EPA-460/3-74-009-b
June 1974
FEASIBILITY STUDY
OF ALTERNATIVE FUELS
FOR AUTOMOTIVE
TRANSPORTATION
VOLUME II - TECHNICAL SECTION
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
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EPA-460/3-74-009-b
FEASIBILITY STUDY
OF ALTERNATIVE FUELS
FOR AUTOMOTIVE TRANSPORTATION
VOLUME II - TECHNICAL SECTION
Prepared by
F. H. Kant, R. P. Cahn, A. R. Cunningham,
M. H. Farmer, W. Herbst, and E. H. Manny
Exxon Research and Engineering Co.
P.O. Box 45
Linden, New Jersey 07036
Contract No. 68-01-2112
EPA Project Officer:
C. E. Pax
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
June 1974
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This report is issued by the Environmental Protection Agency to report technical
data of interest to a limited number of readers. Copies are available free of charge
to Federal employees, current contractors and grantees, and nonprofit organizations
as supplies permit - from the Air Pollution Technical Information Center, Environ-
mental Protection Agency, Research Triangle Park, North Carolina 27711; or may be
obtained, for a fee, 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 Exxon
Research and Engineering Co. in fulfillment of Contract No. 68-01-2112 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~460/3-74-009-b
11
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TABLE OF CONTENTS
1. SUMMARY AND HIGHLIGHTS 1
1.1 Summary --------------------------- 1
1.2 Highlights 5
2. OBJECTIVES OF STUDY AND APPROACH 20
2.1 Objectives -__ ______ 20
2.2 Approach 21
3. BACKGROUND AREAS 22
3.1 Introduction 22
3.2 Relationship to Energy Supply/Demand in General ------- 22
3.3 Future Demand for Automotive Fuels ------------- 23
3.4 Domestic Resource Base ------------------- 24
3.4.1 U.S. Coal Resources 25
3.4.2 U.S. Oil Shale Resources 25
3.4.3 U.S. Petroleum Resources 25
3.4.4 U.S. Natural Gas Resources --- _____ 27
3.4.5 U.S. Nuclear Energy Resources ------------ 27
3.5 Build-up of Synthetic Fuels Capacity 27
3.6 Criteria for Fuel Selection 28
3.6.1 Economic Criteria -_- ____ __ 28
3.6.2 Technical Criteria 29
3.6.3 Performance Criteria 30
3.6.4 Strategic Criteria 31
4. SELECTION OF FUELS FOR IN-DEPTH ANALYSIS 32
4.1 Initial List of Fuels 32
4.2 Physical and Chemical Properties ___ 33
4.2.1 Combustion Properties 33
4.2.2 Vehicular Storage Requirements of Fuels ---_-_- 37
4.2.3 Bulk Handling and Storage of Fuels 40
4.2.4 Automotive Maintenance ---------------- 44
4.2.5 Data Gaps 44
4.3 Cost of Manufacture and Distribution ------------ 47
4.4 Fuel-Vehicle Compatibility 56
4.4.1 Modifications Required to Achieve
Fuel/Vehicle Compatibility 57
111
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4.5 Environmental Effects 66
4.5.1 Resource Production ------__-___-_--- 66
4.5.2 Manufacture and Distribution ------------- 68
4.5.3 Exhaust Emissions ------__________-- 69
4.6 Toxicity and Safety 75
4.6.1 Toxicity 75
4.6.2 Safety 80
4.7 Ranking of Fuels -------_______-__----- 81
5. COST OF AUTOMOTIVE FUELS BASED ON COAL AND SHALE 86
5.1 Fuels From Oil Shale 86
5.1.1 Mining 86
5.1.2 Crushing >- 87
5.1.3 Retorting 87
5.1.4 Shale Oil Upgrading 94
5.1.5 Water Requirements 97
5.1.6 Economics of Syncrude Production ----------- 97
5.1.7 Shale Syncrude Refining _-_ 104
5.1.8 Distribution and Marketing 108
5.1.9 Cost Projections: 1982-2000 113
5.2 Hydrocarbon Fuels From Coal ----------------- 114
5.2.1 Coal Mining 114
5.2.2 Coal Liquefaction 117
5.2.2.1 Pyrolysis 118
5.2.2.2 Hydrogenation _-- 113
5.2.2.3 Fischer/Tropsch 122
5.2.3 Economics of Syncrude Manufacture From Coal ----- 123
5.2.3.1 Process Selection and Economic Bases - - - - 123
5.2.3.2 Investments and Operating Costs - - - 127
5.2.4 Syncrude Refining 132
5.2.5 Distribution and Marketing 133
5.2.6 Cost Projections: 1982-2000 133
5.3 Methanol From Coal 134
5.3.1 Process Description ----------------- 134
5.3.2 Economic Basis 140
5.3.3 Cost of Methanol Manufacture ------------- 149
5.3.4 Economic Sensitivities 152
5.3.5 Distribution and Marketing 152
5.3.6 Cost Projections: 1982-2000 157
5.4 Comparison of Costs --- ________________ 157
5.5 User Economics _-__------------------- 162
IV
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6. PERFORMANCE OF FUELS BASED ON COAL AND SHALE 167
6.1 Performance of Gasolines and
Distillates From Shale and Coal --- ____ __ 167
6.1.1 Coal and Shale Gasolines --------------- 167
6.1.2 Coal and Shale Distillates 173
6.2 Performance of Methanol and
Methanol/Gasoline Blends ------------------ 175
6.2.1 Methanol 175
6.2.2 Methanol/Gasoline Blends ______ _ 175
7. EVOLUTIONARY CONSIDERATIONS 189
7.1 The New Engine/New Fuel Dilemma --- - ______ 139
7.2 The Compatibility Scenario 190
7.3 Automotive Fuel Blends ------------------- 191
7.4 Automotive Distillate Fuels ---- ____ ___ 193
7.4.1 Automotive Diesel Fuel _____ _ _ 193
7.4.2 Other Automotive Distillate Fuels ----- ___ 194
7.5 The Fleet Account Stratagem _______ 195
7.6 Automotive Hydrogen _---------__-_------_ 196
7.7 Labor Force Requirements and Implications ---------- 197
7.8 Capital Availability and Investment Implications ------ 199
8. INFORMATION GAPS 201
8.1 Research Data Gaps --------------------- 201
8.1.1 Fuels From Shale Oil 201
8.1.1.1 Mining and Retorting -___ 201
8.1.1.2 Upgrading and Refining 202
8.1.1.3 Use 202
8.1.2 Hydrocarbon Fuels From Coal 203
8.1.2.1 Mining 203
8.1.2.2 Upgrading and Refining 203
8.1.2.3 Use 204
8.1.3 Methanol From Coal 205
8.1.3.1 Manufacture 205
8.1.3.2 Distribution and Use 205
8.2 Other Information Gaps --- _______ ___ 206
9. CONCLUSIONS 207
10. REFERENCES 211
11. GLOSSARY 222
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FOREWORD
For convenience, the material covered in this report is divided
into three volumes. Volume I is an executive summary comprising the re-
port summary, highlights of the various sections and a list of conclusions,
Volume II is the technical section, which is a complete description of the
work carried out under this contract. It includes the sections bound sep-
arately in Volume I. Volume III includes the appendices, which deal with
supplementary material for some of the topics discussed in Volume II.
Vll
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1.1 SUMMARY
This study identifies feasible and practical alternatives to
automotive fuels derived from petroleum for the 1975-2000 time period.
The alternative fuels are liquids derived from domestic coal and oil
shale — specifically, gasolines, distillates, and methanol. While many
uncertainties remain, initial production of the new fuels is likely within
the next five to seven years.
The United States has vast resources of coal and oil shale, suf-
ficient to permit large scale production of synthetic fuels. However,
other factors such as the availability of skilled manpower and water are
expected to constrain the rate at which the resources can be developed.
Complete replacement of petroleum with synthetic fuels is therefore im-
probable until after the turn of the century. Rather, it appears that
the alternative fuels will begin to be used in conjunction with petroleum,
that usage will expand as availability increases, and that the approach to
complete replacement will be evolutionary.
The study shows that there is an excellent chance of developing
alternative automotive fuels, or blending components, that can take ad-
vantage of the existing distribution and marketing system for automotive
fuels. Additionally, the new products may satisfy the fuel requirements
of conventional vehicles as well as the anticipated needs of several types
of automotive power plants now under development. Not surprisingly, fuels
similar to petroleum, derivable from both coal and oil shale, present the
least difficulty and uncertainty.
While differing in estimated cost, the individual fuels examined
in detail may all be producible at a cost level or range projected for petro-
leum fuels. Indeed, the shale fuels may be significantly lower in cost.
Nevertheless, the estimates of cost are sensitive to more than technological
uncertainties. For example, costs are sensitive to assumptions that concern
inherently unpredictable matters such as surface mining legislation, leasing
policy, and required level of investment return.
Early in 1974 consumption of automotive fuel was just over six
million barrels/day (MMB/D) or 12 x 1015 BTU/year, and this may be taken
as a lower bound of future consumption. Upper limits are estimated to be
about 9.5 MMB/D or 19 x 1Q15 BTU/year in 1985 and 12.5 MMB/D or 25 x 1015
BTU/year in the year 2000. The total output of synthetic fuels, for all
purposes, including automotive fuels, could reach 25 x 1Q15 BTU/year by
the year 2000, but will only be about 4 x 1015 BTU/year in 1985, which is
about a third of the minimum projected automotive fuel demand.
Fuels were screened on the basis of economic, technical, and per-
formance criteria, with consideration given to the way in which each new
fuel could be brought into general use. Consideration was also given to
the environmental impact of producing and using the fuels. From a fairly
comprehensive list of initial candidates, feasible and practical alterna-
tive automotive fuels were identified:
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• gasoline-type and distillate-type fuels from
oil shale
• gasoline-type, distillate-type, and methanol
fuels from coal.
Each of these five fuels was then evaluated in detail.
For the shale-derived fuels, the analysis began with mining,
crushing and retorting of the oil shale. The raw shale oil was upgraded,
and then transported by pipeline to a plant capable of converting the
shale syncrude into automotive fuels. The latter were then fed into a
distribution and marketing system, ending at a fuel pump in a service
station. Investment and operating costs were estimated for the entire
system for three points in time: 1982, 1990 and 2000.
The same procedure was applied to the petroleum-type fuels de-
rivable from coal, except that mining was followed by liquefaction rather
than retorting. Methanol from coal was made by gasification, followed by
methanol synthesis. In this case, the methanol product entered the dis-
tribution and marketing system without additional processing steps other
than keeping the fuel dry throughout the system.
Based on 1973 constant dollars, the costs per million BTU esti-
mated for the five fuels were*: (including a 10% discounted cash flow
return on investment)
1982
Shale:
Coal:
gasoline
distilla* e
gasoline
distillate
methanol
$/MMBTU
2.65
2.05
3.35
2.75
3.85
c/Gal.
31.5
26.5
39.5
36.5
22.
1990 2000
- $/MMBTU -
2.60
2.00
3.15
2.50
3.40
2.15
1.65
2.65
2.10
2.95
1973 $, ex tax at pump
Because internally consistent assumptions were used, the cost
estimates are more reliable on a relative rather than on an absolute basis.
However, the differential between the gasoline-type and distillate-type
fuels depends on a "prudent" refining scheme in which the ratio of gasoline
It must be stressed that these are 1973 costs. As of May 1974, costs
for capital projects have escalated substantially in excess of general
inflation.
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to distillate is not less than about 2:1. The shale-derived fuels are
projected to be cheaper than coal-derived fuels over the entire time-
frame of the study. However, the quantitative development of shale oil
will probably be limited environmentally and by other resources, such as
manpower and water, rather than by economics and potential demand.
The ranking of fuels was not changed by consideration of user
economics, i.e., the total cost of vehicle operation as opposed to fuel
cost alone.
Potential product quality problems, related to the aromaticity
of coal-derived fuels on the one hand and the paraffinicity of shale-
derived fuels on the other, can most easily be dealt with by blending
with petroleum fractions, or with each other. Product quality consider-
ations with methanol depend on whether it will be used alone or in gas-
oline blends. In the former case, significant efficiency improvements in
a spark-ignition engine seem possible if the engine is modified. However,
such a modified engine would not be compatible with gasoline fuel.
Methanol appears to be an excellent gas turbine fuel. In partic-
ular, it could find growing application in stationary turbines where bulk
deliveries minimize the relatively high distribution costs of methanol vs.
hydrocarbon fuels. Methanol is also a leading candidate for fuel cells,
used either directly or via reforming to hydrogen.
The use of methanol/gasoline blends in spark-ignition engines
could lead to performance problems due to water sensitivity, vapor lock,
and excessive leaning out of the engine. On the other hand, use of these
blends would result in improved octane quality and could lead to signif-
icant fuel economy savings, in miles/BTU.
The uncertainties about the performance of methanol have to be
resolved before its merits relative to hydrocarbons can be established.
On balance, however, the compatibility of shale and coal hydrocarbons
with petroleum is a key point in favor of these fuels.
There is a critical need for product quality and performance
data on fuels from coal and shale, alone and in blends. This is one of
the research data gaps identified in a separate phase of the study- Other
data or technology gaps include:
- New or improved technology for:
• in-situ recovery of shale oil
• hydrogen production for coal liquefaction
• selective removal of S, N, and 0 from coal and shale
• coal gasification plus methanol synthesis
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- Large-scale demonstration of environmentally acceptable disposal
of spent shale and reclamation of surface-mined coal areas.
General studies dealing with:
• alternative automotive fuels in the context of the entire
economy, based on utilizing all resources including petroleum
• water availability in the Western states
The future availability of capital will have a strong influence
on investment priorities. This is an argument in favor of alternative
fuels, such as shale and coal gasolines and distillates, which are compat-
ible with the existing petroleum-based system. Major investments are be-
ginning to be made in these synthetic fuels. For example, about $450
million was bid on the first four shale tracts recently leased by the
government. Research and development programs on coal liquefaction by
industry and government, including construction of various demonstration
units, will probably total over one billion dollars in the next five years.
Some products of such shale and coal conversion plants will surely find
their way into the automotive fuel market. There is therefore beginning
to be a commercial underpinning of the technological and economic feasibil-
ity conclusions drawn in this study.
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1.2 HIGHLIGHTS
The highlights that follow reflect the contractor's judgment of
what are the most important points in each of the detailed sections of the
report.
Objectives (2.1)
Identify feasible and practical automotive fuels that are
producible from non-petroleum sources.
- Define the alternative automotive fuels in terms of: when?
how much? at what cost?
Consider safety, toxicity, reliability, compatibility with
different engines, and convenience of use.
Identify R&D and other information gaps.
Approach (2.2)
Select alternative fuels with a reasonable chance of being
feasible and practical within the 1982-2000 time-frame which
is the most important with regard to potentially new fuels.
- Use preliminary screening to permit concentration of effort
on a small number of the most promising fuels to get maximum
information on cost, availability, and performance.
Relationship to Energy Supply/Demand in General (3.2)
- Automotive fuel questions should not be divorced from energy
matters in general.
Detailed analysis of "externalities" is beyond the scope of
the study, but identification and rough quantification of
the most important externalities is possible.
- With some modification, the Department of Interior's energy
forecast of December 1972 may be used quantitatively as an
energy context for alternative automotive fuels.
Automotive Fuel Demand (3.3)
The goals of "Project Independence" probably set upper limits
on automotive fuel consumption of about 9.5 MM B/D in 1985 and
12.5 MM B/D in the year 2000. Consumption of just over 6 MM B/D,
early in 1974, may be taken as a lower limit.
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Domestic Resource Base (3.4)
The principal domestic fossil fuel resources are petroleum,
coal and oil shale. Nuclear energy may facilitate the
utilization of these resources.
Other energy resources can lessen the industrial or stationary
demand for the principal fossil fuel resources, thereby in-
creasing their potential availability for automotive purposes.
U.S. Coal Resources (3.4.1)
The domestic coal resource base is very large and, per se, will
.x^c be the factor that limits the pi^ Auction of synLaetic fuels
for several decades.
Western coal resources, recoverable by surface mining, appear
best suited economically to the production of alternative fuels.
The Federal government controls the mineral rights to much of
the Western coal. This important part of the resource base can-
not be utilized until the coal lands are leased.
U.S. Oil Shale Resources (3.4.2)
The oil shale resource is very large and very important. How-
ever, environmental considerations and other factors such as
water availability are likely to limit the rate at which shale
oil can be produced.
Possible production levels during the next several decades are
more important than the ultimate "reserves" of shale oil.
Government leasing policy will be very important since the
government holds the mineral rights to about 80% of the richer
oil shale properties.
U.S. Petroleum Resources (3.4.3)
- Conventional petroleum supplies for the production of motor fuel
are likely to be available from domestic resources beyond the
year 2000.
- Production of domestic petroleum is likely to be higher in the
1980's than it is today. Even so, synthetic fuels from other
domestic resources will be needed.
U.S. Natural Gas Resources (3.4.4)
- Production of domestic natural gas is also likely to increase,
thereby freeing liquid fuels, such as distillate, from stationary
uses .
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U.S. Nuclear Resources (3.4.5)
- Nuclear electricity capability is behind schedule, and available
capacity will be fully required for satisfaction of conventional
demands for electricity until about 1985.
Eventually, nuclear energy may be applied to the production of
synthetic fuels and, possibly, in the long run to the production
of hydrogen fuel.
Capacity Build-Up (3.5)
- The rate at which resources can be brought into production must
be considered as well as the size of the resource base.
Various constraints on the building of synthetic fuels plants
are expected to limit production in 1985 to products containing
the energy equivalent of about 3.7 x 1015 BTU/yr. This estimate
is for the total of all types of synthetic fuels including what
may be used as automotive fuels. By the year 2000, total output
could reach 25 x 10^5 BTU/yr. These estimates of synthetic fuel
supplied are equivalent to 4.2% and 18% respectively of the total
U.S. energy demand by final consuming sectors as forecast by the
Department of the Interior in 1972.
Criteria for Fuel Selection (3.6)
Economic criteria include the ex. tax cost of fuel at the pump,
the operating cost of the vehicle that would use a particular
fuel, and the implied capital requirements of given fuel/vehicle
systems.
Technical criteria include fuel availability, prudence in re-
source utilization and associated environmental impacts.
Performance criteria include compatibility (i.e., the suitability
of a given fuel for use in a given vehicle), toxicity and safety,
efficiency of fuel use, environmental impact in use, and the con-
venience and acceptability of a given system as perceived by the
user (driver) .
Consideration must also be given to the way in which a new fuel
could be brought into general use, to interactions with the exist-
ing vehicle population and fuel delivery system, and the impact
on availability of resources.
Initial List of Fuels (4.1)
A list of fuels was prepared containing all candidates which
could conceivably become viable automotive fuels by 2000.
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- The list included (1) coal-derived fuels: gasoline, middle
distillate, methanol, higher oxygenated compounds, and hydrogen;
(2) shale-derived fuels: gasoline and middle distillate; (3)
ethanol by fermentation; (4) hydrogen from water; (5) ammonia
from coal or water-based hydrogen, and (6) hydrazine.
Physical and Chemical Properties (4.2)
- A detailed literature search yielded information on the proper-
ties of the above fuel candidates, but indicated that many data
gaps exist. These gaps reflect the fact that the fuels either
have not been available (coal and shale derived hydrocarbons)
or have not been completely evaluated in internal combustion
engines (methanol, hydrogen, ammonia).
- The physical property data were analyzed in terms of their rela-
tion to combustion, storage and handling, automotive maintenance,
and "driveability".
Cost of Manufacture and Distribution (4.3)
- The technology for fuel manufacture was reviewed in order to
choose a basis for estimating manufacturing economics.
- Published information allowed such estimates to be made. Dis-
tribution costs were based on analyzing similarities to, and
differences from, the system presently used for petroleum prod-
ucts .
- The following first generation costs (ex. tax, at the pump) were
estimated in terms of 1973 $/MMBTU (including a 10% DCF return):
Fuel Cost
Gasoline from Shale 2.65
Middle Distillate from Shale 2.05
Gasoline from Coal 3.35
Middle Distillate from Coal 2.75
Methanol from Coal 3.85
Methane from Coal 5.65
Oxygenated Compounds from Coal 4.60
Ethanol by Fermentation 7.10
Hydrogen from Coal 9.90
Hydrogen from Water 10.20
Ammonia 7.65
Hydrazine 20+
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Fuel-Vehicle Compatibility (4.4)
A brief assessment was made of the compatibility of the above
fuels with various engine types including the conventional Otto
cycle, stratified charge, diesel, gas turbine, Stirling, Rankine,
and fuel cell.
- The compatibilities range from high (e.g., for coal and shale
hydrocarbons in all of the engines) to moderate (e.g., alcohols
and methane in Otto cycle engines) to low (e.g., hydrogen in all
engines or ammonia in Otto cycle engines).
Environmental Impact (4.5)
Coal and shale mining will have substantial environmental im-
pacts . In order to keep these to a manageable level, it will
be necessary to (1) permanently revegetate spent shale dispersal
areas with a minimum amount of water, (2) reclaim surface-mined
Western coal lands, (3) plan effectively for the influx of a
large number of people into sparsely populated areas.
- Information is very limited on exhaust emissions for the alter-
nate fuels. Coal and shale-derived hydrocarbons are expected
to result in emissions similar to petroleum fuels.
Toxicity and Safety (4.6)
Hydrazine and ammonia are the most toxic of the fuels examined,
considering skin penetration, inhalation, and ingestion. Methane
and hydrogen are the least toxic. Shale and coal hydrocarbons
and alcohols are intermediate.
Consideration of safety in manufacture, handling, and use indi-
cate that hydrogen, methane, ammonia, and hydrazine present the
most serious problems. Shale and coal gasolines, as well as
methanol, are safer to handle. Shale and coal distillates and
ethanol are the safest of the fuels considered.
Ranking of Fuels (4.7)
- The fuels were ranked using the criteria described in Section 3.5,
- The following five fuels were judged most promising and were ex-
amined in detail:
(1) gasoline from shale
(2) distillate from shale (as coproduct with gasoline)
(3) gasoline from coal
(4) distillate from coal (as coproduct with gasoline)
(5) methanol from coal
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Cost of Automotive Fuels From Shale Oil (5.1)
Economic estimates were prepared for manufacturing gasoline and
distillates from shale using the following sequence:
(1) mining and crushing.
(2) retorting, using the TOSCO design based on recycled
hot solids.
(3) upgrading of raw shale oil to high quality syncrude
by hydrogenation and coking at the mining site.
(4) pipelining of syncrude to a refinery.
(5) refining of syncrude to gasoline and distillates by
conventional processes, such as catalytic cracking
and reforming.
(6) distribution of products the same as for petroleum.
- The economics for steps (1), (2), and (3) were adapted from
those prepared by the National Petroleum Council (NPC) , adjusted
to the bases used in this study.
The following costs in 1973 $, were estimated for the period
1982/1985 (including a 10% DCF return):
Shale Syncrude: ca. $5.50/Bbl (includes value of lease
bonus payment). The sensitivity of syncrude cost to in-
vestment level, rate of return, and oil content of shale
was calculated, e.g., with a 15% DCF return the syncrude
would cost $7.05/Bbl and would result in proportionate
increases in gasoline and distillate costs.
Shale Gasoline: $2.70/MMBTU ex. tax at pump.
Shale Distillate: $2.10/MMBTU ex. tax at pump.
- The distillate cost is applicable only to a case where distillate
and gasoline are co-products in the ratio of ca. 1:2.
Cost projections were made for the 1982-2000 period allowing for
effects of new technology (see Section 5.4).
Cost of Hydrocarbon Fuels From Coal (5.2)
- The cost of gasoline and distillate from coal was based on the
following sequence:
(1) Surface-mining of Western coal.
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(2) Hydrogenation at the mine to syncrude using the HRI
"H-Coal" process; other processes were considered but
were rejected on the basis of insufficient available
information; hydrogen was supplied via gasification
(Lurgi process).
(3) Pipelining of syncrude to a refinery.
(4) Refining of syncrude to gasoline and distillate by
conventional processes, such as hydrocracking and
catalytic reforming.
(5) Distribution of products same as for petroleum.
- The following costs were estimated for the period 1982/1985 (1973 $)
Coal Syncrude: ca. $8.00/Bbl, based on $3/ton coal. The
sensitivity of this cost to changes in coal price, invest-
ment, and return level was calculated, e.g., with a 15% DCF
return and $5/ton coal the syncrude would cost $11.40/Bbl.
Coal Gasoline: $3.35/MMBTU ex. tax at pump.
Coal Distillate: $2.75/MMBTU ex. tax at pump.
As with the shale fuel economics, the distillate/gasoline ratio
was ca. 1:2.
Cost projections for the 1982-2000 period reflected changes in
coal price as well as new technology (see Section 5.4).
Cost of Methanol From Coal (5.3)
The cost of methanol from coal was based on coal gasification
with the Lurgi process followed by methanol-synthesis from CO +
H2 • This scheme produces methanol and methane (SNG) as co-
products. Other gasification processes seem to be less effi-
cient for this application, but information on these alternates
was very limited.
Methanol distribution is significantly different from distrib-
uting petroleum products for two reasons:
(1) if used in a 10-15% gasoline blend', blended at the
pump, methanol must be distributed dry to avoid phase
instability.
(2) methanol has about 50% of the energy content of hydro-
carbon fuels, which results in higher distribution costs,
on a BTU basis .
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- The methanol cost at the pump, for the 1982-1985 period, was
estimated at $3.85/MMBTU.
- As with the other fuels, cost projections were made for the
1982-2000 period.
Comparison of Costs (5.4)
From the cost information developed in Sections 5.1-5.3, the
following projections were made:
Shale:
Coal:
gasoline
distillate
gasoline
distillate
methanol
1982
$/MMBTU
2.65
2.05
3.35
2.75
3.85
c/Gal.
31.5
26.5
39.5
36.5
22.0
1990 2000
- $/MMBTU -
2.60
2.00
3.15
2.50
3.40
2.15
1.65
2.65
2.10
2.95
19 73 $, ex tax at pump
Due to the many uncertainties in these estimates, +10% limits
on the costs seem reasonable. Nevertheless, relative costs
are felt to be fairly reliable.
Shale-derived fuels are projected to be cheaper than coal-
derived fuels over the entire time-frame of the study. The
development of shale fuels, however, will not be governed
solely by these economics. It will probably be controlled by
environmental, manpower, and resource limitations.
Methanol is slightly more expensive than coal liquids, reflect-
ing the greater contribution of distribution costs for methanol.
Methanol would therefore be more attractive in applications such
as transportation fleet accounts, or, more generally, in fuel
uses other than transportation.
Distillates are cheaper than gasolines, as long as a prudent
refining scheme is used, in which the two are co-products with
roughly 30-40% distillate.
A comparison among these fuels on the basis of capital intensity
gives the following:
- 12 -
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$/Barrel/Day
Production
of Syncrude Refining Total
Shale
Gasoline 6,700 2,000 8,700
Distillate** 6,500 400 6,900
Coal
Gasoline 11,600 2,600 14,200
Distillate** 12,200 1,300 12,500
Methanol 5,900 (11,800)* 5,900 (11,800)*
* On equivalent BTU basis.
** As co-product with gasoline.
The relative capital intensities parallel the relative costs at
the plant gate.
- Another comparison was made of the relative efficiencies of
manufacturing these fuels:
Energy in Total Product/Total Input Energy
Auto. Fuel Product:
Shale
Coal Hydrocarbons
Methanol
* If Lurgi process by-products cannot be used as process fuel.
- Efficiencies for producing shale fuels are a little lower than
for coal fuels, reflecting losses in shale retorting. Methanol
production is less efficient than coal liquefaction unless the
gasification by-products can be used as a source of process
heat.
User Economics (5.5)
Gasoline
0.55
0.65
Gasoline + Distillate
0.65
0.70
OA ^
. D J
(0.55)*
An attempt was made to compare the cost of owning and operating
a vehicle over its life as a function of fuel type. This was
done by estimating the effect on vehicle weight and cost due to
fuel-connected factors related to compatibility, environmental
effects, toxicity and safety.
- 13 -
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Based on reference data for cost and weight of a 1973 model,
3500 Ib. vehicle, the following comparison was made for the
relative cost of fuel vs. other operating and fixed costs:
10 Year Life, 100,000 Miles
Relative Cost*
Engine
Otto Cycle
Diesel
Gas Turbine
Fuel
Shale Gasoline
Coal Gasoline
Methanol
Shale Distillate
Coal Distillate
Shale Distillate
Coal Distillate
Methanol
^uel
1.0
1.3
1.5
1.0
1.3
ITo
1.3
2.0
0,M,R,Tt
1.2
1.2
1.2
2.6
2.7
1.7
1.7
1.7
Fixed**
2.9
2.9
2.9
6.5
6.7
4.1
4.2
4.2
Total
5.1
5.4
5.6
10.0
10.7
6.8
7.2
7.9
* Reference point for each engine designated by
engines not valid.
t Oil, mainenance, repairs, tires.
** Depreciation, insurance, license, and registration.
comparison among
- The data indicate that, for a given engine type, changes in
relative fuel cost are dampened by other costs unrelated to
fuel, so that total vehicle operating cost is not changed much.
- Another comparison of relative fuel cost per mile for the three
time periods and engine types indicates that these costs parallel
the relative ex. tax pump costs. This reflects the assumption
that, for the fuels examined, engine efficiency is not a signif-
icant function of fuel.
Performance of Gasolines and Distillates From Shale and Coal (6.1)
- High Research octane gasoline fractions based on catalytically
reformed coal and shale syncrude fractions will be quite aro-
matic but no more so than petroleum fractions reformed to the
same Research octane level. Comparable data on Motor octanes
are generally not available for these synthetic fuels.
- Due to the aromatic nature of coal vs. shale syncrude, naphtha
^unreformed) and distillates based mainly on coal will have a
higher aromatics content. If, however, the coal-derived fuels
are blended either with shale or petroleum fractions, as is
likely to be the case, the aromaticities of the blends will be
similar to those in current use.
- 14 -
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If gasolines rich in coal-based fractions are used, consideration
must be given to factors such as:
(1) front-end volatility adjustment.
(2) maximum safe benzene concentration.
(3) materials of construction of the fuel system.
- It should be possible to make a good quality diesel fuel from
shale syncrude. However, more information is needed on cloud
point to determine if it should be reduced — e.g., by the use
of additives.
There are almost no product quality data on distillates from
coal. Based on their composition, however, it is likely that
such fractions will be deficient in cetane number. If this is
confirmed, the options available for correcting the deficiency
are: (1) blending with shale or petroleum fractions (the best
alternative), (2) use of cetane improvers, or (3) more severe
hydrogenation.
- The suitability of coal distillates as a gas turbine fuel has
to be determined. High aromaticity could lead to excessive
flame luminosity and smoking.
Performance of Methanol and Methanol/Gasoline Blends (6.2)
Pure methanol could be an attractive motor fuel for an Otto
cycle engine, based on its high octane number (106 Research and
92 Motor unleaded). It should be possible to operate at in-
creased compression ratio, leading to improvements in thermal
efficiency- However, the vehicle and engine have to be modified
to take account of the low volatility, high heat of vaporization,
and low heat of combustion of methanol. Methanol should be a
very good fuel for continuous combustion engines.
- The use of methanol/gasoline blends brings up a number of po-
tential problem areas :
(1) Water sensitivity: Me thanol/gasoline blends are sus-
ceptible to phase separation in the presence of small
amounts of water. Unless a cost-effective solution is
demonstrated for this problem, it will be necessary to
insure that the customer receives a dry blend. The only
realistic chance for doing this depends on distributing
dry methanol and gasoline separately, and blending at
the pump.
(2) The non-ideality of methanol/hydrocarbon systems results
in excessive gasoline vapor pressure in the presence of
- 15 -
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5-10% methanol. Unless the automotive fuel system is
modified to handle a more volatile blend, methanol ad-
dition requires displacing butanes from gasoline, which
is economically undesirable.
(3) The use of methanol/gasoline blends results in leaner
operation. It is important to determine if such a change
causes any driveability problems.
The use of methanol/gasoline blends could also lead to some
practical benefits :
(1) Very limited data suggest some improvement in fuel econ-
omy, measured in miles/BTU, by blending 15% methanol into
gasoline. More information is required to define fully
the extent of such improvements.
(2) Exhaust emissions can be reduced. The emissions data
can be rationalized by considering changes in air/fuel
ratio. Whether CO, hydrocarbons, or NOX in the exhaust
increase or decrease depends on whether the initial
operation is leaner or richer than stoichiometric.
(3) Methanol is expected to have good octane blending char-
acteristics, but more data are needed on blending octanes
as a function of gasoline pool octane level.
Evolutionary Considerations (7)
It is necessary to see an approach path from the present to a
new condition in the future.
Although a given path may be technically possible, it is not
likely to be followed if easier or better paths are available.
New Engine/New Fuel Dilemma (7.1)
Highway vehicles must be able to obtain suitable fuel wherever
they are driven. The general public will not purchase a vehicle
for which fuel is not readily available. This poses a special
problem in the hypothetical case of introduction of new engine
and fuel products that are not compatible with existing engines
and fuels.
The Compatibility Scenario (7.2)
Full compatibility of new fuels with existing fuels and engines
has numerous advantages. Nationwide distribution of new fuels
can evolve as availability increases, and the transition from
100% petroleum to 100% alternative fuels can be accomplished
without any discontinuity.
- 16 -
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Automotive Fuel Blends (7.3)
- The most likely way that automotive fuels from coal and oil
shale will be marketed will be as blends with petroleum fuels
and, perhaps, with each other, until the early part of the 21st
century.
Automotive Distillate Fuels (7.4)
- There may be both physical limitations and economic penalties
associated with increasing the ratio of distillate-type to
gasoline-type automotive fuels. This will be examined in an
amendment to the contract, and will be covered in a separate
report.
There will be some difficulty in introducing automotive distil-
late fuels other than automotive diesel. Although an introduc-
tory strategy is available, the incentive for using it will
depend on the capacity of the new fuels to improve upon the
cost and performance of diesel fuel.
Fleet Account Stratagem (7.5)
New fuels may be introduced to operators of fleets of commercial
vehicles. This builds operating experience and defers the prob-
lem of how to introduce a new fuel to the general public. The
maximum potential of the fleet market is about 5% of total auto-
motive fuel demand.
Automotive Hydrogen (7.6)
- It is very unlikely that the automotive transportation system
will evolve of its own accord in the direction of using hydrogen
as a fuel for private vehicles before the year 2000.
Labor Force Requirements and Implications (7.7)
Through 1985, it seems likely that the manpower needed to design
and construct synthetic fuel plants will be a limiting factor.
Longer range, beyond 1990, the balance of natural resources in
the Mountain states may be the limitation. Richness in mineral
resources may not be adequately matched by water availability
for all of the demands, direct and indirect, of a rapidly growing
synthetic fuels industry -
Capital Availability and Investment Implications (7.8)
- Capital availability will set investment priorities; unnecessary
investments will be avoided. One implication is that the exist-
ing distribution and marketing system will not be duplicated to
- 17 -
-------
permit the introduction of fuels not compatible with the exist-
ing system — since new compatible fuels can accomplish the
same objective at lower cost.
Research Data Gaps (8.1)
- Research data gaps were classified according to fuel type.
Fuels From Shale Oil (8.1.1)
- The disposal of spent shale in an environmentally acceptable way
has to be demonstrated for a commercial-scale operation.
In situ retorting of shale is very important to large scale
growth of shale oil production beyond the 1985-1990 period. An
efficient, environmentally acceptable process has to be developed.
Alternatives should be developed to severe mine-mouth upgrading
of raw shale oil to syncrude. One possibility involves mild
treatment with heat and/or hydrogen to make it pumpable to a
remote refining site.
- A complete spectrum of product quality and engine/vehicle per-
formance data is required, for shale oil gasoline and distillate
fractions alone and in blends with petroleum or coal-derived
materials.
Hydrocarbon Fuels From Coal (8.1.2)
- The permanent reclamation of surface-mined land has to be demon-
strated on a large scale.
- Long range, there is a need for an underground coal liquefaction
process, as an alternate to underground mining.
More efficient methods are needed to generate hydrogen from coal
for use in hydrogenation processes.
- Liquefaction processes must be improved to give more selective
molecular weight reduction with the minimum hydrogen consumption
— e.g., by developing better catalysts.
Coal syncrude refining has to be demonstrated with feedstocks
from a variety of different coals to give fuel products with
acceptable sulfur, nitrogen, and oxygen content.
- The Fischer/Tropsch process could be an interesting candidate
for coal liquids if the selectivity and thermal efficiency of
the process were substantially improved.
- Complete product quality and performance data are required for
coal gasoline and distillate fractions alone or in blends with
petroleum or shale-derived materials.
- 18 -
-------
Methanol From Coal (8.1.3)
- Improved coal gasification technology is needed to produce the
CO + H2 for methanol synthesis.
The methanol synthesis reaction could be improved by a more
active catalyst (lower temperature and/or pressure) and by the
development of selective techniques for separating methanol
from unreacted CO + H2.
- With regard to methanol/gasoline blends, complete information
is needed on water sensitivity, volatility, corrosion, exhaust
emissions, fuel economy and driveability -
- With pure methanol fuel, data are needed on the maximum effi-
ciency improvement possible with various engines, making use
of the desirable combustion properties of methanol.
- Methanol is potentially an important fuel cell fuel. Impurity
effects have to be defined both for direct fuel cell use and
as a feedstock to a reformer for fuel cell hydrogen.
Other Information Gaps (8.2)^
- Automotive fuel alternatives must be considered in the context
of the economy as a whole.
- The future availability of water in the coal and shale regions
of the West requires a careful study. This study should be
part of a broader assessment of the the impact of coal and shale
mining and conversion industries in sparsely populated areas.
- On-going studies should address the proper utilization of all
domestic resources including petroleum.
- 19 -
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2. OBJECTIVES OF STUDY AND APPROACH
2.1 Objectives
Almost all of the nation's highway vehicles use petroleum
fuels. However, a substantial and growing fraction of the petroleum is
imported, thereby making the nation's highway transportation system
subject to constraints that would not apply if all of the fuel needed
were to be produced from domestic resources. It is questionable whether
domestic petroleum alone can ever satisfy the entire demand for
transportation fuels as well as the many other demands filled by
petroleum products. Certainly, this is not a possibility now, not for
many years, and perhaps never. Therefore, the principal objective of
this study is to identify feasible and practical alternative fuels
(i.e., non-petroleum fuels) that may be derived from domestic sources
other than petroleum.
Feasibility means much more than the technical feasibility of
producing enough of an alternative fuel to permit some test vehicles to
be driven about. Thus, additional objectives of the study nrc to
identify when?, how much?- and at what cost? for each of the alternative
fuel possibilities that were not eliminated during preliminary consid-
deration of these and other parameters. Particular attention is paid to
the 1985-2000 time-frame for two reasons;
- a significant amount of synthetic fuel manufacturing
capacity cannot be in operation much before 1985.
- uncertainty about the validity of basic assumptions in-
creases with time, e.g., the automotive fuel situation in
the year 2020 begs the question of whether there will then
be automobiles as we know them today. It is the "system"
rather than the fuel that becomes the principal variable in
the distant future.
Hence, the 1985-2000 time-frame is the period during which it is most
reasonable to assume that there may be both a supply of, and demand for,
alternative automotive fuels.
The practicality of an alternative fuel relates to the way it
would be used by the general public and to any problems that could occur
throughout the entire system of distribution, storage, and actual high-
way performance. Here, the objective of the study is to assess
properties such as safety, toxicity, reliability, compatibility with
different prime movers, and convenience of use under a wide variety of
operating conditions.
A further objective is to identify technology gaps of two
different kinds;
- uncertainties about specific and critical aspects of the
- 20 -
-------
processing or performance of the alternative fuels selected
for detailed examination.
- areas offering a scientific challenge, such that a break-
through with new technology could significantly improve the
feasibility or practicality of a particular fuel.
A parallel objective is to identify other gaps in information
or other factors of apparent consequence to the development of alterna-
tive automotive fuels.
Lastly, an objective is to present the results of the study in
a way that will facilitate its use and implementation. This requires
conciseness and intelligibility, and the finding of a middle ground
between oversimplification and excessive detail.
2.2 Approach
Anything that will burn is potentially an automotive fuel. In-
deed, dozens of combustible materials have been suggested as automotive
fuels. More often than not such suggestions have been made with little
regard for cost or practical feasibility.
The first step in this study was to select alternative fuels
with a reasonable chance of being feasible and practical within the key
1985-2000 time-frame from the long list of combustible materials that
could be used to power vehicles if practicality were not an issue. Cost,
potential availability, compatibility with engines likely to be avail-
able in 1985, physical properties, safety and toxicity were among the
criteria used for screening as discussed in Section 3.6. An unsatisfac-
tory rating on a relative or an absolute basis was sufficient reason for
eliminating a given fuel unless there was reason to believe that the
deficiency could be overcome within the foreseeable future.
The detailed criteria for selecting (or rejecting) alternative
fuels are given later in the report. However, the preliminary screening
approach enabled much more time to be devoted to evaluation of the five
candidate fuels that were selected than would have been the case if the
same total amount of effort had been spent on evaluating a much larger
number of possibilities.
The selective approach permitted concentration on cost,
availability, and performance which are the factors that will ultimately
determine whether a potential alternative fuel reaches the market place
in significant quantities and, hence, will have a real impact on the
nation's supply of transportation fuels.
The evaluation of cost, availability, and performance re-
quired assessment of technology already available or under development
and also assessment of apparent gaps that will have to be filled by
research.
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3. BACKGROUND CONSIDERATIONS
3.1 Introduction
This brief section is dedicated mainly to a summary of some
pertinent background information on energy supply/demand, automotive fuel
demand, and extent of the resource base. Its location at this particular
point in the report is to provide a simple, general framework before turn-
ing to a technical/economic analysis of specific alternative fuel candidates.
Most readers may not want to plough through lengthy discussions of
background. In order to accommodate them, the treatment in this section of
the report- is minimal. Others, however, may be very interested in background
considerations and may feel (as the contractor does) that the validity of
the conclusions depends in large measure on the way that such matters have
been recognized and treated in the study. These readers are referred to
the Appendices in Volume 3. The Appendices contain two different types of
information:
(a) Detailed calculation and analysis that directly support
different sections of the text in Volume 2.
(b) Speculations and incomplete analyses that are intended to
flag controversial points or issues that cannot be resolved
within the scope of this study but may be investigated
subsequently.
After the present study was begun, the Environmental Protection
Agency issued a Request for Proposal (CI 74-0142 of 2/26/74) titled
"Impact Study on the Use of Alternative Fuels for Automotive Transportation".
Thus, it is probable that many of the issues touched on in item (b) above
will be analyzed in detail in the impact study. Nevertheless, it is nec-
essary to record what was done in the present study, and also to make it
clear that the contractor recognizes the incompleteness of such efforts.
3.2 Relationship to Energy Supply/Demand in General
Automotive fuel needs, supplies, and alternatives cannot be
adequately assessed in isolation from energy supplies and demands in general.
Quantification of the latter is outside the scope of this study, yet a
framework is needed so that the calculations and estimates for alternative
automotive fuels may be related to broader energy perspectives. A practical,
although imperfect, approach to this problem is built on three postulates:
(1) The technical feasibility of alternative automotive fuels
may be studied separately from energy supply/demand in general, but the
results of the study must be qualified by recognition that the actual
development of such automotive fuels will be influenced greatly by what
occurs in the entire area of energy supply and use.
- 22 -
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(2) Within the practical scope of the alternative automotive
fuels study, it is possible only to indicate relationships between such
fuels with what may be controlling "externalities"*; quantification of the
interactions is not possible.
(3) Plausible projections of some "externalities" can be made,
but it should be understood that the purpose is merely to give the reader
one frame of reference within which to consider the specific findings of
the automotive fuels study.**
3.3 Future Demand for Automotive Fuels
Early in 1974, constrained by the Arab oil embargo, U.S. auto-
motive fuel consumption approximated 6 MMB/D. Currently, with the embargo
removed but with some conservation practices in effect, consumption is at
least 10% higher. Part of the increase is due to the normal seasonal
increase in demand***. The difficulties experienced earlier in the year
have encouraged many ideas or proposals concerning ways in which fuel demand
may be reduced while still providing adequate transportation services. It
is anticipated that evaluation of possible ways of conserving transportation
fuel and, thereby, arriving at different levels of future demand will be
undertaken in the impact study referred to above. For the present purpose,
it is assumed that demand will be in the range of 6 to 12.5 MMB/D during
the 1985-2000 time-frame. A rationalization of this assumption is given
in Appendix 1. The present purpose is to provide a semiquantitative indi-
cation of the size of the target that alternative automotive fuels should
address. The lower bound assumed (6 MMB/D) is consistent with a continua-
tion of the present trend to smaller cars combined with other ways of im-
proving efficiency and conserving fuel. The upper bound (12.5 MMB/D) is a
judgment of the approximate maximum automotive fuel consumption that will
be possible if the U.S. is to achieve the goals of "Project Independence".
* The term "exogenous variables" has been avoided since synthetic
fuels are expected both to affect and be affected by many other
factors, i.e., most of the variables are interdependent rather
than being classifiable as independent or dependent.
** Readers are not asked to accept the projections of "externali-
ties" made in this report. Indeed, it is hoped that the study
will elicit or lead to alternative and more precise projections.
Nevertheless, it does seem necessary to provide a framework that
can be used by those readers who do not wish to extend the study.
*** The peak is usually in August.
- 23 -
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3.4 Domestic Resource Base
The quantitative potential for manufacturing synthetic fuels
from domestic resources depends on the resource base. Four points may be
made by way of introduction:
(1) The resource base is the same whether considered from the
standpoint of automotive fuels or of energy supplies in general.
(2) With the partial exception of petroleum, domestic energy
resources are limited less by their physical extent than by the time and
incentives required to develop them and also by environmental and other
constraints to such development.
(3) The principal domestic fossil fuel resources are petroleum,
coal, and oil shale. Until the end of the century, the principal other
sources of energy are nuclear, hydro, and geothermal. Other resources
(tidal power, wind power, wood, agricultural waste, garbage, solar energy)
are small in extent, limited geographically or logistically, or many years
from commercial development. Each has its merits, but none is likely to
become a general source of automotive fuels. It is more likely that utiliz-
ation of such energy sources will lessen the industrial or stationary
demand for one or more of the principal resources thereby increasing the
potential availability of the latter for automotive uses.
(4) Domestic, as distinct from Canadian, tar sands do not
appear to be a promising source of synthetic fuels (3-1, pp. 225-226).
Hence, this review is confined to coal, oil shale, and petroleum
(oil and gas) as fossil fuel resources. In addition, nuclear energy is
considered because of its potential for (a) substituting for fossil fuels
in power generation, etc., and (b) producing hydrogen for use in the manu-
facture of synthetic fuels or, per se, as a transportation fuel. These
fossil fuel and nuclear resources are discussed in Appendix 3; only the
briefest of summaries are given in the following subsections. First,
however, it is necessary to interject a comment concerning terminology.
There is widespread ambiguity in the use, and misuse, of terms such as
"resources" and "reserves". Addressing the Eastern Section of the American
Association of Petroleum Geologists in April 1974 (3-2), Dr. Thomas V.
Falkie, Director of the Bureau of Mines, said that it had been agreed with
the Geological Survey that:
"Reserves are that portion of the identified resource from which
a usable mineral or energy commodity can be economically and
legally extracted at the time of determination".
"...The definition aims at making it clear that any reserve
figure is a dependent variable—dependent on many things includ-
ing prices and legal restraints of all kinds. In fact, it is so
hard to assign fixed values to those controlling variables that
any reserve figure is understood to include a 20% margin of
uncertainty".
