EPA-460/3-74-012-B
July 1974
ALTERNATIVE FUELS
FOR AUTOMOTIVE
TRANSPORTATION -
A FEASIBILITY STUDY
VOLUME II - TECHNICAL SECTION
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
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EPA-460/3-74-012-b
ALTERNATIVE FUELS
FOR AUTOMOTIVE TRANSPORTATION
- A FEASIBILITY STUDY
VOLUME II - TECHNICAL SECTION
Prepared by
J. Pangborn, J. Gillis
Institute of Gas Technology
Chicago, Illinois 60616
Contract No. 68-01-2111
EPA Project Officer:
E. Beyma
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
July 1974
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22151.
This report was furnished to the Environmental Protection Agency by
The Institute of Gas Technology in fulfillment of Contract No. 68-01-2111
and has been reviewed and approved for publication by the Environmen-
tal Protection Ag'ency. Approval does not signify that the contents
necessarily reflect the views and policies of the agency. The material
presented in this report may be based on an extrapolation of the "State-
of-the-art." Each assumption must be carefully analyzed and conclusions
should be viewed correspondingly. Mention of trade names'or commer-
cial products does not constitute endorsement or recommendation for use.
Publication No. EPA-460/3-74-012-b
11
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PREFACE
This report is the result of a research team effort at the Institute of Gas
Technology. In addition to the authors, the major contributors to the study
were J. Fore, P. Ketels, W. Kephart, and K. Vyas.
This report consists of three volumes:
Volume I Executive Summary
Volume II Technical Section
Volume III Appendices.
111
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TABLE OF CONTENTS
Page
1. INTRODUCTION l
1. 1 Purpose and Objectives 1
1.2 Scope and Definitions 2
2. FUEL SELECTION METHODOLOGY 5
2. 1 Fuel Evaluation Procedure 5
2.2 Resource Base 8
2.3 Economic Model Effect 9
2. 4 Synthesis Technology 10
2.5 Fuel Properties n
2. 6 Environmental Effects 14
2. 7 Fuel System Economics 14
2. 8 Technology and Information Gaps 15
2.9 Reference Cited 16
3. U.S. DOMESTIC RESOURCE BASE 17
3. 1 Hydrocarbon Reserves ' 18
3.1.1 Coal 18
3. 1. 2 Crude Oil 28
3. 1. 3 Natural Gas 32
3. 1.4 Natural Gas Liquids 34
3. 1. 5 Oil Shale 36
3. 1. 6 Tar Sands 39
3. 2 Nuclear Energy Resources 40
3. 2. 1 Uranium 40
3.2.2 Thorium 41
3.2.3 Nuclear Fusion Reactors 43
3. 3 Renewable Resources 43
3.3.1 Hydropower 43
3.3.2 Geothermal Heat 43
3.3.3 Solar Energy 45
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TABLE OF CONTENTS, Cont.
Page
3.3.4 Tidal Energy 46
3.3.5 Wind Power ' 48
3.3.6 Waste Materials 49
3.3.7 References Cited 54
4. ENERGY DEMAND AND SUPPLY MODELS 57
4. 1 Model I 57
4. 2 Model II 64
4. 3 Automotive Sector 73
4. 3. 1 Model I for Automotive Sector 75
4. 3. 2 Model II for Automotive Sector 77
4. 4 Model III 78
4. 4. 1 Case A 81
4. 4. 2 Case B 81
4. 4. 3 Case C 81
4.5 References Cited 83
5. FUEL SYNTHESIS TECHNOLOGY 85
5. 1 Fuel Synthesis From Coal 85
5. 2 Fuel Synthesis From Oil Shale 96
5. 3 Fuel Synthesis From Nuclear Energy 100
5. 4 Fuel Synthesis From Solar-Agricultural Sources
and Waste Materials 105
5. 4. 1 Solar Energy to Electricity 106
5. 4. 2 Solar Energy to Agricultural Products 107
5. 4. 3 Fuel Synthesis From Biomass and Waste Materials 108
5. 5 References Cited 118
6. FUEL PROPERTIES AND COMPATIBILITY 123
6. 1 Transmission and Distribution Compatibility 123
6. 2 Vehicle Tankage of Alternative Fuels 126
6. 3 Engine and Fuel Compatibility 129
VI
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TABLE OF CONTENTS, Cont.
Page
6. 3. 1 Conventional Otto-Cycle Engines 130
6.3.2 Open-Chamber Stratified-Charge Engines 145
6.3.3 Dual-Chamber Stratified-Charge Engines 147
6.3.4 Diesel Engines 147
6. 3. 5 Brayton-Cycle Engines 149
6.-3.6 External-Combustion Engines 150
6. 3. 7 Fuel-Cell Power Plants 150
6.4 References Cited 155
7. ENVIRONMENTAL EFFECTS AND RESOURCE DEPLETION 161
7. 1 Environmental Effects 161
7. 1. 1 Fuel Consumption and Emissions 161
7. 1.2 Synthesis Plants and Effluents 164
7.2 Resource Depletion 166
8. ALTERNATIVE FUEL SYSTEM ECONOMICS 173
8. 1 Costs of Resource Extraction and Fuel Synthesis
(Preliminary) 174
8.2 Fuel Transmission and Distribution Costs (Preliminary) 176
8.3 Fuel Utilization Costs 179
8. 4 Costs of Resource Extraction and Fuel Synthesis
(Candidate Fuels) 181
8. 4. 1 Nuclear-Reactor-Heat Cost Analysis 185
8. 4. 2 Thermochemical Plant Cost Analysis 187
8. 5 Costs of Transmission and Distribution (Candidate Fuels) 190
8. 6 Candidate Fuel System Costs 194
8. 7 Analysis of Future Real Costs (Noninflationary) 194
8. 7. 1 Objectives and Project Life 197
8.7.2 Future Prices 198
8.7.3 Projections of Future Fuel Production Costs 200
8.7.4 Future Domestic Crude Oil and Refinery Product
Cost Analysis 202
8.7.5 Future Shale-Oil-Production Cost Analysis 206
8.7.6 Future Coal-Processing Cost Analysis 209
8.7.7 Future Real Cost Increases for Thermochemical
Hydrogen 217
8.7.8 Future Cost Analysis Summary 221
8.8 References Cited 224
vii
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TABLE OF CONTENTS, Cont.
Page
9. TECHNOLOGY AND INFORMATION GAPS 227
9. 1 Serious Technology Gaps 227
9. 1. 1 Solar Energy to Chemical Fuel 227
9.1.2 Demonstration of Nuclear Fusion 228
9.1.3 Hydrogen From Water 228
9.2 Moderate Technology Gaps 229
9.2.1 Breeder Reactors 229
9. 2. 2 Distribution of Cryogenic Fuels 229
9. 2. 3 Vehicle Storage of Hydrogen 230
9.2.4 SLPG From Coal 230
9. 2. 5 Vehicle Combustion of Solvent-Refined Coal 230
9. 3 Information Gaps 231
10. SELECTION OF CANDIDATE ALTERNATIVE FUELS 235
10. 1 Preliminary Fuel Selection 235
10.1.1 Synthesis Technology 237
10.1.2 Fuel Availability 239
10. 1. 3 Safety and Handling ' 239
10.1.4 Compatibility and Utilization 240
10. 1. 5 Fuel Costs at Service Station 240
10.1.6 Selected Fuels 241
\
10.2 Selection of Energy Sources 242
10.3 Fuel Candidates for the Three Time Frames 242
10.3.1 Near-Term Time Frame (1975-1985) 244
10.3.2 Mid-Term Time Frame (1985-2000) 244
10.3.3 Far-Term Time Frame (2000-2020) 247
11. CONCLUSION AND SCENARIOS 249
11.1 Near-Term Time FrarrB (1975-1985) 249
11.1.1 Oil-Shale-Development Scenario
According to Models I and II 250
11. 1.2 Coal-to-Liquid Fuels Scenario
According to Models I and II 252
11. 1.3 Summary for Near Term Time Frame 254
11.2 Mid-Term Time Frame (1985-2000) 256
11.2.1. Oil-Shale Development Scenarios
According to Models Land II 257
viii
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TABLE OF CONTENTS, Cont.
""ace
11.2.2 Coal-to-Liquid Fuels Scenario
According to Models I and II 258
11.2.3 Summary for Mid-Term Time Frame 260
11.3 Far-Term Time Frame (2000-2020) 260
11.3.1 Nuclear-Based Fuels (Hydrogen) Scenario 261
11.3.2 Oil-Shale-Development Scenario 264
11.3.3 Coal-to-Liquid Fuels Scenario 264
11.3.4 Summary for Far-Term Time Frame 265
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LIST OF FIGURES
Figure No. Page
2-1 Alternative Fuel Evaluation Method 6
3-1 Estimated Mapped and Explored Coal Resources in
the U. S. (Total Shown, 1. 56 Trillion Tons) 22
3-2 Major Underground-Mining Regions of U. S.
Coal Fields .24
3-3 Major Surf ace-Mining Regions of U.S. Coal Fields . 25
3-4 Categorization of the U.S. Coal Resource Base 27
3-5 Petroleum Provinces of the U.S. 30
3-6 Distribution of U. S. Crude Oil Resource Base 31
3-7 Categorization of U. S. Potential Gas Supply 35
3-8 Categorization of Domestic Shale Oil Reserves 37
3-9 Location of Major Oil Shale Resources 38
3-10 Domestic Reserves of Uranium at $15 Per Pound
or Less 41
4-1 Comparison of Models I and II Energy Demand
and Supply Projections 66
4-2 Model II Energy Demand by Market Segment
(All Nuclear to Electricity Generation) 68
4-3 U. S. Refinery Gasoline Capacity 82
5-1 Production of Clean Fuels From Coal 86
5-2 Production of Clean Fuels From Oil Shale 97
5-3 Nuclear Fuel Cycle for Light Water Reactor 101
5-4 Coal Gasification Process Being Developed by
Stone and Webster and General Atomic 103
5-5 HTGR Application to Fuel Production 104
v-
5-6 Schematic Diagram of the Municipal Refuse Pyrolysis
Process With Fluidized Sand Recycle and Char Recycle 110
XI
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LIST OF FIGURES, Cont.
Figure No. Page
5-7 Schematic Drawing of Anaerobic Digestion in
Conventional Sewage Digester 115
5-8 Production of Ethanol From Agricultural Products 117
6-1 Effect of Equivalence Ratio on Engine Emissions 131
6-2 NOx Emissions From General Motors Laboratories'
CFR Engine Operating on Hydrogen 136
6-3 NOX Emissions From JPL's CFR Engine Operating
on Hydrogen 137
6-4 Thermal Efficiency of JPL's V-8 Engine on Hydrogen 138
6-5 Hydrocarbon Emissions as a Function of Air-Fuel
Equivalence Ratio at 50% Throttle 140
6-6 NOx Emissions as a Function of Air-Fuel
Equivalence Ratio at 50% Throttle 140
6-7 Operating Regions for Methanol and Isooctane 142
6-8 Reaction Front Speeds for Methanol and Isooctane 142
t ,
6-9 Hydrocarbon Emissions From an SNG-Fueled Engine 144
6-10 NOx Emissions From an SNG-Fueled Engine 144
6-11 Fuel Cell Types 151
7-1 Schematic Diagram of Resource Depletion Model 167
8-1 Distances to Major Coal Markets 176
Xll
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LIST OF TABLES
Table No. Page
1-1
1-2
2-1
2-2
3-1
3-2
3-3
3-4
3-5
3-6
3-7
3-8
3-9
3-10
3-11
3-12
3-13
3-14
3-15
3-16
Initial-Consideration List
Selected Candidate Fuels
Transportation Energy Demands and Shortfalls
According to Model I
SNG (From Coal) Production and Natural Gas Deficit
U. S. Energy Resource Base in Conventional Units
U. S. Energy Resource Base in Btu Equivalents
Underground Coal Reserves and Production
(Minable by Under ground Mining Methods)
Surface Coal Reserves and Production
(Minable by Surf ace -Mining Methods)
Oil-in-Place Resources
Summary of Estimated Potential Supply of Natural Gas
in the U. S. by Depth Increments as of December 31,1972
Summary of Oil Shale Resources in Green River
Formation
Estimated In-Place Resources of Utah Tar Sands
Deposits
Domestic Resources of Uranium as Estimated by
the AEC, January 1, 1973
In Situ Heat Resources
Estimate of Total Energy Available in Municipal
Wastes, 1970-2000
Estimated SNG Generated From Collected Municipal
Wastes, 1970-2000
Data on Population and Number of Cattle Slaughtered,
1950-1973
Estimate of Total Cattle Population, 1970-2000
Estimated Manure Production, 1975-2000
Estimated Potential Production of SNG From Manure,
4
4
8
10
18
20
23
27
29
33
37
39
40
44
50
50
51 .
52
52
1975-2000 53
xiii
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LIST OF TA BILES, Cont.
Table No. Page
4-1 Model I Energy Supply and Demand by Market Sectors 59
4-2 Model I Residential and Commercial Energy Supply
and Demand 61
4-3 Model I Industrial Energy Supply and Demand 61
4-4 Model I Electricity Conversion Supply and Demand 62
4-5 Model I Transportation Energy Supply and Demand 62
4-6 Model I Other Uses Supply and Demand 63
4-7 Energy Availability for Transportation in Model I 64
4-8 Model II Projected Energy Demands 67
4-9 Model II Residential and Commercial Energy
Supply and Demand 69
4-10 Model II Industrial Energy Supply and Demand 69
4-11 Model II Other Uses Energy Supply and Demand 70
4-12 Model II Transportation Energy Supply and Demand 70
4-13 Model II Electricity Conversion Energy Utilization 71
4-14 Model II Shortfalls (With No Imports) by Sector in
Electricity Supply 71
4-15 Distribution of Energy Consumption in Transportation
by Mode In 1969 73
4-16 Comparison of DOT, Department of the Interior, and
NPC Energy Demand Forecasts 75
4-17 Model I Transportation Energy Supply and Demand and
Automotive Deficit 76
4-18 Model II Transportation Energy Supply and Demand and
Automotive Deficit 77
4-19 U.S. Gross Energy Demand According to Models I,
II, and III 79
5-1 Processes for Producing SNG (Methane) From Coal 88
5-2 Processes for Producing Liquid Hydrocarbons
From Coal ' 90
xiv
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LIST OF" TABLES, Coht.
Table No. Page
5-3 Processes for Producing Synthesis Gas (Hydrogen
and Carbon Monoxide) From Coal 91
5-4 Processes for Methanol Production 92
5-5 Processes for Ammonia Production 93
5-6 Processes for Hydrogen Production 94
5-7 Processes for Producing Fuels From Oil Shale 98
5-8 Petroleum Products From and Fuel Consumed in
U. S. Refineries 99
5-9 Characteristics of Nuclear Model Plants 105
5-10 Fuel Value Production and Estimated Efficiencies
of Conversion of Solar Energy to Vegetable Matter 108
5-11 Products of Pyrolysis of Municipal Waste 109
5-12 Pyrolysis Gas Produced From 400 Tons/Day
of Municipal Refuse 111
6-1 Fuel Tankage Systems 127
6-2 Tankage and Safety Properties of Potential Fuels 128
6-3 Estimated Fuel Cell Costs 154
7-1 Solvent-Refined Coal 163
7-2 Pollution From Coal Processing 164
7-3 Pollution, From Oil Shale Processing 165
7-4 Resource Depletion in 1985 According to Model I 168
7-5 Resource Depletion in 2000 According to Model I 169
7-6 Resource Depletion in 1985 According to Model II 170
7-7 Summary of Resource Depletion in 1985 and
2000 According to Model I 171
7-8 Summary of Resource Depletion in 1985 According
to Model II 171
8-1 Comparison of Fuel-System Economics (Ex-Vehicle)
for Preliminary Costs of Possible Alternative Fuels
(1973 Dollars) 175
xv
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LIST OF TABLES, Cont.
Table No. Page
8-2 Hydrogen Transmission Cost 177
8-3 Data for Preliminary Costs of Fuel
Transportation 178
8-4 Estimated Consumer Costs for Alternative Fuels in
Vehicles With Various Power Plants (Based on
Preliminary Costs From Table 8-1) 180
8-5 Basis for Calculating Gross and Net Operating
Costs for Producing Candidate Fuels 182
8-6 Bases for Fuel Cost Calculation by the DCF Method 183
8-7 Pattern Synthesis Processes and Fuel Production
Costs 184
8-8 Nuclear Heat Module Costs for a Thermochemical
Hydrogen Plant 186
8-9 Thermochemical Plant Capital Costs 188
8-10 Thermochemical Plant Operating Costs 189
8-11 Assumed Syncrude Pipeline Routes 191
8-12 Estimated Investment (1973 Costs) for Syncrude
Pipeline 192
8-13 Operating Costs for Syncrude Pipeline 193
8-14 Unit Cost of Syncrude Pipeline 195
8-15 Summary of Transportation Costs for Candidate Fuels 196
8-16 System Base Costs for Candidate Fuels 197
8-17 Projection of Future Fuel Production Costs 200
8-18 Comparison of Fuel Processing Schemes (Nominal
Production: 250 Billion Btu/Day) 201
8-19 Future Crude Oil and Refinery Gate Costs 202
8-20 Production and Exploration Investment Dollars
per Ba.rrel of Crude Added to Reserves in the U. S. 204
8-21 Real Cost Increases Associated With Shale Oil
Production 210
8-22 Capital Requirements for Continuous Underground
Mining for 1 Million Ton/Yr Mine 212
xvi !
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LIST OF TABLES, Cont.
Table No. Page
8-23 Annual Operating Costs of Underground Mining 212
8-24 Annual Operating Costs of Surface Mining 213
3-25 Total Coal Requirement 215
8-26 Synthetic Fuel Cost Increases Due to Coal and
Water Depletion in the Mid-Term Period 21$
8-27 Synthetic Fuel Cost Increases Due to Shifts in
Mining Techniques and Lower Heating Value in the
Far Term 217
8-28 U.S. Uranium Reserves 218
8-29 Future Projected Costs of Candidate Alternative
Fuels 222
10-1 Preliminary Fuel Selection by Ranking Relative
to Gasoline 238
10-2 Engine-Fuel Compatibility 241
10-3 Adequacy of Domestic Resources 243
10-4 Final Fuel Selection for the Near-Term Time Frame 245
10-5 Final Fuel Selection for the Mid-Term Time Frame 246
10-6 Final Fuel Selection for the Far-Term Time Frame 248
11-1 Oil Shale to Gasoline and Distillates According to
Models I and II for the Near Term > 251
f
11-2 Coal to SNG and Gasoline Plus Distillates or Methanol
According to Models I and II for the Near Term 253
11-3 Transportation Energy Demand and Supply According
to Model I for the Near Term 254
11-4 Transportation Energy Demand and Supply According
to Model II for the Near Term 255
11-5 Oil Shale to Gasoline and Distillates According to
Models I and II for the Mid Term 258
11-6 Coal to SNG and Gasoline Plus Distillates or Methanol
According to Models I and II for the Near Term 259
11-7 Transportation Energy Demand and Supply According
to Models I and II for the Year 2000 260
xvii
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LIST OF TABLES, Cont.
Table No. Page
11-8 Coal to SNG and Gasoline Plus Distillates or
Methanol According to Models I and II for the
Far Term . ; 262
11-9 Transportation Energy.Demand and Supply According
to Models I and II for the Year 2000 263
XVlll
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LIST OF ABBREVIATIONS AND SYMBOLS
AEC
A.G.A.
API
DCF
EEI
EPA
DOT
FPC
GNP
HTGR
IGT
JPL
LPG
LSNG
MON
MRRD
NOX
RON
SCF
SLPG
SNG
SRC
swu
106
109
10'2
1015
1018
UCLA
USGS
Atomic Energy Commission
American Gas Association
American Petroleum Institute
discounted cash flow
Edison Electric Institute
Environmental Protection Agency
Department of Transportation
Federal Power Commission
gross natural product
high-temperature gas-cooled reactor
Institute of Gas Technology
Jet Propulsion Laboratory
liquefied petroleum gas
liquefied substitute natural gas
motor octane number
minimum revenue requirement discipline
oxides of nitrogen: NO (nitric oxide) and NO2 (nitrogen dioxide)
research octane number
standard cubic foot of gas (60°F, 30. 00 in. Hg)
substitute liquefied petroleum gas
substitute natural gas
solvent-refined coal
separative work units
million
billion
trillion
quadrillion
quintillion
University of California at Los Angeles
United States Geological Survey
It is assumed that the reader is familiar with abbreviations for common
units of measurement such as Btu (British thermal unit), bbl (barrel),
psig (pounds per square inch gage), MW (megawatt), kWhr (kilowatt-
hour), etc.
xix
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1. INTRODUCTION
1. 1 Purpose and Objectives
The purpose of this study is to investigate potential solutions for the
anticipated inability of domestic petroleum resources to supply adequate
quantities of fuels for automotive transportation. Because of the unsatis-
factory situation now developing in which the U. S. is becoming increasingly
dependent on imported petroleum, the major emphasis in the selection of
an alternative (non-petroleum-based) fuel is on its long-term availability
from domestic sources. Economics, competition with other energy appli-
cations for limited energy resources, safety, handling, system efficiency,
environmental impacts, and engine and fuel distribution system compati-
bility also are taken into account.
The objective of this study is to assess the technical and economic
feasibility of alternative fuels for automotive transportation, specifically,
*,._ Identification and characterization of potentially feasible and
practical alternative fuels that can be derived from domestic,
nonpetroleum energy resources
Technical and economic assessments of the most promising
alternative fuels for three specific time frames
Identification of pertinent fuels and research data gaps and recom-
mendations of alternative fuel(s) to best satisfy future U.S.
automotive transportation requirements.
Working toward these objectives, we have generated a fuel selection methodo-
logy that can be applied to a potential alternative fuel. We have enlisted the
factors of energy demand and supply, fuel availability, fuel synthesis tech-
nology, and certain physical, chemical, and combustion properties of the
fuel. Apparent technology and information gaps that have bearing on a fuel's
usefulness (for automotive purposes) are identified. This study provides
background information for the development of U. S. energy programs per-
taining to chemical fuels.
In recent years, the U.S. has realized that its projected supply of crude
oil will not be sufficient to meet the expected increased demands of the future.
In fact, recent projections of crude oil supply and petroleum fuel utilization
indicate that, by about 1980, the domestic crude oil supply would not be suf-
ficient for the total U. S. transportation energy demand (if it were so applied).
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Because ground transportation, chiefly automobiles, trucks, and buses,
consumes a majority of the transportation energy, these vehicles probably
will have to find an additional energy source and possibly even a new fuel
before the turn of the century.
1. 2 Scope and Definitions
This study assesses the feasibility of alternative fuels for automotive
transportation from domestic energy sources other than the conventional
petroleum resource base. The petroleum resource base consists of crude
oil, natural gas, and natural gas liquids (including LPG). Conventional
gasoline from this petroleum resource base is the "reference" fuel. When
possible, it is the basis for quantitative and qualitative comparisons.
In this study, "automotive transportation" refers to automobiles, trucks,
and buses. The energy requirements for the remainder of the transportation
sector are only incidental to this study; assessments are beyond the scope
of this study. Accordingly, automotive energy demand is 75% (currently)
of total transportation energy demand, or more than 18% of the total U. S.
energy demand. This study primarily considers vehicles propelled by heat
engines combusting chemical fuels. Electric vehicles those storing and
delivering energy electrochemically are excluded from this study. How-
ever, vehicles that carry a chemical fuel and combust it in a fuel cell (to
produce electricity for a motor) are included.
Fuel energy content, chemical and physical properties, and energy de-
mand and supply quantities are presented in conventional (U. S. -English)
engineering units. In Appendix A and as appropriate elsewhere, certain
quantities also are listed in metric (SI) units. For engineering estimates,
particularly in synthesis process calculations, high heating values are used.
The high (or gross) heating value assumes that the water from combustion
is condensed to yield latent heat that is included in the heat of combustion
or in the enthalpy of a material stream for a process. However, in most
instances, combustion of a fuel actually yields only the low (or net) heating
value. (Water from combustion remains a vapor. ) The fuel-tabulations
and comparisons in this report generally contain both values (as specified),
but the low heating value is a more practical assessment of a fuel's energy
content for automotive use.
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This study is concerned with three time frames: near term, 1975-1985;
midterm, 1985-2000; and far term, beyond 2000. Because of the uncer-
tainties in future energy availability, technological advances, economics,
and public policy, forecasts or projections beyond the near term are very
difficult. The assumptions inherent in our energy demand-and supply models
are specified, and the reader can change the projections by changing the
assumptions. Some of our projections have been made out to the year 2020
for illustrative purposes.
Two energy demand and supply projections (models) are detailed in
this report for two purposes: l) to present an illustration of the methodo-
logy of fuel selection and 2) to provide an optimistic possibility of domestic
energy self-sufficiency as well as a pessimistic possibility of continued
dependence on energy imports. The projections are not intended as models
of energy allocation; rather, they are intended to show quantitatively the
deficits and excesses that could exist in future time frames.
To apply the methodology of alternative fuel selection to a reasonable
number of fuels, we have studied 16 fuels in this program. As possible
energy sources for this synthesis, we have studied 12 potential domestic
sources of energy. Table 1-1 lists these energy sources, four abundant
auxiliary material sources, and the potential alternative fuels. The conven-
tional crude oil and natural gas resource base is excluded. Also, we ex-
cluded any fuel that would produce significant amounts of combustion products
not found in (unpolluted) air. In the potential automotive fuel list, "distillate
oils" refer to the similar hydrocarbon mixtures, kerosene, diesel oil, and
fuel oil (No. 1 or 2). Hydrazine is included as a fuel for fuel cells, and the
coal would be a solvent-refined product (low in ash and sulfur content).
The selected fuels are evaluated in Sections 10 and 11 of this report, and
the selections are made according to the methodology of Section 2. This
methodology is applied to the energy and fuel information contained in
Sections 3 through 9 and in Appendices A and B (Volume III). For convenience,
we also present our selections, in order of preference, in Table 1-2.
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Table 1-1. INITIAL-CONSIDERATION LIST
Energy Sources
Coal
Shale oil
Tar sands
Uranium and thorium
Nuclear fusion
Solar radiation
Solid wastes (garbage)
Animal wastes
Wind power
Tidal power
Hydropower
Geothermal heat
Auxiliary Material
Sources
Air (02, C02, N2)
Ro.ck (limestone)
Water
Land
Potential Automotive
Fuels ;
Acetylene
Ammonia
Carbon monoxide
Coal
Distillate oils
Ethanol
Gasolines (Cs-Cxo)
Heavy oils
Hydrazine
Hydrogen
LPG (synthetic)
Methanol
Methylamihe
SNG
Naphtha s
Vegetable oils
Table 1-2. SELECTED ALTERNATIVE FUELS
Near Term (1975-85) Mid Term (1985-2000) Far Term (Beyond.2000)
Gasoline from oil
shale and water or coal
and water
Distillate (diesel) oils
from oil shale and water
or coal and water
Gasoline from coal and
water or oil shale and
water
Distillate (diesel) oils
from coal and water or
oil shale and water
Methanol from coal
and water
Gasoline from coal and
water or oil shale and
water
Distillate (diesel) oils
from coal and water or
oil shale and water
Nuclear-based hydrogen
(from water)
Methanol from coal
and water
'4
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2. FUEL SELECTION METHODOLOGY
2. 1 Fuel Evaluation Procedure
Candidate alternative fuels are selected by evaluating the many potential
fuels in terms of certain fundamental areas of concern, or general criteria.
The concerns that we have identified are as follows:
Adequacy of energy and material availability and competing demands
for fuel
The existence of known of developing fuel synthesis technologies
Safety (toxicity) and handling properties of fuels
Relative compatibility with contemporary fuel transport facilities
and utilization equipment (tanks and engines)
Severity of environmental impacts and resource depletion
Fuel system economics (resource extraction, fuel synthesis and
delivery, automotive utilization).
Some of the general criteria, for instance, the safety and handling aspects
(toxicity, physical, and chemical properties), do not change with time.
Others, such as the availability of a technology for fuel synthesis, may
vary greatly during the three time frames of this study, so some assess-
ments must be repeated. The different judgements for fuel selection must
be as consistent as possible, and the criteria must be quantified when pos-
sible. How most of these general criteria are quantified into specific criteria
and how other general criteria can be qualitatively used are discussed in
this section of the report. The judgment process in which these general
criteria are used is illustrated in Figure 2-1. Subsequent sections of this
report present detailed explanations of the domestic natural resource base,
energy demand and supply models, synthesis technology, fuel and engine
compatibility, and fuel economics. Then the specific selection criteria are .
applied to the potential fuels to determine the best alternative fuel candidates.
According to the evaluation chart (Figure 2-1), certain background infor-
mation must be assembled before the evaluation can proceed. This background
information consists of the following items:
-------
SYNTHESIS PROCESSES-
Commercial
Developmental
Conceptual
POTENTIAL
ALTERNATIVE
FUEL
ENERGY AND
MATERIAL
RESOURCES
IDENTIFY
TECHNOLOGY/INFORMATION
GAPS
FUEL SELECTION (Sur»
Condidcrtos)-
Relative Ranking,
Subjective and
Qualitative; or
Normalization to
Gasoline and
Ranking
Figure 2-1. ALTERNATIVE FUEL EVALUATION METHOD
SELECTED FUELS
B-54-735
-------
a. Quantitative information on the U.S. domestic energy (and material)
resource base. This must include the conventional petroleum resource
base for reference. Assured, reasonably assured, and speculative
quantities are sought.
b. Energy demand and supply model(s). These models must be divided
into market sectors to show deficits and excesses. The transportation
sector is of prime concern.
c. Information on fuel synthesis processes. Needed are the availability
of commercial processes, processes being developed,and conceptual
processes for fuel synthesis from unconventional energy sources.
d. A bank of data on fuel properties, pertinent chemical, physical,
combustion, and toxicity data. Also, prospects for fuel transport
(handling) and fuel-engine compatibility and performance are needed.
This also establishes the data for conventional gasoline, the reference
fuel for this study.
e. A resource depletion model. This should integrate resource depletion
from automotive requirements with energy.
The evaluation procedure begins with a determination of whether a given
fuel can be synthesized by some process from an available energy (and
material) resource. If not, but if subsequent evaluations are satisfactory
relative to conventional gasoline (selection criteria met), a synthesis tech-
nology gap is identified. Other technology gaps that may be identified concern
fuel transport or tankage, fuel-engine compatibility, and correctable en-
vironmental effects. The energy demand and supply model determines for
the various time frames how much energy (fuel) is required and whether
that fuel will be available for automotive use, considering competing demands
from other (higher priority) sectors of the economy. These assessments are
followed by determinations of fuel safety and handling, and compatibility and
utilization. The overall resource depletion due to the synthesis and use of a
fuel is calculated, and the environmental effects due to potential material
pollutants are assessed (if quantitative determinations can be made). Finally,
the fuel is given a rating relative to conventional gasoline by normalization
of the quantitative data and the semiquantitative judgments. Thus, the fuel has
a certain ranking relative to the other potential alternative fuels.
-------
2.2 Resource Base
One prerequisite in the selection of ah alternative automotive fuel is the
determination of whether or not its domestic resources are adequate to
support a substantial portion of the transportation demand for a period that
allows major development and commercialization of a new industry. Asa
realistic benchmark and for consistency with economic procedures that are
applied to industrial and commercial programs for which significant capital
must be borrowed from sources external to the industry, 25 years has been
chosen as this period. (A more detailed discussion about this 25-year period
is given in Section 8.) Transportation demand is, of course, greater than
automotive demand; hence, this criterion should be satisfactory in light of
competition (from aircraft or railroads) for a commonly desired transpor-
tation fuel (e. g. , distillate oils). If an alternative resource is not adequate,
several alternative systems would be necessary. The term "substantial
portion of the transportaion demand" is quantified by using the supply-demand
projections of Model I. (See Section 4.) From this model, the transportation
energy shortfalls vary between 28 and 34% annually between 1975 and 2000,
as shown in Table 2-1.
Table 2-1. TRANSPORTATION ENERGY DEMANDS AND SHORTFALLS
ACCORDING TO MODEL I
1975 1980 1985 2000 2020
Demand, 1015Btu 19.4 23.0 26.7 40.4 70.1
Shortfall, 1015 Btu (domestic) 6.4 7.4 7.4 13.8 41.7
Shortfall, % of demand 33 32 28 34 59
Integrating the Model I shortfall from.' 1975 to 2000 results in a total short-
fall of about 215 X 1015 Btu, or an average annual shortfall of 8. 6 X 1015 Btu.
If one alternative fuel system (industry) is developed with the goal of domestic
self-sufficiency, its output should be capable of eventually matching the short -
s
falls in Table 2-1. If two systems are developed, one might supply 90% of
the shortfall, and the other, 10% . In this study, we are interested in al-
ternative fuel systems that could have a major impact on the projected shortfalls.
Therefore, as a benchmark, we have chosen one-half of the shortfall, or an
integrated value of 108 X 1015 Btu (1975-2000), as the level of energy supply
-------
that must be potentially achievable by a viable and important alternative fuel
system. This benchmark corresponds to about 15% of the total transportation
energy demand. Hence, to be adequate, a new (unconventional) energy source
should have the potential to supply 3-6 X 1015 Btu/yr of fuel between 1975 and
2000.
For renewable resources, the rate at which a resource becomes available
for conversion is a practical limiting factor. To be adequate, this energy
resource also must be able to meet about 15% of the transportation demand
for 25 years. Energy sources that are limited by a lack of required materials,
conversion efficiency (to a fuel), or other factors to a production rate of less
than 3-6 X 1015 Btu/yr are considered inadequate.
From a multitude of sources, but principally the NPC's U. S. Energy
Outlook,l we have assembled and categorized the domestic energy resource
base in Section 3. For these resources, "assured" reserves are adjacent
to current producing areas and have been measured with a high degree of
certainty. "Reasonably assured" reserves are those that have a high proba*
bility of existing based on geological and other information similar to that
found in areas currently being produced. "Speculative" reserves assume
a high degree of optimism and could possibly fall into one of the former clas-
sifications by means of extensive exploration and development activity. We
have chosen this definition of resource base because, for various resources,
the documentation is adequate and categorization can be uniform. Use of other
classifications, such as economically available (minable ), would result in less
consistency, because these quantities have been reported on different economic
bases. Further, they are strongly affected by economic conditions, and they
will vary impredictably in future time p'eriods.
2. 3 Energy Model Effect
The need for an alternative fuel (to supplement conventional, petroleum-
derived gasoline) is quantified by an energy demand and supply model that is
postulated for future time frames. This model shows how much energy is
needed and when it is needed for alternative fuels. Aside from the aspects of
technology, environment, safety, compatibility, and system costs, this
model sets limits on the energy supply shortfall. It is a selection criterion
because it indicates for a given time frame that, after several "best qualified"
fuel systems are selected, other (additional) fuel systems are not needed. The
"best qualified" fuels are those that best meet all other criteria.
-------
This study uses two energy models to bracket future supply and demand.
They show the fuel requirements resulting from different assumptions about
the effectiveness of conservation efforts, changing demand patterns, and
the drive toward domestic self-sufficiency. These two models are described
in detail in Section 4. A third model, not fully developed, also is contained
in Section 4. This third model shows the effects of high fuel costs, extreme
conservation, and federally legislated vehicle efficiency (fuel economy) on
automotive fuel demand. The effect of these models on our selection criteria
is to define the minimum resource base requirements and fuel production
rates that are required in a particular time frame.
Some directly synthesized chemical fuels, SNG, and SLPG, are in prime
demand by high-priority market sectors and are likely to be consumed by
these sectors. Further, fuels derived from agricultural crops (ethanol and
vegetable oils) must compete with food uses for the crop and with land for
other crops (for food or timber or pasture).
For example, Model I projections of demand for SNG (from coal) and
natural gas by all market sectors (except transportation), based on historical
energy supply percentages, are shown in Table 2-2. From this assessment,
not more than 1.4 X 1015 Btu of SNG will be available annually for automotive
transportation.
Table 2-2. SNG (From Coal) PRODUCTION
AND NATURAL, GAS DEFICIT
Gas Energy. 1015 Btu/yr
Supply, Demand. Deficit 1975 1980 1985 2000
Projected Demand (Natural Gas+SNG) 24.1 25.0 28.6 * 28.6
Projected Natural Gas Supply 24.5 24.6 28.0 22.0
Deficit (0.4) 0.4 0.6 6.6
Model I SNG Production 0 1.0 2.0 8.0
Available for Automotive Use 0.4 0.6 1.4 1.4
2. 4 Synthesis Technology
There are many ways (theoretically) to convert available energy and
material resources into nonpolluting automotive fuels. Coal can be gasified
into synthesis gas and ultimately into liquid and/or gaseous fuels by using
suitable chemical processes. Oil shale and tar sands could be retorted, and
the produced syncrude oil could be hydrogenated or hydrocracked into liquid
10
-------
fuels. Nuclear fuels can be converted into electric power and then into
hydrogen by electrolysis of water. The hydrogen produced can be used in
hydrocracking or hydrogenation of crude oil to make liquid fuels, or hydrogen
itself can be used as an automotive fuel. Alcohol can be produced from plant
materials by fermentation or from synthesis gas by catalytic reaction of CO
and hydrogen. The nonmaterial energy sources, such as solar energy, winds,
tides, ge other ma 1 heat, etc. , can be converted into electric power. It may
be possible to use heat energy derived from solar, nuclear, or geothermal
sources as an input into chemical processing, for example, in the production
of hydrogen from water or of methane from coal.
Most of these synthesis processes are discussed in more detail in Section 5
and in Appendix B. For purposes of evaluating and rating a process route
for synthesis of a fuel, we have divided^the processes into the following four
classes:
1. ,The synthesis technology is probable. It has a reasonable probability of
occurring during the time frames of this study. It is either a commercial
process, or process components are available and a demonstration plant
could be built.
2. The synthesis technology is possible. There is a possibility that it will
be used during the time frames of this study. The process needs develop-
ment work at the pilot-plant level. Prerequisite laboratory development
has been completed.
3. The synthesis technology is speculative. There is an outside chance or a
low probability that it could be used during the time frames of this study.
The technology is in its conceptual stage and requires laboratory develop-
ment and proof of practicality. A moderate technology gap exists.
4. The synthesis technology is unknown. A theoretical concept may exist,
but proof of concept has not been demonstrated. A severe technology
gap exists.
2. 5 Fuel Properties
This subject encompasses physical, chemical, and combustion properties,
safety (toxicity), transportability and storability, and compatibility with
engines. Appendix A contains a listing of the pertinent chemical, physical,
and combustion properties of 18 potential alternative fuels. Section 6 deals
with the details of transportability, storability, and tankage and engine com-
patibility.
Safety assessments might be made by considering combinations of the com-
bustion properties and toxicity of fuels. Combustion properties that are in-
dicative of the likelihood of accidental fire are flash point, ignition energy,
limits of flammability in air, and ignition temperature. Assigning a safety
11
-------
ranking to prospective fuels on the basis of this information is difficult.
Obviously, gasoline and distillate oils can be handled safely; however,
these fuels have very low lean flammability limits and low ignition tem-
peratures. Gasoline also has the lowest flash point of any of the liquid fuels.
Thus, we find only minor (insignificant) distinctions to be evident between
fuels that are potentially safer than gasoline in terms of combustion when
gasoline is handled safely in the reference system.
Toxicity is a different matter, and distinctions should be made. In our
investigation, we have sought the following fuel concentrations in air: least
amount for detectable odor, least amount causing eye irritation, lea'st
amount causing throat irritation, and maximum concentration allowable
for prolonged (8-hr) exposure. Concentrations above this last value cause
a variety of symptoms, differing with different fuels, but on the average,
the effects would be deleterious and incapacitating. In some cases, these
concentration, values were not available. Fortunately, the data reported,
for the most part, are consistent from source to source. Representative
of these test results, and of great concern, is the concentration in air that
is dangerous for prolonged exposure. By using the "toxicity ratio, " which we
define as the ratio of the 8-hour exposure concentration of the fuel in question to
that of gasoline, the safety criterion can be quantified by:
, , .. .. / ppm fuel \~l
Toxicity ratio = (" p)
7 PPm gasoline '
It would be inconvenient and expensive to introduce a fuel that has physical
and chemical properties unsuited for the equipment now used for energy
supply. The great economic incentive to retain existing facilities would have
to be overcome. Fuels that can be handled in existing petroleum product
distribution equipment have an enormous advantage at present.
At present, four separate transport systems handle four classes of fuels.
About 10 X 1015 Btu are delivered as gasoline by the liquid-fuels-distribution
system each year. The solid-fuel (coal) transmission system handles 600 X 106
tons annually, or about 12 X 1015 Btu. Gaseous fuels, primarily natural gas,
have their own pipeline system, which accounts for about 20 X 1015 Btu. The
last class of distribution system, which moves condensable gases like LPG,
is relatively small and would need a considerable (but possible) investment to
12
-------
accommodate the huge quantities of fuel required to supplement gasoline
supplies.
The compatibility of each fuel is judged against the changes and additions
to each of these four distribution systems that it would necessitate. The
best situation allows the continued use of the liquid-fuel pipelines, trucks,
and service stations system. A switch to one of the other three systems
requires at least substantial new distribution equipment and service station
facilities.
The transmission and distribution system required for an alternative is
classed in one of four categories:
1. Probably compatible. The alternative fuel could use the present
gasoline and/or distillate hydrocarbon (diesel fuel) transport and
distribution system. No significant service station changes are
required.
2. Possibly compatible. The alternative fuel has its own (large-scale)
transport and distribution system, or it can use a present system
with some modifications. Some new equipment (including service
station facilities) is needed.
3. Compatibility is speculative. Essentially new equipment is needed
for a workable system.
4. Incompatible. The fuel cannot be practically or safely used in any
of the four major existing systems. New (sophisticated) equipment
is needed that is beyond practicality.'
We have estimated automotive tankage weights and volumes after con-
sultation with manufacturers. Fuel energy content alone does not neces-
sarily indicate the true weight of a fuel system. Because final tankage
weights influence total vehicle weight a.nd hence fuel consumption, we
have calculated the tankage weights of'alternative fuels at the energy
equivalent of 20 gallons of gasoline. Fuels requiring a fuel-storage system
weighing in excess of 500 pounds are poor alternatives to gasoline. Tankage
weights in the range of 200-500 pounds are considered good, and those' in
the range of 140-200 pounds (comparable to that of gasoline) are excellent.
Tankage volume does not affect performance or fuel consumption, but
can affect passenger and payload space. At 600 gallons, gaseous CO is
unacceptable, and at 110 gallons, acetylene is very awkward. To quantify
this criterion, we have used the tankage index defined as:
13
-------
Tankage- / fuel tankage weight * / fuel tankage volume \
index ~ gasoline tankage weighr ^gasoline tankage volume'
Just as it would be impractical to introduce a, fuel in the near term that
is incompatible with the present distribution system, it would be impractical to
introduce a fuel that is incompatible with automotive power plants, present or
planned. The compatibility of fuels with engines is judged on an arbitrary nu-
merical scale. Details are presented in Sections 6 and 10. In the near-term
time frame, fuels are judged for compatibility with conventional spark-ignited
and diesel engines; for the mid term, stratified-charge engines are included;
and for the far term, Brayton, Rankine, Stirling, and fuel cells are included
along with conventional, stratified-charge, and diesel engines.
2. 6 Environmental Effects
The potential for environmental damage associated with a fuel system
stems primarily from resource extraction techniques, synthesis processes,
and utilization methods. Types of pollutants as well as quantities depe\nd on
the type and efficiency of extraction, synthesis, and utilization. Further-
more, pollution depends on raw materials. For example, at a given production
level, synthesis pollutants, such as sulfur, can vary by a factor of at least
5, depending on the type of coal used. Similarly, the volume of shale residue
can vary by a factor of 3, depending on the grade of shale and the recovery
efficiency of the process. Note that the amount of resource depletion (for
automotive transportation purposes) depends on engine efficiency, which,
e. g. , could vary by a factor of 1. 5 (Wankel versus diesel).
In general, we have not developed pollution or resource depletion into
general selection criteria because efficiencies, emissions, and performances
for the various system components are generally not known with sufficient
precision. In many cases, estimates of these would be conjecture. However,
some partial conclusions are possible, and we present pertinent information
in Section 7.
?.. 7 Fuel System Economics
To further evaluate alternative fuels, we have applied a costing procedure
to the potential fuel systems. This method sums the calculated costs of re-
source extraction and synthesis, the costs of refining or liquefying, and the
14
-------
costs of transmission and distribution. This procedure yields a delivered
fuel cost ($/Btu). As with environmental effects, these costs are only part
of the system. A complete fuel selection criterion would include the cost
per mile driven by the consumer and attributable to a given fuel. Such cal-
culations entail knowledge of the fuel-engine efficiency and vehicle weights
as well as the fuel cost at the service station-vehicle interface. These
calculations are complex and tenuous because they involve a mix of mea-
sured, approximated, and assumed engine efficiencies, vehicle weights,
and attendant fuel consumption. These considerations are beyond the scope
of this report.
The determination of fuel system costs has been done in two phases.
An initial "rough cut, " using published estimates of resource extraction
and synthesis costs, was done first. Transmission and distribution costs
for similar fuels or chemicals were used. For the several attractive can-
didate fuels (those ranking most favorably with respect to gasoline), a
second, detailed determination of costs was made. Section 8 and Appendix B
contain pertinent details. The cost of a fuel is itself quantified; as a cri-
terion, it has been normalized by dividing by the cost of conventional
gasoline.
2. 8 Technology and Information Gaps
In this study, a "technology gap" is defined as a technical difficulty that
makes an otherwise acceptable fuel impractical but that might yield to in-
tensive research and development. For instance, hydrogen is perhaps the
cleanest and most efficiently combusted fuel, and its production is com-
mercially feasible (although expensive). Today, however, there are no
satisfactory methods for vehicle storage of hydrogen. Unless this problem
is solved, hydrogen will not be used as an alternative automotive fuel. LPG
also has a technology gap. The fuel can be transported, stored, and utilized
satisfactorily, and vast raw materials are accessible (coal and water).
However, no (catalytic) process has been found that will make principally
LPG from synthesis gas (a mixture of hydrogen and carbon monoxide),
which is the first step in clean fuel-from-coal processes.
We have further qualified technology gaps as serious or moderate. The
existence of a serious technology gap eliminates a fuel from general supple-
/
mental use (as an alternative fuel) before the year 2000. This is necessitated
15
-------
by the lead times required for research, development, prototype achievement,
demonstration, operation and testing (plant or product), and production plant
(or industry) construction and operation. Less serious (moderate) technology
gaps, such as a fuel storage technique or an emission control device, will
eliminate a fuel for the near term (before 1985).
As the study progressed, we encountered another type of gap: information.
In some cases, the data necessary to properly evaluate the potentials of
candidate fuels do not exist, are imprecise and subject to controversy, or
are subject to restricted access. In most cases, we have identified these
"information gaps" and discussed their implications.
2. 9 Reference Cited
1. National Petroleum Council, U. S. Energy Outlook: A Report of the
National Petroleum Council's Committee on U.S. Energy Outlook.
Washington, D. C. , December 1972.
16
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3. U.S. DOMESTIC RESOURCE BASE
The present U. S. domestic energy resource base of all nonrenewable
fuels, both fossil and nonfossil, is in the range of 91-139 X 1018 Btu.
The lower end of the estimate is based upon uranium consumption in bur-
ner reactors without plutonium recycle, and the higher end of the estimate
takes into account the development and implementation of the breeder reactor.
The domestic resources are presented in Table 3-1 in conventional units
and in Table 3-2 in Btu equivalents. These tables are derived from raw
data that are contained in the NPC report and in a variety of other
sources,1'2'6'9'12'13 and have been subclassified into reserves that are
"assured, " "reasonably assured, " and "speculative. "
Many difficulties were encountered in assembling Tables 3-1 and 3-2.
Uranium reserves, expressed in tons, can be converted to thermal energy,
expressed in Btu's, at efficiencies that differ greatly depending on whether
or not the breeder reactor is developed. Both estimates for uranium are
presented in Table 3-2. Reserves of thorium are substantial; however,
technology for its conversion to a usable form of energy is not yet assured.
Therefore, thorium data were omitted from Table 3-2 even though they
appear in Table 3-1. Nuclear fusion data were omitted from both tables
because the technology necessary for conversion to useful energy does not
yet exist.
Hydropower, solar energy, wind, geothermal energy, wastes, and tidal
power are renewable energy resources, so they are shown as an annual
quantity. The other energy forms are nonrenewable; that is, they cannot
be replaced once they are extracted from their natural state. Solar energy
is a renewable resource that could .be classified as either assured or
speculative. The quantity given in Tables 3-1 and 3-2 relates to the
total quantity of direct solar energy falling on the land mass of the con-
tiguous 48 states. The quantity is "assured, " although all of it will not
be available for conversion to transportable energy or fuels because the
entire land mass will not be covered with solar collectors. Most of the
wind power available to the U. S. would result from solar radiation falling
on the ocean surface and not on the land mass. Thus, any detailed com-
parison of the quantities given in Table 3-2 must be carried out with some
degree of caution. The following is a brief discussion of the location and
prospects for development of each resource listed in Tables 3-1 and 3-2.
17
-------
Table 3-1. U. S. ENERGY RESOURCE BASE IN CONVENTIONAL UNITS
Resource
Hydrocarbons (Nonrenewable)
Coala
Crude Oilb
Jiat-iral Gas .
Natural Gas Liquids
Oil Shalee
Tar Sands
Nuclear
K
Uranium"
Thorium '
Nuclear Fusion
Renewable, Annual
HydropoweP
Geothermal
Solar Energy (direct)1"
Tidal Energy
Wind Power0
Municipal Wastesp
1975 (5. 4 Ib/person/day)
1985 (7.0 Ib/person/day)
Animal Feedlot Wastes'3
1975 Manure
1985 Manure
Units
10U tons
1 0' bbl
lO^CF
JO9 bbl
10' bbl
10' bbl
1000 tons
1000 tons
Assured
1.56
36.3
266.0
6.8
34.0
23.5
520. 0
46. Oh
Reasonably
Assured
1.65
227.0
384.0
--
281.0
1000.0
249.0
109 kWhr/yr
1015 Btu/yr
1015 kWhr/yr
10' kWhr/yr
1015 Btu/yr
109 Ib
109 Ib
106 tons
10* tons
530.0
5.6
14.4
--
5.4
422.0
602.0
332.0
452.0
--
2.8
--
1. 8
-
_ .
--
_ .
--
Speculative
209. 0
496. 0
1466.0
Total
3.21
472.3
1146.0
6.8
1781.0
23.5
1520. 0
295.0
530.0
8.4
14.4
1.8
5.4
422.0
602.0
332.0
452. 0
D-94-1676
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Table 3-1. Cont. U.S. ENERGY RESOURCE BASE IN CONVENTIONAL UNITS
These resource classifications were made to establish some uniformity and to provide a basis for direct comparison of the availability of the various
energy resources.
Coal: Assured reserves that are mapped and explored with 0-3000 ft of overburden; recovery factors not applied. Reasonably Assured reserves that
are in unmapped and unexplored areas with an overburden of 0-6000 ft.
Crude oil: Assured reserves of crude oil that have been discovered but not yet produced; often referred to as "proved reserves. " Reasonably Assured
based upon extensive seismic and geological work performed in areas within or adjacent to current producing areas. Speculative reserves estimates
based on geological characteristics of nonproducinz areas; economic recoverability not considered.
Natural Gas: Assured reserves both drilled and undrilled; undrilled reserves located so close to the drilled reserves that every reasonable probability
exists that they will be recovered when drilled and may be associated or nonassociated. Reasonably Assured based on new discoveries in previously
productive formations that are distinctly different from existing fields. Speculative the most uncertain of new supplies, attributable to new field dis-
coveries in formations or provinces not previously productive.
Natural Gas Liquids: reserves based upon the historical ratio of natural gas to natural gas liquid discoveries. Applied to,"assured" reserves of natural
gas only.
Oil Shale: Assured resources satisfying the basic assumption limiting resources to deposits at least 30 feet thick and averaging 30 gal/ton of shale by
assay; those that are assured are a more restrictive cut of these reserves and indicate the portion that would average 35 gal/ton over a continuous interval
of at least 30 feet (Class I resource). Reasonably Assured those resources yielding 30-35 gal/ton over a continuous interval in deposits 30 ft deep; regions
of occurrence are poorly defined and/or not favorably located (Class I and III resources). Speculative resources that are poorly defined ranging down to
15 gal/ton yield, not of current commercial interest (Class IV resources).
Tar Sands: Assured, small quantities of tar saads lie within the U.S. , but commercial development is unlikely.
" Potential resources are reasonably assured.
Assured, recovered as a by-product.
Reasonably assured if recoverable from deposits about 0. 1% thorium oxide.
' 281 billion kWhr developed; additional 249 billion k'.Vhr available.
k
Localized hydrothermal systems down to 6 miles deep; 1% of total equals annual production.
Average over 24-hr period and four seasons. 17W/sq ft over entire U. S. land area.
Passamaquoddy Bay, Me. ; assumed to operate 4380 hours/yr.
° 10 times the projection of Heronemus for ocean wind generators for New England.
^ Collected municipal solid wastes including household, commercial, industrial, construction, and demolition.
q Manure (dry basis) from animal feed lots (90^ from cattle). In 1975, 130 X 106 head; 1985, 177 X 106 head; 70 Ib manure (wet) per head per day.
D-94-1676
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Table 3-2. U.S. ENERGY RESOURCE BASE IN Btu EQUIVALENTS
Assured
Reasonably
Assured Speculative
Total
Resource
Hydrocarbon
Coal
Crude Oil
Natural Gas
Natural Gas Liquids
Oil Shale
Tar Sands
Nuclear
Uranium
In Burner Reactors
Without Plutonium Recycle
In Breeder Reactors
Throium
Nuclear Fusion
Total Nonrenewable
Renewable, Annual
Hydropower
Geothermal
Solar Energy
Tidal Energy
Wind Power
Municipal Wastes
1975
1985
Animal Feedlot Wastes
1975
1985
Total Renewable Annual
Btu /Unit
24 million/ton
5. 8 million/bbl
1032/CK
4. 0 million/bbl
5.4 million/bbl
5. 4 million/bbl
400 billion/ton
300 trillion/ton
3414/kWhr
17 W/sq ft
4580/lb
4740/lb
7500/lb
7500/lb
37,400
210
274
27
116
127
250
18,750
38,403
to 56,903
1. 8
5.6
49,056
1.9
2.9
5.0
6.8
49,080.0
i ft 15 PJ.,-.
39.600
1,317 1,212
396 512
1,517 7,916
--
400
30,000
43,506 9,640
to 73, 106
10IS Etu/yi
2.8
Negl
5.4
--
--
8.2
77.000
2,739
1, 182
27
9,549
127
650
48,750
91,549
to 139,649
1.8
8. 4
49,056
5. 4-
1.9
2. 9
5. 0
6.8
49,088.2
% of Total
84.3
3. 0
1.3
10.5
0. 1
0. 7
99. 9
-Negl-
.. B*
55. 1
2.0
0.9
6.9
0. 1
34.9
99.9
A = uranium in burner reactors without plutonium recycle.
