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

-------
                                     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

-------
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

-------
                               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

-------
                       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

-------
                    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

-------
                   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

-------
                  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

-------
                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

-------
                           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

-------
                      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

-------
                           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

-------
                      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

-------
                      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

-------
                       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       !

-------
                      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

-------
                      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

-------
               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

-------
                           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).

-------
   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.

-------
   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.

-------
              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

-------
                  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

-------
                  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

-------
                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

-------
                      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

-------
   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 I—1" 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 States—Onshore
 2      Pacific Coast
 3      Western Rocky Mtns.
 4      Eastern Rocky Mtns.
 5      West Texas Area
 6      Western Gulf Coast Basin
 7      Midcontinent
 8—10   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

-------
               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

-------
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

-------
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

-------
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

-------
 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

-------
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

-------
        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

-------
       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

-------
             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

-------
   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

-------
 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

-------
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

-------
             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

-------
   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     ;

-------
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

-------
 •  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

-------
   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

-------
   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

-------
   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

-------
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.

5. 5   References Cited

1.  "An  Economic Evaluation of Synthane Gasification  of Pittsburgh Seam
    Coal at 1000 psia  Followed by  Shift Conversion, Purification,  and
    Single-Stage Tube  Wall  Methanator,"  Report No.  72-9A.  Washington,
    D. C. :  U.S.  Department of  the Interior,  Bureau  of  Mines,  October
    1971.

2.  Atomic Energy  Commission, Division of Operations Analysis and
    Forecasting,  "Forecast  of Growth of  Nuclear Power, " WASH-1139.
    Washington,  D. C. : U. S. Government  Printing Office, January  1971.

3.  Brame, J. S. S.  and King,  J.  G. , Fuel — Solid, Liquid and  Gaseous,
    6th Ed.,  326.   London:  Edward Arnold Ltd.,  1967.               ~

4.  Clark,  D. S., Fowler,   D,  B.,  Whyte, R.  B.  and Wiens,  J. K.,
    "Ethanol  From  Renewable Resources  and Its  Application in Automotive
    Fuels  — A Feasibility Study. "   Report of a committee appointed by
    the Hon.  Otto E.   Lang,  Minister responsible for the Canadian  Wheat
    Board, January 1971.

5.  Consolidation Coal Co. ,  "Pipeline  Gas From  Lignite Gasification —
    Current Commercial  Economics, "  R&D Report No.  16,  Interim
    Report No.  4_ prepared  for Office of Coal Research, May 9, 1969.

6.  Davy Power Gas,   Inc. ,   Lakeland,  Fla., private communication.
                                  118

-------
 7.  Federal Power Commission, "The 1970 National Power Survey, "
     Part I.   Washington,  D. C. : U.S. Government Printing Office,
     December 1971.

 8.  Feldmann,  H.  F. ,  "Pipeline Gas From Solid Wastes. "  Paper
     presented at AIChE 69th National Meeting, Symposium  on  Solid
     Waste,  Part II,  Cincinnati,  May 16-19,  197 1.

 9.  Feldmann,  H.  F. ,  Bair,  W. G. , Feldkirchner, H.  L. , Tsaros, C. L. ,
     Shultz,  E.  B. , Jr., Huebler,  J.  and Linden, H.  R. , "Production
     of Pipeline Gas by  Hydrogasification of Oil Shale, "  IGT Res.  Bull.
     No.  36.  Chicago,  August 1966.

10.  Ford,  Bacon & Davis,  Inc.,  "Synthetic Liquid Fuel Potential  of
     Colorado," Vols.  l_ and  "L,  prepared for Bureau of Mines,  U.S.
     Department of the Interior,  December 14,  1951.

11.  Foster  Wheeler Corp.,  "Engineering  Evaluation and Review of
     Consol  Synthetic Fuel Process," R&D Report No.  \T_ prepared for
     Office of Coal  Research,  February 1972.

