the five criteria pollutants along with stack data. In all
cases where a stack was present, a height of 300 ft. and a stack
gas velocity of 60 Fps were assumed.
3.8.1.3b Water Effluents
Data developed by El Paso Natural Gas Company for a proposed
coal gasification plant utilizing a Lurgi gasifier to produce
275 x 109 Btu/day of SNG indicate that 620,000 Ib/hr or 1240 gpm
of wastewater would be produced.* Assuming that the quantity
of wastewater produced is proportional to plant throughput,
approximately 565,000 Ib/hr (1130 gpm) of liquid waste would
be produced by a 250 x 10s scf/day Lurgi gasification facility.
These wastes contain high levels of dissolved solids, hazardous
organic and trace inorganic compounds, and possibly carcinogenic
organic species.
Paso Natural Gas Co. Application of El Paso Natural Gas
Co. for a Certificate of Public Convenience and Necessity.El
Paso, Tex.:El Paso Natural Gas Co., 1973.
-242-
-------
TABLE 3-94. SUMMARY OF GASEOUS EFFLUENT STREAMS -
LURGI COAL GASIFICATION
Waste Stream
Boilers and Turbines Stack Gas
Steam Super Heater Stack Gas
Fuel Gas Heater Stack Gas
Incinerator Stack Gas
Oxygen Production Vent Gases
Water Treating Degasser Vent
Steam and Power Production
Deaerator Vents
Cooling Tower Evaporation
Temperature
°F
300°F
300°F
300°F
300°F
Ambient
Ambient
200°F
Ambient
Pressure
psig
0
0
0
0
0
0
0
0
Contaminants
Particulates
NOX
SO 2
Particulates
NOX
S02
Particulates
NOX
SO 2
Particulates
NOX
S02
None
None
Negligible
H2S
Cooling Tower Drift
Pond Evaporation
Fugitive
Ambient
Ambient
NH3
Dissolved Solids
Trace Elements
Trace Organics
Negligible
H2S
CO
HC
Trace Elements
Trace Organics
Source: Radian Corporation. Characterization of Waste Effluents
From a Lurgi Gasification Plant, Technical Note.
Austin, Texas:Radian Corporation, 1975.
-243-
-------
TABLE 3-95.
SUMMARY OF GASEOUS WASTE EFFLUENTS -
SYNTHANE COAL GASIFICATION
Waste Stream
Temperature Pressure
°F psig
Cooling Tower Drift
Fugitive Emissions
Ambient
Contaminants
Combustion Stack Gases
Sulfur Recovery Vent Gases
Oxygen Production Vent Gases
Cooling Tower Evaporation
200
150
75
Ambient
0 Particulates
Hydrocarbons
CO
SO 2
NOX
Trace Elements
Trace Organic s
0 H2S
CO
0
0 H2S
NH3
Trace Organics
Trace Elements
H2S
NH3
Trace Organics
Trace Elements
H2S
NH3
CO
Hydrocarbons
Trace Elements
Trace Organics
Source: Radian Corporation. Characterization of Waste Effluents
From a Synthane Gasification Plant, Technical Note.
Austin, Texas:Radian Corporation, 1975.
-244-
-------
TABLE 3-96. AIR EMISSIONS OF CRITERIA POLLUTANTS FROM A 250 MMscfd LURGI PLANT
to
Ui
I
Air Emissions (Ib/hr)
Source
Boilers and Turbines
Steam Superheater
Fuel Gas Heater
Incinerator
Storage
Fugitive Losses
TOTAL
Source: Radian
Plant,
Particulate
negligible
negligible
negligible
negligible
—
—
negligible
Corporation.
Technical Nol
SO 2 NOV CO HC
A
248 418 —
34 57 —
8 13
226 161
__ __ 7
__ __ 40
516 649 — 47
Characterization
:e. Austin, Texas
Stack Parameters
Stream Volumetric Velocity
Rate(lb/hr) Flow(ACFM) (fps)
5.7 x 106 1.8 x 106 60
0.31 x 106 0.10 x 106 60
68 x 103 22 x 103 60
1.6 x 106 0.5 x 106 60
7
40
of Waste Effluents From a Lurgi
: Radian Corporation, 1975.
Height Temp.
(ft) (°F)
300 300
300 300
300 300
300 300
50
Gasification
-------
I
N>
TABLE 3-97. AIR EMISSIONS OF CRITERIA POLLUTANTS FROM A 250 MMscfd SYNTHANE PLANT
Air Emissions (Ib/hr)
Source
Combustion Gases
Sulfur Recovery
Storage
Fugitive Losses
TOTAL
Source: Radian
Particulate SO 2
8 3524
—
—
—
8 3524
NOX
5052
—
—
—
5052
CO HC
168 50
8
4
40
176 94
Corporation. Characterization of
Stream
Rate(lb/hr)
3.0 x 10
2.4 x 10
4
40
Stack Parameters
Volumetric
Flow(ACFM)
0.85 x 10
0.61 x 10
—
— -
Waste Effluents From
Velocity
(fps)
60
60
—
— —
Height Temp.
(ft) (°F)
300 200
300 150
50
a Synthane
Gasification Plant, Technical Note.Austin, Texas:Radian Corporation, 1975.
-------
Because of the presence of these hazardous compounds in a
gasification plant's liquid wastes, the facility considered here
is assumed to operate in a "zero liquid discharge" manner. All
potential liquid effluents are either treated for reuse within
the process or sent to evaporation ponds for disposal. Thus,
no liquid effluents are discharged from the boundary limits of
the conversion facility.
The following sections characterize the expected contaminants
contained in these internal liquid streams. The values reported
herein are for the 288 MMscfd Lurgi gasification facility as
proposed by El Paso Natural Gas. The actual quantities for the
250 MMscf facility analyzed here are expected to be somewhat
less but the effluent components should be the same. In addition,
the liquid waste streams within the Synthane facility will be
similar. It should be remembered, however, that the facilities
are designed to produce no liquid discharges and the following
description is of internal waste streams. Table 3-98 shows
the analysis of the raw water used as a make-up to these processes,
Potential liquid effluents within the conversion processes
include:
the oily and tarry gas liquors,
boiler blowdowns,
process condensates,
cooling tower blowdown,
demineralizer and zeolite softener regenerations wastes,
lime softener sludge,
-247-
-------
TABLE 3-98. RAW WATER ANALYSIS
Compounds mg/1
Carbonate Hardness
as CaCOs 211.0
Non-Carbonate Hardness
as CaCOa
Ca**
Mg"1"1"
Na+
HC03"
CDs"
SO*"
Cl"
SiO
pH2 (pH units)
93.0
66.0
9.1
45.0
144.0
0.0
168.0
14.0
11.0
7.8
Source: U.S. Dept. of the Interior, Bureau of Reclamation,
Upper Colorado Region. El Paso Gasification Project.
San Juan County. N.M. , draft environmental statement.
DES-74-77. 1974.
-248-
-------
sewage treatment wastes, and
ash quenching overflow.
Tarry and oily gas liquors are produced by cooling raw
synthesis gas and condensing a portion of the stream's water
content. Both the air and oxygen blown Lurgi gasifiers produce
tarry and oily gas liquors. During the cooling process, soluble
gases present in the synthesis gas, such as C02, CO, H2S and NH3f
dissolve in the condensate stream. Moreover, heavy hydrocarbons,
phenols and trace inorganic compounds present in the synthesis
gas also condense or dissolve in the water stream.
To permit reuse of the water content of the gas liquors
and to recover valuable by-products, the Lurgi process employs
three phases of gas liquor treatment. Separate but analogous
treatment trains are employed for the tarry and oily gas liquors.
The first treatment step employs physical separation vessels
for the recovery of the tars and tar oils present in the gas
liquor. The second treatment step entails extraction with
isopropyl ether of the phenolic compounds. Finally, ammonia and
acid gases are stripped from the gas liquors by steam reboilers.
However, even after treatment, the oily and tarry gas
liquors probably contain small or trace amounts of heavy hydro-
carbons , trace inorganics and dissolved gases. Thus, these
streams still represent potential liquid pollutants and must be
reused within the process or disposed of in the solar evaporation
ponds. In the design, 164,000 Ib/hr of treated tarry gas liquor
is sent to the ash quenching area, about 1,070,000 Ib/hr of
treated oily gas liquor is used as cooling water makeup, and the
remaining 122,000 Ib/hr is sent to the evaporation ponds.
-249-
-------
Another source of internal wastewater is the boiler blowdown.
This blowdown is required to prevent scaling of the boiler tubes.
These streams contain increased levels of dissolved compounds
such as Ca"^, Na+, Mg"4^", SOT, NOj, Cl", and COT. To insure
the clean operation of the process boilers, the concentration of
these ions in the boiler waters is kept well below their satura-
tion levels. Therefore, it is possible to reuse the blowdown
streams elsewhere in the process where higher levels of dissolved
solids can be tolerated.
Boiler blowdown produced from the high and medium pressure
boilers still has enough heat content to produce low pressure
steam upon flashing. The liquid remaining after flashing is
combined with the blowdown from the low pressure boilers and
used as cooling system make-up water. Approximately 228,000
Ib/hr of boiler blowdown is sent to the cooling system. Thus,
the boiler blowdown streams are completely reused within the
process and do not represent liquid effluents.
Besides the tarry and oily gas liquors produced from the
gasification and cooling areas, process condensates are produced
from the gas purification, methanation, dehydration and
compression areas. These condensates are essentially pure water
and are recycled within the process. The gas purification
condensate (103,000 Ib/hr) is reused within the gas liquors. The
condensate from the methanation area (315,000 Ib/hr) is degassed
and combined with the softened water produced in the water
treating area. The condensates produced from the dehydration
and compression area are sent to the cooling system as make-up
water (715 Ib/hr) and to the ash quenching area (535 Ib/hr).
A fourth source of liquid wastes is the cooling tower
blowdown. The cooling water system dissipates heat via evaporation
-250-
-------
of a portion of the recirculating cooling water. To prevent
scaling in the heat exchangers and condensers of the system,
approximately 224,000 Ib/hr of the recirculating water is
removed as blowdown. This stream contains high levels of dis-
solved solids and any other contaminants, i.e., trace organics
and inorganics, present in the cooling system water. Table
3-99 is an analysis of a typical cooling tower blowdown stream.
The cooling tower blowdown is reused in the ash quenching area
and hence does not represent a liquid effluent.
TABLE 3-99. TYPICAL COOLING TOWER BLOWDOWN WATER ANALYSIS
Compounds
Ca^
Mg"1"1"
Na+
Cl"
C02OO
N03~
SO*"
pH (pH units)
mg/1
793
156
975
1,567
7
8
2,416
7.5
A lime softener/clarifier is utilized as the primary water
treatment step in the Lurgi process. This unit reduces the Ca
concentration of the raw< water feed by the mechanism shown in
Equation 5.5-1.
Ca(OH)2 + 2HC03 " + Ca"" + 2CaC034- + 2H20 (5.5-1)
The precipitated CaC03 and any unreacted Ca(OH)2, are removed
from the clarifier in a slurry form. This slurry is sent to
the ash quenching area where it is combined and disposed of
with the quenched ash.
-251-
-------
Ion exchange demineralizers and sodium zeolite softeners
are used in the water treatment area to condition the lime
treated water prior to its use as boiler feed water. Regenera-
tion of these units produces liquid streams concentrated in
dissolved species consisting mainly of Na , Ca , Mg , Cl",
S0<»~, NOs" and C03 = . However, these streams (134,000 Ib/hr)
are not discharged from the Lurgi facility but are sent to the
ash quenching area for further use.
Potable water is produced on-site for in-plant users. The
resultant wastewater (10,000 Ib/hr) is treated and directed to
the cooling system for use as makeup. The plant utility water%
system produces 50,000 Ib/hr of contaminated water which is
treated in API separators before being sent to the ash quenching
area.
The ash quenching area receives wastewaters from many
sources within the Lurgi process, including:
cooling tower blowdowns,
treated gas liquor,
demineralizer and sodium zeolite softener regenerator
wastes,
plant utility water system wastes, and
• dehydration and compression condensate.
These waste streams, approximately 592,000 Ib/hr, are used to
quench the warm gasifier ash. In addition, 108,000 Ib/hr of
water associated with the lime treater sludge is combined with
-252-
-------
the quenched ash. The ash and sludge are separated in a clarifier
with the resultant overflow (530,000 Ib/hr) being sent to the
solar evaporation ponds for final disposal. This stream will
contain any of the contaminants present in the quench water as
well as mineral matter (see Table 3-100) leached from the coal
ash. The exact concentration of the contaminants in this stream
cannot be quantitatively determined, but discharge of this stream
would most likely violate existing water quality standards.
TABLE 3-100. MINERAL CONSTITUENTS OF COAL ASH
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
Source: 0' Gorman, J. V. and P
and Trace Elements in
A1203
CaO
Fe203
K20
MgO
Na20
P205
Si02
S03
Ti02
FeO
. L. Walker,
U.S. Coals.
Jr. Mineral Matter
Pennsylvania State
University, Coal Research Station, 1972.
As was discussed previously with regard to air emissions,
there exists a potential for the production of many different
types of trace organics and trace inorganics at a gasification
facility. These compounds will most likely be found in most of
the internal wastewater streams discussed above. These potential
contaminants are the same compounds as those listed in Section
-253-
-------
3.8.1.3a. As with the air emissions, however, the exact concen-
tration and composition of these compounds in the waste streams
i s unknown.
A summary of the contaminants contained in these internal
liquid waste streams is shown in Table 3-101.
3.8.1.3c Solid Wastes
Solid wastes from the coal gasification plants consist of
1) ash, 2) lime softener sludge, 3) spent shift catalyst, and
4) spent methanation catalyst. In addition the Synthane facility
produces limestone wet scrubber sludge from the SOz control
equipment on the utility boiler.
The ash from the Lurgi facility is from the air and oxygen
blown gasifiers. The Colstrip, Montana, coal fed to these
gasifiers contains about 10% ash. Based on a coal feed rate of
20,190 TPD to the SNG production gasifiers and 4330 TPD to the
fuel gas producing gasifiers, approximately 204,000 Ib/hr of ash
is produced. In addition, approximately 20,700 Ib/hr of unburned
coal is retained with the ash. Therefore, a total of 225,000
Ib/hr of solid wastes is sent to the ash quenching area. Water
is used to cool this ash and it is then returned to the coal
mine for disposal. Approximately 82,000 Ib/hr of water remains
with the ash.
To provide enough energy for the Synthane facility
to be self-sufficient with respect to steam and power needs
a char-fired utility boiler is included. Assuming that all the
ash in the coal leaves the gasifier in the char, approximately
180,000 Ib/hr of ash is produced by the 21,530 TPD of Colstrip,
Montana, coal fed to the gasifiers. It is further assumed that
virtually all the residual" coal in the char is combusted in
-254-
-------
TABLE 3-101. SUMMARY OF LIQUID PHASE EFFLUENT STREAMS
Waste Streams
Contaminants
Gas Liquors Before Treatment
H2S
NH3
Tars
Tar Oil
Phenols
CO
cm
Trace Organics
Trace Elements
Gas Liquors After Treatment
Trace Elements
Trace Organics
H2S
NH3
Boiler Slowdown
Dissolved Solids
Process Condensates
Cooling Tower Slowdown
Negligible
Trace Elements
Trace Organics
Dissolved Solids
Ash Quench Water
Trace Elements
Trace Organics
Dissolved Solids
Mineral Matter
-255-
-------
the utility boiler. This ash is removed as bottom ash and
electrostatic precipitator fly ash. The major constituents of
this ash are oxides of calcium, iron, aluminum, potassium,
titanium, magnesium, sodium and silicon. Other components of
the ash include trace elements and trace organics.
In addition, this utility boiler utilizes limestone wet
scrubbing. The removal of S02 from flue gas by limestone wet
scrubbing produces a sludge containing CaS03-%H20, CaSCV 2H20,
CaCOa, fly ash, and water. The sludge is assumed to be filtered
and settled until a 50 wt. % solids is attained. An analysis of
the limestone scrubber sludge is given in Table 3-102. The
scrubber is designed to reduce the S02 concentration of the re-
sulting stack gas to the national new source standard of 1.2 Ib
S02/MM Btu and remove 99% of the inlet fly ash. This solid waste
effluent is at ambient temperature and pressures.
TABLE 3-102. COMPOSITION OF LIMESTONE SCRUBBER SLUDGE
Ib/hr wt70
CaS03*%H20
CaSO,,-2H20
CaC03
Ash
H20
34,100
16,300
3,600
780
54,800
109,580
31
15
3
1
50
100
Another potential source of solid wastes is the lime-soda
water softener. Based on the raw water analysis given in Table
I i
4-9 and the ability to reduce the Ca concentration to 30 ppm
by lime treating, 500 Ib/hr of CaCOs are produced in the lime
softener. This solid waste will also contain a small amount of
suspended solids removed from the raw water and any excess lime
used in the treater. At the Lurgi facility these solids are
transported in slurry form to the ash quenching area where they
-256-
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are combined and disposed of with the gasifier ash. In the
Synthane facility, however, this potential effluent is directed
to the limestone wet scrubber as a partial source of makeup
alkalinity. If this is not possible or if a different type
scrubber is employed for flue gas cleanup, the softener sludge
becomes a waste effluent.
The final major source of solid wastes at the gasification
facilities is spent catalysts. In these processes, the shift
and methanation reactors employ catalysts to achieve rapid
chemical reaction. Periodically it is necessary to put new
catalyst into service and dispose of the spent catalyst. However,
the frequency of these replacements and the quantities of
spent catalyst involved depend on several factors including
operating conditions, type of catalyst, number of system upsets,
etc. Therefore, the quantity of solid wastes resulting from
catalyst replacement cannot be ascertained at this time, but
provisions should be made for catalyst disposal.
As was discussed previously, virtually all of the solid
wastes generated by these facilities will be handled on-site
either by settling ponds or coal mine disposal. A summary of
the contaminants contained in these wastes from a Lurgi and
Synthane facility are shown in Tables 3-103 and 3-104.
3.8.1.3d Noise Pollution
The gasification facilities considered here will probably
be located in remote areas and on sufficient land to minimize
any noise problems at the property line. In one case, however,
noise has been found to be excessive at a SNG plant.1 Noise
aShaw, H. and E. M. Magee, Evaluation of Pollution Control
in Fossil Fuel Conversion Processes; Gasification.Section 1:
Lurgi Process. Final report.EPA 650/2-74-009c.Linden, N.J.:
Exxon Research & Engineering Co., 1974.
-257-
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TABLE 3-103. SUMMARY OF SOLID PHASE EFFLUENTS -
LURGI
Waste Stream
Temperature Pressure
°F psig Contaminants
Wet Gasifier Ash
Ambient
Minerals
Dissolved Solids
Trace Elements
Trace Organics
Lime Softener Sludge
Spent Catalyst
Ambient 0 CaC03
Ca(OH) 2
Ambient 0 Cobalt
Molybdenum
Vanadium
Nickel
TABLE 3-104. SUMMARY OF SOLID WASTE STREAMS -
SYNTHANE
Waste Stream
Utility Boiler Ash
Limestone Wet Scrubber Sludge
Spent Catalysts
Temperature
°F
350
Ambient
Ambient
Pressure
psig
15
15
15
Contaminants
Trace Elements
Trace Organics
Mineral Matter
Trace Element
-258-
-------
control mechanisms which can be utilized if necessary are as
follows: any gas fired turbines should be enclosed and air
and exhaust systems adequately muffled; sound reducing insulation
should be placed on piping where needed; sound reducing panels
and walls should be used in buildings where coal crushing and
screening occurs; incinerators and boilers should be designed
to minimize combustion noise. By utilizing these measures,
where necessary, the noise problem will be minimal.