B = uranium in breeder reactors.
B-94-1677
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Each resource has been categorized according to its natural occurrence
and most probable end use. Three categories were selected: hydrocarbon
reserves, nuclear reserves, and renewable resources. Hydrocarbon re-
serves comprise coal, crude oil, natural gas and natural gas liquids, oil
shale, and tar sands. These resources typically are naturally occurring
and are nonrenewable after extraction and use. Nuclear reserves com-
prise uranium and thorium, which are naturally occurring metal ores that
must be reduced before they can be used. As in the case of hydrocarbon
resources, nuclear reserves are nonrenewable. The last category, re-
newable resources, comprises hydropower, geothermal heat, direct solar
energy, wind power, waste materials, and tidal power. Based on historical
patterns, these resources are expected to be available at an almost con-
stant annual rate, with the exception of municipal and animal feedlot wastes,
which increase somewhat with time.
3. 1 Hydrocarbon Reserves
3.1.1 Coal
'The total quantity of coal available within the U.S. is estimated to be
3. Zl trillion tons, based on a report prepared by the USGS. * This quan-
tity is broken down as follows:
1012 tons
Mapped and Explored
0-3000 ft overburden' 1.56
Probable Addition, Unmapped and
Unexplored Areas
0-3000 ft depth 1. 31
3000-6000 ft depth 0. 34
Total 3.21
The quantity of coal classified as mapped and explored above, 1.56
trillion tons, is shown in Figure 3-1 as a percentage distribution by depth
with three categories of certainty. The block defined by the broken lines
is equivalent to 25% of the mapped and explored reserves, 394 billion
tons, and is termed in the coal industry as "measured" and "indicated"
reserves. This can be further broken down into coal mined underground
(349 billion tons) and surface-mined coal (45 billion tons).
21
-------
DU
55
50
45
35
1-
z
UJ
i > v\
0 30
LU
Q.
25
15
10
5
0
-
58
-
-
394
BILLION
TONS
23
*
8
ri
4-
I
l
....
r
1
1
i
1
-
I
1 1
3.5
6
9
1 1 1 Q3 j I1" 1
MEASURED INDICATED INFERRED MEASURED INDICATED INFERRED MEASURED INDICATED INFERRED
OVERBURDEN < 1000 FT
OVERBURDEN
1000-2000 FT
OVERBURDEN
2000-3000 FT
A-94-1630
Figure 3-1. ESTIMATED MAPPED AND EXPLORED
COAL RESOURCES IN THE U.S. (Total Shown,
1.56 Trillion Tons) (Source: Ref. 10)
22
-------
The 349 billion tons of underground coal have been further categorized
as "economically available reserves" by the exclusion of underground
lignite, bituminous, and subbituminous seams of intermediate and thin
thickness, leaving a total of 209.2 billion tons. To estimate recoverable
underground reserves, a recovery factor of 50%, based on present under-
ground mining methods, could be used. As a result, the quantity of
"economically recoverable" underground reserves would be reduced to
104. 6 billion tons. The resource quantity has been related to the 1970
rate of production to illustrate reserve life in terms of growth rates of
0, 3, and 5% annually. This is shown in Table 3-3.
Table 3-3. UNDERGROUND COAL RESERVES
AND PRODUCTION (Minable by Underground
Mining Methods) (Source: Ref. 10)*
Billions of Tons
Region
1
2
3
4
5
6
Other
Total §
Remaining
Measured and
Indicated
Reserves*
92.7
9.1
83.1
34.5
21.9
1.6
106.3
349.1
Economically
Available
Reservest
67.1
9.1
59.5
24.4
13.3
.6
35.2
209.2
Recoverable
Reserves^
33.5
4.6
29.7
12.2
6.7
.3
17.6
104.6
1970
Production
(Millions of
Tons)
145.8
N.A.
52.3
95.0
8.6
9.1
N.A.
338.8
Life of Recoverable Reserves
at % Growth Rate (Years)
0%
230
_
568
129
774
35
-
309
3%
69
_
96
52
106
23
-
80
5%
50
_
68
40
74
20
-
58
Bituminous, subbituminous and lignite in seams of "intermediate" or greater thickness and less than 1.000 feet overburden
(see Figure 50).
t Excludes lignite and "intermediate" thickness seams of bituminous and subbituminous coal.
t Based on 50-percent recovery ol economically available reserves.
§ May not add comictly due to rounding.
The map in Figure 3-2 shows each of the geographical regions where
coal is mined underground, and Table 3-3 shows the coal reserves in
each region. A major changeover to a technique such as long-wall mining
could result in a higher recovery factor (as much as 75%) and increase
the recoverable reserves total significantly. Hence, "economically re-
*
coverable" quantities (of coal "or any resource) are subject to great change
in the future as economics and technology change.
Reprinted with permission from the National Petroleum Council, ©1972.
23
-------
M
COAL FIELDS
UNDERGROUND MINING REGIONS
ANALYZED
*
Figure 3-3. MAJOR SURFACE-MINING REGIONS OF
U.S. COAL, FIELDS (See Table 3-4) (Source: Ref 10)*
Reprinted with permission from the National Petroleum Council, ©1972.
-------
(Jl
SURFACE MINING REGIONS
ANALYZED
Figure 3-2. MAJOR UNDERGROUND MINING REGIONS OF
U.S. COAL, FIELDS (See Table 3-3) (Source: Ref. 10)*
Reprinted with permission from the National Petroleum Council, ©1972.
-------
Recoverable
Reserves
(Billions of Tons)
4.2
5.6
0.8
23.8
1.6
2.1
6.9
1970
Production
(Millions of Tons)
101.2
91.0
25.1
19.1
8.3
5.6
13.8
Life of Reserves
at % Growth Rate (Years)
0%
42
62
32
1,246
193
375
500
3%
27
36
23
122
65
85
95
5%
23
29
19
85
48
62
67
Recoverable surface-mined coal reserves are shown in Table 3-4,
corresponding to the regions shown in Figure 3-3.
Table 3-4. SURFACE COAL RESERVES AND PRODUCTION
(Minable by Surface Mining Methods) (Source: Ref. 10)*
Region
1
2
3
4
5
6
Other
Total 45.0 264.1 170 61 46
(A recovery factor is not applied in the same manner as in the case of
underground mining, because in most cases it is in excess of 90%.) As
in the case of underground coal, the life of surface reserves is related
to 1970 production levels at annual growth rates of 0, 3, and 5% in
Table 3-4.
Within existing mapped and explored areas are thick coal beds under
less than 1000 feet of overburden that are considered to be potentially
available. For this study, a coal resource base with an overburden of
3000 feet or less is classified as "assured. " All other coal resources
arc classifh-'fl as "reasonably assured. " This categorization is shown in
Figure 3-4. We-use this classification of the U.S. coal resource base,
for comparison, to be as consistent as possible with the potential avail-
ability of other resource bases for supporting an alternative fuel system.
Reprinted with permission from the National Petroleum Council, ©1972.
26
-------
ASSURED
MAPPED AND EXPLORED
0-3000 ft OVERBURDEN
1.56 X I012 tons
3000-6000 ft
DEPTH
PROBABLE ADDITION °'34 X l0'2 tons
\
UNMAPPED AND UNEXPLORED AREAS
x
0-3000 ft DEPTH
1.31 X 10": tons
A-94-1633
Figure 3-4. CATEGORIZATION OF THE U.S.
COAL RESOURCE BASE
27
-------
3. 1. 2 Crude Oil
Although a number of investigators have made estimates of the total
quantity of oil in place in the U. S. , we have chosen to present an esti-
mate that was made in connection with the recent energy study by the
National Petroleum Council.10 This estimate is shown in Table 3-5.
The regions are shown in Figure 3-5.
The NPC estimates are based on a prior study, entitled the Future
Petroleum Provinces of the United States, 8 and some of the numbers have
been revised to reflect 1972 estimates. Table 3-5 from the latter report
is shown here to provide some indication of the geographical location of
future oil supplies; recent NPC revisions10 have been included where ap-
plicable. Of the volume of future remaining discoverable crude oil,
approximately 42%, or 160 billion bbl, is believed to be located in off-
shore areas.
The NPC reports a total of 810 billion bbl of oil ultimately discover-
able in the U. S, , including Alaska. Of this total, more than half, or
425 billion bbl, have been discovered, while 385 billion bbl remain to
be identified. However, the total quantity of proved recoverable crude
reserves (the "assured" quantity) in the U.S. at present amounts to
approximately 36 billion bbl of oil. The remaining reserves of original
oil-in-place are divided by the NPC into 227 X 109 barrels as possible-
probable (reasonably assured) and 209 X 109 barrels as speculative. The
quantities of the crude oil resource base that we categorize as assured,
reasonably assured, and speculative are presented in Figure 3-6.
3.1.2.1 Lower 48 Oil Supply
The onshore areas of the Lower 48 States contain approximately 70%
of the total ultimate discoverable oil-in-place. An estimated 31% of this
remains to be discovered. In areas such as the mid-continent region,
which has already been thoroughly explored, only 6.4 billion bbl, or 7%,
of the ultimate reserves remains to be discovered. However, in regions
=tich as the Rocky Mountains, as much as 65 X 109 bbl of oil are poten-
tially discoverable.
28
-------
Table 3-5. OIL-IN-PLACE RESOURCES
(Source: Ref. 10)*
Billion Barrels
Region
Lower 48 StatesOnshore
2 Pacific Coast
3 Western Rocky Mtns.
4 Eastern Rocky Mtns.
5 West Texas Area
6 Western Gulf Coast Basin
7 Midcontinent
810 Michigan, Eastern Interior
and Appalachians
11 Atlantic Coast
Total
Offshore and South Alaska
1 South Alaska Including
Offshore
2A Pacific Ocean
6A Gulf of Mexico
1 IA Atlantic Ocean
Total
Total United State* (Ex. North Slope)
Alaskan North Slope
Onshore
Offshore
Total
Total United States
Ultimate
Discoverable
Oil-in-Place
101.9
43.6
52.4
151.6
109.0
63.0
36.5
3.8
561.8
26.0
49.6
38.6
14.4
128.6
690.4
72.1
47.9
120.0
810.4
Oil-in-Place
Discovered
to 1/1/71
80.0
5.8
23.9
106.4
79.7
58.4
30.5
0.2
384.9
2.9
1.9
11.5
0.0
16.3
401.2
24.0
0.0
24.0
425.2
Remaining Discoverable
Oil-in-Place
Billion
Barrels
21.9
37.8
28.5
45.2
29.3
4.6
6.0
3.6
176.9
23.1
47.7
27.1
14.4
112.3
289.2
48.1
47.9
96.0
385.2
%of
Ultimate
21.5
86.7
54.3
29.8
26.9
7.3
16.4
94.7
31.5
88.8
96.2
70.0
100.0
87.3
41.9
66.7
100.0
80.0
47.5
Reprinted with permission from the National Petroleum Council, ©1972.
29
-------
HAWAIIAN ISLANDS
Regional Boundaries: Region 1 Alaska and Hawaii, except North Slope; Region 2-Pacific Coast States; Region 2A-Pacific Ocean, except
Alaska; Region 3-Western Rocky Mountains: Region 4-Eastern Rocky Mountains; Region 5-West Texas and Eastern New Mexico; Region
6-Western Gulf Basin; Region 6A-Gulf of Mexico; Region 7-Midcontinent; Region 8-Michigan Basin; Region 9-Eastern Interior; Region
10-Appalachians; Region 11- Atlantic Coast; Region 11A-Atlantic Ocean.
Figure 3-5. PETROLEUM PROVINCES OF THE U.S. (Source: Ref. 10)*
* Reprinted with permission from the National Petroleum Council, ©1972. ~*
-------
"ASSURED
A-94-1632
Figure 3-6. CATEGORIZATION OF U.S.
CRUDE OIL RESOURCE BASE
3.1.2.2 Offshore Oil Supply
Table 3-5 also shows that the ultimate discoverable oil-in-place esti-
mated in the offshore regions of the U.S. and the Gulf of Alaska amounts
to about 129 billion bbl, of which only 16 billion bbl have been discovered
as of January 1971. Thus, about 112 billion bbl remain to be discovered
in these offshore areas. By 1985, an estimated 50% of the domestic oil
supply will come from offshore areas.
3.1.2.3 Alaskan Oil Supply
The ultimate discoverable oil-in-place on the Alaskan North Slope,
both offshore and onshore, amounts to approximately 120 billion bbl. Only
24 billion bbl are classed as discovered, leaving an additional 96 billion
bbl as potentially discoverable on the North Slope. However, although
the area around Prudhce Bay has been partially explored, the Naval
31
-------
Petroleum Reserve to the west is generally believed to contain larger
reserves of oil and gas. Note that the 5-year delay in building an
Alaskan pipeline has created a corresponding moratorium on further
drilling and exploration on the North Slope of Alaska. This work is now
being resumed with the assurance that pipeline construction is finally
under way.
3. 1. 3 Natural Gas
The estimated potential gas supply of the U. S. reported by the NPC
is 1178 trillion CF. This estimate is based on the work of the A. G. A.'s
Potential Gas Committee in its report, Potential Supply of Natural Gas in
the United States (as of December 31, 1970).l3 Since publication of the .
NPC report, the committee has revised its estimate of potential gas supply
downward to 1146 trillion CF (as of December 31, 197Z). This latter
estimate is the basis for the following discussion.
The future potential supply of natural gas is defined by the committee
as the prospective quantity of gas yet to be found, exclusive of proved
reserves. The future potential supply is further divided into the follow-
ing categories, the sum of which is the total future potential supply:
Probable. The most assured of new supplies resulting from existing
gas fields.
Possible. These supplies are less assured than those that are prob-
able and are derived from new discoveries in previously productive
formations. These new fields are distinctly different from existing
fields.
Speculative. These are the most uncertain of new supplies and are
attributable to new field discoveries in formations or provinces not
previously productive. A summary of the PGC estimates is shown
in Table 3-6.
Within the NPC study,10 the volume of past natural gas production is
combined with current proved reserves and potential supply to arrive at
a quantity of "ultimate gas discoverable. " The cumulative quantity of gas
produced and proved reserves, as of December 31, 1972, then are sub-
tracted from the ultimate gas discoverable, and the result is referred to
as the future potential supply. This calculation, based on December 31,
1972, estimates, is as follbws:
32
-------
Table 3-6. SUMMARY OF ESTIMATED POTENTIAL SUPPLY
OF NATURAL GAS IN U. S. BY DEPTH INCREMENTS
AS OF DECEMBER 31, 1972
Area Totals
OJ
Onshore (Drilling Depth)
0-15,000 ft
15,000-30,000 ft
Subtotal
Offshore (Water Depth)
0-600 ft
600-1500 ft
Subtotal
Total for 48 States
#
Alaska
Total U. S.
Probable
121
33
154
58
t
58
212
54
266
Possible
. in 1^ f-.tr1 at -I A fi
i\J \s£ at 1 rr. 1 J
153
45
198
74
18
92
290
94
384
Speculative
139
59
198 I
71
9
80
278
Z18
496
Total
413
137
550
203
27
230
780
366
1, 146
Not available by depth increments.
Less than 1 X 1012 CF.
-------
1Q12 CF
Ultimately Discoverable Volume 1849. 0
Less:
Cumulative Production 437
Proved Reserves 266 703. 0
1146.0
Proved reserves of natural gas are compiled and reported by the
A. G. A. and are defined as follows:
"Proved reserves may be both drilled and undrilled.
Undrilled reserves are located so close to the drilled
reserves that every reasonable probability exists that
they will be producible when drilled. Proved reserves
are made up of associated and nonassociated gas which
simply indicates whether the reserves are to be pro-
duced with oil or not. "
The quantity of proved natural gas reserves was about 265 trillion CF
as of December 31, 1972. Proved reserves and probable potential sup-
plies are considered "assured. " Possible potential supplies are "reason-
ably assured" and speculative supplies are speculative. The geographical
location of the potential gas supply is summarized in Figure 3-7 by
probable, possible, and speculative categories as of December 31, 1972.
In summary, 68. 1% (780 trillion CF) of the potential gas estimated
by the Potential Gas Committee is located in the Lower 48 States. The
remaining 31. 9% (366 trillion CF) is located in Alaska. Approximately
70. 5% of the gas from the Lower 48 will be found onshore, with 413
trillion CF in the well depth range of 0-15,000 feet and 137 trillion CF
in the depth range of 15,000-30,000 feet. The offshore areas of the
Lower 48 account for the remaining 29. 5% (230 trillion CF) of the poten-
tial supply.
3.1.4 Natural Gas Liquids
Estimates of the quantity of natural gas liquids that are ultimately
recoverable have not been made by the NPC. Natural gas liquids are
extracted from natural gas as it is produced from the well. The NPC
does, however, project the quantity of natural gas liquids production up
to 1985. The following fuels are derived from natural gas liquids: con-
densate, pentane and heavier hydrocarbons, and LPG.
34
-------
\
\
\
\
WELL DEPTH, 0-15,000 ft
PROBABLE I2ICF
POSSIBLE I53CF
SPECULATIVE 139 CF
\
WELL DEPTH
15,000-30,000 ft \
PROBABLE 33 CF \
POSSIBLE 45 CF \
SPECULATIVE 59 CF \
\
\
WATER DEPTH, O-600 ft
PROBABLE 58 CF
POSSIBLE 74 CF
SPECULATIVE 71CF
PROBABLE 54 CF
POSSIBLE 94 CF
SPECULATIVE 218 CF
TOTAL 366 CF
WATER DEPTH, 600-1500 ft
PROBABLE
-------
Although the ultimately recoverable quantity of natural gas liquids has
not been estimated, the quantity of proved reserves is about 6. 8 X 109bbl,
which is assumed to be an "assured" resource. This estimate of reserves
is based upon the historical ratio of natural gas to natural gas liquids
discoveries. Based on the assumption that no economic or technical
limitations will limit future natural gas liquids production, the current
reserves-to-production ratio is approximately 9 years based on 1972
production.
3.1.5 Oil Shale
The NPC8 estimates domestic oil shale resources at 1781 billion bbl.
Resources of oil shale are classified into one of four groups:
1, 2 These are the resources satisfying the 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 access-
ible and better defined deposits are included. Class 1 is a more
restrictive cut of these reserves and indicates that portion which
would average 35 gallons per ton over a continuous interval of at
least 30 feet.
3 Class 3 resources, although matching Classes 1 and 2 in richness,
are more poorly defined and not as favorably located. These may
be considered potential resources and would be exploitation targets
at the exhaustion of Class 1 and Class 2 resources.
4 These are lower grade, poorly defined deposits ranging down to
15 gallons per ton which, although not of current commercial in-
terest, represent a target in the event that their recovery becomes
feasible. These may be considered speculative resources.
Class 1 deposits are considered as an "assured" resource base;
Class 2 and 3 deposits are "reasonably assured"; and Class 4 forma-
tions are "speculative" as a resource base. The appropriate quantities
are shown in Figure 3-8.
Of the total resource base, 129 billion bbl are in Classes 1 and 2 and
would be equivalent to 54 billion bbl of syncrude oil. The location of
major U.S. oil shale deposits is shown in Figure 3-9 and Table 3-7.
36
-------
CLASS 2
ASS I r ASSURED
A-94-I63I
Figure 3-8. CATEGORIZATION OF DOMESTIC SHALE OIL RESERVES
Table 3-7. SUMMARY OF OIL SHALE RESOURCES1 IN
GREEN RIVER FORMATION (Source: Ref. 10)
Resources
Class 1 Class 2 Class 3 Class 4 Total
Location
Piceance Basin
Colorado
Uinta Basin
Colorado and Utah
Wyoming
Total
-109 bbl-
34
34
83
12
95
167
15
4_
186
916
294
256
1466
1200
321
260
1781
37
-------
Go
oo
Great Divide Basin
IDAHO
UTAH
VVYO_MING_
COLORADO
> Salt Lake City
Grand Mesa
Approximate extent
of selected minable
seam in the Mahogany
Zone (at least 30 feet
thick and averaging
at least 30 gal./ton).
Figure 3-9. LOCATION OF MAJOR OIL SHALE RESOURCES (Source: Ref. 10)*
Reprinted with permission from the National Petroleum Council, ©1972.
-------
Oil shale deposits have been found in other regions of the U.S. These
deposits, however, have been assayed at less than 15 gallons of syncrude
per ton and are not considered to be 6f commercial significance until the
more readily available resources are depleted. About 80% of the oil shale
within Classes 1 and 2 is located on Federal lands. Because of this,
development of oil shale resources would involve public as well as private
participation in areas of research and development.
3. 1. 6 Tar Sands
Tar sands is a term used to describe hydrocarbon-bearing deposits to
be distinguished from more conventional oil and gas reservoirs. The
high viscosity of the hydrocarbon does not permit recovery in its natural
state by a conventional well as in the production of crude oil. In-place
domestic resources of tar sands are estimated by the NPC10 to range
from 17.7 to 27.6 billion bbl. Efficiency estimates8 for conversion of
tar sands to synthetic crude (salable product) range from 35 to 87%,
resulting in a maximum of 23. 5 billion bbl of crude oil equivalent, or
an amount that is about equal to 6% of the remaining domestic discover-
able crude oil. The major resources of tar sands are located in five
areas of Utah. They are listed in Table 3-8 and are currently not pro-
duced on a commercial basis. Because only small quantities of tar sands
lie within the U. S. , a major development of this resource is unlikely;
however, it can be considered an assured resource.
Table 3-8. ESTIMATED IN-PLACE RESOURCES OF
UTAH TAR SANDS DEPOSITS (Source: Ref. 10)
109 bbl
Tar Sand Triangle 10.0-18.1
P. R. Spring 3. 7- 4. 0
Sunnyside 2. 0- 3. 0
Circle Cliffs 1.0- 1.3
Asphalt Ridge 1. 0- 1. 2
Total 17.7-27.6
39
-------
3. 2 Nuclear Energy Resources
3. 2. 1 Uranium
The NPC estimates7 of proved and potential uranium resources are
based on AEC projections that have been updated to January 1973. The
AEC resource levels are presented in terms of cutoff costs of production.
Three cost levels are discussed in the NPC report: $8, $10, and $15/lb.
Present estimates of proved and potential uranium resources at a cost of
up to $15/lb are about 1.5 million tons. Proved reserves at $8/lb are
estimated to be 273,000 tons as of January 1, 1973 (Table 3-9). The
potential estimates shown are related to specifically known mineralization
and geological trends and, as such, are subject to review as new informa-
tion becomes available.
Table 3-9. DOMESTIC RESOURCES OF URANIUM AS
ESTIMATED BY THE AEC , JANUARY 1, 1973 (Source: Ref. 15)
Cost of
Production, *
$/lb
8 (or less)
10 (or less)
15 (or less)
Proved
Reserves
273, 000
337, OOOJ
520, 0001"
Potential
Reserves
.... trine TT Oj
450, 000
700, 000
1, 000, 000
Total
723, 000
1, 033, 000
1, 520, 000
*
Based on the forward cost of production, not
including amortization of past investments, interest,
or income taxes; also, no provision is made for
return on investment; does not necessarily repre-
sent the market price.
Includes 90, 000 tons potentially recoverable as a
by-product of phosphate and copper mining at a
cost of $lO/lb or less. .
Substantially all the proved reserves of uranium (U3O8) and approxi-
mately 85% of the reserves categorized by the AEC as potential resources
are located in the present producing areas; yet these areas constitute
less than 10% of the total region where evidence of uranium occurs. In
many cases, present producing areas have not been completely explored.
Because about 50% of all proved and potential uranium resources are on
Federal or Indian lands in the western U.S. , reasonable access to these
40
-------
lands must be allowed to support necessary exploration and development
efforts. Proved reserves (at $15/lb or less) are considered "assured,"
and potential reserves are classified as "reasonably assured. " These
quantities are shown in Figure 3-10.
A -94 -1634
Figure 3-10. DOMESTIC RESERVES OF URANIUM
AT $15 PER POUND OR LESS
3. 2. 2 Thorium
The resource base of thorium in the U.S. is currently estimated at
about 295, 000 tons. This estimate includes resources that are recover-
able as by-products and high- and low-grade non-by-product quantities.
The only reserves that are mined currently are Atlantic Coast beach
placers, where monazite (the raw material ore) is produced as a minor
by-product of titanium mining.
41
-------
Large resources of relatively high-grade thorium of more than 0.1%
are located in Idaho and Montana. A second large potential source is in
a low-grade deposit of granite near Conway, N. H.
Assured reserves are about 46, 000 tons recovered as a by-product.
The remaining reserves, 249, 000 tons, are classified as reasonably
assured.
Thorium resources are not well-defined because of the relatively
small past demand. The amount of thorium recovered as a by-product
has been more than sufficient to meet current needs, and as a result,
the deposits cannot be mined at a profit.
3. 2. 3 Nuclear Fusion Reactors
The predictability of controlled thermonuclear (fusion) reactor develop-
ment, in both pattern and schedule, is very low. We do not expect it to
be a significant factor in the overall energy supply picture by 2000, but
there is a small probability (perhaps 1%) that it could be a much larger factor
than anyone has publicly ventured to predict.
The AEC and those working under its sponsorship are in almost
unanimous agreement that fusion reactor commercialization will not occur
before the end of this century. U. S. development programs based on
magnetic confinement of the fusion plasma are rather firmly geared to
this schedule, and apparently only a dramatic crash program, not yet
on the horizon, would accelerate it noticeably. Such a program would
be politically feasible if, for example, Russian or other foreign techno-
logical efforts begin to show near-term commercial possibilities, but it
is still too soon to predict such occurrences. Such a program also would
become a real possibility if the energy shortage were to become much
worse, but the formidability of the problems of magnetic confinement of
fusion make it more likely that other domestic developments, such as
coal gasification and liquefaction programs, would be given even higher
priorities in efforts to meet pre-2000 energy supply crises.
The largest uncertainty is the rate at which laser fusion development
will proceed. Most authoritative sources predict that this technology will
develop even more slowly than magnetic confinement technology, pointing
out that even technical feasibility is still questionable. Historically, new
42
-------
energy forms are developed to commercial significance over a few decades
rattier than over a few years. Optimistic representations of development
prospects can be expected from both political figures and scientists/
technologists. This optimism must be considered in the light of the lead
time required for commercial development. Laser fusion possibilities
are receiving intense worldwide attention, mostly unpublicized for military
as well as for commercial reasons. The scientific possibilities are
many and largely unevaluated. This immature technology seems to us to
be quite capable of making rapid, unpredictable advances that could attain
commercial significance after 2000. Nobody, to our knowledge, has
information from which he can predict with any confidence that there is
a certain probability of this happening, but the possibility must be acknow-
ledged.
3. 3 Renewable Resources
3. 3. 1 Hydropower
Hydropower is conventionally used in the generation of electricity.
The total hydroelectric energy potential of the U.S. (exclusive of Alaska)
as of January 1, 1971, is estimated to be about 530 billion kWhr annually.
Of this total, 249 billion kWhr were being generated annually through
facilities already installed. The remaining 281 billion kWhr represent
the total undeveloped hydroelectric energy in the U.S. Both the developed
and undeveloped power are considered assured. However, according to
the FPC, economics and other factors may prevent the development of
much of this potential. The remaining sites suitable for economic devel-
opment are limited.
3. 3. 2 Geothermal Heat
Case I of the NPC study assumes that large geographical areas will
be made available for prospecting, including recently opened Federal
lands, to encourage exploration and development of geothermal energy in
the next 4-5 years. The U.S. resource base is summarized in Table 3-10.
43
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Table 3-10. IN SITU HEAT RESOURCES
Reserve Target Resource
Geothermal Resources for 1985 Base
1015 Btu
Localized Hydrothermal Systems,
Down to 2 Miles Deep 5. 6 560
Localized Hydrothermal Systems,
Down to 6 Miles Deep 2. 8 2800
The localized geothermal systems less than 2 miles down are considered
assured, and those between 2 and 6 miles down are reasonably assured.
The most favorable areas of geothermal production in the U. S. are in
the western part of the country, primarily in the states of California,
Nevada, Oregon, Washington, Idaho, Utah, Arizona, Wyoming, Montana,
Colorado, and New Mexico. Alaska and Hawaii also can be included
with this group. This is evidenced by high heat gradients and the oc-
currence of large numbers of warm to hot springs, fumaroles, and geyser
complexes whose temperatures approach the local boiling point.
Some of these localities are represented by a single spring of low
flow and enthalpy, whereas others, such as Yellowstone National Park,
Wyo. , cover many acres. About 100 of these hot-fluid-surface localities
are close to the boiling point.-
The Western U.S. also contains much surface evidence of recent
(Quaternary) volcanism. Many hot springs are associated with recent
faulting. Much of it is basin and range type, in areas of recent volcanism.
Other springs are located in areas where the earth's crust is believed
to be thin and where convective rifting has taken place. In both cases,
faults serve as the vehicle for heat flow to the surface.
3. 3. 3 Solar Energy
Solar energy is undoubtedly the earth's most underutilized resource of
energy. However, it is so diffusely distributed and so variable in intensity
that the capital costs of its collection and application have commonly pre-
cluded its more general use. Until recent years, when the energy affluence
44
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of many countries began to decline noticeably, very little money and effort
were devoted to the development of even the well-recognized possibilities
for solar energy exploitation.
For the "average day" in a year, the solar energy received by a
horizontal surface at ground level in the U.S. is about 1400 Btu/sq ft.
This corresponds to about 58 Btu/sq ft-hr (24-hour day), or about 17
watts/sq ft over 24 hours. The "assured" energy is then about 14. 4 X 1015
kWhr/yr. This is much less than the intensity of radiant energy pro-
jected toward the earth from the sun. This solar constant is about
10,330 Btu/sq ft-day. All the energy consumed in the U.S. in 1970
could have been collected from the sun by a single collector only 27 miles
in diameter (570 square miles in area), providing that collector was a
satellite above the earth's atmosphere and so situated that it was exposed
normal to the sun's rays all the time.
Many ways for converting solar energy to electricity are under devel-
opment, such as solar thermal conversion, photovoltaic conversion,
ocean thermal difference, wind power, and bio conversion. Chemical-fuel-
synthesis routes are discussed in other sections.
A solar energy resource assessment usually considers the land areas
available or required for energy collection. A form of solar energy
capture and energy conversion that is very dependent on land is agri-
culture or the "solar plantation. "
The energy from a plantation is a perpetually renewable source of
fuel. Fuel can be produced from plants in several ways. One way is
to ferment it to produce alcohol. Another way is to burn it to produce
steam and ultimately electricity. A third technique is pyrolysis to pro-
duce fuel gases.
If crops are grown as a source of fuel, the land requirements depend
on the type of crop and fuel synthesis as well as on the growing condi-
tions. In Section 5, "Fuel Synthesis Technology," Table 5-10 presents
45
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examples of crop yields, fuel values, and solar energy conversion effi-
ciencies. For example, on the basis of 5 tons/yr/acre yield and 6500
Btu/lb fuel value, the land requirements for an energy plantation to support
a 1000-MW (50% load factor) power plant can be derived as follows.
Assuming 10, 000 Btu/kWhr, 5 billion Btu/hr is required for a stated
power plant. The amount of heat generated per square mile per hr by
burning produced fuel will be 475 million Btu (5 X 2000 X 6500 X 640/
365 X 24). Therefore, 1053 square miles is required to support the
stated power plant. The efficiency of solar energy conversion in this
case is about 0. 3% on the basis of 54. 2 Btu/hr/sq ft of solar energy
input. However, the solar energy conversion depends on the type of
trees, farm crops, and many other factors. Therefore, the land require-
ment for a particular amount of fuel production varies considerably
from one case to another.
3.3.4 Tidal Energy
The use of the energy in tides to generate power goes back at least
to the llth century when small tidal mills were used to grind corn in
several European countries. In 1734, at Slades Mills in Chelsea, Mass.,
a tidal installation developing 50 hp was used for grinding spices. On
Passamaquoddy Bay in Maine, tidal mills were in operation prior to
1800.
A fundamental problem with tides is that the range (distance between
high and low water levels) varies widely along the U.S. coast. From
Eastport, Me., the tidal range decreases from about 18 to 9 feet at the
north shore of Cape Cod. South of Cape Cod, the tidal range is only 4
feet, and this diminishes to about 2 feet off the coast of Florida. A
notable exception to the East Coast trend is the approximate 7-foot tidal
range in Long Island Sound. On the Gulf Coast, the range is less than
2 feet. For the West Coast, the tidal range increases from about 4 feet
at San Diego to about 11 feet at Seattle. Along the Canadian Coast the
46
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range is about 12 feet, whereas the Cook Inlet in Alaska experiences about
an 18-foot variance. Thus, except for specific bays in Maine and Alaska,
the tidal range is too low to be practically useful.
On a yearly average, the tidal range at the head of the Bay of Fundy
(Southeast Canada) is about 35 feet. This range is significantly higher
than elsewhere on the North American continent and has thus attracted
most attention as a potential source of tidal power. In the U.S.,
Passamaquoddy Bay, with a range of 18-24 feet, also has received much
attention.
Many engineering problems would be involved in developing tidal power,
even in a relatively favorable area such as the Bay of Fundy. Small-
scale development in the Cape Tenny and Cape Maringouin areas would
encounter water depths of no more than 60 feet. Water depths near
St. John would be up to 250 feet. At the mouth of the bay near Yarmouth,
Nova Scotia, and Jonesport, Me., water depths would be about 600 feet.
Thus, plans to tap the ultimate potential of the Bay of Fundy and the
Passamaquoddy area would have to cope with the larger scale problems
of deeper water and the confinement of larger areas of the bay. However,
engineering feasibility exists, given the necessary amount of capital.
Similar problems with water depth would occur near Alaska. Although
interior portions of the Cook Inlet are no more than 120 feet deep, the
mo\i.tVi of the inlet has depths of 300 feet. The remoteness of the area
and l:he presence of drift ice and silt, together with the possibility of
earthquakes, make it unlikely that Alaskan tidal power will be developed
in the next 30 years.
If engineering and commercial practicalities are considered and if
15 feet is assumed to be the lowest tidal variance that might be developed
in the next 30 years, only the Passamaquoddy Bay region in Maine can
qualify. Because this bay is bounded by Canada and Maine, development
would necessarily be a joint venture. Actually, Passamaquoddy is a
small bay that is a part of the larger Bay of Fundy. The amount of
energy that would be potentially available from the U. S. portion of
47
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Passamaquoddy Bay is 1.8 billion kWhr/yr, but this energy can only be
classified as "reasonably assured. "
3. 3. 5 Wind Power
From the 1920's until about 1951, considerable research went into
estimating the amount of energy available from the wind. These studies
concentrated on determining how much wind power is available over the
world's land masses and found that there is far more wind over the
oceans, which at that time was considered to be untappable.
In 1972, Professor William Heronemus6 of the University of Massachusetts
realized that extensive meteorological data were available from the "Texas
Towers, " which were erected off the Atlantic Coast during World War II.
By using data and experience from prototype windmill generators that had
been operating in the 1950's and 1960's in the U.S. and in Great Britain,
Heronemus designed a floating-wind-generator concept, and he estimated
the size, weight, and cost of several configurations of such units.
Using the Texas Towers' wind -speed information, Heronemus observed
the number of hours in the year when the wind would blow at moderate
and peak generating conditions. He determined that the wind speed would
fall below 15 mph, the minimum generating condition, for about one-third
of the year, so a large energy storage system would be required to allow
the system to continue generating on a year-round basis. He selected
electrolytic hydrogen as his energy "storage battery" concept. Each
floating wind generator would house three 2000-kW generators, and 165
of these generators would be clustered around each electrolyzer station,
which would correspond to a size already determined in studies conducted
by ;Allis -Chalmers Corp. in 1966. The electrolyzers themselves would be
housed in floating reinforced concrete hulls and would be joined together in
long chains by an underwater seabed pipeline system.
The total installed plant would have the same generating capacity as the
proposed nuclear, fossil-fuel, and hydroelectric pumped storage plant that
'" planned for installation in New England between 1976 and 1990. The
output of the total plant is to be approximately 160 billion kWhr/yr.
Assuming 10 such plants could be built, the assessed resource base would
48
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be 5.4 X 1015 Btu/yr. To achieve this output, 83 electrolyzer stations,
each with its own cluster of wind generators, are required.
A recent article7 in Environment discusses Heronemus's work and the
classic windmill design work that preceded it. Significantly, the article
begins by painting a picture of the "Great Plains of Mid-America, from
Texas to North Dakota, with a forest of giant windmills, each the height of
a 70-story building. " Whether such an array of towers would be accept-
able to those interested in the beautification of America is one question
a particularly serious one considering intensified public pressure to put
unsightly electrical transmission lines underground.
Environmentalists are already challenging the unsightliness of land-
based windmills, and at this stage, apparently, widespread use of wind
power in the U. S. will be highly unacceptable. The offshore wind power
system proposed by Heronemus, however, appears to be more attractive
and will undoubtedly receive further attention as an energy source in the
future.
3. 3. 6 Waste Materials
We have assessed the potentials of waste materials as an energy
resource, and the practical, large-scale resources are municipal wastes
(solids) and animal feedlot wastes (manure). These waste materials
could be burned directly to yield thermal energy, or they could be con-
verted to a hydrocarbon fuel like methane. The following discussion gives
some estimates of quantities, heating values, and fuel equivalents (as SNG).
3. 3. 6. 1 Municipal Wastes
In 1973, the solid waste collected in the U.S. averaged about 5 lb/
person. This total comprises all types of solid wastes, such as household,
commercial, industrial, construction, demolition, street and alley, and
miscellaneous collections. The per-capita waste production in the U.S.
has been rising; it is projected11 to reach 8 lb by 1990 and almost 10 lb
by 2000. Its heating value also is expected to rise because of an increased
paper and plastic content of refuse. On the basis of Series E population
projection,lv we have calculated the total heating value of collected refuse
in the U.S. from 1970 to 2000 (Table 3-11).
49
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Table 3-11. ESTIMATE OF TOTAL ENERGY AVAILABLE
IN MUNICIPAL WASTES, 1970-2000
Year
1970
1975
1980
1985
1990
1995
2000
Population,
10 .people
204. 9
213. 9
224. 1
235. 7
246. 6
256. 0
264.4
Per -Capita
Daily Refuse
Collected,
lb/dayf
4. 5
5.4
6. 3
7. 0
8. 0
9. 0
9.75
Total Annual
Refuse,
lo9 Ib/yr
336
422
515
602
720
841
941
Estimated
Heating Value,
Btu/lbf
4493
4582
4627
4738*
4849
5005*
5161
Total
Heating Value,
1012 Btu/yr
1512
1932
2384
2853
3492
4209
4856
Source: Ref. 17.
Source: Ref. 11.
Estimated.
Assuming that an overall conversion efficiency of 42% can be obtained
for converting waste to SNG, the net heating value produced from this
municipal waste will increase from 635 trillion Btu in 1970 to 2040 trillion
Btu in 2000 (Table 3-12). This resource is considered "assured."
Table 3-12. ESTIMATED SNG GENERATED FROM
COLLECTED MUNICIPAL WASTES, 1970-2000
Total Heating Value SNG Heating Value*
Btu/yr
635
811
1001
1198
1467
1768
2040
Assumes that overall thermal efficiency of
conversion is 42% (Source: Ref. 5).
V/aa t*
i esir
1970
1975
1980
1985
1990
1995
2000
in12
-J H-.---ii.-T-n m-.mr -_,-- T- J_ \J
1512
1932
2384
2853
3492
4209
4856
50
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3. 3. 6. 2 Animal Feedlot Wastes
Animal feedlots constitute the largest single source of waste products.
Cattle represent the largest single category for the production of wastes
in feedlots. According to a consensus of statistics of solid animal wastes
only, cattle account for almost 90% of the total.
By using statistics from Statistical Abstract,16 a ratio of the animals
slaughtered to the total population ckn be calculated (Table 3-13). These
ratios decrease from 4.2 in 1950 to 3.0 in 1973. We cannot determine
whether this trend will continue or reverse, so -we have assumed that it
will level off at 3. 0. For our purpose, this is a conservative number,
and it is doubtful that the ratio will reverse itself and begin to increase
because the cost of keeping animals will not decrease. As a result, the
feedlot owner will try to keep the ratio of cattle population to the slaughter
as low as possible.
Table 3-13. DATA ON POPULATION AND NUMBER
OF CATTLE SLAUGHTERED, 1950-1973 (Source: Refs. 3 and 16)
Year
1950
1956
I960
1965
1970
1971
1972
1973
Total
Population
11-
million
78
97
96
109
112
115
118
122
Number
Slaughtered
i_ _ i
18.6
26.6
26. 0
33.2
35.4
35.9
38. 8
41. 1
Ratio,
population/
slaughtered
4. 19
3. 65
3. 69
3. 28
3. 16
3. 20
3. 04
2. 97
On this basis, the total cattle population is estimated to be 153 million
head in 1980 and 177 million head in 1985. This is compared with a total
of 118 million head in 1972. Extrapolating these data in a straight line to
2000 results in a total population of 245 million head of cattle (Table 3-14).
51
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Table 3-14. ESTIMATE OF TOTAL CATTLE
POPULATION, 1970-2000
Year
1970
1971
1972
1973
1975
1980
1985
1990
1995
2000
Population,
106 head
112*
115*
118*
122*
130*
153*
177*
197*
221*
245*
Source: Ref. 16.
Calculated.
The average daily wet manure production of cattle is 60-80 Ib/head.
The lower value is usually given for beef cattle and the upper for dairy
cattle. We have used an average of 70 Ib/day of wet manure. This
would mean that, by 2000, the total production of wet manure would be
3130 million tons (Table 3-15), compared with 1400 million tons in 1972.
Table 3-15. ESTIMATED MANURE PRODUCTION, 1975-200C
Manure
Wet Basis Dry Basis
tons
332
391
452
511
572
626
Year
1975
1980
1985
1990
1995
2000
I r)t
1600
1955
2260
2555
2860
3130
52
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To convert this to an equivalent total SNG heating value, we assumed
that manure has a heating value of 7500 Btu/lb (dry) and that manure is
80% liquid. Table 3-25 shows an estimate of the production of manure
on a dry basis as 20% of the production on a wet basis. Thus, the
potential production of SNG from manure is 4980 trillion Btu in 1975 and
9390 trillion Btu in 2000; however, these are gross numbers. Realistically,
a 50% conversion of the gross Btu content to SNG is possible, so the
production of SNG from manure could be almost 2500 trillion Btu in 1975
and 4700 trillion in 2000 (Table 3-16). For this study, all animal feedlot
wastes are considered an "assured" resource.
Table 3-16. ESTIMATED POTENTIAL PRODUCTION
OF SNG FROM MANURE, 1975-2000
Total Heating Value SNG Production
Year 1012 Btu/yr
1975 4980 2490
1980 5866 2933
1985 6780 3390
1990 7666 3833
1995 8580 4290
2000 9390 4695
53
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3. 4 .References Cited
1. Averitt, P., "Coal," in Probst, D. A. and Pratt, W. P., Eds.,
United States Mineral Resources, Geological Survey Professional
Paper 820^ 133-42. Washington, D. C. : U. S. Government Printing
Office, 1973.
2. Dupree, W. G., Jr. and West, J. A., United States Energy Through
the Year 2000. Washington, B.C.: U.S. Department of the Interior,
December 1972.
3. Economic Resource Service, U.S. Department of Agriculture, private
communication, March 1974.
4. Finch, W. I. et al., "Nuclear Fuels, " in Probst, D. A. and
Pratt, W. P. , Eds. , United States Mineral Resources, Geological
Survey Professional Paper 820, 455-76. Washington, D. C. : U.S.
Government Printing Office, 1973.
5. Ghosh, S. and Klass, D. L. , "Conversion of Urban Refuse to
Substitute Natural Gas by the Biogas Process. " Paper presented
at the Fourth Mineral Waste Utilization Symposium, Chicago,
May 7-8, 1974.
6. Heronemus, W. E. , "Power From the Offshore Winds. " Paper
presented at the Annual Meeting of the Marine Technology Society,
Washington, D. C. , September 12, 1972.
7. McCaull, J. , "Windmills, " Environment 15, 6-17 (1973) January-
February.
8. National Petroleum Council, Future Petroleum Provinces of the
United States. Washington, D. C. , July 1970.
9. National Petroleum Council, U. S. Energy Outlook; An Initial Appraisal
by the New Energy Forms Task Group 1971-1985. Washington, D. C. ,
December 1972.
10. National Petroleum Council, U. S. Energy Outlook; A Report of the
National Petroleum Council's Committee on U.S. Energy Outlook.
Washington, D. C. , December 1972.
11. Niessen, W. R. and Chansky, S. H., "The Nature of Refuse, " in
Proceedings of the 1970 National Incinerator Conference. 10. New
York: American Society of Mechanical Engineers, 1970.
12. NSF/NASA Solar Energy Panel, An Assessment of Solar Energy as
a National Energy Resource. College Park, Md. : University of
Maryland, December 1972.
54
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13. Potential Gas Committee, Potential Supply of Natural Gas in the
United States (as of December 31,'" 1972). Sponsored by Potential
Gas Agency, Mineral Resources Institute, Colorado School of Mines
Foundation, Inc., Golden, Colo., November 1973.
14. "Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in
the United States and Canada and United States Productive Capacity
as of December 31, 1972," 27. Arlington, Va. : American Gas
Association; Washington, D. C. : American Petroleum Institute; Calgary,
Alberta: Canadian Petroleum Association, May 1973.
15. Table 3-16. Atomic Energy Clearing House 19, 33 (1973) April 4.
Washington, D. C. : Congressional Information Bureau, Inc.
16. U.S. Bureau of the Census, Statistical Abstract of the United States:
1973, 94th Ed. Washington, D. C. , 1973.
17. U.S. Department of Commerce, Social and Economic Statistics
Administration, Population; Estimates and Projections. Washington,
D. C. : Bureau of the Census, December 1972.
55
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4. ENERGY DEMAND AND SUPPLY MODELS
The competing demand for energy and fuels in the future has been assessed
through the formulation of two energy models. Model I is based, in part, on
the NPC study.4 Model II is based, in part, on a special report for the
Gas Supply Committee of the A.G.A. prepared by Dr. Henry R. Linden
of IGT.2 Both of these studies project the energy supply incrementally to
the year 2000.
Model I shows that U. S. energy self-sufficiency is theoretically feasible
during the mid-term time frame (1985-2000). Model II assumes that energy
demand increases at an annual rate greater than that in Model I and that the
U. S. will not become self-sufficient during the time frames of this study.
In the case of both models, deficits would be filled by imports.
These models are not intended for the purpose of energy allocation in the
future; rather, they are quantitative indications of energy supply and demand
deficits and/or excesses. A true "modeling situation" requires a more ex-
tensive establishment and definition of parameters, which are beyond the
scope of this study. One objective of this study is the determination of the
need for and the quantities of an alternative fuel in some future time frame.
Our methodology for selecting energy sources and alternative fuels uses
the projections of the economic models.
4. 1 Model I
As previously stated, Model I contains data from the NPC report.4 The
NPC projected three levels of energy demand: high, medium, and low in
5-year increments up to 1985 followed by a 15-year interval to 2000. We
selected the low level of projected energy demand for our model. For the
period 2000-2020, energy demand is assumed to continue to grow at the
same annual rate as in 1985-2000, 2. 8%. This assumption was made be-
cause the NPC did not go beyond 2000,
Future energy supplies also are based on NPC data. Unlike energy demand
projections, the energy supply projections were presented in a series of four
cases. Each supply case is based on a different set of parameters related to
resource finding and production rates. Case I represents the highest quan-
tity of domestic energy supply, whereas Case IV represents the lowest
quantity. Case I was selected for our model.
57
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The NPC report is a widely used and the most up-to-date energy resource
analysis available. We selected it for use here to avoid generating yet another
assessment of energy resources and demands. The assumptions upon which
the Case I energy supply quantities are based closely approximate an opti-
mistic situation in which a maximum effort is undertaken to make the U. S.
energy supply self-sufficient at the earliest possible date. These conditions
best fit the ground rules of this study, i.e. , to assess the feasibility of al-
ternative automotive fuels based on U.S. domestic resources.
Four variables were selected by the NPC as being most significant in
determining the level of energy demand. These variables are economic
activity (GNP), cost of energy, population growth, and environmental con-
straint. Under Model I, the future economic growth rate (GNP) is assumed
to be 3.2% annually up to 1985, in terms of real economic increase. Industrial
production and real personal income are assumed to vary in proportion to the
changes occurring in GNP. All demographic factors are included under the
single variable population. Model I population growth is expected to increase
at an annual rate of 1%.
As justification for Model I demand levels, an immediate reduction in the
rate of increase of energy consumption would be attributed to increased prices
that, in turn, induce more efficient energy utilization. Efficiency improvements
are brought about by improved design of heating and cooling equipment for
residential, commercial, and industrial applications; greater use of building
insulation materials; and lighter weight vehicles.
Some moderate changes in domestic petroleum and synthetic fuel supply
have been incorporated, and they are contained in Table 4-1. Most of these
changes concern shale oil production, coal liquefaction, and SNG production,
and they reflect recent projections for development of these industries.3 These
projections serve as optimistic updates to certain portions of NPC Case I,
and they are in the spirit of U. S. energy independence. They do not signifi-
cantly change the overall energy supply according to NPC Case I, and they
have no effect on the NPC level of energy demand.
Some important assumptions had to be made for Model I to arrive at an
energy supply and demand projection arranged according to market segment.
The NPC report provided only gross energy demand numbers for each consum-
ing segment. No attempt was made in the NPC study to show how the demand
58 ;
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was to be satisfied, i. e. , the quantity of each energy resource that is likely
to be consumed within each of the market segments. Table 4-1 summarizes
energy demand and the quantity of each domestic source supplied.
Table 4-1. MODEL I ENERGY SUPPLY AND DEMAND
BY MARKET SECTORS
1970 1975 1980 1985 2000* 2020*
1015 Btu
Demand
Residential/Commercial 15.8 18.2 21.1 23.9 36.2 62.8
Industrial f 20.0 22.2 24.7 27.1 41.0 71.2
Transportation 16.3 19-4 23.0 26.7 40.4 70.2
Electricity Conversion 11.6 15.5 20.7 26.7 40.4 70.2
Nonenergy 4.1 5.0 6.2 8.1 12.3 21.3
Total 67.8 80.3 95.7 112.5 170.3 295.7
Supply
Oil
Conventional (Wellhead) 21.0 23.7 27.3 31.7 31.0 31.0
Oil Shale 0 0 0.6 1.9 6.7 6.7
Coal Liquefaction 0 0 0.2 1.1 10.2 13.0
Total 21.0 23.7 28.1 34.7 47.9 50.7
Gas Production
Conventional (Well) 22.4 24.5 24.6 28.0 22.0 15.0
SNG From Coal _0 0 1. 0 2. 0 8. 0 10. 0
Total 22.4 24.5 25.6 30.0 30.0 25.0
Coal (Traditional Uses) 13.1 1.6.6 21.1 27.1 35.0 64.0
Hydro and Geothermal 2.7 3.1 4.0 4.7 5.0 5.0
Nuclear (Heat) 0.2 4. 0 11.3 29.8 102.0 275.0
Total 59.4 71.9 90.3 126.3 219.9 419.7
The assumed rate of growth for 2000-2020 is 2. 8% /yr, which is the
same for the 1985-2000 period except for nuclear power supply figures.
To determine the areas of potential energy oversupply or shortfall, the
following assumptions were made:
59
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All market segments consume approximately the same percentage
share of total energy as they now do. In 1975, this is expected to
be as follows- residential and commercial, 22. 7% ; industrial,
27.6%; transportation, 24.2%; electricity conversion, 19.3%.;
other, 6.2% . By 1985, these percentages will change slightly:
residential and commercial, 21.2% ; industrial, 24. 1%; transpor-
tation, 23. 7%; electricity conversion, 23. 7% ; other, 72. % . For
the years 2000 and 2020, the market segments are assumed to con-
sume these same percentages.
The residential and commercial market segment receives top
priority in terms of fulfilling its needs from domestic supply
sources. The categories of industrial and other are next in pri-
ority. The electricity generation segment supplies energy for the
priority markets, and excess power (after filling deficits) is
available to the transportation sector.
The utilization of coal in residential and commercial applications
becomes negligible by 1980. Essentially the coal is used in elec-
tricity generation, chemical fuel synthesis, and industrial processes.
f
The utilization of oil for electricity generation continues to increase
up to 1975 and remains at that level. The rate of growth up to 1975
is based on historical 1961-70 data.
Electrical generation does not consume more natural gas than
in 1970.
All nuclear fuels are used for electricity generation. The efficiency
of this conversion is assumed to be 35% in all time periods.
These assumptions result in the energy supply and demand apportionments
in Table 4-2 through 4-6. These predictions are not purported to be accurate,
especially beyond 1985, and they are not recommended as allocation schedules.
They constitute a self-consistent model for energy accounting, and they re-
sult in the quantities of energy available for transportation shown in Table 4-7.
Except for the effect of the energy conversion efficiency (35%) in the 1985-2020
time period, moderate changes in these assumptions have only small effects
on the quantities shown in Table 4-7. If the energy conversion efficiency is
changed (increased) moderately, significant changes (improvements) occur in
energy availability for transportation (Table 4-7). An example of this effect
is presented in Section 11.3.
60
-------
Table 4-2. MODEL I RESIDENTIAL AND COMMERCIAL
ENERGY SUPPLY AND DEMAND
1970 1975 1980 1985 2000 2020
1015 Btu
Demand 15.8 18.2 21.1 23.9 36.2 62.8
Supply
Oil (21% of Supply) 4.4 5.0 5.9 7.3 10.1 10.6
Gas (31.3% of Supply) 7.0 7.6 8.0 9.3 9.3 7.8
Coal (2. 3% of Supply) 0. 3 0.3 0 0 0 0
Total (Excluding Electricity) 11.7 12.9 13.9 16.6 19.4 18.4
Electricity Consumption* 2. 6 3. 0 3.5 3. 9 6. 0 10.3
Total Supply 14.3 15.9 17.4 20.5 25.6 28.7
Deficit in Domestic Supply 1.5 2.3 3.2 3.4 10.6 34.1
M-
Electricity consumption at a constant percentage of the total energy
consumption in 1970 (16. 5% ).
Table 4-3. MODEL I INDUSTRIAL ENERGY SUPPLY AND DEMAND
1970 1975 1980 1985 2000 2020
1015 Btu
Demand 20.0 22.2 24.7 27.1 41.0 71.2
Supply
Oil (17. 5% of Supply)
Gas (35. 5% of Supply)
Coal (35. 7% of Supply)
Total (Excluding Electricity)
Electricity Consumption
Total Supply 18.3 20.9 24.1 29.2 35.7 47.7
Deficit in Domestic Supply 1.7 1.3 0.6 (2.1) 5.3 23.5
#
Electricity consumption at a constant percentage of the total energy
consumed in 1970 (10% ).
