Analysis
repared for CEQ • ERDA • EPA • FEA • FPC • DOI • NSF
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Energy
Alternatives:
A Comparative
Analysis
Prepared for
Council on Environmental Quality
Energy Research and Development Administration
Office of the Assistant Administrator
for Planning and Analysis
Environmental Protection Agency
Division of Policy Planning
Office of Energy Research
Federal Energy Administration
Office for Environmental Programs
Federal Power Commission
Office of Energy Systems
Department of the Interior
Bureau of Land Management
Office of Research and Development
National Science Foundation
Office of Energy R & D Policy
by The Science and PuWic Policy Program,
University of Oklahoma, Norman, Oklahoma
May 1975
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PREFACE AND ACKNOWLEDGMENTS
The descriptions and analysis of
energy resource systems in this report were
prepared by an interdisciplinary research
team working under the Science and Public
Policy Program at the University of
Oklahoma. The study, conducted under
Contract Number EQ4AC034 with the Council
on Environmental Quality, was funded by
the Atomic Energy Commission (now a part
of the Energy Research and Development
Administration) , Council on Environmental
Quality, Department of Interior, Bureau of
Land Management, Environmental Protection
Agency, Federal Energy Administration, and
Federal Power Commission.
The Science and Public Policy Program
was able to develop this report in a rela-
tively short time because the first part
of the report parallels and draws heavily
on research being carried out under phase
one of a complementary project supported by
National Science Foundation Grant Number
SIA74-17866, "An Energy Systems Analysis of
Alternative Resource Options." This volume
will serve as a publicly available data
base for the National Science Foundation
study.
The team which prepared this report
included: Don E. Kash, Director of the
Science and Public Policy Program and
Professor of Political Science; Irvin L.
(Jack) White, Assistant Director of the
Science and Public Policy Program and
Professor of Political Science; Karl H.
Sergey, Research Fellow in Science and
Public Policy and Professor of Aerospace,
Mechanical, and Nuclear Engineering;
Michael A. Chartock, Research Fellow in
Science and Public Policy and Assistant
Professor of Zoology; Michael D. Devine,
Research Fellow in Science and Public
Policy and Associate Professor of Industrial
Engineering; James B. Freim, Research Fellow
in Science and Public Policy and Assistant
Professor of Aerospace, Mechanical, and
Nuclear Engineering; Martha w. Gilliland,
Research Fellow in Science and Public
Policy; Timothy A. Hall, Research Assistant
in Science and Public Policy; David A.
Huettner, Research Fellow in Science and
Public Policy and Associate Professor of
Economics; R. Leon Leonard, Research Fellow
in Science and Public Policy and Assistant
Professor in Aerospace, Mechanical, and
Nuclear Engineering; Paul J. Root, Research
Fellow in Science and Public Policy and
Professor of Petroleum and Geological
Engineering; Thomas J. Wilbanks, Research
Fellow in Science and Public Policy and
Associate Professor and Chairman of
Geography; and David Willcox, Research
Fellow in Science and Public Policy and
Visiting Assistant Professor of Philosophy.
The team's research was supported by Hee
Man Bae, Gary Bloyd, Robert w. Rycroft, and
Cheryl Swanson, all Research Assistants in
Science and Public Policy. Mark Elder,
Co-Director of Program Development, Office
of Research Administration, was technical
editor of the report.
A number of people served as consul-
tants on the study, and we wish to express
our appreciation to them for their assis-
tance and expert advice. They include:
Marian Blissett, Associate Professor, the
LBJ School of Public Affairs, University of
Texas-Austin; James Christensen, Associate
Professor of Chemical Engineering and
111
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Materials Science, University of Oklahoma;
Donald E. Henzie, Professor of Petroleum
and Geological Engineering, University of
Oklahoma, and Paul G. Risser, Director of
the Oklahoma Biological Survey. Pong N.
Lem of the Denver National Environmental
Research Center, Environmental Protection
Agency, provided particularly useful cri-
tiques of the preliminary report.
The staff of the Science and Public
Policy Program was indispensable in the
preparation of this study. Janice K.
Whinery directed the logistics as Project
Specialist. Peggy L. Neff directed the
preparation of the manuscript as Clerical
Supervisor and, with Pamela J. Dickey,
Carol B. Friar, Linda Edzards, and
Pamela K. Hignite, typed the numerous
research papers and drafts of this report.
Martha T. Jordan and Nancy J. Creighton
served as research assistants and were
essential in handling the data and refer-
ences for the report. Ginna A. Davidson
was scientific illustrator and prepared
most of the figures. Sheila Mulvihill was
the Technical Editor for the Council on
Environmental Quality.
Sole responsibility for the contents
of this report rests with the Science and
Public Policy Program of the University of
Oklahoma. Any factual or interpretative
errors are those of the research team which
conducted the research and prepared this
report.
We also wish to express appreciation
for the advice and suggestions of members
of Ae Interagency Committee: Steven
Jellinek, Barrett Riordan, and Malcolm
Baldwin, Council on Environmental Quality;
Carolita Kallaur, Flora Milans, Rima Cohen,
Matthew J. Reilly, and Nicolai Timenes, Jr.,
Department of the Interior; Richard
Livingston, Environmental Protection Agency;
Richard H. Williamson, Energy Research and
Development Administration; Kenneth Woodcock
and Ernest Sligh, Federal Energy
Administration; Richard Hill, Federal Power
Commission. In addition, Stephen Gage, now
at the Environmental Protection Agency,
played a major conceptual role while he
was at the Council on Environmental Quality
during the early period of the study. We
want to express particular appreciation to
Marvin Singer, Chairman of the Interagency
Committee, who provided invaluable assis-
tance and support. Finally, we wish to
thank Charles Johnson and William Wetmore
of the Office of Systems Integration and
Analysis, Research Applied to National
Needs Division of National Science
Foundation, for assistance in coordinating
the National Science Foundation-funded
research with this study.
iv
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PAGE
Preface and Acknowledgments iii
Table of Contents vi
List of Tables xxv
List of Figures xxxi
List of Exhibits xxxiv
List of Acronyms and Abbreviations xxxv
General Introduction xxxvii
Introduction: Part I 1-1
Introduction: Part II II-2
Glossary G-l
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TABLE OP CONTENTS
PAGE
PART I: DESCRIPTIONS OP ENERGY RESOURCE SYSTEMS
CHAPTER 1: THE COAL RESOURCE SYSTEM
1.1 INTRODUCTION 1~1
1.2 A NATIONAL OVERVIEW 1-1
1,2.1 Total Resource Endowment 1-1
1.2.2 Characteristics of the Resources 1-3
1.2.3 Location of the Resources 1-7
1.2.4 Recoverability of the Resources 1-7
1.2.5 Ownership of the Resources 1-9
1.3 A REGIONAL OVERVIEW 1-9
1.3.1 The Eastern Province 1-9
1.3.2 The Interior Province 1-11
1.3.3 The Northern Great Plains Province 1-13
1.3.4 The Rocky Mountain Province 1-13
1.4 SUMMARY 1-16
1.5 EXPLORATION 1-16
1.5.1 Technologies 1-16
1.5.2 Energy Efficiencies 1-18
1.5.3 Environmental Considerations 1-18
1.5.4 Economic Considerations 1-18
1.6 MINING AND RECLAMATION 1-18
1.6.1 Technologies 1-18
1.6.1.1 Surface Mining 1-18
1.6.1.1.1 Surface Preparation 1-21
1.6.1.1.2 Fracturing 1-24
1.6.1.1.3 Excavation 1-24
1.6.1.2 Underground Mining 1-27
1.6.1.2.1 Room and Pillar 1-28
1.6.1.2.2 Longwall 1-31
1.6.1.3 Mine Safety 1-37
1.6.1.4 Reclamation 1-37
1.6.1.4.1 Surface Mine Reclamation 1-37
1.6.1.4.2 Contour Mine Reclamation 1-41
1.6.1.4.3 Area Mine Reclamation 1-41
1.6.1.4.4 Underground Mine Reclamation 1-41
1.6.2 Energy Efficiencies 1-44
1.6.2.1 Surface Mining and Reclamation 1-44
1.6.2.2 Underground Mining 1-46
1.6.3 Environmental Considerations 1-47
1.6.3.1 Surface Mining and Reclamation 1-47
1.6.3.1.1 Water 1-50
1.6.3.1.2 Air 1-50
1.6.3.1.3 Solids 1-52
1.6.3.1.4 Land 1-52
1.6.3.1.5 Summary 1-53
VI
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PAGE
1.6.3.2 Underground Mining 1-53
1.6.3.2.1 Water 1-53
1.6.3.2.2 Air 1-53
1.6.3.2.3 Solids 1-55
1.6.3.2.4 Land !-55
1.6.4 Economic Considerations 1-56
1.6.4.1 Surface Mining and Reclamation 1-56
1.6.4.2 Underground Mining and^Reclamation 1-58
1.7 WITHIN AND NEAR MINE TRANSPORTATION 1-58
1.7.1 Technologies 1-58
1.7.1.1 Surface Mine Transportation 1-58
1.7.1.2 Underground Mine Transportation 1-59
1.7.2 Energy Efficiencies 1-59
1.7.2.1 Surface Mine Transportation 1-59
1.7.2.2 Underground Mine Transportation 1-59
1.7.3 Environmental Considerations 1-60
1.7.3.1 Surface Mine Transportation 1-60
1.7.3.2 Underground Mine Transportation 1-60
1.7.4 Economic Considerations 1-60
1.7.4.1 Surface Mine Transportation 1-60
1.7.4.2 Underground Mine Transportation 1-63
1.8 BENEFICIATION 1~63
1.8.1 Technologies 1-63
1.8.2 Energy Efficiencies 1-64
1.8.3 Environmental Considerations 1-64
1.8.3.1 Breaking and Sizing 1-67
1.8.3.2 Washing 1~67
1.8.3.2.1 Water 1~67
1.8.3.2.2 Air I"6?
1.8.3.2.3 Solids 1-67
1.8.3.2.4 Land l~67
1.8.4 Economic Considerations 1-67
1.9 PROCESSING , !~68
1.9.1 Technologies 1~68
1.9.1.1 Gaseous Fuels 1-68
1.9.1.1.1 Preparation 1-68
1.9.1.1.2 Gasification 1-68
1.9.1.1.3 Upgrading 1-72
1.9.1.1.4 Specific Low-Btu Gasification Processes 1-72
1.9.1.1.4.1 Lurgi 1~72
1.9.1.1.4.2 Koppers-Totzek 1-72
1.9.1.1.4.3 Bureau of Mines Stirred Fixed Bed 1-77
1.9.1.1.4.4 Westinghouse Fluidized-Bed Gasifier 1-77
1.9.1.1.4.5 Ash Agglomerating Fluidized-Bed Gasifier 1-77
1.9.1.1.5 Specific High-Btu Gasification 1-81
1.9.1.1.5.1 Lurgi High-Btu Gasification 1-83
1.9.1.1.5.2 HYGAS 1-83
1.9.1.1.5.3 BI-GAS 1-86
1.9.1.1.5.4 Synthane 1~86
1.9.1.1.5.5 C02 Acceptor 1-89
1.9.1.1.6 Underground Coal Gasification 1-91
1.9.1.2 Liquid Fuels 1-92
1.9.1.2.1 Synthoil 1~92
1.9.1.2.2 H-Coal 1-97
1.9.1.2.3 Solvent Refined Coal 1-97
1.9.1.2.4 Consol Synthetic Fuel 1-97
1.9.1.2.5 COED 1-101
1.9.1.2.6 TOSCOAL , , ,
1.9.1.2.7 Fischer-Tropsch 1-101
1.9.1.2.8 Methanol 1-105
vii
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PAGE
1.9.1.3 Solvent Refined Solid Fuels 1-105
1.9,2 Energy Efficiencies 1-105
1.9.2.1 Gaseous Fuels 1-105
1.9.2.1.1 Low-Btu Gasification 1-105
1.9.2.1.2 High-Btu Gasification 1-105
1.9.2.2 Liquid Fuels 1-105
1.9.2.3 Solvent Refined Solids 1-107
1.9.2.4 Summary 1-107
1.9.3 Environmental Considerations 1-107
1.9.3.1 Gaseous Fuels 1-107
1.9.3.1.1 Low-Btu Gasification 1-107
1.9.3.1.1.1 Water 1-107
1.9.3.1.1.2 Air 1-107
1.9.3.1.1.3 Solids 1-110
1.9.3.1.2 High-Btu Gasification 1-113
1.9.3.1.2.1 Water 1-113
1.9.3.1.2.2 Air 1-113
1.9.3.1.2.3 Solids 1-114
1.9,3.1.2.4 Land 1-114
1.9.3.2 Liquid Fuels 1-114
1.9.3.2.1 Water 1-114
1.9.3.2.2 Air 1-117
1.9.3.2.3 Solids 1-118
1.9.3.2.4 Land 1-118
1.9.3.3 Solvent Refined Solids 1-118
1.9.3.3.1 Water 1-118
1.9.3.3.2 Air 1-119
1.9.3.3.3 Solids 1-119
1.9.3.3.4 Land 1-120
1.9.4 Economic Considerations 1-120
1.9.4.1 Gaseous Fuels 1-120
1.9.4.1.1 Low-Btu Gasification 1-120
1.9.4.1.2 High-Btu Gasification 1-121
1.9.4.2 Liquid Fuels 1-121
1.9.4.3 Solvent Refined Solids 1-122
1.9.5 Summary 1-122
1.10 TRANSPORTATION 1-122
1.10.1 Technologies 1-122
1.10.1.1 Transporting Raw Coal 1-122
1.10.1.1.1 Railroads 1-122
1.10.1.1.2 Barges 1-123
1.10.1.1.3 Trucks 1-123
1.10.1.1.4 Pipelines 1-123
1.10.1.2 Transporting Coal Products 1-123
1.10.2 Energy Efficiencies 1-124
1.10.3 Environmental Considerations 1-124
1.10.3.1 Water 1-126
1.10.3.2 Air 1-126
1.10.3.3 Solids 1-126
1.10.3.4 Land 1-126
1.10.4 Economic Considerations 1-126
REFERENCES 1-129
viii
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PAGE
CHAPTER 2: THE OIL SHALE RESOURCE SYSTEM
2.1 INTRODUCTION 2-1
2.2 RESOURCE DESCRIPTION
2.2.1 Total Resource Endowment 2-3
2.2.2 Characteristics of the Resource 2-3
2.2.3 Location of the Resources 2-4
2.2.4 Ownership of the Resources 2-9
2.3 EXPLORATION 2-9
2.3.1 Technologies 2-9
2.3.2 Energy Efficiencies 2-10
2.3.3 Environmental Considerations 2-10
2.3.4 Economic Considerations 2-10
2.4 MINING 2-10
2.4.1 Technologies 2-11
2.4.1.1 Surface Mining 2-11
2.4.1.2 Underground Mining 2-11
2.4.1.3 Mine Safety 2-13
2.4.2 Energy Efficiencies 2-13
2.4.2.1 Surface Mining 2-15
2.4.2.2 Underground Mining 2-15
2.4.3 Environmental Considerations 2-15
2.4.3.1 Surface Mining 2-15
2.4.3.1.1 Air Pollutants 2-17
2.4.3.1.2 Solid Wastes 2-17
2.4.3.1.3 Land 2-17
2.4.3.1.4 Water Production and Use 2-17
2.4.3.2 Underground Mining 2-17
2.4.3.2.1 Water Pollutants 2-17
2.4.3.2.2 Air Pollutants 2-18
2.4.3.2.3 Solid Wastes 2-18
2.4.3.2.4 Land 2-18
2.4.3.2.5 Water Production and Use 2-18
2.4.3.3 Environmental Summary 2-18
2.4.4 Economic Considerations 2-18
2.5 WITHIN AND NEAR-MINE TRANSPORTATION 2-18
2.5.1 Technologies 2-18
2.5.2 Energy Efficiencies 2-19
2.5.3 Environmental Considerations 2-19
2.5.4 Economic Considerations 2-21
2.6 PREPARATION 2-21
2.6.1 Technologies 2-21
2.6.2 Energy Efficiencies 2-23
2.6.3 Environmental Considerations 2-23
2.6.3 Economic Considerations 2-23
2.7 PROCESSING 2-23
2.7.1 Technologies 2-23
2.7.1.1 Retorting 2-23
2.7.1.1.1 Surface Retorting 2-24
2.7.1.1.1.1 Gas Combustion Retort 2-26
2.7.1.1.1.2 Union Oil "A" Retort 2-26
2.7.1.1.1.3 TOSCO II Retort 2-26
2.7.1.1.2 In Situ Retorting 2-29
ix
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PAGE
2.7.1.1.2.1 Bureau of Mines Process 2-31
2.7.1.1.2.2 Garrett Process 2-31
2.7.1.2 Upgrading 2-33
2.7.2 Energy Efficiencies 2-33
2.7.3 Environmental Considerations 2-35
2.7.3.1 Retorting 2-38
2.7.3.1.1 Water 2-38
2.7.3.1.2 Air 2-38
2.7.3.1.3 Solids 2-38
2.7.3.1.4 Land 2-39
2.7.3.1.5 Water Requirements 2-39
2.7.3.2 Upgrading 2-39
2.7.3.2.1 Water 2-39
2.7.3.2.2 Air 2-39
2.7.3.2.3 Solids 2-39
2.7.3.2.4 Land 2-39
2.7.3.2.5 Water Requirements 2-4C
2.7.3.3 Summary 2-40
2.7.3.3.1 Solids 2-40
2.7.3.3.2 Land 2-40
2.7.4 Economic Considerations 2-40
2.8 RECLAMATION 2-41
2.8.1 Technologies 2-41
2.8.2 Energy Efficiencies 2-43
2.8.3 Environmental Considerations 2-43
2.8.4 Economic Considerations 2-45
2.9 TRANSPORTATION OF FINISHED PRODUCTS 2-45
2.9.1 Technologies 2-47
2.9.2 Energy Efficiencies 2-47
2.9.3 Environmental Considerations 2-47
2.9.4 Economic Considerations 2-47
REFERENCES 2-47
CHAPTER 3: THE CRUDE OIL RESOURCE SYSTEM
3.1 INTRODUCTION 3-1
3.2 CRUDE OIL RESOURCES 3-1
3.2.1 Characteristics of the Resource 3-1
3.2.2 Domestic Resources 3-3
3.2.2.1 Quantity of Domestic Resources 3-3
3.2.2.2 Location of the Resources 3-3
3.2.2.3 Ownership of the Resources 3-3
3.2.2.4 Regional Overview 3-5
3.2.2.4.1 Onshore Lower 48 States . 3-5
3.2.2.4.2 Alaska 3-6
3.2.2.4.3 Offshore 3-6
3.2.3 .World Resources 3-8
3.2.4 Summary 3-8
3.3 EXPLORATION 3-8
3.3.1 Technologies 3-9
3.3.1.1 Regional Surveys 3-9
3.3.1.2 Detailed Surveys 3-9
3.3.1.3 Exploratory Drilling 3-9
3.3.2 Energy Efficiencies 3-11
3.3.3 Environmental Considerations 3-11
3.3.4 Economic Considerations 3-17
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PAGE
3.4 DEVELOPMENT 3-17
3.4.1 Technologies 3-17
3.4.1.1 Completion 3-17
3.4.1.2 Processing 3-19
3.4.1.3 Improved Recovery 3-19
3.4.2 Energy Efficiencies 3-21
3.4.3 Environmental Considerations 3-23
3.4.3.1 Water 3-23
3.4.3.2 Air 3-24
3.4.3.3 Land 3-24
3.4.4 Economic Considerations 3-24
3.5 CRUDE OIL REFINING 3-24
3.5.1 Technologies 3-25
3.5.1.1 Feedstock and Products 3-27
3.5.1.2 Unit Processes 3-27
3.5.1.2.1 Distillation 3-27
3.5.1.2.2 Sulfur Removal 3-27
3.5.1.2.3 Cracking Processes 3-27
3.5.1.2.4 Reforming, Alkylation, and Isomerization 3-31
3.5.1.2.5 Support Facilities 3-31
3.5.2 Energy Efficiencies 3-31
3.5.3 Environmental Considerations 3-33
3.5.3.1 Water 3-33
3.5.3.2 Air 3-35
3.5.3.3 Solids 3-35
3.5.3.4 Land Use 3-35
3.5.4 Economic Considerations 3-35
3.6 TRANSPORTATION 3-36
3.6.1 Introduction 3-36
3.6.2 Domestic Transportation Technologies 3-36
3.6.3 Energy Efficiencies 3-37
3.6.4 Environmental Considerations 3-37
3.6.4.1 Water 3-37
3.6.4.2 Air 3-39
3.6.4.3 Land Use 3-42
3.6.5 Economic Considerations 3-42
3.7 FOREIGN IMPORTS 3-42
3.7.1 Import Technologies 3-42
3.7.2 Energy Efficiencies 3-46
3.7.3 Environmental Considerations 3-46
3.7.4 Economic Considerations 3-49
REFERENCES 3-51
CHAPTER 4: THE NATURAL GAS RESOURCE SYSTEM
4.1 INTRODUCTION 4-1
4.2 CHARACTERISTICS OF THE RESOURCE 4-3
4.2.1 Natural Gas Classifications 4-3
4.2.2 Physical Characteristics 4-3
4.2.3 Domestic Resources 4-3
4.2.3.1 Quantity of the Resources 4-3
4.2.3.2 Accuracy of the Resource Estimates 4-7
4.2.3.3 Location of the Resources 4-7
4.2.3.4 Ownership/Control of the Resources 4-9
4.2.4 Foreign Resources 4-9
4.2.4.1 Canada 4-9
4.2.4.2 Mexico 4-9
4.2.4.3 World 4-9
XI
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PAGE
4.3 EXPLORATION 4-11
4.4 EXTRACTION 4-12
4.4.1 Technologies 4-12
4.4.1.1 Drilling . 4-12
4.4.1.2 Production 4-12
4.4.1.2.1 Well Completion 4-12
4.4.1.2.2 Fluid Processing 4-12
4.4.1.2.2.1 Field Separation of Produced Fluids 4-13
4.4.1.2.2.2 Compression 4-13
4.4.1.2.2.3 Natural Gas Plants 4-15
4.4.1.2.2.4 Sulfur Removal Process 4-15
4.4.2 Energy Efficiencies 4-17
4.4.3 Environmental Considerations 4-17
4.4.3.1 Water 4-19
4.4.3.2 Air 4-21
4.4.3.3 Solids 4-21
4.4.3.4 Land 4-21
4.4.4 Economic Considerations 4-21
4.5 TRANSPORTATION OF NATURAL GAS 4-22
4.5.1 Technologies 4-22
4.5.1.1 Transmission Pipeline 4-22
4.5.1.1.1 Alaskan Pipeline 4-23
4.5.1.1.2 Pipeline Construction 4-23
4.5.1.2 Compression 4-23
4.5.1.3 Storage of Natural Gas 4-24
4.5.1.3.1 Underground 4-24
4.5.1.3.2 Tanks 4-24
4.5.1.3.3 Peak-Shaving Plants 4-24
4.5.1.4 Distribution of Natural Gas 4-26
4.5.2 Energy Efficiencies 4-26
4.5.3 Environmental Considerations 4-26
4.5.3.1 Water 4-26
4.5.3.2 Air 4-27
4.5.3.3 Solids 4-27
4.5.3.4 Land 4-27
4.5.4 Economic Considerations 4-29
4.5.5 Other Constraints and Opportunities 4-29
4.6 IMPORTED NATURAL GAS 4-29
4.6.1 Liquefied Natural Gas Technologies 4-31
4.6.1.1 Pretreatment 4-31
4.6.1.2 Liquefaction 4-31
4.6.1.3 Storage 4-34
4.6.1.4 Tankers 4-34
4.6.1.5 Port and Transfer Facilities 4-35
4.6.1.6 Regasification 4-35
4.6.2 Energy Efficiencies 4-35
4.6.3 Environmental Considerations 4-38
4.6.3.1 Water 4-38
4.6.3.2 Air 4-38
4.6.3.3 Solids 4-38
4.6.3.4 Land 4-38
4.6.3.5 Major Accidents 4-40
4.6.4 Economic Considerations 4-40
4.6.5 Other Constraints and Opportunities 4-41
REFERENCES 4-41
xix
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CHAPTER 5: THE TAR SANDS RESOURCE SYSTEM
5.1 INTRODUCTION 5-1
5.2 RESOURCE QUANTITY 5-1
5.3 CHARACTERISTICS OF THE RESOURCE 5-3
5.4 LOCATION OF THE RESOURCES 5-3
5.5 OWNERSHIP OF THE RESOURCES 5-4
5.6 EXPLORATION 5-4
5.6.1 Technologies 5-4
5.6.2 Energy Efficiencies 5-4
5.6.3 Environmental Considerations 5-4
5.6.4 Economic Considerations 5-4
5.7 MINING AND RECLAMATION 5-6
5.7.1 Technologies 5-6
5.7.1.1 Mining 5-6
5.7.1.2 Reclamation 5-6
5.7.2 Energy Efficiencies 5-6
5.7.3 Environmental Considerations 5-7
5.7.4 Economic Considerations 5-7
5.8 PROCESSING 5-7
5.8.1 Technologies 5-7
5.8.1.1 Bitumen Recovery 5-7
5.8.1.2 In Situ Recovery 5-8
5.8.1.3 Upgrading 5-12
5.8.1.4 Refining 5-12
5.8.2 Energy Efficiencies 5-12
5.8.3 Environmental Considerations 5-14
5.8.4 Economic Considerations 5-14
5.9 TRANSPORTATION 5-15
REFERENCES 5-15
CHAPTER 6: THE NUCLEAR ENERGY—FISSION RESOURCE SYSTEM
6.1 INTRODUCTION 6-1
6.1.1 History of Nuclear Energy 6-1
6.1.2 Basics of Nuclear Energy 6-1
6.1.3 Organization of Chapter 6-2
6.2 LIGHT WATER REACTOR (LWR) SYSTEM 6-3
6.2.1 Introduction 6-3
6.2.2 Resource Base 6-3
6.2.2.1 Characteristics of the Resource 6-3
6.2.2.2 Quantity of the Resources 6-3
6.2.2.3 Location of the Resources 6-6
6.2.2.4 Ownership of the Resources 6-6
6.2.3 Exploration 6-6
6.2.3.1 Technologies 6-8
6.2.3.1.1 Preliminary Investigations 6-8
6.2.3.1.2 Detailed Geological Studies 6-8
6.2.3.1.3 Physical Exploration 6-8
xiii
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6.2.3.2 Energy Efficiencies 6—8
6.2.3.3 Environmental Considerations 6-9
6.2.3.4 Economic Considerations 6-9
6.2.4 Mining and Reclamation 6-9
6.2.4.1 Technologies 6-10
6.2.4.1.1 Open Pit Mining 6-10
6.2.4.1.2 Underground Mining 6-10
6.2.4.2 Energy Efficiencies 6-10
6.2.4.3 Environmental Considerations 6-10
6.2.4.3.1 Open Pit Mining 6-10
6.2.4.3.2 Underground Mining 6-11
6.2.4.4 Economic Considerations 6-11
6.2.5 Processing 6-12
6.2.5.1 Milling 6-12
6.2.5.1.1 Technologies 6-12
6.2.5.1.2 Energy Efficiencies 6-15
6.2.5.1.3 Environmental Considerations 6-15
6.2.5.1.4 Economic Considerations 6-16
6.2.5.2 Uranium Hexafluoride (UFg) Production " 6-16
6.2.5.2.1 Technologies 6-16
6.2.5.2.1.1 Dry Hydrofluor Process 6-19
6.2.5.2.1.2 Wet Solvent Extraction-Fluorination Process 6-19
6.2.5.2.2 Energy Efficiencies 6-19
6.2.5.2.3 Environmental Considerations 6-19
6.2.5.2.4 Economic Considerations 6-20
6.2.5.3 Enrichment 6-20
6.2.5.3.1 Technologies 6-21
6.2.5.3.2 Energy Efficiencies 6-23
6.2.5.3.3 Environmental Considerations 6-23
6.2.5.3.3.1 Chronic 6-23
6.2.5.3.3.2 Major Accidents 6-24
6.2.5.3.4 Economic Considerations 6-24
6.2.5.4 Fuel Fabrication 6-24
6.2.5.4.1 Technologies 6-25
6.2.5.4.1.1 Chemical Conversion of UF, to UO2 6-25
6.2.5.4.1.2 Mechanical Operations 6-25
6.2.5.4.1.3 Scrap Processing 6-25
6.2.5.4.2 Energy Efficiencies 6-25
6.2.5.4.3 Environmental Considerations 6-27
6.2.5.4.3.1 Chronic 6-27
6.2.5.4.3.2 Accidents 6-27
6.2.5.4.4 Economic Considerations 6-28
6.2.6 Light Water Reactors 6-28
6.2.6.1 Technologies 6-28
6.2.6.1.1 Boiling Water Reactors 6-28
6.2.6.1.2 Pressurized Water Reactors 6-30
6.2.6.2 Energy Efficiencies 6-32
6.2.6.3 Environmental Considerations 6-32
6.2.6.3.1 Chronic Residuals 6-32
6.2.6.3.2 Major Accident 6-33
6.2.6.4 Economic Considerations 6-33
6.2.7 Fuel Reprocessing 6-34
6.2.7.1 Technologies 6-34
6.2.7.2 Energy Efficiencies 6-34
6.2.7.3 Environmental Considerations 6-34
6.2.7.3.1 Chronic 6-34
6.2.7.3.2 Major Accidents 6-35
6.2.7.4 Economic Considerations 6-36
6.2.8 Radioactive Waste Management 6-36
6.2.8.1 Technologies 6-36
6.2.8.2 Energy Efficiencies 6-36
6.2.8.3 Environmental Considerations 6-37
6.2.8.3.1 Chronic 6-37
6.2.8.3.2 Major Accidents 6-37
xiv
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6.2.8.4 Economic Considerations 6-37
6.2.9 Transportation 6-37
6.2.9.1 Nuclear Material Transportation Regulations 6-37
6.2.9.2 Technologies 6-39
6.2.9.3 Energy Efficiencies 6-41
6.2.9.4 Environmental Considerations 6-41
6.2.9.4.1 Chronic 6-41
6.2.9.4.2 Accidents 6-42
6.2.9.5 Economic Considerations 6-42
6.3 HIGH TEMPERATURE GAS REACTOR (HTGR) SYSTEM 6-42
6.3.1 Introduction 6-42
6.3.2 Resource Base (Thorium) 6-44
6.3.2.1 Characteristics of the Resource 6-44
6.3.2.2 Quantity of the Resources 6-44
6.3.2.3 Location of the Resources 6-45
6.3.3 Exploration 6-45
6.3.3.1 Technologies 6-46
6.3.3.2 Energy Efficiencies 6-46
6.3.3.3 Environmental Considerations 6-46
6.3.3.4 Economic Considerations 6-46
6.3.4 Mining 6-46
6.3.4.1 Technologies 6-46
6.3.4.2 Energy Efficiencies 6-46
6.3.4.3 Environmental Considerations 6-46
6.3.4.4 Economic Considerations 6-47
6.3.5 Processing 6-47
6.3.5.1 Processing of Thorium Ore to Produce ThO, 6-47
6.3.5.1.1 Technologies 6-47
6.3.5.1.2 Energy Efficiencies 6-47
6.3.5.1.3 Environmental Considerations 6-47
6.3.5.1.3.1 Chronic 6-47
6.3.5.1.3.2 Major Accidents 6-50
6.3.5.1.4 Economic Considerations 6-50
6.3.5.2 Fuel Element Fabrication 6-51
6.3.5.2.1 Technologies 6-51
6.3.5.2.2 Energy Efficiencies 6-53
6.3.5.2.3 Environmental Considerations 6-53
6.3.5.2.3.1 Chronic 6-53
6.3.5.2.3.2 Major Accidents 6-53
6.3.5.2.4 Economic Considerations 6-53
6.3.6 High Temperature Gas Reactor 6-53
6.3.6.1 Technologies 6-53
6.3.6.2 Energy Efficiencies 6-55
6.3.6.3.1 Chronic 6-55
6.3.6.3.2 Major Accidents 6-55
6.3.6.4 Economic Considerations 6-56
6.3.6.5 Other Considerations 6-56
6.3.7 Reprocessing 6-56
6.3.7.1 Technologies 6-56
6.3.7.2 Energy Efficiencies 6-57
6.3.7.3 Environmental Considerations 6-57
6.3.7.4 Economic Considerations 6-57
6.3.8 Radioactive Waste Management 6-57
6.3.9 Transportation 6-57
6.3.9.1 Technologies 6-57
6.3.9.2 Energy Efficiencies 6-58
6.3.9.3 Environmental Considerations 6-58
6.3.9.4 Economic Considerations 6-58
6.4 LIQUID METAL FAST BREEDER REACTOR (LMFBR) SYSTEM 6-58
6.4.1 Introduction 6-58
6.4.2 Resource 6-59
6.4.3 Fuel Fabrication 6-61
xv
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PAGE
6.4.3.1 Technologies 6-61
6.4.3.2 Energy Efficiencies 6-61
6.4.3.3 Environmental Considerations 6-63
6.4.3.3.1 Chronic 6-63
6.4.3.3.2 Major Accidents 6-63
6.4.3.4 Economic Considerations 6-66
6.4.4 Reactor and Power Generation System 6-67
6.4.4.1 Technologies 6-67
6.4.4.2 Energy Efficiencies 6-67
6.4.4.3 Environmental Considerations 6-67
6.4.4.3.1 Chronic 6-67
6.4.4.3.2 Major Accidents 6-69
6.4.4.4 Economic Considerations 6-69
6.4.5 Fuel Reprocessing 6-70
6.4.5.1 Technologies 6-70
6.4.5.2 Energy Efficiencies 6-70
6.4.5.3 Environmental Considerations 6-70
6.4.5.3.1 Chronic 6-70
6.4.5.3.2 Major Accidents 6-71
6.4.5.4 Economic Considerations 6-71
6.4.6 Radioactive Waste Management 6-71
6.4.7 Transportation 6-71
6.4.7.1 Technologies 6-71
6.4.7.2 Energy Efficiencies 6-73
6.4.7.3 Environmental Considerations 6-73
6.4.7.4 Economic Considerations 6-73
REFERENCES 6-73
CHAPTER 7: THE NUCLEAR ENERGY—FUSION RESOURCE SYSTEM
7.1 INTRODUCTION 7-1
7.2 FUSION AS A POTENTIAL ENERGY SOURCE 7-1
REFERENCES 7-2
CHAPTER 8: THE GEOTHERMAL ENERGY RESOURCE SYSTEM
8.1 INTRODUCTION 8-1
8.2 RESOURCE CHARACTERISTICS 8-1
8.2.1 Quantity 8-1
8.2.2 Geology 8-5
8.2.2.1 Hydrothermal Reservoirs 8-5
8.2.2.2 Geopressured Reservoirs 8-5
8.2.2.3 Dry Hot Rock Reservoirs 8-6
8.2.3 Physical and Chemical Characteristics 8-6
8.2.4 Location 8-6
8.2.5 Ownership 8-6
8.3 EXPLORATION 8-6
8.3.1 Technologies 8-6
8.3.1.1 Passive Exploration Techniques 8-8
8.3.1.2 Active Exploration Techniques 8-9
8.3.2 Energy Efficiencies 8-9
8.3.3 Environmental Considerations 8-9
8.3.4 Economic Considerations 8-9
xvi
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PAGE
8.4 EXTRACTION—DRILLING 8-9
8.4.1 Technologies 8-9
8.4.2 Energy Efficiencies 8-10
8.4.3 Environmental Considerations 8-10
8.4.3.1 Chronic 8~10
8.4.3.1.1 Noise 8-10
8.4.3.1.2 Air Pollutants 8-10
8.4.3.2 Major Accident—Blowout 8-12
8.4.4 Economic Considerations 8-13
8.5 EXTRACTION—PRODUCTION 8-13
8.5.1 Technologies 8-13
8.5.1.1 Hydrothermal Reservoirs 8-13
8.5.1.2 Dry Rock Reservoirs 8-13
8.5.1.2.1 Hydraulic Fracturing 8-14
8.5.1.2.2 Nuclear Fracturing—The Plowshare
Geothermal System 8-14
8.5.2 Energy Efficiencies 8-14
8.5.3 Environmental Considerations 8-14
8.5.3.1 Noise 8~?-4
8.5.3.2 Water and/or Brine Disposal from the Separator 8-14
8.5.3.3 Land Subsidence 8-17
8.5.3.4 Earthquakes 8-17
8.5.3.5 Groundwater Contamination 8-17
8.5.3.6 Land Use 8-17
8.5.3.7 Air Pollutants 8~17
8.5.3.8 Additional Concerns Caused by Dry Rock
Fracturing with Nuclear Devices 8-18
8.5.3.8.1 Groundmotion 8-18
8.5.3.8.2 Radiation Releases 8-18
8.5.3.8.3 Aftershocks 8-18
8.5.3.8.4 Volcanic Stimulation 8-18
8.5.3.8.5 Hydrothermal Explosion 8-18
8.5.4 Economic Considerations 8-18
8.6 TRANSPORTATION—STEAM TRANSMISSION SYSTEM 8-19
8.6.1 Technologies 8~i-Q
8.6.2 Energy Efficiencies 8-19
8.6.3 Environmental Considerations 8-19
8.6.4 Economic Considerations 8-19
8.7 POWER GENERATION 8-19
8.7.1 Technologies 8-19
8.7.1.1 Geothermal Steam Generator 8-19
8.7.1.2 Alternative Power Generation Systems 8-21
8.7.2 Energy Efficiencies 8-23
8.7.3 Environmental Considerations 8-23
8.7.4 Economic Considerations 8-24
8.8 SUMMARY 8-24
8.8.1 Energy Efficiencies 8-25
8.8.2 Environmental Considerations 8-25
8.8.2.1 Land 8~25
8.8.2.2 Water 8-25
8.8.2.3 Air 8-26
8.8.2.4 Occupational Health 8~26
8.8.3 Economic Considerations Q-26
REFERENCES 8~28
xvii
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PACT;
CHAPTER 9: THE HYDROELECTRIC RESOURCE SYSTEM
if
9.1 INTRODUCTION 9_i
9.2 CHARACTERISTICS OF THE RESOURCE 9_1
9.2.1 Quantity of the Resources 9-3
9.2.2 Location of the Resources 9-3
9.2.3 Ownership of the Resources 9-3
9.2.4 Summary g_3
9.3 TECHNOLOGIES 9_5
9.3.1 Dams g_5
9.3.2 Transport and Turbines 9_7
9.3.3 Reversible Pump-Generators 9_10
9.4 ENERGY EFFICIENCIES g_10
9.5 ENVIRONMENTAL CONSIDERATIONS 9-13
9.5.1 Air 9_13
9.5.2 Water 9_13
9.5.3 Land 9_14
9.6 ECONOMIC CONSIDERATIONS 9_14
9.7 TRANSPORTATION 9_15
9.8 TIDAL POWER 9_15
REFERENCES 9_16
CHAPTER 10: THE ORGANIC WASTE RESOURCE SYSTEM
10.1 INTRODUCTION 10_1
10.2 RESOURCE I0_i
10.2.1 Characterization 10-1
10.2.2 Quantity 10_3
10.2.3 Location and Ownership 10-3
10.3 COLLECTION 10_4
10.3.1 Technologies 10-4
10.3.2 Energy Efficiencies 10-4
10.3.3 Environmental Considerations 10-5
10.3.4 Economic Considerations 10-5
10.4 PROCESSING 10_5
10.4.1 Preparation 10-6
10.4.1.1 Technologies 10-6
10.4.1.2 Energy Efficiencies 10-6
10.4.1.3 Environmental Considerations 10-6
10.4.1.4 Economic Considerations 10-6
10.4.2 Hydrogenation to Oil 10-7
10.4.2.1 Technologies 10-7
10.4.2.2 Energy Efficiencies 10-7
10.4.2.3 Environmental Considerations 10-7
10.4.2.4 Economic Considerations 10-7
10.4.3 Bioconversion 10-8
10.4.3.1 Technologies 10-8
10.4.3.2 Energy Efficiencies 10-8
10.4.3.3 Environmental Considerations 10-8
10.4.3.4 Economic Considerations 10-8
xviii
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10.4.4 Pyrolysis 10-8
10.4.4.1 Technologies 10-9
10.4.4.1.1 Monsanto LANDGARD System 10-9
10.4.4.1.2 Garrett Pyrolysis 10-9
10.4.4.1.3 Bureau of Mines Pyrolysis 10-12
10.4.4.2 Energy Efficiencies 10-13
10.4.4.3 Environmental Considerations 10-14
10.4.4.4 Economic Considerations 10-14
10.5 DIRECT BURNING FOR ELECTRICAL GENERATION 10-15
10.5.1 Technologies 10-15
10.5.2 Energy Efficiencies 10-16
10.5.3 Environmental Considerations 10-16
10.5.4 Economic Considerations 10-16
10.6 TRANSPORTATION OF PROCESSED PRODUCTS 10-16
10.7 SUMMARY 10-16
10.7.1 Energy Efficiencies 10-17
10.7.2 Environmental Considerations 10-17
10.7.3 Economic Considerations 10-18
REFERENCES 10-19
CHAPTER 11: THE SOLAR RESOURCE SYSTEM
11.1 INTRODUCTION 11-1
11.2 DIRECT SOLAR ENERGY 11-1
11.2.1 Resource Base 11-1
11.2.2 Technologies 11-3
11.2.2.1 Low-Temperature Collectors 11-3
11.2.2.2 High-Temperature Concentrators 11-6
11.2.2.3 Ultrahigh-Temperature Concentrators 11-6
11.2.2.4 Photovoltaic Cells 11-9
11.2.3 Energy Efficiencies 11-9
11.2.4 Environmental Considerations 11-12
11.2.5 Economic Considerations 11-12
11.3 WIND ENERGY 11-14
11.3.1 Resource Base 11-14
11.3.2 Technologies 11-15
11.3.3 Energy Efficiencies 11-18
11.3.4 Environmental Considerations 11-19
11.3.5 Economic Considerations 11-19
11.4 ORGANIC FARMS 11-19
11.4.1 Resource Base 11-19
11.4.2 Technologies 11-20
il.4.3 Energy Efficiencies 11-23
11.4.4 Environmental Considerations 11-23
11.4.5 Economic Considerations 11-24
11.5 OCEAN THERMAL GRADIENTS 11-25
11.5.1 Resource Base 11-25
11.5.2 Technologies 11-25
11.5.3 Energy Efficiencies 11-25
11.5.4 Environmental Considerations 11-25
11.5.5 Economic Considerations 11-25
11.6 SUMMARY 11-25
REFERENCES 11-27
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CHAPTER 12: ELECTRIC POWER GENERATION
12.1 INTRODUCTION 12-1
12.2 BOILER-FIRED POWER PLANTS 12-3
12.2.1 Technologies 12-6
12.2.1.1 Boilers 12-6
12.2.1.1.1 Conventional Boilers 12-6
12.2.1.1.2 Fluidized Bed Boilers 12-8
12.2.1.2 Turbines 12-10
12.2.1.2.1 Steam Turbines 12-10
12.2.1.2.2 Binary Cycle Systems 12-10
12.2.1.3 Generators 12-11
12.2.1.4 Stack Gas Cleaning 12-11
12.2.1.4.1 Oxides of Nitrogen 12-11
12.2.1.4.2 Sulfur Dioxide 12-11
12.2.1.4.3 Particulates 12-12
12.2.1.5 Cooling 12-15
12.2.2 Energy Efficiencies 12-16
12.2.3 Environmental Considerations 12-17
12.2.4 Economic Considerations 12-21
12.3 GAS TURBINE POWER PLANTS 12-22
12.3.1 Technologies 12-23
12.3.2 Energy Efficiencies 12-25
12.3.3 Environmental Considerations 12-25
12.3.4 Economic Considerations 12-25
12.3.5 Other Constraints and Opportunities 12-26
12.4 COMBINED CYCLE POWER PLANTS 12-26
12.4.1 Technologies 12-26
12.4.2 Energy Efficiencies 12-26
12.4.3 Environmental Considerations 12-30
12.4.4 Economic Considerations 12-30
12.5 FUEL CELL POWER PLANTS 12-30
12.5.1 Technologies 12-30
12.5.2 Energy Efficiencies 12-32
12.5.3 Environmental Considerations 12-33
12.5.4 Economic Considerations 12-33
12.5.5 Other Constraints and Opportunities 12-33
12.6 MAGNETOHYDRODYNAMIC POWER PLANTS 12-33
12.6.1 Technologies 12-33
12.6.1.1 Open-Cycle Plasma System 12-34
12.6.1.2 Closed-Cycle Plasma System 12-34
12.6.1.3 Liquid Metal MHD System 12-34
12.6.2 Energy Efficiencies 12-36
12.6.3 Environmental Considerations 12-36
12.6.4 Economic Considerations 12-36
12.6.5 Other Constraints and Opportunities 12-36
12.7 ELECTRICITY TRANSMISSION AND DISTRIBUTION 12-37
12.7.1 Technologies 12-37
12.7.1.1 Transmission Systems 12-37
12.7.1.2 Distribution Systems 12-37
12.7.2 Energy Efficiencies 12-38
12.7.3 Environmental Considerations 12-38
12.7.4 Economic Considerations 12-38
xx
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12.8 SUMMARY AND COMPARISON OF ENVIRONMENTAL FACTORS 12-39
12.9 SUMMARY OF ECONOMIC CONSIDERATIONS 12-42
12.9.1 General Costs of Electric Power 12-42
12.9.2 Costs of Alternative Power Plants 12-45
12.9.2.1 Conventional Steam Power Plants 12-46
12.9.2.2 Stack Gas Cleaning Technologies 12-46
12.9.2.3 Fluidized Bed Systems 12-46
12.9.2.4 Gas Turbine Power Plants 12-46
12.9.2.5 Other Advanced Conversion Technologies 12-46
12.9.2.6 Overall Generation Costs 12-46
REFERENCES 12-46
CHAPTER 13: ENERGY CONSUMPTION
13.1 INTRODUCTION 13-1
13.1.1 Patterns of Energy Supply and Demand 13-2
13.1.2 Energy Consumption By End Use 13-2
13.1.3 Energy Conservation 13-5
13.2 RESIDENTIAL AND COMMERCIAL SECTOR 13-5
13.2.1 Space Heating 13-6
13.2.1.1 Technologies 13-6
13.2.1.1.1 Direct Combustion and Electrical
Resistance Heating 13-6
13.2.1.1.2 Heat Pumps 13-7
13.2.1.1.3 Solar Energy 13-7
13.2.1.2 Energy Efficiencies 13-7
13.2.1.3 Environmental Considerations 13-9
13.2.1.4 Economic Considerations 13-9
13.2.2 Air Conditioning 13-11
13.2.2.1 Technologies 13-11
13.2.2.2 Energy Efficiencies 13-11
13.2.2.3 Environmental Considerations 13-12
13.2.2.4 Economic Considerations 13-12
13.2.3 Water Heating 13-14
13.2.3.1 Technologies 13-14
13.2.3.2 Energy Efficiencies 13-14
13.2.3.3 Environmental Considerations 13-14
13.2.3.4 Economic Considerations 13-16
13.2.4 Refrigeration 13-16
13.2.4.1 Technologies 13-16
13.2.4.2 Energy Efficiencies 13-16
13.2.4.3 Environmental Considerations 13-16
13.2.4.4 Economic Considerations 13-16
13.2.5 Cooking 13-16
13.2.5.1 Technologies 13-16
13.2.5.2 Energy Efficiencies 13-17
13.2.5.3 Environmental Considerations 13-17
13.2.5.4 Economic Considerations 13-17
13.2.6 Other 13-17
13.2.7 Conservation Measures for the Residential and
Commercial Sector 13-17
13.2.7.1 Simple Conservation Practices 13-19
13.2.7.2 Improved Thermal Insulation 13-19
13.2.7.3 Building Design and Construction 13-20
13.2.7.4 Higher Efficiency Fossil-Fueled Furnaces 13-20
13.2.7.5 Higher Efficiency Room and Central Air
Conditioners 13-21
13.2.7.6 Use of Electric Heat Pumps 13-21
xxi
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PAGE
13.2.7.7 Total Energy Systems 13-21
13.2.7.8 Solar Energy 13-21
13.2.7.9 Water Heating 13-21
13.2.7.10 Other Potential Energy Savings 13-22
13.3 INDUSTRIAL SECTOR 13-22
13.3.1 Technologies 13-23
13.3.1.1 Primary Metals 13-23
13.3.1.2 Chemicals and Allied Products 13-25
13.3.1.3 Paper and Allied Products 13-25
13.3.1.4 Stone, Clay, Glass, and Concrete 13-25
13.3.1.5 Food Processing 13-26
13.3.1.6 Transportation Equipment 13-26
13.3.2 Energy Efficiencies 13-26
13.3.3 Environmental Considerations 13-27
13.3.4 Economic Considerations 13-30
13.3.5 Conservation Measures for the Industrial Sector 13-30
13.3.5.1 Industrial Thermal Processes 13-31
13.3.5.2 Process Steam Generation 13-31
13.3.5.3 Increased Efficiency of Industrial Processes 13-31
13.3.5.4 Heat Recuperation 13-32
13.3.5.5 Recycling and Reusing 13-32
13.4 TRANSPORTATION SECTOR 13-33
13.4.1 Freight 13-34
13.4.1.1 Technologies 13-34
13.4.1.1.1 Ships 13-35
13.4.1.1.2 Trucks 13-35
13.4.1.1.3 Railroads 13-35
13.4.1.1.4 Airplanes 13-36
13.4.1.2 Energy Efficiencies 13-36
13.4.1.3 Environmental Considerations 13-36
13.4.1.4 Economic Considerations 13-38
13.4.2 Passenger Travel 13-38
13.4.2.1 Technologies 13-38
13.4.2.1.1 Automobiles 13-39
13.4.2.1.2 Buses 13—41
13.4.2.1.3 Airplanes 13-41
13.4.2.1.4 Railroads 13-41
13.4.2.2 Energy Efficiencies 13-42
13.4.2.3 Environmental Considerations 13-42
13.4.2.4 Economic Considerations 13-44
13.4.3 Military-Government and Feedstocks 13-45
13.4.4 Conservation Measures for the Transportation
Sector 13-45
13.4.4.1 Automobiles 13-47
13.4.4.2 Airplanes 13-48
13.4.4.3 Trucks and Rail 13-50
13.4.4.4 Other 13-50
REFERENCES 13-51
PART II: PROCEDURES FOR EVALUATING AND
COMPARING ENERGY ALTERNATIVES
CHAPTER 14: PROCEDURES FOR COMPARING
THE RESIDUALS OF ENERGY ALTERNATIVES
14.1 INTRODUCTION 14_1
14.2 GENERAL PROCEDURES FOR OBTAINING AND USING
RESIDUALS DATA 14_2
14.3 A DEMONSTRATION OF HOW TO CALCULATE RESIDUALS OF
ENERGY ALTERNATIVES 14_3
xxii
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PAGE
14.3.1 The Proposed Major Federal Action 14-3
14.3.2 A Technological Alternative 14-5
14.3.3 A Locational Alternative 14-5
14.3.4 Source Alternative 14-5
14.3.5 Substitute Fuels Alternatives 14-9
14.4 A DEMONSTRATION OF HOW TO COMPARE THE RESIDUALS OF
ENERGY ALTERNATIVES 14-9
14.4.1 A Comparison of Residuals by Category and Trajectory 14-9
14.4.2 A Comparison of Residuals by Category and Location 14-25
14.4.3 A Comparison of Residuals by Particular Residual
and Trajectory 14-25
14.4.4 A Comparison of Residuals by Particular Residual
and Location 14-25
14.4.5 Summary 14-25
14.5 SUGGESTIONS CONCERNING IMPACT ANALYSIS 14-25
14.5.1 General Procedures 14-27
14.5.2 An Illustration of Impact Analysis 14-28
14.5.2.1 Impact of Particulates, Sulfur Dioxide, and Nitrous
Oxide Emissions 14-32
14.5.2.2 Impact of Water Inputs 14-35
14.6 SUMMARY 14-40
REFERENCES 14-40
CHAPTER 15: PROCEDURES FOR COMPARING THE
ENERGY EFFICIENCIES OF ENERGY ALTERNATIVES
15.1 INTRODUCTION 15-1
15.2 GENERAL PROCEDURES FOR OBTAINING AND USING ENERGY
EFFICIENCY DATA 15-3
15.3 A DEMONSTRATION OF HOW TO CALCULATE ENERGY EFFICIENCIES 15-4
15.3.1 The Proposed Major Federal Action 15-4
15.3.2 A Technological Alternative 15-4
15.3.3 A Locational Alternative 15-7
15.3.4 Source Alternative 15-7
15.3.5 Substitute Fuel Alternatives 15-7
15.4 A DEMONSTRATION OF HOW TO COMPARE THE EFFICIENCIES OF
ENERGY ALTERNATIVES 15-9
APPENDIX TO CHAPTER 15: SUGGESTIONS CONCERNING IMPACT ANALYSIS
A.I INTRODUCTION A-15-12
A.2 CATEGORIES OF EXTERNAL INPUTS A-15-12
A.3 AN ILLUSTRATION OF ENERGY ACCOUNTING A-15-14
REFERENCES A-15-17
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PACK
CHAPTER 16: COMPARING THE ECONOMIC CpSTS OF ENERGY ALTERNATIVES
16.1 INTRODUCTION 16-1
16.2 GENERAL PROCEDURES FOR OBTAINING AND USING THE
COST DATA 16-2
16.3 A DEMONSTRATION OF HOW TO COMPARE THE ECONOMIC
COSTS OF ENERGY ALTERNATIVES 16-3
16.3.1 The Hypothetical Proposed Major Federal Action 16-8
16.3.2 A Technological Alternative 16-8
16.3.3 A Locational Alternative 16-9
16.3.4 Source Alternatives 16-9
16.4 A COMPARISON OF THE ECONOMIC COSTS OF ENERGY
ALTERNATIVES 16-10
16.5 EVALUATION OF ECONOMIC COSTS: SUGGESTED
IMPROVEMENTS 16-12
16.5.1 Updating the Cost Data 16-12
16.5.2 Conflicting Assumptions 16-13
16.5.3 Shifting from a Static to a Dynamic Framework
of Analysis ' 16-13
16.5.4 Cost Effectiveness Analysis 16-13
16.6 SUGGESTIONS FOR ECONOMIC IMPACT ANALYSIS 16-14
16.6.1 Production Costs and Market Prices 16-14
16.6.2 Calculation of Final Consumer Prices 16-16
16.6.3 Comparison of Price and Cost Rankings 16-19
16.6.4 Net Present Value Analysis 16-23
REFERENCES 16-25
BIBLIOGRAPHY 16-25
xxiv
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LIST OF TABLES
TABLE PAGE
1-1 Coal Resources of the U.S. 1-4
1-2 Rank of Identified U.S. Coal Resources 1-7
1-3 Coal Resources in U.S. Geological Survey Provinces 1-7
1-4 Coal Resources in the Eastern Province 1-11
1-5 Coal Resources in the Interior Province 1-11
1-6 Coal Resources in the Northern Great Plains Province 1-13
1-7 Coal Resources in the Rocky Mountain Province 1-13
1-8 Exploration Costs in Surface Mines 1-19
1-9 Exploration Costs in Underground Bituminous Mines 1-21
1-10 Materials Balance for Area Surface Mining 1-27
1-11 Materials Balance for Contour Mining 1-28
1-12 Materials Balance for Room and Pillar Mining 1-36
1-13 Materials Balance for Longwall Mining 1-36
1-14 Coal Characteristics Used in Environmental
Residuals Calculated 1-45
1-15 Surface Mining Efficiencies 1-46
1-16 Mining and Reclamation Efficiencies 1-47
1-17 Residuals for Surface Coal Mining and Reclamation 1-48
1-18 Summary of Surface Mining Residuals 1-51
1-19 Underground Coal Mining and Reclamation Residuals 1-54
1-20 Summary of Underground Mining Residuals 1-55
1-21 Surface Mining Costs 1-56
1-22 Surface Coal Mining Production Costs 1-57
1-23 1973 Underground Coal Mining Production Costs 1-58
1-24 Ancillary Energy Requirements of In-Mine
Transportation Systems 1-60
1-25 Residuals for In-Mine Coal Transportation 1-61
1-26 Coal Beneficiation Efficiencies 1-64
1-27 Residuals for Coal Beneficiation 1-65
1-28 Selected Design Features of Four Low- and
Intermediate-Btu Gasification Processes 1-73
1-29 Materials Balance for Lurgi Process 1-76
1-30 Materials Balance for Koppers-Totzek Process 1-76
1-31 Materials Balance for Bureau of Mines Stirred
Fixed Bed Process 1-77
1-32 Materials Balance for Westinghouse Fluidized Bed Process 1-81
1-33 Materials Balance for an Ash Agglomerating Fluidized
Bed Process 1-81
1-34 Selected Design Features of Five High-Btu Gasification
Processes 1-82
1-35 Inputs and By-Products for a Lurgi Gasification Plant 1-83
1-36 Inputs and Outputs for a HYGAS Plant 1-86
1-37 Inputs and Outputs for a BI-GAS Plant 1-89
1-38 Inputs and Outputs for a Synthane Plant 1-91
1-39 Inputs and Outputs for a CO2 Acceptor Process 1-91
1-40 Characteristics of Coal Liquefaction Technologies 1-96
1-41 Coal Processing Efficiencies 1-106
1-42 Summary of Overall Coal Processing Efficiencies 1-107
1—43 Residuals for Low- to Intermediate-Btu Coal Gasification 1-108
1-44 Summary of Low- to Intermediate-Btu Gasification Pollutants 1-110
1-45 Environmental Residuals for High-Btu Gasification 1-111
xxv
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TABLE PAGE
1-46 Summary of High-Btu Gasification Residuals 1-112
1-47 wastewater Characteristics From Two^igh-Btu Coal
Gasification Processes 1-113
1-48 Solvent Refined Solids and Coal Liquefaction Residuals 1-115
1-49 Summary of Solvent Refined Solids and Coal Liquefaction
Residuals 1-116
1-50 Process Wastewater Pollutant Concentrations From Two
Liquefaction Processes 1-117
1-51 Wastewater Composition From Solvent Refined Solids
Before and After Treatment 1-119
1-52 Summary of (1972) Estimated Coal Processing Costs 1-120
1-53 Estimated Prices of Synthetic Natural Gas 1-121
1-54 Methods of Coal Transportation 1-122
1-55 Coal Transportation Energy Efficiencies 1-125
1-56 Residuals for Coal Transportation 1-127
1-57 Costs of Coal Transportation 1-129
2-1 Oil Shale Resources of the U.S. 2-4
2-2 Location of Oil Shale Resources 2-7
2-3 Oil Shale Resources in the Green River Formation 2-9
2-4 Ownership of Green River Formation Oil Shale Lands 2-10
2-5 Energy Efficiencies for Oil Shale Mining 2-15
2-6 Residuals for Oil Shale Mining 2-16
2-7 Costs for Oil Shale Mining 2-19
2-8 Within and Near-Mine Transportation Residuals for
Oil Shale 2-20
2-9 Within and Near-Mine Transportation Costs for Oil Shale 2-21
2-10 Residuals for Oil Shale Preparation 2-25
2-11 Summary of Aboveground Retort Alternatives 2-25
2-12 Summary of Inputs and By-Products for a Gas Combustion
Retorting System 2-29
2-13 Characteristics of Shale Oil and Syncrude 2-35
2-14 Energy Efficiencies for Oil Shale Processing Technologies 2-35
2-15 Environmental Residuals for Oil Shale Processing 2-36
2-16 Processing Costs for Oil Shale at a Production Rate of
50.000 Barrels Per Day 2-41
2-17 Processing Costs for Oil Shale 2-42
2-18 Required Selling Price of Shale Oil 2-42
2-19 Water Consumption for Shale Oil Production 2-44
2-20 Contingent Water Consumption Forecasts 2-45
2-21 Environmental Residuals From Transportation of Synthetic
Crude Oil Produced From Oil Shale 2-46
3-1 United States Oil Resources 3-5
3-2 World Oil Reserves by Country as of 1970 3-8
3-3 Efficiencies and Residuals From Crude Oil Extraction 3-22
3-4 Efficiency of Improved Recovery Methods 3-23
3-5 Crude Oil Refining Efficiencies 3-33
3-6 Crude Oil Refinery Residuals 3-34
3-7 Crude Oil Refining Costs (1972) 3-36
3-8 Crude Oil and Product Transportation Efficiencies 3-39
3-9 Residuals for Crude Oil and Product Transport 3-40
3-10 Transportation Costs for Crude Oil and Products (1972) 3-43
3-11 Deepwater Port Alternatives 3-46
3-12 Residuals From Refining Imported Crude Oil 3-48
3-13 Cost of Crude Oil Transport From Venezuela. North Africa,
and the Persian Gulf (1967 Dollars) 3-49
4-1 Natural Gas Resources 4-5
4-2 Federal Natural Gas Resource Ownership 4-9
4-3 Estimated Reserves, Production, and Consumption of
Natural Gas By Country 4-11
4-4 Projections of Liquefied Natural Gas Imports 4-12
4-5 Efficiencies for Extracting, Gathering, and Processing
Natural Gas 4-19
4-6 Residuals for Extracting, Gathering, and Processing
Natural Gas 4-20
xxvi
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TABLE PAGE
4-7 Estimated 1974 National Average Cost of Finding and
Producing Nonassociated Gas 4-22
4-8 Efficiency of Transmission, Distribution, and Storage
of Natural Gas 4-27
4-9 Residuals for Transmission, Distribution, and Storage
of Natural Gas 4-28
4-10 Energy Efficiency of LNG Operations 4-35
4-11 Residuals for Liquefied Natural Gas Operations 4-39
5-1 Sulfur Content and Overburden Depth of Some Major U.S.
Tar Sands Deposits 5-3
5-2 Size of U.S. Tar Sands Deposits 5-4
5-3 Annual 1970 Operating Cost and Income for a 50,000-
Barrel-Per-Day Tar Sands Operation 5-15
6-1 Uranium Resources 6-5
6-2 UsOg Needs for Projected Light Water Reactor Capacity 6-5
6-3 Uranium Ore Reserves by States 6-6
6-4 Costs of U3O8 Production 6-9
6-5 Summary of Environmental Residuals For Uranium Mining 6-11
6-6 Estimated Incremental Cost of ^03 to Meet New
Safety Standards 6-12
6-7 U.S. Uranium Ore Mills Operating or on Standby 6-13
6-8 Summary of Environmental Residuals for Uranium Milling 6-16
6-9 Summary of Environmental Residuals for Uranium
Hexafluoride Production 6-20
6-10 Summary of Environmental Residuals for Uranium Enrichment 6-23
6-11 Summary of Environmental Residuals for Fuel Fabrication 6-27
6-12 Annual Radioactive Emission for a 1,000-Mwe LWR 6-33
6-13 Anticipated 1980 Electricity Cost of LWR 6-34
6-14 Summary of Environmental Residuals for Irradiated
Fuel Reprocessing 6-35
6-15 Container Requirements According to Quantity of
Radioactive Materials 6-38
6-16 Summary for Environmental Residuals for Fuel Cycle
Transportation Steps 6-39
6-17 Characteristics of Shipments to and from Reactor 6-40
6-18 U.S. and Canadian Thorium Resources, 6-45
6-19 U.S. Thorium Reserves 6-46
6-20 Annual Effects of a 1,000-Mwe HTGR and Its Fuel Cycle 6-48
6-21 Summary of Thorium Milling Emissions 6-51
6-22 Chemical Stack Effluents From HTGR Fuel Refabrication
Pilot Plant . 6-55
6-23 Production of Depleted UFg Forecast for the Years
1972-2000 6-63
6-24 Chemical Residuals in Liquid Effluents From 1,000-Mwe
LMFBR 6-65
6-25 Potential Radionuclides in the Gaseous Effluents From
an LMFBR Fuel Fabrication Plant 6-65
6-26 Radionuclides in the Liquid Effluents From an LMFBR
Fuel Fabrication Plant 6-66
6-27 Postulated LMFBR Radionuclide Releases 6-69
6-28 Estimated LMFBR Power Plant Capital Cost 6-70
6-29 LMFBR Reprocessing Cost Estimates 6-71
6-30 Estimated Annual Quantities of Radioactive Solid Wastes
From an LWR and LMFBR 6-72
7-1 Federal R&D Funding for Fusion 7-2
8-1 Geothermal Resource Estimates 8-3
8-2 Potential Installed Geothermal Capacity by 1985 8-4
8-3 Effect of Price on Potential Installed Geothermal
Capacity by 1985 8-5
8-4 Characteristics of U.S. Geothermal Fields 8-8
8-5 Noise from Geothermal Operations 8-10
8-6 Gases Released to the Air During Drilling at the Geysers 8-12
8-7 Air Emissions at the Geysers Plant 8-23
xxvii
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TABLE PAGE
8-8 Cooling Tower Discharge Plant Reinjected at the Geysers 8-24
8-9 Capital Costs of Geothermal Power Plants. 1973 8-25
8-10 System Efficiency; Wellhead Through Electric
Power Generation **" 8-25
8-11 Environmental Residuals for Geothermal Development
at the Geysers 8-26
8-12 1972 Costs for Geothermal Power 8-27
8-13 Costs of Geothermal Power Generation Systems 8-28
9-1 U.S. Hydroelectric Power Resources by Region 9-5
9-2 Relationship of Operating Head and Water Flow to
Power Output 9-10
9-3 1972 U.S. Hydroelectric Power Costs by Region 9-15
9-4 Relationship of 1967 Capital Cost to Operating Head 9-15
10-1 Composition of Municipal Refuse Materials and Chemicals 10-3
10-2 Quantities of Organic Wastes by Source 10-4
10-3 Percent of Various Fuels Potentially Represented by
Organic Wastes 10-5
10-4 Products from Garrett Pyrolysis 10-12
10-5 Products from BuMines Pyrolysis 10-13
10-6 Pyrolysis Costs and Revenue 10-15
10-7 1972 Costs for Direct Burning of Organic Waste 10-17
10-8 Energy Efficiencies for Utilization of Organic Wastes 10-18
11-1 Solar Radiation at Selected Locations in the United
States During 1970 11-5
11-2 Annual Energy Output for Various Windmill Diameters in
Central United States 11-17
12-1 Energy Sources for 1972 U.S. Electricity Generation 12-1
12-2 Technological Status of Some Stack-Gas Sulfur Dioxide-
Removal Processes 12-14
12-3 Cooling Water Requirements for 1.000-Mwe Plant 12-16
12-4 Residuals for Boiler-Fired Power Plants 12-18
12-5 Generation Costs (1971) For Steam Power Plants With No
Stack Gas Cleaning 12-22
12-6 Sulfur Dioxide and Particulate Control System Cost 12-23
12-7 Costs of Cooling Systems for Steam-Electric Plants 12-25
12-8 Residuals for Environmentally Controlled Combined-Cycle
Electricity Generation 12-29
12-9 Costs for Westinghouse Combined Cycle Fluidized-Bed System 12-30
12-10 Major Residuals for 1,000-Mwe Plants at 75 Percent Load
Factor 12-40
12-11 Average Costs of U.S. Electricity, 1968 12-44
12-12 Example of Residential Electricity Rate Structure 12-44
12-13 Average 1968 Generation Costs 12-46
12-14 Example of Fixed Charge Rate for Conventional Steam Plant 12-46
13-1 Total and Per Capita U.S. Energy Consumption 13-2
13-2 Energy Consumption in the U.S. by End Use, 1960-1968 13-3
13-3 Fuel Consumption for Major End Uses in the Residential
and Commercial Sector, 1970 13-6
13-4 Space Heating Efficiencies by Fuel for the Residential
and Commercial Sector 13-8
13-5 Coefficients of Performance for. Electrically Driven Heat
Pumps With Various Sources and Sinks 13-8
13-6 Residuals for Space Heating Energy Use 13-10
13-7 Annual Fuel Cost and Consumption for Space Heating 13-11
13-8 Variations in Performance of Selected Air Conditioners 13-12
13-9 Residuals for Air Conditioning Energy Use 13-13
13-10 Water Heating Efficiencies by Fuel for the Residential
and Commercial Sector . 13-14
13-11 Residuals for Water Heating Energy Use 13-15
13-12 Residuals for Cooking Energy Use 13-18
13-13 Annual Fuel Consumption for Six Major Industrial Uses 13-24
13-14 Energy Intensiveness of Major Industrial Groups 13-24
13-15 Residuals for Industrial Energy Use 13-28
13-16 Fuel Sources for Transportation, 1970 13-33
13-17 Categories of Transportation Use 13-33
XXVlll
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TABLE PAGE
13-18 End Use of Energy Within the Transportation Sector, 1970 13-34
13-19 Methods of Inter-City Freight Traffic 13-35
13-20 Energy Intensiveness of Freight Traffic 13-36
13-21 Residuals for Freight Transportation Energy Use 13-37
13-22 Inter-City Freight Transportation Price Data 13-38
13-23 Methods of Inter-City Passenger Traffic 13-39
13-24 Energy Intensiveness of Inter-City and Urban Passenger
Travel 13-42
13-25 Residuals for Passenger Transportation Energy Use 13-43
13-26 Passenger Transportation Prices 13-44
13-27 Residuals for Military and Government and Feedstocks
Transportation Energy Use 13-46
13-28 Effect of Auto Design on Fuel Economy 13-47
14-1 Residuals of the Proposed Action: Synthane High-Btu
Gasification 14-6
14-2 Residuals of a Technological Alternative: Lurgi High-Btu
Gasification 14-7
14-3 Residuals of a Locational Alternative: Synthane Facility
Moved to Demand Center 14-8
14-4 Residuals of a Source Alternative: Alaskan Natural Gas
via Canadian Pipeline 14-10
14-5 Residuals of a Source Alternative: Alaskan Natural Gas
via Alaskan Pipeline and LNG Tanker 14-11
14-6 Residuals of a Source Alternative: Offshore Natural Gas 14-13
14-7 Residuals of a Source Alternative: Imported LNG 14-14
14-8 Totals by Trajectory for Categories of Residuals 14-15
14-9 Totals by Location for Categories of Residuals 14-18
14-10 Comparison of Environmental Protection Agency Source
Standards and Expected Emissions 14-33
14-11 Potential Impacts of Air Pollutants and Ambient Data
Required to Evaluate Them 14-33
14-12 Ground Level Ambient Air Concentrations of Particulates
for Worst Cases 14-34
14-13 Ground Level Ambient Air Concentrations of Particulates
for Two Meteorological Conditions 14-35
14-14 Frequency of High Air Pollution Potential of Colstrip,
Montana 14-36
14-15 Mid-Afternoon Mixing Depths at Colstrip 14-37
14-16 Potential Impacts of Water Demand and Data Required for
Its Evaluation 14-38
14-17 Ambient Data Needed to Evaluate Impact of Water Requirement
on Water Quantity 14-39
14-18 Percent of River Flow and Consumptive Use in Montana
Represented by Gasification Water Demand 14-39
15-1 Efficiencies of the Proposed Action: Synthane High-Btu
Gasification 15-6
15-2 Efficiencies of a Technological Alternative: Lurgi High-
Btu Gasification 15-6
15-3 Efficiencies of a Locational Alternative: Synthane
Facility Moved to Demand Center 15-7
15-4 Efficiencies of a Source Alternative: Alaskan Natural
Gas Via Canadian Pipeline 15-8
15-5 Efficiencies of a Source Alternative: Alaskan Natural
Gas Via Alaskan Pipeline and LNG Tanker 15-8
15-6 Efficiencies of a Source Alternative: Offshore Natural
Gas 15-9
15-7 Efficiencies of a Source Alternative: Imported LNG 15-9
15-8 Energy Cost of Delivering 2.62xl012 Btu's of Natural
Gas Using Seven Alternative Trajectories 15-11
A-l Examples of Energy Content of Materials A-15-13
A-2 Energy Value of a Dollar in 1973 for Several Categories
of Materials A-15-13
A-3 External Inputs to Lurgi High-Btu Gasification A-15-16
XXIX
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TABLE PAGE
16-1 The Proposed Action: Synthane HigK-Btu Gasification 16-5
16-2 Costs of a Technogical Alternative: Lurgi High-Btu
Gasification 16-5
16-3 Costs of a Locational Alternative: Synthane Facility
Moved to Demand Center 16-6
16-4 Costs of a Source Alternative: Alaskan Natural Gas
Via Canadian Pipeline 16-6
16-5 Costs of a Source Alternative: Alaskan Natural Gas
Via Alaskan Pipeline and £NG Tanker 16-7
16-6 Costs of a Source Alternative: Offshore Natural Gas 16-7
16-7 Costs of a Source Alternative: Imported USG 16-8
16-8 Trajectories Ranked by Total Costs 16-12
16-9 Characteristics of Various Market Structures 16-15
16-10 Equations for Cost-Pius Price Computations 16-18
16-11 Sample Cost-Pius Price Calculations for the Offshore
Natural Gas Trajectory 16-20
16-12 Trajectories Ranked by Cost-Pius Price 16-21
16-13 Computation Formula for Net Present Value (NPV) 16-24
XXX
-------
LIST OF FIGURES
FIGURE PAGE
1-1 Coal Resource Development 1-2
1-2 Fixed Carbon Content of Major Coal Ranks 1-5
1-3 Heat Content of Major Coal Ranks 1-6
1-4 Distribution of United States Coal Resources 1-8
1-5 Distribution of Coal in the Eastern Province 1-10
1-6 Distribution of Coal in the Interior Province 1-12
1-7 Distribution of Coal in the Northern Great Plains Province 1-14
1-8 Distribution of Coal in the Rocky Mountain Province 1-15
1-9 Coal Resource Development 1-17
1-10 Increase in Coal Production by Surface Mining 1-18
1-11 Contour Mine 1-22
1-12 Area Mine 1-23
1-13 Dragline , 1-25
1-14 Bucket Wheel Excavator 1-26
1-15 Alternative Methods for Room and Pillar Mining 1-29
1-16 Cutting Machine 1-30
1-17 Mechanical Loader 1-32
1-18 Underground Mining Methods 1-33
1-19 Plan View of Longwall Mining 1-34
1-20 Section View of Longwall Mining 1-35
1-21 Underground Mining Fatalities 1-38
1-22 Ventilation in a Room and Pillar Mine 1-39
1-23 Fatalities from Explosions in Underground Coal Mines 1-40
1-24 Reclamation by Reshaping the Spoil Bank and Partial
Backfilling 1-42
1-25 Reclamation by Full Backfilling of the Bench 1-43
1-26 General Process Scheme -for Producing Gas from Coal 1-69
1-27 Principal Coal Gasification Reactions and Reactor Types 1-71
1-28 Lurgi Low-Btu Coal Gasification Process 1-74
1-29 Koppers-Totzek Coal Gasification Process 1-75
1-30 Bureau of Mines Stirred Fixed Bed Coal Gasification
Process 1-78
1-31 Westinghouse Fluidized Bed Coal Gasification Process 1-79
1-32 Ash Agglomerating Fluidized Bed Coal Gasification Process 1-80
1-33 Lurgi High-Btu Coal Gasification Process 1-84
1-34 HYGAS Coal Gasification Process 1-85
1-35 BI-GAS Coal Gasification Process 1-87
1-36 Synthane Coal Gasification Process 1-88
1-37 CO2 Acceptor Coal Gasification Process 1-90
1-38 Longwall Generator Concept for Underground Coal
Gasification 1-93
1-39 Principal Coal Liquefaction Reactions and Processes 1-94
1-40 Synthoil Coal Liquefaction Process 1-95
1-41 H-Coal Coal Liquefaction Process . 1-98
1-42 Solvent Refined Coal Process 1-99
1-43 Consol Synthetic Fuel Process 1-100
1-44 COED Coal Liquefaction Process 1-102
1-45 TOSCOAL Coal Liquefaction Process 1-103
1-46 Fisher-Tropsch Coal Liquefaction Process 1-104
XXXI
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FIGURE PAGE
2-1 Oil Shale Resource Development 2-2
2-2 Distribution of U.S. Oil Shale Resources 2-5
2-3 Oil Shale Areas in Colorado, Utah, and Wyoming 2-6
2-4 Diagrammatic Cross Section of Green River Formation 2-8
2-5 Hypothetical Oil Shale Surface Mine 2-12
2-6 Small Room and Pillar Oil Shale Mine 2-14
2-7 Primary Crusher Dust Control 2-22
2—8 Gas Combustion Process 2-27
2-9 Union Oil Process 2-28
2-10 TOSCO II Process 2-30
2-11 In Situ Retorting Operation 2-32
2-12 Oil Shale Processing Sequence 2-34
3-1 Crude Oil Resource Development 3-2
3-2 Sulfur Content and API Gravity of Crude Oils 3-4
3-3 Alaskan Oil Provinces 3-7
3-4 Drilling and Mud System 3-10
3-5 Oil Well Casing 3-12
3-6 Blowout Preventer Stack 3-13
3-7 Jack-up Offshore Drilling Rig 3-14
3-8 Drill Ship 3-15
3-9 Semi-Submersible Offshore Drilling Rig 3-16
3-10 Wellhead "Christmas Tree" of Control Valves 3-18
3-11 Waterf lood Secondary Recovery System 3-20
3-12 Oil Refinery . 3-26
3-13 Refinery Crude Oil Distillation Column 3-28
3-14 Refinery Hydrodesulfurization Process 3-29
3-15 Amine Solvent H2S Removal Column 3-30
3-16 Catalytic Cracking Process 3-32
3-17 Offshore Pipelaying Barge 3-38
3-18 Single Buoy Mooring Facility 3-44
3-19 Sea Island Mooring Facility 3-45
3-20 Artifical Island Mooring Facility 3-47
3-21 Costs of Tanker Transport 3-50
4-1 Natural Gas Resource Development 4-2
4-2 Selected Samples of Unprocessed Natural Gas 4—4
4-3 U.S. Natural Gas Proved Reserves and Reserves-to-Production
Ratio 4-6
4-4 Interstate Natural Gas Movements 4-8
4-5 Proposed Canadian Natural Gas Pipeline Routes and Oil and
Gas Discoveries . 4-10
4-6 Three-Stage Wellhead Separation Unit 4-14
4-7 Cycling Operation 4-16
4-8 Amine Treating Process for CO2 and H2S Removal 4-18
4-9 Location of Underground Gas Storage Reservoirs 4-25
4-10 Major Pipeline Costs 4-30
4-11 Integrated Liquid Natural Gas Operation 4-32
4-12 Cascade Cycle Liquefaction Plant 4-33
4-13 Potential Receiving Ports 4-36
4-14 Liquid Natural Gas Receiving Terminal 4-37
5-1 Tar Sands Resource Development 5-2
5-2 Distribution of U.S. Tar Sands Resources 5-5
5-3 Hot Water Extraction Process 5-9
5—4 Solvent Extraction Process 5-10
5-5 Pyrolysis "Coking" Extraction Process 5-11
5-6 Steps Involved in Upgrading Bitumen to Synthetic Crude Oil 5-13
6—1 Light Water Reactor Fuel Cycle 6-4
6—2 Uranium Exploration 6-7
6-3 Milling Plant 6-14
6-4 UFg Production—Dry Hydrofluor Process 6-17
6-5 UF6 Production—Wet Solvent Extraction-Fluorination 6-18
6-6 Gaseous Diffusion Stage 6-22
6-7 Mode of Operation for Gaseous Diffusion Plant 6-22
6-8 Fuel Fabrication—ADU Process 6-26
6-9 Boiling Water Reactor 6-29
xxxii
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FIGURE PAGE
6-10 Pressurized Water Reactor 6-31
6-11 High Temperature Gas Reactor Fuel Cycle 6-43
6-12 HTGR Fuel Components 6-52
6-13 High Temperature Gas-Cooled Reactor 6-54
6-14 Liquid Metal Fast Breeder Reactor Fuel Cycle 6-60
6-15 Plutonium Availabilities and Requirements 6-62
6-16 LMFBR Fuel-Fabrication Plant 6-64
6-17 Liquid Metal Fast Breeder Reactor 6-68
8-1 Geothermal Resource Development 8-2
8-2 Distribution of U.S. Geothermal Resources 8-7
8-3 Typical Well Configuration at the Geysers 8-11
8-4 Dry Rock Geothermal Energy System by Hydraulic Fracturing 8-15
8-5 Plowshare Concept of Geothermal Heat Extraction 8-16
8-6 Geothermal Power Plant Types 8-20
8-7 Geothermal Power Plant 8-22
9-1 Hydroelectric Resource Development 9-2
9-2 Distribution of Developed U.S. Hydroelectric Resources 9-4
9-3 Components of a Hydropower System 9-6
9-4 Impulse Turbine 9-8
9-5 Reaction Turbine 9-9
9-6 Turbine-Generator Unit 9-11
9-7 Pumped-Storage Operation 9-12
10-1 Organic Waste Resource Development 10-2
10-2 LANDGARD Solid Waste Disposal System 10-10
10-3 Garrett Pyrolysis System 10-12
11-1 Solar Energy Resource Development 11-2
11-2 Distribution of U.S. Solar Energy 11-4
11-3 Residential Heating and Cooling with Solar Energy 11-7
11-4 Solar Thermal-Conversion Power System 11-8
11-5 Silicon Solar Cell Cost Projections 11-10
11-6 Satellite Solar Power Station 11-11
11-7 Comparison of Land Disturbed from Surface-Mined Coal and
« Solar Electric 1,000-Mwe Plant 11-13
11-8 Typical Wind Rotor System 11-16
11-9 Farm Output Per Man Hour 11-21
11-10 Land Area Required for 1,000 Mwe Equivalent Output as
a Function of Solar Conversion Efficiency 11-26
12-1 Electrical Generation System 12-2
12-2 Boiler-Fired Power Plant 12-4
12-3 Simplified Schematic of a Steam Power Plant 12-5
12-4 Boiler Air and Flue Gas Circulation Patterns 12-8
12-5 Pope, Evans, and Robbins Fluidized Bed Boiler Power Plant 12-9
12-6 Lime and Limestone Stack Gas Scrubbing Methods 12-13
12-7 Regenerative Cycle Gas Turbine 12-24
12-8 Combined Cycle Gas Turbine 12-27
12-9 Westinghouse Pressurized Fluidized Bed Boiler Power Plant 12-28
12-10 Hydrogen-Oxygen Fuel Cell 12-31
12-11 MHD Generator Electrical System 12-35
12-12 The Electric Power Industry 12-43
13-1 Total U.S. Energy Production and Consumption, 1947-1973 13-4
13-2 Growth in Vehicle Miles, 1940-1972 13-40
13-3 Comparison of Fuel Economy for Four Engines 13-49
14-1 Totals by Trajectory for Categories of Residuals 14-16
14-2 Totals by Trajectory for Categories of Residuals 14-17
14-3 Totals by Location for Air Pollutants 14-20
14-4 Totals by Trajectory for Specific Air Pollutants 14-21
14-5 Totals by Trajectory for Specific Air Pollutants 14-22
14-6 Totals by Trajectory for Specific Air Pollutants 14-23
14-7 Totals by Location for Specific Air Pollutants 14-24
14-8 Impact Analysis for Energy Alternatives, Phase I 14-29
14-9 Impact Analysis for Energy Alternatives, Phase II 14-30
15-1 Energy Efficiency Measures 15-2
15-2 Comparison of Energy Efficiencies 15-10
A-l Dependence of Energy Development on External Inputs
and Evaluation of Net Energy A-l5-15
16-1 Fixed and Operating Costs by Alternative . 16-11
16-2 Cost-Pius Price by Alternative 16-22
xxxiii
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LIST OF EXHIBITS
EXHIBIT PAGE
14-1 Summary of Procedures for Comparing the Residuals
of Energy Alternatives 14-4
14-2 Summary of Impact Analysis Procedures 14-31
15-1 Summary of Procedures for Evaluating and Comparing
the Energy Efficiencies of Energy Alternatives 15-5
16-1 Summary Procedures for Comparing the Economic Costs
of Energy Alternatives 16-4
xxxiv
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ACRONYMS AND ABBREVIATIONS
AC alternating current
ACS American Chemical Society
ADU ammonium diuranate
AEC Atomic Energy Commission
AGA American Gas Association
ANFO ammonium nitrate and fuel oil
API American Petroleum Institute
BART San Francisco Bay Area Rapid Transit
bbl barrel(s)
bcf billion cubic feet
BLM Bureau of Land Management
BOD biochemical oxygen demand
BOP blowout preventer
Btu British thermal unit
BuMines Bureau of Mines
BWR boiling water reactor
C Centigrade
CAB Civil Aeronautics Board
CEQ Council on Environmental Quality
cf cubic foot (feet)
cfs cubic feet per second
CO carbon monoxide
CO2 carbon dioxide
COD chemical oxygen demand
C.O.P. coefficient of performance
CSF consol synthetic fuel
dB decibel
DC direct current
DCF discounted cash flow (analysis)
DOI Department of the Interior
DOT Department of Transportation
ECCS emergency core cooling system
e.g. for example
EIS environmental impact statement(s)
EMDB Energy Model Data Base
EPA Environmental Protection Agency
et al. and others
F Fahrenheit
FCR fixed change rate
FCST Federal Council for Science and Technology
FEA Federal Energy Administration
FFTF fast flux test facility
FHA Federal Housing Administration
f.o.b. free-on-board
FPC Federal Power Commission
FWKO free water knock out
GNP gross national product
gpd gallon(s) per day
gpm gallon(s) per minute
HAPP high air pollution potential
HCDA hypothetical core disruptive accidents
HTGR high temperature gas reactor
HYGAS hydrogasification
ICC Interstate Commerce Commission
i.e. that is
xxxv
-------
KGRA
kv
kw
Tcwe
kwh
LACT
LMFBR
LNG
LOCA
LP
LPG
LWR
mcf
MERES
mmcf
MHD
mpg
mph
mrem
Mw
Mwe
Mwh
NAE
NASA
NEB
NEPA
NGRS
NGSF
NOV
NPC
NPV
NSF
OCR
OCS
OEP
OPEC
OSHA
OST
OU
PCRV
psi
psia
psig
PWR
R&D
r/P
rpm
RSSP
SBM
SIC
SRC
SRI
TAPS
tcf
TOSCO
USGS
USSR
VLCC
known geothermal resource area
kilovolt
kilowatt(s)
kilowatt(s)-electric f
kilowatt-hour(s)
lease automatic custody transfer
liquid metal fast breeder reactor
liquefied natural gas
loss of cooling accident
liquefied petroleum
liquid petroleum gas
light water reactor
thousand cubic feet
Matrix of Environmental Residuals for Energy Systems
million cubic feet
magnetohydrodynamic
miles per gallon
miles per hour
millirem
megawatt(s)
megawatt(s)-electric
megawatt-hour(s)
National Academy of Engineering
National Aeronautics and Space Administration
Canadian National Energy Board
National Environmental Policy Act
National Gas Reserves Study
noble gas storage facility
oxides of nitrogen
National Petroleum Council
net present value
National Science Foundation
Office of Coal Research
outer continental shelf
Office of Emergency Preparedness
Organization of Petroleum Exporting Countries
Occupational Safety and Health Administration
Office of Science and Technology
University of Oklahoma
prestressed concrete reactor vessel
parts per million
pounds per square inch
pounds per square inch atmosphere
pounds per square inch guage
pressurized water reactor
research and development
reserve-to-production
rotations per minute
retrievable surface storage facility
single buoy mooring
standard industrial classification
sulfur oxides
solvent refined coal
Stanford Research Institute
trans-Alaska pipeline system
trillion cubic feet
The oil shale Corporation
United States Geological Survey
union of Soviet Socialist Republics (Russia)
very large crude carrier
jnnrvi
-------
GENERAL INTRODUCTION
This report is intended to contribute
to the development of a methodology for
systematically identifying, assessing, and
comparing energy alternatives in environ-
mental impact statements (EIS) . As a step
toward the achievement of this goal, this
report provides descriptions and data on
the major energy resource systems in the
United States and suggests procedures for
using these descriptions and data.
The report is divided into two major
parts. Part I (Chapters 1 through 13)
contains descriptions of the coal, oil
shale, crude oil, natural gas, tar sands,
nuclear fission, nuclear fusion, geothermal,
hydroelectric, organic wastes, and solar
energy resource systems plus descriptions
of electric power generation and energy
consumption. In addition to discussing the
resource and development technologies, each
resource system description contains data
on energy efficiencies, environmental resid-
uals, and economic costs.
Part II (Chapters 14 through 16)
describes procedures for using the descrip-
tions and data contained in Part I in sys-
tematically evaluating and comparing the
residuals, efficiencies, and economic costs
of a proposed energy action and its alterna-
tives. This part also suggests procedures
for impact analyses. Both Parts I and II
are preceded by introductions that explain
the organization of each part.
The resource descriptions in Part I
rely heavily on reports prepared for the
Council on Environmental Quality (CEQ),
Environmental Protection Agency (EPA),
Bureau of Land Management (BLM), Atomic
Energy Commission (AEC), and National
Science Foundation (NSF). For the most
part, quantitative data on energy efficien-
cies, environmental consequences, and
economic costs are taken from CEQ's Matrix
of Environmental Residuals for Energy
Systems (MERES). At present, MERES contains
data only on fossil fuel systems (coal,
crude oil, natural gas, and oil shale) pre-
pared by Hittman Associates for CEQ, EPA,
and NSF and reported in Environmental
Impacts. Efficiency, and Cost of Energy
Supply and End Use (1974, Vol. I: 1975,
*
Vol. 2) . MERES data have been incorporated
into a computerized data system by
Brookhaven National Laboratory (BNL, 1975) .
Part I descriptions include MERES data plus
additional information and data on tar sands,
nuclear fission, nuclear fusion, geothermal,
hydroelectric, organic wastes, solar,
electric power generation, and energy con-
sumption.
In addition to MERES data, this report
includes data from Teknekron, Incorporated's
Fuel Cycles for Electric Power Generation
(1973) (prepared for EPA), Battelle Columbus
and Pacific Northwest Laboratories'
Environmental Considerations in Future
Energy Growth (1973) (prepared for EPA),
and miscellaneous other sources. Each
chapter of the report cites references (by
author and date) in the text and lists those
references alphabetically at the chapter's
end. Throughout the report, data are pre-
sented in tabular form, where feasible, to
facilitate comparisons by users.
There are several reasons why the data
in this report and MERES should be used
Data on other energy resources will be
added to MERES in the near future.
xxxvii
-------
cautiously. First, the data are basically
limited to What can be quantified. Some
qualitative information is included, espe-
cially for energy efficiencies and environ-
mental residuals, but in many areas the data
in this report must be considered incomplete.
Second, data on energy efficiencies,
environmental residuals, and economic costs
are not available for all the technological
alternatives described in this report.
Because of this, specific abbreviations were
developed for the data tables to avoid mis-
leading or ambiguous entries. Thus, the
term "not applicable" (NA) refers to entries
that would not apply to a particular process
or category. "Not considered" (NC) refers
to potential data that were not available
from a particular problem area or process.
"Unknown" (U) refers to values that should
exist for the particular process or category
but that members of the study team were
unable to find.
Third, many of the estimates are based
on a limited number of cases and, at times,
on scaled-up pilot projects; thus, they may
not accurately represent cases in different
locations, at other scales, or under other
conditions. When known, these types of
factors are noted in this report.
Fourth, most of the individual data
estimates are based on specific assumptions
that may differ from the assumptions of
other individual estimates. For example,
MERES data distinguish between environ-
mentally "uncontrolled" and "controlled"
activities. "Uncontrolled" means that the
data represent processes permitted under
current environmental management regulations.
"Controlled" refers to a more restrictive
set of regulations that might apply 5 to
10 years in the future. As an illustration.
an uncontrolled strip mine involves the
kind of land restoration now being practiced
but a controlled strip mine presumes com-
plete reclamation, including revegetation.
J.n addition to these types of assumptions,
the assumptions about the particular
characterisitcs of an activity (e.g.,
energy content of coal or oil well depth)
vary widely between estimates. Thus,
indiscriminate comparisons of data could
produce invalid results.
In the MERES data, all estimates are
based on an energy input to a process of
one trillion British thermal units (10
Btu's). For consistency and comparisons,
the Battelle, Teknekron, and other data
were converted to this unit of measure.
Linearity is assumed in all scaling and,
in many cases, this is a poor assumption.
For example, the total land required for
a 3,000-Mwe (megawatts-electric) power
plant is not three times that required for
a 1,000-Mwe power plant.
The MERES data have been assigned
"hardness" numbers to indicate their
reliability. Reliability ranges from very
good (an error probability of 10 percent
or less) to very poor (an error probability
as high as an order of magnitude). These
data hardness estimates are included in the
text as a caution to users.
Wherever possible, the report iden-
tifies the assumptions incorporated in the
estimates, but all the current data tend
to be for specific sites, technologies,
and fuels. Therefore, users should regard
data estimates in this report with a healthy
skepticism. As MERES evolves, its data will
be modified frequently, reflecting increased
sources of information and further experi-
ence with technologies.
xxxviii
-------
PART I: DESCRIPTIONS OF ENERGY RESOURCE SYSTEMS
INTRODUCTION
The energy resource descriptions in
Part I of this report (Chapters 1 through
11) contain available information and data
on residuals, energy efficiencies, and
economic costs for 11 major U.S. energy
resource systems: coal, oil shale, crude
oil, natural gas, tar sands, nuclear
fission, nuclear fusion, geothermal, hydro-
electric, organic, and solar. Similar
descriptions were prepared for phase one
of NSF Grant No. SIA74-17866. These 11
chapters, plus a description of electric
power generation (Chapter 12) and a
discussion of U.S. energy consumption
(Chapter 13), comprise Part I of this
report.
Excepting the chapter on nuclear
fusion, the energy resource descriptions
are broken into major sections which begin
with a general resource description then
delineate the steps or activities involved
in developing the resource. The nuclear
fusion chapter is limited to a brief dis-
cussion of present and near future techno-
logy which clearly shows that fusion can—
not be a^ viable energy_ .re source, before__ the
year 2000.
In addition to the 11 energy resource
descriptions. Chapter 12 is a description
of the technological alternatives for the
use of solid, liquid, and gaseous fuels in
central station electric power plants.
Since this chapter covers the conversion of
a produced fuel to electricity, the
activities described are in addition to one
or more of the resource development
activities described in Chapters 1 through
11.
Chapter 13 summarizes available
information about energy end uses in the
U.S. This chapter is divided into three
major consumption sectors: transportation,
industrial, and residential/commercial.
Each sector includes a description of
options for conserving energy at the point
of use. This makes it possible to associate
a product of a resource system with levels
of demand for particular energy end uses.
The first section of each general
resource system description describes the
characteristics of the resource and gives
the best current estimates of total
"resources" and "reserves". The "resource"
estimate is the total amount of the energy
source within the United States (except
where otherwise noted), including amounts
that have not been identified but are sur-
mised to exist on the basis of broad
knowledge or theory. The "reserve" estimate
is the amount of the energy source both
known to exist and economically recoverable
using currently available technologies. For
mineral resources such as coal and oil shale,
these estimates are fixed quantities. For
renewable resources such as organic wastes
and solar radiation, these estimates are
production rates. For example, solar
energy "resources" are daily radiation
rates for selected locations throughout
the U.S. Likewise, organic waste "resources"
are production rates from major sources per
year. In addition to the resource character-
istics, resource estimates, and reserve
estimates, this section also discusses the
resource in terms of location and ownership.
The resource development technologies
sections describe each resource system in
terms of a basic sequence of "activities".
In the coal resource system, for example,
the activities are exploration, mining and
1-1
-------
reclamation, beneficiation, processing/
conversion, and transportation. These
activities are shown graphically in
Figure 1, which is a duplicate of Figure 1-1
in Chapter 1. For each activity, "techno-
logical alternatives" are discussed which
represent one set of policy and/or poten-
tial research and development options.
These alternatives are listed within the
activity blocks in Figure 1. (The number
within each block refers to the text section
where the activity is discussed.) Obviously,
where technological alternatives exist for
each activity, different combinations might
be selected to achieve the proposed resource
development action. Any particular combi-
nation of these alternatives is referred to
as a "trajectory". Each trajectory repre-
sents a second set of policy and/or research
and development options. An example of a
particular coal trajectory from Figure 1
would be to select area surface mining,
beneficiation by breaking and sizing
Synthane high-Btu gasification, and pipe-
line transportation.* For the proposed
action, the descriptions in Part I allow
users to plot a number of possible trajec-
tories and provide basic data on the effects
of those trajectories.
Categories of Data
For each technological alternative,
the descriptions contain three broad cate-
gories of data: energy efficiencies,
environmental considerations, and economic
considerations. These data categories are
described below.
Throughout Part I, energy efficiencies
of technological alternatives are assessed
in two ways: primary energy efficiency and
ancillary energy. Primary energy efficiency
(expressed as a percent) is the ratio
*Some activities are not broken into
technological alternatives and processes.
For example, exploration is generally so
standard that it has not been broken down.
However, exploration, including the equip-
ment used, is described in the text.
between the energy value of the output fuel
and the energy value of the input fuel. In
other words, it is a measure of energy con-
sumed or physically lost in a process.
Ancillary energy is the amount of energy
required from external sources* to accom-
plish the activity, such as fuel for
process heat, electricity for motors, and
diesel fuel for truck transport. This
energy is expressed as Btu's required per
10^ Btu's input to the process. By
dividing the output energy by the sum of
the ancillary energy and energy input, an
overall efficiency (percent) can be cal-
culated for each activity. The overall
efficiency provides a basis for comparing
the energy requirements of activities and
technological alternatives.
The environmental considerations
sections identify and discuss "residuals"
that may pose environmental problems for
each activity or technological alternative.
"Residuals" are defined as the byproducts
that an activity, technological alternative,
or process produces in addition to its
primary product. Using this broad defini-
tion, residuals include such effects as
air and water pollutants, solid wastes,
and impact-producing inputs (e.g., the
materials requirements of a particular
process). For each process and technolog-
ical alternative, the quantified environ-
mental residuals are reported in tabular
•form. These measures, which were taken from
MERES, include air residuals (particulates,
sulfur oxides, nitrous oxides, aldehydes,
carbon monoxide, and hydrocarbons), water
residuals (thermal, acids, bases, phosphates
I nitrates, total dissolved solids, suspended
solids, non-degradable organics, biochemical
oxygen demand, and chemical oxygen demand)
solids, land, deaths, injuries, and man-days
^-lost.
*Where the energy for process heat is
taken from the .resource (coal in a gasifier
or oil in a refinery), it is evaluated as
part of the primary efficiency.
r;
1-2
-------
1.2
Domestic
Resource
Base
i
i
1.5
Exploration
1.6 Surface
Mining 8
Reclamation
Area
Contour
1.6 Underground
Mining Q
Reclamation
Room 8
Pillar
Longwoll
1.8
*lBeneficiation
1.9
Improved Solid
Solvent Refining
1.9 Liquefaction
Solvent Refining
H-COAL
Synthoil
COED
TOSCOAL
1.9 Low-Btu Gasification
Lurgi
Koppers-Totzek
Westinghouse
COED
1.9 High-Btu Gasification
Lurgi
COg Acceptor
Synthane
HYGAS
BIGAS
1.9 In Situ Gasification
^Solid Fuels
"*" Liquid Fuels
>Gaseous Fuels
Involves Transportation 1.7 and 1.10 Transportation Lines
•Does Not Involve Transportation
Figure 1. Coal Resource Development
-------
Residuals are expressed in tons per 1012
Btu's input to the process (acre-year for
land, Btu's for thermal, and days for man-
days lost) in the first 12 chapters (the
resource descriptions plus the description
of electric power generation in Chapter 12).
The units of residuals in Chapter 12, Energy
Consumption, are expressed in tons per
measure, where the measure is the unit
appropriate for each particular end use.
Examples of these measures are passenger-
miles, tons, and dwelling-years. A value
referred to as "the multiplier" is also
included. The multiplier is the amount of
each end use measure which is used in the
U.S. each year. Thus, the product of the
multiplier and the measure is the yearly
consumption for a specific end use. The
product of the measure and any one residual
yields tons of emissions per measure. Where
numerical values are missing from tables,
abbreviations have been entered to indicate
the reasons, as explained in the General
Introduction. "NA" means the residual is
not applicable to the activity, "NC" means
the data were not considered (not given)
by the information sources, and "U" means
that the residual exists but the quantity is
unknown.
Economic considerations sections are
limited to fixed, operating, and total costs
for an activity. As used here, total costs
are simply the sum of fixed and operating
costs. Cost data are given in either
dollars per 1012 Btu's energy input or
dollars per kilowatt-hour output. These
data are necessarily based on market
^situations which are now out-of-date; thus,
reference dates (e.g., "1972 dollars") are
cited wherever possible. Although a user
can convert these figures into current
values, their principal value is in com-
paring costs of alternatives rather than
evaluating the economic feasibility of a
particular alternative in today's economy.
REFERENCES
Battelle Columbus and Pacific Northwest
Laboratories (1973) Environmental
Considerations in Future Energy
Growth. Vol. I: Fuel/Energy
Systems; Technical Summaries and
Associated Environmental Burdens.
for the Office of Research and
Development, Environmental Protection
Agency. Columbus, Ohio: Battelle
Columbus Laboratories.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts. Efficiency.
and Cost of Energy Supply and End
Use. Final Report: Vol. I, 1974;
Vol. II. 1975. Columbia, Md.:
Hittman Associates, Inc. (NTIS
numbers: Vol. I, PB-238 784;
Vol. II, PB-239 158).
Teknekron, Inc. (1973) Fuel Cycles for
Electrical Power Generation, Phase I:
Towards Comprehensive Standards;
The Electric Power Case, report for
the Office of Research and Monitoring,
Environmental Protection Agency.
Berkeley, Calif.: Teknekron.
1-4
-------
CHAPTER 1
THE COAL RESOURCE SYSTEM
1.1 INTRODUCTION
Coal was the U.S.'s principal energy
source from the 1880's until shortly after
World War II (Senate Interior Committee,
1971: 94-102) but declined dramatically
thereafter. In 1947, coal met approxi-
mately 48 percent of the total U.S. energy
demand; by 1971, it accounted for only
about 18 percent (Interior, 1972: 40, 43).
The decreased demand for coal resulted pri-
marily from several major* consumers switch-
ing to other fuels. Railroads converted to
diesel fuel and households, commercial con-
sumers, and (more recently) electric utili-
ties converted to natural gas or fuel oil.
Most of these conversions were made because
the newer fuels are cleaner, easier to
handle, and more environmentally acceptable
than coal.
Recent events (especially the decreas-
ing availability of natural gas and the
oil embargo) emphasize the need to increase
the proportion of our total energy demand
met by coal, a relatively abundant domestic
resource. However, any increased use of
coal must be reconciled with our national
policy of promoting environmental quality.
This has emphasized the need to make coal
less environmentally threatening as an
energy source through the development of
technologies to improve its direct combus-
tion properties or to convert it to a
liquid or gas.
The development of coal for use as
either a solid, gaseous, or liquid fuel
involves five major sequential activities:
exploration, mining and reclamation, bene-
ficiation, processing/conversion, and trans-
portation. These activities are diagrammed
in Figure 1-1 and described in Sections 1.5
through 1.10.
As shown in the figure, the coal
development system can be configured in
various ways, depending on the technological
alternative chosen to achieve each of the
five major activities. Both decision points
within the system and technological alterna-
tives are identified in the description of
coal development technologies in this
chapter.
1.2- A NATIONAL OVERVIEW
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 fields.
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, U.S. coal resources are
described in terms of amount, characteris-
tics, location, and ownership.
1.2.1 Total Resource Endowment
The U.S. Geological Survey (USGS) esti-
mates the total remaining coal resources of
the U.S. to be more than three trillion
1-1
-------
1.2
Domestic
Resource
Base
i
*
1.5
Exploration
r -H
i
I
I
i
i
i
1.6 Surface
Mining and
Reclamation
Area
Contour
1.6 Underground
Mining and
Reclamation
Room ft
Pillar
Long wall
1.8
•*lBeneficiation
1.9
Improved Solid
Solvent Refining
1.9 Liquefaction
Solvent Refining
H-COAL
Syntnoi I
COED
TOSCOAL
1.9 Low-Btu Gasification
Lurgl
Koppers-Totzek
Westinghouse
COED
1.9 High-Btu Gasification
Lurgi
COg Acceptor
Synthane
HYGAS
BIGAS
1.9 In Situ Gasification
>Solid Fuels
•>Liquid Fuels
^Gaseous Fuels
Involves Transportation 1.7and 1.10 Transportation Lines
Does Not Involve Transportation
Figure 1-1. Coal Resource Development
-------
tons; however, as indicated in Table 1-1,
the proportion of this estimate classified
as identified and recoverable is substan-
**
tially less than the total. In fact,
only about 195 billion tons are classified
as reserves, meaning they are (1) known in
location, quantity, and quality from geo-
logic evidence supported by engineering
measurements and (2) economically recover-
able using currently available technolo-
gies. Almost 1.2 trillion tons of
identified coal resources cannot be eco-
nomically rained at present, and an addi-
tional 1.6 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 input in
1970. The 195 billion tons of coal
reserves are equivalent to 55 times the
total U.S. energy input for that year.
U.S. coal resources account for
approximately 20 percent of world coal
resources (Averitt, 1973: 140). The Union
of Soviet Socialist Republics (USSR) pos-
sesses a large share of the remaining 80
percent.
In 1972, about nine percent of the
bituminous and lignite mined in the U.S.
The estimates are 2.9 trillion tons
within 3,000 feet and 3.2 trillion tons
within 6,000 feet of the surface. All
estimates are in short {2.000-pound) tons.
The estimates for identified re-
sources are subject to a 20-percent margin
of error. Both identified and undiscovered
estimates should be treated with caution.
USGS considers its estimates to be cpnser-
vative; however, some other observers dis-
agree .
"Economically recoverable" estimates
are dependent on the market value of the
resource. These estimates are based on the
latest available USGS data.
Total U.S. energy input in 1970 was
Btu's.
was exported, mostly for metallurgical pro-
cessing. A small amount of coal was im-
ported into the U.S. from Canada.
1.2.2 Characteristics of the Resources
Coals are classified on the basis of
specific compositional characteristics
such as carbon content, heating value, and
impurities. Anthracite and bituminous
coals are primarily ranked on the basis of
fixed carbon content (Figure 1-2). Sub-
bituminous coals and lignite, which contain
less fixed carbon, are ranked on the basis
of heating value (Figure 1-3). As indi-
cated in Table 1-2, approximately 70 per-
cent of all U.S. coal is bituminous or sub-
bituminous, 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
(including moisture, ash, and sulfur) pre-
sent problems when coal is processed and
utilized. Moisture content is related to
rank; the higher the rank, the lower the
moisture content. Moisture ranges from
one percent in some anthracites to more
than 40 percent in some lignites (BLM,
1974: Vol. 1, p. 1-57).
The ash content of coal (the amount
of non-combustible inorganic materials the
coal contains) varies considerably even
within a single seam, making proportional
generalizations difficult. 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 (BLM, 1974:
Vol. 1, p. 1-57).
One impurity that causes great diffi-
culty is sulfur. The sulfur content of
U.S. coals ranges from 0.2 to 7.0 percent.
Fixed carbon is the solid, nonvola-
tile portion of coal that is combustible.
Rank is one method of categorizing coals.
Higher rank coals are considered to have
undergone the greatest chemical transfor-
mation from ancient plant deposits.
1-3
-------
TABLE 1-1
COAL RESOURCES OF THE U.S.'
(BILLIONS OF SHORT TONS)
Feasibility
of
Recovery
Recoverab le
Submarginal
Knowledge of Resource
Discovered
0-3,000 feet
overburden
iood
95e
1.285*
Undiscovered Resources
0-3,000 feet
overburden
0
1,300
3,000-6.000 feet
overburden
0
340
Sources: Averitt, 1973: 137; Theobald and others, 1972: 3.
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.
°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; overburden not
more than 1,000 feet.
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.
^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.
1-4
-------
1-5
100
80
60
o
CO
o
LlJ
X
40
20
CO
^>
o
CQ
CO
ZD
oo
CO
o
CQ
LU
et
o:
RANK
Figure 1-2. Fixed Carbon Content of Major Coal Ranks
-------
1-6
2
OQ
co
a
o
CO
co
CO
CO
o
CQ
UJ
I—
I—I
CJ
C£
RANK
Figure 1-3. Heat Content of Major Coal Ranks
-------
TABLE 1-2
RANK OF IDENTIFIED U.S. COAL RESOURCES
Rank
Anthracite
Bituminous
Subbituminous
Lignite
TOTAL
Identified Resources
(billions of tons)3
21
686
424
449
1,580
Source: Averitt, 1973: 137.
aln short tons (2,000 pounds).
varying considerably between geographic
regions. Host of the low-sulfur coal (coal
with a sulfur content of one percent or
less) is located in the western U.S. (BLM,
1974: Vol. 1, p. 1-57). On an equivalent
Btu basis, however, the contrast between
western and eastern coals is often dimin-
ished because western coals generally have
a lower heating value than do eastern coals.
1.2.3 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 mixture
of ranks in the Northern Great Plains and
Rocky Mountains; and scattered deposits
elsewhere (Figure 1-4). However, almost
90 percent of all coal resources in the
contiguous 48 states are located in just
four USGS coal provinces: the Eastern,
Interior, Northern Great Plains, and Rocky
Mountain (Table 1-3). These provinces are
described in the following regional over-
view.
1.2.4 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
TABLE 1-3
COAL RESOURCES IN U.S. GEOLOGICAL SURVEY PROVINCES1
(BILLIONS OF TONS)
Province
Eastern
Interior
Northern Great Plains
Rocky Mountains
Other
TOTAL
Identified
276
277
695
187
146
1,581
Undiscovered
45
259
763
395
181
1,643
Total
321
536
1,458
582
327
3,224
Source: Averitt, 1973: 137.
Because available estimates are by state and USGS Provinces cross
state boundaries, the figures for these provinces are only approximate.
1-7
-------
Coast Province
Rocky Mountain Province
Northern Great Plains Province
Interior Province
Anthracite
Bituminous coal
Subbituminous coal
Lignite
Eastern Province
Gulf Province
Figure 1-4. Distribution of United States Coal Resources
Source: BLM, 1974: 1-47
-------
cost and relatively greater safety of sur-
face mining. In 1965, the average depth
of coal being rained 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 (Young,
1967: 18). This ratio has been increasing
as mining technologies have advanced, and
a 30:1 ratio is now suggested as reasonable
for the mid-1970's (Averitt, 1970: 6).
Whether or not a 30:1 ratio is generally
reached, approximately 45 billion tons of
coal are now considered economically re-
coverable using available surface mining
technologies (BuMines, 1971: 23).
1.2.5 Ownership of the 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
(BLM, 1974: Vol. 1, p. V-208). Federal
ownership in these states ranges from four
percent in Oklahoma to 97 percent in Alaska
(BLM, 1974: Vol. 1, p. V-208). Although
overall data are not available, apparently
the federal government does not own as much
as four percent of the coal lands in any
other state. 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 (BLM, 1974: Vol. 1,
p. 1-64) . In part, this is because only
Industry frequently uses a ratio of
cubic yards of overburden per ton of coal.
Selected thin seams of coal for metal-
lurgical use are presently mined at a 40:1
ratio in Oklahoma (Johnson, 1974).
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 development.
This pattern will change as more mines are
opened in the Northern Great Plains and
*
Rocky Mountain provinces.
1.3 A REGIONAL OVERVIEW
1.3.1 The Eastern Province
The Eastern Province is comprised of
three regions: Appalachian, Pennsylvania
Anthracite, and Atlantic Coast. As shown
in Figure 1-5, the Appalachian Region is
far larger than the other two combined.
Most of the coal lands in the province are
privately owned.
Although this province has been mined
for many years, considerable quantities of
coal (mostly anthracite and bituminous) are
still in place (Table 1-4). Only approxi-
mately 21 billion of the Eastern Province's
276 billion tons of identified resources
are anthracite; however, this province has
more than 80 percent of the U.S.'s remaining
identified high-rank bituminous.
As indicated by their high rank, east-
ern coals have a high fixed carbon content
and contain relatively low amounts of mois-
ture and volatile matter. The sulfur con-
tent of eastern coals varies considerably.
Approximately 65 percent of the province's
identified resources have a sulfur content
of more than one percent.
Coal deposits in this province are
sometimes exposed on the side of a hill or
A province, the largest unit used by
USGS to define the areal extent of coal
resources, is made up of regions on the
basis of similarity in the physical features
of coal fields, coal quality, and contigu-
ity. 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.
1-9
-------
PENN. ANTHRACITE REGION
APPALACHIAN REGION
ATLANTIC
COAST REGION
Figure 1-5. Distribution of Coal in the Eastern Province
Source: BLM, 1974: 11-213.
-------
TABLE 1-4
COAL RESOURCES IN THE EASTERN PROVINCE
TABLE 1-5
COAL RESOURCES IN THE INTERIOR PROVINCE
Depth
(feet)
0-1,000
0-3,000
0-3,000
3,000-6,000
TOTAL
Status
Recoverable
Thin bed and
identified
Undiscovered
Undiscovered
Amount
(billions of
short tons)
122a
154
39
6
321
Sources: BLM, 1974: 1-69; Averitt, 1973:
137.
aDoes not include mining losses. Coal out-
of-the-ground would be approximately 50
percent of this value.
Depth
(feet)
0-1,000
0-3,000
0-3,000
3,000-6,000
TOTAL
Status
Recoverable
Thin bed and
identified
Undiscovered
Undiscovered
Amount
(billions of
short tons)
102a
175
249
10
536
Sources: BLM, 1974: 1-69; Averitt, 1973:
137.
TJoes not include mining losses. Coal out-
of-the-ground would be approximately 50
percent of this value.
mountain; at other times, they are buried
deep below the surface. Seam thickness
rarely exceeds six feet.
Croplands, pasture, and forestry are
the other major land uses in the province.
Most farming is of a subsistence type. The
economic mainstay outside the major urban-
industrial centers, such as Pittsburgh and
Charleston, is minerals extraction.
Surface water supplies are abundant,
and precipitation averages between 35 and
50 inches a year.
1.3.2 The Interior Province
Four regions comprise the Interior
Province: Northern, Eastern, Western, and
Southwestern (Figure 1-6) . Except for a
portion of the Western Region, most coal
lands in the province are privately owned.
The coal resources of the province are
536 billion tons; some 102 billion tons in
the ground could be economically mined
(Table 1-5). Most of this coal is bitumi-
nous, a small amount of anthracite in
Arkansas being an exception. Except for
low-volatile coal found in Arkansas and
eastern Oklahoma, the bituminous is highly
volatile. The moisture content is gener-
ally low, except for coals in the northern
part of the province, and sulfur content
tends to be high, generally in excess of
three percent.
As in the Eastern Province, seams are
generally six feet or less in thickness.
Many of the deposits are close to the sur-
face, making them candidates for surface
mining.
The major land use in the province is
farming and livestock feeding. In fact, the
province is intensely agricultural and one
of the most productive agricultural areas
in the U.S.
Although most of the province is well
supplied with water, competition for its
use is generally keen. The annual rainfall
ranges from about 32 to 48 inches.
Volatile matter is the portion of
coal that turns into a vapor when heated.
Volatile coals burn easily.
1-11
-------
NORTHERN RE6IOI
WESTERN REGION>
ILLINOIS
EASTERN REGION
SOUTHWESTERN REGION
Figure 1-6. Distribution of Coal in the Interior Province
Source: BLM, 1974: 11-192.
-------
1.3.3 The Northern Great Plains Province
As illustrated in Figure 1-7, the
Northern Great Plains Province, which con-
tains 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
trillion tons of coal (Table 1-6), 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 mois-
ture and volatile matter content of both
Fort Union and Powder River coals are rela-
tively high and, as indicated 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 sufficiently near the
surface to allow surface mining.
Much of the surface area of the prov-
ince is still covered by native vegetation.
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.
Much of this water comes from runoff from
the mountains to the west. The average
annual runoff ranges from less than 1 inch
to 10 inches.
1.3.4 The Rocky Mountain Province
The largest of the Rocky Mountain
Province's eight regions (Figure 1-8) are
the Green River, Uinta, and San Juan River.
As shown in Table 1-7, 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.
TABLE 1-6
COAL RESOURCES IN THE NORTHERN
GREAT PLAINS PROVINCE
TABLE 1-7
COAL RESOURCES IN THE
ROCKY MOUNTAIN PROVINCE
Depth
(feet)
0-1,000
0-3,000
0-3,000
3,000-6,000
TOTAL
Status
Recoverable
Thin bed and
identified
Und iscovered
Undiscovered
Amount
(billions of
short tons)
106a
589
663
100
1,458
Sources: BLM, 1974: 1-69; Averitt, 1973:
137.
not include mining losses. Coal out-
of-the-ground would be approximately 50
percent of this value.
Depth
(feet)
0-1,000
0-3,000
0-3,000
3,000-6,000
TOTAL
Status
Recoverable
Thin bed and
identified
Undiscovered
Undiscovered
Amount
(billions of
short tons)
3?a
150
194
201
582
Sources: BLM, 1974: 1-69; Averitt, 1973:
137.
not include mining losses. Coal out-
of-the-ground would be approximately 50
percent of this value.
1-13
-------
ASSINIBOINE REGION
FORT UNION REGION
JUDITH
BASIN
REGION
DENVER REGION
POWDER
RIVER REGION
RATON MESA REGION
Figure 1-7. Distribution of Coal in the
Northern Great Plains Province*
Source: BLM, 1974: 11-132.
*See Figure 1-10, for other coal deposits in *these states.
-------
HAMS FORK
REGION
SOUTHWESTERN
UTAH REGION
WIND RIVER
REGION
GREEN
RIVER REGION
YELLOWSTONE REGION
UINTA
I BASIN
Colorado R.
NEW MEX.
Rio Grande R.
Figure 1-8. Distribution of Coal in the
Rocky Mountain Province*
Source: BLM, 1974: 11-132.
*See Figure 1-9 for other coal deposits in these
states.
-------
The province has the greatest variety
in ranks and geologic setting of any prov-
ince 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. Moisture content tends
to be low and volatile matter content rela-
tively high. Heating values range from
5,000 to more than 14,000 Btu's per pound
(BLM, 1974: Vol. 1. p. 1-57). Sulfur con-
tent is generally low, with almost 90 per-
cent of identified resources having a sul-
fur 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.
Much of the province is still covered
by natural vegetation, and grazing is a
major land use. Mining, logging, ranching,
and farming are other land uses.
Except for the high mountains, pre-
cipitation 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.
1.4 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 contiguous
48 states. There are major differences
between these provinces in terms of the
quantity and quality of their- coal, owner-
ship, bed depth, seam thickness, and avail-
ability of water resources, as well as
competition for surface area usage. Fur-
ther, these differences will become in-
creasingly important as technologies are
developed to make coal a more acceptable,
less environmentally threatening source of
energy.
The Northern Great Plains and Rocky
Mountain Provinces contain approximately
70 percent of the coal resources in the
^four major provinces and most of the
nation's low-sulfur coal. Other character-
istics 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. Coals are lowest in energy value
per unit weight.
5. Water resources are least plenti-
ful.
These points should be kept in mind
when reading the remaining sections in this
chapter.
1.5 EXPLORATION
As mentioned in Section 1.1 and illus-
trated in Figure 1-9, coal resource develop-
ment entails a sequence of activities be-
ginning with exploration and ending with
the transportation of solid, gaseous, or
liquid fuels. There are a number of points
in this sequence at which technological
choices have to be made. In the following
sections, the technological alternatives
associated with each of these decision
points will be identified and described.
1.5.1 Technologies
The general locations of major U.S.
coal deposits are well-known, and data on
these resources are more extensive than for
such resources as oil and natural gas. Con-
sequently, there has been little motivation
for promoting the development of better
coal exploration technologies.
Knowledge about coal resources is
usually obtained in stages. First, avail-
able geological and geophysical data for a
large area are reviewed and evaluated. If
these data are sufficiently promising, a
check is undertaken to identify the owner
1-16
-------
1.2
Domestic
Resource
Base
1.5
Exploration
1.6 Surface
Mining ft
Reclamation
Area
Contour
1.6 Underground
Mining 8
Reclamation
Room ft .
Pillar
Longwall
1.8
Beneficiation
1.9
Improved Solid
Solvent Refining
1.9 Liquefoction
Solvent Refining
yntnoH
COED
TOSCOAL
1.9 LowBtu Gasification
Lurgi
Koppers-Totzek
Westinghouse
COED
1.9 High-Btu Gasification
Lurgi
C02 Acceptor
Synthane
HYGAS
BIGAS
1.9 In Situ Gasification
•Solid Fuels
"^Liquid Fuels
•Gaseous Fuels
Involves Transportation 1.7 and 1.10 Transportation Lines
Does Not Involve Transportation
Figure 1-9. Coal Resource Development
-------
of the surface and mineral rights. Addi-
tional data may also be gathered, usually
by examining the surface to detect coal
outcrops and by collecting samples.
If warranted, this regional appraisal
is followed by a detailed study of identi-
fied or suspected deposits. Although
drilling into deposits to determine seam
depth, thickness, and areal extent is the
primary exploratory technique at this stage,
other techniques may also be used to supple-
ment cuttings and core sample data. For
example, surface and areal photographic
surveys and magnetic and gravimetric mea-
surements may be made to detect variations
in the geologic structure, and tunnels may
be dug to obtain additional subsurface
samples. Seismic devices that distinguish
geologic strata by recording reflected
sound waves may also be employed, as might
down-hole well-logging instruments (includ-
ing cameras and acoustical devices) to
distinguish geophysical characteristics.
Despite the availability of this array of
exploratory tools, the drill remains the
primary tool used for finding and then
mapping coal deposits. Mapping is essential
for planning an effective mine operation
(Grim and Hill, 1974: 26).
1.5.2 Energy Efficiencies
All exploration energy inputs are an-
cillary. While not calculated, they appear
small.
1.5.3 Environmental Considerations
Environmental residuals from explora-
tion are limited to surface and subsurface
physical disturbances and noise associated
with work crews, drilling, tunneling, etc.
These are usually limited to small areas
and the overall residuals are small.
1.5.4 Economic Cons iderations
Data on exploration costs are limited
and generally out of date. However, a
Bureau of Mines (BuMines) cost analysis of
hypothetical mines does provide an indica-
tion of the relative magnitude of explora-
tion costs in 1969 as a component of coal
resource development (BuMines, 1972: 2).
Data for three surface mines and two under-
'ground mines are summarized in Tables 1-8
and 1-9. The data for surface mines combine
capital costs for exploration, roads, and
buildings. These data seem to show that
the proportionate cost of exploration is
less for the higher rank coals.
In the case of underground mining, the
data seem to indicate that the thicker the
seam, the less the proportionate cost of
exploration. Also, the cost of exploration
appears to be proportionately less for
underground mines, although a direct com-
parison is impossible given the failure to
break out exploration costs as a single
category for surface mining. The propor-
tionate total cost of exploration for sur-
face mining is apparently comparable to
that for underground mining.
1.6 MINING AND RECLAMATION
1.6.1 Technologies
The principal coal mining methods are
underground and surface. A third type,
auger mining, is occasionally identified
as a distinct method.
1.6.1.1 Surface Mining
Until recently, most U.S. coal was
mined underground. However, as indicated
in Figure 1-10, surface mining has been
increasing for several decades, and slightly
more than 50 percent of the coal mined in
the U.S. now comes from surface mines
(Gouse and Rubin, 1973: III-1) . Most sur-
face coal is produced by a relatively few
large mines; 50 of the largest mines pro-
duced about one-fourth of the 552 million
tons of bituminous coal produced in 1971.
The choice of mining method depends on
a number of considerations, including seam
depth and thickness, deposit size, and local
geology. As discussed in Section 1.2.4,
1-18
-------
TABLE 1-8
EXPLORATION COSTS IN SURFACE MINES'
(1969 DATA)
Rank
Bituminous
Subb ituminou s
Lignite
Location
Northern West
Virginia
Southwestern
U.S.
North Dakota
or Montana
Direct Capital Requirement13
£•
Exploration
$698,000
797,000
698,000
Total
$9,648,000
5,888,900
4,763,900
Percentage,
Exploration
7.2
13.5
14.6
Total Capital
Requirement
$12,725,500
7,898,100
6,381,800
Percentage
Exploration6
4.5
10.1
10.9
Source: BuMines, 1972: 8, 70, 101.
^ine size capable of producing one million tons of coal per year.
bDirect capital costs are for equipment or items that can be assigned to particular activities, such as buildings,
In contrast, indirect capital costs are a general expenditure such as overhead, engineering, etc.
°Includes direct capital requirement for roads and buildings.
Exploration as a percentage of total direct capital requirement for all mining activities.
Exploration as a percentage of total capital requirement, both indirect and direct as defined in footnote b.
-------
1920 1930 1940 1950 I960 1970
Figure 1-10. Increase in Coal Production by Surface Mining
Source: Adapted from Gouse and Rubin, 1973: III-5.
1980
-------
TABLE 1-9
EXPLORATION COSTS IN UNDERGROUND BITUMINOUS MINES*
(1969 DATA)
Annual Production
(millions of tons)
1.06
1.03
Seam
Thickness
(inches)
72
48
Direct Capital
Requirement
$7,264,600
6,626,900
Percentage
Exploration13
0.7
0.8
Total Capital
Requirement
$10,801,600
11,189,400
Percentage
Exploration0
0.5
0.5
Sources: Katell and Hemingway, 1974a: 6, 7; Katell and Hemingway, 1974b: 5, 6.
aFixed exploration cost of $50,000.
Exploration as a percentage of total direct capital requirement.
°Exploration as a percentage of total capital requirement.
until about 1965 surface mining of coal was
not considered feasible unless the overbur-
den-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 not con-
sidered economically recoverable, even
when the overburden-to-seam thickness ratio
is as much as 30:1.
There are two major types of surface
mines, contour and area. Contour mining
is generally used in hilly or mountainous
terrain. In this mining method, the over-
burden is removed from the slope to create
a flat excavation, or bench, which is
flanked by a vertical highwall on one side
and a downslope pile of spoils on the other
(Figure 1-11) (Senate Interior Committee,
1973: 14). The exposed surface layer of
coal is then mined. Coal exposed in the
highwall may also be mined by large drills
or augers which pull the coal horizontally
from the seam.
As mentioned in Section 1.2.4, se-
lected thin seams of coal for metallurgical
use are being mined at a 40:1 ratio in
Oklahoma.
Area mines, used in flat terrain, are
opened by excavating a trench to expose the
coal deposit (Senate Interior Committee,
s'
1973: 12) . As succeeding cuts are made to
expose the coal, the overburden is piled
into the cut from which the coal has al-
ready been mined (Figure 1-12). The opera-
tions involved in surface mining include
surface preparation, fracturing, excavation,
and transportation.
1.6.1.1.1 Surface Preparation
The initial phase of mine development
requires construction of access roads and
maintenance and personnel facilities. Also,
utilities must be brought to the site and,
in most regions, vegetation removed from
the area to be mined. Even after the mine
is established, additional vegetation re-
moval may be required as the overburden
stripping operation advances. When the
vegetation is sparse and a dragline is used
for excavation, vegetation is removed with
the overburden.
The equipment used in surface prepara-
tion consists primarily of bulldozers,
scrapers, and loaders. If the topsoil is
to be replaced during reclamation, trucks
are required to transport it to a stockpile
or to an area being reclaimed.
1-21
-------
SPOILS
Figure 1-11. Contour Mine
Source: Adapted from NPC, 1972: 51,
-------
BENCH
Figure 1-12. Area Mine
Source: Adapted from NPC, 1972: 51.
-------
1.6.1.1.2 Fracturing
Fracturing consists of two steps,
drilling blastholes and blasting. Blast-
holes extending from the surface to the
coal seam are usually drilled by an elec-
trically-powered rotary drill of 4 to 15
inches in diameter. Larger holes are
drilled for fracturing the overburden than
for the coal, when the formation to be
penetrated is particularly hard, a pneu-
matic drill may be used. Both types of
drills are usually mounted on a truck or
tractor.
The most frequently used explosive is
a mixture of ammonium nitrate (a commercial
fertilizer) and fuel oil termed "ANFO."
Either dynamite or metalized mixtures,. such
as ammonium nitrate and aluminum, can be
used when a more powerful explosive is
required. In populated areas, noise con-
trol is attempted by covering the explosive
cord used in detonating and by introducing
millisecond delays in explosion sequences
(Grim and Hill. 1974: 93). For safety,
blast areas may be covered by mats to
minimize the scattering of rock fragments
(Grim and Hill, 1974: 94).
1.6.1.1.3 Excavation
A number of technological alternatives
are available for excavating overburden and
coal after fragmentation. Four kinds of
equipment are used in typical surface
mining operations:
1. Small, mobile tractors, including
bulldozers, scrapers, and front-
end loaders.
2. Shovels.
3. Draglines.
4. Wheel excavators.
Most mining operations will use sev-
eral of these equipment items in varying
combinations, although one or two usually
dominate the operation. Item selection
and combination are generally based on the
nature and quantity of the material to be
moved, distance and transport surface con-
ditions, and flexibility of the equipment
for other applications (Killebrew, 1968:
463). Descriptions of the major mining
equipment items follow:
1. Tractors. Tractors 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 capability to
dig and transport their own loads
(Killebrew, 1968: 463, 464).
Tractors are used for a variety
of tasks, including clearing, pre-
paring benches, leveling spoil
piles, and constructing roads.
2. Shovels. Large diesel or electri-
cally powered stripping 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.
3. Draglines. Electrically powered
draglines, such as the one shown
in Figure 1-13 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 30 to 220 cubic yards. The
dragline moves along the bench,
positions its bucket on the over-
burden to be removed, 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.
4. 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
(Aiken and Wohlbier, 1968: 479).
As shown in Figure 1-14, 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 excavator.
1-24
-------
Figure 1-13. Dragline
Source: Adapted from NPC, 1972: 51.
-------
Figure 1-14. Bucket Wheel Excavator
Source: Adapted from Weimer and Weimer, 1973: Figure 17-79, p. 17-136
-------
The bucket wheel excavator
has been used fairly extensively
in Europe, generally in deep sur-
face mines where the overburden
is several hundred feet thick
(Gartner, 1969: 26). In this type
of mine, the excavator can operate
for an extended time in a rela-
tively fixed position. Bucket
Wheel excavators can make high
cuts, thus requiring fewer levels
in the mine, and can cut seams
that have a high slope angle
(Gartner, 1969: 26).
Whatever the method used, area and
contour mines require large energy inputs
and have high materials outputs. The mate-.
rials balance for surface mining methods
is listed in Tables 1-10 and 1-11.
1.6.1.2 Underground Mining
The two basic methods used in under-
ground mining in the U.S. are: (1) room and
pillar, and (2) longwall. In both types of
mines, the initial step is to prepare the
surface by constructing access roads and
facilities, bringing the necessary utilities
to the site, and clearing vegetation from
the construction site and the location of
tunnels or shafts. The equipment used for
these tasks is the same as that used for
surface mines.
The coal deposit is reached by digging
or boring a vertical shaft or a horizontal
(or slanting) tunnel. Only after the
deposit is reached do differences in the
mining methods occur.
TABLE 1-10
MATERIALS BALANCE FOR AREA SURFACE MINING
Inputs
Electricity
Fuel (diesel)
Water
Chemicals and
explosives
Quantity
76,741 kwhdb
1,121 gpdd
0
U
Outputs
Coal
Solid waste
Liquid waste
Air emissions
Quantity
5,490 tpdc
46.49 tpd
6.14 tpd
0.32 tpd
U = unknown.
Source: Adapted from Hittman, 1974: Vol. I., Table 1.
National average for coal mine of two million tons production per year;
assumes an average depth of 48 feet and an average seam thickness of 5.2
feet; equivalent to 48.9xlO-'-2 Btu's per year.
kilowatt-hours per day.
ctons per day.
gallons per day.
Coal mining water demands are usually minor and are primarily for dust con-
trol, fire protection, coal washing, and revegetation. However, if the mine
is in an arid region (less than 10 inches of rainfall per year), a supple-
mental source of water (other than local or mine-produced supplies) may be
needed, especially for revegetation. In the revegetation program for an
arid region, 0.5 to 0.75 acre-feet of water per acre mined should be suffi-
cient to establish seedlings (Davis and Wood, 1974: 1).
1-27
-------
TABLE 1-11
MATERIALS BALANCE FOR CONTOUR MINING
Inputs
Electricity
Fuelb (diesel)
Water
Chemicals and
explosives
Quantity
76.183 kwhdc
1,101 gpde
0
U
Outputs
Coal
Solid waste
Liquid waste
Air emissions
Quantity
5,490 tpdd
53.3 tpd
1.22 tpd
0.48 tpd
U = unknown.
Source: Adapted from Hittman, 1974: Vol. I., Table 10.
on a two-million-tons-per-year Central Appalachian mine under con-
trolled conditions (equivalent to 48.9xl012 Btu's per year).
Complete energy consumption information by the modified block cut method
is not available.
kilowatt-hours per day.
tons per day.
gallons per day.
1.6.1.2.1 Room and Pillar
In room and pillar mining, a passage-
way is excavated through the coal seam.
From this passageway, rooms are formed by
mining the coal, leaving portions in place
to act as support pillars for the strata
overlying the rooms. The pattern of this
excavation is diagrammed in Figure 1-15.
Room size depends on the geology of
the strata being mined, the two governing
factors being seam thickness and the
strength of the coal and the materials
immediately above and below it. In typical
U.S. underground mines (which are mostly
in the Eastern Province), coal and surround-
ing material strengths are low, and coal
seams range from two to six feet thick. As
a consequence, the rooms are long and nar-
row, typically 10 to 20 feet wide and
several hundred feet long. The rooms are
kept this small even though mechanical
supports are used to increase the load-
bearing capacity of the mine roof.
In room and pillar mining, the coal is
cut off the face of the seam and loaded
onto some type of transportation equipment.
This is accomplished by any of four methods:
1. Hand cutting and loading.
2. Machine cutting and hand loading.
3. "Conventional mining," which uses
machine cutting and mechanical
loading.
4.
"Continuous mining, " in which one
machine performs the cutting and
loading operations.
Most U.S. room and pillar mines now employ
either conventional or continuous mining
methods.
In conventional mining, a cutting
machine, operating somewhat like a large
chain saw, cuts a slice under the seam
(Figure 1-16). A mobile drilling rig then
drills blastholes, the coal is fragmented
1-28
-------
CONVENTIONAL
MINING Shoot Load Bolt
Continuous Miner
I. 2.
CONTINUOUS MINING
Figure 1-15. Alternative Methods for Room and Pillar Mining
-------
Figure 1-16. Cutting Machine
-------
by blasting (Gouse and Rubin, 1973: 111-19),
and the fragments are picked up by a me-
chanical loader (Figure 1-17). Because of
the low clearances in most underground
mines, the blasthole drills (both rotary
and percussion types are used) are mounted
on low-profile vehicles and the holes
drilled horizontally. As in surface mining,
the most commonly used explosive is ANFO.
In continuous mining, a single machine
(the continuous miner) performs the cutting,
loading, and initial transportation opera-
tions (Gouse and Rubin, 1973: 111-21).
This machine cuts the coal off the face of
the seam by rotating a drum-shaped cutter.
The cutter is mounted above a loading de-
vice that pulls the mined coal onto a con-
veyor belt which then moves it to the trans-
portation system being used to carry the
coal to the surface.
As indicated in Figure 1-18, the cur-
rent trend in U.S. underground mining is
toward increased use of both the conven-
tional and continuous minding method, al-
though the latter method has shown the
greatest increase. One reason for this is
that continuous mining is considerably less
labor intensive than is conventional mining.
Roof support must be provided for the
rooms excavated by either mining method.
The system most frequently used involves
drilling holes in the roof and inserting
bolts equipped with either expansion heads
or another fastening system (Gouse and
Rubin, 1973: 111-21). Roof bolts generate
compressive stresses to strengthen the
roof and, as indicated earlier, permit
excavating larger rooms than would other-
wise be possible. Recently, epoxy has been
used to cement either bolts or rods into
place.
Leaving pillars in place to support
the roof significantly decreases the por-
tion of the coal that can be mined. On
the average, about 45 to 50 percent of the
coal in place is recovered in U.S. room and
pillar mines. This percentage can be in-
creased by removing additional coal when
the mine is being closed down and roof sup-
port 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 (Gouse and Rubin, 1973:
111-36). The materials balance for a hypo-
thetical room and pillar mine is indicated
in Table 1-12.
1.6.1.2.2 Longwall
Although used extensively in Europe,
longwall mining accounts for only about
three percent of U.S. coal production
(Gouse and Rubin, 1973: 111-23). This type
of operation is illustrated in Figure 1-19.
A shearing drum moves back and forth across
the working face of the seam between two
access passageways or galleries (Laird, 1973:
Vol. 1, p. 12-176). Sheared coal drops
onto a conveyor which moves it to the trans-
portation system being used to remove the
coal from the mine. The roof in the area
immediately behind the mining machine is
held up by hydraulic jacks that are moved
forward as the mining operation advances
(Figure 1-20). As the jacks are moved, the
roof in the area from which the coal has
been mined is allowed to collapse.
The major advantage offered by longwall
mining is recovery of a higher percentage
of the coal in place than is possible with
the room and pillar method. It is also
less labor intensive than some of the other
techniques. On the other hand, capital
costs for longwall mining systems are gen-
erally much higher than for either conven-
tional or continuous room and pillar mining
(Gouse and Rubin, 1973: 111-23). The rela-
tive advantage of longwall over room and
pillar mining is indicated in the materials
balance shown in Table 1-13. Longwall
mining consumes less electricity than does
room and pillar mining.
Shortwall mining, a variation of the
longwall method is sometimes used in U.S.
mines. In shortwall mining, the face is
1-31
-------
Figure 1-17. Mechanical Loader
-------
1-33
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D CONTINUOUS
MINER
1950
1960
1971
Figure 1-18. Underground Mining Methods
Source: Adapted from Gouse and Rubin, 1973: III-9.
-------
conveyor-
direction of advancement
COAL
roof support
collapsed
* roof ••
Figure 1-19. Plan View of Longwall Mining
Source: Adapted from Gouse and Rubin, 1973: 111-24.
-------
i
drum
roof support
shearer
r~
Figure 1-20. Section View of Longwall Mining
Source: Adapted from Gouse and Rubin, 1973: 111-24
-------
TABLE 1-12
MATERIALS BALANCE FOR ROOM AND PILLAR MINING0
Inputs
Electricity
Fuel (diesel)
Lime
Water
Chemicals and
explosives
f
Quantity
98,672 kwhdb
0
Approximately
230 tpd
U
U
Outputs
Coal
Solid waste
Liquid waste
Air emissions
Water
Quantity
5.490 tpdc
154 tpd
5.23 tpd
0.00 tpd
1.61 ramgpd
U = unknown.
Source: Hittman. 1974: Vol. I., Table 8.
on a two-million ton-per-year Northern Appalachian mine (equivalent to
47.17x10-12 Btu's per year). Under controlled conditions.
kilowatt-hours per day.
ctons per day.
millions of gallons per day.
TABLE 1-13
MATERIALS BALANCE FOR LONGWALL MINING
Inputs
Electricity
Fuel (diesel)
Water
Chemicals
Quantity
89.346 kwhdb
0
U
U
Outputs
Coal
Solid waste
Liquid waste
Air emissions
Water discharge
Quantity
5,490 tpdc
230 tpd
7.79 tpd
0.00 tpd
1.61 mmgpd
U = unknown.
Source: Hittman, 1974, Vol.. I, Table 8.
TJased on a two-million-ton-per-year Northern Appalachian mine under controlled
conditions.
kilowatt-Incurs per day.
ctons per day.
millions of gallons per day.
1-36
-------
roughly 150 feet long as compared to 600
feet for longwall, and a continuous miner
is used instead of a shearer (BLM, 1974:
Vol. 1, p. 1-96).
1.6.1.3 Mine Safety
Mine safety, a continuing problem, is
more critical in underground than in sur-
face mining. In surface mines, safety
problems are much the same as those asso-
ciated with any activity involving 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 BuMines began keeping records in
1910 and, as Figure 1-21 indicates, fatali-
ties have decreased since then.
Mines are usually ventilated by posi-
tively managing airflow patterns throughout
the mine. This may include erecting tempo-
rary partitions, establishing airwall bar-
riers, and installing fans to circulate
air. Temporary partitions are being used
to control ventilation in the mine dia-
grammed in Figure 1-22. Ventilation systems
typically include several techniques, to-
gether with dust collectors and monitoring
equipment.
Methane has always been a problem in
underground mines. Most current attempts
to deal with this problem use conventional
ventilation methods. However, degasifica-
tion (including drilling holes to drain
methane pockets or introduce gases which
have a higher affinity for methane than
does coal) is now receiving R&D attention
(Gouse and Rubin, 1973: 111-37). Although
at least one large coal company is using
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. All these
technologies have been under development
for considerable periods of time. In addi-
tion, rigid inspection, testing, and ap-
proval procedures have helped make mine
equipment safer. Mine safety has improved
during the last 50 years, and, as shown in
Figure 1-23, this improvement is apparently
linked very closely to the introduction of
new technologies.
1.6.1.4 Reclamation
Although the large areal disturbances
of surface mining are generally more visible,
both underground and surface mining tech-
niques produce significant physical impacts.
Both methods disturb the surface, produce
wastes that require disposal, can affect
water resources, and expose materials that
produce acids when dissolved in water.
Using a broad definition, these are all
reclamation problems.
1.6.1.4.1 Surface Mine Reclamation
In surface mining, the major reclama-
tion problem is dealing with the surface
disruption. This normally involves smooth-
ing out piles of overburden and making some
attempt to revegetate the area. Comprehen-
sive reclamation programs include restoring
the surface topography, replacing the top-
soil, fertilizing and revegetating, and
returning the land to some productive use,
whether agricultural, commercial, residen-
tial, or recreational.
Replacement topsoil may be the original
topsoil, which has been removed and stock-
piled, or may be topsoil brought from some
other area. In any case, plant receptive
material is replaced after the overburden
is graded and shaped. Seeding and fertili-
zation is then undertaken, using either
-------
.- 3
CO
LU
P
-J
<
I
er million tons
_ Per million man hours
1910 1920 1930 1940 I960
Figure 1-21. Underground Mine Fatalities
Source: Adapted from Gouse and Rubin, 1973: 111-13.
1970
-------
^-cutter or mining machine
temporary walls i
for directing
I vent air '
t
ventilation air flow
Figure 1-22. Ventilation in a Room and Pillar Mine
Source: Adapted from Gouse and Rubin, 1973: 111-20.
-------
500
(—(permissible explosives
ifirst application of rock dusting
•»•
[permissible electrical equipment
L.
o\~ [permissible electric cap lamps
[improved ventilation
5 year averages
1910
1920
1930 1940 1950 I960 1970
Figure 1-23. Fatalities from Explosions in Underground Coal Mines
Source: Adapted from House and Rubin, 1973: 111-12.
-------
conventional methods or such combination
techniques as air-dropping palletized seeds
(EPA, 1973: 175). However, successful
revegetation apparently depends more
heavily on adequate rainfall than on seeding
*
and fertilizing methods.
1.6.1.4.2 Contour Mine Reclamation
As noted in the earlier description
of contour mining, the overburden is piled
on the downslope behind the mining opera-
tion. Although this slope presents a
reclamation problem, a number of techniques
are available for minimizing undesirable
impacts (Senate Interior Committee, 1973:
11). Some of these include:
1. Shaping the Spoil Bank. In this
technique, the spoil bank is
reshaped by a bulldozer as indi-
cated in Figure 1-24. This in-
volves knocking down all vegeta-
tion and compacting the spoil in
layers to reduce erosion. A
revegetation program then follows.
Although this technique reduces
damage, the exposed highwall
remains (Senate Interior Committee,
1973: 16-18).
2. Backfilling the Bench. In this
technique, the spoil bank is moved
back over the bench to fill in the
original cut and cover the high-
wall. This leaves the land in a
configuration similar to the
original form (Figure 1-25).
Terraces or diversion ditches can
be used to minimize erosion. Al-
though several approaches can be
used in backfilling, substantial
portions of the downslope areas
are damaged by the spoils, and all
the spoils cannot be returned to
the bench (Senate Interior Commit-
tee, 1973: 18-20).
3. Modified Block Cut. This tech-
nique modifies the sequence of
mining operations in conventional
contour mining. Instead of con-
tinuously mining a slope by pushing
the spoils over the downslope,
successive cuts excavate the
spoils into a previously cut bench.
This has been assumed' to be the case.
However, the actual shaping and restoration
program depends largely on the type of mine
and where it is located. Contour mine rec-
lamation problems are more difficult than
those associated with area mines, primarily
because of topography.
Thus, only an initial bench cut
must push overburden into a down-
slopa pile. This technique has
the advantage of allowing the top-
soil to be set aside, and only the
bench topography is modified
(Senate Interior Committee, 1973:
20-23).
1.6.1.4.3 Area Mine Reclamation
Area mines pose fewer reclamation
problems than contour mines. The mined
areas are frequently returned to their
original topography, but restoration re-
quirements and capabilities vary with loca-
tion. For example, when thick Montana and
Wyoming coal beds are mined, restoring the
land to its original form is almost impos-
sible. Further, revegetation in arid and
semiarid areas such as these is also a
major problem.
1.6.1.4.4 Underground Mine Reclamation
The reclamation problems associated
with underground mines vary somewhat from
those of surface mines. Although some
surface clean-up may be required and the
materials removed to gain access to under-
ground coal seams require disposal, both
problems are comparatively small. A larger
problem is the disposal of materials mined
with the coal. Often the coal is cleaned
at the surface to remove these materials.
However, the materials cannot be simply
piled up and left uncovered because they
may produce acid water runoff when dissolved
by rain. Clean-up of acid mine waste by
lime treatment is assumed in the materials
balance previously tabulated (Tables 1-12
and 1-13).
Waste piles (composed of access mate-
rials, coal-separated materials, and/or
refuse, such as tailings and slag) also
present reclamation problems. The water
impounded by such a pile, and released when
it gave way, produced a disastrous flood
at Buffalo Creek, West Virginia a few years
ago. That pile was not designed to be a
dam but was used as one. The water
1-41
-------
-Original Surface
Backfilled
Figure 1-24. Reclamation by Reshaping the Spoil Bank and
Partial Backfilling
Source: Adapted from EPA, 1973: 116.
-------
g^^fc—-Original Surface
i 1 1 1 1 • i •—r——i • i 1 1
Figure 1-25. Reclamation by Full Backfilling of the Bench
Source: Adapted from EPA, 1973: 112.
-------
impounded in the narrow hollow was also
used as a settling pond and a source of
process treatment water.
Subsidence of the surface area over-
lying underground mines also constitutes a
reclamation problem. Generally, the sur-
face will subside, limiting subsequent
surface usage.
1.6.2 Energy Efficiencies
Energy efficiency and environmental
data are from Hittman, Battelle, and
Teknekron. The Battelle data are based on
hypothetical mines located in the eastern
and western U.S. The characteristics of
the resource used in the Battelle calcula-
tions are listed in Table 1-14. Teknekron
data are representative of eastern coal in
general. Specific coal characteristics
and assumptions used by Teknekron are not
available. Differences in the efficiencies
and environmental residuals reported in
several of the tables can be partially
explained by assumptions stated in the
text. The assumptions cannot account for
many of the differences, however, and these
may represent variation in technologies or
methods of calculation. Hittman's mining
and reclamation data are for respective
mines located in five areas which can be
related to USGS provinces and regions as
follows:
Hittman Area USGS Province/Region
Northern Appalachian Eastern/Appalachian
Central Appalachian Eastern/Appalachian
Central Interior/Illinois
Eastern
Northwest Northern Great
Plains/Powder River
Southwest Rocky Mountain/
San Juan River
The coal characteristics for each of
the five Hittman areas are given in Table
1-14. Since coal composition and the con-
ditions under which coal resource develop-
ment takes place can vary significantly
even within a single area, Hittman's data
for these five areas apply only to a mine
at ja specific location. These data are not
applicable, even as averages, to the region
within which the mine is located.
Data on mining and reclamation are
reported for area, contour, auger, longwall,
and room and pillar mines under either con-
trolled or uncontrolled conditions. Under
controlled conditions, land reclamation
and water treatment are included as a part
of the mining operation; under uncontrolled
conditions, they are not.
Two yardsticks are used in assessing
the efficiency of various mining methods:
the percentage of in-place coal recovered
and the amount of ancillary energy required.
Ancillary energy requirements are the
diesel fuel and electricity required to
operate all mining equipment (including
drills, draglines, tractors, and trucks)
and, under controlled conditions, to re-
claim the land.
1.6.2.1 Surface Mining and Reclamation
Recovery efficiencies and ancillary
energy requirements per 10 Btu's for
various types of surface mines are presented
in Table 1-15. Recovery efficiencies range
from a low of 46 percent for Central
Appalachian auger mining to a high of 98
percent for Northwest strip mining. Area
strip mining in other regions is about
80-percent efficient. No variation occurs
between the uncontrolled and controlled
cases, and the data are known for all of
the recovery efficiencies to within 10
percent.
Ancillary energies are not well known,
and the data are only valid to within an
order of magnitude. Of the total ancillary
requirement, approximately 85 percent is
electric and 15 percent is diesel. An
exception is the Northwest Region, where
Processing of coal for cleaning and
sizing is discussed in Section 1.8.
1-44
-------
TABLE 1-14
COAL CHARACTERISTICS USED IN ENVIRONMENTAL RESIDUALS CALCULATIONS
Heat content
(Btu ' s per pound)
Ash (percentage)
Sulfur (percentage)
Density (pounds per
cubic foot)
Tons coal equal to
1012 Btu's
Average seam
thickness-
underground mine
(feet)
Average seam
thickness-strip
mine (feet)
Average overburden
thickness-strip
mine (feet)
Hittmana
Northwest
8,780
6.77
0.85
81
57,000
U
39
60
Central
10,600
8.9
2.92
81
47,200
6.8
4.8
52
Northern
Appalachia
11,800
14.7
3.07
85
42,400
5.1
3.9
47
Central
Appalachia
12,100
11.2
0.93
85
41,000
4.7
U
U
Southwest
9,820
15.7
0.6
81
51,000
U
11.8
47.9
Battelleb
Eastern
12,000
NC
NC
82
41,500
NC
2
33C
Western
9,235
NC
NC
82
54,000
NC
5
13°
NC = not considered, U = unknown.
Sources: ^ittman, 1974: Vol. I, Tables 3-12 and footnotes.
bBattelle, 1973: 69.
Tons overburden per ton of coal.
*>.
ui
-------
TABLE 1-15
SURFACE MINING EFFICIENCIES
Area mining
Recovery efficiency
(percentage)
Ancillary energy
(109 Btu's per 1012 Btu's)
Uncontrolled
Controlled
Contour mining
Recovery efficiency
(percentage)
Ancillary energy
(1C>9 Btu's per 1012 Btu's)
Uncontrolled
Controlled (modified
block cut)
Auger
Recovery efficiency
(percentage)
Ancillary energy
(109 Btu's per 1012 Btu's)
Uncontrolled
Controlled
Northwest
98
1.92
1.93
NA
NA
Central
81
6.48
6.62
NA
NA
Northern
Appalachia
81
5.82
5.94
80
10.9
U
NA
Central
Appalachia
NA
80
10.6
10.7
46
0.86
0.93
Southwest
81
5.09
5.11
NA
NA
NA = not applicable, U = unknown.
Source: Hittman, 1974: Vol. I. Tables 3-12 and footnotes.
diesel fuel accounts for 50 percent of the
total ancillary energy required.
Ancillary energy needs for area mining
Q
are small, averaging 5x10 (five billion)
Btu's for every 1012 (trillion) Btu's
mined; this means that only 0.5 percent of
the energy mined is used in mining. The
ancillary energy requirement for contour
mining is higher than for either of the
other types, averaging about 1.4 percent.
The electric energy was calculated as
three times the Btu equivalent of a kilo-
watt hour (kwh) to obtain the petroleum
equivalent.
The ancillary energy needed under controlled
conditions increases slightly for all types
of mines.
1.6.2.2 Underground Mining
Recovery efficiencies and ancillary
energy requirements (per 10 Btu's) for
longwall and room and pillar mines are re-
ported in Table 1-16. The recovery effi-
ciencies are valid to within 10 percent, but
ancillary energies are only known to within
an order of magnitude. In room and pillar
mines, recovery efficiency is 57 percent
regardless of region and whether controlled
or uncontrolled. The recovery efficiency
1-46
-------
TABLE 1-16
MINING AND RECLAMATION EFFICIENCIES
Room and Pillar
Recovery efficiency
(percentage)
Uncontrolled
Ancillary energy requirement3
(109 Btu's per 1012 Btu's)
Uncontrolled
Controlled
Longwall
Recovery efficiency
(percentage)
Uncontrolled
Ancillary energy requirement
(per 1012 Btu's)
Uncontrolled
Controlled
Central
57
4.75
4.84
U
U
Northern
Appalachia
57
4.21
4.47
85
r
5.64
6.02
Central
Appalachia
57
4.07
4.18
U
U
U = unknown.
Source: Hittman, 1974; Vol. I, Tables 3-10 and footnotes.
Calculated as three times the Btu equivalent of the kilowatt hour
requirement.
of longwall mining is 85 percent. The
difference is primarily the coal left in
the pillars of room and pillar mines.
In underground mines, the principal
ancillary energy requirement is for the
electrically powered continuous miner. The
higher energy requirement in the Central
Region is a result of the lower heat con-
tent of the region's coal. To produce the
same number of Btu's, more coal must be
mined (and thus more energy expended) in
the Central Region than in the Appalachian
Region. Controlled conditions also increase
energy requirements (by some two to six
percent) because of the addition of water
treatment facilities (Table 1-16).
In all cases, the ancillary energy
needed to extract the coal is only a small
portion of the energy contained in the
coal (on the order of 0.4 to 0.6 percent);
thus, the large data uncertainty is not
serious.
1.6.3 Environmental Considerations
1.6.3.1 Surface Mining and Reclamation
Basic environmental data for surface
mining are presented in Table 1-17, in-
cluding the amount of air and water pollu-
tants, solids, and land consumption asso-
ciated with each type of surface mine.
Although they may be matters of great con-
cern, residuals of a qualitative nature,
such as esthetics and noise, are not
included.
1-47
-------
Table 1-17. Residuals for Surface Coal Mining and Reclamation
SYSTEM
NORTHWEST -AREA STRIP
Uncontrolled
Controlled'5
CENTRAL-AREA STRIP
Uncontrolled
Controlled0
NORTHERN APPALACHIAN-
AREA STRIP
Uncontrolled
Controlled
CONTOUR
Uncontrolled
Controlled c
\UGER
Uncontrolled
Controlled0
Water Pollutants (Tons/1012 Btu's)
Acids
NA
NA
3.82
0
6.9
0
6.8
0
1.89
0
Bases
_y.
0
u
3.98
U
.446
U
.441
U
.34
12 nt-,, i o
Deaths
»
c
.0025
.0025
J!.»
.003
.005
0001
.0001
01
u
•r4
H
3
•n
C
H
.057
.057
.16
. 12
.12
. 12
ii
.094
4J
to
O
.J
l/J
>i
ID
Q
1
I
1.41
1.41
3.99
3.99
2.49
2.49
2.49
r2.49
1.9
-------
Table 1-17. (Continued)
SYSTEM
CENTRAL APPALACHIAN
CONTOUR
Uncontrolled
Controlled0
SOUTHWEST-AREA STRIP
Uncontrolled
Controlled13
EASTERN COAL-AREA STRIP
Uncontrolled6
Controlled*3'0
WESTERN COAL-AREA STRIP
Controlled d'c
Water Pollutants (Tons/1012 Btu's)
Acids
3.28
0
0
0
286.1
0
0
Bases
U
.589
0
0
NC
NC
NC
•tf
g
NA
NA
NA
NA
NC
NC
NC
m
g
NA
NA
NA
NA
NC
NC
NC
Total
Dissolved
Solids
36.9
8.92
0
0
273.2
90.4
U
Suspended
Solids
545.
.2
0
0
514.6
276.
140.3
Organics
NA
NA
NA
NA
NC
NC
NC
Q
S
NA
NA
NA
NA
NC
NC
NC
a
8
0
0
0
0
NC
NC
NC
Therma 1
(Btu's/1012)
NA
NA
NA
NA
0
0
0
Air Pollutants (Tons/1012 Btu's)
Particulates
.068
.068
6.59
2.39
NC
70.3
35.
X
§
1.94
1.94
1.05
1.05
NC
.1
.04
X
o
U}
.142
.142
.077
.077
NC
0
0
Hydrocarbons
.194
.194
.105
.105
NC
0
0
8
1.18
1.18
.639
.639
NC
0
0
Aldehydes
.032
.032
.017
.017
NC
0
0
Solids
(Tons/1012 Btu's) |
5.04
xlO5
398.
414.
414.
39.65
120.5
0
V
Land
Acre-year
w
3
4J
W
i
ro
n
C
ID
E
3.30
3.30
.678
.678
NC
74.
96.
not applicable, NC = not considered, U = unknown.
NA
Fixed Land Requirement (Acre
Five years are assumed for land reclamation.
°Three years are assumed for land reclamation.
^attelle, 1973: Tables A-l and A-2.
^Teknekron, 1973: 63.
Includes overburden as solid waste.
year) / Incremental Land Requirement ( Acres ).
1012 Btu's 1012 Btu's
-------
1.6.3.1.1 Water
Table 1-18 is a summary of residuals
by area, and the data are good to within a
factor of two in most cases. The principal
water pollutant in surface mining is sus-^
pended solids. These solids are a product
of runoff from solid waste piles and are
assumed to occur at a rate of 2.54 tons
per acre mined for each inch of runoff
water. (Runoff is 20 inches per year in
the Appalachian area and 10 inches per year
in the Central area. Acreage mined also
varies in different regions.)
The higher values for residuals in
Battelle's Eastern and Western Strip Mine
(Table 1-17) in part are explained by their
assumption of a two-foot coal seam In the
East and five-foot coal seam in the West.
Both amounts are quite small. Suspended
solids can occur in concentrations at least
as high as 1,600 parts per million (ppm) .
As indicated in Table 1-18, discharges are
particularly high in Appalachian contour
mining due primarily to the large areas of
downslope overburden.
Total dissolved solids are concentrated
at about 850 ppm. For comparison, the
Public Health Service's recommended upper
limit on effluent from secondary treatment
of municipal wastewater is 700 ppm.
All water pollutants in Hittman's
Southwest area are assumed to be zero be-
cause, to date, mines in that area have
not intersected groundwater and the limited
rainfall creates very little runoff. In
addition, the overburden is alkaline. How-
ever, even a small amount of runoff could
possibly leach sulfates and salts from
these soils.
Under controlled conditions, drainage
and runoff water is collected, allowed to
settle, and treated at either a lime or
soda ash facility. Suspended solids are
reduced to a 30-ppm concentration and a
zero acid content. In the Northwest and
Southwest where water is especially valu-
able, groundwater seepage and runoff are
collected and used for dust suppression and
irrigation.
1.6.3.1.2 Air
Air pollutants in a surface mining
operation originate from two sources:
diesel-fueled support equipment and wind
erosion. The particulates, caused princi-
pally by wind erosion and total emissions
from diesel equipment, are summarized in
Table 1-18 but are only known to within an
order of magnitude. Wind erosion is highest
in the Northwest and Southwest areas, aver-
aging 428 pounds per acre each year; there-
fore, particulate pollutants also are high-
est in these areas (Hittman, 1974: Vol. I,
footnote 1207). Particulate emissions for
the Eastern and Western strip mines de-
scribed by Battelle (included in Table
1-17) are three orders of magnitude higher
than those described by Hittman. The former
is based on an emission factor of 0.1 pound
of particulates per ton of overburden re-
moved. (Thirty-three tons of overburden
are removed per ton of coal recovered in
the east; in the west, the ratio is 13:1.)
Regional variations for diesel emis-
sions depend primarily on the percent of
equipment that is diesel rather than elec-
trically powered. A majority of equipment
in the Northwest and Southwest is electric;
thus, the total diesel emissions are small
in those areas. (Using electrical equip-
ment does not mean that air pollutants are
not generated; they are simply transferred
from the mining site to the electric power
station site.) The highest diesel emissions
are from contour mining in Northern
Appalachia and both contour mining and
augering in Central Appalachia (Table 1-18).
Hittman's data indicate no difference
in air pollutant emissions under controlled
and uncontrolled conditions. However, this
may not be correct. Reclamation would re-
duce particulates resulting from erosion
-------
TABLE 1-18
SUMMARY OF SURFACE MINING RESIDUALS
Residual
Water (tons per
1012 Btu's)
Total dissolved solids
Acidity
Suspended solids
Air (tons per 1012 Btu's)
Particulates
Total of others
Solids (waste)
(tons per 1012 Btu's)
Land
Stripping (acres per
lO12 Btu's)
Fixed" (total acres for
mine life)
Northwest
Unc.d
1
0
23
2.27
1.85
730
.8
10.0
Con.6
0
0
0
.839
1.85
730
0
5.0
Central
Unc.
43
4
4.22
.05
2.55
433
5.6
8.7
Con.
13
0
.2
.05
2.55
563
0
10.0
Northern Appalachia
Unc.
45
7
7-265
.05-. 07
2.3-3.6
352
to
368,000
5.9-12.0
7.2-0
Con.
15
0
.22
.05-. 07
2.3-3.6
668-412
0
14.8
Central Appalachia0
Unc.
21-37
2-3
859-545
.04-. 07
2.1-3.5
39,300
to
504,000
3.9-15.6
0
Con.
5-9
0
.1-.2
.04-. 07
2.1-3.5
39,300
to
398
0
6.1
Southwest
Unc.
0
0
0
6.6
1.9
414
2.45
39.2
Con.
0
0
0
2.4
1.9
414
0
U
I
Ul
Source: Hittman, 1974: Vol. I, Tables 3-12 and footnotes.
Area strip and contour mining in Northern Appalachia; contour and augering in Central Appalachia. All others are
area strip.
First value is for area stripping; second value is for contour. When only one value is given, it applies to both.
^
First value is for augering; second value is for contour. When only one value is given, it applies to both.
uncontrolled case.
Controlled case.
Includes sulfur oxides, nitrogen oxides, carbon monoxide, hydrocarbons, aldehydes.
g
For the uncontrolled case, this is total area needed for refuse storage; for the controlled case, it is
a water treatment facility; spoils are assumed reclaimed in the controlled case.
-------
but would increase other pollutants by re-
quiring more diesel-powered trucks, trac-
tors, etc.
1.6.3.1.3 Solids
As indicated in Table 1-18, solid
wastes from mining vary as a function of
surface mining technique, and these varia-
tions are considerable. These data are
considered to be accurate to within 50 per-
cent.
In area strip mining, solid wastes are
produced only during the box cut (five
acres) made to open the mine. The amount
of wastes produced by this initial excava-
tion is on the order of 500,000 to 1,000,000
tons of overburden or about 500 tons per
10 Btu's. Under controlled conditions,
an area mine' s water treatment facility
contributes an additional 50 to 150 tons
12
per 10 Btu's of sludge to the total mine
wastes. The effect is to convert water
pollutants into solid wastes.
Teknekron's estimate for solid wastes
from an Eastern area mine (Table 1-17) is
100 times larger than the Hittman estimates.
The reason for this difference is the
Teknekron data includes all overburden
while the Hittman data includes only that
produced during the initial cut.
In the "uncontrolled" contour mines of
Northern and Central Appalachia, solid
wastes and overburden are continually dumped
downs lope, except for four feet of material
above the height of the coal which is used
to backfill the bench. When the modified
box cut mining technique is used in the
controlled technology, the solids problem
is greatly diminished.
To put the quantities of solid wastes
into perspective, a typical area strip mine
excavating 10,000 tons of coal per day
would produce 100 tons of solid waste per
day. an amount approximately equal to the
daily municipal refuse from a town of 40,000
people. The same coal production from a
contour mine would result in 120,000 tons
per day, which is approximately equal to the
quantity of municipal refuse of 48 million
people.
1.6.3.1.4 Land
Two land impact categories are included
in Table 1-18: the incremental land uses
required by stripping the overburden, and
the fixed land requirement for the life of
the mine (including the land needed to store
-the initial box cut refuse and, under con-
trolled conditions, the water treatment
facility and settling pond). The land im-
pact data are considered accurate to within
50 percent.
Land use for area strip mining varies
from 0.8 to 5.9 acres per 10 Btu's ex-
tracted. The smallest value is in the
Northwest location where seam thickness is
39 feet. The largest amount of land on a
Btu basis is needed in Northern Appalachia,
where seam thickness is 3.9 feet. For per-
spective, a Northwest mine producing 10,000
tons of lower Btu coal per day would strip
2.5 square miles in 30 years, while a simi-
lar mine in Northern Appalachia would strip
27 square miles in 30 years.
Augering and contour mining have more
severe land impacts than does area mining.
Contour mining requires 12.0 acres per 10
Btu's in Northern Appalachia and 15.6 acres
per 10 Btu's in Central Appalachia. Auger-
ing requires 3.9 acres per 10 Btu's in
both areas. Four categories of land de-
spoilment are involved in contour mining:
acreage stripped, acreage covered by the
spoil pile reaching downslope from the out-
crop, drainage ditch above the highwall,
and acreage affected by landslides. Of the
acreage affected in contour mining, strip-
ping and downslope spoils each account for
between 5.3 and 5.8 acres respectively,
while the drainage ditch and landslides con-
sume about 2.5 acres per 10 Btu's mined.
For auger ing, the breakdown is 1.3 acres
for subsidence, while the bench and spoils
from downslope deposits each account for
1-52
-------
1.2 acres. Landslides are negligible in
auger mining. In all cases, the fixed acre-
age required is very small relative to the
acreage involved in stripping.
Controlled conditions assume that con-
tour mines use a modified box cut and that
all land is reclaimed through backfilling,
topsoil replacement, and revegetation. The
revegetation (establishment of grass cover)
period is estimated at five years for the
Northwest and Southwest areas and three
years for the Central and Appalachian areas.
1.6.3.1.5 Summary
In all four environmental categories—
water, air, solids, and land—area strip
mining produces fewer residuals than either
contour mining or augering. Also, the
Hittman sites indicate that the Northwest
area is least affected by all types of sur-
face mining, controlled or uncontrolled.
In the Northwest, the major concern is par-
ticulates generated by wind erosion. Pre-
sumably, particulate air pollution would be
controlled in time by revegetation, although
this is not indicated in the tabulated data.
Environmentally, the Appalachian mine loca-
tion appears to be the worst for surface
mining. This also seems to be the area
where esthetic and noise residuals are most
significant, although these are difficult
to quantify.
1.6.3.2 Underground Mining
Hittman does not discuss underground
mining for the Northwest and Southwest
regions, where surface mining is primarily
used at the present time. Basic environ-
mental data for the other regions are pre-
sented in Table 1-19.
Controlled conditions for underground
mining mean that surface runoff and mine
drainage waters are treated. Prevention of
land subsidence is not addressed, and the
control of spoils is discussed with bene-
ficiation technologies.
Room and pillar mining is used in the
Central and Central Appalachian areas, while
both room and pillar and longwall mining
are used in Northern Appalachia. In
Northern Appalachia, both underground tech-
niques produce the same residuals (Table
1-19) except for land use, which is higher
for longwall mining.
1.6.3.2.1 Water
Underground mining residual data are
summarized in Table 1-20 and are generally
accurate to within 50 percent. The prin-
cipal water pollutant in Appalachia is acid
drainage. In Northern Appalachia, acid
drainage from mines is about 1,700 ppm.
The other dissolved solids are principally
sulfates and minerals contributing to hard-
ness (calcium and magnesium ions). Sus-
pended solids are primarily runoff from the
solid waste pile at a rate of 2.54 tons per
acre per inch of runoff per year (Hittman,
1974: Vol. I, footnotes 1305, 1404, 1503).
Under controlled conditions, lime treatment
is used to reduce acidity to zero, and the
resultant effluent meets the Environmental
Protection Agency's (EPA) guidelines.
In the Central area, acid drainage
(140 ppm) is not a serious problem because
most mines are located below drainage
levels and, in some cases, the overburden
is alkaline. When treated with lime, the
effluent has no acid waste as in Appalachia.
As a result, one-third less water is re-
quired, and the total effluent amount is
one-third less.
1.6.3.2.2 Air
Since electrically powered equipment
is generally used underground, air emis-
sions are not a problem. However, dust
within the mine can be hazardous to the
miners' he alth.
1-53
-------
Table 1-19. Underground Coal Mining and Reclamation Residuals
SYSTEM
CENTRAL
Room and Pillar
Uncontrolled
Controlled
NORTHERN APPAIACHIA
Room and Pillar
Uncontrolled
Controlled
Lonqwall
Uncontrolled
Controlled
CENTRAL APPALACHIA
Room and Pillar
Uncontrolled
Controlled
Water Pollutants (Tons/1012 Btu'a)
Acids
2.02
0
67.7
0
101.
0
9.35
0
Bases
U
U
1.19
U
1.77
U
.49
^
2
NA
NA
HA
NA
NA
NA
NA
ro
8
NA
HA
NA
NA
NA
HA
NA
Total
Dissolved
Solids
341.
14.1
438.
39.9
654.
59.4
331.
16.3
1 Suspended
Solids
.016
.21
.028
.6
.042
.89
.027
.243
Organics
NA
NA
NA
NA
NA
NA
NA
HA*
Q
8
NA
NA
NA
NA
NA
NA
NA
HA
Q
8
0
0
0
0
0
0
0
0
Thermal
(Btu1 3/10*2)
NA
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
0
0
0
0
0
0
0
0
X
§
0
0
0
0
0
0
0
0
X
o
tn
0
0
0
9
o
o
0
0
Hydrocarbons
0
0
n
o
o
o
0
0
8
0
0
Q
Q
o
0
0
Aldehydes
0
0
o
0
0
Solids
(Tons/101 2 Btu's)
1.61
64.
1.40
Fv
Land
Acre-year
m
s
«
fM
rH
O
(H
.0006/9.6
1Jl°-
120.
.0005/10.32
.782/10.32
.0008/22.8
1.16/22.8
4oc
.0005/10.6
.182/10.6
Occupational
Health
1 n!2 R4-ii 1 a
Deaths
(
.01
.01
^
U
U
U
Injuries t
t
i
1.01
1.01
u
u ,,.
n
n
•MH.^^H
4J
tn
s
III
>1
s
c
n
37.8
37.8
_E
-U
,-fl
"Fixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres )
1012 Btu's 1012 Btu,B
-------
TABLE 1-20
SUMMARY OF UNDERGROUND MINING RESIDUALS
Residual
Water (tons per
1012 Btu's)
Total dissolved
solids
Acidity
Suspended solids
Air
Solids (tons per
1012 Btu's)
Land
Incremental (acres
affected per
1012 Btu's)
Fixed (total acres
for mine life)
Uncontrolled Case
Central
341 ,
2.0b
.02
0
2
9.6d
0
Northern
Appalachia
438
68C
.03
0
1
10.3
to
22. 8e
0
Central
Appalachia
331
9.4
.03
0
1
10. 6f
0
Controlled Case
Central
14a
0
.21
0
64
9.6
7.8
Northern
Appalachia
39. 9a
0
.60
0
1,190
10.3
to
22.8
64.6
Central
Appalachia
16
0
.24
0
249
10.6
15.5
Source: Hittman, 1974: Vol. I, Tables 3-12 and footnotes.
Hardness at 2,000 parts per million (ppm), Al = 1 ppm, Mn = 4 ppm, Fe = 4 ppm,
alkalinity = 60 ppm.
142 ppm.
cl,714 ppm.
^b.8-foot seam thickness and 57-percent recovery efficiency.
eHigher value is for longwall mining.
f4.7-foot seam thickness and 57-percent recovery efficiency.
1.6.3.2.3 Solids
In underground mines, the amount of
solids produced by sinking the initial shaft
is not large (about 3,000 tons). However,
as indicated in Table 1-20, the solids pro-
duced when mine water is treated amount to
56,000 tons per year for a typical mine in
Northern Appalachia (1,190 tons per 10
Btu's), 21,200 tons per year in Central
12
Appalachia (249 tons per 10 Btu's), and
449 tons per year in the Central area (64
tons per 1012 Btu's) (Hittman. 1974: Vol. I,
footnotes 1350, 1461, 1550). These data
have an error of 50 percent or less.
1.6.3.2.4 Land
Land impacts include subsidence and
refuse storage sites, as well as a site for
a water treatment facility under controlled
conditions.
Greater subsidence results from the
longwall method than from the room and pil-
lar method because the roof is allowed to
collapse as mining progresses (Table 1-20).
Data for both mining types assume sub-
sidence from single seams and are accurate
to within 50 percent. The combined effects
of mining multiple seams are not considered.
1-55
-------
For room and pillar mining, an average of
25 percent of the undermined acreage sub-
sides, and this subsiding area then affects
a larger surface area. Hittman calculates
that 10.3 acres are affected for every 1012
Btu' s of coal mined by room and pillar meth-
ods in Northern Appalachia (660 acres per
year for a typical mine) (Hittman, 1974j
Vol. I, footnotes, 1304, 1402, 1403, 1502).