3.8.1.3e Occupational Health and Safety
The possible adverse health effects of the gasification
facilities are primarily caused by the presence of toxic com-
pounds. As was discussed in Sections 3.8.1.3a and 3.3.1.3b
there are many toxic and/or potentially carcenogenic compounds
present in the various streams. These compounds are primarily
found in the waste streams and originate from the organics
contained in the coal. As was discussed previously, however, the
exact composition of these streams and concentration of these
compounds is presently unknown. It is assumed that any adverse
health effects caused by the presence of these compounds will
be minimized by proper maintenance and minimized contact with
oily wastes and other effluents. In addition, since the plants
are operated on a zero liquid discharge manner, solid wastes
are disposed of at the mine and stack gases are subjected to
cleaning, the adverse health effects to surrounding areas
will be minimized.
Another potential source of toxic compounds at the facili-
ties are the toxic inorganic gases present. These compounds
include the H2S from the acid-gas removal and sulfur recovery
processes and the ammonia from the gas liquor treating processes.
Although these compounds are highly toxic it is assumed that
-259-
-------
adequate precautions are incorporated into the facility design
to minimize the potential exposure of personnel to toxic levels.
The other potential health and safety problems which exist
at the coal gasification facilities are those which exist at
virtually every chemical processing facility. These include
the potential for burns resulting from occurances such as contact
with hot processing equipment, steam or combustion gases and the
potential for accidents such as falls, etc.
Data on injuries, deaths, and man-days lost at these
facilities are available from Battelle.1 Converting from
Battelle's basis of 106 Btu to a 250 MMscfd plant yields the
following expected annual values: 0.45 deaths, 15 injuries,
and 4,200 man-days lost.
3.8.1.4 Summary
Table 3-105 and Table 3-106 present a summary of the
direct impacts associated with 250 MMscfd Lurgi and Synthane
coal gasification facilities at Colstrip, Montana. Although
these impacts will vary somewhat from location to location due
to the type of coal used, meteorological conditions, etc., they
are not expected to vary significantly between various, sites in
the western states.
1Battelle-Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. EPA
Contract No. 68-01-0470.Columbus, OH., 1973.
-260-
-------
TABLE 3-105. SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
LURGI COAL GASIFICATION PLANT AT COLSTRIP, MONTANA
Input Requirements
Manpower
construction
operating
Materials and Equipment
• structural steel
• piping
• ready mixed concrete
Economics
• capital costs
• operating costs
Water
Land
Ancillary Energy
10,781 man-years
589 men
14,000 tons
58,000 tons
180,000 tons
$750 million
$ 9.8 million
9,263 acre-ft/yr
800 acres
None
Outputs
Air Emissions
• particulates
• S02
' N°x
• HC
• CO
Water Effluent (plant)
• to ash ponds
• to evaporation ponds
Solid Wastes
• ash
• water treatment sludge
• spent catalyst
Noise Pollution
Occupational Health and Safety
• fatalities
• accidents
• man-days lost
negligible
516 Ib/hr
495 Ib/hr
953 Ib/hr
negligible
310 gpra
820 gpm
225,000 Ib/hr
500 Ib/hr
intermittent
negligible
0.45 deaths/yr
15 injuries/yr
4,200 man-days/yr
aThird-quarter 1974 dollars
-261-
-------
TABLE 3-106.
SUMMARY OF IMPACTS ASSOCIATED WITH A 250 MMscfd
SYNTHANE COAL GASIFICATION PLANT AT COLSTRIP, MONTANA
Input Requirements
Manpower
• construction
• operating
Materials and Equipment
• structural steel
• piping
• ready mixed concrete
Economicsa
• capital costs
• operating costs
Water
Land
Ancillary Energy
10,781 man-years
689 men
14,000 tons
58,000 tons
180,000 tons
$750 million
$ 9.8 million
29,036 acre-ft/yr
800 acres
None
Outputs
Air Emissions
• particulates
S02
• NO*
HC
CO
Water Effluent (plant)
• to ash ponds
to evaporation ponds
Solid Wastes
• ash
• limestone sludge
• spent catalyst
Noise Pollution
Occupational Health and Safety
• fatalities
• accidents
• man-days lost
8 Ib/hr
3524. Ib/hr
5052 Ib/hr
1047 Ib/hr
176 Ib/hr
310 gpm
820 gpm
180,000 Ib/hr
110,000 Ib/hr
intermittent
negligible
0.45 deaths/yr
15 injuries/yr
:4,200 man-days/yr
aThird-quarter 1974 dollars
-262-
-------
3.8.2 Liquefaction
3.8.2.1 Technology Description
3.8.2.la Overview
Liquefaction is a conversion process that is designed to
produce synthetic hydrocarbon liquids from coal. The growing
divergence between domestic crude oil supplies and the domestic
demand for liquid fuels and feedstocks has renewed interest in
the development of technically and economically feasible means
for converting coal to environmentally acceptable liquid fuels.
Coal liquefaction is not a new technology but dates back to the
early part of the twentieth century, and in principal even fur-
ther than that.
During the nineteen-twenties and thirties, extensive re-
search into the hydrogenation of coal was performed in Germany.
German interest in liquid fuels stemmed from the fact that the
nation had extensive coal reserves but no domestic petroleum.
The United States Department of the Interior conducted small
scale feasibility studies of the German technology but these
efforts were abandoned with the East Texas oil discovery in 1930.
In 1944, during the latter part of the second World War,
interest in coal liquefaction in the United States was renewed.
In that year the Synthetic Fuels Act provided sixty million
dollars to fund studies through 1955. Again, another large oil
discovery, this time in the Middle East, reduced interest in
liquid fuels from coal.*
Associates, Inc. Technology and Environmental
Overview: Coal Liquefaction. Draft Final Report, for U.S.
Environmental Protection Agency, Contract No. 68-02-2162.
Columbia, Maryland: Hittman Associates, 1977. p. 4.
-263-
-------
With the entry into an era of declining petroleum reserves,
reduced discoveries, and escalating prices, coal liquefaction
technology has once more assumed a major role as a potential
solution to the liquid fuels problem.
The primary objective of coal liquefaction processes is
to reduce the level of impurities and increase the hydrogen to
carbon ratio of coal to the point that it is fluid. Coal has
a hydrogen to carbon molar ratio of 0.8 to 1, while crudes and
fuel oils have hydrogen to carbon molar ratios of 1.6 to 1 or
greater. The essence of coal liquefaction is, therefore, to
crack the coal molecule and either add hydrogen or remove carbon
to increase the H:C ratio.
Currently there are over twenty coal liquefaction processes
in various stages of development by both industry and federal
agencies. However, these processes can be grouped into four
basic liquefaction techniques.
Indirect Liquefaction
Pyrolysis
Solvent Extraction
Catalytic Liquefaction
Indirect Liquefaction
In the indirect liquefaction process, coal is gasified with
steam and oxygen to produce a synthesis gas of carbon monoxide
and hydrogen. These gases are purified and then reacted in the
presence of catalyst to produce liquid products. Fischer-Tropsch
and methanol synthesis are two examples of indirect liquefaction.1
1National Research Council. Assessment of Technology for the
Liquefaction of Coal. Committee on Sociotechnical Systems, National
Research Council.Washington B.C.: National Academy of Sciences.
1977. Ch. 4.
-264-
-------
While indirect liquefaction is the only liquefaction process
practiced on a commercial scale, it does not appear promising for
production of liquid fuels. The indirect liquefaction process
requires complex plants with high capital costs. Also, thermal
efficiencies are low (approximately 40 to 45 percent). Advantages
of the indirect liquefaction process are that it performs equally
well on any coal, there is a high degree of product control, it
produces very clean fuels, and it has been demonstrated on a
commercial scale outside the United States.1
Pyrolysis
In the pyrolysis process, the hydrogen to carbon ratio in
the conversion products is increased by the removal of carbon.
pyrolysis involves heating coal in the absence of air or oxygen
to temperatures exceeding 400°C. At these temperatures the coal
is cracked and converted to liquid and gaseous products high in
hydrogen, and to char, a product containing almost no hydrogen.
Char is primarily composed of carbon and ash.2
Of the pyrolysis processes, only the Lurgi-Ruhrgas process
has reached the point of commercial development. The COED
process has been developed through the pilot scale, and the
Occidental process has been developed on a very small pilot scale.
Although these pyrolysis processes have several distinct
advantages, they do not appear attractive for the large scale
production of liquid fuels. Advantages of the pyrolysis process
are that it operates at low or atmospheric pressure, it is
3
National Research Council. Assessment of Technology for the
Liquefaction of Coal. Committee on Sociotechnical Systems,
National Research Council. Washington D.C.: National Academy
of Sciences. 1977. Ch. 4.
2JJbid.
3 Ibid.
-265-
-------
unnecessary to supply hydrogen, a synthesis gas, or oxygen to
the process, the reaction times are relatively short, and the
equipment is simple with a relatively low capital cost. Some
of the significant disadvantages of the pyrolysis process are that
only about one-third or less of the coal is converted to liquids,
much of the liquid is very heavy and not easily separated from
the char, the liquids will require hydrogenation to produce
environmentally acceptable fuels, and there is a very uncertain
market for the high volume of char produced in the process.l
Solvent Extraction
The solvent extraction coal liquefaction processes use a
solvent generated in the process to transfer externally produced
hydrogen to the coal. Pulverized coal is dissolved and reacted
with the process derived donor solvent at approximately 752°F to
932°C and at pressures of 500 psi or more. The donor solvent is
capable of transferring relatively loosely bound hydrogen atoms
to the coal, maximizing the fraction of coal going into solution.
Solvent extraction processes differ primarily in the location of
hydrogen addition. Hydrogen may be added before or after extrac-
tion. The hydrogen required by the solvent extraction process
may be made from the gasification of unconverted coal (char),
gaseous products, raw coal, or a combination of the above.
Solvent extraction processes have been developed through the 50
ton per day of coal pilot plant scale.2
Major advantages of the solvent extraction processes include
high product yields (2 to 2.7 bbl/ton of coal), indifference
to coal quality, flexibility of product slates, and substantial
National Research Council. Assessment of Technology for the
Liquefaction of Coal. Committee on Sociotechnical Systems,
National Research Council. Washington D.C.: National Academy
of Sciences. 1977. CH. 4.
2 ibid.
-266-
-------
sulfur removal. Disadvantages of the solvent extraction process
include problems with the separation of ash and unconverted coal
from the liquid products, a solid product which is very friable
and difficult to handle with conventional equipment, and limited
knowledge about the preheating and handling of coal-solvent
slurries.l
Solvent extraction processes yielding products which can be
separated with vacuum distillation appear the most promising until
solid-liquid separation devices are perfected for the difficult
conditions of this use.
Catalytic Liquefaction
The catalytic liquefaction process differs from solvent
extraction only in that hydrogen is added to the coal with the
aid of a catalyst. Catalytic liquefaction hydrogenates coal
in a process derived solvent using externally produced hydrogen
in a manner very similar to the solvent extraction process. The
catalyst may be located in a fixed bed or slurried in the donor
solvent with the coal. Currently, catalytic liquefaction processes
are being tested at the 1 ton of coal per day size and at the
3 ton of coal per day size.2
Advantages of the catalytic liquefaction process are its low
operating pressures, short retention time, high degree of product
quality control, and highiliquid yields. However, catalytic
liquefaction also has some significant disadvantages. Separation
of the oil and catalyst from the undissolved 'coal and ash proves
to be a very difficult problem at the elevated temperatures and
National Research Council. Assessment of Technology for
the Liquefaction of Coal, Committee on Sociotechnical Systems,
National Research Council. Washington, D.C.: National Academy
of Sciences, 1977, Chapter 4.
2 Ibid.
-267-
-------
pressures of the process. A second major problem is fouling
and deactivation of the catalyst due to char and trace elements
associated with the coal. Currently catalyst life is very short.
3.8.2.1b Description of SRC Technology
Solvent extraction processes and catalytic liquefaction
processes exhibit the highest combination of thermal efficiency
and liquid products yield. However, among these two technologies,
solvent extraction appears to have the fewer engineering hurdles.
Of the solvent extraction processes currently being developed,
the Solvent Refined Coal (SRC) process has been demonstrated on
the largest scale. Based on this information, the SRC process
was selected to characterize the inputs and outputs from a coal
liquefaction process.
Development Status1
The early work on the solvent refining of coal in solution
under hydrogen pressure was carried out by A. Pott and H. Broche
in Germany in the 1920*s. The Pott-Broche process was utilized
in Germany during World War II to manufacture a raw material for
aluminum plant electrodes.
During the 1950's, research and development work on a modi-
fication of the Pott-Broche process was carried out by Spencer
Chemical Company. In 1962, the Office of Coal Research (O.C.R.)
awarded a research contract to Spencer Chemical to evaluate the
technical feasibility of the Solvent-Refined Coal (SRC) process
as it was then termed. This contract was concluded in 1965 upon
Huffman, Everett L. "Operations at the Wilsonville SRC
Plant," presented at the Third Annual International Conference on
Coal Gasification and Liquefaction.Pittsburgh, Pennsylvania:
University of Pittsburgh.August 1976. p. 2.
-268-
-------
the successful completion of the demonstration of the process in
a 50 pound per hour continuous-flow process development unit.
During the currency of this contract, Gulf Oil Corporation acquired
Spencer Chemical Company and reassigned the SRC project to the
Research and Development Department of The Pittsburgh and Midway
Coal Mining Company (P&M).
In 1966, O.C.R. awarded a 9.5 year contract to P&M to
continue research and development of the SRC process. This
contract provides for a study of the commercial feasibility of
the process through design, construction, and operation of a
pilot plant to process 50 tons of coal per day.
The Stearns-Roger Corporation completed the design of the
pilot plant in 1969. A shortage of funds delayed the start of
construction until 1972, when a contract for the detailed engi-
neering and construction of the pilot plant was awarded to Rust
Engineering Co. of Birmingham, Ala. Field construction was
underway in July, 1972, with completion and preliminary start-up
in mid-October, 197A. Studies are now being carried on at this
pilot plant in Ft. Lewis, Washington.
A joint SRC pilot plant program is also being conducted by
the Edison Electric Institute and the Southern Company system to
study the key steps in the SRC process. The 6 ton per day plant
was built on the site of the Alabama Power Company's Ernest C.
Gaston Steam Plant located near Wilsonville, Alabama.
Catalytic, Inc. designed, built, and is operating this
pilot plant which began operation in 1974. The Electric Power
Research Institute and the U.S. Energy Research and Development
Administration have now assumed joint sponsorship of the pilot
plant operation.
-269-
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Design Parameters
A process flow diagram for the SRC-II process is presented
in Figure 3-27. The SRC-II process is a second generation SRC
process designed to maximize the production of liquid fuels.
The plant size selected for this study has an output equivalent
to the output of a 100,000 barrels per day (bpd) oil refinery
on a Btu basis. The raw coal feed rate for this size facility
is approximately 30,000 tons per day (tpd).l
The SRC plant is also designed to be relatively selfsuffi-
cient with respect to utilities and hydrogen supply. Selfsuffi-
ciency will be required for conversion plants located at remote
western coal fields. A gasification unit is included for the
production of process hydrogen from char and undissolved coal in
the vacuum bottom residue. A utility boiler is provided to sup-
ply steam demands, and a raw water treatment plant is included
for producing process water. The low quality fuel gas produced
by the SRC process is applied internally to the production of
process heat.
The primary portion of SRC-II information presented in this
technology description has been developed from published informa-
tion on the Ft. Lewis Washington SRC pilot plant. The Ft. Lewis
plant has a capacity of 50 tons per day of coal and has operated
successfully since 1974. However, this facility is not a com-
pletely integrated SRC coal conversion plant. Vacuum bottom gas-
ification is not being conducted at this pilot plant. Consequent-
ly, some of the published information used in this report is
based on either engineering designs of a commercial scale SRC
B.K., D.M. Jackson. "Recycle SRC Processing for
Liquid and Solid Fuels." Fourth Annual International Conference
on Coal Gasification, Liquefaction, and Conversion to Electricity,
Pittsburgh, Pennsylvania:-University of Pittsburgh.August 1977.
P- 5.
-270-
-------
OAS PURIFICATION
• SHIFT CONVERSION
• ACIO QAS REMOVAL
•DEHYDRATION
SULPHUR
RECOVERY
PLANT
TAIL
QAS
TREAT
TAIL
OAS
-— CONDENSATES
Mj RECYCLE
OXY
8TE
HAW J
COAL V
^11'
f 1 * '
ASH CO] CONDEMSATES
OASIFIER
HEN »
AM «•
LJ u
IT i
SLAG *
n
f,
X
FLJ. til
1 SLURRY
COAL *" '*"•
V^^^X
HEATER
FLUE
QAS
COAL
SLURRY
|"J* _
ACID
GAS
REMOVAL
LIOH
END
VAPOR/LIQUID
SEPARATION
' (
f ~^
DISSC4.VER
COAL u
FLUE OAS SLURRY 5
A '
X
« FUEL
OISSOLVER
HEATER
SOLVENT/SLURRY RECYCLE
MINERAL RESIDUE SLURRY
t 6
J e
STILLATt
O
n
LIOHTENOS _ f\
-" y
^
T OAS
> PROCESSING.
_n
I
CONDENSATES
FRACTIONATION
SYSTEM
r~i
Hi/
f\
l_j
- FUEL OAS
> LPQ
. CONOENSATES
FOUL CONDENSATES
Figure 3-27. Example Flow Diagram for a SRC-II Coal Liquefaction Process
-------
facility or on information from comparable processes in both the
coal liquefaction and crude oil refining industry.
Coal Handling
Coal handling operations include all of the activities
associated with receiving, storing, and conveying raw coal prior
to its utilization in the SRC process.
Coal feedstock will primarily be delivered to coal conver-
sion facilities by rail car and by truck; however coal slurry
pipelines are proving a viable alternative for long distance coal
transportation. Coal transport trucks and rail cars are generally
uncovered.l
At the coal receiving facility, the coal is unloaded into
an underground hopper and conveyed by belt conveyer to crushing
operations. Based on current trends, unloading and conveying
operations will be contained in Covered facilities equipped with
dust collectors.2
Most coal conversion facilities will require coal sizes
below 2 inches. To achieve this, the incoming coal is crushed in
two stages and screened to recycle oversized chunks. Occasionally
the primary crushing stage is performed at the mine site. Crush-
ing and screening operations are normally enclosed in a single
^arnsworth, J. Frank, D. Michael Mitsak, and J.F. Kamody.
"Clean Environment with K-T Process." Presented at EPA Symposium
on Environmental Aspects of Fuel Conversion Technology. St. Louis,
Missouri:Environmental Protection Agency.May 1974.
2Jl>id.
-272-
-------
structure equipped with dust collectors.1
Crushed coal is conveyed by covered belt conveyers to active
storage bins. These bins have two or more days storage capacity
and tend to serve largely as surge capacity. Active storage
bins are also enclosed and equipped with dust collectors.2
A large supply of coal is often set aside in dead storage
to be used for emergencies only. The size of this supply is
typically 60 days of feedstock, but can be much smaller. The
dead storage pile is prepared on an impervious base in compacted
layers to an average total height of 25 ft. To seal against
wind and water, dead storage piles are often sprayed with asphalt
.or polymer crusting agents .3
Coal Preparation
Coal preparation consists of drying the raw coal to 3 wt %
moisture and grinding it to a size between 1/8 inch and 200 mesh.1*
The natural moisture content of western coals can range from less
than 4 wt % to approximately 40 wt %. Drying and grinding opera-
tions can be performed either simultaneously in wind-swept mills
or in separate dryers and pulverizers. The drying is effected
JJahnig, C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process.Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company. March 1975.
p. 12.
2Farnsworth, J. Frank, D. Michael Mitsak, and J.F. Kamody.
"Clean Environment with K-T Process." Presented at EPA Symposium
on Environmental Aspects of Fuel Conversion Technology. St. Louis,
Missouri:Environmental Protection Agency.May 1974.