61
-------
Table .4-4. MODEL I ELECTRICITY CONVERSION
SUPPLY AND DEMAND
Demand (Heat)
Supply
Oil (6. 1% of Supply)
Gas (17.5% of Supply)
Coal (62. 0% of Supply)
Hydro and Geothermal
(100% of Supply)
Nuclear (Heat)
Total
Electricity Produced Based on
Available Energy Supply
Electricity Required to Satisfy
Demands (Except Transportation)
Electricity Potentially Available
1970
16.
1.
3.
8.
2.
0.
16.
4.
4.
0.
2
3
9
1
7
2
2
9
9
0
1975
17.
1.
3.
10.
3.
4.
22.
7.
5.
2.
5
4
9
3
1
0
7
9
3
6
1980
20.
1.
3.
13.
4.
11.
33.
11.
6.
5.
1985
1015 Btu-
7
4
9
1
0
0
7
8
2
6
23.
1.
3.
16.
4.
29.
56.
19.
6.
13.
0
4
9
8
7
8
6
8
8
0
2000
35.
1.
3.
21.
5.
102.
134.
46.
10.
36.
0
4
9
7
0
0
0
9
5
4
2020
60.
1.
3.
39.
5.
275.
325.
113.
17.
95.
0
4
9
7
0
0
0
8
9
9
Table 4-5. MODEL I TRANSPORTATION ENERGY
SUPPLY AND. DEMAND
Demand
Supply
Oil (54. 7% of Supply)
Gas (0. 0% of Supply)
Coal (0. 1% of Supply)
Total (Excluding Electricity)
Electricity Consumption
Total Supply
Deficit in Domestic Supply
1970
16.
11.
0
3
5
Negl
11.5
Nef
11.
4.
rl
5
8
1975
19.
13.
0
Nef
13.
Nej
13.
6.
4
0
£l_
0
rl
0
4
1980
23.
15.
0
Nef
15.
0.
15.
7.
1985
1015 Btu-
0
4
iL
4
2
6
4
26.
19.
0
Nef
19.
0.
19.
7.
7
0
iL
0
3
3
4
2000
40.
26.
0
4.
2
Negl
26.2
0.
26.
13.
4
6
8
2020
70.
27.
0
Neg
27.
0.
28.
41.
1
7
;!_
7
4
7
62
-------
Table 4-6. MODEL I OTHER USES SUPPLY AND DEMAND
1970 1975 1980 1985 2000 2020
- 1015 Btu -
4.1 5.0 6.2 8.1 12.3 21.3
0. 1
3.5
0
3.6
0. 1
3. 7
0.4
0. 1
3.9
0
4.0
0. 1
4.1
0.9
0.2
4.0
0
4.2
0. 1
4.3
1.9
0.2
4.7
0
4.9
0.2
5.1
3.0
0.3
4. 7
0
5. 0
0. 3
5.3
7.0
0.3
4.0
0
4.3
0.5
4.8
16.5
Demand
Supply
Oil (0.6% of Supply)
Gas (15. 8% of Supply)
Coal (0% of Supply)
Total (Excluding Electricity)
&
Electricity Consumption
Total Supply
Deficit in Domestic Supply
&
Expressed as a constant percentage of the total energy consumed
in 1970 (2.5%).
The NPC Case I supply conditions include the importation of oil and natural
gas necessary to satisfy any shortfall between domestic energy supply and
demand up to 1985. By 1985 and afterward, a potential domestic surplus
exists in the quantity of thermal energy available in the form of coal and
nuclear energy. According to Model I, most of this surplus is nuclear energy.
This surplus, which is converted to electricity, could be exploited to satisfy
shortfalls in the transportation segment. The electricity could be used for con-
verting other materials to a compatible automobile fuel, e.g. , the electro-
lysis of water to obtain hydrogen for use in other fuel conversion systems.
Alternatively, and perhaps more efficiently, the nuclear heat could be used
directly for chemical fuel synthesis.
The electricity sector, Table 4-4, will be unable to consume all the coal
and nuclear energy potentially available to it in the near term. Currently, there
is not enough coal-burning equipment installed that is capable of handling the
projected quantities of coal. In Model I, this excess energy supply is mathe-
matically converted to electricity (or to a chemical fuel) at 35% overall
efficiency, and it is assigned to fill any deficits in the consuming market
segments according to the priorities outlined above. After deficits in markets
other than transportation have been fulfilled, the transportation market would
be assigned more energy to alleviate its shortfalls.
63
-------
Note that the transportation energy demand is tabulated in units of heat
energy or fuel heating value input to the vehicle. Other sector demands are
a mix of primarily heat energy with some electricity requirements. Electric
vehicles are excluded from this study, but the transportation energy demand
would be less in terms of the electricity input to electric vehicles.
The quantity of energy available to the transportation segment, in the form
of electricity or synthetic fuel, is shown in Table 4-7. As shown, the potential
electricity (or synthesized fuel) will be available for the transportation sector
by 1985. However, if the transportation energy demand continues its growth
as projected by this model, even the optimistic quantities of coal- and nuclear-
based electricity or fuel will in insufficient before the year 2000.
Table 4-7. ENERGY AVAILABLE FOR TRANSPORTATION
IN MODEL I
1975 1980 1985 2000 2020
1015 Btu
Transportation Shortfall 6.4 7.4 7.4 13.8 41.7
All Other (Priority) Shortfalls 4.5 5.7 4.3 22.9 74.1
Electricity or Synthetic Fuel
Potentially Available 2.6 5.6 13.0 36.4 95.9
Electricity or Synthetic Fuel
Available for Transportation Nil Nil 8.7 13.5 21.8
In summary, Model I assumes not only optimistic oil and gas supplies
until beyond 2000, but also a large increase in coal output (about 250% from
1975 to 2000) and a huge increase in nuclear energy (about 2500% from 1975
to 2000). Just as important, the overall energy demand in Model I grows at
a "slow" rate, 3.4% for 1970-85 and 2.8% for 1985-2000 (215% overall
from 1975 to 2000).
Beyond 2000, the energy demand continues to increase at 2. 8% per year.
In essence, under the conditions set forth for Model I, the U.S. could become
energy independent by 1985. However, we would not stay that way. By the
far-term time period (beyond 2000), we would not be self-sufficient in trans-
portation energy unless a more efficient process for converting heat to
electricity or a chemical fuel is developed.
4. 2 Model II
The Model II energy demand and supply projection is less optimistic than
that in Model I, and the Model II demand level is much higher because of
64
-------
electricity generation requirements. Model II supply quantities of energy are .
in closer agreement with NPC Cases II and III. Unlike Model I supply and
demand projections, those in Model II do hot show any indication of crossing
or a condition of future "energy surpluses. " Figure 4-1 compares the overall
supply and demand estimates of Models I and II.
An important assumption in Model It, not considered in Model I, is that
the ratio of energy consumption per dollar of GNP does not remain stable
but continually increases with the passage of time. This" is attributed mainly
to an increase in the degree of electrification, with associated efficiency
losses and waste heat, and also to the production of synthetic fuels from
petroleum, oil shale, and coal. These processes will involve further energy
losses that, in turn, will decrease the overall efficiency of energy utilization.
This is expected to occur in spite of continuing conservation efforts.
The NPC has recognized that, from 1967 through 1970, the use of energy
increased more rapdily than the GNP. However, in the level of energy used
in Model I, this trend is expected to be reversed by greater utilization effi-
ciencies brought about by acceleration in technology. Energy used for environ-
mental protection or improvement also is taken into consideration in Model II.
We have determined the incremental energy demand required by the anti-
cipated increase in electrification and have otherwise apportioned the energy
demands according to the previously listed assumptions (for Model I). The
results are shown in Table 4-8 and Figure 4-2.
In contrast to Model I, no potential energy surpluses exist in anytime
period; in fact, all sectors require sizable imports of oil and gas if demand
projections are to be met. Accordin'g to the assumptions of the model, in-
cluding that of a high energy demand from increased electrification and fuel
synthesis, the energy demand and supply has been projected for the various
consuming sectors: residential and commercial, high priority; industrial,
moderate priority; other, moderate priority; and transportation, low
priority. A separate composite listing of the fuels used to generate electricity
has also been made; refer to Tables 4-9 through 4-13.
Model II, like Model I, is not intended for use as a schedule for energy
allocation. The mismatches between supply and demand for energy are the
result of the assumptions and priorities made to establish the model; however,
the fuel deficits are quantitative, which is the objective of the model. The
65
-------
5
o
gj
450
420
390
360
330
300
270
240
210
180
150
120
90
60
30
ACTUAL
CONSUMPTION
I
MODEL H
SUPPLY
I
I
MODEL
DEMAND'
MODEL I .
DEMAND""^ '
/
MODEL I /
/
/
/
/
/
I
I
I960 1965 1970 1975 I960 1985 1990 1995 2000 2005 2010 2015 2020
YEAR
Figure 4-1. COMPARISON OF MODELS I AND II ENERGY
DEMAND AND SUPPLY PROJECTIONS
A-74-1232
-------
Table 4-8. MODEL II PROJECTED ENERGY DEMANDS
Total Energy Demand
Less Projected Nuclear, Geothermal,
and Hydropower Supplies
Probable Demand of Market Segments
to be Met by Fossil Fuels (Supplies
Included)
Transportation
Residential and Commercial
Industrial
Electrical
Other
Imported Supplies Included in Probable
Demand
Oil
Gas
Domestic Supplies Included in Probable
Demand (Oil, Gas, and Coal)
1971
68.7
3.4
65.3
16.6
13. 7
17.7
13.3
4. 0
65.3
7.6
0.8
8.4
1975
82.
6.
76.
19.
16.
20.
16.
4.
76.
16.
1.
17.
9
5
4
1
0
8
2
3
4
2
3
5
1980
101.
12.
88.
22.
18.
24.
18.
5.
88.
23.
2.
26.
1
8
3
4
5
1
3
0
3
3
8
1
1985
i n15
1 U
125.
24.
100.
25.
20.
27.
21.
5.
100.
30.
4.
34.
Bti:
2
6
6
4
9
3
3
7
6
1
0
1
1990
i
153.
32.
121.
30.
24.
32.
27.
6.
121.
35.
5.
41.
4
2
2
2
8
3
1
8
2
8
4
2
2000
228.
57.
170.
41.
34.
44.
41.
9.
170.
51.
8.
59.
2
6
6
3
0
2
9
2
6
1
3
4
2020
500. 5
228.4
272. 1
66.2 :
54.4
70. 8
66.0
14. 7
272. 1
115. 0
21.0
136.0
56.9
59. 9
62.2
66.5
80. 0
111.2
136.1
-------
II OTHER
-rr^ ELECTRICAL
GENERATION
" VYJ INDUSTRIAL
RESIDENTIAL/
COMMERCIAL
Illlllllllli TRANSPORTATION
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020
YEAR
Figure 4-2. MODEL II ENERGY DEMAND BY MARKET SEGMENT
(All Nuclear to Electricity Generation)
A-74-1233
68
-------
Table 4-9- MODEL II RESIDENTIAL AND COMMERCIAL
ENERGY SUPPLY AND DEMAND
1971 1975 1980 1985 1990 2000 2020
Total Demand
Supply
Oil (2 1 % of Supply)
Imported
Domestic
Total Oil
Gas (31. 1% of Supply)
Imported
Domestic
Total Gas
Coal (2.3% of Supply)
Domestic
Total (Excluding
Electricity)
Table 4-10.
13. 7
1.6
4. 8
6.4
0.2
6.9
7. 1
0.3
13. 8
16.0
3.4
4. 5
7.9
0. 4
6.6
7. 0
0.2
15. 1
18.
5.
5.
10.
0.
5.
6.
0
17.
5
1
1
2
9
9
8
0
1015 B'
20.9
6.7
5. 0
11. 7
1.2
5.4
6.8
0
18.5
tu
24.
8.
5.
13.
1.
5.
7.
0
20.
8
4
3
7
7
4
1
8
34.
12.
5.
17.
2.
5.
7.
0
25.
0
3
1
4
6
3
9
3
54.
20.
5.
25.
4.
6.
10.
0
35.
4
0
0
0
0
0
0
0
MODEL II INDUSTRIAL ENERGY
SUPPLY AND DEMAND .
Total Demand
Supply
Oil (17. 5% of Supply)
Imported
Domestic
Total Oil
Gas (35.5% of Supply)
Imported
Domestic
Total Gas
Coal (35. 7% of Supply)
Domestic
1971
17. 7
1.3
4. 0
5.3
0.3
7.8
8.1
4.3
1975
20. 8
2. 8
3.8
6.6
0. 5
7.5
8.0
5. 7
1980
24..
4.
4.
8.
1.
6.
7.
6.
1
2
2
4
0
8
8
9
1985
1015 Bt
27.3
5.5
4.2
9.7
1.4
6.4
7.8
8. 7
1990
u
32.
6.
4.
11.
1.
6.
8.
12.
3
9
4
3
9
2
1
0
2000
44.
10.
4-.
14.
2.
6.
9.
20.
2
3
2
5
9
1
0
5
2020
70.
16.
4.
20.
4.
6.
10.
35.
8
0
0
0
0
0
0
0
Total (Excluding
Electricity) 17.7 20.3 23.1 26.2 31.4 44.0 65.0
69
-------
Table 4-11. MODEL II OTHER USES ENERGY
SUPPLY AND DEMAND
1971 1975 1980 1985 1990 2000 2020
: 1015 Btu >
Total Demand 3.7 4,3 5.0 5.7 6.8 9.2 14.7
Supply
Oil(0. 6% of Supply)
Imported Negl 0.1 0.15 0.2 0.2 0.3 0.3
Domestic 0.2 0.1 0.15 0.1 0.2 0.2 0.2
Total Oil 0.2 0.2 0.3 0.3 0.4 0.5 0.5
Gas (15. 8% of Supply)
Imported 0.1 0.2 0.5 0.6 0.8 1.3 1.2
Domestic 3.5 3.4 2.8 2.7 2.8 2.7 2.4
Total Gas ~T~5 ~~37~6~ 3.3 3.3 3.6 4.0 3. 6
Coal (0. 0% of Supply) 0 0 0 0 0 0 0
Total (Excluding
Electricity) 3.8 3.8 3.6 3.6 4.0 4.5 4.1
Table 4-12. MODEL II TRANSPORTATION
SUPPLY AND DEMAND
1971 1975 1980 1985 1990 2000 2020
1015 Btu-
Total Demand 16.6 19.1 22.4 25.4 30.2 41.3 66.2
Supply
Oil (54. 7% of Supply)
Imported 4.1 8.9 13.2 17.4 21.9 32.3 54.0
Domestic 12. 5 11. 8 13.2 13.2 13. 8 13. 3 13. 0
Total Oil 16.6 20.7 26.4 3075" 35.7 4576" 67.0
Gas (Negligible % of Supply)
Imported
Domestic
Total Gas Negl Negl Negl Negl Negl Negl Negl
Coal (0. 1% of Supply)
Domestic Negl Negl Negl Negl Negl Negl Negl
Total (Excluding
Electricity) 16.6 20.7 26.4 30.6 35.7 45.6 67.0
70
-------
Table 4-13. MODEL II ELECTRICITY CONVERSION
ENERGY UTILIZATION
1971 1975 1980 1985 1990 2000 2020
, 10is Btu __ ._
Nuclear 0.5 3.5 9.3 20.6 27.7 52.1 218.4
Hydro and Geothermal 2.9 3.0 3.5 4.0 4.5 5.5 10.0
Oil Consumption 1.8 2.3 2.3 2.3 2.3 2.3 2.0
Gas Consumption 4. 0 4. 0 4. 0 4. 0 4. 0 4. 0 4. 0
Coal Consumption 7. 5 9. 9 12. 0 15. 0 20. 8 35. 6 60. 0
Total 16.7 22.7 31.1 45.9 59.3 99.5294.4
Electricity Produced 5.8 7.9 10.9 16.1 20.8 34.8 103.0
models also serve to inform the reader about the quantities of energy con-
sumed in various markets, and the magnitude of the quantities involved in
meeting the needs of the U. S.
Under Model II conditions, even with imports, the residential, com-
mercial, and industrial demands are not met, but a sizable importation of
oil and gas would allow the transportation demands to be met. At the same
time, there is extensive utilization primarily of coal and nuclear heat
for the generation of electricity (or the production of a synthetic fuel), as
shown in Table 4-13. Sector shortfalls without imports are shown in
Table 4-14 for the various market sectors, excluding transportation.
Table 4-14. MODEL II SHORTFALLS (With No Imports)
BY SECTOR IN ELECTRICITY SUPPLY
1975 1980 1985 1990 2000 2020
1015 Btu
Transportation Shortfall 7.3 9.2 12.2 16.4 28.0 53.2
Residential/Commercial 4.7 7.5 10.3 14.1 23.6 43.4
Industrial 3.8 6.2 8.2 9.7 13.4 25.8
Other 0. 8 1.9 2. 7 3. 8 6.3 12. 0
Total Deficits
(Less Transportation) 9.3 15.6 21.0 27.6 43.4 81.2
Electricity (or Synthetic
Fuel Available) 7.9 10.9 16.1 20.8 34.8 103.0
Electricity (or Synthetic
Fuel) Available for
Transportation Nil Nil Nil Nil Nil 21.8
7 1
-------
As shown in Table 4-14, the available supply of electricity would be consumed
in its entirety, and the U. S. would not be energy independent because serious
shortfalls would still exist.
Some electricity would be available to reduce importation of energy for
transportation in 2020, when a potential surplus from the other market seg-
ments would be available. If the priorities established for the model were
changed, the energy necessary for conversion (or the fuel supply for electricity
generation) could be diverted to transportation. Asa result, the transportation
segment alone could become energy independent. For example, if the indus-
trial sector is forced to import more fuel (lower its priority) to meet its
energy supply deficit, some of the fuels for generating electricity would be
available for transportation. The release of coal, otherwise committed to
the generation of electricity, for chemical fuel synthesis would enhance the
energy supply situation appreciably because a significant part of the waste
heat produced in the conversion of energy to electricity would no longer be
wasted. On the other hand, at least this much energy is wasted in the use
of a thermal (combustion) engine versus electricity in a motor-powered auto-
mobile. Model II indicates that a) energy supplies must be imported at least
until 2020, b) a way must be found to utilize coal or nuclear heat in a more
efficient manner (e. g. , to synthesize chemical fuels, rather than to generate
electricity), or c) a condition of unsatisfied demand in one or more market
sectors must be tolerated.
In summary, under the conditions and assumptions of Model II, the U.S.
cannot achieve energy independence prior to 2020. This situation is in direct
contrast to the one described in Model I. In Model II, the overall demand for
energy in the U. S. is expected to increase at an annual rate of 4. 4% , 1971-85;
4. 1%, 1985-2000; and 4. 0% , 2000-2020. Supplies of energy from domestic
sources are expected to increase at an annual rate of 2. 9% from 1971 to 1985,
3. 9% from 1985 to 2000, and 4. 0% from 2000 to 2020. Not until the period
2000-2020 will the annual rate of growth in the amount of domestic energy
supplied match the annual rate of growth for demand. We should point out
that nuclear, geothermal, and hydropower energy account for about 36% of
the total domestic supply in 2000 and about 65% in 2020. These energy forms,
under present technology, cannot be used for applications other than the
generation of electricity.
72
-------
4. 3 Automotive Sector
In this section, particular emphasis is placed on determining the quantity
of energy required to satisfy the demand within the transportation sector. The
assumptions in Models I and II are carried over into this discussion arid are
supplemented by data from studies prepared by the Department of the Interior
and DOT. 1 Only a portion of the transportation sector is of concern here,
i.e., automobiles, trucks, and buses. The energy requirements of the re-
mainder of the sector aircraft, ships, and trains are beyond the scope
of this study.
The DOT publication reported transportation energy consumption in terms
of energy source and mode of operation. Its findings are summarized in
Table 4-15, which shows that auto, truck, and bus modes of operation con-
sumed almost 75% of the energy total for the sector.
Table 4-15. DISTRIBUTION OF ENERGY CONSUMPTION
IN TRANSPORTATION BY MODE IN 1969 (Source: Ref. l)
Mode
Automobile
Truck
Bus
Subtotal
Railroad
Pipeline
Airline
Water
Total
Intercity freight
Urban freight
Service and utility
Intercity
Urban and school
Intercity passenger
Freight
Subway
Freight
Passenger
Freight
Passenger
Freight
Energy Source
Oil
Oil
Oil
Oil
Oil
Oil
Oil and wayside electric
Oil
Wayside electric
Oil and gas, mostly
Oil
Oil
Oil
Oil
Percent
51.2
9.1
5.1
8.2
0.2
. 0.5
74.3
0. 1
3.6
0.1
2.0
11.4
2. 6
0.2
5.8
100. 1
Overall transportation consumption: 15 X 1015 Btu/yr.
73
-------
The following conclusions, which were presented in the DOT study, are in
agreement with the projections for Models I and II
Transportation consumes about 25% of total U.S. domestic energy
supply and is expected to do so at the same rate in the foreseeable
future.
Transportation is a major user of petroleum. Fifty-five percent of
the petroleum consumed in the U. S. is used by transportation. This
fraction is projected to increase to 60% in the mid-1980's.
Transportation is intensively dependent on petroleum; more than
98% of the transportation energy consumed is from a petroleum-
based energy source.
The Department of the Interior also has projected energy demand for the
U. S. including consumption within the transportation sector. This study is
in close agreement with the DOT1 and NPC4 studies in that during the period
ending in 1985, transportation is expected to account for about 23% of the
total U. S. consumption. The assumptions used by the Department of the
Interior are as follows:
Population of the U. S. will increase at an annual rate of about 1% .
Industrial production is expected to increase 5% on an annual basis
up to 1980, after which the growth rate will decline to 4. 4% to 1985.
All fuel supply limitations are taken into consideration,resulting in
a forecast of consumption, rather than a forecast of unrestrained
demand.
Energy prices are expected to rise faster than prices for other
commodities.
The NPC has found that changes in automotive fuel consumption, for the
period ending in 1985, correlate very closely with real GNP in spite
of changes in demographic factors, driving habits, types of vehicles, fuel
quality, highway conditions, and alternative forms of transportation. This
finding led to the following conclusions by the NPC for the near-term future:
The consumer regards most automobile mileage as fairly essential,
although he may change the type of car he drives.
The cost of oil and gasoline is only about one-fourth of the total
cost of operating a private automobile.
In the case of commercial transportation, such as trucks, railroads,
and airlines, fuel requirements are an essential element of the business
and are not expected to change only on the basis of cost.
74
-------
The three transportation forecasts are presented for comparison in
Table 4-16, which shows that the estimates are within 10% of each other,
which is quite respectable considering the length of the time period. For
purposes of this study, the trends shown in Table 4-16 are assumed to
continue to .2020.
Table 4-16. COMPARISON OF DOT, DEPARTMENT OF THE INTERIOR,
AND NPC ENERGY DEMAND FORECASTS
Base Years Forecast Years
1969 1970 1971 1975 1977 1980 1985
Btu
Total U. S. Energy as
Demand Projected by
NPC* -- 67.8 -- 80.5 -- 95.7 112.5
DOT1" 59.6 -- -- -- 86.2 -- 119.9
Department of the
Interior -- -- 69-0 80.3 -- 96.0 116.6
Transportation Sector
Demand
NPC -- 16.3 -- 19.3 -- 23.0 26.7
DOT 14.9 -- -- -- 21.5 -- 30.0
Department of the
Interior -- -- 17.0 19.1 -- 22.8 27.1
Model I.
Inferred from report assumption, i.e., transportation consumption
equivalent to 25> of total demand.
4. 3. 1 Model for Automotive Sector
The following conclusions, which relate specifically to energy consumption
by the modes of transportation with which we are concerned, are from NPC
data:
Although fuel cost is not the major item in the total cost of owning
and operating a car, it is an out-of-pocket and highly visible cost.
Therefore, it is likely to carry a disproportionate weight in con-
sumer decisions.
75
-------
The higher cost of motor fuel is one of a package of economic
inducements that would cause consumers to purchase "economy"
cars.
In commercial transportation, the cost of fuel is important enough
to play a significant role in an operator's decision on the type of
new equipment purchased and the timing of the purchase.
In 1970, the ratio of standard cars to economy cars was estimated
to be 86:14; by 1985, the same ratio is expected to be 50:50. The
change in the ratio is due to increased fuel prices, which, in turn,
induce the purchase of smaller vehicles.
All these assumptions and conclusions are incorporated into the total
demand of the transportation sector. In Table 4-17, the automotive (auto,
truck, bus) portion of the total sector demand has been segregated, and as
shown, 55% of the projected domestic supplies of conventional petroleum,
as well as oil shale and coal liquefaction products, will not be adequate to
support automotive requirements.
As stated previously, the condition of over supply attributed to Model I
is in the form of coal and nuclear energy that cannot be used in conventional
form as fuel for automobiles. Clearly, there is a need for an alternative
fuel, synthesized from some resource other than crude oil, or the importation
of petroleum products must continue during the time frame of this study,
if transportation needs are to be satisfied.
Table 4-17. MODEL I TRANSPORTATION ENERGY
SUPPLY AND DEMAND AND AUTOMOTIVE DEFICIT
1970 1975 19«0 1985 2000 2020
: 1015 Btu
Total Sector Demand 16.3 19.4 23.0 26.7 40.4 70.1
#
Automotive Demand
(75% of Total) 12.2 14.5 17.2 20.0 30.3 52.6
Supply
Oil (54. 7% of Total
Domestic Supply) 11.5 13.0 15.4 19.0 26.2 27.7
Automotive Deficit 0.7 1.5 1.8 1.0 4.1 24.9
Automobiles, trucks, and buses; the remaining demand is attributable
to aircraft, ships, and trains.
76
-------
4. 3. 2 Model n for Automotive Sector
The energy demand and supply projections from Model II also can be
used for determining the automotive needs within the transportation sector.
In contrast to Model I, Model II represents a situation in which a permenent
imbalance exists between the supply and demand for energy. Imports of
energy, in the form of petroleum and natural gas, are expected to occur
throughout the time period of this study, whereas Model I showed a potential
surplus of energy supply in the form of coal and nuclear power commencing
by about 1985.
The same assumptions and conclusions for Model I that pertain to the
characteristics of the automotive segment of the transportation sector are
carried over into this assessment of Model II energy demand and supply
conditions. In Model II, a greater rate of increase in the overall demand
for energy is accompanied by somewhat lower levels of domestic supply
capability. As in the case of Model I, Model II transportation energy supply
is the lowest in terms of priority ranking. The demand and supply of energy
in the transportation sector are shown in Table 4-18; total transportation
demand for energy does not differ significantly from the demand shown for
Model I. However, the deficit quantity (based on 55% of domestic petroleum)
is much greater in Model II,. resulting in a need for more alternative sources
of energy at an earlier time.
Table 4-18. MODEL II TRANSPORTATION ENERGY SUPPLY AND
DEMAND AND AUTOMOTIVE DEFICIT
1971 1975 1980 1985 1990 2000 2020
1015 Btu
Total Sector Demand 16.6 19.1 22.4 25.4 30.2 41.3 66.2
4f.
Automotive Demand
(75% of Total) 12.4 j 14.3 16.8 19.1 22.6 30.9 49.6
Supply
Oil (54. 7% of Total
Domestic Supply 12.5 11.8 13.2 13.2 13.8 13.3 13.0
Automotive Deficit From
Domestic Supply -- 2.5 3.6 5.9 8.8 17.6 36.6
£.
Automobiles, trucks, buses; the remaining demand quantity is attributable
to aircraft, ships, and trains.
77
-------
Essentially the same conclusions can be reached in the application of
Models I or II; i.e. , an alternative fuel must be developed for use in auto-
mobiles if this energy-consuming segment is to achieve independence from
imported sources.
4.4 Model III
The projection of energy supply and demand in the U. S. at present is a
particularly difficult task because of the uncertainty of national energy policy
and the future availability of energy from conventional sources. A number
of excellent studies have been published by authoritative sources, and we
have used some of these as bases for Models I and II.
The 1973/74 Arab embargo of oil exports to the U. S. , the unprecedented
and unanticipated increases in energy costs, and the recent allocation and
conservation measures undertaken by the Government and by fuel users of all
kinds illustrate that even the most recent energy projections can quickly
become obsolete. That oil embargo reduced the projected energy
supply in the U.S. for 1974 by approximately 4%, so energy demand was
curtailed by a corresponding amount. The resulting curtailment and
conversion measures undoubtedly will have a far-reaching effect on the
U. 5- energy economy for many years to come.
As a result, we decided to modify available energy demand projections
to determine, to some degree, the effects of these curtailment and conser-
vation measures on transportation energy consumption and the attendant need
for an alternative automotive fuel. Although Model III is not used as a basis
for alternative fuel selection in the remainder of this study, its introduction
does convey the possibility of a set of conditions occurring in which an al-
ternative fuel is not required until at least after 1990 (in contrast to Models I
and II).
Efforts were concentrated on the automobile segment of the transportation
market sector. Time and budget limitations did not permit expanding Model III
to the individual sectors of the economy, and the time period considered ex-
tends only to 1990. Model III demand projections are compared with Models I
and II in Table 4-19.
78
-------
Table 4-19- U.S. GROSS ENERGY DEMAND ACCORDING TO
MODELS I, II, AND III
Model I Model II - Model III
Year 1015 Btu
1975 80.3 82.9 80.3
1980 95.7 101.5 91.5
1985 112.5 125.2 105.9
1990 -- 153.4 122.8
2000 170.3 228.2
2020 295. 7 . 500.5
The automobile plays a very important role in the U.S. economy. Approxi-
mately 130 million motor vehicles are currently in operation in the U. S. ;
of these, about 95 million are automobiles. By age classification, approxi-
mately 60% are less than 5 years old, and less than 15% are more than 9
years old. During the last 5 years, between 8 and 9 million automobiles
were domestically manufactured each year. Approximately 7 million are
produced for the replacement market, and the remainder are additions to
the overall automobile population. An average late-model, full-size auto-
mobile is driven 10,000 miles per year and consumes about 833 gallons
of gasoline on a yearly basis. Further, an estimated 80% of the families
in the U.S. own at least one automobile, whereas 30% own two or more.
For the majority of these persons, the automobile is the means of trans-
portation for getting to and from places of employment. Rapid-transit systems
provide service only to and within a few of the largest metropolitan areas. In
many instances, they are not completely adequate. Bus systems provide
transportation within medium-size cities, but a commuter service is a rarity.
Today, as much as 41% of the gasoline consumed in privately owned auto-
mobiles is for travel to and from work. As stated previously, a significant
increase in the number of cars per household has taken place because about
40% of the households in the U. S. have two or more wage earners.
The population growth in suburban areas and in outlying rural areas also
has greatly increased the dependence upon the automobile to satisfy the
essential family needs. Heavy reliance is placed upon the automobile for
transportation to doctors, shopping, school transportation, and church. Auto-
mobile utilization to satisfy essential needs is almost as extensive as trans-
portation to and from work. This would indicate that about 80% of the gasoline
consumed in privately owned automobiles is for essential purposes.
79
-------
During the 1960's, the general purchasing pattern was toward larger
automobiles with larger engines and more accessory equipment, resulting
in fewer miles traveled per gallon of gasoline. Essentially, vehicle mileage
is a function of vehicle weight. Over the last year, the unit consumption
rate, i. e. , miles/gal of gasoline, dropped approximately 11% from 13. 7 to
12. 2 miles/gal.
The Clean Air Act of 1970 dictated that automobile emissions must be
reduced. At the time, there was no known technology capable of reducing
emissions to the desired level as long as gasoline contained lead additives.
The Government, in its desire to reduce automotive emissions, decided
the most appropriate action would be to make lead-free (or very low lead)
gasoline available from U.S. refineries. After the lead had been removed,
present technology could be used to reach the desired level of automobile
emissions. The equipment installed in cars for reducing emissions has been
a factor in the recent increase in fuel consumption.
Increased fuel prices also are expected to alter automobile fuel consumption
patterns. Doubling the price of gasoline is equivalent to about 4% of the total
income for the average U. S. household. Implicit in this conclusion is the
premise that driving habits will not change. In the very short run, 2-4 years,
this premise is reasonably accurate because, as previously stated, approxi-
mately 80% of the driving done by the average American is essential to sus-
tain the current standard of living. In the longer term, doubling the price of
gasoline will affect demand. In purchasing replacement vehicles, more
attention is expected to be placed on vehicles that use less gasoline per mile .
driven. Such cars are currently available, and they are beginning to become
popular.
Currently, the EPA is evaluating the consequences of introducing Federal
legislation that will require automobile manufacturers to produce cars with
improved fuel economy. The legislation would require that each year in the
next decade, all new-vehicle gasoline consumption rates be improved from
6 to 8%/yr. If such action were taken within the next 2 years, total gasoline
consumption in 1990 is estimated at about 1 million bbl/day less than current
demand. To some extent, this increased mileage trend will occur by customer
preference, because of higher fuel costs. By 1990, daily consumption could
be in the range of 5.25-6. 75 million bbl. Figure 4-4 reflects this projection
80
-------
of gasoline demand, along with several scenarios that could shift the fore-
cast quantity.
4. 4. 1 Case A
For this case and all others, a constant annual production of 10 million
new automobiles was assumed, (imports were not considered because, on
the average, they exceed the minimum fuel consumption quantities considered
herein. ) In this case, the automobile population is assumed to increase by
1 million units per year through 1990. Although this growth is only 60% of
the present rate, evaluation of the population age profile and changes in
social patterns indicate that this rate has a high probability of occurrence.
Implicit with this growth rate is a replacement rate of 9 million units per
years, based on a current automobile population of 130 million.
Further, all new vehicles are assumed to achieve an average of 17 miles/
gal of g'asoline, in contrast to the current average of about 12 miles/gal. All
other driving habits will remain the same.
Under these prescribed conditions, the total gasoline consumption in
1990 would be 5. 75 million bbl/day.
4. 4. 2 Case B
The only difference between Cases A and B is that the automobile popu-
lation growth in Case B continues at a rate of 2 million/yr, instead of the
1 million increase assumed .for Case A. For this condition, the total gaso-
line cnnanmptlon in 1990 would bo 6. 75 million bbl/day, which, represents an
upper bound for Model III.
4. 4. 3 Case C .
This case assumes the introduction of a diesel automobile capable of
achieving 25 miles/gal in 1981. (Automobiles of this type are currently
available.) During the first 3 years, production of these automobiles is
assumed to be 2 million units per year, with 6 million produced per year
in 1984. These new diesel-powered vehicles will replace some of the lower
mileage automobiles. Maximum new car production is maintained at
10 million new units per year. For this case, total gasoline and diesel fuel
coiistimption in 1990 would be 5. 25 million bbl/day.
81
-------
10
oo
ro
7-'
U.S. REFINERY CAPACITY,,^*
PRESENT AND PLANNED
GASOLINE DEMAND
PRODUCT IMPORTS
^ UMC5C. D
TOTAL REFINERY
GASOLINE OUTPUT,
FOREIGN AND
DOMESTIC CRUDE
CASE C
REFINERY GASOLINE
OUTPUT, DOMESTIC
CRUDE
I I
I I
I I II
I I
I960 '62 '64 '66 '68 '70 *72 '74 '76 '78 '80 '82 '84 '86 '88 1990
YEAR
Figure 4-3. U.S. REFINERY GASOLINE CAPACITY
A-74-1234
-------
The shaded area in Figure 4-3 is the estimated decrease in gasoline
availability brought about by the recent Arab oil embargo against the U. S.
The impact of the embargo has not been fully quantified; nevertheless, it
has placed severe restraints on the amount of gasoline temporarily available
to satisfy demand.
Figure 4-3 also reflects new refinery expansion planned through 1977.
(This is in terms of gasoline production, which, historically has been about
48% of total refinery capacity. ) If the projected demand schedule for gaso-
line is valid, an eventual incremental gasoline-refinery capacity of 1. 6
million bbl/day would be available for the production of other products. The
most likely candidate for this additional capacity would be distillate fuels.
In summary, the most probable gasoline demand in 1990 according to
Model III will be about 6 million bbl/day (essentially Case A, allowing for
some degree of slippage in the production of smaller vehicles), in contrast
with the 1974 demand estimate of 7. 5 million bbl/day.
4. 5 References Cited
1. Department of Transportation, Research and Development Opportunities
for Improved Transportation Energy Usage, Report of the Transportation
Energy Panel DOT-TSC-OST-73-14. Springfield, Va. , September 1972.
2. Linden, H. R. , "The Role of SNG in the U. S. Energy Balance. " Special
Report for the Gas Supply Committee of the American Gas Association,
Arlington, Va. , May 15, 1973.
3. Linden, H. R. , "A Program for Maximizing U.S. Energy Self-Sufficiency, "
March 15, 1974.
4. National Petroleum Council, U. S. Energy Outlook: A Report of the
National Petroleum Council's Committee on U. S. Energy Outlook.
Washington, D. C. , December 1972.
83
-------
5. FUEL SYNTHESIS TECHNOLOGY
The resource base assessment (Section 3) and the energy demand and
supply Model I (Section 4) indicate that the domestic energy sources useful*
for automotive fuel production are coal, oil shale, nuclear energy (fission),
and possibly solar energy and waste materials (followed by biomass con-
version). These choices are partially evident from Table 3-2. Justifica-
tion of these energy resource choices is presented in Section 10. Other
energy sources are inadequate because 1) they do not exceed the 25-year,
15% transportation demand requirement of about 108 quadrillion Btu (as
fuel) and the annual requirement of 3-6 quadrillion Btu (as fuel), or
2) the energy production technology constitutes a moderate or severe
technology gap (breeder fission and nuclear fusion). However, other
energy sources (winds, tide, geothermal heat, etc. ) deserve development
as contributors to the overall U.S. energy supply, because local or lim-
ited use of these unconventional sources may .result indirectly in more
(conventional) fuel being available for transportation.
5. 1 Fuel Synthesis From Coal
Considerable effort is being directed toward developing processes that
convert coal to clean fuels gaseous, liquid, or solid. As shown in
Figure 5-1, gasification of coal occurs via two routes. The first route
produces clean gas of either medium heating value (250-550 Btu/CF) or
high heating valxie (950-1000 Btu/CF). The latter is a supplement to
pipeline-quality natural gas (SNG). The second route to clean gas pro-
duces only low-heating-value (100-250 Btu/CF) gas, because the gas
contains considerable nitrogen. The nitrogen is introduced when air is
used to furnish the heat required for the gasification reactions.
Clean liquids or clean solids are produced from coal~ by three principal
routes. In the first route, clean gas containing appropriate proportions
of carbon monoxide and hydrogen (synthesis gas) is converted by the
Fischer-Tropsch Process to hydrocarbon oil. The second route involves
heating the coal to drive out the naturally occurring oils (pyrolysis) and
*
"Useful" means a potential supply sufficient to exceed about 15% of
the annual transportation demand.
85
-------
LOW-Btu
CO, H2, CH4,
N2, C02, H2S
GAS
MEDIUM-Btu
CO, H2, CH4,
C02, H2S
HYDROGEN
SULFIDE
CLEAN FUEL GAS
LOW-Btu (100-250)
CLEAN FUEL GAS
MEDIUM-Btu (250-550)
IMETHANATION ^ CLEAN I
1 ~~ HIGH-Bti
FUEL GAS
u (950-1000)
HYDROTREATING
HYDROGEN
FILTRATION AND | SYNCRUDE
SOLVENT REMOVAL ,
ASH
PYRITIC SULFUR
CLEAN LIQUID
FUEL
CLEAN LIQUID
FUEL
CLEAN LIQUID
FUEL
CLEAN SOLID
FUEL
Figure 5-1. PRODUCTION OF CLEAN FUELS FROM COAL
A-74-1337
86
-------
then treating these oils with hydrogen for desulfurization and quality
improvement. Pyrolysis processes produce significant quantities of by-
product gas and char, which must be disposed of economically. The
third route to clean liquid fuel involves dissolving the coal in a solvent
and filtering out ashes, which include pyritic sulfur. After the solvent
has been removed, the resulting heavy crude oil (syncrude) is treated
with hydrogen (hydrotreating) to remove organic sulfur and, at the same
time, to improve its quality. In one process, a solid fuel (SRC) is
produced if the syncrude is allowed to cool before hydrotreatment.
Many processes produce synthesis gas, SNG, or liquid fuels from coal.
Some processes are in commercial production, some are on a pilot-plant
scale, and some are in the development stage. Tables 5-1 through 5-3
list processes for making SNG, liquid fuels, and synthesis gas from coal,
respectively. The energy and/or material input, synthesized product, by-
products, potential pollutants, and a description of each process are
included.
Methanol can be considered a desirable fuel for automotive transporta-
tion. The processes for producing methanol from coal, SNG, naphtha,
and heavy fuel oil are presented in Table 5-4. Ammonia has been con-
sidered as an automotive fuel for modern armies because it can be
catalytically synthesized from nitrogen obtained from air and from hy-
drogen obtained from the electrolysis of water. Table 5-5 presents the
processes for producing ammonia from coal, naphtha, SNG, and heavy
oil. Hydrogen also has been tested as an alternative automotive fuel on
a hydrogen car. The processes for producing hydrogen from coal (or oil
shale) SNG, naphtha, and electrical energy are presented in Table 5-6.
Coal is considered a "dirty" fuel, principally because of its sulfur content.
When coal is processed to produce desirable fuels, the sulfur goes into
the liquid, gaseous, and solid material streams. The proportion of sulfur
and other pollutants in the liquid products, gaseous products, and char depend
on the process design, operating conditions, and methods of contacting solids
arid gases (cocurrent, countercurrent, entrained bed), etc. For example,
87
-------
Table 5-1. PROCESSES FOR PRODUCING SNG (Methane) FROM COAL
oo
00
Energy/Material
Resources
355-390 billion
Btu coal
4700-6500 tons
02
19,200-28,800
tons steam at
500 psi
21, 600-36, 000
tons /hr feed
wate r
60 MW power*
Name of
Process
Comment on the Process
Synthesized
Fuel
Comments on Pollution
Lurgi Process1"
Lock hoppers feed crushed 250 billion Btu
coal to a moving-bed gasi-
fier. A revolving grate
feeds in O2 and steam while
removing ash. Ope r.pres-
sure is up to 450 psi. Exit
gas temperature is between
700° and 1100'F. This pro-
cess produced 970 Btu/SCF
gas. Limited to noncaking
coals.^inci. both electric
and steam drives)
17, 092 tons coal HYGAS Process*5 Dried coal is slurried with
(12, 401 Btu/lb) (with electro- light oil and fed to a 2-
as a feed and fuel thermal gasifier) stage fluiciized-bed hydro-
(also 347, 217 kW gasifier operating at 1000-
power included . - 1 500 psia. An electro-
in it) thermal gasifier, oxygasi-
fier, or a steam-iron pro-
cess, using char from the
2nd stage of the HYGAS
unit, produces hydrogen-
rich gas *-0ich is supplied
for gasification. Exit gas
temperature is 600°F.
16,237 tons coal HYGAS Process
(12, 401 Btu/lb) (with oxygen
as a feed and gasifier)
fuel (also 2930
tons O2 included
in it)
20,381 tons coal HYGAS Process
(12,401 Btu/ib) (with steam-iron)
as a feed and
fuel (also incl.
manufacture of
Hz) ' '
253 billion Btu
or
262. 5 million
SCF
247 billion Btu
or
256. 4 million
SCF
253 billion Btu
or
261. 4 million
SCF
By-Product -
15,600 tons high- Relatively low off-gas temperature and
pressure steam countercurrent design increase appear-
960-1680 tons of ance of tars, NH3, etc., in waste quench
tar-oil-naphtha liquor.
72-144 tons
phenols
85, 104 gal oil
52,452 gal C
81 tons NH3
76,470 gal oil
46, 339 gal C6H6
72. 4 tons NH3
103, 152 gal oil
63,910 gal C6Hfc
99 tons NH3
For the pretreatment of caking coals,
sulfur existing in the pretreatment off-gas
must be removed.
B-94-1724
-------
Table 5-1, Cont. PROCESSES FOR PRODUCING SNG (Methane) FROM COAL
00
NO
Ene rgy Aviate rial
Resources
Name of
Process
12,000 tons coal Bi-Gasi5
to gasifier (13, 000
Btu/lb); 2400 tons
coal (steam and
O2 production);
16 million gal
water
13,200 tons coal Molten Salt"
(13,990 Btu/lb);
226. 8 tons Na2COj
(makeup)
1. 36 billion SCF
air; 31. 104 million
gal cooling water
(makeup); 3.785
million gal BFW
14,220 tons coal Synthane1
(12,700 Btu/lb);
36. 9 5 million Ib
h-p steam (includes
production of 2770
million SCF O2);
374. 5 million gal
cooling water;25.92
million gal pro-
cess water.
29,850 tons coal CO2 Acceptor5
(including fuel re-
quirements^ 7068
Btu/lb); 2250 tons
makeup dolomite;
1.011 billion SCF
air; 2.955 million
gal BFW; 159.5 mil-
lion gal cooling
water.
Comment on the Process
Coal is gasified withhydrogen.
The resulting char (with Oz
and steam) produces the
hydrogen-rich gas to sustain
the hydrogasification process.
The operating pressure is
1000 psia. Exit gas tempera-
ture is 1700°F. This pro-
cess produces 950+Btu/SCF
gas. Uses all U. S. coal.
O2, steam, and coal are in-
jected into a reactor and
molten Na2CO3 catalizes gas-
ification, Gasifier is oper-
ated at 400 psig and 1900°F.
This process produces 900+
Btu/SCF gas. Uses all U. S.
coal.
Coal is introduced into a
single reactor which incor-
porates 3 processing steps;
a free-fail O2 steam pretreat-
ment zone a dense fluid-
bed carbonizer, and a dilute
fluid-bed gasifier. H2-rich
gas is produced by use of O2
in the reactor. The process
operates at 500 to 1000 psia.
This process produces 900+
Btu/SCF gas. Uses all U.S.
coal.
Coal is charged to a devola-
tilizer and is contacted at
300 psia with H2-rich gas
from a gasifier vessel. Lime
or dolomite (the Acceptor) is
added to both vessels where
it reacts with CO2. This pro-
cess produces 950+Btu/SCF
gas. Uses lignite and sub-
bituminous coal
Synthesized
Fuel
By-
Product
Comments on Pollution
250 million
SCF pipeline
gas (HHV
(950 Btu/SCF)
Slagging gasifiers at high temperature
minimize sulfur content of the ash. High
off-gas temperatures should reduce tars,
amines, phenols, etc. , in the quench
liquor.
250 million
SCF pipeline
gas
(914 Btu/SCF)
250 million
SCF pipeline
gas (HHV
927. 1 Btu/SCF)
The sulfur is recovered during regenera-
tion of molten salt.
tar 501.6 tons Nature of pretreatment does not produce
NH3 38.32 tons a separate, sulfur-laden stream.
262.6 million
SCF/day pipe-
line gas(HHV
953 Btu/SCF)
Sulfur treatment of the regenerator off-
gas is required.
B-94-1724 .
-------
Table 5-2. PROCESSES FOR PRODUCING LIQUID HYDROCARBONS FROM COAL
vO
o
Zne rgy/Mate rial
Resources
1 ton coal
0. 0383 ton coal
fuel (10,630
Btu /lb)
7. 6 kW power
600 gal water
About 15-18,000
CF Hydrogen
Name of
Process
H-Coal Process21
by Hydrocarbon
Research, Inc.
Comment on the Process
The coal is hydrogenated
and converted to liquid
and gaseous product in
an ebuliating bed reactor
containing a cobalt-moly
catalyst. The operating
conditions are 2250-2700
psig and fe 50 'F. H2 is
produced by partial oxi-
dation of the residual oil
and coal residue.
Synthesized
Fuel
2. 429 bbl of
crude oil
25° API
By-Product
3. 24 millionBtu
gas
14.8 lb NH3
Amount of S de-
pends on type of
coal
1 ton coal
(10, 820 Btu/lb)
1 ton dry coal
(12,600 Btu/lb)
550 lb steam
2300 SCF
natural gas to
first stage
1 ton coal
(8750 Btu/lb)
11.6 kW
Power, 1300
gal water
CSF Process"
by Consolidation
Coal Co.
COED Process20
by FMC Corp.
Synthine Pro-
cess10 by U.S.
Bureau of
Mines
21. 9 gal naphtha
58 "API
63. 6 gal fuel oil
10. 3°API
43. 7 gal oil
(-4° API)
Coal is slurried with sol-
vent and heated to extrac-
tion temperature at 765°F
and at 150 psig. Solids are
sent to a low-temperature
carbonization unit. Liquid
passes through solvent
recovery unit. Tar and
heavy residue is hydro-
treated at about 800°F and
3000 psig.
Coal is pyrolyzed in four
stages. Coal is subjected
to increasing temperatures
of 600°, 850°, 1000°,
1600°F in first to fourth
stages, respectively. The
pressure of the operation
is between 6-10 psig. Eff.
of the process depends on
process to desulfurize char.
Coal is converted to syn- 54. 1 gal gaso-
gas, then (CO + H2) is con- line
verted into liquid hydro- 1 7. 8 gal LPG
carbons by using suitable
catalyst. The conditions
of operation are 200-400
psi and about 600 ° F.
34.00 SCF gas
(933 Btu/SCF)
11 lb ammonia
8100 CF gas
(480 Btu/SCF)
1177 lb char
(11,870 Btu/lb)
7. 1 gal liquor
3. 1 gal phenol
Comments on Pollution
Product oillmust be hydrodesulfurized.
Char contains sulfur.
.Syncrude products must be hydrodesul-
furized. The gas coming out from the
low-temperature carbonization unit
must be treated to remove
The removal of sulfur is required from
product liquid, gas streams, and char.
Sulfur is removed only from the gas
stream.
B-94-1725
-------
Table 5-3. PROCESSES FOR PRODUCING SYNTHESIS GAS
(Hydrogen and Carbon Monoxide) FROM COAL12
Ene rgy/Mate rial
Resources
1 ton coal
6470 SCF O2
1687 Ib h-p steam
210 gal process
water
1 ton coal
20, 376 SCF O2
708 Ib LP steam
83. 8 kWhr
Name of
Process
Comment on the Process
Synthesized
Fuel
Lurgi Pressure Operated at 450 psi and
Gasifier 1400°-i600°F
High-ash coal
(7500 Btu/lb)
Koppers-TotzekOpe rated at 1 atm and
Process 1 830°to 2370°F
Carbon conversion 96%
High-ash coal
1 ton coal Winkle r
12, 271 SCF O2 Generator
3100 Ib LP steam
Operated at 1 atm and
1470° to i650°F
Carbon conversion 80%
Low-ash coal (976 Btu/lb)
1 ton coal
14, 050 SCF O2
261 Ib LP steam
1 ton coal
19, 950 SCF O2
2390 Ib LP steam
Rummel Single-Ope rated at 1 atm and
Shaft Slag Bath 1830°F(coal 10, 02 5 Btu/lb)
Gasifier Carbon conversion 99%
46,000 CF raw
gas
30,000 CF puri-
fied gas
(400 Btu/SCF)
56, 600 CF raw
gas
(277 Btu/SCF)
52, 200 CF raw
gas
(288 Btu/SCF)
49, 300 CF
CO + H2
Flesch Demag
Generator
1 ton coal Wiirth
18, 380 SCF O2 Gasifier
1680 Ib LP steam
1 ton coal
19, 160 SCF 02
610 Ib steam
1 ton coal
19,950 SCF 02
1750 Ib steam
1 ton coal
20, 570 SCF O2
3000 Ib steam
U. S. B. M.
Gasifier
BAW-DuPont
IGT Gasifier
Operated at 1 atm and
570°-750°F
High-ash coal
(13,400 Btu/lb)
Pilot-plant scale
Operated at 1 atm and
715°F, coal (12,375
Btu /Ib)
Operated at 20 atm and
high temp. Coal (12, 950
Btu/lb) Pilot plant
Operated at 1 atm and
2190°F, Coal(14, 480
Btu/lb)
Operated at 5 atm and
2700°F, Coal (12, 140
+Btu/lb) Pilot-plant scale
Cold gas efficiency
65, 400 CF
CP + H2
By-Product
0. 5 gal oil
2. 9 gal tar
321 gal gas
liquor
1 551 Ib LP
steam
2374 Ib steam
NO 4. 5 ppm
1500 Ib steam
at 1 7. 6 atm
2064 Ib steam
987 Ib steam
71,900 CF
CO + H2
51, 800 CF
CO + H2
59,000 CF
CO + H2
62,900 CF
CO+H2
1539 Ib steam
>3500 Ib steam
Comments on Pollution
Relatively low off-gas temperature and
countercurrent design increase appearance
of tars, NH3, etc. , in waste quench liquor.
Very high off-gas temperature precludes
the formation of any compound less stable
than H2, CO, CO2 .
High gasifier temperature ensures that all
tars and heavy hydrocarbons.are reacted.
The reactants pass through slag, conse-
quently off-gas contains relatively high
amounts of ash.
Process is good for low reactivity fuels
and fuels with a low ash-fusion temperature.
Heat losses in the gasifier are high. Pro-
duced gas contains less heavy hydrocarbons
because of high temperature of the gasifier.
Two high-temperature reaction zones
ensures that all tars and heavy hydro-
carbons are reacted.
Very high off-gas temperature precludes
the formation of any compound less stable
than H2, CO, CO2.
B-94-1726
-------
fO
Table 5-4. PROCESSES FOR METHANOL PRODUCTION
Energy/Material Name of
Resources Process
Coal to Methanoi6
2 tons of coal Use any gasifier
(8500 Btu/lb) .to make synthe-
About 1 ton of sis gas. (Oxygen
oxygen requirement
varies with the
process)
SNG to Methanoi" .
30. 2 million Btu Lurgi Low-
feed and fuel Pressure
75 kWhr power Process
Comment on the Process
Coal is gasified and con-
verted to CO + H2-rich
gas. The gas can be con-
verted to methanoi in
presence of catalyst at
about 40-50 atm and 200°
to 300°C
Natural gas is reformed
to synthesis gas. The
synthesis gas is corn-
Synthesized
Fuel
1 ton of
methanoi
~1 ton
methanoi
7300 SCF CO2
144, 016 feed
water
13, 200 gal cool-
ing water
pressed to 40-50 atm
and converted to methanoi
in presence of copper-
containing catalyst at
200°-300°C
Coahor Oil Shale-Derived Naphtha to MethanoUa
1148 Ib naphtha
9. 7 million Btu
fuel
58 kWhr power
1600 Ib feed
water
12, 700 gal cool-
ing water
Lurgi Low- Naphtha is converted with
Pressure steam to a CO and H2-rich
Process gas and then converted to
methanoi in presence of
catalyst at 200°-300°C
1 ton methanoi
Coat-or Oil Shale-Derived Heavy Fuel Oil to Methanoi"
2020 Ib Bunker
"C" (18,300
Btu/lb)
130 kWhr power
1680 Ib feed
water
19,800 gal cool-
ing water
Lurgi Low- Heavy feedstock is con-
Pressure verted to synthesis gas
Process by partial oxidation and
then converted to meth-
anoi in presence of
catalyst at 200°-300°C
1 ton methanoi
By-Product
Small amount of
higher alochol is
produced
Comments on Pollution
Sulfur removal problems are similar
to coal gasification problems.