The comparable land impact for longwall
mining is 23 acres. In Central Appalachia,
a total of 10.6 surface acres are affected
by the subsidence of two acres. In the
Central area, 9.6 surface acres are af-
12
fected for every 10 Btu's mined.
The decision to treat mine drainage
and runoff water converts water pollutants
to solid wastes which require disposal and
thus land for settling ponds and a treat-
ment facility.
In all pollutant categories summarized
in Table 1-20, underground mining in the
Central Region produces fewer environmental
residuals than in Appalachia.
1.6.4 Economic Considerations
1.6.4.1 Surface Mining and Reclamation
Surface mining cost estimates for each
mining method are presented in Table 1-21
and have a probable error of less than 50
percent. Estimated 1972 national average
costs range from $0.81 per ton for augering
to $2.73 per ton for contour mining with
reclamation (Table 1-21). For both area
and contour mining, operating costs are 70
percent of the total cost.
The variations in regional production
cost estimates (for hypothetical mines)
given in Table 1-22 are due primarily to
differences in overburden thickness and
characteristics and coal seam thickness
and slope. BuMines 1969 per ton operating
cost estimates range between $3.06 and
$4.15 for Eastern Province bituminous coal,
$2.85 and $5.27 for Interior Province
bituminous, $1.39 and $3.03 for Rocky
TABLE 1-21
SURFACE MINING COSTS*
(DATA FOR 1972)
Technique
Area strip
Contour
Auger
Total Cost
. (dollars per ton)
No
Reclamation
2.51
2.73
0.81
With
Reclamation
2.68
3.61b
0.88
Source: Hittman, 1974: Vol. I, Tables
3-12 and footnotes.
Estimated national averages for 1972.
bModified block cut.
Mountain and Northern Great Plains subbi-
tuminous coal, and $1.68 and $2.37 for
Northern Great Plains lignite. Within
provinces, these cost variations reflect
the size of the operation, as measured in
tons of production per year, and whether
single or multiple coal seams are being
mined. Larger scale operations require a
heavier initial capital outlay but permit
lower per-ton recovery costs. This indi-
cates that there are considerable economies
of scale in strip mining.
As an example of cost variation within
a province, note that the cost of mining
coal in Oklahoma is considerably higher
than in Kentucky. The overburden of the
Oklahoma Iron Post deposit, on which these
estimates are based, has been described as
hard and unyielding and, therefore, expen-
sive to remove. In addition, the coal seam
averages only about 16 inches thick. For
these reasons, the per-ton-of-resource cost
of overburden removal is high.
Another example is the cost differen-
tial between subbituminous mining in
Montana and in Wyoming. This difference
results primarily from varying license fees.
1-56
-------
TABLE 1-22
SURFACE COAL MINING PRODUCTION COSTS
(DATA FOR 1969)
Province
Eastern
(bituminous)
Interior-
(bituminous)
Rocky Mountain
and Northern
Great Plains
( subbituminous)
Northern Great
Plains (lignite)
Mine Type
and Location
Contour strip
Northern West Virginia
Strip mine
single seam
Western Kentucky
Strip mine
double seam
Western Kentucky
Strip mine
single seam
Oklahoma
Strip mine
Southwest
Strip mine
Powder River Basin
Montana
Strip mine
Powder River Basin
Wyoming
Strip mine
Dakota or Montana
Production
(106 tons
per year)
1
3
1
3
1
1
1
5
5
5
1
5
Estimated Capital
Investment
(millions of dollars)
12.7
28.0
13.7
24.9
8.3
16.0
7.9
28.7
13.9
13.9
6.4
20.7
Per Ton Operating
Cost Excluding
Return on Capital
(dollars)
4.15
3.06
3.90
2.85
2.98
5.27
3.03
2.40
1.39
1.58
2.37
1.68
Energy Cost
(cents per
million Btu's)
15.7
11.6
16.3
10.8
12.4
21.1
14.3
11.4
8.2
9.3
16.5
11.7
Source: BuMines, 1972: 3.
aEstimated 1969 costs for 12 hypothetical mines (reclamation costs included).
-------
taxes, wages, and payments to the United
Mine Workers' Welfare Fund.
Table 1-22 also indicates that per-Btu
costs are high for mining lignite, despite
generally low per-ton mining costs. This?
of course, is due to the relatively low Btu
content of lignite.
Everything considered, strip mining in
the Powder River Basin yields the most
Btu's of energy for the least amount of
money. Oklahoma coal is the most expensive.
A study by Continental Oil Company has
estimated that present costs of reclamation
run between $3,000 and $5,000 per acre for
eastern surface mines. This averages be-
tween $1.00 and $3.00 per ton. For western
coal, the per-acre reclamation cost esti-
mates range between $1,000 and $4,000 or
$0.02 to $0.20 per ton. The wide variance
on a per-ton basis results from large
variations in seam thickness.
1.6.4.2 Underground Mining and Reclamation
The hypothetical cost estimates listed
in Table 1-23, based on a room and pillar
mine with 57-percent recovery and a 20-year
expected mine life, have a probable error
of less than 100 percent. The estimated
1973 range of costs is from $6.45 to $7.60
per ton (1973 dollars). Economies of scale
are evident, and coal costs are higher for
thinner seams.
Hittman's estimate for a room and pil-
lar mine is $282,000 per 1012 Btu's or
$6.87 per ton (1972 dollars)(Hittman, 1974:
Vol. I, Table 1). This agrees with the
BuMines estimate. Both estimates include
the cost of rail transportation within the
mine.
According to Hittman, the water treat-
ment facility would add an additional
$20,200 per 1012 Btu's or $0.50 per ton
(Hittman, 1974: Vol. I, Table 2).
Economic data on longwall mining are
not available.
1.7 WITHIN AND NEAR MINE TRANSPORTATION
1.7.1 Technologies
1.7.1.1 Surface Mine Transportation
The major alternatives for transporting
coal within or near surface mines are
TABLE 1-23
1973 UNDERGROUND COAL MINING PRODUCTION COSTS*
Seam
Thickness
72-inch
coal seam
48- inch
coal seam
Mine Output
(million tons
per year)
1.06
2.04
3.18
4.99
1.03
2.06
3.09
Capital Investment
(tons per year
of mining output)
20.62
17.47
15.87
15.15
20.09
17.61
16.83
Total
Production Costs
(dollars per ton)
7.35
6.77
6.50
6.45
7.60
6.97
6.81
Sources: Katell and Hemingway, 1974a: 5; Katell and Hemingway, 1974b: 4.
Estimated 1973 costs for hypothetical mines.
1-58
-------
conveyors and diesel-engine trucks. The
major factors influencing the choice are
capacity, distance, ramp angles, mobility,
and maneuverability.
The trucks used in mines range from
multiple purpose conventional designs to
very large, special purpose, off-the-road
vehicles capable of carrying as much as
250 tons. The latter vehicles are used
extensively in surface mining but normally
only haul materials for short distances.
Trucks require haul roads with appro-
priate contours and drainage provisions.
Dust control can be provided through the
application of calcium chloride or sodium
chloride, although the most common proce-
dure is to keep the roads wet with water
trucks (Grim and Hill, 1974j 116).
Conveyor systems are efficient for
moving large quantities over short-to-
moderate distances. They require little
space, can negotiate tight turns, and move
materials up steeper slopes than a rail or
truck system can accommodate (Gartner,
1969: 21, 34). Some conveyors (not cur-
rently being used) are several miles long,
more than seven feet wide, and can attain
speeds of 17 feet per second or more.
1.7.1.2 Underground Mine Transportation
Most underground mines still use con-
veyors and rail shuttle cars (or some com-
bination of the two) to move coal to a
collection point within the mine. From
there, coal is normally moved to the sur-
face by rail or by a larger conveyor.
However, at least one eastern mine is now
using a slurry pipeline, linked to a con-
tinuous miner, for more rapid extraction
and continuous transportation to the sur-
face, since in-mine transportation has
generally not kept pace with excavation
machinery, this type of innovation is
needed.
1.7.2 Energy Efficiencies
Since data on actual coal losses during
transportation are not available, primary
efficiencies are assumed to be 100 percent.
As discussed previously, ancillary energy
requirements are the diesel fuel and elec-
tricity needed for vehicles and conveyors.
Table 1-24 gives these requirements, by
area, for truck transportation in surface
mines and for conveyors in underground
mines. These data are estimated to have
an error of 100 percent or less.
1.7.2.1 Surface Mine Transportation
Transporting coal by truck consumes
0.2 to O.SxlO9 Btu's for each 1012 Btu's
hauled. In Table 1-24, the lowest energy
expenditure rating for trucked coal is at
Hittman's hypothetical Northwest mine,
which has the shortest average haul dis-
tance. Conversely, the mine with the
longest average haul distance (Hittman's
Northern Appalachian) also has the highest
energy expenditure ratio. However, all
values are small, ranging from 0.02 to 0.08
percent of the energy being hauled; thus,
the data inaccuracies are not serious. No
data for conveyors used in surface mines
are available.
1.7.2.2 Underground Mine Transportation
Transporting coal by conveyors in
g
underground mines consumes about 0.2x10
12
Btu's for each 10 Btu's hauled (within a
factor of two) regardless of the region
(Table 1-24) . Apparently, haul distances
are approximately the same among regions.
This is a very small value (0.02 percent)
relative to the amount of energy being
hauled.
Energy consumption data for rail
transportation in underground mines are
not available.
Diesel engines are discussed in
Chapter 13.
1-59
-------
TABLE 1-24
ANCILLARY ENERGY REQUIREMENTS OF IN-MINE TRANSPORTATION SYSTEMS
Region
Northwest
Central
Northern Appalachia
Central Appalachia
Southwest
Trucking
(surface mines)
Average
Haul
Distance
Assumed
1.5
3.8
7.3
4.7
3.2
Diesel Oil
Gallons per
1012 Btu's
1,400
2.920
5,600
3,160
2,710
108 Btu's
per 1012
Btu's Hauled
1.94
4.05
7.02
4.38
3,76
Conveyors
(underground mines)
108 Btu's
per IQl2
Btu's Hauled
U
2.48
2.23
2.18
U
Kilowatt Hours
per 1012 Btu's
U
24,300
21,800
21,300
U
U = unknown.
Source: Hittman, 1974: Vol. I, Tables 3-12 and footnotes.
1.7.3 Environmental Considerations
1.7.3.1 Surface Mine Transportation
Environmental residuals for truck
transportation in surface mines are given
in Table 1-25 and can be presumed to have
an error of 50 percent or less. Controlled
and uncontrolled conditions are the same
except for suspended solids in runoff water.
Under controlled conditions, suspended
solids are collected in settling ponds
along the haul roads. Consequently, con-
trolled conditions increase land residuals.
About one acre of settling ponds per mile
of haul distance is required. Suspended
solids are assumed to be 35 tons per acre
per year in the Central and Northern
Appalachian examples and 78 tons per acre
per year in the Northwest.
Coal haul roads usually constitute
about 10 percent of the area of a mine
(Grim and Hill, 1974: 116). Haul distances
are longest in the Northern Appalachian
Region (7.3-mile average) and shortest in
the Northwest Region (1.5-mile average);
thus, land residuals for trucking are
highest in Northern Appalachia (Hittman,
1974: Vol. I). Values for particulates
12
range from 0.009 to 0.036 ton per 10
Btu's of coal hauled; for nitrogen oxides,
the range is 0.259 to 1.04 tons; and for
sulfur oxides, the range is 0.019 to 0.075
ton (Table 1-25). Half of these values
would be emitted on a daily basis for a
typical mining operation excavating about
20,000 tons of coal per day. Noise genera-
tion would be greatest from truck and rail
transport.
1.7.3.2 Underground Mine Transportation
According to Table 1-25, all residuals
are zero when conveyors or rail transporta-
tion is used. Thus, conveyors are assumed
to be covered or operated at speeds that do
not produce dust.
1.7.4 Economic Considerations
1.7.4.1 Surface Mine Transportation
Within and near-mine transportation
was included in the BuMines cost data dis-
cussed above in mining and reclamation.
1-60
-------
Table 1-25. Residuals for In-Mine Coal Transportation
SYSTEM
NORTHWEST COAL
Trucking
Uncontrolled
Controlled
CENTRAL COAL
Trucking
Uncontrolled
Controlled
Conveyor
Uncontrolled
Controlled
Mine Rail
Uncontrolled
Controlled
Water Pollutants (Tons/1012 Btu's)
Acids
NA
NA
MA
NA
NA
NA
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
NA
t
8
NA
NA
NA
NA
NA
NA
NA
NA
m
S
NA
NA
NA
NA
NA
NA
NA
NA
Total
Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
NA
Suspended
Solids
21.1
0
20.2
0
NA
NA
NA
NA
Organics
NA
NA
NA
NA
NA
NA
NA
NA
Q
S
NA
NA
HA'
NA
NA
NA
NA
NA
O
8
NA
NA
NA
NA
NA
NA
NA
NA
Thermal
(Btu's/10l2)
NA
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/10
Particulates
.009
.009
.019
.019
0
0
0
0
X
.259
.259
.54
.54
0
0
0
0
X
8
.019
.019
.039
.039
0
0
0
0
Hy d r oc a rbon s
.026
.026
.054
.054
0
0
0
0
12Btu
8
.175
.175
.365
.365
0
0
0
0
•a)
Aldehydes
.002
.002
.009
.009
0
0
0
0
Solids
(Tons/1012 Btu's)
NA
NA
NA
NA
NA
NA
NA
NA
V
10
H -
(0 3
0) 4J
> a
I
T3 0) CM
C fc -H
ra o o
J < "H
.274/0
.274
.303/0
.303
. 584/0
.584
.679/0
.679
0
0
0
0
Occupational
Health
1012 Btu's
Deaths
0
0
U
U
u
U
u
u
Injuries
.027
.027
U
U
u
u
u
u
4J
K
S
U]
>1
(0
Q
c
ID
S
.674
.674
U
U
U
U
U
U
-------
i — Table 1-25. (Continued)
SYSTEM
SOUTHWEST COAL
Trucking
Uncontrolled
Controlled
Water Pollutants (Tons/1012 Btu's)
en
•D
•H
U
NA
NA
0)
01
n
a
NA
NA
«t
s
NA
NA
aFixed Land Requirement (Acre - year) / I
1012 Btu's
B"
NA
NA
Total
G « Dissolved
Solids
0 ,-. Suspended
Solids
n
o
•H
C
10
E1
o
NA
J ™ unknown.
icremental Land Requirera
0
NA
NA
Q
8
NA
NA
tH
O
t-t
•H X
m n
NA
NA
ent ( Acres )
1012 Btu's
Air Pollutants (Tons/1012 Btu's)
3 3 Particulates
co m |
X
§
.5
.5
• in M.
8*
.03$
.036
•• i
tn
1
m
o
8
"D
as
.05
.05
8
.34
.34
0)
01
01
"D
f-4
.008
.008
Cf)
j5 § Solids
(Tons/1012 Btu1
V
(0
01
1
•D 01
10 U
.5:
c
-5t
in
3
4J
CN
iH
O
r— 1
/O
3
I/D
8
Occupational
Health
o o Deaths
H
c
2 3 injuries „
C
s
4J
in
O
(H
ra
Q
i
c
ro
.171
171
-------
BuMines also has separate 1969 cost esti-
mates for the trucks used to transport coal
in its hypothetical surface mines. A
vehicle capable of hauling 100 tons in a
northern West Virginia bituminous contour
mine would have an estimated capital cost
of $175,000. If this vehicle is operated
two shifts (16 hours) per day/ 240 days per
year, driver costs would be about $15,300
(1969 dollars) per truck per year. Esti-
mates for both equipment and operating
costs are out of date and would be much
higher now than when calculated by BuMines
{BuMines, 1972: 5, 7).
According to Hittman data, the 1972
estimate of truck transportation costs
within a surface mine is $6,850 for each
10 Btu's of coal hauled or $0.16 per ton
within an error of less than 50 percent
(Hittman, 1974: Vol. I, Table 1 and foot-
note 1046). Operating costs account for
96 percent of this amount.
1.7.4.2 Underground Mine Transportation
The BuMines 1973 estimate of the cost
of a shuttle car for within and near-mine
transportation in underground mines is
$49,000. In a 48-inch seam room and pillar
mine, 12 shuttle cars would be required to
produce 1.03 million tons per year. Total
operating costs for three shifts per day,
220 days per year are estimated to be almost
$290,000.
A comparable capacity conveyor system
would cost $1,471,200 or approximately $53
per foot. Additionally, the cost for con-
veyor operators would be almost $86,000 per
year (Katell and Hemingway, 1974b: 6-8).
Costs are approximately the same for
a 72-inch coal seam, Hittman estimates
1972 conveyor costs at $1,750 for each 10J
Btu's of coal hauled or $0.04 per ton, 78
percent of which are operating costs
(Hittman, 1974: Vol. I, Table 1 and foot-
note 1049). These estimates have a probable
error of less than 50 percent.
,12
1.8 BENEFICIATION
1.8.1 Technolog ies
Coal is often prepared, or beneficiated,
before being used. Beneficiation, which
may be done at (or near) the mine or at the
point of use, consists of any or all of the
following steps:
1. Crushing and screening to a desired
maximum size.
2. Cleaning to remove dust and noncoal
materials.
3. Drying to prepare the coal for
shipping or use.
Large rotary mills are used to reduce
the coal to a desired maximum size which is
dictated by intended usage. The sized coal
is then cleaned using either air or water.
Air washing—blowing air over the
coal—is the simplest cleaning technique
for removing small particles. In wet wash-
ing, the coal is floated on a water/magne-
tite (pulverized iron ore), slurry and im-
purities are allowed to sink. An alterna-
tive method is to entrain the coal in an
upward flow of water. Both wet washing
methods are avoided wherever possible be-
cause they add moisture to the coal, thereby
reducing its available energy.
A third wet washing technique is froth
flotation. In this process, chemicals are
added to cause the coal to repel water and
attach to air bubbles. The coal is then
skimmed off the top as a froth. Impurities
do not attach to the bubbles and are allowed
to sink. Slurries containing the impurities
recovered by all three types of wet washing
techniques are usually retained in settling
ponds.
Coal is normally dried by hot air
streams. Several different configurations
are used, including fluidized beds and
A fluidized bed is a body of finely
crushed particles with a gas blown up
through them. The gas separates the par-
ticles so that the mixture behaves like a
turbulent liquid.
-------
TABLE 1-26
COAL BENEFICIATION EFFICIENCIES
Technique
Breaking and sizing
Primary efficiency (percent)
Q
Ancillary energy (10 Btu's
per 1QJ-2 Btu's input)
Washing
Primary efficiency (percent)
Q
Ancillary energy (10 Btu's
per 1QJ-2 Btu's input)
Uncontrol led
Controlled
Northwest
100
2.19
U
U
U
Central
100
1.81
97.3
2.42
2.55
Northern
Appalachia
100
1.72
96.4
2.17
2.29
Central
Appalachia
100
1.68
U
U
U
Southwest
100
2.07
U
U
U
U = unknown.
Source: Hittman, 1974: Vol. I, Tables 3-12 and footnotes.
rotary kilns. One drying technique uses
oxygen instead of air to promote the oxida-
tion of any sulfur in the coal. According
to Kennecott, this system removes all inor-
ganic sulfur and up to 30 percent of the
organic sulfur. This method of removing
sulfur is reported to be competitive with
stack gas cleaning technologies achieving
comparable clean-up (Soo, 1972: 187).
1.8.2 Energy Efficiencies
Table 1-26 summarizes efficiencies
and ancillary energy requirements for
breaking and sizing, and washing coal.
Since the amount of feed removed as tramp
iron is miniscule (0.006 percent), breaking
and sizing is considered 100-percent effi-
cient. Ancillary energy requirements have
been estimated, within a factor of two, to
average 2.0xl09 Btu's for each 1012 Btu's
processed, 80 to 85 percent of which is
*A rotary kiln is a heated rotating
horizontal cylinder.
provided by electricity and the remainder
by oil.
Washing is 96- to 97-percent efficient,
depending on the percentage of the feet that
requires washing (56 percent in the Central
area and 72 percent in Northern Appalachia) .
The ancillary energy requirement, within a
factor of two, is estimated to be 0.22 per-
cent of the processed energy (2.2 to
2.4x10 Btu's for each 10 Btu's pro-
cessed) . This requirement is slightly
greater under controlled conditions, 0.25
percent. Electricity provides 80 percent
of the total ancillary energy requirement.
For both processes, regional differ-
ences are small and are due to variability
in heat content of coals. Central
Appalachian coal has the highest heat con-
tent and, therefore, requires the lowest
ancillary energy on a per-Btu basis.
1.8.3 Environmental Considerations
Table 1-27 includes all Hittman data
by areas for breaking and sizing, and
1-64
-------
Table 1-27. Residuals for Coal Beneficiation
SYSTEM
Uncontrolled
Controlled
Northern Appalachia
Uncontrolled
Controlled
Central Appalachia
Uncontrolled
Controlled
Uncontrolled
Controlled
Water Pollutants (Tons/1012 Btu's)
CO
T3
•H
U
0
0
NA
MA
NA
NA
NA
NA
NA
Bases
0
0
NA
NA
NA
NA
NA
NA
NA
<*
R
0
0
NA
NA
NA
NA
NA
NA
NA
NA
ro
g
0
0
NA
NA
NA
NA
NA
NA
NA
NA
Total
Dissolved
Solids
0
0
0
0
0
0
0
0
0
0
Suspended
Solids
0
0
0
0
0
0
0
0
0
0
Organics
0
0
NA
NA
NA
NA
NA
NA
NA
NA
a
s
NA
•NA
NA
NA
NA
NA
NA
NA
NA
NA
O
8
0
0
0
b
0
0
0
0
0
0
Therma 1
(Btu's/K>12)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
0
0
0
0
0
0
0
0
0
0
X
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
X
O
tfi
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Hydrocarbons
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
8
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Aldehydes
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
01
Solids
(Tons/1012 Btu
3.42
3.42
2.83
2.83
2.54
2.54
2.46
2.46
3.06
3.06
V
Land
Acre-year
3
-P
m
1
m
n
i
a
(0
E
.148
.148
U
U
U
U
U
U
0
0
-------
Table 1-27. (Continued)
SYSTEM
CLEANlttfJ INCLUDING
WASHING"
Uncontrolled
Controlled
CLEANING INCLUDING
WASHING0 _ _.
Uncontrolled
Water Pollutants (Tons/1012 Btu's)
Acids
4,4
0
70.7
Bases
NC
NC
NC
,
ra
Q
I
c
10
22.9
22.9
NC
NA - not applicable, NC - not considered, U - unknown.
"Fixed Land Requirement (Acre - year) / Incremental Land Requirement (
Acres
1012 Btu's
1012 Btu's
Battelle, 1973: Vol.
cTeknekron, 1973.
I.
-------
washing. Coals from the Northwest, South-
west, and Central Appalachian areas are
assumed to be relatively clean, thus re-
quiring only breaking and sizing. Central
and Northern Appalachian coals require
washing as well as breaking and sizing.
1.8.3.1 Breaking and Sizing
As stated earlier, residuals from
breaking and sizing are negligible. Al-
though small quantities of water are used
for dust control, potential environmental
impact from this source is also negligible.
Thirty-five acres of land are required
for the preparation plant and loading
facility.
1.8.3.2 Washing
Washing coal creates more residuals
than breaking and sizing, thus has more
serious environmental impacts.
1.8.3.2.1 Water
Battelle estimates that washing re-
quires an estimated 1,500 to 2,000 gallons
of water per ton of coal processed;
Teknekron estimates only 524 gallons, 18
of which are consumed in the process.
According to Hittman, refuse pile run-
off is a problem. This water (which con-
tains acids, sulfates, iron, and manganese)
seeps from refuse piles at a rate of 1,670
gallons per acre per day; acidity concen-
tration is as high as 11,000 ppm. The
refuse pile runoff also contains suspended
solids as does the water used to wash the
crushed coal. These data are considered
to be accurate to within 10 percent.
Under controlled conditions, water
pollutants can be reduced to zero because
seepage from the refuse pile is eliminated
by land reclamation and settling ponds re-
tain suspended solids and other pollutants.
1.8.3.2.2 Air
Air pollutants emanate in small quan-
tities from smoldering refuse piles. These
can be controlled by covering the pile with
soil and revegetating the area during land
reclamation. Thermal and air drying are a
major source of airborne particulates
according to Battelle (1973: 75) and aver-
age 20 to 25 pounds per ton of coal washed
in uncontrolled situations.
1.8.3.2.3 Solids
Solids generated during washing amount
to about 4,000 tons for every 10 Btu's
of coal processed with an error of less
than 100 percent. For a typical washing
plant processing 500 tons of coal per hour,
about 1,000 tons of refuse must be disposed
*
of daily. Thi^ is roughly equal to the
weight of refuse generated daily by a city
of 400,000 people.
1.8.3.2.4 Land
Under controlled conditions, and to
within 50-percent error, five acres are
required for the washing plant, 40 acres
for the loading facility, and 50 acres for
the settling pond. However, Teknekron
(1973: 67) estimates that a coal cleaning
facility may require 200 to 400 acres, in-
cluding mine equipment storage and settling
ponds.
1.8.4 Economic Considerations
The total estimated 1972 cost for
breaking and sizing is $2,250 per 10
Btu's processed. Of this total, operating
costs make up 87 percent and fixed costs
are 13 percent. This total converts to
$0.002 per million Btu's or $0.055 per ton.
Total estimated 1972 cost for washing
is $11,900 per 1012 Btu's processed. Of
this amount, operating costs account for
76 percent and fixed costs are 24 percent.
Washing costs, therefore, are $0.012 per
million Btu's or $0.31 per ton of coal
In some circumstances, up to 40 per-
cent of the mined material may be dumped
as solid waste.
1-67
-------
output assuming an energy content of 26x106
Btu's per ton (Hittman, 1974: Vol. I).
Battelle's (1973: 330) total beneficiation
cost estimate of $0.066 per million Btu>s
is in close agreement with Hittman.
1.9 PROCESSING
1.9.1 Technologies
Once coal has been mined it can be
used raw, processed to improve its quali-
ties as a solid fuel, or converted into
either gas or oil. The technologies for
producing gaseous, liquid, and improved
solid fuels from coal are described in this
section. Information on some of these
•
technologies is limited because they are
either at an early stage of development or,
in some cases, are proprietary.
1.9.1.1 Gaseous Fuels
Gaseous fuels with low, intermediate,
or high energy content can be produced from
*
coal. Low and intermediate gases are
produced in a two-stage process involving
preparation and gasification; a third
stage, upgrading, is required if high-Btu
gas is to be produced. These three stages,
illustrated in Figure 1-26, are described
below. Following the generalized descrip-
tion, specific gasification processes are
identified and described.
1.9.1.1.1 Preparation
All gasification processes require
some preparation of the coal feedstock.
In addition to handling and storage, a
particular gasification process may require
further reduction of the coal particle
size. Also, depending on coal type and
kind of gasifier, the coal may require
additional pretreatment—most commonly to
No fixed energy values are associated
with these gases; however, 100 to 200 Btu's
per cubic foot (cf) is generally considered
low, 300 to 650 Btu's intermediate, and 900
to 1,050 Btu's high.
prevent the coal from agglomerating into
a plastic mass at the bottom of the gasi-
fier.
1.9.1.1.2 Gasification
The three primary ingredients needed
to chemically synthesize gas from coal are
carbon, hydrogen, and oxygen. Coal pro-
vides the carbon; steam is the most com-
monly 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 (CH4) and
hydrogen (H_) . Methane, the primary com-
ponent of natural gas, is similar to natural
gas in heating value. Carbon monoxide and
hydrogen heating values are approximately
equal, being about 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 gasifica-
tion processes is to produce a high quality
gas during the initial gasification stage.
The product from each process is determined
primarily by the methods used to introduce
hydrogen, oxygen, and heat into the gasi-
fier. Each method involves trade-offs.
For example, if air is used to provide the
oxygen, nitrogen is produced as an unde-
sirable by-product and the heating value
of the gas is reduced. Although pure
oxygen is more expensive than air, it
eliminates the nitrogen problem and pro-
duces intermediate- rather than low-Btu
gas.
The use of steam to introduce hydrogen
into the process produces primarily carbon
monoxide and hydrogen, while the direct
1-68
-------
Coal
COAL PREPARATION
-Handling and Storage
-Size Reduction
-Pretreatment
Pipeline Gas
900-1000 Btu
GASIFICATION
Raw Low or
Intermediate Gas
H20—
Air or
t
i— ^
RAW GAS UPGRADING
-Shift: CO + H20
C02+H2
-Remove Acid Gas (C02 + HgS)
-Methanate'- CO + 3H2 —*-CH4
Figure 1-26. General Process Scheme for Producing Gas from Coal
Source: Adapted from Gouse and Rubin, 1973:IV-3.
-------
introduction of hydrogen produces methane
and carbon. Since reacting hydrogen
directly with coal also produces heat (an
exothermic reaction) , hydrogen would seem
preferable to steam, but the amount of
methane produced is usually quite small
(a large amount of the carbon is left in
the gasifier as char) . As a consequence,
this devolatilization reaction (coal +
H2 ^ CH^ + C + heat) is normally placed
in a pretreatment stage rather than in the
stage where most of the gasification
occurs, which also conserves hydrogen.
The other method of introducing hydrogen,
the steam-carbon reaction (heat + C +
H2 > CO + H_) is used more frequently,
both to produce final-product low and
intermediate gases and to produce feed-
stocks for high-Btu gasification.
For coal gasification processes, direct
heat is more thermally efficient than in-
direct heat. However, most direct heat
processes use either air or oxygen as an
oxidizer, producing the products and prob-
lems identified above. One alternative
direct heating method feeds lime (CaO) into
the gasifier where its exothermic reaction
with carbon dioxide produces heat. The
gaseous products are carbon monoxide and
hydrogen, and the carbon dioxide is removed
by the lime. Indirect heating using molten
salts, dolomite solids, molten slag, peb-
bles, etc. 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 temperature
and pressure, reactor vessels can be di-
vided into three general categories: gasi-
fier, hydrogasifier, and devolatilizer
(Figure 1-27). Gasification systems employ
one or more of these reactor types.
As shown in Figure 1—27, the gasifier
reactor produces some-gas through the
steam-carbon reaction (heat + C + H20 >
CO + H_) and some through the water-gas
shift reaction (CO + H20 > CO2 + H2 +
heat). The major differences in gasifier
reactor systems are in the method (direct
or indirect) of providing heat.
In the hydrogasifier reactor, methane
is produced by reacting hydrogen with coal
or char under pressure (C + 2H2 ^ CH^ +
heat) . Although systems of this type
differ in the method of supplying hydrogen,
all hydrogasif iers produce up to twice as
much methane as gasifiers or devolatilizers
of comparable capacity.
The devolatilizer reactor decomposes
large coal compounds. In this system,
hydrogen reacts with the coal to produce
methane and heat (coal + H2 > CH4 + C +
heat).
Gasification systems can also be cate-
gorized on the basis of engineering fea-
tures, two significant ones being whether
the system is pressurized and the type of
bed used. Gasification systems may be
operated either at high pressure or at
atmospheric pressure. The main advantages
gained from pressurizing are improving the
quality of product gas, maximization of
the hydrogasification reaction, reduction
of equipment size, and elimination of the
need to separately pressurize gas before
introducing it into a pipeline (Interagency
Synthetic Fuels Task Force, 1974: 22).
In terms of beds, there are three
basic types of gasification systems: fixed-
bed, fluidized-bed, and entrainment (Corey,
1974: 44). In the fixed-bed system, a
grate supports lumps of coal through which
the steam or hydrogen is passed. Conven-
tional fixed-bed systems are incompatible
with caking coals (coals which, when heated,
pass through a plastic stage and cake or
1-70
-------
GASIFIER REACTOR
HtiGl ~ *
Heat + C+H20— >-CO+ H2
CO + H20-»C02 + H2 + Heat
Coal
Steam and H2
Rich Gas
Heat
HYDROGASIFIER
C+2H2
Intermediate
"Btu Gas
Hydrogen-
Coal
Heat-
DEVOLATILIZATION
REACTOR
CH4+C+Heat
Intermediate
*Btu Gas
Figure 1-27. Principal Coal Gasification Reactions
and Reactor Types
-------
agglomerate into a mass) . To expand the
range of coals that can be used, some fixed-
bed systems are modified to incorporate a f
rotating grate or stirrer to prevent caking.
The fluidized-bed system uses finely
sized coal. Gas is flowed through the
coal, producing a lifting and "boiling"
effect. The result is an expanded bed with
more coal surface area to promote the chemi-
cal reactions. Fluidized-bed systems also
have a limited capacity for operating with
caking coals; consequently, these types of
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 sys-
tem, the coal particles are transported in
the gas (for example, steam and oxygen)
prior to introduction into the reactor.
The chemical reactions occur, and the prod-
uct gases and ash are taken out separately.
There are no limitations on the types of
coal that can be used with the entrainment
system.
1.9.1.1.3 Upgrading
Three steps are involved in upgrading
raw gases produced during the gasification
stage just described: shift conversion,
purification, and methanation. Shift con-
version combines carbon monoxide and water
to produce carbon dioxide and hydrogen
(CO + H20 * CO2 + H2 + heat) . This
shift is necessary to adjust the hydrogen
and carbon monoxide to the 3:1 ratio re-
quired for methanation. A catalyst, usu-
ally an iron-chromium oxide compound, is
used in this reaction.
After shift conversion, the gas is
purified to less than 1.5-percent carbon
dioxide by volume and less than one ppm of
hydrogen sulfide. Methanation follows,
reacting carbon with hydrogen to produce
CH4 + heat).
Nickel
methane (C + 2H2 —
compounds are the most frequently used
catalysts for this reaction. The basic
upgrading process is fairly standardized,
and the major choices involve engineering
details rather than alternative processes.
1.9.1.1.4 Specific Low-Btu Gasification
Processes
The major characteristics of four pro-
cesses designed to produce either low- or
intermediate-Btu gas from coal are sumraar-
rized in Table 1-28. Two of these, Lurgi
and Koppers-Totzek, are used commercially
at present; the others are in the pilot
plant stage. A large number of other pro-
cesses (with, for example, different com-
binations of bed types, pressure levels,
and oxygen sources) have been proposed or
are in early stages of development. The
four technologies described below illus-
trate the current state of the art.
1.9.1.1.4.1 Lurgi
There is no pretreatment in the Lurgi
process and only noncaking coals can be
used._ As shown in Figure 1-28, pulverized
coal is introduced into a pressurized
reactor vessel through a lock hopper. The
coal passes downward and is distributed
onto a rotating grate. Steam and oxygen
are introduced below the grate. All the
coal is combusted, leaving only ash which
is allowed to fall through the grate.
Product gas from the combustion zone above
the grate leaves the reactor at 800 to
1,000 °F. To produce 250 billion Btu's
per day, 27 to 33 gasifiers of 13-foot
inside diameter would be required. Mate-
rials balance for the Lurgi process is
shown in Table 1-29.
1.9.1.1.4.2 Koppers-Totzek
In the Koppers-Totzek process, finely
ground coal is mixed with oxygen and steam,
then pumped into an atmospheric-pressure
vessel (Figure 1-29). Because of the low
pressures used and the entrained flow of
the materials injected, a complex and
troublesome system of hoppers is avoided.
1-72
-------
TABLE 1-28
SELECTED DESIGN FEATURES OP FOUR
LOW- AND INTERMEDIATE-BTU GASIFICATION PROCESSES
Name
Lurgi
Koppers-Totzek
b
BuMines
Westinghouse
Ash agglomerating
Reactor
Type
Gasifier
Gasifier
Gasifier
Gasifier
Gasifier
Bed Type
Modified
fixed
Extrained
suspension
Modified
fixed
Fluidized
Fluidized
Pressure
300-450
pounds per
square inch
Atmospheric
Atmospheric
to 300
pounds per
square inch
200-300
pounds per
square inch
Pressurized
Hydrogen
Sources
Steam
Steam
Steam
Steam
Steam
Oxygen
Sources
Air/
oxygen
Oxygen
Air
Air
Air
Heat
Direct
burning
Direct
burning
Direct
burning
Direct and
internal
exothermic
reactions in
desulfurizer
Direct
burning
Pretreatment
Sizing
Pulverizing
Pulverizing
Pulverizing
drying,
integrated
devolatiles/
desulfurizers
Pulverizing
Coal Input
Noncaking
1/4x2 inch,
no fines
Caking or
noncaking/a
pulverized
Caking or
noncaking,
coarse or
fine
Caking or
noncaking,
pulverized
Caking or
noncaking,
pulverized
aPulverized means crushed so that 70 to 80 percent of the coal passes a 200-mesh screen (0.003 inch).
bThe BuMines process listed here is often identified as two processes. The only difference between the two is
that one is pressurized.
i
-j
U)
-------
Coal
Preparation
Steam
•o
Oxygen
Purification
Ash
Figure 1-28. Lurgi Low-Btu Coal Gasification Process
Source: Adapted from Bodle and Vyas, 1973: 53.
-------
Coal
Preparation
Steam
and
Oxygen
Quench,
Heat Recovery,
and Scrubbing
Approx. 2750° F
Atm. Pressure
Gasifier
T
Ash
Figure 1-29. Koppers-Totzek Coal Gasification Process
Source: Adapted from Bodle and Vyas, 1973: 68.
-------
TABLE 1-29
MATERIALS BALANCE FOR LURGI PROCESS
Input
Coala
Water
Quantity
10,770 tpdb
U
f
Output
Intermediate-Btu gas
Solid waste
Sulfur dioxide
Quantity
250xl09 Btu's per day
865 tpd
0.83 tpd
U = unknown.
Source: Hittman, 1975: Vol. II, p. 111-29.
using Northwest coal of 8,780 Btu's per pound, 6.77-percent ash, and
0.85-percent sulfur.
b
tons per day.
ccontrolled emission.
TABLE 1-30
MATERIALS BALANCE FOR KOPPERS-TOTZEK PROCESS
Input
Coalb
Water
Quantity
10,570 tpdc
463,000 gpdd
Output
Intermediate-Btu gas
Solid waste
Sulfur dioxide6
Quantity
250xl09 Btu's per day
865 tpd
4.4 tpd
Source: Hittman, 1974: Vol. II, p. Ill-34.
^ased on a facility with a 250-billion-Btu output per day.
Using Northwest coal of 8,780 Btu's per pound, 6.77 percent ash, and
0.85 percent sulfur.
ctons per day.
gallons per day
econtrolled emission.
Two or four injection or burner heads may
be used. Combustion occurs at high tempera-
tures (about 3,000 °F) in the center of the
reactor vessel, and the product gas exits
upwards through a central verticle outlet.
Molten slag exits at the bottom. A typical
large gasifier is about 10 feet in diameter
and 25 feet long.
A Koppers-Totzek reactor will produce
about twice the gas of a Lurgi reactor be-
cause of its higher throughput capabilities
(NAE/NRC, 1973: 34). Materials balance for
the Koppers-Totzek process is indicated in
Table 1-30.
1-76
-------
TABLE 1-31
MATERIALS BALANCE FOR BUREAU OF MINES STIRRED FIXED BED PROCESS
Input
Coal
Steam
Air
Water
Quantity
10,000 tpda
5.224 tpd
37,533 tpd
12.3 mmgpd
Output
Intermediate-Btu gas
Tar
Ammonium sulf ate
Solid wastes
Gaseous wastes
Quantity
48,732 tpd
353 tpd
696 tpd
1,104 tpd
1,336 tpd
Source: Interagency Synthetic Fuels Task Force, 1974: 49.
atons per day.
millions of gallons per day.
1.9.1.1.4.3 Bureau of Mines Stirred Fixed
Bed
In the BuMines process, pulverized
coal is fed into the top of the reactor
from a lock hopper and falls downward onto
a rotating grate similar to that used in
the Lurgi process (Figure 1-30). However,
a stirrer is mounted in the center of the
reactor, and a variable speed drive both
rotates the stirrer and moves it vertically.
This prevents clogging and allows caking
coals to be used. Steam and air are in-
jected from below the grate.
The dimensions of a commercial-sized
reactor have not been determined. The
plant has been operated at pressures
ranging from atmospheric to 300 pounds per
square inch (psi). A materials balance
prepared by the Interagency Task Force is
listed in Table 1-31.
1.9.1.1.4.4 Westinghouse Fluidized-Bed
Gasifier
Two pressurized, fluidized-bed ves-
sels are used in the Westinghouse system,
one as the gasifier and the other as a
devolatilizer/desulfurizer. Air, steam,
and char are reacted in the gasifier to
produce a hot gas which is then introduced
into the devolatilizer/desulfurizer with
crushed coal and dolomite (lime) (Figure
1-31). Hot gases from the gasifier supply
the heat for devolatilization and the char
produced by devolatilization is used as
the feedstock for the gasifier. Sulfur is
removed by the dolomite. Materials balance
is indicated in Table 1-32.
1.9.1.1.4.5 Ash Agglomerating Fluidized-
Bed Gasifier
In this process, pulverized coal is
introduced into a pressure vessel and is
partially burned at high temperature while
suspended by an upward flow of air and
steam. The ash slowly agglomerates in the
reactor and falls to the bottom where it
is removed (Figure 1-32). Fine particulates
in the produced gas are removed by a cy-
clone scrubber. The gas is then cooled to
about 1,400°F and passed through a filter
where dolomite reacts with any hydrogen
sulfide to form a sulfurized solid. The
dolomite filter is periodically regenerated
by treating it with hot carbon dioxide to
drive off the sulphur. The hot, cleaned,
pressurized gas (which has a heating value
of about 160 Btu's per cf) is then fed to
a combined cycle electric power plant.
1-77
-------
Coal *| Preparation
IHopperJ
l
Steam.
Gasifier
Air-
1
Ash
Raw Gas
0.5 PSIG
I300°F
I300°F .^Low Btu Gas
1.0 Atmosphere
Absorber
NH, Water Steam
Ammonium Sulfate
Plant
Stack Gas
Sludge
Figure 1-30. Bureau of Mines Stirred Fixed Bed
Coal Gasification Process
Source: Interagency Synthetic Fuels Task Force, 1974.
-------
Dolomite
•\
Hopper
Dolomite
Cool
\
Hopper
Particulate
Removal
System
Devolatilizer
Desulfurizer
Dryer
.Low Btu Gas
Hot Fuel
Gas
Course
Char
Spent
Dolomite>
Hot Gas
Combustor
Gasifier
Air
Steam
Fine Char
Ash
Figure 1-31. Westinghouse Fluidized Bed Coal Gasification Process
Source: Adapted from Archer and others, 1974: 5.
-------
Coal
Air
Gasifier
Steam
Ash
Cyclone
Fines
Air
C02& Steam
v v
Desulfurizer
Power
Gas
H,S
Sulfur
Conversion
S02
s
Figure 1-32. Ash Agglomerating Fluidized Bed Coal Gasification Process
-------
TABLE 1-32
MATERIALS BALANCE FOR WESTINGHOUSE FLUIDIZED BED PROCESS
Input
Coala
Water
Dolomite
Quantity
8,754 tpdb
U
4,000 tpd
Output
Low-Btu gas
Solid waste0
Spent dolomite
Quantity
215xl09 Btu's
1,201 tpd
4,000 tpd
U = unknown
Source: Archer and others, 1974: Figure 2.
aAssumes 95-percent conversion efficiency and coal of 12,927 Btu's
per pound.
tons per day.
solid waste as ash.
HBased on approximately 2:1 coal-to-dolomite ratio when fed with
three-percent sulfur coal.
TABLE 1-33
MATERIALS BALANCE FOR AN ASH AGGLOMERATING FLUIDIZED BED PROCESS
Input
Coala
Water
(steam)
Dolomite
co2
Quantity
9.972 tpdb
633 tpd
21 tpd
498 tpd
Output
Low-Btu gas
Sulfur
Sulfur dioxide
Particulates
Quantity
(S.OlxlO11 cubic feet)
(215xl09 Btu's)
298 tpd
4.31 tpd
13.4 tpd
Source: Teknekron, 1973: Figure 7.1.
aCoal contains 11,770 Btu's per pound.
"tons per day.
The system, now in prototype develop-
ment, has a high throughput for a particu-
lar reactor vessel size and relies on the
agglomerating characteristics of coal to
remove ash. Materials balance is indicated
in Table 1-33. Daily inputs and outputs
are based on a plant capable of producing
250 million cf of high-Btu gas each day.
1.9.1.1.5 Specific High-Btu Gasification
The major characteristics of five
high-Btu gasification systems are identified
in Table 1-34. All five systems are still
in the developmental stage. The Lurgi gasi-
fication process has been proven, but the
final upgrading and methanation steps have
not been used commercially.
1-81
-------
GO
10
TABLE 1-34
SELECTED DESIGN FEATURES OF FIVE HIGH-BTU GASIFICATION PROCESSES
Name
Lurgi
HYGAS
BI-GAS
Synthane
CO_ Acceptor
/
Reactor
Type
Gasifier
Hydrogasifier
Gasifier and
Hydrogasifier
Gasifier
devolatilizer
Gasifier
devolatilizer
Bed Type
Modified
Fixed
Fluidized
Entrained
Flow
Fluidized
Fluidized
Pressure
(pounds per
square inch)
300-500
1,000
1,000
1,000
150
Hydrogen
Sources
Steam
Hydrogen3
Steam
Steam
Steam
Oxygen
Sources
Oxygen
Plant
Oxygen
Plant
Oxygen
Plant
Oxygen
Plant
Air
Heat
Direct
Direct
Direct
Direct
Direct and
Indirect
Pretreatment
Sizing
Sizing,
heating
and slurry
None
Sizing and
heat and
volatilize
Sizing
Coal Input
Noncaking,
1/4x2 inch.
no fines
8 to 100
mesh fines
all coals
"•"V
Liquid to
rank A
bituminous
pulverized
All coals
fines of
200 mesh
Lignite or
subbituminous ,
1/8 inch
aHydrogen introduced into the gasifier is produced by reaction of steam, char, and oxygen.
-------
TABLE 1-35
INPUTS AND BY-PRODUCTS FOR A LURGI GASIFICATION PLANT2
Input
Coalb
Water
Nickel
Quantity
23,600 tpdc
18 mmgpdd
1,000 pounds
per 4 months
Output
Solid waste
Air emission
Ammonia
Sulfur
Tar
Naptha
Quantity
1 , 548 tpd
37.3 tpd
112 tpd
116 tpd
g
41x10 Btu's
per day
63,000 gpd
Source: Hittman, 1975: Vol. II.
250-mmcf-per-day production using Northwest coal of 8.780
Btu's per pound, 6.77-percent ash, and 0.85-percent sulfur.
Assumes 413x10 Btu's input per 250-mmcf output.
tons per day.
millions of gallons per day.
Most high-Btu gasification processes
include pretreatment, gasification, clean-
up, shift conversion, purification, and
methanation steps. Differences between
systems are greatest in the gasification
step. These differences will be highlighted
in the following descriptions for the five
processes listed in Table 1-34.
1.9.1.1.5.1 Lurgi High-Btu Gasification
The initial gasification step used in
Lurgi is essentially the same for both low-
and high-Btu gasification. Synthesis gas
from the gasifier shown in Figure 1-33 has
a Btu value of approximately 285 Btu per cf.
The upgrading process is the same as the
general process described earlier, including
clean-up, shift conversion, purification,
and methanation (Corey, 1974: 51). Pilot
plant configurations of these steps have
been tested in Scotland and South Africa,
but data concerning both plants are pro-
prietary.
Each gasifier reactor is capable of
producing about 10 million cubic feet
(mmcf) of synthetic natural gas per day.
The inputs and outputs of a 250-mmcf-per-
day Lurgi gasification plant are summarized
in Table 1-35.
1.9.1.1.5.2 HYGAS
In the HYGAS process, pulverized coal
of a nominal -8/+100 mesh size is slurried
with hot aromatic by-product oil and pumped
into the gasification reactor. This reactor,
which operates at 1,000 psi, has been heated
and supplied with a hydrogen-rich gas from
a separate char-gasifier vessel (Figure
1-34). As the coal slurry enters the re-
actor, light oils and gases vaporize up-
ward and the coal falls down into a fluidized
bed. Total coal residence time in the gasi-
fication reactor is about 30 minutes. The
devolatilized coal goes from the gasification
reactor into the char gasifier where hydro-
gen-rich hot gases are produced from the
1-83
-------
Coal
Preparation
Steam
Oxygen
C02+H2S
Gasifier
Raw Gas
Quench
Ash
Figure 1-33. Lurgi High-Btu Coal Gasification Process
Source: Adapted from Bodle and Vyas, 1973: 53.
-------
Light Oil
Hot Air
and
Steam
Coal
I
Coal
Preparation
Slurry
Steam
Oxygen
Raw Gas
Purification
Shift
Conversion
Meth a nation
Light Oil
Vaporizer
Low Temp.
Reactor
High Temp.
Reactor
otion
—
H2-rich g
as
-^
\H^
Gasifier
Char
Ash
Figure 1-34. HYGAS Coal Gasification Process
Source: Adapted from Bodle and Vyas, 1973: 64,
-------
TABLE 1-36
INPUTS AND OUTPUTS FOR A HYGAS PLANT
a
Input
Coal
Water
Nickel
Quantity
24,200 tpdb
19 mmgpd0
1,000 pounds
per 4 months
Outgat
Solid waste
Air emissions
Ammonia
Sulfur
Tar
Light oils
Quantity
1,577 tpd
35 tpd
124 tpd
103 tpd
2.3xl010 Btu's
per day
46,000 gpd
Source: Hittman, 1975: Vol. II.
a250-mmcf-per-day production using Northwest coal of 8,780
Btu's per pound, 6.77-percent ash, and 0.85-percent sulfur.
tons per day.
millions of gallons per day.
reaction of char, steam, and oxygen
(Hittman, 1975: Vol. II, p. IV-5). The
HYGAS process differs from other processes
primarily in its use of slurry feed and a
hydrogen-rich gasifier atmosphere.
After leaving the gasification reactor,
the raw gas is cooled, the aromatic oil is
recycled, and other tars and oils are re-
moved as by-products. The gas is then pro-
cessed by water-gas shift conversion, puri-
fication, and methanation.
The HYGAS process is one of the most
complex gasification systems being devel-
oped, having separate circulation systems
for coal, char, and by-product oil. Its
advantages include the use of pumped
slurries instead of lock hoppers and the
efficiencies gained by using a hydrogen-
rich gas for the hydrogasification re-
actions. Although commercial plant size
information is not available, about 10
gasifiers would be needed for a commercial
plant. Inputs and outputs of such a plant
are listed in Table 1-36.
1.9.1.1.5.3 BI-GAS
In the BI-GAS process, pulverized
coal is piston-fed into the middle of a
1,000-psi gasifier reactor where it is
mixed with steam. The coal is devolatilized
by a rising flow of hot gases which are
produced from char (Figure 1-35) (Hittman,
1975: Vol. II, p. IV-5). The gases and
char are then separated, and the char is
piped to the bottom of the gasifier where
it is mixed with steam and oxygen. An ash
slag is removed from the bottom of the
vessel. The process gas stream undergoes
cleaning, shift conversion, purification,
and methanation. Materials inputs and
outputs for a plant using western subbitu-
minous coal are listed in Table 1-37.
1.9.1.1.5.4 Synthane
In the Synthane process, coal sized to
pass through a 200-mesh screen is mixed
with steam and oxygen in a pretreatment
pressure vessel at 1,000 psi and 800°F
(Figure 1-36) . In this pretreatment stage,
the coal is partially oxidized and volatile
1-86
-------
Coal
Prep.
Steam
Oxygen
Cyclone
Stage 2
Gasifier
Stage I
Raw
Gas
Shift
Scrub
Char
Slag
High BTU Gas
Methanator
->• Sulfur Recovery
Figure 1-35. BI-GAS Coal Gasification Process
Source: Adapted from Goodrige, 1973: 56.
-------
Steam
Oxygen
Steam
Oxygen
Coal
;-fl
Spray
Tower
Shift
Tar and Dust
Char
Gas
Scrubber
H2S
COS
COo
Methanator
Figure 1-36. Synthane Coal Gasification Process
Source: Adapted from BuMines, 1974c: 11.
-------
TABLE 1-37
INPUTS AND OUTPUTS FOR A BI-GAS PLANTE
Input
Coal
Water
Nickel
Quantity
19,600 tpdb
37.4 rrangpdc
1,000 pounds
per 4 months
Output
Solid waste
Air emissions
Ammonia
Sulfur
Quantity
1,330 tpd
27.7 tpd
98.5 tpd
93.1 tpd
Source: Hittman, 1975: Vol. II.
a250-mmcf-per-day production. Plant Btu capacity of 236x10
Btu's per day (produces 950 Btu's per cf gas) using Northwest
coal of 8,780 Btu's per pound, 6.77-percent ash, and 0.85-per-
cent sulfur.
tons per day.
r*
millions of gallons per day.
matter is driven off. The coal and gases
from the pretreater are introduced at the
top of the gasifier, and additional steam
and oxygen are introduced at the bottom.
Partial combustion of the coal increases
the temperature of this process to 1,800°F.
After the coal passes through the fluidized-
bed portion of the gasification vessel, it
exits as char at the bottom. The char is
burned to produce steam for the pretreater
and gasifier (Hittman, 1975: Vol. II, p.
IV-5).
The raw gas is cleaned of tars, char,
and water and then undergoes a shift con-
version. Following those operations, the
gas is bubbled through hot carbonate to
remove carbon dioxide and sulfur and is
then methanated.
The Synthane process achieves a high-
Btu raw gas output with a relatively simple
high-pressure gasification system. However,
all the coal entering the gasifier is not
burned, and the remaining high-sulfur char
must be burned for process heat. Materials
requirements and outputs of a Synthane
plant are listed in Table 1-38.
1.9.1.1.5.5 CO2 Acceptor
In the CO- Acceptor process, pulverized
coal and hot dolomite are introduced at the
top of the reactor and steam is introduced
at the bottom (Figure 1-37). Both the heat
of the dolomite and its energy-producing
reaction with the carbon dioxide (a product
of the coal-steam reaction) devolatilize
the coal as it passes down the reactor
vessel. The partially combusted coal exits
as char (Hittman, 1975: Vol. II, p. IV-5).
Both the char and spent dolomite are then
introduced as separate streams into a
dolomite regenerator vessel. In this ves-
sel, the combustion of char with air heats
the dolomite and drives off the carbon
dioxide as shown in Figure 1-37.
The CO2 Acceptor process produces a
gas low in carbon dioxide, carbon monoxide,
and sulfur. A shift reaction is not neces-
sary since the carbon monoxide-to-hydrogen
ratio is already suitable for methanation.
The advantages of the CO_ Acceptor process
are in the use of dolomite to remove some
of the sulfur and carbon dioxide from the
synthesis gas stream. Since dolomite is
1-89
-------
Coal
Preparation
C02+H2S
Raw Gas
Lock
Hopper
Dolomite
Gasifier
Steam
Purification
Methanation
Dolomite
Char
Flue Gas and Ash
Figure 1-37. C02 Acceptor Coal Gasification Process
Source: Adapted from Bodle and Vyas, 1973: 69.
-------
TABLE 1-38
INPUTS AND OUTPUTS FOR A SYNTHANE PLANT*
Input
Coal
Water
Nickel
Quantity
23,400 tpdb
25 inmgpd0
1,000 pounds
per 4 months
Output
Solid waste
Air emission
Sulfur
Ammonia
Benzene, Toluene
and Xylene
Quantity
1,650 tpd
63.0 tpd
100 tpd
150 tpd
25,000 gpd
Source: Hittman, 1975: Vol. II.
250-mmcf-per-day production using Northwest coal of 8,780
Btu's per pound. 6.77-percent ash, and 0.85-percent sulfur.
b
tons per day.
^
millions of gallons per day.
TABLE 1-39
INPUTS AND OUTPUTS FOR A CO_ ACCEPTOR PROCESS2
Input
Coal
Water
Nickel
Dolomite
Quantity
22,700 tpdb
23.7 irangpd0
1,000 pounds
per 4 months
1,260 tpd
Output
Solid waste
Air emission
Ammonia
Sulfur
Quantity
3,440 tpd
42.4 tpd
137 tpd
197 tpd
Source: Hittman, 1975: Vol. II.
250-mmcf-per-day production using Northwest coal of 8,780
Btu's per pound, 6.77-percent ash, and 0.85-percent sulfur.
tons per day.
Q
millions of gallons per day.
used as the oxidizing agent in the gasifier
vessel, oxygen does not have to be supplied.
These advantages must be balanced with the
complexity of plant design for the dolomite
regeneration system. Materials inputs for
the plant are listed in Table 1-39.
1.9.1.1.6 Underground Coal Gasification
The feasibility of gasifying coal
underground by heating it in place and
introducing air in deep beds for combus-
tion is being tested experimentally at the
present time. This system would involve
1-91
-------
drilling inlet wells for air injection and
one or more outlets for the removal of low-
Btu gas. An essential factor is establish-
ing permeability in the coal to be gasified
so that the flow of hot gases can be main-
tained. This permeability could rely on
natural cracks within coal beds or could
be established by artificially fracturing
the beds using explosions or methods de-
veloped for oil wells (BuMines 1973: 40).
Although a number of problems need to
be solved in underground gasification (in-
cluding establishing suitable control of
the combustion process) , production of
150 Btu's per cf of gas has been maintained.
One hypothetical configuration of an under-
ground gasification system is diagrammed in
Figure 1-38 where inclined and horizontal
well holes are used for the injection and
removal of gases. Combustion proceeds
along a horizontal plane to alternately
spaced producing holes {BuMines 1973: 41).
1.9.1.2 Liquid Fuels
There are several methods for producing
a liquid fuel from coal. As with gasifica-
tion, either hydrogen has to be added or
carbon removed from the compounds in the
coal. In bituminous coal, for example, the
carbon-to-hydrogen ratio by weight is about
16:1; in fuel oil, it is about 6:1 (Inter-
agency Synthetic Fuels Task Force, 1974:
12} . Although liquefaction is a complex
process, it can be viewed as a change in
the carbon-to-hydrogen ratio that can be
accomplished using one of three reactions:
hydrogenation, pyrolysis, or catalytic
conversion (Figure 1-39).
In hydrogenation, hydrogen is intro-
duced to react with the coal, either as a
gas in the presence of a catalyst or in the
form of a hydrogen-rich solvent. If a sol-
vent is used, it donates hydrogen to the
coal and is then removed after the reaction
has taken place, carrying with it ash and
inorganic sulfur from the coal. If gaseous
hydrogen is used, the products include liq-
uids, gases, and solids.
Pyrolysis depends on heating the coal
in the absence of an oxidizer until it de-
composes, producing a liquid hydrocarbon,
gases, afid char. The char is primarily
carbon withdrawn from the coal to allow the
remaining carbon-to-hydrogen ratio to reach
the liquefaction level.
A further alternative is to produce
synthesis (intermediate-Btu) gas, then
combine the hydrogen and carbon monoxide
in the presence of a catalyst to produce a
liquid fuel. For this catalytic conversion,
the synthesis gas must be cleaned and shifted
to the proper hydrogen-to-carbon monoxide
ratio before the liquefaction can take
place.
For any of these alternatives, there
are a variety of specific technologies
that might be used. Different combinations
of reactor temperatures and pressures can
also be used, and examples of each are
identified in Table 1-40. However, only
the catalytic conversion methods are in
commercial operation. In general, these
technologies differ sharply from gasifica-
tion processes in their use of recycled gas
and liquid products for a number of purposes.
In any case, the processes usually include
one of the liquefaction steps described,
plus a cleaning step for sulfur removal
and treatment of the product to improve
its quality.
1.9.1.2.1 Synthoil
In the Synthoil process, developed by
BuMines, crushed coal is slurried in re-
cycled product oil, preheated, and intro-
duced (along with turbulently flowing hy-
drogen) into a reactor containing a fixed
bed of cobalt molybdate catalyst (Figure
1-40). Reactor temperature is 850°F and
pressure is 2,000 to 4,000 psi. A transfer
of hydrogen to the coal takes place in the
reactor, yielding oil and releasing gases.
The coal products are then removed and the
liquid, gas, and solids are separated.
Some of the oil is recycled, but the remain-
der is a synthetic oil product ready for
1-92
-------
Gas Clean Up Unit
Compressed Air
Compression And
Combustion Gas
Blender
Surface
Combustion Zone
Figure 1-38. Longwall Generator Concept for Underground Coal Gasification
Source: BuMines, 1973: 41.
-------
Heat
Hydrogen or
Solvent
HYDR06ENATION
Cool
Cn H 2
Heavy
Syncrude
PYROLYSIS
S«__ 1
LJ^.^.4.
Coal •
Coa,_Char + CnH2n
CATALYTIC CONVERSION
nrj+H- ^P H.-. nr PH-.OH
L»\J T np~~"^L».| rip., or L»n3wn
(obtained by gasifying coal)
^-Char
Liquid Hydro-
methanol
Figure 1-39. Principal Coal Liquefaction Reactions
and Processes
-------
Rich Recycle Gas
Hydrogen
Coal
Preparation
Slurry
Preparation
High-Pressure
Oil-Gas
Separation
Fixed-Bed
Catalytic
Reactor
850°
2,000-
4,000 psi
Recycle Oil
Gas
Cleanup
Low- Pressure
Oil-Gas
Separation
I
Solid-
Liquid
Separation
Gas
Solids
Oil
Figure 1-40. Synthoil Coal Liquefaction Process
Source: Adapted from Bodle and Vyas,'1973: 82.
-------
to
TABLE 1-40
CHARACTERISTICS OF COAL LIQUEFACTION TECHNOLOGIES
Process
Hydrogenation
Synthoil
H-Coal
Solvent Refined Coal
Consol Synthetic Fuel
Pyro lysis
COED
TOSCOAL
Catalytic Conversion
Fischer-Tropsch
Methanol
Coal Feedstock
Pulverized, dried,
caking or noncaking
Pulverized, dried,
caking or noncaking
Pulverized, dried,
caking or noncaking
Pulverized, dried,
caking or noncaking
Pulverized, dried, b
caking or noncaking
Pulverized, dried,
caking or noncaking
Depends on
gasification process
Depends on
gasification process
Reactor
Temperature
{%•)
850
nominally
850
800
800
600 to 1,600
in four
reactors
970
Two reactors
at different
temperatures
U
Reactor
Pressure
(pounds per
square inch)
2,000
to
4,000
2,700
1,000
1,000
6 to 10
Atmospheric
330 to 360
U
Product
Oil Grade
(°API)
NA
5 to 17
U
U
25
6 to 13
Various
U
Heating
Value of Oil
(Btu1 s per
pound)
17,700
Ua
U
U
U
16 ,000
Various
U
Yield
(barrels per
ton of coal)
3.0
4.4
U
U
1.0 to 1.5*
0.5
U
U
U = unknown.
Different coal feedstocks may require a greater number of pyrolysis feedstocks.
One reported run; lower temperatures give lower yield of liquids.
-------
use as a fuel oil or for further refining
into other petroleum products.
In addition to the energy for pressuri-
zation, inputs are coal, hydrogen, a start-
up slurry medium, the catalyst, and cooling
water. Water requirements for cooling and
other purposes are expected to be about
20,000 acre-feet of water per year for a
100,000-barrel-per-year plant. This re-
quirement is apparently applicable to the
liquification plants described below (Davis
and Wood, 1974: 12). In addition to the
fuel oil, outputs are hydrogen sulfide,
ammonia, and other gases, along with ash
and other solid residues. Approximately
three barrels of oil are produced from each
ton of coal in the pilot plant.
1.9.1.2.2 H-Coal
In the H-Coal process, a pretreated
hydrogen-enriched slurry of pulverized coal
in oil is introduced into a reactor con-
taining a catalyst at 2,700 psi and 850°F
(Figure 1-41) . The cobalt molybdate is
continuously added and withdrawn to main-
tain its catalytic activity. Liquefied
coal and ash residues leave the reactor in
the slurry along with some gases. The
slurry is rapidly depressurized, causing
most of the liquid to vaporize and separate
from the residues. The vapor then goes
through an atmospheric distillation step
where the remaining heavy slurry is pro-
cessed by vacuum distillation to separate
recyclable oil from a char-rich bottom
slurry product. The technology is notable
for its application of conventional petro-
leum refining operations, building into
the operation several different distilla-
tion processes.
Inputs at the pilot plant stage are
the same as for Synthoil; outputs are simi-
lar as well, but H-Coal has the capability
of producing liquids of more than one grade
at the same time. The other principal dif-
ference between the two processes is in the
specific internal dynamics of the catalytic
reactors.
1.9.1.2.3 Solvent Refined Coal
In the Solvent Refined Coal (SRC)
process, crushed coal is slurried with a
hydrogen donor solvent and exposed to
1,000 psi and 800 F in a hydrogen atmosphere
(Figure 1-42). Under these conditions, the
coal dissolves into the solvent and picks
up hydrogen. The solution is filtered,
removing most of the ash and some undissolved
coal. The remainder is a liquid containing
solvent, dissolved coal, and a light oil—
a product of the reaction of coal with hy-
drogen. In a vacuum-flash operation, the
pressure of the mixture is reduced quickly,
the solvent boils off, and a material is
left which solidifies at about 350°F. This
solid has a considerably lower ash and sul-
fur content than the original coal. A va-
riety of other products result as well,
including fuel oils and high-Btu gas. To
manufacture a predominately liquid product,
an additional hydrogenation step is neces-
sary.
An SRC pilot plant is under construc-
tion, but it will not include the second
hydrogenation step required to produce a
liquid product.
1.9.1.2.4 Consol Synthetic Fuel
The Consol Synthetic Fuel (CSF) process
is a solvent extraction process coupled with
a catalytic hydrogenation step and hydrogen
manufacture in a Lurgi gasifier. The sol-
vent extraction is carried out under condi-
tions very similar to those of the SRC pro-
cess above, and the catalytic hydrogenation
is done under conditions similar to those
used in the H-Coal process (Figure 1-43).
Parts of the CSF process have been
evaluated in pilot plant operations. The
solvent extraction has been tested in a
20-ton-per-day pilot plant in West Virginia,
and the catalytic hydrogenation process has
been operated commercially in a 15,000-
barrel-per-day plant in Kuwait.
At the pilot stage, the CSF process is
designed to have coal and water as its only
inputs and to produce boiler fuel, distillate
1-97
-------
NH,
Hydrogen.
Cool J Coal
Preparation
Slurry
Preparation
Hydrogen Recycle
I
Gas Cleanup
Catalytic
Reactor
2250-
2700
psig
850° F
.Gas
Slurry
relight Oil
eavy Oil
Bottoms
Slurry to
Coking
Figure 1-41. H-Coal Coal Liquefaction Process
Source: Adapted from Bodle and Vyas, 1973: 84.
-------
Hydrogen
Recycle Gas
Coal
Preparation
i
Slurry
Preparation
(
k
i
i
-^
Preheating 8
Dissolution
*
Filtration
t
Solvent
Recovery
^-
' H2S
Gas
Treating
Solidification
Hydrotreating
Gas
Solids
Liquids
Hydrogen
I
Figure 1-42. Solvent Refined Coal Process
Source: Adapted from Bodle and Vyas, 1973: 88.
-------
Coal
Preparation
Air and Steam
Distillate
Naphta
Slurry
Preparation
Extraction
765° F
150 psig
c
0>
>
o
C0
Residue
Separation
Fractionation
o>
Fuel Gas and
Light Oil
Low-Temp.
Carbonization,
925°F 9psig
Tar
Distillation
Char
Tar
••
Hydrogen (from Lurgi Char-Gasifier)
r
Fuel
Gas
Gas
Cleanup
3
CO.
Hydrotreatment,
(800°F 3000
psig)a Distillation
Fuel Oil
Figure 1-43. Consol Synthetic Fuel Process
Source: Adapted from Bodle and Vyas, 1973: 86.
-------
fuel, liquefied petroleum gas, and high-
Btu gas as primary outputs, with ash, hy-
drogen sulfide, and ammonia as waste out-
puts.
1.9.1.2.5 COED
COED is a pyrolysis process in which
crushed coal is exposed to progressively
higher temperatures in four successive
fluidized-bed reactors (Figure 1-44). For
example, with a particular coal the se-
quence is from 600 to 850 to 1,000 to
1,600°F (Bodle and Vyas, 1973: 78,79). The
specific sequence of temperatures and num-
ber of reactors are dependent on the caking
quality of the coal; coals with high-caking
properties require more reactors with
smaller temperature differences. Char from
the first reactor flows toward the hotter
reactors while steam and oxygen, introduced
into the last reactor, flow counter-current,
activating the fluidized-beds in the second
and third reactors. Staging the tempera-
ture increase allows volatile liquids to be
drawn off as they are produced, maximizing
liquid yield and avoiding agglomeration of
the char before most of the hydrocarbons
have been removed. The tar-like product
oil (mostly evolved in the second stage)
is treated with hydrogen (hydrotreated) to
remove sulfur and upgrade it to a synthetic
crude oil. An intermediate-Btu gas (about
500 Btu's per cf after cleaning) and char
are also produced by the pyrolysis process.
At the pilot plant stage, about one
barrel (bbl) of oil per ton of coal has
been produced together with 8,000 to 10,000
cf of gas and about 1,180 pounds of char.
Inputs to the process are 55 pounds of
steam and 375 cf of oxygen per ton of coal
(Jones, 1973: 390). Oxygen-free flue gas
needed for the first stage and hydrogen
needed for the hydrotreater are assumed to
be generated internally in a commercial
plant. Outputs (in addition to the crude
oil, intermediate-Btu gas, and char which
have energy value) are hydrogen sulfide
and vent gas.
1.9.1.2.6 TOSCOAIi
The TOSCOAL process is a pyrolysis
process which uses externally heated cera-
mic balls to provide heat. It is similar
to a process developed by The Oil Shale
Corporation (TOSCO) to retort oil shale.
The crushed, preheated coal is introduced
into a rotating pyrolysis drum where it is
heated by contact with separately heated
ceramic balls (Figure 1-45). This treat-
ment produces gases (including vaporized
hydrocarbon liquids and water vapor) and
large quantities of char.
When separated from the gaseous pro-
ducts, the liquids can be refined like
crude oil, and the gases are burned in the
ball heater.
Inputs for the pilot plant are coal,
ceramic balls, and air. Outputs are hydro-
carbon liquids, char, hydrogen sulfide, and
relatively large amounts of water. A dis-
tinctive feature of the process is the
heating value left in the char, about 80
percent of the heating value of the raw
coal. .The oil yield is low, only about
half a barrel per ton of coal, but 970
pounds of char per ton of coal are produced
as well. In experiments at the pilot plant,
this char had a heating value of 13,000
Btu's per pound. Water yield from the gasi-
fication steps is about 700 pounds per ton
of coal (Bodle and Vyas, 1973: 81).
1.9.1.2.7 Fischer-Tropsch
The Fischer-Tropsch process is a cata-
lytic conversion system which produces
hydrocarbon liquids from coal-derived,
intermediate-Btu synthesis gas. The pro-
cess is in commercial operation in South
Africa where a Lurgi gasifier is used to
produce the synthesis gas. The gas from
the Lurgi gasifier is cleaned of hydrogen
sulfide, carbon dioxide, and impurities,
then shift-converted before it enters a
catalytic reactor which produces hydro-
carbon liquids (Figure 1-46). In this
plant, two reactors, using different cata-
lysts and temperatures, process gases with
1-101
-------
NH
Coal Stage
Goaf^ Preparation 600°F
Scrubber ->Vent
Oil
^ Hecove
i
r-^~S , Filtmt'mr
fc
Char
f2nd ]
Stage
850°F
6-10
iGas Stage
IOOO°F
Char 6-10 Gas
\^__^/ \SA~m
(*t\\\
Char Stag
I60Q
^ R-lf
Oxvaen - »A psio
T
Gas _ Cleanup
| " Plant
ry
i
i
*• St
Re
H™
H2 LJ-.
\ '
L
"N
8
9F
)
1 )
HydrfttrAnter
Product Gas
earn
former
^
Char
Figure 1-44. COED Coal Liquefaction Process
Source: Adapted from Bodle and Vyas, 1973: 78.
-------
Cool
Coal
Preparation
Coal
Preheater
Cool ^
Pyrolysis
800°-
1000° F
Char
Hot Flue Gas
Hs
Gas
Separation
Purification
Liquid
Products
\>
Hot Balls
Ball
Heater
Char
Cooler
Char
Air and
Fuel
Figure 1-45. TOSCOAL Coal Liquefaction Process
Source: Adapted from Bodle and Vyas, 1973: 80.
-------
Coal Icoal
— — -»-|
[Preparation —| H2S+C02
I i
^^^^ • • ^^^^^ ^
Ownm *fcl fnn^ifipfltion LM—^ fin^ _ *- CTIVAH K^/J
LMH^ ^^^J
Ash Cleanup
I
Oil
Synthesis
Synthesis Gas
\ '
Fluid-bed
Synthesis
^- PrrtH ii /*4
Separal
^
•^1 nj r
1 Reform
J
Product
s
Mon
Tail
}
er|
r
S
tion
.,._„. i^i i nu id
Products
Gas
Tail Gas
— ^-Liquid
Products
Figure 1-46. Fisher-Tropsch Coal Liquefaction Process
Source: Adapted from Bodle and Vyas, 1973: 76,
-------
different carbon-to-hydrogen ratios into
different products. Reactor products in-
clude gasoline, diesel/other fuel oils,
waxes, alcohols, and ketones.
The South African plant has a capacity
of 6,600 tons of coal per day. The inputs
are coal and cooling water, and the outputs,
as mentioned above, are quite diverse. The
principal advantage of the process is that
it has been demonstrated commercially. its
main drawbacks are that a great deal of
reaction heat is produced (posing a major
cooling requirement) and that the process
is relatively expensive.
1.9.1.2.8 Methanol
Methyl alcohol (methanol) is manufac-
tured commercially from synthesis gas in
a catalytic reactor. Consequently, methanol
can be derived from coal if the coal is
gasified to produce intermediate-Btu syn-
thesis gas. This is not now being done,
but all the process steps involved have
been demonstrated commercially. The syn-
thesis gas must be shift-converted to the
proper carbon-to-hydrogen ratio and the
proper catalyst used. When this is done,
methanol becomes an alternative product
from any process that can produce high-Btu
gas.
1.9.1.3 Solvent Refined Solid Fuels
The Solvent Refined Coal process de-
scribed above has been proposed to trans-
form a high-sulfur feedstock coal to manu-
facture a lower sulfur solid which could
then be used as a boiler fuel. A pilot
plant is being built to test the feasibil-
ity of this process.
1.9.2 Energy Efficiencies
Data in Table 1-41 are taken from
Hittman. Hittman describes most of these
data as "good" with a probable error of
less than 25 percent. Ancillary energies
for all low-Btu gasification technologies
are described as less reliable, with the
probable error being less than 50 percent.
Differences in efficiencies by plant loca-
tion are based on process inputs and out-
puts when fed coal from selected hypotheti-
cal mines.
1.9.2.1 Gaseous FueIs
1.9.2.1.1 Low-Btu Gasification
Primary efficiencies for low-Btu gasi-
fication processes range from 73 percent
for the Westinghouse process to 95 percent
for the BuMines pressurized process. An-
cillary energy represents the power re-
quirements for fuel gas production, cooling,
and treating. All ancillary energy is
consumed in the form of electricity. Over-
all efficiencies range from 65 to 80 per-
cent. Since their ancillary energy re-
quirements are an order of magnitude higher
than for the other gasification technolo-
gies, the BuMines processes are lowest in
overall efficiency. Given the questionable
quality of the data, however, differences
among the technologies and areas may not
actually exist.
1.9.2.1.2 High-Btu Gasification
In high-Btu gasification processes,
primary efficiencies range from 54 to 68
percent, with BI-GAS appearing to be the
most efficient. Using Central area coal,
which has a high heat content, also appears
more efficient. However, these data are
of questionable quality and the indicated
variations in the data among areas and
processes may not reflect actual differ-
ences in the technologies or locations.
Ancillary energy requirements are
zero because the processes are self-sus-
taining with process heat requirements
generated on site.
1.9.2.2 Liquid Fuels
In Table 1-41, the CSF process appears
to be more efficient than the SRC process.
Although no area variations are obvious,
Hittman's calculations were based on Central
coal and assume that Appalachian and
1-105
-------
H
M
O
TABLE 1-41
COAL PROCESSING EFFICIENCIES
Process
Low-Btu Gasification
Lurgi
Koppers-Totzek
BuMines Atmospheric
BuMines Pressurized
Westinghouse"
Agglomerating
fluidized bed
High-Btu Gasification
Lurgi
HYGAS -Steam-Oxygen
BI-GAS
Syn thane
CO. Acceptor
Liquefaction
Consol Synthetic Fuel
Process
Solvent Refined Coal
Process"
Solvent Refined Solids
Solvent Refining
Primary Efficiency
(percentage)
Appalachia
NC
82.0
78.5
73.4
NC
81.8
NC
58.7
65.4
53.5
NC
69.1
62.5
76.8
Central
NC
81.1
78.3
73.0
95.0
NC
54.1
63.7
67.4
58.0
NC
69.1
62.5
68.6
Northwest
75.8
74.4
73.3
73.3
NC
NC
60.5
58.8
68.2
58.4
62.5
69.1
62.5
NC
Ancillary Energy Needsa
(109 Btu's per 1012 Btu's)
Appalachia
NC
14.8
84.9
85.8
NC
NC
0
0
0
0
0
0
0
76.6
Central
NC
14.4
96.9
98.1
NC
NC
0
0
0
0
0
0
0
68.1
Northwest
27.8
13.4
126.6
128.4
NC
NC
0
0
0
0
0
0
NC
Overall Efficiency
(percentage)
Appalachia
NC
80.8
72.4
67.6
NC
NC
Central
NC
80.0
71.4
66.5
95.0
NC
Northwest
73.7
73.4
65.0
65.0
NC
NC
Same as Primary Efficiency
Same as P
71.3
rimary Ef
64.2
ficiency
n
u
NC = not considered, U = unknown.
Source: Hittman, 1975: Vol. II.
aAncillarv energy values are three times the Hittman values which accounts for conversion of electricity to Btu at an
average Sat Se of" 10?500 Btu's per kwh (rather than 3.400 Btu's per kwh used by Hittman) . Ancillary energy values
for high-Btu technologies are zero as all energy inputs are assumed to be supplied by input coal.
bData from Westinghouse Corporation.
cBattelle estimates the primary efficiency to be 66 percent, location not specified (Battelle, 1973: 102).
dBattelle estimates 75-percent primary efficiency, which apparently does not include nrocess heat (Battelle, 1973: 78)
-------
Northwestern coals would produce the same
results.
The ancillary energy requirement is
zero because the process is self-sustaining
with all power and steam requirements gener-
ated on site. The best overall efficiency
is 69 percent for the CSF process.
1.9.2.3 Solvent Refined Solids
Primary efficiency for solvent refining
appears higher for Appalachian coal than for
Central coal (Table 1-41) . However this
may not be accurate because coal with a
heating value of 12.000 Btu's per pound was
used in both estimates.
The ancillary energy source was assumed
to be natural gas and was calculated using
13,800 Btu's per pound for Central coal
and 12,000 Btu's per pound for Appalachian
coal. Primary efficiency is in the 70- to
75-percent range, and overall efficiency is
in the 65- to 70-percent range.
1.9.2.4 Summary
High-Btu gasification and liquefaction
are generally less efficient than low-Btu
gasification or the production of solvent
refined coal (Table 1-42) . However, low-
Btu gas and solvent refined coal are not
ready for consumer use as these are feed-
Stocks for electric power generation. Thus,
depending on the overall trajectory, low-
Btu gasification or solvent refining may
have a low efficiency.
TABLE 1-42
SUMMARY OF OVERALL COAL
PROCESSING EFFICIENCIES
Process
Solvent refined solids
Liquefaction
Low-Btu gasification
High-Btu gasification
Efficiency
(percent)
65 to 70
62 to 69
65 to 95
54 to 68
1.9.3 Environmental Considerations
Residuals data are drawn from the
Hittman, Battelle, and Teknekron studies.
Hittman's data assume maximum environmental
control; for example, it is assumed that
water is recycled and that no effluent
leaves the facility. The data have an error
of less than 50 percent. The Battelle and
Teknekron data are often based on technolo-
gies that provide more limited environmental
control, and this is reflected in higher
values for environmental residuals.
1.9.3.1 Gaseous Fuels
1.9.3.1.1 Low-Btu Gasification
Residuals for five low- to intermediate-
Btu gasification processes, using coal from
several areas, are given in Table 1-43. Ta-
ble 1-44 summarizes important pollutants.
1.9.3.1.1.1 Water
Since all water is assumed to be recy-
cled or placed in evaporation ponds, all
water pollutants are zero. Potential sources
of water effluent are from boiler blowdown,
the raw gas cooling system, and overfill of
the water clarifier. For example, boiler
blowdown water from the Koppers-Totzek pro-
cess contains 40 ppm suspended solids, 30
milligrams per liter Biochemical Oxygen De-
mand (BOD), and 25 milligrams per liter
Chemical Oxygen Demand (COD). Both boiler
blowdown water and water from raw gas cool-
ing will be routed to a clarifier. Clarified
water containing about 250 ppm total dis-
solved solids is filtered, treated, and re-
12
cycled. For every 10 Btu's of coal gasi-
fied, 1.3 million gallons of water will be
produced from boiler blowdown. Additionally,
the clarifier will require 80 gallons per
minute in make-up water because of evaporation
losses in quenching the ash from the gasifier
(Hittman, 1975: Vol. II, footnote 8090).
1.9.3.1.1.2 Air
Major air emissions (Table 1-44) result
from the sulphur recovery processes, an
ammonia sulfate plant for the two BuMines
1-107
-------
Table 1-43. Residuals for Low- to Intermediate-Btu Coal Gasification 1
SYSTEM
CENTRAL COAL
BuMines
Atmospheric
Pressurized
Koppers-Totzek
uoRTHEM) APPALACHIAN
COAL
BuMines
Atmospheric
Pressurized
Koppers-Totzek
NORTHWEST COAL
BuMines
Atmospheric
Pressurized
Koppers-Totzek
Lurgi
Water Pollutants (Tons/lO1* Btu's)
to
•o
•H
U
0
0
0
0
0
0
0
0
0
0
Bases
0
0
0
0
0
0
0
0
0
0
8*
0
0
0
0
0
0
0
0
0
0
fif
0
0
0
0
0
0
0
0
0
0
Total
Dissolved
Solids
0
0
0
0
0
0
0
0
0
0
Suspended
Solids
0
0
0
0
0
0
0
0
0
0
Organics
0
0
0
0
0
0
0
0
0
0
Q
8
0
0
0
0
0
0
0
0
0
0
Q
8
0
0
0
0
0
0
0
0
0
0
Thermal
(Btu's/I0l2)
0
0
0
0
0
0
0
0
0
0
Air Pollutants (Tons/1012 Btu's)
Particulates
0
0
4.97
0
0
0
0
0
5.42
0
X
§
0
0
270.
o
0
0
0
0
5.15
0
X
8
20.7
24.
41.2
39.5
39.5
8.21
12,
14.1
17.6
3.3
Hydrocarbons
0
0
290.
0
0
0
0
0
5.5
0
8
0
0
195.
0
0
0
0
0
3.71
0
Aldehydes
0
0
0
0
0
0
0
0
0
0
tn
Solids
(Tons/1012 Btu
7060.
7060.
8430.
5060.
5060.
5410.
3460.
3460.
3460.
3460.
V
Land
Acre-year
U)
5
to
CM
0
-58/.04
1.07
• yo
/.U4
998
.12/.96
12.1
.48/.03
.815
.2/.04
75
.11/.32
3.98
•
•
17
1
42/0
.42
42/0
.42
11/0
.11
66/0
.66
Occupational
Health
1012 Btu's
Deaths
U
U
U
U
U
U
u
u
u
u
Injuries
U
U
U
U
U
U
u
TI
u
u
4J
in
o
Uj
10
I
I
U
U
u
u
u
u
u
tt
u
u
-------
Table 1-43. (Continued)
SYSTEM
EASTERN COAL
Agglomerating.
Fluidized Bed
Water Pollutants (Tons/1012 Btu's)
Acids
0
Bases
0
«t
2
0
ro
0
Total
Dissolved
Solids
0
Suspended
Solids
0
Organics
0
a
S
0
Q
8
0
Therma 1
(Btu's/iol2)
0
Air Pollutants (Tons/1012 Btu's)
Particulates
69.
X
11.3
X
o
U)
22.5
Hydrocarbons
0
o
o
6.5
Aldehydes
0
"in
Solids
(Tons/1012 Btu
6500.
V
Land
Acre-year
to
3
m
fN)
•H
O
i— 1
0
Occupational
Health
1012 Btu' s
Deaths
NC
Injuries
NC
4J
tn
a
c/)
>i
10
Q
1
C
to
S
NC
NC
not considered, U = unknown.
aFixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres ).
reknekron, 1973: 132.
1012 Btu's
1012 Btu's
-------
TABLE 1-44 f
SUMMARY OF LOW- TO INTERMEDIATE-BTU GASIFICATION POLLUTANTS
Process
BuMines
Atmospheric
BuMines
Pressurized
Koppers-Totzek
Lurgi
Water
0
0
0
0
Air
(tons per 10A Btu's input)
Sulfur Oxides3
12 to 40
14 to 40
18 to 41
3.3
Other
0
0
12. 5C
0
Solidsb
(tons per 1012 Btu's)
3,500 to 7,000
3,500 to 7,000
3,500 to 8,500
3,500
Source: Hittman, 1975: Vol. II, Table 1.
Variation due to the sulfur content difference in coal; only Northwest coal is
used in the Lurgi calculation.
variation due to the ash content difference in coal; only Northwest coal is used
in the Lurgi calculation.
°Includes 40-percent particulates, 20-percent oxides, 23-percent hydrocarbons,
and 17-percent carbon monoxide.
processes and a Claus plant for the
Koppers-Totzek processes (Hittman, 1975:
Vol. II, pp. 111-19, 111-21, 111-28).
Regional differences in sulfur dioxide
emissions result from variations in the
sulfur content of the coal. Northwest
coal is lowest and Northern Appalachian
coal highest in sulfur content. Sulfur
dioxide emissions from the ammonia sulfate
plant used in the BuMines processes range
from 12 to 40 tons per 10 Btu's processed.
Emissions are lowest from the Lurgi system,
12
3.3 tons per 10 Btu's processed.
In addition to sulfur dioxide, emis-
sions from the Koppers-Totzek system in-
clude particulates, nitrous oxides, hydro-
carbons, and carbon monoxide (Table 1-44).
These other air pollutants are emitted from
the coal-fired thermal dryer. Large guan-
w
A Claus plant takes emission gas
streams containing 10 percent or more hydro-
gen sulfide and oxides the hydrogen sulfide
in the presence of a solid catalyst (either
aluminum oxide or bauxite), thus producing
elemental sulfur of high purity.
1-110
tities of particulates from the agglomer-
ating gasifier are dolomite dust from the
desulfurization step which follows gasifi-
cation (Teknekron, 1973: 132) .
1.9.3.1.1.3 Solids
The solid waste generated by low-Btu
gasification ranges from 3,500 to 8,500
12
tons for each 10 Btu's of coal processed
(Table 1-44). This value includes only ash
removed from the combustor. The lowest
value is for Northwest coal, which has the
lowest (6.4-percent) ash content, and the
highest is for Central coal, which has the
highest (17.3-percent) ash content. Since
a typical low-Btu gasification plant would
produce about half of the tons per 10
Btu's amount daily, some or all of the
waste would require disposal in the mine.
If the sulfur recovered in the process can-
not be sold, it will also require disposal.
The solid waste from a gasifier also con-
tains small quantities of radioactive iso-
topes. For the agglomerating gasifier
discussed by Teknekron (1973: 132), these
-------
Table 1-45. Environmental Residuals for High-Btu Gasification
SYSTEM
HIGH-BTU GASIFICATION
Central Coal
HYGAS -Steam-Oxygen
BIGAS
Synth ane
Lurgi
Northern Appalachian
Coal
HYGAS -Steam-Oxygen
BIGAS
Synthane
Northwest Coal
HYGAS -S team-Oxygen
BIGAS
Synthane
Lurtji
C02 Acceptor
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
u
u
u
u
u
0
0
0
0
0
Bases
U
U
U
U
u
u
u
0
0
0
0
0
*
S
u
u
u
u
u
u
u
0
0
0
0
0
fl
s
u
u
u
u
u
u
u
0
0
0
0
0
Total
Dissolved
Solids
U
U
U
43.1
U
U
u
0
0
0
0
0
Suspended
Solids
U
U
U
.9
U
U
U
0
0
0
0
0
Organics
U
U
U
.426
u/
.03
U
U
0
0
0
0
0
Q
8
u
u
u
u
u
u
u
0
0
0
0
0
o
8
u
u
u
u
0
u
u
0
0
0
0
0
Thermal
(Btu's/1012)
0
0
0
0
0
0
0
0
0
0
0
0
Air Pollutants (Tons/1012 Btu's)
Particulates
6.88
4.75
14.7
3.65
3./
91.
3.66
15.4
5.71
3.42
13.
2.05
3.31
X
68.1
62.6
111.
73.3
60. /
190.
54.4
99.8
68.3
58.3
115.
76.9
38.1
X
8
62.9
81.5
51.8
36.8
20./
400.
17.5
18.7
5.9
14.1
9.63
5.59
61.7
Hydrocarbons
.895
1.
1.86
1.22
• 8/
1.1
.907
1.67
1.15
.928
1.91
1.28
.595
8
3.35
3.35
6.21
4.07
2.92
3.02
5.54
3.8
3.1
6.37
4.27
1.98
Aldehydes
.394
.423
.465
.448
.363
.409
.43
.313
.301
.354
.292
.437
Solids
(Tons/1012 Btu's)
5250.
5340.
5330.
5270.
>500./
24500
6560.
6560.
3730.
3840.
3830.
3730.
8610.
V
Land
Acre-year
a>
•3
•p
03
tN
•-H
O
fM
2.75/0
2.75
3.65/6
3*25
2.67/0
2.67
2.43/0
2.43
2.53/0
2.53
2 . 96/0
2.96
2.46/0
2.46
3.75/0
3.75
4 . 54/0
4.54
3.96/0
3.96
3.78/0
3.78
3 . 16/0
3.16
Occupational
Health
1012 Btu's
Deaths
U
U
U
U
U
U
U
u
u
u
u
u
Injuries
U
U
U
U
U
U
U
U
u
u
u
u
-P
tn
3
til
>i
IB
O
1
C
10
E
U
u
u
u
u
u
u
u
u
u
- -U
u
U = unknown.
aFixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres ) ,
1012 Btu's 1012 Btu's
bWhere two numbers occur, the second is taken from Battelle for a HYGAS unit using
content of. 3 percent.
Eastern coal with an ash content of 14.4 percent and a sulfur
-------
H
H
10
TABLE 1-46
SUMMARY OF HIGH-BTU GASIFICATION RESIDUALS
Process
HYGAS
BI-GAS
Synthane
Lurgi
C0» Acceptor
Water
(Recycled or
treatment
to meet
standards
[Table 1-44])
Air
(tons per 1012 Btu's coal processed)
Particulates
3- 7
3- 5
13-15
2- 4
3
Nitrogen
Oxides
60- 68
54- 63
100-115
73- 77
38
Sulfur
Oxides
6-63
14-81
10-52
6-37
62
Hydrocarbons
1
1
2
1
0.5
Carbon
Monoxide
3-5
3.0
5.0
4.0
2.0
Solids
1012 Btu's)
3,700-6,500
3,800-6,800
3,800-6,600
3,700-5,300
8,600
Total
T ar\f&
(acres)
350
350
350
350
350
Source: Hittman, 1975: Vol. II, Table 2 and associated footnotes.
aLand required is for coal storage, preparation, gasification plant facilities, and evaporation
ponds. No additional requirement is assumed for buffer areas surrounding plant facilities
(although they would probably be included in a commercial facility, on.the order of 1,500 acres)
-------
are 0.00076 curie of radium-226 and 0.0128
curie of radium-228 and thorium-228 and
-230 for each 10 Btu's of coal gasified.
1.9.3.1.2 High-Btu Gasification
Table 1-45 gives all residuals as cal-
culated by Hittman for five high-Btu gasi-
fication systems and three areas. These
are summarized in Table 1-46.
1.9.3.1.2.1 Water
A plant synthesizing 250 mmcf of natu-
ral gas per day at 60-percent efficiency
g
will emit. 160x10 Btu's of waste heat per
day. Presumably, most of this will be
emitted to the atmosphere through the use
of mechanical-draft, wet-cooling towers.
These cooling towers will require 20 to 35
million gallons of make-up water each day.
Thus, in regions where water is scarce, all
process wastewater and impounded runoff
(about three million gallons per day) will
be treated and used for cooling tower
make-up. All blowdown streams are collected
and sent to lined evaporative ponds. For
this reason, water residuals are zero for
the Northwest region (Table 1-45), although
settling ponds and process units could rup-
ture or spill into streams or other water
courses.
Wastewater treatment will also be re-
quired in areas where water is not recycled.
Characteristics of untreated wastewater are
given in Table 1-47 for the Synthane gasi-
fier unit and the entire Lurgi process. Ef-
fluent characteristics from the Lurgi sys-
tem assume the following treatment: three
stages of tar-oil-water separation, filtra-
tion, phenol recovery, ammonia recovery in
an ammonia still, and activated carbon
treatment (Hittman, 1975: Vol. II, p. IV-70).
1.9.3.1.2.2 Air
Air emissions are produced from several
by-product streams, but most are from com-
bustion of fuels in the plant boiler and
TABLE 1-47
WASTEWATER CHARACTERISTICS FROM TWO HIGH-BTU COAL GASIFICATION PROCESSES
Parameter
Thiocyanate
Cyanide
Ammonia
Sulfide
Suspended solids
Organics
Phenols
Oil
Chemical oxygen demand
Synthane
Gasifier Vessel
(parts per million)
23
0.23
9,520
U
140
6,000
0
43,000
b
Lurgi Process
Before Treatment
(parts per million)
0
0
15,900
1,400
600
9.960
1,100
0
After Treatment
(parts per million)
0
0
15.9
1.4
33.5
0.498
15.4
0
U = unknown.
a
Sources: aForney and others, 1974: 3 (Northwest coal).
bHittman, 1975: Vol. II, P- IV (Central Region coal).
1-113
-------
the sulfur recovery plant. Stack discharges
from the bc,'.ler are cleaned with an electro-
static precipitator for particulates and
wet scrubbing system for five gases. Emis-
sions are given in Table 1-46 for five air
pollutants. For a typical size gasification
facility synthesizing 250 mmcf of gas a day,
about half the values shown in Table 1-46
would be emitted daily. The range of values
for any one process reflects variations due
to area coal characteristics. In general,
emissions are highest when Central area
coal is used and lowest when Northwest coal
is used.
Particulates range from 2 to 15 tons
12
for each 10 Btu's processed (1.0 to 7.5
tons daily) . They are highest for Synthane
and lowest for Lurgi. However, Battelle
data (1973: 102) indicate that particulate
emissions from a HYGAS unit using Eastern
coal with a 14.4-percent ash content are
91 tons per 10 Btu's processed. Oxides
of nitrogen range from 38 to 115 tons per
12
10 Btu's processed. Synthane produces
the highest emissions and C0_ Acceptor the
lowest. Sulfur dioxide varies considerably
by coal type, with Northwest coal being the
lowest in sulfur content. Synthane and
Lurgi produce the fewest sulfur dioxide
emissions, and CO_ Acceptor, which uses
Northwest coal, produces the most. Hydro-
carbon and carbon monoxide emissions are
12
small, 0.6 to 4 tons per 10 Btu's pro-
cessed. Estimates calculated by Battelle
for a number of the residuals are substan-
tially higher than those developed by
Hittman (Table 1-45) .
1.9.3.1.2.3 Solids
Regional variations in solids requir-
ing disposal are primarily a function of
the ash content of the coal. Disposal re-
quirements are lowest for Northwest coal
and highest for Northern Appalachian coal.
For a high-Btu gasification facility using
Northwest coal, 3,700 tons of material
(primarily ash) are generated for each 10
Btu's of coal processed (Table 1-46). About
5,30*6 tons of solids would require disposal
from Central coal, and Northern Appalachian
coal use would produce about 6,600 tons of
solid wastes. Half these amounts would be
roughly equivalent to the daily municipal
refuse of 640,000 people in the Northwest
area or 1.3 million people in the Northern
Appalachian area. For this reason, high—
Btu gasification plants may have to be
mine-mouth activities so that solid wastes
can be returned to the mine for burial.
In addition to ash, the CO_ Acceptor
process requires disposal of dolomite. Of
the 8,600 tons shown in Table 1-46, spent
dolomite is 3,200 tons or 37 percent of
that total.
1.9.3.1.2.4 Land
Land requirements given in Table 1-46
are based on 350 acres of fixed area for
coal storage, preparation, and gasification
plant facilities plus an additional 165
acres for evaporation ponds to handle waste-
water streams. The land requirements per
10 Btu's coal input in Table 1-45 are
based on an assumed 350-acre requirement
and are calculated from the plant.
1.9.3.2 Liquid Fuels
Data presented in Table 1—48 have been
developed for two processes, Consol Syn-
thetic Fuel and Solvent Refined coal, and
for coal from three Hittman areas: high-
sulfur Central coal, medium-sulfur Northern
Appalachian coal, and low-sulfur Northwest
coal. A summary of important pollutants is
given in Table 1-49.
1.9.3.2.1 Water
Process wastewater includes phenols,
cyanide, ammonia, sulfide, oil, and sus-
pended solids. Dissolved solids are con-
tributed by boiler and cooling tower blow-
down and demineralization. Wastewater
1-114
-------
Table 1-48. Solvent Refined Solids and Coal Liquefaction Residuals
SYSTEM
SOLID COAL
Solvent Refined Coal
Northern
Appalachian Area
Central
Eastern Coal
Chemical Cleaning
LIQUEFACTION
Northwest Area
CSF Process
SRC Process
Central Area
CSF Process
SRC Process
SRC Process0
Northern Appalachian
Area
CSF Process
SRC Process
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
NC
0
0
U
U
0
u
u
Bases
U
U
NC
0
0
U
U
NC
U
U
I
T> a)
G M
ro u
•J <:
en
3
4J
03
N
O
iH
2 . 54/0
2.54
2*2
2.
4/U
24
9.1
4.48/0
4.48
6.22/0
6.22
2.91/0
2.91
3.
3
4/0
.4
9.10
2.9
2.
3.
3
2/0
92
4/0 •
.4
Occupational
Health
1012 Btu's
Deaths
U
U
NC
U
U
U
U
NC
U
U
Injuries
U
u
NC
U
U
U
U
NC
U
U
4J
1
ro
Q
1
c
(0
E
u
u
NC
U
U
U
U
NC
U
u
NC = not considered, U = unknown.
a.
Fixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres ),
lO1^ Btu's 1012 Btu's
Battelle. 1973: 76.
cBattelle, 1973: 78, location specified as Eastern coal.
-------
TABLE 1-49
SUMMARY OF SOLVENT REFINED SOLIDS AND COAL LIQUEFACTION RESIDUALS
Process
Liquefaction
Consol Synthetic
Fuel Process
Solvent Refined
Coal Process
Solid Coal
Solvent Refined
Water
(tons per 1012 Btu's)
TDSa
63
52
550
ss*
0.008
0.017
1.5
Organics
0.0018
0.003
0.03-0.3
Air
(tons per 1012 Btu's)
Particulates
2.5
3.2
18
Nitrogen
Oxides
61
88
20
Sulfur
Oxides
4-25
5-30
24-47
Solids
(tons per
1012 Btu's)
3,200-5,000
3,400-5,300
3,200-4,000
Land
(acresp
500d
280e
200
Source: Hittman, 1975: Vol. II, Tables 5 and 6.
Total dissolved solids.
Suspended solids.
GLand required is for coal storage, preparation, gasification plant facilities, and evaporation
ponds. No additional requirement is assumed for buffer areas surrounding plant facilities
(although they would probably be included in a commercial facility, on the order of 1,500 acres)
dln the Northwest region, an additional 230 acres is required for evaporation ponds.
ein the Northwest region, an additional 265 acres is required for evaporation ponis.
-------
TABLE 1-50
PROCESS WASTEWATER POLLUTANT CONCENTRATIONS
PROM TWO LIQUEFACTION PROCESSES
Parameter
Sulfide
Ammonia
Cyanide
Other dissolved solids
Total dissolved solids
Suspended solids
Organ ics (phenol and oil)
Consol Synthetic
Fuel Process
(parts per million)
0.8
109.2
1.8
27.774
27,856
3.5
0.8
Solvent Refined
Coal Process
(parts per million)
14.4
48
52.8
62.936
63.052
21.2
3.8
Source: Hittman. 1975: Vol. II, pp. VIII-13, VIII-15, VIII-19, VIII-21,
VIII-22.
concentrations after treatment are given in
Table 1-50 for each process. The summary
in Table 1-49 gives the total amount re-
leased in tons. Wastewater treatment in
the CSF process includes oil-water separa-
tion, dissolved air flotation, ammonia
stills, activated sludge, clarification,
and activated carbon (Hittman, 1975:
Vol. II, pp. VIII-13 and VIII-19). SRC
wastewater treatment is similar, including
oil-water separation, phenol solvent extrac-
tion, sour water stripping, clarification,
and activated carbon (Hittman, 1975:
Vol. II, pp. VIII-15, VIII-21, VIII-22).
Total water pollutants discharged are
higher for the CSF than for the SRC process
(Table 1-49). As shown in Table 1-50, how-
ever, most pollutant concentrations are
considerably higher in SRC wastewaters than
in CSF wastewaters, especially for dissolved
solids and cyanide. Ammonia is the only
pollutant with higher concentrations from
the CSF process. Total dissolved solids
range from 27,856 to 63,052 ppm and cyanide
ranges from 1.8 to 52.8 ppm. For perspec-
tive, the Public Health Service's recom-
mended limits for drinking water are 500
ppm for total dissolved solids, 0.01 ppm
for cyanides, and 0.5 ppm for ammonia.
A liquefaction plant processing 23,000
tons of coal per day will require 15 million
gallons of net make-up water (Hittman, 1975:
Vol. II, pp. VIII-12, VIII-14. VIII-18,
VIII-21, VIII-24, VIII-27). Due to the
high value of water in the Northwest area,
it is expected that no water would be dis-
charged from a liquefaction plant operating
there. The assumptions in the data pre-
sented in Table 1-48, which indicates zero
water pollutants in the Northwest area,
are that process wastewater and impounded
runoff are treated and used for cooling
tower make-up, while all blowdown streams
are collected and sent to lined evaporative
ponds.
1.9.3.2.2 Air
Air emissions are presented in Table
1-48 and summarized in Table 1-49. Emis-
sion sources are fuel combustion, the sulfur
recovery plant, and storage. Particulate
emissions are approximately three tons per
1-117
-------
10 Btu's of coal processed, oxides of
nitrogen are 60 to 90 tons, and sulfur
dioxide emissions range from 4 to 30 tons
(Table 1-47). Particulates originate in
fuel combustion (the coal-fired boiler) and
are reduced 99.5 percent by the use of an
electrostatic precipitator and a Wellman
Lord unit. Battelle (1973: 78) assumes
only 98-percent clean-up efficiency, which
results in a greater estimated quantity of
residuals. Particulate emissions from the
coal thermal dryers are reduced by 85 per-
cent through the use of multiple cyclones
and then further reduced to 99 percent by
a baghouse in the CSF process or to 90 per-
cent by a Venturi scrub in the SRC process
before entering the atmosphere (Hittman,
1975: Vol. II, pp. VIII-11, VIII-13,
VIII-17, VIII-20, VIII-23, VIII-26). All
nitrous oxides originate from fuel combus-
tion. Sulfur dioxides originate from fuel
combustion and from the sulfur recovery
plant, which is assumed to be a Claus re-
covery plant with 94.6-percent removal of
the incoming sulfur. Sulfur dioxide emis-
sions vary as a function of the sulfur con-
tent of the coal; they are highest for
Central coal.
1.9.3.2.3 Solids
The principal solid waste from the
liquefaction processes is ash from fuel
combustion. It ranges from 3,200 tons to
12
5,300 tons per 10 Btu's processed. The
lower value is for six-percent ash coal in
the Northwest; the higher value is for
11.3-percent ash coal in the Central area
(Table 1-49). In addition to ash, the
total includes suspended solids removed in
water treatment. For perspective, note
that a 24,000-ton-per-day coal liquefaction
plant would produce half these totals or
The Wellman lord unit uses wet scrub-
bing for removal of particulates and sulfur
trioxide, and a second gas scrubbing with a
potassium sulfite solution for removal of
sulfur dioxide.
1,600 to 2,600 tons each day. This is
equivalent to the daily municipal refuse
generated by 640,000 to 1,040,000 people.
Coal liquefaction is considered a mine-
mouth activity; thus, all solid waste is
returned to the mine for burial.
1.9.3.2.4 Land
Land requirements are estimated at 500
acres for a 24,000-ton-per-day CSF lique-
faction facility and 280 acres for a 12,000-
ton-per-day SRC facility (Hittman, 1975:
Vol. II, pp. VIII-12, VIII-14, VIII-18,
VIII-21, VI-7, VI-9, VI-13, VI-16).
Battelle (1973: 78) estimates that 750
acres are required for a 7,000-ton-per-day
SRC facility.
1.9.3.3 Solvent Refined Solids
Data for residuals in solvent refined
solids processing for two coals—high-sulfur
Central and medium-sulfur Northern
Appalachian—are given in Table 1-48 and
summarized in Table 1-49. Data in both
tables assume that environmental control
technologies are used.
1.9.3.3.1 Water
There are four sources of wastewater
streams: the dissolver unit, the coal
preparation plant, boiler blowdown water,
and sanitary waste. The composition of
waste from these sources and effluent con-
centrations are indicated in Table 1-51.
Treatment includes phenol solvent extrac-
tion, sour water stripping, primary clari-
fication, activated sludge, and secondary
clarification. Total water effluent is
20 million gallons per 10 Btu's coal pro-
cessed or 4.8 million gallons per day for
a typical 10,000-ton-per-day processing
plant. Of the water pollutants released
(Table 1-51, Column 5), only total dis-
solved solids is high, 14 times the Public
Health Service's recommended limit of 500
ppm for domestic water supplies.
1-118
-------
TABLE 1-51
WASTEWATER COMPOSITION FROM SOLVENT REFINED SOLIDS
BEFORE AND AFTER TREATMENT
Parameter
Phenols
Oil
Ammonia
TDS3 .
ssb
CN and SCN°
BODd
COD6
P°4f
Wastewater Stream Discharge
(pounds per hour)
Dissolver
Unit
3,000
3
160
825
51
27
0
0
0
Preparation
Plant
1,100
1,100
0
0
0
0
0
0
0
Sanitary
Waste
0
0
0
0
1.3
0
1.1
1.4
7.4
Boiler
Slowdown
0
0
0
11,043
25
0
0
0
0
Combined Effluents
After Treatment
(parts per million)
0.19
3.88
0.3
7,670
20.6
1.7
0.1
0.1
4.7
Source: Hittman, 1975: Vol. II, pp. VIII-9, VIII-10, VIII-18, VIII-19.
atotal dissolved solids.
suspended solids.
£
cyanide and thiocyanate.
Tjipchemical oxygen demand.
chemical oxygen demand.
phosphates.
1.9.3.3.2 Air
Air pollutants associated with the
solvent refining process consist primarily
of emissions from fuel gas consumption, the
sulfur recovery plant (Glaus plant tail
gas), and the coal preparation plant. Par-
ticulate emissions average 18 tons per
10 Btu's of coal processed and nitrous
-i f\
oxides average 20 tons per 10 Btu's.
Sulfur dioxide emissions are a function of
the total sulfur in the input coal and are
lowest for Northern Appalachian coal (1.8
percent) and highest for Central coal (3.5
percent).
1.9.3.3.3 Solids
Solid waste from the solvent refining
process is a product of combustion of the
filter cake used as supplementary fuel.
The quantity of residue is a function of the
ash content of the coal and is highest for
Central coal (9.4-percent ash). Generated
12
solids average 3,500 tons per 10 Btu's
processed or 700 tons per day for a 10,000-
ton-per-day installation.
The chemical cleaning process described
by Battelle (1973: 76) does not produce
solid wastes (except elemental sulfur) be-
cause no ash is removed.
1-119
-------
TABLE 1-52
SUMMARY OF (1972 ESTIMATED) COAL fooCESSING COSTS
Process
Low-Btu Gasification
Lurgi
Koppers-Totzek
BuMines-Atmospheric
BuMines-Pressurized
High-Btu Gasification
Lurgi
HYGAS-S team-Oxygen
BI-GAS
Syn thane
CO_ Acceptor
Solvent Refined Solids
Liquefaction
CSP Process0
SRC Process3
Cost
(cents per million
Btu's output)3
Appalachian
NA
U
10.4
26.4
NA
40.0
46.5
44.3
NA
29.1
42.4
81.1
Central
NA
U
11.2
29.7
50.1
40.5
47.1
51.6
NA
30.0
42.1
81.3
Northwest
26.9
U
16.8
39.6
55.9
34.5
41.0
45.7
39.0
NA
42.1
80.6
Fixed Charges
as Percentage
of Cost
S
38
38
70
69
62
65
61
47-59
55
51
Average Cost
With Coal at
$6 per Ton
(cents per
million Btu's)
67
U
54
72
103
96
95
96
89
69
86
129
NA = not applicable, U = unknown.
Source: Hittman. 1975: Vol. II.
aAdopted from Hittman by converting to a Btu output basis, coal cost not included.
b!7 to 206 per million Btu's fixed.
cConsol Synthetic Fuel Process.
Solvent Refined Coal Process.
1.9.3.3.4 Land
A typical 10,000-ton-per-day solvent
refining facility requires 200 acres
(Hittman, 1975: Vol. II, footnotes 9307 and
9338).
1.9.4 Economic Considerations
Because the technologies for processing
coal are not fully developed, cost data are
unreliable and subject to frequent revision.
Table 1-52 summarizes Hittman1s cost esti-
mates (1972 dollars) for specific conversion
technologies in various areas assuming a
25-year life on capital equipment, 10-per-
cent fixed charge rate on investment, and
90-percent utilization of capacity.
The quality of the economic data has
been described by Hittman as good (an error
of less than 25 percent) for SRC and fair
(an error of less than 50 percent) for all
other processing technologies discussed
here.
1.9.4.1 Gaseous Fuels
1.9.4.1.1 Low-Btu Gasification
Although data for four low-Btu gasifi-
cation processes are included in Table 1—51.
1-120
-------
complete economic data exists only for
three of the four: BuMines Atmospheric,
BuMines Pressurized, and Lurgi. Total
costs, excluding coal costs, range from
$0.10 to $0.40 per million Btu's, depending
on the technology used and the rank of
coal. Appalachian coal is the cheapest and
Northwestern coal is the most expensive to
process. Although the BuMines Atmospheric
process appears to be the least expensive
technology, the probability of error in
the data means that differences may not be
significant. Processing costs, including
the costs of the coal feedstock, range from
$0.49 to $0.77 per million Btu's.
Low-Btu gasification is treated by
Hittman as a subprocess in an integrated
electricity generation facility. Hittman
calculates that the electric generation
step would add another $0.16 per million
Btu's for a total of 6.5 to 9.3 mills per
kwh.
TABLE 1-53
ESTIMATED PRICES OF SYNTHETIC NATURAL GAS
(CENTS PER MILLION BTU'S)
Technology
Lurgi
HYGAS
BI-GAS
Syn thane
CO_ Acceptor
CO2 Acceptor
Bituminous Coal
Price per Ton
$2.00
61
53
50
45
49
$4.00
88
76
70
63
71
$6.00
115
98
89
81
92
$8.00
142
120
109
99
114
Lignite Price per Ton
$1.50 $3.00
53 79
$4.50
150
Source: OCR, 1972: Table 7, p. 29.
1.9.4.1.2 High-Btu Gasification
Data on six high-Btu gasification
processes are included in Table 1-52. Pro-
cess costs, excluding coal costs, range
from $0.40 to $0.56 per million Btu's de-
pending on the process and rank of coal.
Northwestern coal is generally cheapest to
process, and the CO- Acceptor is the least
expensive technology. Except for Lurgi,
the other processes average about $0.49
per million Btu's. When coal costs are
included, the average is $0.96 per million
Btu's. Note that in the case of natural
gas, a million Btu's is the same as a
thousand cubic feet (mcf) . This means
that Hittman costs average $0.96 per mcf
of gas.
Recently, the total cost for Synthane
was estimated to be $0.85 per mcf; however,
officials at BuMines believe costs will be
$1.75 to $2.00 per mcf higher in 10 years.
Another recent study estimates BI-GAS costs
to be $0.82 per mcf ($0.30 per million
Btu's of coal) (Hegarty and Moody, 1973).
This study indicated that the gasification
facility itself was a small part of the
total fixed investment. The major part of
the capital investment goes for coal prepa-
ration, acid gas removal, sulfur recovery,
utilities, and offsite facilities. The
capital outlay for high-Btu gasification
is 70 percent of total costs (Table 1-52),
which is 20 to 30 percent higher than for
other coal processing technologies.
For comparison with Hittman estimates,
the Office of Coal Research's (OCR) hypo-
thetical prices for high-Btu gas produced
with various technologies and various coal
prices are given in Table 1-53. Column
three of this table compares favorably with
Hittman estimates.
1.9.4.2 Liquid Fuels
Both the CSF and SRC processes are
included in Table 1-52. As noted there,
the SRC process is twice as expensive as
the CSF process when coal costs are ex-
cluded. When coal costs are included, the
1-121
-------
range is $0.86 to $1.29 per million Btu's.
This agrees with OCR's estimate of $0.82
per million Btu's for the Coal-Oil-Gas (COG)
liquefaction process (OCR, 1971). Conti-
nental Coal Development Company estimates
that it will cost between $1.40 and $1.70
(estimated 1978 dollars) per million Btu's
to produce a synthetic crude from coal by
1978. This agrees with the Hittman esti-
mates if they are translated into 1978
dollars (Reichl, 1973: 34).
1.9.4.3 Solvent Refined Solids
For solvent refining, data on only one
process, that developed by the Pittsburg
and Midway Coal Company, are available.
Including coal costs, this process averages
$0.69 per million Btu's. The cost is
slightly cheaper when Appalachian rather
than Central coal is used (Table 1-52),
primarily due to the lower sulfur content
of Appalachian coal. About half the total
cost, excluding coal, is capital outlay;
the other half is operating cost.
When solvent refined coal costs are
added to Hittman*s estimate for electric
power generation, a total cost of $1.362
per million Btu's is obtained ($0.672 for
electric power and $0.69 for processing).
At a rate of 10,000 Btu's per kwh, this
converts to 13.6 mills per kwh.
1.9.4.4 Summary
For the four technology groups, sol-
vent refining and low-Btu gasification are
considerably less expensive overall than
liquefaction and high-Btu gasification.
This is to be expected because the latter
two technologies produce a product ready
for consumer use while the former are feed-
stocks for electric power generation.
1.10 TRANSPORTATION
After mining, coal must be trans-
ported to either a processing facility or
to the place where it is to be consumed.
If it is to be processed, the resulting
TABLE 1-54
METHODS OF COAL TRANSPORTATION
Method
Rail
Barge
Truck
Otherb
Bituminous Coala
69.2
10.7
10.7
9.2
Source: National Coal Association, 1972:
91.
aPercent moved.
Includes tramway, conveyor, and private
railroad.
solid, gaseous, or liquid products also
have to be transported.
1.10.1 Technologies
1.10.1.1 Transporting Raw Coal
Raw coal is almost always moved from
the mine to either its consumption point
or a processing facility by rail, barge,
truck, or pipeline. When barges are used,
the transportation system often includes
moving coal from the mine to a barge load-
ing facility by either truck or train.
1.10.1.1.1 Railroads
As shown in Table 1-54, railroads
(usually either diesel or electrically
powered) currently transport almost 70 per-
cent of all bituminous coal mined in the
*
U.S. Three types of trains are used in
transporting raw coal: conventional, unit,
and dedicated. When conventional trains
are used, cars carrying coal are treated
Data for all coals are not available.
Since bituminous coal represents all but a
small fraction of coal mined, it is safe to
say that rails ship about 70 percent of all
U.S. coal.
1-122
-------
like any other car. Unit trains, on the
other hand, are made up entirely of cars
carrying coal. When coal is transported
by conventional trains, the Interstate
Commerce Commission's (ICC) general rates
apply. In contrast, a special rate, almost
one-third less, applies to unit trains.
Unit trains offer several other advan-
tages, including better utilization of
equipment, elimination of standard railroad
tie-ups such as classification yards and
layover points, and promotion of better
coordination between mine production and
consumers, particularly consumers dependent
on coal being supplied by a single mine
(NAE, 1974: 36-38).
The dedicated railroad, the third rail
option, is used exclusively for transporting
coal. A dedicated railroad is generally
used only when an existing railroad is not
available and when the railroad will link
a mine to a single-source user.
1.10.1.1.2 Barges
As indicated in Table 1-54, barges
move only about 11 percent of the raw coal
shipped in the U.S. In some areas, such
as the Ohio River Valley, barges can be
loaded directly from the mine. When mines
are not located adjacent to a navigable
river, the coal has to be transported to
the barge-loading facility by either truck
or train (usually by train).
1.10.1.1.3 Trucks
Trucks move as much coal as barges do.
Their major advantage is flexibility; their
major disadvantage is that they are not
cost effective for moving large quantities
long distances.
Again, the generalization is based on
the fact that bituminous accounts for more
than 90 percent of all coal produced in the
U.S.
1.10.1.1.4 Pipelines
Slurry pipelines, such as those de-
scribed in Section 1.6, can be used to
transport pulverized coal suspended in
water. When this system is used, the coal
has to be processed to obtain the proper
particle size. Pumping stations, dewatering
facilities, and (in some cases) storage
facilities are also required. The major
advantage of slurry pipelines for trans-
porting coal long distances is low operating
cost (Mutschler and others, 1973: 1) . The
major disadvantages are that capital costs
are high and water requirements are substan-
tial.
A slurry pipeline is currently being
used to tranport coal from Peabody Coal's
Black Mesa, Arizona mine to an electrical
generating plant more than 270 miles away.
This line requires 3,200 acre-feet of water
annually or approximately 11 million gallons
12
per 10 Btu's of coal input (Davis and
Wood, 1974: 1, 2). Although the pipeline
has apparently worked out very well, there
have been problems at the power plant,
primarily in centrifugal dryers used to
prepare the coal for combustion. A slurry
pipeline is being planned that will trans-
port coal from Wyoming to Arkansas, a dis-
tance of nearly 1,000 miles.
1.10.1.2 Transporting Coal Products
As previously described, coal can be
processed to produce solid, gaseous, or
liquid fuels. None of these products pose
any special transportation problems.
Processed solids will probably be
transported in the same manner as raw coal.
Given their low heating value, low- and
intermediate-Btu gases will almost always
be used at or near the site where they are
generated. On the other hand, high-Btu gas
can be economically transported long dis-
tances and is likely to be fed into the
Pipelines are described in more detail
in Chapter 3.
1-123
-------
existing natural gas pipeline complex that
covers most of the U.S.
If produced liquids are to be used as
a refinery feedstock, a single coal pro-
cessing complex might well combine lique-
faction and refining, in which case the
finished product would be transported by
truck, train, barge, or pipeline. These
same modes of transportation could be used
to move the unrefined liquids as well. If
the thickness of the produced liquid makes
pipelining difficult, it will probably be
at least partially refined for easier trans-
portation. Heating the pipeline, the
method chosen by Standard Oil of California
to move heavy crude in Utah, also makes
heavy liquid movement easier (Oil and Gas
Journal. 1973: 24) .
1.10.2 Energy Efficiencies
Only the predominant modes of transpor-
tation used in specific areas are considered
in the analysis of energy efficiencies.
Distances are adjusted to reflect the mile-
age from the mines to major markets for
each region.
The primary efficiencies for coal
transportation given in Table 1-55 have an
error of less than 50 percent and reflect
losses from the wind. These wind losses
account for one percent of the tonnage
shipped by unit trains, barges, and trucks.
Other losses occur mainly during handling
at end points. Losses in conventional
train transportation are two percent.
Spillage at transfer points accounts for a
one-percent loss when covered conveyors are
used. Thus, primary efficiencies are 98
percent for conventional trains and 99 per-
cent for other modes of transportation,
regardless of area. The pipeline slurry
efficiency of 98 percent is not a loss of
coal in transportation but represents a
reduction in the coal's heating value be-
cause of its slurry water content.
Table 1-55 also gives ancillary energy
requirements which are based on the average
haul distance by area for coal transporta-
tion technologies. These data should be
considered poor, with an error of up to 100
percent. Since energies are not given on
an equal haul-distance basis, they are not
directly comparable. The ancillary energy
source for unit trains, conventional trains,
and trucks is diesel fuel. Conveyors and
slurry pipelines use electricity. The
average loads assumed are: unit trains,
10,000 tons per trip; mixed trains, 1,000
tons per trip; and river barges, 25,000
tons per trip. The average truck capacity
is 20 tons.
The range of ancillary energies is
0.4 to 19.0xl09 Btu's per 1012 Btu's trans-
ported. Note that when a conveyor is used
for coal distribution, it is generally in
conjunction with another mode of transpor-
tation (e.g., a barge or train). Haulage
distances for conveyors are short, averaging
five miles. Similarly, trucks are normally
used only between mines and nearby proces-
sing facilities (10 miles average).
On an equal haul-distance basis, river
barges are the most energy-efficient, con-
suming 378 Btu's per ton-mile. Freight
train energy consumption is 690 Btu's per
ton-mile, and truck consumption is 966 Btu's
per ton-mile. Slurry pipelines appear to
be as efficient as river barges.
1.10.3 Environmental Considerations
From the standpoint of resources re-
quired for a technology, the National
Academy of Engineering (NAE) has pointed
out that all new overland transportation
systems will need additional rights-of-way
and new facilities, crews, and rolling
stock. Further, shortages of locomotives,
gondola cars, and hopper cars (NAE, 1974)
already exist. The NAE conclusion is that
railroads and barge systems alone will not
be able to transport all western coal.
Thus, utilization of pipelines is expected
to increase.
1-124
-------
TABLE 1-55
COAL TRANSPORTATION ENERGY EFFICIENCIES
Method
and
Location
Unit Trains
Northwest
Central
Northern
Appalachian
Central
Appalachian
Southwest
Mixed or
Conventional Train
Northwest
Central
Northern
Appalachian
Central
Appalachian
River Barge
Central
Northern
Appalachian
Central
Appalachian
Trucking
Northwest
Central
Northern
Appalachian
Central
Appalachian
Conveyor
Central
Northern
Appalachian
Central
Appalachian
Slurry Pipeline
Primary
Efficiency
(percent)
99
98
98
99
99
98
Ancillary Energy
Reouirement
(10y Btu's per
1012 Btu's
transported)
9.9
15.8
15.8
18.7
5.89
7.82
12.5
12.6
10.7
8.9
21.3
7.76
1.27
1.07
0.96
0.93
0.42
0.37
0.38
7.09
Average Haul
Distance
(miles)
150
290
320
395
100
150
290
320
275
300
800
300
10
10
10
10
5
5
5
273
Source: Hittinan, 1974: Vol. I, Tables 3-12.
1-125
-------
Included in Table 1-56 are environ-
mental residuals for six transportation
technologies by region. Only the predomi-
nant modes of transportation for a specific
region are considered.
1.10.3.1 Water
River barges may contribute dissolved
solids to the river water. Quantities are
unknown but are expected to be negligible.
Drying the coal, after transporting via a
slurry pipeline, produces a water effluent
with negligible amounts of coal in it.
Other modes of coal transportation do not
involve water.
1.10.3.2 Air
Particulates, ranging from 1 to 46
12
tons per 10 Btu's transported (Table
1-56), represent those associated with wind
losses along the route and at the end
points. These data should only be consid-
ered valid to within an order of magnitude.
A two-percent wind loss is assumed for con-
ventional trains as opposed to one percent
for unit trains, river barges, and trucks.
Based on these assumptions, transportation
methods emit more particulates than any of
the technologies in the coal development
system. Other air emissions from transpor-
tation methods are due to diesel fuel com-
bustion; thus, haul distances govern the
magnitude of the total amounts emitted.
In any case, the nitrous oxide and sulfur
dioxide emissions are low, ranging from
0.5 to 4.3 tons and 0.1 to 4.4 tons, re-
spectively, for each 10 Btu's transported.
Comparisons between transportation modes
are not meaningful because equal haul dis-
tances have not been assumed.
1.10.3.3 Solids
No solids are generated by any mode
of transportation, as losses along the
route are assumed to be air residuals.
1.1J>.3.4 Land
Railroad land use requirements for
coal transport are based on the percentage
of coal-to-total rail freight and on the
percentage of coal originating in the area.
Since haul distances are not equal among
the six transportation modes, values given
in Table 1-56 are not directly comparable.
Land utilization for coal transported
12
ranges from 1 to 70 acres per 10 Btu's
transported. Of additional interest are
the assumptions that rail right-of-way
averages six acres per mile (approximately
55 feet wide), a conveyor requires 30 feet
of right-of-way along its length (3.64
acres per mile), and trucks average
1.67xlO~ acres per ton-mile (to within 50
percent error in the data). However, the
Black Mesa slurry pipeline in Arizona re-
quires 62.5 feet of right-of-way along its
length (7.58 acres per mile) and 50 acres
each for four pumping stations.
1.10.4 Economic Considerations
Fixed costs, operating costs, and total
costs for six modes of transportation are
given in Table 1-57. These 1972 estimates
are based on transporting 10 Btu's of
coal typical distances for each mode. The
haul distance assumed is included in column
four of this table, and the cost per ton-
mile is calculated for that distance. As
expected, conveyors and trucking are the
most expensive modes, costing $0.076 and
$0.045 per ton-mile respectively. For long
distances, river barge is cheapest ($0.03
per ton-mile). Slurry pipelines and unit
trains have almost equivalent costs for
overland coal transportation; conventional
trains are more expensive (Table 1-56).
Because of the ICC rate applications men-
tioned earlier, the freight rate for a
typical 300-mile trip is $2.04 per ton for
a unit train and $3.70 per ton for a con-
ventional train.
1-126
-------
Table 1-56. Residuals for Coal Transportation
SYSTEM
UNIT TRAIN
Northwest Coal
Central Coal
Northern
Appalachian Coal
Central
Appalachian Coal
Southwest Coal
MIXED OR CONVENTIONAL
Northwest Coal
Central Coal
Northern
Appalachian Coal
Central
Appalachian Coal
RIVER BARGE
Central Coal
Northern
Central
Appalachian Coal
Water Pollutants (Tons/1012 Btu's)
Acids
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
Bases
NA
NA
NA
1 NA
NA
NA
NA
NA
NA
0
NA
NA
NA
sf
2
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
m
s
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
Total
Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
U
U
Suspended
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
0
0
Organ ics
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
o
0
Q
§
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
0
0
a
8
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
0
0
Thermal
(Btu's/1012)
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
0
0
0
Air Pollutants (Tons/10 Btu's)
Particulates
23.7
20.3
18.4
18.1
20.9
46.3
38.9
35.
33.8
NA
20.
19.7
17.4
X
2.67
4.17
4.28
5.06
1.59
2.12
3.42
3.4
2.89
NA
.794
1.9
.689
X
0
w
2.32
3.7
3.71
4.39
1.38
1.83
2.96
2.94
2.51
NA
.85
2.04
.739
Hydrocarbons
1.78
2.85
2.85
3.38
1.06
1.41
2.28
2.27
1.93
NA
.566
1.22
.443
O
U
2.5
3.99
4.
4.73
1.49
1.97
3.18
3.17
2.7
NA
.67
1.63
.591
Aldehydes
.392
.626
.627
.743
.234
.31
.502
.499
.424
NA
.045
.095
.034
"in
Solids
(Tons/1012 Btu
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
F/I*
Land
Acre-year
w
3
V
m
tM
r— 1
O
i-H
75.1
30.4/0
30.4
27.6
26
.6
67.2
75.1/0
75.1
30.4
27.6/0
27.6
26.6/0
26.6
19.9
NA
NA
NA
Occupational
Health
1012 Btu's
Deaths
.075
.066
.065
.062
.067
.075
.066
.065
.062
0
.0019
.0019
.0019
Injuries
.599
.876
.856
.767
0534
.599
.876
.856
.767
0
.0032
.0032
.0032
.u
0)
s
0)
>1
IB
O
1
C
a
55.6
81.3
79.6
71.4
49.6
55.6
81.3
79.6
71.4
0
.243
.243
.243
-------
Table 1-56. (Continued.)
SYSTEM
TRUCKING
Northwest Coal
Central Coal
Northern
Appalachian Coal
Central
Appalachian Coal
CONVEYOR
Central Coal
Northern
Appalachian Coal
Central
Appalachian Coal
Water Pollutants (Tons/1012 Btu's)
Acids
NA
NA
NA
NA
NA
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
•»
8
NA
NA
NA
NA
NA
NA
NA
m
g
NA
NA
NA
NA
NA
NA
NA
Total
Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
Suspended
Solids
NA
NA
NA
NA
NA
NA
NA
Organics
NA
NA
NA
NA
NA
NA
NA
Q
s
NA
NA
NA
NA
NA
NA
NA
Q
8
NA
NA
NA
NA
NA
NA
NA
Thermal
(Btu's/1012)
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
22,9
19.
17.
16.4
0
0
0
X
g
1,6?
1.4
1.28
1.29
NA
NA
NA
0*
CO
,124
.104
.093
.09
NA
NA
NA
Hydrocarbons
.169
.14
.128
.124
NA
NA
NA
8
1.03
.866
.776
1.754
NA
NA
NA
Aldehydes
.027
.023
.021
.02
NA
NA
NA
"«
Solids
(Tons/1012 Btu
NA
NA
NA
NA
NA
NA
NA
V
Land
Acre-year
to
~S
a
ca
W
w-t
O
i-H
0
1.84/0
1.84
i.67/0
1.67
1.6/0
1.6
.42/0
.42
. 386/0
.386
.376/0
.376
Occupational
Health
1012 Btu's
Deaths
.032
.032
.032
.032
0
0
0
Injuries
.692
.692
.692
.692
0
0
0
*J
to
s
tfl
>1
ID
Q
1
C
ro
E
45.4
45.4
45.4
45.4
0
0
%
NA « not applicable, NC = not considered, U « unknown.
aFixed Land Requirement (Acre - year) / Incremental Land Requirement (—Acres ) .
1012 Btu's 10" Btu's
-------
TABLE 1-57
COSTS OF COAL TRANSPORTATION
(1972 ESTIMATES)
Type
Unit Train
Conventional Train
River Barge
Slurry Pipeline
Trucking
Conveyors
Costs
(dollars per 1012
Btu ' s transported)
Fixed
5,100
9,240
4,850
48,500
1,850
10,500
Operating
79,800
145,000
35,600
20,800
16,700
5,100
Total
84,900
154,000
40,400
69,300
18,500
15,600
Distance Assumed
(miles)
300
300
300
273
10
5
Cost per Ton-Mile
(cents per ton-mile)
0.7
1.3
0.3
0.6
4.5
7.6
Source: Hittman, 1974, Vol. I, Tables 1 and 2 and associated footnotes.
Of the total cost given in Table 1-57
for train transport, fixed costs are six
percent and account only for depreciation.
Fixed costs are 12 percent of the total for
river barge transport and include deprecia-
tion and insurance. Fixed costs are 70
percent for the slurry pipeline and include
power costs and maintenance.
BuMines estimates that transportation
costs account for one-third to one-half of
total costs by the time coal reaches the
point of utilization (Mutschler and others,
1973: 29) . Thus, trade-offs between pro-
cessing coal at the mine site and trans-
porting a different fuel form (e.g., elec-
tricity, oil, or gas) become important.
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1-131
-------
CHAPTER 2
THE OIL SHALE RESOURCE SYSTEM
2.1 INTRODUCTION
Oil shale, "the rock that burns," has
long been known as a potential source of
energy. Early in its history, the U.S.
considered developing a shale oil industry
in Appalachia, but the 1859 discovery of
oil in Pennsylvania provided a cheaper,
more accessible energy source. Interest
in oil shale was revived with the discovery
of rich deposits in several western states
from 1912 to 1915, and that interest was
heightened by a petroleum shortage follow-
ing World War I. However, before any sig-
nificant work was done, huge oil fields
were discovered in Texas, again making oil
shale extraction uneconomical. During the
1950's and 1960's, several processes were
tested for producing a liquid fuel from
oil shale, but the continuing availability
of less expensive crude oil negated commer-
cial development.
Outside the U.S. (generally in coun-
tries where domestic crude oil was limited
and imports were insufficient), oil shale
has been commercially mined and processed
into liquid fuels like those refined from
petroleum. The first commercial processing
occurred in France in 1838; production con-
tinued there and in Scotland and South
Africa until the early 1960's. Currently,
oil shale is commercially processed in
China, Sweden, and Spain; raw oil shale is
being burned to power thermal electrical
generation plants in Estonia and the Federal
Republic of Germany (UN, 1967: 11-13).
If the demand for liquid fuels grows
and the interest in being domestically
self-sufficient continues in the U.S., oil
shale should become increasingly prominent
in the discussion of energy options. A
recognition of this was the Prototype Oil
Shale Leasing Program, announced by the
Department of the Interior (Interior) in
1971 and approved for implementation in
1973. Intended to "provide a new energy
source by stimulating private commercial
technological development" while assuring
"the environmental integrity of affected
areas" (House Committee on Science and
Astronautics, 1973: 54), this program was
designed to lease six federal land tracts
of approximately 5,000 acres each, using
a bonus-bid fixed royalty system. The
program was completed by mid-1974; two
tracts each were leased in Colorado and
Utah, but there were no bids on the two
Wyoming tracts.
The development of oil shale resources
involves six major activities: explora-
tion, mining, preparation, processing,
reclamation, and transportation. This
chapter describes U.S. oil shale resources,
then delineates the activities and tech-
nologies associated with oil shale. In
most cases, a major activity can be
achieved by using any of several techno-
logical alternatives. The principal oil
shale development technologies are shown
in Figure 2-1; these methods, other alter-
natives, and points at which options are
available are identified and discussed.
2-1
-------
2.2
Domestic
Resource
Base
2.4
Surface Mining*
area
2.3
Exploration
2.4
Underground
Minings
room and pillar
2.8
Reclamation
2.6
Preparation
2.7
Retorting*
Bu Mines Gas
Combustion
Union Oil
Tosco H
2.8
Reclamation
2.7
Gasification
•Gaseous Fuels
2.7
In Situ Retorting:
Bu Mines
Occidental
2.7
Upgrading
•Liquid Fuels
•Solid Fuete
2.5 and 2.9
Transportation Lines
Involves transportation
Does not involve transportation
Figure 2-1. Oil Shale Resource Development
-------
2.2 RESOURCE DESCRIPTION
Oil shale is a fine-grained, sedimen-
tary rock containing a solid, largely in-
soluble organic material called kerogen.
When this shale is heated, it releases the
kerogen both as gas and a heavy oil that
can be upgraded to syncrude (synthetic
crude oil) , which is equivalent to a high-
grade crude oil. Deposits of oil shale
axe usually found in a layer or series of
layers, known as a "zone," sandwiched be-
tween other layers of sedimentary rock.
The following portions of this section
describe the total quantity, characteris-
tics, location, and ownership of U.S. oil
shale resources.
2.2.1 Total Resource Endowment
The U.S. Geological Survey (USGS) es-
timates that U.S. oil shale deposits con-
tain more than two trillion barrels (bbl)
of oil. A more speculative estimate, based
on the assumed average hydrocarbon content
of all sedimentary rock in the U.S., is 27
trillion bbl. However, only a very small
portion of these resources could be classi-
fied as "reserves" (both known to exist and
economically recoverable using currently
available technologies).
Although no oil shale is presently
regarded as economically recoverable by the
USGS, 418 billion bbl either border on
being economically producible or are not
producible solely because of legal or
political circumstances (Table 2-1). The
portion of these 418 billion bbl that can
be considered reserves depends heavily on
the economic criterion used, which in turn
depends on assumptions about the production
costs of alternative energy sources. Conse-
^quently, a precise estimate of reserves is
difficult to obtain. For example. Inte-
rior's final Environmental Impact statement
for its Prototype Oil Shale Leasing Program
estimated that 80 billion bbl were actually
recoverable under 1973 conditions (1973:
Vol. I. p. II-6), and the National Petroleum
Council's 1972 review of the U.S. energy
outlook suggested that 129 billion bbl were
recoverable under 1972 conditions (1972a:
208). Using either of these estimates, oil
shale reserves contain more energy than the
total U.S. oil and natural gas reserves.
Another useful comparison may be that the
U.S. used about 4.8 billion bbl or petro-
leum products in 1968 (API, 1971: 283).
2.2.2 Characteristics of the Resource
Oil shale resources are described
primarily by their average oil yields, as
measured by a standardized laboratory tech-
nique called a Fischer Assay. High-grade
shale is normally defined as a deposit that
averages 30 or more gallons of oil per ton
of shale. Low-grade shale averages 10 to
30 gallons per ton. Shale with an average
yield of less than 10 gallons per ton is
normally omitted from USGS resource esti-
mates. Since an oil shale zone is often
composed of a large number of thin layers
with different yields, a zone average may
be composed of widely varying yields.
In addition to yield, several other
factors are important in determining
whether or not an oil shale deposit is
recoverable. These include zone thickness,
overburden thickness, and the presence of
other materials in the shale. National
data for these characteristics are unavail-
able.
As with coal, the amount of overburden
that can be economically removed in oil
shale mining is determined by the zone
thickness. In practice, the minimum zone
thickness considered for mining is 10 to
15 feet. Many high-quality deposits are
known to be well over 100 feet thick (in-
cluding, by definition, all the 418 billion
bbl of identified paramarginal resources).
The presence of materials other than
kerogen in the shale is of interest when
the materials might themselves be recover-
able and marketable. Although data are
sparse, some of the western oil shales are
2-3
-------
TABLE 2-1^
OIL SHALE RESOURCES OF THE U.S.3
(BILLIONS OF BARRELS OF OIL YIELD)
Feasibility
of
Recovery
Recoverable
Pararaarginal
Submarginal"
Knowledge of Resource
Identified^
0
418
1,600
Undiscovered0
Hypothetical
0
300
1.600
Speculative6
0
600
23.000
Sources: Culbertson and Pittman, 1973; Duncan and Swanson, 1965.
Reliability of estimate decreases downward and to the right.
Specific bodies known from geological evidence supported by engineering
measurements.
c
Unspecified bodies of mineral-leasing material surmised to exist on the
basis of broad geologic knowledge and theory.
"TJndiscovered materials that may reasonably be expected to exist in a
known mining district.
eUndiscovered materials that may occur either in known types of deposits
in a favorable geologic setting where no discoveries are made or in as
yet unknown types of deposits that remain to be recognized.
That portion of subeconomic resources that (1) borders on being economi-
cally producible or (2) is not commercially available solely because of
legal or political circumstances.
"The portion of subeconomic resources which would require a substantially
higher price (more than 1.5 times the price at the time of determination)
or a major cost-reducing advance in technology.
known to contain sodium carbonate or sodium
bicarbonate (nahcolite. halite, trona, and
others) and alumina (dawsonite). Eastern
deposits contain small amounts of uranium,
vanadium, other metals, and phosphate.
2.2.3 Location of the Resources
About 90 percent of the identified oil
shale resources of the U.S. are located in
a single geological formation in western
Colorado, Utah, and Wyoming known as the
Green River Formation (Figure 2-2 and
Table 2-2). Other oil shales underlie
large areas in the eastern and central
parts of the 48 contiguous states and
the northern part of Alaska.
The Green River Formation underlies
25,000 square miles of land, some 17,000
of which are believed to contain oil shale
deposits with commercial development poten-
tial. These deposits occur in several
geologic basins (Figure 2-3) and, in many
instances, are exposed at the basin edges
but slant deeply underground toward the
centers. Although substantial deposits
are found in all three states, about 80
2-4
-------
Deposits on the
Green River for-
mation, including
all identified high-
quality resources
Other deposits
Figure 2-2. Distribution of U.S. Oil Shale Resources
Source: Duncan and Swanson, 1965.
-------
HDAHO
UTAH
^f^^^ffK^^i:
I Fossil Basin/:>-'F: >^K'V/V^-.'%VV^:*^i'j:*
A*S*tiv&>ifi»k-i/ (A/
^~r^-. •<>••; ?•*./.!• ••• 'A-y.-.x^-Tysxj
^'^•^^'•^•^^M^^
t.. .Uinta Basin .- ••."•.-•.. • j^AiSv^AfsikVl
j Colofad River
^
Junction
[XvJArea of oil shale deposits
| Area of 25 gal/ton or richer
oil shale 10ft. or more thick
A Location of federal
lease tracts
Green River
1
25 50
miles
Figure 2-3. Oil Shale Areas in Colorado, Utah, and Wyoming
Source: Interior, 1973: Vol. I, p. II-3.
-------
TABLE 2-2
LOCATION OF OIL SHALE RESOURCES3
(BILLIONS OF BARRELS OIL YIELD)
Location
Green River Formation
(Colorado, Utah, and
Wyoming)
Chattanooga shale and
equivalent formations
(Central and Eastern U.S.)
Marine shale (Alaska)
Other shale deposits
TOTAL
Identified
25-100
Gallons
per Ton
418
0
small
0
418+
10-25
Gallons
per Ton
1,400
200
small
small
1,600+
Hypothetical
25-100
Gallons
per Ton
50
0
250
NE
300
10-25
Gallons
per Ton
600
800
200
NE
1,600
Speculative
25-100
Gallons
per Ton
0
0
0
600
600
10-25
Gallons
per Ton
0
0
0
23,000
23,000
NE = not estimated.
Source: Culbertson and Pitman, 1973: 500.
T'or definition of categories, see Table 2-1.
percent of the higher grade zones are in
'Colorado, mostly in the Piceance Basin
(Table 2-3) . The current focus in the
Piceance Basin is on the "Mahogany Zone,"
; a high-quality and relatively accessible
deposit ranging from 100 to 1,000 feet be-
low the surface (except where it outcrops
at the basin edges) and from 30 to more
than 100 feet in thickness. Figure 2-4 is
a schematic cross-section of the Green
River Formation as it occurs in the
Piceance Basin.
The population density of the Green
River Formation Region is about three per-
sons per square mile (Interior, 1973: Vol. I,
pp. 11-11 through 11-16), most of whom live
in small towns in the river valleys adjacent
to the shale lands. Farming, ranching, and
mining are mainstays of the economy. The
arid to semiarid lands overlying the oil
shale deposits are characterized by promi-
nent oil shale cliffs, plateaus, low escarp-
Bents, and some flat lands.
Water is scarce in the region. The
main water supply is the Colorado River and
its major tributaries, such as the Green
and the White Rivers. These rivers are fed
by the winter snows that constitute most of
the region's precipitation. Average pre-
cipitation ranges from seven inches per year
in Wyoming to twenty-four inches per year
in upland parts of the Colorado oil shale
lands. Runoff from oil shale lands is le-
gally committed to agricultural and stock-
watering use, and water in the rivers is
controlled by an intricate system of water
rights covering the entire Colorado River
system. Complicated by annual variations
in stream-flow and conflicting results of
litigation, the actual rights to water are
not always clear.
Regional water quality is an interna-
tional concern because .the increasing sa-
linity of Colorado River water affects both
American and Mexican usage. Since mining
the Colorado oil shale will require using
2-7
-------
south
north
Plateau
Colorado
River
r'r/oVv'AV;vff^S/ ^^;r??Tr'*^^ -:
Mahogany Zone
While
River
Green River Formation
Evacuation Creek member F«Pi*''9;.?-3 Garden Gulch member
Wasatch Formation
Parachute Creek member J Douglas Creek member
Figure 2-4. Diagrammatic Cross Section of Green River Formation
Source: Atwood, 1973: 619 (After Neilson).
-------
TABLE 2-3
OIL SHALE RESOURCES IN THE GREEN RIVER FORMATION
(BILLIONS OF BARRELS)
Location
Piceance Basin
Colorado
Uinta Basin
Colorado and Utah
Wyoming
TOTAL
Resource Class
Class 1
34
0
0
34
Class 2
83
12
0
95
Class 3
167
15
4
186
Class 4
916
294
256
1,466
Total
1,200
321
260
1,781
Source: NPC. 1972a: 207-208.
Classes 1,2: Resources satisfying a basic assumption limiting resources
to deposits at least 30 feet thick and averaging 30 gallons of oil per ton
of shale, by assay. Only the most accessible and better defined deposits
are included. Class 1 indicates the portion of these resources which
would average 35 gallons per ton over a continuous interval of at least
30 feet.
Class 3: Although matching Classes 1 and 2 in richness, more poorly defined
and not as favorably located.
Class 4: Lower grade, poorly defined deposits ranging down to 15 gallons
per ton.
water from the Colorado River and/or its
tributaries to meet mining and processing
needs, these net withdrawals, plus runoff
from the spent shale, may increase salinity
even further.
Although groundwater resources in the
Piceance Basin are not well known, the area
is believed to have substantial water in a
leached zone beneath the Mahogany Zone.
Other basins have more limited prospects.
2.2.4 Ownership of the Resources
About 80 percent of the high-grade
shale lands in the Green River Formation
are owned by the federal government (House
Committee on Science and Astronautics,
1973: 4) . Private lands extend almost
uninterrupted along the southern margin of
the Piceance Basin. Several pilot-scale
development operations have been conducted
on the private lands, and the first commer-
cial-scale operation will be located in
this area. Federal ownership predominates •
elsewhere, although the title to much of
the land is under challenge on the basis
of prior claims not yet litigated (Table
2-4). About 85 percent of the federal oil
shale land has a clouded title. More than
75 percent of the private acreage is con-
trolled by seven firms (Interagency Task
Force, 1974: 100).
2.3 EXPLORATION
Oil shale resource development in-
volves a sequence of activities beginning
with exploration (Figure 2-1) and termi-
nating with the transportation of upgraded
syncrude or refined products. This section
describes the exploration technologies.
2.3.1 Technologies
Exploration activities for oil shale
are essentially the same as those described
for coal: regional appraisal, based heavily
2-9
-------
TABLE 2-4
f
OWNERSHIP OF GREEN RIVER FORMATION OIL SHALE LANDS
(THOUSANDS OF ACRES)
Ownership
Federal oil shale land
(clear title)
Federal oil shale land
(clouded title)
Nonfederal oil shale
lands including
Indian and state
lands
TOTAL
Colorado
320
1,100
380
1.800
Utah
780
3.000
1,120
4,900
Wyoming
70
2,600
1,630
4,300
Total
1,170
6,700
3,130
11,000
Source: Interior, 1973: Vol. I, pp. 11-104 through 11-106.
on inferences from exposed rock formations,
and physical evaluation, involving exten-
sive drilling and coring. The current fo-
cus is on the physical evaluation of tracts
in the Piceance Basin. A large portion of
the exploration effort, past and present,
has been handled by USGS.
2.3.2 Energy Efficiencies
The energy inputs during exploration
are ancillary. Precise amounts have not
been calculated, but the inputs appear to
be small compared to those required by the
other activities.
2.3.4 Economic Considerations
Although no data are available on oil
shale exploration costs, the techniques
are similar to those used for coal and
thus the discussion of exploration costs
in Chapter 1 should be relevant. This
would suggest that costs are less, propor-
tionately, for high-quality deposits,
thicker zones, and deposits close to the
surface. Some regional appraisals are done
by government, and the results (together
with resource data compiled from other
sources) are made available at minimal
direct cost to private developers.
2.3.3 Environmental Considerations
Environmental residuals from explora-
tion are limited to surface and subsurface
physical disturbances associated with dril-
ling and coring and to emissions from ve-
hicles used in the exploration process.
The residuals are usually localized and
small. An estimate of the quantity of dust
produced by these activities has not been
made.
2.4 MINING
As Figure 2-1 indicates, the oil shale
development sequence proceeds in one of two
directions after the exploration stage.
The oil-bearing rock can be mined and then
processed on the surface, or the rock can
be processed underground (in situ) and the
resulting liquids withdrawn by wells. This
section is limited to a description of oil
shale mining; the in situ approach is de-
scribed in Section 2.7, Processing. Al-
though reclamation is a corollary of mining,
2-10
-------
its discussion follows the processing sec-
tion because by-products from surface pro-
cessing are primarily a reclamation problem.
2.4.1 Technologies
Although the broad categories of tech-
nologies used to mine oil shale are similar
to those used in mining coal, the actual
operation and specific equipment items in
an oil shale mine differ significantly from
coal mining, primarily because the charac-
teristics of the two resources are so dif-
ferent. For example, oil shale deposits
are often much thicker than coal seams, and
oil shale is considerably harder than coal.
Like coal, oil shale can be mined
either underground or from the surface.
Although there is no commercial oil shale
mining operation in the U.S. at present,
two prototype underground mines have been
developed and the techniques used in these
mines are believed to be feasible on a
commercial scale. Surface mining of oil
shale has not been attempted in the U.S.,
but two of the four tracts leased in the
prototype leasing program are expected to
be mined from the surface.
2.4.1.1 Surface Mining
In general, surface oil shale mines
involve the same specific activities as
surface coal mines: surface preparation,
fracturing, and excavation.* The drilling,
blasting, and excavation technologies de-
scribed for surface coal mining also apply
to surface oil shale mining. However,
since oil shale zones can be very thick,
sane surface oil shale mines may be deeper
and larger than surface coal mines. These
nines are more like limestone quarries or
open-pit copper mines than coal mines. A
deep mine of this sort is likely to have
several working benches, such as the mine
illustrated in Figure 2-5.
*
See Chapter 1 for a discussion of
these activities.
Primarily for economic reasons, sur-
face mining is likely to be preferred for
very thick (e.g., over 100 feet) oil shale
deposits relatively near the surface. Sur-
face mining might also be feasible for very
thick, deeper seams as well, but the size
of the mine would have to be enormous to
be economical (Hottel and Howard, 1971:
195).
2.4.1.2 Underground Mining
To date, the only oil shale mining in
the U.S., even on a prototype or pilot
scale, has been underground. Although gen-
erally similar to underground coal mining,
underground oil shale mining involves some
significant differences, mainly because of
the greater thickness and hardness of the
producing zones.
Access to a production zone is usually
through a tunnel dug into the side of a
valley where an outcrop appears. (An out-
crop is a place where an underground rock
formation surfaces.) These tunnels are
larger than those found in coal mines but,
in the prototype mines, they have been dug
using conventional drilling, blasting, and
loading equipment and techniques. In a
commercial-scale mine, moles and other ad-
vanced cutting machines might be used. If
such machines are found to be capable of
efficiently cutting materials as hard as
oil shale, they would allow the operation
to proceed more rapidly, be less labor-
intensive, and produce more stable tunnels,
thus requiring less auxiliary support.
However, these machines would be more cap-
ital-intensive and less versatile than con-
ventional equipment, which will probably
be used in the first commercial oil shale
mines (Senate Interior Committee, 1973: 51).
Underground oil shale mines will prob-
ably use the room and pillar approach, pri-
marily because it offers the most efficient
method for mining hard materials underground
2-11
-------
^Rotary
Drill
Figure 2-5. Hypothetical Oil Shale Surface Mine
Source: NPC, 1972b: 51.
-------
(Welles, 1970: 26-30). However, the oil
shale mines will differ from coal mines in
that the rooms and pillars will be larger
(on the order of 60 feet square) and the
floor-to-ceiling clearance will be greater
(ranging from about 60 to 80 feet) (East
and Gardner, 1964: 33). The prototype
method illustrated in Figure 2-6 allows
mining on two levels. First, the upper 30
feet or so are removed, then deeper cuts
are made in selected areas. When the mine
is in full operation, extraction proceeds
on both levels at the same time.
The steps in the oil shale mining se-
quence (fracturing and excavation) are the
same as those for coal, and the technolo-
gies presently used are similar. Rotary
drills prepare holes for blast charges
which fragment a part of the oil shale
zone. After fragmentation, the shale is
loaded onto a large truck or conveyor by
a large front-end loader and moved to a
crushing facility outside the mine. A pre-
liminary study conducted by the U.S. Bureau
of Mines (BuMines) indicates that a contin-
uous miner could be used for excavation
(East and Gardner, 1964: 127) but the sys-
tem has not yet been tested.
Although the extracted material is
almost entirely oil shale, the oil content
of the shale may vary considerably because,
as mentioned earlier, a single zone con-
tains layers of varying quality. Generally,
the mined zone consists of a thick stack of
layers with an average yield of 30 gallons
per ton or higher. Lower yield layers of
oil shale above the mineral zone are treated
as overburden, but there is no separation
of material within the zone into high- and
low-quality seams.
Underground mining is likely to be pre-
ferred whenever deposits are too thin or
deep for surface mining to be attractive.
Room and pillar mines are described
in Chapter 1.
The prototype mines involve more or less
horizontal movement into a 60- to 80-foot
thick deposit from the edge of a basin.
2.4.1.3 Mine Safety
Safety techniques in both underground
and surface oil shale mines should be sim-
ilar to those used in surface coal mines.
Most of the shoring techniques required in
underground coal mines will probably not
be needed in oil shale mines because the
shale's greater strength results in a more
stable roof. However, both expanding-'head
and epoxy roof bolts (as described in Chap-
ter 1) will be used to provide an additional
safety margin.
Since tunnels and rooms will be much
larger, ventilation in oil shale mines
should not be a major problem, and there is
no danger of toxic gases being trapped in
the zone.
2.4.2 Energy Efficiencies
The conditions under which oil shale
resource development will take place may
vary significantly from place to place,
and some of the conditions can be affected
by the scale of the operation. The Hittman
estimates of energy efficiencies and envi-
ronmental residuals for oil shale are based
on a few prototype or pilot mines and thus
are indicative rather than authoritative.
These estimates include assumptions that
the land used will be reclaimed and that
treatment of mining water, as part of the
mining process, will reduce water contami-
nation to zero.
The efficiency of oil shale mining is
assessed by the percentage of in-place oil
shale that is recovered (there is some vari-
ation in how this is defined) and by the
ancillary energy required to power the
mining equipment under controlled conditions.
Although neither is the equivalent of an
overall efficiency measure, these two mea-
sures provide a basis for comparing the
relative efficiencies of surface and under-
ground mining methods.
2-13
-------
Figure 2-6. Small Room and Pillar Oil Shale Mine
Source: East and Gardner, 1964: 33.
-------
TABLE 2-5
ENERGY EFFICIENCIES FOR OIL SHALE MINING
Method
Surface mining
Underground mining
Recovery
Efficiency
(percent)3
62
65
Ancillary Energy ,
(109 Btu's per 1012 Btu's)13
0.57
1.27
Source: Hittman, 1975: Vol. II. Table 3 and footnotes.
These figures appear to be based on different conceptions of how the
"resource in place is defined" (see the text) and are not directly
comparable.
This is calculated on the basis of the energy value of the resource in
place, not the energy value of the resource extracted or that portion of
the mined resource that may be subsequently processed.
2.4.2.1 Surface Mining
Estimates of the recovery efficiency
and ancillary energy requirements for sur-
face mining are presented in Table 2-5.
Recovery efficiency data are estimated to
have errors of less than 25 percent, while
ancillary energies are less certain, with
errors less than 50 percent. The recovery
efficiency for a mine supporting a 100,000-
barrel-per-day processing operation is es-
timated at 62 percent. (The remaining 38
percent consists of lower grade oil shales—
less than 30 gallons per ton—which are not
processed.) This suggests that the effi-
ciency figure is a proportion of all the oil
shale in a deposit, not just a target zone
with especially high yield, because nearly
100 percent of the target zone will be
mined.
Ancillary energy requirements are
almost equally divided between electricity
for shovels and diesel fuel for hauling.
These needs are relatively small, less than
0.1 percent of the energy value extracted.
Data uncertainties are the same as for sur-
face mining. For a mine supporting a
50, 000-barrel-per-day processing operation,
the recovery efficiency is estimated by
Hittman at 65 percent; the remainder is
left in the mine as roof-support pillars to
prevent land subsidence. Here, the effi-
ciency figure is based solely on the target
zone, from which nearly all of the extracted
rock is processed. An underground mining
efficiency comparable to the surface mining
figure, which includes lower-grade deposits
overlying the target zone, is 40 percent.
Although ancillary energy in under-
ground mining is used for the same purposes
as in surface mining, electricity require-
ments are more than six times greater and
diesel fuel requirements are about one-
fifth those of surface mining. However,
the total ancillary energy needs are still
small, approximately 0.1 percent of the
energy value extracted.
2.4.3 Environmental Considerations
2.4.2.2 Underground Mining
Table 2-5 also includes estimates of
the recovery efficiency and ancillary en-
ergy requirements for underground mining.
2.4.3.1 Surface Mining
Just as for other minerals, surface
mining of oil shale involves many forms of
residuals. Table 2-6 gives estimates of
2-15
-------
Table 2-6. Residuals for Oil Shale Mining
SYSTEM
UNDERGROUND
Room an*1 Pillar
SURFACE
flnon Pit
Water Pollutants (Tons/1012 Btu's)
U>
TJ
•H
U
rt
0
0
Bases
0
0
«
8
0
0
m
g
0
0
Total
Dissolved
Solids
0
0
Suspended
Solids
0
0
Organics
0
0
aResiduals are based on 1012 Btu's of energy in the ground, not 1
divide by the primary efficiency. (See text for an explanation.)
bFixed Land Requirement (Acre - year) / Incremental Land Requirem
1012 Btu' s
1
0
0
Q
8
0
o
Thermal
(Btu's/1012)
0
o
Air Pollutants (Tons/1012 Btu's)
Particulates
.354
.013
X
g
.076
.379
X
8
.005
.026
Hydrocarbons
.008
.038
8
.046
.231
Aldehydes
0006
003
'm
Solids
(Tons/1012 Btu
17.5
50300
F/Ib
Land
Acre-year
in
3
4J
m
CM
•H
o
rH
. 04/ . 13
1.97
3.
99
O12 Btu's extracted. To convert the listed values to a base of
ent ( Acres __) .
1Q12 Btu ' s
Occupational
Health
1012 Btu1 s
Deaths
0041
0011
Injuries
189
054
4J
U)
S
U]
>
ro
Q
I
c
(0
MA
NA
1012 Btu's extracted.
-------
air and water pollutants, solid wastes, and
land consumption that would result from oil
shale mining under controlled conditions.
Data uncertainties are on the order of 50
percent. However, total control of water
pollutants will require that surface run-
off be directed away from the mine, that
seepage be used for dust control and recla-
mation, and that any other contaminated
water be either injected into deep wells or
purified before being released. The feasi-
bility of these controls for a commercial-
scale mine.has not yet been demonstrated.
The contamination of groundwater supplies
by saline mine water is a possibility, but
no amount has been estimated.
2.4.3.1.1 Air Pollutants
The air pollution estimates given in
Table 2-6, which amount to less than one
12
ton of air pollutants per 10 Btu's of oil
shale energy in the ground, assume that air
emissions are from vehicular traffic and
that dust will be controlled by water
sprays (a difficult job in a dry area like
western Colorado or Utah) . The data assume
an average conveyor {shovel-to-crusher)
distance of 2,000 feet, an average over-
burden thickness of 450 feet, and a haul
distance for overburden disposal of one
mile. If an actual mine involves more ve-
hicular movement, the residuals will be
higher.
2.4.3.1.2 Solid Wastes
Solid wastes consist of the overburden
removed to expose the oil shale and low-
grade oil shales which are not processed.
During the first 16 years of commercial
production, the expected average quantity
12
of solid wastes is 94,200 tons per 10
Btu's of energy value in the ground; the
expected average over 30 years is 50,300
tons. These estimates assume an average
overburden of 450 feet, a portion of which
will be used to fill mined-out cavities
after the first 16 years of a 30-year mine
lifetime. If a mine is supporting a
100,000-barrel-per-day processing operation,
it will produce an average of nearly 90,000
tons of solid wastes per day—an amount
that would cover 25-plus acres to a depth
of one foot. Obviously, the amount would
be less for a mine with a shallower over-
burden. For information on the handling
of these wastes (and the spent shale from
processing activities), see the descrip-
tion of reclamation activities in Section
2.8.
2.4.3.1.3 Land
As an average, about six acres will be
12
affected for each 10 Btu's of energy ex-
tracted, including the mine pit and the
disposal of overburden and waste shale
(shale averaging less than 30 gallons per
ton in yield). This average assumes that
the disposal will be handled largely by
filling deep canyons near the mine and back-
filling into the mined-out pit (Section 2.8).
Obviously, solid waste disposal accounts
for a major portion of the total land re-
quirement per mine.
2.4.3.1.4 Water Production and Use
Surface mining requires water for dust
suppression and reclamation of solid wastes.
Some water may result from seepage in the
deep mine pit, but the quantities of water
required will usually necessitate an outside-
mine source. The actual mining operation
uses only about two percent of the water
required in a complete oil shale development
trajectory. Solid waste reclamation can
require a much higher percentage (Section
2.8).
2.4.3.2 Underground Mining
Environmental data for controlled
underground mining are shown in Table 2-6.
These data have an error probability of 50
percent or less.
2.4.3.2.1 Water pollutants
Water pollutants are defined by Hittman
as negligible. If low-quality mine water
2-17
-------
with dissolved solids ranging from 200 to
63.000 parts per million (ppm) is encoun-
tered, it is to be used for dust control
and reclamation, filling a need that other-
wise must be met from nearby surface
sources. The possibility exists that water
with higher salinity might be encountered,
and this would be more difficult to treat
or use.
2.4.3.2.2 Air Pollutants
Air pollutant estimates (which total
about one-half ton of material per 10
Btu's of oil shale energy in the ground)
outside the mine include particulates from
both vehicular traffic and blasting with-
in the mine. Other emissions, from vehic-
ular traffic inside the mine, are dispersed
into the atmosphere by exhaust fans.
2.4.3.2.3 Solid Wastes
Solid wastes from underground mining
consist mainly of rock removed to an access
to a high-grade zone. The solid waste data
assume that overburden removal to gain en-
trance to the mine is a onetime activity
rather than a continuing production. The
waste from four mine shafts, if each was
25 feet in diameter and 1,500 feet deep,
would amount to 17.5 tons per 1012 Btu's
in the mined zone. However, this estimate
is less than 0.1 percent of the equivalent
residual for surface mining. Spent shale
is considered in Section 2.7.
12
2.4.3.2.4 Land
Land use is about two acres per 10
Btu's in the ground or about three acres
12
per 10 Btu's recovered. This includes
incremental use of land for the portion of
waste shale disposal that cannot be returned
to underground voids as well as land for
mine openings, equipment storage, mainte-
nance, etc. Subsidence of the land surface
from underground oil shale mining is not
considered likely.
2.4.1".2.5 Water Production and Use
The primary water requirement in under-
ground mining is for dust suppression. Al-
though less dust suppression water (and
considerably less solid waste disposal
water) is needed in underground mines,
shaft and tunnel seepage will probably not
meet total water requirements.
2.4.3.3 Environmental Summary
Environmental residuals are generally
lower in underground mines than surface
mines, particularly in the amount of solid
wastes. The only exception, a minor one,
is the quantity of particulates emitted into
the air, which reflects the greater practi-
cability in surface mines of using water
sprays for dust suppression. This suggests
that, on a basis of environmental impact,
underground mining is preferable.
2.4.4 Economic Considerations
Cost estimates for oil shale mining
are listed in Table 2-7. Underground mining
is perhaps twice as expensive as surface
mining, but larger mines probably reduce
12
costs per 10 Btu's recovered in either
case. In the Hittman estimates, the costs
include the assumptions mentioned above and
environmental pollution controls. The
Hittman estimates have a probable error of
less than 50 percent. Fixed costs include
deferred capital and interest during con-
struction, and operating costs include pay-
roll, supplies, labor, taxes, and insurance.
2.5 WITHIN AND NEAR-MINE TRANSPORTATION
2.5.1 Technologies
Mine transportation consists of mine-
to-crusher (preparation) and crusher-to-
processor links. Oil shale may be moved
from excavations to crushing facilities by
either truck or conveyor. From the crusher
to the processor, the shale normally is moved
by conveyor. The general technologies for
these transportation systems are described
2-18
-------
TABLE 2-7
COSTS FOR OIL SHALE MINING
(DOLLARS PER 1012 BTU'S EXTRACTED)
Method
Underground (room
and pillar)
Surface (open pit)
Hittman Estimates
Fixed Cost
7,740
8,430
Operating Cost
79,300
30,300
Total
87,400b
38.7006
Interageney Oil
Shale Task Force
Total
105,440C
96,940d
90,700f
Source: Hittman, 1975: Vol. II; Interageney Oil Shale Task Force, 1974a: Appendix H.
Estimated costs are strongly influenced by assumptions about mine size.
Mine size: 73,600 tons per day.
c...
'Mine size: 50,000 tons per day.
nine size: 100,000 tons per day.
e...
'Mine size: 147,200 tons per day.
f...
'Mine size: 100,000 tons per day.
in Chapter 1. Surface oil shale mines use
equipment similar to that used in surface
coal mines. In underground oil shale mines,
however, the larger rooms and shafts allow
use of surface-type diesel trucks rather
than the low-profile equipment used in coal
mines. The movement distances are expected
to be short because of the great bulk of
the resource.
2.5.2 Energy Efficiencies
According to the Hittman data, the pri-
mary efficiency of the within and near-mine
transportation options is 100 percent.
Based on a movement distance of one mile,
ancillary inputs for trucks (total diesel
8 12
fuel consumption) are 3x10 Btu's per 10
Btu's transported or about .03 percent.
For a 1,000-foot rise/fall inclined-belt
conveyor, ancillary inputs (electricity)
q 12
.are estimated to be 2.6x10 Btu's per 10
.Btu's or somewhat less than 0.3 percent.
Thus, although a conveyor requires 10 times
more ancillary energy than a trucking system,
both amounts are small in terms of the en-
ergy value of the transported oil shale.
Also, the conveyor estimate apparently in-
cludes an assumption of a steeper grade
than the truck estimate. The energy effi-
ciency and ancillary energy estimates are
considered to be good, with a probable
error of less than 25 percent.
2.5.3 Environmental Considerations
Environmental residual estimates are
listed in Table 2-8 and are considered good
to fair, with an error of less than 50 per-
cent. Water pollution is assumed to be
controlled and thus is zero according to
Hittman. This is apparently based on en-
gineering criteria and has not been demon-
strated on any large scale. Air pollution,
amounting to about one-half ton of pollu-
12
tants per 10 Btu's transported, is limited
to particulate dust from conveyors and
2-19
-------
Table 2-8. Within and Near-Mine Transportation Residuals for Oil Shale
SYSTEM
Conveyor
Water Pollutants (Tons/1012 Btu'a)
Acids
0
0
Bases
0
0
$
0
0
m
g
0
0
Total
Dissolved
Solids
0
0
Suspended
Solids
0
0
Organics
0
0
§
0
0
Q
8
0
0
g £
0
0
Air Pollutants (Tons/10 Btu's)
Particulates
.481
.014
X
g
0
.404
X
o
en
0
.029
Hydrocarbons
0
.04
8
0
.245
Aldehydes
0
.003
tn
3
i>
n
(M
rH
O
•H
n X
•D »
•H C
r-t O
O B
Ul
0
0
V
Land
Acre-year
w
3
CO
CM
rH
O
rH
.04/0
J.94,
.02/0
.02
Health
1012 Btu's
Deaths
U
U
Injuries
U
U
jj
to
a
cu
>i
10
Q
C
ID
S
U
U
— * —
aFixed Land Requirement (Acre - year) / Incremental Land Requirement (
1012 Btu's
Acres — )
Btu's
-------
trucks, and emissions from engine exhaust.
Dust is controlled by water sprays. Oil
shale dust from the loading operation is
also assumed to be suppressed. Solid
wastes are negligible. Land use consists
of one mile of right-of-way, 60 feet wide
for a 48-inch conveyor and 30 feet wide
for a road. Water requirements, which are
almost entirely for dust suppression, can
be considerable for a one-mile truck trans-
portation system in a dry climate.
2.5.4 Economic Considerations
Economic data, shown in Table 2-9,
can be considered fair, with a probable
error of less than 50 percent. They indi-
cate that truck transportation is five or
six times more expensive than conveyor
transportation because of a sharp differ-
ence in operating costs. The conveyor fig-
ures refer to an inclined-belt conveyor
system handling 2,100 tons per hour. The
truck estimates are based on two road
graders, two water trucks, and 50 100-ton
dump trucks. The operating cost advantage
of conveyors is striking (40 to 50 times
less) despite the higher ancillary energy
input required. However, trucks may be the
better choice for a specific mine because
a conveyor is a less flexible piece of equip-
ment, equipment breakdown in a conveyor
system can be more disruptive, and these
transportation costs are a relatively small
TABLE 2-9
WITHIN AND NEAR-MINE TRANSPORTATION
COSTS FOR OIL SHALE
(DOLLARS PER 1012 BTU'S TRANSPORTED)
Method
•Conveyor
Truck
Fixed
Cost
1,490
2.460
Operating
Cost
146
6,740
Total
Cost
1,640
9,200
iSource: Hittman, 1975: Vol. II, Table 3.
part of the total trajectory costs. In pro-
totype mines, the only technology used so
far has been trucks.
2.6 PREPARATION
2.6.1 Technologies
When mined, oil shale tends to break
into large pieces weighing as much as sev-
eral tons. Since the feedstock for pro-
cessing must be within certain size limits,
crushing and sizing is required, with the
activity located near (or even in) the mine
to facilitate transportation. The location
of the crusher depends on the configuration
of the within and near-mine transportation
system.
The crushing is done in several stages.
In one system, the first stage reduces
pieces to less than about one foot in diam-
eter, the second to less than about four
inches, and the third to less than about
three inches. The stages are linked by
conveyor. Beyond this point, preparation
activity depends on the needs of the pro-
cessing technology to be used. If the pro-
cessor cannot accept fine particles, these
particles (smaller than about one-quarter
of an inch) are removed, crushed further,
mixed with oil, and formed into briquettes
large enough to be used. If the processor
can accept fine particles, the three-inch
material is crushed to the maximum particle
size for the process but is not screened.
After any of the crushing stages, the oil
shale may be routed through a storage fa-
cility (stockpiled) as protection against
an interruption in supply. For example,
to guard against processor shutdowns re-
sulting from conveyor breakdowns, a three-
day supply of oil shale may be stored be-
tween the primary and final crushing stages.
The main technological challenge in
the crushing operation is dust suppression.
Figure 2-7 illustrates one concept for this
in the first crushing stage—the conversion
of material direct from the mine into mod-
erate-sized chunks.
2-21
-------
Shed Structure
Srade ft Floor
Line
Pan Feeder,
Primary Crusher
Surge ;vBi
Filtered
Air Exhaust
3in\s
.,/
•'7
9r
Bag House *
_>
0
,Fan
-Screw
Conveyor
To Tunnel Conveyor -To Fine Crushing
Figure 2-7. Primary Crusher Dust Control
Source: Adapted from Colony development Operation, 1974: 178.
-------
2.6.2 Energy Efficiencies
Hittman estimates the primary energy
efficiency for the crushing operation, with
a probable error of less than 25 percent,
to be 98.7 percent. The losses are in dust
and spillage. Ancillary energy inputs, the
power required to operate the crushing
Q 1 £
equipment, amount to 8.4x10 Btu's per 10
Btu's entering the crushing stage or less
than 0.1 percent of the energy value.
2.6.3 Environmental Considerations
Environmental residuals from crushing
are listed in Table 2-10 and should be con-
sidered good, with a probable error of less
than 25 percent. Although wastewater from
wet collection devices is high in suspended
solids and contains a dust suppressant
(sulfonate) , water residuals are assumed to
be zero. This assumption requires that the
wastewater be piped to reclamation areas
and used for irrigation of spent shale,
with any excess runoff from the spent shale
pile being trapped in holding ponds and
recycled. Water requirements for dust sup-
pression are expected to amount to three
to five percent of the total water use in
an oil shale development trajectory in-
volving mining.
Air pollution is in the form of fugi-
12
tive dust and amounts to 0.84 ton per 10
Btu's crushed. This assumes that the
crushing system includes wet and dry dust
collection devices. Solid wastes are
wastes from the dust control devices and
spillage from the crushers. A mine with an
output of 73,600 tons of oil shale per day
would generate about 960 tons of waste oil
shale per day. The land-use figure in
Table 2-10 refers to a 15-acre crushing
operation handling 73,600 tons per day with
three days storage. Because data are avail-
able on only one operation, they are of
questionable validity and should be assumed
to have a probable error of less than 100
percent.