- 24 -
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It will be recognized that the qualification of "at the time of
determination" presents a special difficulty with respect to projecting
the level of reserves in the future. In effect, it is first necessary to
quantify all of the legal and economic factors that will affect the recovery
of the particular resource throughout the period of the forecast. To date,
no one has performed this task successfully. Additional discussion will be
found in Appendix 3.
3.4.1 U.S. Coal Resources
(1) The domestic coal resource base is very large.
(2) The potential for Western coal is much larger than implied by
official estimates of "reserves" (which are limited to deposits that have
been mapped and measured).
(3) Much of the Western coal is recoverable by surface mining.
(4) Most of the coal synthetic fuel plants will be based on
Western coal.
(5) Constraints to the development of Western coal resources are
environmental, e.g., water availability, the exact requirements of pending
surface mining legislation, and the Government's approach to additional leas-
ing of coal lands. Initially, manpower and equipment limitations are also
expected to be important.
3.4.2 U.S. Oil Shale Resources
(1) The shale oil resource appears very important in view of its
large size. However, other factors are likely to limit the rate at which shale
oil can be produced. Such limitations are certain initially and, while
potentially removable by new technology (yet to be developed), may remain as
a severe constraint for many years. About 8070 of the richer oil shale deposits
are under Government jurisdiction, hence leasing policy (guided by environ-
mental considerations) will be important. At present, it seems preferable to
discuss shale oil from the standpoint of anticipated or possible production
levels at various times in the future rather than in terms of "reserves".
For example, this study projects that about 400 MB/D of shale syncrude may be
produced in 1985.
(2) The significance of the nation's shale oil resources is mis-
represented when (in terms of hundreds of billions of barrels) they are
claimed to be larger than the proved reserves of petroleum in the Middle
East. Ultimate potential should not be confused with the capability that
can be developed during the next few decades.
3.4.3 U.S. Petroleum Resources
Domestic petroleum resources are a combination of (a) what has
been discovered, and (b) what is estimated to be discoverable in the
future. Proved reserves are estimates of the amount of oil already dis-
covered that is economically and technologically recoverable. For obvious
- 25 -
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FIGURE 3-1
CO
&
3
Q
O
Pi
Oi
Z
1 1
Pi
<:
w
>-"
pi
w
PL,
3
H
P3
O
H
0
< — 1
PLAUSIBLE PROJECTIONS OF U.S. SYNTHETIC FUELS PRODUCTION
10
9
8
7
6
5
4
3
2
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
1 i i l • '
X
s
— •
X •
' SHALE /A
OIL .^x
B' V^ COAL SYN CRUDE -
f ^^r
COAL SYNGAS5"* £
/F
/
i t
/ /
i /
/ *
1 .SHALE OIL AND
/ / COAL SYN CRUDE
• /
r y /
- • »
A •
* /
.' *
r ^
* •*
/ //
/ *A
" I'1
- ///
//'
'•,A
- •/ 1
I 1 COAL SYN CRUDE
SHALE I ,
OIL / *
I I
• A
A
1 1 1 1 1 1
1975 1980 1985 1990 1995
YEAR
*See p. 28 for methanol equivalent.
- 26 -
2000
EPA-460/3-74-009
-------
reasons, existing proved reserves tend to decline as production continues.
Whether production increases, remains the same, or decreases in the future
will depend on the rate at which new oil is discovered. In turn, the dis-
covery rate will depend on a combination of technological/geological and
other factors of considerable political and economic complexity. The
recent trend in domestic production has been downward, but there are
reasons for expecting that a reversal will occur soon and that the level
of production in the 1980's will be higher than it is today.
From a resource standpoint, domestic petroleum is likely to be
available through the first quarter of the 21st century and, hence,
potentially available for automotive use during most of this period. Thus a
probability of significant, even if declining, availability through the
year 2000 is high.
3.4.4 U.S. Natural Gas Resources
Domestic natural gas resources parallel liquid petroleum resources
in extent and with respect to the factors that affect leasing of acreage,
exploration, discovery, production, etc.
Natural gas can substitute for petroleum liquids in most stationary
uses of fuel, thereby affecting the availability of liquid fuels for non-
stationary uses. In addition, natural gas is the source of gas liquids
(NGL) including natural gasoline.
3.4.5 U.S. Nuclear Energy Resources
Technologically, nuclear energy has the potential for replacing
fossil fuel energy in most stationary uses. However, actual replacement
will depend on the rate that nuclear capability is developed. The resource
base appears adequate to support foreseeable energy demand during the next
century and probably beyond. On the other hand, the long lead-time
associated with bringing nuclear capability on line makes it unlikely that
such capacity will be available for application to the production of syn-
thetic or alternative fuels before the mid-1980's. By the year 2000, the
impact may be appreciable and growing fast. However, the complete dis-
placement of fossil fuels by nuclear energy is not a feasible scenario
until well into the 21st century.
3.5 Build-up of Synthetic Fuels Capacity
Quantitatively, the manufacture of synthetic fuels is expected
to depend far more on the rate at which resources can be brought into
production than on the size of the resource base--which is very large.
It is outside the scope of this study to predict the extent to
which the synthetic fuels that are produced will be used for automotive
purposes. However, the projections in Figure 3-1 may be taken as an indi-
cation of the upper limit of such use until the year 2000. The hypo-
thetical upper limit will be set by the total quantity of synthetic fuels
- 27 -
-------
that can be produced. The limit for automotive fuels will be some frac-
tion of this quantity.
The shape of the shale syncrude curve in Figure 3-1 reflects the
concept that shale oil development is likely to occur in phases: (a) the
prototype leasing program and associated developments on privately held
acreage, (b) further leasing of shale lands by the D.O.I, if the prototype
program proves to be environmentally acceptable, and (c) commercialization
of in situ technology by about 1990. The latter technology is still at a
very early stage of development. Hence, there is considerable uncertainty
about the projection of the shale oil curve beyond the approximate level
of 2 x lO1^ BTU/yr.* If shale oil production were to be severely con-
strained, it is possible that greater effort would be applied to the pro-
duction of synthetic fuels from coal.
Arithmetically, the 1 x 1015 BTU point on the coal syngas curve
corresponds to 900 MB/D or 46 MM tons/yr. of methanol.** However, until
the domestic shortage of natural gas is alleviated, it seems likely that
gasification plants will emphasize the production of SNG rather than
methanol. This does not mean that methanol will not be produced, but
rather that the level of production will be much less than the upper
limit implied by the syngas curve in Figure 3-1.
The synthetic fuels industry will be only a part of a much larger
whole. Hence, any factors that have a major impact on any aspect of energy
supply and demand are also likely to have a direct or indirect impact on
synthetic fuels and alternative automotive fuels.
3.6 Criteria for Fuel Selection
Criteria for fuel selection were considered at two different
stages of the study: first in narrowing down the original list of fuels
to the most promising candidates for further analysis and, second, to
assess these remaining fuels in more detail. Following is a list of the
criteria which were used in the study along with some explanatory comments.
3.6.1 Economic Criteria
(1) Cost, ex. tax at the pump.
This is the most direct criterion for comparison although not
easy to calculate. It includes costs of producing the resource, manu-
facturing the fuel, and distributing it to the customer. As discussed in
Sections 4 and 5 of the report, costs estimated in the screening study
usually are revised upon more detailed analysis. There is also an obvious
effect of time, as new and improved technology becomes available. For the
* 2.2 x 10^-5 BTU/yr. is approximately
equivalent to 1 MMB/D of shale syncrude.
** The basis of this conversion is explained in Section 5.3.
It assumes maximum conversion of syngas to methanol.
- 28 -
-------
initial screening, a single time period was considered reflecting mature
technology for the manufacture of each fuel. In the detailed considera-
tion of selected fuels, an effort was made to project changes in costs
through the year 2000.
(2) Operating cost of the vehicle.
It is important to consider the cost of the fuel from the point
of view of the consumer. In this study this was dealt with in a very
perfunctory manner in the initial screening and in somewhat more detail
in the subsequent analysis. In order to do a meaningful comparison of this
type, it is necessary to have fairly reliable fuel economics and an
appreciation of the fuel/vehicle interactions. The latter is important to
make sure that all the significant effects on vehicle weight and cost due
to the fuel are considered.
(3) Capital requirements.
The energy sector of the U.S. economy will require tremendously
large quantities of capital in the future. The manufacture of alternative
transportation fuels is very capital intensive. Different fuels, however,
vary in the distribution of capital intensivity in going from the resource
in the ground to the fuel at the pump. It was decided in the study to
defer comparison of capital requirements until the most promising fuel
candidates had been identified.
3.6.2 Technical Criteria
(1) Technological status, fuel availability.
It is critical to determine when various alternative fuels can
be made generally available. In order to do this, the technology of manu-
facturing these fuels has to be assessed. This assessment also leads to
a definition of technology gaps. The rate at which these can be filled
is important in determining the relative attractiveness of various fuels
at a given point in the future.
(2) Efficiency of resource utilization.
Resources must be used prudently in order to prevent undue
depletion. The overall efficiency of resource utilization comprises a
number of steps including production of the resource, manufacture and
distribution of the fuel, and use of the fuel. The last of these is dealt
with below as part of another criterion. Resource utilization was con-
sidered in the first round screening only if very serious problems were
foreseen for certain fuels. Efficiency of utilization was calculated for
selected fuels in the second part of the study.
- 29 -
-------
(3) Environmental impact.
Protection of the environment is a paramount consideration for
any system of fuel manufacture and use. As in (2) above, environmental
considerations come into play in manufacture, distribution, and use.
Important potential problems were identified in the first round, with
detailed consideration left for the second phase.
3.6.3 Performance Criteria
(1) Compatibility.
The issue of fuel-vehicle compatibility is an extremely complex
one and cannot really be dealt with adequately within the scope of this
contract. In the initial assessment, a qualitative list was prepared of
the modifications required to the engine and the vehicle in order to
handle a given alternative fuel. This analysis considered internal com-
bustion engines, diesel engines, as well as gas turbines and external
combustion engines. In the second phase of the study, the effect of
specific properties of selected fuels on engine and vehicle performance
w'as considered.
(2) Toxicity and safety.
These factors were considered in the initial screening, and in
more detail in the subsequent assessment.
(3) Efficiency of use.
An attempt was made to quantify the efficiency of fuel use in
various engines to allow some discrimination among the candidate fuels in
the initial list. For a given engine, efficiency is measured by fuel
economy, which determines the fuel component of vehicle operating cost.
As mentioned in (2) under 3.4.1, this analysis was carried out for selected
fuels.
(4) Environmental impact in use.
This criterion deals with the problems of exhaust emissions
and vehicle noise. For the initial screening, those fuels are identified
and debited which are expected to lead to major problems in these areas.
In the detailed analysis, potential problem areas were analyzed, including
the economic and technical implications of possible solutions.
(5) Driver acceptability and convenience.
This criterion is very important because, in the final analysis,
the driver rates the fuel-vehicle system on the basis of its performance.
Factors such as stalling, cold starting, acceleration, frequency of
maintenance, etc., are related to properties of the fuel and the perform-
ance of the engine. As with the above criteria, a simple subjective
rating was considered in the initial screening with a more careful analysis
in the second phase of the study.
- 30 -
-------
3.6.4 Strategic Criteria
(1) Vehicle shift compatibility and entry strategy.
This criterion considers how a new fuel would be brought into
general use. The ease with which this transition can be made depends on
the compatibility of the fuel with both existing fuels and engines. A
qualitative ranking is given on this basis in the initial screening. A
detailed appraisal for the preferred fuels includes estimates of capacity
buildup and the feasibility of using blends of the fuel with existing
fuels.
(2) Resource availability.
The feasibility of different fuels depends on the availability
of the resources required for their production (as indicated in Section
3.4). Various types of constraints were considered: land and water
availability; environmental impacts; capital, manpower and materials
limitations.
- 31 -
-------
4. SELECTION OF FUELS FOR IN-DEPTH ANALYSIS
4.1 Initial List of Fuels
The following group of fuels was selected for initial consid-
eration :
1. Coal derived fuels:
Gasoline
Middle Distillate*
Methanol
Oxygenated Compounds
Hydrogen
2. Shale derived fuels:
• Gasoline
• Middle Distillate
3. Ethanol via fermentation of plant products
4. Hydrogen from water by electrolysis
5. Ammonia using hydrogen from coal or water electrolysis
6. Hydrazine from ammonia
It would have been possible to make the above list substantially
larger by including a variety of materials that could conceivably be
burned in present or projected automotive power plants. However, the
judgment was made that the initial list be restricted to a manageable
number by considering only those fuels whose general properties and poten-
tial availability might make them viable candidates to supply a substan-
tial fraction of the automotive fuel demand. By this criterion, hydrazine
is a questionable candidate simply because of the lack of a large-scale
synthesis process, as will be mentioned later. It was included because
of its potential use in fuel cells.
Also, the list avoids duplication of the same fuels from dif-
ferent sources where this does not seem practical. For example, methanol
can be made by fermentation, starting from carbohydrates, or by the
destructive distillation of wood. However, the most cursory analysis
quickly indicates that neither of these methods can reasonably compete
with a large-scale production based on coal. Similarly, it is possible
to derive either hydrogen or methanol from shale oil. In this case, it
would be very wasteful to convert the shale oil to carbon monoxide and
hydrogen, the necessary first step in such a process. On the other hand,
this concept is compatible with the projected utilization of coal, where
gasification to CO and hydrogen, and then to methane, is already being
developed.
* The glossary at the end of this volume defines a large number of the
specialized terms, abbreviations, etc., used in this report.
- 32 -
-------
Another example involves ethanol from coal via hydration of
ethylene made in coal pyrolysis or Fischer/Tropsch synthesis from CO +
H2• Coal conversion processes are best utilized in preparing mixtures
of oxygenated compounds, which are already on the list. Fermentation
was chosen as the preferred route to reasonably pure ethanol.
In the following discussion, the properties of these fuels, as
well as an estimate of their costs, are compared to allow selection of
the most promising candidates for detailed consideration.
4.2 Physical and Chemical Properties
Experience has shown that many physical and chemical properties
of a fuel influence its performance in the engine, acceptability to the
customer, impact on the environment, and methods of handling and distri-
bution.
In the eyes of the driver, the ideal fuel should permit easy
engine starting at all ambient temperatures, give rapid warm-up and
acceleration, provide quiet trouble-free operation, have good fuel econ-
omy and adequate range between refuelings, keep engine and car mainte-
nance to a minimum, not be unduly hazardous and, of course, be inexpen-
sive. Neither the fuel nor the exhaust should have an objectionable
odor. As mentioned in Section 3.6, environmental impact involves fuel
emissions encountered in handling, storage, and refueling, as well as
the nature and composition of the exhaust emissions. Storage and han-
dling considerations also require that large volumes of the fuel be con-
tained without serious deterioration or loss for periods up to six months
or longer, to move it through pipes, and/or in tankers, barges and tank
trucks, and to dispense and meter it to individual vehicles quickly.
This must be done safely, without serious environmental damage and with-
out significant contamination with water, rust, or dirt.
A discussion of the significance of various fuel properties is
given in Appendix 6. It is evident that the properties of the fuel have
an impact on all the criteria mentioned in Section 3.6. The interrela-
tionship is summarized in Table 4-1. It served as the general basis for
categorizing the property data collected in this study. For example,
Tables 4-2 to 4-5 list fuel properties related to combustion behavior,
handling and storage, and automotive maintenance. These tables show
properties for the fuels listed in Section 4.1, and also give typical
values for petroleum gasolines and distillates for comparison. In quite
a few instances, where data were not available, estimates were made,
identified by parentheses around the value.
4.2.1 Combustion Properties
A number of significant observations can be made regarding the
combustion properties of the fuels shown in Table 4-2.
* Appendices are found in Volume III,
- 33 -
-------
TABLE 4-1
RELATION OF FUEL PROPERTIES AND FUNCTIONS
•H .5
iH &
CRITERION OF ^
FUNCTION
Engine Type(a) — *•
FUEL PROPERTY J
Volatility
Initial Boil. Ft'.
502 Di-t •?
Sv;/i lu- t i?
Final Boil. Et»
V.-.POT ?r"sA"
P.-.i.lty
H._ ,-ir or Co.rb. ,BTU/gal
Ociiar.c "o. ^a'
Otar.e No. ('•'
VlscoBjry @ 100°F
'•sh ...
S^luiUi
Vanadium'1*)
Pour Point^d'
Carboa Residue
Flame Speed <•*•'
Sulfur
Corroslvity(-e;
Effect on Plastics^'
Exhaust Emissions^1'
NitroRen
Fuel Odor
ToxicltylB)
Flash Point
Viscosity 9 0°F
Soluhilltv in Water^
Solubility For Water1'1
Emulsion Tendency^"'
StoraEe Stability
Sludee Tendency
'•jbricityU'1
Static Charr.e
Flanmability Limits^ '
Elecfochem. React.
Heat ot Vaporization
ribution
Storage
tD (U ;
•H 3 !
Q h ;
A A
1
H H
M H
K M
JM M
|M M
j
|M M
1 H H
IH H
M M
[M M
I'M M
; M H
M H
M H
M
H M
M H
Fuel Economy
Otto Dies. C.C. F.C.
H H H H
H
MM MM
H
Autinotive Behavior
Engine
Maintenance & Service
Otto IMes. C.-C. F.C.
MUM
HUM
H
(n)
H H H (n)
11 H
M H
MM M (n)
M M (n)
H H H H
H H H H
(n)
(n)
M M M M
H MM M
M M M M
H H (n)
M M (n)
H
Drlveabillty
Otto Dies. C.C. F.C.
H
H H M
H M
M
H H H H
M
H
H
H H
H H H H
M M M
(n)
MM MM
(.n)
M M M
H
M
G a Tt >,
s I & s§
T!13 » B-u
& 5 3
A A A
M
H H H
M
M
M !
M
H M
1
M
M
M
H M
M H
M H
H H H
H H
MM M
H H H _,
H M
M
H
H
M
M
M
M ,
H H
H M
Footnotes:
(a) A All engines
C.C. Continuous conbustlon engine (!•<=•> gas turbine, Ranklne, Stirling)
F.C. Fuel Cell
(b) Code - H Highly important
M - Moderately important
A blank space means property la not Important for the particular function.
(cj It is assumed ti:e car fuel system will be designed to handle the fuel, i.e., avoid •'izcessivu v&^&T lessee or vapor InrV.
(d) Can be improved by additives. However In some cas«s Ce.g., letraethyl lead) these may contribute to air pollution.
(e) Problem; can probably be minimized by Judicious selection of fuel system materials.
(f) Includes unburned fuel (e.g., hydrocarbons), CO, NO*, smoke, participates, polynuclear aromatlcs, odor.
(g) Includes vapor, ingestion, skin. Can probably be mitigated by proper design of equipment and suitable precautions.
(h) Problems may be alleviated by proper design of fuel handling, and storage systems.
(i) Fairly wide range can probably be utilized by suitable adjtsaaent and modification af the engine.
(j) Problems can be alleviated by proper selection of pumps, controls, etc. Fuel properties may be adjusted by use of
proper additives.
(n) The fuel cell is in such an early state of development., it la not possible to define the fuel
requirements with any certainty.
(p) Includes storage on vehicle. - 34 -
EPA-460/3-74-009
-------
TABLE 4-2
Methane Ammonia Hydrazine
Property-!-
Volatility (Boiling Point)
Initial Boil. Pt. °F —
50% off @ °F -423
90% off @ "F
Final Boil. Pt. °F
Vapor Pressure @ 100° F,
psi
Heat of Vap. BTU/Lb @
Normal Boil. Pt. 194
Heat of Combustion (Net)
219
-28
591
236
540
BTU/lb
BTU/gal
Stoichiometric Mix
# Air/# Fuel
BTU/ft3 @ SIP
Vol. air /vol. fuel
Octane No. (No Antiknock
Research
Motor
Cetane No.
Auto Ignition Temp.°F
Max. Flame Speed,
ft/sec
Flammable Limits,
Vol %
Upper
Lower
Kinematic Vis.,77°F,cs
References
(Section 4-)
Footnotes:
51,600
30,600
34.6
85.2
2.38
Add.)
1085
8.7
74
4.1
2,11,
12,17
21,500
80,000
17.3
90.9
9.53
130
105
<0
1004
1.12
15.4
5.0
15,24,
27,29
30,31
8,060 7,294
31,000 61,000
6.1 4.3
83.5 104
3.57 4.76
130
<0
1204
0.034
25 100
16 4.7
0.89
1,2,8, 37,39
9,12,
14
ISTICS RELATED TO COMBUSTION BEHAVIOR^
[ethanol
149
4.6
474
8,640
57,370
6.5
95
7.14
106
92
(10)
878
1.6
37
6.0
0.64
11,12,
41,44
45
Ethanol Oxyg.(c^
(149)
173
(300)
0.28(°) (1)
360 (350)
11,550 (11,500)
76,000 (76,000)
9.0 (9.0)
97 (97)
14.3
106 (105)
89 (90)
(15) (15)
738 (800)
19
3.5
1.39 (1.5)
11,20
42,44
Coal
Gasol .
100
270
360
400
(150)
(18,200)
(114,000)
(13.9)
(105)
(50)
82-98
(75-86)
(0-5)
(1.1)
(8)
(1)
(0.5)
61,62,
122,123,
124,125
126,127
128
Distill.
400
600
(0.01)
(110)
(17,900)
(133,000)
(13.5)
(101)
(101)
—
(40)
(1.1)
(3.0)
122
Shale
Gasol. (d)
148
285
340
411
(150)
(18,200)
(114,000)
(14.8)
(100)
(55)
35-91
( ?-82)
(12)
(900)
(1.1)
(8)
(1)
(0.5)
59,95,
108
Petroleum
Distill.(e) Gasol.
350
550
(0.01)
(110)
(18,300)
(129,000)
(14.5)
(102)
(105)
(40-45)
(500)
(1.1)
(3.0)
60,
108
100
210
330
400
8-12
(150)
18,650
113,500
(14.8)
100
57
86-93
7Z-84
(0-5)
800-950
a.i)
8
1
0.5
12,67,
68
Distill.
375
500
580
620
0.01
(110)
18,400
129,400
(14.5)
102
107
—
48
500
(1.1)
3.0
12,66
(a) @ 77°F.
(b) (3 68°F.
(c) Estimated on basis Fischer/Tropsch oxygenated compounds will consist essentially of
50% ethanol, 20% methanol, 20% propanol and 10% C^ + oxygenates.
(d) From catalytic reforming of hydrogenated naphtha from shale oil.
(e) From hydrogenating crude in situ shale oil.
(f) Blank spaces indicate absence of data.
Dash indicates data Inconsequential.
( ) indicates estimated values.
EPA^460/3-74-009
-------
1. The low boiling points of hydrogen, methane and ammonia
indicate that special equipment will be required to store and handle
these materials. Storage could be either as cryogenic liquids or pres-
surized gases. In either case, there are serious problems in adapting
these fuels to a vehicle. This problem is discussed further below.
2. The relatively low volumetric heat of combustion (BTU/gal.)
of the alcohols, hydrazine, ammonia, methane, and hydrogen is a signifi-
cant disadvantage, in that it will require the storage of relatively
large volumes of these fuels to provide an adequate cruising range for
the vehicle.
3. The relatively high heat of vaporization of the alcohols,
hydrazine, liquid ammonia, liquid methane, and liquid hydrogen, combined
with their low heat content, means that with a carburetted engine,
special pains must be taken to transfer adequate heat to the intake
manifold to vaporize the fuel. For example, it takes eight times as
much heat to provide the same amount of combustion energy in the vapor
form with ammonia as with a conventional gasoline. This is usually
waste heat from the engine (in exhaust or water) and represents no ther-
mal penalty to the engine. This heat exchange problem can be avoided by
injecting the liquid fuel directly into the combustion chamber. However,
fuel injection involves additional cost.
A. The BTU/ft. of a stoichiometric fuel/air mixture relates
to the amount of energy that can be inducted into the combustion chamber
of a carburetted reciprocating piston engine of a given displacement.
The higher this figure, the more power can be produced from a given dis-
placement engine at a given engine speed. This assumes that each fuel
is being burned with an amount of air theoretically required for complete
combustion.
5. The high octane numbers of ammonia, methane, and methanol
are noteworthy. With such fuels it should be possible to design an Otto
cycle engine (high compression ratio) that would have a higher thermal
efficiency than would be possible with the lower octane number fuels.
However, this point will have to be demonstrated with ammonia and
methanol, in view of the hazards of translating experience based on high
octane hydrocarbon fuels to widely different compounds.
6. Apparently the combustion characteristics of hydrogen are
such as to make a rating by the accepted anti-knock methods difficult
since no octane numbers have been published. Single-cylinder engine
combustion studies have indicated (4-17), however, that hydrogen can be
burned in an Otto cycle engine without knock over a compression ratio
range from 6:1 to 16:1 by careful adjustment of spark advance and air/
fuel ratio. At a given compression ratio, say 8:1, combustion behavior
varies as the amount of hydrogen in the air is increased. For example,
a mixture containing less than 0.73 wt. % hydrogen is too lean to burn
and misfire results. Between 0.73 and 1.5 wt. % hydrogen, satisfactory
knock-free operation is achieved. As the amount of hydrogen is increased
- 36 -
-------
above 1.5 wt. %, knock is encountered and continues until the hydrogen
reaches 16 wt. %. From here to the upper flammability limit (25 wt. %)
knock-free operation is again experienced. It should be noted that above
a hydrogen concentration of 2.81 wt-. % (stoichiometric mixture) hydrogen
combustion will be incomplete because of insufficient air. Thus, the
feasible knock-free fuel/air operating range at 8:1 compression ratio,
according to these data, is in the range of 0.73 to 1.5 wt. %. At 16:1
compression ratio, this knock-free "operating window" ranges from 0.75
to 1.0 wt. % hydrogen. Evidently, it will require closer fuel/air ratio
control to operate knock-free with hydrogen at high compression ratios
than at low. However, there is some question about the validity of
these results since knock-free operation over a wide range of fuel/air
ratio has also been reported (4-48,101). Problems of preignition (4-22)
and backfire (4-55) with hydrogen have also been reported. Exhaust gas
recycle has been used to modify and control the combustion of hydrogen
in an Otto cycle engine (4-55)-
7. The Cetane Number of all the fuels in Table 4-2, except for
the distillates from petroleum, shale, or coal, are too low to make them
attractive as fuels for an engine operating on the compression ignition
principle. The use of cetane-improving additives, supplementary sources
of ignition (e.g., a glow plug, pilot-injection, or spark plug), blends
with high-cetane number fractions, or the use of exceptionally high com-
pression ratios (say 22:1) would probably circumvent this problem in
some cases.
8. The high flame speed of hydrogen and the low flame speed
of ammonia are noteworthy. They imply that the optimum engine operating
conditions or design for these fuels will be different than for the more
conventional hydrocarbon fuels.
9. The exceptionally wide flammability limits of hydrogen are
significant. This is the basis of the "Hydrogen Induction Technique"
(4-48,101) method of engine (Otto cycle) operation in which the engine
power is varied by varying hydrogen-air ratio and not by throttling the
fuel/air mixture. In the Hydrogen Induction Technique the amount of air
taken into the combustion chamber on each piston stroke is held constant
(no air throttling) while the amount of hydrogen inducted is increased
for increased power. Higher efficiency is claimed for this method of
operation (4-48). Unfortunately, the wide flammability limits adds to
the hazard of using hydrogen as an automotive fuel.
4.2.2 Vehicular Storage Requirements of Fuels
As pointed out above, the low boiling points of ammonia,
methane, and hydrogen present a problem with regard to the storage of
these fuels in an automobile. The magnitude of this problem is illus-
trated in Table 4-3 comparing the weight and volume of the tank and
fuel required to store 2.27 x 10^ BTU combustion energy (equivalent to
20 gallons of gasoline) with the various fuels under consideration.
- 37 -
-------
TABLE 4-3
VEHICULAR STORAGE REQUIREMENTS OF FUELS
(a)
Basis: Energy Equivalent of 20 gals, gasoline
(2.27 x 106 BTU)
(d)
Fuel Alone
Fuel + Container
Gasoline(b)
112 Diesel Fuel
(c)
H2(g) @ 3000 psi, 80°F
H2(l) @ 1 atmos.
H2 as MgH2(e)
Methane(g) @ 3000 psi, 80°F
Methane(1) @ 1 atmos.
Ammonia(l) @ 80°F
Hydrazine
Methanol
Ethanol
Higher Oxy. Compounds(g)
Ibs.
119
120
43.9
43.9
577
105.5
105.5
284
338
261
195
200
ft. 3
2.59
2.28
40.6
10.2
6.6
12.40
4.06
7.16
5.40
5.26
3.95
4
Ibs.
134
134
2250*
353*
692*(f)
500
240
455
367
285
214
220
ft. ^
2.76
2.50
*
66 *
10.2
10.8*
27.6
16.1
13. 4>
6.05
5.70
4.78
5
(f)
(a) Based on data from (4-26) except for figures marked (*) which are from (4-70).
(b) This assumed to apply to all gasolines whether from petroleum, coal or shale.
(c) This assumed to apply to all distillate fuels whether from petroleum, coal
or shale.
(d) On 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 diesel
power the above figures would be reduced by 1/3.
(e) Assumes theoretical yield of H?) density MgH- 1.4 gms/ml. (4-58).
(f) Does not include heat exchange means and ancillary equipment to charge and
discharge MgH_.
(g) Estimated on basis that Fischer/Tropsch Oxygenated compounds will consist of
about 50% ethanol, 20% methanol, 20% propanol and about 10% C, + alcohols
(4-53).
- 38 -
EPA-4x50/3-74-009
-------
In automobiles using gasoline or distillate fuels, the fuel
and container will weight 134 Ibs. and occupy 2.5-2.8 cubic feet.
Oxygenated fuels (i.e., methanol, ethanol, and higher oxy compounds) re-
quire heavier and bulkier fuel storage systems, averaging twice as large
and heavy as for gasoline, because of their lower heat content.
Storage problems become more severe with the gaseous fuels.
Ammonia stored as a liquid will require relatively large and heavy tanks
to hold the pressure. With methane and hydrogen, storage as a gas under
pressure (e.g., 3000 psi) requires tanks weighing 370 and 2000 Ibs. more
than current automotive practice. The 2000 Ib. increase is prohibitive
for automotive use.
Methane and hydrogen may also be stored as cryogenic liquids at
atmospheric pressure. This reduces the weight debits (which, however,
are still severe, i.e., 100 Ibs. and 220 Ibs., respectively) but causes
other problems, e.g., cost of the cryogenic storage containers, fuel
losses due to evaporation, and the requirement for safe venting provi-
sions while the vehicle is in the garage.
The practicability of using hydrogen as an automotive fuel, and
to a lesser extent methane, will depend on solving the vehicular fuel
storage problem. In this connection the use of metallic hydrides (4-70)
is receiving considerable attention. As noted in Table 4-3, storing
hydrogen as MgH2 brings the problem to more manageable proportions. The
weight penalty, however, is still 550 Ibs. without considering the heat
exchange means and ancillary equipment required to discharge the hydrogen
from the hydride. Magnesium hydride, however, is probably too stable for
automotive applications. Hydrides currently being studied, such as iron
titanium hydride, have a lower capacity.
If fuel storage requirements are considered on the basis of
equal miles (say 270 miles per tankfull) rather than an equal heat con-
tent, the thermal efficiency (fuel economy) of the vehicle must be con-
sidered. The following is a comparison of the thermal efficiencies
recently reported (4-71) for several power plants over the Federal
Driving Cycle. It is important to point out that efficiency and relative
fuel consumption comparisons are valid only for vehicles operating under
similar power-to-weight ratios. As a first approximation, however, the
efficiency data below can be used to estimate relative fuel storage re-
quirements on an equal mileage basis:
- 39 -
-------
Thermal Efficiency Over the Federal Driving Cycle (4-71)
Power Plants
1973 Internal Combustion Engine (ICE)
(Avg.)
Wankel (Mazda)
Dual-Chamber Stratified Charge (Honda)
Stratified Charge (Texaco)
Stratified Charge (Ford)
Diesel (Mercedes Benz)
ICE - Hydrogen Induct. Technique
Thermal Efficiency
Relative
to I.C.E.**
1.00
0.74
0.85
0.92
1.18
1.72
1.45 est.*
9.5
7.0
8.0
8.7
11.2
16.5
14 est.*
* From data in (4-48).
** Inverse of relative fuel consumption,
4.2.3 Bulk Handling and Storage of Fuels
Table 4-4 lists the characteristics related to the handling and
bulk storage of the fuels. Following are some observations regarding this
table:
1. The high freezing point of hydrazine (36°F) indicates that
special means would be required to keep it liquid in automotive and stor-
age tanks in many areas of the United States at various times of the year.
One solution to this problem may be to use it mixed with unsymmetrical
dimethyl hydrazines (freezing point ca. -71°F).
2. The water-miscibility of hydrazine, methyl alcohol and
ethyl alcohol indicates that the storage and transportation system han-
dling these fuels would have to be kept dry, to avoid problems such as
fuel instability, corrosion, etc., which could affect performance.
3. There are water sensitivity problems with handling and
storing alcohol-hydrocarbon blends, particularly with methanol. Such
blends can separate into two phases when only a few tenths of one percent
of water is added. This issue is considered in detail in Section 6.3.
Since water can condense in the fuel tank by diurnal "breathing," special
venting of the vehicle's storage tanks or the use of adsorbent canisters
would be required where gasoline-alcohol blends are used. It will also
be necessary to keep water out of the fuel transportation and storage
systems.
- 40 -
-------
TABLE 4-4
FUEL PROPERTIES RELATED TO HANDLING AND STORAGE OF FUELS ("^
Fuel->-
Property-!-
Vapor Press, psi @ 100°F
Density
Liquid @ 60°F, lbs/ft3
Liquid, "API @ 60°F
Kin. Viscos. cs @ 0°F
Freezing or Pour Point, °F
Flash Point °F (Closed Cup)
Sol. in Water 8 68°F Wt %
Sol. for Water @ 68°F, ppm
Emulsion Tendency
Storage Stability
Static Charge
Toxicity
Vapor
Ingestlon
Skin
Lubricity
Corrosivity
Effect on Plastics
References
(Section 4-)
Hydrogen Methane Ammonia Hydrazine
(i) (i) 212 0.28(a)
4.43(c) 27.9(c' 48.l(c) 62.6
(1.9)
1-2(d)
-435 -296 -108 35. o" }
126 (e>
33.1 infinite
Infinite
(NP) (NP) (NP)
NP NP NP
D
None'h) None(h) Hi Hi
Mod
Hi
NP
(1) 00
See Table 4-5
11,15 20 8,9, 37,40
10,13,
15
Higher Coal
Methanol Ethanol Oxy Gasol. Distill. Gasol.
4.6 0.2&W (0.3)(b> (0.01)
49.7 49.3 (49.5) (47) (55) (47)
(45.7) (47.0) (46.2) (57) (28) (57)
(1.0) (4.5) (1.0)
-142 -179 (-170)
52 (e> 65 (e> (-40) 148 (-40)
infinite infinite
infinite infinite
(LD)(g> (U»(8> (LD)(S> (D) (D) (D)
Mod. Low Mod (Sig) (Sig) (Sig)
Mod Sod Mod (Sig) (Sig) (Low)
Low Low Low (Sig) (Sig) (Low)
(NP) (NP) (NP)
0)
11,41 11,20,
45 42.
Shale Petroleum
Distill. Gasol. Distill.
(0.01) 8-12 0.01
(54-55) 46.0 52.6
(30-35) 60 36
(4.5) (1.0) (4.5)
20 ^-40 -20+5
(125) -40 125
Nil Nil
0.02
ffi-Cf) NP(£)
NP(f) NP(f>
(D) D D
(Low) (Sig) (Low)
(Low) (Low) (Low)
(Low) (Low) (Low)
(NP) NP NP
NP NP
12,67, 12,66
68
Footnotes to Table 4-3:
(a) at 77°F
(b) at 68°F
(c) at normal boiling point
(d) at 41°F
(e) Open cup
(f) Can be controlled by careful refining and aided by additives.
(g) Specific electric conductivity 106 times higher than hydrocarbons.
(h) Asphixiant
(i) Above critical temperature
(j) May contain small amounts of organic acids which may corrode certain materials.
(k) Material to be avoided include cobalt, copper, pure iron, lead, manganese, magnesium, tin i
(1) Corrodes copper, brass and zinc.
(m) Code: NP - no problem stg „ significant
D - danger
LD - less danger than petroleum hydrocarbons
Blank spaces - data unavailable
( ) - estimated data.
(n) It might be possible to avoid this high freezing point by using a mixture of hydrazlne and
hydrazine.
EPA-460/3-74-009
unsymetrical dimethyl
-------
4. The danger from explosions or fires set by static electric
discharges generated in the handling of hydrogen, methane and ammonia is
understood to be low. Static electric generation is a maximum with ma-
terials whose conductivities are in the range of lO^-iolS 0^m centi-
meters . The conductivities of liquid methane and liquid hydrogen are
below this range. The conductivity of liquid ammonia is above this
range.
5. It will probably be more hazardous to handle ammonia and
hydrazine than petroleum fuels. The primary hazard with ammonia is from
inhalation. With hydrazine both inhalation and skin contact must be
avoided. With liquefied ammonia, hydrogen, and methane, skin contact
with the cold liquids must obviously be avoided.
6. The indications are that the coal liquids will probably
contain a high concentration of aromatic hydrocarbons. It appears also
that the benzene content may be appreciably higher than gasolines from
petroleum sources (1-5 vol. %)*. These points are developed more fully
in Section 6.2. In view of the toxic nature of benzene, the unblended
coal gasolines may require more careful handling than current petroleum
gasolines. Information on toxicity of the fuels being screened is
given in Section 4.6.
7. Ammonia and hydrazine are apparently the most corrosive
fuels. Ammonia is corrosive to materials containing copper, brass and
zinc. Hydrazine is corrosive to cobalt, copper, pure iron, lead,
manganese, magnesium, tin and zinc. Corrosion due to the introduction
of water into the fuel handling and storage system is also a potential
problem. Hydrazine decomposition is also catalyzed by various metal
contaminants.
8. Hydrogen can cause metal embrittlement at elevated pres-
sures even at ambient temperatures (4-130). This must be considered in
designing systems for distributing and storing hydrogen.
9. Table 4-5 summarizes information on fuel compatibility
with various elastomers and plastics which might be used in the ve-
hicle. There is by now a good deal of industrial experience in
handling liquid hydrogen, methane, and ammonia. This experience can
serve as a suitable starting point for selecting materials of con-
struction for fuel systems to handle these compounds. However, the
stringent performance requirements in a vehicle, centered around long-
time, safe, and trouble-free operation, may impose new limitations on
material selection. For example, the low viscosity and high differ-
sivity of gaseous hydrogen will make it extremely difficult to contain
in equipment having any non-metallic parts.
However, the separation of benzene for petrochemical purposes is a
possibility.
- 42 -
-------
TABLE 4-5
EFFECT OF POTENTIAL AUTOMOTIVE FUELS ON
VARIOUS ELASTOMERS AND PIASTICS^52)
Swell, Vol %
(a)
Fuel
H
c/>
O
o
u
M
Hydrogen, (g)
Hydrogen (1)
Methane (g)
Methane (1)
Ammonia (g)
Ammonia (1)
Hydrazine (1)
Methanol
Ethanol
Coal-Gasoline(b)
Coal-Distillate^
Shale-Gasoline
Shale-Distillate
15 8
-1 -4
75
27
25
-2 18 140 68 0
5 21 13 5
Benzene
Toluene
Hexane
113 23 103 190 S 198 180 92 155 214 10 70 168
37 218 150 187 188 138 163 157 87 144 5 83 171
178 93 125 24 53 51 27 108 21
(a) Suitability criteria:
Not suitable
Borderline
Satisfactory
S
swell above 25%
swell between 15-25%
swell below 15%
material softened excessively
(b) Data on benzene and toluene may be taken as a guide to behavior of these highly aromatic
hydrocarbon mixtures.
(c) Code:
CST - polysulfide rubber
FVSi - fluorosilicone rubber
EPM - ethylene-propylene rubber
EPDM - ethylene-propylene terpolymer
NR - natural rubber; polyisoprene, hevla
CSM - chlorosulfonated polyethylene
EU - urethane rubber
ECO - epoxychlorohydrin rubber
SBR - styrene-butadiene rubber, GR-S
IIR - isobutene-isoprene rubber; Butyl
rubber
NBR - nitrile-butadiene rubber
ACM - polyacrylate-acrylic acid copolymer
FPM - vinylidene fluoride-hexafluoropro-
pylene copolymer (Vitan)
VSi - polydimethyl silicone with vinyl
crosslinks
CR - polychloroprene (Neoprene)
PTFE - polytetrafluoroethylene (Teflon)
Blank spaces mean that data were not available.
EPA-460/3-74-009
- 43
-------
A number of polymeric materials seem to have good resistance
to the alcohols, e.g., chlorosulfonated polyethylene, butyl rubber, poly-
dimethyl silicone with vinyl crosslinks, etc. There are no data on the
effect of coal liquids on the various elastomers. A plastic resistant
to the aromatic hydrocarbons is vinylidene fluoride-hexafluoro-propylene
copolymer (Viton). Fluorosilicone rubber may also be a possibility.
4.2.4 Automotive Maintenance
Table 4-6 lists the fuel properties that relate to automotive
maintenance requirements. None of these fuels is expected to contain
excessive amounts of ash or vanadium.
The sludge tendency listed in the table refers to crankcase
sludging in reciprocating piston engines. This usually arises because
of unburned or partially burned high boiling fuel components which reach
the crankcase by slipping by the piston rings. Shale and coal liquids
would be expected to be quite similar to petroleum-derived fuels in this
regard. However, this remains to be confirmed by engine tests. The com-
bustion products of hydrogen and methane would be expected to be rather
innocuous as far as crankcase conditions are concerned. However, the
fuels rich in nitrogen, i.e., ammonia and hydrazine, might have bad
effects because of reactive oxidation products (e.g., NOX) and incompati-
bility with the crankcase lubricants (e.g., reaction with lubricant
additives).
The question of lubricant compatibility is also of concern with
the alcohols. The unburned fuel or oxidation products and the lubricating
oil may form two phases in the crankcase, cause precipitation of the
lubricant additives, or have other unexpected effects. These questions
also can only be answered by engine tests.
4.2.5 Data Gaps
A study of Tables 4-2 through 4-6 shows a large number of
estimated data and numerous gaps where an estimate was not felt to be
justified. Section 8 of this report considers in detail the research
data gaps which should be filled for those fuels selected for in-depth
analysis. In addition, the brief tabulation below summarizes the key
data gaps in physical and chemical properties of some of the fuels:
• Coal or Shale Gasoline; vapor pressure, Research O.N.,
Motor O.N., solubility in water, solubility for water,
emulsification characteristics, storage stability, effect
on elastomers and plastics.
• Coal or Shale Distillate; cetane number, viscosity,
freezing point, pour point, solubility in water, solubility
for water, emulsification characteristics, storage stability,
effect on elastomers and plastics.
- 44 -
-------
TABLE 4-6
Fuel-*
Property^
Res, Octane No.
Motor Octane No.
Ash, Wt. %
Na, ppm
V, ppm
Carbon Residue, Wt %(a'
Sulfur, Wt %
Corrosivity
Effect on Plastics
Sol. for Water 9 68°F ppm
Emulsion Tendency
Lubricity
Storage Stability
Sludge Tendency
References
FUEL PROPERTIES RELATED TO AUTOMOTIVE MAINTENANCE^8'
Higher Coal Shale
Hydrogen Methane Ammonia Hydrazine MeOH EtOH Oxyg'f' Gasol. Distill. Gasol. Distill.
133 130 106 106 (105) 82-98 35-91
105 92 89 (90) (75-86) (?-82)
000 000 0.02 0
000
0 000
0 000 000 0.02
<0.001 <0.0001
(k) (k) (b) (c) (d)
See Table 4-5
(NP) (NP) (NP)
NP (NP) (NP) (NP) (NP)
NP NP NP
NP NP
30 2 44 44
Petroleum
Gasol. Distill.
86-93 —
77-84
0 0.002
1
Nil
Nil 0.1
0.03 0.2
NP NP
0.02
NP NP
NP NP
12, 12,66
67,68
Footnotes:
(•) on 10% bottoms
(b) Corrodes copper, brass, zinc.
(c) Materials to be avoided include cobalt, copper, pure iron, lead, manganese, magnesium, tin, zinc.
(d) May contain small amounts of organic acids which may corrode certain materials.
(e) Can be controlled by careful refining and aided by the use of proper additives.
(f) Estimated assuming Fischer-Tropsch oxygenated compounds consist approximately of 20% methanol, 50%
ethanol, 20% propanol, 10% higher oxygen compounds.
(g) Code: NP - no problem
( ) - estimated values.
Blank spaces-data currently unavailable.
(k) Cryogenic hydrogen and methane require special materials to avoid embrittlement — not really corrosion.
EPA-460/3-74-009
-------
BASES OF ESTIMATES
Heat of Combustion of hydrocarbon fuels: (lower heating value)
' = 18'4 + 15.8[lbs./gal. - 0.0034 (vol. % aroma tics)]
Cetane No.:
Distillates
Calculated Cetane Index from °API Gravity and
Mid Boiling Point via ASTM Standard D 976
Others
Relationship between Octane Number and Cetane Number: from (4-69)
Other Properties of Hydrocarbon Gasolines & Distillates
By analogy from known properties of petroleum fuels and/or field
experience in use and marketing of gasolines and diesel fuels.
- 46 -
-------
• Hydrogen; Research O.N., Motor O.N., static electric
characteristics.
• Methane: static electric behavior.
• Methanol; lubricity, corrosion, viscosity, emulsification
tendency, storage characteristics.
• Ammonia; Motor O.N., lubricity, static electricity charac-
teristics, effect on plastics and elastomers.
4.3 Cost of Manufacture and Distribution
The study calls for a cost comparison of alternative automo-
tive fuels on the basis of the ex. tax cost at the pump. This cost is
estimated by considering both the manufacturing and distribution plus
marketing steps for the various fuels. However, before estimating the
preliminary economics for these operations, it was necessary to specify
the process used to manufacture the fuel from the source. Table 4-7
summarizes the various processes for this conversion, estimates the
present stage of their development, and also gives an estimate of the
earliest date of commercialization.
As regard the dates indicated on the table, they refer to
commercialization of one of the alternates in those cases where a num-
ber of possible routes exist. The date represents the time at which
production from the first one or two plants achieves significant
levels. It might in principle be possible to achieve earlier commer-
cialization of any one of the fuels indicated provided a massive
national effort is dedicated to that end. However, it quickly becomes
apparent that such a technique could not simultaneously be employed to
bring along a number of potentially promising fuels. Consequently, the
dates indicated on Table 4-7 represent an optimistic but balanced
approach in committing capital, people, and natural resources to the
production of the alternate fuels.
Turning to the economics, Tables 4-8 through 4-10 summarize
the cost of manufacture and distribution. The basis agreed upon with
the EPA involves the use of 1973 dollars for all costs. It was also
decided to calculate return on investment using the discounted cash
flow (DCF) method with a basis of 10% DCF return*. The details of this
method are summarized in Appendix 7. In order to facilitate comparison
among fuels of different energy content, it was further decided to cal-
culate costs per unit energy content, given by $/MMBTU. The lower
heating value of fuels was used in this calculation since the latent
heat of water of combustion would usually not be recoverable in an
automotive application.
* The sensitivity of the economics as a function of DCF return level
was estimated for the most promising fuels.
- 47 -
-------
TABLE 4-7
SUMMARY OF TECHNOLOGY FOR MANUFACTURING ALTERNATIVE FUELS FOR AUTOMOTIVE TRANSPORTATION
Gaiollne or
Middle DUtlllate
Type of_Procje8B__
Coal
1. Liquefaction:
(a) Direct Hydroeenatlon:
- Hydrocarbon Res. Inc. (H-Coal): 850°F-,
3000 pslg; catalytic, ebullatlng bed
- Bureau of Mines (Syntholl): 4000 peig,
fixed bed of catalyst
Plttsburg & Midway (PAMCO): non-
catalytic, direct hydrogenatlon at 850°F.