Small amount of
higher alcohol is
produced
Minimum pollution problems.
Small amount of
higher alcohol is
produced
Sulfur removal is necessary for
feedstocks containing sulfur.
Small amount of
higher alcohol is
produced
Sulfur removal problems are similar
to coal gasification problems.
B-94-1727
-------
Table 5-5. PROCESSES FOR AMMONIA PRODUCTION
Ene rgy/Mate rial
Resources
Coal to Ammonia
i. 8 ton coal
147 kWhr
6600 ib boiler
feed wate r
490, 000 cooling
water
Name of
Process
Comment on the Process
Synthesized
Fuel
By-Product
Comments on Pollution
Make H2 by any
process, then
make ammonia
Requires 44. 05 million
Btu/l ton NH3
Coat-or Oil Shale-Derived Light Naphtha to Ammonia25
0.81 tons naphtha Gasify naphtha
Requires 33. 7 million
Btu/l tori NH3
33. 5 kWhr to produce
6180 Ib boiler and then make
vO feed water ammonia
^ 468,000 Ib cool-
ing water
SNG to Ammonia38
32. 6 million Btu Reform natural
of natural gas as gas to make H2
feed and fuel. and then make
15 kWhr ammonia
22, 400 Ib make-
up water
Coal-or Oil Shale-Derived Heavy Oil to Annmonia25
Requires about 32. 9
million Btu/ton of NH3
0.94tons Bunker
;'C" oil
110 kWhr
3840 Ib boiler
feed wate r
883,000 Ib
cooling water
Gasify to pro-
duce H2 and then
make NH3
Requires about 36. 9
million Btu/ton of NH3
1 ton of ammonia Depends on
gasific" tion
process.
Sulfur removal problems are similar
to coal gasification problems.
1 ton of ammonia
Sulfur removal is necessary for feed-
stocks containing sulfur
1 ton of ammonia
Minimum pollution problems.
1 ton of ammonia
Sulfur removal problems are similar
to coal gasification problems.
B-94-1728
-------
Table 5-6. PROCESSES FOR HYDROGEN PRODUCTION
Energy/Material Name of
Resources Process
Coal to HydrogenM
32 tons coal Gasify coal by
(12, 300 Btu/lb) any gasifica-
2000 kWhr power tion process,
64, 000 gal water then shift the
produced gas.
19. 52 tons coal Process in-
(1^, 300 Btu/lb ) vestigated by
2000 kWhr power Bureau of
24, 000 gal water Mines
SNG to Hydrogens*
246 million Btu Steam Methane
feed; 166 million Reforming
Comment on the Process
Coal is gasified with steam
and oxygen, then shifted to
produce H2. The operating
conditions of gasifier are
450 psig and 2200° F
Coal reacts with steam
and the heat of reaction is
supplied by a helium
stream cycling between a
nuclear heater, and the
gasification system
Reforming pressure is
about 290 psig
Synthesized
Fuel
1 million SCF
H2 (97% pure)
1 million SCF
H2 (98% pure)
1 million SCF
H2 (98% pure)
By- Product
steam
steam
34, 200 Ib steam
Comments on Pollution
Sulfur removal problems are similar
to coal gasification problems.
Sulfur removal problems are similar
to coal gasification problems.
Btu fuel; 1040
kWhr power;
133, 00 gal cool-
ing water
9300 gal boiler
feed water
B-94-1729
-------
Table 5-6, Cont. PROCESSES FOR HYDROGEN PRODUCTION
Energy/Material
Resources
Name of the
Process
Comment on the Proce»»
Synthesized
Fuel
By-Product
Comments on Pollution
Coar-or Oil Shale-Derived Naphtha to Hydrogen32
13, 000 Ib naphtha
feed; 7600 Ib
naphtha fuel
1160 kWhr power
188, 700 gal cool-
ing water
6050 gal boiler
feed water
Steam-Naphtha Reforming pressure is 1 million SCF
Reforming about 290 psig H2 (98 % pure)
5,
Ib steam Sulfur removal is necessary for
feedstocks containing sulfur.
Electrical Energy to Hydrogen32
559 Ib of distilled
water; 140, 000
kWhr AC or
130, 000 kWhr DC
290, 000 gal cool-
ing water
(1 kWhr = 3413 Btu)
Electrolytic
Process
Hydrogen is generated on
the cathodes and oxygen
on the anodes by electrol-
ysis of distillated water.
The operating conditions
are 160°F and about
atmospheric pressure.
million SCF
Z (99. 9% pure)
0. 5 million SCF
02 (99. 7% pure)
. Minimum pollution problems.
B-94-17Z9
-------
in the Lurgi Process, the sulfur is removed from the raw material and products
by gasifying it to sulfur dioxide and hydrogen sulfide. Then the elemental sulfur
is recovered from sulfur dioxide and hydrogen sulfide by one of the many avail-
able processes (e.g., Glaus Process, Stretford Process). Comments on pollu-
tion for many of these processes are included in Tables 5-1 through 5-6.
Appendix B contains a detailed description of (and economic estimates
for) the production of gasoline, distillate oils, methanol, and SNG from
coal by several example (pattern) processes for which there are sufficient
data for characterization.
5. 2 Fuel Synthesis From Oil Shale
Many processes produce gaseous or liquid fuels from oil shale. Some
processes are on the pilot-plant scale (e.g., Tosco-H Process, Gas
Combustion Retort Process, Union Oil Process), and some are in com-
mercial use (e.g., Petrosix Process, GCOS* Process). As shown in
Figure 5-2, oil shale can be hydrogasified to gaseous fuel, or it can be
retorted to make liquid fuel. The liquid fuel then can be gasified to
produce gaseous fuels. Table 5-7 lists some of the processes for making
fuels from oil shale.
The processed (spent) shale is a fine, granular, dark residue dark
due to residual carbon that coats the particles because the low tempera-
tures in the processing retort do not produce any significant agglo-
meration into clinkers. More than 75% (by weight) of feed shale
becomes spent shale. Therefore, disposition of spent oil shale is a major
problem, and once this shale has been deposited, there remains the prob-
lem of revegetating the deposit. Studies are being conducted to resolve
this problem.
Appendix B presents a detailed description of (and economic estimates
for) the production of gasoline and distillate oils from oil shale by a
selected (pattern) process for which there are sufficient data for charac-
terization. The processing of oil shale for liquid hydrocarbons results
in a heavy "syncrude" oil, and petroleum-refining techniques are required
for finishing. Table 5-8 presents the usual products from the refining of
crude oil and the energy requirements.
*
Great Canadian Oil Sands, Ltd.
96
-------
LOW-Btu GAS
HYDROGASIFICATIOH
OF OIL SHALE
HYDROGEN OR
SYNTHESIS GAS
RETORTING OF
OIL SHALE
OILS
CLEAN FUEL GAS
LOW-Btu
METHANATION
OIL
GASIFICATION
HYDROGEN
SULFIDE
HYDROTREATING
HYDROGEN
CLEAN FUEL GAS
MEDIUM-Btu
CLEAN FUEL GAS
HIGH-Btu
LOW =100-250 Btu
MEDIUM = 250-550 Btu
HIGH = 950+ Btu
CLEAN LIQUID
FUEL
A-74-1238
Figure 5-2. PRODUCTION OF CLEAN FUELS FROM OIL SHALE
-------
00
Name of
Process
Oil Shale
Hydrogasification
With Synthesis
Gas
Ene rgy /Mate rial
Resources
Oil Shale to Gas9
23, 436 tons shale
(40 gal/ton Colo-
rado oil shale,
3400 Btu/lb), 14.5
million Ib h-p steam
(include power re-
quired for oxygen
plant)
24, 867 tons shale
(36 gal/ton Colorado
oil shale, 3200 Btu/
Ib); 13.4 million Ib
h-p steam; 10. 7
million Ib LP steam
(Include power re-
quired for oxygen
plant)
Oil Shale to Shale
66, 000 tons shale TOSCO II
(36 gal/ton), plus Process
electricity, fuel gas,
etc.
Table 5-7. PROCESSES FOR PRODUCING FUELS FROM OIL SHALE
By-Product Comments on Pollution
Synthesized
Comment on the Process Fuel
Oil Shale
Hydrogasification
With Hydrogen
Shale is preheated to 300°F 97. 8 million SCF 38. 9 tons benzene Problem of disposing of
by countercurrent exchange (924 Btu/SCF)
with 700'F flue gas. The
preheated shale is fed to the
hydrogasifie r through lock
hoppers. The operating con-
ditions are 1000 psig and
1400°F. Synthesis gas is
fed to the hydrogasifier.
Same as above except hydro- 96. 5 million SCF
gen is fed to the hydrogasifier (932 Btu/SCF)
instead of synthesis gas.
The shale is preheated to
500 = F by flue gas from ball
heater. The heated balls and
preheated shale are fed to the
retort where shale is pyro-
lyzed at 900°F. By-product
gas is used for firing the ball
heater after purification.
59, 500 bbl
63. 3 tons carbon large amount of "dirty"
from partial oxi- spent shale. Sulfur has
dation. 18,000 tons to be removed from gas
spent shale, streams and liquid products.
262. 8 tons liquid
fuels.
51- 3 tons benzene
45. 1 tons carbon
from partial oxida-
tion. 18, 400 tons
spent shale,
18, 400 tons spent
shale; 349. 4 tons
liquid fuels.
Same as above.
180 tons NH3
630 tons coke
spent shale
Same as above.
B-94-1730
-------
Table 5-8. PETROLEUM PRODUCTS FROM AND FUEL, CONSUMED IN U.S. REFINERIES
Crude Oil*
to -
Gasoline
Ke rosene
Gas Oil and
Distillate
Residual
Fuel Oil
Lubricating
Oils
Other
Products
Fuel
Electric
PowerC
Steamc
Total
Average
Thermal
Efficiency
1968°
44. 7
7. 7
22. 1
7. 3
1. 7
16. 5
100. 0
6'98,000
58, 100
6, 500
762, 600
87.43%
1967
44. 8
7.3
22.2
7.6
1.8
16.3
100. 0
692, 000
56, 500
7,200
755, 700
8 7. 54%
1966
45. 3
6. 5
22. 5
7. 6
1.9
16.2
1960
irnl °ftt
45. 2
4. 6
22.4
11.2
2.0
14.6
100.0 100.0
put Btu/bbl crude oil
701,000 744,000
49, 200
6,200
756,400
87. 51%
47,000
6, 700
797, 700
86. 82%
1950
43.0
5. 6
19.0
20.2
2. 5
9. 7
100.0
658, 000
22,900
--
680,900
88. 69%
1925*
32. 0
8.0
48. 7
__
4.2
7.1
100. 0
829, 000
_ _
829, 000
86. 18
a 1 bbl of crude oil = 6 million Btu.
Other products include fuel.
C 1 kWhr(e) generated corresponds to 13,400 Btu (heat) and 1 Ib steam requires
1100 Btu.
Preliminary.
Residual fuel oil included with gas and distillates.
B-94-1718
-------
5. 3 Fuel Synthesis From Nuclear Energy
The 40 nuclear power plants now in operation in the U. S. produce
about 1% of the nation's energy, but this is projected (optimistically) to
soar to more than 45% by the year 2000. Nuclear fission of uranium
or other fissile fuels produces heat, and this generated heat is utilized
to produce steam for turbines and ultimately electricity. Three types of
reactor systems have been commercialized in the U. S. :
Light-water reactors (LWR)
a. Pressure-water reactor (PWR)
b. Boiling-water reactor (BWR)
High-Temperature Gas-Cooled Reactor (HTGR).
Two others are in the development stage:
Breeder reactors
a. Steam-cooled breeder reactor (SBR)
b. Light-water breeder reactor (LWBR)
c. Molten-salt breeder reactor (MSBR)
Fast breeder reactors
a. Liquid-metal fast breeder reactor (LMFBR)
b. Gas-cooled fast breeder reactor (GCFBR)
Heavy-water-moderated organic-cooled reactor (HWOCR)
(low-priority project).
Figure 5-3 is a diagram of a nuclear fuel cycle for an LWR. 7
The potential efficiency of a conventional nuclear electric conversion
plant is on the order of 33%, according to the AEC, 2 though in practice,
commercial plants have not achieved this high a figure. The HTGR is
intended to operate at an efficiency nearer to 40% .
At present, the commercial practice for extracting energy from these
reactors is as electric power. The power generation cycle involves steam
or possibly helium gas turbines. However, the electric power can be
used to produce a chemical fuel. Hydrogen can be produced by elec-
trolysis from water by using commercially available electrolyzers, and
this hydrogen can be used as a fuel or as a feedstock for the manufacture
of another fuel, such as ammonia or a hydrocarbon.
100
-------
Figure 5-3. NUCLEAR FUEL CYCLE FOR
LIGHT WATER REACTOR (Source: Ref. 7)
Recently, attention has been given to the possibility of the use of
process heat directly from the core of a HTGR or GCFBR to drive a
chemical process. The production of hydrogen by this means is a dis-
tinct possibility.
Thermal decomposition of water is a concept that merits technology
development. Because of the temperature limitations of nuclear reactors
and conventional process equipment, direct single-step water decompo-
sition cannot be achieved, but a sequential chemical reaction series can
be devised in which hydrogen and oxygen are produced, water is con-
sumed, and all other chemical products are recycled. This multistep
thermochemical method offers the potential for processes that can use
high-temperature nuclear heat and be contained in chemical process
equipment.
101
-------
An example of such a chemical reaction sequence is as follows28:
2CrCl2 + 2HC1 - 2CrCl3 4- H2
2CrCl3 - 2CrCl2 + C12
H20 + C12 - 2HC1 + i/202
H2O - H2 + i/2O2
A thermochemical hydrogen production plant that directly uses the heat
from a nuclear reactor might be more efficient (depending on the chemical
process) than a nuclear electric generator-water electrolyzer plant.
Thermochemical hydrogen production offers a closed-cycle, non-
material-polluting route to gaseous fuel synthesis. It would be environ-
mentally compatible because there would be no by-products (except oxygen),
and combustion of the produced hydrogen recreates the raw material,
water. In the longer term, thermochemical hydrogen production offers
a conversion technology for transforming heat from any high-temperature
source into chemical energy by using a perpetually available material
resource.
One of the prospects for nuclear process heat that has been investigated
by General Atomic Co. is the production of gaseous fuels from coal. 19 The
conversion of carbon and steam to hydrogen and carbon monoxide is exothermic
(evolves heat), but the shift of the carbon monoxide with steam to produce more
hydrogen is endothermic (requires heat). The overall carbon-to-methane pro-
cess also is endothermic. These reactions are as follows:
C + H2O = CO + H2 evolves 28 kcal/mol
CO + H2O = CO2 + H2 requires 10 kcal/mol
C + 2H2 = CH4 requires 20 kcal/mol
Figure 5-4 is a simplified diagram of the process being developed by
Stone and Webster Inc. and General Atomic Co. The coal is ground,
mixed with a coal-derived solvent, and solubilized in the presence of
hydrogen. The liquid coal is further hydrogenated in subsequent steps,
the final product being primarily a high-Btu gas with some low-sulfur
aromatic liquids. A portion of the gas is cycled to the steam-methane
reformer located in the nuclear reactor vessel, where the endothermic
steam-methane reforming takes place. The resulting hydrogen-rich gas
102
-------
COAL
SOLVENT
RECYCLE
CARBON
DIOXIDE
ASH
SULFUR
SULFUR
WATER
STEAM
AROMATICS PIPELINE GAS
A-15-65
Figure 5-4. COAL GASIFICATION PROCESS BEING
DEVELOPED BY STONE AND WEBSTER AND
GENERAL ATOMIC (Source: Ref. 29)
is taken to the carbon monoxide-shift and carbon dioxide-stripping sections
before compression and entry into the coal-processing sequence. The
HTGR also provides high-pressure steam to drive the hydrogen com-
pressors and a turbine-generator set for in-plant electrical needs.
Figure 5-5 shows some general applications of HTGR heat that are
possible (in concept) for the production of fuels.
As with other techniques of energy conversion and fuel production,
nuclear processes do pollute the environment.36'40 The overall thermal
conversion efficiency of a nuclear power plant (Table 5-9) is about 30%,
compared with perhaps 40% in conventional plants. Moreover, none of
the inefficiency or waste heat is discharged through a stack, which ac-
counts for a considerable part of the heat dissipation from a conversion
103
-------
HTGR PROCESS HEAT
DEVELOPMENT
t *
STEAM
100-600 psi
HEAVY OIL
RECOVERY
TAR SANDS
MINING
STEAM
600-3500 psi
*.
TAR SANDS
IN SITU
OIL REFINERY
* *
SYNTHESIS GAS
STEAM-HYDROCARBON
REFORMING
*
*
COAL
GASIFICATION
COAL
LIQUEFACTION
HYDROGEN
SPECIAL PURPOSE
^
#
HYDROGEN
CLOSED LOOP
SYNCRUDE
OIL SHALE
COAL GASIFICATION
C-H20
A-74-1239
Figure 5-5. HTGR APPLICATIONS TO FUEL PRODUCTION
(Source: Ref. 30)
plant. Consequently, a large amount of heat (twice as much as for a
conventional plant) is discharged to rivers or to the atmosphere, causing
thermal effects that may be hazardous to plant and animal life. In
commercial use, fuel rods have, on infrequent occasions, developed some
leaks, allowing fission product leakage into the primary cooling water.
This represents a potential for serious environmental contamination with
radioactivity and must be taken into consideration in the plant design.
Some radioisotopes produced in the nuclear-fuel-reprocessing cycles
have very short lives, others last for days, and a few remain radio-
active for thousands of years. At present, the high-activity radioactive
liquid wastes are delivered to underground storage tanks for long-term
containment and decay, causing serious concern over their ultimate
disposal.
104
-------
Table 5-9. CHARACTERISTICS OF NUCLEAR MODEL
PLANTS (Source: Ref. 2)
Plant starting commercial operation in period:
Thermal efficiency (%)
Specific power (MWt/MTU)
Boiling Water
1976-80
34
22
1981-85
Pressurized Water
1976-80
34 33
26 37
1981-85
33
41
Irradiation level (MWDt/MTU) ....
Fresh fuel assay (wt.%U-23S)
Spent fuel assay (wt.% U-235)
Fissile Pu discharged (kg/MTU) ....
Feed required (ton U308/MWej , . . .
Separative work required (kg/MWe) . \ .
Replacement Loadings (steady state)
Irradiation level (MWDt/MTU)
Fresh fuel assay (wt.% U-235)
Spent fuel assay (wt % U-235) . .
Fissile Pu discharged (kg/MTU) . .
Feed required (ton U308/MWe/yr)k . .
Separative work required (kg/MWe/yr) . .
. . 21,000
. . 2.2
. . 0.8
. . 5.1
. . 0 680
. . 345
. . 27,000
. . 2.6
. . 08
. . 5.6
. . 0.145
. . 105
24,000
2.4
0.7
5.4
0635
340
33,000
2.8
0.7
5.9
0.140
100
26,000
2.8
0.9
6.0
0545
320
33,000
3.3
0.9
6.7
0.165
130
26,000
2.7
0.8
6.0
0480
275
33,000
3.2
0.8
67
0.165
125
3 MWt is thermal megawatts, MWe is electrical megawatts, MWDt is thermal megawatt days, MTU is metric tons (thousands of
kilograms) of uranium, and ton UjOg is short tons (2,000 pounds each) of yellowcake from a refinery. Separative work is given in
kilogram units.
o Based on operation of enriching facilities at a tails assay of 0.2% U-235 and on no recycle of plutonium. For replacement
loadings the required feed and separative work are net, in that they allow for the use of uranium recovered from spent fuel.
5. 4 Fuel Synthesis From Solar-Agricultural
Sources and Waste Materials
Solar energy is the most abundant form of energy available on the
earth, but it is very diffuse at the earth's surface. As a result, it is
expensive to capture the large amounts of energy required for conversion
and distribution at commercial levels because of the large surface areas
required for "collection" of the solar energy.
105
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5. 4. 1 Solar Energy to Electricity
Many ways are being developed for converting solar energy to electricity,
such as solar thermal conversion, photovoltaic conversion, ocean thermal
difference, wind power, and bioconversion. Solar energy systems have no
fuel cost, but they currently require higher initial capital investments than
other energy systems.
Drs. Aden B. and Marjorie Meinel have proposed that solar radiation
might be captured so efficiently that the overall conversion to electricity
by means of a thermal (steam) cycle would be 25-30% efficient.17 Here,
solar energy is converted to thermal energy and generated heat is util-
ized to produce steam for turbines to produce electricity. A material
such as liquid sodium is used as a heat-transport fluid operating at about
1000°F and is pumped through steel conduits throughout the solar-energy-
collecting field. The high-energy radiation from the sun is absorbed as
heat by a semiconductor layer, and the heat flows by conduction to the
liquid sodium. According to the Meinels1 estimates, about 8 square
kilometers of collecting surface and a 50-million-liter thermal storage
tank would be required for the equivalent of a 1000-MW generating plant.
Based on 10, 000 Btu/kWhr, a heat input of 10 billion Btu/hr would be
required for a 1000-MW plant.
Photovoltaic conversion is another > means of producing electricity from
solar energy. This is based on the utilization of the photovoltaic effect
in solid-state devices, in which the absorption of light generates free
electrical charges, which can be collected on contacts applied to the sur-
face of semiconductors. The theoretical thermal efficiency is about 24%
at room temperature. An orbiting-satellite collector system has been
proposed by Dr. Glaser. 13 This scheme proposes the positioning of two
geo-stationary satellites such that one is illuminated by the sun at all
times. Both would have a direct line of sight to the same point on earth.
According to Dr. Glaser, to produce 0. 5 trillion kWhr of electrical
energy, an orbiting solar collector with a conversion efficiency of 100%
would need an area of 16 square miles for this energy. This corresponds
to approximately 105 square miles of silicon cells weighing 180 million
pounds, with an assumed efficiency of about 15%.
106
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Electric energy can be generated from ocean temperature differences.
More than 70% of the solar radiation falls on the ocean, which creates
a pronounced temperature difference between the surface and lower layers
of the ocean. The hot water at the top would provide heat to boil another
working fluid (such as ammonia of propane). The produced vapor would
expand through a turbine to produce electricity. The bottom cool water
would provide cooling to condense the vapor back to liquid. The average
temperature difference between surface and lower layers is about 18°F in
selected parts of the ocean, which would yield an efficiency of about 4%.27
The transfer of electric power from ocean to the shore is also a
capital-consuming step.
Wind energy is an indirect form of solar energy. The use of wind
power to drive a propeller to produce electrical energy is not new.
Solar energy can be utilized in the byconversion of organic matter.
Algae have the capability of converting visible light energy into cellular
energy under a wide range of conditions. This cellular energy is trans-
formed into the chemical energy of methane and other combustible gases
by anaerobic digestion. Methane thus formed would be burned in a gas
turbine generator system to produce electricity.14 The overall efficiency
of the process is less than 4% . 34
5. 4. 2 Solar Energy to Agricultural Products
A solar plantation is another way of utilizing solar energy. The energy
from a plantation is a perpetually renewable source of fuel.
No one has tried to grow forests of other crops purposely for fuel on
a large scale in the U.S. Wood charcoal is produced in several parts
of the country, but the wood used is a scrub growth or wood waste.
However, data that are available can be used to estimate fuel values
potentially available from forest and farm crops; fuel value production
and estimated efficiencies of conversion of solar energy to vegetable
matter are given in Table 5-10.
107
-------
Table 5-10. FUEL VALUE PRODUCTION ANti
ESTIMATED EFFICIENCIES OF CONVERSION OF SOLAR
ENERGY TO VEGETABLE MATTER (Source: Ref. 33)*
Plant
Alfalfa:
U.S. average,
1969
2 cuttings per
season
3 cuttings per
season
Reed Canary Grass
Corn:
mature silage
stalk and ears
Gen. Agriculture
Sugar Cane
Cottonwood
Cottonwood
Slash Pine
(crown & bole)
Conifers:
Pseudotsuga \
toxifoliac {
Pinus Nigrad f
Piceaabies* )
Sycamore
Age of plant
(years)
1-
'
1-
1-
1-
1-
1-
1-
?
2
7
20+
18-22
5
Location
U.S.
U.S. Midwest
U.S. Midwest
U.S. Midwest
U.S. Midwest
U.S.
U.S.
La. and Fla.
Ala. and Miss.
Ala. and Miss.
Southeastern
States, U.S.
England, lat.
51 °-52° North
Georgia
Yield
(tons/acre-year)
o.d.ora.d."
2.85 o.d.
3.60 o.d.
4.60 o.d.
6.32 o.d.
6.50 o.d.
7-11 o.d.
4. 5-13. 5 o.d.
20 o.d.
2.0 a.d.
3.1 a.d.
3.8-4.8 a.d.
1.6-1 1.2 a.d.
Fuel value
assumed
(Btu/lb)
6500
6500
6500
6500
6500
6500
6500
6500
5800
5800
7000
5800
Estimated
solar energy
conversion* (%)
0.29
0.39
0.41
0.44-0.69
0.28-0.85
1.2
0.24-0.30
0.37
0.64
Reterence
(1)
(2)
(2)
(3)
(4)
(5)
(5)
(5,6)
(7)
(8)
(9)
(10)
(11)
" o.d. = oven dry; a.d. = air dry (12 to 20% moisture content).
" Based on annual average insolation equal to 1300 Btu/ft2-day.
c Douglas Fir.
d A species of pine.
' A species of spruce.
5. 4. 3 Fuel Synthesis From Biomass and Waste Materials
The use of biomass material, growing plant organisms, or organic
waste is a means of obtaining energy from a renewable source. The
technology of converting nonfossil, renewable carbon to a synthetic fuel
uses two major sources of raw material: 1) growth of plants and 2) col-
lection of organic waste produced by the conversion of solar energy to
chemical energy. Thus, the two broad classifications, by resource base,
for biomass fuel synthesis are waste products and plant materials. Fuel
synthesis from waste products uses the same technology as fuel synthesis
from plant materials except that its raw material has to be collected and
sorted before the organic material can be used.
*
Reproduced with permission from Chemical Technology, the polydisciplinary
publication of the American Chemical Society. ©Copyright 1973 by the American
Chemical Society.
108
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If direct burning is not used to extract the energy from either the
waste or plant material, four general processing methods pyrolysis,
hydrogasification, anaerobic digestion, and (aerobic) fermentation can
be used to convert the raw material to low-Btu gas, SNG, liquid fuel,
or any combination of these fuels. Each method is reviewed, and some
of the advantages and disadvantages of each technique are emphasized.
5. 4. 3. 1 Pyrolysis
Pyrolysis involves the thermal decomposition of organic matter at
about atmospheric pressure and at temperatures generally above 1000°F
in the absence of oxygen to produce a complex mixture of gaseous, liquid,
and solid products. A typical distribution of products reported by the
U.S. Bureau of Mines for the pyrolysis of raw municipal refuse at 1650°F
is given in Table 5-11. Chemically, the process results in fragmentation
and rearrangement of the more complex organic molecules in the waste
to yield simpler molecules.
Table 5-11. PRODUCTS OF PYROLYSIS OF
MUNICIPAL WASTE (Source: Ref. 31)
Yield per Ton
of Feed
Gas 17,741 SCF
Oil 0. 5 gal
Ammonium sulfate 25. 1 Ib
Aqueous 113.9 gal
Residue 154 Ib
One major disadvantage of pyrolysis is that, although the product
gas contains appreciable amounts of methane, the product distribution
is usually complex, as shown in Table 5-11. The gas has a heating
value of about 450 Btu/SCF and contains methane (12. 7 mole percent),
hydrogen (51. 9 mole percent), carbon monoxide (18. 1 mole percent),
carbon dioxide (11.4 mole percent), and 5.2 mole percent Cz and higher
components. Light oil, ammonium sulfate, an aqueous phase containing
water-soluble organics, and a residue that contains mainly a lightweight
flaky char and the nonorganics also are produced. The char has a
heating value of about 5300 Btu/lb.
109
-------
Several groups currently are developing pyrolysis processes for the
production of fuel gas from organic wastes; among them are Battelle
Memorial Institute, Union Carbide Corp., Hercules Inc., Monsanto Co.,
and Occidental Petroleum Corp. A process using a fluidized-bed system
is being developed at West Virginia University. 39 Described as an
example, the heart of this process is depicted in Figure 5-6.
COttUSTIOH
PRODUCTS
TO STACK
PYROLYSIS
.. GAS
PRODUCT
RECYCLED
PYROLYSIS
GAS
AIR BLOWER
PYROLYSIS GAS
RECYCLE BLOWER
A-74-1208
Figure 5-6. SCHEMATIC DIAGRAM OF THE MUNICIPAL
REFUSE PYROLYSIS PROCESS WITH FLUIDIZED SAND
RECYCLE AND CHAR RECYCLE (Source: Ref. 39)
In this design, the heat given off by combustion of the char supplies the
energy for pyrolysis. The oxygen required for combustion is supplied
by compressed air. To prevent nitrogen from diluting the gas, pyrolysis
and combustion are conducted in separate reactors, each of which contains
equal depths of fluidized sand. Energy transfer is accomplished by sand
flow from the combustion reactor at 1750°F to the pyrolysis reactor at
1500°F. The feed to the pyrolysis unit is municipal refuse, whereas that
to the combustion unit is char. Subsequent processing of the pyrolysis
gas by shifting, scrubbing, and methanation yields SNG. The projected
110
-------
compositions of the product gas after each treatment step are summarized
in Table 5-12.
Table 5-12. PYROLYSIS GAS PRODUCED FROM
400 TONS/DAY OF MUNICIPAL REFUSEa(Source: Ref. 39)
Component
Carbon Dioxide
Carbon Monoxide
Methane
Hydrogen
Total 4795 5620 4010 1400
Pyrolyzer
Exit
785
1700
530
1780
CO -Shift CO2 Scrubber Methanator
Exit Exit Exit
i onn cic'tr //lair
1610
870
530
2610
870
2610
2610
1400
a
Refuse feed contains, on the average, 30% moisture.
The SNG yield from this process corresponds to about 2. 5 SCF of
methane per pound of feed, or an overall thermal efficiency of about
35% in terms of the energy content of the dry feed and the SNG.
If pyrolysis is viewed as strictly a disposal process, its costs appear
to be competitive with those for incineration, which generally range from
about $ 3 to $10/ton. However, as an SNG-producing process, the added
costs of the other unit operations needed to produce pipe line-quality
(high-Btu) gas would appear to make the total costs too high. Low-Btu-
gas applications are probably more suitable for such processes.
In the next few years, several processes are scheduled for demon-
stration on a scale of 50-100 tons/day of waste feed.
Pyrolysis also can be used to convert solid waste into a liquid fuel.
The conversion of organic waste into a liquid fuel has the advantage that
the material can be more easily stored or tanked than gaseous alternatives.
Two processes are currently under development, one by the Bureau of
Mines and one by Garrett Research Corp. The Garrett process has
received EPA and City of San Diego support, and a demonstration plant
is under way in San Diego. ^
The first phase of the Garrett system consists of a crusher, metals,
and glass separater, and dryer. This prepares the waste for the con-
verter. In this case, the conversion process is pyrolysis, and it occurs
111
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in a reacting system of proprietary design. The pyrolysis is fast, and
the temperature is about 800°F. The liquid product is purported to be
a replacement for No. 6 fuel oil, and the heating value of this oil is
12, 000 Btu/lb.
The Bureau of Mines has reported on the batch heating of waste in a
hydrogen atmosphere. The temperature is 250°-400°C, and the hydrogen
pressure is 100-300 atm. The process yields 2 bbl/ton of waste.
5. 4. 3. 2 Hydrogasification
A limited amount of work has been done on the hydrogasification of
municipal waste. Limited proprietary studies have been carried out at
IGT with paper, the major component of municipal solid waste, and a
few experimental studies were reported by Feldmann of the Bureau of
Mines. 8 Basically, the concept of waste hydrogasification is based on
the premise that any organic material can be treated with hydrogen at
elevated temperatures and pressures to produce methane.
Part of the waste feed is used to convert hydrogen to synthesis gas
by partial oxidation and shifting, which are followed by hydrogasification
and gas purification. For a balanced plant, Feldmann estimates that
about 40% of the carbon in the feed can be converted to SNG, while the
remaining 60% is used for hydrogen production. This corresponds to a
maximum SNG yield of about 3. 8 SCF of methane per pound of feed, or
an overall maximum thermal efficiency of about 65%, again in terms of
the energy content of the SNG and the dry feed. In one preliminary
experiment, 53% of the carbon in a typical municipal waste was hydro-
gasified at about 10Z5°F and 1300 psig, to produce, after methanation, a
936-Btu/SCF gas. Detailed experimental data and process design studies
have not been published. However, the reported experimental work indi-
cates that conversion levels high enough to allow balanced operation of
the plant can be achieved.
A major problem in pyrolysis or hydrogasification of organic waste
to produce SNG is the large amount of water in the raw waste. A large
part of the energy content of the waste is needed during pyrolysis and
hydrogasification to remove the water. In many cases, little or no net
energy can be derived from the overall process in the form of methane.
112
-------
For example, consider a waste' that has a moisture content of 85% and a
fuel value of 5000 Btu/dry Ib. These values are close to those often en-
countered in typical agricultural wastes, whereas the moisture content of
sludge can be as high as 99%. Heat-drying an 85%-moisture content waste
to a final moisture content of 30% or less requires more energy than the
fuel value of the waste itself.
5. 4. 3. 3 Anaerobic Digestion
Anaerobic digestion has been known and used for more than 70 years.
In simple terms, it consists of the bilogasification of organic waste mate-
rials by methane-producing bacteria with the concurrent "cleaning" of
the waste. The organic substances in the waste are fermented by the
organisms. Technically, the process is called anaerobic fermentation,
or digestion, because the organisms grow in the absence of oxygen. The
process is used throughout the world today, either alone or in combination
with other processes, for the treatment of domestic, industrial, and
agricultural liquid wastes. However, anaerobic fermentation has not yet
been applied to the commercial treatment of solid wastes.
The basic process of anaerobic digestion can be represented as a two-
stage process: First, the complex organic materials in the waste are
converted to acids, alcohols, and aldehydes by acid-forming bacteria, and
then the acids are converted to methane and carbon dioxide by methane-
forming bacteria.
Complex
Organics
Acid Formers
Stage I
Acids
Alcohols
Aldehydes
Methane Formers
Stage II
Methane
Carbon Dioxide
and Solids
Although this is an oversimplification of complicated biological phen-
omena, the two-stage representation of anaerobic digestion is useful in
explaining some of the characteristics of the process, such as the effect
of acid buildup and pH.
In general, three types of biodegradable compounds are found in wastes:
fats, carbohydrates, and proteins. Fat degradation in anaerobic processes
occurs by hydrolysis to fatty acids and alcohols and then oxidation to lower-
molecular-weight volatile acids, which are digested. Carbohydrate de-
gradation occurs by molecular disruption to disaccharides and mono-
saccharides, which then are converted to the lower-molecular-weight
113
-------
components by cell metabolism. Protein degradation occurs by hydrolysis
to amino acids and then deamination to the acids. The resulting acids then
are converted to methane and carbon dioxide by the methane-formers.
In its conventional design, anaerobic digestion is carried out in a
closed tank at the proper fermentation conditions. The entire operation"
is carried out in a closed unit because oxygen inhibits the digestion pro-
cess. The escaping gas, containing 50-80% methane and 20-50% carbon
dioxide, is collected, and a portion is usually combusted as fuel for the
plant to maintain the temperature of the digestion chamber at 85°-95°F.
At temperatures near 125°F, the thermophilic microorganisms predominate;
and the digestion proceeds at a higher rate.
The production and release of methane stabilize the organic material.
The process can be maintained on a large scale for an indefinite period,
as long as the usual fermentation parameters are controlled and a con-
tinuous supply of waste material is fed to the digester. A schematic
drawing of the process in terms of the distribution of components in the
digester is shown in Figure 5-7.
The anaerobic digestion process is used in combination with activated
sludging in many small, medium, and large cities and towns across the
U.S. to treat municipal liquid wastes. The process also is used as the
primary treatment for the stabilization and volume reduction of garbage
from municipalities and in industry for the treatment of wastes from
meat-packing plants. Perhaps the oldest application of anaerobic diges-
tion is the stabilization of organic wastes in septic tanks.
As noted, the problem with pyrolysis and hydrogasification is that
large amounts of energy are necessary to separate the carbon and water
in the feedstock. Biological gasification by anaerobic digestion over-
comes this disadvantage. Anaerobic digestion is applicable to most types
of high-moisture-content municipal, agricultural, and industrial organic
wastes. Also, in contrast to hydrogasification and pyrolysis, the hardware
for large-scale biological digestion is quite advanced.
114
-------
RAW
SEWAGE
PRIMARY
SETTLING
TANK
(100%)
SOLUTIONS AND
SUSPENSIONS
(99-99%)
PRIMARY
SLUDGE
FEED
(1-5 % SOLIDS)
ACTIVATED
SLUDGE
OR
TRICKLING
FILTER
-*-WATER
SECONDARY
SLUDGE
FEED
(1/2-2% SOLIDS)
ANAEROBIC
DIGESTER
A-50503
DISPOSAL
Figure 5-7. SCHEMATIC DRAWING OF ANAEROBIC
DIGESTION IN CONVENTIONAL SEWAGE DIGESTER
115
-------
The major disadvantage of anaerobic digestion is it's relatively low
gasification rate, compared with the rates of hydrogasification and pyrolysis
for the same feeds. Also, in applying anaerobic digestion to the treat-
ment of municipal refuse, special consideration must be given to two
factors. Unlike sewage sludge, the organic portion of the refuse is
mainly cellulosic and constitutes a nutritionally deficient substrate for
the anaerobic organisms. Then too, mixed municipal refuse, as received,
cannot be directly gasified because a sizable fraction of this material is
oversized, inert, abrasive, and not biodegradable. Consequently, the
refuse must be processed, and the inorganic and heavier fractions sep-
arated from the organics as much as possible before digestion can begin.
5. 4. 3. 4 Agricultural Products to
Alcohol, Fermentation
The main process for the production of ethanol from agricultural
products is microbial fermentation. The fermentation is accomplished
by enzymatic conversion of fermentable carbohydrates in vegetable matter
to ethanol and carbon dioxide by select strains of yeasts.
The main classes of carbohydrate materials that can be used for the
purpose are as follows:
a. Saccharine material (containing sugar) such as molasses, sugar
beets, fruit juices, sugar cane, corn syrup
b. Starchy materials such as potatoes, cereal grains, cassava,
Jerusalem artichokes
c. Cellulosic materials such as wood, agricultural waste such as straw
and stocks, and hemicellulose in wood pulp and grasses.
Raw materials of the "a" class are directly fermentable. Those of
the "b" class must first be converted to mono- or disaccharides (sugars).
This conversion can be brought about 1) by use of mineral acids,
2) enzymatically by use of malt (dried sprouts of barley or rye),
amylolytic molds, or bacteria, and 3) by treatment with alpha- and beta-
amylase preparations. Those of the "c" class are converted to fermentable
carbohydrates by hydrolysis with mineral acids. These fermentable
carbohydrates then are yeast-fermented to alcohol. The scheme is shown
in Figure 5-8.
116
-------
CELLULOSIC
MATERIAL
SACCHARINE
MATERIAL
ACID
HYDROLYSIS
STARCHY
MATERIAL
ACID HYDROLYSIS
MALT DIASTASE
MOLD AMYLASES
BACTERIAL AMYLASES
I
FERMENTABLE
CARBOHYDRATES
I
YEAST
FERMENTATION
SPENT MASH
CARBON DIOXIDE
ALDEHYDES
ETHANOL
A-74-1236
Figure 5-8. PRODUCTION OF ETHANOL
FROM AGRICULTURAL PRODUCTS
Special strains of yeasts are capable of giving an efficient and rapid
conversion. Strains are selected on the basis of alcohol tolerance (up
to 1Z% ethanol by volume is common), efficiency of conversion, speed
of fermentation, ability to maintain physiological constancy, and adapta-
bility to harsh conditions (in the case of wood waste).
The amount of the alcohol obtained from a substance is directly pro-
portional to the amount of fermentable sugar that can be produced from
that substance. The overall sugar conversion efficiency is 90-99%.
From 1 gram of converted sugar, the alcohol yield is 0. 51 gram. The
remaining 0.49 gram is lost as carbon dioxide.4
Ethanol production from some crops is as follows:3
117
-------
gal/ton gal/acre
Marigolds 8 150
Artichokes 28 500
Potatoes 22 220
Grain 78 50
Sugar Beet 21 240
Molasses 66
A commercial product containing only 95% by volume alcohol can be
produced from fermented liquor by straight distillation. However, 99. 8%
by volume alcohol can be produced by azeotropic distillation.'
The main by-products of the alcoholic fermentation of agricultural
products are spent mash, carbon dioxide, and aldehydes. After drying,
the spent mash can be used as a constituent in cattle feed, or it can
be concentrated and used as a core binder in foundries or as a briquet
adhesive. Various amounts of fuel oil can be obtained, depending upon
the agricultural feed.
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118
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~
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120
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34. Tamplin, A. R., "How Shall We Use the Sunlight? Let Us Count
the Ways..." Environment 15, 16-34 (1973) June.
35. "The IGT HYGAS Process. " A status report for the Federal Power
Commission's Synthetic Gas-Coal Task Force of the National Gas
Survey. Chicago: Institute of Gas Technology, December 1971.
36. Tsivoglou, E. C. , "Nuclear Power: The Social Conflict," Environ.
Science Technol. .5, 404-10 (1971) May.
37. Voogd, J. and Tielrooy, J. , "Improvement in Making Hydrogen, "
Hydrocarbon Process. 46, 115-20 (1967) September.
38. Wett, T. , "Ammonia Synthesis From Natural Gas or Naphtha,"
Oil Gas J. 71, 86 (1973) March 12.
39. West Virginia University University Department of Chemical
Engineering, Solid Waste; A New Natural Resource. Morgantown,
W. Va. , May 1971.
40. "Why it's a Good Idea to Break Up the AEC, " Bus. Wk. No. Z286,
40-41 (1973) June 30.
121
-------
6. FUEL PROPERTIES AND COMPATIBILITY
The subject of fuel properties and compatibility comprises certain chemical
and combustion properties, toxicity, transportability and tankage, and compat-
ibility with present-day and futuristic types of engines. Appendix A contains
a detailed tabulation of the chemical and combustion properties and the fuel
concentrations (in air) that exhibit various degrees of toxicity.
This section presents discussions of fuel transmission, distribution, and
tankage on-board a vehicle and then a subjective analysis, based on information
in the published literature, of the compatibility of the potential fuels in various
types of engines.
6. 1 Transmission and Distribution Compatibility
The introduction of an alternative automotive fuel that has properties un-
suitable for the equipment now used for energy transmission and distribution
would be difficult and expensive. The great economic incentive for retaining
existing facilities would have to be overcome. Fuels that can be handled in
existing equipment therefore have an enormous advantage.
At present, four separate transport systems handle four classes of fuels:
1. Liquid fuels (gasoline and diesel oil) in pipelines and tank trucks
2. Solid fuel (coal) in railroad cars, trucks, and barges or perhaps
pulverized and slurried for pipeline transmission
3. Gaseous fuels (natural gas) in transmission and distribution pipe-
line s
4. Condensable gases (LPG^ propane) in long-distance pipelines and
distribution in pressurized tanks (trucks).
Sections 2 and 10 discuss the ratings and quantitative evaluations of the
various fuels for compatibility with energy transmission and distribution
systems. The following is a summary of our assessments.
1. Synthetic Gasoline. For the network of pipelines, trucks, and service
stations, synthetic gasoline is the most acceptable alternative. Pumps,
lines, meters, and tanks can be used, and synthetic gasoline can
be blended with conventional gasoline. The compatibility of synthetic
gasoline is rated excellent.
123
-------
2. Distillates (Diesel Oils, Naphthas, Kerosene). From the standpoint
of compatibility with transmission and distribution systems, distillates
can be substituted for gasoline when blending with gasoline is prevented.
Gasoline transmission pipelines and pumps can be used, but separate
truck, tanks, and service station facilities are desirable. Blending
with gasoline is impractical for internal combustion engine usage. The
compatibility of distillates is rated good.
3. Alcohols (Ethanol, Methanol). Gasoline transmission pipelines and
pumps can be used, but separate trucks, tanks, and service station
facilities are desirable unless the alcohol is blended (as allowed by
solubilities) with gasoline. Adulteration with water would most likely
be illegal and must be guarded against. The fuel-handling compatibi-
lity of alcohols is considered good.
4. Heavy Fuel Oils, Residuals. Because of viscosity, these fuels are
not transportable in gasoline pipelines, and tank trucks would need
modifications, including pumps and perhaps heaters (depending on
climate). Service station facilities also would have to be modified,
and separate tanks would be required. The compatibility is. rated poor.
5. Condensable Gases. Synthetic LPG and ammonia are fuels that are
liquids at low pressures. LPG has its own long-distance transmission
system, and ammonia could be transported (separately) in such lines.
However, use of these fuels would necessitate changes in the dis-
tribution equipment now used for gasoline, and trucks built for con-
ventional liquid fuels could not be used. Extensive service station
modifications would be necessary. The compatibility of synthetic LPG
and ammonia with distribution equipment is rated poor. Methylarnine also
is an easily condensed gas, but its toxicity requires sealed systems
and transfers. It is an incompatible fuel.
6. Acetylene and Hydrazine. Acetylene gas decomposes explosively when
compressed above 15 psig (2 atm). It cannot be transported in pres-
surized pipelines. Closed systems are desirable because it is an asphy-
xiant. It can be transported in a liquid state when dissolved in a solvent
(acetone). New distribution and service station equipment would be re-
quired, and the acetone-acetylene solution would have to be transferred
to vehicle tanks. Acetylene is unacceptable in terms of compatibility.
Hydrazine is extremely toxic, and all fuel transport facilities would
have to be sealed. It is normally transported and stored as a hydrate.
New, sophisticated distribution and service station equipment would be
required for its use (to service fuel-cell vehicles). Hydrazine is in-
compatible with present fuel transmission and distribution systems.
7. Gas Systems and Cryogenics (Carbon Monoxide, Hydrogen, Methane).
Methane already has a transmission and distribution system (the
natural gas system, which serves more than 40 million customers).
With changes to the compressor stations, the meters, and some of the
sealing and packing materials, hydrogen could be transported in this
system. Except for the slight "leakiness" in this system, carbon
monoxide also could be transported safely in it (as it was in the days
of manufactured, or town, gas). Because of its toxicity, however,
124
-------
carbon monoxide cannot be vented, making cryogenic storage im-
practical. Also, transfer systems would have to be sealed. In
addition, the weights and volumes associated with gaseous carbon
monoxide make it impractical to store or tank as a vehicle fuel.
Hydrogen and methane can be liquefied for storage (with safe venting),
and hydrogen can be hydrided to a solid. New service station facil-
ities would be required, but tank trucks would be unnecessary if
service stations performed the liquefaction (or hydride formation).
We consider the compatibility of liquid hydrogen and methane to be
fair and that of a metal hydride to be poor. Carbon monoxide is
unacceptable.
8. Coal. Solids are incompatible with the present liquid and gaseous
energy supply networks, but coal could be slurried for pipeline
transport. It is hauled by train, truck, and barge. However, dis-
tribution to and storage at service stations would require all new
facilities, and a convenient vehicle interface is not evident. Hence,
the long-distance transport of coal is of good compatibility with ex-
isting systems, but distribution to service stations and vehicles is
not compatible.
9. Special Features of Certain Fuels
Acetylene. As indicated above, acetylene spontaneously
decomposes (violently) and must be dissolved in a solvent,
such as acetone, for storage. Although not toxic, it is an
asphyxiant and an anesthetic.
Ammonia. Because it can be catalytically decomposed to
hydrogen and nitrogen, ammonia is a storage medium for
hydrogen. Except for toxicity, storage (tankage) of liquid
ammonia is practical.
e Carbon Monoxide. Carbon monoxide would have to be tanked
as a compressed gas. Liquefaction is not practical because
the toxicity requires complete containment, but heat leaks
would cause excessive tank pressures and require venting.
Further, filling warm containers with liquid carbon monoxide
entails a great degree of venting unless a reliquefaction cycle
or an oxidation process (to carbon dioxide) is employed.
Ethanol. Because of its intoxicating characteristics and the
legalities of transport and usage, ethanol would have to be
denatured to prevent human consumption. Further, regulations
would have to be invoked and metering equipment utilized to
prevent illegal "watering down" of the fuel.
Hydrazine. Hydrazine is considered because it is a preferred
fuel for fuel cells to produce electricity to power a motor to
propel the vehicle. It is not considered for combustion in a heat
engine.
125
-------
Hydrogen. The storage of hydrogen as a liquid offers some
distinct advantages and disadvantages. Present-day technology
indicates that,for long-term storage, the tank must be vacuum-
insulated to avoid condensing liquid air from the atmos-
phere. But even with highly effective vacuum insulation, the
tanks will eventually begin to vent hydrogen, which could be a
flammability hazard.
6. 2 Vehicle Tankage of Alternative Fuels
Table 6-1 lists some fuel data that affect storage or tankage on-board a
vehicle. Table 6-2 summarizes the data from Table 6-1 plus selected data
on heating value, flammability, and toxicity from Appendix A.
Fuel tank weights were calculated by first assuming that equal amounts
of heat energy are needed for each fuel: the equivalent of 20 gallons of
gasoline, or 2,246, 000 Btu. For each fuel, a volume and weight for fuel
alone are computed. (These appear in columns 2 and 3 of Table 6-1. ) This
computation inherently assumes that the fuels are utilized with the same
efficiency (as gasoline) in a vehicle to yield identical performance, but does
not take into account potential gains and/or losses in efficiency from engine
designs suited for a particular fuel.
After calculating the volume requirements, -we solicited estimates for
tank weight, volume, and cost from commercial suppliers of containers
(vessels, dewars, tanks, etc.). In some cases, the estimates are within
about 20% of each other; however, in one case (liquid hydrogen), the esti-
mates vary by a factor of 10. (These data are presented in columns 5, 6,
and 7 of Table 6-1. ) Currently available Dewar flasks that weigh about
400 pounds could accommodate the necessary 72. 5 gallons of hydrogen.
Estimates for the weight of improved vessels have been as low as 1 pound
of tank per pound of liquid hydrogen (about 46 pounds for a 75-gallon tank).
The lightweight tanks make use of advanced aerospace techniques87 that might
not be practical for automobiles.
Estimates of the weight of an advanced, but practical, tank have been
made. For tanks with a short "lock-up" time (time before hydrogen boil-
off gases must be vented), the estimates are as low as 150 pounds.
Tanks for LSNG follow the same pattern as liquid hydrogen tanks, except
that the overall weight is a little less. The LSNG tank is only about 40% the
size of the hydrogen tank, but it must be stronger because methane is not
126
-------
Table 6-1. FUEL TANKAGE SYSTEMS
(Energy Equivalent of 20 gal of Gasoline)
Fuel
Acetylene
Ammonia
Coal
Diesel Oils
Ethanol
Gasoline
Hydrazine
Hydrogen (Gas)
Hydrogen (Liquid)
Hydrogen (MgHj)
Kerosene
LPG
Methanol
SNG (Gas)
SNG (Liquid)
Vegetable Oils
Estimated selling
TTHtimatprf ma nnf
Fuel
Stored As
Dissolved in
Acetone
Liquid at 200 psi
Dust
Liquid
Liquid
Liquid
Hydrate
Gas (2000 psi)
Liquid (-422°F)
Hydride
Liquid
Liquid
Liquid
Gas
Liquid
Liquid
I price.
a ft 11 1"<> T- ' a r»n«f-
Weight
(Fuel Only), Ib
120
279
173.3
121 !
189
117
542
43
43
43
117
112
247
104
104
139
Volume
(Fuel Only), eal
105
43.4
15.3
17.0
29.2
20.0
63. 1
72.6
17.3
26.4
38.9
29.4
18.3
Cost,
1973 dollars
125-175*
12-16,
50-80
11-13*
50-70
12-20*
50-80
11-13*
50-70
70-90*
200*
At least 340*
11-13*
50-70
125-175*
12-20*
50-80
160*
10-13*
50-70
Fuel Tank
Weight, Ib
680
105
20-30
25-30
35-45
25-30
165
4600
a 150
At least 700
24-26
65-75
50-55
1100
«60
25-28
Volume, gal
,. 110
45
16
18
30
21
65
103
At least 62
19
27
41
_._
43-46
20
Vendor's quoted price (mass-produced).
B-94,-1693
-------
Table 6-2. TANKAGE AND SAFETY PROPERTIES OF POTENTIAL FUELS
Flammability Limits
1 «
ro
00
Fuel
Acetylene
Ammonia
Carbon Monoxide a
Coal
Diesel Oil or
No. 2 Fuel Oil
Ethanol
No. 6 Fuel Oil
Gasoline
Hydrazine
Hydrogen ( l)b
Kerosene
LPG (synthetic)
Methanol
Methylamine
Methane SNG U)b
Naphthas (approx)
Vegetable Oil
(Cottonseed)
Chemical
Formula
C2H2
NH3
CO
c
Mix
C2H5OH
Mix
Mix
N2H4
H2
Mix
C3H8
CH3OH
CH3NH2
CH4
Mix
Mix
Lower Heating
Value ,
Btu/lb
20,
3,
4,
10,
18,
11,
17,
19,
7,
51,
19,
19,
9,
12,
21,
18,
16,
730
000
350
000
480
930
160
290
000
620
090
940
080
860
250
850
110
Tankage Weight, Tankage Volume,
Ib gal
800
385
ZOOO
200
150
235
165
145
710
200
145
180
280
260
165
150
165
390
45
600
18
22
"30
22
22
65
105
22
27
41
35
45
22
22
c in Air, %
L«an
2.8
15
12.5
d
--
4.0
--
1.4
4.7
4.1
. 0. 7
2. 1
6.7
4.9
5.0
1. 1
--
Rich
80
28
74
d
--
19
--
7.6
100
74
5
10
36
21
15
6
--
Ignition
Tempe rature ,
°F
581
1200
1128
d
494
793
765
430
518
1085
491
808
878
806
1170
430-530
530
Dangerous for
Prolonged Exposure,
ppm
Nontoxic
100
100
Nontoxic
500
1000
500
500
1
- Nontoxic'
500
e
s
Nontoxic6 "
200
10
Nontoxic
500
Nontoxic
Gaseous.
Cryogenic liquid.
Energy equivalent of 20 gallons of gasoline.
For coal dust, the flammability data vary with the type of coal. For dust of coal of medium volatility,
the ignition temperature is about 1100°F. The minimum explosive concentration is about 50 oz/1000 cu ft.
A sphyxiant.
B-54-753
-------
easy to vent safely and cannot be conveniently combusted catalyt.ica.lly as it
goes overboard.