12
2.6.4 Economic Considerations
According to Hittman, the fixed
crushing cost for an oil shale input of
10 Btu's of energy value will be $6,770
(assuming a 10-percent fixed charge rate),
and the operating cost, based solely on
ancillary energy consumption, will be
§1,330. The total cost is $8,100 per 10
Btu's. This assumes a 73,600-ton-per-day
crushing operation. The probable error of
the economic data is less than 100 percent.
2.7 PROCESSING
2.7.1 Technologies
Two stages are involved in the pro-
cessing of oil shale to recover the hydro-
carbons it contains. First, the oil shale
is heated to form gas and oil by a pyroly-
sis reaction called "retorting." ("Pyroly-
sis" is the heating of organic material in
an atmosphere that does not allow complete
oxidation.) Under these conditions, the
solid hydrocarbons decompose, producing a
liquid hydrocarbon and a variety of gases.
In the second stage, the liquid is upgraded
for transportation and use (refineries or
consumers of fuel oil). The major tech-
nology choices have to do with the retorting
stage.
Of the oil shale products, the liquid
(a synthetic crude oil) has received by far
the most attention, and the descriptions
that follow will focus on this syncrude.
The gases are expected to be used within
the processing complex as a source of power
and a source of hydrogen for upgrading.
An oil shale processing complex will
require substantial amounts of electricity
and may therefore involve a power plant at
the processing site. Such a plant would,
of course, be a major consideration in the
calculation of the various residuals. For
example, water use would be significant.
2.7.1.1 Retorting
Retorting may be accomplished either
on the surface after mining or underground.
2-23
-------
2.7.1.1.1 Surface Retorting
Until very recently the only process-
ing approach tested on a pilot-plant scale
was surface extraction of the oil from
mined shale in heating facilities called
"retorts." In this approach, the shale is
prepared (crushed) and heated in a closed
vessel to a temperature between 850 and
950°F, at which the waxy, solid kerogen is
converted into liquid and gaseous hydro-
carbons. The reaction involves a decompo-
sition of carbon compounds rather than their
combination with other inputs. Inputs to
the process are oil shale and heat; outputs
are oil, gas, and spent shale.
Retort yields are compared by reference
to the Fischer Assay yield of an oil shale
sample. The actual yield for a particular
process is determined largely by the method
of introducing heat into the retort. In-
ternal heating uses the combustion of part
of the shale itself to provide the necessary
heat; external heating generates heat in a
separate combustor and transfers the heat
to the reactor in hot solids or gases.
Since it does not make direct use of any
of the hydrocarbons in the shale introduced
into the retort, external heating gives
higher yields but has the disadvantages of
greater complexity and a need for an energy
source for the separate combustor.
The heating method also has an effect
on the sizing of the oil shale injected
into the retort. For internal heating, the
particles have a lower size limit, con-
strained by the need to maintain a flow of
gases inside the retort. External heating
retorts can cope with fine particles. Be-
cause of the difference in feedstock sizes,
the type of retort will determine the tex-
ture of the spent oil shale discharged.
In addition to the hydrocarbon liquid
(called "shale oil"), several other outputs
are characteristic of surface retorting and
upgrading:
1. Gases which are used within the
processing complex for power gen-
eration and as a source of hydro-
gen. The Btu content of these
f gases depends on the retorting
method.
2. Spent shale, from which most of
the hydrocarbons have been removed.
This waste material has a greater
volume than the very dense oil
shale from which it was derived.
Its disposal is the principal
reclamation problem in the oil
shale development sequence (Sec-
tion 2.8) .
3. Water vapor, which forms part of
the pyrolysis gas from retorting.
Therefore, the production of oil
shale is water-forming (Hubbard,
1971: 21-25). The amount of water
varies with the feedstock and the
method of retorting, but it is a
volume equal to about 20 to 40
percent of the oil produced or
two to four percent of the weight
of the shale processed (Hubbard,
1971: 21). The recovered water is
expected to be used in upgrading
and spent shale disposal near the
processing site.
Mined oil shale might be processed by
techniques other than pyrolysis retorting,
but no other method appears technically and
economically feasible at present. Also,
unprocessed oil shale can be burned to gen-
erate heat for electrical power plants
(UN, 1967: 97), but the sulfur and nitrogen
content of kerogen is high and the heating
value of American oil shale is low. The
Institute of Gas Technology has done tests
of the direct hydrogasification of raw oil
shale, producing a gas with a heating value
of 800 Btu's per cubic foot (cf) (as com-
pared to 1000 Btu's per cf for natural gas),
but the process does not appear commercially
attractive at this time (FPC, 1973: VIII-2
through VIII-9).
Internal heating retort processes have
been developed by BuMines and the Union Oil
Company, and an external heating retort
process has been developed by The Oil Shale
Corporation (TOSCO). All three have been
demonstrated in pilot plants, and the two
internal heating processes have recently
been expanded to include an external heating
component. These processes are described
below and compared in Table 2-11.
2-24
-------
Table 2-10. Residuals for Oil Shale Preparation
SYSTEM
fruHhina
Water Pollutants (Tons/1012 Btu's)
Acids
0
Bases
0
8*
0
s"
0
Total
Disso
Solid
0
0)
•o
Suspe
Solid
0
u
c
a
CP
n
0
0
Q
8
0
Q
8
0
CN
i— 1
m w
0) -P
0
Air Pollutants (Tons/10
0)
r-l
3
n
Parti
.84
i
X
0
X
o
in
0
W
c
o
ff
ID
U
0
0
12 Btu
8
0
•s)
n
01
•o
Aldeh
0
m
3
JJ
a
rH
O
» \
•H C
^1 O
O E^
1730.
n
(0
u
Land
1 Acre-
-
3
a
OJ
o
1— 1
.Ut)/u
.08
Occupat iona 1
Health
1012 Btu's
01
Death
U
(0
•H
3
C
H
U
to
o
iJ
Cf)
n
Q
i
c
ID
U
aFixed Land Requirement (Acre - year) / Incremental Land Requirement (—Acres ) .
1012 Btu's iO12 Btu's
Table 2-11. Summary of Aboveground Retort Alternatives
Alternative
Union
(internal
heating)
Gas combustion
(internal
heating)
TOSCO
(external
heating)
Feedstock
Size
(inches)
1/8-53
l/4-3a
less
than 1/2
Cooling
none
none
water
cooled
Oil
Gravity
API
21
20
28
Oil
Sulfur
(percent)
0.77
0.74
0.80
Oil
Nitrogen
(percent)
2.0
2.2
1.7
OUTPUTS
Gas
(Btu's)
100
100
775
Gas
(cubic foot
per barrel)
10,000
10,000
923
Spent
Shale Size
(mean)
0.2 cm
0.2 cm
0.007 cm
Spent Shale
Compounds
oxides
oxides
carbonates
Source: Interior, 1973: Vol. I.
aNeither the maximum nor the minimum feedstock dimension is firmly fixed.
-------
2.7.1.1.1.1 Gas Combustion Retort
The BuMines gas combustion retort,
developed during the 1950's, has served as
a basis for several processes, including
Petrosix and Paraho. In its basic form, it
is a vertical reactor in which crushed oil
shale is introduced at the top while air
and other gases enter near the bottom
(Figure 2-8) . The shale is fed by gravity,
falling downward through four zones in the
reactor. The top zone preheats the shale;
the second zone retorts the shale (heats
the shale to 850 to 950°F, the pyrolysis
level) ; the third zone introduces air to
burn the hydrocarbons remaining in the
shale after pyrolysis, thus heating the
higher zones; and the fourth zone cools the
shale before it is passed through a grate
and removed through a lock hopper.
Recycled gas (mostly inert) flows up
from the bottom, air enters through nozzles
above the cooling zone, and hot gases and
vapor from the combustion and retorting
zones are carried up to an outlet at the
top of the retort. This mist is directed
through centrifugal separators and an elec-
trostatic precipitator to separate the oil
and gas products. Part of the gas is then
recycled to the retort while the rest is
used in a power plant for the processing
complex. An advantage of this process is
that the solids flow through the reactor
without the use of external pumps. The
inputs and outputs of a 50,000-barrel-per-
day processing system, using the Gas Com-
bustion retort, are summarized in Table
2-12.
Cameron Engineers, in cooperation with
Petrobas (the Brazilian national petroleum
corporation) has modified the BuMines pro-
cess to burn recycled gas outside the re-
tort and use the hot gas as the source of
pyrolysis heat (Petrosix). After start-up,
this eliminates combustion inside the retort,
simplifying temperature control and reducing
problems with agglomeration inside the re-
tort. The process is being tested in a
"pilot plant in Brazil.
The Petrosix process has been further
modified by Development Engineering, Incor-
porated, under contract to a consortium of
17 companies and a program of tests is
underway (the "Paraho" program).
2.7.1.1.1.2 Union Oil "A" Retort
Although the Union Oil retort is also
a vertical internal-heating reactor, the
flows in this retort are basically the re-
verse of those in the Gas Combustion retort.
In this process, oil shale is introduced
at the bottom of the reactor by a rock pump,
and air enters at the top (Figure 2-9).
The shale is pumped upward, where it meets
downward-moving air, creating three zones
of activity. At the top, cool air meets
hot spent shale, cooling the shale and
heating the air. Immediately below this
area, in a combustion zone, the hydrocarbons
remaining in the shale are oxidized, pro-
ducing hot gases that heat the lower feed-
stock shale to pyrolysis temperature in a
retorting zone. The retorting produces
shale oil, which is drawn off at the bottom
of the reactor with product gas and steam.
The spent shale leaves the top of the reac-
tor as clinkers.
As in the BuMines design, the heat
transfer properties of the Union Oil retort
negate the need for cooling water. The
advantage of this design over the Gas Com-
bustion design is that oil products cannot,
before vaporizing, drip down to hotter
parts of the reactor and leave heavy resi-
dues that eventually must be removed.
Union Oil has proposed an alternative
system that would use several reactors,
only one internally heated. One would
gasify coke (from retorted shale) to pro-
duce hot gases which would provide pyrolysis
heat to one or more retorts. These gases
would be supplemented by heated recycled
gas (Interagency Task Force, 1974b: 263,264).
2.7.1.1.1.3 TOSCO II Retort
TOSCO II retort is an externally-heated
reactor that uses hot ceramic balls to heat
?-26
-------
Raw oil shale
^O-V'
erAo?V^°KV3-'-0-'(\'>
?^nfe^
i Pro duct cooling a
preheating
'•^o-,-.
\\ v .-• 'tt.\^ . - • >* o • r\" r^v-li i-CV °
ssssfw
o
(Heat recovery S;^
shale cooling
1 •-«•
Retorted shale
Separators,
Precipitate r
Product oil
Dilution gas
Air
Recycle gas
Product
gas
Figure 2-8. Gas Combustion Process
Source: BuMines.
-------
Raw oil
shale
Rock pump
Shale ash
^Combustion
Separators
Precipitator
Product gas
Product oil
Figure 2-9. Union Oil Process
Source: BuMines.
-------
TABLE 2-12
SUMMARY OF INPUTS AND BY-PRODUCTS FOR A
GAS COMBUSTION RETORTING SYSTEM3
(50,000-BARREL-PER-DAY CAPACITY, UPGRADING STAGES INCLUDED)
Input
Quantity
Output
Quantity
Oil shale
Water
73,600 tons per day
5.04 to 8.15 million
gallons per day
Spent shale, air
emissions
Coke
Synthetic crude
oil, at 42 API
Waterb
59,900 tons per day
24 tons per day
2,050 tons per day
50,000 barrels per day
1,750 to 3,000 tons per
day
Source: Hittman, 1975: Vol. II, Table 3 and associated footnotes; Table 16, this
chapter; footnote 13, this chapter; Hubbard, 1971.
Outputs, like low-Btu gas, and inputs, like heat, which are handled internally within
a processing complex are omitted.
See the discussion of water in the environmental considerations section.
the shale to pyrolysis temperature in a
horizontal, rotating kiln (Figure 2-10).
The shale, crushed to less than one-half-
inch size, is fed into a fluidized bed
where it is preheated by hot combustion
gases from a separate ball heater. After
preheating, the shale is moved into the
reactor and mixed with half-inch diameter
heated ceramic balls from the ball heater.
The heat in these balls transfers to the
shale, effecting pyrolysis. The oil,
steam, and gases are given off as a mist,
which is fed to a fractionator for product
recovery. The spent shale and ceramic balls
are discharged from the pyrolysis drum and
separated by a trommel screen. The balls
are returned to the ball heater, and the
spent shale is removed for disposal.
A fractionator (cyclone separator)
separates the oil from the gas output.
The gas is then burned to heat the balls
in the ball heater. Since no combustion
Fluidized-bed reactors are described
in Chapter 12.
takes place in the reactor vessel, the re-
sulting gas has a higher energy content
and the oil a lower viscosity than that
from an internally heated retort. These
features, and the reactor's ability to han-
dle fine particles, are advantages of the
TOSCO II process.
2.7.1.1.2 In Situ Retorting
An alternative to surface preparation
and retorting is underground (in situ) pro-
cessing. The in situ approach involves
fracturing the oil shale underground, intro-
ducing heat to cause pyrolysis underground,
and collecting and withdrawing the shale
oil, through wells, to the surface for up-
grading. Two principal methods have been
suggested: "horizontal sweep," with a py-
rolysis zone advancing horizontally from a
zone of heat injection to a line of liquid
extraction wells, and "mine and collapse,"
with a pyrolysis zone advancing vertically
in a large underground version of an inter-
nal heating retort. Garrett Research and
Development Company, a subsidiary of
2-29
-------
Gas
Air
Flue gas
Preheater
Ground
oil shale
Ball
heater
Fractionator
i Heated balls
[JTromrnel
Product
recovery
Retorted shale
cooling and disposal
Figure 2-10. TOSCO II Process
Source: BuMines.
-------
Occidental, has successfully tested one
"mine and collapse" method at a pilot plant
scale.
Many fracturing technologies are under
study. Liquid chemical explosives, hydrau-
lic pressure, and high-voltage electricity
are being investigated (Hottel and Howard,
1971: 202), and the Garrett test used con-
ventional explosives. Drilling and blast-
ing technologies are described in Chapter 8.
Pyrolysis heat is generated by partial
combustion of the fractured shale through
the use of injected air, a mixture of air
and recycled gas, or another method of oxi-
dation, depending in part on whether the
flow of retorting gases to recovery wells
can be controlled.
The withdrawal of shale oil by wells
involves essentially the same pumping tech-
nologies as for crude oil,* but the wells
are relatively shallow {the overburden is
seldom more than 2,000 to 3,000 feet thick).
There are advantages and disadvantages
to in situ processing compared with mining
and surface retorting (Hottel and Howard,
1971: 202,203; House Committee on Science
and Astronautics, 1973: 14). Advantages
include the avoidance of the costs and en-
vironmental residuals of mining and solid
waste disposal, notably including a large
part of the water requirements. Disadvan-
tages are generally related to the early
stage of technology development for in situ
processing, especially an uncertainty as to
how well combustion can be controlled, and
the low recovery efficiency associated with
current in situ processing technologies.
However, the recent Garrett test indicates
•that these factors may no longer be serious
problems, which improves the prospects of
in situ processing substantially.
Two in situ processes merit specific
description: a BuMines horizontal sweep
approach and the Garrett mine and collapse
method.
See Chapter 3.
2.7.1.1.2.1 Bureau of Mines Process
The BuMines process, shown in Figure
2-11, calls for a series of wells to be
drilled along two opposing sides of an oil
shale deposit. The shale is then fractured
by hydraulic pressure. Because of the
shale's structural characteristics, the
fracturing tends to occur along horizontal
planes (Interior, 1973: Vol. I, p. 1-14) .
The wells on one side are then used to
introduce heat to the formation, either by
pumping air down the wells and igniting
the shale or by pumping down heated retorting
gases which carry the necessary heat for
pyrolysis with them. In either case, the
heat decomposes the kerogen, and the pres-
sure from the injection wells forces the
oil along the fracture lines toward the
opposing wells, through which the oil is
recovered.
In theory, the process operates like
a horizontal retort, with a retorting zone
advancing across the formation ahead of a
combustion zone, pushing the retorted shale
oil ahead of it. This process has been
tested on a small scale, but process con-
trol is difficult because the pattern of
fracturing is still difficult to predict
and it is hard to control the pace and
extent of combustion.
2.7.1.1.2.2 Garrett Process
The Garrett process has been tested
by a 25-gallon-per-day pilot plant opera-
tion near Grand Junction, Colorado (Chew,
1974). The process begins with the excava-
tion of rock from just below the target
zone, using conventional underground oil
shale mining techniques. Shale oil collec-
tor pipes are installed in the floor of
the mined area. From the surface, explo-
sives are then sunk to the top of the for-
mation and used to fracture the oil shale,
filling the mined area and the overlying
part of the zone with fragments. The re-
sult is a large room, 120 feet in diameter
and 300 feet high, containing broken oil
shale intermixed with air. The room is
2-31
-------
AIR AND GAS INJECTION
OIL AND GAS RECOVERY
OIL
SHALE
OVERBURDEN
HOT GASES / X COOL GASES
SHALE OIL
V t
TEMPERATURE \
/ PROFILE 1 X
Gas Drive
Retorting
-Burned Out
Figure 2-11. In-Situ Retorting Operation
Source: Interior, 1973: Vol. I, p. 1-37.
-------
used as a large underground retort, with
fire introduced at the top and air or gas
from the bottom. The downward-moving fire
front releases oil that flows to the bot-
tom and is removed through the collector
pipes.
Garrett envisions .two underground
mines 75 feet apart, each 25 feet in diam-
eter, extending horizontally under rows of
retorts which are fired in retreating or-
der. Pillars and bulkheads separate indi-
vidual retorts, providing combustion con-
trol. The retorts are operated at low-
velocity and low-pressure, burning slowly.
As long as the yield of the oil shale is
above 15 gallons per ton, the combustion
consumes excess carbon, not shale oil. Ac-
tivating 50 retorts at a time would pro-
duce 30,000 to 50,000 bbl of shale oil
daily.
2.7.1.2 Upgrading
The upgrading stage is similar to the
first stage in a conventional crude oil
refinery, and the technologies are similar
to those developed for crude oil refining
(see Chapter 3). Upgrading is usually ac-
complished near the retorting site because
the high viscosity of the heavy shale oil
makes it hard to transport at ambient tem-
peratures and the high sulfur and nitrogen
content of the shale oil complicates con-
ventional refining and use. Some of the
differences between shale oil and pipeline-
quality syncrude are indicated in Table
2-13.
Upgrading includes a number of steps.
Figure 2-12 shows one representative con-
figuration, illustrating the extensive in-
ternal use of products generated by indi-
vidual steps in the process. However, the
production of syncrude from the retorted
shale oil directly involves only the follow-
ing phases:
1. Sulfur and nitrogen removal by
catalytic hydrogenation, using
nickel and cobalt molybdate cata-
lysts to combine hydrogen with
nitrogen (as ammonia, 1013) and
sulfur (as hydrogen sulfide, H2S).
2. Distillation by flash separation,
separating the lighter hydrocar-
bons in the oil from the heavier
ones.
3. Delayed coking, separating the
lighter components from the heavier
stream.
4. Hydrotreating, adding hydrogen to
the lighter liquids to make them
still lighter and less viscous
(more easily flowing).
As indicated above, these technologies
are standard, resembling the first stages
in a conventional crude oil refinery (Chap-
ter 3), and will not be described here.
As Figure 2-12 indicates, the upgrading
stage generates two kinds of outputs in
addition to those from the retorting stage:
1. Coke, a combustible solid output
from the delayed-coking stage in
upgrading. Although this is a
possible fuel source, it does not
appear to be economically feasible
to transport it away from the
processing plant.
2. Chemical by-products from catalytic
hydrogenation and any other
cleaning steps, like ammonia and
elemental sulfur.
2.7.2 Energy Efficiencies
The Hittman estimates provide data on
three alternatives: the Gas Combustion
internal-heating surface retort, the
TOSCO II external-heating surface retort,
and the BuMines in situ retort (all esti-
mates include upgrading but not catalytic
hydrogenation). The efficiency figures
listed in Table 2-14 range from 53 to 67
percent and should be considered to be
accurate to within 25 percent probable
error. It is questionable whether the pri-
mary efficiency of the TOSCO process is as
superior as the estimates show and whether
in situ efficiency is likely to be as high
as 53 percent; Garrett reports 40- to 45-
percent efficiency. Note that in situ
efficiency should be compared with the pro-
duct of mining and surface retorting effi-
ciencies .
2-33
-------
Power for mining,
preparation, retorting,
and upgrading
Power
Plant
Acid Gas
Treatment
Preparation
Retorting
Distillation
v
Hydrogen
Production
V
Hydrotreaiing
Synthetiz
Crude Oil
Spent
Shale
Delayed
Coking
Solids
Liquids
Gases
Electricity
Coke--
alternate heat
source for power
plant, retorting
Figure 2-12. Oil Shale Processing Sequence
Source: Adapted from Hittman, 1974: Tasks 7 and 8, p. V-5,
-------
TABLE 2-13
CHARACTERISTICS OF SHALE OIL AND SYNCRUDE
Oil Type
Shale oil
(TOSCO process)
Syncrude
Typical Viscosity
(Saybolt Universal
seconds at 100°F)a
120
40
Sulfur
{percent
by weight)
0.8
.005
Nitrogen
(percent
by weight)
1.7
.035
Source: Interior, 1973: Vol. 1. p. 1-17. 1-29.
This index refers to the number of seconds required for a standard
quantity to drain out through an orifice of a standard size.
TABLE 2-14
ENERGY EFFICIENCIES FOR OIL SHALE PROCESSING TECHNOLOGIES
Technologies
Gas combustion
TOSCO II
BuMines
in situ
Primary Efficiency
(percent)
53.1
66.7
53.1
Ancillary Inputs
(Btu's per 1012 Btu
0
0
5.99xl010
•s)
Source: Hittman, 1975: Vol. II, Table 3.
The surface retorting methods, togeth-
er with upgrading, are considered to be
self-sufficient (requiring no ancillary en-
ergy inputs) because necessary heating and
electrical power are furnished by internal
by-products. In situ retorting by the
BuMines process has substantial ancillary
requirements, equal to about six percent of
the energy value of the oil shale processed.
Because the recoverable retort gas is ex-
pected to be too low in heating value to be
used for power generation, it is assumed
that natural gas will be purchased to fire
a steam-powered generator. Garrett, how-
ever, reports that they plan to use 50-Btu
off-gas to generate needed electricity
(Chew, 1974) .
2.7.3 Environmental Considerations
Environmental data are presented in
Table 2-15. These Hittman estimates con-
sider residuals from retorting and all the
upgrading steps except catalytic hydrogena-
tion. Retorting residuals are discussed
first, followed by upgrading residuals.
Power generation residuals are grouped with
upgrading residuals where the power gener-
ated is used only for on-site ancillary en-
ergy needs for extraction, crushing, retort-
ing, and upgrading.
Since residuals are given for each of
12
the seven steps on the basis of a per-10
Btu's input to that unit, and since many
of the residuals are absorbed by other
steps, summing the columns of residuals
2-35
-------
SYSTEM
GAS -COMBUSTION
Retorting
Distillation
Delayed Cokinq
Hydrogen Manufacture
Hydrotreatinq
Gas Treat ina
Power Generation
TOSCO II
Retorting
Distillation
Delayed Coking
Hydrogen Manufacture
Hvdrotreatinq
Gas Treating
Power Generation
W
T)
•H
O
0
0
NA
NA
NA
NA
0
0
0
0
NA
NA
NA
NA
0
0
0)
o
in
S
0
0
NA
NA
NA
NA
0
0
0
0
NA
NA
NA
NA
0
0
Water Pollutants (Tons/1012 Btu's)
*
0
0
NA
NA
NA
NA
0
0
0
0
NA
NA
NA
NA
0
0
n
§
0
0
NA
NA
NA
NA
0
0
0
0
NA
NA
NA
NA
0
0
Total
Dissolved
Solids
0
0
.604
.477
U
.604
0
3.4
0
0
604
477
NA
604
0
3.4
Suspended
Solids
0
0
U
U
U
U
0
0
0
0
U
U
U
U
0
0
Organics
0
0
4.3
.0247
U
.733
0
.003
0
0
4.3
0247
U
733
0
003
Q
8
0
0
U
1.02
U
.0863
0
0
0
0
1.73
xlO-3
U
U
0863
0
0
a
8
0
0
U
1.02
U
1.72
0
0
0
0
U
1.02
U
1.72
0
0
CM
rH
O
rH
-i X
re in
u 3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
La for Oil Shale Processing
' — • _
Air Pollutants (Tons/1012 Btu's)
m
V
4->
re
rH
3
U
•H
4J
re
a,
4.
0
0
0
0
0
0
21.5
.2
0
0
0
0
0
0
2.62
35.5
0
0
0
0
0
0
189
12.9
0
0
0
0
0
0
190.
0*
w
30.6
0
o
o
0
o
33.9
155
37.4
0
0
0
0
0
33.9
522.
J Hydrocarbons
a
Q
2 13
1.49
0
1Q A
12 2
0
2.73
2 13
1 49
2.59
n
19.5
8
o
0
o
.194
01
o
o
o
Q
0
Q
.195
(Aldehydes 1
0
0
0
1.46
o
Q
0
o
1.46
^ ™«»»™
m
„ W Jx J
[§ KcJS 3 Solids
u.au«a (Tons/ioi2 Btu-
«A
NA
0
1.08
xlOS
1.08
NA
NA
"A
NA
0
o
F/Ia
L°KLand
L - Pu-Ki Acre-year
l
2.5
2.76
-^A
1.7
.028/
.027
" i ii
to
3
i— 1
O
57B
78
5?0
i5
I
•
'
r
To
5
/O
6
To —
0
8
' —
U
y
U
2.55/0
Occupational
Health
10
in
fl
re
HI
Q
.0014
—«•••— ••••J
.0014
"• M..
U
U
U
-.U _
U
.0006
.0014
.0014
U
U
U
U
" Btu
01
01
•H
tj
p
•ri
C
H
— — . ^
.155
.144
"" -i
V
U
U
U
U
.057
.145
.144
U
U
U
U
U
057
' 8
u
m
s
m
1
.444
U
U
U
U
- V .
U
.2. .3.6
.rti
U
— ^
U
_u_
U
U
2.36
-------
Table 2-15. (Continued)
SYSTEM
BuMINES IN SITU
Retorting
Distillation
Delayed Coking
Hydrogen Manufacture
Hydrotreating
Gas Treating
Steam Generation
Water Pollutants (Tons/1012 Btu's)
Acids
0
0
NA
NA
NA
NA
0
0
Bases
0
0
NA
NA
NA
NA
0
0
•*
2
0
0
NA
NA
NA
NA
0
0
m
i
0
0
NA
NA
NA
NA
0
0
Total
Dissolved
Solids
0
0
.604
.477
NA
.604
0
3.4
Suspended
Solids
0
0
U
U
u
u
0
0
Organics
0
0
4.3
.0274
U
.733
0
.003
a
s
0
0
1.73
xlO-3
U
U
.0863
0
0
o
8
0
0
u
1.02
U
1.72
0
0
Thermal
(Btu's/lQiZ)
0
0
0
0
0
0
0
0
Air Pollutants (Tons/1012 Btu's)
Particulates
6.5
6.22
0
0
0
0
0
7.34
X
7.5
U
0
0
0
0
0
191.
X
o
Ul
264.
262.
0
0
0
0
33.9
.293
Hydrocarbons
160.
151.
2,73
2.13
4.08
2.59
0
19.6
o
o
11.3
11.3
0
0
0
0
0
.19
Aldehydes
.13
U
0
0
0
0
0
3.43
Solids
(Tons/lO1-2 Btu
0
0
NA
NA
NA
NA
0
0
V
Land
Acre-year
to
3
4J
0
(N
r-t
O
1.41/.43
7 84
U/.43
6 47
U
u
u
u
2.55/0
2 55
2.76/0
2 76
Occupational
Health
1 n!2 TJ-t-,-1 i e.
Deaths
.0036
0036
u
u
u
u
u
Injuries
i
.571
569
u
u
jj
w
o
j
VI
>1
ro
O
1
c
ro
.097
NA - not arjnlicable. U = unknown . ' ' ' •-• J '
Fixed Land Requirement (Acre - year) / Incremental Land Requirement
1012 Btu's 1012 Btu's
Acres
-------
will not yield correct totals for the three
processes. Thus, a summary row, represent-
ing the actual total residuals per 10
Btu's of oil shale input to a processing
complex is given in Table 2-15 for the
technologies, and these totals are discussed
in the summary section following the retort-
ing and upgrading discussions. The residual
data are based upon pilot plant operation
and should be considered fair, with a prob-
able error of less than 50 percent.
2.7.3.1 Retorting
2.7.3.1.1 Water
Water residuals from the Gas Combus-
tion and TOSCO II retorting processes are
defined as zero, although large quantities
of water are used and large quantities of
wastewater are generated. Wastewater gen-
erated "in the retorting activity is a re-
sult of boiler blowdown, steam generation,
wet scrubbing, and process water. (Process
water is water driven out of the oil shale
during retorting.) Wastewater from retort-
ing will receive chemical treatment with
lime to remove carbonates (40,000 ppm in
the wastewater), most of the ammonia, and
some organic material. This treated water
will be used for dust control or consumed
in the spent shale disposal system.
Water generated from BuMines in situ
retorting will require primary treatment
with lime and advanced treatment by carbon
absorption and ion exchange resins. Even
though the wastewater will still contain
1,890 ppm dissolved solids after treatment,
it will be suitable for cooling tower make-
up, which is where the treated water is ex-
pected to be used (Hittman, 1975: Vol. II,
27). In theory, then, no effluents will be
released outside the boundary of the oil
shale processing complex. However, the
feasibility of such a pollution control
system has not yet been demonstrated at a
commercial scale.
2.7.3T1.2 Air
Although significant quantities of air
pollutants are generated in both the TOSCO
II and Gas Combustion retorts, air residuals
are zero in Table 2-15 because the tail gas
from the retort is fed to the power plant.
Thus, electrical generation accounts for
all the air pollution from these processes
as total complexes.
In the BuMines in situ retorting ac-
tivity, air residuals are large and result
from flaring the low-Btu product gas. Par-
ticulate emissions are six tons, sulfur
dioxides are 262 tons, and hydrocarbons are
11 tons per 10 Btu's retorted. Nitrogen
oxides are assumed to be present, but the
quantity is unknown. Air residuals from
the Garrett process will be negligible if
the gas is used for power generation.
2.7.3.1.3 Solids
Solid wastes from the retorts are in
the form of spent shale and the amount is
highly significant, over 100,000 tons of
12
waste per 10 Btu's of oil shale retorted
or nearly 60,000 tons per day from a 50,000-
barrel-per-day retorting operation. This
amount of residue would cover 20 acres of
land to a depth of one foot (NPC, 1972b:
67,68) and is greater than the daily solid
waste residuals from surface mining. Ob-
viously, the logistics of moving and dis-
posing of this much material will be formi-
dable. Another point is that the texture
of the solid waste from the Gas Combustion
process and TOSCO II retorts differ. Waste
from the Gas Combustion process is pebbly,
and TOSCO II waste is sandy, even powdery.
Thus, disposal techniques (and costs) must
vary accordingly.
Hittman data assume that the BuMines
in situ retorting technique does not pro-
duce solid wastes. The Garrett process
produces waste rock with a volume equal to
*
Some solids are produced in drilling
the injection wells and chimneys.
2-38
-------
15 to 20 percent of the oil shale pro-
cessed, a sizeable amount but less than 15
percent of the volume from surface process-
ing (not taking into account additional
solid wastes from mining to support surface
processing).
water exiting the gas treating facility
contains hydrogen sulfide and ammonia.
Steam stripping of the sour refinery tail
gas is assumed to remove enough of these
compounds to make the water available for
reuse.
2.7.3.1.4 Land
Fixed land impact for the surface re-
torts is about 10 acres for a 50,000-barrel-
per-day operation. Land use for the dis-
posal of spent shale is not included in the
estimate.
For BuMines in situ retorting, the
land impact is that required for drilling
and restoration. Based on the time average
land impact for the Colorado, Utah, and
Wyoming tracts (Hittman, 1975: Vol. II,
p. V-25), this is 1,088 acres over a 30-
year period. The land impact of the Garrett
process has not been estimated because the
approach to solid waste disposal and recla-
mation is only beginning to be investigated.
If in situ processing is done on a grand
scale far underground, subsidence of the
land surface may be a possibility.
2.7.3.1.5 Water Requirements
The retorting stage of surface pro-
cessing is estimated to use 600 to 700
acre-feet of water per year for a 50,000-
barrel-per-day operation, largely for dust
suppression and, in the TOSCO II process.
Cooling. Water requirements for in situ
processing have not been estimated.
2.7.3.2 Upgrading
Upgrading residuals are given in Table
2-15 for distillation, delayed coking, hy-
drogen manufacture, hydrotreating, gas
treating, and power generation (supplying
power for extracting, crushing, retorting,
and upgrading) .
.2.7.3.2.1 Water
Although water residuals that leave
the plant boundary are given in Table 2-15
as zero for the three processes, the waste-
2.7.3.2.2 Air
Although hydrocarbons are emitted from
each unit in the upgrading process, the
principal source of air pollutants is from
electric power generation (and steam gen-
eration only for in situ). These pollutants
range from 2 to 21 tons of particulates
12
emitted per 10 Btu's of gas input to the
power generation plant, with TOSCO II having
the lowest value and Gas Combustion having
the highest value. Nitrogen oxide emissions
are 189 tons for Gas Combustion and 190
12
tons for TOSCO II per 10 Btu's input to
the power plant. Sulfur dioxide emissions
are 155 tons for Gas Combustion and 522
tons for TOSCO II per 10 Btu's input to
the power plant. The differences reflect
the fact that the retort gases, which are
used as feedstock for the power plants,
have different compositions.
Feedstock for the steam generator used
in the in situ process is assumed to be
purchased natural gas. This explains the
low sulfur dioxide emissions from the in
12
situ steam generator (0.3 ton per 10
Btu's of gas input to the boiler).
2.7.3.2.3 Solids
No solids are assumed to result from
the upgrading process. Not considered are
the solid waste products of the delayed
coking step and solids recovered from
wastewater treatment. Both are small com-
pared to quantities of overburden and spent
shale.
2.7.3.2.4 Land
Land impact is the fixed land required
for facilities. This has not been subdi-
vided unit by unit for the upgrading process.
2-39
-------
Total land impact for retorting and up-
grading is given in Section 2.7.3.3.
2.7.3.2.5 Water Requirements
Water requirements in oil shale pro-
cessing are substantial. The upgrading
stage (for both surface and in situ retort-
ing) uses 1,400 to 2,200 acre-feet of water
per year for processing (mostly as process
water in acid gas treatment and hydrogen
production, along with cooling require-
ments) and another 700 to 1,000 acre-feet
per year for electric power generation
(Interagency Oil Shale Task Force, 1974:
154). The water produced from oil shale
by surface retorting is insufficient to
meet these needs; therefore, water will
have to be acquired from other sources.
Once on hand, the water can be recycled in
some cases, but some continuing inputs of
water are likely to be needed. (The water
requirements for oil shale resource devel-
opment are summarized in Section 2.8.)
2.7.3.3 Summary
Residuals are summarized for the
BuMines in situ, TOSCO II, and Gas Combus-
tion processes in the summary rows of
Table 2-15.
According to the assumptions, no water
leaves the plant boundary; thus, no resid-
uals enter receiving waters. However, the
practicality of the complicated treatment
and recycling system assumed has not been
demonstrated. Further, contamination of
groundwater has not been considered. Air
residuals result principally from power
generation in the TOSCO II and Gas Combus-
tion processes and from both retorting and
steam generation in the BuMines in situ
process. Particulates range from 0.2 to
6.5 tons emitted per 10 Btu's of oil
shale input to the process. The highest is
for BuMines in situ processing. Nitrogen
oxide emissions range from 7.5 to 35.5 tons
with the lowest being for BuMines in situ.
Sulfu'f dioxide emissions range from 30 to
264 tons with the highest being from retort-
ing in the BuMines in situ process; this is
due to flaring the low-Btu product gas.
2.7.3.3.1 Solids
Solids are 108,000 tons of spent shale
per 10 Btu's of oil shale retorted on the
surface. This is the most serious output
residual in oil shale development and has
encouraged the investigation of in situ
processing, where less solid wastes are
generated.
2.7.3.3.2 Land
For the Gas Combustion and TOSCO II
processes, land use is calculated on the
basis of a 320-acre site requirement for a
72,700-ton-per-day processing operation
(50,000 bbl per day). For BuMines in situ
processing, the land use figure represents
230 acres for fixed surface facilities and
0.125 acre per year for well drilling and
restoration.
2.7.4 Economic Considerations
The Hittman estimates of processing
costs are listed in Table 2-16 and are
considered fair, with a probable error of
less than 50 percent. The retorting step
accounts for half or more of the fixed
costs for the surface processing technolo-
gies and slightly less than half for
BuMines in situ processing. Distillation
is the most expensive of the steps in terms
of operating costs. These cost figures and
any evaluation of their impact on profit-
ability are quite tentative because much
of the economic information is proprietary,
the government tax and royalty policy is
subject to change, and the prices of inputs
are constantly changing (NPC, 1973: Chapters
2 and 3). Generally, there should be no
major difference between processes, at least
in a comparison of surface retorting alter-
natives. For example, the TOSCO II retort
2-40
-------
TABLE 2-16
PROCESSING COSTS FOR OIL SHALE
AT A PRODUCTION RATE OF 50,000 BARRELS PER DAY
(DOLLARS PER 1012 BTU'S INPUT)
Process
Gas combustion process
TOSCO II process
BuMines in situ process
Fixed Cost
118,000
75,000
111,000
Operating Cost
332,000
373,000
298,000
Total Cost
489,000a
487,000a
409,000
Source: Hittman, 1975: Vol. II, Table 3.
a
Includes $39,600 in power plant costs not incorporated in fixed or
operating cost estimates.
is more expensive to build than the Gas
Combustion retort, but its recovery is more
efficient, thus reducing costs elsewhere
(Hottel and Howard, 1971: 203).
Table 2-17 presents a different set of
cost estimates, which suggest a higher cost
for in situ processing. Table 2-18 summa-
rizes the anticipated profitability of oil
shale processing as of mid-1974, assuming
that useful by-products are sold. These
estimates indicate that surface retorting
is probably an economically viable energy
option, but late in 1974 the plans for
commercial application of the TOSCO II pro-
cess by Colony Development Operation were
suspended, while prototype experiments with
the Garrett in situ process were proceeding
more optimistically.
Recent estimates (Interagency Oil
Shale Task Force, 1974b: 64-77) indicate a
rate of return (discounted cash flow) of
11 to 16 percent at a $8.35 per bbl selling
price for shale oil (not upgraded) and a
rate of return of 15 to 25 percent at a
selling price of $12.35 per bbl. However,
rising prices for retorts and the possible
expense of reclamation make surface retort-
ing less attractive than this would indi-
cate, and in situ retorting is too untried
as yet for persuasive economic data to be
available.
2.8 RECLAMATION
Reclamation problems in oil shale re-
source ^development not only include the
wide range of problems associated with coal
extraction but also the large quantities of
spent shale resulting from surface retorting.
2.8.1 Technologies
For surface mines, reclamation methods
will be essentially the same as for the sur-
face mining of coal. Spent shale will be
mixed with the overburden that is being
replaced, and the reclaimed area will be
reshaped and revegetated.
In underground mining, some of the
spent shale could be returned to the mine,
but this would be difficult to coordinate
with ongoing mining and would complicate
any future recovery of oil in the pillars.
It is more likely that the spent shale,
together with mining wastes, will be dis-
posed of on the surface.
If mined-out pits are unavailable, one
proposal for surface disposal is a version
of the "head-of-hollow" method sometimes
discussed in connection with contour coal
2-41
-------
TABLE 2-17
f
PROCESSING COSTS FOR OIL SHALE
Method
50,000 barrels per day,
underground mining, surface
processing
100,000 barrels per day,
underground mining, surface
processing
100,000 barrels per day,
surface mining, surface
processing
50,000 barrels per day,
in situ processing, surface
upgrading
Synthetic Crude Oil Cost
Dollars per Barrel
3.45
3.09
3.10
8.50b
Dollars per 10 2
Btu's outputa
614,100
550,020
551,800
1,513,000
Source: Interagency Oil Shale Task Force, 1974a: Appendix H.
aAt 178,000 barrels per 1012 Btu's.
Operating costs only.
TABLE 2-18
REQUIRED SELLING PRICE OF SHALE OIL
(DOLLARS PER BARREL)
Method
100,000 barrels per day,
underground mining,
surface processing
100,000 barrels per day,
surface raining,
surface processing
50,000 barrels per day,
in situ processing, surface
upgrading
Discounted Cash Flow Rates
of Return
12
Percent
5.15
5.52
11.95
15
Percent
6.11
6.63
13.18
20
Percent
7.90
8.70
15.23
Source: Interagency Oil Shale Task Force, 1974a: Appendix H.
2-42
-------
mining. The material would be deposited
in a naturally-occurring deep canyon near
the mine, moistened and compacted, con-
toured to some moderate slope angle, and
shaped to blend into the natural setting.
An upstream reservoir would be built to
catch water that would otherwise flow over
the surface of the embankment, while a dam
downstream would collect rainfall runoff
from it. The embankment would be revege-
tated, which requires the addition of soil
or mulch at the surface and regular water-
ing until plant growth takes hold (or per-
haps longer if a reduction in watering
means that mineral salts in the waste rise
to the root zone of the vegetation, killing
it) . It is possible that enough revegeta-
tion could be attained in two or three
years so that embankment treatment could
be ended (TOSCO, 1973; 7).
It has yet to be demonstrated that the
water pollution controls are manageable in
a situation requiring the disposal of
60,000 tons of spent shale a day, and the
technical and economic feasibility of re-
vegetation at this scale are likewise
unsubstantiated by experience. In addition,
the general approach requires a particular
kind of terrain to be workable and demands
a quantity of water that may be unavailable.
The head-of-hollow approach has been
investigated specifically for the powdery
spent shale from the TOSCO II process.
With the chunkier residues from the inter-
nal-heating retort processes, revegetation
could be expected to be more difficult, and
iihe control of pollution from rainwater
falling on the embankment could be more
difficult because the aggregated material
would be more permeable.
Solid waste from the Garrett in situ
process is broken- marlstone rock, presently
dumped from a valley-side mine mouth. Meth-
ods are being explored for speeding the
natural process of revegetation of steep
jcocky slopes in the Piceance Basin area.
2.8.2 Energy Efficiencies
Reclamation energy efficiencies have
not been separated from the mining and pro-
cessing estimates, but some ancillary in-
puts would be involved apart from trans-
portation of the solid waste to the dis-
posal site. One assessment of the effi-
ciencies of energy systems (Oregon Office
of Research and Planning, 1974) indicates
that external energy subsidies for oil
shale production (including mining, pro-
cessing, reclamation, and other activities)
are higher than for any other system con-
sidered.
2.8.3 Environmental Considerations
No separate estimates exist for resid-
uals from the reclamation effort, but run-
off water from waste piles clearly consti-
tutes a water pollution danger. Water
coming off spent shale under a condition
where runoff rate equals rainfall rate has
been estimated to contain as much as 45
milligrams per liter of sulfates, carbon-
ates, sodium, calcium, and magnesium salts
(Ward and others, 1971).
However, the primary environmental im-
pact of reclamation is likely to be its
consumption of water. Water consumption
estimates for oil shale development are
given in Tables 2-19 and 2-20. For a one-
ntillion-barrel-per-day oil shale industry,
these estimates suggest a need for between
121,000 and 189,000 acre-feet of water per
year, or about 10 percent of the total
water usage in the Colorado part of the
Upper Colorado River Basin in 1970
(Interior, 1973: Vol. I, p. 11-29; House
Committee on Science and Astronautics,
1973: 18,19). Assuming a shale oil heating
value of 5.4 million Btu's per bbl, a 100-
percent load factor, and 58-percent effi-
ciency, this is the equivalent of 36 to 56
acre-feet per 10 Btu's input or 12 to 18
million gallons per 10 Btu's input. This
quantity can be reduced 10,000 to 40,000
acre-feet per year by recovering and re-
cycling water from retorting and upgrading
2-43
-------
TABLE 2-19
f
WATER CONSUMPTION FOR SHALE OIL PRODUCTION
(ACRE-FEET PER YEAR)
Use Category
Process requirements:
•Mining and crushing
Retorting
Shale oil upgrading
Processed shale
disposal
Power requirements
Revegetation
Sanitary use
Subtotal
Associated urban:
Domestic use
Domestic power
Subtotal
TOTAL
AVERAGE VALUE
50,000 barrels
per day of shale
oil, underground
mining
370- 510
580- 730
1,460- 2,190
2,900- 4,400
730- 1,020
0- 700
20- 50
6,060- 9,600
670- 910
70- 90
740- 1,000
6,800-10,600
8,700
100,000 barrels
per day of shale
oil, surface
mining
730- 1,020
1,170- 1,460
2,920- 4,380
5,840- 8,750
1,460- 2,040
0- 700
30- 70
12,150-18,420
1.140- 1,530
110- 150
1,250- 1,680
13,400-20,100
16,800
50,000 barrels
per day of shale
oil, BuMines in
situ processing
0
0
1,460-2,220
0
730-1,820
0- 700
20- 40
2,210-4,780
720- 840
70- 80
790- 920
3,000-5,700
4,400
Source: Interior, 1973: Vol. I, p. 111-34; Interagency Oil Shale Task Force, 1974b: 154.
operations, depending on the processing
technology (House Committee on Science and
Astronautics, 1973: 19), but an oil shale
processing complex clearly would have a
powerful impact on water use patterns in
the region. Generally, water rights law
in the area gives first claim on water to
prior users, which means that the necessary
water might not be obtainable at all
(Interior, 1973: Vol. I, p. 111-70) .
About 50 percent of the water require-
ment is for solid waste disposal and recla-
mation, and very little of this is likely
to be recoverable for recycling. Because
most available water is already committed
to existing activities, the prospects of
massive oil shale development based on sur-
face retorting seem to be severely limited
in the area of the Green River Formation.
The alternatives include: an emphasis on
in situ technologies, which have a smaller
solid waste impact (but which may require
external power for upgrading); the trans-
portation of shale oil to an upgrading site
elsewhere, avoiding the need for local wa-
ter for upgrading; water supply augmenta-
tion in the region, although any method
(e.g., new impoundments) would have envi-
ronmental impacts of its own; a relaxation
of reclamation requirements, which could
result in dramatic environmental impacts
on the region; or development at a rela-
tively low level of activity.
Oil shale development does not con-
sume more water than all other energy sys-
tems. For example, its water consumption
is considerably less than coal gasification
or liquefaction (Davis and Wood, 1974: 12) .
2-44
-------
TABLE 2-20
CONTINGENT WATER CONSUMPTION FORECASTS3
(ACRE-FT PER 1012 BTU'S INPUT FOR A ONE-
MILLION-BARREL PER DAY SHALE OIL INDUSTRY)
Use Category
Process requirements:
Mining and crushing
Retorting
Shale oil upgrading
Processed shale disposal
Power requirements
Revegetation
Sanitary use
Subtotal
Associated urban:
Domestic use
Domestic power
Subtotal
TOTAL
Ancillary development:
Nahcolite/dawsonite
GRAND TOTAL
Lower Range
1.6
2.3
4.4- 5.5
6.2
2.6
0
0.3
17.4-18.5
2.3- 2.9
0
2.3- 2.9
19.7-21.4
NC
19.7-21.4
Most Likely
1.6- 2.1
2.3- 3.1
7.5-11.4
12.2-18.2
3.9- 6.0
0 - 3.1
0.3- 0.3
27.8-44.2
3.4- 4.4
0.3- 0.5
3.7- 4.9
31.5-49.1
NC
31.5-49.1
Upper Range
2.1
3.1
11.4
21.8
9.6-11.7
4.7
0.3
53.0-55.1
4.4
0.5
4.9
57.9-60.0
8.3-16.6
66.2-76.6
NC = Not Considered
Source: Calculated from Interior, 1973: Vol. I, p. 111-44.
a
Assumption: 100-percent load factor, 55-percent recovery factor, and
5.8x10° Btu's per barrel of shale oil.
The central problem is that high quality
D.S. oil shale is located in areas where
water is scarce, and oil shale is too bulky
to transport economically to a location
with more water.
2.8.4 Economic Considerations
The costs of reclamation are included
with cost estimates for raining and process-
ing as appropriate. For the head-of-hollow
method described above, they will be influ-
enced by the depth of the canyons being
filled (which affects the ratio of surface
area to be treated compared with the volume
Of material deposited), and they will
depend significantly on the difficulty of
the water pollution control and revegeta-
tion efforts and the regulations established
as minimum standards for reclamation.
2.9 TRANSPORTATION OF FINISHED PRODUCTS
Long-distance transportation in the oil
shale development system is likely to be
limited to movement of the produced syncrude.
Because shale oil from the retort is so
thick that it is difficult to pump through
pipelines at ambient temperatures (and be-
cause of the possible product linkages be-
tween retorting and upgrading), upgrading
will probably take place at the retorting
2-45
-------
Table 2-21. Environmental Residuals from Transportation of Synthetic Crude Oil Produced from Oil Shale
SYSTEM
Water Pollutants (Tons/1012 Btu's)
Acids
NA
Bases
NA
*f
s
NA
n
i
NA
Total
Dissolved
Solids
NA
Suspended
Solids
NA
Organics
NA
Q
S
NA
o
8
NA
Thermal
(Btu's/lQl2)
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
.2
X
S
4.6
X
8
.3
Hydrocarbons
.5
8
2.8
Aldehydes
04
w
Solids
(Tons/1012 stu
0
V
M
10
0)
>
(
•a a
C M
ra o
lJ <:
63
tn
3
-U
m
N
»H
O
t-H
.6
Health
lol2 Btu's
Deaths
00002
Injuries
0028
4J
tn
S
01
>,
ID
Q
1
C
to
S
085
%
'Fixed Land Requirement (Acre - year) / Incremental Land Requirement (
1012 Btu's
Btu's
-------
location, although it is possible that the
shale oil will, in some cases, be trans-
ported to refineries elsewhere. The main
trade-off will be between the added costs
of transportation of the oil before up-
grading versus the costs of decentralized
refining at each retorting site.
2.9.1 Technologies
The upgraded product liquids can be
transported by truck, railroad, or pipeline
(see the liquid product transportation de-
scriptions in Chapter 1), but the general
expectation is that oil shale processing
vill be linked to a crude oil pipeline net-
work. However, a heated pipeline may be
required to reduce viscosity problems in
transporting oil shale before upgrading
(see the transportation technology descrip-
tions in Chapter 3).
2.9.2 Energy Efficiencies
In pipeline transportation, the pri-
mary efficiency is 100 percent. Ancillary
energy required to pump 172,500 bbl of
syncrude (1012 Btu's) 300 miles is 3.4xl09
Btu's or 0.3 to 0.4 percent of the energy
value of the transported product. These
data are considered good, with a probable
error of less than 25 percent.
2.9.3 Environmental Considerations
Table 2-21 lists the Hittman estimates
of environmental residuals from syncrude
transportation, and these estimates are
considered fair (a probable error of less
than 50 percent). The air pollutants,
totaling about eight tons per 10 Btu's
of oil transported, are emissions from
diesel-engine units pumping the oil through
the pipeline. For additional information
see Chapters 1 and 3.
2.9.4 Economic Considerations
The average cost estimate to transport
10 Btu's of syncrude 300 miles is $25,400
(to within a probable error of 50 percent
or less). For further data, see Chapters
1 and 3.
REFERENCES
American Petroleum Institute (1971) Petro-
leum Facts and Figures. Washington:
API.
Atwood, Mark T. (1973) "The Production of
Shale Oil." Chemtech (October 1973);
617-620.
Chew, Randall T. (1974), personal communi-
cation, November 6, 1974.
Colony Development Operation (1974) An En-
vironmental Impact Analysis for a
Shale Oil Complex at Parachute Creek,
Colorado; Vol. 1, Part 1: Plant
Complex and Service Corridor. Denver,
Colo.: Atlantic Richfield Company.
Culbertson, William C., and Janet K. Pitman
(1973) "Oil Shale," pp. 497-503 in
Donald A. Brobst and Walden P. Pratt
(eds.) United States Mineral Resources,
U.S. Geological Survey Professional
Paper 820. Washington: Government
Printing Office.
Davis, George H., and Leonard A. Wood
(1974) "Water Demands for Expanding
Energy Development," USGS Circular
703. Reston, Va.: USGS.
Department of the Interior (1973) Final
Environmental Statement for the Pro-
totype Oil Shale Leasing Program.
Washington: Government Printing
Office, 6 vols.
Duncan, D.C., and V.E. Swanson (1965)
Organic-Rich Shale of the United States
and World Land Areas, U.S. Geological
Survey Circular 523. Washington:
Government Printing Office.
East, J.H., Jr., and E.D. Gardner (1964)
Oil Shale Mining, Rifle, Colorado,
1944-56, Bureau of Mines Bulletin 611.
Washington: Government Printing
Office.
Federal Power Commission (1973) The Supply-
Technical Advisory Task Force—Syn-
thetic Gas-Coal; Final Report, pre-
pared by the Synthetic Gas-Coal Task
Force for the Supply-Technical Advisory
Committee, National Gas Survey.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts, Efficiency and
Cost of Energy Supply and End Use,
Final Report: Vol. I, 1974; Vol. II,
1975. Columbia, Md.: Hittman
Associates, Inc.
Hottel, H.C., and J. B. Howard (1971) Hew
Energy Technology: Some Facts and
Assessments. Cambridge, Mass.: MIT
Press.
2-47
-------
House Committee on Science and Astronautics,
Subcommittee on Energy (1973) Energy
from Oil Shale; Technical, Environ-
mental. Economic. Legislative, and
Policy Aspects of an Undeveloped En-
ergy Source. Washington: Government
Printing Office.
Hubbard, A.B. (1971) "Method for Reclaiming
Wastewater from Oil-Shale Processing, "
PP- 21-25 in American Chemical Society,
Division of Fuel Chemistry, Preprints,
Vol. 15, No. 1, Symposium on Shale Oil,
Tar Sands and Related Materials.
Lexington, Mass.: ACS.
Interagency Oil Shale Task Force (1974a)
Potential Future Role of Shale Oil;
Prospects and Constraints, for Federal
Energy Administration's Project
Independence Blueprint.
Interagency Oil Shale Task Force (1974b)
Potential Future Role of Shale Oil;
Prospects and Constraints. Final Re-
port, for Federal Energy Administra-
tion's Project Independence Blueprint.
National Petroleum Council, Committee on
U.S. Energy Outlook (1972a) U.S. En-
ergy Outlook. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook, Other Energy Re-
sources Subcommittee (1972b) U.S. En-
ergy Outlook; An Initial Appraisal
by the Oil Shale Task Group, 1971-
1985. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook, Other Energy Re-
>ources Subcommittee, Oil Shale Task
Group (1973) U.S. Energy Outlook; Oil
Shale Availability. Washington: NPC.
Oregon Office of Energy Research and
Planning (1974) Energy Study; Interim
Report. Salem, Ore.: State of Oregon.
Senate Committee on Interior and Insular
Affairs (1973) Legislative Authority
of Federal Agencies with Respect to
Fuels _and Energy. Washington:
Government Printing Office.
The Oil Shale Corporation (1973) Annual
Report. New York: TOSCO.
United Nations, Department of Economic and
Social Affairs (1967) Utilization of
Oil Shale; Progress and Prospects.
New York: United Nations.
Ward, J.C., G.A. Margheim, and G.O.G. Lof
(1971) "Water Pollution Potential of
Spent Shale Residues from Aboveground
Retorting," pp. 13-20 in American
Chemical Society, Division of Fuel
Chemistry, Preprints, Vol. 15, No. 1,
Symposium on Shale Oil, Tar Sands and
Related Materials. Lexington, Mass.:
ACS.
Welles, Chris (1970) The Elusive Bonanza.
New York: E.P. Dutton.
2-48
-------
CHAPTER 3
THE CRUDE OIL RESOURCE SYSTEM
3.1 INTRODUCTION
Since its discovery in 1859, oil has
been a significant factor in our national
growth and development. Although it did
not supplant coal as the primary energy
source until the 1940's, oil was important
well before that, in large part because of
its key role in the development and mass
production of the automobile—and the fun-
damental changes in life style which fol-
lowed.
In more recent times oil has become
the base for many of our necessities, in-
cluding medicinal drugs and clothing
"fibers;" and it is a major substitute for
Other sources of energy. This flexibility
in end use makes oil a particularly valu-
able resource in all industrialized coun-
tries .
The oil industry has grown from a
uniquely American business into a worldwide
operation. Six of the 10 largest U.S. cor-
porations are oil companies, and technol-
ogies developed to produce U.S. oil re-
sources have been the basis for all free
world oil development.
The U.S. was a net oil exporter until
1948, when U.S. consumption exceeded supply
for the first time. Although the change
from exporter to importer created a number
of economic and political problems, depen-
dence on oil imports will probably continue
for the foreseeable future.
The development of oil resources in-
volves four major sequential activities:
exploration, development, refining, and
transportation (Figure 3-1) . In the fol-
lowing sections, world and national oil re-
sources are outlined, the activities and
technologies for recovering those resources
are described, and the efficiencies, en-
vironmental considerations, and economic
considerations for these technologies are
discussed.
3.2 CRUDE OIL RESOURCES
3.2.1 Characteristics of the Resource
Crude oil is a mixture of a large num-
ber of liquid hydrocarbons which can be
separated and altered to produce gasoline,
fuel oil, and other petroleum products. In
describing oil resources, both foreign and
domestic supplies must be considered be-
cause oil may be easily transported; in
1973, imports constituted 4 million of the
17 million total barrels (bbl) per day of
domestic U.S. consumption.
Since various crude oils may contain
over 1,000 different organic (carbon-
containing) compounds, any given crude is
chemically complex (Peel, 1970: 154). Crude
oil is most commonly characterized by its
density. The highest energy oil has a low
density (about 80 percent of that of water),
while the density of low-energy oil is al-
most the same as water. Density is mea-
sured in degrees API (°API) also termed
API gravity. There is an inverse relation-
ship between density and API gravity, hence
API stands for the American Petroleum
Institute, an overall petroleum interest
group.
3-1
-------
3.2*
Domestic resource
base
Onshore, lower 48
Alaska
Offshore
I
I
I
I
V
3.3
Exploration
3.2
Extraction
Drilling
3.3/3.4
Production
Primary
Waterflooding 3.4
Improved
fmmiseible polymers
& surfactant flooding
Miscibfe flooding
Inert-gas processes
Thermal processes
Import resource
base
Crude oil
Refined products
3.5
Refining
T-M_iquid Fuels
i *
involves transportation
does not involve
transportation
* Section containing description of process.
3.6 Transportation Lines
Figure 3-1. Crude Oil Resource Development
-------
crude oils range from less than 10 API,
corresponding to a very heavy tar or
asphalt-like crude, to above 50°API, corre-
sponding to a light, highly volatile crude.
Value is generally related to API
gravity (the higher the API gravity, the
more valuable the crude), although other
factors also affect crude oil price. Most
crude oil being produced worldwide at
present ranges from 30 to 37°API, with the
feedstocks for U.S. refineries averaging
about 36°API (Peel, 1970: 161, 162).
The sulfur content of a crude is im-
portant because it has a major impact on
air quality if retained in refinery pro-
ducts. Sulfur may be present in crude oil
as dissolved gaseous hydrogen sulfide or as
sulfur-containing organic compounds. As
shown in Figure 3-2, the sulfur content of
crude decreases with higher API gravity for
crudes of a particular geographic region.
However, regional variations dominate.
For an API gravity of 36°, Middle East
crudes contain between 1.4 and 2.1 percent
sulfur, while most U.S. or Venezuelan crudes
contain between 0.1 and 0.6 percent sulfur.
North African, Turkish, West Texas, and
California crudes have high sulfur contents,
while Nigerian, Canadian, some East Indian,
and the remaining U.S. crudes fall into one
low-sulfur category (Peel, 1970: 163, 164) .
Because of the odor of hydrogen sulfide,
low-sulfur crudes are termed "sweet" and
high-sulfur crudes are termed "sour." Sweet
crudes usually contain less than one percent
sulfur.
3.2.2 Domestic Resources
3.2.2.1 Quantity of Domestic Resources
Although one 1971 estimate of total
U.S. oil resources was 810 billion bbl
(NPC, 1972: 72), more recent oil resource
estimates are much lower. A 1974 U.S.
Geological Survey (USGS) estimate put the
upper limit at 400 billion bbl, while a
major oil company estimated only 88 billion
bbl (Gillette, 1974: 128). These esti-
mates of the quantity of oil yet to be dis-
covered or recovered are obviously subject
to considerable uncertainty.
U.S. reserves (that portion of identi-
fied resources which can be economically
extracted now) are estimated to be 50
billion bbl (NPC, 1974: 50) which, at the
present levels of consumption, is at most
a nine-year supply (NPC, 1972: 85). Al-
though this appears small, U.S. reserves
have never been greater than an 11- or
12-year supply, possibly because they can
be considered inventory and inventories
larger than 10 years may not be economically
advantageous.
3.2.2.2 Location of the Resources
Oil has been found in most parts of
the U.S. Information on U.S. reserves and
resources is frequently divided into two
categories, onshore and offshore, and two
regions, the lower (coterminous) 48 states
and Alaska. Estimates of oil resources in
these categories and regions are shown in
Table 3-1. U.S. reserves are estimated at
50 billion bbl, of which 34.2 billion bbl
are onshore in the lower 48 states, 6.2
billion bbl offshore, and 9.6 billion bbl
onshore in Alaska (NPC, 1974: 50).
3.2.2.3 Ownership of the Resources
In the past, ownership has had less
impact on oil resource development than on
coal resource development. Because of the
high value of oil resources and because oil
resource development has had relatively
limited impact on surface land use, private-
ly owned land has been developed with little
problem. However, oil-bearing lands owned
by the government are becoming increasingly
significant. The federal government owns
most of the offshore acreage outside the
3-3
-------
Q>
•a
o
"o
3
CO
% Sulfur Allowed In
Boiler Fuel By CFR40
API Gravity
Figure 3-2. Sulfur Content and API Gravity of Crude Oils
Source: Peel, 1970: 164.
-------
TABLE 3-1
UNITED STATES OIL RESOURCES
Location
Onshore
Alaska
Lower 48 states
Subtotal onshore
Offshore3
Atlantic
Alaska
Gulf of Mexico
Pacific Coast
Subtotal offshore
Total United States
Petroleum Liquid
Resources
(billions of barrels)
uses
Low
<.25j
110
135
10
vJ03
20
nr/"
65
200
High
50
220
270
20
60
40
10
130
400
Source: Gillette, 1974: 128.
I'D a water depth of 660 feet.
three-mile limit, and federal ownership
onshore is significant in Alaska and the
western states. The federal government is
estimated to control 15 percent of domestic
crude oil reserves, 11 percent on the Outer
Continental Shelf (DCS) and 4 percent on-
shore. Federal resource ownership is es-
timated to be 37 percent, 30 percent on
the OCS (which has not yet been extensively
explored) and 7 percent onshore. The fed-
eral government owned 16 percent of all
The exceptions are Texas and
Florida's west coast where state ownership
extends out to nine miles. Other states'
claims to ownership beyond three miles are
still being adjudicated.
1972 U.S. oil production (Ford Foundation,
1974: 271).
3.2.2.4 Regional Overview
3.2.2.4.1 Onshore, Lower 48 States
The area of the coterminous U.S. with
prospects for oil discovery, either by
virtue of previous discovery or promising
geology, is approximately 1.7 million
square miles, with a sedimentary rock vol-
ume of 3.2 million cubic miles (NPC, 1970:
1). Present production in the lower 48
states is about 11 million bbl per day
(NPC, 1974: 27) from reserves of 34.2
billion bbl, and reserves are being found
at about 3.4 billion bbl per year (NPC,
1974: 27). Reserve additions in the lower
3-5
-------
48 states will come from three major
sources: wells in previously undrilled
areas, deeper wells, and additional re-
covery from known fields. As new discov-
eries are made, more is learned about geo-
logical formations that might contain oil
resources. Other areas where such geo-
logical formations occur then become prom-
ising, and drilling activity is initiated
in such areas (NPC, 1970: 3). The ability
to drill deeper wells and the discovery of
petroleum in rocks at extreme depths sug-
gest that a great volume of unexplored
sedimentary rock may have promise, although
wells deeper than 16,000 feet will probably
produce gas rather than oil (McCulloh, 1973:
488). Also, the reserves in known fields
can be increased by using techniques to
recover oil that remains in place after
natural drive mechanisms have been depleted.
3.2.2.4.2 Alaska
The prospective area for petroleum
discovery in Alaska lies under approximately
85,000 square miles and has a sedimentary
rock volume of 215,000 cubic miles (NPC,
1970: 6). This area can be divided into
three provinces—North Slope, Cook Inlet,
and Pacific Margin—as shown in Figure 3-3.
Of these, the North Slope is the most prom-
ising and is currently the subject of con-
siderable exploratory attention (as well as
political controversy because of the trans-
Alaska pipeline). The Cook Inlet is now
producing gas and some oil, with new petro-
leum expected from extensions of present
fields rather than significant new finds.
New areas in the Pacific Margin province
are almost all offshore and thus have not
yet been drilled, although geophysical and
geological analyses have been made.
Alaskan reserves at present are about 10.5
billion bbl, 9.6 billion of which are on
the North Slope (NPC, 1974: 50). Prospec-
tive areas in Alaska have winter climates
and frequent earthquakes (CEQ, 1974: 1-22).
3.2.2.4.3 Offshore
Offshore oil resources are contained
almost entirely on the DCS and thus are
federally owned. State-owned resources
offshore include only ahout_.lQ. percent of
potential production on the continental
jSheJLf. Petroleum resources on the OCS to
a water depth of 200 meters are estimated
to be between 54 billion bbl (Gillette,
1974: 127) and 710 billion bbl (Kash and
others, 1973: 315, 316). A number of spe-
cific regions of the OCS have been identi-
fied in the Bureau of Land Management (BLM)
tentative lease schedule for development by
1985. These include the Gulf of Mexico,
Pacific Coast, Atlantic Coast, and Alaska.
Most present production is taking place in
the Gulf of Mexico. Production in 1972
from the Gulf was about 1.05 million bbl
per day (Kash and others, 1973: 319), with
reserves of 3.2 billion bbl. Estimates are
that an additional 2.5 to 5 billion bbl of
reserves will be discovered (BLM, 1972: 7) .
Production in the Pacific region is in the
Santa Barbara channel and was about 0.1
million bbl per day in 1972. Resources for
the Pacific region are estimated to be about
nine billion bbl, in both the Santa Barbara
channel and outside the channel islands
(Kash and others, 1973: 320).
No exploratory drilling has been done
on the Atlantic OCS, although discoveries
have been made offshore of Nova Scotia in
Canadian waters. A number of areas with
considerable potential have been identified,
and resource estimates of 48 billion bbl
have been made by the USGS (Kash and others,
1973: 320).
Areas on the Alaskan OCS with petro-
leum potential include Bristol Bay, Lower
Cook Inlet, Prudhoe Bay, and the Gulf of
Alaska. The extreme environmental condi-
tions of the Alaskan OCS will probably pre-
clude exploratory drilling in the near fu-
ture (CEQ, 1974: 1-22) . Resources on the
Alaskan OCS have been estimated at 62 bil-
lion bbl (Kash and others, 1973: 320) .
3-6
-------
Arctic Slope
Province
Pacific Margin Prov.
Cook Inlet Prov.
Figure 3-3. Alaskan Oil Provinces
Source: NPC, 1970: 16.
-------
TABLE 3-2
WORLD OIL RESERVES BY COUNTRY
AS OF 1970a
Country
Asia-Pacific
Australia
Brunei-Malaysia
Indonesia
Total Asia-Pacific
Europe
Norway
United Kingdom
Total Europe
Middle East
Abu Dhabi
Iran
Iraq
Kuwait
Neutral Zone
Oman
Qatar
Saudi Arabia
Syria
Total Middle East
Africa
Algeria
Egypt
Libya
Nigeria
Total Africa
Western Hemisphere
Argentina
Colombia
Mexico
Venezuela
United States
Canada
Total Western Hemisphere
Communist Countries
Russia
Red China
Hungary
Total Communist
Reserves
(billions
of barrels)
2
1
10
14.4
b
1D
lb
3.7
11.8
70
32
67.1
25.7
1.7
4.3
128.5
1.2
344.6
30
4.5
29.2
9.3
74.8
4.5
1.7
3.2
14
37C
10.8
73.9
77
20
1
100
Source: NPC, 1971: 46-47.
Only countries with reserves exceeding one
billion barrels are listed.
North Sea reserves have increased dramat-
ically since 1970. /
CA recent (1974) estimate is 50 jmjLllion
barrels (see text). \* 7-3~)
3.2.3 World Resources
Wo^3-d oil reserves are shown in Table
3-2. U.S. reserves are only about 11 per-
cent of the total free world reserves
(NPC, 1974: 102). In 1973, the U.S. im-
ported about four million bbl of oil per
day. Of this, two million bbl per day
were from Venezuela, one million from
Canada, and one million from the Mideast.
Since the Mideast has 62 percent of the
world's proven reserves, future increases
in imports are likely to come from this
area, oil supply is international in scope
because the largest consumers are unable to
meet their demands from domestic sources .
3.2.4 Summary
The major conclusion with regard to
U.S. oil resources is that they are inade-
quate to satisfy the present or anticipated
needs of the country. Therefore, the U.S.
must either continue importing oil for the
foreseeable future, reduce average yearly
energy consumption drastically, or develop
alternate sources and technologies for
using a different mix of fuels.
Two other conclusions can be drawn
from this resource description. First, new
petroleum reserves will be developed to a
great extent in areas where severe environ-
ments prevail, such as Alaska, the offshore
Atlantic, and on the Alaskan OCS. If these
areas are to be developed, the technologies
used must be adequate to meet the demands
of these environments (White and others,
1973: 149).
Second, sulfur control technologies
will be needed for most imported crude, and
for some U.S. crude, so that fuels refined
from these crudes will be acceptable under
present environmental regulations.
3.3 EXPLORATION
As mentioned earlier and diagrammed in
Figure 3-1, oil resource development entails
a sequence of activities beginning with ex-
ploration and ending with transportation of
refined products. In the following section
3-8
-------
the technologies, efficiencies, residuals,
and economic costs associated with explor-
ation will be identified and described.
3.3.1 Technologies
Exploratory activities are undertaken
to locate geological formations that are
potential oil reservoirs. These activities
progress through three principal phases:
1. Regional surveys to identify
promising geological conditions.
2. Detailed surveys on which eval-
uations of specific areas are
based.
3. Exploratory drilling to determine
whether oil is actually present
in a specific area.
3.3.1.1 Regional Surveys
The oil industry is engaged almost
continuously in regional surveys. Often
made by air or from boats, survey methods
are generally passive in nature and include
measurements of changes in the earth's mag-
netic field and local variations in the
earth's gravity. These measurements aid in
identifying irregularities in subsurface
geology and, thus, potential geological
traps in which gas or oil may have accumu-
lated. Regional surveys also look for
natural oil seeps. The purpose of regional
surveys is to identify areas where more
detailed exploratory activity may be jus-
tified.
3.3.1.2 Detailed Surveys
When the decision is made to under-
take a more detailed investigation of a
particular area, seismic surveying and core
drilling are the exploration techniques
most commonly used. In a seismic survey,
an energy source is used to generate sound
waves which are reflected and refracted by
the underlying geologic strata. The echoes
are picked up on acoustic detectors and
recorded on magnetic tape. These data are
then digitized and computer processed to
prepare cross-sectional maps of the area
being surveyed.
Onshore, explosives are used as the
source of acoustic waves for seismic work;
offshore, explosives have been replaced by
contained detonations of propane and oxygen.
Another acoustic source, used both onshore
and offshore, is the VIBROSEIS, which uses
a high-powered oscillator whose frequency
changes continuously over a period of a few
seconds.
Recent advances in computer processing
of seismic data may provide methods for
direct detection of petroleum reservoirs
(Lindsey and Craft, 1973: 23-25). Appar-
ently, natural gas reservoirs and oil res-
ervoirs with natural gas caps can now be
located from offshore seismic data.
Core drilling of shallow holes is also
employed in detailed investigations. On
the OCS, core drilling is only allowed
after receipt of a special permit, and
depths are limited to 1,000 feet or less.
Onshore, depths are usually limited by the
land owner.
3.3.1.3 Exploratory Drilling
Exploratory drilling for oil is done
with a rotary drill; that is, the hole is
drilled by a rotating drill bit connected
to the surface with a length of pipe called
a drill string. Cuttings from the drill
face are removed by a fluid called "drilling
mud" which is pumped down through the drill
pipe, out through holes in the bit, and
circulated back to the surface in the
annular space between the drill pipe and
the bore hole (Figure 3-4). Drilling mud
is a water-based slurry of chrome ligno-
sulfate with a variable density of between
10 and 20 pounds per gallon. In addition
to removing cuttings, the mud also main-
tains hydrostatic pressure in the hole to
prevent a "blowout" (the unconstrained flow
of liquids or gases from formation zones
penetrated as the hole is drilled). In
some wells, high pressure air is used in
place of mud to remove cuttings.
In addition to drilling mud, a number
of safeguards are used to minimize the
3-9
-------
The Mud System
The diagram shows the path taken by the
drilling fluid in circulating through the well.
From the slush pumps (A) the fluid goes to
the swivel (B), from the swivel down through
the kelly iC), through the drill stem (D) to
the bit (E). At the bit the drilling fluid
washes the cuttings from the bit and the bot-
tom of the hole and carries them back to the
surface through the annulus (F). At the sur-
face, a pipe carries the cuttings in suspension
through a shale shaker iGj, which removes
the cuttings from the drilling fluid. From the
shaker the drilling fluid goes to the mud pit
i H ) and the whole cycle is begun again.
Figure 3-4. Drilling and Mud System
Source: University of Texas, 1957: 35.
-------
likelihood of a blowout. These include
setting casing and installing blowout pre-
venter (BPO) valves. Casing is large-
diameter steel pipe which is cemented in as
a liner to the bore hole to prevent the
loss of drilling mud into formations and
to prevent communication (seepage of fluids)
between formations at different depths.
Casing is normally set to the total depth
of the well (Figure 3-5). BOP valves are
attached at the top of the casing and can
close off the hole in the event control is
lost. Usually, a series of these valves is
used so that the hole can be sealed whether
or not there is drill pipe in the hole
(Figure 3-6). Drilling technology is dis-
cussed in Kash (1973: 44).
Exploratory wells are usually drilled
to reach a particular geological formation
that is believed to contain oil or gas.
The drill cuttings taken from the hole are
used to determine which formation is being
penetrated and whether oil is present.
Offshore exploratory drilling uses the
same techniques as onshore except that a
platform must be provided to support the
drilling rig and other equipment. The four
basic types of offshore exploratory drill-
ing platforms, all of which are mobile, are
barges, jack-ups, drill ships, and semi-
submersibles. Because of their lack of
seaworthiness, barges are normally used in
shallow, protected waters, although some
have been built for water depths as great
as 600 feet. Barges are anchored to the
ocean floor. Jack-ups are platforms with
retractable legs that can be lowered to the
ocean floor to lift the platform out of the
water (Figure 3-7). Jack-ups are limited
to water depths of about 300 feet but can
withstand severe weather. Drill ships
(Figure 3-8) are used for exploratory drill-
ing in deep water (as much as 2,000 feet),
but they are not suitable for severe weath-
er. Semisubmersibles are floating platforms
with most of the flotation submerged (Figure
3-9). "Semis" have excellent stability in
severe weather and can drill in water as
deep as 2,000 feet. Semis and drill ships
are either anchored or kept in position
with propeller thrusters.
3.3.2 Energy Efficiencies
All the energy used in regional and
detailed exploration surveys is ancillary
and has not been documented in Hittman,
Battelle, or Teknekron data. Energy ex-
pended in exploratory drilling is also
ancillary and would be used to operate the
drill rig and any associated equipment.
To obtain an energy efficiency, the energy
expended would have to be divided by the
energy in the amount of oil found per well
drilled. Data on these energies are not
available.
3.3.3 Environmental Considerations
The environmental residuals from re-
gional and detailed exploration surveys are
minimal. Explosives are still used onshore,
but earlier impacts due to use of explosives
for offshore seismic work have been elimin-
ated by the use of contained detonations,
as mentioned in Section 3.3.1.2.
The most serious environmental resid-
uals associated with drilling have resulted
from blowouts. The number of blowouts
during all drilling on land from 1960 to
1970 was 106 out of 273,000 wells or .039
percent, most of which were from high-
pressure gas rather than oil wells (Kash
and others, 1973: 286). Offshore, there
have been 19 blowouts since 1960 (17 were
gas only) which is 0.2 percent of the new
wells started (Kash and others, 1973: 285).
Although the number of drilling blow-
outs has been small, the residuals include
nondegradable organics in the form of crude
oil (in amounts ranging from a few hundred
to a few hundred thousand barrels per event)
and, in the event of fire, air pollutants
which can include hydrocarbons,, oxides of
nitrogen (NOX), sulfur dioxide (503), carbon
monoxide (CO), and particulates. Both the
3-11
-------
.OOSE
SURFACE SOIL
INTERMEDIATED^
PRODUCTION
CASING
CEMENT
CASING
SHOE
SHAIE
Figure 3-5. Oil Well Casing
Source: University of Texas, 1957: 48.
-------
HIGH-
PRESSURE
FLUID
L EG END
A Kelly
B Rotary table
C Hydraulic valve controls
D Drill floor
E Manual valve controls
F Bag-type preventer
6 Pipe ram preventer
H Blind ram or shear ram preventer
Figure 3-6. Blowout Preventer Stack
Source: University of Texas, 1957: 45.
-------
Figure 3-7. Jack-Up Offshore Drilling Rig
Source: Esso Production Research Company. Used by permission,
-------
Figure 3-8. Drill Ship
Source: The Offshore Company. Used by permission,
-------
Figure 3-9. Semi-Submersible Offshore Drilling Rig
Source: The Offshore Company. Used by permission.
-------
environmental and social impacts of these
blowouts have been significant. Hittman,
Battelle, and Teknekron data do not dis-
tinguish drilling blowouts from blowouts
occurring during production; all blowout
data are combined with chronic pollutants
under oil extraction. These data are dis-
cussed in Section 3.4.
3.3.4 Economic Considerations
The total cost for regional and de-
tailed onshore exploration surveys between
1959 and 1970 was $5.1 billion. The cost
for drilling dry holes during that period
was $9.1 billion (NPC. 1974: 672). Since
drilling is also an exploratory activity,
the minimum exploration cost for 1959 to
1970 was $14.2 billion or 15 percent of the
cost of producing oil. These are minimum
exploration cost figures because the cost
of drilling successful wells was not in-
cluded.
The total offshore exploration cost
through 1968, including regional and de-
tailed exploration surveys as well as ex-
ploratory drilling, was $1.5 billion
(Kash and others, 1973: 82). Hittman,
Battelle, and Teknekron do not separate ex-
ploration costs; the overall cost for oil
extraction given by these sources is dis-
cussed in Section 3.4.
3.4 DEVELOPMENT
3.4.1 Technologies
The crude oil development technologies
described in this section are grouped into
three categories: completion, processing,
and improved recovery.
3.4.1.1 Completion
Once oil is discovered by exploratory
drilling, the well is tested to determine
the possible oil flow rate and size of the
reservoir. If the reserves calculated from
these data and other geological information
are large enough to warrant commercial pro-
duction, the reservoir is developed. De-
velopment includes drilling a number of
wells to drain the reservoir as efficiently
as possible, completing these well so that
flow occurs and can be controlled, install-
ing field processing equipment, and in-
stalling pipelines.
Development drilling is carried out in
the same manner as exploratory drilling,
except that the spacing of wells and loca-
tion of the bottoms of the holes are more
carefully controlled. Offshore, develop-
ment wells are usually drilled from fixed
platforms rather than mobile rigs. Each
platform normally contains a number of
wells which are directionally drilled to
different parts of the reservoir. The
platforms are steel tubular truss struc-
tures with two or more decks and are at-
tached to the ocean floor by steel pilings.
Current designs have been set in water
depths as great as 400 feet, and new plat-
forms are being designed for water depths
as great as 1,000 feet.
Once development wells are drilled,
they are completed by setting casing in the
hole with cement and installing tubing
(pipe) to carry the produced oil to the
surface. In offshore wells and in those
onshore wells in danger of wellhead damage
(such as in seismically active areas), a
valve is placed near the bottom of the pro-
duction tubing string. This downhole
safety valve, commonly called a Storm Choke
(the trade name for one brand), is designed
to close when the flow through the valve
exceeds a set limit. Recent modifications
have made these valves much more reliable
than earlier versions, which were respon-
sible for some serious offshore accidents.
A set of wellhead control valves, called
a Christmas tree (Figure 3-10) controls the
flow rate from the well.
Crude oil is delivered at the top of a
well either by the natural pressure in the
reservoir or by using some artificial lift
technique. The reservoir properties, the
3-17
-------
Figure 3-10. Wellhead "Christmas Tree" of Control valves
Source: Cameron Iron Works, Incorporated, 1973: 1035.
-------
pressure initially occurring in the reser-
voir, and the properties of the oil and
any dissolved gas determine the percentage
of oil that will be recovered by natural
forces alone. Artificial lift techniques
include pumps (the most common of which are
sucker-rod pumps) and gas lifts (in which
natural gas is injected into the oil in the
well to decrease its density so that it
will flow to the surface).
A new approach to completion offshore
is the subsea completion. A number of pro-
totype systems currently being tested are
designed to permit well completion at the
ocean floor rather than on a platform.
However, because of field processing and
servicing requirements, subsea completions
will still require nearby surface platforms
if they are far from shore. For a more
complete description of subsea completions,
see Kash (1973: 52) .
3.4.1.2 Processing
Once out of the well, oil is processed
in the field to remove natural gas, salt
water (brine), sand, and/or other impuri-
ties. Although the exact field processing
used depends on the impurities present,
usually only one or two processing steps
are required. If present, natural gas is
separated from the oil by a gravity separa-
tor. The gas may then be sold if a gas
pipeline is nearby. If not, the gas may be
used for lift to aid recovery, may be in-
jected back into the reservoir, may be used
in lieu of ancillary energy on site, or may
be mixed with air and burned in a flare.
Unlike the other alternatives, flaring
wastes the gas and produces air pollutants.
Thus, flaring is normally used only in
isolated regions, such as offshore. In
1973, the gas flared was estimated to be
3.4 percent of all the gas produced offshore
(Interior, 1972: 7).
Salt water produced with the oil is
removed in free water knockout processing
in which the mixture sits in a large tank
and is separated by gravity. If the brine
is emulsified in the oil, more sophisti-
cated processing methods (such as heaters
or chemical surfactants) are required. In
addition to separation, oil field brines
require treatment before disposal. Off-
shore water treatment facilities can clean
water down to about 50 parts per million
(ppm) of oil by using gravity, filters,
surfactants, or combinations of these tech-
niques. Onshore, brine is usually treated
by gravity separation (allowing the brine
to sit for a few days in a large tank).
Cleanliness is determined by tank reten-
tion time but can be as low as five ppm.
Sand is very erosive to equipment and
thus, when present in the formation, is
normally held in the bottom of the well by
injected chemical binders or screens. When
sand is produced with the oil, it is also
removed in the free water knockout or oil-
gas separators.
, After field processing, oil quality is
verified and quantity is measured before
the oil enters a pipeline.
3.4.1.3 Improved Recovery
When the natural flow of oil has di-
minished, additional oil may be recovered
from the reservoir through the use of im-
proved recovery techniques which add sup-
plemental energy to the reservoir. The
most common method of improved recovery is
waterflooding, which is sometimes called
secondary recovery. This technique is so
effective that, in recent years, it has
been used quite early in the productive
life of a reservoir to extend potential pro-
duction. Waterflooding consists of pumping
water down selected wells in a field to
force oil up other wells in the field.
Generally, waterflooding requires injection
of one or more barrels of water for each
barrel of oil recovered. A typical water-
flooding system is shown in Figure 3-11.
Tertiary recovery, which refers to all
improved recovery methods other than
3-19
-------
,Woter stabilization and
clarification tank
Clear water
storage tank
Injection
pump
Figure 3-11. Waterflood Secondary Recovery System
Source: BuMines, 1970: 26.
-------
waterflooding involves adding a large quan-
tity of a liquid material (usually mixed
with water) or a gas to the reservoir. The
most promising tertiary technique is to
inject a mobilizing material designed to
release oil locked in pore spaces or the
reservoir rock. The mobilized oil is then
pushed to production wells by injecting
either water or gas behind the mobilizing
material. The five categories of tertiary
recovery techniques are polymer floods;
surfactants; miscible recovery processes;
immiscible gases; and thermal recovery
methods.
In polymer flooding, a high molecular
weight polymer is dissolved into water and
injected into the reservoir. The polymer
increases the viscosity of the water, re-
sulting in a thickened material that is
more likely to flow within the oil-bearing
zones of the reservoir and less likely to
disperse into nonoil-bearing zones.
Surfactants are chemicals that act
very much like soap when added to water.
Injected into reservoirs, they help to wash
the oil from the surface of the rock.
In miscible recovery, a fluid that will
mix with the oil is injected, then water is
injected to push the mixture to producing
wells. The immiscible technique uses gases
such as nitrogen, air, or flue gases to
push the oil from the reservoir.
Thermal techniques use heat to thin
the crude oil for easier recovery- Heat is
most often provided by injecting steam into
the reservoir, but in situ combustion of
part of the oil (supported by injected air)
has also been used.
Whenever a material has been added to
the oil in secondary or tertiary recovery,
it must be separated out after the mixture
has been produced. The separation may be
similar to other field processing or may
take place at the refinery.
The choice among the various tertiary
recovery processes as applied to a particu-
lar reservoir depends on the viscosity of
the reservoir oil, reservoir properties,
and the availability of injection materials.
Although research and field testing are
being conducted on all .these techniques,
tertiary recovery has limited applications
at present.
3.4.2 Energy Efficiencies
The primary efficiency of oil extrac-
tion is the amount of oil extracted from
the reservoir divided by the amount con-
tained in the reservoir. This efficiency,
called recovery efficiency in the industry,
averages about 30 percent for onshore wells
and about 40 percent for offshore wells to
within an error probability of less than
50 percent. The difference between the
two results from location of the reserves.
More than 90 percent of offshore drilling,
to the present, has been in the Gulf of
Mexico where reservoir conditions are more
favorable than for the U.S. as a whole.
In the future, more offshore oil will
be taken from the Pacific or from previous-
ly undeveloped areas such as the Atlantic
and Gulf of Alaska. Since no recovery
efficiencies are available for these areas
and since reservoir conditions may be less
favorable than for the Gulf of Mexico res-
ervoirs, future offshore recovery efficien-
cies should be estimated at about 30 percent,
which is the national average.
Table 3-3 gives primary energy effi-
ciencies for onshore and offshore extrac-
tion as estimated by Hittman, Battelle,
and Teknekron. Battelle apparently defines
primary efficiency differently than Hittman
and Teknekron, because Battelle cites 100-
percent efficiency for both onshore and
offshore extraction. Such an assumption is
probably not as useful as assuming that the
primary efficiency for oil extraction is the
same as recovery efficiency. However, es-
timates indicate that recovery efficiencies
as high as 70 percent can be achieved, al-
though at considerable expense. Recovery
efficiency estimates for secondary and
tertiary recovery are shown in Table 3-4.
3-21
-------
Table 3-3. Efficiencies and Residuals from Crude Oil Extraction
SYSTEM
EXTRACTION
Onshore Oil
Offshore Oilb
Onshore Oilc
Offshore Oilc
Onshore Oil
Offshore Oild
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
U
U
U
U
Bases
NA
NA
NC
NC
NC
NC
^f
s
NA
NA
NC
NC
NC
NC
m
i
NA
NA
NC
NC
NC
NC
Total
Dissolved
Solids
U
U
3100.
0
U
U
Suspended
Solids
NA
NA
0
0
NC
NC
Organics
.15
1.3
4.
1.
.8
2.
Q
S
NA
NA
NC
NC
NC
NC
Q
8
U
U
NC
NC
NC
NC
Thermal
(Btu's/I0l2)
0
0
0
0
NC
NC
Air Pollutants {Tons/1012 Btu's)
Particulates
U
U
.002
.002
U
U
X
U
U
.004
.004
U
U
X
8
U
U
.03
.03
U
U
Hydrocarbons
U
U
.0002
.0002
U
U
8
U
U
1.5
1.5
U
U
Aldehydes
0
0
'NC
NC
NC
NC
tn
Solids
(Tons/101-2 Btu
NA
NA
0
0
NC
NC
V
Land
Acre-year
en
3
jj
CQ
CN
0
'3.03/0
3.03
.35/0
.35
b.a/0
6.9
6.9/0
6.9
U/U
0
U/U
0
Occupational
Health
1012 Btu's
Deaths
5.2
xlo-5
5.7
xlO-6
0022
.0022
NC
NC
Injuries
.004
0003
.21
,21
NC
NC
4J
tn
S
tn
(0
d
i
c
IB
E
.137
.009
35.
35.
NC
NC
•*!
NA = not applicable, NC = not considered, U = unknown.
aFixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres )
1Q12 Btu's 1012 Btu's
bHittman, 1974: Vol. I, Table 13.
^attelle, 1973: Tables A-34, A-35.
TeXnekron, 1973: Figure 4.1.
-------
TABLE 3-4
EFFICIENCY OF IMPROVED RECOVERY METHODS
Method
Waterf lood
Steam (heavy oil)
Alternate water
(polymer)
Thickened water
(polymer)
Wettability
reversal
Miscible-hydro-
carbon
Miscible-CO2
Miscible (micellar)
water
IFT (micellar)
watera
Thermal (COFCAW)b
Recovery Improvement
(percent)
From
10
10
30
30
45
45
45
45
45
40
TO
50
60
40
40
55
75
70
80
75
70
Incremental Cost
(dollars per barrel
of added oil)
0.35-0.50
0.75-1.25
0.25-0.35
0.60-0.80
0.50-0.75
0.75-1.00
0.60-0.85
1.00-1.50
0.75-1.25
1.25-1.50
Source: Geffen, 1973: 88.
alnjected Fluid Thickened (IFT) Waterflooding.
^Combined Forward Combustion And Waterflooding (COFCAW).
to "Huff-and-Puff" steam injection techniques.
This data also applies
Ancillary energy for oil extraction
includes drilling and pumping requirements
for primary recovery, and injection well
drilling and fluid pumping requirements for
secondary and tertiary recovery. Addition-
al ancillary energy may be used in tertiary
recovery if natural gas or other possible
fuels are pumped into the well. The amounts
of ancillary energy, particularly for sec-
ondary and tertiary recovery, will be sig-
nificant; however, no data is presented in
Hittman, Battelle, or Teknekron for ancil-
lary energy use.
3.4.3 Environmental Considerations
Environmental residuals can be gener-
ated both chronically and by accidents such
as blowouts. Blowouts were discussed in
Section 3.3 and will not be further de-
scribed here, but the residuals listed in
Table 3-3 can be assumed to arise from both
chronic discharges and blowouts .
3.4.3.1 Water
Water residuals from onshore oil ex-
traction are nondegradable organics (oil)
and dissolved solids (brine). As indicated
in Table 3-3, estimates of oil residuals
range from one to four tons per 10 Btu's
of oil in the ground to within a possible
error of 50 percent. Estimates of dissolved
12
solids range from 0 to 3,100 tons per 10
Btu's. The Hittman oil discharges assume
that 12 percent of the produced brine is
discharged while Battelle assumes four per-
cent is discharged. The dissolved solids
are not discussed by Hittman except to
assume that the brine is not a pollutant.
And the long-term possibility of groundwater
pollution from casing corrosion has not
been addressed.
The only category of water residuals
from offshore oil extraction is the oil
contained in the discharged wastewater
(brine). The range of oil discharged is
3-23
-------
from zero to two tons per 10 Btu's.
Without this oil, brine (produced salt
water) is assumed to be nonpolluting when
discharged into the ocean. Hittman esti-
mates zero water pollution from offshore
wells by assuming that all the produced
brine is reinjected into the reservoir.
However, complete reinjection is not prac-
ticed at all offshore wells at present, and
there is no regulation requiring such re-
injection. Present regulations permit dis-
charges averaging up to 50 ppm of oil in
discharged water, which implies an oil dis-
charge of nine bbl per million bbl pro-
duced (Kash and others, 1973: 292) or 0.22
ton per 10 Btu's. Battelle assumes 40
bbl of oil discharged per million bbl of
oil produced.
Teknekron assumes that oil will be
lost due to blowouts and spills at wells
but makes no assumption concerning the
amount of oil or dissolved solids in the
discharged brine. Consequently, the or-
ganic pollutants from the Teknekron data
are from a different source (blowouts) than
the organic residuals from the Hittman and
Battelle data. To obtain a reasonable es-
timate of total organic residuals in water
due to oil extraction, the sum of chronic
and blowout discharges should be used.
3.4.3.2 Air
Air-pollutant residuals include par-
ticulates, NOX, SOx, hydrocarbons, and CO,
all of which are due to blowouts and sub-
sequent evaporation or burning, or due to
testing wells offshore in which produced
oil is burned to dispose of it. Residual
quantities are not significant when nor-
malized by total oil production (on a tons
12
per 10 Btu's basis) but generate sig-
nificant local impacts in the area of a
spill or blowout. The air-pollutant re-
siduals from gas flaring are not included,
although they should be much larger than
the residuals resulting from either testing
wells or blowouts. Air-pollutant residuals
are assumed to be the same offshore and
onshore, although in testing wells onshore,
the oil produced is loaded into tank trucks
and sold.
3.4.3.3 Land
Estimates of land use from oil extrac-
tion ranges from 3.03 to 6.9 acres per
1012 Btu's per year (Hittman, 1974: Vol. I,
Table 13; Battelle, 1973: Table A-34).
These data are based on onshore land use
ranging from one-quarter to one acre per
well, and offshore land use from zero to
' one acre per well. Land use attributed to
offshore wells should be much less than
for onshore because the only land used will
be for onshore field processing facilities
near an offshore field.
3.4.4 Economic Considerations
The fixed cost estimate, within a fac-
tor of two, for an onshore well is about
$273,000 and for an offshore well is about
12
$125,000 per 10 Btu's output. These es-
timates assume that offshore wells produce
an average of 17 times as much oil as on-
shore wells but that development costs of
offshore wells are almost eight times
greater than onshore wells. Capital costs
were assumed to be 10 percent for both
types of wells (Hittman, 1974: Vol. I).
No operating costs were given for oil
wells. Operating costs should include well
maintenance, pumping costs, and the costs
of workovers.
3.5 CRUDE OIL REFINING
3.5.1 Technologies
A petroleum refinery is a combination
of processes and operations designed to
convert crude oil into various products.
As discussed in Section 3.2, crude may be a
mixture of more than a thousand different
hydrocarbons, together with trace quantities
of such compounds as sulfur and nitrogen.
The crude is first separated by distillation
3-24
-------
into fractions selected on the basis of
boiling points; the relative volume of each
fraction is determined by the type of crude
used.
Since the relative volume of each
fraction produced by merely separating the
crude may not conform to the relative mar-
ket demand for each fraction, some of the
separation products are converted into pro-
ducts having a greater demand by splitting,
uniting, or rearranging the original mole-
cules .
The processes used in a refinery to
accomplish the above conversions include
distillation, sulfur removal, cracking, and
reforming. Each refinery design is a unique
combination of types and capacities of
these processes (Hittman, 1974: Vol. I, pp.
IV-1 through IV-3). A schematic of a re-
finery is shown in Figure 3-12. The follow-
ing describes the refinery feedstocks and
products, unit processes, and operation
residuals.
3.5.1.1 Feedstock and Products
The feedstock for a refinery is
crude oil, but there is a limited range of
crudes that a particular refinery can pro-
cess efficiently. Thus, early in the de-
sign of a new refinery, an effort is made
to insure that feedstocks will be sufficient
to allow efficient refinery operation for a
maximum length of time. The important feed-
stock characteristics are density (API grav-
ity) , sulfur content, and the quantities
of other impurities such as nitrogen and
salts. If an appropriate feedstock is not
available from a single source, different
crudes are blended to obtain the desired
characteristics. In addition to crude oil,
feedstock can include natural gas liquids
or synthetic crude (syncrude) from oil shale
or coal liquefaction.
The principal products of U.S. refiner-
ies are gasoline, jet fuels and kerosene,
and diesel and fuel oils. Lubricants, waxes
and solvents, petrochemical feedstocks, and
asphalt (oil) are also produced. The pro-
portions of the principal products vary
with the refinery design, location, and
time of the year. For example, refineries
in the northeastern U.S. produce mostly
gasoline during the summer but shift to
predominately fuel oil production during
the winter to meet heating oil demands in
that part of the country.
Gasoline production has become more
difficult recently because of pollution
control requirements. Tetraethyl lead,
*
which improves the gasoline octane number,
cannot be added to gasoline for use in 1975
model cars because it destroys the effec-
tiveness of their catalytic converters.
Although low octane gasoline is compatible
with the low-compression, less efficient
engines in the newer cars, unleaded gas-
oline does not burn efficiently in older,
high-compression engines. The result is
lowered gas mileage (and thus increased
demand) from users of both types of vehi-
cles. Research has and is being done on
nonpolluting alternatives to the use of
tetraethyl lead to increase octane ratings,
but the only feasible method at present is
to increase the proportion of high octane
hydrocarbons in the gasoline, which requires
additional refining steps not available in
older refineries.
Fuel oils, which are relatively low
energy products, are graded from one through
six, the highest number corresponding to
the heaviest, least energetic oil. The two
highest grades (lowest numbers) are distil-
late fuel oils (obtained from the distilla-
tion process in the refinery). The lowest
four grades are residual fuel oils, pro-
duced by diluting the residual from the
distillation process with varying amounts
of kerosene to obtain the desired viscosity.
Number six residual fuel oil must be heated
before it will flow through a pipe or burn.
Octane number is a measure of the
gasoline's ability to burn smoothly.
3-25
-------
Fuel Gas
Crude Oil
Liauified Pe-froleum Gas(LPG)
Recovery
Plant
Isomenzation
Unit-
Purchased Butane »
Light Straight Run Gasoline (IOQ-200<>F
To 3as Recovery
Fuel Blending
IMaptha
Hydro-
desulforher
Distillation
Tc
Turbine Fuel
Heating Oil
Diesel Fuel
I No. 2 Heating Oil
I Catalytic Gasoline
Catalytic Cycle Oil
850-IIOO°F)
Catalytic Heavy Cycle Oil
No fifl fi Fuel O
Residuum
Hydro-
desulfurizer
Vacuum
Distillation
Unit
Road Oils and Asohalts
Topped Crude
(850-1500° F)
Figure 3-12. Oil Refinery
-------
3.5.1.2 Unit Processes
As mentioned previously, a refinery
complex consists of a number of unit pro-
cesses that are sized and combined to pro-
duce the desired products from a given
crude oil feedstock. This section describes
these processes and identifies considera-
tions necessary to combine them into a com-
plete refinery.
3.5.1.2.1 Distillation
Distillation is a process of progres-
sively heating crude oil in a column and
drawing off various components at their
different boiling points. The very light
hydrocarbons, such as gasoline, boil at less
than 250°F, while the boiling points of the
heavy or residual fuel oils are more than
900°F. Distillation occurs in a fractiona-
tion or distillation tower which is heated
at the bottom and cooled at the top (Figure
3-13). The crude goes into the column from
an electrostatic desalter in which salts
are removed to minimize corrosion. A typ-
ical tower will be about 15 feet in diam-
eter and more than 100 feet high. Inside
the tower, 35 or more trays are arranged so
that the rising vapor must bubble through
the liquid in each tray. The lower boiling
point (lighter) fractions move further up
the column before they condense on a tray.
The residual leaving the distillation
column is processed in a vacuum distilla-
tion column to separate very high boiling
point fractions that could not be separated
in the main tower.
The number and type of products obtain-
able from crude distillation is highly de-
pendent on the design of the unit, as well
as on the crude type. Changes in operating
temperatures and heating rates can also
affect the proportions of products, and
these factors are normally the ones used to
make seasonal changes in product output.
:3.5.1.2.2 Sulfur Removal
; The sulfur initially in the crude
•leaves the distillation column in the heav-
ier fractions or as hydrogen sulfide gas.
Hydrodesulfurization, the process used to
remove the sulfur in the heavier fractions,
reacts high-pressure (300 to 1,000 pounds
per square inch [psi]) hydrogen with the
sulfur-containing liquid at high tempera-
tures (600 to 800°F) and in the presence of
cobalt and molybdenum oxide catalysts (see
Figure 3-14). The many different propri-
etary catalyst formulations account for a
variety of hydrodesulfurization processes.
Heavy metals, such as vanadium, will poison
these catalysts so that they cannot be used
or regenerated, but even without heavy metal
poisoning the catalysts must be regenerated
with steam twice a year. A fractionation
column is used to separate the cleaned
hydrocarbon from the hydrogen sulfide. A
similar process for removing acid gases
from natural gas is described in Chapter 4.
The hydrogen sulfide gas (whether from
the distillation column or from the hydro-
desulfurization process) exists in a mix-
ture with hydrocarbon gases and must be
separated to recover the hydrocarbon gases
and to allow the hydrogen sulfide to be
further processed. The mixture, called
"sour gas," is circulated through a packed
column in which an amine solvent absorbs
the hydrogen sulfide (Figure 3-15). The
solvent is then regenerated in a distil-
lation column and the hydrogen sulfide
removed. The hydrogen sulfide is processed
in a Glaus plant to recover elemental sulfur.
(Glaus plants are discussed in Chapter 1.)
3.5.1.2.3 Cracking Processes
Cracking is a process of breaking up
large molecules in the feedstock to form
smaller molecules with higher energy content.
Two kinds of cracking processes, catalytic
cracking and hydrocracking, are presently
used in modern refineries, having replaced
thermal cracking processes used earlier.
Catalytic cracking or "cat cracking"
accounts for the vast majority of cracking
processes in use today. Cracking catalysts
are zeolites, synthetic formulations of
3-27
-------
Final
Condenser
Condenser
Feed From
Desalter
Detail of
Bubble Cap
^=:=\ Steam
^\ Heated
Fraction
Residue To
Vacuum
Distillation
Figure 3-13. Refinery Crude Oil Distillation Column
Source: Peel, 1970: 178.
-------
Feed
Make-up hydrogen
Hydrogen
Recycle
Separator
Sour gas
Stripper or
fractionator
^ Steam
fNaphtha product
Figure 3-14. Refinery Hydrodesulfurization Process
Source: Radian Corporation, 1974: 87.
-------
Hydrocarbon gases out
Amine solvent in
A
A
7
V
Multipoint
xX'solvent distributor
In some
• installations a
screen is placed
above to
restrain packing
Section of tower
filled with
packing material
'Screen or grid and
beam support for
packing material
H2S + hydrocarbon
gases in
Down-flowing
solvent
Amine solvent
with H2S out to
distillation column
Removal Column
Figure 3-15. Amine Solvent H
Source: G.G. Brown and Associates, 1960:
323.
-------
alumina in silica. Modern cat crackers use
fluidized beds of catalyst. (See Chapter
1 for a description of fluidized beds.)
Cat cracking catalysts rapidly become
fouled with carbon and must be frequently
regenerated; thus, regenerators are includ-
ed as an integral part of the cat cracking
reactor. The regenerator burns the carbon
with air to form carbon monoxide, which is
then used for refinery process heat. As
with other refinery processes, the cracked
hydrocarbons are separated in a distil-
lation column. A typical catalytic crack-
ing process is shown in Figure 3-16.
Hydrocracking carries out the crack-
ing reactions under high pressures (2,000
to 2,500 psi) and temperatures (about
800°F) in the presence of hydrogen and a
catalyst in fixed-bed reactors. Because
of the high pressures and temperatures, and
the hydrogen requirement, hydrocracking
equipment is relatively expensive. However,
hydrocracking should become more competi-
tive in the future because it generates
higher octane products and does not leave
a carbon residue.
3.5.1.2.4 Reforming, Alkylation, and
Isomerization
Reforming, alkylation, and isomeriza-
tion processes are used to rearrange the
molecular structure of hydrocarbons to form
high octane number compounds for high oc-
tane gasoline manufacture. These processes
differ in the technique of rearranging the
molecule and, consequently, in the chemical
engineering details involved. In each pro-
cess, a catalyst is used. Reforming uses a
platinum or rhenium catalyst in a hydrogen
atmosphere at pressures of 100 to 200 psi
and temperatures of 800 to 900°F. Also,
the feedstock must be sulfur free because
sulfur will poison these catalysts. Alkyl-
ation uses concentrated hydrofluoric, sul-
furic, or phosphoric acid as the catalyst'.
Isomerization uses a platinum oxide cata-
lyst at a temperature of 320°F and a pres-
sure of 400 psi.
3.5.1.2.5 Support Facilities
In addition to the combination of
basic processes identified above, a com-
plete refinery also has support facilities
that may be important in determining the
quantity of residuals produced or the
economics of the refinery. These include
stack gas cleaning, wastewater treatment,
and facilities for generating hydrogen,
steam, and electrical power.
Stack gas cleaning equipment is used
on processes where combustion occurs and
the products do not conform to air quality
standards. The technologies are the same
as those used in central station power
plants and are described in Chapter 12.
Wastewater from a refinery usually
contains various hydrocarbons and some sul-
fur. Refinery wastewater treatment is the
same as that used for other industrial
wastewater and is described in Chapter 1.
Hydrogen, necessary for hydrodesulfuri-
zation and hydrocracking, is generated by
the decomposition of methane with steam at
very high temperatures (about 1,700 F)
using a catalyst. This process also pro-
duces carbon dioxide which is separated
from the hydrogen in an amine scrubber (see
Section 3.5.1.2.2).
When electricity and steam are generat-
ed in the refinery, their production may be
combined. In many cases, however, electric
power is purchased and only process steam
is generated on site. In either case, the
technology is the same as that used for
central station power generation and is de-
scribed in Chapter 12.
3.5.2 Energy Efficiencies
The energy efficiencies for a national
average refinery are shown in Table 3-5.
The data are considered fair, with an error
of less than 50 percent. They range between
88 and 96 percent when both primary effi-
ciency and ancillary energy consumption are
included. Ancillary energy consumption for
refineries without residual controls is
3-31
-------
To CO
Boiler
Combustion Air
Reactor
Catalyst
Stripper
•
Steam
Regenerator
Gas 81 Gasoline to Gas
Concentration Plant
I
Main Column
Light Cycle Gas Oil
Heavy Cycle GasOi I
I Heavy Recycle
\ Charge
Clarified Slurry
Slurry
Settler
Combined Reactor Charge
Raw Oil Charge
Raw Oil
Slurry Charge
Figure 3-16. Catalytic Cracking Process
Source: Radian Corporation, 1974: 113.
-------
TABLE 3-5
CRUDE OIL REFINING EFFICIENCIES
National
Average Refinery
Uncontrolled Onshore
Controlled Onshore
Uncontrolled Offshore
Controlled Offshore
Uncontrolled Imported
Canadian Crude
Controlled Imported
Canadian Crude
Uncontrolled Imported
Middle East Crude
Controlled Imported
Middle East Crude
Domestic Crude (Battelle)
Imported Crude (Battelle)
Domestic Crude (Teknekron)
Primary
Efficiency
(percent)
93.2
93.8
93.2
93.8
93.2
93.8
93.2
93.8
90
90
90
Ancillary
Energy
(109 Btu's per
1012 Btu's)
59.8
50.5
59.8
50.4
59.8
50.4
59.8
50.7
4.44
Source: Hittman, 1974: Vol. I; Battelle, 1973; and Teknekron,
1973.
about 20 percent higher than for controlled
9
refineries (59.8 as compared to 50.5x10
Btu's per 10 Btu's of energy), but the
effect on overall efficiency is insignifi-
cant.
3.5.3 Environmental Considerations
Several studies of the environmental
residuals of refinery unit processes are
available. In this section, the residual
.estimates in three studies (Hittman, 1974;
Vol. I Battelle, 1973; and Radian, 1974)
are compared. Rather than an exhaustive
unit-by-unit analysis, the units chiefly
responsible for each significant residual
are cited. Environmental residual data are
presented in Table 3-6.
3.5.3.1 Water
Water residuals include dissolved
.solids, suspended solids, nondegradable
organics, and biochemical and chemical
oxygen demands. The data available are
fair, with a presumed error of less than
50 percent. The principal dissolved solid
is salt (from electrostatic desalting
prior to fractionating), which will be
present in either controlled or uncon-
trolled refining. The range of total dis-
solved solids is from 1.5 to 98 tons per
10
12
Btu's (Radian, 1974: 149), with the
magnitude most likely between 34 and 50
12
tons per 10 Btu's.
Suspended solids consist of small
amounts of oily sludge not removed in
oil/water separators and the dirt from
runoff water and solids from biological
treatment not removed by settling or flo-
tation. Estimates are between .694 and
12
22.2 tons per 10 Btu's depending on
whether the refinery is controlled or un-
controlled. For a controlled refinery,
the weight of dissolved solids is much lar-
ger than that of suspended solids.
3-33
-------
Table 3-6. Crude Oil Refining Residuals
SYSTEM
KATIOHAL AVERAGE
REFINERY
uncontrolled.
National OilD
Controlled .
National Oil
uncontrolled b
Domestic Onshore
Controlled .
Domestic Onshore
Uncontrolled ,
Domestic Offshore
Controlled ,
Domestic Offshore
CONVENTIONAL REFINERY
Domestic Crudec
OIL REFINERY
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
U
U
U
U
2
DC
Bases
U
U
U
U
U
U
NC
NC
*t
S
NA
NA
NA
NA
NA
NA
NC
NC
m
§
NA
NA
NA
NA
NA
NA
NC
1.5
Total
Dissolved
Solids
35.8
34.
35.8
34.
35.8
34.
50.
1.6
Suspended
Solids
22 2
.694
22 2
.694
.694
2.2
7.3
Organics
6.
.35
6.
.35
6.
.35
NC
1.8
Q
S
6.92
.694
6.92
.694
6.92
.694
NC
6.3
Q
8
20.2
4.24
20.2
4.24
20.2
4.24
NC
NC
Thermal
(Btu's/lQl2)
7.06
xl0lc
0
7.06
xlpiC
0
7-°fn
xlO10
0
0
NC
Air Pollutants (Tons/1012 Btu's)
Particulates
9.1
2.73
9.1
2,73
9.1
2.73
1.1
3.3
X
22.8
19.7
22.8
19.7
22.8
19.7
12.8
23.7
X
o
' 01
240.
21.
246.
21.3
181.
17.9
SO 2
66.7
35.5
Hydrocarbons
232.
23.6
232
23.6
232.
23.6
13.9
19.1
8
611.
.166
611.
.166
611.
.166
1.7
1.4
Aldehydes
3.73
3.71
3.73
3.71
3.73
3.71
NC
.8
0}
Solids
(Tons/1012 Btu
7.57
43.7
7.57
43.7
7.57
43.7
3.9
NC
V
Land
Acre-year
to
3
iJ
<0
CM
iH
O
10.3/0
10.3
10.3/0
10.3
10.3/0
10.3
10.3/0
10,3
10.3/6
10.3
10.3/0
10.3
1.
NC
Occupational
Health
1012 Btu's
Deaths
0004
0004
0004
.0004
.0004
.0004
.0014
U
Injuries
0362
0362
0362
Jl^sa
.0562
JX&2.
.107
U
4J
01
s
Ul
>i
s
c
ra
£
2.05
2.05
2.05
•>.n*
2.05. ,
2.05
\
25.5
u
NA = not applicable, NC = not considered, U = unknown.
aFixed Land Requirement (Acre - year) / Incremental Land Requirement ( Acres ).
1012 Btu's 10l2 Btu's
bHittman, 1974: Vol. I, Tables, 13, 14, 15, 16, 17, and 18.
GBattelle, 1973: Table A-39.
T'eknekron, 1973r Figure 4.1.
-------
There are two nondegradable organic
residuals, oil and phenols, oil is found
in oily cooling and process water, and the
principal source of phenols is the cataly-
tic cracking process (Radian, 1974: 157).
Estimates are between 0.35 and 8 tons per
10 Btu's of total organics, determined by
whether the refinery is controlled.
Biochemical oxygen demand (BOD) for
refinery effluents is due primarily to sour
gas treatment in the Glaus plant and totals
^between 0.694 and 6.92 tons per 10 Btu's
for the controlled and uncontrolled re-
fineries respectively. Chemical oxygen
demand (COD) is due primarily to alkylation
and is between 4.24 and 20.2 tons per 10
Btu's for controlled and uncontrolled re-
fineries. Whether these oxygen demands
have serious impact depends on the rate of
discharge. An oxygen demand of 200 ppm in
discharge water would be serious.
3.5.3.2 Air
The data for air residuals given in
Table 3-6 are fair, with an error probabil-
ity of less than 50 percent. NOX residuals
12
are between 12.8 and 23.7 tons per 10
Btu's and arise from the operation of fuel
burning process heaters and power plant
boilers. Considerable reduction in NOx
emissions can be achieved by combustion con-
trol measures on heaters and boilers (see
Chapter 12). Two processes with high NOX
: residuals are hydrogen production and the
olefin manufacturing process which is com-
monly found in petrochemical refineries.
Combustion control measures cannot be em-
; ployed in hydrogen and olefin plants, how-
ever, because of the high temperatures in-
volved.
SOx residuals are between 21 and 240
12
tons per 10 Btu's for controlled and un-
; controlled refineries respectively. The
SOx residual is primarily due to the cata-
J.lytic cracker, and refinery residuals would
i:be sharply reduced with the use of hydro-
, cracking or sulfur removal from cat cracker
I feedstocks.
Hydrocarbon emissions are between
12
13.9 and 23.6 tons per 10 Btu's for con-
trolled refineries and are 10 times larger,
12
232 tons per 10 Btu's, for uncontrolled
refineries. More than half of the hydro-
carbon emissions in both controlled and
uncontrolled refineries are from crude oil
and product storage. Storage emissions
can be reduced by a factor of 10 or more
by proper control measures.
Generation of particulates, CO, and
other organics is not significant.
3.5.3.3 Solids
Solid waste residuals from controlled
refineries are between 3.9 and 7.57 tons
per 10 Btu's and up to 43.7 tons per
12
10 Btu's for uncontrolled refineries.
The most troublesome solid wastes are oily
sludges from crude oil storage which cannot
be disposed of in ordinary landfills. Good
quantitative data on solid wastes is almost
nonexistent. The Hittman data is rated
"poor" or "very poor," which means that the
error is within (poor) or around (very poor)
an order of magnitude.
3.5.3.4 Land Use
Land use is estimated to be between
9.1 (Battelle, 1973: 307) and 10.3 (Hittman,
1974: Vol. I, Tables 13-18) acres per 1012
Btu's per year energy input if storage,
loading areas, buffer zones, and room for
expansion are included. For the refinery
process alone, the land use is estimated to
12
be one acre per 10 Btu's per year of
energy input. These data are considered
accurate within a factor of two.
3.5.4 Economic Considerations
Energy production costs for 1972 in
controlled refineries were $85,600 per
10 Btu's fixed costs and $248,000 per
12
10 Btu's operating cost as shown in Table
3-7. The fixed costs represent a flat
fixed charge rate of 10 percent on capital
which gives a total capital investment of
ft 12
$2.48x10 per 10 Btu's per year.
3-35
-------
TABLE 3-7
CRUDE OIL REFINING COSTS" (1972)
National average
refinery
Uncontrolled
national oil
Controlled
national oil
Fixed Cost
(dollars per
10" Btu's input)
76,800
85,600
Operating
(dollars per
1012 Btu's input)
242,000
248,000
Total
(dollars per
1012 Btu's input)
319,000
334,000
Source: Hittman, 1974: Vol. I.
Production costs in uncontrolled refineries
were $76,800 in fixed costs and $242,000
12
in operating costs per 10 Btu's input.
The primary value of these figures is in
showing the relationship between capital
and operating figures.
3.6 TRANSPORTATION
3.6.1 Introduction
Crude oil must be transported from the
producing field to the refinery, and re-
fined products must be transported from the
refinery to market. This section is di-
vided into domestic transportation of crude
and products and the transportation of
foreign imports.
3.6.2 Domestic Transportation Technologies
Tank trucks, railroad tank cars, tank-
ers, barges, and pipelines are all used for
domestic transportation. The choice among
these alternatives depends on the distance
traveled, the product being transported,
and the availability of alternatives. Tank
trucks are useful for small quantities
carried a short distance (less than 500
miles). Railroad tank cars are competitive
with tank trucks for distances of more than
a few hundred miles and for quantities
large enough to fill one car. Tankers and
barges are used for long-distance, large
quantity transportation but are limited by
available ports. Pipelines are competitive
with both waterborne transportation and
railroads but lack any flexibility of route
or destination.
Barges and tankers used for inter-
coastal shipping are of limited size, the
largest being the 125,000-ton tankers being
built for transportation of Alaskan crude
from Valdez to the West Coast. The tankers
should be considered part of a system that
includes loading and unloading facilities
as well as the vessels themselves. Current
loading and unloading techniques utilize
docks and loading booms that swing out over
the vessel.
Pipelines onshore in the lower 48 states
are laid in trenches and use welded steel
construction. Oil pipelines as large as 48
inches in diameter have been laid. Pipeline
right-of-ways are inspected by air regularly
after a pipeline is operating to detect
leaks. Because of the pressure drop due to
friction along a pipeline, pumping stations
must be installed each 50 to 150 miles, de-
pending on the size of pipe and desired
flow rate. The stations normally employ
centrifugal pumps powered by electric motors
or diesel engines. Pumping stations are not
usually manned but are monitored remotely at
3-36
-------
the pipeline control station and designed
to be fail-safe (Watkins, 1970: 134-136).
Offshore pipelines are difficult to
lay because the pipe must be lowered to
the ocean floor from a barge (Figure 3-17).
After being laid, the pipe is usually bur-
ied by barges that use high pressure water
jets to dig a trench under the pipe. The
pipe must be inspected carefully before it
is laid because of the expense and diffi-
culty involved in repairing an offshore
pipeline. Repairs can be carried out
underwater using divers and special weld-
ing techniques or on the surface by lift-
ing the pipeline with a derrick. Detec-
tion of small leaks is difficult for off-
shore pipelines despite aerial inspection
and the use of mass flow monitors in many
cases.
The trans-Alaska pipeline has pre-
sented unique problems in both its con-
struction and use. The anticipated high
temperature (135°F) of the oil and the
presence of permafrost will require special
insulation and even refrigeration in some
segments. Corrosion protection must be
provided in the form of coatings and ca-
thodic protection, and remove control gate
valves and check valves must be installed
to limit the possibility of widespread
pollution from leaks or ruptures. Special
provisions must be taken to provide oppor-
tunities for wildlife to cross the pipeline
so as not to interrupt migratory patterns.
Finally, seismic faults crossed by the pipe-
line require design considerations for ma-
jor horizontal and vertical displacements.
Plans call for shutdown and inspection of
the line after any earthquake within 0.3
Richter scale points of the maximum design
earthquake.
3.6.3 Energy Efficiencies
The primary efficiency of all the
technologies for oil transportation is very
near 100 percent. Any losses of the trans-
ported product would be due to leaks or
spills, and although these could have a
serious environmental impact, they con-
stitute only a fraction of one percent of
the total oil transported. The efficiency
data are shown in Table 3-8 and are con-
sidered good, with a possible error of 25
percent or less.
The only distinction in the efficiency
data is between controlled and uncontrolled
tanker transportation. The difference is
that .01 percent of the oil transported in
uncontrolled tankers is lost in ballast
dumping, and none is lost in controlled
tankers.
Ancillary energy requirements are pre-
sented in Table 3-8 and are considered ac-
curate to within 25 percent. The data are
not comparable for different modes of
transportation, however, because each mode
is assumed to transport the oil a different
distance. Ancillary energy requirements
are:
g
1. Pipelines: 3.59x10 Btu's for
1Q12 Btu's piped 300 miles.
2. Tankers and supertankers:
39.7x109 Btu's for 1012 Btu's
transported 10,000 miles (assumed
due to diesel engines).
3. Barges: 25.2xl09 Btu's for 1012
Btu's carried 1,500 miles (assumed
due to diesel-powered tugs).
4. Tank trucks: 6.15xl09 Btu's for
1012 Btu's carried 500 miles
(assumed due to diesel tractors).
Q
5. Railroad tank cars: 4.59x10 Btu's
for 1012 Btu's carried 500 miles
(assumed due to diesel-electric
locomotives).
3.6.4 Environmental Considerations
Environmental residuals for domestic
crude oil and product transport are shown
in Table 3-9. The data are generally
good; that is, considered accurate to with-
in 50 percent.
3.6.4.1 Water
Water pollutant residuals from domes-
tic oil and product transportation are con-
fined to nondegradable organics, in this
case the oil or products transported.
3-37
-------
Figure 3-17. Offshore Pipelaying Barge
Source: McDermott, Incorporated.
-------
TABLE 3-8
CRUDE OIL AND PRODUCT TRANSPORTATION EFFICIENCIES
Method
Pipeline
Tankers and supertankers3
Barges
Tank trucksa
Tank carsa
•*.
Tanker transportation
Pipeline transportation0
Barge transportation
Pipeline transportation6
Primary
Efficiency
(percent)
100
99.9
100
U
U
U
U
U
99.96
Ancillary
Energy
(109 per
1012 Btu's)
3.69
40.7
25.7
14.1
14.6
U
U
U
U
Overall
Efficiency
(percent)
99.3
95.8
97.4
U
U
99.5
99.1
99.6
U
Distance for
Ancillary
Energy (miles)
300
10,000
1,500
500
500
NA
NA
NA
NA
U = unknown, NA = not available
Sources: ^ittman, 1974: Vol. I.
bBattelle, 1973: Table A-36.
cBattelle, 1973: Table A-37.
^attelle, 1973: Table A-38.
eTeknekron, 1973: Figure 4-1.
Residual levels are between .08 and 12.4
12
tons per 10 Btu's transported for pipe-
lines, with the difference arising from
different assumptions about the percentage
of transported oil assumed to be discharged
and the amount of the discharged oil which
reaches a body of water. Residuals from
tankers are between 7.57 and 126 tons per
10 Btu's transported with no reason pro-
vided by the sources for the wide discrep-
ancy in the data. Both data were for
approximately .03 percent of cargo assumed
lost in discharges, leaks, and spills.
3.6.4.2 Air
Air-pollutant residuals from trans-
portation include particulates, NOx,
hydrocarbons, CO, and aldehydes. For pipe-
lines, particulate emissions range from
12
.172 to 1.0 ton per 10 Btu's transported,
NOX from 4.5 to 4.89 tons per 10 Btu's
transported, SOX from .357 to 8.1 tons per
12
10 Btu's transported, hydrocarbons from
12
.2 to .49 ton per 10 Btu's transported,
12
CO from .01 to 2.98 tons per 10 Btu's
transported, and aldehydes in trace amounts.
The source of these emissions is assumed
to be diesel-powered pumping stations, and
the differences in residual quantities are
apparently different sources of data on
diesel emissions.
For tankers, particulate emissions
12
range from .0375 to 1.1 tons per 10 Btu's
transported, CO ranges from 6.14xlO~ to
3-39
-------
Table 3-9. Residuals for Crude Oil and Product Transport
SYSTEM
CRUDE OIL
Pipeline13
Pipeline
Pipeline
Uncontrolled Tanker
or Supertanker*3
Controlled, Tanker
or Supertanker"
Oil Tanker0
Barges
Oil Barge0
Tank Truck
Tank Cars
Product Distribution
Picelineo
Uncontrolled Tanker
or Supertanker0
Controlled Tanker
or Supertanker0
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
U
U
U
U
U
U
U
U
U
U
U
Bases
U
U
U
u
u
u
u
u
u
u
u
u
u
*f
2
u
u
u
u
u
u
u
u
u
u
u
u
u
f>
s
u
u
u
u
u
u
u
u
u
u
u
u
u
[Total
Dissolved
Solids
U
U
U
U
U
U
U
U
U
U
U
U
u
Suspended
Solids
U
U
U
U
U
U
U
u
u
u
u
u
u
Organics
.08
0
12.4
30.
8.07
NC
7.86
NC
U
U
.0822
30.8
8.07
Q
s
NA
NC
NC
NA
NA
NC
NA
NC
NA
NA
NA
NA
NA
Q
8
u
NC
NC
U
U
NC
U
NC
U
U
U
U
U
Therma 1
(Btu's/I0l2)
NA
0
NC
NA
NA
0
NA
0
1 NA
NA
NA
NA
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
.172
1.
NC
.0375
.0375
1.1
3.02
.9
.658
1.28
.172
.0375
.0375
X
9,
4.89
4.5
NC
.337
.337
.8
2.17
.7
18.7
3.84
4.89
.337
.337
X
O
en
.357
8.1
NC
.515
.515
.801
2.31
.7
1.37
3.33
.357
.515
.515
Hydrocarbons
.49
.2
NC
.019
.019
.05
1.4
.4
1.87
2.56
.49
.019
.019
R
2.98
.01
NC
6.14
x!0~3
6.14
xlO-3
.7
1.86
.6
11.4
3.59
2.98
6.14
xlO-3
b.14
xlO-3
Aldehydes
.0794
NC
NC
3.35
xlO-3
3.35
xlO~3
0
.109
NC
.304
.56
.0794
3.35
xlO-3
3.35
xlO-3
to
Solids
(Tons/1012 Btu
0
0
0
0
0
0
0
0
0
0
0
0
0
V
Land
Acre-year
en
D
4J
m
CM
.— i
o
37.9/0
37.9
U/U
34.6
NC
. 166/0
.166
. 166/0
.166
U/U
0
. 166/0
.166
U/U
0
363. /O
363.
19 . 9/0
19.9
37 . 9/0
37.9
. 166/0
.166
.166/0
.166
Occupational
Health
1012 Btu's
Deaths
6.9_5
xlO 3
.0009
NC
U
U
.0009
U
.0009
U
u
6.9
xlO-5
U
u
Injuries
4.2
xlO~J
.008
NC
U
U
.008
U
.008
U
U
xio~3
u
u
4]
W
o
J
111
>
ro
p
I
c
ro
S
1.
15.
NC
U
U
15.
>U
15.
U
U
.1
u
u
-------
Table 3-9. (Continued)
SYSTEM
American Tankerc
American Tankerc
Tanker
Baraesb
Tank Trucks
Tank Cars
Water Pollutants (Tons/1012 Btu's)
Acids
U
^u
U
U
U
U
Bases
U
U
U
U
U
U
•*
s
U
U
U
U
U
U
n
6
U
U
U
U
U
U
Total
Dissolved
Solids
U
U
U
U
U
U
Suspended
Solids
U
U
U
U
U
U
Organics
29.
7.58
126.
7.86
U
U
Q
S
NA
NA
NC
NA
NA
NA
D
8
u
U
NC
U
U
U
Thermal
(Btu's/lo!2)
NA
NA
NC
NA
NA
NA
Air Pollutants (Tons/1012 Btu's)
Particulates
.0375
.0375
NC
3.02
.658
1.28
X
§
.337
.337
NC
2.17
18.7
3.84
X
0
in
.771
.771
NC
2.31
1.37
3.33
Hydrocarbons
.019
.019
NC
1.4
1.87
2.56
O
b.14
xlO~J
6.14
xlO-3
NC
1.86
11.4
3.59
Aldehydes
3.35
xlO~3
3 . 3 5~
xlO-3
NC
.109
.304
.56
en
Solids
(Tons/1012 Btu
_^
-
0
0
0
V
Land
Acre-year
CO
3
4J
O
(N
rH
O
NA
NC
. lfeb/0
363
19^
19
./o
9/0
.9
Occupational
Health
10 12 Btu's
Deaths
NC
Injuries
NC
4J
V)
3
tit
><
ID
P
1
C
ro
NC
. - unknown.
Fixed Land Requirement (Acre - veari / Incremental Land Requirement ( Acres )
1012 Btu's 1012 Btu's
Hittman, 1974: Vol. I, Tables 13, 14, 15, 16, 23, and 24.
CBattelle, 1973: Tables A-36, A-37, and A-38.
'T'eknekron, 1973: Table 4.1.
-------
12
.7 ton per 10 Btu's transported, and all
other air-pollutant residuals are small.
The variation in residuals from different
sources is due to the different assumed
distances traveled in transportation,
10,000 miles for the smaller numbers and
325 miles for the larger numbers. Both
sources assumed diesel-powered engines for
tankers.
For barges, particulate emissions are
between .9 and 3.02 tons per 10 Btu's
transported, NOX emissions are between
.7 and 2.17 tons per 10 Btu's transported,
CO emissions are between .6 and 1.86 tons
12
per 10 Btu's transported, and all other
emissions are small. The emissions are
assumed due to diesel-powered tugs, and the
variations between sources are due to the
different distances assumed.
For tank trucks, NOx emissions are
18.7 tons per 10 Btu's transported, and
12
CO emissions are 11.4 tons per 10 Btu's
transported. All other emissions are
small. The emissions are due to diesel-
powered tractors.
For tank cars, particulate emissions
are 1.23 tons, NOX emissions are 3.84 tons,
SOx emissions are 3.33 tons, and CO emis-
12
sions are 3.59 tons per 10 Btu's trans-
ported. All other emissions are small.
The trains are assumed powered by diesel-
electric locomotives.
3.6.4.3 Land Use
Land use for pipelines is between
34.6 and 37.9 acres per 10 Btu's per year
transported. Land use for tankers, barges,
and supertankers is between 0 and .166
12
acre per 10 Btu's per year transported.
The latter figure was obtained by assuming
land used for tank farms and loading facil-
ities. Land use for tank trucks is given
12
as 363 acres per 10 Btu's per year trans-
ported; this figure was developed by using
the total area of the nation's highways and
assuming that tank trucks constitute a
given percentage of all vehicular traffic.
Land use for railroad tank cars is 19.9
acres
-------
TABLE 3-10
TRANSPORTATION COSTS FOR CRUDE OIL AND PRODUCTS (1972)
Crude Oil
Pipeline
Uncontrolled Tankers
Uncontrolled Supertankers
Controlled Tankers
Controlled Supertankers
Barges
Tank Trucks
Tank Cars
Products
Pipeline
Uncontrolled Tankers
Uncontrolled Supertankers
Controlled Tankers
Controlled Supertankers
Barges
Tank Trucks
Tank Cars
Fixed
(dollars per
1012 Btu's)
U
u
U
u
u
u
u
u
u
u
u
u
u
u
u
u
Total
(dollars per
1012 Btu's)
22,500
244,000
148,000
333,000
199,000
223,000
59,800
96,400
35,900
251,000
152,000
343,000
205,000
229,000
61,500
99,000
Distance Traveled
(miles)
300
10,000
10,000
10,000
10,000
1,500
500
500
300
10,000
10,000
10,000
10,000
1,500
500
500
U = unknown
Source: Hittman, 1974: Vol. I, Tables 13 and 14 and footnotes.
U.S. appears to be the use of very large
crude carriers (VLCC), up to 500,000 dead
weight tons. The crude oil would be un-
loaded in deepwater ports and transshipped
to refineries by tanker or pipeline. This
would entail an extensive program of build-
ing deepwater ports. Currently, there is
only one port in the U.S., Puget Sound in
the state of Washington, which has the wa-
ter depth adequate to accommodate VLCC's .
However, Puget Sound does not now have a
VLCC port.
There are three general types of deep-
water ports: single buoy mooring (SBM)
systems, sea islands, and artificial is-
lands.
SBM systems include a deepwater area,
usually far offshore, and a large buoy, 30
or more feet in diameter. The VLCC is
moored by a single line to the buoy so that
the ship can rotate and thus head into the
prevailing sea. The crude is unloaded
through a line from the ship to the buoy;
from the buoy, a pipeline transports the
oil to the ocean floor and then to shore.
SBM's are particularly suited for rough
weather operation and have been operated
in seas as high as 16 to 20 feet (White
and others, 1973: 74). Figure 3-18 shows
an SBM.
The sea island is a platform-type
structure alongside which tankers can be
berthed. Sea islands consist of loading/
unloading platforms with necessary pilings
for absorbing the impact of ships as they
come alongside. Unloading is via metal
arms, and oil is transferred to shore by
pipeline. Fixed berths (such as sea is-
lands) require a more sheltered area than
SBM's, and tankers can only be moored in
modest waves (less than three feet gen-
erally) . Tugs are required to aid in
mooring. Figure 3-19 shows a sea island
facility.
3-43
-------
Discharging/ loading tanker
SINGLE BUOY MOORING FACILITY
Mooring lines
Mono mooring buoy.
,-• \\ Floating hoses
\f^
Mooring chains
Underwater hoses
Pipe lines to shore tank farm
Anchors
Figure 3-18. Single Buoy Mooring Facility
Source: Interior, 1973: 1-6.
-------
merer station
2 products or transhipment
berths
submarine pipelines
2 crude berths
SEA ISLAND
Figure 3-19. Sea Island Mooring Facility
Source: Interior, 1973: 1-13.
-------
TABLE 3-11
DEEPWATER PORT ALTERNATIVES
Single Buoy Mooring (SBM)
Sea Island
Artificial Islands
Advantages
Suited to higher sea state:
10-12 feet to berth,
25 feet once moored.
Flexible on-siting,
orientation (ship swings
with wind, current).
Less damage prone in poor
approach (can be ducked
easily and tried again).
Less costly for one berth.
Disadvantages
Access is difficult to
crews and supplies.
Flexible and floating hose,
risers are liable to damage
(mechanical, fatigue,
corrosion) and pollution
(drainage difficult).
Loading rate generally lower.
Can be designed for waves:
10 feet longitudinal,
5 feet beam, while moored.
Orientation conditions by
wind and wave directions.
Damage to pilings and plat-
form are costly in time
and dollars.
Less costly than SBM for
several berths.
Access somewhat easier than
SBM.
Steel loading arm better
than aluminum or flexibles.
Higher loading rates than
SBM.
Same as sea island.
Same as sea island
Damage at T-pier
connections endangers
pipelines.
Less costly for high
loading rates
and short offshore
distances.
No access problems.
Same as sea island.
No limits on loading
rates.
Source: Interior, 1973: 1-18.
Artificial islands are the most expen-
sive type of deepwater port, but they also
offer the most versatility. Construction
of an island would require transporting
earth and rock to the site and placing the
material in the sea in a manner that would
insure minimum loss due to currents and
waves. The island would be used for both
unloading and storage, and would have berth-
ing facilities on all four sides. Berthing
would be subject to the same sea state lim-
itations as a natural island, and a break-
water would probably be used to permit op-
eration in heavy seas. Figure 3-20 shows
an artificial island mooring facility.
Table 3-11 gives the advantages and disad-
vantages of the alternative deepwater ports.
3.7.2 Energy Efficiencies
The energy efficiencies for importing
crude by tanker or supertanker are the same
as those for transporting domestic crude in
the same carrier. The primary efficiency
is very nearly 100 percent, and the ancil-
lary energy requirements, primarily for
ship fuel, are about four percent for the
assumed 10,000-mile trip. The detailed
data is presented in Section 3.6.3.
3.7.3 Environmental Considerations
Although the sulfur content of most
imported crude is greater than that of
domestic crude, this is not reflected in
the environmental residuals for imports
because the transportation of imports is
3-46
-------
Platform
or
Island
^
Breakwater
V;
Figure 3-20. Artificial Island Mooring Facility
Source: Interior, 1973: 1-17.
-------
Table 3-12. Residuals from Refining Imported Crude Oil
SYSTEM
Canadian Crude/Imported
Uncontrolled
Controlled13
Imported
Uncontrolled13
Controlled13
Conventional Refinery
Arabian Crude0
Kuwait Crude0
Toppincr Refinerv
Kuwait Crude0
Water Pollutants (Tons/1012 Btu's)
Acids
U
U
U
U
.2
.2
.08
Bases
U
U
U
u
NC
NC
NC
•*
S
NA
NA
NA
NA
NC
NC
NC
m
g
NA
NA
NA
NA
NC
NC
NC
Total
Dissolved
Solids
35.8
34.
35.8
34.
SO.
50.
48.9
Suspended
Solids
22.2
.694
22.2
.694
2.2
2.2
2.2
Organics
6.
.35
6.
.35
NC
NC
NC
n
S
6.92
.694
6.92
.694
NC
NC
NC
O
8
20.2
4.24
20.2
4.24
NC
NC
NC
Thermal
(Btu's/1012)
7.06
x!0lc
0
7.06
Xl0lc
0
0
0
0
Air Pollutants (Tons/10 Btu's)
Particulates
9.1
2.73
9.1
2.73
1.1
1.1
4.9
X
9.
22. B
19.7
22.8
19.7
12.8
12.8
16.8
X
o
w
179.
17.6
584.
40.3
SO 2
66.7
SO 2
83.3
SO 2
38.6
Hy d roc a rbon s
232.
23.6
232.
23.6
13.9
13.9
7.1
R
611.
.166
611.
.166
1.7
1.7
0
Aldehydes
3.73
3.71
3.73
3.71
NC
NC
NC
Solids
(Tons/1012 Btu's)
7.57
43.7
7.57
43.7
3.9
3.9
3.8
F/I*
Land
Acre-year
tn
P
.LJ
CQ
M
O
10.3/0
10.3
10.3/0
10.3
10.3/0
10.3
10.3/0
10.3
U/U
1.
U/U
1.
U/U
1.
Occupational
Health
1012 Btu's
Deaths
4.4
xlO-4
4.4
xlO~4
4-4,,
xlO-4
4.4
xlO-4
.0014
.0014
.0014
Injuries
.0362
.0362
.0362
.0362
.11
.11
.11
4J
Ifl
O
ij
If)
>,
re
Q
1
c
re
S
2.05
2.05
2.05
2.05
25.
25-
25.
NA = not applicable, NC = not considered, U = unknown.
aFixed Land Requirement (Acre - year) / Incremental Land. Requirement ( Acres ) .
1012 Btu's 1012 Btu's
bHittman, 1974: Vol. I, Tables 19, 20, 21, and 22.
cBattelle, 1973: Tables A-40, and A-41.
-------
assumed to be in the same carriers or kinds
of carriers used for domestic transport.
This is not likely to be the case, however,
as more and more imports are being carried
in supertankers. For a discussion of the
residuals and problems associated with
supertankers, see Mostert (1974). The de-
tailed data are presented in Section 3.6.4.
However, the presence of high sulfur levels
is reflected in refinery residuals as shown
in Table 3-12. The data are considered
fair; that is, accurate to within 100 per-
cent. All water and most air residuals are
the same as for domestic oil, but SC>2 re-
siduals are 17.6 tons per 10 Btu's energy
input for controlled refineries and 179
12
tons per 10 Btu's energy input for uncon-
trolled refineries using Canadian crude.
Using Middle East crude, SOx residuals are
12
40.3 tons per 10 Btu's energy input for
12
controlled refineries and 584 tons per 10
Btu's energy input for uncontrolled refin-
eries (Figure 3-2). Land use residuals are
unchanged from domestic oil refining.
3.7.4 Economic Considerations
The economics of tanker transportation
are assumed to be the same for domestic and
foreign crude with the only distinction
arising from the different distances in-
volved. Figure 3-21 illustrates the econo-
mies of scale attainable in tanker trans-
port of crude oil by using larger vessels.
Costs given are 1967 figures. Table 3-13
compares the approximate costs of crude
transport from Venezuela, North Africa, and
the Persian Gulf. Although the economies
of scale are obvious in this data, the po-
litical considerations surrounding the con-
struction of deepwater ports and the price
of Middle East crude will have a much
greater effect than the mode of transporta-
tion used.
TABLE 3-13
COST OF CRUDE OIL TRANSPORT FROM VENEZUELA,
NORTH AFRICA, AND THE PERSIAN GULF (1967 DOLLARS)
Ship Size
(dead weight
tons)
65,000
250,000
326,000
500,000
Cost Per Barrel of Oil Transported
Venezuela
(4,000 miles
round trip)
$ .28
.21
.18
.15
North Africa
(8,000 miles
round trip)
$ .52
.37
.34
.28
Persian Gulf
(24,000 miles
round trip)
$1.34
.97
.91
.81
Source: Interior, 1973: 1-41.
3-49
-------
I
d co
°§
U. _j
o _i
ct:
CO <
oa:
01-
2.00
1.50
1.00
.50
,10,000 nautical miles
-6,000 nautical miles
'3,000 nautical miles
500 nautical miles
0 200 400 600
VESSEL DEADWEIGHT TONS
(THOUSANDS)
800
Figure 3-21. Costs of Tanker Transport
Source: Interior, 1973: 1-41.
-------
REFERENCES
Battelle Columbus and Pacific Northwest
Laboratories (1973) Environmental Con-
siderations in Future Energy Growth.
Vol. I: Fuel/Energy Systems: Techni-
cal Summaries and Associated Environ-
mental Burdens, for the Office of Re-
search and Development, Environmental
Protection Agency. Columbus, Ohio:
Battelle Columbus Laboratories.
G.G. Brown and Associates (1960) Unit Oper-
ations . New York: John Wiley and
Sons, Inc.
Bureau of Land Management (1972) Final En-
vironmental Statement; Proposed 1972
Outer Continental Shelf Oil and Gas
General Lease Sale Offshore Louisiana.
Washington: Department of the Inte-
rior.
Bureau of Mines (1970) Potential Oil Recov-
ery by Waterflooding Reservoirs Being
Produced by Primary Methods, Informa-
tion Circular 8455. Washington: Gov-
ernment Printing Office.
Cameron Iron Works, Inc. (1973) Cameron Oil
Tool Products 1972-1973. Houston:
Cameron Iron Works, Inc.
Council on Environmental Quality (1974) PCS
Oil and Gas—An Environmental Assess-
ment. Washington: CEQ.
Department of the Interior (1972) Statement,
Questions and Policy Issues Related to
Oversight Hearings on the Administra-
tion of the Outer Continental Shelf
Lands Act, Held by the Senate Committee
on Interior and Insular Affairs, Pursu-
ant to S. Res. 45, March 23, 1972.
Washington: Interior.
Department of the Interior (1973) Draft En-
vironmental Impact Statement: Deep-
water Ports. Washington: Interior.
Federal Energy Administration (1974) Project
Independence Blueprint. Washington:
Government Printing Office.
•Ford Foundation, Energy Policy Project (1974)
A Time to Choose; America's Energy
Future. Cambridge, Mass.: Ballinger
Publishing Co.
Geffen, Ted (1973) "Improved Oil Recovery
Could Help Ease Energy Shortage."
World Oil 177 (October 1973): 84-88.
Gillette, Robert (1974) "Oil and Gas Re-
sources: Did USGS Gush Too High."
Science, 185 (July 12, 1974): 127-130.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts, Efficiency, and
Cost of Energy Supply and End Use, Fi-
nal Report: Vol. I, 1974; Vol. II,
1975. Columbia, Md.: Hittman Asso-
ciates, Inc.
Kash, Don E., Irvin L. White, Karl H.
Bergey, Michael A. Chartock, Michael
D. Devine, R. Leon Leonard, Stephen
N. Salomon, and Harold W. Young (1973)
Energy Under the Oceans: A Technology
Assessment of Outer Continental Shelf
Oil and Gas Operations. Norman, Okla.:
University of Oklahoma Press.
Lindsey, J.P., and C.I. Craft (1973) "How
Hydrocarbon Reserves Are Estimated
from Seismic Data." World Oil 177
(August 1, 1973): 24-25.
McCulloh, T.H. (1973) "Oil and Gas," pp.
477-496 in Donald A. Brobst and Walden
P. Pratt (eds) United States Mineral
Resources, USGS Professional Paper
820. Washington: Government Printing
Office.
Mostert, Noel (1974) Supership. New York:
Alfred A. Knopf.
National Petroleum Council (1970) Future
Petroleum Provinces of the United
States. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook (1971) U.S. Energy
Outlook: An Initial Appraisal, 1971-
1985. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook (1972) U.S. Energy
Outlook. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook, Oil and Gas Sub-
committees, Oil and Gas Supply Task
Groups (1974) U.S. Energy Outlook:
Oil and Gas Availability. Washington:
NPC.
Peel, D.H. (1970) "The Character of Crude
Oil," pp. 154-170 in British Petroleum
Co., Ltd., Our Industry Petroleum.
London: BP.
Radian Corporation (1974) Final Report: A
Program to Investigate Various Factors
in Refinery Siting, for the Council on
Environmental Quality and the Environ-
mental Protection Agency. Austin, Tex.
Radian Corporation.
3-51
-------
Teknekron, Inc. (1973) Fuel Cycles for Elec-
trical Power Generation. Phase I: Tg^
wards Comprehensive Standards; The
Electric Power Case, report for the
Office of Research and Monitoring, En-
vironmental Protection Agency.
Berkeley, Calif.: Teknekron.
University of Texas, Division of Extension,
Petroleum Extension Service (1957)
A Primer of Oil Well Drilling, 2nd ed.
Austin: University of Texas, Division
of Extension, Petroleum Extension Ser-
vice.
Watkins, R.E. (1970) "Transport of Crude
Oil," pp. 130-143 in British Petroleum
Co., Ltd., Our Industry Petroleum.
London: BP.
White, Irvin L., Don E. Kash, Michael A.
Chartock, Michael D. Devine, and R.
Leon Leonard (1973) North Sea Oil and
Gas; Implications for Future United
States Development. Norman, Okla.:
University of Oklahoma Press.
3-52
-------
CHAPTER 4
THE NATURAL GAS RESOURCE SYSTEM
4.1 INTRODUCTION
The first recorded use of natural gas
in the U.S. was in Fredonia, New York in
1821. Early usage tended to be localized
and many utilities distributed gas manufac-
tured from coal. In 1947, a major change
in the character of the industry occurred
when natural gas from the Southwest reached
the East Coast through two converted liquid
pipelines, the "big inch" (crude oil) and
the "little inch" (refined crude oil prod-
ucts) . Since then, the consumption of
natural gas in all end-use classifications
(residential, commercial, industrial, and
power generation) has increased rapidly.
This growth has resulted from several fac-
tors, including: the development of new
markets; replacement of coal as a fuel for
providing space and industrial process
heat; use in making petrochemicals and
fertilizers; and the strong demand for low-
sulfur fuels that emerged in the mid
1960's.
As a result of these expanded end
uses, local utility gas mains increased
from 218,000 miles in 1945 to 906,925 miles
in 1970 (Zareski, 1973). The high-pressure
natural gas transmission network was ex-
tended into all the lower 48 states and,
by 1970, included 269,610 miles of pipe and
4.0 million horsepower of compression,
representing a total undepreciated, origi-
nal cost investment of $18.6 billion (FPC,
1974a: 62) . However, the rapid growth
record and structure of the industry may
soon change drastically in response to a
new pattern of gas supply.
All phases of development and utili-
zation of gas resources are provided by
private industry and fall within three
fairly well-defined segments: supply;
transmission; and distribution. Although
large corporations dominate the individual
segments, the industry is not character-
ized by vertical integration from the gas
field to the consumer. For the most part,
the gas industry consists of transmission
companies that buy their gas from the oil
industry and distribution companies that
sell the gas to the ultimate consumers.
This chapter contains a description
of the natural gas resource system and a
discussion of the technologies involved in
exploration, extraction (including drilling
and production technologies), and transpor-
tation (including transmission, storage,
and distribution technologies). Because
of the potential importance of imported
natural gas, both the resource and tech-
nologies descriptions include portions that
focus on foreign resources and import tech-
nologies.
As shown in Figure 4-1, the develop-
ment of natural gas involves four major
activities: exploration, drilling, pro-
duction, and a substantial range of trans-
portation or transmission alternatives.
Present domestic and imported Canadian gas
is transported via pipelines. Future im-
ports (and perhaps Alaskan gas as well)
will likely involve transportation in the
form of liquefied natural gas (LNG). This
option involves several distinct technolo-
gies which will also be covered in this
chapter.
4-1
-------
4.2
Natural Gas
Import
Resource
Base
4.2
Domestic
Natural Gas
Resource
Base
4.6
Liquefaction
4.6
Tanker
4.6
Transportation
45
Pipeline
Revaporization
Imports
4.3
4.4
Exploration
Extraction
Drilling
Production
4.4
Natural Gas
Plant
Involves Transportation
Does Not Involve Transportation
4.5
Storage
Gas
Liquid (LPG)
Products
4.5 Transportation Lines
Figure 4-1. Natural Gas Resource Development
-------
4.2 CHARACTERISTICS OF THE RESOURCE
4.2.1 Natural Gas Classifications
Although natural gas resources are
classified in numerous ways, three summary
classifications will be used in this chap-
ter: proved reserves; potential supply;
and ultimate supply. Proved reserves are
discovered gas that can be produced under
current economic and operating conditions.
Potential supply is that portion of the
resource that may be found and proved pro-
ductive in the future. Ultimate supply is
the total quantity of producible resources;
it includes past production, proved re-
serves, and potential supply.
The potential supply classification
reflects an estimate of future conditions,
such as the level of exploration, state of
technology, and economics. The impacts of
these considerations have been central to
the continuing debate over the effect of
government regulation on the development
of gas supplies.
4.2.2 Physical Characteristics
Dry natural gas is composed primarily
of hydrocarbons (compounds containing only
hydrogen and carbon). Methane (CH4), the
simplest and most basic compound of the
hydrocarbon series, is the major component.
Others, fractionally small but important,
include ethane (C-Hg), propane (C-jHg), bu-
tane (C.H. 0), and heavier, more complex
hydrocarbons. In processing, most of the
butane and heavier hydrocarbons, as well
as a portion of the ethane and propane, are
frequently removed from the gas in the form
of liquids. Jfost of the water, gaseous
sulfur compounds, nitrogen, carbon dioxide,
.and other impurities found in natural gas
are also removed in various processing
stages. The composition and the Btu con-
tent of unprocessed natural gas produced
from different reservoirs vary widely as
illustrated in Figure 4-2.
In addition to composition and Btu
content, gas is commonly designated in
terms of the nature of its occurrence
underground. It is called nonassociated
gas if found in a reservoir that contains
a minimal quantity of crude oil and either
dissolved or associated gas if found in a
crude oil reservoir. Dissolved gas is
that portion of the gas dissolved in the
crude oil, and associated gas (sometimes
called gas-cap gas) is free gas in contact
with the crude oil. All crude oil reser-
voirs contain dissolved gas and may or may
not contain associated gas.
Some gases are called gas condensates
or simply condensates. Although conden-
sates occur as gases in underground reser-
voirs , they have a high content of hydro-
carbon liquids which may yield on produc-
tion.
4.2.3 Domestic Resources
In the .following description of the
domestic gas supply, the quantities esti-
mated for proved reserves and for potential
gas supply will be presented for three
regions—onshore lower 48 states, offshore
lower 48 states, and Alaska—in addition
to total U.S. figures.
4.2.3.1 Quantity of the Resources
The estimates of domestic ultimate
supply made for the lower 48 states and
Alaska since 1950 range from about 200
trillion cubic feet (tcf) to 2,995 tcf,
with more recent estimates ranging from
1,000 to 2,955 tcf (FPC, 1974b: 14, 168).
Table 4-1 summarizes the more widely quoted
estimates (Potential Gas Committee, 1973;
Interior, 1974) of potential supply pre-
sented on the basis of lower 48 states on-
shore, lower 48 states offshore, Alaska,
and total U.S.
The variation in proved reserves from
1946 to 1973 as compiled by the American
Gas Association (AGA) (AGA and others.
4-3
-------
SELECTED SAMPLES OF NATURAL GAS
LOCATION, GEOLOGIC FORMATION
AND HEATING VALUE PER C. F.
McDowell County, West Va.
Lime and Weir
(1014 BTU)
Williams County, North Dakota
Red River
(1032 BTU)
Morgan County, Colorado
D. Sand
(1228 BTU)
Schleicher County, Texas
Straw Reef
(1598 BTU)
m
HHe<
fe£
Heavier Hydrocarbons
San Juan County, Utah
Mississippian
(717 BTU)
• Inerts, Impurities, and
I Other Trace Components I
Figure 4-2. Selected Samples of Unprocessed Natural Gas
Source: FPC, 1974a: 6,
-------
TABLE 4-1
NATURAL GAS RESOURCES (TRILLIONS OF CUBIC FEET)
Area
Lower 48 states
Onshore: 0 to 15,000 feetd
below 15,000 feetd
TOTAL
Offshore: 0 to 600 feetf
600 to 1,500 feet
Lower 48 states i TOTAL
Alaska
TOTAL U.S.
Proved
Reserves
AGAa
NC
NC
182. 2e
NC
NC
36. le
218.3
31.6
250.0
Potential Supply
PGCb
413
137
550
203
27
230
780
366
1,146
USGSC
NC
NC
593-1,177
NC
NC
247- 493
840-1,670
290- 580
1,130-2,250
NC = not considered.
Sources: iJased on year end 1973 statistics published by American Gas
Association (AGA and others, 1974).
bPotential Gas Committee (PGC, 1973).
CU.S. Geological Survey (Interior, 1974).
Refers to drilling or formation depth.
eBased on the ratio of lower 48 states offshore to lower 48 states total
reserves in 1972 of 16.5 percent.
Refers to water depth. Applies to PGC data only. USGS water depth
limitation for undiscovered recoverable resources is 200 meters.
1974) is shown in Figure 4-3. The proved
reserves as of the year ending 1973 were
218.3 tcf for the lower 48 states, with
approximately 36.1 tcf offshore and 182.2
tcf onshore and 250.0 tcf for the total
U.S. (Table 4-1). At the current annual
production rate, the life of the reserves
(i.e., the reserve-to-production [r/p]
ratio) is 9.7 years with Alaska excluded
and 11.1 years with Alaska included.
Figure 4-3 also shows that the r/p ratio
has declined steadily for the last 30
years.
The first year that more gas was pro-
duced than found in the lower 48 states was
1968. Similar deficits have been realized
each succeeding year, and the overall quan-
tity of domestic gas produced was more than
twice the quantity found in the lower 48
states during the period 1968 to 1973. The
accelerated decline in the r/p ratio during
that period reflects both the decreasing
reserves base and an increasing production
rate.
4-5
-------
Proved Reserves and Reserves to Production Ratio
0)
a
*J5
3
o
300r
250
200
150
00
Proved reserve
(left scale)
/P ratio
(right scale)
"excluding Alaska
_L
40
30
20
10
o
"5
Q.
x.
tr
1945 1950
1955
I960 1965
1970 1975
Figure 4-3. U.S. Natural Gas Proved
Reserves and Reserves-to-Production Ratio
Source: FPC, 1974b: 22.
-------
4.2.3.2 Accuracy of Resource Estimates
The variation in estimates of poten-
tial gas supply suggests that these are
only order-of-magnitude figures and can
serve as little more than a basis for
rough, pragmatic analyses of energy policy
alternatives. Similarly, ultimate supply
is subject to the same degree of uncer-
tainty because potential gas supply is one
of its constituent elements.
Although proved reserves figures can
be stated with greater certainty than ul-
timate and potential supply figures, they
are also only estimates. Reserves are
based on the best engineering, geological,
and economic data available and the judg-
ment of the estimator. The latter element
visually accounts for the difference between
evaluations. Because of the importance of
having reliable reserves data, the Federal
Power Commission's (FPC's) National Gas
Survey conducted a National Gas Reserves
Study (NGRS) (FPC, 1973a) to yield an
independent estimate of the total proved
gas reserves in the U.S., including Alaska
and the offshore areas, as of December 31,
1970.
The NGRS estimate of 258.6 tcf was
9.8 percent lower than the corresponding
AGA estimate of 286.7 tcf. However, minor
variations in the results obtained by com-
petent technical groups using recognized
and accepted methods for calculating and
compiling reserves estimates are to be
expected. For all practical purposes, the
agreement between the two total estimates
is reasonable, and the reported reserve
estimates seem to provide a reliable basis
for short-term forecasting.
4.2.3.3 Location of the Resources
Approximately 88 percent of the natu-
ral gas reserves in the lower 48 states
are located in five southern and southwest-
ern states: Texas, Louisiana, Oklahoma,
Iffiw Mexico, and Kansas (AGA and others,
1974) . Of the gas moving through the
interstate pipeline system, about 79 per-
cent originates in Texas, Louisiana, and
Oklahoma (FPC, 1974a: 62) as indicated by
the general pattern of gas flow illustrated
in Figure 4-4.
Based on data for proved reserves and
USGS estimates of potential supply given
in Table 4-1, 73 percent of the reserves
and 52 percent of the potential gas are
located in the onshore lower 48 states, 14
percent of the reserves and 22 percent of
the potential gas are located in the off-
shore lower 48 states, and 13 percent of
the reserves and 26 percent of the poten-
tial gas are located in Alaska.
Gas production in Alaska has been con-
fined to the southern part of the state,
primarily to support an LNG export project
to Japan. However, the current activity
on the North Slope has generated consider-
able public awareness. The estimate of
t he proved reserves for the Prudhoe Bay
area of the North Slope is 26 tcf as com-
pared to total Alaskan proved reserves of
31.6 tcf (AGA and others, 1974). The dis-
covery of the Prudhoe Bay field has estab-
lished the existence of oil and gas in a
region containing a large volume of poten-
tially hydrocarbon-bearing geological for-
mations; nevertheless, the proved reserves
of the Prudhoe Bay field alone are only
slightly more than the amount of gas con-
sumed in the U.S. in 1973.
The availability of future Alaskan
gas depends on the completion of the trans-
Alaska pipeline system (TAPS) as discussed
in Section 4.5.1.1.1. The North Slope gas
reserves consist of associated and dis-
solved gas, and gas production is contin-
gent on oil production. Because of venting
and flaring restrictions in Alaska, oil
production is also somewhat contingent on
developing an outlet for gas production as
it may not be economically feasible to re-
inject into the reservoir the quantity of
of gas produced at a specified oil produc-
tion rate.
4-7
-------
1970 INTERSTATE NATURAL GAS MOVEMENTS
I
0 10,000
VOLUME
(billions of cubic feet per year)
Figure 4-4. Interstate Natural Gas Movements
Source: FPC, 1974a: 63.
-------
TABLE 4-2
FEDERAL NATURAL GAS RESOURCE OWNERSHIP
(PERCENTAGE OF DOMESTIC TOTAL)
Offshore
Onshore
TOTAL
Reserves
15
6
21
Resources
36
8
44
Production
in 1972
16
6
22
Source: Ford Foundation, 1974: 271.
4.2.3.4 Ownership/Control of the Resources
The increasing role of government own-
ership in the development of natural gas
parallels that for crude oil as discussed
in Chapter 3. This reflects, in substan-
tial part, government ownership of Alaskan
and offshore resources. The ownership of
natural gas resources is clearly shown in
Table 4-2.
4.2.4 Foreign Resources
As noted in the introduction, the U.S.
may rely on gas imports in the years ahead.
A brief summary of foreign gas resources
is presented here.
4.2.4.1 Canada
Western Canada contains over 99 per-
cent of Canada's proved reserves (FPC,
1974c: 35) but only 15 percent of Canada's
potential supply (FPC, 1974c: 39). The
bulk of the potential supply is attributed
to the frontier provinces. Estimates are
that about 31 percent of potential supply
is located in the Arctic Islands, about 12
percent in the Mackenzie Delta, and about
35 percent in the Atlantic offshore (FPC,
1974c: 38). Future Canadian export autho-
rizations will probably depend on suffi-
cient development of the frontier gas to
justify a pipeline. Potential pipeline
routes for transmission of gas to the U.S.
from the frontier provinces and the Atlantic
offshore are shown in Figure 4-5.
4.2.4.2 Mexico
Although gas imports from Mexico aver-
aged approximately 50 billion cubic feet
(bcf) per year from 1958 to 1969, they de-
clined to 1.6 bcf in 1973 as compared to
exports of 13 bcf from the U.S. to Mexico.
The relatively small natural gas resource
base and the long-standing Mexican policy
of "self sufficiency in energy" make it
improbable that Mexico will be a major
source of future U.S. pipeline imports.
The impact of the recently reported dis-
coveries on Mexican import policy cannot
be assessed at this time.
4.2.4.3 World
Statistics on the reserves, production,
and consumption of natural gas throughout
the world were developed by members of the
Supply Technical Advisory Task Force-
Liquefied Natural Gas of the FPC's National
Gas Survey (FPC, 1973b: 351, 352). As of
the end of 1971, statistics for the coun-
tries with reported reserves in excess of
30 tcf and the world totals as adapted
from the LNG Task Force report are shown
in Table 4-3. However, data on foreign
reserves are even less reliable than those
for the U.S. Published information is
often inconsistent, and various values can
usually be found for a given country. This
occurs in part because the definition of
"reserves" varies widely throughout the
world. Table 4-3 represents a choice of
what was believed by members of the LNG
Task Force to be the most likely estimate
from the range of information available.
Table 4-3 shows that many world re-
gions containing large volumes of developed
gas reserves have limited internal markets.
As indicated in the tables, world produc-
tion exceeds consumption, and a significant
proportion of the gas is apparently wasted.
4-9
-------
PROPOSED PIPELINE ROUTES
Gas —
A Arctic gas project
B Polar gas project Q
C Sable Island project g
Oil
D Trans-Alaska project
SIGNIFICANT DISCOVERIES
Gas
1 Prudhoe Bay
2 Mackenzie Delta
3 Drake Point
4 King Christian Island
5 Ellef Ringnes Island
6 Sable Island
Oil
Prudhoe Bay
2 Mackenzie Delta
Elle f Ringnes
Sable Island
Fosheim Peninsula
Figure 4-5. Proposed Canadian Natural Gas
Pipeline Routes and Oil and Gas Discoveries
Source: FPC, 1974c: 36.
-------
TABLE 4-3
ESTIMATED RESERVES, PRODUCTION, AND CONSUMPTION
OF NATURAL GAS BY COUNTRY
(TRILLION CUBIC FEET)
Country
USSR (Russia)
United States
Iran
Algeria
The Netherlands
Canada
Saudi Arabia
Nigeria
United Kingdom
Kuwait
Venezuela
Others
WORLD TOTALa
Reserves
(December 1971)
547.4
278.8
197.0
106.5
83.0
55.5
50.9
40.0
40.0
35.0
31.6
279.4
1,745.1
Production
(1970)
7.1
23.8
1.1
0.3
1.1
2.7
0.7
0.3
0.4
0.5
1.7
6.3
45.9
Consumption
(1970)
7.1
22.0
0.4
0.1
0.7
2.3
0.1
minimal
0.4
0.2
0.3
4.6
38.3
Source: Adapted from FPC, 1973b.
aTotals may not add due to rounding.
The FPC's National Gas Survey identified
21 sources of LNG with adequate reserves
for supporting potential long-term import
projects to the U.S. (FPC, 1973b: 344).
Although operational dates for the proposed
projects are uncertain and specific pro-
jects cannot be identified beyond 1980,
current activity seems to indicate a pat-
tern of long-term importation of LNG into
•the contiguous U.S. Table 4-4 shows
various projections of long-term U.S.
imports of LNG.
,4.3 EXPLORATION
The following description of the tech-
nologies involved in the natural gas re-
source system covers both the domestic and
import options identified in Figure 4-1.
Since many of these technologies are the
same as those used in developing crude oil,
references are made, where appropriate, to
Chapter 3 rather than repeating descrip-
tions .
One new gas exploration method is the
"bright spot" technique. This technique
indicates the presence of both free gas
reservoirs and of the nonassociated gas
portions of "gas caps" at crude oil reser-
voirs. However, it does not respond to
dissolved gas and thus cannot be used to
search for crude oil reservoirs without
gas caps.
The "bright spot" technique has been
extremely useful in identifying potentially
4-11
-------
TABLE 4-4
PROJECTIONS OF LIQUEFIED NATURAL GAS IMPORTS
(TRILLION CUBIC FEET)
Federal Power Commission
Department of the Interior
National Petroleum Council0
Low-Case
High-Case
Institute of Gas Technology
American Gas Association6
National Gas Survey
Low-Case
High-Case
1980
2.0
0.9
2.3
2.3
1.1
1.7
0.4
3.2
1985
3.0
1.6
3.2
3.9
1.6
2.7
0.4
3.8
1990
4.0
NC
NC
NC
2.1
3.2
0.4
4.7
NC = not considered.
Sources: aFPC, 1972: 70.
blnterior, 1972a: 32.
CNPC, 1972: 133.
dLinden, 1973.
eHardy, 1974.
fFPC, 1974b: 4, 5.
productive zones among the younger, very
permeable formations in the Gulf of Mexico.
However, its effectiveness may be limited
to these special conditions. The technique
may prove less effective for locating res-
ervoirs in other regions or for identifying
hard to find stratigraphic traps which are
not normally indicated by classical geo-
physical techniques.
4.4 EXTRACTION
4.4.1 Technologies
4.4.1.1 Drilling
There are no substantive differences
between gas drilling technologies and the
oil drilling technologies described in
Chapter 3.
4.4.1.2 Product ion
4.4.1.2.1 Well Completion
For the purposes of this report, there
are no substantive differences in the equip-
ment and techniques used to complete natu-
ral gas wells and those described in Chap-
ter 3 for oil wells.
4.4.1.2.2 Fluid Processing
Natural gas may be produced in asso-
ciation with oil (associated and dissolved
gas) or from predominantly gas (nonasso-
ciated gas) wells. However, once the gas
is produced, processing technologies differ
significantly from those for crude oil.
The following sections discuss field sepa-
ration of the produced fluids, compression,
natural gas plants, and sulfur removal
4-12
-------
plants. Although the technologies involved
in systems for gathering the produced gas
and injecting it into high-pressure pipe-
lines do not differ significantly from
those used for other fluids, these are dis-
cussed in Section 4.5.
The processing method selected for a
particular gas depends on factors such as
its type and composition, the geographic
location of the source, and the proximity
of natural gas transmission lines. For
example, different processing methods may
be used for similar gas produced from on-
shore and offshore wells. Also, some pro-
cessing may be done to make the gas suit-
able for pipeline transmission or sales,
while other processing is done to recover
valuable products, including a wide range
of hydrocarbon liquids.
4.4.1.2.2.1 Field Separation of Produced
Fluids
Processing requirements for produced
gas vary widely. Natural gas produced
from a nonassociated gas reservoir (i.e.,
one which contains little or no oil) may
require minimal treatment before it is
transferred to the transmission line. Con-
versely, associated gas, dissolved gas,
and gas condensates may require full pro-
cessing before they are marketable.
Generally, fluids from both oil and
gas wells are first treated to remove water
and sand, then passed through a single
separator or a sequence of separators
depending on the composition and the na-
ture of the produced fluids. Both water
and water vapor must be removed from the
gas to prevent formation of hydrates
(solid snow-like compounds of water and
methane) . Hydrates form as the result of
the cooling which accompanies gas expansion
and can plug wellhead valves, metering
equipment, and pipelines. If formation of
hydrates is a problem in a particular
field, the produced fluids may be heated
at the wellheads prior to flow into any
gas processing equipment to deter hydrate
formation before treatment.
Normally, the produced stream from a
crude oil reservoir is separated in a
single stage by passing it through a free
water knockout separator to remove water
and sand and then through a low-pressure
separator to split the oil and gas streams.
The separation of associated gas and con-
densates may be done in several stages to
increase the recovery of liquid hydrocar-
bons. In the three-stage separation pro-
cess shown in Figure 4-6, the first stage
(a high-pressure separator) separates the
liquid hydrocarbons from the gas by expand-
ing the stream of well fluids. Liquid from
the first stage separator is partially
vaporized in the second stage (an inter-
mediate-pressure separator) and additional
gas is recovered. The remaining liquid
then passes to the third stage (a low-
pressure separator) for additional vapori-
zation and gas removal. The liquid remain-
ing after the third separation stage is
transferred to storage. Three-stage sepa-
ration is frequently hard to justify eco-
nomically and is not as commonly used for
gas wells as two-stage separation.
The type of gas produced and the pro-
cessing methods required determine the
amount of gas marketed. Normally, the
produced fluid stream from crude oil reser-
voirs is processed using a single-stage,
low-pressure separator. Frequently, the
gas recovered from a single separator can-
not be economically compressed and trans-
mitted to shore or to an existing gas pipe-
line. Consequently, this gas is often
vented to the atmosphere or flared. Energy
losses and environmental residuals resulting
from these and other operations are dis-
cussed in Sections 4.4.2 and 4.4.3.
4.4.1.2.2.2 Compression
Since pressures are normally high in
the early production life of a gas reser-
voir, compression may be needed to transmit
4-13
-------
i
Wellhead
p
|»r
1
hor
High- Interm
ressure pressu
gas 4 i
V.
Q) O
O"«
22
to a
a
^- 0)
W (/}
r
Liquid 1
0>fc_
0>O
o+~
£o
%>
a
•oci
CQ>
f\lw
ediate- Low
re gas pres
. i
r
Liquid |
w w
0)
Cnv.
52
too
w
O
•pa.
.Xa>
to to
f-
>sure
gas
Liquid
W
Liquid
hydrocarbon
storage
Figure 4-6. Three-Stage Wellhead Separation Unit
Source: Adapted from Handbook of Natural Gas Engineering^
by D. L. Katz et al. Copyright 1959. Used with permission
of McGraw-Hill Book Company.
-------
the gas through the gathering system and
into the high-pressure transmission line
only in later reservoir stages. In oil-
gas reservoirs, however, compression is
required throughout the life of the reser-
voirs because all fluids are passed through
low-pressure separators. Thus, depending
on the type and stage of the reservoir, a
range of compressor facilities from indi-
vidual wellhead compressors to a central
compressor station may be required. The
use of individual wellhead compressors
offers the advantage of flexibility,
whereas the use of a central compressor
station offers economy of scale. Section
4.5.1.2 gives a more detailed description
of gas compression.
4.4.1.2.2.3 Natural Gas Plants
When the produced gas is very rich
(i.e., has a high content of natural gas
liquids), complex processing plants may be
required to condition the gas and, indeed,
may be economically attractive because of
the value of the recovered liquids. In
contrast to field separation, these natu-
ral gas plants not only separate the gases
from the produced liquids but split the
liquids into fractions. Separation of the
liquid stream is achieved by distillation
or fractionating towers as described in
the refinery section of Chapter 3. The
plant products are liquefied petroleum (LP)
gases (including propane, butanes, and
propane-butane mixtures), natural gaso-
lines, ethane, plant condensate, and small
amounts of other hydrocarbon mixtures (FPC,
1974a: 93) . "Lean" gas (processed gas) is
normally used to fire the boilers that
provide heat to the fractionation towers
and in the combustion engines that drive
the plant compressors.
Natural gas plants are often used in
conjunction with gas cycling projects.
The lean gas is piped back to the field
and reinjected into the reservoir to en-
hance liquid recovery. Figure 4-7 is a
diagram of a typical cycling operation.
In this example, the liquids are stripped
from the produced gas in the oil absorber.
The residue (dry) gas is returned to the
reservoir. The hydrocarbon liquids are
recovered from the rich oil in the separa-
tion plant, and the lean oil is returned
to the absorber to contact additional pro-
duced fluids. Reservoir reinjection is
used to enhance the recovery of liquids
from gas condensate reservoirs or the crude
oil recovery from crude oil reservoirs
containing gas caps. When the economic
returns from gas reinjection are no longer
attractive, the reservoir is then depleted
using normal production practices.
4.4.1.2.2.4 Sulfur Removal Process
Many natural gases contain hydrogen
sulfide (HpS) in amounts ranging from zero
to as high as 76 percent (Battelle, 1973:
284). As with crudes, gases containing
H-S are termed "sour" and gases essentially
free of H2S are termed "sweet." Sour gases
pose several problems because they are ex-
tremely toxic and corrosive and, when
burned, produce either sulfur dioxide (SO-)
or sulfur trioxide (SO.,) . Consequently,
special grades of steel must be used in
completing and equipping wells and in con-
structing surface facilities for the ex-
traction and processing of sour gases.
Also, because of the danger to operating
personnel, field procedures for sour gases
must contain precautions not required in
the production of sweet gas.
Federal law does not allow more than
.25 grain of H-S per 100 standard cubic
feet (cf) of natural gas (Katz and others,
1959: 612, 613), and individual states
have also set H_S limits. In addition,
the toxic and corrosive characteristics of
H-S necessitate its removal in processing
plants before the gas can be transported
and marketed in the U.S. Desulfurization
is an adjunct to other processing methods
and may be used in conjunction with any
combination of those covered previously.
4-15
-------
Residue gas
Compression plant
Oil absorber
Injection well
Lean oil
Rich oil
Separation
plant
L P gas
Condensate
Production well
Gas condensate reservoir
Figure 4-7. Cycling Operation
Source: Adapted from Handbook of Natural Gas Engineering,
by D. L. Katz et al. Copyright 1959. Used with permission
of McGraw-Hill Book Company.
-------
Because it permits almost complete
removal, the process most commonly used in
these plants is reaction of the H_S with
an ethanolamine in solution or, as it is
commonly called, an amine solution (Katz
and others, 1959: 613, 614). This process
removes both K~B and carbon dioxide (CO-),
which are classified as acid gases, from
the gas stream as shown in Figure 4-8.
