EPA-460/3-74-013-C
July 1974
CURRENT STATUS
OF
ALTERNATIVE AUTOMOTIVE
POWER SYSTEMS
AND FUELS
VOLUME III -
ALTERNATIVE
NONPETROLEUM-BASED FUELS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Wasle Management
Offire of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
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EPA-460/3-74-013-C
CURRENT STATUS
OF
ALTERNATIVE AUTOMOTIVE
POWER SYSTEMS
AND FUELS
VOLUME III -
ALTERNATIVE
NONPETROLEUM-BASED FUELS
Prepared by
The Environmental Programs Group
The Aerospace Corporation
El Segundo, California 90245
Contract No. 68-01-0417
EPA Project Officer: Graham Hagey
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 of this
report are available free of charge to Federal employees, current contractors
and grantees, and non-profit organizations - as supplies permit - from the
Air Pollution Technical Information Center, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711, or may be obtained, for a
nominal cost, from the National Technical Information Service, 5285 Port
Royal Road, Springfield, Virginia 22151.
This report was furnished to the U.S. Environmental Protection Agency
by the Aerospace Corporation, El Segundo, California, in fulfillment of
Contract No. 68-01-0417 and has been reviewed and approved for publication
by the Environmental Protection Agency. 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 by
the reader to assure that it is acceptable for his purpose. Results and
conclusions should be viewed correspondingly. Mention of trade names
or commercial products does not constitute endorsement or recommendation
for use.
Publication No. EPA-460/3-74-013-C
11
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FOREWORD
This report, prepared by The Aerospace Corporation for the
Environmental Protection Agency (EPA), Alternative Automotive Power
Systems Division, summarizes available nonproprietary information on the
technological status of automotive power systems which are alternatives to
the conventional internal combustion engine, and the technological status of
nonpetroleum-based fuels derived from domestic sources which may have
application to future automotive vehicles.
The status of the technology reported herein is that existing at
the end of 1973 with more recent data in selected areas. The material pre-
sented is based principally upon the results of research and technology
activities sponsored under the Alternative Automotive Power Systems (AAPS)
Program which was originated in 1970 and which is administered by the Alter-
native Automotive Power Systems Division of EPA. Supplementary data are
included from programs sponsored by other government agencies and by pri-
vate industry. Additional information on technology and development programs
is known to the government but cannot be documented herein because the data
are proprietary.
One purpose that the AAPS Program serves is to provide a
basis of knowledge and perspective on what can and cannot be accomplished
with the use of alternative propulsion and fuels technology and to disseminate
this information to Congress, Federal policy makers, industry, and the public.
Thus, the publication of information such as that contained herein is in keeping
with this element of the mission of the AAPS Program. This is the first of a
series of reports on alternatives that are intended to be published annually.
The results of this study are presented in four volumes and
three main topical areas:
Volume I. Executive Summary
Volume II. Alternative Automotive Engines
111
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Volume III. Alternative Nonpetroleum-Based Automotive
Fuels
Volume IV. Electric and Hybrid Power Systems
Volume I, the Executive Summary, presents a concise review of important
findings and conclusions for all three topical areas. Thus, an overview of
study results may be obtained by reading Volume I only. Volumes II, III,
and IV contain detailed, comprehensive discussions of each topical area and
are therefore of interest primarily to the technical specialist. Each of these
three volumes also contains Highlights and Summary sections pertaining to
the topical area covered in the volume.
This volume, Volume III, presents available information per-
taining to the current technological status of alternative nonpetroleum-based
automotive fuels which may have application to future energy demands
imposed by automotive vehicles.
A brief review of important findings and conclusions is pre-
sented in the Highlights and Summary sections. A short overview of energy
supply/demand trends and the implications of the United States self-sufficiency
goal is given in Section 1. Section 2 presents an overview of energy resources
for transportation needs and industry projections for meeting them. Sec-
tions 3 through 11 address in detail the available data concerning the potential
use of the following types of alternative automotive fuels: synthetic gasoline
and distillate hydrocarbons, methanol and methanol-gasoline blends, methane
(natural gas and synthetic natural gas), propane and butane, ethanol and
ethanol-gasoline blends, hydrogen, ammonia, hydrazine, and fuels reformed
on-board conventional gasoline engine-powered automobiles. Principal
topics covered for each alternative fuel are characterization, suitability for
use as an engine fuel, current status, and projected status.
IV
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ACKNOWLEDGMENTS
Appreciation is acknowledged for the guidance and assistance
provided by Mr. Graham Hagey of the Environmental Protection Agency (EPA),
Alternative Automotive Power Systems (AAPS) Division, who served as EPA
Project Officer for this study. Appreciation is also extended to staff members
in the AAPS Division, to other EPA divisions, to various government agencies,
and to those in industry and the academic community who supplied reference
material and reviewed the contents of this report.
Data provided by Exxon Research and Engineering Company and
the Institute of Gas Technology were derived from the study effort performed
by them under contract to AAPS/EPA.
The following technical personnel of The Aerospace Corporation
made valuable contributions to the effort performed under this contract:
Edmund Blond
Lester Forrest
Otto Hamberg
Albert Lum
Alex Muraszew
Herbert White
Elliot Weinberg
Merrill G. Hinton, Director
Office of Mobile Source Pollution
D. E. Lapedes, citudy Manager
Toru lura, Associate Group Director
Environmental Programs
Group Directorate
XT^seph/Meltzer, Groun Director
(^Environmental Programs
Group Directorate
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CONTENTS
FOREWORD iii
ACKNOWLEDGEMENTS v
HIGHLIGHTS H-l
SUMMARY S-l
1. INTRODUCTION 1-1
2. TRANSPORTATION ENERGY RESOURCE
OVERVIEW 2-1
2. 1 Energy Supply versus Demand 2-1
2.2 Energy Supply 2-3
2.3 Energy Demand 2-l'2
2.4 Projected Status 2-13
3. SYNTHETIC GASOLINE AND DISTILLATE HYDROCARBON
FUELS 3-1
3. 1 Characterization 3-1
3.2 Suitability for Use as an Engine Fuel 3-27
3.3 Current Status 3-33
3.4 Projected Status 3-33
4. METHANOL AND METHANOL-GASOLINE BLENDS 4-1
4. 1 Characterization 4-1
4.2 Suitability for Use as an Engine Fuel 4-15
4.3 Current Status 4-34
4.4 Projected Status 4-39
5. METHANE (NATURAL GAS AND SYNTHETIC
NATURAL GAS) 5-1
5. 1 Characterization 5-1
5.2 Suitability of NG, SNG, and LNG for Use as
an Engine Fuel 5-20
vn
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CONTENTS (Continued)
5-40
5.3 Current Status ,
5.4 Projected Status 5~43
6. PROPANE AND BUTANE 6-1
6. 1 Characterization
6. 2 Suitability for Use as an Engine Fuel • • °-7
6. 3 Current Status 6'14
6. 4 Projected Status 6~18
7. ETHANOL AND ETHANOL-GASOLINE BLENDS 7-1
7. 1 Characterization 7-1
7.Z Suitability for Use as an Engine Fuel 7-8
7.3 Current Status 7-14
7.4 Projected Status 7-14
8. HYDROGEN 8-1
8. 1 Characteristics 8-1
8.2 Suitability for Use as an Engine Fuel 8-7
8.3 Current Status 8-16
8.4 Projected Status 8-20
9. AMMONIA 9-1
9. 1 Characterization 9-1
9.2 Suitability for Use as an Engine
Fuel 9-6
9.3 Current Status 9-15
9.4 Projected Status 9-16
10. HYDRAZINE 10-1
10. 1 Characterization 10-1
10. 2 Suitability for Use as an Engine Fuel 10-6
10. 3 Current Status 10-8
10. 4 Projected Status 10-10
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11. FUELS REFORMED ON-BOARD THE VEHICLE 11-1
11. 1 Characterization 11-3
11.2 Suitability for Use as an Engine Fuel 11-20
11.3 Current Status 11-32
11.4 Projected Status 11-32
ABBREVIATIONS Ab-1
GLOSSARY Gl-1
REFERENCES R-l
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FIGURES
S-i. Coal Demand/Supply Forecast S-3
1-1. U.S. Energy Consumption by Sector 1-2
1-2. Petroleum Con sumption/Supply Forecast 1-3
1-3. Gaseous Fuel Consumption/Supply Increase 1-5
1-4. Alternative Fuels, Guide to Topics of Discussion 1-6
3-1. COED Process 3-7
3-2. TOSCOAL Process 3-10
3-3. SYNTHOIL Process 3-12
3-4. H-Coal Process 3-14
3-5. Solvent Refined Coal Process 3-17
3-6. Consol Synthetic Fuel (CSF) Process 3-19
3-7. Oil-Shale Utilization - Routes and State of
Knowledge 3-22
3-8. TOSCO Process for Oil Shale Treatment 3-24
4-1. Methyl Alcohol Production Processes 4-9
4-2. Overall Scheme of the Sasol Plant 4-11
4-3. ASTM Distillation Curves for Gasoline and
Alcohol 4'13
4-4. Calculated Performance Comparison (IMEP) for
Isooctane, Benzene, Ethanol, and Methanol 4-19
4-5. Comparative Performance Results (IMEP) from
Engine Normalized about IMEP for Isooctane
at = 1.0 4'21
XI
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FIGURES (Continued)
4-6. Comparative ISFC from Engine Results Normalized
about ISFC of Isooctane at 0 = 1. 0 4-21
4-7. Air-to-Methanol Mixture Ratio as a Function of
Speed 4-22
4-8. Gasoline and Methanol Performance Comparison 4-24
4-9. Interrelationships of Power, Equivalence Ratio,
and Hydrocarbon with Isooctane and Methanol
at 1,000 rpm 4-26
4-10. Interrelationships of Power, Equivalence Ratio,
and Carbon Monoxide with Isooctane and
Methanol at 1,000 rpm 4-26
4-11. Interrelationships of Power, Equivalence Ratio,
and Nitric Oxide with Isooctane and Methanol
at 1,000 rpm 4-27
4-12. Interrelationships of Power- Equivalence Ratio,
and Aldehydes with Isooctane and Methanol
at 1,000 rpm 4-27
4-13. Invested Capital Cost Estimates for Methanol
via Natural Gas 4-40
5-1. Chemistry of Coal Gasification Process 5-14
5-2. Process and Alternatives for Producing SNG
from Coal 5-14
5-3. Power and Exhaust Emissions as a Function of
Air-Fuel Equivalence Ratio for Gasoline and
Natural Gas Fuels 5-33
5-4. Effect of Ambient Temperature on Exhaust
Emissions for Gasoline and Natural Gas Fuels 5-36
5-5. Effect of Productivity on the Average Value of
Coal from Surface Mines 5-49
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FIGURES (Continued)
6-1. Refrigerated Absorption Process for the Production of
LP Gas and Natural Gasoline Liquids 6-5
6-2. Air-Fuel Ratio and Spark Timing Effects 6-11
7-1. Manufacture of Ethyl Alcohol by Esterification-
Hydrolysis (Indirect Hydration) 7-5
7-2. Manufacture of Ethyl Alcohol by Direct
Hydration of Ethylene 7-5
7-3. Efficiency at Loads - 1962 Oldsmobile "7-10
7-4. Road Load Economy - 1962 Oldsmobile . . l-\\
8-1. Specific Fuel Consumption 8-10
8-2. Hydrogen-to-Gasoline Btu Consumption Ratio 8-10
9-1. Ammonia Synthesis from Natural Gas or Naphtha 9-3
9-2. Combined Coal Gasification/Water
Electrolysis 9-5
9-3. Flammability Characteristics of Ammonia in
Air and Oxygen at Atmospheric Pressure 9-9
10-1. Manufacture of Hydrazine by the Raschig
Process 10-3
10-2. Manufacture of Hydrazine by the Urea
Process 10-5
xin
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FIGURES (Continued)
11-1. Effect of Air-Fuel Ratio on Emission Levels 11-2
11-2. Component Location, International Materials Concept ... 11-7
11-3. Block Diagram, International Materials Concept 11-8
11-4. Reformer Canister Cross Section, International
11-5.
11-6.
11-7.
11-8.
11-9.
11-10.
11-11.
Fuel Reformer Concept, Phillips Petroleum
Features of Siemens Catalytic Carburetor System ....
Effect of Hydrogen Addition on Lean Operating
Limit with Isooctane as the Base Fuel
Effect of Ultralean Operation on Engine Power and
Efficiency with Hydrogen- Supplemented Fuel
Emissions Characteristics of Isooctane-Hydrogen
11-11
11-13
11-15
. . 11-16
. . 11-21
. . 11-23
11-27
XIV
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TABLES
S-l. Comparative Physical Characteristics of Alternative
S-26
S-2.
S-3.
S-4.
S-5.
2-1.
2-2.
2-3.
2-4.
2-5.
2-6.
3-1.
3-2.
3-3.
3-4.
3-5.
3-6.
4-1.
Production Processes for Alternative Nonpetroleum-Based
Automotive Fuels
Logistic Factors for Use of Alternative
Nonpetroleum-Based Automotive Fuels
Summary of Availability and Suitability of Alternative
Nonpetroleum-Based Automotive Fuels
Comparison of Tankage Requirements for Alternative
Nonpetroleum-Based Automotive Fuels
U.S. Energy Balance
U.S. Energy Resource Base
Domestic Coal Resources
Coal Potential Domestic Supply
Transportation Energy Demand
Distribution of Energy Consumption in
Transportation by Mode
Coal to Synthesis Gas (H_ + CO)
Properties of Conventional Hydrocarbon
Liquid Fuels
Fuel/Engine Compatibility
Plausible Schedule for Buildup of Shale Oil
Capacity and Production
Plausible Schedule for Buildup of Coal Liquids Production. .
Preliminary Economics of Coal and Shale Fuels
Methanol Production
S-27
S-29
S-30
S-34
2-2
.2-4
2-5
2-7
2-14
2-15
3-6
3-26
3-28
3-35
3-36
3-38
4-5
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TABLES (Continued)
4-2.
4-3.
4-4.
4-5.
4-6.
4-7.
4-8.
5-1.
5-2.
5-3.
5-4.
5-5.
5-6.
5-7.
5-8.
5-9.
5-10.
5-11.
5-12.
Properties of Isooctane and Methanol
Simplified Comparison of Combustion Chemistry
between Methanol and Isooctane
Chart Calculations of Cycle Characteristics
C.R. = 9:1, Intake Air = 100°F, 14.7 psia
Exhaust Emissions from Gremlin Automobile
Annual Synthetic Methanol Production in the
United States
U.S. Methanol Producers and Plant Capacities
Key Characteristics of Natural Gas
Methane Characteristics
Relative Properties of Natural Gas versus
Gasoline for Constant Energy Value
Natural Gas Reserves - Domestic
Potential Natural Gas Supply Rate
Summary of SNG from Coal Plants and
Projects
Coal to SNG
Tankage Comparison
Automotive Vehicle Compatibility with Natural Gas
when Compared with Gasoline Fuel
Vehicle Identification Fuel Consumption, and
Carbon Dioxide Data
Comparison of Exhaust HC Reactivity
Fuel Cost Comparison, 1973 $ per 10 Btu
4-14
4-17
4-18
4-28
4-35
4-36
4-38
5-3
5-4
5-7
5-8
5-9
5-16
5-21
5-25
5-27
5-30
5-34
5-42
XVI
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TABLES (Continued)
5-13. Comparison of U.S. Energy Forecasts by the Bureau
of Mines and Institute of Gas Technology 5-44
5-14. Plausible Schedule for Buildup of Coal Syngas
Production 5-46
5-15. Required Natural Gas Field Price in 1970 Constant
DoUars at 15% Return on Net Fixed Assets 5-48
5-16. Exploration and Development Expenditures for NG
in U. S 5-50
5-17. Cumulative Number of 250 Million Cubic Feet/
Stream Day Coal Gasification Plants 5-52
6-1. Physical Properties of Propane and Butane 6-3
6-2. Typical Emission Reduction through Gaseous Fuel
Conversion 6-10
6-3. Annual Production of LP-Gas 6-15
6-4. Source Production of LP-Gas 6-16
6-5. LP-Gas Consumption - 1971 6-17
7-1. Typical Ethyl Alcohol Specifications 7-2
7-2. Properties of Isooctane and Ethanol 7-7
7-3. U.S. Consumption of Specially Denatured Alcohol,
Fiscal Years 1960-1964 7-15
7-4. Price History of Industrial Ethyl Alcohol in the
United States 7-15
8-1. Domestic Resources of Fossil Hydrocarbons 8-2
8-2. Properties of Hydrogen 8-6
8-3. Emissions from Hydrogen Fueled Automobile,
gm/mile 8-13
xvu
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TABLES (Continued)
8-4. U.S. Hydrogen Usage 8-18
8-5. Investment for 2, 500-ton/day Liquid Hydrogen
Supply System 8-23
9-1. Ammonia Production 9-7
9-2. Physiochemical Properties of Anhydrous Ammonia 9-8
10-1. Producers of Hydrazine 10-9
11-1. Catalytic Hydrogen Generator Output Composition 11-18
11-2. Summary of Operational Characteristics,
JPL System 11-24
XVlll
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HIGHLIGHTS
-------
HIGHLIGHTS
Several nonpetroleuxn-based alternative fuels derived from
domestic sources have been considered as potential replacements for, or
partial supplements to, conventional petroleum-based gasoline and distillate
fuels for automotive use. Based on data sources in the open literature and on
information provided by Exxon Research and Engineering Company and the
Institute of Gas Technology (IGT) during their study contracts with EPA, a
status review of these fuels has been conducted with particular emphasis on
requirements of the personal passenger car in a near-term period (1975 to
1985)* and in a far-term period (1985 to 2000). The fuels that were examined
consisted of: synthetic gasoline and distillate hydrocarbons, methanol and
methanol-gasoline blends, methane (synthetic natural gas), propane, ethanol
and ethanol-gasoline blends, hydrogen, ammonia, and hydrazine. In addi-
tion, the concept of reforming fuels (chemical conversion) in a gas generator
on the vehicle was also considered.
The evaluation of each fuel was predicated on numerous inter-
acting factors, among which were abundance of domestic resources, tech-
nological status of production techniques, schedule for mass production,
estimated capital and consumer costs, and adaptability to both internal and
external combustion types of engines for automobiles (including character-
istics related to fuel economy, exhaust emissions, handling, storage, and
toxicity). It is noted that evaluations relating the ability of nonpetroleum-
based alternative fuels to compete in price with petroleum-based fuels are
in a state of flux because of the recent fluctuations in the cost of automotive
fuel. Likewise, cost estimates for alternative fuels may be revised as more
data are acquired from future pilot and prototype demonstration fuel produc-
tion plants.
^Exxon and Institute of Gas Technology designations were: near term (1975-
1985), mid-term (1985-2000), and far term (beyond 2000).
H-l
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It should also be recognized at the outset that an important
factor affecting the rate of possible implementation of each of these fuels
(except synthetic gasoline and distillate fuels) would be the need for a com-
pletely new nationwide specialized distribution and storage network.
Undoubtedly, if they were introduced, a dual-fuel system would be required
for an extended period of time to satisfy the needs of both gasoline-fueled
vehicles and new vehicles designed to use the alternative fuel.
Based on all the aforementioned considerations, it would appear
that synthetic gasoline and distillate hydrocarbons manufactured from coal and
shale will offer the greatest promise for contributing to automotive fuel
requirements in both the near-term and far-term periods. Coal-derived
methanol, particularly in a methanol-gasoline blend, could be considered
a secondary fuel source if certain technical problems can be solved. Another
alternative fuel of merit is hydrogen, but it can only be considered as a sig-
nificant contributor to automotive needs in the period beyond the year 2000.
The rationale for these selections is amplified in the following highlights
which present the essential elements of the current status of alternative
automotive fuels.
Synthetic Gasoline and Distillate Hydrocarbon Fuels
1. Synthetic gasoline and distillate hydrocarbon fuels could be
manufactured from coal, oil shale, tar sands, or organic
waste products. They possess the primary advantage of
expected complete compatibility with existing and advanced
automotive power plants, as well as with distribution facilities
down to the local gas station.
2. Coal (particularly from strip mining processes) is by far the
largest and most probable domestic energy resource available
for synthetic fuel production, followed by oil shale. Addi-
tional domestic sources of much less potential, in terms of
ability to meet projected energy needs, are tar sands and
organic waste products.
3. The production cost in the post 1985 time period for gasoline
and distillate hydrocarbon fuels derived from oil shale is
estimated to be competitive with that for current costs of con-
ventional petroleum-based sources. Equivalent liquid hydro-
carbon fuels derived from coal are more expensive but are
H-2
-------
also competitive. Waste product disposal constitutes a
serious environmental problem in either case with processed
oil shale being the most critical concern.
4. The production economics for liquid hydrocarbon fuels derived
from coal and shale will ultimately depend on (a) the efficient
commercialization of various production processes currently
under evaluation in laboratory and pilot-plant models, and
(b) the transport distance required for raw and/or refined
products. Intensive capital investment will be required if
several 50,000- to 100,000-barrel-per-day plants are to be
in operation in the 1980-1985 period.
5. Little information is available on the actual use of synthetic
gasoline or distillates in automotive engines. A test program
to verify the compatibility of these fuels with automotive
engines is planned for Fiscal Year 1975 under an interagency
agreement between EPA and the Bureau of Mines.
Methanol and Methanol-Gasoline Blends
1. Pure methanol has seen limited successful use with spark
ignition engines powering automobiles. It offers the following
advantages:
a. An increase in power from existing engines fueled with
gasoline, largely because methanol heat of vaporization
characteristics lead to increases in air inducted into the
engine and to increases in net work output.
b. An increase in efficiency and in power output per pound
of engine weight or new engine designs because the
engine can operate at higher compression ratios than
with high octane premium gasoline.
2. Certain disadvantages of pure methanol will require that care-
ful preparation by fuel distributors and automotive manufac-
turers precede its possible introduction into the retail sales
market. Among these disadvantages are:
a. Fuel economy (in miles per gallon) with pure methanol
is about half that with gasoline, necessitating a major
increase in the size of the automobile fuel tank and
modifications to the carburetor fuel jets [although the
energy expended each mile (in Btu per mile) in powering
an automobile with methanol is equivalent to the energy
expended with gasoline],
b. When contrasted with gasoline, vapor pressure charac-
teristics of pure methanol imply that there may be a
greater incidence of vapor lock with current automobile
H-3
-------
fuel system designs. Also, cold start is more difficult
and manifold preheating is required to ensure complete
vaporization in carbureted systems.
c. Miscibility between pure methanol and water can result
in the presence of water (from local atmospheric mois-
ture condensation) in the fuel distribution system, in
the service station tanks, and in the vehicle tank, lead-
ing to possible corrosive action on metal surfaces in
piping, tankage, and within the engine itself. Corrosion
inhibitors may be required in the fuel to avoid this
problem.
d. Synthetic methanol transport costs are expected to be
higher than those estimated for synthetic gasoline
because, for equal energy content, the pure methanol
volume required to be piped, trucked, and stored is
approximately twice that of gasoline. Therefore, when
distribution costs are included, the cost at the pump to
the consumer, per unit of fuel energy delivered (excluding
tax), is estimated to be 10 to 30 percent greater than that
for synthetic gasoline from coal and shale,respectively.
e. The solvent action of pure methanol may damage paint,
metal, and plastic surfaces; therefore, solvent-resistant
materials must be considered for use in all applications.
3. A greater near-term advantage may be evident by the use of
methanol-gasoline blends rather than pure methanol. This
approach would conserve gasoline stocks to a small degree
without necessitating major redesign of automobiles or engines.
It should be noted, however, that even if methanol is added in
a methanol-gasoline blend only to the five percent level, cur-
rent automotive fuel consumption would require about five
times the present U.S. methanol production.
4. As with pure methanol, methanol-gasoline blends have a higher
octane rating than gasoline alone. But there are indications
that the motor octane number (MON) increase is not nearly
as great as that which would be expected from measured
increases in the research octane number (RON). This would
indicate that engine road performance increases will not be as
marked as those found in the laboratory.
5. Vapor lock and water miscibility problems would be present to
a much greater degree with methanol-gasoline blends than with
pure methanol. An example of these problems is the separa-
tion of gasoline and methanol hi the presence of very small
amounts of water, particularly at low temperatures. Solutions
to these problems may be possible, but they require laboratory
and road test verification.
H-4
-------
6. The majority of published data on the application of methanol
and methanol-gasoline blends to fueling automotive engines
Ls about 20 to 30 years old. The use of new materials, engines,
gasoline blends, and lubricating oils is a compelling factor for
acquiring more contemporary characteristics of methanol in
order to verify or invalidate older concepts regarding advan-
tages and disadvantages of this alternative fuel. In this
regard, the adaptability of methanol and methanol-gasoline
blends to modern automotive systems will be explored sys-
tematically in a test program initiated by the Bureau of Mines
through an interagency agreement with EPA. Other research
programs investigating methanol and methanol blends are in
progress or planned at several universities and industry
research laboratories.
Methane (Synthetic Natural Gas)*
1. Because of supply constraints of natural gas, efforts are under
way to develop the technology for deriving synthetic natural
gas from either coal or liquid hydrocarbons. Production levels
will depend on the completion of coal gasification plants which
are first expected to be in operation in the post-1980 period
Liquefied gas (natural or synthetic) is more attractive than the
gaseous form because of its greatly increased density (result-
ing in reduced storage volume requirements in the vehicle).
However, the low boiling point requires application of cryo-
genic tank insulation techniques which add substantially to
automobile tankage weight and cost relative to a conventional
gasoline system.
3. Energy expenditure per mile in powering an automobile with
an engine converted to operate on natural gas is approximately
equal to or better than that for a similar vehicle using a
modern gasoline engine equipped with emission control devices.
In general, exhaust emissions with natural gas are expected
to be lower than those with gasoline.
4. A significant factor in the use of natural gas in place of gaso-
line as an automotive fuel is the reduced activity of hydro-
carbon emissions in the formation of photochemical smog.
Total hydrocarbon activity is four to six times less than that
of gasoline.
*Also referred to as Substitute Natural Gas
H-5
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5. Because of the difficulties in implementation of an adequate
fuel distribution system throughout national urban areas, and
because of the problems of storage on the vehicle, neither
liquified nor compressed natural gas is considered to be a
primary alternative fuel candidate for large-scale automotive
use. Usage would be expected primarily for commercial fleet
operations. However, synthetic natural gas may be expected
to be of significance in replacing petroleum fuels for stationary
electric generating power plants based on projections that, in
the far-term period, 20 to 25 percent of the total gas supply
may come from coal gasification.
Propane
1. Propane appears suitable for use in all of the conventional and
alternative engines currently being considered. Vehicle tank-
age volume and weight is less than that required for methane,
and cryogenic cooling is not required for storage in a liquid
form if the fuel is pressurized to about 250 pounds per square
inch. However, as in the case of methane, this fuel is not
considered a primary alternative candidate for large-scale
autpmptive use because of distribution and storage problems.
2. Exhaust emissions from propane show marked reductions when
compared to those from gasoline, but fuel economy trends are
inconsistent amongst different data sources.
3. Adequate availability of the fuel is a major problem because
the major production source of propane is natural gas process-
ing plants (a declining resource). Hence, a new raw material
source (e. g. , coal or oil shale) and production process would
be required to increase its availability.
4. Consumer costs of liquid petroleum gas are generally similar
to the price of gasoline, as of mid-1973, but gasoline is cheaper
on the basis of energy expended per mile in powering an auto-
mobile. Furthermore, if in the future propane is manufactured
synthetically from coal, costs to the consumer are projected
to be greater than for synthetic methane (and certainly greater
than for synthetic gasoline).
Ethanol and Ethanol-Gasoline Blends
1. Ethanol has been demonstrated to be compatible as a motor
fuel with present vehicles. In many parts of the world, it has
been blended in concentrations varying between 10 and 20 per-
cent to alleviate gasoline shortages. Pure ethanol or blends
with gasoline have essentially the same usage problems cited
for methanol.
H-6
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2. The economics and instability in the price of ethanol production
based on fermentation of agricultural raw materials and the
poor fuel economy are additional major factors tending to limit
its use. Ethanol-gasoline blends have been considered, but
the cheaper and equally efficient methanol-gasoline blends are
preferred.
Hydrogen
1. Success has been attained in carrying out the necessary
mechanical conversions to enable conventional gasoline engines
to operate on hydrogen. Indications are that extremely low
exhaust emission levels are possible. Fuel economy on an
energy-expended-per-mile basis is found to be comparable to
that for gasoline, but maximum engine power output for a
given engine size is reduced significantly.
2. A major technical drawback with hydrogen, as fuel for the
automobile, is the problem of storage on the vehicle. In com-
pressed gas form it is not practical, and even in cryogenic
liquid form the complex and expensive storage requires a tank
capacity three and one-half times that needed for gasoline on
an equivalent energy basis. Research is under way to evaluate
an alternative reduced-volume storage approach using metal
hydrides; a means of also reducing the storage weight will be
necessary before this technique can be considered practical.
3. Additional major obstacles to using hydrogen as a universal
fuel concern the energy supply adequacy for its manufacture
as well as very high costs to the consumer. Nuclear power
will be a necessary factor in ensuring an adequate supply of
energy for production of hydrogen by water electrolysis. On
an equivalent energy basis, liquid hydrogen cost to the con-
sumer will be much greater than the cost of gasoline or distil-
late derived from coal. Much of this cost is attributable to
significant cost items connected with the liquefaction of hydro-
gen and its subsequent transportation to, and storage at,
retail outlets.
4. Even if costs are reduced, hydrogen appears to be a possible
fuel only for the post 2000 time period. The massive capital
requirements for manufacturing plants and distribution facil-
ities, and the extensive period needed for actual construction
activities, preclude any earlier consideration of this fuel as a
major contributor to passenger car needs.
H-7
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Ammonia
1. The Interest in ammonia as an engine fuel stems from the
consideration that it allows the storage of hydrogen in nitrogen
hydride form at relatively low pressures without some of the
fire and explosion hazards associated with pure hydrogen. But
the extreme toxicity of ammonia, combined with expected high
consumer costs, does not hold much promise for this fuel
even for the far-term period.
Hydrazine
1. For the very sarrie reasons cited for ammonia, hydrazine is
considered unsuitable as an alternative to petroleum-based
fuels.
Fuels Reformed On the Vehicle
1. One approach which is being investigated as a means of extend-
ing the lean operating limits of gasoline engines in order to
achieve low exhaust emissions is the incorporation of a fuel
reformer device to chemically convert all or a portion of the
engine's fuel requirements from gasoline (or any liquid hydro-
carbon fuel) to a gaseous product (principally hydrogen) prior
to induction into the engine. Initial exploratory tests have
indicated marked reductions in carbon monoxide and oxides
of nitrogen exhaust emissions at very lean air-fuel ratios, but
these positive factors are offset by high hydrocarbon exhaust
emissions. Fuel economy is projected by some investigators
to be equal to or better than that obtainable with a gasoline-
powered engine.
2. Fuel-reformer concepts are still in the exploratory, proof-of-
principle, or feasibility determination stage. A number of
critical data gaps must be filled before the potential of reformed
fuels can be fully assessed. NASA has been funding the Jet
Propulsion Laboratory to acquire data and prove concept feasi-
bility, and EPA is providing supplemental funding for this work
in addition to other contractor-supported programs for evalua-
tion of similar concepts.
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SUMMARY
-------
SUMMARY
S. 1 SUMMARY OF ALTERNATIVE NONPETROLEUM-BASED
FUEL RESOURCES
Domestic liquid petroleum products satisfied 74 percent of the
United States energy consumption in 1971; they are expected to satisfy only
about 1/2 of the need in the year 1985 and less than half in the year 2000.
This excess demand-versus-supply situation provides a strong motivation for
government agencies and the transportation industry (which consumes at
present about 55 percent of liquid petroleum products) to investigate the
potential of alternative nonpetroleum-based fuels for automotive applications.
Several nonpetroleum-based alternative fuels have been considered as poten-
tial replacements for, or partial supplements to, conventional petroleum-
based fuels. These were evaluated on the basis of: availability, compati-
bility with existing distribution and storage systems (both mobile and
stationary), suitability for use with personal passenger cars, relative advan-
tages in terms of vehicle fuel economy and emissions, costs to the consumer,
capital investment costs, critical research gaps, technological status, and
the time scale for production implementation. A principal data source used
was the two EPA/A A PS-funded studies (with the Institute of Gas Technology
and Exxon Research and Engineering Company) related to the assessment of
alternative automobile fuels.
In evaluating the potential of alternative fuels for transportation,
the energy source from which they are derived is a prime consideration.
Sources available in the future will be coal, oil shale, solar energy, and
nuclear energy, while liquid petroleum and natural gas will be in continued
short supply. Significant production of liquid petroleum fuels from coal, oil
shale, and tar sands cannot be expected until the far term period of 1985 to
2000. * Contributions to domestic energy needs from solar and nuclear energy
are not expected to be available until even later periods.
# Exxon and IGT designations were near term (1975-1985), mid-term (1985-
2000), and far term (beyond 2000).
S-l
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Coal is relatively plentiful in the U. S., but its availability will
be somehow limited by the mining rate. The various forecasts which may
require updating now show that it is possible to achieve a rate of domestic
coal supply such that, after providing for its normal usage and for coal
liquefaction and gasification, a surplus may be left allowing for coal export.
Figure S-l shows the forecast of the future coal supply and demand. It is
quite possible that, with the new emphasis put now on coal production, the
supply beyond the year 1985 may exceed previous predictions. Thus, the
availability prospects are good for alternative fuels derived from coal. Oil
shale resources are not as plentiful as coal and domestic tar sands form sub-
stantially lower fossil fuel reserves than oil shale.
According to estimates of the National Petroleum Council and
other sources, the domestic energy resource base for these fuels is
80, 200 X 1015 Btu (3. 21 X 1012 tons) for coal, 9549 * 1015 Btu (1781 X 109 bbl)
for oil shale, and 127 X 1015 Btu (23.5 X 109 bbl) for tar sands. For coal
resources, 39,000 X 10 Btu are proven and 41,200 X 10 Btu are reason-
ably assured. For oil shale resources, 116 X 10 Btu are proven,
1517 X 10 Btu are reasonably assured, and 7916 X 10 Btu are speculative.
The tar sands figure is designated as a reasonably assured resource. Recover-
able reserves are less than the figures cited and depend largely on extraction
economics, extraction procedures, and possible legal restraints.
Nuclear energy, if developed at the rate forecast, could indi-
rectly benefit the transportation sector by partially relieving the electric
sector from the use of fossil fuels. These benefits to the electric sector could
also be supplied by solar energy. This energy source will require a major
technology breakthrough to be considered for use by the transportation sector.
It cannot be considered for the near-term period (1975 to 1985) and may be
problematical for use to the year 2000.
Based on all the aforementioned considerations, it would appear
that synthetic gasoline and distillate hydrocarbons manufactured from coal and
shale will offer the greatest promise for contributing to automotive fuel
requirements in both the near-term and far-term periods. Coal-derived
S-2
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«o 700
600
500
400
300 -
200 -
100 -
0
1970
RECENT EXXON PROJECTIONS
(coal for SNG production)
EXPORTS
1980 1990
YEAR
2000
?!
Figure S-l. Coal Demand/Supply Forecast
Walter G. Dupree and James A. West, "United States Energy
through the Year 2000," U.S. Department of the Interior,
December 1970.
S-3
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methanol, particularly in a methanol-gasoline blend, could be considered a
secondary fuel source if certain technical problems can be solved. Another
alternative fuel of merit is hydrogen, but it can only be considered as a sig-
nificant contributor to automotive needs in the period beyond the year 2000.
The rationale for these selections is amplified in the following discussion
which presents a summary of the characteristics, attributes, and problem
areas associated with each alternative fuel. Tabulated comparative data are
also presented to summarize the overall alternative fuel picture in a more
graphic manner.
S. 2 STATUS SUMMARY OF ALTERNATIVE FUELS
S. 2. 1 Synthetic Gasoline and Distillate Hydrocarbon Fuels
Synthetic gasoline and distillate hydrocarbon fuels could be
manufactured from coal, oil shale, tar sands, or organic solid waste prod-
ucts. They possess the primary advantage of expected complete compatibility
with existing and advanced automotive power plants, as well as with distri-
bution facilities down to the local gas station. Coal (particularly from strip
mining processes) is by far the largest and most probable domestic energy
resource available for synthetic fuel production, followed by oil shale. Tar
sands and organic waste products show much less potential to meet projected
energy needs.
The production cost in the post-1985 time period for gasoline
and distillate hydrocarbon fuels derived from oil shale is estimated to be
competitive with that for current costs of conventional petroleum-based
sources. Equivalent liquid hydrocarbon fuels derived from coal are more
expensive but are also competitive. The cost of petroleum-based fuels are
determined by a combination of both foreign and domestic fuels costs; the
foreign import costs are not within the control of this country.
The production economics for liquid hydrocarbon fuels derived
from coal and shale will ultimately depend on (a) the efficient commercializa-
tion of various production processes currently under evaluation in laboratory
S-4
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and pilot-plant models, and (b) the transport distance required for raw and/or
refined products. Intensive capital investment will be required if several
50,000 to 100,000-barrels-per-day plants are to be in operation in the 1980
to 1985 period.
Several processes are being investigated to make liquid hydro-
carbon fuels from coal; one is in commercial production outside the United
States, others are in the development stage or at a pilot plant scale within the
United States. It is expected that the United States coal liquefaction industry
will primarily be associated with western strip mine coal. This reflects the
large resource base in this area, as well as low mining costs. Western coal
has a further economic advantage because much of it has low sulfur content.
The coal syncrude can be processed by extension of conventional refining
technology.
The availability of shale oil for production of synthetic gasoline
and distillate hydrocarbon fuels is very uncertain because of the difficulty in
predicting production levels through the rest of the century. On the one hand,
the resource base is extensive, the cost of production is moderate, and the
technology is fairly well developed. On the other hand, there are very signi-
ficant environmental problems. (As in the case for coal, waste product dis-
posal constitutes a serious environmental problem, with contaminated water
from oil shale processing being a critical concern. ) Federal leases must
also be made available, and the capital intensive mining and retorting must
be carried out in remote locations. Costs of a specific shale oil recovery
project are influenced by the richness of the shale, water availability, shale
disposal facilities, general terrain, etc. Except for the construction of spur
lines, it is expected that existing pipe lines can be used to transfer the syn-
crude from the first few plants, either to midwest or gulf area refineries.
Projections indicate that shale oil cannot meet the total expected transporta-
tion fuel demand and that conventional petroleum or other synthetic fuels
would be also needed.
S-5
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The high cost of oil extraction from U. S. tar sands, combined
with the limited resources, will most probably delay any major production of
fuel from this source until the end of the far-term period.
The outlook for liquid fuel production from organic solid waste
is highly speculative. Most development and pilot plant work will be confined
to utilization of municipal waste, although design studies are being made of a
plant to convert wood processing and logging wastes to oil.
Little information is available on the use of synthetic gasoline
and distillate hydrocarbon fuels in automotive engines. A test program to
investigate the compatibility of these coal- and shale-derived synthetic fuels
with automotive engines is planned for Fiscal Year 1975 under an interagency
agreement between EPA and the Bureau of Mines. In regard to the character-
istics of these fuels, shale-derived transportation fuels will be probably
almost indistinguishable from conventional petroleum fuel, while coal-derived
fuels will have a much higher aromatic content. Emissions data are not yet
available for synthetic hydrocarbon fuels in current or advanced automotive
engines. A first step in obtaining such information will form part of the above-
mentioned Bureau of Mines test program.
Major issues controlling the production levels of coal- and oil
shale-derived synthetic fuels include the following: trends in petroleum
refinery construction, expected automotive transportation fuel demands, and
efficient and economic methods for processing coal and shale syncrude (both
before 1990 when it will be a fairly small fraction of the total crude oil, and
after 1990 when it could become a sizable fraction). The refined gasoline or
distillate from both coal and shale will probably be blended with petroleum-
derived analogs for quite some time.
S. 2. 2 Methanol and Methanol-Gasoline Blends
Industrially, methanol is used chiefly as a solvent and precur-
sor in the manufacture of plastics, resins, and organo-chemicals. It also
has been used as an automotive antifreeze, an automotive fuel in racing, and
as a reciprocating aircraft engine fuel injectant.
S-6
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Practically any organic matter, including fermentable matter,
can be used to produce gases for the direct synthesis of methanol. The most
economical domestic starting materials at present are hydrocarbons derived
from natural gas or naphtha. Synthetic methanol production has climbed
steadily in this country. Present production rates represent about one bil-
lion gallons annually, with new production capacity being achieved from lar-
ger plants. These larger units have also tended to improve economics.
Future production of methanol for transportation fuel will more
likely come from solid fuels as starling materials for methanol synthesis.
The primary constituent of the synthesis gas is hydrogen, along with carbon
monoxide and, frequently, carbon dioxide. Coal is by far the largest and
most probable domestic resource of this type available for methanol produc-
tion. The technology in coal gasification is well founded, and funding is being
accelerated to bring the various processes into the production stage. The
practicality of converting oil shale to methanol is doubtful; it is more likely the
derived liquids would be consumed directly as hydrocarbon fuels.
United States forest areas represent a potential source of
organic raw material for methanol manufacture, since methanol is obtained as
a byproduct in the destructive distillation of wood. The key economic question
to be resolved is whether the insignificant cost of waste wood as raw material
would sufficiently offset the large investment required in plant equipment and
product distribution costs.
Methanol has many physical and chemical properties that are
similar to gasoline. Aside from some operational problems, pure methanol
has seen limited successful use with spark ignition engines powering auto-
mobiles. For this type of engine it offers the following advantages: (a) an
increase in power from existing engines fueled with gasoline, largely because
methanol heat of vaporization characteristics lead to increases in air inducted
into the engine and to increases in net work output, and (b) an increase in
efficiency and in power output per pound of engine weight for new engine
designs, because the engine can operate at higher compression ratios than
with high octane premium gasoline. It would also be generally compatible for
S-7
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use
with future turbine engines, with relatively minor impact on such vehicles
and their respective powerplants. Methanol is deemed suitable for use with
other external combustion systems, for example, Rankine or Stirling engines,
and some effort has been reported regarding fuel cell applicability. It is not
suitable, however, for compression ignition (diesel-type) cycles because of
its low cetane number.
Little data exist on emission levels for spark ignition gasoline
engines run with pure methanol. The general trends seem to indicate, how-
ever, that emissions can be reduced for hydrocarbons, carbon monoxide, and
oxides of nitrogen, although results were quite mixed and dependent upon the
source of data and the conditions under which the engines were run.
Certain disadvantages of pure methanol will require that care-
ful preparation by fuel distributors and automotive manufacturers precede its
possible introduction into the retail sales market. Some of these disadvantages
are discussed in the following paragraphs.
Fuel economy (in miles per gallon) with pure methanol is about
half that with gasoline, necessitating a major increase in the size of the auto-
mobile fuel tank and modifications to the carburetor fuel jets [although the
energy expended each mile (in British thermal units per mile) in powering an
automobile with methanol is equivalent to the energy expended with gasoline].
Synthetic methanol distribution costs are expected to be higher
than those estimated for synthetic gasoline because, for equal energy content,
the pure methanol volume required to be piped, trucked, and stored is approx-
imately twice that of gasoline. Therefore, when distribution costs are
included, the cost at the pump to the consumer, per unit of fuel energy
delivered (excluding tax), is estimated to be 10 to 30 percent greater than
that for synthetic gasoline from coal and shale,respectively.
The boiling point of pure methanol is lower than that of the
bulk of the constituents of gasoline, which may result in a greater incidence
of vapor lock with current automobile fuel system designs. On the other hand,
the vapor pressure of methanol is substantially less than that of the very
lightest ends of gasoline. The latter being responsible for the good cold start
S-8
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properties of gasoline, manifold preheating would probably be required for
cold starts with a carbureted methanol system.
Miscibility between pure methanol and water can result in the
presence of water (from local atmospheric moisture) in the fuel distribution
system, in the service station tanks, and in the vehicle tank, leading to
possible corrosive action on metal surfaces in piping, tankage, and within
the engine itself. Corrosion inhibitors may be required in the fuel to avoid
this problem.
Because of the solvent action of pure methanol, paint, metal,
and plastic surfaces may be damaged; solvent resistant materials must be
considered for use in all applications.
Methanol-gasoline blends may offer a greater near-term advan-
tage than pure methanol. This approach would conserve gasoline stocks to a
small degree without necessitating major redesign of automobiles or engines.
It should be noted, however, that even if methanol is added in a methanol-
gasoline blend only to the five-percent level, current automotive fuel con-
sumption would require about five times the present U. S. methanol production.
As with pure methanol, methanol-gasoline blends have a higher
octane rating than gasoline alone. But there are indications that the motor
octane number (MON) increase is not nearly as great as that which would be
expected from measured increases in the research octane number (RON).
This would indicate that engine road performance increases will not be as
marked as those found in the laboratory.
Vapor lock and water miscibility problems would be present to
a much greater degree with methanol-gasoline blends than with pure methanol.
An example of these problems is the separation of gasoline and methanol in
the presence of very small amounts of water, particularly at low temperatures.
Solutions to these problems may be possible, but they require laboratory and
road test verification.
S-9
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The majority of published data on the application of methanol and
methanol-gasoline blends to fueling automotive engines is about 20 to 30 years
old. The use of new materials, engines, gasoline blends, and lubricating oils
is a compelling factor for acquiring more contemporary characteristics of
methanol in order to verify or invalidate older concepts regarding advantages
and disadvantages of this alternative fuel. In this regard, the adaptability of
methanol and methanol-gasoline blends to modern automotive systems will be
explored systematically in a test program initiated by the Bureau of Mines
through an interagency agreement with EPA. Other research programs
investigating methanol and methanol blends are in progress or planned at
several universities and industry research laboratories.
Methanol is known to be toxic, producing blindness through
ingestion or narcosis through inhalation. There is a need for more informa-
tion on extended low-level exposure to methanol such as would result from
widespread use as a motor fuel.
In terms of fire safety, methanol fires should be easier to
quench than gasoline fires because of its miscibility with water. On the other
hand this miscibility will require special precautions to prevent fuel contami-
nation, adulteration, and the corrosive effects previously discussed.
S. 2. 3 Methane (Natural Gas and Synthetic Natural Gas)*
Natural gas consists mostly of methane, with relatively small
amounts of other hydrocarbons such as ethane, propane, butane, etc. Because
of supply constraints of natural gas, efforts are under way to develop the
technology for deriving synthetic natural gas from either coal or liquid hydro-
carbons. A necessary constraint is that the synthetic gas be interchangeable
with the natural gas as used by the power utility industry and the transporta-
tion industry.
*Also referred to as Substitute Natural Gas
S-10
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In the application of natural gas to the transportation industry,
both compressed natural gas (at pressures up to 3000 pounds per square inch)
and liquid natural gas are being used. Liquid natural gas is more attractive
than the gaseous form because of its greatly increased density (resulting in
reduced storage volume requirements on-board the vehicle) as compared with
pressurized gas. However, the low boiling point requires application of
cryogenic tank insulation techniques, which will add substantially to auto-
mobile tankage weight and cost relative to a conventional gasoline system.
For example, liquefied natural gas fuel plus container will require an addi-
tional 100-pound weight and occupy approximately 2. 2 times the volume of
gasoline, including tankage provisions.
The production of synthetic natural gas from coal is particu-
larly attractive. Production levels will depend on the completion of coal
gasification plants expected to be in operation in the post-1980 period. It is
expected that by 1985, 35 to 40 coal gasification plants, each producing
approximately 250 million cubic feet per day, will be in operation, with a
total output approaching nine billion cubic feet per day. The predicted supply
of synthetic natural gas derived from coal in the year 2000 will be about 20 to
25 percent of the domestic production level of natural gas and may be expected
to be of significance in replacing petroleum fuels for stationary electric
generating plants.
Based on limited data, engine operation with methane is char-
acterized by energy consumption, in British thermal units per mile, equal to
or better than gasoline. There will be, however, a 10 to 15 percent drop in
maximum power with gasoline-to-methane converted engines because of the
greater volume occupied by gas than by semivaporized gasoline in the air. ,
The favorable characteristics of operation with natural gas or
synthetic natural gas in a spark ignition engine are expected to apply to other
alternative engines. These characteristics are ease of starting (particularly
in cold weather), cleaner combustion with low emission of pollutants, and
possibility of operation at lean air-fuel mixtures with high combustion
efficiency.
S-ll
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Exhaust emissions from engines run on natural gas can be
expected to be lower in general than those from gasoline-powered engines.
A factor of importance is the reduced activity of hydrocarbon emissions with
natural gas as opposed to the higher levels of activity with gasoline. (Total
hydrocarbon activity is four to six times less with natural gas.) This should
result in a reduction in photochemical smog. Data on exhaust emission levels
and fuel economy for automotive engines powered by natural gas, synthetic
natural gas, or liquid natural gas are quite sparse.
The toxicity of natural gas is indicated to be less than gasoline
and it does not present a health problem. Natural gas may also be less
hazardous than gasoline because its specific density is lower than air, which
prevents formation of fuel-rich pockets near the ground in case of leakage.
However, the hazard of operation with natural gas and particu-
larly liquid natural gas should not be underestimated. The low boiling point of
LNG at atmospheric pressure will require overboard venting^ when the engine
is not operative and the safe disposal of the boiloff by burning.or dissipation
in free air must be ensured. Information of a more extensive nature is
required to evaluate the problem of boiloff of liquid natural gas from storage
tanks.
As long as price regulation keeps natural gas prices low,
current projections show the fuel cost per mile for natural gas as being lower
than that for gasoline. The competitiveness of compressed natural gas or
liquid natural gas with gasoline is, of course, highly dependent on fluctuations
in price at the service station pump.
Considering the impact factors of economy of operation, safety,
maintenance, fuel distribution, and refueling provisions, the use of natural
gas will be limited mainly to fleet vehicle operation with depot refueling.
Available gas supplies could also be used in stationary power plants, thus
releasing some of the liquid petroleum for use by the automotive sector.
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S. 2. 4 Propane and Butane
Liquid petroleum gas consists of various petroleum-associated
chemical compounds whose boiling temperatures are below normal room
temperature. The principal commercial products are propane and butane,
and because of the chemical and physical properties of these compounds, they
are the only potential liquid petroleum gas candidates considered here as
alternative automotive fuels.
Crude oil wells, natural gas wells, light-hydrocarbon wells,
and refinery operations are the principal sources of liquid petroleum gas
(generally a by product in the production of natural gas and gasoline). Liquid
petroleum gas domestic reserves are, therefore, related to the domestic
crude oil and natural gas reserves. The primary production of liquid petroleum
gas (approximately 74 percent of total production) comes from natural gas
processing.
The use of liquid petroleum gas as an internal combustion
engine fuel has a long history dating back to the early 1930s. The early com-
mercial product was an uncertain mixture of propane, butane, and other gases
with variable chemical and physical properties. Its use as an engine fuel
resulted in many problems leading to disagreements as to its advantages and
disadvantages. In 1962, the National Gas Processors Association adopted a
specification for standardizing propane engine fuel and establishing the mini-
mum level of propane and other standards of purity.
Propane appears suitable for use in all of the alternative engines
currently being considered. In general, the use of gaseous fuels will provide
for better mixing of the fuel-air charge, particularly in multicylinder engines
where uniform distribution of the mixture from cylinder to cylinder and within
each combustion chamber is difficult to achieve. This permits leaner mixtures
to be used which may result in some measurable gain in specific fuel consump-
tion. The ability of the engine to run on lean propane mixtures also tends to
offer reductions in exhaust emissions of hydrocarbons, carbon monoxide, and
oxides of nitrogen. Further, the reactivity of the exhaust products in reaction
with sunlight (to form photochemical smog) is reduced when burning propane
as compared with gasoline .
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Based on test results for a converted 1969 327-cubic-inch-
displacement Chevrolet engine operating at lean air-fuel settings ranging
from 15 to 20, it appears that propane fuel offers a means of meeting the
1975 Federal interim emission standards. The emission control capability
presently attainable through the use of propane fuel falls somewhat short of
meeting the original 1976 Federal emission standards; vehicles tuned to
achieve this capability show definite driveability problems associated with
lean operation.
For the spark ignition engine, the high octane rating of propane
permits a higher compression ratio to be used in the design, thereby improving
the thermal efficiency and, accordingly, the specific fuel consumption char-
acteristics of the engine. The overall improvement Ln fuel economy attainable
through the use of propane in different engines is difficult to predict. For the
conventional spark ignition engine, different users have experienced varying
results depending upon the condition of the engine, weight of the vehicle, air-
fuel mixture ratio, engine power setting, and a host of other variables.
Both propane and butane are relatively nontpxic gases and thus
are safe to use.
Propane and butane can be stored in a liquefied state by either
pressurizing the storage container or by cooling below relatively moderate
boiling points. Of the two gases, propane is more generally suitable for on-
the-road automotive vehicles because of its lower boiling point and higher
octane rating. The lower boiling point of propane permits its use in colder
climates where butane may require a separate heating source to vaporize the
fuel for initial engine starting. Propane does, however, require higher tank
storage pressures than butane to maintain it in a liquid state.
Because the current major production source of propane and
butane is natural-gas processing plants, a new raw material source and pro-
duction process for obtaining liquid petroleum gas would be required to increase
its availability. Economically acceptable methods of producing liquid petroleum
gas directly from coal or from oil shale are needed. But even if costs of
S-14
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production of liquid petroleum gas from coal by either gasification or lique-
faction are reduced, the production of gasoline from coal would be more
efficient in terms of energy utilization. Considering this factor as well as
the problems in establishing a nationwide distribution and storage system, this
fuel is not considered a primary candidate for large-scale automotive use.
Rather, it may find application to commercial fleet operations.
S. 2. 5 Ethanol
Ethanol or ethyl alcohol has been produced over the centuries
by fermentation of various carbohydrates (sugars) and is now mainly manu-
factured synthetically for industrial use from petroleum-derived ethylene.
The principal industrial uses of ethanol are (a) as a chemical intermediate,
(b) as a solvent, (c) as an antifreeze, and (d) in fine chemical manufactures
such as drugs, polishes, perfumes, and cosmetics. It is mainly known by
virtue of its use in alcoholic beverages as the principal product of fermenta-
tion. Most of the ethyl alcohol production outside the United States is
accomplished by the fermentation process. Fermentation alcohol production
is affected by very complex cost economics involving domestic availability
and stability in the price of ethylene versus the widely fluctuating availability
of agricultural raw materials around the world.
Ethanol has been demonstrated to be compatible as a motor
fuel with present vehicles. In many parts of the world, it has been blended
in concentrations varying between 10 and 20 percent to alleviate gasoline short-
ages. Like methanol, it has not proved to be economical for such use in the
United States because it has a lower calorific value per unit weight or volume
than gasoline while being more costly than domestic gasoline.
Studies over the years have demonstrated that the use of
alcohol as an automotive fuel reduces fuel mileage essentially in proportion
to the reduction in lower heating values of the fuels. For pure ethanol, this
corresponds approximately to a 60 percent increase in fuel consumption.
Experiments with single-cylinder engines and multicylinder-engine-powered
S-15
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vehicles generally have tended to verify this; however, comparison of relative
fuel consumption levels is influenced to some degree by the type of engine
used and the duty cycle. The most favorable test data for ethanol-gasoline
blends indicate fuel economy about equal to that of gasoline on a Btu per mile
basis.
While some data are available concerning the exhaust pollution
effects of ethanol, the literature is far from comprehensive. Some recent
efforts have dealt with ethanol-gasoline blends of approximately 25 percent
by volume. The results in single-cylinder test engines compared on the basis
of equivalence ratios* show that the emissions are controlled by the primary
fuel constituent (gasoline) in the blend and are essentially the same as for
gasoline alone.
The rationale of using ethanol as an antiknock replacement for
tetraethyl lead is not convincing, since there are other compounds, for example, ,
methanol, that are cheaper and at least as efficient; pure ethanol or blends
with gasoline have essentially the same usage problems cited for methanol.
Ethanol is not highly toxic. If inhaled for continuous periods
under poor ventilation conditions, discomfort occurs such as coughing, eye
irritation, headache, and related symptoms.
Although ethanol is being produced in large quantities, pro-
jected availability is not expected to improve in the near term to the level
required to support its use as a motor fuel. The economics of ethanol pro-
duction and poor fuel economy are major factors tending to limit its use.
New methods are needed to enable low-cost synthesis of ethanol on a very
large production scale. Otherwise, it will not be competitive with other
prospective automotive fuels.
(fuel-air ratio) , .
___ actual
(fuel-air ratio) . . , . , .
stoichiometric
S-16
-------
S. 2. 6 Hydrogen
The United States space program has created a large demand
for hydrogen as a primary rocket engine fuel for combustion principally with
oxygen, but its main use in this country is in the production of ammonia.
Hydrogen can be produced from all fossil hydrocarbons including natural gas,
oil refinery gas, liquid petroleum, natural gasoline, naphtha, fuel oil, crude
oil, coal, and coke. Hydrogen is currently produced primarily from hydro-
carbons, using steam reforming or partial oxidation processes. It is also
produced commercially from water electrolysis. Although the supply of
hydrogen from water is virtually inexhaustible, facilities for mass production
are not yet available and will be dependent on a greater availability of nuclear
power sources.
Under combustion with oxygen in an automotive power plant,
hydrogen offers the complete elimination of hydrocarbons, carbon monoxide,
and oxides of nitrogen. However, oxygen would have to be stored on-board
the vehicle. By contrast, with air combustion oxides of nitrogen, emissions
are expected. The level of emission is highly dependent on the combustion
temperature because oxides of nitrogen emissions increase •with increases in
temperature. Low combustion temperatures (and lower oxide of nitrogen
emissions) are achievable by using lean fuel mixtures.
Experimental work using modified gasoline engines fueled with
hydrogen-air mixtures have shown good fuel economy. On a Btu per pound
basis, hydrogen-fueled cars can have a comparable fuel economy to cars
operating on conventional fuels. There is, however, a concomitant loss of
maximum power.
In regard to toxicity effects, gaseous hydrogen acts as a
simple asphyxiant.
Because its flammability limits when mixed with air are very
wide and its ignition energy is very small, a hydrogen fire is easier to create
than a gasoline fire. An unconfined mixture of hydrogen and air will burn
S-17
-------
but not detonate if it is exposed to a limited ignition source such as a spark.
Explosion can occur in confined areas or when ignition is accomplished by a
shock source equivalent to a blasting cap or a small explosive charge. The
required safety precautions for handling hydrogen are, therefore, more
stringent than those required for conventional fuels.
Furthermore, because the storage temperature of liquid
hydrogen is below -423°F, there are significant and unique hazards. This
temperature is low enough to liquefy all other gases except helium. Any
part of the hydrogen tank or transfer line that becomes cooled to this tempera-
ture level and is exposed to air will liquefy the air. Because of the difference
in boiling points between oxygen and hydrogen, the resulting liquid will
become enriched in oxygen buildup with a consequent dangerous fire hazard.
Although hydrogen appears to be highly suitable as a fuel for
automobiles, a major technical drawback is the problem of on-board storage.
Four methods of storage on-board a transportation vehicle can be considered:
(a) as a pressurized gas at ambient temperature, (b) as a cryogenic liquid at
-423 F, (c) as a metal hydride, and (d) in a chemical compound such as
ammonia. As a compressed gas, 40 standard cylinders would be required
to provide reasonable driving range. Clearly, compressed gas is not
feasible even with lightweight cylinders. In liquid form, the tank capacity
required is more than three and one-half times that required for gasoline on
an equivalent energy (British thermal unit) basis. In addition, the method of
tank insulation and fabrication is complex and could prove to be expensive.
In the case of a metal hydride, it can be decomposed on the vehicle by the
addition of heat to provide hydrogen and it can be replenished at filling stations
supplying hydrogen gas. Research work is under way to develop this process
and reduce the excess system weight, but it is too early to assess ultimate
feasibility at this time. (Storage as ammonia is discussed in the next section).
On an equivalent energy basis, liquid hydrogen cost to the
consumer is estimated to be much greater than the cost of gasoline or distillate
from coal. Much of this cost is attributable to significant cost items connected
S-18
-------
with the liquefaction of hydrogen and its subsequent transportation to, and
storage at, retail outlets. Hence, a major obstacle to using hydrogen as a
universal fuel is one of economics. Extensive and long-range programs may
possibly lead to a narrowing of the gap between the cost of hydrogen and the
cost of fossil fuel.
Furthermore, capital investment requirements are quite large.
Recent estimates of capital costs for large-size production plants (2500 ton-
per-day capacity) indicated a coal conversion plant cost of $1.2 billion and a
nuclear-powered water electrolysis plant cost of $2.7 billion. The lower
value is approximately 60 percent higher than plant investment for coal-
produced gasoline (on equal British thermal units per day basis).
Techni .ally, it is not difficult to make hydrogen from coal, but
it is an inefficient means of using coal energy. A more practical, though more
costly, means of producing hydrogen is by application of nuclear energy to
dissociate water. Unfortunately, delays in current implementation of this
form of energy have led to predictions of reduced future availability. Using
optimistic assumptions regarding this availability for production of hydrogen
fuel, it is estimated that no more than a small percentage (about 9%) of auto-
motive fuel demands could be met even by the year 2000. Even if nuclear
energy could somehow be made available to a greater degree at earlier dates,
the massive capital requirements for hydrogen manufacturing plants and distri-
bution facilities, and the extensive period needed for actual construction
activities, preclude any earlier consideration of this fuel as a major contributor
to passenger car needs.
A greater benefit may be derived from application of nuclear
energy and nuclear-derived hydrogen to (a) release of petroleum fuels from
power-gene rating stations (thereby making them available for automotive use)
and (b) providing hydrogen for coal conversion processes such as in the manu-
facture of synthetic gasoline and distillate hydrocarbon fuels.
S-19
-------
S. 2. 7 Ammonia
The interest in ammonia as an engine fuel stems from the
consideration that it allows the storage of hydrogen in nitrogen hydride form
at a relatively low pressure (250 psig) when at ambient temperature, without
some of the fire and explosion hazards associated with pure hydrogen. Addi-
tionally, the products of combustion will contain neither carbon monoxide nor
unburned hydrocarbons; oxides of nitrogen, however, will be present.
Basically, ammonia is produced by catalytic synthesis from
hydrogen and nitrogen. Practically all current production of ammonia is
from natural gas or petroleum-derivative sources. The nonpetroleum or
natural gas derivative chemical feed stocks considered most suitable for
ammonia process manufacture via the hydrogen route are coal and oil shale.
Other methods, such as water electrolysis, can also be used to produce
hydrogen.
The net heating value of ammonia is 8000 British thermal units
per pound, compared with a heating value of 19, 000 British thermal units per
pound for gasoline. This indicates that for equal combustion efficiencies and
for equal energy outputs, the weight of ammonia required will be 2. 4 times
the weight of gasoline. Based on this figure, the volume of ammonia would
be about 2. 8 times that for gasoline. Because it requires approximately
this much more ammonia by volume on the average to drive equivalent miles
using conventional engines, the consumer costs of ammonia would be several
times that of current gasoline.
The possibility of the presence of unburned ammonia in exhaust
emissions raises the concern that these ammonia gases maybe discharged
directly to the atmosphere and prove harmful to health. The physiological
effects of ammonia are directly traceable to its ability to produce local
S-20
-------
severe irritation of tissues. It is extremely irritating and highly corrosive
to the eyes and respiratory tract. Suffocation and death from pulmonary
edema can result from exposure to high concentrations. Hence, the fuel
transfer system in the vehicle will have to be a closed and pressurized system.
To produce sufficient ammonia for complete replacement of
gasoline as an automotive fuel, and if ammonia were produced by conventional
processes from naphtha or natural gas, industry would have to make a capital
investment of approximately $54 billion. However, because naphtha and
natural gas are in short supply, ammonia will more likely have to be made
by coal gasification or water electrolysis. The capital costs for producing
ammonia from coal would exceed the $54 billion for ammonia produced from
naphtha, because of the additional capital required for coal gasification plants.
Likewise, if ammonia were produced by water electrolysis, investment costs
would be even greater. In view of the many other problems associated with
ammonia usage, it does not appear to be a promising alternative fuel.
S. 2. 8 Hydrazine
Hydrazine derivatives are used today in the plastic industry,
in the pharmaceutical industry, and predominantly as fuel for rocket propul-
sion. Hydrazine has heretofore not been considered as an automotive fuel,
although it could find application in fuel cells for electric vehicles.
The hazards to health and safety may be an inhibiting factor to
the use of hydrazine as an automobile fuel. Anhydrous or aqueous solutions
of hydrazine are toxic by ingestion, inhalation of vapors, or contact with the
skin. Also, because mild steel is incompatible with hydrazine due to the
presence of oxides, stainless steel must be used for fuel containers and for
transfer piping.
S-21
-------
Anhydrous hydrazine is now being delivered to the U. S. Air
Force under contract at a cost of $1. 23 per pound. It is anticipated that the
cost of hydrazine may be lowered to $0. 75 per pound in large tonnage produc-
tion. These costs are an order of magnitude higher than those for gasoline-
powered automobiles, when compared on a utilization-per-mile basis.