3Jahnig, C.E. op.cit.
*(Ralph M.) Parsons Company. Demonstration Plant Clean
Boiler Fuels From Coal. Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-1234. Los Angeles,
California: Ralph M. Parsons Company. September 1973.
-273-
-------
by contact with flue gas from either the dissolver heater or a
separate heater designed expressly for coal drying. Tight tem-
perature control insures the coal temperature does not exceed
185°F to 195°F, thus preventing devolatilization of the coal.1
Coal is conveyed by belt to the grinding operation. All
subsequent coal conveying is performed pneumatically using re-
cycle nitrogen from the oxygen plant. Nitrogen blankets are also
used on all coal storage bins.2
Drying, grinding and conveying operations are enclosed and
equipped with dust collectors to minimize particulate emissions.3
Coal Dissolution
Prepared coal is conveyed to a slurry mix tank where it is
mixed with infiltered recycle solvent to form a 40 wt % slurry.1*
Pittsburgh & Midway Coal Mining Company. Development of a
Process for Producing an Ashless, Low-Sulfur Fuel From Coal.
Vol III - Pilot Plant Development Work. Part 2 - Construction of
Pilot Plant.Energy Research, and Development Administration, R&D
Rept. 53, Int. 9, FE 496 T2. Fort Lewis, Washington: Pittsburgh
& Midway Coal Mining Company. May 1975.
2(Ralph M.) Parsons Company. Demonstration Plant Clean Boiler
Fuels From Coal. Office of Coal Research R&D Report 82, Int. Rpt.
1, 3 Volumes, Contract No. 14-32-0001-1234. Los Angeles, Cali-
fornia: Ralph M. Parsons Company. September 1973.
3Jahnig, C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process.Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629.
Linden, New Jersey: Exxon Research and Engineering Company.
March 1975. p. 22.
"Huffman, Everett L. "Operations at the Wilsonville SRC
Plant." Presented at the Third Annual International Conference
on Coal Gasification and Liquefaction.Pittsburgh, Pennsylvania:
University of Pittsburgh.August 1976 p. 19.
-274-
-------
The recycling of unfiltered solvent improves product yield and
product quality. These improvements are attributable to cataly-
tic properties of the coal ash and to the reprocessing of undis-
solved organic material.1 Remaining moisture in the coal is
partially evaporated in the slurry mix tank and vented to a
condenser.2
Coal slurry from the slurry mix tank is pressured to 1000
psig-2000 psig and mixed with hydrogen-rich synthesis gas from
the gasifier.3'* After addition of synthesis gas, the coal slurry
is heated in the dissolver heater to temperatures ranging from
700°F to 750°F. At this time the coal is already partially dis-
solved in the recycle slurry "solvent", and the exothermic reac-
tions of hydrogenation and hydrocracking have just begun.5
From the dissolver heater the coal slurry enters the dissolver
where the hydrocracking and hydrogenation reactions continue.
Quench hydrogen must be added to the dissolver to alleviate the
effect of these exothermic reactions, and to maintain dissolver
temperatures in the range of 820°F to 870°F.6
Huffman, Everett L. "Operations at the Wilsonville SRC
Plant." Presented at the Third Annual International Conference
on Coal Gasification and Liquefaction"! Pittsburgh, Pennsylvania:
University of Pittsburgh. August 1976. p . 3.
2Jahnig, C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process. Final Report for U.S.
Environmental Protection Agency.Contract No. 68-02-0629.
Linden, New Jersey: Exxdn Research and Engineering Company.
March 1975. p. 22.
3Ibid.
''Huffman, Everett L., op. cit., p. 19.
5Schinid, B.K., D.M. Jackson. "Recycle SRC Processing For
Liquid and Solid Fuels." Fourth Annual International Conference on
Coal Gasification, Liquefaction, and Conversion to Electricity.
Pittsburgh, Pennsylvania:University of Pittsburgh.August 1977.
p. 8.
6 Ibid.
-275-
-------
During the dissolution and hydrogenation process, large
portions of the oxygen and primarily non-ring organic sulfur in
the coal are hydrogenated to HaO and HaS. A small portion of the
nitrogen in the coal is converted to NHa.l
Product Separation
The dissolver effluent is separated into several product
streams by a series of flash separators and condensers. The
non-condensed gases from this separation consist of unreacted
hydrogen, methane, light hydrocarbons, H2S, and C02. These
gases are sent to the gas processing unit.2
Hydrocarbon liquids and coal-solvent slurry recovered
from the separators and condensers are further separated in a
fractionation system. Atmospheric distillation and vacuum dis-
tillation are used in the fractionation system to separate the
products into a light distillate fraction, a fuel oil fraction,
and a mineral residue slurry. The light distillate fraction and
the fuel oil fraction are low sulfur fuels requiring no further
processing. The mineral residue slurry consists of undissolved
coal, ash, and a very high boiling hydrocarbon fraction. This
product is used for gasifier feed. Prior to fractionation, a
portion of the coal-solvent slurry was withdrawn and^recycled to
the slurry mix tank.3
National Research Council. Assessment of Technology fojr
the Liquefaction of Coal. Committee on Sociotechnical Systems",
National Research Council. Washington D.C.: National Academy
of Sciences. 1977.
2Huffman, Everett L. "Operations at the Wilsonville SRC
Plant." Presented at the Third Annual International Conference
on Coal Gasification and Liquefaction.Pittsburgh, Pennsylvania:
University of Pittsburgh. August 1976. p . 7 .
3rbid.f p. 8.
-276-
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Gas Processing
Noncondensed gases from the product separation processes
are first sent to an acid gas treating unit for removal of H2S
and C02. In the acid gas removal unit, feed gas is first contacted
with diethanolamine (DEA) where the H2S and C02 in the feed gas
are chemically absorbed by the DEA solution. The DEA solution
is subsequently regenerated by distilling or stripping off the
H2S and CO2. The H2S and C02 are then routed to a sulfur
recovery unit.l
Treated gases from the acid gas treating unit are subse-
quently separated in the gas processing unit by using cryogenic
condensation and fractionation. Products from the gas processing
unit include fuel gas, liquid petroleum gases (LPG), and a
hydrogen-rich recycle stream. The hydrogen recycle stream is
returned to the dissolver heater. The low sulfur fuel gas may
be used.for plant fuel or sold as pipeline gas.2
Synthesis Gas Production
The hydrogen-rich synthesis gas required by the SRC process
is manufactured on-site in an oxygen-blown gasifier. Gasifier
feed is expected to be the mineral residue slurry withdrawn from
the product fractionation section. This mineral residue slurry
is composed of undissolved coal, ash, and a very high boiling
hydrocarbon fraction. Normally this stream will be sufficient
C.E. Evaluation of Pollution Control in Fossil Fuel
Conversion Processes: SRC Process.Final Report for U.S. Environ-
mental Protection Agency.Contract No. 68-02-0629. Linden, New
Jersey: Exxon Research and Engineering Company. March 1975. p. 24,
2Huffman, Everett L. "Operations at the Wilsonville SRC
Plant." Presented at the Third Annual International Conference
on Coal Gasification and Liquefaction.Pittsburgh, Pennsylvania:
University of Pittsburgh.August 1976. p. 7.
-277-
-------
to supply gasifier feed requirements. If not the case, under-
sized and oversized coal from the drying and grinding operation
and raw coal can be added to the gasifier feed.l
In the gasifier, the mineral residue slurry is partially
combusted to Ha, CO, H20, HzS, NH3, C02, and minor quantities of
other combustion products. After passing through waste heat
recovery, the gasifier products are processed to form a hydrogen-
rich synthesis gas. Typical gas purification processes include
particulate removal, absorption of H2S, C02, and NH3, water
removal and shift conversion. In the shift conversion process,
CO and H20 are catalytically reacted to form C02 and additional
H2.2
The C02 removed from the gasifier is normally vented to the
atmosphere. The H2S and NH3 are routed to the sulfur recovery
plant. Condensates are sent to a sour water stripper and recovered
coal ash is landfilled with other solid wastes from the plant.3
Auxiliary Facilities'*
Several auxiliary facilities will be required by an SRC
coal liquefaction plant to perform utility and support functions :
• oxygen plant
wastewater treatment
sulfur recovery plant
C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes:SRC Process.Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company. March 1975.
p. 24.
2 ibid.
3Ibid.
"ibid., Ch. 4.
-278-
-------
cooling water system
utility power plant
process water treating
Oxygen for the mineral residue gasifier is supplied by an
on-site oxygen plant. The oxygen plant recovers oxygen and
nitrogen from the atmosphere using cryogenic separation processes.
The nitrogen recovered by the oxygen plant is used to blanket coal
storage and handling operations.
Water effluents generated by condensate systems and collected
from process drains are sent to a wastewater treating facility.
The wastewater treating facility encompasses sour water stripping,
soluble oil removal, and conventional wastewater treatment. The
sour water stripper employs a steam stripping process to remove
HaS and NH3 from wastewaters. The H2S is routed to the sulfur
recovery plant and the recovered NHa is salable as anhydrous
liquid ammonia. Phenolics and cresylics are dissolved in the
wastewater to excessive levels and cannot be treated by conven-
tional biological processes. These oxygenated compounds are
removed from the wastewater by absorption in a lean oil.
All H2S streams generated within the SRC plant are routed
to the sulfur recovery plant where the hydrogen sulfide is
recovered as elemental sulfur. The Glaus process is the most
common process used for sulfur recovery. Residual sulfur in
the tail gas from the sulfur recovery plant is further recovered
in a tail gas treatment unit. The treated tail gas is subse-
quently vented to the atmosphere.
Cooling water for the SRC plant is provided by a conventional
cooling water system. In the cooling water system, cool water is
circulated to plant coolers and condensers where it absorbs
process heat. Warm cooling water is returned to central cooling
-279-
-------
towers where the absorbed heat is released to the atmosphere
by direct contact evaporation. The cooled cooling water is then
recycled to the SRC processes.
The steam required for operating the SRC plant is supplied
by a utility power plant. Fuel needs for the utility power
plant are supplied by combusting the low sulfur fuel gas pro-
duced by the process. Other potential fuel sources include
low sulfur coal or one of the low sulfur SRC fuel oils.
Depending on the quality and end use, raw water for the
SRC plant must go through some degree of treatment in the pro-
%
cess water treating unit. Process water treating often involves
filtering and lime treatment to precipitate hardness. Floccu-
lating agents are sometimes added to promote precipitation.
Treated water is clarified; the sludge is disposed with
gasifier ash and slag. Boiler feed water goes through the
additional clean-up of cation and anion exchange, deaeration
heaters, and additional chemical treatment.
3.8.2.2 Input Requirements
This section reports the input requirements for an SRC-II
coal liquefaction facility sized for a coal feed rate of approxi-
mately 30,000 tons per day. The output from such a facility will
have an output equivalent to a modern 100,000 bpd refinery on a
Btu basis. Table 3-107 lists the estimated product flow rates for
a typical 30,000 tpd SRC-II plant. Information from Gulf Minerals
Co. on their 50 ton per day pilot indicates that general input
requirements will not vary greatly among the various SRC process
designs being developed by Gulf Mineral Resources Co. This trend
-280-
-------
probably holds true for all the various solvent extraction and
catalytic liquefaction processes.1
TABLE 3-107. ESTIMATED NET PRODUCT FLOW RATES FOR A
TYPICAL 30,000 TPD SRC-II PLANT
Products Rate
Pipeline gas (106 scf/d) 36
LPG (bpd) 7,700
Light oil (bpd) 15,600
Fuel oil (bpd) 63,500
Source: Schmid, B.K., D.M. Jackson. "Recycle SRC Processing
for Liquid and Solid Fuels." Fourth Annual International
Conference on Coal Gasification, Liquefaction, and
Conversion to Electricity.Pittsburgh, Pennsylvania:
University of Pittsburgh. August 1977. p. 4.
3.8.2.2a Manpower
Estimated manpower requirements for the construction and
operation of a 30,000 tpd coal liquefaction facility are presented
in Table 3-108 and Table 3-109 respectively. These estimates were
developed by Radian Corporation using Bechtel Corporation's
"Energy Supply Planning Model." The Energy Supply Planning Model
is a computer simulation model developed by Bechtel Corporation
based on the extensive construction experience of their Operating
Divisions. Bechtel Corporation reports that the accuracy of
Schmid, B.K., D.M. Jackson. "Recycle SRC Processing for
Liquid and Solid Fuels." Fourth Annual International Conference
on Coal Gasification, Liquefaction, and Conversion to Electricity.
Pittsburgh,Pennsylvania:University of Pittsburgh. August 1977.
p. 23.
-281-
-------
TABLE 3-108. SCHEDULE OF MANPOWER REQUIREMENTS FOR CONSTRUCTION
OF A 30,000 TPD COAL LIQUEFACTION FACILITY
Manpower
Skill Yr
Chemical Engineers
Civil Engineers
Electrical Engineers
Mechanical Engineers
Other Engineers
Total Engineers
Total Designers & Draftsmen
Total Supervisors & Managers
Total Technical
Total Non-Tech, (non-manual)
Pipefitters
Pipefitters /Welders
Electricians
•Boilermakers
Bo ilermaker s /Weld er s
Iron Workers
Carpenters
Operating Engineers
Other Major Skills
Total Major Skills
Other Craftsmen
Total Craftsmen
Total Teamsters & Laborers
Total Labor Force
1
6
6
6
9
3
33
24
3
60
21
0
0
0
0
0
0
0
0
0
0
0
0
0
81
Yr 2
48
57
51
66
18
237
174
30
438
147
48
15
21
12
3
12
15
9
3
132
30
165
30
780
Source: Carasso, M., et al . The Energy Supply
and Use, Bechtel Corporation,
Requirements (man-years)
Yr 3
1 \
126
147
132
180
48
633
462
78
1173
390
327
108
138
81
15
81
108
54
15
930
219
1149
219
2931
Model,
Final Report to
Yr 4
150
177
159
216
57
759
552
93
1407
468
891
297
372
222
36
222
297
147
36
2523
594
3117
594
5586
Vol.
Yr 5
99
120
105
144
39
507
369
63
939
312
1266
423
528
315
54
315
423
210
54
3585
843
4431
843
6525
Yr 6
54
63
57
75
21 .
270
195
33
498
165
939
312
390
234
39
234
312
156
39
2655
624
3282
624
4569
Yr 7
18
21
21
27
6
96
69
12
177
60
282
93
117
69
12
69
93
48
12
798
189
984
189
1410
I: Model Structure
The National Science
Foundation, Contract No. NSF-C867. San Francisco, California:
Bechtel Corporation, August 1975.
-282-
-------
TABLE 3-109. MANPOWER REQUIREMENTS FOR OPERATION OF A 30,000 TPD
COAL LIQUEFACTION FACILITY
Skill No. of People
Chemical Engineers 22
Civil Engineers 5
Electrical Engineers 2
Mechanical Engineers 10
Other Engineers 2
Total Engineers 41
Total Designers & Draftsmen 5
Total Supervisors & Managers 65
Total Other Technical 30
Total Technical 141
Total Non-tech, (non-manual) 147
Pipefitters 90
Electricians 50
Boilermakers 32
Carpenters 25
Equipment Operators 15
Other Operators 448
Welders, unclassified 60
Other Major Skills 247
Total Major Skills 967
Other Craftsmen 154
Total Craftsmen 1121
Total Teamsters &' Laborers 179
Total Operating Staff 1588
Source: Carasso, M., et ai. The Energy Supply Model, Vol. I;
ModelStructure and Use, Bechtel Corporation. Final
Report to the National Science Foundation, Contract No.
NSF-C867. San Francisco, California: Bechtel Corpora-
tion, August 1975.
-283-
-------
these estimates are approximately -30 percent/+75 percent.1
Table 3-108 indicates that construction manpower require-
ments during the first year's activity will be approximately 80
people, most of whom are engineers, designers and draftsmen.
Manpower requirements rise dramatically the second year and
reach a peak of approximately 6500 people in the fifth year
of construction. Total construction time is estimated to be
seven years.
Table 3-109 indicates that approximately 1600 people are
required for operating a 30,000 tpd coal liquefaction plant.
This total includes 300 technical and nontechnical (non-manual)
people, 1100 craftsmen, and 200 non-craftsmen.
3.8.2.2b Materials and Equipment
Materials and equipment requirements for the construction
and operation of a 30,000 ton per day SRC coal liquefaction plant
are presented in Table 3-110 and Table 3-111 respectively. The
construction material and equipment requirements were developed
by Radian Corporation using Bechtel's "Energy Supply Model"
computer program. The Energy Supply Model is based on the exten-
sive construction experience of their Operating Divisions.
Sechtel Corporation reports that the accuracy of these estimates
^arasso, M., et. al. The Energy Supply Model, Vol I; Model
Structure and Use. Bechtel Corporation.Final Report to the
National Science Foundation, Contract No. NSF-C867. San Francisco,
California: Bechtel Corporation. August 1975. pp. 6-30.
-284-
-------
TABLE 3-110. SELECTED MAJOR MATERIALS AMD EQUIPMENT REQUIRED FOR
CONSTRUCTION OF A 30,000 TPD COAL LIQUEFACTION PLANT
Materials Quantities
Refined Products (tons) 48,000
Cement (tons) 36,000
Ready Mix Concrete (tons) 288,000
Pipe & Tubing (less than 24" D, tons) 60,000
Pipe & Tubing (24" D and greater, tons) 6,000
Structural Steel (tons) 26,000
Reinforcing Bars (tons) 9,000
Valves (24" D & greater, items) 6,000
Valves (24" D & greater, tons) 1,000
Steam Turbogenerator Sets (1000 hp) 300
Pumps & Drives (100 hp, items) 600
Pumps & Drives (100 hp, tons) 5,000
Compressors & Drives (1000 hp, items) 150
Compressors & Drives (1000 hp, tons) 40,000
Heat Exchangers (1000 sq. ft. surface area) 10,000
Pressure Vessels (!%" plate, tons) 45,000
Boilers (10s Btu/hr) 60,000
Source: Carasso, M., et al. The Energy Supply Model, Vol I:
Model Structure and Use, Bechtel Corporation, Final
Report to The National Science Foundation, Contract
No. NSF-C867. San Francisco, California: Bechtel
Corporation, August 1975.
-285-
-------
TABLE. 3-111.
MAJOR MATERIALS REQUIRED FOR OPERATION OF A 30,000
TPD COAL LIQUEFACTION PLANT
Materials
Quantities
Monoethanolamine (Ib/day)
Corrosion Inhibitor (gal/day)
Antifoam (gal/day)
Sodium Hydroxide (Ib/day)
Active Carbon (Ib/day)
Shift Catalyst (ft3/yr)
BSRP CoMo Catalyst (ft3/3 yr)
Sulfur Recovery Catalyst (ft3/3 yr)
Stretford Solution Makeup ($/day)
Corrosion Inhibitor (Ib/day)
Polymer Dispersant (Ib/day)
Sulfuric Acid (Ib/day)
Chlorine (Ib/day)
Phosphate Polymer Antifoam (Ib/day)
Hydrazine (Ib/day)
Lime (Ib/day)
Aluminum Sulfate (Ib/day)
Caustic Soda (Ib/day)
12,000-40,000
150
20-50
1020
150-300
7200
2300
15,000
1200
100
100
10,000
5300
1100
8
6200
3900
6400
Source: (Ralph M.) Parsons Company. Demonstration Plant.
Clean Boiler Fuels From Coal, Office of Coal" Research
R&D Report 82, Int. Rpt. 1, 3 Volumes, Contract No.
14-32-0001-1234. Los Angeles, California: Ralph
M. Parsons Company, September 1973, p. 28.
-286-
-------
are approximately -30 percent/+75 percent.1 Table 3-110 indicates
that construction materials and equipment consist of over 200,000
tons of fabricated steel, 288,000 tons of concrete, and over
50,000 tons of refined products.