12.  "Gas,  Manufactured, "  in Kirk-Othmer Encyclopedia  of  Chemical
     Technology,  Vol.  ^0,  2nd Ed.,  353-442.  New York: John Wiley,
     ~
13.  Glaser,  P.  E. ,  "The Future  of Power From  the Sun."   Paper
     presented at the Intersociety Energy Conversion Engineering
     Conference,  Boulder, Colo.,  August 13-17,  1968.

14.  Golueke,  C.  G.  and Oswald,  W. J. ,  "Power  from Solar Energy Via
     Algae -Produced Methane," Solar Energy  7,  86-92 (1963).

15.  Grace,  R. J. ,  "Development  of the Bi-Gas  Process."   Paper pre-
     sented at Clean Fuels From Coal Symposium,  Institute of Gas
     Technology,  Chicago, September 10-14,  1973.

16.  Hall,  R.  N.  and Yardumian,  L.  H. ,  "The Economics of Commercial
     Shale Oil Production by the TOSCO II Process."  Paper  presented
     at 61st Annual Meeting  of American Institute of Chemical Engineers,
     Los Angeles,  December 5,  1968.

17.  Hammond, A.  L. ,   "Solar Energy:  A Feasible Source of Power, "
     Science 172,  660 (1971) May 14.

18.  Hiller,  H. and  Marschner,  F. ,  "Lurgi Makes  Low-Pressure
     Methanol, " Hydrocarbon Process.  49.  281-85  (1970) September.

19.  Johnston, T. A.,  "The  High- Temperature Gas -Cooled Reactor for
     Process Heat," GA-10317.  San Diego,  Calif.,  General  Atomic  Co.,
     1970.
                                   119

-------
20.  Jones,  J.  E.,  "Project  COED. "  Paper presented at Clean Fuels
     From Coal Symposium,  Institute of Gas  Technology,  Chicago,
     September 10-14,  1973.

21.  Jonson,  C. A.  et  al.,  "Present Status of the H-Coal Process. "
     Paper presented at Clean Fuels From Coal Symposium,  Institute of
     Gas Technology, Chicago,  September 10-14, 1973.

22.  Katell,  S.  and  Faber,  J. H. ,  "What  Hydrogen From Coal Costs, "
     Hydrocarbon Process.  Pet. Refiner 43,  143-46 (1964)  March.

23.  Klass,  D.  L.  and  Ghosh,  S. ,  "SNG From Biogasification of Waste
     Materials. "   Paper presented  at SNG Symposium I,  Institute of Gas
     Technology,  Chicago, March 12-16,  1973.

24.  Klass,  D.  L.  and  Ghosh,  S. ,  "Fuel Gas From Organic  Wastes,"
     Chem.  Tech. J3. 689-98  (1973) November.

25.  Lurgi Gesellschaft fur Warme- und Chemotechnik Mbh. ,  "Modern
     Ammonia Plants Based on Coal," September 1968.

26.  M.  W.  Kellogg Company,  "Commercial  Potential for the Kellogg
     Coal  Gasification Process, "  R&D Report No. 38,  Final Report
     prepared for  Office of Coal Research, September 1967.

27.  Ouellette,  R. P. (The MITRE  Corporation),  "The Solar  Energy:
     The Alternate  Option."   Paper presented at U. S.-Japan  Joint
     Symposium on Energy  Problems,  September 17-18,   1973.

28.  Pangborn,  J. B. and Sharer,  J. C. ,  "Analysis of Thermochemical
     Water-Splitting  Cycles, "  Proceedings  of  the Hydrogen Economy
     Miami Energy (THEME)  Conference.  University of Miami,  Coral
     Gables,  Fla",  March 1974.

29.  Quade,  R. N.  and McMain, A. T. ,  "Nuclear Energy for Coal
     Gasification, "  Gulf-GA-Al270l.  San  Diego,  Calif. : General
     Atomic Co. ,  1973.