Metal hydride storage of hydrogen is another area of undefined commercial
technology and constitutes part of the technology gap for the efficient auto-
motive storage of hydrogen. Depending on the heat of formation of the hydride
and its decomposition temperature, it may be possible to use the engine's
cooling water or exhaust gas to liberate the fuel from the metal. On this
basis, we estimated the cost of the tank alone and note it as the "at least"
cost in Table 6-1.
Fuel-tank costs were estimated as closely as possible by using data from
the manufacturers. Design configurations influence price, and when storage
systems are not well-defined, costs are very uncertain. Some cost infor-
mation was so vague that only two conclusions could be drawn. First, the
cost of liquid hydrogen tanks can be substantially reduced by development and
ma>ss production. Current costs for the required 73 gallons might be as
much as $1500, but one manufacturer thought that the price could be reduced
to about $200. Second, the cost of metal hydride storage, based on current
prices for magnesium, may be largely compared to that of gasoline. The
estimated costs appear in Table 6-1.
The cost estimates given here are incidental information. Their assembly
was part of an effort aimed at predicting the relative costs of alternative fuel
utilization in a vehicle. Because vehicle mileage depends on power-plant
efficiency and total vehicle weight, this cost can be estimated. However, a
uniform and credible estimation procedure for engine efficiencies and the
performance of alternative fuels in different types of power plants is beyond
the scope of this study. As explained in Section 7, much of the required data
is nonexistent or controversial.
6. 3 Engine and Fuel Compatibility
The compatibility of possible engine and fuel cycles is discussed by sum-
marizing each engine's combustion requirements and then each fuel's com-
patibility with that engine. The engines considered are as follows:
1. Conventional Otto-cycle engine
2. Open-chamber stratified-charge engine
129
-------
3. Dual-chamber st rat if led-charge engines
4. Diesel engines
5. Brayton-cycle engines, gas turbines
6. 'Rankine-cycle engines, notably steam engines
7. Stirling cycle engines
8. Fuel cells.
6. 3. 1 Conventional Otto-Cycle Engines
For the conventional spark ignition engine, which uses no charge strati-
fication, the following fuel characteristics are of importance when considering
performance65: volatility, detonation and preignition characteristics, heat
of combustion per unit mass and volume, safety, and chemical stability,
neutrality, and cleanliness.
When emissions are considered, the effects of flammability limits become
important, as illustrated in Figure 6-1. Obviously, for the fuel characterized
by Figure 6-1 a typical hydrocarbon burning at lower equivalence ratios
lowers emission of all three pollutant groups. As the mixture approaches
the lower limit of flammability, hydrocarbon emissions begin to rise again.
The lower a fuel's lean limit of combustion, the lower the air/fuel ratio at
which the engine can be operated, thus lowering emission levels.
6. 3. 1. 1 Acetylene
Acetylene has been used on an emergency basis as a substitute for gasoline.
During World War II, many cars in Germany and Switzerland used gas genera-
tor units to produce acetylene for propulsion from calcium carbide and water.
It proved to be a poor substitution. 5 Acetylene is very hard to handle because
it tends to dissociate into carbon and hydrogen in fuel lines and manifolds,
releasing heat and leading to high pressures. The risk of dissociation explo-
sions can be lessened by dissolving the acetylene in water or another hydro-
carbon fuel.
The use of acetylene as a fuel makes engine operation difficult. Its low
octane number (40) makes operation at even moderately efficient compression
ratios impossible, unless an excessively lean mixture is used or the acety-
lene is mixed with alcohol or water. Carbon deposits appear rapidly and
maintenance may have to be doubled.
130
-------
CARBON HYDROCARBONS,
MONOXIDE, % ppm C6 NOX, ppm
ro f\> i>
_ r\> 01 A u> *> o> rv> o> o & a
ooooo ooooooc
D rooiAtnOOOOO OOOOOOOOC
/
/
/
/
r\
\
\
V
\
\
^-
X.
^
J
*s
\
\
\
\
V
.100 .090 .080 .070 .060
'rich') FUEL/AIR RATIO
.050
A-74-1256
Figure 6-1. EFFECT OF EQUIVALENCE RATIO ON ENGINE EMISSIONS
(Source: Ref. 56)
Most fuel tank or gas generator schemes are very heavy and/or bulky.
In our opinion, acetylene is not well-suited for conventional, carbureted
engines, although it may be usable in stratified-charge or other engines.
6.3.1.2 Ammonia
Ammonia has been intensively investigated as a fuel for spark-ignition
engines, *' 17 primarily for military applications. The chief problem with
ammonia apparently is its reluctance to ignite.66 Increased spark energies
and very accurate spark timing are required to initiate combustion, and re-
searchers reported better combustion at higher compression ratios. 19 One
alternative to high compression ratios (or supercharging to achieve the same
operating pressures) would be partial dissociation into hydrogen and nitrogen
before ignition. Most investigations, including those at General Motors
Laboratories, have chosen this approach. Apparently, about 2-10% by weight
dissociation is sufficient to begin modernately rapid combustion. A catalytic
ammonia dissociator appears technically feasible.
131
-------
The power output with ammonia is reported to be less than that with
hydrocarbons by about 20%,60 probably because of the lowered volumetric
efficiency with a gaseous fuel. Most investigations reported that very high
ignition energies17 were required, and spark advance had to be greatly
increased to compensate for ammonia's low flame velocity.
Whether emissions from ammonia-fueled engines are reduced is unclear.
Carbon monoxide and hydrocarbon exhaust are of course eliminated. The
potential for NO reduction is an area of controversy.
Sawyer and Starkman found that, despite ammonia's low peak-combustion
temperature, NO were greatly increased. 53'60 In addition, General Motors
3C
Research Laboratories found that, at fuel-rich conditions, high concentrations
of ammonia (5300 ppm) appeared in the exhaust gases. 17 These findings
recently have been challenged by Hodgson,28'32 who found low NO and dis-
.X
sociated ammonia.
Because ammonia is stored as a liquid and has a very high heat of vapori-
zation, large amounts of heat are necessary for evaporation; however,
ammonia is a gas at ambient temperature and pressure, and this heat could
be supplied from engine exhaust and/or the atmosphere.
6. 3. 1. 3 Carbon Monoxide
No data are available for engines run on carbon monoxide alone. The
National Bureau of Standards investigated it briefly during World War II
before deciding that alcohol was a better alternative to gasoline. The Bureau
found that the octane number of carbon monoxide could not be expressed on
the usual scale. 1
During World War II, automobiles were adapted to operate on producer
gas,5 which is mainly carbon monoxide and hydrogen. Power was reported
to have been decreased 50%, probably because of the displacement of com-
bustion air by the gaseous fuel. Compression ratios were raised to 8:1, but
this did not increase output to the gasoline-fueled level.5
Like other gaseous fuels, carbon monoxide would offer advantages in
cylinder-to-cylinder fuel distribution, cold starting, and avoidance of vapor
lock. However, its toxicity would require careful construction of fuel sys-
tems to avoid disastrous leaks.
132
-------
6.3. 1. 4 Coal
Coal is not compatible with conventional internal-combustion engines
because it is a solid fuel.
6.3. 1.5 Diesel Oils
Diesel oils are not volatile enough for use with carburetors15: fuel in-
jection would be required. However, the low octane quality, the deposit-
forming tendencies, and the difficulty of cold-engine starting make diesel
oil very poor fuel for conventional engines.
6. 3. 1. 6 Ethanol
Ethanol has been the subject of many separate investigations, most of
which were concerned with gasoline-alcohol blends; these were summarized
by Bolt in 1964. 9
Because of its low heating values, alcohol reduces the overall heating
value of the fuel when it is added to gasoline. Many investigations into the
performance of unmodified, conventional engines have shown the effect of
leaner mixtures, "surge, " slight loss x>f power, and roughness during warm-
up. However, when air/fuel ratios were adjusted to reflect the stoichiometry
of the blend, observers concluded that, any effects were minimal.40
A prime motivation for blending ethanol with gasoline is the resulting
increase in octane number. Ethanol's octane numbers are 106 (RON) and
89 (MON), compared with about 93 (RON) and 85 (MON) for regular gasoline.
Large amounts of blends (greater than 10% of total gasoline sales) have been
used in Europe.9
Tests on gasoline with up to 30% ethanol as fuel showed no substantial
improvement in emissions over pure gasoline.40
The use of pure ethanol requires some modifications to conventional
engines, but can produce satisfactory results. Ethanol-fueled engines have
been shown to produce up to 8% greater power output if run richer than
stoichiometric. 6z Tests by the National Bureau of Standards showed ethanol
did less damage than gasoline to cylinder walls and oil. 13 With its high
octane number, ethanol is suitable for high-compression engines. However,
engines running on ethanol will not start below 58°F, unless fuels of higher
volatility, usually naphtha or diethyl ether, are blended with them. These
compounds reportedly13 sometimes lead to vapor lock at about 90°F.
133 ~~
-------
Because of the high latent heat of vaporization of ethanol, some type of
manifold heating arrangement would be needed. Brooks13 found pure ethanol
slightly more efficient than gasoline, whereas Starkman et al. a have pre-
sented results that suggest it may be slightly less efficient. Seemingly,
engine design is the dominant factor. Certainly, using ethanol as a fuel
would allow an increase in compression ratio, because of ethanol1 s high
octane number relative to that of unleaded gasoline. The estimated increase
in efficiency should be about 10% when the compression ratio is raised65
from 8:1 to 11:1. Apparently, ethanol has no great effect on emissions.61'62
In summary, ethanol-gasoline blends are quite compatible with present
engines, and pure ethanol would require some modifications. However, its
use presents no great efficiency advantages.
6.3.1.7 Gasoline
Gasoline-like fuels (Cs-Cjo) manufactured from alternative energy sources,
principally coal or oil shale, are expected to be compatible with present
automobile engines. Gasoline from the Canadian Tar Sands is already in use.
Prior to I960, there was little reason to consider alternative fuels; gasoline
was satisfactory. However, two new considerations have entered the pic-
ture: emissions and energy efficiency.
The efficiency of automobile engines has dropped in recent years because
of the need to reduce pollution, and vehicle efficiency has decreased because
of increased weight. The proportionate causes for efficiency losses are
debatable.
There seems to be some agreement that an emission-controlled, 4200-pound
car goes about 85% as far per gallon as precontrolled cars-a 15% loss.16'34'67'89'90
There is no agreement, however, on the total loss that will be incurred in
meeting 1977 Federal Standards. Estimates range from 15% losses 46> 67 to
25-30% losses. 16'18 With dual catalysts and a better air/fuel ratio manage-
ment system, however, some of the losses may be recouped by the time the
1977 Federal Standards are met.
6.3.1.8 Heavy Oils
Heavy fuel oils are incompatible with conventional spark-ignited engines
because of high viscosity, poor volatility, and many of the same reasons
134
-------
previously enumerated for diesel oils. Residual oils have additional problems
becjiuse of their great sulfur content and the damage done by the ash content
of combustion products.
6.3.1.9 Hydrazine
We found no evidence that hydrazine has ever been used as a motor fuel'
(flame combustion in a heat engine). We included it in this study only as an
energy carrier for fuel cells.
6.3.1.10 Hydrogen
The use of hydrogen in conventional engines would require that all the
problems of engine conversion to gaseous fuels be overcome, plus several
difficulties arising from hydrogen's extreme physical properties. Operation
of engines using modified propane carburetors shows that hydrogen precom-
busts in the intake manifold.22 The flame speed of hydrogen is so high that,
with near stoichiometric mixtures, "knock" results from rapid flame propa-
gation. 8 Various solutions to these problems have been used; none are en-
tirely satisfactory. Exhaust gas recirculation,23 a combination of a very
clean engine (free of dirt, oil, or deposits) and a low coolant temperature,
and water injection are among the methods used. 8
Once "knock" is under control, operation on hydrogen is described as
ideal. Hydrogen engines idle very smoothly (and at very low rpm), experience
no warm-up roughness, and respond well to changing load. However, a great
deal of combustion air is displaced by gaseous hydrogen, so the charge is
diluted. (Hydrogen's low volumetric heating value makes it worse in this
respect than other gaseous fuels.) As a result, power from hydrogen-fueled
engines is reduced considerably. At UCLA, a medium-sized V-8 (351 cubic
inches) engine fueled with hydrogen gives performance similar to that of a
small six-cylinder engine.22 Interest in hydrogen engines continues, however,
because of the low emissions and the efficient use of chemical energy.
If lubricants and other contaminants are kept out of the combustion chamber,
emissions of carbon monoxide and hydrocarbons are eliminated when hydrogen
is used as a fuel. Nitric oxide, which is the only significant pollutant proved
in engine tests, can be controlled by judicious regulation of the air/fuel ratio.
However, the possibility exists that hydrogen peroxide also could be a com-
bustion product, and hydrogen-engine emissions tests should be conducted to
135
-------
determine this. Figures 6-2 and 6-3 show data on CFR engines taken at
General Motors Laboratories and JPL ' ; there is reasonably good agree-
ment. These experiments indicate that peak NO concentrations
40
(53.6)
(40.2)
o.
£ 20
"S. (26.8)
in
o
V)
uj 10
x (13.4)
i
KNOCK
GASOLINE
(Approx)
HYDROGEN
LEAN
I
1.0 0.8 0.6 0.4 0.2
(Full rich) (Futl l«an)
AIR/FUEL EQUIVALENCE RATIO
A-74-1258
Figure 6-2. NO EMISSIONS FROM GENERAL MOTORS
LABORATORIES'CFR ENGINE OPERATING ON HYDROGEN
(Source: Ref. 63)
CFR = Cooperative Fuel Research.
136
-------
100.0
10.0 -
Q.
^
O>
(O
1
V)
UJ
X
O
LEAN LIMIT
FOR GASOLINE
0 O.I 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 I.I 1.2 1.3 1.4
(futl. AIR/FUEL EQUIVALENCE RATIO (Fufll
lean) , rich)
A-74-1257
Figure 6-3. EMISSIONS FROM JPL'S
CFR ENGINE OPERATING ON HYDROGEN
(Source: Ref. 11)
are as bad or worse for hydrogen than for gasoline, but that hydrogen's very
low lean limit of combustion (equivalence ratios of 0. 1^0. 2 for hydrogen
versus 0. 6-0. 8 for gasoline) offer a low- to medium-load operating region
in which NO emissions are virtually zero. The problem of high NO at
x x
peak power (near stoichiometric region) remains to be solved.
In addition to lower emissions, there is another reason why the ultra-lean
region, where hydrogen burns but hydrocarbons do not, can be beneficially
exploited. The first cars to run on very lean hydrogen have shown signifi-
cant increases in efficiency.23 Figure 6-4 shows how thermal efficiency is
increased by operation in the very lean region. n This is the result of the
decreased dissociation of combustion products as peak cycle temperatures
are reduced and the high polytropic expansion exponent, which allows the in-
dicated efficiency to approach the ideal.10 JPL has recorded a decrease of
34% in energy demand per mile for a V-8 engine operating in this region.
(The fuel was gasoline supplemented with just enough hydrogen to make it
flammable. )n
137
-------
N = 2000 rpm
O HYDROGEN ONLY
A HYDROGEN+ INDOLENE-30
O.I
(Fuel
lean)
0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
AIR/FUEL EQUIVALENCE RATIO
A-74-I25I
1.0
Figure 6-4. THERMAL EFFICIENCY OF JPL'S V-8 ENGINE
OPERATING ON HYDROGEN
(Source: Ref. 11)
The UCLA car reportedly can go 200 miles on 106 Btu, even though it
weighs 4000 pounds.23 This figure remains valid for urban driving and com-
pares favorably with the 193 miles/106 Btu that the EPA calculates for the
Mercedes diesel (over the Federal Driving Cycle). 12
Additional opportunities exist for increasing efficiency. Swain and Adt of
the University of Miami have made use of hydrogen's wide flammability limits
to eliminate throttling as a means of load control.64 In their scheme, engine
output is determined by the amount of fuel injected at low pressure into the
intake stream. This eliminates the intake manifold "pumping" losses ex-
perienced at partial throttle and, in effect, allows the engine to regulate out-
put in the same way that a stratified-charge engine does, but without using
high-pressure fuel injection. Swain and Adt claim a 50% increase in energy
mileage (miles/Btu) for this system.3
Hydrogen is not completely compatible with conventional engines, but offers
some impressive incentives for conversion.
6. 3. 11 Kerosene
The reasons for kerosene's poor compatibility with conventional engines
are much the same as those for other fuel (diesel) oils. Model T Ford engines,
138
-------
tractor engines, and other very-low compression-ratio (4:1) Otto-cycle
engines have been operated on kerosene after the engine is completely warm.
However, kerosene's low volatility, its tendency to form deposits, and its
low octane quality make it generally incompatible.
6.3. 1. 12 SLPG
If the proper fuel system is used, LPG is quite compatible with conven-
tional engines. Appropriate fuel systems already have been designed, and
propane-fueled cars have been in operation for some time. 33' 55
LPG has the same advantages as other gaseous fuels easy starting, quick
warm-up, better fuel distribution, simplified carburetion, and smooth idling.
The disadvantage also is the same: About 10% of the peak power is lost be-
cause the gaseous fuel displaces combustion air. 36
Propane has a lower lean limit of combustion than gasoline, and for this
reason, emissions can be reduced when switching from gasoline to propane.
Figures 6-5 and 6-6 show the regions where propane is burned.32 Carbon
monoxide also is reduced by lean running, but for most hydrocarbons, carbon
monoxide concentration is a function of equivalence ratio and is really not
affected by fuel characteristics. The less complicated fuel molecules in
LPG (butane, propane) should produce less reactive hydrocarbons than the
more complicated molecules in gasoline.
As with other gaseous fuels, users of propane report that less maintenance
is necessary and that frequently replaced components (spark plugs, oil filters,
oil) last longer. 55
Because propane can be burned at lower equivalence ratios than gasoline
(because of its slightly wider flammability limits and better fuel distribution),
an improvement in fuel economy on the basis of miles per Btu can be ex-
pected. Efficiency also can be increased by raising compression ratios
because of LPG's high octane quality (RON =109; MON = 96).
6. 3. 1. 13 Methanol
Methanol is a liquid fuel like gasoline, and the same storage and carbure-
tion systems can be used if the physical and combustion properties of methanol
are taken into account.
139
-------
o
o.
Q.
z"
o
00
oc.
<
o
o
oc
a
f
o
5000
4000
3000
2000
1000
LEAN MISFIRE
LIMITS
0
0.8
(Fuel
0.9 1.0 I.I 1.2 1.3 1.4 1.5
rich) AIR/FUEL EQUIVALENCE RATIO
A-74-1249
1.6
(Fuel
lean)
Figure 6-5. HYDROCARBON EMISSIONS AS A FUNCTION OF
AIR-FUEL, EQUIVALENCE RATIO AT 50% THROTTLE
(Source: Ref. 55)
a.
a.
x
O
Z
7000
6000
5000
4000
3000
2000
1000
0
LEAN MISFIRE
LIMITS
PROPANE
I
0.8
(Fuel
rich)
0.9 1.0 I.I 1.2 1.3 1.4 1.5
AIR/FUEL EQUIVALENCE RATIO
1.6
(Fuel
lean)
A-74-1250
Figure 6-6. NOX EMISSIONS AS A FUNCTION OF
AIR-FUEL EQUIVALENCE RATIO AT 50% THROTTLE
(Source: Ref. 55)
140
-------
Methanol has a high Qash point, similar to that of ethanol. Early researchers
had trouble starting ethanol engines in moderately cold weather. 13 For start-
ing below temperatures of 40-50°F, volatile agents, such as ethers or acetone,
must be added; electric heaters also have been suggested.2
Methanol1 s heating value is one-half that of gasoline, and its latent heat of
vaporization is about 4 times as high. Therefore, 8 times as much-heat
must be supplied for methanol vaporization as for gasoline vaporization, the
usual procedure is to route exhaust gases through the intake manifold. l Many
sources have assumed that the incoming charge is cooled during fuel evapora-
tion and that this increases volumetric efficiency and peak power9; this idea
was challenged by Starkman. 62 Because of methanol's low heating value,
fuel systems must be modified for greater fuel flow rates.
Apparently, some of methanol's properties can be utilized to make spark-
ignition engines more efficient. Some researchers have found that only 70%
as much energy per mile was needed with methanol and that emissions remained
at a low level. 7 Methanol's low lean limit of combustion extends the operating
region of methanol engines greatly,20 as Figure 6-7 shows, and has the ad-
vantage of reduced emission of hydrocarbons, carbon monoxide, NO , and
X *
more efficient operation. Furthermore, because this low-emissions region
is available, less drastic measures are necessary to meet emissions standards.
Burning in the lean region, methanol has another advantage over gasoline:
Its flame speed does not fall off as fast when the mixture is air-rich. Figure 6-8
shows the results of experiments in an internal combustion engine by Stark-
man, Strange, and Dahm. 58 The fact that methanol's flame (reaction front)
speed stays high is important. One effective way to lower NO emissions is
Ji
to retard ignition, which results in lost cycle efficiency. Because methanol's
flame speed is faster than that of gasoline, this lost efficiency is recovered. 1
The last important property of methanol is its low peak combustion tem-
perature, about 180°F less than that of gaeoline, significantly lowering the
rate of NO formation. 1
x
Methanol has one peculiar emissions problem. Researchers have noted
increased emissions levels of aldehydes, especially for lean mixtures.20 The
seriousness of this emissions problem, however, has not been determined.
141
-------
90
80
70
S. 60
50
40
30
20
Q."
2E
1800 rpm
METHANOL
ISOOCTANE
1.2 1.3
0.6 0.7 0.8 0.9 1.0 I.I
(|ean') AIR/FUEL EQUIVALENCE RATIO
A-74-1253
Figure 6-7. OPERATING REGIONS FOR
METHANOL AND ISOOCTANE
(Source: Ref. 20)
200
O
UJ
UJ
a.
O
OL
O
<
0.8
Tean) AIR/FUEL EQUIVALENCE RATIO
Figure 6-8. REACTION FRONT SPEEDS FOR
METHANOL AND ISSOCTANE
(Source: Ref. 58)
A-74-1252
142
-------
The fuel economy and emission performance of an internal combustion
engine optimized for operation on methanol is unknown obviously a research
gap. However, a Gremlin modified for methanol by Adleman et al. of
Stanford University almost passed the 1977 Federal Standards without re- '
sorting to exhaust gas; recirculation.1
6.3.1.14 Methylamine
Methylamine is an easily liquefied gas produced from ammonia and
natural gas or methanol (through synthesis gas), and it is a conveniently
handled fuel (except for toxicity). Because methylamine is a condensable
gas, it would require a propane-like fuel system for automotive use. Its
heating value is lower than that of hydrocarbons. No octane ratings exist,
but methylamine has a convenient flash point (0°F).
Methylamine contains chemically bonded nitrogen and there are indi-
cations that bound nitrogen is easily converted to NO . ** Impurities con-
JfL
taining bound nitrogen may be a significant source of NO even in hydrocar-
X.
bon flames. The probability is high that NO formation would be a severe
problem with methylamine.
6. 3. 1. 15 SNG
Because no SNG is now available for automotive tests, performance must
be inferred from experiments with simulated SNG or natural gas.4'21'24
Methane shares the advantages of LPG; i.e. , the fuel is distributed as
a gas. The natural gas fuel system is similar to the LPG fuel system ex-
cept that it needs no evaporator, unless the SNG is stored as a liquid. Cars
designed for natural gas idle more smoothly and have better fuel distribution
and warm-up characteristics than gasoline-fueled cars. They also can be
operated in the same lean region as propane (air/fuel equivalence ratio
greater than 1. 0); see Figures 6-9 and 6-10.
143
-------
£
o>
" 2
1
a:
8 '
O COMPRESSION RATIO 8.6
A COMPRESSION RATIO 12.5
I
I
I
0.9
(Fuel
rich)
I
1.0 I.I 1.2 1.3 1.4
AIR/FUEL EQUIVALENCE RATIO
1.5
(Fuel
lean)
A-74-1255
Figure 6-9. HYDROCARBON EMISSIONS FROM
AN SNG-FUELED ENGINE
(Source: Ref. 4)
3.0
i.o
O COMPRESSION RATIO 8.6
A COMPRESSION RATIO 12.5
I I I
I
I
0.9 1.0 I.I 1.2 1.3 1.4 I.S
(F."' AIR/FUEL EQUIVALENCE RATIO
-------
and because the fuel displaces more intake air. This loss in volumetric
efficiency can be recouped, if the methane is;stored as a cryogenic liquid
and if the air intake manifold is cooled by col$ methane gas before com-
bustion in the engine. 36
6. 3. 1. 16 Naphthas
Only a few engine experiments have been performed with naphthas; the
National Bureau of Standards operated engines on 25% naphtha and 75%
ethanol during World War II. These tests indicated that small amounts of
naphtha could be satisfactorily burned with alcohol. Naphtha's octane num-
ber (50-60) is too low for it to be used alone.
6.3.1.17 Vegetable Oils
Apparently no conventional spark-ignited engines have been run on vege-
table oils. They are not volatile, and in experiments with diesels, some
vegetable oils had to be preheated before being given to the fuel injectors.35
They probably are not suitable for conventional engines.
6. 3. 2 Open-Chamber Stratified-Charge Engines
The open-chamber stratified-charge engine uses high-pressure fuel in-
jection to obtain the following advantages47:
a. Detonation at any compression ratio and fuel/air ratio can be
decreased.
b. Low-octane fuels can be utilized at high compression ratios.
c. Load control can be achieved without air throttling, because
combustion is localized. This feature increases the economy of
part-load operation.
d. The overall lean air/fuel ratios at part load result in good fuel
consumption and constitute an approach to the theoretical limit
of engine efficiency.
The term "stratified charge" comes from the gradient in air/fuel ratios
that exists after injection. The area around the fuel jet is rich because the
fuel is breaking up into fine droplets and evaporating. The air/fuel ratio
varies from ultra-lean (definitely outside the jet) to stoichiometric (where
proper amount of fuel has evaporated) to very rich (definitely inside the jet).
Combustion is initiated by a spark plug, and, in principle, this is the only
difference between stratified -charge and diesel engines.
145
-------
In general, fuels used in stratified-charge engines range from methane to
No. 2 diesel fuel; all fuels in this range give good performance.19 Fuel in-
jection also frees the engine from any volatility concerns. Open-chamber
engines are characterized by high fuel economy (up to 30% better than
comparable carbureted engines46) and lower emissions.
All liquid hydrocarbon fuels (fuel oils, kerosenes, gasolines, naphthas),
except heavy oils, are well-suited to stratified-charge engines. The high
viscosity of heavy oils as well as their ash and sulfur content may make
them impractical as fuel. Gaseous hydrocarbon fuels (methane and propane)
have been used, although no test data a,re available. Note that fuel injection
eliminates the power loss due to displaced intake air usually associated
with gaseous fuels.
Because coal dust is solid, abrasive,and difficult to combust completely
and produces some ash, it probably would not be a good fuel. Hydrazine
also would be impractical because of chemical instability; it could explode
in the fuel injection system.
The suitability of the other fuels for the stratified-charge engine is as
follows:
Acetylene. Acetylene should be a useful fuel; however, the problem
of spontaneous, explosive dissociation must still be solved.
Ammonia. Tests by Pearsall show that anhydrous ammonia could be
used in a high-compression (12-16:1) engine, which should probably
be supercharged to retain a good specific output. 49 No data on em-
missions are available, but ammonia would probably not follow the
pattern of hydrocarbon fuels.
Carbon Monoxide. This fuel probably could be used.
Ethanol. The low energy density and high latent heat of vaporization
could cause problems. Four to five times as much heat must be
supplied to the jet for evaporation (compared with that for a liquid
hydrocarbon fuel). Otherwise, ethanol should be acceptable.
Hydrogen. No test data have been published for stratified-charge
engines, per se. However, Schoeppel's injected Clinton engine is
very similar to the stratified-charge engine, and hydrogen works well
in it. 45> 54 It probably would be a. good fuel.
146
-------
Methanol. Methanol requires about 8 times as much fuel (by volume) for
fuel vaporization purposes as liquid hydrocarbon fuels; this require-
ment would change the injection system requirements considerably.
On the other hand, methanol's lower lean limit of combustion may
extend the combustion zone further away from the core of the injection.
spray, perhaps reducing NO emissions.
X.
Methylamine. Methylarriine could be a good fuel if NO emissions
are not excessive.
Vegetable Oils. Cottonseed oil has been used in diesels and is a good
fuel. 35 If the greater viscosity of vegetable oils (compared with those
of hydrocarbons) is not a problem, they should be a useful fuel.
6. 3. 3 Dual-Chamber Stratified-Charge Engines
The dual-chamber stratified-charge engine was developed specifically
for low emissions. Two combustion chambers are used, each with its own
carburetibn system. Except for the comments on emissions,, the descriptions
from the section on conventional engines (Section 6. 3. l) apply here, also.
6. 3. 4 Diesel Engines
The diesel engine has advantages in emissions and in fuel economy
over other engines. Because they are designed for very high compression
ratios and do not usually throttle intake air, diesels are the most efficient
engines on the road and will probably be so for a long time. The emissions
of a 3500 pound Mercedes Benz automobile as investigated by Southwest
Research Institute and the EPA, approach the 1977 limit. If the 1977 NO
.X
limit is relaxed to 2. 00 grams/mile, the diesel could be within all the
c *j
standards with only modest modifications. Diesels do, however, have a
problem with exhaust odor, which is not currently subject to regulation.
Diesel engines are not insensitive to fuel characteristics. Diesel fuels
should have good "ignition quality; " i. e. , a short delay period, the time
between start of ignition and an appreciable rise in pressure. 65 Some of
the fuels considered here have poor ignition quality and therefore are un-
suitable for use in compression-ignition engines. In general, the best fuels
for diesel engines are the distillate hydrocarbons (fuel oils, kerosene).
Acetylene. Because acetylene has a high heat of combustion per
standard cubic foot, it was investigated as a diesel fuel; it was
found to be impractical. 6S
Ammonia. Ammonia was tested in a compression-ignition engine
and found to be an unsuitable fuel. 49> 59
147
-------
Carbon Monoxide. Carbon monoxide probably is only suitable for use in
dual-fuel engines. In such a case, it would be inducted through the
intake valve, and a high compression ratio could be retained because
of carbon monoxide's high octane number. This would reduce the
volumetric efficiency somewhat, but this is a minor consideration
in diesels except at peak load.
Coal. Dr. Rudolph Diesel at first tried to operate his newly invented
engine on solid fuel (coal). Powdered coal and even sawdust have
been used to run internal-combustion engines in isolated cases. The
elaborate apparatus required to prepare and inject such fuels, together
with the difficulties due to solid residue (ash), have so far prevented
successful commercial application. 65
Ethanol. Alcohols are ndt good fuels for injection into compression-
ignition engines. 65 However, ethanol has been used in conjunction
with residual oils as a power bolster. At a compression ratio of
22:1, up to 36% alcohol was carbureted into the engine where the
heavier fuel was injected. When greater percentages of alcohol were
used, knock occurred. 31
Gasoline. Because of its very low cetane number, gasoline generally
is unsuitable for use in diesel engines. It has been used in divided-
chamber engines, and Ricardo31 was able to run a supercharged
diesel smoothly on an unspecified fuel with a cetane number of 18.
There are no data on emissions.
Heavy Oils. Heavy oils have been burned with alcohol and by adding
ignition accelerators to the fuel. Wear is increased, and ignition
accelerators are expensive. 31 Despite a long-standing economic
incentive for constructing an engine to burn residuals, there has
been no great success with them.
Hydrazine. No data are available on hydrazine. Injection may be
difficult.
Hydrogen. Hydrogen may be an acceptable fuel for diesel engines.
Homogeneous mixtures of hydrogen and oxygen diluted by argon have
been compression-ignited by Karim and Watson.3? No work on in-
jection in compression-ignition engines was found.
LPG. Gaseous fuels are not injected into diesel engines in the same
manner as liquid fuels., Propane, when used in diesel engines, is
inducted with the air and then is compressed and ignited by the injec-
tion of a high-cetane fuel. This scheme is very similar to spark
ignition. 65 Compression ratios are limited to about 14:1. The power
is slightly lower than that from a diesel of the same compression
ratio.36
Methanol. No data were uncovered for methanol in diesel engines.
It should be as unsuitable as ethanol. Alcohols are not good diesel
fuels.65
148
-------
Methyiamine. No reports on methylamine in diesel engines were
found. Injection as a liquid should be possible, but no data on ignition
quality exist.
Natural Gas. Methane is burned in the same way as L.PG.
Naphthas. No data are available for naphthas as diesel fuel. Naphtha
is composed of straight-chain and cyclic molecules, has a moderate
overall octane number, and most probably has a low cetane number.
The gasoline-like components may make naphthas a poor diesel fuel.
Vegetable Oils. Vegetable oils have been used successfully as
diesel fuel. Cottonseed oil has been shown to be a promising fuel
that produced horsepower comparable to that produced by diesel oil.
The corrosion caused by cottonseed oil is about the same as that
for diesel oils. Starting is no more difficult, and engine thermal
efficiency is increased slightly. 35
6. 3. 5 Brayton-Cycle Engines
Gas turbine engines are attractive because they have steady-flow com-
bustion, which is easier to control than Otto-style cyclic combustion. For
this reason, gas turbines have legendary fuel versatility. They were
heavily investigated by Chrysler Corp. in the early 1960's, and 50 experi-
mental models were actually built and tested.
Gas turbines have been run successfully on fuels ranging from methane
to residual oils. 66 Coal has been used in some power-industry applications. 68
Gasoline, kerosene, fuel oils,and diesel oils have been omitted from the
discussion of fuels because the generally available performance figures in
the gas turbine are about the same.
New gas turbine combustion designs are often tested on a variety of
fuels. In the past, few emission data have been taken, but recently for a
development program sponsored by the EPA, emission data were taken.
Ammonia. An ammonia gas turbine engine was built for the Army
in International Harvester's Solar Division. 14 It was found to be
more troublesome than hydrocarbon fuels. The ammonia must be
introduced in the vapor phase; the vaporizer adds to the cost and
complexity of the engine. However, the thermal efficiency of the
engine was about 2. 5% higher, and (apparently by rich running) about
10-20% more power could be extracted from the same engine.
Coal. Coal has been used for stationary applications, but the ash
content must be screened out by several rows of turbine blades,
making the overall engine quite heavy. 69
149
-------
Carbon Monoxide. No data were found on carbon monoxide gas
turbines.
Heavy Oils. Residuals have been used; they have a tendency to
smoke. 6b Requirements for complete combustion might necessitate
an increase in the nominal residence time of the fuel in the combustion
chamber, and this could lead to high NOX emissions.
Hydrogen. In the 1950's, NACA (NASA's predecessor) operated
a gas-turbine engine on hydrogen successfully in an airplane; how-
ever, no data were taken on emissions.41
LPG. In the EPA gas turbine combustion development program,
General Electric used LPG as its check-out fuel. 6T In tests of
continuous combustion systems, propane produces fewer emissions
than liquid fuels. 15
Methanol. In a paper published in June 1973, LaPointe and Schultz39
of Ford Motor Co. report that the use of methanol in gas turbines
gave only about 25% as much nitric oxide as diesel fuel. This dif-
ference is attributed to methanol's lower (by 200°F) peak-combustion
temperature and the strong temperature dependence of the nitric
oxide formation mechanism. Hydrocarbon and carbon monoxide
levels were increased by methanol.
Methane. Gas turbines have been operated on methane, and nitric
oxide emissions are much lower than from propane. 48
We could obtain no published data on the use of acetylene, carbon
monoxide, hydrazine, or vegetable oils !as diesel fuel.
6. 3. 6 External-Combustion Engines
Rankine and Stirling engines depend on heat only. The heat source can
be anything, decaying nuclear isotopes, electrical resistance heat, or, as
in most cases, hot gases from combustion. 68 For this reason, any of the
fuels listed will be satisfactory, providing the external burner is designed
to take into account the proper flow rates, flame speeds, etc. The more
volatile fuels may produce fewer emissions, however.
6.3.7 Fuel-Ceil Power Plants
Theoretically, all 18 potential automotive fuels selected for study could
be used as the fuel for a fuel cell. Fuel cells generally are classified ac-
cording to l) the type of electrolyte or ion-conducting media used and 2) the
operating temperature, as shown in Figure 6-11. With the exception of coal,
which would first have to be gasified, and hydrogen, which is already present
in a usable form, the other 16 potential automotive fuels could be used as the
150
-------
HYDROCARBON
FUEL
REFORM
s
HZ.CO,
C02,
CH4,
ETC.
>
PURIFY
CO
C02
ETC.
HZ
SOLIDOXIDE
CELL
1800° F j
MOLTEN SALT
CELL
ALKALINE
CELL
ACID
CELL
I50J4OO°F
"*
PURIFY
.-AIR
Figure 6-11. FUEL CELL TYPES
hydrocarbon fuel, as shown in the figure. However, considering the
state-of-the-art and historical advancements during the development of
each type of fuel-cell system, the choice of system and applicable fuels is
quickly reduced to only a few easily cracked or reformed hydrocarbons
and to fuel cells containing either acid or alkaline electrolytes.
6.3.7.1 High-Temperature Fuel Cells ^lOOO^)
Dviring the past two decades, numerous programs have been initiated
to commercially develop this type of fuel cell. Cells operating above about
1000°F have basically two desirable features:
a. Hydrocarbon fuels can be utilized directly.
b. Cheap electrocatalysts for the electrodes are possible.
As a result, a great variety of hydrocarbon fuels can be utilized rather
inexpensively either directly or indirectly, as shown in Figure 6-11. How-
ever, numerous undesirable features make their use in vehicular applications
remote; e.g.,
High operating temperature
Low power -to-weight ratio for molten carbonates
* Brittleness of solid oxide electrolyte.
151
-------
The high operating temperature (generally greater than 1000°F) of these
cells is the primary reason that these cells probably will never be used in
automobiles. Unless their temperature is maintained near the operating
level (which would result in very inefficient overall operation in most cases),
the thermal cycling from ambient temperature to operating temperature
causes large, thermally induced stresses of the ceil components, resulting
in failure due to cracking and/or loss of electrochemical activity.
For molten carbonate fuel cells, the additional disadvantage of a low
power-to-weight ratio would result in large, bulky, and unacceptably heavy
power plants. In addition, such a power, plant also requires carbon dioxide
in the oxidant, which would necessitate the recirculation of the anode effluent.
Solid oxide cells that operate at an even higher temperature, 1800°F, have
the inherent disadvantage of extremely thin, fragile, and brittle electrolytes.
These electrolytes must be thin (less than 0. 01 inch thick) to obtain accept-
able performance; therefore the feasibility of fabricating more durable cells
is zero. Asa result, the prospect of using thin, fragile solid oxide cells
operating at 1800°F in a vehicle that is constantly undergoing varying G-forces
(acceleration, deceleration, bumpy roads, impacts, etc.) is very remote.
6.3.7.2 Moderate-Temperature Fuel Cells (l500-600°F)
Tremendous progress has been made on these systems in the last two
decades, mainly as a result of huge Government-sponsored programs aimed
at the development of systems capable of supplying the electrical power re-
quired for space travel. The Gemini series used acid ion-exchange electro-
lyte fuel cells developed by General Electric Co. , and the more recent
Apollo series used alkaline fuel cells developed by Pratt & Whitney Aircraft.
Both systems reached the extremely high levels of sophistication and reli-
ability required for such duty; the reactants (hydrogen and oxygen) were
supplied by cryogenic means. However, both systems are theoretically
capable of operating on a hydrocarbon fuel and air, as shown in Figure 6-11.
Complete purification of fuel and air to free them from carbon dioxide is
difficult but essential if alkaline electrolytes are to be used. Although the
acid system can utilize a hydrocarbon directly, the resulting performance
is generally poor. As a result practical systems require the indirect use
of the fuel, i.e. , either reforming, cracking, or partial oxidation to form
a hydro gen-containing product.
152
-------
At present, only two major fuel-cell-development programs are active.
One program is at Pratt & Whitney Aircraft and the other is a joint program
between Alsthom (a division of the French company, CGE) and Exxon
Corporation. Numerous other smaller programs are being carried out, such as
as those at Union Carbide (U.S.), Shell Oil Ltd. (England), Monsanto (U.S.),
the Institute of Petroleum (France), and Hitachi, Ltd. (Japan).
Because most of the work on fuel cell systems has been done for nonvehic-
ular applications, obtaining a meaningful and accurate component cost
breakdown is very difficult. However, we attempt to estimate some approxi-
mate figures based on the literature information currently available, together
with the following assumptions:
a. Only fuel cells operating near ambient conditions, such as those
containing either acid or alkaline electrolytes, will be available
for use in vehicular applications prior to the year 2000.
b. Fuels will be available in the following order of decreasing desirability:
hydrogen, methanol, ethanol, and methane.
These two assumptions are perhaps more easily discussed with the aid of
Figure 6-11, which shows both the types of fuel cells available and the pos-
sible fuel and oxidant choices. We think the alkaline cell and the acid cell
have the best possibility for vehicular use for two reasons:
a. Their technology is the most advanced.
b. Their overall efficiency of operation would be the highest because
the least amount of heat would be wasted during rest conditions to
keep the cells heated and ready for instant operation and response.
The second assumption (choice of fuels) was made because for vehicular
use fuel cells must operate on hydrogen or an easily reformed hydrocarbon.
#
This constraint is necessary because, at present, no direct hydrocarbon
fuel cell is available with the high performance necessary to satisfy the
weight and volume requirements of vehicular use.
Using these assumptions and ground rules, we have estimated the costs
for the three major subsystems mentioned above based on published infor-
mation; see Table 6-3. This tabulation is purely an estimate based on
laboratory results and vendor quotations for similar hardware applications.
A direct hydrocarbon fuel cell is one that can utilize the hydrocarbon
without a reforming step.
153
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Table 6-3. ESTIMATED FUEL CELL COSTS
Fuel Cell Type
Acid Alkaline
Subsystem
Fuel Pretreatment 25a 50j
Oxidant Pretreatment Not necessary 10
Hydrogen Tank 7-10b 7-10b
Fuel Cell 200-350° 35-85b
50e
Motors and Controls 25-30b 25-30b
Total Cost
Hydrogen/Air 232-390 77-135
Hydrocarbon/Air 250-405 120-175
a Source: Ref. 25.
b Source: Ref. 50.
° Source: Ref. 42.
Because the reformer for an alkaline system also must have a
purifier so that only pure hydrogen enters the cells, we have
estimated that the fuel treatment for the alkaline system will cost
twice as much as that for the acid system. Similarly, because
the oxidant cleanup is rather simple compared to fuel reforming,
we have assumed that the cost of the oxidant pretreatment will be
less than one-half of that of the fuel pretreatment.
e Source: Ref. 38.
Part of the difference in costs for the acid and alkaline systems can be at-
tributed to design: The acid system is designed to operate for 16,000-40,000
hours in stationary power-plant applications, whereas the alkaline system
is designed to operate for much shorter periods of time probably on the
order of 2000-4000 hours in vehicular applications. In any event, although
the wide price range ($77/kW to $405/kW) indicates the uncertainty of the
estimate, it nevertheless demonstrates the rather high costs that can be ex-
pected for fuel-cell power plants in vehicles. For example, the Funk study,50
which was based on using a 16. 6 kW peak power fuel cell to power a Renault 4L
(2090 pounds loaded weight, including approximately 450 pounds of effective
load), estimated that it would cost between 40 and 72% more than a comparable
conventional vehicle. No comparable costs are available for the Kordesch
vehicle, which as an Austin A-40 weighing 2000 pounds and which was powered
154
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by a 6 kW fuel cell and 4kWTir battery (16 kW peak output) in parallel. This
vehicle was actually built and operated for thousands of miles. The range on
one filling of hydrogen was more than 200 miles; its top speed was 55 mph.
Realistic estimates of the thermal efficiency and weight of the propulsion
system are rather difficult because most of the fuel-cell-develbpment work
has been done either for space applications43 requiring extremely reliable,
lightweight (4 lb/kW),and sophisticated systems or for Stationary power
applications27 for which cost is the only concern and weight (20-88 Ib/kW)
and volume are secondary. The fuel cell systems cited above have the fol-
lowing characteristics:
Kordesch38: fuel cell system, 60 Ib/kW, ~50% conversion
efficiency; lead acid batteries, 20 Ib/kW.
Institut Francais Du Petrole50: fuel cell system, 20-33 Ib/kW,
~50% efficiency at full power.
Because of the embryonic stage of development of fuel-cell-powered
vehicles, estimates of maintenance costs would be meaningless at this
time;
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19, 1973.
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15. Cameron, D. J. , "Controlling Liquified Petroleum Gas for a Gas Tur-
bine. " Paper presented at the L-P Gas Engine Fuel Symposium,
Detroit, 1970.
16. Clewell, D. H. and Koehl, W. J. , "Impact of Automotive Emissions
Regulations on Gasoline Demand. " SAE Paper 730515 presented at the
National Automobile Engineering Meeting, Detroit, May 15, 1973.
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As an Engine Fuel," General Motors Research Publication No. G MR-436.
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23-28 (1973) July.
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August 1973.
20. Ebersole, G. D. and Manning, F.S. , "Engine Performance and Exhaust
Emissions, Methanol Versus Isooctane. "SAE Paper 720697.
156
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21. Eccleston, D. B. and Fleming, R.D. , "Clean Automotive Fuel> " Bureau
of Mines Automotive Exhaust Emissions Program Technical Progress
Report 48. Bartlesville, Okla. : Bartlesville Energy Research Center,
February 1972.
22. Finegold, J. , et al., "Hydrogen Asa Fuel for Future Automotive Appli-
cations. " Paper presented at "the Urban Vehicle in the 1980's, "
Washington, D.C., May 7, 1972.
23. Finegold, J. G. et al. , "The UCLA Hydrogen Car: Design Construc-
tion and Performance. " SAE Paper No. 730507 presented at the National
Automotive Engineering Meeting, Detroit, May 14-18, 1973.
24. Flemming, R.D. and A11 sup, J. R. , "Natural Gas As an Automotive Fuel,
An Experimental Study. " Department of the Interior Report of Investi-
gations 7806. Bartlesville, Okla: Bartlesville Energy Research Center,
1973.
25. "Fuel Cells for Conversion of Synthetic Fuels to Electricity, " Section 6
of OST Study. East Hartford, Conn.: Pratt & Whitney Aircraft, 1972.
26. Furlong, L. E. , Holt, E. L. and Bernstein, L. S. , "Emission Control
and Fuel Economy. " Paper presented to the American Chemical Society,
Los Angeles, April 1, 1974.
27. George, J.H. B. , "Electrochemical Power Sources for Electric Highway
Vehicles." Cambridge, Mass.: A.D. Little, Inc., June 1972.
28. Graves, R. L. , Hodgson, J. W. and Tennant, J. S. , "Ammonia As a
Hydrogen Carrier and Its Application in a Vehicle. " Proceedings of the
Hydrogen Economy Miami Energy (THEME) Conference. Coral Gables,
Fla. : University of Miami, March 1974.
29- Gray, J. T, , Jr. et al. , "Ammonia Fuel-Engine Compatibility and Com-
bustion. " SAE Paper 660156 presented at the Automotive Engineering
Congress, Detroit, January 1966.
30. Gupta, R.K. and Graiff, L. B. , "Effect of Exhaust Gas Recirculation
and Ignition Timing on Fuel Economy and Exhaust Emissions of Several
1973 Cars. " Paper presented at the Central States Section of the Com-
bustion Institute, Madison, Wis. , March 26, 1974.
31. Halemann, H. A. et al. , "Alcohol in Diesel Engines, " Automobile Eng. 44,
256-62 (1954) June.
32. Hodgson, J. W. , "Is Ammonia a Transportation Fuel for the Future? "
ASME Paper 73-ICT-65 presented at the Intersociety Conference on
Transportation, Denver, September 23-27, 1973.
33, Holzapfel, G. L. and Pinkerton, J. D. , "Status of Emissions From LPG-
Fueled Engines, " Butane-Propane News 16, 24-26 (1974) January; Part II,
ibid., _6, 29-31 (19T4) February.
157
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34. Hubener, G. J. and Gasser, D. J.., "Energy and the Automobile General
Factors Affecting Vehicle Fuel Consumption. " SAE Special Report SP-383
presented at the National Automobile Engineering Meeting, "Energy and
the Automobile, " Detroit, May 1973.
35. "Indian Vegetable Fuel Oils for Diesel Engines, " Gas Oil Power 37_,
80-85 (1942) May.
36. Institute of Gas Technology, "Emissions: Reduction Using Gaseous Fuels
for Vehicular Propulsion, " Final Report on EPA Contract No. 70-69,
IGT Project 8927. Chicago, June 1971.
37. Karirri, G.A. and Watson, H.C., "Experimental and Computational Con-
siderations of the Compression Ignition of Homogeneous Fuel-Oxidant
Mixtures," SAE Paper No. 710133, SAE Trans. 80, 450 (1971).
38. Kordesch, K. V. , "Hydrogen-Air/Lead Battery Hybrid System for Ve-
hicular Propulsion, " £.JEl£c_tr^h^m._Soc_. 118, 812-17, (1971) May.
39. LaPointe, C.W. and Schultz, W. L. , "Comparison of Emission Indexes
Within a Turbine Combustor Operated on Diesel Fuel or Methanol. " SAE
Paper No. 730669 presented at National Powerplant Meeting, Chicago,
June 18-22, 1973.
40. Laweason, G. C. and Finigan, P. F. , "Ethyl Alcohol and Gasoline as
a Modern Motor Fuel, " in SAE Publication SP-254, Alcohol as Motor
Fuel.
41. Lockheed Aircraft Corp. , Burbank, Calif., private communication,
May 15, 1973.
42. Martin, C. , "Apollo Spurred Commercial Fuel Cell, " Aviat. Week Space
Technol. W, 56-59 (1973) January 1.
43. "Megawatt Fuel Cells for Aerospace Application, " in 25th Power Sources
Symposium. Red Bank, N. J. : PSC Publications, May 1972.
44. Merryman, E. L. et al., "Recent Studies of the Conversion of Fuel
Nitrogen to NOjj. " Paper presented to the Central States Section of the
Combustion Institute, Madison, Wis. , March 26, 1974.
45. Murray, R. G. and Schoeppel, R. J. , "Emission and Performance Char-
acteristics of an Air-Breathing Hydrogen-Fueled Internal Combustion
Engine." Stillwater, Okla. : Oklahoma State University, n. d.
46. National Academy of Sciences, Interim Standards Report by the Com-
mittee on Motor Vehicle Emissions to EPA, Washington, D. C. ,
April 26, 1972.
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Scranton, Pa. : International Textbook Co. , 1952.
158
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48. Parikh, P.G., Sawter, R.F. and London, A.L. , "Pollutants From
Methane Fueled Gas Turbine Combustion. " ASME Publication 72-WA/GT-3,
November 1973.
49. Pearsall, T. J. and Garabedian, C.G., "Combustion of Anhydrous Ammonia
in Diesel Engines- " SAE Paper 670947 presented at the Combined Fuels
and Lubricants, Power Plants and Transportation Meetings, 1967.
50. "Problems Related to the Marketing of H2/Air Cell Urban Vehicle, "
Institut Francais Du Petrole, August 1972.
51. Puckett, A.D. , "Knock Ratings of Gasoline Substitutes, " National Bureau
of Standards Research Paper RP 1673 . J. Res. Nat. Bur. Std. 35,
273-84 (1945) October.
52i Raggio, D. G. , "Stratified Charge Engine Development. " Paper presented
at the Sixth E. P. A. Contractors Coordination Meeting, Ann Arbor, Mich. ,
October 16, 1973.
53. Sawyer, R.F. et al. , "Oxides of Nitrogen in the Combustion Products of
an Ammonia Fueled Reciprocating Engine. " SAE Paper 68041 presented
at the Mid-Year Meeting, Detroit, May 1968.
54. Schoeppel, F. J. , "Prospects for Hydrogen Fueled Vehicles, " at 163rd
National Meeting, ACS Div. Fuel Chem 16, 135-42 (1972) April 10-14.
55. Sorem, S. S. et al., "Gaseous Motor Fuels An Assessment of the
Current and Future Status. " Paper presented to the Symposium on
Current Approaches to Automobile Emission Control, ACS Meeting,
Los Angeles, March 1, 1974.
56. Springer, G. S. and Patterson, D. 3. , Exhaust Emissions. New York;
Plenum Press, 1973.
57. Springer, K. J. , "The Low Emission Car for 1975 - Enter the Diesel, "
Proceedings of the 8th Intersociety Energy Conversion Conference,
282. New York, American Institute of Aeronautics and Astronautics,
1973.
58. Starkman, E.S. , Strange, F. M. and Dahm, T. J. , "Flame Speed and
Pressure Rise Rates in Spark Ignition Engines, " SAE Publication 83V-1,
July 1959.
59. Starkman, E.S. , James G. E. and Newhall, H. K. , "Ammonia as a Diesel
Engine Fuel: Theory and Application. " SAE Paper 670946 presented at
the Combined Fuels and Lubricants Powerplant and Transportation Meet-
ings, Pittsburgh, November 1967.
60. Starkmen, E. S. et al. , "Ammonia as Spark Ignition Engine Fuel,
Theory and Application, " SAE Trans. 75, 765 (1967).
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159
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62. Starkman, E. S. et al. , "Alcohols as Motor Fuels. Comparative Per-
formance of Alcohol and Hydrocarbon Fuels, " SAE Special Publication
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Using Hydrogen Supplemented Fuel. " Research Publication GMR-1537
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160
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7. ENVIRONMENTAL EFFECTS AND RESOURCE DEPLETION
7. 1 Environmental Effects
The comparison of environmental effects due to most alternative fuel
systems is necessarily incomplete at the present state of technology. A
fuel system is composed of resource extraction, fuel synthesis, trans-
portation and storage, distribution to the vehicle, and fuel utilization in
the vehicle power plant. To evaluate alternative fuel systems from the
aspect of environmental damage, each system component should be char-
acterized and the overall effect determined.
The environmental damage caused by the introduction of waste heat and
material pollutants or waste products depends on the fuel synthesis process,
the fuel-handling and -delivery system, and the general performance of
the automotive power plant. For a given production level, synthesis
pollutants, such as sulfur, can vary by a factor of at least 5, depending
on the type of coal used. The volume of shale residue can vary by a
factor of 3, depending on the grade of shale and the efficiency (recovery)
of the process.
In general, we do not recommend that pollution due to a system com-
ponent be developed into a selection criterion because this component
cannot indicate overall pollution or resource depletion effects. The
exception to this is the use of coal (solvent-refined) in vehicle engines.
We cannot deal with total environmental pollution (which should be a
selection criterion) because the efficiencies, emissions, and performances
of the various system components arq not known with precision. In most
cases, estimates of these would be conjecture.
7. 1. 1 Fuel Consumption and Emissions
The environmental effects of potential alternative fuel systems are
impossible to assess. For most cases, the efficiency and emissions are
not known accurately or precisely (with a stated degree of error).