Capital costs for hydrazine production facilities would be
certainly higher than costs for hydrogen or ammonia plants because these
liquids are mainly feedstocks for the formulation of hydrazine. The many
deficiencies of hydrazine as a potential automotive fuel lead to the conclusion
that it is unsuitable as an alternative to petroleum-based fuels.
S. 2. 9 Fuels Reformed Qn-board the Vehicles
Operation of a spark ignition internal combustion engine at
lean air-fuel ratios (greater than 15 to 1) can result in the reduction of exhaust
emissions without the addition of emission control devices. Currently, gaso-
line engines are normally operated at air fuel ratios below approximately 17
to avoid rough engine operation.
One approach that is being investigated as a means of extending
the lean operating limits of gasoline engines in order to achieve low exhaust
emissions is the incorporation of a fuel reformer device between the gasoline
tank and the carburetor of the gasoline engine-powered conventional automobile.
The fuel reformer device converts all or a portion of the engine's fuel require-
ments from gasoline (or other liquid hydrocarbon fuel) to a gaseous combustible
product (principally hydrogen) prior to induction into the engine. It should be
noted that such lean operation causes reduced engine power that would necessi-
tate the use of a larger displacement engine for the same maximum power output.
In general, reformed fuels may be processed from a variety of
liquid hydrocarbon fuels including: gasoline, kerosene, jet fuel, diesel fuel,
home heating oil, heptane, hexane, and liquid petroleum gas. Specific reformer
devices or systems, however, may be designed to operate on a single grade
S-22
-------
of hydrocarbon fuel or a more limited range of hydrocarbon fuel choices.
Thus, reformed fuels are in turn limited by the reserves and/or raw material
sources for conventional petroleum or nonpetroleum hydrocarbon liquids.
Improved fuel economy for vehicles operated with reformed
fuels has been postulated to result from (a) higher engine thermal efficiencies
as a result of lean operation, and (b) reduced throttling losses at part-load
conditions by using fuel throttling control instead of air or intake charge
throttling; this latter approach is rendered feasible because of the combusti-
bility of hydrogen-air mixtures over the wide range of air-fuel ratios that
would be encountered during unthrottled part-load engine operation.
Engine-indicated thermal efficiencies were measured by
General Motors for a single-cylinder engine operating on hydrogen-
supplemented gasoline. The indicated thermal efficiency increased from
33 percent to about 37 percent. Similar trends were observed by the Jet
Propulsion Laboratory in tests of a single-cylinder CFR engine and a 350 cubic-
inch-displacement V-8 engine. But substantive fuel economy data from
vehicle tests are currently not available.
A prototype model of the International Materials Corporation
reformer was tested in simulated vehicle operation. This system, which con-
verts all of the engines fuel requirements, demonstrated exhaust emissions
in grams per mile of 0. 412 to 2. 78 for CO, 0. 012 to 0. 15 for HC, and 0. 040 to
0. 37 for NO . However, reformers of this type (i. e. , reform all of the engine
jt
fuel requirements) are typically large in volume and pose difficult vehicle
packaging problems. In addition, reformer inefficiencies are applied to all
of the gasoline used by the vehicle and may result in reduced fuel economy.
The Jet Propulsion Laboratory recently conducted comparison
tests of a 1973 Chevrolet Impala on the 1975 Federal Test Procedure. The
first set of tests were run with gasoline only and the second set of tests were
run with hydrogen-supplemented gasoline to partially simulate expected supply
S-23
-------
of hydrogen that would eventually be provided by an on-board reformer
converting a portion of the engines fuel requirements. (The reformer has been
undergoing development in laboratory tests. ) The hydrogen was supplied from
hydrogen gas bottles located in the trunk of the car. The reduction in CO and
NO emissions was marked, but HC emissions were high.
J\,
Similar to the Jet Propulsion Laboratory test configuration,
in-the-engine control of NO was also verified by General Motors in one
Ji
experimental vehicle with hydrogen-supplemented gasoline; the hydrogen was
supplied by gas bottles in the trunk of the car. These exhaust emissions tests
were conducted on the cold start 1975 Federal Test Procedure at 3500 pounds
inertia weight. NO and CO emissions satisfied the 0. 4 and 3. 4 gram-per-
5C
mile original 1976 Federal standards, respectively. However, the HC
emission was nearly an order of magnitude higher than the 0. 41 gram-per-
mile limit.
All the foregoing tests were exploratory and they may not
reflect the ultimate system potential for engines operated on reformed fuel,
nor the case of gasoline supplemented by either hydrogen or reformed fuel.
All the liquid hydrocarbon fuels which are potential candidates
for use with fuel reformers are in commercial use today, with contemporary
handling, storage, and distribution systems. This fact enhances the potential
for use of reformed fuel systems since no new handling, storage, or distri-
bution systems would be required.
Fuel reformer concepts are still in the exploratory, proof-of -
principle, or feasibility determination stage. A number of critical data gaps
must be filled before the potential of reformed fuels can be fully assessed.
NASA has been funding the Jet Propulsion Laboratory to acquire data and
prove concept feasibility, and EPA is providing supplemental funding for this
work in addition to other contractor-supported programs for evaluation of
similar concepts.
S-24
-------
S.3 COMPARATIVE REVIEW OF ALTERNATIVE FUELS
The foregoing summary of each alternative fuel is now presented
on a relative basis in succeeding paragraphs.
A comparison of physical characteristics for the alternative
fuels being considered is given in Table S-l. The various processes associated
with manufacture of these fuels are summarized in Table S-2 and are dis-
cussed briefly below.
The production of synthetic gasoline and distillate hydrocarbon
fuels obtained from coal or oil shale is now in the pilot plant stage of process
development and it would probably be close to 1985 before any appreciable
quantities could be made available to the transportation sector. By then,
approximately 3-billion gallons per year of liquid petroleum from coal and
14-billion gallons per year from oil shale can be made available. Production
rate •will be paced by available investment funds and the mining rates for coal
and oil shale.
The manufacturing processes for methanol and ethanol from
petroleum are well established, but, in the derivation from coal of synthetic
gas and ethylene, the production processes require further development. Con-
sidering this fact, the availability of these fuels for the transportation sector
would be similar to that of synthetic gasoline and they could be a viable con-
tributor to energy needs in the far-term period (1985-2000).
Methane in the form of compressed natural gas or liquid natural
gas processed from coal is in the development stage, but significant quantities
will not be available before 1985 (1.1 trillion cubic feet per year equivalent in
Btu to 10-billion gallons of gasoline). Thereafter- availability is projected
to approximately 8. 5 trillion cubic feet per year in the year 2000.
With regard to propane and butane, the discussions pertaining
to methanol and ethanol would apply in this case.
Hydrogen gas is produced either by partial oxidation of hydro-
carbons or electrolysis of water. Other processes are under development.
S-25
-------
Table S-l. Comparative Physical Characteristics of JUternative
Nonpetroleum-Based Automotive Fuels
a, o
in
i
IS)
Fuel
Gasoline
Distillate
( Include*)
naphtha
through
fuel oil)
Methanol
(CHjOH)
Kthanol
(C2 H5 OH)
Methane
(CH4)
Propane
(CjHB)
! lydrogen
(H2)
Ammonia
(NH3}
Hydrazine
(N2H4)
Heat of Combustion
(Lower)
Btu/lb
16,650
It, 400
8,640
11, 550
21, 500
19, 940
51,600
8,000
7, Z90
D. P. Gregory and R. B. Roaenber
Hydrogen and Synthetic Fuels, Atom
Heat of Vaporization
at Normal
Boiling Point
Btu/lb
150
110
474
360
219
183
194
591
540
Normal Boihnf
Point
Op
100 - 400
375 - 620
14':'
173
-259
-48. 1
-423
-28
236
Vapor Pressure
at 100°F
Psia
8-12
0.01
4.6
2.4
Above
crit. temp.
189
Above
crit. temp.
212
0.57
Density
Liquid Gas, STP
Ib/ft' Ib/ft3
4b.O NA
52.6 NA
4«.7 NA
4'(.3 NA
27.9 0.045
31.8 0.11%
4.43 0.0056
38. 0 (70°F) 0.0433
62.4 NA
Freetinn
Point
"F
c-40
-40 to +5
-142
-179
-296
-309.8
-435
-108
35.6
j, "Synthetic Fuels for Transportation and National Energy Needs", SAE Paper No. 730520 (19731
ic Energy Commission, Report No. UC-80(September 1972)
-------
Table S-2. Production Processes for Alternative Nonpetroleum-Based
Automotive Fuels
en
Fuel
Gasoline /Distillate
Methanol
Ethanol
Methane
Propane
Hydrogen
Ammonia
Hydrazine
Process Alternatives
1. Coal liquefaction
2. Coal gasification— --synthesis gas
gasoline via Fischer-Tropsch
process
3. Oil-shale extraction
Coal gasification -•-synthesis gas (carbon
monoxide and hydrogen) in presence of catalyst
Fermentation of agricultural products
( sugar, starch, cellulose)
Coal gasification— ^-synthesis gas (carbon
monoxide plus hydrogen)-*catalytic
methanatlon
By-product in coal gasification or liquefaction
1. Water electrolysis
2. Coal gasification— ^synthesis gas (carbon
monoxide plus hydrogen}— »shift converter—*
carbon' dioxide scrubber
3 . Thermochemical
Hydrogen plus nitrogen in presence of
catalyst
1. Raschig process
Z. Urea process
Development Status
1. Pilot plant
2. Commercial production
in South Africa.
Inefficient, costly.
3. Ready for commercial
plant
Commercial production
demonstrated
Commercial production
Commercial production
with methanation step now
being demonstrated.
Same as coal liquefaction
and/or gasification
1. Commercial production
2. Pilot plant
3. Laboratory
Commercial production
with H-, from natural gas
1, Commercial production
2. Commercial production
Technology Needs
1. Catalyst, material handling,
hardware development
2. Make more selective, handle
caking coals
3. Disposal of spent shale and
water; deep mining techniques
Gasification process improvement
too expensive. Need new rapid
fermentation process.
improvement.
Develop efficient byproduct
P g
1. Improve cell efficiency
2. Efficient carbon dioxide
removal, gasification process
improvements
3 . Simple, energy-efficient
chemical steps. Avoid corro-
sive, unstable materials
Same as for hydrogen above
New, cheaper process required.
Thermodynamics limit possible
savings .
Data are primarily from F. H. Kant, et al. , Feaaibility Study of Alternative Fuels for Automotive Transportation {in three
volumes), EPA-460/3-74-009-4-a, Exxon Research" and Engineering Company (June 1974).
-------
A ton of coal can yield only a certain amount of liquid petroleum products and
a certain amount of hydrocarbon gases with residual char and by-products.
Any amount of hydrogen shiphoned off this process will reduce the amount of
either liquid petroleum or gas produced. With that understanding, the avail-
ability of hydrogen is also regulated by the coal processing rate and the demand
for alternative synthetic fuels. Hydrogen availability could increase in the far
term period when breeder reactors could be used for the production of elec-
tricity needed for the water electrolysis process. But production rates are
not likely to be significant to the transportation sector before the year 2000.
Ammonia and hydrazine processes are defined, and the com-
ments regarding future availability are similar to those for hydrogen.
A variety of parameters determining the suitability of alterna-
tive fuels for automotive application are summarized in Table S-3. A sum-
mary of the highlights for each fuel considered is presented in Table S-4.
The succeeding discussion elaborates on the information given in these tables.
From the fuel costs at the pump (excluding tax) given in
Table S-3, it can be seen that synthetic gasoline and distillate hydrocarbons
manufactured from shale are potentially the least expensive alternative fuels.
These same synthetic fuels made from coal are also favorable from an eco-
nomic standpoint, particularly if petroleum product prices continue to rise.
Next in order for favorable consideration would be methanol. (Methanol-
gasoline blends would be even more attractive price-wise. ) Fuels such as
hydrogen, ethanol, ammonia, and hydrazine are poor economic contenders.
The costs shown in Table S-3 are for the post 1985 period but
are given in 1973 dollars. These estimates, of course, are highly dependent
on a host of complex interacting factors such as: (a) environmental control
during mining or conversion processes, (b) manufacturing scale of operations,
(c) rate of progress in improving process efficiencies, (d) the type of manu-
facturing process, (e) capital investment requirements and allowable rate of
equipment depreciation, (f) logistics of distribution and storage. Costs for
S-28
-------
Table S-3. Logistic Factors for Use of Alternative
Nonpetroleum-Based Automotive Fuels
Fuel
Gasoline^
Distillateb
Liquid
Hydrogen
Ammonia
Hydrazine
Methanol
Ethanol
Methane
Propane
Est. Cost at Pump in 1973
Dollars (Taxes Excluded)
$/106 Btu*
3. 15 (from coal)
2. 60 (from shale)
2. 50 (from coal)
2.00 (from shale)
7. 00 (from nuclear electrolysis)
4, 70 (from coal)
7. 65 (using hydrogen from
electrolysis)
Over 20
3. 40 (from coal)
7. 80 (from organic waste)
3; 80
Greater than 3. 80 (from coal
liquefaction)
Vehicle
Storage
Excellent
Excellent
Poor
Fair
Good
Good
Good
Poor
Fair
Toxicity
Medium
Low
Low
High
High
Medium
Low
Low
Low
Safety
High fire hazard
Low fire hazard
High fire and
explosion hazard
Moderate fire
hazard
High fire and
explosion hazard
Moderate fire
hazard
Moderate fire
hazard
High fire and
explosion hazard
Moderate fire
hazard
Compatability
with Petro-
leum Fuels
High
Low
Low
Low
High if water
contamination
controlled
High if water
contamination
controlled
Low
Low
Status of Distribution to Consumer
Existing
Existing
Major development and investment required
Some experience in farm distribution. Major
expansion required with emphasis on safety
Major modifications to existing gasoline system
in areas of materials compatibility and safety
Existing gasoline system could be used with
modifications to prevent water contamination
and corrosion
Same as Methanol
About the same problem as for Hydrogen
Limited availability at present.
Requires extension
a#/10 Btu - Dollars per million British thermal units for the post- 1985 period. Data are primarily from F. H. Kant, et ai. , Feasibility Study of Alternative
Fuels for Automotive Transportation (in three volumes), EPA-460/3-74-009-4-a, Exxon Research and Engineering Company (June i9?4).
Currently at the pump, gasoline from petroleum at 38^ per gallon is equivalent to S3. 35/10 Btu and distillate from petroleum at 37^ per gallon is equivalent
to $2. 80/10 Btu (taxes excluded).
en
i
Cs)
xD
-------
Table S-4. Summary of Availability and Suitability of Alternative
Nonpetroleum-Based Automotive Fuels
00
o
Fuels
Synthetic gas-
oline and dis-
tillate
hydrocarbon
Methanol,
JL'thanol
Methane
(CNG or LNG)
Propane,
Butane (LPG)
Hydrogen
Ammonia,
Hydrazine
Reformed
fuels
Present Energy
Source
Liquid
petroleum
Natural gas,
liquid hydro-
carbons
Natural gas
Natural gas,
liquid hydro-
carbons
Petroleum,
gas, coal,
water (by
electrolysis)
Same as
hydrogen
Liquid hydro-
carbons
Future Energy
Source
Coal, oil
shale
Coal, possibly
solid waste-
Coal, possibly
solid waste
Coal
Coal, nuclear
(electrolysis)
Same as
hydrogen
Coal, oil
shale
Fuel Available
in Limited
Quantity
(Near-Term
Energy Source)
Pre-1985
Pre-1985
Pre-1985
Pre-1985
Post-1985
Post-1985
Post-1985
Fuel Available
in Significant
Quantity
(Future Energy
Source)
Post-1985
Post-1985
Post-1985
Post-1985
Post-2000
Post- 2000
Post-1985
Future
Suitability for
Automotive
Use
Excellent
Good,
Fair
Fair
Fair
Fair to
poor
Poor
Fair
Research Gaps
in Engine
Application
More engine
data
More engine
data
More engine
data. Resolve
storability
problem
More engine
data
More engine
data. Resolve
e torability
problem
Not worth
pursuing
More engine
data. Devel-
opment of fuel
reforming
Factors
Inhibiting
Fuel Use
Major factors
identified
Cost, per-
formance,
compatibility
factors
On-board
storage, dis-
tribution
network
More expen-
sive than
synthetic
gasoline and
similar fuels
On-board
storage, dis-
tribution
network, safety
Toxicity,
safety, cost
Cost and
complexity
Possible application when mixed with CNG = compressed natural gas
gasoline (methanol blend). LNG = liquid natural gas
LPG = liquid petroleum gas
-------
later periods are expected to decline as process refinements and operational
experience are applied to new, and larger, facilities. On the other hand,
fuel costs may increase due to the increased cost of extracting raw materials
from the ground.
An estimate of the possible production implementation for
several alternative fuels is presented in Table S-4 for both near-term and
far-term periods. As can be seen, gasoline and distillate hydrocarbon fuels
derived synthetically from coal or shale rank highest in terms of probable
implementation and timeliness in response to meeting current fuel shortages;
this is particularly true of shale-derived fuels. The primary reasons for
this ranking are (a) similarity of these fuels to current products in use, (b)
the ready availability and extensive domestic reserves of coal and shale, and
(c) a recognized acceptable technology for converting coal and shale to
syncrude.
Methanol has been run satisfactorily in spark ignition engines.
Its low heating value (in Btu per pound), as compared to gasoline, results in
over twice the fuel consumption when expressed in miles per gallon. However,
the cost per Btu is approximately equal to that of gasoline. From a desir-
ability standpoint, it should be noted that the emissions of NO with methanol
are lower than those with gasoline. Mixes of methanol with gasoline can also
be considered. However, there are two major factors which mitigate against
methanol-gasoline blends at present: water absorption susceptibility (leading
to phase separation and corrosion of containers) and high volatility (leading
to vapor lock).
Ethanol has shown performance similar to gasoline in the spark
ignition engine but its cost is higher than that of methanol. Consequently, its
future application to automotive engines is doubtful.
Methane, when used in automotive engines, gives performance
equal to or better than gasoline with a reduction in all primary exhaust emis-
sions. But the problem of storage on board the vehicle and the need for a
distribution network are factors inhibiting its use.
S-31
-------
Propane and butane (liquified petroleum gas) have been used
successfully in automotive engines and some reductions in exhaust emissions
were noted. The lower heating values of liquified petroleum gas and the lower
density result in higher fuel consumption reflected in reduced miles per gal-
lon when compared to gasoline. However, on an equivalent energy basis, it
is more expensive than gasoline. Distribution of liquified petroleum gas is
at present limited and storage on-board the vehicle is more complicated than
that of gasoline, requiring pressurized tanks to keep the fuel in liquid phase.
Hydrogen fuel can burn with air in an automotive engine at very
lean air-fuel ratios with fuel economy comparable to that of gasoline (when
expressed in miles/Btu). Exhaust emissions are low and theoretically there
should be no carbon monoxide or hydrocarbons present (except that produced
in burning of lubricating oil); oxides of nitrogen levels are substantially lower
than those for gasoline engines. Costs are quite high when compared with
other fuels, and a means of safe, efficient distribution to the consumer is a
major problem to be resolved. Another problem is that hydrogen density is
low even in the cryogenic phase (1/12 that of gasoline) and this creates a
problem in storability (large volume containment) aboard the vehicle. This
problem might be alleviated by the use of solid metal hydrides that are under
development by the Federal government and commercial interests, but weight
reduction is needed for assurance of a practical system.
Compared to gasoline ammonia has a low heating value (fuel
consumption is over twice that obtained with gasoline) and NOX emissions are
higher. Storage of ammonia on-board the vehicle requires pressurized tanks.
Production costs are much higher than synthetic gasoline and distillate fuels.
Like ammonia, hydrazine has a low heating value. No data are
available for its use with automotive engines. This fuel is not considered as
a serious contender for automotive application because of high cost, toxicity,
and potential explosive hazard during transportation. An alternative use of
hydrazine in the far-term period could be for fuel cells. But costs are pro-
hibitively high when compared with other alternative fuels.
S-32
-------
Fuels reformed on-board the vehicle are generated by thermal
decomposition of hydrocarbons and consist primarily of hydrogen and carbon
monoxide. Such gas generator systems are now under development to permit
engine operation at lean air-fuel ratios with anticipated improvements in fuel
economy and exhaust emissions compared to operation with gasoline.
Of importance is the adaptability of various types of fuels
to the personal passenger car in a form which can find wide public accep-
tance. One criterion for ranking fuels is the relative weight and/or volume
required for storage in the vehicle. To retain acceptable vehicle seat-
ing arrangements and safe handling characteristics, practical fuel storage
designs should come reasonably close to the type of packaging that has evolved
through use of the current petroleum-derived fuels. A comparison of the
tankage requirements for several fuels is presented in Table S-5. Some fuels
come reasonably close to the weight and volume for gasoline, but nonetheless
are still overweight and oversize by factors of 2 to 3.
Research needs for alternative fuels constitute (a) refinement
of processes for the manufacture of automotive fuels from coal and shale,
(b) further evaluation of on-board vehicle reformed fuel processes, (c) evalua-
tion of the most promising alternative fuels for various alternative engines,
and (d) defining the safety, handling, and storage regulations of those fuels
with physical characteristics markedly different from gasoline.
The choice of a given fuel for automotive use will be, in part,
a function of alternative fuel availability discussed before. It will also depend
on the time and funding allocated to close the general research gaps enumer-
ated above, and to resolve the specific problems connected with application
of these fuels to automotive power plants.
S-33
-------
Table S-5. Comparison of Tankage Requirements for Alternative
Nonpetroleum-Based Automotive Fuels
Basis: Energy Equivalent of 20 gallons of gasolinea
(2. 27 X 106 British thermal units)
Fuel
Gasoline"
No. 2 Diesel fuelc
Hydrogen (gas) at 3000 psi,
80°F
Hydrogen (liquid) at one
atmosphere
Hydrogen as magnesium
hydrided
Methane (gas) at 3000 psi,
80°F
Methane (liquid) at one
atmosphere
Ammonia (liquid) at 80°F
Hydrazine
Methanol
Ethanol
Propane (liquid) at 250 psi
Fuel Alone
Weight,
Ib
119
120
43.9
43.9
577
105.5
105.5
284
338
261
195
106
Volume,
ft3
2.59
2. 28
40. 6
10. 18
6.6
12.40
4. 06
7. 16
5.40
5. 26
3.95
3.34
Fuel and Container
Weight,
Ib
134
134
1330
392
750
500
240
455
367
285
214
220
Volume,
ft3
2.76
2.50
89.2
15.2
9e
14.6
6. 1
7.5
6.05
5.70
4.78
4.6
aOn an equal mileage basis (say 270 miles) the fuel storage requirements
must be adjusted for the thermal efficiency of the vehicle. In the case
of dies el power the above figures would be reduced by one-third.
bThis assumed to apply to all gasoline whether from petroleum, coal, or
shale.
cThis assumed to apply to all distillate fuels whether from petroleum,
coal, or shale.
^Assumes theoretical yield of hydrogen, density of magnesium hydride
is 1.4 grams per milliliter.
eDoes not include means for heat exchange and ancillary equipment to
charge and discharge magnesium hydride.
Ib = pounds ft = cubic feet psi = pounds per square inch
S-34
-------
SECTION 1
-------
SECTION 1
INTRODUCTION
The objective of this volume of the report is to review the
current status of alternative (to petroleum-based gasoline) fuels for use in
automotive engines. The need for such a review received additional emphasis
from a series of well-publicized events occurring near the end of calendar
year 1973. These events brought sharply into focus the worldwide fossil
fuel shortage and the curtailment in U.S. imports of petroleum products.
Of necessity, this report utilizes predictions in energy demand
(consumption) and supply growth which are based on a previously observed
and extrapolated trend. Such predictions are illustrated in Figure 1-1, which
shows an almost constant rate of growth in U.S. energy consumption until the
year 2000. It was based on a 1 percent per year population growth and an
annual GNP growth of 4. 3 percent until 1980 (4 percent thereafter). These
predictions are now in the process of major revision in view of the declared
Federal government goal to attain U.S. self-sufficiency in domestic energy
supply to meet future demands.
The transportation sector,which is almost entirely dependent
now on liquid petroleum products, will be profoundly affected by the U. S. energy
self-sufficiency goal. The transportation energy demand in the future may be
substantially lower than that predicted by various sources quoted in this report.
Such a reduction in demand will not be a simple task to implement and will
require major readjustment in energy use in the transportation sector as well
as in other sectors utilizing petroleum products. For example, the import of
petroleum in 1973 rose to 35 percent of the total U.S. petroleum demand,
exceeding previous predictions, and it would probably be in the 50 percent level
in 1985 if the demand growth is permitted to continue. This important forecast
is shown in Figure 1-2, which illustrates the widening gap between domestic
1-1
-------
200
190
180
170
160
^ 150
CD 140
| 130
i 120
8
°" 110
•>
9 100
90
80
70
Q.
2
V)
O
U
O
oz
u
z
UJ
60
50
40
30
20
10
0
1970
HOUSEHOLD&COMMERCIAL
cvMTHETIC GAS
1980
1990
2000
YEAR
Figure 1-1. U.S. Energy Consumption by Sector (Ref. 1-1)
1-2
-------
SUPPLEMENTAL SUPPLY:
imports, shale oil, coal liq.
DOMESTIC SUPPLY: lower 48 & Alaskan crude
natural gas liquids
1980
1990
2000
YEAR
Figure 1-2. Petroleum Consumption/Supply Forecast (Ref. 1-1)
1-3
-------
supply and U.S. demand. A similar situation exists with respect to gaseous
fuels (see Figure 1-3), although the main demand for this fuel is not in the
transportation but in the residential, industrial, and electrical sectors. It
becomes clear, therefore, that a drastic reversal in the prior trends is neces-
sary to meet the President's declared national goal of energy self-sufficiency
in the 1980s.
With this in mind, the reader is advised to view the fuel supply
and demand predictions quoted in this report with caution, realizing that
dramatic changes are taking place in the energy picture. On the other hand,
the changing energy situation will not substantially affect the state of the art,
the performance characteristics, or the availability in their natural state of
alternative fuels, and these can be used as a base for future predictions.
A pictorial guide is presented in Figure 1-4 for helping the
reader progress through this alternative fuels volume. A brief review of
energy sources in Section 2 defines, in general, the energy base of each of
the alternative fuels. Then the status of the production process development
of each fuel is briefly described in succeeding sections of the report. This is
*
accompanied by a review of the expected near-term (1975 to 1985) and far-
term (1985 to 2000) availability of the fuel, including information on the cur-
rent and projected production rates and consumer costs. A principal data
source used was the two EPA/AAPS-funded studies (with the Institute of Gas
Technology and Exxon Research and Engineering Company) related to the
assessment of alternative automobile fuels.
Addressed next is a review of the applicability of a given
alternative fuel to automotive engines. This includes evaluation of: (1) com-
patibility with various engine cycles, (2) fuel economy, (3) emission charac-
teristics, (4) toxicity, (5) distribution, (6) storage, (7) safety, and (8) con-
sideration of those factors inhibiting production and market introduction.
From this review, research and development needs are identified, and the
projected status of alternative fuels for transportation use in both the near-
term and far-term periods is presented.
Exxon and IGT designations were near term (1975-1985), mid-term (1985-
2000), and far term (beyond 2000).
1-4
-------
16
IMPORTS: pipeline CNG
and LNG
DOMESTIC SUP> PLY: L0WER"48 AlsiD XLAScTtlG'
,wvv SYNTHETIC GAS
TRANSPORTATION
YEAR
2000
Figure 1-3. Gaseous Fuel Con sumption/Supply mcrease (JRef K
1-5
-------
STATUS OF
ALTERNATIVE
FUELS PROCESS
ING
ENGINE/FUEL
AVAILABILITY
FAR TERM
ENGINE/FUEL
AVAILABILITY
NEAR TERM
Figure 1-4. Alternative Fuels - Guide to Topics of Discussion
-------
SECTION 2
-------
SECTION 2
TRANSPORTATION ENERGY RESOURCE OVERVIEW
In evaluating the viability of alternative (other than liquid
petroleum-based) fuels for meeting automotive transportation needs, it is
pertinent to provide an overview of the current energy picture for the U.S.
and a projection of future energy supply and demand. It is the purpose of
this section to provide such overview.
Of necessity, this report draws on published information and
projections. It should be recognized, however, that published projections of
the domestic energy future were based on an extrapolation of trends that are
undergoing revision or change in fundamental ways. Hence, it is necessary
that we factor uncertainty into our concepts of the future to a much greater
degree than we have done in the past.
2. 1 ENERGY SUPPLY VERSUS DEMAND
To attain a better insight into the U. S. energy balance (i. e. ,
the comparison of predicted supply versus demand), three cases of supply
(optimistic, inter mediate, and pessimistic) and three cases of demand (low,
intermediate, and high) are shown in Table 2-1. In all cases shown in
Table 2-1, there is a deficiency in the domestic energy supply caused by
increasing demand in energy coupled with the limited utilization of alternative
forms of domestic energy (such as coal) by consumer sectors (industrial,
electrical,and transportation). However, greater energy shortages have
developed since these projections were made, and a number of conservation
measures are already in effect to reduce current demand levels. In addition,
significant increases in energy costs are beginning to impact on demand. The
impacts are both direct and indirect (e.g. , accentuating the demand for small
cars while deflating the demand for large automobiles). The duration and
degree of the current fuel supply limitations are not known; but, even when the
2-1
-------
Table 2-1. U.S. Energy Balance (Refs. 2-1, 2-2)
15
All Units: Btu/Year X 10
\ item
Year N.
1970
1975
1980
1985
2000*
Domestic Supply
Available
Level
Actual
High
Case I
In term.
Case U
Low
Case IV
High
Case I
Interm.
Case U
Low
Case IV
High
Case I
Interm.
Case II
Low
Case IV
Interm.
Amount
59.42
67.00
66.69
61.79
86.42
82.85
63.95
111.49
100.42
77. 59
137.2
Consumer Demand
Level
Actual
Low
Interm.
High
Low
Interm.
High
Low
Inte rm .
High
Interm.
Amount
67.83
80.50
83.48
85.82
95.70
102.58
105. 30
112.50
124.94
130.0
191.9
Deficiency in %
of Domestic
Supply
14.1
20.0
25.0
38.9
10.7
23.8
64.6
9.1
24.4
67.5
28.5
From Ref. 1-1
2-2
-------
limitations are removed, it is possible that a permanent and more modest
pattern of energy consumption will have been established.
The energy deficit shown in Table 2-1 must be made up pri-
marily by import of liquid petroleum and gas. In 1971 this import amounted
to 26 percent for liquid petroleum and 4 percent for gas (expressed as per-
centage of each fuel total supply), but it has been estimated to increase by
1985 to 53.4 percent and 19.3 percent, respectively,and by 2000 to 70.3 per-
cent and 28.2 percent, respectively (Ref. 1-1). The latter two sets of fig-
ures for liquid petroleum include relatively small quantities of liquids
obtained from domestic oil shales or coal liquefaction.
2.2 ENERGY SUPPLY
One estimate of the U.S. energy resource base (Ref. 2-1) is
shown in Table 2-2. According to this reference, coal is the largest single
earth-bound energy source, followed by uranium (with nuclear breeder
reactors) and oil shale. Solar energy requires a technological breakthrough
before it can be used economically on a large scale; nuclear energy, based on
breeder reactors, requires approximately 15 years development. Oil shale
and coal resources require solution of environmental problems but are the
most promising near-term available sources for energy growth. A brief
review of some of these resources follows.
2.2.1 Coal
The domestic coal reserves are shown in Table 2-3. Accord-
ing to the U.S. Geological Survey, this country has 3,210 billion tons, of
which 1, 560 billon tons are mapped and explored at strip mining depths from
0 to 300 feet. Of this amount, approximately 150 billion tons are considered
proven recoverable reserves, consisting of 45 billion tons of surface coal and
105-billion tons of below-surface coal (Ref. 2-2). With regard to sulfur con-
tent, 46 percent of the mapped and explored coal reserves (720 billion tons)
have sulfur content <0. 7 percent, while 93 percent of these low sulfur
reserves are located in states west of the Mississippi River.
2-3
-------
Table 2-2. U.S. Energy Resource Base (Ref. 2-1)
R e s < > u r (. n
r..al
< rtidn Oil
Natural Gas
Natural (ias Liquids
Oil Shal<-
1 ' rnninm:
In burner reactors w/o Pu recycle
In breeder reactors
1 her turn
Hydropower (Annual)
Geothermal (Annual)
la r Sands
Niu-lear Fusion
Solar Energy (Annual)
Tidal Knerpy (Annuall
Wind Power (Annual)
Uln/t'nil
Z^ x lnf'/ton
5. « x I0h/bbl
1032/cf
4. 0 x 106/bbl
^. -4 x lo'Vbbi
400 x 10?/ton
30 x 1012/ton
-
10. 5 x 103/k»-hr
-
5. 4 x 106/bbl
-
ITwatts/ft2
-
,5
-• ~ ~ ( 1 0 Btu \
Assured
1r'. 000
210
27 ^
27
1 Ib
250
IN. 7SO
-
5. 5
4. 0
-
-
49,056
-
5.4
88,946.9-
107,446. 9
Rrasona M v
Assured
41, 200
1. 317
(,72
-
1,517
400
30,000
_
-
4. 0
127
—
-
10. S
45, 247. 5-
74, 847. 5
Sppcu 1 at ivc
1
1. 212
S12
-
7, ''16
_
-
-
-
-
-
—
-
-
-
9, 640
Total
HO, 200
2 . 7 VI
1, 4=.?
,'7
9 "> .) i)
650
48,750
-
S. 5
K. 0
127
-
49, 056
10. 5
5.4
143. 834.9-
1
-------
Table 2-3. Domestic Coal Resources (Refs. 2-2 and 2-3)
Depth of overburden (feet)
0-100 (strip mining)
100 - 3000 (underground
mining)
3000 - 6000 (underground
mining)
8000 - 9000 (underground
mining)
Type of Coal
Sub -bituminous
and lignite
Bituminous
Lignite
Anthracite
All types
All types
TOTAL
Tons x 109
139. 97
959. 29
447. 64
12. 97
337. 10
1313. 10
3210. 10
18
Energy, Btu x 10
3.56
24. 94
11.64
0. 34
8.76
34. 14
83.40
Mapped and
explored -
n
1560 x 10y
tons;
unmapped -
o
1650 x 10y
tons.
Ul
9 9
Location of proven recoverable reserves: 105 x 10 tons underground; 45 x 10 tons surface
(<5% of total estimated).
Sulphur content: 46% of explored (720 x 10 tons) sulphur < 0. 7%; 93% west of Mississippi.
-------
Although coal reserves appear ample, it is also important to
consider the rate at which they could become available to meet demands for
both raw coal itself and derived synthetic fuel. In Reference 2-2, several
cases of supply rates were examined and the most optimistic forecast,
Case I, is shown in Table 2-4. An annual growth rate of 5 percent was
assumed for the domestic market until 1985 and 3. 2 percent in the period
1985 to 2000. The export rate increased annually at a rate of 4. 2 percent
until 1985 and 3.2 percent thereafter. Table 2-4 also shows for comparison
a less optimistic, intermediate supply forecast taken from Reference 1-1
with an average annual growth rate of 4 percent until 1985 and 2. 7 percent
thereafter. Excess of coal supply over domestic demand allows for an annual
export of 9 to 12 percent of the total annual supply through the year 2000.
There is, however, considerable uncertainty concerning
future U. S. coal exports. On the one hand, foreign importers of U. S.
metallurgical £oal are developing technology to reduce the need for coal and
colce" in- «te~e~f making. On the other hand, constraints on the availability of
petroleum to these importers make it possible that U.S. exports o^ steam
coal will increase. The export value of coal and related products is at the
billion dollar level and will increase significantly in the future, thereby
providing a partial offset to the cost of importing other materials.
Considering these factors, it appears reasonable to assume
that the average coal export level will be approximately 10 percent of domes-
tic production. At this level, the exports would not constrain the availability
of coal for the production of synthetic fuels. This inference may be strength-
ened by reasoning that synthetic fuel production will be based primarily on
Western or Midwest coals, whereas coal exports are likely to be primarily
from Eastern mines.
Both optimistic and intermediate coal supply forecasts
(Ref. 2-2) point out problem areas that can influence actual future output.
These considerations include: environmental concern over strip mining and
sulfur dioxide emissions from power plants, availability of capital to open
2-6
-------
Table 2-4. Coal Potential Domestic Supply (Ref 2-2, Case I)
Units - Tons/year x 10
^^^^^ Year
Conventional Market
-d
• u co c
S £•« JS
r^2 3 S
w£ fc »
Gas
Liquids
Exported to Other
Countries
TOTAL SUPPLY
1970
519.0
0
0
71.0
590.0
1975
665
0
0
.92
757
1980
851
48
12
111
1022
1985
1093
232
107
138
1570
2000*
1700
360
166
214
2440
Overall
Growth Rate %
5.0 (3.2)**
-
-
4. 5 (3. 2)
6. 7 (3. 2)
FOR COMPARISON, INTERMEDIATE CASE (Ref. 1-1)
Units - tons/year x 10
TOTAL SUPPLY
568. 8
636
740
980
1418
4.0 (2.7)
* Extrapolated from Ref. 2-2
:«*( ) Refers to growth rate in the period 1985 to 2000
-------
new mines, environmental acceptability of high-sulfur coal, reclamation of
strip mining areas, and possible shortages of trained miners as well as
supervisory and professional personnel.
The environmental problems associated with coal mining and
with construction and operation of coal gasification plants are being investi-
gated in detailed studies to evaluate this problem. The plant effluents con-
sidered necessary to control are noxious gases generated during gasification
processes (such as hydrogen sulfide, sulfur dioxide, and oxides of nitrogen);
combustion and sulfur recovery operations; liquids consisting of processed
waste waters contaminated with phenols, ammonia, oil, and tars; and solids
consisting of fine coal dust and char. The plan for either disposal of the
wastes as byproducts or conversion into useful products must be made before
a facility is constructed and before an environmental impact statement can be
submitted to the appropriate agency.
Coal gasification research in the United States during the last
10 to 15 years has been funded by the Office of Coal Research, the Bureau of
Mines, the American Gas Association, and private industry. Over $71 mil-
lion has been spent on this research. In addition to these funds, an acceler-
ated research program was started with joint funding of the Department of the
Interior and the American Gas Association. The project will involve expendi-
ture of approximately $300 million over the next eight years.
The cumulative investment cost of coal gasification plants is
estimated to be approximately $10 billion to 12 billion. When additional costs
are added for coal mines, water supply, and environmental control require-
ments, total costs ranging from $20 billion to $25 billion are possible. Such
investment funds may be difficult to raise in light of the high risks associated
with new processes and plants for the energy industry, and there may be need
for a government subsidy or for participation of the oil-producing nations
themselves.
2-8
-------
2.2.2 Oil Shale
Turning now to the question of oil shale resources, Refer-
ence 2-2 contains a detailed analysis of availability. Deposits of potential
commercial interest exist in the Green River Formation of Colorado's Piceance
Basin. Of the 1, 781 billion barrels of potential resources, only 129 billion
barrels are accessible, -well-defined, and sufficiently rich (30 to 35 gallons per
ton bv assav). Furthermore, the amount that can be recovered bv proven tech-
nology (which starts with extraction of a minable seam) will be considerably
less than the gross resource estimate. The most economically recoverable
portion of the Green River Formation is calculated to be equivalent to
54 billion barrels of synthetic crude. Less than 6 billion barrels are forecast
to be recovered through 1985 under the maximum feasible production growth
(Ref.2-2). This corresponds to a production capacity of 150, 000 barrels per
day by 1980 and 750, 000 barrels per day by 1985. Production by the year
2000 could reach about 2 million barrels per day.
Unlike coal, the organic material, kerogen, in shale shows
much less variability in composition with geographical location. It is typically
composed of 80 percent carbon, 10 percent hydrogen, 1 percent sulfur, with
oxygen and nitrogen making up the balance. The hydrogen-to-carbon ratio is
higher than in most coals, so that about two-thirds of the kerogen can be con-
verted to oil simply by heating. Processes for oil shale treatment are more
nearly ready for use than those for coal liquefaction. However, the crude
yield from coal is much greater: 3 to 3. 5 barrels per ton of coal versus
0.8 barrel per tcm^of shale for relatively rich oil shale (Ref. 1-1).
There are a number of factors that can influence the future
level of production. Federal leasing policies are of utmost importance
because about 80 percent of the oil shale resources of the Green River Forma-
tion are federal holdings. Environmental controls, particularly on the dis-
posal of spent shale, fines, and contaminated wastes, can either delay project
startup or add substantially to product costs. Over the long term, water
availability may be a limiting factor, although sufficient water for mine and
2-9
-------
plant use is available for the maximum anticipated scale of oil shale crude
production up to 1985. (Approximately 150 gallons of water per barrel of
shale crude is required for mining and extraction. ) Technological improve-
ments in mining and oil production will likely occur as industry experience
develops. Development of feasible and economic in-situ methods are impor-
tant for recovery of the deeply buried shale deposits. The growing impact of
fossil fuel price escalation will, no doubt, be an incentive in the development
of oil shale production processes. Of interest is the recently announced oil
shale projects of Union Oil and ARCO/TOSCO/Ashland in which a 50, 000-
barrel-per-day plant will be constructed in the Piceance Basin of western
Colorado with operations starting in 1977.
2. 2..3 Tar Sands
Domestic tar sands of potential commercial value have been •
identified in only five deposits in Utah, with total estimated in-place resources
ranging from 1 8 to 28 billion barrels. These estimates are based on very
sketchy data and may be overstatements. Based upon available information on
resources, technology, and likely costs, the conclusion is that the total possible
rate of output from domestic tar sands would be minimal even to the year 2000
(Ref. 2-2), mainly because the cost of extracting fuel from domestic tar sands
is expected to be significantly higher than the cost of producing alternative
domestic synthetic fuels, and because the technology being developed for
extracting fuel from Canada's Athabaska tar sands may not be applicable to
U. S. deposits.
2.2.4 Solid Waste
The last potential source of synthetic hydrocarbon fuel to be
considered is solid waste. The U.S. unquestionably generates large quan-
tities of solid wastes, about 1. 1 billion tons of inorganic mineral wastes
and more than 2 billion tons of organic wastes each year. As recently as
1971, waste conversion proponents argued that treatment of this organic
waste could produce nearly 2.5 billion barrels of oil per year, roughly half
this country's total oil consumption in that year (Ref. 2-4). A study
2-10
-------
prepared for the U.S. Department of Interior's Bureau of Mines by the
University of Utah (Ref. 2-5) indicates that more than half the total waste is
absorbed water. The total amount of dry, ash-free organic waste was actu-
ally 880 million tons, of which more than 80 percent was so widely dispersed
that it could not be readily collected. Typical constituents are manure, urban
refuse, logging and wood manufacturing residues, agricultural crop and food
wastes, industrial wastes, and municipal sewage solids. Because energy is
required for both the collecting and processing of wastes, there are thermo-
dynamic as well as cost limitations to what can be collected and how far it
can be transported to a processing plant. Readily collectable annual wastes
could have produced 170 million barrels of oil, roughly three percent of 1971
U. S. total crude oil consumption or 12 percent of imported crude oil. It appears
that, while conversion of organic wastes to fuel is an ideal way to dispose of
the wastes, it -would not have a significant impact on relieving energy deficits.
2.2.5 Uranium
Uranium can be a substantial energy source in the year 2000
if the fast breeder reactors with fuel doubling time of eight to ten years
(Ref. 2-2) come into operation in the period starting in the period starting in
1990. The rate of uranium utilization for electric power generation depends
on the number of regulatory and environmental constraints. Predictions made
for the electrical sector (which will depend increasingly on nuclear energy)
indicate that it is the fastest average annual growth sector (Ref. 1-1),
exceeding the rate of total energy demand; the difference in growth rate is
expected to decrease as the fraction of total energy contributed to electricity
increases. To illustrate the dramatic predicted growth in nuclear power
plants, Reference 1-1 quotes approximately 9,000 megawatts installed in 1972;
215,000 megawatts predicted in 1985; and 960,000 megawatts in the year 2000.
2.2.6 Solar Energy
19
Solar energy received in the U.S. amounts to 4. 9 x 10 Btu
per year (see Table 2-2), but conversion of it to useful form is difficult with
present technology. Use of photovoltaic methods with 10 percent conversion
2-11
-------
efficiency would require about 15 square miles for a 1, 000-megawatt plant
(Ref. 2-6). On a smaller scale, experiments with solar cells and heat pumps
are being conducted for residential dwellings. Another approach lies in plac-
ing hugh solar cell platforms in earth synchronous orbit and transmitting the
energy to earth by microwave radiation, but this appears to be economically
unfeasible. Clearly, for significant utilization of this energy source a new
technological approach to the conversion of solar energy is required.
2.3 ENERGY DEMAND
2.3.1 Industrial Sector
The industrial sector used fossil fuels (petroleum, natural gas,
and coal) for 89.6 percent of its energy requirement in 1971; it is estimated
that this sector will use fossil fuels for 82 percent of its energy requirement
in 1985 and 73 percent in the year 2000 (Ref. 1-1). The participation of coal
in meeting its energy needs decreased from 19- 7 percent of requirements in
J971 to a forecast of 11.6 percent in 2000. The balance is taken up by an
increased amount of electricity purchased (from 10. 7 percent in 1971 to
27 percent in 2000) (Ref. 1-1). The desired trend here would be the mainte-
nance of 20 percent of coal participation which would reduce the demand for
liquid petroleum products. This would be reflected, for example in a reduc-
tion in liquid petroleum imports needed for the year 2000 by about 13 percent.
2.3.2 Electrical Generation Sector
The electrical generation sector is characterized by a pre-
dicted tremendous growth in nuclear energy from 2. 3 percent of total installed
electric capacity in the U.S. in 1971 to 61 percent in the year 2000 (Ref. 1-1).
Simultaneously, the fossil fuel contribution in this sector is predicted to
decrease from 82 percent in 1971 to an estimated 31 percent in the year 2000.
In spite of that decline, fossil-fuel energy expenditures in the year 2000 are
1. 75 times that of 1971 (Ref. 1-1).
The referenced forecast predicts a growing participation of
coal and a gradual decline in petroleum after 1985. One of the anticipated
improvements would be a faster transition from petroleum and gas to coal in
2-12
-------
the 1975 to 1985 period. Another would be acceleration in the development of
industrial production processes for coal liquefaction and gasification.
2.3.3 Transportation Sector
Transportation consumed approximately 25 percent of the U.S.
total energy demand in 1970 and most references predicted only a slight
decrease to approximately 22 percent in the year 2000, as shown in Table 2-5.
It uses at present approximately 55 percent of U.S. liquid -petroleum (Refs. 2-7
and 2-8), with 95 percent of its energy coming from liquid petroleum, 4.9 per-
cent from natural gas and 0. 1 percent from electricity (Ref. 1-1).
However, the projections were based on an extrapolation of
trends that we now recognize as being unstable. The recognition of supply
limitations and the implications of such limitations have resulted in a federal
program of fuel allocations and priorities. The impact on the transportation
sector is relatively large. It now appears possible that the absolute trans-
portation energy demand growth may be much flatter than previously projected
and may decline significantly as a percentage of a total energy demand.
2.4 PROJECTED STATUS
It can be concluded from the brief U. S. energy review that a
competitive demand for liquid petroleum and natural gas will exist through
the year 2000. Some easement in the shortage could be realized by an accel-
erated program of coal mining, coal liquefaction and gasification, and more
rapid conversion toward coal usage of the industrial and electrical sectors.
The transportation industry is taking steps to reduce its fuel
requirements. Table 2-6 shows that in 1969 just over half of the transporta-
tion energy was consumed by automobiles. Clearly, this is an area where
improvements could be of national importance. A step in that direction would
be the implementation of an improved mass transit system for intracity and
intercity traffic. Although air transport is a smaller consumer, it could
also produce significant economies by operating at higher load factors, lower
per-trip fuel consumption, etc.
In the near term (1975 to 1985), improvements leading to a
reduction in the use of liquid petroleum products could be realized by a
2-13
-------
Table 2-5. Transportation Energy Demand
Units: Btu per yr x 10
Year
1970
1975
1980
1985
2000
Level
Actual
Low
Inter.
High
Low
Inter.
High
Low
Inter.
High
Low
Inter.
High
Data Source
Reference 2-2
Amount
16.2
19.3
20. 0
20. 5
23. 0
23. 9
24.4
26. 7
28.3
29.0
--
--
--
% of Total
Domestic Demand
24.0
24. 0
24. 0
24. 0
24. 0
23. 3
23. 2
23. 7
22. 6
22. 3
--
--
--
Reference 1-1
Amount
16. 97
19.07
22. 84
27.09
42.61
% of Total
Domestic Demand
24. 6
23. 8
23. 8
23. 2
22. 2
2-14
-------
Table 2-6. Distribution of Energy Consumption in
Transportation by Mode (Ref. 2-1)
(1969 Ref. Year)
Overall Transportation Consumption: 15 x 10 Btu per Year
Mode
Auto
Truck
Bus
Rail
Pipeline
Air
Water
(Intercity Freight)
(Urban Freight)
(Service and Utility)
(Intercity)
(Urban and School)
(Intercity Passenger)
(Freight)
(Subway)
(Passenger)
(Freight)
(Passenger)
(Freight)
Energy Source
Oil
Oil
Oil
Oil
Oil
Oil
Subtotal
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. 27
0. 54
74.41
0. 14
3. 6
0. 14
2.0
11.4
2.6
0. 27
5. 8
2-15
-------
two-fold approach: one is an improvement in fuel economy of automotive
vehicles by development of more efficient engine cycles and more efficient
vehicles (those with reduced parasitic losses and reduced weight); the other
is by application of alternative nonpetroleum-based fuels.
The problem posed in the distribution of alternative fuels for
the transportation sector in particular cannot be overlooked because of the
multiplicity of retail outlets required. The present distribution system for
liquid petroleum products starts with oil wells, proceeds to refineries, then
to terminal distribution centers, and from there to approximately 300, 000
service stations throughout the U.S. This represents a multibillion-dollar
investment. Alternative fuels that are compatible with this distribution sys-
tem would utilize this investment, while, for other fuels such as natural gas,
synthetic gas, or hydrogen, for instance, a new distribution system must be
considered in evaluation of the total fuel economics.
In the far term (1985 to 2000), further diversification of energy
sources for transportation may be possible by application of electrical energy
to automotive vehicles. This will require a technology breakthrough in
vehicle power train components; more efficient and economical energy storing
devices (batteries) and lightweight motor /control packages are needed.
Each of the sections within this volume on alternative fuels con-
tains estimates of capital investment required to produce these fuels. The
impact of these costs can best be evaluated by comparing them with capital
investments for gasoline refining. The following quotation referring to capital
investment needs for petroleum refining was obtained from Reference 2-9:
"U.S. refining must double annual investment to meet 1980
needs. C.F. Braun's Robert Skamser says the nation will
need 67 new 150, 000 barrels per day plants to provide the
additional 10 million barrels per day of new refinery capac-
ity required by then. Total cost of construction will exceed
$18 billion ---"
2-16
-------
Although the exact magnitude of the capacity additions is
perhaps questionable in view of pjas-sib-l-e-cantinuing limitations on the-a
ability of imported crude oil, it may be inferred from the above figures that
lew investment in petroleum refining will average about $1, 800 per daily _--
barrel of crude charging capacity^ Also (per Reference 2-9) as of March
1973 tEedaily aver&geTJr^refinery runs were in excess of 12 million bar-
rels per day. Based on current costs, the present capital investment in
petroleum refining (assuming that operation is at 100 percent capacity) is
estimated at approximately $22 billion. This investment is exclusive of the
cost for storage and distribution.
The succeeding sections will examine the various approaches
to the use of nonpetroleum-based alternative fuels in some detail by evalua-
tion of (1) the characteristics of potential fuels in various automotive power
plants, (2) the supply and economics of these alternative fuels and energy
sources, and (3) the problems involved in their future application.
2-17
-------
SECTION 3
-------
SECTION 3
SYNTHETIC GASOLINE AND DISTILLATE HYDROCARBON FUELS
3.1 CHARACTERIZATION
3.1.1 Fuel Type
This category includes a broad spectrum of hydrocarbon
mixtures which are qualitatively similar to those in use today in the trans-
portation sector. However, rather than being derived from petroleum
sources, they would be manufactured from coal, oil shale, tar sands, or
organic waste products. They possess the primary advantage of essentially
complete compatibility with existing and advanced mobile combustion power
plants as well as with distribution facilities down to the local gas station.
On the other hand, they do not, in themselves, provide a path to reduced
pollutant emissions.
There are five hydrocarbon fuels included in this category:
gasoline, diesel oil, kerosene, naphtha,and No. 2 fuel oil. They are mixtures
of hydrocarbons of four basic types, differing in their properties according
to the number of carbon atoms in the molecule and in the arrangement of
the atoms. The four types are: (1 )rp£H~affina> — open chain, saturated as
hexane, Cx-H^; (2) jplefjjas^— open chain, one double bond, as hexene, C,H,.>;
(3) joaphthaoes — cyclic, saturated, as cyclohexane, C^H12; (4) a£ornatics —
cyclic, unsaturated, as benzene, C,H, . The various hydrocarbon fuels
differ in the proportions of, and specific compounds within, each type. To
indicate the great number of possible compounds in this category, there are
several hundred different hydrocarbons present in a single commercial
gasoline. Because each type imparts certain specific characteristics to the
final product, there are frequently specifications that directly or indirectly
control the percentage allowed in the final product. In addition to the
3-1
-------
hydrocarbon compounds, there are usually minute quantities of impurities
containing the so-called heteroatoms, sulfur, oxygen, and nitrogen that
are carried over from the feed stock or introduced during processing. Also,
various additives are employed to impart certain desired properties such
as antiknock, detergent.and viscosity-control compounds.
Individual compounds, such as benzene, are not included in
the list of candidate fuels in this section for several reasons. It is not
economically feasible to convert the complex mixture in crude oil into one
specific compound. Also, a single compound seldom possesses all the
attributes of a good fuel.
A few properties of these fuels may serve to put them in per-
spective. The carbon-to-hydrogen weight ratio is on the order of 5.5 with
lower heating values ranging between 18,500 and 19, 300 Btu/pound. Specific
gravity extends from 0. 73 for gasoline to 0. 86 for No. 2 fuel oil. Boiling
points range from below 100 F for the low end of gasoline to near 650 F for
the high end of fuel oil, illustrating the great diversity of compounds present
in these fuels. A further discussion of physical and chemical properties is
given in Se ction 3.1.4.
3.1.2 Reserves or Raw Material Sources
The fuels in this category have to date been obtained predom-
inantly from petroleum sources; the only exception is the gasoline derived
from natural gas liquids. Inasmuch as domestic sources are already
inadequate to meet automotive requirements plus other fuel and nonfuel
demands, attention has recently been focused on other domestic energy
supplies. The primary potential sources of liquid hydrocarbon fuels are
from the processing of either coal or oil shale. Additional domestic sources
of much less potential in terms of ability to meet energy needs are tar sands
and solid wastes. These sources were discussed in Section 2.
3-2
-------
3.1.3 Methods of Manufacture
A brief digression at this point is worthwhile to review the
steps in process development leading to commercial production. This
review is intended to provide a better understanding of the current status
of coal liquefaction and the magnitude of the task for the future. The
earliest stage occurs in the laboratory, often termed bench-scale, where
the pertinent chemical and physical principles are demonstrated, usually
on a batch basis. Once scientific feasibility is shown, the process can be
scaled up to pilot plant size to prove engineering feasibility, generally on
a continuous basis. Hardware, machinery and control equipment can be
tested and proven, processing alternatives evaluated, and yields confirmed
here. At this point it is prudent, especially for a new technology such as
coal liquefaction, to proceed to an intermediate stage, variously termed a
demonstration, prototype or semicommercial plant. The primary purpose
here is to determine the economics of a large-volume operation through
verification of equipment durability, product yield and quality, adequacy of
environmental controls, and such logistic support requirements as operating
and maintenance manpower. At some point during this demonstration phase,
the decision is made to commit a large capital investment to the construction
of full-scale, probably multiple, production plants.
It is difficult to define a general size range in terms of either
input or output quantities for each development stage, since it varies widely
with the specific product involved. However, for coal or shale conversion,
a rough breakdown would be:
• Bench scale - less than 1 ton per day raw material input
• Pilot plant - 1 to 200 tons per day
• Demonstration plant - 200 to 5, 000 tons per day
• Commercial - greater than 5, 000 tons per day
Production of clean liquids (or clean solids) from coal can be
carried out by three principal routes. In the first route, clean gas containing
3-3
-------
appropriate proportions of CO and H2 (synthesis gas) is converted by the
Fischer-Tropsch process to hydrocarbon oil.
The second route involves heating the coal in the absence of
air (pyrolysis), which breaks down the coal structure to the molecular
weight range of oil. The oil is then treated with hydrogen for desulfurization
and quality improvement. The major products from pyrolysis processes
are gas plus char (~80 percent) rather than oil. The COED (Char-Oil-Energy.
Development) Process of the FMC Corporation and TOSCOAL Process of
The Oil Shale Corporation are based upon the pyrolysis approach. Pyrolysis
produces an oil with a higher hydrogen-to-carbon ratio than in the original
coal by rejection of carbon (char).
The third route to clean liquid fuels raises the H:C ratio by
adding hydrogen. One approach is by direct hydrogenation in the presence of
a catalyst, exemplified by the Synthoil Process of the Bureau of Mines, and
the H-Coal Process developed by Hydrocarbon Research, Incorporated.
Alternatively, a two-stage route can be used in which the first stage consists
of a mild hydrogenation without a catalyst. After solids rejection, the extract
may be further hydrogenated over a catalyst to yield a lower boiling distillate
fraction. In the Consol Process of the Consolidation Coal Company, a donor
solvent supplies most of the hydrogen in the first step, while in the Solvent
Refined Coal Process, developed by the Pittsburgh and Midway Coal Mining
Company, gaseous hydrogen at elevated pressure is employed. These proc-
esses are discussed in further detail in Section 3. 1. 3. 1.
The chemical composition of the available coal greatly influ-
ences the processes that can be used, the equipment and operating conditions,
the quantity and characteristics of the products produced, and the economics
of the operation. Several feed coals are therefore included during process
development; Pennsylvania State University is characterizing the composition,
physical properties,and process behavior of over 300 U.S. coal samples
(Ref. 3-1).
3-4
-------
Several processes are being investigated to make liquid
hydrocarbon fuels from coal, some in commercial production outside the
United States, others in the development stage or on a pilot-plant scale.
The least thermally efficient or economically attractive process is the one
with the longest history of commercial utilization, viz. , the Fischer-Tropsch
process. The Sasol installation in South Africa has been producing small
amounts of synthetic liquid hydrocarbons for over 20 years, based upon
German technology that was commercialized between 1925 and 1945. The
first step is the generation of purified synthesis gas, primarily, CO + H~.
The Lurgi process is used at Sasol, but others are possible as shown in
Table 3-1. The synthesis gas then contacts an iron catalyst in either a
fixed-bed or fuild-bed synthesis are straight-chain, high-boiling hydrocarbons
with some medium boiling oils, diesel oil, LPG, and oxygenated compounds.
Products from the fuild-bed reactor are mainly low boiling hydrocarbons
(C, - C.) and gasoline, with a little medium and high boiling material.
Turning now to the production of synthetic liquid fuel based
upon coal pyrolysis, several processes are under development, principally
the COED and TOSCOAL, approaches described in the following paragraphs.
3.1.3.1 COED Process Description
The COED (Char-Oil-Energy-Development) process produces
synthetic crude oil by pyrolysis of coal (see Figure 3-1). Coal is crushed
to minus 1/8 inch size, dried, then heated to successively higher tempera-
tures in a series of fluidized-bed reactors. In the first stage the coal is
heated to 600 F by hot flue gases and devolatilized. In the subsequent stages
the coal is subjected to increasing temperatures of 850 , 1000 and 1600 F.
The pressure of the operation is between 6 to 10 psig. Some of the char is
burned with oxygen in the fourth stage to maintain the 1600 F temperature in
that stage and to provide the hot gases for heating the second and third stages.
Gas from the fourth stage flows countercurrent to the solids through the third
to the second stage, from which most of the volatile products are collected.
3-5
-------
Table 3-1. Coal to Synthesis Gas (H, + CO) (Ref. 3-2)
Energy/Material
Resources
1 !->n coal
M7fl SCF O,
H. H7 Ih high-
pressure steam
210 K»l- process
water
1 tnn coal
20, 376 SCF O
708 Ib low-
pressure steam
81. 8 kWhr
1 ton coal
12.271 SCF O
3100-lb low-
pressure stearn
1 ton coal
14,050 SCF O
261-lblow-
pressure steam
1 ton coal
19,950 SCF O7
2390-lb low-
pressure steam
1 ton coal
18, 380 SCF O,
1680-lb low-
pressure steam
1 ton coal
19, 160 SCF 0
610 Ib steam
1 ton coal
19,950 SCF 0
1750-lb steam
1 ton coal
20,570 SCF 0,
3000-lb steam
Name of the
Process
Lurpi Pressure
Ga B i f i e r
Kopper Totzek
Process
Winkler
Generator
Rummcl Single-
Shaft Slag Bath
Gasifier
Flesch Demag
Generator
Wurth Gasifier
U.S.B.M.
Gasifier
BWV-DuPont
IGT Gasifier
Comment on the Process
Operated at 450 psi and
I400'-1600'F high-
ash coal
(7500 Btu/lb)
Operated at 1 atm and
1830° to 2370°F
carbon conversion 96%
high-ash coal
Operated at 1 atm and
1470° to 1650'F
carbon conversion 80%
low-ash coal (976 Btu/lb)
Operated at 1 atm and
1830°F (coal 10,035 Btu/lb
carbon conversion 99%
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/lb)
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
Synthesized
Fuel
46,000 C7 raw
gas
30,000 CF
purified gas
(400 Btu/SCFI
56,600 CF raw
gas
(277 Btu/SCF)
52,200 CF raw
gas
(288 Btu/SCF)
49,300 CF
CO + HZ
65,400 CH
CO + H2
71,900 CF
CO + H2
51,800 CF
CO + H2
59,000 CF
CO + H2
62,900 CF
CO + H2
By-Product
0.5 gal. oil
2.9 gal. tar
321 gal. gas liquor
1551 Ib low-pressure
steam
2374 Ib steam
NO 4. 5 ppm
1500 Ib steam
at 17. 6 atm
2064 Ib steam
987 Ib steam
1539 Ib steam
3500 Ib steam
Thermal '
Efficiency,
77
71
65
78
66
75
60
65
63*
Comments on Pollution
Relatively low off-gas temperature and
countercurrent design increase appearance
of tars, NH-,, etc. , in waste quench liquor.
Very high off-gas temperature precludes
the formation of any compound less stable
than H2, CO, CO^.
High gasifier temperature ensures that all
tars and heavy hydrocarbons are reacted.
The reactants pass through slag, con-
sequently 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
ensure that all tars and heavy hydrocarbons
are reacted.
Very high off-gas temperature precludes
the formation of any compound lees stable
than H2, CO, CO2-
Thermal efficiency based upon high heating value of input and output streams, including by-products.
oo
I
-------
COAL
COAL
PREPARATION
VENT
' GAS
GAS
AMMONIA
i
CLEANUP
PLANT
OIL
RECOVERY
FLUE GAS
1000 F
u>
CHAR
2nd
STAGE
850° F
6-10
H2S
PRODUCT
GAS
STEAM
REFORMER
HYDROGEN
GAS
STAGE
1000 F
6-10
psig
SYNTHETIC
CRUDE OIL
4th STAGE
1600°F
6-10 psig
STEAM
OXYGEN
CHAR
Figure 3-1. COED Process (Ref. 3-3)
-------
Exit gas from the first stage is quenched with recirculating liquorj and oil
is recovered. Part of the gas is used in the coal drier and part in the char
cooler. Volatile products in the second-stage gas proceed to the product
recovery section. The gas is quenched directly with water to condense the
oil. The oil is separated from water and filtered to remove char carryover.
Separator gas from the oil recovery section is purified to remove ammonia,
CO0, and H9S and is then steam reformed to produce hydrogen. The filtered
Z " v'-
synthetic crude oil is minus 4 API', a solid at room temperature. Hydro-
treating at about 750°F and 1500-3000 psig removes sulfur, nitrogen, and
oxygen from the oil and produces a 25 API synthetic crude oil.
• Typical Products
Some yield data for pyrolysis of Illinois No. 6 seam coal.
Net Yield From Coal
Pyrolysis, Weight %
Net Process Yield of Dry Coal
Char . 1177 Ib/ton 59. 1
Oil 1.04 bbl/ton 19.6
Liquor 7.1 gal/ton 5.5
Gas 8133 SCF/ton 15.8
TOTAL, 100.0
After acid gas removal, the pyrolysis gas will typically have
a composition of 50 percent H2, 32 percent CO, 10 percent CH4, 8 percent
other. The portion of this gas not required for hydrogen production might be
converted by methanation to high Btu pipeline gas. This modification is
Tefered to as the COGAS process.