1000 palg, makes low-ash, low-sulfur,
aoltd product (350°F.) can make liquid
fuels by further hydrogenatlon
(b) Donor Solvent;
- Consolidation Coal; liquefaction at
800°F., 350 pslg; ebullatlng bed for
hydrogenating solvent and product oils
- Old Ben Coal: same general approach aa
Conaol. Coal to make synthetic crude;
could also run to make solvent refined
coal
- Exxon: hydrogen donor solvent, which Is
catalytlcally regenerated external to
the liquefaction reactor
- A number of processes under development
(FMC-COED, TOSCOAL, Garrett) and one in
commercial operation (Lurgi-Ruhrgaa);
these pyrolyais schemes are aimed at
maximizing char and heavy fuels and are not
good candidates for transportation fuel
3. Fischer/Tropach;
- gasification of coal followed by catalytic
conversion of CO + H2 to liquid hydro-
carbons at 300 pslg, 400-600°F.
_._S_tage of Development
Earliest Available Date
at Comments
References
• H-Coal: operating 3 ton/day pilot unit
proposing 300-600 T/D unit
• Syntholl: operating 10 Ib/hr pilot
plant; 0.5 T/D pilot plant
built
• PAMCO: constructing 70 T/D pilot
plant
operated 25 T/D pilot plant but shut
down due to problems; Office of Coal
Reaearch considering reactivation
plans to construct 900 T/D plant
• operated 0.5 T/D pilot plant; 200-300
T/D pilot plant under design
• FMC-COED: operated 35 T/D pilot unit
• TOSCOAL: operated 25 T/D pilot unit
• Garrett: operating 300 Ib/hr pilot
plant
• commercial operation in South Africa
(SASOL) at 6000 barrels/day scale
1982
See Section
5.2 for
further
detail!
t
1979
1
1979
Larger version of
SASOL plant
- The above processes yield a crude oil
substitute (syncrude) which has to be
refined hopefully using conventional
technology
refining of coal syncrude has to be
fully demonstrated
EPA-460/3-74-009
-------
TABLE 4-7 (Cont'd.)
Earliest Available Date
Fuel Source
Gasoline or Shale
Middle Distillate
Type of Process
1. Retorting
(a) TOSCO Retort: ceramic balls transfer heat
shale and hot air
(c) Gas Combustion Retort: (Bureau of Mines)
(d) Paraho: externally heated recycle gas ;
2. Upgrading of Raw Shale Oil to Syncrude
(a) Pour point and viscosity reduction by "")
"visbreaking1' I
Stage of Development Year Comments References
• operated 1000 T/D retort
• operated 1200 T/D retort
• operated 360 T/D retort
1C
• pilot plant program getting underway
(but similar retort operated in Brazil
at 2500 T/D)
• technology generally available for
See Section
79 5.1 for
further
details
sulfur and nitrogen
3. Reflnin^of Syncrude
General Scheme; coal and steam gasified, using
oxygen to support combustion; CO/H2 ratio adjusted;
sulfur compounds, C02, other impurities scrubbed
out; catalytic methanation; approximately 3_0
different processes under study. Some of the
leading contenders are:
(1) Lurgi: 300 psig gasification
(2) Winkler: fluid-bed gasification at I atm.
(3) Koppers/Totzek: gasification at 3000°F.,
1 atm.
(4) Babcock & Wilcox: entrained coal gasifier
with char recycle
(5) Bituminous Coal Research, Inc. (BI-GAS) :
2-stage gasifier at 1000-1500 psig
(6) Institute of Gas Technology (Hygas): 2-stage
hydrogasifier at 1000-1500 psig
(7) Bureau of Mines (Synthane): fluid bed
gasifier at 1000 psig
demonstrated on shale
has to be commercially demonstrated
• commercially available up to 700 T/D
for gasifier; methanation being
demonstrated
• commercially available up to 700
T/D*
• commercially available up to 400
T/D*
• commercially available up to 400
T/D*
• 120 T/D pilot plant under
construction
• 75 T/D pilot plant in operation
• 75 T/D pilot plant completed
based on start
of detailed
design in 1974
1978
1981
1981
(4-102,103)
also see
Section
5.3 for
further
details
* required methanation technology not
yet commercially demonstrated
EPA-460/3-74-009
-------
TABLE 4-7 (Cont'd.)
Earliest Available Date
Fuel Source
HI- thane Coal
Mcthanol Coal
Oxygenated Coal
Hydrocarbons
Ethanol Carbohydrates
Hydrogen Coal
Hydrogen Water
Type of Process
(8) Consolidation Coal (CO. Acceptor)
(9) Exxon: char burning to provide heat for fluid-
bed gasification
General Scheme: gasification of cnnl fnllouAH hy
methanol synthesis; methane made in gasifier is co-
product.
(2) Methanol synthesis:
(a) Imperial Chem. Indust.: 700-1500 psig
(b) Lurgl: 550-750 psig
(c) Vulcan/DuPont; 2000-2800 psig
Flscher/Tropsch: similar to process described
production of oxy compounds.
Fermentation: anaerobic process, at ambient
temperature and pressure ; baaed on molasses,
grain, sulflte waste liquor, and wood wastes;
carbohydrates have to be hydrolyzed to sugars
first; 50-60% potentially fermentable sugar In
wood .
General Scheme: coal or char Is gasified; methane
shifted with H^O to C02, and C02, H2S, CO are
removed. Any of the gasification schemes described
above could be adapted to make hydrogen.
Electrolysis ; electricity for cells from nuclear
power plant, a longer range from aolar converters
Stage of Development Year Comments Refer
' nc e s
• 30 T/D pilot plant in operation 1981 (4-102,1031
• 500 T/D pilot plant under design 1981 Section
5.3 for
fiirth
M
I"
.
gasification process ate Sect Ion
5.3 f
Dr
further
d e t a i Is
• commercially available up to
1800 T/D
• conraercially available up to 1983 based on newer
600 T/D gasification process
• commercially available up to
2500 T/D '
• SASOL operation In South Africa makes 1979 Larger version of
along with hydrocarbons
• sugar from wood hydrolysis also
fermented commercially, but operation
Is more difficult to control
hydrogen processes In early pilot not fully developed
plant stage
• electrolysis cells available up to 1985 based on dedicating (4-105,106)
this use by 1975
• solar converters still in early research 71990 for solar based
stages electrolysis
Hydrogen
Coal or Water
Amnonla or Urea
net effect is: H^O > H2 + 7 °2 J n^ny cycles have
been proposed and analyzed thermodynamically
Hydrogen either from coal or water combined with
nitrogen from air In conventional ammonia synthesis
(1) Raschig process:
NH- + NaOCl »• NH,C1 + NaOH
J i
NH2C1 + NH3 + NaOH *• NHj-NHj + NaCl + HjO
(2) Urea process :
experiments
• ammonia production demonstrated up to
1500 T/D
• see above for hydrogen
• both processes commercial; Raschlg
better at >2MM Ib/yr.
• total U.S. production <50MM Ib/yr.
>1990
1981 for H2 from coal
>1985 for H2 from water
1978 based on existing
technology
(4-107)
(f.-\00)
EPA-440/3-74-009
-------
TABLE 4-8
FIRST-ROUND SCREENING ECONOMICS FOR MANUFACTURING ALTERNATIVE AUTOMOTIVE FUELS
Basis: Costs are given in 1973 $ at the plant gate.
Plant sized for output of 6 x 10" BTU/day fuel corresponding to 100,000 barrels/day gasoline.
Costs include a 107, discounted cash flow (DCF) return (see Appendix for more information).
Gasoline froa Coal
Middle Distillate from Coal
Gasoline from Shale
Middle Distillate from Shale
Methane from Coal
Methanol from Coal
Manufacturing Cost
$/MMBTU (Lower Heating Value)
1.85; 2.35*
1.65; 1.75*
1.25; 1.65*
1.10; 1.05*
1.50; 1.65*
1.55; 2.00*
Baaia of Manufacturing Coat
Coal Syncrude: 7.80$/Bbl from National Petroleum Council (NPC) report (4-108)
adjusted to above basis by escalating 1970 to 1973 at Wyr; 50c/Bbl reduction
going from 30M B/D to 100M B/D; 3$/ton Western sub-bltum; coal (8500 BTU/lb) ,
hydrogenated via H-coal process; hydrogen made via Lurgi gasification process;
5$/ton coal would increase ayncrude coat 13C/MM BTU.
Refining: adjusted conventional refining coats (from 4-109) to reflect operation
with coal syncrude; estimated 2.30 $/Bbl.
Total of 10.10 $/Bbl compares to 1.85 $/MMBTU @ 5.5 MMBTU/Bbl.
Coa1 Syncrude: same as above.
Re finding: estimated 1.70 $/Bbl for refining costs; note that gasoline and middle
distillates are co-products in refining. The diatribution of refining costs
among co-products is considered in detail in Section 5.
Sha_le Syncrude; 4.40 $/Bbl adjusted from NPC report; hydrogen supplied *from
process.
Refining: estimated 2.30 $/Bbl, same as for Coal Syncrude.
Total of 6.65 $/Bbl corresponds to 1.25 $/MMBTU @ 5.33 MMBTU/Bbl.
Shale_S_yncrude_; same as above.
Refining: estimated ca. 1 $/Bbl, which is considerably lower than for cpal.
This reflects the higher H/C ratio of shale relative to coal syncrude, and
requires a detailed explanation as given in Section 5.
Baaed on LurgJ gasification of 5 $/ton coal (4-108, 110); methane produced
at 1000 psig; expect that improved technology for gasification could lower
costs ca. 0.20 $/MMBTU-
Bas«d on methanol costs from (4-111) adjusted to 20,000 T/D, 5 $/ton coal.
Oxygenated Hydrocarbon from Coal
3.50-4.00
Hydrocarbon liquids from Fischer/Tropsch are expected to cost ca. 2.50 $/MMBTU
as long as gas is the predominant product. In order to get oxygenated
compounds, the best approach probably is to make olefins and hydrate them,
which would increase costs about 1.00-1. $/MMBTU; if the synthesis were
run to maximize the yield of liquids, the cost would escalate markedly.
Identified costs that were recalculated using the more detailed procedures discussed in Section 5. All other cost estimates were made by adjusting economics
from various literature sources to correspond with a common basis of scale, year, return level, etc., as explained in the last column of the table. In the
initial pact of the program, no attempt was made to analyze the published numbers in detail.
EPA-460/3-74-009
-------
TABLE 4-8 (Cont'd.1
Fuel
Ethanol by FcrmentatIon
Manufacturing Cost
$/MMBTU (Lower Heating Value)
6.00
Hydrogen from Coal
Hydrogen from Water
Ammonia
2.60
4.60
6.25
Hydrazlne
ca. 20.
Ba3is of Manu_fac_t_u ring Cost
Based on fermenting corn at 2 $/bushe 1, est ima te 12.50 $/MMBTU (ca. 9V/gal)
(4-111), with adjustment to common economic basis with other fuels. This is
completely unrealistic scheme.
A more realistic prospect would be the fermentation of cellulose (at ca. l^/lb)
e.g. from wooJ chips; a very rough estimate indicates that this could result
in ethanol at ca. 6 $/MMBTU which corresponds to ca. 45 c/gal.
5 $/ton
• Based on either Lurgi gasification or partial oxidation with coal at 5 $
and hydrogen compressed to 3200 psig; it is anticipated that improved
gasification processes would reduce the cost by ca. 0.20 $/MMBTU.
• Using an electrolyzer with 767, efficiency and a power cost of 10 mil/KW hr
(4-111); there are good indications that 12 mil/KW hr (In 1973 costs) may be
more typical of the 1980's, giving a hydrogen cost of 5-40 $/MMBTU.
• Baaed on hydrogen from water at 4.60 $/MMBTU and nitrogen at 2.90 $/ton based
on (4-112)
• Uaing hydrogen from coal at 2.60 $/MMBTU as above would lead to NH3 at 3.35
$/MMBTU. Practically, however, It is totally unrealistic to convert coal to
hydrogen to make NH3 for automotive fuel use, when coal can be directly
converted to hydrocarbons or methanol.
• Projections for Raschig process at 1000 T/D (4-106) indicate 28 $/MMBTU. For
very large scale applications, a completely new synthesis would have to be
developed, which, conceivably could lead to much lower prices.
EPA-460/3-74-009
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TABLE l> -9
FIRST ROUND SCREENING ECONOMICS OF PISTRIBUTING AND MARKETING ALTERNATIVE AUTOMOTIVE FUELS
Fuel
Gasoline and Middle
Distillate from Coal
Operation
Gasoline and Middle
Distillate from Shale
Methane from Coal
Methanol from Coal
(1) Pipeline syncrude from mine mouth
(2) Products from refinery to bulk
terminal
(3) Retailing
Total
(1), (2), and (3) as above
(1) Pipelining of gas from mine mouth
plant to liquefaction plant
(2) Liquefaction
(3) Transportation to service station
(4) Retailing
Total
(1) Pipeline methanol from mine mouth
plant to bulk terminal
(2) Bulk terminal operations and truck
transport to service station
(3) Retailing
Total
Cost, 1973 $/MMBlu
0.05
0.95
1.00
1.00
0.30
1.60
0.45
1.65
4.00
Bajija for Estimating Costs
0.22
1.25
1.47
call 1.45
• 1000 mile Wyoming-Chicago pipeline; petroleum experience.
• pipeline or barge plus bulk terminal handling. *1 n / i
• tank-truck to service station plus retailing margin-J r er ?e , Q*
O« /™-1 §„_
c
* neglect differences in heat content between gasoline and
middle distillate
eal Pfor°«V
. for' (3)] *'
neglect differences in heat content between shale and coal liquids.
assumes that methane would be used as liquefied natural gas (LNG) ;
did not consider cylinders of compressed gas a viable possibility
for automotive transportation.
pipeline gas average of 1500 miles to liquefaction site; cost of
2c/MMBTU/100 miles (4-113)
assume fairly arn^ll liquefaction plants (10 MMSCF/D) close to the
market, in order to avoid an intermediate storage and distribution
which would increase handling of LNG; costs based on (4-120)
tank truck delivery over 250 mile radius; based on (4-120)
estimate by considering "typical" service station operation (prior
to Fall 1973): ca. $150,000 investmant, 360,000 gal./yr.; markup
ca. ScYgal.; assume that LNG operation would involve ca. $100,000
additional investment [based on (4-220)]; assume 407D capital recovery
factor for this added investment:
0.4 x 100,000 x 100 T1 / 1 u 4 !
- 360?OOQ - = llc/gal. gasoline equivalent
= 1<67) Cal1 U65
therefore, total retailing cost is 0.^3
1500 mile pipeline; cost prorated from hydrocarbon pipeline on
basis of BTU content; if shipped by unit train, would cost
$0.65/MMBTU.
see Section 5.3.6 for further details on costs of
methanol d is tr ibut ion , inc lud ing compar is on with
gasoline.
EPA-460/3-74-009
-------
(Cont'd.l
Fuel
Ethanol by Fermentation
Operation
Hydrogen from Coal
(1) Pipeline from plant to bulk terminal
(2) Bulk terminal operations and truck
transport to service station
(3) Retailing
(1) Pipeline gas from mine mouth to
liquefaction plant
(2) Liquefaction costs
Coat, 1973 5/MMBTU
0.10
0.30
0.70
1.10
0.45
3.50
Baais for Estimating Costs
• 1000 mile pipeline; prorate from hydrocarbon pipeline on basis of
BTU content .
• intermediate between gasoline and methanol costs for equivalent
operation on basis of Intermediate BTU content.
• assume $3,000 extra Investment In service station; leads to
ca. 70c/t*fflTU. (See sample calca. on previous page.)
• the same total of $1.10/MMBTU can be used as a first approximation
to the cost of distributing various mixed oxygenated compounds,
as would result from Flscher/Tropsch synthesis.
• 1500 mile pipeline; cost averaging 3C/MMBTU/100 miles from (4-111).
• assume 100 T/D plant; equivalent BTU's to LNG plant (see above).
These costs are substantially higher than those In (4-115) because
of the smaller size plant chosen; this choice is dictated by a
desire to eliminate a bulk storage transfer facility.
Hydrogen from Water
Anoonli, baled
(3) Transportation to service station
(4) Retailing
Total
(1) Liquefaction at nuclear plant
(2) Distribution to bulk terminal and
bulk terminal operation
(3) Retailing
Total
(1) Liquid NH3 from nuclear plant to bulk
terminal and bulk terminal operation
(2) Retailing
Total
0.75
2.60
7.30
2.00
1.00
2.60
5.60
0.50
0.93
1.43
call 1.45
• based on use of H2 Dewar trucks at $0.35/MMBTU/100 miles over
250 mile radius.
• baaed on $200,000 extra Investment in service station (I.e., 2 x
investment for LNG); corresponds to extra retailing charge of
2.00 $/}+fflTU relative to gasoline.
• liquefaction plants at nuclear plant, demanding much larger
liquefaction plant than for case above; costs therefore much lower.
• assume direct delivery of H2 from plant to service station; requires
longer average shipping distance than case above.
• same as above .
• Ref. 4-13 for transportation from nuclear plant to bulk terminal.
• assume 2 x gasoline costs.
• based on $25,000 extra investment in service station; corresponds
to 0.27 $/MMBTU extra retailing charge relative to gasoline.
EPA-460/3-74-009
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TABLE 4-10
FIRST ROUND SCREENING OF ALTERNATIVE AUTOMOTIVE FUELS
COMPARISON OF EX TAX COSTS AT THE PUMP
Fuel
Gasoline from
Shale
Middle Distillate
from Shale
Gasoline from
Coal
Middle Distillate
from Coal
Methanol from
Coal
Methane from Coal
Oxygenated
Compounds from
Coal
Ethanol
Hydrogen from Coal
Hydrogen from Water
Ammonia
Hydrazine
Manufacturing
(from Table 4-8)
1.25; 1.65*
1.10; 1.05*
1.85; 2.35*
1.65; 1.75*
1.55; 2.00*
1.50; 1.65*
3.50
6.00
2.60
4.60
6.25
ca 20
_1Q71 £ /MVTRTTT— ___.
Distribution
(from Table 4-9)
1.00
1.00
1.00
1.00
1.45
4.00
1.10
1.10
7.30
5.60
1.45
not estim.
At Pump,
ex Tax
2.25; 2.65*
2.10; 2.05*
2.85; 3.35*
2.65; 2.75*
2.85; 3.45*t
4.35; 5.65*
4.60
7.10
9.90
10.20
7.65
>20
* See footnote on Table 4-8.
t Initially would be $3.85/MMBTU if methanol shipped by unit train
rather than by pipeline.
- 55 -
EPA-460/3-74-0
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Economics of manufacture are obviously a function of plant
size. In these estimates the comparison was made for a plant size
roughly corresponding to 100,000 barrels a day of petroleum gasoline
production, corrected for differences in energy content. The economics
collected from the literature were all corrected to the above bases.
In the subsequent part of the study, a detailed analysis was
carried out on shale and coal derived fuels. Not surprisingly, this
detailed analysis gave results significantly different from those ob-
tained by a preliminary study of existing literature data. It was
decided to take account of this, in Tables 4-8 and 4-9, by showing the
original value in parentheses together with the subsequently revised
costs.
Finally, the economics shown on Tables 4-8 through 4-10 are
not presented for various time frames. They represent costs typical of
the first generation technology for each fuel. The detailed analysis of
the coal and shale derived fuels in Section 5 considers the effect of
new and improved technology as well as other factors which would have an
impact on costs through the year 2000.
Turning to distribution costs, a fair degree of approximation
was involved, based on reasoning by analogy with the distribution and
marketing operations for conventional petroleum derived fuels. No
attempt was made to optimize the distribution system for each fuel. It
was felt, however, that the results are adequate for initial screening
purposes.
4.4 Fuel-Vehicle Compatibility
The compatibility of the fuel with the vehicle involves the
interaction between the fuel and the engine as well as a consideration
of fuel storage. The spark-ignited Otto cycle engine is by far the most
common power plant in the U.S. car population. It is used in more than
99% of the vehicles (cars and trucks) on the road, with about 0.9% of
the vehicles using the diesel engine. In terms of fuel consumed, the
Otto cycle engine uses 92 vol. % of the total with the diesel engine
using 8 vol. %.
However, the emphasis on exhaust emission control has sparked
a great deal of work on low emission engines. It is very likely that
the engine population will undergo significant changes in the 1974-2000
period covered by this study. Since it is not the purpose of this study
to speculate on the prospects of alternative new automotive power plants,
fuel compatibility has been considered for all potentially promising
engine types. The major characteristics of the various types are shown
in Table 4-11. The major distinguishing features are:
• The combustible mixture (i.e., the fuel and air) may be
introduced to the combustion chamber either in a homo-
geneous or heterogeneous state.
- 56 -
-------
• The combustion may be either intermittent, or continuous.
If intermittent, some means of ignition must be provided,
e.g., by spark, by compression to temperatures and pres-
sures exceeding the .autoignition point of the fuel, by
glow plug, or by pilat injection*. The latter two are
usually used only in conjunction with high compression
ratios typical of the diesel engine. With steady-state
combustion, ignition occurs only once when the engine is
started and is not a critical characteristic.
• The device used to extract the expansion work from the hot
gases may consist of reciprocating pistons, rotating pis-
tons (as in the Wankel) or a turbine wheel.
The following shows the types of engines that will fall in
the various classes:
Class
A/F Combust. Ignition Engine Types
Homo. Intermit. Spark Otto Cycle; reciprocating and rotary
Hetero. Intermit. Spark, etc. Stratified charge; recip. and rotary
Hetero. Intermit. Compression Diesel Cycle; recip. and rotary
Hetero. Continuous Gas Turbine, Stirling, Rankine
Electric cars powered by batteries or fuel cells are con-
sidered for the sake of completeness in Table 4-11. However, battery-
powered vehicles were not considered further in this study. Fuel-cell
powered vehicles were within the scope of the power plants considered,
which is the prime reason for including hydrazine in the initial list
of fuels.
4.4.1 Modifications Required to Achieve
Fuel/Vehicle Compatibility
A detailed engineering study to design a vehicle operating
with the various future engine-fuel combinations is much beyond the
scope of this report. However, estimates were made of the magnitude of
the vehicle changes that might be involved, based on known character-
istics of various engines and fuels, and accounts in the literature of
actual operations with various engine-fuel combinations.
The estimate is expressed as a numerical compatibility
rating defined as follows:
Pilot injection - a relatively small amount of an easily ignited
material is injected into a mixture of air and fuel that is more
difficult to ignite.
- 57 -
-------
TABLE 4-11
CHARACTERISTICS OF AUTOMOTIVE POWERPLANTS
Distinguishing Characteristics
Engine Name
Conv. Current Auto
Rotary Comb. (Wankel)
Stratified Charge^
Ford PROCO
Texaco TCCS
Honda CVCC
Diesel
, Gas Turbine
<•" Rankine
00
1
Stirling
Electric (d)
Elprfrlr
State of
Combust.
Mix.
Homog.
Homog.
Hetero.
Hetero.
Hetero.
Hetero.
Hetero.
Hetero.
Hetero.
~
-•• _ .
Type of
Combust.
Intermit.
Intermit.
Intermit.
Intermit.
Intermit.
Intermit.
Continuous
Continuous
Continuous
— • T?no1 Co
Type of
Ignition
Spark
Spark
Spark
Spark
Spark
Compress.'3'
Not Crit.
Not Crit.
Not Crit.
Type of
Expander
Recip. Piston
Rot. Piston
Recip. Piston
Recip. Piston
Recip. Piston
Recip. Piston
Turb . Wheel
Turb. Wheel
or Piston
Piston
v^
Common
Fuel
Gasoline
Gasoline
Gasoline
Gas./Dist.
Gasoline
Distillate
Gas./Dist.
Gas./Dist.
Gas./Dist.
Central
Power
(a)
(a) Note in some types ignition may also be by glow-plug or pilot injection (small amount of easily ignited fuel
injected into mixture of fuel and air).
(b) It is theoretically possible to also use a rotary piston engine.
(c) Technology most advanced with hydrogen, methylalcohol, hydrazine or reformed gases from petroleum stocks.
(d) Not considered in this study.
EPA-460/3-74-009
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Compatibility
Rating Description
4 No modifications required
3 Minor modifications required
2 Major modifications required
1 Not practical
The rating is really the result of two separate considerations,
i.e., the compatibility of the fuel with the engine and vehicle changes
required to use the fuel.
Table 4-12 shows the qualitative compatibility ratings of the
various fuel-engine combinations. The following discussion summarizes
the assumptions involved and gives some general comments on compati-
bility:
• General
~ The distillates, regardless of source, are not suitable
fuels for the carburetted Otto cycle engine because of
inadequate anti-knock quality and volatility.
- Gasoline fuels, regardless of source, having a Motor
octane number above about 50, are poor fuels for a
compression ignition engine because of low Cetane
number and low viscosity. Increase in engine compres-
sion ratio (say from 15 to 22+) would help counter the
poor compression ignition characteristics. However,
engine operation would probably be harsh, rough and
noisy.
- The electrochemical reactivity of the hydrocarbon fuels
is too low to make them directly suitable as fuels for
automotive fuel cells. However, they might be reformed
to H2 and CO external to the fuel cell.
• Fuels From Coal and Shale
The critical combustion property of the gasolines is essen-
tially their anti-knock quality. For the distillates Cetane number,
flame luminosity and smoking characteristics are critical. All of these
properties are related to the concentration of aromatic hydrocarbons in
the fuels. As aromaticity increases, octane number increases, Cetane
number decreases, flame luminosity increases, and smoking tendency
increases.
The aromaticity of the fuels is largely a function of fuel
processing and can be controlled by the severity of the hydrogenation
conditions employed. High octane number gasolines either from coal or
shale will have a high concentration of aromatic hydrocarbons, as do
- 59 -
-------
TABLE 4-12
COMPATIBILITY OF FUEL AND VEHICLE
Engine Class Characteristics Vehicle Compatibility
F/A Conditions +
Combustion ->-
Ignition ->•
Fuel 1
Pet. Gasoline
Pet. Distillate
Shale - Gasoline
Shale - Distillate
Coal - Gasoline
Coal - Distillate
, Higher Oxygenates (100%)
^ Higher Oxygenates as
0 b lends (b)
i
Ethanol(100%)
Ethanol as blend^
Methanol(100%)
Methanol as blend (b>
Hydrazine
Ammonia
Methane
Hydrogen
Homo.
Intermit.
Spark
4
1
4
1
4
1
3
4
3
4
3
4
2
2
2
2
Hetero
Intermit.
Spark
4
3-4
4
3-4
4
3-4
3
4
3
4
3
4
2
2
2
2
Ratine With Indicated Eneine Class (c) ...
Hetero
Intermit.
Comp.
2
4
2
3-4
2
3-4
2
2
2
2
2
2
1
1
1
1
Hetero
Continuous
NA
4
4
4
3-4
3-4
3-4
3-4
4
3-4
4
3-4
4
3
2
2
2
( 0\
Fuel(a'
Cell
1
1
1
1
1
1
2
1
3
1
4
4
2
1
2
(a) These ratings are for the fuel with the fuel cell. Actually, because of the excessive weight and size of
the fuel cell, its vehicle compatibility is probably 2 or less.
(b) With a hydrocarbon fuel of appropriate characteristics; max. cone. ca. 15-20 vol. %.
(c) See previous page for description of rating system.
EPA-460/3-74-009
-------
conventional gasolines. On the other hand, high Cetane number distil-
lates, such as those from shale, will be of relatively low aromaticity.
For the purpose of this part of the study, therefore, it was assumed
that the processing of the coal and shale fuels can be adjusted to give
the fuel quality required by the engine population. Under these condi-
tions, and if the coal fuels are used without blending, the gasoline
will probably have somewhat more aromatics than current gasolines and
the distillate will tend to be borderline in cetane quality. However,
if the coal fuels are blended with petroleum fuels, as is very likely to
be the case, the potential problems are greatly reduced. In the case of
unblended coal fuels, attention should be given to the following areas:
- Special gasketing, diaphragms and hose materials might be
required in the fuel system to resist high aromatic con-
centrations .
- Difficulties in burning the distillate fuels cleanly may
result in smoke-limited diesel and gas turbine engine
operation. This limitation can probably be removed by
hardware tailored to clean combustion of these fuels.
- Highly luminous flame may require special combustor design
(as in the gas turbine) for better combustor wall cooling,
cleaner combustion, and for reduction in smoke and particu-
lates.
• Alcohols
The relatively low heat of combustion will require, for methanol,
about double the rate (weight or volume) at which fuel must be sup-
plied to the engine to equal the power produced by a hydrocarbon
fuel. This may mean larger fuel lines, pump, filter, carburetor, and
jets (4-46).
The high heat of vaporization combined with a low heating value means
a large amount of heat (for methanol, about six times that for hydro-
carbon fuel) must be supplied to the intake manifold of a carburetted
engine to provide a given number of BTU's as vaporized fuel (4-43,46).
The water sensitivity of gasoline-alcohol blends (4-44) requires
special precautions.
Alcohols make poor fuels for use in compression ignition engines
because of their low Cetane numbers.
Low flame luminosity suggests a simplified combustor design for a
continuous combustion system (e.g., gas turbine).
The particular solvency characteristics of alcohols may require
changes in elastomers and plastics used in the fuel system, e.g., in
diaphragms, gasket, lines, etc.
- 61 -
-------
Methanol is being seriously considered for use in fuel cells. It can
be used as a primary fuel or can be reformed external to the cell to
a hydrogen-rich gas.
• Ammonia
The low heat of combustion indicates about two times the weight and
three times the volume of ammonia, relative to petroleum fuel, must
be introduced into the combustion chamber for equivalent power output.
The high heat of vaporization coupled with the low heat of combustion
indicates eight times as much heat as for petroleum fuel must be
provided to generate a given number of BTU's as vaporized fuel. How-
ever, the low boiling point suggests that this could readily be sup-
plied by the ambient air or engine exhaust.
In order to provide performance equal to that obtained in current
auto engines, supercharging with or without an increase in compres-
sion ratio, will be necessary (4-1) .
Hot spark plugs with wide gaps and high voltage ignition is required.
A combustion chamber shape that encourages rapid ignition (4-2) is
also desirable.
The addition of a small amount of hydrogen to the ammonia (4-5 wt. %)
is necessary for suitable part-load performance. This might be sup-
plied by partial decomposition of the ammonia. A catalytic dissociator
heated by engine exhaust shows promise (4-1) .
The high octane number of ammonia will allow the use of high compres-
sion ratios with a resulting improvement in thermal efficiency.
Ammonia is a poor fuel for a diesel engine because of its low Cetane
number. Combustion of ammonia requires high compression ratios
(35/1) and high temperatures (300°F air and coolant). The use of
alternate ignition sources (glow plug, spark plug, pilot injection)
is a possibility (4-14).
The low flame speed requires long residence time in a combustor for
complete combustion. Ammonia requires a combustor volume about
three times as large as that necessary for a hydrocarbon fuel. A
catalytic combustor is a possibility (4-8) .
Pumping of liquid ammonia requires special attention to pump bearing
surfaces because of its low lubricity (4-8).
The electrochemical reactivity of ammonia is of a relatively low
order making a fuel cell operating directly on ammonia of doubtful
practicability- However, it is possible to decompose the ammonia
to nitrogen and hydrogen for fuel cell use.
- 62 -
-------
The strong odor of ammonia will require careful attention to the fuel
system to avoid leaks.
The materials of construction of the fuel system must be limited to
those not adversely affected by the corrosive nature of ammonia.
• Hydrazine
The low heat of combustion means that about 2.5 times as much hydra-
zine as a hydrocarbon fuel must be delivered to the engine for com-
parable power output.
The low heat of combustion and high heat of vaporization indicates
that nine times as much heat as with a hydrocarbon fuel must be pro-
vided in a carburetted car to produce the same energy in the vapor.
The relatively high boiling point of hydrazine (236°F) indicates a
need to provide special means of supplying this heat.
In general, with regard to combustion in a heat engine, hydrazine
would be expected to behave in a manner analogous to ammonia.
Hydrazine has a fairly high electrochemical reactivity and is there-
fore attractive as a fuel for fuel cells. The successful operation
of a hydrazine fuel cell has been demonstrated (4-99).
Corrosion and odor characteristics will require careful attention to
the fuel system design.
• Methane
In many respects methane is an excellent fuel for the Otto cycle
engine. It has high octane number and burns cleanly (4-35,36,100).
Because of its low boiling point (-259°F) it is metered and fed to
the engine, in most cases, as a gas. This requires a gas-air car-
buretor (presently available), plus the necessary valves, pressure
regulators and plumbing to handle the high pressure gas.
A major disadvantage is the need for a bulky and heavy fuel storage
system. This will be discussed later.
The low Cetane number of methane indicates that it is not a suitable
fuel for conventional diesel engines (compression ignition) because
it is difficult to ignite by heat and pressure. This problem can be
overcome by the use of ignition assists such as pilot fuel injection,
glow-plugs or spark plugs. Stationary diesel engines burning methane
are currently in operation using the pilot injection technique.
However, this application involving constant power operation is a
simple case compared to a vehicle which requires complete flexibility
over a wide range in power.
- 63 -
-------
Methane is an excellent fuel for engines using steady-state combus-
tion (e.g., gas turbine). It is clean burning with a flame that is
relatively non-luminous.
Methane is not promising as a primary fuel for fuel cells. It is
possible, however, to reform methane to give a hydrogen-rich gas
which can be reacted in a fuel cell. The combination of a bulky
reformer plus a fuel cell makes this type of power plant very un-
likely for automotive use.
• Hydrogen
It has been demonstrated that a spark-ignited Otto cycle engine of
the current type can be operated with hydrogen as a fuel without
major changes in the basic structure of the engine (4-22,55).
Changes involved in converting from a gasoline fuel include:
(a) a reduction in compression ratio (to 8/1), (b) the use of a gas
metering carburetor, (c) modification of the cam shaft (to change
valve overlap characteristics), (d) use of sodium cooled exhaust
valves, (e) a capacitive discharge ignition system, and (f) adjust-
ment of spark timing and exhaust gas recirculation (to eliminate
knock and backfire and to minimize exhaust emission). Water injec-
tion may be used in the place of exhaust recycle (4-24).
Another approach is to use the Hydrogen Induction Technique (4-48)
for which a significant improvement in fuel economy is claimed. In
this method some modification of the cylinder head is required and a
separate intake manifold for the hydrogen is required.
It has been reported that a rotary combustion engine (Wankel) runs
smoothly on hydrogen-air mixtures over a wide range of composition
(4-57). No mechanical changes were required except to improve
carburetion and to inject an oil spray into the hydrogen to provide
lubrication for the rotor seals.
The high auto-ignition temperature of hydrogen suggests it will be
hard to ignite by compression, probably making it a very poor fuel
for conventional diesel engines. The use of auxiliary ignition
means such as a glow-plug or pilot injection might provide ignition
but does not seem practical for vehicular application where wide and
rapid changes in power are required.
Hydrogen is an excellent fuel for a continuous combustor such as used
with a gas turbine, Rankine cycle or Stirling engine. Its high flame
speed, wide flammability limits, and non-luminous flame will allow
the design of a small combustor capable of a wide range of operation,
clean combustion, and long combustor life. The wide flammability
range suggests that the hydrogen combustor can be run very lean
indicating promise for reduced NOX emissions by virtue of a low flame
temperature. The following comparison illustrates the lowered tem-
perature possible under lean conditions:
- 64 -
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Flame Temperature
at Lean Limit, °F
Hydrogen 1500
Jet Fuel 2900
Data from (4-56)
The electrochemical reactivity of hydrogen makes it attractive as a
fuel for fuel cells. This has been demonstrated by the successful
use of hydrogen-powered fuel cells in the space program and develop-
ments for land-based applications.
In addition to engine changes, many of the fuels require sub-
stantial changes in the vehicle itself. These are primarily associated
with storing enough fuel to provide a reasonable operating range between
fuelings. Table 4-3 illustrates the problem by comparing the volume and
weight of fuel plus fuel container required to carry the energy equiva-
lent to gasoline-powered cars with a 20 gallon fuel tank. The weight
and volume penalties associated with fuel storage, relative to a liquid
petroleum fuel, are indicated below:
Fuel and
Container Debit*
Fuel Lbs. Ft.3
H (g) @ 3000 psi @ 80°F 2100 63.0
IH(1) @ 1 atmos. 220 7.4
H£ as MgH2 560 8.0
Methane(g) @ 3000 psi @ 80°F 366 25.0
Methane(1) @ 1 atmos. 106 13.0
Ammonia(l) @ 80°F 321 11.0
Hydrazine 233 3.3
Methanol 151 2.9
Ethanol 80 2.0
Higher Oxy Compounds 86 2.2
* Relative to liquid hydrocarbon fuel.
It is evident that normally gaseous fuels are at a consider-
able disadvantage relative to liquid hydrocarbon fuels with regard to
fuel storage requirements.
The foregoing figures are valid if it is assumed all the
fuels are used with a thermal efficiency equal to that of 1973 Model
- 65 -
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internal combustion gasoline engines (i.e., ca. 9.5% in urban driving).
As discussed previously (4-71), other engines have different efficien-
cies. The fuel storage debit of a given fuel-engine combination for a
specified driving range should therefore be modified by an engine effi-
ciency correction.The magnitude of this correction is quite significant
for the diesel engine and for the "Hydrogen Induction Technique" in the
internal combustion engine.
4.5 Environmental Effects
The use of an alternative automotive fuel involves environ-
mental effects in a number of steps: (1) resource production, (2)
manufacture and distribution, and (3) vehicle use. The following dis-
cussion highlights some of the issues in this area. A more detailed
discussion is given in Section 5 of the report. Nevertheless, it is
beyond the scope of this feasibility study to present a detailed
assessment of environmental impact, particularly in the area of resource
production.
4.5.1 Resource Production
The resources used to manufacture all the fuels being con-
sidered in the initial screening are shale, coal, water, and agricul-
tural products. The most serious environmental concerns involve shale
and coal mining.
• Shale
Considering shale mining and retorting, the major problem area
is the efficient and environmentally acceptable disposal of the spent
shale after the mined rock is retorted. The volume of such spent shale
is ca. 110% the volume of the mined rock, due to expansion during retort-
ing. It is essential that certain conditions be met in this operation:
(1) Dust formation must be suppressed.
(2) Leaching of minerals from the spent shale by rainwater
must be minimized.
(3) The spent shale area must be revegetated in a manner
compatible with the local fauna.
The recent environmental impact statement by the Department of
the Interior (5-2) concluded that the techniques for accomplishing these
- 66 -
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objectives have been successfully demonstrated on a pilot scale*. Full-
scale demonstration of spent shale disposal and land reclamation tech-
niques will occur when commercial mining and retorting operations are
carried out on the tracts of the prototype leasing program.
In addition to spent shale disposal, good environmental
management dictates minimizing the use of water which is scarce in the
shale-producing areas of the West. As discussed in Section 5.1, about
one third of the water required to mine and upgrade the shale to synthe-
tic crude is used to wet down the spent shale. In principle, spent-
shale disposal would be eliminated by a process of in situ retorting.
The incentive to develop such a process is certainly great, but it, too,
could have potential environmental problems, such as subsidence or
ground water contamination.
Other environmental issues relative to shale are:
(1) Land availability: it has been estimated that a one
million barrel/day shale industry would require 80,000
acres for 30 years' supply.
(2) Sulfur and nitrogen: provisions must be made to remove
the sulfur and nitrogen, originally in the shale oil,
which is released during upgrading.
(3) Population changes: the development of a mature shale
oil industry will bring large numbers of people to
sparsely populated areas of the country. The environ-
mental consequences of such a situation on the local
eco-system must be realistically assessed.
Overall, the Department of Interior assessment concludes that
the environmental impacts of a one million barrel/day shale industry are
serious but can be managed. Longer range, it will be critical to deter-
mine the environmental limitations as larger production levels are con-
templated.
• Coal
The major environmental problem with coal involves strip-
mining. In order to achieve coal production levels required for con-
version to synthetic fuels as well as for direct power plant use, it
will be necessary to strip-mine about 450 million tons/yr. by 1990.
As with shale, it will be necessary to demonstrate that the strip-mined
The conclusions in (5-2) relative to spent shale disposal and land
reclamation have not been accepted in some circles. Other studies in
these areas, now being completed, may help resolve some of the un-
certainties.
- 67 -
-------
land can be restored to an environmentally acceptable level. Water is
also of concern in coal mining, and more importantly, in the conversion
of coal to a synthetic crude, but overall the operations are less water-
intensive than the corresponding shale operation.
As is the case for shale conversion, it is necessary to provide
for recovery of sulfur and nitrogen during the syncrude preparation step.
Furthermore, the mining and conversion operation will involve about the
same number of people as for a shale oil operation of comparable size,
bringing up the same ecological issues.
On balance, the environmental problems involved in shale
mining and upgrading are felt to be more severe than those for coal, for
an equivalent scale of operation (based on recovered energy). This will
be dealt with further in Section 5.2.
4.5.2 Manufacture and Distribution
• Coal and Shale: The refining of syncrude from coal and
shale and the distribution of the resulting products is very analogous
to petroleum refining and distribution. The same environmental consid-
erations apply regarding: (1) air and water effluents from the refinery,
(2) prevention of leaks and spills in the distribution network.
• Methanol: As discussed in Section 5.3, the manufacture of
methanol from coal involves gasification and methanol synthesis at the
mine, giving rise to the environmental concerns mentioned above. In the
distribution system, it is important to avoid spills which could pose
toxicity problems if the metnanol is not rapidly bio-degraded.
* Hydrogen: The major environmental concerns involve the
nuclear reactor which will be required to generate the electricity for
water electrolysis. This issue is beyond the scope of this study. The
use of solar-based water electrolysis would avoid the difficulties asso-
ciated with nuclear reactors.
• Ammonia: The technology is well-developed including
methods of dealing with environmental issues involved in manufacture and
distribution.
• Methane: With coal-based methane, the environmental con-
cern is in the gasification step, as mentioned above.
• Hydrazine: Provisions have to be made to handle the
aqueous effluents involved in the Raschig process (see Table 4-7). This
is not a serious problem.
In summary, coal and shale-based liquid fuels require the most
attention to environmental problems during manufacture and distribution.
- 68 -
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4.5.3 Exhaust Emissions*
A partial list of the components of automotive exhaust
includes nitrogen, oxygen, water, unburned fuel, carbon dioxide, carbon
monoxide, oxides of sulfur, organo-sulfo compounds,'oxides of nitrogen,
various other complex nitrogen compounds, polynuclear aromatic hydro-
carbons, various organo-oxy compounds (e.g., aldehydes) and particulates.
The focus in this study has been largely on the emissions of unburned
hydrocarbons, carbon monoxide and oxides of nitrogen, because these have
been of primary concern in automotive combustion of hydrocarbon fuels.
Furthermore, the available data are largely in this area. However, some
general comments are made below about some of the other exhaust compo-
nents .
While there is considerable controversy regarding the long-
range effects of carbon dioxide in the atmosphere, the evidence is not
persuasive that it constitutes a threat to the environment in the time-
frame of this study.
There is a strong possibility that small amounts of unburned
fuel will be present in the exhaust from each engine. This would be
particularly objectionable with toxic and malodorous materials like
ammonia and hydrazine. The amount of unburned fuels will probably be
less with those power plants employing a steady-state combustion, in
contrast to intermittent combustion of reciprocating piston engines. It
is claimed that low molecular weight alcohols have the same photochemical
reactivity as paraffinic hydrocarbons. There are indications that they
tend to produce significant quantities of objectionable aldehydes in the
auto exhaust. If catalytic exhaust treatment is used, this potential
problem can be avoided (4-129).
The available data on the emissions of unburned hydrocarbons,
carbon monoxide and oxides of nitrogen (calculated as NC^) are shown in
Tables 4-13 to 4-15. The units are gms/MMBTU to facilitate comparison
among fuels having different heats of combustion. The relationship
between gms/mile and gms/MMBTU requires a knowledge of the efficiency of
the auto system. In making the conversions, appropriate efficiencies
have been used for the various engines types as discussed earlier.
However, it has been assumed that all fuels will give the same efficiency
in a given engine. This may be open to question in some cases, e.g.,
with hydrogen which can be burned under very lean conditions (4-48,55).
The test basis is the Federal Test procedure or a simulated version
thereof except where noted otherwise (e.g., methanol in the Brayton
cycle (4-49), ammonia in the Otto cycle (4-3)). In the case of existing
This discussion of exhaust emissions is not intended to be a detailed
assessment of the area, but is simply a screening assessment aimed at
identifying potential emission problems with some of the alternate
fuels.
- 69 -
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TABLE 4-13
Cycle
State of Comb. Mixture
Combustion
Ignition P
Fed • RGQ uiretucn t
Pet. Gasol.
Pet. Distill.
Shale Gasol.
Shale Distill.
Coal Gasol.
Coal Distill.
Higher Oxys - 100%
Higher Oxys - Blend8
Ethanol - 100%
Ethanol - Blend?
Methanol - 100%
Methanol - Blend*
Hydrazine
Ammonia
Methane
Hydrogen
Otto
Homo.
Intermit.
Spark
298a
—
—
(200)
(200)
95-165h
(200)
(0)
(0)
210*
(0)
1
Str. Ch.
Hetero.
Intermit.
Spark
35b
(25)h
(25)h
(25)h
(0)
(0)
(0)
SXHAUST EMISSIONS - HYDROCARBONS
Exhaust Emissions -
Diesel Brayton
Hetero. Hetero.
Intermit. Continuous
Co rap Not appl.
(25)
53C 26d
—
—
(18)
(18)
240i
(18)
(0) (0)
(0) (0)
—
- (0)
gms/MMBTU
Rankine
Hetero.
Continuous
Not appl.
/ 7
4-36e
(5-35)
(4-25)
(4-25)
(4-25)
(0)
(0)
(0)
Stirling Fuel Cell
Hetero.
Continuous
Not appl.
18-28f
(20-30)
—
—
(15-20)
(15-20)
(15-20)
(0) (0)
(0) W)
—
(0) (0)
Note: See footnotes following Table 4-15.
EPA-460/3-74-009
-------
TABLE 4-14
EXHAUST EMISSIONS - CARBON MONOXIDE
Exhaust Emissions - gms/MMBTU
Cycle
State of Comb. Mixture
Combustion
IgnitionP
Fed. Requirement
Pet. Gasol.
Pet. Distill.
Shale Gasol.
Shale Distill.
Coal Gasol.
Coal Distill.
Higher Oxys - 100%
Higher Oxys - BlendS
Ethanol - 1002
Ethanol - BlendS
Methanol - 100%
Methanol - Blend 8
Hydrazine
Ammonia
Methane
Hydrogen
Otto
Homo.
Intermit.
Spark
43003
—
—
—
(4000)
(4000)
320-1300h
(4000)
(0)
(0)
220k
(0)
Str. Ch.
Hetero.
Intermit.
Spark
350b
(350)
(350)
(350)
(0)
(0)
(0)
Diesel Brayton
Hetero. Hetero.
Intermit. Continuous
Comp. Not appl.
__ 107-1 AAftn * 1976*-
(300)
206C 290d
—
(300)
__
(300)
3721
(300)
(0) (0)
(0) (0)
—
(0)
Rankine
Hetero.
Continuous
Not appl.
oar!
19 -3006
(20-300)
(20-300)
(20-300)
(20-300)
(0)
(0)
(0)
Stirling
Hetero.
Continuous
Not appl.
160-166 f
(150-170)
(150-170)
(150-170)
(150-170)
(0)
(0)
(0)
Fuel Cell
—
__
—
—
—
—
—
—
—
~"
(0)
(0)
—
(0)
Note: See footnotes following Table 4-15.