Approximations or estimates contain biases and cannot allow for the use
of emission control devices installed on engines.
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7. 1. 1. 1 Efficiency
For the vast majority of engine-fuel combinations, efficiencies have
not been measured. Therefore, the specific fuel consumption and the
quantity of exhaust can only be estimated from a fuel's chemical and
(presumed) combustion properties. The EPA is now measuring fuel con-
sumption for conventional (Otto cycle) engines and for diesel engines.
Performance in stratified-charge engines will soon be known, but per-
formance in Brayton, Rankine, and Stirling cycle power plants can only
be estimated. There are reports on several alternative fuels in (modified)
engines, e. g. , ammonia, ethanol, methanol, hydrogen, methane, and
LPG in spark-ignited internal combustion engines. Information on these
fuels was presented in Section 6. These data can be used to characterize
these combinations, but cross comparisons with unmeasured combinations
are without precision. Therefore, any selection criterion based on the
efficiency of various fuel-engine combinations is indeterminate at this
time.
7. 1. 1. 2 Exhaust Emissions
For the various fuel-engine combinations, emissions have not been
measured, except for specific cases, e. g. , ammonia, ethanol, methanol,
hydrogen, methane, and LPG iii spark-ignited internal combustion engines.
Complete cross comparisons are not valid because emissions from un-
measured combinations are conjecture. Further, the uncertain future of
automobile emission regulations and the potential use of emission control
devices make even the measured pollutant levels less of a determinant.
Therefore, fuel-engine emissions cannot be used to conclusively aid in the
selection of alternative fuels at this time.
7. 1. 1. 3 Coal Emissions
The synthetic liquid and gaseous fuels that are potential alternative
automotive fuels contain one or more of the following elements: carbon,
oxygen, hydrogen, and nitrogen. The combustion products are either
nonpollutants (carbon dioxide, water), or they are pollutants that can be
reduced to acceptable levels by emission control devices (carbon monoxide,
NOX, hydrocarbons). Such control devices are now under development*.
162
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Coal itself is not a synthetic fuel, and in natural occurrence it con-
tains carbon, oxygen, hydrogen, nitrogen, sulfur, ash, mercury, and
other heavy metals (chlorides and oxides). If the coal is solvent-refined,
some polluting materials are removed, but much remains. The content
of solvent-refined coal is sensitive to the raw coal content. Table 7-1
shows a typical analysis of the common elements in solvent-refined coal.
Table 7-1. SOLVENT-REFINED COAL
(Pittsburgh and Midway Coal Mining Co. )
Typical Products
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Moisture
Heating Value
Raw Coal
70.7
4. 7
1. 1
3.4
10.3
7.1
2.7
12, 800 Btu/lb
Solvent -Refined
Coal
art- "f
88.2
5.2
1.5
1.2
3.4
0.5
--
15, 800 Btu/lb
If the solvent-refined coal were combusted in a vehicle engine, the
following products would have to be contained to prevent environmental
damage (in addition to carbon monoxide, NO , and hydrocarbons).
X.
Sulfur dioxide (gas), 7-8 grams/mile (Table 7-1)
Ash (silicon dioxide, aluminum oxide, ferric oxide, and calcium oxide
solids), 3-5 grams/mile (Table 7-1)
Metals: trace vanadium and mercury.
In conclusion, we consider solvent-refined coal to be a speculative
alternative fuel on environmental grounds. It is eliminated in the near
term because of a technology gap in the on-board vehicle control of
emissions.
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7. 1. 2 Synthesis Plants and Effluents
From Section 3, the probable energy/material resources are coal and
oil shale, and the additional possible resources are nuclear and solar
energy. The types of pollution for fuel systems vary according to the
resource.
7.1.2.1 Coal to Clean Fuelg
Process characterizations for clean liquid and gaseous fuels from coal
are described in Appendix B and in Section 5. Table 7-2 lists the poten-
tial pollutants from coal for a gasification plant producing 250 million
CF/day (240 X 109 Btu/day) of pipeline gas from Illinois No. 6 coal
(3. 7% sulfur).
Table 7-2. POLLUTION FROM COAL PROCESSING
(250 Million CF/Day SNG Plant)
Pollutants Range of Emissions
Sulfur (Primarily as Hydrogen Sulfide) 300-450 tons/day
Ammonia 100-150 tons/day
Hydrogen Cyanide 0 to possibly 1 ton/day
Oil and Tars Trace tp 400 tons/day
Mercury Less than 5 Ib/day
Ash Residue 1000-3000 tons/day
Ranges are given in Table 7-2 because of variations among gasification
processes and because of the uncertainties in some yields. A plant pro-
ducing 250 million CF/day of pipeline gas (250 X 109 Btu/day) consumes
between 12, 000 and 22, 000 tons/day of coal, depending on the process and
the rank of the coal.
7.1.2.2 Oil Shale to Clean Fuels
Section 5 contains information on process routes to clean liquid and
gaseous fuels from oil shale. The total quantity of potential emissions
for an oil shale plant producing 50, 000 bbl/day of oil (280 X 109 Btu/day)
from 30 gal/ton of oil shale are shown in Table 7-3. Appendix B contains
more details.
164
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Table 7-3. POLLUTION FROM OIL SHALE PROCESSING
(50, 000 bbl/Day Shale Oil Plant)
Pollutants Emissions
Sulfur (Primarily as Hydrogen Sulfide) About 150 tons/day
Ammonia About 150 tons/day
Spent Shale About 47, 000 tons/day
7. 1. 2. 3 Nuclear and Solar Energy
Nuclear plants and the pollutants associated with them are discussed
in Section 5. Solar energy conversion, in general, is the least polluting
conversion process, but a usable automotive fuel is not the direct product;
a chemical fuel must be synthesized from steam, electricity, or plant
growth (crops). Except for electrolysis of water to produce hydrogen
(and oxygen), material as well as thermal pollution result. Qualitatively,
pollutants from nuclear and solar processes are as follows:
Nuclear Plants: gaseous and solid nuclear fission products of various
half-lives; fissile uranium and plutonium, tritium and
induced radioactive isotopes; and waste heat
Solar Plants: despoiled land area, concentrated waste heat, and
agricultural wastes;
Within the scope of this study, quantitative comparisons cannot be
made among such things as shale residue, coal ash, fission products, and
acres of land devoted to solar collectors or crops. The types of environ-
mental effects are different, and ecological damage occurs to varying
degrees. Further, future technology development for land reclamation and
waste treatment or containment will alter these pollution effects in an
unpredictable manner. Moreover, these environmental effects are only
a few of those attributable to an alternative fuel system. Hence, selection
criteria for fuel systems based on synthesis plant pollution would be in-
complete and would lack objectivity, although subjective judgments might
be made.
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7. 2 Resource Depletion
To determine whether large differences in resource depletion are
required by the candidate fuels using coal and oil shale resources, we
formulated and calculated three resource depletion models by using
reasonable efficiencies for fuel production and utilization. Because some
coal-to-fuel processes are more efficient than others, some fuels require
smaller amounts of resources to satisfy automotive demand. In addition,
fuel comparison is complicated by the by-products of fuel synthesis.
Some processes produce substantial amounts of by-product fuels (e.g.,
oils or high-Btu gas) with wider uses than the raw material, whereas
other processes have by-products with little or no thermal use (e. g. ,
waxes, tars, or ammonia). Heavy fuels, such as residual oils, can be
burned in fossil-fueled central power stations as low-sulfur replacements
for coal, so the coal demand is reduced by a factor of 1. Tars and
ammonia, on the other hand, were not assumed to reduce the demand
for coal.
For comparison, then, we have set up a simplistic model of U.S.
coal consumption for 1985 and ZOOO. These years were chosen because
the synthetic fuel industry will be ope.rating on a large scale by then.
The following assumptions were made:
1. The demand for automotive transportation energy was established by
Model I as 20.0 X 1015 Btu in 1985 and 30.3 X 1015 Btu in 2000.
Also, methanol-fueled automobiles were assumed to be 10% more
efficient than hydrocarbon-fueled cars, and the use of hydrogen in
vehicles was assumed to be 30% more efficient. For comparison,
the calculation also was made for 1985 by using Model II assumptions
(automotive energy demand = 19.1 X 1015 Btu). Note that Model II,
although it assumes a greater total energy demand and supply, allows
for large, post-1985 imports; thus, the amount of coal mining in
Model II is actually less than that in Model I.
2. To accentuate the differences, we assumed that all automotive re-
quirements would be met with shale- and coal-derived fuels.
3. Quantities of by-product fuels were obtained from process flow sheets.
(These processes are described briefly in Section 5 and summarized
in Tables 5-1 through 5-6. Very detailed process descriptions are
presented in Appendix B. ) Low-Btu gas and heavy oils made as by-
products of synthetic fuel production were credited against coal de-
manded by electrical generation and other coal-burning industries.
These needs were estimated by Models I and II. Ammonia, phenols,
tars, and waxes were assumed to be of no heating value because they
would probably not be used as fuels.
166
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4. The process synthesis efficiencies are taken from the descriptions
cited in 3 above. These efficiencies are not overall energy effi-
ciencies. They are the efficiencies with which the processes produce
the individual products or by-products. They are the ratio of the
heating value of the particular product to the total energy input to
the process. Hence, by-product synthesis efficiencies are inherently
low.
5. Production of oil from oil shale was limited to 1. 0 X 106 bbl/day in
1985 and 3. 5 X 106 bbl/day in 2000. The balance then was filled in
with coal liquids. The assumed oil shale assay was 25 gallons of
oil per ton of shale.
For each fuel, we have used this model together with the fuel-synthesis
product and by-product lists from Appendix B to calculate the total amount
of coal or oil shale that must be mined to meet the demands of gasifica-
tion, automotive fuel, and industrial and electrical needs for coal. A
representation of the model appears in Figure 7-1. The calculations made
appear in Tables 7-4, 7-5, and 7-6 and are summarized in Tables 7-7
and 7-8.
MINED
COAL
OR
OIL
SHALE
COAL
COALO
COAL TO
SNG
t
HIGH-Btu GAS
HIGH-Btu GAS
NAPHTHAS "1 TO HIGH-Btu GAS
LIGHT OILS/ AT 85% EFFICIENCY
R
OIL SHALE
COAL
*
COAL OR OIL
SHALE TO
AUTOMOTIVE FUEL
AUTOMOTIVE FUEL
1 1
T
RESIDUAL OILS
AND LOW-Btu GAS
1
ELECTRICAL AND
INDUSTRIAL DEMAND
FOR COAL
AMMONIA, TARS,
WAXES, PHENOLS,
ETC.
HEAT AND
ELECTRICITY
A-74-1259
Figure 7-1. SCHEMATIC DIAGRAM OF
RESOURCE DEPLETION MODEL
167
-------
Table 7-4. RESOURCE DEPLETION IN 1985 ACCORDING TO MODEL I
oo
Fuel
LSNG From Coal by
Lurgi Process
Methanol by Koppers
Totzek, ICI Processes
Coal to Gasoline and
Distillate Oils by
CSF Process
Coal to Liquid
Hydrogen
Oil Shale to Gasoline
and Distillate Oils
Use
Automobile fuel
Coal and oil from coal
(industrial and electrical)
Automobile fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Additional coal for
automotive fuel
Coal to residual oil
Demand,
1015 Btu
20. 0
26.5
18. 0
26. 5
20. 0
26.5
15.4
26.5
1.9
26. 5
18. 1
Synthesis
Efficiency, %
47.2
5.9
40. 0
--
44. 8
15.4
35 (est)
--
59.4
5.7
44. 8
15.4
By-product Demand for
Credit Coal
in15 P«-n
42.4
2.50 24.0
45. 0
26.5
44. 6
6.87 19.6
44. 0
26.5
..
0.18 20.3
40.4
6.22
Demand for
Coal
Total Coal
Demand
~^v
2. 04
1. 15
2.16
1.27
2. 14
0. 94
2.12
1.27
0. 58 (shale)
0. 97 (coal)
1.94 (coal)
3.19
3.43
3. 08
3.39
3.49
(coal and
oil shale)
B-94-1696
-------
Table 7-5. RESOURCE DEPLETION IN 2000 ACCORDING TO MODEL I
Fuel
LSNG From Coal by
Lurgi Process
Methanol by Koppers
Totzek, ICI Processes
Coal to Gasoline and
Distillate Oils by
CSF Process
Coal to Liquid
Hydrogen
Oil Shale to Gasoline
and Distillate Oils
Use
Automobile fuel
Coal and oil from coal
Automobile Fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Automobile fuel
Coal and oil from coal
Additional coal for
automotive fuel
Coal to residual oil
Demand,
1015 Btu
30. 3
34.2
27. 3
34.2
30. 3
34.2
23.3
34.2
6.7
34.2
23. 6
Synthesis
Efficiency, %
47.2
5.9
40.0
--
44.8
15.4
35 (est)
--
59.4
5.7
44.8
15.4
By-product
Credit
1 n!5
3.79
. ..
--
--
10.41
--
--
--
0. 64
8.11
Demand for
Coal
TMni
64.2
30.4
68. 3
34. 2
67. 6
23. 9
66. 6
34.2
--
25.4
52.7
Demand for
Coal
1 nq
3. 09
1.46
3. 28
1. 64
3.25
1. 14
3. 20
1. 64
2. 02 (shale)
1. 22 (coal)
2. 53 (coal)
Total Coal
Demand
A
4. 54
4. 92
4. 39
4.84
5.77
(coal and
oil shale)
B-94-1697
-------
Table 7-6. RESOURCE DEPLETION IN 1985 ACCORDING TO MODEL II
-j
o
Fuel
LSNG From Coal by
Lurgi Process
Methanol by Koppers
Totzek, ICI Processes
Coal to Gasoline and
Distillate Oils by
CSF Process
Coal to Liquid
Hydrogen
Oil Shale to Gasoline
and Distillate Oils
Use
Automobile fuel
Coal and oil from coal
(industrial and electrical)
Automobile fuel
Coal and oil from coal
(industrial and electrical)
Automobile fuel
Coal and oil from coal
(industrial and electrical)
Automobile fuel
Coal and oil from coal
(industrial arid electrical)
Automobile fuel
Coal and oil from coal
Additional coal for
automotive fue 1
Coal and oil from coal
(industrial and electrical)
Demand,
1015 Btu
19.1
23. 7
17.3
23. 7
19.1
23.7
14.7
23. 7
1.9
23.7
17.2
Synthesis
Efficiency, %
47.2
5.9
40. 0
--
44. 8
15.4
35 (est)
--
59.4
5.7
44. 8
15.4
By-product Demand for
Credit Coal
1 fU 5 Tt4-n
40.5
2.39 21.3
43.2
23.7
43. 6
6.57 17.1
42.0
. . -- 23.7
..
0.18 17.6
38.4
5.91
Demand for
Coal
i n9
1.95
1.02
2.08
1.14
2. 05
0.82
2. 02
1. 14
0.58 (shale)
0. 85 (coal)
1.84 (coal)
Total Coal
Demand
A
2.97
3.22
2.87
3.16
3. 27
(coal and
oil shale)
B-94-1698
-------
Table 7-7. SUMMARY OF RESOURCE DEPLETION
IN 1985 AND 2000 ACCORDING TO MODEL I
Coal Mined
Fuel
Gasoline, Distillates
From Coal
Methanol From Coal
LSNG From Coal
Liquid Hydrogen From Coal
Gasoline and Distillates From
Oil Shale*
Coal
1985 2000
-409 tons/yr
3.08
3.43
3.19
3.39
4.39
4.92
4.54
4.84
2.02
3. 75
5. 77
See assumption 5.
Table 7-8. SUMMARY OF RESOURCE DEPLETION
IN 1985 ACCORDING TO MODEL II
Fuel
Gasoline, Distillates
From Coal
Methanol From Coal
LSNG From Coal
Coal to Liquid Hydrogen
Gasoline and Distillates From
Oil Shale*
Coal
Coal Mined,
109 tons/yr
2. 87
3.22
2.97
3. 16
0. 58
2. 69
3.27
See assumption 5.
171
-------
Note that the quantities given in Tables 7-4 through 7-7 are based on
particular processes for fuel synthesis, and we have taken into account
certain differences in fuel utilization efficiencies (according to assump-
tion 1).
In conclusion, some differences in the amount of resource depletion
will occur, depending on the alternative fuel that is synthesized. There
is a definite indication that about 10% more coal would be required to
support methanol synthesis (versus gasoline and distillate oil synthesis),
regardless of the time frame. SNG production (including liquefaction)
requires slightly more coal than liquid-hydrocarbon-fuel production but
less coal than hydrogen production. For the processes and products con-
sidered, the largest total mining requirements would occur if oil shale
is used for gasoline and distillate oil synthesis and coal is used solely
for methanol synthesis. When gasoline and distillate hydrocarbons are
the synthesized fuels, the inclusion of oil shale as an energy and material
resource decreases coal-mining requirements by 5-15%, but increases
overall mining requirements by 15-30%.
172
-------
8. ALTERNATIVE FUEL SYSTEM ECONOMICS
A complete cost assessment of an alternative fuel for automotive use
comprises the costs of the following system components:
Resource extraction and delivery
Fuel synthesis plant operation
Fuel transmission, storage, and distribution ( including service station)
Fuel utilization costs ( in the vehicle) .
For this study, the economic assessments have been made in two tiers.
The first tier, denoted as "preliminary" costing, has been performed for
most of the potential fuels those that seemed possible after consideration
of natural resource availability and fuel properties and safety. We have made
the second-tier effort for the most promising, or "candidate," alternative
fuels after an initial fuel selection had been made. The methodology of
Section 2 (based on preliminary costs) was applied to determine these
candidate fuels. We have not considered excise or road taxes for fuels.
For the first tier, the cost ranges (in 1973 dollars) have been determined
by using a simplified DCF costing procedure. Some guidelines of this pro-
cedure are as follows:
a. The capital cost for the processes involved is obtained by a search of
the literature or by an estimation based on similar industrial plants.
b. An annual operating cost of 20% of the capital cost is determined,
together with return on investment, depreciation, maintenance, opera-
ting labor, operating supplies, insurance, and taxes.
c. An additional operating cost is assigned for the cost of the resource base
and utilities supplied.
d. Items b and c are combined to obtain the total estimated operating cost.
From this total and the plant throughput, a unit production cost for the
fuel is obtained.
. Raw material costs assumed are coal, 25^-35^/106 Btu ($6. 25-$ 8. 25/
ton) ; water, 10^-30^/1000 gal; oil shale, $1.00/ton; and nuclear heat,
60^/million Btu.
173
-------
The cost estimates from this procedure are based largely on data pub-
lished during 1965-73, and a simplistic (but uniform) financing model has
been applied. Proponents of various energy conversion methods are often
overly optimistic in their economic assessments. They tend to under-
;
estimate such important costs as charges for interest, labor, and utilities
and to overestimate energy efficiencies. To develop an alternative fuel
system and to construct and operate the synthesis plants, present-day
costs would significantly exceed those listed in Table 8-1. These more
realistic considerations have been ma.de in our second-tier costing effort
for the candidate fuels.
8. 1 Costs of Resource Extraction and Fuel Synthesis (Preliminary)
The raw material costs assumed are typical of those in the recent litera-
ture. The costs for raw material extraction have been determined by a
survey of current mining costs for coal or oil shale. These costs will
increase in future time frames, excluding inflation; the cost of oil shale
mining, which is now much lower than that of coal, will rise as deeper or
lower-oil-content shale must be mined. Future costs of strip-mined oil
shale may exceed those of coal (per Btu) , and the small price advantage
shown for oil- shale -based fuel systems in Table 8-1 will disappear and even-
tually become reversed. The rate of raw material supply is based on an
estimate of the process energy efficiency. Ethanol synthesis costs are
determined from the work of Miller11 in producing industrial alcohol from
wheat and from Hanson et al. ,7 who consider two processes using corn.
For methanol from wood chips, we assume wood chip costs (including land
charges, growing and harvesting costs, and chipping) to be approximately
those of Szego and Kemp. 22
From a refining standpoint, the syncrude produced from coal or oil shale
has much the same properties as conventional crude oil. Existing refineries
can treat it with only small modifications. For refining cost estimation,
the methodology outlined in articles in the Oil and Gas Journal by Nelson13'l4
has been used. Additional operating costs have been obtained from
Grigsby et al. 6
The average current refining costs for gasoline and distillate oils are
about 7^-14#/gal. The cost of liquefying hydrogen has been obtained from
the data of Johnson. 9
174
-------
Table 8-1.
Resource Base,
Synthetic Fuel
COMPARISON OF FUEL-SYSTEM ECONOMICS (Ex-vehicle) FOR PRELIMINARY
COSTS OF POSSIBLE ALTERNATIVE FUELS (1973 Dollars)
Resource Extraction
and Fuel Synthesis
Refining or Processing
$/\Ob Btu
Transmission and
Distribution
Total Cost
Coal
Gasoline 0. 95-1. 25
Distillate Oils 0.95-1.25
Methanol 1.40-1.60
Methane (SNG) 0.95-1.50
Liquid SNG 0. 95-1. 50
Hydrogen Gas 1.20-1.90
Liquid Hydrogen 1.20-1.90
Hydrogen Hydride 1.20-1.90
Synthetic LPG 0.95-1. 25
Oil Shale
Gasoline 0.70-1.00
Distillate Oils 0.70-1.00
Methane ( SNG} 1.15-1.60
Liquid SNG 1. 15-1. 60
Synthetic LPG 0.70-1.00
Nuclear Energy (Water)
Electrolytic Hydrogen Gas 3.20-3.80
Liquid Hydrogen 3.20-3.80
Hydrogen Hydride 3.20-3.80
Thermochemical Hydrogen Gas 1. 75-2. 25
Liquid Hydrogen 1. 75-2. 25
Hydrogen Hydride 1.75-2.25
Solar Energy (Agriculture)
Ethanol ( 190 proof)
$1.00-$3.00/bu wheat, 7.25-17.50
200 proof 7. 25-17. 50
$1. 00-$2. 00/bu corn, 6.50-10.80
200 proof 6.50-10.80
Methanol
$1. 15-$1. 40/106 bu pulpwood chips 2. 30-2. 65
0. 75-0. 85
0. 40-0. 50
0. 85-0. 95 (liq)
1. 60-1. 80 (liq)
Hydride at distribution
0. 85-1.00
0. 95-1. 05
0. 5O-0. 60
0. 85-0.95 (liq)
1. 05-1. 20
1. 60-1.80 (liq)
Hydride at distribution
1. 6O-1. 80 ( liq)
Hydride at distribution
0. 25-0. 35
0.25-0. 35
0. 20-0. 30
1. 00-1. 20
1.00-1. 20
2.00-2.40
1.60-1.80
1.90-1. 65
4. 80-5. 40
2. 10-2. 50
3. 40-3. 75
1. 35-1.60
1.00-1. 20
1.00-1. 20
1.60-1. 30
1. 90-1. 65
1. 35-1.60
4. 80-5.40
2. 10-2. 50
3.40-3. 75
4.80-5.40
2. 10-2. 50
3.40-3. 75
1. 50-1.80
1. 50-1. 80
1. 50-1. 80
1.50-1.80
2.00-2.40
2. 70-3. 30
2. 35-2.95
3.40-4.00
2.55-3. 30
3. 20-4. 10
6. 00-7. 30
4.90-6. 20
4. 60-5. 65
3.15-3. 85
2. 65-3. 25
2. 20-2.80
2. 75-3.40
3.40-4. 20
3. 10-3.80
8. 00-9. 20
6.90-8. 10
6.60-7.55
6. 55-7.65
5. 45-6. 55
5. 10-6.00
8.75-19. 30
9.00-19. 65
8. 00-12. 60
8.25-12.95
4. 50-5. 35
B-104-1813
-------
8. 2 Fuel Transmission and Distribution Costs (Preliminary)
The cost of transporting these products between the refinery and final
consumer outlet and handling them depend on the volume handled, the distance
from the refinery to the consumer outlet, and the mode of transportation
(pipeline, railroad tank car, or tank truck) .
The resource bases of coal and oil shale are located predominantly in the
Western U.S. The synthesis plants for syncrude, SNG, methanol, and other
products will be in this region also. The major processing and market areas
lie in the Midwest and along both coasts. Therefore, the output from these
plants will have to be shipped from 600 to 1800 miles to reach the major con-
suming centers. (See Figure 8-1.)
Western |*oit w.
' (Oal | Houston
Figure 8-1. DISTANCES TO MAJOR COAL MARKETS
(Source: Ref. 31)*
The major product pipeline costs from $300 to $800/bbl-calendar day
( cd) of capacity. Figures published by the Explorer Pipeline Co. for its
28 and 26-inch lines from the Gulf Coast to Chicago are $550/bbl-cd.
Terminal capital requirements depend on size, but fall in a range of $100-
$200/bbl. Tank trucks of 8500-gal capacity cost approximately $40,000 and
can deliver 10 million gal/yr. Their capital requirements are estimated to
be $60/bbl-cd of capacity.
s'c
'Reprinted with permission from the Oil and Gas Journal, ©1973.
176
-------
Service-station capital investment depends on the site, capacity, type of
service, and other factors. The capital investment ranges from $2000 to
$ 8000/bbl-day. A 50,000 gal/month sales volume per unit would require a
base investment of approximately $160,000, using an average of $4,000/bbl-
day capital requirement.
Liquid fuels such as methanol and ethanol would be transported, stored,
and handled in a manner similar to that for gasoline and diesel fuel. There-
fore, the cost estimates for marketing the latter have been used; adjustments
have been made for the volumes needed to deliver the same energy require-
ments.
IGT has estimated the transmission costs associated with hydrogen in its
report A Hydrogen-Energy System;? published by the American Gas Associa-
tion. A summary is shown in Table 8-2.
Table 8-2. HYDROGEN TRANSMISSION COST
Pipeline
Diameter, in.
Natural Gas
(100 miles)
~ 1. 14
~ 1.00
-0.91
Hydrogen
( 65 miles)
iH 1 n& Tn-n
-------
Table 8-3. DATA FOR PRELIMINARY COSTS
OF FUEL TRANSPORTATION (Source: Ref. 4)
Form of Energy
Means of
Transportation
Transportation cost
per 100 miles
^/Million BtuMills/Kwhr
Oil
Natural gas (gas)
Natural Gas (liquefied)
Tanker ship
Pipeline
Barge (average)
Railroad tank car
(average)
Truck (average)
Pipeline
Tanker
Barge
Railroad
0. 1 to 0.5
0. 04 to 1. 6
0. 5
4.3
7. 4
1. 1 to 1.4
0. 5 to 0.9
0.6
2. 7
0.01 to 0.05
0. 04 to 0. 16
0.05
0.43
0. 74
0. 11 to 0.24
0. 05 to 0. 09
0. 06
0.27
178
-------
Total compression and service costs would depend on the volume of gas
sold and the type of installation. Dual Fuel Systems'has estimated an average
cost for compressing natural gas at 7^-9^/100 CF for fleet users.
8. 3 Fuel Utilization Costs
As with environmental effects, costs at the station-vehicle interface are
only part of the system. A complete fuel selection criterion is based on the
cost per mile driven by the consumer. Calculation of this cbst entails fuel-
engine efficiency, vehicle weights, and vehicle fuel tankage costs, as well
as the fuel cost at the service station-vehicle interface. We have found
that considerable effort is required for these estimates and calculations
because they involve a mix of measured, approximated, and assumed values.
The conclusions drawn from these calculations have not been used in the
fuel selection procedure.
The details of these calculations are beyond the scope of this report.
In summary, using EPA-reported efficiencies, an EPA mileage-versus-
weight correlation, and our estimates of vehicle weights and efficiencies
with unconventional power plants, we have obtained the cost-per-mile esti-
mates shown in Table 8-4. Regardless of engine type and ignoring differences
in engine costs, four important conclusions result:
1. Agricultural ethanol costs about 3 times as much as the other candidate
fuels ( except hydrogen) ; this conclusion also is indicated by the first-
tier costs in Table 8-1.
2. Although hydrogen in Table 8-1 is about 3 times as expensive as the
other candidate fuels (except ethanol) , it is only about 2 times as
expensive in cost per mile ( Table 8-4) . Further, liquid hydrogen is
cheaper than a metal hydride (e. g. , Mg2NiHx, a lightweight hydride),
and this is not shown by the preliminary costs in Table 8-1.
3. LSNG costs more than methanol, as shown in Table 8-4, but it costs
less than hydrogen. ,
4. Operation on distillate fuels from coal or oil shale (particularly the
diesel) is decidedly the cheapest fuel system.
179
-------
Table 8-4. ESTIMATED CONSUMER COSTS FOR ALTERNATIVE FUELS
IN VEHICLES WITH VARIOUS POWER PLANTS
( Based on Preliminary Costs From Table 8-1)
Open-Chamber Dual-Chamber
Fuel Conventional Stratified-Charge StratifJed-Charge Diesel Brayton Rankine Stirling.,,
^/mile
Distillate Oils
2.44 + 0.53 -- 1.91 + 0.52 2. 53 +_ 0. 74 2.76 + 0.82 2.50^0.52
Ethanot 14. 70 J- 5. 92 W
9.97+_3.00P 9-97 + 3.37 10. 09 +_ 3. 49 10.36+_4.21 11.28 + 4.53 9.42 + 4.17
ii
oo Gasoline 4. 68+_1.36W
0 3.40 + 0. 75 P 2.90 + 0.61 3. 04+_ 0. 68 -: 3.00 + 0.85 3.27 + 0.88 2.71+0.85
Hydrogen 6.57 + 3.14 W
(Liquid) 5. 15 + 2.06 P 5. 13 +_ 2. 00 __ 4. 77 +_ 2. 03 6.80 + 2.83 7.39 + 2.98 5.98 + 2.69
Hydrogen 7. 52 +_ 3. 42 W -
(Hydride) 5. 82 + 2. 33 P 5.84 + 2.39 -- 5.22 +.1.72 7.96 + 3.36 8. 39 +_ 3. 47 7.05 + 3.14
Methanol 4. 05 +_ 1. 05 W
2.96 + 0.56 P 2. 86 +_ 0.52 2.99 + 0.59 -- 3.36+_ 0. 84 3.59 + 0.86 3.01+^0.85
LSNG 5.21 + 1.72 W
3. 82 + 0.97 P 3.63 + 0.88 3.64 + 0.95 -- 3. 89 + 0.95 4. 02 + 1. 18 3.69 + 0.82
*
W = Wankel; P = Piston. A-34-505
-------
8. 4 Costs of Resource Extraction and Fuel Synthesis ( Candidate Fuels)
On the basis of workable processes and available engineering and
economic data, we selected example or pattern processes for synthesis of
alternative fuels. These processes are not necessarily recommended for
commercialization. Appendix B contains detailed process descriptions and
economic calculations. These pattern processes are well developed techni-
cally or are composed of process components for which sufficient data have
been published to allow characterization and reasonable estimates of econ-
omics. The economics have been calculated by using the DCF financing
method discussed in the FPC's report on synthetic gas-coal. a
Based on process equipment requirements and operating (or experimental)
data, we have made careful determinations of all components of capital and
operating costs. The method is outlined in Tables 8-5 and 8-6, and the cal-
culations are included in Appendix B. Table 8-7 presents the results for
those candidate fuels and synthesis routes that can be characterized in
sufficient detail. The processes described are "pattern" processes for
fuel synthesis, and certain other synthesis processes would be equally (or
more) acceptable for commercialization. The synthesized fuels are candi-
dates for use as alternative fuels for automotive transportation, but they are
not necessarily the selected (chosen or recommended) alternatives. The
selected fuels depend on the needs for supplemental fuel, as shown by an
energy demand and supply projection, and on the application of a fuel selec-
tion procedure, as described in Section 2.
During this study, the domestic petroleum reference base underwent a
major change in economics. The reference gasoline cost to be compared
with preliminary costs of potential fuels was set at $2. 40/million Btu
(lower heating value) : $1. 20 for resource extraction and refining and $1. 20
for transmission and distribution. This cost for reference gasoline was
valid during the first half of 1973. However, it does not correspond rigor-
ously, in all cases, to the preliminary costs of alternative fuel systems
(Table 8-1) , because capital and other costs for these systems were taken
from literature published prior to 1973 (generally in the late 1960's and
early 1970's) . Although appropriate cost escalation factors were used,
these preliminary costs are of doubtful accuracy in absolute terms. However,
we consider them acceptable for intercomparisons and preliminary evaluations.
181
-------
Table 8-5. BASIS FOR CALCULATING GROSS AND NET OPERATING
COSTS FOR PRODUCING CANDIDATE FUELS
Raw Materials
Mine-Mouth Coal ($0.30/106 Btu) XXX
Oil Shale at Mine ($0.86/ton) XXX
Catalysts and Chemicals XXX
Purchased Utilities
Electric Power ( $0. 009/kWhr) XXX
Raw Water ( $0. 30/1000 gal) XXX
Natural Gas ( $1. 00 /1000 SCF) XXX
Labor
Process Operating Labor (men/shift X 8304
man-hours/year X $/man-hour) XXX
Maintenance Labor (1. 5%/yr of total plant invest-
ment) XXX
Supervision (15% of operating and maintenance
labor) XXX
Administration and General Overhead ( 60% of total
labor, including supervision) XXX
Supplies
Operating ( 30% of process operating labor) XXX
Maintenance (1. 5%/yr of total plant investment) XXX
Local Taxes and Insurance ( 2. 7%/yr of total plant
investment) XXX
Total Gross Operating Cost (per year) XXX
By-product Credits (XXX)
Total Net Operating Cost (per year) XXX
182
-------
Table 8-6. BASIS FOR FUEL COST CALCULATION BY THE DCF METHOD'
Basis
25-year project life
16-year sum-of-the-years'-digits depreciation on total plant investment
100% equity capital
Essential Input Parameters
12% DCF return rate
oo 48% Federal income tax rate
Handling of Principal Cost Items
Total plant investment and working capital are treated as capital costs at start-up completion.
"Return on investment during construction" (equal to total plant investment X DCF return rate
X 1. 875 years) is treated as a capital cost at start-up completion.
Start-up costs are treated as an expense at start -up completion.
See Appendix B (Volume III) for detailed calculations.
-------
Table 8-7. PATTERN SYNTHESIS PROCESSES AND
FUEL PRODUCTION COSTS (For 1973 in 1973 Dollars)
Raw
Material
Coal
Coal
Oil Shale
Coal
Coal
Synthesized
Fuel
Gasoline
Gasoline and
distillate oils
Gasoline and
distillate oils
Methanol
SNG (CH4)
Production Cost (12% DCF)
Volume Basis, Energy Basis,
Pattern Process
Consol Synthetic
Fuel ( CSF) plus
refining with
hydrocracking
Consol Synthetic
Fuel (CSF) plus
refining with
catalytic cracking
Gas Combustion
Process (Bureau
of Mines) plus
hydrotreating and
refining
Koppers-Totzek
gasifier and ICI
synthesis
Lurgi gasifier
with methanation
$/gal
Btu
0.33
0. 31
0.25
2.81
2. 51
2.05
0.23
1.84/103
SCFt
3.88
2.14
If 10% SCF financing is used, the resulting fuel synthesis costs
are 88% to 91% of the costs presented in this table.
Basis: the low heating value of the fuel.
To correspond with up-to-date economics for the candidate fuels selected
and studied several months later, the reference gasoline cost was updated (for
accuracy and validity of comparison) to $2. 80/million Btu (lower heating value) .
This was $1. 60 for resource extraction and refining, and $1. 20 for trans-
mission and distribution ( December 1973) . Use of these reference fuel costs
(adjusted for time frame) is demonstrated in Section 10 in the selection of
candidate fuels.
A candidate fuel and synthesis procedure of interest, for the far term
is hydrogen produced thermochemically from water. Thermochemical pro-
duction is designed to decompose water into hydrogen and oxygen by using the
heat energy available from nuclear reactors. The process concept is described
in Section 5. At present, no commercial process for the thermal conversion.
184
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of water to hydrogen and oxygen exists. Nevertheless, many proposed
multistep chemical reaction sequences, in theory, could thermally separate
water at lower overall temperatures (less than 1000°C) . IGT has obtained
experimental evidence for proof of concept and information16 on practically
attainable energy efficiencies. Currently, work is being conducted in the
laboratory to identify the chemical reaction cycles that appear to have the
greatest potential. To date, most research has been directed at the range of
heat input temperature between 700° and 1000°C. The respective energy
transfer efficiencies reported fall between 40 and 60%. Despite the many
uncertainties associated with evaluating this infant technology, its long-term
potential is too great for it to be excluded from this study, especially after
the year 2000.
For this analysis, a nuclear heat-to-hydrogen energy conversion efficiency
of 50% is used. This is a reasonable estimate, and the economics associated
with this process are very sensitive to this number. A 1% change in efficiency
is equivalent to 12^/million Btu of hydrogen produced over the life of the
project. The HTGR reactor was assumed to be the primary heat source
because it is potentially capable of achieving temperatures of 1000°C and
because its operating and economic characteristics are reasonably well-known.
8. 4. 1 Nuclear Reactor Heat Cost Analysis
During 1973, plans for 38 new nuclear plants were announced, and the
capital costs ranged from $313, 000 to $650, 000/MWe, with an average
cost of $456, 000/MWe. The scheduled construction periods were between
6 and 13 years, with an average of 8. 8 years. The capital costs for the
nuclear heat module of a thermochemical plant were estimated from capital
costs reported in Combustion. 1? Both estimates appear in Table 8-8.
In determining the reactor operating cost, two primary source documents
were used. 23' ^ The cost components reported in Combustion23 were derived
by the EEI Reactor Assessment Panel. The totals from both sources were
in reasonable agreement; i. e., 1. 74-1. 82 mills/kWhr was projected for 1975.
185
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Table 8-8. NUCLEAR HEAT MODULE COSTS FOR A
THERMOCHEMICAL HYDROGEN PLANT
*
Nuclear Nuclear
Electric Thermochemical
Cost Component $1000/MWe:
Nuclear Steam Supply System 46 46
Turbine Generator Unit 33
Construction Materials and Equipment 72 50
Craft Labor 85 60
Professional Services 42 30
Construction Management 26 18
Contingencies 14 10
Plant Investment 318 214
Two modules of this size are required for a nominal 250 X 109 Btu/day
hydrogen plant.
There were significant variances in the individual cost components, primarily
mining and milling, and enrichment. In these instances, the EEI values were
selected because they were more in agreement with the operating character-
*
istics of an HTGR reactor as reported ^ by the AEC. The cost components
used in this study are as follows:
mills/kWhr
Mining and Milling ( $8/lb U3O8) 0. 56
Enrichment ( $26/SWUt) 0. 62
Fabrication 0. 34
Shipping and Reprocessing ( $45/kg of uranium) 0. 19
Waste Management 0. 04
Plutonium and Uranium Credit ( $7. 50/gram of
plutonium) Q. 35
Total 1.40
This source does not reflect the thorium requirements. In terms of thorium
oxide, these quantities represent nearly 10% of the initial and annual uranium
oxide requirements. Also, thorium oxide and uranium oxide unit costs are
comparable.
SWU = Separative work unit.
186
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The total operating cost used in this study is as follows:
mills/kWhr
Fuel Costs
Operations and Maintenance
Insurance
Supplies and Taxes
Total
* Source: Ref. 5
W-
To arrive at an annual operating cost, a plant availability factor of 0. 9
and a plant capacity factor of 1 were used. The actual annual operating
charge calculated was $15. 4 million/yr.
Currently, most economic analyses of reactors are based on heat output
in terms of electrical energy equivalent. HTGR heat can be converted to
electricity at an efficiency of approximately 39%. A standard llbOMWe
reactor requires a net thermal output of 2974 MWth,, which is available for
thermochemical hydrogen production. Assuming a reactor availability
factor of 0. 9 and a capacity factor of 1.0, the heat generated in the reactor
is 68. 99 trillion Btu/yr. When these cost and energy output data are subjected
to the standard DCF calculations, a price for unit heat transfer between the
reactor and the thermochemical processing plant of $2.01 /million Btu was
obtained. In the DCF calculations, an optimistic construction period of
3.5 years was assumed for consistency and to acknowledge the shorter con-
struction periods commensurate with industry growth in the future.
8.4.2 Thermochemical Plant Cost Analysis
We acknowledge that it is presumptious to estimate the cost associated
with the processing plant without specifying the particular thermochemical
cycles. However, commercially attractive multistep chemical reaction
cycles will have several important things in common. These cycles will be
This figure is high by nearly 10% when compared with plant availability
factors quoted by the AEC. Also, it is approximately 20% higher than
past experience indicates. Nevertheless, technology improvements are
anticipated prior to the period when these plants are scheduled to be
placed on-stream and all other fuel conversion processes are compared
on this basis.
187
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closed-loop regenerative processes. For a given heat supply, efficiencies
of practical cycles should be within 10% of each other,and therefore, hydrogen
production capacities should not vary significantly. At this stage of develop-
ment, common chemicals are being considered and only very small makeup
quantities will be required after the initial loading. Therefore, the use of
the chemicals should not be a critical factor. Unless a major breakthrough
makes them advantageous, exotic chemical processing schemes will not be
required.
The estimated capital costs associated with a general thermochemical
plant (chemical sequence unspecified) are shown in Table 8-9. These costs
are educated guesses projected from laboratory-scale studies.
Table 8-9. THERMOCHEMICAL PLANT CAPITAL COSTS
(1973 Dollars; 250 X 109 Btu/Day Hydrogen)
Cost Components _^ Cost, $1Q6
Chemical Process Reactor System 75
Gas Separation System 25
Gas Compression 5
Heat Recovery;System 25
Oxygen Compression and Storage 10
Raw Water Storage , Treatment,and Pumping 15
Initial Catalysts and Chemicals 20
General Facilities 40
Contractor Fees 30
Contingencies 30
Total Plant Investment 275
188
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Table 8-10 depicts the operating cost components used in this analysis.
Table 8-10. THERMQCHEMICAL PLANT OPERATING COST
(1973 Dollars; 250 X 109 Btu/Day Hydrogen)
Cost Components Annual Cost, $106
Purchased Raw Materials
Heat (164. 25 X 109 Btu/yr, $2. 01/106 Btu ) 330.04
Water (18,500 gpm, $0. 30/1000 gal) 2.62
Catalysts and Chemicals 5. 00
Labor
Process Operating Labor (62 men/shift, $5/hr,
8304 man-hr/yr) 2.57
Maintenance Labor (1.5% of plant investment) 4. 12
Supervision (15% of operating and maintenance labor) 1. 00
Administration and General Overhead (60% of total
labor, including supervision) 4. 61
Other Charges
Supplies (30% of process operating labor) 0.77
Maintenance (1.5% of plant investment) 4. 12
Local Taxes and Insurance (2. 7% of plant investment) 7. 42
Total Gross Operating Costs 362.27
By-product Credit
Oxygen ( 1 26. 47 X 109 CF/yr, $7/ton) 39.46
Not Operating COB!: 322. 81
When these estimated capital and operating costs are factored into the
standard DCF calculations, the basic cost of producing hydrogen is $4. 80/106 Btu.
This cost includes a by-product credit for the oxygen produced, but it does
not consider a by-product credit for the heat not used. A process heat supply at
1600°F with a 700°F temperature drop is assumed to drive the chemical
reaction cycle. Thus, the equivalent of 34. 5 X 1012 Btu/yr at temperatures
of 900°-200°F is not being utilized. This heat source is adequate to drive
a nominal 400-MWe turbine generator unit. A credit of 10 mills/kWhr produces
revenues of $32.3 million/yr.
189
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The capital cost associated with the turbine generator unit is estimated
at $40 million (from Table 8-8. scaled to 400 MWe). The associated operating
cost is estimated at $4. 75 million/yr. The revenue needed to regain this cost
over the life of the project is $15 million/yr. The net saving is $17. 3 million/yr.
This yearly saving reduces the cost of hydrogen produced to $4. 55 /106 Btu.
This cost in 1973 dollars with energy by-product credits is consistent with
the costs of other fuels (from oil shale or coal) with their by-product credits
(per Table 8-7)
8.5 Costs of Transmission and Distribution (Candidate Fuels)
For candidate gaseous fuels, the preliminary estimates are derived from
the best available data, and no further refinements have been necessary or
attempted. The natural gas pipeline network furnishes adequate logistics
information and operating data. Separate IGT studies on hydrogen transmission
are sufficiently extensive for complete economic estimates, and these were
included in the preliminary costs. The preliminary service-station costs for
potential fuels are also adequate for comparisons among the candidate fuels.
Because the transport of liquid hydrocarbons from the Rocky Mountain area
constitutes new logistics for the energy supply, we have made further and more
detailed cost estimates of the long-distance transport of shale oil or syncrude
from coal to existing refining and marketing centers. The results do not
substantially change the previous (preliminary) costs; details are summarized
below.
We have carefully estimated the economics associated with oil pipelines
from the Green River region in Wyoming. We assume that these pipelines
would go to Houston, Chicago, and Los Angeles. The basic parameters of
the analysis are as follows:
Volume: 100,000 bbl/day.
Syncrude specifications: 46. 2° API; specific gravity, 0. 796; and
viscosity, 40 SSU (100°F).
Maximum pressure was not established specifically, but a maximum
operating pressure of around 1200 psi was set as desirable.
The remaining parameters of pipe diameter, horsepower, and operating
characteristics are contingent on the above and on the pipeline route.
190
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The routes for the three destinations are stated in Table 8-11 with inter-
mediate cities and gross changes in altitude.
Table 8-11. ASSUMED SYNCRUDE PIPELINE ROUTES
Pipeline City
Green River to
Houston
Green River to
Chicago
Green River to
Los Angeles
Green River, Wyo.
Cheyenne, Wyo.
Amarillo, Texas
Vernon, Texas
Fort Worth
Houston
Green River, Wyo.
Cheyenne, Wyo.
North Platt, Neb.
Lincoln, Neb.
Chicago
Green River, Wyo.
Las Vegas, Nev.
Los Angeles
Average
Estimated
Altitude, ft
8000
5000
2500
1150
300
300
8000
5000
2500
1150
300
8000
1150
1150
Distance From
Last Point,
miles
_ _
275
520
175
155
285
1410
_ _
275
205
215
530
1225
_ _
500
410
910
On the basis of the pipeline route, the volume to be moved, and product
specifications, the associated hydraulics can be calculated and the pipeline
din m«'l < I'M n nd hornrpowfr roqui rmnmt.H choHOn. Wt' have nstirn.'vtod the
approximate Locations of pumping stations and the necessary pump horsepower
requirements for a 20-inch-diameter pipeline.
The horsepower requirements are very low: 3300 hp for the Houston
pipeline, 2305 hp for Chicago, and 850 hp for Los Angeles. This is the
case because of the very high static head due to the large negative change
in altitude, and the relatively low function head associated with a 20-inch
line for this thoughput. All the pipelines are assumed to begin with a pump-
ing station. The Houston and Chicago pipelines each have one additional
pumping station,whereas the Los Angeles line needs only the initial one.
Estimates of the investment components are shown in Table 8-12. The
gross investment, exclusive of product inventory in the pipeline and storage,
191
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is about $5500/in. /mile for the 20-inch-diameter lines. Inventory costs
are based on the total volume of syncrude necessary to fill the pipelines and
the initial storage fill. The price of syncrude has been set at $10/barrel for
this initial estimate.
Table 8-12. ESTIMATED INVESTMENT U973 Costs) FOR
SYNCRUDE PIPELINE 15' 3i
Miles of Pipeline
Number of Pump Stations
Total Horsepower
Inve stment
Right of Way and Damages
Survey and .Mapping
Line Pipe
Coating and Wrapping
Freight
Sales Tax
Cathodic Protection
Construction
Pump Stations
Storage
Capital Equipment Cost
Engineering, Inspection, and
Testing (2%)
Contingencies and Overhead (5%)
Capitalized Interest During
Construction (9%)
Pipeline and Storage Inventory
Total Investment
Houston
1410
2
3300
5. 58
0. 82
73.08
2.97
4.76
2.19
0. 67
40.95
0.46
2. 60
134.08
2. 68
6. 70
12.07
37.94
193.47
Chicago
1225
2
2305
-------
Table 8-13. ' OPERATING COSTS FOR SYNCRUDE PIPELINE32
Chicago
Miles of Pipeline
Number of Pump Stations
Total Horsepower
Fixed Operating Costs
Variable Operating Costs
Maintenance
Pipeline
Stations
Storage
Cathodic Protection
Pipeline
Houston
1410
2
3300
Stations
Supplies
Delivery Facilities and
Stations
Communications
Labor
Power
Overhead and Miscellaneous
Contingencies
Total Annual Operating Costs
25.98
0. 34
0. 03
0. 01
0. 01
0. 14
0. 40
0.46
0. 14
27.51
1225
1
2305
$ million
22. 80
0. 29
0.03
0. 01
0. 01
0.12
0. 36
0.32
0.11
24.05
Los
Angeles
910
2
850
17. 37
0. 22
0.03
0.01
0. 01
0. 10
0.40
0. 12
0. 09
18. 35
The fixed charge rate is calculated to be 13. 4% by using the minimum
revenue requirement discipline (MRRD).8 This method includes revenue
>
requirements only and makes no assumptions about profit incentive. Assump-
tions made for calculating the fixed charge rate are
90% debt/10% equity
9% interest rate on debt
12% return on investment
-------
In principle, then, MRRD calculates the cost-of-service of moving syncrude
through a pipeline from A to B. Unit costs are 5. 35^-5. 52^/bbl/lOO miles,
as shown in Table 8-14.
Table 8-14. UNIT COST OF SYNCRUDE PIPELINE
Los
Houston Chicago Angeles
Miles of Pipeline 1410 1225 910
Total Annual Operating Cost, $106 27. 51 24. 05 18. 35
Unit Operating Costs
miles 5.35 5.38 5.52
#bbl 75.4 65.9 50.3
Table 8-15 summarizes the candidate fuel transmission and distribution
costs with conservative 1400-mile transmission and 150-200 mile distribu-
tion distances.
8. 6 Candidate Fuel System Costs ( 1973)
Table 8-16 presents the system costs for the candidate fuels, exclusive
of vehicle utilization, in terms of late-1973 dollars. They are the predicted
fuel costs at the service station-vehicle interface, but do not include Federal
and state sales and other taxes normally imposed on gasoline.
In the future, the real costs of coal, oil shale, and fissile (nuclear) fuels
will escalate because of such factors as the necessity for deeper mining, the
use of lower -as say-material deposits, and longer distance transport of
materials including water. Synthesis costs also will escalate because of
the necessarily increased amounts of processing per unit of product.
8. 7. Analysis of Future Real Costs ( Noninflationary) of Candidate Fuels
Fuel production costs cannot be analyzed and projected without consider-
ing two related factors: 1) alternative fuel system objectives and project
life and 2) the role of future prices in supply and demand. The cost analysis
discussed in this section is based upon certain premises of study objectives
and future prices. These premises are explicitly stated below to establish
a frame of reference for the comparative cost analysis of candidate fuel
production in future time frames.
194
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TabU 8-15. SUMMARY OF TRANSPORTATION COSTS FOR CANDIDATE FUELS
Fuel and
Resource
Gasoline From
Shale and Coal
Methanol From
Coal
Liquid SNG
From Coal
Liquid Hydrogen
From Coal (
Hydrogen (Hydride)
From Coal (
Field -to -
Refinery Cost
9. 14
( 1400 miles)
18.66
( 1400 miles)
22.40
( 1400 miles)
52.2
1400 miles as gas)
52. 2
1400 miles as gas)
Product
Distribution Terminal
Cost Charge
2.14 1.63
( 150 miles)
4.15 3.16
( 1 50 miles)
6.0 3.16
( 1 50 miles)
21.8 16.3
( 150 miles)
29.0
( 200 miles)
Truck-to- Service Station
Service Station ... Capital Recovery Liquefaction
Cost Cost (Rent) at 2
-------
Table 8-16. SYSTEM BASE COSTS FOR CANDIDATE FUELS (Late 1973)J
Resource Base and
Resource Extraction Transmission
and Fuel Synthesis and Distribution
Total Cost Total Cost,
C j.v j_« T-« i
Coal
Gasoline (Primarily)
Gasoline and Distillate Oil
Methanol
SNGC
Oil Shale
d- /I nb TH_.
2.81
2.51
3.88
2. 14
1.06
1. 06
1.
2.
34
04
3.
3.
5.
4.
87
57
22
18
$/gal
0.49
0.47
0.32
0. 31
Gasoline and Distillate Oil
2.05
1. 06
1 3. 11
0. 39
Nuclear Heat
Hydrogen
Hydrogen
4. 55
4.55
3. 83
2. 21
8. 38
6.76
0.25
Reference Gasoline
1.60
1.20
2.80
0.33
Basis, low heating values of the fuels.
50:50 product mix, average price.
SNG transmission and distribution as a gas, liquefied at service stations.
Thermochemical hydrogen transmission to terminal as a gas, liquefied, and-distributed in
liquid-hydrogen trucks to service stations.
Thermochemical hydrogen transmission and distribution as a gas, combined as a metal
hydride at the service stations.
-------
8. 7. 1 Objectives and Project Life
A global objective of this feasibility study is to satisfy future automotive
energy demand patterns based upon an extrapolation of historical demand
patterns and to assess the feasibility of the U. S. becoming as domestically
self-sufficient as possible without incurring excessive costs. Emphasis
was placed on ensuring the supply of an existing automotive fuel ( gasoline
or an acceptable substitute or supplement) without significant economic
dislocations.
The initial approach was to determine the cost and the potential availability
of fuels derived from domestic resources. The second phase involved
collecting detailed data on new technology for producing acceptable fuels
from selected energy sources. The candidate fuels were compared on the
basis of cost by an analysis of capital budgeting.
A prime requisite for the comparison of capital budgeting programs is
the length of the planning horizon, or the project life, particularly when
alternatives involve programs with different project lives that can start
at different times.
For this study, all potential alternative fuel programs were evaluated
for a minimum project life of 25 years, although there is no firm justifica-
tion for this particular period. Industrial practice varies between 5 and
30 years. In the chemical industry, there is a high substitution rate among
products, and the new products that are frequently introduced are not con-
ducive to long-term planning horizons. The utility industries represent
the major group over 20 years. This utility industry practice originated
with early institutional guidelines requiring all new projects to have a
minimum life of 20 years.
Conceptually, a project has three lives: a physical life, a technological
life, and a production, or market, life. Ideally, the shortest of these life
cycles is selected as the base period for comparison. In this study, an
objective is to assess the availability of an existing fuel or an acceptable
substitute in time frames extending beyond the year 2000. For the most
part, only the newest technology was considered; therefore, the shortest
life cycle appears to be the physical life. Some of the equipment in the rep-
rentative fuel conversion processes will not last 25 years; however, much
of the plants, facilities, and equipment will last this long.
197
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For this study, several additional factors must be considered to establish
program life. An important consideration is that we are dealing with fixed
resource bases ( e. g. , oil shale, coal, or uranium deposits) for each project.
Because of location and technology, a fuel conversion process is usually
coupled to a single raw material supply. In commercial practice, this raw
material supply is selected because it has the potential for 30-40 years of
supply. This makes an extended program life more economically attractive.