°API = 141'5 - 131. 5
sp. gr. at 60 F
3-8
-------
• Current Status
A pilot plant with a capacity of processing 36 tons of coal per
day has been operational since December 1970 near Princeton, New Jersey.
Design capacities have been achieved on all parts of the pilot plant with sig-
nificant accomplishments being demonstrated in solids circulation between
multiple fluidized bed reactors, in the filtration of coal oil, and in upgrading
the coal oil to synthetic crude oil through fixed bed hydrotreating. The prod-
uct oil is being refined by several petroleum companies: FMC Corporation
is investigating private backing for a commercial plant by 1980 (Ref. 3-4).
The Navy has tested the fuel oil at sea. Research is directed toward utilizing
the high-sulfur chars obtained from high-sulfur coals.
3.1.3.2 TOSCOALT Process Description
The basic feature of this pyrolysis process is to provide the
required heat by using hot ceramic balls (see Figure 3-2). Coal is crushed,
dried and preheated with hot flue gas. The preheated coal is transferred to a
rotating pyrolysis drum where it is heated to carbonization temperature by
contact with hot ceramic balls. The balls are separated from the char and
conveyed to a ball heater. The char produced is about 50 percent of the
weight of the raw coal feed and contains about 80 percent of raw coal heating
value. Economical use must obviously be found for this material. Pyrolysis
vapors are cooled to condense oil and water from the gaseous products. The
liquid products are fractionated into gas, oil, naphtha, and residuum. Gas
is utilized in the ball heater as a fuel.
• Typical Products
Typical products obtained from Wyodak coal (a subbituminous
coal from the Wyoming/Dakota region with a gross heating value of 8139 Btu
per pound and 0.3 weight percent sulfur) are as follows:
The Oil Shale Corporation
3-9
-------
I
K^
o
GAS
COAL
COAL
PREPARATION
COAL
PREHEATER
H2S
t
PURIFICATION
SEPARATION
PYROLYSIS
800°-
1000°F
CHAR
LIQUID
PRODUCTS
HOT BALLS
CHAR
COOLER
CHAR
HOT FLUE GAS
BALL
HEATER
AND
Figure 3-2. TOSCOAL Process (Ref. 3-3)
-------
Product/Ton of Raw Coal Characteristics of
970°F 800°F Products
Gas, MSCF 1.625 0.438 600 (includes CO-,, H?S)
HHV Btu/SCF
Oil, barrels 0.52 0.25 6-13° API, HHV 16, 000
Btu/lb
Char, pounds 970 1100 Sulfur 0.2-0.4%,
13,000 Btu/lb., 16%-25%
volatile s
• Current Status
The Oil Shale Corporation has carbonized sub-bituminous coal
in its 25 ton/day pilot plant located at Golden, Colorado.
Of the four principal processes based upon solvent separation
or solvent extraction, two utilize direct hydrogenation of coal in the presence of
an active catalyst followed by removal of mineral matter and unreacted coal.
This is the concept employed in the SYNTHOIL and H-Coal processes
described below.
3.1.3.3 SYNTHOIL, Process Description
The SYNTHOIL Process (Figure 3 -3) was developed by the
Bureau of Mines to convert coal into fuel oil. Coal is crushed, dried, and
slurried in a recycled portion of its own product oil. The slurry is fed to a
fixed-bed catalytic reactor with turbulently flowing hydrogen. The combined
effect of the hydrogen, turbulence, and catalyst is to liquefy and desulfurize
the coal. A commercially available catalyst is used and consists of cobalt-
molybdenum on silica activated alumina. The conditions of operation are
850°F and 2, 000 to 4, 000 psig. The violently moving slurry prevents plug-
ging of the packed bed as the coal passes through its sticky plastic phase
prior to becoming liquid; it also increases the mass transfer of hydrogen
into slurry and keeps the catalyst surface clean by controlled attrition. The
slurry residence time is less than 14 minutes, and reactor pressure drop is
150 psi. The product passes through a high-pressure receiver where the
3-11
-------
COAL
PREPARATION
00
SLURRY
PREPARATION
H2 SUPPLY
SYSTEM
FIXED-BED
CATALYTIC
REACTOR
PREHEATER
HIGH-
PRESSURE
OIL AND GAS
SEPARATION
i
LOW-
PRESSURE
OIL AND GAS
SEPARATION
SOLID-
LIQUID
SEPARATION
GAS
CLEANUP
GAS
SOLIDS
SYNTHETIC OIL
H2S
RECYCLE H2-RICHGAS
RECYCLE OIL
SYNTHETIC OIL
-^ PRODUCT
Figure 3-3. SYNTHOIL Process (U.S. Bureau of Mines)
(Ref. 3-3)
-------
gas is separated and recycled after HZS and NH3 removal. The product
slurry oil pressure is reduced in passing to a low-pressure receiver, and it
is centrifuged to remove ash and organic coal residues. Part of the centri-
fuged oil is recycled as slurry oil and the remainder is the product oil.
• Typical Results - Treating Kentucky Coal
Hydrodesulfurization of Kentucky Coal
Experimental Conditions:
Liquid Feed Throughput: 140 lb/hr/ft3 Reactor Volume
Slurry Feed: 45 Coal/55 Recycle Oil
Hydrogen Recycle Rate: 125 std. ft3/hr
Pressure: 4, 000 lb/in^ gauge
Temperature: 450°C
Sulfur in Feed Coal, wt. % 4.6
Sulfur in Recycle Oil (Product Oil), Wt. % 0.19
Yield: bbl. oil/ton coal m.a.f 3.0
Solvent Analysis of Product Oil, wt. %
Oil (Pentane Soluble) 79.5
Asphaltene 17.4
Organic benzene insolubles 2.1
Ash 1.0
Elemental Analysis of Product Oil (Ash-Free), wt. %
Carbon 89.9
Hydrogen 9.2
Nitrogen 0.19
Viscosity of Product Oil, SSF at 180°F 21-30
Calorific Value of Product Oil, Btu/lb 17, 700
• Current Status
The SYNTHOIL process is being tested in a small 5 to
10-pounds-per-hour pilot plant. A pilot plant capable of processing 1/2 tons
of coal per day, -with output of 1. 5 barrels per day of oil has been started up
in Bruceton, Pennsylvania, and plans are being formulated for construction
of an 8-ton-per-day pilot unit.
3. 1.3.4 H-Coal Process Description
The H-Coal process can produce synthetic crude oil from coal
(Figure 3-4). Coal is dried, pulverized (minus 40 mesh), and slufried with
coal-derived oil. The slurry, mixed with hydrogen, is preheated and fed to
3-13
-------
COAL
UJ
LIGHT
DISTILLATE
PRODUCT GAS
HYDROGEN RECYCLE
GAS CLEANUP
ATMOS-
PHERIC
DISTILLA-
TION
COAL
PREPARATION
CATALYTIC
REACTOR
2250-2700
SLURRY
PREPARATION
PREHEATER
BOTTOMS
SLURRY TO
COKING
HEAVY
DISTILLATE
Figure 3-4. H-Coal Process (Hydrocarbon
Research, Inc. ) (Ref. 3-3)
-------
an ebullating bed reactor containing a cobalt-molybdenum catalyst. The coal
is hydrogenated and converted to liquid and gaseous products. Reactor con-
ditions are about 850 F and 2700 psig. A constant catalyst activity is main-
tained by adding and withdrawing catalyst continuously. A slurry of
unconverted coal and liquid product is let down from the reactor to an
atmospheric-pressure flash drum. Flash vapors go to an atmospheric distil-
lation tower and the bottom products are further processed in a vacuum
tower to obtain vacuum distillate overhead and a vacuum bottoms slurry
product. The light hydrocarbon vapors in the gas leaving the reactor are
removed in a recycle gas scrubber. Ammonia and hydrogen sulfide are
removed and gas is recycled to the H-Coal reactor. A part of the heavy
distillate product from the top of the vacuum distillation and the bottom of
the atmospheric distillation are recycled as slurry oil.
• Typical Products
Typical products from Illinois No. 6 bituminous coal are
as follows:
IBP Cuts Volume. % Gravity, °API
IBP - 400°F 42.18 44.6
400 - 650°F 41.51 17,3
650 - 975°F 16.31 5.0
• Current Status
This process has been operated on a 3-ton-per-day pilot
plant scale.
An alternate approach has also been developed in which the
first stage consists of mild hydrogenation without a catalyst. After solids
rejection, the extract (or solvent refined coal) is further processed over a
catalyst if the end products so dictate. This is the route followed by
Pittsburgh & Midway Coal Mining Company (a subsidiary of Gulf Oil Corpo-
ration) in the Solvent Refined Coal (SRC) process and by the Consolidation
3-15
-------
Coal Company in the Consol Synthetic Fuel (CFS) process. In the former
case, gaseous hydrogen at elevated pressure is used in the extraction step
while a donor solvent supplies the hydrogen in the CSF process. Both
concepts are reviewed in the following pages.
3.1.3.5 SRC Process Description
The Solvent Refined Coal (SRC) process produces a low-
sulfur, ash-free material that can be handled in either a liquid or solid
form (Figure 3-5). Coal is ground to minus 200 mesh size, dried, and
mixed with a coal-derived solvent having a boiling range of 500 to 800 F.
The slurry, together with hydrogen, is heated to 815 F at 1, 000 psi causing
complete solution of the organic matter. Hydrogen requirement varies
from 15,000 to 80, 000 SCF/ton of coal. Gas from the dissolver is separated
in a high-pressure, flash vessel operating at 995 psia and 625 F. Liquid
and solids from the flash vessel go to a rotary filter where undissolved coal
solids are removed. The filtrate is sent to a vacuum distillation. The
overhead fraction is solvent for recycle and product light oil. The bottom
fraction is a hot liquid with a solidification point of about 300°F (solvent
refined coal), having a heating value of about 16, 000 Btu/pound. Gas from
the high-pressure flash tank is treated for acid-gas removal before recycling
it to the dissolver. In this process all the pyritic sulfur and over 60 percent
of the organic sulfur, and most of the ash are removed from the coal. Solids
from the filtration system are dried to recover solvent. The dried solids
containing about 35 to 55 percent by weight undissolved carbon and about 5 to
8 percent sulfur are burned in a fluidized combustor to generate steam.
Stack gas containing SO,, reacts with H S from the gas scrubbing system in a
Claus plant to produce sulfur. The liquid product can be transported hot as
a liquid fuel or can be allowed to cool below 300°F to solidify and produce a
relatively clean solid fuel.
3-16
-------
COAL
COAL
PREPARATION
SLURRY
PREPARATION
i
LU
u
r
.fe.
f
u
u
DC.
PREHEATING
AKin —
L
to
0
U-
^.
GA<
HYDROGEN
GAS
DISSOLUTION
TREATING
I
t—•
-J
SOLID
FUEL
SOLIDIFICATION
LIQUID
FUELS
HYDRO-
CONVERSION
AND
HYDROTREATING
SOLVENT
RECOVERY
LIQUID
I
FILTRATION
SOLID
RESIDUE f
LIQUID
FUEL
BOILER AND
POWER
GENERATION
HYDROGEN
ASH
H2S
SO,
Figure 3-5.
Solvent Refined Coal Process
(The Pittsburgh &; Midway Coal
Mining Company) (Ref. 3-3)
-------
• Typical Products
Product
Raw Coal Solvent Refined Coal
Wt. %
Carbon 70.7 88.2
Hydrogen 4.7 5.2
Nitrogen 1.1 1.5
Sulfur 3.4 1.2
Oxygen 10.3 3.4
Ash 7.1 0.5
Moisture 2.7
100.0 100.0
Volatile matter 38.7 36.5
Fixed Carbon 51.5 63.0
Ash 7.1 0.5
Moisture 2.7
100.0 100.0
Btu/lb 12,821 15,768
• Current Status
Construction of a 50-tons/day plant is under way in Fort Lewis,
near Tacoma, Washington. Completion was scheduled for late 1973. A pilot
plant is also located in Wilsonville, Alabama. These plants produce a solid
fuel product.
3.1.3.6 Consol Process Description
The Consol Synthetic Fuel Process (Figure 3-6) can produce
liquid hydrocarbon fuel from coal. Crushed coal (minus 14 mesh), is dried
and preheated in a fluid bed to 450 F. It is then slurried with a coal derived
solvent and pumped at 150 psig through a tubular furnace where it is heated
to an extraction temperature of 765 F. Extraction occurs mainly in a stirred
extraction vessel. Vapors produced in the extraction section are sent to the
solvent recovery section. Unreacted coal and liquid product are separated
in hydroclones. Liquid passes to the solvent recovery section, and solids are
sent to a low-temperature carbonization unit.
3-18
-------
•£>
SOLVENT
DISTILLATE
COAL PREP-
ARATION
SULFUR
REMOVAL
1
SULFUR
SLURRY
PREP-
ARATION
EXTRACTION
765*F
150 psig
RESIDUE
SEPARATION
GAS
AIR AND
STEAM
i
LOW-TEMP.
CARBONIZA-
TION, 92? F
9 psig
OXYGEN
CHAR
H2 MANU-
FACTURE
ASH
3_t
SOLVENT
RECOVERY
l-
I
FUEL GAS AND
LIGHT OIL ^
TAR
DISTILLA-
5TILLA- •++>
iFI
HYDROTREAT-
MENT, 800° F
3000 psig
HYDROGEN
3
—^ NAPHTHA
L
°* FUEL
GAS
GAS
CLEAN UP
NH- T
co
FUEL
OIL
H2S
Figure 3-6. Consol Synthetic Fuel (CSF) Process
(Consolidation Coal Company) (Ref. 3-3)
-------
Solvent for recycle to the extraction process is distilled from
the liquid. The remaining liquid, along with tars from the carbonization
unit, is treated with hydrogen in a reactor system operating at 800 F and
3000 psi and using a cobalt-moly-nickel catalyst. This desulfurizes and
upgrades the product fuel oil. Hydrogen for this operation is produced from
the char of the carbonization unit.
Gas streams from the carbonization and hydrotreating opera-
tions are treated for removal of H2S, NH , CO2 and light hydrocarbon
liquids. This produces a clean fuel gas and a naphtha liquid product.
• Typical Products Using Pittsburgh Seam Coal (Ireland Mine)
_ Product/Ton Characteristics
product of Raw Coal of Products
Gas 3.424MSCF HHV 933 Btu/SCF
Naphtha 0.52 bbl 58° API, 5.2 MMBtu/bbl,
0.056 Wt%S
Fuel Oil 1.52 bbl 10.3° API, 6.3 MMBtu/bbl,
0.128 Wt%S
Ammonia
Sulfur
Ash
•
2
Current
11.00
71.00
13.60
Status
Ib
Ib
Ib
A 70-ton per day pilot plant was operational at Cresap, West
Virginia for 40 months with less than 500 hours of operating time. It was
shut down in April 1970 for a detailed study of the process and its operating
problems. The original intent was to make liquids in the gasoline range; but,
if the plant were to be reactivated, it would be modified to maximize produc-
tion of low-sulfur fuel oil.
All the foregoing processes provide a synthetic crude oil of
varying composition suitable for processing in a conventional petroleum
refinery. The refinery processes will not be reviewed here, since they are
standard methods described in any text on petroleum refining. However, the
3-20
-------
processing sequence will probably differ from that used for petroleum-
derived crudes because of differences in chemical and physical properties.
3.1.3.7 Oil Shale
Thus far in this section, the topic has been the liquefaction of
coal. We turn now to the recovery of oil from oil shale deposits in the
Western United States. Oil shale is a finely textured sedimentary rock
containing the solid, largely insoluble organic material, kerogen. High
temperature decomposes the kerogen, yielding a viscous oil which can be
upgraded to a product suitable for use as a refinery feedstock. There are
two principal routes to recovering the oil contained in shale: conventional,
above-ground retorting of mined shale and in-situ retorting. Each approach
involves several stages that have been developed to various degrees, as
summarized in Figure 3-7. Above-ground retorting is almost ready for com-
mercialization, -while in-situ recovery is still in the exploratory stage.
The two methods of recovery are complementary rather than
competitive. Where the shale can be mined inexpensively, such as where
relatively rich shale crops out or where the overburden is shallow, above-
ground processing •will probably be used. However, where the shale is
deeply buried and in varying layers of rich and lean shale, in-situ processing
would be advantageous.
This discussion of shale oil recovery processes will be con-
fined to above-ground retorting, which is the more advanced approach,
although in-situ recovery has many attractive features if developed, pri-
marily elimination of spent shale disposal. The principal efforts in devel-
oping oil shale retorts have been made by the Bureau of Mines, Union Oil
Company, and The Oil Shale Corporation.
In the BuMines Combustion Process, crushed shale (1/4 to
2 inches) is fed to the top of a cylindrical retort and falls successively through
preheating, retorting, combustion, and cooling zones to a grate and lock
3-21
-------
OIL SHALE DEPOSIT
(3AI NATURAL
(2C| HYDRAULIC
EXPLOSIVE
4) NUCLEAR
IN-SITU oi
CONVENTIONAL 121
COMBUSTION (3B)
STEAM I3A)
I2B) GAS DRIVE
(2BI ARTIFICIAL LIFT
(1C) THERMAL AND CHEMICAL TREATING
(MILD-CATALYTIC
(2CIHYDROGENATION HYDROCRACKING
MINING
CRUSHING
RETORTING
^**^"^^
CODE -
State of knowledge applicable to oil shale
1. Rwionably well demonstrated
2. Some experimental knowledge
3. Little known
4. Conceptual
- with knowledge stemming from:
A. Shale experience
B. Petroleum or other Industry
experience
C. Both
{ROOM AND PILLAR (IA)
CUT AND FILL (4)
BLOCK CAVING (3B)
(1C)
ssr-11 =->
TOSCO (IA)
HYDROGEN ATMOSPHERE (3A)
UTILIZE (2A)
DISPOSE f M(NE F|LL (4)
1 REVEGETATE (3)
DUMP (1)
(1C)
GASOLINE
DIESEL FUEL
JET FUEL
DISTILLATE FUEL
RESIDUAL FUEL OIL
LIQUEFIED
PETROLEUM GAS
AMMONIA (1C)
SULFUR (1C)
AROMATIC: IZA)
SPECIALTIES (3A)
COKE (1C)
PITCH (1C)
ASPHALT (1C)
Figure 3-7.
Oil-Shale Utilization - Routes and State of
Knowledge (U.S. Department of the Inte-
rior, 1968) Ref. 3-5
-------
hopper. Recycle gas, mostly inert but containing a small amount of hydro-
carbon vapor, flows up from the bottom. Air is introduced through nozzles
above the cooling zone, burning the residual carbon off the shale, producing
a temperature of 1, 600 to 1, 800°F in the gas and on the lump surfaces, and
decomposing about one quarter of the shale carbonate. In the retorting zone
where the kerogen decomposes, the temperature is 800 to 900°F. Flow of
the gases upward through the fresh downcoming shale to the peripheral top
outlet ports cools the gas to 130 F and forms a suspended oil mist which
passes through centrifugal separators and an electrostatic precipitator,
yielding a crude oil of 20 API gravity and 80 F pour point and a gas which
is split into two streams; part being recycled to the retort and part going to
a steam plant. The retorting efficiency is 90 percent (the percent of that oil
yield obtainable in a standard Fischer Assay of the feed). The process has
been demonstrated on a 260-ton-per-day scale by the Colorado School of
Mines Research Institute.
In the Union Oil process, shale is charged into the lower and
smaller end of a vertical truncated cone and is pushed upward against down-
flowing process gas. One retort in four uses air for partial combustion of
the carbon residue in the shale (maximum temperature 2, 200 F); its product
gas, after separation from the oil, is burned to preheat the rich nitrogen-
free recycle gas from the other three retorts. The preheated recycle gas
is fed to the top of all four retorts, producing a maximum temperature of
950 F in the three unfired retorts. The process has the advantages over the
BuMines process of not dripping oil products into hotter parts of the charge
for recracking and of permitting an improved thermal balance by proper
portioning of the recycle gas. The average retort efficiency (Fischer Assay)
is 91 percent. The process was demonstrated at a rate of 1, 000 tons shale/
day in 1958.
The TOSCO II retorting process uses hot ceramic balls to heat
the shale in a horizontal rotating kiln to 920°F (Figure 3-8). The balls are
separated from the spent shale, reheated in a furnace fired with product
3-23
-------
SHALE
I
SURGE
HOPPER
FLUE GAS TO atm
4.
SHALE
PRE-
HEATER
SHALE
SEPARA-
TOR
PRE-
HEATED
SHALE
HOT FLUE GAS
TO DEPOSIT
Figure 3-8. TOSCO Process for Oil Shale Treatment
(Ref. 3-5)
-------
gas, and returned to the retort. Flue gas from the ball furnace is used to
preheat the shale. The retort efficiency, based on standard Fischer Assay,
is 105 percent. The process was demonstrated at a rate of 1, 000 tons of
shale per day in 1967-
The product of any of the retorting processes is too viscous
for piping to a refinery. The upgrading process starts with a 650°F flash
over into 40 percent overhead and 60 percent residuum; the latter is heated
to 900 F and sent to coke drums. Gas oil and naphtha streams are separately
hydrofined in multiple-bed reactors consuming 2, 100 and 1, 500 SCF, respec-
tively, of 97 percent H~ per barrel of charge. The final byproducts, based
on 50, 000 bbl/SD" of 43° API syncrude, are 820 T/SD** of coke, 162 T/SD
of ammonia, and 66 T/SD of sulfur- This is a rather severe upgrading proc-
ess, producing an excellent refinery feedstock. However, large water
requirements may prevent such processing in arid shale regions. The alternative
is a relatively low water requirement, mild heat treatment to reduce viscosity
("visbreaking") -which -will allow pipeline transport of the crude to the refinery.
3.1.4 Physical and Chemical Properties
A compilation of property data for the liquid hydrocarbon fuels
is given in Table 3-2. Note that the data are for petroleum-derived products.
There are several reasons for this situation. Relatively little data are avail-
able on many properties of refined coal and shal liquids. What has been pub-
lished may not be representative of the products that finally are commercially
produced. Indeed, it is probable that at least some refined fractions, such
as gasoline, will be made from blends of petroleum- and synthetic-derived
material. Other than some increase in the aromatic content of coal-derived
products, it appears that the liquid hydrocarbon fuels made in whole or part
from synthetic crude will be similar to present petroleum fuels when sold to
the consumer-
*
**
Barrels per stream day
Tons per stream day
3-25
-------
Table 3-2. Properties of Conventional
Hydrocarbon Liquid Fuels
Elementa Composition
Boiling Point, °F
Density, Liquid, lb/ft3
Specific Gravity, Liquid
Heating Value Liquid
Volumetric Gross, B/ft
Volumetric Net, B/ft3
Weight Gross, B/lb
Weight Net, B/lb
Air for Combustion - Liquid
O2 Weight, Ibs/lb
N2 Weight, Ibs/lb
Air Weight, Ibs/lb
Products of Combustion Liquid
CO2 Weight, Ibs/lb
H2O Weight, Ibs/lb
N2 Weight, Ibs/lb
Flame Velocity, ft/sec
Ignition Temperature, °F
Research Octane No.
Cetane No.
Gasoline
C 84 . 90% by wt
H2 15.02%
S 0.08%
89 - 406
45.5
0.7275
941, 850
877, 740
20, 700
19,290
3.455
11.49
14.945
3.004
1.342
11.494
1.4
536 to 804
92 100
18
Naphtha
C 84.7% by wt
H 15.3%
95 to 450
48
0.77
974,400
905,472
20, 300
18,864
3.470
11.547
15.017
3.103
1.367
11.547
1.10
450 to 530
30 to SO
NAb
Kerosene
C 84% by wt
H 16% by wt
300 = 480
50.6
0.811
1,012, 000
941, 160
20, 000
18, 600
3.455
11.495
14.950
3. 114
1.341
11.495
-
490
30 50
56 40
Diesel Oil
and No. 2
Fuel Oil
C 85
H 14
S 1%
380 - 650
53.4
0.856
1,046, 301
987,017
19,590
18,480
3.281
10.919
14.200
3.218
1.057
11.019
-
490
30 - 50
56-40
Property data are for petroleum-derived products. Fuels from oil shale are expected to be similar.
Coal-derived fuels may show some differences due to higher aromatic content.
Not available, estimated to be between 18 and 40.
3-26
-------
3.2 , SUITABILITY FOR USE AS AN ENGINE FUEL
Little information is available on the use of synthetic gasoline
or distillates in automotive engines. In the post-World War II period, the
Bureau of Mines produced some motor gasoline from the liquid phase catalytic
hydrogenation of sub-bituminous coal. There were no obvious product quality
problems; in fact, the gasoline was successfully field-tested in Army vehicles
under sustained high load conditions. The Navy successfully tested, in sea
trials, a boiler fuel produced from coal via the FMC Corp. COED process in
late 1973. With regard to shale oil, a diesel oil prepared from this source
was used in the 1950s to fuel a locomotive operating between Denver and Salt
Lake City. (Ref. 3-6)
On the basis of the limited information cited above, it is evi-
dent that there is need for a test program to investigate the compatibility of
these coal and shale derived synthetic fuels with automotive engines. Such an
effort is planned for FY 1975 under an interagency agreement between EPA
and the Bureau of Mines. An experimental effort by the Bureau of Mines will
investigate the combustion characteristics of synthetic fuels followed by field
tests to reveal the feasibility and limitations of these fuels in the operating
environment of current road vehicles.
A qualitative assessment of the synthetic fuels' compatibility
with four classes of engines is shown in Table 3-3. The estimates are based
upon the fact that shale-derived transportation fuels will probably be almost
indistinguishable from conventional petroleum fuels, while coal-derived fuels
will have a much higher aromatic content. In the case of blended petroleum-
synthetic fuels, of course, any differences in properties will be mitigated.
As indicated in the table, the synthetic fuels would be expected to have about
the same compatibility characteristics as their petroleum analogues.
3-27
-------
Table 3-3. Fuel/Engine Compatibility (Ref. 3-7)
Engine Class Characteristics
Car Compatibility Rating3 With Indicated Engine Class
F/A Conditions :^r"
Combustion
Ignition
Homo.
Inte rmit.
Spark
Fuelf
Pet. Gasoline
Pet. Distillate
Shale Gasoline
Shale Distillate
Coal Gasoline
Coal - Distillate
4
Id
4
Id
4gh
Id
Hetero
Intermit.
Sp, GP,PIb
4
2f
4
Zf
4h
2fh
Hetero
Intermit.
Comp.
Ze
4
2e
4
2 eh
3i
Hetero
Continuous
NA
4
4
4
4
Footnotes:
Compatibility Rating
4 No car modifications required
3 Minor modifications required
2 Major modifications required
1 Not practical
Letters indicate modifications required as described below.
Types of Ignition
Sp Spark
GP Glow Plug
PI Pilot Injection
Engines in the Various Classes
Class
A/F
Combust,
Homo. Intermit.
Hetero. Intermit.
Hetero. Intermit.
Hetero, Continuous
Ignition
Spark
Spark, etc.
Compression
Engine Types
Otto Cycle; reciprocating and rotary
Stratified charge; recip. and rotary
Diesel Cycle; recip. and rotary
Gas Turbine, Stirling, Rankine
Modifications Required Relative to Current Engines
Octane number and volatility too low
Will require very high compression ratio (~22) for satisfactory ignition (current
compression ratio ~15)
Pilot injection requires a secondary fuel & injection system; Spark requires installation
of electric system plus distributor; Glow Plug requires installation of electric resistor
in combustion chamber and necessary ancillary electric rig.
Change carburetor jets
May need some changes in gaskets, diaphragms, hose or other elastomeric parts in
fuel system
Low cetane number may require special starting technique
May require modification in combustor design, for better cooling, cleaner combustion,
reduction in smoke
3-28
-------
3.2.1 Fuel Economy Effects
In general, fuel economy for these liquid hydrocarbon fuels
will be more a function of the thermal efficiency differences between engine
types than between fuels. However, there is some variation in heat content
for these fuels, as can be noted from the data in Table 3-2. Generally, the
heating value on a weight basis increases as the specific gravity decreases.
Thus, gasoline with a specific gravity of 0.73 contains 19, 290 Btu/lb while
No. 2 fuel oil with a specific gravity of 0.86 contains 18,480 Btu/lb. Con-
versely, the volumetric heat content varies directly with specific gravity.
The preceding numbers are pertinent to petroleum-derived fuels. The trend
to higher aromatic content for coal liquids and shale liquids will provide a
lower heating value on a weight basis but higher volumetric values.
3.2.2 Emission Effects
Emission data are not yet available for synthetic hydrocarbon
fuels in current or advanced automotive engines. There is a definite need
for such test data despite the general similarity of the synthetic fuels to their
petroleum derived counterparts. A first step in obtaining such information
is a planned interagency agreement between EPA and the Bureau of Mines
which established a program for an engine combustion investigation with
gasoline and diesel fuel derived from coal and shale, as well as fuel blends
with petroleum-derived fuels. The program is expected to be completed
during FY 1975. Physical, combustion, and emission characteristics are to
be determined in engine dynamometer tests in order to reveal the feasibility
and limitations in the use of synthetic fuels in contemporary automobile
engines. Follow-on work of a similar nature will be necessary to evaluate
the synthetic hydrocarbon fuels in advanced engines; e.g., Rankine and
Brayton cycle external combustors.
3.2.3 Toxicity Effects
The following paragraphs are general discussions of health
hazards involved in handling these fuels.
3-29
-------
3.2.3.1 Gasolines from Coal or Shale
These gasolines would be expected to contain the same range
of hydrocarbon types as petroleum derived gasolines. However, the con-
centration of aromatic hydrocarbons in the coal-derived fuels is expected to
be relatively high. Experience has shown that gasoline of considerable
difference in compositions have the same general toxicological properties.
• Toxicity. Gasolines generally act as irritants to skin and
mucous membrane and as anesthetics resulting from
depression of the central nervous system. Mucous mem-
brane (eye, nose, throat) irritation may be produced by
vapor or liquid. Skin contact is irritating. On a prolonged
or repeated basis this contact may produce defatting of the
skin leading to dermatitis. Gasoline from coal, particularly,
should be evaluated for carcinogenic properties.
The oral toxicity of gasoline is low; however, the aspiration
effects are significant. Minute amounts of liquid gasoline
•which may be drawn into the lungs can be rapidly
fatal.
The dermal toxicity of gasoline is low. It is doubtful that
toxicologically significant amounts can be absorbed through
the skin.
The most important route of entry of gasoline is by inhalation.
Excessive exposure to gasoline vapors may induce symptoms
of alcoholic intoxication including a feeling of fullness in the
head, headache, blurred vision, dizziness, unsteadiness,
nausea, and allied symptoms. The time of onset and the
severity of these signs and symptoms is inversely related to
the concentration. The olefin and aromatic content of the
gasoline is important as these materials are more potent
3-30
-------
anesthetics. The irritant properties of the vapor cannot
always be relied upon to provide an adequate warning.
The question of effects from long-term exposure to low level
of petroleum-derived gasolines is controversial. Vague and
ill-defined effects have been suggested, but no well-documented
cases exist. The amount of benzene present in any gasoline
assumes importance where prolonged or repeated low level
exposure is possible. Benzene causes the destruction of the
blood-forming organs leading to aplastic anemia and has been
implicated in certain cases of leukemia. No reports have
been made of such effects from benzene-containing gasolines,
but the exact exposure levels are not known.
• Hazard.
• Oral ingestion. low apart from risk of aspiration
• Skin penetration. low
• Vapor inhalation, high, particularly in confined
space where vapor concentrations can build up rapidly
• Skin, eye, nose, and throat contact, moderate
risk of irritancy.
3.2.3.2 Distillates from Coal or Shale
These distillates would be expected to contain the same range
rocarbon
range.
of hydrocarbon types as petroleum distillates in the 380 to 650 F boiling
Toxicity. Distillates generally act as irritants to skin and
mucous membranes. Toxicity is low by the oral, dermal,
and vapor inhalation routes. However, aspiration, the entry
of small amounts of liquid hydrocarbon directly into the lungs,
rapidly produces severe injury to lung tissues which may be
fatal. The low volatility of distillates precludes vapor build-
up unless the liquid has been heated.
3-31
-------
Skin contact may be irritating and on a prolonged bases can
remove sufficient fat from the skin to result in a dermatitis.
Distillate from coal, particularly, should be evaluated for
carcinogenic properties. Eye contact results in only slight,
transient irritation.
• Hazard
• Oral ingestion. low apart from risk of
aspiration which is very hazardous
• Skin penetration. low
• Vapor inhalation, low
• Skin, eye, nose, and throat contact, low risk of
irritancy, increasing with increased severity of
exposure.
3.2.4 Safety Effects
Only a few general comments need be made since these fuels
are in general use now, and the safety effects of coal or shale-derived
material should be similar to those of current fuels. Fire and explosion are
the principal hazards, particularly for the lower boiling fractions such as
gasoline. Higher boiling fuels, such as diesel and fuel oils, present only a
fire hazard due to their low volatility.
3.2.5 Handling, Storage, and Distribution Requirements
As for the two preceding topics, the current widespread use
of these hydrocarbons obviates the need for an extended discussion of handling,
storage and distribution requirements. In fact, it is particularly these factors
that make such fuels so attractive as alternatives to their petroleum-derived
counterparts.
3-32
-------
3.2.6 Critical Research Gaps
From an overall standpoint, the most important technical gap
is in the production processes for obtaining these fuels from coal or shale.
To date, the preponderance of federal R&D funding in the fuel-from-coal
area has been for gas production, although there are recent indications that
there will be some shift toward support of coal liquefaction technology. In
the engine performance and emissions area there is essentially no experi-
ence in automotive usage for these synthetic fuels. The Bureau of Mines
synthetic fuels evaluation program, planned for FY 1975, should furnish
valuable data on engine compatibility and exhaust emissions, at least for
current road vehicles.
3.3 CURRENT STATUS
There is no current commercial production of liquid fuels
from coal or shale in the United States although a number of pilot plants
have been built and operated. The problem of coal liquefaction differs from
that of gasification because an acceptable technology for liquefaction has yet
to be proven (Ref 3-8). The buildup rate of a synthetic-liquid enterprise
in the United States is therefore dependent,among other factors, on the rate
at which technology is developed. The technical situation for shale extraction
is somewhat better with at least one retorting process available for near-
term commercial scaleup. The forecasted production schedule and limiting
factors are discussed in detail in Section 3. 4.
3.4 PROJECTED STATUS
3.4.1 Availability
With regard to shale oil, many uncertainties make it difficult
to predict production levels through the rest of the century. On the one hand,
the resource base is extensive, the cost of production is moderate, and the
technology is fairly well developed. On the other hand, there are very sig-
nificant environmental problems: federal leases must be made available in
3-33
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adequate number and economic size, and the capital-intensive mining and
retorting must be carried out in remote locations.
The National Petroleum Council forecast (Ref. 3-8) was pub-
lished in December 1972, prior to the Arab oil embargo, the declaration of
"Project Independence", and the probable congressional funding of substantial,
energy-related R&D. In this document, the maximum shale oil production
rate on a non-emergency basis was forecast to reach 750 Mbbl/day in 1985.
An intermediate rate would be 400 Mbbl/day. Detailed forecasts were not
made beyond 1985.
A more recent appraisal of the projected capacity and produc-
$
tion buildup of shale oil was made by Esso Research and Engineering Company
(Ref. 3-6). Their preliminary schedule is shown in Table 3-4. Production
increases from 400 Mbbl/day in 1985 to 900 Mbbl/day in 1990 and to
3,200 Mbbl/day in 2000, corresponding to a 15 percent/year growth rate.
A growth rate of that magnitude over that time span is possible but uncommon,
as an example, for tonnage petrochemicals. The forecast also makes the very
important assumption that in-situ recovery methods will become available in
the 1985 to 1990 period. As stated, these projections indicate that shale oil
cannot meet the total expected transportation fuel demand and that conventional
petroleum or other synthetic fuels would also be needed.
Reference 3-8 also presents several rates for coal-derived
liquid fuel production buildup. For the intermediate supply case, the first
commercial plant of 30 Mbbl/day would come on stream in 11 years (1985) with
a second plant of 50 Mbbl/day added about 4 years later. A faster buildup is
also visualized under greater economic incentives or new government policies
but still limited by technology growth. This maximum case predicts 1984
production at 200 MB/day, reaching 680 Mbbl/day by 1987.
The initial coal-derived liquid fuel forecast by Exxon (Ref. 3-6)
is shown in Table 3-5. They postulate 100 Mbbl/day liquid production by 1982,
growing to 900 Mbbl/day by 1990, to 2700 Mbbl/day by 2000. This represents
*
Mbbl/day - thousands of barrels per day
*-,-
Currently Exxon Research and Engineering Company
3-34
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Table 3-4. Plausible Schedule for Buildup
of Shale Oil Capacity and
Production (Ref. 3-6)
Year
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
2000
Nominal Capacity, Mbbl/ day
at Year End
100
150
200
300
350
450
500
600
700
800
900
1, 000
1, 100
1, 250
1,400
1, 600
1, 800
3, 500
Average Production, Mbbl/Day
During Year
50
100
150
200
250
300
400
500
600
700
800
900
1, 000
1, 100
1, 200
1,400
1,600
3,200
Notes: For above schedule to be achieved, it is assumed that engineering
and purchasing would begin 3-1/2 to 4 years before the startup
of each plant, and that construction would begin at least 3 years
before plant startup. For example, if an average of 50 Mbbl/Day
of shale oil is to be produced from the first plant during 1979 then
this plant would have to start up early in 1979. In turn, the con-
struction would have to begin by mid-1975, while engineering and
purchasing for the plant would have to start before the end of 1974.
3-35
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Table 3-5. Plausible Schedule for Buildup of
Coal Liquids Production (Ref. 3-6)
Year
1980
1981
1982
1983
1984
1985
1990
1995
2000
Nominal Capacity,
Mbbl/Day
at Year End
50
100
200
300
400
500
1, 000
1,800
3,000
Average Production,
Mbbl/Day
During Year
50
100
200
300
400
900
1,600
2, 700
Coal
Required
Million STa
6
12
24
36
48
108
192
324
aln terms of short tons of bituminous coal. Corresponding tonnages of sub-
bituminous coal or lignite would be higher because of the lower Btu contents
of these lower rank coals.
about a 19 percent/year growth rate, reflecting the fact that production of coal
liquids will be started later than shale, due to the remaining technology to be
developed.
Exxon points out that the production levels indicated in their
tables are total liquids and not automotive transportation fuels. There will
be a certain fraction of the syncrude which will be outside the gasoline and
distillate boiling range. This issue will have to be considered further before
making projections of total alternative automotive fuel production. Subordinate
issues include: (1) trends in petroleum refinery conversion; (2) expected
automotive transportation fuel demand; (3) the best way to process shale and
coal syncrudes, both before 1990 when they will still be a fairly small fraction
of the total crude oil and after 1990 when they could become a sizable fraction.
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The outlook for liquid fuel production from organic solid waste
is highly speculative. Most development and pilot plant work will be confined
to utilization of municipal waste, although design studies are being made of
plants to convert wood processing and logging wastes to oil. A full-scale
commercial plant incorporating the Bureau of Mines hydrogenation process
for either animal or wood wastes could be operational in 1980 (Ref. 2-4). The
Garret pyrolysis plant in Southern California is scheduled to begin operation in
1974; it is a 200-ton-per-day demonstration plant processing municipal solid
waste; the product oil will be sold to the San Diego Gas and Electric Company
(Ref. 2-4). The city of Baltimore is planning to install a 1, 000-ton-per-day
pyrolsis plant but the product is a low-Btu gas (Ref. 2-4). The buildup rate
of oil production from such sources is expected to be slow with almost insig-
nificant amounts by 1985. Most of this fuel will probably be sold locally for
central station power generation.
3.4.2 Projected Consumer Costs
Some preliminary economic data from Exxon Research and
Engineering Company are given in Table 3-6. The total cost at the service
station pump (ex taxes) is the sum of: (1) the syncrude cost plus refining
cost, given in the second column of the table; and (2) distribution costs,
which include transportation of the syncrude to the refinery, transportation
of the refined product to the service station, and the service station markup.
Of these cost factors, the greatest uncertainly lies in the cost of the syncrude,
since all others can be reasonably estimated from conventional petroleum
product costs with minor adjustments.
The economics of a specific shale oil recovery project are
quite sensitive to location, not only from the viewpoint of the richness of
the shale but also reflecting water availability, shale disposal facilities,
general terrain, etc. The costs associated with a substantial influx of con-
struction and operating manpower to a sparsely populated region of the
country must also be considered. The first few plants will also be more
expensive due to incomplete demonstration of technology and need for
3-37
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Table 3-6. Preliminary Economics of Coal and Shalea Fuels (Refs. 1-2 and 3-2)
FUEL
Gasoline from Coal
Distillate from Coal
Gasoline from Shale
Distillate from Shale
Gasoline from Petroleum
Distillate from Petroleumd
COST F.O.B REFINERY, b
$ /Million Btu
2. 15
1.50
1.60
1. 00
2. 15
1.80
DISTRIBUTION COST,0
$ /Million Btu
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL COST (EX TAXES),
$ /Million Btu
3. 15
2.50
2.60
2. 00
3. 15
2.80
3 1973 dollars, 10% DCF
b!00 MB /day plant
clncludes transportation from Western U.S. to Chicago refinery, refinery to service station;
includes service station mark-up
Average of current prices
I
Co
oo
-------
equipment modifications. The effluent from the retorting operations is too
viscous to be piped and will either be processed at the mine to a high quality
syncrude or subjected to minimum processing at the mine to reduce viscosity
to the point where it is pumpable. Except for the construction of spur lines,
it is expected that existing pipelines can be used to transfer the syncrude
from the first few plants either to Midwest or Gulf area refineries; the West
Coast should be supplied with adequate petroleum from Alaska. Pipeline
transportation costs in any event, make a relatively small contribution to the
retail cost (ca. 10^/MMBtu).
With respect to coal liquefaction, it is assumed that the
industry -will be associated with western strip-mined coal. This reflects the
large resource base in this area as well as low mining costs. Western coal
has a further economic advantage because much of it has low sulfur content.
The coal syncrude can be processed by extension of conventional refining
technology. The refined gasoline or distillate from both shale and coal will
probably be blended with petroleum-derived analogues for quite a long
time.
Cost data for gasoline and distillate from petroleum as of
October 1973 are compared in Table 3-6. More recent events have brought
the cost of imported petroleum to a level above the cost-plus-return-on-
investment level estimated for synthetic fuels derived from domestic
resources. Whether this will continue is dependent on events outside the
U. S. , in particular, on decisions made by the petroleum exporting countries.
3.4.3 Capital Costs and Timing Implications
Capital cost estimates are available from a limited number of
sources. Reference 3-8 presents some capital requirement estimates for
coal and shale derived synthetic fuels. In the former case, the basis of
calculations was $7,400 per barrel-day for the first 80, 000 barrel-day and
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$6, 500 per barrel-day thereafter. These costs apply to the liquefaction
plant only. The resulting synthetic liquid plant investment for maximum pro-
duction (Case I of Reference 3-8) would reach $590 million in 1980 and
$4. 5 billion (cumulative) by 1985. In the intermediate case, the $590 million
would not be reached until 1985. Associated mine investment is difficult to
ascertain from the data given, since it also includes costs to support syn-
thetic gas plants. However, it appears that mining capital for liquefaction
only would be something less than half the liquid plant costs. The statement
is also made that the annual investment rate for Case I would be about
$3 billion in 1985 for the coal gasification and liquefaction industry, or
approximately one-third of the 1970 total combined investment rate of the
chemical and petroleum industries. While no detailed study was made, such
a rate of investment in 1985 appears to be feasible (Ref. 3-8).
Reference 3-9 presents plant investment costs for the H-Coal
process for several ranks of coal and products produced. Capital costs run
from $5, 500 to $6, 820 per barrel-day of product produced for a plant making
about 65, 000 barrel-day. Reference 3-10 gives an investment cost of $6,300
per barrel-day of coal-derived liquid for a 100, 000-barrel-per-day plant,
with an additional investment for a mine of $152 million or $1, 520 per barrel-
day. This plant uses the Solvent Refined Coal Process. It can be seen that
these cost figures are in the same general range as given by the National
Petroleum Council.
For oil-shale recovery, capital cost data are first quoted
from Ref. 3-8. Using Case I (maximum production rate) as a basis, cumu-
lative investment would be $4 billion for a total production of 750, 000-barrel-
day or $5, 330 dollars per barrel-day of synthetic oil. Total industry invest-
ment would actually be about $5 billion by 1985, since 4 of 12 scheduled plants
would still be under construction. The maximum annual rate of investment
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would be $700 million per year. It can be seen that the investment cost per
barrel-day is less than for coal since the shale costs include mining costs.
The Bureau of Mines in Reference 3-11 gives a total investment
cost of $426 million for a 100, 000 barrel-day plant of $4, 260 per barrel-day
produced. For in-situ recovery, costs are $123 million for a 35,000-barrel-
per-day plant or $3, 520 per barrel-day of capacity; the in-situ figures are
very speculative, however. The difference between the National Petroleum
Council figures and those from the Bureau of Mines may be due to the fact
that the former is an average value for many plants, some of which are
smaller than 100, 000-barrel-day; also, the first plants will probably be more
expensive.
Capital investment costs for liquid-fuel production from
agricultural or municipal wastes have not been documented; it is expected
that they would be even more uncertain than costs for coal or shale
conversion.
3.4.4 Impact With Other U.S. Energy Requirements
The liquid fuels that can be obtained from coal or shale have
primary utility in the transportation sector, although they possibly could be
utilized for intermediate and peak load turbines in central station electric
power plants. As electric generation turns more and more to nuclear power,
transportation demand will be the major utilization sector for liquid fuels.
Certainly through 1985, and most probably to year 2000, combustion of con-
ventional liquid fuels will predominate in the transportation market (Ref. 1-1);
this forecast assumes no significant trend to electric cars. Thus, the major
impact will be in easing U. S. requirements for imported fuels, although the
degree of relief afforded by synthetic liquid fuels will be small to year 2000.
Assuming the crude oil recovery plants are located at the
mines, the energy required to produce these fuels will come primarily from
the local sources of coal and shale except for transportation of the products.
Thus, these industries should not be significant consumers of other energy
sources.
3-41
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3.4.5 Factors that May Inhibit Use
There are many factors that will govern the rate of growth of
these fuel sources. Obviously, economics are important, both product prices
and capital investment costs. However, assuming that these factors are
favorable or not limiting, other considerations may be, as pointed out in
Ref. 3-8. Certainly environmental effects, at least currently, are very
important, specifically strip mining of coal and spent shale disposal. For
coal liquefaction, there is some technological uncertainty that may delay
implementation of commercial scale plants. For shale, there is also some
question of the government leasing policy for shale lands. Leasing of the
first four of six 5, 000-acre tracts of government-owned oil shale land in
Colorado, Utah and Wyoming has recently been completed. However, the
present legal restriction of 5, 120 acres to any one party will prevent com-
mercial development on an economical scale over an extended period of time.
There have been recommendations from industry to at least double the acreage
restrictions (Ref. 3-8). In both cases, there are logistics problems con-
cerned with availability of trained manpower, industry's capability to supply
heavy mine and plant equipment, and sufficient water resources. The intent
of this listing is not so much to imply that these factors will prevent eventual
development of our coal and shale resources but to indicate the complexity of
such development and perhaps explain why they will not be a major source of
our energy supply for many years to come.
3.4.6 Critical Technology Gaps
It has already been mentioned that coal liquefaction requires
further technological advancement. The problem is not one of technical
feasibility but in selection of the best unit operations, defining optimum
product mixes and operating conditions, demonstrating equipment life,
evaluating scaleup effects, tailoring the process to the coal characteristics,
and achieving credible cost estimates for large scale plants. Solution of
3-42
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these problems takes time and infusion of more money, both public and
private, than has heretofore been allocated. There is evidence that such
funding will be forthcoming soon (Ref. 3-12). In the area of oil shale utiliza-
tion, the above-ground retorting and upgrading processes are satisfactory for
initial commercialization. Technical problems involve environmental con-
siderations in spent shale and water disposal, mining, and scaleup effects;
however, considerable progress has been made in these areas. In-situ
processing is essentially in its infancy. At present, two in-situ research
projects are under way but this approach is many years from commercial
realization (Ref. 3-11).
In conversion of organic wastes, only the pyrolysis process is
approaching commercial application, and most of this effort is directed toward
reducing solid waste volume and generating low-Btu gas. The hydrogenation
process being developed by the Bureau of Mines is barely out of the laboratory
stage; economic feasibility is now being addressed. The principal technical
problem is the development of methods for handling the solids and introducing
them to the reactor under pressure. Other problems include refinement of
the process for maximum oil yield, separation of oil from the solids, and
minimization of air and water pollution. The third process, bioconversion,
is less advanced than the others; since its fuel product is methane, it is out-
side the scope of this section (Ref. 2-4).
3.4.7 Potential for National and Regional Transportation Use
Because the synthetic petroleum-like fuels will be almost identi-
cal to the fuels now utilized in the transportation sector, the potential for
employment is high if their cost is competitive. They do not, in themselves,
provide lower emissions or higher efficiency in current engines but they are
selectively compatible with advanced powerplants based on Brayton, Rankine,
or Stirling cycles. Until such time as electric cars or hydrogen-fueled
vehicles might dominate the population, these fuels will find ready markets.
That time will probably be after the year 2000.
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SECTION 4
-------
SECTION 4
METHANOL AND METHANOL-GASOLINE BLENDS
4.1 CHARACTERIZATION
4.1.1 Fuel Type
Methyl alcohol, or methanol as it is commonly called, is the
hydroxyl derivative of methane with the formula, CH.,OH. It is a colorless,
chemically neutral flammable liquid at ambient temperature with a mild
odor. Originally derived as a by-product from destructive distillation of
wood (wood alcohol) in the manufacture of charcoal, it is now chiefly pre-
pared synthetically from hydrocarbon raw materials stemming from petro-
leum, natural gas, or coal sources. The earliest manufacturing process was
developed in Germany and France shortly before World War I, and is still in
use at the present time. It involves the catalytic hydrogenation of a synthe-
sis gas containing carbon monoxide at elevated pressure and temperature.
More recent processes are generally refinements of the carbon monoxide
route. An outgrowth of the early work on carbon monoxide-hydrogen reac-
tions led to the Fisher-Tropsch process for the manufacture of synthetic
hydrocarbon fuels, alcohols, and related products.
Industrially, methanol is used chiefly as a solvent and precur-
sor in the manufacture of plastics, resins, and organochemicals; it has
been used as an automotive antifreeze, as an automotive fuel in racing,
and as a reciprocating aircraft engine fuel injectant. Recently, because
of lower market prices, methanol has been proposed for use as a bulk fuel
to be manufactured at overseas sites where abundant natural gas resources
exist. It would then be transported as a low volatility liquid (compared to
LNG) and used as a fuel either in its liquid form or decomposed thermally
or catalytically into combustible gases.
4-1
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The methanol of commerce is generally defined according to
ASTM standards in terms of purity, specific gravity, etc. A typical speci-
fication is shown (Ref. 4-1).
ASTM D1152-58 (adopted 1954; revised 1958)
Methyl alcohol (methanol) (99.85% grade) shall conform to
the following requirements:
Specific gravity 20/20°C
Color
Distillation range:
below 64.0°C
above 65.5°C
Nonvolatile matter
Odor
Water
Acidity (free acid as acetic)
Not more than 0.7928
Not more than No. 5 on the platinum-
cobalt scale
None
None
Not more than 0. 005 g/100 ml
Characteristic, nonresidual
Not more than 0. 15% by weight
Not more than 0. 003% by weight
(equivalent to 0.028 mg KOH per
gram of sample)
Potassium permanganate test Color of added KMnO4 must be
retained at least 30 min at 15 + 0.5°C
in the dark
Acetone
Not more than 0.003% by weight
The product is shipped in one-gallon metal containers, five- or
55-gallon metal drums, or tank cars. The latter normally are loaded and
unloaded by pump. Methanol can be shipped in the same tank cars used for
petroleum products but precautions are taken in cleaning to prevent contami-
nation. In dry air, the flammability ranges between 6.7 to 36 percent (by vol).
Therefore, each shipping container must bear the ICC red label for "flamma-
ble liquids", and each tank car or railroad car carrying methanol must be
provided with ICC "Dangerous" placards. In addition, a certain caution
label, accepted by the U.S. Public Health Service, and indicating the product
to be flammable and poisonous, is affixed to all containers. Other cautionary
labels are prescribed by some states.
4-2
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4.1.2 Reserves or Raw Material Sources
Practically any organic matter, including fermentable matter,
can be used to produce gases for the direct synthesis of methanol. The
primary constituent of the synthesis gas is hydrogen along with carbon monox-
ide and frequently carbon dioxide. This is discussed in more detail in
Section 4. 1.3. The most economical domestic starting materials at present
are hydrocarbons derived from natural gas or naphtha. Estimates of
natural gas resources total 1,412 trillion cubic feet which is equivalent to about
1450 x 1015 Btu. In addition, 6. 8 billion barrels (27 x 1015 Btu) of natural
gas liquids are believed to be recoverable. Crude oil reserves from which
naphtha is made exist as assured reserves in the amount of approximately
36 billion barrels (210 x 10 Btu) and,when added to estimates of undiscov-
ered and other resources, total resources of 472 billion barrels (2739x 10 Btu)
are projected. These liquid and gas supplies represent approximately 40 tril-
lion gallons of manufactured methanol.
_,;
However, any future production of methanol for transportation
fuel would more likely come from solid fuels as starting materials for meth-
anol synthesis. Solid substances are more difficult to handle and process,
producing undesirable solid wastes (ash) for example, or causing a greater
diversion of the available thermal energy to supply the required stoichiome-
tric amounts of hydrogen/carbon oxide gases. The primary constituent of
synthesis gas is hydrogen, along with carbon monoxide and frequently carbon
dioxide. Chemically bound hydrogen in reduced form is preferred as a start-
ing raw material, but at one time the cheapest source of synthesis gas in this
country was "blue gas" produced by the action of steam on coke. United
States forest areas represent a potential source of organic raw material for
methanol manufacture since methanol is obtained as a by-product in the dis-
tructive distillation (pyrolysis) of wood or coal, producing wood char and coke
Coal is by far the largest and most probable single energy
resource available for synthetic fuel production with an estimated total
18
U.S. coal in place of about 3.2 trillion tons (80 x 10 Btu). This represents
4-3
-------
a potential of about 500 trillion gallons of manufactured methanol based upon
the conversion factor in Table 4-1.
In certain areas of the world where coal or lignite was abun-
dantly available at prices highly competitive with other fossil fuel resources,
coal's use as a source of methanol or liquid fuel synthesis gas was dictated
in the past. Between 1936 and 1939, a total of nine plants were erected in
Germany to produce synthetic liquid gasoline from coke and coal . They
became obsolete after World War II (Ref. 4-1). The capacity of most of these
plants was less than 200 tons/day (20 million gallons/yr), which is not large
by today's standards. Japan was also using coal as a raw material source by
1939. The largest and most modern plant to use coal (low grade) as a syn-
thesis gas source for hydrocarbons and alcohols was put into operation at
Sasolburg, South Africa in 1955. This plant is still operating (Ref. 4-2).
While coal represents an extensive, available solid fuel energy
resource, other solid materials also offer potential for methanol production.
Shales in the western United States are believed to contain liquids in amounts
18
up to 1780 billion barrels (10 x 10 Btu). The practicality of converting to
methanol is doubtful as it is more likely these liquids would be consumed
directly as hydrocarbon fuels.
Szego, et al (Ref. 4-3) have proposed the "energy plantation"
concept as a competitor to coal, using wood forests to supply energy in
renewable form for electrical power generation. Correspondingly, U.S. for-
est areas represent a potential source of organic raw material for methanol
manufacture. As previously stated, methanol is obtained as a byproduct in
the destructive distillation of wood (wood alcohol) during the manufacture of
wood char, but this yields a small percentage of methanol. However, steam
gasification of wood char is proposed as an alternate route to synthesis gas
which could be converted to methanol (thereby increasing the yield percent-
age). The wood processing industry produces waste residues in the form
of bark, slash, sawdust, and other material. Some of this is presently used
to manufacture particle board and other products, but a good deal still goes
to waste. While resource availability has not been precisely defined, one
4-4
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Table 4-1. Methanol Production
Energy/Material
Resources
Coal to Methanol
2 tons of coal
(8500 Btu/lb)
About 1 tone of
oxygen
SNG to Methanol
30. Z million
Btu of SNG as
feed and fuel
75 kWhr power
7300 SCF CO2
144, 016 feed
water
13,200 gal cool-
ing water
Coal or Oil Shale I
1148 Ib naphtha
9. 7 million Btu
fuel
58 kWhr power
1600 Ib feed
water
12,700 gal cool-
ing water
Coal or Oil Shale I
2020 Ib heavy
oil {18,300
Btu/lb)
130 kWhr power
1680 Ib feed
water
19, 800 gal cool-
ing water
Name of the
Process
Use any gasifier
to make synthe-
sis gas, Lurgi and
others. (Oxygen
requirement varies
with the process)
Same
derived Naphtha to h
Same
derived Heavy Fuel
Same
Comment on the Process
Coal is gasified and con-
verted to CO + H^-rich
gas. The gas can be con-
verted to methanol 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 com-
pressed to 40-50 atm
and converted to methanol
in presence of copper-
containing catalyst at
200° - 300°C
/tethanol
Naphtha is converted with
steam to a CO and H£-rich
gas and then converted to
methanol in presence of
catalyst at 200°-300°C
Dil to Methanol
Heavy feedstock is con-
verted to synthesis gas
by partial oxidation and
then converted to meth-
anol in presence of
catalyst at 200°-300°C
Synthesized
Fuel
1 ton of
methanol
1 ton
methanol
1 ton
methanol
1 ton
methanol
By-Product
Small amount of
higher alcohol is
produced
Small amount of
higher alcohol is
produced
Small amount of
higher alcohol is
produced
Small amount of
higher alcohol is
produced
Thermala
Efficiency,
%
50
63b
59b
50b
Comments on Pollution
Sulfur removal problems are similar
to coal gasification problems .
Minimum pollution problems.
Sulfur removal is necessary for
feedstocks containing sulfur.
Sulfur removal problems are similar
to coal gasification problems .
I
(Jl
aThermal efficiency based upon higher heating value of input and output streams, including by-products.
Does not include energy involved in producing liquid or gaseous hydrocarbon raw materials from coal or shale.
-------
estimate (Ref. 4-4) indicates that sawmill and other mill processing operations
annually yield over 100 million tons of wood residues (conservatively 500 x
1012 Btu). Integration of methanol production plants with large wood process-
ing plants could advantageously utilize these wastes, which represent more
than 3 billion gallons of methanol per year. The key economic question to be
resolved is whether the insignificant cost of waste wood as raw material
would sufficiently offset plant equipment investment and product distribution
costs. Other fuel studies have been started which consider the use of agri-
cultural products as chemical raw materials. By the year 2000, up to 10 per-
cent of domestic natural gas fuel requirements could be obtained by biological
chemical conversion processes (Ref. 4-5). These gases could be used to
synthesize methanol.
Examples of other sources of usable gas include by-products
of industrial processes. Refinery gases containing hydrogen, metallurgical
process gas, and fermentation process gases are potentially "available.
Methanol was once prepared synthetically by the Commercial Solvents Com-
pany from butanol fermentation gases and by DuPont from impure ammonia
synthesis gases containing carbon monoxide. Generally speaking, these
processes result in small plant capacities which tends to prevent them from
competing against very large producers in the general chemical marketplace,
although they may prove adequate for captive production. In the case of off
gases from a basic oxygen furnace, economic studies have shown that the
largest steel installations produce only enough off gas to support a methanol
capacity of 250 tons/day or 25 million gallons/year. This is small capability
by present standards. Nevertheless, as the cost of available raw materials
continues to increase, the use of waste gases which otherwise have effectively
zero value will become increasingly attractive.
In order for methanol to continue as a viable fuel for combustion-
driven powerplants over the longer term, it could become necessary to resort
to raw materials that normally exist in a partially or fully oxidized state.
Hydrogen can be prepared by electrolyzing water or can be captured as a
by-product from certain electrolytic processes, such as brine electrolysis.
4-6
-------
Sources for manufacture of carbon oxides, particularly carbon dioxide,
include naturally occurring carbonates in the form of limestone and dolomite
deposits or even seashells. Carbon dioxide is potentially recoverable from.
air, in which it represents a relatively minor constitute (about 320 ppm).
A partial listing of domestic starting material sources
capable of conversion to synthesis gas follows:
a. Natural hydrocarbon gases and liquids
b. Natural hydrocarbon solids - lignite and coal deposits
and shales
c. Natural agricultural products - wood forests
d. Agricultural waste products
e. Industrial gases and by-products - refinery gases,
metallurgical process gases, fermentation gases, SNG,
electrolysis hydrogen, combustion flue gases, limestone
kiln gases, and others.
4.1.3 Methods of Manufacture
There are several processes in operation for the commercial
manufacture of methanol,with the basic synthesis steps represented by the
equations:
CO + 2H2 ^ CH3OH AH298°K = 21'684 cal
or
C02 + 3H2 ^ CH3OH + H20 AH298°K = -11'830 cal
The latter reaction may be considered to occur in two steps, viz:
CO2 + H2 ^ CO + H2O
CO + 2H2 ^ CH3OH
4-7
-------
The composition of the gas mixture varies with the source
material and the actual process operating conditions. Blue gas resulting
from the action of steam on coke is an older route mostly replaced by steam
methane reforming today. Since the latter process is current, it is covered
herein, but the coke process is very similar. Steam reacts with methane
to form a mixture of hydrogen, carbon monoxide, and carbon dioxide. The
resulting mixture is carbon deficient, and carbon dioxide is commonly added
into the process to promote the reverse-shift reaction. When higher hydro-
carbons are used, a higher proportion of steam is required to prevent coking.
The reactant mixture passes through catalyst-packed tubes in a furnace and,
after cooling and compression, goes to the methanol converter- The pressure
generally lies in the range of 50 to 400 atmospheres (750 to 6, 000 psi).
Recent trends have been in the direction of lower pressures using improved
catalysts.
The catalytic conversion to methanol is the critical step in
the process. The type of catalyst used and the operating conditions signifi-
cantly influence the end-product composition. Many side reactions can take
place so that a spectrum of products is possible including higher alcohols,
aldehydes, ketones, hydrocarbons, etc. This is basically the Fischer-
Tropsch synthesis. The key to methanol catalysis involves choosing a highly
selective catalyst which does not promote carbon-carbon bond linkage. The
most prevalently used catalysts are the zinc-chromium oxides and zinc-
copper-aluminum oxides. In operation of the facility, several precautions
are usually taken. Gases must be purified to remove such contaminants as
sulfur and iron carbonyl to avoid catalyst poisoning. In addition, converter
temperatures are carefully controlled and the exothermic methanation reac-
tion, which can proceed rapidly, is avoided to prevent destroying the catalyst.
In general, temperatures around 300 C are reported to result in carbon
monoxide conversions of 15 percent. A typical flow sheet for the production
of methyl alcohol from natural gas is shown in Figure 4-1. After the con-
version step is completed, the crude methanol and water are separated by
4-8
-------
PREHEATED DESULFURIZED FEEDSTOCK
FUEL
STOCK
WATER PURGE
CONDENSER HEAT EXCHANGE 4
HIGH PRESSURE
STEAM RAISING
CONDENSER
PURGE
TOPPING
COLUMN
LOW
PRESSURE
STEAM
REFINING
COLUMN
WATER
CRUDE
VESSEL STORAGE
LOW
PRESSURE
STEAM
COOLING
HIGHER ALCOHOLS PURGE •
REFINED METHANOL-*-
Figure 4-1. Methyl Alcohol Production Processes (Ref. 4-6)
-------
condensation followed by distillation. The unreacted gases leaving
the separator are partly released (purge gas) and partly combined with
fresh synthesis gas to be recycled to the converter as shown.
Another similar process is the Fisher-Tropsch (F-T)
process mentioned previously, which produces commercial amounts of
methanol as a by-product. The major products are light gas and liquid
hydrocarbons, oils, waxes, and other chemicals.
A few representative reactions involved in Fisher-Tropsch
chemistry are as follows:
nCO + 2n HL ?i (-CH,-) + nH.O
L L n L
2nCO + n H, ^ (-CH,-) + n CO,
L £. TL £•
nCO + 2n H, ^ H(-CH,-) OH + (n-l)H,
£ c. n £•
CO2 + 3H2 ^ (-CH2-) + 2 H2O
The relative extent to which these reactions proceed in the
catalyst converter is somewhat controllable through catalyst selection and
reactor operation. The important catalysts are Ni, Ru, Fe, and oxides
such as ZnO and ThO-,. While most converter designs operate as fixed-bed
reactors, fluidized-bed conversion is also practiced. The latter is used
mainly with reduced iron catalyst at medium pressures. An overall picture
of the Sasol/F-T synthesis process is shown in Figure 4-2.