After removal from the gas and regeneration
of the ethanolamine solution, the H_S has
often been flared, resulting in the dis-
charge of SO_ (a combustion product) di-
rectly to the atmosphere.
Heat is given off in the reaction be-
tween H_S and the ethanolamine. The etha-
nolamine solution, which has been reacted
with H_S, is regenerated by boiling the
solution to reverse the reaction and strip
out the acid gases before the solution is
recycled to the absorber. Natural gas must
be used as fuel for regenerating the etha-
nolamine solution and for generating steam
to drive process pumps throughout the plant.
When SO_ discharges reach a certain
limit, such as 10 tons per day from a
single source in Texas, sulfur recovery is
required. In current practice, 80 to 95
percent of the H_S is converted to ele-
mental sulfur in a conventional Glaus
*
plant, and the remainder is vented to the
atmosphere unless plant tail gases are
treated. Newer techniques for treating
the tail gas of a Claus sulfur plant in-
clude the Beavon, Shell, and Clean Air pro-
cesses. Although an estimated 99.9 percent
of the sulfur can be recovered when these
processes are used, all are expensive
{Battelle, 1973: 287).
Since the conversion of H_S to sulfur
gives off heat, no fuel need be consumed
in the process except in start-up. In
fact, under certain conditions heat from
the system is used to generate steam.
See Chapter 1 for a discussion of
: Claus plants.
4.4.2 Energy Efficiencies
Overall, about one percent of U.S. gas
production per year is lost through flaring,
venting, and production operations (FPC,
1974a: 24). Offshore losses are higher
than onshore, formerly amounting to about
3.4 percent of all gas produced from both
oil and gas wells on the outer continental
shelf (OCS) (Interior, 1972b: 7). However,
recent FPC actions establishing alterna-
tives for setting higher wellhead prices
for gas that costs more to produce (FPC,
1973c) have resulted in the marketing of
some of this gas, reducing offshore losses
somewhat.
A minimal amount of ancillary energy
is required for natural gas drilling and
production operations. The primary energy
efficiencies of various natural gas extrac-
tion, gathering, and processing technolo-
gies are very high. Also, a portion of the
gas cannot be recovered from the reservoir.
Like the definition for oil, the primary
efficiency factor for gas as given by
Hittman (1974: Vol. I, Table 25) seemingly
includes a reservoir recovery factor of
about 35 percent. However, recovery from
gas reservoirs (that portion of the total
gas in the ground which is extracted)
ranges from 50 to 90 percent. Thus, the
primary efficiency factors given by Hittman
may range from 15 to 55 percent lower than
the efficiencies commonly realized in prac-
tice. Hittman claims the efficiency data
has a probable error of less than 25 per-
cent. (See Table 4-5.)
4.4.3 Environmental Considerations
The considerations involved in the
environmental assessment of natural gas
production differ from those involved in
crude oil production. However, before
these differences are described in detail,
several observations should be made.
As noted in Chapter 3, accidents occur
more frequently in natural gas operations
than in corresponding crude oil operations.
4-17
-------
Purified gas
Acid gas
Sour gas
— ^ I ann nmina end i4-!r\n
r ^
a>
jQ
JO
<
^
ii MIIIIII& owiuiiwn
(
Rich amine solution
.
^
J
X"
^\
•»-
a
"o
a
a>
cr
V^
1
^/
f
Figure 4-8. Amine Treating Process for C02 and H2S Removal
Source: Adapted from Handbook of Natural Gas Engineering,
by D. L. Katz et al. Copyright 1959. Used with permission
of McGraw-Hill Book Company.
-------
TABLE 4-5
EFFICIENCIES FOR EXTRACTING, GATHERING, f( ,
AND PROCESSING NATURAL GAS "'^
Activity
Extraction (onshore)
Extraction (offshore)
Gathering (pipeline)
Processing (natural gas
liquids plant)
Processing (hydrogen
sulfide removal)
Primary
Efficiencya
(percent)
.30 >
30,
89.2
93.4
99.7
Ancillary
Energy
(Btu's per
1012 Btu's)
0
0
0
0
0
Overall
Efficiency3
(percent)
30
30
89.2
93.4
99.7
Source: Hittman, 1974.
aLosses are due primarily to gas escaping to the atmosphere during the
various activities.
Energy efficiencies for wellhead separation are included.
but natural gas operational accidents gen-
erally cause far less environmental damage.
For example, water pollution resulting from
gas well blowouts, gas pipeline leaks, and
malfunctions of gas processing equipment
would be much less severe than from similar
oil operations. The exception, according
to Battelle, is that oxides of nitrogen
(NO ) emissions are higher for gas wells
ithan oil wells (Battelle, 1973: 24). How-
ever, since well classifications are some-
what arbitrary (production from a "gas"
well may range from a very dry gas to crude
with very little gas), gas wells with rela-
tively high liquid production rates should
be viewed as oil wells in an environmental
impact assessment.
Offshore, there are several significant
considerations in siting well and production
facilities. Examples are possible effects
on commercial fishing, navigation, long-term
'ecosystem equilibrium, and esthetics. The
debris resulting from initial construction
, and the drilling muds, water, sand, and
chemical wastes associated with drilling
and processing facilities remain possible
residuals. Present federal regulations
reflect these concerns in requiring that
discharged sand must be free of oil and
discharged water must have an average of
not more than 50 parts per million (ppm)
of oil (Kash and others, 1973: 62).
On land, and in marshes and estuaries,
site preparation should include an analysis
of the cutting and filling needed for the
site, access roads, and other support
activities.
The Hittman residuals for extracting,
gathering, and processing natural gas are
given in Table 4-6. The probable error in
the data is less than 50 percent. An analy-
sis of the more significant of these fol-
lows .
4.4.3.1 Water
No water contaminants are generated
by any of the modes of extraction, gather-
ing, or processing, although some discharge
4-19
-------
Table 4-6. Residuals for Extracting, Gathering, and Processing Natural Gas
NA = not applicable.
aFixed Land Requirement (Acre - Y^r) / Incremental Land Requirement ( *|~- > •
1012 Btu's
SYSTEM
EXT RACT I ON
Offshore
Onshore
GATHERING
PROCESSING
Natural Gas Liouids
Hydrogen Sulfide
Water Pollutants (Tons/1012 Btu's)
Acids
NA
0
NA
NA
NA
Bases
NA
0
NA
NA
NA
8
NA
0
NA
NA
NA
m
i
NA
0
NA
NA
NA
Total
Dissolved
Solids
NA
0
NA
NA
NA
Suspended
Solids
NA
0
NA
NA
NA
Organics
0
0
NA
0
NA
Q
S
NA
NA
NA
NA
NA
P
8
NA
NA
NA
NA
NA
Thermal
(Btu's/1012)
NA
NA
NA
rr~
ir Pollutants (Tons/1012 Btu's)
Particulates
NA
NA
0
.285
.042
^
NA
NA
2.65
1.88
.28
X
O
in
NA
NA
0
0095
.001
Hydrocarbons
NA
NA
0
.63
.094
8
NA
NA
0
.0063
9.4
xlO-4
l§ > Aldehydes
0
157
.02
.0165
in
|2 g Solids
(Tons/10^-2 Bti
NA
V
in
ID 3
<1) 4J
> m
"O CU CM
C H ^
10 U O
^^— ~^*~ — «^- ^-™
.12/0
.62/0
.62
21. 8/ O
21.8
.133/0
.133/0
NA .133
f—
|
Occupational
Health
1Q12 Btu's
.004
xlO"6
.001
,. ,
xlO"5 I .004
.002
025
097
-------
of contaminants such as lubricating oil and
caustic wastes would occur in these opera-
tions. Although it is not a serious prob-
lem, thermal pollution may result from
operation of natural gas and sulfur extrac-
tion plants. The thermal discharge for the
natural gas liquids plant is considered to
be 25 percent of the energy content of the
g
gas used for plant fuel or 7.7x10 Btu's
12
discharged for each 10 Btu's of natural
gas processed. For sulfur removal, the
9
estimate of the thermal discharge (0.8x10
12
Btu's per 10 Btu's) is based on a plant
designed to treat 60 million cubic feet
(mmcf) per day of gas containing one grain
of H2S per standard cubic foot of gas.
If a cooling tower is used, the thermal
discharge to water from either type of
plant is eliminated.
4.4.3.2 Air
The magnitude of the gas discharged
into the atmosphere during extraction is
reported as not applicable in the Hittman
analysis and no other residuals are con-
sidered to be applicable during extraction.
The estimated NO emission level dur-
12
ing gas gathering (2.6 tons per 10 Btu's
gathered) is obtained from the consumption
of 3.67 percent of the produced fuel in
gas engines used to drive compressors. No
other air pollutants are reported by
Hittman for gas gathering. Combustion
products resulting from flaring are not
indicated under either the extraction or
the gas gathering residuals.
Emissions from natural gas liquid
separation and sulfur removal plants come
primarily from the industrial steam genera-
tion boilers. In natural gas liquids
plants, air emissions total about three
12
tons per 10 Btu's processed; these re-
siduals are based on using 3.1 percent of
the gas processed as plant fuel and flaring
0.1 percent. Similarly, the residuals for
sulfur removal are small, totaling 0.4
ton, and are based on using natural gas as
fuel to generate process steam for a 60-
mmcf per day plant. On the basis of gen-
erating 6,000 pounds per hour of 40 pounds
per square inch atmosphere (psia) steam
with 75 percent combustion efficiency, the
fuel required is 0.2 mmcf per day or 0.3
percent.
4.4.3.3 Solids
No solids are generated in the extrac-
tion, gathering, or processing of natural
gas except for elemental sulfur, which is
not a waste product.
4.4.3.4 Land
The land requirements given in Table
4-6 for both the offshore or onshore wells
are based on the use of one acre per well.
Because offshore wells tend to be larger
producers and are produced on platforms,
12
their land requirement per 10 Btu's is
substantially less than that for onshore
wells. The average well productivities
used in Hittman's calculations are based
on 1963 statistics and should be updated.
The gathering system land requirements
assume a 62.5-foot pipeline right-of-way
with compressor stations on 25-acre sites
spaced 187 miles apart. These assumptions
seem inappropriate for analysis of land
requirements for gas gathering systems
because the length of any line or any con-
tinuous path in a gas gathering system is
commonly much less than 187 miles. The
total requirements for either a natural gas
liquids or a sulfur removal processing
plant are based on an assumed value of
five acres for a 100-mmcf per day plant.
4.4.4 Economic Considerations
FPC, in Opinion No. 699 (1974d),
established a single uniform national base
rate of $0.42 per thousand, cubic feet (mcf)
at the wellhead for domestic interstate
sales of natural gas commenced after Janu-
ary 1, 1973. This is based on the Commis-
sion's finding that $0.3754 per mcf to
4-21
-------
$0.4274 per mcf is a reasonable cost range
for production of gas. The cost components
yielding the above range are shown in
Table 4-7. Provision is made for annual
escalations of $0.01 per mcf and special
condition allowances. Recently, in Opinion
No. 699-H (FPC, 1974e), FPC concluded that
a base rate of $0.50 per mcf, subject to
the same price escalation and allowances
that applied to the former rate, was just
and reasonable. The new rate is based on
an alternative method of calculating return
on investment and trended 1973 cost figures.
4.5 TRANSPORTATION OF NATURAL GAS
4.5.1 Technologies
The transmission of natural gas pri-
marily involves the technologies of pipe-
line construction, flow of gas within these
lines* and gas compression. Secondary
technologies include metering and automa-
tion.
4.5.1.1 Transmission Pipeline
Natural gas pipeline systems generally
consist of one or more lines of large diame-
ter (12 to 42 inches), thin-walled (usually
.1 to .5 inch) steel pipe selected in ac-
cordance with standard pipeline codes. On
land, pipelines are normally buried two to
four feet below the surface in a cross-
country right-of-way.
Natural gas is pushed through a pipe-
line by pressure obtained from compressing
the gas. The capacity of a pipeline (i.e.,
the amount of gas that can be transmitted
through it) can be increased by using
TABLE 4-7
ESTIMATED 1974 NATIONAL AVERAGE COST OF FINDING
AND PRODUCING NONASSOCIATED GAS
Cost Component
Successful wells
Recompleted and deeper drilling
Lease acquisitions
Other-production facilities
Subtotal
Dry holes
Other exploration
Exploration overhead
Subtotal
Operating expenses
Return at 15 percent and
10*s years
Return on working capital
Net liquid credit
Regulatory expense
Subtotal
Royalty at 16 percent
TOTAL at 14.73 pounds per
square inch atmosphere
Revised Update High
(cents per thousand
cubic feet)
5.68
0.20
3.83
1.28
10.99
3.77
2.62
0.82
7.21
3.10
17.15
1.14
(3.89)
0.20
35.90
6.84
42.74
10-Year Estimate
(cents per thousand
cubic feet)
4.99
0.20
3.36
1.13
9.68
3.32
2.30
0.72
6.34
3.10
15.09
1.01
(3.89)
0.20
31.53
6.01
37.54
Source: FPC, 1974d: Appendix B (Schedule No. 1, Columns f and g, Sheet 1 of 9)
4-22
-------
additional compressor stations (2,500 to
20,000 or more horsepower) located about
50 to 100 miles apart along the route (FPC,
1974a: 46). Natural gas from the pipeline
is normally used as fuel for the compressor
engines. Valves, often called section-
alizing valves, are commonly installed
every 10 to 30 miles along the pipeline.
These valves make it possible to isolate a
pipeline section for repairs or maintenance
and frequently are equipped to close auto-
matically in response to a rapid, large
drop in pressure (Katz and others, 1959:
637, 638). Metering and regulating sta-
tions are located at gas purchase and
delivery points between the transmission
lines and local distribution systems.
Many major gas pipelines exceed 1,500
miles in length and cross all types of
terrain, including mountains, deserts,
forests, swamps, offshore, farmland, and
urban areas. River crossings are con-
structed in various ways with some lines
laid underwater and some using highway or
railroad bridges.
Natural gas transmission pipelines
.must be operated at high pressures. Line
pressures from 600 to 960 pounds per
square inch gauge (psig) are common, and a
few lines operate at pressures in excess
of 1,000 psig. Pressures are highest at
the outlet of a compressor station and drop
an average of approximately three psig
per mile between stations. A significant
decrease in the delivery capacity of a
pipeline results from a reduction in the
^operating pressure.
Pipelines are normally coated to pro-
tect them from corrosion. In addition,
cathodic protection as discussed in Section
4.5.1.4 is used to counteract corrosion by
earth currents, particularly where the
pipe passes through urban areas.
4.5.1.1.1 Alaskan Pipeline
The timing of the completion of a gas
pipeline from Prudhoe Bay is extremely
important as discussed in Section 4.2.3.3.
At present, two alternatives are being con-
sidered as shown in Figure 4-5. One calls
for the construction of a pipeline through
the Mackenzie Delta area in Canada to the
midwestern and far western states. That
pipeline might transport both Alaskan and
Canadian import gas (FPC, 1974c: 41) . The
other alternative is the construction of a
gas pipeline along the same right-of-way
as the TAPS oil pipeline. The gas would
be liquefied in Valdez and shipped by LNG
tanker to the West Coast. This would open
the possibility of additional development
of onshore supplies.
4.5.1.1.2 Pipeline Construction
Offshore gas pipelines are constructed
in the same manner as the offshore oil
pipelines discussed in Chapter 3 and result
in the same environmental residuals (ex-
cluding leaks during operation). However,
because of their higher pressures, onshore
gas pipelines are constructed differently
than onshore oil pipelines. Preliminary
operations include clearing and grading of
the right-of-way, pipe stringing, welding
of the strung pipe, ditching, and coating
of the pipe. In the next step, sideboom
tractors lower the completed continuous
pipe into the ditch and backfill. Finally,
clean-up crews restore the land to its
former condition. In good pipelining
areas, construction rates of one to three
miles of completed pipe per day are nor-
mally achieved, and the distance from the
front to the back of the spread (ditching
to covering operations) will not exceed
two to three miles. Special crews deal
with road and river crossings along the
route and the installation of valves,
service connections, etc.
4.5.1.2 Compression
The size and characteristics of com-
pressor stations are very significant in
overall transmission efficiency, the
4-23
-------
addition of compressor horsepower being one
of the options considered as*a means of in-
creasing pipeline capacity. Compressor
stations on gas transmission lines may have
capacities ranging from 2,500 to 20,000
horsepower or more. Each station may be
equipped with a dozen or more compressors
to provide the necessary flexibility for
maintenance.
Since reciprocating gas compressors
are long-lived and have been used since the
early days of gas pipelining, they are the
most commonly found units. Individual
reciprocating compressors range in size up
to 15,000 horsepower, and the installed
unit cost decreases as the size of the unit
increases. Modern units can be stopped,
started, or adjusted to other loading con-
ditions by computer or by manual control
from remote locations.
Centrifugal compressors are also used
in compressor stations. These compressors
are easier to install and automate, and
offer lower installation and maintenance
costs; however, they consume more fuel and
offer less operating flexibility than re-
ciprocating compressors. The individual
centrifugal compressors range in size up
to 20,000 horsepower.
Gas compressors operate most effi-
ciently when the ratio of the outlet pres-
sure to the inlet pressure lies between
certain limits: about 1.2:4 for recipro-
cating compressors and about 1.5:2 for
centrifugal compressors.
4.5.1.3 Storage of Natural Gas
Natural gas storage facilities are
developed in conjunction with long-distance
pipeline systems so that the pipeline can
operate at an essentially constant trans-
mission rate throughout the year. Pipe-
lines are designed for a delivery rate
roughly equal to the average demand rate,
and excess gas delivered during periods of
low demand is stored for use during periods
of peak demand. Operation of the pipeline
near its capacity (i.e., at a high load
factor) minimizes the unit transportation
cost.
4.5.1.3.1 Underground
Normally, natural gas is stored under-
ground in depleted gas reservoirs, but de-
pleted oil reservoirs are also used. Water-
bearing formations known as aquifers, dug
caverns, and sealed mines have also been
used for underground gas storage in areas
where depleted oil or gas fields are not
available.
An underground storage reservoir must
have the capacity to hold large volumes of
gas, must be gas tight, and must have high
deliverability (i.e., it must support high
production rates during withdrawal and high
intake rates during injection). In addi-
tion, the storage area is normally close to
the market served by the pipeline. The
locations of underground gas storage reser-
voirs in the U.S. are shown in Figure 4-9.
4.5.1.3.2 Tanks
Aboveground storage of natural gas in
tanks known as gas-holders is also common.
However, since tanks cannot hold large
volumes of gas, this storage mode is used
primarily to meet daily peak demands in
local distribution systems (such as the
high demand periods in the morning and
early evening).
4.5.1.3.3 Peak-Shaving Plants
Although underground storage is nor-
mally sufficient to meet the demands of
ordinary winter weather, the coldest days
result in extreme demand peaks which often
exceed the capacities of the long-distance
pipeline and the underground storage facili-
ties. To supply the incremental gas re-
quired during these short-term periods of
extreme demand, many companies operate peak-
shaving plants. One type of peak-shaving
plant introduces a mixture of air and a
high-cost liquefied petroleum gas (LPG)
4-24
-------
LOCATION OF UNDERGROUND GAS STORAGE RESERVOIRS IN THE U.S.
1973
• SALT DOME
• AQUIFER
A COAL MINE
0 DEPLETED OIL AND/OR GAS FIELD
Figure 4-9. Location of Underground Gas Storage Reservoirs
Source: FPC, 1974a: 84.
-------
(propane or, less commonly, butane) into
the natural gas stream. Liquefied natural
gas plants are also used to meet peak loads
and offer the advantage that the revapor-
ized LNG is more compatible with the base-
load gas.
4.5.1.4 Distribution of Natural Gas
The local distribution system consti-
tutes the means of delivering gas to the
ultimate consumers. (To the residential
or small commercial user, the local distri-
bution utility is frequently seen as the
natural gas industry.) A local distribu-
tion system consists basically of a system
of mains, valves, regulators, meters, and
other equipment and serves to transmit,
control, and measure the gas flow to the
individual customers. Natural gas enters
local distribution systems at points called
city gate stations or city border stations.
Although most communities have only one
city gate station, some large cities have
high-pressure loops operated at 400 to 500
psig with several stations from which the
gas enters the local system. Normally, the
gas enters the local distribution system at
a pressure between 100 and 150 psig. (The
delivery pressure may be a matter of con-
tractural obligation or merely a function
of the operating pressure in the transmis-
sion line supplying the gas.)
The lines serving individual residen-
tial or commercial customers contain pres-
sures ranging from .25 to .35 psig. Mains
operating in the pressure range 25 to 35
psig are called the medium-pressure system.
If pressures in street mains are maintained
much above .25 psig, individual house and
service regulators must be used. Because
of the operating pressures in most gas dis-
tribution systems, the use of individual
regulators is the common practice. The
pipe carrying the gas from the street main
to the regulator is usually either .75 or
1 inch in diameter. Large-volume commercial
and industrial customers (2,500 cf per hour
or more,) are normally served by individual,
direct lines from the high-pressure system
or transmission lines.
In most gas distribution systems, the
pipes must be coated to protect them from
chemical corrosion, and measures must be
taken to counteract corrosion resulting
from stray electrical currents in the
earth. Such currents are prevalent in
cities and are the most frequent cause of
corrosion in a distribution system. This
type of corrosion is caused by a loss of
iron ions from the point at which the cur-
rent leaves the pipe. One protection tech-
nique, cathodic protection, applies a
direct current to the pipe so that the
current leaves the pipe, and metal is lost,
at a preplanned point.
4.5.2 Energy Efficiencies
Energy efficiency data are given in
Table 4-8. The data are considered fair,
with a probable error of less than 50 per-
cent. The primary efficiencies for storage
and pipeline distribution reflect the use
of part of the gas as fuel for compressors.
The quantity of fuel used for storage is
very small, averaging 0.36 percent of the
fuel stored, while fuel used to drive the
compressors in pipeline transmission is
3.9 percent. Truck transportation of LPG
requires diesel fuel (an ancillary energy) ,
amounting to about 0.5 percent of the energy
transported.
4.5.3 Environmental Considerations
Hittman residuals for transmission,
distribution, and storage of natural gas
are given in Table 4-9. The data are con-
sidered poor, with a probable error of less
than 100 percent.
4.5.3.1 Water
Water pollutant residuals are reported
in the Hittman data as not applicable for
transmission, distribution, and storage of
natural gas and natural gas liquids.
4-26
-------
TABLE 4-8
EFFICIENCY OF TRANSMISSION, DISTRIBUTION,
AND STORAGE OF NATURAL GAS
Activity
Transmission and distribution
Pipeline
Liquefied petroleum gas trucks
Storage
Underground
Gas holders
Primary
Efficiency
(percent)
97.1
100
99.6
99.6
Ancillary
Energy
(Btu's per
10i2 Btu's)
0
5.21xl09
0
0
Overall
Efficiency
(percent)
97.1
99.5
99.6
99.6
Source: Hittman, 1974.
4.5.3.2 Air
The minimal estimated NOx emission
level during pipeline transmission is 10
12
tons per 10 Btu's transported. This
estimate assumes the consumption in com-
pressor engines of 3.67 percent of the gas
entering the pipeline. However, if a
liquid hydrocarbon is used as fuel, higher
NO levels would be realized.
The NO emissions during either under-
ground or tank storage result from the use
of gas engines to drive the compressors.
Total amounts of NO emitted are small,
12
averaging 12.2 tons per 10 Btu's stored.
The air emissions generated in the
truck transportation of LPG include par-
ticulates, nitrous oxides, sulfur dioxide,
hydrocarbons, carbon monoxide, and alde-
hydes. The amounts are consistent with
those normally associated with the opera-
tion of diesel tractor-trailers.
In general, the air residuals asso-
ciated with transmission, distribution,
and storage of natural gas do not consti-
tute serious environmental impacts.
4.5.3.3 Solids
No solid pollutants are generated in
the transmission, distribution, and storage
of natural gas and natural gas liquids.
4.5.3.4 Land
The land requirements given in Table
4-9 for pipeline transmission of natural
gas are based on the same parameter values
as those for natural gas gathering systems.
The transmission pipeline land requirements
analysis, like that for the gathering sys-
tem, is based on a 62.5-foot pipeline
right-of-way with compressor stations on
25-acre sites spaced 187 miles apart. Be-
cause compressor stations are spaced 50 to
100 miles apart on many major pipelines,
using Hittman's residuals may lead to a
low estimate of pipeline land requirements.
The land required for an underground
storage project is that required for a com-
pressor station and related equipment,
which was estimated to be 10 acres per
project. The land needed for high-pressure
storage tanks was based on 1.25 acres per
mmcf of gas storage capacity. Storage
capacity equivalent to 25 percent of the
daily flow rate was assumed.
4-27
-------
Table 4-9. Residuals for Transmission, Distribution, and Storage of Natural Gas
•
SYSTEM
TRANSMISSION AND
DISTRIBUTION
Pioeline
"Liquefied Petroleum
Gas Trucks
STORAGE
Underground
Gas Holders
—
—
— —
Water Pollutants (Tons/1012 Btu's)
CO
•0
-H
O
<
NA
NA
NA
NA
Bases
NA
NA
NA
NA
^
s
NA
NA
NA
NA
ro
NA
NA
NA
NA
Total
Dissolved
Solids
NA
NA
NA
NA
Suspended
Solids
NA
NA
NA
NA
Organics
NA
NA
NA
NA
Q
8
NA
NA
NA
NA
n
8
NA
NA
NA
NA
Thermal
(Btu's/I0l2)
NA
NA
NA
NA
ir Pollutants (Tons/1012 Btu's)
Particulates
0
.245
0
0
X
103.
6.95
12.2
12.2
X
o
tn
0
.509
0
0
Hydrocarbons
0
.695
0
0
8
0
4.23
0
VI
to
TJ
1
*D
,-<
<.
0
.113
0
u)
? g j§ Solids
(Tons/1012 Btt
NA
V
J J I Land
- . | H* ro| *q Acre-year
U)
3
ft
C4
i-4
O
^
22.
75/0
733/0
.33
. Health
1012 Btu's
Deaths
10-5
U
U
U
Injuries
D138
U
U
U
4J
tn
O
iJ
(I)
>i
10
a
i
c
m
S
.324
U
U
U
• i
N
NA = not applicable, NC = not considered, u - UUK.UUWU.
aFixed Land Requirement (Acres - year) / Incremental Land Requirement (
1012 Btu's
1012 Btu's
J.
-------
The Battelle report states, relative
to onshore gas pipelines, that "other than
the need to clear and maintain an overland
easement, the pipelines in the continental
U.S. present a minimal impact on the sur-
roundings they traverse (after initial
installation)" (Battelle, 1973: 240).
4.5.4 Economic Considerations
The average costs for major pipelines
from 1956 to 1970 are shown in Figure 4-10
(FPC, 1973d: 111). The costs range from
$0.19 to $0.24 per mcf and indicate an
overall downward trend over the 14-year
interval. The Hittman report lists the
following cost data (probable error less
than 50 percent) for natural gas transmis-
sion by pipelines (Hittman, 1974: Vol. I,
Table 25):
Fixed cost: $1.69xl05 per 1012 Btu's
Operating ,.
cost: $0.62x10;? per 1012 Btu's
Total cost: $2.31xl05 per 1012 Btu's
Clearly, the natural gas transmission
industry is highly capital intensive.
About 90 percent of the costs of gas trans-
mission by pipeline are fixed costs (taxes,
depreciation, and return associated with
the physical plant), and 10 percent are
operating and maintenance costs which are
partly constant and partly variable de-
pending on the throughput volume of gas.
The costs of pipeline transmission are so
sensitive to load factor that the cost per
mcf of gas transmission at 50-percent load
factor is almost double the cost of trans-
mission at 100-percent load factor (FPC,
1974a: 66). For a typical 30-inch diameter,
1,000-mile pipeline operating during 1973
at an average pressure of 800 pounds per
square inch (psi) and at 95-percent load
factor (i.e., at 95 percent of its ca-
pacity) , the total cost of transporting gas
is about $0.02 per mcf per 100 miles, of
which fixed charges represent over 90 per-
cent (FPC, 1974a: 51) .
4.5.5 Other Constraints and Opportunities
Intrastate distribution companies are
regulated by the individual states, but
the FPC regulates interstate pipelines
(under the authority granted in the Natural
Gas Act) and establishes the rates at the
city gates of the distribution companies.
Other federal responsibilities for the
regulation and administration of pipelines
are not as clearly defined. Four agencies—
the Federal Power Commission, Bureau of
Land Management, United States Geological
Survey, and Office of Pipeline Safety—have
jurisdiction over some aspect of offshore
natural gas pipelines. Natural gas pipe-
line operations are also subject to provi-
sions of the Natural Gas Act of 1936,
National Environmental Policy Act, Federal
Water Pollution Control Act, Clean Air Act
of 1970, Occupational Safety and Health
Act, and regulations issued pursuant to
these statutes as well as various safety
laws and regulations.
4.6 IMPORTED NATURAL GAS
Gas imports into the U.S. are from
Canada by pipeline and from Algeria by LNG
tankers. In 1973, net imports from Canada
were in excess of one tcf. Since reserves
from which this gas was drawn were not in
excess of Canadian requirements under cur-
rent guidelines established by the Canadian
National Energy Board, it seems unlikely
that additional gas will be available to
the U.S. from this source.
Except in the Canadian pipeline, impor-
tation of natural gas first requires its re-
duction to a liquid so that useful amounts
can be transported. Liquefaction of meth-
ane, the primary constituent of natural gas,
occurs at atmospheric pressure when the
temperature of the gas is reduced to -259°F.
The resulting volume reduction is more than
600:1.
Past use of LNG has been primarily for
peak load service in gas distribution
4-29
-------
u_
o
O
o
o
H-
24.00 r
23DO -
2 2.00 -
21.00 -
20.00 -
0 t-
1956 1958
I960
1962
1964
1966 1968
1970
YEARS
Figure 4-10. Major Pipeline Costs
Source: Adapted from FPC, 1973d: 111
-------
operations. However, the development of
technology for marine transportation of
LNG has made new sources of supplemental
natural gas available for baseload service
in the U.S. Current interest centers on
initiating long-term (usually 20 to 25
years) baseload projects; that is, projects
which would supply a significant portion
of the average load of a transmission sys-
tem. Two such projects have been approved
and one conditionally approved by the FPC;
in addition, applications for four others
have been filed with the FPC (FPC, 1974f).
Other prospective and possible projects
have been reported in the press.
4.6.1 Liquefied Natural Gas Technologies
An LNG export-import system as illus-
trated in Figure 4-11 would include the
following components: a source of natural
gas; transportation from the source to the
liquefaction plant; the liquefaction plant;
storage, loading, and port facilities at
the exporting site; transportation by ocean
tanker; unloading and storage facilities
at the importing site; a regasification
plant; and transmission facilities from the
regasification plant to a major pipeline.
For most LNG projects, some components of
the system would have no environmental
impact on the U.S. and, for purposes of
this report, could be ignored. However,
the environmental impact of all components
of the system for shipping the LNG from
Alaska to the West Coast must be considered.
4.6.1.1 Pretreatment
Prior to liquefaction any gas con-
stituents that would solidify at the low
temperatures involved must be removed or
reduced to insignificant amounts. Some of
the more critical of these constituents are
carbon dioxide, water, hydrogen sulfide,
lubricating oils, dust, and odorants. The
conditioning process includes cleaning,
dehydration, and purification.
4.6.1.2 Liquefaction
The liquefaction complex at the export
point consists of several major components
including the refrigerator or "coldbox" in
which the gas cooling occurs, the source
of refrigeration power, the means of de-
livering the power, and the cooling system.
The plant will also normally contain facili-
ties for pretreatment of the gas, fluid
transfer within the plant (i.e., pumps and
piping), storage of LNG, and docking and
loading of tankers. Figure 4-11 illus-
trates the role of the liquefaction plant
in the overall LNG system.
Basically, liquefaction is achieved
by using a refrigerant to remove heat from
a gas at a low temperature and transfer it
to some other medium (cooling water or
atmospheric air) called a heat sink. Using
a single refrigerant, the temperature of
natural gas can only be reduced to approxi-
mately -150°F. Thus, liquefaction of
natural gas requires the use of more than
one refrigerant. Three types of refrigera-
tion systems are commonly used to liquefy
natural gas: the cascade cycle; mixed
refrigerant cycle; and single fluid expander
cycle.
The cascade cycle uses a sequence of
refrigerants to obtain progressively lower
temperatures. As illustrated in the flow
diagram of Figure 4-12, cooling is accom-
plished by reducing the gas temperature to
-31 F in the propane-cooled exchangers, to
-142°F in the ethelene-cooled exchangers,
to -240°F in the methane-cooled exchangers,
and finally to -259 F by reducing the pres-
sure to 20 psia in the flash drum. This
cycle has lower horsepower requirements,
fewer distribution problems because single
component fluids are circulated, more rapid
plant start-up and shutdown, and normally
simplified plant operation. It is gener-
ally believed to be the most reliable,
especially in remote areas.
The-mixed refrigerant cycle is a varia-
tion of the cascade cycle and involves the
4-31
-------
Storage
Loadin
~XA^JL/^~~
1
uuiidiei
£
Transport
return "*~~|
Transport outward
r
j—^ Vapor streams
Regasification
Figure 4-11. Integrated Liquid Natural Gas Operation
Source: Bodle and Eakin, 1971: 5.
-------
Propane
cooled exchangers
Ethylene
cooled
Methane
cooled
Feed gas
preparation
•0-
Natural gas compressor
I— Natural gas supply
exchanger:
.
^-
exchanger?
T
Liquid separator
t Pentanes 8 heavier gases
Flash
drum
LNG
storage
pump
Figure 4-12. Cascade Cycle Liquefaction Plant
Source: J.F. Pritchard and Company.
-------
circulation of a single refrigerant stream.
In this process, the natural gas is also
chilled, condensed, and subcooled in a
series of heat exchangers. The refrigerant
is first compressed to a high pressure,
then partially condensed and flashed in
successive steps until the lightest com-
ponent is condensed and flashed. The con-
tents of the mixed refrigerant stream are
usually constituents of the natural gas
such as butane, propane, ethane, methane,
and nitrogen. This cycle has fewer com-
pressor types and simpler piping and
refrigerant process-vessel requirements.
Because the compression and heat exchange
systems are simpler, a mixed cycle plant
may, under certain circumstances, require
lower capital expenditures than a conven-
tional cascade plant.
The single-fluid expander cycle uses
the cooling effect obtained by expanding a
stream of compressed gas through a turbine
or engine and is of primary application in
distribution system peak-shaving plants
rather than baseload export-import systems.
4.6.1.3 Storage
Continuous operation of liquefaction
plants requires the use of storage to
accommodate gas liquefied when tankers are
not being loaded. Normally, storage ca-
pacity of two to three million barrels
(bbl) is required per bcf per day of pro-
cessing. Aboveground, double-wall metal
tanks are most commonly used. The space
between the walls contains various types
of insulation, a partial vacuum, or a com-
bination of both. Other cryogenic fluids
have been stored in prestressed concrete
tanks, and this type of tank may be suit-
able for LNG storage as well. Such storage
techniques as the use of frozen holes or
pits in the earth and mined caverns have
been tested or investigated, but' there are
no reported successful applications.
4.6.1.4 Tankers
O? the variety of LNG tanker configu-
rations either in operation or proposed,
two basic systems are used to contain and
insulate the LNG. The first uses self-
supporting (free-standing) tanks that rest
inside the ship's hold and are independent
of and insulated from the hull of the ship.
The second uses a membrane tank in which
the ship's hull serves as the outer tank
wall. The inside of the hull is insulated,
and a thin membrane covering the insulation
serves as a liquid barrier. The membrane
tank system offers more efficient utiliza-
tion of cargo space; however, differences
which may be significant in an environ-
mental sense have not been reported.
Generally, the ship's engines can use
either boil-off from the cargo or conven-
tional fuel. Boil-off gas is always avail-
able to furnish a portion of the ship's
fuel requirements because some LNG is
carried on the return trip to keep the
tanks cold.
Equipment supporting the loading,
transportation, and discharging of LNG
includes cargo pumps, gas compressors, heat
exchangers, inert gas generators, and pip-
ing. As reported by the FPC's National Gas
Survey (1973b: 377), the largest carrier in
operation (75,000 cubic meters) was deliv-
ered in late 1972, but there are several
ships currently on order with 125,000-cubic-
meter capacities and LNG carriers of
160,000-cubic-meter capacities and larger
are under consideration.
In terms of the total Btu content of
the cargo, a 160,000-cubic-meter LNG tanker
delivers about 70 percent as much energy
per trip as a 125,000-ton crude oil tanker
(the largest size oil tanker that can be
accommodated in most U.S. ports) . Typical
ranges for the dimensions of LNG tankers
are: length, 750 to 950 feet; beam, 120
to 150 feet; and draft, 35 to 40 feet.
4-34
-------
TABLE 4-10
ENERGY EFFICIENCY OF LNG" OPERATIONS
Activity
LNGa liquefaction
LNGa tanker
LNGa tank
LNG vaporization
Primary
Efficiency
(percent)
83
96.4
100
98
Ancillary
Energy
(Btu's per
1012 Btu's)
0.00
2.43xl010
2.81xl09
7.11xl08
Overall
Efficiency
(percent)
83
94.1
99.7
97.9
Source: Hittman, 1974.
aLiquefied natural gas.
4.6.1.5 Port and Transfer Facilities
The FPC's National Gas Survey (1973b:
404) identified 19 potential receiving
ports as shown in Figure 4-13. This map
contains a tabulation of the water depths
and remarks pertinent to the suitability
of each location. In some cases, substan-
tial dredging and/or fill and foundation
building may be necessary. The list was
compiled on the basis of the physical di-
mensions of the port with the assumption
that suitable plant sites are available.
Receiving sites need not be limited to
those shown in Figure 4-13. At Cove Point,
Maryland, for example, a mile-long pipeline
Vill connect the unloading buoy in the
Chesapeake Bay to the onshore facilities.
Facilities for transfer of LNG to or
from the tankers or storage area are re-
quired. These facilities are similar at
ioth the export and import points; thus,
only the import case is described here.
For unloading either at a dock or
through a pipeline, LNG ships connect to
liquid unloading arms and the LNG is moved
from the ships to stainless steel or alu-
ainum storage tanks. A schematic diagram
Of the facilities at the receiving site is
Shown in Figure 4-14. The LNG is unloaded
by submerged pumps in the ship's cargo
tanks and flows into the LNG storage tanks.
During the unloading period, vapor is
physically displaced from the storage
tanks; part of this vapor flows into the
pipeline, while the remainder must flow
through the vapor return line to the ship
to prevent the ship's tanks from either
taking in air or collapsing.
4.6.1.6 Regasification
The LNG is regasified (vaporized) by
passing it through heat exchangers, which
are tubes heated by either the surrounding
air or water, or by the combustion of either
a fuel or some of the gas itself. Regasi-
fication occurs at pressures up to 1,200
psig, which is sufficiently high for direct
introduction into a conventional natural
gas pipeline.
4.6.2 Energy Efficiencies
The liquefaction, transportation,
storage, and vaporization of natural gas
requires about 23 percent of the energy
of the gas. Liquefaction alone consumes
17 percent of the overall energy expended.
The available quantified data for energy
efficiencies as given by Hittman (1974:
Vol. I, Table 25) are shown in Table 4-10.
4-35
-------
LIQUEFIED NATURAL GAS IMPORTS
POSSIBLt' PORTS OF ENTRY
AREA
WATER DEPTH TIDF RANGE
(fort) (fc-ot)
REMARKS
18
1. Penobscot liny, M.iine
2. Portland, Maine
3. Boston, Massachu:
4. Conanicut Island, R.I.
5. New Vork, New York
6. Delaware River
7. Chesapeake Bay, Va.
40
40
40
9.0
9-5
3.0
e.
9.
10.
11.
12.
13.
I 1.
IV
16.
17.
18.
19.
Savannah, Georgia
Mobilf, Alabama
New Orleans, La.
Lake Charles, La.
Sabino, Texas
Galveston-Iiouston, Texas
Tacoma, Washington
Portland, Oregon
San Francisco-Oakland,
California
Huenerne, California
Los Angeles- Long Beach,
California
San Diego, California
40
40
40
40
40
1"
45
35-40
40
40
40-50
40
7.0
6.0
3.0
2.0
6.0
6.0
6.8-11
2.4
3.2-6.
2.8-5.
2.6-B.
3.0-5.
Substantial distance from major
gas transmission lines.
Substantial distance from major
gas transmission lines.
Densely populated.
Good location for receiving LNG.
Low demand area.
i:igh marine traffic density.
Densely populated.
Several possible sites. High
demand area. Near major gas
transmission lines.
Several possible sites. Heavy
Navy traffic.
Near major gas transmission line.
Near major gas transmission lines.!
Near major gas transmission lines.
Near major gas transmission lines..
Near major gas transmission lines.
Near major gas transmission lines.
6.8-11.8 Good location for receiving LNG.
Near major gas transmission line.
Near major gas transmission line.
3.2-6.0 High demand area—Near major gas
transmission line.
Near major gas transmission line.
120,000 cubic meter ships.
2.B-5.4 High demand area—Hear major gas
transmission line.
3.0-5.7 Near major gas transmission line.
Heavy Navy traffic.
8
13
Figure 4-13. Potential Receiving Ports
Source: FPC, 1973b: VI-4.
-------
Vapor-return line
Blower
\
t
Unloading
line
Storage
Ship pumps
Compressor
Fuel or flare
Vaporizer
\
To pipeline
Sendout pumps
Figure 4-14. Liquid Natural Gas Receiving Terminal
Source: The Oil and Gas Journal, 1974: 60.
-------
These data have a probable error of less
than 25 percent.
4.6.3 Environmental Considerations
The Hittman residuals for the compo-
nents of an LNG export-import system are
shown in Table 4-11. These data have a
probable error of less than 100 percent.
4.6.3.1 Water
No water pollutant data are given for
any of the liquefaction, storage, or
vaporization operations. For tanker opera-
tions, the nondegradable organics residual
12
is 0.212 ton per 10 Btu's shipped, based
on a discharge of 12 gallons of LNG per
day per vessel while in U.S. coastal waters
or berthed. Although there is always the
possibility of an LNG spill on land or
water, any such spill would immediately
begin to vaporize. Two studies (Wilcox,
1971; Enger and Hartman, 1972) dealing with
the release of LNG and the subsequent dis-
persions of the resulting vapor both
reached the conclusion that the environ-
mental stress stemming from large and sud-
den releases to either land or water sur-
faces are short-lived and minor when com-
pared to the safety hazard involved (FPC,
1973b: 411). Water residuals for LNG
tankers are essentially the same as those
for normal shipping operations, and the
environmental impact of an LNG spill, in
contrast to a crude oil spill which might
occur in the transportation of crude oil
by tanker, would be minimal.
Any dredging required to prepare and
maintain channels and turning basins at the
exporting and importing terminals causes
turbidity of the water and disturbance of
bottom-dwelling marine animals and orga-
nisms. In addition, movement of LNG car-
riers in shallow and restricted 'areas may
result in disturbance of bottom and shore
life both from the turbulence generated by
propellers and the ship's wake (FPC, 1973b:
411). Although such disruptions would be
temporary in most cases, import-export
facilities should not be placed near com-
mercial fishing areas if possible (BLM.
1973: 336, 337).
Plants using water in the regasifica-
tion step will discharge water at a lowered
temperature. In the case of the Savannah
plant, water temperature will be lowered
5°F before being returned to the river.
The possible use of the potential cooling
in conjunction with another process requir-
ing dissipation of heat may represent a
process benefit.
A level of discharge of shipboard
wastes and engine exhaust fuel consistent
with other comparable marine carriers would
be anticipated.
4.6.3.2 Air
As given in Table 4-11, the NOx emis-
sions (the only residual listed for the
liquefaction plant) are 354 tons per 10
Btu's processed and are based on the con-
sumption by compressor motors of 13 percent
of the feeds tock.
The tanker emissions are based on a
294,000-bbl LNG tanker traveling 100 miles
per trip in coastal waters and spending two
days in port. The total includes emissions
from the tanker while in coastal waters and
in port as well as emissions from the re-
quired tugboats.
No residuals are generated in storing
LNG. The residuals attributable to vapori-
zation are based on the use of two percent
of the LNG input as fuel for the heat
exchanger.
4.6.3.3 Solids
No solid pollutants are generated in
LNG operations.
4.6.3.4 Land
A total of 1,000 acres is needed for
the fuel storage depot, dock, port facili-
ties, and vaporization system required for
a 1,000-mmcf-per-day receiving terminal;
4-38
-------
Table 4-11. Residuals for Liquefied Natural Gas Operations
SYSTEM
LIQUEFIED NATURAL GAS
Liquefaction
Tanker
Tank
Vapori zation
Water Pollutants (Tons/lQl2 Btu's)
Acids
NA
NA
NA
NA
Bases
NA
NA
NA
NA
$
NA
NA
NA
NA
NA
NA
NA
NA
Total
Dissolved
Solids
NA
NA
NA
NA
Suspended
Solids
NA
NA
NA
NA
Organics
NA
.212
NA
NA
Q
8
NA
0
NA
NA
Q
8
NA
NA
NA
NA
Thermal
(Btu's/1012)
1.03
0
NA
0
X
Air Pollutants (Tons/1012 Btu's)
Particulates
0
.0315
NA
.187
X
354.
.437
NA
1.00
X
O
0
.336
NA
.0059
Hydrocarbons
0
.0154
0
.0785
8
0
.0062
NA
.196
Aldehydes
0
.0044
NA
.108
"in
Solids
(Tons/1012 Btu
NA
NA
NA
NA
"/I*
Land
Acre-year
tn
3
4J
m
CM
0
iH
.0125
739/6
.49
^1 . 04/ 0
2.04
. 133/0
.133
Occupational
Health
1012 Btu' s
Deaths
U
•u
U
U
Injuries
U
U
U
U
4J
ffl
O
V)
ns
Q
1
C
ro
S
U
U
U
u
NA
not applicable, NC = not considered, U = unknown.
aFixed Land Requirement (Acres - year) / Incremental Land. Requirement ( Acres ) .
1012 Btu'
1012 Btu's
-------
this corresponds to 2.66 acre-years per
12
10 Btu's. Allocation of land usage to
the components of the receiving site
storage, vaporization, and port facilities
is made on the basis that the acreage is
approximately proportional to the corres-
ponding investment values.
For the liquefaction operations, the
land requirements are assumed to be equal
to those for vaporization of LNG. However,
the land requirement figures given in the
Hittman data for both the vaporization and
liquefaction sites are misleading because
a part of the land requirements for each
has been reported as LNG tanker land re-
quirements. The land requirements for a
liquefaction site should actually include
the Hittman values for the liquefaction
site and one-half of the value for the
tanker. Although the sum of the three
residuals (liquefaction site, tankers, and
vaporization site) may be representative
of a complete LNG system, the indicated
residual would not represent the full im-
pact of the facility if an environmental
assessment of either a liquefaction plant
or a revaporization plant was being pre-
pared. For example, the plant proposed for
Cove Point, Maryland would initially pro-
duce 650 mmcf per day and require a 1,022-
acre tract of land. The plant proposed for
Savannah, Georgia would initially produce
335 mmcf per day and require 860 acres
(BLM, 1973: 337, 338). Expressed in terms
of acre-years per 10 Btu's, the land
usage at Cove Point would be 4.18 and that
at Savannah would be 6.82, while the cor-
responding value for land usage given in
the Hittman data is 0.130.
4.6.3.5 Major Accident
The potential for fire or explosion
is always present during LNG operations.
In 1944, an early LNG plant was destroyed
by a disastrous fire, resulting from a
storage tank failure, that killed 100
people. Since then, the technology of LNG
operations has been improved and greater
attention has been given to proper safety
precautions. Nevertheless, the recent ex-
plosion of a Staten Island storage tank,
killing more than 40 men, shows that there
is still an element of danger involved in
storing and handling LNG (BLM, 1973: 337).
In 1969, the U.S. Bureau of Mines
reported on several instances of violent
reactions resulting from the contact of LNG
and water. No fire or ignition of vapor
was observed, but there was a rapid upward
movement of gas accompanied by a loud
"bang" (Burgess and others, 1970). A later
study concluded that there was little like-
lihood of a violent reaction between normal
LNG and water and that such a reaction
could result only after the methane content
of the LNG had dropped to 40 percent.
Since the normal methane content of LNG is
80 to 90 percent or more and the boil-off
rate is about 0.2 percent per day, a reduc-
tion to 40 percent is not likely under cur-
rent shipping practices (Enger, 1972).
Although, in the case of a large spill, the
quantity of LNG remaining after weathering
(or methane boil-off) into the critical
composition range could be significant,
the weathering period would be of sufficient
duration that the UJG would have spread on
the surface and the chance of a single large
reaction would be relatively small. Also,
the energy available for the reaction is
limited because it is not a chemical reac-
tion (BLM, 1973: 336).
4.6.4 Economic Considerations
Although costs for individual compo-
nents of an LNG importation system are
listed in the Hittman report (1973: Table
25) , the delivery price into the sales
pipeline is more meaningful for the pur-
poses of this report. The delivery price
includes: the gas price, royalties, taxes,
and other payments in the exporting country;
production, transmission, liquefaction,
storage, and loading costs in the exporting
4-40
-------
country; tanker transportation costs from
the exporting country to the U.S.; and
unloading, storage, revaporization, and
some transmission costs in the U.S.
In approving the application by El
Paso Natural Gas to import LNG, the FPC
limited prices to $0.77 per million Btu's
delivered to Cove Point, Maryland and to
$0.83 at Savannah, Georgia (FPC, n.d.).
(On the basis of a heating value of 1,032
Btu's per cf, these prices are approxi-
mately $0.80 per mcf and $0.86 per mcf
respectively.) The company has indicated
that these prices may not be sufficient.
The current uniform national rate for sales
of interstate natural gas established by
the FPC is $0.50 per mcf (FPC, 1974e).
While the prices approved by the El Paso
project offer some guidance, the magnitude
of price increases for future projects is
difficult to predict because prices for a
given project are markedly influenced by
freight-on-board (f.o.b.) prices in the
exporting country in addition to the usual
capital and operating cost escalations.
Based on component costs given by the
National Petroleum Council (1972: 294) for
a project in which LNG is shipped from
Algeria to Cove Point, Maryland, approxi-
mately 40 percent of the capital require-
ments are for ships, 41 percent for the
liquefaction plant, and 19 percent for the
revaporization plant. Clearly, the major
capital costs are incurred in liquefying
and shipping the LNG. The regasification
facilities are the only capital cost in the
importing country, and this cost is nor-
mally less than 20 percent of the total
capital requirements. The above distribu-
tion of operating costs in the categories
of regasification, shipping, and liquefac-
tion would be expected to be typical of all
IiIG projects; however, the cost of the gas
in the exporting country will undoubtedly
be a dominant component of the total oper-
ating costs.
Other capital expenditures would in-
clude the development of marine facilities
and the construction of two pipelines; one
to the liquefaction plant and one from the
regasification plant to the major transmis-
sion line. Pipeline construction for the
Cove Point, Maryland plant will require
$89 million, while pipelines for the
Savannah plant will cost $25 million (FPC,
n.d.).
4.6.5 Other Constraints and Opportunities
The impact of LNG imports on the U.S.
balance of payments is difficult to assess
at this time. The construction of lique-
faction plants will certainly involve capi-
tal from the U.S. For example, some of the
funds for construction of an Algerian plant
are being provided by the Export-Import
Bank. However, the amounts of U.S. capital
that will flow to exporting countries and
the amounts that will return through the
purchase of U.S. equipment have not been
established. In addition, the past methods
of financing such projects may undergo
changes because of the increased flow of
money into the oil producing countries.
The use of foreign or domestic tankers is
another factor in the balance of payments.
Undoubtedly, the most significant ef-
fect on the balance of payments will be the
price of the gas in the exporting country.
One estimate of the f.o.b. price of gas is
$0.38 to $0.53 per mcf (Khan and Bodle,
1972). On this basis, a long-term project
for importing two tcf of LNG would result
in an outflow of $760 million to $1.06
billion.
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-------
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University of Oklahoma.
Katz, D.L. and others (1959) Handbook of
Natural Gas Engineering. New York:
McGraw-Hill Book Co., Inc.
Khan, A.R. and W.W. Bodle (1972) "Supple-
menting United States Gas Supplies
with Imported LNG." Journal of
Petroleum Technolocry (May 1972).
Linden, H.R. (1973) "The Role of SNG in the
U.S. Energy Balance." Special report
for the Gas Supply Committee of the
American Gas Association, May 15, 1973.
National Petroleum Council, Committee on
U.S. Energy Outlook (1972) U.S. Energy
Outlook. Washington: NPC.
Oil and Gas Journal (1974) Oil and Gas
Journal (May 13, 1974): 60.
Phillips, J.G. (1974) "Energy Report/
Congress Nears Showdown on Proposal
to Decontrol Gas Prices." National
Journal Reports 6 (May 25, 1974):
761-775.
Potential Gas Committee (1973) Potential
Supply of Natural Gas in the United
States, As of December 31, 1972.
Golden, Colorado: Colorado School
of Mines, Potential Gas Agency.
Wilcox, D.C. (1971) "An Empirical Vapor
Dispersion Law for LNG Spill." AGA
Project 15-33-4, Arlington, Va.,
April, 1971.
Zareski, G.K. (1973) "The Gas Supplies of
the United States—Present and Future,"
in Pollution Control and Energy Meeds,
Advances in Chemistry Series No. 127.
New York: American Chemical Society.
-------
CHAPTER 5
THE TAR SANDS RESOURCE SYSTEM
5.1 INTRODUCTION
Tar sands are deposits of porous rock
or sediments that contain hydrocarbon oils
(tar) too viscous to be extracted by con-
ventional petroleum recovery methods (NPC,
1972: 225). Large deposits of tar sands
were identified in North America at the
end of the 19th Century, and efforts to
extract the tar sands were undertaken
early in the 20th Century (Camp, 1969:
690). Some of these efforts achieved
intermittent commercial operation. In
Canada, commercial ventures for producing
energy products from tar sands are being
developed on a large scale, but in the
U.S., only relatively small-scale develop-
ment efforts have been made on selected
deposits in Utah (Kilborn. 1964: 247).
The tar sands resource development
system is described in this chapter as a
sequence of activities starting with ex-
ploration, continuing with the recovery,
upgrading, and refining, and ending with
transportation of the finished products.
As diagrammed in Figure 5-1. this system
can involve several transportation steps,
depending on the location of facilities.
Most information on tar sands tech-
nologies comes from Canadian developments.
Future technologies that might be employed
in the U.S., and the impacts sustained,
may differ from those indicated by Canadian
information. No data on tar sands were
available from the Hittman, Battelle, and
Teknekron studies that provide much of the
quantitative data for other chapters. The
similarities between certain activities in
the tar sands system and oil shale, coal,
and crude oil technologies suggest that
those technologies may be useful refer-
ences for understanding tar sands.
5.2 RESOURCE QUANTITY
Few quantitative estimates of tar
sands resources have been made, and the
existing estimates are based on limited
information. The total world deposits are
estimated to be equivalent to one to two
trillion barrels of tar (NPC, 1972: 225).
Large deposits occur in Columbia,
Venezuela, and especially Canada, where
the Athabascan deposit in Alberta contains
a total resource of 700 billion barrels
(BLM, 1973: 366; Camp, 1969: 682).
The U.S. possesses two to three per-
cent of the world tar sands, an estimated
resource* of about 30 billion barrels of
oil (Cashion, 1973: 100). These resources
should not be counted as energy reserves
because they are not known to be econom-
ically recoverable at the present time.
However, the Department of the Interior
believes that in 15 to 30 years it may be
feasible to begin recovery of about 30 to
50 percent of the resource, resulting in
the production of 10 to 16 billion barrels
of oil. Estimates of recoverable U.S. tar
sands made by the Bureau of Mines (based
A resource is an identified or un-
discovered (but surmised to exist) deposit
that is currently or potentially feasible
to extract.
4b ju
A reserve is an identified deposit
that can be extracted, processed, and sold
on a profitable basis under current market
conditions.
5-1
-------
5.2
Domestic
Resource
Base
i
i
I
I
5.6 *
Exploration
5.8
r->
,_j
I--*
In Situ
Recovery
R 7
Mining
i.
5.8
Upgrading
5.8
-
*5.8
Bitumen
Recovery
..T 1
Reclamation
Rofinina .. • ^fc-l idUld Fuels
Involves Transportation
Does Not Involve Transportation
5.9 Transportation
Figure 5-1. Tar Sands Resource Development
-------
on shallow occurrences only) are lower,
ranging from 2.5 to 5.5 billion barrels of
recoverable oil (BLM, 1973: 364).
5.3 CHARACTERISTICS OF THE RESOURCE
Tar sands are composed of an organic
hydrocarbon fraction occupying pore space
in a rock such as sandstone or dolomite
(Spencer and others, 1969: 5). Porous
space consists of 26 to 39 percent of rock
volume in most U.S. tar sands, and this
space can be occupied by water or tar.
Water is frequently the largest fraction,
and tar content varies between 13 and 33
*
percent of the pore volume (Spencer and
others, 1969: 6).
The tar, which consists of many hydro-
carbon compounds, is frequently referred
to as bitumen by geologists. Thus, tar
sands are often referred to as bituminous
sands. The bitumen content of most U.S.
tar sands deposits varies between 9 and 16
percent of the total weight. A deposit
with about 14 percent bitumen is consid-
ered rich. About 1.5 tons of rich tar
sands yield about one barrel of bitumen,
the equivalent of about 6.3x10 Btu's (AEC,
1974: A.2-95). A few deposits in Utah are
very high in bitumen and are distinguished
from other deposits by being labeled gil-
sonite. The viscosity or resistance to
flow of the bitumen varies greatly, but
all tars are by definition more viscous
than petroleum. Some bitumen-bearing rocks
are solid with the tar softening only on
heating.
The sulfur content of U.S. tar varies
considerably between different geographic
locations, but the major Utah deposits
have a low sulfur content (about 0.5 per-
cent as indicated in Table 5-1). The over-
burden of specific deposits also differs
greatly; some are covered by as much as
2,000 feet of rock while others emerge at
the surface as the data in Table 5-1 indi-
cate.
5.4 LOCATION OF THE RESOURCES
About 550 deposits of tar sands have
been identified in 22 states, but only
California, Kentucky, New Mexico, Texas,
and Utah have individual deposits of over
a million barrels (Cashion, 1973: 101).
Table 5-2 summarizes reserve and resource
TABLE 5-1
SULFUR CONTENT AND OVERBURDEN DEPTH
OF SOME MAJOR U.S. TAR SANDS DEPOSITS
Location
Asphalt Ridge, Utah
Sunny s ide , Utah
Whiterocks , Utah
Edna, California
Size of Identified
Resource
(million barrels)
900
500
250
165
Sulfur Content
(percentage
by weight)
0.5
0.5
0.5
4.2
Overburden
Depth
(feet)
0-2,000
0 - 150 .
nil3
0 - 600
Source: Camp, 1969: 685.
aSpecific overburden depths are not available but deposits are very shallow.
Canadian tar sands have oil in 40 to
98 percent of the pore volume.
5-3
-------
TABLE 5-2
SIZE OF U.S. TAR SANDS DEPOSITS
(KNOWN DEPOSITS OF AT LEAST
ONE MILLION BARRELS)
State
California
Kentucky
New Mexico
Texas
Utah
Reserves
2
Ua
ua
ua
1, 000-5, 000b
Resources
(millions
of barrels)
270 - 320
30 - 40
60
120 - 140
19,000 - 29,000
Source: Cashion, 1973: 101; AEC, 1974:
A.2.95-98.
u = unknown.
These "reserves" are apparently not pres-
ently recoverable. They could be appro-
priately termed paramarginal reserves.
estimates in these states. Widespread
thin occurrences of tar sands underlie
areas in the central U.S. as indicated in
Figure 5-2. The vast majority of the
identified resource, estimated at up to 29
billion barrels of oil, is located in Utah.
One deposit alone, the Tar Sand Triangle
west of the confluence of the Green and
Colorado rivers in the eastern portion of
Utah, is estimated to contain between 10
and 20 billion barrels of oil (Cashion,
1973: 101) . The major Utah deposits are
in an arid setting that has been described
more completely in Chapter 2.
5.5 OWNERSHIP OF THE RESOURCES
The major tar sands deposits in Utah
*
are owned by the federal government.
Several of the tar sands deposits are on
lands that contain other minerals, such as
oil shale. Private claims to mineral
rights on these lands are being challenged
Apparently extensive deposits occur
in the Uinta and Ouray Indian Reservations.
by the federal government. Most of the
deposits located outside Utah are on
private land.
5.6 EXPLORATION
5.6.1 Technologies
Exploration for tar sands has largely
been confined to visual observation of
surface outcrops or tar seeps and the
examination of core drillings. Little use
has been made of the sophisticated explo-
ration tools, such as seismic exploration
and the introduction of electrical instru-
mentation into well bores, that are used
in the petroleum industry. If the need
arises for more intensive tar sands explo-
ration, petroleum industry tools (includ-
ing seismic, well logging, and aerial
reconnaissance devices) will be employed
(Cashion, 1973: 102) . In the near future,
however, efforts will most likely be con-
fined to coring and more carefully de-
scribing known tar sands deposits.
5.6.2 Energy Efficiencies
The ancillary energy expended in dis-
covering tar sands deposits has been a
small fraction of the energy recovered in
the Canadian operations. U.S. exploration
expenditures should be similar.
5.6.3 Environmental Considerations
Environmental residuals from explora-
tion are limited to surface and subsurface
physical disturbances associated with
drilling and support facilities for geolo-
gists. These are confined to small areas
and the overall residuals are small.
5.6.4 Economic Considerations
Data on tar sands exploration costs
are not available. Because seams are
thick and many of the deposits have al-
ready been identified, exploration activi-
ties in support of mining operations are
likely to be a very small portion of the
overall costs of mine development.
5-4
-------
0 400
miles
0 400
miles
Figure 5-2. Distribution of U.S. Tar Sands Resources
Source: Spencer, Eckhard, and Johnson, 1969:
-------
5.7 MINING AND RECLAMATION
The bitumen can be recovered either
by mining the tar sands and transporting
them to the surface for processing or by
underground extraction of the oil without
mining or removing the overburden. The
underground extraction method is called
in situ recovery. Mining and reclamation
procedures are described in this section;
in situ extraction is described in Section
5.8.
5.7.1 Technologies
5.7.1.1 Mining
As with coal and oil shale, tar sands
can be mined from the surface or under-
ground, depending primarily on economic
considerations. Most deep deposits, in-
cluding many of those occurring in Utah,
await development of in situ recovery
methods (BLM, 1973: 365). Underground
mines have only been used to recover high
quality consolidated tar deposits, such as
the thick veins of gilsonite in Utah.
Although rudimentary hand excavation and
loading techniques have been used in the
past, more recent methods have employed
jetted water streams to fracture and exca-
vate the gilsonite, a process called hy-
draulic mining. The largest such opera-
tion produced about 1,000 tons of gilson-
ite a day (Kilborn, 1964: 247).
Shallow deposits (an overburden
roughly as thick as the resource seam) can
be mined from the surface. In surface
mining, the vegetation is cleared from the
area to be mined, the overburden is frac-
tured (if necessary) by blasting, and the
material is then removed by standard exca-
vation techniques. With the overburden
removed, the tar sands are mined and
carried by conveyor or truck to the pro-
cessing facility.
Two methods of excavating the over-
burden and tar sands have been proposed:
one uses several large pieces of excavating
equipment, as in surface coal mines, and
the other uses a number of smaller mining
units Tcamp, 1969: 702). The large-scale
units can be either bucket wheel excava-
tors or draglines, and the smaller-scale
units can be either shovels or motorized
scrapers. (Chapter 1 includes descrip-
tions of these techniques and machines.)
A consortium of oil companies has
proposed a system employing a number of
excavating scrapers for one tar sands
operation. These scrapers will remove the
overburden, then the tar sands, discharg-
ing the mineral onto a conveyor for trans-
portation to the processing plant (Camp,
1969: 703).
5.7.1.2 Reclamation
Reclaiming lands disturbed by tar
sands development through mining primarily
involves the disposal of spent sand from
the processing plant and restoration of
the mined area. For surface mining, sat-
isfactory reclamation procedures will
integrate the mining and disposal opera-
tions, returning the spent sand to the
mine or to other suitable areas as de-
scribed in the mine reclamation sections
of Chapters 1 and 2. Complete reclamation
will also require recontouring the mate-
rial and revegetating the area. For under-
ground operations, subsidence could be
minimized if processed sands could be re-
turned to the mine.
5.7.2 Energy Efficiencies
Few data are available on the effi-
ciency of surface mining tar sands. The
recovery efficiency should be about 80
percent, based on other surface mining
operations (e.g., coal surface area mines
recover 80 to 98 percent of the seams)
(Hittman, 1974: Vol. I, Tables 1 through
12). Ancillary energy requirements could
be about the same as in oil shale mining
or about one billion Btu's per 1012 Btu's
excavated from the mine, not including
energy used in reclamation. Efficiency
5-6
-------
data on possible underground operations
are not available.
5.7.3 Environmental Considerations
Surface mining produces substantial
residuals, including: gross modification
of surface topography; disposal of large
amounts of overburden (and spent tar sands
returned from processing facilities); dust
and vehicle emissions into the atmosphere;
and water pollution from mining and pro-
cessing activities, erosion, watershed
modification, and disturbances to ground-
water (BLM, 1973: 370). In Canada, about
3.3 tons of tar sands and overburden must
be excavated to produce one barrel of oil.
The weight of overburden is about one-half
that of the tar sands. In a typical day's
mining operation in support of a 50,000-
barrel-per-day processing facility, a
total of about 165,000 tons of material is
moved (Spencer and others, 1969: 10).
Depending on seam thickness, several
acres of surface lands per day could be
affected by surface mine operations. Quan-
tification of other residuals from hypo-
thetical mining operations in the U.S. has
not been attempted. The use of controlled
technologies, including revegetation and
irrigation in arid areas (if water is
available), would substantially minimize
the impact of surface mining, and as pre-
viously mentioned, returning the processed
sands to underground mines could minimize
the extent of subsidence.
Residuals from both types of mining
operations could be similar to those de-
scribed in Chapters 1 and 2.
5.7.4 Economic Considerations
Current information on all aspects of
the cost of tar sands operations is limited
and is usually based on Canadian-opera-
tions. These operations differ greatly in
such areas as geology, scale of operations,
and environment, and it should not be as-
sumed that possible activities in the U.S.
will be similar.
In Canadian operations, mining aver-
ages about 41 percent of the total costs
of producing synthetic oil from tar sands
(Hottel and Howard, 1971: 193). However,
the mining costs vary with the overburden-
to-seam thickness ratio, which is nor-
mally 1:1 or less. One 1969 estimate of
costs of supplying raw tar sands to a pro-
cessing facility was 15 to 25 cents per
ton under relatively good conditions
(Cameron, 1969: 256). The 41-percent cost
figure and the 25-cents-per-ton figure do
not agree well (if 1.5 to 2 tons are re-
quired for a barrel of oil), and extrac-
tion costs are probably closer to $1.00
per ton.
5.8 PROCESSING
5.8.1 Technologies
Following the mining operation, the
first processing step is bitumen recovery
and removal of the inorganic mineral sands.
If the tar sands are too deep for economic
mining operations, in situ bitumen re-
covery could be employed, although this
technology is only in developmental stages.
Whether recovery of the bitumen is accom-
plished in surface facilities or in situ.
the next step is upgrading the bitumen to
a product that resembles crude oil. This
upgrading step can then be followed by a
refining operation if products such as
gasoline or jet fuel are desired.
5.8.1.1 Bitumen Recovery
Once the tar sands have been mined,
three general processes for recovering the
bitumen have been suggested: hot water
extraction, solvent extraction, and py-
rolysis.
The bitumen extraction technique used
in Canada heats the tar sands with steam,
hot water, and sodium hydroxide in separa-
tion tanks where the sands fall to the
bottom and the tar floats to the
5-7
-------
top. The bitumen is then skimmed off and
centrifuged to remove the water and any
dissolved minerals before being mixed with
a naphtha to reduce viscosity and allow
pumping to the upgrading facilities
(Spencer and others, 1969: 11). Figure 5-3
diagrams this hot water extraction process.
Figure 5-4 delineates the steps in
the solvent extraction process. In this
method, the bitumen is dissolved by mixing
a solvent (such as naphtha) with the tar
sands, and the resulting mixture is drained
from the inorganic mineral sands (Camp,
1969: 706). This mixture is then pumped
to a vessel where the solvent is recovered
(e.g., by distillation) and recycled. Re-
covery of all the solvent is important
because even small losses of solvent can
make this system costly.
The pyrolysis method (Figure 5-5) con-
sists of partial combustion or "coking" of
the tar sands to decompose the complex
bitumen molecules into gases and liquids.
One method first heats the tar sands
(Camp, 1969: 705) in a vessel called a
coker to drive off most of the volatile
matter. The remaining hydrocarbons in the
coked sands are then burned to provide
process heat for the coker. The volatile
matter is driven out of the sands in the
coker and then condensed and recovered for
gases and liquids. This system has only
operated on a pilot-plant basis in Canada
(Camp, 1969: 706). A more complete de-
scription of pyrolysis extraction technolo-
gies is given in Chapter 2.
5.8.1.2 In Situ Recovery
Two basic methods have been suggested
for recovering the hydrocarbons from tar
sands without mining the deposits: apply-
ing heat in various forms to lower vis-
cosity, and using emulsifiers or organic
solvents to dissolve the tar from the
sands. By definition, tar sands are too
The caustic sodium hydroxide facili-
tates separation of the tar from the sand.
viscous to be recoverable by petroleum
secondary recovery methods, and simple
waterflooding of the tar sand formation is
not sufficient for in situ removal of the
hydrocarbons. However, some of the terti-
ary petroleum recovery practices described
in Chapter 3 are applicable (such as
thermal recovery and injection of emulsi-
fiers) .
A number of heat application methods
have been proposed, including injection of
hot liquids or gases such as water or
steam, combustion in place, and nuclear
.explosions. Steam injection can either be
cyclic or continuous. In a cyclic process,
steam is pumped down a wellbore drilled
into the formation for several days or
weeks. After the tar sands are suffi-
ciently heated, the steam system is dis-
connected and the tar is pumped from the
well. This method has been used to re-
cover several million barrels of tar from
sands in California. In continuous steam
drive, two or more wells are used, with
one of the wells supplying steam while the
other is used for material extraction.
Experimental steam drive operations have
taken place in California and Canada. Like
other in situ heating processes, lack of
permeability and heat losses in the forma-
tion tend to limit the success of the
steam extraction method (Spencer and
others, 1969: 9-11).
Combustion of the tar sands to reduce
viscosity and volatilize the hydrocarbons
can be accomplished by drilling wells,
fracturing the formation, injecting air,
and establishing a combustion zone (Spencer
and others, 1969: 9) . The resulting mate-
rials are then produced from a downstream
well. This method can be modified by
adjusting the relative location of the
combustion zones, type of air injection,
and extent of fracturing, or by introducing
additional materials such as steam. Simi-
lar in situ combustion processes have been
described in Chapters 1 and 2.
5-8
-------
Tar sand
Sodium
hydroxide
Water
Conditioning
(I80-2IO°F)
V
t
Separation
Froth
Scavenging
Air
Tailings
Bitumen
waste
Figure 5-3. Hot Water Extraction Process
Source: Camp, 1969: 710.
-------
Steam
Tar sand
Mixer
Drain
Recycle Solvent
Moke-up Solvent
Solvent
recovery
from
solids
Solids to
waste
Recovered
solvents
Solvent recovery
from product
Bitumen product
Figure 5-4. Solvent Extraction Process
Source: Camp, 1969: 707.
-------
Flue gas
Tar sand
Coked
sand
Air
Coker
Heat
er
/
, ^
__f
t
\
Cle
Reac
Product
receiver
Synthetic
crude oil
Reaction off-gases
Figure 5-5. Pyrolysis "Coking" Extraction Process
Source:^ Gamp, 1969: 706.
-------
Several groups have suggested that a
nuclear device could be used to heat tar
sands. One effort, advocated for use in
Canada during the 1960's, would have em-
ployed a nine-kiloton device (Camp, 1969:
701). However, some spokesmen have sug-
gested that nuclear fracturing and heating
would be less controlled and more expen-
sive than conventional steam injection
(Spencer and others, 1969: 10).
Solvent extraction methods also use
injection wells for introduction of the
dissolving agents. Three types of dis-
solution systems have been applied: emul-
sifiers, such as detergents; organic sol-
vents, such as naphthene; and caustic
agents, such as sodium hydroxide. All
three types require removal of the additive
after the tars are produced.
The detergent systems dissolve the
tar in water and are much less expensive
than the organic solvents. Although deter-
gents usually penetrate only a portion of
the tar sands reservoir, almost all the
bitumen is removed from the area "swept"
(Spencer and others, 1969: 10). Emulsi-
fiers have also been successfully tried in
conjunction with steam injection.
Organic solvent extraction has been
attempted but is not as economical as
methods that heat the reservoir.
Caustic agents, such as sodium hydrox-
ide, have been used in conjunction with
steam. Tests in Canada during the 1960's
have produced generally favorable results,
but steam requirements were high (Camp,
1969: 701).
Whichever in situ method or combina-
tion of methods is employed, the extracted
bitumen must be piped a short distance to
upgrading facilities.
5.8.1.3 Upgrading
The bitumen extracted in situ or by
surface processing facilities must be up-
graded to a synthetic crude oil (syncrude)
for handling and pipeline transport. Two
basic methods can be used: thermal break-
down and direct hydrogenation.
In the thermal process the bitumen is
heated to between 800 and 1,000°F to break
down the chemicals and drive off the vola-
tile matter. A'part of this process may
involve a coking unit similar to that used
for the pyrolysis extraction of bitumen
from tar sands. The leftover material
(coke) is a carbon residue that can be
burned for process heat within the plant
(Camp, 1969: 712-717).
The gases and liquids from the coking
unit are fractionated into oils of differ-
ent weight, and these are pumped into a
pressure vessel and mixed with hydrogen.
The hydrotreating step removes the sulfur
by forming hydrogen sulfide and also re-
duces the viscosity of the oil. One pro-
posed alternative method of refining would
involve direct hydrogenation of bitumen
under high temperatures and pressures,
without the coking step. However, direct
hydrotreating will require more hydrogen
and catalysts (Camp, 1969: 719). A sim-
plified diagram of the sequence of these
basic upgrading steps is shown in
Figure 5-6.
5.8.1.4 Refining
Processes for refining the syncrude
are the same as for crude oil and are
described in Chapter 3.
5.8.2 Energy Efficiencies
Only limited data are available on
energy efficiencies for processing tar
sands, and these are primarily from proto-
type facilities tested in Canada. The
following describes some efficiencies for
in situ recovery, bitumen recovery follow-
ing mining, and upgrading.
The in situ extraction method employ-
ing both steam and emulsifiers has been
tested by Shell Canada, Ltd. (Camp, 1969:
700) . Shell reports an overall recovery
of 50 to 70 percent of the bitumen in
5-12
-------
Bitumen
Fluid cokers
Coke
Fractionation
Hydrogen
Recycle
gas
Naphtha
Light oil
Heavy oil
Hydrotreating
Hydrogen
plant
Hydrogen
sulfide
recovery
Sulfur plant
•*"Sulfur
.^Synthetic crude
Figure 5-6. Steps Involved in Upgrading Bitumen to
Synthetic Crude Oil
Source: Camp, 1969: 710.
-------
place. However, this process has high
heating requirements and ancillary energy
g
for steam injection represents 160x10
Btu's per 10 Btu's of bitumen produced.
Also, this 16-percent energy subsidy is
sensitive to the thermal efficiency of
heat transfer in the tar sands, and if
this efficiency is impaired, ancillary
energy requirements would be much greater.
Primary efficiency for removal of
bitumen following mining ranges between 81
percent and 95 percent for some coking
type processes. Ancillary energy require-
Q
ments are about 1,400 kilowatts or 3.4x10
Btu's per day for a 10,000-barrel-per-day
(6.3xl010 Btu's) plant. Most of the
product losses result from material con-
sumed during combustion, and the energy is
dissipated as heat. Solvent recovery
systems can operate with primary efficien-
cies of about 90 percent; losses result
primarily from incomplete stripping of the
bitumen from the sand and in the recovery
of solvent. The hot water bitumen removal
process has achieved primary efficiencies
of 90 to 96 percent. The 90-percent effi-
cient operation was on Utah tar sands
(Camp, 1969s 712).
Upgrading efficiencies are not avail-
able on a detailed basis, although the pri-
mary efficiency of the Canadian operations
is about 78 percent in transforming bitumen
to syncrude (not including by-products that
could be sold or used for process heat,
such as plant fuel oil, fuel gas, and
coke). Efficiencies for refining are de-
scribed in Chapter 3.
5.8.3 Environmental Considerations
Surface processing plants have a num-
ber of process streams that involve poten-
tial discharges to air, land, and water.
Although these discharges are similar to
oil shale upgrading facilities or petro-
Calculated on the basis of 33 percent
efficiency and 3,413 Btu's per kilowatt
hour. Each barrel of bitumen is equivalent
to 6.3x10° Btu's.
chemical and refinery operations, quantita-
tive data are not available. Perhaps the
most significant potential discharges are:
solid tailings from the extraction opera-
tions ; cooling water and blowdown streams;
thermal discharges? and off-gases from the
refinery, cokers, and process heat plants.
Under controlled conditions, a number of
these residuals could be minimized. For
example, tailings could be returned to the
mine and reclaimed, process streams could
be equipped with suitable particulate and
gas removal devices, water streams could
be purified and sent to evaporative ponds,
and thermal discharges could be vented to
the air via cooling towers.
In situ recovery can result in re-
sidual discharges including: thermal addi-
tions to the atmosphere, water, and ground
in association with steam or combustion
methods; possible contamination of aquifers
with chemicals; surface spills and acci-
dents from machinery or human failure;
possible surface earth movements associated
with subsurface disturbances that could
affect large areas; noise pollution; and
emission of gases to the air, especially
from combustion for steam generation pro-
cesses (BLM, 1973: 370). Residuals from
hypothetical in situ tar sands operations
have not been quantified.
5.8.4 Economic Considerations
Current information on the economics
of tar sands processing is not available.
One 1970 study found that the Canadian tar
sands operation had an overall cost of
$270 million (Hottel and Howard, 1971:
190). Assuming a depreciation over 15
years and a discounted cash flow rate of
return of 5.8 percent, the value of tar
sands syncrude would be $2.90 a barrel.
This is certainly a low figure by present
standards. The distribution of total pro-
duction costs was about 22 percent for
extraction of bitumen from sands and 37
percent for upgrading (41 percent was for
mining) (Hottel and Howard, 1971: 193).
5-14
-------
TABLE 5-3
ANNUAL 1970 OPERATING COST AND INCOME
FOR A 50,000-BARREL-PER-DAY
TAR SANDS OPERATION
Category
Mine operations
Labor, supervision
Maintenance
Catalysts and chemicals
Process royalty
Overhead, taxes, insurance
Alberta product royalty
Total operating costs
Syncrude income at $2.90
per barrel
Sulfur income at $20.00
per ton
Total annual income
Millions
of
Dollars
10.9
3.2
5.8
2.6
0.5
3.6
5.9
31.7
50.8
2.3
53.1
Source: Hottel and Howard, 1971: 191.
The operating costs and income from the
plant are listed in Table 5-3.
Extraction costs using in situ meth-
ods are not available. If steam heating
is applied, an important variable appears
to be the cost of ancillary energy in pro-
ducing the steam. This energy would
probably be supplied by burning a portion
of the produced bitumen. Although in situ
methods negate the mining and processing
plant costs, they do require substantial
outlays for well development, field expan-
sion, and injection and recovery equipment.
A number of tar sands development
costs are difficult to predict, thus making
U.S. cost projections questionable. Fac-
tors contributing to this include: govern-
ment royalty and taxation policies; impact
of adverse weather on material handling
problems; distance to market; and competi-
tion with other energy forms (Hottel and
Howard, 1971: 193). Other factors may
also impact on costs; for example, the
U.S. export and import policies are of
special importance to Canadian tar sands
development.
5.9 T RANS PORTATION
Transportation of tar sands and mate-
rials would generally take place following
the upgrading or refining steps. One
exception is gilsonite, which .is slurried
and then piped several miles to a refinery
in Utah. If demand and supply were suffi-
cient, gilsonite could probably be trans-
ported longer distances economically.
Liquid transportation technologies used
for synthetic crudes are more completely
described in Chapters 1 and 2.
REFERENCES
Atomic Energy Commission (1974) Draft
Environmental Statement; Liquid
Metal Fast Breeder Reactor Program;
Vol. I, Alternative Technology
Options. Washington: Government
Printing Office.
Bureau of Land Management (1973) Energy
Alternatives and Their Related
Environmental Impacts. Washington:
Government Printing Office.
Cameron, R.J. (1969) "A Comparative Study
of Oil Shale, Tar Sands and Coal as
Sources of Oil." Journal of Petro-
leum Technology 21 (March 1969):
253-259.
Camp, Frederick W. (1969) "Tar Sands,"
pp. 682-732 in Encyclopedia of Chemi-
cal Technology. Vol. 19 (2nd edition).
New York: Interscience.
Cashion, W.B. (1973) "Bitumen-Bearing
Rocks," PP- 99-103 in Donald A. Brobst
and Walden P. Pratt (eds.) United
States Mineral Resources. USGS Pro-
fessional Paper 820. Washington:
Government Printing Office.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use,
Final Report: Vol. I, 1974; Vol. II,
1975. Columbia, Md.: Hittman Asso-
ciates, Inc.
5-15
-------
Hottel, B.C.. and J.B. Howard (1971) Hew
Energy Technology; Some Facts and
Assessments. Cambridge, Mass.:
M.I.T. Press.
Kilborn. George R. (1964) "New Methods of
Mining and Refining Gilsonite,"
pp. 247-252 in Edward F. Sabatka (ed.)
Guidebook to the Geology and Mineral
Resources of the Uinta Basin: Utah's
Hydrocarbon Storehouse. Salt Lake
City: Intermountain Association of
Petroleum Geologists.
National Petroleum Council, Committee on
U.ff. Energy Outlook (1972) U.S. Energy
Outlook. Washington: NPC.
Spencer, George B., W.E. Eckard, F. Sam
Johnson (1969) "Domestic Tar Sands
and Potential Recovery Methods—
A Review," pp. 5-12 in Interstate Oil
Compact Commission Committee Bulletin
11 (December 1969).
5-16
-------
CHAPTER 6
THE NUCLEAR ENERGY—FISSION RESOURCE SYSTEM
6.1 INTRODUCTION
6.1.1 History of Nuclear Energy
Commercial use of nuclear fission as
an energy source has a history of less than
20 years; the first electric power gener-
ating plant went into operation at
Shippingport, Pennsylvania in 1957. The
use of nuclear power as an energy source
grew out of nuclear weapons development
during World War II. With the creation of
the Atomic Energy Commission (AEC) following
the war came an explicit effort by the gov-
ernment to fund and develop the commercial
use of nuclear energy. The major rationale
behind this development has been the assump-
tion of a large supply of nuclear resources
that could one day be substituted for the
more limited fossil fuel sources.
The development of nuclear fission as
an energy source has been strongly influ-
enced by the complex technologies and the
hazards from radioactivity. The complexity
of the technologies has required continuous
research and development, and as a result,
development costs have been higher than the
private sector has been willing to bear.
Together with the need for regulating radio-
active materials, the level of cost has re-
sulted in a major role for the federal gov-
ernment in the development of nuclear energy.
6.1.2 Basics of Nuclear Energy
Nuclear fission is the process whereby
certain heavy atoms split into two dissimi-
lar atoms and, in doing so, release energy
and one or several neutrons (a basic nuclear
particle) . The neutrons can then react with
other atoms, causing them to fission, and
thus create a "chain reaction." The term
"nuclear criticality" is used to describe
a sustaining chain reaction; that is, the
chain reaction will continue until condi-
tions are altered to make the reaction
cease. In a nuclear reactor, the controlled
chain reaction creates heat, which can be
converted to electrical energy.
*
Three isotopes fission readily and are
usually referred to as fissile fuels:
U-235, Pu-239 (Plutonium-239), andU-233.
When an atom fissions, the two newly formed
atoms are called fission products or fission
fragments. Since the splitting can occur
in a variety of different ways, various.
fission products are formed; for example,
strontium, cesium, iodine, krypton, xenon,
etc. The nuclear fuels and most of these
fission products are radioactive, thereby
creating fuel and fuel by-product handling
problems that are unique to the nuclear
power industry.
Radioactivity (or "radioactive decay")
can be described as the spontaneous
Isotopes are atoms that contain the
same number of protons but a different num-
ber of neutrons. Two or more isotopes of an
element exhibit similar chemical properties
but different physical properties because
of their different atomic weight. For ex-
ample, uranium has three isotopes, Uranium-
233, Uranium-235, and Uranium-238. All con-
tain 92 protons but a different number of
neutrons.
**
Fissile is a term that describes nu-
clear fuels that will fission when bombard-
ed with low-energy neutrons. Fertile is a
term that describes a material which, when
bombarded by a neutron, becomes fissile.
6-1
-------
transformation of an atom into either a new
atom or a different form of the original
atom with the concurrent release of energy
in the form of highly energetic alpha par-
ticles, beta particles, or gamma rays. The
term "half-life" indicates how rapidly a
material will decay. In the time equal to
a half-life, the amount of radioactive ma-
terial decreases by one-half. In addition
to a number of beneficial uses (including
several in medicine), these particles and
rays can have significant adverse effects
on the cells of biological organisms. The
effect of radioactivity on biological orga-
nisms is determined by the rate of decay
and by the type of particles and rays that
are released. Two units for describing
radioactivity that will be used throughout
this chapter are "curies" and "rems." A
curie measures the rate of decay of a sub-
stance; that is, it is a measure of a num-
ber of unstable nuclei that are undergoing
transformation in the process of radioac-
tive decay. One curie equals the disinte-
gration of 3.7x10 nuclei per second. A
rem is a unit to measure the radiation re-
ceived by organisms in the form of the par-
ticles and rays. The natural background
dose, not including medical x-rays, is ap-
proximately 125xlO~ rem. In many cases
the notation "mrem" (or millirem) will be
used, where one millirem equals 10 rem.
Thus, natural background dose levels may be
expressed as 125 mrem.
Two generations of nuclear fission
technology are either available or under
development: conventional fission reactors
and breeder reactors. Conventional fission
reactors are commercially available and rep-
resented approximately 6.1 percent of the
The conversion from curies to rems
for a certain type of radiation can be made
when the biological damage caused by that
radiation is known. The received dose is
determined by the curie value and the dam-
age.
nation's^electrical generating capacity as
of May 1974, or 27,800 megawatts-electric
(Mwe) (INFO, 1974: 7) . These reactors are
expected to be the major source of nuclear-
generated electric power for the next 20
years. Two types of conventional fission
reactors are presently available in the
U.S.: the light water reactor (LWR) (43
of these are licensed) and the high temper-
ature gas reactor (HTGR) (two of these are
licensed). The AEC expects conventional
fission reactors to provide 16 percent of
total U.S. electric power consumption by
1980 (INFO. 1974: 5) . Three factors should
be noted with regard to conventional fission
reactors:
1. Although they are commercially
available, engineering problems
are still being solved.
2. The rate at which these reactors
have been brought into operations
has been slower than projected.
3. A controversy exists over the
amount of uranium that is avail-
able for conventional reactor use.
The last factor, the projected scarcity
of uranium, has driven the development of
the liquid metal fast breeder reactor (LMFBR) .
The breeder reactor is attractive because it
produces plutonium, which may be used to fuel
other LMFBR1s, and therefore reduces the
amount of uranium required per reactor per
year. The AEC is presently carrying on a
major development program for the LMFBR,
but commercial LMFBR's are not expected to
be available until around 2000.
6.1.3 Organization of Chapter
The remainder of this chapter is orga-
nized into three major sections. Section
6.2 covers the LWR, Section 6.3 covers the
HTGR, and Section 6.4 covers the LMFBR.
Each section begins with a description of
the resource base and then sequentially
describes the entire fuel cycle for that
system, beginning with exploration and
ending with transportation. As with the
other chapters, each technological process
6-2
-------
j described, including information on en-
ergy efficiencies, environmental impacts,
and economics.
The presentation of the environmental
residual data differs from the presentations
in other chapters. In the LWR section, the
amount of residuals for each process is
based on a 1,000-Mwe nuclear plant operating
for one year at a load factor of 80 percent.
Each process (such as milling, enrichment,
etc.) must produce a certain "quantity" of
product material to be used by the model
1,000-Mwe plant. The residuals listed in
the tables are based on this "quantity."
Another difference is that the LWR tables
include the residuals from secondary power
sources. For example, the majority of the
sulfur oxides (SO ) residuals listed for
the enrichment process are emissions from
the Tennessee Valley Authority coal-fire
plants .
The residual assumptions used in the
HTGR and the LMFBR sections differ from
those used in the LWR. The necessary infor-
mation to understand these residuals is giv-
en in the appropriate HTGR and LMFBR sections.
6.2 LIGHT WATER REACTOR (LWR) SYSTEM
6.2.1 Introduction
The light water reactor gets its name
.from the use of ordinary water (terms light
*
water ) to transfer heat from the fission-
ing of uranium to a steam turbine. The pri-
mary energy sources for the LWR is U-235,
and there are 10 major activities in the LWR
fuel cycle as indicated in Figure 6-1: ex-
ploration for uranium; mining of uranium ore
and reclamation; milling of uranium ore to
produce yellowcake (U3O8) ;** production
Light water is pure I^O (two hydrogen
atoms plus one oxygen atom) . Heavy water is
deuterium oxide, D2O (two deuterium atoms
plus one oxygen atom) . Deuterium is a heavy
isotope of hydrogen.
**
The product of a milling process that
converts ore containing 0.2-percent 11303 in-
to "yellowcake" containing approximately 80-
percent 11309.
of uranium hexaflouride (UF6); enrichment
to produce a higher concentration of U-235;
fuel fabrication; use of the LWR to produce
electricity; reprocessing of used fuel to
recover the remaining U-235 and Pu-239;
radioactive waste management; and transpor-
tation of radioactive materials at various
stages in the LWR system.
6.2.2 Resource Base
6.2.2.1 Characteristics of the Resource
Uranium is one of the elements and
occurs in nature as a compound. About 95
percent of the uranium mined in the U.S.
exists as uranium oxide (known as uraninite
or pitchblende) . Most of the remaining
five percent exists in uranium hydrous
silicate compounds (known as coffinite) or
potassium uranium vanadate (known as carno-
tite) (Singleton, 1968:11). Uranium con-
sists of three naturally occurring isotopes
in the following proportions: 99.29 percent
U-238, 0.71 percent U-235, and a trace of
U-234. U-235 is used to fuel the LWR. A
*
ton of uranium-bearing ore contains, on the
average, four to five pounds of uranium
oxide from which 0.024 to 0.030 pound of
U-235 can be obtained. ^
Most of the uranium mined in the U.S.
is found in three types of deposits: petri-
fied rivers, veins, and ancient conglomer-
ates. Ancient conglomerates are old stream
channel deposits that were formed more than
one-half million years ago (Singleton, 1968:
22) . The difference between petrified riv-
ers and veins is that the host sandstone
containing the uranium lies horizontally
in the first and vertically in the second.
These sandstone formations provide 95 per-
cent of the ore mined in the U.S.
6.2.2.2 Quantity of the Resources
Uranium resources and reserves are
normally discussed in terms of quantities
*
Unless preceded by "metric," "ton" will
refer to a short ton (2,000 pounds). A
metric ton is 2,205 pounds.
6-3
-------
6.2.8 ,
Radioactive
Waste
Management
6. ? . 7
6.2.3
6.2.4
6.2.5.1 6.2.
Exploration
Mining and
Reclamation
Milling
Reprocessing
5.2 6.2.5.3
6.2.5.4 6.?.6
UF6
Production
Enrichment
Fuel
Fabrication
i
6.2.2 I
LWR
Electricity
Domestic
Uranium
Resources
6.2.5 Processing
6.2.9 Transportation Lines
Involves Transportation
Does Not Involve Transportation
Figure 6-1. Light Water Reactor Fuel Cycle
-------
TABLE 6-1
URANIUM RESOURCES
Cutoff Costs
(1974 dollars
per pound)
8
10
.15
Resources
(thousands of tons
of u3o8)
Reserves Potential
227 450
340a 700b
520a l,000b
Source: AEC, 1974a.
Includes lower cost reserves.
Includes lower cost potential resources.
available at three cost-of-recovery levels:
$8, $10, and $15 per pound of U,Og. Table
6-1 gives the AEC's estimates of uranium
resources at each of these price levels in
1974 dollars. The prices include the cost
of exploration, mining, and milling. The
resources are divided into reserves (that
amount currently known to be recoverable
at the given price level) and potential
resources (that amount estimated to be ulti-
mately recoverable at the given price level).
The estimated reserve of 520,000 tons at
$15 per pound represents approximately 47
percent of the free world reserves.
To indicate the energy represented by
these reserves, a typical 1,000-Mwe LWR
requires 200 tons of yellowcake per year.
Therefore, the presently licensed capacity
of approximately 28,000 Mwe would exhaust
the nation's $8-per-pound reserves in about
49 years. If the nation achieves the
250,000-Mwe capacity projected by the AEC
for 1985 (INFO. 1974: 5), existing $15-per-
pound reserves would last only 10 years.
Table 6-2 presents estimates of the
relationships between generating capacity,
uranium needs, and years of supply to 1985.
These projections make the accuracy of ura-
nium reserve estimates a critical issue.
Part of the debate revolves around the gov-
ernment's procedures for estimating reserves.
Responsibility for these estimates rests
with the AEC which publishes a yearly esti-
mate (AEC, 1974b). The data base for the
estimate is proprietary reserve information
provided on a voluntary basis by private
companies. The AEC makes its own reserve
estimates based on the company-supplied
TABLE 6-2
U_O0 NEEDS FOR PROJECTED LIGHT WATER REACTOR CAPACITY
J O
Date
1974
1980
1985
AEC Projected Nuclear
Capacity (Mwe) a
28,183
102,000
250,000
Tons of U O
Needed per Year
5,367
20,400
50,000
Number of Years the Proven
Reserves Will Last at the
Given Nuclear Capacity
$8 per
pound
49
13.5
5.5
$10 per
pound
60
16.5
6.8
$15 per
pound
92
25.5
10.4
Source:'
INFO. 1974: 5.
6-5
-------
information. The AEC judges the reasonabil-
ity of the company's estimates by a compar-
ison with the AEC's own estimates. However,
no uniform data collection method or reserve
estimate method exists in the uranium in-
dustry.
In an effort to provide more reliable
reserve estimates, the AEC undertook the
National Uranium Resource Evaluation pro-
gram for a comprehensive assessment of U.S.
uranium resource potential (AEC, n.d.).
However, the inherent problems in arriving
at generally accepted estimates are illus-
trated by the AEC's preliminary study of
the San Juan Basin in New Mexico. The AEC
estimated that this basin contained 740,000
tons of U,O0 at a price of $30 per pound.
J O
When the AEC had 36 independent geologists
review its study and their estimates were
averaged, reserves were calculated to be
290,000 tons less than the AEC estimate, or
a total of 450,000 tons of U3°8'
Conversely, some industry critics con-
tend that the overall domestic resource
estimates of the AEC are low. These differ-
ing conclusions reflect both the difficul-
ties inherent in judging the quantity of
resources and those associated with judging
the impact of differing prices. There does,
however, appear to be general agreement that
only a small portion of potential ore-carry-
ing formations has been explored (NPC, 1973:
6).
6.2.2.3 Location of the Resources
As indicated in Table 6-3, two states
(New Mexico and Colorado) contain more than
84 percent of the proven reserves at $8 per
pound. The Colorado plateau (which covers
parts of Utah, Colorado, Arizona, and New
Mexico) contains 63 percent of the proven
reserves at $15 per pound (Senate Interior
Committee, 1973: 34).
Fifty-eight percent of the $8-per-
pound reserves are located at depths that
require underground mining; the rest can be
TABLE 6-3
URANIUM ORE RESERVES BY STATES
State
New Mexico
Wyoming
Utah
Colorado
Others
Percent of Total
Ore Reserves At
$8 Per Pound
49.5
35.0
2.8
3.1
9.6
Source: AEC, 1974b: 34.
surface mined. The higher cost of underground
mining; generally requires that the deep
ores have a higher concentration of uranium
before they can be classified as reserves.
6.2.2.4 Ownership of the Resources
In January 1974, approximately 19 mil-
lion acres of land were classified as being
held for uranium exploration and mining.
Of that amount, approximately 31 percent was
private land and the rest was held by the
federal government or by the states. Pri-
vate access to public lands varies, depending
on their particular legal classification.
Access to the largest portion of the federal
land, public domain, may be had by the rel-
atively simple process of filing a claim.
6.2.3 Exploration
Exploration for uranium divides into
three principal phases (preliminary inves-
tigations, detailed geologic studies, and
detailed physical exploration) and eight
specific activities as illustrated in Fig-
ure 6-2. Full exploration of an area re-
quires, on the average, from four to five
years. The following technical description
is organized around the three principal
phases.
6-6
-------
PRELIMINARY
INVESTIGATIONS
|_No prospectj
! No prospect
! No discovery}1
DETAILED
GEOLOGICAL
STUDIES
8
DETAILED
PHYSICAL
EXPLORATION
"Hold land ~^
! position i
' 1
Development working
geological hypothesis
Select promising geographic
areas for investigation
Collect and review
available data
Define prospect;
Conduct initial drilling;
Minimum land acquisition
^Prospect conf i rmedj
[Complete land or lease acquisition
I
Conduct exploration
drilling program
(~Dis_covery_
Y
Evaluate!
^
1
r
Conduct
drilling
detailed
program
exploration
COMMENTS
Creative Stage
Limiting Factors
4 Months
2 Months
2 Months
I Year
2 Months
2-3 Years
Figure 6-2. Uranium Exploration
Source: NPC, 1973: 51.
-------
6.2.3.1 Technologies
6.2.3.1.1 Preliminary Investigations
Preliminary investigations are char-
acterized by data collection and review
based on available reports and aerial photo-
graphs for a selected area. This initial
phase seeks to identify a uranium host rock,
usually sandstone.
6.2.3.1.2 Detailed Geological Studies
Phase two includes all or part of the
following activities: surface mapping,
sampling, preparing subsurface maps, and
performing geochemical, geophysical, and
aerial surveys. Although these activities
generally parallel those used in prospect-
ing for other minerals, some uranium pro-
specting techniques rely on the ore's ra-
dioactivity to aid in its location. The
uranium in the ore emits gamma rays that
can be detected. One such detection tech-
nique is airborne radiometric prospecting,
which uses either Geiger-Muller tubes
(Geiger counters) or scintillometers. Al-
though both of these instruments are sen-
sitive to gamma rays, the scintillometer
is more effective and is more frequently
used.
Radiometric prospecting is most effec-
tive in locating uranium deposits that are
older and close to the surface. Where the
deposit is recent (less than 500,000 years
old) or where there is a thick overburden,
radiometric prospecting is less reliable.
Additionally, such prospecting sometimes
identifies radiation from thorium and
potassium rather than uranium. Therefore,
deposits found by radiometric prospecting
must be confirmed by some type of geophys-
ical or geochemical technique (Youngberg,
1972) .
Another prospecting technique involves
monitoring for radon gas. Radon gas is a
radioactive element naturally produced from
the uranium that can be identified either by
scintillometers or sensitive film. Radon
gas monitoring must be carried out on the
surface.
6.2.3.1.3 Physical Exploration
The final phase of exploration involves
drilling into the suspected ore deposit.
Drilling is usually done with rotary or
pneumatic percussion equipment. Drilling
allows two types of final assessments: scin-
tillometer measurements at various depths
in the borehole and geochemical analyses
of the materials brought to the surface.
Data from these two measures are correlated
to determine uranium' concentrations at var-
ious depths.
Drilling is one measure of the rate of
exploration and has remained relatively con-
stant for the last three years at approxi-
mately 17 million feet per year. This rate
is slightly more than half the rate of the
peak year, 1969, when approximately 30 mil-
lion feet were drilled (AEC, 1974b). In
1973, about one-half of all exploratory
drilling for uranium was located in Wyoming
and one-quarter in New Mexico.
The discovery rate of uranium per foot
drilled has averaged 3.8 pounds of U,O0
3 o
contained in the ore, and, with the exception
of a period in the 1950's, the addition to
proven reserves has fluctuated in direct pro-
portion to the drilling rate.
6.2.3.2 Energy Efficiencies
The energy required in exploration is
classified as ancillary. While the amounts
of ancillary energy required have not been
calculated, they are apparently quite small
compared to the energy content of the ura-
ium found. The overall efficiency is prob-
ably above 99 percent.
6-8
-------
6.2.3.3 Environmental Considerations
Data on environmental residuals result-
ing from exploration are not available but
appear small. The main environmental impact
is land disturbance associated with drilling.
6.2.3.4 Economic Considerations
Exploration represented about 13 per-
cent of the total cost of yellowcake pro-
duction in 1970, as given in Table 6-4.
Since yellowcake production represented
only six percent of the 11 mills per kilo-
watt-hour (kwh) nuclear electric generation
cost that year, exploration costs were only
about 0.8 percent of the power generation
costs. Thus, even if exploration costs
rise, as some observers expect, nuclear
power costs should not be appreciably af-
fected .
6.2.4 Mining and Reclamation
Uranium mining techniques depend on
the depth, size, assay, and host formation
of the ore body, but the basic technologies
are similar to those used in coal mining
(Chapter 1). Of the 175 uranium sources
being worked in 1973, 70 percent were under-
ground mines, 19 percent were open pit mines,
and the remaining 11 percent consisted of
other sources (e.g., low-grade stock piles,
etc.) In terms of total 1973 ore produc-
tion, however, underground mines provided
36 percent, open pit mines provided 62 per-
cent, and other sources provided about 1.5
percent (AEC, 1974b: 22). Thus, although
small in numbers, open pit mines produced
a majority of the yellowcake mined in 1973,
the reason being that daily production rates
from underground mines are much lower than
the rates from open pit mines.
As noted earlier, a 1,000-Mwe model
reactor requires approximately 200 tons of
yellowcake per year. Assuming a U_00 con-
J o
centration in the ore of 0.2 percent,
100,000 tons of ore must be mined each year
to supply one 1,000-Mwe reactor. For com-
parison, a 1,000-Mwe coal-fired plant would
require approximately three million tons of
coal per year (assuming coal with a heating
value of 10,000 Btu's per pound).
TABLE 6-4
COSTS OF U,OQ PRODUCTION (CONSTANT 1970 DOLLARS)
J o
Production Task
Exploration
Land cost
Exploration drilling
Development drilling
Mine/Mill
Capital
Operating
TOTAL
Dollars Per Pound
of U_O0 Recovered
J O
0.10
0.60
0.20
1.59
4.35
6.84
Percent of Total
13
87
Source: NPC, 1973: 10.
-------
6.2.4.1 Technologies
6.2.4.1.1 Open Pit Mining
Open pit uranium mining techniques
are quite similar to the surface coal min-
ing techniques described in Chapter 1. (The
primary difference between "open pit" and
"surface" mines is that open pit mines are
deeper and do not cover as broad an area
as surface mines.) One significant differ-
ence is that each truckload of uranium ore
is graded (measured for radioactivity) as
it leaves the pit. The truck then delivers
the ore to one of several stockpiles main-
tained near the mine. The purpose of sep-
arating ore by grades is to control the
feed to the mill and thereby insure the
most efficient and economical processing
of each grade.
6.2.4C2 Energy Efficiencies
No data is available for calculating
the energy efficiencies of uranium mining.
The primary energy efficiency in the mining
step would be equivalent to the percentage
of in-place uranium ore that is recovered.
The ancillary energy is that required to
power the equipment used in mining and
reclamation. In coal mining, the ancillary
energy requirements represent less than one
percent of the energy of the coal extracted
(Chapter 1) . Presumably, the ancillary en-
ergy requirements would be even smaller for
uranium mining because, as noted earlier,
much smaller amounts of uranium ore than
coal must be mined to provide an equivalent
amount of energy.
6.2.4.3 Environmental Considerations
6.2.4.1.2 Underground Mining
As in open pit mining, underground
uranium mining techniques are similar to
underground coal mining techniques. The
two major differences are related to seam
sizes and mine ventilation systems. Most
uranium ore bodies are long, thin, and
quite erratic in occurrence, and thus re-
quire special adaptations of routine coal
mining techniques. Since the seam at any
one site is often quickly mined, both the
working equipment and total mining oper-
ations must be highly mobile.
Special ventilation systems are re-
quired in underground uranium mines because
of the radon gas created by the uranium.
To maintain radon radioactivity in the air
at acceptable levels, large-capacity air
circulation pumps are used in conjunction
with special exhaust shafts at tunnel ex-
tremities to provide adequate ventilation
throughout the mine. Fresh air enters the
main shaft, travels through the various
tunnels and passageways, and exits through
the vent holes.
6.2.4.3.1 Open Pit Mining
Table 6-5 lists the residuals associ-
ated with open pit mining; the data are
normalized to the requirements of a typical
1,000-Mwe LWR (AEC, 1974c). Generally, the
major impact categories are the same as coal,
with impacts differing depending on location
(Chapter 1) . However, the scale of the im-
pacts is generally much less for uranium
because of the difference in the quantities
of material mined to provide an equivalent
amount of energy. Approximately 55 acres
are temporarily committed and two acres are
permanently committed per model 1,000-Mwe
LWR per year. The overburden represents
the most significant environmental residual
associated with open pit mining. About 2.7
million metric tons of overburden per year
is moved for each 1,000-Mwe LWR plant. The
overburden is used for backfilling the pit,
although in the past the pit normally has
never been completely filled because of
economic considerations. Present and future
land reclamation laws may require, as in
Colorado and Wyoming, that the land be prop-
erly reclaimed and restored.
6-10
-------
TABLE 6-5
SUMMARY OF ENVIRONMENTAL RESIDUALS
FOR URANIUM MINING (NORMALIZED TO
1,000-Mwe LWR ANNUAL FUEL REQUIREMENT)
Natural Resource Use
Land (acres)
Temporarily committed
Undisturbed area
Disturbed area
Permanently committed
Overburden moved
(millions of metric tons)
Water (millions of gallons)
Discharged to ground
Effluents
Chemical (metric tons)
Gases
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Carbon monoxide
Quantity
55
38
17
2
2.7
123
8.5
5.0
0.3
0.02
Source: AEC, 1974c: A-2.
Estimated effluent gases based upon com-
bustion of coal to supply power, together
with combustion of diesel fuel for mining
equipment operation.
The AEC estimates that 123 million gal-
lons of water per year (per model 1,000-Mwe
LWR) are pumped out of the mine and dis-
charged to the ground. If this water con-
tains suspended solids, the pollutants can
enter local water supplies unless control
procedures (such as settling ponds) are
used. Another effect is the probable low-
ering of the local water table. However,
water levels usually return to former levels
once the pumping has ceased.
The gaseous residuals include chemical
and radioactive effluents. The sulfur oxides
(SO ), nitrogen oxides (NO ), hydrocarbons
X 2s.
and carbon monoxide (CO) emissions are from
the operation of the mining machinery.
The major radioactive effluent is radon
gas, a naturally occurring radioactive ele-
ment that is a decay product of uranium.
However, this effluent is readily diluted
in the atmosphere and has a short half-life
(defined in Section 6.12) , and thus its con-
centrations in unrestricted areas near the
mine are expected to be undetectable (AEC,
1974c: A-3). Therefore, radon gas is not
shown in Table 6-5.
6.2.4.3.2 Underground Mining
Data on environmental residuals for
underground mining are not available at
present. The disturbed surface area is
much less for underground mines than for
open pit mining. Unlike open pit material,
the rock removed from underground mines is
stockpiled because it is generally not econ-
ically feasible to refill the "rooms."
Since, on the average, underground ore must
contain 0.27-percent uranium to make mining
economical (as opposed to 0.17-percent
uranium in open pit mines) (AEC, 1974b: 33),
less ore needs to be extracted from under-
ground mines to produce a given quantity of
uranium.
A controversial aspect of underground
uranium mining has been the exposure of
miners to radioactivity, primarily radon gas
as described earlier. Currently, the EPA
is responsible for establishing guidelines
for exposure limits, but the industry has
protested the current limits as being too
strict.
No data are available on land subsi-
dence resulting from underground uranium
mining. However, any such subsidence should
be less than that from either underground
coal or oil shale mining because of the
smaller extraction areas.
6.2.4.4 Economic Considerations
Table 6-4 presents cost data for the
combined uranium mine/mill operation; sep-
arate data for just mining and reclamation
are not available. As indicated in Table
6-4, the mine/mill costs (including both
6-11
-------
TABLE 6-6
ESTIMATED INCREMENTAL COST OF U-
TO MEET NEW SAFETY STANDARDS
Pounds of U308Recovered
Per Ton of Ore
2.6
4.0
Incremental Cost of u3Os
Under Given Mine Conditions
(dollars per pound)
Favorable Average Severe
0.40 0.63 1.12
0.26 0.41 0.73
Source: *NPC, 1973: 81.
aCosts are in 1972 dollars.
.capital and operating costs) are 87 percent
of the cost of a pound of UjOg. However,
the cost of U.,O0 in the complete production
3 o
of electric power is only 0.66 mill per kwh
out of a total power generation cost of 9
to 11 mills per kwh. Therefore, the mine/
mill costs represent only about six percent
of the total nuclear power generation costs.
The Federal Metal and Non-Metallic
Mines Safety Act of 1966 has had an impor-
tant effect on the underground mining of
uranium (NPC, 1973: 79) due to the strict
regulations on radiation exposure limits.
Table 6-6 gives an estimate of the increase
in the cost of U_0_ due to these new safety
J O
and radiation regulations (NPC, 1973: 81).
For ore containing only 2.6 pounds of re-
coverable U.Og per ton, the increase in the
cost of a pound of U,O_ would be 63 cents
J O
in an average mine.
Although the act will have a negligible
effect on open pit mines, the cost of sur-
face reclamation for an open pit mine is
expected to range from $0.07 to $2.90 per ton
of ore (or from $0.03 to $1.15 per pound of
U O assuming 2.6 pounds of U 0 per ton of
3 o 38
ore), depending on the degree of reclamation
desired.
6.2.5 Processing
Processing consists of a variety of
different physical and chemical steps in
which the raw uranium ore is converted in-
to uranium fuel pellets encased in long
metal tubes that are ready to be inserted
into the reactor. As shown in Figure 6-1,
the steps in processing are usually divided
into milling, UF, production, enrichment,
and fuel fabrication.
6.2.5.1 Milling
The basic purpose of the milling pro-
cess is to convert the uranium ore (which
contains about 0.2-percent U_O0) into a
J O
compound called "yellowcake" (which contains
80- to 83-percent U,O_).
J O
In 1973, 16 yellowcake mills were op-
erating or on standby (Table 6-7) . These
mills vary in processing capacity from 400
to 7,000 tons of ore per day. Operating at
79 percent of their capacity in 1973, ap-
proximately 6,800,000 tons of ore were
milled for an annual t^Og production of 13,
13,200 tons. A typical 1,000-Mwe LWR needs
200 tons of 0308 per year.
6.2.5.5.1 Technologies
Figure 6-3 is a flow chart for the
typical milling plant in the U.S. The steps
in the milling process are:
1. Crushing and Grinding: The basic
purpose of this step is to reduce
the particle size so that chemical
reactions can be accomplished more
rapidly.
6-12
-------
TABLE 6-7
U.S. URANIUM ORE MILLS OPERATING OR ON STANDBY (DECEMBER 1973)
Company
Location
Nominal
Capacity
(tons ore
per day)
Anaconda Company
Atlas Corporation
Conoco and Pioneer Nuclear, Incorporated
Cotter Corporation
Dawn Mining Company
Federal-American Partners
Exxon Company
Kerr-McGee Nuclear Corporation
Petrotomics Company
Rio Algom Corporation
Union Carbide Corporation
Union Carbide Corporation
United Nuclear-Homestake Partners
Utah International, Incorporated
Utah International, Incorporated
Western Nuclear, Incorporated
TOTAL
Grants, New Mexico
Moab, Utaha
Falls City, Texas
Canon City, Colorado
Ford, Washington
Gas Hills, Wyoming
Powder River Basin, Wyoming
Grants, New Mexico
Shirley Basin, Wyoming
La Sal, Utah
Uravan, Colorado
Natrona County, Wyoming
Grants, New Mexico
Gas Hills, Wyoming
Shirley Basin, Wyoming
Jeffrey City, Wyoming
3,000
1,500
1,750
450
400
950
2,000
7,000
1,500
500
1,300
1,000
3,500
1,200
1,200
1.200
28,450
Source: AEC, I974b; 62.
Cranium production facility on standby at end of 1973.
I
H
00
-------
ORE
1
CRUSHING
ATMOSPHERE
T
WATE
DUST
COLLECTION
GRINDING
OXIDANT^
LEACHING
ACID
TAILINGS-
WASH WATER
ORE
RESIDUE
SEPARATION
PREGNANT
LIQUOR
RAFFINATE-*-
PURIFICATION
AMMONI
PRODUCT
LIQUOR
PRECIPITATION
SEPARATION %
THICKENER \
FILTER-DRYER^
\
YELLOW CAKE PRODUCT
U3°8
ATMOSPHERE
Figure 6-3. Milling Plant
Source: AEC, 1974c: B-8.
-------
2. Leaching. After the physical
grinding, the uranium minerals are
dissovled (or "leached") from the
host rock. The type of chemical
used in this process is determined
by the composition of the uranium
in the ore and by the other types
of minerals present. The two pri-
mary leaching agents used in the
U.S. are sulfuric acid and either
sodium carbonate or sodium biocar-
bonate. Eighty percent of all yel-
lowcake is produced using sulfuric
acid. Acids will react with the
uranium more quickly than carbonate
but also will react with the other
dissolved minerals, which are re-
moved during later steps.
3- Washing (Separation). Regardless
of the leaching method, the leached
solution is then "washed" with wa-
ter to remove the sand and slime.
4. Purification. Uranium is separated
from all the other leached minerals
by sending the washed solution
through a "purification" step. The
purification process selectively
removes the uranium from the water
solution and leaves the unwanted
metals in solution.
5. Precipitation. The product from
the purification step enters the
precipitation stage where ammonia,
air, and heat are used to cause the
uranium to become insoluable.
6. Separation. The solution containing
suspended uranium particles proceeds
to a thickener, and the resulting
product from the thickener, yellow-
cake, is further washed and dried.
The yellowcake is packaged in 55-
gallon drums for shipment.
6.2.5.1.2 Energy Efficiencies
The ancillary energy requirement is the
energy required to run the milling process.
The ancillary energy requirement for the
milling operation to supply a 1,000-Mwe
plant for one year is equivalent to 68.5
million cubic feet (mmcf) of natural gas
and 970 metric tons of coal (AEC, 1974c: B-2) .
Assuming an energy content of 1,000 Btu's
per cubic foot (cf) for natural gas and
10,000 Btu's per pound of coal, the ancillary
energy requirement for lust the milling op-
eration is approximately 0.09xl012 Btu's
(thermal) . Since the annual output of such
a model LWR is equivalent to approximately
23x10 2 Btu's (electric), the ancillary
energy requirement for milling is quite
small.
The primary efficiency is equivalent
to the recovery efficiency in the milling
process, which was approximately 93.5 per-
cent during 1973. From 1964 to 1970, the
recovery efficiency was about 95 percent
(AEC, 1974b: 67). The main factors that
affect the recovery rate are the contact
time in the leaching tank and the concen-
tration of the leaching agent that is used.
The time and concentration can both be in-
creased, but at a sacrifice of product
throughput and economics.
6.2.5.1.3 Environmental Considerations
Table 6-8 contains the chronic environ-
mental residuals associated with the typical
yellowcake milling operation normalized to
the annual requirement for a 1,000-Mwe LWR
(AEC, 1974c: B-2, B-3) . The table was
derived under the following assumptions:
1. Acid leaching is used.
2. The mill is located in an arid,
isolated region.
3. Several mines are close to the
mill.
The main residuals associated with the
milling process are the solid and liquid
tailings. Since the percentage of U^Og in
the ore is always low (i.e., about 0.2 per-
cent) , essentially all the processed ore
becomes a residual known as solid tailings.
The solid ore residuals are 91,000 metric
tons of ore per year per model 1,000-Mwe
LWR, but this quantity will vary inversely
with the ore assay. If the percentage of
U3
-------
TABLE 6-8
SUMMARY OF ENVIRONMENTAL
RESIDUALS FOR URANIUM MILLING
(NORMALIZED TO 1,000-Mwe
LWR ANNUAL FUEL REQUIREMENT)
Natural Resource Use
Land (acres)
Temporarily committed
Undisturbed areaa
Disturbed area
Permanently committed
(limited use)
Water (millions of gallons)
Discharged to air
Effluents
Chemical
Gases*3 (metric tons)
Sulfur oxides
Nitrogen oxides
(40 percent from natural
gas use)
Hydrocarbons
Carbon monoxide
Liquids
(thousands of metric tons)
Tailings solutions
Solids
(thousands of metric tons)
Tailings solutions
Radiological (curies)
Gases (including airborne
particulates)
Radon-222
Radium-226
Thorium-230
U natural
Liquids
U and daughters
Solids
U and daughters
Thermal (billions of Btu's)
Source: AEC, 1974c: B-2, B-3.
Quantity
0.5
0.2
0.3
2.4
65
37
15.9
1.3
0.3
240
91
74.5
0.02
0.02
0.03
600
69
portion of undisturbed area for mills
is included in mine land use.
Estimated effluent gases based upon combus-
tion of equivalent coal and natural gas for
power and heat.
The sodium carbonate or alkaline leaching
process' uses 3.5 times less water than the
acid leaching process and thus releases a
smaller volume of discharge (containing
less radium) to the tailings pond.
Two possible major accidents in a
uranium milling plant are a failure of the
tailings pond dam and a fire in the building
where the purification step is performed.
Either incident would produce additional
residuals not included in Table 6-8, but
the effect on the environment in both cases
is expected to be negligible because the
materials at this step are neither toxic
nor highly radioactive.
6.2.5.1.4 Economic Considerations
Data are not available on just the mil-
ling operation. The costs of the combined
mining/milling operation were discussed in
Section 6.5.4
6.2.5.2 Uranium Hexafluoride (USV)
Production
The purpose of UF production is to
convert the uranium in the yellowcake to a
gaseous compound (UFg) that can be used in
the uranium enrichment step. Two processes
of producing UFfi are currently being used:
the dry hydrofluor process and the wet sol-
vent extraction-fluorination process. At
present, two plants are in operation (one
of each type) and produce about equal quan-
tities of UFg (AEC, 1974c: C-l) . The cap-
acity of these two plants is currently suf-
ficient, but their capacity will have to be
doubled to meet the projected 1980 demand.
6.2.5.2.1 Technologies
Simplified flow diagrams for the dry
hydrofluor process and the wet solvent
extraction-fluorination process are given
in Figures 6-4 and 6-5 respectively. Common
steps in the two processes are the hydro-
fluorination step and the fluorination step.
6-16
-------
ROASTED URANIUM CONCENTRATE
N,
H,
HF
SOLID
WASTES
BURIED
REDUCTION
UO.
HYDRO-
FLUORINATION
UF4
FLUORINATION
UF,
COLD TRAP
UB
6
DISTILLATION
ATMOSPHERE
t
SCRUBBING
T
LIQUID WASTE
UF6 PRODUCT
Figure 6-4.
UFg Production—Dry Hydroflour Process
Source: AEC, 1974c: C-7.
-------
URANIUM CONCENTRATE
HNO.
yiir
1
DIGESTION
/ENTj
SOLVENT I SOLVENT
EXTRACTION
HEAT
EATl
CALCINATION
UO.
N
2_
2
REDUCTION
UO,
HF
HYDROFLUORh
NATION
UF
RAFFINATE
CONDEN
SATION
DILUTE
TO RECOVERY
FLUORINATION
T
SOLID WASTE
BURIED
ATMOSPHERE
SCRUBBING
HN03 RECOVERY
LIQUID WASTE
TREATMENT
IMPOUNDMENT
ATMOSPHERE
SCRUBBING a
TREATMENT
LIQUID WASTE
COLD TRAP
I
UF6 PRODUCT
Figure 6-5.
Production — Wet Solvent Extraction -Flourination
Source: AEC, 1974c: C-9.
-------
In essence, the two processes differ at the
point where impurities are removed. The
dry method produces the gas, then removes
the impurities by distillation. The wet
method removes impurities from the yellow-
cake before the gas is made (AEC, 1974c:
Section C).
6.2.5.2.1.1 Dry Hydrofluor Process
The dry hydrofluor process consists
of the following steps:
1. Reduction. The yellowcake is
roasted with cracked ammonia
(N2 and Hj) to change the U3O8
into uranium dioxide (uc>2) .
2. Hydrofluorination. Hydrogen
fluoride (HP) is used to change
the UO2 into uranium tetrafluoride
(UF4) .
3. Fluorination. Reaction of the UP^
with fluorine gas (F2> results in
the "crude" UFg product. The term
"crude" refers to the purity of the
UFg gas, which at this point con-
tains other volatile fluorides of
such elements as molybdenum and
vanadium that are impurities found
in the original ore.
4. Cold trap. The cold trap removes
molybdenum and vanadium impurities.
5. Distillation. Fractional distil-
lation separates the UFg from the
remaining impurities in the gas to
produce a "refined" UFg.
6.2.5.2.1.2 Wet Solvent Extraction-
Fluorination Process
The wet solvent extraction process
contains the following steps:
1. Digestion. The yellowcake is first
dissolved in nitric acid to prepare
it for extraction.
2. Solvent Extraction. This step se-
lectively removes the uranium. The
impurities, such as molybdenum and
vanadium, remain in the aqueous so-
lution called raffinate. The ura-
nium is in a uranyl nitrate solution.
3. Calcination. The uranyl nitrate is
heated to form uranium trioxide
(U03) .
4. Reduction. The UC-3 is reduced to
UC>2 by chemical reaction with N2
and H0.
5. Hydrofluorination. This step is
the same as in the dry process.
6. Fluorination. This step is the
same as in the dry process.
7. Cold trap. This step is the same
as in the dry process.
6.2.5.2.2 Energy Efficiencies
The primary energy efficiency of UFg
production is quite high, as both processes
recover nearly 100 percent of the uranium
in the yellowcake (AEC, 1974c: C-17). The
ancillary energy requirement to produce
enough UF, for the model 1,000-Mwe reactor
for one year is reported as equivalent to
620 metric tons of coal plus 20 mmcf of
natural gas (AEC, 1974c: C-2) . Assuming
an energy content of 10,000 Btu's per pound
for coal and 1,000 Btu's per standard cf for
gas, the ancillary energy requirement is
12
0.033x10 Btu's (thermal). Comparing this
with the annual energy output of a 1,000-Mwe
12
plant of approximately 23x10 Btu's (elec-
tric) , the ancillary energy requirement for
UF, production is quite small.
6.2.5.2.3 Environmental Considerations
Table 6-9 lists the chronic environ-
mental residuals from UF, production for the
model 1, 000-Mwe LWR. In deriving this table,
the assumption was that one-half of the nec-
essary UF, comes from each of the two pro-
cesses (AEC, 1974c: C-2, C-3). Again, these
residual data are somewhat inconsistent with
the residual data of other chapters because
Table 6-9 includes residuals from the elec-
tric power plant that supplies electricity
to the UFg production plant.
The gaseous fluoride from the two fluor-
ination steps used in UFg production is emit-
ted at a rate of 0.11 metric ton per year per
model 1,000-Mwe LWR. Measurements of the fluo-
ride concentration in the vicinity of a wet
solvent extraction plant have indicated lev-
els below those expected to cause deleterious
effects on humans or grazing animals (AEC,
1974c: C-4).
6-19
-------
TABLE 6-9
SUMMARY OF ENVIRONMENTAL RESIDUALS
FOR URANIUM HEXAFLUORIDE PRODUCTION
(NORMALIZED TO MODEL LWR
Annual Fuel Requirement)
Natural Resource Use
Land (acres
Temporarily committed
Undisturbed area
Disturbed area
Permanently committed
Water (millions of gallons)
Discharged to air
Discharged to water bodies
TOTAL
Effluents
Chemical
Gases (metric tons)
Sulfur oxides3 .
Nitrogen oxides
Hydrocarbons*5
Carbon monoxide3
F-
Liquids
P-
SO4_
NO 3
ci-
Na+c
NH "*"
Fe3
Solids (metric tons)
Radiological (curies)
Gases
Uranium
Liquids
Radium-226
Thorium-230
Uranium
Solids (buried)
Other than high-level
Thermal (billions of Btu's)
Quantity
2.5
2.3
0.2
0.02
3.3
23.0
26.3
29
10
0.84
0.2
0.11
17.5
4.5
.1
8.8
.2
3.4
1.6
.04
40
0.00015
0.0034
0.0015
0.044
0.86
20
Source: AEC, 1974c: C-2, C-3.
Affluent gases from combustion of equiva-
lent coal for power generation.
From the combustion of coal and natural gas
and process vents, hydrocarbons include 0.2
metric ton per year of hexane from wet pro-
cess portion of model plant.
°Contains 80-percent potassium.
Three radioactive materials—uranium,
radium-226^ (Ra-226), and thorium-230
(Th-230—are emitted as liquid residuals in
the UF, production. The natural uranium
in the exhaust gases is quite small, and
calculations of natural uranium concentra-
tions at the site boundary indicate con-
centrations less than 0.1 percent of the
federally established limit (AEC, 1974c:
C-15). Radioactive elements in the liquid
effluents released to the river near the
plant are approximately four percent of
maximum permissible concentrations (AEC
1974c: C-15). The raffinate stream in the
wet process is impounded, and plans call for
disposal of the sludge either by burial or
reprocessing at a mill to recover the
uranium. Solid wastes from the dry process
contain radioactivity and will require
burial.
The amount of water used is approxi-
mately 2.4 million gallons per day. Most
of this is used as cooling water, and about
90 percent of this cooling water is returned
to the source (e.g., a river) from which it
came at a slightly higher temperature. The
rest is lost by evaporation. The wet pro-
cess uses about 1.5 million gallons per day
in the wet solvent extraction step (AEC,
1974c: C-4).
6.2.5.2.4 Economic Considerations
The cost in 1972 of the UF_ production
step has been calculated as $2.52 per kilo-
gram, which is equivalent to 0.08 mill per
kwh out of a total generation cost of 9.0
to 11.0 mills per kwh (NPC, 1973: 28) .
Thus, the UF, production step represents
a very small portion (about four percent)
of the total fuel cost and only about 0.8
percent of the total power generation cost.
6.2.5.3 Enrichment
Naturally occurring uranium consists
of approximately 0.7-percent U-235 and 99.3-
percent U-238. Enrichment is the process
by which the percentage of the desired
6-20
-------
fissile fuel, U-235, is increased. LWR's
require a fuel that is approximately three-
percent U-235, while the high temperature
gas reactor will require a U-235 concentra-
tion of 95 percent. There are currently
three operational enrichment plants in the
U.S.: Portsmouth, Ohio; Paducah, Kentucky;
and Oak Ridge, Tennessee.
6.2.5.3.1 Technologies
There are currently one extant and two
proposed enrichment technologies. The pro-
posed techniques are ultracentrifuge and
laser enrichment. The operational process
is known as gaseous diffusion.
Basically, a gaseous diffusion plant
consists of a large number of pumps to move
UF, through a large amount of piping and
separate enrichment stages. As shown in
Figure 6-6 (Elliot and Weaver, 1973: 114),
each enrichment stage produces two outgoing
streams of UF,, one which has a higher per-
b
centage of U-235 than the input feed stream
and one which has a lower percentage than
the input.
Each stage operates in the following
manner. A high-pressure feed stream of UF-
gas enters the stage. Since a very slight
weight difference exists between the U-235F-
and U-238F,. molecules, the lighter molecules
containing the U-235 move at a slightly
higher velocity than the molecules containing
0-238. The high-pressure input stream flows
by a porous membrane known as a barrier, and,
since the lighter U-235 molecules are moving
faster, they strike and pass through the mem-
brane at a higher rate than the heavier U-238
molecules. Therefore, the stream of UF, that
b
has passed through the barrier will contain
a higher percentage of the light U-235 mole-
cules.
By combining a series of stages, the gas
can be further enriched. However, the mass
difference between the light and heavy mole-
cules is small, and a large number of stages
in series are necessary to produce enriched
uranium that can be used in an LWR. For
example, about 1,500 stages are necessary
to produce UFfi that contains four percent
U-235.
As shown in Figure 6-7, the three
government-owned diffusion plants work as
a complex, each plant producing different
enrichments (Elliot and Weaver, 1972: 116) .
The Paducah plant produces UF. gas at one-
percent enrichment for input to the Oak
Ridge or Portsmouth plant. The Oak Ridge
plant typically produces enrichments from
one to four percent while Portsmouth can
produce 98-percent enriched gas. The de-
pleted streams of gas from Portsmouth or
Oak Ridge can be used as input to the Paducah
plant. All three plants were built between
1943 and 1955.
In 1972, any of the three existing
plants had the capacity to satisfy the total ,
U.S. demand for enrichment. However, given
the existing projections, additional plant
capacity will be needed by the early 1980' s
(House Interior Committee, 1973: 10) . These
new plants may use the gaseous diffusion
method or may use the ultracentrifuge sepa-
ration or laser enrichment techniques if
they are commercially feasible by the time
plant construction is begun.
As a result of government urging, two
U.S. industrial consortia for enrichment
have been formed. Bechtel, Union Carbide,
and Westinghouse constitute one group, and
the other group consists of Exxon Nuclear
and General Electric (INFO, 1973: 14) . At
present, both groups are leaning toward the
ultracentrifuge method, which consumes far
less electricity than the gaseous method,
although the technology for this method has
not yet been proved (House Interior Committee,
1973: 10). (A British-Dutch-West German com-
bine has decided to use this method.) Laser
enrichment.will probably not be feasible be-
fore 1985 but classified enrichment work with
6-21
-------
LOW
PRESSURE
ENRICHED
STEAM
HIGH
PRESSURE
FEED
STEAM
LOW
PRESSURE
•=U-235
DEPLETED
STEAM
= U-238
Figure 6-6. Gaseous Diffusion Stage
Source: Elliot and Weaver, 1972: 114.
Shipments
to industry
Essd
(various
assays)
Product
97,65%
Product
4.0%
T03% Available 2to3%
reproductio
Stored
Feed
Product
0.96%
Feed
(various
assays)
93.15%
Shipments
to industry
8k govt.
users
Feed
(various
assays)
0.3%
Tails
(%Values are weight % U-235)
Figure 6-7. Mode of Oneration for Gaseous Diffusion Plant
Source- Elliot and Weaver, 1972: 116.
-------
lasers at a number of locations (primarily
at the Los Alamos Scientific Laboratory)
•could change the entire uranium enrichment
picture if successful (Weekly Energy Report,
1973: 1).
6.2.5.3.2 Energy Efficiencies
The ancillary energy required to enrich
enough UF, to supply a model 1,000-Mwe plant
(80-percent load factor) for one year is
310,000 megawatt-hours (Mwh) (AEC, 1974c:
D-4) . The annual output from the 1,000-Mwe
plant would be 7,008,000 Mwh; thus, the
ancillary energy in the enrichment step re-
presents 4.4 percent of the final electrical
power output.
The primary efficiency losses for the
enrichment process would be the U-235 that
remains in the depleted stream and is stored
for possible future uses. A facility which
provides three-percent enriched U-235 fuel
leaves 22.9 percent of the total amount of
naturally occurring U-235 isotopes in the
depleted stream (Westinghouse, 1968: 18).
Therefore, the primary efficiency for the
enrichment step would be 77.1 percent.
6.2.5.3.3 Environmental Considerations
6.2.5.3.3.1 Chronic
Table 6-10 contains a summary of the
environmental residuals normalized to the
yearly requirement for a 1,000-Mwe LWR
(AEC, 1974c: D-2, D-3). Again, the resid-
ual data include those from the ancillary
energy source, in this case a coal-fired
power plant. However, the residuals can
be placed into two categories: primary
residuals are those associated with the
actual operation of the gaseous diffusion
plant; and secondary residuals are associ-
ated with the operation of the supporting
coal-fired plants that supply electricity
for the diffusion plants.
TABLE 6-10
SUMMARY OF ENVIRONMENTAL RESIDUALS
FOR URANIUM ENRICHMENT
(NORMALIZED TO MODEL LWR
ANNUAL FUEL REQUIREMENT)
Natural Resource Usea
Land (acres)
Temporarily committed
Undisturbed area
Disturbed area
Permanently committed
Water (millions of gallons)
Discharged to air
(at gaseous diffusion
plant)
Discharged to water
bodies (at gaseous
diffusion plant)
Discharged to water
bodies (at power plants)
Effluents
Chemicals (metric tons)
Gases (from coal-fired
power plants) ,
Sulfur oxides ^
Nitrogen oxides
Hydrocarbons" ,
Carbon monoxide
p—
Particulates
Liquids (from gaseous
diffusion plant)
Ca++
ci-
Na+
SO 3
Fe
NO 3
Radiological (curies)
Gases
Uranium
Liquids
Uranium
Thermal (1012 Btu's)
(from coal-fired power plants
and gaseous diffusion plants) ^
Quantity
0.8
0.6
0.2
0.0
84
6
11,000
4,300
1,130
11
28
0.5
1,130
5.4
8.2
8.2
5.4
0.4
2.7
0.002
0.02
3,200
6-23
-------
Source: AEC, 1974c: D-2, D-3.
aBased on 20-year life of gaseous diffusion
plant.
Estimated effluent gases based on combus-
tion of equivalent coal for power genera-
tion, assuming 100-percent load factor.
°Based on four-percent isotopic enrichment.
Approximately 67 percent of this heat is
discharged by the electric generating plants
servicing the model enrichment plant, assum-
ing 100-percent load factor coal-fired plant.
The primary residuals consist of dis-
charged water, a small amount of elemental
liquid effluents, and a small amount of
radioactivity. About one-third of the
total waste heat is at the enrichment
plant, which requires that approximately
84 million gallons of water be discharged
to the atmosphere from the cooling towers
and another six million gallons be returned
to its source. All the liquid effluents
listed in Table 6-10 were emitted at con-
centrations less than current standards.
The radioactivity emissions are small, and
no significant increase in the natural back-
ground radiation levels near the diffusion
plants is expected (AEC, 1974c: D-5).
Secondary residuals are greater than
primary residuals. About 11 billion gallons
of water are needed for once-through cooling
at the coal-fired plants that supply the
electricity to the diffusion plant. The
gaseous chemical effluents are combustion
products from the coal. The coal plants also
12
dissipate 2.1x10 Btu's of heat to the en-
vironment .
6.2.5.3.3.2 Major Accidents
The AEC has considered the possibilities
and impacts of enrichment plant accidents
such as fires, explosions, and a nuclear
criticality incident (AEC, 1974c: D-6). The
conclusions were that while fires and explo-
sions could release gaseous and liquid chem-
icals to the environment, plant design would
limit the quantities that could be involved
in one accident. As far as nuclear criti-
cality, the AEC concluded that (1974c: D-6)
a criticality incident in the low-enrich-
ment portions of a diffusion plant is highly
improbable and that handling U-235 concen-
trations above 1.0 percent requires special
safety criteria. In the event of a highly
improbable nuclear incident, most of the
materials, if releases occurred, would be
contained in the equipment or the building
with only minor contamination and clean-up
required beyond the section where the inci-
dent occurred.
6.2.5.3.4 Economic Considerations
The cost of enrichment is reported as
, 0.8 mill per kwh, compared to a total fuel
cost of 1.93 mills per kwh and a total gen-
eration cost of 9.0 to 11.0 mills per kwh.
Thus, enrichment is a relatively large por-
tion (41 percent) of the nuclear fuel cost
but represents only about eight percent of
the total generation cost.
However, the price for enrichment work
has increased from $32 per separative work
unit to $39.80 as of July 1974. But the
government increased the rate to about $48.00
as of December 1974, and private industry
proposed enrichment facilities will probably
charge at least $74 per separative work unit
when operative (Nuclear Hews. 1974: 65) . If
the rate increased to $74, the total gener-
ation cost would increase from 11.00 to 11.66
mills per kwh or a six-percent increase.
6.2.5.4 Fuel Fabrication
The fuel fabrication step converts the
enriched UF, into UO pellets and then en-
cases them in long metal tubes known as
A separative work unit is a measure
of the effort expended in the enrichment
plant to separate a quantity of uranium
into enriched and depleted components.
6-24
-------
cladding. From 50 to 200 of the cladding
tubes are positioned in a grid to form a
fuel assembly. Several of these fuel
assemblies are shipped to an LWR each year.
Ten plants are licensed by the AEC to
perform all or part of the necessary steps
of converting the UF, to the UO. assemblies.
Three plants perform the complete process,
four produce only the UO_, and the remainder
produce assemblies from the UOu.
6.2.5.4.1 Technologies
The production of the fuel assemblies
requires a substantial number of chemical
and mechanical processes, the basic tech-
niques of which are the same for all U.S.
plants. The process of fuel fabrication can
be subdivided into: the chemical conversion
of UFg to UO_; mechanical processing, in-
cluding pellet and fuel element fabrication;
and processing of all the scrap. Figure
6-8 is a flow diagram of the complete fuel
fabrication process.
6
6.2.5.4.1.1 Chemical Conversion of UF
to U02
The currently dominant method for UF-
to UO_ conversion is a wet process that
involves an intermediate ammonium diuranate
(ADU) compound and is thus termed the ADU
process. The six steps in the ADU process
are:
1. The UFg is received as a frozen
solid in a high-pressure cylinder
and is heated to change it to a
gas.
2. The gaseous UFg reacts with water
to form UO2F2-
3. Ammonium hydroxide is used to con-
vert the UO2F2 into ADU.
4. The ADU slurry is concentrated by
centrifuging or filtering.
5. The ADU is converted to U^Og by
heating (calcined).
6. The U3Os is heated in a hydrogen
atmosphere to form.UOo (AEC, 1974c:
E-9) .
6.2.5.4.1.2 Mechanical Operations
The purpose of mechanical processing
is to produce U0_ pellets (approximately
one-half inch in diameter and one inch in
length) and to insert these pellets into
the cladding. The seven steps in the pro-
cess are:
1. The UO2 powder is ground to reduce
the particle size.
2. The powder is pressed into pellets.
3. The pellets are baked, known as
sintering, in a furnace.
4. The hard pellets are ground to the
needed dimensions (the accuracy
needed is typically +0.0005 inch.
5. The pellets are cleaned (washed
and dried).
6. The pellets are loaded in the
cladding and the ends of the tubes
are sealed.
7. The tubes are used to form a fuel
assembly (AEC, 1974c: E-9) .
6.2.5.4.1.3 Scrap Processing
The purpose of scrap processing is to
recover the uranium left in any of the scrap
material; the uranium is quite valuable at
this point because it has undergone a large
number of processing steps. The scrap pro-
cessing cycle involves three basic steps
(not shown in Figure 6-8):
1. The scrap is dissolved in nitric
acid, which produces uranyl nitrate.
2. A solvent extraction process is
used to recover the uranium from
the nitric acid solution.
3. The uranium is converted into a
suitable form for return to the
UO2 production phase.
6.2.5.4.2 Energy Efficiencies
To fabricate the annual fuel require-
ment for a model 1,000-Mwe LWR requires
1,700 Mwh of electricity and 3.6xl09 Btu's
of heat energy from natural gas (assuming a
heat content for gas of 1,000 Btu's per cf)
(AEC, 1974c: E-2). Since the annual output
from the model LWR would be approximately
6-25
-------
CONVERSION
MECHANICAL
HEAT
H
"2
U
HEAT
t
/
NH4OH
WATER
HEAT
REDUC
3°8 ]
TION
1
CALCINATION
FILTER
XDU ]
t
PRECIPITATION
J
I
HYDROLYSIS
1
VAPORIZATION
uu
ATMOSPHERE
(
DFF GASES
ALL
CONVERSION
STEPS
^
HN°3 y
SOLVENT
FILT
1
ETD
tr<
I
SCRUB
i
SCRAP
RECYCLE
!
LIQUID
i
WASTE
TREATMENT
ASSEMBLY
H
TREATMENT
•\
OFF GASES
* MECHANICAL
STEPS
SCRAP
FROM
ALL STEPS
^
-ifc RE LEASE
t
PELLETIZE
1
-
SINTER
\
GRI
•\
ND
r
WASH a
DRY
Dfl
KVJ
\
IDS
T
FUEL TO REACTOR
Figure 6-8. Fuel Fabrication--ADU Process
Source: AEC, 1974c: E-10.
HEAT
-------
7,008,000 Mwh (or 23xl012 Btu's electric),
the ancillary energy requirement for fuel
fabrication is relatively small.
The primary efficiency loss would be
equivalent to the percent of uranium lost
in the fuel fabrication process. No data
on these losses are available, but pre-
sumably they are quite small.
6.2.5.4.3 Environmental Considerations
6.2.5.4.3.1 Chronic
Table 6-11 lists the chronic residuals
for a fuel fabrication plant, normalized
to the annual fuel requirements for a model
1,000-Mwe LWR (AEC, 1974c: E-2). Again,
these data include the emissions at the
electric power plant (secondary residuals).
The main residuals are associated with
the chemical processing steps; that is, the
conversion to UC>2 and the scrap recovery.
The mechanical processing produces few
residuals. The important primary residuals
(those associated directly with the fuel
fabrication plant) are the 10 metric tons
of ammonia and 23 metric tons of NO., emitted
into waste holding ponds. These two emissions
are generated when the ammonium hydroxide
and nitric acid are used in the processing.
The significant primary gaseous residuals
are fluorides; approximately 0.0055 ton of
fluorides is emitted each year. A radio-
active residual is thorium-234 (Th-234);
however, the small amount released would
present no known health hazards (AEC, 1974c:
E-4).
• The most important secondary residuals
are the SO , NO , hydrocarbons, and CO from
X X
the fossil-fueled plants that supply the
^electricity from the fabrication plants.
6.2.5.4.3.2 Accidents
A variety of accidents can be postu-
,lated (and have occurred) in the fabrication
plants. However, experience has shown that
the impact of these minor accidents is
TABLE 6-11
SUMMARY OF ENVIRONMENTAL RESIDUALS
FOR FUEL FABRICATION
(NORMALIZED TO 1,000-Mwe LWR
ANNUAL FUEL REQUIREMENT)
Natural Resource Use
Land (acres)
Temporarily committed
Undisturbed area
Disturbed area
Permanently committed
Water (millions of gallons)
Discharged to water
Effluents
Chemical (metric tons)
Gases
Sulfur oxidesa
Nitrogen oxides3
Hydrocarbons3
Carbon monoxide3
F~
Liquids
N as NH3
N as NO3
Fluoride
Solids
CaF2
Radiological (curies)
Gases
Uranium
Liquids
Uranium
Thorium-234
Solids (buried)
Uranium
Thermal (billions of Btu's)
Quantity
0.2
0.16
0.04
0
5.2
23
6
0.06
0.15
0.005
8.4
5.3
4.1
26
0.0002
0.02
0.01
0.23
9
Source: AEC, 1974c: E-2.
Affluent gases from combustion of coal for
power supply.
confined to the plant. The postulated acci-
dents that could have significant off-site
effects are rupture of a hot UF, cylinder,
a criticality accident, and a furnace ex-
plosion. The AEC has analyzed these acci-
dent possibilities and, in essence, con-
cluded they have a very low probability of
6-27
-------
occurring and would have very little effect
if they did (AEC, 1974C: E-4 and E-5) .
6.2.5.4.4 Economic Considerations
The cost of fabricating the fuel assem-
blies was estimated in 1972 to be approxi-
mately $70 per kilogram of contained ura-
nium. This cost represents approximately
0.4 mill per kwh, about 20 percent of the
total fuel processing costs of 1.93 mills
per kwh or only four percent of the total
power generation costs of 9.0 to 11.0 mills
per kwh (NPC, 1973: 28) .
6.2.6 Light Water Reactors
6.2.6.1 Technologies
A nuclear-electric power plant is sim-
ilar in nature to the fossil-fueled power
plants described in Chapter 12 except that
the nuclear steam supply system replaces
the conventional fuel boiler and the nuclear
fuel core replaces the fossil fuel supply.
In LWR's, the heat energy comes basically
from the fissioning of U-235 atoms, with
a small contribution from the fissioning
of U-238 atoms. However, as the reactor
operates, a fissile atom (Pu-239) is pro-
duced from U-238. For each gram of U-235
consumed in LWR fuel, as much as 0.6 gram
is formed. Generally more than half of the
plutonium formed undergoes fission in the
core, thus contributing significantly to
the energy produced in the power plant (AEC,
1974d: Vol. IV, p. A.1.1-2). LWR's typical-
ly employ partial refueling annually, with
somewhere between one-fourth and one-third
of the fuel assemblies being removed and
replaced with fresh fuel each year. Spent
fuel assemblies are stored underwater at the
power plant for a period of five to six
months to allow their radioactivity level
to decrease prior to shipment to a fuel re-
processing plant (AEC, 1974d: Vol. IV, p.
A.1.1-15). Since the historical origin of
nuclear power is from nuclear weapons, it
• is important to point out that a nuclear
reacto'r cannot explode like a bomb. A dif-
ferent type of fuel and different fuel con-
figuration are used in a reactor.
There are currently two different types
of U.S. LWR's: the boiling water reactor
(BWR) manufactured by General Electric and
the pressurized water reactor (PWR) manufac-
tured by Babcock and Wilcox, Combustion
Engineering, and Westinghouse.
6.2.6.1.1 Boiling Water Reactors
Figure 6-9 is a simplified schematic
of a boiling water reactor. In this type
of reactor, water is pumped in a closed
cycle from the condenser to the nuclear
reactor. In the reactor core, heat generat-
ed by the fissioning uranium pellets is
transferred through the metal cladding to
the water flowing around the fuel assemblies.
The water boils and a mixture of steam and
water flows out the top of the core and
through steam separators in the top of the
pressure vessel. The separators clean and
"dry" the steam before it is piped to the
turbine-generator(s). The turbine exhaust
is condensed and returned to the reactor
pressure vessel to complete the cycle. (See
Chapter 12 for a more complete description
of steam power plants).
Because the energy supplied to the water
from the hot fuel is transported directly
(as steam) to the turbine, the BWR system
is termed a "direct cycle" system The pres-
sure in a typical BWR is maintained at about
1,000 pounds per square inch (psi) , with a
steam temperature of 545°F (AEC, 1974d: Vol.
IV, p. A.1.1-18). Neutron-absorbing control
rods, operated by hydraulic drives located
below the vessel, are used to control the
rate of the fission chain reaction (and thus
the heat output) .
One major concern with light water
reactors is an accidental depressurization
or coolant loss (e.g., resulting from a high-
pressure steam pipe rupture) . If no safety
measures were in effect, such events would
cause the core to overheat and melt, and
6-28
-------
Boiling water reactor (BWR)
containment
structure
IBWWWMWVVWVVWWVWWWWVVVVVV
fggagwgggMgggeggg^
j^M&sss^ssssg
turbine
generator
condenser
cooling
water
Figure 6-9. Boiling Water Reactor
Source: Atomic Industrial Forum, Incorporated.
-------
large amounts of high-level radioactivity
might be released to the environment. To
prevent such catastrophes, reactor systems
include emergency core cooling systems
(ECCS's) to prevent meltdowns and contain-
ment systems for preventing the release of
radioactivity in the event of any type of
accident.
Although provisions differ from plant
to plant, all BWR's have multiple provi-
sions for cooling the core fuel in an
emergency. Typical ECCS's involve either
a high-pressure core spray system (early
BWR's) or both core sprays and a high-pres-
sure coolant-injection system (latest BWR's)
to assure adequate cooling of the core in
the event of reactor system depressurization
(AEC, 1974d: Vol. IV, pp. A.1.1-20).
To prevent such accidents from releas-
ing radioactivity and other pollutants to
the environment, BWR designs generally pro-
vide both "primary" and "secondary" contain-
ment. The primary containment system, shown
in Figure 6-9 as the "containment structure,"
is a steel pressure vessel surrounded by re-
inforced concrete and designed to withstand
the peak transient pressures that might occur
in the most severe of the postulated loss-
of-coolant accidents. The primary contain-
ment system employs a "drywell," which en-
closes the entire reactor vessel and its
recirculation pumps and piping. The drywell
is connected to a lower-level, pressure sup-
pression chamber in which a large pool of
water is stored. In the event of an acci-
dent, valves in the main steam lines from
the reactor to the turbine-generators (the
"isolation valves" in Figure 6-9) would
close automatically and any steam escaping
from the reactor system would be released
into the drywell. The resulting increase
in drywell pressure would force the air-
steam mixture in the drywell down into and
through the large pool of water where the
steam would be completely condensed, there-
by preventing any large pressure buildup.
This pressure injection pool also serves
as a potential source of water for the
emergency core spraying system (AEC, 1974d:
Vol. IV, p. A.1.1-21).
The "secondary" containment system is
the building that houses the reactor and
its primary containment system (not shown
in Figure 6-9). Reactor buildings are con-
structed of poured-in-place, reinforced con-
crete and have sealed joints and interlocked
double-door entries. Under accident condi-
tions, the normal building ventilation sys-
tem would shutdown, and the building would
be exhaust-ventilated by two parallel stand-
by systems. These ventilating systems in-
corporate effluent gas treatment devices,
including high—efficiency particulate
cleaners and solid absorbents for trapping
radioactive halogens (particularly iodine)
that might have leaked from the primary
containment system (AEC, 1973: 1-24).
6.2.6.1.2 Pressurized Water Reactors
Figure 6-10 is a simplified schematic
of a pressurized water reactor. The pri-
mary difference between a PWR and a BWR
is that all PWR's employ a dual coolant
system for transferring energy from the
reactor systems. In the dual coolant sys-
tem, the primary loop is water that is
pumped through the core and the heat ex-
changer. The secondary loop is water that
is pumped through the heat exchanger and
the turbine. ^The water is heated to about
600°F by the nuclear core in the pressure
vessel,but pressure is sufficiently high
(about 2,250 psi) to prevent boiling. The
high-pressure water is piped out of the
reactor vessel into usually two or more
"steam generators" that form a basic heat
exchanger. The primary heat is transferred
to the secondary stream. The secondary
stream boils, providing steam for the tur-
bine. The secondary stream is then con-
densed and the water is pumped back to the
6-30
-------
Pressurized water reactor (PWR)
containment structure
turbine
generator
condenser
cooling
water
Figure 6-10. Pressurized Water Reactor
Source: Atomic Industrial Forum, Incorporated.
-------
steam generator to begin the cycle over. No
steam is generated in the primary loop and
the water is returned to the core from the
steam generator to start the primary cycle
over. As in BWR's, the nuclear chain re-
action is controlled through the use of
neutron-absorbing rods; however, in PWR's,
additional control can be obtained through
the dissolution of such variable-concen-
tration neutron-absorbing chemicals as boron
(which may also serve other purposes) in the
primary system coolant.
The PWR ECCS's consist of several in-
dependent subsystems, each characterized
by redundancy of equipment and flow path.
Although the arrangements and designs of
PWR ECCS's vary from plant to plant (de-
pending on the vendor of the steam supply
system), all modern PWR plants employ both
accumulator injection systems and pump
injection systems. Accumulator injection
systems are called passive systems because
they operate automatically without acti-
vation of pumps, motor driven valves, or
other equipment. The systems consist of
pressurized tanks of cool borated water
which are connected through check valves
to the reactor vessel. Should the primary
coolant system lose pressure, the check
valves would open and a large volume of
water would be rapidly discharged into the
reactor vessel and core. Two pump injection
(active) systems are also incorporated in
PWR ECCS's. One is a low-pressure system
to provide coolant after the above mentioned
accumulator tanks are empty, and the other
is a high-pressure system designed to func-
tion if the break is small and the primary
coolant pressure remains too high to acti-
vate the passive systems (AEC, 1973: 1-14).
The containment structure for PWR's
is of reinforced concrete with a steel liner
and is stressed to withstand the maximum
expected temperature and pressure if all the
water in the primary system was expelled into
the containment. However, containment sys-
tem designs vary widely from plant to plant.
For example, in some plants, the contain-
ment space is kept slightly below atmo-
spheric pressure so that leakage through
the containment walls would, at most times,
be inward from the surroundings. Other
systems have double barriers against escape
of material from the containment space. In
addition, to condense the steam resulting
from a major break of the primary system,
either cold-water sprays or stored ice is
provided (AEC, 1973: 1-17).
6.2.6.2 Energy Efficiencies
The overall energy efficiency for the
power plant is the ratio of electric energy
output to total heat energy produced. LWR's
(both BWR's and PWR's) have energy efficien-
cies around 32 percent, as compared to 38
to 40 percent for modern fossil-fueled plants
(see Chapter 12) . The reason for this lower
efficiency is that LWR plants can only oper-
ate at a maximum steam temperature of around
600 F while fossil plants can operate at
1,000°F or higher.
6.2.6.3 Environmental Considerations
6.2.6.3.1 Chronic Residuals
The main residuals from LWR's are waste
heat and radioactive emissions. For a 1,000-
Mwe plant operating at a 75-percent load
factor, a 32-percent efficient nuclear plant
12
would emit 47.6x10 Btu's of waste heat
annually. For comparison, a 38-percent
efficient fossil plant would emit 36.5x10
Btu's of waste heat. For a description of
the cooling mechanisms and water required
to dissipate this waste heat, see the sec-
tion on cooling in Chapter 12.
Table 6-12 gives the annual chronic
radioactive emissions for both types of
LWR's. These data are based on a 1,000-Mwe
plant operating at a 100-percent load factor.
The PWR emits a larger quantity of
tritium (the heaviest hydrogen isotope which
is radioactive) than does the BWR. The
tritium is created as a direct product of
6-3?
-------
TABLE 6-12
ANNUAL RADIOACTIVE EMISSIONS
FOR A 1,000-Mwe LWRa
Radioactive Gas
Tritium (H )
Iodine (I131)
Noble gases (Kr+Xe)
BWRb
(curies)
10
0.3
50,000
PWRC
(curies)
50
0.8
7,000
Source: Teknekron, 1973: Figure 2.1.
Based on 32-percent thermal efficiency,
8.8xl09 kwh produced.
Boiling water reactor.
^
Pressurized water reactor.
some fission events in both types of reactors
and may then diffuse out of the fuel rods
into the coolant water. In addition, tritium
is also formed from the boron used in the
coolant water of the PWR. Noble gases (i.e.,
inert gases, primarily krypton and xenon)
are fission fragments. These too can diffuse
out of the fuel rods into the coolant water.
The radioactive gases may leak out of the
coolant water or are removed from the coolant
water during the coolant purification oper-
ation. If trapped in the purification oper-
ation, the gases are held in tanks to allow
decay to reduce the radioactivity level.
The radioactivity emission from noble gases
is higher for BWR's because the gas is held
a much shorter time than for PWR's (AEC,
1974d: A.1.1-35). All emission levels are
below AEC standards and have no known adverse
health effects.
6.2.6.3.2 Major Accident
As mentioned in Section 6.2.6.1, the
history of nuclear power is interwined with
the image of nuclear weapons. A nuclear
reactor cannot explode like a bomb because
different fuels and fuel configurations are
used in a reactor. However, a reactor can
experience a core meltdown if the primary
coolant is lost. To prevent such a melt-
down, the reactors (BWR's and PWR's) are
equipped with ECCS's described in Sections
6.2.6.1.1 and 6.2.6.1.2. The possibility
exists that the ECCS may not function and
the core would melt.
In a recent reactor safety study,
estimates were made of the frequency of
core meltdowns and the danger to the public
(AEC, 1974h: 18). The risk of a public
fatality per year from 100 nuclear plants
(1,000-Mwe) is one chance in 300,000,000.
This compares to one chance in 4,000 of a
fatality from a motor vehicle accident.
The probability of a core meltdown is one
chance in 17,000 per reactor per year. This
means that an operating reactor is likely
to have one core meltdown every 17,000 years.
Of the core melt accidents, only 1 in 10
might produce measurable health effects.
6.2.6.4 Economic Considerations
The economics of the two types of LWR's
are very similar and thus no distinction is
made between BWR's and PWR's. Table 6-13
gives an estimate for electric power costs
in 1980 from LWR's (1980 dollars). For
comparison, average U.S. electric power
costs from all sources in 1980 are expected
to be near 12 mills per kwh. Obviously, the
plant capital costs constitute the majority
of nuclear electric generation costs and
dictate that the plants be used as base load
units. However, fuel accounts for only 18
percent of nuclear generation costs, whereas
in 1968 fuel accounted for 32 percent of
fossil-fuel generation costs (see Chapter
12).
The capital costs for an LWR have been
projected as between $411 and $472 (1974
dollars) per kw installed capacity for a
plant to begin operation in 1981 (Nuclear
News Buyers Guide. 1974: 23) . For compari-
son, this same source estimated the capital
6-33
-------
TABLE 6-13
ANTICIPATED 1980 ELECTRICITY
COSTS FOR LWR
Expense
Capital
Operation and
maintenance
Fuel
Abatement costs such
as land reclamation
TOTAL
Mills per kwh
(in 1980 dollars)
8.50
0.73
2.10
0.60
11.93
Source: AIF, 1974.
costs for a coal-fired plant at §386 to
$444 per kw and for an oil-fired plant at
$280 to $332 per kw.
6.2.7 Fuel Reprocessing
Instead of being discarded, used fuel
from LWR's is reprocessed to recover the
unused uranium and the created Pu-239.
Reprocessing enables use of the recovered
fuel to partially allay the need for mining
and processing new fuel. At present, the
plutonium is being stored, with the
expectation that it will be used for LWR
fuel or for liquid metal fast breeder
reactors in the future. The reprocessing
step is unique to nuclear power production;
fossil fuel forms (such as coal, oil, gas,
etc.) are discarded when oxidation is com-
plete.
Although three nuclear fuel reproces-
sing plants are either being constructed or
modified, none are presently operating.
One plant, operational since 1966, is shut
down for modifications. A second plant was
expected to begin operation in 1974, but
economic and operational problems have
caused the company to undertake the study
to consider how (or even whether) to attempt
to overcome these problems (Nuclear News,
1974: 65). The third plant is under con-
struction and is scheduled to begin oper-
ation in late 1976. As a result, the fast
approaching glut of irradiated fuel has
caused some concern in the industry. When
these plants are operational, they will have
a combined capacity of 2,700 metric tons of
fuel per year. Since each 1,000-Mwe LWR re-
quires that 33 tons of fuel be reprocessed
each year, the combined capacity should be
sufficient until the later 1970's.
6.2.7.1 Technologies
The three plants will all use the same
process, with some slight variations. The
used fuel elements are stored under water
for 150 days before processing begins to
allow the radioactivity levels to decrease,
then a mechanical cutter chops the elements
into short pieces, and the resulting pieces
are put in a nitric acid bath which reacts
with the fuel and leaves the metal tubing
behind. The acid solution is then altered
chemically so that a solvent extraction
process can be used. The solvent extraction
recovers the plutonium and uranium. The
uranium is converted to UF,. and returned to
o
the enrichment plant. As stated earlier,
the plutonium is presently being stored
(AEC, 1974c: F-10).
6.2.7.2 Energy Efficiencies
The ancillary energy requirement to
reprocess the annual fuel requirement for
the model 1,000-Mwe reactor is 450 Mwh,
which is quite small compared to the total
power output from this reactor. Essentially
all the unused U-235 and created Pu-239 is
recovered in the fuel reprocessing step;
therefore, the primary efficiency is approx-
imately 100 percent.
6.2.7.3 Environmental Considerations
6.2.7.3.1 Chronic
Table 6-14 lists the residuals asso-
ciated with reprocessing. The items listed
include both the primary and secondary re-
siduals emitted during reprocessing; high-
level wastes that are moved to the burial
6-34
-------
TABLE 6-14
SUMMARY OF ENVIRONMENTAL RESIDUALS
FOR IRRADIATED FUEL REPROCESSING
(NORMALIZED TO 1,000-Mwe LWR
ANNUAL FUEL REQUIREMENT)
Natural Resource Use
Land (acres)
Temporarily committed
Undisturbed area
Disturbed area
Permanently committed
Water (millions of gallons)
Discharged to air
Discharged to water
TOTAL
Effluents
Chemical
Gases (metric tons)
Sulfur oxides3
Nitrogen oxides^
Hydrocarbonsa
Carbon monoxide3
F~
Liguids
Na+
Cl~
so?
NOJ (as N)
Radiological (curies)
Gases (including entrained
matter)
Tritium (thousands)
Krypton-85 (thousands)
Iodine-129
Iodine-131
Fission products
Transuranics
Liquids
Tritium (thousands)
Ru-106
Cs-137
Sr-90
Thermal (billions of Btu's)
Quantity
3.9
3.7
0.2
0.03
4.0
6.0
10.0
6.2
7.1
0.02
0.04
0.11
5.3
0.2
0.4
0.2
16.7
350
2.4x10-3
2.4xlO~2
1.0
4xlO-3
2.5
0.15
0.075
0.004
61
Source: AEC, 1974c: F-3.
estimated effluent gases from combustion of
equivalent coal for power generation.
23 percent of total is estimated effluent
gas from combustion of equivalent coal for
power generation.
site are not included. Obviously, repro-
cessing reduces the total residuals asso-
ciated with mining, milling, and conversion
to UFg because the recovered uranium re-
places uranium that otherwise must be sup-
plied by mining and processing uranium ore.
The quantity of released radioactive
effluents in this step is large in compari-
son with other steps in the LWR fuel cycle.
Reprocessing is a source of emitted tritium,
krypton-85 (Kr-85), iodine, fission products,
and transuranium elements. The estimates
in Table 6-14 assume that 100 percent of
the Kr-85 and 87 percent of the tritium
originally contained in the incoming fuel
elements are emitted to the environment.
The data are based on the operating experi-
ence of the Nuclear Fuel Services Plant near
Buffalo, New York. Air and land surveys
have indicated that emissions are a small
percentage of the maximum permissible con-
centrations as specified by the AEC (Shleien,
1970; Cochran and others, 1970).
Another residual is the casks of high-
level wastes. These wastes are initially
stored in the form of a liquid for a period
of up to five years. After being converted
to inert solids, the wastes are shipped to
a storage facility (see Section 6.2.8).
6.2.7.3.2 Major Accidents
The most significant accident would be
an accidental criticality of the used fuel.
Calculations have indicated that a person
at the site boundary could receive a dose
of 50 mrem to the thyroid, an important
organ indicating accumulation of radioactive
and stable iodine. Other accidents of lesser
importance could result in a dose of 10 mrem
to the bones of individuals at the site
boundary. It is interesting to note that
no accident has resulted in any significant
release of radioactivity in 25 years of op-
erating experience at commercial and govern-
ment reprocessing facilities using similar
processes (AEC, 1974c: F-5, F-6) .
6-35
-------
6.2.7.4 Economic Considerations
The reprocessing and shipping of fuel
to be reprocessed costs about $45 per kilo-
gram of uranium, or approximately 0.14 mill
per kwh (NPC. 1973: 14). This represents
only about 1.4 percent of the total power
generation costs. As the prices of raw ore,
milling, and conversion processing steps
increase, reprocessing will become even more
important. After subtracting the necessary
associated costs, the reclaimed U-235 and
plutonium have a net worth of about $1.75
million per model LWR per year.
6.2.8 Radioactive Waste Management
Radioactive waste management is another
unique and necessary process for nuclear
power generation. The purpose of the man-
agement program is to insure that nuclear
wastes do not enter the environment until
their radioactivity is below harmful levels.
Certain types of waste must be isolated
from the environment for thousands of years.
Radioactive waste management is concerned
with the manipulation and storage of all
radioactive materials produced in the nucle-
ar fuel cycle.
6.2.8.1 Technologies
Radioactive wastes are classified as
either "high-level" or "other than high-
level," the distinction being based on the
radioactive content of the waste. High-
level waste, which contains hundreds of
thousands of curies, is produced from the
reprocessing plant and contains the fission
products. Low-level waste consists of re-
siduals from UFfi production, fuel fabrica-
tion, reactor operation, and fuel reproces-
sing.
New regulations regarding high-level
liquid wastes require that the inventory at
the reprocessing plant be limited to the
amount processed in the prior five years
and that the waste be converted into a solid
form and be transferred to a federal reposi-
tory within 10 years of its separation from
1 the irradiated fuel. Until a long-term
storage facility is available, the govern-
ment will provide a retrievable surface
storage facility (RSSF) as a temporary
holding facility. Federal control over
this facility will be maintained as long
as waste is being stored in the facility.
The "other than high-level" wastes
are buried in shallow trenches, usually in
the containers in which they are shipped.
There is no intent to recover the waste
once they are buried. These wastes are
currently being buried at six commercial
sites (AEC, 1974c: G-l). The land is con-
trolled by the host state, which must main-
tain care and surveillance of the site if
the commercial operator defaults. In future
years, the burial site cannot be used for
any other purpose.
Proposals for dealing with radioactive
wastes consist of either using the wastes
or disposing of the wastes. Since high-level
radioactive wastes generate significant
amounts of heat, various means of using these
wastes as heat sources in remote locations
have been proposed. Some of the wastes are
used as sources of radioactive isotopes for
medical purposes. However, current and
future applications for these purposes will
not use sufficient material to alleviate the
waste disposal problem. A variety of dis-
posal methods have been proposed (Kubo and
Rose, 1973). Storage in salt vaults, further
chemical separation of the waste to reduce
the necessary surveillance time, near-sur-
face storage in mausoleum-type structures,
burial in antarctic rocks, and storage in
a large cavity beneath the reprocessing
plant are some of the proposals.
6.2.8.2 Energy Efficiencies
The ancillary energy requirement for
radioactive waste management cannot be
calculated because a long-term solution for
disposal of these wastes has not been found
6-36
-------
However, any energy used in radioactive
waste management represents an ancillary
energy and should be subtracted from the
reactor output to calculate actual net
energy.
6.2.8.3 Environmental Considerations
6.2.8.3.1 Chronic
The residuals of the actual operation
are small and negligible. To bury the re-
siduals (both high-level and other than high-
level) resulting from the various steps in
the fuel cycle requires approximately 0.2
acre per year per model 1,000-Mwe LWR (AEC,
1974c: G-2). Typical quantities of resid-
uals to be buried per 1,000-Mwe LWR per year
are 114 cf of fission products containing
18,300,000 curies and 72 cf of cladding
containing 167,000 curies. The total low-
level waste is approximately 14,000 cf per
model 1,000-Mwe LWR.
6.2.8.3.2 Major Accidents
Possible accident effects at other
than high-level waste burial facilities
would normally be confined to the immediate
area and would not release any significant
amounts of radioactivity to the environment.
The most severe accidents would involve
high-level radioactive wastes. Two types
of such accidents have been analyzed: a
handling accident and catastrophic failure
of the cooling system. The handling acci-
dent would result in a bone dose of 0.1 rem
per year at the site perimeter. The loss
of cooling could result in a meltdown of
the waste, but even if the cooling system
failed the waste would not begin to melt
within the first week. Because of the many
safety precautions and the long time period
for corrective action, a waste meltdown is
highly unlikely (AEC, 1974c: G-2, G-3) .
6.2.8.4 Economic Considerations
The economics of radioactive waste
management cannot be properly estimated at
at present. The dollar costs associated
with the burial of low-level waste at the
six commercial burial sites, and the extra
costs involved for containing and packaging
this waste at each step in the fuel cycle,
can probably be estimated, but no data are
available at this time. Also, the economics
of storing and securing high-level waste for
thousands of years cannot be estimated, es-
pecially since the RSSF has not yet been
built.
6.2.9 Transportation
In Figure 6-1, the solid arrows indicate
the necessary transportation steps in the
LWR system. Because of the unique radioac-
tive nature of the material being transported,
special regulations are necessary. These
regulations have three purposes: to protect
the general public and workers from radiation,
to insure no release of radiation in all types
of accidents, and to insure the security of
the material. Two agencies, the AEC and the
Department of Transportation (DOT), are re-
sponsible for writing the regulations and
setting standards. A recent memo of under-
standing between the two agencies has delin-
eated each agency's area of jurisdiction
(AEC, 1974e: 70). In this section, a general
description is given of the regulations con-
cerning the transport of radioactive materials
(both fissile and nonfissile). In addition,
a brief description of the specific transpor-
tation steps in the LWR system is presented.
6.2.9.1 Nuclear Material Transportation
Regulations
All radioactive materials must conform
to certain packaging requirements as outlined
in Table 6-15. There are two broad classes
of radioactive materials: "normal form," which
has seven classifications based on radiotoxi-
city of the material, and "special form." The
type of container required for each of these
material groups depends on the amount shipped,
as indicated in Table 6-15. For example,
Pu-239 can be shipped as "exempt" if it con-
tains less than 10 curies; it is shipped
6-37
-------
TABLE 6-15
CONTAINER REQUIREMENTS ACCORDING TO
QUANTITY OF RADIOACTIVE MATERIALS
Radioactive
Materials
Transport Group
B
o
fc.
H
g
I
II
III
IV
V
VI
VII
Special Form
Examples
Pu-239, Cm-242, Cf-252
Bi-210, Pi-210, Sr-90
Cs-137, Ir-192, Ir-131
As-76, C-14, Cr-45
Noble gases, Kr-85
Ar-37. Xe-133, Kr-85
uncompressed
Tritium - as a gas or
in luminous paint
Co-60 radiography
source, Pu-Be neutron
source
Exempt
Quantity
(less than
Curies)
ID'5
ID'4
ID'3
ID'3
io-3
_3
10 J
25
o
10 J
Type A
Container
(up to
Curies)
io-3
5xlO~2
3
20
20
1,000
1,000
20
Type Ba
Container
(up to
Curies)
20
20
200
200
5,000
50,000
50,000
5,000
Source: AEC, 1972: 12.
^ "Large Quantity" is defined as any quantity in excess of a Type B quantity.
in Type A containers if it contains less
than 10 curies; and it is shipped in Type
B containers if it contains less than 20
curies. Any Pu-239 in excess of 20 curies
would be designated as a "Large Quantity"
and is subjected to special requirements.
Exempt quantities can be shipped in strong
industrial packages and are exempt from
labeling regulations. The Postal Service
will ship exempt quantities if they are
packaged in leakproof containers. The
container standards for Type A packages
require that they prevent loss or dispersal
and retain shielding efficiency under "nor-
mal" transport conditions. However, Type
B containers must meet the following tests
in sequence without leakage:
1. A drop from 30 feet onto the con-
tainer's most vulnerable area.
2. A drop from four feet onto a six-
inch diameter spike.
3. Exposure to a fire of 1,475 F
for 30 minutes.
4. Immersion for 24 hours in three
feet of water.
"Large Quantities" (usually nuclear
fuel assemblies that contain millions of
curies) have special packaging and shipping
requirements, depending on the characteris-
tics of the specific fuel assembly.
In addition to the above general radio-
active materials packaging requirements,
certain quantities of fissile materials
(i.e., U-233, U-235, and plutonium) require
additional control to prevent accidental
criticality. Safety in transport is pro-
vided by the container design so that criti-
cality cannot occur under any conditions to
be encountered, including accidents. All
fissile material must be shipped in contain-
ers capable of meeting the accident test
conditions listed earlier for Type B con-
tainers .
6-38
-------
TABLE 6-16
SUMMARY FOR ENVIRONMENTAL RESIDUALS FOR FUEL CYCLE TRANSPORTATION STEPS
(NORMALIZED TO MODEL LWR ANNUAL FUEL REQUIREMENT)
Step - Material
T ransported
Mine to mill - ore
Mill to UF, production -
yellowcake
UFg production to enrichment -
natural UFg
Enrichment to UO2 enrichment -
enriched UF,
b
U02 Plant to fabrication -
enriched UO2
Low-level wastes to commercial
land burial sites
Solid wastes to federal storage -
fission products
TOTALS - public highway
and truck shipment
TOTALS - Truck shipments
Assumed Method
Truck - mostly private
land
Truck - public highway
and rail
Truck - public highway
and rail
Truck - public highway
and rail
Truck - public highway
Truck - public highway
Rail
Shipments
3,350
12
22
5
9
58
1
106
3,450
Travel
Miles
16,800
12,000
11,000
3,750
6,750
29,000
2,000
62,000
80,000
Source: AEC, 1974c: H-3.
6.2.9.2 Technologies
Table 6-16 lists the characteristics of
the transportation steps in the LWR fuel
cycle (excluding steps to and from the re-
actor) , and Table 6-17 lists the character-
istics of the transportation steps to and
from the reactor. The procedures involved
in these steps are:
1. Ore from Mine to Mill
Uranium ore is usually in the form
of low-level radioactive sandstone.