30.  Royal, M. J.,  "Why Not Methanol As SNG  Feedstock? "  Pipeline Gas
     _J._  200,  58,  60,  62 (1973) February.

31.  Schlesinger,  M. D. , Sanner,  S.  S.  and  Wolfson,  D.  E. , "Pyrolysis
     of Waste  Materials From Urban and Rural Sources, " in  Proceedings
     of the Third Mineral Waste Utilization Symposium.   Chicago:  IIT
     Research Institute,  1972.

32.  Stuart,  A. K.,  "Modern Electrolyzer Technology  in  Industry."
     Paper presented at the American  Chemical  Society Annual National
     Meeting Symposium on Non-Fossil  Chemical Fuels,  Boston,  April
     9-14,  1972.
                                    120

-------
33.  Szego,  G.  C.  and Kemp,  C. C. ,  "Energy  Forests and Plantations, "
     Chem.  Tech.  3,  175-84  (1973) May.

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

-------
              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

-------
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;


6.4  References Cited
1. Adleman, H. G.  et al. ,  "Exhaust Emissions From a Methanol-Fueled
   Automobile. " SAE Paper 72093.  New York, 1972.

2. Adt, R.R.,  Greenwell,  H. and Swain, M. R. , "The Hydrogen Methanol-
   Air Breathing Automobile Engine. " Proceedings of the Hydrogen Economy
   Miami Energy (THEME) Conference, S10-37 to S10-48. Coral Gables,
   Fla. :  University of Miami, March 1974.

3. Adt, R.R. et al. ,  "The Hyd-rogen-Air Fueled Automobile Engine (Part l). "
   Paper presented at the 8th Intersociety Energy Conversion Engineering
   Conference, Philadelphia, August 13-16, 1973.

4. Allsup,  J. R. , "Gas From Coal As an Automotive Fuel. "  Paper presented
   at the SAE Combined Farm, Construction, and Industrial Machinery and
   Fuels and Lubricants  Meeting, Milwaukee,  September  12, 1973.

5. "Alternative Fuels, "  Automobile Eng.   33_, 299-307 (1943) August;
   Pt.  2, ibid. , 343-48 (1943) September.

f-. Austin,  A. L. ,  "A Survey of Hydrogen's Potential as a  Vehicular Fuel, "
   Prepared for U. S. Atomic Energy Commission under Contract No.
   W-7405-ENG-48.  Livermore, Calif:  Lawrence Livermore Laboratory,
   June 19,1972.
                                   155

-------
 7. Autotronic Controls Corp. ,  private communication, October 1973.

 8. Billings, R.E. and Lynch, F.E., "History of Hydrogen-Fueled Internal
    Combustion Engines, fl Energy Research Publication 73001. Provo, Utah, 1973.

 9. Bolt,  J. A. , "Air Pollution and Future Automotive Power Plants, "
    SAE Paper 680191. New York,  1968.

10. Breshears, R. , "Partial Hydrogen Injection Into Internal Combustion
    Engines, "  in Air Pollution — Symposium on Low Pollution Power Systems
    Development, NATO Document No. 32.  Ann Arbor, Mich. ,  October 14-
    19, 1973.

11. Breshears, R. , Cotrill, H.  and Rupe, J. ,  "Partial Hydrogen Injection
    Into Internal Combustion Engines — Effect on Emissions and Fuel Econo-
    my. "  Paper presented to the Council on Environmental Quality,
    Advisory Committee on Alternative Automotive Power Systems.
    Washington,  D. C. , February 12,  1974.

12. Brogan,  J. J. ,  "Automobile  Engine Prospects for the Future. "  Paper
    presented at International Conference on Automobile Pollution,  Toronto,
    Canada,  June 27,  1972.

13. Brooks,  D. B. , "Engine Performance of Substitute  Motor Fuels, "
    Automot. Aviat. Ind.  93,  18-21,  60-66 (1945) September 1.