EPA-460/3-74-009
-------
TABLE 4-15
Cycle
State of Comb. Mixture
Combustion
IgnltionP
Fed > Rcoui. rcn£n t
Pet. Gasol.
Pet. Distill.
Shale Gasol.
Shale Distill.
Coal Gasol.
Coal Distill.
Higher Oxys - 100%
Higher Oxys - Blend 8
Ethanol - 100Z
Ethanol - Blend
Methanol - 100Z
Methanol - Blend8
Hydrazlne
Ammonia^
Methane
Hydrogen
Otto Str. Ch.
Homo. Hetero.
Intermit. Intermit.
Spark Spark
26 5* 140b
—
—
(270) (140)
(270) (140)
43-45h
(270) (140)
(50-2000)
50-2000
230k
235™
EXHAUST EMISSIONS - NO*
Exhaust Emissions -^ms/MMBTU
Diesel Brayton Rankine Stirling
Hetero. Hetero. Hetero. Hetero.
Intermit. Continuous Continuous Continuous
Comp. Not appl. Not appl. Not appl.
(230) 12-356 19-106f
282C 230d (10-40) (20-105)
(280)
—
—
(230) (10-40) (20-105)
40 i
(230) (10-40) (20-105)
—
265-530"
Fuel Cell
—
—
—
—
—
(0)
(0)
(0)
(0)
(0)
—
(0)
Note: See footnotes following Table 4-15.
EPA-460/3-74-009
-------
Footnotes to Tables 4-13, 14, and 15
a - Avg. 1972 cars. (1972 FTP) (4-83)
b - Honda - 1975 FTP (4-87)
c - Mercedes 220 D modified (4-88)
d - Assumes 11 mpg (4-77)
e - Estimated; LA-4 Driving Cycle (4-89,90,91)
f - Simulated 13 Mode Calif.-Cycle (4-92); CVS Test Simulation (4-93)
g - Estimated for 30% alcohol blend assuming emissions will be same as
for gasoline corrected for reduced gasoline concentration in blend.
h - No exhaust cat. or EGR. UHC is mostly methanol. 1972 FTP- (4-82)
i - From combuster rig - exit temp. - 1400°F, 3 atmos. press., air flow
1.6 Ibs./sec. (4-49)
j - Several studies are in considerable disagreement (4-3,84)
k - Cold-start, seven mode Federal Test Cycle (5.8 miles/test) (4-81);
UHC largely methane
m - With 25% exhaust recycle (4-55)
n - Calculated for jet engine - cruise conditions
p - Code: NA - not applicable
q - NO emissions from fuel cell assumed to be nil because of low
x
reaction temperatures
* Original 1976 Federal targets. Note: refer to page 74 for
assumptions regarding gms/mi and gms/MMBTU conversions.
- 73 -
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engines, the data are from units without exhaust emission treatment or
exhaust gas recycle, except for the hydrogen-Otto cycle case which em-
ployed 25% exhaust recycle (4-55). The emission performance shown for
the Brayton, Rankine and Stirling engines are estimated from data ob-
tained in connection with EPA sponsored research directed at the develop-
ment of low emission engines (4-77,89,90,91,92,93).
For the purpose of orientation, the relationship between
gms/mile in the Federal standards and gms/MMBTU is indicated below
assuming a vehicle having a fuel economy of 13 miles/gal.
Standards: 1973 Interim 1975 Original 1976
Cms/mi Cms/MMBTU Cms/mi Gms/MMBTU Cms/mi Gms/MMBTU
HC 3.4 390 1.5 195 0.41 47
CO 39 4460 15 1720 3.4 390
NO 3.0 345 3.0 345 0.4 46
x
Actual data on emissions from alternative fuels are relatively
scarce, which accounts for the many blanks in the tables. However, an
attempt was made to estimate (indicated by parentheses) the emission
characteristics in the cases where there was felt to be a close similar-
ity with petroleum fuels. For example, methanol/gasoline blends were
assumed to have the same emissions as gasoline run at the same equiva-
lence ratio. The expected higher aromatics concentration of coal-derived
fuels relative to petroleum was taken as sufficient reason not to assume
similar exhaust emissions (4-129). As pointed out in Section 6.1, shale
gasolines, if catalytically reformed to 90-100 Research octane number,
also have a high concentration of aromatics , as do petroleum reformates
of the same octane number. Of course, there is a high probability that
the fuels from coal and shale will be used by blending with appropriate
materials from petroleum. Such blends will approximate current petroleum
gasolines and distillates in properties and behavior and would be ex-
pected to have similar exhaust emission characteristics.
The dashed spaces in the table indicate impractical fuel-engine
combinations. The following observations are based on the tabulated
emissions data of Tables 4-13 to 4-15.
1. Hydrocarbon and Carbon Monoxide Emissions
Hydrazine, ammonia and hydrogen will of course emit no hydrocar-
bons or carbon monoxide directly under any combustion conditions.
It is possible, however, that burning lubricating oil can reach
the combustion chamber and form these components.
-------
- Hydrocarbon fuels alone and in alcohol blends will probably meet
1977 automotive emission targets if they are burned under proper
conditions (e.g., in a stratified charge, diesel, or steady-state
combustion system). Exhaust treatment may allow these standards
to be met in a conventional Otto cycle engine.
- The emission characteristics of the unblended highly aromatic
coal and shale liquids and the 100% alcohol fuels need to be
established. There are data (4-82) indicating that 100% methanol
emits less hydrocarbons and carbon monoxide than a hydrocarbon
gasoline in an Otto cycle engine. A contributing factor is the
ability of the methanol to run under leaner conditions than is
possible with a conventional gasoline (see Section 6.3).
2. Oxides of Nitrogen
- Meeting the 1976 target for NOX emissions appears to be difficult
for any of the fuels considered. There are data indicating a
number of the fuels can probably meet this goal under very care-
fully controlled combustion conditions. For example:
• Petroleum or shale source hydrocarbon fuels (including alcohol
blends) in highly developed Rankine or Stirling engine type
combustors (4-89,90,91,92,93). Data are needed on the behavior
of the coal liquids (and highly reformed shale liquids) which
contain a high concentration of aromatic hydrocarbons.
• Hydrogen under some special conditions (4-48,94); however,
supporting data have not yet been obtained.
In order to firm up and complete the picture on exhaust emis-
sion characteristics of future fuels, it will be necessary to operate a
variety of engines under optimum conditions on the various fuels. This
need for data is summarized in Section 8 of the report.
4.6 Toxicity and Safety
4.6.1 Toxicity
In judging the feasibility of alternative fuels, matters of
toxicity and associated health hazards must be examined by the manu-
facturer and marketer for the potential impact upon employees, consumers,
and the public at large. The following is a brief overview of these
considerations for several fuels. In the absence of detailed specifica-
tions and composition data, it is assumed that additives or contaminants
(trace or otherwise) will not be of toxicological significance. Product
types, where this assumption is of critical importance, will be noted.
For each fuel there will be a summary of toxicity information and a
statement of risk.
- 75 -
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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 concentration of aromatic hydrocarbons
in the coal-derived fuels is expected to be relatively high. Experience
has shown that gasolines of considerable difference in composition have
the same general toxicological properties.
(a) Toxicity - Gasolines generally act as irritants to
skin and mucous membrane and as anesthetics resulting from depression of
the central nervous system. Mucous membrane (eye, nose, throat) irrita-
tion 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.
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 during ingestion can be rapidly fatal.
The dermal toxicity of gasoline is low. It is doubt-
ful 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 related to the concentration. The olefin and aromatic content of the
gasoline is important as these materials are more potent 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 assumed importance where prolonged or repeated low level
exposure is possible. Benzene causes the destruction of the blood form-
ing 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.
(b) Hazard - oral ingestion - low apart from risk of
aspiration
skin penetration - low
inhalation - high, particularly in confined
spaces where vapor concentra-
tions can rapidly build up
eye, skin, nose, and throat contact -
moderate risk of irritancy
- 76 -
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2. Distillates from Coal or Shale. These distillates would
be expected to contain the same range of hydrocarbon types as petroleum
distillates in the 325°-650°F boiling range.
(a) Toxicity - Distillates generally act as irritants to
skin and mucous membranes. Toxicity is low by the oral, dermal, and
inhalation routes. However, aspiration, the entry of small amounts of
liquid hydrocarbon directly into the lungs, rapidly produces a severe
injury to lung tissues which may be fatal. The low volatility of dis-
tillates precludes vapor build-up unless the liquid has been heated.
Skin contact may be irritating and on a prolonged
basis can remove sufficient fat from the skin to result in a dermatitis.
Eye contact results in only slight, transient irritation.
(b) Hazard - oral ingestion - low apart from risk of
aspiration which is very
hazardous
skin penetration - low
inhalation - low
skin, eye, nose, and throat contact - low
risk of irritancy; increasing
with increased severity of
exposure
3. Methanol. The following comments regarding methanol would
also apply to blends containing significant amounts of the alcohol.
(a) Toxicity - Methanol is both an irritant and a central
nervous system depressant. The low molecular weight alcohols share
these properties although their anesthetic potency is definitely less
than the comparable hydrocarbon. Toxic effects include dizziness,
stupor, cyanosis, cramps, and gastric disturbances.
Prolonged vapor exposure may also lead to headache,
ringing in the ears, tremor, and disturbances in nerve function.
Methanol is unique among the alcohols in that it produces degeneration
of the optic nerve and retina leading to complete and permanent blind-
ness. There is apparently a wide variation in individual susceptibility
to methanol.
Acute toxicity studies in animals indicate that the
lethal oral dose is 18 ml/kg vs. 12.5 ml/kg for ethanol. The toxic dose
for man may be as low as 10 mg/kg, and the lethal dose as low as 50
mg/kg. Toxic effects, including blindness, have also been reported in
man where skin absorption and/or vapor inhalation have been involved.
It is not always possible to eliminate ingestion as an additional route
of exposure in such cases.
- 77 -
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(b) Hazard - oral ingestion - very high
skin penetration - moderate
inhalation - low (industrial exposures
should be controlled to meet
TLV* of 200 ppm)
skin, eye, nose, and throat contact - slight
to moderate
4. Ethanol. The chief difficulty associated with ethanol
exposure under industrial circumstances involves willful ingestion.
(a) Toxicity - Ethanol is a local irritant to mucous mem-
brane and a central nervous system depressant. The action first involves
inhibition of higher functions and later increasing degrees of anesthetic
action. In this respect it is more potent than methanol.
Acute toxicity studies in animals point to a lethal
dose of 12.5 ml/kg. The lethal dose for man is estimated to be 3 g/kg
body weight (approximately 1/2 pint of absolute alcohol taken all at
once). Although it is possible to produce toxic effects by skin absorp-
tion, the necessary conditions of exposure are such as to make it most
unlikely. Absorption of toxic amounts of ethanol by inhalation is nor-
mally not encountered because the odor and mucous membrane irritation
become intolerable before anesthetic concentrations are achieved.
Repeated or prolonged exposures to ethanol vapor apparently have no
chronic effect in man.
(b) Hazard - oral ingestion - moderate
skin penetration - low
inhalation - low (industrial exposures
should be controlled to TLV
of 1000 ppm)
skin, eye, nose, and throat contact - slight
(skin) to moderate (mucous
membranes)
5. Higher Oxygenates. Processes such as the Fischer/Tropsch
may yield mixtures of aliphatic alcohols, with lesser amounts of alde-
hydes and ketones. Certain general statements can be made regarding
such products. With the lower alcohols, toxicity tends to increase with
increasing carbon number up through Cg. Skin penetration and irritancy
effects also increase. Although the volatility is less with increasing
molecular weight, the toxicity and irritancy are also greater. On
balance, the hazard from the higher alcohols would be judged lower than
for methanol and ethanol.
* TLV - Threshold Limit Value
- 78 -
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With respect to ketones, industrial exposure has occurred to
a considerable degree without significant health effects. Although the
ketones may be toxic, the irritancy of the materials provides fairly
effective warning. The vapors are considered narcotic, but concentra-
tions required to produce obvious effects are also irritating to mucous
membranes of the eyes, nose, and throat. Lower concentrations, not
likely to produce discomfort, may lead to some impairment of judgment.
In general, the toxicity irritation, and anesthetic potency increase
with increasing molecular weight. Irritancy and toxicity also increase
with increasing unsaturation. The liquids are painfully irritating to
the eyes, and prolonged and repeated skin contact can irritate as well
as lead to dermatitis from the defatting action of the solvent. Skin
absorption is not likely to result in toxic effects from the common
saturated ketones.
Aldehydes have generally produced only local reactions without
severe cumulative effects under occupational exposure conditions. The
local reactions consist of irritation of skin and mucous membranes of
the eyes, nose, and throat. The response is most characteristically
seen with the lower molecular aldehydes, particularly with unsaturation
in the aliphatic chain. Aromatic aldehydes tend to be less irritating.
Sensitization, a specific form of heightened responsiveness, is well
known with formaldehyde and may also occur with other aldehydes. This
effect is ordinarily associated with liquid contact and is only rarely
reported from vapor inhalation. Some aldehydes (paraldehyde and chloral
hydrate among others) have a definite anesthetic action, but this is
much weaker with the typical aliphatic aldehyde. In general, the irri-
tating properties of the aldehyde prevent voluntary exposure to toxic
or anesthetic concentrations.
6. Methane. This hydrocarbon gas is a simple asphyxiant.
The only physiological effects seen are the result of a decrease in the
available oxygen due to the presence of methane. It has no warning
properties. The limiting factor in exposure is the partial pressure of
oxygen which should not go below 135 mm in atmospheres containing no
toxic gases or vapors. Compounds such as methane and ethane are explo-
sion hazards, and whatever precautions are taken to avoid this risk are
adequate to protect against asphyxia.
7. Ammonia. The physiological effects of ammonia are
directly traceable to its ability to produce local severe irritation of
tissues.
(a) Toxicity - 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
irritant properties 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 reported at 400-700 ppm. Exposures of 2500-
6500 ppm have been judged dangerous for 0.5 hour, and 5000 ppm and above
- 79 -
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is believed to be rapidly fatal. High concentrations of ammonia in
addition to the corrosive action on eyes, throat, and respiratory tract
may also reflexly affect heart and respiratory action. Moist atmospheres
containing 1% or more ammonia may cause increasing amounts of skin irri-
tation including chemical burns with blistering. There is no evidence
of cumulative or chronic toxic effects following prolonged or repeated
exposures to tolerable atmospheric concentrations.
(b) Hazard - oral ingestion - unlikely for a gas
skin penetration - low
inhalation - moderate (industrial exposures
should be controlled to TLV of
25 ppm)
skin, eye, nose, and throat contact -
variable, depending upon con-
centration; can be high where
exposure is severe
8. Hydrogen. This odorless, colorless gas acts as a simple
asphyxiant. The physiological effects result from a decrease in avail-
able oxygen due to the presence of hydrogen. There are no warning
properties, and the onset of asphyxia may be insidious. The precautions
taken to prevent fire and explosion are more than adequate to protect
against oxygen deprivation and consequent asphyxia.
4.6.2 Safety
The major issue in fuel safety involves flammability and
danger of accidental detonation. Coal and shale-derived hydrocarbons
will require the same degree of caution as do the analogous petroleum
products. The lower flammability limits of methanol and ethanol are
3-6% in air, and caution is required. Data on the flash point indicate,
however, that the alcohols are safer than petroleum-derived fuels.
Ammonia has fairly narrow limits of flammability combined with a high
lower limit (16-25%) relative to the other fuels and should be fairly
safe if properly handled. Methane must be handled with great care,
particularly in the liquefied form. The proper procedures have been
worked out in the natural gas industry. Nevertheless, the widespread
use of methane, as LNG, in automotive transportation, would present
serious safety problems. Similar considerations apply to hydrogen,
which has been widely used as a liquid in the space program. The wide-
spread use of this fuel in distribution networks, service stations, and
on-board vehicles, is a cause for considerable concern. The question
is whether the advantages of a fuel such as hydrogen, or methane, are
sufficient to justify the stringent safety program needed to handle the
hazards. Hydrazine is another fuel with serious potential safety prob-
lems. It has the one mitigating property of being a liquid at room
temperature.
The safety aspects of these fuels are considered in Section
4.7, dealing with fuel selection.
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4.7 Ranking of Fuels
An attempt was made to rank fuels using a semi-quantitative
technique wherever possible. Relative costs were estimated for operating
a vehicle using the various fuels. This cost comprised two components:
direct fuel costs plus a correction to a common basis of comparison.
The data for this comparison are summarized in Table 4-16.
The fuel cost in $/MMBTU, from Table 4-10, was first translated
into a cost over the life of the car, taken as 100,000 miles, using as a
basis an average of 13 miles per gallon for conventional gasoline in a
spark-ignition engine. This value was corrected for relative vehicular
efficiency by making the assumptions* that:
(1) the passenger vehicle in the 1985-2000 period will
consume 25% less BTUs per mile than the average 1973
vehicle.
(2) this vehicle fuel efficiency is independent of the
fuel (as a first approximation).
(3) the future hypothetical engine will be able to burn
either gasoline or distillates.
Each of these simple assumptions is of course open to criticism.
For the purposes of this simple ranking procedure, it does not matter
which power plant is chosen as long as it can handle all the fuels under
consideration, and as long as there is no major change in efficiency due
to the fuel. As for the constant efficiency assumption, two perturba-
tions were briefly considered involving efficiency debits (as measured
by changes in fuel economy) due to (1) exhaust emission control equip-
ment and (2) incremental car weight due to weight changes of the fuel
storage system. The first of these reduces fuel economy on the order of
5% (4-16). This was felt to be insignificant in this type of simple
analysis. The second was estimated using the data in Table 4-3. The
efficiency correction was calculated to be quite small, ranging from zero
for coal and shale liquids to 7% for ammonia and hydrogen. This was also
factored into this comparison. The second column in Table 4-16 gives the
corrected total fuel costs over the life of the vehicle.
The next column deals with fuel-vehicle compatibility as dis-
cussed in Section 4.4. In order to quantify this criterion, a cost was
estimated for adjusting the vehicle to make it compatible with the fuel.
The following costs were used:
A somewhat more detailed analysis of fuel-related cost in operating
an automobile is given in Section 5.5 for the more promising fuels.
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TABLE 4-16
oo
K)
INITIAL SCREENING OF FUEL CANDIDATES
Criterion:
Fuel
Coal Gasoline
Coal Distillate
Shale Gasoline
Shale Distillate
Methanol
Ethanol
Higher Oxys
Hydrogen (Liquid)
Methane (LNG)
Ammonia
Hydrazine
Cost at Pump
$/MMBTU
3.33
2.75
2.65
2.05
3.45
7.10
4.60
10.20
5.65
7.65
20+
Efficiency
of Use
•
2,150
1,800
1,750
1,300
2,450
4,850
3,250
7,200
3,900
5,100
14,000
Corapt. with
Vehicle
0
0
0
0
50
50
50
800
600
400
100
Envir . Impact
of Use
250
200
250
200
100
100
150
0
50
300
350
Totals
Toxicity
50
0
0
0
50
0
0
0
0
200
200
Safety
50
0
50
0
50
50
0
200
150
150
200
2,500
2,000
2,050
1,500
2,700
5,050
3,450
8,200
4,550
6,150
14,850
Ranking
4
3
2
1
5
8
6
10
7
9
11
EPA-460/3-74-009
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Fuel
Alcohols
Hydrazine
Vehicle Changes*
Ammonia
Methane
Hydrogen
• increased fuel tanks, lines
• improved gasketing material
• provide for partial decomposition
to yield H2-rich fuel for best
results
• special materials of construction
in fuel lines
• heavy, bulky fuel storage
• special plumbing and carburetion
or fuel injection
• partial decomposition to H_ for
best results
• heavy, bulky fuel storage
• special plumbing and carburetion
or fuel injection
• same as methane, but more costly
due to lower temperature
(liquid hydrogen) or complexity
(hydride chamber)
Estimated Cost, $
50
100
400
600
800
* From column on stratified charge engine of Table 4-12.
The next column gives estimates of the costs of pollution con-
trol equipment. As a reference, an estimate of $250 (4-18) was used for
the total cost of emission control equipment with conventional fuels.
It was judged that the same cost would apply to gasoline made from coal
or shale oil. The cost for using other fuels was estimated by consider-
ing the nature of the emissions relative to gasoline-type fuels.
Ammonia and hydrazine were assumed to require additional equipment to
handle ammonia in the exhaust and any increase in nitrogen oxides.
Finally, changes in the vehicle required to correct safety and
toxicity problems with these fuels are indicated in the next two columns
of Table 4-16. Ammonia and hydrazine are debited the most for toxicity
and hydrogen and hydrazine the most for safety (with ammonia and methane
not far behind).
Adding up the cost gives the totals and the ranking shown on
the table. It is interesting to note that this relative ranking would
be the same if only the direct fuel cost component were considered.
In view of the importance of fuel cost in this ranking, it is
necessary to comment on the accuracy of the data. The costs quoted are
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rough screening costs, and are probably no better than ±10% for the coal
and shale fuels and significantly less accurate in the case of the other
fuels. No attempt was made in this part of the study to assess the
economic effect of technology improvements. Furthermore, since the
costs were obtained by adjusting values from the literature, their accu-
racy is inherently limited.
As regards the effect of new technology, however, there is no
a priori reason to assume that the production costs of one fuel would be
reduced more than another. Overall, it is the contractor's judgment
that a more detailed economic analysis of the cost of all the alternate
fuels would not change the relative ranking of coal and shale derived
liquids (gasoline, distillate, methanol, and higher oxy compounds)
versus ethanol, hydrogen, methane, ammonia, and hydrazine.
The next step in this simple ranking analysis dealt with those
criteria which could not be readily quantified, but which were felt to
have an important bearing on selecting fuels for detailed consideration.
One of these is earliest date of general availability, defined as
approximately five years after a fuel is commercially Introduced. Using
the introduction dates of Table 4-7, it appears that all of the candidate
fuels could be made generally available sometime in the 1985-2000 period.
Large-scale hydrogen production via nuclear electricity would come quite
late in this period, at the earliest.
Another important qualitative criterion is the ease with which
the fuel can be introduced, which is related to its compatibility with
existing fuels. On this basis, shale and coal based hydrocarbons would
score highest, oxygenated liquids would be intermediate, and compressed
or liquified gases would rate lowest. As a result, the following
ranking was developed:
Shale gasoline and distillate
Coal gasoline and distillate
Ethanol
Methanol
Higher oxygenates
Methane
Hydrogen
Ammonia
Hydrazine
The last criterion considered is quite important, but also the
most difficult to assess. It involves consumer acceptability and con-
venience. On a purely subjective basis, the fuels were rated as follows
in this category:
decreasing
fuel shift
compatibility
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Acceptability Fuel(s) Comments
High Gasoline and distillate Very much like
from coal and shale petroleum
Moderate to High Alcohols Possible concern over
odor and driveability
problems
Low Methane Concern over toxicity
Hydrogen and safety
Ammonia
Hydrazine
The overall rankings in Table 4-16 plus the qualitative dis-
cussions above were considered and the decision was made to examine
five fuels in detail:
Fuel Source
Gasoline . _, . .,
Distillate > Shale oil
J
J
Gasoline
Distillate \ Coal
Methanol
It was felt that this was the maximum number of fuel candidates which
could be analyzed in detail considering the resources available to carry
out the remainder of the study- There may be some question regarding
the absence of hydrogen from the above list, in view of the attention
which the so-called "hydrogen economy" has received. However, as is
discussed in Section 3, coal and oil shale resources are large enough to
provide for synthetic fuels capacity well into the next century. There
is no foreseeable major driving force for introducing hydrogen into the
automotive transportation fuel market in the 1975-2000 time period. Its
main advantages of clean combustion and very high energy density per
unit weight are not felt to be sufficient, relative to the best available
technology for handling other fuels, to warrant the difficult transition.
A reasonable case might be made for including oxygenated com-
pounds from Fischer/Tropsch synthesis as a fuel type for detailed analy-
sis, based on projected costs and other criteria. However, as mentioned
in Section 5.2.2, Fischer/Tropsch is a very inefficient process, par-
ticularly when geared to make special fractions, such as oxy compounds.
The production of an impure methanol, such as "methyl fuel", results in
materials which approach F/T oxy compounds in nature. Overall, there-
fore, oxygenated compounds can be considered as a variant on methanol,
which will be covered in detail.
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5. COST OF AUTOMOTIVE FUELS BASED ON COAL AND SHALE
In this section of the report, the fuels selected in Section 4
are considered in detail: gasoline and distillate from shale, gasoline
and distillate from coal, and methanol from coal. For each fuel, the
economics of manufacturing and distribution are developed, beginning
with the resource in the ground and ending at the service station pump.
The technology involved in these various steps is reviewed in sufficient
detail so that the economics can be readily understood. Starting with
costs based on technology now being developed, projections are made of
potential improvements resulting in cost reductions through the year
2000. These projections are of necessity quite speculative, but they do
serve to identify a number of technology gaps which are discussed later
in the report, in Section 8.
5.1 Fuels From Oil Shale
5.1.1 Mining
It is possible to mine shale either using surface or under-
ground methods. The major underground mining method involves the room-
and-pillar technique, in which underground "rooms" are excavated,
leaving pillars of unmined shale to support the structure. In this type
of operation 25-407, of the shale is left behind as pillars. For most of
the rich shales of ca. 35 gal/ton, which are close to the surface, it is
possible to use a horizontal entrance for the room-and-pillar mine.
This is called an "adit access" underground mine. A substantial effort
has gone into developing technology for room and pillar shale oil
mining over the last 20 years and the operation has been demonstrated
in prototype mines.
Surface mining is a well-developed technique for a variety of
ores. It requires the removal and disposal of whatever overburden is
present, followed by a quarry-like mining operation of the underlying
oil shale. The technique has not been applied to shale mining so far,
but will be explored in the Department of Interior's prototype oil shale
leasing programs. Factors determining the optimal mining method in-
clude topography, overburden, richness, deposit depth, underground and
surface water conditions, surface ownership rights, disposal problems,
and other factors.
The reported costs of open pit mining, strip mining, and adit
access (horizontal entrance) underground mining, are roughly the same,
as estimated by the National Petroleum Council. Development of
specific sites may cost more or less than indicated in the NPC study
depending upon local factors. It was therefore decided to use the NPC
analysis on adit access underground mining as the basis of the
economics given later.
Other minerals, nahcolite and dawsonite, are believed to
- 86 -
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coexist and may have some future potential for recovery with shale oil.
(5-28) Nahcolite is a sodium bicarbonate deposit, while dawsonite is a
lean aluminum bearing ore. Definition of the deposits is poor and the
extent to which they could be commercially extracted is not known. How-
ever, if later developments show that economic recovery is possible along
with shale oil, these other minerals could contribute to lower costs on
some tracts.
5.1.2 Crushing
Oil shale has resiliency and abrasive properties which lead to
difficulties in the crushing operation. The NPC study was based on a
process using heat transfer from recycled hot solids to extract shale
oil. In this type of operation, shale was reduced to particles less
than % in. in size.
In a process involving a different retorting system, the
crushing equipment may be substantially simpler. For example, the Gas
Combustion Retort of the Bureau of Mines (GCR), mentioned below, uti-
lizes shale crushed to about 3 in. and smaller, thereby requiring less
energy. However, fines of about 1/2 in. or smaller are produced and
are unacceptable to the process. Briquetting is required to utilize
these fines in the process. Alternatively, the fines for GCR may be
used in an associated recycled hot solid retort.
The estimates of power requirement, maintenance and fines
production have been based on experimental work carried out. Neverthe-
less, crushing technology will have to be demonstrated in commercial
operation.
5.1.3 Retorting*
Retorting is the process or recovering oil from the shale-
bearing rock. Several retorting techniques have been under development
for the last several years. In all probability, a mature industry will
include both recycled hot solid retorts and modifications of the Gas
Combustion Retort.
• Recycled Hot Solids Retort
The Tosco retort, a form of the recycled hot solids retort,
has been developed through semi-works demonstration and appears ready
for commercial application. It is similar to the retort used in the NPC
study which serves as the basis of this analysis. The Tosco retort is
illustrated in Figure 5-1. It used direct contact heating of small
sized shale particles with heated ceramic balls to pyrolyze the kerogen
A brief summary of shale retorting technology was given in Section
4.3 (Table 4-7) as part of the initial fuel screening.
- 87 -
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FIGURE 5-1
iUSCO II SHALL OIL RETORT
FLUE GAS TO ATMOSPHERE
1
RAW SHALE
SPENT
SHALE
COOLER
Ref: TOSCO Paper, AIChE Meeting, December 1968.
SPENT SHALE
TO DISPOSAL
EPA-460/3-74-009
-------
for recovery of crude shale oil. This retort is best suited for richer
shales, containing 35 to 40 gal/ton of oil, on which it can achieve high
recovery levels, exceeding 100% of that measured by the Fischer Assay
test* for oil content. However, leaner shales may be best recovered
using the Gas Combustion Retort, which is expected to have lower
equipment and operating costs on a ton basis, but which cannot be used
on rich shale.
The retort produces, along with the oil, a gas co-product that
has a relatively high heating value of about 600-700 BTU/SCF, which can
be used to help satisfy the large heat requirements for the process or
for subsequent shale oil upgrading. In the NPC analysis, carbon on
spent shale was assumed to be used as fuel for process requirements.
The carbon content of spent shale is about 5%, equivalent to roughly
20 MB/D of fuel oil in a 100 MB/D plant. The operation of burning
carbon on spent shale has not been demonstrated but has a large
economic incentive. Since richer shale (35-40 gal/ton)tends to become
friable when burned, burning carbon from spent shale may present special
handling and dust problems which will require close attention and
possibly new technology and equipment.
• Gas Combustion Retort (GCR)
The Gas Combustion Retort (GCR) has also been developed on
pilot plant and semi-works equipment. Technology has been improved over
the years and appears ready for commercial application. The oil content
of the feed must not be too high, since clinkering and flow problems
develop in the 35 gal/ton range. The shale size required for this
process is larger than for the TOSCO retort, thereby reducing crushing
requirements. However, particles smaller than 1/2 in. cause flow problems
in the retort. These fines may be briquetted to an acceptable size or
processed in a recycled hot solids type retort which can accept them as
is.
In the GCR, illustrated in Figure 5-2, air is introduced into
the middle of the retort where a combustion zone is created to generate
the heat required for pyrolysis of the kerogen. However, the offgas,
diluted with nitrogen from the air and products of combustion, is very
low in heating value (about 90 BTU/SCF). As a result, economic use of
the gas is limited to the immediate vicinity of the retort because
transport of the gas would be costly relative to its value. In the Gas
Combustion Retort process there is no requirement for external heat as
there is with recycled hot solids. Hence, the gas has potential for
use as refining fuel or for utilities generation. However, if refining
A standard test for measuring oil content of shale. Since the proce-
dure itself is a recovery method, recoveries referenced to it can
exceed 100% if it is a more efficient recovery process.
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FIGURE 5-2
GAS COMBUSTION RETORT FOR SHALE OIL
RAW SHALE
o a o a p P
d a p p" P
a
0 PRODUCT COOLING £7
0 ZONE D
Q RETORTING ZONE p
HEAT RECOVERY
ZONE
PRODUCT
OIL
COMBUSTION
ZONE
^
RECYCLE GAS
I
RETORTED SHALE
REF: BUREAU OF MINES R.I. 7303, p. 6, Nov. 1969,
PRODUCT GAS
- 90 -
EPA-460/3-74-nno
-------
of raw shale oil at the mine is kept to a minimum to reduce water con-
sumption, finding a use for surplus low BTU gas could be a problem.
A modification of the GCR under development has potential for
upgrading the quality of retort gas. In this modification, shown in
Figure 5-3, heat for pyrolysis is provided through externally heating a
portion of the offgas stream and reinjecting the hot gas into the
retort. By eliminating internal combustion, nitrogen from air and
combustion products are eliminated from the offgas. The spent shale in
this operation will likely have a carbon content similar to that of the
Tosco retort and could possible be used as fuel for the external heater.
The richer offgas could be economically transported greater distances
offsite and could be used in boilers or power generation not
immediately adjacent to the retort. This modification has been incor-
porated in a semi-works plant soon to begin operation in Brazil.
Spent shale from the conventional GCR operation has only about
half the carbon content of recycled hot solids retort spent shale.
Since there is no external heating requirement for the GCR, the lower
heating content may not be economically recoverable in a commercial
operation. Stripped free of hydrocarbon in the retorting operation,
this spent shale should pose no unusual disposal or reclamation
problems.
• Retort oil
In both the recycled hot solids and GCR operation, there is
likely to be a small amount of entrained dust included in the oil.
Although the level in commercial operation is not known, these solids
could pose a problem in subsequent refining operations. If the raw
shale oil is refined by coking, most of the solids will remain in the
coke. In other operations, the solids may contaminate the catalyst un-
less removed. However, with careful design of equipment or a
supplemental clean up operation, solids in the crude shale oil should
be controllable to an acceptable level.
• Environmental Concerns
There are a number of environmental issues associated with
shale oil retorting, which were mentioned briefly in Sect. 4.5. These
mainly have to do with the disposal of the spent shale from the
retorting operation.
In mining and crushing, the volume occupied by shale in-
creases due to void space between broken particles. Although retorting
causes a loss in weight of 15-20%, the volume of spent shale, even with
maximum compaction, will occupy a larger volume than the deposit re-
moved, by at least 10%. In some operations, return of some of the
spent shale to mined-out areas may be possible at a later stage in
development of the project. But even if such operations are possible,
some disposal on the surface will be necessary.
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FIGURE 5-3
PETRDSIX PROCESS USING THE CAMERON AND JONES KILN
OIL SHALE
GAS
INJECTORS
DISCHARGE
GRATE
tttt
SHALE
OIL
FURNACE
RECYCLE GAS
ACE^ _
T
HIGH-BTU
GAS PRODUCT
FUEL
COOL RECYCLE GAS -
130°F
Ref: Proceedings of the First Five Oil Shale Symposia, 1964-1968, p. 319,
Colorado School of Mines.
- 92 -
-74 -009
-------
Surface disposal envisions filling box canyons with spent shale
and providing facilities to catch and retain drainage from the area.
When development of the project starts, the land will of course become
unavailable or unusable for grazing and forage until revegetated.
Original vegetation in the immediate disposal area will be covered and
in nearby areas disturbed. However, the disposal area itself is ex-
pected to be stable. Spent shale will compact or set similar to Portland
cement in the presence of water. Therefore, if adequately watered
during disposal, leaching and erosion should be controllable.
The Department of Interior, in their Environmental Impact
Statement, for the prototype leasing program, (5-2) estimated the impact
of a 1 MMB/D industry on surface requirements. They foresaw a need for
up to 80,000 acres over a 30 year period for mining, processing, spent
shale disposal utility corridors, urban needs and all associated
facilities. Of this, up to 50,000 acres are required for processing,
about 15-20,000 acres for urban development, and about 10,000 acres for
utility corridors. Through backfilling of processing land, use may be
reduced to about 35,000 acres, of which about 15,000 acres could be used
for other purposes.
Restoration of land is an area of major uncertainty. Rainfall
in the semi-arid shale oil region is sparse, averaging about 10-16 inch/
year. In addition, spent shale salt content is high. Consequently,
restoration of the land will require salt-resistant vegetation that will
use little water after it is established. Vegetation has been re-
established on spent shale disposal areas in tests, but uncertainties
over its permanence remain, particularly for a large scale operation,
after the initial period of watering and caretaking stops. Additional
research and development work must continue in this activity as the
shale oil industry grows.
Special procedures and controls will be required to guard
against free oil remaining on spent shale. Normally, there should be no
oil on spent shale, but during upset conditions, special handling may be
needed to remove retained oil. As will be pointed out subsequently, the
cost of spent shale disposal is not expected to be excessive, assuming
that the techniques so far demonstrated are shown to be valid in large
scale operation.
Another area of concern involves the population influx
associated with a rapidly growing industry in a sparsely populated area.
Estimates made for coal conversion (5-26) indicate that a large mining
and upgrading operation might involve 1,500 employees, which increases
to ca. 20,000 persons total, including families, support workers, store
owners, teachers, etc. This kind of estimate would probably hold for
shale operations as well, and points up many potential problems which
have to be addressed.
In situ Recovery
In view of the environmental concerns associated with
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above-ground retorting, there is increasing interest in developing an
underground, in situ, retorting technique. The recent Department of
Interior study (5-2) summarizes the studies carried out to date, which
indicate that fracturing of the impermeable shale rock was very diffi-
cult. It is crucial that an efficient method be developed for genera-
ting such permeability, so that the heat for retorting can be introduced
and the products withdrawn efficiently. (8-1)
The use of nuclear explosives has recently been proposed
(5-3) to fracture the shale. Occidental Petroleum has announced an
in situ technique which involves conventional explosives to collapse a
partially mined area, followed by in situ retorting (5-4). Another
approach involves the use of acid-generating microbes, injected into the
shale formation, to leach the dolomite away from the shale oil, making
it easy to recover (5-5).
It is too early to tell whether in situ retorting truly
provides an effective method for recovering shale oil with minimum
environmental effects and at reasonable costs. It is quite conceivable
that the in situ technique may lead to other environmental problems,
such as subsidence or underground water contamination. This will have
to be checked out in test programs. In addition, it will be necessary
to demonstrate that good recoveries can be achieved. Much more data are
needed to develop meaningful economics for in situ retorting.
5.1.4 Shale Oil Upgrading
As a refinery raw material, shale oil has a high pour point,
as well as high nitrogen and sulfur content. The properties of raw
shale oil from the Tosco process are shown on Table 5-1. The
properties of GCR shale oil are quite similar to those of the Tosco
retort. Sulfur and nitrogen must be removed either at the shale oil
mining site or in the refinery where the shale oil is to be processed.
The NPC study assumed a severe upgrading to remove sulfur and nitrogen,
while reducing pour point, according to the scheme illustrated in
Figure 5-4. The properties of the synthetic crude produced in such an
upgrading operation are shown in Table 5-1.
An alternate to the severe upgrading operation located at the
mine is to do a minimum amount of processing at the mine, just enough
to make the raw shale oil pumpable via a pipeline to a central refinery
location. This minimum processing would consist of simple coking or
"visbreaking" to reduce viscosity and pour point. This approach will
probably be favored as a large shale mining and retorting industry
develops in the Rocky Mountain area. One driving force for such a
change is water availability, as discussed below.
The synthetic crude produced by the upgrading scheme in the
NPC study is actually superior in quality to the average U.S. petroleum
crude. As shown on Table 5-1, the syncrude has only 50 ppm of sulfur
and 350 ppm of nitrogen. It contains 2870 naphtha, with the balance in
-------
TABLE 5-1
TYPICAL PROPERTIES OF
CRUDE SHALE OIL AND SYNTHETIC CRUDE (Ref 5-1)
Gravity, °API
Pour Point, °F
Sulfur, wt 7o
Nitrogen, wt 7,
RVP,(T' psi
Viscosity, SUS(2) at 100°F
Analysis of Fractions
Butanes and Butenes, vol 7,
C5-350°F Naphtha
Vol %
Gravity, °API
Sulfur, wt 7,
Nitrogen, wt %
K Factor(3)
Aromatics, vol %
Naphthenes, vol %
Paraffins, vol 7»
350-550°F Distillate
Vol 7o
Gravity, °API
Sulfur, wt 7o
Nitrogen, wt 7»
Aromatics, vol %
Freezing Point, °F
550-850°F Distillate
Vol 7o
Gravity, "API
Sulfur, wt 70
Nitrogen, wt 7,
Pour Point, °F
850°F-Plus Residue
Vol 7,
Gravity, °API
Sulfur, wt 7,
Nitrogen, wt 7,
Crude
Shale Oil
28.0
75
0.8
1.7
120
4.6
19.1
50.0
0.70
0.75
11.7
17.3
31.0
0.80
1.35
33.0
21.0
0.80
1.90
26.0
12.0
1.0
2.4
Syncrude
46.2
50
0.005
0.035
8
40
9.0
27.5
54.5
<0.0001
0.0001
12.0
18
37
45
41.0
38.3
0.0008
0.0075
34
-35
22.5
33.1
<0.01
0.12
+80
None
(1) Reid vapor pressure
(2) Saybolt Universal Seconds
(3) Empirical characterization factor related to specific gravity and
molecular weight.
EPA-460/3-74-009
- 95 -
-------
FIGURE 5-4
FLOW DIAGRAM FOR UPGRADING CRUDE SHALE OIL
(Ref. 5-1)
GAS
TREATING
HYDROGEN SULFIDE
NAPHTHA
NAPHTHA
550>F
LIGHT OIL
AND NAPHTHA
LIGHT
OIL
• STEAM
• PROCESS GAS
• FUEL GAS
DISTILLATION
HEAVY OIL
CRUPE SHALE OIL
ICM.OOO B/CD
•f*-fna Point
A
k
VAI
>OR
k-
RESIO r
DELAYED
COKER
CATALYTIC
HYDRO-
GENATION
HYDROGEN
PLANT
H,
CATALYTIC
HYDRO-
GENATION
STABILIZER
1—<
SEPARATOR
WATER
AMMONIA -
HYDROGEN
SULFIDE
SEPARATION
WATER
SULFUR
PLANT
FUEL GAS
100.000 B/CD
SYNCRUDE
250 T/CD
AMMONIA
100 T/CD
SULFUR
1.450 T/CD
COKE
EPA-460/3-74-009
-------
the distillate boiling range. Only 15% of the crude boils above 650°F.
As pointed out later, it is an excellent crude for refining to automo-
tive fuels.
5.1.5 Water Requirements
The table below summarizes the water requirements for a
100 MB/D shale syncrude plant.
Water Requirement for 100 MB/D
Synthetic Crude from Oil Shale
Mining and Crushing
Spent Shale Disposal
Retorting
Upgrading
Total
Acre ft
Yr
300
3000
6000
7200
16,500
lOOO's Gal
Day
268 1.8
2678(1) 18.2
5356 36.4
6427 43.6
14,729 100.0
(1) Not required to be fresh water
The Environmental Impact Statement of the Department of
Interior estimates that there is sufficient water available to support
a 1 MMB/D industry by 1985. The study did not undertake to define the
limits water might impose on the ultimate capacity of a shale oil
industry. The table above shows that about half the water requirement
is involved in upgrading the raw shale oil at the mine, according to
the scheme of Figure 5-4. If this upgrading were moved to a refinery
remote from the mine, by simply making the raw shale oil pumpable, the
water requirement at the mine site would be substantially lowered. Water
availability and its relationship to ultimate shale oil capacity remains
a area of uncertainty which requires additional study.
5.1.6 Economics of Syncrude Production
Review and analysis of recent literature on shale oil
indicates that the NPC study entitled: "U.S. Energy Outlook: Oil Shale
Availability" provides a reasonable basis for determining the steady-
state costs of producing shale syncrude. The study looked broadly at
various types of mining and three levels of oil content.
In applying the NPC results to this study, some adjustments
were made and alternatives considered:
• Project and Process Contingencies
Consideration was given to a possible adjustment to the
contingency level of the project cost estimate. For major projects
- 97 -
-------
where the processes are well known, e.g., a refinery project, a project
contingency is generally added to allow for omissions, factors over-
looked, and other unknowns. In early stages of development, where
design details are lacking, the contingency factor may be in the range
of 15-2570 and in later stages, with well defined projects, only about
10%. Under the generalized circumstances for the shale oil plant des-
cribed in the NPC study, the 2570 project contingency was used.
An additional factor must be considered when the process
itself is not well defined, or is under development. This involves un-
certainties about process operations and their relationship to equipment
and facilities.
During these early stages, experience shows that costs may be
substantially underestimated. Usually after additional development work,
uncertainties are reduced which reduces the probability of under-
estimating a project. it is very difficult to choose an appropriate
level of process development contingency for shale oil plants. As a
result of the experience on similar, large projects at an early stage
of development, it is reasonable to expect that the initial cost
estimates of this study may be 10-5070 low. As more plants are designed,
built, and operated, experience will generate technology improvements
and begin to reduce costs. The NPC study estimated, for example, that
costs might be reduced by about 107o due to the learning curve factor.
In the economics discussed below, it was decided to base costs on the
NPC investment and operating costs, adjusted to the basis of this study.
However, the sensitivity of these results to higher investments is cal-
culated .
• Economic Basis
In examining the NPC study, economics were developed for a
100 MB/D case using 35 gal/ton shale. In developing this breakdown,
the underlying economic factors were also reviewed and some minor
changes in the NPC basis were made;
1. Depreciation life was assumed to be 16 yrs. on retorting and
refinery instead of 15 years.
2. Sum of years digits depreciation was used instead of combination of
double declining balance and straight line.*
3. 507o Income Tax was used instead of 5270.
* See Appendix 7 for details and definitions.
** The first commercial shale oil plants on the Dept. of Interior proto-
type tracts have been announced to be at the 50 MB/D level, but these
will doubtless be expanded after commercial operation is successfully
demonstrated.
- 98 -
-------
4. Three months start-up with incurred costs but without production was
deleted.
5. 27» salvage on all investments was credited at the end of their use-
ful life.
6. Depletion allowance of 157= of upgraded product value was used with-
out the 507, margin limitation for simplicity.
Other bases were not changed, including investment, operating
costs, pre start-up investment schedule, project life, and royalty.
These bases are shown in Appendix 7.
• Results for Base Case
The economic estimates of this study checked closely with
those of the NPC for the same grade of shale, simply because the above
changes were minor. The NPC estimate resulted in a syncrude cost of
about $4.00/Bbl (1970 dollars) at 1070 return and 35 gal/ton shale. The
present study estimated $4.64 in 1973 dollars assuming escalation of
7.17o/Yr. from $3.77/Bbl in 1970 dollars.* Following is a breakdown of
these costs by processing area.
Syncrude Production from 35 Gal/ton Shale
107, DCF Return, 1973$
$/Bbl of
Syn Crude
Mining .83
Crushing .30
Spent Shale Disposal .20
Retorting 1.44
Royalty .18
Sub Total 2.95
Upgrading 1.69
Total (excluding bonus bid payment) 4.64
All the economics developed in Section 5, as well as in other sections
of this report, are given in 1973 $ (except where specifically noted
otherwise). If these figures were corrected to a 1974 basis, the es-
calation would be more than the 10% general inflation, reflecting
higher escalation in various materials and labor costs.
- 99 -
-------
Water costs and working capital were prorated as required in
each of the operations. The mining operation cost of 0.83$/Bbl in this
case is based on room and pillar mining with adit access. These costs
should be a reasonable basis for a mature industry but some projects may
incur higher cost if the mining method and location characteristics
differ from the NPC analysis. The cost for room and pillar mining and
surface mining costs should be similar. However, open pit mining has
higher capital requirements mostly due to pre-startup development, but
operating costs are about the same as other mining techniques.
The crushing costs of 0.30$/Bbl were developed for the Tosco
type retort. It has greater crushing and briquetting requirements than
the Gas Combustion Retort on a ton basis. However, the ability of the
process to use richer shales provides an offset on a barrel basis.
Spent shale disposal represents a relative minor cost of about
0.20$/Bbl, of which 0.07-0.08$/Bbl is related to investment and
0.12-0.13$/Bbl to operating cost. At this point in time, however, there
are still major uncertainties involved in spent shale disposal, many of
which are site dependent. These include availability of a satisfactory
disposal area, amount of spent shale that can be returned to the mines,
use of conveyors versus trucks, amount of spent shale and compaction for
a given operation, water availability for dust control and restoration,
dusting problems, and others. As commercial experience develops, these
uncertainties could well be resolved at substantially higher costs than
those given above.
The retorting cost of $1.44/Bbl is based on Tosco type re-
torting of 35 gal/ton shale. This retorting process, as was mentioned
earlier, has been demonstrated on a semi-commercial scale in Colorado.