As has already been discussed, the primary sources of feed-
stocks for the above synthesis routes to methanol are naturally occurring
carbonaceous materials, water, and air. Several process routes are sum-
marized in Table 4-1 for the production of methanol from coal, gaseous
hydrocarbons, and liquids which can be derived from coal or shale deposits.
A two-state, liquid-phase process for low temperature hydro-
genation of carbon monoxide to methanol has been demonstrated. The process
4-10
-------
Air
Process water, steam,
and electricity
t
Nitrogen
*- Oxygen
Crude phenols
Ammonium suKate
»• Road prime
*• Creosote
*• Pitch
Entrainer benzene
Motor benzole
Toluol
Xylol
Light naphtha
Heavy naphtha
*• Reactor wax
•»• Soft waxes
Medium waxes
Hard waxes
>• Superhard wax
^ Fuel oil, cracking
stock, etc
Gasoline
*• Paraffin
*• Diesel oil
*• Liquid petroleum gases
Acetone
Methyl ethyl ketone
Higher ketones
Methanol
Motor alcohol
Ethanol
C3 and higher alcohols
>• Salts of lower fatty acids
Figure 4-2. Overall Scheme of the Sasol Plant
4-11
-------
involves the formation of methyl formate by reaction of CO on sodium
methoxide solution followed by hydrogenation in the presence of copper
chromite. This method has not been used commercially.
4.1.4 Physical and Chemical Properties
In terms of use as a. transportation fuel, methanol properties
are frequently compared to gasoline. Careful assessment of such compari-
sons is sometimes necessary because of the complex nature of gaso-
lines. For example, gasolines are composed of a range of molecular species
of hydrocarbons (usually C. - C,Q), each of which has a different boiling
point. This characteristic of gasoline results in a distillation curve which
generally begins about 90 F (recovery of first distillate) and ends at about
400°F. Alcohols and other pure chemicals do not have this characteristic
range of volatility. Boiling takes place at a given temperature as shown in
Figure 4-3. Some of the more volatile species of gasoline begin to boil at
temperatures below the boiling point of methanol. Presumably, if fuel
methanol were to achieve widespread usage, it too would be marketed as a
mixture of alcohols or perhaps blended with gasoline as many have suggested;
however, straight methanol is also being considered. In this section,
methanol is compared (see Table 4-2) with isooctane, a representative pure
hydrocarbon constituent of gasolines.
Methanol has many physical and chemical properties that are
similar to isooctane and, therefore, gasoline. Its heat of combustion is lower
than analogous hydrocarbons because it is in a partially oxidized state. How-
ever, it also has a higher heat of vaporization and better antiknock value than
isooctane. Unlike gasoline, it contains no sulfur. On the other hand, there
are some disadvantages. Because its heat release is somewhat less than
half that of gasoline, fuel mileage per gallon is reduced accordingly. It is
also completely miscible with water, which poses the possibility of contamina-
tion and corrosion problems.
4-12
-------
BUTYL ALCOHOL—
ETHYL ALCOHOL
METHYL ALCOHOL
20 30 40 50 60 70 80 90 100
FUEL EVAPORATED-Percent
(Lichty and Ziurys)
Figure 4-3. ASTM Distillation Curves for Gasoline
and Alcohol (Ref. 4-7)
4-13
-------
Table 4-2. Properties of Isooctane and Methanol (Refs. 4-1, 4-7, 4-8, 4-9)
Item
Formula
Molecular weight
Carbon to hydrogen weight ratio
Carbon, % by weight
Hydrogen, % by weight
Oxygen, % by weight
Boiling point, °F at 1 atm
Freezing point, °F at 1 atm
Vapor pressure, psia at 100 F
Density, 60°F, Ib/gal
Coefficient of expansion
1/F at 60°F and 1 atm
Surface tension, dynes/cm at
68°F and 1 atm
Viscosity, centipoises at
68°F and 1 atm
Specific heat of liquid,
Btu/lb-0Fat 77°F and 1 atm
Heat of vaporization, Btu/lb
at boiling point and 1 atm
Heat of vaporization, Btu/lb
at 77°F and 1 atm
Heat of combustion, at 77°F
Higher heating value, Btu/lb
Lower heating value, Btu/lb
Lower heating value, Btu/gal
Stoichiometric mixture, Ib air/lb
Research octane no.
Isooctane
C8H18
114.224
5.25
84.0
16.0
0.0
210.63
-161.28
1.708
5.795
0.00065
18.77
0.503
0.5
116.69
132
20, 556
19,065
110,480
15. 13
100
Methanol
CH3OH
32.042
3.0
37.5
12.5
50.0
148. 1
-144.0
4.6
6.637
0.00065
22.61
0.596
0.6
473.0
503.3
9,776
8,593
57,030
6.463
106
4-14
-------
4.2 SUITABILITY FOR USE AS AN ENGINE FUEL
4.2.1 Engine/Vehicle Compatibility
Methanol has been used for many years as a gasoline additive
(mainly to prevent carburetor icing) and as a power boost fluid in piston air-
craft engines. Probably the two most important factors which to date have
presented it from becoming a primary automotive fuel base are its low calo-
rific value, compared to gasoline, and its higher cost. It is considered to
be generally compatible for use in automotive vehicles powered by spark
ignition engines except for those factors noted in succeeding paragraphs.
Methanol is deemed suitable for use with continuous combustion systems
(e. g. , Brayton, Rankine, Stirling) and some effort has been reported regard-
ing fuel cell applicability. It is not suitable, however, for compression
ignition cycles because of its low cetane number.
From the standpoint of tankage and fuel transfer lines, corro-
sion inhibitors in the fuel may be necessary to prevent attach on carbon steel.
Methanol is known to cause swelling of various polymers such as vinyls and
acrylates but is reported to be satisfactory with certain silicones, neoprene,
butyl, styrenebutadiene, and other elastomeric components.
The boiling point of pure methanol is lower than that of the
bulk of the constituents of gasoline, which may result in a greater incidence
of vapor lock with current automobile fuel system designs. On the other hand,
the vapor pressure of methanol is substantially less than that of the very
lightest ends of gasoline. The latter being responsible for the good cold
start properties of gasoline, manifold preheating would probably be required
for cold starts with a carburetor methanol system.
In the case of methanol-gasoline, there is an additional problem
with regard to phase separation in the fuel tank. Water in the fuel distribution
system or automobile fuel tank causes phase separation which in turn could
lead to corrosion, rough engine operation, and starting difficulties.
Vapor lock problems may also be encountered with methanol-
gasoline blends because methanol has a very high blending-vapor pressure in
gasoline. The composition of the base gasoline would have to be adjusted to
4-15
-------
produce a lower vapor pressure. Then, in combination with methanol, the
blend could be expected to have vapor lock characteristics no more severe
than found with current gasolines.
4.2.2 Power and Fuel Economy Effects
With fixed spark-ignition engine design and operational
parameters (e. g. , compression ratio, displacement, fuel-air equivalence
#
ratio, etc. ), the use of methanol instead of gasoline results in an increase
in both output power and fuel consumption.
Power output is primarily determined by the heat of combus-
tion of the fuel per unit of air consumed, plus the effect of the latent heat of
vaporization of the fuel. The cooling effect caused by a higher latent heat
value decreases the compression work and tends to induct a greater mass of
air, thus resulting in improved volumetric efficiency. When contrasted with
gasoline, methanol has both a higher combustion energy value[(1335 Btu/
pound air compared to 1265 Btu/pound air for isooctane) (Ref. 4-lO)]and a
higher latent heat of vaporization (473 Btu/pound at boiling point and 1 atm
compared to 11 7 Btu/pound for isooctane at the same conditions — Table 4-3).
Thus, there is a noticeable increase in power output for methanol.
In the case of fuel consumption, vehicle fuel economy (miles/
gallon) and engine specific fuel consumption (Ib/hp-hr) are primarily a func-
tion of the heat of combustion per unit volume of fuel, with latent heat being
a secondary factor only. Methanol has a much lower heating value (8, 593
Btu/pound or 57, 030 Btu/gallon) than gasoline (19, 065 Btu/pound or
110, 480 Btu/gallon) (Table 4-2). Thus when methanol is used in place of
gasoline, there is an increase in fuel consumption, both in weight and vol-
ume by about a factor of two.
On the basis of miles per Btu, of course, the two fuels would
be approximately equal for equivalent engine designs, sizes, and vehicle
performance capability. If the effect of latent heat is considered, methanol
should have a slightly better miles/Btu fuel economy than gasoline, other
factors again being equal.
*
4> = Equivalence Ratio = fuel-air ratio/stoichiometric fuel-air ratio.
4-16
-------
Table 4-3. Simplified Comparison of Combustion Chemistry
between Methanol and Isooctane
Fuel
Constituent
CH3OH
C8?18
No.
of
Mols.
1
1
Weight
Ib.
32.0
114.2
Intake Air
No.
of
Mols
7. 15
59.5
Weight
Ib.
206
1,716
Combustion
Products
No.
of
Mols
8.65
64
Weight
Ib.
238
1, 830
Ratios
Mols
Prods
Mols
Air
1.21
1. 08
Ib Fuel
Ib Air
0. 16
0.07
Gal.
Fuel
Mol
Air
0.68
0.33
LHV,
Btu/lb Air
1,335
1, 265
-------
The higher antiknock quality of methanol (106 research octane
number vs 100 for isooctane, see Table 4-2) will allow the use of a higher
engine compression ratio for new engine designs. This can be used to further
increase power output, and to increase engine thermal efficiency with con-
comitant beneficial effects on fuel consumption.
Predicted increases in engine power output have been calcu-
lated for methanol compared to isooctane and other fuels by detailed computer
analyses (Ref. 4-8). An example of the cycle analysis results is shown in
Table 4-4. At equal equivalence ratio (^ = 1) and compression ratio (9:1),
the calculated compression work for methanol (101 Btu/pound) is below that
of isooctane (130 Btu/pound); the peak combustion temperature is lower
%
(4870°R vs 5200°R), while the peak pressure is higher (1300 psia vs 1240
psia). Thus, it follows that a methanol-fueled engine can achieve power
boost over a gasoline-fueled engine at the same equivalence ratio or equal
power at a leaner equivalence ratio.
Table 4-4. Chart Calculations of Cycle Characteristics
C.R. = 9:1, Intake Air = 100°F, 14.7 psia (Ref. 4-8)
Fuel
Isooctane, 0-0.8
Isooctane, 0=1.0
Isooctane, 0 = 1.2
Isooctane, 0=1.4
Methanol, 0=1.0
Methanol, 0 = 1.5
Ethanol, 0 = 1.0
Benzene, 0=1.0
Peak
Temperature,
R
4820
5200
5170
4910
4870
4360
5000
5315
Peak
Pressure,
psia
1000
1240
1200
1260
1300
1420
1255
1265
Cu Ft
of Mix/
Ib Air
13.89
13.92
14. 24
13.90
13.92
13.82
14.09
13.98
Compression
Work,
Btu/lb
130
130
126
125
101
109
111
128
= Equivalence Ratio = fuel-air ratio/stoichiometric fuel-air ratio.
4-18
-------
As already noted, the thermal efficiency of an internal
combustion engine may be improved by increasing engine compression ratio.
Calculated representative effects of compression ratio on engine indicated
mean effective pressure (IMEP) for methanol, isooctane, and other fuels at
various equivalence ratios are shown in Figure 4-4. In general, increasing
compression ratio from 8:1 to 12:1 is accompanied by 1 0 to 12 percent
increase in power at fixed stoichiometry, or roughly equivalent fuel savings
by operating with 1 0 to 12 percent leaner mixtures at fixed engine power.
Methanol with a research octane number of 106, compared to
100 for isooctane, can be used at a compression ratio as high as 15:1 (well
above the useful compression ratio for efficient combustion of isooctane or
alkyl-leaded high octane premium gasoline). However, most comparative
testing in the past has been conducted with engines of modest compression
ratio which may put methanol at a disadvantage from a fuel-consumption stand-
point, although it does allow direct comparison with standard gasoline fuels.
280 i—
METHANOL * = 1.0
METHANOL = 1.5
ISO-OCTANE = 1.0
ETHANOL <1> = 1.0
180 —
ISO-OCTANE 0 = 1.2
BENZENE = 1.0
ISO-OCTANE = 1.4
8 10 13 14 16
COMPRESSION RATIO
Figure 4-4. Calculated Performance Comparison (IMEP)
for Isooctane, Benzene, Ethanol, and
Methanol (wet charge) (Ref. 4-8)
4-19
-------
Starkman (Ref. 4-8) obtained comparison test results with a
CFR test engine operating at a 9:1 compression ratio. With this low com-
pression ratio and injection of fuel immediately ahead of the cylinder intake,
engine power output with methanol was found to exceed that for isooctane and
other fuels with a corresponding penalty in specific fuel consumption as shown
by Figures 4-5 and 4-6.
Ebersole and Manning (Ref. 4-9) performed an extensive fuel
characterization and comparison test series with a single-cylinder CFR
engine at 7. 5:1 compression ratio. They showed the effects of spark timing,
lean operating limits, compression ratio, and other variables on prevaporized
isooctane versus methanol performance. In general, the relative specific
fuel consumption figures agreed with those of Starkman. The indicated
specific fuel consumption (IFSC) was found to be 2. 15 times that of isooctane.
The lean operating (misfire) limits were found to be about = 0. 6 for
methanol versus = 0. 8 for isooctane.
Fitch and Kilgroe (Ref. 4-12) road tested a modified 6-cylinder
engine powered Dodge Dart and tested a laboratory engine, both fueled with
either methanol or predissociated methanol. Carburetion and manifolding
modifications were made but automobile test results tended to show mostly
rich operation and nonuniform distribution. Consequently, the vehicle fuel
economy obtained was reduced. They reported achieving 7 to 9 miles per
gallon. The spectrum of carburetor operation using different sets of fuel
control jets is shown in Figure 4-7. With a main jet diameter of 0. 063 inch
and an air correction jet diameter of 0. 060 inch, the proper equivalence mix-
ture was reached at about 45 mph. The vehicle ran lean above this speed and
rich below with this carburetor configuration. With a larger main jet (0. 070
inch), operation was continuously rich.
In the laboratory engine tests, various effects were studied on
a CFR engine. It was found that specific fuel consumption improves with
increased compression ratio (values up to 15:1 were tried), and the engine
could be operated at very lean mixture levels (4> = 0. 65). Specific fuel
4-20
-------
1.2 i—
5 1.0
i
o
t-
bj
> 0. 9
I-
£ 0.8
8
METHANOL
O ISO-OCTANE
D BENZENE
A METHANOL
0 ETHANOL
I
0.8
I lean)
1.0 1.2 1.4
0, EQUIVALENCE RATIO
J
1.6
Irichl
Figure 4-5. Comparative Performance Results (IMEP)
from Engine Normalized about IMEP of
Isooctane at = 1. 0 (Ref. 4-8)
3.5
3.0
1.0
O ISO-OCTANE
D BENZENE
A METHANOL
0 ETHANOL
(lean)
0.6
0.8
METHANOL.
ISO-OCTANE
1.0 1.2
EQUIVALENCE RATIO
1.6
(rich)
Figure 4-6. Comparative ISFC from Engine Results
Normalized about ISFC of Isooctane
at 4>= 1. 0 (Ref. 4-8)
4-21
-------
tSJ
8
<
a:
S 4
u.
O
LEAN
MAIN JET DIAMETER, in.
AIR CORRECTION JET DIAMETER, in.
0.063
CHEMICALLY CORRECT MIXTURE _^^ ° 0.060
RICH
IDLE
10
0.070
0.053
225 DODGE DART
32NDIX ZENITH CARB.
20 30
SPEED, mph
40
50
60
Figure 4-7. Air-to-Methanol Mixture Ratio as a Function of Speed (Ref. 4-1
1)
-------
consumption was generally about 1.2 Ib/hp-hr. Some slight improvement
was noted with partially (thermally) dissociated methanol.
Continuation of the above effort has been reported from
research at the University of Santa Clara (Ref. 4-12). A total of 191 tests
were made on the CFR engine. The data were normalized for comparison
between undecomposed CHgOH, decomposed CH-OH, and gasoline on the
basis of air-fuel equivalence ratio as shown by Figure 4-8. They showed
that peak power occurs at or close to the stoichiometric mixture and that
thermal efficiency increases as operation varies from rich misture to lean
mixtures. The fuels were prevaporized before entering the combustion
chamber.
In another investigation, Stanford University modified an
American Motors Gremlin to run on methanol (Ref. 4-13). Fuel economy
figures for this vehicle powered by gasoline showed about 18 miles per gallon,
which was reduced to 9 to 10 miles per gallon with methanol in a carbureted
engine. (This is approximately as predicted by the ratio of gasoline and
methanol-fuel heating values. )
4.2.3 Emission Effects
Only in the last several years has attention been drawn to
investigating exhaust pollution levels attributable to methanol fuel. Studies
of fuel blends containing up to 25 percent (by volume) methanol with isooctane,
n-heptane, and toluene were conducted by Ford Motor Company (Ref. 4-14).
Their conclusions indicated that methanol adversely affected aldehyde con-
centrations and unburned toluene in the exhaust under rich operation and did
not improve engine exhaust quality at lean equivalence ratios (4> = 0. 8). The
emissions appeared to be controlled primarily by the hydrocarbon constitu-
ents in the fuel. (Fuel blends are further discussed in Section 4. 2. 7. )
The exploratory single-cylinder engine tests conducted by
Ebersole and Manning (Ref. 4-9) give perhaps the most definitive data pub-
blished so far. In these tests, a 7. 5:1 compression ratio was used in the
CFR engine and provision was made to ensure good mixing and fuel
4-23
-------
100
o
•o
90
Of.
(U
5
O
O.
Ul
O
0.
i 80
70
60
GASOLINE
RICH -* »- LEAN
I I I
40 i—
Q
UJ
O
Q
30
>- *
O w
20
U.-J
U. '
UJ
10
ce.
UJ
RICH
^ — GASOLINE
LEAN
I
I
CH3OH
CO + H-
I
0.6 0.8 1.0 1.2 1.4
ACTUAL AIR-FUEL RATIO/STOICHIOMETRIC
AIR-FUEL RATIO - M"1
1.6
Figure 4-8. Gasoline and Methanol Performance
Comparison (Ref. 4-12)
4-24
-------
vaporization. Experimental data contour maps permit comparisons of
emissions, equivalence ratio, and power obtained with prevaporized fuel-air
mixtures. Several of these charts are shown for data obtained at an engine
operating speed of 1, 000 rpm. Figures 4-9 through 4-12 map the unburned
hydrocarbons, CO, NO, and aldehydes obtained over a range of power
settings and fuel-air equivalence ratios. Methanol data are superimposed
over the isooctane data.
The maps represent the boundaries of conditions over which
operation was found to be satisfactory (absence of misfire) up to fuel-air
equivalence ratios of 1. 3 (rich). The broader footprint of the methanol data
graphically shows the lower lean limit of methanol operation compared to
isooctane. Also shown are the nearly equal power settings.
Unburned hydrocarbons in the exhaust with methanol were
0. 1 to 0. 3 times that of isooctane. Undetectable levels of carbon monoxide
were found at stoichiometric and leaner mixtures for both fuels. Carbon
monoxide emissions with isooctane increased more rapidly than with meth-
anol at rich operation. Trends in nitric oxide emissions bet-ween the fuels
appeared comparable, tending to favor methanol at lean equivalence ratios.
This was particularly evident in regions where methanol allowed operation
at the same IMEP and lower equivalence ratio. For example, at an equiva-
lence ratio for isooctane of 0. 8, there were 13 to 14 g NO/ihp-hr with an
IMEP of 100 psi. At the corresponding IMEP for methanol ( = 0. 73) there
were 8 g NO/ihp-hr, representing roughly 60 percent lower nitric oxide
emissions. Aldehyde emissions increased at low equivalence ratios and
were generally higher for methanol than for isooctane.
The converted Dodge Dart and the Gremlin used in the 1970
Clean Air Car Race are probably the best examples so far of modified vehi-
cles capable of low emission operation on pure methanol. Typically, the
Gremlin vehicle was able to meet the then 1975 to 1976 EPA emission stan-
dards (when equipped with a catalytic reactor) except under cold-start con-
ditions. Emissions test data are shown in Table 4-5. The two basic engine
modifications made were intended (1) to enable operation on methanol and
4-25
-------
IM
120
HO
KM
_ K
•n
9^
».- »o
a <
TO
H
SO
40
JO
10
tOOORPU
METHANOl
•—ISCOCTANt W-°-T>
04 0.7 01 O.I 1.0 I.I 1.2 1.1
«. ruCL-AIR EQUIVALENCE »ATK>
Figure 4-9. Interrelationships of Power, Equivalence
Ratio, and Hydrocarbon with Isooctane
and Methanol at 1, 000 rpm (Ref. 4-9)
Figure 4-10. Interrelationships of Power, Equivalence
Ratio, and Carbon Monoxide with Isooc-
tane and Methanol at 1, 000 rpm (Ref. 4-9)
4-26
-------
0.7 0 8 0.9 1.0 1.1 1.2 1.3
«. FUEL-AIR EQUIVALENCE RATIO
Figure 4-11. Interrelationships of Power, Equivalence
Ratio, and Nitric Oxide with Isooctane
and Methanol at 1, 000 rpm (Ref. 4-9)
20
O.t 0.7 08 0.9 1.0 1.1 1.2 1.3
», FUEL-AIR EQUIVALENCE RATIO
Figure 4-12.
Interrelationships of Power, Equivalence
Ratio, and Aldehydes with Isooctane and
Methanol at 1, 000 rpm (Ref. 4-9)
4-27
-------
(2) to lower exhaust pollutants. Because methanol requires less combustion
air than gasoline and has higher latent heat, larger carburetor jets and modi-
fied intake manifold heating were provided to obtain suitable vaporization and
distribution of air-vapor mixtures under various loading conditions. A cata-
lytic reactor was employed in the discharge manifold and, although an exhaust
gas recirculation (EGR) system was built and tested, it was not used. The
results of the tests showed that:
a. Satisfactory operation can be obtained at leaner equivalence
ratios than with gasoline.
b. Unburned hydrocarbons in the exhaust consist mostly of
methanol and aldehydes.
c. Low NOX concentration results from several factors
including lean, low-combustion-temperature operation,
late timing, etc.
d. The catalytic muffler effectively reduces hydrocarbons,
aldehydes, and CO.
f.
Cold starting is difficult and causes substantial increases
in emissions.
Further reduction in NO is achievable with EGR.
Table 4-5. Exhaust Emissions from Gremlin Automobilea> (Ref. 4-13)
Fuel
HC
g/mi
CO
g/mi
NOX
g/mi
Gasoline
Methanol
0.28
0.32
7.25
3.87
2.80
0.39
Hot manifold & catalytic muffler; rejetted carburetor for
methanol
1972 CVS Federal Test Procedure
4-28
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There appears to have been no emission work involving
methanol liquid fuel-injection engines operating at a high compression ratio.
The expectation from such work would be to improve lean-operating engine
power and efficiency without seriously degrading pollution levels. Very little
data appear in the literature concerning exhaust pollutant measurements with
other engine cycles.
4.2.4 Toxicity Effects
Methanol is known to be quite toxic, producing blindness
through ingestion or narcosis through inhalation. The threshold limit value
for vapor is 200 ppm. This value is accepted by the American Council of
Governmental and Industrial Hygienists as safe for nearly all workers under
;repeated exposures day after day. By observing certain precautions neces-
sary for handling a flammable toxic material, methanol is being used safely
in bulk quantities at the present time. There is a need for more information
on extended lower-level exposure to methanol, such as would result from
widespread use as a motor fuel.
4.2.5 Safety Effects
In terms of fire safety, methanol fires should be easier to
quench than gasoline fires because of its miscibility with water. The auto-
ignition temperature of methanol (878 F) is comparable to that for gasoline.
The flash point for methanol (52°F) is lower than that of many liquid fuels
but much higher than that for gasoline (-40 F).
4. 2. 6 Handling, Storage, and Distribution Requirements
One basic disadvantage of methanol is its miscibility with
water, which requires special precautions during transport and storage to
prevent contamination or adulteration. This problem is accentuated if the
methanol is to be blended with gasoline, as discussed in the next section.
There may also be difficulties associated with corrosion and solvent action
which will emphasise proper material selection and design practices. The
toxicity of methanol may impose restrictions on how it is handled at the retail
4-29
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level, e. g. , vapor control. An educational compaign to publicize such
hazards would be essential. Finally, the lower volumetric heat content of
methanol as compared to gasoline would indicate the need for larger storage
tanks, larger tank trucks or more frequent deliveries, increased capacity
auto tanks, etc. Conversely, inasmuch as methanol is neither gaseous nor
cryogenic, many features related to current gasoline storage and distribution
practice could be retained with only minor modifications.
4. Z. 7 Methanol-Gasoline Blends
While there has been a long history of ethanol-gasoline blends
usage in internal combustion engines, particularly in Europe, there as been
relatively little experience with methanol-gasoline mixtures. Those favoring
the use of such fuels mention the following favorable factors: (1) methanol
can be made from many domestic natural resources and waste products, (2)
it can thus solve the energy shortage by extending gasoline supplies, (3) the
addition of methanol can reduce automotive emissions. It is difficult at this
time to judge the validity of these arguments due in large part to the lack of
substantiating data and to insufficient study of many important considerations
such as fuel economy, exhaust emissions, engine design, vapor lock, etc.
The following review briefly examines some of the issues involved, the data
available, and the information required.
The fact that methanol can be synthesized from many raw materials--
natural gas, petroleum, coal, oil shale, wood, and solid waste--has already
been discussed in previous sections. However, the only realistic domestic
source for methanol in the future appears to be coal; conversion of solid
waste and forest products remain speculative, long-term sources of supple-
mental alcohol. Some appreciation for the magnitude of the supply problem
involved can be realized from the fact that, if methanol is added at only the
five percent level to gasoline, current automotive fuel consumption would
require about five times present United States methanol production. Clearly,
methanol is not a panacea for our present fuel shortfall. However, methanoL-
gasoline blends may be worth producing from coal in the future; some of the
issues involved in the use of such fuels are reviewed below.
4-30
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As previously discussed, methanol alone does not match the
vehicle fuel economy (miles per gallon) obtainable from an equal volume or
weight of gasoline because of its lower heat of combustion. However, the
*
fuel economy comparison appears more promising when methanol is blended
with gasoline at levels below about 20 volume percent. Tests quoted in
Reference 4-10 showed essentially constant fuel consumption when 10 percent
methanol was added to gasoline in actual road tests in automobiles of differ-
ent types with normal carburetor settings. Even more favorable results are
reported in Reference 4-15, where positive gains of 5 to 13 percent in fuel
economy were obtained in unmodified 1966 to 1972 model cars using methanol
additions of 5 to 30 percent. More specific data were given for a 1969
Toyota with an 8:1 compression ratio. All concentrations of methanol showed
an improvement in fuel economy (maximum improvement of approximately
7.5 percent with 15 percent methanol). Elimination of knock and dieseling
were observed even -when as little as 5 percent methanol was used. The
authors attribute the improvements to dissociation of methanol during the
compression stroke in the engine, thereby cooling the charge and quenching
premature combustion. Also, the CO and tL, formed on dissociation increase
the flame velocity, giving more complete and efficient combustion. Not
mentioned was the effective leaning of the air-fuel mixture due to the fact that,
although the stoichiometric fuel-air ratio for methanol is richer than that for
gasoline, the same air flow rates as for gasoline were used. Additional per-
formance improvement, using higher compression ratios and leaner operation
may be feasible if unaccompanied by detrimental side effects.
Another possible advantage for methanol-gasoline blends is in
exhaust emissions. Here the data are even more meager and in disagree-
ment. The Ford Motor Company previously mentioned (Ref. 4-14) concluded
that under fuel rich conditions, methanol addition increased unburned hydro-
carbons in the exhaust while it had no effect under lean conditions. Previous
work they cited had indicated that methanol decreases total hydrocarbon
emissions. The same investigators found no change in carbon monoxide,
nitric oxide,or exhaust temperature with up to 25 percent methanol, whereas
4-31
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Reference 4-15 reported that CO emissions decreased from 14 to 72 percent
and exhaust temperature decreased by one to nine percent with no mention of
nitric oxide measurements. The fact that the various investigations utilized
different types of engines, fuels, operating conditions,and analytical instru-
mentation undoubtedly contributed to the conflicting results.
One major problem previously mentioned in Section 4. 2. 1,
with the use of methanol in blends (and to a lesser extent with ethanol) is the
degree of miscibility in gasoline and the effect of water. The subject is
summarized in Reference 4-15 and discussed at length in Reference 4-10.
The solubility of methanol (and ethanol) in any hydrocarbon is function of
(1) the molecular configuration and physical properties of the hydrocarbon,
(2) temperature, and (3) the proportion of water present. Methanol is soluble
to the least extent in the normal paraffins and to the greatest extent in the
aromatics (gasoline from coal would have an advantage here). In most cases,
it is more soluble in unsaturates than in naphthenes. Further^ the lower the
temperature, the less the miscibility, while the presence of very small
quantities of water greatly reduces miscibility. Reference 4-10 states that
dry methanol is miscible in all proportions with an aromatic gasoline at
60 F but only about 13 percent would dissolve in a regular gasoline and 4
percent in an all straight run gasoline. At 0 F, the methanol solubility
drops to 4 percent in regular gasoline and further to about 0. 5 percent with
the addition of 0. 03 percent water. Higher alcohols, as might be present in
"methyl-fuel", are effective in increasing methanol solubility. Miscibility
needs to be determined using modern gasolines, as many of the literature
data are more than 20 years old.
Thus, methanol-gasoline miscibility and the effect of water on
miscibility present problems both in the fuel-distribution system and in the
automobile fuel tank. Several measures may be required to meet these
difficulties. It appears desirable to keep the methanol and gasoline separated
through the distribution system and blend of the two fuels at the service
station delivery pumps. The methanol should, of course, be maintained in a
"bone dry" condition to that point. To allow for temperature fluctuations
4-32
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and some moisture pickup in the automobile, the concentration may be limited
to, perhaps, ten percent. During the winter season in colder parts of the
country, it may not be feasible to market such blends at all. On the other
hand, further research needed on all aspects of blend utilization in automo-
biles may obviate these problems through tailoring of the gasoline composi-
tion, formulation of miscibility promoters, etc.
The other potential problem mentioned in Section 4.2. 1 is the
possibility of encountering vapor lock with methanol-gasoline blends. Com-
pared to its behavior when pure, methanol becomes much more volatile in
hydrocarbon solutions. The result is a substantial increase in vapor pres-
sure of a gasoline by the addition of relatively small amounts of methanol.
It is predicted that an increase in vapor pressure of 3 psig (compared to an
average base level of 9 psig in the summer and 12 psig in the winter), due to
as little as two percent methanol, would cause significant vapor lock problems
in current automobiles (Ref. 4-16). One method of correcting the problem
is to remove the volatile hydrocarbons, such as butane and pentane, from
the gasoline. The octane number of the resulting blend will be higher than
that of the all-hydrocarbon gasoline; however, the absolute level must be
experimentally determined because the octane blending value of methanol is
quite variable with concentration and base gasoline type. Poor drivability
could result from debutanization of the gasoline, since one function of butanes
(and pentanes) is to ensure adequate fuel evaporation in the intake manifold.
The higher boiling point plus high heat of vaporization of methanol could also
lead to fuel maldistribution to the cylinders. These are potential problems
which also need to be investigated prior to adoption of methanol-gasoline
blends as automotive fuels.
As with pure methanol, methanol-gasoline blends have a higher
octane rating than gasoline alone. But there are indications that the motor
octane number (MON) increase is not nearly as great as that which would be
expected from measured increase in the research octane number (RON). This
would indicate that engine road performance increases will not be as marked
as those found in the laboratory.
4-33
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It is apparent from the preceding discussion that there is a
need for additional investigation of all aspects of the use of methanol-
gasoline blends. The advantages and potential problems need to be explored
systematically to determine if there is a worthwhile net benefit in these
blends and, if so, the best combination of fuel and operating conditions.
The economics of not only methanol (and gasoline) production from coal but
also of the impact on the distribution system needs to be explored. Until
these studies are completed, it is premature to make a judgment regarding
the utilization of this fuel combination.
4.2.8 Critical Research Gaps
As noted above in Sections 4. 2. 1 through 4. 2. 7, there is a
definite need for additional data concerning combustion characteristics, fuel
economy, and emissions for both methanol and methanol-gasoline fuel blends.
The miscibility of methanol-gasoline, and the effect of water on miscibility,
need to be fully evaluated, using modern gasolines, for both the fuel distri-
bution network and the autombile fuel and engine system. The impact of
methanol toxicity on fuel handling requirements needs to be explored, and
the potential for achieving satisfactory methanol-gasoline vapor lock charac-
teristics should be examined.
A program to obtain the necessary fuel economy and emissions
information is being initiated by the Bureau of Mines under an interagency
agreement with EPA. A range of blends, gasolines, ambient temperatures,
and engines will be investigated in the test program. In addition, data will be
provided on the stability of alcohol-gasoline blends and on problems connected
with fuel storage and transfer.
4. 3 CURRENT STATUS
4.3.1 Production Rates
Synthetic methanol production has climbed steadily in this
country as shown by data in Table 4-6. Present production rates represent
about one billion (10 ) gallons annually, or over 60 x 1012 Btu/year. Since
4-34
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Table 4-6. Annual Synthetic Methanol Production in the United States
(Source: U.S. Tariff Commission and Refs. 4-17 and 4-18)
Year
1965
1966
1967
1968
1969
1970
1971
1972
Production
Millions gal/yr
434
494
158
575
635
744
746
898 (est.)
1965, the average annual increase in total output has been 11 percent and
overall growth has been maintained over a much longer time period.
The production picture within the methanol industry has
changed considerably over the last five years. The trend has been to eliminate
marginal or noncompetitive facilities. New production capacity replacement
has been achieved with larger plants. These large units have tended to
improve cost economics. This has resulted mainly from new technology
using the medium pressure synthesis route introduced by Power-Gas, Limited
of England in 1968. Methanol producers and annual capacities of units in
operation in 1972 are shown in Table 4-7.
The largest operating units are the Celanese and DuPont plants
with annual capacities of 200 million gallons per year (about 2, 000 tons per
day). Of the 9 major manufacturers and 11 plant sites, more than 50 percent
of overall capacity is concentrated in 3 plants. With the shutdown of the
Union Carbide unit, the average unit capacity is 115 million gallons per year.
By comparison, in 1966 there were 12 major producers with 15 plant sites
and a total estimated volume of 564 million gallons per year. While this
represents an average unit capacity of 38 million gallons per year, more than
half of the units then operating had capacities of 25 million gallons per year
4-35
-------
Table 4-7. U.S. Methanol Producers and Plant Capacities
Company and
Plant Location
Methanol
Capacity,
million gal/yr
Borden Chemical
Geismar, La.
Celanese
Bishop, Tex.
Clear Lake, Tex.
Du Pont
Beaumont, Tex.
Orange, Tex.
Georgia-Pacific
Plaquemine, La.
Hercules
Plaquemine, La.
Monsanto
Texas City, Tex.
Rohm and Haas
Deer Park, Tex.
Tenneco
Pasadena, Tex.
Union Carbide
Texas City, Tex.
Total
160
90
200
200
125
100
80
100
22
80
42 (Shutdown was
expected in
1973)
1, 199
4-36
-------
or less, and only one (DuPont in Orange, Texas) exceeded 100 million
gallons per year. Since that time, 10 of these plants with a combined annual
output of 230 million gallons per year have ceased manufacture. It is worth
noting also that by 1966, all major producers used gaseous fuels as feedstock.
Earlier, coke had been a common raw material but in the period between
World War II and 1966, plant shutdowns or equipment replacements elimina-
ted coke as a raw material in the United States.
4. 3. 2 Users
The major uses for methanol are in formaldehyde and other
chemical syntheses. Other uses include solvents, antifreezes, and fuels as
shown in Table 4-8.
4. 3. 3 Consumer Costs
With the advent of several large production facilities which
use the low pressure catalyst process, the trend of methanol manufacturing
costs based on natural gas feedstock has been downward in recent years.
At current prices for natural gas (ca. $0.40/MM Btu), the sales value of
methanol at the plant is on the order of $0. 10 to $0. 12 per gallon or about
$1.55 to $1. 86/MM Btu.
Exxon recently completed an economic analysis of the manu-
facture of methanol from coal (Ref. 4-16). A methanol-synthetic natural gas
(SNG) co-product plant was examined. The SNG costs were adjusted from
the 1973 National Petroleum Council report on coal availability, which con-
sidered Lurgi gasification. Depending upon the cost of coal, the scale of
operation, and the relative product yield, the methanol cost (including 10 per-
cent DCF return) was in the range of $1. 70 to $2. 35/MM Btu at the plant.
For an initial 1982 scale of operation, an average methanol cost of ca. $2. OO/
MM Btu was estimated. Adding on a distribution cost of $1. 90/MM Btu to
account for unit train shipment from plant to terminal, truck shipment to the
service stations, and the service station mark-up, the consumer price would
be ca. $3. 90/MM Btu. This price was projected to fall to $3. 55 in 1990 and
$2. 95 in 2000 as the scale of production increased, technology improved,
4-37
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Table 4-8. Methanol End Uses, million gallons
(Refs. 4-17 and 4-20)
Uses
Formaldehyde and inhibitor
P olyf ormaldehyde
Methacrylates
Methylamines
Dimethyl terephthalate
Methyl halides
Ethylene glycol
Other chemical uses
Antifreeze
Solvent
Aircraft fuel injection
Export
Miscellaneous
Total
1960
125
11
13
9
10
7
16
20
10
20
17
29
20
297
1965
150
11
19
17
17
11
22
25
8
25
10
60
24
40?
1970
200
20
26
25
22
13
22
28
5
28
6
20
28
450"
1972
375
n. a.
25
27
46
28
n. a.
n.a.
n.a.
67
n.a.
145
185
198
pipelines replaced unit trains, etc. However, averaging cost figures from
various sources, the best estimate for future costs in 1973 dollars would be
about $3.40 at the pump. For comparison, IGT (Ref. 4-19) estimated
methanol cost at $2. 85/MM Btu based on published data but indicated the
cost would probably be significantly greater. It is difficult to determine the
manufacturing cost accurately without a detailed plant design study inasmuch
as the scale of operation postulated is much larger than any operation to
date.
4-38
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4.4 PROJECTED STATUS
4.4.1 Availability
Methanol is a bulk chemical with annual production of nearly one
billion gallons per year. While older, smaller, and marginally profitable
production plants are being shut down, several new facilities with annual
capacities on the order of 200 million gallons per year have been put onstream.
In a period of about a year, four large plants with annual capacity of 600 mil-
Ion gallons began to produce more than half of domestic annual production.
The availability of methanol for use as a motor fuel is however, presently
extremely limited.
4. 4. 2 Capital Costs and Timing Implications
Recent proposals have been made for jumbo size chemical
plants to produce alcohol fuels from natural gas at gas well sites. For plants
with production capacities of 10, 000 tons per day (3 MM gal/day), invested
capital estimates are on the order of $35 to $40 per daily methanol gallon
capacity (Ref. 4-21). Earlier studies (Ref. 4-22) of gas feedstock plants at
smaller capacity were made by A. D. Little. Their data showed invested
capital for plants with 150 tons per day (45, 000 gal/day) and 800 tons per day
(240,000 gal/day) as $97/gallon per day and $63/gallon per day, respec-
tively. Another study conducted in 1970 (Ref. 4-23) gave plant economics data
for these capacities and 300 tons per day as well. The results of these studies
are combined in Figure 4-13, corrected to 1973 dollars. These figures were
compiled without distinguishing between the various types of processes, so
that variations will occur in individual circumstances. Indications are that
approximately three years are required for methane conversion plants tobe built
and begin operation. Inasmuch as natural gas is not a realistic raw material
for methanol as a future transportation fuel, these data are included only as
a point of reference for methanol production from coal.
Plants to convert coal to methanol will require larger capital
expenditures and longer lead time, since solids handling involves costlier
operation and equipment. A capital investment of $140/gallon per day for a
4-39
-------
1000
i
o
a
<
u
o
o 100
UJ
V)
ui
a.
<
u
o
UJ
V>
UJ
10
100
DATA SOURCES
A.D. LITTLE
HARVARD UNIV
CHEM ENG
1968 (Ref. 4-22)
1970 (Ref. 4-23)
1973 (Ref. 4-21)
NOTE: PRIOR DATA CORRECTED TO 1973
i i I i I i ill i i i I I
1000
METHANOL DAILY CAPACITY, tons/day
10,000
Figure 4-13. Invested Capital Cost Estimates for
Methanol via Natural Gas
4-40
-------
large methanol-from-coal plant was given by Exxon (Ref. 4-16), exclusive
of distribution and marketing costs. Comparison with the data of Figure 4-13
at 10, 000 tons per day capacity gives an indication of the higher investment
cost when starting from coal.
4. 4. 3 Impact with Other U.S. Energy Requirements
Various estimates for domestic energy demand exist which
show near-term average annual growth trends to be about 4 percent overall,
with growth in the transportation sector trailing slightly behind. Neverthe-
less, an important consideration insofar as the transportation industry is
concerned, is the almost entire dependence (95 percent) on the use of liquid fuels
as an energy source. This situation is likely to exert a predominant influence
on the trends of prime movers for future transportation conveyances (at least
in the private sector). For one thing, any fuel change must be evaluated in
terms of how it impacts current methods of fuel distribution between producer
and consumer. Methanol, being a synthetic liquid chemical, would have a
relatively minor impact for gasoline-powered vehicles, unless control
methods for water exclusion from the system proves to be a formidable
problem.
Attention has been turning to methanol as a liquid fuel in other
energy sectors (e.g. , power plants) for precisely similar considerations.
Economic studies have shown that the cost of imported LNG delivered from
overseas can be greater on an equivalent energy basis than methanol manu-
*
factured from the same gas for distances in excess of 12, 000 miles because
of LNG boiloff losses (Ref. 4-24). Contributing to this situation is a rapid
recent rise in costs of liquefaction equipment and cryogenic transport tankers.
Methanol can be delivered in existing tankers and used as a fuel in existing
equipment with only minor adjustments.
''Based on cost of $0.40/MM Btu for NG at liquefaction plant.
4-41
-------
Perhaps the most significant feature of methanol is that it
can be synthesized from such a broad raw material base. The important
constituent is hydrogen, presently made by reacting steam with hydrocarbons.
With the greater abundance of coal, methanol as a liquid fuel supplement
must be made from this source. Other starting materials, based on the
indirect conversion of solar energy to plant matter or wood can possibly
become practical over the long term.
4. 4. 4 Factors which May Inhibit Use
As has already been stated, poor fuel economy (miles per
gallon) compared to gasoline and toxicity of methanol are foreseen as major
factors limiting its use. In this case of methanol-gasoline blends, if satis-
factory solutions to potential phase-separation problems (in storage, dis-
tribution system, and the automobile fuel tank) and vapor lock problems are
not forthcoming, they would also become major use-limiting factors.
4. 4. 5 Critical Technology Gaps
Several gaps in technology exist pursuant to the use of
methanol as an automotive fuel, although they are not seen as critical issues.
One of these is the integration of large-scale coal processing plants (with
improved gasification technology) and methanol synthesis plants. Perhaps
a more important problem is the need for a more efficient methanol synthe-
sis catalyst.
An area which deserves further attention involves the fact
that methanol can operate at lower equivalence ratios (i. e. , leaner in spark
ignition engines than in gasoline-powered engines. Development programs
should strive to take advantage of the high octane rating of methanol to
achieve better fuel economy (miles per gallon). In fact, the whole area of
methanol and methanol-gasoline performance as engine fuels needs investi-
gation. The recent Bureau of Mines program is a good start in this
direction.
4-42
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4. 4. 6 Potential for National and Regional Transportation Use
As previously noted, the transportation industry in the United
States today depends almost entirely on the use of liquid petroleum resources
as an energy source. About 95 percent of the energy used in various con-
veyances operate on products of petroleum distillation in the form of liquids.
The utilization of future fuel supplies will be dictated mainly by competition
within the various consumer industries, although government policy decisions
may influence how supplies are allocated. Nevertheless, it is highly unlikely
that a significant proportion of transportation energy fuel demands over the
near term will shift from using liquid fuels. Except for control of water
absorption, increase in storage container capacity, and care in the use of
solvent-resistant materials, pure methanol may be distributed in essentially
the same -way as gasoline. Methanol-gasoline blends may present some
additional (but not insurmountable) problems if separate distribution lines and
storage facilities are used for gasoline and the blending is accomplished at
the terminal station. But in general methanol and methanol-gasoline blends
may be considered for regional as well as national use.
4-43
-------
SECTION 5
-------
SECTION 5
METHANE (NATURAL GAS AND SYNTHETIC NATURAL GAS)
5. 1 CHARACTERIZATION
5. 1. 1 Fuel Type and Properties
Natural gas consists mostly of methane (CH.) with relatively
small amounts of other hydrocarbons (ethane, propane, butane). Nitrogen
and carbon dioxide may also be present in smaller amounts. Because of
supply constraints of natural gas, efforts are under way to develop the tech-
*
nology for deriving synthetic natural gas (SNG) from either coal or liquid
hydrocarbons. A necessary constraint is that SNG be interchangeable with
natural gas as used by the power utilities industry and the transportation
industry. The principal measure of equivalency is a heating value greater
than 1,000 Btu/SCF.
A number of indices have been proposed to evaluate this inter-
changeability. They are based on the gas heating value, specific gravity,
combustion air requirement, burning velocity, etc. As an example, the
Wobbe Number (Ref. 5-1) is defined as the heating value of the gas divided
by the square root of its specific gravity (a measure of the rate at which the
thermal energy is delivered to a combustor burner tip). The coal gasifica-
tion processes to be described have, in general, sufficient flexibility in the
final SNG composition to ensure that such interchangeability can be
preserved.
*
Also referred to as substitute natural gas.
5-1
-------
Typical composition of natural gas and SNG as piped to
consumers is shown below:
Composition of Natural Gas and Synthetic Natural Gas, % mole
Ingredient
Fuel
Natural Gas
Synthetic Natural Gas
Methane
Ethane
Propane
co2/co
CA and heavy
hydrocarbons
Hydrogen
Nitrogen
89.0 - 99
8. 5 - 1.5
1. 5 - 0.2
0 - 0.7
1.2- 0. 5
0 - 0.2
0 - 0. 5
88.0-97
0. 4 - 0. 1
1.1- 1.3
10. 0 - 0. 8
0. 8 - 1.1
Table 5-1 shows some of the key characteristics of natural
gas (NG), compressed natural gas (CNG), and liquefied natural gas (LNG).
The properties of natural gas (methane) are listed in
Table 5-2 from Reference 4-19. For ease in transportation and storage the
gas is often maintained in liquid form as LNG; therefore, both gaseous and
liquid properties are quoted.
Natural gas has a density 0. 6 that of air; therefore, in case of
leakage in open air- it diffuses rapidly. Its ignition temperature of 1,170 F
is higher than that of gasoline (approximately 700 F), but its higher vapor
pressure at ambient conditions and its ability to form explosive mixtures with
air require, as with any other highly flammable product, careful handling in
storage and transport. Natural gas is not considered a toxic agent. Its
physiological action is that of a simple asphyxiant displacing oxygen in air.
In the application of natural gas to the transportation industry,
both CNG at pressures up to 3, 000 psi and LNG were being used. Liquefied
5-2
-------
Table 5-1. Key Characteristics of Natural Gas
Gas
Liquid
Density (Ib/cf)
15 psia, 60°F
3000 psia, 60°F
15 psia, -260°F
Heat of Combustion (net)
Btu/scf
Btu/lb
Btu/gal
Boiling Point
15 psia, °F
0.0449
8. 50
966 - 1000
27. 82
21,520.00
80,000. 00
-258.20
Gasoline Equivalence:
1 gallon of gasoline - 6. 08 Ib, net heat value - 117, 350 Btu
1 gallon of LNG - 3. 75 Ib, equivalent in Btu to 0. 68 gallons
of gasoline
1 cu ft CNG (3000 psi, 60°F) -8.5 Ib, equivalent in Btu to
1. 56 gallons of gasoline
5-3
-------
Table 5-2. Methane Characteristics (Ref. 4-19)
Chemical Formula
Molecular Weight
Melting Point
Boiling Point
Density
Vapor (1 atm, 60°F); lb/ft3
Compressed at 2000 psi, lb/ft
Specific Gravity (Liquid)
Heating Value (Vapor)
3
Volumetric Gross, Btu/ft
Volumetric Net, Btu/ft3
Weight Gross, Btu/lb
Weight Net, Btu/lb
Heating Value (Compressed at 2000 psi)
Volumetric Gross, Btu/ft
Volumetric Net, Btu/ft3
Weight Gross, Btu/lb
Weight Net, Btu/lb
Air for Combustion - Vapor
Air Volumetric, ft /ft3
O2 Weight, Ibs/lb
N2 Weight, Ibs/lb
Air Weight, Ibs/lb
Air for Combustion - Liquid
Air Volumetric, ft3/ft3
O2 Weight, Ibs/lb
N2 Weight, Ibs/lb
Air Weight, Ibs/lb
CH4
16.041
-296.5°
-258.5
0.04243
7.08
0. 5543
1013.
913. 1
23,879
21,520
169,065
152, 362
23,879
21,520
9. 528
3. 990
13.275
17. 265
1589.9
3.990
13.275
17.265
5-4
-------
Table 5-2 (continued)
Products of Combustion - Vapor
CO2 Volumetric, ft3/ft3
H2O Volumetric, ft3/ft3
N2 Volumetric, ft3/ft3
C02 Weight, Ibs/lb
H2O Weight, Ibs/lb
N2 Weight, Ibs/lb
Flammable Limits, %
Flame Velocity, ft/sec
Ignition Temperature, F
Theoretical Combustion Temp. , F
Heat of Vaporization at Boiling Point, Btu/lb
Octane Number
Toxicity - Max. Allowable Concentration for
Prolonged Exposure, pprn
Normal Transportation - Pipeline under
pressure or as a cryogenic liquid in bulk
1.0
2.0
1. 528
2.744
2. 246
13. 275
5. 00 to
15. 00
1. 5
1170
3484
219. 22
115
90,000
5-5
-------
natural gas is attractive because of its greatly increased density compared to
gas at atmospheric pressure (620:1) and about 3:1 higher than the density of
CNG at 3, 000 psi. However, the low boiling point (-260°F) requires applica-
tion of cryogenic tank insulation techniques, which add substantially to auto-
mobile tank weight and cost relative to a conventional gasoline system.
The expanded use of LNG resulted in development of portable
cryogenic tankage for overland and sea transportation as well as for station-
ary, large-volume, long-period storage facilities near metropolitan areas to
meet peak demands for natural gas.
A summary of natural gas (methane) characteristics of speci-
fic interest to the transportation industry and a comparison with gasoline
characteristics is shown in Table 5-3 (Ref. 2-7).
5. 1.2 Reserves of Domestic Raw Material Sources
Data for domestic reserves and demand of natural gas as well
as coal, which is the future raw material source for SNG, were taken from
References 2-1 and 5-2. However, since these references are dealing with
projections up to the year 1985*. additional data were obtained from Refer-
ences 1-1 and 2-3.
The NG domestic reserves are shown in Table 5-4. The defi-
nition of ultimate gas discoverable was made by combining the volumes of past
production with the estimates of the Potential Gas Committee (PGC) (Ref. 5-2).
As estimated by the PGC, 62 percent of the remaining discoverable gas
(1, 178 x 10 ft ) is situated in the operationally difficult or frontier areas
(14 percent below 15, 000 feet, 20 percent offshore, and 28 percent in Alaska).
The uncertainties associated with yet-undiscovered gas resources are appar-
ent when comparing, for example, the Alaskan gas resources estimated at
272. 3X10 ft in Reference 5-2 with those estimated at 327 X 1Q12 ft3 in
12 3
Reference 2-3, although both are in agreement in the total 1, 178 X 10 ft
remaining. In addition, there is a possibility of utilization of nuclear devices
A brief forecast to the year 2000 is included in Reference 5-2.
5-6
-------
Table 5-3. Relative Properties of Natural Gas (Mfitha.ne| versus
Gasoline for Constant Energy Value (Ref. 2-7)
Gasoline
0)
C
rt
-4->
0)
s
Liquid
Compr
3, 000 psi
Relative
Ib /Btu
1.0
0.9
0.9
Relative Fuel
Weight
1.0
0. 9
0.9
Relative Fuel
Volume
1. 0
1.6
4. 8
Fire
Hazard
Rating
Fair
Fair
Fair
Toxicity
Slight to
moderate
None to
slight
Combustion
Rating
Good
Excellent
Excellent
Distribution
Logistics
Excellent
Fair
Fair
Tankage
Cost
Low
Fairly
high
Fairly
high
-------
Table 5-4. Natural Gas Reserves - Domestic
Units - 1012 ft3 (trillion cubic feet)(Refs.2-3, 5-2)
Nonassociated
Onshore - lower 48 states
Offshore - lower 48 states
Alaska
Subtotal
Associated - dissolved:
Subtotal
Grand Total
Estimated addition by
nuclear stimulation
TOTAL
Ultimate
Discoverable
Gas
963. 1
260. 1
277.4
1500. 6
356.7
1857. 3
Gas
Discovered
to 1/1/71
413. 1
45. 9
5. 1
464. 1
215. 2
679.3
Remaining
550.0
214. 2
272. 3
1036. 5
141. 5
1178. 0
317. Oa
1495.0
Discoverable %
of Ultimate
57. 1
82.4
98.2
69. 1
39.7
63.4
aFrom Reference 2-3 (Ref. 5-2 estimates 4.6 X 10 ft for Case I, 1971 to 1985 period)
01
I
oo
-------
for massive fracturing of substrata which might in the future release
additional quantities of natural gas from low-permeability reservoirs. The
estimated amount of gas released by nuclear stimulation of 317 x 1012 ft3 was
taken from Reference 2-3 and is also included in Table 5-4.
The potential rate of domestic gas supply is shown in
Table 5-5. The data are based on Case I (Ref. 5-2) which was adopted in
Ref. 2-1 as the baseline condition. Case I represents a maximum effort to
develop additional domestic fuel supplies and assumes oil and gas drilling
increasing at a rate of 5. 5 percent per year until 1985. Synthetic fuels are
developed and produced at the maximum rate physically possible without any
restrictions due to environmental problems, economics, etc. In short,
Case I represents a most optimistic picture of domestic gas supply. For
comparison, data are also shown (from Reference 1-1) which represent an
intermediate approach to the gas supply forecast (average growth rate of
2. 2 percent).
An important factor with regard to gas reserves for the gas
industry is the ratio of proven reserves to production rate. If probable
12 3
reserves of 871 x 10 ft (Ref. 2-3) are considered and an average annual
rate increase from 1970 is assumed to be only 3 percent, the domestic gas
reserve would be exhausted in approximately 26 years. Other forecasts are
not as optimistic and, for example, it was estimated (Ref. 5-3) that, at pres-
ent rates of consumption, the known reserves will be depleted in 13 years.
This ratio is important for construction of any new pipeline since the
Federal Power Commission (FPC) generally insists that the industry must
have its reserves assured for 12 years or more in advance before a pipeline
can be built (Ref. 5-4).
Irrespective of the assumed projection rates, it is obvious
that the potential supply of domestic NG is insufficient and, that if the pro-
jected demand is to be met, progressively larger quantities have to be
imported. The figures quoted below are solely for the purpose of illustrating
the widening gap between demand and supply. The absolute values may be
subject to major revisions in view of the reduced worldwide availability of
fossil fuel supplies. Thus, in Table 5-5, a projected rate of increase is shown
5-9
-------
Table 5-5. Potential Natural Gas Supply Rate
Units - 1012 ft3/yeara
Gas, domestic
production
Synthetic (coal)
Nuclear
stimulation
Subtotal
Percent domes-
tic potential
energy supply
Gas - Domestic
Synthetic
Subtotal
Imports
Pipeline
LNG
.Imports in per-
cent of domestic
gas supply
1970
21.80
0
0
21.80
36. 50
21. 15
0
21. 15
0.90
-
4.00
1975
23.70
0
0
23. 50
35. 50
21.962
0
21.962
2.00
0. 50
11.40
1980
25. 90
0. 60
0. 20
26.70
29. 80
22. 27
0.70
22. 97
3.00
0. 90
16. 90
1985
30. 60
2. 50
1. 30
34.40
26.80
21. 84
2.00
23. 84
4. 10
1. 60
23.90
2000
25.00
5. 50
1.50
32. 00
16. 00
22. 16
5. 50
27.66
7.40
3.40
39. 00
Maximum rate of
development
Ref. (5-2) Case I.
Data for year
2000 are an
extrapolation
Intermediate rate
of development
Ref. (1-1)
For Btu, multiply by 1030
Subject to major revision in view of the reduced world availability
of fossil fuel
5-10
-------
of gas imports from four percent of the domestic supply in 1970 to 23.9
percent in 1985 and 39 percent in the year 2000. For the optimistic supply
Case I of Reference 5-2, the projected gas imported in 1985 is estimated at
17. 1 percent of the domestic supply. A still worse situation exists with
respect to the petroleum supply, which is not discussed in detail in this
report. The shortage of gas (and petroleum products) is an incentive to search
for alternative fuels such as SNG which could supplement and eventually
replace NG. The production of SNG from coal is particularly attractive. A
review of the domestic coal supply as a raw material source was discussed
in Section 1.
The production of SNG will depend on the completion of coal
gasification plants to be in operation in the post-1980 period. The predicted
supply of SNG derived from coal (Table 5-5) in the year 2000 will be about
20 to 25 percent of the domestic production level of natural gas and may be
expected to be of significance in replacing petroleum fuels for stationary
electric generating plants.
5. 1.3 Method of Manufacture
5.1.3.1 Natural Gas
The natural gas found in deposits can be either associated with
petroleum, which is also called "wet natural gas" containing condensable
hydrocarbons (propanes, butanes, and heavier hydrocarbons), or nonassoci-
ated dry gas free of the heavy hydrocarbons. Natural gas may be also classi-
fied as "sour natural gas" if it contains a sufficient amount of sulfur and/or
carbon dioxide to be corrosive or odoriferous. "Sweet natural gas," on the
other hand, does not contain these impurities. Condensable hydrocarbons
removed from the wet natural gas are categorized as liquified petroleum
gas (LPG).
Natural gas may also contain undesirable impurities such as
CO N_, H9O, H~S and other compounds. A variety of processes are avail-
W L* t* 1-4
able for removal of these impurities (Ref, 5-5). For example, water vapor
5-11
-------
removal is based on absorption on activated solid dessicants or reactive
solids. The most widely used process for removal of CC>2 and H_S employs
an aqueous solution of diethanolamine. Propane, butane, and heavy-
hydrocarbons are removed in a conventional oil absorption plan consisting
of an absorption tower, a stripping tower, and a purification system for the
by-products.
5. 1.3. 2 LNG
The first United States facility to liquefy and store natural gas
was built in 1940. There has since been a rapid growth in the number of LNG
plants and, in 1970, there were 15 plants in operation and another 9 in con-
struction and planning stages, with a combined capacity of 750 million cubic
feet per day. The rapid growth in use of LNG was brought on by its unique
storage capabilities that met the needs for: (1) peaking requirements of power
utilities (peak shaving), (2) providing natural gas supply for areas beyond
pipelines (satellite operation), (3) enabling the transport of large quantities of
gas over sea and land (baseload operation), and (4) automotive transportation
applications.
Before liquefaction, the gas has to be stripped of traces of
contaminants that may solidify during the liquefaction process and plug piping
or four heat exchangers. Thus, water, carbon dioxide, sulfur compounds,
and other natural gas constituents have to be removed. There are various
dehydration processes currently in use, such as: the glycol system, amino-
glycol, molecular sieves, and other dry dessicants (Ref. 5-6). Water con-
centration has to be reduced to approximately one part per million (0.0416
pounds of water per MM ft ). Removal of hydrogen sulfide and the carbon
dioxides is also done by various means which include: molecular sieves,
amine treatment, glycol amino, Giammarco- Vetrucoke, and hot potassium
carbonate. During the liquefaction cycle, the sensible and latent heat of the
gas has to be removed by either cascade-cycle heat transfer through refrig-
erants to a heat sink, such as cooling air or water in an expander cycle cool-
ing the gas by the work performed by it, or by modifications of these two
basic cycles.
5-12
-------
5.1.3.3 SNG (by coal gasification)
Coal gasification research in the U.S. during the last 10 to
15 years has been funded by the Office of Coal Research, the Bureau of Mines,
the American Gas Association (AGA), and by private industry. Over $71 mil-
lion have been spent on this research. In addition to these funds, an acceler-
ated research program was started with joint funding of the Department of the
Interior and AGA. The project will involve expenditures of approximately
$300 million over the next 8 years.
There are various processes for coal gasification in the
development stage, but the fundamentals of the process are common to all.
The atomic ratio of hydrogen to carbon is 4:1 in methane, but only 1:1 in
coal. Consequently, to produce methane the process must include a stage to
remove the excess carbon or one to add hydrogen or a combination of both.
The first stage of the process, after the coal is suitably crushed and sorted
(and sometimes pretreated), is the gasification stage which operates at pres-
sures from 20 to 70 atmospheres and temperatures up to 1, 500 C (Ref. 5-3).
Coal is brought into contact with synthesis gas at temperatures of 600 to
800 C in the first phase of gasification. In the second phase of gasifi-
cation, the devolatilized coal is brought into contact with steam at tempera-
tures greater than 900°C to form synthesis gas of 40 to 65 percent methane.
The gas mixture passes through cyclone separators to remove fine particles
and dust and is then transferred to a catalytic shift converter to obtain the
proper ratio of hydrogen to carbon monoxide for methane production by
CO-steam reaction (Ref. 5-1). The gas then enters a purification stage in
which carbon dioxide and hydrogen sulfide are removed. Then follows the
catalytic methanation stage to increase the content of methane and to reduce
carbon monoxide for a heating value comparable to NG (typically 1,000 Btu/
cuft). The methanation gas is then dried and, if necessary, compressed to
pipeline pressures or subjected to a process of liquefication.
The basic chemistry of the process is shown in Figure 5-1
(Ref. 5-3) and the process schematic in Figure 5-2 (Ref. 5-1).
5-13
-------
Coal
Catalytic shift conversion
CO + H20 ^=± C02 + Hj
CO,. H2S
Hj/C0<3
t
Hydrogasification
> CH + C
Coal
C + 2H2
C + H20
CO + H20
C04+ H,
CO?* Hj
Steam
Heat
Catalytic methanation
3H2 + CO-*CH4 + H20
SNG
Figure 5-1. Chemistry of Coal Gasification
Process (Ref. 5-3)
Hydrogen (or hydrogen-rich gas)*— — ——-
H,Sto
sulfur
/£&•
x>al (rom
minemouth
Oxygen .
*
Coal
|>r
-------
Of the several processes now under development in the U.S. ,
the following few can be mentioned: the Hygas process developed by the
AGA and the Institute of Gas Technology, the CO2 Acceptor process devel-
oped by the Consolidated Coal Company, the Bi-Gas process developed by
Bituminous Coal Research, Inc. , the Synthane process developed by the U.S.
Bureau of Mines; and the Lurgi process developed in Germany and adopted
by several companies in the U.S. A more complete list of the various proc-
esses, including plant output levels and a description of the status and fund-
ing, is given in Table 5-6. The principal difference between the various
processes is in the type of coal that can be used, the manner in which the
coal is admitted to the gasifier, and the source of heat for the gasification
process. In the Hygas and Synthane processes/ some types of coal must be
pretreated by partial volatilization to avoid conglomeration of coal particles.
Each pilot plant will also incorporate a different system for
shift conversion, scrubbing, purification, and methanation, so, by the time
a pilot plant is operated at 60 to 70 MMft per day, the most economical and
efficient processes will be sorted out and proven.
There are environmental problems associated with coal
mining and with construction and operation of coal gasification plants.
Detailed studies are being conducted; for instance, West Virginia University
is conducting a study on this subject (Ref. 3-1).
The plant effluents considered necessary to control are: gases
(HS, SO7, NO ) generated during gasification, combustion and sulfur-recovery
tj 5C
operations; liquids consisting of process waste waters contaminated with
phenols, ammonia, oil and tars; and solids consisting of fine coal dust and
char.
Coal mining involves residuals in the form of aggregates and
refuse as well as mine drain sludges. The plan for either disposal of the
wastes as by-products or conversion into useful products must be made
before a facility is constructed, and an environmental impact statement must be
be approved by the appropriate agency.