14. Bull,  M. G. , "Development of an Ammonia-Burning Gas Turbine
    Engine, " Report No. DA-44-009-MC-824171. Fort Belvoir, Va. :
    U.S. Army Engineer Research and Development  Labs,  April 1968.

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.

17. Cornelius,  W. , Huellmantel, L. W. and Mitchell, H. R., "Ammonia
    As an Engine Fuel,"  General Motors Research Publication No. G MR-436.
    Warren,  Mich. , October 14, 1964.

18. Covington,  J. P. , Ed. ,  "How Soon Clean Engines ?" Automot. Eng.  81,
    23-28 (1973) July.

19. Curtiss-Wright Corp. ,  Wood-Ridge, N. J. ,  private communication,
    August 1973.

20. Ebersole, G. D.  and Manning, F.S. , "Engine Performance and Exhaust
    Emissions, Methanol Versus Isooctane. "SAE Paper 720697.
                                   156

-------
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

-------
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.

47. Obert, E.F., Internal Combustion Engines —Analysis and Practice.
    Scranton,  Pa. :  International Textbook Co. , 1952.
                                  158

-------
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).

61. Starkman,  E. S.  et al. ,  "Alternative Fuels for Control of Engine Emis-
    sions, "    J. Air Pollut. Control Assoc.  20, 92 (1970).
                                    159

-------
62. Starkman, E. S.  et al. ,  "Alcohols as Motor Fuels.  Comparative Per-
    formance of Alcohol and Hydrocarbon Fuels, " SAE  Special Publication
    SP-254.

63. Strebar, R. F. and Parks, F. B. , "Emission Control With Lean Operation
    Using Hydrogen Supplemented Fuel. " Research Publication GMR-1537
    (FL-552).   Warren, Mich.:  General Motors Corp., March 1974.

64. Swain, M. R.  and Adt, R. R. , Jr.,  "The Hydrogen-Air Fueled Automobile. "
    Paper presented at the 7th Intersociety Energy Conversion Engineering
    Conference, San Diego,  September 25-29,  1972.

65. Taylor, C.F. and Taylor, E. S. , The Internal Combustion Engine.
    Scranton, Pa. :  International Textbook Co. , 1961.

66. Taylor, W. G.  et al. ,  "Reducing Smoke From Gas Turbines, " Mech.
    Eng. 9£, 29-35  (1968) July.

67. U.S. Environmental Protection Agency, Office of Air and Water Programs,
    Mobile Source Air Pollution Control, "Report  on Automotive Fuel Econo-
    my. " October 1973.

68. Walker, G. , "The Stirling Engine, " Sci.  Am.   229, 80-87 (1973) August.

69. Walter, L. , "First  German Coal-Fired Gas-Turbine Plant Comes
    Into Operation, " Elec.  Light Power  35.,  54-164 (1957) March  25.
                                 160

-------
     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.
                                   161

-------
      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

-------
   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.
                                    163

-------
   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

-------
       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.
                                    165

-------
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

-------
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
i—i
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

-------
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

-------
         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

-------
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

-------
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

-------
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

-------
   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

-------
   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

-------
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

-------
         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

-------
   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

-------
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

-------
                    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.
                                   202

-------
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
                                  203

-------
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.
                                 204

-------
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.
                                  205

-------
   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.
                                  206

-------
   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
                                    207

-------
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
                                    208

-------
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.
                                  209

-------
      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

-------
   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.
                                   211

-------
  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
                                   212

-------
    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.
                                  213

-------
   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.

                                   214

-------
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
                                    215

-------
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
                                   216

-------
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
                                    217

-------
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

-------
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

-------
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

-------
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

-------
                  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

-------
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

-------
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

-------
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

-------
              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.
                                   227

-------
   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

-------
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

-------
   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

-------
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

-------
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.
                                    233

-------
        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

-------
   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

-------
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

-------
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

-------
 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

-------
      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

-------
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

-------
 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

-------
   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

-------