Another important consideration is the manner in which these programs must
be financed. The development of a new synthetic fuel industry will be very
capital-intensive, 3-4 times more than the present-day petroleum or petro-
chemical industry. The probability is very small that all the required capital
can be generated internally from industry funds within the necessary time
span. Therefore, the general trend will be toward debt financing by using
the vehicle of 20-30 year bonds. Again, this trend enhances the use of an
extended program life. For these reasons, we have chosen 25 years as the
average project life for evaluation purposes.
8. 7. 2 Future Prices
In this analysis, price is viewed as the mechanism for balancing the flow
of funds over the project planning horizon. In general, the accomplishment of
the same project objective in a shorter time frame requires higher prices
to accumulate the same amount of funds. Conversely, a project with identi-
cal costs, evaluated over a longer project life, requires a lower price to
accumulate similar funds. The relationship between supply and demand is
assumed to be constant over the life of the project, and the price equals the
return on investment plus all associated costs' over the life of the project,
Two critical aspects of this analysis are a steady supply-demand relation-
ship throughout the project life and the inclusion of all costs that will occur
over the life of the project.
The probability of actually maintaining a continuous supply-demand equil-
ibrium is low. Current plus projected demand already exceeds current
plus projected supply, and no large-scale substitute automotive fuels have
appeared on the planning horizon. Hence, an assumption of steady-state
conditions would most likely be invalid. When steady-state conditions are
disrupted in a free market, the incurred price increases until the supply-demand
198
-------
relationship regains equilibrium; either supply catches up to demand, or
demand is reduced to equal supply. In this analysis, the return on in-
vestment is held constant, and the price increases reflect the minimum
costs associated with increasing supply to the point that it again equals
demand.
The cost analysis includes all costs that must be incurred over the life
of the project. The capital and operating costs that we have considered are
associated with the accumulation and use of the natural resources that are
raw materials for fuel production. Generally, these resources are limited,
irreplaceable commodities. The acquisition of these raw materials contains
two principal cost components: exploration and production. The exploration
cost component is associated with the precise location and amount of the
basic raw commodity. The natural resource production cost component is
associated with the extraction of the commodity from its natural state.
Initial cost estimates for raw material production will not be correct unless
adequate reserves are allocated and sufficiently defined over the life of the
project. The probability for error occurs because the next unit of produc-
tion will not cost the same as the last unit of production. Marginal economic
analysis is not always applicable because the natural resource may be limited
and irreplaceable. As the sum of past production approaches the upper limit
of total availability, the cost associated with the acquisition of new incremental
production increases beyond proportionality.
For a finite natural resource, increasing exploration costs will, at some
time, produce less than proportional or normal results. For this reason,
economic theory dictates that the return on investment should be adequate
to generate the funds required to develop desirable substitute resources
after the existing resource bases have been depleted. Obviously, supple-
mental or substitute resources are more expensive; otherwise, they would
have been developed first. Hence, the development of supplemental resources
reflects real cost increases.
In the cost analyses for candidate alternative fuels in future time frames,
all the real cost increases are associated with the exploration and production
of limited irreplaceable commodities and their synthesis into automotive fuels.
199
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As a new synthetic fuel industry develops, some cost saving can result
from technological improvements beyond those anticipated in this analysis.
However, they will not be adequate to offset the cost increases resulting
from the depletion of finite irreplaceable resources.
Also, economies of scale will not be realized beyond those already
included. The basic plant size used in the technical and economic analyses
(Appendix B) are well beyond the domain in which economies of scale could
occur. Further, we have attempted to include all real cost components in
this analysis, except for the costs of land reclamation, environmental
impacts, legal aspects, and societal dislocations. We have quantified the
costs required to develop new incremental production by using the accumu-
lated historical or scheduled consumption as a reference.
8. 7. 3 Projections of Future Fuel Production Costs (Summary)
As stated previously, the projected future costs are based primarily on
the real cost increases associated with obtaining new (incremental) fuel
production from a limited resource base. The projected costs are f. o. b.
plant. Transmission and distribution Costs are not treated because they
are considered about constant throughout the planning horizon. Technologi-
cal improvements are incorporated in this analysis, but such improvements
are offset by the real cost increases associated with the raw material
resources. Table 8-17 reflects an overview of the real cost increases
anticipated throughout the planning period.
Table 8.-17. PROJECTION OF FUTURE FUEL PRODUCTION COSTS
(In 1973 dollars) _ ,
x Reference
Thermo- Coal Coal Oil Shale Coal Crude Oil
chemical to to to to to
p . Hydrogen SNG Gasoline Gasoline Methanol Gasoline
1973 Base
Near Term (1985)
Mid Term (2000)
Far Term (2020)
4.55
--
4. 79
4. 79
2. 14
2.74
4. 00
4. 60
* i
? /
2. 51
3. 64
5.29
6. 16
'10* Btu-
2.05
3.32
5.74
6.97
3.88
4.77
6.47
7.36
1.60
2.76
4.56
7.82
200
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Table 8-18. COMPARISON OF FUEL PROCESSING SCHEMES
(Nominal Production: 250 Billion Btu/day; 1973 Base Data)
Processing Scheme
Crude to Gasoline and
Distillate (50:50)
Oil Shale to Gasoline and
Distillate (50:50)
Coal to Gasoline and
Distillate (50:50)
Coal to Methanol
Coal to SNG
Thermochemical Hydrogen
Nuclear Plant
Thermochemical
Processing
Total
Refin-
Net Annual ery
Capital Operating Gate
Cost Cost Price
100
608
653
980
496
428
275
b
c
d
d
d
TOT
$106
140
54
92
136
64
15
323
T38~
Ratio of
Feed to
Operating
Costs
1.
2.
2.
3.
2.
4.
60
05
51
88
14
55
0.
0.
0.
0.
0.
0.
86
50e
66
49
69
91f
bbl
Water per
106 Btu
Product
0.
1.
1.
1.
1.
2.
3
3
1
8
0
5
a
b
c
d
e
f
Low heating value.
Based on a crude price of $6. 96/bbl.
Includes mining capital expenditures equivalent to $0. 84/106 Btu.
Based on a coal price of $0. 30/106 Btu.
Not listed as a separate item, estimated.
At nuclear reactor-thermochemical plant interface.
-------
These figures are not the average costs for the time frame in question;
father, they represent the costs of new incremental production at the end of
the period.
An overview of some of the significant parameters associated with the
candidate fuel systems, upon which these costs are based, is shown in
Table 8-18. An analysis of the specific cost components associated with
these respective future production costs is presented later in this section.
8. 7. 4 Future Domestic Crude Oil and Refinery Product Cost Analysis
As stated previously, we do not believe there will be significant real cost
increases associated with the transmission distribution costs between the
refinery gates and the service stations.
Table 8-19 reflects the results of the anticipated real cost increases in
the areas of exploration, development,and production.
Table 8-19. FUTURE CRUDE OIL AND REFINERY GATE COSTS
(Domestic Crude Reference Base, 1973 $)
Crude Oil (Input) Refinery Gate (Product)
Year $/10b Btu $/bbl %/yr Growth $/lOfe Btu $ /bbl "^
1973 1,20 6.96 8.25 1.60 9.04
1980 1.92 10.85 6.95 2.32 13.11
1990 2,80 15.82 3.84 3.20 18.08
2000 4.16 23.50 4.00 4.56 25.76
2010 6.16 34.80 4.00 6.56 37.06
Table 8-19 includes no increase for refinery costs but an overall increase
of 4. 52%/yr in crude oil costs. The constant refining cost is$0. 40/bbl.
Note that the basic oil cost used for 1973 was $6. 96/bbl. A precise definition
of this cost is necessary because there is a very real question of "What is
the base price of crude oil for the U. S. in 1973?" Although much of the crude
oil cost movement during 1973 was surrounded by political actions and it
was a transitional year for crude oil cost worldwide, world crude production
during 1973 nearly equaled world crude demand. In the U.S. production was
only 70% of demand.
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In January 1973, the average price of crude worldwide was $4. 50/bbl. In
December 1973, the average price of crude worldwide was $10. 00/bbl,
more than a 200% increase. During the last 3 months of 1973, crude oil
was purchased for as much as $24/bbl. During this period, Governmental
price controls were in effect. There was a two-tier crude oil pricing system
in the U. S. : $5. 25/bbl for old oil and $8, 50 for new oil from stripper wells
(15% of domestic production was from new oil) . Further, 30% of our
petroleum products were purchased from foreign markets at worldwide
market prices. The weighted average of these data is $6. 96/bbl.
The primary basis for crude-oil real cost increases is that much of the
readily accessible geology has been explored, especially in the U. S. During
the i960's, approximately 7000 exploratory wells were drilled each year in
the U. S. The sum of these yearly drillings was approximately 40 million
ft/yr, excluding the 15,000-20,000 development wells per year. The net
result of these extensive activities was an average annual addition to reserves
of 3. 6 billion bbl/yr. Assuming a modest reserve-to-production ratio of
10, this is equivalent to a production rate of 1 million bbl/day, or approx-
imately 6% of present demand. Current production is being supported by
additions to resources made prior to I960. This situation is not unique,
and similar statistics are reported in many other countries, including some
major producing countries.
In the future, we will have to extend, our exploration to the more inaccessible
and/or more complex stratigraphy. The unit cost associated with exploration
and development of more complex stratigraphy can increase as much as
tenfold even in the near term. For example, the difference in drilling costs
for various conditions is as follows:
Location Cost, $/ft
Lower 48, less than 15,000 feet 18
Lower 48, more than 15, 000 feet 80
Lower 48, offshore (less than 600 ft water) 71
Alaska 285
In addition, the gathering systems for these more inaccessible locations will
be more expensive. Finally, much new technology needs to be developed in
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the following areas: geological surveying for more complex stratigraphy,
drilling in more than 600 feet of water, and secondary and tertiary recovery.
Although estimates of these costs are not available, this information is not
needed to validate the real cos,t increases associated with domestic crude oil
processing. Table 8-20 is adequate to justify the projections of increased
real costs. The average capital requirement for crude oil additions to
reserves during the 6 years between 1967 and 1972 was $2. 05 /bbl. Included
-!<
in this average is the Prudhoe Bay discovery. Excluding the year (1970 )
of the Prudhoe Bay discovery, the average cost was $2. 39/bbl, which is more
representative of the 1960's.
Table 8-20. PRODUCTION AND EXPLORATION INVESTMENT FOR
CRUDE ADDED TO RESERVES IN THE U. S. 2'19
Additions Capital for Production, Capital Requirement,
to Reserves, Exploration, Geological $/bbl
Year 109 bbl/yr Surveys, $109/yr added to reserves
1967 2.96
1968 2.45
1969 2.12
1970 12.69
1971 2.32
1972 1.56
Using the same assumptions as in all other DCF calculations and a
capital investment of $2/bbl for new crude additions to reserves, we deter-
mined that the capital required to supply 16. 4 million bbl/yr ( 50, 000 bbl/day
refinery with 328. 5 on-stream days) for 25 years was $810 million. By
making a conservative simplifying assumption that the annual operating costs
associated with exploration, development, and-production were only 10% of
the capital requirements, the price of this new crude oil delivered to the
refinery would be more than $17. 50/bbl to obtain a 12% return on investment.
This calculation places crude oil processing on the same basis as coal and
oil shale processing; i. e. , the cost of obtaining the raw feedstock is evaluated
4. 37
5.39
5.25
4. 75
3. 90
6.48
1.26
1.91
2.13
0. 33
1.37
3.68
The actual discovery was made in 1968. The statistics were not included
until 1970.
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over the life of the project.* The premise is that a new fuel conversion
plant will not be constructed unless feedstocks are available over the life
of the program. For a new crude refinery, the acquisition of the feedstock
must be based upon current and future costs associated with finding new
supplies of crude. The current cost (average cost between 1967 and 1972)
of finding new crude in the U. S. was $2. 00/bbl.
Some would argue that it is not necessary to have all the required 410
million barrels on hand at the beginning of a project ( 50, 000 bbl/day refinery).
After all, the U.S. current re serves-to-production ratio is nearly 50%
of the assumed 25-year program life. This new assumption would translate
into an approximate price of $8. 75 bbl for crude oil instead of the pre-
viously quoted $17. 50/bbl. However, exploration and production costs
could increase up to tenfold. A threefold increase in exploration and pro-
duction costs in the next 10-15 years would still translate into a crude price
of $20. 00/bbl, assuming a reserves-to-production ratio of 10. Depending
upon the assumptions that are used, the cost of crude oil will fall between
about $34/bbl and about $50/bbl by the year 2010.
Underlying this analysis is the assumption that the probability of finding
any additional secure supergiant oil fields is very low. (A supergiant field
is one with proved reserves in excess of 30 billion barrels. ) Currently,
there are 10 such fields worldwide: six were discovered prior to 1950,
three in the 1950's, and one in the 1960's. The discovery rate of these
supergiant; fields has slowed despite the development of more effective
exploration techniques and increased drilling activity.
Based on the above DCF assumptions, a price of $7/bbl could indicate
thatan $0. 80/bbl capital in vestment is needed to develop the necessary
reserves. Although no industry investment data are readily available
for the I940!s"and early 1950's, this figure appears to be reasonable.
Further, the development cost in the Middle East is approximately $0. 50/
bbl. Note that this figure translates into a price of $4. 30/bbl based on the
same assumptions. This price approximates the world price of oil in
early 1973.
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The early recognized existence of these supergiant fields, which were
discovered at minimal costs, has given the false impression that other,
similar fields can be obtained at "replacement costs." The largest of these
fields is equivalent to 60% of all known U.S. reserves plus past production.
During the last 20 years, an average of 14 billion bbl/yr was discovered
outside these fields in worldwide exploration, but this represents only 7% of
worldwide consumption. As in the situation within the U.S. , most of the
world demand for crude oil is being supplied from additions to reserves
made prior to I960.
Nearly 60% of today's known crude supplies were located prior to 1950.
In 1950, the world's consumption of oil was 10 million bbl/day. At that
time, existing supplies apparently would last more than 100 years. During
the next 23 years, oil products were priced below other energy sources.
Consequently, the increase in the consumption rate of petroleum products
was 8% per year, whereas the total increase of other energy products,
primarily coal, was only 2% per year. In 1973, the consumption rate of
crude oil was 57 million bbl/day. During these 23 years, an average of
only 3. 8 million bbl/day was added to reserves. If a conservative 5%
growth rate of oil consumption is assumed through 1990, the consumption
rate in 1990 would be 90 million bbl/day. To support this consumption, the
finding rate must be increased by a factor of 6 just to keep the supply equal
to demand.
The world statistics were cited because some believe that an abundant
supply of foreign oil will soon be available in the marketplace and that the
"artificial" prices currently being posted will revert to the early 1973 price
of $4. 50/bbl, or to an even lower level. This analysis clearly indicates
otherwise.
8. 7. 5 Future Shale-Oil-Production Cost Analysis
The calculated base price (1973) of a 50:50 mixture of gasoline and dis-
tillate produced from oil shale is $2.05/106 Btu. This figure is based upon
underground mining of 30 gal/ton oil shale. Much of the oil shale to be used
during the mid- and far-term time frames will only contain 15 gal/ton oil.
Therefore, some real cost increases will be associated with processing this
less desirable oil shale.
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First, significant process improvements are not expected to offset these
real cost increases because many of these anticipated improvements have
already been factored into the analysis. For example, the calculated base
price includes the assumption that about 270 tons of oil shale can be mined per
man-day, which is almost 20 times the current average coal productivity
rate for underground mining and more than 8 times the current average rate
for surface mining.
In the base case for oil shale, approximately 58% of the capital and oper-
ating costs are associated with ore processing to the point at which the crude
shale oil has been removed from the shale. Included in this figure is the cost
associated with waste shale disposal. The remaining 42% of the cost is for
upgrading and refining the extracted oil. Few technological improvements
are anticipated in the latter area because of the similarity with crude oil
processing a mature technology.
For gasoline and distillate hydrocarbons derived from oil shale, nearly
90% of the real cost increase is associated with mineral extraction and shale
processing and the other 10% of the real cost increase is associated with
obtaining the adequate supplies of water that are required to support this
industrial development.
The two principal variables in mineral extraction are the assay, which
can vary between 15 to more than 35 gal/ton, and the density of the seams,
some of which exceed 40 feet in diameter. The calculated base 1973 cost was
based on processing only the highest ore concentration in the most desirable
seams. The attendant high mining rates and low capital investment for
underground mining are not realistic for extensive industry development.
The differences between estimated oil shale and coal mining rates and costs
are shown below. (These oil shale mining rates have not been achieved, only
estimated. )
Rate, Capital Cost,
^ TL.X- ' tons/man-day $/tons mined
Deep Mining <-
Oil Shale 271 4. 50
Coal 13 20
Surface Mining, Coal 35 12
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The most current estimate of oil shale reserves is that less than 33%
contain 30 gal/ton oil shale. A few deposits with seams greater than 40 feet
in diameter have been identified; however, there is no known reliable cor-
relation between assay and seam diameter. We estimated that two adjust-
ments will have to be made in mining rates and costs to take less desirable
seams into consideration for large-scale development of the oil shale industry
during the near- and mid-term periods. No adjustment was made for shale
assay in the near-term period.
The first adjustment to be realized in the 1980's lowers the mining rate
from 271 to 135 tons/man-day and increases the capital cost from $4.50
to $9/ton of output. This adjustment adds $0. 65/106 Btu to the cost of new
shale oil purchased.
A similar adjustment would be required 5-10 years later according to the
implementation schedule of a Model I scenario (Section 11). . At this
time, the mining rates drop from 135 to 70 tons/man-day, and the capital
costs increase from $9 to $14/ton of annual output. This adjustment adds
another $0. 62/IO6 Btu to the cost of producing new incremental shale oil.
To place these two adjustments in perspective, note that oil-shale-mining
rates are still twice surface coal-mining rates and more than 5 times under-
ground coal-mining rates. Further, it is being accomplished for only 70%
of the capital cost associated with deep coal mining.
Another real cost that will be increased is that of obtaining water. The
Bureau of Reclamation's estimate of water availability in the area of the
Green River Formation is 5. 8 million acre-ft/.yr (122 million bbl/day).
However, only 11% (11 million bbl/day) is uncommitted and could be made
directly available for commercialization of this industry. This quantity of
water would support the production of about 2 million bbl/day of shale oil,
approximately 56% of the anticipated total production (according to the scenario
based on Model I energy supply) . The economic basis used to determine water
costs was 30^/1000 gal. If adequate water is not available, major capital
expenditures will be required to transport the water over longer distances.
Pipeline capital costs vary between 25^ and 75^/bbl/day/mile. We have
assumed that 60% of the required water must be transported, an average
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of 150 miles (due to the terrain associated with the Green River Formation),
for a capital cost of $0. 75/bbl/day/mile. The capital cost of the transport-
ation portion of the water system is $25 million. Because of the general
lack of water in the area, we have assumed that another $125 million would
be required for the collection and storage portions of the system, both at
the source of supply and at the plant site. The annual operating cost of the
total water system was estimated at 10% of the capital investment. At the
beginning of the mid-term period, these costs will add another $0. 62/106 Btu
to the cost of new incremental shale oil.
In the mid term, the 15 gal/ton ore will have to be mined, so almost
twice as much ore will have to be processed. In addition to doubling the
mining production and the cost for new incremental shale oil, the costs of
retorting, particulate control, and spent shale disposal will increase, which
will add $1. 80/106 Btu to the cost of new incremental shale oil.
In the far term, oil shale seams that are comparable to current (1973)
coal seams will have to be mined. Oil shale mining productivity will drop
from about 70 to about 35 tons/man-day, and the capital cost of oil shale
will increase from $14 to $20/ton of productivity. Consequently,another
$1. 25/106 Btu will be added to the cost of producing shale oil. Table 8-21
reflects the consequence of this and all other real cost increases for oil
shale production.
8. 7. 6 Future Coal-Processing Cost Analysis
Three coal-processing schemes are considered in this study: 1) coal
to an equal mixture of gasoline and distillate, 2) coal to methane, and
3) coal to SNG. The basic assumption used in calculating the respective
base product price in 1973 was that all coal could be supplied at mine mouth
for $0. 30/106 Btu. This assumption was made to ensure that uniform coal
extraction premises and calculations were used in the overall analysis.
However, this coal cost is too optimistic when assessing the development
of a new coal-based synthetic fuel industry. In the future, the rapid exploi-
tation of coal reserves required by the rapid growth of a coal-fuel industry,
per the requisites of this study, makes this coal cost inadequate.
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Period
Near Term
ro
>>
o
Mid Term
Far Term
Table 8-21. REAL COST INCREASES OF SHALE OIL PRODUCTION
Operating Cost Capital Cost
1
Description
Base
Increment Base
$106
Increment
Base: 271 tons/day 51.2 -- 473.7
Capital Cost: $4. 5/ton
30 gal/ton shale
Production: 135 tons/day 72.1 20.9 597.2 123.5
Capital Cost: $9/ton
30 gal/ton shale
Production: 70 tons/day 97 24.9 700 202.8
Capital Cost: $14/ton
30 gal/ton shale
Water 112 15 850 150
Capital Cost: $150X TO6
Operating Cost: $15 X 106
Production: 70 tons/day 167 45 1217 367
Capital Cost: $ 14/ton
15 gal/ton shale
Production: 35 tons/day 244.6 77.6 1304 87
Capital Cost: $20/ton
15 gal/ton shale
Price
Base Increment
$/10° Btu I
2.05
2. 70
3.32
3.94
5.74
6.97
0.65
0.62
0.62
1.80
1.23
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For bituminous coal with a heating value of 24 X 106 Btu/ton (Eastern coal),
this $0. 30/106 Btu cost is equivalent to $7. 2Q/ton. With a heating value of
16 X 106 Btu/ton (Western coal), this quoted cost is equivalent to $4. 80/ton.
Because almost 85% of current coal production is in the East, these statistics
translate into an average coal price of $6. 84/ton. This base price is some-
what lower than the average U. S. mine-mouth coal price of $7. 66/ton in 1972.
However, these prices are well within tolerance when the range of regional
coal prices during 1973 is taken into consideration. These prices varied
from 1. 90/ton to more than $25/ton.
The first objective is to establish the current and future capital and opera-
ting costs of delivering new incremental raw coal feedstock to a mine-mouth
fuel conversion plant. After these data are quantified, they can be used in
the standard DCF calculation. The basic requisites are the capital and operating
costs of putting surface and deep mines into production.
Table 8-22 is an estimate (in 1973 dollars) of the itemized investment
requirements for a new 1 million ton/yr mine. Table. 8-23 is an estimate
of the operating costs for an underground mine. The total capital require-
ment for a surface mine was estimated at $12 million for a 1 million ton/yr
mine. Table 8-24 summarizes the components of the annual operating costs
of surface mining. By using these estimates of capital and operating costs
for mining and calculating the cost of coal based on the standard DCF criteria,
the cost of new deep-mined coal is $16. 23/ton , and the cost of hew surface-
mined coal is $8. 05/ton. In 1972, 275. 7 million tons, or 46% of the total
coal production, was from surface mines, and 319. 7 million tons, or 54%
was from deep mining. The weighted average of the estimated costs for new
coal via the standard DCF criteria is then $12. 46/ton ( $4. 88/ton higher
than the average 1972 production cost) .
The cost of "new" coal is higher than the average 1972 mine-mouth cost
( $7. 66/ton) because either the coal industry is not averaging a 12% return
on its investment and/or the "book value" of its fixed assets is less than the
capital requirements depicted in the estimates.
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Table 8-22. CAPITAL REQUIREMENTS FOR 1 MILLION TON/YEAR
UNDERGROUND MINE
Component Cost, $1000
Underground Equipment 5,750
Trucks, Bulldozers, etc. 175
Exploration 50
Safety Equipment 150
Mine Drainage Equipment 30
Water and Oil Storage 20
Power Substation and Distribution 75
Portal 70
Ventilation 100
Preparation Plant 4, 250
Buildings (Ship, Bathhouse, etc.) 500
Site Preparation 25
Supply Yard 10
Railroad Siding 200
Slope 3,250
Shafts 2,400
Slope Belt and Drive 3,000
Total 20,055
Table 8-23. ANNUAL OPERATING COSTS OF UNDERGROUND MINING
Cost Component Annual Cost, $1000
Utilities 200
Labor
Miners (12.5 tons/man-day, $46/day, 227 days/yr) 3,600
Welfare Fund ( $0. 7/ton ) 700
Maintenance Labor (3% of plant investment) 600
Supervision (15% of 630
operating and maintenance labor)
Administration and General Overhead (60% of 2,900
,' total labor, including supervision)
Supplies
Operating (30% of operating labor) 1,080
Maintenance (3% of plant investment) 600
Local Taxes and Insurance (3% of plant investment) 600
Total 10,910
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Table 8-24. ANNUAL OPERATING COSTS OF SURFACE MINING
Cost Component Annual Cost, $1000
Utilities 100
Labor
Miners ( 37. 1 tons/man-day, $46/day, 225 days/yr) 1,300
.Welfare ( $0. 70/ton) 700
Maintenance (3% plant investment) 360
Supervision (15% of operating and maintenance labor) 250
Adminstration and General Overhead ( 60% of total 1, 150
labor including supervision)
Supplie s
Operating (30% of operating labor) 390
Maintenance (3% of plant investment) 360
Local Taxes and Insurance (3% of plant investment) 360
Total 4,870
By using 1972 price and productivity data and the capital and operating
costs estimated, a set of simultaneous equations was solved to obtain a
reasonable estimate for the current 1973 return on investment and "book
value" of fixed assets for the coal industry. This calculation indicates that
currently the return on investment is about 6%, and the "book value" of the
existing equipment is essentially zero.
The objective of this mining cost analysis is to place all fuel extraction
and conversion processes on an equal basis for comparison. This requires
an adjustment in coal prices so that required new capital expenditures for
coal extraction can be discounted on a consistent basis with crude oil, oil
shale, and uranium. Further, new incremental coal obviously cannot be
placed on-stream without an adequate return on investment. The increased
demand for coal in 1972 and early in 1973 apparently has brought coal
supply and demand back into balance. In fact, the numerous announced
price increases indicate that coal demand may exceed production capacity
this year. In January 1973, the average coal cost to the electric utility
industry was 37. 8^/106 Btu. In January 1974, this cost had climbed to
51. 4^/106 Btu, an increase of nearly 36% in 1 year.
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In summary, a near-term, real cost increase is associated with the ability
to attract the capital for new production capacity. Because 1973 appears
to be a transition year, a reference base must be stablished to assess the
necessary future adjustments. The following shows the basis for this
adjustment in coal costs.
Eastern Coal, Western Coal,
24 X 106 Btu/ton 16 X 1Q6 Btu/ton
Mine Type $/lQ6 Btu
Deep Mine ( $16. 23/ton) 0.68 1.01
Surface Mine ( $8. 05/ton) 0.34 0.50
Currently 85% of coal production is in the East. We have assumed that all
i\f
Eastern mining is deep-mining and Western mining is surface-mining. These
assumptions allow us to determine an average coal price based on current
cost and productivity patterns and a 12% return on investment. This price
is $0. 65/106 Btu, which is the estimated price of new incremental coal in
1972. Therefore, the first real cost increase is $0. 35/106 Btu for new
incremental coal extraction capacity (the difference between the calculated
average cost for near-term mine-mouth coal at a 12% return on investment
and the $0. 30/Btu used to establish the initial, 1973, base costs of coal conversion,
processes).
The consequences of this real cost increase on the coal conversion process
are reflected below:
Coal Conversion Process
SNG Methanol Gasoline Mixture
Cost Components $/l06 Btu-
Base Cost 2.15 3.88 2.80
Incremental Cost 0. 59 0. 89 0. 84
Near Term Cost 2. 74 * 4. 77 3. 64
In 1970, 176 locations in the U.S. were identified as feasible sites for
SNG plants. About 150 million tons of recoverable and uncommitted coal
would be necessary to each of these plants. Further, these locations have
State reclamation costs in the East are nearly $2. 00/ton. These costs
were not included in our estimates.
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water resources adequate for supporting SNG plants but not necessarily
other types of plants because some plants (e.g., methanol) require considerably
more water per plant. These known reserves are equivalent to 26.4 X 109 tons
of coal. This number of plants and the associated reserves were based on an
assumed SNG selling price in accordance with economics prevailing at the time
of this previous study. The production costs for the pattern process used in
this study are necessarily higher, and more sites for coal conversion plants
are feasible at higher product selling prices.
An interesting observation is obtained when total coal requirements are
determined for the Model I scenario (Section 11) of coal conversion processes
over 30 years , which is 5 years beyond the planned program life. This
extension is justified because of the many uncertainties in the precise defin-
ition of these reserves. Nominal-sized, 250 billion Btu/day plants are
assumed here for illustration. These results are shown in Table 8-25.
Table 8-25. TOTAL COAL REQUIREMENT
Annual
No. of Product 30-Year
Fuel Conversion Nominal Reqmt. Reqmt.
Process Plants ' Ton/Plant/Day 109 tons
SNG 100 9.5 0.950 28.5
Methanol 63 13.2 0.832 24.9
Gasoline-Distillate
Mixture 108 12.2 1.328 39.8
;l,
Nominal plant is defined as 250 billion Btu/day output; these are not
necessarily the same size plants described in Appendix B or in the
scenarios of Section 11.
The 176 locations of known coal reserves and with water supplies adequate for
SNG plants are limited to 26.4 X 109 tons of coal. Nevertheless, this
represents only 39% of the total coal requirements for the proposed schedule
(28% if methanol is included, but this is not considered possible per the
scenarios of Section 11) .
According to the planned synthetic fuel industry scenarios, the stated coal
reserves, 26.4 billion tons, that are capable of being mined with existing
technology, with adequate water supplies, will be allocated to existing plants
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in the near term. After 1990, during the mid term, it will be necessary
to begin exploiting less desirable coal reserves less desirable from three
viewpoints: accessibility, seam thickness, and heating value. We have
assumed that the effects of the lower heating value will not change dramati-
cally, that the ratio of strip mining to deep mining will stay the same, but
that the capital cost of mines will double and the operating cost will increase
50%. These cost increases are associated with the lack of accessibility to
thicker coal seams. The net result of these real mining cost increases is
$0. 37/106 Btu, so the new average price of coal is $1. 03/106 Btu.
During this mid term, we also have assumed that, for each plant in
production, water must be collected and transported 100 miles to the plant.
As previously stated, the number of locations that have been identified are
capable of supporting both the coal and water requirements for only about
39% of the anticipated total coal conversion plant requirements (Model I
scenario) . Further, much of the existing coal reserves is located in the
Western States, where water is scarce and/or clustered in a specific region;
more than 25 potential locations are in Illinois. We estimate the per-plant
capital cost of the collection of water and its transportation to and storage
at the plant site will be $150 million, and the annual operating cost
will be $15 million.
The impacts of these mid-term-period increases on the costs of obtaining
coal and water for each of three coal conversion processes are shown in
Table 8-26.
Table 8-26. SYNTHETIC FUEL COST INCREASES DUE TO COAL
AND WATER DEPLETION IN THE MID-TERM PERIOD
Coal Conversion Processes
SNG Methanol Gasoline Mixture
Cost Components $/lOb Btu
Near-Term Cost 2.74 4.77 3.64
Cost Increase 1.26 1.70 1.65
Mid-Term Cost 4.00 6.47 5.29
Toward the end of the mid-term period, the ratio of surface-mining to deep-
mining production is assumed to begin to change. In the mid-term, this ratio
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was held constant at 4:1. By the end of the far term, this ratio will reverse
to 1:4, because the surface deposits will have been depleted to the point
that most new coal will be mined underground. The ratio of the capital and
operating costs of surface mining to those of deep mining is nearly 1:1. 67,
and the corresponding production ratio is 1:2.8. As these ratios reverse,
there will be a corresponding real cost increase, (it should not be inferred
that, because these ratios are constant, technological improvements were
not considered. Technological improvements were considered in the deri-
vation of the real cost increases in the mid term in the same proportion. )
The impact of these real cost increases on the respective coal process-
ing schemes in the far term is shown in Table 8-27.
Table 8-27. SYNTHETIC FUEL COST INCREASES DUE TO SHIFTS IN
MINING TECHNIQUES AND LOWER HEATING VALUE IN THE FAR TERM
Coal Conversion Processes
SNG Methanol Gasoline Mixture
Cost Components $/l(T Btu
Mid-Term Cost 4.00 6.47 5.29
Cost Increase 0. 60 0. 89 0. 87
Far-Term Cost 4. 60 7.36 . 6.16
8. 7. 7 Future Real Cost Increases for Thermochemical Hydrogen
The only real cost increases anticipated are reactor fuel costs: mining
and milling, and enrichment. These cost components represent 40% and
45%, respectively, of the total reactor fuel costs. Present mining and
milling costs are based on $8/lb of uranium oxide and $10/lb of thorium
oxide. The thorium oxide requirements for the nuclear industry are cur-
rently about 10% of the uranium oxide requirements.
The $8/lb uranium oxide ( yellowcake) price is based on AEC cost analysis
procedures and does not include all costs of a private enterprise situation.
The basic cost components in the AEC cost analysis are the "out of pocket"
costs of mining, handling, royalty, milling, and mill recovery. Private
enterprise real cost components not included are property acquisition,
exploration, cost of money, and a return on investment. Consequently, the
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real costs of uranium ( and thorium) extraction are understated, at least
from a private industry viewpoint. Historically, the cost components not
included in the AEC analysis have not produced inaccurate results because
reserves and production capabilities were approximately 50% of demand;-
therefore, "out of pocket" costs are all that are required to conduct the
appropriate incremental cost analysis.
In 1979, demand is predicted to exceed supply, and in 1983 the demand is
projected to be 3 times the current production capacity. This situation
requires a more detailed analysis of the cost components that previously
have been excluded. A detailed analysis in this area is beyond the scope of
this program. The basic problem is that this segment of the uranium industry
is too decentralized and there is no uniform reporting of economic data other
than AEC data. At present, almost 200 mines are servicing some 20 mills
to produce 13,000 tons/yr of U3O8. This quantity of yellowcake requires the
extraction of nearly 7 million tons of ore, 60% of which is surface-mined,
and 40% of which is produced from deep mines. The mining rates are
comparable with those for coal mining, 50 tons /man-day and 10 tons/man-day,
respectively.
Current known U. S. reserves total 273,000 tons of uranium as U3O8 at $8/lb,
only 4 times the 1985 requirements. The depths of these reserves are as
follows: 49% less than 400 ft, 44% between 400 and 2250 ft, and 17% more
than 2250 ft. Present production is 60% at less than 400 ft and 30% between
400 and 800 ft. Clearly, radical shifts in mining must occur to tap these
reserves. Also, these known reserves are not necessarily adequate to
support a new mine for over a 20-30 year life span.
The AEC's estimates28'29 of exploitable uranium reserves are shown in
Table 8-28.
Table 8-28. U.S. URANIUM RESERVES
Reasonably Assured, Tons of Ore Mined
1000 tons, U3O8 $/lb (U3O8) per Ton of U3OB
427 10 500
630 15 800
800 30 4,000
4,800 50 13,000
218
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During the period 1966-1972, from $0. 23/lb to $1.95/lb. has been spent
for exploration and development per ton of uranium oxide added to reserves,
with the highest value occurring in 1972. Drilling costs have been relatively
constant during this period (and very cheap when compared to crude oil
drilling costs) $1. 20/ft with exploration and development costs of $1. 30/ft
and $0. 90 ft, respectively. During this period, the average depth/hole
increased from 187 to 439. If these reasonably assured estimates are
correct, the reserves-to-production ratio for $30/lb uranium oxide is
approximately 10 for currently scheduled domestic production during the
1980's. The significant point is the near- to mid-term increase in the amount
of ore that must be mined to produce 1 ton of uranium oxide; this is an
eightfold increase.
An estimated 9-H years are required to initiate new incremental mining,
milling, and conversion processes (for enrichment). In the mid-1980's,
the annual demand for yellowcake is estimated to be 70,000 tons/yr. If
this quantity is to be obtained for $30/lb, almost 280 million tons of ore
would have to be mined, a 40-fold increase over current production. (If
this quantity is obtained at $50/lb, the uranium-mining operation would have
to be twice the size of the existing coal-mining capacity.) Regardless,
it is doubtful that domestic reserves will be developed at a higher expense.
Worldwide uranium reserves at $15-30/lb (U3O8) are numerous. There-
fore, international trade in uranium will probably be expensive. Further,
yellowcake at $30/lb is considerably cheaper than oil at $24/bbl (domestic,
year 2000) on an equivalent Btu basis. For these reasons, the maximum
real price increase for yellowcake is assumed not to exceed 375% by about
the year 2000, the far-term period.
Economic analysis of the enrichment sector of the uranium industry is
more straightforward. All three plant sites are Government-operated, so
the appropriate data are available. These plants were installed between
1944 and 1956, and approximately 67% of the existing capacity was added in
I
the mid-1950's.
Estimates for new enrichment costs can be found in AEC reports. 25' 26
The AEC capital cost estimate for new enrichment capacity is $ 157/SWU,
based on 1971 dollars. Technology improvements anticipated during the
1970's will decrease this cost to $144/SWU. Several consortia in the
219
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private sector who are doing their own evaluations have reported costs
as high as $171/SWU. For this analysis we have used $144/SWU for
new technology development. Also associated with the new technology
development was a 17% reduction in total power requirements. Because
nearly 94% of the operating cost is the cost of power, these savings
are significant.
To determine the appropriate power cost for a new enrichment plant, the
data generated to determine the cost of the nuclear heat requirements for
thermochemical processing of hydrogen were used. The processing of these
cost data in the standard DCF calculations produced a power cost of 13. 44
mills/kWhr.
For 8. 75 million SWU/yr plant, which is comparable to one of the new
module additions to the existing enrichment complex, the power requirement
is estimated at 2050 MW. For 13. 44 mills /kWhr,the annual power cost is
$323.46 million. The other operating charges are estimated at $15 million,
and the capital requirement at: $1 billion. The enriching cost resulting from
the standard DCF calculations is $66/SWU. (if the capital cost were $17l/SWU,
the high value reported; the cost of enrichment would be $81/SWU. ) The
incremental cost associated with the anticipated 17% power reduction is nearly
$4/SWU.
In summary, we anticipate that uranium oxide costs will increase from
$8/lb to $30/lb and that enrichment costs will increase from $26/SWU to
$66/SWU. In turn, these cost increases should increase the cost of the
reactor heat output by approximately $0. 70/106 Btu, which would result in
a cost increase of hydrogen of $1.40/106 Btu. However,' the cost analysis
just described does not include a credit for the recycle of U233 (bred from
Th232) . This recycling of U233 is estimated to reduce the overall HTGR fuel
requirements by 60% over the life of the project. This results in a potential
cost increase of $0. 84/106 Btu for thermochemical hydrogen by the far term.
As previously stated, a 1% increase in heat transfer or energy conversion
efficiency is equivalent to a $0. 12/106 Btu reduction in the cost of producing
hydrogen. Such improvements can be achieved in two areas, the reactor
and the chemical reaction cycle. The thermochemical process efficiency
used in this analysis was 50%. This energy conversion efficiency (reactor
plus chemical reaction cycle) can be improved to 55% by the far term.
220
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Such an improvement is equivalent to a reduction of $0. 60/106 Btu in hydrogen
production cost.
The net result of the future cost analysis of the production of thermo-
chemical hydrogen is that the base 1973 cost of $4. 55/1Q6 Btu will increase to
$4.79/l06 Btu.
8. 7. 8 Future Cost Analysis Summary
The projected future costs associated with delivering synthesized fuels
to the service stations are depicted in Table 8-29. These costs are based
upon the cost components described in the preceding sections. There is a
reasonable potential for other real cost increases not reflected in these
sections. They were not included because, being in the realm of societal
impacts and human factors, they cannot be quantified within the scope of
this study and/or because these cost increases are generally applicable
to all candidate fuel schemes; therefore, they would not contribute directly
to comparative analysis.
Because the synthetic fuel processing industry will be labor-intensive and
frequently located in sparsely populated areas, additional time may be
required to attract and train the appropriate labor force. This problem is
compounded by competition among candidate-fuel sectors for skilled personnel.
A common skilled labor classification for the coal, the oil shale, and the
uranium industries is miners. Assuming reasonable productivity increases
per miner, a fivefold increase over the present mining manpower, to 750,000
miners, will be needed by the early 1990's . No attempt has been made to
quantify the number of professionals required in this area; however, this
may represent a greater constraint, because less than 300 new graduates
are entering this profession in the U.S. each year.
The construction period, 3. 5 years, used in this analysis was for ideal
conditions.. Considering possible industrial implementation schedules, there
is a high probability that the construction period could be extended to 9 years,
the current planned schedule for nuclear reactors. Such a slippage would
add between $0. 50 and $1. 00/106 Btu to the unit cost of the fuels involved.
Another consideration is the cost of money, i. e. , the expense associated
with attracting new capital. Current interest rates are at least 33% higher
221
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Table 8-29. PROJECTED COSTS OF CANDIDATE ALTERNATIVE FUELS'
tv
tVJ
Resource Base and
Synthetic Fuel
Coal
Gasoline and Distillate Oil
Methanol
SNG°
Oil Shale
Gasoline and Distillate Oil
Nuclear Heat,
Hydrogen
Hydrogen
Domestic Crude
Production Costs
Transmission and
Total Costs
1985
3. 64
4. 77
2.74
3.32
f
f
2000
5.29
6.47
4.00
5.74
4.79
4.79
2020 Distribution Costs 1985 2000
6.16
7.36
4. 60
6.97
4. 79
4. 79
$/ 1 nb rn-n
1.06
1.34
2. 04
1.06
3.83
2.21
4. 70 6. 35
6.11 7.81
4.78 6.04
4. 38 6. 80
f 8.62
f 7.00
2020
7.22
8. 70
6.64
8.03
8.62
7. 00
Reference Gasoline
2. 76
4.56
7.82
1.20
3.96
5.76 9.02
Basis: low heating values of the fuels.
50:50 product mix, average price.
SNG transmission and distribution as a gas, liquiefied at service stations.
Thermochemical hydrogen transmission to terminals as a gas, liquefied and distributed in liquid
hydrogen trucks to service stations.
Thermochemical hydrogen transmission and distribution as a gas, combined as a metal hydride at
service stations.
Technology gap, near -term hypothetical production cost, $4. 55/106 Btu.
-------
than those in 1973. Based upon the industry scenarios of Section 11 (or
anything like these schedules) , the demand for capital goods will continue
to be strong; therefore, interest rates will not decrease appreciably. The
initial yearly capital requirements for the oil shale industry, for example,
will be approximately $ 1 billion, or nearly 20% of the planned capital
expenditures for the petroleum industry between 1971 and 1974 inclusive.
In general, to meet the capitalization schedule, the industry debt-to-
equity ratio must be increased. A precise estimate of these consequences
is difficult to obtain. A first-order approximation can be obtained by
increasing the "cost of capital" in a DCF calculation , holding all other
parameters constant. The resulting difference in the cost of the fuel
product over the project life, 25 years; is from $0.40/106 Btu to $0. 60/106
Btu (added to the cost of producing the product).
The ratios pertaining to water requirements are shown in Table 8-18 to
emphasize the criticality of water in many potential site locations. Although
allowances were made for the potential cost increase of transporting increr
mental water requirements to these sites, some of the regional consequences
have to be considered when more and more synthetic fuel plants are placed
on-stream. Seasonal weathe.r variations could affect production at plants
with limited water availability. When water costs are approached from
this point of view, the estimates used may prove to be too conservative.
An additional socio-economic consideration is the cost of the development
of new communities in sparsely populated areas to attract personnel. This
incremental cost increase is only about $0. 10/106 Btu over the project life.
That all these incremental costs will occur simultaneously across the
industry is highly unlikely. Nevertheless, some portion of these costs
probably will be incurred in the aggregate. Because of the strong demand
for energy, some of these additional cost increases will be experienced to
various degrees in all three time frames.
223
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8. 8 References Cited
1. Brown, K. B. and Ferguson, D. E. , "Uranium Supply Crisis? " Letter
to the Editor, Nucl. News 17, 32 (1974) April.
2. Chase Manhattan Bank, "Capital Investments of the World Petroleum
Industry, " PS 24. New York, n. d.
3. Dual Fuel Systems, Inc. , Los Angeles, private communication,
December 1973.
4. Federal Power Commission, 1970 National Power Survey, Part III, 3-119.
Washington, D. C. , 1970.
5. Gregory, D. P. , Anderson, P. J. , Dufour, R. J. , Elkins, R. H. ,
Escher, W. J. D. , Foster, R. B. , Long, G. M. , Wurm, J. and Yie, G. G. ,
A Hydrogen-Energy System. Arlington, Va. American Gas Association, 1972.
A. G.A. Catalog No. 121173T
6. Grigsby, E. K. , Mills, E. W. and Collins, D. C. , "Refiners Facing
Future Need for $5. 3 Billion/Year Investments, " Oil Gas J. 71, 76-80
(1973) May 7.
7. Hanson, A. M. et al. , "Plant Scale Evaluation of a Fungal Amylase Process
for Grain Ale ohoTT^Agr. Food Chem. 3_, 866-72 (1955).
8. Jeynes, P. H. , Profitability and Economic Choice. Ames, Iowa: Iowa
State University Press, 1968.
9. Johnson, J. E. , "The Economics of Liquid Hydrogen Supply for Air
Transportation. " Paper presented at the Cryogenic Engineering Conference,
Atlanta, August 10, 1973.
10. Kephart, W. L. , "The Energy Supply-Demand Balance Through 1990. "
Remarks delivered at IGT/Chase Econometric Seminars, Washington, D. C.
and Houston, March 1974.
11. Miller, D. L. , "Industrial Alcohol From Wheat, " U. S. Agricultural
Research Service Report of Sixth National Conference on Wheat Utiliza-
tion Research, 20-33. Washington, D. C. , 1969.
12. National Petroleum Council, U. S. Energy Outlook, A Report of the National
Petroleum Council's Committee on U.S. Energy Outlook. Washington,
D. C. , December 1972~I
13. Nelson, W. L. , "How to Allocate Operating Cost to Each Product, "
Oil Gas J. 61, 108, 109 (1963) August 5.
14. Nelson, W. J. , "Allocation of Operating Costs Again, " Oil Gas J. 64,
128 (1966) October 24.
15. O'Donnell, J. P., "Pipeline Economics, " Oil Gas J. 71, 69-96(1973)
August 13.
224
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16. Pangborn, J. B. and Sharer, J. C. , "Analysis of Thermochemical Water -
Splitting Cycles, " in Proceedings of the Hydrogen Economy Miami
(THEME) Conference . Coral Gables, Fla. ; University of Miami,
March 1974.
17. "Problems Abound But So Does Optimism," Combustion 44, 6-9 (1973)
June.
18. "Reserves Exploration Rate Hike Needed, Report Says," Nucl. News.
16_, 96 (1973) November.
19. "Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the
United States and Canada and United States Productive Capacity as of
December 31, 1973, "^8. Arlington, Va. : American Gas Association;
Washington, D. C. : American Petroleum Institute; Calgary, Alberta:
Canadian Petroleum Association, June 1974.
20. Shaw, G. V. and Loomis, A. W. , Eds. , Cameron Hydraulic Data.
New York: Inger soil -Rand Co. , Cameron Pump Division, 1958.
21. Synthetic Gas -Coal Task Force, The Supply -Technical Advisory Task
Force Synthetic Gas -Coal. Prepared for the Supply -Technical Advisory
Committee, National Gas Survey, Federal Power Commission, April 1973.
22. Szego, G. and Kemp, C. , "Energy Forests and Fuel Plantations, "
Chem. Tech. 3_, 75-84 (1973) May.
23. "Technical Review of and Cost Data for Reactor Concepts, " Combustion
42_, 12-23 (1971) June.
24. Tremmel, E. D. , "The Nuclear Industry, 1971," USAEC Report WASH -
1174-71, Washington, D. C.: U.S. Government Printing Office, 1971.
25. U.S. Atomic Energy Commission, "AEC Gaseous Diffusion Plant
' Operation, " PRO -6 84. Oak Ridge, Term. : USAEC Technical Information
Center, January 1972.
26. U.S. Atomic Energy Commission, "Data on New Gaseous Diffusion Plants,"
ORO-685. Oak Ridge, Tenn. : USAEC Technical Information Center,
April 1972.
27. U.S. Atomic Energy Commission, "Forecast of Growth of Nuclear
Power, " WASH- 11 39. Washington, D. C. : U.S. Government Printing
Office, January 1971.
28. U.S. Atomic Energy Commission, "Nuclear Fuel Resources and Require-
ments," WASH-1243. Washington, D. C. : U.S. Government Printing
Office, April 1973.
29. U.S. Atomic Energy Commission, "Nuclear Fuel Supply, " WASH-1242.
Washington, D. C. : U.S. Government Printing Office, May "
30. "U.S. Producers Fear Uranium Imports, " Chem. Eng. News 52, 7
(1974) May 13. --
225
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31. Wasp., E. J. and Thompson, T. L. > "Slurry Pipelines. . . Energy
Movers of the Future, " Oil Gas J. 71, 44-50 (1973) December 24.
32. White, J. E. , "Economics of Scale Applies in Long-Distance Pipeline
Transport," Oil Gas J. 67, 149-54 (196.9) January 27.
33. Winton, J. M., "Plant Sites, " Chem. Week 111, 35-56 (1972)
October 11.
226
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9. TECHNOLOGY AND INFORMATION GAPS
In this study, a "technology gap" is defined as a lack of technical
capability that makes an otherwise acceptable fuel impractical. This
technical problem might be solved by intensive research and development.
We have further qualified technology gaps as serious or moderate. A
serious technology gap eliminates a fuel from general supplementive use
(as an alternative fuel) before the year 2000 because of the lead times
required for research, development, prototype achievement, demonstra-
tion, operation and testing (plant or product), and production plant (or
industry) construction and operation. Less serious (moderate) technology
gaps, such as a fuel storage technique or an emission control device,
eliminate a fuel for the near term (before 1985).
As the study progressed, we encountered another type of gap: informa-
tion. In some cases, the data necessary to properly evaluate the potentials
of candidate fuels do not exist, are imprecise and subject to controversy,
or are subject to restricted access. In other cases, laboratory or vehicle
tests are required to obtain measurements.
9. 1 Serious Technology Gaps
9. 1. 1 Solar Energy to Chemical Fuel
With present agricultural technology, solar energy is converted to
plant material at an efficiency of about 1%. After the latter's conver-
sion to a chemical fuel, the overall efficiency is about 0. 5%. Although
the energy is free, the land area and capital investment are not. To be
practical, a solar plantation needs higher efficiencies (2-5% for the crop).
The lack of an efficient and economical fuel crop constitutes a serious
technology gap.
A heat-to-work (or fuel) cycle based on solar energy (alone) that could
achieve an overall efficiency of 15-25% would be a significant develop-
ment. Concepts have been proposed, but specific processes that could,
by demonstration, lead to proof of concept do not exist. Such a process
would decrease the land area requirements of current agricultural methods
by a factor of 30-50.
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9. 1. 2 Demonstration of Nuclear Fusion
As a potential source of energy, almost without raw material limits,
fusion reactors promise to be an eventual solution to the continuing energy
crisis. Aside from capital investment limitations, reactors creating the
fusion of deuterium nuclei and extracting some of the produced energy
could be used for electricity generation or process heat applications.
However, demonstration of net energy production from a continuously
operating fusion mechanism is not anticipated in the near future; this
requirement constitutes a serious technology gap.
9. 1. 3 Hydrogen From Water
A nonfossil and nonelectric process for producing a chemical fuel
from a renewable material resource is highly desirable. To date, the
best prospects are for the thermochemical production of hydrogen from
water. Such a process might be coupled to solar energy, nuclear fusion
process heat, or nuclear fission process heat to provide adequate amounts
of a chemical fuel in the future. Methane or alcohol from water and a
renewable carbon resource (e. g. , carbon dioxide, plants) or an extensive
resource (limestone) are other possibilities.
Of key importance is the ability to extract useful energy from nuclear
heat in the future at higher efficiencies than are now possible. Although
involved, an exercise with energy demand and supply Model I (optimistic
for self-sufficiency) illustrates this point. If the heat from future nuclear
and coal sources is utilized at an overall efficiency of 30%, some deficits
occur in certain market sectors in all time periods. With this condition
we can never be self-sufficient, even though we have plenty of raw heat
as "prime" energy. In practice, nuclear reactors are now about 30%
efficient. Model I assumes a 35% conversion efficiency; this results in
potential self-sufficiency from about 1985 until 2000. If we achieve an
overall conversion efficiency of 40%, we can be self-sufficient with
nuclear fission (breeders required) and coal for a much longer period.
228
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9. 2 Moderate Technology Gaps
9. 2. 1 Breeder Reactors
The production of fissile fuels (uranium or plutonium) from fertile
materials (thorium or depleted uranium) is a practical requirement for
nuclear energy to be assured as a major energy supply beyond 1985.
The breeding of U233 or Pu239 has been demonstrated, and the limited
production of U233 from Th232 occurs in the newly commercialized HTGR's.
However, demonstration of a fast breeder reactor is needed to show
commercial potential for net production of fissile fuel. On the basis of
the data in Table 3-2, the development of plutonium breeding could result
in 75 times as much heat energy from nuclear reactors.
9. 2. 2 Distribution of Cryogenic Fuels
Two of the candidate alternative fuels, hydrogen and SNG, can be
distributed as cryogenic liquids. The technology and the hardware for
transferring such fuels from different containers exist, but safety re-
quirements are necessarily extreme, and the equipment is expensive and
sophisticated compared with that for conventional fuel transfer. For
practical distribution to vehicles at service stations, the following tech-
niques and equipment are required:
Safe filling of an initially warm tank by reliquefying, venting (if safe,
economical, and environmentally acceptable), or combusting the vapor-
ized portion of the fuel
Fail-safe devices for containing the cryogenic liquid and preventing
human contact
Prevention of liquid air or liquid oxygen formation in the case of
liquid hydrogen fuel.
In the case of liquid hydrogen, a large portion (about 30%) of the
fuel's heating value is spent in liquefaction. More efficient processes
or a cycle in which the latent heat is used would lower the distribution
costs for hydrogen and make them more attractive.
229
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9.2.3 Vehicle Storage of Hydrogen
At present, no satisfactory method for tanking sufficient hydrogen on-
board a vehicle exists. Three options have been considered: liquid
hydrogen and metal hydrides, which have drawbacks, and chemical
storage, which shows promise.
1. Liquid hydrogen is bulky, requires vacuum-jacketed tanks, and
suffers from the problems enumerated above.
2. Metal hydride storage is too heavy and, in most cases, requires
moderate- or high-temperature heat for decomposition to "generate"
the hydrogen. The logistics of hydride regeneration have not been
defined sufficiently, and the most practical and cost-effective scheme
has not been delineated. A systems study is required. The options
are a) to recharge the hydride in a container fixed on-board the
vehicle, b) to replace the vehicle container (canister) with another
that is charged at the service station or elsewhere, or c) to dump
the spent hydride at the service station and refill the container,
which remains on-board the vehicle, with regenerated hydride.