5-15
-------
Table 5-6. Summary of SNG from Coal Plants and Projects
(as of April 15, 1973) (Ref. 5-7)
Name of Process
Lurgl F'rrisure Gasification
(l.urgi Grsellschaft fur
W»rnir und Chemotechnlk
m. b.H. }
Lurgi Pressure Gasification
Lurgi Pressure Gasification
LurgI Pressure Gasification
Lurfl Pressure Gasification
Owners) or Contractor and Site
£1 Paso Natural Gas Co. (Four
Corneri area, New Mexico)
El Paso Natural Gai Co. (Four
Corner* area, New Mexico)
Texas Eastern Transmission
Corp., Pacific Lighting Corp.,
Utah International Inc. (Four
Corner* area, New Mexico)
Panhandle Eastern Pipe Line
Co. and Peabody Coal Co.
(Illinois)
Conoco Methanation Co.
and Scottish Gas Board
(Westfield, Scotland)
Description of Process
A bed of crushed coal in introduced to
the gasifier vessel through lock hopper*
and travels downward as a moving bed.
to 450 psi. Steam and oxygen are Intro-
grate which 'also remove • ash at the
bottom of the gasifier. The hydrogen-
rich gat passes up through the coal
bed, producing tome methane by
hydrogenation of coal. The product
gas la purified and methanated to
produce 97Z Btu/SCF gas.
Same ai above
Same as above
Same aa above
Methanation of purified low Btu
product gas from a Lurgi pressure
gasifier to demonstrate the commercial
feasibility of the combination of
Lurgi gasification and methanation to
produce a 950+ Btu/SCF gas.
Coal
Type
Limited to non-
caking coals
Limited to non-
caking coals
Limited to non-
caking coals
Limited to non-
caking coals
Subbituminouo
Consumption,
ton/day
26, 600
765
29, 090
Plant Output
106 CF/day
Z50
50
(Raw synthesis
gas)
250
2.6
Status and Funding
El Paso ha* announced plans for
construction and operation of the
Burn ham Coal Gasification Complex
on the Navajo Indian Reservation.
for the gasification plant and 65, 3
million for the associated mine.
Initial gas production is scheduled for
June 1976. The estimated 1977 coat
of gas at the plant outlet la $1. 21/MCF.
A single Lurgi gaalfler will be
installed to test Improvements In
the process. Goals are operation
at 20% above design capacity and
fler mechanical Improvements,
coal lines gasification and Improved
pollution control. Capital Invest-
ment will be 814. 1 million. Flr»t
million. Completion and operation
Is scheduled for April 1974.
Texas Eastern and Pacific Lighting
have made application to the FPC
for authorization to construct and
operate a $406.9 million coal
gasification plant on the Navajo
N. M. Utah International will supply
the coal and water. Plant operation
Is scheduled for 1976.
Feasibility study contract has been
awarded to M. W. Kellogg and
American Lurgi Corp,
Conoco Methanation Co. will design
and construct facilities to carry out a
Eleven U.S. companies are sponsoring
the test which Is scheduled to begin In
mid 1973. The construction contractor
ia Wood all Duckham, Ltd.
Ul
I
-------
Table 5-6 (Continued)
Name of Process
Lurgi Pressure Gasification
CO2 Acceptor
BI-GAS
Synthane
Owner(a) or Contractor and Site
South African Coal, Oil, and
Gas Corp. and Lurgi (Saaolburg,
South Africa)
Texas Gas Transmission Corp.
and Consolidation Coal Co.
Eastern Gas & Fuel Associates
Corp.
Consolidation Coal Company
(pilot plant constructed and
operated by Stearns-Roger
Corp.) (Rapid City, S. D. )
Bituminous Coal Research, Inc.
(Homer City, Pa.)
U. S. Bureau of Mines
(Bruceton, Pa.)
Description of Process
Methanatlon of the product gas from a
Lurgi gaslfier to produce 950+ Btu/SCF
gas.
Coal is charged to a devolatilizer and
is contacted at 300 psia with hydrogen-
rich gas from a gasifier vessel. Cal-
cined dolomite {the "Acceptor") is added
carbon dioxide. "Acceptor11 regenera-
tion and ash removal is carried out in
spent char is combusted. The product
gas can be purified and methanated to
produce a 950+ Btu/SCF gas.
Coal is introduced into a reactor where
it is contacted and partially gasified with
hydrogen rich gas produced in the lower
section of the reactor by the slagging
gasification of recycle char with oxygen
is 1000 psia. The product gae can be
purified and methanated to produce 950+
Btu/SCF gas.
Coal is introduced into a single reactor
which incorporates three processing
steps, a free fall oxygen- steam pre-
treatment zone, a dense fluid bed i
carbonizer, and a dilute fluid bed gasi-
fier. Hydrogen-rich gas for the re-
action is produced by use of oxygen in
the reactor. The process operates at
purified a.nd methanated to produce
950+ Btu/SCF gaa.
Coal
Type
Lignite and
subbituminous
All U. S. coal
types
All U. S. coal
types
Consumption,
ton/day
40
(Pilot plant)
120
(Pilot plant)
70
(Pilot plant)
Plant Output
106 CF/day
Up to 2 (No
heating value
specified)
2.3
1.4
Status and Funding
commercial feasibility of methanation, A
slip- stream from the SASOL plant will be
used as feed to the methanator.
Texas Gas Transmission Corp, has
acquired one half interest in a large
block of Illinois Basin coat reserves
controlled by Consolidation Coal Co.
The largest parcel will be held for 10
The companies have acquired coal
mining and prospecting rights to about
40, 000 acres of federal and state leases
in northwestern New Mexico. If the
would conduct the mining and Texas
Eastern would build and operate the
gasification plant.
Pilot plant undergoing start-up. A
methanation stage is not incorporated,
but may be added at a later date. The
original pilot plant cost was about $9. 3
million.
Preliminary pilot plant design complete.
to Stearns Roger, Inc. Plant cost will
be about &18 million and construction
will take 18 to 24 months.
Pilot plant design completed. Estimated
cost is $10 million. Plant will be com-
pleted in December 1973. Design and
consultation by Lummus Co. Construc-
tion by Rust Engineering Co.
Ul
I
-------
Table 5-6 (Continued)
N«me of Process
K.«-ll»gR Molten Salt Process
None
None
COCAS
HYGAS
Kopp* r » - Tol »a.k
Owner(s) or Contractor and Site
M. W. Kellogg Company
Garrett Research and Develop-
Colorado Interstate Gas Co. )
Gulf General Atomic and Stone
(, Webster
Corp. , Panhandle Eaatern Pipe
Line Co., Tennecolnc., Con-
•olldated Natural Gas Service
Co., Republic Steel Corp. ,
Rocky Mountain Energy Co. )
Institute of Gas Technology
(Chicago, Illinois)
Koppers Company
Description of Process
oxygen, a team and coal are Injected Into
lyzes complete gasification of the coal.
The product gas can be purified and
methanated to produce 950+ Btu/SCF
gas.
Coal IB Introduced Into a simple reactor
produced by rapid de volatilization of
are produced.
Coal li dissolved and the solution Is
hydrocracked and reacted non-
catalytically with hydrogen to produce
gas which is purified and methanated
to 950+ Btu/SCF gas.
bed reactors with increasing stage
temperatures to pyrolyze the coal and
drive off volatile fractions In each stage.
After separation of the oils and gas
produced In the initial processing, the
residual char is reacted with steam' and
air to produce a synthesis gas which is
purified and methanated to a 950+ Btu/
SCF gas. The operating pressure is
50 pslg. The oil by product is hydro-
treated to make a synthetic crude oil.
Ground, dried coal Is pretreated with
air, slurried with byproduct oil, and
fed to a two- at age fluid! zed bed hydro-
gasifler operating at 1000-1500 psia,
hydrogen- rich gas for the reaction can
be furnished by processes uaing electric
energy or oxygen, or by the stremation
process. Gas from the reactor is puri-
fied and methanated to produce 950+
Btu/cu ft gas.
Raw coal is dried, ground and charged
to a gaalfler by a screw conveyor with a
mining head In which oxygen and steam
are added to the coal fines. The reactor
operates at atmospheric pressure and at
2700" F. The product gas, mostly hydro-
gen and carbon monoxide, can be metha-
nated to produce 950+ Btu/SCF gas.
Sixteen low Btu plants are in operation
In other countries, primarily to make
synthesis gas for ammonia production.
Coal
Type
All U. S. coal
types
All U.S. coal
All U.S. coal
types
and bituminous
All U. S. coal
types
All U. S. coal
types
Consumption,
ton/day
-
-
_
75
(Pilot plant)
-
Plant Output
10° CF/day
-
-
.
1. 5
_
Status and Funding
1904-1967. Total expenditures wore
Si. 7 million. Major difficulties were
tlon. OCR ceased sponsorship because
of this problem, budgetary restrictions
and assignment of higher priorities to
other coal gasification processes.
M. W. Kellogg has carried out additional
development work since 1967, but sup-
port has not yet been obtained for con-
struction of a large-scale pilot plant.
Early stage of development. Being
California.
Feasibility studies being made.
plant in Princeton N. J. , which was
designed to produce oil, char, and a
relatively small amount of gas. The
COED pilot plant was funded by OCR
and completed In 1970 at a cost of $4. 5
million. COGAS Development Co. will
Invest 9? million for a pilot plant. An
18 to 24 month process evaluation Is
planned.
Pilot plant in operation. Preliminary
demonstration plant design complete.
Original coat of pilot plant was approxi-
mately $9. 5 million.
Process la being offered in U.S. and
Canada under a general license from
Heinrich Koppera G. m.b. H. , Eaaen,
We at Germany.
I
»-^
00
-------
Table 5-6 (Continued)
Name of Process
ATGAS
Union Carbide
_
Self -Aggloine rating
Gasification Process
None
_
_
Owner(a) or Contractor and Site
Applied Technology Corp.
Chemical Construction Corp.
(Chemico) has been licensed by
Union Carbide to use coal gasi-
fication technology developed
by Union Carbide
Colorado Interstate Gas Co. and
Westmoreland Resources
The Columbia Gae System, Inc.
(West Jefferson, Ohio)
Chem Systems, Inc.
(Hackensack, N. J. )
Coteau Properties (wholly owned
subsidiary of North American
Coal Corp. ) and Michigan
Wisconsin Pipe Line Co.
Northern Natural Gas Co. and
Cities Service Gas Co. (Powder
River Basin, Montana)
Natural Gas Pipeline Co. of
America (Dunn County, N. D. )
Description of Process
Coal is Injected into a molten Iron bath
where steam and oxygen react with the
carbon to produce hydrogen and carbon
monoxide. The gases are then metha-
nated to produce 950+ Btu SCF gae.
Coal Is crushed and fed to a gasifler as
a dry solid or water slurry. The coal
is heated in the presence of steam by
direct contact with hot ash agglomerates
generated by the combustion process,
producing a product containing carbon
monoxide, hydrogen and about 10%
methane.
_
stage fluidized-bed system. Air is used
for combustion of part of the coal to
provide heat for the gasification process.
The process operates at pressures up to
100 psi to produce a synthesis gas suit-
gas by methanation.
A methanation process to convert coal-
derived synthesis gas to high-Btu pipe-
line gas
_
_
Coal
Type
All U.S. coal
types
_
_
_
Lignite
_
Lignite
Consumption,
ton/day
-
_
_
_
_
_
_
Plant Output
106 CF/day
-
_
_
0 8
(Synthesis gas)
_
_
250
(Initial plant)
_
Status and Funding
EPA has added $222,000 to its initial
contract of $820, 000 for work on the
awarded the company $282,000 for de-
veloping a pre-pilot plant to demon-
strate the process.
-
sibility of coal gasification plant will
be studied.
Core drilling program in West Virginia
to identify possibilities for coal gasifi-
cation facilities 293 million tons of re-
coverable coal reserves have been
proved on part of land on which the
company has coal rights.
$4. 1 million contract under the joint
OCR A. G. A. program.
Chem Systems has been awarded a
30 month, $1.9 million control under
the joint OCR/A. G. A. program.
A 20 yr option on 2.7 billion tons of
North Dakota lignite to convert to syn-
thetic gas, not before 1980's.
Northern Natural and Cities Service
are considering construction of four
250 million CF/day coal gasification
plants. Peabody Coal has agreed to
supply about 500 million tons of coal.
and the gas companies are negotiating
for another. The amount of $10 million
will be sent for preliminary development
through 1975. Construction of the first
plant could start in 1976, with opera-
tion in 1979.
Rights to 2 billion tons of lignite have
been obtained from Star Drilling Inc.
The lignite will be reserved for possible
future use in a coal gasification project.
(J\
I
-------
Table 5-7 provides additional information on the energy balance
of the various processes. For example, in the Lurgi process the efficiency
is estimated at 70 percent; of the 30 percent loss, approximately 25 percent
is contained in the energy required for processing. Therefore, for three
cubic feet of gas produced, one cubic foot is used for energy input.
It is expected that 35 to 40 SNG coal gasification plants, each
producing approximately 250 MM ft /day, will be in operation by 1985 with a
total output approaching 9,000 MM ft /day-
5.2 SUITABILITY OF NG, SNG, AND LNG FOR USE
AS AN ENGINE FUEL
5.2.1 General Considerations
The large demand for petroleum products in the U.S. exceeds
the domestic supply and is an incentive for implementing a search for alterna-
tive fuels derived from fossil sources.
Another incentive in the search for alternative (to liquid
petroleum products) fuels is the large amount of pollutants in the form of
carbon monoxide, unburned hydrocarbons, and nitric oxides, generated by
heat engine prime movers using liquid petroleum products. Data for 1969
showed that 52 percent by weight of all atmospheric pollutants was contributed
by transportation (Ref. 5-8). The progressively tighter Federal Emission
Standards which compelled the use of various emission control devices on the
conventional spark ignition engine, resulted in a 15 percent increase in fuel
consumption between the vehicles meeting the 1973 and 1975 standards
(Ref. 5-8). Thus, current efforts to clean up the conventional spark ignition
engine, while acceptable as an interim solution, indicate the need for develop-
ing alternative fuels and alternative prime movers.
Natural gas is also in short supply, as shown earlier; but, in
discussion of its long-term application to automotive vehicles, the main atten-
tion should be placed on SNG, derived from coal gasification and interchange-
able with NG. All comments made on CNG or LNG operation will be,
therefore, applicable to SNG.
5-20
-------
Table 5-7. Coal to SNG (Ref. 5-18)
Ul
Energy /Material
Resources
355-390 billion Btu
coal
4700-6500 tons O2
19,ZOO-28,800
tons team at
500 psi
21,600-36,000
tons/hr feed water
60 MW power*
17, 092 tons coal
(12,401 Btu/lb)
as a. feed and fuel
(also 347,217 kW
power included
in it)
16,237 tons coal
(12,401 Btu/lb)
as a feed and fuel
(also 2930 tons O2
included in it)
20,381 tons coal
(12,401 Btu/lb) as
a feed and fuel
(also incl. manu-
facture of F2)
Name of the
Process
Lurgl Process
HYGAS Process3
(with electro-
thermal gasifier)
HYGAS Process
(•with oxygen
gasifier)
HYGAS Process
(with steam-
iron)
Comment on the Process
Lock hoppers feed crushed
coal to a moving-bed gasi-
fier. A revolving grate
feeds in O2 and steam
while removing ash. Oper,
pressure is up to 450 psi.
Exit gas temperature is
between 700° and 1100°F.
This process produced 970
Btu/SCF gas. Limited to
noncaking coals (incl. both
electric and steam drives).
Dried coal is slurried with
light oil and fed to a 2-
stage fluidized-bed hydro-
gas ifier operating at 1000-
1500 psia. An electro-
thermal gasifier, oxygasi-
fier, or a steam-iron pro-
cess, using char from the
2nd stage of the HYGAS
unit, produces hydrogen-
rich gas which is supplied
for gasification. Exit gas
temperature is 600° F.
Synthesized
Fuel
250 billion Btu
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-
pressure steam
960-1680 tons of
tar -oil-naphtha
72-144 tons
phenols
85, 104 gal oil
52,452 gal C(Ji,
81 tons NH3
76,470 gal oil
46,339 gal C6H6
72.4 tons NH3
103, 152 gal oil
63,910 gal C6H6
99 tons NH3
Thermal
Efficiency,
%
70
65
66
63
Comments on Pollution
Relatively low off-gas temperature
and countercurrent design in-
crease appearance of tars, NH3,
etc. , in waste quench liquor.
For the pretreatment of caking
coals, sulfur existing in the pre-
treatment off-gas must be
removed.
-------
Table 5-7 (continued)
i
M
ro
Energy /Mate rial
Resources
12, 000 tons coal to
gasifier (13, 000
BtWlb); 2400 tons
coal (steam and C>2
production): 16
million gal water
1 3, 200 tons coal
{13 990 Btu/lb)'
226. 8 tons Na2CO3
(makeup)
1. 36 billion SCF
air; 31 . 104 million
Ral cooling water
(makeup); 3.785
million gal BFW
14, 220 tons coal
(12,700 Btu/lb);
^6 95 mi Hi on Ib
h-p steam (in-
cludes production
of 2770 million
SCF O2); 374.5
million gal-cooling
water; 25. 92 mil-
lion gal.process
water.
29,850 tons coal
(including fuel re-
quirements) (7068
Btu/lb); 2250 tons
makeup dolomite;
1. Oil billion SCF
air; 2.955 million
gal BFW; 159. 5
million gal cooling
water
Name of the
Process
Bi-Gas4
Molten Salt5
£
Synth ane
CO^ Acceptor
Comment on the Process
Coal is gasified with hydro-
gen. The resulting char
(with O? and steam) pro-
duces the hydrogen- rich
gas to sustain the hydro-
gasification process. The
operating pressure is
1000 psia. Exit gas tem-
perature is 1700°F. This
process produces 950 +
Btu/SCF gas. Uses all
U.S. coal.
O?, steam, and coal are
molten Na2CO3 catalizes
gasification. Gasifier is
operated 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 in-
steps; a free-fall C^
steam pretreatment zone -
a dense fluid-bed carbon-
izer, and a dilute fluid-
bed gasifier. H^-rich gas
is produced by use of C"2
in the reactor. The pro-
cess operates at 500 to
1000 psia. This process
produces 900+Btu/SCF
gas. Uses all U.S. coal.
Coal is charged to a devo-
latilizer and is contacted
at 300 psia with H2~rich
gas from a gasifier v«rs-
sel. Lime or dolomite
(the Acceptor) is added to
both vessels where it re-
acts with CO2- This pro-
cess produces 950+Btu/
SCF gas. Uses lignite and
subbituminous coal.
Synthesized
Fuel
250 million
SCF pipeline
gas {HHV 950
Btu/SCF)
250 million
gas
(914 Btu/SCF)
250 million
SCF pipeline
gas (HHV
927.1 Btu/
SCF)
262. 6 million
SCF/day pipe-
line gas {HHV
953 Btu/SCF)
By-Product
--
tar 501. 6 tons
NH3 88. 32 tons
_.
Thermal
Efficiency,
%
63
62
63
59
Comments on Pollution
Slagging gasifiers at high tem-
perature minimize sulfur content
of the ash. High off-gas tempera-
tures should reduce tars, amines,
phenols, etc. , in the quench
liquor.
The sulfur is recovered during
regenera ion o mo en
Nature of pretreatment does not
produce a separate, sulfur-laden
Sulfur treatment of the regenera-
tor off -gas is required.
-------
5.2.2 Engine/Vehicle Compatibility
Experience with the use of NG or SNG as an automotive fuel
has been mainly with spark ignition engines. Since natural-gas fueling sta-
tions are practically nonexistent, the use of it is presently confined to fleet
vehicles with their own depot refueling. 'In portable form, the gas is usually
stored on-board an automotive vehicle in high pressure bottles (typically at
2400 psi) with a regulation system to reduce the pressure at the carburetor
intake to a range of from 30 to 60 psi. The conversion of a gasoline engine
to NG is relatively simple because, with a gaseous fuel system, the carbu-
retor needs only to mix in the proper amount of air. The conversion con-
sisted in many cases of a gaseous-fuel carburetor fitted on top of the existing
carburetor such that, with the appropriate solenoid valves and switches, a
dual-fuel operation was possible with the same ignition timing and carburetor
setting (Ref. 5-9). In a dual-fuel system full advantage is not taken of high
NG octane numbers (105 to 115), which permit operation at higher compres-
sion ratios and with advanced ignition timing. NG engines can also operate
at leaner mixture ratios (20:1) than gasoline, and improved volumetric effici-
ency can be obtained with a redesigned inlet manifold. A dedicated NG system
will, therefore, show an improvement in fuel economy and reduction in pollu-
tants (HC, CO) on an energy-distance basis as compared to a dual-fuel system
(Ref. 5-10). Without a leaded fuel, however, some problems may still arise
with excessive valve wear. Hence, valve and valve-seat induction hardening
may be required of engine manufacturers. Various fleet operators, including
cities and gas utilities, have converted (starting in 1967) cars to CNG
(Ref. 5-9) or LNG; and General Services Administration (GSA) has under-
taken a large-scale (several thousand vehicles) conversion to natural gas,
both to CNG and LNG (Ref. 5-11). Thus, over the period of the last few
years, considerable experience was gathered with both CNG and LNG in auto-
motive vehicles. While some of the details regarding fuel consumption and
emissions will be discussed later it can be stated that, because of the higher
volume occupied by gas (than by semi vaporized gasoline in the air), there is
5-23
-------
a 10 to 15 percent drop in maximum engine power; that engine fuel
consumption in miles/Btu will be approximately equal to or better than that
of the modern gasoline engines equipped with emission control devices; and
that exhaust emissions may be able to meet the original 1976 Federal Emis-
sion Standards except for NO , which may require catalytic decompostion or
3C
exhaust gas recirculation (EGR). It is also reported (in Ref. 5-12) that NG
offers easy starting (even in cold weather), reliable idling, and smoother
acceleration. In most vehicles, these advantages offset the disadvantage of
loss in peak power.
Maintenance cost for spark ignition engines is lower for CNG
and LNG than for gasoline (Ref. 5-9) because gaseous fuels burn cleanly
without carbon buildup. Clean burning increases the life of the motor oil, the
spark plugs, and the engine. The following data can be quoted (Ref. 5-9) re-
presenting an average of automobiles and light-duty or medium-duty trucks.
Fuel
Gasoline
CNG
Total Miles
105, 969
101, 907
Maintenance Cost,
cents per mile
0.41
0. 26
One of the problems of the conversion from gasoline to CNG
or LNG is the weight and bulk of the tankage. Whether compressed to
3, 000 psi or liquefied at -260 F, the fuel is less dense than gasoline, and this
is well illustrated in Table 5-8. Thus, CNG tankage plus fuel equivalent to
20 gallons of gasoline will weigh approximately 350 pounds more and occupy
5. 5 times more volume than a gasoline system. LNG will require an addi-
tional 100 pounds weight and occupy approximately 2. 2 times the volume of
gasoline including tankage provisions. The size of the tank required for NG
vehicles depends on the type of operation, but fleet operators think that a daily
range of 100 to 125 miles is sufficient.
Both high-pressure tanks for CNG and cyrogenic tanks for LNG
are available commercially in various sizes. With LNG, certain boiloff loss
5-24
-------
Table 5-8. Tankage Comparison
(Refs. 2-1, 5-18)
Basis: Energy Equivalent of 20 gals gasoline3
(2. 27 X 106 Btu)
Gasoline
No. 2 Diesel Fuelc
Methane (gas) @ 3000 psi, 80°F
Methane (liquid) @ 1 atm
Fuel Alone
Ibs.
119
120
105. 5
105. 5
ft3
2.59
2. 28
12.40
4.06
Fuel +
Container
Ibs.
134
134
500
240
Jil
2.76
2. 50
14. 6
6.1
aOn an equal mileage basis (i.e., 270 miles) the fuel storage require-
ments must be adjusted for the thermal efficiency of the vehicle. In
the case of diesel power the above figures would be reduced by 1/3.
This assumed to apply to all gasolines whether from petroleum,
coal, or shale.
CThis assumed to apply to all distillate fuels whether from petroleum,
coal or shale.
5-25
-------
when the vehicle is nonoperating becomes unavoidable and is of the order of
3 to 4 percent per day. This must be added to the operating cost of LNG.
The cost of conversion of medium-size gasoline vehicles to
CNG or LNG was about $300 to $500 (the lower figure for CNG), but this cost
and the cost of refueling equipment was amortized in California Institute of
Technology operations in approximately five years because of savings in
maintenance and in fuel cost (Ref. 5-9) in a dual fuel system using 20 per-
cent gasoline and 90 percent CNG. With 100 percent CNG use, these costs
would be paid off in four years because of the low cost of CNG.
The characteristics of operation with natural gas (or SNG) of
a spark ignition engine (that is, cleaner combustion with low emission of
pollutants, high combustion efficiency, and possibility of operation at lean
air-fuel mixtures, as well as the storage problems) will apply to other engine
cycles. Automotive vehicle compatibility with natural gas used as fuel for
various engines is given in Table 5-9.
5. 2. 2. 1 Wankel Engine
The Wankel engine is characterized by high fuel consumption,
high hydrocarbon and carbon monoxide emission, low thermal efficiency, and
low oxide of nitrogen emission compared to Otto cycle spark ignition engines.
Its advantage lies in its small size and weight. Its operation with natural gas
(or SNG) is expected to be similar to that of Otto cycle spark ignition engines.
5. 2. 2. 2 Brayton Cycle Engine
Brayton cycle engines, represented by gas turbines, have
inherent fuel versatility. They have been run on methane with oxide of nitro-
gen emissions much lower than those with gasoline or propane ,(Ref. 2-1).
5.2.2.3 Rankine Cycle Engine
Rankine cycle engines use an external source to heat a working
fluid for conversion into work. The heat source may be solar or fossil fuel
energy; consequently, natural gas with its clean combustion and lean mixture
5-26
-------
Table 5-9. Automotive Vehicle Compatibility -with Natural Gas when
Compared with Gasoline Fuel (Ref. 5-18)
^^^^v^ Engine
Fuel ^^\^^
Gasoline
Natural gas
(methane)
Spark
Ignition
Otto Cycle
No
modification
Major mod-
ification.
Bulky fuel
storage.
Stratified
Charge
Pilot injec-
tion. High
compres-
sion ratio
for satis -
factory
ignition.
Major mod-
ification.
Bulky fuel
storage.
Diesel
Major
modi-
fication
Major
modifi-
cation.
Pilot in-
jection
of high
octane
number
fuel.
Gas Turbine
No modi-
fication
Major mod-
ification.
Bulky fuel
storage.
Rankine
No mod-
ification
Major
modifi-
cation.
Bulky
fuel
storage.
Stirling
No mod-
ification
Major
modifi-
cation.
Bulky
fuel
storage.
Ul
I
-------
operation may show an advantage over gasoline, but no data are available as
yet to substantiate this expectation.
5.2.2.4 Stirling Cycle Engine
Stirling engines use an external heat source, and the same
comments apply as to the Rankine engine.
5. 2. 2. 5 Stratified Charge Engine
The stratified charge engine utilizes high pressure fuel injection
or dual carburetors. With injection, combustion is nearly immediate after
injection and this frees the engine from the need for high octane fuels; however,
there is probably a minimum cetane number (maximum ignition delay) require-
ment. Fuels generally run in stratified charge engines range from methane to
No. 2 diesel fuel. Tests have been run with methane by Curtiss-Wright without
difficulty, but no emission data are available.
5. 2. 2. 6 Diesel Engine
Diesel engines are more efficient engines because of very high
compression ratios. Gaseous fuels are not injected into diesel engines in the
same way as liquid fuels (Ref. 2-1). Methane (or propane), when used in
diesel engines, is inducted with the air, compressed, and finally ignited by
the injection of high-cetane fuel. This scheme is very similar to the spark
ignition process. Compression ratios are limited to 14:1. Power is slightly
lower than that of a diesel engine with the same compression ratio.
5.2.3 Fuel Economy
Although a substantial number of motor vehicles are operating
now in the U.S. on CNG or L/NG, the data on fuel consumption are relatively
meager. One source (Ref. 5-13) quotes, for example, over 3,000 CNG and
500 LNG motor vehicles operating in the U.S. in 1972. Data on fuel consump-
tion of GSA vehicles demonstrated almost the same fuel consumption in miles/
gallon for LNG and gasoline (9. 15 to 9.3 mpg). Other findings were reported
in the SAE Engineering Congress in January 1972, where a paper cited
16 percent loss (on a mile/Btu basis) for CNG fueled cars (quoted in Ref. 5-13).
5-28
-------
Reference 5-14 quotes a 50,000-mile road test under varying
climatic conditions with a 1968 Dodge Dart and a 1968 Ford Fairlane, both
converted to LNG. The conversion was relatively simple. A 21-gallon,
double-walled, vacuum-jacketed vessel was installed for the fuel tank and
operated at pressures of 40 to 60 psia so there was no need for a pump. Com-
pression ratio was increased from 8. 00 to 9. 75 to take advantage of LNG high
octane number (>105), and a commercially available natural gas carburetor
was substituted for the gasoline carburetor with a fuel vaporizer tube fitted
into the carburetor intake. The fuel consumption test results are shown
below.
Gasoline
LNG
Dodge
17.8 mpg
15.4 mpg
Ford
15.3 mpg
13. 9 mpg
• Gross heating value for gasoline - 120,000 Btu/gal
• Gross heating value for LNG - 90,000 Btu/gal
"The consensus of operational experience with natural gas has
been that 100 cubic feet (lower heat value 100, 000 Btu) are equivalent in
average driving to one gallon of gasoline, " McJones and Corbell (Ref. 5-10).
This result is generally consistent with fuel -con sumption data for vehicles
operated on a seven-mode driving cycle. Results are given in Table 5-10
showing Btu/mile with NG running from 80 to 100 percent of gasoline values,
a 90-percent average.
The operation with natural gas is particularly advantageous
in city driving where the absence of an accelerator pump and the very lean
mixtures at idling contribute to Btu/mile figures lower than for gasoline.
Tests with single and multi- cylinder engines carried out in
Reference 5-12 with gasoline and CNG have shown that the CNG engine could
operate with lean mixtures up to air-fuel ratio of 25:1 (equivalence ratio* of 1. 5),
if / i
"Actual air-fuel ratio/ stoichiometric air-fuel ratio = ()
5-29
-------
Table 5-10. Vehicle Identification, Fuel Consumption, and Carbon Dioxide Data (Ref. 5-10)
K n ^ i n e
C las s
( u b i c Inch
Uispl.
(a)
0-140
(b)
140-250
(c)
200-2C>0
(rf)
2^0-300
(e)
500-375
m
375 +
Yr/Cyl
Displ.
'I rans .
1969/4
1 3-4 c.i.
Man.
1969/6
199 c. i.
Man.
1968/6
350 c.i.
Man,
1968/8
289 c. i.
Auto.
1969/8
302 c.i.
Auto .
1967/8
440 c. i.
Auto.
Teat
Conditions
Baseline
At conversion
After 4000 mi.
Baseline
At conversion
After 4000 mi.
Baseline
At conversion
After 4000 mi.
Baseline
At conversion
After 9000 mi.
Baseline
At conversion
After 4000 mi.
Baseline
At conversion
After 4000 mi.
Odometer
Mileage
3997
3295
7298
3081
3990
8402
9541
10559
14123
3172
4987
14060
3097
5443
9754
41188
44933
49097
Gasoline
Fuel
g /mi
128.0
131.0
127.2
153.6
170.0
180.0
176.0
205.0
195.5
-
—
173.0
213.0
236.0
222. 0
267.0
267.0
267.0
c°z
g/mi
405
415
403
487
539
571
558
650
620
-
—
548
676
748
704
846
846
846
Natural Gas
Fuel
cu ft/mi
-
4.58
4.86
-
5.46
6.08
-
7.84
7.92
-
—
7.2
-
9.62
8.66
-
9.61
10.26
C02
g/mi
-
263
279
-
313
349
-
450
454
-
—
413
-
552
497
-
552
588
Natural Gas3
CO£ Reference
%
-
9.5
10.4
-
8.7
9.2
-
10.4
11.0
-
—
11.3
-
11.0
10. 6
-
9.8
10.4
Btu/Mile
Nat. Gas/Gasoline
-
0. 84
0.91
-
0.77
0.81
-
0.92
.97
-
—
1.00
-
0.98
0.93
-
0.86
0.92
OJ
o
'Natural gas CO, reference is calculated as 15% X __2 na ' ^as and is presented as verification of the 11% value adopted by the
B 2 CO2 gasoline
California ARB for natural gas exhaust dilution corrections.
-------
while the lean mixture limit for gasoline was 19. 5:1 (equivalence ratio of
1.35). The minimum fuel consumption of CNG engines was at air-fuel ratios
between 19 and 20 and was improved with an advance in ignition timing. On
the other hand, HC and NO emissions decrease with retarded ignition and
leaner mixtures. Consequently, a compromise setting in air-fuel and ignition
timing has to be made for low emissions with acceptable fuel economy.
Summarizing the data quoted, it appears that,due to higher
combustion efficiency (better mixing) of natural gas and its ability to operate
at leaner mixtures (up to 1.45 equivalence ratio), a CNG or LNG engine may
have a lower expenditure of Btu/mile than 1968 model year engines. The
addition of more extensive emission control devices on later car models may
further tip the scale in favor of natural gas fueled engines which may require
only a device for suppression of NOX.
The result of this improved efficiency is a fuel-cost savings,
assuming that with continued price regulation the cost of 100 cubic feet of NG
in the form of CNG will be $0. 157 at the pump; a gallon of LNG will be $0. 245,
O-.
compared with a gallon of medium-octane gasoline at $0.265. With a medium-
size automobile driven, say, 15, 000 miles per year and equal consump-
**
tion per gallon of gasoline = 100 cubic feet of natural gas, at 13 miles per
gallon, the assumed fuel saving alone between gasoline and CNG would be
approximately $125 per year. To this should be added engine maintenance
savings previously discussed in this section.
5.2.4 Emission Effects
In contrast to the consumption data, a substantial amount of
information has been published on exhaust emissions for various automotive
engines operating on NG (both CNG and LNG). The data vary depending on
the type of vehicle, the extent of conversion which may or may not have used
the full NG system potential, and the type of road test over which the exhaust
* No taxes, 1971 prices (see Table 5-12). With continually changing 1974
prices, the fuel cost saving will continue to fluctuate.
** For equal Btu expenditure per mile
5-31
-------
emission check was performed. These data are limited to the standard Otto
cycle spark ignition engine; exhaust emission characteristics of other cycles
operating with NG or SNG are presently unknown.
To provide a firmer basis for the emission characteristics of
NG in a spark ignition engine, data for a single cylinder engine (Ref. 5-12)
are shown in Figure 5-3. These tests were conducted at the same indicated
horsepower for gasoline and NG. The following observations, which are con-
firmed in all road tests on multicylinder engines including the former seven-
mode federal cycle, can be made: the idling carbon monoxide emissions are
drastically reducedwithNG (as compared to gasoline) because of the possibility
of operating at higher equivalence ratios of 1. 2 to 1. 3 (lean mixtures )with NG;
lower HC content with NG because of better mixing and better combustion
efficiency; and, finally, lower NO content due again to the possibility of opera-
X.
tion at air-fuel mixtures leaner than gasoline.
Two factors are not evident in the comparison in Figure 5-3.
One is a drop in maximum power when operating a gasoline engine with NG
because of a drop in volumetric efficiency of the lower density NG. This drop
is approximately 15 percent, as was mentioned before, but it could be partially
recouped with a redesigned inlet manifold and higher compression ratios for
NG operation. The other factor of importance is the reduced activity of HC
emissions with NG as opposed to that of gasoline. Photochemical smog is
caused by the action of solar radiation upon inorganic and organic contaminants
which include NO , HC, and oxygenated HC derivatives. Because HC is the
most prominent of organic emissions, it has been given the most attention in
estimating smog-forming reactivity of exhaust gas (Ref. 5-12). Reactivity
of HC is usually expressed in terms of equivalent ethylene; that is, grams of
ethylene having the rate of NO? formation equal to that of one gram of organics
in the exhaust.
The comparison of reactivity of HC and aldehydes produced in
engines run with gasoline, NG, and SNG is shown in Table 5-11.
5^32
-------
UJ
o
X
i-
0§
2H
8*
m
a:
<
O
KEY
o GASOLINE
• NATURAL GAS
HORSEPOWER
CARBON
MONOXIDE
oc
UJ
o
QL
UJ
10
O
Q
UJ
I-
<
O
Q
Z
0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6
(fuel (fuel
rich) AIR-FUEL EQUIVALENCE RATIO lean)
*Actual Air-Fuel Ratio/Stoichiometric Air-Fuel Ratio - (0)
Figure 5-3. Power and Exhaust Emissions as a Function of Air-Fuel
Equivalence Ratio for Gasoline and Natural Gas Fuel
(Ref. 5-12)
5-33
-------
Table 5-11. Comparison of Exhaust HC Reactivity
(Refs. 5-12 and 5-15)
Fuel
Gasoline
NG
SNG
Engine
8 cyl.
1970
345-CID
7 -mode
test(2°>
Emissions, gm/mi
HC
4.4
2.8
2. 7
Aldehydes
0. 19
0. 12
0. 12
Reactivity, Ethylene
Equivalent, gm/mi
HC
2.47
0. 30
0. 13
Aldehydes
0. 12
0. 12
0. 13
Total
2.59
0.42
0.26
Fuel
Gasoline
Natural
Gas
Engine
Single
cylinder
CFR<19>
A/F
Equivalence
1.0
1.2
1.0
1.2
Reactivity, Ethylene
Equivalent, gm/ihp-hr
HC
0.63
0.46
0.092
0.073
Aldehydes
0.09
0. 18
0. 068
0.088
Total
0.72
0.64
0. 160
0. 161
5-34
-------
As can be seen, the total HC activity with NG is four to six
times less than that of gasoline. Further reduction of HC activity is
observed with SNG, primarily because of the absence of ethane in SNG. The
relatively higher concentration of ethane in NG (in this particular case,
8 percent) against that of SNG (in this case, 0.4 percent) resulted in higher
reactive hydrocarbons in the exhaust.
A considerable amount of work was done (Refs. 5-12, 5-15) on
the effect of air-fuel ratio and ignition timing on the level of pollutants in the
exhaust of NG and SNG fuel in comparison with gasoline-fueled engines. The
exhaust sampling technique consisted of a constant volume sampling (CVS)
system similar to that described in the Federal Register Vol. 35, No. 136
(Part II, 85, 81) July 15, 1970 . The test cycle on multicylinder engines
consisted of the seven-mode federal test cycle beginning with a cold start
(Ref. 5-12) and road tests (Ref. 5-15) on a level highway. The engines used
were automotive commercial engines of the 1968 to 1970 vintage with a dis-
placement range from 232 to 400 CID. In summary, it was found that with
NG operation CO emission was relatively independent on ignition timing and
dependent only on air-fuel ratio; that HC emissions were minimum at air-
fuel ratio of 19-20, and were decreasing as ignition timing was retarded; and
that NO values decreased with mixtures leaner than air-fuel ratio of 19 and
x
with retarded ignition timing (Ref. 5-12).
An SNG engine could operate with leaner mixtures than NG
before the vehicle performance was degraded. The difference was probably
due to improved flame propagation found with the hydrogen-bearing SNG (9. 8%).
It was also of importance to note the relative insensitivity of NG exhaust
emissions to the mileage accumulated and to the ambient temperature changes
(Ref. 5-12). Over the 10,000 miles accumulated, the average content in
the exhaust of CO (2 gm/mile), HC (1.5 gm/mile) and NOx (4 gm/mile)
remained constant for the vehicles tested. The effect of ambient tempera-
ture on exhaust emissions with NG and gasoline is shown in Figure 5-4.
5-35
-------
60
50
£ 40
E
E 30
o
o* 2O
10
0
e
o ^
CO
CC
O
O
£ 2
0
10
« 6
X
i 2
I
KEY
Gaiolint
Natural gat
I
I
20 40 60 80
AMBIENT TEMPERATURE, *f
100
Figure 5-4. Effect of Ambient Temperature on Exhaust Emissions
for Gasoline and Natural Gas Fuels (Ref. 5-12)
5-36
-------
In a dual-fuel engine operation (gasoline and NG) in which no
basic engine changes have been made, a substantial amount of emission data
was collected in the former federal seven-mode test cycle on a number of fleet
vehicles converted to NG. Both CNG and LNG were used in these tests. Some
of the emission data from Reference 5-10 are extracted in the table below.
Summary of Emission Data
Engine Type
140-200 CID,
1969, 6 cyl
Test Condition
At conversion
After 4000
miles
C0%
Gasoline
2. 34
3. 21
NG
0. 09
0. 12
HC, ppm
Gasoline
348
378
NG
106
74
NOX, ppm
Gasoline
855
840
NG
359
359
Approximate conversion to gm/mile for light duty vehicle:
HC - 100 ppm = 1.16 gm/mile
CO - 1% = 21. 63 gm/mile
NO - 100 ppm = 0. 35 gm/mile
x
A complete conversion to LNG (single-fuel operation) was
described (Ref. 5-14) in which the engine compression ratio was increased
and other engine modifications were made to take advantage of NG properties.
The results of emission test after 50, 000 miles are given in the table below.
Emission Test Data (Ref. 5-14)
Emission Type
HC, ppm
CO %
NO ppm
Car No. 1
Gasoline
175. 00
0. 69
1655.00
LNG
71. 00
0. 17
1135. 00
Car No. 2
Gasoline
177.00
1. 06
1570. 00
LNG
90. 00
0. 17
1277. 00
5-37
-------
Of interest are emission data obtained on a great number of
vehicles by the GSA which are given in Reference 5-9. These data show the
familiar emission trend of NG compared to gasoline.
GSA Emission Data (Ref. 5-9)
^^^^^ Emission
Vehicle ^""^^^
Automobiles
Light Trucks
Medium Trucks
HC, gm/mile
Gasoline
3. 13
5. 38
9. 83
NGa
0. 5
1. 1
1.63
CO, gm/mile
Gasoline
41. 8
47. 2
65. 0
NG
8.6
4. 94
5.96
NO , gm/mile
J\.
Gasoline
6. 21
3.64
3.71
NG
2. 15
1.79
2.38
Reduced to 50 percent of measured values to account for reduced
reactivity of HC with NG fuel
The emission data for the various alternative engines are
limited to use of gasoline only (Ref. 2-1), and these are discussed in Vol-
ume II of this report. The reduction of exhaust emissions with NG when
compared to gasoline, as shown by the test data, can be expected to occur
with other engine cycles because of the possibility of operation on leaner air
fuel mixtures, low-activity HC, and a "cleaner" combustion. This expecta-
tion must be confirmed by test data.
5. 2. 5 Toxicity and Safety Effects
The toxicity aspect of methane (or NG) was discussed before,
and Table 5-3 indicated that it is less toxic than gasoline and does not
present a health problem.
The safety aspects of NG operation (in the form of CNG or
LNG) were discussed in the literature by various operators who converted
their vehicle fleets to NG. The consensus was that NG may be less hazardous
than gasoline because its density is lower than air, which prevents formation
5-38
-------
of fuel-rich pockets near the ground in case of leakage, and because the
ignition temperature of NG is higher (1170°F) than that of gasoline (800 to
900 F). Inspection by insurance underwriters and fire protection officials
resulted in acceptance of the conversion vehicles as being as safe or safer
than conventional gasoline-powered vehicles.
However, the hazard of operation with NG, and particularly
LNG, should not be underestimated. The low boiling point of LNG at atmos-
pheric pressure will require overboard venting when the engine is not
operative, and the safe disposal of the boiloff by burning or dissipation in
free air must be ensured. This is particularly important for enclosed spaces
such as garages, since natural gas can form explosive mixtures with air over
a band of air-fuel ratios of 18.0 to 6.2.
Department of Interior regulations presently exist that concern
safety valves, fuel tanks, and inspection procedures. The insurance com-
panies are willing to insure CNG or LNG vehicles at nominal rates (i.e. ,
same as gasoline fueled) if properly designed (Ref. 5-9). Special vehicle
crush tests with 25 high-pressure CNG bottles were conducted by the Cal-Tech
Clean Air Car Project without any bottle failures or even a major displacement
(Ref. 5-9).
5. 2. 6 Handling, Storage, and Distribution Requirements
Storage and distribution of CNG or LNG requires either high-
pressure compressors and tanks at the distribution outlet or large cryogenic
tanks with appropriate pumping facilities for transfer of the cryogenic LNG to
a vehicle tank. Because of the cost of the installation and need for trained
personnel, it is unlikely that such equipment would be made available at the
300, 000 service stations in the U.S. , even if the supply of NG were plentiful.
One of the possible solutions to the distribution problem is for operators of fleet
vehicles such as GSA, urban transport agencies, utilities, etc. , to install
their own refueling equipment for CNG or LNG. This is, in fact, the present
arrangement for fleet vehicles converted to NG. The other possible solution
in the future is to install such refueling equipment only at the major service
stations selected on the basis of their large sales volume. The incentive to
5-39
-------
do that may arise from: (1) a future shortage and rise in cost of gasoline
fuel, (2) low cost of NG vehicle operation (lower maintenance cost, lower
NG cost, lower taxes), and (3) a continuing effort to achieve and maintain
high standards of exhaust cleanliness with minimum sacrifice in fuel con-
sumption. The partial changeover from gasoline to an alternative fuel, such
as NG, will not be accomplished rapidly; a period of some five to ten years
can be considered a reasonable time. Such a changeover has to be justified
not only by the improved operation of the prime mover with an alternative
fuel, but also by sound economics for such a changeover, taking into account
the overall U.S. picture of energy supply and demand.
5. 2. 7 Critical Research Gaps
Almost all of the data on automotive engines operating with NG
or SNG are limited to spark ignition engines. Even in this case the data are
insufficient, and more research is required on engine optimization for NG and
SNG to obtain the best compromise between fuel economy and emission level.
With regard to other engine cycles (such as stratified charge
engines, diesels, gas turbines, Rankine and Stirling cycles) there are at
present no published data on their performance or emission levels with either
NG or SNG. This is a research gap which has to be bridged for a future
selection of the preferred engine cycle and preferred alternative fuel.
Another gap exists in the hazard assessment of NG and SNG
(in the form of compressed or liquefied gas) for its use in automotive vehicles.
This includes distribution, vehicle installation, gas storage in confined spaces,
and safe disposal of boiloff. Appropriate studies of the problems involved
should be made and the necessary regulations issued.
5.3 CURRENT STATUS
5. 3. 1 Demand
The current production ofNGin the U.S. was shown in Table 5-5.
Perusal of Table 5-5 shows that import of natural gas in 1970 in the amount of
0. 9 x 10 ft was necessary to meet the growing demand which in the 1960s
5-40
-------
increased at an average rate of 6 percent per year. Gas utilization in 1971
by sector is shown below. The rate of LNG production in 1970 by U.S. -based
1971 Natural Gas Utilization per Sector
Percent of Total Gas Demand
Household
and Commercial
32.4
Industrial
46. 0
Transportation
3.6a
Electrical
Generation
18. 0
Total
100
Principally power for pipeline gas transportation.
(Ref. 1-1)
plants was 750 million cubic feet per day. However, only a small percentage
of NG in the form of either CNG or LNG is currently used for automobiles. It
was stated that in 1972 (Ref. 5-13) 3, 000 CNG and 500 LNG vehicles were oper-
ating in the U.S. These numbers have increased over the last year and are
expected to continue to increase in future years; but, in the near term, it
will not be a critical factor in the U. S. natural gas energy balance.
A decrease in the production of domestic NG is expected in the
period 1980 to 1985 and, because production of SNG and the supply of Alaskan
gas will not grow fast enough, a larger amount of NG will have to be imported
(see Table 5-5).
5.3.2
Consumer Costs
Consumer costs associated with operating an automotive
vehicle with NG or SNG in either compressed or liquefied form consist of
conversion kit cost (assuming that the customer presently runs a gasoline-
powered vehicle), maintenance cost, and fuel cost. The cost of refueling
equipment (e.g. , compressor or refrigeration units) for CNG or LNG is
prorated for amortization purposes in the cost of the fuel, which is shown
in Table 5-12. The maintenance costs were discussed briefly before, and it
appears that with NG or SNG the maintenance cost of an engine will be
reduced by 30 to 35 percent when compared to gasoline.
5-41
-------
Table 5-12. Fuel Cost Comparison (Ref. 1-2)
1973 $per 10b Btu
^^"^^^^^ Fuel
Cost Item ^~-1-- ^^^
At Terminal
Distribution
Total
(taxes not included)
Gasoline
(90 Octane)
2. 15
1.00
3. 15
NG
(CNG)
0.60
1.40
2.00
LNG
1.60
1. 50
3. 15
SNG
(Liquefied)
1.50
4.00a
5.50
ho
Includes liquefaction cost.
-------
There is a possibility of fuel energy saving when operating a
vehicle on SNG or NG as compared to gasoline, but for the purpose of cost
comparison equal Btus utilization is assumed.
The conversion cost will depend on the CNG or LNG tank size
and on the number of vehicles converted. Estimates given by fleet operators
varied between $300 to $500 per vehicle (the higher figure for LNG).
The economics of complete conversion will become more
attractive with the rising cost of fuel. Assuming a fuel saving cost of $125
per year, as shown in Section 5. 2.3, and assuming a maintenance saving
of 0. 15 cents per mile, based on data in Reference 5-9, a total annual
saving of $142 will result. The cost of the conversion kit would then be
amortized in 2-1/2 to 3 years at 1971 prices. In the current rapidly fluctuat-
ing fuel price market, however, this type of tradeoff analysis must be
reviewed on a continual basis, particularly if government price regulations
are relaxed or eliminated. Furthermore, since SNG would ultimately have
to be used, because of limited NG supplies, the higher-priced SNG would be
competitive only at the time when gasoline prices have risen substantially
above the figures cited for 1971.
5.4 PROJECTED STATUS
5. 4. 1 Availability
5.4.1.1 Near Term (1975 to 1985)
The availability of NG and SNG in the 1975 to 1985 time per-
iod was discussed briefly before and was presented in Table 5-5, which in-
dicated the growing need for NG/LNG imports and the beginning of SNG, al^-
beit in small quantities, in 1980. Projected figures for SNG differ from diff-
erent references. A projection from Reference 5-7, for example, is given in
Table 5-13 showing SNG production volumes, both from coal and petroleum
liquids, larger than those predicted (Refs. 1-1 or 5-2). Projections for
Case I (Ref. 5-2) are 2. 3 percent of total domestic supply in 1980,
5-43
-------
Table 5-13. Comparison of U.S. Energy Forecasts by the Bureau of
Mines and Institute of Gas Technology (IGT)(Refs. 1-1
and 5-7)
Total Primary Energy Consumption,
quadrillion (1015) Btu
Source, percent
Petroleum
Shale Oil
Coal
Dry Natural Gas
Nuclear Energy
Hydro and Geothermal Energy
Oil Supply
Total, million bbl/day
Sources, percent
Total Domestic U.S. Petroleum
Liquids, Excl. North Slope
Total North Slope Liquids
Shale Oil
Sync rude from Coal
Net Imports
Gas Supply
Total, trillion cu ft/year
Sources, percent
Lower 48 Production
Alaska
Net Pipeline Imports
Net LNG Imports
Syngas from Petroleum Liquids
Syngas from Coal
Coal Consumption
Total, million tons /year
End Use, percent
Conventional
Syngas
Sync rude
Exports
1985
Bureau
of Mines
116.6
42.6
0.9
18.4
24.3
10. 1
3.7
25.0
36.8
8.0
2.0
53. 2a
29. 537
I 7 0 Q
> f J- 7
13.9
5.4
I f. a
f \J t O
980
82. 3
8.8
--
8.9
IGT
125.2
43. 1
0.5
18.9
17.5
16.8
3.2
26.9
36. 1
7.4
1. 1
0.7
54.7
25.6
67.2
5.9
9.8
6.2
6.6
4. 3
1028
79.8
6.4
1.8
12.0
2000
Bureau
of Mines
191.9
36.2
1.0
16.3
17.7
25.7
3. 1
35. 5
16.9
10.0
2.8
70. 3a
38.459
\
f 57. 6
19.3
8.8
>< A •!
I 1 T • J
1418
70.7
21.7
7.6
IGT
228.2
32.8
2.8
24.6
11. 1
26.3
2.4
43.0
18.6
7.0
7.0
9.3
58.1
35.3
37.4
12.7
15.6
8.8
2.3
23.2
2333
54.4
21. 1
16.3
8.2
Based on present trends and policies; may include additional domestic supplies
from conventional sources or from synthetics, depending on governmental pol-
icies, environmental restraints, economic conditions, and technological
developments.
5-44
-------
7.3 percent in 1985. Reference 1-1 predictions for the same period are
three percent and 8.4 percent, respectively. With imports removed from
supply figures, Reference 5-7 predicts SNG production of 12.9 percent of
total domestic gas in 1985. Reference 1-2 provides a more detailed forecast
of SNG production through the year 2000, and the data are shown in
Table 5-14. The Hi-Btu Syngas data are in reasonable agreement with IGT
forecasts shown in Table 5-13. However, even with optimistic projections
for SNG, only NG either in the form of CNG or LNG would be considered as
an alternative fuel in the near-term period.
Industrial and electricity generation users now rely on a mix
of coal, liquid petroleum, and natural gas fuels. A small increase in the
percentage of coal used by these consumers would make sufficient NG avail-
able for future growth in transportation needs. However, the application of
NG in the transportation sector may be limited not so much by the gas supply
in the near-term period as by other inhibiting factors, such as distribution
and s tor ability.
Summarizing the comments it can be stated that, in addition to
other fuels discussed in the report, NG in the form of CNG or LNG cannot be
considered a viable candidate for alternative fuels on a large scale within
the near-term period.
5.4.1.2 Far Term (1985 to 2000)
In the far term, development of advanced engine cycles are
expected to be completed, and the most efficient engine may be available in
mass production.
SNG as an alternative fuel will be of significance since, as
noted previously, 20 to 25 percent of the total gas supply will come from coal
gasification (see Tables 5-5 and 5-13). The most probable SNG use would be
in stationary power plants, thus releasing more of the liquid fuels for trans-
portation use. Gas from oils is not likely to be of importance, even in this
time period, with estimates of only 2. 3 percent of the gas supply coming
from liquid petroleum. (See Table 5-13.)
5-45
-------
Table 5-14. Plausible Schedule for Buildup of
Coal Syngas Production
(Ref. 1-2)
Year
1978
1981
1982
1983
1984
1985
1986
1990
1995
2000
Annual Production, TCF
Hi-Btu
0. 08
0.4
0. 55
0.7
0.9
1. 1
1. 3
2.4
4. 1
5.6
a
Lo-Btu
-
0. 2
0. 25
0.4
0. 6
0.8
1. 1
2. 3
4. 2
6.0
Total
0.08
0.6
0. 8
1. 1
1. 5
1.9
2.4
4.7
8. 3
11.6
Coal
Required
Million ST3
5
37
48
62
91
115
195
235
500
700
Lo-Btu gas reported in terms of Hi-Btu gas equivalency,
corrected to a heat content of 1000 Btu/CF.
i. e.
In terms of bituminous coal. Corresponding tonnages of
subbituminous coal or lignite would be higher because of the
lower Btu contents of these lower rank coals. Tonnages may
be overstated because of the lower amount of process energy
required to make Lo-Btu gas, i.e., by not having to use
energy for the methanation step required in the production
of Hi-Btu gas. On the other hand, the conversion of Lo-Btu
gas to methanol does have an energy requirement and, to the
extent that the end product is methanol rather than Lo-Btu
gas, the coal requirement on the basis of product Btu con-
tent would approach that of Hi-Btu gas production.
5-46
-------
5.4.Z Projected Consumer Cost
The projected cost of NG in 1970 dollars is shown in Table 5-15.
These figures represent an average "required cost" at the well-head to obtain
a 15-percent Return on Investment (ROI). Depending on the rate of investment
and the discovery rate, the 1985 prices per thousand cubic feet will be higher
compared to 1971 prices by a factor of 1. 6 to 2. 3.
It has to be pointed out that the cost projections in (Refs. 1-1,
5-2, 5-7, and others) were made without an assumption of steep increases in
prices of petroleum products, and of higher rates of inflation such as are
taking place in the 1973 to 1974 period. Consequently, the figures quoted in
this Section -will require an upward revision, if the increased inflationary
trend continues into the 1975 period and beyond.
The SNG cost of $1. 50/10 Btu at the refinery (See Table 5-12)
was quoted for the post-1985 period. These costs will vary comparatively
little with the various processes and will depend mainly on the cost of raw
material, that is, coal. The formula for derivation of the- cost of SNG in
1971 dollars, f. o. b. mine, is based on data from IGT (Ref. 5-17):
• SNG cost ($/10 Btu) = coal cost ($/ton) X 0. 16 + 0. 7.
The projected cost of surface coal, which is of primary inter-
est in the coal gasification process, is shown in Figure 5-5. The consumer
cost of SNG (no taxes, 1973 dollars) is also shown in Table 5-12.
Thus for a $5 per ton cost of coal, the cost of SNG is $1. 50/10
Btu; for $7 per ton cost of coal, cost of SNG would be $1. 80/10 Btu.
Further cost increases for NG and SNG could be extrapolated
into the 1985 to 2000 far-term period, but there were no data available in the
literature to support such an extrapolation. However, assuming speculatively
an annual 5 percent inflation rate between 1985 and the year 2000, and 3 percent
increase in mining cost because of the accessibility and depth of gas deposits,
the manufacturing cost of NG shown in Table 5-15 for 1985 could be increased
5-47
-------
Table 5-15. Required Natural Gas Field Price in 1970 Constant Dollars
at 15% Return on Net Fixed Assets (Excluding Alaska)
oo
National Petroleum Council - 1972
(Ref. 5-2)
Drilling Rate
Finding Rate
1970 (Actual)
1971
1975
1980
1985
Cents /MCF
Case I
High
Growth
High
17. 1
23.5
26.7
33.7
43.6
Case II
Medium
Growth
High
17. 1
23.5
26.2
31.8
39.8
Case III
Medium
Growth
Low
17. 1
23. 5
27.9
37.8
53.0
Case IV
Current
Downtrend
Low
17. 1
23. 5
26.6
31.6
38.7
-------
01
I'
cc
d
z
o
LU
0-
cc
O
Q
1965
EFFECT OF 10% DECREASE
IN PRODUCTIVITY
EFFECT OF 10% INCREASE
IN PRODUCTIVITY
r-45
BASE CASE PRODUCTIVITY
(Right Scale)
LU
O
<
J J L
- 40
_JCC
L-35
to
o
D
Q
O
CC
a.
I I L
1970
1975
YEAR
1980
1985
Figure 5-5.
Effect of Productivity on the Average Value of Coal
From Surface Mines (Constant 1970 dollars - 15%
of Return, 3% growth rate) (Ref. 5-2)
5-49
-------
by a factor of 2 for the year 2000. Similar reasoning could be applied to the
projected cost of SNG.
5.4.3
Capital Cost and Tinning Implications
The cost of both capital investment and exploration in the
development of NG resources and production plants was estimated in Refer-
ence 5-2, and data extracted from that source are shown in Table 5-16,
below.
Table 5-16. Exploration and Development Expenditures
for NG in U.S. (Ref. 5-2)
(billion 1970 $)
^""-\^Year
Case ^.^
I
II
III
IV
1971
2. 1
2. 1
2. 1
2.0
1975
2.7
2.4
2.4
1. 8
1980
4.6
3.6
3.6
1.7
1985
5. 8
4. 3
4. 3
1. 5
15 -year Total
58. 7
47. 1
46.3
26. 5
Thus, for the highest rate of exploration (Case I), the invest-
ment expenditure is predicted at $58. 7 billion, and at the intermediate case
(Case II or III) it is approximately $47 billion. To this must be added the
capital investment for SNG plants and for coal mines supporting such plants.
For SNG, a typical investment cost of a million cubic feet per
day coal gasification plant are given in Reference 5-1 based on El Paso Natu-
ral Gas Company estimates. Cost for water supply lines, reservoir, etc.
for the plant itself would cost approximately $40 million. Process modifi-
cations needed to meet stringent sulfur emission restrictions and other en-
vironmental requirements total, perhaps, an additional $60 million. A rea-
sonable approximation of plant cost itself based on these data is $1 to $1. 2 per
cubic foot per day.
5-50
-------
The estimated implementation schedule for production coal
gasification plants is shown in Table 5-17. The output of 40 plants in 1990
will correspond to approximately 3. 2 X10 ft per year, which is in reas-
onable agreement with projections in Table 5-5.
The cumulative investment cost of these plants is estimated
to be approximately $10 to $12 billion. The plants are expected to consume
approximately 2.6 X 108 (Ref. 5-1) tons/year of coal in 1990 at a minimum
capital approximately $3 billion for water supply (for cooling and steam) and
other facilities and perhaps $2 billion for environmental control, with a total
of approximately $20 to $21 billion. This figure is close enough to the $25
billion quoted in Reference 5-16 for coal-associated synthetic gas and crude
projects by 1990. Such investment funds may be difficult to raise in light of
the energy industry's high risks associated with new processes and plants,
and there may be need for governmental subsidy or for participation of the
oil-producing nations themselves (Ref. 5-16).
5.4.4 Impact with Other U. S. Energy Requirements
The transportation sector has to compete in the gas and liquid
petroleum products with the household, commercial, industrial, and electri-
cal generation sectors. Since it appears that in the near-term and possibly
even in the far-term period, energy for the transportation sector will be mostly
based on petroleum fuels, it is necessary to examine the other sectors, mainly
the industrial and electric generation, for possible use of coal or nuclear fuels
to relieve demand on petroleum fuels.
From the general review of the energy resources in the Intro-
duction Section, it appears that competitive demand for liquid petroleum and
NG will exist through the year 2000. Some easement in that shortage in self
sufficiency of the United States could be realized by an accelerated program
of coal mining and more rapid conversion of the industrial and electrical sec-
tors toward coal, as well as utilization of electrical energy for automotive
application in the far-term period.
5-51
-------
Table 5-17. Cumulative Number of 250 Million Cubic Feet/Stream Day
Coal Gasification Plants (Ref. 5-7)
Year
Lurgi
New Process A
New Process B
New Process C
Total
77
1
•
•
•
1
78
1
•
•
•
1
79
2
•
•
•
2
80
2
•
•
•
2
81
3
1
•
•
4
82
3
1
1
•
5
83
4
2
1
1
8
84
5
3
2
1
11
85
6
4
2
2
14
90
6
14
4
16
40
5.4.5
Factors Which May Inhibit Use
One of the major problems in the widespread use of an alterna-
tive fuel such as NG or SNG is the distribution system. There are at present
approximately 300, 000 service stations and 300 terminal outlets in the U.S.
for distribution of gasoline. The investment in station refueling equipment for
CNG is approximately $25, 000 and for LNG $50, 000. It is apparent that such
an investment at a service station has to be justified on the basis of economics.
It could possibly be considered for major stations with large sales volume if
the number of vehicles on the road equipped with CNG or LNG conversion kits
is large enough to guarantee a return on the investment. The number of CNG
or LNG vehicles will, in turn, depend on the economy of operation whereby
the user must be convinced of safe operation, good fuel economy, and less
costly maintenance. Considering these factors, it appears that in the near-
and probably the far-term, the use of NG will be limited mainly to fleet
vehicle operation with their own depot refueling. Experience obtained in
operation of such vehicles, and well proven fuel and maintenance economy,
may be a factor in gradual proliferation of its use, particularly if the prospect
for future supply of NG and SNG appear favorable. For the year 2000, this
combination, combined with possible severe limitation of liquid petroleum
imports in the future, may force the contribution of NG or SNG powered
5-52
-------
vehicles from the predicted 6. 1 percent to greater than 12 percent, based on
the prediction of Reference 5-7.
5.4.6 Critical Technology Gaps
The technology gaps existing in the application of NG or SNG
to automotive vehicles have already been discussed.
The technology in coal gasification is well founded, and funding
is being accelerated to bring the various processes into the production stage.
The environmental problems connected with large-scale sur-
face coal mining, previously discussed, remain to be solved. The large
investment funds for continuing NG exploration and production, as well as
funds for large-scale operation of coal gasification plants, must be planned
well in advance of need.
The vehicle storage tanks for liquified NG or SNG require
insulation improvements for reducing their bulk and weight. The quality of
the insulation and tank suspension should be aimed at minimizing the boiloff
to one percent per day.
Safety aspects of the storage and use of compressed or liquid
gas in automotive vehicles must be covered by appropriate regulations which
must be developed.
5.4.7 Potential for National and Regional Transportation Use
The potential for NG and later for SNG-powered vehicles is good
for regional transportation use and fleet vehicle operation, but the national
use will be inhibited by the need for a costly distribution system. The possi-
bility of conversion and operation of a large number of vehicles from selected
refueling points for fleet operation reduces the cost of conversion equipment
and leads to early amortication of the investment. A possible saving in fuel
energy of approximately 20 percent, as compared to 1976 spark ignition gaso-
line engines equipped with emission control devices, and lower maintenance
cost will be additional factors favoring such a conversion. The fuel economy
5-53
-------
of NG or SNG will result mainly from its characteristic high octane number
( > 105) permitting operation of engines at higher compression ratios,
advanced ignition timing and lean mixtures, while the unleaded gasoline com-
ing into use require reduced compression ratios and retarded ignition.