Because of the nature of the equipment, there are uncertainties as to
durability of equipment and service factor. Initially, retorting costs
may be higher than indicated, but as trouble spots are eliminated and
technological improvements are implemented, costs should be reduced to
the level shown.
A royalty payment was assumed at the level set by the Depart-
ment of Interior prototype leasing program of 12£/ton for 30 gal/ton
shale, + Ic/ton for each gallon/ton greater or less than 30. For 35 gal/
ton shale, the 17c/ton royalty is equivalent to about 18c/Bbl of syncrude
after considering depletion allowance. At this level, the royalty is a
small portion of the overall cost.
An additional cost which has not been included in the table
is the bonus bid lease payment. As shown by recent bids for the first
tracts under the U.S. Department of interior prototype leasing program,
the bonus bid payment is likely to be a major cost component of
producing shale oil. Time value of money is particularly significant
when considering the high bid of $210 million for the first lease in
1974 and projected start-up in 1980. Assuming the bids are payable in
five annual payments beginning in 1974, the additional cost per barrel
of syncrude at 10% return is about $1.00/Bbl for a 50 MB/D plant with a
- 100 -
-------
20 year life. At 15% return, this cost is increased to $1.64/Bbl. A 30
year project reduces costs only slightly to 90<:/Bbl at 10% and $1.56/
Bbl at 15% return, because the additional earnings are so far in the
future. Building a second 50 MB/D plant five years after the first re-
duces the costs to 62$/Bbl at 10% and $1.10 at 15% return. A third
plant of 100 MB/D after 5 more years reduces costs to 42^/Bbl at 10% and
82c/Bbl at 15% return.
The upgrading cost of $1.69/Bbl represents the largest cost of
producing synthetic crude from rich shale deposits. Processes and
operations are reasonably well known and the costs estimates should be
reliable for first generation facilities. Longer term potential exist
for reducing investment and operating costs through improved catalysts
for sulfur and nitrogen reduction. Nitrogen reduction was assumed to be
a particularly difficult operation in the NPC study. Research in
progress in the petroleum industry on the desulfurization of heavy feed-
stocks might have application to the catalysis of nitrogen removal from
shale oil.
As was mentioned earlier, since shale oil upgrading uses large
quantities of water, future shale oil recovery plants may be built with
minimum upgrading facilities, relying on refineries in consuming centers
for this operation. Under this concept, onsite upgrading would simply
consist of a process to reduce pour point in order to make the crude
shale oil pumpable by pipeline.
Upgrading produces byproducts such as coke, ammonia, and
sulfur. Coke was valued at $4/Ton, ammonia at $30/Ton, and sulfur at
$15/Ton. Taken together by-product values reduce the cost of shale oil
by about 15
-------
Effect of Shale Richness on Syncrude Costs
$/Bbl of Syncrude
Mining
Crushing
Spent Shale Disposal
Retorting
Royalty
Sub Total
Upgrading
Total (ex bonus bid payments)
Basis: 107=, DCF, 1973$
25 gal/ton
1.16
.41
.27
2.02
.11
3.97
1.69
5.66
35 gal/ton
0.83
0.30
0.20
1.44
0.18
2.95
1.69
4.64
In this estimate royalty is based on 7c/ton for 25 gpt. Again, the re-
torting costs are based on the Tosco retort but for the leaner shales
the Gas Combustion Retort, possibly with some modification, is likely
to see economic application. The GCR has less complex equipment and
operation but lower recovery. The GCR costs have not been developed in
detail as have the Tosco retort costs, but work that has been done in-
dicates that costs should be lower for leaner shale.
The costs shown here and in the NPC study represent
operations where optimal size units have been achieved, and where
leaner shale requires only additional units of similar size. Upgrading
costs therefore are not directly proportional to shale oil content.
(2) Return on Investment
The NPC estimated the total investment for a 100 MB/D syncrude
shale oil plant (adit access underground mining of 35 gal/ton shale) at
$643MM- (1970 costs corrected to 1973 basis). This total includes
$393MM for mining, crushing, spent shale disposal, retorting and asso-
ciated water, and working capital, and $250MM for upgrading.
Because of this large investment, return on investment has a
very significant impact on cost. The table below shows the estimated
syncrude cost for three return levels and two grades of shale:
- 102 -
-------
Effect of Return Level on Syncrude Cost, $/Bbl
Return Level
35 gpt Oil Content 5% 10% 15%
Cost, 1973$/Bbl
Mining, Crushing
Ash Disposal, Retorting, Royalty 2.35 2.95 3.65
Total Including Upgrading 3.50 4.65 5.95
25 gpt Oil Content
Mining, Crushing
Ash Disposal, Retorting, Royalty 3.15 3.95 4.95
Total including Upgrading 4.30 5.65 7.30
Bonus bid payments have not been included in these sensitivities, but
were considered in subsequently calculating the gasoline and distillate
cost.
(3) Investment Level
As indicated earlier, costs for large projects involving new
technology are likely to be underestimated. The costs shown previously
have been based on those shown in the NPC report. The following table
shows the effect of a 50% investment increase on syncrude cost for two
return levels:
Effect of Investment Escalation on Syncrude Costs
35 gpt Oil Content
1973 $/Bbl Syncrude
% DCF return 10 15
Investment Base +50% Base +50%
Mining, Crushing, Ash Disposal
Retorting, Royalty 2.95 3.70 3.65 4.75
Total, including upgrading 4.65 6.10 5.95 8.00
As expected, the effect of investment escalation is substantial.
(4) Water Costs
It would be possible to bring water by pipeline from the
Pacific or the Mississippi to the shale producing areas of the Rocky
Mountains. The economics of this scheme have not been examined in
detail. However, as a first approximation, if the transportation costs
are assumed to be the same as pipelining equivalent volumes of crude
oil over the same distance, it could add about l$/Bbl to the syncrude
costs.
- 103 -
-------
(5) Range of Potential Costs
The economic sensitivity calculations carried out above provide
a range of expected costs of shale syncrude. The lowest cost in this range
would correspond to a case based on 35 gal/ton shale, 10% DCF return, plus
a 50c/Bbl effect of bonus bid, giving a total of $5.15/Bbl. A reasonable
upper limit in this range would be a case with a 30 gal/ton shale, 12% DCF,
25% investment escalation, plus a 50c/Bbl bonus bid, giving a total of
$7.15/Bbl.
5.1.7 Shale Syncrude Refining
A separate study was carried out to determine the cost of refin-
ing shale syncrude to gasoline and middle distillate. This was combined
with a refining study of coal syncrude. This refining study was carried
out as a separate unit, and since it involved a fair degree of detail in
analyzing refinery operations, it is presented intact as Appendix 8. Rel-
evant parts" will be discussed and summarized separately in the coal and
the shale section.
s t udy:
Following are some of the key parameters of the shale refining
1. Shale syncrude, as indicated by the properties shown on
Table 5-1, is quite different from conventional petroleum crude in that
it contains no "bottoms", i.e., material boiling above 850°F-975°F. Con-
sequently, the refining sequence employed does not need any bottoms con-
version processes.
2. The syncrude contains very little sulfur and nitrogen, which
reduces the need for hydrotreating during refining.
3. The study was referenced to a 100 MB/D refinery located on
the U.S. Gulf Coast.
4. Two cases were considered: one to make only gasoline, and a
second to make both gasoline and distillate in the ratio of 2.4/1. For
reasons explained below, this ratio is the maximum prudent distillate pro-
duction*. This has important implications for distillate cost. The gas-
oline was refined to 91 Research octane number (unleaded) and the distil-
late to 50 Cetane Number.
5. The overall processing sequence is summarized schematically
in the flow sheet on Figure 5-5. The syncrude is distilled into various
fractions which fall into two types: initial/375°F, which goes directly
The issue of distillates vs gasoline production, as it affects crude
utilization, is considered, for petroleum crude, in an amendment to
the present contract and is summarized in a separate report.
- 104 -
-------
FIGURE 5-5
SIMPLIFIED SYN CRUDE REFINERY
SYN CRUDE
180 °F
D
I
S
T
I
L
L
A
T
I
0
N
M^^
180/375°F
375/650°F
1
1
1
1
1
1 .
650°F+
REFORMER
RE FORMATE
CONVERSION
INIT/400°F
400/650°F
GASOLINE
DISTILLATE
- 105 -
EPA-460/3-74-009
-------
into gasoline production, and 375°/650+°F which, is aimed primarily at dis-
tillate production. In order to achieve the octane number required for
gasolines, the 180/375°F fraction of the syncrude is catalytically reformed.
This is a process which primarily converts paraffins to aromatics (typified
by the dehydrocyclization of heptane to toluene) along with some dehydrog-
enation (e.g., cyclohexane to benzene) and isomerization (e.g., normal to
lightly branched hexanes).
The other processing step is a conversion of heavier to lighter
material. The preferred process is catalytic cracking, which produces
some lighter products to be blended into gasoline as well as the primary
400/650°F fraction for distillate.
In the case of maximum gasoline production, two steps are taken:
(a) the conversion process on Figure 5-5 is changed from cata-
lytic cracking to hydrocracking, which is a more severe operation producing
much more lighter material.
(b) all the 375+°F material is fed to this process, as shown by
the dotted line.
In the case of maximum prudent distillate production, it is nec-
essary to:
(a) back out the 375/650°F fraction from catalytic cracking.
(b) replace hydrocracking with (mild) catalytic cracking.
Even so, as mentioned under point (4) above, the distillate yield is only
35% on syncrude.
6. The economics of refining are presented in terms of the cost
of gasoline and distillate made by the above processing schemes. Since
these are co-products, there is a question of allocation of costs between
them. This was done by calculating total costs for the two cases of max-
imum gasoline and distillate production, and then solving for the individ-
ual cost as two unknowns from two simultaneous equations.
The results of the refining cost analysis are as follows:
- 106 -
-------
Auto. Fuel Product: Gasoline Only Distillate**
$/Bbl* $/MMBTU $/Bbl* $/MMBTU
Syncrude 5.61 1.13 5.47 1.0
Refining
ex fuel 2.00 0.40 0.19 0.04
fuel @ 6$/Bbl (ca $!/
MMBTU) 0.27 0.05 (0.29) (0.05)1"
Total 7.88 1.58 5.37 1.00
Lower Heating Value , qs 5 /0
MMBTU/Bbl
* Cost is $/Bbl product; corresponds to syncrude at $5.27/Bbl (includes
$0.62/Bbl large bonus bid for two 50 MB/D plants).
** Co-product with gasoline.
t This small credit to cost is due to the assumption that by-product
fuel at $1/MMBTU is worth slightly more than the syncrude at $5.61/Bbl.
The high quality of the shale syncrude is reflected in the fact that it
is possible to produce about 30% distillate by very simple processing.
Actually, the table above indicates essentially a zero net cost of re-
fining to distillate. In all refining processes, some gas is produced
which has fuel value. Since shale syncrude has a relatively high H/C
ratio, significant quantities of gas are produced, which are a credit
against the refining costs. However, it is worth stressing again that
the distillate costs are valid only for a situation in which the gasoline/
distillate ratio is ca 2.4/1. If attempts are made to increase distillate
yield at the expense of gasoline, the cost would rapidly escalate to the
point where distillate becomes more expensive than gasoline. The analysis
of this situation is beyond the scope of this contract.
As mentioned earlier, the gasoline produced by this scheme has a
91 lead-free Research octane number (RON). The emphasis on fuel economy
in the future will probably involve a trend to higher octane numbers. This
can be achieved by more severe catalytic reforming. The effect of increas-
ing octane number on refining cost is not large, over reasonable increases.
For example, based on the data in (5-6) , refining cost would increase about
13C/MMBTU (1.5c/gal) if the gasoline octane increases from 91 to 96 RON.
Another way to present the economics is on the basis of capital
investment required per unit product. This leads to the following result:
- 107 -
-------
$/B/D
Auto. Fuel Distillate Plus
Product: Gasoline Only Gasoline
Syncrude* 6660
Refining 2020
Total 8680 6880
* Based on syncrude at $6240/B/D.
These investments will be compared with coal-derived fuels in Section 5.4.
5.1.8 Distribution and Marketing
The distribution and marketing of alternative automotive fuels is
expected to have much in common with the current system used for petroleum
fuels. Much of the same physical system may well be utilized. The alter-
nate to tying in with the existing system is essentially to duplicate an
investment which now has a replacement cost in excess of $15 billion.
Table 5-2 gives recent and projected expenditures of the domestic petro-
leum industry. It indicates that marketing investments alone, which are
strongly weighted towards automotive fuels, are expected to average $1.75
billion annually between now and 1985. These expenditures would, of course,
be exclusive of any investments for a separate distribution system involving
an alternative fuel.
• The Existing Distribution System: In view of the above con-
siderations, it is worth outlining the elements of the existing petroleum
distribution system before considering these functions in relation to the
alternative fuels. Figure 5-6 is a very simple diagram illustrating the
principal steps involved in bringing petroleum from tens of thousands of
wells to hundreds of refineries. The diagram also shows the relations
between oil and gas distribution and marketing.
Figure 5-7 illustrates how petroleum products move from the re-
finery to a bulk terminal and from there, in the case of motor gasoline, to
the service station. The same system is used for delivery to large consumers
except that the latter will have their own storage facilities, and would be
able to accept delivery in bulk by barge, railroad tank car, or whatever is
the cheapest mode of delivery for the quantity of product involved. The
delivery of gasoline or diesel fuel to fleet accounts is analogous to the
case of large consumers except that location and quantity will probably
favor delivery by tank truck.
- 108 -
-------
TABLE 5-2
RECENT AND PROJECTED EXPENDITURES OF THE
DOMESTIC PETROLEUM INDUSTRY
BILLIONS OF 1970 DOLLARS
Exploration & Production
Natural Gas Plants
k
Pipelines
*
Tankers
Refineries
fi
Marketing
Chemical Plants
Other
TOTAL
ACTUAL EXPENDITURES
1970
1971
8.890
7.965
CUMULATIVE INVESTMENTS
1970 - 1985
140
5
13
7
25
25
10
15
240
Subtotal for Transportation
and Marketing
2.000
2.025
45
Subtotal as % of Total
22.5
25.4
18.8
Source: Chase Manhattan Bank Study, reported by Oil and Gas Journal,
March 26, 1973
EPA ^60/3-74-009
- 109 -
-------
FIGURE 5-6
MAIN ELEMENTS OF TRANSPORTATION. STORAGE AND DISTRIBUTION
OH WELL
GAS WELL
PIPELINE GATHERING SYSTEM
PIPELINE GATHERING SYSTEM
GAS/OIL SEPARATION PLANT
•—STABILIZED CRUDE
(ASSOCIATED) NATURAL GAS-
, NATURAL GAS PLANT
NATURAL GAS LIQUIDS (NGL)
1 NATURAL GASOLINE
— PIPELINE
REFINERY
PETROLEUM PRODUCTS
PIPELINE
MARINE TERMINAL
TANKER
RECEIVING TERMINAL
REFINERY
PETROLEUM PRODUCTS
LPG
PETROCHEMICAL FEED STOCKS
1 ALSO:
1 DRY NATURAL GAS
i
i
CRYOGENIC STORAGE
CRYOGENIC TANKERS
LNG RECEIVING TERMINAL
I
REGASIFICATION
I
PIPELINING TO CUSTOMERS
GAS TREATMENT (H2S REMOVAL etc.)
DRY NATURAL GAS
NATURAL GAS TRUNK PIPELINE
DIRECT DELIVERY
TO LARGE
INDUSTRIAL CUSTOMERS
STORAGE CAVERNS etc.-
LOCAL DELIVERIES BY
GAS UTILITIES
EPA-460/3-74-009
-------
FIGURE 5-7
MAIN ELEMENTS OF PETROLEUM DISTRIBUTION FROM
PETROLEUM REFINERIES
BULK DISTRIBUTION
LOCAL DISTRIBUTION
REFINERY
PETROLEUM PRODUCTS
1
COASTAL TANKER BARGE ^PRODUCTS PIPELINE
_
1
T
1.
RAILROAD
i
i
I
— — i
BULK TERMINAL '
BULK TERMINAL
ERMI
TANK TRUCK
RETAIL OUTLETS
(SERVICE STATIONS FOR AUTOMOTIVE FUELS AND LUBES)
ALSO: MINOR QUANTITIES OF FUELS DISTRIBUTED IN DRUMS BY TRUCK
- Ill -
EPA-460/3-74-009
-------
The distribution system for automotive fuels has grown over a
period of more than 60 years and is in practice much more complex than the
outline shown in these two figures. Although all major petroleum companies
use the same basic system, the mix of their individual operations may vary
greatly.
Another aspect of the marketing and distribution system is re-
lated to the seasonality of fuel demand. The peak demand for automotive
fuels occurs in the summer while the peak demand for distillate fuel (heat-
ing oil) is in the winter. The petroleum industry deals with this season-
ality by a combination of inventory buildup, conversion processes, and
imports. Entirely new ways of balancing seasonal demand might be required
when alternative fuels enter the market. It is most likely, however, that
the alternative fuel will be absorbed on an incremental basis without dis-
location, but with progressive adaptation of the existing balancing mech-
anisms. This will only be possible if the alternative fuels are compatible
with conventional fuels and their distribution system.
• Shale Fuel Distribution System: For the purposes of this
analysis, it is reasonable to assume that the distribution system for shale-
derived fuels will be completely analogous to the one described above for
petroleum. However, it is extremely difficult to be precise in projecting
costs for this operation with a new fuel. The reasons for this lie in the
great variations possible in the present system. For example, the distance
between various points in the distribution network varies markedly through-
out the country. As is pointed out above, the transportation mode between
the refinery and the bulk terminal or between the bulk terminal and the
service station varies greatly. Finally, the service station itself, which
contributes the largest increment to the distribution costs, can be a company-
owned station, a company-leased station, or a privately owned station. The
economics for the retail operation differ substantially among these alter-
natives .
In Section 4.3 distribution costs were estimated for all the al-
ternative fuels in the initial list. In view of the above complexities,
it is beyond the scope of this study to make a more detailed analysis.
Consequently, the distribution costs mentioned in Table 4-9 were used:
$0.90-1.00/MMBTU from the refinery gate to the service station pump. This
number will be used for both the shale and coal derived hydrocarbon fuels.
A different situation exists for methanol as will be discussed in Section
5-3.
These distribution costs are average for the U.S. during the
first half of 1973. An analysis based on more recent data would be ex-
tremely complicated and misleading, due to two factors: (1) price in-
creases allowed to dealers to maintain their overall profit in the face
of reduced volume during shortages and (2) higher foreign oil prices re-
sulting in wide variations of gasoline price, reflecting the percentage
of foreign oil content in the gasoline.
- 112 -
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1982
Gaso.
1.70
0.95
2.65
Dist.
1.10
0.95
2.05
1990
Gaso.
1.60
1.00
2.60
Dist.
1.00
1.00
2.00
2000
Gaso.
1.15
1.00
2.15
Dist.
0.65
1.00
1.65
5.1.9 Cost Projections; 1982-2000
The economics for shale derived fuels developed in the previous
sections can be taken as typical of "steady-state" operation of the first
generation of plants. Based on the timetable of the prototype leasing
program, 1982 is taken as a reasonable date for these economics. As part
of the study, however, an effort was made to predict changes in cost for
the period 1982-2000, reflecting such things as new and improved technology.
It was decided to choose 1990 and 2000 as the two dates for estimating such
changes. The results of this projection are given below:
$/MMBTU (1973 $)
At Refinery*
Distrib. and Marketing
At pump, ex t ax
* Includes pipeline transportation of raw shale oil or syncrude to a Mid-
West refinery.
For the 1982-1990 period, it was assumed that:
(1) The technology of retorting and upgrading would result in a
10% cost reduction. This is in line with the NPC prediction and reflects
the fact that this technology is fairly mature. It is very likely that
the location of the upgrading operation will move from the shale-mining
area to the refining centers of the Mid-West or the Gulf Coast. This will
affect water availability in the mining area, but will not significantly
affect overall economics.
(2) A new pipeline system would have to be built to transport
the syncrude (or mildly treated raw shale oil) to the refining center.
This would increase pipelining costs ca. $.05/MMBTU over the cost of
$0.10/MMBTU in 1982. This latter figure assumes that spur lines will be
built to tie into existing pipelines which have spare capacity.
(3) No significant change would occur either in the refining
of shale oil or in the marketing of the gasoline or distillate.
For the 1990-2000 time period, it was assumed that:
(1) The lease bonus payments would have a much smaller effect
on project DCF return not only because the absolute payments would nec-
essarily be smaller (leaner ores, more difficult recovery), but because
- 113 -
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a growing industry would provide a larger output against which this pay-
ment would be debited. A $0.10/Bbl cost was assumed for the lease pay-
ment, rather than $0.62/Bbl in the 1982 base period.
(2) In situ retorting would be developed. Based on some very
preliminary economics in (5-3), a cost of ca. $2.00/Bbl was taken for
in situ retorted oil.
(3) Upgrading of the raw shale oil would be improved 25% over
this period.
(4) No significant change would occur either in the refining of
the shale oil or in the marketing of the gasoline or distillate.
Similar projections are made for coal-derived fuels in Section
5.2.6. The relative costs for the various fuels can then be assessed over
the time frames of interest.
5.2 Hydrocarbon Fuels From Coal
5.2.1 Coal Mining
In 1973, the U.S. produced almost 600 MM tons of coal, divided
about equally between production from surface and deep mines. National
needs require coal production to expand rapidly. As discussed in Section
3, conversion to synthetic fuels could consume as much as 700 MM tons/yr.
of coal by 1995. This will require very rapid development of surface
mining in the West.
In surface mining, the overburden (ground cover) is removed to
expose the coal seam. Two types of mining can be employed: contour mining
and area mining. In contour mining, a series of pits is developed in the
form of long, narrow strips, which follow the contour of the land. This
method is used for mining hilly or steep terrain. Area mining is used for
flat or slightly rolling areas, where coal seams lie relatively parallel
to the land. The pits are designed in a strip, such that the overburden
from each strip can be cast back into the previous pit. Area mining is
employed in the Mid-West and Western states, whereas contour mining is
used primarily in Appalachia.
Surface mining has been increasing because it offers better re-
covery, lower investment and operating costs, and requires less manpower
than does underground mining. Surface mining recovers on the average~of
85% of the coal, whereas underground mining yields only 50%. Manpower
productivity, is higher for surface mining than for the mining industry as
a whole; i.e., in 1973, strip mining averaged 35 tons/man-day vs. 11.2
tons/man-day for underground mines. Present productivity estimates for new
strip mines run as high as 60 tons/man-day.
The feasibility of surface mining depends on the stripping ratio
— i.e., the number of cubic yards of overburden to be removed to recover
one ton of coal. In the Mid-West, this ratio ranges from 11:1 to 18:1,
whereas the Western states offer a lower, more economical ratio on the
- 114 -
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average of 6:1. In some areas, the ratio can be as low as 1:1. Because
of the lower stripping ratios, high productivity, and abundance of re-
serves, the Western states are a promising source for the future supply
of coal to the synthetic fuels industry.
Coal produced by underground mining in the Mid-West may increase,
primarily for use in power plants, if problems with SOX emissions can be
overcome. It is also possible that some synthetic fuels plants will be
built around this source of coal.
Underground mining methods can be classified into three main
categories: conventional, continuous, and longwall. Most of the coal is
mined by conventional or continuous mining. Both methods involve a room
and pillar system as previously described for shale mining. Conventional
mining involves a cutter, face drill, loading machine and blaster, whereas
continuous mining performs all these operations with one machine. Con-
tinuous mining is on the increase as the trend toward automation grows.
In longwall mining, tunnels are driven through the four sides of
the block of coal to be mined, thus isolating it. Slices are then made
across the width of the block (300-800 ft) by a drum-type shearing machine
moved along the coal face. The coal dug from the face drops to the floor
where it is removed by a continuous conveyor. This method is becoming more
important in the U.S. because it concentrates production in a smaller area,
providing better productivity and ventilation.
The NPC has predicted that, in 1975, continuous mining will yield
65% of total underground production, longwall mining will grow to 5%, and
conventional mining output will decline by
The projected growth in coal mining could be limited by various
factors:
(1) Manpower: Concern has been expressed by a number of industry
spokesmen that a shortage of both technical and non-technical manpower could
severely hamper the long term growth of the coal industry. Efforts will
have to be made to recruit personnel for the industry and to promote college
programs in mining technology-
(2) Transportation; It is expected that the first generation of
coal conversion plants will be located near the mines, so that only liquid
or gaseous products will have to be transported to consuming areas. How-
ever, as the coal conversion industry matures, it may be necessary to con-
sider plant sites away from the coal-mining areas. A likely driving force
for such a shift would be the long-range availability of water (see below).
Another is the problem of population growth. A large total conversion
plant plus mine is expected to employ ca. 1300 people. This implies a
total population of up to 20,000 people, including families, support ac-
tivities, etc. (5-26).
- 115 -
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At present, coal can be shipped most economically by unit trains,
dedicated solely to coal transport, and capable of carrying up to 7,000 tons
of coal. Two of these trains per day would be required to move the output
of a large 5 MM ton/yr. surface mine. However, rail costs are escalating
rapidly.
The alternative to unit trains involves slurry pipelines, in which
a 50/50 coal/water slurry is moved to the conversion site. The economics of
slurry pipelines developed to date indicate that this technique could be
cheaper than unit trains for distances greater than 600-800 miles. (5-7)
Slurry pipelines need water at the slurrying site but only about half as
much as a conversion plant at the same location.*
(3) Legislation: A number of measures before Congress in early
1974, if passed, would have a severely inhibiting effect on the development
of surface-mined Western coal. Of particular concern are provisions which
would: (a) prevent surface mining on land for which the Government holds
the mineral rights, (b) require land restoration to its exact original con-
tour, and (c) assess a high levy on mined coal to finance the reclamation
of "orphan lands" — i.e., land mined in the past (primarily in Appalachia)
without having been reclaimed according to present standards.
(4) Environmental Concerns: The major issues here are land res-
toration, water availability, and waste disposal. The Department of Interioi
estimates that about 35,000 acres of land would be disturbed in the West by
1985 due to the increased surface mining associated with coal conversion
projects. Costs of land reclamation have been estimated by NPC to vary be-
tween $0.01 and $0.20/ton depending on the yield of coal per acre and the
terrain. An average reclamation cost of $0.10 - 0.15/ton seems reasonable.
However, as in the case of shale, the economic and technical feasibility of
large-scale reclamation operations will have to be demonstrated.
As part of the reclamation system, water will have to be provided
to aid in revegetation and to prevent erosion. In general, the availability
of water in the coal-mining regions of the West appears to be greater than
in the shale-mining regions. However, a detailed assessment of water avail-
ability is not yet complete. It is part of on-going planning programs —
such as the "Northern Great Plains Resource Program" (NGPRP) organized by
the Federal Government.**
* e.g. Early in 1974, the Wyoming legislature passed a bill permitting
construction of a slurry pipeline to ship coal from northeast Wyoming
to south-central Arkansas, a distance of more than 1,000 miles. The
project envisions the use of undrinkable saline water obtained from
wells nearby the coal deposit. The pipeline would carry about 25
million tons of coal annually.
** Involving the Depts. of Interior and Agriculture, EPA, and the states
of Montana, Nebraska, N. & S. Dakota, and Wyoming.
- 116 -
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Waste disposal during surface mining involves management of ef-
fluents including slit, acid mine waters and dust. Techniques are avail-
able for handling such wastes, but they have to be demonstrated in large
commercial operations.
Mining costs and investments are briefly summarized in Appendix
9. As discussed later in the section on coal liquefaction economics, a
coal cost of $3/ton was assumed for surface-mined coal to be used in the
first generation liquefaction plants. This represents coal reserves al-
ready owned by potential producers.
5.2.2 Coal Liquefaction*
Producing a high yield of clean liquid fuel from coal requires
several conditions. Severe processing (combination of pressure, temper-
ature, and time) is needed to break down the high molecular weight coal
into smaller fragments. Large amounts of hydrogen are required to in-
crease the hydrogen to carbon ratio to levels more typical of liquid
fuels, and to react with impurities such as sulfur and nitrogen so they
can be removed more easily from the system as gaseous hydrogen compounds
(i.e., H2S and NH3).
Minerals, in the form of ash, are also present. This mineral
matter includes silicon, aluminum, iron, calcium, sodium, titanium, and
other elements. This material must also be removed to make a suitable
clean liquid fuel.
In general terms, there are three levels of processing severity
used to derive liquid fuels from coal. The least severe approach is mod-
erate to high temperature pyrolysis. Heat is used to drive off or "distill"
the volatile portions of the coal, but without adding hydrogen.
A second level of severity uses both heat and pressure. The coal
is processed under high pressure at moderate temperatures and in the pres-
ence of hydrogen. Volatile matter is driven off and portions of the coal
molecule are broken down. Hydrogen is added and combines chemically with
some of the carbon to form hydrocarbons with molecular weights lower than
the original coal molecules. This general approach is usually described
as coal liquefaction.
Finally, a third level of severity is to convert the coal mol-
ecule into hydrogen and carbon oxides through very high temperature proc-
essing and then to catalytically recombine the hydrogen and carbon oxides
into hydrocarbon materials. This approach incorporates coal gasification
with steam and oxygen followed by the Fischer-Tropsch synthesis reaction
to produce the liquid hydrocarbons.
A brief summary of coal liquefaction technology was given in Section
4.3 (Table 4-7) as part of the initial fuel screening.
- 117 -
-------
A brief review follows of some of the processes for producing
clean liquid fuels from coal, identifying those which are particularly
suitable for making automotive transportation fuels.
5.2.2.1 Pyrolysis
The schematic drawing on Figure 5-8 illustrates the general
process steps in coal pyrolysis. Coal is crushed to the particles size
needed. Then, in the pyrolysis step, heat is applied to drive off water,
gases, and liquid hydrocarbons. The oil is recovered and sent to hydrog-
enation for upgrading to either fuel oil or synthetic crude. Gas is also
recovered, scrubbed of contaminants, and made available for use as plant
fuel, hydrogen plant feedstock, or for sale as a by-product. The char
remaining after pyrolysis is available for sale as a high-BTU solid fuel.
Several pyrolysis processes are currently under development.
These include the FMC Corporation COED process (Char 0_±l Energy Develop-
ment) , The Oil Shale Corporation (TOSCO) process called TOSCOAL, and the
Garrett Research and Development process. Also, there is the Lurgi-Ruhrgas
process which has a single small commercial operating plant.
Pyrolysis processes are suited primarily for the production of
heavy fuel oils and particularly of chars. The yield of oil is only about
10-20 wt. % on dry coal, and its quality is such that severe upgrading is
required in order to make a satisfactory transportation fuel.
5.2.2.2 Hydrogenation
The second level of processing severity to convert coal into
liquids involves the chemical reaction with hydrogen at high temperature
and high pressure. The broad range of conditions at which liquefaction
has been tested runs from 750°F and 300 psig up to 900°F and 10,000 psig.
Processes currently under development generally involve operation below
5,000 psig.
The general process scheme for coal liquefaction is shown in
Figure 5-9. Prepared coal is mixed with an internally-generated slurry
oil and transported to the liquefaction reactor. In the reactor, coal is
liquefied in the presence of hydrogen. In the solids separation step, un-
converted coal and ash are removed. Gases are recovered, sent to clean-up
processing, and then used for sales or plant fuel. Liquids are sent to up-
grading for futher removal of contaminants (sulfur, nitrogen) and to in-
crease their hydrogen content. Hydrogen manufacture is another basic step
in the overall sequence.
On the bottom part of Figure 5-9 are listed the different methods
used in various processes to carry out the basic steps. In liquefaction,
the hydrogen can be provided through the use of a hydrogen donor solvent,
or by direct hydrogenation, either with or without a catalyst. For solids
separation, the methods have included distillation, coking, and the use of
hvdroclones, filters, and centrifuges. In upgrading, catalytic fixed beds
- 118 -
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FIGURE 5-8
GENERAL SCHEME FOR COAL PYROLYSIS
Raw
Coal
Heat
Process Steps
1. Coal Preparation (Crushing)
2. Pyrolysis Step
3. Oil Recovery
Synthetic
Or Fuel
Oil Product
Product
4. Gas Scrubbing And Processing
5. Liquid Upgrading
- 119 -
EPA-460/3-74-009
-------
FIGURE 5-9
GENERAL SCHEME FOR COAL LIQUEFACTION BY HYDROGENATION
Coal
Feed
t
*
••£
i
r *~ i »~ ;
1
Liquid Recycle
. „ . . "
H2
!
Net Fuel Gas
I +- 3
\
c
' ^ *"
Crude
Solids
Alternative Processing Steps
1. Liquefaction
+ H2 Donor Solvent
+ Direct Hydrogenation
- Catalytic
- Non-Catalytic
2 . Solids Separation
+ Distillation
+ Coking
+ Hydroclones
+ Filters
+ Centrifuges
Upgrading
-i- Catalytic Fixed Bed
+ Catalytic Ebullating Bed
Hydrogen Manufacture
+ Steam Reforming
-i- Partial Oxidation
+ Steam-Iron
+ Gasification Of Coal And/Or
Char
- 120 -
EPA-460/3-74-009
-------
and catalytic ebullating beds* have both been used. Hydrogen can be manu-
factured by steam reforming, partial oxidation, the steam-iron process,
and the gasification of coal or char.
Several U.S. companies have been doing research work on coal
liquefaction processes. The more publicized programs include those by
Consolidation Coal Company, Pittsburg and Midway Coal Company, Hydrocarbon
Research Incorporated, U.S. Bureau of Mines, and Exxon.
Consolidation Coal Company, under sponsorship of the Office of
Coal Research (OCR) , has done major work on a donor solvent process (5-8).
This process operated mainly at about 350 psig and 800°F in the liquefac-
tion step. Filters, hydroclones, and coking were employed for solids sep-
aration and a catalytic ebullating bed system was used for hydrogenating
the solvent and product oils. The products include hydrocarbon gases,
liquids, and a bottoms product consisting of unconverted coal and ash.
The bottoms product could also contain some high boiling liquids, depend-
ing on the solids separation technique used.
Recently, Old Ben Coal Company (an affiliate of Standard Oil of
Ohio) proposed a $73 MM, 5-year program (5-9) to construct and operate a
816 T/D donor liquefaction plant that could produce either a solvent re-
fined coal (like the Pittsburg and Midway Coal Company process described
below) or a distillate synthetic crude. Support of the program by a large
group of industrial companies as well as the Electric Power Research Insti-
tute and the OCR is being solicited.
The Pittsburg and Midway Coal Company (PAMCO), (an affiliate of
The Gulf Oil Corporation), who are also working under OCR sponsorship, have
made bench scale studies on a non-catalytic, direct-hydrogenation liquefac-
tion step at about 1,000 psig and 850°F (5-10). Hot, rotary filters are
used to separate the residual solids. The main product is a low ash, par-
tially desulfurized, and high-melting-point (350°F) solid fuel which is
called "solvent refined coal." In addition, gas and some lighter liquid
hydrocarbons boiling in the naphtha range are produced.
Hydrocarbon Research Incorporated (HRI) has worked mainly on a
high severity catalytic system which is called H-Coal (5-11). The lique-
faction is carried out in an ebullating-bed reactor which contains coal,
catalyst, product liquids and gas, and hydrogen in a mixed condition at
about 3,000 psig and 850°F. For solids separation, a combination of vacuum
distillation plus coking as well as hydroclones, filters, centifuges and a
solvent precipitation method were investigated. Since 1971, HRI carried
out bench scale and pilot plant work which included operating a 2.7 T/D
process development unit. Based on this work, HRI is proposing to build
and operate a 226-635 T/D experimental plant.
A reactor in which the catlyst is dispersed or fluidized in a liquid
(as opposed to gas fluidization).
- 121 -
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The U.S. Bureau of Mines has been studying a different type of
catalytic reactor (5-12) . The approach has been to vise a fixed bed of
catalyst operating at high pressures of up to 4,000 psig. A rapid, tur-
bulent flow of hydrogen is used to force a coal slurry through the cata-
lyst bed. A 5-10 Ib/hr pilot plant has been operated to test the feasibil-
ity of this process.
Exxon is also studying coal liquefaction, including operation of
a 0.5 T/D pilot plant. The Exxon process uses a solvent which donates
hydrogen to the coal. It also involves a catalyst external to the lique-
faction reactor. The process can produce either a low sulfur fuel oil or
a synthetic crude oil that can be processed by conventional refining tech-
niques. Several types of coals have been successfully tested. In late
1973, Exxon announced plans for an accelerated two-phase program to com-
plete the process development work. Phase I consists of additional labor-
atory and engineering work plus the design of a large 200-300 T/D pilot
plant to be completed in 1975.
5.2.2.3 Fischer/Tropsch
The most severe processing approach for making liquid hydrocar-
bons from coal is the combination of coal gasification to produce a syn-
thesis gas followed by Fischer-Tropsch synthesis to catalytically convert
the hydrogen and carbon oxides in the synthesis gas to liquid hydrocarbons.
This process sequence has been demonstrated commercially in South Africa
by SASOL (5-13, 5-14).
In the SASOL operation, coal gasifiers are used to convert the
coal to a raw synthesis gas. This gas is sent to the Fischer-Tropsch
reactors where the hydrogen and carbon monoxide are converted into hydro-
carbon gases, liquid hydrocarbons and oxygenated hydrocarbons. SASOL uses
two types of reactor systems for the hydrocarbon synthesis — fixed and
fluid bed. Their key features are shown in the following table:
Circulating Fluid Bed Fixed Bed
Kellogg/SASOL Lurgi/SASOL
Pressure, psig 300 360
Temperature, °F 600 450
H2/CO Ratio in Feed 2-3 1.5-2
Catalyst Type Fused Iron With Low Precipitated
Surface Area. Iron With High
Surface Area.
Major Liquid Product Light Hydrocarbons Heavy Hydro-
gasoline) carbons (Fuel
Oil and Wax)
- 122 -
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Both employ iron-based catalysts with physical and chemical characteristics
tailore to produce the desired products. Gasoline and lighter products are
produced in the fluid bed process and heavier products from the fixed bed
process. Process conditions and feed H2/CO ratios are set to meet the de-
sired product distribution.
5.2.3 Economics of Syncrude Manufacture From Coal
5.2.3.1 Process Selection and Economic Bases
It was decided to base this analysis on the HRI "H-Coal" process
described briefly above. There are two reasons for this:
(1) Published process and economic data are adequate (5-11,
5-15 through 5-18).
(2) According to the NPC analysis the process was judged
to show good promise for ultimate commercial devel-
opment.
The Fischer/Tropsch process was not considered further because of its low
thermal efficiency, the low yield of gasoline and distillate fractions
relative to liquefaction, and the lack of detailed published data on in-
vestments and economics.*
The H-coal process was based on the use of Western coal, which,
as discussed earlier, is found in thick seams close to the surface, making
it economically attractive. This analysis further assumed that the coal
will be liquefied near the mine and that the syncrude will be pipelined
to refineries in fuel consuming areas. As pointed out previously, the
transportation advantages of such a system have to be balanced against
potential problems with water availability and the settling of unpopulated
areas.
The liquefaction and hydrogen manufacturing balances described
below are based on Navajo coal as described in documents submitted to the
Federal Power Commission on the proposed El Paso Natural Gas SNG plant in
the Four Corners area of New Mexico (5-19). The coal has the following
properties:
Proximate Analysis Wt. %
Dry & Ash Free (DAF) Coal 64.50
Ash 19.25
Moisture 16.25
Total 100.00
As is pointed out in Section 8.1.2, however, Fischer/Tropsch could con-
ceivably become an attractive alternate if a more selective, efficient
process were developed (better catalyst?).
- 123 -
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Component Analysis (DAF Coal) wt. %
Carbon 76.26
Hydrogen 5.58
Nitrogen 1.32
Sulfur 1.07
Oxygen 15.74
Trace Compounds 0.03
Total 100.00
Heat of Combustion BTU/Lb.
Higher Heating Value 8714
Lower Heating Value 8370
Figure 5-10 describes the H-coal process in fair detail. Coal
is crushed, dried, slurried with an oil recycled from the process, and fed
to the H-Coal reactor. In the reactor, the slurry and hydrogen pass in
upward flow through an ebullating catalyst bed. The coal is converted to
liquid and gaseous products. The upward passage of the slurry and hydrogen
maintain the catalyst in a fluidized state. Unconverted coal, oil and gas
leave as overhead products, while the catalyst, which is coarser than the
finely divided coal, is retained in the reactor.
The reaction products are separated by fractionation and absorp-
tion into streams of gas, naphtha, atmospheric and vacuum gas oils, and a
vacuum bottoms, which contains heavy oil and unreacted coal. The latter
stream is fed into a fluid coker which produces gas, gas oil and dry char.
The coker gas oil and the H-Coal vacuum gas oil are fed to an H-Oil hydro-
cracker for conversion to lighter products. Plant gas is processed for
removal of hydrogen sulfide and ammonia, and sulfur and aqueous ammonia
are recovered. The naphtha, H-Coal atmospheric gas oil, and H-Oil liquids
constitute the synthetic crude which is pipelined to refining centers for
conversion to automotive fuels. The properties of this blend of fractions
which constitutes the coal syncrude, is given in Table 5-3.
Hydrogen requirements (8500 SCF/B of coal liquids) exceed the
potential which can be supplied by steam reforming the total gas made in
processing. It was assumed that hydrogen would have to be made from coal
since natural gas will not be available for that purpose. A Lurgi gasifi-
cation step was therefore integrated into the scheme to provide all the
hydrogen required.
Feed to the gasifier is coal plus char from the liquefaction
plant coker. The gasifier operation is modified from conventional SNG
production by providing for additional oxygen to increase hydrogen and
carbon monoxide production at the expense of methane. The gasifier prod-
uct undergoes the water gas shift reaction to convert carbon monoxide and
- 124 -
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FIGURE 5-10
LIQUEFACTION BASED ON "H-COAL"PROCESS
COAL
CO-
REFUSE
t
CRUSHING
SIZING
GASIFIER AND
H GENERATION
ENES
CRUSHING
&
DRYING
TARS
GASIFICATION
FOR UTILITIES
AND PROCESS
FUEL
APHTHA & GAS
H-COAL
CHAR & VAC. EOT.
J
COKING
HAR |
T GAS OIL
HYDROGEN
t
H-OIL
AGO!
IGAS fi
NAPHTHA
NAPHTHA, GAS,
SULFUR AND
AMMONIA
RECOVERY
•AMMONIA
r
AMMONIA
SULFUR
C4/375
NAPHTHA
375/675
GAS OIL
675/975
GAS OIL
GAS TO
SALES &
FUEL
- 125 -
EPA-460/3-74-009
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TABLE 5-3
PROPERTIES OF SYNCRUDE FROM H-COAL PROCESS
Boiling Range:
Gravity, °API
Vol.7, on Total
Analysis (Wt.7,)
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Initial/375°F
53.0
40.0
84.5
13.6
1.7
0.1
0.1
375/650°F
23.2
54.2
88.8
11.0
0.1
0.1
650/975°F
3.5
5.8
89.4
10.2
0.1
0.3
Total
32.4
100.0
87.3
11.9
0.6
0.1
0.1
- 126 -
EPA-460/3-74-009
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water to hydrogen and carbon dioxide. The gas is then purified by scrub-
bing out carbon dioxide, hydrogen sulfide and ammonia. Finally, the meth-
anation converts traces of carbon oxides to methane. The product gas con-
tains 95% hydrogen.
The Lurgi gasifier also produces by-product tars, phenols, etc.
Anticipating that a very large volume of by-products will accompany future
coal-based gas and liquids industries, it was decided that the by-products
should be fed to the H-Coal reactor as a portion of the slurry. As a re-
sult, the hydrogen and liquefaction areas are well integrated: the char
from liquefaction is fed to gasification, and the tar products from gasifi-
cation are fed to the liquefaction plant, along with coal fines made in
preparing feed for gasification.
A separate coal gasification section has been included to gener-
ate fuel gas for power and steam production. This avoids environmental
problems associated with large-scale coal combustion to provide process
heat and power. Coal is fed to a Lurgi gasifier which uses air rather
than oxygen. After scrubbing, the fuel gas is burned in gas turbines
which drive compressors or electrical generators. Heat in the exhaust
gas is used to raise steam for steam turbine drives and power generation.
Fuel gas produced in coal liquefaction is used as plant fuel and a small
excess is sold.
The operations are summarized in the material balance shown in
Table 5-4. The left hand column shows the inputs to and outputs from the
coal liquefaction plant. The inputs include coal, coal fines from pre-
paring coal for gasification, and naphtha, tars, and hydrogen from hydrogen
production. Output from the liquefaction plant includes synthetic crude,
gas, sulfur, ammonia and char which is sent to the Lurgi plant to supple-
ment coal. The second column indicates the inputs and outputs from the
hydrogen plant, and indicates that by-products from one operation become
feedstock for the other. The last column indicates the net overall inputs
and outputs from the complex. Coal is the sole input and synthetic crude
the principal product with small volumes of gas, sulfur, and ammonia as
by-products.
5.2.3.2 Investments and Operating Costs
Investments for producing synthetic coal liquids are summarized
in Table 5-5. Investments for coal liquefaction are based on the numbers
published in the NPC report. Adjustments were made for processing Navajo
rather than Illinois coal, for scaling the plant from 30 to 100 MB/SD, and
for escalation between 1970 and 1973. A 15% process contingency has been
applied because the processes employed have not been demonstrated beyond
the small pilot plant scale. A complete design for a commercial plant has
not yet been undertaken.
The El Paso amended submission to the FPC (5-16) was used in de-
veloping investments for making hydrogen from coal. Adjustments were made
to reflect changes required for producing a product which is primarily
- 127 -
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TABLE 5-4
MATERIAL BALANCE FOR H-COAL
PROCESS AND HYDROGEN PLANT
Inputs
Coal, ^ T/SD
Coal Fines, T/SD
Naphtha B/SD
Coal Tar, etc B/SD
Hydrogen, MHSCF/SD
Liquefaction
Plant
Hydrogen
Plant
33,201
2,200
2,191
11,079
855
26,623
(2,200)
(2,191)
(11,079)
(855)
Total
59,824
Outputs
Syn. Crude B/SD
Gas. , 109 BTU/SD
Char, T/SD
Sulfur, T/SD
Ammonia, T/SD
100,000
186.0
10,820
152
345
(10,820)
203
225
100,000
186.0
355
570
(1) Navajo Coal, properties cited previously.
Note: SD = Stream Day;
Output/Stream Day (SD) x Service Factor = Output/Calendar Day (CD or D)
- 128 -
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TABLE 5-5
INVESTMENTS FOR PRODUCING 100
OF SYNTHETIC CRUDE FROM NAVAJO COAL
MM $ (1973)
Coal Liquefaction
Coal Preparation 30.5
Coal Hydrogenation 143.2
Hvy. Gas Oil Hydrocracking 29.7
Coking Vacuum Bottoms & Char 19.5
Naphtha, Gas, Sulfur & Ammonia Recovery 27.7
Offsites, Utilities, and Tankage 69.0
Subtotal
15% process contingency
Total Liquefaction Section 367.5
Hydrogen From Coal
Coal Preparation & Ash Disposal 32.4
Gasification 83.6
Water Gas Shift 30.3
Gas Purification & Methanation 65.6
Hydrogen Compression 42.3
Tar Recovery 20.5
Sulfur and Ammonia Recovery 9.0
Oxygen Production & Air Compression 75.8
Fuel Gas Production & Treating 35.1
Utilities, Offsites, etc. 119.3
Total Hydrogen Production
Total, ex contingency
15% Contingency
Total 1013.6
(1) 91,000 barrels per calendar day assuming a service factor of 0.91 as
per El Paso proposal.