The mined ore is normally moved in
open trucks with capacities of up
to 30 tons. The economics of mov-
ing ore dictates that the transpor-
tation distances be short, typical-
ly five miles or less, and in gen-
eral do not involve public high-
ways.
2. Yellowcake from Mill to UF,.
Production
Yellowcake is low in radioactivity
and must be transported from mills
in the western U.S. to the two UFg
production sites. An average ship-
ment travels 1,000 miles. Yellow-
cake is transported in 55-gallon
steel drums, each containing about
0.42 ton of yellowcake, and each
truck can carry about 40 drums or
17 tons per load.
3. Natural UFg from Production to
Enrichment Plant
Natural UFg is shipped as a solid
from the UFg production center to
the enrichment facility. Natural
UFg is low in radioactivity and,
typically, one of two types of con-
tainers is used. One container is
6-39
-------
TABLE 6-17
CHARACTERISTICS OF SHIPMENTS TO AND FROM REACTOR
(NORMALIZED TO REQUIREMENTS TO TYPICAL 1,000-Mw REACTOR)
Qj
Oj
4J
W
Fuel
fabrication
to reactor
Reactor to
reprocessing
§
•rl
W
O
Q)
dt
EH
unirradiated
fuel
irradiated
fuel
C
o
•H
id
ti
iw O
o a
(0
•i? id
O M
truck
truck
rail
barge
&
•H <— *
0) M
* fi
o
•841
•P O
•ri ^j
4j l
6a
(18 initial)3
60a
10a
5a
tP—
C CO
•rl tt)
ft-rl
•H a
rC ^*^
t5 CO
0) 0)
JJ 0) U
9? 9
•H M 4J
4J -rl
K
i« (B
W U M^.
Con
•H (B 4J Q)
Ifl 4J O H
*J in (8 -H
0 -rl
-------
about 4 by 10 feet and carries 11
tons of UFg; the other container
is 4 by 12.5 feet with a capacity
of approximately 14 tons. The av-
erage shipment is by truck over a
distance of 500 miles.
4. Enriched UF6 from Enrichment to
U02 Plant
Enriched UF6 is a fissile material
and is shipped as a solid. The
shipping package consists of a
2.5-ton cylinder with a protective
outer covering. Each package will
hold about 2.2 tons of UF6. The
shipments are made by truck over
an average distance of 750 miles,
and each truck can carry a maximum
of five cylinders.
5. Enriched VO2 from the UC>2 Plant to
Fuel Fabrication
If the plant receiving the enriched
UF6 does not have the capability
to perform the complete operation
of producing the fuel assemblies,
this transportation step is neces-
sary. The enriched UO, is a fis-
sile material and is snipped as a
powder. The U(>2 is packaged in
55-gallon steel drums with each
container holding about 0.12 ton
of UO2- The shipments are made
by truck over an average distance
of 750 miles, and each truck car-
ries 40 drums or about 4.8 tons.
6. Fuel Assemblies from Fuel Fabri-
cation to Reactor
Approximately 30 metric tons of
new fuel must be supplied to an
LWR reach year. Because of nu-
clear criticality safety require-
ments, the new fuel arrives in six
separate truck shipments during
the year. The shipping container
is a long cylindrical device in
which the fuel assemblies are
cradled. The average transit dis-
tance is 1,000 miles (AEC, 1972:
22) .
7. Used Fuel from Reactor to Repro-
cessing Plant (AEC, 1972: 32;
Elliot and Weaver, 1972: 140).
Since the radioactivity and heat
levels of used fuels are much
higher than unused fuels, irra-
diated fuels require special ship-
ping containers to dissipate the
heat and to contain the radioactiv-
ity. As of December 1972, only '
one design had been approved for
transportation of future fuel
assemblies.
The shipment is made by either
truck or rail. The containers
are similar in their cylindrical
appearance, but the rail cask
weighs from 77 to 110 tons and a
truck cask weights a maximum of
39 tons. The weight of the irra-
diated fuel is only two to three
percent of total cask weight.
Approximately 30 metric tons of
used fuel must be transported from
each 1,000-Mwe reactor each year;
this amount of used fuel would re-
quire either 60 trucks or 10 rail
car shipments.
8. High-Level Radioactive Waste from
Reprocessing Plant to Disposal Site
The high-level waste consists of
the radioactive fission products.
These products will be solidified
and shipped to the RSSF when it is
completed. At present, the solid
wastes are accumulating at the re-
processing plant. The shipping
containers for these wastes will
resemble those used in transporting
irradiated fuel. Approximately 100
cf, the amount generated per model
1,000-Mwe LWR per year can be moved
in one shipment by rail an average
distance of about 2,000 miles (AEC,
1974c: H-13).
9. Low-Level Wastes to Commercial
Burial Sites
Low-level wastes are generated at
the UFg production plants, fuel
fabrication plants, and fuel re-
processing plants,and must then be
shipped to a commercial burial site.
The total waste per year per model
1,000-Mwe reactor is about 14,000
cf and requires about 58 truckloads,
shipped an average distance of 500
miles.
6.2.9.3 Energy Efficiencies
The primary efficiency for each of the
transportation steps should be 100 percent.
The ancillary energy is the fuel required
for the trucks or trains. No data are avail-
able on these energy requirements.
6.2.9.4 Environmental Considerations
6.2.9.4.1 Chronic
The two categories of chronic residuals
are the combustion emissions from the trucks
and trains, and the radioactive exposure.
The truck and rail traffic due to the
transportation of materials for the LWR
6-41
-------
system is so small, compared to total U.S.
transportation, that the impact of the ad-
ditional combustion residuals should be
negligible.
Under normal conditions, some radio-
active exposure will be received by hand-
lers, truck drivers, and onlookers. The
highest dose that might be received under
normal conditions is about 0.5 rem per year
(AEC, 1974c: H-4) as compared to a natural
background radiation dosage of 0.125 rem
per year. The AEC's facility regulations
specify a maximum worker dosage of 5 rems
per year.
6.2.9.4.2 Accidents
An accidental criticality could result
in significant amounts of radiation expo-
sure, but the AEC believes that such an
accident is not possible because of the
safety precautions that are undertaken
(AEC, 1974c: H-4). The only other type of
accident that would release significant
quantities of radioactivity to the environ-
ment would be one in which a high-level
waste container is breached. However,
considering the low probability of a serious
vehicle accident and the construction stan-
dards of the Type B containers, the AEC be-
lieves that the likelihood of a high-level
waste container being breached is small
(AEC, 1974c: H-22).
6.2.9.5 Economic Considerations
No separate data are available on the
cost of the various transportation steps
and their effect on total power generation
costs.
6.3 HIGH TEMPERATURE GAS REACTOR (HTGR)
SYSTEM
6.3.1 Introduction
The HTGR derives its name from the use
of helium (as opposed to water in a LWR)
as a coolant and heat transfer medium.
In addition>to this characteristic, the
HTGR differs from the LWR in efficiency
and fuel characteristics. The capacity to
heat helium to high temperatures at high
pressures allows the HTGR to achieve ef-
ficiencies of 40 percent. Its fuels are
Th-232, U-233, and U-235 which are formed
into microspheres and loaded in graphite
blocks.
A distinctive characteristic of cur-
rent HTGR development is its limited sup-
port by the federal government when com-
pared to support for the LWR or the LMFBR.
The development of the HTGR is mainly a
commercial venture by Gulf General Atomic.
Although the HTGR is commercially
available, only the 40-Mwe Peach Bottom
facility in Pennsylvania that began oper-
ation in 1966 is currently producing elec-
tricity. The 330-Mwe Fort St. Vrain facil-
ity in Colorado has received its operating
license and is expected to begin commercial
operation in late 1974 or early 1975. Ten
additional plants have been ordered (Nuclear
Task Force, 1974: 10), but the future role
of the HTGR is unclear. Projections of
HTGR growth made in 1969 indicated total
capacities of 23,000 Mwe by 1985, 54,000
Mwe by 1990, and 100,000 Mwe by 2000 (AEC,
19y4d: A.1.2-24). More recent estimates
are that the HTGR will not be a major pro-
ducer of electrical power until the year
2000 (Battelle, 1973: 470).
The resource system diagram for the
HTGR is given in Figure 6-11 and includes
seven major activities:
1. Exploration for both uranium and
thorium.
2. Mining of both uranium and thorium.
3. Processing of both uranium and
thorium.
4. Energy production in the reactor.
5. Fuel reprocessing.
6. Waste management.
7. Transportation.
6-42
-------
6.3.2
Thorium
Resources
6.3.3
Thorium
Exploration
Uranium
Exploration
6.2.2 '
Domestic
Uranium
Resources
6.3.4
Mining and
Reclamation
6.3.5.1
Thorium
Processing
6.2.4
6.2.5.1 6.2.5.15
Mining and
Reclamation
6.3.5.2
Fuel
Fabrication
Involves Transportation 6.3.9 Transportation Lines
Does Not Involve Transportation
6.3.6
HT6R
6.3.7-
Fuel
Reprocessing
e . 3 . e •,
Radioactive
Waste
Management
^electricity
Figure 6-11. High Temperature Gas Reactor Fuel Cycle
-------
As the flow diagram indicated the
reactor's three fuels come from different
sources, and the mix of fuels changes be-
tween the start-up period and regular op-
eration. A summary of these characteristics
is necessary to understanding the following
descriptions.
The initial fuel loading of the reactor
core will consist of U-235 and Th-232. In
the reactor, the Th-232 will be converted
into U-233. The used fuel will be repro-
cessed and the U-233 recovered and recycled
to be used as fuel in the HTGR. The annual
fuel requirements for a 1,000-Mwe HTGR are
13 tons of U3°o and about eight tons of
thorium dioxide (ThO2) (AEC, 1974d: A.1.2-15)
U-235 is obtained by using the same
fuel production steps, through enrichment, as
as described in the LWR section, the differ-
ence being that uranium for the HTGR must be
enriched to 95 percent versus three to four
percent for the LWR. Th-232 comes from nat-
ural sources that are described in Section
6.3.2. Also, mining and processing of thor-
ium are described. The production of U-233
is covered in Section 6.3.7. The three fuel
sources are then developed as HTGR fuel in a
specialized step that involves fuel micro-
sphere production and fuel fabrication as
indicated in Figure 6-11.
The following description of the HTGR
system is divided between thorium resources
and HTGR technologies. This description
will not repeat material covered in the LWR
description. Further, the limited experience
with commercial HTGR's is reflected in the
lack of available data on many of the activ-
ities.
6.3.2 Resource Base (Thorium)
Following is a description of domestic
and Canadian thorium resources. Thorium
by-products of Canadian uranium mining are
included because their low cost makes them
a major factor in the resource base for the
HTGR.
6.3.2.1 Characteristics of the Resource
Thorium, one of the basic elements,
is a heavy, silvery metal. Estimates of
the thorium content in the earth's crust
range from 5 to 13 parts per million (ppm)
(Brobst and Pratt, 1973: 471) with the
element being widely distributed in small
quantities. Thorium occurs naturally in
a variety of chemical forms, the most
common of which are ThPCK (the chemical
form found in monazite), ThO_, and thorite
(ThSi04).
Thorium is obtained from three main
sources: monazite, a mixture of rare metals
often found in sand or gravel deposits
(Brobst and Pratt, 1973: 471); as a by-pro-
duct of uranium mining; and from veins con-
taining thorite. Prior to 1953, monazite
was the major source of thorium (Brobst and
Pratt, 1973: 469); since 1953, uranium de-
posits containing commercial amounts of
thorium have been found in Malagasy and,
more importantly for the proposed U.S. HTGR
program, at Elliot Lake, Canada. These
locations are now the major sources of
thorium for the U.S.
6.3.2.2 Quantity of the Resources
Thorium resource quantities are not
well identified mainly because the demand
is small in relation to the available sup-
ply. Table 6-18 lists the identified
thorium resources for the U.S. and Canada.
The presently known resources are about
10,000 times greater than the amount used
in 1968 (Brobst and Pratt, 1973: 473). The
amount of thorium available in Canada as
a by-product of uranium will be sufficient
to fuel all of the HTGR's to be built in the
U.S. during the century, a projected capacity
Of 100,000 Mwe (AEC, 1974d: A.1.2-6). At
present, obtaining thorium from Canada is
considered to be less expensive than develop-
ing U.S. resources. If U.S. thorium resources
were developed and used for the HTGR's pro-
jected to be operating by the year 2000, the
6-44
-------
TABLE 6-18
U.S. AND CANADIAN THORIUM RESOURCES
Locality
U.S.:
Atlantic Coast
North and South Carolina
Idaho and Montana
Lemhi Pass District,
Idaho and Montana
Wet Mountains, Colorado
Powderhorn District,
Colorado
Mountain Pass District,
California
Mountain Pass District,
California
Palmer Area, Michigan
Bald Mountain, Wyoming
TOTAL U.S.
Canada:
Elliot Lake, Ontario
Type of Deposit
Beach placer
Fluviatile placer
Pluviatile placer
Veins
Veins
Veins
Veins
Carbonatite
Conglomerate
Conglomerate
Conglomerate
Thousands of Short Tons ThO2
Recoverable
Primarily as
By-Product
or Coproduct
16
NA
2
NA
NA
NA
NA
28
NA
NA
46
580
Recoverable Primarily
for ThO2 of grade —
Less Than
0.1 Percent
NA
NA
NA
100
4.5
1.5
0.5
NA
NA
NA
106.5
Greater Than
0 . 1 Percent
NA
56
38
NA
NA
NA
NA
NA
NA
2
142
HA - not applicable
Source: Brobst and Pratt, 1972: 474.
Includes some hypothetical resources, which are undiscovered mineral deposits, whether
of recoverable or subeconomic grade, that are geologically predictable as existing in
known districts.
3.2 million tons of reasonably assured ThO-
at $50 per pound would last for 400 years
(see Table 6-19) .
6.3.2.3 Location of the Resources
The major sources of U.S. thorium are
monazite-containing beach placers on the
Atlantic coast and thorite-containing vein
deposits in the Lemhi Pass, Idaho. The
only U.S. resources presently being mined
are the Atlantic coast beach placers, where
monazite is produced as a by-product of
titanium mining.
Approximately 16,000 tons of ThO- are
thought to be available in the Atlantic
coast beach placers and about 100,000 tons
may be present in the Lemhi Pass area.
Table 6-19 lists U.S. thorium reserves
(those resources economically recoverable
at present). Like uranium, thorium resources
are categorized according to amounts recover-
able at different per-pound costs.
6.3.3 Exploration
Thorium exploration has been minimal
because the amount of thorium available as
a by-product from titanium and uranium min-
ing has been sufficient to meet the small
demand (Brobst and Pratt, 1973: 475).
6-45
-------
TABLE 6-19
J*
U.S. THORIUM RESERVES
Cost
(dollars per
pound Th02)
10
30
50
Reserves
(thousands of tons)
Reasonably
Assured
65
200a
3,200a
Estimated
Additional
335
400a
7 , 400a
Total
400
600a
10,600a
Source: AEG, 1974d: A.1.2-6.
alncludes lower cost resources.
6.3.3.1 Technologies
Thorium exploration methods are simi-
lar to those used for uranium as described
in the exploration section of the LWR. In
general, exploration methods rely on the
radioactivity of thorium; also, more tra-
ditional methods are used for examination
and sampling.
6.3.3.2 Energy Efficiencies
Although existing data are insufficient
for ancillary energy calculations, these
values should be negligible compared to
ancillary energy requirements in other
portions of the HTGR fuel cycle. The pri-
mary energy efficiency is not applicable
for exploration.
6.3.3.3 Environmental Considerations
The residuals associated with explor-
ation should be similar to those described
in Chapter 1 or in the LWR description.
6.3.3.4 Economic Considerations
Specific economic data on thorium
exploration are not available; however,
the dollar costs should be similar to
uranium exploration.
6.3.4 Mining (Battelle, 1973: 467)
6.3.4.1 Technologies
Mining techniques for monazite deposits
and thorite veins differ. Since the water-
insoluble monazite accumulates with other
minerals on river bottoms and ocean beaches,
placer mining methods are normally used. In
essence, the material is simply gathered by
shovel, dragline, or dredge.
The extraction of thorite (as from the
Lemhi Pass veins) would be done by conven-
tional mining methods, either open pit or
underground, as described in Chapter 1.
6.3.4.2 Energy Efficiencies
Present information is insufficient to
calculate either the primary or ancillary
energy requirements for thorium mining. How-
ever, the ancillary energy use should be mini-
mal in comparison to ancillary energy used
at other points in the fuel cycle.
6.3.4.3 Environmental Considerations
The residuals associated with placer
mining are unknown. The conventional mining
techniques to be used on the Lemhi Pass veins
should produce residuals similar to those for
other minerals mined by these techniques.
6-46
-------
6.3.4.4 Economic Considerations
Costs for extracting and converting
ore into ThO_ are divided into cost-per-
pound categories as shown in Table 6-19.
These range from $10 to $50 per pound for
the ore presently classed as reserves.
As shown in Table 6-20, the mining
costs associated with a 1,000-Mwe HTGR are
$1.1x10 per year or 0.19 mill per kwh.
6.3.5 Processing
The processing of fuel for the HTGR
is characterized by three major steps.
First, thorium ore is processed to produce
a powder, ThO_. (This step is unnecessary
for ThO2 shipped from Canada.) Second,
raw uranium is processed in the manner des-
cribed in the LWR section to produce UO2-
(As mentioned earlier, HTGR uranium must be
95-percent enriched.) The third step, fuel
fabrication, makes the ThO2, enriched U-235,
and reprocessed U-233 into microspheres
and inserts the spheres into channels in
graphite blocks that measure 14 inches by
31 inches.
Uranium processing has been covered
in the LWR description. A discussion of
the thorium processing and fabrication
steps follows.
6.3.5.1 Processing of Thorium Ore to
Produce ThO_
Since the Canadian thorium is delivered
to the fabrication plant as ThO2, and the
Lemhi Pass thorite is unlikely to be ex-
ploited in the near future, only the des-
cription of monazite processing will be
presented.
6.3.5.1.1 Technologies
Processing monazite consists of two
main phases, separating the monazite from
its host material (primarily sand) and
producing the ThO2.
After the hos.t material has been mined
from placers or sand beaches, water is
added and the mixture is sieved. Because
monazite occurs in fine particles, it passes
through the larger screens which retain and
reject coarse material. The fine material
resulting from the sieve operation is approx-
imately 60-percent monazite (Yemel'vanov and
Yevstyukhin, 1969: 377). After drying, this
material is passed through a strong magnetic
field. The monazite collects on one pole of
the magnet in concentrations of 95 to 98 per-
cent (Yemel'vanov and Yevstyukhin, 1969: 377).
ThO2 production from the concentrated
monazite is normally done by a three-step
process. The initial step uses a hot caustic
to dissolve and strip away unwanted portions
of the monazite. The second step is a series
of chemical treatments that start by dissolv-
ing the thorium and other remaining materials
in acid. Through solvent extraction, the
thorium (in the form of thorium nitrate)
is then separated from other materials. The
final step involves milling the thorium
nitrate to produce ThO_ (Battelle, 1973: 468).
£i
6.3.5.1.2 Energy Efficiencies
Although a lack of data prevents energy
efficiency calculations for thorium ore pro-
cessing, the primary efficiency will be large
because only an estimated 0.1 percent of the
thorium is lost in the processing. The an-
cillary energy requirement should also be
small.
6.3.5.1.3 Environmental Considerations
6.3.5.1.3.1 Chronic
As shown in Table 6-21, the primary
radioactive elements to be discharged from
thorium milling are thorium, radium, and
uranium isotopes. Estimated 1990 emissions
vary from 3.0 to 2.3 curies per 1,000 Mwe.
All these estimated discharges will be
ejected into a settling pond. Additional
residual data for the combined milling-fabri-
cation step are given in Table 6-20.
The total land area needed for the milling
plant and the settling pond is not known.
6-47
-------
TABLE 6-20
ANNUAL EFFECTS OF A 1,000-Mwe HTOR AND ITS FUEL CYCLE
(BASED ON 75 PERCENT LOAD FACTOR)
Conventional Costs
106 dollars
1980 dollars
Fuel
Plant capital
Operating and
maintenance
Abatement cooling
towers
TOTAL COSTS
Occupational Accidents
Deaths
Non-fatal injuries
Man-days lost
Mining and Milling
Impacts
Strip mining of
uranium and mill
tailings (acres)
Tailings produced
at mill (103 metric
tons)
Public Accidents in
Transportation of
Nuclear Fuels
(excluding exposure
to radioactivity)
Deaths
Non-fatal injuries .
Man- days lost
Occupational Health
Miners ' radiation
exposure (miner-
WLM)
Other occupational
exposure (man-
radiation)
Mining
1.1 „
(.19)°
0.05
1.8
383
2.7
0
0
0
58
0
Milling
Fabrication
7'5 c
(1.26)°
0.003
0..75
47
1.2
43
0
0
0
0
15
Reactor
Power Plant
(-59)c
57
4.8
2.4
67.7
0.01
1.3
110
NA
0
0
0
0
300
Reprocessing .
Transportation
(.25)c
0.002
0.06
14
NA
0.009
0.08
60
0
12
Totals
15
(2.3)c
57
(8.9)c
4.8
(-7)C
2.4
(.4)c
79.4
(12.3)C
0.07
3.9
354
3.9
43
0.009
0.08
60
58
327
-------
TABLE 6-20 (Continued)
Solid Radioactive
Waste Disposal
Volume (102 cubic
feet)
Burial area (acres)
Effects at the
Power Plant
Thermal discharge
(1010 kilowatt
hour [thermal] )
Net destruction
of uranium
(metric tons)
Net destruction
of thorium
(metric tons )
Routine Radioactive
Releases to the
Atmosphere (curie)
H-3
Kr-85
1-129
1-131
Xe-131m
Xe-133
Cs-137
Rn-220
Rn-222
U-232
U-233
Total U
Others
Routine Radioactive
Releases to
Waterways (curies)
H-3
1-129
1-131
Cs-137
tf-232
U-233
Total U
Other
Mining
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Milling
Fabrication
31
0.06
0
0
0
0
0
0
0
0
0
0
23
23
0.4
0.2
0.7
0
0
0
0
0
9
4
14
0.1
Reactor
Power Plant
t
22
0.04
1.1
0.3
0.5
4
9
0
0
0
0
0
0
0
0
0
0
0
«
0
0
0
0
0
0
0
4
Reprocessing ,
Transportation
10
0.26
0
0
0
16,000
570,000
0.0003
3
0
0
0.002
0
0
0
0
0
0
350
0.0002
0.02
0.004
0
0
0
2
Totals
63
0.4
1.1
0.3
0.5
16 , 000
570,000
0.0003
3
0
0
0.002
23
23
0.4
0.2
0.7
2
350
0.0002
0.02
0.004
9
4
14
6
6-49
-------
TABLE 6-20 (Continued)
Population Exposure
from Routine Releases
of Radionuclides
Global model: All-time
commitment, long-lived
nuclides
World (whole body man-
radiation)
Kr-85
H-3
TOTAL WORLD
U.S. (whole body man-
radiation)
Kr-85
H-3
TOTAL U.S.
Local model: Airborne
short-lived noble gases
and tritium
Total man-rem within
50 miles
High population
assumption
Medium population
assumption
Low population
assumption
Mining
0
0
Milling
Fabrication
0
0
Reactor
Power Plant
0
0
Reprocessing ^
Transportation
256
21
12.0
2.3
Totals
256
21
277
12.0
2.3
14.3
48
4.8
0.69
Source: AEG. 1974d: A.1.2-32.
aMilling, conversion, enrichment, and preparation and fabrication.
Includes all transportation steps.
°Units are in mills per kilowatt hour.
"Vorking capital charges. ">
6.3.5.1.3.2 Major Accidents
A major accident associated with
thorium ore processing has not been anal-
yzed; however, the residuals should be
comparable to the residuals given in the
LWR uranium milling section.
6.3.5.1.4 Economic Considerations
Table 6-20 gives a combined cost of
milling and fabrication of $7.5 million
per year (1980 dollars) or approximately
1.26 mills per kwh for a 1,000-Mwe reactor.
6-50
-------
TABLE 6-21
SUMMARY OF THORIUM MILLING EMISSIONS
Airb
Land
Water
Radioisotope Discharge to Receptors
Total Curies of Th-232, Th-228,
Ra-228, U-238, and Ra-226 per
1,000-Mwe
197 5a
0
0
0
1980
0
3
0
1985
0
2.5
0
1990
0
2.3
0
Source: Modified from Battelle, 1973: 469.
^o residuals are included in 1975 because it was assumed
there would be no thorium milling for reactor use until
1980.
The actual distribution of the short-lived gas Ra-220
throughout the milling industry is not known, particularly
since the ore is mined in a pulverized state and is mechan-
ically concentrated at the mine site to chemical milling
procedures. Thus, the contribution of radon to the air re-
ceptor is not included in this study.
6.3.5.2 Fuel Element Fabrication
Fuel element fabrication will consist
of the following steps:
1. The fuel will be formed into two
types of microspheres.
2. The microspheres will be bound
into 0.5- by 1.5-inch pellets.
3. The pellets will be inserted into
the graphite blocks.
InHTGR's, the first fuel loading will con-
sist of U-235 and Th-232. For subsequent
loadings, the U-233 produced in the reactor
from the Th-232 and recovered in the repro-
cessing step (Section 6.3.7) will be used as
the nuclear fuel. At present, no large com-
mercial HTGR fuel fabrication plants are in
existence, but an HTGR refabrication pilot
plant has been proposed by the AEC (1974g) .
The plant would be built at Oak Ridge
National Laboratory and operated for two
years; its basic purpose would be the devel-
opment of fuel cycle technology.
6.3.5.2.1 Technologies
In the present HTGR fuel element fab-
rication process, the three input streams
are the U-235F,. from the enrichment plant,
the ThO_ from the mill, and the recycled
U-233 from the reprocessing plant. These
three materials will be formed into two
types of microspheres, one containing the
U-235 and the other containing a combination
of thorium and U-233. Fabrication of the
two types of spheres will be similar except
that the U-235 receives an extra coating
of carbon as shown in Figure 6-12.
To form the microspheres, fuel particles
will be dried and baked in an oven. The
particles will be then inspected, sorted,
and weighed to insure a uniform size for
each type (AEC, 1974b: 19). After accep-
tance, the particles will be sent to a fur-
nace to be coated with layers of graphite.
Following the coating, the microspheres
will again be checked for uniformity.
6-51
-------
HTGR FUEL COMPONENTS
TRISO(U-235)
BISO(Th-232 & U-233)
Scale:
FUEL PARTICLES
lOOx
FUEL ROD
FUEL
ELEMENT//7;f
Figure 6-12. HTGR Fuel Components
Source: AEC, 1974d: A.12-12.
-------
To form pellets, the two types of mi-
crospheres are blended together and poured
into molds with a carbonaceous "binder"
(a material that will hold the microspheres
together in the mold). After heating to
drive off any volatile materials, pellets
approximately 0.5 inch in diameter and 2.5
inches in length will be created (AEG, 1974f:
20) .
These pellets, labeled fuel rods in
Figure 6-12, are positioned in the holes of
the machined graphite blocks. Approximately
2,000 fuel rods are needed to fill a single
fuel element.
6.3.5.2.2 Energy Efficiencies
Since no commercial plants are presently
operating, the ancillary and primary energy
efficiencies cannot be calculated. However,
the primary energy efficiency should be quite
high; that is, approximately 99 percent.
6.3.5.2.3 Environmental Considerations
6.3.5.2.3.1 Chronic
The stack chemical effluents listed in
Table 6-22 are calculations for the HTGR
refabrication pilot plant for a daily oper-
ation of 25 kilograms of uranium and thorium
per day. The major chemical stack effluent
will be 53.0 metric tons per year of CO2-
The main solid chemical residual will
be sodium nitrate (NaNC- ) , and the largest
release of a solid radioactive residual will
be 13.0 curies per year of U-233. The gas-
eous radioactive effluents, U-233 and U-232,
will be released in small amounts (AEC,
1974g: 23) .
6.3.5.2.3.2 Major Accidents
An analysis of the pilot plant indicates
-that an inadvertent criticality, a fire, or
an explosion could result in the release of
radioactive material. However, shielding,
containment, and ventilating systems are
designed to contain the radioactive material
in the plant in case of accident (AEC, 1974g:
26) .
6.3.5.2.4 Economic Considerations
Table 6-20 lists a combined cost of
$7.5 million (1980 dollars) per year or
1.26 mills per kwh for milling and fabri-
cation to support a 1,000-Mwe HTGR plant.
6.3.6 High Temperature Gas Reactor
6.3.6.1 Technologies
A schematic of the high temperature
gas reactor is shown in Figure 6-13. The
heat created by the fissioning of U-235 and/
or U-233 is transferred to the helium, which
is circulated through the core, to a steam
generator, and back to the core. The pro-
duction of electricity from the steam is via
a turbine-generator as described in Chapter
12.
The other major pieces of equipment
shown in Figure 6-13 are the control rods
(which control the rate of fission), the
prestressed concrete reactor vessel (PCRV),
the steam generator, and the containment
structure. The PCRV is a unique feature of
the HTGR. All the major equipment, includ-
ing the primary coolant system, is contained
inside the PCRV. The PCRV eliminates the
worry over a primary pipe rupture that occurs
outside the reactor vessel, as associated
with an LWR. If a break occurs in one of
the helium pipes, the PCRV is designed to
contain the leaking gas.
The HTGR can achieve overall thermal
efficiencies of about 40 percent due to the
high temperature and pressure capabilities
of helium. In the Fort St. Vrain plant, the
helium will be heated to 1,430°F at 700
pounds per square inch atmosphere (psia)
(Gulf General Atomic, 1973: 6) . These hel-
ium conditions create steam at 1,005°F at
2,512 psia.
6-53
-------
High temperature gas-cooled reactor (HTGR)
containment structure
helium circulator
control I steam
rods1||
prestressed concrete reactor vessel
Figure 6-13. High Temperature Gas-Cooled Reactor
Source: Atomic Industrial Forum, Incorporated.
turbine
generator \
condenser
cooling
water
-------
TABLE 6-22
CHEMICAL STACK EFFLUENTS FROM HTGR FUEL REFABRICATION PILOT PLANT
(BASED ON 25 KILOGRAMS OF HEAVY METAL, U + Th, PER DAY)
Chemical
Hydrogen
Inert (Ar, He)
Carbon dioxide
Carbon monoxide
Nitrogen oxide
Surfactant
2-ethyl-l-hexanol
Annual Release
Rate (metric
tons per year)
1.8
25.0
53.0
2.7
0.124
0.0033
0.0033
Concentration ( u. g/m )
At Stack
Exit3
2.6xl03
3.6xl04
7.2xl04
3.6xl03
174
4.8
5.2
At Site
Boundary"
0.015
0.20
0.40
0.020
0.00001
0.000029
0.000029
Source: AEC, 1974g: Appendix A.
Just prior to leaving top of the stack on the basis of a stack flow rate of
60,000 standard cubic foot per minute.
-7
Based on dispersion factor ( -%/ Q) of 2x10 seconds per meter cubed.
6.3.6.2 Energy Efficiencies
The net plant efficiency of an HTGR
is about 40 percent.
6.3.6.3.1 Chronic
The primary chronic residuals, as
shown in Table 6-20, will be radioactive
emissions to the air and water, thermal
discharges, and low-level solid radio-
active wastes. The radioactive releases
of tritium and Kr-85 will be four and nine
curies respectively as compared to LWR re-
leases of 10 to 50 curies of tritium. The
total radioactive release to the water will
be four curies. The thermal discharge will
be 1.1x10 kwh (thermal). Approximately
2,200 cf of low-level solid radioactive
waste will require burial each year. The
total radiation dose to the general public
is expected to be indistinguishable from
the natural background radiation dose of
125 mrem per year.
6.3.6.3.2 Major Accidents
As described in the LWR section, the
loss of core coolant is a major accident.
Since the HTGR graphite core can absorb
The HTGR has a number of safety advan-
tages when compared to an LWR or an LMFBR
(AEC, 1974d: A.1.2-20). First, the loss
of the helium coolant is not a severe prob-
lem as compared to the loss of water coolant
in a LWR. The graphite core can absorb
large amounts of heat, and the temperature
change of the core will be slow. Second,
the PCRV adds to overall reactor safety,
as mentioned earlier. Third, the use of
small, coated fuel particles reduces the
amount of radioactive fission products re-
leased into the coolant. If a fuel rod
ruptures in an LWR or LMFBR, large quanti-
ties of radioactive material can be released
into the coolant; however, the rupture of
one coated particle in an HTGR would re-
sult in a far smaller release of radio-
activity.
The HTGR has one undesirable feature.
The use of graphite introduces the problem
of a possible steam-carbon reaction. If
large amounts of steam enter the core, the
reaction could result in structural damage
and the release of some fission products.
6-55
-------
much larger amounts of heat without melting
than can LWR cores, coolant loss accidents
should be much less severe in HTGR's than
in LWR's.
6.3.6.4 Economic Considerations
The capital costs of a 1,300-Mwe HTGR
introduced in 1985 are projected to be $419
per kwe (kilowatts-electric) . The annual
operating and maintenance costs are esti-
mated to be $12.7 million for the 1,300-Mwe
plant (AEC, 1974d: Appendix 11).
Table 6-20 lists the economics for
1,000-Mwe plant in 1980 dollars. Of the
total reactor plant annual costs of about
$68 million, five percent is for fuel, 84
percent is for plant capital, seven percent
is for operating and maintenance, and four
percent is for the cooling towers. The
total power generation costs are expected
to be 12.3 mills per kwh.
The figures from Table 6-20 and the
values in the above paragraph are from
different sources.
6.3.6.3.5 Other Considerations
Future research efforts on HTGR's will
examine the possibility of using a direct
cycle, where the helium expands through the
turbine. Coupled with a bottoming cycle
(explained in Chapter 12), the primary ef-
ficiency of these HTGR's could be increased
to 50 percent (AEC, 1974d: A.1.2-23). The
HTGR could also be used as a source of pro-
cess heat for coal gasification, steelmaking,
hydrogen production, etc. (AEC, 1974d:
A.1.2-24).
6.3.7 Reprocessing
The purpose of reprocessing HTGR fuel
is to recover the unused U-235, Th-232, and
the created U-233 for reuse as nuclear fuel.
The status of the HTGR reprocessing
industry is characterized by uncertainties.
Presently, there are no operating plants,
but an HTGR fuels reprocessing facility has
been proposed for construction at the
National Reactor Testing Station, Idaho
(AEC, 1974g). The most probable situation
is that reprocessing of HTGR fuel will not
be needed until 1990 (Battelle, 1973: 507) .
The actual reprocessing method is not
completely known. The chemical processing
of the used fuel has been established on a
small scale, but the physical procedures
for preparing the fuel elements for the
chemical processes have not been established.
The problems involved in scaling up both the
chemical and physical processing will be
examined at the proposed facility in Idaho
(AEC, 1974d: A.1.2-23).
6.3.7.1 Technologies
The first step in reprocessing the HTGR
fuel is to reduce the fuel to a form ready
for chemical processing. One proposed meth-
od is to ship the large block graphite fuel
elements to the reprocessing plants where the
graphite is burned (AEC, 1974d: A.1.2-22)
and the microspheres of fuel are separated
from the graphite. The two types of micro-
spheres can then be separated by further
burning because the coating on the U-235
pellets will not disintegrate while the
coating on the Th-232 and U-233 pellets
will.
The second step is the chemical proces-
sing of the two types of microspheres. The
U-235 is reprocessed by the method described
in the LWR section. For the microspheres
containing thorium, the "Thorex" process
has been and will be used (AEC, 1969: 121) .
In the "Thorex" process, solvent extraction
is used to separate both the uranium and
thorium from the majority of the fission
products. The thorium can then be separated
from the uranium by dissolving both in a
weak nitric acid solution; the thorium re-
acts while the uranium does not. Each is
then recovered from its respective solution.
The uranium will be shipped to the fuel
fabrication plant, but the thorium will
6-56
-------
probably be stored (AEC, 1974d: A.1.2-19)
for about 12 years to allow the level of
radioactivity to decrease. If low-cost
thorium is not available, the storage
period could be shorter.
6.3.7.2 Energy Efficiencies
The primary energy efficiency will
probably be large; that is, greater than
90 percent. The ancillary energy require-
ment has not been calculated.
6.3.7.3 Environmental Considerations
Table 6-20 contains the residuals for
reprocessing and transportation. In re-
processing, the main radioactive releases
to the atmosphere will be 16,000 curies
of tritium and 570,000 curies of Kr-85.
The main radioactive release to the water
will be 350 curies of tritium. The exposure
to the general public is expected to be in-
distinguishable from background.
Major accident considerations will
be similar to those in the LWR reprocessing
section.
6.3.7.4 Economic Considerations
The preliminary estimate to build the
reprocessing facility in Idaho is $30 mil-
lion, although inflation will probably in-
crease this figure (AEC, 1974g: 68). The
operating costs of this plant are expected
to be $3 million per year for a processing
capability of 24 fuel elements per day.
Table 6-20 lists a reprocessing cost
of $1.5 million or 0.25 mill per kwh for
a 1,000-Mwe plant for a year.
6.3.8 Radioactive Waste Management
The radioactive waste management pro-
gram of the HTGR fuel cycle is expected to
be similar to the program for the LWR. No
major shipments of HTGR wastes have taken
place or will take place in the near future.
Since commercial reprocessing capability
will not be needed until around 1990 and
since the high-level waste can be stored
at the reprocessing plant for up to 10 years,
the first large shipments of high-level
waste may not occur until 2000.
The only significant difference between
the HTGR and LWR program is the amount of
burial ground needed for the radioactive
wastes. Since the HTGR does not use cladding
and has a higher efficiency, the volume of
radioactive wastes will be about 70 percent
of those generated by a comparable size LWR
(AEC, 1974d: A.1.2-28).
6.3.9 Transportation
The solid lines in Figure 6-11 represent
transportation of radioactive material. In
addition to the necessary uranium transpor-
tation steps described in the LWR section,
a certain number of movements of radioactive
thorium materials are necessary. At present,
however, no major movements of thorium are
being performed or anticipated because the
resource needs of the HTGR industry are
small. Therefore, the economics and details
of transportation in the HTGR fuel cycle
are not well known.
6.3.9.1 Technologies
The necessary transportation steps are:
1. The steps described in the LWR
transportation section for uranium
through the enrichment process.
2. Thorium concentrate from the mine
to processing.
3. ThC>2 from processing to the fuel
fabrication plant.
4. Fuel elements from fabrication plant
to the reactor.
5. Used elements from the reactor to
the reprocessing plant.
6. Recovered U-233 from the reprocessing
plant to the fuel fabrication plant.
7. High-level radioactive waste from
the reprocessing plant to the burial
site.
6-57
-------
8. Low-level radioactive waste from
all the steps to the burial site.
The transportation methods and con-
tainers will be similar to those used in
the uranium fuel cycle. If the fuel fabri-
cation and fuel reprocessing plants are
located at the same site, one transportation
step is eliminated.
A shipping cask has been approved for
the shipment of HTGR fuel elements that
contain U-233, U-235, and Th-232. The
highly enriched uranium (95-percent U-235)
requires more stringent measures than trans-
porting low enrichment uranium.
6.3.9.2 Energy Efficiencies
The total ancillary energy require-
ment for HTGR fuel transportation has not
been calculated; once the commercial facil-
ities have been established, 'the ancillary
energy needs will represent the fuel require-
ments for the various modes of transporta-
tion.
6.3.9.3 Environmental Considerations
Table 6-20 lists residuals for trans-
portation and reprocessing combined. The
transportation residuals should be compar-
able to those described in the LWR section.
For major accidents, the analysis given
in the LWR transportation section should be
applicable.
6.3.9.4 Economic Considerations
Table 6-20 gives a reprocessing and
transportation cost figure of $1.5 million
per year or 0.25 mill per kwh for a 1,000-
Mwe HTGR. The transportation portion of
this value is probably for the transportation
of the high-level waste from the reprocessing
plant to the disposal site.
No separate economic data are available
for the other transportation steps.
6.4 LIQUID METAL FAST BREEDER REACTOR
_ (LMFBR) SYSTEM
6.4.1 Introduction
The term "fast breeder reactor" refers
to nuclear reactors that, in addition to
providing useful electric power output,
convert abundant U-238 into fissile Pu-239
and thereby produce more fissile nuclear
fuel than they consume. The AEC has been
conducting basic studies on the breeder
reactor concept for more than 20 years and,
about eight years ago, launched an intensive
effort (in cooperation with industry) to
develop a liquid metal fast breeder reactor
(AEC, 1974e: 26).
To indicate the level of this develop-
ment effort, the breeder reactor program
represented more than 42 percent of all
federal energy R&D expenditures in the
fiscal 1973 budget. The primary goal of
this program is to build and operate a 400-
Mwe power plant on the Clinch River in
Tennessee by the'early 1980's. Another
principal element of the breeder program
is the commitment to build and operate the
Fast Flux Text Facility for the purpose of
testing instrumented fuels and materials.
The major difference between LMFBR's
and other reactors is that the central
reactor core is surrounded by an outer core
or "blanket." The fuel rods in the central
core contain a mixture of plutonium dioxide
(PuO2) and U02 (primarily U-238), while the
blanket is loaded only with UQ,. As the
plutonium in the central core fissions,
neutrons interact with the U-238 in both the
core and blanket, transforming the U-238
into Pu-239. For every four pounds of Pu-239
consumed by an LMFBR, approximately five
pounds will be created, thus the term
"breeder reactor."
Compared to LWR's and HTGR's, the LMFBR
has two other distinctive features. First,
the LMFBR core employs "fast" neutrons
6-58
-------
(neutrons whose speed has not been slowed
by a moderating substance, such as hydrogen)
to achieve fission. For this reason, LMFBR's
are known as "fast" reactors while reactors
using moderated neutrons (such as the LWR's
and HTGR's) are known as "thermal" reactors.
Second, the LMFBR used liquid sodium to
transfer heat from the reactor core to the
water/steam that drives the turbine-gene-
rators. Combined with the plutonium breed-
ing capabilities, these features give the
reactor its name, "liquid metal fast breeder
reactor."
The LMFBR has two basic advantages.
One, of course, is that it creates fissile
fuel (Pu-239) out of U-238, thereby greatly
increasing the usable nuclear energy re-
sources. The second advantage is that the
liquid metal coolant permits higher opera-
ting temperatures, thus giving projected
plant efficiencies of 41 percent as compared
to 32-percent efficiency for LWR plants.
However, the LMFBR also has two major
disadvantages. First, plutonium is one of
the most toxic substances known to man, and
a major LMFBR industry would require han-
dling large amounts of plutonium safely.
Second, sodium is extremely reactive chemi-
cally and its use as a reactor coolant also
creates significant safety problems.
Figure 6-14 is a simplified flow dia-
gram for the LMFBR system. In the fuel
fabrication step, both U-238 and Pu-239 are
involved. The three U-238 supply options
! are: uranium that is mined and processed
;as in the LWR system except that the enrich-
ment step is not necessary; U-238 from the
depleted stream in the uranium enrichment
step for the LWR system? and U-238 that is
recovered from the used LWR fuel. In the
near future, all U-238 for the LMFBR will
come from depleted enrichment tailings.
Plutonium comes from two sources: Pu-239
recovered from the used LWR fuel and (even-
tually) Pu-239 that is bred in an LMFBR.
For a full description of the LWR fuel -
fabrication process, see Section 6.2.
Figure 6-14 shows that the fabricated
fuel feeds into the LMFBR which generates
electricity. Used fuel is reprocessed,
the Pu-239 going to the fuel fabrication
plant and the radioactive wastes (fission
products) going to the radioactive waste
management step. All solid arrows in the
figure indicate transportation steps
described in Section 6.4.7.
The following descriptions are brief
because of a lack of LMFBR system infor-
mation on efficiencies, environmental resi-
duals, and economic costs. Further, much
of the available data is speculative due
to a lack of operating experience with the
LMFBR system technologies.
6.4.2 Resource
The LMFBR system resources are more
complex to treat than those for other
energy sources. As mentioned above, heat
used for generating electric power comes
from the fissioning U-238 and Pu-239, and
the Pu-239 is created from U-238 either in
*
an LWR or in an LMFBR. Therefore, the
total LMFBR energy resource depends on the
total uranium resource base, which was dis-
cussed in Part I. The difference is that
the LWR system uses the U-235 isotope
(which constitutes only 0.71 percent of
naturally occurring uranium) while the
LMFBR utilizes the U-238 isotope (which
constitutes the remaining 99.29 percent
of the naturally occurring uranium). Thus,
the total energy resource base for the
LMFBR is many times larger than the LWR
energy resource base.
However, the LMFBR system will also
require initial plutonium inventories to
operate until the generated plutonium
Although Pu-239 does exist naturally,
it is in such small concentrations that it
would be costly to recover, and its quantity
could not provide a major energy base.
6-59
-------
Uranium Supply Option
6.2.2
6.2.5.3
6. 7 .1
U238 Supply
Options
Plutonium_Supply_ Option
6.4.2
Pu239 from
Other LMFBR's
6.2.7
Pu239 Supply
Options
Pu239 from
LWR Fuel
Reprocessing
U238 from
LWR Fuel
Reprocessing
•-1
\f 6.4.3
LMFBR
Fuel
Fabrication
6.4.5
LMFBR
Fuel
Reprocessing
6.4.4
LMFBR
Electricity
5.4.7Tronsportation Lines
Involves Transportation
Does Not Involve Transportation
6.4.6
Radioactive
Waste
Management
Figure 6-14. Liquid Metal Fast Breeder Reactor Fuel Cycle
-------
supplies are sufficient to supply the needed
fuel. This initial plutonium must come from
the LWR system. Thus, plutonium sufficiency
will be determined by the excess quantities
produced in the LWR economy, by the growth
rate and timing of the LMFBR economy, and
by the doubling time of the plutonium in-
ventory due to the breeding gain in the
LMFBR's (AEC, I974d: 4.1-20). Figure 6-15
is a projection of plutonium availabilities
and requirements. LMFBR inventory require-
ments do not exceed the plutonium available
from LWR's until the year 2000, at which
time excess plutonium from LMFBR's will pro-
vide inventories for new plants.
Since the primary source of U-238 will
be the depleted uranium streams from the
enrichment plants, the current projections
of depleted uranium are crucial to LMFBR
development. Table 6-23 gives projected
quantities of depleted uranium from the
enrichment of LWR and HTGR fuels. Since
a 1,000-Mwe LMFBR uses less than one ton
of uranium per year (Creagan, 1973: 14),
the potential supply of UF- appears to be
adequate for LMFBR needs for hundreds of
years without additional mining operations.
6.4.3 Fuel Fabrication
6.4.3.1 Technologies
As noted, the initial fuel loadings
for LMFBR plants will consist of Pu-239
recovered from LWR fuels and U-238 from
the enrichment plant tailings. The plutonium
will be converted to PuO_ for shipment from
stockpiles to the fabricating plant. The
uranium is shipped to the fuel fabrication
plant as UF_.
The fabrication plant produces two
types of pellets: mixed oxide pellets con-
taining UO_ and PuO2 to be used in the re-
actor core, and UO_ pellets to be used in
the blanket. At present, there are no
commercial fuel fabrication plants devoted
solely to LMFBR fuels. Nine existing small-
scale plants are capable of performing all
or part of the necessary steps, and a plant
capable of producing 220 tons per year of
mixed oxide fuel is scheduled to begin op-
eration in 1977 (AEC, 1974d: 4.3-2).
The fuel elements for both the core
and the blanket consist of long thin tubes
(cladding) that are filled with either UO_
pellets or mixed oxide (both IK^ and PuO_)
pellets. These pellets are similar in size,
being approximately 0.25 inch in diameter
and 1.5 inches in length.
The fuel fabrication plant will consist
of two physically separated sections, one
to produce the UO_ fuel elements and one
to produce the mixed oxide fuel elements.
The division is necessary because the
plutonium containment regulations are much
more stringent than those for the depleted
uranium. Figure 6-16 shows the flow dia-
gram for a plant capable of producing 5.5
tons of LMFBR fuel per day (AEC, 1974d:
4.3-10), which would be sufficient to supply
80 1,000-Mwe plants.
The mixed oxide section mechanically
mixes the PuO_ and UO_ powders. Pellets
are produced from the mixed powder and
sintered in a high-temperature oven. The
pellets are then ground to size and loaded
into the stainless steel cladding tubes.
The UO_ section of the plant involves
both chemical and mechanical processing
and is similar to the fuel fabrication
plant described in Part I. The depleted
UF, is converted to UO_ by successive re-
actions using water and ammonia. The pro-
duct of these reactions is heated to a high
temperature to produce the UO™ powder. Pro-
cessing the UO, powder into fuel pellets
follows the same process as that for the
mixed oxide powder.
6.4.3.2 Energy Efficiencies
At present, there is insufficient
information to calculate the energy effi-
ciency of the fuel fabrication step. The
6-61
-------
2000
1500 -
CO
z
o
h-
1000 -
500 -
Pu surplus. /
>^
1970 1980
1990 2000
YEAR
Figure 6-15. Plutonium Availabilities and Requirements
Source: Creagan, 1973: 16.
-------
TABLE 6-23
PRODUCTION OF DEPLETED UFC FORECAST FOR THE YEARS 1972-2000
b
Year
1972
1975
1980
1985
1990
1995
2000
Fabrication Load, Metric Tons of U
LWR U02
750
1,970
4,600
8,400
14.000
17,700
19,700
HTGR Fissile
1
0
7
23
44
60
70
LMFBR
Mixed Oxide
0
0
5
56
850
3,300
6,900
Blanket
0
0
1
23
310
1,150
2,500
UFg Metric T
Conversion
3,700
12,400
25,500
48.100
81,900
102,600
110,200
ons of U
Depleted3
2,949
10,430
20,893
39,677
67,856
84,840
90,430
Source: AEC, 1974d: 4.1-42.
^Depleted UF- = (conversion
(LWR UO )
primary loss of uranium and plutonium would
be negligible. The ancillary energy would
be the energy required to operate the fuel
fabrication plant.
6.4.3.3 Environmental Considerations
6.4.3.3.1 Chronic
The information on environmental resid-
uals in Table 6-24 is based on a model plant
and the residuals have been normalized to
reflect the requirements for a 1,000-Mwe
LMFBR power plant.
In Table 6-24, the two principal liquid
chemical effluents of the UO_ section are
ammonium hydroxide, NH.OH, and calcium hy-
droxide, Ca (OH)_. After passing through a
waste treatment plant, the residue is pumped
to a lined lagoon for fluoride precipitation.
The remaining wastes are pumped to another
lined storage lagoon where they are retained.
The accumulation of these wastes requires
the periodic construction of new lagoons.
(AEC, 1974d: 4.3-33) .
The gaseous chemical effluents would
be small amounts of NO and about 2,000
2C
grams of hydrogen fluoride (HF) and 6,000
grams of ammonia (NH-) per day (AEC, 1974d) .
- (HTGR fissile).
Tables 6-25 and 6-26 give the radio-
active emissions in the gaseous and liquid
effluents respectively (AEC, 1974d: 4.3-52).
The maximum individual radiation dose from
both gaseous and liquid emissions during
normal operations is estimated to be 0.059
mrem per year (AEC, 1974d: 4.3-92). This
is approximately 2,000 times less than nat-
ural background radiation and represents
the "fence-post" dosage (the radiation ex-
psoure of a person living at the power plant
boundary 24 hours per day, 365 days per
year).
6.4.3.3.2 Major Accidents
The potential for major accidents dif-
fers in the two sections of the fabrication
plant. In the UO2 section, the rupture of
a UF, cylinder would result in the release
of uranium and HF. The gaseous effluent
would result in a localized radiation level
285 times greater than normal operations.
The HF may present a greater potential haz-
ard than the uranium. Under extreme condi-
tions, human health could be affected by HF
in the air (AEC, 1974d: 4.3-144).
In the mixed oxide section of the plant,
the worst postulated accident would be a
general fire that resulted in the release of
6-63
-------
To Reactor
Radial-
Blanket-Rod
Fabrication
0.72 metric ton/day
U02- Blanket-
Pellet
Fabrication
2.76 metric tons/day
Depleted
UF6
From —
Diffusion
Plant
(4.63 metric
ton/day)
~ Powder
Preparation
4.89 metric tons/day
U02 Section
Axial
Blanket
Core
Fuel-Rod
Fabrication
433 metric ton/day
Pellets
Mixed-Oxide
Pellet
Fabrication
2.85 metric tons/day
U02
Powder
U02-Pu02
Powder
Preparation
2.85 metric tons/day
Pu02 Powder
I From
Reprocessing
Plant
(0.45 metric
ton/day)
Mixed-Oxide Section
Note= Numbers represent the weight of material being processed, including reject material
and loss, due to simplification, weights will not balance.
Figure 6-16. LMFBR Fuel-Fabrication Plant
(5-Metric Tons of Heavy Metal Per Day)
Source: AEC, 1974d: 4.3-10.
-------
TABLE 6-24
CHEMICAL RESIDUALS IN LIQUID EFFLUENTS FROM 1,000-Mwe LMFBR
Chemical
H2S04
HNO,
HCL
NaN03
NaOH
NH4OH
Ca (OH) 2
CaF2
4
PO4 (after degrading)
Solids
P03-
4 (in cooling tower)
Release Rate (metric tons per year)
Mixed-Oxide
Section
0.0537
0.0248
0.0164
3.52
0.507
0.745
0.0745
2.814
0.040
Uranium Dioxide
Section
2.850.
166.
0.0737
1.490
0.149
5.62
0.0840
Combined Plant
0.0537
0.0248
0.0164
3.52
0.507
2,850.
166.
0.0737
2.23
0.223
8.44
0.124
Source: AEC. 1974d: 4.3-41.
TABLE 6-25
POTENTIAL RADIONULCIDES IN THE GASEOUS EFFLUENTS FROM AN LMFBR FUEL FABRICATION PLANT
Radionuc 1 ide
Pu-236
Pu-238
Pu-239
Pu-240
Pu-241
Pu-242
U-232
U-234
U-235
U-236
U-238
Annual Release (10~ Curies per year)
Mixed-Oxide
Section
2.58 E-3
2.88 El
5.91
8.07
8.34 E2
2.20 E-2
9.12 E-5
2.17 E-4
2.35 E-4
Uranium Dioxide
Section
1.01 E2
1.25 El
1.58 El
9.19 E2
Combined Plant
2.58 E-3
2.88 El
5.91
8.07
8.34 E2
2.20 E-2
9.12 E-5
1.01 E2
1.25 El
1.58 El
9.19 E2
6-65
-------
TABLE 6-25. (Continued)
Radionuclide
Th-228
Th-231
Th-234
Am-241
Np-237
Pa-234
Annual Release (10~° Curies per year)
Mixed-Oxide
Section
2.40 E-5
1.37
2.30 E-7
Uranium Dioxide
Section
1.25 El
9.19 E2
9.19 E2
Combined Plant
2.40 E-5
1.25 El
9.19 E2
1.37
2.30 E-7
9.19 E2
Source: AEC, 1974d: 4.3-49.
radionuclides listed for the mixed-oxide section and the UO2 section would be released
from individual rooftop stacks (60 feet aboveground level) about 1,000 m from the site
boundary.
TABLE 6-26
RADIONUCLIDES IN THE LIQUID EFFLUENTS FROM AN LMFBR FUEL FABRICATION PLANT
Radionuclide
Pu-236
Pu-238
Pu-239
Pu-240
Pu-241
Pu-242
U-232
U-234
U-235
U-236
U-238
Th-228
Th-231
Th-234
Am-241
Np-237
Pa-234
Annual Release (10~6 Curies per year)
Mixed-Oxide
Section
2.8 E-l
2.4 E3
5.0 E2
6.7 E2
7.3 E4
1.8
7.6 E-3
1.8 E-2
2.0 E-2
2.0 E-3
1.2 E2
1.9 E-5
Uranium Dioxide
Section
2.6 E4
3.2 E3
4.1 E3
2.4 E5
3.2 E3
2.4 E5
2.4 E5
Combined Plant3
2.8 E-l
2.4 E3
5.0 E2
6.7 E2
7.3 E4
1.8
7.6 E-3
2.6 E4
3.2 E3
4.1 E3
2.4 E5
2.0 E-3
3.2 E3
2.4 E5
1.2 E2
1.9 E-5
2.4 E5
Source: AEC, 1974d: 4.3-52.
Contained in liquid effluent from combined plant and discharged at a rate of 237,000 gallons
per day.
a significant amount of plutonium. The
resulting gaseous radioactive effluent
would be 90 to 100 times greater than
those associated with normal operations.
The expected dosage to the general public
is expected to be well below current AEC
guidelines (AEC, 1974d: 4.3-146).
The accidents involved in the above
discussion assume multiple failures of all
preventative equipment.
6.4.3.4 Economic Considerations
The economics of LMFBR fuel fabrication
are uncertain because of the lack of operating
6-66
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experience. The fuel now being produced
for the Fast Flux Text Facility will cost
about $3,000 per kilogram of U0_ and PuO_
contained in the fuel elements (AEC. 1973a:
Element 8, 22). The cost in large-scale
production is expected to range between
$100 and $200 per kilogram (AEC, 1973a:
Element 8, 23) .
6.4.4 Reactor and Power Generation System
6.4.4.1 Technologies
The concept of the LMFBR was described
in Section 6.4.1. Figure 6-17 is a schemat-
ic diagram of an LMFBR power generation
system. Although not shown separately in
Figure 6-17, the central core contains
mixed oxide fuel rods, while the blanket
fuel rods are loaded with UO_ pellets only.
During operation, the U-238 in both the
core and the blanket is converted to plu-
tonium. For every four pounds of plutonium
consumed, approximately five pounds will
be created (AEC, 1973b: 6) .
The heat created by the fissioning fuel
is transferred to liquid sodium that flows
through the core. However, since sodium
becomes radioactive in passing through the
reactor core, an intermediate heat exchanger
is necessary to transfer the heat to a sec-
cond loop of nonradioactive sodium, which
flows through the steam generator. In the
steam generator, the heat is transferred to
water, thereby creating steam which then
drives the turbine. The sodium used in the
primary and secondary loops is an alkali
metal that melts at about 210 F, vaporizes
at 1,640°F, and has excellent heat transfer
properties. Sodium can be heated to high
temperatures at relatively low pressures,
thus permitting the use of low-pressure
cooling circuits which are less susceptible
to failure.
Since the operation of a breeding re-
actor depends on the availability of high-
energy neutrons, no moderating material
exists in an LMFBR core. The control rods
are used to change the power level and to
shut down the reactor. To provide the nec-
essary core stability and accident response,
the LMFBR is designed so that the reaction
rate tends to slow down as the core temper-
ature increases.
Among the many design problems of the
LMFBR is the tendency of the fast neutrons
in the core to damage the stainless steel
used as structural material in the reactor
and as cladding for the fuel rods. Radia-
tion damage creates small voids in the steel
which cause the material to swell and become
brittle.
Another potential problem is created
by the use of the sodium coolant. Sodium
is extremely chemically active. When ex-
posed to air in the liquid state, sodium
burns; when exposed to water, it reacts
violently (explodes). Sodium also forms
radioactive isotopes under irradiation,
making the containment of the sodium coolant
a critical aspect of LMFBR design.
6.4.4.2 Energy Efficiencies
As noted previously, the LMFBR can op-
erate at higher temperatures than an LWR and
therefore can achieve higher efficiencies.
The net plant efficiency for an LMFBR plant
is expected to be around 40 to 41 percent,
while LWR plants can only achieve efficiencies
near 32 percent.
6.4.4.3 Environmental Considerations
The land requirements for a 1,000-Mwe
LMFBR will range from 100 to 400 acres,
depending on the type of cooling system used.
6.4.4.3.1 Chronic
The total waste heat for a 40-percent
efficient 1,000-Mwe plant with at least
75-percent load factor would be 33.6x10
Btu's annually. »This would compare with
47.6x10 Btu's waste heat annually for a
32-percent efficient plant.
6-67
-------
Liquid metal fast breeder reactor (LMFBR)
containment structure
primary sodium loop secondary sodium loop
Figure 6-17. Liquid Metal Fast Breeder Reactor
Source: Atomic Industrial Forum, Incorporated.
turbine
generator
condenser
cooling
water
-------
TABLE 6-27
POSTULATED LMFBR RADIONUCLIDE RELEASES
(1,000-Mwe POWER PLANT AT 100-PERCENT CAPACITY FACTOR)
Nuclide
H-3 (Tritium)
Ar-39
Kr-85m
Kr-85
Kr-87
Kr-88
Xe-133
Atmospheric Release
(Ci per year)
60.
80.
0.3
0.4
0.4
0.5
0.03
Liquid Release
(Ci per year)
60.
Source: AEC, 1974d: 4.2-54.
In addition to thermal pollution, LMFBR
power plants create liquid, gaseous, and
solid wastes. Liquid wastes associated with
the reactor operation will be negligible,
but chemical agents will be required for
water treatment in the steam system and for
suppressing biological growths in the cool-
ing water. The nature and volume of these
chemical wastes are expected to be similar
to those of conventional power plants of
the same capacity.
Table 6-27 lists the annual postulated
radioactive effluents from a 1,000-Mwe plant
with a 100-percent load factor. As noted
in Table 6-12, an LWR will emit 10 to 50
curies of tritium and 7,000 to 50,000 curies
of krypton and Xenon; this compares to
LMFBR gaseous releases of 60 curies of
tritium and neglible amounts of krypton and
Xenon. All radioactive effluents represent
a maximum dosage that is small compared to
. natural background (AEC, 1974d: 4.2-118).
6.4.4.3.2 Major Accidents
The AEC has analyzed potential LMFBR
accidents and divides these accidents into
three categories: (AEC, 1974d: Section
4.2.7)
1. Reasonably anticipated occurrences
leading to no significant release
of radioactivity.
2. Unlikely events with a potential
for small-scale radioactive release.
3. Extremely unlikely events with a
potential for large-scale radio-
active release.
The first category includes such
events as plumbing leaks of nonradioactive
materials. The second category includes
accidents involving the release of stored
radioactive gas. The third category in-
cludes massive sodium leaks, refueling
accidents, or accident sequences that could
involve substantial damage to the core.
The AEC has not been able to assess
probabilities and environmental impacts for
the various accident sequences, citing the
lack of experimental data and analytic
models. Thus, further analysis is needed?
one operating LMFBR (Fermi, located near
Detroit) was shut down because a portion
of the core did melt after a coolant passage
was blocked.
6.4.4.4 Economic Considerations
At present, LMFBR costs are speculative
at best. The high start-up costs normally
associated with a new and complex technology
6-69
-------
TABLE 6-28
ESTIMATED LMFBR POWER PLANT CAPITAL COSTS
(1974 DOLLARS)
LWR (1.300 Mwe)
HTGR (1,300 Mwe)
LMFBR 1,300 Mwe)
Capital Costs
(dollars per kilowatt-hour)
1974
420
419
NA
1980
420
419
NA
1990
420
419
487
Source: AEC, 1974d: Appendix III-B, p. 4-5.
are likely to be exaggerated by the need for
complex provisions against catastrophic
failure and the atmosphere of public con-
cern in which the LMFBR is being developed.
Table 6-28 compares the AEC estimates
for LMFBR power plant capital costs in 1974
dollars with those for LWR's and HTGR's.
These cost estimates should be viewed with
caution, as the cost of the Clinch River
project, originally estimated at $700 million
by the AEC, has been recently re-estimated
at $1,800 million. At a total cost of
$1,800 million, the Clinch River project
would cost approximately $4,000 per kwe.
6.4.5 Fuel Reprocessing
6.4.5.1 Technologies
Reprocessing is an important part of
the LMFBR fuel cycle because the recovery
of Pu-239 from the core fuel and the blanket
is necessary to provide new fuel supplies.
At present, no commercial plants exist for
reprocessing LMFBR fuel. Although the chem-
ical processes are similar to those for LWR
fuels, the preparation of the LMFBR fuel
for chemical conversion will be significantly
different because of the increased amount
of heat in the fuel, the rugged construction
of the fuel assemblies, and the criticality
control problem caused by the high plutonium
content (AEC, 1974d: Section 4.4).
A plant producing 5.5 tons of uranium
and plutonium per day (approximately 1,650
tons per year) would be adequate for 80,000
Mwe of installed LMFBR capacity. The weight
of the plutonium processed each year would
be 150 tons (AEC, 1974d: Section 4.4).
The following steps are involved in
reprocessing LMFBR fuel (AEC, 1974d: 4.4-12,
4.4-14):
1. The incoming fuel assemblies are
stripped of sodium.
2. The fuel cladding is broken up
and shredded by mechanical and
torch cutting.
3.
6.
7.
8.
The nuclear fuel is reacted with
nitric acid.
The heavy metal is separated from
the fission products.
Uranium is separated from the
plutonium.
Uranium is converted to UO,.
Plutonium is converted to puO_.
Radioactive wastes are diverted
to the appropriate liquid, gas,
or solid waste streams.
In general, the fuel will be allowed
to "cool" one year before reprocessing. If
a shorter time delay is involved, the shield-
ing must be increased.
6.4.5.2 Energy Efficiencies
The ancillary energy is the energy
required to operate the fuel reprocessing
plant, but no information on this require-
ment is currently available. The primary
efficiency is related to the percent of
plutonium and uranium recovered, which
presumably is near 100 percent.
6.4.5.3 Environmental Considerations
A reprocessing plant capable of pro-
ducing 5.5 tons per day of uranium and
plutonium will occupy approximately 1,000
acres of land (AEC, 1974d: 6).
6.4.5.3.1 Chronic
Only a very small amount of waste heat
will be discharged. Small amounts of gase-
ous chemical effluents (primarily NO )
X
6-70
-------
directly associated with the processing will
be emitted. There are liquid chemical
wastes, but these are discharged to a re-
tention pond (AEC, 1974d: 4.4-57) .
The radioactive wastes (including
krypton, tritium, iodine-129, iodine-131,
plutonium, and various isotopes of uranium)
have been estimated by AEC (1974d: 4.4-57) .
The maximum individual dose at the site
boundary, including ingestion through the
food chain, is estimated by the AEC at 1.0
mrem per year, compared to a natural back-
ground of 125 mrem per year.
6.4.5.3.2 Major Accidents
In postulating accidents, the AEC has
assumed that the plant would be protected
from floods by siting considerations and
that the vital structures would be resis-
tant to tornadoes and earthquakes (AEC,
I974d: 4.4-84) . Man-originated accidents
that could result in the release of radio-
activity are:
1. Fuel element rupture.
Leakage of radioactive liquid.
Solvent fire.
Nuclear criticality.
TABLE 6-29
LMFBR REPROCESSING COST ESTIMATES
(1974 DOLLARS)
2.
3.
4.
5.
Explosive rupture of a process
vessel.
6. Catastrophic failure of a Kr-85
storage vessel.
For all the above accidents, the maxi-
mum dose absorbed by an individual at the
plant boundary was calculated by the AEC
to be less than 1.0 mrem, as compared to
an average natural background of 125 mrem
per year.
6.4.5.4 Economic Considerations
The reprocessing cost estimates are
shown in Table 6-29 for LMFBR fuels and
LWR fuels.
6.4.6 Radioactive Waste Management
The radioactive waste management tech-
nologies are similar for the LWR, HTGR, and
LMFBR. However, the amounts and types of
wastes can vary.
Fuel Type
LMFBR
LWR
Dollars per
Initial
92
94
Kilogram
2020
75
41
Source: AEC, 1974d: Appendix III-B, p. 4-18.
Table 6-30 compares the radioactive
solid wastes from an LWR with plutonium
recycle and an LMFBR, each with an output
of 1,000 Mwe. The quantities of high-level
waste for the two programs are approximately
the same at 55 and 60 cf per year respective-
iy.
The LMFBR will generate 170 cf of clad-
ding hulls per year compared to 60 cf for
the LWR. The LMFBR produces fewer cf of
solids at the reactor than the LWR.
6.4.7 Transportation
Many of the transportation steps
involved in LMFBR operation are similar
or identical to those described for the
LWR. Thus, only those procedures or equip-
ment unique to the LMFBR cycle will be
described in this section (AEC, 1974d:
Section 4.5) .
6.4.7.1 Technologies
In addition to the transportation steps
described for the LWR, the following four
steps are required for LMFBR operation.
1.
2.
from the LWR reprocessing
plant to the LMFBR fuel fabri-
cation plant.
Nonirradiated fuel containing
PuO2 from the fuel fabrication
plant to the reactor.
Irradiated fuel from the reactor
to the reprocessing plant.
Recovered PuO2 from the reproces-
sing plant to the fuel fabrication
plant .
6-71
-------
TABLE 6-30
ESTIMATED ANNUAL QUANTITIES OF RADIOACTIVE SOElD WASTES FROM AN LWR AND LMFBR
Production Location
Produced at Reactor Site
Other-than-High-Level
Cubic feet per year
used, square feet per year
Burial ground area used
Noble Gases
Cylinders per year
Produced at Reprocessing
Plant Site
Hiqh-Level Solid
Cubic feet per year
RSSF repository3 space
required, square feet
per year
Cladding Hulls
Cubic feet per year
Repository3 or burial
space required, square
feet per year
Other Solid Wastes
Cubic feet per year
Burial ground, square feet
per year
Noble Gases
Cylinders per year
Produced at Fabrication Plant
Site Other-than-Hicrh-Level
Including Plutonium Contaminated
Wastes
Cubic feet per year
Repository space, square feet
per year
1,000-Mwe LWR
With Pu Recycle
2,000-4,000
400 - 800
55
11
60
12
600-4,000
100 - 800
10,000-30,000
2,000-6.000
1,000-Mwe
LMFBR
1,000-2,000
200 - 400
60
12
170
35
5,000-10,000
1,000 -2,000
10,000-30,000
2,000 -6,000
Source: AEG, 1974d: 4.6-12.
If required by future regulations.
6-72
-------
Approximately 1.700 kilograms of PuO-
must be shipped over an average distance
of 750 miles each year for a typical
1,000-Mwe LMFBR (AEC. 1974d: 4.5-15).
Approximately 16 metric tons of nonirradi-
ated uranium and plutonium must also be
shipped over the same distance each year.
At present, no casks have been de-
signed for shipping LMFBR-irradiated fuel.
Such casks are expected to be similar to
those used for LWR fuel, which weigh 50 to
100 tons and are shipped by rail or barge.
6.4.7.2 Energy Efficiencies
The primary efficiency should be 100
percent. The ancillary energy is the fuel
required to power the vehicles, which
should be small compared to total power out-
put of the fuel.
6.4.7.3 Environmental Considerations
In routine shipping operations, the
thermal load and radiation exposure are
expected to be small. The former will be
negligible by comparison to the heat gener-
ated by an ordinary automobile engine. The
radiation exposure to the general public
will be small compared to natural background
radiation.
The AEC has analyzed a number of poten-
tial transportation accidents. Their anal-
ysis of extreme accidents for a container
of PuO_, or for shipments of nonirradiated
fuel containing PuO2, indicates that radio-
active releases would be negligible.
A series of postulated events for an
irradiated fuel cask leading to an extreme
accident could result in high radiation
doses near the cask. The dose rate at the
cask surface has been estimated to be 10
to 500 mrem per hour. This is within the
current AEC limits but could be greater
than the natural background radiation of
125 mrem per year.
6.4.7.4 Economic Considerations
No specific data is available on the
costs of the various transportation steps.
However, the costs of shipping used fuel
is expected to be approximately $36.40 per
kilogram of heavy metal (AEC, 1971: 113).
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*
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Atomic Energy Commission (1974f) Environ-
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-------
CHAPTER 7
THE NUCLEAR ENERGY-FUSION RESOURCE SYSTEM
7.1 INTRODUCTION
The most optimistic proponents of nu-
clear fusion as a source of commercial en-
ergy do not expect it to be available until
after the year 2000. Therefore, fusion is
a long-term energy alternative and does not
meet the criteria specified for inclusion
in this report. However, fusion has been
the subject of so much continuing discus-
sion that it needs to be set in perspective
vis-a-vis the other resource systems. This
very brief discussion, which is organized
differently than the other chapters, has
five purposes: to describe briefly the
history of fusion as a potential energy
source; to indicate why it is considered by
many to be an attractive energy alternative;
to indicate its state of scientific develop-
ment; to indicate the current level of gov-
ernment R&D funding; and to summarize the
role of fusion as an energy alternative in
the context of environmental impact state-
ments .
7.2 FUSION AS A POTENTIAL ENERGY SOURCE
The first demonstration of fusion as a
source of energy was the explosion of a hy-
drogen bomb in 1952. Following that ther-
monuclear explosion, the Atomic Energy
Commission (AEC) established, in late 1952,
a project to investigate the possibility of
generating energy by fusing atoms in a con-
trolled manner within a reactor (AEC, 1973:
7).
The continuing interest in fusion has
resulted from what appear to be attractive
fuel and environmental characteristics.
Among the most important of these is the
expectation that the fuel sources for a
fusion reactor would be plentiful. Specif-
ically, the first fusion reactors are ex-
pected to use heavy isotopes of hydrogen:
deuterium and tritium. Deuterium exists
naturally in sea water (Glasstone, 1974:
A.1.6-12). Tritium does not occur natural-
ly but is expected to be produced from
lithium in normal operation of a fusion
reactor (Hansborough and Draper, 1973: 43).
Lithium is a relatively plentiful natural
element. Environmentally, fusion reactors
are expected to be more attractive than
fission because of less serious fuel han-
dling problems, lower radioactive inven-
tories, and because fewer radioactive
*
wastes will be generated.
Present strategies for developing
fusion reactors involve two concepts: mag-
netic confinement and laser implosion. In
the first, the hydrogen isotopes exist in
a gas (plasma) that is being contained
within a magnetic field. The magnetic
field accelerates the isotopes to high ve-
locities; when the isotopes collide, fusion
will occur. The second concept uses concen-
trated light from lasers to compress and
heat a pellet of deuterium and tritium
causing fusion (Metz, 1972: 1180).
The first strategy for developing
fusion and the one that has received the
most attention to date, is being pursued by
There is disagreement on this point.
See, for example. Post and Ribe (1974) and
Starr and Hafele's response (1975).
7-1
-------
the Controlled Thermonuclear Reaction
*
Division of the Atomic Energy Commission.
The program is being planned to proceed
through five major steps in magnetic con-
tainment technology ending with construc-
tion and operation of a demonstration re-
actor. These are: hydrogen plasma experi-
ments at near the conditions necessary in
a reactor between now and 1980; fusion test
reactors at the level of 1 to 10 megawatts-
thermal between 1980 and 1985; an experi-
mental power reactor producing 20 to 50
megawatts-electric (Mwe) between 1985 and
1989; a second experimental power reactor
producing more than 100 Mwe between 1989
and 1997; and finally a demonstration re-
actor producing more than 500 Mwe in 1997
(AEC, 1974: 1-4). No similar timetable has
been offered for the laser technology op-
tion, but at the present time, laser fusion
does not appear to be as far advanced as
the magnetic containment technologies.
Although work on fusion is only in the
scientific feasibility phase, the AEC is
providing increased support. AEC's support
pattern for five years is reported in
Table 7-1. The nearly 70-percent increase
in total estimated support for 1975 reflects
an effort to accelerate fusion development.
Even with accelerated support, however,
commercial use of fusion energy is at least
25 years away. Further, both its purported
energy and environmental benefits are ex-
trapolations from theory and laboratory
work. Until additional experience and data
are available, no firm conclusions con-
cerning benefits or costs are warranted
(Metz, 1972: 1180). What can be concluded
is that fusion is not an available energy
alternative in the context of contemporary
environmental impact statements.
TABLE 7-1
-"
FEDERAL R&D FUNDING FOR FUSION
(MILLIONS OF DOLLARS)
Type
Magnetic
Laser
TOTAL
1971
33.3
19.5
52.8
1972
39.6
25.9
65.5
1973
39.7
35.1
74.8
1974
57.0
44.1
101.1
1975
102.3
66.3
168.6
Source: Gillette (1974: 637) .
REFERENCES
Atomic Energy Commission, Division of
Controlled Thermonuclear Power (1973)
Fusion Power. Washington: Government
Printing Office.
Atomic Energy Commission, Division of
Controlled Thermonuclear Research
(1974) Fusion Power by Magnetic
Confinement. Washington: Government
Printing Office.
Gillette, Robert (1974) Energy Science. 183
(February 15, 1974).
Glasstone, Samuel (1974) Controlled Nuclear
Fusion, AEC Understanding the Atom
Series. Washington: Government
Printing Office.
Hansborough, Lash, and E. Linn Draper, Jr.
(1973) Overall Tritium Considerations
for Controlled Thermonuclear Reactors.
Austin, Texas: University of Texas.
Metz, William D. (1972) "Laser Fusion:
A New Approach to Thermonuclear Power. "
Science 177 (September 29, 1972) .
Post, R.F., and F.L. Ribe (1974) "Fusion
Reactors as Future Energy Sources."
Science 186 (November 1, 1974):
397-407.
Starr, Chauncey, and Wolf Hafele (1975)
Letter to the Editor. Science 187
(January 24, 1975): 213-214.
This program is now in ERDA.
7-2
-------
CHAPTER 8
THE GEOTHERMAL ENERGY RESOURCE SYSTEM
8.1 INTRODUCTION
Generation of electricity from geo-
thermal steam resources occurred for the
first time in 1904 at Larderello. Italy.
Continuous generation began in 1913 with
a 12.5-megawatt-electric (Mwe) plant, and
current output at Larderello is 360 Mwe.
The only commercial geothermal production
in the U.S. is in the Geysers area of
California and it dates from about 1960.
In 1974, output was 412 Mwe (0.1 percent
of U.S. electric power generation capac-
ity) . Annual increases of 110 Mwe until
1980 are planned. With these additions,
geothermal power should provide about one
percent (under very favorable conditions,
several percent) of electric power in the
U.S. from 1980 through the year 2000. Al-
though its national role is small, geo-
thermal power can be a significant sup-
plement to other forms of electric power
in local areas (e.g., California).
Besides power generation, geothermal
steam is produced for space heating at
Klamath Falls, Oregon and Boise, Idaho.
Geothermal electric production is
distinctive in that all steps in the fuel
cycle are localized at the site of the
power production facility; thus, there are
no transportation alternatives. Aside
from steam transport from the wellhead to
the power plant, the only transportable
item is electricity.
As shown in Figure 8-1, there are
:four principal activities in using geo-
thermal energy: exploration, extraction,
;pipeline transportation, and electric
power generation. (Extraction includes
both drilling and production phases.)
Following a description of U.S. geothermal
resources, these activities and the tech-
nologies for achieving them will be de-
scribed. A summary section then discusses
total trajectory efficiencies, environ-
mental residuals, and costs.
8.2 RESOURCE CHARACTERISTICS
8.2.1 Quantity
Estimates of geothermal reserves
vary considerably. Table 8-1 gives re-
source estimates using the U.S. Geological
Survey (USGS) categories with some expla-
nation of which reservoirs each author in-
cludes in a category. Reserve estimates
vary from 1,000 Mwe (10 6 Btu's at the
wellhead) to 60,000 Mwe. Total resource
estimates vary from 400,000 to 148,000,000
Mwe for 50 years. Several factors explain
the variance in reserve and resource esti-
mates . The limited exploration for geo-
thermal resources to date has resulted in
a lack of agreement on unexplored reser-
voir characteristics, on the time required
for the needed new technologies to become
commercially available, and on future
changes in cost factors within the energy
sector of the economy, some of which would
stimulate geothermal production.
To provide perspective and a basis
for comparing potential geothermal-electric
reserves. Table 8-2 contains 1985 installed
capacity estimates under various growth
scenarios. The estimates range from 3,500
to 132,000 Mwe in 1985. In Table 8-3, the
economic dimension is added to the
8-1
-------
8.2
Geothermal
Resource
_ w
"P
8.3
Exploration
,___.. _^
Extractioi
84Drilling
i
8.5 Production
Steam
Steam & Water
Nuclear (Plow-
ohfirA^ or
OllUI O/ V* 1
Hydrofracturing
& Water Injection
w
Pipeline
8.7
tiecinc rower
Generation
—^-Electricity
Involves Transportation
Does Not Involve Transportation
8.6 Transportation Lines
Figure 8-1. Geothermal Resource Development
-------
TABLE 8-1
GEOTHERMAL RESOURCE ESTIMATES
Source
Muffler and White,
Identified recoverable
or reserves (the Geysers
and several others)
Undiscovered recoverable
Paramarginal
(high temperature hot-
water systems nearly
economical )
Submarginal to a depth of
10 kilometers (neither
economical nor tech-
nically feasible)
White.
Proved
(recoverable at present
cost and technology)
Paramarginal
(present technology, one-
third increase in price)
Rex and Howell,
Known reserves
(Geysers and Imperial
Valley)
Probable reserves
(Western U.S.
hydrothermal systems)
Undiscovered reserves
(dry hot resources to
a depth of 35,000 feet)
Btu's In Situ
(1016)
6
40-80
400
4,000
7
24
360
12,000
880,000
Btu'sa at the
Wellhead
,,n16.
(10 )
1
6-12
60
600
1
3.6
54
1,800
133,200
Megawatts3 of
Electricity for 50
Years
1,000
3,000-6,000
40,000
400,000
1,200
4,000-8,000
60,000
2,000,000
148,000,000
Sources: Muffler and White, 1972: 50; White, 1973: 91; Rex and Howell, 1973: 63.
Conversion from Btu in the ground assumes current efficiencies (15 percent of
the in situ energy is deliverable to the wellhead and electrical generating
efficiency is 14 percent.
8-3
-------
TABLE 8-2
POTENTIAL INSTALLED GEOTHERMAL CAPACITY BY 1985
Organization Cited
(with scenarios used from each)
Projected
Capacity in Mwe
1985
National Petroleum Council
Most optimistic scenario
(maximum technological progress
with no impediments)
Large areas of land available
with no environmental delays
Realistic estimate based on
current costs and technologies
Least optimistic
Hickel Panelb
Moderate R&D Program
Accelerated R&D Program
Bureau of Minesc
Based on projects currently
under consideration
Atomic Energy Commission
Active R&D program to stimulate
production
Bureau of Land Management6
All western sources (assumes
technology for hot water
systems available)
Rex and Howell
Assumes hot dry rock systems are
now technically exploitable
Estimate is for development in
western U.S. only
19.000
9,000
7,000
3,500
19,000
132,000
4,000
20,000
7,000
to
20,000
400,000g
Sources: Kilkenny, 1972: 27-35.
bHickel, 1972: 15.
clnterior, 1973: Vol. I, p. 11-19.
dAEC, 1973: 119.
gBy 1993.
"BLM, 1973: 347.
Rex and Howell, 1973: 63.
8-4
-------
TABLE 8-3
EFFECT OF PRICE ON POTENTIAL INSTALLED GEOTHERMAL CAPACITY BY 1985
National Petroleum Council3
Power Cost
(mills per kwh)
5.25
5.75
6.25
Installed
Capacity
1985
(Mwe)
7,000
14,000
19,000
Rex and Howe 11
Fuel Price0
(mills per
kwh)
2.9-3.0
3.0-4.0
4.0-5.0
Known
Reserves
Probable
Reserves
Undiscovered
Units Mwe for 50 Years
2.000
60.000
0
10,000
800,000
1.200,000
20,000
4,000,000
24,000,000
Sources: Kilkenny, 1972; 27-35, 1972 dollars.
bRex and Howell. 1973: 63, 1972 dollars.
Q
A price of 2.9 mills per kwh (cost of the produced steam) is roughly equivalent
to a power cost of 5.25 mills per kwh.
resource estimate, indicating price rises
required to stimulate additional produc-
tion.
Most estimates indicate that geother-
mal energy may make substantial contribu-
tions in the western U.S. by the end of
the century. By 1985, contributions are
postulated to be on the order of one per-
cent of U.S. electric capacity.
8.2.2 Geology
Normally, the heat of the earth is
diffuse. When local geologic conditions
concentrate heat energy into hot spots or
thermal reservoirs, it becomes a potential
energy resource. Three categories of
thermal reservoirs are defined geologi-
cally: hydrothermal, geopressured, and
dry hot rock reservoirs.
8.2.2.1 Hydrothermal Reservoirs
Hydrothermal reservoirs are the most
desirable type for producing geothermal
energy. These reservoirs consist of a
heat source (magma) overlain by a perme-
Jible formation (aquifer) in which the
groundwater circulates through pore
spaces. The aquifer is capped by an im-
permeable formation which prevents water
loss. Water and steam transport the heat
energy from the rock to the well and fi-
nally to the surface. Two categories of
hydrothermal reservoirs are defined, based
on whether hot water or vapor dominates
the reservoir. Vapor dominated systems,
such as the Geysers in California, are the
most commercially attractive but are rel-
atively rare. Hot water dominated res-
ervoirs, sometimes termed wet steam, are
20 times more common.
8.2.2.2 Geopressured Reservoirs
No production from geopressured res-
ervoirs has occurred to date, although
these reservoirs differ from hydrothermal
reservoirs only in the source of heat.
Rather than a magma, the clays in a rapidly
subsiding basin area, such as the Texas
and Louisiana Gulf Coast, trap heat in
underlying water-bearing formations.
California's Imperial Valley geothermal
reservoir may be a combination of a hot
water hydrothermal and a geopressured res-
ervoir.
8-5
-------
8.2.2.3 Dry Hot Rock Reservoirs
In dry hot rock systems, no permeable
aquifer (and thus no water or steam) over-
lies the heat source. Consequently, pro-
duction requires fracturing the rock and
injecting water. No production from this
type of reservoir has occurred.
8.2.3 Physical and Chemical Characteris-
tics
Only vapor and hot water dominated
hydrothermal reservoirs can presently be
defined as reserves. For both technolog-
ical and economic reasons, commercial pro-
duction now requires the following charac-
teristics (White, 1973: 69):
1. Reservoir depth not exceeding
1.86 miles.
2. Naturally occurring reservoir
water for transferring the heat.
3. Reservoir volume greater than
1.2 cubic miles.
4. Sufficient reservoir permeability.
In the U.S., empirical data exist for
only two reservoirs, the Geysers and
Niland (Salton Sea). The characteristics
for these two reservoirs, given in
Table 8-4, represent the range of known
U.S. reservoir characteristics to date,
although this range is expected to widen
as exploration expands. In general, vapor
dominated reservoirs have a higher heat
content, lower salinity, lower temperature,
and deeper drilling requirements than hot
water dominated reservoirs. The high mass
flow for the hot water system represents
both water and steam.
8.2.4 Location
Figure 8-2 is a map of U.S. geother-
mal regions, including the geopressured
zone of the Gulf Coast. In the U.S., all
locations likely to be developed until
1985 (and probably until 2000) are in the
western one-third of the country. There
are currently 43 known geothermal resource
areas in the U.S. (Godwin and others,
1971: 2), 14 of which are in California,
13 in Nevada, 7 in Oregon, and the re-
mainder in Alaska, Idaho, Montana,
New Mexico, Utah, and Washington. A
known geothermal resource area (KGRA)
occurs where "the prospect of extraction
of geothermal steam or associated geo-
thermal resource from an area is good
enough to warrant expenditure of money for
that purpose" (Godwin and others, 1971: 2) .
Currently 1.8 million acres are classed as
KGRA. An additional 96 million acres are
termed as having prospective value. All
are hydrothermal reservoirs.
Areas where geothermal development is
expected in the near future are the
Imperial Valley (hot water-brine), Clear
Lake-Geysers (vapor), Mono-Long Valley,
California (hot water), and several hot
water dominated reservoirs in Nevada.
8.2.5 Ownership
Of the 1.8 million acres classed as
KGRA's, 56 percent occur on federal land.
Sixty percent of the 96 million acres
termed prospective are on federal land.
8.3 EXPLORATION
8.3.1 Technologies
The great majority of presently ex-
plored hydrothermal systems display sur-
face discharges of hot water or steam,
accompanied by strong surface temperature
anomalies. Since such systems are readily
detectable (and many are currently known) ,
U.S. geothermal exploration in the near
future will probably be confined to these
reservoirs (Banwell, 1973: 42).
Although both passive and active ex-
ploratory techniques are available, these
tools and methods were developed princi-
pally for defining the extent of the res-
ervoir and determining its characteristics,
not for locating reservoirs lacking sur-
face discharges. However, even these
techniques are unsophisticated, and little
direct knowledge of thermal reservoir char-
acteristics is obtainable without drilling.
8-6
-------
Hydrothermal Reservoirs
Geopressured Brines
Figure 8-2. Distribution of U.S. Geothermal Resources
Source: Interior, 1973: Vol. 1, p. 11-17.
-------
TABLE 8-4
CHARACTERISTICS OF U.S. GEOTHERMAL FIELDS
Reservoir temperature
(degrees Centigrade)
Reservoir pressure
(pounds per square
inch)
Wellhead pressure
(pounds per square
inch)
Heat content
(Btu's per pound)
Average well depth
(feet)
Fluid salinity
(parts per million)
Average mass flow per
well
(pounds per hour)
Non-condensable gases
(weight percent)
Geysers
Vapor
Dominated
245
500
150
1,200
8,200
1,000
150,000
1
Niland
Hot Water
Dominated Brine
300+
2,000
400
560
4,250
250,000
440,000
1
Sources: ^oenig, 1973: 24.
Austin and others, 1973: 4, 5, 16.
8.3.1.1 Passive Exploration Techniques
Passive exploration techniques are
usually surface-oriented, although air-
borne geologic reconnaissance flights may
be used in data gathering. The first step
is normally compilation of a catalog of
existing geological, geochemical, and geo-
physical data. If necessary, several quick
and easy field measurements may then be
made to supplement the existing data. Geo-
logic techniques include stratigraphic
and structural mapping and locating sur-
face thermal manifestations (hot springs).
Also, temperature and discharge measure-
ments are made on hot and cold springs.
Passive geophysical techniques also
include gravity and magnetic surveys for
delineating major structural features and
the measurement of ground noise and micro-
earthquakes. Many geothermal reservoirs
are characterized by abundant raicroearth-
quakes and high noise levels. Individual
geothermal systems may even have charac-
teristic seismic signatures as measured
with ultrasensitive, high frequency geo-
phones.
Geochemical techniques involve ana-
lyzing thermal surface waters to determine
whether the reservoir is hot water or va-
por dominated as well as to estimate the
reservoir minimum temperature, chemical
character, and source of recharge water.
For example, a chloride content in a hot
spring of greater than 50 parts per million
8-8
-------
(ppm) usually indicates a hot water reser-
voir, while less than 20 ppm indicates a
vapor dominated reservoir (Combs and
Muffler, 1973: 100).
8.3.1.2 Active Exploration Techniques
Active exploration techniques include
seismic measurements, electrical conduc-
tivity tests (earth resistivity surveys),
and thermal gradient surveys. In the
seismic tests (described in Section 3.3),
reflected sound waves are translated into
subsurface maps which indicate the struc-
tural nature of the rocks at depth.
In the electrical conductivity and
thermal gradient tests, small diameter
holes are drilled (from 50 to 330 feet for
earth resistivity measurements and to a
minimum of 330 feet for heat flow measure-
ments) , and measurements are made by in-
struments lowered down the boreholes. Be-
cause the temperature, material porosity,
and fluid salinity of geothermal reservoirs
tend to be high, these reservoirs are good
conductors of electricity and thus low in
resistivity. The same characteristics also
result in higher than normal heat flow
rates and temperature gradients in the
immediate vicinity of the reservoirs.
If the results of the above tests are
sufficiently promising, a hole is drilled
into the producing zone to evaluate reser-
voir production potential. Drilling tech-
nology is discussed in Section 8.4.
8.3.2 Energy Efficiencies
Since no energy conversions are in-
volved in exploration, primary energy effi-
ciencies are not applicable. The manpower,
technology, and power for shallow drilling
reflect the ancillary energy used in geo-
thermal exploration. Numerical estimates
of this energy have not been made.
8.3.3 Environmental Considerations
Prelease exploration (all techniques
except drilling for thermal measurements)
involve minor impacts. Some alteration in
land use from construction of access
roads, cross country roads, and clearings
occurs .
8.3.4 Economic Considerations
Geothermal exploration costs account
for only a small percentage of development
costs unless exploratory drilling costs
are included. Thus, the costs of recon-
naissance surveys and measurements on the
surface do not inhibit development. How-
ever, when several exploratory test wells
are drilled, costs escalate. Armstead
(1973: 163) has estimated that three mil-
lion dollars is required for exploration
of one developed zone or geothermal field.
8.4 EXTRACTION—DRILLING
The extraction system for geothermal
energy is similar to oil and gas in that
a well is drilled to sufficient depth,
cased, and completed to provide a stable
conduit for fluids. Facilities required
to control and transport the fluid to its
point of utilization are added at the well-
head. Only those characteristics and
problems unique to the extraction of geo-
thermal energy are discussed here. The
details of drilling rigs are discussed in
Chapter 3.
8.4.1 Technologies
Experience indicates that the differ-
ences between oil drilling and geothermal
drilling are:
1. Slower penetration rates are
common due to harder rock.
2. Equipment, casing, and cement are
subjected to higher temperatures
in geothermal wells; thus, some
variation in cement types and
equipment occurs.
3. A more elaborate system for cool-
ing mud is required. (A cooling
tower may be used.)
4. Completion is usually some com-
bination of cased wellbores and
an open hole at the bottom.
(Slotted or pre-perforated casing
becomes clogged with chemical
deposits.)
8-9
-------
5. The casing itself is used as the
production string due to the high
volume and velocity of discharge.
6. Air drilling is common below seg-
ments where water-bearing forma-
tions have been cased off.
7. Due to caking and subsequent
steam blockage, drilling mud can-
not be used within the steam-
bearing formation.
Completed wells at the Geysers range
from 600 to 9,000 feet; a typical depth
and diameter configuration is shown in
Figure 8-3 (Budd, 1973: 133).
8.4.2 Energy Efficiencies
Steam losses occur during the drilling
• phase because of testing and well bleed-
ing. Data on the ancillary energy (pow-
er required at the drilling rig) are un-
available. Ancillary energy is apparently
small, relative to the energy extracted.
8.4.3 Environmental Considerations
The minor impacts of air pollutants
from motor vehicles coming to and from
the site, the acre of land cleared for the
drill site, and water contaminants from
condensed steam will not be discussed here.
The significance of venting formation dust
into the air during air drilling is not
known. The following three categories re-
present areas of concern; two are chronic
and one represents a major accident.
8.4.3.1 Chronic
8.4.3.1.1 Noise
Table 8-5 gives some noise levels for
two operations. Due to the frequency dis-
tribution, noise from muffled testing wells
does not attenuate as rapidly with distance
as air drilling noise. Air drilling noise
comes from the air compressors and dis-
charge vents. At the Geysers, well testing
may last only a few weeks; however, a time
—
"Well bleeding" refers to the vent-
ing of the steam to the atmosphere before
well equipment is attached at the wellhead.
TABLE 8-5
NOISE FROM GEOTHERMAL .OPERATIONS
Operations
During air drilling
of a well
Muffled testing
well
Distance
Measured
(feet)
25
1,500
25
1,500
Noise
Level
(decibels)
125
55
100
65
Source: Interior, 1973: Vol. II, p. V-56.
aFor comparison, jet aircraft takeoff
noise is approximately 125 decibels (dB)
at 200 feet.
lag of several years between testing and
utilization of the steam often occurs .
The wells are bled continuously during
this interium (Interior, 1973: Vol. II,
p. V-55), and noise levels are the same as
for a muffled testing well.
8.4.3.1.2 Air Pollutants
During testing and bleeding of the
wells, all the noncondensable gases con-
tained in the steam are vented to the at-
mosphere. Table 8-6 gives the gas con-
centrations in Geysers steam and total
quantities as calculated by Teknekron
(Finney and others, 1972). The total
quantities assume that venting of each
well occurs for two months prior to pro-
duction and ;that reservoir and power plant
life are 25 years.
Hydrogen sulfide (H_S), occurring as
500 ppm in the steam, is the principal air
pollutant of concern because of toxicity
and nuisance odor. Standards for oper-
ating personnel set by the Occupational
Safety and Health Administration (OSHA)
state that 20 ppm H_S in the air may not
be exceeded during a normal eight-hour day.
Although undiluted steam concentrations
are higher than this, concentrations in the
8-10
-------
* • '
t
This Interval
Drilled With
Mud
\
This Interval Drilled
With Mud Or Air
(Depending On
Formation)
This Interval
Drilled With Air
L..- •: ...0.. . .
""300 Ft., 20 In.
2000 Ft., 13 In.
Top Of Probable
Steam Zone
4000 Ft, 10 In.
— Steam Entries
Open Hole, 9 In.
Figure 8-3. Typical Well Configuration at the Geysers
Source: Adaoted from Budd. 1973: 135.
-------
TABLE 8-6
w"
GASES RELEASED TO THE AIR DURING DRILLING AT THE GEYSERS
Parameter
Steam
Carbon dioxide
Hydrogen sulfide
Methane
Ammonia
Nitrogen, Argon
Hydrogen
Concentration
(weight percent)
99.0
0.79
0.05
0.05
0.07
0.03
0.01
Quantity Released
By 1,000-Mwe Plantb
(tons per year)
533,169
4,211.5
266.4
266.4
373.1
160.1
53.4
b
Quantity
(tons per 10 2
Btu's input)
2,791.5
22.1
1.4
1.4
1.9
0.8
0.3
Sources: ^inney and others, 1972.
^Calculated from Teknekron, 1973: 144, assuming a 25 year power plant
life.
air at the Geysers range from 5 to 10 ppm
(Interior, 1973: Vol. II, p. V-78). How-
ever, the unpleasant odor threshold for
H_S has been defined by the California Air
Resources Board as 0.03 ppm. This is not
a regulation but represents the nuisance
odor threshold.
Mercury and radon gas occur in geo-
thermal steam in trace amounts. Since
methyl mercury accumulates in the food
chains, monitoring of the mercury pathway
after emission is needed. Radon is a nat-
ural radioactive material and could build
up in the environment of geothermal facil-
ities. The environmental impact of the
mercury and radon emissions is not known.
8.4.3.2 Major Accident—Blowout
Like oil and gas wells, geothermal
wells may experience blowouts. Two types
of blowouts may occur in these wells: hot
fluid may move up the well during drilling,
or the hot fluid may leave the well through
a permeable channel, traveling to the sur-
face and emerging with eruptive force. To
prevent the first type of occurrence,
blowout preventers (similar to those on
oil wells and described in Chapter 3) are
routinely used at the wellhead. The sec-
ond type of blowout prevention (again
taken from oil well technology) is in-
stallation of a suitable casing and com-
plete cement fill around the casing. Addi-
tionally, during the drilling of geothermal
wells, the drilling mud must be cool to
prevent excessive pressure development.
Several impacts may result from a
blowout:
1. Bodily injury to workers may oc-
cur at two times: at the time
of the blowout, which is sudden
and violent, and during subsequent
control attempts.
2.
3.
4.
Noise nuisance.
Air contamination from gaseous
emissions.
Possible pollution of surface and
groundwater resources.
The probability of a blowout has been
greatly reduced through improved drilling
techniques and blowout preventers. How-
ever, the potential for one is highest
during the exploratory drilling stage when
subsurface conditions are unknown. No
8-12
-------
serious blowouts have occurred since 1961
at the Geysers or Imperial Valley loca-
tions .
8.4.4 Economic Considerations
Average drilling costs are $150,000
per well in a hot water field (such as
Niland in the Imperial Valley) and $250,000
per well in the deeper steam fields (such
as the Geysers). Rex and Howell's (1973:
65) drilling cost estimates for future,
deeper wells range from $300,000 for a
6,000-foot well through $635,000 for a
10,000-foot well to $2,750,000 for a
20,000-foot well.
8.5 EXTRACTION—PRODUCTION
Production begins when the steam lines
are connected to the wellhead. The well-
head production objective is to collect
and deliver the steam free of water drop-
lets and particulate matter with little
reduction in energy.
8.5.1 Technologies
8.5.1.1 Hydrothermal Reservoirs
In hydrothermal reservoirs, pressure
differentials force the steam or water to
the surface. In vapor dominated reser-
voirs, only steam is produced. In hot
water reservoirs, the surface output is a
mixture of steam and water because 13 to 25
percent of the hot water flashes to steam
(due to pressure reductions) as it rises
in the well.
The production system at the wellhead
includes:
1. Safety features (valves which open
automatically with any pressure
increase) to relieve line pres-
sure in the event of a plant
shutdown.
2. A meter at each wellhead to mea-
sure the production rate.
3. Separating devices and vessels
for removal of liquids and solids.
In terms of production requirements,
the principal difference between vapor and
hot water reservoirs is the amount of water
and particulate separation required before
the steam can be used. In the vapor dom-
*
inated type, a centrifugal separator
(which is normally installed in the well
discharge line) removes formation dust and
corrosion particles (grit). In the hot wa-
ter types, both water and grit must be re-
moved. The water, which is often a brine,
is not utilized for power production and
thus must be discarded after separation
from the steam. This wastewater is nor-
mally collected from all the wellheads and
conveyed to reinjection wells located
throughout the field.
In hot water reservoirs, minerals are
released in the wellbore when the water
flashes to steam. These minerals (mainly
silicon [Si] and calcium carbonate [CaCO.j] )
collect in the well shaft, often to the
point where the well requires redrilling
to maintain adequate production. Unlike
drilling the original borehole, however,
redrilling can normally be accomplished
quickly and with only a light drilling rig.
Production rates at the Geysers, a
vapor dominated field, range from 40,000
pounds of steam per hour per well from
shallow wells to 320,000 pounds per hour
from deeper wells (Interior, 1973: Vol. I.
p. 11-20). The average is 150,000 pounds
per hour. In the Imperial Valley, a hot
water dominated field, the average is
440,000 pounds of steam and water per hour.
Since individual wells decline in produc-
tion with time, additional wells must be
continually drilled to maintain the steam
supply.
8.5.1-2 Dry Hot Rock Reservoirs
Dry hot rock reservoirs are being
examined for their potential, but no pro-
duction from these fields has occurred any-
where in the world. In addition to the
As it rotates, a centrifugal sep-
arator throws particles and water (which
are heavier than steam) to the outside and
the steam leaves the middle of the separa-
tor through the top or bottom.
8-13
-------
production system discussed earlier, dry
hot rock reservoirs require that the rock
be fractured and water injected to produce
the necessary steam. As shown in Figures
8-4 and 8-5, a pair of wells is needed.
Cool water is pumped into the deeper well
and circulated through the hot, cracked
zone into the higher well where it returns
to the surface. If the water returns to
the surface as steam, the steam can be used
to drive the turbine. If it returns as hot
water, the heat energy can be extracted
through a heat exchanger (see Section
8.7.1.2). In either case, the re-cooled
water is pumped down the deeper well again
to be reheated, thus effecting a closed cir-
culation system.
Two stimulation methods, differing
only in the manner in which the rock is
fractured, are being studied. Both ap-
proaches are unproven and speculative.
8.5.1.2.1 Hydraulic Fracturing
Hydraulic fracturing involves pumping
water under high pressure (7,000 pounds per
square inch [psij) (Smith and others, 1973:
258) into a well, causing the rock to crack
around the borehole. The Los Alamos Scien-
tific Laboratory has conducted an initial
test of the method at the edge of a volcanic
crater in the Jemez Mountains of New Mexico.
The test was considered successful in that
the granite fractured as expected and the
water was maintained in the rocks (Hammond,
1973: 43-44).
8.5.1.2.2 Nuclear Fracturing—The Plowshare
Geothermal System
In the Plowshare system, the fracturing
agent is an array of multiple nuclear ex-
plosives. Although the feasibility of this
method was examined by the American Oil
Shale Corporation and the Atomic Energy
Commission (AEC) in 1971, no experiments
have been conducted. Similar techniques
have been tried with very little success to
stimulate natural gas wells. Explosions
would be in the multi-megaton range, array
configurations ranging from 238 devices at
200 kilotons each to 10 devices at 1,000
kilotons each. Some of the energy from the
explosion is trapped as heat; thus, unlike
hydraulic fracturing, heat recovery for pow-
er generation involves the heat from both
the original rock and the nuclear explosion.
8.5.2 Energy Efficiencies
The recovery efficiency for-hydrother—
mal reservoirs (percent of stored Btu's de-
livered to the wellhead) is currently about
15 percent (Muffler and White, 1972: 50) .
8.5.3 Environmental Considerations
Essentially all the environmental con-
cerns resulting from production in hydro-
thermal systems are also present in hot dry
rock systems. Hydraulic fracturing results
in no new problems, but nuclear fracturing
presents a number of concerns. This section
first discusses the general area of envi-
ronmental concerns in production followed
by those specific to nuclear fracturing.
8.5.3.1 Noise
When a wellhead power plant is shut
down, geothermal steam must be vented to the
atmosphere. Noise from steam line vents
averages 100 decibels (dB) at 50 feet and
90 dB at 250 feet (Interior, 1973: Vol. I,
p. III-6). At the Geysers, the common pro-
cedure is to use a muffler attached to the
relief valves in the steam line. Where
water is abundant, discharging the flow
through a submerged outlet into a large vol-
ume of water eliminates noise.
8.5.3.2 Water and/or Brine Disposal from
the Separator
A typical brine in the Imperial Valley
consists of 250,000 ppm dissolved solids—
primarily Si, CaCO.,, sodium chloride (NaCl) ,
boron (B), ammonia, and argon (Ar). Because
these concentrations and types of materials
preclude release in fresh surface or
8-14
-------
1
Vertically Oriented
Cracks Produced By
Hydraulic Fracturing
Thermal Region,
^300° C
Figure 8-4. Dry Rock Geothermal Energy System
by Hydraulic Fracturing
Source: AEG, 1973: A.4-20
-------
Generator
Turbine
Steam Line
Figure 8-5. Plowshare Concept of Geothermal Heat Extraction
Source: American Oil Shale Corp. and AEC, 1971: 2-3.
-------
groundwater, the separated brine must be
reinjected into the formation from which it
was extracted or eliminated in some other
manner. As an indication of the problem's
magnitude, disposal of an estimated 50
billion gallons of brine per year containing
50 million tons of solids would be required
for a 1,000-Mwe plant in the Imperial Valley
(Battelle, 1973: 550). Reinjection of the
wastewater, in addition to economic and
environmental advantages over other dis-
posal methods, may have the added effects
of preventing land subsidence and facili-
tating greater steam production as noted
below.
8.5.3.3 Land Subsidence
Whenever fluids are extracted from a
groundwater reservoir (withdrawals exceed
recharge, thus decreasing the reservoir
pressure), land subsidence may occur. Fur-
ther geothermal reservoirs may be especially
susceptible to this phenomenon because of
the high mass removals required for produc-
tion. Subsidence has occurred at Wairakei,
New Zealand and Cerro Prieto, Mexico after
the extraction of geothermal water. The
Imperial Valley appears to be a likely can-
didate for subsidence, although the data
required to predict the rate is unavailable.
Minimizing subsidence requires main-
taining adequate fluid in the strata by
natural or artificial recharge (reinjection),
8.5.3.4 Earthquakes
Changes in reservoir pore pressure (due
to either injection or withdrawal of large
volumes of fluid) may result in instability
leading to earthquakes along faulted or
fractured zones. Instability due to oil
withdrawal occurred in the Wilmington Oil
Field, California (Poland and Davis). In-
stability due to injection has been docu-
mented at the Baldwin Hills Oil Field,
California (Hamilton and Muchan, 1971: 333-
;344), the Rangely Oil Field, Colorado
(Healy and others, 1970: 205-214), and at
the Rocky Mountain Arsenal, Colorado
(Healy and others, 1968: 1301-1310).
Both withdrawal and injection occur
in geothermal fields. Intuitively, one
would be expected to cancel the other.
However, evaluation of earthquake possibil-
ities in U.S. geothermal fields must await
a test case. Large withdrawals and injec-
tions are planned in the Imperial Valley;
thus, this area may provide the needed
experience. Continuous monitoring for
earthquake activity will be necessary.
8.5.3.5 Groundwater Contamination
If a fresh water aquifer occurs above
a geothermal reservoir, tapping the geo-
thermal strata could contaminate the fresh-
water strata through the well. Proper and
complete cementing of well casings in both
production and reinjection wells is re-
quired to eliminate this possibility.
8.5.3.6 Land Use
For a 110-Mwe geothermal unit, the
drill site pads and work area require 28
to 35 acres, which is 3.5 percent of the
total acreage needed for all facilities.
Of the total, however, only about 10 per-
cent is used directly (Interior, 1973:
Vol. I, p. III-6).
8.5.3.7 Air Pollutants
Venting steam to the atmosphere occurs
in the production phase only during blow-
downs . The types of air pollutants re-
leased during blowdowns are the same as
those released in the drilling phase. To-
tal quantities of air pollutants released
during production are not known. As men-
tioned previously, the problem pollutant
is H?S, which primarily creates a nuisance
odor.
Blowdowns are the release or cleaning
out of water with high solids content, the
solids accumulating each time water evap-
orates.
8-17
-------
8.5.3.8 Additional Concerns Caused by
Dry Rock Fracturing with Nuclear
Devices
8.5.3.8.1 Groundmotion
At the time of detonation of a nuclear
fracturing device, damage to natural and
man-made structures may occur as the shock
wave moves to the surface. Thus, although
the Plowshare concept of geothermal devel-
opment has been proposed for Appalachia
and the Ozarks, as well as for the western
U.S. (Horvath and Chaffin, 1971: 17-33),
the use of multimegaton nuclear devices in
most of the continental U.S. may be imprac-
tical .
8.5.3.8.2 Radiation Releases
With any nuclear explosion, whether
from fission devices or fusion devices with
fission triggers, radiation is released.
At the depths contemplated for Plowshare
activities, however, the possibility of
radiation leakage to the atmosphere should
be minimal. Also, with proper cementing
of the drill hole, radiation leakage to
the groundwater aquifers is unlikely. Al-
though the steam brought to the surface for
power production would contain small quan-
tities of radioactive isotopes, almost all
the radiation would be returned to the
fractured region with the recirculation
steam.
8.5.3.8.3 Aftershocks
Local seismic activity may be affected
by an underground nuclear explosion. Read-
justment of the surrounding ground to the
transient shock waves could theoretically
produce an earthquake. The Plowshare geo-
thermal study (American Oil Shale Corpora-
tion and AEC, 1971: 4.3.2) indicates that
the probability is "negligible in stable
areas and low, but nonnegligible in tec-
tonically active areas."
8^5.3.8.4 Volcanic Stimulation
A remote possibility exists that mol-
ten rock from an underground explosion
might be extruded onto the surface through
an older established vent. The probability
would depend on local geologic conditions
as well as the size and depth of the ex-
plosion.
8.5.3.8.5 Hydrothermal Explosion
If there were hot springs in the vi-
cinity of an explosion site, and if the
water was near its flash temperature, the
nuclear explosion could cause the whole
section of fluid to flash to steam, pro-
ducing a hydro-thermal explosion. This
possibility is considered remote because
Plowshare geothermal applications are
intended for areas where there is no nat-
ural water circulation system.
8.5.4 Economic Considerations
Armstead (1973: 163) estimates that
wellhead equipment costs—including sep-
arator, silencer, valves, pipework, and
gauges—average $35,000 per well. The ac-
tual cost of the production step (capital
and operating) is not available. Cost
factors differ with the type of reservoir:
1. Vapor dominated. These reservoirs
are currently the most economical
geothermal power sources because
all the steam produced is uti-
lized .
2. Hot water dominated. Additional
costs associated with these res-
ervoirs result from:
a. The need to reinject large
quantities of water or brine
into the formation.
b. The possible need to redrill
existing wells because of
mineral depositions downhole.
3. Dry hot rock. Additional costs
associated with these reservoirs
result from:
8-18
-------
8.6
The need to drill two wells
(an injection well and a recov-
ery well) for each production
unit.
The expense of the initial frac-
turing, whether water-induced or
by nuclear explosion.
TRANSPORTATION—STEAM TRANSMISSION
SYSTEM
8.6.1 Technologies
Four parameters characterize the geo-
thermal steam transmission system. First,
because of thermal expansion and contrac-
tion and because regular maintenance is
required, the insulated pipes must be above
ground with U-shaped expansion loops at
frequent intervals. Second, pipe sizes
must be relatively large to minimize frac-
tional losses. The present system at the
Geysers utilizes 10-inch diameter pipes at
the wellhead expanding to 36-inch diameter
pipes at the turbine inlets.
Third, steam transmission distances
from the wellhead to the power plant are
generally short due to pressure and tem-
perature loss factors. The greatest dis-
tance of any connected well at the Geysers
is 1,200 feet. Fourth, air-actuated relief
valves are used in the steam line to vent
the steam to the atmosphere in the event
of a power plant shutdown. At the Geysers,
.these valves activate automatically when
the pressure increases from the normal 100-
120 psi to 150 psi. The control valve ex-
hausts are equipped with mufflers for noise
attenuation.
8.6.2 Energy Efficiencies
o
Since 10 F or one percent of the heat
content is lost between the wellhead and
power plant at the Geysers, pipeline trans-
portation there is 99-percent efficient.
Reservoirs developed in the future
will have different transport efficiencies
because wellhead pressures and temperatures
will vary.
8.6.3 Environmental Considerations
Air pollutants released during steam
venting were discussed in Section 8.5.
Concentrations are the same here; total
quantities are not known.
The land requirement for steam lines
is the only other impact category. The
terrain is laced with exposed steam pipes
radiating from the power plant to the well-
heads. Steam lines and access roads cons-
titute 3.5 percent of the 800 to 1,000
acres needed for each 110-Mwe system at
the Geysers. Accompanying the land require-
ment is the reduction in plant and animal
habitat caused by it.
8.6.4 Economic Considerations
Cost data for the kind of pipelines
used to transmit geothermal steam are not
available.
8.7 POWER GENERATION
8.7.1 Technologies
8.7.1.1 Geothermal Steam Generator
The power generation step in the geo-
thermal resource system parallels that
described in Chapter 12, Electric Power
Generation. Commercially available geo-
thermal systems are distinctive primarily
in that they use low pressure steam tur-
bines to drive generators. Once the steam
has passed through the turbine, condensers
convert it to hot water by mixing it with
cool water. The hot water then goes to an
evaporative cooling tower where 75 percent
evaporates into the air. The remaining,
cooled Vater is recirculated through the
condenser, reinjected in the reservoir, or
both. This power generation sequence ap-
plies to both vapor dominated (Figure 8-6a)
and water dominated systems (Figure 8—6b)
where only the steam produced is used.
8-19
-------
GEOTHERMAL POWER PLANTS
Open Systems
V)
Steam to
Atmosphere
h
i
Surface
E
o
a>
>.
u.
O
a>
o
c/>
a>
T3
o
O
\
'Zon.
ie//
' X
DRY STEAM TYPE
(Geysers USA, Italy)
a
Steam
[Generator]
Z J Steam to
''Atmosphere
o
ex
&
Turbine
Hot Brine
I
8
I
Surface
a>
o
X
'Zon
/ /
Drain
a o
a,
0)
00
Closed System
Isobutane
•o
o
o
Turbine
Heat Exchanger}
Surface
V)
I
HOT WATER TYPE
(Mexico, New Zealand)
b
Figure 8-6. Geothermal Power Plant Types
Source: Interior, 1973: Vol. 2, p. V-156.
HOT WATER TYPE
(Under Development)
c
-------
The distinctive characteristics of
jeothermal power generation are:
1. No combustion of any fuel occurs
in a geothermal plant.
2. Low efficiencies result from the
low temperature and pressure of
the steam. The temperature of
steam entering the turbines at
the Geysers is 350°F at 100 psi
(75 psi in a hot water field),
while inlet temperatures for a
modern fossil-fueled plant are
1,000°F at 3,500 psi. The tur-
bine at the Geysers is about 22
percent efficient.
3. The overall plant efficiency for
geothermal power production is
approximately 15 percent, com-
pared to 35 to 38 percent for a
fossil-fueled plant. This means
that a geothermal plant requires
22,000 Btu's to generate one kilo-
watt-hour (kwh) while a modern
fossil-fueled plant requires 9,000
to 10,000 Btu's.
4. Due to long, complicated start-up
procedures, geothermal units
should operate as base-load units
rather than peak—load units.
5. Since steam cannot be transported
over long distances, geothermal
generating plants are relatively
small. At the Geysers, each plant
has a 110-Mwe capacity and con-
sists of two 55-Mwe generators.
6. A 110-Mwe station requires two
million pounds of steam per hour
or the output of 14 wells at
150,000 pounds per hour each.
7. Direct contact condensers are
used in which the steam and cool-
ing water mix directly.
8. No external makeup water for
cooling is required. The steam
flow to the turbines exceeds the
cooling tower evaporation rate;
thus, condensed exhaust is used
as cooling tower makeup water.
9. In the power generation step, non-
condensable gases are released
into the air from the condenser
and from the cooling tower.
10. At the Geysers, 75 to 80 percent
of the condensed steam evaporates
in the cooling tower; 20 to 25
percent is reinjected into the
geothermal steam-bearing formation.
11. In hot water systems, (Figure
8-66), the water or brine is
passed through a separator, which
draws off steam to drive the tur-
bine, then routed to reinjection
wells. Additional water from the
cooling tower may also need rein-
jection.
12. The minerals in the steam cause
corrosion and erosion in the
turbine, requiring continuous
and extensive maintenance.
8.7.1.2 Alternative Power Generation
Systems
In response to the desire to improve
geothermal power generation efficiency,
several modifications are being investi-
gated. One approach, now at the pilot
plant stage, uses a heat exchanger to trans-
fer the heat energy from the hot, geo-
thermal water to a second (working) fluid
which is then fed into the turbine,
(Figure 8-6c). After being exhausted from
the turbine, the working fluid is cooled
in a condenser and pumped back into the
circulatory system. Magma Power Company
of Los Angeles is developing one of these
binary fluid systems in which isobutane is
the working fluid. Construction of a 10-
Mwe pilot plant using that system is under-
way in Brady, Nevada. Also, a 0.5-Mwe
pilot plant is operational at Kamchatka,
USSR, in which Freon is the working fluid.
A second approach to hot water systems
would connect high- and low-pressure tur-
bines in tandem (Figure 8-7). Steam from
the wellhead separator would drive the
high-pressure turbine as in existing plants.
The low-pressure turbine would be driven
by both the high-pressure turbine exhaust
and steam created by flashing part of the
otherwise rejected hot brine in a flash
boiler.
A third approach focuses on develop-
ment of impulse turbines (basically modern '
water wheels) in which a high velocity jet
of water impinges on vanes or buckets at
the wheel periphery. (See Chapter 9 for
a more complete description of impulse
turbines.) To obtain the jet of water,
the geothermal water-steam mixture is ex-
panded through a converging-diverging
nozzle to a low pressure and high velocity.
This system, termed total fluid flow (Smith
8-21
-------
.Cool Water
Contact Condenser-
Low-Pressure Turbine
High-Pressure Turbine
High- Pressure Steam-
Exhaust Steam
High-Pressure
-—Water—*•
^-Separator
Flash
Boiler
Generator
Low-Pressure Steam
Water-Steam Mixture
Brine Discharge
Reinjection
Figure 8-7. Geothermal Power Plant
Source: Interior, 1973: Vol. 1, p. 11-30,
Cooling
Tower
Water
Condensate
Surplus
Water
-------
and others, 1973: 252), is being developed
by the Lawrence Livermore Laboratory prin-
cipally for the hot brine geothermal res-
ervoirs typical of the Imperial Valley.
A variation of the impulse turbine is
the helical screw expander being developed
by the Hydrothermal Power Company of
California.
8.7.2 Energy Efficiencies
The power generation step (turbine
and generator) is more efficient in vapor
dominated systems than in hot water domi-
nated systems because the steam enters at
a higher temperature and pressure. (Tur-
bine efficiency is about 22 percent at the
Geysers, as stated earlier.) Similarly,
the power generation step where the total
fluid is utilized in a heat exchanger or
impulse turbine is less efficient because
of lower temperatures and pressures. How-
ever, total efficiencies in hot water domi-
nated systems (from the wellhead through
power generation) may be equal to or great-
er than vapor dominated types because the
heat content of the water is used. Total
system efficiencies are discussed in the
summary section of this chapter.
At the Geysers, an ancillary electri-
cal energy requirement of 3.6 percent gen-
erated power is needed for coolant pumps,
cooling tower blowers, and other plant
equipment (Teknekron, 1973: 144).
8.7.3 Environmental Considerations
Teknekron calculations for power plant
air pollutant emissions and cooling tower
effluent at the Geysers are given in Tables
8-7 and 8-8, respectively. Land utiliza-
tion for each power house and cooling unit
is six acres or 0.75 percent of the gross
area required to serve a 110-Mwe plant.
Noncondensable gas fractions are
usually higher from a. hot water dominated
reservoir than from the vapor dominated
reservoir shown in Table 8-7. Noxious gas
control is expected to become a part of the
TABLE 8-7
AIR EMISSIONS AT THE GEYSERS PLANTc
Parameter
Water
(10° gallons)
Waste heat
(109 kwh)
Carbon dioxide
(tons)
Ammonia (tons)
Methane (tons)
Hydrogen sulfide
(tons)
Nitrogen, argon
(tons)
Hydrogen (tons)
Quantity
for a
1,000-Mwe
Plant
(per year)
15,800
44. 9b
631,732
54,000
40,020
39,249
24,034
7,993
Quantity
per 1012
Btu ' s Input
to Power
Plant
83
0.23
3,307
283
209
205
126
42
Source: Teknekron, 1973: Figure 9.1.
From the cooling tower and steam gas
ejectors.
3,630 Mwe of heat are rejected by a 1,000-
Mwe vapor dominated geothermal plant (a
nuclear plant rejects 2,000 Mwe).
power plant technologies for hot water type
reservoirs (Battelle, 1973: 550).
Heat rejection from the power plant
in a hot water type reservoir is expected
to be 2.5 times that from a vapor type—
10,000 Mwe rejected for a 1,000-Mwe plant
(Battelle, 1973: 550). In both cases,
rejection is into the atmosphere via a
cooling tower.
Where binary fluid systems are used,
the water is reinjected directly with fewer
gas releases to the air. However, these
systems will be even less efficient than
vapor or standard hot water systems, have
greater thermal effluents, and may require
an external source of water to condense
the working fluid.
8-23
-------
TABLE 8-8
j»
COOLING TOWER DISCHARGE PLANT REINJECTED AT THE GEYSERS
Parameter
Carbonates
(alkalinity)
Ammonia
Sulfur dioxide
Sulfate
Sulfur
Nitrate
Chloride
Calcium
Magnesium
Silicon
Boron
Total solids
from evaporation
Organics and
volatile solids
Water3 (gallons
per year)
Concentration
(milligrams
per liter)
42.9
148.3
2.0
131.2
8.3
0.1
3.5
5.3
1.0
3.7
17.1
185.2
206.3
NA
Quantity for
a 1,000-Mwe
Plant (tons
per year)
5.590
1.929
26
1,708
109
1.3
45.5
69.0
13.0
48.7
223.0
2. 414
2.690
31.2xl08
Quantity
(tons per
1012 Btu's
input to
power plant)
29.3
10.1
0.14
8.9
0.6
0.007
0.24
0.36
0.07
0.25
1.17
12.6
14.1
U
NA = not applicable, U = unknown
Source: Teknekron, 1973: 144.
aOne large injection well can accommodate the one million gallons per
day output of a 100-Mwe unit which is fed by about 14 wells.
8.7.4 Economic Considerations
Based on existing geothermal installa-
tions, Armstead (1973: 170) has estimated
power plant capital costs, including build-
ings and cooling water facilities (Table
8-9). Note that these costs are less sen-
sitive to scale than conventional thermal
plants; this is due to the small size units
required, even for large total installed
capacity.
8.8 SUMMARY
Since all technologies associated with
the utilization of geothermal energy are
located at one site and ambient conditions
are the same throughout the trajectory, to-
tal system,environmental residuals may be
\
summed. In this summary, data for the to-
tal system are presented.
8-24
-------
TABLE 8-9
CAPITAL COSTS OF
GEOTHERMAL POWER PLANTS, 1973
Size (Mwe)
20
50
100
200
Cost {per kw)
$160
140
125
110
Source: Armstead, 1973: 170.
TABLE 8-10
SYSTEM EFFICIENCY: WELLHEAD
THROUGH ELECTRIC POWER GENERATION0
Type
Vapor dominated reservoir
(Geysers )k
Hot water dominated
reservoir (flushed steam)
Binary fluid type
Total flow impulse
turbinec
Efficiency
Percent
14.7
11
11
18
Reservoir recovery efficiency included.
bleknekron, 1973: 144.
CAustin and others, 1973: 20.
8.8.1 Energy Efficiencies
Table 8-10 gives primary efficiencies
for four geothermal energy systems. Note
that the total fluid flow impulse turbine
system appears to give the best efficiency.
This system, however, is still unproven
commercially. Using steam from vapor dom-
inated reservoirs is currently the most
efficient system.
8.8.2 Environmental Considerations
Major impact categories which were
more fully discussed under each technology
are listed here, as well as quantitative
estimates of the residuals for a 1,000-Mwe
installation using several reservoir types.
In addition, Table 8-11 gives water and air
residuals on a per 10 Btu's input basis
for the Geysers. The air pollutants in-
clude those from testing and bleeding wells
during the drilling phase and those emitted
at the power plant. Excluded are emissions
that occur intermittently during the pro-
duction phase when the power plant is shut
down and pipelines are bled to the atmos-
phere. Although concentrations in the
steam are the same, total quantities emitted
during production are not known. Since the
contribution during the drilling phase is
only about one percent of that from the
power plant, and air emissions during pro-
duction are less than during drilling, the
values on Table 8-11 appear to be good
estimates of total air emissions.
8.8.2.1 Land
Between 3,000 and 5,000 acres (Battelle,
1973: 550) are required for a 1,000-Mwe
plant, with 7 to 10 percent of this directly
used for facilities. Subsidence may occur
due to removal of fluids, and seismic ac-
tivity may be generated from fluid with-
drawal and/or reinjection.
8.8.2.2 Water
No makeup water is required for vapor
dominated systems. The cooling water re-
quirement could be significant in closed
cycle designs unless air-cooled condensers
are used.
In all cases, wastewater cannot be
discharged into surface water without treat-
ment. In the U.S., wastewater is reinjected
through a well into the geothermal reservoir.
A 1,000-Mwe vapor dominated plant requires
9
disposal of 3x10 gallons per year contain-
ing 105 tons of solids (Battelle, 1973: 550).
8-25
-------
TABLE 8-11
ENVIRONMENTAL RESIDUALS FOR
GEOTHERMAL DEVELOPMENT AT THE GEYSERS'
Pollutants
b
Water
Bicarbonate
Nitrogen oxides
Sulfur oxides
Total dissolved
solids
Organics
Air
Carbon dioxide
Ammonia
Methane
Hydrogen sulfide
Quantity
(tons per
1012 Btu's)
29.3
10.1
9.7
63.7
14.1
3,329
57
210
206
Source: Calculated from Battelle,
1973: 550 and Teknekron, 1973^ 144.
Through electric power generation.
Condensate return water; it is rein-
jected. thus does not reach surface
waters.
Brine hot water dominated power plants re-
quire disposal of 5x10 gallons per year
containing 5x10 tons (Cerro Prieto) to
5x10 tons (Salton Sea) of solids (Battelle,
1973: 550).
8.8.2.3 Air
Hydrogen sulfide is the most trouble-
some air pollutant, amounting to 500 ppm
in the steam. Total release from a Geyser
type system for a 1,000-Mwe plant would
range from 3.6xl07 pounds of H_S per year
7
(100,000 pounds per day) to 7.8x10 pounds
per year (215,000 pounds per day) (Battelle,
1973: 550).
For hot water systems. H_S releases
are higher. At Cerro Prieto, H_S would be
Q
1,250,000 pounds per day or 4.56x10 pounds
per year for a 1,000-Mwe plant (Battelle.
1973: 550). This exceeds the amounts re-
leased from burning high sulfur fuel in
fossil-fueled plants.
Other chemicals (such as mercury,
radon, ammonia, boron, and flourides) drift
from the cooling towers and rain out. The
severity of these pollutants is site de-
pendent and, in the case of mercury and
radon, the impact is unknown.
Heat rejection to the atmosphere
(thermal pollution) via cooling towers is
3,630 Mwe by a 1,000-Mwe plant for the
Geysers. Up to 50,000 acre-feet of water
per year (Battelle, 1973: 550) is evapor-
ated in cooling towers. This amount of heat
is not large, but if a concentration of
1,000-Mwe plants occurred, their combined
heat output would affect local climate.
Hot water systems reject 2.5 times the heat
output of the Geysers plant.
8.8.2.4 Occupational Health
Noise pollution can be a problem, with
levels well above 100 dB for venting and
similar activities.
8.8.3 Economic Considerations
Table 8-12 summarizes the component
costs of obtaining geothermal power. Ex-
ploration costs appear high because explor-
atory drilling throughout the life of the
reservoir is included in that category.
Economies of scale are due principally to
decreases in exploration costs as they are
averaged over total kilowatts generated.
These estimates were made in 1972 and range
from $232 per kwh for a 200-Mwe installation
to $465 per kwh for a 20-Mwe installation.
Table 8-13 presents estimates on the
cost of power generation from various types
of geothermal reservoirs. Estimates are
based on 1970 or 1972 dollars and range
from five to eight mills per kwh in this
country.
8-26
-------
TABLE 8-12
1972 COSTS FOR GEOTHERMAL POWER
Component
Exploration
Drilling
Wellhead gear and
collection pipeline
Power Plant
Subtotal
20-percent interest
during construction
and contingencies
TOTAL
Cost (dollars per kilowatt)
20-Mwe
150
18
59.8
160
387.8
77.6
465.4
50-Mwe
60
16.2
53.8
140
270.0
54
324.0
100-Mwe
30
16.2
53.8
125
225.0
45
270.0
200-Mwe
15
15.7
52.4
110
193.1
39.5
232.6
Source: Armstead, 1973: 170.
8-27
-------
TABLE 8-13
j*
COSTS OF GEOTHERMAL POWER GENERATION SYSTEMS
Type
Cost
(mills per kwh)
Vapor dominated
Geysersa
Larderello, Italva
Matsukawa,
Hot water dominated .
Wairakei, New Zealand
Namafjall, Icelanda
Cerro Prieto, Mexico
pauzhetsk, USSR3
Total flow impulse turbine0
Dry hot rock systems ,
Hydraulic fracturing
15,000-foot wells
18,000-foot wells
Plowshare — nuclear fracturing6
5.0
4.8 to 6.0
4.6
5.14
2.5 to 3.5
4.1 to 4.9
7.2
8.0
4.7
8.0
6.0 to 7.5
Sources: aKoenig, 1973: 19. 1972 dollars.
Armstead, 1973: 167, 172. 1972 dollars.
cAustin and others, 1973: 34. 1972 dollars.
Smith and others, 1973: 263. 1972 dollars.
eAmerican Oil Shale Corp. and AEC, 1971: 7.47-7.51.
1970 dollars.
REFERENCES
American Oil. Shale Corporation and Atomic
Energy Commission (1971) A Feasibility
Study of a Plowshare Geothermal Power
Plant. Oak Ridge, Term.: AEC.
Armstead, H. Christopher H. (1973) "Geo-
thermal Economics," pp. 161-174 in
H. Christopher H. Armstead (ed.)
Geothermal Energy. Paris: UNESCO.
Atomic Energy Commission (1973) The
Nation's Energy Future; A Report to
Richard M. Nixon. President of the
United States, submitted by Dixie
Lee Ray, Chairman. Washington:
Government Printing Office.
Atomic Energy Commission (1974) Draft
Environmental Statement: Liquid
Metal Fast Breeder Reactor Program.
Washington: Government Printing
Office, 4 vols.
Austin, A.L., G.H. Higgens, and J.H. Howard
(1973) The Total Flow Concept for
Recovery of Energy from Geothermal Hot
Brine Deposits. Lawrence, California:
Lawrence Livermore Laboratory.
Banwell, C.J. (1973) "Geophysical Methods
in Geothermal Exploration," pp. 41-48
in H. Christopher H. Armstead (ed.)
Geothermal Enercrv. Paris: UNESCO.
Battelle Columbus and Pacific Northwest
Laboratories (1973) Environmental
Considerations in Future Energy Growth.
Vol. I:Fuel/Energy Systems;
Technical Summaries and Associated
Environmental Burdens. for the Office
of Research and Development, Environ-
mental Protection Agency. Columbus,
Ohio: Battelle Columbus Laboratories.
8-28
-------
Budd, Chester F. Jr. (1973) "Steam Produc-
tion at the Geysers Geothermal Field,"
pp. 129-144 in Paul Kruger and Carel
Otte (eds.) Geothermal Energy:
Resources, Production. Stimulation.
Stanford, Calif.: Stanford University
Press.
Bureau of Land Management (1973) Energy
Alternatives and Their Related
Environmental Impacts"Washington:
Government Printing Office.
Combs, Jim and L.J.P. Muffler (1973)
"Exploration for Geothermal Resources,"
pp. 95-128 in Paul Kruger and Carel
Otte (eds.) Geothermal Energy;
Resources. Production, Stimulation.
Stanford, Calif.: Stanford University
Press.
Department of the Interior (1973) Final
Environmental Statement for the Geo-
thermal Leasing Program. Washington;
Government Printing Office. 4 vols.
Finney, J.P., F.J. Miller, and D.B. Mills
(1972) "Geothermal Power Project of
Pacific Gas and Electric Company of
the Geysers, California" presented at
the IEEE Power Engineering Society
Summer Meeting, 1972 as cited on p. 147
in Teknekron, Inc. (1973) Fuel Cycles
for Electrical Power Generation,
Phase I; Towards Comprehensive
Standards; The Electric Power Case,
report for the Office of Research and
Monitoring, Environmental Protection
Agency. Berkeley, Calif.: Teknekron.
Godwin, L.H., and L.B. Haegler, K.L. Kioux,
D.E. White, L.D.P. Muffler, and R.G.
Wayland (1971) Classification of Public
Lands Valuable for Geothermal Steam and
Associated Geothermal Resources, USGS
Circular 647. Washington: Government
Printing Office.
Hamilton, D.H. and R.L. Muchan (1971)
"Ground Rupture in the Baldwin Hills."
Science 172 (April 23. 1971): 333-344.
Hammond, A.L. (1973) "Dry Geothermal Wells:
Promising Experimental Results."
Science 182 (October 5, 1973): 43-44.
Healy, J.H., W.W. Rubey, D.T. Griggs, and
C.B. Raleigh (1968) "The Denver Earth-
quakes." Science 161 (September 27,
1968): 1301-1310.
Healy, J.H., R.M. Hamilton and C.B. Raleigh
(1970) "Earthquakes Induced by Fluid
Injection and Explosion." Tektono
Physics 9 (March 1970): 205-214.
Hickel, Walter J. (1972) "Geothermal Energy:
-A Special Report." University of
Alaska, Fairbanks.
Horvath, J.C. and R.L. Chaffin (1971)
"Geothermal Energy, Its Future and
Economics in Atlanta." Economic
Review 21 (December 1971): 17-33.
Kilkenny, John E. (1972) "Geothermal
Energy—Part II". in National Petroleum
Council, Committee on U.S. Energy-
Outlook, Other Energy Resources
Subcommittee, U.S. Energy Outlook; An
Interim Report; An Initial Appraisal
by the New Energy Forms Task Group.
Washington: NPC.
Koenig, James B. (1973) "Worldwide Status
of Geothermal Resources Development,"
pp. 15-58 in Paul Kruger and Carel
Otte (eds.) Geothermal Energy;
Resources, Production, Stimulation.
Stanford, Calif.: Stanford University
Press.
Muffler, L.D.P. and D.E. White (1972)
Geothermal Energy Resources of the
U.S..USGS Circular 650. Washington:
Government Printing Office.
Poland, J.F. and G.H. Davis. "1969 Land
Subsidence Due to Withdrawal of Fluid."
Geological Society of America Reviews
in Engineering, Geology II, pp. 187-269.
Rex, Robert W. and David J. Howell (1973)
"Assessment of U.S. Geothermal
Resources," pp. 59-68 in Paul Kruger
and Carel Otte (eds.) Geothermal
Energy: Resources, Production, Stim-
ulation. Stanford, Calif.: Stanford
University Press.
Smith, Morton, R. Potter, D. Brown, and
R.L. Aamodt (1973) "Induction and
Growth of Fractures in Hot Rock,"
pp. 251-268 in Paul Kruger and Carel
Otte (eds.) Geothermal Energy;
Resources, Production, Stimulation.
Stanford, Calif.; Stanford University
Press.
Teknekron, Inc. (1973) Fuel Cycles for
Electrical Power Generation, Phase I;
Towards Comprehensive Standards: The
Electric Power Case, report for the
Office of Research and Monitoring,
Environmental Protection Agency.
Berkeley, Calif.: Teknekron.
White, Donald E. (1973) "Characteristics of
Geothermal Resources," pp. 69-94 in
Paul Kruger and Carel Otte (eds.)
Geothermal Energy; Resources, Produc-
tion, Stimulation. Stanford, Calif.;
Stanford University Press.
8-29
-------
CHAPTER 9
THE HYDROELECTRIC RESOURCE SYSTEM
9.1 INTRODUCTION
Water power for central station elec-
tricity generation was first used in
Wisconsin in the 1880's. By about 1940,
hydroelectric power represented 30 percent
of the installed electric generating
capacity in the U.S. (Doland, 1954: 5) .
Although the nation's hydroelectric gener-
ating capacity has continued to expand
since 1940, its relative role had declined
to 15 percent of installed generating
capacity in 1971. Several factors appar-
ently account for this relative decline
and reliance on other energy resources,
including limited availability of dam sites
and high capital costs. Although hydro-
electric facilities have always been
attractive as renewable power sources (and
frequently have multiple uses including
recreation, irrigation, and flood manage-
ment) , most dam construction projects have
sparked controversy, especially over
changed land use and impact to wildlife.
The output of hydroelectric power
plants is easily adjusted by manipulating
water flow to follow demand loads for
meeting peak electricity needs. Storage
of water for use during peak demand periods
has become increasingly significant. One
technique is pumped storage, where elec-
tricity from another power source (such as
a nuclear plant) is used to pump water
from a low basin into an upper storage
reservoir for subsequent hydroelectric
generation during peak demand periods. The
first pumped storage plant was installed in
1930; by 1970, nine pumped storage plants
were operating (AEC, 1974: Vol. IV,
p. A.3-4). A new development of appar-
ently limited potential significance is
tidal power, where daily changes in sea
level are used to drive reversing turbine-
generators. Tidal power is essentially
derived from the earth's rotation and
gravitational forces exerted by the moon
and sun. The limited potential of this
energy source is discussed briefly in
Section 9.8.
Components of conventional hydroelec-
tric resource systems consist of an initial
water source, storage reservoir, pipe
transport system, and a turbine-generator
complex that feeds electricity into a
transportation network as diagrammed in
Figure 9-1. As shown, the pumped storage
subsystem usually employs reversible pump-
generators that elevate water back through
the pipes into the reservoir for use during
the peak demand periods.
9.2 CHARACTERISTICS OF THE RESOURCE
Water is considered a hydroelectric
resource when adequate quantity or flow
rate occurs together with a suitable ele-
vation difference between the surface of
the water storage and the outlet of the
turbine discharge. This minimum elevation
or "head" is about 20 feet (FPC, 1970:
IV-1-72).
Since hydroelectric resources are
renewable, they are usually calculated as
annual rates or installed capacity for pro-
ducing power, rather than as fixed quanti-
ties of depletable fossil fuels.
9-1
-------
9.2
Water
Resource
9.3
Water
Storage
Other
Sources of
Electricity
9.3
Reversible
Pump-
Generators
9.3
Turbine-
Generators
Electricity
9.3 Transportation Lines
Figure 9-1. Hydroelectric Resource Development
-------
Hydroelectric power is also affected
by weather, and seasonal or annual changes
in precipitation can have a major impact
on available power. The variability in
weather patterns might be minimized by
weather modification, or weather modifica-
tion might augment the total quantity of
water available. For example, one study
found that snow augmentation in the Rocky
Mountains would produce substantial in-
creases in hydroelectric resources
(Weisbecker, 1974: 295. 553) . However,
attempting to modify characteristic weather
patterns on a national scale could produce
changes in the availability of water
resources, and the impacts of this are
little known.
9.2.1 Quantity of the Resources
Assuming average rainfall, the hydro-
electric potential of the U.S. can be
calculated on the basis of the average
flow of all streams and their change in
elevation. This theoretical resource has
been estimated at 390,000 megawatts-
electric (Mwe) capacity (Landsberg and
others, 1963: 416). Engineering con-
straints alone (such as difficulties in
designing turbines that can take advantage
of heads less than 20 feet) reduce this
estimate to 179,000 Mwe (AEC, 1974: Vol.
IV, p. A.3-4), and economic, environmental,
and political constraints make actual
development less than one-third of the
technically available figure. As of Janu-
ary 1971, the total installed capacity was
51,900 Mwe.
Present installations represent a
large portion of the most attractive hydro-
electric dam sites in the U.S. Thus, even
This total resource estimate excludes
Alaska and Hawaii. With a 100-percent load
factor (390,000 Mwe of continuous opera-
tion) this resource represents 3.42x10
kilowatt-hours (kwh) qper year, and this
would require 1.7x10 tons of subbituminous
coal annually or 3.0xl016 Btu's in a 39-
percent efficient power plant. Total U.S.
-energy input in 1970 was 6.9xl016 Btu's.
without such restrictive legislation as
*
the Wild and Scenic Rivers Act of 1968,
near-future development will probably
result in only small generating capacity
increases. In recent years, capacity has
increased at a rate of about five percent
per year and apparently most of this in-
crease is from new dams (NPC, 1972: 228).
9.2.2 Location of the Resources
The distribution of hydroelectric
resources is highly regional, with about
46 percent of the operating capacity in
Washington, Oregon, and California as
shown in Figure 9-2 (AEC, 1974: Vol. IV,
p. A.3-3). About half of the undeveloped
U.S. capacity is located in the contermi-
nous Pacific and Rocky Mountain states,
with another undeveloped 25 percent located
in Alaska (AEC, 1974: Vol. IV, p. A.3-5).
Although the data on potential power
reserves in Table 9-1 indicate that sub-
stantial power increases in hydroelectric
capacity are possible in several regions,
these appear to present a highly optimistic
picture.
9.2.3 Ownership of the Resources
The federal government owns about 44
percent of the installed capacity, pri-
vately owned utilities account for 33 per-
cent, and non-federal public utilities own
23 percent (FPC, 1971: 1-7-9). In addition,
a major portion of the potential resources,
especially in the western states and Alaska,
are under federal control.
9.2.4 Summary
Although the hydroelectric resource
represents a significant potential source
of power (179,000 Mwe), a number of con-
straints limit its likely development.
The Wild and Scenic Rivers Act of
1968 (Public Law 90-542, October 2, 1968)
excludes portions of 37 rivers from hydro-
electric development. However, this exclu-
sion represents only about 9,000 Mwe of
potential power (FPC, 1970: 1-7-21).
9-3
-------
CAPACITY, Mw
• 100-499
• OVER 499
Figure 9-2. Distribution of Developed U.S. Hydroelectric Resources
Source: FPC, 1971: 1-7-12.
-------
TABLE 9-1
U.S. HYDROELECTRIC POWER RESOURCES BY REGION
Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Rocky Mountain
Pacific
Subtotal
(lower 48 states)
Alaska
Hawaii
TOTAL
Potential
Power
(103 Mwe)
4.8
8.7
2.5
7.1
14.8
9.0
5.2
32.9
62.2
147.2
32.6
0.1
179.9
Developed
Capacity
(103 Mwe)
1.5
4.2
0.9
2.7
5.3
5.2
1.9
6.2
23.9
51.8
0.1
0.0
51.9
Percent
Developed
31.3
48.3
36.0
38.0
35.8
57.8
36.5
18.8
38.4
35.2
0.3
0.0
29.0
Source: Interior, 1973: Vol. I, p. IV-170.
Even if hydroelectric power continues to
expand at recent rates, there seems little
chance that its share of total U.S. energy
supply will increase.
9.3 TECHNOLOGIES
Water pressure for generating hydro-
electric power may exist as a naturally
flowing stream, but a head is most often
obtained by building a dam from which the
water is then released via a pipe termed a
penstock. As shown in Figure 9-3, this
high-pressure water drives a turbine which,
in turn, drives one or more generators to
produce electricity.
9.3.1 Dams
Impoundments for storing water are
engineered following detailed studies of
the hydrology and geology of the area.
Dams are normally built to achieve multiple
objectives, such as maintaining an adequate
head for hydroelectric generation, provid-
ing significant water storage, and serving
flood control, recreational, and water
supply objectives. Dams are classified as
low or high, run-of-river or storage, and
are of earth or concrete construction.
Low dams range up to about 100 feet
in elevation and are normally located on
rivers of relatively continuous flow.
Unless the impounded water occupies a vast
area for storage (e.g., 10 to 20 square
miles), low dams most frequently function
as run-of-river facilities with the water
running continuously through the turbines
to provide electricity for baseloads
rather than for peak demands. The primary
9-5
-------
Trash screen
Water
100 feet
I 1
Power line
Generator
Turbine
Figure 9-3. Components of a Hydropower System
Source: Creager and Justin, 1950: 193.
-------
purpose of this type of dam is to obtain a
nominal water elevation that can provide
pressure to run the turbines.
High dams range from about 100 to
about 1,000 feet in height and are capable
of storing great quantities of water.
These dams are frequently located in moun-
tains where rivers have seasonal flows
(e.g., are dependent on snow runoff).
Stored water can be controlled to provide
power during periods of peak electricity
demand.
Construction of either an earth-fill
or concrete dam of sufficient size for
power generation is a locally massive ac-
tivity. For example, a 400-foot high
earth-fill dam several miles wide takes
about five years of round-the-clock con-
struction time and requires the movement
of as much as 80 million cubic yards of
materials. While concrete dams have much
narrower base and crest, they require large
quantities of expensive steel and cement,
as well as specially prepared sand and
aggregate. Also, vast quantities of sup-
plies, equipment, and personnel are re-
quired for both types of construction.
Construction activities usually include
clearing the reservoir area and modifying
and excavating the location of the dam
site before actual building begins.
The longevity of storage capacity in
a reservoir is a function of the sediment
content of inflowing waters. The rate of
sediment addition or "siltation" varies
with location and is a particularly sig-
nificant problem in the southwest, where
rainstorms are severe and soil-stabilizing
vegetation is scarce (Creager and Justin,
1950: 167). Short of utilizing streams
with a low silt load, few methods are both
economical and effective in reducing silta-
tion. According to general guidelines
developed by the Corps of Engineers, most
reservoirs have a life expectancy of
several hundred years (Garvey, 1972: 158).
Evaporation from reservoirs can re-
sult in substantial losses of water depend-
ing primarily on temperature, humidity,
and wind conditions. Several evaporation
prevention techniques have received atten-
tion, including structural coverings and
the use of floating oils or plastics.
However, none of these techniques has been
used commercially.
9.3.2 Transport and Turbines
Penstocks, illustrated in Figure 9-3,
convey water from screened intakes (trash
racks) located near the inside base of the
dam to the turbines. The turbines are
usually located in a power house just
below the dam but may be several miles
from the reservoir if a large drop in ele-
vation from the impoundment to the turbine
is available (permitting additional head
pressure even with a low dam height).
Penstocks are usually made of steel, can
be installed either above- or belowground,
r
and, in some instances, may be tunneled
through mountains.
Both impulse and reaction turbines
are used to drive the electric generators.
In impulse turbines, a nozzle transforms
the static head into a high-velocity jet
that exerts a high pressure on cup-shaped
blades at the perimeter of the turbine as
shown in Figure 9-4. This type of unit is
called a "Pelton wheel." Impulse turbines
are normally used with heads of greater
than 1,000 feet to achieve the high ve-
locity jet (FPC, 1971: IX-1-72).
In reaction turbines, the water from
the penstocks flows directly through the
turbine, exerting pressure on the angled
blades or "vanes" as shown in Figure 9-5.
Unlike the impulse turbine, the reaction
turbine uses total blade area pressure to
turn the shaft rather than applying pres-
sure at one side or edge. Thus, reaction
turbines do not require a high velocity
jet and can operate efficiently with heads
as low as 20 feet. Some reaction turbines
9-7
-------
SHAFT TO
GENERATOR
P ELTON
WHEEL"
FROM DAM
NOZZLE
TO RIVER DISCHARGE
Figure 9-4. Impulse Turbine
Source: Adapted from Brown, 1958: Vol. II, pp. 25-90.
-------
COUPLED TO
GENERATOR
TO RIVER DISCHARGE
Figure 9-5. Reaction Turbine
Source: Adapted from Brown, 1958: Vol. II, pp. 91-132
-------
have adjustable blade pitch, and these can
efficiently utilize variable flow rates to
follow demand loads. Also, newer turbine
designs have permitted efficient and eco-
nomical use of low-head dams and may pro-
vide a method of utilizing rivers in rela-
tively flat terrain.
The generator is usually located
above the turbine and is connected to the
turbine by a steel shaft. Normally, one
generator is installed for each turbine as
indicated in Figure 9-6.
Turbine-generator units come in many
sizes but frequently have 100 to 400 Mwe
of capacity. Also, several units are
usually installed, depending on the amount
of water available. Recently, units as
large as 600 Mwe have been installed at
the Bonneville dam. Although the amount
of electricity produced from a given flow
rate and head varies from one installation
to another, typically a gallon of water per
second falling a distance of about 100 feet
will produce one kilowatt (kw). The head,
water flow, and power output of several
installations are given in Table 9-2.
9.3.3 Reversible Pump-Generators
As shown in Figure 9-7, a pumped
storage facility is a closed-cycle (except
TABLE 9-2
RELATIONSHIP OF OPERATING HEAD
AND WATER FLOW TO POWER OUTPUT
Input Characteristics
Head
(feet)
100
680
1,000
Flow
(gallons per second)
120,000
110,000
23,000
Output
Power
(megawatts)
120
680
210
Source: California Resources Agency,
1974: 13.
for evaporation and seepage losses) system.
During light load periods, water is_ pumped
from a lower reservoir to an upper (stor-
age) reservoir for use during peak demand.
With the exception of the storage basin
below the dam, the external features of
this system closely resemble those of con-
ventional hydroelectric power systems.
The major equipment difference is that the
generators are reversible; that is, they
act as motors when supplied with elec-
tricity. During low demand periods, elec-
tricity is supplied from an outside source
and the generator-motors rotate the tur-
bines (in reverse of normal operations) to
pump the water to the upper storage area.
Pumped-storage is especially attrac-
tive in conjunction with nuclear power
because it allows a nuclear plant to run
at normal operating loads consistently,
using the off-peak excess electricity to
pump water which can then supply overload
requirements during peak demands. The
effectiveness of pumped storage depends in
part on the extent of evaporative losses
and the efficiency of pumping and conver-
sion. These are discussed in the follow-
ing section.
9.4 ENERGY EFFICIENCIES
Hydroelectric facilities are among the
most efficient energy-producing systems,
primarily^because there are no chemical or
thermal energy transformations. Optimum
designs for turbine generators are about
94-percent efficient in transforming the
potential energy in water to electricity
(Doland, 1954: 27) . However, most installa-
tions have actual efficiencies of about 75
to 80 percent (Doland, 1954: 13).
Aside from the major energy require-
ments during construction, there are vir-
tually no ancillary energy requirements;
within-plant energy consumption is associ-
ated with lights, control equipment, and
maintenance and other service needs. Al-
though significant water losses can occur
9-10
-------
WATER
SUPPLY
GENERATOR
REACTION
TURBINE
ISCHARGE
Figure 9-6. Turbine-Generator Unit
-------
DURING LIGHT POWER LOAD
Pumping Cycle
High pool
DURING PEAK POWER LOAD
Generating Cycle
High pool
Figure 9-7. Pumped-Storage Operation
Source: California Resources Agency, 1973: 13
-------
in the reservoir, quantities are location
specific. Water loss data are not avail-
able for existing or potential pumped-
storage systems.
Pumped-storage facilities operate
with substantially lower efficiencies than
conventional hydroelectric plants. The
need for both pumping and generation cycles
results in a compromised generator effi-
ciency so that optimum units are about 90-
to 92-percent efficient in transforming
potential energy to electricity (FPC, 1971:
IV-1-81). In addition, the best pump
designs operate with only about 90-percent
efficiency.
Thus, the highest overall efficiency
for future pumped-storage facilities is
expected to be about 80 percent, not in-
cluding reservoir evaporative losses or
electrical transmission losses. The effi-
ciencies of most proposed plants range
from 66 to 72 percent; thus, about three
kw of energy from a fossil-fuel or nuclear
power plant will be required to generate
two kw after transmission from a pumped-
storage facility. Some existing pumped-
storage installations have efficiencies as
low as 50 percent (FPC, 1971: IV-1-81).
9.5 ENVIRONMENTAL CONSIDERATIONS
The degree to which hydroelectric
facilities affect air, land, and water
quality depends on location, design, use,
and other factors. In a number of in-
stances, impacts have been interpreted as
beneficial changes, depending on the values
against which those changes were compared.
The residuals and impacts from hydroelec-
tric facilities differ during the construc-
tion and operating phases.
9.5.1 Air
Large quantities of dust and vehicle
emissions are produced during the multi-
year construction periods, but the only
such emissions during operational periods
come from recreational vehicles (including
powerboats). However, emissions from such
vehicles are not comparable to emissions
from equal-capacity fossil-fuel plants.
Since large impoundments are sources of
water vapor, some local increases in hu-
midity may occur. However, such increases
typically represent only a small portion
of the water vapor in the atmosphere in a
given location.
9.5.2 Water
During the long construction period,
erosion, dust, and other discharges may
contribute to downstream siltation and
pollution. Following construction, the
physical and chemical characteristics of
the impounded water will differ from those
of streams or rivers previously occupying
the location. As a result, impoundments
have plant and animal life entirely differ-
ent than the streams and land they replace.
Dams act as barriers to movements of
chemicals and organisms. For example, the
reproductive activities of migrating fish
may be curtailed unless means are provided
for crossing the dam. Even then, some
losses will occur because many native
species (such as salmon) require flowing
streams for egg—laying habitats. To alle-
viate fish losses, many dams incorporate
*
ladders to allow fish to circumvent the
dam, and state or federally operated fish
hatcheries with artificial breeding ponds
help replenish losses due to reduced
breeding habitats.
Dams also change the water conditions
downstream. If little water is released
from the reservoir (during off-peak demand
periods), downstream water temperatures
may increase, making these areas unsuitable
for many fish and other biota that are suc-
cessful in colder waters. Although minimum
water flow requirements are typically es-
tablished by government agencies, down-
stream conditions still may be modified
Fish "ladders" are stepped spillways.
9-13
-------
because the water discharged through the
turbines is normally taken from the deeper,
oxygen-depleted zones of the lake. The
result can be oxygen-poor downstream condi-
*
tions during certain periods.
Although penstocks and turbines are
usually screened to prevent the entrance
**
of fish, small organisms pass through.
A significant proportion of these organisms
can be killed by impact against the cups
if Pelton wheel turbines are being used.
Apparently, reaction turbines cause less
damage to aquatic life. Other adverse
impacts to water quality from hydroelectric
facilities that reduce stream flow include
possible saline water intrusion into
waterways and decreased ability to tolerate
chemical, municipal waste, and thermal dis-
charges (Nisbet, 1974: 5).
9.5.3 Land
Typically, most impoundments inundate
extensive areas (often between 1,000 and
20,000 acres)' and, after many years, fill
through the process of siltation. As a
result, the previous topography is irre-
trievably lost. Depending on the land use,
areas adjacent to reservoirs are frequently
affected. Recreational and other uses may
damage vegetation and cause increased ero-
sion. In the California State Water Proj-
ect, for example, the use of about 10 major
reservoirs accounted for about two million
recreation man-days per year.
A variety of other uses of reservoirs
is apparent, including flood control. Al-
though this allows for occupation of pre-
viously uninhabited downstream flood
plains, periodic siltation and nutrient
addition to flood plains and river deltas
is also curtailed (Nisbet, 1974: 5). Sup-
In some instances, excess gas such as
nitrogen can be a problem. Well-aerated
spillway discharges may result in high
nitrogen content which kills fish.
fish.
Such as zooplankton and juvenile
port facilities for power generation (such
as roasts and transmission line rights-of-
way) may also affect surface use.
9.6 ECONOMIC CONSIDERATIONS
Most hydroelectric facilities require
large expenditures of capital over a multi-
year period. In the past, the low costs of
fuels and fossil fuel electric plants have
made hydroelectric generation less attrac-
tive, but this may not continue to be the
case.
Specific construction costs are vari-
able and depend on the size, type, and
location of the dam. Land and relocation
of people, buildings, and facilities can
be the greatest costs, depending on exist-
ing land-use patterns. For example, one
small hydroelectric facility in Pennsylvania
cost only $15 million for the dam in 1971,
but relocation and property adjustment
added $100 million to the total facility
cost.
An important consideration in calcu-
lating the cost per unit of power is the
annual capacity factor or percent of time
the facility is being used to generate
electricity. In recent years, this factor
has been decreasing as hydroelectric fa-
cilities are used more to satisfy peak
demands. In 1970, the annual operating
factor averaged 55 percent for U.S. hydro-
electric facilities (NPC, 1973: 26). One
proposed facility in Oregon is scheduled
to have a capacity of 1,640 Mwe and cost
$275 million. It will have an annual
capacity factor of 20 percent, which is
typical of new sites. The cost of its
peaking power will be about 10 mills per
kwh. A 1972 survey of costs of hydro-
electric power in various regions of the
country is given in Table 9-3.
Capital costs of the powerhouse and
equipment decrease with an increase in the
operating head, as shown in Table 9-4.
Average costs for hydroelectric facilities
have varied between $200 and $400 per kw.
9-14
-------
TABLE 9-3
1972 U.S. HYDROELECTRIC POWER
COSTS BY REGION
Region
Northwest
Southwest
Midwest and East
Cost
(mills per
kilowatt hour)
2.4
8.4
4.3 to 5.6
Source: NPC, 1973: 27.
TABLE 9-4
RELATIONSHIP OF 1967 CAPITAL
COST TO OPERATING HEAD
Head
(feet)
100
400
Cost per Kilowatt
130
90
(dollars)
Source: FPC, 1970: IV-1-73.
New economies are apparently being realized
through development in design and construc-
tion of dams and new tunneling and under-
ground excavation equipment.
The cost of electricity from pumped-
storage includes both the cost of building
and operating the facilities and the price
of the input electricity. These costs are
substantial because about three kw of
electricity must be purchased for each two
kw produced when pumping, generation,
transmission, and evaporative losses are
taken into consideration. However, the
cost of facilities alone, in terms of in-
stalled generating capacity, is relatively
low; a 1967 estimate ranged from $150 to
$220 per kw (NPC, 1973: 29). One study
found that pumped-storage facilities were
used about 17 percent of the time and
resulted in an average 1967 cost of 3.4
mills per kwh in addition to the purchase
price of the electricity (NPC, 1973: 28).
9.7 TRANSPORTATION
Transportation of electric power is
described in Chapter 12.
9.8 TIDAL POWER
The tidal bulge in the ocean is caused
by the gravitational pull of the sun and
the moon. The bulge of water "moves" as
the earth rotates and creates a changing
water elevation which might be used to
drive a turbine. One estimate suggests
that the tidal energy in the ocean, if
accessible, would provide about half the
energy needs of the entire world (AEC,
1974: A.6-8). On the open ocean, the
average surface height change is only about
two feet, but when the tidal bulge impinges
against shorelines, this height change may
be accentuated. In locations where a bay
may partially enclose the tidal wave, sig-
nificant amplification of the wave height
may occur; in several bays in the world,
these resonance amplifications increase
the height to 50 or more feet.
At present only two tidal sites have
been developed: one in the Soviet Union
with 400-kw capacity and one in France
with 240,000-kw capacity (Quigg, 1974: 32).
Two locations near or in the U.S. have been
considered as potential resources: the
Bay of Fundy area and Turhagain Bay in Cook
Inlet, Alaska (AEC, 1974: A.6-8). The Bay
of Fundy has nine sites primarily in
Canadian waters that have a potential power
capacity of 29,000 Mwe, and the Alaskan
site has the potential for about 9,500 Mwe.
Utilizing these resources would re-
quire construction of dams across bays and
installation of turbines. In the past,
economic analysis has usually found that
the estimated cost was too high for the
production of intermittent power. The
potential environmental and social impacts
9-15
-------
have not been assessed. Because of limited
resource availability, and relatively high
cost in recent comparisons with more con-
ventional energy resources, tidal power
will not be an important contribution to
energy production in the future.
REFERENCES
Atomic Energy Commission (1974) Draft
Environmental Statement; Liquid Metal
Fast Breeder Reactor Program.
Washington: Government Printing
Office, 4 vols.
Brown, J. Guthrie, ed. (1958) Hydro-
electric Engineering Practice. Vol. II.
London: Blackie and Son, Ltd.
California Resources Agency, Department of
Water Resources (1974) California
State water Project, Annual Report
1973. Sacramento: California
Resources Agency.
Creager. William P. and Joel D. Justin
(1950) Hydroelectric Handbook.
New York: John Wiley.
Department of the Interior (1973) Final
Environmental Statement for the Geo-
thermal Leasing Program. Washington:
Government Printing Office, 4 vols.
Doland, James J. (1954) Hydro Power Engi-
neering. New York: The Ronald Press.
Federal Power Commission (1971) 1970
National Power Survey. Washington:
Government Printing Office, 4 vols.
Garvey, Gerald (1972) Energy, Ecology.
Economy; A Framework for Environ-
mental Policy. New York: W.W.
Morton and Company.
Landsberg, Hans H., Leonard L. Fischman,
and Joseph L. Fisher (1963) Resources
in America's Future; Patterns of
Requirements and Availabilities.
Baltimore: Johns Hopkins.
National Petroleum Council, Committee on
U.S. Energy Outlook (1972) U.S. Energy
Outlook. Washington: NPC.
National Petroleum Council, Committee on
U.S. Energy Outlook, Other Energy
Resources Subcommittee, New Energy
Forms Task Group (1973) U.S. Energy
Outlook; New Energy Forms.
Washington: NPC.
Nisbet, Ian C.T. (1974) "Hydroelectric
Power: A Non-Renewable Resource?"
Technology Review 76 (June 1974: 5,
64).
Quigg, Philip W. (1974) "World Environment
Newsletter: Alternative Energy
Sources." Saturday Review/World 1
(February 9, 1974: 29-32).
Weisbecker, L.W. (1974) The Impacts of
Snow Enhancement. Norman, Okla.:
University of Oklahoma Press.
9-16
-------
CHAPTER 10
THE ORGANIC WASTE RESOURCE SYSTEM
10.1 INTRODUCTION
Until the recent energy shortages,
organic and inorganic wastes had been con-
sidered primarily as disposal (and thus
energy consuming) problems in the U.S. Al-
though electricity has been generated for
years in Europe by burning municipal wastes,
U.S. efforts have been directed primarily
at environmental considerations, such as
reducing landfill and pollution problems
by recycling of inorganic wastes. Further,
these recycling efforts have generally been
minimal because they were not economically
feasible as long as raw materials were
plentiful and energy for their conversion
into finished goods was cheap.
Now, the cost of energy has increased
dramatically, some raw material shortages
have occurred, and the Environmental Pro-
tection Agency (EPA) and other government
agencies have given increased attention
and funding support to the development of
technologies for recycling and energy con-
version. As a result, a number of tech-
nologies for converting organic wastes into
usable energy are now in the pilot plant or
early commercial operation stages. Figure
10-1 is a diagram of the basic technologi-
cal processes involved in the conversion
of organic wastes to liquid or gaseous
fuels. As indicated, the wastes must be
collected and prepared (shredded and sorted)
before the materials can be fed to the con-
version process that is to be used. Gen-
erally, the sorting process consists of
removing the inorganic matter, which is
then disposed of or transported for re-
cycling.
In the following discussion, recycling
is covered only where a specific technology
is designed for total resource recovery;
that is, where recycling and fuel conver-
sion cannot be separated in the descrip-
tion. Further, although recycling paper
(as well as metal and glass) may ultimately
be more economical than converting it to
fuel, the technologies here assume that
paper will be incorporated into the organic
waste and converted to fuel. No paper
recovery technologies are discussed. If
paper were recovered from the wastes, the
heat content of the remaining waste would
be low, precluding conversion to a fuel
form.
Although the total amount of energy
potentially available from organic wastes
is small (two percent of U.S. energy input
in 1971), utilization of these wastes re-
sults in several positive environmental
effects: all processed products are low
in sulfur, and all processes reduce the
landfill requirement.
10.2 RESOURCE
10.2.1 Characterization
Of the solid waste generated in the
U.S., only the dry organic solids portion
can be converted into energy; thus, the
dry organic solids are the resource. These
solids include portions of municipal refuse,
manure, agricultural crop waste, logging
and wood manufacturing residues, sewage
sludge, and some categories of industrial
waste. These wastes are, in effect.
10-1
-------
10.3
Collection
10.4
Preparation
10.4
Hydrogenation
10.4
Pyrolysis
Gas
Monsanto
BuMines
Liquid
Garrett
10.4
Byconversion
Liquid _
10.5
Direct
Burning
Electricity
Figure 10-1. Organic Waste Resource Development
-------
TABLE 10-1
COMPOSITION OF MUNICIPAL REFUSE
MATERIALS AND CHEMICALS
Materials
Paper
Food
Glass
Ferrous and
nonferrous metals
Miscellaneous—
grass clippings,
rags, leather,
etc.
Chemicals
Volatile matter
Fixed carbon
Ash and metals
Moisture
Weight
Percent of
Total Refuse
53.0
8.0
8.0
7.0
24.0
52.7
7.3
20.0
20.0
Source: Anderson, 1972: 3.
residuals from other processes. Assuming
that the overall patterns of society do
not change, the organic waste system rep-
resents a renewable resource which is
expressed as a rate rather than a fixed
amount.
Table 10-1 gives the composition of
municipal refuse by product and by chemical
constituent. The 60 percent of the refuse
that is combustible (volatile matter plus
fixed carbon) has a heat content of 8,700
Btu's per pound, while the heat content of
raw refuse is 5,200 Btu's per pound. For
comparison, low rank lignite has a heat
content of 6,000 Btu's per pound. Although
only 53 percent (by weight) of the refuse,
paper products provide 71 percent of the
potential heat (Kasper, 1973: 3-4) . Thus,
paper recycling precludes u-se of the waste
for fuel.
10.2.2 Quantity
Since organic waste is a renewable
resource, the terms "reserve" and "re-
source" are expressed here as a rate (per
year). In compliance with the general
definition of a reserve (the portion that
is economically recoverable under present
market conditions), the organic waste
reserve is that portion of the dry solids
available at a point relatively near a
market (urban area). The organic waste
resource is the total amount of dry organic
solids generated per year. These are dif-
fuse and cannot now be collected economi-
cally.
Table 10-2 gives organic waste reserve
resource estimates in tons. To put these
numbers in perspective. Table 10-3 indi-
cates the percent of total U.S. energy
input (1971) that the various fuel forms
of these wastes represent. If all were
collected, reserves could represent two
percent of total U.S. energy input in one
of the following forms: if converted into
crude oil, reserves would represent three
to four percent of crude oil demand; if
converted to natural gas, they would rep-
resent six percent of natural gas demand;
and if burned directly, they would repre-
sent 6,8 percent of electricity generation
in 1971 where they would be substituting
for eight to nine percent of coal demand.
If all organic waste resources could be
collected and converted, they could provide
13 percent of U.S. energy input.
10.2.3 Location and Ownership
As noted above, the key to economic
recovery of organic wastes is concentration
and near-market location. For manure, this
means the quantity generated by animals in
confinement (feedlots). Agricultural crop
wastes are usable only at specific proces-
sing plants such as canneries and mills.
Urban refuse and sewage sludge are concen-
trated in large cities, and wood manufac-
turing wastes include those from sawmills
(bark and sawdust).
10-3
-------
TABLE 10-2
QUANTITIES OF ORGANIC WASTE BY SOURCE
(DRY WEIGHT IN TONS PER YEAR)
Source
Urban refuse
Manure
Logging and wood
manufacturing
Agricultural crops
and food wastes
Industrial wastes
Municipal sewage
solids
Miscellaneous
TOTAL
Reserve
1971
(Readily
collectable)
71.0b
26.0
5.0
22.6
5.2
1.5
5.0
136.3
Resource
1971
(Total
amount
generated)
129
200
55
390
44
12
50
880
Resource
1980
(Total
amount
expected)
222
266
59
390
50
14
60
1,061
Source: Anderson, 1972: 8, 13.
aDoraestic, municipal, and commercial components of this waste
amount to 3.5, 1.2, and 2.3 pounds per capita per day respectively.
Based on the 100 largest population centers in the U.S.
The process system that generates the
waste is usually responsible for its dis-
posal; that is, cities "own" municipal
refuse and feedlot operators "own" the
manure. Presently, these owners must pay
for disposal (landfills) and, therefore,
are willing to donate the wastes to any
conversion operation, such as those
described here. Thus, the owner pays for
collection but saves the cost of disposal.
As processing technologies develop, the
waste eventually may be sold to the pro-
cessor.
10.3 COLLECTION
Collection of refuse is not unique to
energy recovery programs. Wastes require
collection and disposal whether or not any
resource utilization is or will be involved.
10.3.1 Technologies
Except in the case of sewage, collec-
tion is by trucks ranging up to the 30-
cubic-yard packer types. Frequency of
collection in municipalities is usually
once or twice a week. Feedlot waste is
often piled near the lot but may be trucked
away for fertilizer.
10.3.2 Energy Efficiencies
Although no quantitative estimates are
available, truck fuel is a major ancillary
energy requirement in .solid waste collec-
tion and the reason that diffuse sources
are not collected. However, if processing
facilities are located within an urban
area, as opposed to landfills which require
long hauls, this ancillary fuel requirement
could be reduced.
10-4
-------
TABLE 10-3
PERCENT OF VARIOUS FUELS POTENTIALLY REPRESENTED BY ORGANIC WASTES
Reserve
(Readily
collected
now)
Resource
1971
Resource
1980
Quantity
Dry Organic
Wastea
(106 tons
per year)
136.3
880.0
1,061.0
Percent
of Total
Energy
Input1"
in 1971
2
13
NA
Percent
of Crude
Oil
Demandc
3-4
19
NA
Percent
of
Natural
Gas
Demand
6
39
NA
Percent
of 1971
Coal
Demand6
8-9
50
NA
Percent
of 1971
Electricity
Con sumpt i on ^
7
44
NA
NA
not applicable
Anderson, 1972: 8, 13.
Based on an average heat content for refuse of 5,260 Btu's per pound (Kasper,
1973: 7) and a 1971 U.S. energy input of 69.0xl015 Btu's (Senate Interior
Committee, 1971: 85).
Tlydrogenation process at 1.25 net barrels per ton of dry wastes (Anderson,
1972: 3) and a 1971 crude oil demand of 5.7 billion barrels.
Conversion to methane at 5 cubic feet per pound dry waste (Anderson, 1972: 3)
and a 1971 natural gas demand of 23 trillion cubic feet.
Q
Coal demand of 600 million tons per year.
Based on 2,000 billion kilowatt-hours consumed.
10.3.3 Environmental Considerations
No residuals are generated except
those that already result from current col-
lection and transportation practices.
These include nuisance collection noise
and air pollutants from the vehicles.
10.3.4 Economic Considerations
Of the total cost of solid waste
management in municipalities now, collec-
tion accounts for about 80 percent and dis-
posal about 20 percent (EPA, 1974: 7). In
large cities where land is expensive or
incinerators are used, disposal cost may
be a slightly higher percentage. Collec-
tion cost, however, is the major economic
factor governing the utilization of diffuse
waste sources. Nationally, collection
costs averaged $18 per ton in 1971 {EPA,
1974: 7). Total collection cost in munici-
palities in the U.S. was $2.16 billion in
1971 (120 million tons collected) and is
expected to be $2.7 billion by 1980.
10.4 PROCESSING
Processing includes the technologies
necessary to convert the organic waste into
a usable fuel form (Figure 10-1). This
trajectory includes some waste preparation
or beneficiation and one or two technolo-
gies for converting the waste to oil, gas,
or electricity.
10-5
-------
10.4.1 Preparation
10.4.1.1 Technologies
The technologies employed in organic
waste preparation are designed to ready the
waste for further processing and to recover
salable products. Some combination of
three units—hammermill shredders, magnets,
and air classifiers—is normally used.
Shredding reduces waste volume and pro-
duces a uniform particle size, thus always
precedes further processing. Sorting, by
either magnets or air classifiers or both,
usually precedes conversion to a fuel (the
Monsanto pyrolysis unit is an exception).
Several sizes of hammermills may be
required to achieve the desired particle
size. Depending on the conversion process
to be used, input particle size may range
from about eight inches (primary shredder
in the Wilmington, Delaware direct burning
system) to less than 0.015 inch (secondary
shredder in the Garrett pyrolysis process).
Sorting techniques are primarily de-
signed to recover metals and glass. Fer-
rous metals are recovered by passing large
magnets over the waste stream, usually
after primary shredding.