5-54
-------
SECTION 6
-------
SECTION 6
PROPANE AND BUTANE
Propane and butane are variously known as LP-gas (liquid
petroleum gas), bottled gas, or tank gas. LP-gas actually consists of various
petroleum-associated chemical compounds whose boiling temperatures are
below normal room temperature but above those of the constituents of natural
gas (i.e., methane and ethane). LP-gas comprises several of the aliphatic
hydrocarbons, such as propane, propylene, butane, butylene and butadiene.
The principal commercial products are propane and butane, and, because of
the chemical and physical properties of these compounds (higher octane rating
and other desirable characteristics), they are the only potential LP-gas
candidates considered in this study as alternative automobile fuels.
6.1 CHARACTERIZATION
6. 1. 1 Chemical Composition
Propane and butane belong to the saturated paraffin hydrocarbon'
group, having the general chemical formula, C H9 _, where n is the number
~
n.
of carbon atoms. Propane, C_HR, exists in but one chemical structural form,
while butane, C,Hlf), can exist in one of two isomeric forms (i.e., as n-butane
or isobutane).
6. 1.2 Physical Properties
Both propane and butane are gaseous hydrocarbon fuels under
ambient conditions, having boiling points of -44°F and 31 F respectively at
atmospheric pressure. Thus, they are more volatile (lower boiling temper-
ature) than gasoline mixtures but are less volatile than natural gas. Conse-
quently, they can be stored easily in a liquified state by either pressurizing the
Storage container or cooling them below their relatively moderate boiling po-
ints. Of the two, propane is more generally suitable for on-the-road automo-
tive vehicles because of its lower boiling point and higher octane rating.
6-1
-------
The lower boiling point of propane permits its use in colder climates, where
butane may require a separate heating source to vaporize the fuel for initial
engine starting. Propane does, however, require higher tank storage pres-
sures than butane to maintain it in a liquid state, but these pressures are
still very moderate for pressurized systems and do not present any difficulties.
Propane and butane are both odorless and colorless gases;
consequently they require the addition of a strong-smelling additive to enable
the user to detect leaks. Pertinent physical properties are listed in Table 6-1
for both pure and commercially delivered products (Ref. 6-1). Important
characteristics for automotive fuels are the higher heating value (heat of
combustion), combustion temperature and the octane number. These charac-
teristics for propane, butane, and gasoline are compared in the following
table.
Propane* Butane* Gasoline
Net Heating Value
Btu per Pound 19,950 19,700 19,080
Btu per Gallon 85,000 96,000 117,000
Combustion Temp. °F 3,595 3,615 3,700
Motor Octane 96 89 83-95
This table indicates that propane, butane, and gasoline are generally comparable
as fuels. In terms of higher heating value, propane and butane are higher than
gasoline on a weight basis but lower on a volume basis (gasoline has a higher
density).
6. 1. 3 Sources and Domestic Reserves
The principal sources of LP-gas are (1) crude-oil wells, (2)
natural gas wells, (3) light hydrocarbon gas wells, and (4) refinery operations.
In all of these sources, LP-gas is generally a by-product of derivation or
production of natural gas and gasoline. The LP-gas domestic reserves are
therefore related to the domestic crude oil and natural gas reserves.
*
Propane and butane properties are for average commercial products.
6-2
-------
Table 6-1. Physical Properties of Propane and Butane (Ref. 6-1)
Physical Properties
Vapor Pressure, psig @ 70°F
@ 100°F
@ 130°F
Specific Gravity of Liquid® 60/60°F
Initial Boiling Point @ 14. 7 psia, °F
Weight Per Gal. of Liquid @60°F, Ib
Specific Heat of Liquid @ 60°F, Btu/lb°F
Cu Ft of Gas @ 60°F, 30" Hg, per gal liq @ 60°F
Spec. Vol of Gas, @ 60°F, 30" Hg, cu ft/lb
Spec. Heat of Gas @ 60°F(Cp), Btu/lb°F
Spec. Grav. of Gas (Air = 1) @ 60°F, 30" Hg.
Ignition Temp, in Air, °F
Max. Flame Temp, in Air, °F
% Gas in Air for Max. Flame Temp.
Max. Rate of Flame Propagation in 25 mm
Tube, in/ sec.
Limits of Flammability, % gas in air
@ Lower Limit
@ Upper Limit
Required for Complete Combustion, Ib air/
Ib gas
Latent Heat of Vaporization @ Boiling Point
Btu/lb
Btu/gal
Total Heating Values (after vaporization)
Btu/lb
Btu/gal
Btu/cu ft
Propane
Pure
0. 51
-44
1.56
808
3, 573
--
15. 70
--
21,661
2, 580
Commercial
124
192
286
0.509
-51
4.24
0.588
36.28
8.55
0.404
1.52
920-1,020
3,595
4.2-4.5
33.4
--
2.4
9.6
15.58
185
785
--
21, 560
91,500
2,522
Butane
Pure
0.584
31
2.01
--
--
21, 134
Commercial
31
59
97
0.582
15
4.84
0.549
31.46
6.50
0.382
2.01
900-1,000
3,615
3.3-3.4
34.3
--
1.9
8.6
15.3
167
808
—
21, 180
102,600
3,261
Notes: 1. The physical properties of commercial propane and butane can vary widely depending
on the varying amount of impurities included.
2. Commercial properties obtained from
Bland and Davidson, McGraw Hill Bool
Petroleum Processing Handbook by
c Company.
6-3
-------
Proven reserves of natural gas liquid at the end of 1970 were about 7.7 billion
barrels (Ref. 6-2). These natural gas liquids are composed of LP gases and
ethane, natural gasoline and isopentane, and other products. Liquified petro-
leum gas accounts for slightly over one half of these natural gas liquids.
Considering a current domestic use rate of gasoline of approximately 80 billion
gallons per year, the total LP-gas reserves would last about one year if used
exclusively as an automotive fuel.
6. 1.4 Manufacturing Methods
The primary production of LP-gas (approximately 74 percent
of total production) comes from natural gas processing. LP-gas is recovered
from natural gas by three basic recovery methods: compression, adsorption,
and absorption. The most common process for recovery of LP-gas and
natural gasoline liquids from natural gas is the oil absorption process. A
simplified flow diagram for a typical oil absorption process is shown in
Figure -6-1. (Ref. 6-3).
The natural-gas feed exchanges heat with the residue gas from
the overhead of the absorber followed by further cooling by refrigeration to
about -35 F. It is then dried by means of diethylene or triethylene glycol,
which is injected into the gas feed ahead of the cooler. The gas from the
cooler enters a glycol separator where glycol containing water is separated
from the natural gas as a liquid phase from which, by distilling off the water,
a dry glycol is recovered for recycle to the injection. The gas and any hydro-
carbon condensate passes to the base of the absorber, where it is contacted
with absorption oil at -35 F entering at the top of the absorber. About 85 per-
cent of the propane and essentially all of the higher-boiling hydrocarbons are
absorbed in the oil. The overhead residue gas from the absorber, at about
-15 F, is heat-exchanged with the inlet gas after which, at 40°F and 600 psig,
it flows to the booster where the pressure is increased to that of the natural
gas line.
6-4
-------
COMPRESSOR
START
©
EXCHANGER
INLET GAS
REFRIG-
ERATING
COOLER
GLYCOL
INJECTION
a-
i
t^
a
0
!<
tr
<
)Q-
LU
V)
o:
LU
tt
8
m
_j
o
«S i
r ^
IREFRIGEF
^JL CHILLE
O x'
X
HYDRAULIC
TURBINE
GLYCOL TO
REGENERATION
EXCHANGER
in
K
LJ
1-
1-
~
_J
a.
>f>
z
^
^
m
SULFUR
REMOVAL
DRIER
oc.
UJ
N
D
ffi
LJ
Q
•n-BUTANE
ISOBUTANE
N
Z
Q.
o
at
a.
DRIER
PROPANE
r -^a
Cf.
0
/ il
EXCHANGER
\
UJ |j
u.
NATURAL GASOLINE LIQUIDS
-^•RESIDUE NATURAL GAS
BOOSTER
Figure 6-1.
Refrigerated Absorption Process for the Production of LP
Gas and Natural Gasoline Liquids (Ref. 6-3)
-------
The rich oil from the absorber is expanded through a hydraulic
turbine to recover power. The fluid from the turbine is flashed in the rich-
oil flash tank to about 300 psig and -26 F. The flashed vapor is compressed
to the inlet pressure before recycling. The oil phase from the flash passes
through another exchanger and to the rich-oil deethanizer. The overhead gas
product from the deethanizer, rich in ethane, is compressed and used for
producing petrochemicals or is added to the residue-gas stream.
The bottoms product from the ethanizer, consisting of
absorption oil and absorbed propane and higher-boiling hydrocarbons, is fed
to the lean-oil fractionator. The LP-gas and natural-gasoline components
are removed as overhead product from the absorption oil which is removed
as bottoms product.
The lean oil from the lean-oil fractionator passes through
several heat exchangers and a refrigerated cooler to lower the temperature
to -35 F. Part of the lean oil is used as reflux to the lower section of the
rich-oil deethanizer. Most of the lean oil is presaturated in the top section
of the deethanizer, cooled again to -35 F and returned to the top of the
absorber, thus completing the oil cycle.
The overhead product from the lean-oil fractionator, consisting
of propane and heavier hydrocarbons, enters the depropanizer. The depro-
panizer overhead product is treated to remove sulfur and water to provide
LP-gas specification propane. The bottoms product from the depropanizer
containing butane and higher boiling hydrocarbons enter the debutanizer.
The debutanizer overhead product, mixed butanes, is treated to remove
sulfur and water and enter the butane splitter. Isobutane is produced as
an overhead product from the splitter and n-butane is produced as bottoms
product. Natural gasoline is produced as bottoms product from the
debutanizer.
6-6
-------
6.2 SUITABILITY FOR USE AS AN ENGINE FUEL
6.2.1 Engine/Vehicle Compatibility
The use of LP-gas as an internal combustion engine fuel has
a long history, dating back to the early 1930s. The early commercial product
was an uncertain mixture of propane, butane, and other gases with variable
chemical and physical properties. Its use as an engine fuel resulted in many
problems, leading to disagreements as to its advantages and disadvantages.
Some of the early problems involved frozen fuel lines, hard starting, clogging
filters, oil contaminants in LP-gas, blown head gaskets, burned valves,
scored pistons, broken rings, etc. Many of these problems were attributed
to the variations in constituent gases incorporated in the commercially
available product. Also, the use of mixtures high in butane resulted in some
further difficulties when operated in cold climates; e.g. , vaporizing the fuel
during engine starting, due to the relatively high condensation temperature
of butane (31°F). In order to solve these problems by obtaining a more
standardized product, the National Gas Processors Association (in 1962)
adopted a specification for a propane engine fuel, which was designated HD-5.
This engine has a minimum of 90 percent propane, a maximum of 5 percent
propylene, and meets certain other standards of purity. The following dis-
cussion on the suitability of liquefied petroleum gas as an engine fuel refers
to HD-5 or higher grades of propane.
Propane appears suitable for use in all of the alternative engines
currently being considered. For the conventional reciprocating spark ignition
engine, operation with propane involves several differences from operation
with gasoline. The required propane equipment consists of:
a A pressurized tank to contain propane as a liquid (with a
working pressure of 250 psig, and weighing about 80 pounds
for a tank capacity of 20 gallons)
b A regulator/convertor with the dual functions of vaporizing
the fuel from liquid to a gas and of regulating the gas pressure
to the propane "carburetor"
6-7
-------
c. An automatically controlled shutoff valve that positively
stops the flow of fuel when the engine is not in operation
d. A propane "carburetor" or device for mixing gaseous fuel
and air
e. Excess pressure-relief valves in the tank and in some installa-
tions between the tank and shutoff valve and engine to avoid
potential overpressure conditions. The pressure-relief valves
are connected to a high level vent pipe. These items replace
the atmospheric-pressure fuel tank, fuel pump, and carburetor
of a gasoline-operated engine. The modification involved in
operating other engine candidates on propane are not defined
at this time, but they are not expected to be significantly
different from those indicated for the conventional recipro-
cating spark ignition engine.
6. 2. 2 Fuel Economy Effects
In general, the use of gaseous fuels will provide for better
mixing of the fuel-air charge, particularly in multicylinder engines where
uniform distribution of the mixture from cylinder to cylinder and within
each combustion chamber is difficult to achieve. This permits leaner
mixtures to be used, which may result in some measurable gain in specific
fuel consumption. Additionally, for the spark ignition engine, the high
octane rating of propane permits a higher compression ratio to be used
in the design, thereby improving the thermal efficiency and, accordingly,
specific fuel consumption characteristics of the engine. It should be noted,
however, that the current trend in automotive engine design is toward lower
compression ratios to minimize the production of NO .
The overall improvement in fuel economy attainable through
the use of propane in different engines is difficult to predict. For the con-
ventional spark ignition engine, different users have experienced varying
results, depending on the condition of the engine, weight of the vehicles,
air-fuel mixture ratio, engine power setting, and a host of other variables.
Reference 6-4, for example, indicates a reduced specific fuel consumption
(SFC) of 13 percent by using propane instead of gasoline.
6-8
-------
6.2.3 Emission Effects
Use of propane as an automotive fuel minimizes the problem of
controlling evaporative HC emissions in conventional reciprocating engines,
since the storage and supply systems are pressurized. Venting will occur only
during excessively high operating and storage temperature conditions, when
the propane is vented through one or more pressure-relief valves. Usually, a
single valve located in the fuel tank is provided. The problem of liquid evapora-
tion, as from a gasoline carburetor, is nonexistent. In any of the engine candi-
dates under consideration, the use of a fuel introduced as a gas tends to pro-
mote even mixing and thereby enhances combustion, permitting leaner mixtures
to be used without significant loss in engine performance or response. Leaner
mixtures tend to reduce HC, CO, and (at very lean mixture ratios) NO
emissions. Further, the reactivity of the exhaust products (tendency to react
with sunlight to form photochemical smog) is reduced when burning propane,
as the exhaust products contain a smaller fraction of reactive olefins than the
exhaust products of gasoline-like fuels.
For the conventional internal combustion engine, the reduction
in emissions using-propane instead of gasoline has been measured by a number
of investigators. However, test data based on the use of the 1972 or 1975
federal certification test procedures are limited, and these data are largely
comprised of tests on older model year cars. Table 6-2 summarizes some of
the available emission test results for propane versus gasoline as used in
conventional engines (Ref. 6-5). It will be noted that in a f,ew instances one
or more of the measured pollutants showed an increase in emission levels
when propane was used. However, the bulk of the data shows that substantial
reductions in exhaust HC, CO, and NO are concurrently achievable by the use
X
of propane fuel.
Much of the variability in the data shown in Table 6-2 is
undoubtedly due to variations in the engine settings for air-fuel ratio and
spark timing. The influence of these factors on emission levels and the
potential for operating at extremely lean mixtures with propane fuel are
6-9
-------
Table 6-2. Typical Emission Reduction through
Gaseous Fuel Conversion (Fig. 6-5)
Vehicle
Converted 1968 Buick 350
Stock 1968 Buick 350
Percent Reduction
Converted 1969 Ford 351
Stock 1969 Ford 351
Percent Reduction
Converted 1968 Ford 302
Stock 1968 Ford 302
Percent Reduction
4 Converted 1969 Chrysler 318s
Stock 1969 Chrysler 318
Percent Reduction
2 Converted Rambler 343s
Stock 1969 Rambler 343
Percent Reduction
Converted 1969 Ford 429
10 Converted 1970 Ford 250s
10 Stock 1970 Ford 250s
Percent Reduction
10 Converted 1970 Rebel 232s
10 Stock 1970 Rebel 232s
Percent Reduction
1972 FTP Emissions
(grams/mile)
HC
3.5
1.9
(84)*
3. 1
7.4
58
2.4
3. 1
23
2.4
3.4
29
3.0
3.0
0
1.3
0. 69
3.70
81
0.51
2.7
81
CO
4.7
29.6
84
7.3
17.8
59
4.2
28.5
85
7.2
30.5
76
15.4
31.5
51
4.0
1.8
16.0
89
3.9
22. 1
82
NOX
8.9
4.0
(123)*
8.6
5.2
(65)*
1.8
3.6
50
2.9
3.6
19
2.6
3. 1
16
1.9
2.6
9.4
72
3.1
6.9
55
Type
Conversion
LPG
LPG dual fuel
LPG dual fuel
LPG dual fuel
LPG dual fuel
LPG
LPG
LPG
( )* indicates emission increase
indicated in Figure 6-2 (Ref. 6-6). This figure shows the California Seven-
mode Cycle test results for a converted 1969, 327-CID Chevrolet engine
operated at air-fuel settings ranging from 15 to 20.5; the sensitivity in CO
emissions to the air-fuel ratio at settings up to 18 may be noted. Note also
6-10
-------
FUEL RATE
0-60 mph WOT acceleration
O STANDARD TIMING
D SPARK RETARDED
2-10°
18 19 20
AIR/FUEL RATIO
* At conventional carburetor and ignition timing
Figure 6-2. Air-Fuel Ratio and Spark Timing Effects (Ref. 6-6)
(1969, 327-CID Chevrolet, California Seven-Mode
Test Cycle)
6-11
-------
the improvement in NO emission control achievable at the extremely lean
limits of operation made possible by the use of a gaseous fuel.
From a weighted average of the data presented in Table 6-2, it
appears that exhaust emission levels of approximately 1.0 gm/mi HC, 4 gm/mi
CO, and 3 gm/mi NO , as measured by the 1972 Federal Test Procedure, are
achievable in conventional spark ignition engines equipped with existing pro-
pane fuel conversion hardware. Using relationships from Reference 6-7,
these levels may be expressed in terms of the 1975 Federal Test Procedure
and may then be compared with the original 1975 and 1976 Federal emission
standards for light duty vehicles as shown in the following table:
HC
CO
NO
X
Emission Levels
using Propane
(gm/mi)
0.9
2.9
3.0
1975 Interim
Standards
(gm/mi)
1. 5
15.0
3. 1
Original 1975
Standards
(gm/mi)
0.41
3.40
3. 10
Original 1976
Standards
(gm/mi)
0.41
3.40
0.40
From these results, it appears that propane is capable of meeting the 1975
interim standards for all three pollutants and may also meet the original 1975
standards for CO and NOX. With regard to the HC requirement for 1975, it is
noted that,while propane HC emissions are approximately twice the standard,
the photochemical reactivity of propane exhaust hydrocarbons is considerably
lower than that for gasoline. The original 1976 requirement for NOX does not
appear to be attainable through the use of propane without additional engine
control equipment. In this regard, it may be noted that a 197 1 Olds Delta 88
equipped with LPG conversion kit, thermal reactor, and exhaust gas recircula-
tion yielded the following improved emission results: 0.7 gm/mi HC,
2. 2 gm/mi CO, 0. 4 gm/mi NO (Ref. 6-8).
Jt
iNevertheless, because the emission control capability pre-
sently attainable through the use of propane fuel falls somewhat short of meet-
ing the original 1976 federal baseline emission standards and, since vehicles
tuned to achieve this capability show definite driveability problems, additional
research is required.
6-12
-------
6. 2. 4 Toxicity and Safety
Both propane and butane are relatively nontoxic gases and
relatively safe. The Interstate Commerce Commission has stated that
LP-gas is a safer fuel than either gasoline or diesel (Ref. 6-9). LP-gas
does not puddle when spilled, and it quickly dissipates into the air (if the
temperature is above the boiling point of the liquid). The flammability limits
are very narrow, limiting the likelihood of accidental combustion. "Since the
equipment is designed as a pressurized container it is inherently sturdy
and limits the possibility of rupture and fire should a vehicle be involved in
an accident. In the event of a collision, an LP-gas tank has over 20 times
the resistance of an ordinary gasoline or diesel tank.
6.2.5 Handling, Storage, and Distribution Requirements
Both propane and butane are generally stored and transported in
a liquefied state by either pressurization in the storage container or by cooling
below relatively moderate boiling points as a means of minimizing their volume
for easier handling purposes. Of the two gases, propane is more generally
suitable for on-the-road automotive vehicles because of its lower boiling point
(advantageous in cold climates) and higher octane rating. Propane does, how-
ever, require higher tank storage pressures than butane to maintain it in a
liquid state. For these reasons handling, storage, and distribution requirements
for both two gases are somewhat complicated.
At present, neither propane nor butane is readily available to the
motoring consumer as gasoline. Both can, however, be purchased from any of
the more than 25, 000 propane and butane dealers in the United States. These
dealers are located in all large cities, along highways, and at most truck stops
or recreational vehicle locations .
A vast amount of physical assets have been geared in the storage
and transportation of propane and butane (for general purpose usage). At the
end of 1971, these assets included more than 20,000 railroad tank cars, most of
which exceeded 30, 000 gallons in capacity; 28, 500 transport and delivery vehi-
cles; 72,000 miles of cross-country pipelines; a fleet of 150 barges and tankers;
6-13
-------
9,200 bulk storage plants or distribution centers,and underground storage
caverns having a total storage cpacity in excess of. 7 .2 billion gallons of LP-gas.
6.2.6 Critical Research Gaps
The emission control capability, presently attainable through the
use of propane fuel.falls somewhat short of meeting the original 1976 federal
standards. In addition, vehicles tuned so as to achieve this capability show
definite driveability problems associated with lean operation. Reference 6-10,
for example, reports that slugishness on response to acceleration and low
power at high speeds were two problems encountered with lean-adjusted pro-
pane fueled vehicles. Performance deterioration at lean mixtures is also
indicated in Figure 6-2. Thus, if propane were to be considered for use as
an alternate fuel, further improvements in emission levels and vehicle per-
formance at lean operating conditions would be desirable.
Propane availability and cost are additional factors which
demand consideration in evaluating propane as an alternate fuel. A new raw
material source and production process for obtaining LP-gas would be
required to increase its availability. Therefore, an economically acceptable
method of producing LP-gas directly from coal or oil shale is needed if it
is to be considered as a viable alternative fuel.
6. 3 CURRENT STATUS
6. 3. 1 Production Rates
LP-gas is produced at natural gas processing plants and at
refineries, in the course of certain refining processes. The production of
LP-gas (comprised mainly of propane and butane) has increased at an average
annual rate of between 5 and 6 percent over the past 10 years. More than
200 oil and gas companies were domestically involved in producing in excess
of 19 billion gallons of propane and butane in 1971 (Ref. 6-11). Table 6-3
presents the yearly production rates of LP-gas from 1961 to 1971. A further
production breakdown in terms of the two basic LPG sources, the natural gas
processing plants and the refineries, is given in Table 6-4. The major pro-
duction source of propane and butane is seen to come from the natural gas
processing plants, amounting to approximately 74 percent of the total LP-
gas production.
6-14
-------
Table 6-3. Annual Production of LP-Gas (Ref. 6-11)
(Thousands of Gallons)
Date
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
Propane
6, 344,486
6, 333,496
7,252,476
7,791,469
8, 177,271
9, 168,793
10, 159,783
10, 867,290
11,427,738
12, 011,706
12, 834,738
Butane
2, 658,883
2,636, 907
3,002,761
3, 168,093
3,074, 379
3,722, 368
4,021,651
4, 238, 976
4, 661, 706
4, 597, 320
4, 544, 190
Butane -Propane
Mixture
757,718
746,011
634, 182
554,258
595, 132
997,696
1,099, 581
988, 344
760,284
629, 034
426, 342
Iso-Butane
806, 912
845,075
971,428
1,014, 934
1, 113,008
1, 188, 355
1,282, 630
1,297, 590
1,201, 536
1, 355, 508
1,433, 334
Other*
674,012
788,656
1, 145, 132
1, 300, 551
1, 351,449
-
-
-
-
-
-
Total
Production
11,242,011
11, 350, 145
13,005, 979
13, 829, 305
14, 311,239
15,077,212
16, 563, 645
17, 392,200
18,051,264
18, 593, 568
19, 238,604
This category discontinued by the Bureau of Mines after 1965
-------
Table 6-4. Source Production of LP-Gas (Ref. 6-11)
Type
Propane
Butane
Butane -Propane Mixture
Iso-Butane
Total
Source, thousands of gallons
Production at
Natural Gas
Production Plants
8,910,006
3,718,848
175,266
1,354,500
14, 158, 620
Production at
Refineries
3,924,732
904, 176
251,076
5,079,984
Total
Production
12,834,738
4,623,024
426,342
1,354,500
19,238,604
Since proven natural-gas resources in the United States are
rapidly being depleted, it would appear that the production of natural gas will
peak out and then decline in the future, eventually eliminating this as an
important source for LPG. In this event, it may be possible to augment the
supply of LPG by modifying the refining operations in the United States so as
to increase LPG production by additional cracking or other processing of the
heavier distillate components of crude oil. Another possible future source of
LPG is synthesis from coal by either the gasification or liquefaction route.
At present, however, the synthesis process as applied to the production of
propane would appear to be less efficient in terms of energy utilization than,
for example, the production of gasoline.
6.3.2
Consumption and Uses
The consumption of LP-gas in 1971 between the various users
is presented in Table 6-5 in order of diminishing use rates. The major con-
sumption of LP-gas is seen to be in the areas of residential and commercial
usage (39.9 percent of total consumed), chemical and synthetic rubber
industries (26. 6 percent of total consumed), gasoline production (17.4 per-
cent of total consumed),and internal combustion engines (6. 9 percent of total
consumed). Typical uses of LP-gas are many and varied. In homes, LP-gas
6-16
-------
Table 6-5. LP-Gas Consumption - 1971
LP-Gas Use
Percentage
of Total Use
Residental and Commercial
Chemical and Synthetic Rubber
Gasoline Production
Internal Combustion
Industrial and Refinery Fuel
Export
Miscellaneous and Secondary Recovery
Utility Gas
is used for cooking, water heating, heating and air conditioning, clothes
drying, etc. Around homes, LP-gas heats swimming pools, fuels barbecue
grills, and provides outdoor light and heat. On the farm, LP-gas powers
trucks and tractors, destroys weeds, dries crops, broods chicks and pigs,
cures tobacco, runs irrigation pumping engines,and heats stock tank water.
Commercially, LP-gas has a wide variety of uses as engine fuel for trucks,
buses, lift trucks, taxi fleets, stationary engines, and as feed stock for the
chemical, synthetic rubber, and gasoline industries.
6.3.3 Consumer Costs
The consumer costs of LP-gas has increased sharply in recent
months, due to the high demand and limited domestic supplies currently avail-
able. The Oil Daily Price Listings for LP-gas group 3 (Tulsa, Oklahoma)
shipments, for example, have increased by over 130 percent from September
5, 1972 to September 28, 1973. In this rapidly changing market, any listing
of current prices may soon become obsolete. The prices of propane in bulk
lots of 100,000 gallons or more, as of 30 November 1973 in the Los Angeles
6-17
-------
area, averaged between $0.39 to $0.47 per gallon depending on the bulk amount
sold, and was generally similar to the price of gasoline at that time. On the
basis of Btu per dollar, before the present price increase gasoline was run-
ing about 30 to 40 percent cheaper than propane.
6.4 PROJECTED STATUS
The future availability of LP-gas as an alternative fuel does
not look encouraging for either the near term or the longer term. In the
near term, the production of LP-gas is tied directly to the production rates
at the natural gas processing plants and the gasoline refineries, or more
simply to our domestic production of petroleum products. Though the pro-
duction of LP-gas is expected to rise in the 1970s, the annual increase is
expected to taper off from that experienced in the 1960s to an average annual
increase of 4.7 percent (Ref. 6-12). The reason for the tapering off of LP-gas
production increase is due in large part to the fact that the newer oil well finds
are generally drier (i.e., less wet gas).
Because the current major production source of propane and
butane is natural gas processing plants, a new raw material source and pro-
duction process for obtaining liquid petroleum gas would be required to
increase its availability. Therefore, economically acceptable methods of
producing liquid petroleum gas directly from coal or oil shale are needed if
it is to be considered as a viable alternative fuel. But even if costs of pro-
duction of liquid petroleum gas from coal by either gasification or liquefaction
are reduced, the production of gasoline from coal would be more efficient in
terms of energy utilization. Considering this factor as well as the problems
in establishing a nationwide distribution and storage system,this fuel is not
considered a primary candiate for large-scale antomotive use. Rather, it may
find application to commerical fleet operations.
6-18
-------
SECTION 7
-------
SECTION 7
ETHANOL AND ETHANOL-GASOLINE BLENDS
7. 1 CHARACTERIZATION
7. 1. 1 Fuel Type
Ethyl alcohol (also ethanol) is the hydroxyl derivative of ethane
and has the chemical formula C H OH. It is mainly known by virtue of its
use in alcoholic beverages as the principal product of fermentation.
At normal ambient conditions, ethanol is a clear, colorless,
combustible liquid. It has a fairly broad liquidus range, freezing at -114 C
and boiling at +78 C, with a specific gravity of 0. 79. Produced over the
centuries by fermentation of various carbohydrates (sugars), which reached a
zenith in this country during World War II, ethanol is now mainly manufactured
synthetically from petroleum-derived ethylene for industrial use. The first
commerical process for ethylene-based alcohol dates back to 1930.
The principal industrial uses of ethanol are as a chemical
intermediate, as a solvent, as an antifreeze, and in fine chemical manu-
facture such as drugs, polishes, perfumes, cosmetics, etc. Alcohol has
been used as a rocket and automotive fuel but has been replaced by more
energetic fuels (e.g., kerosene, hydrogen) in the former instance and gasoline
in the latter. Almost all industrial alcohol used in this country is sold in
denatured form.
Alcohol content in commercial ethanol is expressed in terms
of "proof" which in the U.S. is twice the concentration by volume. Thus a 190-
proof alcohol contains 95% (volume) ethanol. Typical specifications for 190
for 190- and 200-proof alcohol are given in Table 7-1.
The specifications are designed to allow alcohol requirements
to be met by either fermentation-produced or synthesis-produced ethanol.
7-1
-------
Table 7-1. Typical Ethyl Alcohol Specifications
Requirement
190 Proof
200 Proof
Specific gravity, 60/60 F,
max.
Purity, % by vol, min.
Acidity, % by wt as HOAc,*
max.
Nonvolatile matter, g/100ml,
max.
Miscibility with water
Permanganate time test,
minutes, min.
Odor
Color, APHA, max.
Water, % by wt, max.
0. 816
95
0.002
0.002
Complete
50
No foreign or
residual
10
0.794
99.9
0.002
0.002
Complete
30
10
0. 1
Refer to American Chemical Society Procedures, Specifications of
Reagent Chemicals, I960 ed. , ACS, Washington, D. C. , 1961
7-2
-------
The major producers of ethyl alcohol also market the specially
denatured and completely denatured alcohols, as well as various proprietary
solvents in which ethyl alcohol is the basic ingredient. These various prod-
ucts can also be described by rigid and descriptive specifications, but the
requirements must make allowances for the chemical and physical character
of the denaturants.
7. 1. 2 Reserves or Raw Material Sources
The starting raw materials for ethanol manufacture are some-
what broader than those given for methanol. Most of the raw materials used
in the manufacture of methanol (discussed in Section 4) can also be consider-
ed for ethanol, and the reader is referred to that section. The basic differ-
ence.insofar as direct U.S. commercial synthesis is concerned, relates to
the use of petroleum-derived ethylene as feedstock from which ethanol is man-
ufactured. Ethanol, however, is also being produced via Fischer-Tropsch
synthesis and by fermentation of grain (thus the name grain alcohol is some-
times used), molasses, sulfite liquors, and other fermentable sugar- or
starch-bearing agricultural products. Most of the ethyl alcohol production
outside the United States is accomplished by the fermentation process and
whenever demand has exceeded supplies in this country (World War II and
Korean War), emergency production by fermentation increased. The raw ma-
terials came chiefly from molasses, fruits, and grains such as wheat and corn.
Other raw materials include sawdust and sulfite liquors, potatoes, beets,
and other agricultural products. Fermentation alcohol production is affected
by very complex cost economics involving domestic availability and stability
in the price of ethylene versus widely fluctuating availability of agricultural
raw materials around the world. Historically, the price of fermentation
enthanol in the U.S. has depended largely on competition for molasses which
has tended to be a more stable commodity (except during the Cuban crisis)
than grains. It should be noted that annual weather conditions exert a signifi-
cant influence on availability of these crops. This makes the prediction such
a difficult problem.
7-3
-------
7. 1. 3 Methods of Manufacture
The two primary methods of ethanol synthesis involve the
hydration of ethylene. The indirect hydration process involves reaction with
concentrated sulfuric acid in an absorption column to form a solution of sul-
fates which are then hydrolyzed with water:
H,C - CH_ - OSO H
J £ J
_ HOSO.
2 24
(H C - CH ) SO
3 ^
- OH
(H3C - CH2) S04 + 2H2O - ~2H3C - CH2 - OH + H
C*
The alcohol and certain side products such as diethyl ether
are separated from the spent sulfuric acid which is then reconstituted and
recycled. A flow sheet for this process is shown in Figure 7-1.
The direct hydration process involves the catalytic addition
of steam to ethylene at high pressure and temperatures
- OH
The catalyst commonly used is phosphoric acid on a suitable carrier, although
other catalysts have been claimed to be effective. As in any catalytic process,
yields depend upon proper control of reaction conditions as well as upon the
catalyst used. With phosphoric acid catalyst the recommended conditions
are about 300°C and 66 atm pressure with 66 percent (vol) water to ethylene
in the feed stream. A flow sheet for this process is contained in Figure 7-2.
7-4
-------
ETHYLENE
TO GAS PURIFICATION
CAUSTIC SODA
CRUDE
ETHANOL
Figure 7-1. Manufacture of Ethyl Alcohol by Esterification-
Hydrolysis (Indirect Hydration)
VENT
HEATER
WATER
CAUSTIC
SODA ETHYLENE RECYCLE
ETHYLENE
COMPRESSOR
RECYCLE COMPRESSOR
Figure 7-2. Manufacture of Ethyl Alcohol by Direct
Hydration of Ethylene (Ref. 7-1)
7-5
-------
The Fischer-Tropsch and partial oxidation processes for the
production of methanol can also be applied to the manufacture of ethanol.
These have also been described in Section 4.
Ethanol has also been synthesized from methanol through vapor
phase catalysis in the presence of carbon monoxide and hydrogen with a cobalt
catalyst.
Fermentation processes for ethanol manufacture involve a
series of complex yeast-originated enzymatic reactions upon sugars. In
chemical terms, this is often shown as:
C,H100, ENZYM,E 2CLH-OH + 2CC-
b 1 <£ o 2 3 £
The reactions may be thought of as very slow catalytic conver-
sions, the enzymes acting as catalysts. The processes occur at near-ambient
temperature and pressure in batch-reactor vessels called fermenters. Con-
version times are measured on the order of 2 to 3 days, at which time the
alcohol volume concentration is about 6 to 9 percent. As in other conversions
previously described, side reactions occur which require careful process and
culture (catalyst) controls. At the completion of fermentation, the product,
called liquor or "beer," goes to a series of distillation columns where con-
centrated alcohol and various byproducts are recovered.
A typical yield from one gallon of blackstrap molasses is 1/2
gallon of 95-percent ethanol. A bushel of corn yields 2-1/2 gallons, and one
ton of dry wood yields 55 gallons, although recovery from wood bark is lower.
7. 1.4 Physical and Chemical Properties
As discussed in sections of this report dealing with methanol,
properties of ethanol are frequently compared to gasoline. Since gasoline is
a mixture of hydrocarbons, the properties given in Table 7-2 are compared
to isooctane, which is a representative gasoline constitutent. The most im-
portant difference is seen to be in the heat of combustion, insofar as the use
of ethanol as an engine fuel is concerned.
7-6
-------
Table 7-2. Properties of Isooctane and Ethanol (Ref. 7-1)
Item
Formula
Molecular weight
Carbon to hydrogen weight ratio
Carbon, % by weight
Hydrogen, % by weight
Oxygen, % by weight
Boiling point, F at 1 atm
Freezing point, F at 1 atm
Vapor pressure, psia at 100 F
Specific gravity, 60 F/60F
and 1 atm
Coefficient of expansion
1/F at 60 F and 1 atm
Surface tension, dynes /cm at
68 F and 1 atm
Viscosity, centipoises at
68 F and 1 atm
Specific heat of liquid,
Btu/lb -F at 77 F and 1 atm
Heat of vaporization, Btu/lb
at boiling point and 1 atm
Heat of vaporization, Btu/lb
at 77 F and 1 atm
Heat of combustion, Btu/lb at 77 F
Higher heating value
Lower heating value
Liquid fuel -gaseous H2O
Stoichiometric mixture, Ib air/lb
Auto ignition temperature, F
Octane no.
Isooctane
C8H18
114.224
5.25
84.0
16.0
0.0
210.63
-161.28
1.708
5.795
0.00065
18.77
0.503
0.5
116.69
132
20,556
19,065
15. 13
784
100
Methanol
46.07
4.0
52.0
13.0
35.0
173.0
-173.4
2.5
6.63
0.00048
23
1. 17
0.6
361
395
12, 780
11, 550
9.0
685
106
7-7
-------
7.2 SUITABILITY FOR USE AS AN ENGINE FUEL
7. 2. 1 Engine/Vehicle Compatibility
Ethanol has been demonstrated to be compatible as a motor
fuel with present vehicles. In many parts of the world it has been blended
in concentrations varying between 10 and 20 percent to alleviate gasoline
shortages. Like methanol, it has not proven to be economical for such usage
in the United States because it has a lower calorific value per unit weight of
volume than gasoline while being more costly than domestic gasoline.
7. 2. 2 Fuel Economy Effects
Studies over the years have demonstrated that the use of
alcohol as an automotive fuel reduces fuel mileage essentially in proportion
to the reduction in lower heating values of the vaporized fuels. For pure
ethanol this corresponds approximately to a 60 percent increase in fuel con-
sumption. Experiments in single cylinder engines and multicylinder engine-
powered vehicles generally have tended to verify this. However, fuel consump-
tion is influenced to some degree by the type of engine used and the duty cycle.
While much information appears in the literature concerning fuel
economy effects of ethanol and ethanol/gasoline blends in spark ignition engines,
they will not be cited in detail because publication was prior to World War II.
More recent work shows that the engine and the test conditions
bear upon the comparative results, as published in a paper by Lawreson and
Finigan (Ref. 7-2). Using a 1962 Oldsmobile V-8 (10. 5:1 combustion ratio)
and four different fuel blends (two alcohol-free gasolines and two containing
25 percent ethanol 190 to 200 proof), these investigators determined specific
fuel consumption relative to motor load conditions. The fuels were as follows:
Blend 1: A commercially available 100 octane gasoline with a
phosphorous additive
Blend 2: A 98 octane blend comprised of 92. 5 octane unleaded
gasoline and 3. 0 ml of tel/gal
7-8
-------
Blend 3: A 97. 5 octane blend comprised of 75% (by vol) of
92. 5 octane unleaded gasoline (as in Blend 2) and
25% of 200 proof ethanol
Blend 4: A 75% (vol) blend of 92. 5 octane unleaded gasoline
and 25% of 190 proof ethanol.
Figure 7-3 shows that at reduced engine loads the bsfc was
greater with the 200-proof ethanol blend than with gasoline (leaded) but the
differences were nullified at WOT (wide open throttle) conditions.
When translated into road economy figures versus speed, the
authors stated that "the 190-proof alcohol blend was noticeably less efficient"
while "the 200-proof blend produced essentially the same economy as the
commercial gasoline except for a superiority at the higher road speeds for
the latter". This is shown by Figure 7-4.
Kilayko (Ref. 7-3) reported results of comparison tests between
gasoline (92 octane) and 190-proof ethanol in a 4-cylinder Renault engine. With
gasoline as the fuel, engine compression ratio was 7. 25:1 and with alcohol the
compression ratio was increased to 12:1. With spark timing adjusted for max-
imum power, the tests showed that improved efficiency could be obtained by
operating the higher-octane rated ethanol at the higher compression ratio.
The following table shows that at the same engine speed and fuel-air equiva-
•jf
lence ratio (0 ^ = 0. 9) the specific fuel consumption was 0. 76 (ethanol) vs
0. 52(gasoline), which is less than a 50 percent increase in consumption.
Fuel
Gasoline
190° EtOH
Compres-
sion Ratio
7.25
12:1
0*
0.9
0.9
Speed
(rpm)
2400
2400
Bsfc
(Ib/hp-hr)
0. 52
0.76
BMEP
(psig)
87
99
0 =
actual fuel-air ratio
stichiometric fuel-air ratio
7-9
-------
1.0
0.9
0.8
0.7
0.6
1-0
0.7
0.6
0.5
CD
0.6
0.5
0.4
0.6
0.4
FUEL 2
—O— BLEND 3
(STANDARD TIMING
AND CARBURETION)
o
o-
1500 2000 2500 3000 3500 4000
RPM
Figure 7-3 . Efaciency at Loads - 1962 Oldsmobile (Ref. 7-2)
7-10
-------
36
32
2
£ 26
Q.
5 22
O
U
L_
18
14
10
FUEL 1
•O— BLEND 3
•A— BLEND 4
(STANDARD TIMING
AND CARBURETION)
20
40
60
mph
80 100
Figure 7-4. Road Load Economy - 1962 Oldsmobile (Ref. 7-2)
7-11
-------
7.2.3 Emission Effects
While some data are available concerning the exhaust pollution
effects of ethanol, the literature is far from comprehensive. Some recent
efforts have dealt with ethanol/gasoline blends of approximately 25-percent
ethanol (by volume) run in single-cylinder test engines (Ref. 7-4). The
results compared on the basis of equivalence ratios show the emissions are
controlled by the primary fuel constituent (gasoline) in the blend, and are
essentially the same as for gasoline alone.
7.2.4 Toxicity Effects
Ethanol is not highly toxic. If inhaled for continuous periods
under poor ventilation conditions, discomfitures occurs: coughing, eye
irritation, headache, and related symptoms. The threshold limit value is
1,000 parts per million. Alcohol ingestion causes intoxication at levels below
100 grams; larger intake will cause stupor (150 to 200 grams) and poisoning
(250 grams).
7.2.5 Safety Effects
Ethyl alcohol is a flammable liquid requiring a red explosive
label by the ICC and Coast Guard shipping classifications; its flash point is
70°F, which lies below the established ICC limit of 80°F but far above that
for gasoline, -40 F. Vapor concentrations between 3. 3 and 19. 0 percent by
volume in air are explosive. Liquid ethyl alcohol can react vigorously with
oxidizing materials. As this alcohol would probably be used, if used at all,
the safety aspects of ethanol-gasoline blends would be about the same as for
gasoline alone.
7.2.6 Handling, Storage, and Distribution Requirements
Commercial ethyl alcohol is shipped in railroad tank cars, tank
trucks, five- and 55-gallon drums, and in smaller glass or metal containers
having capacities of a pint, quart, U.S. or Imperial gallon. The 55-gallon
drums may be of the unlined iron type. If a guarantee of more meticulous
quality is desired, the drums may be lined with phenolic resin. The problem
of contamination or adulteration by water is similar to that for methanol.
7-12
-------
7.2.7 Ethanol-Gasoline Blends
Much of the preceding discussion has already dealt with ethanol-
gasoline blends inasmuch as cost and reduced fuel economy, in the absence of
other advantages, have militated against use of neat alcohol. Indeed, even
the blends have little to recommend them. The most favorable test data
indicate fuel economy about equal to that of gasoline. With regard to emis-
sions, the general consensus of published reports is that ethanol-gasoline
blends give the same carbon monoxide, hydrocarbon, and oxides of nitrogen
levels in the exhaust as gasoline at the same equivalent air-fuel ratios
(Ref. 7-5). The rationale of using ethanol as an antiknock replacement for
tetraethyl lead is not convincing since there are other compounds (e.g.,
methyl alcohol) that are cheaper and at least as efficient.
The tendency of ethanol-gasoline blends to separate upon water
addition is similar to, but not as strong as, that previously described for
methanol. For example the water that can be tolerated by a 25 percent alco-
hol blend at room temperature is about one percent. For ethanol, however,
this causes an additional problem. Water might be added purposely to obtain
tax-free alcohol for drinking. The taste and odor of gasoline in the separated
alcohol could be removed by shaking with activated carbon. Denaturing of the
alcohol will be essential, whether used neat or in a gasoline blend.
Although ethanol-gasoline blends have a higher vapor pressure
than the gasoline alone, the vapor pressure increase is much less than in the
case of methanol-gasoline blends. Some removal of the butane from the
gasoline would be required to achieve the same vapor lock protection for the
ethanol-gasoline blend as for the neat gasoline.
In light of the current and projected high cost of ethanol and
the lack of any significant advantage when added to gasoline, it does not
appear these blends warrant serious consideration as a replacement for
gasoline alone. If the alcohol-gasoline blends have any viability as future
automotive fuels, the one selected for further evaluation should be methanol.
7.2.8 Critical Research Gaps
If ethanol is seriously considered for gasoline blends, more
data are needed on miscibility and vapor lock problems using modern gasolines.
7-13
-------
7.3 CURRENT STATUS
7.3.1 Production Rates
Recent production level figures for 1965 showed a total ethanol
production (190° proof) of 175 million .gallons, and of this amount over 80
percent (147 million gallons) was produced sythetically, with the rest com-
prised essentially of grain fermentation alcohol. In 1973, production was
Z45 million gallons of synthetic ethanol.
7.3.2 Uses
Domestic usage for years I960 to 1964 are shown in Table 7-3.
A significant proportion of ethanol production is used in acetaldehyde manu-
facture.
7.3.3 Consumer Costs
The price history of industrial ethanol in the United States is
shown in Table 7-4. Unless a low-cost route to ethanol manufacture is found,
ethanol cannot compete with other prospective fuels such as methanol.
7. 4 PROJECTED STATUS
7.4.1 Availability
Although ethanol is being produced in large quantities, pro-
jected availability is not expected to improve in the near term to the level
required to support its use as a motor fuel.
7.4.2 Projected Consumer Costs
Various projections are possible depending upon raw material
costs, the type of process (synthesis versus fermentation), and related factors.
The lowest-cost production route over the near term will continue to be syn-
thesis from cracked hydrocarbons. The cost for fermentation process
alcohol from grain has been estimated as about $1 per gallon or $12 per
million Btu, except when sulfite waste liquor or waste wood is used as raw
7-14
-------
Table 7-3. U.S. Consumption of Specially Denatured Alcohol,
Fiscal Years I960-1964a (Total disappearance,
thousand wine gal, 190° proof alcohol) (Ref. 7-1)
Use
acetaldehyde
other chemicals
solvents
solvent and thinners for
etc.
toilet preparations
processing, foods, drugs,
other products
parmaceutLcal products
for external use
detergents, flavors,
disinfectants, and other
solutions
Total
fluid0
fuel
laboratory and experimental
use
Grand Total
1960
156,348
57,760
31,961
11,621
9.034
4, 107
10.60Z
67.325
173
528
1,026
283, 160
1961
148,948
56,392
28,760
12,718
9,020
3,860
12, 174
66,532
187
434
1,204
273,696
1962
138,334
61,966
29.779
16,859
9,302
4,614
12,641
73,195
184
506
1,616
275,801
1963
145, 113
58,317
29,960
21,977
8,765
4,518
11,430
76,659
158
453
1,437
282.137
1964
104, 072b
96,788b
29,400
26,766
8,843
*,377
12, 160
81,546
127
477
1,812
284,822
aFigures published by the U.S. Business and Defense Services Administration.
Changed pattern may be due to change in usage classification.
cAntifreezes, brake fluids, cutting oils, etc.
Table 7-4. Price History of Industrial Ethyl Alcohol in
the United States (Ref. 7-1)
Year
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
Price,*
-------
material. The cost then drops to about $6 per million Btu (Ref. 3-7), with
an additional $1.10 per million Btu for distribution to the consumer.
7.4.3 Capital Costs and Timing Implications
The capital costs for ethanol synthesis plants appear to be
slightly above those for methanol production. A recently installed USI
Chemicals Company operation with an annual capacity of 60 million gallons
per year reportedly cost $16 million. Based on a 350-day operation, this
amounts to a daily capacity of 171, 000 gallons per day or $93 per daily gal-
lon capacity. Fermentation plants tend to differ from each other. Plants
using molasses require lower capital investment than grain because of the
absence of grain handling and by-product feed recovery operations. Capital
costs for large-scale fermentation plants must still be determined. For
competitive processes, a figure of $0. 10 per gallon would require an invest-
ment of less than $275 per daily gallon at a return of 12-1/2 percent. For
100, 000 barrels per day production this represents over $1 billion investment.
7.4.4 Impact With Other U.S. Energy Requirements
Unless ethanol can be economically produced from waste
products or very low cost raw materials its use as motor fuel will be very
limited. Ethanol produced as a by-product in Fischer-Tropsch synthesis
will also have minor impact.
7. 4. 5 Factors Which May Inhibit Use
Economics of ethanol production and poor fuel economy are
the major factors tending to limit its use. It is also susceptible to water
contamination and adulteration.
7. 4. 6 Critical Technology Gaps
New methods are needed to enable low-cost synthesis of
ethanol on a very large production scale.
7-16
-------
SECTION 8
-------
SECTION 8
HYDROGEN
This section discusses pure hydrogen as a potential alternative
fuel. Hydrogen gaseous blends or hydrogen/gasoline fuel mixtures are dis-
cussed in Section 11, "Fuels Reformed On-Board the Vehicle. "
8. 1 CHARACTERISTICS
Hydrogen, H, is the first element in the periodic table. Its
principal source is water. Hydrogen was first recognized in about the 15th
century. It was discovered that water was formed when hydrogen burned in
air. The name "hydrogen" is derived from a similar Greek word meaning
water producer.
8. 1. 1 Fuel Type
Hydrogen appears to be suitable for use as an automotive fuel.
Hydrogen is stable and relatively unreactive at ordinary temperature. It
reacts with oxygen to form water: 2H_ + O_ — 2H~O. This reaction is exo-
thermic, producing 51,600 Btu per pound of hydrogen (lower heating value).
At temperatures of about 500°C or higher, this reaction proceeds sponta-
neously. At lower temperatures, the reaction occurs in the presence of a
suitable catalyst, such as platinum or palladium, or if activated by a spark.
Hydrogen has been used successfully as a fuel on internal
combustion engines with fuel mixtures of hydrogen-oxygen, hydrogen-air,
and hydrogen-air-gasoline. Early problems of engine knock, preignition,
and backfire have largely been resolved (Ref. 8-1).
The United States space program created a large demand for
hydrogen, both as a primary rocket engine fuel for combustion—principally
with oxygen, and as a propellant for conceptual nuclear-powered space
vehicles. But its main use in this country is in the production of ammonia.
8-1
-------
8. 1.2
Reserves or Raw Material Sources
Hydrogen can be produced from all fossil hydrocarbons
including natural gas, oil refinery gas, LPG (propane and butane), natural
gasoline, naphtha, fuel oil, crude oil, coal, and coke. Hydrogen can be also
produced from water by separating the chemical bond between hydrogen and
oxygen by the addition of energy. The supply of hydrogen from water is vir-
tually inexhaustible, although facilities for mass production are not yet
available.
Estimates of known and yet to be discovered resources of
hydrocarbons in the United States are shown in Table 8-1. By 1985, the
annual domestic energy supply from all sources is estimated to be 131.5
x 1015 Btu. Of this 96. 9 X 1015 Btu will be derived from fossil hydrocarbon
sources. The total annual energy demand at that time will be 130. 0 X 10* Btu
Of this 29. 0 X 10 Btu or approximately 22 percent will be required by the
transportation sector (Ref. 2-1).
8. 1. 3 Methods of Manufacture
Hydrogen is currently produced primarily from hydrocarbons,
using steam reforming or partial oxidation processes. Its main use is in the
production of ammonia. Hydrogen is also commercially produced from water
electrolysis. Water electrolysis is accomplished by passing a direct current
Table 8-1. Domestic Resources of Fossil
Hydrocarbons (Ref. 2-1)
Source
Resource Base
Natural Gas
Crude Oil
Oil Shale
Coal
1412.0 x 1012 CF (1,457 x 1Q15 Btu)
472. 3 x 109 bbl (2, 739 x 1015 Btu)
1781. 0 x 109 bbl (9, 549 x 1015 Btu)
3.2 x 1012 tons (80,200 x 1015 Btu)
8-2
-------
between two electrodes immersed in an electrolyte (usually potassium
hydroxide solution). Hydrogen is formed at the cathode and oxygen is formed
at the anode. The rate of hydrogen production is directly proportional to the
current passing between the electrodes. Thermal, thermochemical,and
radiolytic processes are also potential, but as yet undeveloped, production
methods. The world production of hydrogen from water is only 3 percent of
the total hydrogen used in the U. S. (Ref. 8-2). This low percentage is due
to the present low cost of hydrogen produced from hydrocarbons as compared
with that produced from water.
Processes available for the production of hydrogen include the
following:
a. Catalytic Steam-Hydrocarbon Reforming
Gaseous hydrocarbons, such as methane and ethane.and those
which may be vaporized at moderate temperatures, such as
propane, butane, and petroleum naphtha, are reacted with
steam over a nickel catalyst at 1200° to 1800°F to produce
carbon monoxide and hydrogen. This can be followed by a
shift reaction in -which the CO is converted to CO? and
additional hydrogen produced by the action of water.
b. Pressure Noncatalytic Partial Oxidation of Hydrocarbons
Hydrogen and hydrogen-rich synthesis gases are produced
from partial oxidation by burning hydrocarbons with oxygen or
oxygen-rich gases. The advantage of this process over steam
reforming is that it operates with any hydrocarbon feedstock
that can be compressed or pumped, from natural gas to crude
oil or asphalts.
c. Pressure Catalytic Partial Oxidation of Hydrocarbons
Hydrogen is produced from hydrocarbons in an autothermal
self-sustaining process. The exothermic reaction of oxygen
with the hydrocarbon and the endothermic reaction between
hydrocarbons and steam and carbon dioxide maintains the
required reaction temperature over a nickel catalyst bed. The
hydrocarbons are converted to hydrogen and carbon dioxide.
d. Thermal Decomposition of Hydrocarbons
The endothermic thermal decomposition reaction CH,—»-C + 2H_
is carried out at 1200 to 1800°F and 10 to 30 psig pressure in
a fluidized-bed reactor containing silica-aluminum-nickel
catalyst particles on which carbon collects. The catalyst
8-3
-------
particles are withdrawn from the reactor and flowed to a.
regenerator through which air is blown to burn off the carbon
and reheat the catalyst. The hot regenerated catalyst is car-
ried back to the reactor with the feed gas stream.
e. Hydrogen from Coal
Coal is gasified by treating with oxygen at 450 psig and at
combustion temperatures of approximately 2250°F. Most
processes synthesize gas from coal in lump form, although
gasification processes for powdered coal are available. The
specific process used depends upon the availability of lump or
powdered coal. The higher the calorific values in the process,
the greater is the hydrogen yield. For this reason, a mixture
of oxygen and steam is used in the process.
f. Electrolysis
Hydrogen has been produced commercially by water electroly-
sis for many years. Water electrolysis is accomplished by
passing a direct current between two electrodes immersed in
an electrolyte, usually a potassium hydroxide solution. Hydro-
gen is formed at the cathode, and oxygen is formed at the anode.
For every two parts by volume of hydrogen formed, one part of
oxygen is recovered. The process requires from 140 to
160 kW-hr of electric power per 1000 SCF of hydrogen pro-
duced. It is economical only where the cost of electricity is
low (e.g., 6 mills/kW-hr) and where profitable use can be
made of the oxygen.
g. Thermochemical
Thermochemical production of hydrogen is in an early experi-
mental phase and involves the decomposition of water by the
absorption of thermal energy in a multistage reaction series
requiring high temperature in excess of about 600 to 700°C.
Utilization of large amounts of thermal energy from a nuclear
reactor or other primary heat source is necessary.
h. Radiolytic
Radiolytic production of hydrogen, also in the experimental
phase, involves the direct absorption of nuclear energy by
the water to form hydrogen and oxygen, which must then be
separated. Considerable research in this area is required for
a complete evaluation of merits. Meaningful cost estimates
for this process are not available. As of now, it does not
appear to be economically competitive with water electrolysis.
8-4
-------
8.1.4 Physical and Chemical Properties
Liquid hydrogen is a transparent, water white, odorless liquid.
When in an observable condition, it is usually boiling vigorously because of its
low boiling point. When liquid hydrogen vaporizes in air, the gas can create
an ignitable or, if confined, an explosive mixture. It will react violently with
strong oxidizers igniting easily with oxygen and spontaneously with fluorine
and chlorine trifluoride. All known substances are essentially insoluble in
liquid hydrogen. Helium is probably soluable to the extent of 1 percent.
The hydrogen molecule H_ contains two atoms, each consisting
of a single proton in the nucleus and a single electron outside the nucleus. It
is the lightest of all known substances, with an atomic number of 1 and an
atomic weight of 1.0080. The physical and chemical properties of hydrogen
are given in Table 8-2.
The diatomic hydrogen molecule exists in two forms, ortho and
para. Each of the two atoms consists of a proton and an electron. Both
parallel spin (same direction) and antiparallel spin (opposite direction) of
the protons can occur in the molecules. Those molecules having parallel
spins are termed orthohydrogen, while those having antiparallel spins are
called parahydrogen. There is no difference in the chemical properties of
the two forms, but there is a slight difference in the physical properties due
to the difference in nuclear spins. The two modifications are usually found
to be in equilibrium with one another. The equilibrium ratio of their con-
centrations is a continuous function of temperature. Freshly liquefied hydro-
gen which has not been catalyzed into a stable "para" state is not at equilib-
rium. On standing, this mixture, which is referred to as normal hydrogen,
undergoes a slow shift towards the equilibrium concentration and in this
process it loses about 20 percent of its volume during the first day due to
boiloff. To prevent such evaporation losses, the normal hydrogen is con-
verted rapidly to the stable parahydrogen by the use of a catalyst and energy
extraction.
8-5
-------
Table 8-2. Properties of Hydrogen (Ref. 8-3)
Chemical Formula
Molecular Weight
Density
Vapor - gas at 2000 psi 0.667
Liquid - at normal boiling point
Heating Value
Volumetric Gross
Weight Gross
Weight Net
Air for Combustion
O2 Weight
N2 Weight
Air Weight
Products of Combustion
CO2 Weight
H2O Weight
N2 Weight
Flammable Limits
Flame Velocity
Ignition Temperature
Theoretical Combustion Temperature
Normal Transportation
2.016
0.005327 lb/ft3
4.43 lb/ft3
270,274 Btu/ft3
228,693 Btu/ft3
51,623 Btu/lb
7.937 Ib/lb
26.406 Ib/lb
34.344 Ib/lb
8.937 Ib/lb
26.407 Ib/lb
4.00-74.2%
9.2 ft/sec.
1065°F
3887°F
Normally carried as compressed gas in high pressure
container. Can be shipped by pipeline.
Could also be transported as a cryogenic liquid.
8-6
-------
8.1.5 Qxidizer Requirements and Combustion Characteristics
An unconfined mixture of hydrogen and air will burn but not
detonate if it is exposed to a limited ignition source such as a spark. In con-
fined areas or when ignition is accomplished by a shock source, equivalent
to a blasting cap or a small explosive charge, an explosion can occur. Hydro-
gen burns readily and evenly in air with a very hot, nonluminous, and almost
invisible flame. Flame temperature of hydrogen-air in stoichiometric pro-
portions is about 2300 K. The burning velocity is dependent on the hydrogen-
air mixture and reaches a maximum, at about 40 to 45 percent hydrogen by-
volume. When no impurities are present, hydrogen burns in air with an
invisible flame. Hydrogen-air mixtures containing as little as 4 percent
and as much as 74 percent hydrogen by volume are readily ignited. Hydrogen-
oxygen mixtures are flammable over the range of 4 to 94 percent hydrogen
by volume.
8.2 SUITABILITY FOR USE AS AN ENGINE FUEL
8. 2. 1 Engine/Vehicle Compatibility
Hydrogen, with air from the atmosphere or with oxygen
supplied on-board, offers an impressive potential for fueling future trans-
portation systems. Hydrogen, the most energetic of chemical fuels, offers
these critically important advantages: (1) it is available from water resources
through the addition of energy from fossil, nuclear, or perhaps solar sources,
and (2) it can be consumed with minimal environmental degradation. The use of
hydrogen as a fuel for internal combustion engines, especially gas turbines
and reciprocating types, has been proven technically feasible (Ref. 8-4).
An historical review of application of hydrogen to internal combustion engines,
together with some results of recent experimental work, is presented in
References 8-5 and 8-6. Successful operation with lean air hydrogen
mixtures and compression ratios up to 16:1 was demonstrated. Experimental
work has demonstrated satisfactory engine operations with lean fuel-air
ratios from 30 to 65 percent of stoichiometric. Operation at a fuel-air ratio
8-7
-------
of 45 percent of stoichiometric seems optimal, -where the thermal efficiency
was maximum and NC> emissions were minimum.
a.
In addition to conventional engine types, unconventional power
plant designs such as stratified charge, diesel, rotary, and gas turbine engines
appear capable of sustaining efficient combustion with hydrogen. This type of
system offers the potential of extremely high thermal efficiencies and produces
only water as exhaust, along with nitrogen and variable amounts of oxides of
nitrogen.
One of the key problems with hydrogen which must be addressed
is the mode of on-board storage. Hydrogen in its densest form (as a cryo-
genic liquid) is ten times the volume of the same weight of gasoline. Fortu-
nately, it has approximately 2-1/2 times the heating value per unit weight as
partial compensation. On an equivalent Btu basis, hydrogen requires 3-1/2
times the volume of gasoline. Four methods of storage on-board a transpor-
tation vehicle can be considered:
a. As a cryogenic liquid at -423 F
b. As a pressurized gas at ambient temperature
c. As a metal hydride
d. In a chemical compound such as ammonia.
The cryogenic form appears to be best for automotive applica-
tion based on existing technology. The pressurized gas form appears to require
heavy, bulky, and hazardous containers for most applications. Research work
is under way in hydride and chemical compound storage of hydrogen, but it is
too early to assess ultimate feasibility.
A general conclusion is that hydrogen storage by any of these
methods will take up considerably more volume than conventional hydrocarbon
fuels and that substantial cost may be incurred in converting hydrogen gas to
the stored form. Also the container will tend to be rather heavy, sophisti-
cated in design, and probably very expensive. In addition, the filling and
emptying of the storage unit will no longer be a simple operation. This
8-8
-------
appears to be an inherent problem with hydrogen vehicles. The bulky
storage requirements will have a substantial impact on automotive layout
and design.
Ground transportation vehicles may utilize conventional inter-
nal combustion engines converted to hydrogen fuel or unconventional hydrogen
or hydrogen/oxygen power plants. In conventional engines some improvement
in thermal efficiency may result from the shift to hydrogen due principally
to its propensity for very lean operation at part-load conditions. However,
major gains can be obtained from the development of basic cycle improve-
ments and/or new operating cycles which can capitalize on hydrogen's out-
standing heating value, combustion characteristics, and excellent cooling
performance.
8.2.2 Fuel Economy
Experimental work using modified gasoline engines but fueled
with hydrogen-air mixtures have shown good fuel economy.
A four-cylinder Toyota engine was modified to incorporate a
special hydrogen induction technique (HIT) of varying the fuel-air ratio by
varying the fuel charge and not by air throttling (Ref. 8-7). Thus, the part-
load pumping losses encountered in a spark ignition engine are eliminated,
resulting in high efficiency at light loads characteristic of urban driving.
The part-load efficiency of the HIT engine was found to be higher than that
of the throttled gasoline engine.
Fuel economy tests were performed on a four cylinder Pontiac
engine (Ref. 8-7), converted to operate on hydrogen using the HIT technique.
The specific fuel consumption (pounds of hydrogen per horsepower hour) is
plotted as a function of spark advance at an average speed of 1,375 rpm and an
average torque of 24 foot-pounds. It is observed in Figure 8-1, that for this
combination of rpm and torque, the best economy setting is 50 plus or minus
2 degrees before top dead center. The gain in efficiency over that of a throt-
tled gasoline engine at part load was realized. This is illustrated in Fig-
ure 8-2 where the ratio of Btu fuel consumed per horsepower hour for the
8-9
-------
.c 0.40
Q.
£ 0.36
•n
5 0.32
8
a: 0.28
O
60 55 50 45
SPARK ADVANCE, DEGREE BTC
Figure 8-1. Specific Fuel Consumption (Ref. 8-7)
1.0
2 0.9
O 0.8
UJ
O 0.7
60 55 50 45
SPARK ADVANCE, DEGREE BTC
Figure 8-2. Hydrogen-to-Gasoline Btu Consumption
Ratio (Ref. 8-7)
8-10
-------
hydrogen engine to that of an essentially equivalent gasoline engine operating
at the same part-load condition is plotted as a function of spark angle. It is
observed that at the best economy spark setting (curve minimum value), the
hydrogen engine reduces Btu input by about 30 percent. At light loads the
percentage increase is even greater.