The operating materials listed in Table 3-111 were scaled
from a 10,000 tpd coal liquefaction plant design developed by The
Ralph M. Parsons Company. The Ralph M. Parsons design is a de-
tailed preliminary plant designed based upon the research data
collected by Pittsburgh & Midway Mining Company up through 1973.2
No reliability values are available for these estimates.
3.8.2.2c Economics
Capital investment costs for an SRC-II coal liquefaction
plant are presented in Table 3-112. These cost estimates are
developed by Gulf Mineral Resources Co. from conceptual designs
of a 30,000 tpd SRC-II plant.3
The total plant investment cost is estimated to be 1.05
billion dollars. In addition to the normal estimating contin-
gency, a second contingency factor must be applied to account
for these estimates being based on the preliminary design of a
first-of-a-kind system. This contingency will add $100 million
^arasso, M., et. al. The Energy Supply Model, Vol I;
Model Structure and Use. Bechtel Corporation.Final Report to
The National Science Foundation, Contract No. NSF-C867. San
Francisco, California: Bechtel Corporation. August 1975. pp. 6-30.
2(Ralph 11.) Parsons Company. Demonstration Plant Clean
Boiler Fuels From Coal. Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-12334. Los
Angeles, California: Ralph M. Parsons Company. September 1973. p. 1
3Schmid, B.K., D.M. Jackson. "Recycle SRC Processing For
Liquid and Solid Fuels." Fourth Annual International Conference
on Coal Gasification. Liquefaction, and Conversion to Electricity.
Pittsburgh, Pennsylvania:University of Pittsburgh.August 1977.
p. 30.
-287-
-------
TABLE 3-112. CAPITAL INVESTMENT COSTS FOR SRC-II PLANT
(1976 Dollars)
... Cost
Item ($106)
SRC-II Systems
coal preparation 81
hydrogenation/dissolution 276
hydrogen recycle 91
fractionation 22
hydrogen plant 277
gas processing 117
utilities and off-sites 114
general facilities 76
Total Plant Investment 1054
Contingency Cost
<§ 10% 105
@ 20% 211
Other Capital Costs 79
Note: Feed Rate, 30,000 TPD; Product Output, 205 x 1012 Btu/yr.
Source: Schmid, B. K., D. M. Jackson. "Recycle SRC Processing
For Liquid and Solid Fuels," Fourth Annual International
Conference on Coal Gasification, Liquefaction, and Con-
version to Electricity'. Pittsburgh, Pennsylvania:
University of Pittsburgh, August 1977, p. 34.
-288-
-------
to $200 million to the total plant investment. Additional
capital costs including land, working capital, start-up costs,
catalysts, chemicals, and licensing costs will add another $80
million dollars to the total investment cost. Net capital cost
for an SRC-II facility is estimated to be approximately $1.2
to $1.3 billion (in 1976 dollars).1
Operating cost estimates for a 30,000 tpd SRC-II plant are
presented in Table 3-113. The total operating cost and coal
costs were developed by Gulf Mineral Resources Co. based on the
conceptual design of a 30,000 tpd SRC-II plant.2 The operating
cost breakdown was proportioned from operating cost data supplied
by the Bureau of Mines based on the conceptual design of a 34,000
tpd SRC-I plant.3
The data in Table 3-113 indicates that the net annual operat-
ing cost of $302 million is very dependent on the cost of coal.
Plant operating costs excluding coal costs are estimated to be
$83 million per year. At $20/ton, annual coal costs are esti-
mated to be $219 million.
The required selling price of products from an SRC-II plant
is presented in Table 3-114. Again, these costs were developed
by Gulf Mineral Resources Co. based on the conceptual design of
B.K., D.M. Jackson. "Recycle SRC Processing For
Liquid and Solid Fuels." Fourth Annual International Conference
on Coal Gasification, Liquefaction, and Conversion to Electricity.
Pittsburgh, Pennsylvania:University of Pittsburgh.August 1977.
p. 30.
2Ibid., p. 34.
3Bureau of Mines. Preliminary Economic Analysis of SRC Liquid
Fuels Process, Producing 50,000 bpd of Liquid Fuels From Two Coal
Seams: Wyodak And Illinois No. 6.Process Evaluation Group
report for U.S. Energy Research and Development Administration.
Morgantown, West Virginia: U.S. Government Printing Office.
March 1976. p. 31.
-289-
-------
TABLE 3-113. OPERATING COSTS FOR SRC-II PLANT
(1976 Dollars)
Item Cost
($106/yr)
Raw materials and utilities 7
Direct Labor 2
Plant maintenance 33
Payroll Overhead and Operating Supplies 11
Indirect Costs (G&A) 17
Fixed Cost (taxes and insurance) 13^
Plant Operating Costs (excluding coal) 83
Coal Costs ($20/T. dry basis) 219
Net Operating Cost 302
Note: Feed Rate, 30,000 tpd; Product Output, 205X1012 Btu/yr
Sources: Schmid, B.K., D.M. Jackson. "Recycle SRC Processing
For Liquid and Solid Fuels." Fourth Annual International
Conference on Coal Gasification, Liquefaction, ancr
Conversion to Electricity.Pittsburgh, Pennsylvania:
University of Pittsburgh. August 1977. p. 34.
Bureau of Mines. Preliminary Economic Analysis of SRC
Liquid Fuels Process, Producing 50,000 bpd of Liquid
Fuels From Two Coal Seams: Wyodak and Illinois No. 6.
Process Evaluation Group report for U.S. Energy Research
and Development Administration. Morgantown, West
Virginia: U.S. Government Printing Office. March 1976.
p. 31.
-290-
-------
TABLE 3-114. REQUIRED SELLING PRICE FOR INVESTMENT RETURN
(1976 Dollars)
Price - $/10s Btu
Investment Return lO%Contingency 20% Contingency
Constant Dollars (07» escallation)
127, DCF 3.07 3.21
157o DCF 3.55 3.69
Current Dollars (67o escallation)
127« DCF
1570 DCF
2.38
2.69
2.45
2.76
Basis: Equity Funding 1007.
Return on Equity 127o, 1570
Tax Rate 507,
Investment Tax Credit 1070
Life 20 .years
Depreciation Straight Line
Escallation 07o, 6%
DCF - Discounted Cash Flow
Source: Schmid, B.K., D.M. Jackson. "Recycle SRC Processing For
Liquid and Solid Fuels.1' Fourth Annual International
Conference on Coal Gasification. Liquefaction, and
Conversion to Electricity.Pittsburgh, Pennsylvania:
University of Pittsburgh. August 1977. p. 37.
-291-
-------
a 30,000 tpd SRC-II plant. For this study LPG, pipeline gas, and
fuel oil have been valued equally on a Btu basis and no credit
has been applied for the value of sulfur or phenols recovered
from the wastewa,ter.l
While none of these parameters are specifically recommended,
they do indicate that SRC fuels could be available commercially,
following large-scale demonstration, for a cost in the order of
$3/10s Btu. This is equivalent to approximately $18-20/barrel.
3.8.2.2d Water
Water consumption estimates for a typical 30,000 tpd SRC-I
plant range from 15 to 29 million gallons per day.2 Water consump-
tion estimates for a 30,000 tpd SRC-II plant are expected to be
equivalent. A breakdown of water uses is presented in Table 3-115.
TABLE 3-115. WATER CONSUMPTION FOR A 30,000 TPD SRC PLANT
Consumer Consumption Rate
(10s gal/day)
Process water 1
Boiler feed water makeup 2
Potable water 1
Cooling tower makeup 13_
Total 17
Source: (Ralph M.) Parsons Company. Demonstration Plant. Clean
Boiler Fuels From Coal. Office of Coal Research R&D
Report 82, Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-
1234. Los Angeles, California: Ralph M. Parsons Company.
September 1973. p. 27.
B.K., D.M. Jackson. "Recycle SRC Processing For Liquid
and Solid Fuels." Fourth Annual International Conference on Coal
Gasification, Liquefaction, and Conversion to Electricity"! Pitts-
burgh, Pennsylvania: University of Pittsburgh.August 1977. p. 37.
National Research Council. Assessment of Technology for the
Liquefaction of Coal. Committee on Sociotechnical Systems, National
Research Council.Washington D.C.: National Academy of Sciences. 1977
-292-.
-------
These water consumptions are scaled from a 10,000 tpd SRC plant
design developed by Ralph M. Parsons Company. This preliminary
plant design assumes a conventional level of water recycle and
reuse.:
In a study on water conservation and pollution control,
Water Purification Associates determined that net water consump-
tion by unrecoverable systems (i.e., evaporation, dust control,
chemical reaction, etc.) is approximately 3 to 4 million gallons
per day for a 30,000 tpd SRC plant.2 This represents the minimum
water consumption achievable by applying maximum water recycle
and reuse.
3.8.2.2e Land Area
Based on a preliminary plant design, Ralph M. Parsons Com-
pany estimates the minimum land area required to establish a
30,000 tpd SRC plant to be 1050 acres. However, a site of 1800
acres or more is recommended as much more desirable. These
estimates include land area for coal yards and solid waste dis-
posal. 3
3.8.2.2f Ancillary Energy
The ancillary energy requirements for an SRC-II coal lique-
faction facility are highly dependent on the designer's choice
1 (Ralph M.) Parsons Company. Demonstration Plant.
Boiler Fuels From Coal. Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-1234. Los Angeles,
California: Ralph M. Parsons Company. September 1973. p. 27.
2Water Purification Associates. Water Conservation and Pollu-
tion Control in Coal Conversion Processes.Final Report for the
U.S. Environmental Protection Agency, Contract No. 68-03-2207.
Cambridge, Mass: Water Purification Associates. July 1977. p. 106
3(RalphM.) Parsons Company, op.cit.,
-293-
-------
of power sources. In the conceptual design of a 10,000 tpd SRC
plant, Ralph M. Parsons estimated the average electrical energy
consumption to be 76 MW. * The design basis 30,000 tpd SRC-II
plant would consume an estimated 228 MW of electrical power.
This is considered to be a large enough electrical demand to
justify electrical generation facilities on site fueled with
low quality fuel gas.
Gulf Mineral Resources Company in a recently completed con-
ceptual design of a 30,000 tpd SRC-II plant, estimated that
electrical energy consumption would be 41 MW.2 This signifi-
cantly lower electrical energy consumption is attributable to
their use of steam drives where possible. This is a low enough
energy consumption that they would likely purchase this power
from off-site and up-grade their fuel gas to a valuable product.
3.8.2.3 Outputs
The outputs associated with a liquefaction facility are
dependent on site, size, feedstock, processing scheme, and
product mix. The outputs herein developed for this study are
for a hypothetical 30,000 tpd SRC-II coal liquefaction facility
located near Gillette, Wyoming. This facility has an output
equivalent to a modern 100,000 bpd oil refinery on a Btu basis.3
1 (Ralph M.) Parsons Company. Demonstration Plant.
Boiler Fuels From Coal. Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-1234. Los Angeles,
California: Ralph M. Parsons Company. September 1973. p. 21.
2Huffman, Everett L. "Operations at the Wilsonville SRC
Plant." Presented at the Third Annual International Conference
on Coal Gasification and Liquefaction.Pittsburgh, Pennsylvania:
University of Pittsburgh.August 1976. p. 11.
3Schmid, B. K., D. M. Jackson. "Recycle SRC Processing for
Liquid and Solid Fuels", Fourth Annual International Conference
on Coal Gasification, Liquefaction, and Conversion to Electricity.
Pittsburgh, Pennsylvania:University of Pittsburgh, August 1977,
?. 23.
-294-
-------
Table 3-107 lists the estimated product flow rates for this
facility. A Wyoming subbituminous coal from the Powder River
coal field was used for the feed stock. An analysis of Powder
River coal is presented in Table 3-116.
The SRC-II process has been described in Section b of
3.8.2.1. A self-sufficient SRC-II process located in a remote
western coal region will include the following operations:
coal receiving and handling facilities
liquefaction plant
gasification unit
product handling and storage
auxiliary facilities
utilities
cooling water
oxygen plant
sulfur recovery
waste handling
personnel facilities
Air, water, and solid waste outputs are discussed in Sections
a, b, and c respectively. Sludges, slurries, and spent reagents
are included in the solid waste section. Noise emissions are
discussed in Section d, and odor emissions are discussed in
Section e. Section f reviews the general occupational health
and safety aspects of coal liquefaction facilities. And, Section
g reviews the carcinogenic nature of coal derived liquids and its
potential impact on the environment.
-295-
-------
TABLE 3-116. -COAL ANALYSIS FROM THE POWDER RIVER COAL FIELD;
CAMPBELL COUNTY, WYOMING
Component Concentration Range
(wt 7.)
Proximate Analysis
Moisture 30.8 - 33.2
Volatile 39.0 - 47.7
Fixed C 31.8-52.7
Ash 5.0-8.9
Ultimate Analysis
Ash
Sulfur
Hydrogen
Carbon
Nitrogen
Oxygen
5.0
0.3
4.7
45.7
0.6
16.1
- 8.9
- 0.8
- 5.2
- 74.5
- 1.1
- 40.5
Source: Ctvrtnicek, T.E., S.J. Rusek,. and C.W. Sandy. Evalua-
tion of Low-Sulfur Western Coal Characteristics. Utili-
zation, and Combustion Experience.Dayton, Ohio:
Monsanto Research Corporation, May 1975.
-296-
-------
3.8.2.3a Air Emissions
Air emissions from the SRC-II liquefaction process are
primarily attributable to the following processes and operations.
coal yard operations
coal drying and grinding
fuel combustion
sulfur recovery
product storage
fugitive leaks and spills
Although there are other sources of air emissions from a complex
coal liquefaction facility, they are not well defined and are
generally considered small with respect to the major emission
sources which are described here. Air emissions and stack
parameters for the major SRC-II emission sources are presented
in Table 3-117. Explanations of these air emission sources and
references for the emission data are presented below.
Coal Yard Operations
Almost all phases of coal yard operations generate fugitive
dust emissions. Coal yard operations at a coal liquefaction
facility will include such activities as coal receiving, conveying
to storage piles, storage pile maintenance, and conveying from
storage piles to the coal drying and pulverizing operations.
Based on EPA emissions data for aggregate storage pile operation,
-297-
-------
TABLE 3-117. AIR EMISSIONS FROM A 30,000 TPD SRC-II COAL LIQUEFACTION PLANT
.1
to
v£>
C3
I
Emission Rate
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Source.
Coal Yard
Drying and Grinding
Lilsiolver Heater
a
b
c
Distillation Heater
a
b
Gasifler
0: pceheater
Stcara buperheat
Char heater
Char heater
Shift Conversion
Culler 1
Boiler 2
Shift heater
Sulfur Recovery
a
b
Steaa Generation
a
b
c
Storage
Aidioonla
Light oil
Fuel oil
Fugitive
Part
162
200
18
18
18
3
3
0.4
0.3
0.6
O.S
2
2
1
2
2
14
14
14
SO,
-
-
34
34
34
5
5
0.7
0.6
1.0
0.9
4
3
2
23
23
26
26
26
Total
Organic*
-
-
4
4
4
1
1
0.1
0.1
0.1
0.1
0.4
0.4
0.2
0.3
0.3
3
3
3
13
9
1020
(Ibs/hr)
CO
-
-
20
20
20
3
3
0.4
0.4
0.6
O.S
3
2
1
2
2
16
16
16
NO,
-
-
207
207
207
30
30
4
4
6
3
27
21
12
20
20
160
160
160
NHi CO}
-
-
139,000
I 3V ,000
139,000
20,000
20,000
3,000
3,000
4,000
4,000
18,000
14,000
8,000
13,000
13.000
107,000
10V.OOO
107.000
12
Mass Flow
10' Ib/hr
-
200
2200
2200
2200
310
310
50
40
60
60
2BO
220
120
210
210
1700
1700
1700
Vol. Flov
101 acfn
-
(a)
450
450
450
65
65
10
8
13
12
58
45
25
43
43
350
350
350
Stack Parameters
Velocity
.
(a)
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
Height
ft
ground
leval
(a)
200
200
200
200
200
200
200
200
200
200
200
200
200
2CO
200
200
200
50
50
50
5
Temp.
...
450
450
450
450
450
450
450
450
450
450
450
450
200
200
450
450
450
Diameter
ft
(a)
13
13
13
5
5
1.9
1.7
2.1
2.1
5
4
3
4
4
11
11
11
a. These cmlsblan* are vented with the ills solver heater emissions.
-------
emissions for a storage pile in Gillette, Wyoming, would be
approximately 1.3 pounds per ton stored.1 A 30,000 tpd coal
liquefaction facility would consequently have an uncontrolled
coal yard dust emission rate of 1625 pounds per hour. Concerted
dust control efforts can reduce these emissions by as much as
90 percent. Resulting controlled emissions are estimated to be
162 pounds per hour. These emissions are released at ground
level.
Coal Drying and Grinding
The raw coal is dried and pulverized in wind swept mills
to about 3% moisture. Flue gas from the coal dissolver heaters
are used as the drying medium because they represent a readily
available source of low temperature heat. Although combustion
emissions are present in the drying and grinding vent gases,
these are attributable to the dissolver heater and discussed in
the next section. Coal drying temperatures are maintained low
enough that coal devolatilization does not occur.2
A particulate emission factor for fluidized bed coal dryers
of 20 Ib/ton coal is used to determine the particulate emission
rate.3 According to a study by Hittman Associates Inc., coal
drying emissions can be reduced approximately 99.2% by the
^.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. EPA Publication No. AP-42.Research
Triangle Park, North Carolina: U.S. Government Printing Office,
April 1977, p. 11.2.
2Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process, Final Report for U.S.
Environmental Protection Agency,Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company, March 1975,
p. 12.
3U.S. Environmental Protection Agency, op.cit., p. 8.9.
-299-
-------
combined use of cyclones and bag filters.1 Resulting particulate
emissions are 200 -Ibs/hr.
Fuel Combustion
Low heating value fuel gas produced by the SRC-II coal
liquefaction process is used to supply the process heat demand.
Table 3-118 lists expected fuel gas requirements for a 30,000
tpd SRC-II facility based on data from Ralph M. Parsons Company's
conceptual design of a 10,000 tpd SRC plant.2 Steam generation
capacity has been increased and electric power generation
eliminated from the Parson's design since latest plans by Gulf
Mineral Resources Co. are to construct a SRC-II facility that
uses steam drives where ever possible and purchases the remaining
electrical needs (41 MW).3
Combustion characteristics used to calculate air emissions
from the fuel combustion sources are presented in Table 3-119.
Sulfur oxide emission rates were calculated using the refinery
emission standard of 0.10 gr H2S/dry scf of fuel gas. Nitrogen
oxide emissions were assumed controlled to 0.2 lbs/106 Btu
using staged firing.11 Particulate, CO, and hydrocarbon emission
lHittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use, Final Report Vol. I, 1974;
Vol II, 1975.Colombia, Md.:Hittman Associates, Inc., 1974 and
1975, p. VII-10.
2Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes:SRC Process, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company, March 1975,
p. 25.
3Huffman, Everett L. "Operations at the Wilsonville SRC
Plant", presented at the Third Annual International Conference
on Coal Gasification and Liquefaction"Pittsburgh, Pennsylvania:
University of Pittsburgh, August 1976, p. 11.
"Jahnig, C. E., op.cit., p. 12.
-300-
-------
TABLE 3-118. SRC-II PLANT FUEL GAS REQUIREMENTS
(30,000 tpd)
Unit Fuel Requirements
10s Btu/hr
Coal dissolver heaters 3100
Coal liquefaction product distillation 300
Gasification 100
Shift conversion 300
Sulfur plant 200
Steam generation 2400
Source: Jahnig, C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process.Final Report
for U.S. Environmental Protection Agency, Contract No.
68-02-0629. Linden, New Jersey. Exxon Research and
Engineering Company. March 1975. p. 65.