Shredded waste is further sorted into
two fractions—a light combustible waste
fraction (organics) and a heavy waste frac-
tion (inorganics)—by air classification.
In this method, air is forced up through a
cylindrical container at the velocity re-
quired to force light materials out the
top while allowing heavy materials to fall
to the bottom. Glass falls to the bottom
and is recovered as part of the inorganic
heavy fraction.
In addition to these three fundamental
units, other units may be employed for a
higher degree of process feed preparation.
Dryers precede secondary shredding in the
Garrett Research and Development Company,
Inc., pyrolysis system to remove moisture
and thus enhance particle separation. A
proprietary froth-flotation glass reclama-
tion unit developed by Garrett recovers
over 70 percent of all glass with a product
purity of 99.7 percent (Mallan and Finney,
1973: 58). Separation and recovery of
nonferrous metals with high energy electro-
magnetic separators have been examined
under an EPA grant at Vanderbilt University
(Appell and others, 1971). Garrett is
also examining new techniques for recover-
ing aluminum, copper, and brass (Mallan
and Finney, 1973: 58) .
10.4.1.2 Energy Efficiencies
According to Garrett {Mallan and
Finney, 1973: 58), each hammermill unit
requires about 50 horsepower-hours per ton
of waste processed. This is an ancillary
energy requirement of about 130,000 Btu's
per ton per shredder; that is, 1.3 percent
of the energy in the incoming waste is
required for each shredder.
10.4.1.3 Environmental Considerations
Residuals include: the metals and
glass products, which are salable; the
light fraction coming out of the air
classifier, which is the feed for the
energy conversion process; and other prod-
ucts, ranging from 6 to 15 percent of the
incoming stream, which require landfilling.
Although decibel measures are not
available, hammermill shredders are noto-
riously noisy. Mufflers mitigate the
problem somewhat.
10.4.1.4 Economic Considerations
Economic estimates are given on a
total plant basis in the conversion process
section. Hammermill shredders contribute
significantly to the operating costs of a
system. Garrett expects the costs for
daily maintenance of the primary and sec-
ondary shredders to be $1.60 per ton (1971
dollars) in a commercial scale plant
(Mallan and Finney, 1973: 59) .
10-6
-------
10.4.2 Hydrogenation to Oil
10.4.2.1 Technologies
Hydrogenation is basically the addi-
tion of hydrogen to an organic molecule to
achieve a higher hydrogen-to-carbon ratio.
The process for hydrogenating organic waste
is an outgrowth of research on the hydro-
genation of coal, which is discussed in
the liquefaction technologies section of
Chapter 1.
In the Bureau of Mines (BuMines) pro-
cess, carbon monoxide and water (steam) are
introduced at high temperatures (570 to
750°F) and pressures (3,000 to 4,000 pounds
per square inch tpsi]) in the presence of
a catalyst to react with the organic waste
(Appall and others, 1971: 17-18). Residence
time in the reactor is about two hours.
Although the chemical aspects of the pro-
cess are not yet completely understood,
basically a water-gas shift reaction occurs
where the carbon monoxide and water react
to form hydrogen and carbon dioxide. Some
of this hydrogen is then added to the
organic compounds during their conversion
to oil.
The BuMines pilot plant (Appell and
others, 1971), which is a 480-pounds-per-
day continuous reactor, has obtained two
barrels of oil per ton of dry organic
material with 0.75 barrel per ton required
for the process, resulting in a net yield
of 1.25 barrels per ton. The oil has a
heating value of 15,000 Btu's per pound
(Friedman and others, 1972: 15). For com-
parison, number six fuel oil has a heating
value of 18,200 Btu's per pound. A full
scale commercial plant is expected by 1980
(Hammond and others, 1973: 75).
10.4.2.2 Energy Efficiencies
The hydrogenation process has a pri-
mary energy efficiency of 39 percent
based on the net amount of oil output, and
a heating value for the dried organic
waste of 8,000 Btu's per pound.
10.4.2.3 Environmental Considerations
Residuals include a carbon residue,
water and its pollutants, and carbon diox-
ide. Total quantities are not known. The
process water requires treatment. The oil
has a low sulfur content (0.1 percent), a
desirable feature for fuel oils.
10.4.2.4 Economic Considerations
The largest cost items for the hydro-
genation process are the capital investment
in high-pressure equipment and the cost of
carbon monoxide, which is now about one
cent per pound (Friedman and others, 1972:
16). Income from the oil, assuming $4 per
barrel (1972 market price) and 1.25 barrels
per ton, would be $5 for each ton of dry
refuse processed.
BuMines cost data indicate a break-
even size of 900 tons of prepared organic
waste per day. This is roughly equivalent
to the amount of daily waste generated by
300,000 people. However, these data are
not directly comparable to other processes
given here because the estimate includes
an income of $5 per ton refuse disposal
charge to the community. Rather than pay-
ing $5 per ton for landfilling, the munici-
pality pays the processor $5 per ton for
disposal. In addition, the municipality
is assumed to pay for collection. Although
hydrogenation appears to be the most expen-
sive conversion technique (Hammond and
1.25 barrels of oil per ton of dry
waste at 5xl06 Btu's per barrel (Hammond
and others, 1973:,75) is equivalent to an
output of 6.25x10° Btu's per ton of dry
waste. At 8,000 Btu's per pound, the dry
waste has a heating value of 16xl06 Btu's
per ton. Dividing the output by the input
(6.25xl06 Btu's per ton divided by 16x10°
Btu's per ton) yields 0.39.
10-7
-------
others, 1973: 76), it does produce a high-
grade product in terms of heat content.
In 1972, Congress appropriated
$200,000 to increase the BuMines plant
capacity to one ton of animal waste per
day and $300,000 for design studies of a
$1.75 million plant to convert wood pro-
cessing and logging wastes to oil.
10.4.3 Biocbnversion
10.4.3.1 Technologies
Bioconversion is the conversion of
organic wastes into methane (natural gas)
through the action of microorganisms.
Chemically, this is the reduction of com-
plex organic compounds to simpler, more
stable forms, including methane. (The
reaction occurs spontaneously in the ab-
sence of oxygen.) Technologically, the
process is simple, occurring at atmos-
pheric pressure and temperatures in the
range of 70 to 120 F. Bioconversion is
part of the present sewage treatment pro-
cess where it is termed anaerobic diges-
tion. There, the methane is flared off or
trapped and burned to heat the sewage.
Sewage^digestion, however, is designed to
maximize the rate of breakdown rather than
methane production.
Conditions that maximize methane pro-
duction should yield about 70 percent
methane and 30 percent carbon dioxide,
plus small amounts of ammonia, hydrogen,
mercaptans, and amines. Gas production is
estimated to be 10,000 cubic feet (cf) of
methane per ton of organic material with a
heat content of 1,000 Btu's per cf (Hammond
and others, 1973: 77).
The National Science Foundation (NSF)
has begun funding research in anaerobic
digestion with a $600,000 three-year feasi-
bility study at the University of
Pennsylvania. If feasibility is proven, an
NSF-funded pilot plant could be in opera-
tion in five years and a demonstration
plant in 8 to 10 years.
10.4.3.2 Energy Efficiencies
Primary efficiency is about 60 per-
*
cent. Unlike other calculations in this
description, this efficiency estimate does
not account for process heat required.
The process heat requirements are unknown
but would reduce the efficiency estimate.
10.4.3.3 Environmental Considerations
Residuals include sludge and water,
both of which require treatment and dis-
posal, and cleaning these by-products is a
major block to immediate use of bioconver-
sion. Organic sludge may amount to 40
percent of the starting material and would
require landfilling. The water requires
treatment by conventional sewage treatment
processes. The methane must be scrubbed
for removal of carbon dioxide, water,
hydrogen sulfide, and ammonia.
10.4.3.4 Economic Considerations
No economic estimates have been made
for bioconversion. The economics of sludge
disposal may play a major role in deter-
mining the viability of the process
(Hammond and others, 1973: 78).
10.4.4 Pyrolysis
Pyrolysis is the chemical decomposi-
tion of waste without oxidation. It in-
volves heating material at atmospheric
pressure in the absence of air. The advan-
tages of pyrolysis are that it occurs at
atmospheric pressure (eliminating the
expense of high pressure equipment) and
requires neither hydrogen nor catalysts.
The disadvantage is that several fuel forms
are produced; low-Btu gas and char are
always produced, and a heavy, tar-like oil
may be produced. Product distribution
among the three fuel forms is primarily
Output energy is 10,000 cf per ton
at 1,000 Btu's per cf or 10 million Btu's
per ton. Input energy is 8,000 Btu's per
pound or 16 million Btu's per ton. Ten
million divided by 16 million equals 0.625.
10-8
-------
determined by the moisture in the incoming
waste stream.
Although a number of research groups
are investigating pyrolysis, the three
processes discussed here are the most
fully developed. The first process, devel-
oped by Monsanto Enviro-Chem Systems, Inc.,
is currently at a commercial scale level
(1,000 tons per day) and produces gas and
char. The second process, developed by
Garrett, is at a demonstration scale level
(200 tons per day) and produces oil, gas,
and char with the objective of maximizing
oil production. The third process is the
BuMines pilot plant operation which pro-
duces oil, gas, and char in various quanti-
ties depending on the feed type, prepara-
tion, and pyrolysis temperature.
10.4.4.1 Technologies
10.4.4.1.1 Monsanto LANDGARD System
The Monsanto LANDGARD System is de-
signed for total resource recovery; thus,
fuel (gas) is only one of the products.
Figure 10-2 illustrates the discrete steps
in the Monsanto system. Basically, the
shredded waste is pyrolyzed at temperatures
reaching 1,800°F. The product is a low-Btu
gas (100 Btu's per cf) which is burned in
an afterburner (gas purifier of Figure
10-2), thus generating steam. Magnetic
metals, a glassy aggregate, carbon, char,
and ash are separated after the pyrolysis
process.
A 35-ton-per-day prototype plant in
St. Louis County has demonstrated the
feasibility of the system. A LANDGARD
plant being constructed in Baltimore will
handle 1,000 tons per day of solid waste,
and start-up was planned for late 1974.
Products in the Baltimore facility
are: 80 tons per day of carbon, char, and
ash; 70 tons per day of ferrous metals;
170 tons per day of glassy aggregate; and
4.8 million pounds per day of steam (Dis-
trict Heating, 1974: 2). The char and ash
will probably be landfilled (six percent
of original volume) but may be mixed with
sewage sludge for fertilizer use. The
ferrous metal and glassy aggregate (used
for street paving) are salable. The steam
is sold to Baltimore Gas and Electric Com-
pany for use in its steam distribution
system. The City of Baltimore has con-
structed a one-mile, 12-inch steam main at
a cost of $1,101,000 to connect the
LANDGARD plant to the Baltimore Gas and
Electric facility.
Although Baltimore's system appears
quite feasible, the general LANDGARD system
has several limitations. The impurities in
the gas preclude its use as a gas turbine
fuel. And, since this gas is low in heat
content, it must be used at a point close
to the sourdte of production. Producing
steam directly in an afterburner has this
same transportation limitation. There is
the possibility of upgrading the gas to
high-Btu fuel (see Chapter 1 for high-Btu
gasification), but this has not been in-
vestigated.
10.4.4.1.2 Garrett Pyrolysis
As in the Monsanto process, the py-
rolysis system developed by Garrett is
designed for total resource recovery. In
the Garrett process, however, the principal
fuel recovered is oil, which is given the
trade name Garboil. A schematic of the
resource recovery plant is shown in Figure
10-3. Initially, the raw refuse is
shredded (reduced to one- to two-inch
particles), dried, and air-classified to
remove most of the metals, glass, and other
inorganics.
However, the key to the Garrett pro-
cess is the secondary shredding and drying.
To maximize oil yields, a finely divided
and dry organic feed to the pyrolysis
reactor is essential. The secondary
shredder (hammermill) reduces the feed
particles to one-eighth inch by one-eighth
inch maximum size before a pyrolysis
10-9
-------
clean air to atmosphere
gas scrubber
gas purifier^ heat
exchanger
I
stack
fan
water clarifier
^magnet
solids water quenching
Figure 10-2. LANDGARD Solid Waste Disposal System
Source: District Heating, 1974.
-------
primary shredder
air classifier
product recovery
receiving pit
glass & metal
processing system
glass ?'
.'x metals
secondary
shredder
Figure .10-3. Garrett Pyrolysis System
Source: Garrett Research and Development Company, Inc
gas to recycle
pyrolysis reactor
waste to
disposal
^pyrolytic
oil
-------
TABLE 10-4
PRODUCTS FROM GARRETT PYROLYSIS
Oil
Gas
Char
Water
Magnetic
metals
Glass
Amount of
Product
(percent
by weight)
40
27
20
13
NA3
NAa
Amount Produced
(per ton
raw refuse)
1 barrel
unknown
160 pounds
NA
140 pounds
120 pounds
1
Heating Value
4.78xl06 Btu's
per barrel
500 Btu1 s per
cubic foot
9,000 Btu's
per pound
NA
NA
NA
NA = not applicable
Sources: Mallan and Finney, 1973: 59-61; Hammond and others,
1973: 75.
Removed from waste prior to pyrolysis.
reactor rapidly heats the particles to 500
to 900 degrees Centigrade (°C) (930 to
1,650 F). Oil, gas, and char (as well as
water) are collected and separated from
the pyrolysis reactor. All the gas and
one-third of the char are used to supply
heat for the dryer and pyrolytic reactor.
Pertinent characteristics of the products
are given in Table 10-4. The oil has the
desirable characteristic of being only
0.1- to 0.3-percent sulfur by weight.
A four-ton-per-day pilot plant at
LaVerne, California has proven the feasi-
bility of the Garrett pyrolysis system.
Presently, a 200—ton—per—day recovery plant
is being built to handle the waste from
Escondido and San Marcos, California. Oil
is to be sold to the San Diego Gas and
Electric Company.
Although Garboil can be used as a fuel
supplement in electric power generation, it
has different chemical properties than
crude oil and could not be refined in a
typical oil refinery to produce gasoline,
lubricating oils, etc. In addition
Garboil is quite viscous, requiring heating
to temperatures around 160 F before it can
be pumped (Mallan and Finney, 1973: 60).
The char produced has a 40-percent ash
content, which limits its usefulness as a
fue1 supplement.
10.4.4.1.3 Bureau of Mines Pyrolysis
Unlike Garrett and Monsanto, BuMines
has not been designing total resource re-
covery systems but has been examining, at
a pilot plant, the pyrolysis reaction of
various waste materials, including munici-
pal wastes, tires, and cow manure. Shred-
ding and separation precedes the process,
which essentially consists of an electric
furnace, cylindrical steel retort, con-
densing and scrubbing train to recover
products, and gas metering and sampling
10-12
-------
TABLE 10-5
PRODUCTS FROM BuMINES PYROLYSIS
(PER TON OF REFUSE)
Gas (cubic feet)
Oil (gallons)
Char (pounds)
Heating values.
Gas (Btu's per
cubic foot)
Char (Btu ' s
per pound)
Municipal Waste at 1,650°F
Wet Feed
(43.3 percent
moisture)
17,741
0.5
200
447
5,000
Dry Feed
(7.3 percent
moisture)
18,470
16.2
200
545
5,000
Passenger
Tires at
1,650°F
11,460
51.5
1,046
700
13,500
Cow Manure
at 930 to
1,650°F
10,983
17.4
702
500
7,380
Source: Schlesinger and others, 1972: 425-427.
devices. Products include three fuels
(gas, oil. and char) as well as an ammonium
sulfate solid and an aqueous solution con-
taining organic compounds.
Products from pyrolysis of several
waste streams are given in Table 10-5.
Lower temperatures yield less gas and more
oil; similarly, dry feed yields the most
oil. The heating value of the gas averages
500 Btu's per cf; thus, enough gas is pro-
duced in all cases to supply the required
process heat of two million Btu's per ton
of refuse. Although excess gas could be
burned industrially, it has no value for
home heating because it does not burn prop-
erly when mixed with natural gas and the
carbon monoxide content exceeds allowable
limits.
10.4.4.2 Energy Efficiencies
The efficiency of the Monsanto
*
LANDGARD pyrolysis process is 71 percent,
**
of the Garrett process is 45.7 percent,
and of the BuMines process is 68.5
* 6
Energy In: Raw Refuse: 10.5x10
Btu's per ton times 312,500 tons per year
equals 3.28xl012 Btu's per year.
Fuel Oil: 2.2x10 gallons per year times
0.14xl06 Btu's per gallon equals O.SlxlO12
Btu's per year.
12
Energy Out: 2.54x10 Btu's per year
(District Heating. 1974: 2).
Efficiency: 2.54x10 divided by
(3.28xl012 plus 0.31xl012) equals 0.707.
** 6
Energy In: 10.5x10 Btu's per ton.
Energy Out: 1 barrel per ton at
4.8xl06 Btu's per barrel.
Efficiency: 4.8x10 divided by
lO.SxlO6 equals 0.457.
10-13
-------
percent using a wet feed and 59.1 percent
**
using a dry feed. The calculations in-
clude process heat requirements, which are
7.1 gallons of number two fuel oil per ton
(one million Btu's per ton) of solid waste
for the Monsanto process, the entire amount
of gas produced in the Garrett process, and
two million Btu's per ton for the BuMines
process.
Other ancillary energy requirements
include the electricity needed for the
shredders, fans, and separating units.
Shredders require 127,350 Btu's per ton of
refuse shredded. The total electric re-
quirement for the Garrett process is
960,000 Btu's (as oil) per ton of refuse
or 9.1x10 Btu's per 10 Btu's of refuse
input to the process (Mallan and Finney,
1973: 58).
Electricity requirements for the
Monsanto and BuMines systems are not known.
10.4.4.3 Environmental Considerations
Nonsalable residuals resulting from
pyrolysis include stack gas, water from
the pyrolysis reactor, and char. The char,
amounting to 0.06 to 0.07 ton per ton of
raw refuse, is landfilled. The pyrolytic
water, which contains organic compounds
and a very high biochemical oxygen demand,
requires secondary sewage treatment. In
Energy In: 9.65x10 Btu's per ton in
feed plus 2xl06 Btu's per ton in process
heat.
Energy Out: 7.93x10 Btu's per ton
in gas plus O.lxlO6 Btu's per gallon times
0.5 gallon in oil.
Efficiency: 7.98 divided by 11.65
equals 0.685.
Energy In: 17.78x10 Btu's per ton
in feed plus 2x10^ Btu' s per ton in pro-
cess heat.
Energy Out: 10.07xl06 Btu's per ton
in gas plus 0.1x10 Btu's per gallon times
16.2 gallons in oil.
Efficiency: 11.69 divided by 19.78
equals 0.591.
the Monsanto process, the water is continu-
ously clarified in a closed recirculatory
system. No effluent is discharged. The
Garrett process, as applied in San Diego,
will discharge water into the munici-
pality 's sewerage system.
The stack gases require cleaning for
removal of particulates and certain com-
pounds, such as the methyl chloride that
results from the pyrolysis of chlorinated
plastics. Scrubbing transfers the unde-
sired compounds to water. Combustible
gases are burned (by the Monsanto process
in the afterburner and by the Garrett pro-
cess in the process heater) to oxidize
odor-causing compounds and incinerate par-
ticulates. In the Garrett process, stack
gases are cooled and vented through a bag
filter. Particulate emissions are 0.08
grain per cf or 6,400 grains per ton of
raw refuse. In the Monsanto process, gases
are cleaned by passing them through a water
spray scrubbing tower. In addition, the
gases are passed through a dehumidifier to
suppress formation of a steam plume.
In general, a pyrolysis plant is a
low-profile, light-industry installation
suitable for an urban area.
10.4.4.4 Economic Considerations
The Monsanto LANDGARD system in
Baltimore (1,000 tons per day) is being
built at a total 1974 cost of $16,177,000
(EPA, 1974: 96). Financing for this in-
stallation is a combination of a $6 million
grant from EPA, $4 million from the
Maryland Environmental Service, and
$6,177,000 from the city treasury.
The Garrett pyrolysis system being
built in San Diego County (200 tons per
day) will have a 1974 cost of $4,012,710
with EPA providing $2,962,710, San Diego
County providing $600,000, Garrett Research
and Development providing $300,000, and
San Diego Gas and Electric providing
$150,000 (EPA, 1974: 96).
10-14
-------
TABLE 10-6
PYROLYSIS COSTS AND REVENUE
(DOLLARS PER TON)
Source of
Estimate
Monsanto Process
Monsantoa
Kasper13
EPA3
Garrett Process
Garrett6
Rasper13
EPAa
Cost
9.60
11.00
10.50
5.40f
7.35
9.79r
Revenue
4.70
4.67C
4.35
5.70
6.10
3.87^
Net Cost
4.90
6.33
6.15
-0.30
1.25
5.92
District Heating. 1974: 2, 1973 cost data.
Kasper, 1973: 19, using 1973 cost data.
The steam from one ton of solid wastes
sells for $3.89, the iron for $0.44, and
the glassy aggregate for $0.34.
^PA, 1974: 95-96, using 1974 cost data.
SMallan and Finney, 1973: 62, using 1971
cost data.
u'he large difference in these estimates
is partially attributable to the size of
facility assumed (see text) .
"The oil from one ton of solid wastes was
estimated in 1972 to be worth $2.27, the
iron worth $1.28, and the glass worth
$0.32.
Table 10-6 gives cost and revenue
estimates per ton of incoming raw refuse
from three data sources for the Monsanto
pyrolysis process and the Garrett process.
Approximately half of each cost estimate
is operating cost and half is plant cost
amortization. The apparent discrepancy
between the Garrett and EPA cost estimates
for the Garrett process is attributable to
economies of scale; Garrett's estimates
are figured for a 2,000-ton-per-day plant
while EPA's are based on the 200-ton-per-
day plant being built in San Diego County.
In addition, Kasper uses an amortization
of capital costs over a 10-year period
with a five-percent interest rate while
Garrett uses 25 years at six percent.
BuMines preliminary cost data for their
pyrolytic process are in the same range as
the Monsanto and Garrett processes
(Schlesinger and others, 1972: 425-427).
Depending on the size of the installa-
tion and assumptions made, the net cost of
pyrolysis may be anywhere from zero to
$6.33 per ton (Table 10-6). In no case
does this net cost reflect the savings in
reduced landfill requirements, which now
average $4 to $5 per ton nationally and
are higher in urban areas where land costs
are high.
10.5 DIRECT BURNING FOR ELECTRICAL
GENERATION
10.5.1 Technologies
Prepared {shredded and sorted) solid
waste is burned as a supplementary fuel in
existing coal- and gas-fired boilers in
St. Louis (Union Electric). The boilers
there' are 20 years old and were designed
to burn pulverized coal and gas. The only
boiler modification required was addition
of a solid waste-firing port in each cor-
ner (Lowe, 1973: 7). Each boiler now has
four coal-firing ports, one solid waste-
firing port, and five gas-firing ports in
each corner. Burning organic waste saves
Union Electric 300 tons of coal per day by
supplying 10 percent of the heat require-
*
ment for two 125-Mwe boilers.
In Wilmington, Delaware, a processing
facility to be operating by 1977 will pro-
cess 500 tons of municipal waste, 15 tons
of industrial waste, and 230 tons of sewage
sludge (eight percent solids) per day.
Most of the organic waste will be used as
a fuel supplement for electric power gen-
eration in an existing oil-fired boiler.
The dewatered sewage sludge and some or-
ganic waste will be converted to compost.
650 tons per day of raw waste are pre-
pared, producing 520 tons of supplemental
fuel per day with a heating value after
preparation of about 5,800 Btu's per pound
(EPA, 1974: 91).
10-15
-------
and the industrial waste will be pyrolyzed.
Pyrolysis gases will be burned for heat to
dewater the sludge (EPA, 1974: 92).
Boilers that burn oil can be adapted to
burn solid waste only if they were origin-
ally .designed to burn coal and have bottom
ash and fly ash (particulate) handling
equipment. This is the case in Wilmington.
10.5.2 Energy Efficiencies
Although data are not available, elec-
tric power generation with organic waste
making up some part of the fuel is pre-
sumably about as efficient as fossil fuel-
fired plants (35 to 38 percent).
10.5.3 Environmental Considerations
Principal residuals from electric
power generation are particulates, nitrous
oxides, and sulfur dioxide as air pollu-
tants and ash as solids (see Chapter 12 for
a detailed discussion). When supplementing
a coal-fired facility with organic wastes,
particulate and nitrous oxide emissions are
about the same as with coal alone (EPA,
1974: 92). (When supplementing an oil-
fired plant with solid waste, particulate
emissions may be greater than for oil
alone.) However, sulfur emissions are
lower. The sulfur content of organic waste
*
averages 0.12 percent by weight which is,
on an equivalent heat basis, the same as
burning bituminous coal with a 0.3 percent
sulfur content (EPA, 1974: 96).
In the St. Louis system, boiler bottom
ash is sluiced to a settling pond. Of the
raw incoming waste, 13 percent (by weight)
requires lahdfilling. This reduces the
land requirement for solid waste disposal
by as much as 95 percent (Lowe, 1973: 7).
0.12 percent sulfur equals 0.23 pound
of sulfur per million Btu's (EPA, 1974:
96). Federal emission standards for a
coal-fired plant are 0.4 pound of sulfur
per million Btu's and for an oil-fired
plant are 0.4 pound of sulfur per million
Btu's.
10.5.4 Economic Considerations
Total 1974 cost for designing con-
structing, operating, and evaluating the
St. Louis system (including shredding and
sorting) through August 1974 was
$3,888,544. EPA has paid $2,580,026 or
66.3 percent of the total. Of the non-
federal share. Union Electric provided
$950,000, and the City of St. Louis pro-
vided $358,518 (EPA, 1974: 91).
In Wilmington, the total cost for
design, construction, operation, and
evaluation to May 1978 is expected to be
$13,760,000 with EPA paying $9,000,000 or
65.4 percent (1974 dollars). The State of
Delaware is providing the remaining $4.76
million (EPA, 1974: 93).
Projected 1974 system costs in St.
Louis and Wilmington are given in Table
10-7. In St. Louis, the system costs the
city $4.00 per ton but saves the electric
company $3.15 per ton for an overall net
cost of $0.85 per ton.
Although the Wilmington system appears
very expensive ($15.24 per ton), it pro-
vides (through other processes) disposal
of industrial wastes and sewage sludge as
well as municipal wastes.
10.6 TRANSPORTATION OF PROCESSED PRODUCTS
Methods of transporting pipeline gas
produced by bioconversion or oil produced
from hydrogenation are the same as those
discussed in the crude oil and natural gas
resource descriptions. Due to its low
heat content, pyrolysis gas requires utili-
zation close to production.
10.7 SUMMARY
Organic waste reserves (that portion
which is readily collectable) constitute
about two percent of total U.S. energy in-
put. Converted to oil, this amount would
represent three to four percent of the
total 1971 U.S. demand; converted to natu-
ral gas, it would represent six percent of
the gas demand; used as a coal replacement.
10-16
-------
TABLE 10-7
1972 COSTS FOR DIRECT BURNING OF ORGANIC WASTE
Capital investment
Annual costs
Amortization and interest
Operation and maintenance
Total
Costs per ton of input waste
Before revenue
Revenue
Metal
Fuel
Other
Revenues subtotal
Net cost per ton
St. Louis System
Preparation
Costs Charged
to the
Municipality
$2,394.000
227.000
618.000
$ 845,000
$5.00
1.00
NA
NA
$1.00
$4.00
Burning Costs
Charged to
Union
Electric
$600.000
120,000
20.000
$140,000
$1.05
NA
4.20
NA
$4.20
$-3.15
Net = $0.85
Wilmington System
$11.200.000
1,400,000
1. 520,000
$ 2.920,000
$22.40
1.25
0.57
5.34a
$ 7.16
$15.24
NA = not applicable
Source: EPA, 1974: 92-93.
aincludes humus at $2.35 per ton, nonferrous metal at $2.40 per ton, glass at $0.49 per
ton, and paper at $0.10 per ton.
it would represent eight to nine percent
of the coal demand, thus being capable of
generating 6.8 percent of electricity con-
sumption on a yearly basis. Although
power from organic wastes could never be-
come the primary fuel source, it could be
a significant supplement in selected areas.
10.7.1 Energy Efficiencies
Table 10-8 summarizes efficiencies
for processing organic wastes. Process
heat requirements are included in the pri-
mary efficiency. Ancillary energy require-
ments, in particular electricity needed
for each process, are unknown. Those tra-
jectories that reduce the number of steps
are the most efficient; for example, direct
burning for electrical generation rather
than conversion to oil and gas followed by
burning for electrical generation.
10.7.2 Environmental Considerations
Residuals from hydrogenation, biocon-
version, and pyrolysis of organic wastes
are similar. Water, containing a high bio-
chemical oxygen demand, requires treatment.
This may be done on site, or the water may
be routed to the municipalities' sewage
treatment plants. Stack gases require
scrubbing for particulate removal in all
cases. Solids requiring landfilling are
char from hydrogenation and pyrolysis, and
sludge from bioconversion. Char quantities
range from 0.07 to 0.1 ton per ton of raw
10-17
-------
TABLE 10-8
ENERGY EFFICIENCIES FOR
UTILIZATION OF ORGANIC WASTES
Process
Hydrogenation
Bioconversion
Pyrolysis, Monsanto
Pyrolysis, Garrett
Pyrolysis, BuMines
Direct burning
Product
oil
natural gas
low-Btu gas
(space heating)
oil
gas, oil
electricity
Efficiency3
(percent)
39
unknown0
71
45.6
59 to 68
NA
Trajectory
Efficiency^
(processing
and electric
generation)
(percent)
15
unknown
NA
17.3
22 to 26
34
NA = not applicable
Includes process heat.
Process efficiency times 38 percent electric power generation efficiency.
Q
Process heat requirement is unknown; efficiency without process heat is
62.4 percent.
refuse or 6,000 to 9,000 tons of char per
10 Btu's input to the process.
Three positive impacts result from
any of the processes:
1. All process products are low in
sulfur. Raw refuse is 0.12 per-
cent (by weight) sulfur or 0.23
pound of sulfur per million Btu's
which is, on a heat content basis,
equivalent to coal with a 0.3 per-
cent (by weight) sulfur content.
2. All processes reduce the landfill
requirements, some by as much as
95 percent.
3. There is an unmeasured social
benefit of resource recycling for
future societies.
ages $6.00 per ton and $0.85 per ton for
direct burning in St. Louis (1972 dollars) .
Both estimates include separation costs.
For comparison, the cost of incineration
is about $8 per ton (1972 costs)
(Schlesinger and others, 1972: 425-427),
and the cost of landfill disposal is $4 to
$5 per ton (1973 costs). Direct burning
in an existing coal-fired plant appears to
be the most economical because it takes
advantage of an established system for
providing, distributing, and marketing the
products.
10.7.3 Economic Considerations
Costs for hydrogenation and bioconver-
sion are unknown due to their very prelimi-
nary stage of development. After account-
ing for revenues received from salable
products, the net cost of pyrolysis aver-
10-18
-------
REFERENCES
Anderson, Larry L. (1972) Energy Potential
from Organic Wastes: A Review of the
Quantities and Sources. Bureau of
Mines Information Circular 8549.
Washington: Government Printing
Office.
Appell, H.R. , Y.C. Fu, Sam Friedman, P.M.
Yavorsky, and Irving Wender (1971)
Converting Organic Wastes to Oil;
A Replenishable Energy Source, Bureau
of Mines Report of Investigations
7560. Pittsburgh, Pa.: Pittsburgh
Energy Research Center.
District Heating (1974) "Baltimore's
Resource Recovery Centre: The World's
First Pyrolysis Solid Waste System."
District Heating (January-February
1974).
Environmental Protection Agency (1974)
Second Report to Congress: Resource
Recovery and Source Reduction.
Washington: Government Printing
Office.
Friedman, Sam, Henry H. Ginsberg, Irving
Wender, and Paul M. Yavorsky (1972)
"Continuous Processing of Urban Refuse
to Oil Using Carbon Monoxide." Paper
presented at The 3rd Mineral Waste
Utilization Symposium, IIT Research
Institute, Chicago, March 14-16, 1972.
Garrett Research and Development Company,
Inc., "Solid Waste Disposal and
Resource Recovery," process descrip-
tion. La Verne, Calif.: Garrett
Research and Development Company, Inc.
Hammond, Allen L., William D. Metz, Thomas
H. Maugh II (1973) Energy and the
Future. Washington: American Asso-
ciation for the Advancement of
Science.
Kasper, William C. (1973) Solid Waste and
Its Potential as a Utility Fuel.
Office of Economic Research Report
No. 18. Albany, N.Y.: New York State
Public Service Commission.
Lowe, Robert A. (1973) Energy Recovery from
Waste: Solid Waste as Supplementary
Fuel in Power Plant Boilers. Environ-
mental Protection Agency Solid Waste
Management Series. Washington:
Government Printing Office.
Mallan, G.M., and C.S. Finney (1973) "New
Techniques in the Pyrolysis of Solid
Wastes," pp. 56-62 in AIChE Symposium
Series, Vol. 69, No. 133.
Monsanto Enviro-Chem (1973) "'LANDGARD1
System for Resource Recovery and Solid
Waste Disposal: Process Description
for Baltimore, Maryland." St. Louis:
Monsanto Enviro-Chem Systems, Inc.
Schlesinger, M.D., W.S. Banner, and D.E.
Wolfson (1972) "Pyrolysis of Waste
Materials from Urban and Rural
Sources," pp. 423-428 in Proceedings
of the Third Mineral Waste Utilization
Symposium. IIT Research Institute,
Chicago, March 14-16, 1972.
Senate Committee on Interior and Insular
Affairs (1972) The President's Energy
Message. Hearing. 92nd Cong., 1st
sess., June 15, 1971, pp. 85-104, as
cited in Anderson, Larry L. (1972)
Energy Potential from Organic Wastes;
A Review of the Quantities and
Sources, Bureau of Mines Information
Circular 8549. Washington: Govern-
ment Printing Office.
10-19
-------
CHAPTER 11
THE SOLAR RESOURCE SYSTEM
11.1 INTRODUCTION
The inflow of solar energy warms the
earth's surface and atmosphere, drives the
winds and ocean currents, and produces
(through photosynthesis) all the food,
fuel, and free oxygen on which life de-
ft
pends.
In the past, solar radiation provided
a major share of the total energy used in
preindustrial and early industrial soci-
eties. As wind, it served to grind the
grain, pump the water, and drive the ships.
Converted to firewood, it heated homes and
public buildings and provided steam for
industrial heat engines. As the forests
disappeared, both the industrial and pri-
vate sectors turned to coal and other
fossil fuels to meet the increasing demand
for cheap energy.
A return to some limited reliance on
direct solar energy would represent a turn
toward familiar and essentially benign
technologies and an expansion of existing
energy sources. As recently as 1969, wood-
burning in the U.S. provided as much total
energy as all the operating nuclear power
plants (Commerce, 1973: 518, 630) .
Figure 11-1 is a flow diagram of four
potential sources of solar energy: direct
radiation, the wind, organic fuels, and
ocean thermal gradients. Each has its own
unique characteristics and its own poten-
tial time scale. None is likely to have
any major impact in the next 10 years.
Gravitational pull from the sun also
accounts for a small percentage of tidal
movements (see Chapter 9).
although the expected R&D activity in this
field will insure that a number of pilot
programs will be in operation before 1985.
In the following section, each of the
four major solar energy sources is dis-
cussed in detail, along with the antici-
pated energy efficiencies, environmental
impacts, economics, and other factors asso-
ciated with specific applications.
11.2 DIRECT SOLAR ENERGY
11.2.1 Resource Base
The sun radiates energy in a rela-
tively narrow band of wavelengths between
0.22 and 3.3 microns. This results from
the transformation of a portion of the
sun's mass from hydrogen to helium through
the fusion of hydrogen nuclei (see Chapter
7). It has been estimated that the trans-
formation of only one percent of the sun's
mass from hydrogen to helium would supply
enough energy to keep it shining for one
billion years.
At the outer limits of the earth's
atmosphere, the solar radiation falling on
a surface perpendicular to the sun's rays
has an intensity of 442.2 Btu's per hour
per square foot. This quantity, known as
the solar constant, is reduced by an aver-
age of 54 percent in the earth's atmos-
phere, where 35 percent is reflected back
into space and 19 percent is absorbed and
then reradiated to space. The total amount
of solar radiation intercepted by the earth
is 5.9x1017 Btu's per hour. But at the
surface of the earth, this is reduced to
11-1
-------
1.3
11.2
Solar
Resources
11.3
Wind
Windmills
1 1 O
Mechanical Work
Electric
Genertor
Electricity
11.2
Direct
Radiation
Thermal
. Lo Temp
.Hi Temp
. Ultra Hifernp
Electric
Generator
Photovoltaic
Terrestrial
.Space
1.5
1.5
11.4
Heat
Electricity
Electricity
Ocean
Thermal
Gradients
Heat
Engine
Electric
Generator
Electricity
Organic
Farms
ortation
j Transportati
Solid
L
on
11.4
Pyrolysis
Hydrogenation
Bio-Conversion
1
Liquid
Gaseous
Fuel
FueL
Fuel
fc
See
Electrical
Generation
Section
Figure 11-1. Solar Energy Resource Development
-------
2.4x10 Btu's per year or roughly 18,000
times as much energy as is consumed in all
man-made devices currently in use through-
out the world (Encyclopaedia Britannica.
1973: Vols. 20 and 21).
At any given point on the earth, the
amount and intensity of solar radiation
varies with season, latitude, and atmos-
pheric transparency. Figure 11-2 shows
the distribution of solar energy in the
U.S. As might be expected, the maximum
intensities occur in the southwestern por-
tions of the U.S. Table 11-1 shows the
seasonal variation in local solar energy
for a variety of U.S. cities. The annual
average for all locations listed is 1,450
Btu's per square foot per day. As a mea-
sure of the potential for solar energy, all
the electricity used in the U.S. in 1972
could have been generated from a land area
of about 3,000 square miles in Arizona,
assuming a generating efficiency of 12 per-
cent. For a typical city of one million
in the northern part of the U.S., the
electrical needs could be satisfied by a
tract of land less than five miles on a
side.
However, such simplified examples
ignore the very real problems associated
with the use of solar energy. Because of
the variability of solar radiation, either
energy storage or backup power is needed
to provide failure-free capacity at night
or when the sun is obscured. A second
major problem is the low density of solar
radiation, which requires large land areas
devoted to energy collection. Finally,
solar energy sources tend to operate at
relatively low efficiencies. Thus, even
though the fuel itself is free, the capital
investment for collecting, storing, and
transforming the energy is high.
Solar radiation in the U.S. has been
studied and mapped in great detail over the
years. It appears that the information now
available is adequate to characterize the
potential of solar radiation for any spe-
cific location in the U.S.
11.2.2 Technologies
Solar radiation may be used either to
heat an object directly, as with a home
water heater, or to heat a working fluid
that may be used to develop power in a
heat engine or to transfer heat to the
ultimate receiver.
Solar energy through thermal conver-
sion may be divided into three categories:
low-temperature direct radiation, high-
temperature concentrators, and ultrahigh-
temperature concentrators. A fourth cate-
gory includes the various applications of
photovoltaic cells in the conversion of
energy directly to electrical power.
11.2.2.1 Low-Temperature Collectors
About 6 to 10 times the amount of
energy required to heat the average build-
ing in the U.S. radiates down on the build-
ing from the sun each year (Professional
Engineer, 1973: 15). If this radiation is
allowed to enter the building through win-
dows in winter and is shaded from the
interior in summer, fossil fuels are con-
served. If the solar radiation is used to
heat a working fluid, a major share of the
energy requirements of the house can be
satisfied by various conversion processes,
including the generation of electricity.
Space heating by solar energy has been
used in a variety of structures over the
years, but the long-term and continuous
experience with solar power generation is
limited.
When solar radiation falls on a dark-
ened surface, the shortwave radiation is
absorbed and converted into heat. The
temperature of the surface will rise until
it can dissipate energy at the same rate
at which energy is being absorbed. If the
surface is painted black and is covered by
a sheet of clear glass, spaced about
11-3
-------
Distribution of Solar Energy over the
United States*
^Figures give solar heat in Btu/ft per day
Figure 11-2. Distribution of U.S. Solar Energy
Source: AEC, 1974: A.5-7.
-------
TABLE 11-1
SOLAR RADIATION AT SELECTED LOCATIONS IN THE UNITED STATES DURING 1970
Location
Seattle-Tacoma,
Washington
Fresno,
California
Tucson,
Arizona
Omaha ,
Nebraska
San Antonio,
Texas
Lakeland,
Florida
Atlanta,
Georgia
Burlington,
Vermont
Average Total Daily Insolation (Btu's per square foot per day)
Jan.
278
710
1,110
777
862
1,029
873
581
Feb.
688
1,117
1,391
1,110
1,103
1,436
1,203
781
Mar.
1,069
1,709
1,750
1,284
1,432
1,480
1,288
1,088
Apr.
1,354
2,205
2,202
1,576
1,506
1,983
1,635
1,384
May
1,950
2,609
2,435
1,939
1,906
2,079
1,991
1,447
June
2,065
2,579
2,449
2,165
2,083
2,042
1,854
1,758
July
2,105
2,576
2,190
2,002
2,176
1,883
1,917
1,587
Aug.
1,750
2,412
1,983
1,865
2,057
1,680
1,628
1,835
Sept.
1,217
2,050
1,735
1,280
1,587
1,639
1.591
1,195
Oct.
747
1,425
1,587
944
1,388
1,436
1,021
759
Nov.
370
910
1,221
581
1,310
1,302
955
444
Dec.
229
614
870
596
784
1,169
714
448
Annual
Average
1,152
1,743
1,745
1,351
1,516
1,597
1,389
1,109
Source: Commerce, 1970: Vol. 21, Nos. 1-12.
M
H
I
-------
one-half inch above the surface, it will
reach an equilibrium temperature of 225
to 250°F under favorable conditions. This
temperature can be maintained for about
five hours during the middle of the day,
dropping off rapidly to ambient temperature
at sunset and not increasing again until
well after sunrise (Yellot. 1973: 5).
The glass cover is important because
solar radiation can pass quite readily
through the glass but the longwave radia-
tion from the sun-heated surface cannot
pass outward through the same glass. The
cover also reduces convection and conduc-
tion losses to the atmosphere.
One of the earliest uses of low-
temperature solar radiation was to distill
salt from brackish water in arid regions.
Modern developments throughout the world
have made well-designed installations com-
petitive with other means of producing
drinking water in sunny climates. They are
not presently adaptable for producing water
on the scale needed for irrigation or large
industrial demands.
Other applications for low-temperature
solar collectors are based on the use of a
working fluid (normally water) to furnish
space and water heating directly, as shown
in Figure 11-3. Hot water can also provide
energy for thermally-driven refrigeration
units and, when kept in insulated tanks,
can store heat during the night and when
the sun is obscured. Low-boiling-point
fluids, such as Freon, have also been used
to generate vapor to operate a heat engine.
The engine in turn may be used to drive a
pump or electrical generator unit.
11.2.2.2 High-Temperature Concentrators
To attain temperatures higher than
200 to 250°F, the sun's rays must be con-
centrated by the use of reflecting surfaces.
Parabolic troughs—two-dimensional para-
bolic mirrors—with water pipes running
along their focal lines are relatively
simple and have been most commonly used for
this purpose. Steam temperatures on the
order of 600 F are possible from these
units. For maximum efficiency, the units
must be capable of following the sun, since
only direct solar rays will be reflected
to the foci.
The resulting high-temperature steam
is both more efficient and more versatile
than the output of flat plate collectors.
It can be used for space heating, for
absorption refrigeration, for industrial
process steam, and for the development of
mechanical or electrical power in Rankine
or Brayton cycle engines, as shown in
Figure 11-4. The technologies required
for both the collection and use of high-
temperature solar energy are well devel-
oped. Their technical feasibility has
been established by a variety of experi-
mental and operational units during the
past 100 years. Until recently however,
the economic aspects of solar concentrators
have suffered by comparison with those of
fossil-fueled power sources. Although the
gap is narrowing, a considerable disparity
still exists.
The use of solar-generated steam has
been proposed for large-scale electrical
generation by combining the output of a
large number of collectors to drive con-
ventional turbine generators. If the plant
is to be able to operate continuously, some
type of energy storage will be required.
Molten salts, in which the energy is stored
as heat of fusion, have been suggested for
this purpose. The principle is shown in
Figure 11-4. If storage is not used, it
will b,e difficult to integrate the discon-
tinuous and variable output into the exist-
ing demand system, although the statistical
predictability of solar radiation on a
nationwide scale should permit some limited
reliance on central solar power plants.
11.2.2.3 Ultrahigh-Temperature Concen-
trators
Extremely high temperatures (approach-
ing 5,000 F) may be obtained through the
11-6
-------
Winter Operation
I
I
Cool
Water
Hot
Water
Gas or oil (used
only when solar
is depleted)
Auxiliary
Heater
To House Hot
Water System
Hot Water
Storage
Tank
Pump
Summer Operation
I
I
I
f
Automatic
Valve
Hot Water
Warm Air
(winter)
Cool Air
(summer)
House Rooms
Air Returns
r
Cool
Water
Return
Blower
From Cold Pump
Water Supply
Figure 11-3. Residential Heating and Cooling with Solar Energy
Source: AEC, 1974: A.5-17.
Hot
Water
c
3
or
o
-i
•o
o'
V J
8
5"
«o
Warm
Water
Return
-------
Steam,
Sun's Rays
Solar Collector
Condenser
'ater
Molten Salt Heat Storage
Figure 11-4. Solar Thermal-Conversion Power System
Source: AEG, 1974: A.5-9.
-------
use of precisely contoured parabolic re-
flectors. These reflectors differ from
trough-type concentrators by being true
paraboloids which reflect all incoming
solar energy to a single point. Although
solar furnaces are being used for research
in many parts of the world, none are cur-
rently being used for power generation.
The largest such furnace in the world today
is a French installation in the Pyrenees
which, on a clear day, can attain a thermal
rating of 3.4x10 Btu's per hour and tem-
peratures of 3,000°F. It is used primarily
for research on high-temperature refractory
materials.
The major advantage of extremely high-
temperature solar concentrators is their
potential for high conversion efficiencies
in steam engines or steam turbines. Care-
fully designed heat absorbers located at
the focal point are capable of heating
flow-through working fluids to temperatures
of 1,500 F or more.
11.2.2.4 Photovoltaic Cells
The photovoltaic converter, a silicon
solar cell, was developed in 1954 by Bell
Laboratories as an outgrowth of previous
work on the transistor. It converts solar
radiation directly into electrical current.
Used first on an American satellite in
1958, solar cells have now become the major
source of power for space vehicles which
are required to operate reliably for long
periods of time. Their high cost has lim-
ited their use for terrestrial power gen-
eration and results from the fact that
individual silicon cells must be made from
single crystals. It has been estimated
that solar cell costs must be reduced by a
factor of 1,000 before they become econom-
ically feasible for large-scale power
generation.
Figure 11-5 shows cost projections for
solar cells as a function of total produc-
tion (Glaser, 1973: 9) . Recent successes
in the growth of continuous crystals and
the abundance of the silicon base material
give some hope for achieving appreciably
lower costs in the short-term future.
To avoid the losses due to atmospheric
attenuation and the nighttime outage, pro-
posals have been made to place large arrays
of solar cells in a near-equatorial syn-
chronous orbit, where the sun would shine
on them nearly 100 percent of the time
(Brown, 1973: 39). The direct current (DC)
power obtained from the photovoltaic arrays
would then be converted into microwave
power, beamed to large receivers on the
surface of the earth, and there converted
back to DC power. The concept envisions
32 square kilometers of solar cells in each
satellite station and an area of 55 square
kilometers for each ground receiver. It
has been estimated that a satellite system
of this size would provide 10,000 mega-
watts-electric (Mwe). The principle is
illustrated in Figure 11-6.
The technical developments required
to make satellite power stations feasible
are so formidable that such stations are
not likely to play any part in supplying
energy for the foreseeable future.
11.2.3 Energy Efficiencies
In discussing efficiency for solar-
related energy sources, it is important to
recognize that the input energy is free
and essentially inexhaustible. Thus, the
conversion efficiency has less effect on
direct operating costs than it does for
conventional fossil-fuel plants. Conver-
sion efficiency does, however, influence
the size of the facility required to pro-
duce a given amount of energy. As a conse-
quence, it has a great deal to do with
capital investment and overhead costs.
When solar energy is used for direct
heating, either with flat plate collectors
or with parabolic concentrators, the con-
version efficiencies can be relatively
high, with a maximum between 60 and 70 per-
cent. The actual value depends strongly
11-9
-------
CM
o
^s
-O-
CO
to
o
o
QL
I
_J
O
O
en
8
1000
1958
63 65 68 71 Vear
1000
90% Slope
—Space Power
$ 80/W
Remote Power
2 inch dia:
-Auxiliary Power 5/W
2inch dia. single crystal wafer(19711
Building Power $ I/W
•Central Power S0.30/W
•Markets for Solar Cell Applications
1000
10,000 100,000 200,000
ACCUMULATED PRODUCTION ( cm2 x I06 )
Figure 11-5. Silicon Solar Cell Cost Projections
Source: Glaser, 1973: 9.
-------
Receiving Antenna
(6x6 miles)
22,300 miles
Solar Collector (5x5 miles)
' • " •••"-• *
|v^^;A Electrical
;-v^:i:vV.;:"'ATransrnissional/ Microwave Antenna
S^-KALine / -(Ixl mile)
V£^A(2 miles)n^2^C
te^A \1P^57 ~Contro1 Station
-Waste Heat Radiator
Cooling Equipment
Figure 11-6. Satellite Solar Power Station
Source: AEC, 1974: A.5-13.
-------
on the particular application and on the
design of the system. When solar radia-
tion is used to generate electricity, the
combined efficiency of collectors, storage,
heat engines, and the associated electrical
equipment is not likely to be more than 20
percent and may be much less. The overall
efficiency of photovoltaic generators,
whether located on the earth or in space,
is not likely to exceed 10 percent.
11.2.4 Environmental Considerations
The residuals associated with solar
space heating are negligible, aside from
the land area requirements discussed in
the following section. The net heat re-
siduals for solar electrical power genera-
tion are also negligible, but solar heat
will be removed from the collection area
and transferred to the generating plant in
the form of heated wastewater and elec-
trical output. As a result, there may be
some cases of localized thermal pollution
associated with electrical generation from
solar radiation.
The most promising geographic areas
for solar power generation are located in
the southwestern part of the U.S. Much of
the land is sparsely settled and of low
productivity. The development of such
land into solar farms will involve some
damage to the local ecosystems as a result
of road-building, grading, and the in-
stallation of the solar collectors and
generating equipment. On the other hand,
the Heinels, the principle proponents of
such solar farms in the West, believe the
areas shaded by an array of solar collec-
tors could became more productive as range-
land (Meinel and Meinel, 1972).
Since the solar farms are likely to
be located some distance from population
centers, there would be a need for power
lines to transmit the electricity over
long distances.
Finally, the development of power
plants in desert areas would require the
construction of new towns in relatively
inhospitable circumstances. The resulting
demands on limited local resources will
vary with the size of the facility and the
maintenance and operational requirements.
Solar farms could also disrupt ecological
processes involving local plant and animal
systems.
11.2.5 Economic Considerations
The two factors that have a major
effect on the economics of direct solar
conversion are its relatively low density
at the earth's surface and its intermit-
tency. The former imposes a need for large
surface areas devoted to the collection of
solar energy and a correspondingly high
capital investment in solar energy devices.
The latter requires either large-scale
storage or sufficient backup capacity to
meet the energy demand when solar energy
output is low or nonexistent.
The land use problem is mitigated by
the permanence of the power generation
capability of a given land area, in con-
trast, for example, to the incremental
needs in strip mining to supply adequate
fuel to coal-fired boilers. Although re-
search and analysis are required on this
aspect of solar power, some evidence sug-
gests that the self-sufficiency and perma-
nence of solar energy sites will compare
favorably on a land-use basis with fossil
or nuclear fission energy sources (AEC,
1974: Vol. IV, A.5-22). Figure 11-7 shows
a comparison of total land disturbed by
surface-mined coal and solar -electric
plants for equivalent 1,000-Mwe power
plants. It is also important to note that
federal lands include many areas with high
solar energy potential.
For a given output, the capital in-
vestment required for a conventional fossil-
fueled plant is determined largely by sys-
tem efficiency and load factor. Load fac-
tor is the ratio between the actual output
and the total plant capacity. For fossil
11-12
-------
tfl
B
L.
c
c
d"
UJ
03
or
D
Q
U
:~
-
O
2
UJ
-
s
ID
O
18,000 -
16,000
14,000 -
12,000 -
10,000 -
8,000 -
6,000 -
4,000 -
2,000 -7
Solar Photovoltaic
Range for Coal Surface
Mined
Solar Thermal
Conversion
0
TIME AFTER START OF OPERATION, years
Figure 11-7. Comparison of Land Disturbed from
Surface-Mined Coal and Solar Electric 1000-Mwe Power Plant
Source: AEC, 1974: A.5-23.
-------
and nuclear plants, load factors of 50 to
85 percent are common. Solar plants, re-
stricted to daylight use, operate at load
factors on the order of 20 to 25 percent.
As a result, the capital investment in a
solar plant is likely to be relatively
high, assuming similar costs per installed
kilowatt (kw)i
The intermittency problem is less
tractable than the land—use issue. If
backup capacity based on fossil or nuclear
plants is used, the one-for-one duplica-
tion required to assure a continuous supply
at maximum demand levels will result in
excessive capital costs and reduced effi-
ciency. In any transition from fossil- to
solar-based power sources, such backup is
a natural and reasonable approach. How-
ever, reliance on backup fossil power is
not likely to be cost effective in the long
term and would not conserve depletable re-
sources to the maximum possible extent.
Energy storage provides both backup
capacity and the potential for large-scale
conservation of fossil fuel resources.
Energy storage can take a number of forms,
from pumping water to high dams for later
use, to the generation and storage of hy-
drogen. All are relatively expensive in
terms of capital costs, and only pumped
water storage has a history of successful
long-term experience as a basis for accu-
rate cost estimates. (Hydroelectric power
is discussed in Chapter 9.) For any situa-
tion in which direct solar radiation pro-
vides the baseload capacity, the cost of
storage must be added to the basic cost of
the solar conversion units.
As a consequence of intermittency, the
installed capacity of a solar power plant
must be somewhere between three and six
times the capacity of an equivalent fossil-
fueled power plant for a given annual out-
put.
Since no large-scale solar units have
been built recently (a large array was
erected at Meadi in Egypt in 1913), any
estimates of unit cost per installed kw
must be considered speculative at the pres-
ent time. Further, since large solar
arrays are made up of a large number of
small concentrators, the effect of econo-
mies of scale, in both fabrication and
installation, is not entirely clear. At
present, the most generally accepted cost
estimates place the cost per installed
kw well above that of fossil-fueled plants.
For a continuous energy plant (including
collectors, storage, turbines, and periph-
eral generating equipment), the costs in
1973 dollars may range from $750 (NSF/NASA
Solar Energy Panel, 1972: 50) to $1,100
(Alexander and others, 1973) per kw. This
represents a capital cost of three to five
times that of an equivalent fossil-fueled
plant. The lower of the two estimates is
based on mass-produced components and an
assumed solution to several unresolved
technical problems.
Although operating costs of solar
power plants are expected to be low, the
amortization of capital investment will
represent a major share of generating costs
and will cause solar-generated energy to be
several times as expensive as fossil or
conventional nuclear power so long as fuel
costs remain at or near present levels.
Installed costs are expected to compare
favorably with breeder nuclear power plants.
Electrical transmission costs are ex-
pected to be similar to those of conven-
tional power plants, as described in Chap-
ter 12.
11.3 WIND ENERGY
11.3.1 Resource Base
In any discussion of the windpower
potential for the continental U.S., it is
important to recognize that, at present,
there is no completely adequate basis for
making an accurate assessment. Although
there is a satisfactory knowledge of the
total atmospheric energy flux, there are a
11-14
-------
number of practical limitations. How
closely can windmills be spaced without
unacceptable losses in efficiency? Is it
economical to build tall support towers to
tap the winds at high altitudes? The an-
swers to these and other related questions
have a strong bearing on the total avail-
able wind energy.
Despite these problems, approximations
are not only possible but are adequate for
development in many areas. For example, a
precise measure of the total wind resource
is not necessary before undertaking the
development of windpower. Our use of oil
and gas is in no way inhibited by an in-
ability on the part of geologists to define
an accurate resource base for geological
fuels.
At the most general level, about two
percent of all solar radiation to the earth
is converted to wind energy in the atmos-
phere (Brunt, 1941: 287). A simple calcu-
lation shows that the rate at which wind
energy is being generated over the 48 con-
tiguous states is about 14 times the 1973
energy demand.
Although the conversion of solar
energy to wind energy takes place at all
levels, 30 percent of the wind energy is
generated in the lowest 3,280 feet of the
atmosphere (Kung, 1966: 635). Only a small
part of the energy flux in this lower level
is available for conversion to a form of
power directly useful to man. The amount
is, however, more than might be supposed
from an analysis of the energy contained
in, for example, the lower 500 feet of the
atmosphere. As energy is removed from the
winds close to the ground, kinetic energy
is transferred downward from higher alti-
tudes through the energy transfer mechanism
of the earth's boundary layer. Thus, the
lower atmosphere from which energy is re-
moved is continually replenished by natural
meteorological processes.
In a recent study sponsored jointly by
the National Science Foundation (NSF) and
the National Aeronautics and Space Admin-
istration (NASA), a research team at the
University of Maryland estimated that an
annual output of 5.1x10 Btu's of wind
energy would be possible by the year 2000
(NSF/NASA Solar Energy Panel, 1972: 50).
That amount is close to the total electri-
cal demand in the U.S. for the year 1972.
The most promising geographical loca-
tions for windpower generation in the U.S.
occur along the coastal margins and
throughout the Great Plains Region from
Texas through the Dakotas. Proposals have
also been put forward to harness the steady
offshore winds through the use of ocean-
based windrotor complexes.
11.3.2 Technologies
As with most technologies, windpower
has its characteristic measures of perfor-
mance. In the case of conventional wind-
mills, the output from the rotor is a
direct function of the square of the diame-
ter of the blades and the cube of the wind
velocity. The potential range of perfor-
mance for a windpower system is thus rela-
tively large for only modest changes in
size or operating conditions. It is this
exponential relationship between wind
velocity and output that places such a high
premium on identifying sites with continu-
ous high winds.
Conventional rotor-style windmills
retain the basic configuration that has
been used for thousands of years to pump
water and grind grain. This configuration
consists of a horizontal shaft to which is
attached a number of blades, from two to
several dozen, depending on the operating
conditions and the desired characteristics.
A schematic diagram of a typical modern
windrotor system is shown in Figure 11-8.
Even though a windrotor's output is
proportional to the wind velocity cubed,
it is often not economical to design the
electrical generating equipment to absorb
all the rotor power at maximum possible
11-15
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GEARBOX-
ELECTRICAL GENERATOR
POWER CABLE
SLIP RINGS
ROTOR
DIAMETER
100 FT
Figure 11-8. Typical Wind Rotor System
-------
TABLE 11-2
ANNUAL ENERGY OUTPUT FOR VARIOUS WINDMILL
DIAMETERS IN CENTRAL UNITED STATES
Windmill
Diameter
(meters)
10
20
30
40
50
Installed
Capacity
-------
one of demonstration rather than research.
Some windpower proposals, such as
those for gigantic multirotor wind frames,
will require further research and economic
studies. By and large, however, a major
part of the potential for windpower in the
U.S. can be realized with current tech-
nology and with straightforward development.
As noted before, part applications of
windpower have involved mechanical work—
for propelling boats, grinding corn, and
pumping water, for example. In contrast,
the future of large-scale windpower is tied
almost completely to electrical generation.
Central generating systems can feed direct-
ly into existing power nets from large-
scale wind farms. Smaller wind units can
supply power for a variety of applications,
from remote stations to individual homes.
For large-scale, central-power appli-
cations, there is much to recommend
straightforward energy farms, each covered
with a grid of identical wind generating
units. Aside from the relative simplicity
of the concept, it takes advantage of mass
production economics and simplifies the
development and demonstration of basic
windpower units.
Power densities of 40 Mwe per square
mile are possible in the Midwest with this
approach. Wherever soil and water condi-
tions permit, conventional agriculture can
be carried on in conjunction with wind
farms, since a grid of windpower generators
is entirely compatible with high-yield
farming and cattle grazing.
The intermittence of wind energy is
likely to be less critical than that of
solar energy. If windpower is introduced
into multiregional power grids as baseload
capacity, the emergency fill-in and peaking
can be accomplished by existing fossil-
fueled units. The key to this approach is
to cover a sufficiently broad area so that
the wind is sure to be blowing in some parts
of-the subgrids at all times. Modern
interconnecting and power-sharing technol-
ogy is already adequate for this purpose.
Small-scale applications are also
promising. A ten-foot rotor will recharge
a small urban car overnight. A 25-foot
rotor will provide enough energy for an
all-electric single family home in many
parts of the U.S. In all such individual
applications, the problem of windpower
outages cannot be avoided. To insure
adequate service, either storage or an al-
ternate energy source must be provided.
The former appears to be prohibitively
expensive for average homes at the present
time. Alternate energy sources are more
attractive. As noted in the section on
solar radiation, a promising option is to
tie into—or remain tied into—the existing
utility line, switching to central-station
power when the windpower source is inade-
quate.
11.3.3 Energy Efficiencies
The rotary motion of a conventional
windmill represents mechanical energy which
may be used to drive electrical generating
equipment directly. The maximum theoretical
energy recovery for any wind-driven device
is about 60 percent of the energy contained
in the airstream intercepted by the wind-
mill blades. This is true for conventional
horizontal-axis rotors and for the variety
of alternate configurations which have been
suggested from time to time. Blade ineffi-
ciencies and mechanical losses reduce the
theoretical recovery to a maximum of about
40 percent. The overall wind efficiency of
an individual rotor generating system is
not likely to be more than 35 percent, and
may be less. The solar efficiency of wind-
mill farms, defined as the energy output
as a percentage of total solar insolation
for a given land area, is a measure of land-
use efficiency. It is likely to range be-
tween five and seven percent in the Midwest.
As noted before, efficiency has very little
effect on direct operating costs, but it
does influence capital investment and over-
head costs.
11-18
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11.3.4 Environmental Considerations
Windpower has no significant environ-
mental residuals. It produces no waste
heat and, for the most part, is compatible
with multiple land uses, including farming.
It has been suggested that large windpower
units be sited along railways and highways,
taking advantage of existing rights-of-way
and thereby tending to reduce land-use con-
flicts.
Some restraints may be imposed on the
use of airspace over large wind farms, but
there seems to be no reason to believe that
tower-rotor systems with total heights of
200 to 300 feet will interfere with normal
air traffic, except in the immediate vicin-
ity of airports.
Finally, on the matter of aesthetics,
some people may find the prospect of giant
towers marching across the landscape to be
distasteful, no matter how great their
dedication to nonpolluting energy sources.
In general, however, it appears possible to
develop wind energy in areas with low pop-
ulation densities and to transmit the re-
sulting electrical power to major population
centers with conventional electrical power
nets, thus reducing the aesthetic impact.
11.3.5 Economic Considerations
As with any new technology, the initial
unit costs for windpower generators will be
high. Until the inevitable bugs are worked
out of prototype systems, the operating
costs will also be high. Assuming that
these early hurdles can be passed success-
fully, it has been estimated that windpower
generating systems can be built for about
$150 to $200 (equivalent 1974 dollars) per
installed kw (Hughes and others, 1974: 23).
This compares with today's costs of $200
to $350 for conventional fuel plants and
$500 for conventional nuclear plants. For
the same annual output, the windpower sys-
tems will require about three times the
capacity of the other two systems. Initial
capital investment will be roughly in
proportion.
Assuming a 25-year payback of capital
along with a 25-percent load factor, 10-
percent interest on debt, no provisions for
energy storage, and a conservative allow-
ance for operating costs, a typical instal-
lation will produce electricity at an aver-
age of 2.0 to 2.5 cents (1974) per kwh.
11.4 ORGANIC FARMS
11.4.1 Resource Base
A pound of dry plant tissue will yield
about 7,500 Btu's of heat when burned di-
rectly. A ton of dry biomass, when heated
in the absence of air, will produce 1.25
barrels of oil, 1,200 cubic feet (cf) of
medium-Btu gas, and 750 pounds of solid
residue with a heat content roughly equal
to that of coal. By adjusting the process
temperatures and pressures, the relative
amount of solid, liquid, and gas generated
can be varied to meet end-use specifica-
tions .
Although attractive from many stand-
points, the growing of plants for energy
generation is relatively inefficient. The
solar conversion efficiency of the photo-
synthetic process is seldom over three
percent during the growing season. A year-
round average of just over one percent is
typical for most high-yield crops. As a
result, the land required for a given energy
output is very high relative to other solar
power sources. Based on yields of 10 to 30
tons of biomass per acre per year, the land
required for a 100-Mwe organic-fired power
plant would be somewhere between 25 and 50
square miles.
The.development of algae as an energy
biomass has also received some attention,
largely because the oceans comprise about
70 percent of the earth's surface area.
High productivity has been demonstrated
under controlled conditions, but harvesting
and dewatering represent major obstacles
(Inman, 1973: 20).
The total land area in the U.S. is just
over 3.5 million square miles. Nearly
11-19
-------
one-third (1.1 million square miles) is
owned by the federal government. The
Bureau of Land Management controls about
two-thirds of the federal lands and the
Forest Service just under one-fourth. The
remainder is divided among nine major agen-
cies and a variety of smaller agencies
(World Almanac, 1973: 739-740). In the
lower 48 states, 34 percent of the land is
classified as forest area and 29 percent as
rangeland (Agriculture, 1973: 22). The
productivity of forest/rangeland varies
widely throughout the country, a major limi-
tation being imposed by the availability of
water. In the southwestern part of the
U.S., much of the rangeland is characterized
by sparse vegetation, although a rapid
growth of annual grasses is common in the
rainy seasons. In the Northwest, South,
and East, the natural forests and croplands
are more productive. Under intensive cul-
tivation, both forest and field crops can
yield 20 tons of biomass per acre per year.
Irrigation is an important factor in
the productivity of crops without deep root
systems capable of tapping underground
water resources or in areas where the normal
rainfall is insufficient for high-yield
agriculture. Less than five percent of the
cropland was irrigated in the 1930's, rising
to 10 percent in 1959 (Rottan, 1965: 10).
In most eastern regions, the expansion
of irrigated acreage is limited more by the
cost recovery from high-value crops than by
the physical limitation of soil and water
availability. In the western regions, the
water resources vary widely as do the poten-
tial increases in productivity due to irri-
gation. In general, the gains from a given
level of irrigation in arid regions are
likely to be high.
11.4.2 Technologies
Agriculture and silviculture (develop-
ment and care of forests) are based on pro-
cesses that have, in principle, remained un-
changed for millennia. The basic functions
of soil preparation, planting, 'fertilizing,
irrigation, crop maintenance, and harvesting
are all familiar and recognizable elements
in modern farming and forestry. This seem-
ing familiarity, however, tends to mask the
radical changes which have taken place in
food and fiber production methods during
the past 40 years.
Farm productivity per acre has tripled
since 1934, and the output per man-hour
has increased by a factor of seven. Ma-
chines have replaced farm animals, hybrid-
ized and genetically manipulated seed have
replaced the best of "natural" grains, and
modern forestry practices have increased
productivity dramatically. Figure 11-9
shows some important measures of change
from 1910 to 1960 (Starr, 1971: 41). It is
this change which has made it possible to
consider the development of energy planta-
tions as a partial substitute for the use
of fossil fuels. The equipment required
for organic energy production is well devel-
oped and in a continual state of improve-
ment.
A number of improvements in plants and
in the photosynthetic process appear to be
possible and would significantly enhance
the economics of organic energy production.
These improvements include plants with in-
creased biomass production and plants which
conserve water and nutrients.
To date, no -major efforts have been
made to maximize biomass production per
unit of land area. Most crops, whether
field or forest, have a specific high-value
component which has been emphasized genet-
ically, often at the expense of other growth
factors. Certain plants do, however, have
fortuitously high biomass yields. Among
them are the genus Eucalyptus, which con-
sists of over 500 species of broad-leaved
evergreen trees native to Australia (Inman,
1973: 8). Eucalyptus trees grow in most of
the temperate regions of the world, some in
hot, dry weather where annual rainfall av-
erages 10 inches or less. Biomass yields
11-20
-------
400
OJ
g>
i
2 300
2 200
o
O
O
cc
Q_
(T
oo
farm outpu^
s —
man-hours
1910
1920
1930
1940
1950
I960
Figure 11-9. Farm Output Per Man Hour
From "Energy and Power," Chauncey Starr.
Copyright (c) 1971 by Scientific American, Inc. All rights reserved,
-------
on the order of 8 to 25 tons per acre per
year have been recorded, the highest being
in California.
Other high-yield crops are sugar cane
(12 to 50 tons), sorghum (8 to 30 tons),
kenaf (8 to 20 tons), algae (15 to 30 tons),
and sunflower (10 to 20 tons).
The potential for increasing biomass
yields (while at the same time decreasing
the need for water and fertilizer) exists
because of natural variations in the photo-
synthetic pathways, some of which reduce
photorespiration and provide greater heat
and drought resistance.
Other plants, such as soybeans, peas,
and alfalfa, can extract nitrogen from the
air and convert it into protein. This abil-
ity to "fix" atmospheric nitrogen avoids
the need for nitrogen-rich fertilizers and
tends to protect the fertility of the soil.
There is some hope that research now going
on with the alternate photosynthetic path-
ways and with nitrogen-fixing will permit,
through hybridization or other processes,
the extension of these desirable traits to
other species (Bjorkman and Berry, 1973:
93).
Finally, the possibility of large-scale
plant growth in a controlled environment has
been investigated, primarily in Arizona.
Large inflated plastic structures provide
protection against wind and weather. The
solar rays passing through the plastic
cause the plants to grow just as they would
in the open, but the moisture which tran-
spires through the leaves of the plants
condenses on the underside of the plastic
and is directed back to the roots of the
plants. The net water consumption could be
as little as 10 percent of that which would
normally be required. As a further ad-
vantage, it is possible to increase the
carbon dioxide concentration in the con-
trolled environment and thus accelerate the
growth rate of the plants (Yellot, 1973: 8).
The first large-scale application of
plastic domes for plant production is now in
operation on an island off Abu Dhabi, where
it supplies a major share of the fresh veg-
etables consumed by the local population.
High yield agriculture demands high
insolation, adequate water supplies, and
the availability of nutrients, either
through natural soil conditions or the use
of fertilizer. Based only on temperature
and insolation characteristics, the south-
western quarter of the U.S. offers the best
growing conditions. Annual insolation is
lower in the Southeast because of increased
cloud cover. Lakeland, Florida, for exam-
ple, received only 67 percent of the sun-
light possible in 1970 as compared to av-
erages of 80 to 90 percent in the Phoenix-
Tucson-Yuma area. Annual rainfall in 1970,
on the other hand, was 46.5 inches in
Lakeland and only 7.3 inches in the Phoenix-
Tucson-Yuma area.
The use of nitrogen-fixing plants will
tend to reduce the need for some types of
fertilizer. Other strategies for reducing
fertilizer requirements include crop rota-
tion and the use of less demanding plants.
Nevertheless, intensive farming requires
soil supplements, and the demand for fer-
tilizers represents one aspect of the energy
plantation development which requires major
attention. Some areas of the country, such
as Florida, have large natural phosphate
resources. Others require long supply lines
for the required nutrients.
Since standing forests may be harvested
at any time of the year and dry biomass may
be stored for long periods of time, organic
power has a greater potential for base-
loading than any other solar energy source.
The similarity of its technology to existing
fossil fuel generating systems could be ex-
pected to reduce the problems associated
with introducing a new source of power.
Bagasse, the residue of sugar cane, has been
used for years to develop both power and
process steam for sugar-making.
The conversion of organic materials to
gas, oil, char, and other products through
11-22
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pyrolysis, hydrogenation and biological
processes is described in Chapter 10.
The potential for by-products from
energy farms ranges from sunflower oil to
furniture. Since by-products are likely to
have a higher unit value than the material
used for direct combustion, the economics
of the multiple-output farm will benefit
accordingly. In addition, the use of na-
tural and nondepletable materials for con-
sumer products will tend to reduce the
pressure on metals, plastics, and other
materials which are either in limited sup-
ply or require large amounts of energy to
produce and fabricate.
11.4.3 Energy Efficiencies
As noted previously, photosynthetic
conversion efficiencies are seldom higher
than three percent during the growing sea-
son or more than 1.5 percent on an annual
basis. Coupled with thermodynamic effi-
ciencies of 30 to 40 percent for conven-
tional steam-turbine power plants, the
overall efficiency of organic energy forms
is less than one percent.
11.4.4 Environmental Considerations
The oxygen now in the atmosphere is
almost entirely of biological origin, pro-
duced through the decomposition of water
molecules by light energy in photosynthesis.
In the past 100 years, man's overwhelming
reliance on fossil fuels has tended to
change the natural balance between oxygen
generated through photosynthesis and carbon
dioxide generated through organic decom-
position. Within that period of time, the
carbon dioxide content of the atmosphere has
risen from 280 to 325 parts per million
(ppm), with nearly one-quarter of the rise
occurring in just the past decade (Bolin,
1970: 128).
The continued increase in the consump-
tion of fossil fuels implies that the amount
of carbon dioxide in the atmosphere will
increase to 400 ppm by the year 2000. The
long-term effect of this change in the
carbon balance of the earth is not known.
It has also been suggested that possible
increases in vegetation from organic farms
might function as a sink for ammonia, hy-
drogen fluoride, sulfur dioxide, and ozone.
In addition to these specific envir-
onmental effects, there are the more intan-
gible benefits of aesthetics and multiple
use. A forest or a field of sugar cane
would be considered by most people to be
more attractive than a strip mine or an
oil field. A forest is a more appropriate
place for picnicking, camping, or hunting
than a tank farm or the immediate vicinity
of a uranium mine. Although it is not clear
that high-yield silviculture and extensive
recreational activities are entirely com-
patible, the possibility exists and some
compromises on energy yield might make
reasonable accommodation possible.
Environmental problems associated with
energy plantations involve their need for
land, water, and fertilizer. Even if new
croplands were to be opened and yields im-
proved, the potential for land-use conflicts
still exists because of the growing world-
wide demand for food. This competition
poses one of the most predictable obsta-
cles to the development of energy planta-
tions. In the U.S., the problem is exacer-
bated by our preference for animal protein.
Since seven calories of vegetable energy
are required to produce an equivalent cal-
orie of beef, the efficient use of land for
the production of food, fiber, and energy
may require some reordering of priorities
and public policies.
The water problems associated with
organic energy farming are extremely geo-
specific, depending on local rainfall, soil
conditions, depth of the water table, and
availability of well water. Although plant
selection can tend to reduce the need for
water in arid regions, some irrigation will
be required in most parts of the country
where land availability and high insolation
11-23
-------
rates are favorable. The water problems
described in the chapters on oil shale and
coal should also apply generally to organic
energy farming in the Southwest.
Fertilizer requirements may be one of
the most serious limitations to biomass
production. As with fossil fuels, natural
fertilizer sources are limited and fertili-
zer transportation may involve long dis-
tances and large volumes. A major source
of energy plantation fertilizer could be
found in municipal sewage plant sludge,
organic trash, and feedlot wastes. The re-
sulting symbiotic relationship could result
in reduced costs for both fertilizer to the
farm and waste disposal by cities. What-
ever its source, unabsorbed fertilizer will
be subject to runoff and other pollution
problems.
Since the organically fired power
plants will almost invariably be located
in or adjacent to the farm itself, trans-
portation distances for the biomass will
seldom exceed 5 to 10 miles, depending on
the layout of the farmland and the power
plant units. No appreciable environmental
residuals are expected from the intrafarm
transportation phase of the operations.
11.4.5 Economic Considerations
Farming costs for existing crops are
well documented because of the economic im-
portance of large-scale, intensive agri-
culture. Thus, a firm base exists for es-
timated organic farm costs, even though it
is not known which species may eventually
be selected or in what proportion they may
be cultivated.
In early 1972, the nationwide average
purchase price for farmland was $217 per
acre. Most good cultivated land sold for
considerably more than $217 in 1972, but
much potentially arable land could be bought
for considerably less. Assuming an average
price of $500 per acre, an annual land
"charge" of $42 (1973) per acre per year is
reasonable (Inraan, 1973: 20).
Production costs, including the labor,
materials, and equipment needed to prepare
the fields and plant and cultivate the
crop, average about $57 (1973) per acre.
The cost of installing and operating
irrigation systems of the self-propelled
tower and rainbird type average about $30
(1973) per acre per year. This includes
the costs of purchase, installation, oper-
ation, and depreciation of the complete
system.
The cost of water is highly variable,
ranging from zero to as high as $20 per
acre-foot. For the crops of interest to
energy plantations, an annual charge of $30
(1973) per acre would appear to be reason-
able.
Harvest costs include labor, the oper-
ation and depreciation of harvesting equip-
ment, and short-range hauling. Assuming
field crops such as sugar cane, sorghum,
and kenaf, a charge of $4.50 (1973) per
ton is representative.
Combining the values above with an
assumed profit of 20 percent, biomass will
be approximately $18 (1973) per ton at the.
yield level of 15 tons per acre and $12
(1973) per ton at a yield level of 30 tons
per acre. At 7,500 Btu's per pound of dry
plant tissue, the cost per million Btu's
would vary between $0.80 and $1.20. This
compares with current prices per million
Btu's for coal of $0.79, domestic oil of
$0.87, and interstate natural gas of $0.43.
The crop value per acre would be somewhere
between $180 and $300, which is comparable
to the current yield from wheat acreage in
the Midwest.
Economies of scale can be expected to
apply to energy plantations as they do to
most industrial and agricultural processes.
The operation would involve a low-density
collection function, which is characterized
by the large-scale replication of unit
equipment and functions. Under such circum-
stances, the economic size is more likely
to be determined by total nationwide
11-24
-------
capacity, which establishes the market and
the production base for related equipment,
than it is by individual plantation size.
11.5 OCEAN THERMAL GRADIENTS
11.5.1 Resource Base
The surface temperature of the oceans
between the Tropic of Cancer and the Tropic
of Capricorn stays remarkably constant at
about 77 F because the heat gained from
solar radiation is balanced by the heat
lost from evaporation (Metz, 1973: 126).
At depths as shallow as 3,280 feet in these
latitudes, the water temperature is 41°F.
This temperature difference may be used to
generate electricity in a conventional heat
engine.
The amount of continuous energy avail-
able from ocean thermal gradients is many
times more than that consumed throughout
the world today. How much more depends on
a number of factors, including the depth
from which the cold water must be obtained,
the conversion efficiency of the system, and
the transmission losses in getting the elec-
trical energy to shore. As with the wind,
an accurate assessment of the resource base
is probably less important than the know-
ledge that the potential is greater than
the existing demand.
11.5.2 Technologies
Although sea water has been used as a
working fluid in demonstration units, the
economic development of ocean thermal power
plants requires the use of a secondary
fluid which will boil at about 68°F. In
operation, the working fluid would be
heated and vaporized by the warm surface
water in large heat exchangers. The vapor
would then be expanded through turbines to
produce electricity and finally condensed
to the liquid state in heat exchangers
cooled by deep ocean water.
The heat exchangers are the critical
technology in such power plants, although
the pumps, turbines, and water ducts also
require major development. The heat ex-
changers, both condensor and evaporator,
must transfer an enormous amount of heat
through very thin walls which are oper-
ating in a corrosive seawater environment.
Although some government-funded research
is being done in this area, the technical
problems are formidable. The practical
application of ocean thermal gradient pow-
er sources lies well beyond the next 10-
year time period.
11.5.3 Energy Efficiencies
The maximum theoretical efficiency
of a power plant working with a temperature
difference of 36°F is about 6.7 percent.
The actual efficiency is not likely to ex-
ceed three percent and may be considerably
less.
11.5.4 Environmental Considerations
Ocean thermal power appears to have
very little direct environmental effect,
although the subject has not been inves-
tigated to any great extent. Removal of
thermal energy from the oceans is expected
to be more than balanced by solar radiation
to the cold discharge water at the surface.
Environmental effects due to the construc-
tion and operation of large thermomechanical
installations in the ocean are not known.
11.5.5 Economic Considerations
The technology is insufficiently devel-
oped at this time for calculating reliable
economic information. Some thought has been
given to using the nutrient-rich deep water
for the cultivation of algae and marine
animals for food.
11.6 SUMMARY
All solar energy sources are charac-
terized by low power densities and low con-
version efficiencies when used to generate
electricity. As a consequence, the land
area requirements for a given output are
11-25
-------
cr
CO
Q
UJ
CC
ID
a
UJ
en
UJ
<
_l
1000 r-
500
200
100
50
20
10
ORGANIC FARM ELECTRICITY
WINDPOWERv
SOLAR ELECTRICITY
DIRECT. SOLAR HEATING
I
I
1
1
I
I
1
.2 .5 I 2 5 10 20 50 100
NET SOLAR CONVERSION EFFICIENCY, percent
Figure 11-10. Land Area Required for 1,000 Mwe-Equivalent Output
as a Function of Solar Conversion Efficiency
-------
relatively large. Although the affected
land area may, in the long run, compare
favorably with that of fossil-fueled power
plants, the initial land commitment may
seem formidable. Figure 11-10 shows the
land requirements as a function of overall
conversion efficiency and identifies the
range for specific solar technologies.
These requirements are based on an average
daily solar insolation for the U.S. of
about 1,450 Btu's per square foot and a
load factor of 75 percent. The land area
requirements shown for space heating are
calculated for an output equivalent to a
1,000-Mwe power plant, although in practice
individual units would be relatively small
and tailored to individual building re-
quirements .
From a land-use standpoint, direct
solar heating for buildings would appear to
be most attractive. If the required equip-
ment can be made reliable and cost-competi-
tive with current heating methods, the
potential contribution to the U.S. energy
demand will be large. Further, with suffi-
cient economic incentives as a result of
high fuel prices or government initiatives,
solar space heating could become a signifi-
cant factor in a relatively short period of
time.
When solar energy is used for gener-
ating electricity or other portable power,
the efficiency is greatly reduced.
Offsetting the overhead costs due to
the high initial investment in solar power
systems are the economic benefits associated
with free energy and lower operating costs.
This relative advantage of all solar-related
energy sources is likely to increase in the
future, since fossil and nuclear fuels re-
quire extensive (and energy-intensive)
exploration, extraction, transportation,
and processing before they can be converted
to usable energy in a burner and heat en-
gine. The resulting "energy debt" is a
major part of fuel costs and the cost of
conventional (including nuclear) power
generation.
In the meantime, the relatively high
capital costs of direct solar energy, com-
bined with the present U.S. commitment to
fossil and nuclear fuels, are expected to
inhibit its use in the near future in the
absence of specific government incentives.
REFERENCES
Alexander, L.G., and others (1973) "Solar
Power Prospects." Paper presented at
the Solar Thermal Conversion Workshop,
University of Maryland, January 11-12,
1973.
Atomic Energy Commission (1974) Draft
Environmental Statement; Liquid Metal
Fast Breeder Reactor Program.
Washington: Government Printing
Office.
Sergey, K.H. (1971) "Feasibility of Wind
Power Generation for Central Oklahoma."
Aerospace and Mechanical Engineering
Report. University of Oklahoma, June
1971.
Bjorkman, O., and J. Berry (1973) "High-
Efficiency Photosynthesis." Scien-
tific American 226 (October 1973):
80-93.
Bolin, B. (1970) "The Carbon Cycle."
Scientific American 223 (September
1970): 124-132.
Brown, W.C. (1973) "Satellite Power Sta-
tions: A New Source of Energy?"
IEEE Spectrum 10 (March 1973): 38-47.
Brunt, D. (1941) Physical and Dynamic
Meteorology. New York: Cambridge
University Press.
Crawford, K.C., and H.R. Hudson (1970)
"Behavior of Winds in the Lowest 1500
Feet in Central Oklahoma: June 1966-
May 1967." ESSA Technical Memorandum
ERLTM-NSSL 48, August 1970.
Department of Agriculture, Forest Service
(1973) The Nation's Range Resources.
Forest Resource Report No. 19.
Washington: Government Printing
Office.
Department of Commerce (1970) Climatological
Data; National Summary. Washington:
Government Printing Office.
11-27
-------
Department of Commerce (1973) Statistical
Abstract of the United States. 1973.
Washington: Government Printing
Office.
Encyclopaedia Britannica (1973) Chicago:
Encyclopaedia Britannica, 24 vols.
Glaser,'P.E. (1973) "Solar Power via
Satellite." Testimony before the
Senate Committee on Aeronautical and
Space Sciences, October 31, 1973.
Hughes, W.L., and others (1974) "Basic
Information on the Economic Generation
of Energy in Commercial Quantities
from Wind." Report #ER 74-EE-7,
Oklahoma State University, May 21,
1974.
Inman, R.E. (1973) "Effective Utilization
of Solar Energy to Produce Clean Fuel."
Stanford Research Institute, Third
Quarter Progress Report, NSF Founda-
tion Grant GI38723, October 30, 1973.
Rung, B.C. (1966) "Large Scale Balance of
Kinetic Energy in the Atmosphere."
Monthly Weather Review 94 (November
1966) .
Heinel, A.B., and M.P. Meinel (1972)
"Thermal Performance of a Linear Solar
Collector." ASME Technical Paper No.
72-WA/SOC-7, November 1972.
Metz, W.D. (1973) "Ocean Temperature Gradi-
ents: Solar Power from the Sea."
Science 180 (June 22, 1973): 1266-1267.
National Science Foundation/National Aero-
nautics and Space Administration Solar
Energy Panel (1972) An Assessment of
Solar Energy as a National Energy
Resource. College Park, Md.: Univer-
sity of Maryland.
Professional Engineer (1973) "Solar Energy:
An Idea Whose Time Has Come and Gone
and Come Again." Professional Engi-
neer (October 1973) .
Rottan. V.W. (1965) The Economic Demand
for Irrigated Acreage. Baltimore:
Johns Hopkins Press.
Starr, C. (1971) "Energy and Power." Sci-
entific American 224 (September 1971):
36-49.
World Almanac and Book of Facts. 1974
(1973). George E. Delury, ed. New
York: Newspaper Enterprise Associa-
tion, Inc.
Yellot. T.I. (1973) "Solar Energy in the
Seventies." The Bent of Tau Beta Pi
(Spring 1973).
11-28
-------
CHAPTER 12
ELECTRIC POWER GENERATION
12.1 INTRODUCTION
Electric power consumption in the U.S.
has grown much more rapidly than total U.S.
energy consumption during the last several
years, maintaining an average annual growth
rate of seven percent. At this rate,
electric power consumption doubles every
10 years. In 1971, electric power genera-
12
tion consumed 25.3 percent (or 17,500x10
Btu's) of the nation's energy. Some pro-
jections indicate that electricity produc-
tion will account for 40 percent of total
U.S. energy consumption by the year 2000.
The energy sources used to generate elec-
tricity in 1972 are shown in Table 12-1.
A number of technical and economic
problems facing the electric utility indus-
try have made electric power generation
technologies the focus of much research and
debate. First, the concern with environ-
TABLE 12-1
ENERGY SOURCES FOR 1972 U.S.
ELECTRICITY GENERATION
Source
Coal
Natural gas
Oil
Hydroelectric
Nuclear
Percent of
Total
44
21
16
16
3
Source: Atomic Industrial Forum,
1974.
mental quality has had a major impact be-
cause electric power plants can be large
and easily identifiable polluters. For
example, as discussed in the chapter on
coal, environmental concerns have been re-
sponsible for the rapid shift from coal to
cleaner burning fuels in electric power
plants. Second, electric power generation
is a relatively inefficient process (the
U.S. average efficiency is around 30 per-
cent) and thus a number of new, more effi-
cient processes are under investigation.
Third, the demand for electricity varies
drastically with the time of day and season,
posing a number of technical and economic
problems in meeting "peak" demand. In
addition, the rapid growth in demand de-
scribed above has compounded these technical
and economic problems.
The primary purpose of this chapter is
to describe the technologies for converting
solid, liquid, and gaseous fuels (chemical
energy) into electrical energy. However,
many of the component technologies described
here also apply to other resource systems
whose primary output is electrical energy.
For example, the steam turbine and cooling
mechanisms described in this chapter are
identical to those used in nuclear power
plants. Therefore, the chapter on fission
refers to this chapter for descriptions of
certain power plant components.
Figure 12-1 is the electric power gen-
eration flow diagram used for organizing
this chapter. Five basic plant types are
shown which convert the chemical energy to
electrical energy: boiler-fired, gas
12-1
-------
Solids
Gases
Liquids
12.2
Boiler-Fired Power Plants
•Boilers
• Turbines
•Generators
• Stack Gas Cleaning
•Cooling
12.3
Gas Turbine
Power Plants
12.4
Combined Cycle
Power Plants
12.5
Fuel Cell
Power Plants
12.6
12.7
Dist.STrans.
Pumped Storage
(See Hydro-
Electric)
MHD
Power Plants
12.7 Transportation Lines
— Involves Transportation
•—Does Not Involve
Transportation
Figure 12-1. Electrical Generation System
-------
turbine, combined cycle, fuel cell, and
magnetohydrodynamic (MHD) power plants.
In addition, electricity transmission and
distribution is described. Pumped storage
is also shown in Figure 12-1, but this
component is described in Chapter 9.
As mentioned above, the demand pattern
for electric power is a significant problem
and, therefore, an important variable to be
considered in designing a power plant. The
industry identifies three types of load
demands that plants must be designed to
serve: base, intermediate, and peak. Base-
load units are large, relatively efficient
units that operate continuously at or near
full capacity. Typical annual capacity
factors (percent of annual output if oper-
ated continuously) are around 80 percent.
Intermediate-load units are smaller, less
efficient, and typically are required to
shut down and start up daily as demand
varies. Annual capacity factors vary from
20 to 60 percent. Peak-load units provide
power for short periods of the day (when
the demand for electricity is at its maxi-
mum) and generally have capacity factors of
20 percent or less.
This chapter first describes the major
components identified in Figure 12-1.
These descriptions include available infor-
mation on efficiency, residuals, and costs.
Following this description, additional sec-
tions summarize and compare environmental
residuals and the economic costs of the
various technological alternatives.
12.2 BOILER-FIRED POWER PLANTS
Figure 12-2 shows the various compo-
nents or stages that make up a boiler-fired
power plant. 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 is converted to heat energy
in the boiler and the 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 electri-
cal energy by a generator. The boiler-
fired power plant may also incorporate
stack gas cleaning to reduce the air pollu-
tants created in the boiler, and it must
use some cooling mechanism for disposing
of waste heat. The technical description
of boiler-fired power plants is organized
around the five basic components shown in
Figure 12-2.
A typical steam power plant consists
of a "conventional" boiler, a steam turbine,
a generator, and some type of cooling
mechanism but normally no stack gas clean-
ing. These systems are currently the most
important type of boiler-fired power plant,
accounting for 78 percent of the nation's
generating capacity. A simplified sche-
matic of a steam power plant is given in
Figure 12-3. In the boiler, heat from
conventionally fueled fires (or from nu-
clear, solar, or geothermal sources) 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,
in the process, drives the turbine which
in turn drives the generator. After the
thermal energy in the steam has been con-
verted to mechanical energy, the discharged
steam is reconverted to water in a con-
denser. The water is then pumped back into
the boiler and starts the cycle over again.
The heat removed in the condenser is re-
jected to the environment in cool bodies
of water (i.e., lakes, ponds, rivers, etc.)
or to the atmosphere by cooling towers.
Detailed descriptions of each of the
five components are given below. Informa-
tion on efficiency, environmental effects,
and economic considerations for several of
the alternative boiler-fired power plant
configurations follows the descriptions.
12-3
-------
Stack Gas
Cleaning
Cooling
Solid, Liquid
or Gaseous
Fuels
Boilers
'Conventional
•Fluidized Bed
Heat
Energy
Turbines
• Steam
•Binary Cycle
Mech.
Energy
Generator
Electricity
HEAT= Solar, Geothermal, Nuclear
Figure 12-2. Boiler-Fired Power Plant
-------
Heat Input
To Cycle
(Fuel)
High Pressure
High Temperature Steam
Pump
Boiler
High Pressure
Water
Condenser
D
Low Pressure
Water
Generator
Electrical
•^"Energy
Mechanical Energy
Output To Generator
Low Pressure
Low Temperature
Steam
Heat Rejected From Cycle
Figure 12-3. Simplified Schematic of a Steam Power Plant
Source: AEC, 1974: B.2-4.
-------
12.2.1 Technologies
12.2.1.1 Boilers
Boilers are mechanisms that burn fuels
to create heat energy which is then trans-
ferred to a fluid (normally water) to pro-
duce steam. To improve thermal efficien-
cies, both conventional boilers and the
new fluidized bed combustors generally con-
tain other system components such as:
1. Superheaters. A superheater 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 superheater, the reheater
reheats partially expanded steam
taken from the early stages of the
turbine that is then returned to
the final stages of the turbine.
3. Economizers. An economizer ex-
tracts heat from the flue gases
(after the superheater) and trans-
fers 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.
In addition to these components, a
boiler normally consists of steam separa-
tors, fans, pumps, fuel handling equipment,
and combustion by-product handling equip-
ment.
Because the boiler encompasses the
fuel combustion operation, it produces most
of the potentially adverse environmental
residuals associated with electric power
generation.
This section deals with both conven-
tional type boilers and fluidized bed com-
bustors .
12.2.1.1.1 Conventional Boilers
Conventional boilers are extremely
large and complex pieces of equipment; some
steam power plant boilers are 10 or more
stories tall. Figure 12-4 is a somewhat
simplified boiler design showing the air
and flue gas circulation patterns.
A number of variables affect conven-
tional boiler design, a primary one being
the type of fuel to be burned. Oil and gas
are both blown with the combustion air into
the combustion chamber through orifices.
Coal is generally pulverized to a very fine
powder (approximately 200 mesh) and then
blown into the furnace in much the same
manner as oil and gas. However, additional
problems that must be dealt with when coal
is burned include fly ash 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 tan-
gentially 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 mixing, approximately 20 per-
cent more air (termed 120-percent excess
air) must be injected into the combustion
chamber than is theoretically required for
complete combustion.
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 (Babcock and wilcox,
1972: 10-1):
1. Reduction of fly ash content in
flue gas.
2. Savings in fuel preparation, since
only crushing is required instead
of pulverizing.
3. Reduction in furnace size.
12-6
-------
Forced Draft Fan
Induced Draft Fan-^Fuel Conveyor
Economizer
Pulverizer
Boiler
Figure 12-4. Boiler Air and Flue Gas Circulation Patterns
Source: Shields, 1961: 209.
-------
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 (SO ) emissions are directly
X
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. Sulfur
oxides must be dealt with either before or
after burning. The stack gas cleaning
approach will be discussed later.
Nitrogen oxides (NO ) emissions can
be significantly affected by boiler design
and operating conditions, but the process
of NO creation during combustion is not
completely understood. The major factor
affecting the creation of NO is tempera-
ture. One study indicates that the most
important variables for fossil-fueled
boilers in controlling NO emissions are
X
staged firing, low excess air (less than
110 percent of the actual requirement for
complete combustion). and flue gas recir-
culation (Bartok and others, 1972: 66).
This study indicated the potential for
similar methods to be applied for coal,
but the emission of NO from coal-fired
boilers is the least explored and the most
difficult problem area of all the NO
emission sources (Bartok and others, 1972:
72).
Particulate emissions are a major
problem with coal-fired boilers and some-
what of a problem with certain fuel oils.
Improved boiler design can reduce the par-
ticulate emissions. The primary advance
in this area is the cyclone furnace de-
scribed earlier, which can reduce fly ash
by 50 percent over pulverized units.
12.2.1.1.2 Fluidized Bed Boilers
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
available at present, but their proponents
believe they hold great promise as substi-
tutes for conventional steam boilers.
A fluidized bed boiler involves passing
air 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 par-
ticulates and, with the relatively small
amount of air used to inject the fuel
(usually coal but possibly residual oil),
. serves as the combustion air (AEC, 1974:
Vol. IV, p. A.2-17). The heat transfer sur-
faces or boiler tubes can be embedded in
the fluidized bed directly because combus-
tion takes place at temperatures (approxi-
mately 1,500°F) that will not damage the
tubes.
The fluidized bed boiler has two
basic advantages: the ability to burn
high-sulfur coal with low sulfur dioxide
(SO,), particulate, and, to some extent,
NO emissions; and high heat release and
A
heat transfer coefficients that can dras-
tically 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 will
considerably reduce construction times for
new power plants (Hittman, 1975: Vol. II,
p. VI-1).
There are several fluidized bed con-
cepts at various stages of development.
In this section we will describe one of the
processes treated in the Hittman study:
the Pope, Evans, and Robbins Atmospheric
Pressure Fluidized Bed Boiler. Another
fluidized bed system treated in the Hittman
study that combines, gas and steam turbines
will be treated in Section 12.4.
The Pope, Evans, and Robbins Atmos-
pheric Pressure Fluidized Bed Boiler,
being developed for the Office of Coal
Research (OCR), is designed as a replace-
ment for conventional boilers. This sys-
tem is illustrated in Figure 12-5 The sys-
tem uses repeating elements or cells to
12-8
-------
Dust Removal
Turbine
Generator
Steam
Limestone
& Salt
Dust \
Removal
/
»
Fan
Stack
_^ Solid
Waste
Sulfur
Plant
\
11
-Coal
n
' i
1
Multicell Fluidized-Bed Boiler
1500 F
Primary
Boiler
Cells _
ri^n^Vn
1 ^ ~ 1
1 ' '
2000 F
Carbon
Burnup
Cells
1 4 1 * ^ *
Refiger
Cells
— —9
1 .
T J
1 |
| "*
I
I
I
Airl
,Ash
Figure 12-5. Pope, Evans, and Robbins Fluidized
Bed Boiler Power Plant
Source: Hittman, 1975: Vol. II, p. VI-4.
-------
make any size boiler desired. The cell
concept reduces the scale-up problems that
have been plaguing the industry. Each cell
produces enough steam for a 30-megawatt-
electric (Mwe) generator. A prototype cell
is being installed at an existing power
plant and is scheduled to go into operation
by mid-1975 (Papamarcos, 1974: 39).
12.2.1.2 Turbines
The purpose of the turbines is to con-
vert the heat energy created by the boiler
into mechanical energy. Two types of tur-
bine systems are described, the steam tur-
bine and the binary cycle system.
12.2.1.2.1 Steam Turbines
In a steam turbine, high-temperature,
high-pressure steam expands to a low-
temperature and low-pressure, exerting
force against the turbine blades in the
process. The force on the turbine blades
turns the turbine shaft which is connected
directly to the generator shaft.
Steam turbine technology is well devel-
oped, and many feel that there are not
likely to be any major improvements in
their design. Advanced blade technology,
seals, and moisture removal techniques—as
well as lower-cost, high-temperature
alloys—are areas receiving attention.
The steam turbine represents the most
inefficient component in the electric power
generation process. In thennodynamic ter-
minology, the turbine is a heat engine
(i.e., it converts thermal energy to me-
chanical energy) and as such is limited by
the Carnot cycle efficiency. Carnot effi-
ciency is a theoretical maximum, not
achievable in practice, that is used for
comparisons. It is directly a function of
the temperature difference between the
high- and low-temperature ends of the
cycle; a typical steam turbine operating
between a maximum temperature of 1,000°F
and a minimum temperature of 70 F would
have a theoretical maximum efficiency of
64 percent. In actual practice, however,
steam turbines operating under these condi-
tions only achieve efficiencies on the
order of 50 percent. Attempts to obtain
greater efficiencies by using higher steam
temperatures and pressures are currently
constrained by metallurgical limits.
12.2.1.2.2 Binary Cycle Systems
As indicated in the previous discus-
sion, the primary disadvantage of steam
turbines is their low efficiency. To im-
prove efficiency, two or more heat engine
cycles covering different parts of the tem-
perature range can be combined. This com-
bination is commonly referred to as a
binary cycle. 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.
In this section, two possible liquid-
metal topping cycles will be described.
Gas turbine/steam turbine systems—the so-
called "combined cycle"—can also be clas-
sified as a topping cycle, but this will
be covered in a separate section. A steam-
ammonia bottoming cycle has been proposed,
but many feel its advantages over the
single cycle system are marginal (AEC, 1974:
Vol. IV, p. B.5-1) and it will not be dis-
cussed here.
The principal advantage of using one
of the "liquid metals" as the working sub-
stance in power plants is their high boil-
ing or vaporizing temperatures at rela-
tively low pressures. While water boils
at 662°F at 2,400 pounds per square inch
absolute (psi-absolute), mercury boils at
907 F at 100 psi-absolute and potassium
boils at 1,400°F at 14.7 psi-absolute (one
atmosphere ). The efficiency of the liquid-
metal Rankine cycle by itself is not high,
but with the binary cycle the condenser for
the liquid metal serves as the boiler for
the water, and the overall efficiency is
relatively high (AEC, 1974: Vol. IV,
p. B.5-2).
12-10
-------
Between 1922 and 1950, the General
Electric Company constructed a series of
six fossil-fueled mercury and steam binary
cycle power plants. These mercury plants
demonstrated the practical feasibility
of the mercury topping cycle. However, no
mercury topping cycles were built after
1950 because of the improved efficiency and
economies of scale of the conventional
steam power plant and the price fluctua-
tions of mercury which increased the eco-
nomic risk of such plants (AEC, 1974: Vol.
IV, p. B.5-4).
A potassium topping cycle has not been
used in utility power plants, but possible
use has been studied since the early
1960's. The potassium cycle has potential
for use above about 1,400°F and thus would
be considered primarily for use with
fossil-fueled heat sources, although it
could possibly be used in conjunction with
a nuclear high temperature gas reactor
(HTGR). The mercury topping cycle will
require a heat source in the range of 900
to 1,300°F and thus could also be used in
conjunction with the liquid metal fast
breeder reactor (LMFBR), which is expected
to have a sodium outlet temperature of
1,100°F. This would have the advantage of
eliminating sodium-water interfaces (AEC,
1974: Vol. IV, p. B.5-6).
There do not appear to be any unsolv-
able technical difficulties associated with
bringing binary cycle concepts to fruition,
but it is unlikely they would have any sig-
nificant impact on the U.S. energy picture
before 1985. The primary R&D effort needed
is in the area of design and testing of
scaled—up key components. The Oak Ridge
National Laboratory, under a grant from the
National Science Foundation (NSF), has be-
gun the construction of a small potassium
boiler (AEC, 1974: Vol. IV, p. B.5-11).
12.2.1.3 Generators
The mechanical energy from the turbine
is converted to electrical energy by the
generator. An electrical generator relies
on a basic phenomenon in electromagnetics;
namely, 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 large power
plants is the synchronous type, whereby
the speed of the rotor is related to the
frequency of the current produced. In the
large synchronous generators, the conductor
is stationary while the magnetic field is
rotated.
The state of the art of synchronous
generators is well developed with efficien-
cies for the central station size ranging
from 96 to 99 percent depending on the size
and load.
12.2.1.4 Stack Gas Cleaning
Stack gas cleaning has been receiving
considerable attention as a means of re-
ducing air pollutants from boilers. Some
stack gas cleaning processes, such as those
for collecting sulfur dioxides and particu-
lates, are commercially available at pres-
ent, but this is a developing technology.
The major problems with the processes are
not technical but eco.nomic.
Stack gas cleaning processes vary de-
pending on which of the three major air
pollutants (oxides of nitrogen, sulfur di-
oxide, or particulates) they are designed
to remove.
12.2.1.4.1 Oxides of Nitrogen
Oxides of nitrogen (NO ) are now
X
treated by modification of the combustion
process as indicated in Section 12.2.1.1,
Boilers. Nitrogen oxide "catalytic
scrubbers" for boiler stacks have been pro-
posed, but the scrubbers are much more ex-
pensive than combustor modification treat-
ment.
12.2.1.4.2 Sulfur Dioxide
Sulfur dioxide (SO2) residuals have
been the major air pollution concern
12-11
-------
associated with electric power generation
and the most difficult to control. Al-
though more than 50 individual processes
for removing SO_ from stack gases have been
identified (Battelle, 1973: 394), the most
effective appear to be "scrubbing" pro-
cesses in which the stack gas is passed
over or through a material that reacts
with SO, to form a compound. The resultant
compound is then either dumped (so-called
"throwaway" methods) or treated so that
some useful form of the sulfur may be re-
covered. The throwaway methods convert an
air pollution problem to a solid waste
problem, while the recovery methods involve
costly production of a surplus material.
The basic problem of stack gas desul-
furization is that of continuously removing
most of a small concentration of sulfur
dioxide from very large volumes of stack
gas (AEC, 1974s Vol. IV, p. A.2-24) . None
of the sulfur dioxide stack gas systems is
yet in routine full-scale operation on
large boilers burning high-sulfur coal.
Lime and limestone throwaway processes
are currently favored by the electric
utility industry as the best solution to
SO, emissions (Slack and others, 1972).
Their advantages are relative simplicity,
relatively low investment, and freedom
from the problems of marketing and making
a by-product. There are three principle
forms of this system, as illustrated in
Figure 12-6 (Slack and others, 1972):
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 limestone, install a
larger scrubber, recirculate more
slurry, grind the limestone finer,
or 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 lime kiln installation is expen-
sive to build and operate. Use
of lime also increases the problem
of deposit formation in the scrub-
ber (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.
A summary of some of the main processes
under consideration and their technological
status as of mid-1973 are listed in Table
12-2. Some process engineers anticipate
that present difficult]is will be overcome
by continued development and that success-
ful regenerative units will be installed
on perhaps three-fourths of the coal-fired
power plants by 1980 (AEC, 1974: Vol. IV,
p. A.2-27).
12.2.1.4.3 Particulates
Removing particulates from the gases
can be accomplished mechanically, electro-
statically, or, to a limited extent, as
part of the SO_ removal. Mechanical sepa-
ration 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 fall into a
hopper (dry cyclone). Depending on size
and type, mechanical separators vary in
efficiency from 65 to 94 percent (Nonhebel,
1964: 514).
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
12-12
-------
Stack
gas
Gas to stack
Scrubber
CaCQ,
•ra
Settler
Pump
tank"
METHOD I. SCRUBBER ADDITION OF LIMESTONE
CaS03+ CaS04
to waste
Stack
gas
CaCO.
Calciner
-Gas to stack
Ca(OH)2
Scrubber
Pump
tank
CaO
Settler
CaS03+ CaS04
to waste
METHOD 2, SCRUBBER ADDITION OF LIME
CaO +gas
CaCO-
Boiler
•Gas to stack
Scrubber
Pump
tank
Settler
to waste
METHOD 3. BOILER INJECTION
Figure 12-6. Lime and Limestone Stack Gas Scrubbing Methods
Source: Slack, Falkenberry, and Harrington 1972: 160.
-------
Table 12-2. Technological Status of Some Stack-Gas
Sulfur Dioxide-Removal Processes
Process
Major U.S.
engineering
participants
Status of demonstration plants
U.S. plants
operating on coal
of greater than
two percent sulfur
Other plants, U.S.
and foreign'',
operating on oil
or low-sulfur coal
Status of process
chemistry
Major technological
problem areas
Magnesium oxide wet
scrubbing
Sodium solution
scrubbing
Chemico
Wellman-Lord
Catalytic oxidation
Limestone into
boiler with wet
scrubbing
Wet scrubbing with
lime slurry feed
Wet scrubbing with
limestone slurry
feed
Monsanto
Combustion
Engineering
Combustion
Engineering
CHEMICO
Babcock and
Wilcox,
Combustion
Engineering
TVA
100-Mw unit near
startup
125-Mw unit under
construction
100-Mw unit completed
in 1972 but not yet
in operation
Shut down as a result
of continuing
operating
difficulties
Several near startup
175-Mw unit completed
in 1972; has not yet
met acceptance tests,-
many others of
greater than 100-Mw
under construction
Two 150-Mw units in
operation; U.S. on
oil, Japan with
throwaway cycle
250-Mw unit near
startup for coal of
one percent sulfur.
Smaller units of
several types
operating without
difficulty
Small units for
process development
only
No additional plants;
scheduled units have
been canceled
Successful operation
of 150-Mw unit in
Japan on coal of two
percent sulfur; other
plants operating
Small scale
development units
only
No major uncertainties
Additives required to
minimize oxidation to
Na2S04
Apparently no problems
Complex CaSO. scaling
difficult to control
Complex CaS04 scaling
difficult to control
Complex, not completely
understood; blinding of
limestone surface a
problem
Ash removal requirements
Sulfate formation
requires waste bleed and
caustic makeup
Ash removal requirements;
high operating tempera-
tures; catalyst
attrition; low H2S04
quality
Severe boiler operating
problems; poor limestone
utilization; severe
scaling, demister
plugging
Severe scaling, demister
plugging
Demister plugging; poor
dependab i1i ty; low
limestone utilization;
waste sludge disposal
Source: AEC, 1974: Vol. IV, p. A.2-26.
-------
tubes. Waste disposal is usually accom-
plished by rapping the tubes and collecting
the dust. The performance of a precipita-
tor depends strongly on the amount of sul-
fur in the dust. 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 the 0.59-
percent sulfur coal. Also, the efficiency
of electrostatic precipitators are 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 (Soo, 1972: 191). Most electro-
static precipitators are designed to have
removal efficiencies of between 92 and 99
percent.
12.2.1.5 Cooling
Selecting a suitable means of dissi-
pating waste heat depends on a number of
factors such as the quantity of heat to be
dissipated, the availability of water, and
local thermal pollution regulations. The
four types of cooling systems are:
1. Once-through cooling using fresh
or saline water.
2. Cooling ponds.
3. Wet cooling towers.
4. 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 generally used
where adequate supplies of water are avail-
able 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 sys-
tems. The only consumptive water uses are
those resulting from increased evaporation
in the source water bodies because of the
addition of heat (Jimeson and Adkins,
197la).
Where water supplies are limited and
suitable sites are available, cooling ponds
may be constructed so that water may be re-
circulated between the condenser and the
pond. Sufficient inflow would be needed,
either from upstream runoff or by diversion
from another stream, to replace the natural
evaporation and the evaporation induced by
the addition of heat to the pond. A pond
surface area of one to two acres per mega-
watt of plant capacity is normally required
to dissipate the heat. Cooling ponds are
frequently used for other beneficial pur-
poses, including recreation (Jimeson and
Adkins, 1971a).
Where conditions are not favorable for
once-through cooling or for the construc-
tion 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 in direct contact with a flow
of air, and the heat is dissipated prin-
cipally 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 (Jimeson and Adkins, 1971a).
Currently, the maximum size of a wet
cooling tower employing a natural draft is
about 400 feet in diameter and 450 feet
high. A tower of this size can provide the
cooling requirements for a 500-Mwe nuclear
plant or an 800-Mwe fossil-fired plant.
Wet cooling towers using mechanical draft
are constructed in multiple cells and a
plant may contain one or more banks of
cells. Forced-draft type fan diameters are
limited to 12 feet or less, compared to
nearly 60 feet for the induced draft type,
which necessitates more cells for a given
capacity (Jimeson and Adkins, 1971a).
12-15
-------
TABLE 12-3
COOLING WATER REQUIREMENTS FOR 1,000-Mwe PLANT
(ACRE-FEET PER YEAR)
Cooling Method
and Plant Type
(percent efficiency)
Once- through
Nuclear (32)
Coal (38)
Wet cooling tower
Nuclear (32)
Coal (38)
Cooling pond
Nuclear (32)
Coal (38)
Dry cooling3
Nuclear (29.2)
Coal (36.5)
Intake
1,558,000
925,900
31,020
18,440
47,650
28,300
311
248
Consumed
(evaporated)
0
0
19,390
11,520
28,600
17,000
0
0
Discharged
1,558,000
925,900
11,630
6,920
19,050
11,300
311
248
Source: Teknekron, 1973: Chapter 6.
Small quantity of makeup water for circulation.
In a dry cooling tower, the water cir-
culates in a closed system with the cooling
provided by a flow of air created either
by mechanical or natural draft. This sys-
tem is much like the radiator in an auto-
mobile, and no water is lost by evapora-
tion. Because of the large heat transfer
surface area and air volumes required,
however, dry cooling towers are substan-
tially more expensive than wet towers.
There are no large dry cooling towers at
power plants in this country. Recently, a
dry cooling tower for a 20-Mwe plant was
constructed in Wyoming (Jimeson and Adkins,
1971a).
The amount of water "consumed" by the
cooling process will depend on the specific
plant design and the affected water-body
conditions. Table 12-3 gives the cooling
water requirements (intake) and the cooling
water consumed (evaporated) for the four
cooling types, using both a 32-percent
efficient nuclear plant and a 38-percent
efficient fossil-fired plant operating at
100-percent load factors (Teknekron, 1973:
Chapter 6). The data show that once-
through systems require large amounts of
water but that none is consumed. Cooling
ponds require more intake water and consume
more water than do wet cooling towers.
However, these data do not agree with an-
other source that indicates wet cooling
towers consume 75 percent more water than
cooling ponds (Jimeson and Adkins, 1971a).
12.2.2 Energy Efficiencies
The efficiency of any power plant is
the amount of electrical energy output per
unit of fuel energy input. Modern steam
power plants in the 1,000-Mwe size range
are capable of .efficiencies of approxi-
mately 38 to 40 percent. This overall
efficiency is the product of the efficien-
cies of the boiler, turbine, and generator.
Typical efficiencies for these components
are 85 percent (both conventional and
12-16
-------
fluidized bed), 50 percent, and 97 percent
respectively.
In the boiler, energy is lost through
heat in the stack gas, unburned combusti-
bles, radiation and convection from boiler
walls, and loss due to hydrogen and mois-
ture in the fuel. Most of these individual
losses are small and probably unavoidable.
Stack gas temperatures represent the pri-
mary loss, but most of the heat energy is
removed by the series of superheaters, re-
heaters, economizers, and air preheaters.
Attempts at capturing the remaining heat
energy in the stack gas would probably not
be economical and, if the stack gases were
too cool, they would settle back to earth
near the plant rather than being dispersed
in the atmosphere.
The conversion of heat energy to me-
chanical energy performed by the turbine
represents the most inefficient component
in the electric power generation process.
However, the laws of thermodynamics elimi-
nate the possibility for significant im-
provements . The entire purpose of binary
cycle systems is to increase the efficiency
of this heat energy-to-mechanical energy.
conversion step. If the mercury binary
cycle is used in conjunction with the LMFBR,
net plant efficiencies up to 46 percent
might be achieved, as compared to potential
LMFBR single-cycle efficiencies of about
42 percent (AEC, 1974: Vol. IV, p. B.5-7).
If the potassium binary cycle is used
in a boiler-fired plant, the net plant
efficiency is estimated to be 50 to 55 per-
cent or more over a turbine inlet tempera-
ture range of 1,400 to 1,800°F (AEC, 1974:
Vol. IV, p. B.5-7). This compares with 38
to 40 percent for a plant using a single-
steam turbine.
There is little likelihood that the
generator efficiency of 96 to 99 percent
can be improved.
The type of cooling system used has
only a slight effect on overall plant effi-
ciency. The dry cooling system is the most
energy consumptive cooling system, requir-
ing approximately 10 percent of the net
plant output.
No firm data have been found on the
energy required to run stack gas cleaning
processes, but a Battelle study "assumed"
an overall plant efficiency reduction of
two percent (from 37 percent to 35 percent)
when various SO- scrubbing technologies
are applied (Battelle, 1973: 93). The
Hittman study listed the efficiencies for
"controlled" plants (i.e., those employing
stack gas cleaning along with other environ-
mental controls) as 38 percent, which is
the same as the efficiency for their "un-
controlled" plants (Hittman, 1974: Vol. I,
Table 26).
Improving the efficiency of electric
power generation is the focus of major
research efforts at the current time, and
many of the alternatives described in the
following sections are aimed entirely at
increasing this efficiency. Improved effi-
ciencies can have a beneficial impact on
operating costs (reduced fuel bills), but
the primary interest is in conserving
limited fossil fuel resources and reducing
the environmental impacts of electrical
generation. To illustrate the effect, if
the efficiency of conversion can be in-
creased from 30 to 40 percent, the chemical
pollutants emitted per unit of electricity
output will decrease by 25 percent. For
thermal pollution, an increase in effi-
ciency from 30 to 40 percent will decrease
waste heat by approximately 36 percent.
12.2.3 Environmental Considerations
Table 12-4 lists the residuals for
several different boiler-fired power plants
burning different fuels. In this table,
lines one through three are for a conven-
tional steam power plant with no controls
burning coal, oil, and gas, respectively.
These data should be considered to have a
probable error of less than 50 percent.
The coal line assumes a pulverized-feed
12-17
-------
Table 12-4. Residuals for Boiler-Fired Power Plants
SYSTEM
1 ro&t
Conventional steam
Conventional steam
No controls"
i RAB
Conventional Steam
No controls"
4 CENTRAL COAL
Atmospheric
Fluidized Bed
Controlled"
NORTHERN APPALACHIAN
5 COAL
Atmospheric
Fluidized Bed
Controlled
Atmospheric
Fluidized Bed
Controlled13
Water Pollutants (Tons/10" Btu's)
OJ
"O
•H
u
«K
u
u
o
0
0
Bases
u
u
u
o
0
0
't
8
u
u
u
u
u
u
m
g
U
u
u
u
u
u
Total
Dissolved
Solids
5.81
7,44
7.44
18.2
18.2
18.2
Suspended
Solids
6.84
.709
.709
0
0
0
Organics
2.71
.015
.016
.003
.003
.003
§
U
u
u
u
u
u
Q
8
u
u
u
u
u
u
N~
rH
o
iH
.-i X
ro if)
^ .
3 3
01 JJ
c m
5. 2b
xlOll
5.2b
xlOU
5.26
xlO^
0
0
0
ir Pollutants (Tons/1012 Btu1
particulates
82.2
27.2
7.34
11.3
8.52
5.31
X
g
369.
357.
191.
70.
70.
70
X
O
in
2020.
801.
.293
378
167
56.8
Hydrocarbons
6.15
6.81
19.6
242.
242
242
8
20.5
138
190
2.5
2.5
2.5
s)
Aldehydes
103
.40
3.43
0
0
0
"»
Solids
(Tons/1012 Btu
050.
0
0
6990.
5880
3990
F/x*
01
^ -
ro 3
0) -U
> (P
i
•D 0) C4
C IJ ft
(0 O O
H) ft -<
8.49
2.48
1.42
1.62/.18
4.28
3.82
— i — c.i 1 1
3.10
Occupational
Health
1012 Btu's
Deaths
001
.0006
.0006
U
U
U
Injuries
0106
06
057
U
U
U
u
V)
3
CH
>1
IS
Q
I
C
ra
E
4.41
2.5
2.36
U
U
U
-------
Table 12-4. (Continued)
SYSTEM
7 EASTERN COAL
Conventional Boiler
with wet limestone
scrubbing0
8 EASTERN COAL
Conventional Boiler
with Mc:O scrubbina°
9 WESTERN COAL
Conventional Boiler
with wet limestone
scrubbing0
PHYSICALLY CLEANED
10 EASTERN COAL
Conventional Boiler
with limestone
scrubbing0
11 COAL
Steam Plant with
controls15
Water Pollutants (Tons/1012 Btu's)
Acids
9
0
0
0
0
Bases
NC
NC
NC
NC
0
£
NC
NC
NC
NC
U
rn
8
NC
NC
NC
NC
U
Total
Dissolved
Solids
0
0
0
0
18.2
Suspended
Solids
12.5
12.5
12.5
12.5
0
Organ ics
5.5
5.5
5.5
5.5
.003
Q
8
NC
NC
NC
NC
U
Q
8
NC
NC
NC
NC
U
Thermal
(Btu's/1012)
0
0
0
0
0
Air Pollutants (Tons/1012 Btu's)
Particulates
50.
50.
35.
22.
20.6
X
300.
300.
390.
275.
369.
X
o
250.
250.
80.
100.
202.
Hydrocarbons
6.5
6.5
8.
5.5
6.15
8
21.
21.
27.
19.
20.5
Aldehydes
NC
NC
NC
NC
.103
Solids
(Tons/1012 Btu's)
1.49
xlO*
6400.
7600.
6500.
1.46
xlO4
F/Ta
01
^ -
a 3
0) u
> a
i
13 5) (N
C tJ -i
ro u o
iJ rt — i
12 . 5/U
12.5
12.5/0 '
12.5
12. 5/U
12.5
12. 5/U
12.5
6.9/.2
11.5
Occupational
Health
1012 Btu's
Deaths
.0003
.0003
.0003
.0003
.0002
Injuries
.014
.014
.014
.014
.024
V
to
0
U]
ID
P
C
to
S
5.1
5.1
5.1
5.1
2.6
-------
Table 12-4. (Continued)
~~
SYSTEM
12 LOW-BTU GAS
(Central Coal,
BuMines-Atmospheric)
Boiler PAant with
controls13
13 LOW-BTU GAS
(Northern
Appalachian Coal,
BuMines-Atmospheric)
. Boiler PJ-ant with
controls"
14 LOW-BTU GAS
(Northwest Coal
BuMines-Atmospheric)
Boiler Plant with
controls'3
15 RESIDUAL FUEL OIL
Steam Power Planta
16 NATURAL GAS
Steam Power Plant
17 BITUMINOUS COAL
d
Steam Power Plant
18 LOW-BTU GAS
Steam Power Plant
Water Pollutants (Tons/lol2 Btu's)
Acids
0
0
0
1.17
Ivl5
1.16
1.16
Bases
0
0
0
NC
NC
NC
NC
f
s
u
u
u
.6
.5
.58
.58
n
§
U
U
U
NC
NC
NC
NC
Total
Dissolved
Solids
3.4
3.4
3.4
66.
71.
71.
65.
Suspended
Solids
0
0
0
5.76
6.95
7.
7.
Organics
.003
.003
.003
.94
.925
.93
.92
Q
§
u
u
u
.034
.033
.034
.034
§
U
u
u
NC
NC
NC
NC
Thermal
(Btu's/1012)
0
0
0
NC
NC
NC
NC
Air Pollutants (Tons/1012 Btu's)
Particulates
125.
115.
216.
21.1
7.13
NC
NC
X
§
56.9
6.63
7.76
351.
185.
383.
168.
X
o
0)
269.
488.
15.6
531.
.286
808.
9.18
Hydrocarbons
0
0
0
6.7
21.
6.36
NC
8
0
0
0
.13
NC
21.3
NC
Aldehydes
0
0
0
3.3
1.42
.1
NC
tn
Solids
(Tons/1012 Btu
0
0
0
110.
NC
5055.
NC
F/xa
tn
h -
ID S
v a
>
-------
furnace burning coal with an ash content of
12.53 percent and a sulfur content of 2.59
percent. The oil line assumes a 1.5-per-
cent sulfur oil. The thermal pollution for
these plants is equal, because all have the
same conversion efficiencies. The primary
chemical pollutants are: particulates,
NO , SO», and solid wastes for coal; NO
X £. X
and SO0 for oil; and NO only for gas.
£. X
In Table 12-4, lines four through six
are for the Pope, Evans, and Robbins Atmos-
pheric Pressure Fluidized-Bed power plant
burning three different types of coal: a
high-sulfur Central Region coal, a medium-
sulfur Northern Appalachian coal, and a
low-sulfur Northwestern coal. The air and
solid residuals have a probable error of
less than 25 percent, while the water re-
siduals have a probable error of less than
100 percent.
Lines 7 through 11 in Table 12-4 give
the residuals for steam power plants em-
ploying various stack gas scrubbing tech-
nologies in combination with different fuel
types. Lines 7 through 10 are samples of
data from the Battelle study. The two
processes considered are throwaway wet
limestone scrubbing and magnesium oxide
(M O) scrubbing with recovery of sulfuric
acid (H_SO4). Both processes include par-
ticulate removal. These data are based on
removal efficiencies of 90 percent for SO2,
20 percent for NO , and 99 percent for par-
X
ticulates. The Eastern coal is assumed to
be 3.0-percent sulfur and 14.4-percent ash.
The Western coal is 0.8-percent sulfur and
8.4-percent ash. The physically cleaned
Eastern coal is 1.4-percent sulfur and
7.2-percent ash. Line 11 is from the
Hittman study and is for a "controlled"
plant burning coal. The "controls" mean
that virtually all water effluents can be
eliminated except nondegradable organics,
cooling towers are used, and a wet lime-
stone scrubber system is employed with SOx
removal efficiencies of 85 percent and par-
ticulate removal efficiencies of 99 percent.
The coal is assumed to be a national aver-
age coal, with 12.53-percent ash and 2.59-
percent sulfur.
Lines 12 through 14 are from the
Hittman study and are for boiler-fired,
"controlled" plants burning low-Btu gas
from the Bureau of Mines Atmospheric pro-
cess for three different coals (Central,
Northern Appalachia, and Northwest). These
residuals assume that all water effluents
can be eliminated and that an electrostatic
precipitator with 97-percent efficiency is
employed for air emissions. Residuals data
on these plants is considered poor, with a
probable error of less than 100 percent.
Lines 15 through 18 are from the
Teknekron study and are for steam power
plants burning four different types of
fuel. All four cases assume that wet cool-
ing towers are used. The residual fuel oil
case assumes an oil containing one-percent
sulfur and 0.5-percent ash, and particulate
removal with 84-percent efficiency. The
bituminous coal case assumes one-percent
sulfur and 12-percent ash, and particulate
removal with 99-percent efficiency. The
low-Btu gas case is based on clean gas made
from coal with three-percent sulfur.
In addition to the residuals listed
in Table 12-4, boiler-fired power plants
can also be large consumers of water, de-
pending on the type of cooling method used
and the plant efficiency. The water re-
quirements for the four major types of
cooling were given in Table 12-3.
12.2.4 Economic Considerations
Currently, the conventional boiler-
fired steam turbine system is the most
economical and technologically developed
system available to the electric power
industry. Estimates for 1972 capital costs
per kilowatt (kw) of installed capacity
for plants with no stack gas cleaning are
$180 for coal, $150 for oil, and $100 for
gas (CEQ, 1973: 44, 50, 54). Presumably,
these costs have risen considerably in the
12-21
-------
TABLE 12-5
GENERATION COSTS (1971) FOR STEAM
POWER PLANTS WITH NO STACK GAS CLEANING
(MILLS PER KILOWATT HOUR)
Cost Category
Power plant (capital
costs)
Fuel
Fuel storage
Operation and
maintenance
TOTAL
Fuel Source
Coal
4.05
3.14a
.08
.39
7.66
Oil
3.38
4.04b
.04
.21
7.67
Gas
2.25
4.58C
NA
.24
7.07
NA = not applicable
Source: Olmstead, 1971.
Based on a cost of $.35 per million Btu's.
Based on a cost of $.45 per million Btu's.
Q
Based on a cost of $.51 per million Btu's.
recent past. Table 12-5 shows generation
costs determined in a survey of steam
plants during 1971 (Olmstead, 1971) and are
the same data included in the Hittman study,
except that Hittman excluded fuel costs.
Binary cycle plants will clearly have
higher capital costs than the conventional
steam plant due to the increased complex-
ity, but these costs could be offset by
higher plant efficiency. Detailed plant
and equipment design studies are needed to
develop more reliable cost data.
The Hittman study included cost data
for the Pope, Evans, and Robbins Fluidized-
Bed Systems on a mills per kilowatt-hour
(kwh) basis (excluding fuel). This cost,
2.77 mills per kwh (1972 dollars), appears
low in comparison to the costs for a con-
ventional boiler system with no stack gas
cleaning, as listed in Table 12-5.
Most of the SO stack gas cleaning
technology is at such an early stage of
development that it is difficult to make
any definitive statements about its cost.
The Hittman data places the incremental
cost of the wet limestone scrubbing system
for coal at 1.8 mills per kwh. Table 12-6
summarizes the estimated economics of sev-
eral SO2 control systems (Davis, 1973).
These cost estimates include the cost for
particulate removal. For comparison pur-
poses, the estimated operating cost for an
early wet limestone scrubbing process at
Commonwealth Edison's Will County Unit One
is 4.5 mills per kwh (Battelle, 1973: 409).
Part of this high-cost is attributable to
a difficult retrofit task, overtime paid
to meet regulatory deadlines, and a rela-
tively expensive sludge disposal system.
In 1972, the Environmental Protection
Agency (EPA) estimated, based on certain
assumptions concerning clean fuel avail-
ability, that stack gas cleaning would be
applied to 30 to 50 percent of existing
coal- and oil-fired capacity. It was pre-
dicted that 80 or 90 percent of the power
plants in the Northeastern U.S. could in-
stall stack gas desulfurization processes
with a kwh cost at or below that which
would be required if high-cost clean fuels
were used (Battelle, 1973: 409).
The type of cooling system chosen can
have an effect on electric power costs.
The exact costs for any system will, of
course, depend on the design conditions,
but a range of capital cost data gathered
in a 1971 study is given in Table 12-7.
The cooling costs for nuclear systems are
generally higher because of lower plant
efficiencies.
A further discussion and comparison of
the economics of electric power are given
in Section 12.9.^
12.3 GAS TURBINE POWER PLANTS
The electric utility industry has made
increasing use of gas turbines in the last
10 years; they now represent nearly eight
percent of the nation's installed generating
12-22
-------
TABLE 12-6
•)
SULFUR DIOXIDE AND PARTICULATE CONTROL SYSTEM COST3
Process
Dry Limestone
Injection
Wet Lime/Limestone
Scrubbing
Magnesium Oxide
Scrubbing
Sodium Sulfite
Scrubbing
Throwaway
or
Recovery
Throwaway
CaSO3/CaSO4
Throwaway
CaSO3/CaSO4
Recovery :
Concentrated
H2SO4 or
Sulfur
Recovery :
Concentrated
H2SO4 or
Sulfur
Investment
Cost (dollars
per kilowatt)
17-19
27-46
33-58
38-65
Annual Cost (mills per kilowatt hour)b
Without
Sulfur
Recovery
Credit
0.6-0.8
1.1-2.2
1.5-3.0
1.4-3.0
With Sulfur
Recovery
Credit
U
U
1.2-2.7
1.1-2.7
Sulfur Dioxide
Removal
Efficiency
Percent
22-45
80-90
90
90
U = unknown.
Source: Davis, 1973.
a
Costs are expressed in 1973 dollars.
3Based on 80 percent load factor and fixed charges of 18 percent of capital costs.
capacity. The major use is to accommodate
peak loads to which the gas turbines can
respond because of their fast start-up
time. In addition, they have been attrac-
tive because of low initial cost and short
delivery times.
This section will describe a simple
gas turbine power plant. Other systems
that use gas turbines in conjunction with
steam turbines (combined cycle plants) are
described in Section 12.4.
12.3.1 Technologies
The gas turbine, sketched in Figure
12-7, is essentially the same engine used
in jet aircraft. Incoming air is com-
pressed and injected into a combustion
chamber with the gaseous or vaporized
liquid fuel. The high-temperature, high-
pressure combustion gas expands and drives
the turbine similar to the process in a
steam turbine. The turbine drives both
the generator and the compressor. A re-
generator may be used to transfer heat from
the exhaust gases to the incoming air.
Note that no cooling is required since the
exhaust gases are vented directly to the
atmosphere.
An important characteristic of the
gas turbine is the requirement for a clean
(no particulates or corrosive components)
gas flow through the turbine. This neces-
sitates either a clean burning fuel or a
source of high-temperature thermal energy,
such as a nuclear reactor, where the fuel-
element coolant is the high-pressure,
heated gas for the turbine expansion.
12-23
-------
Combustion Chamber
Regenerator
Exhaust
Gas
Generator
Turbine
Compressor
Air
Figure 12-7. Regenerative Cycle Gas Turbine
Source: AEC, 1974: B.4-2.
-------
TABLE 12-7
COSTS OF COOLING SYSTEMS FOR STEAM-ELECTRIC PLANTS
Type of System
Once- through
Cooling pondsc
Evaporative cooling towers
Mechanical draft
Natural draft
Dry cooling towers
Mechanical draft
Natural draft
Investment Cost
(dollars per kilowatt)
Fossil-Fueled
Plant3
2.00- 3.00
4.00- 6.00
5.00- 8.00
6.00- 9.00
18.00-20.00
20.00-24.00
Nuclear-Fueled
Plant3
3.00- 5.00
6.00- 9.00
8.00-11.00
9.00-13.00
26.00-28.00
28.00-32.00
Source: Jimeson and Adkins, 1971b: 67.
TJased on unit sizes of 600 Mwe and larger.
Circulation from lake, stream, or sea and involving no investment
in pond or reservoir.
GArtificial impoundments designed to dissipate entire heat load
to the air. Cost data are for ponds capable of handling 1,200 to
2,000 Mwe of generating capacity.
12.3.2 Energy Efficiencies
Simple-cycle gas turbines without re-
generation have overall thermal efficien-
cies of 27 percent, while those with regen-
eration can obtain efficiencies of 34 per-
cent (AEC, 1974: Vol. IV, p. B.4-7).
12.3.3 Environmental Considerations
Because gas turbines require clean
burning fuels, most of the stack gas emis-
sions (e.g., SO_, particulates, etc.) are
negligible. Although NO is a problem
area, it is currently being controlled by
injecting demineralized water into the com-
bustion chamber. Most gas-turbine manufac-
turers feel that they will be able to offer
combustion chambers that will reduce oxides
of nitrogen without the necessity for water
injection.
Neither the Hittman, Battelle, nor
Teknekron studies has any residual coeffi-
cients for gas turbines. However, the
Hittman study does have residual data for
combined-cycle power plants burning low-Btu
gas, as described in Section 12.4. Pre-
sumably, the residual data would be similar
for the gas turbine system.
12.3.4 Economic Considerations
Capital costs for gas turbine plants
are approximately $90 per kw for single
cycle and $100 per kw for regeneration
cycle plants (1972 dollars) (AEC, 1974:
Vol. IV, p. B.4-13). This compares to
approximately $180 per kw (1972 dollars)
for coal-fired power plants as listed
earlier. Thus, gas turbine plants have
definite capital cost advantages over the
more complex coal-fired steam plants.
However, due to their lower efficiency and
their need for clean fuels, the fuel costs
for gas turbine plants can be much higher.
12-25
-------
For example, the Federal Power Commission
(FPC) estimated that in 1990, the fossil
fuel costs for steam plants would be 3.79
mills per kwh (1968 dollars), while the
fuel costs for clean fuels (for gas tur-
bines and diesel) would be 16.1 mills per
kwh (1968 dollars) (FPC, 1971: p. 1-19-7).
12.3.5 Other Constraints and Opportunities
If a gas turbine plant is constructed,
it must have available a clean burning
gaseous or liquid fuel. On the other hand,
conventional steam plants can be relatively
easily converted from one type of fuel to
another.
12.4 COMBINED CYCLE POWER PLANTS
In this section, two power systems
that combine gas turbine and steam turbine
cycles will be described: the gas turbine/
steam turbine system and the Westinghouse
pressurized fluidized-bed system.
12.4.1 Technologies
A very important variation of the
simpler gas turbine system described in
Section 12.3 is the combined gas turbine
and steam turbine plant. In this plant,
the hot exhaust from the gas turbine is
used to generate steam in an unfired
boiler, and the steam is used to drive a
conventional steam turbine. (Some plants
have an in-between variation where the gas
turbine exhaust generates steam along with
a fired boiler, but here only the charac-
teristics of those combined-cycle systems
that use unfired boilers will be consid-
ered.) For instance, a 1,000-Mwe plant
might consist of four gas turbines and
their associated electrical generators,
plus one steam turbine with its electrical
generator.
A sketch of the combined-cycle pro-
cess is given in Figure 12-8. There are
really no technological components required
for the combined-cycle system that have not
already been covered in the sections on
steam turbines or in the preceding discus-
sion of gas turbines. The combined-cycle
system is being used currently by some
utilities for serving intermediate system
loads but presumably could be used in the
future for baseloads.
A new concept in combined-cycle sys-
tems is Westinghouse's pressurized fluid-
ized-bed system, whose development is
being supported by EPA. This system com-
bines the fluidized-bed boiler concept de-
scribed in Section 12.2 and the gas-turbine
system described in Section 12.3. The
system is illustrated in Figure 12-9.
Essentially, the concept is to burn coal
in a dolomite (limestone) bed at 10 atmos-
pheres of pressure. The water is initially
heated to steam in the walls of the combus-
tor and is then superheated in the beds.
The steam drives a conventional turbine and
has one heat cycle. The combustion gases,
after particulate removal, are used to
drive a gas turbine, and the heat remaining
in the gas turbine exhaust is used to pre-
heat the boiler feedwater. The spent dolo-
mite is regenerated.
12.4.2 Energy Efficiencies
Gas turbine/steam turbine plants now
available have overall thermal efficiencies
in the range of 36 to 38 percent. Commer-
cial design should be available in the
1975 to 1977 period having improved effi-
ciencies, in the range of 40 to 42 percent,
making them competitive with the best avail-
able conventional steam plants. By 1980,
some designers feel further evolutionary
developments could yield efficiencies in
the range of 43 to 45 percent (AEC, 1974:
Vol. IV, p. B.4-7).
The overall efficiency for the
Westinghouse system is about 36 percent
{Hittman, 1975: Vol. II), but further
improvements are projected to obtain an
overall efficiency near 45 percent (Keairns
and others, 1972).
12-26
-------
Exhaust Gas
Boiler
Fuel
Generator
Cooling Water
Combustion
Chamber
Gas Turbine
Compressor
"Air
Generator
Figure 12-8. Combined Cycle Gas Turbine
Source: AEC, 1974: B.4-5.
-------
Tail Gas
Sulfur
Plant
1- • fc •
^ ^
/
Coal
Air
1
Dolomite
Regenerator
Regenerated
«*•
Dolomite
Particulate
Removal
Solid Waste
Pressurized
Fluidized Bed
Boiler
1750° F
10 atm.
t
Spent
Dolomite
Coal and
Makeup
Dolomite
2000° F
Carbon Burnup
Cell
Air
Steam
Steam
Turbine Generator
Preheated Feedwater
300° F
Stack
Solid Waste
I
Air
Gas
Turbine\
Figure 12-9. Westinghouse Pressurized
Fluidized-Bed Boiler Power Plant
Source: Hittman, 1975: Vol. II, p. VI-3.
»
»Heat Recovery
Cooling Water In
-------
Table 12-8. Residuals for Environmentally Controlled Combined-Cycle Electricity Generation
SYSTEM
CENTRAL
"j BuMmes-Pressurized
Combined-cycle
lioppers-Totzek
Combined-cycle
NORTHERN APPALACHIA.
, BuMines-Pressurized
Combined-cycle
. Koppers-Totzek
Combined-cycle
NORTHWEST
, BuMines-Pressurized
Combined-cycle
,. Lurgi
Combined-cycle
7 Koppers-TotzeX
Combined-cycle
CENTRAL COAL
Combined -cycle
8 Pressurized Fluidized
Bed
NORTHERN APPALACHIAN
COAL
Combined-cycle
9 Pressurized Fluidized
Bed
NORTHWEST COAL
Combined-cycle
10 Pressurized
Fluidized Bed
Water Pollutants (Tons/1012 Btu's)
Acids
0
0
0
0
0
0
0
0
0
0
Bases
0
0
0
0
0
0
0
0
0
0
•*
£
u
u
u
u
u
u
u
u
u
u
<">
u
u
u
u
u
u
u
u
u
V
Total
Dissolved
Solids
3.4
3.4
3.4
3.4
3.4
3.4
3.4
18.2
18.2
18.2
Suspended
Solids
0
0
0
0
0
0
0
0
0
0
Organ ics
.003
.003
.003
.003
.003
.003
.003
.003
.003
.003
Q
§
u
u
u
u
u
u
u
u
u
u
o
8
u
u
u
u
u
u
u
u
u
u
Thermal
(Btu's/1012)
0
0
0
0
0
0
0
0
0
0
Air Pollutants (Tons/1012 Btu'a)
Particulates
3.75
.462
3.44
.503
468.
14.3
,456
9.29
12.3
9.70
X
39.4
23.7
.1,9., 3
19.6
32.4
10.
15, ,9.
67.3
67.3
67.3
X
O
tt>
278.
457.
.47,4
91.2
165.
28.6
25.9
441.
210.
71.8
Hydrocarbons
0
0
.P. . ..
0
0
0
0
0
0
0
8
0
0
. o
0
0
0
0
0
0
0
Aldehydes
0
0
0
0
0
0
.0. .
0
0
0
Solids
(Tons/1012 Btu's)
0
0
.0
0
0
0
0
6760.
5780.
3950.
V
Land
Acre-year
in
•2
a
M
CN
T-i
O
•-H
.217/0
.217
.482/0
.482
. 205/6
slS^ •
.482/0
.482
. 181/0
.181
.418/0 "*
.418
.418/0
.418
1.62/.17
4.19
1.62/. 14
3.78
1.62/.10
3.09
Occupational
Health
1012 Btu's
Deaths
.0002
.0002
,P002,
.0002
.0002
.0002
.0002
U
U
U
Injuries
.0188
.0188
.0188
.0188
.0188
.0188
.0188
U
U
U
4->
U)
S
W
>,
ro
Q
i
c
ro
£
2.08
2.08
2.08
2.08
2.08
2.08
2.08
tr
u
u
NA = not applicable, NC = not considered, U = unknown.
aFixed Land "Requirement (Acre - year) / Incremental Land. Requirement (
101-2 Btu's
Acres )
1012 Btu's
-------
12.4.3 Environmental Considerations
Residuals data for a combined-cycle
plant burning low-Btu gas are given in
lines 1 through 7 of Table 12-8. These
data are considered poor, with a probable
error of less than 100 percent. Residuals
are given for low—Btu gas from two systems
(the Bureau of Mines [BuMines] Pressurized
process and the Koppers-Totzek process),
for three coals (Central, Northern
Appalachia, and Northwest), and for low-Btu
gas from the Lurgi process. Note these
residuals are for the electric power gen-
eration step only and do not include re-
siduals from the low-Btu gasification step.
The residual data for the Westinghouse
combined-cycle pressurized fluidized-bed
system are given in lines 8 through 10 of
Table 12-8 for three different types of
coal: a high-sulfur Central Region coal,
a medium-sulfur Northern Appalachian coal,
and a low-sulfur Northwestern coal. The
data are considered good with a probable
error of less than 25 percent for air and
land data but are considered poor with a
probable error of less than 100 percent for
water data. These data are discussed and
compared to other systems in Section 12.8.
12.4.4 Economic Considerations
The approximate capital cost for a
gas turbine/steam turbine plant is $150 per
kw (AEC, 1974: Vol. IV, p. B.4-13). No
operating cost data are available.
Cost data for the Westinghouse system
is included in the Hittman study and is
4.64 mills per kwh (1972 dollars), exclud-
ing fuel costs.
Westinghouse*s own cost estimates
(using different economic assumptions than
the Hittman study) for their system are
shown in Table 12-9.
For comparison, the economics for a
conventional boiler system with stack gas
cleaning were calculated by Westinghouse
using the same assumptions, and this yielded
a cost of 13.20 mills per kwh.
TABLE 12-9
COSTS FOR WESTINGHOUSE
COMBINED CYCLE FLUIDIZED-BED SYSTEM
Cost Category
Fixed charges
Fuel
Dolomite or limestone
Operation and
maintenance
TOTAL
Generation Costs
(mills per
kilowatt hour)
6.75
4.35
0.12
0.90
12.12
Source: Keairns and others, 1972: 274.
12.5 FUEL CELL POWER PLANTS
There are no commercially available
power plants using fuel cells, and the most
optimistic estimates place prototype plants
several years in the future. Their theo-
retical attractiveness, however, appears
to justify continued research and develop-
ment, and they are identified here as a
long-term potential option.
12.5.1 Technologies
A fuel cell is a device that produces
electrical energy directly from the con-
trolled electrochemical oxidation of fuel.
Since fuel cells do not require an inter-
mediate heat cycle, they are not limited
by the Carnot efficiency and have a theo-
retical efficiency approaching 100 percent.
The basic components of a simple hydrogen-
oxygen fuel cell (illustrated in Figure
12-10) are the electrodes (anode and cath-
ode) and an electrolyte. The electrolyte
may be either acidic or basic. The reac-
tants are normally consumed only when the
external circuit is completed, allowing
electrons to flow and the electrochemical
reaction to occur. The result is good fuel
efficiency even with low or intermittent
loads.
12-30
-------
Fuel(H2)
Porous
"Anode
Porous
Cathode
Spent Fuel and"
Water Vapor
Spent Oxidant
Electron Flow
Oxidant (02)
Figure 12-10. Hydrogen-Oxygen Fuel Cell
Source: AEG, 1974: B.6-2.
-------
When the external circuit is completed,
an oxidation reaction yielding electrons
takes place at the anode and a reduction
reaction requiring electrons occurs at the
cathode. The electrodes provide electro-
chemical-reaction sites and also act as
conductors for electron flow to the exter-
nal circuit. Power is produced as long as
fuel and oxidant are supplied to the fuel
cell and the external electrical circuit
is closed, allowing current to flow (AEC,
1974: Vol. IV, p. B.6-1). Continuous
operation necessitates the removal of heat,
water, and any inert material that enters
the cell with the reactants, and reaction
kinetics are usually enhanced by the incor-
poration of a catalyst such as platinum on
the high surface area electrode surfaces.
The power produced from fuel cells is
direct current (DC) and thus must be con-
verted to alternating current (AC) before
being usable in conventional electric power
systems.
Two routes are being followed with
respect to fuel cell development for rou-
tine electric power generation: one for
central power station application, and the
other for dispersed generation of electri-
cal power at substations. For either type
of system there are three main classifica-
tions of fuel cells, according to the type
of fuel used: hydrogen-oxygen, hydro-
carbon-oxygen, and reformer. The operation
of the hydrogen-oxygen type was described
above. The hydrogen fuel would presumably
be provided by nuclear or solar energy
sources. The hydrocarbon-oxygen cells use
gaseous hydrocarbons directly in a phos-
phoric acid electrolyte fuel cell. The
reformer cells actually consist of two
stages. First, coal or various hydrocar-
bons are reformed (reacted with steam) to
produce a fuel that consists primarily of
hydrogen and carbon monoxide. (Note that
this is exactly the low-Btu gasification
.process described in the chapter on coal.)
The hydrogen and carbon monoxide fuel are
then used in a high-temperature fuel cell.
Some of the major fuel cell develop-
ment programs are as follows (AEC, 1974:
Vol. IV, Section B.6):
1. Westinghouse is developing a 100—
kw system based on low-Btu gasifi-
cation of coal (to carbon monoxide
and hydrogen) and a high-tempera-
ture (1,870°F) zirconin electro-
lyte fuel cell. The development
is aimed toward central station
power production uses. The total
system consists of fuel cell bat-
tery tubes assembled into banks,
a coal gasifier, and ancillary
equipment. Cell banks, which
operate at 1,850°F, are physically
located in the fluidized-bed coal
gasifier for maximum heat recovery.
2. Pratt and Whitney, under the spon-
sorship of 31 gas utilities, is
developing fuel cell systems using
reformed natural gas as fuel.
This low-temperature (less than
250°F), fuel cell is designed ini-
tially for dispersed power genera-
tion. In May 1971, a 12.5-kw
system was demonstrated and more
than 4,000 hours of automatic
operation has been achieved. This
system will also use gasified coal.
3. The Institute of Gas Technology is
doing work complementary to the
Pratt and Whitney effort. This
group is developing a low-tempera-
ture phosphoric acid and higher
temperature (2,200°F) molten car-
bonate electrolyte cell designed
to use either natural gas or gasi-
fied coal. (It is not clear
whether these cells use the fuel
directly or whether it is reformed
first.)
The further research and development
needed for fuel cells is considerable. Al-
though their feasibility has been clearly
demonstrated, considerable work still re-
mains to determine whether they offer any
advantages in terms of economics, environ-
mental impacts, or energy conversion effi-
ciencies.
12.5.2 Energy Efficiencies
The present published efficiency of
conversion of chemical energy from natural
gas fuel to AC electrical energy, including
the reforming step, is 40 to 45 percent in
12-32
-------
the 12.5-kw Pratt and Whitney system. The
large central station version of this sys-
tem is projected to have an overall effi-
ciency around 55 percent.
The Westinghou.se high-temperature sys-
tem is designed to operate at a projected
efficiency of 58 percent for the 100-kw
size and near 70 percent for 1,000-Mwe,
based on DC output.
12.5.3 Environmental Considerations
Central station systems using fuel
cells will produce chemical pollutants
similar to those obtained by conventional
combustion of the same fuels, except that
NO emissions will be reduced because of
X
the reduced temperatures to which air
streams are exposed (AEC, 1974: Vol. IV,
p. B.6-14). However, the fuel cell is
particularly sensitive to pollutants, such
as sulfur, now causing concern in conven-
tional steam turbine plants. Thus, the
pollutants must be removed prior to the
fuel cell system.
If the higher projected efficiencies
of fuel cells (as compared to conventional
systems) are achieved, this would, of
course, yield the primary environmental
benefit, as discussed previously with all
of those systems aimed at achieving higher
conversion efficiencies. Waste-heat rejec-
tion is not a significant problem with fuel
cell power systems because most of the
waste heat is used in the fuel gasification
or reforming process. Excess heat is re-
jected to the atmosphere, and cooling water
is not required.
Gas transmission by buried pipeline
requires less land for an equivalent amount
of energy transmitted, and thus dispersed
power generation via fuel cells would have
a positive effect on the environment. How-
ever, the total environmental impact of
overhead transmission lines versus buried
pipelines has not been fully evaluated.
12.5.4 Economic Considerations
Since no large fuel cell power systems
have been built, an estimate of the costs
is somewhat speculative. However, initial
economic calculations for the coal-fired
Westinghouse system do show that it could
produce competitively priced electricity.
The projected economics of fossil-fueled
fuel cell systems show capital costs com-
parable to conventional systems but lower
operating costs.
Economic estimates for dispersed gen-
eration of electrical power are much more
complex and speculative. The capability
for gaseous fuel storage at the point of
usage allows a degree of freedom not found
in present electrical distribution systems.
12.5.5 Other Constraints and Opportunities
Dispersed power generation, where the
waste heat could be utilized for residen-
tial heating and for hot water needs, ap-
pears to be a potentially attractive option.
However, this requires a drastic change
from the current operational mode.
12.6 MAGNETOHYDRODYNAMIC POWER PLANTS
Like the fuel cell option, there are
no commercially available power plants
using MHD, and the most optimistic esti-
mates place prototype plants many years in
the future. However, their theoretical
attractiveness appears to justify continued
research and development, and they are
identified hare as a long-term potential
option.
12.6.1 Technologies
An MHD generator produces electrical
energy directly from thermal energy and has
the potential for conversion efficiencies
in the range of 50 to 60 percent. The
higher conversion efficiency results pri-
marily from the high temperature at which
MHD generators operate but also from
12-33
-------
bypassing the heat energy to mechanical
energy conversion step that occurs in steam
power plants.
As previously described, a conven-
tional large generator works by spinning a
magnet around a stationary conductor. In
an MHD generator, the conductor is an
electrically conductive fluid. As illus-
trated in Figure 12-11, the conductive
fluid flows through a rectangular duct
which is immersed in a magnetic field. As
the conductive fluid flows through the
duct, a voltage drop is induced across the
stream. The electrodes of the MHD genera-
tor are normally two opposite walls of the
duct to which electrical leads are attached.
Note that MHD systems generate DC power
which, if used in a conventional central
station power plant, must then be trans-
formed to AC power.
Three basic types of MHD systems have
been investigated: the open-cycle plasma
system, the closed-cycle plasma system,
and the liquid metal system.
12.6.1.1 Open-Cycle Plasma System
The open-cycle plasma system has re-
ceived the most attention to date. In this
system, fossil fuel is burned at a suffi-
ciently high temperature (4,000 to 5,000°F)
to ionize the product gases. Electrical
conductivity is increased by "seeding" the
gas with readily ionized material, gener-
ally salts of potassium or cesium. These
gases then pass through the MHD generator,
and the existing hot gas can be used to
generate steam for a conventional steam
turbine. The seed material must then be
extracted from the hot gases before venting
to the atmosphere.
The open-cycle plasma system is at the
pilot stage in the Union of Soviet
Socialist Republics (USSR) where they ex-
pect to have a 75-Mwe system (25 Mwe from
the MHD generator and 50 Mwe from the steam
turbine) in operation by 1975 (AEC, 1974:
Vol. IV, p. B.10-5). The technology in
the U.S. is somewhere between the bench
test and pilot plant stage.
There are still several major problems
which must be solved before MHD systems can
become a reality for central station power
generation, but proponents feel that all of
the problems identified thus far are solv-
able. In any case, it will be at least 10
years before any large-scale MHD plants
could be built in the U.S.
12.6.1.2 Closed-Cycle Plasma System
The closed-cycle plasma system uses a
seeded noble gas (helium or argon) heated
by an indirect heat source such as a nu-
clear reactor or a fossil fuel boiler. The
hot gases pass through the MHD generator
and the cooled existing gases are compressed
for reheating. These systems would require
a heat source operating over the range of
2,300 to 3,500°F.
The closed-cycle plasma system is at
the "bench test" level of development, and
sufficient experimental and theoretical
background exists to permit extrapolation
to large sizes with reasonable confidence.
The closed-cycle plasma system has basic
problems similar to that of the open-cycle
system. However, the working conditions
of the closed-cycle MHD nonequilibrium duct
are much less severe than for the open-
cycle system because of a cleaner gas
stream and lower temperatures. Therefore,
fewer difficulties are anticipated in the
development of long-life ducts (AEC, 1974:
Vol. IV, B.10-10).
12.6.1.3 Liquid Metal MHD System
In the liquid metal system, there are
two fluid circuits, a liquid metal and an
inert gas. The liquid metal is heated by
a fossil or nuclear heat source, and the
inert gas xis then dispersed into the liquid
metal. As the gas expands, due to being
heated by the liquid metal, the two fluids
accelerate through the MHD generator, the
liquid metal providing the moving conductor
12-34
-------
MHD Generator
Electrodes
Electrically
Conductive
Working Fluid
Magnetic
Field
Figure 12-11. MHD Generator Electrical System
Source: AEC, 1974: B.10-3.
-------
capability. At the exit of the MHD genera-
tor, the ' •< flulcls nre seps:>-~ "-ed. The
liquid metal is reheated and the gas is
cooled and recompressed before being re-
mixed with the liquid metal. Rejected heat
from the gas circ; - for u«ed to gener-
ate steam or dumpeu L.O the atn, ^sphere.
Liquid metal MHD systems appear to be com-
patible with thermal energy sources oper-
ating in the range of 1,000 to 2,000°F.
Research on liquid metal systems has
been conducted on a much smaller scale
than for plasma systems. Generator effi-
ciencies up to 75 percent have been mea-
sured for a liquid metal MHD generator at
relatively low temperatures with a measured
output of about one kw. Tests of larger
(5 to 50 kw) and high-temperature (in ex-
cess of 1,000 F) liquid metal MHD genera-
tors are currently underway or being
planned (AEC, 1974: Vol. IV, p. B.10-5).
12.6.2 Energy Efficiencies
MHD power systems have higher poten-
tial efficiencies than conventional steam
and other expansion-type energy conversion
devices. First generation open-cycle
plasma systems would operate as a topping
cycle on a conventional steam plant and
would be expected to give overall plant
efficiencies in the range of 46 to 50 per-
cent. Such power plants are projected to
have an ultimate efficiency in the range
of 55 to 60 percent (AEG, 1974: Vol. IV,
p. B.10-8).
The closed-cycle plasma MHD system
operating in a binary cycle appears capable
of plant efficiencies in excess of 50 per-
cent for heat-source temperatures of
2,900°F (AEC, 1974: Vol. IV. p. B.10-8).
Two-phase, liquid metal MHD power sys-
tems are predicted to have overall effi-
ciencies competitive with those of modern
steam systems (when operating at the same
maximum cycle temperature) and should have
efficiencies approaching 50 percent at
•1,600°F (AEC. 1974: Vol. IV, p. B.10-8).
Proponents believe that a high-tempera-
ture, all-MHD binary power cycle is possible
using the open-cycle plasma and the two-
phase liquid metal MHD concepts. In such
a system, an open-cycle plasma MHD genera-
tor obtains thermal energy from a fossil-
fired heat source and rejects waste heat to
a two-phase liquid metal MHD generator.
This dual cycle is projected to have effi-
ciencies in excess of 60 percent for a
maximum cycle temperature at 5,000°F (AEC,
1974: Vol. IV, p. B.10-8).
12.6.3 Environmental Considerations
The effluents associated with MHD
power plants are associated with the energy
source; that is, nuclear or fossil fuels.
Since higher conversion efficiencies are
expected as compared with conventional
steam plants, significant reductions in
emissions per unit of power produced should
be achieved. However, two special environ-
mental problems associated with the open-
cycle system are recovery of seed material
and possible increases in NO emissions due
to the higher combustion temperature.
12.6.4 Economic Considerations
The MHD power plant concepts are still
in the early development stage; thus, it
is not possible to make accurate assess-
ments of their economic benefits. The
higher efficiencies projected for the
various MHD systems must provide sufficient
fuel and residual clean-up cost savings to
compensate for the higher capital costs of
the MHD system.
12.6.5 Other Constraints and Opportunities
Since the MHD system generates DC
power, the entire system must be analyzed
to determine the feasibilitv of using the
DC power directly in certain applications
or converting it all to AC power. Costs
and efficiencies for this DC to AC conver-
sion must be studied.
12-36
-------
12.7 ELECTRICITY TRANSMISSION AND
DISTRIBUTION
This section treats those technologies
for transporting electrical energy from the
generation plant to the point of use. At
present, there are approximately 4,000
electric utility companies in the U.S. that
operate transmission and/or distribution
systems.
12.7.1 Technologies
. The system for delivering electrical
energy is generally separated into two com-
ponents: the transmission system which
transports the energy at relatively high
voltages (69 to 500 kilovolts [kv]) from
the electrical generation plant to main
substations; and the distribution system
which transports the electrical energy, at
voltages ranging from 138 kv to 120 volts,
from the substations to the point of utili-
zation.
12.7.1.1 Transmission Systems
The transmission system consists of
overhead transmission lines and underground
cables, terminal equipment (e.g., high
voltage transformers, converters, switch-
gear, etc.), and control and metering sys-
tems (e.g., meters, relays, communications
equipment, computers, etc.). In addition
to providing transmission within individual
utility service areas, transmission systems
also generally interconnect adjacent elec-
tric utility systems to achieve more reli-
able and economic service (AEC, 1974:
Vol. IV, p. C.5-2).
At present, there are more than 40,000
miles of overhead transmission lines and
about 2,000 miles of underground transmis-
sion cables. The transmission lines util-
ize about four million acres of land for
right-of-way (Battelle, 1973: 176).
Early transmission lines used wooden
poles, wooden cross arms, and solid copper
conductors. Voltages on these lines were
as low as 69 kv. Today, voltages of 345,
500, and 765 kv are in use, with future
planning on the next highest voltage levels
of 1,000 and 1,500 kv. As voltages in-
creased, insulators and conductors became
bigger and heavier, requiring large steel
or aluminum towers (Battelle, 1973: 176).
Because of increased environmental
awareness and right-of-way costs, trans-
mission design and technology are the focus
of substantial research interest. Major
investigative effort is being put into
ultrahigh voltage (745 kv and above) and
underground transmission lines. The use
of higher voltages will enable a given
line to carry more power and thus avoid the
use of multiple lines or circuits. Also,
higher voltages generally result in greater
transmission efficiencies.
One of the areas receiving attention
in underground transmission is compressed
gas insulation. In this method, the wire
carrying the power is suspended concentric-
ally in a pipe. Compressed gas (sulfur
hexafluoride [SF,] is a likely candidate)
fills the annular space between the pipe
and wire, with the advantages of improved
heat transfer and low dielectric loss.
Another underground transmission
method of interest uses cryogenics. When
certain metals are supercooled (to about
4 to 10° Kelvin [K]), they lose their
resistivity entirely, a condition known as
superconductivity (Battelle, 1973: 280,
281). Thus, relatively small wires could
carry large amounts of power if maintained
in a state of superconductivity. Of course,
there would be system losses associated
with maintaining cryogenic conditions, and
it will be several years, if ever, before
such systems become economically feasible.
12.7.1.2 Distribution Systems
The typical distribution system con-
sists of subtransmission lines (usually
ranging from 69 to 138 kv), primary distri-
bution lines (2.4 to 34.5 kv), distribution
transformers, secondary distribution lines
12-37
-------
(120 to 240 volts), and service lines to
residential and commercial customers.
Large commercial and industrial customers
are generally supplied at primary distribu-
tion or even subtransmission voltages (AEC,
1974: Vol. IV, p. C.5-19).
Distribution systems may either be
constructed as overhead or underground sys-
tems. Today, the trend is toward more
underground installations, especially for
the primary and secondary distribution
systems feeding suburban loads. Aluminum
has been the material most used for conduc-
tors in distribution systems because of its
physical characteristics and economics.
12.7.2 Energy Efficiencies
The efficiency of the electrical
transmission/distribution system is approxi-
mately 92 percent, with losses about evenly
divided between those systems (AEC, 1974:
Vol. IV, p. C.5-1). This 92-percent effi-
ciency is high compared to the 40-percent
or less efficiency in the electric power
generation stage. Thus, the opportunities
for increased efficiencies in transmission
and distribution are small compared to
those in other parts of the overall electric
utility system. Resistance accounts for
the majority of transmission/distribution
losses.
Of the two, most of the opportunities
for increased efficiency are in the trans-
mission system. Here, some of the options
are: extra-ljigh and ultrahigh voltage AC
transmission systems; high voltage DC sys-
tems; compressed gas and cryogenic systems
(as described earlier); and improved power
system control.
12.7.3 Environmental Considerations
One of the primary environmental im-
pacts of overhead transmission and distri-
bution lines is esthetic. Towers, poles,
and their associated cables are not pleas-
ing sights to most people. Of course, the
severity of the impact depends on the par-
ticular area; for example, the esthetic
impacts of transmission lines are greater
in heavily timbered areas, over steep
slopes, through scenic areas, and across
open waters. Obviously, the interest in
underground cables is to minimize these
esthetic impacts.
The other primary environmental impact
associated with transmission lines, and to
some extent distribution lines, is the land
use and physical destruction of the natural
vegetation, which can increase soil erosion.
The land use residual is the only nonzero
coefficient listed by Hittman and is 778
per 1012 Btu's.
Finally, a number of people are con-
cerned about the impact of the extra-high
voltage lines that are being proposed.
Some evidence suggests that the relatively
high electric fields and induced magnetic
fields in the vicinity of the line are
physically dangerous and can have adverse
physiological effects.
12.7.4 Economic Considerations
On a national average basis in 1968,
transmission costs were two mills per kwh
and distribution costs were 5.7 mills per
kwh (FPC, 1971: 1-19-2). Generally, the
transmission and distribution step is char-
acterized by high capital costs and rela-
tively small operating costs.
Part of the interest in high voltage
transmission lines, in addition to the im-
proved efficiency, is the lower per unit
transmission cost. The optimum voltage for
any transmission line (i.e., the voltage
that results in the lowest per kwh trans-
ferred) depends on the load to be trans-
ferred and the particular economic condi-
tions. For example, using certain economic
assumptions, a line transmitting 1,300 Mwe
would cost 1.5 mills per kwh for a 345-kv
line and only 1.0 mills per kwh for a 500-
kv line (FPC, 1971: 1-13-8).
Although underground transmission
lines are still in an early stage of
12-38
-------
development, they are estimated to cost
about 10 times as much as overhead lines
(Battelle, 1973: 278).
12.8 SUMMARY AND COMPARISON OF
ENVIRONMENTAL FACTORS
In the previous descriptions of elec-
trical generation alternatives, the re-
sidual data based on 10 Btu's input were
given. To put some of this residual data
in better perspective, the residuals in the
following paragraphs are presented on an
annual basis for a modern size power plant
with a 1,000-Mwe capacity and an average
annual load factor of 75 percent. Such a
plant would serve an average population of
900,000.
Table 12-10 lists the total annual
output of the residuals of major concern in
electric power generation. This table in-
cludes data for selected alternative power
plants and fuel types previously described.
In addition, residuals are listed for two
hypothetical plants to illustrate the
effect of efficiency. Plant number 14
burns the same coal and in the same manner
as plant one but uses an advanced conver-
sion technology (possibly a binary cycle
or MHD) to achieve a conversion efficiency
of 60 percent. Plant 15 is like plant four
(both employ stack gas cleaning) but has a
conversion efficiency of 58 percent.
Plant one is a conventional coal-fired
steam power plant, burning an average coal
with 12.53-percent ash and 2.59-percent
sulfur. Assuming an average coal with a
heat content of 12,000 Btu's per pound,
this plant would consume 2.46 million tons
of coal annually. From Table 12-10 the
emissions for plant one are approximately
48,500 tons of particulates, 119,200 tons
of SO , and 21,800 tons of NO—a total of
X X
A 1,000-Mwe plant operated for one
year at an average load factor of 75 per-
cent has an output of 22.43xl012 Btu's of
electrical energy and, assuming a 38-per-
cent conversion efficiency, requires
59xl012 Btu's energy input.
182,200 tons (or 364,400,000 pounds) of air
pollutants annually. It also creates
nearly 298,000 tons of solid wastes (pri-
marily ash) and produces 31.1x10 Btu's of
waste heat. Plants two and three, which
burn oil and natural gas respectively, are
much cleaner, except that all three plants
have essentially the same level of NO
emission.
For comparison with plant one, note
the emissions for plants four, six, seven,
and eight which employ throwaway stack gas
cleaning systems, and plant five which em-
ploys a recovery stack gas cleaning system.
The SO and particulate emission levels are
5C
drastically reduced. However, the solid
wastes show a large increase. For example,
plant four has 955,000 tons of solid wastes,
which are essentially the materials that
would have gone into the air plus the re-
acted limestone. For plant five, the solid
Waste increase is not as large because the
MgO is recycled and thus the solid waste
is primarily ash. Based on densities from
the Hittman data, the solid wastes from
plant four during one year would cover 15
acres to a depth of 35 feet. It is not
known what the disposal plans are for such
wastes, but transporting them for long dis-
tances is presumed to be uneconomical.
Also, these sludge wastes will not solidify
(thixotropic), and many persons are con-
cerned about their environmental impact.
Plants 9 through 11 are fluidized bed
systems, with sulfur recovery (plant 11
having a combined-cycle operation), and
they appear to be the most attractive sys-
tems for burning coal in t erms of environ-
mental residuals. These plants offer defi-
nite advantages in terms of NOx emissions
and solid wastes when compared to throwaway
stack gas cleaning. However, their differ-
ences with plants four through eight in
terms of the other residuals are small,
being primarily attributable to varying
assumptions about efficiencies and physical
make-up of the coal.
12-39
-------
t
C.
o
Table 12-10. Major Residuals for 1,000-Mwe Plants at 75 Percent Load Factor
Plant
Number
la
2a
3a
4b
5b
6
7b
8a
9a
10a
lla
12a
13a
Description
Coal: Conventional steam
No controls
Oil: Conventional steam
No controls
Gas: Conventional steam
No controls
Eastern Coal: Conventional
Boiler with wet limestone
scrubbing
Eastern Coal: Conventional
Boiler with magnesium oxide
scrubbing
Western Coal: Conventional
Boiler with wet limestone
scrubbing
Physically Cleaned Eastern
Coal: Conventional Boiler
with wet limestone scrubbing
Coal: Steam plant with controls
Northern Appalachian Coal:
Atmospheric Fluidized Bed
Northwest Coal: Atmospheric
Fluidized Bed
Northern Appalachian Coal:
Combined-Cycle Pressurized
Fluidized Bed
Low-Btu Gas (Northern Appalachian
Coal) : BuMines-Atmospheric
Boiler plant with controls
Low-Btu Gas (Northern Appalachian
Coal) : BuMines-Pressurized
Combined-Cycle plant
Primary
Efficiency
38
38
38
35
35
35
35
38
36.8
36.8
35.8
38
40
Nitrogen
Oxides
(103 tons)
21.8
21.1
11.2
19.2
19.2
25.0
17.6
23.2
4.3
4.3
4.22
0.391
0.577
Sulfur
Oxides
(103 tons)
119.2
47.3
.02
16.0
16.0
5.1
6.4
19.1
10.2
3.5
13.2
28.8
2.66
Particulates
(103 tons)
48.5
1.6
.43
3.2
3.2
2.2
1.4
2.6
.5
.3
.8
6.78
.19
Thermal
(1012 Btu's)
31.1
31.1
31.1
0
0
0
0
0
0
0
0
0
0
Solid
(103 tons)
298
0
0
955
410
487
417
1,009
359
243
362
0
0
-------
Table 12-10. Continued.
Plant
Number
14
15
Description
Hypothetical Plant:
Similar to #1 but with high
conversion efficiency
Hypothetical Plant:
Similar to #4 but with high
efficiency
Primary
Efficiency
60
58
Nitrogen
Oxides
(103 tons)
14.0
11.6
Sulfur
Oxides
(103 tons)
80.8
9.7
Particulates
(103 tons)
130
1.9
Thermal
(1012 Btu's)
19.7
0
Splid
(10d tons)
41.1
576
Sources: ^ittman, 1974: Vol. I; 1975: Vol. II.
bBattelle, 1973.
to
I
-------
Plants 12 and 13 are conventional
boiler and combined-cycle plants respec-
tively, each burning low-Btu gas made from
Northern Appalachian coal. The low-Btu
gas is made from the BuMines atmospheric
process for plant 12, and the BuMines pres-
surized process for plant 13. Note that
plant 13 has much lower SOx and particulate
emission levels than plant 12, but both
appear relatively clean when compared to
the other systems. However, it is impor-
tant to realize that these residuals are
only for the electric power generation
step and do not include the emissions for
the low-Btu gasification process itself.
Comparing plants 14 with one and 15
with four shows the environmental advan-
tages of improved efficiency, although
these plants can still yield large amounts
of pollutants. However, this is not the
entire picture because plant 14 requires
only 63 percent as much fuel as plant one
and thus all the residuals associated with
producing the fuel would be reduced by 37
percent.
Note that the thermal pollution for
many of the plants is zero. The assumption
here is that these plants would use cooling
towers, and thermal pollution is deemed to
occur only when the heat goes to nearby
bodies of water. However, it is important
for comparison to realize that cooling
towers "consume" water (by evaporation),
and thus the trade-off is generally between
heating bodies of water by some amount or
consuming some amount of the water. The
water consumed annually by a 38-percent
efficient, 1,000-Mwe plant varies from zero
to approximately 17,000 acre-feet, depend-
ing on the cooling system used.
Cooling Process Water Consumption
Once-through 0 acre-feet
Cooling pond 17,000 acre-feet
Wet cooling towers 11,520"acre-feet
Dry cooling towers 0 acre-feet
For comparison, a 60-percent efficient
plant using a wet cooling tower would only
consume 4,245 acre-feet annually. For
reference, note that the waste heat from a
38-percent efficient, 1,000-Mwe power plant
is equivalent to the energy required to
heat approximately 250,000 homes.
12.9 SUMMARY OF ECONOMIC CONSIDERATIONS
A brief survey of some of the primary
economic considerations that affect elec-
tric power production follows. First,
general data concerning the costs of the
electric power industry are discussed and
then the economics of the alternative tech-
nologies are summarized.
12.9.1 General Costs of Electric Power
The electric power industry is made up
of a great many utility companies. Some
of these are owned by private organizations
(investor-owned utilities); some are owned
by the federal government, municipalities,
states, or public utility districts; and
some are owned by electric cooperatives.
The general structure of the industry is
illustrated in Figure 12-12. The investor-
owned segment is by far the largest, ac-
counting for 77 percent of the nation's
total generating capacity. Nearly all of
the approximately 200 major investor-owned
utilities operate integrated generation,
transmission, and distribution systems. The
existence of so many separate and relatively
small systems creates a variety of problems.
The small systems cannot take advantage of
economies of scale, and the large number
of systems complicates the job of regional
power development.
Historically, the electric utility
industry has a record of delivering electric
power to the consumer at a continually de-
clining cost. The average price paid by
consumers declined from 27 mills per kwh
in 1927 to 15.4 mills per kwh in 1968.
(In 1968 dollars, this represents a de-
crease from 52.8 mills per kwh to 15.4
mills per kwh.) Table 12-11 shows U.S.
average costs for the three primary func-
tions in electric power supply: generation.