Using a Ford V-8 engine modified to recirculate a fraction of
the exhaust gas (EGR), a UCLA hydrogen-fueled test car obtained 10 miles
per pound of hydrogen under actual driving conditions, which corresponds to
5100 Btu per mile (Ref. 8-8), as compared to a similar gasoline-fueled car
using, typically, 9000 Btu per mile.
Another project utilizing hydrogen generated by reforming
gasoline on-board the vehicle is being carried out at Jet Propulsion Labor-
atory (Ref. 8-5). More details on this process are given in Section 11.
It has to be realized, however, that engine operation at lean
mixtures and low reduced manifold-charge density because of low density of
hydrogen, will result in maximum power loss of gasoline to hydrogen con-
verted engines which may be of the order of 15 to 20 percent.
8.2.3 Emission Effects
Hydrogen itself appears to be an ideal fuel for the automobile
engine for achieving low exhaust emissions. It is the cleanest possible fuel
in use, with the complete absence of carbon. A number of approaches have
been made toward operating conventional gasoline engines on hydrogen.
Success has been attained in carrying out the necessary mechanical conver-
sions, with indications that extremely low pollution levels have been achieved.
Under combustion with oxygen, hydrogen offers the complete
elimination of hydrocarbons, carbon monoxide, and oxides of nitrogen. How-
ever, oxygen would have to be stored on-board the vehicle. With air com-
bustion, emission of oxides of nitrogen are expected; the level of emission
is dependent on the combustion temperature because NOX emissions increase
with increases in temperature. Low combustion temperatures are achievable
by using lean fuel mixtures. Impressive results were achieved in the UCLA
8-11
-------
entry in the 1972 Urban Vehicle Design Competition (Ref. 8-1). This car,
using a Ford V-8 engine with a propane carburetor operating on pure hydro-
gen fuel was tested by the California Air Resources Board and by the Environ-
mental Protection Agency. The results in Table 8-3 show surprisingly low
NOX emissions, considering that none of the conventional antipollution equip-
ment had been installed. The HC and CO emission results are most probably
due to excessive lubricating oil combustion. The high CC"2 level tends to
support the latter conclusion.
8.2.4 Toxicity Effects
Gaseous hydrogen acts as a simple asphyxiant. The physio-
logical effect results from a decrease in available oxygen due to the presence
of hydrogen. There are no natural warning properties, so an odorant has
been considered. The precautions taken to prevent fire and explosion are
more than adequate to protect against oxygen deprivation and consequence
asphyxia.
8. 2. 5 Safety Effects
Hydrogen, being readily flammable in air, creates combustible
mixtures with air. Because its flammability limits when mixed with air are
very wide and its ignition energy is very small, a hydrogen fire is easier to
create than a gasoline fire. The required safety precautions for handling
hydrogen are therefore more stringent than those required for conventional
fuels. The safety aspects of both gaseous and liquid hydrogen will be examined.
8. 2. 5. 1 Gaseous Hydrogen
The occurrence of leaky hydrogen systems can pose a hazard.
In contained spaces, however, the amount of energy released in a fire or
explosion is low enough such that relatively small hydrogen explosions can be
contained within the walls of laboratory glassware. In unconfined spaces,
limited release of hydrogen tends to move away from the point of release
since the density of hydrogen is only about seven percent that of air. On the
8-12
-------
00
Table 8-3. Emissions from Hydrogen-Fueled Automobile,
gm/mile (Ref. 8-1)
Test No.
1
2
1975 Federal
Interim Stds
1977 Federal Stds
HC
0.20
0
1. 50
0.41
CO
0.44
0. 32
15.00
3.40
NO
X
0.850
0.205
3. 1
0.400
C°2
9.72
Not Reported
Not Stipulated
Not Stipulated
-------
other hand, gasoline vapor tends to collect around a spill or leak, since its
density is greater than that of air. This aspect is important when considering
public reaction to the safety aspects of hydrogen. Although extremely rapid
combustion of hydrogen can occur, the detonation of hydrogen-air mixtures
is unlikely in unconfined spaces.
Extra precaution should be taken for leaks. Since the hydrogen
flame is almost invisible, small hydrogen fires may go unnoticed. Severe
burns to personnel may be caused by hydrogen flames from leaky equipment.
8. 2. 5. 2 Liquid Hydrogen
Liquid hydrogen is hazardous because of its extremely low
temperature. Burns and freezing of the skin and tissue will result if contacted
by liquid hydrogen, cold hydrogen vapors, or cold pipes and valves.
Since liquid hydrogen has a very low viscosity, leakage through
a ruptured tank occurs at a high rate. The chances of leakage are, however,
remote, since hydrogen must be stored in double-walled, vacuum-insulated
tanks.
The storage temperature of liquid hydrogen is below -423°F.
This creates a significant and unique hazard. This temperature is low enough
to liquefy all other gases except helium. Any part of the hydrogen tank or
transfer line that becomes cooled to this temperature or close to this tempera-
ture and is exposed to air will liquefy the air. Because of the difference in
boiling points between oxygen and nitrogen, the resulting liquid will become
enriched in oxygen. Thus, an improperly insulated liquid hydrogen line can
cause oxygen buildup, with a consequent dangerous fire hazard. For this
reason, flammable materials cannot be used as insulation. In addition, foam
insulation cannot be used unless the voids in the insulation are purged by
either hydrogen or helium, the only gases that will not condense. Any air
leaks in the insulation will present a fire hazard due to the presence of
oxygen concentration by liquefaction. During transfer operations, hydrogen
gas evolves. This gas must either be contained or be vented without being
ignited.
8-14
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8'2'^ Handling, Storage and Distribution Requirements
Some major drawbacks are found in the problems of distribution
to service centers and in storage on-board the vehicle. To provide a vehicle
with reasonable driving range, an energy content of about 20 gallons of gaso-
line, or about 2 million Btu, must be provided. A standard 2-cubic foot
cylinder of compressed hydrogen at 2000 psi weighs about 125 pounds and
contains only 1 pound of hydrogen, which is about 51,600 Btu. Thus, about
40 such cylinders would be required. Clearly, compressed gas is out of the
question, even with lightweight cylinders. In liquid form, hydrogen has an
energy density of 30,800 Btu/gal, so that a tank capacity of 110 gallons is
required, over four times the size required for gasoline. A vacuum-insulated
storage tank weighing about 300 pounds will be required, the fuel will add
43 pounds for a total weight of 343 pounds. For the same energy content,
20 gallons of gasoline will weigh about 119 pounds while the tank will weigh
about 26 pounds for a total of 145 pounds.
Because liquid hydrogen must be maintained in vacuum-
insulated tanks at below its boiling point of -423°F, the method of insulation
and fabrication are complex and could prove too expensive. Such tanks are in
routine laboratory use today, and large-scale transportation of liquid hydro-
gen is carried out by rail-tank car and by road tanker. The safety problems
of liquid hydrogen tanks in these applications have been identified and reduced
to acceptable risks.
A possibility exists for the use of a metal hydride that can be
decomposed on the vehicle to provide hydrogen and that can be replenished at
filling stations supplying hydrogen gas. The hydrogen is held inside the metal
hydride by chemical bonds which are broken by heat addition. The use of a
magnesium-nickel alloy hydride system has been suggested, but its weight and
volume are still excessive (some 530 pounds plus a container) for matching
the equivalent of about 20 gallons of gasoline. Another problem with this con-
cept is the dissipation of the large amount of heat released when the fuel tank
is filled and the hydride is formed.
8-15
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Structural materials used for the storage and transfer of liquid
hydrogen are of interest to the design engineer. For the low-temperature appli-
cation, materials should be selected on the basis of their structural properties
such as yield strength, ductility, impact strength,and notch sensitivity. The
material must also be metallurgically stable, so that phase changes in the
crystalline structure will not occur under repeated thermal cycling. Hydrogen-
created blistering and embrittlement of metal may be avoided by the use of
protective coatings and of the proper alloys. Low-alloy carbon steel becomes
brittle at liquid hydrogen temperatures and should not be used. Ferritic and
martensite stainless steels have poor ductility at low temperature and are
not recommended for cryogenic use. As a rule, copper, brass, aluminum,
monel, nickel, and authentic or 300 series stainless steels are satisfactory.
8.2.7 Critical Research Gaps
The technical suitability of hydrogen as an automotive fuel has
been demonstrated by the limited experiments to date. Before hydrogen can
be seriously considered for widespread use as an automotive fuel, considerable
research efforts are required. These include:
a. Automobile storage method for hydrogen whether gaseous,
liquid, hydride, or chemical compounds
b. Combustion and mechanical efficiency characteristics of
alternative engines operating with hydrogen fuel
c. Performance of hydrogen-engine-powered automobiles as
measured by exhaust emissions, fuel economy, acceleration
level, response to driver commands, start time, all-weather
and altitude operation, etc.
d. Research directed toward increased safety in handling liquid
hydrogen by untrained persons at the service station.
8. 3 CURRENT STATUS
8. 3. 1 Production Rates
World hydrogen production in 1965 was estimated at 2.7 trillion
cubic feet (7. 170 million short tons), of which two-thirds was used in manu-
facturing ammonia.
8-16
-------
The U.S. Department of Commerce, Bureau of the Census,
reported the following annual U.S. production figures for hydrogen, in billions
of cubic feet:
Grade 1959 I960 1961 1962 1963 1964
High Purity (99. 5%+) 10.6 12.9 14.3 18.0 21.2 22.1
Low Purity (below 99. 5%) 47.4 52.3 51.9 57.7 72.9 85.2
These production figures did not include hydrogen produced and consumed in
the manufacture of ammonia or methanol, or hydrogen produced and consumed
in oil refining.
The largest single production and use of hydrogen is in ammonia
manufacture. Ammonia production in the U.S. was estimated at 8. 6 million
short tons in 1965 (Ref. 8-8), which required the use of 602 billion ft3 of
hydrogen. World ammonia production was estimated at 25.7 million short
3
tons, requiring 1. 8 trillion ft of hydrogen, or about two-thirds of the total
world production of hydrogen (Ref. 8-9).
The second largest use of hydrogen is in petroleum-refining
operations. This use has grown rapidly in recent years. Five hydrocracking
processes (catalytic cracking with simultaneous hydrogenation) were in use
in the U.S. in 1965 with an estimated annual hydrogen requirement of 63 bil-
lion ft3 (Ref. 8-10). More than twelve hydrogen treating processes (hydro-
desulfurization, etc. ) were being used in the U.S. in 1965, with a hydrogen
3
requirement of about 300 billion ft per year.
A considerable portion of the hydrogen used in the preceding
oil-refining processes was obtained as a by-product from catalytic
hydrocarbon-reforming processes, of which more than ten were being used
3
in the U.S. in 1965, with a total hydrogen production of about 720 billion ft
per year. A large portion of this by-product hydrogen was being used as fuel
gas, with the remainder being utilized in oil-refining processes or ammonia
synthesis.
8-17
-------
Methanol production required about 70 billion ft3 of hydrogen
in the U.S. in 1965. A comparison of the U.S. hydrogen utilization rates in
1945 (Ref. 8-11) and 1965 appears in Table 8-4.
8.3.2
Uses
The United States space exploration program has created a
large demand for hydrogen, both as a primary rocket fuel for combustion
principally with oxygen and as a propellant for nuclear-powered rocket
research. The production capacity of 160 tons per day of liquid hydrogen
was generated primarily for the space program requirements.
Hydrogen has been favored as a propellant for nuclear space
propulsion devices, essentially because of its low molecular weight. Liquid
hydrogen carried by the vehicle is vaporized and heated to high temperatures
by heat from the nuclear reactor, and then ejected as the propellant. Various
schemes have been devised to attain maximum fuel efficiency, including the
use of liquid-solid hydrogen slush to reduce storage volume and to enhance
storability.
Hydrogen has been used in many industrial processes, such
as the generating power in spacecraft as just discussed, as high-temperature
plasma in carrying out chemical reactions, and in reducing iron ores.
Table 8-4. U.S. Hydrogen Usage
3
Hydrogen Usage, billion ft
Ammonia
Oil Refining
Methanol
Other Uses
Total
1945
36
6
12
18
72
1965
602
363
70
120
1155
8-18
-------
Hydrogen was formerly used in large quantities for inflating
lighter-than-air (LTA) vessels such as dirigibles, balloons, etc. In recent
years, helium has been used for this service, whenever available, as it is
nonflammable and thus safer than hydrogen. Considerable quantities of
hydrogen were used in England during World War II for the inflation of bar-
rage balloons.
Hydrogen is used in welding metals due to the intense heat of
the oxygen-hydrogen flame. More recently, hydrogen has been replaced some-
what by acetylene for this purpose, although many special applications still
require the use of hydrogen. Atomic-hydrogen welding is of considerable
importance in welding thin sections of alloy material. In this process, hydro-
gen gas is passed through an electric arc between tungsten electrodes where
it dissociates to atomic hydrogen. Molecular hydrogen reforms a short
distance from the arc with the evolution of intense heat.
The reducing property of hydrogen is widely used in the metal-
lurgical field. It may be used in the direct reduction of metallic oxides as in
the production of tungsten and molybdenum, and the reduction of iron ore to
sponge iron, as mentioned previously. In the production of metallic magne-
sium with carbon, the carbon monoxide and magnesium vapors leaving the
furnace are chilled with a blast of hydrogen to prevent the reverse reaction,
which takes place on slow cooling. Metals are bright,annealed in an atmo-
sphere of hydrogen and/or nitrogen. This atmosphere prevents the formation
of metallic oxides during the annealing operation, which would otherwise dull
the surface.
Another major use of hydrogen is in the hydrogenation of
vegetable and animal oils and fats to produce vegetable shortening, margarine,
lard flakes, etc. Other oils are hydrogenated for use in soap and lubricants,
as well as in the paint, varnish, and textile industries. Organic chemicals
are also hydrogenated industrially in processes such as the production of
glycols from aldols, alcohols from esters and glycerides, amines from nitriles,
8-19
-------
and cycloparaffins from aromatics. Gasoline and fuel oil may be obtained by
the hydrogenation of coal, but at present this process is not competitive with
obtaining these products from petroleum.
8.3.3 Consumers Costs
The cost of electrolytically produced gaseous hydrogen is a
strong function of the cost of electricity, the latter presently being about
$0. 012/kW-hr in the United States (Ref. 8-12). a gaseous hydrogen cost of
$4. 60 per million Btu is given in References 8-2, 8-16 for electricity at
$0. 08 per kW-hr; a cost range of $3 to $5 per million Btu is given in Refer-
ence 8-13. For comparison, gaseous hydrogen from natural gas, by far the
largest current source in the United States, costs $0. 80 to $1. 00 per million
Btu (Refs. 8-2, 8-14). However, hydrogen for automotive use would probably
be in the liquid state, and would be produced from coal because of natural gas
shortage. The projected cost of hydrogen from coal is $2. 60 per million Btu,
and the additional cost of liquefaction, distribution, and retailing is estimated
at $7. 30, bringing the total cost at the station (without tax) to $9. 90 per mil-
lion Btu (Ref. 8-16).
For comparison, gasoline from petroleum currently cost $2. 15
per million Btu ($0. 38/gal.) at the refinery in mid-1973 (Ref. 8-16). To this
figure must be added about $1. 00 per million Btu ($0. 115/gal) for distribution
costs to the consumer (excluding taxes).
8.4 PROJECTED STATUS
8.4.1 Availability
Many possible alternatives are available for manufacturing
hydrogen. Processes currently available include production from fossil
fuels and water electrolysis. The source of hydrogen is either from water
or hydrocarbon. Although it is theoretically easy to obtain hydrogen from
coal, the process is less efficient than processes for producing hydrocarbon
8-20
-------
luce
gas or liquids. Consequently, the more practical way would be to prodx
hydrogen by water electrolysis, which requires electrical power. With the
optimistic assumption for a rapid nuclear buildup, it was estimated in Refer-
ence 1-2 that the maximum production of fuel hydrogen that could be accom-
plished in the year 2000 would be equivalent to 1. 5 million barrels of petroleum
per day. This would satisfy approximately 20 percent of the 1973 automobile
fuel consumption, and a considerably lower percentage of the figures projected
for the year 2000.
Thus, it appears unlikely that hydrogen will become a signifi-
cant factor, at least for automotive application.
8.4.2 Projected Consumer Costs
A preliminary cost analysis for hydrogen produced from
nuclear power (by electrolysis) and from coal is given in Reference 8-16.
In the former case, a cost of $4.65 per million Btu is derived for gaseous
hydrogen at the production plant, based upon power at one cent/kW-hr and a
relatively high cell efficiency of 76 percent. Other sources (e.g., Ref. 8-2)
arrive at somewhat lower costs ($4.50 per million Btu and up) depending upon
the level of technology assumed, electrical costs, by-product credits, etc.
Gaseous hydrogen from coal is projected to cost $2.60 per million Btu using
improved gasification technology (Ref. 8-16).
To arrive at consumer costs for the final fuel product, here
considered to be liquid hydrogen, several other items must be added. For
electrolytic hydrogen an increment of $5. 60 per million Btu must be added
to cover. The total consumer cost is then $10. 25 per million Btu. In the
case of hydrogen from coal, the distribution costs may be higher because of
higher liquefaction and transportation cost, resulting in distribution cost of
$7. 30/million Btu (Ref. 8-16).
8-21
-------
Note that no estimated costs are given for liquid hydrogen
derived from oil shale. Although this approach is technically feasible, the
fact that synthetic crude oil can be more easily and cheaply obtained from
shale will probably reserve this resource only for hydrocarbon fuel produc-
tion, leaving water electrolysis as the most practical future source.
8.4.3 Capital Costs and Timing Implications
To have a noticeable impact on energy or pollution problems
in the next 5 to 10 years, any suggested changes to fuel systems must be
relatively simple and must be able to use much of the existing equipment.
Past problems in handling cryogenic liquids and compressed gases will act
as a deterrant to near-term use of hydrogen in any significant quantities.
When appraising capital costs for a hydrogen economy,
factors to consider include the production process and the distribution
systems.
Substantial savings in capital cost investment can be realized
if present distribution systems for gasoline can be utilized. Unfortunately,
this is not feasible, and future hydrogen-production centers will probably be
located away from existing gasoline-production centers. This is because
water sources and electrical power sources for hydrogen production will not
likely be located near existing gasoline-producing centers.
Recent studies were conducted of capital cost investment for
large-size plants for the production of hydrogen. For a 2, 500-ton per day
capacity, a coal conversion plant was estimated to cost $1.2 billion, as
compared to $2. 7 billion for a nuclear electrolysis plant. The itemized
cost is shown in Table 8-5.
8-22
-------
Table 8-5. Investment for 2^500-Ton/Day Liquid Hydrogen
Supply System (Ref. 8-4)
Coal Conversion
Process
Investment
$ Million
Coal Requirements
Coal Conversion Plant
Pipeline — H2 Gas
Compressor Stations
Refrigeration/
Air Compression
Oxygen Generators
H2 Liquefiers
H2 Storage Tanks
Distribution Area
31.000 tons/day, (12,000 Btu/lb), 31,000 MM Btu/hr
4 - 400 Million ft3/day H2 gas
generators - eff. = 0.53 $ 500
1 — 300 Mile, 36 in. dia. , 900 psi 147
2 - 12,000-hp ea, gas drive 3
10 - 125,000 kW - steam drive
eff. = 0.65 : 250
10 - 1200 tons/day told boxes 50
10 - 250 tons/day c&ld boxes 100
10— 12,500,000-gallon flat bottom tanks 63
5 — Filling stations per tank 5
Total Investment $1,118 Million
6,200 Megawatts, 64,000 MM Btu/hr
6 - 1033 MW Reactors - eff. = 0.33 $2,188
6—1 million gallon/day units 5
6 - 175 MM ft3/day H2 - 820,000 kW ea. train,
1 atm pressure 220
10 - 125,000 kW - electric drive 125
10 - 250 tons/day cold boxes 100
8 — 1,100,000 gallon barges, 1-day
turnaround 20
10— 12,500,000-gallon, flat-bottom tanks 63
15
Total Investment $2,736 Million
Nuplex— Electrolysis
Process
Nuclear Energy
Requirements
Nuclear Plants
Destination Plant
Electrolysis Units
Refrigeration
Compressors
H2 Liquefiers
Barges — H2 Liquid
H2 Storage Tanks
Distribution Area —
Docks
8-23
-------
8.4.4 Factors Which May Inhibit Use
Technical problems of compatibility of storage containers
and distribution systems must be resolved. Hydrogen embrittlement must
be considered in the service life of the designs. Storage on-board and safety
in handling both gaseous and liquid hydrogen is of concern. The economic
impact in changing over from gasoline-fueled engines to hydrogen-fueled
engines will undoubtedly be a major factor to be considered.
On a dollar-per-Btu basis, liquid hydrogen cost to the consumer
will be much greater than the cost of gasoline or distillate from coal, depend-
ing upon the source of the economic analysis. Significant cost items are con-
nected with the liquefaction of the hydrogen and its subsequent transportation
and storage to retail outlets.
Technically it is easy to use coal to make hydrogen. Indeed,
most synthetic fuel processes use this route to "correct" the unfavorable
C:H ratio in coal. However, a more efficient use of the energy in coal is
obtained as the consumption of process hydrogen is minimized. Thus, the
manufacture of a hydrogen fuel product is an inefficient way of using coal
energy (Ref. 8-14).
The practicality of using hydrogen as fuel, subject to the
above efficiency considerations, appears to lie in the application of nuclear
energy to dissociate water. Here, the problem is in the rate at which nuclear
capability can be developed. Slippage in on-line dates is still continuing, and
this has caused groups such as the AEC, Atomic Industrial Forum (AIF), and
the staff of the Joint Committee on Atomic Energy to revise earlier downward
estimates of future capability. In consequence, the time at which a "spare"
nuclear capability may be conceptualized as being potentially available for
hydrogen production continues to move farther into the future (Ref. 8-14).
8-24
-------
8.4.5 Critical Technology Gaps
Research and development efforts are required before hydrogen
can be considered as an alternative fuel for automotive applications. These
are identified as follows:
a. Investigate economics of hydrogen production methods for
large-scale use in the transportation sector
b. Develop techniques for long-distance transmission and bulk
storage of hydrogen
c. Develop techniques for safe storage arrangements on-board
of vehicles
d. Develop public safety guidelines and regulations.
The major obstacle to using hydrogen on a large scale is one
of economics. Extensive and long-range R&D programs, as well as avail-
ability of nuclear-de rived electrical energy for water electrolysis, may
possibly lead to a narrowing of the gap between the cost of hydrogen and the
cost of fossil fuel.
8.4.6 Potential for National and Regional Use
With overall logistics in view and, in particular, examining
the problems associated with distribution of hydrogen fuel and vehicle ser-
vices, any progress in conversion from hydrocarbon to hydrogen fuel must
take place over a long period. Perhaps the logical place to initiate hydrogen
as a fueling standard would be in new, unprecedented applications, such as
projected high-speed ground transportation units. These would have the
assumed advantage of a minimum of required fueling points, where trained
personnel and adequate equipment could be located.
Next in turn might be conventional vehicles, such as intercity
and urban trucks and city buses. Once again controlled central servicing
centers are normally used, with the vehicles carrying enough fuel for
expended endurance. Probably the last place that hydrogen will be put into
service will be the private automobile, since it requires a very large number
8-25
-------
of service stations attended by relatively unskilled personnel. Nevertheless,
such a service station operation can be conceived and, in time, an unskilled
operator may be able to service hydrogen vehicles safely and efficiently.
The routine servicing of LNG (essentially cryogenic methane) into a number
of city fleets of "clean air" cars testifies to this potential.
Liquid hydrogen has been investigated for use as an aircraft
fuel, and the Apollo program has provided significant technology to meet high
standards of safety and performance. Careful overall system planning, how-
ever, will be required to convert from the present hydrocarbon fuel to a
hydrogen fuel.
Using optimistic assumptions concerning a rapid buildup of
post-1985 nuclear capability, it is estimated that the maximum quantity of
fuel hydrogen that could be produced in the year 2000 is equivalent to 1.5 mil-
lion barrels per day of petroleum. This quantity is based on the assumption
of a "maximum" nuclear program and the dedication of all nuclear capability
in excess of current AEC estimates to the production of hydrogen. These are
considered to be unrealistic assumptions. Even so, the hydrogen-fuel poten-
tial so calculated would not be able to satisfy more than a small percentage
(about 9%) of automotive fuel demand in the year 2000V (Ref. 8-14). Based
on these estimates, it would appear that the more obvious potentials for
nuclear energy and nuclear-de rived hydrogen are to:
• Release petroleum and other fossil fuels from power
generation, thereby making them available for other uses
including automotive fuels
• Provide hydrogen for conversion processes (particularly,
but not exclusively, coal) so as to maximize the yield of
useful synthetic fuels from a given quantity of the resource
processed
• Possibly supply hydrogen for a long-distance, supersonic
airplane.
*
It is also possible to consider hydrogen produced by a thermochemical
dissociation process. Barring a breakthrough in new decomposition
cycles, it is unlikely that this approach will lead to large quantities of
economical hydrogen in the next 20 years.
8-26
-------
SECTION 9
-------
SECTION 9
AMMONIA
9. 1 CHARACTERIZATION
9. 1. 1 Fuel Type
Anhydrous ammonia is a colorless gas at standard conditions
with the chemical formula NH,. At 70°F, ammonia will become a liquid when
•^ o
pressurized to 129 psia with a density of 38 Ib/ft . The molecular structure
of ammonia is a triagonal pyramid with an H-N-H bond angle of 107° and an
N-H bond length of 1. 008 angstrom (gas) and 1. 13 angstrom (solid) (Ref. 9-1).
Ammonia burns readily in oxygen but its combustion in air is more difficult.
In the presence of a catalyst its combustion in air is aided.
On heating to 900 F or above in the presence of a catalyst,
ammonia is decomposed into hydrogen and nitrogen. The decomposition of
ammonia is sometimes used as a source of hydrogen, as in portable welding
outfits, because a given volume of liquid ammonia will yield more hydrogen
than will an equal volume of compressed hydrogen gas (Ref. 9-2).
Ammonia is under consideration as an alternative automotive
fuel for storing hydrogen in nitrogen hydride form on-board a vehicle without
many of the problems associated with storing pure hydrogen. Additionally,
the products of combustion will contain neither carbon monoxide nor unburned
hydrocarbons; oxide of nitrogen, however, will be present.
Basically, ammonia is produced by catalytic synthesis from
hydrogen and nitrogen. The manufacture of ammonia therefore resolves it-
self into obtaining hydrogen by the methods discussed under Methods of Manu-
facture, Section 8. 1.3, and obtaining nitrogen from air.
9.1.2 Raw Material Sources
Raw materials which lend themselves to ammonia manufacture
are identical to hydrogen manufacture with the exception of the air required to
9-1
-------
provide nitrogen. Practically all current production is from natural gas or
petroleum derivative sources. The nonpetroleum or natural gas derivative
chemical feedstocks considered most suitable for ammonia process hydrogen
manufacture are coal and oil shale. Other methods used to produce hydrogen,
such as water electrolysis, can also be used. This last method is especially
suitable if alternative uses for the simultaneously derived oxygen can be
found. Other elements involved as a part of the processing are water, cata-
lysts, CO plus CO_ absorbing chemicals, electrical power, and heat, as will
be discussed under methods of manufacture.
9. 1. 3 Methods of Manufacture
9.1.3.1 Hydrocarbon Synthesis
Most current industrial processes for the manufacture of
ammonia are similar to the process shown in Figure 9-1.
The process is adaptable to produce ammonia from any gas
containing hydrocarbons with the primary objective of producing free hydro-
gen to combine with nitrogen supplied by air.- Ammonia is produced by passing
hydrogen and nitrogen at elevated pressure and temperature over an iron-base
catalyst (Haber process). The chemical reaction is expressed as:
N
_ + 3 H Catalyst (Iron Alloys) 2 NH,
^ ^ -^ 3
Gases leaving the catalytic converter are cooled to condense the ammonia,
which is removed as a liquid.
The process operates in the following manner: A portion of
the hydrocarbon in the feedstock is converted to raw synthesis gas, combining
with steam in the primary steam reformer to form H? and CO. The remain-
ing hydrocarbons are converted in the secondary reformer. Air is introduced
to supply nitrogen. The CO shift converter catalytically oxidizes most of the
CO to CO.,. After cooling, the major portion of the CO_ is removed by chem-
ical reactions. The residual CO and CO_ are then removed by methanation.
9-2
-------
xO
I
10
HYDROGENAT.ON ^f™™™"
FEED -*t r*l
BOILER FEED WATER
STEAM
1-N/W
STEAM
3F
AIR-g-i
£3"
r^
UJ
Xd
CO SHIFT CONVERTER
UJ
QO
Z<
-------
The process described uses up oxygen in the air supply, leaving a synthesis
gas consisting of hydrogen and nitrogen. This combination is then catalyzed
into ammonia gas, compressed, refrigerated, and extracted as liquid ammonia.
While gaseous and liquid raw materials lend themselves rela-
tively easily to the process described, solid fuels such as coal and oil shale
require preprocessing to gasify them. The conversion of coal to hydrogen
is briefly covered in the preceding section. Nitrogen would be obtained from
an air liquefaction plant. The remaining synthesis process is as just descri-
bed. However, with the possible exception of a combustion plant (see Sec-
tion 9. 1.3.3), it is unrealistic to make ammonia by converting coal to hydrogen.
9.1.3.2 Electrolysis
The two principal electrolytic processes for producing hydro-
gen, water, and hydrogen halide electrolysis were discussed under hydrogen
production methods. Current installed electrolysis plant capacity throughout
the world is estimated to be three million pounds of hydrogen per day with
primary use in the production of ammonia. This is only 3 percent of the daily
U.S. hydrogen consumption (Ref. 9-4). The electrolysis plants are located
where there is significant demand for ammonia-derived fertilizer, plentiful
low-cost electricity, and no low-cost hydrocarbon fuel supply such as in
India, Egypt, Chile, Norway (Ref. 9-4), and British Columbia in Canada
(Ref. 9-5). As previously noted, the manufacture of nitrogen for the catalytic
synthesis of the ammonia requires an air liquefaction facility. The by-product
of both water (or halide) electrolysis and air liquefaction is oxygen. Since
oxygen can be used in the synthesis of hydrogen from coal, the concept of a
combined system approach appears attractive.
9. 1.3.3 Combination Hydrocarbon/Electrolysis System
Figure 9-2 derived from Reference 9-4 shows a combined
system whereby coal is gasified using an oxygen gasification system. The
required oxygen would be supplied from the electrolysis and air separation
systems. The hydrogen produced by the combined hydrocarbon gasification
and electrolysis would then be converted into ammonia by catalytic synthesis
with the nitrogen produced by the air separation facility.
9-4
-------
1100 TONS OF BITUMINOUS COAL OR
1460 TONS OF LIGNITE
Ui
660 TONS 0?
500 TONS E
2.6 x 106 k\
220 TONS O2
COAL GASIFIER
AND
SHIFT REACTOR
WATER
ELECTROLYSIS
FACILITY
/V-hr
1050 TONS AIR
(26 x 206 ft3)
122 TONS H2
JS 02
55 TONS H2
AIR SEPARATION
FACILITY
2 ^ AMMONIA ^ 1000
* SYNTHESIS ^ NJj™
~"n TniTTr* f-AULIM
9.6 x 104 kW-hr
OVERALL COAL GASIFICATION REACTION
(THEORETICAL):
3C + 0^ + 4H^O -» 3 CO^ + 4H,
Figure 9-2. Combined Coal Gasification/Water
Electrolysis (Ref. 9-4)
-------
9.1.3.4 Summary of Ammonia Manufacture
Table 9-1 provides a summary of the ammonia manufacturing
processes, including energy and raw material resources data from Refs. 2-1
and 9-4. The thermal efficiencies of the various processes are based on the
ratio of gross calorific values of the ammonia produced to the total process
equivalent heat input. For processes using large amounts of electrical power,
the efficiency of the electric power generation process was included. The
efficiencies using synthetic liquid or gaseous fuels as raw materials do not
include the efficiency in producing them from coal or shale.
9.1.4 Physical and Chemical Properties
The physicochemical properties of anhydrous ammonia are
provided in Table 9-2. It can be noted that the net heating value of ammonia
is 8000 Btu per pound compared to heating value of 19, 000 Btu per pound for
gasoline. This indicates that, for equal combustion efficiencies, approximately
2.4 times the amount of ammonia as gasoline is required for equal energy
outputs.
The vapor pressure of liquid ammonia ranges from 250 psia to
20 psia over the normal automotive temperature extremes of 110 F to -20 F,
respectively. This indicates that the vehicle storage tank should pressurize
the ammonia to approximately 250 psia to maintain the ammonia in liquid form.
The flammability characteristics of ammonia in air and oxygen at atmospheric
pressures are shown in Figure 9-3.
9.2 SUITABILITY FOR USE AS AN ENGINE FUEL
As noted previously, the interest in ammonia as an engine fuel
stems from the consideration that it allows the storage of hydrogen in nitrogen
hydride form at relatively low pressures (250 psia) when at ambient temper-
atures. Additionally, the products of combustion will contain neither carbon
9-6
-------
Table 9-1. Ammonia Production
Energy /Material
Resources
Coal to Ammonia
1. 8 ton coal
147 kWhr 6600 Ib
boiler feed water
490, 000 cooling
water catalysts
Coal or Oil Shale D
0. 81 tons naphtha
33. 5 kWhr 6180
Ib boiler feed
water 468, 000 Ib
cooling water
SNG to Ammonia
32. 6 million Btu
of SNG as feed
and fuel. 15 kWhr
22,400 Ib makeup
water
Coal or Oil Shale-E
0. 94 tons heavy
oil, 110 kWhr
3840 Ib. boiler
feed water 883, 000
Ib cooling -water
Water Electrolysis
Name of the
Process
Make H£ by any
process, then
make ammonia
erived Light Naphth
Gasify naphtha
to produce ti-^
and then make
ammonia
Reform SNG to
make H2 and
then make
ammonia
lerived Heavy Oil to
Gasify to pro-
duce H2 and then
make NH,
to Ammonia
1. 61 tons Distilled or demineralized
H2O 1.05 tons air, 85 tons cooling
water, catalysts
Combination Coal Gasification/Electro
Comment on
the Process
Requires 44. 05
million Btu/ 1
ton NH
a to Ammonia
Requires 33. 7
million Btu/1
ton NH3
Requires about
32. 9 million
Btu /ton of NH.
Ammonia
Requires about
36. 9 million
Btu/ton of NH3
7750 kWhr
.ysis
1. 1 tons coal or 1. 5 tons Lignite 0. 5 tons distilled
water 1.05 tons air 2600 kWhr 0.4 tons feed water
26.4 tons cooling water, catalysts
i 1
Synthesized
Fuel
1 ton of
ammonia
1 ton of
ammonia
1 ton of
ammonia
1 ton of
ammonia
1 ton of
ammonia
1 ton of
ammonia
By-Product
oxygen
Thermal
Efficiency
%
44
b
57
59b
53b
25°
38d
Comments on
Pollution
Sulfur removal
problems are
similar to coal
gasification
problems.
Sulfur removal
is necessary
for feedstocks
containing
sulfur.
Minimum pol-
lution problems
Sulfur removal
problems are
similar to coal
gasification
problems.
Thermal pol-
lution sulfur
removal
Sulfur removal
thermal
pollution
Reference
2-1
2-1
2-1
2-1
9-4, 2-1
9-4, 2-1
Thermal efficiency based upon higher heating value of input and product streams.
Does not include energy involved in producing liquid or gaseous hydrocarbon raw materials from coal or shale.
Assumes 33% thermal efficiency to produce electricity, 75% efficiency to electrolize water.
Assumes 29% thermal efficiency to electrolize water, 44% thermal efficiency to gasify coal.
vO
1
-------
Table 9-2. Physiochemical Properties of Anhydrous
Ammonia (Ref. 2-1)
Chemical Formula
Molecular Weight
Melting Point
Normal Boiling Point (NBP)
Density at Normal Boiling Point
Vapor, lbs/ft3
3
Liquid, lbs/ft
Density at 70°F
Vapor, lb/ft3
Liquid, lb/ft3
Heating Value, Liquid
Lower Heating Value, Btu/lb
Lower Heating Value, Btu/gal (70°F)
Products of Combustion, Liquid
Heat of vaporization at NBP, Btu/lb
Flammable limits in air, vol %
Autoignition temperature, F
Stoichrometric mixture, Ib air/lb fuel
Research octane number
17.031
-108°F
-28°F
0.0556
42.6
0.0433
38.0
8,000
40,640
591
16-27
1204
6. 1
130
At atmospheric pressure of 14. 7 psia.
9-8
-------
(A
Q.
UJ
f£
V)
V)
Ul
oc
a.
a:
O
a.
14.7
10
8
6
1
VAPOR
PRESSURE
CURVE
°'-7400
UPPER LIMIT IN OXYGEN
FLAMMABLE MIXTURES
-200
MELTING POINT
I . I . I .
SPONTANEOUS
IGNITION
100
68.0
54.4
40.8
27.2
20.4
200 400 600 800
TEMPERATURE, °F
1000 1200 1400 1600
6.8
4.8
O
h-
QC.
UJ
8
O
<
I
Q>
O.
O
13.6 * •=
Figure 9-3. Flammability Characteristics of Ammonia in Air
and Oxygen at Atmospheric Pressure (Ref. 9-6)
-------
monoxide (CO) nor unturned hydrocarbons (HC), two automobile exhaust
pollutants of current concern. Oxides of nitrogen will be present, however.
The following discussion addresses:
• The use of ammonia as a fuel for various automotive
heat engines
• The exhaust emissions including nitric oxides (NOX) and
unburned NH,
• The requirements to handle, store, and distribute the
ammonia fuel considering toxicity and safety requirements
• The fuel economy effects.
The characteristics of ammonia as a fuel applicable to any
engine are noted below. Of particular note are emission effects where NO
and unburned NH,. in the exhaust represent potential air pollution problems.
The impact of ammonia as a fuel for the typical automobile engine is also
noted below. For a convenient frame of reference, the data are normalized to
the use of a hydrocarbon fuel, gasoline.
• Otto Cycle Engine. Data are available for the use of
ammonia as a fuel for conventional reciprocating engines
but not for rotary or stratified charge engines. Since these
are versions of an Otto cycle engine, however, it is expected
that the general trends for the typical automotive recip-
rocating engine will apply to them as well.
• Gas Turbine Engine. There are minimal data available on
the use of ammonia as a fuel for gas turbine engines. Most
of the available data are based on theoretical predictions
(Refs . 9-7 and 9-8) and are shown below.
• Diesel Engine. The impact of using ammonia fuel for Diesel
engines is indicated in the following paragraphs. The data are
indexed to cetane as the HC fuel and are mainly based on exper-
imental results (Ref. 9-9).
• External Combustion Engines. No data are available for the use
of ammonia as a fuel for Rankine and Stirling engines. However,
based on the smaller (8000 Btu/lb) content of ammonia, fuel
consumption would be more than twice that of gasoline. Addition-
ally, the potential pollution from NO and unburned NH, in the
exhaust would present problems.
9-10
-------
9.2-1 Engine Compatibility
Ammonia is corrosive to copper, zinc, and their alloys
(Ref. 9-3).
• Otto Cycle Engine
• Spark Advance: 54° for NH vs 30 to 43° for HC fuel
for maximum output. The greater advance is considered
to be due to a flame -propagation rate about 30% slower
and a kernel development time 40% longer for NH
(Ref. 9-10). 3
• Cooling Jacket Temperature: 354°F for NH3 to enhance
decomposition during compression versus 152°F for HC
fuel to suppress knocking at a compression ratio of 10.
Dissociation: 4 to 5% ^ needed to obtain maximum
engine power at any given mixture ratio at 1800 rpm and
a compression ratio of 8. About 25% of the NHg must be
dissociated to achieve 4 to 5% of H£.
Peak Power: 65 to 71% of HC fuel peak power for opera-
tion on
Gas Turbine Engine *
• Power Output: Ammonia can yield power output up to
10% greater than that for hydrocarbon fuels under the
same conditions of limited turbine inlet temperature.
This is due to the combined effects of high heat of vapor-
ization and high yield of product moles for ammonia.
• Thermal Efficiency: Ammonia efficiencies should range
up to 10% higher than with HC fuels due to the high yield
of product moles.
• Combustion Stability Limits; Blowout points are charac-
terized by low frequency pulsations (1/2-1 Hz). Addition
of 5% propane will suppress pulsation and more than
double the maximum blowout limits.
Diesel Engine
• Ignition: A compression ratio of 35 to 1 or higher would
be required for compression ignition of NH3>
* Minimum data available, mostly based on theoretical
predictions (Refs. 9-7 and 9-8)
9-H
-------
Fuel Injection: NHj injection at 150 - 180° before top
dead center (btdc) versus 10° btdc for diesel fuel.
Combustion Chamber Peak Pressure: 750 psi for
vs. 1000 psi for diesel fuel.
Peak Power; At a comparable fuel- air equivalence ratio,
the engine develops about 10% less power on liquid NHo
than on diesel fuel. However, diesel-fueled engines are
usually smoke limited to operate at a fuel-air equivalence
ratio of 0.7, whereas NH3 peak power is developed at an
equivalence ratio of 1.06. Compared this way, the NHo
fueled engine will produce about 20% more power.
9.2.2 Emission Effects
Nitric oxide concentrations in excess of calculated equilibrium
levels were observed over the fuel-air equivalence-ratio range of 0.4 to 1.85
in ammonia combustion in an atmospheric pressure flame and are considered
likely to be of concern to air pollution (Ref. 9-11).
In the same experiment, the measurement of unburned ammonia
led to the conclusion that utilization of NH? as a fuel is likely to result in the
production of unburned NH^ at levels which must be of concern to air pollution.
• Otto Cycle Engine (Ref. 9-12)
• HC; There are no hydrocarbon emissions for NH-
fuel.
• CO; There are no carbon monoxide emissions from
NH3 fuel.
• NOX; The nitric oxide emissions for NH3 are
3. 8 times those of HC fuel at maximum power
output. At maximum economy, the NH3 emissions
are 1. 5 times those of HC fuel.
• NH3: (No data)
9-12
-------
• Gas Turbine Engine (No data)
• Diesel Engine (No data)
9.2.3 Fuel Economy
• Otto Cycle Engine. Specific Fuel Consumption (SFC) for NH3
is approximately 2.4 times that of hydrocarbon fuel at maxi-
mum economy.
• Gas Turbine Engine. The SFC for ammonia is predicted to
exceed that of hydrocarbon fuels by 2. 5 to 3 times.
• Diesel Engines. The SFC for NH3 is about 2.4 times that of
diesel fuel over wide operating ranges of fuel-air ratios and
compression ratios.
9.2.4 Toxicity Effects
The physiological effects of ammonia are directly traceable to
its ability to produce local severe irritation of tissues (Ref. 9-13). Ammonia
is extremely irritating and highly corrosive to the eyes and respiratory tract.
Suffocation and death from pulmonary edema can result from exposure to high
concentrations. The threshold limit value for ammonia is 50 ppm, the same
as for carbon monoxide. Thus, ammonia is highly toxic. The irritant prop-
erties and pungent odor give adequate warning so that toxic exposures are not
voluntarily permitted. Up to 500 ppm in air may be tolerated for an hour.
Irritation of mucous membranes of the eyes, nose, and throat have been re-
ported at 400 to 700 ppm. Exposures of 2500 to 6500 ppm have been judged
dangerous for 0. 5 hour, and 5000 ppm and above is believed to be rapidly
fatal. High concentrations of ammonia in addition to the corrosive action on
eyes, throat and respiratory tract may also reflectively affect heart and
respiratory action. Moist atmospheres containing a 1 percent or more am-
monia may cause increasing amounts of skin irritation including chemical
burns with blistering. There is no evidence of cumulative or chronic toxic
effects following prolonged or repeated exposures to tolerable atmospheric
concentrations.
9-13
-------
9.2.5 Safety Effects
Ammonia is very stable and not shock sensitive. The
flammability range in air (1 6 to 27 percent by volume) is at higher concen-
trations than for gasoline, but large anhydrous ammonia spills present a
fire hazard. Ammonia fires have proved very difficult to extinguish; water
fog in large quantities is required.
9. 2. 6 Handling, Storage and Distribution Requirements
Based on fuel consumption for ammonia of 2. 4 times that for
gasoline, it would take 284 pounds of stored ammonia to equal 20 gallons of
gasoline (119 pounds for gasoline). The NH, volume required is 7. 16 cubic
feet (versus 2. 59 cubic feet of gasoline) or a volume ratio of 2. 8 times. The
weight of NH, plus a250-psi tank is 445 pounds (versus 134 pounds for gasoline
and tank) or a total weight ratio of 3.4 times (Ref. 9-13).
Based on current NH, storage and handling practices (Ref. 9^14),
the automobile storage tank should be designed for a working pressure of
250 psia and be equipped with two relief valves. The current practices of
venting to a stack which discharges at least 6 feet above any surrounding
platform or work area and that of providing ventilation to avoid pocketing of
ammonia under roofs, implies a requirement for an automobile to carry some
form of closed capture system for containing ammonia venting. Based on
current practice a closed two-line pressure differential system appears to be
required for filling the automobile storage tank. The fuel transfer system in
the vehicle will have to be a closed and pressurized system.
9.2.7 Critical Research Gaps
• Otto Cycle Engine
• NOy Emissions; The NOX emissions measured are
higher than those predicted from equilibrium calcula-
tions. Knowledge as to the NO formation mechanisms
is needed.
9-14
-------
• NH3 Emissions: The literature does not indicate any
measurements of NH3 in the engine exhaust. Since
this represents a new pollution problem, such data
are needed.
• Gas Turbine Engine. Experimental data appear to be needed
to verify power output, thermal efficiencies, and specific fuel
consumption, and to investigate improvement of combustion
stability (e.g., effects of NH3 dissociation) and quantification
of exhaust products.
• Diesel Engine. Experimental data for quantification of exhaust
products using NH3 fuel appear to be needed as do data for
optimizing ignition. However, NH3 does not appear to be a
practical fuel for this type of engine.
9.3 CURRENT STATUS
9.3.1 Production Rates
The 1971 U.S. annual production rate of synthetic anhydrous
ammonia was 13 million tons (Ref. 9-15). Almost all of this was used for
fertilizer materials. A relatively small amount is converted into nitric
acid for other purposes. Per Reference 2-1, to drive equal distances in a
conventional piston engine automobile requires on the average 2. 35 times as
much ammonia by weight as gasoline. As of March 1973, the daily average
production of automotive gasoline at U.S. refineries was 6. 128 million
barrels per day (Ref. 9-16), which is equivalent to approximately 365 mil-
ion tons per year. By using the factor of 2.35 to convert to ammonia usage,
this would then require 860 million tons of ammonia or 66 times the current
annual production rate.
9.3.2 Consumer Costs
A 1, 000-ton-per-day plant on the U. S. Gulf coast using naphtha
as feedstock, required a $23 million capital investment and now produces am-
monia at $48. 39 per ton (Ref. 9-16), which is equivalent to $0. 123 per gallon
of ammonia (f.o.b. plant) or $3.03 per million Btu. The estimated production
cost using electrolytic hydrogen is $6. 25 per million Btu, to which a distri-
bution cost of $1.40 per million Btu must be added (Ref. 2-1). Thus, ammo-
nia offers no economic advantage compared to alternative hydrocarbon or
methanol fuels.
9-15
-------
9.4 PROJECTED STATUS
9.4.1 Availability
The projected availability of ammonia is dependent on the raw
materials used for its manufacture. Coal gasification or oil shale conver-
sion to gas using humidified oxygen followed by hydrogen-nitrogen catalyzation
are possible candidate processes for producing ammonia. For electrolysis
of water, nuclear-derived electric power to electrolyze the water and to
liquify air is the primary candidate.
9.4.1.1 Ammonia from Coal
The domestic consumption of coal in 1970 was 517 million tons
(Ref. 9-17). Based on Table 9-1, 1. 8 tons of coal are required to produce
one ton of ammonia. In order to produce 860 million tons per year of ammonia
to replace current gasoline usage for automotive use, an annual total of
1, 550 million tons of coal would be required. This is approximately triple
the current coal consumption and would require a total annual coal consump-
tion in excess of 2 billion tons based on 1970 consumption rates. Although
this consumption rate indicates that depletion of coal would be relatively
slow, it must be considered that energy demands are consistently increasing.
Reference 9-4 states that 50 percent of the world coal reserves will be de-
pleted by the years 2030 to 2070, with nearer-term depletion if coal is used
to manufacture synthetic fuel. Nevertheless, ammonia from coal shows a
relatively good near-term availability.
9.4.1.2 Ammonia by Water Electrolysis
The use of nuclear-derived electrical power for water elec-
trolysis to produce ammonia is claimed to be the most realistic method using
present technology (Ref. 9-4). The availability of energy from uranium using
18
conventional reactors has been estimated at 12,000 x 10 Btu (Ref. 9-18)
18
which is equivalent to 3. 5 x 10 kW-hr. This figure can probably be expanded
by more than a magnitude if fast breeder reactors are developed. Other
9-16
-------
methods of utilizing nuclear energy to produce HZ have been studied: (1)
thermal decomposition of water at high temperature, (2) radiolytic decomposi-
tion of water by fission fragments, (3) heat input to a multistep chemical
process.
The production of 860 million annual tons of ammonia by
water electrolysis would require 6. 65 x 10 12 kW-hr annually which is equiv-
alent to an installed capacity of 7.7 x 10 megawatts. This can be compared
with 1973 U.S. electrical energy installed capacity from all fuels of ~3 x 10
megawatts, using 1. 33 x 10 kW-hr annually as interpolated from data in
Reference 9-18. An electrical energy capacity expansion of more than double
the 1973 capacity and a consumption rate of approximately five times that in
1973 would therefore be required to meet the annual demand of ammonia to
replace 1973 gasoline usage. It appears that the availability of uranium using
conventional reactors could satisfy this demand for long periods. It must,
however, be kept in mind that electrical energy consumption due to other
demands is predicted to triple by the year 2000.
The consumption of water to produce 860 million annual tons
of ammonia is estimated at 1. 38 billion annual tons of distilled or deminer-
alized water to produce hydrogen. In addition to this amount consumed,
73 billion annual tons of cooling water in excess of this amount would be re-
quired for the electrolysis process. Additional cooling water would be re-
quired for nuclear reactors and electrical power plants to generate the
1 ?
6. 65 x 10 kW-hr. Based on data extrapolated from Reference 9-18, it is
estimated that these facilities would require 1, 520 billion tons per year of
cooling water for an assumed 12°F temperature rise. Makeup water require-
ments are normally 4 percent of the total cooling water flow with evaporation
accounting for 1 to 1-1/2 percent and blowdown for 2 to 3 percent (Ref. 9-18).
For an assumed evaporation loss of 1-1/4 percent, the evaporation consump-
tion would then be ~19 billion tons per year, and the total makeup withdrawal
would be approximately sixty billion tons per year. This compares with a
1970 U.S. consumption of 134 billion tons per year and withdrawals of 565 bil-
lion tons per year. It can be noted that cooling water is a critical raw material
9-17
-------
to produce ammonia by electrolysis unless sea water or considerably more
expensive air cooling methods are used.
9.4.2 Capital Costs
9.4.2.1 Ammonia from Coal
The capital costs for producing ammonia by coal gasification
would exceed $54 billion estimated for ammonia produced from naphtha, since
coal gasification plants would be required. A 250 million cubic feet per day
plant by El Paso Natural Gas will cost $250 million (Ref. 9-19). Assuming a
35 percent hydrogen content gas, this type of plant would produce 87 million
cubic feet per day of hydrogen or 83, 000 tons annually. It is estimated that
860 million tons of ammonia would require 152 million tons of hydrogen or
1,800 such plants for a total cost of $450 billion. For larger plants produc-
ing approximately 3, 000 tons of ammonia per day each, it is estimated that
this cost could be reduced to $300 billion (Ref. 9-20). To this cost would
have to be added the capital investment to produce 960 million tons of oxygen
for the oxygen blasting of the coal and the nitrogen required for ammonia
synthesis. It can be noted that the capital cost of ammonia by coal gasifica-
tion would be approximately a magnitude higher than by conventional processes.
9.4.2.2 Ammonia by Water Electrolysis
The capital cost of the installed electrical capacity of 7. 7 X 10
megawatts is estimated at $230 billion based on $300 million per 1,000 mega-
watts (Ref. 9-18). The capital cost of the total process will probably be higher
by more than a magnitude than the more conventional means of ammonia pro-
duction from natural gas or naphtha feedstocks.
9.4.3 Summary
Since coal gasification and water electrolysis, particularly the
latter, are the major candidates for ammonia production in the future, the
capital investment to produce ammonia by these means appears extremely
high when compared to conventional processes. Reference 9-21 concluded
9-18
-------
that ammonia could be produced competitively via electrolysis with the
conventional process of natural gas or naphtha conversion. However, this
study assumed that electrical power would be provided by external sources
and did not include the tremendous capital investment for new electrical
power sources to produce ammonia in the amounts required to meet national
transportation needs. In view of the many other problems associated with
ammonia usage, it does not appear to be a promising alternative fuel.
9-19
-------
SECTION 10
-------
SECTION 10
HYDRAZINE
10. 1 CHARAC TERIZATION
Hydrazine (N H ) is a clear, colorless, hygroscopic liquid
with an odor similar to that of ammonia. Hydrazine was first produced in
the laboratory in 1887. Early use of hydrazine was in sugar chemistry,
giving cystalline, easily recognizable derivatives. Today, hydrazine deriva-
tives are used in the plastic industry, in the pharmaceutical industry and
predominantly as fuel for rocket propulsion.
10.1.1 Fuel Type
Hydrazine is a strong reducing agent and will also react with
carbon dioxide or air. When exposed to air on large surfaces, such as rags,
hydrazine may ignite spontaneously, due to evolution of heat caused by oxida-
tion with atmospheric oxygen. A film of hydrazine in contact with metallic
oxides and other reducing agents may ignite.
Until hydrazine was used as a rocket fuel by the Germans in
World War II, it had remained in the laboratory as a curiosity. Hydrazine
is of great interest now as a storable propellant for rockets; in combination
with a strong oxidizing agent, it is one of the highest performing chemical
fuels.
10.1.2 Methods of Manufacture
The Raschig process and the urea process are closely related
to those currently used commercially for the manufacture of hydrazine.
10-1
-------
In the Raschig process, the synthesis of hydrazine from
ammonia and sodium hypochlorite takes place in the following steps: Ini-
tially, chloramine is formed from ammonia and sodium hypochlorite:
hydrazine:
+ NaOCl— NH2C1 + NaOH
Then, the chloramine reacts with excess ammonia to form
NH Cl + NH + NaOH— —NH NH + NaCl + HO
Ct J Lt C* L*
The formation of chloramine is rapid, whereas the reaction
of chloramine with ammonia is slow and rate -determining, requiring heat.
Hydrazine, a strong reducing agent, is sensitive to a variety
of oxidizing agents, particularly in the presence of metal ions. Oxidizing
agents, such as chloramine, dichloramine, nitrogen trichloride, and sodium
chlorate, are present in varying amounts in the reaction liquor during the
formation of hydrazine. Thus, as the formation of hydrazine proceeds,
chloramine may oxidize or react with hydrazine to form ammonium chloride
and nitrogen.
NH_NH, + 2 NH,C1— -2NH .Cl + N,
22 2 42
The rate of formation of hydrazine increases with the tempera-
ture, but the rate of decomposition is essentially independent of the tempera-
ture. Thus, it is best to run the reaction at high temperatures. At about
130 C rapid conversion of chloramine to hydrazine is ensured and, by using
a large excess of ammonia (20:1 to 30:1) to react with any chloramine that is
formed, the decomposition of hydrazine by chloramine is kept at a minimum.
Raschig' s "catalysts" increase the yield of hydrazine by complexing the metal-
ion impurities that catalyze the decomposition of hydrazine by chloramine. A
schematic of the Raschig process is shown in Figure 10-1.
10-2
-------
ANHYDROUS AMMONIA
o
I
(JO
AMMONIA
COMPRESSOR
CAUSTIC SODA
CHLORINE
STORAGE
TANK
AMMONIA
HYDRAZINE
SODIUM
HYPO-
CHLORITE
CHLORAMINE
REACTOR
HYDRAZINE
REACTOR
CONDENSATE
NITROGEN + AMMONIA
TO SCRUBBING TOWER
AMMONIA RECOVERY
COLUMNS '
HYDRAZINE NaCI, WATER
CHLORINATION
REACTOR
HYDRATE
COLUMNS
rW
1
r*
FILTER I ^T
I K^TH-J
I • I ^'CRYSTAL i ZING
^ EVAPORATOR
SALT
WATER
HYDRATE
STORAGE
-D
HYDRAZINE
HYDRATE
ANILINE
RECYCLE
HYDRAZINE
COLUMN
(DECANTER)
\ i I /
AZEOTROPE . WATFB
COLUMN T WATER
ANHYDROUS
HYDRAZINE
Figure 10-1. Manufacture of Hydrazine by the Raschig Process
(Ref. 10-1)
-------
The degradation of urea by sodium hypochlorite forms the
basis of this process for the production of hydrazine.
O
NH2CNH2 + NaOCl + 2 NaOH—NH2NH2 + Nad + Na2CC>3 + H^O
In the urea process, a cold solution of urea and sodium hydroxide is added to
a cold solution of sodium hypochlorite. The heat of reaction increases the
temperature to 100° C, where the reaction takes place rapidly. As in the
Raschig process, various proteins are usually added to prevent the decom-
position of hydrazine.
A 43-percent solution of urea is prepared by dissolving urea
in water while steam is passed through the solution to maintain the tempera-
ture at about 5° C, since the dissolution is strongly endothermic. A 30 per-
cent solution of sodium hydroxide is chlorinated until it has an available
chlorine content of 140 to 155 grams per liter and a residual sodium hydroxide
content of 170 to 190 grams per liter.
These solutions (four volumes of sodium hypochlorite-sodium
hydroxide to one volume of urea solution with 500 mg of glue per liter) are
fed continuously to the reactor where the temperature is allowed to rise to
100°C. The reaction liquor contains approximately 35 grams of hydrazine
per liter of solution; a schematic for the urea process is shown in
Figure 10-2.
10. 1.3 Physical and Chemical Properties
Anhydrous hydrazine is a strong reducing agent and a weak
chemical base. Aqueous hydrazine shows both oxidizing and reducing prop-
erties. Although data show hydrazine to be a powerful oxidizing agent in
acidic solutions, reactions with many reducing agents are so slow that only
the most powerful ones reduce it quantitatively to ammonia ion. Hydrazine
is an endothermic compound and will decompose spontaneously in a way
10-4
-------
o
i
Ul
CAUSTIC
SODA
CHLORINE
CHLORINATION
REACTOR
SULFURIC
ACID
VENT
CRYSTALLIZER
VENT
1
GAS SEPARATOR
HYDRAZINE
REACTOR
•s—i
SYNTHESIS LIQUOR
^CENTRIFUGE
HYDRAZINE
MONOSULFATE
DRYER
HYDRAZINE
MONOSULFATE
(NH2NH2-H2SO4)
LIQUOR
TO WASTE
Figure 10-2. Manufacture of Hydrazine by the Urea
Process (Ref. 10- i)
-------
similar to hydrogen peroxide. It is incompatible with many metals, plastics,
and lubricants. The reaction of hydrazine with the oxide of copper, manganese,
iron, silver, mercury, molybdenum, lead or chromium may be particularly
violent.
Hydrazine has a molecular weight of 32. 04. It freezes at
34. 7°F and boils at 236. 3°F. Its density is 8. 482 pounds per gallon at 77°F.
The heat of combustion with air is 8, 346 Btu per pound at 77 F. Flamma-
bility limits in air at 68 F and one atmosphere is 4. 7 percent lower and
100 percent upper by volume.
10. 2 SUITABILITY FOR USE AS AN ENGINE FUEL
10.2.1 Engine/Vehicle Compatibility
No data are available. Hydrazine has heretofore not been
seriously considered as an automotive fuel, although it could find application
in fuel cells for electric vehicles.
10.2.2 Toxicity Effects
Anhydrous or aqueous solutions of hydrazine are toxic by
ingestion, inhalation of vapors, or contact with the skin. The maximum
allowable concentration of one ppm has been established by the American Con-
ference of Governmental Hygienists. The maximum tolerable concentration
in air breathed for no more than 10 minutes is suggested as 10 ppm. Hydra-
zine produces local irritating effects upon the eyes and respiratory tract.
Inhalation causes dizziness, nausea, and possibly death. Repeated or chronic
exposure causes damage to the liver. Hydrazine salts produce hyperglycema.
Symptoms resulting from exposure to hydrazine include itching of the eyes
and a slight swelling initially and conjunctivitis after about a day. Although
hydrazine has a readily detectable ammoniacal odor, smell should not be
relied on as a warning of excessive concentration because, on contact with
vapors, membranes of the nose desensitize rapidly. Contact of hydrazine
with any body tissue will produce a caustic-like burn if not washed off
immediately.
10-6
-------
10.2.3 Safety Effects
10.2.3.1 Fire Hazard
Liquid anhydrous hydrazine is very stable and nonexplosive.
In the absence of decomposition catalysts, it has been heated above 500°F
with very little decomposition. Hydrazine vapors, however, can present a
hazard. Mixtures of hydrazine vapor in air are flammable between the
limits of 4. 7 percent and 100 percent hydrazine by volume. Since liquid
hydrazine at 40 C (104°F) exerts sufficient vapor pressure to support a 4. 7
percent hydrazine-in-air mixture, it is possible for flammable mixtures to
form at any temperature above 40°C. It is hypergolic with some oxidants
such as hydrogen peroxide, fuming nitric acid, and nitrogen tetroxide.
Water solutions at any concentration below 40 percent cannot be ignited.
10.2.3.2 Explosion Hazards
Hydrazine is' an endothermic compound and may, therefore,
be expected to undergo decomposition under appropriate conditions with the
release of considerable energy. This property leads to hydrazine's usage
as a monopropellant for rocket propulsion and power systems. The reaction
of hydrazine catalyzed by metallic oxides may be violent and may cause an
explosion or fire. Hydrazine is not sensitive to impact or friction but the
vapors can be detonated by a spark; the vapor propogates detonation within the
flammability limits. It is, therefore, not advisable to maintain a large quantity
of vapor near or at the boiling point for any length of time.
10.2.4 Handling, Storage, and Distribution Requirements
Mild steel is incompatible with hydrazine because of the
presence of oxides; only certain grades of stainless steel can be used. Con-
ventional stainless steel fuel tank designs are quite adequate for unlimited
service application. Pumps with stainless steel bodies and Teflon packing
are suitable. Some aluminum alloys and titanium are also satisfactory.
Some oils used for lubrication are compatible with hydrazine.
Special care must be taken in design of all flow systems to exclude stagna-
tion zones in which heat may be present. Such zones may cause local
decomposition of hydrazine and may lead to explosion.
10-7
-------
Fuel transfer can be accomplished through stainless
steel lines by low-pressure inert gas or by gravity feed. Plenty of water
should be available to flush away any spillage.
Hydrazine should not be handled in facilities with wooden
flooring, as spillage may cause the wood to ignite. Rags, paper, and
other common organic materials should not be used around hydrazine since
they may also ignite.
10.2.5 Critical Research Gaps
Since the freezing point of hydrazine is relatively high (34. 5°F),
it is not practical for use with automobiles operating in colder climates. Its
freezing point may be lowered to a more suitable level by additives, but
these additives should not change other properties of hydrazine. However,
hydrazine is too toxic and dangerous to handle unless diluted with water. In
this form it is ideal fuel for fuel cells but not for internal combustion engines.
Experimental work is required to determine its suitability for use with the
external combustion engine.
10.3 CURRENT STATUS
10.3. 1 Production Rates
Both the Raschig and urea processes are used at present for
the production of hydrazine.
Table 10-1 shows the producers of hydrazine and their pro-
duction capacities.
10.3.2 Uses
Examples of the use of hydrazine and its derivatives follows:
• As a reducing agent for scavenging oxygen from boiler
water to prevent corrosion of boilers
• As a reactive chemical in the reclaiming of platinum and
copper catalyst
10-8
-------
• As an unstable species, tetracene, an ignitor for
explosives
• As physiologically active compounds for plant growth
regulators, herbicides, and drugs
• As a source of energy in rocket propulsion.
The greatest consumption of hydrazine in the United States is
for rocket fuel by the aerospace industry and related government facilities.
Table 10-1. Producers of Hydrazine (Ref. 10-1)
Country
United States
England
West Germany
France
Spain
Japan
Producer
Olin Mathieson Chemical Corp.
Fairmount Chemical Co., Inc.
U.S. Rubber Co., Naugatuck
Chemical Div.
National Polychemicals, Inc.
Whiffen & Sons, Ltd.C
Farbenfabriken Bayer, A.G.
Monopole des Poudres
Societe des Produits d'Azotes
Quimica Sintetica
Hikari Chemical Industries Co., Ltd.
Japan Hydrazine Co.
Otsuka Chemical Co.