-301-
-------
TABLE 3-119. SRC-II PLANT FUEL GAS COMBUSTION CHARACTERISTICS
Participates
Sulfur Oxides
Carbon Monoxide3
a
Hydrocarbons
Nitrogen Oxides'
15 lb/106 scf
28 lb/106 scf
17 lb/10s scf
3 lb/10s scf
172 lb/106 scf
Heating Value
860 Btu/scf
Flue Gas Volume
13 scf/scf
aSource: U.S. Environmental Protection Agency. Compilation of
Air Pollutant Emission Factors. EPA Publication No.
AP-42.Research Triangle Park, North Carolina. U.S.
Government Printing Office. April 1977. p. 1.4.
Assumes 0.1 gr/dry scf
"Source: Jahnig, C.E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process.Final Report
for U.S. Environmental Protection Agency, Contract No.
68-02-0629. Linden, New Jersey. Exxon Research and
Engineering Company. March 1975. p. 12.
Source: Hittman Associates, Inc. Environmental Impacts,
Efficiency, and Cost of Energy Supply and End Use.
Final Report Vol I, 14M; Vol II, 1975.Columbia, MD.
Hittman Associates, Inc. 1974 and 1975. p. VII-10.
-302-
-------
factors were developed by EPA.l The heating value of plant fuel
gas was estimated by Hittman Associates to be 860 Btu/scf, which
results in a flue gas volume of 13 scf/scf when combusted with
20% excess air. Stack velocities of 60 ft/sec, heights of 200
ft, and temperatures of 450°F were assumed for dispersion
modeling.
Sulfur Recovery
Hydrogen sulfide generated in the coal dissolution and
hydrogenation process is recovered as elemental sulfur in the
sulfur recovery plant. Due to inefficiencies in the sulfur
recovery process, some H2S remains in the tail gas vented from
the sulfur recovery plant. Tail gas cleanup processes will
reduce tail gas emissions to very low levels. Based on the
conceptual design of a 10,000 tpd SRC facility by Ralph M.
Parsons, Exxon Research and Engineering estimated that 0.2% of
the sulfur in the coal feed exited the SRC facility in the treated
tail gas as SC-2.2 These sulfur oxide emissions are combined with
the flue gas emissions from the sulfur recovery plant heaters.
Product Storage
Product and by-product storage capacity is provided on site
to function as surge capacity, allowing continued plant operations
during transportation interruptions. Storage area ammonia
^.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. EPA Publication No. AP-42.Research
Triangle Park, North Carolina: U.S. Government Printing Office,
April 1977, p. 1.4.
2Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes:SRC Process, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company, March 1975,
p. 48.
-303-
-------
emissions were calculated using the EPA emission factors for
ammonia storage and loading operations.1 It was assumed that
40% of the nitrogen entering with the coal was recovered as
ammonia and that 997» emission control was effected by application
of a packed tower scrubber.2
Emissions from fuel products storage were calculated using
EPA emission factors and assuming two weeks storage capacity.3'1*
Product storage capacities are summarized in Table 3-120.
Fugitive Emissions
There are numerous miscellaneous hydrocarbon emission sources
throughout a coal liquefaction facility which are very difficult
to account for individually. However, these sources collectively
are a major contributor to the emissions from a SRC-II plant.
Example fugitive emission sources include waste water drains
and sumps, pump seals, valves, flanges, equipment leaks, and
loading racks. Based on literature data, Radian Corporation
determined that miscellaneous 'hydrocarbon emissions from a
petroleum refinery amount to approximately 0.1 weight percent
^.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. EPA Publication No. AP-42.Research
Triangle Park, North Carolina: U.S. Government Printing Office,
April 1977, p. 5.2.
2Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes; SRC Processes, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company, March 1975.
3U.S. Environmental Protection Agency, op.cit., p. 4.3.
"Hittman Associates, Inc. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use. Final Report Vol. I, 1974;
Vol. II, 1975.Colombia, Md.:Hittman Associates, Inc., 1974
and 1975, p. VII-7.
-304-
-------
of the refinery's capacity.1 Fugitive emissions from the SRC-II
liquefaction facility were assumed to be the same, and calculated
based on the weight of the liquid products.
TABLE 3-120. DESIGN BASIS FOR CALCULATING STORAGE EMISSIONS
Product Pr°dU°n ^^ Storage^Capacity
Light Oil
Fuel Oil
15,600
63,500
218,400
889,000
Floating Roof
Fixed Roof
Trace Elements
Table 3-121 lists many of the trace elements commonly found
in U.S. coals. Some of these elements are highly toxic in one
form or another. It is likely that most of these elements appear
in the products and effluents from the SRC-II process. However
very few of these trace elements form compounds volatile enough
to be present in the air emissions. The most volatile trace
elements are mercury, selenium, arsenic, lead, cadmium, antimony,
fluorine, bromine, boron, and zinc.2 Arsine and metal carbonyls
of some of these trace elements are sufficiently volatile to
be present in even cool fuel gas streams. Therefore, the flue
gas from combustion of plant fuel gas is likely to contain low
levels of these trace elements. These low levels can potentially
be important if the fuel gas combustion rates are high.
1Radian Corporation. A Program to Investigate Various
Factors in Refinery Siting, prepared for The Council on
Environmental Quality and The Environmental Protection Agency.
Austin, Texas: Radian Corporation, February 1974, p. 195.
2Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629.
Linden, New Jersey: Exxon Research and Engineering Company,
Marcy 1975, p. 52.
-305-
-------
TABLE 3-121. TRACE ELEMENT ANALYSIS OF A TYPICAL U.S. COAL
Element
As
B
Ba
Be
Co
Cr
F
Ga
Hg
La
Mn
Mo
Nb
Ni
Sb
Sc
Se
Sn
Sr
Te
Ti
Tl
U
V
Y
Yb
Zr
Source: Burklin, C.E. Characterization
A SRC Coal Conversion Process.
Concentration
(ppm of coal)
2
700
3,000
5
20
60
20
30
0.06
70
300
80
20
30
13
20
0.2
30
7,000
0.04
4,000
<0.2
0.5
200
30
3
150
of Waste Effluents From
Prepared for the Energy
Research and Development Administration. Austin, Texas.
Radian Corporation. 1975. p. 28 .
-306-
-------
Organic Compounds
Trace quantities of organic compounds, particularly poly-
nuclear hydrocarbons , may also be emitted from miscellaneous fugi-
tive leaks and spills. Table 3-122 and Table 3-123 list several
polynuclear and aromatic compounds which have been identified in
SRC products. Many of these compounds have been identified or
are suspected of being carcinogens, even at extremely low
concentrations. Although these compounds are not considered
volatile, they may be present in air emissions from coal lique-
faction processes in potentially significant concentrations.
3.8.2.3b Water Effluents
Although the SRC process produces water, the SRC plant as
a whole is a net consumer of water. Hence, zero wastewater
discharge can be achieved by recycling water effluents after
treatments such as dephenolization, steam stripping, biological
treatment, and thermal sterilization. These treatments are
expensive and consume energy, which increases plant cost and
reduces thermal efficiency. The practice is economically
attractive only in areas where water resources are limited or
effluent water pollution standards are extremely restrictive.
The 40,000 ton-per-day Fischer-Tropsch plant now under construc-
tion in South Africa is designed for zero wastewater discharge.1
There are five major water streams from the SRC processes:
foul condensates, condensates from gas purification, condensates
from the gasifier, condensates from the reformer, and cooling
National Research Council. Assessment of Technology for
the Liquefaction of Coal, Committee on Sociotechnical Systems,
National Research Council. Washington, B.C.: National Academy
of Sciences, 1977, p. 113.
-307-
-------
TABLE 3-122. CHEMICAL COMPOSITION OF SOLVENT FRACTION
Composition
Compounds (wt %)
Aromatics
Benzenes 6
Naphthalenes 8
Tetralins 30
Acenaphthalenes 3
Hydroacenaphthalenes 5
Phenanthrenes and Anthracenes 1
Hydrophenanthrenes 5
Crysenes, Pyrenes, Fluoranthrenes <1
Hydrocrysenes 1
Benzopyrenes <1
Phenols, Resorcinols, Naphtholes 7
Olefins 1
Saturates 2£
98
Source: Given, P. H., et at. The Relation of Coal Character-
istics to Coal Liquifaction Behavior, prepared for
National Science Foundation, NSF/RA/N-74-154. University
Park, PA.: Pennsylvania State University, August 1974.
-308-
-------
TABLE 3-123. CHEMICAL COMPOSITION OF SOLVENT FRACTION
Composition
Compound (wt 70)
Naphthalene 10
2-Methylnaphthalene 8
1-Methylnaphthalene 3
1, 2-Dimethylnaphthalene 9
Acenaphthalene 5
Anthracene and Phenanthrene 17
Carbozole, Fluoranthene, and Pyrene _5
62
Source: Auburn University. Solvent Refined Coal Studies,
prepared by Engineering Experiment Station, Auburn
University, for the National Science Foundation
NSF/RA/N-74-075: Auburn University, 1974.
-309-
-------
tower blowdown. The flow rates of these streams are presented
in Table 3-124. Condensates from the reformer are very clean and
can be used directly for boiler feed water. Condensates from
gas purification and from the gasifier are low in dissolved
solids and organics. These waters can be blended with raw
water and treated for use as either boiler makeup or cooling
tower makeup. Cooling tower blowdown water will have high
levels of dissolved solids (1,500 - 10,000 mg/A) but relatively
low levels of organics. It has been suggested that cooling
tower blowdown will be used for quench and slag slurrying
applications.*
TABLE 3-124. WASTEWATER FLOWS FROM A 30,000 TPD SRC PLANT
Stream Flow Rate
Stream lb/hr
Foul Condensates 500,000
Gas Purification Condensates 500,000
Gasifier Condensates 300,000
Reformer Condensates 300,000
.Cooling Tower Blowdown 900,000
Source: Water Purification Associates. Water Conservation and
Pollution Control in Coal Conversion Processes, Final
Report for the U.S. Environmental Protection Agency,
Contract No. 68-03-2207. Cambridge, Mass.: Water
Purification Associates, July 1977, p. 437.
Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process, Final Report
for U.S. Environmental Protection Agency, Contract No.
68-02-0629. Linden, New Jersey: Exxon Research and
Engineering Company, March 1975, p. 14.
lWater Purification Associates. Water Conservation and
Pollution Control in Coal Conversion Processes, Final Report for
the U.S. Environmental Protection Agency, Contract No. 68-03-2207
Cambridge, Mass.: Water Purification Associates, July 1977,
p. 437.
-310-
-------
The foul condensates are the dirtiest of the wastewaters
and will present the major wastewater disposal problem. Foul
condensates can not be reused nor discarded without extensive
treatment. However, current plans for handling foul condensates
are not well documented. Analysis of foul condensates from Pitts-
burgh and Midway's SRC pilot plant are presented in Table 3-125.
Because the foul condensates have generally been in direct
contact with the coal liquids, they will also contain many of
the trace elements and organic compounds found in the coal liquids,
Of the trace elements commonly occuring in coal (Table 3-121),
mercury, selenium, arsenic, molybdenum, lead, cadmium, berylium,
fluorine, and antimony are most likely to be found in the foul
water systems.1 Table 3-126 lists several polynuclear organic
compounds which have also been identified in typical wastewaters
from coal conversion processes.2 Other polynuclear compounds
which may be present in the foul condensates are listed in
Table 3-122 and Table 3-123.
Another major source of water effluents from the SRC
facility will be coal pile runoff water from heavy rains.
Example analyses of runoff from power plant coal piles are
presented in Table 3-127. These waters are characteristically
very acidic and have high levels of dissolved solids.3 However,
:Jahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629. Linden,
New Jersey: Exxon Research and Engineering Company, March 1975,
p. 32.
2Webb, Ronald G., et al. Current Practices in GC-MS Analysis
of Organics in Water, Final Report for the Environmental Protec-
tion Agency R2-73-277, 16020 GHP. Athens, Georgia: Southeast
Environmental Research Laboratory, 1973, p. 53.
3Burns and Roe, Inc. Steam Electric Power Plants, Develop-
ment for Effluent Limitation Guidelines and Standards of Per-
formance"New York, New York:Burns and Roe, Inc., 1973.
-311-
-------
TABLE 3-125. ANALYSIS OF FOUL PROCESS CONDENSATES FROM PITTSBURG
AND MIDWAY SRC PILOT PLANT
Concentration (mg/g.)
Components Sample 1 Sample 2
Total Carbon 9,000 8,160
Total Organic Carbon 6,600 7,390
Inorganic Carbon 2,400 770
BOD (5 day) 32,500
BOD (15 day) 34,500
BOD (20 day) >34,500
COD 43,600 25,000-30,000
Phenol as C6H5OH 5,000 12,000
Total Kjeldahl N 8,300 15,000
Total Ammonia as N 7,900 14,000
Cyanide as CN 10
Total Sulfur as S 10,500 16,200
Ca 0.47
Mg 0.14
Si <0.5
Source: Water Purification Associates. Water Conservation and
Pollution Control in Coal Conversion Processes,Final
Report for the U.S. Environmental Protection Agency,
Contract No. 68-03-2207. Cambridge, Mass.: Water
Purification Associates, July 1977, p. 267.
-312-
-------
TABLE 3-126. CONCENTRATIONS OF ORGANIC COMPOUNDS IN COAL
CONVERSION PROCESS WASTES
Compound Concentration
rag/fc
Acenaphthene 0.2
n-Butylisothiocyanate 0.5
Carbazole 0.3
Cresol 2.5
2,6-Dimethyl naphthalene 0.015
Dimethyl pyridine 0.2
Ethylisothiocyanate 1-5
Fluoranthene 0.6
Fluorene 0.17
Indene 0.026
Methyl naphthalene 0.03
Naphthalene 0.05
Phenanthrene ! • **•
Phenol °•6
Trimethylpyridine ° •3
Xylene °•°08
Xylenol l •5
Source: Webb, Ronald G., et al. Current Practices in GC-MS
Analysis of Organics in Water, final report for the
Environmental Protection Agency R2-73-277, 1602D GHP
Athena, Georgia. Southeast Environmental Research
Laboratory. 1973. p. 53.
-313-
-------
TABLE 3-127. WATER QUALITY OF COAL PILE RUNOFF
I
co
Coal Pile
BOD
COD
Dissolved
Suspended
NH
NO "
P
Turbidity
Hardness
SO **
Cl~
Al
Cr
Cu
Fe
Mg
Zn
Na
PH
No.
mg/Jl
mg/Jl
Solids mg/Jl
Solids mg/Jl
mg/Jl
mg/Jl
mg/S,
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
mg/Jl
Source: Burns and Roe,
1
0
1,080
720
610
0
0.3
-
505
130
525
3.6
-
0
1.6
0.168
-
1.6
1,260
2.8
Inc. Steam
2
0
1,080
720
610
0
0.3
-
505
130
525
3.6
-
0
1.6
0.168
-
1.6
1,260
2.8
Electric
3
10
806
7,743
22
1.77
1.9
1.2
1,109
5,231
481
-
0.37
-
-
89
2.43
160
3
Power
4
-
85
5,800
200
1.35
1.8
•-
1,850
861
-
-
0.05
-
0.06
174
0.006
-
4.4
5
3
1,099
247
3,302
0.35
2.25
0.23
-
133
23
-
-
'-
-
-
0.08
-
7.8
Plants, Development
6 7
- —
-
28,970
100
-
-
-
. -
6,837 19,000
-
1,200
15.7
1.8
0.368 4,700
-
12.5
-
2.7 2.1 .
8
—
-
44,050
950
-
-
-
-
21,920
-
825
0.3
3.4
93,000
-
23
-
2.8
for Effluent Limitation
Guidelines and Standards of Performance. New York, New York. Burns and Roe Inc. 1973,
-------
runoff from low sulfur western coals is not likely to be as
acidic as these examples. Normally, coal pile runoff will be
collected in ponds and used by the SRC plant. If clean enough,
these waters can be treated and used for plant makeup. Other-
wise these waters will be used for dust control on the coal pile
and coal roads.l
3.8.2.3c Solid Wastes, Sludges, Spent Catalysts
The major source of solid waste from a SRC-II facility is
the gasifier ash. A 30,000 tpd coal liquefaction facility will
produce approximately 2500 tpd of gasifier ash. The major
constituent of this ash will be minerals entering with the coal.
Depending on the nature of the gasification process, gasifier
ash will also contain various concentrations of trace elements
and polynuclear organic compounds. Some of the trace elements
and polynuclear organics potentially present are presented in
Table 3^121 and Table 3-126, A more in-depth discussion of the
characteristics of gasifier ash is presented in Section 3.8.1.3
on Gasifier Outputs.2
The method of disposal for gasifier ash will vary with
plant design, but will generally be coupled with the coal delivery
operation. Many plant designs provide for ash disposal at the
coal mining site. On-site landfilling is another alternative.3
JJahnig, C. E. Evaluation of Pollution Control in Fossil
Fuel Conversion Processes: SRC Process, Final Report for U.S.
Environmental Protection Agency, Contract No. 68-02-0629.
Linden, New Jersey: Exxon Research and Engineering Company,
March 1975, p. 31.
2(Ralph M.) Parsons Company. Demonstration Plant • Clean
Boiler Fuels from Coal, Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-1234. Los
Angeles, California: Ralph M. Parsons Company, September 1973.
3Jiid.
-315-
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Two major sources of sludge from coal liquefaction operations
are process water treating and wastewater treating. Common
process water treating techniques include filtration, lime/lime-
soda softening, and ion exchange. The major constituents of
process water treatment sludges include minerals entering with
the raw process water, coagulating and flocculating agents, lime,
and soda. The most common flocculating agents are alum, alumi-
nates, ferric chloride copperas, bentenites, and polyelectrolytes.l
Wastewater treatment sludges consist of oily grit removed
by the API separator and biological sludge from the bio-ponds.
These sludges consist primarily of coal ash minerals, waste oils,
and biological material, but may also contain small quantities
of trace elements and polynuclear organics.
The flow rates of these sludges are highly dependent on
raw water quality and wastewater handling practices. However,
the volume of these sludges is much smaller than the volume of
*
gasifier ash. Disposal of these sludges is normally by the same
methods as gasifier ash.2
A wide variety of catalysts and sorbents will be used in
the SRC-II process. Many of these are listed in Table 3-111.
These catalysts and sorbents deactivate with time or during
plant upsets. Generally, catalysts must be replaced on a
schedule of one or two years, although sorbents may require
more frequent replacement. In some cases the catalysts and
1(Ralph M.) Parsons Company. Demonstration Plant • Clean
Boiler Fuels from Coal, Office of Coal Research R&D Report 82,
Int. Rpt. 1, 3 Volumes, Contract No. 14-32-0001-1234. Los
Angeles, California: Ralph M. Parsons Company, September 1973
2Ibid.
-316-
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reagents will be discarded with the gasifier ash and sludge.
However, in most cases they will be returned to the supplier
for reclamation.1
3.8.2.3d Noise Pollution
Coal receiving, conveying, and crushing are particularly
noisy operations and will require careful shielding design to
reduce in-plant noise.to the levels required by the Occupational
Safety and Health Act (OSHA). The remainder of the coal lique-
faction plant is comparable in noise generation to oil refineries
and should create no unusual problems.2
3.8.2.3e Odor
There will undoubtedly be disagreeable odors associated
with any coal liquefaction process. Many malodorous compounds
such as mercaptans, hydrogen sulfides, organic nitrogen compounds,
phenols, cresols, and naphthenic acids are present in the SRC-II
process. These compounds are perceptible at concentrations as
low as one part per billion, or even less. As a result, extremely
small concentrations, well below toxic or harmful levels, may
still present a nuisance to nearby residents. However, good
housekeeping practices and other practices which reduce fugitive
emissions will aid significantly in the reduction of the odor
nuisance.
Associates, Inc. Technology and Environmental
Overviews: Coal Liquefaction, Draft Final Report, for U.S.