3. Hydrogen can be carried by chemical bonding as another material,
preferably as a liquid, such as methanol, gasoline, formaldehyde,
or acetic acid. These chemicals can be decomposed (reformed)
on-board the vehicle to produce hydrogen. Feasibility studies and
experimental programs are required.
9.2.4 SLPG From Coal
Coal is easily gasified to carbon monoxide and hydrogen. Selective
formation of Cz, C3, and C4 hydrocarbons from this synthesis gas re-
quires a catalytic process not yet known, or at least not published. If a
suitable catalyst were developed, this process would make SLPG a more
viable alternative fuel.
9. 2. 5 Vehicle Combustion of Solvent-Refined Coal
According to Model I (and inherent in Model II), direct combustion
of coal as a fuel would help solve our future energy supply problems
because resource-to-fuel conversion efficiencies would probably exceed
90% (coal to solvent-refined coal). An external, continuous-combustion
engine cycle could utilize solvent-refined coal, but problems with ash and
gaseous pollutants (primarily sulfur dioxide in addition to carbon mono-
xide, NOX, and possibly traces of heavy metals, would have to be solved.
In addition, a suitable vehicle-refueling scheme would have to be devised.
With convenient distribution and acceptable combustion, solvent-refined coal
would become a more desirable alternative fuel.
230
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9. 3 Information Gaps
The following questions could be answered by performing laboratory
experiments:
a. What additives for methanol and gasoline blends allow up to 1%
(or more) water to be accommodated without phase separation?
b. What additives for methanol and gasoline blends prevent phase
separation at low temperatures (0° to 20°F)?
c. What additives for methanol decrease the flash point of the mixture
from 50°F (methanol) to -20°F (mixture)? These additives would
enable quick and convenient cold-engine starts. However, the addi-
tive should not adversely increase high-temperature vapor pressure
and result in vapor lock at normal engine-running temperatures.
The following questions could be answered by vehicle and/or engine
tests conducted by scientific methods with appropriate controls:
a. How energy-efficient are vehicles with spark-ignited, internal-
combustion engines that meet 197? emission standards when
these vehicles are operated on
Conventional gasoline (reference)?
Coal-derived gasoline?
Shale-oil-derived gasoline?
Blends of coal gasoline and/or shale oil gasoline with conventional
gasoline?
Methanol?
Methanol-gasoline blends?
Hydrogen?
SNG?
To obtain meaningful answers, knowledge of and control over fuel
combustion ratings, air/fuel equivalence ratios, and vehicle charac-
teristics are required. These efficiencies can affect consumer costs,
but they probably cannot have sufficient impact on overall energy
requirements or resource depletion.
b. How energy-efficient are experimental engines of different types
(Rankine, Brayton, etc. ) when they are operated on different alter-
native fuels?
c. What are the emissions and pollutants from the alternative fuels when
used in a standard engine? Do the additives for the methanol-gasoline
blends cause new pollutants? When hydrogen is used as a fuel in an
internal combustion engine, is hydrogen peroxide emission significant?
If so, can it be controlled or reduced to acceptable levels if necessary?
The following hardware development may be necessary, depending on
alternative fuel implementation:
231
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a. A safeguard device for (catalytic) combustion on the vehicle tank to
prevent venting of hydrogen, SNG, or LPG vapors from becoming a
flammability hazard.
b. A service station metering device for methanol that is sensitive to
water content; this will deter illegal "watering" of the fuel.
c. A warning device to alert passengers of the presence of methanol
vapors inside an automobile. For methanol, the least detectable odor
occurs at 100 ppm in air, and the maximum allowable concentration
for prolonged exposure is only 200 ppm.
i
The following information could be derived by further feasibility and
impact studies on alternative fuels for automotive transportation:
a. The economic and social impacts of an alternative fuel system based
on coal in Montana, Wyoming, North Dakota, and the Four Corners
area (New Mexico) as well as in the Eastern States.
b. The economic and social impacts of an alternative fuel system based
on oil shale in Colorado, Utah, and Wyoming.
c. The derivation of a continually updated energy demand and supply
model in a computerized format, which would permit energy deficits
and excesses in future time frames. Emphasis could be given to
the automotive sector of the economy. Given a computerized version
of the methodology of Section 2, the need for and the quantities and
types of alternative fuel could be predicted.
The following information exists but was not available to this study:
a. Actual energy expenditures in the mining, refining, and enriching of
uranium for nuclear fuel usage; this information is classified.
b. The numbers and locations of coal-to-synthetic fuel plants versus the
selling price of the produced fuel; this information (for SNG) is
proprietary.
c. The numbers and locations of oil-shale-processing plants versus the
selling price of the produced fuel; this information is proprietary,
as are details of experimental in situ shale oil processes.
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10. SELECTION OF CANDIDATE ALTERNATIVE FUELS
10. 1 Preliminary Fuel Selection
According to the methodology described in Section 2, we have applied
information described in Sections 3 through 9 to the potential alternative
fuels. The fuel system rating is based on six general categories:
Adequacy of energy and material availability and competing demands
for fuel
The existence of known or developing fuel synthesis technologies
Safety (toxicity) and handling properties of fuels
Relative compatibility with fuel transport facilities and utilization equip-
ment (tanks and engines)
Severity of environmental impacts and resource depletion
Fuel system economics (resource extraction, fuel synthesis and de-
livery, automotive utilization).
In each category, the fuels are rated on a numerical basis of 1 to 5, except
for fuel costs, safety, and handling properties, which are normalized to
those of reference gasoline. Section 2 explains the normalization procedure.
In summary,the indices are as follows:
Toxicity ratio (fuel concentration in air for 8-hour exposure limit)
-i
/ ppm fuel \
ppm gasoline
Tankage index (weight and volume of fuel)
fuel tankage weight fuel tankage volume
gasoline tankage weight gasoline tankage volume
Cost index (fuel at service station)
fuel cost, $/106 Btu
gasoline cost, $/10b Btu
235
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The numerical ratings are outlined below.
Fuel Availability (Energy Sources and Fuels)
1 Probable. The energy supply is currently available (potentially)
because it exceeds, by a factor of 5 or more, the 25 year-15%
transportation demand requirement of about 108 X 10*5 Btu (as
fuel). The fuel is not required elsewhere (in market sectors of
higher priority) and would be substantially available for trans-
portation.
2 Possible. The energy supply is available (potentially) because
it is 2-5 times the 25 year-15% transportation demand require-
ment of about 108 X 1015 Btu (as fuel). Although not required
elsewhere, the fuel is desired as a chemical commodity.
3 Speculative. The energy supply is 1-2 times the demand require-
ment of 108 X 1015 Btu (as fuel). The fuel is desired elsewhere.
5 Not Adequate: or Available. The energy supply is less than the
demand requirement of 108 X 1015 Btu (as fuel). The fuel is re-
quired for a high-priority deficit in a market sector other than
transportation.
Synthesis Technology
1 Probable. Commercial processes or demonstration plants
could be built.
2 Possible. Synthesis processes are developmental and require
pilot-plant testing.
3 Speculative. Conceptual or laboratory methods exist, constituting
a moderate technology gap.
5 Serious Technology Gap. The synthesis route needs proof of
concept and laboratory development.
Transmission and Distribution Compatibility
1 Probably Compatible. The fuel can use the present system.
2 Possibly Compatible. The fuel has its own system or can use
the present system with modifications; some new equipment
is needed.
3 Speculative. Essentially all new equipment is needed for a
workable system.
5 Incompatible. Not only is the fuel incompatible with transport
systems, but also new, sophisticated equipment that is needed is
beyond practicality.
236
-------
Engine Compatibility
1 Probably Compatible. No changes or very minor changes to the
engine are required (e. g. , carburetor adjustment).
2 Possibly Compatible. Some design changes or add-ons and major
adjustments are required (e.g. , change intake manifold and car-
buretor).
3 Speculative. Major engine design changes are necessary, or an
existing engine would require extensive rebuilding (e.g. , change
compression ratio).
5 Incompatible. The fuel is not suitable for use in the engine type;
tests have shown it to be impractical or impossible.
Environmental Effects
Of the alternative fuels considered, only solvent-refined coal would
be expected to produce emissions of the type that are beyond the
capability of automotive emission controls now being developed.
Overall system effects cannot be determined at this time. All fuels
are given a "2, " except coal, which is given a "5. "
Table 10-1 shows the application of these criteria to the potential fuels.
The numbers in Table 10-1 were assigned for the following reasons:
10.1.1 Synthesis Technology (Section 5)
The survey of synthesis technologies has concluded that acetylene,
ammonia, carbon monoxide, gasoline, distillate hydrocarbons, alcohols,
and vegetable oils have synthesis processes sufficiently well-developed to
be classified as probable (or No. l).
Solvent-refining of coal is by itself in the "probable" classification,
but better methods of sulfur and ash removal would be needed before solvent-
refined coal could be used as an automotive fuel.
Hydrazine and methylamine are rated as "possible" because processes
that might work directly from synthesis gas and nitrogen have not been
developed. With present technology, we must consume "better" fuels such
as ammonia and methanol to make these fuels.
SLPG suffers from a moderate synthesis technology gap, described
in Section 9. SLPG therefore is rated as "speculative. "
237
-------
oo
Table 10-1. PRELIMINARY FUEL SELECTION BY RANKING RELATIVE TO GASOLINE
Compatibility
Synthesis
Fuel Technology
Acetylene 1
Ammonia 1
Carbon Monoxide 1
Coal (Solvent Refined) 2
Distillate Oils 1
Ethanol (Agriculture) 1
Gasoline (Reference) l
Gasoline (Synthetic) 1
Hydrazine 2
Hydrogen 1
SLPG 3
Methanol 1
Methylamine 2
SNG 1
Vegetable Oil 1
Fuel Availability Competition Safety and Handling
1975-85
3
3
2
3
2
5
1
2
3
Z
5
2
3
5
5
1985-2000
2
3
2
2
2
5
2
2
2
2
5
2
2
5
5
2000-2000+ Toxicity Tankage
2 0 10.
2 5 4.
2 5 41.
202.
2 1 2.
3 0.5 3.
3 1 2.
2 1 2.
2 500 7.
206:
502.
1 2.5 3.
2 50 3.
503.
302.
5
7
0
2
0
0 '
0
0
6
2
4
9
4
2
1
Trans-
mission
5
2
2
2
2
2
1
1
5
2
2
2
3
2
2
Distri-
bution
3
3
5
5
2
2
1
1
5
3
3
2
5
3
2
Conventional
Engine
5
3
3
5
5
2
1
1
5
2
2
2
5
2
2
Unconventional Environmental Costs at
Engine Effects Station
3 2 5.4
2 2 2.2
3 2 1.6
3 5 0. 8
2 2 1.0
2 2 4.3
2 2 " 1.0
2 2 1.3
2 2 9. 8
2 2 2.4
2 2 1.5
2 2 1.2
3 2 3.2
2 2 1.5
2 2 10.8
Score Final
(L) Rankin]
41.
32.
69.
32.
24.
31.
18.
18.
545.
26.
32.
24.
83.
31.
39.
9
9
6
0
0
8
0
3
4
6
9
6
6
7
9
10
8
11
7
2
6
1
13
4
8
3
12
5
9
B-94-1777
-------
10.1.2 Fuel Availability (Sections 2. 3 and 4)
The ratings for fuel availability have been awarded uniformly, except for
certain fuels that are sure to be in short supply to the automotive sector
because of competition from other demand sectors or technical limitations.
Reference gasoline/ refined from domestic petroleum, is graded "very
available" in the first time frame. In the second time frame, it is rated
"possibly available," acknowledging the relative inelasticity of domestic
petroleum supplies. In the post-2000 period, conventional gasoline is ex-
pected to be a minority fuel for automotive transportation. In this time
frame, it is rated "speculative. "
For fuels with a synthesis technology limitation, rated "2, " availability
is "speculative, " at least in the first time frame. The moderate technology
gap for production of synthetic LPG from coal effectively eliminates LPG
until the mid-term period when the low-level output from newly developed
processes would be demanded by other priority markets (residential and
commercial).
The agricultural fuels, ethanol and vegetable oils, are given low ratings
for availability for the first time frame because of the large amounts of
land required by today's agricultural technology for the production of sig-
nificant amounts of fuel.
SNG and SLPG will be available in very limited quantities during the
time frames of this study, and they are considered to be not available for
general automotive use.
Other fuels are given moderate availability ratings for all time frames.
10.1.3 Safety and Handling (Appendix A and Section 6)
Data for ratings on toxicity and tankage are taken from the tables of
Appendix A. These criteria are quantified by the toxicity ratio and tankage
index. The toxicity ratios of hydrazine and methylamine are so high that
they effectively eliminate-these fuels from further consideration. This
seems proper and reasonable for fuels that are more toxic than gasoline
by 2 or 3 orders of magnitude.
239
-------
10.1.4 Compatibility and Utilization (Section 6)
For the preliminary fuel selection, compatibility has been judged in
four areas:
Compatibility with the present transmission system
Compatibility with the present distribution system
Compatibility with present automobile engines
Compatibility with unconventional power plants that might be
introduced in the future (stratified-charge, Brayton, Rankine,
or Stirling engines or fuel cells).
The ratings recorded for compatibility with transmission and distribution
systems have been determined subjectively for the reasons given in Section 6.
The need for fuel compatibility with present or future power plants is
clear. Even if only slight modifications to vehicles are necessary, there
will be resistance to introduction of the new fuel. Two of the prime movers
currently under consideration are most sensitive to fuel characteristics:
fuel cells and conventional Otto-cycle engines. Diesel engines are less sen-
sitive, and stratif ied-charge engines can be designed for operation with
several different fuels. Continuous-combustion engines can be designed to
accommodate almost any of the potential alternative fuels.
Results of the study on engine-fuel compatibility (Section 6) are summarized
and presented in Table 10-2. The ratings iri the fuel selection sheet (Table 10-1)
were awarded from this table.
10.1.5 Fuel Cost at Service Station (Section 8)
The cost of alternative fuels, as determined by the first-tier (preliminary)
method, have been used as a basis for quantifying these criteria. Predicted
fuel costs were normalized relative to conventional gasoline at the gas pump
in 1973 ($2.40/106 Btu).
The cost of fuel at the station does not represent the complete cost story.
Some of the fuels listed are substantially more or less efficient than the re-
ference fuel. Outstanding examples are hydrogen (0-50% more efficient),
methanol (0-25% more efficient), or hydrazine, which could be used in very
efficient fuel cells. The effects of changes in vehicle efficiency on the fuel
system cost cannot be determined with sufficient accuracy and documentation.
240
-------
Hence, the cost of utilization of alternative fuels in vehicles is not included
in the fuel system cost.
Table 10-2. ENGINE-FUEL COMPATIBILITY
Type of Engine
1 Stirling
Conventional Open Chamber or
Fuel With Carburetor Stratified-Char.ge Diesel Brayton Rankine
Acetylene
Ammonia
Carbon Monoxide
Coal
Distillate Oils
Ethanol
Gasoline
Hydrazine
Hydrogen
LPG
Methanol
Methyl A mine
Natural Gas
(SNG)
Vegetable Oils
5
3
3
5
5
2
1
2
2
2
5
2
5
2
3
3
5
2
2
2
2
2
2
3
2
.4
5
5
5
5
1
5
5
2
3
5
3
3
3
2
2
2
3
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Fuel-cell fuel.
10.1.6 Selected Fuels
By adding the scores for each fuel in Table 10-1, a ranking of the fuels can
be determined. A low score indicates a "good" fuel. The lowest five scores
are candidate fuels and therefore are considered in the second tier of exami-
nation. The selected fuels are
Gasoline
o Distillate oils
Methanol
Hydrogen
SNG.
241
-------
10.2 Selection of Energy Sources
One requirement in the selection of an alternative fuel system is the
determination of whether its domestic resources are adequate to support
15% (or more) of the transportation demand for at least 25 years. Trans-
portation demand is of course greater than automotive demand; hence, this
criterion should be adequate with competition (from aircraft) for a commonly
desired transportation fuel (distillate oils). If the adequacy of the alterna-
tive resource falls below 15%, more than two simultaneous alternative
systems are necessary, because the transportation energy shortfall ranges
from about 28 to 39% of the total demand until the year 2000, after which it
increases. Development of more than two simultaneous alternative systems
is not practical, and a system life of less than the nominal life of a fuel-
synthesis plant network plus the life of the transmission and distribution
system is not realistic. From Section 2 or 4, 15% of the transportation
energy demand for the 25 years following 1975 amounts to approximately
108 X 1015 Btu (Model I).
For this study we have chosen to sum 100% of the assured resource base,
75% of the reasonably assured resource base, and 25% of the speculative
resource base for finite domestic fossil and nuclear resources. This is an
arbitrary but uniform method of estimating the adequacy of a resource base
for fuel synthesis. These resources and sums are presented in Table 10-3,
in which the adequacy of the resource is rated according to the require-
(Section 10. l).
In the case of solar heat, we have taken one average size state, or 2% of
the U. S. land area, as an approximation of that potentially available for ag-
ricultural production of a crop that could be converted to a fuel for automotive
transportation. This is about 45 million acres, and between I960 and 1973,
an average of about 43 million acres of cropland has been withheld from pro-
duction. In the cases of municipal and feedlot wastes, we have taken the
annual supply projected for 1985.
10. 3 Fuel Candidates for the Three Time Frames
The approach to detailed fuel selections for each time frame is'basically
the same as that in Section 10. 1. The differences are the quality of informa-
tion used and the fact that the selection procedure is applied for each of the
three time periods with appropriate availability, engine compatibility, and
costs.
242
-------
Table 10-3. ADEQUACY OF DOMESTIC RESOURCES
Finite Resource
Coal
Oil Shale
Uranium (Fission)
Burner Reactors
Breeder Reactors
Tar Sands
Deuterium (Fusion)
Potential
Supply, 1015 Btu
67, 100
3,230
550
41,250
127
Unassessed
Adequacy
Probable
Probable
Possible
Moderate technology gap
Not adequate
Serious technology gap
OJ
Renewable Resource
Hydropower
Total
Uncommitted
Geothermal Heat
Fuel Conversion
Solar Heat (Total Area)
2. 0% U.S. Area
Agricultural Production
Fuel Conversion
Tidal Power
Wind Power
Municipal Wastes
Animal Feedlot Wastes
Potential
Annual Supply
1.8
1.5 (as fuel)
7. 7 (as heat)
2. 7 (as fuel)
49,000 (as heat)
980 (as heat)
9. 8 (as crop)
4. 9 (as fuel)
Negl
4. 0 (as fuel)
2. 9 (as heat)
1.2 (as fuel)
25-Year
Fuel Supply
1015 Btu-
. 8 (as heat)
. 4 (as fuel)
37.5
67.5
122.5
Negl
100
30
85
Adequacy
Not adequate
Not adequate
adequate
Speculative
Not adequate
Not adequate
Not adequate
Not adequate
Not adequate = >108x 1015 Btu.
-------
10.3.1 Near-Term Time Frame (1975-1985)
In the near-term time frame, all criteria remain the same in the first-
tier selection, except for the fuel costs and engine compatibility. The re-
ference gasoline cost is $3. 96/106 Btu, and the fuel costs are taken from Table
8-29. For the near term, only conventional Otto-cycle engines are considered.
Vehicle compatibility is divided between compatibility with "old" (pre-1975)
engines the extent to which these engines would be modified for the new fuel
and compatibility with "new" engines the extent to which design changes
would be needed.
The ranking of the seven alternative fuels selected for detailed study for
the near-term time frame, according to Table 10 -4, is as follows:
Fuel Source
Gasoline Oil shale
Gasoline Coal
Distillates Oil shale
Distillates Coal
Methanol Coal
SNG Coal
Hydrogen Coal
10.3.2 Mid-Term Time Frame (1985-2000)
In the mid-term time frame, "new" vehicles and power plants are con-
sidered, and the synthesis processes with moderate technology gaps are
considered available. A nuclear hydrogen industry (thermochemical) could
be in the early stages of growth by the end of this time frame. Mid-term
fuel costs are taken from Table 8-29- The ranking of the seven alternative
fuels selected for detailed study for the mid-term time frame, according to
Table 10-5, is as follows:
Fuel
Gasoline
Gasoline
Distillates
Distillates
Methanol
SNG
Hydrogen
Source
Coal
Oil shale
Coal
Oil shale
Coal
Coal
Nuclear
244
-------
Table 10-4. FINAL FUEL SELECTION FOR THE NEAR-TERM TIME FRAME
Synthesis Fuel
Fuel Technology Availability
Gasoline (Coal)
Gasoline (Shale)
Methanol (Coal)
Hydrogen (Coal)
SNG (Coal)
Distillate Oils (Coal)
Distillate Oils (Shale)
Reference Gasoline
2 2
1 2
1 2
2 2
1 5
2 2
1 2
1 1
Safety and
Toxicitv
1
2
2. 5
0
0
1
1
1
Handling
Tankage
2.0
2.
3.
6.
3.
2.
2.
2.
0
9
2
2
0
0
0
Compatibility
Transmission
1
1
2
2
2
2
2
1
Distribution
1
1
2
3
3
2
2
1
Old New
Vehicles Vehicles
1 1
1 1
2 2
4 2
3 2
4 2
4 2
1 1
Environmental Costs at
Effects Station
2
2
2
2
2
2
2
2
1. 19
1. 11
1. 54
1.40
1.21
1.19
1. 11
1.00
Score
14. 19
13.
20.
24.
22.
20.
19.
12.
11
94
60
41
19
11
00
Final
Ranklni
2
1
5
7
6
4
3
B-94-1778
-------
Table 10-5. FINAL FUEL SELECTION FOR THE MID-TERM TIME FRAME
Compatibility
Synthesis
Fuel Technology
Gasoline
Gasoline
tv Methanol
^ Hydrogen
(Coal) 1
(Shale) 1
(Coal) 1
(Nuclear) 2
SNG (Coal) 1
Distillate
(Coal)
Distillate
(Shale)
Reference
Oils
1
Oils
1
Gasoline 1
Fuel
Availability
2
2
2
2
5
2
2
2
Safety and Handling
Toxic ity
1
1
2.5
0
0
1
1
1
Tankage
2. 0
2.
3.
6.
3.
2.
2.
2.
0
9
2
.2
0
. 0
0
INew
Transmission Distribution Vehicles
1 1 1
1 1 1
2 1 1
2 32
2 3 1
2 1 1
2 1 1
1 1 1
Environmental Costs at
Effects Station
2
2
2
2
2
2
2
2
1.10
1. 18
1.36
1.22
1.05
1. 10
1. 18
1.0
Score
12.
12.
16.
20.
18.
13.
13.
12.
10
18
76
42
25
10
18
0
Final
Ranking
1
2
5
7
6
3 :
4
--
B-94-1779
-------
10.3.3 Far-Term Time Frame (2000-2020)
In the post-2000 period, there are no distinctions for engine compatibility
or synthesis technology. Methanol is "possible" in availability because it
competes with gasoline and distillate oils (preferred fuels) for the same coal
and water resources, but, because of process characteristics, less methanol
can be made from these resources. The cost increases for fuel production
have resulted in minor fuel price differences relative to reference gasoline,
which is now the most expensive fuel. The ranking of the five alternative fuels
selected for detailed study for the far-termtime frame, according to
Table 10-6, is as follows:
Fuel Source
Gasoline Coal or oil shale
Distillates Coal or oil shale
Hydrogen Nuclear
Methanol Coal
SNG Coal
247
-------
Table 10-6. FINAL FUEL SELECTION FOR THE FAR-TERM TIME FRAME (2000-2020)
t\>
oo
Synthesis
Fuel Technology
Gasoline (Coal; 1
Gasoline (Shale) 1
Methanol (Coal) 1
Hydrogen
(Nuclear) '
SNG (Coal) 1
Distillate Oils .
(Coal) '
Distillate Oils
(Shale) '
Reference Gasoline 1
Fuel Safety and
Availability Toxicity
1 1
1 1
2 Z. 5
1 O
5 0
1 1
1 1
3 1
Handling
Tankage Transmission
2.
2.
3.
6.
3.
2.
2.
2.
0 1
0 1
9 2
2 2
2 2
0 - 2
0 2
0 1
Compatibility Environmental
Distribution New Vehicles Effects
1 1 2
1 1 2
1 1 2
2 1 2
2 1 2
112
1 1 2
1 1 2
Costs at
Station
0.
0.
80
89
0.96
0.
0.
0.
0.
1.
78
74
80
89
00
Score '
(£)
10. 80
10.
16.
15.
16.
11.
11.
13.
89
36
98
94
80
89
00
Final
Rankini
1
2
6
5
, 7
3
4 ;
--
B-94-1780
-------
11. CONCLUSIONS AND SCENARIOS
11.1 Near-Term Time Frame (1975-1985)
During the next decade, we will witness the commercial development of
a "synthetic" or substitute fuel technology; i.e., fossil resources, other
than conventional crude oil and natural gas, will be used for conversion to
clean and convenient fuels. In addition, the nuclear industry's energy out-
put should grow by a factor of 6-7 during the decade, but this contribution
may be limited to the electricity supply. Unfortunately, the long lead times
required by pilot-plant development, testing of demonstration plants, and ..
full-scale plant construction and start-up will prevent these new fuel syn-
thesis technologies from contributing appreciably to the domestic energy
supply. In addition, capital investment limitations will be complicated by
unusual risk factors stemming from raw material availability and fluctuating
foreign supplies of fuels.
The automotive sector will be low in priority during fuel shortages and
allocations, and supplies and costs of these fuels will be subject to strong
influences from "marginal" supplies that could potentially fill the deficit.
These marginal supplies consist of the crude oil produced elsewhere than
in North America, and,later in this time frame, synthesized fuels also will
be in this category. The immediate economic attractiveness of fuel syn-
thesized from coal and oil shale will depend to a great extent on the price of
imported crude oil and finished products. From the standpoints of longer
term economics (international trade balance), politics, and national resource
strength, the U. S. should begin a large-scale synthetic fuel industry without
regard to price maneuvers by foreign suppliers.
According to the selections of Section 10, the fuels for automotive
transportation in order of preference for the near term are conventional
gasoline and distillate fuels (dominant), supplemented by
1. Gasoline from oil shale
2. Gasoline from coal
3. Distillate (diesel) oils from shale
4. Distillate (diesel) oils from coal
5. Methanol from coal.
249
-------
The next two fuels in order of preference are SNG and hydrogen, both from
coal. SNG is subject to priority demands by the gas utility industry and would
be available for automotive use in limited quantities only. Hydrogen suffers
from a moderate technology gap in practical tankage on-board a vehicle.
Further, its production from coal and water would require competition with
SNG, gasoline and distillates, and possibly methanol for the same resources.
Production of hydrogen from nuclear process heat and water suffers from
a severe technology gap.
11.1.1 Oil Shale Development Scenario According to Models I and II
Several areas in the U.S. contain oil shale deposits. Only the Green
River Formation is considered adequate for commercialization of the oil
shale industry prior to 2000. The Green River Formation consists of
25,000 square miles (16 million acres) in portions of Wyoming, Colorado,
and Utah. It contains the equivalent of 1800 billion barrels of shale oil in
oil shale seams that are more than 10 feet thick and that contain more than
15 gal/ton. In fact, an estimated 600 billion barrels can be obtained from
shale containing more than 30 gal/ton from this formation.
The commercialization of the oil shale industry cannot begin until the
Federal Government leases the land. Nearly 80% of the Green River Form-
ation is on Federal land. Furthermore, approximately 60% of this acreage
is under a clouded jurisdictional issue because of the existence of previously
issued mining rights. Court rulings relative to these claims must be ob-
tained before 1980; otherwise, significant delays in commercialization will
occur. The current leasing schedule of the Federal Government, one lease
per month for a 6-month period during the first half of 1974, has been com-
pleted. The first four of these leases attracted high bids, but the last two
(probably requiring in situ processing) failed to attract interest. The purpose
of these six leases was to give industry an opportunity to build demonstration
units on land containing the high-quality oil shale. To our knowledge, future
leasing schedules do not exist at this time.
The present law permits leases totaling not more than 5120 acres for
each owner. This is not sufficient to encourage industry development be-
cause l) it does not provide adequate higher quality shale for continued
long-term operation with second-generation plants by the same party, and
2) it does not allow a single operation sufficient reserves to sustain a
250
-------
lOOi 000-150, 000 bbl/day operation. Minimum holdings of up to 25, 000
acres are needed to provide adequate minable shale per plant for a long-term
commercial operation. Another major leasing policy issue that needs to
be addressed is water rights. The industry cannot be developed efficiently
if water rights are not as available as mineral rights in the proper propor-
tions. The other constraints relative'to the commercialization of this in-
dustry are the availability of proved technology, capital, and skilled labor.
The two major options in oil shale technology are mining-plus-surface
processing and in situ processing. The mining-plus-surf ace processing is
considered to be in the early stages of known technology, despite the fact .
that no demonstration plants are in operation or under construction. A
pattern process for the production of gasoline and distillates from oil shale
and its economics are described in Appendix B. Government and industry
have expended much effort oh evaluating this technology over the last 30
years at the experimental and pilot-plant levels. On the other hand, in situ
processing must still be placed in the experimental category.
\
The schedule of oil shale development according to Model I implications
for the near-term time frame is presented in Table 11-1. The bases are
1 barrel of crude shale oil at 5. 8 X 106 Btu (high heating value) and a refining-
to-product efficiency of 90% . The schedule of oil shale development accord-
ing to Model II implications for the near-term time frame also is presented
in Table 11-1.
Table 11-1. OIL SHALE TO GASOLINE AND DISTILLATES
ACCORDING TO MODELS I AND II FOR THE NEAR TERM
Annual
Production
Year
Model I
1975
1980
1985
Model II
1975
1980
1985
No. of New Plants
and Vol, bbl/day
PI Inf
3 at 100,000
7 at 100,000
4 at 50, 000
4 at 100.000
Total No.
Vol.
of Plants and
bbl/day
3 at 100,000
10 at
4 at 50
100,000
,000
4 at 100,000
Total Vol.
bbl/day
300,000
1. 000, 000
200.000
600,000
Shale
Oil
0. 63
2. 09
0. 42
1.25
Gasoline
and
Distillates
1S
10' Btu
0.57
1. 88
0.38
1. 12
A-94-1811
251
-------
11.1.2 Coal-to-Liquid Fuels Scenario According to Models I and II
Coal can be processed with water to produce the candidate alternative
fuels: SNG (methane), gasoline, and distillate hydrocarbons, and methanol.
Pattern processes and their economics are described in Appendix B.
The major coal reserves available for use in these conversions could be
mined in several areas. In the West, Montana, Wyoming, and North Dakota
and the Four Corners area (New Mexico) have sufficient reserves of both
coal and water for the development of large-scale industries. In these areas,
water does become an eventual limiting factor on industry size. In the East,
water is generally not a limiting factor, and the states of Illinois, Kentucky,
West Virginia, Pennsylvania, and Ohio (and others) have coal reserves that
could be further developed for synthetic fuel production. Here, other factors,
such as real estate availability, terrain, and strip-mining laws, would be
limiting. The number of coal-to-liquid and -gaseous fuel plants that could be
built, of course, is limited by capital investment and product selling prices.
In general, the higher the (real) price of the product, the higher the productive
level because marginal mining and distant water supplies then will be utilized.
From water availability studies, we conclude that process efficiency and
water requirements will become important to coal-based fuels at the begin-
ning of the far-term time frame. Hence, in the near term, large-scale
development of a process or synthesis route that is inordinately water-
consuming would be unwise. In a coal-to-fuel process, water is used for
two major purposes: for cooling or heat rejection to the environment, and
for supplying hydrogen to the synthesized molecule as required by chemistry.
The most efficient process requires the least cooling water, and the molecule
with the smallest hydrogen-to-carbon ratio requires the least synthesis water.
From our process studies, we deduce the following overall thermal efficien-
cies:
Coal to SNG, 65-70%
Coal to gasoline and distillates, 61-67%
Coal to methanol, 41-46%
From chemistry, the mole ratio of hydrogen to carbon is as follows:
252
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Table 11-2. COAL TO SNG AND EITHER GASOLINE PLUS DISTILLATES OR
METHANOL ACCORDING TO MODELS I A ND II FOR THE NEAR TERM
SNG
No. of Plants and Vol, l.O6 CF/day
Daily Production, 109 Btu
Annual Production, 1015 Btu
Gasoline and Distillates
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
Methanol
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
SNG
No. of Plants and Vol, 1000 CF/day
Daily Production, 109 Btu
Annual Production, 1015 Btu
Gasoline and Distillates
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
Methanol
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
1975
KTnrirl T
Pilot Plants Only
Pilot Plants Only
Pilot Plants Only
>,>,-, Jr, 1 TT
Pilot Plants Only
Pilot Plants Only
Pilot Plants Only
1980-
12 at 250
2850
1.0
1 at 100
36
0.22
1 at 200
72
0.22
6 at 250
1425
0.5
1 at 100
36
0.22
1 at 200
72
0.22
1985
24 at 250
5700
2.0
2 at 100,2 at 150
180
1.08
2 at 200,2 at 300
360
1.08
12 at 250
2850
1.0
4 at 100
144
0.86
4 at 200
288
0.86
-------
SNG.(CH4), 4:1
Gasoline (isooctane), 2.25:1
Methanol (CH3OH), 4:1
Hence, methanol from coal is the most water-intensive of the three syn-
thesis processes.
Because of the priority demands of the natural gas utility industry, plans
already made, mineral and water rights, and capital already committed,
SNG will be made from coal. Asa result, three near-term options remain
for alternative automotive fuels: gasoline and distillates, methanol, or
a combination. For illustration in this and the other time frames, we have
tabulated potential industry growth for both gasoline and methanol from
coal. However, because of a lack of resources, mainly water, only one or the
other would be practical on a large scale. We recommend gasoline and
distillates as the most advantageous.
Table 11-2 shows the coal-to-fuel industry projection according to
Models I and II implications. SNG is included because it is assumed to oc-
cur, and the unused coal and water resources remain available for gasoline
and distillates or methanol. k
1.1.1.3 Summary for Near-Term Time Frame
The synthetic fuel production rates of Tables 11-1 and 11-2 are included
(inherently) in the energy supplies of Models I and II. As a result, we face
energy deficits in 1975 and 1980, but in 1985 a state of self-sufficiency can
be achieved for Model I only, as shown in Table 11-3. In 1985 according to
Table 11-3. TRANSPORTATION ENERGY SUPPLY AND DEMAND
ACCORDING TO MODEL I FOR THE NEAR TERM
% of
1975 1980 1985 1985 Market
-10Ib Btu
Fuel Demand (Nonelectric) 19.4 22.8 26.4
Domestic Crude Fuels 13.0 15.0 17.4 63
Conventional Deficit 6.4 7.8 9.0
Shale Oil Fuels (Table 11-1, 55%) Nil 0,3 1.0 4
Coal Fuels (Table 11-2, 55%)* Nil 0.1 0.6 2
Reallocated Coal to Fuel Nil Nil 5.9 21
Reallocated Nuclear to Fuel Nil Nil 2.8 10
Required Fuel Imports 6.4 T..4 (1.3)
#
Gasoline and distillates or methanol.
254
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Model I, 8. 7 X 1015 Btu is potentially available as electricity or as a syn-
thetic fuel; see Table 4-7. This energy is not included in Tables 11-1 or
11-2, but it would be available to the transportation market sector. By
reallocation of the energy supply, as permitted by the models (which are
not formulas for allocation), the excess coal and nuclear energy of the
electricity conversion sector of Model I is used to supply this 8. 7 X 1015 Btu
of "fuel. " One such allocation is as follows:
16. 8 X 1015 Btu (from coal) X 0. 35 = 5. 9 X 1015 Btu (fuel)
8. 0 X 1015 Btu (from nuclear heat) X 0. 35 = 2. 8 X 1015 Btu (fuel)
Synthesis of this fuel will have to be in addition to that scheduled in Tables 11-1
and 11-2. If we do not develop nuclear process heat as an energy source
for a synthetic fuel by 1985, e. g. , hydrogen from water, which must be
tanked adequately, or electricity for use in an electric car, we will not
utilize the potentially available 2. 8 X 1015 Btu, and we will have a deficit
in 1985.
The disastrous situation of not conserving energy coupled with a slower
rate of development of natural resources is shown in Table 11-4 for Model II.
Table 11-4. TRANSPORTATION ENERGY DEMAND AND SUPPLY
ACCORDING TO MODEL II FOR THE NEAR TERM
% of
1975 1980 1985 1985 Market
101* Btu
Fuel Demand (Nonelectric) 19. 1 22. 4 25. 4
Conventional Supply 11.8 13.2 13.2 52
Conventional Deficit 7.3 9-2 12.2
Shale Oil Fuels (Table 11-1,55%) Nil 0.2 0.6 2
Coal Fuels (Table 11-2,55%)* Nil 0.1 0.5 2
Reallocated Coal-Based Fuel Nil Nil Nil
Reallocated Nuclear-Based Fuel Nil ' Nil Nil
Required Fuel Imports 7.3 8.9 11.1 44
.£
Gasoline and distillates or methanol.
255
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11.2 Mid-Term Time Frame (1985-2000)
During the mid-term time frame, the commercial development of synthetic
or substitute fuels will be expanded greatly. According to Model I projections,
by the year 2000, the SNG industry reaches 80% of its ultimate capacity, coal
to distillate fuels reaches about 75% of capacity, or alternatively, coal to
methanol reaches 80% of its capacity. The oil shale industry reaches 100%
of expected capacity by the year 2000. According to Model II projections,
the industry growth rates are slower and the ultimate capacities are lower;
thus similar growth proportions are observed during this time frame. The
principal limit on the ultimate capacities for these new industries is water
availability in the Western States. As in the near-term time frame,, other
governing factors also will change as time progresses; these limitations on
growth rate are a result of fuel economics and capital for investment, skilled
labor supply, environmental constraints, etc.
Always growing at a rapid pace but becoming a major contributor to energy
supply in this time frame is nuclear energy. According to Model I, the mid-
term time frame is a period of self-sufficiency if, among other things, we
develop this nuclear energy by synthesizing a fuel. As in the near-term time
frame, coal and nuclear energy are potentially available to the transportation
sector of the economy. In this time frame, the nuclear heat portion becomes
almost as large as the reallocated coal fuel. This projection assumes the
success of breeder reactors as a supply of fissile fuels 50-75 times greater
than the U235 that is naturally obtainable. However, this time frame also
could be a deceiving one. We will need to learn how to convert nuclear energy
into a fuel with high efficiency. Model I assumes a 35% overall conversion
efficiency for all time frames, but this level of technology becomes inadequate
for self-sufficiency by the year 2000. Model II always requires imported
fuels, primarily because of poor energy conservation (high demand) and
large energy losses during conversion processes.
According to the selections of Section 10, the fuels for automotive trans-
portation in order of preference for the mid term are conventional gaso-
line and distillate fuels (no longer dominant by Model I), supplemented by
1. Gasoline from oil shale and coal
2. Distillate (diesel) oils from oil shale and coal
3. Methanol from coal.
256
-------
The next two fuels in order of preference are SNG from coal and hydrogen
either from coal or nuclear heat (if the technology gap is solved). As in the
near term, SNG is subject to priority demands and would be available for
automotive use in limited quantities only. By 1985, we can assume solution
of the hydrogen tankage problem (a moderate technology gap), but the nuclear
synthesis technology may not be developed until nearer 2000.
11.2.1 Oil Shale Development Scenario According to Models I and n
In the late 1980's and the early 1990's, water supply constraints will be
more severe than other constraints. The Bureau of Reclamation's estimate
of water availability in the Green River area is 5. 8 million acre-ft/yr
(122 X 106 bbl/day). However, the Bureau also estimates that only 83%
(101 X 106 bbl/day) can be utilized. At present, about 55% of the water
that can be effectively utilized is being used, and about 35% is committed
to future use. Most of the remainder, 11%, is uncommitted and could be
made available for the commercialization of this industry. This 11% would
support the process requirements but not land reclamation requirements for
the production of about 1. 7 X 106 bbl/day of shale oil, approximately 50%
of the anticipated total production according to Model I. The most expedient
method of obtaining the additional 11 X 106 bbl/day water required is to re-
direct 25-30% of the potential water reserves committed for future use
elsewhere into the commercialization of the oil shale industry.
For shale oil production from the Green River Formation, water require-
ments could be supplied by the Colorado, White, and Roaring Fork Rivers
in Colorado, several reservoirs, and the West Divide Water Project. In
Utah, the White River would be the main supply, and in Wyoming, the Green
River and Flaming Gorge Reservoir would be sources of supply. For Model I,
the ultimate production rate of shale oil is 3. 55 X 106 bbl/day, or 6. 7 X 1015
Btu/yr, as gasoline and distillate fuels. The total Model I supply is about
700, 000 acre-ft/yr. For Model II, no future additions to the water supply
are assumed. The ultimate supply is 341,000 acre-ft/yr, and the ultimate
production rate is 1. 7 X 106 bbl/day (syncrude), or 3.2 X 1015 Btu/yr (fuel).
The mid-term schedule for oil shale development according to both Model I
and Model II is presented in Table 11-.5.
257
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Table 11-5. OIL SHALE TO GASOLINE AND DISTILLATES
ACCORDING TO MODELS I AND II FOR THE MID TERM
Year
Model II
1990
1995
No. of New Total No. of
Plants and Vol, Plants and Vol, Total Vol,
bbl/day bbl/day bbl/day
Annual Production .
Gasoline
and
Shale Oil Distillates
Model I
1990 10 at 150,000
1995 5 at 150,000
2000 3 at 100,000
2 at 100,000
2 at 150,000
3 at 100,000
2 at 150, 000
2000 None
10 at 100,000
10 at 150,000
10 at 100,000
15 at 150,000
13 at 100,000
15 at 150,000
4 at 50,000
6 at 100,000
2 at 150,000
4 at 50,000
9 at 100,000
4 at 150,000
4 at 50,000
9 at 100,000
4 at 150,000
-iO15 Btu-
2,
3,
3,
500,
250,
550,
000
000
000
5.
6.
7.
22
79
41
4.
6.
6.
7
3
7
1,100,000 2.29
1,700,000 3.55
1,700,000 3.55
2. 1
3.2
3.2
11.2.2 Coal-to-Liquid-Fuels Scenario According to Models I and II
As with oil shale, water is a constraint on the ultimate size of a coal-to-
gaseous and -liquid fuel industry. Because the SNG industry appears immi-
nent, it must be considered as a priority user of coal, and the remaining
reserves - limited by water availability in the West - could be used for
gasoline and distillates or methanol production.
By 2000, according to Model I, 93 SNG plants are to be on-line at a
production rate of 250 million CF of SNG per day. Although this is
a very optimistic projection, six such plants are already firmly planned
or on order.
The coal-to-synthetic and -substitute fuel industry will reach maturity
in the far-term time frame, and geographical areas and water limitations
are discussed in that scenario. Table 11-6 presents the coal-to-SNG and
gasoline plus distillate or methanol schedules for Models I and II. Again,
258
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Table 11-6. COAL TO SNG AND EITHER GASOLINE PLUS DISTILLATES OR
METHANOL ACCORDING TO MODELS I AND II FOR THE MID TERM
SNG
No. of Plants and Vol, 106 CF/day
Daily Production, 109 Btu
Annual Production, 1015 Btu
Gasoline and Distillates
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
Methanol
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
Annual Production, 1015 Btu
SNG
No. of Plants and Vol, 106 CF/day
Daily Production, 109 Btu
Annual Production, 1015 Btu
Gasoline and Distillates
No. of Plants and Vol, 1000 bbl/day
Annual Production, 106 bbl
. Annual Production, 1015 Btu
Methanol
No. of Plants and Vol, 106 bbl
Annual Production, 1 06 bbl
Annual Production, 10s Btu
1990
* r .-. J ,-, 1 T
ivioaei i
48 at 250
11,400
4. 1
2 at 100
10 at 150
612
3. 7
2 at 200
10 at 300
1224
3. 7
"MnHnl TT
30 at 250
7125
2. 6
6 at 100
5 at 150
486
2. 9
6 at 200
5 at 300
972
2.9
1995
72 at 250
18,000
6.5
2 at 100
20 at 150
1152
6.9
2 at 200
15 at 300
1764
5.3
50 at 250
11,875
4.3
6 at 100
12 at 150
864
5.2
6 at 200
10 at 300
1512
4.5
2000
93 at 250
22,250
8.0
2 at 100
30 at 150
1692
10.2
2 at 200
20 at 300
2304
6.9
70 at 250
16,625
6.0
6 at 100
20 at 150
1296
7.8
6 at 200
14 at 300
1940
5.8
-------
gasoline and methanol cannot both be made from the same resources, and
we recommend gasoline (and distillates) as the choice providing the largest
ultimate fuel supply.
11.2.3 Summary for Mid-Term Time Frame
Table 11-7 presents the energy demand and supply situation at the end
of the mid-term time frame for Models I and II. Potential market pene-
trations also are tabulated. The nuclear energy-to-fuel supply will only be
available (Model I) if technology permits. If not, Model I imports for trans-
portation will be 6. 2 X 1015 Btu, instead of 0. 3 X 1015 Btu.
Table 11-7. TRANSPORTATION ENERGY DEMAND AND SUPPLY
ACCORDING TO MODELS I AND II FOR THE YEAR 2000
Model I Model II
10*3 Btu Market % 10" Btu Market
Fuel Demand (Nonelectric) 40.0 41.3
Domestic Crude Fuels 16.9 42 13.3 32
Conventional Deficit 23. 1 28. 0
Shale Oil Fuels (Table 11-5, 55%) 3.7 9 1.7 4
Coal Fuels (Table 11-6,55%)* 5,6 14 4.3 10
Reallocated Coal .to Fuel t 7,, 6 19 Nil
Reallocated Nuclear to Fuel* 5.9 15 Nil
Required Fuel Imports 0.3 1 22.0 54
y.
Gasoline and distillate oil.
Hydrocarbons, methanol, or hydrogen.
Possibly hydrogen.
11.3 Far-Term Time Frame (2000-2020)
For the distant time period beyond 2000, quantitative projections with
any degree of certainty are impossible. Continuing to follow the two models
of energy demand and supply, we show the procedures for estimating energy
supplies, fuel needs, and the penetration of the transportation market sector
by alternative fuels.
In this distant time period, the nuclear energy supply becomes dominant.
Coal is still a major contributor to substitute fuel synthesis, and its annual
production potential as gasoline and distillates is about 200% of that of oil
260
-------
shale. If methanol from coal were the synthesis route, its ultimate production
rate would be about 125% of that of oil shale. Water limitations restrict oil
shale industry growth in the mid term and coal processes in the far term.
According to the selections of Section 10, the fuels for automotive trans-
portation in order of preference for the far term are conventional
gasoline and distillate fuels (a minor contributor in Model I and large imports
in Model II), supplemented by -
1. Gasoline from coal and oil shale
2. Distillate (diesel) fuels from coal and oil shale
3. Nuclear-based hydrogen.
The next two fuels in order of preference are methanol and SNG from coal.
Again, the supplies of SNG available to the transportation sector are limited
to about 1-2 X 1015 Btu/yr, a minimal contribution by 2000. We assume the
solution of the hydrogen tankage problem during the mid term; the nuclear
synthesis technology should be a reality in the far term.
11.3.1 Nuclear-Based Fuels (Hydrogen) Scenario
For the synthesis of hydrogen from water, nuclear heat is available from
HTGR's using helium or hydrogen as the heat-transfer medium. In addition,
breeder reactors are operating to supply part of the fuel needed by the HTGR's.
Because of the anticipated temperature limitations, fast-breeder reactors
probably are not adequate for producing hydrogen by thermochemical water-
splitting. Breeders serve as heat sources for electricity generation, and
this electricity can be used for the electrolysis of water to produce hydrogen.
In addition, process heat and electricity might be available from fusion reactors
whose commercialization should begin in the far-term time frame.
From the basic assumptions of Model I, we find that the U.S. experiences
energy deficits during the period 2000-2020. Significant fuel importation
would be necessary to satisfy transportation energy demands, primarily
because of the overall efficiency of 35% assumed for the conversion of nuclear
heat and coal and fuel. If this assumption is relaxed slightly for this far-term
scenario, the situation improves greatly. If we assume overall conversion
efficiencies of 42% for nuclear heat to electricity and thermochemical hydrogen
and for coal to fuel (hydrocarbons or hydrogen), in 2020 according to Model I,
261
-------
114. 3 X 1015 Btu is available as fuel and electricity. Of this quantity,
74. 1 X 1015 Btu (electricity) is required to fill all sector energy deficits
except transportation, and the remaining 40.2 X 1015 Btu (fuel) is left to
alleviate the transportation shortfall of 41. 7 X 1015 Btu. A possible re-
allocation within Model I is 23. 5 X 1015 Btu of nuclear-based hydrogen and
16. 7 X 1015 Btu of coal-based fuel. This coal-based fuel is in addition
to that shown in Table 11-8, and we do not know where the additional water
supplies required can be secured. A solution is that this fuel be solvent-
refined coal. If this reallocation is not the case, a domestic deficit can
occur, requiring imports of about 20 X 1015 Btu of fuel in 2020 by Model I.
In contrast, the domestic deficit (imports) in Model II (nuclear and coal
conversions at 35%) would be 39. 8 X 1015 Btu. The energy quantities con-
sidered above for Models I and II are contained in Table 11-9.
Table 11-9. TRANSPORTATION ENERGY DEMAND AND SUPPLY
ACCORDING TO MODELS I AND II FOR THE YEAR 2020
'Model I Model II
_
Btu Market % 10ia Btu Market
Fuel Demand (Nonelectric) 69.4 66.2
Domestic Crude Fuels 16.9 24 13.0 20
Conventional Deficit 52.5 53.2
Shale Oil Fuels (55% Production) 3.7 5 1.8 . 2
Coal Fuels (Table 11-8, 55% )* 7.1 10 5.6 8
Reallocated Coal to Fuel . 16.7 24 3.0 5
Reallocated Nuclear to Fuel 23.5 34 3.0 5
Required Fuel Imports 1.5 2 39.8 60
w
Gasoline plus distillate oil.
Unspecified hydrocarbon or solvent -refined coal.
Hydrogen.
262
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Table 11-8. COAL TO SNG AND EITHER GASOLINE DISTILLATES OR
METHANOL ACCORDING TO MODELS I AND II FOR THE FAR TERM
2010 2020
Model I
Model II
SNG
No. of Plants and Vol, 106 CF/day 105 at 250 117 at 250
Daily Production, 109 Btu 15,000 27,800
Annual Production, 1015Btu 9.0. 10.0
Gasoline and Distillates
No. of Plants and Vol, 1000 bbl/day 2 at 1000 40 at 150
35 at 150
Annual Production, 106 bbl 1962 2160
Annual Production, 1015 Btu 11.8 13.0
Methanol
No. of Plants and Vol, 1000 bbl/day 2 at 200 2 at 200
22 at 300 22 at 300
Annual Production, 106bbl 2520 2520
Annual Production, 1015Btu 7.6 7.6
SNG
No. of Plants and Vol, 106 CF/day 30 at 250 90 at 250
Daily Production, 109Btu 19,050 21,400
Annual Production, 1015 Btu 6.9 7.7
Gasoline and Distillates
No. of Plants and Vol, 106 CF/day 6 at 100 10 at 100
25 at 150 25 at 150
Annual Production, 106 bbl 1566 1710
Annual Production, 1015 Btu 9.4 10.2
Methanol
No. of Plants and Vol, 1000 bbl/day 6 at 200 6 at 200
14 at 300 14 at 300
Annual Production, 106 bbl 1940 1940
Annual Product-ion, 105 Btu 5. 8 5. 8
263
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11.3.2 Oil-Shale-Development Scenario, Models I and II
According to Models I and II, there is no further growth in the oil shale-
to -hydrocarbon fuels industry beyond the levels of 2000 (Table 11-5). As
old plants become obsolete or as oil shale deposits are depleted, new plants
and mines are brought on-line to compensate, but net production rates are
essentially unaffected. These rates are limited by the process water supply.
In 2010 and 2020 for Model I, the production rate is 3550 bbl/day of syncrude,
or 6. 7 X 1015 Btu/yr of fuel. In 2010 and 2020 for Model II, the production
rate is 3000 bbl/day of syncrude, or 5. 6 X 1015 Btu/yr of fuel.
11.3.3 Coal-to-Li quid-Fuels Scenario. Models I and II
The production rates of SNG and gasoline plus distillate oils or methanol
for the far-term time frame are shown in Table 11-8.
For Model I, we assume the operation of 105 SNG plants by 2010 and 117
plants by 2020 as the ultimate production level (10 X 1015 Btu). In addition,
we can have 40 coal -to-liquid hydrocarbon fuels plants by 2020, or 24
coal-to-methanol plants. Optimistic coal and water supplies can be approxi-
mately apportioned to support this level of industry.
For Model II, we assume 80 SNG plants in 2010 and 90 plants in 2020 as
the ultimate production level (7. 7 X 1015 Btu). In addition, we can have 35
coal-to-liquid hydrocarbon fuel plants by 2020, or 20 coal-to-methanol
plants. Known (uncommitted) coal and water supplies can be approximately
apportioned to support this level of industry.
For Model I, we must place 82 SNG plants in the East, 30 in Illinois
alone. In the West, optimistically, we could utilize 1 million acre-ft/yr
of water in Montana and Wyoming, 375, 000 acre-ft/yr of water in North
Dakota, and 150,000 acre-ft/yr of water in the Four Corners area (New
Mexico). A 250 million CF/day SNG plant requires about 15, 000 acre-ft/yr
of water. Therefore, we can place 25 SNG plants in North Dakota and 10 in
the Four Corners area. This leaves the Montana and Wyoming reserves
available for gasoline and distillate hydrocarbon production or methanol
synthesis. Roughly, a barrel of coal-produced gasoline plus distillate re-
quires 3.5 barrels of water, and a barrel of coal-produced methanol requires
about 3 barrels of water. The result is 40 gasoline and distillate fuel plants
at 150, 000 bbl/day, or about 24 methanol plants at 300, 000 bbl/day (13 X 1015
Btu/yr hydrocarbon versus 7. 6 X 1015 Btu/yr methanol output).
264
-------
For Model II, we must place 55 plants in the East, 25 in Illinois. In the
West, we could utilize 785,000 acre-ft/yr of water in Montana and Wyoming,
375, 000 acre-ft/yr of water in North Dakota, arid 150,000 acre-ft/yr of water
in the Four Corners area. The East plus North Dakota and the Four Corners
area support the 90 SNG plants required. We would then site about 4, 750, 000
bbl/day of gasoline and distillates, or about 5,400,000 bbl/day of methanol, in
Montana and Wyoming.
11.3.4 Summary for Far-Term Time Frame
Table 11-9 presents the energy demand and supply situation ;at the end of
the far-term time frame for Models I and II. Potential market penetrations
also are tabulated. The Model I reallocation is based on nuclear and coal-to-
fuel conversion efficiencies of 42%.
265
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