- 129 - EPA-460/3-74-009
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hydrogen, not methane. Among these adjustments were (1) decreasing pri-
mary methane yield, (2) increasing the water gas shift and acid gas re-
moval, and (3) decreasing methanation. The El Paso submission was based
on Navajo coal, which is also the coal used in this study. No process
contingency was applied to the hydrogen production section because most
of the processing proposed for the El Paso SNG plant has been commercially
tested. A 15% project contingency for the entire project has been added.
The total investment of just over 1 billion dollars is equivalent to
$11,000 per daily barrel of syncrude.
The cost buildup for this operation is summarized in Table 5-6.
A coal cost of $3/ton was assumed, as mentioned earlier. The financial
bases are spelled out in Appendix 7.
The sensitivity of these costs to coal price and return level
was calculated as follows :
Syncrude Cost
Coal Cost, $3/T $/Bbl $/MMBTU
5% DCF 6.40 1.16
10% DCF 7.97 1.44
15% DCF 10.70 1.94
Coal Cost, $5/T
5% DCF 7.10 1.29
10% DCF 8.68 1.57
15% DCF 11.43 2.07
The cost of syncrude is very sensitive to return level, which
reflects the large capital investment. The cost of coal has a significant
but not a very large effect: a 67% increase in coal cost results in about
a 10% increase in the cost of coal liquids.
In the section on shale liquids, the point was made that escala-
tions in investment are likely to occur as more detailed designs are pre-
pared based on an actual plant site, and as better data are obtained in
semi-commercial equipment. A good example of this escalation involves the
Lurgi gasification plant for the El Paso Burnham I complex, where the equip-
ment is the same as required for the hydrogen production part of the H-Coal
process. The total investment for the gasification plant increased over
100%, of which 70% was due to a better definition of the investment partic-
ularly the off-sites required. The cost of syncrude via the H-coal process
would escalate roughly in direct proportion to the total investment increase,
again reflecting the extreme degree of capital intensity of this operation.
Since the H-coal process itself is still under development, and since various
features of a hydrogen-from-coal process need to be demonstrated, it is likely
that the investment will escalate before the first plant is built. With time,
it is anticipated that technology will be developed which will lower costs, as
projected in Section 5.2.5.
- 130 -
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TABLE 5-6
OPERATING COSTS FOR PRODUCING 100 MB/SD
OF SYNTHETIC CRUDE FROM NAVAJO COAL
MM $/Yr. (1973)
Liquefaction(1)
Wages and Salaries' ' 11.7
Repair Materials (2% of Investment) 8.5
Supplier Taxes, etc. (3.5% of Investment) 14.8
Catalyst and Chemicals 9.8
Other Costs 2.3
Hydrogen Manufacturing
Wages and Salaries 15.0
Repair Materials (2.25% on Investment) 13.3
Supplies, Taxes, etc. (3.57o on Investment) 20.7
Chemicals and Catalyst 4.3
Subtotal Manufacturing Costs 100.4
10% DCF return (0.215 annual capital recovery factor) 217.9
Coal at $3/Ton (19.8 x 103 tons/yr) 59.4
By-Product Credits
Sulfur 117 x 103 Long Tons/Yr @ $15/LT (1.8)
Ammonia 184 x 106 Tons/Yr @ $50/Ton (9.5)
Fuel Gas 61.7 x 1012 BTU/Yr @ $1.65/106 BTU (101.6)
Net Cost for 33.215 x 106 Bbl/Yr 264.8, call 265
$/Bbl 7.95
$/MMBTU 1.45
(1) Utilities included in hydrogen manufacturing.
(2) Base Wage Rate - $5.57/hr plus 40% benefits.
(3) Contained ammonia in 2070 aqueous solution.
- 131 -
EPA-460/3-74-009
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Syncrude Refining
Appendix 8 gives details of the refining study for coal and eliale
syncrude. The key parameters of the coal refining study are very similar
to those spelled out for shale refining in Section 5.1.7, with one impor-
tant difference. Coal syncrude is more aromatic (hydrogen-deficient) than
shale syncrude. It therefore requires substantially more hydrogen in re-
fining, based on conversion by hydrocracking rather than simple catalytic
cracking. In general, coal syncrude requires more severe processing, which
would be more expensive.
Neither coal and shale syncrude, however, contain high boiling
fractions (975+°F material), thereby eliminating the need for bottoms con-
version processes. The simple processing scheme mentioned earlier with
regard to shale oil refining (Fig. 5-5) applies to coal refining as well.
In the case of coal, it is possible to achieve a 1:2 split between distil-
late and gasoline with prudent refining practice. The refining costs for
this case, and for the case of converting the crude essentially 100% to
gasoline, are as follows:
Auto. Fuel Product:
Syncrude
Re f i n i n g
ex. Fuel
Fuel at $6/B
(ca. $1/MMBTU)
Total
Lower Heating Value,
MMBTU/Bbl.
Gasoline Only
Distillate**
$/Bbl*
7.85
2.44
1.14
11.43
4.95
$/MMBTU
1.58
0.49
0.23
2.38
$/Bbl
8.32
1.12
0.19
$/MMBTU
1.49
0.20
0.03
9.63 1. 79
5.58
* Cost is $/Bbl product; corresponds to coal syncrude at $7.95/Bbl.
** Co-product with gasoline.
The gasoline produced by this refining scheme has a 92 Research
Octane Number. As was pointed out in the shale refining discussion, an
increase to 96 RON would incur about a 13C/MMBTU (1.5c/gal.) additional
processing cost.
The Cetane Index* of the coal distillate is predicted to be 35-38,
This is too low for use as an automotive diesel fuel, assuming that the
Cetane Index correlation holds for coal-derived distillates. A simple way
*Cetane Index is based on a correlation of API gravity and mid-boiling
point with the measured Cetane N"umber of many petroleum fractions
and distillate diesel fuels.
- 132 -
-------
to circumvent this problem would be to use a blend of coal distillate with
shale or petroleum-derived distillates. Alternatively, it is possible to
use Cetane Number improvers, such as amyl nitrate, or, perhaps, even to
hydrogenate or hydrocrack the coal distillate in an attempt to increase
its Cetane Number. This last route is expected to be quite expensive, on
the order of $3/Bbl or $0.50/MMBTU. Of course, a more general approach is
simply to use the coal distillate in applications other than diesel fuel,
where Cetane Number is irrelevant.
The following table summarizes the economics on the basis of
capital investment per unit product:
$/B/D
Auto. Fuel Gasoline Distillate Plus
Product: Only Gasoline
Syncrude* 11,000 11,630
Refining 2,550 1,270
Total 13,550 12,900
* Based on syncrude at $11,140/B/D.
5.2.5 Distribution and Marketing
It was assumed that the distribution system for coal-derived
gasoline and distillate would be completely analogous to that for petro-
leum fuels, as described in Section 5.1.8. The costs of distribution
were, therefore, taken at $0.90-1.00/MMBTU, which is the equivalent cost
for petroleum fuels.
5.2.6 Cost Projections; 1982-2000
The economics for coal-derived hydrocarbon fuels are felt to be
optimistic costs for the first round of liquefaction plants which are ex-
pected to go on stream in the early 1980's. As was mentioned in Section
5.1.9 on shale fuels, 1982 was taken as the initial time frame for economic
comparison. Projections for 1990 and 2000 were made, and are summarized
below:
1973 $/MMBTU
At Refinery
Distrib. + Marketing
1982
Gaso.
2.40
0.95
3.35
Dist.
1.80
0.95
2.75
1990
Gaso.
2.15
1.00
3.15
Dist.
1.50
1.00
2.50
2000
Gaso.
1.65
1.00
2.65
Dist.
1.10
1.00
2.10
- 133 -
-------
For the 1982-1990 period, it was assumed that:
(1) The cost of coal would increase from $3 to $5/ton. This re-
flects the fact that construction of new plants in this period will require
the purchase of coal lands from private owners or the leasing of Government
land and mineral rights. The value of this land is expected to be substan-
tially higher than present values, leading to higher coal costs. As dis-
cussed in Section 5.2.3, the estimated change corresponds to a $0.13/MMBTU
increase in syncrude cost.
(2) The cost of coal liquefaction would be 25% lower by 1990,
due to improved technology. This corresponds to a $0.40/MMBTU reduction
in syncrude cost.
(3) The cost of transporting syncrude from the liquefaction
plant to the refinery would increase by $0.05/MMBTU over the $0.10/MMBTU
base, due to the need to construct new pipelines. The lower figure assumes
that initially spur lines will be built to tie into existing pipelines
which have spare capacity.
(A) No significant change would occur in the refining of syn-
crude or in the marketing of gasoline or distillate.
For the 1990-2000 time period, it was assumed that:
(1) A further 25% reduction in syncrude cost due to improved
technology.
(2) No further change in coal costs. This may be an unduly
optimistic assumption, but there is no good basis for projecting cost
changes beyond 1990.
(3) No change in syncrude refining or in marketing of the
fuels.
5.3 Methanol From Coal
5.3.1 Process Description
Methanol can be produced from coal* via coal gasification fol-
lowed by direct methanol synthesis from carbon monoxide and hydrogen. As
It was mentioned in Section 3 that natural gas is a potential source of
methanol for automotive use. Currently, however, the demand for domes-
tic natural gas greatly exceeds the supply. Hence, there is no imme-
diate likelihood that automotive methanol will be produced from this
domestic resource. In the long run, it is conceivable that other forms
of energy could displace sufficient gas from some of its present uses
to make feasible the use of domestic natural gas as a feedstock for
fuel methanol. This study merely notes this as a possibility but does
not predict that it will occur. The source of methanol will not affect
its performance as an automotive fuel.
- 134 -
-------
summarized In Table 5-6, there are a number of coal gasification processes
under development. There are three, however, which have been commercially
proven: the Lurgi, the Koppers/Totzek, and the Winkler process.
In the Lurgi process, coal is gasified in a countercurrent moving
bed reactor operating at 300-500 psig and at temperatures of about 1,450°F
maximum (5-20). A drawing of the Lurgi reactor is given in Figure 5-11.
It is mechanically complex due to the pressure operation and the rotating
grate plus other internal moving parts. The temperature and pressure of
operation favor the maximum direct formation of methane, which also results
in the formation of liquids, such as tars and oils. The Lurgi process to
date has only operated on so-called "noncaking" coals which, fortunately,
include the Western sub-bituminous coals. A program is under way to adapt
the Lurgi process to caking coals, such as Midwestern bituminous coals.
In the Koppers/Totzek (K/T) process, pulverized coal is partially
oxidized with oxygen and steam at atmospheric pressure and a temperature of
ca. 2,700°F (5-2l). A drawing of a Koppers/Totzek unit is shown in Figure
5-12. At the high temperature, all gaseous hydrocarbons are decomposed,
and the effluent of the reactor is CO, C02, and H2. The K/T process is
very versatile with regard to feedstock. It can process coals of any rank,
as well as liquids and gases .
The Winkler process (5-22) employs a fluid bed of coal maintained
by injection of steam and oxygen (see Figure 5-13). The gasification is in
two steps for temperature control to avoid ash fusion. Like the K/T proc-
ess, the Winkler process produces almost no methane. It can be operated at
pressures up to 50 psig.
It was decided to base the economics of methanol production on
the Lurgi process, both for the case where SNG and methanol are coproducts
and for the case where methanol is the major product. The main reason for
this is that considerable published information exists on the Lurgi process.
Also it can handle the sub-bituminous coals of main initial interest for
methanol production.
The K/T or Winkler processes appear to be suited to methanol pro-
duction without coproduct SNG. However, not enough published information
is available for a detailed economic analysis. From the information that
is available, however, it appears that these processes have a low thermal
efficiency and use large quantities of oxygen. Furthermore, low pressure
operation would be an economic drawback if followed by methanol synthesis
at 750-1000 psig.
The process scheme used in this study is summarized in Figure
5-14, which compares two flowsheets, one for the production of SNG only
and the other for the production of methanol and coproduct SNG. The first
steps are quite similar: coal preparation, coal gasification, adjustment
of the H2/CO ratio by CO shifting, and removal of C02 and l^S. The major
differences are in the position of the compression step and in the steps
needed for synthesis of methanol and methane respectively.
- 135 -
-------
FIGURE 5-11
LURGI PRESSURE GASIFIER
FEED COAL
DRIVE
COAL
DISTRIBUTOR
MECHANICAL
STIRRER
GRATE
DRIVE
GAS LIQUOR
AND TAR
CIRCULATING
LIQUID
SCRUBBING
COOLER
GAS
STEAM + •" /S
OXYGEN
- 136 -
EPA-460/3-74-009
-------
FIGURE 5-12
KOPPERS-TOTZEK GASIFIER
PULVERIZED
COAL
AND
OXYGEN
STEAM
GAS
OUTLET
t
BOILER
PULVERIZED
COAL
AND
OXYGEN
WATER-SEALED
ASH REMOVAL GEAR
- 137 -
EPA-460/3-74-009
-------
FIGURE 5-13
WINKLER GASIFIER
GAS
COAL
STEAM
r-OO—*-
RADIANT
BOILER
ASH
PROCESS STEAM
WATER
OXYGEN
- 138 -
EPA-460/3-74-009
-------
FIGURE 5-14
FLOW PLAN FOR METHANOL AS
A SNG PLANT COPRODUCT FROM COAL
SNG Only
C02
1
Methane
i/oai ^
*
1 PI
us SN
X
G
0
f.
C02
£.
! +l"
*
<2S
j?
«•»
1
7
1
(1000 Ibf/in2)
(1000 Ibf/in2)
Processing Steps
1. Coal Preparation
2. Gasification
3. Shift And Purification
4. Methanation
5. Compression
6. Methanol Synthesis
7. Methanol Purification
- 139 -
EPA-460/3-74-009
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The Lurgi gasifier produces an effluent containing 014, H2, CO,
CC>2, and ^0. Sulfur will leave the reactor predominantly as H2S. Un-
gasified coal and ash are drawn off separately from the gas stream, but
fines must be recovered from the gaseous effluent after appropriate quench-
ing.
The quenched converter effluent is first passed through a water
gas shift catalyst bed where the H2/CO ratio is adjusted to about 3/1 in
order to allow subsequent methanation. Acid gases (H2S and most of the
CC>2) are next scrubbed out in the gas purification section, where heavier
hydrocarbons are also removed by a combination of condensation and other
physical separation methods.
In the methanator, CO and the small amount of C02 are converted
over a catalyst to CH4 and 1^0 with the release of large quantities of
heat. The product SNG is compressed and dried.
In the methanol flowsheet, the compression step is moved ahead
of the methanol converter, since the methanol synthesis is very pressure
sensitive. Also, since methanol is made from CO + 2H21 while methane re-
quires CO + 3H2, less shifting and C02 scrubbing are needed in a coal
gasification plant having methanol as a coproduct compared with a plant
directed at a single (SNG) product. When methanol is produced, less
methanation is, of course, required for a given size coal gasification
unit, and whatever methanation is done entails a somewhat less strenuous
heat removal problem than when SNG is produced.
The methanol facility is basically a reactor-condenser-separating
unit, without the need for a recycle compressor. Several suqh units can be
put in series to maximize the methanol yield.
The methanol product will be essentially dry, since there is
little water in the high-pressure feed gas, and the only water produced
in the reactor is derived from 002 which can be scrubbed out of the feed
to any desired level. Consequently, for fuel purposes, the only product
fractionation requirements are flashing to remove dissolved gases and
simple distillation to remove small amounts of dimethyl ether which could
lead to vapor pressure and safety problems.
By adjusting the type of catalyst and the reactor temperature
profile, it is possible to suppress or promote the formation of higher
alcohols as by-products. The recently announced "Methyl Fuel" process by
Vulcan-Cincinnati (5-23) makes a product containing 10-15% higher alcohols.
This technology is aimed primarily at large-scale conversion of foreign
natural gas to methanol for importation. It could however be adapted to
the coproduct SNG scheme.
5.3.2 Economic Basis
The coal gasification section of the process was analyzed based
on the two references cited in Section 5.2 in relation to hydrogen from
coal (5-18,19). As mentioned below, the revised El Paso economics which
- 140 -
-------
were published after the study economics were developed* has necessitated
a revision.
In order to bracket the range in methanol/gas yield from a given
size of gasification unit, two cases were considered:
(1) High Direct Methane Yield
The yield basis, which was assumed to underlie the NPC study
design, was arbitrarily taken as follows (based on general coal gasifica-
tion experience):
Direct yield of CH4 in
gasifier effluent = 40% of ultimate CH4 product
H2/CO ratio in
gasifier effluent = 2/1
CO/C02 ratio in
gasifier effluent = 1.2/1
Shift requirements, CC>2 removal load, and methanator duty were
estimated baeed on the above yield assumptions. The achievable methanol
yield, after compressing the gas to about 1,300 psig, ahead of the con-
verters, was assumed to be equivalent to commercial levels which allow a
build-up of inerts (City) in the recycle gas to a level of 20-35%. Over-
all, 23.5% of the fuel product effluent of this case was methanol, with
76.5% SNG corresponding roughly to a 1/3 ratio.
The rough material balance is shown in Table 5-7. It is inter-
esting to note that the total energy output from the coproduct scheme is
somewhat higher than that from the SNG-only case. The size of the methanol
unit is 3,575 T/D (25,700 B/D). Considering that the heating value of
methanol is only half that of a light hydrocarbon on a volume basis, this
methanol unit is only equivalent to a 12,000 B/D petroleum refinery —
i.e., a relatively small and, hence, uneconomical unit.**
(2) Low Direct Methane Yield
Keeping the total coal feed to gasification unchanged from the
NPC basis, the yield pattern was assumed to be changed to a much lower
direct methane yield in the gasifier. This change was brought about by:
(1) increasing the oxygen requirement (43% increase), (2) operating the
unit at higher temperature and (3) making whatever revisions in reactor
geometry necessary to undo the very intent of the conventional coal gas-
ifier design (to maximize direct methane production). For purposes of
* Based on data in NPC's: "U.S. Energy Outlook - Coal Availability"; 1973.
** More precisely, the 12,000 B/D applies to the refinery yield of gasoline
Typically, this quantity of gasoline would be produced by a refinery
charging about 24,000 B/D of crude oil.
- 141 -
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TABLE 5-7
SIMPLIFIED MATERIAL BALANCE FOR
METHANOL/SNG COPRODUCT PLANT
(a) High Direct Methane Yield
Basis; Per 100 mols of SNG Product
No Methanol Coproduct
Methanol Coproduct
Component
(dry basts)
i
H>
£-
ro
'
H2
CO
CC-2
CH3OH
Gas if ier
Effluent
40
160
80
66.7
Shift C02 Scrubber Methanation
Effluent Effluent Product
40
180
60
86.7
40 100
180
60
8 8
Shift C02 Scrubber
Effluent Effluent
40
171
69
77.7
40
171
69
7
Methanol
Effluent
40
101
34
7
35
Methanation
Effluent
74
-
-
7
EPA-460/3-74-009
-------
of the present study, It was assumed that these changes reduce direct
methane yield from 40% to 5%. Compared to the yield pattern in the pre-
vious, high yield case, the 35 mols of methane/100 mols product not made
directly were simply assumed to leave the gasifier in the partially ox-
idized form of equivalent (CO + 2H£).
With a lower methane concentration in the gas, methanol repre-
sents a far greater proportion of the total plant product — specifically,
a split of 90/10 on a BTU basis between raethanol and SNG. The methanol
facility in this case is sized for 11,338 T/D or 81,400 B/D which is equiv-
alent to a medium-size petroleum refinery. The simplified material balance
for this case is shown in Table 5-8.
Originally, the NPC study investments were used as a basis for
the gasification and gas treating portions in the present study. This in-
formation is shown in Table 5-9. The investments for the different parts
of the plant were adjusted from the base case by means of the material
balances to reflect the effect of coproduct methanol synthesis. These
adjustments are shown in Table 5-10.
The methanol plant investments were prorated from curves in
(5-24) and an estimated breakdown of conventional steam reforming/methanol
plant investments according to the following:
Section % of Investment
Feed Preparation and Steam Reforming 40
Process Gas and Recycle Compression 15
Synthesis Loop (ex Compression) 30
Two-Column Finishing 15
100
Since the investments for the large methanol plants in the above
reference have only a one-column finishing section, the numbers were ad-
justed to reflect this change when distributing the total investment among
individual plant sections. Details for the methanol investment in the high
and low direct methane cases are shown in Table 5-11.
Aa was mentioned in Section 5.3, the recent FPC submission by
Steams-Rogers on the El Paso gasification project showed much higher in-
vestments than the original costs given in the NPC study. Most of the
change was due to a large increase in offsites and utilities and, of
course, escalation over the three-year period 1970-1973. Also, the cost
of the coal preparation facilities increased nearly four fold. These
changes and the new basis, namely the 1973 El Paso FPC application + 15%
contingency, are shown in Table 5-12.
- 143 -
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TABLE 5-8
SIMPLIFIED MATERIAL BALANCE FOR
METHANOL/SNG COPRODUCT PLANT
Component
(dry basts)
H2
CO
CO 2
CH3OH
(b) Low Direct Methane Yield
Basis: Same coal feed to gasifier as in Table 1
Gasifier Shift C02 Scrubber Methanol
Effluent Effluent Effluent Effluent
5
230
115
66.7
5
231
114
67.7
5
231
114
6.7
5
9
3
6.7
Methanetion
Effluent
8
6.7 (or less)
111
EPA-460/3-74-009
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TABLE 5-9
INVESTMENT FOR 270 MM SCF/D 900 BTU/SCF GAS
COAL GASIFICATION PLANT (LURGI BASIS)
Basis: NPC 1973 Study: U.S. Energy Outlook--Coal Availability
(Noncaking Coal)
Total Investment, including working capital: $209 MM
By Sections _ 7. of Investment $ MM (1973)
Coal Handling 4 8.4
Oxygen Plant 25 52.2
Gasification 23 48.1
Water Gas Shift 6 12.5
Gas Purification 22 46.0
C02 Scrubbing 17.6 36.8
Oil Removal 4.4 9.2
Sulfur Recovery 4 8.4
Methanation Section 16 33.4
Methanation Step 13.8 28.9
Product Compression 2.2 4.5 _
209.0
EPA-460/3-74-009
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TABLE 5-10
ADJUSTMENTS TO COAL GASIFICATION INVESTMENTS
FOR COPRODUCT METHANOL CASES
(Based on NPC Report Investments)
Investment, $ MM (1973)
Coproduct Cases
Section
Coal Handling
Oxygen Plant
Gasification
Water Gas Shift
C02 Scrubbing
Oil Removal
Sulfur Recovery
Me tha nation Step
Product Compression
Proration Basis
Coal Feed
0 8
(Oxygen Rate)
(Effluent)0'7
1/2 of investment constant "*)
f\ /. i
1/2 of inv. (shift load)u>4f
1/5 of investment constant N
4/5 of inv. (C02 load) 5 J
constant
constant
(Methanation load)
2 units, 0.95 factor; and"^
Base
Case
8.4
52.2
48.1
12 5
A ^ • ^
36.8
9.2
8.4
28.9
High Direct
Methane
8.4
52.2
48.1
11.2
35.3
9.2
8.4
21.7
Low Direct
Methane
8.4
69.6
53.3
6.2
33.3
9.2
8.4
6.5
0.5 index on H.P.
EPA-460/3-74-009
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TABLE 5-11
ESTIMATED INVESTMENT IN EffiTHANOL FACILITIES
Basis: (5-23)
High Direct Low Direct
_ Case _ Methane Yield Methane Yield
Methanol Rate, T/D 3,575 11,334
Estimate Basis, T/D 1 x 3,575 2 x 5,670
Conventional Plant, Onsite Investment
$/T/D (1973) 11,000 9,600
$MM 39.3 103.4*
Coproduct Plant, Methanol Section
Investment, $MM
Synthesis Section 12.8 33.5
Finishing Section 3.2 8.4
Offsites, Utilities & Working Cap. 9.3 24.5
Total 25.3 66.4
* Allows for 0.95 factor for 2 identical units built in
parallel.
EPA-460/3-74-009
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TABLE 5-12
COMPARISON OF FPC AND NPC INVESTMENTS
NPC 1973 Report
Bas is
Size of Plant
SNG, MMSCF/D
BTU/SCF
109 BTU/D
Plant Section
Ons 1 tes
Coal Preparation
Gasification
Water Gas Shift
Gas Purification
Sulfur Recovery
Mcthanation
Oxygen Plant
Total Onsites
Utilities and Qffsites
Total
Investment
$MM (1973)
7.2
41.0
10.6
39.2
7.1
28.4
44 5
270
900
243
% of
Total
178.0
31.0
209.0
85
15
100
% of
Qnsites
4
23
6
22
4
16
25
100
1973 El Paso FPC Application
+ 157. Contingency
288
954
275
Investment
$MM (1973)
26.2
76.3
18.7
69.9
9.4
30.1
33.3
437.6
% of % of
Total Onsites
10
29
7
26
4
11
13
100 60
40
100
The ''Base Case" investment in Table 5-10 was obtained by applying
a U.95 power to the plant capacity ratio (in 109 BTU/D), i.e.,
Base Case"Investment = 437.6 x
243V
275^
0,95
= $389 MM
This gave the same result as applying an escalation factor of 1.238
for the 1970 to 1973 period to the onsites, adding incremental coal
preparation facilities and allowing for the new offsite/onsite ratio
of 40/60 vs. 15/85 before.
- 148 -
EPA-460/3-74-009
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The high, and low direct methane gasification plus corproduct
methanol investments were then revised to reflect (a) the escalation from
1970-1973 (23.8% increase), (b) the $14.4 MM increase in coal handling
facilities, and (c) the new offsite/onsite split of 40/60 vs. 15/85 in
the NPC report. These revisions are shown in Table 5-13.
As mentioned previously in this section, a considerable quantity
of by-products is made in the course of the Lurgi coal gasification. Most
of these can be used as fuel in the process or as a potential source of
liquid products. This material has been credited at $0.75/MMBTU, as shown
in Table 5-14. Different fuel values can be assumed to obtain the sensi-
tivity of methanol cost to by-product value.
Other details of the economic basis were the same as discussed
for the other fuels — e.g., financing on a 100% equity basis.
5.3.3 Cost of Methanol Manufacture
The cost of producing methanol from coal in a methanol/SNG co-
product facility was developed using the method in the NPC report as a
basis, but revising the investment according to the latest information,
as discussed above. The results are presented in Table 5-15 and indicate
methanol costs of about 8.5-12c/gal. (i.e., $1.50-2.15/MMBTU).
The NPC study had shown that with 15C/MMBTU coal (3$/ton) and
13% capital charges, SNG could be synthesized at 76C/MMBTU (high heating
value). However, this has been adjusted as follows:
(a) The much higher investments discussed previously have
been substituted.
(b) Both $3 and $5/ton coal (15-25C/MMBTU) were used.
(c) A 10% contingency has been added to the coal feed
and operating cost.
(d) A by-product credit of $0.75/MMBTU for the liquid
products has been taken.
(e) Capital charges have been raised to 21.5% (equivalent
to 10% DCF) to conform more closely to industry
standards.
(f) Gas value is expressed in $/MMBTU lower heating value.
The "Base Case" in Table 5-15 produces only SNG and is used to
price the SNG for all the coproduct cases. Depending on coal cost, SNG
costs vary from $1.66-1.88/MMBTU from a 270 MM SCF/D facility.
The methanol costs for the coproduct cases were then derived by
(1) estimating the necessary total product value needed to meet the cap-
ital charge (return) requirement for that case and (2) substracting the
- 149 -
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TABLE 5-13
INVESTMENTS FOR COPRODUCT METHANOL/SNG PLANTS
Investment,
$MM
Coproduct Cases
Case
Investment, based on NTC Report
(see Table 5-9)
Apply 1.238 escalation factor to 1973
Add extra coal handling
Add methanol^ '(from Table 5-10)
Total, before offsite adjustment
Base
Case
209.0
258.7
14.4
273.1
High Direct
Methane
204.9
253.7
14.4
25.3
293.4
Low Direct
Methane
206.5
255.7
14.4
66.4
336.5
Correct to new offsite basis
(see Table 5-11); i.e., 40/60 split vs.
15/85
389
417
475
(1) This is a 1973 investment, and therefore needs no
escalation.
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EPA-460/3-74-009
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TABLE 5-14
BY-PRODUCT CREDITS
(Basis: El Paso FPC Application)
Quantity
Assumed Value
Product
FPC
NPC
Tar
Tar Oil
Naphtha
Crude Phenol
Sulfur
20% NH3 Solution
239,250 GPD 211,600 GPD
157,370 GPD
74,900 GPD
32,470 GPD
167 LTPD
332,550 GPD
139,200 GPD
66,240 GPD
28,720 GPD
148 LTPD
294,100 GPD
Per Unit
12.9e/gal.,
i.e.,
$1.50/MMBTU
$5/LT
$50/ST NH3
$H/yr.
28.6
32,7
For Low Direct Methane Yield Cases, the same by-product credit was
assumed for the base case size plant, and triple this amount for the
large unit.
GPD = gal/day
LTPD = long tons/day (The long ton is a
standard unit in the sulfur industry;
1.0 LT = 1.12 ST.)
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EPA-460/3-74-009
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value of the gas coproduct as calculated using the SNG value from the ap-
propriate "Base Case."
The first coproduct case studied, based on high direct methane
production in the coal gasifier, can produce about 3600 T/D of methanol at
ll-12c/gal. Gas production is cut back to about three-fourths of the base
case output. As mentioned above, the overall economics were evaluated on
the assumption that the reduced quantity of SNG would be put into the prod-
uct gas pipeline at the same price as the SNG from the base case.
When the direct methane production is severely reduced much more
of the gasifier output can be diverted to methanol production. Methanol
production increases to 11,338 T/D, or more than 90% of the plant's BTU
output. The methanol cost is 12-13.5
-------
Table 5-15
ECONOMICS OF METHANOL/SNG COPRODUCT PLANT VIA COAL GASIFICATION
Methanol/SNG Coproduct
High Direct
Case
SNG, ttlSCF/D
Methanol, T/D
LHV, 106 MMBTU/yr.
SNG
Methanol
Total
Investment, $MM (1973)
Coal Cost, $/T
Manufacturing Cost, $MM/Yr.
Coal Feed
Operating Cost
Conting. @ 10% Fd. + Op.Cost
By-Product Credit
Cap. Charges, @ 21.5% Inv.*
Total Product Value
(Gas Value, $/MMBTU)
Total Gas Value
Total Methanol Value
Base Case
270
73.0
Methane
Yield
200
3,575
54.0
20.5
73.0 74.5
389
3
22.1
28.8
5.1
-18.4
83.7
121.3
(1.66)
121.3
-
5
36.8
28.8
6.6
-18.4
83.7
137.5
(1.88)
137.5
-
417
3
22.1
30.8
5.3
-18.4
89.7
129.5
(1.66)
89.7
39.8
5
36
30
6
-18
89
145
(1.
101
44
.8
.8
.8
.4
.7
.7
88)
.7
.0
Low Direct Methane Yield
Base Case Size
22
11,338
5
65
70
475
3
22.1
35.1
5.7
-18.4
102.2
146.7
(1.66)
9.6
137.1
-8
.0
.8
5
36.8
35.1
7.2
-18.4
102.2
162.9
(1.88)
10.2
152.7
Large Size Plants
65
34,000
17.5
194.9
1,144
3
66.2
84.5
15.1
-55.2
246.0
356.6
(1.66)
29.1
327.5
212
/ T \
(1)
5
110.4
84.5
19.5
-55.2
246.0
405.2
(1.88)
33.0
372.2
.4
1349 W
3
66.2
99.7
16.6
-55.2
290.0
417.3
(1.66)
29.1
388.2
5
110.4
99.7
21.0
-55.2
290.0
465.9
(1.88)
33.0
432.9
Methanol Value
$/MMBTU (LHV)
C/gal.
1.94
11.1
2.15
12.2
2.11
12.0
2.35
13.4
1.68
9.6
1.91
10.9
1.99
11.4
2.22
12.7
(1) Prorated from 11,338 T/D case using 0.8 power.
/2\ ii " ii ii ii it 0.95 "
* Equivalent to
DCF.
EPA-460/3-74-009
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FIGURE 5-15
POSSIBLE DISTRIBUTION SYSTEM FOR METHANQL
.c-
l
Coal Mine
Gasification Plant
> Synthetic Gas
Methanol
Initial Marketing as Automotive
Fuel in Limited Market Area
Railroad Tank Car
(To Major Population Center)
Bulk Terminal
Tank Truck
Retail Outlets
Large Scale Marketing
(Nationwide Distribution)
Coastal Tanker
Pipelines
i-
1 Barge
Bulk Terminals
Tank Truck
Retail Outlets
EPA-460/3-74-009
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or volume) than hydrocarbon has to be distributed for
the same energy output.
(3) Methanol is not very compatible with hydrocarbons, as
discussed in Section 6.2, so that separate equipment
will be required to move and store methanol.
The diagram on Figure 5-15 shows a potential distribution system for
methanol for two time frames. Initially, methanol from the synthesis
plant will be shipped by railroad tank car to bulk terminals near major
population centers. When the market requirements grow sufficiently, pipe-
lines will be constructed between the synthesis plants and the bulk ter-
minals .
The underlying assumption in postulating this system is that
methanol will be distributed separately from hydrocarbon fuels, even if
a blend is to be used in the automobile. In such a case the blend will
be dispensed at the service station by a mixing pump from separate stor-
age tanks. The reason for choosing this route is that methanol/gasoline
blends undergo phase instability and separation in the presence of small
amounts of water (see Section 6.2). Unless evidence is obtained that this
problem can be avoided, or that it does not lead to performance problems,
even if it does occur, it will be necessary to avoid water pickup anywhere
in the distribution system.
The modern gasoline distribution network contains many features
to assure that water contamination is minimized. This is not a difficult
objective to achieve since water is only very slightly soluble in gasoline
(ca. 200 ppm at room temperature). This means that entrained water is the
major problem in today's system. It can be minimized by proper storage
tank design, good housekeeping and, when necessary, by providing for phys-
ical separation techniques. However, the greatest opportunity for water
contamination occurs at the service station.
In marketing a methanol/gasoline blend, the distribution cost
will have to reflect a penalty associated with keeping the system dry. It
was assumed that this penalty is 40% on those components of the distribu-
tion costs which are concerned with equipment and operating procedures.
This figure is not the result of a detailed systems analysis, which is
beyond the scope of this study, but is based on experience with aviation
fuels. For example, the distribution costs of aviation fuels, which have
to be bone-dry*, are approximately 20% higher than the corresponding costs
for motor gasoline. This difference was increased to 40% for methanol
distribution to account for its much greater water affinity.
Another result of distributing methanol is the requirement for
larger bulk storage equipment and more tank trucks compared to distributing
the equivalent energy via gasoline. The optimum system has to be calculated
* To avoid the hazard associated with the formation of ice crystals under
actual flight conditions.
- 155 -
-------
for a given set of specific market parameters, but it will certainly in-
volve a combination of larger tanks, both bulk and retail, and more fre-
quent service station deliveries. The cost penalty associated with these
modifications will be significant but not large — in the order of 0.5C/
gal. gasoline equivalent, or ca. $0.05/MMBTU.
The next area to consider in markemng methanol in conjunction
with gasoline involves the service station operation. As a result of
marketing the two fuels the service station operator will have to make
investments in tanks and mixing pumps. A simple procedure was outlined
in Section 4.3 for estimating the increased retailing cost due to such
investment. The added investment was taken at $5,000 for a typical ser-
vice station, which is equivalent to ca. $0.05/MMBTU at 10% DCF.
There is a further consideration involving dealer margin which
is calculated on a per gallon basis. The service station will deliver
twice as much methanol as the gasoline it replaces. It is, of course,
unrealistic to expect that the dealer would maintain his gasoline margin
on the methanol he dispenses, which, in effect, would double his net in-
come. On the other hand, it is unreasonable to set his margin simply on
the basis of energy content, which would give him the same total income,
even though he now pumps a much greater volume. In the absence of an
economic analysis based on dealer attitude surveys, it was assumed that
the dealer would require an increased margin, of ca. 10% on a BTU basis,
above the capital recovery justified by his increased investment. This
extra margin corresponds to $0.50-0.10/MMBTU and would be justified on
the basis of the increased complexity of his operation.
The last area to consider is the distribution of methanol from
the plant to the bulk terminal. As mentioned above, it is projected that
unit trains will be used for this operation in the initial time frame
(1982). The cost for this operation was estimated to be $0.60/MMBTU
based on the energy equivalent of coal transportation, taken as $10/ton
for a 1,000 mile trip.
With this background, it is possible to estimate the total mar-
keting and distribution cost:
$/MMBTU
1. Unit train to bulk terminal 0.60
2. Distribution and marketing
• Gasoline equivalent 0.95
• Penalty for keeping system dry 0.20
• Larger tanks, lines; more
frequent tank truck delivery 0.05
• Extra service station
investment; extra margin 0.10
Total 1.90
- 156 -
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5.3.6 Cost Projections; 1982-2000
The table below summarizes the cost projections for methanol for
the period 1982-2000:
1973 $/MMBTU
1982 1990 2000
At plant gate 1.95 1.90 1.55
Distrib. and marketing 1.90 1.50 1.40
At pump, ex tax 3.85 3.40 2.95
The following assumptions were made in projecting costs for the
1982-1990 period:
(1) Coal cost would increase from $3 to $5/ton. This is con-
sistent with the assumption made in projecting the cost of coal-derived
hy dro carb ons.
(2) Methanol would be produced in plants using the low-methane
approach — i.e., maximize methanol production. Larger plants would be
built on the order of 35,000 T/D (equivalent to 100,000 B/D gasoline).
In order to take new and improved technology into account, the investment
for such a plant is scaled up from smaller sizes using a 0.8 exponent,
rather than 0.95.
(3) A pipeline from the Western coal regions, either to the
Gulf Coast or to the Midwest, will replace the unit train method of ship-
ment assumed for the first time period. The cost for this operation is
roughly equivalent to pipelining hydrocarbons on a volume basis.
The following assumptions were made in projecting costs for the
1990-2000 period:
(1) A 25% reduction in the cost of methanol due to improved
technology.
(2) Methanol will be used primarily unblended (i.e., "neat")
so that extra precautions for keeping it dry can be relaxed. However,
some measures will have to be taken to avoid batch-to-batch irreproduc-
ibility in the customer's tank due to significant variations in accidental
water pickup.
5.4 Comparison of Costs
With the information developed in Sections 5.1-5.3, it is pos-
sible to make an economic comparison among the five fuels studied over
the 1982-2000 time period. This comparison is given below in tabular
form and is shown graphically on Figure 5-16.
- 157 -
-------
FIGURE 5-16
COST PROJECTIONS FOR ALTERNATIVE FUELS
x
<
H
X
W
(X,
H
-------
1982 1990 2000
$/MMBTU Q/Gal. - $/MMBTU —
Shale
Gasoline 2.65 31.5 2.60 2.15
Distillate 2.05 26.5 2.00 1.65
Coal
Gasoline 3.35 39.5 3.15 2.65
Distillate 2.75 36.5 2.50 2.10
Methanol 3.85 22.0 3.40 2.95
Although the costs above 1973 $, ex tax at pump have been cal-
culated to +0.05 $/MMBTU, the uncertainties in the numbers are signif-
icantly greater. No quantitative attempt was made to evaluate this un-
certainty in view of the various approximations which were made in the
course of the analysis. Realistically, the limits on these costs are
estimated to be on the order of + 10%.
Furthermore, there are good reasons to believe that all these
costs, particularly those for 1982, are much more likely to be low than
high. As was pointed out in the discussion, experience with large com-
mercial ventures of a highly technical nature indicates significant cost
escalation from early design to commercialization. The effect of such
escalations was considered by applying process contingencies and by cal-
culating the economic sensitivity to further escalations. However, since
there are no compelling reasons to assume that such escalations are likely
to affect one fuel more than another, it was decided to base the compar-
ison on the base costs as calculated.
Another uncertainty involves the effect of new and improved
technology. There is no way to assess the likelihood that the new tech-
nology will result in the cost reductions indicated. The curves on Figure
5-16 therefore show a band for each fuel in the 1990-2000 period. The
upper limits of this band represent cost reduction due to evolutionary
improvements — the so-called "learning curve." The lower limits are due
to the major cost reductions that were postulated, e.g., in situ shale
retorting.
The comparison indicates that shale-derived fuels are expected
to be cheaper than coal-derived fuels over the entire time frame of the
study. Nevertheless, the development of shale fuels, as pointed out in
Sections 3.3 and 5.1, will not simply be governed by these relative eco-
nomics. The environmental, manpower, and resource limitations of a multi-
million barrel per day shale industry are expected to be controlling. The
impact of such a large shale oil industry has to be studied and the eco-
nomics of production and manufacturing have to be adjusted to reflect
various limiting factors.
- 159 -
-------
The difference in cost between hydrocarbons and methanol from
coal is of borderline significance. However, in the first time period,
methanol is significantly more expensive. This reflects the fact that
the methanol was assumed to be shipped to distribution points by train,
until the production is large enough to warrant the construction of
dedicated pipelines. Distribution costs are relatively more singificant
for methanol than for the other fuels. This suggests that it would be
more attractive in those applications where distribution costs are lower.
In the automotive transportation sector, this implies large fleet accounts,
as discussed in Sections 6 and 7. More generally, it implies that methanol
should be considered in non-transportation fuel applications, such as in
industrial fuels.
The curves on Figure 5-16 also indicate that distillates are
cheaper than gasoline from the same source. It is important again to em-
phasize that this conclusion holds only for the "prudent" refining se-
quence described in Section 5.1 where distillate and gasoline are co-
products. Attempts to increase distillate production at the expense of
gasoline would result in much higher distillate costs.
Another criterion for economic comparisons is the capital in-
tensity in the mining and manufacturing. A summary is given below:
Capital Intensity of Alternative Fuels
Production
of Syncrude* Refining Total
1973 $/B/D
Shale
Gasoline 6,660 2,020 8,680
Distillate*** 6,490 390 6,880
Coal
Gasoline 11,600 2,550 14,150
Distillate*** 12,200 1,270 13,470
Methanol 5,850(11,700)** 5,850(11,700)
* Production of syncrude includes mining investment at 5 $/T/yr.
** Number in ( ) on basis of equivalent BTU's.
*** Produced as co-product with gasoline.
In view of the great difficulty in analyzing typical investments
for distribution and marketing, it was decided to eliminate this sector in
the overall comparison. The relative capital intensities for the manufac-
ture of the above fuels parallels the relative costs at the "refinery gate"
This was expected since investment-related costs are the biggest component
of manufacturing cost. Once again, it is necessary to point out that the
lower investments for shale-derived fuels do not reflect potential limita-
tions to the development of this resource. Within the limits of accuracy
- 160 -
-------
of this analysis, methanol and coal hydrocarbons are approximately equal
in capital intensity, when compared on the basis of equal energy content.
By way of comparison, the average capital intensity for U.S.
petroleum production is about 9000 $/B/D, based on data by the Chase
Manhattan Bank as reported in (5-25). Adding an average refining cost
of ca. $2500/B/D gives a total for U.S. petroleum of about $11,500 $/B/D,
which is intermediate between shale and coal.
Finally, a comparison was made of the relative efficiencies of
manufacturing the various fuels. Such a comparison is given below in terms
of the fraction of the energy in the crude recovered in the total product:
Energy in Total Product/Total Input
Energy
Gasoline & Distillate
Gasoline Co-Products
Upgrading & Refining
0.80
0.70 0.82
0.55 0.65
Liquefaction 0.75
Refining 0.85 0.95
Overall 0.65 0.70
Methanol 0.65*
Assumes that by-products (tars, oils, etc.) from the Lurgi
gasification are used as a source of process heat; if these
cannot be utilized, the efficiency drops to 0.55.
The above tabulation does not include the energy efficiency in
mining. This reflects a convention, used in all energy statistics devel-
oped by the Bureau of Mines, the Department of Interior, etc., by which
energy used captively in producing coal, oil, and gas is excluded from
primary energy input to the U.S. economy*. However, for completeness,
mention should be made of coal and shale mining recoveries.
* It is appropriate to re-examine this convention in the context of in-
creasing concern about energy conservation.
- 161 -
-------
In the case of surface mining of coal, recoveries of 80-90% are
reasonable with the higher recoveries probably achievable in thick seams
of Western coal. If shale mining 'is. carried out by the room-and-pillar
technique, the recovery would be ca. 60%.
The data indicate that the energy efficiency for shale syncrude
production is a little lower than for coal, reflecting losses during the
retorting step. If the energy utilization in the retorting operation can
be increased to 90%, as some industry experts hope, shale and coal syn-
crude would be equivalent on this basis.
Methanol production is roughly equivalent to coal liquefaction
only if the liquid by-products during gasification can be utilized. An
energy efficiency of 55% might be more typical of gasification processes
which do not make unsable liquid by-products.
The data indicate that the co-production of distillate and gas-
oline from either coal or shale is more efficient than the production of
gasoline alone. This conclusion holds for the case studied, where the
ratio of gasoline/distillate is ca. 2/1. A modification to the present
contract is now looking into the general question of petroleum distillates
vs. gasolines on the basis of energy and crude utilization.
5 . 5 User Economics
Among the criteria used in the selection of the most promising
future fuels (see Section 3.6) are the following:
1. Fuel costs
2. Efficiency of use
3. Compatibility with the vehicle
4. Impact on the environment in use
5. Toxicity and safety
6. Driver acceptability
For each fuel and engine combination, it is possible to quantify
the compatibility, environmental impact, toxicity and safety aspects by
estimating the cost of modifying both vehicle and engine to meet antic-
ipated future standards. Fuel cost and efficiency of use can also be
quantified and are important both to the individual driver and to the
national economy. In fact, fuel cost has an impact on driver accepabil-
ity greater than its relative contribution to total costs because it is
a highly visible part of operating expense.
Driver acceptability, however, is a complex criterion that in-
volves not only cost considerations but also various aspects of perform-
ance such as ease of starting, warm-up, acceleration, frequency of main-
tenance, durability, noise, odor, and styling. As mentioned in Section 4,
it is difficult to express these aspects numerically but qualitative judg-
ments can be made. In the following paragraphs the impact of the first
five criteria mentioned above is quantified in terms of their effect on
- 162 -
-------
the cost of owning and operating a passenger car. By carrying out such an
analysis, it is possible to express the effect of all these factors in
terms of a single number: the total cost of owning and operating a vehicle
over the life of the car. This total cost is made up of two components:
(1) the variable or operating cost consisting of fuel, oil, maintenance,
repairs and tires, and (2) the fixed costs including depreciation, insur-
ance, and license and registration fees.
This analysis was limited to shale and coal gasoline, shale and
coal distillate, and methanol from coal. Although the intent of the analy-
sis is a comparison of fuels and not of engines, three engine types were
used in the comparison to explore how the fuel comparison might be influenced
by engine types. The engine-fuel combinations used were:
1. an Otto cycle engine using gasoline or methanol.
2. a Diesel engine using distillates.
3. a gas turbine engine using distillates or methanol.
The fuel comparison was calculated for the three time periods mentioned
earlier in this section: 1982, 1990 and 2000.
In calculating the total cost of operating an automobile, the
variable costs were assumed to be related to the weight of the vehicle
whereas the fixed costs are essentially determined by the vehicle retail
price. As a basis of calculation, a 10-year life of the car was chosen
corresponding to 100,000 miles of operation. By way of orientation, the
figures below give an approximate magnitude of these costs for a gasoline
powered 1973 automobile of 3500 Ib. curb weight retailing at $3400 (5-27).
$ (1973)
Operating Costs
Fuel 2,850
Oil, Maintenance, 2,750
Repairs, Tires
Fixed Costs 6,270
Total 11,870
As stated earlier, the motorist is very sensitive to increases
in fuel costs but such increases are diluted by other operating costs,
such that doubling the cost of the fuel increases the total operating
cost only by about 25%.*
The effect of car size, not considered here, is on both operating and
fixed costs. In fact, the most obvious way to minimize fuel costs is
to buy a small car.