Environmental Protection Agency, Contract No. 68-02-2162.
Columbia, Maryland: Hittman Associates, 1977.
2National Research Council. Assessment of Technology for
the Liquefaction of Coal, Committee on Sociotechnical Systems,
National Research Council. Washington, D.C.: National Academy
of Sciences, 1977, p. 115.
-317-
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3.8.2.3f Occupational Health and Safety
Available data on the carcinogenicity of products from
processes currently under development are limited. Samples of
solvent refined coal (SRC), solvent, and heavy hydrogenated SRC
prepared from Pittsburgh seam coal at the ERDA Cresap pilot plant
in 1970 were tested in cutaneous applications with mice at
Kettering Laboratory. As compared to benzo-(a) pyrene, a
solution of SRC was weakly carcinogenic, and the hydrogenated
bottoms and solvent were moderately carcinogenic.
Hygienic practices and medical surveillance are employed
by most organizations now engaged in liquefaction process
development. Similar practices are employed on a commercial
scale by SASOL, with a reported complete absence of carcinogenic
reaction by the workmen. The basic principle involved is the
avoidance of prolonged contact with the potentially carcinogenic
materials; this requires bathing at the end of a workday,
laundering work clothes each day, and inspection to establish
the complete removal of carcinogens.l
Data on injuries, deaths, and man-days lost are available
from Battelle. Converting from Battelle's basis of 106 Btu to
a 100,000 BPD plant yields the following expected annual values:
0.32 deaths, 6.2 injuries, and 1,494 man-days lost.2
1National Research Council. Assessment of Technology for
the Liquefaction of Coal, Committee on Sociotechnical Systems,
National Research Council. Washington, B.C.: National Academy
of Sciences, 1977, p. 116.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus Laboratories,19737
-318-
-------
3.8.2.3g Community Exposure
Concern has been expressed about the risk to adjacent
communities that may arise from coal liquefaction manufacture.
Although some hazardous compounds are present in the coal
liquefaction process, coal liquefaction plants, like petroleum
refineries, are continuous, closed systems. Uncontrolled
emissions to the atmosphere will not occur in a well designed
commercial plant during normal operation.1
The Ad-Hoc Panel on Liquefaction of Coal (National Research
Council) appointed to assess coal liquefaction technology reports
that based on present knowledge of processes and emissions, they
see no reason for the potential exposure of a community to
environmental hazards from an adjoining coal liquefaction plant
to exceed that from other existing controlled industrial
operations.2
3.8.2.4 Summary
Table 3-128 presents a summary of the inputs and outputs
associated with a 30,000 TPD SRC-II coal liquefaction plant
located near Gillette, Wyoming. Although these impacts will
vary somewhat from location -to location due to the type of coal
used, meteorological conditions, etc., they are not expected
to vary significantly between various sites in the Western
States.
National Research Council. Assessment of Technology for
the Liquefaction of Coal, Committee on Sociotechnical Systems,
National Research Council. Washington, D.C.: National Academy
of Sciences, 1977, p. 116.
2Ibid.
-319-
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TABLE 3-128.
SUMMARY OF IMPACTS ASSOCIATED WITH A
30,000 TPD SRC-II COAL LIQUEFACTION
PLANT AT GILLETTE, WYOMING
Input Requirements
Manpower
• construction.
• operating
Materials and Equipment
• fabricated steel
• concrete
• refined products
Operating Reagents
Econoaics
• capital costs
• operating costs (excluding coal costs
Water
• 0 lOOt reuse and recycle
• 0 current development plans
land
Ancillary Energy
21,900 man-years
1,600 men
200,000 tons
288,000 tons
50,000 tons
40 tons/day
$1.2 - $1.3 billion*
$219 Billion/year
4 Billion gal/day
17 Billion gal/day
1800 acres
41 MH
Outputs
Air Emissions
• particulates
• SOX
• total organics
• CO
• HO
• COi
Hater Effluents
Solid Wastes
Boise
Odor
Occupational Health and Safety
• fatalities
• injuries
• Ban-days lost
475 Ib/hr
248 Ib/hr
1,067 Ib/hr
126 Ib/hr
1,280 Ib/hr
12 Ib/hr
858,000 Ib/hr
negligible
2,500 ton/day
negligible
trace
0.32 deaths/yr
6.2 injuries/yr
1494 man-days/yr
*1976 dollars
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3.8.3 Electrical Generation
The electrical generation facilities considered here are
designed to produce electricity by the direct combustion of
coal in boilers. The unifying characteristic of boiler-fired
power plants is that the electrical energy is generated by a
series of three conversion stages. First, the chemical energy
of the coal is converted to heat energy by combustion in the
boiler. This heat is transferred to some working fluid, usually
water and/or steam. Second, the heat energy of the working
fluid is converted to mechanical energy by a turbine (or heat
engine in thermodynamic terminology). Third, the mechanical
energy is converted to electrical energy by a generator.
In the boiler, coal is combusted, generating combustion by-
products and heat. The combustion by-products are removed from
the boiler as ash and stack gases. Pollutants in the stack
gases may be removed by a stack gas cleaning mechanism before
the gases are released to the atmosphere. The heat produced
by the combustion is transferred to water to produce high-
pressure, high-temperature steam. The steam enters the turbine
where it expands to a low pressure and low temperature and drives
the turbine which in turn drives the generator.
After the thermal energy in the steam has been converted to
mechanical energy, the discharged steam is condensed to water.
The water is then pumped back into the boiler to start the cycle
over again. The heat removed in the condenser is rejected into
bodies of water (i.e., lakes, ponds, rivers, etc.) or to the
atmosphere by cooling towers. A simplified schematic of this
type of power plant is shown in Figure 3-28.
-321-
-------
Heat Input
To Cycle
(Fuel)
High Pressure
High Temperature Steam
Pump
Boiler
High Pressure
Water
Turbine
Condenser
b
Low Pressure
Water
Generator
Electrical
•^•Energy
Mechanical Energy
Output To Generator
Low Pressure
Low Temperature
Steam
Heat Rejected From Cycle
Figure 3-28. Simplified Schematic of a Steam Power Plant.
Source: U.S. Atomic Energy Commission. Draft_Environmental
Statement: Liquid Metal Fast Breeder" Reactor
Program, 4 Vols. Washington, B.C.:
Printing Office, 1974.
Government
-------
3.8.3.1 Technology Description
The technological description of this electrical generation
section is divided into the following segments: boilers, turbines,
generators, stack gas cleaning, and cooling.
Boilers
Boilers are mechanisms that burn fuel to create heat energy
which is then transferred to a fluid (normally water) to produce
steam. To improve thermal efficiencies, both conventional
boilers and the new fluidized bed combustors generally contain
other system components such as:l
1; Superheaters. A superheat is a system of tubes
located at the top of the boiler in which the
saturated steam is superheated by combustion
gases.
2. Reheaters. A system of tubes much like the super-
heater, the reheater reheats partially expanded
steam taken from the early stages of the turbine.
The steam is then returned to the final stages of
the turbine.
3. Economizers. An economizer extracts heat from
the flue gases (after the superheater) and
transfers it to the boiler feedwater.
4. Air preheaters. An air preheater extracts
additional heat from the flue gases (after the
economizer) and transfers it to the combustion
air before it is fed into the furnace.
1University of Oklahoma, Science and Public Policy Program.
Energy Alternatives: A comparative Analysis. Washington, B.C.:
Government Printing Office, 1975.
-323-
-------
In addition to these components, the boiler also has
steam separators, fans, pumps, fuel handling equipment, and
combustion by-product handling equipment.
Because combustion occurs in the boiler, it produces most
of the potentially adverse environmental residuals associated
with electric power generation.*
Conventional boilers are extremely large and complex.
Some steam power plant boilers are 10 or more stories tall.
Figure 3-29 is a simplified boiler design showing the air and
flue gas circulation patterns.
A number of variables affect conventional boiler design,
a primary one being the type of fuel to be burned. Coal is
generally pulverized to a very fine powder (approximately
200 mesh) and then blown into the furnace. However, additional
problems that must be dealt with when coal is burned include
fly ash handling and slagging.
The firing mechanism and techniques are other important
conventional boiler design variables that affect the combustion
pattern and temperature control. In some cases the burners are
directed vertically downward, an option used primarily with
solid fuels. In others, the burners are fired horizontally,
in opposition, or tangentially along the walls of the furnace.
In a frequently used technique, staged firing, 90 to 95 percent
of the air enters the boiler as primary and secondary air with
the fuel before combustion, and the remainder enters as tertiary
air through auxiliary ports in the furnace. Because of imperfect
University of Oklahoma, Science and Public Policy Program.
Energy Alternatives: A Comparative Analysis. Washington, D. C.:
Government Printing Office, 1975.
-324-
-------
Stack
Precipitator
A.
~ _ -Economizer
Pulverizer
Boiler
Figure 3-29. Boiler Air and Flue Gas Circulation Patterns
Source: Shields, C. D. Boilers, Types, Characteristics, and
Functions. New York: IlcGraw-Hill, 1961
-325-
-------
mixing, approximately 20 percent more air (termed 120-percent
excess air) must be injected into the combustion chamber than
is theoretically required for complete combustion.1
A significant advance in coal firing technology, known as
the cyclone furnace, has developed over the past 35 years. In
cyclone furnace operation, crushed coal (approximately 4 mesh)
enters a horizontal cylinder at one end while air is injected
(at high velocities) tangentially along the cylinder periphery,
resulting in a cyclonic burning pattern. The advantages of this
type of furnace are reduction in fly ash content of the flue
gas, savings in fuel preparation (since only crushing is
required instead of pulverizing) and reduction in furnace size.2
A disadvantage, however, is that the increased temperatures
due to accelerated combustion cause generation of significantly
higher levels of NOX.3
Three major factors determine the amount and character of
the air pollutants generated by a boiler: fuel burned, boiler
design, and boiler operating conditions. Sulfur oxides (SOx)
emissions are directly relatable to the sulfur content of the
fuel, and there is little in the way of conventional boiler
design or operation that can affect this residual. These SOx
emissions can be dealt with either by coal cleaning prior to
combustion or stack gas cleaning after combustion.
lUniversity of Oklahoma, Science and Public Policy Program.
Energy Alternatives: A Comparative Analysis. Washington, B.C.:
Government Printing Office, 1975.
2Babcock & Wilcox. Steam/ Its Generation and Use, 38th Ed.
New York: Babcock & Wilcox, 1972.
3National Research Council, Commission on Sociotechnical
Systems. Assessment of Advanced Technology for Direct Combustion
of Coal. Prepared for:National Academy of Sciences, Washington,
D.C. 1977.
-326-
-------
Nitrogen oxides (NOX) emissions can be significantly affected
by boiler design and operating conditions, but the process of NOx
formation during combustion is not completely understood. The
major factor affecting the formation of NOX is temperature. One
study indicates that the most important variables for fossil-
fueled boilers in controlling NOx emissions are staged firing,
low excess air (less than 110 percent of the actual requirement
for complete combustion), and flue gas recirculation.l This
study indicated the potential for similar methods to be applied
for coal, but the emission of NOX from coal-fired boilers is
the least explored and the most difficult problem area of all
the NOx emission sources.2
Particulate emissions are a major problem with coal-fired
boilers. Improved boiler design can reduce these emissions.
The primary advance in this area is the cyclone furnace described
earlier, which can reduce fly ash by 50 percent over pulverized
units, but with a significant increase in NOX emissions. The
particulates generated in a coal-fired boiler primarily consist
of ash in the coal which becomes entrained in the flue gases
(fly ash). The major factor affecting these emissions, there-
fore, is the amount of ash contained in the coal. The primary
method of controlling particulates is stack gas cleaning, which
will be discussed subsequently.
In addition to the' pulverized and cyclone furnaces discussed
above, a third type of boiler currently being analyzed is the
^artok, W., A. R. Crawford, and G. J. Piegari. "Systematic
Investigation of Nitrogen Oxide Emissions and Combustion Control
Methods for Power Plant Boilers", in Air Pollution and Its
Control, AIChE Symposium Series 68 (125), A. F. Sarofim and
N. J. Weinstein, eds.New York, American Institute of Chemical
Engineers, 1972.
-327-
-------
fluidized bed boiler. The desire to reduce pollutants as well
as to improve boiler efficiency has led to increased work on
fluidized bed boilers. Such boilers are not commercially avail-
able at present, but their proponents believe they hold great
promise as substitutes for conventional steam boilers.
In a fluidized bed boiler air is passed upward through a
grid plate supporting a thick (several feet) bed of granular,
noncombustible material such as coal ash or lime. The air
fluidizes the granular particulates and, with the relatively
small amount of air used to inject the fuel serves as the com-
bustion air. The heat transfer surfaces or boiler tubes can
be embedded directly in the fluidized bed because combustion
*
takes place at temperatures (approximately 1,500°F) that will
not damage the tubes.
The fluidized bed boiler has two basic advantages: the
ability to turn high-sulfur coal with low sulfur dioxide (S02),
particulate, and, to some extent, NOx emissions; and high heat
release and heat transfer coefficients that can drastically
reduce boiler size, weight, and cost. This means that fluidized
bed boilers can be built as factory-assembled, packaged units,
shipped to sites, and arrayed as required. These factors would
considerably reduce construction times for new power plants.1
There are several fluidized bed concepts at various stages
of development. In this section one of the processes treated
in the Hittman study2 will be described: the Pope, Evans, and
Robbins Atmospheric Pressure Fluidized Bed Boiler.
Hittman Associates, Inc. Environmental Impacts. Efficiency.
and Cost of Energy Supply and End Use. Final Report;Vol. I,
1974; Vol. II, 19/5. Columbia, Md.: Hittman Associates, Inc.,
1974 and 1975.
2Ibid.
-328-
-------
The Pope, Evans, and Robbins Atmospheric Pressure Fluidized
Bed Boiler, being developed for the Office of Coal Research (OCR),
is designed as a replacement for conventional boilers. This
system is illustrated in Figure 3-30. The system uses repeating
elements or cells to make any size boiler desired, thus reducing
scale-up problems. The largest fluidized bed boiler currently in
use is the four cell 30-MW unit at Riversville, West Virginia
which is expected to provide many answers regarding large scale
application of thise boilers.1
Turbines
The purpose of the turbines at a power plant is to convert
the heat energy released in the boiler to mechanical energy
for turning generators. The turbines discussed in this section
are steam turbines utilizing high-temperature, high-pressure
steam generated by coal combustion.
In these steam turbines, the high-temperature, high-
pressure steam is allowed to expand greatly increasing its
velocity but decreasing temperature and pressure. The high
velocity steam impacts turbine blades causing rotation.
Depending on the turbine design, the steam turbine can have
one or several stages to extract energy from the high-temperature,
high-pressure steam and produce a low-pressure, low-temperature
steam.
The typical operating conditions for a steam turbine are
an input steam temperature of about 1000°F and an outlet tempera-
ture of about 100°F. The mechanical efficiency (percent thermal
energy removed from the steam which is converted to usable
National Research Council, Commission on Sociotechnical
Systems. Assessment of Advanced Technology for Direct Combustion
of Coal. Prepared for:National Academy of Sciences, Washington,
D77T 1977.
-329-
-------
Dust Removal
Turbine
Generator
Steam
Limestone
& Salt
I
r-Coal
Dust
Removal
Stack
+. Solid
Waste
y
Sulfur
Plant
Mulficell Fluidized-Bed Boiler
I500F
Primary
Boiler
Cells
L.
±1
Ail
2000 F
Carbon
Burnup
Cells
Refigeralion
Cells
•'
Ash
Figure 3-30. Pope, Evans, and Robbins Fluidtzed Bed Boiler Power Plant
Source: Hittman Associates, Inc. Environmental Impacts, Efficiency, and
Cost of Energy Supply and End Use, Final Report: Vol. I, 1974;
Vol. II, 1975.Columbia, Md.:Rittman Associates, Inc., 1974 and 1975,
-------
mechanical energy) is less than 60%. Although this efficiency
cannot be significantly improved by turbine design, the quan-
tity of heat available for conversion can be increased by
various methods. One such method is the use of reheaters. In
this design, steam is removed from the turbine between the high
and low-pressure stages and heated with boiler flue gases.
Although this will not significantly affect turbine mechanical
efficiency, it will increase overall plant efficiency by utiliz-
ing more available heat.
Another method of increasing overall plant efficiency is
the binary cycle design. In this design, two or more heat
engine cycles covering different parts of the temperature range
are combined. When the second cycle is added to the high-
temperature end, it is referred to as a topping cycle; a second
cycle added to the low-temperature end is termed a bottoming
or tailing cycle.
The binary cycle which has been the subject of much research
and development is the liquid metal combined cycle design. In
this design, a metal which will be a liquid at boiler feed
temperatures (e.g., mercury or potassium) is used as the
working fluid in the boiler. The principal advantage of using
one of the liquid metals as the working fluid is their high
boiling or vaporizing temperatures at relatively low pressures.
While water boils at 662°F at 2,400 pounds per square inch
absolute (psia), mercury boils at 907°F at 100 psia and potas-
sium boils at 1,400°F at 14.7 psia (one atmosphere). By
vaporizing these metals in the boiler, therefore, a much higher
temperature at the input to the topping turbine is possible.
Even after the high-temperature vaporized metal has been through
-331-
-------
the topping turbine, it contains enough heat to produce steam
while being condensed. This steam is then used in the steam
turbine. By utilizing these two turbines (combined cycle) a
greater temperature range can be achieved. Although the effi-
ciency of the liquid-metal Rankine cycle by itself is not high,
by using the condenser for the liquid metal as the boiler for
the water, the overall efficiency is relatively high.1 For
example, the overall efficiency of a conventional steam cycle
power plant is about 287.. The binary cycles, however, can
achieve efficiencies of approximately 50%.
Between 1922 and 1950, the General Electric Company con-
structed a series of six fossil-fueled mercury and steam binary
cycle power plants. These mercury plants demonstrated the prac-
tical feasibility of the mercury topping cycle. However, no
mercury topping cycles were built after 1950. This is due to
the improved efficiency and economics of scale of the modern
conventional steam power plants and the high costs associated
with construction and operation of the binary cycle.
Generators
The mechanical energy from the turbine is converted to
electrical energy by the generator. An electrical generator
relies on the basic phenomenon in electromagnetics; when an
electrical conductor is moved properly through a magnetic
field, a voltage will develop along the conductor. The only
type of alternating current (AC) generator presently used in
^.S. Atomic Energy Commission. Draft Environmental
Statement: Liquid Metal Fast Breeder Reactor Program. 4 Vols
Washington, D.C. : Government Printing Office, 19/4.
-332-
-------
large power plants is the synchronous type, whereby the speed
of the rotor is related to the frequency of the current pro-
duced. In the large synchronous generators, the conductor is
stationary while the magnetic field is rotated. The efficiency
of these generators (i.e., the percent of the input mechanical
energy which is converted to usable electrical energy output)
is about 95 percent.
Stack Gas Cleaning
Stack gas cleaning is the process by which contaminants
are removed from the boiler flue gases before the gases are
vented to the atmosphere. Some stack gas cleaning processes,
such as those for collecting sulfur dioxides and p articulates",
are commercially available at present. Other processes for the
removal of nitrogen oxides are still a developing technology.
The systems which are available for stack gas cleaning depend
on the contaminant to be removed. The following sections de-
scribe technologies for removal of particulates, nitrogen oxides
and sulfur dioxide.
Particulates
Removing particulates from the gases can be accomplished
*
mechanically, electrostatically, or as part of the S02 removal.
Mechanical separation takes place in a cyclone where the flue
gases are rotated at high speed to throw the higher-mass
particulates against the outside walls where they are separated.