12-42
-------
THE ELECTRIC POWER INDUSTRY
1970
250*
Investor Owned
Systems ^_
262,668 MW
1,183 Million MWH
16
il
o OT
HE
r
v^
r
NON-GENERATING SYSTEMS
150*
Investor
Owned
Systems
^D f^
•z a> o
0 u_ ,
Federal * =• o
^'o
— "3 0>
0. 00
C
,0
"5
JO
5'
2
_^ Federa
38,718 I
1 4 »
VIW
7
16 Million MWH 139
GENERATING S
•^
J
t ULTIMATE CONSUM
m
33
U)
Distribution Transmission
7nr»-X- , - ,
ruu n •
Piihlir ^ k 65*
Non-Fed C°-°P
4,245 MW 4,722 MW
Million MWH 22 Million MWH
IYSTEMS J
r
r
64,017,652 7,865,073
Residentia Commercial
Customers Customers
448 Million MWH 313 Million MWH
352,993
Industrial
Customers
572 Million MWH
t
Note:Power generated at other Federal facilities is
marketed by the 5 major Federals shown.
* Estimated
Figure 12-12. The Electric Power Industry
249,250
Other Customers
58 Million MWH
Source: FPC, 1971: 1-1-11.
-------
TABLE 12-11
AVERAGE COSTS OF U.S. ELECTRICITY. 1968
Function
Generation
Transmis s ion
Distribution
TOTAL
Cost
(mills per
kilowatt hour)
7.7
2.0
5.7
15.4
Percent
of Total
50
13
37
100
Source: FPC, 1971: 1-19-10.
transmission, and distribution. These
data indicate that generation alone ac-
counted for one-half of the cost of elec-
tricity.
An interesting aspect of electric
power is that (for most utilities) the
more electricity used by the customers,
the cheaper the rate per kwh charged those
customers. The rate structures vary from
utility to utility and also depend on
classification of customers and power
needs. As an example. Table 12-12 gives
j'
the cost of electricity .from a southwestern
power company for residential users during
two periods of the year.
Any electric power generation plant
has three principal cost components: fixed
charges on capital investments (including
cost of money, depreciation, insurance,
taxes, etc.); fuel expenses; and operating
and maintenance expenses, excluding fuel,
but including allocated administrative and
general expenses. (Plants with stack gas
cleaning could also add a fourth category
for the costs of scrubbing material.)
Although costs of power generation
and the relative proportion for each of
the three components vary from region to
region, the U.S. total for 1968 is given
in Table 12-13.
The annual fixed charges can generally
be expressed as a percentage of the total
capital investment. The percentage used
can vary with ownership (private, federal,
municipal, etc.) and with the type of equip-
ment, primarily because of differences in
service lives but also because of
TABLE 12-12
EXAMPLE OF RESIDENTIAL ELECTRICITY RATE STRUCTURE
On-Peak Season (May-September)
Off-Peak Season (October-April)
$1.00
.0380C
.0330C
.0210'
.0185'
.0180C
.0150°
for first 16 kilowatt
hours or less
next 24 kilowatt hours
next 100 kilowatt hours
next 460 kilowatt hours
next 900 kilowatt hours
next 1,000 kilowatt hours
all additional kilowatt
hours
$1.00
.0380
.0330
.0210
.0100
.0090*
for first 16 kilowatt
hours or less
next 24 kilowatt hours
next 100 kilowatt hours
next 460 kilowatt hours
next 1,900 kilowatt hours
all additional kilowatt
hours
Source: Oklahoma Gas and Electric Company.
oollars per kilowatt hour.
12-44
-------
TABLE 12-13
AVERAGE 1968 GENERATION COSTS
Component
Fixed charges
Fuel
Operation and maintenance.
allocated administration
and general
TOTAL
Mills per
Kilowatt Hour
3.71
2.47
1.57
7.75
Percent of
Total
48
32
20
100
Source: FPC, 1971: 1-19-10.
differences in tax rates and other items.
Table 12-14 illustrates the fixed charge
rate for a conventional fossil-fueled
steam plant with a 30-year life. For this
example, a plant with a capital cost of
$100 million would have an annual fixed
charge cost of $14.2 million (FPC, 1971:
1-19-6).
One of the difficulties in comparing
many of the cost figures from different
TABLE 12-14
EXAMPLE OF FIXED CHARGE RATE FOR
CONVENTIONAL STEAM PLANT
(30-YEAR LIFE)
Component
Cost of money
Depreciation and replacements
Insurance
Income taxes
Other taxes
TOTAL
Annual
Fixed
Charge Rate
(percent
of capital
investment)
8.2
1.2
0.2
2.2
2.4
14.2
sources is that they often use signifi-
cantly different fixed charge rates, due
to different assumptions of service life,
interest on borrowed money, etc.
Although fuel costs have increased
sharply in recent months and are expected
to continue increasing, their percentage
of power generation costs may not rise
substantially because fixed charges should
also increase sharply due to higher inter-
est rates and general inflation.
12.9.2 Costs of Alternative Power Plants
For various reasons, it is very diffi-
cult to compare the alternative systems
based only on a direct comparison of the
economic data from the previous sections.
First, the estimates are generally made by
different sources, each using different
assumptions about cost of money, time for
construction, future fuel costs, plant
operating costs, etc. Second, many of the
alternative systems are still in the devel-
opment stage and thus the cost calculations
are based largely on conjecture. However,
even though it is difficult to directly
compare the data, several important conclu-
sions can be drawn. These are summarized
be low.
Source: FPC, 1971: 1-19-6.
12-45
-------
12.9.2.1 Conventional Steam Power Plants
Conventional steam power plants have
been the most economical systems to date,
with capital cost differences depending on
fuel type as shown in Table 12-5. However,
the generation costs have been about equal
for all fuel systems, as also shown in
Table 12-5.
12.9.2.2 Stack Gas Cleaning Technologies
Since stack gas cleaning technologies
are still in the early stages of develop-
ment, their precise cost impact is still
somewhat uncertain. It is estimated that
the addition of stack gas cleaning systems
can cost anywhere from approximately $20
per kw to $65 per kw (1973 dollars), as
shown in Table 12-6. This will add from
one to two mills per kwh to the cost of
electrical generation (Table 12-6), which
is from 6 to 15 percent of electricity
supply costs (Table 12-11).
12.9.2.3 Fluidized Bed Systems (Including
Westinghouse Combined-Cycle
System)
Like stack gas cleaning technologies,
fluidized bed systems are still in the
development stage and thus economics are
still uncertain. However, the evidence
suggests that fluidized bed systems can
generate electric power at or below the
cost of steam plants with stack gas clean-
ing.
Ejupply of clean gaseous fuels and certain
refined liquid fuels in comparison to solid
fuels and fuel oils.
12.9.2.5 Other Advanced Conversion
Technologies
It is still too early to determine the
economic trade-offs of the advanced conver-
sion technologies; i.e., binary cycles,
MHD, and fuel cells. However, the trade-
offs are generally between the increased
capital costs of more complex systems and
lower costs for fuel and possible lower
costs for pollution control due to in-
creased efficiencies. Of course, it is
entirely possible that some of the proposed
systems can offer both capital cost and
efficiency advantages.
12.9.2.6 Overall Generation Costs
Generation accounts for approximately
50 percent of delivered power cost (Table
12—11), and thus a given percentage in-
crease in generation costs should only
increase the total cost of electricity by
one-half that percentage.
Fuel costs have ranged from around 33
to 50 percent of generation costs (Tables
12-5 and 12-11). Therefore, even if fuel
costs double, total electrical energy
costs to the consumer should only increase
from 16 to 25 percent.
12.9.2.4 Gas Turbine Power Plants
(Including Combined-Cycles)
The simple gas turbine system has
capital cost advantages, but its relatively
low efficiency and higher fuel costs make
it attractive primarily for peak load pur-
poses. Apparently, combined-cycle power
plants can offer capital cost advantages
over steam power plants with no loss in
overall efficiency, although the precise
capital cost differences are not known.
Whether these systems will provide lower
energy costs will depend on the price and
REFERENCES
Atomic Energy Commission (1974) Draft
Environmental Statement; Liquid Metal
Fast Breeder Reactor Program.
Washington: Government Printing
Office, 4 vols.
Atomic Industrial Forum (1974) "Comparison
of Fuels Used in Power Plants." Back-
ground INFO, published under the
Public Affairs and Information Program.
New York: AIF.
Babcock and Wilcox (1972) Steam/Its Genera-
tion and Use. New York: The Babcock
and Wilcox Company.
12-46
-------
Bartock, w., A.R. Crawford, and G.J. Piegari
(1972) "Systematic Investigation of
Nitrogen Oxide Emissions and Combustion
Control Methods for Power Plant
Boilers," pp. 66-74 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.
Battelle Columbus and Pacific Northwest
Laboratories (1973) Environmental
Considerations in Future Energy Growth,
Vol. I: Fuel/Energy Systems; Tech-
nical Summaries and Associated Environ-
mental Burdens, for the Office of
Research and Development, Environ-
mental Protection Agency. Columbus,
Ohio: Battelle Columbus Laboratories.
Council on Environmental Quality (1973)
Energy and the Environment; Electric
Power. Washington: Government Print-
ing Office.
Davis, John C. (1973) "SOx Control Held
Feasible." Chemical Engineering- 80
(October 29, 1973): 76, 77.
Federal Power Commission (1971) 1970
National Power Survey. Washington:
Government Printing Office, 5 parts.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts and Cost of
Energy Supply and End Use, Final
Report: Vol. I. 1974; Vol. II, 1975.
Jimeson, R.M., and G.G. Adkins (1971a)
"Factors in Waste Heat Disposal Asso-
ciated with Power Generation." Paper
#26a presented at 68th National Meet-
ing of AIChE, Houston, Texas.
Jimeson, R.M., and G.G. Adkins (1971b)
"Waste Heat Disposal in Power Plants."
Chemical Engineering Progress 67
(July 1971): 64-69.
Keairns, D.L., J.R. Hamm, and D.H. Archer
(1972) "Design of a Pressurized Bed
Boiler Power Plant," pp. 267-275 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.
Nonhebel, Gordon (1964) Gas Purification
Processes. London: George Newnes,
Ltd.
Olmstead, Leonard M. (1971) "17th Steam
Station Cost Survey." Electrical
World (November 1, 1971), as cited in
Council on Environmental Quality
(1973) Energy and the Environment;
Electric Power. Washington: Govern-
ment Printing Office.
Papamarcos, John (1974) "Design Directions
for Large Boilers." Power Engineering
78 (July 1974): 34-41.
Shields, Carl D. (1961) Boilers; Types,
Characteristics, and Functions. New
York: F.W. Dodge Corporation.
Slack, A.V., H.L. Falkenberry, and R.E.
Harrington (1972) "Sulfur Oxide
Removal from Waste Gases: Lime-
Limestone Scrubbing Technology."
Journal of the Air Pollution Control
Association 22 (March 1972): 159-166.
Soo, S.L. (1972) "A Critical Review on
Electrostatic Precipitators," 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.
Teknekron, Inc. (1973) Fuel Cycles for
Electrical Power Generation, Phase I:
Towards Comprehensive Standards; The
Electric Power Case, report for the
Office of Research and Monitoring,
Environmental Protection Agency.
Berkeley, Calif.: Teknekron.
12-47
-------
CHAPTER 13
ENERGY CONSUMPTION
13.1 INTRODUCTION
The preceding chapters reflect the
dominant emphasis of this report by de-
scribing the nation's alternative energy
supplies. However, significant alterna-
tives also exist for energy consumption
and, like supplies, these have ranges of
efficiencies, environmental residuals, and
costs. The energy consumption portion of
the U.S. energy system received little pub-
lic attention until the recent energy
shortages and price increases.
Although information on U.S. energy
consumption is in an early stage of devel-
opment, recent studies have provided a
more systematic data base. These studies
can be divided into three phases. The
first phase involved data collection on
U.S. energy consumption and classification
into meaningful end uses according to var-
ious consumption sectors. Phase two in-
volved identification of points within the
major consuming sectors where opportunities
for energy conservation exist. Phase three,
the recent Hittman study, identified the
residuals associated with the various end
uses found in phase two.
The objectives of this chapter are to:
identify quantities of consumption by sec-
tor and more specifically by end use (e.g.,
space heating); identify the environmental
residuals associated with the end use; and
indicate conservation opportunities re-
sulting either from reduced consumption or
increased efficiency. Following a dis-
cussion of energy supply and demand, the
chapter is divided into three consumption
"sectors:" residential and commercial,
transportation, and industrial. The first
part of each consumption sector describes
the applicable technologies (i.e., utilizing
devices) and traces the residuals associated
with end use. The second part identifies
energy conservation alternatives for various
end uses, and includes estimates of the
potential savings.
Although the end use data format in
this chapter is similar to the supply chap-
ters, there are some differences in the data
units. The units of residuals for energy
consumption are expressed in tons per "mea-
sure." The particular "measure" is the unit
most appropriate for each end use; examples
of measures are passenger-mile, ton, and
dwelling-year. A value referred to as the
"multiplier" is also included. The "multi-
plier" is the amount of each end use mea-
sure expended in the U.S. for a given year
("multiplier year"). Thus, the product of
the energy required for each end use and
the multiplier (Column 19 x Column 20) pro-
vides an actual yearly energy use expressed
in Btu"s.
In addition to the above differences,
the columns for land use and occupational
health are not included in the consumption
residuals tables. Land use is not consid-
ered the direct result of energy consump-
tion (Hittman, 1974: Vol. I, Table 30,
footnote 7026), and, in almost every case,
occupational health and safety residuals for
energy consumption are identified by Hittman
as either not applicable or unknown. The
end use residuals data are uncontrolled in
13-1
-------
TABLE 13-1
TOTAL AND PER CAPITA U.S. ENERGY CONSUMPTION
Year
1950
1955
1960
1965
1970
Total Energy
Consumption
(1012 Btu's)a
34.0
39.7
44.6
53.3
67.4
Population
(millions)
152.3
165.9
180.7
194.2
204.8
Energy
Consumption
Per Capita
(106 Btu's)
223.2
239.3
246.8
274.4
329.1
Source: Interior. 1972: 11.
energy consumption is the sum of inputs into the
economy of the primary fuels (petroleum, natural gas, and
coal, including imports) or their derivatives, plus the
generation of hydro and nuclear power converted to equiv-
alent energy inputs .
that the level of control of environmental
impacts is representative of very recent or
current practices.
13.1.1 Patterns of Energy Supply and Demand
Since 1950, there has been a growing
gap between U.S. energy production and con-
sumption levels. This trend is illustrated
in Figure 13-1. Demand for energy in the
U.S. grew at an average annual rate of about
3.5 percent from 1950 to 1965, increased to
4.3 percent annually from 1965 to 1970 (In-
terior, 1972: 12). Concurrently, domestic
energy production grew at three percent an-
nually from 1950 to 1970 but has been at a
virtual standstill since 1970 (Ford Foun-
dation, 1974: 1). Domestic energy produc-
tion furnished 84.1 percent of total U.S.
energy supplies in 1973, with the remainder
supplied by imports (Braddock, Dunn and
McDonald, 1974a: III-6). Several projec-
tions for the present through 1985 indicate
continued domestic supply/demand imbalances
in the energy market (BLM, 1973; Interior,
1972; and NPC, 1972).
An important reason for the domestic
energy market disparity has been the growth
of energy demand during a period when ener-
gy was relatively inexpensive. Higher en-
ergy usage per capita, compounded by popu-
lation growth, has resulted in unprecedent-
ed levels of energy consumption. Although
the U.S. represents only six percent of the
world's population, it consumes one-third
of the energy used in the world (Cook, 1971:
135). Even though population growth has
slowed to about the replacement level, in-
creasing energy use per capita, as shown in
Table 13-1, is expected to contribute to an
increasing total demand in this country.
13.1.2 Energy Consumption By End Use
Energy consumption by end use in the
U.S. is shown in Table 13-2. These esti-
mates were calculated by Stanford Research
Institute (SRI) using Bureau of Mines
(BuMines) data and other sources. More
current energy consumption data, developed
by Hittman, are reported in the following
sections.
13-2
-------
70
50
0>
CL
CD
TJ
O
30
10
0
1950
Production
Consumption
_L
I960
1970 1980
Figure 13-1. Total U.S. Energy Production and Consumption, 1947-1973
Source: Adapted from the Ford Foundation, 1974: 2 (based on Interior, 1972: 11)
-------
TABLE 13-2
ENERGY CONSUMPTION IN THE U.S. BY END USE, 1960-1968
Sector and
End Use3
Residential
Space heating
Water heating
Cooking
Clothes drying
Refrigeration
Air conditioning
Other"
TOTAL
Commercial
Space heating
Water heating
Cooking
Clothes drying
Refrigerationc
Air conditioning
Otherd
TOTAL
Industrial
Process steam
Electric drive
Electrolytic
processes
Direct heat
Feedstock
Other
TOTAL
Transportation6
Fuel
Raw materials
TOTAL
NATIONAL TOTAL
Consumption
(1012 Btu's)
1960
4,848
1.159
556
93
369
134
809
7,968
3,111
544
98
534
576
734
145
5,742
7,646
3,170
486
5,550
1,370
118
18,340
10,873
141
11.014
43,064
1968
6,675
1,736
637
208
692
427
1,241
11,616
4,182
653
139
670
1,113
984
1,025
8,766
10.132
4,794
705
6,929
2,202
198
24.960
15,038
146
15.184
60.526
Annual Rate
of Growth
(percent)
4.1
5.2
1.7
10.6
8.2
15.6
5.5
4.8
3.8
2.3
4.5
2.9
8.6
3.7
28.0
5.4
3.6
5.3
4.8
2.8
6.1
6.7
3.9
4.1
0.4
4.1
4.3
Percentage of
National Total
1960
11.3
2.7
1.3
0.2
0.9
0.3
1.9
18.6
7.2
1.3
0.2
1.2
1.3
1.7
0.3
13.2
17.8
7.4
1.1
12.9
3.2
0.3
42.7
25.2
0.3
25.5
100.0
1968
11.0
2.9
1.1
0.3
1.1
0.7
2.1
19.2
6.9
1.1
0.2
1.1
1.8
1.6
1.7
14.4
16.7
7.9
1.2
11.5
3.6
0.3
41.2
24.9
0.3
25.2
100.0
Source: SRI, 1972: 6 (using BuMines and other sources).
Consumption by electric utilities has been allocated to each end use.
Other in residential sector includes lighting, large and small appliances,
television, food freezers, etc.
clncludes energy consumed for food freezing.
Other in commercial sector is primarily electricity used for lighting and
mechanical drives (for computers, elevators, escalators, office machinery, etc.)
See transportation sector discussion for a subdivision of transportation by
specific methods.
-------
Several important observations may be
made regarding the data in Table 13-2. For
example, during the interval 1960 through
1968, annual energy consumption increased
from a total of 43,064x10 2 Btu's to
60,526xl012 Btu's. The Department of the
Interior (Interior) estimated that the to-
tal U.S. energy consumption in 1970 had
12
further increased to 67,444x10 Btu's (In-
terior, 1972: 40). The table also shows
that a relatively few end use categories
offer the greatest potential for conserva-
tion: residential and commercial space
heating and cooling, industrial thermal
processes, and transportation fuel usage.
Collectively, these activities accounted
for approximately 74 percent of the total
energy consumption in 1968.
13.1.3 Energy Conservation
Measures to reduce energy demand at the
point of end use should be evaluated as a
method for achieving a balance between en-
ergy production and consumption. That is,
conservation might decrease or eliminate
some of the requirements that otherwise must
be satisfied by new or alternate sources of
energy. In addition, slowing the growth
rate of energy demand will improve the lon-
gevity of domestic supplies, thus allowing
more flexibility in developing systems to
meet long-term needs (CEQ, 1973: 27).
A number of recent studies have ex-
amined ways in which energy demand can be
reduced; principal among these is one re-
leased by the former Office of Emergency
Preparedness (OEP) in 1972. The objective
of this study was the suggestion of pro-
grams that would either improve the effi-
ciency with which energy is consumed or
minimize the consumption of energy while
providing the same or similar services to
the consumer. OEP divided conservation
measures into two broad categories referred
to as "belt tightening" and "leak plugging."
Belt tightening is defined as measures
that would reduce energy consumption at
fixed efficiency levels. If the consumer
expended less energy while achieving de-
sired ends (e.g., driving at slower speeds),
then energy production could be reduced.
Leak plugging is defined as measures that
would retain performance while increasing
efficiency. In this case, extant technol-
ogy (e.g., improved insulation in buildings)
could be used to improve short- and mid-
term energy use (three to eight years).
Efficiency improvements in the form of long-
term efforts would require new technological
developments and/or larger scale application
of existing technology (e.g., heat pumps)
(OEP, 1972: 5).
13.2 RESIDENTIAL AND COMMERCIAL SECTOR
Energy is consumed in the residential
and commercial sector principally for space
heating and cooling and water heating. As
shown in Table 13-2, these applications for
households and commercial establishments
required about 24 percent of U.S. energy
consumption in 1968. Increasing residential
demand is due primarily to more widespread
use of electricity-consuming devices for
air conditioning, clothes drying, refriger-
ation, and "other" (primarily lighting,
television, and assorted appliances). Grow-
ing consumption in the commercial area re-
flects the expansion of commercial and ser-
vice activities in the U.S. economy, which
have outpaced industrial growth consistently
over the last decade (Ford Foundation, 1974:
3). Significant increases in the commercial
sector are in air conditioning and "other,"
which consists of electricity used in light-
ing, computers, elevators, office machinery,
and some electric heat (SRI, 1972: 66).
Table 13-3 is a breakdown of energy
consumption by fuel for the major end uses
of energy in the residential and commercial
sector in 1970. As would be expected, two-
thirds of total demand is for natural gas
and electricity. Distillate fuel ranks
third as a result of its contribution to
residential space heating. Coal usage in
these two sectors is insignificant except
for its use in commercial space heating.
13-5
-------
TABLE 13-3
FUEL CONSUMPTION FOR MAJOR END USES IN THE
RESIDENTIAL AND COMMERCIAL SECTOR, 1970
End Use Sector
Residential End Use
Space heating
Air conditioning
Water heating
Refrigeration
(includes freezer)
Cooking*3
Commercial End Use
Space heating
Air conditioning
Water heating
Refrigeration
(includes freezer)
Cooking
TOTAL
Fuel Type (1012 Btu's per year)
Natural
Gas
4,375
14
945
NC
328
1,857
43
419
NC
120
8,099
LPGa
476
NA
85
NA
56
83
NA
18
NA
5
723
Distillate
2,294
NA
214
NA
NA
569
NA
NC
NA
NA
3,076
Residual
NC
NA
NA
NA
NA
1,173
NA
NA
NA
NA
1,173
Electricity
708
570
744
1,126
310
NC
868
263
777
26
5,392
Coal
NC
NA
NA
NA
NA
427
NA
NA
NA
NA
427
Total
7,853
584
1,988
1,126
694
4,109
911
700
111
151
18,893
NA = not applicable, NC = not considered.
Source: Calculated from Hittman, 1974: Vol. I, Tables 27 and 28.
aLiquefied Petroleum Gas (butane, propane, etc.).
Does not include natural gas, LPG, or electricity consumption for automatic-cleaning
oven-ranges.
13.2.1 Space Heating
13.2.1.1 Technologies
Space heating in the residential and
commercial sector accounted for approxi-
mately 18 percent of the national energy
requirement in 1970. This end use repre-
sents the largest single energy-consuming
function for both homes and commercial
buildings. Almost 70 percent of American
homes now contain central heating or built-
in units which deliver heat to every room
in the house. (Battelle, 1973: 603). En-
ergy for space heating, as indicated in
Table 13-3, is used either directly as fuel
(coal, natural gas, and petroleum products)
or as electricity.
13.2.1.1.1 Direct Combustion and Electrical
Resistance Heating
Natural gas and petroleum products pro-
vide the major energy sources for space
heating. However, electricity is increas-
ingly the energy source for this end use.
Only 0.7 million homes were electrically
heated in 1960, but 4.9 million used elec-
tric heat in 1970 (SRI, 1972: 40; Battelle,
1973: 603). Currently, electrical resis-
tance heating is estimated to comprise 20
percent of the installations in new homes.
Some electric space heating is probably
used by commercial activities, but informa-
tion is not available on the actual amounts.
Likewise, coal usage for residential combus-
tion space heating is significant in some
geographic regions but is assumed "nil" in
most source studies.
13-6
-------
13.2.1.1.2 Heat Pumps
The electric heat pump represents an
efficient, alternative technology for space
heating because it delivers about two units
of heat for each unit of electricity con-
sumed (Hirst and Moyers, 1973a: 1301). The
primary application of heat pumps to date
has been in space heating and cooling of
residential buildings, although some have
been installed in larger commercial build-
ings. In 1970, only 11 percent of electri-
cally heated households in the U.S. had
heat pumps (Tansil).
The heat pump is essentially a refrig-
eration system capable of operating in re-
verse to provide heating. Economic consid-
erations dictate that heat pumps use the
vapor compression refrigeration cycle
(Battelle, 1973: 540). In this cycle, the
evaporator extracts energy (heat) from a
low-temperature source (the outside atmos-
phere in the heating season and the indoor
environment in the cooling season) and re-
jects this heat to the higher temperature
reservoir. Heat is "pumped" outdoors to
provide summer cooling and "pumped" indoors
for winter heating.
Since heat pump power requirements and
thermal energies vary as a function of out-
side air temperature, overall heat pump
efficiency is as much as 50 percent lower
in cold regions (Hirst and Moyers, 1973b:
168). As a result, heat pump performance
must be evaluated on the basis of seasonal
temperature information for different U.S.
climatic regions.
Central heat pump systems are manufac-
tured by Carrier, Chrysler, Fedders, General
Electric, Singer, Westinghouse, and other
corporations. In addition to high capital
costs, excessive maintenance costs due to
equipment failure have curtailed the wide-
spread use of heat pumps. However, efforts
to improve unit reliability are currently
being made which should increase heat pump
acceptance by homeowners (Hirst and Moyers,
1973b: 169).
13.2.1.1.3 Solar Energy
For a description of on-site solar en-
ergy technologies, efficiencies, and re-
lated environmental considerations, see
Chapter 11.
Solar energy for space heating and
cooling and water heating in the residen-
tial sector could become economically fea-
sible in some regions of the country (e.g.,
the Southwest) if the price of fuel in-
creases sufficiently (OEP, 1972: D-5).
During the past 30 years, the use of solar
energy for heating has developed slowly
through the design and construction of
about 20 solar collection and storage sys-
tems in houses and experimental buildings
in the U.S., Japan, Australia, and Italy.
Solar space heating and cooling systems are
presently available in the U.S. on a custom-
built basis (NSF/NASA Solar Energy Panel,
1972: 13).
All solar heating systems have common
elements, but their characteristic design
and operation vary from one installation
to another. Consequently, solar collectors
and heat storage systems have not developed
the necessary dependability and economy re-
quired for mass production and widespread
public use. In addition, though solar en-
ergy is well distributed, energy storage
requirements and seasonal needs would have
to be carefully considered for each locality.
13.2.1.2 Energy Efficiencies
For this report, the efficiency with
which fuels and energy are utilized is de-
fined as the efficiency of the fuel-using
device by itself (e.g., the furnace effi-
ciency of a residential space heating unit).
Some of the differences in space heat-
ing efficiencies can be explained by the
type of fuel used. Table 13-4 is a break-
down of the estimated efficiencies for
space heating by fuel in the residential
and commercial sector. These estimates re-
flect average experience rather than the
maximum achievable. It is estimated that
13-7
-------
TABLE 13-4
SPACE HEATING EFFICIENCIES BY FUEL
FOR THE RESIDENTIAL AND COMMERCIAL SECTOR
Fuel Type
Coal
Natural gas
Petroleum
products
Electricity
Residential
(percent)
55
75
63
95
Commercial
(percent)
70
77
76
95
Source: SRI, 1972: 153.
start-up, shutdown intermittency (tempera-
ture control by thermostat on-off opera-
tion) of a residential gas-fired furnace
can drop the overall efficiency to as low
as 50 to 60 percent. Also, equipment mal-
adjustments can reduce the efficiency an-
other 5 to 10 percent (Schurr, 1971:
VIII-32, VIII-33) . Thus, reported typical
end use efficiencies of gas— and oil-
burning home heating systems range between
40 and 80 percent.
As shown in Table 13-4, coal effi-
ciency is much higher for commercial estab-
lishments than for residences, primarily
because of better equipment maintenance
and adjustment. Conversely, the efficien-
cy of the larger, more sophisticated com-
mercial natural gas burners is only two
percent greater than that of home furnaces.
Oil efficiency in commercial establishments
is substantially higher than in homes and
approaches natural gas efficiency. The
efficiencies of coal, gas, and oil heating
units are limited primarily by economics.
Additional heat exchangers necessary to
extract all possible heat from the combus-
tion gases would require substantial capi-
tal investment in the heating device.
As indicated in Table 13-4, electric
heating is considered 95-percent efficient
in both homes and businesses. However,
this estimate applies only to the conver-
sion of electricity to heat and does not
take into account the conversion of fuel to
electricity. In the U.S., the average
efficiency for electric power generation
plants is about 33 percent (see Chapter 12).
Thus, if the efficiency for electrical re-
sistance heating included electricity gen-
eration, the total system efficiency would
be approximately 30 percent (SRI, 1972:
154) .
Table 13-5 lists typical coefficient
of performance (C.O.P.) values obtainable
for electric heat pumps using various heat
sources and sinks. The performance measure
for heat pumps is defined as the ratio of
useful heat moved to the quantity of energy
required to operate the system. Given an
electric power generation plant operating
•
at approximately 33-percent efficiency in
conjunction with an air-to-air heat pump
(C.O.P. of 2.5—average overall performance
given certain assumptions about the climate
of the region), the total system efficiency
is 33 percent times 2.5 or about 82 percent.
On the average, this efficiency is better
than that required for fueling a typical
TABLE 13-5
COEFFICIENTS OF PERFORMANCE FOR
ELECTRICALLY DRIVEN HEAT PUMPS WITH
VARIOUS SOURCES AND SINKS
Source
and
Sink
Air
Water
Earth
Coefficient of Performancea
(C.O.P.)
Heating
2.5
5.0
3.0
Cooling
3.0
4.0
3.0
Source: Battelle, 1973: 540.
^.
^
C.O.P. is the ratio of heat moved to the
quantity of energy needed to operate the
system (see text).
13-8
-------
house furnace. Note that as the overall
operating efficiency of the central power
station increases, the heat pump potential
relative to other heating systems also in-
creases (Battelle, 1973: 541).
13.2.1.3 Environmental Considerations
Table 13-6 contains the environmental
residuals quantified by Hittman for resi-
dential and commercial space heating. Im-
pact data corresponds to a particular fuel,
and the fuel used serves as the link be-
tween the end use and supply portions of
the data. Where the end use is electrical,
the Btu values represent the energy neces-
sary to generate that electricity. There-
fore, these values include the 67-percent
energy loss involved in the generation
phase. The residuals for electrical space
heating devices occur prior to end use;
that is, the residuals are at the central
power station. The data in Table 13-6 are ,
considered fair, with a probable error of
less than 50 percent.
A quick review of Table 13-6 shows
that space heating environmental impacts
are primarily air pollutants with the prin-
cipal emissions being particulates, oxides
of nitrogen (NOX), and oxides of sulfur
(SOx). As reported in the technological
description, specific air emissions can be
affected by fuel type, quality, and other
factors such as equipment design, adjust-
ment, and maintenance. The significance
of these residuals is directly related to
the concentration of residential and commer-
cial activities and to local meteorological
and topological circumstances.
13.2.1.4 Economic Considerations
Relatively "cheap" energy (i.e., ener-
gy that is inexpensive compared to other
components of production cost) discourages
investment in more energy-efficient systems.
As long as energy was cheap and abundant,
the economic trade-off favored low capital
investment rather than optimization of
long-term maintenance and operating costs.
Rising energy prices and the possibility of
limited supplies should encourage consumers
to consider energy consumption levels and
lifetime operating costs as well as the
initial cost of heating equipment.
Table 13-7 depicts fuel costs and
consumption levels for heating a typical
1,500-square foot house by various methods.
The fuel quantity is the Btu equivalent
measured at the input to the power plant.
The fuel costs for oil and gas heating are
essentially the same, while electrical re-
sistance heating costs about twice as much.
From a conservation viewpoint, direct com-
bustion heating does not waste as much pri-
mary fuel as electrical resistance heating
because the electrically heated home re-
quires about twice as much fuel per unit of
heat delivered. Because of the higher op-
erating costs of electrical resistance
heat, only the more expensive homes would
be expected to use it. However, lower in-
stallation costs and promotional appeals
have resulted in widespread use. Presently,
electric rate schedules favor heavy elec-
tricity users, which enhances electric
heating. However, pressure is increasing
to remove or in some manner reduce these
advantages because they favor energy waste-
fulness (Braddock, Dunn and McDonald, 1974b:
V-16).
The utilization of heat pumps could
equalize the positions of electric, gas,
and oil heating systems from a fuel conser-
vation standpoint. As a countrywide aver-
age, the heat pump delivers about two units
of heat energy for each unit of electrical
energy that it consumes (Hirst and Moyers,
1973a: 1301). Also, dual heating/cooling
heat pumps are not particularly expensive
when compared to conventional central
heating/cooling systems because the basic
equipment and air handling systems are the
same for both heating and cooling. Although
the figure seems low, one source estimated
that installed in a typical residence, a
13-9
-------
Table 13-6. Residuals for Space Heating Energy Use
End Use Sector
Residential End Use/Fuel
SPACE HEAT
Natural Gas
Liquid Petroleum Gas
Distillate
Electricity
Commercial End Use/Fuel
SPACE HEAT
Natural Gas
Liquid Petroleum Gas
Distillate
Residuals
Coal
Water Pollutants (Tons/measure)
1 Acids
NA
NA
NA
NA
NA
NA
NA
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
NA
NA
0*
0<
NA
NA
NA
NA
NA
NA
NA
NA
NA
ro
O
2
NA
KA
NA
NA
NA
NA
NA
NA
NA
Total Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
1 Suspended
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
Organics
NA
NA
0
NA
NA
NA
0
0
NA
8
0)
NA
NA
NA
NA
NA
NA
NA
NA
NA
8
u
NA
NA
NA
NA
NA
NA
NA
NA
NA
1 Thermal (Btu's/
[measure)
NA
NA
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/measure)
Particulates
1.15
xlO-3
1.21
xlO-3
5.01
xlO-3
NA
2.32
xlO-6
2.45'
xlO-6
1.38
xlO-5
1.96
XlO-5
1.19
xlO-4
§*
3.03
xlO-3
3.92
xlO-3
6.01
xlO-3
NA
1.23
xlO-5
' 1.3i "
xlO-5
5.54
xlO-5
5.12
xlO-5
3.39
xlO-5
0*
U]
3.45
xlO-5
7.06
xlO-4
1.62
xlO-2
NA
7.15
xlO~8
1.36
xlO-6
2.90
xlO-5
2.23
xlO-4
3'4?
xlO-4
Hydrocarbons
4.86
XlO~4
4.9
xlO-3
1.5,
xlO-3
NA
9.78
xlO~7
9. S3
xlO~7
2.76
x!0~6
2.56
xlO-6
1.28
XlO-5
O
o
1.21
xlO-3
1.28
xlO'3
XlO1'
NA
2.45
x!0~6
•ZTSB-
xlO"6
1.84
xlO-V
1.71
Xl0~7
5.64
xlO-5
Aldehydes
6.05
xlO-4
6.22
xlO-5
.001
NA
1.23
XlO'6
1.25
xlO-6
1.84
xlO~6
8.54
Xl0~7
2.09
xlO-7
Solids
(tons/measure)
NA
NA
NA
NA
NA
NA
NA
NA
U
a,b
Measure
Dwelling-
year
Dwelling-
year
Dwelling-
year
Dwelling-
year
Square foot
year
Square foot
year
Square foot
year
Square foot
year
Square foot
year
Energy
Btu/measure
1.25
xlO8
TT25
xlO8
1.39
xlo8
1.45
x!08
2.52
xlQ5
2.52
Xlfl5
2.55
xlO5
2.55
X105
2.77
xlO5
Multiplier
xlO'
3.81
xlo6
1.65
xlO7
4.88
xlO6
7.37
xlO9
xio8
2.23
x!09
4.6
X109
1.54
xlQ9
Multiplier Year
1970
1970
1970
1970
1970
1970
1970
1970
1970
NA = not applicable, NC = not considered, U = unknown.
Dwelling-year is a heated and cooled typical residence operated for one year.
Square foot-year is a heated and cooled typical square foot of commercial space over a period of one year.
-------
TABLE 13-7
ANNUAL FUEL COST AND CONSUMPTION FOR SPACE HEATING5
Heating Method
Resistance heating
Electric heat pump
Home combustion, oil
Home combustion,
natural gas
Fuel Cost
(dollars)
471.3
117.6
209.0
227.1
Fuel Quantity
(10° Btu's)
251.3
62.8
154.6
134.0
Source: Szego, 1971: Vol. II, Part B, p. F-27.
Represents heating cost and consumption for a typical 1,500-
square foot house.
Btu equivalent is measured at the input to the power plant.
three—ton heat pump unit would cost about
$1,800 (Battelle, 1973: 541). However, if
increased utilization is expected, cost
data and unit reliability need to be more
firmly established.
Solar energy residential heating in
suitable climates could be available even
today at costs below those of electrical
resistance heat (Tybout and Lof, 1970;
Szego, 1971: Vol. II, Part B, p. G-18).
Further, as the cost of conventional heat-
ing fuels increases and solar economics
become more certain, solar heating should
compare even more favorably.
13.2.2 Air Conditioning
13.2.2.1 Technologies
In 1970, residential and commercial
air conditioning accounted for 3.0 percent
of the national energy requirement. More
important, air conditioning represents one
of the most rapidly growing uses of energy.
From 1960 through 1968, residential air
conditioning grew at an annual compounded
rate of 16 percent (Table 13-2). In addi-
tion, approximately 18 percent of the in-
crease in total residential electrical en-
ergy consumption between 1960 and 1970 was,
due to electric-powered "compression-type"
air conditioning; more than one-half of
this increase was consumed by room units
(Large, 1973: 871).
Using averages reported by the SRI
(1972: 73), Hittman estimated that about 70
percent of the building space in commercial
establishments was air conditioned in 1970
(13 percent used gas as a fuel source with
the remainder allotted for electricity).
Since electricity meets most of the air
conditioning needs and powers the auxiliary
equipment for gas units, space cooling is
an important factor in summer peak loads of
utility systems (Braddock, Dunn and
McDonald, 1974b: II-l, II-2).
13.2.2.2 Energy Efficiencies
The efficiencies of heat removal for
air conditioning have been estimated at 50
percent for electric equipment and 30 per-
cent for gas equipment (SRI, 1972: 173).
Thus, the cooling cycle is much less effi-
cient than the heating cycle.
The conventional measure of efficiency
for room air conditioners is the ratio of
cooling capacity to power requirements ex-
pressed in Btu's per watt-hour. Existing
13-11
-------
TABLE 13-8
VARIATIONS IN PERFORMANCE OF SELECTED AIR CONDITIONERS
Rated Cooling
Capacity
(Btu's)
4.000
5,000
6,000
8,000
24,000
Rated Current
Demand
(amperes)
8.8
7.5
7.5
5.0
9.5
7.5
7.5
5.0
9.1
9.1
7.5
7.5
12
12
13.1
15.4
17.0
Retail
Price
(dollars)
100
110
125
135
120
140
150
165
160
170
170
180
200
220
U
U
U
Power
Consumption
(Btu's per
watt-hour)
3.96
4.65
4.65
6.96
4.58
5.80
5.80
8.70
5.34
5.24
6.96
6.96
5.80
5.80
8.25
7.10
5.85
10-Year
Total Cost
(dollars per
1,000 Btu's)
84
77.70
81.45
67.25
74.90
68.20
70.20
59.80
67.30
68.90
61.80
63.50
67.30
67.80
U
U
U
U = unknown
Source: Federal Council on Science and Technology.
data indicate that room air conditioner
efficiencies vary widely from one model to
another. Differences of efficiency also
occur for different models with the same
rated cooling capacity. In a study of units
having ratings up to 24,000 Btu's per hour
published by the Committee on Energy Re-
search of the Federal Council on Science
and Technology (Table 13-8), efficiencies
ranged from 3.96 to 8.70 Btu's per watt-
hour, with a probable error of less than 50
percent for most of the data. Thus, the
least efficient device consumes 2.2 times
as much electricity per unit of cooling as
the most efficient one. Table 13-8 illus-
trates that the most expensive units gener-
ally offer the best efficiency and the low-
est long-term costs.
From the standpoint of primary fuels
consumption, electric central air condition-
ing systems are more efficient than gas in
a private household. For large buildings,
gas may be more efficient.
13.2.2.3 Environmental Considerations
Estimates of the environmental resid-
uals for natural gas central residential
and commercial air conditioning systems are
given in Table 13-9. The validity of the
data is unknown, with the error probably
within or around an order of magnitude.
The residuals for the electric equipment
occur prior to end use; that is, at the
electric power generation plant.
13.2.2.4 Economic Considerations
In general, as noted in Table 13-8,
the efficiency of air conditioning equip-
ment correlates with price; units with effi-
ciency improving design features (e.g., lar-
ger heat transfer surfaces, more efficient
motors, etc.) cost more to build. Due to
13-12
-------
Table 13-9. Residuals for Air Conditioning Energy Use
End Use Sector
Residential End Use/Fuel
AIR CONDITIONING;
Central
Natural Gas
Electric
Room
Electric
Commercial End Use/Fuel
AIR CONDITIONING:
Central
Natural Gas
Electric
Electric
Water Pollutants (Tons/measure)
in
U
NA
NA
NA
NA
NA
NA
10
w
a
«
NA
NA
NA
NA
NA
NA
2*
NA
NA
NA
NA
NA
NA
ro
O
z
NA
NA
NA
NA
NA
NA
•a
01
O
Ul
in
"«,
r-l'O
JJ .-1
O O
E-i W
NA
NA
NA
NA
NA
NA
T3
t}
C Ul
3 O
cncfl
NA
NA
NA
NA
NA
NA
u
• H
C
tfi
H
O
NA
NA
NA
NA
NA
NA
8
NA
NA
NA
NA
NA
NA
8
u
NA
NA
NA
NA
NA
NA
^
3
4J
S
10 U
6 3
01 id
A a)
H e
NA
NA
NA
NA
NA
NA
Air Pollutants
01
0)
IV
u
• r4
M
id
cu
5.72
xlO~4
NA
NA
2.68
Xl0~7
NA
NA
§*
1.66
xlO-3
NA
NA
1.55
xlO~6
NA
NA
X
o
U)
1.8
xlO-5
NA
NA
8.23
xlO-9
NA
NA
(Tons/measure)
C/l
0
u
o
M
"D
fi1
2.41
xlO~4
NA
NA
1.13
xicr7
NA
NA
O
u
6.02
xlO~4
NA
NA
2.82
xicr7
NA
NA
in
£
01
T3
n-l
rt!
3.01
xlO~4
NA
NA
1.41
Xl0~7
NA
NA _,
01
3
w
10
0)
e
MX
T3 W
•H C
rH O
0 4J
U) —
NA
NA
NA
NA
NA
NA
,Q
id
3
Ul
ID
£
Dwelling-
year
Dwelling-
year
Unit-year
Square fool
year
Square foot
year
Square foot
year
0!
3
in
(0
>i m
CnS
* *>
-------
the large number of available models and
the range of efficiencies (complicated by
the fact that efficiency figures have not
been given in a meaningful way to the pub-
lic) , the consumer is not likely to select
the unit with the best long-term cost. In-
stead, his decision will likely depend more
on first costs, resulting in the purchase
of a unit with a lower selling price and,
generally, a lower efficiency.
In addition to picking the most ener-
gy-efficient unit, it is equally important
to accurately determine the needed cooling
capacity. A larger than necessary unit
will not only draw excess power but also
will not cool properly as it tends to cycle
off before the room space is sufficiently
dehumidified.
In the case of central air condition-
ers (24,000 to 36.000 Btu's per hour), in-
stallation expenses and operating costs
vary markedly in the same manner as room
units. In general, however, gas units are
more expensive to install but may be less
expensive to operate.
Finally, most space cooling equipment
uses an inefficient and inexpensive throt-
tle valve to expand the fluid used in the
system and thus produce the cooling effect.
To accommodate for the cooling losses
caused by this throttling process, an ex-
cess of 20-percent power consumption is
designed into the cycle for a given cool-
ing capacity (Berg, 1974: 21). In other
words, since market demand is based pri-
marily on first cost, the first-cost econ-
omies of throttling valve use are more
important in customer sales than the long-
term inefficiencies of such units.
13.2.3 Water Heating
13.2.3.1 Technologies
Water heating in the residential and
commercial sector accounted for approxi-
mately four percent of the national energy
demand in 1970. About three-fourths of
this amount was used in residences where
TABLE 13-10
WATER HEATING EFFICIENCIES BY FUEL
FOR THE RESIDENTIAL AND COMMERCIAL SECTOR
Fuel Type
Coal
Natural gas
Petroleum
products
Electricity
Residential
(percent)
15
64
50
92
Commercial
(percent)
70
64
50
92
Source: SRI, 1972: 154.
water heating is the second largest energy-
consuming function. Currently, increased
consumption for both electric and gas water
heaters is explained by the increasing num-
bers of dishwashers and washing machines.
Not only do these appliances demand more
energy for hot water, but they also require
electricity for operation. As per capita
affluence increases in this country, the
number of appliances using hot water is
likewise expected to increase. Some manu-
facturers offer heat pump energized water
heaters, but data are not available for
this technology.
13.2.3.2 Energy Efficiencies
The efficiency of heating water varies
by fuel as shown in Table 13-10. Most of
the data are considered good, with a proba-
ble error of less than 25 percent. About
20 percent of the energy used by hot water
heaters is required to maintain the desired
temperature of the water; that is, to com-
pensate for heat losses to the heater's
surroundings and for water that cools off in
piping between uses (Hirst and Moyers, 1973b:
174) .
13.2.3.3 Environmental Considerations
Table 13-11 contains the environmental
residuals for water heating in the
13-14
-------
Table 13-11. Residuals for Water Heating Energy Use
End Use Sector
Residential End Use/Fuel
WATER HEAT
Natural Gas
Liquid Petroleum Gas
Distillate
Electricity
Commercial End Use/Fuel
WATER HEAT
Natural Gas
Liquid Petroleum Gas
Electricitv
Water Pollutants (Tons/measure)
Acids
NA
NA
NA
NA
NA
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
0*
H
NA
NA
NA
NA
NA
NA
NA
r>
i
NA
NA
NA
NA
NA
NA
NA
1 Total Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
1 Suspended
Solids
NA
NA
NA
NA
NA
NA
NA
Organics
NA
NA
0
NA
NA
NA
NA
§
m
NA
NA
NA
NA
NA
NA
NA
8
u
NA
NA
NA
NA
NA
NA
NA
Thermal (Btu's/
| measure)
U
U
U
U
IT
U
U
Air Pollutants (Tons/measure)
Particulates
2.49
xlO-4
2.62
xlO-4
1.25
xlO-3
NA
9.58
XlO-9
1.01-
xlO'8
NA
X
o
z
7.22
xlO-4
9.35
xlO-4
1.5
xlO-3
NA
5.55
xio-e
xio-8
NA
0*
en
7.86
xlO-6
1-53^
xlO-4
4.03
xlO~3
NA
2.95
xlO-iO
5.73o
xlO-9
NA
Hydrocarbons
1.05
XlO-4
1.06
xlO-4
3.92
xlO-4
NA
4,03
XlO-9
4.09
xlO-9
NA
O
U
2.62
xlO-4
2.76
xlO~4
6.25
xlO-4
NA
1.01
xlO~8
1.06
xlO-8
NA
Aldehydes
1.31
xlO-4
1'34^
xlO-4
2.5
xlO-4
NA
5.04
XlO-9
5.18
xlO-9
NA
Solids
(tpns/measure)
NA
NA
NA
NA
NA
NA
NA
a
Measure
Dwelling-
year
Dwelling-
year
Dwelling-
year
year
Gallons
Gallons
Gallons
Energy
Btu/measure
2.7
xlO7
2.7
xlO7
3.46
xlO?
4.62
xlO?
1.04
xlO3
r.53
xlO3
2.19
xlO3
Multiplier
3.5
xlO?
3.14
XlO6
6.2
xlO6
1.61
xlO7
4.03
xlQll
1.7
xlO^-O
1.2
xlO11
Multiplier Year
1970
1970
1970
1970
1970
1970
1970
NA = not applicable, NC = not considered, U = unknown.
aDwelling-year is water heated in a typical residence over a period of one year.
-------
residential and commercial sector. The
data are considered fair, with a probable
error of less than 50 percent. Residuals
quantified are for natural gas, liquefied
petroleum gas (LPG)• and distillate-using
devices. The residuals for electric water
heaters occur at the electric power genera-
tion plant and not at the end use point.
Compared to the residuals for space heating,
water heating air emissions are relatively
small (particularly in the commercial use).
13.2.3.4 Economic Considerations
The use of additional insulation in
the jacket surrounding the water storage
tank appears to be a promising way of de-
creasing water heater energy consumption.
However, as with space-conditioning de-
vices, the trade-off is in terms of lower
initial investments. The cost of two—inch,
factory-installed insulation for electric
water heaters is about $5.00 per unit cheap-
er than if three-inch insulation is used.
Yet, use of three-inch insulation would
result in an operating savings of $1.00 to
$2.00 per year, resulting in a net savings
over the normal 10-year service life of
these water heaters (Hirst and Moyers,
1973b: 174).
13.2.4 Refrigeration
13.2.4.1 Technologies
Refrigeration in the residential and
commercial sector accounted for 2.5 percent
of the total energy demand in 1970. Esti-
mates report 96 percent of all households
had refrigerators in 1969 (SRI, 1972: 46).
In the commercial area, supermarkets, pub-
lic eating places, and institutions have
been identified as the major users of re-
frigeration and food storage.
Increased size and design changes
(e.g., automatic ice cube makers, frostfree
operation) have contributed to increased
unit consumption. Using averages calcu-
lated by Hittman, total residential and
commercial consumption for refrigeration
12
and freezer use in 1970 was 2,904x10
Btu's (Hittman, 1974: Vol. I, Table 27),
12
compared to approximately 1,362x10 Btu's
in 1968. Part of this increase can be
attributed to more widespread use of large,
frostfree model refrigerator/freezers which
require about two-thirds more energy than
smaller, manual defrost units (Ford Founda-
tion, 1974: 2).
13.2.4.2 Energy Efficiencies
The average efficiency of electric
refrigeration devices is about 50 percent
(SRI, 1972: 155).
13.2.4.3 Environmental Considerations
The environmental residuals for resi-
dential and commercial electric refrigera-
tion occur at the central power plant.
Although some gas refrigerators are still
used in the U.S., their environmental im-
pact is negligible.
13.2.4.4 Economic Considerations
Both the operating and capital costs
for frost-free refrigerator/freezers are
higher than for standard models. This is
an example of how the convenience extras,
which are available in many electric appli-
ances, often increase their energy consump-
tion. As a result, there is a need for
better labeling (e.g., capacity, fuel con-
sumption, electric power rating, service
life expectancy, etc.) of appliances so
that consumers can weigh increased oper-
ating costs against the added convenience.
These trade-offs will become more signifi-
cant to consumers if electricity costs con-
tinue to increase.
13.2.5 Cooking
In 1970, cooking accounted for 1.2
percent of the overall energy consumption
in the U.S.
13.2.5.1 Technologies
Gas or electric oven/ranges were found
in 96 percent of all U.S. households by 1960.
13-16
-------
Although electric range usage increased
from 33 percent in 1960 to 40 percent in
1968, the average per-unit energy consump-
tion decreased, probably because of the use
of improved heat-transfer materials. As in
other appliances, range convenience fea-
tures such as self-cleaning ovens, automat-
ic timers, and built-in clocks increase
energy consumption.
In the commercial sector, energy de-
mand for cooking is affected primarily by
the nature, size, and diversity of the
equipment. Although insignificant in terms
of total national energy consumption, com-
mercial cooking is one of the fastest grow-
ing end uses in this sector. Between 1960
and 1968, the annual growth rate of commer-
cial cooking was 4.5 percent, larger than
that of commercial space heating (3.8 per-
cent) .
13.2.5.2 Energy Efficiencies
Both natural gas and LPG have an effi-
ciency of about 37 percent in cooking,
while electricity has 75-percent efficiency
(SRI, 1972: 154). Self-cleaning features
on ovens have been estimated to increase
overall energy consumption by 21 percent.
Also, thermal efficiencies vary according
to several factors; for example, different
utensils and different amounts of water.
Microwave ovens are an important de-
velopment in cooking technology. American
Gas Association studies show that microwave
ovens use an average 96.5 percent fewer
Btu's than gas ovens and 71.4 percent fewer
Btu's than electric ovens (SRI, 1972: 46).
13.2.5.3 Environmental Considerations
Table 13-12 gives the environmental
residuals associated with cooking. These
residuals are negligible in terms of over-
all residential and commercial environmen-
tal impacts, even considering the probable
error of about 100 percent.
Automatic-cleaning oven/ranges used in
residences emit higher per-unit levels of
air pollutants than standard oven/ranges.
For example, a natural gas range with auto-
matic oven cleaner emits 4.67xlO~4 tons per
dwelling-year of air emissions compared to
4.47x10 tons per dwelling-year for a stan-
dard oven/range.
13.2.5.4 Economic Considerations
Like other appliances, ovens waste
considerable amounts of energy because mar-
ket demand is based primarily on initial
cost, with operating costs and service life
expectancy secondary. In addition, conven-
ience extras increase both capital and long-
term appliance costs.
Recently, the price of microwave ovens
has reached a competitive level, causing
their sales to make headway in the residen-
tial market. This factor could enhance con-
servation goals.
13.2.6 Other
Of the remaining end uses reported by
Hittman for the residential and commercial
sector, only natural gas yard lights and
gasoline-powered lawn and garden equipment
have measurable environmental residuals
associated with their use.
Each natural gas yard light emits
5.24xlO~ tons of SOX per unit-year. Since
approximately 3,800,000 such lights were in
use at the end of 1971, almost 20 tons of
SOX were emitted by these lights during
that year.
Air pollutants in tons per unit-year
for gasoline-powered lawn and garden equip-
—4
ment are: 3.05x10 for particulates;
2.83xlO~4 for NO,,; 3.04xlO~5 for SOx;
-•> -2
2.49x10 for hydrocarbons; 2.32x10 for
carbon monoxide (CO); and 3.99xlO~ for
aldehydes. This represents a total of
2.63xlO~2 tons per unit-year of air pollu-
tants, the major portion being hydrocarbons
and CO.
13.2.7 Conservation Measures for the
Residential and Commercial Sector
As discussed in the preceding sections,
the principal energy consuming end uses—
13-17
-------
Table 13-12. Residuals for Cooking Energy Use
End Use Sector
Standard Oven-Range
Liquid Petroleum Gas
Automatic Cleaning
Commercial End Use/Fuel
Water Pollutants (Tons/measure)
10
-D
•H
O
<
NA
Bases
NA
1 NA
NA
NA
-------
space heating, air conditioning, and water
heating—are the same for households and
commercial establishments. Thus, conser-
vation measures aimed at one are generally
applicable to the other. A recent study
(Ford Foundation, 1974a: 48) identified
two basic criteria for conservation mea-
sures: a significant savings in energy
should be possible, and the conservation
measure must be economical (i.e., save
money for the consumer). For example, the
installation of electric heat pumps instead
of electric resistance heating units in
new homes and businesses in some parts of
the U.S. would result in a small additional
investment but very significant dollar sav-
ings per year in electricity bills. Thus,
this conservation measure is also economi-
cal on a life cycle cost basis.
The OEP study cited in Section 13.1.3
found the greatest potentials for energy
savings in the residential and commercial
sector to be improved insulation in homes
and adoption of more efficient air condi-
tioning systems. Following is a summary
of OEP's recommendations (1972: 56-57) for
short-, mid-, and long-term measures. The
potential savings given for each period
are estimates for the last year of the pe-
riod and are expressed both in Btu's per
year and as a percentage of the projected
total residential and commercial consump-
tion.
1. Short-Terra Measures (1972-1975).
Provide tax incentives and in-
sured loans to encourage improved
insulation in homes. Encourage
use of more efficient appliances
and adoption of good conservation
practices. Savings: 100x10^2
Btu's per year (one percent).
2. Mid-Term Measures (1976-1980).
Establish upgraded construction
standards, tax incentives, and
regulations to promote design and
construction of energy-efficient
dwellings, including the use of
the "total energy concept" for
multi-family dwellings. Provide
tax incentives, R&D funds, and
regulations to promote energy-
efficient appliances, central air
conditioning, water heaters, and
lighting. Savings: 5,100x10
Btu's per year (14 percent).
3. Long-Term Measures (beyond 1980).
Provide tax incentives and reg-
ulations to encourage demolition
of old buildings and construction
of new, energy-efficient buildings.
Provide R&D funding to develop new
energy sources (e.g., solar and
windpower). Savings: 15,000x10
12
Btu's per year (30 percent).
The savings indicated above are in
terms of primary source energy inputs be-
fore conversion to the energy forms finally
utilized. Some of the savings would result
in direct reductions in electric energy
demand, while others could possibly result
in greater electricity consumption. Yet
other measures would reduce the direct con-
sumption of fossil fuels at their point of
end use. However, in all cases, fuel in
some form would be saved contributing to
net energy reduction; that is, total demand
would be reduced compared to a "no conser-
vation" projection. Some of the alterna-
tives for achieving the energy savings
cited above are described in the following
sections.
13.2.7.1 Simple Conservation Practices
Some energy demand reduction for space
heating and cooling can be achieved through
encouraged adoption of simple conservation
practices that cause minor or no inconven-
ience to consumers. Examples are thermo-
stat regulation, turning off lights when
not in use, drawing blinds and draperies in
unoccupied rooms, installation of awnings
and shades, selecting light colors for house
paint and roofing, and the use of reflective
glass to screen out solar radiation in the
summer (OEP, 1972: D-l, D-4). Of course,
the potential of such measures is not large
when compared to results that might be
achieved by "leak plugging" techniques.
13.2.7.2 Improved Thermal Insulation
The most significant potential for
energy conservation is in improved home and
business insulation. The heat losses or
13-19
-------
gains that determine the effectiveness of
heating a- d air conditioning in buildings
are essentially the same, the major sources
of the leaks being inadequate insulation,
excessive ventilation, and high rates of
air infiltration (Berg, 1973: 553). De-
creasing the thermal leakage in buildings
would benefit the consumer by both reducing
heating and cooling expenditures and re-
ducing the size and capital cost of heating
and air conditioning equipment. In addi-
tion, improved insulation offers an imme-
diate control measure to reduce the local
air pollution emitted by space heating
devices (National Mineral Wool Insulation
Association, 1972: 3-4).
One measure of the effectiveness of
residential building insulation and ven-
tilation is the Federal Housing Adminis-
tration (FHA) minimum property standards,
which in 1965 permitted heat losses of
2,000 Btu's per thousand cubic feet (mcf)
per degree day. In 1972, these standards
were raised to require that losses by less
than 1,000 Btu's per mcf per degree-day.
Because few residential buildings are de-
signed to exceed FHA performance standards,
it is reasonable to assume that most of
the residential buildings in use today re-
quire about 40 percent more energy to heat
and cool than they would if they were in-
sulated and sealed in accordance with cur-
rent FHA standards. Similarly, sample
field observations indicate that as much
as 40 percent of the fuel used to heat and
cool commercial buildings could be saved
by improved insulation (Berg, 1973a: 553-
554).
Techniques to accomplish improved
thermal performance of structures include:
1. Fit houses with storm windows
and storm doors.
2. Caulk and weatherstrip windows
and doors.
3. Insulate attics in existing
houses.
4. Insulate walls and ceilings in
new homes.
Future standards for insulation and
control of air infiltration may offer even
greater potential for saving energy. Stud-
ies indicate that it is technologically
and economically feasible to reduce heating
losses from buildings to approximately 700
Btu's per 1,000 cubic feet (cf) per degree-
day through improved insulation practices.
Implementation of this standard would re-
duce total energy requirements of build-
ings by more than 50 percent through well-
designed insulation and careful control of
ventilation (Berg, 1973a: 554).
13.2.7.3 Building Design and Construction
A measure related to better insula-
tion practice is better design and con-
struction concepts for both residential
and commercial buildings. For example, a
few of the currently available methods for
saving energy are the use of more energy-
efficient shapes (circles and cubes), more
windows facing north than south, summer
shades for windows facing south or west,
use of double glazing and heat reflective
glass, prescribed heating and cooling of
occupied and specialized areas (such as
computer centers) rather than entire build-
ings, and improved building skins (Braddock,
Dunn and McDonald, 1974a: L-12).
13.2.7.4 Higher Efficiency Fossil-Fueled
Furnaces
Higher efficiency furnaces, including
improved design of heat transfer surfaces
and better maintenance and adjustment of
burners, offer other potential savings in
space heating. Battelle Laboratories con-
ducted three residential case studies to
determine the effect of combustion equip-
ment adjustment and servicing, plus the
effect of increasing thermal insulation,
on pollutant emission estimates for vari-
ous fuels (Battelle, 1973: 606-608).
Their results show substantial reduction
in emissions for gas, oil, and coal burning
devices when the equipment is kept well-
tuned and insulation is provided according
13-20
-------
to FHA specifications, including additional
insulation and storm windows.
In conjunction with higher efficiency
furnaces, the continuous burning gas pilot
light could be replaced with an electric
switch-operated ignitor. (One source es-
timates that the installation of electric
ignition systems for gas appliances in res-
idences could result in energy savings in
1980 of 70xl012 Btu's per year (Braddock,
Dunn and McDonald, 1974b: L-97).
13'.2.7.5 Higher Efficiency Room and
Central Air Conditioners
Available data suggest substantial
latitude for improving the efficiency of
air conditioning units. Considering the
size distribution for 1970 sales, the av-
erage efficiency of existing room air con-
ditioners was estimated to be six Btu's
per watt-hour. If the assumed efficiency
is improved to 10 Btu's per watt-hour (a
level technologically feasible today),
overall consumption for this end use could
be reduced 15.8 billion kilowatt-hours
(kwh) or approximately 40 percent (Hirst
and Moyers, 1973a: 1302).
13.2.7.6 Use of Electric Heat Pumps
As noted previously, the use of elec-
tric heat pumps could just about equalize
the overall efficiencies of electric, gas,
and oil heating systems. From the con-
sumer 's point of view, heat pump savings
must be balanced against higher capital in-
vestment and maintenance costs. These
costs have tended to retard their wide-
spread use; however, as manufacturers im-
prove component reliability, the heat pump
should receive greater market acceptance.
One source estimates that if heat pumps
were used instead of electrical resistance
heating for residential and commercial
space heating, the potential energy savings
by 1985 could be 2,400x10 Btu's per year
(Ford Foundation, 1974a: 50, 52).
13.2.7.7 Total Energy Systems
Sufficiently higher fuel prices may
make total energy systems more attractive.
Electricity could be generated on site,
allowing the waste heat from the electrical
generation process to be used for space
heating in the winter and air conditioning
in the summer. Such systems could be em-
ployed for large commercial establishments
and in urban or residential complexes. A
total energy system wastes only 20 to 30
percent of the fuel by providing both elec-
tricity and heat, unlike the central gen-
erating plant where 60 to 70 percent of the
fuel's energy is wasted (Ford Foundation,
1973: Chapter XII, p. 15).
13.2.7.8 Solar Energy
Solar radiation provides clean energy
without polluting or depleting the earth's
resources. Solar energy could be used for
space heating, to power heat pumps, to heat
water, and for absorption air conditioning
(after additional research and development).
One source estimates that use of solar en-
ergy to provide the above residential needs
would result in a total energy savings of
almost 20 percent, as well as a substantial
overall load reduction on central power
stations (Battelle, 1973: 534). Although
savings estimated in the next decade from
solar energy usage are speculative, the
potential (especially for space heating and
water heating) is great, given further re-
search and development.
13.2.7.9 Water Heating
Several approaches designed to reduce
consumption of energy for water heating can
be identified. One such approach is to im-
prove the efficiency of hot water systems
through better insulation of heater shells
and hot water transporting pipes, recovery
of heat from hot water after use (i.e.,
using the drain flow from washing machines.
13-21
-------
dishwashers, etc.), and using waste heat
from other appliances to preheat the feed-
water for hot water tanks.
A second approach is the use of solar
water heaters. Solar water heaters are
commercially available (NSF/NASA Solar
Energy Panel, 1972: 13) and have been used
in Florida, California, and a number of
foreign countries for years. One source
estimates that using solar energy for water
heating could reduce U.S. fuel requirements
by two percent or more (Berg, 1973a: 559) .
A third approach is the one previously
mentioned for space heating devices, re-
placing pilot lights on all fossil-fueled
hot water heaters'with electric igniters.
I
13.2.7.10 Other Potential Energy Savings
In addition to the above, other mea-
sures can be taken to conserve energy.
Cooking utensils could be made more energy
efficient and range burners redesigned or
other efforts made to use the heat that
currently escapes around the utensil and
into the air (OEP, 1972: D-7).
Improved design of electric appliances
could significantly enhance their energy
utilization efficiency. For example, the
energy requirements of the refrigerator
could be reduced through such measures as:
1. Increased box insulation.
2. Better unit efficiency for the
cooling cycle.
3. Better user maintenance.
Gas yard lights, which have been re-
ported as emitters of SO, could be im-
proved or eliminated. Efforts to reduce
the proliferation and use of gasoline-
powered lawn and garden equipment would re-
duce local air emissions and energy con-
sumption .
Illumination of residences and commer-
cial buildings also deserves attention.
Twenty-four percent of all electricity sold
is used for lighting purposes (Large, 1973:
884), with commercial lighting accounting
for about 10 percent of total electricity
consumption. Light-intensity standards
-have more than tripled in the last 15 years,
and recommended lighting levels in office
buildings, which are considered excessive
by some, might be reduced in cases where no
danger exists to eyesight or worker perfor-
mance. According to one source, energy
used for lighting could be reduced by 50
percent if high levels were concentrated in
work areas, rather than throughout entire
rooms as in the current design philosophy
(Large, 1973: 884). The more extensive use
of flourescent lamps would result in addi-
tional savings because they are more than
three times as efficient as incandescent
lamps (OEP, 1972: D-9).
As indicated by the preceding analysis,
the effectiveness of energy use in the res-
idential and commercial sector can be im-
proved, and many of the possible improve-
ments appear to be economically justifiable,
especially considering that the alternative
is to expand the national energy supply.
In general, the measures to improve end-use
effectiveness are technological; these tech-
nologies are either currently extant or can
be readily developed.
13.3 INDUSTRIAL SECTOR
The industrial sector is the largest
energy consuming sector. In 1971, American
industries consumed 22,623x10 Btu's or
about 33 percent of the nation's total en-
ergy requirement for that year (Interior,
1972: 30). More than one-half of that en-
ergy was used in industrial thermal pro-
cesses alone (i.e., the direct burning of
fuels or the manufacture of steam), about
the same amount as required to supply all
residential energy needs. Manufacturing
consumes approximately 85 percent of indus-
trial energy and the remainder is equally
shared by agriculture and mining.
Industry uses energy in extremely di-
verse ways and only recently have detailed
breakdowns of industrial consumption been
attempted (SRI, 1972: 83-143; Braddock,
Dunn and McDonald, 1974a; III-ll; Hittman,
1974: Vol. I, Table 29, Parts 1, 2, and 3) .
13-22
-------
This description of industrial con-
sumption is incomplete in that it only
addresses use patterns for the following
six Standard Industrial Classification
(SIC) categories:
SIC 33: Primary Metals
SIC 28: Chemicals and Allied Products
SIC 32: Stone, Clay, Glass, and
Concrete
SIC 26: Paper and Allied Products
SIC 20: Food and Kindred Products
SIC 37: Transportation Equipment
Together, however, these industrial groups
accounted for almost two-thirds of total
industrial energy consumption in 1971.
The specific fuels and amounts used in the
six groups are given in Table 13-13. Nat-
ural gas has been the largest (about 40
percent) and most rapidly growing energy
source consumed directly in industrial
plants, followed by coal and coke (27 per-
cent) , electricity (22 percent), and petro-
leum products (11 percent). Electricity is
expected to replace natural gas as the
growth source of industrial energy in the
future.
As shown in Table 13-14, the six in-
dustrial groups also include the top five
energy intensive industrial groups, as
identified by the ratio of input energy to
dollar output (Braddock, Dunn, and McDonald,
1974a: 111-10). Among the large industrial
energy users, only food processing is not
energy intensive (Ford Foundation, 1974: 5).
Industrial uses include small amounts
of energy for space heating, air condi-
tioning, water heating, lighting, etc., and
conservation measures for these as dis-
cussed in the residential and commercial
sector are applicable here. As noted, half
the energy used in the industrial sector is
for heating processes. In 1968, industrial
use of process steam accounted for about 17
percent of total U.S. energy consumption.
An additional large industry—SIC
29-Petroleum Refineries and Related Prod-
ucts—is contained implicitly within .the
oil supply tables (see the refinery dis-
cussion in Chapter 3).
Direct heat—that is, heat obtained when
fuel is burned directly in an industrial
process (e.g., in the manufacture of steel
or cement)—comprised almost 13 percent of
the nation's energy requirement. Much of
the remaining energy use in this sector is
for mechanical energy in the form of elec-
tric drives (eight percent of national con-
sumption) , electrolysis to manufacture pri-
mary metals (one percent), and for "non-
energy" purposes; that is, as raw materials
or feedstocks for manufacturing processes
(about four percent) (SRI, 1972: 6).
13.3.1 Technologies
13.3.1.1 Primary Metals
The primary metal industries consume
the largest share of coal and coke, and the
second largest share of electric energy
used in the industrial sector. Energy use
in the iron and steel industry is comprised
principally of fossil fuels combustion,
oxygen, and electricity for firing coke
ovens, blast furnaces, and creating steam
for compressing blast, generating electric-
ity, and driving mills, forges, and process
lines. The energy required to produce a
ton of raw steel declined by 13 percent
between 1960 and 1968. (This discussion of
energy consumption by industrial groups is
largely from SRI, 1972: 88-143). This de-
cline was due primarily to more efficient
energy use by blast furnaces; for example,
the introduction of the "basic oxygen"
steel making furnace (OEP, 1972: E-7, E-8).
From 1960 through 1969, aluminum pro-
duction and processing were the most impor-
tant energy consuming segments of the pri-
mary metal industries. In 1969, primary
aluminum production was 88 percent above
the 1960 level, resulting in corresponding
increases in energy consumption (especially
electricity, the basic form required by the
industry). In the aluminum industry, elec-
tricity is used for electrolytic smelting
of aluminum, melting aluminum ingots and
13-23
-------
TABLE 1-13
ANNUAL FUEL CONSUMPTION FOR SIX MAJOR INDUSTRIAL USES'
Industrial Group
Chemical
Primary metals
Stone, clay,
glass, and
concrete
Paper and allied
products
Food and kindred
products
Transportation
equipment
TOTAL
Fuel Type (1012 Btu's per year)
Coal
and
Coke
696
1,706
702
373
177
78
3,732
Natural
Gas
2,335
1,095
1,289
420
378
84
5,601
Residual
183
170
433
196
65
14
1,061
Distillate
59
77
180
71
49
1
437
Electricity
1,083
1,018
317
304
261
146
3,129
Total
Energy
4,356
4,138b
2,921
1,364
930
323
14,032
Source: Calculated from Hittman, 1974: Vol. I, Table 29, Parts 1,2, and 3.
Petroleum refining not included because it is implicitly considered in the energy resource
chapter. In general, year associated with data is 1970, the principal exceptions being
paper and allied products and transportation equipment numbers which are from 1971.
"h T 2
Includes 72x10 Btu's of petroleum coke used in primary aluminum production.
TABLE 13-14
ENERGY INTENSIVENESS OF MAJOR INDUSTRIAL GROUPS
sica
32
29
28
26
33
Industrial Group
Stone, clay, and glass products
Petroleum and coal products
Chemicals and allied products
Paper and allied products
Primary metal industry
Energy b
Intens ivene s s
.090
.072
.066
.063
.052
Source: Braddock, Dunn and McDonald, 1974a: 111-12 (data from
Annual Survey of Manufacturers, 1973X.
aStandard Industrial Classification
bTotal energy consumed for each dollar of production goods shipped
out.
13-24
-------
scrap for casting, and other miscellaneous
process power and steam generation uses.
Additional energy is consumed in the pro-
duction of secondary aluminum from aluminum
scrap and the processing of wrought alumi-
num (e.g., rolling and extruding).
13.3.1.2 Chemicals and Allied Products
Chemicals and allied products have
recently surpassed primary metals as the
number one energy consumer in industry.
This group designates the manufacture
of basic, intermediate, and end chemicals,
including drugs and Pharmaceuticals. About
43 percent of the largest industrial corpo-
rations in this country participate in
some aspect of the manufacture and sale of
chemicals. The chemical industry's role
has been referred to as that of a "middle-
man;" that is, "...a purchaser of raw ma-
terials and services from numerous supply-
ing industries and a provider of higher
value products to a host of consuming in-
dustries" (SRI, 1972: 115). Historically,
the raw material bases for this group have
been coal and coal tar. However, over the
past 25 years, coal has been increasingly
replaced by petroleum and natural gas as
the petrochemical industry has grown.
The petrochemical industry involves
the processing of liquids extracted from
natural gas or specific products derived
from crude oil refining to yield chemical
raw materials. Further processing results
in a wide range of end use products, in-
cluding paints, synthetic rubber, uphol-
stery materials, clothing textiles, house-
hold goods, building materials, numerous
molded and extruded plastic products, and
parts for automobiles and industrial equip-
ment.
In 1972, petrochemicals accounted for
30 percent of the tonnage and more than 60
percent of the value of all organic chem-
icals produced in the U.S. (SRI, 1972:
115.116). Until recently, the petrochem-
ical industry has been able to use plen-
tiful, low-cost natural gas liquids as its
primary feedstock. However, the rising •
costs and shortages of petroleum and natu-
ral gas may require changes in the kinds
of raw materials used by this industry
(Shell, 1973a: 11).
Any attempt to analyze the energy con-
sumption patterns within the chemical in-
dustries is complicated because there are
hundreds of chemical products, many of
these products are produced by more than
one process, and different processes use
different amounts of energy.
13.3.1.3 Paper and Allied Products
Energy in the paper manufacturing pro-
cess is typically consumed in two forms,
steam and electric power. The electricity
is essentially used for mechanical drives.
Insignificant amounts of steam may be used
for mechanical drives but for the most part,
steam is used for heat. Consumption in
different mills can vary significantly de-
pending on the pulping process, mill equip-
ment, raw materials, product mix, and out-
side humidity and temperature. In general,
final energy use in this industrial group
is estimated at 90 percent for heat and 10
percent for mechanical drive (SRI, 1972:
132) .
13.3.1.4 Stone, Clay, Glass, and Concrete
Due to the nature of the raw materials
and the required processes, the principal
uses of energy in cement manufacture are
for mechanical operations (in the form of
electric drives) such as crushing, grinding,
conveying, and blending, and for direct-
fired heating operations to achieve chem-
ical changes. Energy consumption in glass
and clay manufacturing is divided between
electrical energy for mechanical devices
(e.g., blowers, conveyors, and materials
handling equipment) and direct process heat
in the firing of kilns. The fuel energy
required for these products depends on the
material being fired, the type of product.
13-25
-------
and the required formation process, as well
as the type of kiln used.
13.3.1.5 Food Processing
The Food and Kindred Products indus-
trial group consists of manufacturers of
foods and beverages for human consumption,
including certain related products such as
manufactured ice, vegetable and animal fats
and oils, and prepared feeds for animals
and fowl. Although demand for food prod-
ucts has steadily increased during the re-
cent past, the industry's relative share
of total energy consumption has been de-
clining. This decline is attributed gen-
erally to greater efficiency in operation;
that is, closing of inefficient plants,
modernization and introduction of more ef-
ficient processing systems, and consolida-
tion (SRI, 1972: 138, C-3).
13.3.1.6 Transportation Equipment
The transportation equipment group in-
cludes those industries involved in manu-
facturing equipment for transport of passen-
gers and freight by land, air, and water.
The predominant concern here is for manu-
facturers of motor vehicles (i.e., passenger
cars, trucks, truck tractors, chassis, and
buses as new units) and motor vehicle parts.
13.3.2 Energy Efficiencies
The" average heat transfer efficiency
of individual industrial plant equipment
items used in the direct heat operations
discussed above (e.g., cement kilns, glass
furnaces, and similar equipment) ranges
from 20 to 30 percent (Berg, 1974: 16).
Heat treating furnaces also operate at
approximately 30-percent heat transfer ef-
ficiency (Berg, 1973b). The overall effi-
ciency of some plant systems (e.g., paper
mills, glass factories, and heat treating
facilities) has been reported to be even
lower than the efficiencies of the individ-
ual devices, which are sometimes as low as
five percent (Berg, 1974: 16). This lower
overall efficiency of thermal processing
plants results in part from poor system
control and ineffective heat transfer and
mixing; that is, plants are not normally
operated to make optimal use of energy
(Senate Interior Committee 1973a: 588).
The relatively primitive technologies
employed to generate process steam in indus-
try generally make inefficient use of the
potential energy in fuels. One source es-
timates the efficiencies of different fuels
for process steam production as follows:
coal, 70 percent; gas, 64 percent; and
oil, 68 percent (SRI, 1972: 155).
To meet its electricity needs, indus-
try either purchases electricity from a
central station power plant or generates
the electricity on site. If electricity is
produced alone, about 30 to 40 percent of
the fuel used is converted to electricity.
However, if electricity is combined with
process steam production, an optimum 80
percent of the potential energy in the fuel
can be used to produce both steam and elec-
tricity (Ford Foundation, 1974a: 67, 462).
Although efficiency can vary to some degree
in the industrial use of electricity for
the direct drive of machinery and equipment,
a reasonable average is reported to be 90
percent (SRI, 1972: 155) .
In general, the efficiency of electro-
lytic processes is much lower than might be
expected in an electrical process. The ef-
ficiency depends to a large extent on the
material being reduced, and losses occur in
the circuitry, electrodes, heating and heat
loss of the containers, consumption of elec-
trodes, and chemical reactions to contam-
inants (SRI, 1972: 155,156). For example,
in the conversion of alumina to aluminum,
the theoretical energy used for that con-
version is 35 to 40 percent of the elec-
trical power input and 10 to 15 percent of
the energy in the fuel consumed to generate
the electricity (SRI, 1972: 156).
13-26
-------
13.3.3 Environmental Considerations
Table 13-15 contains environmental re-
siduals that have been quantified for the
six industrial groups. The data are con-
sidered poor, with a probable error of less
than 100 percent. Each industry has been
broken into subparts, which essentially
correspond to a specific end use (e.g.,
paper and allied products is broken into
pulp and paper mills, and paper products
manufacturing). Although the source study
(Hittman, 1974: Vol. I: Table 29) does in-
clude a breakdown of the end use for each
industry by the fuels consumed, the avail-
able data on industrial environmental im-
pacts did not justify an attempt at dis-
aggregating the level of the data presented.
Thus, contrary to other end use tables in
this chapter, the environmental impacts are
not allocated to each fuel. Instead, im-
pacts are reported for end uses within the
particular industrial group. As a result,
the environmental usefulness of the resid-
uals data is limited because impacts cannot
be allocated to specific fuels except in a
very approximate manner. Also, the impact
data are uncontrolled in that the level of
control is representative of very recent
or current practices.
Industrial facilities generate a range
of air pollutants specific to the process
involved. The significant pollutants are
particulates, SO, and NO . Industry is
the leading producer of particulates and
ranks second in the production of SO (ACS,
1969: 59). In some cases, other pollutants
deserve attention (e.g., CO from integrated
steel mills). The major contributors of
the pollutants cited above are chemical
plants, iron and steel mills, refineries,
pulp and paper mills, and nonferrous metal
smelters.
Manufacturing is also one of the lead-
ing sources of controllable man-made water
pollutants in this country. The industrial
use of water has increased rapidly over the
last two decades and is expected before
long to surpass water use for either irri-
gation or municipal and rural nonirrigation
purposes. In 1970, industrial water usage
(excluding water used for steam-electric
power generation) was estimated at 103
billion gallons per day (gpd), compared to
46 billion gpd in 1950 (Commerce, 1956: 41).
Water is used in industries as a raw
material, as a bouyant transporting medium,
as a cleansing agent, as a coolant, and as a
source of steam in heating and power genera-
tion. Since both water quality and quantity
requirements vary considerably with indus-
trial use, it is impossible to describe the
impact of water use for each of the differ-
ent industrial purposes.* The general types
of industrial water pollutants identified
for the six industrial groups are shown in
Table 13-15.
Many industries discharge process wa-
ters containing compounds not found in nat-
ural waters. For example, among the most
significant are metal ions (mostly toxic),
a spectrum of organic and inorganic chem-
icals, and many refractory compounds which
resist biological degradation. Industrial
waste streams with high temperature, tur-
bidity, color, acidity, or alkalinity are
also common (Commerce, 1956: 40). Some 66
percent (average value) of industrial water
use is for cooling purposes; about half of
this water is lost to the atmosphere and
the remainder returns to the resource pool
with its salt concentration doubled.
Examples of wastewaters that contain
significant amounts of mineral impurities
are steel-pickling liquors, copper-bearing
wastes, electroplating wastes, and gas and
coke plant wastes. The most important or-
ganic wastes are produced by the meat and
*For a discussion of input water qual-
ity requirements which have been quantified
for various industries, see McKee and Wolf
(1963: 92-106). References estimating the
quantity of water used per unit of product
for many industries are cited in the above
source and in McGauhey (1968: 44,45).
13-27
-------
Table 13-15. Residuals for Industrial Energy Use
_„ ,, Paper and Allied
sic, ^6: products
Pulp and Paper Mills
Paper Products
Manufactured
SIC 37- TranaP°rtation
Eouiranent
Motor Vehicles
Parts
Stone, Clay, Glass
SIC 32: and concrete
Glass Products
Clay Products
Cement and Related
Stone and Related
SIC 28: Chemicals
Inorganic
Organic
„ „ ,- Food and Kindred
SIC 20: products
Meat and Dairy Products
Bakery, Sugar, and
Confectionary
Water Pol
Acids
a
0
U
u
u
u
u
u
1.72
xlO-2
.02
0
0
Bases
a
0
U
u
• u
u
1.57
xicr5
u
4.64
xlO-2
U
u
5.57
xlO-3
B*"
u
0
u
u
3.2
xlO-4
0
0
0
9.84
xicr3
5.08
XlO-3
8.
xKT6
2.5
xlO-3
m
8
u
0
u
u
0
0
0
0
u
u
8.75
xlO~7
4.35
xlO-3
utants (Tons/measured
Total Dissolved
Solids
8.7fe
xlO-2
0
U
U
2.31
xlO-2
U
7.06
xlO-Sj
2.09
xlO-2
.106
2.51
xlO-2
4.14
xlO~*
.252
Suspended
Solids
2.25
xlO-2
0
1.83
xlO-4
2.35
xlO-4
1.36
xlO"3
U
2.81
xlO-5
3.41
xlO-4
.446
1.94
xlO-5
5.69
XlO-4
.595
Organics
U
0
S.22
XlO-5
6.56
xlO-5
1.25
xlO"3
U
U
U
2.17
x!0~4
.023
1.89
Xl0~4
U
2.46'
xlO-2
0
1.28
xlO"4
1.78
XlO-5
xio-3
U
6.5
xlO~7
3.62
xlO~4
6.21
xlO~6
1.96
XlO-5
4.66
xlO-3
3.2
xlO-3
8
U
4.17
xio-2
0
3.53
x!0~4
U
U
U
1.2
xlO~7
1.85
xlO~4
2.42
xlO-5
5.1
xlO-5
4.5
XlO-3
.223
Thermal {Btu ' s/
measure)
U
U
U
u
u
u
u
u
u
u
u
IT
Air Pollutants
Particulates
4.53
xlO-2
1.63.
xl
-------
Table 13-15. (Continued)
End Use
Beverage, Can, Cured,
and Frozen
Grain Mill and
Mi e;cellaneous
SIC 33: Primary Metals
Iron and Steel Making
Iron and Steel Castings
Primary Aluminum
Primary Copper
Primary Zinc
Water Pollutants (Tons/measure)
Acids
U
U
U
u
u
u
u
Bases
2.64
xlO-4
U
U
U
U
U
u
•*
s
1.47
xlO~-
U
U
0
0
U
u
f>
g
5.97
xlO-5
U
U
0
0
0
U
Total Dissolved
Solids
8.12
xlO-2
U
U
U
U
U
U
Suspended
Solids
7.42
xlO-4
U
1.21
xlO-3
1.37
xlO-2
.005
1.74
.XlO-2
•U
Organics
2.44
xlO~4
U
4. 5
xlO-4
U
xio-3
U
U
q
O
«
3.16
xlO-2
U
U
3.69
XlO-3
1.62
xlO-4
U
U
1
3.28
xlO-2
U
U
2.29
xlO-2
1.37
xlO-2
2.18
XlO-3
U
Thermal (Btu's/
measure)
U
U
c
U
U
u
u
Air Pollutants (Tons/measure)
Particulates
5.54
xlO~3
2.42
xlO-2
1.02
xlO-2
3.95
xlO-4
.126
2.02
XlO-4
.01
X
3.42
x!0~4
1.48
x!0~4
4. 54
xlO-2
3.74
x!0~6
t>
U
U
X
o
in
1.98
xlO~3
6.47
xlO-4
4.63
XlO-4
e
b
6.25
XlO-2
2.02
xlO-2
Hydrocarbons
4.91
xlO-5
1.17
xlO-5
0
e
b
U
U
O
U
3.16
xlO-5
1.03
xlO-5
8.64
xlO-3
4.5
xlO-3
b
U
U
Aldehydes
8.47
xlO~6
5.52
XlO~4
0
e
2.12
xlO-2
U
U
Solids
(tons/measure)
.825
U
d
U
U
U
u
Measure
Ton
Ton
Ton
Ton
Ton
Ton
Ton
Energy
Btu/measure
4.48
xlQ6
9.45
X105
2.23
xlO?
1.31
xlo7
1.96
xlo8
4.43
x!07
7.25
xlO7
Multiplier
4.93
xlO7
3.17
X108
1.33
x!08
1.88
xlO7
3.96
xlflS
1.77
x!06
9.55
xlO5
Multiplier year
1970
1970
L972
1969
1970
1970
1970
U = unknown.
aPh values of wastewaters are reported to range from 3.4 to 12.0.
Considered small or negligible.
cBecause of many outfalls for each steel mill, average temperature rise is not available.
dSlag produced in the blast furnace process is readily salable as a general rule and is not considered a solid waste.
Hydrocarbon, SOx, aldehydes and metallics are emitted but are highly variable.
-------
dairy products industries, breweries and
distilleries, and canneries. The biologi-
cal wastes from industry are particularly
significant because of the exceptionally
high biochemical oxygen demand (BOD) of
many such discharges. Examples of wastes
containing both organic and mineral impuri-
ties are those of the paper mills.
13.3.4 Economic Considerations
In industries, such as chemical refin-
ing, where the function of the industry is
to convert the energy content of fuel to
some readily marketable form, the design of
large plants is based on an optimal consid-
eration of initial costs and operating
costs, especially fuel costs (Berg, 1973a:
556) . In the past, other industries con-
structed plants that minimized total costs,
not clearly emphasizing the role of energy
as an essential ingredient. As long as
energy was plentiful and inexpensive rela-
tive to other components of production cost
(energy has accounted for only five percent
of value added on the average [ Ford Foun-
dation, 1974a: 63]), investment in more en-
ergy-efficient equipment and processes was
not of major concern. Despite the advan-
tage of having competent engineering staffs
capable of understanding and analyzing all
the costs of owning equipment, industry
often buys inefficient devices because it
desires a "quick payout" (two to five years)
on its initial expenditures (OEP, 1972:
E-16). This practice of seeking quick re-
covery of capital expenditures often re-
sults in low-cost plants that are large
energy consumers. Of course, not all in-
dustrial concerns take this attitude but,
in some cases, industry has found that be-
cause energy was inexpensive, "it has been
cheaper to permit a leak of energy than to
modify or replace inefficient equipment"
(Berg, 1973a: 556). As energy costs rise,
industry may find the trade-offs favor more
efficient energy utilization; that is, re-
duced fuel consumption.
Due to the extreme diversity among
industries, it is not possible to general-
ize about economic considerations for spe-
cific industrial groups. In almost every
case, however, investment in more efficient
equipment, coupled with the introduction of
more efficient processes, should reduce fuel
consumption. Further, price'is not the only
influencing factor. In some parts of the
country, gas suppliers have placed fuel
quotas on industries that may not be ex-
ceeded. Industries affected by such mea-
sures are already seeking to improve their
plant efficiencies (Berg, 1973a: 556).
13.3.5 Conservation Measures for the
Industrial Sector
The following discussion of conserva-
tion measures is organized around energy
use in generic manufacturing processes rath-
er than around the specific industrial
groups or end uses. This approach reflects
the manner in which industrial conservation
proposals most often appear in the litera-
ture . Such a focus reflects the complexity
and diversity of the industrial sector. As
a result, conservation discussions have fo-
cused more generally on energy uses and
practices common to more than one industry.
The conservation study by the OEP re-
ported that, with the exception of the pri-
mary metals group, all the energy intensive
industries could cut energy demand by 10 to
15 percent (and probably more) over a period
of time by accelerated retirement of old
equipment, optimal energy process design,
and upgraded and increased adjustment and
maintenance of existing equipment {OEP,
1972: E-14). OEP outlined the following
recommendations, including possible sector
savings corresponding to different time
parameters (OEP, 1972: 56,57):
1. Short-Term Measures (1972-1975).
Increase energy price to encourage
improvement of processes and re-
placement of inefficient equipment.
Provide tax incentives to encourage
recycling and reusing of component
materials. Savings: 1,900 to
3,500xl012 Btu's per year (6 to 11
percent).
13-30
-------
2. Mid-Term Measures (1976-1980).
Establish energy use tax to pro-
vide incentive to upgrade pro-
cesses and replace inefficient
equipment. Promote research for
more efficient technologies. Pro-
vide tax incentives to encourage
recycling and reusing component
materials. Savings: 4,500 to
6,400xl012 Btu's per year (12 to
17 percent).
3. Long-Term Measures (beyond 1980).
Establish energy use tax to pro-
vide incentive for upgrading pro-
cesses and replacing inefficient
equipment. Promote research in
efficient technologies. Provide
tax incentives to encourage re-
cycling and reusing component
materials. Savings: 9,000 to
12,000xl012 Btu's per year (15 to
20 percent).
As indicated in the preceding discus-
sion, energy consumption in this sector
could be reduced through changes in the pro-
cesses for the manufacture of products. The
responsibility for such changes lies almost
entirely within the various individual in-
dustrial groups. In addition, process re-
search is almost always proprietary.
13.3.5.1 Industrial Thermal Processes
As indicated in the technological de-
scription, the overall efficiency of ther-
mal processing plants is not high. Approx-
imately 30 percent of the energy used in
industrial processes could be saved by ap-
plying existing conservation techniques
that are economically justifiable given
present fuel prices (Berg, 1973a: 556).
Certain examples of improved equipment that
would more effectively utilize energy de-
serve attention.
Gas-fired vacuum furnaces have recently
been developed for industry, and one source
reports that under ideal circumstances such
furnaces, used in conjunction with well-
designed vacuum insulation and modern heat
transfer and combustion techniques, could
operate with 25 percent of the total fuel
consumption of previous vacuum furnaces
(Berg, 1973a: 556).
The effectiveness of industrial fuel
utilization could also be improved through
the application of fluidized-bed processing
to cement kilns and similar apparatus.*
Estimates indicate that recent advances in
fluidized-bed equipment design may increase
the heat transfer efficiency from present
levels to about 50 percent. Also, the re-
action completion time in the kiln may be
significantly reduced, resulting in improved
productivity in, for example, cement making
(AEG, 1974: Vol. IV, p. C.6-11).
Another device that offers the prospect
of reduced fuel demand is the heat pipe.
This device allows rapid and highly control-
lable heat transfer over long distances with
minimal drop in temperature. Heat pipes
can be used as heat sources for vacuum fur-
naces, and indications are favorable for
their application to glass furnaces. They
can also be used to extract heat from stack
gases, thus recovering heat that would
otherwise be wasted (AEG, 1974: Vol. IV,
p. C.6-11).
13.3.5.2 Process Steam Generation
One technological option offering po-
tential energy savings is combined electric
power/steam generation systems (also dis-
cussed in Chapter 12). In combined systems,
approximately 80 percent of the fuel energy
is converted to steam and electricity; when
electricity alone is produced, only 30 to
40 percent of the fuel is converted to elec-
tricity. The savings result because the
electricity generated in combined systems
can displace electricity that would other-
wise be generated inefficiently. The net
savings in total energy requirements for
steam and electricity can be about 30 per-
cent (Ford Foundation, 1974a: 67).
13.3.5.3 Increased Efficiency of Industrial
Processes
More efficient management of systems
and improved efficiency of industrial pro-
cesses (e.g., petroleum refining, chemical
A discussion on fluidized-bed boiler
systems is given in Chapter 12.
13-31
-------
processing, and metal manufacturing) can
produce substantial energy savings. For
example, the Shell Oil Company has made
substantial progress toward a goal of re-
ducing energy consumption in its refineries
by 10 percent over a two- to four-year pe-
riod (amounting to 3.5 to 4 million barrels
[bbl] of fuel oil per year) (Shell, 1973b:
15)- The DuPont and Dow chemical companies
suggest that savings of 10 to 15 percent on
fuel are possible in almost every chemical
complex (Shell, 1973b: 15) . A process de-
veloped to reduce water requirements four-
fold in the paper industry also cuts energy
requirements in half. In the aluminum in-
dustry, a new Alcoa electrolytic "chloride"
process, called the Alcoa Smelting Process,
has been estimated to reduce energy needs
for primary aluminum production by 30 per-
cent (Senate Interior Committee, 1973a:
661). Presumably, the successes of these
programs do not represent isolated examples
of possible industrial savings through pro-
cess changes.
13.3.5.4 Heat Recuperation
Better waste heat management can be
expected to yield industrial energy savings.
A substantial fraction of the process heat
requirements (other than steam) is present-
ly lost to exhaust gases or to materials in
process. Few chemical or mechanical pro-
cesses can utilize very low-grade heat;
however, the use of heat recuperators or re-
generators that return some of this other-
wise wasted energy to various processing
steps could reduce fuel consumption by 20
to 25 percent (Ford Foundation, 1974a: 67).
There are applications for process
steam extracted at higher temperatures that
use waste heat. For example, the Dow
Chemical Company will make use of steam ex-
tracted from a nuclear power plant under
construction in Midland, Michigan for the
production of chemicals (Battelle. 1973:
620). Also, combustion air could be pre-
heated with exhaust gases. One source in-
dicated that the use of such devices is
economically feasible, even for backfitting
plants already in existence (Ford Founda-
tion, 1974a: 67). At present, however,
there are few examples of clear financial
incentives for exploitation of this possible
conservation measure.
13.3.5.5 Recycling and Reusing
One area where clear financial incen-
tives exist for energy conservation is in
the reuse and recycling of materials, es-
pecially primary metals and paper. Recycled
aluminum requires only two to five percent
of the energy required for the production
of primary aluminum (Senate Interior Com-
mittee, 1973a: 656). An exception is re-
cycled glass, which requires about as much
energy to recycle as glass produced from
virgin raw materials (sand). However, the
reuse of glass containers is only one-fifth
as energy intensive as using disposable
glass containers (Senate Interior Committee,
1973b: 141). Thus, energy could be con-
served by designing equipment to facilitate
recycling or by reusing component parts and
materials; that is, standardizing product
components to encourage reuse.
Most of the recycle-reuse measures
are currently economical. One study re-
ported (Hannon, 1972: E-18) that, in the
container industry, the total resource sys-
tem energy use is significantly higher for
the throwaway system. In fact, dollar costs
for the soft drink glass throwaway container
system were about twice as expensive as the
returnable system.
Another area that has received con-
siderable attention for recycling potential
is the auto industry (cf. OEP, 1972: E-18,
E-19). If cars were properly designed for
recycling, a substantial amount of metal
and other materials could be recovered from
junked automobiles.
There are numerous measures, besides
the savings opportunities discussed here,
that can be implemented over the short-term
requiring little, if any, capital invest-
ment. "Leak plugging" tactics that would
13-32
-------
improve present practices can result in en-
ergy savings generally in the range of 10
to 15 percent in the short-term (Ford Foun-
dation, 1974a: 68). In all cases, an anal-
ysis of energy use should enhance the pos-
sibility of implementing, where practical,
conservation measures in the industrial
sector.
13.4 TRANSPORTATION SECTOR
The transportation sector accounts for
a significant percentage of total U.S. en-
*
ergy consumption, averaging about 24 per-
cent since 1950. Thus, like total energy
consumption, U.S. transportation energy re-
quirements almost doubled from 1950 to 1970
(i.e., from 8,724xl012 Btu's in 1950
[Hirst, 1972: 3] to 15,843xl012 Btu's in
**
1970). Most of this increase was in the
form of petroleum products used in cars,
trucks, and aircraft. In fact, transporta-
tion currently accounts for more than half
of the total U.S. petroleum use and con-
tinues to increase its share (SRI, 1972:
B-8). Table 13-16 shows a breakdown by
fuel type of the gross consumption of en-
ergy in this sector.
The following discussion is organized
around two general transportation catego-
ries, freight and passenger. Two other
***
categories, feedstocks and military and
government, were identified by Hittman and
will be included in this description only
in terms of their environmental residuals.
Energy consumption for each category is
shown in Table 13-17.
TABLE 13-16
FUEL SOURCES FOR TRANSPORTATION, 197Oa
Fuel Type
Gasoline
Distillate
Residual
Jet fuel
Electricity
Feedstocks
(lubricants)
TOTAL
1012 Btu's
per year
11,522
1,613
455
2,059
41
153
15,843
Percent of
Total
72.6
10.2
2.9
13.0
0.3
1.0
100.0
Source; Calculated from Hittman, 1974:
Vol. I, Table 30.
a!2-month period during 1970-1971.
TABLE 13-17
CATEGORIES OF TRANSPORTATION USE
Category
Freight
Passenger
Feedstocks
Military and
government
1012 Btu's
4,822
10,167
153
701
Percentage
of Total
30.4
64.2
1.0
4.4
Source: Hittman, 1974: Vol. I, Table 30.
a!2-month period during 1970-1971.
This description does not deal with
the energy required to build transportation
systems, only with the energy used to oper-
ate them.
**
Year associated with 1970 estimate is
actually a 12-month period during 1970/1971
as reported by Hittman (1974: Vol. I, Table
30). BuMines data, which includes military
fuel, give a total of 17,080x1012 Btu's for
1971 and 16,490xl012 Btu's for 1970.
***
Feedstocks are automotive and avia-
tion lubricants.
Table 13-18 shows the transportation
end use distribution in 1970. Automobiles
were the leading consumer, using more than
52 percent of the overall transportation
energy. Trucks were second, consuming ap-
proximately 22 percent. The percentage of
energy used by domestic commercial aircraft
increased substantially, from 4.1 percent
in 1960 (Hirst, 1972: 27) to 7.3 percent in
1970 (Hittman, 1974: Vol. I, Table 30).
13-33
-------
TABLE 13-18
END USE OF ENERGY WITHIN THE TRANSPORTATION SECTOR, 1970*
Use
Automobiles
Urban
Intercity
Aircraft (domestic/international)
Freight
Passenger
Railroads
Freight
Passenger (including urban
rapid transit)
Trucks (freight)
Ships and Barges (freight)
Buses
Urban
Intercity
Military/Government
Aircraft
Ground vehicles
Ships
Feedstocks (lubricants)
Otherb
OVERALL TOTAL
Percent of Total
Transportation Energy
32.5
19.8
1.1
8.8
3.3
0.4
0.5
0.4
3.8
0.3
0.4
Total
52.3
9.9
3.7
21.8
4.1
0.9
4.5
1.0
1.8
100.0
Source: Calculated from Hittman, 1974: Vol. I, Table 30.
12-month period during 1970-1971.
Includes passenger traffic by motorcycle, and recreational boating.
During that same period, the railroads'
percentage of total energy usage declined.
Increasing consumption in the trans-
portation sector is due primarily to growth
in traffic levels, shifts to less energy-
efficient modes, and declines in energy
efficiency for individual modes of trans-
portation (Hirst and Moyers, 1973a: 1299).
Growth projections suggest that pressure
on fossil fuel resources will continue from
this sector (OEP, 1972: 14).
13.4.1 Freight
13.4.1.1 Technologies
Primary transport for freight includes
waterways (barges, ships), trucks, rail-
roads, and domestic and international jet
airplanes. (For a discussion of pipelines
see Chapter 3). Table 13-19 shows that a
shift has occurred in intercity freight
transport usage over the past 20 years.
Railroads now haul a smaller percentage
13-34
-------
TABLE 13-19
METHODS OF INTER-CITY FREIGHT TRAFFIC
Year
1950
1955
1960
1965
1970
Ton-Miles
Freight
•(109)
1,090
1,300
1,330
1,650
1,930
Percentage of Total Ton-Miles
Railroads
57.4
50.4
44.7
43.7
40.1
Trucks
15.8
17.2
21.5
21.8
21.4
Waterways
14.9
16.7
16.6
15.9
15.9
Pipelines
11.8
15.7
17.2
18.6
22.4
Airways
0.03
0.04
0.06
0.12
0.18
Source: Hirst, 1972: 6 (data from Statistical Abstract. 1970, and from Transpor-
tation Facts and Trends, 1971).
of total ton-miles, while all other trans-
portation methods carry a larger share.
Although air freight remains relatively
small (0.18 percent), it did steadily in-
crease its percentage share of total ton-
miles during 1950 to 1970.
13.4.1.1.1 Ships
Over the last few years ship usage has
shown a slight increase and is expected to
continue growing at a slow rate (Szego,
1971: Vol. II, Part B, pp. N-10, N-26).
In the recent past, the fuel supply for
ships has switched from coal to residual
oil. For freight movement, domestic water-
borne traffic is composed primarily of
barges pushed by diesel-powered towboats.
13.4.1.1.2 Trucks
Trucks are large users of gasoline and
diesel fuel. Because they are not substan-
tially limited in the kinds of materials
they can move, and due to the flexibility
of their pickup and delivery points, trucks
have considerably increased their share of
the freight market. Approximately 95 per-
cent of truck ton-mileage is concentrated
in hauls greater than 100 miles, and 35
percent is for hauls more than 200 miles
(Ford Foundation, 1973: Chapter XII, p. 31)
13.4.1.1.3 Railroads
Railroad energy consumption for
freight transport has continually declined
over the last 20 years, from 57.4 percent
of total ton-miles in 1950 to 40.1 percent
in 1970. This reduction is the result of
a change in fuels used and more efficient
engines. During 1950 to 1970, most rail-
road locomotives were changed from coal to
residual fuel oil (steam engines) and then
were replaced by distillate-burning diesel-
electric engines. Since the diesel-electric
engines are more efficient, more freight
was moved with less energy consumption.
Yet, as noted in Table 13-19, freight ship-
ment by rail has declined even as the en-
ergy efficiency of railroads has increased.
This trend is explained in part by
the increase in freight shipment by trucks.
The attractiveness of trucks over railroads
apparently reflects differential regulation
of the two industries, as well as better
and more dependable service by trucks.
Customer preference is illustrated by the
fact that approximately 40 percent of all
freight tonnage in 1967 could have been
moved by either truck or rail, yet trucks
hauled over 80 percent of this "competi-
tive" cargo (Ford Foundation, 1974a: 60).
13-35
-------
13.4.1.1.4 Airplanes
Air transportation energy demand is
increasing at a rapid rate, yet is still a
small percentage of total freight traffic.
Between 1965 and 1970, air freight experi-
enced an average annual growth rate of 13
percent (DOT, 1972: 1031). If this growth
rate continues, air cargo demand will dou-
ble about every six years, resulting in
increased (although not necessarily corre-
sponding) energy demand. This implies
that air freight transportation, though in-
significant over the last two decades,
could eventually become a primary energy
consuming end use.
The predicted exponential growth in
air freight is due largely to such factors
as speed, convenience, and kinds of mate-
rials shipped. Air cargo falls into three
categories: emergency (unplanned); routine
perishable (planned); and routine surface
divertible (planned) (NASA/ASEE, 1973: 77).
As energy becomes more expensive, the lat-
ter category might experience a significant
diversion to other modes, lowering the ex-
pected overall growth rate of air freight.
13.4.1.2 Energy Efficiencies
Fuel consumption through the use of a
particular mode of transport is directly
proportional to the energy intensiveness of
that mode. Energy intensiveness is defined
as the amount of energy required to move
one unit (one passenger or one ton of cargo)
a distance of one mile. The measure is ex-
pressed in Btu's per passenger-mile or Btu's
per ton-mile.
Table 13-20 shows energy intensiveness
for the movement of freight by various
transport modes. The energy data is consid-
ered good, with a probable error of less
than 25 percent. Pipelines and waterways
represent a very efficient means of freight
transport; however, they are limited in the
kinds of materials they can carry and in
the flexibility of their pick-up and deliv-
ery points. Railroads are more than four
TABIiE 13-20
ENERGY INTENSIVENESS OF FREIGHT TRAFFIC
Mode
Aircraft
Trucks
Waterway
Rail
Pipeline
Btu ' s per Ton-Mile
42,000
2,800
680
670
450
Source: Hirst and Moyers, 1973a:
1300.
Assuming 136,000 Btu's per gallon.
times as efficient as large trucks (diesel
trucks are more efficient than gasoline-
powered trucks) and almost 63 times as
efficient as air transportation. Generally,
in freight transportation, increased fuel
consumption pays for speed, flexibility,
and scheduling.
13.4.1.3 Environmental Considerations
The environmental residuals quantified
for freight transportation are given in
Table 13-21. The measure of use for all
freight modes is the ton-mile. As in the
residential and commercial sector, all end
use impact data correspond to a particular
fuel. A quick review of Table 13-21 shows
that the primary environmental residuals
from transportation are air emissions;
these data are considered fair, with a
probable error of less than 50 percent.
Environmental consequences, such as solid
and liquid wastes, are not quantified due
to insufficient data, incomplete knowledge
of effects and consequences, and the wide
variability of liquid and solid by-product
discharges.
As in the other tables, the not appli-
cable designation (NA) means either that
any environmental impacts which may occur
are not energy related or that no rational
13-36
-------
Table 13-21. Residuals for Freight Transportation Energy Use
End Use/Fuel
FREIGHT TRANSPORTATION
Barge/Distillate
Ship-Foreign Trade/
Residual
Truck/Distillate
Truck/Gasoline
Rail/Distillate
Airolane-Domestic/Jet
Airplane-International/
Jet
Water Pollutants (Tons/measure)
Acids
MA
NA
NA
NA
NA'
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
0*
0.
NA
NA
NA
NA
NA
NA
NA
m
O
-------
technique exists to distinguish what por-
tion of the total impact is energy related.
For example, no effort is made to relate
auto accident deaths to energy use (Hittman,
1974: Vol. I, p. 11-18).
The U.S. Office of Science and Tech-
nology (OST) reported that, in 1969, motor
vehicles accounted for almost half the na-
tion's total air pollution by weight (OST,
1972). Pollutants of particular signifi-
cance in vehicle use are NO , hydrocarbons,
and CO. Since the establishment of Environ-
mental Protection Agency (EPA) standards,
government and industry have been investi-
gating a number of techniques by which
these pollutants can be kept below levels
required by the standards. Of the three
pollutants, NOx (formed by the nitrogen-
oxygen reaction at high combustion tempera-
tures) is the more difficult to control.
Modifications to control emissions may take
several forms such as the current use of
catalytic beds (the new "mufflers") which
convert the uriburned hydrocarbons and CO
contaminants to water and CO2, acceptable
effluent products (Hittman, 1974a: 5).
Proposed solutions to the NOx problem are
based on exhaust gas recirculation, catal-
ysis, changes in compression ratios, and
other methods.
While studies show that emission con-
trol engineering changes have resulted in
reduced emissions, they have also adversely
affected fuel economy. This point is dis-
cussed in more detail in Section 13.4.2.1.1.
13.4.1.4 Economic Considerations
Table 13-22 gives (approximate) average
prices for the movement of inter—city
freight by various methods in 1970. This
table closely resembles the variation in
energy intensiveness (Table 13-20); that is,
the price per ton-mile increases for the
less efficient modes, reflecting their
greater speed, flexibility, and reliability.
For example, the truck is four times less
efficient than the railroad, and costs 5.35
times more. Consequently, there is no great
TABLE 13-22
INTER-CITY FREIGHT
TRANSPORTATION PRICE DATA (1970)
Mode
Pipeline
Railroad
Waterway
Truck
Airplane
Price (cents per ton-mile)
0.27
1.4
0.30
7.5
21.9
Source: Hirst and Moyers, 1973a: 1300.
difference between relative economic and
energy costs. In general, the public has
been willing to pay higher operating costs
in return for greater convenience.
13.4.2 Passenger Travel
13.4.2.1 Technologies
Table 13-23 shows that, over the past
20 years, the automobile traffic share of
total inter-city passenger-miles has re-
mained relatively constant, accounting for
86.8 percent of the total in 1950 and 87.0
percent in 1970. During this period, rail-
roads declined from 6.4 percent to less
than one percent of the total passenger-
miles, while the airplane increased its
share nearly five-fold. In 1970, air
transportation accounted for almost 10 per-
cent of the total inter-city passenger-
miles. These data clearly illustrate the
degree to which the automobile and airplane
presently dominate the inter-city passenger
sector.
The urban passenger sector is domi-
nated by the automobile. As population
growth is increasingly concentrated in the
suburbs, a further demand for automobiles
and roads is created. Much of this urban
travel results from the separation of resi-
dential areas and work places, shopping
13-38
-------
TABLE 13-23
METHODS OF INTER-CITY PASSENGER TRAFFIC
Year
1950
1955
1960
1965
1970
Total
Passenger-Miles
(109)
510
720
780
920
1,180
Percentage of Total Passenger-Miles
Automobile
86.8
89.5
90.1
88.8
87.0
Airplane
2.0
3.2
4.3
6.3
9.7
Bus
5.2
3.6
2.5
2.6
2.1
Railroad
6.4
4.0
2.8
1.9
0.9
Source: Hirst, 1972: 10 (data from Statistical Abstract. 1970, and from
Transportation Facts and Trends, 1971).
centers, and recreational facilities. To
date, public transportation (i.e., buses
and rapid transit modes) has not competed
effectively with growing automobile usage,
even though such transit systems could po-
tentially alleviate congestion and pollu-
tion problems.
13.4.2.1.1 Automobiles
The largest single energy consumer in
the transportation sector is the passenger
car. Automobiles account for more than
half of the total transportation energy
needs. Eight out of 10 American households
presently own at least one car while 3 in
10 have two cars (Washington Center for
Metropolitan studies, 1974). The auto-
mobile's use is related to rising affluence,
suburban development, and shifting employ-
ment patterns. Essentially, the car is
very much a part of the American lifestyle,
reflecting mobility and independence. It
offers distinct advantages over competing
modes of transportation, such as privacy,
speed, personal comfort, and freedom to
choose one's own route of travel. As a
consequence, Americans have tended to ig-
nore many of the energy trade-offs involved
in their transportation decisions.
Presently, most automobiles are heavy,
high-powered, and very inefficient. Cal-
culations for the 1973 average American car
indicate a fuel economy of less than 12
miles per gallon (mpg) (EPA, 1972). This
figure represents about a 20-percent de-
cline from the 1968 nationwide average.
Until recently, the primary reasons for
this declining fuel economy were steady in-
creases in engine displacement, weight, and
average operating speed, in conjunction
with the use of energy consuming accessories
such as air conditioners, power steering,
and automatic transmissions (Hirst and
Herendeen, 1973). Although the recent im-
position of the national 55-miles per hour
(mph) limit has reduced the average speed
and EPA standards have caused some reduc-
tion in engine size, fuel economy has con-
tinued to decline because of lowered engine
efficiencies {higher power-to-weight ratios),
emission control devices, and continued use
of power accessories.
The above factors—combined with low
average car occupancy (one passenger for
urban use, two passengers for average use
[Rice, 1972: 34]), the growing use of cars
for short distance trips, and an increase
in total miles driven (Figure 13-2)—have
13-39
-------
1,200
1,000
W
- 800
_ 600
o
« 400
200
All Motor Vehicles
Pdssenger Cars
I
1940 I960 I960
1970
Figure 13-2. Growth in Vehicle Miles, 1940-1972
Source: The Ford Foundation, 1974: 5
(from Motor Vehicle Manufacturers Association).
-------
not only increased fuel consumption but
contributed significantly to environmental
pollution.
13.4.2.1.2 Buses
Although buses are a highly efficient
method of transportation, both in terms of
energy and cost, they have not been able
to effectively compete with either the auto-
mobile or the airplane. From 1950 through
1970, buses' percentage of the total passen-
ger-miles declined from 5.2 to 2.1 percent.
Demands for mobility, speed, comfort, con-
venience, and reliability have caused buses
to lose customers to other, more energy in-
tensive modes. In addition, traffic con-
gestion has contributed to the buses' rep-
utation as a time consumer. A considerable
amount of current research and development
funds are being expended by the Department
of Transportation (DOT) to make bus trans-
port more attractive to the public and re-
verse the negative growth trend (DOT, 1972:
1031) .
Buses generally fall into three cate-
gories: urban bus, highway (inter-city)
bus, or microbus. The average passenger
loads for these categories are 12, 22, and
7 respectively (Rice, 1972: 34). Urban
buses have recently received more attention
in several large U.S. cities (Los Angeles,
New York City, and Washington, D.C.) where
special lanes have been provided for their
travel, thereby increasing their speed and
reliability. An interesting variant over
the more conventional urban bus is the
"Dial-a-Ride" bus that holds 10 to 20 pas-
sengers, is dispatched in response to a
phone call, and provides door-to-door
service.
13.4.2.1.3 Airplanes
Between 1965 and 1970, passenger air
travel experienced a dramatic average an-
nual growth rate of 14 percent (DOT, 1972:
1031). This is the fastest growing mode
of inter-city passenger travel, increasing
its share of the total passenger-miles from
two percent in 1950 to 9.9 percent in 1970.
Most earlier estimates projected this trend
to continue for some time. Recent estimates
assume the passenger air transportation in-
dustry is maturing while air freight is
only beginning to grow (Ford Foundation,
1974a: 446).
For most Americans, the airplane rep-
resents the fastest method to a given des-
tination, thus is a way to save time. De-
spite other delays (e.g., airport and
ground congestion), the airplane is con-
sidered the standard to be used in judging
all other modes of transportation. In addi-
tion, as the automobile market becomes es-
sentially saturated within the next few
decades, increasing amounts of per capita
real disposable income will probably be
used for common carrier transportation. In
fact, one source attributes part of the in-
crease in air travel to just that influ-
ence—money available to be used in air
rather than automobile travel (DOT, 1972:
1032) .
13.4.2.1.4 Railroads
Between 1965 and 1970, railroads were
rapidly losing their small share of the
inter-city passenger market. During this
five-year period, passenger service dropped
9.3 percent annually (DOT, 1972: 1036). As
a result, railroads were eliminating their
remaining passenger services until recently.
This decline in service is expected to stop,
or at least slow down, because of a federal
commitment to help rail transportation.
Passenger trains use either distillate
fuel or electrical energy. U.S. railroads
are predominately diesel; for example, only
seven of the 20 billion passenger-miles
carried by mass transit in 1970 were handled
by electric-powered systems.
Rapid transit systems operating on
electrical energy are proposed as a method
for substantially reducing the number of
commuters using automobiles. However,
13-41
-------
economic problems associated with these
systems have delayed their implementation.
For example, the San Francisco Bay Area
Rapid Transit (BART) District was founded
in 1958. Construction of the system began
in 1966, and the expected completion date
was 1974. During this period, costs in-
creased from the $700 million original es-
timate to $1.5 billion. On completion,
the system is expected to carry only one
percent of the total surface travel and 10
to 15 percent of the commuters in the bay
area (Shell, 1973a: 9).
13.4.2.2 Energy Efficiencies
Approximate energy requirements for
various passenger modes of inter-city and
urban travel are given in Table 13-24. The
data are considered good, with a probable
error of less than 25 percent. LiXe the
trends reported for freight, passenger
transport has also shifted to more energy
intensive modes. For example, airplanes
are less energy efficient for passenger
movement than autos, which in turn are less
TABLE 13-24
ENERGY INTENSIVENESS OF
INTER-CITY AND URBAN PASSENGER TRAVEL
Mode
Aircraft
Automobile
Railroad
Bus
Automobile
Mass transit
Average
Load Factor
(percent)
50
48
35
45
28
20
Btu's per
Passenger-Mile
INTER-CITY
8,400
3,400
2,900
1,600
URBAN
8,100
3,800
Source: Hirst and Moyers, 1973a: 1300.
efficient than buses and railroads. Since
efficiency rises dramatically as more pas-
sengers are accommodated, the load factor
assumptions in the table are crucial in
determining the most efficient modes. For
example, consider the efficiency of the
automobile in inter-city transportation,
where the load factor is about double that
for urban transportation.
The effective overall thermal efficien-
cy of the average automobile is only 8.3
percent, compared to 22 to 25 percent the-
oretical efficiency of the internal combus-
tion engine. This theoretical to actual
difference is the result of losses due to
engine design, emission controls, aerody-
namic drag, rolling resistance, parasitic
and transmission losses, constraints im-
posed on the driver and vehicle by traffic
conditions such as stop-and-go driving,
and others. (Szego, 1971: Vol. II, Part B,
pp. N-8, K-22). Significant improvements
in automobile efficiencies will probably
require a transition from the present in-
ternal combustion engine to more advanced
engines. (See Section 13.4.4 for an exam-
ple) .
Table 13-21 indicates that, for inter-
city traffic, buses and trains are the most
efficient modes. Cars are less than half
as energy efficient as buses but more than
twice as efficient as airplanes.
Urban efficiencies are lower than those
for inter-city travel due to lower average
miles per gallon and fewer passengers per
vehicle (load factor). Mass transit sys-
tems—60 percent are bus systems—are more
than twice as efficient as cars for urban
travel.
13.4.2.3 Environmental Considerations
Table 13-25 contains the environmental
residuals that have been quantified for
passenger transportation. The data are con-
sidered fair, with a probable error of less
than 50 percent. The pollutants of signi-
ficance are air emissions. The automobile
13-42
-------
Table 13-25. Residuals for Passenger Transportation Energy Use
End Use/Fuel
PASSENGER TRANS PORTATION
Auto-Intercitv/Gasoline
Auto-Urban/Gasoline
Bus-Intercity/Distillate
Bus-Intercitv/Gasoline
Bus-Urban/Distillate
Bus-Urban/Gasoline
Air-Civil-Domestic/Jet
Air-Civil/
International/Jet
Rail-Urban Rapid
Transit/Electric
Rail-Intercity/
Electric
Rail-Intercity/
Distillate
General Aviation-Piston/
Gasoline
General Aviation-
Turbine/Jet
Water Pollutants (Tons/measure)
Acids
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Bases
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
0*
cm
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
ro
O
Z
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Total Dissolved
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Suspended
Solids
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Organics
0
0
0
0
0
0
0
0
NA
NA
0
0
0
Q
o
(0
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
§
O
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Thermal (Btu's/
measure)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Air Pollutants (Tons/measure)
Particulates
1.05
xlO-7
1.95
x!0~7
4.85
xlO-9
1.08
xlO-8
1.05
xlO-7
2.15
xlO-8
1.45
xlO-7
7.53
Xl0~8
NA
NA
2.21
XlO-7
xio-4
u
X
o
z
1.44
xlO~6
1.44
XlO~6
1.39
xio~b
2.53
xicr7
2.98
xicr6
3.24
XlO-7
1.05
xlO~7
4.6
xlO-8
NA
NA
6.65
xlO-7
xlO"4
2.49
xlO-4
0*
m
6.2
xlO-8
1.18
xlO~7
1.
xlO-7
6.25
xlO"8
2.18
XlO-'
1.39
xlO-8
4.2
Xl0~8
1.67
XlO-8
NA
NA
5.72
XlO-7
xio"6
5.65
xlO-5
Hydrocarbons
3.53
xlO~6
4.78
xlO"7
1.36
x!0~7
xio~7
2.93
xlO"7
5.55
xlO"7
xlO"7
8.36
xlO-8
NA
NA
4.43
xlO-7
xio"4
2.72
xlO-4
O
o
2.25
xlO-S
4.
xlO-5
8.45
Xl0~7
2.05
xlO"6
1.81
xlO"6
4.65
xlO-6
XlO"7
2.2
xlO-8
NA
NA
6.2
xlO-7
xlO"3
9.5
xlO-4
Aldehydes
1.69
xlO~7
3.21
XlO-7
2.21
xlO~8
xlO~8
4.75
xlO-8
3.5
xlO-8
1.05
xlO~8
4.2
xlO-9
NA
NA
9.75
XlO-8
xio~5
U
Solids
(tons/measure)
b
b
b
b
b
b
b
b
b
b
b
b
b
Measure3
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Passenger-
Mile
Hour
Hour
Energy
Btu/measure
3520.
4730.
1070.
757.
2300.
1440.
9320.
5660.
3390.
2360.
2900.
2.75
xin6
1.51
xlO7
Multiplier
8.95
xlO11
1.09
x!Ql2
2.35
XlO10
4.31
xlQlO
1.84
xlOlO
1.81
xlOlO
xioii
4.88
xlOlO
7.75
x!09
6.07
XlO9
6.1
xlo9
2.4
XlO7
1.5
xlfl6
Multiplier Year
1970
1970
1971
1971
1971
1971
1970
1970
1970
-910
1969
1970
1970
NA = not applicable.
aPassenger-Mile is one passenger moved a distance of one mile.
Solid waste is not attributable to transportation energy consumption except for the secondary impacts of discarded propulsion systems.
-------
is shown to be a major contributor to the
man-made emissions of CO, unburned hydro-
carbons, and NOX. One source estimated
that, in cities, motor vehicles emitted 50
to 90 percent of the above pollutants in
1973 (EPA, 1973: 156).
Current pollution abatement efforts of
the automotive industry have increased con-
sumption of gasoline and petroleum products
for motor vehicles, but not as much as of-
ten reported. A recent EPA study estimates
that the loss in fuel economy for 1973 mod-
el year vehicles over those with no emis-
sion controls is in the range of seven to
eight percent (EPA, 1972: 141).* Indica-
tions suggest that the fuel economy of 1975
vehicles with their additional controls
should remain unchanged from 1973. The
imposition of the initial 1976 NOX emission
standards could have caused a further re-
duction in fuel economy of 10 percent to 12
percent; however, due to recent developments
in air quality data, the emission standards
for 1976 are being reconsidered. In terms
of operating costs, a fuel economy loss of
seven to eight percent is estimated to in-
crease the average driver's fuel bill by
less than $25 a year (1973 prices). The
increased initial cost of a 1975 model year
vehicle due to emission controls should be
in the range of $150 to $300 (approximately
two to three percent of the total cost)
(EPA, 1973: 160.161).
In addition to the air emissions re-
sulting from the operation of vehicles,
gaseous, liquid, and solid wastes are gen-
erated by the manufacture, maintenance, and
scrapping of vehicles. Though these im-
pacts are beyond the scope of this descrip-
To put these numbers in perspective,
the fuel penalty associated with consumer
choices such as auto air conditioning and
automatic transmissions have been reported
respectively as nine and five or six per-
cent. On the other hand, high vehicle
weights can result in fuel penalties up to
50 percent, especially when they result in
very low power-to-weight ratios.
tion (in that they are not attributed di-
rectly to the end use of energy for trans-
portation) , they should be considered at
least qualitatively in an overall assess-
ment of the environmental impacts of any
one transportation mode (cf. Hittman,
1974b: Appendix C).
13.4.2.4 Economic Considerations
Table 13-26 shows approximate 1970
prices for passenger travel by various
methods. Although not as strongly corre-
lated as for freight movement, passenger
travel modes also show a direct relation-
ship between energy intensiveness and
price. In other words, price per passenger-
mile increases for the less efficient modes,
reflecting their speed, convenience, com-
fort, flexibility, and reliability. How-
ever, user costs do not always reflect rel-
ative energy costs. For example, comparing
the energy intensiveness figures. Table
13-24 shows that, although the urban auto-
mobile consumes 2.24 times more energy per
TABLE 13-26
PASSENGER TRANSPORTATION
PRICES (1970)
Mode
Bus
Railroad
Automobile
Airplane
Mass transit
Automobile
Price
(cents per
passenger-mile)
INTER-CITY
3.6
4.0
4.0
6.0
URBAN
8.3
9.6
Source: Hirst and Moyers, 1973a:
1300.
13-44
-------
passenger-mile than a bus, the economic
cost is only 1.15 times greater.
Massive commitments in terms of energy
and money are made to the automobile in our
society. During 1970, 8.4 million cars
(both domestic and foreign) were sold by
retail dealers, and 87 million passenger
cars were registered in the U.S. Approxi-
mately 10 percent of the Gross National
Product (GNP) and 16 percent of the
American work force can be directly traced
to the automotive industry (Hittman, 1974a:
21,23). Obviously, the production and use
of the automobile constitutes a significant
part of the national economy. in addition,
owning an automobile constitutes a major
part of each family's budget. The average
new car price for 1970, excluding taxes,
was $3,190 (Hirst and Herendeen, 1973: 973),
and until recent price increases, the total
cost for auto transportation was about 14
cents per vehicle mile (Ford Foundation,
1973: Chapter XII, p. 23).
13.4.3 Military-Government and Feedstocks
As previously noted, Hittman provided
estimates for two additional transportation
categories: consumption and related resid-
ual data for military and government trans-
portation (based on records maintained by
the Department of Defense Fuel Supply
Center), and the total gallons of lubricants
for automotive and aviation transportation
{a separate feedstocks category).
Table 13-27 gives estimates of the en-
vironmental residuals that have been quan-
tified for the above two categories. Most
of the data is considered poor, with a
probable error of 100 percent. Feedstocks
for transportation services are a source
of nondegradable organic water pollutants,
contributing about 7.42xl04 tons per year
to the environment. The residuals associ-
ated with military and government transpor-
tation use are similar to those for freight
and passenger vehicle modes; that is, air
pollutants.
13.4.4 Conservation Measures for the
Transportation Sector
As demonstrated in the preceding tech-
nological description, U.S. transportation
is dominated by the least efficient (in
terms of energy consumption) methods. Gov-
ernment policies appear preferential to the
development of air and highway transporta-
tion and have contributed to declining en-
ergy use efficiency. Further, the present
mix of transport modes is determined by
personal preference, private economics,
convenience, speed, and reliability (Hirst
and Moyers, 1973a: 1300)—factors that
often ignore energy consumption rates.
Conservation strategies for the trans-
portation sector must take into account na-
tional and social factors so that changes
do not result in excessive damage to trans-
portation-dependent industries or appre-
ciably disrupt the quality of transporta-
tion services. Energy demand in this sec-
tor could be reduced by shifting to more
energy efficient transportation modes; in-
creasing load factors; and improving the
efficiency of the different transport
modes. Of these measures, only the latter
would require additional research and de-
velopment (e.g., to determine improvements
or alternatives to the internal combustion
engine).
A conservation study by the OEP found
the greatest potential for transportation
energy savings in the shift of inter-city
freight from highway to rail, inter-city
passengers from air to ground travel, urban
passengers from automobiles to mass transit,
freight consolidation in urban freight move-
ment, and longer term improvements through
the introduction of more efficient equip-
ment. OEP outlined the following specific
recommendations (1972: 56,57), including
estimated sector savings if the measures
were implemented:
1. Short-Term Measures (1972-1975).
Conduct educational programs to
stimulate public awareness of en-
ergy conservation in the transpor-
tation sector. Establish govern-
ment energy efficiency standards.
13-45
-------
Table 13-27. Residuals for Military and Government and Feedstocks Transportation Energy Use
End Use/Fuel
MILITARY AND GOVERNMENT
TRANSPORTATION
Aircraft-Piston/Gasoline
Aircraft -Turbine/ Jet
Ground Vehicles/Gasoline
Ships/Distillate
Ships/Residual
TRANSPORTATION FEEDSTOCKS
Lubricants
I
Water Pollutants (Tons/measure)
»
•o
•H
a
NA
NA
NA
NA
NA
NA
10
CO
to
a
to
NA
NA
NA
NA
NA
NA
g
NA
NA
NA
NA
NA
NA
n
g
NA
NA
NA
NA
NA
NA
13
0)
>
rH
o
01
°.
13
+J H
O O
E-> w
NA
NA
NA
0
0
NA
T)
<
•S
•O
rH
•C
2.22
xlO-7
2.28
6.8
xlO~6
U
U
0
3
Si>
w m
1.25
1.33
xlO5
1.25
1.39
xlO5
1.5
XlO5
1.44
xlO5
A
•H
-p
3
4.18
xlO°
4.19
X.1Q9
3.29
xlo8
1.78
xlO8
1.7
1.06
XlO9
H
a
ix
&
•H
4J
i
1972
1972
1972
1972
1972
1969
NA = not applicable, U « unknown.
Solid waste is not attributable to transportation energy consumption except for the secondary impacts of discarded propulsion systems.
-------
Improve traffic flow. Improve
mass transit and inter-city rail
and air transport. Promote auto-
mobile energy efficiency through
low-loss tires and engine tuning.
Savings: I,900xl012 Btu's per
year (10 percent).
2. Mid-Term Measures (1976-1980).
Improve freight handling systems.
Support pilot implementation of
most promising alternatives to
internal combustion engine. Set
tax on size and power of autos.
Support improved truck engines.
Require energy efficient operating
procedures for airplanes. Provide
subsidies and matching grants for
mass transit. Ban autos within
the inner city. Provide subsidies
for inter-city rail networks. De-
crease transportation demand
through urban refurbishing pro-
jects and long-range urban/subur-
ban planning. Savings:
4,800xl012 Btu's per year (21 per-
cent) .
3. Long-Term Measures (beyond 1980).
Provide R&D support for hybrid en-
gines, nonpetroleum engines, ad-
vanced traffic control systems,
dual mode personal rapid transit,
high speed transit, new freight
systems, and people movers. De-
crease demand through rationing
and financial support for urban
development and reconstruction.
Savings: S.OOOxlO12 Btu's per
year (25 percent).
The remainder of this discussion spe-
cifically identifies several of the more
promising energy conservation alternatives
for various end uses within the transpor-
tation sector. Public awareness of these
measures should help foster an understanding
of the energy implications of transportation
decisions.
13.4.4.1 Automobiles
The consumer should be made aware of
the energy and dollar cost implications of
his decisions concerning the expected fuel
economy of new cars, as well as the long-
term costs associated with accessories
(e.g., air conditioners, automatic trans-
missions, etc.).
The Ford Foundation energy study esti-
mated that about 75 percent of the potential
transportation energy savings in 1985 can
come from improving the fuel economy of the
TABLE 13-28
EFFECT OF AUTO DESIGN
ON FUEL ECONOMY
Design Feature
Body redesign to reduce
aerodynamic drag
Use of radial tires
to reduce rolling
resistance
Better load-to-engine
match
Substitution of 300
pounds of aluminum
for 750 pounds of
steel
Fuel Economy
Improvement
(percent)
10
10 to 15
18
Source: Ford Foundation, 1974a: 59.
automobile to 20 mpg (Ford Foundation, 1973:
Chapter XII, p. 23). This could be accom-
plished by shifting to smaller, lighter-
weight or medium-sized cars which in many
cases already achieve or surpass the 20-mpg
average. Short-term fuel economy could be
favorably affected by some rather simple,
economically feasible engineering improve-
ments as listed in Table 13-28. Improve-
ments like the above might increase auto
capital costs up to $450 but the fuel
savings would more than compensate for the
added investment (Ford Foundation, 1974a:
59) .
Another conservation opportunity is
car pooling, which increases the average
occupancy (load factor) of automobiles.
The impact of car pooling is difficult to
estimate because of variations in geographic
locations, size of metropolitan areas, busi-
ness types, and residential densities. How-
ever, increased load factors represent a
source of immediate savings.
The development of efficient, conve-
nient, and reliable mass transit systems to
be used in place of more energy intensive
13-47
-------
automobiles could significantly reduce the
traffic congestion and the need for addi-
tional highways. Although mass transit
systems have very long lead times and high
capital costs, urban transportation is a
primary target for this action.
To illustrate possible energy savings
through use of more energy efficient modes,
one study (Hirst and Moyers, 1973a: 1300)
compared two transportation models (an ac-
tual and a hypothetical case), one based
on historic growth trends and the other on
a steady shift toward more energy efficient
modes. This comparison revealed that adop-
tion of the hypothetical case would require
only 78 percent as much energy to move the
same traffic as the actual case.
Assumptions underlying the hypothetical
mode1 include:
1. Half the freight traffic carried
by conventional methods (truck
and air) is assumed to be carried
by rail.
2. Half the inter—city passenger traf-
fic carried by air and one-third
the traffic carried by auto is
assumed to be carried by bus and
train.
3. Half the urban automobile traffic
is assumed to be carried by bus.
For this scenario's potential to be real-
ized, changes must occur in public attitudes
concerning mass transit. The balance among
transportation modes is constrained by var-
ious socio-economic factors that might in-
hibit shifts to more energy efficient modes.
Such factors include: existing land use
patterns, capital costs, changes in energy
efficiency within a given mode, substitut-
ability among modes, new technologies,
transportation ownership patterns, and other
institutional arrangements. However, fuel
scarcities, rising energy prices, dependence
on foreign petroleum, urban land-use prob-
lems, and environmental considerations may
provide the incentives necessary to alter
current transportation practices (Hirst and
Moyers, 1973a: 1300) .
Further improvements for the long-term
can be achieved through research and devel-
opment in motor vehicle engine design.
Possible improvements range from modifica-
tion of conventional engines, with add-on
devices like catalytic beds, to systems
based on thermodynamic cycles different
than the conventional internal combustion
engine. Hittman performed a technology
assessment of advanced automotive propul-
sion systems in an effort to define and
study the interrelationships and impacts
resulting from a transition from the current
internal combustion engine to alternate pro-
pulsion systems (1974b). The stratified-
charge engine (developed by Honda) appears
to be especially promising for the automo-
bile. Hittman concluded that stratified-
charge engine design had progressed to the
point that full-size vehicles, compacts,
and subcompacts could be developed with
significantly improved fuel economy, low-
emissions without catalysts, and minor ma-
terials and economic impact (Hittman, 1974a:
102) .
Another alternative is the lightweight
diesel engine. (Presently, the Mercedes-
Benz 220D is the leading diesel-powered
auto available in the U.S.) The advantage
of the diesel-powered auto is fuel economy.
Figure 13-3 illustrates this engine's high
fuel economy in relation to three gasoline
engines at the low speeds characteristic of
urban driving. Additional advantages of the
diesel engine are its low level of pollutant
emissions, low maintenance requirements, and
high mileage between overhaul capability.
However, present customer acceptance of
diesel—powered cars is low and future levels
are very uncertain because of the engine's
characteristic high noise level, smoke,
odor, difficult cold starting, low perfor-
mance, and particulate emissions (Hittman,
1974a: 29-31).
13.4.4.2 Airplanes
Energy use for air travel can be re-
duced either by shifting to alternative
modes or by improving the operating effi-
ciencies . The Ford Foundation energy study
13-48
-------
D>
Q.
E
O
O
UJ
_J
UJ
Diesel
30
20
10
-I972USA
M-B230
Gasoline, 1975 USA
10 20 30 40 50 60 70 80 90
SPEED, mph
Figure 13-3. Comparison of Fuel Economy for Four Engines
Source: Wakefield, 1973: 67 (Courtesy Road & Track Magazine)
-------
reported the most important single measure
for reducing energy requirements for this
transport mode would be to increase the
load factor for passengers (Ford Foundation,
1974a: 61). As the public and the federal
government become more aware that air trav-
el is not energy efficient when seats are
vacant, the possibility that load factors
will change becomes greater. Load factors
depend to a large degree on the rate at
which the Civil Aeronautics Board (CAB)
authorizes competitive routes. Recently,
airlines have been authorized by the CAB to
discuss the elimination of competing
flights.
It has been estimated that load factors
could be increased to 67 percent without
appreciably reducing a passenger's chances
of losing his reservation. Such an improve-
ment is calculated to result in a 18-percent
direct fuel savings for domestic flights
and an eight-percent savings for interna-
tional flights, which are already loaded to
a greater capacity (Ford Foundation, 1973:
Chapter XII, p. 29).
Further improvements could come from
reducing speeds of airplanes to the level
where fuel consumption in minimal. Reducing
speeds to this level would result in a 4.5-
percent fuel savings and would increase
flight times only six percent (Ford Foun-
dation, 1974a: 61).
In an attempt to achieve a more opti-
mal balance in terms of energy efficiency,
short-haul air freight (up to 150 miles)
should be shifted to truck, and interme-
diate-haul air freight (250 to 450 miles)
should be shifted to rail. As rapid rail
transport systems are developed, it might
even become feasible to shift short-haul
air traffic to rail.
13.4.4.3 Trucks and Rail
Energy demand for trucks and railroads
can be reduced by:
1. Loading trucks more efficiently.
2. Switching gasoline-powered trucks
to diesel or equally efficient
engines.
3. Changing truck configurations.
4. Shifting many truck shipments to
rail.
The Ford Foundation estimates that
savings of 10 to 30 percent are possible
through improved loading practices. In
addition, about 30-percent savings could
be achieved by switching freight-hauling
trucks from gasoline to diesel engines
(Ford Foundation, 1974a: 60).
Although several changes in truck con-
figuration are possible, the most promising
is probably a change in the truck body
shell to reduce aerodynamic drag. One
source indicated that a modest design pro-
gram, completed in the short-term, could
result in design capable of achieving a
five-percent reduction in energy consump-
tion (Seidel and others, 1973: 94).
The use of railroads instead of trucks
for freight was suggested earlier as a po-
tential energy saving measure. To the pre-
sent, the difference in efficiency has not
been great enough to outweigh the positive
features of trucks. This situation could
change with rising fuel costs. There are
indications that with changed government
policies, some upgrading of rail service,
and the adoption of marginal cost pricing,
the economics of a switch to rail would be
favorable for more than half the freight
now moving by truck (Ford Foundation, 1973:
Chapter XII, p. 31). If 20 percent of the
large truck traffic (corresponding to hauls
longer than 600 miles) is shifted to rail,
the Ford Foundation estimates savings by
1985 to be 300xl012 Btu's.
13.4.4.4 Other
Inter-city buses and short- and medium-
distance high-speed trains are another po-
tential for reducing the number of persons
using private automobiles and commercial
airplanes. An example is the Metroliner
train between New York and Washington. How-
ever, these transport modes depend to a
large extent on major financial assistance
and changes in the attitudes of the general
13-50
-------
public. Without such support, these trans-
portation modes will not be used to their
maximum.
Energy conservation strategies within
the transportation sector are highly inter-
active, and any conservation measure will
tend to shift the structure of the trans-
port market to which it is applied (Seidel
and others, 1973: 91,92). Thus, studies of
the competition between transport modes
should be an integral part of any assess-
ment of energy conservation strategies.
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Washington: Government Printing
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Office of Science and Technology (1972)
Cumulative Regulatory Effects on the
Cost of Automotive Transportation,
Final Report of the Ad Hoc Committee
as cited in Shell Oil Company (1972)
Oil and the Environment: The Prospect.
Houston: Shell Oil Company, p. 7.
Rice, Richard A. (1972) "System Energy and
Future Transportation," Technology
Review 74 (January 1972): 31-37.
Schurr, Sam H. (1971) Energy Research Needs.
Washington: Resources for the Future,
Inc.
Seidel, Marquis R., Steven E. Plotkin, and
Robert O. Reck (1973) Energy Conserva-
tion Strategies. Washington: Envi-
ronmental Protection Agency.
Senate Committee on Interior and Insular
Affairs (1973a) Energy Conservation
and S. 2176, Hearings. 93rd Cong.,
1st sess., August 1973.
Senate Committee on Interior and Insular
Affairs (1973b) Energy Research and
Development—Problems and Prospects,
by Harry Perry. Washington: Govern-
ment Printing Office.
13-52
-------
Shell Oil Company (1973a) The National
Enerqy Problem: Implications for
the Petrochemical Industry.
Shell Oil Company.
Houston:
Shell Oil Company (1973b) The National
Energy Problem; Potential Energy
Savings. Houston: Shell Oil Company.
Stanford Research Institute (1972) Patterns
of Energy Consumption in the United
States. Washington: Government
Printing Office.
Szego, G.C. (1971) The U.S.
Warrenton, Va.:
Corporation.
Energy Problem.
InterTechnology
Tansil, J., Residential Consumption of
Electricity; 1950-1970. Oak Ridge
National Laboratory Report ORNL-NSF-
EP, as cited by Hirst and Moyers
(1973b): 169.
Tybout, Richard A., and George O.G. Lof
(1970) "Solar House Heating" Natural
Resources 10 (April 1970): 268-326.
Wakefield, R. (1973) "The Diesel." Road
and Track 25 (September 1973).
Washington Center for Metropolitan Studies
(1974), as cited in the Ford Founda-
tion (1974).
13-53
-------
PART II: PROCEDURES FOR EVALUATING AND COMPARING ENERGY ALTERNATIVES
INTRODUCTION
Guidelines issued by the Council on
Environmental Quality (CEQ) and court
interpretations of the National
Environmental Policy Act (88 Stat. 842, 42
U.S.C. Sec. 4321) emphasize certain content
requirements for environmental impact state-
ments (EIS), including the evaluation of
both primary and secondary effects, the
consideration and balancing of both advan-
tages and disadvantages, and a thorough
exploration of all reasonable alternatives.
Reasonable persons can and have disagreed
on whether these requirements have been met
in particular impact statements. As a con-
sequence, most agencies have made a consid-
erable effort to improve the quality of the
EIS they prepare and to make them less
susceptible to challenge. However, EIS are
often uneven in quality, largely because
there is no satisfactory methodology for
systematically identifying, measuring,
interpreting, and/or replicating the evalua-
tion of the proposed action and reasonable
alternatives to it. The environmental
impact statement process has now evolved to
a point where it is both desirable and
possible to suggest procedures for making
more systematic evaluations and comparisons.
The primary purpose of this part of the
report is to suggest procedures for using
CEQ's Matrix of Environmental Residuals for
Energy Systems (MERES) data and the
University of Oklahoma (OU) resource systems
descriptions in Part I of this report.
By themselves, these procedures and
data will not satisfy current requirements
for evaluating and comparing energy alterna-
tives in an EIS. For example, while
accounting for many of the significant
residuals, the procedures do not provide for
a comprehensive analysis of the impacts of
a proposed action on the environment; they
do not provide guidelines for identifying
which alternatives should be evaluated
and compared as "reasonable" alternatives,
including non-energy uses of affected
lands; they do not specify evaluative
criteria; and they do not provide answers
to questions regarding policy alternatives
such as the impact of deregulating the
wellhead price of natural gas. In short,
these procedures are primarily a tool to
be used in planning and preparing an energy
EIS, a tool for making certain limited
kinds of calculations and comparisons
that can be supported by the MERES data
base and the OU resource systems
descriptions. However, Part II does
suggest general procedures for relating
residuals to ambient conditions, extending
the examination of energy efficiencies to
a more comprehensive energy balance
analysis, and upgrading the economic
analysis to include a consideration of
prices as well as economic costs. All
three of these analyses require data not
available in either MERES or the OU
resource systems descriptions; they also
require an explicit identification of
goals, objectives, and evaluative criteria
at a level of specificity beyond that
possible within the limitations imposed
for this report generally and Part II
specifically.
*Three broad classes of EIS have
evolved to date—an EIS for: a specific
project; a particular geographical area
or region; and an overall program. The
examples used in this report fit the
specific project category.
II-l
-------
Both the OU resource systems descrip-
tions and MERES incorporate residuals,
energy efficiency, and economic cost data
reported in Hittman Associates'
Environmental Impacts, Efficiency and Cost
of Energy Supply and End Use (1974: Vol. 1;
1975: Vol. 2). MERES presently contains
only data on four fossil fuels: coal, crude
oil. natural gas, and oil shale.* The OU
resource systems descriptions also contain
data drawn from Battelle's Environmental
Considerations in Future Energy Growth
(1973), Teknekron's Fuel Cycles for
Electrical Power Generation (1973), the
Federal Energy Administration's Project
Independence Blueprint (1974), and mis-
cellaneous other sources published by
agencies such as the Atomic Energy
Commission, Bureau of Mines, U.S. Geological
Survey, and other government agencies with
responsibilities in the energy area. In
addition to the four fossil fuels covered
by MERES, Part I of this report describes
geothermal, hydroelectric, nuclear fission,
nuclear fusion, organic wastes, solar, tar
sands, electric power generation, and energy
consumption.
MERES data have also been incor-
porated into a computerized data system,
the Energy Model Data Base (EMDB), developed
by the Energy/Environmental Data Group of
the Brookhaven National Laboratory. De-
tailed information on data and documentation
files and the methods of accessing the EMDB
are contained in Brookhaven's Energy Model
Data Base User Manual (1975).
Note that the proposed procedures
are affected by data quality. As noted in
the General Introduction, both the OU
descriptions and MERES data are incomplete
because they are limited to what can be
quantified. Although the OU descriptions
do identify and discuss certain qualitative
residuals, data contained in all three
sources must be considered incomplete.
*Data for other energy resources
will soon be added.
This gap is especially significant when
these data and procedures are used in
planning and EIS preparation.
While both the OU descriptions and
MERES incorporate only the most accurate
data currently available, some of the data
are of questionable quality. In part, this
is due to disagreements within the scientific
and technological communities, and in part it
is due to the quality of data included in
MERES and the OU descriptions. MERES data
have been reviewed systematically and have
been assigned "hardness" numbers to indicate
their reliability. As noted earlier, these
numbers show that reliability ranges from
very good (an error of 10 percent or less)
to very poor (an error of perhaps as much
as an order of magnitude). These numbers
are also used in the OU descriptions of
energy resource systems to identify data
quality.*
Plans for MERES include continuously
updating and improving data quality. Users
of MERES and this report can help by calling
to the attention of CEQ, OU's Science and
Public Policy Program, and Brookhaven's
Energy/Environmental Data Group errors in
the present data, the existence of more
reliable data, and when more current data
become available.
Part II consists of three chapters
that describe and demonstrate procedures for
using MERES data and the energy resource
descriptions in Part I of this report.
Chapter 14 focuses on the calculation and
comparison of residuals and suggests
procedures for analyzing impacts.
Chapter 15 deals with energy efficiencies
and energy balances. Chapter 16 discusses
economic costs and prices. Analyses and
comparisons in all three chapters are
based on the following hypothetical
proposed major federal action and selected
alternatives to it. The alternatives are
*When technological activities are
combined, the error of the combination is
reported by OU as the hardness number for
the lowest quality data.
II-2
-------
intended to be illustrative only and should
not be considered the "reasonable" alter-
natives to the hypothetical proposed action.
Hypothetical Proposed
Major Federal Action
The Secretary of the Interior
is considering an application of
the Synthetic Energy Company to
construct and operate a coal mine
and coal gasification facility on
leased federal lands near Colstrip,
Montana. It is assumed that the
company leased the lands to be
mined and upon which the processing
facility is to be located in a
competitive lease sale. Under the
conditions of the sale, the winning
bidder was required to submit an
application to the Secretary within
30 days after the lease was awarded.
That application, which includes a
mine and facilities development plan
and an assessment of the environmen-
tal impact of the planned develop-
ment, was submitted to the Secretary
and is now being reviewed by the
Department. These plans call for an
area surface mine, a Synthane high-
Btu gasification facility, and
introduction of the produced gas
into an existing interstate pipe-
line that transports natural gas
to the Pacific Northwest. Approval
of this application is interpreted
to constitute a major federal action
within the meaning of Section 102
(2) (C) of the National Environmental
Policy Act of 1969 (88 Stat. 842,
42 U.S.C. Sec. 4321).
In an EIS, it may be legally necessary
to consider a number of alternatives to
the proposed action, including "no action".
For example, different technologies might
be chosen (the Lurgi rather than Synthane
high-Btu gasification process); a different
location could be chosen for the Synthane
plant (the Pacific Northwest rather than
Montana); an alternative source of high-
Btu gas might be considered (the Alaskan
North Slope); and a different fuel might
be substituted (electricity generated
by an oil or nuclear-powered facility).
Again, not all "reasonable" or possible
alternatives that it would be necessary
to consider in an EIS analysis are
compared in Chapters 14 through 16; the
following alternatives have been selected
only to illustrate the use of MERES and OU
descriptions:
1. Technological Alternative.
Substitution of Lurgi for
Synthane.
2. Locational Alternative. Relocate
the high-Btu gasification facility
from the mine-mouth to the demand
center.
3. Alternative Sources of High-Btu
Gas.
a. Alaskan natural gas via a
Canadian pipeline.
b. Alaskan natural gas via
pipeline to Valdez and by
LNG tanker to the west coast.
c. Increased domestic production
offshore.
d. Imported foreign LNG.
The residuals, energy efficiencies, and
economic costs of each of these alternatives
and the hypothetical proposed major federal
action are calculated and compared in the
following three chapters.
REFERENCES
Battelle Columbus and Pacific Northwest
Laboratories (1973) Environmental
Considerations in Future Energy
Growth, Vol. I: Fuel/Energy Systems;
Technical Summaries and Associated
Environmental Burdens. for the Office
of Research and Development,
Environmental Protection Agency.
Columbus, Ohio: Battelle Columbus
Laboratories.
Brookhaven National Laboratory, Associated
Universities, Inc., Energy/Environmental
Data Group (1975) Energy Model Data
Base User Manual, BNL 19200.
Federal Energy Administration (1975) Project
Independence Blueprint. Washington:
Government Printing Office.
Hittman Assosiates, Inc. (1974 and 1975)
Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use,
Final Report: Vol. I, 1974; Vol. II,
1975. Columbia, Md.: Hittman
Associates, Inc. (NTIS numbers: Vol. I,
PB-238 784; Vol. II, PB-239 158).
"National Environmental Policy Act",
Statutes at Large 88, Sec. 842; U.S.
Code, Title 42, Sec. 4321.
II-3
-------
CHAPTER 14
PROCEDURES FOR COMPARING THE RESIDUALS OF ENERGY ALTERNATIVES
14.1 INTRODUCTION
Residuals are by-products that an ac-
tivity, process, or technological alter-
native produces in addition to its primary
product. Residuals include particulates,
gases, solid and liquid wastes, accidents
and death, and land consumption, all or
some of which might produce significant
environmental impacts where they-occur.
This chapter describes the residuals
data contained in Matrix of Environmental
Residuals for Energy Systems (MERES) and
the University of Oklahoma (OU) resource
system description and demonstrates methods
by which these data can be used in the com-
parison of energy alternatives. Residuals
data are divided into five categories: air,
water, solids, land, and occupational health.
Air pollutant residuals include particulates,
oxides of nitrogen, oxides of sulfur, hydro-
carbons, carbon monoxide, and aldehydes.
Water pollutant residuals include acids,
bases, phosphates, nitrates, dissolved
solids, suspended solids, nondegradable
organics, thermal pollution, and increased
biochemical and chemical oxygen demands.
Solids include various kinds of solid
These data are limited to those in-
cluded in Hittman (1974 and 1975) and, as
indicated earlier, may not be complete.
For example, heavy metals are not included
as air and/or water pollutants. The purpose
of this report was not to make the data base
all inclusive; rather, the report should be
viewed as a step toward developing a com-
prehensive data base and a methodology for
using it in evaluating and comparing energy
alternatives.
wastes such as processed (spent) oil shale
and the overburden that has to be removed
to surface mine coal, oil shale, tar sands,
etc.
In the OU report, the land residual
includes three numbers: fixed land use,
incremental land use, and a time-averaged
total. Only the time-averaged total is
given in MERES. Fixed land use refers to
the land required for facilities; for ex-
ample, a gasification plant, a settling pond,
water treatment plant, etc. This require-
ment is given in acres for a typical size
facility. Incremental land use refers to
such items as the number of acres mined to
produce a given amount of coal or the acres
required to dispose of a given amount of
solid waste. This requirement is stated in
acres per 10 Btu's input to the process.
The time-averaged value is the total land
impact for the life of the facility (assumed
to be either 25 or 30 years, depending on
the facility, for a facility which processes
10 Btu's per year). This value is obtained
by summing (1) the fixed value obtained by
linearly interpolating to a size of operations
12
equivalent to processing 10 Btu's per year
and (2) the time average obtained by multi-
plying the incremental value by half the num-
ber of years the facility will operate. This
requirement is expressed in acre-years per
1012 Btu's.
Occupational health includes deaths,
injuries, and man-days lost. These values
and the air, water, and solids residuals
are quantified in MERES on the basis of
14-1
-------
energy inputs per 10 Btu's. Many of the
OU data are quantified in the same units
as the MERES data, but the OU data include
seme qualitative residuals as well (such
as noise and esthetics). OU data also
include impact producing inputs (e.g., re-
quirements for water, catalysts, etc.).
When broadly defined, the term "residual"
encompasses inputs of this type.
In the OU resource systems descriptions
(Chapters 1 through 13), residuals data are
reported in an "Environmental Considerations"
section following the description of each
technological activity. Brookhaven's Energy/
Environmental Data Group has prepared an
Energy Model Data Base User Manual (1975)
which describes the Energy Model Data Base
(EMDB) data and documentation files as well
as the programs that have been written for
using the data in energy modeling. The
EMDB can be accessed from remote terminals.
Information on procedures may be obtained
from either the Council on Environmental
Quality (CEQ) or Brookhaven.
14.2 GENERAL PROCEDURES FOR OBTAINING AND
USING RESIDUALS DATA
The steps for calculating and comparing
the residuals of energy alternatives,
including the action being proposed in the
environmental impact statement (EIS) re-
quiring the comparisons to be made, are:
1. Identify, describe, and calculate
residuals for the process, activity,
partial trajectory, or trajectory*
to be evaluated and compared.
a. Identify the alternative ac-
tivities and/or processes to
be evaluated and compared by
referring to Figure 1 in each
of the OU resource system de-
scriptions. (Some alternatives
may be eliminated as unreason-
able without going through the
entire evaluation and compari-
son procedure. For example,
some coal gasification processes
could be eliminated from further
These terms are defined in the Intro-
duction to this part of the report.
consideration if they are not
compatible with the kind of coal
that is to be gasified.)
b. Access MERES data and documenta-
tion files following procedures
described in Brookhaven's User
Manual. Residual amounts for
each process, activity, partial
trajectory, or trajectory will
be calculated for the size of
operation being considered.
For example, if high-Btu coal
gasification processes are to
be compared, residuals can be
based on either the energy value
of the coal that goes in or the
gas that comes out (e.g., if the
HYGAS process produces 6.88 tons
of particulates per 10^-2 Btu's
of coal input, 3.02 tons of
particulates will be produced
by a facility producing 250
million cubic feet [mmcf] of
gas daily*).
c. To obtain supplemental data in-
cluded in *-Jhe OU descriptions
and information on the assump-
tions made concerning the data,
data quality, and descriptions
of qualitative residuals, read
the sections on "Environmental
Considerations" that follow the
descriptions of processes for
each activity in the OU resource
systems descriptions. Information
on assumptions and data quality
can also be obtained from MERES.
d. For those resource systems not
included in MERES, obtain both
quantitative and qualitative
residuals data from the "Environ-
mental Considerations" sections
of the OU resource systems de-
scriptions. As when using MERES,
the size of operations to be
compared should be specified.
e. If the quantities for each pro-
cess, activity, partial trajec-
tory, or trajectory have not been
summed, sum them and list all
quantitative residuals. Caution:
the residual quantities are first
converted (from those in the data
base) to correspond to the size
operation or trajectory output
specified. For example, the
hypothetical proposed high-Btu
gasification facility produces
250 mmcf daily.
2. Make the desired comparisons.
These can include:
a. A comparison of specific
250 mmcf = 2.6x10 Btu's of gas.
Based on a HYGAS primary efficiency of 59
percent, this is 4.4xlQll Btu's of coal
input.
14-2
-------
residuals, such as oxides of
nitrogen, or categories of
residuals, such as water pol-
lutants (e.g., from source
to end use).
b. A comparison of complete tra-
jectories or of any part of a
trajectory (e.g., by geogra-
phic location).
3. In comparing the proposed action
and alternative sources, the feasi-
ble options can be determined by
referring to the OU descriptions.
(These descriptions include only
technologies that have the possi-
bility of being available in pro-
totype form in 10 years, that are
the subject of major research sup-
port, that have the potential for
producing hydrocarbons, or that
can be substituted to meet speci-
fied end use requirements. If
these descriptions are not used,
the user must specify his own
criteria for determining feasibil-
ity; for example, economic costs,
a fixed level of air or water pol-
lutants, etc.) Those source alter-
natives determined to be feasible
can then be compared with the pro-
posed action and the technological
and locational alternatives on the
basis of a fixed amount or a fixed
reference point such as input or
output energy. 'However, evaluators
should be alert to the possible
effects of scale, the addition of
new point sources at a given lo-
cation, and possible cumulative
and synergistic effects. All three
of these cautions will be discussed
in the demonstration that follows.
The three procedural steps for evalua-
ting and comparing the residuals of energy
alternatives are summarized in Exhibit
14-1.
These procedures are applicable to the
calculation and comparison of technological,
locational, source, and substitute fuels
alternatives. However, the criteria for
determining feasible alternatives may vary
between categories, as might the comparison
bases. For example, in the case of loca-
tional alternatives, complete trajectories
can be compared on the basis of where they
will or would be produced. This becomes
most important when impacts are being evalu-
ated and compared since impact analysis
Residuals categories include air pol-
lutants, water pollutants, solids, land,
occupational health, aesthetics, inputs, and
outputs.
requires that residuals be related to ambient
conditions. (Impact analysis is discussed
in Section 14.5.)
14.3 A DEMONSTRATION OF HOW TO CALCULATE
RESIDUALS OF ENERGY ALTERNATIVES
In demonstrating the use of the pro-
posed system, calculations and comparisons
are based on the proposed action, a techno-
logical alternative, a locational alter-
native, and the four source alternatives
outlined in the Part II Introduction.
14.3.1 The Proposed Major Federal Action
The trajectory for the hypothetical
proposed major federal action consists of
five activities: mining and reclamation,
within and near mine transportation, bene-
ficiation, processing/conversion, and trans-
portation. In illustrating the calculation
of residuals for this action, MERES data
and the OU resource systems descriptions
are used. However, in many instances these
data are averages and thus, often will not
be directly applicable to a specific action.
For example, MERES data for coal are reported
as though they were national averages for
*
five regions. Also, the data for a par-
ticular process, such as Synthane, assume a
configuration that may not be the same as
that called for in the proposed action. As
a consequence, these data should be used
only for planning purposes. New site-specific
data should be gathered for specific pro-
posed actions.
The action agency (or anyone) wishing
to evaluate a particular proposal might begin
by calculating the residuals for that action
and selected alternatives using the OU re-
source systems descriptions. If, after
these calculations, the action is still
considered desirable and an EIS is to be
Regional coal data contained in MERES
are actually based on one or more mines with-
in the region: that is, they are not aver-
ages of all coal resources within that region.
14-3
-------
EXHIBIT 14-1
SUMMARY PROCEDURES FOR COMPARING THE
RESIDUALS OF ENERGY ALTERNATIVES
STEP
I
IDENTIFY, DESCRIBE, AND CALCULATE RESIDUALS
Identify the alternatives to be evaluated
by referring to the technologies flow
charts in the OU descriptions.
Obtain residuals using MERES data.
Supplement with additional quantitative
and qualitative residuals data from the
OU descriptions.
Summarize and tabulate all residuals data
for each alternative to be evaluated.
STEP
II
COMPARE THE RESIDUALS OF ALTERNATIVES
Compare either particular residuals or
categories of residuals.
Compare either partial or complete
trajectories.
STEP
III
DECIDE WHICH ALTERNATIVES ARE FEASIBLE
AND WARRANT FURTHER EVALUATION
14-4
-------
prepared, the residuals calculations for
the EIS should be based on new site specif-
ic data. Although basing calcuations for
all possible alternatives on specific site
data is neither necessary nor feasible,
comparing the proposed action and alterna-
tives may indicate that certain alterna-
tives should be examined more closely,
including perhaps the recalculation of
residuals for specific sites and configu-
*
rations.
Note that the three data sources and
the procedures described in this report may
be used:
1. As a planning tool for initially
appraising an energy alternative.
2. To determine whether the residuals
that would be produced warrant pre-
paration of an EIS.
3. To identify feasible (reasonable)
alternatives and allow a compari-
son on a process, activity, par-
tial trajectory, and/or complete
trajectory basis.
For purposes of this demonstration,
a printout of the residuals for each
individual process and total amounts of
residuals for the hypothetical proposed
action's trajectory was requested. The
results reported in Table 14-1 are based
on a daily energy output of 2.62x10 Btu's
{250 mmcf at 1,050 Btu's per cubic foot
[cf]) from the Synthane gasification
facility. Note that the residuals to be
produced at or near the same location have
been grouped together; that is, residuals
have been combined on a geographical basis
as well as for the total trajectory. In
the proposed trajectory, all residuals
except those associated with the transmis-
sion 'and distribution pipeline occur at or
near the mine.
An evaluation of the residuals of a
project may lead to cancellation, but it
also may lead to design modification.
14.3.2 A Technological Alternative
For purposes of illustration, only one
technological alternative, Lurgi high-Btu
gasification, has been considered (see
Table 14-2). However, three other high-
Btu gasification processes are included
in the OU descriptions, each of which could
be evaluated as an alternative to Synthane.
As Chapter 1 illustrates, there are tech-
nological alternatives for almost all of the
other activities as well.
14.3.3 A Locational Alternative
Residuals for a trajectory moving the
Synthane plant from near the mine site in
southeastern Montana to the Pacific North-
west are reported in Table 14-3. Note that
this trajectory also requires changing from
natural gas pipeline to unit train trans-
portation. (Another transportation tech-
nological alternative would be to pulverize
the coal at or near the mine site and trans-
port it by a slurry pipeline.) Again,
residuals have been grouped and totaled by
the area where they would be produced. In
the example, this results in three groups
of residuals: those that occur at or near
the mine site, those associated with unit
train transportation, and those that would be
produced at or near the demand center loca-
tion of the Synthane facility.
14.3.4 Source Alternatives
Four separate source alternatives will
be calculated and compared: Alaskan natural
gas to be transported to the U.S. upper mid-
* *
west by a pipeline through Canada; Alaskan
As noted in Chapter 1, several of the
coal conversion technologies are still in
the development stage. This should be kept
in mind when data for these processes are
used.
**It is assumed that this alternative
will displace pipeline quality gas from other
sources currently being consumed in the upper
midwest, and the 250 mmcf per day to be sup-
plied to the Pacific Northwest could be
drawn from one of these sources.
14-5
-------
Table 14-1. Residuals of the Proposed Actions Synthane High-Btu Gasification
(2.62X1011 Btu's Per Day Output)
Activity/Process
MINING AND
RECLAMATION:
Strip 15" or
less alone
WITHIN OR NEAR MINE
TRANSPORTATION:
Trucking
BENEFICIATION:
Breaking and
Sizing
PROCESSING/
CONVERSION:
Synthane
TRANSPORTATION:
^c
Feeder Pipeline
Subtotal3
TRANSPORTATION:
Transmission
Pipeline
TOTAL
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
NA
NA
NA
0
NA
0
NA
0
Organics
NA
NA
0
0
NA
0
NA
0
Total
0
0
0
0
NA
0
NA •
0
Air Pollutants (Tons/day)
particulates
.443
.00471
0
6.73
0
7.18
0
7.18
X
8
.544
.134
0
59.6
.802
61.
27.8
88.8
01
O
w
.0398
.00974
0
4.99
0
5.04
0
5.04
Hydrocarbons
.0544
.0134
0
.989
83.8
84.8
0
84.8
O
u
.332
.0906
0
3.3
0
3.72
0
3.72
rfl
01
•O
>,
•s
•o
,-1
<
.00883
.00109
0
.183
0
.193
0
.193
Total Air
pollutants
1.42
.254
0
75.6
84.7
162.
27.8
190.
Solids (tons/day)
386.
0
1.77
1980.
0
2370.
0
2370.
Land
«—
(n
•o v
0) t4
X O
•H (TJ
[K ---
15.
10.6
35.
330.
U
U
U
U
Incremental
(acres/year)
0
0
0
0
0
0
0
0
Total
(acres)b
747.
57.
189.
749.
2410.
4150.
8980.
13100.
Occupational
Health
Deaths/year
.483
0
0
U
0
U
.004
U
Injuries/year
11.
5.28
.545
U
.117
U
1.36
U
4J
W
S
tfl ^
>, as
m ,
i
c ^
n o>
E a
272.
128.
28.
U
2.73
U
31.9
U
Inputs
Water
(millions of
gallons/day)
0
0
0
25.
0
25.
0
25.
Nickel
(pounds/day)
0
0
0
>
.00411
0
.00411
0
.00411
NA = not applicable, NC = not considered, U = unknown.
a
For a synthane facility processing 22,550 tons per day; feeder and transmission pipelines require 62.5 feet of right-of-way and a 25 acre corapresser
station every 187 miles.
Time-averaged total land impact for the life of the facility.
MERES data for gathering pipelines is used.
d,
'Subtotal is for all residuals that will be produced at or near the mine. Transmission pipeline residuals will be spread over the length of the pipe-
line. Certain residuals, as for pumping stations, for example, could be localized.
-------
Table 14-2. Residuals of a Technological Alternative: Lurgi High-Btu Gasification
(2.62x!0li Btu's Per Day Output)
Activity/Process
MINING AND
RECLAMATION:
Strip 15° or
less slope
WITHIN OR NEAR MINE
T RANS PORT AT I ON :
Trucking
BENEFICIATION:
Breaking and
Sizing
PROCESSING/
CONVERSION:
Lurgi
T RANS PORT AT I ON :
Feeder Pipeline
d
Subtotal
TRANSPORTATION:
Transmission
Pipeline
TOTAL
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
NA
NA
HA
0
NA
0
NA
0
Organics
NA
NA
0
0
NA
0
NA
0
Total
0
0
0
0
NA
0
NA
0
Air Pollutants (Tons/day)
Particulates
.428
.00455
0
1.02
0
1.46
0
1.46
X
.526
.129
0
38.4
.802
39.9
27.8
67.7
CM
O
CO
.038
.00945
0
2.79
0
2.84
0
2.84
Hydrocarbons
.0526
.0129
0
.64
83.8
84.5
0
84.5
O
u
.32
.0875
0
2.13
0
2.54
0
2.54
Aldehydes
.00852
.00105
0
.146
0
.156
0
.156
Total Air
Pollutants
1.37
.245
0
45.2
84.7
131.
27.8
159.
Solids (tons/day)
372.
0
1.71
1860.
0
2240.
0
2240.
Land
Fixed
(acres)
15.
10.6
35.
330.
U
U
u
u
Incrementa 1
(acres/year)
0
0
0
0
0
0
0
0
[Total
(acres)
721.
55.3
182.
690.
2410.
4060.
8980.
13000.
Occupational
Health
Deaths/year
.466
0
0
U
0
U
.0039
U
Injuries/year
10.6
5.1
.526
U
.117
U
1.36
U
Man-Days Lost
per year
263.
123.
27.
U
2.73
U
31.9*
U
Inputs
Water
(millions of
gal Ions/day)
0
0
0
18.
0
18.
0
18.
Nickel
( pounds/day)
0
0
0
.004
0
,004
0
.004
NA = not applicable, NC = not considered, U = unknown.
aFor a Lurgi facility processing 23,654 tons per day; feeder and transmission pipelines require 62.5 feet of right-of-way and a 25 acre compressor station
every 187 miles.
Time-averaged total land impact for the life of the facility.
°MERES data for gathering pipelines is used.
Subtotal is for all residuals that will be produced at or near the mine. Transmission pipeline residuals will be spread over the length of the pipeline.
Certain residuals, as for pumping stations, for example, will be localized.
-------
Table 14-3. Residuals of a Locational Alternative: Synthane Facility Moved To Demand Center
(2.62X1011 Btu's Per Day Output)
Activity/Process
MINING AND
RECLAMATION:
Strip 15° or
leap slope
Within or Near Nine
TRANSPORTATION:
Trucking
BENEFICIATION:
Breaking and.
Sizing
Subtotal0
TRANSPORTATION:
Unit Traind
PROCESSING/
CONVERSION:
Synthane
TOTAL
Water Pollutants
(Tons/day)
"a
*~z
HOt
0) 0
fii
NA
NA
NA
0
NA
0
0
Organics
NA
NA
0
0
NA
0
0
Total
0
0
0
0
NA
0
0
Air Pollutants (Tons/day)
Particulates
.384
.00408
0
.388
10.6
5.83
16.9
X
8
.472
.116
0
.588
7.99
51.6
60.2
(N
O
U)
.0345
.00848
0
.043
6.95
4.32
11.3
Hydrocarbons
.0472
.0116
0
.0588
5.34
.857
6.25
8
.287
.0785
0
.366
7.49
2.86
10.7
Aldehydes
.00765
.000942
0
.0086
1.17
.159
1.34
Total Air
Pollutants
1.23
.22
0
1.45
39.6
65.5
107.
Solids (tons/day)
334.
0
1.53
336.
0
1720.
2050.
Land
Fixed
(acres)
15.
10.6
35.
60.6
U
330.
U
Incremental
(acres/year)
0
0
0
0
0
0
0
Total
(acres)
647.
49.7
163.
860.
82100.
649.
83600.
Occupational
Health
Deaths/year
.418
0
0
.418
81.9
U
U
u
ra
a
<•
in
o
•H
14
p
•r-t
C
H
9.51
4.57
.472
14.6
654.
U
U
4J
tn
s
01 h
>i ID
10 V
O" >,
C it
a it
X 0-
236.
110.
24.3
370.
6080.
U
U
Inputs
Water
(millions of
gallons/day)
0
0
0
0
0
9^.
25.
Nickel
(pounds/day)
0
0 .
0
0
0
. nrui i
.00411
NA o not applicable, NC = not considered, U = unknown.
aPor a Synthane facility processing 22,550 tons per day; train right-of-way is 6 acres per mile.
Time-averaged total land for the life of the facility.
cSubtotal is for the residuals that would be produced at or near the mine, unit train residuals would be spread over the route of the train. Processing/
Conversion residuals would be produced at the facilities site at or near the demand center.
T1ERES data are adjusted for mileage since those data are based on an average hauling distance of 150 miles. The assumed value here is 1,000 miles and
all coefficients, except those for occupational health, have been multiplied by 6.67.
-------
natural gas to be pipelined to Valdez.
Alaska, and transported from there to the
U.S. west coast by liquefied natural gas
(LNG) tanker; increased offshore production
of natural gas; and foreign LNG imports.
Together with coal gasification, these
appear to be the feasible alternative sup-
plies of large quantities of pipeline qual-
ity gas during the next 10 to 15 years.
The residuals associated with each of
the four source alternatives are identified
.and calculated in Tables 14-4 through 14-7.
The evaluation is on the basis of 250 irancf
per day, but neither Alaskan gas (either
through Canada or Valdez) nor foreign LNG
imports alternatives would be undertaken
on so limited a scale, primarily because
neither would be economical on this scale.
This consideration is discussed in Chapter
16.
14.3.5 Substitute Fuels Alternatives
Although not included in this demon-
stration, the procedures used to calculate
the residuals for technological, locational,
and source alternatives can be used to cal-
culate the residuals for substituting other
fuels for pipeline quality gas. In addition
to the data used in the examination of other
sources of pipeline quality gas, MERES and
the OU resource systems descriptions include
residuals data for coal, crude oil, natural
gas, and oil shale, and the OU descrip-
tions include some residuals data for geo-
thermal, nuclear fission, organic, electric
power generation, and conservation (con-
sumption) . However, substitute fuels are
not included in the demonstration of pro-
cedures presented in this chapter.
14.4 A DEMONSTRATION OF HOW TO COMPARE
THE RESIDUALS OF ENERGY ALTERNATIVES
Energy alternatives can be compared
on the basis of' the residuals they produce
in a variety of ways, ranging from a com-
parison of particular processes to a com-
parison of complete trajectories* and from
a comparison of particular residuals (such
as oxides of nitrogen) to categories of
residuals (air pollutants).** For illus-
tration purposes, the following comparisons
are made:
1. Totals by categories of residuals
for each of the seven trajectories
being evaluated (Table 14-8 and
Figures 14-1 and 14-2).
2. Totals by categories of residuals
on the basis of where the residuals
will be produced: at or near the
mine-site, over the length of the
transportation corridor, at or
near the demand center, etc.
(Table 14-9 and Figure 14-3).
3. Totals for specific residuals
for each of the seven trajectories
evaluated (Table 14-8 and Figures
14-4, 14-5, and 14-6).
4. Totals for specific residuals on
the basis of where the residuals
would be produced (Table 14-9
and Figure 14-7).