- 163 -
-------
The details of the calculations are given in Appendix 10. Table
5-16 compares life-time vehicle operating costs for the various fuels and
engines. Relative rather than absolute costs are used in this comparison
to focus on the fuel. For convenience, the relative costs are referenced
to shale gasoline and distillate. It is not the intent of this analysis
to explore operating costs as a function of engine type, since the vehicle
and engine data, as explained in Appendix 10, are not of sufficient quality
for this purpose. This comparison confirms first of all that changes in
relative fuel cost are dampened by other non-fuel related costs, such that
the total vehicle operating cost is not affected very much. The weight and
cost changes occasioned by changes in fuel are quite small relative to base
case costs. In order for fuel changes to have a really significant effect
on total costs beyond one of direct fuel cost, the weight changes directly
attributable to the fuel would have to be quite large. This could be the
case for compressed or liquefied gases, such as ammonia, hydrogen, or
methane.
Table 5-17 shows the relative fuel cost per mile for the various
engines for 1982, 1990, and 2000. These relative costs are very close to
the relative ex tax pump costs from Section 5, since, in this analysis,
vehicle efficiency is determined by the efficiency of the engine, which is
assumed not to vary significantly with the fuel.
- 164 -
-------
Engine
TABLE 5-16
TOTAL COST OF OPERATING VEHICLE
AS A FUNCTION OF FUEL TYPE
Basis: 10-year, 100,000 mile life,
1982 projected fuel costs
Fuel
Relative Cost*
Fuel 0,M,
Otto Cycle
Diesel
Gas Turbine
Shale Gasoline 1.
Coal Gasoline 1.
Methanol 1.
Shale Distillate 1.
Coal Distillate 1.
Shale Distillate 1.
Coal Distillate 1.
Methanol 2.
0 1.
25 1.
52 1.
0 2.
31 2.
0 1.
32 1.
01 1.
* The reference point for each engine type is
R,T**
19
19
22
63
65
68
68
72
Fixed
2.85
2.93
2.85
6.47
6.65
4.07
4.17
4.22
indicated by 1.
Total
5.047
5.365
5.59
10.10
10.61
6.75
7.18
7.94
0 .
Comparison among different engine types is not valid since the
reference point for the various engines differs.
** Oil, maintenance, repairs, tires.
EPA-460/3-74-009
- 165 -
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Engine
Otto Cycle
TABLE 5-17
PROJECTIONS OF FUEL COST PER MILE
Basis: 10-year, 100,000 mile life
Fuel Relative Fuel Cost Per Mile*
1982
1990
2000
Shale Gasoline
Coal Gasoline
Methanol
0.95 0.78
1.24 1.16 0.99
1.51 1-37 1-17
Diesel
Gas Turbine
Shale Distillate
Coal Distillate
Shale Distillate
Coal Distillate
Methanol
i.o I
1.27
l.OJ
1.33
2.01
0.99
1.23
0.97
1.26
1.81
0.79
1.0
0.78
1.01
1.56
* The reference point for each engine type is indicated by 1.0
Comparison among different engine types is not valid since the
reference point for the various engines differs.
EPA-460/3-74-009
- 166 -
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6. PERFORMANCE OF FUELS BASED ON COAL AND SHALE
This section of the report discusses the performance of the
shale and coal-derived fuels analyzed in Section 5. The focus is on the
key properties and product quality considerations which affect vehicle
performance. There are almost no data on the use of these fuels in internal
combustion engines. As a result, it is necessary to infer performance
characteristics from limited data on physical and chemical properties.
This general approach was used in the preliminary analysis of the complete
list of fuels in Section 4. It is important to realize, however, that the
main value of such an approach is to identify areas where detailed, reli-
able information is needed.
6.1 Performance of Gasolines and
Distillates From Shale and Coal
There are very few data in the literature on the product quality
of shale and coal-derived fuels, based on the processes described in
Section 5. It must therefore be stressed at the outset that inferences
drawn from such limited information are tentative, subject to availability
of more data.
6.1.1 Coal and Shale Gasolines
• Octane Number
Available data indicate that high octane gasoline fractions
based on coal or shale syncrude will be quite aromatic. The information
is presented in Figure 6-1 based on the data of Tables 6-1 and 6-2. The
figure also shows a band, representing data for a petroleum naphtha
catalytically reformed to various severities.
The limited data indicate that, regardless of source, the
octane-aromatics curves tend to converge at octanes above 95. This simply
reflects the fact that aromatics are the only compounds which are capable
of achieving these (lead-free) octane levels under the processing condi-
tions employed.
The points for shale gasoline represent three catalytically
reformed hydrogenated naphthas. The data indicate a very steep octane
response as low octane paraffins are converted to high octane aromatics.
The data for coal are not easy to interpret because they repre-
sent a mixture of results obtained from pyrolysis as well as hydrogena-
tion processes. The former are highly aromatic due to the nature of the
process. Pyrolysis also produces olefins, but these have been selectively
hydrogenated as indicated by the data of Table 6-2. Gasolines made by
coal hydrogenation are of more interest since this is probably the pre-
ferred future route for motor fuels. These products are rich in naphthenes
(cycloparaffins) as well as aromatics. The naphthenes still have a
- 167 -
-------
FIGURE 6-i
AROMATICS-OCTANE RELATIONSHIP
FOR SHALE AND COAL GASOLINES
100
1 1
• COAL GASOLINES - SEE TABLE 6-2
• SHALE GASOLINES SEE TABLE 6-1
777777 AVERAGE OF DATA FOR PETROLEUM
REFORMATES FROM NAPHTHAS OF
"MEDIUM" AROMATICITY
90
o
x
u
Pi
-------
Research
Oc tane No.
Clear(a)
55.4
57.9
57.0
36.4
73.0
90.9
40
59
69
82
89
TABLE 6-1
ANTIKNOCK QUALITY OF SHALE GASOLINES
Vcl. %
Ar omatic
Hydro carbons
16.6
Processing
23. L
5.5
12.5
28.0
45.1
51.9
Hydrog. of 400°F. + oil from
in situ shale oil
240-408°F. naphtha from in situ
crude shale oil
203-400°F. naphtha from in situ
crude shale oil
HDN(b) naphtha 175-404°F.
oteformate of HDN; 140-385°F.
Cat. cracked 400°F.+;
hydrogenated
H;rdrogenated naphtha
Cat. Reformed Hydrog. Shale Oil
Cat. Reformed Hydrog. Shale Oil
Cat. Reformed Hydrog. Shale Oil
d t Reformed Hydrog. Shale Oil
Reference
(a) No antiknock agent has been sided.
(b) HDN = hydrodenitrogenated.
= npt reported.
(4-95)
V
(4-59)
EPA-460/3-74-009
- 169 -
-------
TABLE 6-2
COMPOSITION OF GASOLINES FROM COAL
Process
Boll. Range of Fract. *F,
Research O.N. clear
Motor O.N. clear
Hydrocarbon Comp. Vol. 7.
Saturates
Paraffins
oleflns
Naphlhcne.
Aroma tics
Total Cyclici
Atonic Comp., We. 7.
C
H
0
S
N
Reference
Hydro. COG
COED (a) SRCfb)
Cj-400 Cj-180
82.9
50
l.»
47
15.7 3
50
86.20
13.74
0 0.005
0.02 nil
0.02 0.01
(4-61) (6-2)
Scacoke
180-375 C5-420
20 18.6
65 70.0
15 U.4
80 81.4
86.4
13.4
0.02 0.14
0.001 0.007
0.02 0.009
(6-2) (6-3)
COED (a)
C.-435
0
18.1
64.6
17.3
81.9
86.7
13.1
0.06
0.01
(6-3)
Hydro. Hydro. Hydro. Hydro.
Hydro. Light Pyrolysls Ltght Light Hydro.
Coal Tar Tar Oil Oil Coal
Gasol. Gasol. Gasol. 90-357 90-362 (lasol .
93 95 98 83.7
76.2 76.5 77.3
30 26
17 41. 8
2 1.0 1.0 3.0 4.0 2.5
8 26.2
52 69 73 28.6 27.9 29.5
60 55.7
(6-4) (4-62) (4-62) (6-1) (6-6) (6-7)
Hydro.
Coal
Reformed
Gasol .
97.2
85.3
24.5
1.0
17.0
57.5
74.5
(6-7)
Hvdi P.
Coal
Reformed
Gasol.
81.5
75.3
3.4
28-29
(6-8)
(a) COED - utllltei pyrolyau of coal to give gas, oil and char >
(b) COG - "Coal, Otl, I'ai" concept V See Section 5.2 for process descriptions
SRC - Solvent Refined Coal process J
Blanks Indicate that data were not obtained
EPA-460/3-74-009
-------
fairly good octane number, certainly better than paraffins in shale naphtha,
which is reflected in the data in Figure 6-1.
The above discussion has been based on the Research octane number,
since it is the most familiar antiknock criterion. Further, in pre-1965
automobiles, it had a stronger influence on road antiknock performance
than Motor method octane number. However, in the past several years, the
character of the automobile has changed until now the Motor octane number
is more important in determining road antiknock performance (6-19, 6-20).
Since it is difficult to forecast how future automobiles will respond, it
is necessary to view both Research and Motor octane numbers as important
properties of future gasolines. Table 6-2 indicates a Motor octane rating
of about 6-12 units lower than the Research rating, based on three data
points for coal gasolines. A difference of 8-10 units between Research
and Motor octane numbers is typical for conventional gasolines. There are
no recent published data on the Motor octane of shale gasolines.
The ^discussion so far has dealt with components of a finished
gasoline, i.e., in the petroleum case, reformates are only one component
of a finished gasoline. Unleaded petroleum gasolines in the U.S. contain
about 207o aromatics at 90 RON and 40% at 95 RON. These aromaticities
compare with 50-60% for shale and coal fractions as well as for petroleum
reformates of the same octane range. In petroleum, highly aromatic
reformates are blended with other fractions rich in paraffins or olefins.
It is expected that petroleum fuels will be available throughout the rest
of this century. Consequently, coal gasolines could replace petroleum
reformates to make finished gasolines of equivalent octane number and
aromatics content. Alternatively, such finished gasolines could be pre-
pared by blending coal gasolines with paraffinic shale naphtha components.
However, the contract also requires consideration of a scenario
in which petroleum is postulated not to be available and fuels are pre-
pared from the alternative source. Under these conditions, it is necessary
to explore the ramifications of formulating coal gasolines with higher
aromatics concentrations than presently used.
• Exhaust Emissions
It is expected that highly aromatic gasolines will not have an
appreciable effect on exhaust emissions from automobiles equipped with
advanced emission control systems. This is indicated by data (6-9) from
an engine equipped with a catalytic exhaust treating system, which showed
very low sensitivity to changes in fuel aromaticity. Atmospheric
reactivity of the exhaust from such systems is very low due to the low
mass emission of hydrocarbons. The use of exhaust gas recycle in future
cars to control NOX emissions would also tend to compensate for any effect
of fuel composition on NOX formation.
In an uncontrolled vehicle the emissions of aromatic hydro-
carbons in the exhaust increased as the aromaticity of the fuel increased.
Total aldehyde emissions, however, decreased slightly (6-9).
- 171 -
-------
• Volatility
Since benzene (boiling point 176°F) is the lowest boiling
aromatic hydrocarbon, the portion of the gasoline boiling below 176°F
(i.e., the "front-end") probably decreases in concentration as the
aromaticity of the gasoline increases. This would tend to cause difficult
starting of carburetted engines at low temperatures. The simplest
solution to this potential problem is to add some low-boiling non-
aromatic fraction.
* Toxicity
The toxicity of highly aromatic coal gasolines is also of con-
siderable concern. An analysis (4-62) of an unleaded 98 Research octane
number coal gasoline produced by the hydrogenation of tar from the
pyrolysis of coal indicated about 70% aromatic hydrocarbons of which 1/3
(i.e., >20% on fuel) was benzene. There are no comparable data available
on coal gasolines made via hydrogenation.
At present, there are no Federal or State restrictions in the
U.S. on the amount of benzene in gasoline delivered to an automobile fuel
tank. However, there are labeling restrictions (6-14) on products con-
taining more than 5% benzene that may be carried home by a customer.
This presumably would cover gasoline delivered to a container provided by
a customer for use in an applicance such as a lawn mower.
It is possible that a limitation on benzene in gasoline may
be established in the future. The advent of fuels from coal and/or shale
may focus attention on this question. It is of interest to note that
Switzerland limits benzene in gasoline to a maximum of 57,. Sweden and
Germany also have proposed laws providing a limit of 57» or lower.
• Materials of Construction
The materials of construction of the automotive fuel system may
require some changes to handle properly fuels containing appreciably more
than 5070 aromatics. Such high concentrations of aromatics may cause
deterioration and swelling of current gaskets, fuel pump diaphragms, etc.
This, however, should not be a difficult problem to rectify by the use of
different materials.
• Nitrogen and Sulfur Content
Although raw shale oil is high in nitrogen, the upgraded syn-
crude, as described in Section 5.1, contains only 0.0357,, nitrogen. Data
on petroleum crudes (6-11) indicate a median nitrogen content of 0.0570,
with a maximum of ca. 0.67,. It is expected, therefore, that conventional
refining processes will produce gasolines and distillates with nitrogen
contents as low as that made from petroleum.
- 172 -
-------
It is more difficult to denitrogenate a given material than to
desulfurize it. As a result, the denitrogenation of shale oil invariably
gives extremely low sulfur levels, e.g., ca. 0.0057> sulfur corresponding
to 0.0357o nitrogen.
The same general picture also applies to coal. There are some
data in the literature (6-12) which indicate that the crude product from
coal hydrogenation (a 143/510°F fraction) contains 0.23% nitrogen and
0.107o sulfur. After catalytic hydrogenation, the total product contained
O.OG577o nitrogen and 0.0127o sulfur. These levels compare favorably with
analogous petroleum products.
6.1.2 Coal and Shale Distillates
The table below summarizes some properties of shale syncrude
fractions which are in the distillate boiling range. The information is
abstracted from Table 5-1.
Properties of Shale Syncrude Fractions
Boiling Range, °F 350/550 550/850
Gravity, "API 38.3 33.1
Sulfur, Wt.% 0.0008 <0.01
Nitrogen, Wt.% 0.0075 0.12
Aromatics, Vol.7» 34
Freezing Point, °F -35
Pour Point, °F -- +80
The data indicate that it should be possible to make a good
quality diesel fuel from shale syncrude. By interpolating the data on the
350-550°F and 550-850°F cuts it is estimated that the syncrude will yield
a diesel fuel (350-650°F) with an API gravity in the range of 30-35° and
a Cetane Index of about 40-45. While usable in current automotive diesel
engines, 40-45 C.I. is low. Hence, blending with petroleum-derived diesel
fuel could be advantageous if it is feasible logistically. The sulfur
and nitrogen levels are very satisfactory.
The high pour point (80°F) of the 550-850°F fraction suggests
that a normal diesel fuel (i.e., 350-600°F) produced from the shale syn-
crude shown may have a higher pour and cloud point than can be tolerated
in truck operation under low temperature conditions. A dewaxing operation
may be required, or alternatively, additive should be used, such as those
used to improve the low temperature flow properties of petroleum fuels.
Dewaxing would be expensive, and the response of shale distillates to low
temperature flow improving additives remains to be established.
The 3470 aromatic content of the 350-550°F fraction indicates
this fuel would not be of premium quality as a gas turbine fuel. Possible
problems arising from the high aromaticity includes smoke formation and
- 173 -
-------
high flame luminosity resulting in decreased gas turbine combustor life.
More extensive catalytic hydrogenation might correct this deficiency, but
at a cost, as mentioned below.
With regard to distillates from coal, there is no body of data
from which to infer reliable product quality information. There are
indications from a single literature source (6-12) that the H-coal hydrog-
enation process yields a distillate fraction (390/510°F) which is very
low in aromatics, i.e., most of the polynuclear aromatics have at least
been partially reduced to cycloparaffins. Such a fraction is expected to
have a cetane number of ca. 40. As pointed out in Section 5.2 and in
Appendix 9, the refining study of coal syncrude led to a distillate with
Cetane Index of 35-38. The indication therefore is that coal distillates
are unsatisfactory automotive diesel fuels, which require ca. 40-45 cetane
number.
First of all, however, it is necessary to confirm this implica-
tion by direct measurement on coal distillates. It is conceivable that
the Cetane Index correlation, derived from data on petroleum fractions,
should be corrected for coal distillates. If the low cetane number is
confirmed, a number of options exist for dealing with the situation:
1. The simplest alternative is to divert the distillate into
uses other than diesel fuel--e.g., heating oil, low sulfur fuel oil, etc.
2. As pointed out earlier in this section, it is simple to blend
the coal distillate with either shale or petroleum fractions of higher
cetane number.
3. Cetane improvers, such as amyl nitrate, can be added to the
coal distillate. These, however, increase the cost of £he finished fuel
and, moreover, would contribute to NOX in the exhaust emissions.
4. Another alternative is to increase the cetane number by
processing, such as severe hydrogenation or hydrocracking. It is not
clear how much improvement can be achieved in this fashion, although the
cost will certainly be high--on the order of $3/bbl. or $0.50/MMBTU.
Moreover, such processing would crack some of the distillate into the
naphtha boiling range.
The same literature source cited above (6-12) indicates a smoke
point for the 390/510°F fraction which is outside the ASTM specification
for Jet A fuel. This is surprising in view of the low aromaticity of this
fraction. The jet fuel properties are indicative of fuel performance in
automotive gas turbines.
Finally, it appears that both the sulfur and nitrogen levels
will be satisfactory, if the distillate is processed according to the
refining scheme discussed in Section 5.2.
Overall, it must be stressed that available data on coal and
shale distillate are very limited. Much more data are needed.
-------
6.2 Performance of Methanol and Methanol/Gasoline Blends
Methanol can be used as an alternative fuel either unblended
("neat") or as a blend with gasoline hydrocarbons. These two approaches
will be discussed separately.
6.2.1 Methanol
In order to use neat methanol in a spark-ignition engine, a
number of factors would have to be considered (as mentioned in Section 4.4):
1. The relatively low volatility of the methanol (149°F boiling
point) requires special means for starting carburetted engines at low
temperatures.
2. The high heat of vaporization requires special heated mani-
folds for providing suitable air-fuel mixtures for ignition.
3. The low heat of combustion requires a large fuel system
(tank, pump, lines, filters) to give satisfactory range and performance.
4. The high octane number of methanol (106 Research and 92 Motor
Octane unleaded) should permit operation at increased compression ratio,
leading to improvements in thermal efficiency.*
5. The effect of methanol on materials of construction for the
fuel system must be considered.
With the modifications needed to take account of the above
factors, the vehicle would be essentially inoperable on conventional
gasoline. Consequently, a separate fuel distribution network has to be
provided in order for such modified vehicles freely to be used. It would
be possible, of course, as mentioned in Section 7, to limit methanol for
use in vehicle fleets operating within cruising range of specific refuel-
ing points, such as current LPG vehicles.
Some of the modifications mentioned above, e.g., involving
octane number, cold starting, and manifold heating, apply only to an Otto
cycle engine. They are not applicable to a continuous combustion device,
such as a gas turbine. In such an engine, the low luminosity of the
methanol flame and the low NOX emissions would be significant advantages.
As mentioned below, water sensitivity is a serious problem with
methanol/gasoline blends. This is a much less serious concern with pure
methanol. However, water still could cause problems due to:
* This point is not firmly established, because the road anti-
knock properties of methanol have not yet been fully defined,
- 175 -
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1. Possible corrosion in the fuel system, particularly if the
water contains an appreciable concentration of minerals.
2. Batch-to-batch variability in water content could affect
performance.
3. Potential for intentional adulteration with water, which
would penalize the consumer financially.
6.2.2 Methanol/Gasoline Blends
The concept of using a methanol/gasoline blend as a fuel is not
new. There are a number of important potential problems with such a
system that must be recognized and evaluated:
1. Partial Miscibility and Water Sensitivity
Methanol is completely miscible with some gasoline components but
only partially miscible with others. As would be expected, mutual solu-
bility decreases as the temperature is lowered. Methanol and benzene are
miscible in all proportions down to 3°C. However, as shown in Figure 6-2
(6-17), only 5 vol.7, of methanol can be dissolved in n-hexane at 0°C.
Benzene and n-hexane, representing aromatic and paraffin hydrocarbons,
respectively, bracket the solvency of commercial gasolines for methanol.
As was pointed out in Section 6.1, aromaticity increases with
octane number in lead-free automotive gasolines. Thus, methanol is
likely to be more miscible with premium grade than with regular grade
gasolines. For example, it has been reported (4-44) that dry methanol was
miscible in all proportions with a dry aromatic gasoline at 15.5°C. At
the same temperature, only 13% of methanol dissolved in a regular grade
fuel while, at -18°C, only 4% of methanol was dissolved.
Solubility may be improved by the use of a mutual solvent, but
the available data are not particularly encouraging. For example, the
addition of 2.4 vol.7» of isobutanol to the blend can increase methanol
solubility from 3 vol.7, to 10 vol.7, in regular grade gasoline at 0°C.
Approximately 4 vol.7, of isopropanol would accomplish the same improvement,
whereas high molecular weight alcohols would be somewhat more effective.
The problem of phase separation is greatly intensified if water
is present. As indicated in Figure 6-3 (4-44) the presence of less than
0.57, water causes almost complete phase separation at 76°F. At lower
temperatures, the problem is even more severe. There are indications that
the presence of mutual solvents, such as higher molecular weight alcohols,
increases water tolerance but not enough to avoid phase separation. Con-
ceivably, an emulsifier might also be developed which would stabilize the
separated phases, but the cost of this approach would certainly be a problem.
If a methanol/gasoline blend were to be marketed, it would have
to be blended at the pump. It simply is not practical to consider a
totally dry distribution system from the refinery to the customer's tank.
- 176 -
-------
FIGURE 6-2
BINARY PHASE DIAGRAM FOR HEXANE/METHANOL
AND BENZENE/METHANOL
(Ref. 6-17)
40
30
u
o
W
H
20
10
0
METHANOL
20
BENZENE/METHANOL
40
60
80
VOL.7o
100
HEXANE
(BENZENE)
EPA-460/3-74-009
- 177 -
-------
FIGURE 6-3
EQUILIBRIUM PHASE DIAGRAM FOR THE SYSTEM METHANOL,
WATER, AND GASOLINE (PREMIUM)
(Ref. 4-44)
METHANOL
100 VOL.7,
GASOLINE
100 VOL.7,
WATER
100 VOL.7,
EPA-460/3-74-009
- 178 -
-------
Even if the methanoI/gasoline blend cpuld be supplied dry to the customer's
tank, the possibility remains of separation in the tank due to "breathing".
This might require the use of adsorbent traps on the gas tank.
2. Volatility and Vapor Lock*
Methanol and hydrocarbons form very nonideal solutions, as shown
in the vapor pressure composition diagram in Figure 6-4. In dilute hydro-
carbon solution, methanol cannot hydrogen-bond to itself, and therefore
becomes much more volatile. Translating this effect to a methanol/gasoline
mixture, Figure 6-5, data obtained at Exxon Research and Engineering Co.**
on the substantial increase in vapor pressure of a gasoline due to the
addition of relatively small amounts of methanol. It is predicted that
an increase in Reid vapor pressure (RVP) 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 2% methanol, would cause significant vapor lock problems in
current automobiles.
Presumably the problem could be corrected by backing out volatile
hydrocarbons, such as butane and pentanes, from the gasoline. This is
illustrated in Table 6-3. It illustrates the adjustments that must be
made in a gasoline to avoid undesirably high RVP when 10% methanol is added
to a gasoline which has been blended to 10 psi RVP with 6.7 vol.7» n-butane.
If the methanol is added directly to the 10 psi base fuel, a blend having
an RVP of 13 psi would be obtained. This is too high. In order to pro-
duce a methanol blend of 10 psi the base gasoline must be debutanized.
The net result is that although the 10 psi methanol blend constitutes a
570 larger volume than the n-C4 blend, there is essentially no change in
the BTU's available as automotive fuel (119,890 vs. 119,930). However,
the methanol blend will be higher in octane quality than the all-
hydrocarbon gasoline. The calculated octane numbers are shown to indicate
the trend only. The absolute level is open to question because the octane
blending value of methanol is quite variable with concentration and base
gasoline type.
* Vapor lock is the malfunctioning of a gasoline powered vehicle caused
by pockets of fuel vapor formed at critical points in the fuel system.
It arises when the vapor pressure of the gasoline is too high for the
ambient temperature under which the vehicle is operating. The symptoms
are hard starting, poor acceleration, and stalling. They usually
develop after operating under conditions causing high under-hood
temperatures, e.g., on a hot day in stop-and-go traffic, after sus-
tained high-speed operation, etc.
** These data were obtained totally at the contractor's own expense in a
program independent of the work performed under this Government
contract.
- 179 -
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FIGURE 6-4
VOLATILITY OF METHANOL/BENZENE MIXTURES
400
300 —
LO
C/D
s
O
P-l
200
0
BENZENE
20
40
60
VOL .7.
DATA FROM (6-17)
80
100
METHANOL
EPA-460/3-74-009
- 180 -
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FIGURE: 6-5
EFFECT OF METHANOL ON
GASOLINE VAPOR PRESSURE
o
fXl M
w O
<; M
OW
td
C/l
3 -
35% AROMATICS A
10% AROMATICS •
I
2468
VOL. % METHANOL IN GASOLINE
*REID VAPOR PRESSURE (PSIG)
10
EPA-460/3-74-009
- 181 -
-------
oo
NJ
TABLE 6-3
COMPARISON OF METHYL ALCOHOL
AND n-BUTANE AS GASOLINE BLENDING AGENTS
Property
Reid Vapor Press. (Blend Value) psi @ 100°F
Research O.N. (clear)
Motor O.N. (clear)
Heating Value (Net) BTU/gal.
n-C4
59
-------
This simple analysis shows that the addition of methanol to
gasoline would not result in any significant increase in the automotive
fuel supply. It is most likely that the displaced butane would be used as
an industrial fuel, which begs the obvious question: Why not use methanol
as an industrial fuel and avoid all of the complications associated with a
gasoline/methanol blend?
On the positive side, methanol seems to have very good octane
blending characteristics. However, in the example just described, a
debit must be included due to the octane number of the displaced butane.
Furthermore, the road performance of late model vehicles correlates best
with Motor octane number. A good Research octane blending value is of
little value in such cases.
Admittedly, it should be possible to modify the automotive fuel
system to handle a more volatile blend, completely avoiding the problem of
butane displacement. Such a modification would add complexity and cost
which must be justified in terms of performance.
3. Driveability
It is very important to determine the performance of vehicles
fueled with methanol/gasoline blends—e.g., with regard to acceleration
and stalling. Should such problems arise, the cause must be defined.
Poor driveability could result from debutanization of the gasoline to
avoid excessive vapor pressure due to methanol. One of the functions of
butanes (and pentanes) is to maximize fuel evaporation in the intake
manifold. The high boiling point and heat of vaporization of methanol
could lead to fuel maldistribution.
Performance problems could also result from the fact that
methanol/gasoline blends operate leaner than gasoline alone for a given
air/fuel ratio. An engine with a carburetor set to deliver 15/1 A/F will
operate at 17o excess air* with gasoline and 1270 excess air with a 1570
methanol-gasoline blend. With cars adjusted to borderline performance
on gasoline (for exhaust emission control purposes) the additional leaning-
out with the alcohol blend could be enough to cause misfiring and
stalling (see Figure 6-7).
4. Exhaust Emissions and Fuel Economy
The discussion of exhaust emissions data in Section 4.5.3
mentioned a few references in which an attempt was made to analyze the
performance of vehicles and engines fueled by methanol or methanol/
gasoline blends. A more recent study involved a few vehicles, chosen at
* Over the stoichiometric required amount for complete
combustion to carbon dioxide and water.
- 183 -
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random from a group of private individuals, which were operated on
methanol/gasoline blends (6-18). Nevertheless, there has not been a care-
fully controlled, side-by-side comparison of the exhaust emissions and
fuel economy of vehicles fueled with gasoline vs. gasoline/methanol blends,
Recent data by Exxon Research and Engineering Company* shed some
light on this subject. The table below summarizes exhaust emission data
on three vehicles:
Exhaust Emissions with Methanol/Gasoline Blends
Emissions, g/mi,
1967 Model
Equivalence Ratio Hydrocarbons CO NQx Aldehydes**
W/0 Methanol
+15% Methanol
1973 Model
W/0 Methanol
+15% Methanol
Advanced Model
W/0 Methanol
+15% Methanol
0.9
1.05
ca.
5.2
3.8
1.1
1.1
0.1
0.1
83
41
21
8
6.4
8.1
2.6
1.7
0.3 2.6
0.4 2.3
0.13
0.20
0.075
0.10
0.002
0.004
* Federal Test Procedure.
** Calculated as Formaldehyde.
In this work a 15% methanol blend was compared with a typical
gasoline in three vehicles: a 1967, a 1973, and an "advanced model".
The 1967 model was a 289 cu. in. V-8, and the 1973 and advanced models were
351 cu. in. V-8. All cars had automatic transmission. These models
represent a wide range in carburetion, i.e., (1) the 1967 car is set rich,
(2) the 1973 car is lean, and (3) the advanced model operates at about
the stoichiometric A/F ratio, and is equipped with a catalyst for control
of exhaust emissions. The two test fuels were matched in Reid vapor
pressure which meant backing out all the butane and about half the pentane
to make the methanol blend. There were no carburetion changes made when
methanol was added.
These data were obtained totally at the contractor's own expense in a
program independent of the work performed under this Government
contract. They will be presented as part of a paper on "Methanol as a
Gasoline Extender: Fuel Economy, Emissions, and High Temperature
Driveability" by E. E. Wigg and R. S. Lunt at the meeting of the
Soc. of Automotive Engineers, Toronto, Oct. 21-26, 1974.
- 184 -
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The addition of methanol resulted in lower CO and HC and higher
NOx in the 1967 model. In the case of the 1973 model, there was a decrease
in CO, no change in HC, and a decrease in NOx. The CO and HC emissions
with the "advanced" model were too low to establish any effect due to
fuel. The NOx emissions showed a slight decrease.
These trends are quite consistent with the basic relationships
between exhaust emissions and A/F ratio, as shown on Figure 6-6. The
1967 model operated at A/F less than stoichiometric, and the 1973 model
operated on the lean side of the stoichiometric point.
It is not surprising to observe that the aldehyde emissions
(mainly formaldehyde) are 30-50% greater for the methanol/gasoline blends.
The table below summarizes fuel economy data for the same test:
Fuel Economy Data Using Methanol/Gasoline Blends
Fuel Economy*
v, j i Miles/Gallon Relative mi./BTU, %
Model - -
W/0 Methanol 14.3
+15% Methanol 14.4 +8
1973 Model
W/0 Methanol 11.2
+15% Methanol 10.5 +1
"Advanced" Model
W/0 Methanol 11.5
+15% Methanol 10.9 +3
* By fuel weight measurement in Federal Test
Procedure; 4000 Ib. inertial weight setting
on dynamometer.
The fuel economy for the methanol/gasoline blend, on a miles
per gallon bas'is, was about the same as gasoline for the 1967 vehicle,
but was somewhat poorer for the 1973 and the "advanced" model. These
results can most easily be explained by the curves on Figure 6-7. The
1967 car, operating rich, showed essentially no change in miles per
gallon fuel economy with the methanol blend because of two compensating
effects: the improvement in relative fuel economy due to leaner opera-
tion with methanol was nullified by the lower BTU/gal. of the methanol
blend. The decrease in fuel economy for the lean 1973 and "advanced"
model is due to the lower heat content of the methanol blend and the fact
that they are operating on the descending portion of the fuel economy-
A/F curve.
The fact that a small increase in miles/BTU is obtained in
every case with the methanol blend indicates that the presence of methanol
- 185 -
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FIGURE 6-6
EFFECTS OF AIR/FUEL RATIO
ON EXHAUST COMPOSITION
(Ref. 6-16)
20
22
AIR-FUEL RATIO
EPA-460/3-74-009
- 186 -
-------
FIGURE 6-7
FUEL ECONOMY AS A FUNCTION OF
AIR-FUEL RATIO
OTTO CYCLE ENGINE, CONSTANT SPEED
(Ref. 4-117)
STOICHIOMETRIC
100 -,
o
§
o
w
90-
70-
60-
50-
40
12
0,82
I
13
0.88
r
14
i
16
15
A/F RATIO
0.95 1.01 1.09
% STOICHIOMETRIC AIR
- 187 -
POOR
I—* DRIVEABILITY
17
1.17
18
1.22
EPA-460/3-74-009
-------
may help the efficiency of combustion in the engine, e.g., because of its
wide flamraability limits. Furthermore, there is the possibility that
optimizing the engine (with regard to spark advance, carburetor adjustment,
etc.) for operation on the methanol blend may permit improvements in per-
formance and/or economy and still meet exhaust emission requirements.
Obviously, much more data are needed to clarify the picture.
- 188 -
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7. EVOLUTIONARY CONSIDERATIONS
If it is postulated that the system of automotive fuel use will
be different in the future than it is today, then it is also necessary to
conceptualize how the changes can come about., Not only is it necessary to
see a possible approach path from the present to a new condition in the
future but it is also necessary to:
(a) look at the entire path to see what roadblocks may
be along the way.
(b) consider whether other easier or better paths may
be available such that the "possible" path is not
likely to be followed.
Various types of transition are involved in this study of al-
ternative fuels, and each will be discussed separately. The first example
is an extreme case and one of maximum difficulty. The purpose of this ex-
ample is categorize the various difficulties as a prelude to discussing
ways in which some or all of the problems may be overcome.
American industry is adept in the introduction of new products.
Resourcefulness and sophistication in this respect may be taken for granted.
However, the alternative fuels problem has features that distinguish it from
most other types of new product development and introduction. The single
most important feature is that highway vehicles, of their very essence, are
mobile. This means that they must be able to obtain suitable fuel wherever
they are driven. In turn, this poses a special problem in the hypothetical
case in which the introduction of a new engine would require the concurrent
introduction of a new fuel, i.e., neither the new engine nor the new fuel
could be used except with each other. This problem is referred to as the
"New Engine/New Fuel Dilemma" in the following section.
7.1 The New Engine/New Fuel Dilemma
This particular version of the old "chicken-or-the-egg" problem
has several unique characteristics. Here, it is not a matter of which
comes first but rather that a number of conditions must be satisfied
simultaneously:
(a) the automotive industry must decide to introduce a
new engine.
(b) independently of (a), the fuels industry must decide
to introduce a new fuel.
(c) preferably, for competitive reasons, several companies
in both industries should independently decide to
introduce the respective new products.
- 189 -
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(d) the general public must be willing to purchase the
new products (otherwise commercial introduction
will be a failure) .'
(e) the new fuel must be widely available (because the
general public will not purchase equipment for which
fuel is not readily available).
(f) the new system should offer cost or performance
advantages over conventional or other alternatives,
and should not present any radical disadvantage.
By way of example, the simultaneous introduction of automotive
hydrogen and vehicles equipped with engines modified to use hydrogen would
seem to require solution of the complex problem created by the above condi-
tions. Steps towards a solution will be discussed later; the immediate
purpose is merely to illustrate that the dilemma discussed above is per-
tinent to the alternative fuels study.
Reference may also be made to electric vehicles, e.g., advanced
battery-powered automobiles. The introduction of such vehicles is recog-
nized as being a significant marketing problem, and the matter is already
being studied under EPA sponsorship. However, there is one important
difference: namely, that battery-powered vehicles do not require a new
fuel (since electricity is very widely available). The point here is that
the introduction of a new engine (or vehicle) will be much easier if it
can use fuels or energy sources that are already available. Similarly,
the introduction of new fuels will be much easier if they can be used by
existing vehicles. Extension of these concepts leads to the "compatibility
scenario" discussed below.
7.2 The Compatibility Scenario
Highway vehicles have an average useful life of about ten years.
At the time of introduction of a new power plant, the existing vehicle
population, or part of it, will require the continued supply of what are
then "conventional fuels" for at least another ten years.
No evolutionary problem on the fuel side will occur if the new
prime mover can use conventional fuels. Similarly, no evolutionary problem
will be associated with the introduction of a new fuel if it can be used by
a large segment of the then existing vehicle population. Moreover, new
engines and new fuels may be introduced at the same time if both are com-
patible with existing vehicles and fuels.
Compatibility is taken a step further if new fuels are new only
in the sense of being derived from a non-petroleum source but, in other
respects, are equivalent to petroleum fuels. In this case, it will not
matter if the new fuels are blended with petroleum fuels before, or after,
reaching the tank of the customer's vehicle. Such blending may not be
necessary, but it will not be a restriction. For example, one type of
- 190 -
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blending would occur if the customer were to purchase conventional fuel at
another service station. Thus, full compatibility has numerous advantages
s uch as :
(a) an individual vehicle operator can purchase fuel any-
where in the U.S. without having to concern himself
about whether the fuel is "new" or conventional.
(b) natiDnwide distribution of new fuels can evolve as
availability increases.
(c) new fuels will fit into the existing distribution
system (thereby avoiding the additional cost that
would be associated with a new, separate system).
(d) potential problems with different costs and prices
for new and conventional fuels can be avoided if the
new fuels are "rolled into" the existing system (via
blending with conventional fuels).
(e) the transition from 100% petroleum to 100% alternative
fuels can be accomplished without any discontinuity.
The rate at which this transition occurs can then de-
pend on normal market factors such as cost and avail-
ability .
(f) competition among suppliers of new, conventional, or
blended fuels will be maximized and will ensure that
the public will have access to automotive fuels at
the lowest commercial cost.
7.3 Automotive Fuel Blends
Conventional automotive fuels are blends. For example, motor
gasoline may be a blend of butane, natural gasoline, alkylate, cataly-
tically cracked naphtha, and catalytic reformate. Every petroleum re-
finery will blend regular (and premium grade) gasoline in a slightly
different way. Moreover, the proportions of the different components
in the blend will be varied throughout the year to adjust volatility to
meet changes in ambient temperatures. The individual purchaser of motor
gasoline need not concern himself with these matters and may be quite
unaware of them. It is the responsibility of petroleum suppliers to
deliver fuels of appropriate quality to service stations.
In the full compatibility scenario discussed in the previous
section, the responsibility for blending would be with the fuel supplier.
He might blend gasoline components derived from shale oil or coal syn-
crude with other components derived from petroleum.
- 191 -
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The individual driver who feels that the quality of the fuel he
has purchased is unsatisfactory is likely to switch to another brand. If
the deficiency is real and detectable by the user, other users of the same
fuel will do the same. Then the fuel supplier, conscious of a loss of
sales, will diagnose and correct the problem.
In practice, it would be extremely difficult for a fuel supplier
to market a fuel that is incompatible with other fuels on the market. This
is because the supplier cannot be sure that the customer will always buy
the same product. Compatibility in this context means that sequential pur-
chases of different fuels should not lead to any serious problems. The
only major exception involves the difference in octane number between reg-
ular and premium grade gasolines. If a car knocks on regular grade, the
remedy is both obvious and available.
Several petroleum companies use blending pumps to provide a range
of anti-knock quality between regular (or sub-regular O.N.) and premium (or
super-premium O.N.). The same approach could be used for blending methanol
with gasoline at the service station pump. However, the volume of methanol
in the blend would probably be fixed, e.g., at less than 15%. The reasons
for using a fixed blend were discussed in Section 6.2. In principle, the
blending pump approach would offer the alternatives of:
100% gasoline
a fixed blend, say 10% methanol/90% gasoline
- 100% methanol
However, three potential problems with this approach are apparent.
First, to be sold separately, the "100% gasoline" would have to
be satisfactory in both octane number and volatility. The blend with
methanol would also have to be satisfactory in these respects. However,
blending of methanol with gasoline would produce changes in both octane
number and volatility as discussed previously. Hence, it would not be
possible for both the "100% gasoline" and the blend with methanol to be
optimized for octane number and volatility. A reasonable compromise may
be possible, but this will require verification by experimental data.
The second potential problem is that the purchaser of a methanol/
gasoline blend might make his next fuel purchase at a different service
station where only "100% gasoline" was available. A low level of water in
this gasoline might then cause the fuel mixture in the car's tank to sep-
arate into two phases. With adequate anticipation this problem, too, may
be avoidable. One approach would be to sell the methanol/gasoline blend
for a slightly lower price than "100% gasoline". This would tend to dis-
courage customers from refuelling with "100% gasoline" after once using
the methanol/gasoline blend. The practicality of this approach is question-
able economically.
- 192 -
-------
The third potential problem relates to "100% methanol". The
feasibility of using this fuel depends on changes to the induction system
and engine beyond a simple adjustment that could be made at a service
station. Certainly, such changes would be required in order to take max-
imum advantage of methanol as an automotive fuel. Therefore, this third
potential problem is a special case of the "New Car/New Fuel Dilemma".
This is because the purchaser of a car with an engine designed specific-
ally to run on methanol (and which would not operate properly on gasoline)
would expect methanol to be available throughout the U.S. A conceptual
way around this difficulty is to assume that there would be a period of
years during which methanol blends, but not 100% methanol, would be intro-
duced gradually throughout the U.S. Then, once nationwide coverage was
achieved, it would be possible for engines designed specifically for 100%
methanol to be sold to the general public.
7.4 AutomotivevDistillate Fuels
Currently, there is only one type of commercial automotive
distillate fuel, namely automotive diesel fuel. However, other types of
distillate fuel are used by aircraft powered by gas turbines. This engine
type is one of the prime movers under development for highway use. Other
engines under development could, or would, also use distillate fuel but
not necessarily diesel fuel. Hence, the discussion that follows will deal
first with automotive diesel fuel and then with automotive distillate fuels
in general.
7.4.1 Automotive Diesel Fuel
In the full compatibility scenario, there would not appear to be
major problems with product quality. However, there could be two different
problems with fuel availability.
Automotive diesel fuel is widely available throughout the U.S.,
but at a far smaller number of outlets than is the case with gasoline. For
obvious reasons, diesel fuel is available along truck routes but not in
residential areas. Given both time and the incentive provided by customer
demand, it may be assumed that many service stations would be willing to
sell diesel fuel (or an equivalent distillate fuel). Some smaller service
stations may not have the physical room to be able to sell an additional
fuel but, overall, this would not seem to be a serious limitation. Stated
another way, an evolutionary solution appears feasible.
A quite different problem of availability will be examined in an
amendment of (i.e., addition to) the scope of work. Here, it will merely
be stated that there may be both physical limitations and economic penal-
ties associated with increasing the ratio of distillate-type to gasoline-
type automotive fuels beyond a certain point.
- 193 -
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7.4.2 Other Automotive Distillate Fuels
The first evolutionary factor to be considered is that a given
engine may, in principle, be able to burn a wide range of fuels but, as
marketed, the engine may require a certain type of fuel in order to give
optimum performance in automotive use.* In practice, the matching of an
engine to a particular type of fuel occurs while the (new) engine is being
developed. For obvious reasons, the design and optimization of the engine
will take account of what fuel is expected to be available when the engine
is marketed. Historically, this has meant that new engines have been de-
signed to use widely available conventional fuels. For example, automotive
gas turbines have been designed to use automotive diesel fuel even though
the engines are capable of operation on other fuels (e.g., naphtha, wide-
cut, kerosene, etc.). Furthermore, the optimization will include not only
the matching of engine and fuel but also the matching of engine and vehicle.
The latter consideration is important to commercial vehicles in terms of
fuel cost, specific fuel consumption, size of fuel tank, operating range,
power output, and the pay-load that can be carried in view of the other
factors.
The next evolutionary factor may be considered in the form of a
question: despite technically feasible alternatives, what incentives are
there for an automotive distillate fuel that is significantly different
from automotive diesel fuel? A possible, but hypothetical, answer is that
insufficient automotive diesel fuel will be available in the future but
that another type of distillate fuel will be available. A supply/demand
forecast of great complexity would be needed to resolve the issue.**
Another approach is to argue the following:
(a) potential evolutionary problems are avoided by the
full compatibility scenario.
(b) there is great flexibility for matching fuels and
energy (in the forms in which they can be made avail-
able most economically) to end-uses without the need
to force-fit any particular fuel into a use for which
it is less suited than another fuel.
(c) automotive distillate fuels other than automotive
diesel fuel face some problems of introduction.
These problems can probably be overcome by the
approach discussed in Section 7.5. However, the
* In general, stationary applications enjoy a greater flexibility of
fuel use because of (a) a narrower range of operating conditions,
and (b) less need to be concerned with seasonal variations that im-
pose fuel quality requirements on automotive fuels, e.g., satisfac-
tory flow properties at low ambient temperatures.
** Since it would involve forecasting all forms of energy supply and
demand.
- 194 -
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incentive for vising this approach depends on the
capacity of the new fuels to better the cost and
performance of diesel fuel. This incentive re-
mains to be established..*
7.5 The Fleet Account Stratagem
To the fuel supplier, a fleet account is the operator of a num-
ber of vehicles who purchases fuel in bulk. The vehicles may be buses,
trucks, taxi cabs, police cars, etc. The operator may purchase fuel from
more than one supplier, and may require the fuel to meet his own specifi-
cations. Purchases are often made by annual contracts signed after com-
petitive bidding.
Fleet accounts are often used for test purposes by the developers
of improved fuels and lubricants. An important characteristic of the fleet
account is that the type of fuel (or lubricants) used may be controlled
because it may be dispensed only from the operator's fuel storage. This
type of fleet will not re-fuel elsewhere. All maintenance will be per-
formed at the operator's garage, and proper records of fuel consumption,
etc., will be kept. Also, the fuel supplier may send his own trained
personnel to inspect the vehicles under test and to make appropriate
measurements Clearly, a fleet account provides the opportunity for test-
ing under controlled conditions with statistical replication, etc. Thus,
the fleet account offers one means by which a new fuel may be introduced
while side-stepping most of the difficulties discussed in Section 7.1.
Theoretically, 100% methanol fuel or a methanol/gasoline blend could be
marketed first to a growing number of fleet accounts before being offered
to the general public.
Some limitations must also be considered. As a first approxima-
tion, about 10% of all highway fuel may be sold to fleet accounts. However,
some of these accounts are too small to be considered as potential customers
for new fuels at least in the early stages of introduction. Other accounts
will be poorly located with respect to the delivery of a new fuel. Still
others will operate vehicles with engines (e.g., diesel) for which the new
fuel is unsuited. In total, it is guesstimated that a maximum of about 5%
of total automotive fuel demand might be satisfied with a new fuel supplied
to fleet accounts. Hence, this introductory strategy:
(a) offers a way of accomplishing initial commercial
introduction of a new fuel, and
(b) defers the problem of how to introduce a new fuel
to the general public
The matter cannot be decided without detailed consideration of the
prime-movers that would use the new fuels. Such consideration is
outside the scope of this contract.
- 195 -
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Clearly, the approach also offers a way of introducing new prime
movers under controlled conditions. A great advantage is that any operat-
ing problems could be detected and corrected professionally, thereby avoid-
ing the backlash that might be expected from the general public if exposed
to malfunctioning vehicles or fuels. Thus, experience gained from fleet
operations is a way of de-bugging automotive equipment and fuels prior to
full-scale commercial promotion.
7.6 Automotive Hydrogen
In a paper (7-1) presented at a conference on "The Hydrogen
Economy", the conclusion was:
"it is our present conclusion that it is very unlikely
that the transportation system will evolve of its own
accord in the direction of using hydrogen as a fuel for
private vehicles; moreover, government intervention to
alter this state of affairs in favor of the hydrogen
system is unlikely to be warranted".
Exactly so. But how could automotive hydrogen be introduced if it were
desirable to do so at some future date? The answer to this hypothetical
question is predicated by several assumptions. It is taken for granted
that vehicles can be powered with hydrogen. It assumes that automotive
peiformance and safety will be satisfactory. It also assumes that the
economy will be able to produce hydrogen in the huge quantity needed to
satisfy the implied automotive demand.