The dust may be collected using water (irrigated cyclone) or
simply allowed to fall into a hopper (dry cyclone). Depending on
-333-
-------
size and type, mechanical separators vary in efficiency from 65
to 94 percent.1
Electrostatic precipitators impose a very high electric
field on a series of wires and tubes (or wires and plates) so
that a low-current electric discharge occurs between them. If
the particulates to be removed can be ionized, they will respond
to this field and be drawn to the tubes. Waste disposal is
usually accomplished by rapping the tubes and collecting the dust.
The performance of a precipitator depends strongly on the percent
sulfur in the coal which is combusted. This is because the elec-
trical resistivity of the fly ash is high. For example, if a
unit is designed for 95-percent efficiency using 5-percent sulfur
coal, it will operate at only 70-percent efficiency with 0.59-
percent sulfur coal. This poses-special problems with combustion
of low-sulfur western coals.2
In addition, the efficiency of electrostatic precipitators
is highly dependent on the stack gas temperature. A system giving
92-percent efficiency at 310°F may only give 55-percent efficiency
at 270°F.3 This presents a problem for startup, since there is
significantly lower particulate removal until the precipitator
temperature is brought up to design temperature. Most electro-
static precipitators are designed to have removal efficiencies of
between 92 and 99 percent.
^onhebel, G., ed. Gas Purification Processes. London:
George Newnes Limited, 1964.
2National Research Council, Commission on Sociotechnical
Systems. Assessment of Advanced Technology for Direct Combustion
of Coal. Prepared for:National Academy of Sciences, Washington,
DTCTT977.
3Soo, S. L. "A Critical Review on Electrostatic Precipita-
tors", pp. 185-193 in R. W. Coughlin, A. F. Sarofim, and N. J.
Weinstein, eds. Air Pollution and Its Control, AIChE Symposium
Series, Vol. 68, No. 126.New York:American Institute of
Chemical Engineers, 1972.
-334-
-------
Another particulate control device which is being proposed
for use with pulverized-coal-fired boilers is the bag filter.1
These devices utilize cloth filters which collect particulates
as the flue- gases are forced through the fabric. The collected
particulates are collected by shaking the filters and allowing
the particulates to fall. The efficiencies of these devices
are generally over 99 percent.
Sulfur Dioxide
Sulfur dioxide (S02) residuals have been a major air
pollution concern associated with electric power generation and
the most difficult to control. Although more than 50 individual
flue gas desulfurization processes (FGD) have been identified2,
the most effective appear to be "scrubbing" processes in which
the stack gas is intimately contacted with a material that reacts
with SO2 to form a compound. The resultant compound is then
either dumped (nonregenerable methods) or treated so that some
useful form of the sulfur may be recovered.
The nonregenerable methods convert an air pollution problem
to a solid waste problem, while the recovery methods involve
costly production of a by-product such as elemental sulfur or
gypsum. The commercial value of these by-products from a regen-
erable FGD system are generally uncertain and depend on many
economic factors which will not be considered here. In addition,
many utility companies may be hesitant to get into what is viewed
as the chemical business.
National Research Council, Commission on Sociotechnical Sys-
tems . Assessment of Advanced Technology for Direct Combustion of
Coal. Prepared for:National Academy of Sciences, Washington, D.C
T977.
2Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus Laboratories, 19737
-335-
-------
Lime and/or limestone nonregenerable processes are cur-
rently favored by the electric utility industry as the best
solution to SO* emissions.1 As of June 1977, 977» of the new
generating capacity constructed with flue gas desulfurization
(FGD) systems and 83% of the retrofit capacity with FGD systems
used lime and/or limestone scrubbing.2 The three basic forms
of this system are shown in Figure 3-31. In each system, S02
is reacted with lime and/or limestone to form calcium sulfate
and calcium sulfite which is disposed of in settling ponds.
A description of the three basic alternatives shown in Figure
3-31 is as follows:
1. Introduction of limestone directly into the
scrubber. This is the simplest route and
seems to be the one favored by the power
industry at present. The main drawback is
that limestone is not as reactive as lime,
which makes it necessary to use more lime-
stone, install a larger scrubber, recirculate
more slurry, grind the limestone finer, and
otherwise offset the lower reactivity.
2. Introduction of lime into the scrubber.
Scrubbing efficiency can be improved by
first calcining the'limestone to lime (CaO)
and introducing the lime into the scrubber.
However, the cost is increased greatly over
that for limestone slurry scrubbing, since a
1 Slack, A. V., H. L. Falkenberry, and R. E. Harrington.
"Sulfur Oxide Removal from Waste Gases: Lime-Limestone Scrubbing
Technology."
2PEDCo Environmental Specialists, Inc. Summary Report,
Status of Flue Gas Desulfurization Systems in the U.S.. April-
May 1977"Cinncinatti, OH:1977.
-336-
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Stack
gas
r>Gas to
stack
Scrubber
CaCQj
Settler
Pump
tank
METHOD I. SCRUBBER ADDITION OF LIMESTONE
CaS03+ CaS04
to waste
Stack
gas
CaCO.
Calciner
j—*Gas
to stack
Ca(OH)2
Scrubber
Pump
tank
CaO
Settler
to waste
METHOD 2. SCRUBBER ADDITION OF LIME
CaO +gas
CaCOj
Boiler
•Gas to
Scrubber
Pump
tank
Settler
CaSOj
to waste
METHOD 3. BOILER INJECTION
Figure 3-31. Lime and Limestone Stack Gas Scrubbing Methods
Source: Slack, A.V., H. L. Falkenberry & R. E. Harrington.
"Sulfur Oxide Removal from Waste Gases: Lime-Limestone
Scrubbing Technology". J. APCA 22 (3), 159 (1972).
-337-
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lime kiln installation is expensive to build
and operate. Use of lime also increases the
problem of deposit formation in the scrubber
(scaling).
3. Introduction of limestone into the boiler.
The cost of calcination can be reduced in
power plants by injecting the limestone into
a boiler furnace. The gas then carries the
lime into the scrubber. Problems include
possibility of boiler fouling, danger of over-
burning and inactivating the lime, and
increased scaling in the scrubber when the
lime enters with the gas.
In addition to the lime and/or limestone FGD systems, the
three other systems currently in use or soon to be operational
are magnesium oxide scrubbing, sodium carbonate scrubbing and
Wellman Lord/Allied Chemical scrubbing. The primary difference
between these systems and the lime/limestone systems is that
the SOa stream can then be utilized to form elemental sulfur,
H2SOi, or other by-products.
The S02 removal efficiency of the FGD processes are generally
designed to be over 90 percent. In actual practice, however, some
systems have achieved significantly lower efficiencies. In
addition to this S02 removal, the FGD systems all effect a par-
ticulate removal efficiency greater than 99 percent. This
removal is either achieved in the scrubber itself or in electro-
static precipitators within the FGD system for the purpose of
protecting scrubbers and/or absorbers from particulates.
-338-
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A listing of the electrical generating capacity which
utilizes each type of FGD system currently or soon to be in
use as of June 1977 is shown in Table 3-129. Table 3-130 shows
a breakdown of the generating capacity for which FGD systems
are already operational, are under construction, or are planned.
In addition, it should be noted that there are many other
types of FGD systems under consideration for future use.
TABLE 3-129. GENERATING CAPACITY UTILIZING FGD SYSTEMS
JUNE 1977
FGD System MW
Lime Scrubbing 2702
Lime/Alkaline Scrubbing 720
Lime/Limestone Scrubbing 20
Limestone Scrubbing 3767
Magnesium Oxide Scrubbing 120
Sodium Carbonate Scrubbing 375
Wellman Lord/Allied Chemical1 455
Total 8159
*350 MW of this capacity is scheduled to go on line November
1977.
Source: PEDCo Environmental Specialists, Inc. Summary Report,
Status of Flue Gas Desulfurization Systems in the U.S., April-
May 1977. Cinncinatti, OH: 1977, p. 219.
-339-
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TABLE 3-130. NUMBER AND TOTAL MW OF FGD SYSTEMS
JUNE 1977
Status No. of Units MW
Operational 27 7,819
Under Construction 29 12,648
Planning
Contract Awarded 20 9,797
Letter of Intent 5 1,892
Requesting/Evaluating Bids 5 3,565
Considering Only FGD Systems 33 14,856
Total 119 50,577
Source: PEDCo Environmental Specialists, Inc. Summary Report,
Status of Flue Gas Desulfurization Systems in the U.S.,
April-May 1977.Cinncinatti, OH:1977, p. 203.
Oxides of Nitrogen
Oxides of nitrogen are formed during fuel combustion by
oxidation of the nitrogen in the air and the nitrogen in the
fuel with air generally the major source. This oxidation occurs
at high temperatures and the rate of formation increases with
temperature. The primary form of NOX control, therefore, is
combustion modification to reduce temperatures and minimize N0x
formation. This is generally accomplished by staged firing,
excess air control, water injection and other methods. Since
flame temperature control is most important in NO control,
-340-
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some boiler designs produce significant quantities of NOX and
are not amenable to extensive control. An example of such a
boiler is the cyclone boiler described earlier where the com-
bustion rate and temperature are very high.
Catalytic scrubbers for NOx removal have also been proposed.
These units remove NOx from stack gases after formation by
reacting the NOx to form other compounds capable of being
disposed of more readily than the NOx. An example is the
formation of a dilute nitric acid stream in the scrubber.
These scrubbers, however, are much more expensive than combustion
modification.
Cooling
Selecting a suitable means of dissipating waste heat depends
on a number of factors such as the quantity of heat to be dis-
sipated, the availability of water, and local thermal pollution
regulations. The four types of cooling systems are once-through
cooling using fresh or saline water, cooling ponds, wet cooling
towers, and dry cooling towers.
In once-through systems, water is withdrawn from some source,
circulated through the condenser where it is heated, and then
returned to the source. Once-through cooling systems are gen-
erally used where adequate supplies of water are available and
no significant adverse effects on water quality are expected.
Sources of water include rivers, lakes, estuaries, and the ocean.
Once-through systems are normally more economical than other
systems. The only consumptive water uses are those resulting
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from increased evaporation in the source water bodies because
of the addition of heat.1
Where water supplies are limited and suitable sites are
available, cooling ponds may be constructed so that water may
be recirculated between the condenser and the pond. Sufficient
inflow would be needed, either from upstream runoff or by diver-
sion from another stream, to replace the-natural evaporation
induced by the addition of heat to the pond. A pond surface
area of one to two acres per megawatt of plant capacity is nor-
mally required for dissipating the heat in the western states.
However, pond size is very dependent on climate conditions.
Cooling ponds are frequently used for other beneficial purposes,
including recreation.2
Where conditions are not favorable for once-through cooling
or for the construction of cooling ponds, cooling towers are
generally employed for the dissipation of waste heat. Cooling
towers may be used to provide'full or partial cooling require-
ments during certain periods or throughout the year.
In wet cooling towers, the warm water is brought into direct
contact with a flow of air, and the heat is dissipated princi-
pally by evaporation. Cooling towers may be either*of natural-
or mechanical-draft design. Because of the large structures
involved and the added pumping and other costs, wet cooling
towers are usually more expensive than once-through systems or
cooling ponds.3
^imeson, R.M. and G.G. Adkins. "Factors in Waste Heat
Disposal Associated with Power Generation", Paper 26a, Presented
at the 68th National AIChE Meeting, Houston, 1971.
zlbid.
3 Ibid.
-342-
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Currently the largest natural draft wet cooling tower is
about 450 feet in diameter and 450 feet high, and is adequate
for an 800 Mwe plant. Wet cooling towers using forced draft
are smaller because of limitations on fan diameters1, and are
constructed in multiple cells to cool large plants.
In a dry cooling tower, the water circulates in a closed
system with the cooling provided by a flow of air created either
by mechanical or natural draft, much like the radiator in an
automobile. Because of the large heat transfer surface area
and air volumes required, however, dry cooling towers are
substantially more expensive than wet towers.
The amount of water "consumed" by the cooling process will
depend on the specific plant design and the affected waterbody
conditions.
3.8.3.2 Input Requirements
For illustrative purposes, a 3,000 Mw electrical generating
facility has been chosen for quantifying the inputs associated
with a power plant. The following sections discuss manpower
requirements, material and equipment, costs, water needs, land
usage, and ancillary energy requirements. The values reported
below for manpower, materials and equipment and economics were
extracted from Bechtel's "Energy Supply Planning Model".1 The
data were developed on the basis of well.established technology
and are considered to be accurate within +20, -10 percent.
^arasso, M., et al. Energy Supply Model, Computer Tape.
San Francisco: Bechtel Corporation, 19/5.
-343-
-------
3.8.3.2a Manpower Requirements
Manpower estimates required for construction of a 3,000 Mwe
power plant are shown in Table 3-131. The 3,000 Mwe facility
will consist of 4 separate 750 Mwe boilers. Field construction
is anticipated to last seven years with the first boiler completed
at the end of the fourth year, the second boiler due to come on
line at the end of the sixth year, and boilers number 3 and 4 to
be finished during the seventh year. Table 3-132 lists the
manpower resources required to operate and maintain the power
plant.
3.8.3.2b Materials and Equipment
Table 3-133 lists the major materials and equipment needed
for construction of four 750 Mwe boilers and associated generat-
ing and transforming equipment comprising a 3,000 Mwe power plant.
This information was selectively extracted from "The Energy Supply
Planning Model."1
3.2.3.2c Economics
Bechtel2 has estimated capital costs of power plants in
third-quarter 1974 dollars. From Bechtel data a cost estimate
of $880 million has been derived for a 3,000 Mwe coal-fired
power plant. The same data base indicates total annual utility
costs of $4 million. This figure does not include the cost of
the coal consumed since the power plant complex is a mine-mouth
operation and the annual costs of producing the coal are accounted
for in the mining operation. Using the manpower figures in
^arasso, M., et al. Energy Supply Model. Computer Tape.
San Francisco: Bechtel Corporation, 19/5.
-344-
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TABLE 3-131.
SCHEDULE OF MANPOWER RESOURCES (MAN-YEARS)
REQUIRED TO CONSTRUCT A 3,000 MW POWER PLANT
Skill
Civil Engineers
Electrical Engineers
Mechanical Engineers
Mining Engineers
Nuclear Engineers
Geological Engineers
Petroleum Engineers
Other Engineers
Total Engineers
Total Designers + Draftsmen
Total Supervisors 4- Managers
Total Technical
Total Non-Tech (Non-Manual)
Pipefitters
Pipefitter /Welders
Electricians
Boilermakers
Boilermaker/Welders
Iton Workers
Carpenters
Operating Engineers
Other Major Skills
Total Major Skills
Other Craftsmen
Total Craftsmen
Total Teamsters + Laborers
GRAND TOTAL
1
22
16
13
0
0
0
0
0
51
20
10
81
39
60
27
42
45
15
21
21
15
0
246
18
264
36
420
2
38
28
22
0
0
0
0
0
87
35
16
139
66
140
63
98
165
35
49
49
35
0
574
42
616
84
905
3
58
43
33
0
0
0
0
0
134
54
25
213
- 102
200
90
140
150
50
70
70
50
0
820
60
880
120
1315
4
86
63
49
0
0
0
0
0
198
79
37
315
150
320
144
224
240
80
112
112
80
0
1312
96
1408
192
2065
5
83
60
47
0
0
0
0
0
190
76
36
301
144
420
189
294
315
105
147
147
105
0
1722
126
1848
252
2545
6
54
39
31
0
0
0
0
0
124
50
23
196
94
340
153
238
255
85
119
119
85
0
1394
102
1496
204
1990
7
22
16
13
0
0
0
0
0
51
20
10
81
39
120
54
84
90
30
42
42
30
0
492
36
528
72
720
-345-
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TABLE 3-132. MANPOWER RESOURCES REQUIRED TO OPERATE
AND MAINTAIN A 3,000 MW POWER PLANT
Skill Numbers
Electrical Engineers 16
Mechanical Engineers 8
Total Engineers 24
Total Designers + Draftsmen 4
Total Supervisors + Managers 56
Total Technical ,84
Total Non-Tech (Non-Manual) 40
Pipefitters 32
Pipefitter/Welder 48
Electricians 48
Boilermaker/Welders 32
Other Operators 80
Total Major Skills 240
Total Craftsmen 240
Total Teamsters + Laborers 72
GRAND TOTAL 436
-346-
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TABLE 3-133. SELECTED MAJOR MATERIALS AND EQUIPMENT REQUIRED
FOR CONSTRUCTION OF A 3,000 MW POWER PLANT
Resource Number
Refined Products (tons) 72,400
Ready Mixed Concrete (tons) 456,400
Pipe + Tubing (less than 24% D) (tons) 11,800
Pipe + Tubing (24% D + Greater) (tons) 1,200
Structural Steel (tons) 20,360
Reinforcing Bars (tons) 6,000
Valves (24% D + Greater) (items) 120
Valves (24% D + Greater) (tons) 100
Steam Turbogenerator Sets (1,000 hp) 4,280
Steam Turbines w/o Generators (1,000 hp) 120
Pumps + Drives (100 hp) (items) 140
Pumps + Drives (100 hp) (tons) 848
Heat Exchangers (1,000 sq. ft. surface) 600
Boilers (1,000,000 Btu/hr) 28,000
Source: Carasso, M., et al. Energy Supply Model, Computer Tape.
San Francisco: Bechtel Corporation, 1975.
-347-
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Table 3-123 and assuming an average annual wage of $15,000,
then total annual operating costs excluding coal costs * $4
million + (436) ($15,000) « $10.5 million. It should be noted
that since these values are in third-quarter 1974 dollars, price
escalations for future years must be considered.
3.8.3.2d Water Requirements
The major consumer of water in a power plant is the cooling
tower system. The make-up water for the cooling tower system
replaces three losses - drift, blowdown, and evaporation. The
magnitude of each of these losses is calculated from mass and
energy balances around the cooling system by using the following
assumptions or data.
1) 48% of input heat to the plant is sent to the
cooling towers.
2) 90% of the heat to the cooling towers is
dissipated via evaporation.
3) The heat of vaporization of water is 1050
Btu/lb.
4) The cooling water temperature rise across the
steam condenser is 25°F.
5) Cooling tower drift losses are 0.02% of the
cooling water circulation rate.
For a 3000 Mw power plant at 100% load factor and a 34%
efficiency, the cooling tower makeup water requirements are
42,000 acre-ft per year. (See Section 3.8.3.3 for a more
-348-
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detailed description of facility size, efficiency, etc.) Other
water losses include potable water, cleaning water, and other
miscellaneous uses. These uses, however, are negligible com-
pared to cooling tower usage. The process water used elsewhere
in the plant has virtually no losses since all excess water
(e.g., boiler blowdown) is sent to the cooling tower as makeup
water.
3.8.3.2e Land Requirements
A 1,000 Mwe coal-fired power plant requires 800 acres of
land area. Linearly scaling to a 3,000 Mwe plant gives the land
requirement as 2,400 acres. Within this 2,400 acres will be a
968 acre solar evaporation pond for cooling tower blowdown and
a 228 acre limestone sludge disposal pit. These figures were
determined for a 3,000 Mwe power plant at Gillette, Wyoming.
3.8.3.2f Ancillary Energy
There are no outside energy requirements for operation of
a power plant.
3.8.3.3 Outputs
This section of the analysis considers the outputs from a
3,000 Mwe electrical generating facility design to burn coal
from the Gillette, Wyoming vicinity. A description of this coal
is shown in Table 3-134. The power plant is a new plant which
utilizes a supercritical steam boiler system to drive steam
turbines which in turn drive generators. A supercritical steam
boiler operates at a temperature and pressure above the super-
critical point of water.
-349- -
-------
TABLE 3-134. CHARACTERISTICS OF GILLETTE,
WYOMING COAL
Location
Campbell County
Powder River Coal Field
Proximate Analysis. 7o
Dry Basis Avg. Wet Basis
Moisture: 30.8-33.3 32.1 32.17.