14.4.1 A Comparison of Residuals by
Category and Trajectory
Figures 14-1 and 14-2 indicate total
air emissions are highest for the offshore
natural gas source alternative. LNG imports
produce only small quantities of all residuals.
"Large quantities" does not refer to
the 250 mmcf per day for this specific case
but rather to the amount of pipeline qual-
ity gas that will be required in addition
to the amounts from current onshore and off-
shore domestic sources. At best, increased
onshore production is expected to be small,
and alternative synthetic sources are not
expected to be available in large quantities.
**
As noted earlier, data on other energy
resources will soon be added to MERES.
Although residuals can be combined
by category, they should be combined only
with great care since residuals within any
category, such as air pollutants, can vary
widely as to their potential effects.
**
Note that the "complete" trajectories
used here extend from extraction to placing
250 mmcf per day of pipeline quality gas in
the Pacific Northwest. These trajectories
could actually be extended to include end
uses such as residential space heating, for
example.
14-9
-------
Table 14-4. Residuals of a Source Alternative: Alaskan Natural Gas via Canadian Pipeline
(2.62xlQll Btu's Per Day Output)
Activity/Process
EXTRACTION:
Onshore
Extraction
NEAR SITE
TRANSPORTATION 8
Gathering
Pipeline
Subtotal0
TRANSPORTATION:
Transmission
Pipeline3
TOTAL
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
NA
NA
NA
NA
NA
Organics
NA
NA
NA
NA
NA
Total Water
Pollutants
NA
NA
NA
NA
NA
Air Pollutants (Tons/day)
Particulates
NA
0
0
0
0
X
9,
NA
.885
.885
123.
124.
CN
0
10
NA
0
0
0
0
Hydrocarbons
NA
92.5
92.5
0
92.5
8
NA
o
0
0
0
Aldehydes
NA
0
0
0
0
Total Air
pollutants
NA
93.5
93.5
123.
216.
"S
ID
Solids (tons/(
NA
NA
NA
NA
NA
Land
Fixed
(acres) a
1.
V
U
U
U
Incremental
(acres/year)
0
0
0
0
0
Total b
(acres)
250.
2660.
2910.
39600.
42500.
Occupational
Health
Deaths/year
.0329
.0004
.0333
,5174
.0507
Injuries/year
1,45
.129
1.58
6.
7.58
4J
tn
3
If) 14
>, m
re iu
P >,
C h
re m
£ D-
51.2
3.01
54.2
141. ,
196.
Inputs
r Water
(millions of
gallons/day)
U
0
U
0
U
Nickel
(pounds/day)
NA
NA
NA
s.
NA
NA
Nft =« not applicable, U - unknown.
aFor extraction, fixed represents acres per well, for the gathering and transmission pipeline, the right-of-way along the pipeline is 62.5 feet, and 25
acres are required for a compressor station every 187 miles.
bTime-increased total land for the life of the facility.
GSubtotal is for onshore extraction and gathering pipelines, residuals for which would occur at or near the extraction site.
dlt was assumed that MERES data were based on an average U.S. transmission distance of 500 miles. The value in this case was 2,000 miles, 1,500 miles
through Canada and 500 miles in the U.S.
-------
Table 14-5. Residuals of a Source Alternative: Alaskan Natural Gas via Alaskan Pipeline and LNG Tanker
(2.62X1011 Btu'a Per Day Output)
Activity/Process
EXTRACTION:
Unshotfe
Extraction
NEAR SITE
TRANSPORTATION:
Gathering Pipeline
Subtotal0
TRANSPORTATION:
Transmission
Pipeline
PROCESSING:
Liquefaction
TRANSPORTATION:
Liquid Natural
Gas Tanker
PROCESSING:
Storage
PROCESSING:
Vaporization
Subtotal
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
NA
NA
NA
NA
3.69
0
NA
NA
NA
Organics
NA
NA
NA
NA
NA
1.89
NA
NA
NA
Total Water
Pollutants
NA
NA
NA
NA
NA
1.89
NA
NA
NA
Air Pollutants (Tons/day)
Particulates
NA
0
0
0
0
.281
NA
.0515
.0515
X
NA
1.10
1.10
38.
127.
3.9
NA
.275
.275
CN
O
in
NA
0
0
0
0
3.01
NA
.00162
.00162
Hydrocarbons
NA
115.
115.
0
0
.138
0
.0216
.0216
8
NA
0
0
0
0
.0551
NA
.054
.054
Aldehydes
NA
0
0
0
0
.039
NA
.0297
.0297
Total Air
Pollutants
NA
116.
116.
38.
127.
7.41
NA
.432
.432
Solids (tons/day)
NA
NA
NA
NA
NA
NA
L NA
NA
NA
Land
Fixed a
(acres)
1.
U
U _,
U
250.
0
U
250.
U
Incremental
(acres/year)
0
0
,0 .„ ,
0
0
0
0
0
0
Total
(acres)b
31000.
3300.
34300.
12300.
1.64
53.3
205.
13.4
218.
Occupational
Health
Deaths/year
.0408
0
.0408
.0054
U
U
U
u
u
Injuries/year
1.8
.16
1.96
1.86
U
U
U
U
U
-u
in
O
>j
t/T M
>, ro
ro 0)
a >,
i
c ^
ro a)
s a
63.5
3.74
67.2
43.7
U
U
U
U
U
Inputs
Water
(millions of
gallons/day)
U
0
U
0
U
U
U
u
u
Nickel
( pou nd s /d ay )
NA
NA
_._NA
NA
NA
NA
NA
NA
NA
-------
Table 14-5. (Continued)
Activity/Process
TRANSPORTATION!
Transmission
Pipeline
TOTAL
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
HA
3.69
Organics
NA
1.89
1 Total Water
Pollutants
NA
1.89
Air Pollutants (Tons/day)
Particulates
0
.333
x
s
27.8
198.
fsl
O
w
0
3.01
Hydrocarbons
0
115.
8
0
.109
Aldehydes
0
.069
Total Air
Pollutants
27.8
317.
Solids (tons/day)
NA
NA
Land
Fixed
(acres)
U
U
Incremental
(acres/year)
0
0
Total
(acres)13
8980.
25100.
Occupational
Health
Deaths/year
.00394
U
Injuries/year
1.36
U
•M
m
O
J
in M
>1 HJ
ID O
Q >i
1
C H
S 8.
31.9
U
Inputs
water
(millions of
gallons/day)
U
U
Nickel
(pounds/day)
NA
NA
NA « not applicable, U *> unknown.
aFor extraction, fixed represents acres per well; for the gathering and transmission pipeline, the right-of-way along the pipeline is 62.5 feet, and 25
acres are required for compressor stations every 187 miles; the 250 acres represents the requirement for a typical port facility including docks, storage,
and liquefaction or vaporization.
Time-averaged total land for the life of the facility.
d,
Subtotal for onshore extraction and gathering pipelines, residuals for which would occur at or near the extraction site.
Subtotal for LNG storage and vaporization, residuals for Which would occur at or near the port site.
-------
Table 14-6.
Residuals of a Source Alternative: Offshore Natural Gas
(2.62x1011 Btu's Per Day Output)
Activity/Process
EXTRACTION:
Offshore
Extraction
NEAR SITE
TRANSPORTATION:
Gathering Pipeline
Subtotal3
TRANSPORTATION:
Transmission
Pipeline
TOTAL
water Pollutants
(Tons/day)
In
H 5
(8 CQ
6, ra
m
-------
Table 14-7. Residuals of a Source Alternatives Imported LNG
(2.62X1011 Btu's Per Day Output)
Activity/Process
TRANSPORTATION:
Liquefied Natural
Gas Tanker (LNG)
PROCESSING: LNG
Storage
PROCESSING: LNG
Vaporization
Subtotal0
TRANSPORTATION:
Transmission ,
Pipeline
TOTAL
Water Pollutants
(Tone/day)
n
3
»H JJ
n n
o o
£2
0
NA
NA
0
NA
0
Organics
.066
NA
NA
.066
NA
.066
Total Water
Pollutants
.066
NA
NA
.066
NA
.066
Air Pollutants (Tons/day)
Particulates
.009
NA
.0515
.0605
0
.0665
X
.125
NA
.275
.4
27.8
28.2
(M
O
in
.096
NA
.00162
.0976
0
.0976
Hydrocarbons
.0044
0
.0216
.026
0
.026
8
.00177
NA
.054
.0558
0
.0557
Aldehydes
.00124
NA
.0297
.0309
0
.031
Total Air
Pollutants
.237
NA
.432
.669
27.8
28.5
">
ID
Solids (tons/c
NA
NA
NA
NA
NA
NA
Land
Fixed
(acres)3
U
U
250.
250.
U
U
Incremental
(acres/year)
0
0
0
0
0
0
Total b
(acres)
51.1
205.
13.4
270.
8980.
9250.
Occupational
Health
Deaths/year
U
U
U
U
.004
U
Injuries/year
U
U
U
U
1.36
U
4J
01
O
J
en M
>, ro
(0 Q)
Q >.
1
c ^
m
-------
Table 14-8. Totals by Trajectory for Categories of Residuals
(2.62X1011 Btu's Per Day Output)
PROPOSED ACTION:
Synthane High-Btu
Gasification
TECHNOLOGICAL
ALTERNATIVE:
Lurgi High-Btu
Gasification
LOCATION
ALTERNATIVE :
Synthane Facility
at Demand Center
SOURCE ALTERNATIVE:
Alaskan Natural
Gas Pipeline
SOURCE ALTERNATIVE:
Alaskan Natural ua
Pipeline and Tanker
SOURCE ALTERNATIVE;
Offshore Natural
Gas
SOURCE ALTERNATIVE;
Imported Liquefiec
Natural Gas (LUG)
Water Pollutants
(Tons/day)
01
3
H 4*
rQ 0)
V O
g ~
0
0
0
NA
3.69
NA
0
Total Water
Pollutants
0
0
0
NA
1.89
NA
.066
Air Pollutants (Tons/day)
Particulates
7.18
1.46
16.9
0
.333
0
,065
X
88.8
67.7
60.2
124.
.198
31.
28.2
IN
O
tn
5.04
2.84
11.3
0
3.01
0
.098
Hydrocarbons
84.8
84.5
6.25
92.5
115.
340.
.026
8
3.72
2.54
10.7
0
.109
0
.056
Aldehydes
.193
.156
1.34
0
.069
0
.031
Total Air
Pollutants
190.
159.
107.
216.
317.
371.
28.5
Solids (tons/day)
2370.
2240.
2050.
NA
NA
NA
NA
Land
Fixed
(acres)
U
u
U
u
u
u
u
Incremental
(acres/year)
0
0
0
0
0
0
0
Total
(acres)
13100.
13000.
83600.
42500.
25100.
18800.
9250.
Occupational
Health
Deaths/year
U
U
U
.0507
U
.00799
U
Injuries/year
U
U
U
7.58
U
_ J..9S
U
4J
CO
O
ij
VI L4
>i 10
10 HI
Q ><
1
c n
m to
£ a
u
u
U
196.
U
47.
U_
Inputs
Water
(millions of
gallons/day)
25.
IB.
25.
U
U
u
u
Nickel
(pounds/day)
.00411
.00411
.00411
NA
NA.
NA
NA
NA = not applicable, U = unknown.
-------
AIR POLLUTANTS
TOTAL AIR POLLUTANTS
(tons /day)
_ ro OJ 4* C
o o o o c
o o o o o c
- ^^1 Particulates
" t';-fol Nitrous oxides
- V/^/\ Hydrocarbons
-
Other contr
• small qua
-
-
1 ^
-// y/
• *0 * * '• •
ibutors in
ntities
w,
I
> * •"•
* * • *
*• • *
I
* •"* '
• * • •
* . • •
• •
1
I
I
v>.
% * *
n
Synthane Lurgi Synthane at Alasken Alasken Nat. Offshore Imported
Demand Nat. Gas- Gas- Nat. Gas LNG
Center Pipeline Pipeline 8 Tanker
ALTERNATIVE
Figure 14-1. Totals by Trajectory for Categories of Residuals (Table 14-8)
-------
CO
O
2400
SOLIDS
2300
o
TJ
(O
C
O
. *•
2200
O
CO
2100
2000
Synthane Lurgi Synthane at
Demand Center
ALTERNATIVE
No solid residuals are produced by the
source alternatives.
Figure 14-2. Totals by Trajectory for Categories
of Residuals (Table 14-8)
-------
Table 14-9.
Totals by Location for Categories of Residuals
(2.62X1011 Btu's Per Day Output)
PROPOSED ACTION:
Syntnane High-Btu
Gasification
At or Near
Mine Site
Transportation
Corridor
TECHNoLOCICAl ""• '
ALTERNATIVE:
Lurgi High-Btu
Gasification
At or Near
Mine Site
Transportation
Corridor x
LOCATIONAL
ALTERNATIVE:
Synthane Facility
at Demand Center
At or Near
Mine Site
Transportation
Corridor
Demand Center
SOURCE
ALTERNATIVE :
Alaskan Natural
Gas Pipeline
At or Near
Extraction Site
Transportation
_ corridor
Water Pollutants
(Tons/day)
Thermal
(109 Btu's)
0
NA
0
NA
0
NA
0
NA
NA
Total Water
Pollutants
0
NA
0
NA
0
NA
0
NA
NA
Air Pollutants (Tons/day)
particulates
7.18
0
1.46
0
.388
10.6
5.83
0
0
X
61.
27.8
39.9
27.8
.588
7.99
51.6
.885
123.
fs
o
Ul
5.04
0
2.84
0
.043
6.95
4.32
0
0
Hydrocarbons
84.8
0
84.5
0
.059
5.34
.857
92.5
0
8
3.72
0
2.54
0
.366
7.49
2.86
0
0
Aldehydes
.193
0
.156
27.8
.009
1.17
.159
0
0
Total Air
Pollutants
162.
27.8
131.
27.8
1.45
39.6
65.5
93.5
123.
Solids (tons/day)
2370.
0
2240.
0
336^
0
1720.
NA
NA
Land
Fixed
(acres)
U
U
U
U
60.6
U
330.
U
U
Incremental
(acres/year)
0
0
0
0
0
0
0
0
0
Total
(acres)
4150.
8980.
4060.
8980.
860.
82100.
649.
2910.
39600.
Occupational
Health
Deaths/year
U
.004
U
.0039
.418
81.9
U
.0333
.0174
Injuries/year
U
1.36
U
1.36
14.6
654.
U
1.58
6.
4J
in
s
W> b
>. ro
m
-------
Table 14-9. (Continued)
SOURCE ALTERNATIVE:
Alaskan Natural
Gas Pipel ine and
Liquefied Natural
Gas Tanker (LNG)
At or Near
Extraction Site
Transportation
Corridor 1
Port Site 1
Transportation
Corridor 2
Port Site 2
T ransportation
Corridor 3
SOURCE ALTERNATIVE:
Offshore Natural
Gas
At or Near
Extraction Site
Transportation
Corridor
SOURCE ALTERNATIVE:
Imported Liquefied
Natural Gas (LNG)
Port Site
Transportation
Cornaor
Water Pollutants
(Tons/day)
"»>
3
rt 4J
ra to
E»
01 0
i-
NA
NA
3.69
0
NA
NA
NA
NA
0
NA
Total Water
Pollutants
NA
NA
NA
1.89
NA
NA
.0660
NA
Air Pollutants (Tons/day)
Particulates
0
0
0
.281
.0515
0
0
0
.06
0
X
1.1
38.
127.
3.9
.275
27.8
3.25
27.8
.4
27.8
CM
O
w
0
0
0
3.01
.002
0
340.
0
.098
0
Hydrocarbons
115.
0
0
.138
.022
0
0
0
.026
0
8
0
0
0
.005
.054
0
0
0
.056
0
Aldehydes
0
0
0
.039
.03
0
0
0
.031
0
Total Air
Pollutants
116.
38.
127.
7.41
.432
27.8
343.
27.8
.669
27.8
>,
rc
Solids (tons/c
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Land
, ID
ro a)
o >>
i
c ^
10 ai
E a
67.2
43.7
U
U
U
31.9
15.1
31.9
U
iU3. .
Inputs
Water
(millions of
ga 1 Ions /day )
U
0
U
0
U
0
U
0
U
0
Nickel
(pounds/day)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA = not applicable, U = unknown.
-------
350
300
250
o
T3
CO
C.
O
h-
z
<
h-
O
Q_
OC
200
150
100
50
0
.MS
TC
DC
MS
i
AIR POLLUTANTS
Particulates
itrous Oxides
Hydrocarbons
Sulfurous Oxides
Other contributors in
small quanities
At or Near Mine or
Extraction Site
Transportation Corridor
Demand Center
MS
TC
i
Synthane Lurgi Synthane at Alaskan Nat. Offshore
Demand Center Gas-Pipeline Nat. Gas
ALTERNATIVE
Figure 14-3. Totals by Location for Air Pollutants (Table 14-9)
-------
PARTICULATES
PARTICULATES ( tons /day)
C.\J
18
16
14
12
10
8
6
4
2
0
-
-
-
• * "•*
"•*• ? '
> • * •
*• • •
» • ••
1 * *•*•"
l
• • •
•" * *
vVj
£?
':'.'•'.
'* • * '
I * *•
* * • •
•" * •
* * '•
•* •
vV:
° •* * >
, * *•
t "•-:
• * • .
• * * •
• # •
. • * *
i1-- .^ •• i _ >
Synthane Lurgi Synthane at Alaskan Nat. Imported
Demand Center Gas-Pipeline LNG
and Tanker
ALTERNATIVE
Figure 14-4. Totals by Trajectory for Specific Air Pollutants (Table 14-8)
-------
(A
C
O
UJ
o
X
o
o
rr
h-
200
150
100
50
0
NITROUS OXIDES
'':V
Synthane Lurgi Synthane Alaskan Nat. Alaskan Nat. Offshore Imported
at Demand Gas-Pipeline Gas-Pipeline Nat. Gas LNG
Center and Tanker
ALTERNATIVE
Figure 14-5. Totals by Trajectory for Specific Air Pollutants (Table 14-8)
-------
HYDROCARBONS
o
T3
DO
a:
<
o
o
CL
oou
300
250
120
100
80
60
40
20
0
-
-
f
-
-
-
-
-
-
S3
• « ••*
* • * *
o ,• *
* ' (
•/•* \
V;.'
."•"••*
-*l
* • t°
• * t
»• .
;•:.'•
».* •**
* " .*.*
»• 0 i" '
'&
1 • » •
* r* * *
P
*:•'••
• o* •
* m •
• *» <
• •
* • »
•••••
•*•'.•!'
' *•*•"
•*••.
••'.',
;•:.
''•:'••.
E*
• • V
• * *.
• ff * •
* • »»
* * * 1
* *• * *
'.***•
• • • •
.';'..•
!•'. •
*.• •' *
' '.'•'
• ! * 9
•.*:
* * • *
'^
• * * •
.*• » *.
* *- "
•'.' .*
*•"" .
•* • *
> • •
» " * (
- » •
• 0 • •
• • *•
*••••*
'*,* • *
• • *
•'••::'
"• •• •
* * •
.';•.*
. • *
1 • .*'
* ^ •
• • V *
• :•'-'
• » a
.:».•
* • *•
" • *. o
."'* • •
• • *
• * •
•*** *
* •*» "
• « - <
* .* e.
:•«'••
• • • •
'•a * •
••*•*'
** • '
t^
?y
(t •_*
•• *;
• n • *
•. .
' •;"'
• •"•'.
•• '/ *
• • * ,
:'•*:
". • *
• • •'
•" • *
• « t
•'-:
• * • i'*
'.* • •
* • * *
• " •
r ' * ' *
'•*.*"
".* .* •*
• *• *.
• • *
i *'•
Synthane Lurgi Synthane at Alaskan Alaskan Nat. Offshore Imported
Demand Center Nat. Gas- Gas-Pipeline Nat. Gas LNG
Pipeline and Tanker
ALTERNATIVE
Figure 14-6. Totals by Trajectory for Specific Air Pollutants (Table 14-8)
-------
NITROUS OXIDES
125
100
^m^
O
•o
\
2 75
o
H"
CO
UJ
o
§ 50
CO
o
o:
z 25
o
_
-
-
~ RU:::-:| '
,-.0-..
-
t\t or Near Mine or
Extraction Site
~ E£^ Transportation Corridor
fJ^VV^
_ Kxxvl Demand Center
• • *»
*\»
','.'.'.
.•':
:&
••i"»
r- o •
gv;
••* •
*».v
**** *
V*-"J
*.?-
.v.v
•• . •,'
•» •
".• •
'.y
* *»*
••*•
^
o V
o* •
* @ i
n
•v-
'.'•'•'•
* * •
• • • *
m*'Z
^
^'p
Synthane Lurgi
r^1
ji
$§
^
^
^
^\
!
IT
f
'4
^
i'/)'.
W-
°o
J >-
' • tf •
ro':
• V
•'.' •.'(
>.J
o.
DO
Q>
1 *
"*»' ' '
> °(
'0*
!°?
^.
3^<
!^
^^
1
V0.
I
W\
'-_'o e
i
1
Synthane at Alaskan Nat. Offshore
Demand Center Gas-pipeline Nat. Gas
ALTERNATIVE
Figure 14-7. Totals by Location for Specific Air Pollutants (Table 14-9)
-------
primary because only those emissions that
would occur within the U.S. are reported
here.
14.4.2 A Comparison of Residuals by
Category and Location
Figure 14-3 indicates that air pollu-
tants are highest (300 tons per day) at the
extraction site of natural gas in Alaska
and offshore. The air pollutants are mostly
hydrocarbons.
14.4.3 A Comparison of Residuals by
Particular Residual and Trajectory
Figures 14-4, 14-5, and 14-6 indicate
that particulate emissions are highest for
the locational alternative (train transport
of coal). Nitrous oxide emissions are
highest for the Alaskan pipeline/tanker
transport source alternative. Hydrocarbon
emissions are highest for the offshore nat-
ural gas alternative. All types are lowest
for importing LNG, again because only a
portion of the trajectory is within the U.S.
14.4.4 A Comparison of Residuals by
Particular Residual and Location
Figure 14-7 indicates that nitrous
oxide emissions are highest along the
transportation corridor for the Alaskan
pipeline source alternative. They are
lowest at the extraction (mine) site for
the locational alternative. In general,
nitrogen oxides are highest wherever com-
bustion occurs (at the mine site for the
proposed action and technological alter-
native and at the demand center for the
locational alternative) and in all trans-
portation activities.
14.4.5 Summary
In Section 14.4, residuals of selected
alternatives have been calculated and com-
pared. Although these calculations'and
comparisons are only illustrations, they
show how MERES data and the data in Chapters
1 through 13 of this report can be used in
comparing energy alternatives. Chapters
1 through 13 can be considered as a catalog
from which an analyst can select residuals
data for individual technological activities
or combinations of technological activities.
Although the combinations or trajectories
used as illustrations here stop with the pro-
duction of a gaseous fuel. Chapters 1 through
11 can be combined with Chapter 12 to include
the generation of electricity. Also, data
contained in Chapter 13 permit calculations
of trajectories that include an end use.
14.5 SUGGESTIONS CONCERNING IMPACT ANALYSIS
The evaluation and comparison of energy
alternatives will be incomplete if they are
restricted to the kinds of residuals analysis
demonstrated to this point. To be complete,
evaluation and comparison should include an
effort to determine what the impact of re-
siduals will be. This involves relating
residuals to ambient conditions; that is,
impact analysis requires evaluating the
effect of residuals on environmental con-
ditions at the place where they occur.
Unfortunately, there are no obviously
correct procedures or method for conducting
this type of impact analysis.
The lack of a single analytical method
is not due to a lack of developmental
efforts.
Since the National Environmental Policy
Act (NEPA) became law, numerous attempts
have been made to develop a methodology for
environmental impact assessment. In a recent
review for the Environmental Protection
Agency (EPA), Maurice L. Warner and Edward
H. Preston (1974) found that impact assess-
ment methodologies can be divided into five
*Place or location in this sense goes
beyond the term site. Some residuals may
produce impacts that are, indeed, site-
specific, but others may produce local,
state, or even national impacts. The char-
acteristics of the residual dictate the scope
of the evaluation of its impact. This is
taken into account in the procedures sug-
gested here.
14-25
-------
types based on the way impacts are identi-
fied. They describe the five as (Warner
and Preston, 1974: 3-4):
1. Ad hoc. These methodologies pro-
vide minimal guidance to impact
assessment beyond suggesting broad
areas of possible impacts (e.g.,
impacts on flora and fauna, impacts
on lakes, forests, etc.), rather
than defining specific parameters
to be investigated. (For example,
Western Systems Coordinating Coun-
cil, 1971.)
2. Overlays. These methodologies rely
on a set of maps of environmental
characteristics (physical, social,
ecological, aesthetic) for a pro-
ject area. The maps are overlaid
to produce a composite character-
ization of the regional environ-
ment. Impacts are identified by
noting the impacted environmental
characteristics lying within the
project boundaries. (For example,
Krauskopf and Bunde, 1972; McHarg,
1969.)
3. Checklists. These methodologies
present a specific list of environ-
mental parameters to be investi-
gated for possible impacts but do
not require the establishment of
direct cause/effect links to pro-
ject activities. They may or may
not include guidelines on how pa-
rameter data are to be measured
and interpreted. (For example.
Adkins and Burke, 1971; Dee and
others, 1972 and 1973; Institute
of Ecology, University of Georgia,
1971; Arthur D. Little, 1971; Smith,
n.d.; Stover, 1972; Multiagency
Task Force, 1972; Tulsa District,
U.S. Army Corps of Engineers, 1972;
and Walton and Lewis, 1971.)
4. Matrices. These methodologies in-
corporate a list of project activ-
ities in addition to a checklist of
potentially impacted environmental
characteristics. These two lists
are related in a matrix which iden-
tifies cause/effect relationships
between specific activities and
impacts. Matrix methodologies may
specify which actions impact which
environmental characteristics or
may simply list the range of pos-
sible actions and characteristics
in an open matrix to be completed
by the analyst. (For example. Dee
and others, 1973; Leopold and others,
1971; Moore and others, 1969; and
Central New York Regional Planning
and Development Board, 1972.)
5. Networks. These methodologies work
from a list of project activities
to establish cause/condition/effect
networks. They are an attempt to
recognize that a series of impacts
may be triggered by a project
action. These approaches generally
define a set of possible networks
and allow the user to identify
impacts by selecting and tracing
out the appropriate project actions.
(For example, Sorensen, 1970: and
Sorensen and Pepper, 1973.)
Among these five, the most comprehensive
and systematic methodologies also tend to
be the most cumbersome and costly to use.
This is because any attempt to be compre-
hensive tends to reflect the complexity of
the task of relating residuals to the natural
setting and social system within which im-
pacts will occur. For example, in the matrix
approach, the tendency is to have extended
lists of the activities, processes, tech-
nologies, etc. that might produce impacts
as well as lists of the environmental char-
acteristics that might be impacted. Such an
approach often leads to unnecessary data and
analyses being included in impact statements.
Thus, the network or "relevance tree" offers
the best approach for a concise but adequate
impact assessment, and the following sug-
gestions generally fit into the network cat-
egory.
Analytical procedures should be as
simple and straightforward as possible but
should permit a response to the need for more
details and greater complexity when neces-
sary. That is, the amount of detail and
degree of complexity should build from the
less detailed and complex to the more de-
tailed and complex on the basis of analytical
need. This is in direct contrast to methods
or procedures that call for describing com-
plex activities, natural settings, and social
systems in advance of any actual analysis
*
of impacts.
The following suggestions are not in-
tended to be comprehensive. The objective
The level of detail required is prob-
ably directly related to the credibility of
the agency preparing the EIS; that is, agen-
cies which develop high credibility may be
able successfully to employ a more concise
approach to impact analysis than can agencies
with low credibility.
14-26
-------
is to suggest and illustrate an approach,
not to produce an analysis that will satisfy
all requirements of an adequate EIS. Al-
though categories of evaluative criteria
are suggested, no attempt is made to pro-
vide the detailed criteria appropriate for
an agency preparing an EIS.
The impact analysis suggested here
begins with the residuals data obtained
using the procedures described in Section
14.2. Since, as indicated earlier, this
type of analysis requires data not included
in either MERES or the OU descriptions, the
analysis requires that goals, objectives,
and evaluative criteria be made explicit.
Given the limitations imposed here, this
example cannot be that explicit and thus
can only provide general guidelines.
Residuals can be evaluated individually
or by categories: air pollutants, water
pollutants, solids, land, health and safety,
aesthetics, inputs, and outputs. Residuals
can impact individually or in combination
and directly or indirectly on two major
systems:
1. Natural setting: air, water, land,
and biological productivity and
diversity.
2. Social system: health, safety,
and welfare; economics; land use;
and the environment (e.g.,
aesthetics and recreation).
As indicated, these two impact categories
can be subdivided into a few major sub-
categories and, if need be, can be sub-
divided even further.
The criteria for evaluating the impact
of residuals on the natural setting and/or
the social system can be divided into at
least three general categories:
1. Legal requirements.
2. Scientific standards or expert
judgment.
3. Public acceptability as indicated
by public attitudes and/or reac-
tions.
Regardless of how it is conducted, an
impact analysis basically consists of in-
terrelating residuals, environmental char-
acteristics, and evaluative criteria.
Since no present or future method of impact
analysis is likely to eliminate all uncer- •
tainties, questionable judgments will con-
tinue to be made, regardless of the criteria
applied. As a consequence, analytical pro-
cedures should provide for broad partici-
pation, both to guard against inadequately
based judgments and to insure the broad
acceptibility (the legitimacy) of the
analytical results. To this end, the impact
analysis portion of an EIS should be pre-
pared by an interdisciplinary team of ex-
*
perts.
14.5.1 General Procedures
The first procedural step of an impact
analysis should be to determine whether
residuals would be generated in any location
that violate national, state, or local laws.
Since pollution standards vary by area as
well as discharge types and quantities, a
comparison of the allowable statute levels
with process estimates should determine
whether any obviously illegal impacts will
result. If so, then the proposed action
could be altered or the proposal withdrawn
before the expense of a complete impact
analysis is incurred.
Following this preliminary step, impact
analysis should proceed in two phases.
Phase I should attempt to identify potential
impacts as a basis for delineating the
ambient data required to determine actual
impacts. Phase II should attempt to deter-
mine the actual impacts. The sequence of
When there is a great deal of uncer-
tainty concerning the likely impact of a
significant residual or category of residuals,
public participation in the existing hearings
process may well be inadequate to legitimate
the team's analysis and the team may wish
to seek the advice of a consultive committee
whose membership should include both germane
expertise and interests. When such a com-
mittee is appointed, a variety o± interests
as well as expertise should be represented,
both to comply with the admonition to in-
crease public participation and as a means
of anticipating what is publicly acceptable.
14-27
-------
steps involved in each phase is shown dia-
grammatically in Figures 14-8 and 14-9.
In Phase I, each residual or category
of residuals to be evaluated should be re-
lated to the natural setting and the social
system to determine:
1. Whether the residual or category
of residuals would produce a pri-
mary impact.
2. If so, what ambient data would be
required to determine the signif-
icance of the impact in terms of
legal requirements, scientific
standards and expert judgments,
and public acceptability.
.The required ambient data should then
be collected. As the examples of ambient
data categories listed in Figures 14-8 and
14-9 indicate, these data can be quite
diverse, ranging across both the physical
and social spectra of the place of the pro-
posed action.
In Phase II, specific residuals or
categories of residuals should be evaluated
against specific ambient data, and the im-
pact of these residuals on the natural set-
ting or social system should be determined
on the basis of the specified evaluative
criteria (see Figure 14-8) . The quality
of judgments made at this procedural point
will depend directly on the quality and
breadth of the expertise built into the
interdisciplinary team responsible for pre-
paring the EIS. (At this point in the pro-
cedures, a broadly based consultive com-
mittee may be used to enhance the credibility
of evaluations and to legitimate the EIS
process.)
Note that the process is iterative.
For example, when a primary impact is iden-
tified, it should be subjected to both
Phase I and Phase II impact analyses. This
procedural step is intended to include
effects often called "secondary impacts"
in the analysis.
As a final step, residuals and impacts
of residuals should be evaluated to deter-
mine, if possible, whether there are likely
to be synergistic and/or additive impacts
when they are combined. Procedurally,
little more can be done than to suggest
that questions about these two possible
effects be raised explicitly during the
impact analysis. The attempt to evaluate
synergistic impacts should begin with a
review of the residuals to be produced rather
than with an extensive inventory of existing
ambient conditions. This review should
attempt to determine whether some of the
residuals, under certain conditions, might
produce significant synergistic impacts.
If so, then the next step is to determine
whether the synergistic-producing conditions
exist at the location where the residuals
will be produced.
Additive impacts, on the other hand,
will generally require that a point source
inventory be conducted to determine existing
ambient loadings. Also, such assessment
tools as diffusion models may be required
for these analyses.
Finally, the results of various impact
analyses should be compared on the bases of
specific impacts or impact categories and
partial or complete trajectories.
The suggested procedures for conducting
impact analyses can be summarized as in
Exhibit 2.
14.5.2 An Illustration of Impact Analysis
Two examples illustrate how to use the
suggested procedures for conducting impact
analyses: the impact of the water input
requirements for the Synthane and Lurgi
high-Btu coal gasification facilities and
the impact of the air pollutant residuals
produced by the same two processes. For
purposes of identifying ambient data, both
examples assume that the hypothetical gasi-
fication facility will be located near
Colstrip, Montana.
14-28
-------
Residuals
PHASE I IMPACT ANALYSIS
Potential Impact Required Ambient Data
Natural Setting
I. Air
2. Water
3. Land
4. Biological Productivity
a Diversity
Social Setting
I. Health, Safety, and
Welfare
2.Economics
3.Land Use
4. Environment
Climatology
Physiography
Geology and
Hydrology
Soils
Plant and Animal
Communities
Archaeology
Demography
Economics
Figure 14-8. Impact Analysis for Energy Alternatives, Phase I
-------
Residuals
Water
Inputs
PHASE
IMPACT ANALYSIS
Reo
uired Ambient Data
Climatology
Physiography
Geology and
Hydrology
Soils
Plant and Animal
Communities
Archaeology
Demography
Economics
Evaluative
Criteria
Legal
Requirments
Scientific
Standard and
Expert
Judgments
Public
Acceptability
Potential Impact
Natural Setting
I.Air
Z.Water
3. Land
4. Biological Productivity
8t Diversity
Social Setting
I. Health, Safety, and
Welfare
2. Economics
3. Land Use
4. Environment
Figure 14-9. Impact Analysis for Energy Alternatives, Phase II
-------
EXHIBIT 14-2
SUMMARY OF IMPACT ANALYSIS PROCEDURES
IDENTIFY UNLAWFUL EMISSIONS, AMBIENT CONDITIONS,
AND IMPACTS, AND COMPARE ALTERNATIVES
Determine whether there are residuals that,
regardless of where they occur, will
produce unlawful impacts.
Determine what the potential impacts of
residuals are likely to be and what
ambient data will be required to assess
actual impacts.
Using the ambient data collected, determine
impacts by evaluating residuals in relation
to specific natural setting and social
system conditions.
Attempt to determine whether there are
likely to be synergistic or additive effects,
Compare the impacts of alternatives on the
bases of particular impacts or impact
categories and partial or complete
trajectories.
14-31
-------
14.5.2.1 Impact of Particulates, Sulfur
Dioxide, and Nitrous Oxide
Emissions
Residuals data for Synthane (Table
14-1) and Lurgi (Table 14-2) are:
Residuals
Particulates
Sulfur dioxide
Nitrous oxide
Synthane
(tons per
day)
6.73
4.49
59.6
Following the procedures described
in Section 14.5.1, the analysis would be
as follows:
Step 1. Do residuals produce unlawful
impacts regardless of where
they occur? Although federal
standards have not been estab-
lished for coal gasifiers,
EPA's New Stationary Source
Emission Standards for Fossil
Fuel-Fired Steam Generators
can be used to illustrate
this procedural step. Table
14-10 gives the amounts and
types of expected emissions
from Synthane and Lurgi, none
of which would violate exist-
ing new source standards for
fossil-fired steam generators.
Step 2. What are possible impacts and
what ambient data are required
to assess them? The possible
impacts are summarized in
Table 14-11, and the impact
categories are shown in Fig-
ures 14-8 and 14-9. Many of
the potential impacts des-
cribed in Table 14-11 may be
insignificant, and most are
impossible to predict quan-
tatively. Not all the ambient
data tested in Table 14-11
has been collected, but the
procedures are illustrated
by an example: evaluation of
the impact of air residuals
on air quality.
Step 3. Determination of impacts. A
diffusion model of the site
could be developed to pre-
dict new ambient air concen-
trations . *
Bases for diffusion models and equa-
tions for predicting ambient air quality
can be found in Pasquill, 1962; Gifford,
1961; Miller and Holzworth, 1967; and Turner,
1969.
For stack gas emission control,
each of the technologies under
consideration employ an elec-
trostatic precipitator, a
Wellman Lord scrubbing unit,
and, for sulfur removal and
recovery, a Claus plant and
an ammonia still. As a re-
sult, emissions are low, av-
eraging an order of magnitude
less than new source emission
standards for power plants.
Thus, for the Montana location
(where other urban sources of
air pollutants are minimal),
the probability of exceeding
ambient air quality standards
is small. Consequently, a
site-specific diffusion model
(a process perhaps requiring
a consultant) may not be
needed. Approximations using
general formulas could sub-
stitute. One example is given
below.
Example:
For a particulate emission
of 6.73 tons per day (Synthane
facility. Table 14-1), ground
level concentrations are cal-
culated for the worst possible
meteorological conditions and
a stack height and downwind
distance combination yielding
the highest concentration.
Thus, the data in Table 14-12
represent the worst cases or
maximum possible concentrations
for various stack heights and
two wind speeds.
The EPA primary ambient
air standard for particulates
(40 CFR 50) sets an upper
limit of 75 micrograms per
cubic meter (annual geometric
mean). Since the instanta-
neous, worst case concentra-
tions presented in Table 14-12
exceed the standard, further
calculations were made.
Table 14-13 gives con-
centrations at various distances
downwind for a constant effec-
tive stack height of 328 feet
(100 meters) and windspeed of
6.7 miles per hour (mph) (3
meters per second). Results
indicate little chance in the
annual geometric mean exceed-
ing 75 micrograms per cubic
meter.
14-32
-------
TABLE 14-10
COMPARISON OF ENVIRONMENTAL PROTECTION AGENCY
SOURCE STANDARDS AND EXPECTED EMISSIONS
(POUNDS PER MILLION BTU'S INPUT)
Air Residual
Particulates
Sulfur dioxide
Nitrous oxides
Environmental
Protection Agency3
0.1
1.2
0.7
Synthane
0.026
0.017
0.230
Lurgic
0.004
0.011
0.154
aMaximum two-hour average source standard for burning solid fossil
fuel (40 CFR 60).
Daily energy inflow to the gasifier is 5-lSxlO11 Btu's.
cDaily energy inflow to the gasifier is 5.00x10 Btu's.
TABLE 14-11
POTENTIAL IMPACTS OF AIR POLLUTANTS AND AMBIENT DATA
REQUIRED TO EVALUATE THEM
Potential Impact Category and Subcategory
Ambient Data Required for Impact Evaluation
Air Quality
Exceed legal standards for ambient
conditions
Change in ambient air quality
Percent this new input is of all other
input
Quantity carried downwind
Aerosol3 formation
Water Quality and Quantity
Aerosols impinging on water bodies
Change in pH of rain
Change in pH of existing water bodies
Change in other water quality parameters
due to pollutants in rainout
Biological Communities and Diversity
Direct damage to species; relationship
of damaged species to food web
Reduction in crop growth and
productivity
Change in plant and animal diversity
Specific species possibly affected
Possible chemical and physical changes
in plant cells or interference with
plant enzyme system
Effect on biogeochemical cycles of
oxygen, sulfur, carbon, nitrogen,
phosphorus
Concentration of the pollutant at the
point of emission, other pollutant
sources, diffusion characteristics
at the site and surrounding area
(topography, velocity, direction of
prevailing wind, frequency and duration
of temperature inversions), existing
ambient air quality. Environmental
Protection Agency air quality standards
Amount of rain
Location and size of water bodies
(lakes, rivers, estuaries)
Water quality of existing water bodies
Other sources of water pollutants
Characterization of each ecosystem
present in terms of productivity,
diversity, bioenergetics
Species present and any data on their
tolerance levels
Identification of rare and endangered
species
14-33
-------
TABLE 14-11 (Continued)
Potential Impact Category and Subcategory
Ambient Data Required for Impact Evaluation
Land Use Patterns
Change in ecosystems due to plant,
animal, or crop damage
Relocation of suburbs away from
pollutant source
Economics
Material damage due to rainout
Environment
Smog formation
Increased dust in homes
Health and Safety
Respiratory ailment rate
Accident rate due to high carbon
monoxide levels
Current land use patterns
Population characteristics which may
stimulate changes
Experience in other areas
Content and diffusion characteristics
of the plume
Demographic characteristics of the
population—number of elderly people,
etc.
Past history in other places with the
expected ambient air quality in this
location
aAerosol refers to droplets of air pollutants in the air as when sulfur dioxide is con-
verted to sulfuric acid droplets.
TABLE 14-12
GROUND LEVEL AMBIENT AIR CONCENTRATIONS OF PARTICULATES FOR WORST CASES'
Combination Yielding Highest
Possible Concentrations
Effective Stack
Height*3 (feet)
98
164
230
328
492
656
Distance Downwind
(miles)
0.09
0.15
0.22
0.28
0.34
0.40
Ground Level Concentration
(Micrograms Per Cubic Meter)
Wind Speed of 6.7
Miles Per Hour
4,710
1,130
777
424
235
162
Wind Speed of 11.2
Miles Per Hour
2,826
678
466
254
141
97
Source: Calculated using Figure 3-51 of Turner (1969), p. 11.
aStack emission is 6.73 tons per day = 70.66x10 micrograms per second.
Effective stack height is actual stack height plus plume rise before leveling.
14-34
-------
TABLE 14-13
GROUND LEVEL AMBIENT AIR CONCENTRATIONS OF PARTICULATES
FOR TWO METEOROLOGICAL CONDITIONS*
Distance Downwind (miles)
0.09
0.19
0.62
0.93
3.11
6.21
31.07
Ground Level Concentration
(Micrograms Per Cubic Meter)
Stability Class Ab
0.1
235.0
70.6
0
0
0
0
Stability Class Db
0
0
23.5
94.2
153.0
77.7
9.4
Source: Calculated using Figures 3-5A and 3-5D of Turner (1969): 11 and 14.
aStack emission is 6.73 tons per day = 70.66x10 micrograms per second.
Class A refers to very unstable air; Class D is the neutral class, being
neither stable not unstable.
Step 4. Possible synergistic effects.
From a practical standpoint,
the question is not whether
interaction effects exist—
they almost certainly do—but
whether they are of sufficient
magnitude to cause impacts in
other categories.
The current level of un-
derstanding of synergistic
effects is minimal. For ex-
ample, nitrogen dioxide is
known to be the trigger for
the photochemical reactions
(with hydrocarbons) which pro-
duce smog. However, predicting
the extent of smog producing
reactions from residual data
is not yet possible. For in-
sight, data on the mean mixing
depths and history of inver-
sions at Colstrip, Montana
(Table 14-14) has been incor-
porated into the example ana-
lysis. The conclusion from
these data is that, since
ambient air quality concentra-
tions are predicted to be ac-
ceptable and dispersion po-
tential at the site is good,
smog will not be a significant
problem.
Step 5. Comparison of impacts of
alternatives. Air residuals
produced by both Lurgi and
Synthane are insignificant
on the basis of new source
standards. In all cases,
Lurgi produces lesser amounts
than does the Synthane process.
14.5.2.2 Impact of Water Inputs
Residuals from Tables 14-1 and 14-2
are:
1. Synthane: 25 million gallons of
water per day consumed.
2. Lurgi: 18 million gallons of water
per day consumed.
Following the procedures described in
Section 14.5.1 the analysis wtjuld be as
follows:
Step 1. Do residuals produce unlawful
impacts regardless of where
they occur? There are no non-
s±te specific laws governing
water use and consumption.
Step 2. What are possible impacts and
what ambient data are required
to access them? potential im-
pacts of increased water con-
sumption were evaluated against
the impact categories and a
partial list of impacts and the
14-35
-------
TABLE 14-14
FREQUENCY OF HIGH AIR POLLUTION POTENTIAL AT COLSTRIP, MONTANA
Data obtained from the Colstrip area during November 1971
to November 1972 were used to provide a measure of thermodynamic
stability and a means for characterizing atmospheric dispersion
potential. Vertical temperature profiles indicate that there
were 250 inversions during the year, an average of 18 per
month. Most of those inversions were short (lasting from
several hours to 24 hours), but 14 lasted for periods longer
than 24 hours. The short inversions were most common in August,
September, and October while those exceeding 24 hours occurred
during the winter months (seven in December, three in January,
and four in February). The longest inversion recorded during
the year lasted 67 hours and occurred in December. Data on tops
of ground-based inversions indicate the mean top of the inversion
occurs about 1,000 feet above the ground during the summer and
the fall tops may occur up to 3,000 feet above the ground.
Mean maximum mixing depths range from about 3,800 feet in
the winter to about 6,500 feet in the summer (Table 14-17). Fall
and spring seasons show means of 5,600 and 6,000 feet respectively.
In Table 14-15, the last column in the table provides mean mixing
depths as estimated by Holzworth (1971). This estimation of the mean
mixing depth is lower during the wintertime periods than the actual
measurements made at Colstrip during the one-year period.
Holzworth (1971) data on the frequency of high air pollution
potential (HAPP) caused by low mixing depth and light winds indicate
that from 1960 to 1965 the Colstrip region experienced no HAPP cases
occurring where wind speed was around 13.5 miles per hour. Mixing
heights less than 3,280 feet coupled with winds less than 9 miles
per hour lasting 2 days or more occurred about 70 times in the 5-year
period. Similar conditions lasting 5 days or more occurred about 10
times. These data indicate that southeastern Montana is in a region
which experiences extended periods of high air pollution potential.
Holzworth's calculations, however, were based mainly on information
gathered from weather stations in Wyoming where stagnant air masses
are somewhat more frequent. The data from Colstrip indicate that
this portion of southeastern Montana is a moderately good dispersion
region.
Source: Westinghouse, 1973: 2-12.
14-36
-------
TABUS 14-15
MID-AFTERNOON MIXING DEPTHS AT COLSTRIP
Month
December
January
February
'WINTER
March
April
May
SPRING
June
July
August
SUMMER
September
October
November
FALL
MEAN
Mixing Depth, feet
a
Maximum
6,770
6,770
6,770
6,770
6,770
6.770
6,770
6.770
6,770
6,770
6,770
6,770
6,770
6,770
6,770
6,770
NA
Mean
3,000
4,740
4,460
3,800
4,930
6,180
6,690
6,030
5,640
6,770
6,770
6,490
6,440
4,980
5,610
5,620
5,250
Minimum
0
0
0
0
1,870
3,770
5,770
3,800
3,370
6,770
6,770
5,640
4,170
1,970
500
2,210
NA
Mixing Depth, feet
Mean (Holzworth)
NC
NC
NC
2,950
NC
NC
NC
7,550
NC
NC
NC
8,860
NC
NC
NC
5,250
5,900
HA = not applicable, NC = not considered
Source: Westinghouse, 1973: 2-12.
aMaximum height of aircraft.
14-37
-------
TABLE 14-16
POTENTIAL IMPACTS OF WATER DEMAND
AND DATA REQUIRED FOR ITS EVALUATION
Potential Impact Category
Ambient Data Required
for Impact Evaluation
Water Quality and Quantity
Change in river flow
Change in quality parameters
Air Quality
Fogging and microclimate changes
due to thermal loading from
the evaporative cooling tower
Biological Productivity and Diversity
Changes in the river aquatic
communities and terrestrial
communities linked to the river
Land Use
If land use for agriculture or
urban areas is water dependent,
what changes could be expected?
River flow distribution through
the year
Present water quality of rivers
Temperature, humidity, dew point
distribution throughout the
year
Present aquatic and terrestrial
communities with emphasis on
terrestrial animal population
levels and their water needs
Present land use patterns and
their source and level of water
consumption
Present legal distribution of
the water
data required for their eval-
uation drawn (Table 14-16).
For example, only the impact
of direct water demand or
primary water demand on exist-
ing water quantity is consid-
ered. The ambient data col-
lected for this evaluation
are given in Table 14-17.
As indicated in Table 14-17,
see page 14-36, the consump-
tive use of surface water
dominates that of groundwater,
and surface water sources are
responsible for 98.6 percent
of that diverted. The great-
est diversion of water is for
irrigation of crops, and about
98 percent of the consumed
water is for irrigation. Only
a small quantity of ground-
water, less than one percent
of the total irrigation di-
version, comes from wells.
Step 3. Determination of impact.
Table 14-18 gives the percent
of each of the two river flows
required by the Synthane and
Lurgi processes. Percent of
existing consumption in
Montana is also given. Both
Synthane and Lurgi demand a
very small percent of the
Yellowstone River but a sig-
nificant percentage of the
Tongue River (7 to 10 percent).
When the Tongue River is at
low flow, the gasification
facility could conceivably
demand the entire flow. Con-
sequently, data on the season-
al flow of the river should be
obtained.
Step 4. Determination of synergistic
and additive effects. Impacts
in this category require
knowledge of the other uses
and demands on the river flow.
This information was not avail-
able.
14-38
-------
TABLE 14-17
AMBIENT DATA NEEDED TO EVALUATE IMPACT
OF WATER REQUIREMENT ON WATER QUANTITY
1. Surface Water Availability: Two rivers are close enough to Colstrip
to be water sources. The Yellowstone River has an annual average flow of 10,460
cubic feet per second. The Tongue River has an annual average flow of 405 cubic
feet per second with a range of 0 to 13,300 cubic feet per second (Westinghouse,
1973: 2-41; 2-46) .
2. Groundwater Availability: Within the Yellowstone Basin, river water
is virtually the sole source of water for all uses. In Rosebud County, ground-
water is available at less than 50 feet at rates between 50 and 500 gallons per
minute per well; however, this source is considered an extension of the river in
that depletion is recharged at the expense of river discharge, not by aquifers
fed from other sources. At locations three or more miles distant from the river,
soil infiltration rate ability is less than 0.05 mile per hour at saturation,
and availability per well is less than 50 gallons per minute, within the entire
Yellowstone Basin, groundwater is practical only for limited use (Westinghouse,
1973: 2-47).
3. Present Water Consumption and Diversion in Montana per year.
Use
Crop production
Public supplies
Industrial
Rural domestic
Stock
Volume (10 3 acre- feet)
Surface Water Groundwater
Diverted
10,000.0
79.0
169.0
1.0
18.0
Consumed
3,750.0
8.0
17.0
0.1
6.0
Diverted
45.0
33.0
31.0
11.0
20.0
Consumed
20.0
3.0
3.0
1.0
7.0
Total Water
Consumption
(percent)
98.8
0.3
0.5
0.0
0.4
Source: Westinghouse, 1973: 2-47.
TABLE 14-18
PERCENT OF RIVER FLOW AND CONSUMPTIVE
USE IN MONTANA REPRESENTED BY GASIFICATION WATER DEMAND
Gasification
Water Demand
(million gallons
Syn thane - 25
Lurgi - 18
Yellowstone Rivera
(percent)
0.37
0.27
b
Tongue River
(percent)
9.55
6.88
Current Consumptive
Use in Montana0
(percent)
0.73
0.53
Average flow of 10,460 cubic feet per second =6.757.2 million gallons per day.
Average flow of 405 cubic feet per second = 261.6 million gallons per day.
"current consumption of 3,812.100 acre-feet per year = 3,402.9 million gallons per day.
14-39
-------
Step 5. Compare alternatives. Gasi-
fication using the Lurgi
process consumes 18 percent
less water than gasification
using the Synthane process.
Both would exert a major de-
mand on the Tongue River flow
but a minor demand on the
Yellowstone River flow.
14.6 SUMMARY
Two levels of analysis (residuals and
impacts) have been described in this dis-
cussion of how to evaluate and compare
energy alternatives. As indicated, MERES
and the OU resource systems descriptions
provide the basic data required for cal-
culating and comparing residuals. The pro-
cedures presented in Sections 14.2 through
14.4 are a guide to systematic analysis at
this level. Impact analysis is of a higher
order and is much more difficult to achieve.
In Section 14.5, procedures were suggested
for progressing to this higher level of
analysis, employing a network or relevance
tree approach designed to contribute to the
systematic analysis of the impacts of the
residuals peoduced by energy alternatives.
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in Highway Decision Making, for the
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with the U.S. Department of Transpor-
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University, Texas Transportation
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Code of Federal Regulations (1973a) Title
40, Protection of Environment. Section
60, "New Stationary Sources."
Code of Federal Regulations (1973b) Title
40. Protection of Environment. Section
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Dee. Norbert, Janet K. Baker, Neil L.
Drobny, Kenneth M. Duke and David C.
Fahringer (1972) Environmental Evalu-
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Dee, Norbert, and others (1973) Planning
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Gifford, F.A. (1961) "Uses of Routine
Meteorological Observations for
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Hittman Associates. Inc. (1974 and 1975)
Environmental Impacts, Efficiency, and
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Holzworth, G.C. (1971) "Mixing Heights,
Wind Speeds and Potential for Urban
Air Pollution Throughout the Contiguous
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Institute of Ecology, University of Georgia
(1971) Optimum Pathway Matrix Analysis
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McHarg, Ian (1969) Design with Nature.
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14-41
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CHAPTER 15
PROCEDURES FOR COMPARING THE ENERGY EFFICIENCIES
OF ENERGY ALTERNATIVES
15.1 INTRODUCTION
Matrix of Environmental Residuals for
Energy Systems (MERES) and the University
of Oklahoma (OU) resource systems descrip-
tions provide two measures of the energy
intensiveness of a technology: primary
efficiency (the ratio of output to input
energy) and ancillary energy requirements
(the amount of energy required to fuel
*
trucks, power draglines, etc.). As shown
in Figure 15-1, primary efficiency (express-
ed as a percentage) measures the unavoidable
losses which all energy alternatives suffer
as a consequence of physical, thermal,
and/or chemical processes. Ancillary en-
12
ergy (reported in Btu's per 10 Btu's of
energy input) measures the direct energy
subsidy required to deliver energy from a
**
particular activity of process.
Neither primary efficiency nor ancil-
lary energy can be used as the single mea-
sure for comparing the energy intensiveness
of technologies. For example, there may be
no overall difference in terms of direct en-
ergy consumption between a technology that
has a high primary efficiency but requires
large amounts of ancillary energy and an
alternative technology that has a low pri-
mary efficiency but requires little ancil-
lary energy. Thus, in comparing alterna-
tives, an overall efficiency should be cal-
culated from the primary efficiency and an-
cillary energy requirements. In this cal-
culation, output energy is divided by total
input energy (including ancillary energy)
to obtain the overall efficiency. As ex-
pressed in Figure 15-1, overall efficiency
y ***
18 X + U'
Where energy for process heat is
taken from the fuel being processed (refin-
ery gas in a refinery or coal in a coal
gasification facility), it is calculated as
part of the primary efficiency, thus making
the process appear to be less efficient.
** . -
All energy alternatives are also sub-
sidized by the energy required to manufac-
ture materials and equipment (e.g., steel
and aluminum, and trucks and draglines).
Although a comprehensive calculation of en-
ergy efficiencies would require that these
materials and equipment subsidizes be taken
into account, adequate data are not avail-
able and they are omitted from the calcu-
lations made in this chapter. An increas-
ing number of researchers undertaking en-
vironmental and technology assessments now
advocate that all external inputs or sub-
sidies be evaluated on an energy basis
(Bayley, 1973; Boynton, 1974; Odum, 1973;
and Slesser, 1974).
Net energy analysis as introduced by
Howard T. Odum (1971) for impact assessment
is being evaluated by the Office of Planning
and Analysis of Energy Research Development
Administration (ERDA) (with the actual analy-
sis being done at Brookhaven National
Laboratory), the Office of Energy Policy of
National Science Foundation (NSF), and the
Office of Research and Development of the
Department of Interior. The ERDA, NSF, and
Interior studies are intended to provide a
systematic critique of Odum's work.
***In any calculation, the same energy
quality units should bemused. The quality
of energy is a measure of its ability to do
work. That is, one Btu of electricity can
do more work than one Btu of coal; thus,
electricity is a higher quality energy. As
a result, Btu's of electricity should not
be added to Btu's of coal, oil, or gas
without first converting the electricity by
the heat rate (approximately 10,500 Btu's
per kilowatt hour [kwh]) to the equivalent
quality.
15-1
-------
All Ancillary,
Material, and
Monetary Subsidies
Subsidies
from Natural
Ecosystems
Resource in
the Ground
Total Subsidy to Resource
Development2 A + B
Net Energy = Y-(A+ B)
Trajectory Activities:
Extraction, Transporting,
and Processing
Physical and
Thermodynamic
Losses
Figure 15-1. Energy Efficiency Measures
-------
The remainder of this chapter is a
demonstration of how energy efficiency data
in MERES and the OU resource systems de-
scriptions can be used to calculate and
compare the energy efficiencies of energy
alternatives. Procedures are suggested
that account for all external inputs (in-
cluding materials and equipment) in terms
of energy units.
15.2 GENERAL PROCEDURES FOR OBTAINING AND
USING ENERGY EFFICIENCY DATA
The steps for evaluating and comparing
efficiencies of energy alternatives are
essentially the same as those described in
Chapter 14 for residuals. They are:
1. Identify, describe, and calculate
energy efficiencies for the pro-
cess, activity, partial trajectory,
or trajectory to be evaluated and
compared.
a. Identify the alternative activi-
ties and/or processes to be
evaluated and compared by re-
ferring to Figure 1 in the appro-
priate chapter(s) of the OU re-
source system description.
b. Access the MERES data by means
of the computer programs de-
scribed in Broolchaven1 s Users
Manual (1975). This will pro-
vide a printout of the primary
efficiency and ancillary energy
for each process, activity, par-
tial trajectory, or trajectory
for which a request is entered.
Ancillary energy requirements
will be calculated for the size
of operation specified in the
request. For example, the ancil-
lary energy requirement for gasi-
fying 10l2 Btu's of coal in a
Lurgi low-gas unit is 27.8xl09
Btu's (see Chapter 1). For a
Lurgi facility synthesizing 250
million cubic feet (mmcf) of
low-Btu gas a day, the ancillary
energy requirement is 1.83x10"
Btu's per day.* Note that all
ancillary energies given in
MERES and OU data have been con-
verted to the same energy quality.
*250xl06 cubic feet (cf) x 200 Btu's
per cf = 5xl010 Btu's out as gas. 5x10 J-"
Btu's divided by 0.758 primary efficiency -
6.6xl010 Btu's input as coal. If 27.8x10^
Btu's are required to process lO-1-^ Btu's of
coal, then 1.83xl09 Btu's are required to
process 6.6xl010 Btu's.
c. To obtain supplemental data in-
cluded in the OU descriptions,
to obtain information on the
assumptions made concerning the
efficiency data, and to obtain
descriptions of the type ancil-
lary energy required, read the
sections on "Energy Efficiencies"
that follow the process descrip-
tions in the OU resource systems
descriptions. Information on
assumptions can also be obtained
from the MERES when footnotes
are requested with the efficiency
data.
d. For those resource systems not
included in MERES, obtain effi-
ciency data from the "Energy
Efficiencies" sections of the
OU resource systems descriptions.
The size of operations to be
compared should be specified
and adjustments in ancillary en-
ergy made accordingly.
e. Calculate an overall efficiency
for each process, activity, par-
tial trajectory, or trajectory
and list primary efficiencies,
ancillary energies, and overall
efficiencies for each.
(1) To calculate the primary effi-
ciency of a trajectory, mul-
tiply all process primary
efficiencies together. Exclude
the recovery efficiency (the
primary efficiency for extrac-
tion) which is the amount of
energy not recovered from the
mine or reservoir. For exam-
ple, an underground coal
mining recovery efficiency of
57-percent or an oil reservoir
recovery efficiency of 30-per-
cent is not a measure of over-
all energy intensiveness or
consumption.
(2) To calculate the ancillary
energy requirement for a tra-
jectory, add the ancillary
energy requirements for all
processes. Remember that
ancillary energies are first
converted (from those in the
data base) to correspond to
the size of operation speci-
fied.
(3) To calculate an overall effi-
ciency for a process, add the
ancillary energy value to in-
put energy value and divide
the resulting sum into the
amount of energy output from
the process.
(4) To calculate a trajectory's
overall efficiency, multiply
all process overall efficien-
cies together.
15-3
-------
2. Make the desired comparisons.
Comparisons of energy efficiencies
for energy alternatives should be
made based on:
. a. Primary efficiencies, ancillary
energy requirements, and overall
• efficiency for processes.
b. Primary efficiencies, ancillary
energy requirements, and overall
efficiency for the trajectory.
3. At this point, specify some cri-
teria for feasible alternatives,
thus narrowing the total number
to be compared. Chapter 14 gives
examples of criteria.
These three procedural steps for eval-
uating and comparing the energy efficiencies
of energy alternatives are summarized in
Exhibit 15-1. These procedures are appli-
cable for comparing technological, loca—
tional, source, and substitution alterna-
tives. The implications of energy effi-
ciencies for energy development are dis-
cussed in Section 15.5.
15.3 A DEMONSTRATION OF HOW TO CALCULATE
ENERGY EFFICIENCIES
Primary efficiencies, ancillary energy
requirements, and overall efficiencies are
given for each activity for the proposed
action and each of the six alternatives to
the proposed action in Tables 15-1 through
15-7. In addition, pertinent information
and assumptions relating to the data (as
discussed in the "Energy Efficiencies"
sections which follow the process descrip-
tions Chapters 1 through 13) are listed.
Table 15-8 gives trajectory totals for the
seven alternatives. Each trajectory de-
livers 2.62X1011 Btu's per day (or 250 mmcf
at 1,050 Btu's per cf) to the consumer.
15.3.1 The Proposed Major Federal Action
As noted in Chapter 14, MERES data
are based on configurations that may differ
from that proposed for a particular action.
These data are, in a sense, averages. Con-
sequently, when calculations are made for
For convenience, these tables have
been placed where they are explained in
the text.
a proposed action, they should be based on
the configuration proposed; for example,
the particular sulfur recovery process,
stack gas cleaner, wastewater unit processes,
etc. to be used (see Section 14.3.1). For
this demonstration, data were taken from the
OU descriptions and are presented in Table
15-1 for each activity in the trajectory.
The following information pertains to
the data in Table 15-1:
1. Ancillary energy is zero for high-
Btu gasification because process
heat requirements are generated
on-site using some of the coal.
The loss is reflected in the pri-
mary efficiency.
2. The ancillary energy for extrac-
tion is about half diesel fuel and
half electricity.
3. The ancillary energy for trucking
is supplied by diesel fuel and
represents an average haul dis-
tance of 1.5 miles.
4. The ancillary energy for breaking
and sizing is about 80 to 85 per-
cent as electricity and 15 to 20
percent as oil.
5. Ancillary energies for pipeline
gathering and distribution are
zero because part of the gas is
used for the compressors with the
loss being reflected in the pri-
mary efficiency.
15.3.2 A Technological Alternative
In addition to Synthane, four high-Btu
gasification alternatives are discussed in
the OU descriptions. Only one, Lurgi, is
used here as an example. Efficiency data
for the trajectory that includes the Lurgi
process are given in Table 15-2.
Concerning the data in Table 15-2,
note that:
1. The same five facts listed above
for the proposed action data in
Section 15.3.1 apply to the data
in this trajectory.
2. Although the table indicates that
Lurgi is a more efficient process
than Synthane, the level of data
accuracy (error less than 25 per-
cent, Hittman, 1975 Vol. II) may
mean that the difference is not
real.
15-4
-------
EXHIBIT 15-1
SUMMARY PROCEDURES FOR EVALUATING AND COMPARING THE ENERGY
EFFICIENCIES OF ENERGY ALTERNATIVES
STEP
I
IDENTIFY, DESCRIBE, AND CALCULATE EFFICIENCIES
Identify the alternatives to be evaluated
by referring to the technologies flow
charts in the OU description.
Obtain efficiency data from MERES and/or
the OU descriptions.
Summarize and tabulate all efficiency data
for each alternative to be evaluated,
calculating the overall efficiency.
STEP
II
COMPARE ALTERNATIVES
Compare primary efficiencies, ancillary
energy requirements, and overall
efficiencies.
Compare either processes or complete
trajectories.
15-5
-------
TABLE 15-1
EFFICIENCIES OF THE PROPOSED ACTION:
SYNTHANE HIGH-BTU GASIFICATION
Activity
Extraction
Mine transportation
(trucking)
Breaking and sizing
High-Btu gasification
Pipeline gathering
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
NA
100.0
100.0
58.4
89.2
97.1
50.5
Ancillary
Energy3
(Btu's)
1.02xl09
O.lOOxlO9
1.13xl09
0
0
0
2.25xl09
Overall
Efficiency
(percent)
NA
100.0
99.8
58.4
89.2
97.1
50.4
NA = not applicable
on a trajectory outflow of 2.62x10
nsncf per day.
Btu's per day or 250
TABLE 15-2
EFFICIENCIES OF A TECHNOLOGICAL ALTERNATIVE:
LURGI HIGH-BTU GASIFICATION
Activity
Extraction
Mine transportation
(trucking)
Breaking and sizing
High-Btu gasification
Pipeline gathering
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
NA
100.0
100.0
60.5
89.2
97.1
52.4
Ancillary
Energya
(Btu's)
0.985xl09
0.097xl09
1.09xl09
0
0
0
2.18x109
Overall
Efficiency
(percent)
NA
100.0
99.8
60.5
89.2
97.1
52.2
NA = not applicable
^ased on a trajectory outflow of 2.62x10 Btu's per day or 250
mmcf per day.
15-6
-------
TABLE 15-3
EFFICIENCIES OF A LOCATIONAL ALTERNATIVE:
SYNTHANE FACILITY MOVED TO DEMAND CENTER
Activity
Extraction
Mine transportation
Breaking and sizing
Unit train transportation
High-Btu gasification
Trajectory
Primary
Efficiency
(percent)
NA
100.0
100.0
100.0
58.4
58.4
Ancillary
Energya
(Btu's)
0.884xl09
0.087xl09
0.982xl09
29.6xl09
0
31.6xl09
Overall
Efficiency
(percent)
NA
100 . Ob
99.8
93.8
58.4
54.5
NA = not applicable
Tiased on a trajectory outflow of 2.62x10 Btu's per day or 250 mmcf
per day.
The exact efficiency is 99.96 percent because there is a 0.04 percent
loss during transport.
15.3.3 A Locational Alternative
The high-Btu gasification facility can
be located at the demand center, in which
case the coal is transported from the mine
to the processing plant and transmission of
the natural gas is not required. Energy
efficiency data for the locational alterna-
tive are given in Table 15-3.
For the data in Table 15-3:
1. The facts listed as numbers 1
through 4 in Section 15.3.2 apply
to this trajectory.
2. Unit train transportation is
assumed to be over a distance of
1,000 miles.
3. The primary efficiency of a unit
train reflects wind losses.
15.3.4 Source Alternatives
An alternative to producing synthetic
gas from coal is to obtain more natural gas
frorr. natural reservoirs. However, increased
onshore production does not appear to be a
feasible alternative. The alternatives con-
sidered here are: Alaskan natural gas piped
directly to the U.S. via Canadian pipeline
or liquefied and shipped by tanker from
Valdez; increased offshore production of
natural gas; and imported liquefied natural
gas (LNG). Tables 15-4 through 15-7 give
the efficiency data for the activities in
each of these processes.
Pertinent information about the data
in Tables 15-4 through 15-7 includes:
1. The primary efficiency of natural
gas extraction reflects losses
due to escaping gas.
2. The primary efficiencies for
storage and pipeline distribution
reflect the use of part of the gas
as fuel for compressors.
3. The primary efficiencies for lique-
faction and vaporization reflect
the use of part of the incoming
gas to fuel the vaporizer and
liquefaction plant.
4. Ancillary energy for tanker trans-
port of LNG is diesel fuel.
15.3.5 Substitute Fuel Alternatives
Although not included here, the energy
efficiencies for substituting other fuels
for pipeline quality gas could also be cal-
culated using the procedures described
above.
15-7
-------
TABLE 15-4
EFFICIENCIES OF A SOURCE ALTERNATIVE:
ALASKAN NATURAL GAS VIA CANADIAN PIPELINE
Activity
Extraction-onshore
Gathering pipeline
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
NA
89.2
88.0
78.5
Ancillary
Energy3
(Btu's)
0
0
0
0
Overall
Efficiency
(percent)
NA
89.2
88.0
78.5
NA = not applicable
eased on a trajectory outflow of 2.62x10 Btu's per day or 250 mmcf
per day.
TABLE 15-5
EFFICIENCIES OF A SOURCE ALTERNATIVE:
ALASKAN NATURAL GAS VIA ALASKAN PIPELINE AND LNG TANKER
Activity
Extraction -onshore
Gathering — pipeline
Transmission — pipeline
LNG liquefaction
LNG tanker transportation
LNG storage
LNG vaporization
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
NA
89.2
97.1
83.0
92.5
100.0
98.0
97.1
63.3
Ancillary
Energy3
(Btu's)
0
0
0
0
14.5xl09
0.77xl09
0. 20x10 9
0
15.4xl09
Overall
Efficiency
(percent)
NA
89.2
97.1
83.0
88.2
99.7
97.9
97.1
61.0
NA = not applicable
,11
HBased on a trajectory outflow of 2.62x10 Btu's per day or 250 mmcf
per day.
15-8
-------
TABLE 15-6
EFFICIENCIES OF A SOURCE ALTERNATIVE: OFFSHORE NATURAL GAS
Activity
Extraction-offshore
Pipeline gathering
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
NA
88.0
97.1
85.4
Ancillary
Energy3
(Btu's)
0
0
0
0
Overall
Efficiency
(percent)
NA
88.0
97.1
85.4
NA = not applicable
^ased on a trajectory outflow of 2.62x10 Btu's per day or 250
mmcf per day.
TABLE 15-7
EFFICIENCIES OF A SOURCE ALTERNATIVE: IMPORTED LNG
Activity
LNG tanker on
U.S. coastal waters
Storage — LNG tank
LNG vaporization
Pipeline distribution
Trajectory
Primary
Efficiency
(percent)
96.4
100.0
98.0
97.1
91.7
Ancillary
Energya
(Btu's)
6.94xl09
0.77xl09
0.20xl09
0
7.91xl09
Overall
Efficiency
(percent)
94.1
99.7
97.9
97.1
89.3
on a trajectory outflow of 2.62x10 Btu's per day or 250
mmcf per day.
15.4 A DEMONSTRATION OF HOW TO COMPARE
THE EFFICIENCIES OF ENERGY
ALTERNATIVES
Efficiency data for the proposed ac-
tion trajectory and six alternatives are
summarized in Table 15-8 and compared
graphically in Figure 15-2. The high en-
ergy cost of converting coal to natural gas
is evident. Primary efficiencies range
from 63 to 92 percent for alternative
sources of natural gas. The most efficient
is imported gas because that trajectory be-
gins in U.S. ports and does not include ex-
traction or transportation to the U.S.
Ancillary energy requirements are
highest for trajectories involving trans-
portation over long distances other than by
a pipeline. The train transport of coal in
the locational alternative and the tanker
transport of LNG from Alaska raises the
Q
trajectory ancillary energy to 31.6x10 and
15.4x10 Btu's respectively. Since 2.62x10
Btu's of natural gas are delivered at the
end of the trajectories, these ancillary en-
ergy requirements represent 12.1 percent
and 5.9 percent of delivered energy re-
spectively.
15-9
-------
EFFICIENCIES
1 UU
80
60
K
Z
LU
o 40
LU
20
r\
-
•
r-;
3S
Primary Efficiency
Overall Efficiency
-
-
—
—
:':•:
:'•'.;.
P
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11 "n;
.«.b •.<
A' i
1
i
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o1.0.-'.'
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•'"•'a
prt
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'•:•.''.•:•'
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illf
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•'•""',
Synthane Lurgi Synthane Alaskan Alaskan Offshore Imported
at Demand Nat. Gas- Nat.Gas- Nat. Gas LNG
Center Pipeline Pipeline
and Tanker
ALTERNATIVE
Figure 15-2. Comparison of Energy Efficiencies
-------
TABLE 15-8
ENERGY COST OF DELIVERING 2.62xl012 BTU'S OF NATURAL GAS
USING SEVEN ALTERNATIVE TRAJECTORIES
Trajectory
Synthane high-Btu
gasification
Lurgi high-Btu
gasification
Synthane facility
at demand center
Alaskan natural gas —
pipeline
Alaskan natural gas —
pipeline and LNG tanker
Offshore natural gas
Imported LNG
Primary
Efficiency
(percent)
50.5
52.4
58.4
78.5
63.3
85.4
91.7
Ancillary
Energy
(109 Btu's)
2.25
2.18
31.6
0
15.4
0
7.91
Overall
Efficiency
(percent)
50.4
52.3
54.6
78.5
60.1
85.4
89.2
Overall efficiencies follow the same
pattern as primary efficiencies, with con-
version of coal to natural gas being less
efficient than direct production of natural
gas. The large ancillary energy require-
ments for the locational alternative (train
transport of coal) and the Alaska-LNG tanker
alternative depress the overall efficiencies
of these two trajectories.
The appendix to this chapter suggests
methods for using Odum's energy accounting
approach to extend the analysis of energy
efficiency beyond what has been discussed
above. References for both the chapter and
the appendix follow the appendix.
15-11
-------
APPENDIX TO CHAPTER 15
SUGGESTIONS CONCERNING IMPACT ANALYSIS
A.I INTRODUCTION
The ancillary energies given and com-
pared in the preceding sections of this
chapter are only those used directly in
each activity. As noted earlier, this rep-
resents only part of the total subsidy to
the trajectory. In the development and
operation of any activity, energy is uti-
lized in constructing the equipment, sup-
porting the people and supply systems, pro-
viding the raw materials other than energy
(such as water and catalysts), and sup-
porting the research for its development.
These are all subsidies from other fuel
sectors to developing and operating the
process. At present, all nonfossil fuel
energy resources require fossil fuel sub-
sidies to provide the technology, machines,
and direct ancillary energy for their de-
velopment. Many new forms of energy are,
in effect, low-grade because we have to
drill or dig deeper, go offshore, or con-
centrate dilute forms. Thus, there is in-
creasing interest in evaluating these
sources in terms of how much energy is re-
quired to deliver the product to the con-
*
sumer.
A.2 CATEGORIES OF EXTERNAL INPUTS
There are two principal categories of
external inputs or "subsidies" in the de-
velopment of an energy resource. The first
includes the ancillary energy as well as
Recall that this approach, pioneered
by Howard T. Odum (1971), is currently
being systematically evaluated by ERDA,
NSF, and Interior.
material requirements. The second includes
the required inputs from the natural sector
which allow for resource development.
Material and capital requirements are
most often measured in terms of economic
costs. However, estimates of the energy
values (in Btu's) of these inputs can be
determined by evaluating the fuels needed
for manufacturing materials and by trans-
forming the dollar cost of items and activi-
ties into energy units.
Table A-l gives examples of the Btu
content of selected materials. (Details on
the development of these types of figures
can be found in Berry and Pels, 1972 and
Makino and Berry, 1973.) A preliminary
estimate of Btu's expended per dollar cost
can be obtained by dividing total U.S.
energy consumption by the Gross National
Product in a given year. (The Btu-to-dollar
conversion in 1973 was 68,000 Btu's per
dollar and in 1958 was 93,000 Btu's per
dollar [Klystra, 1974].) This value can
be used when the cost item covers a spec-
trum of activities. For example, explora-
tion includes personnel, equipment, informa-
tion, and fuel. In addition, the Office of
Energy Research and Planning of the State of
Oregon has developed estimates for some spe-
cific categories of activities. These are
given in Table A-2. Oregon's Office of
Research and Planning recently calculated
net energy for 14 energy supply trajectories
(Oregon Office of Research and Planning,
1974).
When the external inputs from nature
are added, the accounting of subsidies is
completed. The natural systems which are
A-15-12
-------
TABLE A-l
EXAMPLES OF ENERGY CONTENT OF MATERIALS
Material
Energy Content
(106 Btu's per ton)
Carbon steel: forged
pipe
Alloy steel: forged
pipe
Stainless steel: forged
pipe
Iron casting
Aluminum-forged
Copper-rolled
Zinc-rolled
Nickel
Lead
Paper
76.0
52.6
78.6
55.2
102.1
78.7
25.0
75.0
128.0
79.2
374.7
31.1
40.6
Source: Oregon Office of Research and Planning, 1974:
~
TABLE A-2
ENERGY VALUE OF A DOLLAR IN 1973 FOR SEVERAL
CATEGORIES OF MATERIALS
Material
1973 Btu's per dollar
General industrial machinery
(16 categories including
pumps, compressors,
transmission lines)
Construction machinery
(18 sectors including mining
equipment, and oil field
equipment)
Engines and turbines
Petroleum—diesel
(purchases by 10 manufacturing
sectors)
Natural gas
(purchases by 10 manufacturing
sectors)
49,955
43,800
40,900
1,000,000
1,717,000
Source: Oregon Office of Research and Planning, 1974: 203.
The numbers for 1973 were updated from 1967 data. They assume that
Btu consumption per unit product has remained fairly constant; thus,
Btu-per-dollar changes from year to year are caused by inflation.
Since the ratio changes slightly each year, this ratio should be used
for 1973 dollars only.
A-15-13
-------
stressed by resource development have an
energy value. They are part of man's life
support because they produce useful pro-
ducts and recycle wastes, without economic
cost. Only when the biosphere is over-
stressed does society realize the existence
of such natural services, as the recycling
of sewage and the absorption and dilution
of air pollutants. Nature also provides
water supply systems, microclimate control,
and recreational and aesthetic opportunities.
Recently, society has had to funnel large
amounts of money and energy into so-called
"environmental technology" to help the
natural system absorb residuals. Thus, the
loss of parts of natural ecosystems due to
the development of an energy activity is an
energy cost or subsidy. This too must be
subtracted from the gross energy to obtain
net energy available to society over and
above the expenditures and losses in free
services. Examples of changed natural en-
ergy value due to energy development are:
*
the land taken out of biological production
during strip mining, decreased production
due to plant damage from air pollution, and
the change in aquatic production due to
wastewater disposal.
An analysis that includes all these
external inputs (as represented in Figure
A-l) has been called an "energy cost/benefit
analysis" (Odum, 1974a). Examples of using
this type of analysis for evaluating alter-
native energy sources are: Lent and others,
1974, "Some Considerations that Affect the
Net Yield from Nuclear Power;" Ballantine,
1974, A Net Energy Analysis of Surface
Mining. Electrical Power Production, and
Coal Gasification; and Odum, 1974b, "Energy
Cost/benefit Approach to Evaluating Power
Plant Alternatives."
A.3 AN ILLUSTRATION OF ENERGY ACCOUNTING
The technology alternative, which in-
cludes a Lurgi high-Btu gasification facility
The rate at which solar energy is
stored by the photosynthetic activity of
plants.
located at the strip mine in Colstrip,
Montana, was chosen for this illustration.
High-quality energy in the form of petro-
leum, electricity, and machinery is required
to deliver the synthetic gas to the consumer
and reclaim the land. In addition, the
land produced crops and supported livestock
before being disturbed. These external
inputs to the trajectory are summarized in
Table A-3. As indicated in that table, the
energy subsidy for delivering 262 billion
Btu's of energy as high-Btu gas to the
customer is 28.21 billion Btu's.
The first column in Table A-3 repre-
sents the ancillary energy calculated from
MERES data. For the trajectory evaluated,
ancillary energy is a small portion (6.8
percent) of the total energy subsidy. The
second column represents energy required
in constructing facilities, manufacturing
materials, and supporting the labor force
required by each activity. Exploration
activity includes the energy cost of ex-
ploring, testing, siting, land leasing, and
initial clearing. For extraction, the value
represents the energy cost of reclamation
(estimated at $10,000 per acre) and of con-
structing the equipment for large strip
mining operations (see Table A-l for exam-
ples of energy cost of material construction)
Cleaning and gasification values represent
construction materials, materials hauling,
maintenance energy, and water pumping. The
value for pipeline distribution includes
the energy equivalent of pipeline materials
(see Table A-l) and pipeline construction
energy. The pipeline construction energy
for a 1,000-mile pipeline has been estimated
at 8.4x10 Btu's. However, since this pipe
would carry considerably more than the gas
produced by this trajectory, the value was
scaled linearly to this size operation.
The third column represents the losses
in natural photosynthetic energy caused by
land disruption. The number of acres dis-
rupted to supply the daily trajectory re-
Q
quirement of 262x10 Btu's was calculated.
A-15-14
-------
u
Ancillary Energy Requirement
Btu's Input
Technology
Btu's Output
Physical and
Thermodynamic Losses
v
Primary Efficiency2--
Overall Efficiency =
X + U
Figure A-l. Dependence of Energy Development on
External Inputs and Evaluation of Net Energy
-------
TABLE A-3
EXTERNAL INPUTS TO LURGI HIGH-BTU GASIFICATION3
(109 Btu's)
Activity
Exploration
Extraction (includes
reclamation)
Mine transportation
Breaking and sizing
Gas i f icat ion — Lurgi
Gathering pipeline
Distribution pipeline
TOTAL
Ancillary
Energy
0
0.99
0.10
1.09
0
0
0
2.18
Energy Value of
Construction
and Materials13
0.14
16.74
0.14
0.94
4.01
0
3.77
25.74
Energy Value
of Natural
Sector
0
0.02
0
0.05
0.55
0
0
0.62
trajectory energy outflow is 262.0x10 Btu's.
Calculated from: Oregon Office of Research and Planning, 1974. The
original data were expressed in dollars.
In addition, there are losses in natural
production due to the acreage requirement
of the facilities: 35 acres for a breaking
and sizing plant and loading facility and
515 acres for the gasification facility in-
cluding storage, preparation, gasifier, and
evaporation ponds to handle wastewater
streams (Hittman 1975: Vol. II, p. IV-27).
The energy subsidy to the trajectory
due to lost photosynthetic productivity was
calculated as follows: the gross primary
*
productivity of this Montana grasslands
(approximately two grams per square meter
per day) was multiplied by the number of
**
acres disrupted and converted to the same
Gross primary productivity is a mea-
sure of the amount of sunlight caught and
concentrated by plants.
**
For the hypothetical Colstrip mine
with a 25-foot seam thickness, there are
43,000 tons extracted per acre of coal.
A-15-16
energy quality as coal (20 Btu's sugar per
Btu coal). The assumption was that this
productivity would be lost completely for
10 years. In reality, there would be no
productivity for several years (until the
plants reestablished themselves), and a
much longer period than 10 years would be
required for the grasslands to reach their
original level of productivity.
The total of the three columns in
Table A-3 is 28.6xl09 Btu's. This is 11
percent of the energy delivered to the con-
sumer. In this hypothetical case then, the
trajectory yields nine times as much energy
as it consumes (its net energy). However,
the values in this calculation are not pre-
cise; several calculations are estimates.
For example, the conversion from dollars to
Btu's is approximate and several effects
within the natural sector have not been
accounted for. These include the effect on
other water users (man and nature) of elimina-
tion of aquifers within the coal beds and the
effect, if any, on crops and natural vegeta-
tion due to air emissions.
-------
REFERENCES
Ballantine, T. (1974) A Net^Energy Analysis
of Surface Mining, Electrical Power
Production, and Coal Gasification.
AEC Research Proposal, Environmental
Engineering Sciences, University of
Florida, Gainesville.
Bayley, S. (1973) Energy Evaluation of
Water Management Alternatives in the
Upper St. Johns River Basin of Florida.
Report of EPA Water Program, Region IV
Office, Atlanta, Georgia.
Berry, S. and M. Fels (1972) The Production
and Consumption of Automobiles.
Illinois Institute for Environmental
Quality.
Boynton, W.R. (1974) "Regional Modeling and
Energy Cost-Benefit Calculations
Regarding Proposed U.S. Army Corps of
Engineers Dam on the Appalachicola
River at Blountstown, Florida," in
C. Hall and J. Day (eds.) Models as
Ecological Tools; Theory and Case
Histories. (In press).
Brookhaven National Laboratory, Associated
Universities, Inc., Energy/Environment
Data Group (1975) Energy Model Data
Base User Manual. BNL 19200.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts, Efficiency, and
Cost of Energy Supply and End Use,
Final Report: Vol. I, 1974; Vol. II,
1975. Columbia, Md.: Hittman
Associates, Inc. (NTIS numbers:
Vol. I, PB-238 784; Vol. II, PB-239
158) .
Klystra, C.D. (1974) "Energy Analysis as a
Common Basis for Optimally Combining
Man's Activities and Nature." Presented
to the National Symposium on Corporate
Social Policy, Chicago, Illinois.
Lent, P.N., H.T. Odum, andW.E. Bolch (1974)
"Some Considerations that Affect the
Net Yield from Nuclear Power." Paper
presented at Health Physics Society
19th Annual Meeting, Houston, Texas.
Makino, H. and S. Berry (1973) Consumer
Goods; A Thermodynamic Analysis of
Packaging, Transport, and Storage.
Illinois Institute for Environmental
Quality.
Odum, H.T. (1971) Environment. Power, and
Society. Wiley-Interscience.
Odum, H.T. (1973) The Role of the Power
Plants at Crystal River in the Coastal
System of Florida. Florida Power
Corporation.
Odum, H.T. (1974a) "Energy, Value, and
Money," in C. Hall and J. Day (eds.)
Models as Ecological Tools: Theory
and Case Histories. (In press).
Odum, H.T. (1974b) "Energy Cost Benefit
Approach to Evaluating Power Plant
Alternatives." Environmental Engineer-
ing Sciences and Center for Wetlands,
University of Florida, Gainesville.
Oregon Office of Energy Research and Planning
(1974) Energy Study; Interim Report.
Salem, Ore.: State of Oregon.
Slesser, M. (1974) "Energy Analysis in
Technology Assessment." Technology
Assessment 2: 201-208.
A-15-17
-------
CHAPTER 16
COMPARING THE ECONOMIC COSTS OF ENERGY ALTERNATIVES
16.1 INTRODUCTION
As noted in the Part II Introduction,
the Matrix of Environmental Residuals for
Energy Systems (MERES) data bank presently
contains data on coal, crude oil, natural
*
gas, and oil shale. The University of
Oklahoma resource descriptions also con-
tain data on these energy sources and on
geothermal, hydroelectric, nuclear fission,
nuclear fusion, organic wastes, solar, tar
sands, electric power generation, and
energy consumption.
Economic data in the OU resource sys-
tems descriptions are limited to publicly
available information on fixed, operating,
**
and total costs (estimated for a trillion
12 ***
Btu's [10 Btu's] of energy input ).
MERES also contains these types of data
plus such additional information as fixed
investments and labor and maintenance
costs. Except for electric energy costs
(which are generally estimated for plants
producing 1,000 megawatts-electric [Mwe] ),
cost estimates in the OU descriptions are
based on trillions (1012) of Btu's of
Data on other resources will be
added soon.
**Fixed costs are those that continue
at set levels regardless of the level of
production; for example, interest on debt,
repayment of debt, insurance payments, and
property taxes. Operating costs vary with
level of production; for example, labor
and materials costs.
It is more conventional to base costs
on output. Output costs can be obtained
by dividing the cost per unit of input by
the primary efficiency of the activity.
energy inputs. Additional information on
fixed investment, labor costs, etc. are
included in the "Economic Considerations"
section of each OU resource system descrip-
tion.
The user should be aware of certain
limitations and cautions when using both
data bases, including:
1. Annual fixed costs per Btu of
energy are considered to be con-
stant over the entire lifetime of
an activity.* For example, in
evaluating a high-Btu gasification
facility, fixed costs are assumed
to be the same for the first and
last year during which the facility
is to be operated. In practice,
fixed costs may change considerably
from year to year. Fixed costs
are calculated as follows:
Fixed Cost per Btu =
(Fixed Investment)x(Fixed Charge Rate)
(Btu's of input energy)
3.
By-products have been treated as
a cost credit rather than as a
source of revenue; that is, revenue
obtained from the sale of by-
products has been used to offset
costs rather than to augment
revenue.
Plant output is assumed to be 90
percent of rated capacity.
Note that cost data are discussed on
an annual basis. Both residuals (Chapter
14) and energy efficiency data (Chapter 15)
were considered on a daily basis.
**MERES data are based on a fixed charge
rate of 10 percent and, in most cases, a
25-year.life on capital equipment. The
fixed charge rate is defined as interest
plus depreciation plus yearly recurring
costs such as insurance, property taxes,
and interim replacements of short-lived
equipment.
16-1
-------
4. Cost estimates for each activity
are based on a specified scale of
operations. As a consequence,
linear extrapolations should be
treated with caution.
5. Transportation costs are generally
based on a fuel of a given Btu
content and a given haulage dis-
tance (usually the national aver-
age for each transportation mode) .
Since freight rates for energy
products are usually based on ton-
nage and miles, they cannot be
accurately scaled up or down on a
per-Btu basis. As a consequence,
Btu and distance adjustments will
generally be required.
6. Transportation costs for natural
gas combine both transmission and
distribution.
7. The cost estimates for activities
beyond extraction do not include
the cost of energy used as a raw
material. For example, the cost
of coal gasification in the MERES
data bank does not include the
value of the coal that is gasified.
8. Cost estimates generally assume
ideal circumstances such as the
absence of construction delays,
work stoppages, technical problems
with new technologies, etc.
9. Cost data are static, for a single
year (1972), and already seriously
out of date.
10. The cost estimates generally do
not include the cost of working
capital requirements; that is, the
cost of the firm's investment in
short-term assets such as cash,
short-term securities, accounts
receivable, and inventories.
As with both residuals and energy
efficiencies, procedures for gaining access
to MERES economic data are described in
Brookhaven's User Manual (1975). OU eco-
nomic data are reported in an "Economic
Considerations" section following the
description of each technological activity.
This chapter demonstrates the use of
these cost data in calculating and compar-
ing energy alternatives, explains ways to
modify the data to improve analytical
quality, and suggests methods for extending
che level of analysis to include an assess-
ment of economic impacts.
16.2 GENERAL PROCEDURES FOR OBTAINING
AND USING THE COST DATA
Direct, unaugmented use of economic
data in MERES and the OU descriptions is
limited to a relatively simple, static cost
analysis. The general procedures listed
below and the cost calculations contained
in the next section illustrate this type
of analysis, which should be regarded as
only a first step in the economic analysis
of energy alternatives.
The general procedures for calculating
and comparing the costs of energy alterna-
tives are:
1. Identify, describe and calculate
costs for the process, activity,
partial trajectory, or trajectory
to be evaluated and compared.
a. Identify the alternative
activities and/or processes to
be evaluated and compared by
referring to Figure 1 in the
appropriate OU resource sys-
tems descriptions. (At this
point, some alternatives may
be obviously unfeasible. For
example, some coal gasification
processes are designed to be
used only with certain kinds
of coal.)
b. Access MERES data by means of
the computer programs described
in Brookhaven's User Manual
(1975). This will provide a
printout of the costs for each
process, activity, partial
trajectory, or trajectory for
which a request is entered.*
Costs will be calculated for
the size of operation speci-
fied in the request. (For
example, if high-Btu coal gasi-
fication processes are to be
compared, costs can be based
on either the energy value of
the input coal or the output
gas; that is, if the HYGAS
total costs are $258,000 per
1012 Btu's of coal input, then
total costs will be $100,620.
Separating these costs is frequently
useful. Distribution costs are 46 percent
of fixed costs, 60 percent of operating
costs, and 50 percent of the total.
Costs for transportation activities
will generally require a distance adjustment
and in some cases a Btu adjustment. The
user must compute this adjustment and enter
the new cost figures per 10^2 Btu's before
continuing the analysis.
16-2
-------
2.
for a facility producing 250
million cubic feet [mmcf] of
gas daily.*)
c. To obtain supplemental cost
data included in the OU de-
scriptions, information on the
assumptions made concerning
the data, and descriptions of
qualitative costs, read the
"Economic Considerations"
sections that follow the pro-
cess descriptions for each
activity in the OU resource
systems descriptions. As when
using MERES, the size of
operations to be compared
should be specified.
d. If the costs for each process,
activity, partial trajectory,
or trajectory have not been
summed, sum them and list all
quantitative and qualitative
costs. Note that all of the
activities in a trajectory
must be balanced in terms of
operational size before sum-
ming.
Make the desired comparisons.
These can include:
a. A comparison of fixed costs,
operating costs, and/or total
costs.
b. A comparison of costs for com-
plete trajectories or for any
part of a trajectory.
c. A feasibility comparison of
the proposed action and alter-
native sources. In this com-
parison, the feasible options
can be determined by referring
to the OU descriptions or by
specifying criteria for deter-
mining feasibility; for exam-
ple, economic costs, a fixed
level of air or water pollu-
tants, etc. Those source
alternatives determined to be
feasible can then be compared
with the technological and
locational alternatives on
the basis of a fixed amount
or a fixed reference point
such as input or output energy
or total costs. However,
evaluators should be alert to
possible effects of scale, to
possible cost changes through
time, and to possible syner-
gistic effects, particularly
external economies or disecon-
omies. All these cautions
are discussed in Section 16.3
A summary of the procedures for com-
paring the economic costs of energy alter-
natives is given in Exhibit 16-1. As dis-
cussed in this section, the procedures in
Exhibit 16-1 can be used to calculate
economic costs for a variety of alterna-
tives, including other technologies, loca-
tions and sources, and fuels.
16.3 A DEMONSTRATION OF HOW TO COMPARE
THE ECONOMIC COSTS OF ENERGY
ALTERNATIVES
This section demonstrates economic
cost calculations using the general pro-
cedures described in Section 16.2. Total
costs for each of the seven trajectories
described in Chapter 14 are listed in
Tables 16-1 through 16-7. All the cost
figures in these tables are based on MERES
data except for the coal mining activities
(extraction, mine trucking, and breaking
and sizing) which were obtained from Chap-
ter 1 of the OU resource descriptions.
Each of the trajectories assumes con-
trolled environmental conditions and the
delivery of 95.7 trillion (95.7xl012) Btu's
per year of pipeline quality gas to the
Seattle market. All the cost figures in-
clude the normal linear magnitude or scale
adjustment. Natural gas pipeline trans-
mission and distribution costs have been
separated because several of the trajec-
tories do not require any pipeline trans-
mission.
Tf
The production of 250 mmcf of gas
daily requires 3.9X1011 Btu's of coal input
when the efficiency of the process is con-
sidered. Total costs may then be calcu-
lated as:
3.9x10
11
1x10
12
x $258,000 = $100,620
As stated in Section 16.3, each of
the activities is assumed to have been
organized into identical operations, all
having the scale assumed in the MERES or OU
cost estimates. Note that natural gas
liquids (NGL) separation and hydrogen sul-
fide (H2S) removal have been assumed to be
unnecessary for any of the trajectories.
16-3
-------
EXHIBIT 16-1
SUMMARY PROCEDURES FOR COMPARING
THE ECONOMIC COSTS OF ENERGY ALTERNATIVES
STEP
I
IDENTIFY, DESCRIBE, AND CALCULATE ECONOMIC
COSTS
Identify the alternatives to be evaluated
by referring to the technologies flow
charts in the OU descriptions.
Obtain economic cost data from MERES.
Supplement with additional quantitative
and qualitative economic cost data from
the OU descriptions.
Summarize the economic cost data for each
alternative.
STEP
COMPARE FIXED COSTS,
OPERATING COSTS, AND/OR 1
TOTAL COSTS FOR EITHER PARTIAL OR
COMPLETE •
TRAJECTORIES FOR EACH ALTERNATIVE •
STEP
III
DECIDE WHICH ALTERNATIVES ARE
WARRANT FURTHER ATTENTION
FEASIBLE AND I
16-4
-------
TABLE 16-1
THE PROPOSED ACTION: SYNTHANE HIGH-BTU GASIFICATION3
Activity
Extraction (strip mining, <15°
slope. Powder River Basin,
Mountain)
Mine transportation (trucking)
Processing (breaking and
sizing)
'
High-Btu gasification (mine
mouth, Synthane process)
Gathering (pipeline)
Transmission (pipeline)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
3.03
31.80
2.54
9.02
7.68
54.0
Operating Cost
(millions
of dollars
per year)
15.50
18.70
0.71
2.36
3.77
41.1
Total Cost
(millions
of dollars
per year)
18.53
50.50
3.25
11.41
11.41
95.1
on 1972 cost data.
TABLE 16-2
COSTS OF A TECHNOLOGICAL ALTERNATIVE: LURGI HIGH-BTU GASIFICATION3
Activity
Extraction (strip mining, <15
slope, Powder River Basin,
Mountain)
Mine transportation (trucking)
Processing (breaking and
sizing)
•
High-Btu gasification (mine
mouth, Lurgi process)
Gathering (pipeline)
Transmission (pipeline)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
2.93
43.10
2.54
9.02
7.68
65.2
Operating Cost
(millions
of dollars
per year)
15.00
18.60
0.71
2.36
3.77
40.4
Total Cost
(millions
of dollars
per year)
17.93
61.70
3.25
11.41
11.41
105.6
aBased on 1972 cost data.
16-5
-------
TABLE 16-3
COSTS OF A LOCATIONAL ALTERNATIVE:
SYNTHANE FACILITY MOVED TO DEMAND CENTER0
Activity
Extraction (strip mining, <15°
slope. Powder River Basin,
Mountain)
Mine transportation (trucking)
Processing (breaking and
sizing)
•
Unit train transportation
to Synthane plant
High-Btu gasification
(Synthane process,
Seattle area)
Gathering (pipeline)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
2.63
3.79
27.50
2.28
7.68
43.9
Operating Cost
(millions
of dollars
per year)
13.40
58.50
16.20
0.64
3.77
92.5
Total Cost
(millions
of dollars
per year)
16.03
62.30
43.80
2.92
11.41
136.4
Based on 1972 cost data.
TABLE 16-4
COSTS OF A SOURCE ALTERNATIVE:
ALASKAN NATURAL GAS VIA CANADIAN PIPELINE1
Activity
Extraction (on-shore)
Gathering (pipeline)
Transmission (pipeline)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
18.70
2.80
65.80
7.68
95.0
Operating Cost
(millions
of dollars
per year)
1.83
0.78
23.40
3.77
29.8
Total Cost
(millions
of dollars
per year)
20.53
3.58
89.20
11.41
124.8
on 1972 cost data.
16-6
-------
TABLE 16-5
COSTS OF A SOURCE ALTERNATIVE-
ALASKAN NATURAL GAS VIA ALASKAN PIPELINE AND LNG TANKER3
Activity
Extraction (on-shore)
Gathering (pipeline)
Transmission/Distribution
(pipeline)
Processing (LNG liquefaction)
Transmission/Distribution
(LNG tanker)
Storage (LNG tank in
Seattle area)
Conversion (LNG vaporization)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
23.10
3.40
22.80
13.50
12.40
1.56
0.11
7.68
84.6
Operating Cost
(millions
of dollars
per year)
2.27
0.97
8.39
11.60
5.48
0.89
1.56
3.77
34.9
Total Cost
(millions
of dollars
per year)
25.40
4.45
31.20
25.20
17.80
2.44
1.67
11.41
119.5
eased on 1972 cost data.
TABLE 16-6
COSTS OF A SOURCE ALTERNATIVE: OFFSHORE NATURAL GAS'
Activity
Extraction (offshore)
Gathering (pipeline)
Transmission (pipeline)
Distribution (pipeline)
TOTAL
Fixed Cost
(millions
of dollars
per year)
8.14
10.30
9.02
7.68
35.1
Operating Cost
(millions
of dollars
per year)
10.60
2.87
2.36
3.77
19.6
Total Cost
(millions
of dollars
per year)
18.70
13.17
11.41
11.41
54.7
on 1972 cost data.
16-7
-------
TABLE 16-7
COSTS OF A SOURCE ALTERNATIVE: IMPORTED LNG2
Activity
Transmission/Distribution (LNG
tanker in U.S. coastal waters)
Storage (LNG tank in Seattle area)
Conversion (LNG vaporization)
Distribution (pipeline)
Subtotal
12
Purchase price (104x10 Btu's
per year at $1.25 per 109 Btu's
on long-term contract)
TOTAL
Fixed Cost
(millions
of dollars
per year)
11.90
1.56
0.11
7.68
21.2
0.0
21.2
Operating Cost
(millions
of dollars
per year)
5.26
0.89
1.56
3.77
11.4
130.0
143.9
Total Cost
(millions
of dollars
per year)
17.10
2.44
1.67
11.41
32.6
130.0
165.1
Based on 1972 cost data.
16.3.1 The Hypothetical Proposed Major
Federal Action
The trajectory of the hypothetical
proposed major federal action begins with a
strip mine located in the Powder River
Basin of Montana. Data for the coal mine
activities were obtained from the OU
descriptions because MERES does not now
include cost data for a particular
Northwest coal mine. The mining cost esti-
mates shown in Table 16-1 are based on a
strip mine scale of five million tons per
year and a 10-percent fixed charge rate.
(The 10-percent rate was used for the OU
data because this rate was used for all
MERES cost estimates.) A Synthane gasifi-
cation plant is located at the mine mouth,
and plant cost estimates assume that all
the solid wastes are returned to the mine
for disposal.
The costs of extraction, mine trans-
portation, and processing have been combined
in Tables 16-1 and 16-2 because the OU
descriptions do not show the costs for each
of these activities separately.
Transmission and distribution costs
have been separated, as explained in Sec-
tion 16.1 above, to facilitate comparisons
with other trajectories. Since distance
adjustments cannot be made for pipeline
*
costs, the estimates for transmission and
distribution activities are probably only
rough indicators of these costs. Total
estimated costs for this trajectory are
$95.1 million, 57 percent of which are
fixed costs.
16.3.2 A Technological Alternative
When Synthane is replaced with Lurgi,
the cost estimates for the mining activities
are lower because the primary efficiency of
the Lurgi process (60.5 percent) is slightly
higher than that of the Synthane process
(58.4 percent). Thus, a smaller coal input
is required. The Lurgi gasification plant
is located at the mine mouth, and its solid
Distance and Btu adjustments are ex-
plained in Section 16.5.2.
16-8
-------
wastes are returned to the mine for dis-
posal. Pipeline costs (for gathering,
transmission, and distribution) are iden-
tical to those of the hypothetical proposed
major federal action. Total estimated costs
using Lurgi are $105.6 million, 62 percent
of which are fixed costs.
16.3.3 A Locational Alternative
Cost estimates for mining activities
(Table 16-3) are slightly different when
the Synthane facility is moved to the
Pacific Northwest because of slight differ-
ences in efficiency over each trajectory.
By locating the Synthane gasification plant
in the Seattle area instead of at the mine
mouth, the coal must be transported 1,000
miles by unit train, an additional activity.
The unit train transportation costs include
adjustments for both distance and the Btu
content of the coal (8,800 Btu's per
*
pound).
Since the gasification plant is not
located at the mine mouth, the assumption
that its solid wastes are returned to the
mine for disposal cannot be met and no
costs for an alternate disposal method have
been included. (This type of simplification
should be avoided in actual use because dis-
posing of solid wastes would be an addi-
tional operating cost.) Locating the
Synthane plant in the Seattle area also
obviates any need for pipeline transmission;
thus, only the costs for gathering and dis-
tribution activities are included. Total
estimated costs for this trajectory are
$136.4 million, 32 percent of which are
fixed costs.
The unit train cost estimates in the
MERES assumed that 12,000-Btu's-per-pound
coal was hauled 300 miles. The cost per
Btu for hauling 8,800-Btu's-per-pound-coal
1,000 miles is 4.52 times the MERES esti-
mates :
12.000 1.000
8,800 300
= 4.52.
16.3.4 Source Alternatives
The costs for delivering Alaskan natu-
ral gas via a trans-Canadian pipeline are
shown in Table 16-4.* Total estimated
costs for this trajectory are $124.8 mil-
lion, 76 percent of which are fixed costs.
Alaskan natural gas could also be
routed by pipeline to Valdez and from there
to the U.S. west coast by tanker. Esti-
mated costs for this trajectory are pre-
sented in Table 16-5. The primary effi-
ciency of this trajectory is lower than
that for the Canadian pipeline alternative,
and, as a consequence, costs are slightly
higher. Pipeline transmission is via an
Alaskan pipeline to Valdez. (Again, the
scale of this trajectory alone would not
justify building such a pipeline.) Trans-
portation of the gas from Valdez to Seattle
is via LUG tanker. Storage and conversion
are necessary in the Seattle area (LNG is
to be revaporized there), but there is no
need for pipeline transmission within the
continental U.S. Total estimated costs for
this trajectory are $119.5 million, 71 per-
cent of which are fixed costs.
Another alternative source of natural
gas is increased production offshore.
Gathering, transmission, and distribution
costs have been separated in Table 16-6,
but, since no distance adjustments can be
made for pipeline transportation, these
estimates should only be regarded as rough
estimates. Total estimated costs for this
trajectory are $54.7 million, 64 percent
of which are fixed costs.
Cost data include exploration and
leasing, but it is not clear whether the
costs of dry-holes are included. The scale
of this trajectory is insufficient to jus-
tify the construction of a trans-Canadian
pipeline; thus, an existing pipeline must
be assumed if this alternative is to be
feasible.
**See Section 16.5.2 for an explanation
of distance adjustments.
16-9
-------
A final source alternative is to import
LNG produced overseas. The trajectory for
this alternative does not include an extrac-
tion activity; therefore, some resource cost
or purchase price for the imported LNG has
to be introduced. Since many long-term con-
tracts for Russian and Algerian gas have
involved prices of approximately $1.25 per
10 Btu's, this figure was used. No esca-
lation of the contract price was considered
in this analysis, and all purchase costs
are assumed to be operating costs.
Since the LNG is stored and vaporized
in the Seattle area, no pipeline transmis-
sion is required. Total estimated costs
for this trajectory are $162.6 million,
13 percent of which are fixed costs.
16.4 A COMPARISON OF THE ECONOMIC COSTS
OF ENERGY ALTERNATIVES
As cited in Section 16.3, the trajec-
tories for the hypothetical proposed action
and the six alternatives provide for the
12
delivery of 95.7x10 Btu's per year
(2.62x10 Btu's or 250 romcf per day) of
pipeline quality gas to the Seattle market.
Total estimated costs for each trajectory
are listed in Table 16-8 and charted in
Figure 16-1. Based on these figures, off-
shore continental U.S. production is the
least costly, coal gasification at the
mine mouth ranks second, Alaskan gas is
third, and the total cost of coal gasifica-
tion in the Seattle area is exceeded only
by the cost of importing LNG. Except for
the two highest cost trajectories, fixed
costs increase as total costs increase.
Operating costs are roughly comparable for __
the first five trajectories but are mark-
edly higher for the two highest cost tra-
jectories.
Section 16.1 noted that these cost
estimates are static and that they repre-
sent, at best, costs in only the initial
years of the economic life of a trajectory.
Changes in costs through time are not in-
cluded in these estimates, but the sensi-
tivity of a trajectory to cost changes can
be assessed by assuming that significant
changes will occur only in operating costs.
Using this assumption, the ratio of fixed
to total costs in Table 16-8 indicates the
percentage of a trajectory's cost structure
that would not be exposed to rising costs
through time. The first five trajectories
in the ranking have at least 57 percent of
their cost structure unexposed to rising
costs while the last two are heavily ex-
posed. In addition, qualitative cost con-
siderations indicate that imported LNG has
additional exposure to rising costs because
of the risk that energy exporting countries
will raise LNG prices through time regard-
less of contractual obligations.
Other qualitative cost considerations
include balance of payments and foreign
trade effects. Imported LNG rates particu-
larly low on this criterion because of ad-
verse balance of payment effects, the ex-
porting of jobs overseas, and the risks
associated with cutoff of LNG imports and
dollar devaluations. The trajectory routing
Alaskan natural gas via Canadian pipeline
also has these problems although to a lesser
degree than does the imported LNG trajec-
tory. The remaining five trajectories have
none of these effects.
The trajectories substituting Lurgi
for Synthane, moving the liquefication
facility to the demand center, and the hypo-
thetical proposed action are the only tra-
jectories for which the final price to the
consumer would not be determined primarily
by the Federal Power Commission (FPC).
Current FPC policy is not to regulate the
price of synthetic gas until it enters a
pipeline under FPC jurisdiction, but both
The fixed costs for gasification in
the Pacific Northwest are probably under-
stated because the fixed costs for unit
trains are estimated in the MERES data as
six percent of total operating costs (based
on the fact that depreciation amounts to
six percent of total operating expenses for
rail freight service).
16-10
-------
200
Fixed Costs
CO
o:
o
o
u_
o
O)
z
o
150
100
50
Operating Costs
*?.'
•.Oo'.O
><#]
Axf,
Synthane Uirgi
Synthane Alaskan Alaskan Offshore
Demand Nat. Gas- Nat. Gas- Nat.Gas
Center Pipeline Pipeline
and Tanker
ALTERNATIVE
Imported
LNG
Figure 16-1. Fixed and Operating Costs by Alternative
-------
TABLE 16-8
TRAJECTORIES RANKED BY TOTAL COSTS
Trajectory
Offshore Natural gas
Synthane high-Btu gasification
Lurgi high-Btu gasification
Alaskan natural gas-pipeline
and LNG tanker
Alaskan natural gas-pipeline
Synthane facility at demand
center
Imported LNG
Total Costs
(millions
of dollars
per year)
54.7
95.1
105.6
119.5
124.8
136.4
162.6
Fixed Costs
(percent of
total costs
per year)
64
57
62
71
76
32
13
Fixed Costs
(millions
of dollars
per year)
35.1
54.0
65.2
84.6
95.0
43.9
21.2
Operating Costs
(millions
of dollars
per year)
19.6
41.1
40.4
34.9
29.8
92.5
141.4
on 1972 cost data.
the proposed action and the trajectory which
substitutes the Lurgi process could fall
under increased FPC control if this policy
is altered. Moving the Synthane facility
to the demand center involves intrastate
sale of gas; thus, there is less risk of
increased FPC price regulation. However,
this reduction in risk is obtained by a
$41-million increase in total cost over the
hypothetical proposed action, primarily
because of the high cost of unit train
transportation.
16.5 EVALUATION OF ECONOMIC COSTS:
SUGGESTED IMPROVEMENTS
The cost estimates presented above
represent costs as of 1972 and reflect the
technological, scale, economic, and legal
assumptions that underlie them. The user
might well wish to update the cost esti-
mates so that they more closely reflect
current conditions. The user might also
find it either necessary or desirable to
make assumptions that conflict with the
assumptions built into the MERES data base.
And, most importantly, the user may wish to
shift from a completely static to a more
dynamic framework of analysis. Each of
these adjustments for improving the evalua-
tion of economic costs is discussed below.
16.5.1 Updating the Cost Data
Several types of updating adjustments
might be considered by the user, including
adjustments for changes in scale, improve-
ments in technology, and alternatives in
the legal environment, particularly in the
area of environmental legislation. However,
the most pressing reasons for updating will
probably result from changes in costs, by-
product credits, or both. For example,
unit train rates have nearly doubled since
1972.
Since cost indexes will undoubtedly be
one of the tools used for such adjustments,
the user should be aware that these indexes
do not adequately account for technological
changes and substitution possibilities.
Thus, the indexes are most accurate when the
time"interval considered is short and the
16-12
-------
magnitude of the cost change is small. The
Survey of Current Business (published
monthly by the U.S. Department of Commerce)
is a good source for cost indexes.
16.5.2 Conflicting Assumptions
In practice, the user will frequently
need to make assumptions that conflict with
those made for the data included in MERES
and the OU descriptions. Several examples
of this occurred in the analysis of the
seven trajectories listed in Table 16-8.
Perhaps the best example of this type of
assumption is the need to adjust transpor-
tation costs for distance and Btu factors.
As noted in Section 16.1, freight rates
for energy products are generally based on
tonnage and miles; thus, the data base costs
cannot be merely scaled up or down as the
size of the activity (in terms of Btu's)
changes. First, a new cost figure per 10
Btu's must be calculated for the particular
Btu content of the fuel and for the haulage
distance being considered. This cost fig-
ure is then adjusted up or down as the
scale of the activity (in terms of Btu's)
changes. For example, in the analysis of
the trajectory locating the Synthane plant
in the Seattle area (section 16.3), the
coal had a Btu content of 8,800 Btu's per
pound and was to be hauled 1,000 miles.
The fixed, operating, and total cost fig-
ures for unit train distribution were all
increased by a factor of 4.52 to adjust for
these changes (note that these are the
12
costs per 10 Btu's). Distribution of
coal by mine train, river barge, slurry
pipeline, truck, or conveyor would all re-
quire similar cost adjustments.
Similar problems will also be encoun-
tered in natural gas and oil transmission/
distribution; however, in most cases a
distance adjustment cannot be made because
no distance information is provided in the
MERES data. In particular, no distance
adjustment can be made for either crude
oil or petroleum product transportation by
pipeline, tanker, supertanker, or tank truck.
For similar reasons, distance adjustments
cannot be made for natural gas transporta-
tion by either pipeline or tanker or for
either crude oil or natural gas gathering
pipeline. Although Btu adjustments can be
made, they will usually be unnecessary
unless, for example, low-Btu gas (below
pipeline quality) is introduced into a
pipeline.
16.5.3 Shifting from a Static to a
Dynamic Framework of Analysis
As mentioned earlier, cost estimates
in the data bases are static and likely
only to represent costs during the initial
years of the economic life of an activity.
The need to reflect dynamic conditions goes
beyond simply allowing for the time value
*
of money and requires that the user con-
sider likely cost changes through time,
including those resulting from continued
expansion or changes in the industry under
study, expansion or changes in either the
industries supplying or competing for the
resource, or changes in the general eco-
nomic or legal environment in which the
industry operates. Although difficult,
this type of analysis is most useful.
16.5.4 Cost Effectiveness Analysis
The absence of any price-, value-, or
demand-oriented information for the seven
trajectories given in Table 16-8, can be
circumvented by a cost effectiveness analy-
sis which compares the costs of trajectories
with identical physical end points. For
example, all the trajectories resulted in
12
the delivery of 95.7x10 Btu's of pipeline
The time value of money recognizes
the fact that $1.00 to be received in the
future has less value than $1.00 received
today because an amount less than $1.00
could always be invested now and allowed
to grow to $1.00 in the future. This con-
cept should not be confused with infla-
tionary or deflationary effects on the pur-
chasing power of the dollar.
16-13
-------
quality gas to the Seattle market. Thus,
an argument could be made that a cost
effectiveness analysis would be appropriate
and that the cost analyses illustrated
above are a sufficient basis of comparison
for these trajectories. However, this type
of analysis would be misleading because the
economic ramifications of each trajectory
are markedly different, particularly with
respect to final consumer price but also in
terms of balance of payment effects, govern-
ment tax revenues, impacts on input markets,
and local or regional economic impacts.
These factors severely limit economic
analyses based exclusively on cost data.
16.6 SUGGESTIONS FOR ECONOMIC IMPACT
ANALYSIS
Section 16.5.4 suggested that the
economic impacts of an action are not
effectively measured by trajectory costs
alone. In fact, several types of economic
impacts should be analyzed, including
effects on: input markets; final consumer
prices or output markets; local, regional,
national, and international (balance of
payments) economies; and tax revenues at
all levels of government.
The diversity of these potential
effects makes a single starting point for
the impact analyses desirable. A net
present value (NPV) analysis can serve this
purpose. However, since an NPV analysis
will generally require an evaluation of
energy demand factors, the reasons why
market prices often deviate from production
costs, causing profits to expand or con-
tract, are discussed before the NPV analy-
sis is explained.
16.6.1 Production Costs and Market Prices
Although, by definition, total unit
cost plus profit per unit equals market
price, profit margins (profit as a percent-
age of unit price) are not constant across
industries, products, or even time. Profit
margins vary as a result of at least three
factors.
First, profit margins are not the same
as actual profits in economic terms. Eco-
nomic theory has always held that under
conditions of workable competition (particu-
larly free exit and entry of competitors
into industries) profits across industries
would tend to equalize (allowing for differ-
ences in risk and assuming that no unex-
pected events occur). However, this theory
applies only to return on investment, not
to profit margins among industries. In
fact, there is no tendency for profit mar-
gins to equalize across industries because
of differences in fixed and operating costs.
High fixed cost industries tend to have a
low ratio of sales to total investment
while the opposite is true for industries
that have low fixed costs. For example,
grocery stores with an annual sales-to-
total investment ratio of 12 can survive
on a profit margin as low as one percent
because the product of the two is a 12-
percent return on total investment before
taxes. On the other hand, the electric
power industry has an annual sales-to-
total investment ratio of one-third; thus,
its profit margin of 36 percent (of sales)
is necessary if it is to earn a 12-percent
return on investment before taxes. The
point is that profit margins may be some-
what similar within industries, particularly
for firms with similar cost structures, but
they will differ among industries.
A second factor is the occurrence of
unexpected events that, at least tempo-
rarily, can disrupt any tendency for return
on investment to equalize. Unexpected
events can lead to lower than normal profits
(or even losses) or to higher than normal
profits and thus magnify existing differ-
ences in profit margins. For example, the
The discussion in this section assumes
that firms have no debt and, therefore, that
returns on equity and total investment are
identical. This restriction on a firm's
capital structure simplifies the analysis
and can be relaxed without affecting the
results.
16-14
-------
TABLE 16-9
CHARACTERISTICS OF VARIOUS MARKET STRUCTURES
Type of Market
Competitive
Monopolistic competition
Oligopoly
Unregulated monopoly
or cartel
Regulated monopoly
Number of
Competitors
very large
many
few
none
none
Characteristics
Barriers
to Entry
none
minor
high
total
total
Nature of
Product
homogeneous
some
differentiation
differentiated
highly
differentiated
highly
differentiated
Control
Over Price
none
minor
high
total
minor
unexpected increases in imported oil prices
by the Organization of Petroleum Exporting
Countries (OPEC) caused the domestic price
*
of "new" oil to rise to the delivered
price of imported oil (approximately $11
per barrel). Since domestic oil companies
differ widely in their dependence on im-
ported oil and in their proportionate mix
of new versus old oil, profit margins
within the oil industry should diverge.
(The Federal Energy Administration's en-
titlement program was designed to counter
this problem, at least for refining prof-
its.)
This example also indicates that events
in one industry can spread to other indus-
tries because of substitution possibilities.
New domestic oil is the only perfect sub-
stitute for imported oil; thus, its price
should have equalized with that of imported
oil. Low-sulfur coal is also a good sub-
stitute, and its spot market price plus
delivery costs has risen to a level com-
"New" oil is oil produced from domes-
tic reserves added after January 1, 1974.
parable to that of imported oil on a per-
Btu basis.
A third factor is the different market
structures in which goods are traded.
Economists have identified at least five
distinct market structures, each containing
various gradations. These market struc-
tures and the various characteristics asso-
ciated with each are summarized in Table
16-9.
"Competitive markets" constitute one
extreme and are characterized by a very
large number of competitors producing a
homogeneous product in an industry that
allows very easy entry or exit. Under these
conditions, each competitor has an infini-
tesimal share of the market and no control
over market price. Market price is deter-
mined by the interaction of industry supply
and demand, and each competitor sells as
much as he can at the market price. Agri-
cultural markets are perhaps the best exam-
ples of competitive markets.
"Monopolistic competition"'describes
a market in which there is some product
differentiation created by style, brand
16-15
-------
name, advertising, location, etc. These
markets have many competitors and minor
barriers to entry (licensing requirements,
advertising expenses, etc.). Each competi-
tor has seme control over price and can
vary price within a small range without a
substantial loss of customers because of
brand loyalty and other factors. Retail
gasoline outlets are examples of this type
of market.
"Oligopolistic markets" differ from
monopolistic competitive markets only in
degree and in the interdependence of the
competitors. In oligopolistic markets,
each competitor must consider the potential
reactions of his counterparts to any price
changes. Examples of this type market in-
clude many important manufacturing indus-
tries such as the steel, automobile, chemi-
cal, and oil refining industries.
"Unregulated monopolies" are charac-
terized by highly differentiated products
for which there are no close substitutes.
Entry into the industry is completely
blocked (usually by law) ; thus, there are
no competitors and the unregulated monopo-
list has complete control over market price.
Recent examples of unregulated monoplies
include both the Xerox and Polaroid com-
panies, which were granted temporary market
monopolies during the life of their patents.
In "regulated monopolies," prices and
profits are limited by government regulatory
commissions, and the monopolist has, in
effect, a cost-plus contract. Examples of
regulated monopolies include: electric
power generation, transmission, and distri-
bution; interstate natural gas production,
transmission, and distribution; and crude
oil and petroleum product pipelines.
Market structure is important because,
in theory, return on investment should in-
crease as the market moves from competition
toward unregulated monopoly. In addition,
temporary increases in return on investment
caused by unexpected events should endure
longer as the market moves in this direc-
tion. Empirical results are mixed but do
tend to support these theories.
This section has discussed three of
the more important reasons why profit mar-
gins should differ substantially across and
within industries. For these reasons, the
total unit cost of a particular production
process is not as accurate an indicator of
market price for energy as might be ex-
pected, particularly when other lower cost
techniques may emerge to determine the
market price and when extended periods of
time are being considered.
16.6.2 Calculation of Final Consumer Prices
Section 16.6.1 discussed the reasons
why, in a market economy, production costs
are often poor indicators of market prices.
Frequently, however, prices calculated on
production costs and an assumed rate of
return on stockholders equity can be useful.
These prices (cost-plus prices) do not
accurately predict future market price
(because market price would be determined
by a wider array of supply and demand
forces) but are indicative of the minimum
market price necessary to make a given
activity attractive to private investors.
Cost-plus prices can also be used to compare
alternatives based on the minimum output
prices required for their adoption or to
rank alternatives in order of economic
desirability.
Profit on total investment is not as
sensitive to market structure as is profit
on equity, indicating that more concentrated
industries (i.e., industries with fewer com-
petitors) tend to be more highly leveraged
(i.e., have a higher proportion of debt in
their capital structure). These factors
suggest that the increased profitability of
more highly concentrated industries may be
due more to financial power than to pricing
power.
16-16
-------
In general, calculation of cost-plus
price requires that annual revenue be iden-
tified and divided by annual output. The
essential feature of a cost-plus price is
that profits are treated as the cost of
attracting equity capital and usually esti-
mated as some percentage return on equity
times the amount of equity required. Prof-
its and all other costs may then be summed
to determine annual revenue requirements.
In the remainder of this section, cost-
plus output prices are calculated for each
of the seven trajectories listed in Table
16-8. To simplify these calculations,
several assumptions were made:
1. There is no depletion allowance.
2. All capital facilities have a 25-
year life and zero salvage value.
3. Straight line depreciation is used.
4. State, federal, and local corpo-
rate income taxes are 50 percent
of taxable income.
5. Price computations are to be made
for the year 1972 (which eliminates
the need to update the MERES and
OU cost estimates).
Five additional assumptions regarding
financial structure were made based on
typical financial relationships for gas
utilities, large corporations, and coal
companies:
6. Fifty percent of the capital struc-
ture is debt (both long and short
term), and 50 percent is equity.
7. The average cost of debt is eight
percent.*
8. Stockholders require an eight-
percent, after tax, rate of return
on equity.
9. Working capital is equal to seven
percent of fixed investment.**
10. Property taxes and insurance costs
are two percent of total invest-
ment.
The eight percent includes interest
charges, underwriting costs, etc.
Working capital is defined as the
firm's investment in cash, short-term se-
curities, accounts receivable, and inven-
tories. The MERES and OU cost estimates
generally do not include working capital
requirements.
Given these 10 assumptions and the
cost information in MERES and the OU de-
scriptions, cost-plus price calculations
for each of the seven trajectories can be
based on the equations given in Table 16-10.
Equation 1 indicates that cost-plus price,
P, is equal to annual revenue, R, divided
by annual output, Q.* Quantity is known
since each trajectory delivers 95.7xl012
Btu's or 92.8 mmcf of pipeline quality gas
per year. Revenue requirements may be
computed by summing the costs of the five
components listed in equation 2 of Table
16-10.
The first component, operating costs
(CQ), for a given trajectory may be obtained
from MERES using the procedures described
in Section 16.2. These calculations have
already been done for the seven trajectories
in Table 16-8.
Fixed costs, Cf, should not be obtained
directly from MERES because of the need to
include working capital and to consider
separately the costs of depreciation,
**
equity, and debt. Fixed costs consist of
the cost of debt, i, and insurance and
property taxes, T , since depreciation has
been identified as a separate item. As
defined in equation 3, fixed costs are
equal to six percent of total investment,
I, which is assumed to be 107 percent of
fixed investment (equation 4). To compute
fixed costs, the user must first determine
fixed investment by obtaining the MERES
fixed cost estimate and multiplying this
Costs, revenues, profits, and output
all have time dimensions and are expressed
as rates; that is, so many dollars per year.
Total investment, fixed investment, and
working capital investment do not have a
time dimension and are expressed as amounts?
that is, $1 million.
**The fixed costs, Cf, can be found by
multiplying the MERES fixed costs by 1.9
but this 1.9:1 relationship is a result of
assumptions 5 through 10 made at the start
of this section. A change in any of these
six assumptions and the 1.9:1 relationship
will also be changed.
16-17
-------
TABLE 16-10
EQUATIONS FOR COST-PLUS PRICE COMPUTATIONS
Equation 1. P = R/Q
Where P
R
Q
Equation 2. R = C
Where C
annual average price
annual revenue
annual output of gas in thousands of cubic feet
- + IT + D + T.
annual operating costs of each trajectory
(obtained from the OU or MERES cost estimates
in Table 16-8)
Equation 3.
C- - annual fixed costs (computed from equation 3 and
not obtained directly from the OU or MERES cost
estimates)
1T = annual after tax profits
D = annual straight line depreciation computed as
1/25 of fixed investment
T. = annual federal, state, and local corporate income
taxes
Cf = i + T = 0.06 I
Where i = annual cost of debt (by assumptions 6 and 7 on page
16-17, this equals 0.04 I)
T = annual property taxes and insurance costs (by assump-
p tion 10 on page 16-17, this equals 0.02 I)a
I - total investment
Where If = fixed investment (obtained from the OU and MERES
descriptions or by multiplying the OU or MERES fixed
Equation 4. I = If + Iw = 1.07 If
fixed invei
description __..
cost estimates by 10 )b
I = working capital investment (by assumption 9 on page
16-17, this equals 0.07 If)
Equation 5. 1f = 0.08 (0.5 I) = 0.04 I (by assumptions 6 and 8 on page 16-17)
Equation 6. D = 0.04 If (by assumptions 2 and 3 on page 16-17)
Equation 7. T.= (R-C -C-—D) 0.5 =tT (by assumptions 1 and 4 on page 16-17)
Property taxes would include all federal, state, and local non-income taxes. In actual
practice, the insurance and property tax base may not be the same.
Since the OU and MERES descriptions computed fixed costs as 10 percent of fixed invest-
ment, fixed investment may be found by multiplying their fixed cost estimates by 10.
16-18
-------
number by 10 (MERES and the OU descriptions
computed fixed costs as 10 percent of fixed
investment). Equation 4 may then be used
to calculate total investment, I, and equa-
tion 3 to compute the new fixed cost esti-
mates .
After tax prof its, 77-, are assumed to
be eight percent of equity. Since equity
is assumed to be half of the capital struc-
ture, after tax profits (equation 5) amount
to four percent of the total investment
calculated in the above paragraph.
Depreciation, D, is defined as four
percent of fixed investment (equation 6).
Fixed investment, as noted above, is cal-
culated as 10 times the MERES or OU fixed
cost estimates.
Corporate income taxes, T., are assumed
to be 50 percent of income before taxes.
As defined in equation 7, income before
taxes is revenue less operating costs, fixed
costs, and depreciation.
The sum of the above five components
yields required revenue, R. calculation
of each of these components and of cost-
plus price for the offshore natural gas
trajectory is illustrated in Table 16-11.
Similar calculations for each of the seven
trajectories have been summarized in Table
16-12 and Figure 16-2.
16.6.3 Comparison of Price and Cost
Rankings
The seven trajectories have been ranked
in order of increasing output price in
Table 16-12. The prices range from a low
of $0.93 per thousand cubic feet of gas
(mcf) to a high of $2.26 per mcf. Under
the assumptions made, these prices represent
the minimum average price at which natural
gas from a given trajectory would be avail-
able in the Seattle area. The average 1972
market price for natural gas in the State
of Washington was $0.76 per mcf.* The cost-
plus price for all trajectories exceeded
this average price, and only the offshore
natural gas trajectory delivers gas at a
roughly comparable price.
The rank ordering of each trajectory
in terms of annual total cost, as shown in
Table 16-8, differs from the rank ordering
by consumer price (calculated on a cost-plus
basis) as shown in Table 16-12. The cost
and price rankings are identical for the
first three trajectories in Table 16-12,
but in Table 16-8 the fourth through seventh
ranked trajectories were, in order: Alaskan
gas via LNG tanker, Alaskan gas via Canadian
pipeline, Synthane facility at demand
center, and imported LNG.
Two additional points concerning
Table 16-12 should be made. First, the
cost-plus price computations are based on
1972 cost estimates with no cost escalations
through time; thus, alterations in costs
could produce changes in the rankings.
Second, the profit margins also vary with
the cost structure from a high of 19.4 per-
cent for Alaskan natural gas via Canada
(the highest ratio of fixed costs to total
costs) to a low of 5.0 percent for imported
IiNG (the lowest ratio of fixed costs to
total costs). This variation in profit
margins is caused by differences in cost
structure and not by the rate of return on
equity, which is eight percent for all
seven trajectories.
The basic difference between Tables
16-8 (trajectories ranked by total costs)
and 16-12 (trajectories ranked by cost-plus
price) is that Table 16-12 has a broader
scope because it includes the cost of
This average included residential,
commercial, and industrial prices as follows:
Residential Price:
Commercial Price:
Industrial Price:
Average Price:
$1.44 per mcf.
$1.19 per mcf.
$0.48 per mcf.
$0.76 per mcf.
16-19
-------
TABLE 16-11
SAMPLE COST-PLUS PRICE CALCULATIONS
FOR THE OFFSHORE NATURAL GAS TRAJECTORY
1. C = $19.6 million (from Table 16-8) .
o ~—^———
2. Cf = 0.06 I = 0.0642 If
since I = 1.07 If
The MERES fixed costs for this trajectory in Table 16-8 are
$35.1 million, therefore If = 10 ($35.1 million) = $351 million.
The new fixed cost estimate, C^, is:
Cf = 0.642 If = 0.0642 ($351 million) = $22.53 million
3. IT = 0.04 I = 0.04 (1.07 If) = 0.0428 If
= 0.0428 ($351 million) = $15.02 million
4. D = 0.041 = 0.04 ($351 million) = $14.04 million
5. T± = rr = $15.02 million
6. R=C + C, +1T+D+T. = $86.21 million
or i
7. Q = 92.8 million mcf
8. P = R/Q = $86.21 million/92.8 million mcf = $0.93 per mcf
16-20
-------
TABLE 16-12
TRAJECTORIES RANKED BY COST-PLUS PRICE
Trajectory
Offshore natural gas
Synthane high-Btu
gasification
Lurgi high-Btu
gasification
Synthane facility at
demand center
Imported LNG
Alaskan natural gas
pipeline and LNG
tanker
Alaskan natural gas
pipeline
Operating
Costb
19.6
41.1
40.4
92.5
141.4
34.9
29.8
Fixed Cost
22.53
34.67
41.86
28.18
13.61
54.31
60.99
After Tax
Profits13
15.02
23.11
27.91
18.79
9.07
36.21
40.66
Depreciation
14.04
21.60
26.08
17.56
8.48
33.84
38.00
State, Federal
and Local
Corporate ,
Income Taxes
15.02
23.11
27.91
18.79
9.07
36.21
40.66
Profit
Margin0
17.4
16.1
17.0
10.7
5.0
18.5
19.4
Required
Revenue15
86.21
143.59
164.16
175.82
181.63
195.47
210.11
Required
Output
Priced
0.93
1.55
1.77
1.89
1.96
2.11
2.26
Based on 1972 cost data and an eight-percent after tax return on equity. See text for assumptions. Each trajectory
delivers 92.8x10 thousand cubic feet of gas per year to the Seattle market assuming that each cubic foot of gas con-
tains 1,031 Btu's. The total cost figures in this table differ slightly from those of Table 16-8 due to the addition
of working capital requirements and the explicit treatment of the costs of debt and equity.
Millions of dollars per year.
Profit as a percentage of revenue.
Dollars per thousand cubic feet.
I
to
-------
u_
o
o:
UJ
CL
o:
<
-J
2.25
2.00
1.75
1.50
1.25
LOO
.75
.50
.25
0
\\N
\\N
\\\
^7"
o.c
V
\\\
\\N
\\\
^\^
v\\
m
I
1
XN
.
fl'f.t
2,
^
\\\
Synthane Lurgi Synthane Alaskan Alaskan Offshore Imported
at Demand NatGas- Nat. Nat. Gas LNG
Center Pipeline Gas-
Pipeline and
Tanker
ALTERNATIVE
EMI Operating Cost
Fixed Cost
After Tax Profits
Depreciation
State, Federal and Local Corperate
Income Taxes
Figure 16-2. Cost-Pius Price by Alternative
-------
raising working capital, equity, and tax
revenue. These additional factors must be
considered whether a trajectory is financed
by public or private means. Thus, the cost-
plus price rankings in Table 16-12 are more
useful than those in Table 16-8 for public
policy decisions. Although these cost-plus
prices do not predict future market prices,
they do indicate the minimum output price
necessary to make a trajectory economically
attractive and therefore are one method of
ordering alternatives, assuming risks and
other factors are comparable.
Although rankings made in this manner
have the advantage of involving relatively
simple computations, they ignore demand
forces and cannot easily accommodate such
factors as the time value of money and
future economic considerations. For these
reasons, the more sophisticated (and com-
plex) analysis of the next section is often
used to rank alternatives in order of
economic desirability.
16.6.4 Net Present Value Analysis
Although many volumes have been writ-
ten about the best economic criterion for
evaluating a proposed investment activity,
most of the methods employed in both the
public and private sectors are related to
the concept of net present value (NPV) or
discounted cash flow (DCF) analyses. In
essence, the net present value criterion
states that revenues should exceed costs
when adjusted for their sequence in time;
that is, when the time value of money is
properly accounted for.
NPV is essentially a method for deter-
mining the profitability of an investment
over its life. The numbers calculated by
use of equation 8 in Table 16-13 can vary
from negative (unprofitable) to positive
(profitable). Since a doubling of all
revenue and cost figures on the right hand
side of equation 8 would double the NPV of
an investment, the NPV concept should be
interpreted carefully when investments of
differing magnitudes are being compared.
Because of this, the user may wish to com-
pute the NPV of an investment per dollar of
total investment when comparing investments
of differing magnitudes.
To make a NPV calculation, the user
should identify the prices and quantities
of all inputs and outputs for each time
period over the life of the investment.*
Inputs include land, buildings, labor, raw
materials, management skills, financing,
etc. Outputs include products, by-products,
and services. Once this price and quantity
information is assembled, costs for any
given time period, Cfc, may be found by
multiplying price times quantity and summing
over all inputs (equation 9). Similarly,
revenue for any given time period, R , may
be found by multiplying price times quantity
and summing over all outputs (equation 10).
These revenue and cost estimates plus an
appropriate discount or interest rate may
then be used to compute the net present
**
value of the investment (equation 8).
Note that time, t, is generally ex-
pressed in years and that revenue may be
zero in the initial time periods and may
include salvage value in the final time
period. Costs in the initial time periods
generally represent outlays for plant and
equipment (fixed investment), while costs
Price and quantity information for
each input are not always given in the OU
and MERES descriptions since some costs,
such as maintenance costs, are estimated as
a percent of operating costs. It would be
useful to have the information on prices
and quantities for each input as this would
facilitate evaluation of local employment
effects, balance of payments effects, etc.
**While there is general agreement that
the selection of an appropriate discount
rate is a critical factor, there is little
general agreement on the numerical rate to
be used. In addition, higher discount
rates are frequently used for higher risk
investments.
***Assuming that the plant and equipment
are purchased and not leased.
16-23
-------
TABLE 16-13
COMPUTATION FORMULA FOR NET PRESENT VALUE (NPV)
Equation 8. NPV =
Where C. is cost in the t time period
R.. is revenue in the t time period
r is the discount rate or percent
and, T is the economic life of the proposed activity,
and t is an integer so that 0
-------
in subsequent periods are composed of both
operating and fixed costs.* Working capi-
tal requirements may also be introduced as
a cash outflow in the initial periods (a
cost) and as a cash inflow in the final
period (a revenue).
NPV may be computed either before or
after taxes. For private sector activi-
ties, it is generally preferable to compute
NPV after taxes. This may be done simply
by considering depreciation, tax credits,
and all federal, state, and local taxes in
a separate computation and then introducing
the annual results for each time period
into equation 8 as an additional cost or
revenue, depending on whether the tax cred-
its outweigh the tax payments. Tax calcu-
lations do not generally enter an NPV
analysis of public sector activities unless
some change in tax revenues is expected.
The principal value of the NPV approach
is that it forces the user to consider
present as well as future economic factors
that may affect the action he takes now.
This type of consideration is lacking in
the estimates discussed in Sections 16.3
and 16.6.2.
Although the net present value of an
activity is one of the more useful summary
measures of its economic desirability, it
is clearly a simplification of reality
because NPV is only one factor to be con-
Fixed investment and fixed costs are
related but dissimilar concepts. Fixed in-
vestment represents cash outlays for land,
plant, and equipment in the initial time
periods. Most companies use debt to finance
their fixed investments and some fixed ob-
ligation or costs over future time periods
are created including interest on debt and
repayment of debt. Fixed costs also include
annual insurance costs, property taxes, etc.
Fixed costs are sometimes estimated as fixed
investment times a fixed change rate (FCR)
where the FCR is expressed as a percent per
year.
**
For example, a decision by the federal
government to construct an office building
rather than to rent office space would re-
duce both property and income tax payments
in the city or state affected.
sidered when evaluating an investment. For
this reason, decision makers frequently con-
sider other aspects or impacts of the ac-
tivity such as availability of skilled man-
power, risks, local economic impacts, etc.
One value of NPV analysis is that the
price and quantity information for each
input and output should serve as a starting
point for an analysis of any particular
economic impact of interest. For example,
the local economic impact of a plant could
be assessed by starting with information on
state and local tax payments, the number of
employees, their wage rates, etc. and esti-
mating housing needs, consumption expendi-
tures, schooling needs, etc. Balance of
payments impacts, both present and future,
could also be assessed by identifying in-
puts and outputs that are now, or might be
in the future, either imported or exported.
Finally, the terms NPV and DCF are
sometimes applied to private sector invest-
ments, and the terms "cost-benefit analysis"
or "cost effectiveness analysis" are fre-
quently used for non-profit or public sec-
tor investments. All these analyses are
essentially the same and, with appropriate
care, equation 8 can be used for all. For
example, cost benefit analysis generally
requires the assigning of values to non-
market outputs of an investment such as the
value of the recreation and conservation
outputs of a government hydroelectric proj-
ect. These annual values may then be
treated as revenues along with the revenues
obtained from the sale of electricity. When
there are alternative methods of producing
**
identical benefits, a cost benefit
The internal rate of return can also
be calculated from equation 8 by setting
NPV = 0 and solving for the value of r
that satisfies this relationship; that is,
the discount rate that equates discounted
revenues and discounted costs.
In other words, the revenue flows in
equation 8 are identical for each alterna-
tive; thus, the analysis can be narrowed to
consideration of only the cost flows through
time.
16-25
-------
analysis can be reduced to a cost effective-
ness analysis by merely selecting the alter-
native with minimum cost.
REFERENCE
Brookhaven National Laboratory, Associated
Universities, Inc., Energy/Environ-
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Data Base User Manual. BNL 19200.
APPENDIX TO CHAPTER 16
A SELECTED BIBLIOGRAPHY OF ENERGY ECONOMICS
COAL
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Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts. Efficiency, and
Cost of Energy Supply and End Use.
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Katell, Sidney, and E.L. Hemingway (1974)
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Bureau of Mines Information Circular
8641. Washington: Government Printing
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Katell, Sidney, and E.L. Hemingway (1974)
Basic Estimated Capital Investment and
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Killebrew, Clarence E. (1968) "Tractor
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Mutschler, P.H., R.J. Evans, and G.M.
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16-26
-------
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OIL SHALE
BuMines, TOSCO, and Garrett, personal
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Energy Technology; Some Facts and
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CRUDE OIL
Battelle Columbus and Pacific Northwest
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Vol. I: Fuel/Energy Systems; Techni-
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A-16-27
-------
TAR SANDS
Cameron, R.J. (1969) "A Comparative Study
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NUCLEAR ENERGY—FUSION
No economic references.
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A-16-28
-------
Rex, Robert W. and David J. Howell (1973)
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A-16-29
-------
ELECTRICAL POWER GENERATION
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Council on Environmental Quality (1973)
Energy and the Environment; Electric
Power. Washington: Government
Printing Office
Davis, John C. (1973) "SOx Control Held
Feasible". Chemical Engineering 80
(October 29, 1973): 76-77.
Federal Power Commission (1971) 1970
National Power Survey. Washington:
Government Printing Office, 5 parts.
Hittman Associates, Inc. (1974 and 1975)
Environmental Impacts, and Cost of
Energy Supply and End Use. Final
Report: Vol. I, 1974: Vol. II, 1975.
Columbia, Md.: Hittman Associates, Inc.
Jimeson, R.M. and G.G. Adkins (1971) "Waste
Heat Disposal in Power Plants."
Chemical Engineering Progress 67 (July
1971): 64-69.
Keairns, D.L., J.R. Hamm, and D.H. Archer
(1972) "Design of a Pressurized Bed
Boiler Power Plant," pp. 267-275 in
R.W. Coughlin, A.F. Sarofim, and M.J.
Weinstein (eds.) Air Pollution and Its
Control. AIChE Symposium Series,
Vol. 68, No. 126. New York: American
Institute of Chemical Engineers.
Olmstead, Leonard M. (1971) "17th Steam
Station Cost Survey." Electrical
World (November 1, 1971), as cited in *
Council on Environmental Quality (1973)
Energy and the Environment; Electric
Power. Washington: Government Print-
ing Office.
ENERGY CONSUMPTION
Berg, Charles A. (1973) "Energy Conservation
Through Effective Utilization,"
reprinted in Energy Conservation and
S.2176, Hearings before the Committee
on Interior and Insular Affairs, U.S.
Senate, 93rd Cong., 1st sess.,
pp. 552-561.
Federal Council on Science and Technology,
Committee on Energy Research, as cited
in Charles A. Berg (1974) "A Technical
Basis for Energy Conservation."
Technology Review 76 (February 1974):
14-23.
Hirst, Eric, and Robert Herendeen (1973)
Total Energy Demand for Automobiles.
New York: Society of Automotive
Engineers. Reprinted in Energy Conser-
vation and S.2176. Hearings before the
Committee on Interior and Insular
Affairs, U.S. Senate, 93rd Cong.,
1st sess., August 1973, pp. 970-976.
Hirst, Eric, and John C. Moyers (1973)
"Efficiency of Energy Use in the United
States." Science 179 (March 30, 1973):
1299-1304.
Hittman Associates, Inc. (1974) The
Automobile—Energy and the Environment;
A Technology Assessment of Advanced
Automotive Propulsion Systems.
Columbia, Md.: Hittman Associates, Inc.
Office of Emergency Preparedness (1972)
The Potential for Energy Conservation.
Washington: Government Printing Office.
Szego, G.C. (1971) The U.S. Energy Problem.
Warrenton, VA.: InterTechnology
Corporation.
A-16-30
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GLOSSARY
Area mining—A surface mining technique used in flat terrain.
Air classification—A method of separation whereby air is forced up a
cylindrical container at a certain velocity, causing light materials
to escape from the top and heavier materials to fall to the bottom.
Aldehyde—Any of various organic compounds containing a carbonyl group
(CO) and a hydrocarbon group such as CH3. The carbonyl group is
linked to the hydrocarbons at the end of the chain.
Ambient—A term referring to conditions in the vicinity of a reference
point, usually related to the physical environment (e.g., the ambient
temperature is the outdoor temperature).
Amine—Any of various organic compounds containing the chemical group
NH2f NH or N and a hydrocarbon group such as CH3-
Ancillary energy—A measure of the external energy required for an energy
process. It includes such things as energy for process heat,
electricity for pumps, and fuel for truck, train, or barge
transportation.
ANFO—An explosive which is composed of ammonium nitrate and fuel oil.
Anthracite—A high-rank coal with high fixed carbon, percentages of
volatile matter and moisture; a late stage in the formation of
coal (see Rank).
API gravity—A measure of the mass of a fluid relative to water; it
is inversely proportional to viscosity.
Aquifer—Water-bearing permeable rock, sand or gravel.
Ash—The residue left when combustible material is thoroughly burned
or otherwise oxidized.
Auger—A screw-type mechanism used in the transference or excavation
of solid materials.
Backfilling—A reclamation technique which returns the spoils to mined
cuts or pits. This leaves the land in a configuration similiar
to the original form.
Baghouse—A fabric filter used to separate particulates from an
airstream.
Basin—A geologic or land-surface feature which is lower in the center
and higher at the sides. Geologic basins may be filled with sediment
and not visible from the surface.
Bench—A flat excavation.
Bench test—A small scale laboratory test of a process, preceding pilot
plant testing.
Beneficiation—Cleaning and minimal processing to remove major impurities
or otherwise improve properties.
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Binary cycle—Combination of two turbine cycles utilizing two different
working fluids in electrical generation plants. The waste heat
from the first turbine cycle provides the heat energy for the
second turbine cycle.
Biochemical oxygen demand (BOD)—The amount of oxygen required by
bacteria to convert organic material into stable compounds.
Bioconversion—The conversion of organic wastes into methane (natural
gas) through the action of microorganisms.
Biomass—The amount of living matter in a unit area or volume; the
living weight.
Bit—The cutting or boring element used in drilling.
Bitumen—A general name for various solid and semi-solid hydrocarbons;
a native substance of dark color, comparatively hard and nonvolatile,
composed principally of hydrocarbons.
Bituminous—An intermediate-rank coal with low to high fixed carbon,
intermediate to high heat content, a high percentage of volatile
matter, and a low percentage of moisture (see Rank) .
Blanket—The area immediately surrounding the reactor core in a liquid
metal fast breeder reactor. Its major function is to produce
plutonium-239 from uranium-238.
Slowdown—The release or cleaning out of water with high solids content,
the solids having accumulated each time water evaporates.
Blowout—An uncontrolled flow of gas, oil and other well fluids from a
well into the atmosphere. A well blows out when formation pressure
exceeds the counter-pressure being applied by the drilling fluid.
Blowout preventer—Equipment installed at the wellhead for the purpose
of controlling pressures in the annular space between the casing
and drill pipe or in an open hole during drilling and completion
operations.
Boiler—A mechanism which burns fuel to create heat energy and transfer
the heat to a fluid (generally water/steam).
Box cut—Initial excavation in a mine that penetrates a hill resulting
in walls on three sides, with spoils dumped over the slope.
Brayton cycle engine—Turbine cycle engines using internal heat sources,
usually from the burning of fossil fuels.
Breeder reactor—A nuclear reactor that produces more fissile material
than it consumes. This reactor is sometimes called the fast breeder
because high energy (fast) neutrons produce most of the fissions
in current designs.
Brine—Water saturated with salt; a strong saline solution.
Btu (British thermal unit) —The amount of energy necessary to raise the
temperature of one pound of water by one degree Fahrenheit, from
39.2 to 40.2 degrees Fahrenheit.
Bucket-wheel excavator—A continuous mining machine which uses scoops
mounted in a circular rotating frame to remove overburden and deposits.
Cake—To form or harden in a cohesive mass; to form a hard or brittle
layer or deposit.
Carnot efficiency—The maximum efficiency with which work can be produced
from heat in ideal processes. Carnot efficiency is only dependent
upon the maximum and minimum temperatures available.
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Catalysis—Modification and especially an increase in the rate of a
chemical reaction induced by material unchanged chemically at the
end of the reaction; any reaction brought about by a separate agent.
Catalyst—A substance that induces catalysis.
Catalytic conversion—A chemical reaction induced by a catalyst.
Centrifugal separator—A device which separates two fluids, or a fluid
and a solid of different density by rotating them rapidly and forcing
the denser material to the outside.
Char—A mixture of ash and carbon which remains after partial combustion
or heating.
Chemical oxygen demand (COD)—The amount of oxygen required to convert
(oxidize) organic compounds into stable forms—usually carbon
dioxide and water. COD includes all compounds requiring oxidation
while BOD includes only the biodegradable fraction.
Christmas Tree—The assembly of valves, pipes, and fittings used to
control the flow of oil and gas from a well.
Cladding—The long, tube—like container in which uranium or plutonium
oxide fuel pellets are encased.
Clarifier—A unit operation in wastewater treatment cleaning the water
of some suspended'solids. Rotary scrapers in square or circular
tanks are used to move the sludge in the water toward the center
of the tank where it is removed by pumping.
Claus recovery plant—A Glaus plant takes emission gas streams containing
10 percent or more hydrogen sulfide and oxidizes the hydrogen slufide,
producing elemental sulfur of high purity.
Coal—A solid, combustible organic material.
Coke—The solid, combustible residue left after the destructive distillation
of coal, crude petroleum or some other material.
Combined cycle—Combination of a steam turbine and gas turbine in an
electrical generation plant (see Binary cycle).
Continuous miner—A single machine used in underground mining which
accomplishes excavating,, loading and initial transportation operations.
Contour mining—A mining technique used in steeply-sloped terrain where a
seam outcrops on a slope.
Control rods—Devices that are inserted into the nuclear reactor core to
control the chain reaction and permit a change in power level.
Core—A sample removed from a drilled hole.
Cracking—The process of breaking up large molecules in refinery feedstock
to form smaller molecules with higher energy content.
Critical mass—An amount of fissile material that can sustain a chain
reaction.
Cryogenic techniques—Techniques involving the use of extremely low
temperatures to keep certain fuels in a liquid form (e.g., liquefied
hydrogen, methane, propane).
Curie—A curie measures the radioactivity level of a substance; i.e., it
is a measure of the number of unstable nuclei that are undergoing
transformation in the process of radioactive decay. One curie equals
the disintegration of 3.7xl010 nuclei per second.
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Cuttings—Solid material removed from a drilled hole.
Cyclone—A cleaning device which uses a circular flow to separate the
heavier particulates from stack gases.
Dedicated railroad—A system in which the right-of-way, rails and rolling
stock are used exclusively to transport a single resource.
Devolatilization—The removing of volatile matter from coal; mostly used
as a pretreatment step to destroy the caking property of coal.
Direct heat—Heating of a substance through immediate contact with a
combustion zone.
Distillation—Heating a liquid mixture in order to drive off gases or
vapors which are then separated according to boiling point and
condensed into liquid products.
Dolomite—A mineral, CaMg(CO3>2» found as crystals and in extensive
beds as a compact limestone.
Down-hole well-logging instruments—Instruments which measure characteristics
of formations such as electrical resistivity, radioactivity, and
density. The information is used to evaluate the formations for
petroleum content.
Dragline—An excavating machine used for the removal of overburden in
open pit mines. It has a boom from which is suspended a bucket which
is filled by dragging.
Dredge—A machine for removing earth underwater, usually by buckets on an
endless chain or by a suction tube.
Drilling rig—The derrick, drawworks and attendant surface equipment
used to drill or service an oil well.
Drill pipe—In rotary drilling, the heavy seamless tubing used to rotate
the bit and circulate the drilling fluid. Individual pipe lengths are
normally 30 feet and are coupled together with tool joints (see Drill
string; Rotary drilling).
Drill string—A column of pipe that connects to a bit used to bore (drill)
holes for wells.
Electrolysis—Chemical changes produced by passage of an electric current
through an easily ionized liquid called an electrolyte.
Emergency core cooling system (ECCS)—A safety system in a nuclear reactor
whose function is to prevent the fuel in a nuclear reactor from
melting if a-sudden loss of coolant occurs. It consists of a reserve
system of pipes, valves and water supplies designed to flood water
into the core.
Energy intensiveness—In transportation, the relative amount of energy
required to move one unit (one passenger or one ton of cargo) a
distance of one mile. In industry, the ratio of total energy
consumed for each dollar of production goods shipped out.
Enrichment—The process by which the percentage of the fissionable
isotope, U-235, is increased above that contained in natural
uranium.
Entrained bed—A coal combustion (or gasification) process in which
pulverized coal is carried along in a gas stream.
Equity—The net worth of a firm or corporation (total assets less total
debts).
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Eutectic—A mixture of two metals having the lowest melting point oossiblP
of any ratio of the two.
Exothermic—Refers to a chemical reaction that gives off heat.
Fast flux test facility (FFTF)--A liquid metal fast breeder reactor presently
under construction whose purpose is to test various fuels and reactor
core components.
Feedstock—Raw material supplied to a processing plant.
Ferrous—Of, relating to, or containing iron.
Fischer assay—A standardized laboratory procedure which removes oil from
oil shale, used as a basis for comparing oil shale processing alterna-
tives and shale feedstocks.
Fissile material—Uranium-233, uranium-235, or plutonium-239. Fissile is
a label for an atom that will fission upon absorption of a low energy
neutron.
Fission—The splitting of an atomic nucleus, resulting in the release of
energy.
Fixed bed—A coal combustion (or gasification) process in which the coal
is combusted on a stationary platform.
Fixed carbon—The solid, non-volatile, combustible portion of coal.
Fixed charge—Expenses which have to be borne whether any business is done
or not. The chief items are the company's interest on bonds or other
external borrowings, some taxes levied by the government, insurance
payments, and depreciation due to obsolescence.
Fixed cost—The cost of a business which exists regardless of the amount
of production, for example, depreciation of a building or insurance.
Fixed investment--Outlays for land, plant, equipment, etc. occurring only
in the initial time period of the life of an investment.
Flash separation—Distillation to separate liquids of different volatility,
accomplished by a rapid reduction in the pressure on the liquid.
Flat plate collector—Solar energy collector characterized by non-concentra-
tion of solar radiation.
Flat-rating—Limit placed on the maximum output of a power source for
economic or technical reasons.
Flue gases—Gases, usually carbon dioxide, water vapor, oxides of nitrogen
and other trace gases, which result from combustion processes.
Fluidized bed—A body of finely crushed particles with a gas blown through
them. The gas separates the particles so that the mixture behaves
like a turbulent liquid.
Fluidized bed boiler—A new type of boiler designed to reduce combustion
product pollutants and reduce boiler size (see Fluidized bed).
Fly ash—Lightweight solid particles which are carried by stack gases.
Fracturing—Splitting or cracking by explosion or other source of pressure
to make rock more permeable or loose.
Front end loader—A tractor with a large bucket mounted on arms that can
scoop up material and raise the load for dumping into a truck.
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Froth-flotation—A separation process that uses the surface wetting behavior
of chemicals to precipitate some materials and float others in an aerated
pond.
Fuel cell—A device that produced electrical energy directly from the con-
trolled electrochemical oxidation of fuel. It does not contain an
intermediate heat cycle, as do most other electrical generation
techniques.
Fuel fabrication—The manufacturing and assembly of reactor fuel elements
containing nuclear fuel material.
Fuel pin—A long, approximately 12 to 15 foot, thin tube that is approxi-
mately one-half inch in diameter. The tube is filled with nuclear
fuel pellets.
Fusion—The combining of certain light atomic nuclei to form heavier nuclei
resulting in the release of energy.
Gallium arsenide—A compound used in making photovoltaic cells.
Gaseous diffusion—The process used to "enrich" nuclear fuel. The fuel in
the form of a gas passes through a thin membrane. Light gas molecules
move at a higher velocity than heavy molecules. These light molecules
strike and pass through the membrane more often than the heavy molecules.
Gasification—Commonly refers to the conversion of coal to a gas fuel.
Generator—A mechanism which converts mechanical energy to electrical energy.
Gilsonite—Very rich tar deposits; a tar sand with a very high hydrocarbon
content and low mineral content.
Graphite—Soft black carbon. A special form is used as a moderator in
nuclear power plants (see Moderator).
Gravimetric survey—An exploration method which involves interpreting the
probable density of minerals in the earth by measured gravity variations.
Groundwater—Water which is underground in an aquifer (see Aquifer).
Hammermill shredder—A cylindrical machine which is lined with spike-shaped
projections which are utilized to tear and break up organic waste
material.
"Head of hollow" method—A method of reclamation whereby solid residuals
are deposited in a naturally-occurring deep canyon.
Heat exchanger—A device in which heat energy is transferred from one fluid
to another due to a temperature difference between the two fluids.
Heat pump—A method of moving, concentrating or removing heat by alternately
vaporizing and liquefying a fluid through the use of a compressor. A
reversible refrigeration system that can provide heat.
Helical screw expander—A spiral shaped machine for driving a generator
through which hot water and steam expand.
High-Btu gas—An equivalent of natural gas, predominantly methane; obtained
by methanating synthesis gas; energy content is usually 950 to 1,000
Btu's per cubic foot.
High temperature gas reactor—A nuclear reactor in which helium gas is the
coolant with graphite fuel elements containing coated particles of
highly enriched uranium plus thorium.
Highwall—The unexcavated face of exposed overburden and coal (or other
resource) in a surface mine.
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f0rmed b^ the »ion of water with some other
water streams are em^ed to
Hydrocarbon—Organic compounds containing only carbon and hydrogen charac-
teristically occurring in petroleum, natural gas, coal and b^umens
reaCtiOn °f Carb°n W±th hydrogen to produce
Hydrogenat ion— Adding hydrogen to an organic compound.
Hydrostatic head—The pressure created by the weight of a height column of
Hydrotreat ing— Using a catalyst, high temperature, and high pressure to
change the structure of a molecule through the addition of hydrogen
An additional benefit may be the removal of sulfur as hydrogen sulfide
in the process .
Impulse turbine— A turbine driven by high velocity jets of water or steam
which impinge on some kind of vane or bucket attached to a wheel Th«=>
high velocity jets are produced by forcing the water and steam through
a nozzle.
In situ — In the natural or original position; applied to energy resources
when they are processed in the location where they were originally
deposited.
Irradiated fuel — Nuclear fuel that has been used in a nuclear reactor.
Isotope — One of two or more atoms with the same atomic number (i.e., the
same chemical element) but with different atomic weights. Isotopes
usually have very nearly the same chemical properties, but somewhat
different physical properties.
Kerogen — A solid, largely insoluble organic material occurring in oil shale
which yields oil when it is heated but not oxidized.
Ketone — Any of various organic compounds containing a carbonyl group (C)
and a hydrocarbon group such as CH3 . The carbonyl group is linked to
the hydrocarbon groups in the middle of the chain resulting in at
least one hydrocarbon group on each side of the carbonyl group.
Kiln — An oven, furnace, or heated enclosure used for processing a substance
by burning, firing or drying.
Kilocalorie — One thousand calories. A unit of energy equal to 3.968 Btu's.
Kinetic energy — The energy that an object possesses because it is moving;
it is determined by the mass and the speed of the object.
Krypton-85 — An inert radioactive gas which is a fission product of U-235 or
Pu-239.
Leaching — The continued removal, by water, of soluble matter from rock or
soil.
Lean gas — Refers to processed gas.
Light water reactor — A nuclear reactor which uses water (H2O) to transfer
heat from the fissioning of uranium to a steam turbine.
Lignite — The lowest-rank coal, with low heat content and fixed carbon, and
high percentages of volatile matter and moisture; an early stage in
the formation of coal.
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Liquefaction of gases—Any process by which gas is converted from the gaseous
to the liquid phase.
Liquefied natural gas—A clean, flammable liquid existing under very cold
(see cryogenic) conditions, that is, almost pure methane.
Lock hopper—A device for introducing solids, such as coal, into a
pressurized system.
Longwall Mining Removing a mineral from an extensive exposed surface
of a deposit usually underground where minerals are removed by a shearing
machine, and roof support is provided by movable hydraulic jacks.
Loss of coolant accident—An accident in a nuclear reactor where the coolant
is lost from the reactor core. For example, a break in a coolant pipe
in the reactor cooling system would cause this accident.
Low-Btu gas—Gas obtained by partial combustion of coal with air; energy
content is usually 100 to 200 Btu's per cubic foot.
Magma—Naturally occurring melted and mobile rock material occurring within
the earth's crust and consisting mainly of liquid material with sus-
pended crystals and bubbles of gas in it.
Magnetic survey—An exploration method based on distortions in the normal
magnetic field of the earth's crust.
Megawatt—A megawatt is a million watts or a thousand kilowatts and is used
to measure the amount of power as electricity that can be produced by
a facility at any one time.
Mercaptan—Any of various organic compounds containing a sulfur and hydrogen
group (SH) and a hydrocarbon group such as CH3- The sulfur present in
the compound often causes disagreeable odors.
Methanation—The catalyzed reaction of CO and H2 to form CH4 and H2O.
Methane—A colorless odorless flammable gaseous hydrocarbon, CH4> that is
a product of decomposition of organic matter in marshes or mines or
of the carbonization of coal. It is used as a fuel and as a raw
material in chemical synthesis.
Micron—A unit of length equal to one thousandth of a millimeter.
Microsphere—A small nuclear fuel particle that is coated with layers of
graphite; used in the HTGR.
Milling—A process in the uranium fuel cycle where ore which contains only
.2 percent uranium oxide (0303) is converted into a compound called
yellowcake which contains 80 to 83 percent U3OQ.
Mine-mouth—The vicinity or area of a mine, usually within several miles.
Moderator—A material used in some reactors; the purpose is to reduce the
energy of neutrons.
Mole—A large diameter drill mounted on a movable framework capable of
tunneling holes of 5 to 30 feet in diameter.
Monazite~A yellow, red, or brown phosphate of the cerium metals and thorium
found often in sand and gravel deposits.
Mrem—A unit used to measure a radiation dose.
Naphtha—Any of various volatile, often flammable liquid hydrocarbon mix-
tures used chiefly as solvents and dilutents.
Natural background radiation—The amount of radiation present in the environ-
ment which is not the result of man's activities.
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Natural gas—A mixture of light weight hydrocarbons in geologic deposits,
with its predominant compound being methane.
Noble gas—The gases helium, neon, argon, krypton, xenon, and radon which
do not normally combine chemically with other elements.
Ocean thermal gradient—Difference in temperature of the ocean water at
various depths.
DCS (outer continental shelf)—The submerged lands extending from the
outer limit of the historic territorial sea (typically three miles)
so some undefined outer limit, usually a depth of 200 meters. In
the U.S., this is the portion of the shelf under federal jurisdiction.
Octane number—A measure of a gasoline's ability to burn smoothly.
Oil shale—Sedimentary rocks containing insoluble organic matter (kerogen)
which can be converted into oil by heating.
Operating costs—Costs that vary with the level of output such as labor
costs, raw material costs, supplies, etc.
Outcrop—A place where a mineral formation is exposed to direct observa-
tion from the land surface.
Overburden—The rock, soil, etc., covering a mineral to be mined.
Paramarginal resources—Deposits not currently produced because the
recovery is not quite economically feasible or because, although
recovery is economically feasible, legal or political circumstances
do not allow it.
Particulates—Microscopic pieces of solids which emanate from a range
of sources and are the most widespread of all substances that are
usually considered air pollutants. Those between 1 and 10 microns
are most numerous in the atmosphere, stemming from mechanical
processes and including industrial dusts, ash, etc.
Penstock—A pipe which transports water to a turbine for the production
of hydroelectric energy.
Permeability—The ability of a porous medium to conduct fluid through it.
Phenol—Any of various organic compounds containing a hydroxide group (OH)
and a hydrocarbon group such as CH3- Phenols are highly reactive
compounds.
Photosynthesis—The synthesis of chemical compounds with the aid of
radiant energy, especially light; the formation of carbohydrates
in the chlorophyll-containing tissues of plants exposed to light.
Photovoltaic cells—A method for direct conversion of solar electrical
energy. Commercially available cells are limited to an efficiency
of 10 percent.
Pillar—A solid mass of coal, rock, or ore left standing to support a
mine roof.
Placer deposit—A deposit of clay, silt, sand, gravel or some similar
material deposited by running water which contains particles of
uranium, gold, or some other valuable mineral.
Plutonium—An element that is very rare in nature, and is usually
obtained by exposure of U-238 to neutrons in a reactor.
Pneumatic drill—A drill which is worked by air pressure.
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Primary containment—Also referred to as a pressure vessel. The •
primary containment is an enclosure Which surrounds the nuclear
reactor core and associated equipment for the purpose of
minimizing the release of radioactive material in the event of
a serious malfunction in the operation of the reactor.
Profit margin—Profit as a percentage of sales.
Province—The largest unit used by the USGS to define the areal
extent of coal resources.
Pyrolysis—Decomposition of materials through the application of
heat with insufficient oxygen for complete oxidation.
Radiometric prospecting—Finding minerals using a geiger counter or
scintillometer that measures radioactivity.
Radon gas—A radioactive gaseous element formed by disintegration
of uranium.
Raffinate stream—In the solvent extraction process there are two
output streams. One is the "pregnant" stream containing the
recovered valuable material such as uranium and plutonium.
The raffinate stream contains the unneeded material; the
raffinate is transferred to a pond.
Rank—A classification of coal according to percentage of fixed
carbon and heat content. High rank coal is presumed to have
undergone more geological and chemical change than lower rank
coal.
Rankine cycle—A cycle of processes to produce work from heat,
commonly using steam as a working fluid (a steam engine).
Reactor core—The part of a nuclear power plant which contains control
rods and the fuel elements where fissioning occurs.
Rem—A unit of radiation dose. Quantities of radiation dose are often
quoted in millirem units (see Mrem).
Reprocessing—The used fuel elements from a nuclear reactor are sub-
jected to a variety of chemical and mechanical processes; the
purpose is to recover the created plutonium-239 and the unused
uranium-235, and to remove the fission products.
Reserves—Resources which are known in location, quantity and quality
and which are economically recoverable using currently available
technologies.
Retort—A closed heating facility used to process oil shale.
Room and pillar—An underground mining technique in which small areas
of a coal or oil shale seam are removed and columns of the deposit
are left in place to support the roof.
Rotary drill—A machine which uses a revolving bit to bore out holes.
Rotary drilling—The drilling method by which a hole is drilled by a
rotating bit to which a downward force is applied. The bit is
fastened to and rotated by the drilling string, which also pro-
vides a passageway through which the drilling fluid is circulated.
New joints of drill pipe are added as drilling progresses (see
Bit, Drill string. Rotary drill).
Rotary kiln—A heated horizontal cylinder which rotates to dry coal.
Runoff—The portion of precipitation on the land that ultimately
reaches streams.
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Ruthenium-106—A radioactive fission fragment with a half life of
369 days. Ruthenium-106 does not occur in nature.
Scintillometer—A device that is sensitive to various types of
radiation.
Scrubber—Equipment used to remove pollutants, such as sulfur dioxides
or particulate matter, from stack gas emissions usually by means
of a liquid sorbent.
Seam—A bed of coal or other valuable mineral of any thickness.
Secondary recovery—Methods of obtaining oil and gas by the augmenta-
tion of reservoir energy; often by the injection of air, gas,
or water into a production formation (see Tertiary recovery).
Seismic survey—A geophysical exploration technique in which generated
sound waves are reflected or refracted from underlying geologic
strata and recorded for later analysis.
Shearing machine—An excavating machine used in longwall mining which
has a rotating toothed drum which cuts parallel to the coal face.
Shift conversion—A step in the process of converting coal to methane
(CH4); during this step the ratio of H2 to CO is altered to 3:1
through the use of a catalyst.
Shortwall mining—A variation of longwall mining in which a continuous
miner rather than a shearer is used on a shorter working face;
identical advance roof supporters are used (see Longwall mining).
Silt—Loose sedimentary material with rock particles usually 1/20
millimeter or less in diameter.
Siltation—The deposition or accumulation of fine particles that are
suspended throughout a body of standing water or in some con-
siderable portion of it; especially the choking, filling or
covering with stream-deposited silt behind a dam or other place
of retarded flow in a reservoir.
Slag—A molten or solidified ash.
Sludge—A muddy or slushy deposit or sediment.
Slug—A section of heavy or dense fluid between two lighter fluids in a
pipeline or other flow passage.
Slurry—A mixture of a liquid and solid. Explosive slurries of ammonium
nitrates, TNT and water are used for blasting. Slurries of oil
and coal or water and coal are used in coal processing and transporta-
tion .
Solar constant—The solar radiation falling on a unit area at the outer
limits of the earth's atmosphere.
Solvent—A substance capable of dissolving or dispersing one or more
other substances.
Spoils—The rock, soil, etc., of the overburden after it has been
broken and removed from above the coal seam.
Spot market price—The price of energy commodities sold for cash or
immediate delivery.
Stack gas—Gases resulting from combustion.
Stack gas cleaning—Referring to the removal of pollutants from combus-
tion gases before those gases are emitted to the atmosphere.
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Subbituminous—A low-rank coal with low fixed carbon and high
percentages of volatile matter and moisture (see Rank).
Subsidence—The sinking, descending or lowering of the land surface.
Sulfur dioxide (802)—One of several forms of sulfur in the air; an
air pollutant generated principally from combustion of fuels that
contain sulfur. A natural source of sulfur dioxide is volcanic
gases.
Super heat—A condition in which the volume of steam is a function of
both pressure and temperature. It has a higher energy than
steam in which the volume is only a function of temperature.
Surfactant—Surface acting agent; a chemical which reduces the surface
tension between two materials, causing one to be "washed" from
the surface of the other.
Syncrude—A liquid obtained by processing oil shale or coal.
Synthesis gas—Intermediate-Btu gas; almost always used as a feedstock,
but it can be used as a starting point for the manufacture of
high-Btu gas, methanol or other products.
Tailings—Refuse material separated as residue in the preparation of
various products (as ores).
Tar—A dark brown or black bituminous liquid obtained by destructive
distillation of organic material or more commonly, a viscous oil.
Tar Sands—Hydrocarbon-bearing deposits distinguished from more con-
ventional oil and gas reservoirs by the high viscosity of the
hydrocarbon, which is not recoverable in its natural state
through a well by ordinary production methods.
Tertiary recovery—Use of heat and other methods other than fluid
injection to augment oil recovery (presumably occurring after
secondary recovery).
Thorium—A radioactive element of atomic number 90; naturally occurring
thorium has one main isotope—thorium-232. The absorption of a
neutron can result in the creation of uranium-233.
Throttle valve—A valve used in space cooling equipment which expands
the fluid in the system to produce a cooling effect.
Trajectory—The overall combination of the technological alternatives
chosen for each activity in resource development.
Tramp iron—Stray metal objects such as picks or bolts, which have
become mixed with coal or ore, usually removed by magnets before
they damage the ore-handling machine.
Tritium (H_)—A radioactive isotope of hydrogen.
Trommel screen—A usually cylindrical or conical revolving screen used
for screening or sizing substances such as rock, ore, or coal.
Turbine—A rotary engine activated by the reaction and/or impulse of a
current of pressurized fluid (water, steam, liquid metal, etc.)
and usually made with a series of curved vanes on a central rotating
spindle.
Uranium—A radioactive element of atomic number 92; naturally occurring
uranium consists of 99.29 percent uranium-238 and .71 percent
uranium-235.
Uranium-235—An isotope of uranium of mass number 235. When bombarded
with slow or fast neutrons it will undergo fission.
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Uranium-238—An isotope of uranium; naturally occurring uranium consists
of 99.29 percent uranium-238 and .71 percent uranium-235- uranium-
uranium-238 will fission upon absorption of a fast neutron or can
be converted to plutonium-239.
Uranium hexafluoride (UFg)—A gaseous compound of uranium; used in the
diffusion process of enrichment.
Uranium oxide (U30g)—The most common compound of uranium that is found
in typical ores.
Venturi scrub—A method for cleaning particulates from stack gases
which consists of water being injected into a high-speed gas flow.
The particulates are removed with the water.
Viscosity—The property of a fluid which indicates its ability to resist
flow.
Volatile—Readily vaporizable at a relatively low temperature.
Well bleeding—Allowing a bore hole (usually in reference to a geothermal
well) to vent to the atmosphere for the purpose either of clearing
it of impurities or of testing it.
Wellbore—The hole made by the drilling bit.
Wellhead—The equipment used to maintain surface control of a well. It
is formed of the casing head, tubing head, and Christmas tree.
Also refers to various parameters as they exist at the wellhead:
wellhead pressure, wellhead price of oil, etc.
Working fluid—Fluid in electrical generation plants that is heated by
the energy source and then expands through the turbine without
leaving the system.
Yellowcake—Product of the milling process in the uranium fuel cycle
that contains 80 to 83 percent uranium oxide.
Xenon—An inert gas used in specialized electric lamps, present in air
at about .05 parts per million.
* U. S. GOVERNMENT PHINTING OFFICE : 1975 O - 570-834
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