Location
Virginia
Louisiana
New Jersey
New Jersey
Louisiana
Massachusetts
Loughbo rough
Widnes
Leverkusen
Toulouse
Lannemezan
Madrid
Ohmiya City
Tokyo
Osaka
Process
Raschig
Raschig
urea
Raschig
Raschig
urea
Raschig
Raschig
Capacity,
million
Ib/year
16
2
0.6
1. 5
2
0.3
2
2
4
0.6
0.6
0. 1
1
1
2.5
aBased on anhydrous hydrazine.
bU.S. Government-owned plant, operated by Olin Mathieson Chemical Corp.
A division of Fisons, Ltd.
10-9
-------
10.3.3 Consumer Cost
Anhydrous hydrazine is now being delivered to the U.S. Air
Force under contract at a cost of $1.23/lb. It is anticipated that the cost
of hydrazine may be lowered to $0.75/lb. in large tonnage production
(Ref. 10-2). These costs are an order of magnitude higher than those for
gasoline-powered automobiles when compared on a utilization per mile basis.
10. 4 PROJECTED STATUS
The projected availability of hydrazine is dependent upon
availability of the raw materials for its manufacture. In this case, the
basic raw material is hydrogen, which is used to produce ammonia, which
is then synthesized to hydrazine.
Hydrogen production from natural gas feedstock appears in
short supply in the years ahead. Alternative hydrocarbon supply sources,
such as propane and butane, also appear limited.
Hydrogen production from coal is technically feasible but
not economically attractive compared to SNG or liquid hydrocarbon fuels
from coal. Water electrolysis offers the most promise as a source of
large-scale hydrogen production. However, problems with supplying
adequate electrical power are involved in such an approach (see Section
9.4. 1.2).
Capital costs for hydrazine production facilities would
certainly be more than for hydrogen or ammonia plants, since these liquids
are merely feedstocks for the formulation of hydrazine.
The hazards to health and safety may be a factor that could
inhibit the use of hydrazine as an automotive fuel. The cost of producing
hydrazine, which is an additive to the cost of producing its raw materials,
is another deterrent.
The many deficiencies of hydrazine fuel in application to
automobile heat engines lead to the conclusion that it is unsuitable as an
alternative to petroleum-based fuels, particularly for near-term use.
10-10
-------
SECTION 11
-------
11. FUELS REFORMED ON-BOARD THE VEHICLE
Operation of gasoline-fueled spark ignition internal combustion
engines at lean air-fuel ratios [i.e. , air-fuel ratios greater than stoichiometric
(or 15:1)] can result in the reduction of exhaust emissions without the addi-
tion of emission control devices, as illustrated in Figure 11-1. As can be
noted from the figure, at the stoichiometric air-fuel ratio, NOX production is
very high while HC and CO production is relatively low. For air-fuel ratios
between approximately 17 and 19, levels for all three constituents are reduced
considerably from peak values. Currently, gasoline engines are normally
operated as air-fuel ratios below approximately 17 to avoid rough engine
operation which occurs as the lean limit of gasoline-air combustion is
approached. This inherent lean limit then prevents the achievement of
lowered NO emissions which occur at still leaner mixtures.
x
One approach that is being investigated as a means of extend-
ing the lean operating limits of gasoline engines for the control of NO is the
!X
incorporation of a fuel-reformer unit between the gasoline tank and the car-
buretor of the gasoline engine-powered conventional automobile. The fuel
reformer device is a unit that converts all or a portion of the engine's fuel
requirements from gasoline (or other liquid hydrocarbon fuel) to a gaseous
product prior to induction into the engine. This gaseous reformed fuel is
principally hydrogen and carbon monoxide. The hydrogen, with its wide
flammability limits, enables operation of the engine at much leaner mixtures
than are obtainable with gasoline only.
Another attribute of lean operation is an increase in engine
thermal efficiency resulting from inherent characteristics of the thermo-
dynamics of the air cycle. Unless other system inefficiencies (e.g., fuel
reformer losses) or deleterious effects are introduced, increased thermal
efficiency should result in improved vehicle fuel economy (miles per gallon).
There are, however, several disadvantageous consequences
to lean operation. Chief among these is the reduced specific power output of
11-1
-------
o _
o
o
^
o
o
to
LJ
UJ
111
Of
STOICHIOMETRIC
14 16 18
AIR-FUEL RATIO
Figure 11-1. Effect of Air-Fuel Ratio on Emission Levels
(Gasoline Spark Ignition Engine)
11-2
-------
the engine, which would necessitate the use of a larger-displacement engine
for the same maximum power output. Also, in the case where a reformer is
used to facilitate lean operation, the reformer products, being gaseous in
nature and at elevated temperature, can reduce engine volumetric efficiency
and still further reduce specific power output. Another deleterious effect, as
can be noted from Figure 11-1, is that HC emissions rise as air-fuel ratio
is increased to reduce NOX emissions.
Thus, the potential for achieving reduced NO emissions and
improved fuel economy must be balanced against reduced specific power output,
possible HC increases, and increased system configurational and operational
complexities when evaluating the relative merit of concepts for reforming
fuel on-board the vehicle to permit lean operation.
The following sections discuss and summarize the character-
istics of a number of specific fuel reformer devices and the available data
concerning emissions, fuel economy, and other system operational features.
Also included are the results of recent General Motors tests with hydrogen-
supplemented gasoline fuel. These tests simulate to a first order engine
operation with reformer products and are, therefore, included to summarize
data relevant to the reformed fuel concept.
Although this volume of the report is principally directed to
alternative fuels, the interrelationship of the fuel reformer and the engine
makes it necessary to discuss engine-related items and characteristics
in order to adequately treat the reformed fuel concept.
11. 1 CHARACTERIZATION
11. 1. 1 Fuel Type
Fuels reformed on-board vehicles are gaseous fuels result-
ing from thermal decomposition or catalytic cracking of liquid hydro-
carbon fuel stored on-board the vehicle in a conventional manner, i. e. ,
in the normal gasoline tank. These gaseous reformed fuels result from the
passage of the stored liquid hydrocarbon fuel through a fuel reformer device
(or gas generator) just prior to the introduction of the reformed fuel into the
11-3
-------
air induction and mixing system of the heat engine. The principal constituents
of the gaseous reformed fuel are hydrogen (H2) and carbon monoxide (CO),
although water vapor, carbon dioxide (CO ), nitrogen (N7), methane (CH.),
L, £• 4
and other hydrocarbons may also be present, depending upon the specific
reformer device used and its principle of operation (discussed further in
Section 11.1.3).
11.1.2 Reserves or Raw Material Sources
In general, reformed fuels may be processed from a variety
of liquid hydrocarbon fuels including: gasoline, kerosene, jet fuel, diesel
fuel, home heating oil, heptane, hexane, LPG, etc. Specific reformer
devices or systems, however, may be designed to operate on a single
grade of hydrocarbon fuel or in a more limited range of hydrocarbon
fuel choices.
Thus, reformed fuels are in turn limited by the reserves
and/or raw material sources for conventional petroleum or nonpetroleum
hydrocarbon liquids as set forth previously in Sections 3, 4, and 7.
11. 1.3 Methods of Manufacture (Fuel Reformer Concepts)
All of the variously proposed hydrocarbon fuel reformers (or
gas generators) for mobile vehicle use have their roots in stationary petro-
leum gasification processes developed for production of hydrogen by steam
reformation, principally the partial oxidation and the catalytic reformation
processes. Versions of partial oxidation gasification have been developed
principally by Texaco, Shell, Exxon, and Lurgi. Catalytic reformation
processing has been developed by M. W. Kellogg, Foster- Wheeler, Mobil,
Exxon, and many others.
Hydrogen is produced by steam reformation of gasoline accord-
ing to well-known refinery technology and the following ideal summary reaction
equation (for isooctane) (Ref. 11-1):
CgH18 + 8H20 — SCO + 17H2 (11-1)
11-4
-------
In the non-ideal case, however, lower reformation conversion efficiencies
and the specifics of the particular process used introduce other process
products. To illustrate one such effect, consider the conversion of isooctane
at 1450 R. At 1450°R the equilibrium conversion of the hydrocarbon to
reformer products is about 70 percent. The steam reforming action in this
case would be (Ref. 11-2):
C8H18 + 8H2° ~* 5-6c° + U-9H2 + 0.3CgH18 (11-2)
+ 2.4H20
thus reducing CO and H~ quantities in the product gases and introducing steam
and residual hydrocarbons.
Further, partial oxidation systems consume oxygen, either as
a pure gas or from air; to provide the endothermic heat (via combustion) for
gasification. In this process, part of the fuel feedstock is combusted with
the oxygen or air within the reformation chamber. The alternative use of
air for combustion in these processes produces a yield gas heavily diluted by
nitrogen. Also, stationary installations incorporating partial oxidation
processes fail to gasify the feedstock completely, producing an effluent by-
product of aromatics, tars, and coke or soot.
Catalytic steam reformation has been successfully applied to
methane, propane, condensate.and naphtha, yielding a high quality synthesis
gas mixture containing 60 percent hydrogen or more (by volume). Such
processing involves a steam-hydrocarbon reaction within a heated process
tube which is packed with a granular catalytic bed to promote the reaction.
The heat is supplied by heat exchange with an external heat source, thus no
air or oxygen is required for combustion in the process chamber, as is
required in the partial oxidation process. Since no air is used in the process,
the yield gas is not diluted with nitrogen. This process has a high thermal
efficiency in conversion (typically 85 to 95 percent as compared to 67 percent
for stationary partial oxidation installations) and does not have soot and tars
in its gas product.
11-5
-------
For mobile vehicle use, a number of different hydrogen gas
generator (or fuel reformer) concepts have been proposed. Those concepts
sufficiently disclosed are separately discussed in the following sections.
Their developmental activities are exploratory in nature and none has yet
resulted in on-the-road vehicle tests with an on-board fuel reformer.
11.1.3.1 International Materials Corporation Concept
In 1971 the International Materials Corporation disclosed by
patent (Ref. 11-3) and SAE paper (Ref. 11-4) the principles of an on-board
hydrogen gas generating system. Briefly, it is a system which mixes a
liquid hydrocarbon fuel with water and heats the mixture sufficiently to cause
thermal decomposition resulting in hydrogen gas which is fed to an internal
combustion engine. Water from the engine exhaust is recycled for mix-
ing with the hydrocarbon fuel. To date, effort has been limited to exploratory
development of the reformer unit only. The following description of the system
and its operation is abstracted from Reference 11-4.
*
11.1.3.1.1 Brief Description of the Reformed Fuel System
Water is condensed from the engine exhaust by muffler heat ex-
changers; this water, as shown in Figure 11-3 and 11-4 is pumped in excess
of the chosen system pressure of approximately 800 psi through a metering
orifice to a vaporization chamber. The steam is then led through an initial
length of coil to provide superheating to near 1, 000°C, at which point gasoline
is injected through a metering orifice at the same pressure. The length of
the lead-in tubing is sufficient to vaporize the gasoline, with its lower specific
heat. In the next downstream region of coil reactions, the primary production
of CO and H^ is completed. A second injection of low-temperature steam
follows for a quenching effect, and the CO shift occurs in the low-temperature
region. The product gases are then led from the canister, through suitable
*
Component location is shown in Fig. 11-2.
11-6
-------
HEAT
EXCHANGE
MUFFLER
ENGINE
CARBURETOR
REFORMED FUEL
STORAGE!
i I
GAS AND WATER
PUMP
WATER
BALLAST
BULKHEAD
/ ^REFORMED"
FUEL UNIT
TRUNK
Figure 11-2. Component Location, International
Materials Concept (Ref. 11-4)
11-7
-------
GASOLINE
TANK
1
00
REFORMER
2
n
AIR
REFORMED
FUEL STORAGE
3
t
i
AIR
INTERNAL
COMBUSTION
ENGINE
4
WATER
BALLAST
6
WATER RETURN
HEAT
EXCHANGE
5
EXHAUST
2 + H2
CO + H0
Figure 11-3.
Block Diagram, International
Materials Concept (Ref. 11-4)
-------
t
vO
IGNITION
CO PRIMARY STEAM
SHIFT-| REACTION [-SUPER HEAT
GASOLINE
EXHAUST
HEAT EXCHANGER
SKIN
COOLING AIR
EXHAUST
/ I < i i i r i A
w ., rn i OUTPUT
H2 + C02 |H^ + co
AIR
BLOWER
CARBON
CANISTER
METAL
CANISTER
Figure 11-4. Reformer Canister Cross Section, International
Materials Concept (Ref. 11-4)
-------
heat recovering structures. The reformed fuel is then directed to a small
storage tank that services the engine. This tank is the source of reformed
fuel when the engine is started with the reformer cold. A pressure switch
detects depletion of tank pressure, causing the reformer to begin replenishing
the tank. This fuel storage also serves as the source of combustion energy
for the reformation process. Theoretical efficiencies of the reformer are
approximately 59.7 percent without heat exchange. Efficient heat exchange
(that is, exhaust temperature below 260°C) indicate efficiencies in the range
of 86 to 87 percent.
11.1.3.2 Phillips Petroleum Company Concept
In 1973 the Phillips Petroleum Company (Ref. 11-2) disclosed
by patent (as assignee) a method and apparatus for passing exhaust gases
from an engine through a fuel regenerator in indirect heat exchange with fuel
and steam in contact with a catalytic bed for steam reforming the fuel. The
system is illustrated in Figure 11-5, and the following description of system
operation is abstracted from Ref. 11-2.
1 1.1 .3.2.1 Operational Features
In this concept, a hydrocarbon liquid fuel such as diesel fuel,
gasoline, jet fuel, kerosene, or liquefied petroleum gas is initially delivered
from the fuel reservoir to the fuel injector for injection into the engine. The
engine is operated until the temperature of the exhaust from the combustion
chamber of the engine increases to a sufficient level.
Fuel and water are then metered into the inner chamber of the
fuel regenerator tube (by proportioning pumps) and contacted with the catalyst
bed of the inner chamber in indirect heat exchange with exhaust gases
discharging from the engine and passing through the outer chamber of the fuel
regenerator tube. Ordinarily, a ratio of water to hydrocarbon weight of about
1. 2 or higher is satisfactory. The pressure within the inner chamber of the
fuel regenerator is maintained at a preselected pressure during injection of
fuel and water by a pressure regulator.
11-10
-------
INJECTOR
WATER
RESERVOIR
FUEL
RESERVOIR
-PROPORTIONING
PUMPS
HEAT
-EXCHANGER
INNER CATALYST BED CHAMBER
OUTER CHAMBER
FUEL REGENERATOR TUBE
ENGINE EXHAUST
Figure 11-5. Fuel Reformer Concept, Phillips Petroleum Company
(from Ref. 11-2) ^ '
-------
The fuel and water mixture is maintained in contact with the
catalytic bed until the mixture is heated to a temperature sufficient for
reforming the fuel mixture in the presence of the catalyst and producing a
gaseous fuel. The gaseous fuel is delivered to the engines fuel injector and
mixed with air; the resultant mixture is injected into the engine and combus-
ted.
The temperature of the exhaust gases passing through the fuel
regenerator adjacent the catalytic bed should be at least 950 °F before the
fuel and water is injected into the catalyst bed.
To reduce the pollutants discharging from the engine during
operation thereof, the reformed fuel should be produced at a rate such that
delivery of the reformed fuel to the engine is sufficient to operate the engine
at the desired speed and load, and delivery of the liquid fuel to the engine
can be terminated.
11.1.3.3 Jet Propulsion Laboratory Concept
In October, 1973, the Jet Propulsion Laboratory (JPL) of the
California Institute of Technology disclosed a concept for improving the
emissions and fuel economy of conventional spark ignition engines (Ref. 11-1).
Basically, the concept is to blend small amounts of hydrogen
with gasoline in a carburetor to allow combustion to proceed at ultra-lean
conditions. As shown in Figure 11-6 a gaseous mixture (largely hydrogen)
is generated on-board the vehicle by feeding gasoline and air to a hydrogen
generator. The generated gas is mixed with gasoline and fed to a conven-
tional engine. The required hydrogen is produced in the generator, and no
hydrogen is stored on-board the vehicle.
The most critical element in development of this system is the
hydrogen generator. The design chosen is similar to that used for commercial
Previously water was also fed to the hydrogen generator, but recent generator
developments allow elimination of the water feed (Ref. 11-5).
11-12
-------
GASOLINE
ACCELERATOR
FLOW CONTROL I
VALVE |~ •"••""
GASOLINE
r
H2 GENERATOR
H2 + CO
AIR
AIR
1
INDUCTION SYSTEM
CONVENTIONAL
ENGINE
EXHAUST
Figure 11-6. JPL, System (Ref. 11-5)
-------
production of hydrogen from hydrocarbons. (The process is called partial
oxidation fuel reforming. ) In this process gasoline, water, and air are
reacted at 1500 to 2000 °F, forming a gaseous mixture composed of hydrogen,
carbon monoxide, plus various hydrocarbons and diluents. Heat is supplied
by pumping air into the generator and burning a portion of the gasoline. The
reaction takes place in a reactor with or without the use of catalysts. The
maximum theoretical hydrogen yield for a hydrogen generator with water,
gasoline, and air feed is 29 percent by volume. When no water feed is used
the generator air-fuel mass ratio must be greater than five to avoid soot for-
mation. Under these conditions the maximum theoretical hydrogen yield is
25 percent by volume. A current JPL catalytic generator (Figure 11-7) yields
22 percent hydrogen by volume with a small trace of soot. This operation is
achieved with gasoline and air feed only and no water is used. The catalytic
generator has an efficiency of 81 percent. This is a major improvement over
an earlier JPL generator which produced 14. 5 percent by volume hydrogen
with an efficiency of 67 percent and which required water feed. Development
is continuing toward eliminating the need for catalysts in the hydrogen
generator (Ref. 11-5).
11.1.3.4 Siemens Catalytic Carburetor Concept
The general features of a catalytic carburetor system under
development by the German industrial firm, Siemens, was disclosed in
December 1973 (Ref. 11-6) from which the following descriptive material
was abstracted.
Although termed a catalytic carburetor, it is a gas generator
that breaks up the gasoline molecules into gaseous components such as
hydrogen, carbon monoxide, and methane before the fuel is mixed with air.
Some air is necessary for the gasification process, but the ratio is 1 part
air, by weight, to 20 parts gasoline.
As shown in Figure 11-8, fuel is metered by electromagnetically
controlled injectors and enters from both aides at the top of an enclosure
about the carburetor. A priming device feeds in small amounts of air mixed
with recirculating exhaust gas. The fuel enters the catalyst bed and is
gasified in a cracking process. The purpose for recirculating the exhaust
11-14
-------
I
H^>
On
k
n.
D,
i
LJ
\ n
\
\
^ -
v
:'• ^TN*^
•.•.•>•",•
*"#:
.•.. .»-•>
¥>&.
C
9 in
iii.
.••'•-:,.•'• i ,-: fJ-V •.-*•". '*'"'''
•CATALYST^
/ i-> ^ P* ->•
; BED v
/
i ! I Illiiill
u
>1 .'
1
s
IN. •"
^s-
x"^
HC + AIR
VAPORIZED
1 ~T
1 1
«.
: s
5-1/2 in. ID
\
-*
CERAMIC
LINER
CAST
CERAMIC
1/8 in. PELLETS NICKEL ON MAGNESIUM OXIDE
START-UP
LIQUID HC
Figure 11-7. Catalytic Hydrogen Generator (JPL; Ref. 11-5)
-------
—I
I A small box about 12 inches high encloses the carburetor unit. The diagram
at right shows the flow path of the gaseous fuel from the catalyst bed through
the built-in heat exchanger. Fuel is metered by electronic computer.
All functions in
the Siemens fuel
j system are con-
trolled by an
electronic unit.
Fuel is gasified
before being
mixed with air
into a combus-
tible charge. It's
all gas, without
fuel droplets, so
mixture can be
extremely lean.
That means com-
plete combustion
and more mpg.
METERING VALVE
AIR CLEANER
WITH THERMISTOR
ENGINE
-J INTERCOOLER MIXING THROTTLE
WITH WATER UNIT
Figure 11-8. Features of Siemens Catalytic Carburetor System
(Ref. 11-6)
11-16
-------
is to heat up the catalyst. It will not work below a certain temperature.
Siemens engineers won't identify the catalyst but claim it does not contain
noble metals.
The gas is formed at an elevated temperature and must be
cooled before it can be mixed with air. The cooling takes place in two stages.
First, the gas flows through a heat exchanger contained within the carburetor
body. Some heat is recovered and goes back to the catalytic bed. Then the
gas flows through a water-cooled radiator before being led to the mixing unit.
The air-fuel charge is created in the mixing unit, when the
gasified fuel is metered into fresh air that has entered the plenum chamber
mounted upstream from the mixing unit and intake manifold. The air-fuel
ratio is closely controlled by an electronic control unit (computer).
This small computer also controls the priming device and the
quantity of raw fuel admitted to the catalytic carburetor. The computer is
wired to sensors for engine speed and load, ambient temperature, and air
density; it automatically adjusts fuel quantity and air-fuel ratios as incom-
ing information is received. Adjustments are made in milliseconds.
Despite intercooling, the air-fuel mixture still has a higher-
than-ambient temperature when it enters the combustion chambers. This
brings with it the disadvantage of reduced cylinder filling. Siemens engineers
estimate that the catalytic carburetor gives volumetric efficiency between 10
and 20 percent lower than conventional carburetors.
However, this loss can be restored by raising the compression
ratio. The catalytically cracked fuel offers high knock resistance (high
octane number) and is compatible with high-compression engines. The raw
gasoline must be lead-free, as lead will contaminate the catalyst.
11.1.4 Physical and Chemical Properties
As noted previously, ideal steam reformation of hydrocarbon
fuels would yield only HZ and CO as the reformer fuel products. However,
process inefficiencies and the differences in reformer design approach and
process characteristics combine to produce reformed fuels with a variety of
othe r c on s tituent s.
11-17
-------
In the case of the partial oxidation process approach, results
from the JPL concept program can be used to illustrate these effects (Ref.
11-5). The reformed fuel products, or the output composition of the partial
oxidation process hydrogen generator, are illustrated in Table 11-1 for both
the theoretical case and the experimental catalytic laboratory generator.
As can be noted, even in the ideal case, in addition to the desired H2 and CO
there is a substantial amount of nitrogen generated (from the air used to
provide process combustion heat), as well as carbon dioxide, methane, and
steam. In the actual case shown, the steam content is reduced and there
are other hydrocarbon species present.
Table 11-1. Catalytic Hydrogen Generator Output Composition
(JPL, Ref. 11-5)
Component
H2
CH4
C2H4
CO
C°2
H20
N2
Volume %
Theoretical
24.3
0. 1
21.9
1.4
2.0
50.3
100.0
Actual
21.60
1.54
0.85
23.20
1.16
1.30
50.35
100.00
Feed: Indolene and air
Trace quantities of soot
11-18
-------
In the case of a catalytic-steam reformation process, Ref-
erence 11-2 indicated reformer products with the following composition, in
mol percent:
Methane 35.3
Hydrogen 30.0
Carbon monoxide 3.3
Carbon dioxide 16.4
Water 15.0
The above composition was expressed as typical of an equilibrium product
of steam reacted with hexane at 1, 000 °F and using a steam-hexane ratio of
1.71 pounds per pound with a water condenser operating at 180°F to condense
out a portion of the water content of the effluent.
A complete description of the reformed fuel products from the
Siemens "catalytic carburetor" is not available; however,they do mention that
methane is present as well as hydrogen and carbon monoxide. Since some
air is used in their device (one part air- by weight, to 20 parts of gasoline),
some nitrogen generation would also be expected.
A complete delineation of the reformed fuel products from the
International Materials Corporation concept (Ref. 11-4) is not currently
available in the literature. Reference 11-7 indicates that the products include
H2, CO, C02, and CH.^.
11.1.5 Combustion Characteristics
Although specific combustion characteristics of reformed fuel
products have not yet been detailed, it would be expected that effects of the
hydrogen gas present would predominate and that the excellent combustion
characteristics of hydrogen (see Section 8) would similarly apply to the
hydrogen-gas generator products, unless excessive amounts of diluents
(steam, nitrogen) were present. Laboratory tests of a V-8 engine with
products from an experimental generator were conducted by JPL (Ref. 11-1),
and engine operation was generally similar to that obtained with mixtures of
gasoline and pure hydrogen (Ref. 11-8).
11-19
-------
11.2 SUITABILITY FOR USE AS AN ENGINE FUEL
11.2.1 Engine/Vehicle Compatibility
Since the principal combustible constituent of reformed fuels
is hydrogen, they should be very compatible with engine combustion require-
ments, as delineated previously for hydrogen in Section 8.1.5. In addition,
on-board fuel reformation provides conventional storage of the basic liquid
hydrocarbon fuel, much the same as gasoline is stored on-board today's auto-
mobiles, thus negating the well-known storage problems attendant to gaseous
and liquid hydrogen fuels (Section 8.2.6).
There are, however, ancillary effects caused by the method
of reformer operation and the characteristics of the reformed fuel in terms
of its gaseous nature, its temperature at inlet to the engine, and its species
composition. These effects are discussed in the following sections.
11.2. 1. 1 Method of Reformer Utilization
Fuel reformers may be utilized to process the entire engine
fuel requirements or to gasify only a portion of the engine fuel requirements
(i.e. , engine operates on liquid gasoline plus reformer gaseous products).
In either case, partial or total fuel reformation, the principal objective to
date has been to operate the engine at lean air-fuel mixtures in order to
reduce the amounts of HC, CO, and NO exhaust emissions (Refs. 11-1,
5C
11-2, 11-4, and 11-6) as discussed more fully in Section 11. 2. 3.
The gaseous hydrogen in the reformed fuel, with its high
flame velocity and ready combustibility over a wide range of air-hydrogen
mixtures, enables operation at fuel-air ratios much leaner than possible
with gasoline. This is illustrated for hydrogen-plus-gasoline mixtures in
Figure 11-9 from General Motors tests (Ref. 11-9) with a single-cylinder
engine. Shown is the lean limit equivalence ratio* as a function of the amount
of gaseous hydrogen present in the hydrogen plus gasoline mixture. The lean
r-
, .. (actual fuel air ratio)
equivalence ratio = . . ——z—= : ; = 0
(stoichiometric fuel air ratio) r
11-20
-------
I.Or—
S
§0.8
M
-------
operating limit for pure isooctane (0.89 equivalence ratio) could be extended
to an equivalence ratio of 0. 55 with a hydrogen fraction of 0. 10 and to an
equivalence ratio of 0.40 with a hydrogen fraction of 0.20.
11.2.1.2 Effects on Power Output
A concomitant effect of very lean operation is a loss in engine
power output, whether the fuel be conventional gasoline, gaseous reformed
fuel products, or mixtures thereof. Figure 11-10 illustrates results obtained
by General Motors -with hydrogen-plus-gasoline mixtures in a single-cylinder
engine. The indicated horsepower decreased about 40 percent for the change in
mixture ratio from = 1. 0 to 0 = 0. 55 due to the reduced energy input at the
leaner mixture.
In addition to the power loss occasioned by lean operation,
further power losses with reformed fuels may be caused by decreased volu-
metric efficiency and fuel dilution effects. The volumetric efficiency is
reduced due both to the gaseous nature of the reformed fuel and the higher
temperatures of the reformed fuel products entering the engine. Although
the specific fuel reformed concept usually provides for cooling the gas-
generator products prior to induction by the engine, the resultant cooled
gaseous reformed fuel product may be several hundred degrees hotter than
normal inlet air and fuel temperatures.
As noted in Section 11. 1.4, the reformed fuel has, in addition
to hydrogen, some amounts of carbon monoxide, methane, water, unreacted
hydrocarbons, and, in the case of partial oxidation processes, large fractions
of nitrogen from the air used in the combustion process. While the diluents'
steam and nitrogen might be expected to have salutory NO emission reduc-
tion effects, they also reduce specific power output if quantities are too large.
Table 11-2 illustrates the effects on engine power of gaseous
fuel dilution, lean operation, and reformer products for the case of a JPL
partial oxidation experimental fuel reformer operated in laboratory tests
with a 350-CID V-8 engine. As shown, the effect of gaseous hydrogen in a
gasoline-plus-hydrogen fuel mixture reduces engine horsepower (at 2, 000 rpm)
11-22
-------
60
r~ 6i—
u
z
UJ
y
u. 40
u.
Ul
UJ
I-
Q
UJ
I-
O
5
z
I
20
— $ 4
O
Q.
o:
O
O
UJ
-? 2
9
I
•— o
ISOOCTANE
ONLY
ISOOCTANE + HYDROGEN
—Qr'
1
HYDROGEN
ONLY
RICH
LEAN
1.2 1.0 0.8 0.6 0.4
EQUIVALENCE RATIO
0.2
Figure 11-10. Effect of Ultralean Operation on Engine Power
and Efficiency with Hydrogen-Supplemented
Fuel (Ref. 11-9)
11-23
-------
Table 11-2. Summary of Operational Characteristics,
JPL System (Ref. 11-1)
Engine Maximum Indicated H.P.
at 2000 rpm Condition
Gasoline 0=1.0
H_ + Gasoline 0=1.0
H_ + Gasoline 0 = 0.6
H? Generator + Gasoline 0=1.0
H_ Generator + Gasoline 0 = 0.6
Current Engine
and H_ Gen.
91
88
61
75
54
from 91 to 88. With this same fuel mixture, reducing the equivalence ratio
from stoichiometric (0 = 1.0) to lean operation (0 = 0.6) further reduces the
power output to 61 horsepower. With reformer products instead of the hydro-
gen, at 0 = 1 the power is reduced from 88 to 75 and at 0 = 0.6 the power is
reduced from 61 to 54.
Siemens (Ref. 11-6) reports that their "catalytic carburetor"
produced no power loss (over the standard carburetor) when operated at 0 =
0. 8 in a small (122-cubic inch) engine, and it produced a 4. 14 percent gain
in power at stoichiometric conditions (0 = 1.0). However, at leaner condi-
tions (0 = 0. 70 to 0. 75) there was a sizeable power loss (15 to 25 percent).
It should be noted that the aforementioned power losses apply
only in the case where the fuel reformer is operating. Some concepts pro-
vide for the capability to bypass the reformer under certain operating condi-
tions (e.g. , high-speed highway operation). By operating an engine with gaso-
line only, full engine power would be available at normal engine efficiency.
11.2.2 Fuel Economy Effects
Improved fuel economy for vehicles operated with reformed
fuels has been postulated to result from (1) higher engine thermal efficien-
cies as a result of lean operation and (2) reduced throttling losses at part-
11-24
-------
load conditions by using fuel throttling control instead of air or intake charge
throttling; this latter approach is rendered feasible because of the combus-
tibility of hydrogen-air mixtures over the wide range of air-fuel ratios that
would be encountered during unthrottled part load engine operation.
Engine-indicated thermal efficiencies were measured by
General Motors (Ref. 11-9) for a single-cylinder engine operating on
hydrocarbon-supplemented gasoline, as shown in Figure 11-10. As can be
noted, the indicated thermal efficiency increased from 33 percent for an
equivalence ratio of 1.0 to about 37 percent at an equivalence ratio of 0.55.
Similar trends were observed by JPL (Ref. 11-1) in tests of a single-cylinder
CFR engine and a 350 CID V-8 engine.
In tests of the Siemens "catalytic carburetor," a 20 percent
improvement in gas mileage (miles per gallon) was reported at operation
with 20 percent more air than stoichiometric (0 = 0.8) (Ref. 11-6).
Substantive fuel economy data from vehicle tests are
currently not available.
11.2.3 Emissions Effects
The principal driving force behind the development of fuel
reformers or hydrogen generators has been the potential for reducing emis-
sions by (1) using a fuel product (hydrogen) having inherently lower exhaust
emission products and (2) using a fuel product (hydrogen) enabling very lean
engine operation. Lean operation has long been recognized as offering the
potential for concurrent or simultaneous reductions of all three exhaust
emissions species (HC, CO, NO ). For the case where all of the fuel con-
.X
sumed by the engine is reformer products (U^, CO, etc.), data are available
for three specific concepts.
As reported in Reference 11-7, tests from a prototype model
of the International Materials Corporation reformer in simulated vehicle
operation demonstrated CO emissions of 0.412 to 2.78 grams per vehicle miles
(gm/mi), unbumed hydrocarbons of 0.012 to 0. 15 gm/mi, and NOx of 0.040
to 0.37 gm/mi. References of this type which convert all of the engine's
11-25
-------
fuel requirements are typically large in volume and pose difficult vehicle
packaging problems. In addition, reformer inefficiencies are applied to all
of the gasoline used by the vehicle and may result in reduced fuel economy.
Siemens "catalytic carburetor" tests (Ref. 11-6) indicated
the following emissions resulted when tested with a small (122 cubic inch)
engine:
CO
NO
X
Unmodified
Standard
Carb.
1.5%
Engine
Leanest
Possible
Setting
0.5%
l,400ppm l,200ppm
Catalytic Carburetor
iLJLi
0. 15%
0 = 0. 8
0.09%
l.OOOppm 40 ppm
0 = 0.7-0.75
CO went up
NOX went
down further
No hydrocarbon emissions data were presented in Reference 11-6.
Emissions were also measured in the Phillips Petroleum
Company CFR tests of gasoline and synthetic normal hexane reformate fuels
noted above in Section 11.2.2 (Ref. 11-2). These tests gave the following
results in terms of weighted average emissions over a simulated driving
schedule (Ref. 11-10) for optimum spark timing, and homogeneous, lean,
fuel-air mixtures:
Carbon monoxide, gm/ihp-hr
Hydrocarbons, gm/ihp-hr
Nitric Oxide, gm/ihp-hr
Reformate Fuel
Only
0.8
0
0.9
Gasoline
Only
47. 5
3.8
6.8
where ihp-hr = indicated horsepower per hour
In the case where only a portion of the fuel used by the engine
is passed through the reformer, substantive data are available from recent
hydrogen-supplemented gasoline tests performed by General Motors and JPL.
11-26
-------
The effect of lean operation on emissions with isooctane-hydrogen mixtures
in a single-cylinder engine is shown in Figure 11-11 (from Ref. 11-9). As
was the case with pure hydrogen, NO emission was extremely low for equiv-
alence ratios leaner than 0. 55. The 0. 55 equivalence ratio is then an appar-
ent optimum mixture, since NO emission was reduced to near-minimum
.. ISOOCTANE + HYDROGEN.
AT LEAN LIMIT
^
/
9
/HC
j_
.c
Q.
PURE
HYDROGEN
1.2
1.0
0.8 0.6 0.4
EQUIVALENCE RATIO
0.2
Figure 11-11. Emissions Characteristics of Isooctane-
S Hydrogen Fuel Mixtures (Ref. 11-9)
11-27
-------
levels with limited hydrogen requirement. However, as is typical of ex-
tremely lean operation on hydrocarbon fuels, the HC emission increased with
very lean mixtures reflecting the increased quench layer thickness and re-
duced post-flame oxidation of the quenched hydrocarbons. At 0. 55 equiva-
lence ratio, HC emission increased about 100 percent from the minimum
level. In contrast, the leaner operation made possible by hydrogen addition
had only a minor effect on CO emission; CFR and V-8 engine (350-CID) tests
by JPL (Ref. 11-1) with hydrogen-plus-gasoline mixtures exhibited results
and trends generally similar to the General Motors data of Figure 11-11.
Recent JPL comparison tests of a 1973 Chevrolet Impala on
the 1975 Federal Test Procedure (FTP) (Ref. 11-5), first with gasoline only
and then with hydrogen-supplemented gasoline, produced the following exhaust
emissions results:
Stock Impala Modified Impala
(Gasoline only- (Gasoline plus hydrogen-
stock carburetor) special test carburetor)
HC gm/mi 2.29 2. 17
CO gm/mi 43.91 1.63
NO gm/mi 1.75 0.67
x 6
The hydrogen was supplied from hydrogen gas bottles located
in the trunk of the car. The variation of equivalence ratio throughout the test
is not known. The reduction in CO and NO is marked. It should be noted
x
that the special test carburetor used could have effects on the data shown.
In-the-engine control of NO was also verified by General
.X
Motors in one experimental vehicle tailored to operate at mixture equiva-
lence ratios of 0. 55 to 0. 65 with a hydrogen fraction of 0. 10 for most driv-
ing conditions; the hydrogen was again supplied by gas bottles in the trunk
11-28
-------
of the car. Results of exhaust emissions tests on the cold start 1975 FTP
at 3, 500-pound inertia weight were as follows:
Vehicle Exhaust Emissions with Constant Hydrogen
Fraction (Ref. 11-9)
^
Emissions, gm/mi
NOX CO HC
0.34 3.3 3.2
0.44 3. 3 3. 0
Average 0. 39 3. 3 3. 1
NO and CO satisfied the 0.4 and 3.4 gm/mi standards,
respectively. Hydrocarbon emission, however, was nearly an order of mag-
nitude higher than the 0.41 gm/mi limit.
All of the foregoing tests were initial exploratory tests and
may not reflect ultimate system potential for engines operated on reformed
fuel nor for the case of gasoline supplemented by either hydrogen or re-
formed fuel.
11.2.4 Toxicity Effects
The principal ingredients in gaseous reformed fuel products
are hydrogen, carbon monoxide, and water vapor, as delineated in Sec-
tion 11.1.4; other ingredients which may be present include methane, carbon
'"1975 Federal Test Procedure
11-29
-------
dioxide, and other unreacted hydrocarbons. A brief resume of the toxicity
effects of the various ingredients follows:
• Hydrogen. Acts as a simple asphyxiant; decreases available
oxygen; no warning properties (see Section 8.2.4)
• Carbon monoxide. A colorless, ordorless gas; very poisonous
• Water. Nontoxic
• Methane. Toxicity ranges from none to slight; less toxic
than gasoline (refer to Table 5-3)
• Carbon dioxide. Nontoxic
• Unreacted hydrocarbons. Similar to gasoline (Section
3.2.3. 1): low oral toxicity; low dermal toxicity; signi-
ficant aspiration effects (minute amounts drawn into lungs
can be rapidly fatal).
11.2.5 Safety Effects
With regard to on-board storage of the liquid hydrocarbon fuel
prior to reformation, the safety hazards should be similar to those of current
fuels and would depend on the specific fuel used. Fire and explosion would be
the principal hazards for the lower boiling fractions such as gasoline. Higher
boiling fuels, such as diesel and fuel oils, only represent a fire hazard due to
their lower volatility.
When the reformer is in operation, the generation of gaseous
products could introduce the additional hazard of fires if lines or pressure
vessels leak or rupture due to the hydrogen content of the reformer products
(see Section 8.2.5.1).
If an accumulator is used in the system to store reformed
fuel products (for example, for starting on gaseous fuel products), addi-
tional hazards of vessel rupture, fire, and explosives are introduced, with
the degree of hazard associated with the level of pressure at which the prod-
ucts are stored.
11.2.6 Handling, Storage, and Distribution
All of the liquid hydrocarbon fuels that are potential candi-
dates for use with fuel reformers are in commercial use today with contem-
porary handling, storage, and distribution systems. This fact enhances the
11-30
-------
potential for use of reformed fuel systems, since no new handling, storage,
or distribution systems would be required.
11.2.7 Critical Research Gaps
Although a number of investigators (Refs. 11-1 through 11-9)
have made available selected data that tend to confirm that fuel reforma-
tion (partial or total) can beneficially reduce exhaust emissions and/or
increase fuel economy (via lean operation), there is no single comprehen-
sive set of experimental and/or analytical data for any given concept which
fully treats the combined effects of emissions, fuel economy, power loss,
and system operation to the degree necessary to fully evaluate the concept
potential. Principal data missing or factors not adequately treated or
assessed include:
a. Techniques for reducing high HC emission levels during lean
operation
b. Actual emission levels for all constituents (HC, CO, and
NOX) when actual reformer products are burned in the engine
(H2 plus gasoline mixtures and synthesized reformer products
used in most cases to date)
c. Experimental determination of fuel reformer output and
performance in a finite and reasonable size (e.g. , as would
be built for installation in a passenger car for production)
d. Measurement of fuel economy with an actual reformer sys-
tem operating in a vehicle driven over the Federal Driving
Cycle
e. Determination of the operating characteristics of the reformer/
engine system over the full range of normal vehicle operation
f. The reformer/vehicle performance capability over the full
range of normal vehicle operation in customer use, including
speed and load conditions not encountered in the Federal
Driving Cycle
g. The effect of high-temperature reformer products on engine
performance
h. Potential soot formation problems
i. Water handling and attendant problems (volume, weight,
location, freezing, vehicle weight, growth effects, etc.)
j. System startup and control techniques
k. Overall system economics and durability.
11-31
-------
11.3 CURRENT STATUS
No mobile on-board fuel reformer system is known to be in
developmental vehicle operation. A prototype model of the International
Materials Corporation concept reformer has been operated on a chassis
dynamometer (Ref. 11-7). The Siemens "catalytic carburetor" concept is
reported to have been under study for some years, with recent engine dyna-
mometer tests on a small (122-cubic inch) engine and a larger 170-
horsepower engine (Ref. 11-6); and JPL has performed reformer tests with
an experimental laboratory reformer unit and a 350-CID V-8 engine in an
engine dynamometer, but their passenger car tests (1973 Chevrolet Impala)
have been restricted to tests with gasoline supplemented by gaseous hydrogen.
Available data on the Phillips catalytic reformer concept are restricted to
CFR engine tests with synthesized reformate fuel products only (Ref. 11-2).
In summary, with regard to current status, fuel reformer
concepts are still in the exploratory, proof-of-principle, or feasibility
determination stage. A number of critical data gaps exist, as delineated in
Section 11.2.7, which must be filled before on-board reformed fuels can be
fully assessed as to their future potential. NASA has been funding the Jet
Propulsion Laboratory to acquire data and prove concept feasibility and EPA
is providing supplemental funding for this work in addition to other contractor-
supported programs for evaluation of similar concepts.
11.4 PROJECTED STATUS
11.4. 1 Availability
Since fuel reformer concepts have the potential to operate with
a wide range of liquid hydrocarbon fuels (Section 5.9. 1. 2), the concept is
limited as to fuel reserves and/or raw material sources only insofar as con-
ventional petroleum or nonpetroleum hydrocarbon fuels are limited (see
Sections 3, 4, and 7). The availability of on-board reformed fuels is limited
by the availability of a developed fuel reformer system which can be mass
produced and marketed on a competitive basis with other engine systems
competing for the same liquid hydrocarbon basic fuel source. As noted in
11-32
-------
Section 11.3, such a reformer system has not yet reached the prototype
vehicle demonstration stage.
II-4-2 Projected Consumer Costs
Estimates of consumer initial costs for mass-produced fuel
reformers have not yet been made available in the literature. Maintenance
cost requirements are similarly not available. If fuel reformer use results
in full economy gains (as postulated),then the consumer will realize fuel cost
savings.
11-4.3 Capital Costs and Timing Implications
As in the case of initial consumer costs, no estimates of
capital cost requirements are available. However, by analogy with emission
control system concepts such as thermal reactors and catalytic converters,
it would take the automobile industry at least three to four years after
successful prototype vehicle evaluation to produce reformer systems in any
sizeable mass-production quantities.
11.4.4 Impact with Other U. S. Energy Requirements
The fuel reformer concept, per se, should have no adverse
impact on other U.S. energy requirements, but will not alleviate future
shortages of gasoline or distillates. One possible attribute advanced for this
broad concept is that it may be compatible with the use of a number of basic
hydrocarbon fuels over a wide boiling range. However; specific reformer
designs may require the use of a single fuel grade in order to operate most
efficiently. For those concepts that reform only a portion of the engine's
fuel requirements for the conventional spark ignition engine, the fuel choice
would, of course, be limited to gasoline.
11.4.5 Factors Which May Inhibit Use
Assuming that reformer system performance (emissions and
fuel economy) goals can be met, there are a number of other factors which
could inhibit their use. Chief among these may be:
• Reformer system installation size
11-33
-------
• Reformer system operational complexity
• High system installed cost
• Potential of soot production (partial oxidation
systems)
• High engine power losses (causing increased
engine displacement and size and weight for same
output)
• Water storage and freezing problems.
11.4.6 Critical Technology Gaps
Although a number of general and specific research data gaps
were identified as being critical to the overall assessment of the reformed
fuel system concept (Section 11.2.7), the fuel reformer device itself is the
critical technology gap. Research and development efforts are required,
for a specific reformer device, to demonstrate adequate lifetime and per-
formance characteristics, including transient output characteristics and
control system compatibility with the engine/vehicle system.
11.4.7 Potential for National and Regional Use
Due to the present lack of demonstration of concept feasibility
(on an overall system basis), the application of on-board fuel reformers to
automotive systems does not seem to be immediately pending. As previously
noted, extensive research and development efforts are required to resolve
uncertainties as to reformer, reformer/engine, and engine/vehicle system
performance potential and exhaust emission and fuel economy characteristics.
The effectiveness of hydrogen-supplemented fuel in extending
lean operating limits and reducing NO and CO emissions has been substan-
3t
tiated in single-cylinder-engine tests and in experimental vehicles modified to
carry on-board gaseous hydrogen storage bottles. When 10-percent hydrogen
(by weight) was used, engine power decreased by approximately 40 percent,
and indicated thermal efficiency increased from 33 percent to 37 percent.
Hydrocarbon emissions were increased, as is typical of very lean combustion
engines operating with hydrocarbon fuels.
11-34
-------
ABBREVIATIONS
-------
ABBREVIATIONS
ACGH
AGA
APHA
atm
bbl
btdc
BuMines
C2H5OH
C6H6
CFR
CH3OH
CH4
CNG
C6H12
CO
co2
CR
CSF
CVS
DCF
American Congress of Government Hygenists
American Gas Association
American Public Health Association
atmosphere
barrel
before top dead center
Bureau of Mines
chemical formula for ethyl alcohol or ethanol
chemical formula for acetone
chemical formula for benzene
Cooperative Fuel Research (Council)
chemical formula for methyl alcohol or methanol
chemical formula for methane
compressed natural gas
chemical formula for cyclohexane
chemical formula for carbon monoxide
chemical formula for carbon dioxide
compression ratio
Consol Synthetic Fuel
constant volume sampling (federal test procedure)
Discounted Cash Flow, a method of computing return
on investment
Ab-1
-------
EGR
ft2
ft3
Fe
f.o.b.
FTP
FPC
g> 8m
GSA
H2
H20
HHV
HIT
HO Ac
IBP
ICC
IGT
IMEP
ISFC
JPL
KOH
kW-hr
Ib
LHV
exhaust gas recirculation
square foot
cubic foot
chemical symbol for iron
free on board
Federal Test Procedure
Federal Power Commission
gram
General Services Administration
chemical formula for hydrogen
chemical formula for water
higher heating value (see Glossary)
hydrogen induction technique
a procedure for measuring acidity
initial boiling point
Interstate Commerce Commission
Institute of Gas Technology
indicated mean effective pressure
indicated specific fuel consumption
Jet Propulsion Laboratory
chemical formula for potassium permanganate
chemical formula for potassium hydroxide
kilowatt (thousand watts) hour
pound(s)
lower or net heating value (see Glossary)
Ab-2
-------
LNG
LTA
M
ml
MM
MMCF
MSCF
mol
MON
MW
N2
N2H4
NG
NGL
Ni
°2
PGC
0 (phi)
ppm
psi
psia
Pu
ROI
liquified natural gas
lighter than air (craft)
thousand
milliliter
million
million cubic feet
thousand standard cubic feet
molecule
motor octane number
megawatt (million watts)
chemical formula for nitrogen
chemical formula for hydrazine
natural gas
natural gas liquids
chemical formula for ammonia
symbol for nickel
chemical formula for oxygen
Potential Gas Committee
equivalence ratio
parts per million
pounds per square inch
pounds per square inch absolute
symbol for plutonium
return on investment
Ab-3
-------
RON research (or road) octane number
Ru symbol for ruthenium
SAE Society of Automotive Engineers
SCF standard cubic foot (of gas) measured at 70° F and
14.696 psia
ST stream day
SFC specific fuel consumption
SNG synthetic natural gas
SRC solvent refined coal
ST short ton, 2,000 pounds
tel tetra-ethyllead
ThO7 chemical symbol for thorium oxide
c*
T/SD tons per stream day
UCLA University of California, Los Angeles
U symbol for uranium
U.S. B.M. United States Bureau of Mines
USI United States Industries
w/o without
WOT wide open throttle
ZnO chemical formula for zinc oxide
Ab-4
-------
GLOSSARY
-------
GLOSSARY
aldehyde an odorous, oxygenated hydrocarbon classified as
a pollutant
anhydrous without water
0
API a method of expressing specific gravity for hydrocarbon
fuels
°API = 141.5
specific gravity of hydrocarbon "
specific gravity for test fluid referenced to water at
60°F.
catalyst a substance that increases the rate of a chemical
reaction without itself undergoing a permanent
chemical change
cetane number a measure of the ignition delay of a fuel in a com-
pression ignition (diesel) engine
cryogenic related to the production and effects of very low
temperatures
endothermic reaction a chemical reaction in which heat is absorbed
equivalence ratio the actual fuel-air ratio to stoichiometric fuel-
air ratio
exothermic reaction a chemical reaction in which heat is evolved
fixed-bed reactor a grate or bed in which pellets are tightly packed
and constrained from movement as a hot gas
stream flows through the bed
flash point the temperature at which the vapor above bulk
liquid can be ignited by an open flame
fluidized-bed reactor a grate or bed in which finely divided pellets are
free to move in the vertical direction and are
suspended by the upward flow of a hot gas stream
gross or higher the energy released by a fuel when it is completely
heating value (HHV) burned in such a way that the water vapor of com-
bustion is condensed to a liquid
G-l
-------
hypergolic ignition
hydrocracking
kerogen
kinematic viscosity
methanol
naphtha
natural gas
neat
net or lower
heating value (LHV)
octane number
photovoltaic
pyrolysis
Rankine engine
recuperator
regenerator
regenerative engine
spontaneous ignition upon contact of the fuel and
oxidizer
catalytic cracking process with simultaneous
hydrogenation used in the processing of crude oil
bituminous material occuring in shale and yielding
oil when heated
viscosity divided by density
same as methyl alcohol
a light oil product of petroleum having properties
intermediate between gasoline and kerosene
a gaseous fuel consisting primarily of methane
a pure material without additives
the energy released by a fuel when it is burned com-
pletely without condensing the water vapor of combustion
a measure of the resistance of a fuel to detonate in a
spark ignition, reciprocating (Otto cycle) engine
relating to the generation of an electromotive force
when radiant energy falls on the boundary of dissimilar
substances
chemical decomposition resulting from heat in the
absence of oxygen
a heat engine that operates in the Rankine thermo-
dynamic cycle, which includes fluid vaporization,
expansion, and condensation stages (e.g., conven-
tional steam engine)
a fixed device used to improve gas turbine engine
efficiency by providing for heat exchange between
turbine exhaust gases and compressor outlet air
a rotating device used to improve gas turbine engine
efficiency by providing for heat exchange between
turbine exhaust gases and compressor outlet air
incorporates a regenerator or recuperator to
improve engine efficiency
G-2
-------
specific fuel
consumption
stoichiometric
syncrude
thermal efficiency
thermal reforming
fuel consumption of a heat engine measured in terms
of fuel weight per hour consumed by the engine
divided by its horsepower output
refers to conditions in a combustion process wherein
the fuel is completely burned with no excess oxygen
remaining
a synthetic crude oil made from oil shale or coal
the ratio of theoretical work done by an engine to the
mechanical equivalent of heat supplied in the fuel
a process using heat (but no catalyst) to effect
molecular rearrangement of a hydrocarbon fuel
(example: low-octane naphtha into gasoline of
higher antiknock quality)
G-3
-------
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-------
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(November 1969).
5-5. Kirk-Othmer, Encyclopedia of Chemical Technology, Vol. 10, 2nd Ed.,
John Wiley and Sons (1966), pp. 454-456.
5-6. Kirk-Othmer, Encyclopedia of Chemical Technology- Supplemental
Volume, John Wiley and Sons (1971) p. 426.
5-7. H. R. Linden, The Role of SNG in the U.S. Energy Balance, Special
Report for the Gas Supply Committee of the AGA (15 May 1973).
R-4
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5-8. J. J. Brogan, "Present and Future Trends in Automotive Fuel
Consumption, " Automotive Engineering 81 (7) (July 1973).
5-9. "Cal Tech Clean Air Car Project, " Gaseous Fuels Manual.
California Institute of Technology (March 1972).
5-10. R. W. McJones and R. J. Corbell, "Natural Gas Fueled Vehicles -
Exhaust Emission and Operational Characteristics, " Society of
Automotive Engineers, Automotive Engineering Congress, January
5-11. N. E. Fraize, U.S. Transportation - Some Energy and Environmental
Considerations, M72-164, The Mitre Corporation (September 1972).
5-12. R. D. Fleming and J. R. Allsup, Natural Gas as an Automotive
Fuel, An Experimental Study, U.S. Department of Interior; Report
of Investigation-7806 (1973).
5-13. W. D. Anderson, "R&D for Fuel Economy in Automotive Propulsion,"
U.S. Army Tank-Automotive Command (19 June 1972).
5-14. M. R. Engler, Jr., "Investigation of Liquefied Natural Gas as an
Engine Fuel, 69-WS/DGP-3, ASME Meeting, Los Angeles, California
November 1969.
5-15. D. B. Eccleston.el al., Clean Automotive Fuel, Engine Emissions
Using Natural Gas, Hydrogen-Enriched Gas and Gas Manufactured
from Coal (Synthanej, TPR 48, U.S. Department of Interior, Bureau
of Mines, Salt Lake City, Utah (February 1972).
5-16. W. D. Trammel, "The Energy Crisis and the Chemical Industry, "
Chemical Engineering (30 April 1973).
5-17. IGT Hygas Process, Institute of Gas Technology brochure (1972).
5-18. R. P. Cahn, etal., Feasibility Study of Alternative Fuels for
Automotive Transportation - Phase I, Esso Research and Engineering
Co.; preliminary information as of October 1973; report to be
published. *
6-1. Bland and Davison, Petroleum Processing Handbook, McGraw-Hill
Book Company (1967).
6-2. "Metals, Minerals and Fuels," 1970 Minerals Year Book. Vol. I.
6-3. Kirk-Othmer, Encyclopedia of Chemical Technology. Vol. 12, John
Wiley and Sons (1967).
See footnote, page R-2
R-5
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6-4. R. C. Lee and D. B. Wimmer, "Exhaust Emission Abatement by
Fuel Variations to Produce Lean Combustion, " SAE Paper No.
580769, given at National Fuels and Lubrications Meeting, Tulsa,
Oklahoma, 29-31 October 1968.
6-5. Control Strategies for In-Use Vehicles, U.S. Environmental
Protection Agency (November 1972).
6-6. Fleming, et al., "Propane as an Engine Fuel for Clean Air Require-
ments, " U.S. Department of the Interior, Bureau of Mines, July
1971.
6-7. Federal Register 36 (128) pt II (2 July 1971).
6-8. U.S. Environmental Protection Agency, unpublished data, October
1971.
6-9. Facts and Figures on the Clean Air Question, booklet, Petrolane,
Long Beach, Calif. (1971).
6-10. J. C. Thompson, NAPCA Findings on Gaseous Fuels, National Air
Pollution Control Administration (October 1970).
6-11. 1971 LP-Gas Market Facts, National LP-Gas Association.
6-12. Dr. Leo Garwin, "LP-Gas Supplies for the Engine Fuel Market,"
paper given at the LP-Gas Engine Fuel Symposium, 21-22 October
1970.
7-1. Kirk-Othmer, Encyclopedia of Chemical Technology, Vol. 8, 2nd Ed. ,
John Wiley and Sons, pp. 422-427 (1963).
7-2. G. C. Lawreson and P. F. Finigan, Ethyl Alcohol as a Modern Motor
Fuel, SAE Reprint SP-254 (1964).
7-3. E. L. Kilayko, Ethyl Alcohol as Fuel for Internal Combusion Engines,
Massachusetts Institute of Technology (August I960).
7-4. M. W. Jackson, Exhaust Hydrocarbon and Nitrogen Oxide Concentra-
tions with an Ethyl Alcohol Gasoline Blend, SAE Preprint SP-254
(1969).
7-5. "Use of Alcohol in Motor Gasoline -- a Review, " American Petroleum
Institute, Publication No. 4082 (August 1971).
8-1. A. F. Bush and W. D. Van Vorst, "On the UCLA Hydrogen Car,"
School for Engineering and Applied Science, UCLA.
R-6
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8-2. Hydrogen and Other Synthetic Fuels. Report No. UC-80, U.S. Atomic
Energy Commission, Div. of Reactor Development and Technology
(September 1972). ey
8-3. Liquid Propellant Manualr Liquid Propellant Information Agency,
LPM-1 (March 1961).
8-4. J. E. Johnson, The Economics of Liquid Hydrogen for Air Transpor-
tation, Union Carbide Corporation (10 August 1973).
8-5. R. E. Billings and F. E. Lynch, "History of Hydrogen-Fueled
Internal Combustion Engines, " Energy Research 73001.
8-6. K. H. Weil, "The Hydrogen 1C Engine - Its Origins and Future in
the Emerging Energy. . . "
8-7. R. R. Adt, Jr., D. L. Hershberger, T. Kartage, and M. R. Swain,
"The Hydrogen-air Fueled Automobile Engine (Part 1), " School of
Engineering and Environmental Design, University of Florida.
8-8. Wall Street Journal (3 August 1965).
8-9. Nitrogen (1964).
8-10. D. H. Stormont, Oil Gas Journal 63 (14) 103-106 (1965).
8-11. R. M. Reed, Trans. American Institute Chemical Engineers 42 (2)
379-401 (1946).
8-12. "Hydrogen: Synthetic Fuel of the Future. " Science 178, 849-852
(24 November 1972).
8-13. "Production Figures and Cost Estimates for Fuels, " Institute of Gas
Technology letter, 27 November 1973.
8-14. "Hydrogen: Likely Fuel of the Future, " Chemical and Engineering
News, pp. 14-17 (26 June 1972).
8-15. "Hydrogen Fuel Economy: Wide-Ranging Changes." Chemical and
Engineering News, pp. 27-30 (10 July 1972).
8-16. Feasibility Study of Alternative Fuels for Automotive Transportation -
Phase I, Esso Research and Engineering Co.; preliminary information
as of October 1973; report to be published.'
9-1. B. L. Shaw, Inorganic Hydrides, Pergamon Press, Oxford, England
(1967).
*
See footnote, page R-2
R-7
-------
9-2. B. S. Hopkins, et al., Essentials of General Chemistry, D. C. Heath 8t
Co. , Boston (1946).
9-3. "Ammonia Synthesis from Natural Gas or Naphtha, " Oil and Gas
Journal (12 March 1973).
9-4. Hydrogen and Other Synthetic Fuels, Synthetic Fuel Panel Report
UC-80, Federal Council on Science and Technology (September 1972).
9-5. D. Gregory, "The Hydrogen Economy, " Scientific American 228
(January 1973).
9-6. Liquid Propellant Manual Unit 15, Liquid Propellants Information
Agency, Johns Hopkins University, Silver Springs, Maryland,
(December 1961).
9-7. H. K. Newhall, et al., "Theoretical Performance of Ammonia as a
Gas Turbine Fuel," Society of Automotive Engineers Transactions,
(17-21 October 1966).
9-8. D. T. Pratt,elal., "Gas Turbine Combustion of Ammonia, " Inter-
society Energy Conversion Engineering Conference, 1967.
9-9. E. S. Starkman, et al., "Ammonia as a Diesel Engine Fuel: Theory
and Application, " Society of Automotive Engineers Transactions,
Paper 660768 (1967).
9-10. E. S. Starkman, et aL, "Flame-Propagation Rates in Ammonia-Air
Combustion at High Pressure, " Eleventh Symposium on Combustion,
The Combustion Institute, Pittsburgh, Pennsylvania, 1967.
9-11. H. W. Cremer, et al., Chemical Engineering Practice, Vol. 10,
Academic Press, Inc., New York (I960).
9-12. E. S. Starkman, et al., "Ammonia as a Spark Ignition Engine Fuel:
Theory and Application, " given at Intersociety Energy Conversion
Engineering Conference, 1966.
9-13. Feasibility Study of Alternative Fuels for Automotive Transportation -
Phase I, Esso Research and Engineering Co.; preliminary information
as of September 1973; report to be published.*
9-14. Kirk-Othmer, Encyclopedia of Chemical Technology, Vol. 2, 2nd Ed. ,
John Wiley and Sons, Inc. (1963).
9-15. "1971, A Subpar Year for Chemical Production, But Fibers, Plastics,
Fertilizers Made Gains, " Chemical and Engineering News (5 June
1972).
See footnote, page R-2
R-8
-------
9-16. Oil and Gas Journal (12 March 1973).
9-17. L. W. Westerstrom, "Coal-Bituminous and Lignite, " Minerals
Yearbook (1970).
9-18. Environmental Effects of Producing Electric Power, Joint Committee
on Atomic Energy Congress of the U.S. Hearings, October - November
1969.
9-19. "Coal Gasification; Can it Stage a Comeback," Chemical Engineering
(3 April 1972).
9-20. Cost Engineering in the Process Industries, McGraw-Hill Book Co.,
New York (I960), p. 282.
9-21. R. E. Blanco,et al., "Ammonia Cost and Electricity, " Chemical
Engineering Progress (April 1967).
10-1. Kirk Othmer, "Hydrazine, " Encyclopedia of Chemical Technology,
Vol. 2, 2nd Ed., John Wiley and Sons, pp. 164-196.
10-2. "Hydrazine, " Liquid Propellant Manual, Unit 2, Liquid Propellant
Information Agency (March 1961).
11-1. Breshears, Cotrill, and Rupe, Partial Hydrogen Injection into
Internal Combustion Engines Effect on Emissions and Fuel Economy,
First Symposium on Low Pollution Power Systems Development,
Ann Arbor; Michigan (14-19 October 1973).
11-2. Method and Apparatus for Reducing Engine Exhaust Pollutants, United
States Patent 3,717, 129 (20 February 1973).
11-3. Method and Means for Generating Hydrogen and a Motive Source
Incorporating Same, United States Patent 3, 682, 142 (8 August 1972).
11-4. Marc S. Newkirk and James L. Abel, The Boston Reformed Fuel
Car, International Materials Corp., SAE Paper No. 720670 (2 November
1971).
11-5. S. R. Breshears, "Partial Hydrogen Injection Into Internal Combustion
Engines Effect on Emissions and Fuel Economy, " Project briefing at
Jet Propulsion Laboratory (February 1974).
11-6. "Siemens Catalytic Carburetor Gives Cleaner Exhaust, " Popular
Science Magazine, pp. 76-77 (December 1973).
11-7. Machine Design, p. 42 (9 April 1973).
1U8. ,Personal communication with JPL personnel.
R-9
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11-9. R. F. Stebar and F. B. Parks, "Emission Control with Lean
Operation Using Hydrogen Supplemented Fuel, " SAE Paper No.
740187, General Motors Research Laboratories (25 February •
1 March 1974).
11-10. "Los Angeles Traffic Pattern Survey," Vehicle Emission SAE
Progress Series 617, Macmillan Co. (1964).
R-10
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REPORT NO.
EPA-460/3-74-013-C
TECHNICAL REPORT DATA
(Please read Imlruc lions on the reverse before com/tiding)
2.
TITLE AND SUBTITLE
Current Status of Alternative Automotive Power
Systems and Fuels
Volume III - Alternative Nonpetroleum-Based Fuels
6. PERFORMING ORGANIZATION CODE
). RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
July 1974
,AUTHOR(S)D> E> Lapedes, M. G. Hinton, J. Meltzer,
T. lura, E. Blond, L. Forrest, O. Hamberg,
T.nm A. Mnrasy.pw,
"
Whifrp F!.
8. PERFORMING ORGANIZATION REPORT NO.
ATR-74(7325)-l, Vol. in
9. PERFORM
ORGANIZATION NAME AND ADORES
The Environmental Programs Group
Environment and Urban Division
The Aerospace Corporation
El Segundo, Calif. 90245
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-01-0417
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
13. TYPE OF. REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
A summarization has been made of the available nonproprietary information on
the technological status of automotive power systems which are alternatives to the
conventional internal combustion engine, and the technological status of non-
petroleum-based fuels derived from domestic sources which may have application
to future automotive vehicles. The material presented is based principally upon
the results of research and technology activities sponsored under the Alternative
Automotive Power Systems Program which was originated in 1970. Supplementary
data are included from programs sponsored by other government agencies and by
private industry. The results of the study are presented in four volumes; this
volume presents available information pertaining to alternative nonpetroleum-based
automotive fuels.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDEDTERMS
Automotive Nonpetroleum-Based Fuels,
Synthetic Gasoline and Distillate
Hydrocarbons, Methanol, Methane,
Propane and Butane, Ethanol, Hydrogen,
Ammonia, Hydrazine, Fuels Reformed
On-Board Vehicle
Characterization,
Production Processes
Engine/Vehicle Compatibility
Technology Status
Domestic Resources
Consumer Costs
Capital Costs
COSATl Field/Group
3-DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS
Unclassified
ri'j Report)
380
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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