Volatile: 39.0 - 47.7 43.4 32.2
Fixed C: 31.8-52.7 42.0 30.6
Ash: 6.0- 8.9 7.5 5.1
Ultimate Analysis, %
Ash: 5.0 - 8.9
S: 0.3 - 0.8 - average =0.55
H : 4.7 - 5.2
C: 45.7 - 74.5
N: 0.6 - 1.1
0: 16.1 - 40.5
Btu/lb (as received): 7,770 - 12,780 - avg: 10,275
Source: Evaluation of Low-Sulfur Western Coal.
EPA-650/2-75-046.May 1975.
-350-
-------
The efficiency of the power plant is assumed to be 34%.
This efficiency is defined as the net electrical energy output
of the plant divided by the energy input to the plant. Net
electrical energy output is defined as gross electrical energy
generated minus any plant auxiliary energy requirements. Although
the cycle efficiency of the power plant is 38%, the overall net
efficiency is 34% due to a usage of 4% of the gross electrical
production by the lime/limestone scrubbers* (see Sections 3.8.3.1
and 3.8.3.3a).
The load factor at the plant was assumed to be 100%. This
value was chosen in order to quantify maximum daily emissions
with the facility operating at capacity output. It should be
noted, however, that load factors can vary greatly. Some power
plants in areas of highly varying electrical demand have load
factors lower than 50%.
The coal usage at this 3,000 Mw powe'r plant burning 10,275
Btu/lb coal with an overall efficiency of 34% and a load factor
of 100% is 35,180 tons per day.
3.8.3.3a Air Emissions
The only significant air emissions from a power plant come
from the boiler flue gas produced during combustion of the
plant's fuel. Emission rates of particulates, SOa, NOX, CO and
hydrocarbons are calculated from fuel rates, fuel ash and sulfur
contents and emission factors from "Compilation of Air Pollutant
Emission Factors."1 Carbon dioxide emissions are based on the
theoretical combination of the-coal analysis presented in
Table 3-134.
XU.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors, 2nd ed., with supplements.Research
Triangle Park, N.C.: Environmental Protection Agency, 1973.
-351-
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The SO2 and particulate emissions are assumed to be
controlled by a limestone scrubbing unit. The particulates
are 99 percent controlled by an electrostatic precipitator
which precedes the SOz scrubber in the limestone scrubbing unit.
The SOz emissions are 80% controlled in the scrubbing unit.
Table 3-135 lists the air emissions resulting from these
operations.
3.8.3.3b Water Effluents
Water effluents are calculated as suspended solids, total
dissolved solids, and organic matter. Battelle1 states that
suspended solids and organic matter in power plant liquid wastes
amount to 0.036 lb/106 Btu of fuel burned. Of this total 70%
is suspended solids and 3078 is organic matter. This factor and
plant heat rates are used to calculate these two emissions.
Total dissolved solids (TDS) are calculated by assuming that
cooling tower blowdown, containing 10,000 ppm of TDS, is the
main liquid effluent.
Using the above basis and a total blowdown rate of 1,400
gpm, 756 Ib/hr suspended solids (1,000 ppm) and 324 Ib/hr
organics (460 ppm) are emitted with the cooling tower blowdown.
At Gillette, Wyoming, of the 2,258 acre-ft/yr blowdown (1,400 gpm),
2,096 acre-ft/yr are sent to solar evaporation ponds and 162
acre-ft/yr are sent to SOz scrubbing as make-up water for the
limestone scrubber.
Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus Laboratories, 19737
-352-
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TABLE 3-135. AIR EMISSIONS - 3,000 MW POWER PLANT
BURNING GILLETTE, WYOMING COAL1
Emissions/750 MW Boiler Total Plant Emissions
Participates2
S023
NOx
CO
HC
Aldehydes
CO 2
Flow Rate
(acfm)
(Ib/hr)
299
1,610
6,580
366
110
2
1,600,000
Stack Parameters (per boiler)
Velocity Height Temp .
(fps) (ft) CF)
(tons/day)
14.4
77.3
316.0
17.6
5.3
0.1
76,800
Diameter
(ft)
2.56 x 10s
60
500
180
30.0
1 Based on combustion of 35,180 TPD of 10,275 Btu/lb coal.
2Based on 5% ash and 99% control
3Based on 0.58% sulfur and 80% control.
-353-
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3.8.3.3c Solid Wastes
The two primary types of solid waste produced at the power
plant are ash from the boiler and electrostatic precipitators
and sludge from the S02 scrubbers. The ash which is collected
is the ash which enters the boiler in the coal and is not emitted
out the stack (see Table 3-135). The ash collected at the 3,000
Mw power plant burning 35,180 tons per day of coal with 5 per-
cent ash is 1745 tons per day. Concern has been raised about
radioactive emissions from trace amounts of Radon 220 and 222 in
coal ash. Concentrations are on the order of 10-20 of these
materials, but emissions could be as high as 10 times background
emissions depending upon coal composition and method of ash
disposal.*
The quantity of scrubber sludge is determined on the basis
of 80 percent S02 removal producing 90 percent CaSOa and 10 per-
cent CaSO.,. In addition, the sludge contains a small amount of
unreacted limestone (assumed to be 10 percent of the CaCOs which
is reacted). The quantity of solids produced on this basis is
62,000 pounds per hour. These solids leave the sludge thickener
in a 30 weight-percent solids water slurry and are sent to the
settling pond. The slurry flow rate to the pond is 207,000 pounds
per hour. Supernatant from the settling pond is removed as makeup
water to the scrubbers at a rate which will maintain a 50 weight-
percent solids sludge in the settling pond. The net flow to the
TLee, Hong, et al. Potential Radioactive Pollutants Result-
ing from Expanded Energy Programs.EPA 600/7-77-082.Las Vegas,
RV7U.S. Environmental Protection Agency, Office of Research and
Development, Environmental Monitoring and Support Laboratory.
1977. p. 46, 124.
-354-
-------
pond (input sludge less withdrawn supernatant), therefore, is
approximately 124,000 pounds per hour (1488 tons/day). It should
be noted, however, that these wastes are disposed of on-site as
part of the generation process.
3.8.3.3d Noise Pollution
Noise emissions will be generated during both the
construction and the operation phases of a coal-fired power
plant. Sources of noise emissions during the construction
phase are primarily associated with heavy duty construction
equipment such as cranes, bulldozers, dump trucks, graders,
air compressors, rock drills, pneumatic wrenches, and welding
generators. The sound levels for each of these pieces of
equipment range from 80 dBA for bulldozers and dump trucks to
98-99 dBA for rock drills and pneumatic wrenches. Total sound
levels in the construction area will range from 89 dBA to
110 dBA.1
Principal noise sources for an operating coal-fired power
plant include the cooling towers, pulverizer, coal pile bull-
dozers, coal car shakers, and rail car switching. Bulldozers
and rail car switching will emit approximately 80 dBA. The
cooling towers and pulverizer will emit approximately 104 dBA.
^attelle Memorial Institute, Columbus Laboratories.
Detailed Environmental Analysis Concerning a Proposed Coal
Gasification Plant for Trans-Western Coal Gasification CoT,
Pacific Coal Gasification Co., and Western Gasification Co.,
and the Expansion of a Strip Mine Operation Near Bumham, N.M.
Owned and Operated by Utah International, Inc.
-355-
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And the coal car shakers will emit approximately 101 dBA.
Noise levels of 55 dBA will extned about one mile from the
plant.1'2'3
3.8.3.3e Occupational Health and Safety
Data on injuries, deaths, and man-days lost are available
from Battelle.1 Converting from Battelle's basis of 106 Btu to
a 3,000 Mwe power plant yields the following expected annual
values; 0.77 deaths, 3.2 injuries, and 1,200 man-days lost.
SUMMARY
Table 3-136 presents a summary of the direct impacts
associated with a 3,000 Mwe power plant in Gillette, Wyoming.
3.8.4 Social Controls
The regulation of conversion activities covers a wide
range of technologies and residuals, including orderly devel-
opment, environmental protection, health and safety, and
regulation of product output. In the following section, the
federal and state permit and regulatory structure over these
activities will be discussed. These social controls will be
described, beginning with Water Quality, Water Use, Air Quality,
^racor, Inc. Guidelines on Noise. Washington, D.C.:
American Petroleum Institute, 1973.
2Bolt, Beranek, and Newman. Noise from Construction
Equipment and Operations, Building Equipment and Home Appliances
Cambridge, Mass.:Bolt, Beranek, ana Newman,1971.
3Swing, Jack W., and Donald B. Pies. Assessment of Noise
Environments Around Railroad Operations, Report No. WCR 73-5.
El Segundo, Calif.:Wyle Laboratories, 1973.
**Battelle Columbus and Pacific Northwest Laboratories.
Environmental Considerations in Future Energy Growth. Columbus,
Ohio:Battelle Columbus Laboratories, 1973.
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TABLE 3-136. SUMMARY OF IMPACTS ASSOCIATED WITH A
3000 MW POWER PLANT AT GILLETTE, WYOMING
Input Requirements
Manpower
• construction phase
• operation and maintenance
Materials and Equipment
• refined produces
• ready mix concrete -
• piping
• sceel
• steam turbogenerators
• boilers
Economics
• capital cost
• operating cost (excluding coal)
Water
Land
Ancillary Energy
9,960 man years
436 people
72,000 Cons
456,000 tons
13,000 tons
26,000 tons
4 million hp
28 billion Btu/hr
$880 million
$11 Million
42,000 acre-ft/year
2,400 acres
none
Outputs
Air Emissions
• particulaces
' N0x
. CO
• HC
• Aldehydes
• C02
Water Effluents
• to zero discharge solar evap. ponds
Solid Wastes
• ash
• FGD scrubber sludge
Noise Pollution
Occupational Safety and Health
• fatalities
• injuries
• los* tine
14 ton/day
77 ton/day
316 ton/day
18 ton/day
5 ton/day
0.1 ton/day
76,800 ton/day
2,096 acre-ft/year
1,745 ton/day
1,488 ton/day
minimal
0.77 deaths
3.2 injuries
1200.0 man-davs
*third quarter 1974 dollars
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Solid Waste, Noise, Safety and the Regulation of Product Output.
A generalized flow diagram of the sequence of regulator proce-
dures dealing with processing is shown in Figure 3-32.
3.8.4a Water Quality
Regulation of coal conversion facilities for water dis-
charges can occur at the state and federal level. The provisions
for this regulation have been described in the section on gener-
ally applicable regulations, which identified the Federal Water
Pollution Control Act of 1972 (FWPCA) as the major legislation
affecting water discharges.
The requirements of FWPCA do not supersede water quality
standards affecting navigation under the 1899 Rivers and Harbors
Act. Thus, the Army Corps of Engineers still issues permits
for constructing discharge into navigable waterways, and EPA
issues permits on the use of such discharges.1 The FWPCA pro-
vides for establishing a system of permits that are issued
either by EPA or by the states with EPA approval. The permit
must specify the substance to be discharged and how and when
water quality will be improved.
The technologies described in Section 3.8 have been designed
for zero discharge. If discharges were to be made, the above
laws would be applicable, in addition to appropriate state
regulations and permit programs.
Environment Information Center. "Water Pollution" in
Environment Regulation Handbook. New York: Environment Infor-
mation Center, 1973, Water Int. 3.
-35-3-
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Request Permits to Initiate
Mai or Federal Action
File EIS as in
Exploration Phase
EIS Process
(LEAD Agency)
Obtain
Discharge
Permit
(CORPS)
Obtain
Regulative
Certification
If Applicable
(FPC)
Plant Construction Phase
Obtain Other
Permits and
Right-of-Ways
Monitor
Air
Emissions
(EPA)
Report
Accidents
(OSHA)
Monitor Plant
Product(s)
Output
(FEA. FPC)
Figure 3-32. Processing Procedures
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3.8.4b Water Use
Obtaining water for conversion facilities can require a
complex interaction with federal, intergovernmental, state and
local agencies in order to build a dam, drill a water well, or
remove water from a stream or water district pipe. Water rights
laws are complex, and typically are most important at the state
level. The procedures for obtaining water have been described
in Chapter 2 on generally applicable social controls.
3.8.Ac Air Quality
Both the states and federal government have major regulations
that deal with the control of air quality affected by processing
emissions. The legislation and air quality standards have been
described in Chapter 2 on general social controls.
Standards for air quality are established by the federal
government, and most of the enforcement is left to the states.
EPA has the primary role in developing and promulgating minimum
air quality standards, which have been of two types: ambient
standards on the quality of the atmosphere as measured at ground
level (usually) and emission standards for quantities of pollutant
discharges from processing facilities. The "New Source Performance
Standards" for coal burning facilities are listed in Table 3-137.1
3.8.4d Solid Wastes
Much of the disposal problem in coal processing facilities
deals with the disposal of ash, slag or other chemical by-products
(sulfur, calcium sulfate, etc.). Solid wastes, however, are the
^Emission standards for liquefaction and gasification plants
have not been established.
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TABLE 3-137. FEDERAL NEW SOURCES OF COAL
BURNING EMISSION STANDARDS
Contaminant Quantity
(1 pound per million Btu)
Sulfur Dioxide 1.2
Nitrogen Oxides 0.7
Particulates 0.1
Opacity (percent) 20.0
Source: U.S., Department of the Interior, Bureau of Reclamation.
El Paso Coal Gasification Project, New Mexico: Draft
Environmental Statement^Salt Lake City:Bureau of
Reclamation, Upper Colorado Region, 1974.
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major form of pollutant for which the federal government has not
set standards. Much of the problem is handled by the state
governments, as has been described in Chapter 2 on general social
controls. Also noted in the general social controls are the
impacts of the air and water laws on solid waste disposal.
3.8.4e Noise
Noise control is under the jurisdiction of both the Occu-
pational Health and Safety Administration (OSHA) and the Environ-
mental Protection Agency (EPA). OSHA standards and enforcement
deal primarily with worker exposure, whereas EPA standards cover
a broader area. The Federal Power Commission (FPC) requires that
above ground compressors must be located and treated to reduce
noise impacts.l
Noise control standards were established by the Occupational
Health and Safety Act of 1970 (OSHA) and are also referenced
by the Federal Coal Mine Health and Safety Act2 (see section on
mining social controls). Procedures for enforcing the OSHA
standards are described in the following section on safety.
Current noise standards are shown in Table 3-138. If these
standards are exceeded some protection must be provided against
the effects of noise exposure. In addition to the standards
listed, noise from impulses, or impacts are not to exceed 140
decibels (dB).
3.8.4f Safety
Coal processing activities usually involve high temperatures
'18 CFR 2.69.
2Federal Coal Mine Health and Safety Act of 1969, 15 USC
Sections 633.636; 30 USC Sections 801-804, 811-821, 841-846,
861-878, 901, 902, 921-924, 931-936, 951-960; 83 Stat. 742.
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TABLE 3-138. OSHA NOISE LEVEL STANDARDS3
Noise Duration Maximum Sound Level
(hours/day) (Decibels)
15 minutes 115
30 minutes 110
60 minutes 105
90 minutes 102
2 hours 100
3 hours 97
4 hours 95
6 hours 92
8 hours 90
aMaximum values without ear protection.
Source: U.S., Department of the Interior, Bureau of Reclamation,
El Paso Coal Gasification Project, New Mexico: Draft
Environmental Statement"! Salt Lake City: Bureau of
Reclamation, Upper Colorado Region, 1974.
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and pressures and expose workers and others in the immediate area
of the plant to hazards from equipment failure or misuse. A
number of federal, state and industrial regulations deal with
these safety problems:
Federal
Federal jurisdiction over processing -safety is derived
largely from the Occupational Safety and Health Act of 19701 and
the Natural Gas Pipeline Safety Act of 19682. The Departments
of Labor and Health, Education and Welfare (HEW) have the major
responsibilities under OSHA. HEW makes working condition evalua-
tions and provides technical assistance to employers, and Labor
is responsible for enforcement, the Office of Pipeline Safety
within the Department of Transportation is responsible for pro-
mulgation and enforcement of most interstate gas transmission
facilities, and apparently has some jurisdiction over coal gasi-
fication projects. The Occupational Safety and Health Administra-
«
tion has developed an extensive and complex set of standards and
regulations.
Enforcement of the standards is handled by the Assistance
Secretary for Occupational Safety and Health, who has most of the
ultimate decision making authority. There are four sets of stan-
dards: (1) general industry standards, (2) special industry
standards, (3) construction safety standards, and (4) maritime
standards. Although the major elements of the standards are
published in four sections of the Code of Federal Regulations,
Occupational Safety and Health Act of 1970, 5 USC Sections
5108, 5314, 5315, 7902; 15 USC Sections 633, 636, 18 USC Section
1114; 29 USC Sections 553. 651-678; 42 USC Section 3142-1; 84
Stat. 1590.
2Natural Gas Pipeline Safety Act of 1968, 49 USC Section
1671, 82 Stat. 720.
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many of the standards refer to the American National Standards
Institute (ANSI) "national consensus standards"1. Significant
research efforts are currently underway to refine and develop
additional standards in many areas, and much of this work is
conducted by the National Institute for Occupational Safety and
Health (NIOSH) under HEW. Apparently some of this research is
applicable to emerging coal conversion technologies.
States
Prior to the passage of the Occupational Safety and Health
Act, most of the responsibility for worker safety rested with
the states. The states may enforce the OSHA standards, but they
will be preempted if they fail to do so.2 At the present time,
only Colorado, Utah and Wyoming in the 8-state region have
operating OSHA plans.
Industry
Processing plant design and safety features usually employ
company manuals of engineering standards, current refinery codes
and power piping codes. These codes are primarily standards
established by the American Standards Institute (ANSI) which
develops the consensus standards frequently referenced by OSHA.3
Mallino, David L., and Shaun M. Werner, eds. Occupational
Safety and Health: A Policy Analysis. Washington: Government
Research Corporation, 1973, p. 10.
U.S., President. Report on Occupational Safety and Health.
Washington: Government Printing Office,1972, p.35.
U.S., Department of the Interior, Bureau of Reclamation.
El Paso Coal Gasification Project, New Mexico: Draft Environmental
Statement"! Salt Lake City: Bureau of Reclamation, Upper Colorado
Region, 1974, p. 4-41.
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3. 8.4g Regulation of Product Output
Under certain circumstances the output of processing faci-
lities is regulated by federal and state energy agencies or
regulator commissions. The applicability of these regulations
is uncertain at this time, and may be dependent on policies
developed in the near future. Apparently neither the Interstate
Commerce Commission (for liquid and solids) nor the Federal
Power Commission (for gas) is presently exercising jurisdiction
over price or supply distribution of synthetic fuels except as
these relate to pipelines or other transportation systems.
The regulation of product output and distribution, as well
as the use of raw energy inputs has recently become a major
element of federal energy regulation. These activities were
initially accomplished by the Federal Energy Office (FEO) and
are now the responsibility of the Department of Energy (DOE) l .
DOE has broad regulatory powers over the allocation of petroleum,
but apparently has less authority over the use and price of coal.
DOE has, however, issued regulations under which it may allocate
and price low sulfur coal to such processing facilities as elec-
tric power generation facilities. Although it can control the
product mix of petroleum processing facilities (i.e., refineries),
it is not known at this time if it would exercise similar authority
over synthetic fuels facilities.
Energy Supply and Environmental Coordination Act of 1974,
15 USC Section 791 et seg., 42 USC Section 1857, 88 Stat. 246.
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3.8.4h Other Requirements
Components of processing facilities may involve a number
of additional agencies or regulator pr-ecedures. For example,
these facilities are frequently somewhat isolated and require
radio-communication facilities and permits from the Federal Com-
munication Commission for the construction and operation of such
facilities. Large scale operations may require health permits
for food or hospital facilities. Of course, business and tax
permits need to be acquired, usually with state Revenue
Departments or Corporation Commissions. Details of these per-
mits and regulatory arrangements will not be covered in this
chapter..
» nt QumaMi mam OMCE an -z«i-i47/62
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