Automotive hydrogen involves the new engine/new fuel dilemma
discussed in Section 7.1. There appear to be at least two ways around
the fundamental problem of not being able to sell a new engine to the
public unless suitable fuel is widely available. The first way is to use
the fleet account stratagem discussed in Section 7.5. The second way in-
volves a scenario whereby hydrogen would be distributed by pipeline
throughout the U.S. in place of natural gas. Leaving aside the credibil-
ity of this scenario, it is then possible to argue that gaseous hydrogen
would be widely available. For hydrogen to be delivered to vehicles as
a liquid, it would be necessary for fuel supply points to have storage
for cryogenic hydrogen or, perhaps, to be able to liquefy it directly
from a gas pipeline. While technically feasible, it would seem that a
new fuel distribution system would be needed and that this would add a
significant cost relative to automotive fuels that are compatible with
the existing distribution system. These costs were discussed in Section
4.3.
In summary, the introduction of automotive hydrogen appears ex-
tremely difficult. While evolutionary paths can be hypothesized, commer-
cial incentives are missing at this time.
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7.7 Labor Force Requirements and Implications
The mining operations of the domestic synfuel industries are
likely to be concentrated in the Mountain states. This is certain for oil
shale and highly probable for (Western) coal. Current levels of mining
activity in the Mountain states are far below what will be required to
support a synthetic fuels industry- Moreover, the prospective mining
sites in the West are distant from population centers. Hence, considera-
tion should be given to the size of the mining labor force that may be
needed in the future and to any implications that may be drawn.
Some recent statistics for the U.S. coal industry are reported
in Table 7-1. Last year, the average productivity of strip mining was
35 ST/man/day and the average number of days worked was 227. Hence, the
average strip miner produced about 8000 tons of coal. It is anticipated
that large strip mines in the West will enjoy a higher productivity. On
the other hand, the rank of coal mined will be lower than the current
U.S. average. Thus, future productivity may stay close to 8000 T/man/yr.
when corrected to the heat content oi bituminous coal. This was the basis
used in Section 3.3 for estimating the raw coal requirements of the coal-
based segments of the future synfuel industries. These figures may be
converted to a very approximate future requirement for coal miners in the
Western states :
Raw Coal Need For Surface Miners
Year Synfuels, MM ST* Required (1000)
1985 163 21
1990 343 43
1995 692 87
2000 1024 129
* In terms of 11,500 BTU/lb. bituminous coal.
The above figures do not take account of the labor force re-
quired to mine coal for other purposes than synthetic fuels. Nor do they
consider the requirements of the future oil shale industry. Finally, and
perhaps most important, an increase in mining may be expected to have a
multiplier effect on jobs and population growth in the Mountain states.
Some evidence on this point comes from an article in the 1973 Annual Report
of the Wyoming Bancorporation*:
"Wyoming non-farm wage and salary employment increased
from 118,900 in December 1972 to 127,000 in December
1973, up 7.4% Numerically, Wyoming's major employ-
ment gains were registered in contract construction (up
3,200 workers); services (up 1,800); trade (up 1,700);
mining (up 900) ; government (up 800) ; and transportation
and public utilities (up 600) "
* "The Wyoming Economy", Dr. Dwight M. Blood, University of Wyoming.
- 197 -
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TABLE 7-1
RECENT PRODUCTION AND LABOR STATISTICS FOR U.S. COAL INDUSTRY
1969
1970
1971
1972
1973
oo
I
Production (million short tons)
Strip
Auger
Underground
Total
"/„ of Production
Strip
Auger
Underground
Average Production, ST/Man/Day
Strip
Auger
Underground
Total
Ratio, Strip/Underground
Average Number of Days Worked
Strip
Underground
Average Number of Men Working Daily (1000)
Strip
Auger
Underground
Total
%. of Labor Force
Strip
Auger
Underground
197.0
16.4
347.1
560.5
244.1
20.0
338.8
602.9
259.0
17.3
275.9
552.2
275.7
15.6
304.1
595.4
275.3
14.2
301.5
591.0
35.2
2.9
61.9
2.3
247
224
18.0
2.3
79.7
40.5
3.3
56.2
2.6
236
229
20.3
2.7
77.0
46.9
3.1
50.0
3.0
220
210
22.7
2.3
75.0
46.3
2.6
51.1
3.0
225
227
22.8
2.0
75.2
46.6
2.4
51.0
35.7
39.9
15.6
19-9
36.0
34.3
13.8
18.8
35.7
39.0
12.0
18.0
36.0
43.0
11.9
17.7
34.6
41.1
11.2
16.8
3.1
227
225
22.3
2.9
99.3
124.5
28.4
3.9
107.8
140.1
33.0
3.4
109.3
145.7
34.0
3.0
112.3
149.3
35.0
2.9
119.9
157.8
22.2
1.8
76.0
Source:
Ref. 7-2
EPA-460/3-74-009
-------
The total increase in employment in the categories cited above
was 9,000 versus 900 in mining alone. However, much of the impetus was
due to the increase in mining activity. Thus, the approximate multiplier
for employment was 10.*
The same article reports that, since 1970, the Mountain states
have been gaining population at three times the national rate. It also
speculates that Wyoming's population will double by the year 2000. One
of the consequences of population growth is to place an increased demand
on water resources. In low rainfall areas, such as the Mountain states,
it seems certain that the competing demands for water by (a) industry,
(b) farming and (c) the general public will present very difficult prob-
lems to the state governments and to all concerned.
Specialized labor requirements are discussed in Appendix 5.
Through 1985, iit seems likely that the professional effort needed to de-
sign and construct synfuel plants will be a limiting factor. In the longer
run, this limitation may be removed only to be replaced by one of a more
fundamental nature, namely the balance of natural resources in the Mountain
states. Richness in mineral resources may not be adequately matched by
water availability for all of the demands, direct and indirect, that are
likely to be created by a rapidly growing synthetic fuels industry.
This study does not predict that water availability will limit
production of synfuels, but it does recognize this as a possibility that
should be taken very seriously.
7.8 Capital Availability and Investment Implications
The capital requirements of the energy industries are discussed
in Appendix 5. A major conclusion will be restated, namely that alterna-
tive automotive fuels must be considered as a part of a much larger whole.
Hence, capital availability for alternative automotive fuels cannot prop-
erly be considered in isolation from the availability of capital for energy
investments in general. The overall availability of capital would seem to
depend on the future profitability of energy investments relative to other
investments since it is clear that the energy investments will require
capital considerably in excess of what can be generated by the internal
cash flow of the energy industries.
At least one general conclusion follows from the postulate that
there will be competition for external investment funds by most segments
of the economy. The conclusion is that investments will have to be as
efficient as possible. The same point stated negatively is that wasteful
or unnecessary investments will have to be avoided because such investments
An even higher multiplier was cited in Section 5.1. In fact, the two
estimates are mutually compatible because one considers mining while
the other involves synthetic fuel production as well.
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would subtract capital from projects that are needed. A specific impl
cation is that a duplication of the existing distribution and marketing
system will not occur (so as to permit the introduction of fuels not
compatible with the existing system) unless there is no alternative.
However, this study shows that there is an alternative.
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8. INFORMATION GAPS
In the course of assessing-the feasibility of coal and shale-
derived fuels, it was possible to identify a number of areas where sig-
nificant information gaps exist. The relative attractiveness of one
fuel versus another cannot be discussed with a high degree of confidence
until more of these data gaps are filled. The following discussion
describes these information gaps, dividing them into research data gaps
and other information gaps.
8.1 Research Data Gaps
8.1.1 Fuels From Shale Oil
8.1.1.1 Mining and Retorting
Techniques for underground mining of oil shale are fairly well
established, but could certainly stand improvement by the development of
equipment which will allow more rapid mining. The room-and-pillar tech-
nique should be improved to allow greater recoveries.
The retorting step, although not yet demonstrated commercially,
has been checked out in various semi-commercial operations. Improvements
can be made in heat transfer, oil recovery, versatility with respect to
particle size and oil content of the feed, and, very importantly, in
spent shale disposal. The first three areas are under continuing study
and improvements will doubtless be demonstrated in the first group of
commercial plants (to be constructed on the prototype lease tracts
recently made available by the U.S. government).
The question of spent shale disposal is critical to the success
of the shale oil industry. It has been possible to stabilize and re-
vegetate spent shale piles in pilot experiments. The key issue is
whether large-scale disposal associated with a full-size commercial plant
can meet the objectives of:
(1) minimal dust formation
(2) no leaching of minerals by rainfall
(3) reduced water requirement to wet down the shale
(4) effective and permanent revegetation of spent shale
(5) minimal dislocation of local fauna
The development of a shale-oil industry will hinge in great measure on
being able to demonstrate these objectives in the first group of plants.
If spent shale disposal is accompanied by serious environmental disloca-
tions, the industry cannot grow to the size required by fuel demand.*
Technology needs for pollution abatement in fossil fuel conversion
processes (e.g., coal and shale) are being studied by Exxon Res. &
Eng. Co. under a separate E.P.A. contract (8-3).
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In view of all of the above concerns, the concept of under-
ground (in situ) retorting is receiving rapidly increasing attention
(8-1). It will be necessary to develop an economic, efficient, and
environmentally acceptable in situ process if shale oil production is
to achieve levels greater than 1-2 MMB/D (see Section 3.5). The impor-
tant technological issues involve:
(1) use of explosives to create permeability in the forma-
tion, allowing effective communication between the com-
bustion front and the rock.
(2) optimum underground "plumbing" for good heat and mass
transfer required to achieve acceptable recovery.
It is also essential that the in situ process does not create
any new environmental problems, such as subsidence or underground water
contamination. A possible compromise between a conventional mining and
an in situ technique might involve: (a) partially mining an area, (b)
collapsing the excavated area, and then (c) retorting the remaining
rock underground. It will probably be necessary to have an in situ
technique commercially demonstrated by the early 1980's.
Effort applied to solve environmental problems associated
with shale oil has special merit because many other aspects of shale
oil production appear favorable even though further experimental con-
firmation is needed.
8.1.1.2 Upgrading and Refining
The key process in upgrading is nitrogen (and sulfur) removal.
Technology for this step exists, but there is an incentive to develop
more efficient denitrogenation catalysts, i.e., systems which lead to a
lower hydrogen consumption per unit of sulfur and nitrogen removed.
The alternative to severe upgrading at the mine is to treat
the raw shale oil mildly with heat and/or hydrogen. More information is
needed on this process with respect to the inter-relationships among
viscosity reduction, pumpability (in a pipeline), and storage stability.
There is no published information on the response of shale
syncrude to current petroleum refining processes. Based on the composi-
tion of such a syncrude, there is no reason to expect any anomalous
response. Nevertheless, pilot plant data should be obtained on reform-
ing, hydrocracking, isomerizing, etc., shale fractions. These data can
be used to confirm or revise the correlations on which detailed refinery
economics are based.
8.1.1.3 Use
For all the shale and coal-derived fuels, there is an urgent
need to determine product quality and performance data. In the case of
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shale fuels, Tables 4-1 to 4-3 indicate that data are required on com-
bustion properties, low temperature properties, toxicity, and trace
metal content.
Engine and vehicle tests are needed for both shale gasolines
and distillates over a wide range of operating conditions, including
various automotive power plants under development. Such tests should
be carried out, in particular, with blends of shale fractions with
petroleum and coal fractions. Indications are that shale and coal
hydrocarbon fuels will be used in blends with petroleum throughout the
time period considered in this study.
8.1.2 Hydrocarbon Fuels From Coal
8.1.2.1 Mining
It was pointed out in Section 5.2 that the development of a
coal liquids industry will be based in great measure on the rapid growth
in the surface-mining of Western coal. Further improvements in large
semi-automated surface-mining equipment could have a very significant
effect on productivity. The permanent reclamation of mined land has yet
to be demonstrated on a large scale. Problems In this area will be as
difficult to solve and as critical to the success of the industry as
those associated with spent shale disposal.
Suggestions have been made to develop an in situ coal liquefac-
tion process, analogous to solution mining (8-2). Conceptually, a coal-
derived solvent would be pumped, hot and under pressure, into a coal
seam to dissolve some of the coal. The process would resemble the sol-
vent refining of coal, with the important difference that the ash would
be left in the ground. Theoretically, such a scheme is applicable to
fairly deep coal, i.e., as an alternative to conventional underground
mining or in situations where such mining is not feasible. This could
make such coal an attractive resource for liquefaction. As with in situ
shale retorting, there are various environmental, as well as technical,
questions which have to be answered before such a process can be
assessed.
.-<
In situ gasification of coal is also being seriously considered.
In the context of this study, it is of importance as a source of CO/H-
for methanol production.
8.1.2.2 Upgrading and Refining
The major cost in coal liquefaction is due to the hydrogen
required to alter the C/H ratio of the coal. This suggests a two-
pronged attack aimed at lowering the cost and/or the requirements for
hydrogen.
Although the technology for hydrogen production from coal is
very similar to coal gasification, the optimum process for one is not
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-------
the same as for the other. The objective for hydrogen production is to
minimize direct methane production and maximize CO + H2- Partial oxida-
tion processes, particularly at elevated pressure, are of considerable
interest in hydrogen production. The char remaining from gasification
processes is an important feedstock in hydrogen production.
Liquefaction research should be directed at minimizing hydrogen
consumption. This, in turn, is tied to the development of more selective
catalysts, which promote the aromatic ring-opening reactions without con-
comitant cracking. For example, in the H-coal process, 20% of the BTU's
appear in gas by-product. Although liquefaction basically is 40-50
years old, the underlying mechanisms have yet to be unravelled. The
major stumbling block has been the very limited knowledge of the chem-
ical structure of coal. Recent advances in analytical techniques are
now making it possible to get this much-needed information.
Another important research area in coal liquefaction involves
improved techniques for separating the unconverted bottoms from the
liquefied product, so as to avoid the need for severe treatment such as
coking.
The Fischer/Tropsch process potentially could be an attractive
alternate for producing liquid hydrocarbon fuels from coal. More selec-
tive catalysts are needed to maximize the yield of liquid product in the
naphtha + distillate boiling range. Engineering research is required on
the F/T process to allow it to be scaled up efficiently to the produc-
tion levels required — i.e., from 5-10 MB/D to 50-100 MB/D.
The refining of coal syncrude calls for the same comments as
were made for shale syncrude refining. However, various coal hydrogena-
tion processes produce different quality syncrudes, with varying sulfur,
nitrogen, and oxygen content. Similar variability will be caused by
using raw coal of different composition. This implies a matching of
processes to feedstock quality (as is the case in the refining of crude
oils of different composition). This will require versatile catalysts
to handle hetero-atom removal, taking account of the fact that the
relative proportions of S-, N-, and 0- compounds will vary from coal to
coal.
8.1.2.3 Use
It is necessary to obtain a complete spectrum of inspection
and product quality data on coal liquids. However, in regard to engine
performance, the stress should be on coal/shale or coal/petroleum
blends.
In generating data on coal liquids, it is important to study
as wide a range of materials as possible, representing the various syn-
crude processes under active development.
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8.1.3 Methanol From Coal
8.1.3.1 Manufacture
The major need in this area involves coal gasification to
produce the CO + H£ mixture needed for methanol synthesis. In the long
run, the co-product SNG scheme will give way to processes which minimize
direct methane production, and which maximize the yield of CO + H2-
Specifically, the need is for high pressure coal gasification to avoid
subsequent compression for the methanol-synthesis — e.g., Lurgi gasifi-
cation with increased oxygen input or a modified Winkler or Koppers/
Totzek process capable of operating at pressures greater than about
five atmospheres.
Methanol synthesis is commercially practiced. Nevertheless,
there is room for improvement. The synthesis reaction is strongly exo-
thermic, which severely limits conversion per pass. It would be very
advantageous to develop a more active catalyst, capable of operating at
lower temperatures, coupled with a selective technique for separating
methanol from unreacted CO + !!„.
8.1.3.2 Distribution and Use
There are many questions associated with the use of methanol/
gasoline blends. First of all, it is critical to define completely the
extent of phase separation due to water contamination. A detailed
assessment is then needed of the specific precautions required to assure
that this contamination does not occur.
Information is also needed on the volatility of methanol/
gasoline blends as it affects vapor-lock. Complete information is re-
quired on emissions, fuel economy, and driver acceptability for vehicles
operating on such blends. The EPA is planning to support a program at
the Bureau of Mines aimed at answering these questions.
With regard to pure methanol as a fuel, it is most important
to define the changes required in the engine and the vehicle to achieve
optimum efficiency and performance. A valid comparison of methanol with
hydrocarbon fuels must consider potential performance advantages for
methanol.
Methanol is potentially an important fuel for fuel cells,
either for direct use or via reforming to hydrogen. As a primary fuel
for fuel cells, information is needed on the effect of impurities on
fuel cell performance. If the methanol is to be reformed, it is neces-
sary to develop active reforming catalysts which do not involve precious
metals, and which could lead to systems whose cost and size is compati-
ble with potential automotive use.
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8.2 Other Information Gaps
The need for technical information that relates directly tc
the production and use of alternative automotive fuels is paralleled by
the need for other types of information. This was recognized by the
Environmental Protection Agency in a recent Request For Proposal, No.
CI 74-0142 of February 26, 1974, titled "Impact Study on the Use^of
Alternative Fuels For Automotive Transportation". Hence, there is no
need to make reference to the information gaps perceived during the
present study that have already been identified in CI 74-0142. However,
three points will be made for the sake of emphasis:
(1) it is essential to consider automotive fuel alternatives
in the context of the economy as a whole. The practical implications of
the present feasibility study will be uncertain until this has been done.
The proposed impact study is therefore essential.
(2) The future availability of water requires sophisticated
and detailed study. Just as the consideration of automotive fuels should
not be divorced from other fuel needs, so the availability of water for
the production of alternative fuels should not be considered in isolation
from the availability and demand for water for all purposes. A study of
water requirements should, in fact, be part of a bigger study assessing
the total impact of coal and shale mining and conversion industries in
sparsely populated areas of the West.
(3) On-going studies should address the proper utilization of
all domestic resources including petroleum. It is probable that differ-
ent resources will be used so that they complement each other, off-
setting individual weaknesses and utilizing individual strengths to best
advantage. In this context, the alternative is not between all petroleum
and no petroleum. The alternative is the progressive complementation of
petroleum fuels with fuels from other sources, and the blending of fuel
components from different sources if this is the most effective approach.
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9. CONCLUSIONS
The conclusions of this study can be classified into four
types;
(a) Virtual certainty; Where the evidence and logic are so persuasive
that it may be concluded that something will happen.
(b) Dependent on assumptions used; The conclusion is valid only if the
assumptions are valid, e.g., that surface mining will be permitted
or that the cost of automotive fuels may be adequately compared on
an ex-tax basis.
(c) Dependent on contractor's judgment; Many factors affecting long
range projections are not forecastable in a rigorous way and must
be dealt with by judgment.
(d) Information gaps; One objective of the study is to identify un-
certainties that can be resolved by additional work. In effect,
such conclusions are recommendations that the necessary work be
done.
The conclusions that follow are identified by (a), (b), (c),
or (d) to indicate the type of uncertainty associated with it. Unless
otherwise noted, the conclusions apply to the 1982-2000 time-frame.
(1) It is feasible and practical to make petroleum-type fuels from coal
and oil shale. They are the most attractive alternates to
petroleum over the time frame of the study. (a),(c)
(2) Initial production of these petroleum-type fuels is likely within
the next 5-7 years. (a)
(3) Automotive fuel components from coal and oil-shale will be blended
with petroleum fractions. (c)
(4) For practical purposes, if petroleum-type products from coal and
oil shale are blended with petroleum, no product quality problems
will be experienced by customers. However, at present, there are
many data gaps which will have to be filled. (c),(d)
(5) The potential for product quality problems is greater if unblended
coal or shale gasoline distillate is marketed: (c)
- early determination of product quality and other performance data
would be essential, but - (d)
- the scenario of unblended fuels is unrealistic (c)
- 207 -
-------
(6) Methanol from coal:
- is a feasible automotive fuel for spark-ignition engines, gas
turbines, and fuel cells. (a)
- in spark-ignition engines will require engine and vehicle modifi-
cation for optimum performance. (a)
- is an excellent gas turbine fuel, particularly suited for
stationary turbine applications. (c)
- if used widely as an automotive fuel, in the near and mid-term
future, would have to enter the market as a blend with gasoline
but, eventually, would be used unblended. (c)
- if used in a modified spark-ignition engine could lead to im-
proved efficiency relative to hydrocarbon fuels. (c)
- used in blends with gasoline could lead to driveability problems
unless the system is kept dry, the gasoline is debutanized and
the fuel system is modified. (c)
- is a sufficiently probable product that vehicle performance data
should be obtained using both methanol/gasoline blends and neat
methanols. (d)
(7) Synthetic fuel production from coal and oil shale:
- will not be limited by the size of domestic coal and oil shale
resources. (a)
- will be limited initially by the availability of skilled man-
power and eventually by water availability and environmental/
ecological considerations. (c)
- will make only a minor contribution to automotive fuel supplies
in 1985, but has the potential for becoming a major factor by
the year 2000. Realization of this potential is critically
dependent on a satisfactory resolution of the previous item, (c)
(8) Estimates of fuel costs;
- In the 1982/85 time-frame the cost of shale and coal syncrudes,
including a 10% DCF return, will be about $5.50/bbl and $8.00/
bbl respectively in 1973 constant dollars. (b)
- At the pump, on an ex-tax basis, the potential alternative auto-
motive fuels are estimated to cost;
- 208 -
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1982 1990 2000
$MMBTU
-------
(14) Automotive fuel questions should not be divorced from energy
supply/demand in general. the future demand for aviation fuels is
particularly pertinent. (c),(d)
(15) On-going studies should address the optimum utilization of all
domestic resources, including petroleum. It is impossible to
properly evaluate the impact of alternative fuels without con-
sidering petroleum as an integral part of domestic energy
supplies. (a)
(16) Many research data gaps were identified. The most important of
these point up the need for: (d)
- product quality and performance data on shale and coal-derived
fuels, alone or in blends with petroleum, in various types of
engines and vehicles.
- an improved process for producing hydrogen from coal.
- a more selective coal hydrogenation process.
- an improved coal gasification process, operating at elevated
pressure, which maximizes CO+H?•
- commercial demonstration of spent shale disposal.
- longer-range, an underground shale retorting process, which
minimizes environmental problems.
(17) The relative overall attractiveness of coal and shale-derived fuels
requires more than the technical feasibility analysis presented in
this study. However, this issue will be addressed in an EPA
sponsored alternate fuels impact study. , .
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Section 3
(3- 1) "U.S. Energy Outlook", National Petroleum Council,
Washington, D.C., 1972.
(3- 2) Coal Age, April 19, 1974, page 5.
Section 4
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- 211 -
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Section 4
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-------
section 4
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Section 4
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(4- 55) Bush, A. F., et al., "On the UCLA Hydrogen Car", Report of
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Energy Conversion Engineering Conference - 1972; p. 1342.
(4- 58) Data by Wiswall, R. H., Brookhaven National Laboratory;
Personal Communication from U.S., Environ. Prot. Agency,
Sept. 18, 1973.
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(4- 60) Personal Communication from Jensen, H. B., Bureau of Mines,
Laramie Energy Research Center, Laramie, Wyoming.
(4- 61) Johns, J. J., et al., ACS Div. Fuel Chem. Prepr. 1(6 (1),
26-35 (1972).
(4- 62) Quader, S. A., et al., ACS Div. Fuel Chem. Prepr. 1J3 (1),
36-43 (1972).
(4- 63) Chem. Eng. Mar. 3, 1967; p. 163.
(4- 64) Olin Chemicals Brochure, "Product Data Anhydrous Hydrazine
Handling and Storage".
(4- 65) Stewart, W. F., ASME Paper 73-ICP-78 (1973).
(4- 66) U.S., Bur. Mines, Survey, Diesel Fuel Oil, Summer 1972
(November 1972).
(4- 67) U.S., Bur. Mines, Survey, Motor Gasolines, Summer 1972
(January 1973).
(4- 68) U.S., Bur. Mines, Survey, Motor Gasoline, Winter 1972-73
(June 1973).
(4- 69) Brewster, B., et al., "Automotive Fuels and Combustion
Problems", presented at SAE Natl. West Coast Meeting,
August 19, 1963.
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Section 4
(4- 70) Hoffman, K. (Brookhaven National Labs), presented at U.S.,
Environ. Prot. Agency Symp., October 14-19, 1973.
(4- 71) Brogan, J. J., SAE Paper 730519 in SAE Special Publication
SP-383 (1973).
(4- 72) Schlatter, M. J., SAE Paper 670453 (1967).
(4- 73) Corner, E. S., et al., ACS Div- Water, Air & Waste Chem.,
Vol. 11, (1), 1971; p. 170.
(4- 74) Diesel and Gas Engine Progress, April 1973; p. 84.
(4- 75) Gardiner, A. W., SAE Paper 730617 in SAE Special Publication
SP-379, (1973); p. 1.
(4- 76) Davis, S. R., et al., SAE Paper 730620 in SAE Special
Publication SP-379, (1973); p. 36.
(4- 77) Fourth Summary Report, Automotive Power Systems Contractors
Coordination Meeting, June 1973, Division of Advanced
Automotive Power Systems Development, U.S., Environ. Prot.
Agency.
(4- 78) Brogan, J. J., et al., SAE Paper 729125, in Proceedings of
the 7th Intersociety Energy Conversion Engineering Conference,
1972; p. 806.
(4- 79) "Report by the Committee on Motor Vehicles Emissions,"
National Academy of Science, Feb. 12, 1973.
(4- 80) Michels, A. P- J., SAE Paper 729133, in Proceedings of the
7th Intersociety Energy Conversion Engineering Conference,
1972; p. 875.
(4- 81) Fleming, R. D., et al., SAE Paper 710833 (1971).
(4- 82) Adelman, H. G., et al., "Reduction of Automobile Exhaust
Emissions with Methyl Alcohol as Fuel," Dept. of Aeronautics
and Astronautics, Stanford University.
(4- 82a) Pefley, R. K., et al., "Study of Decomposed Methanol as a Low
Emission Fuel", Final Report to U.S., Environ. Prot. Agency,
April 30, 1971, Contract No. APCO-EHS 70-118; PB-202 732.
(4- 83) Jennings, F. A., et al., SAE Paper 730804 (1973).
(4- 84) Personal Communication from Hodgson, J. W., University of
Tennessee, Mechanical and Aerospace Engineering.
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Section 4
(4- 87) Same as (4-77).
(4- 86) Ninomiya, J. S., et al., SAE Paper 690504 (1969).
(4- 87) Plungis, D., Note presented at First Symposium on Low
Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 88) McFadden, J. J., Note presented at First Symposium on Low
Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 89) Aerojet Liquid Rocket Co., Paper presented at First Symposium
on Low Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 90) Thermo Electron Corp., Paper presented at First Symposium on
Low Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 91) Scientific Energy Systems Corp., Paper presented at First
Symposium on Low Pollution Power System Development,
Sponsored by U.S., Environ. Prot. Agency, October 14-19, 1973.
(4- 92) Ortegren, L. G., Paper presented at First Symposium on Low
Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 93) Michels, A. P- J., Paper presented at First Symposium on Low
Pollution Power System Development, Sponsored by U.S.,
Environ. Prot. Agency, October 14-19, 1973.
(4- 94) Murray, R. G., et al., SAE Paper 719009 (1971).
(4- 95) Frost, C. M., ACS Div. Fuel Chem. Prepr. _16 (1), 73-87 (1972).
(4- 96) Same as (4-60).
(4- 97) Coward, H. F., et al., U.S., Bur. Mines, Bull. 50 (1952);
p. 130.
(4- 98) Barnett, H. C., et al., N.A.C.A. Rep. 1300.
(4- 99) Clark, M. B., et al., "Hydrazine-Air Fuel Cell Simplification
Studies", Union Carbide Corp., Res. & Dev. Technical Report
ECOM-0163-F (October 1968) Contract No. DAAB07-68-C-0163;
AD 676 873.
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Section 4
(4-100) Fleming, R. D., et al., U.S., Bur. Mines, Rep. Invest. 7806
(1973).
(4-101) Adt, R. R., SAE Paper 739092, in the 8th Intersociety Energy
Conversion Conference Proceeding, Aug. 13-16, 1973.
(4-102) Chem. Bag., March 4, 1974; p. 70.
(4-103) SNG Symposium I, Collected Papers, Inst. Gas Technol.,
March, 1973.
(4-104) Mills, G. A. and Harney, B. M., Chemtech., Jan. 1974; p. 26.
(4-105) "A Hydrog Energy Carrier", 2 vols., Systems Design Institute
(N.A.S.A./ASEE) 1973.
(4-106) "Hydrogen and Other Synthetic Fuels", Synthetic Fuels Panel,
Federal Council On Science & Technology, R & D Goals Study,
Sept. 1972.
(4-107) "Thermochemical Hydrogen Production", The Hydrogen Economy,
Miami Energy Conference, Conference Proceedings, Session #11,
March 1974.
(4-108) Same as (3-1) .
(4-109) Oil Gas J., March 2, 1970; p. 63.
(4-110) Coal Gasification Report by the Federal Power Commission, as
given at The Conference on Synthetic Natural Gas at Institute
of Gas Technology, Sept. 10-14, 1973.
(4-111) Same as (4-39).
(4-112) Fuinerau, J. A., Prepr., 74th AIChE Meeting, March 11, 1973.
(4-113) Johnson, J. E., "Storage and Transportation of Synthetic
Fuels", Report to the Synthetic Fuels Panel, ORNL-TM-4307,
Oak Ridge National Lab., September 1972.
(4-114) Chem. Week, Nov. 11, 1972; p. 46.
(4-115) Johnson, J. E., "Economics of Liquid Hydrogen Supply for Air
Transportation", presented at Cryogenic Engineering Conference,
Atlanta, Ga., August 10, 1973.
(4-116) Brogan, J. J., SAE Paper 730519, in SAE Special Publication
SP-383 (1973); p. 31.
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Section 4
(4-117) Furlong, L. E., et al., "Emission Control and Fuel Economy",
paper presented at the Spring ACS National Meeting, Los
Angeles, Calif., April 1, 1974.
(4-118) Same as (4-79) .
(4-119) Underkofler, L. A. and Hickey, R. J., "Industrial
Fermentations", Section I, Chem. Publ. Co., New York (1954).
(4-120) Personal Communication from P. A. Sipple, Air Products &
Chemical Co., Allentown, Pa.
(4-121) Work at U.S. Army Natick Laboratories, Science 184, 524 (1974)
(4-122) Hydrocarbon Research, Inc., "Commercial Process Evaluation of
H-Coal Hydrogenation Process", Office of Coal Research,
Contract: 14-01-0001-477-
(4-123) Frank, M. E., et al., ACS Div. of Fuel Chem. Prepr. _16 (1),
13-25 (1972).
(4-124) Seglin, L., Encyclopedia Chem. Technology, 2nd Ed. Supplement,
Kirk-Othmer Editors (1971) pages 177-198.
(4-125) Hill, G. R., Chem. Technology _2 (5), 292 (1972).
(4-126) "Oil from Coal; Synthetic Liquid Fuels Annual Report of the
Secretary of the Interior for 1952", U.S. Bur. Mines, Rep.
Invest. 4942 (1953).
(4-127) "Oil from Coal; Bur. Mines; Synthetic Liquid Fuels Program
1944-1955: Part I"; U.S. Bur. Mines, Rep. Invest. 5506
(1959).
(4-128) "Oil from Coal; Synthetic Liquid Fuels, Annual Report of the
Secretary of the Interior for 1950", U.S., Bur. Mines, Rep.
Invest. 4770 (1951).
(4-129) Wigg, E. E., Am. Petr. Inst. Prepr. 62-72; presented at Am.
Petr. Inst. Mtg. (Div. of Refining) May 11, 1972.
Section 5
(5- 1) Same as (3-1).
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Section 5
(5- 2) "Final Environmental Statement for the Prototype Oil Shale
Leasing Program," Vol. I, U.S. Dept. of Interior, 1973.
(5- 3) Lewis, A. E., "Nuclear In Situ Recovery of Oil from Oil Shale,"
Lawrence Livermore Laboratories, September 14, 1973; Prepared
for AEC under Contract No. W-7405-Eng-48.
(5- 4) Oil Gas J., Sept. 24, 1973; -p. 94.
(5- 5) Oil Daily, April 16, 1974, p. 3.
(5- 6) Corner, E. S. and Cunningham, A. R., paper at ACS Natl.
Meets., Los Angeles, March 1971.
(5- 7) Wasp, E. J., "Importance of Slurry Pipelines for Western Coal
Development," Proceedings of Montana Coal Symposium, Billings,
Montana, January 1970.
(5- 8) Consolidation Coal Company, "Summary Report on Project
Gasoline, Period: September, 1963 through June, 1969," U.S.
Off. Coal Res., R & D Report No. 39, Volume I, Interim Report
No. 5.
(5- 9) Oil Gas J., Dec. 3, 1973; p. 29.
(5- 10) Pittsburg and Midway Coal Mining Company, "Economic Evaluation
of a Process to Produce Ashless, Low Sulfur Fuel from Coal,"
U.S., Off. Coal Res., R & D Report No. 53, Interim Report
No. 1, Issued June, 1970.
(5- 11) Johnson, C. A., et al., "Present Status of the H-Coal Process,"
Paper 30, IGT 1973 Coal Symposium.
(5- 12) Yavorsky, P. M., "Synthoil Process Converts Coal into Clean
Fuel Oil," Paper 29, IGT 1973 Coal Symposium.
(5- 13) Hoogendoorn, J. C., "Experience with Fischer-Tropsch Synthesis
at Sasol," Paper 21, IGT 1973 Coal Symposium.
(5- 14) Tramm, H., "25 Years Fischer-Tropsch Synthesis with Fixed-Bed
Catalysts, Present Status and Future Possibilities,"
Section III - Paper 27, Fifth World Petroleum Congress,
1959.
(5- 15) Johnson, C. A., et al., "H-Coal: Conversion of Western Coals,"
AIME Prepr. 72-40, AIME Annu. Meet. February 20-24, 1972.
(5- 16) American Oil Company, "Evaluation of H-Coal," OCR Contract
14-01-0001-1188.
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Section 5
(5- 17) Same as (4-122) .
(5- 18) "U.S. Energy Outlook, Coal Availability," National Petroleum
Council, Library of Congress Catalog Card Number: 72-172997.
(5- 19) Plant Description and Cost Estimates, El Paso Natural Gas Co.,
Burnham I Coal Gasification Complex, prepared by Steams-Roger,
Inc., August, 1972; revised October, 1973.
(5- 20) Rudolph, P. F. H., "The Lurgi Process - The Route to S. N. G.
from Coal," presented at the Fourth Synthetic Pipeline-Gas
Symposium, Chicago, October 30, 31, 1972.
(5- 21) Farnsworth, J. F. et. al., "Production of Gas from Coal by The
Koppers-Totzek Process," Paper 9, IGT 1973 Coal Symposium.
(5- 22) Banchik, 1. N., "Winkler Process for Production of Low BTU Gas
from Coal," Davy-Powergas, Inc., Lakeland, Florida.
(5- 23) Environ. Sci. Technol. 7 (1973); p. 1002.
(5- 24) Pet. Petrochem. Int. 13_ (9), 49 (1973).
(5- 25) "The Oil Import Question," Cabinet Task Force on Oil Import
Control, February 1970, Washington, D.C.; p. 278.
(5- 26) Speech by Kelly, J. M., to Washington Coal Club, as reported
in Coal News, No. 4206, March 29, 1974; p. 4.
(5- 27) "Your Driving Costs - 1973/1974 Edition"; Pamphlet from
American Automobile Association.
Section 6
(6- 1) "Project H Coal", Hydrocarbon Research, Inc., U.S., Off. Coal
Res., Project No. 14-01-001-477, 1967-
(6- 2) Same as (4-123).
(6- 3) Seglin, L., Encyclop. Chem. Tech., 2nd Ed., Kirk-Othmer,
Editors, Supplement. Vol., 177-198 (1971).
(6- 4) Same as (4-125).
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Section 6
(6- 5) Wu, W. R. K. , et al., U'.S., Bur. Mines, Bull. 633 (1968).
(6- 6) Same as (4-126).
(6- 7) Unpublished data from Bureau of Mines Demonstration Plant
Louisiana, Missouri; cf. U.S., Bur. Mines, Rep. Invest. 5506
(1959).
(6- 8) Same as (4-128) .
(6- 9) Wigg, E. E., API Annu. Meet. Prepr. 62-72, Presented at the
American Petroleum Institute Div. of Refining, May 11, 1972.
(6- 10) "U.S. Energy Outlook: Oil Shale Availability", National
Petroleum Council, Washington, D.C., 1973.
(6- 11) Smith, H. W. , U.S., Bur. Mines, Bull. 642 (1968).
(6- 12) "Project H-Coal Report", U.S., Off. Coal Res. R & D Report 26
by Hydrocarbon Research, Inc.; Contract No. 14-01-001-477.
(6- 13) Frost, C. M. , et al., ACS Div. Pet. Chem. Prepr. JL8 (1), 119
(1973).
(6- 14) Fed. Regist. J38 (187); Sept. 27, 1973.
(6- 15) Same as (4-34).
(6- 16) Same as (4-117) .
(6- 17) International Critical Tables, Vol. Ill, p. 287, 395.
(6- 18) Reed, T. B. and Lerner, R. M. , SCIENCE 182, 1279 (1973).
Section 8
(8- 1) Same as (5-3) .
(8- 2) Chem. Eng. News, April 23, 1973; p. 38.
(8- 3) "Technology Needs For Pollution Abatement in Fossil Fuel Conversion
Processes", E. M. Magee and H. Shaw; presented at Symp. on Environ-
mental Aspects of Fuel Conversion Technology, St. Louis, Mo.,
May 1974 (work performed under E.P.A. Contract No: 68-02-0629).
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11. GLOSSARY
antiknock quality of motor gasoline refers to the ability of the fuel to
resist spontaneous ignition in localized areas of the combustion
chamber. An audible "knock" or "ping" may result from such spontaneous
ignition. The tendency to knock is affected by engine operating con-
ditions (speed, temperature, etc.). and this is why the antiknock
quality of motor gasoline is measured by two different laboratory
engine tests: Research Method and Motor Method. The Research octane
numbers and Motor octane numbers determined by these procedures are
discussed in Appendix 6 in Volume 3. Many other terms relating to
fuel properties are also explained in Appendix 6.
associated-dissolved gas - associated gas is free natural gas in immediate
contact, but not in solution, with crude oil in the reservoir;
dissolved gas is natural gas in solution in crude oil in the reservoir;
nonassociated gas is free natural gas neither in contact with, nor
dissolved in, crude oil in a petroleum reservoir.
barrel a liquid volume measure equal to 42 U.S. gallons.
breeder reactor - a nuclear reactor that produces more fissionable material
than it consumes. This reactor is sometimes called the fast breeder
because high energy (fast) neutrons will produce most of the fissions
in current designs.
British Thermal Unit amount of heat required to raise the temperature of
one pound of water one degree Fahrenheit. The BTU is a very small unit
of measurement, and when one adds up large quantities of energy, one
must count in large multipes of the BTU. Thus national energy balances
are often expressed in quadrillions (10") of BTU's.
The approximate BTU equivalents of common fuels are as follows;
Fuel Common Measure BTU' s
Crude Oil Barrel (Bbl.) 5,750,000
Natural Gas Cubic Foot (CF) 1,032
Bituminous Coal Short Ton (2000 Ibs.) 23,000,000
Electricity Kilowatt Hour (KWH) 3,412
Two trillion BTU's per year are approximately equal to 1,000 barrels
per day of crude oil.
capital intensity - is a relative term often used when discussing the
extractive and energy industries. The intensity may be measured as
the amount of capital that must be invested in order to generate a
unit of production. For petroleum refining, a commonly used ratio is
"thousand dollars"(of refining investment) per daily barrel of crude
oil charging capacity, i.e., $M per B/D. Although subject to
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economic controversy, it is generally considered that return on invested
capital, rather than net profit per dollar of sales, is of controlling
importance in capital intensive industries.
cash bonus payment - a cash consideration paid by the lessee for the execu-
tion of an oil or gas lease by a landowner. The bonus is usually
computed on a per acre basis.
coal gasification - the conversion of coal to a gas suitable for use as a
fuel.
coal liquefaction (coal hydrogenation) - the conversion of coal into liquid
hydrocarbons and related compounds by hydrogenation.
committed reserves - of coal refer to the quantities of recoverable coal
from a specific deposit or deposits that would be committed to an
individual coal conversion project (syncrude and/or syn. gas) over the
expected life of the project. Such coal reserves, once committed,
would not be available for other purposes. Committed coal reserves
are analogous to "dedicated" reserves of natural gas.
condensate - liquid hydrocarbons obtained by the condensation of a vapor or
gas produced from oil or gas wells and ordinarily separated at a field
separator and run together with crude oil in petroleum refineries.
constant dollars - wherever used in this report, the terms "constant dollars"
or "1973 dollars" refer to the purchasing power of the U.S. dollar in
the year 1973. These terms are used to provide a measure of compara-
bility (or common denominator) to projections of Gross National Product,
costs, revenues, capital requirements, and other financial data which
might otherwise be distorted by varying estimates of the unpredictable
factor of inflation or deflation in future years. Where used, the
term "current dollars" refers to the purchasing power of the U.S.
dollar in the year specified, including such inflation or deflation as
may have existed at that time.
To convert "constant" to "current" dollars for future years, it is
necessary to apply such inflation or deflation factors as the reader
deems appropriate. For example, assuming an inflation factor of 40%
for the 1970-1975 period, the 1975 "current" dollar could be derived
by multiplying the 1970 "constant" dollar by 1.4.
conventional gas - natural gas as contrasted with synthetic gas.
conventional oil - crude oil and condensate as contrasted with synthetic
oil from shale or coal.
conversion processes - are used extensively in petroleum refining, and are
potentially applicable to the refining of synthetic crudes derived
from coal or oil shale. A higher yield of desired products is obtained
by conversion of less desired fractions. The most widely used class of
conversion processes involves "cracking," i.e., the breaking of higher
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molecular weight molecules into fragments of lower molecular weight
and boiling point. When such cracking is assisted by a catalyst, it
is called "catalytic cracking" or "cat. cracking." When the process
is carried out in the presence of hydrogen under pressure, it is called
"hydrocracking." The pertinent process units are called "cat. crackers"
and "hydrocrackers." If the principal purpose of the cracking process
is to reduce the viscosity of the product, it is called "visbreaking"
(i.e., "viscosity breaking"). In the presence of hydrogen, the process
is "hydrovisbreaking." If the principal purpose of the conversion
process is to achieve molecular rearrangements, rather than conversion
into lower molecular weight fragments, it is called "reforming." In
the presence of hydrogen, the process is "catalytic reforming." This
latter process is widely applied to naphtha fractions in order to
increase octane number so that the catalytically reformed naphtha
product may be used as a motor gasoline blending component. Catalytic
reforming involves dehydrogenation and other reactions that have the
net effects of increasing the concentration of aromatic hydrocarbons
in the product at the expense of paraffins and cycloparaffins and of
yielding hydrogen as a by-product. It is a common refining practice
to utilize the by-product hydrogen from catalytic reforming for de-
sulfurization ("hydrofining," "hydrodesulfurization," etc.) and for
other refining processes that consume hydrogen. When applied to fuel
oils, desulfurization may also be referred to as an "upgrading" or
"bottoms upgrading" process. Visbreaking, too, is an upgrading process
since it improves the quality of the product relative to that of the
visbreaker feedstock. The majority of, but not all, petroleum refining
processes involve some combination of:
(a) Distillation, i.e., separation by boiling point (and molecular
weight).
(b) Cracking, i.e., conversion of higher boiling fractions to lower
boiling fractions.
(c) Reforming, i.e., molecular rearrangements without substantial
change in boiling point.
(d) Upgrading, i.e., improvement in product quality.
cryogenic techniques - techniques involving extremely low temperatures
used to keep certain fuels in a liquid form; i.e., liquefied hydrogen,
methane, propane, etc.
depletion allowance - a proportion of income derived from mining or oil
production that is considered to be a return of capital not subject
to income tax.
distillate - as used in this report refers to "middle distillate," i.e.,
the mid-boiling range fraction of a conventional or a synthetic
crude oil. This is the fraction from which automotive distillate
fuels, such as automotive diesel fuel, may be derived. While their
specifications differ in detail, automotive diesel fuel and A.S.T.M.
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No. 2 fuel oil (or heating oil) are very similar distillate fuel
products. Under low temperature conditions (e.g., severe winter),
the pumpability of automotive diesel fuel and/or No. 2 fuel oil may be
unsatisfactory. In such cases the products may be blended with, or
replaced by, A.S.T.M. No. 1 fuel oil (or kerosene). Most commercial
aviation jet or gas turbine fuel is a specially refined kerosene.
Formerly, kerosene was used as lamp oil; this is now an extremely
minor use in the U.S. Kerosene is the "lightest" or lowest boiling
middle distillate fuel. From the standpoint of petroleum refining,
it is a narrow boiling range cut between naphtha (most of which is con-
verted into gasoline) and "distillate fuel" (i.e., A.S.T.M. No. 2 fuel
oil and automotive diesel fuel). In refineries that do not produce
kerosene, most of the "kerosene boiling range" hydrocarbons would be
included with the "distillate fuel" produced by the refinery, while
the lowest boiling hydrocarbons in the kerosene boiling range would be
included in naphtha.
dry hole - or "duster" refers to a well that did not encounter deposits of
either crude oil or natural gas. It may be noted that a well may find
hydrocarbons (and, hence, not be "dry") in insufficient quantities to
warrant production. Such a discovery would be termed "noncommercial
shows of oil and/or gas." When considering future domestic resources,
it is important to recognize that coal and oil shale deposits cannot
be "dry," i.e., there is a certainty that the resources exist.
fossil fuel - any naturally occurring fuel of an organic nature, such as
coal, crude oil, and natural gas.
fuel cell - a cell that continuously changes the chemical energy of a fuel
and oxidant to electrical energy.
hopper car - a car for coal, gravel, etc., shaped like a hopper, with an
opening to discharge the contents.
hydrocarbon fuels - fuels that contain organic chemical compounds of hydrogen
and carbon.
hydrotreating - the removal of sulfur from petroleum feedstocks by replace-
ment with hydrogen.
high-temperature gas reactor - a nuclear reactor in which helium gas is the
primary coolant with graphite fuel elements containing coated particles
of highly enriched uranium plus fertile thorium.
in situ - in the natural or original position; applied to a rock, soil, or
fossil when occurring in the situation in which it was originally
formed or deposited.
light-water reactor (LWR) - nuclear reactor in which water (f^O) is the
primary coolant/moderator with slightly enriched uranium fuel. There
are two commercial light-water reactor types — the boiling water reactor
(BWR) and the pressurized water reactor (PWR).
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liquefaction of gases - any process in which gas is converted from the
gaseous to the liquid phase.
liquefied natural gas (LNG) - a clear, flammable liquid both tasteless and
odorless; almost pure methane.
liquefied petroleum gas (LPG) - a gas containing certain specific hydro-
carbons which are gaseous under normal atmospheric conditions, but can
be liquefied under moderate pressure at normal temperatures; principal
examples are propane and butane.
metallurgical coal - coal with strong or moderately strong coking properties
that contains no more than 8.0% ash and 1.25% sulfur, as mined or after
conventional cleaning.
methanol/methyl alcohol (CH30H) the lowest member of the alcohol series.
Also known as wood alcohol, since its principal source used to be
destructive distillation of wood.
narrow cut - is a relative term applied in petroleum refining. Kerosene
would generally be considered a narrow cut because of its narrow, or
limited, boiling range. A blend of naphtha and kerosene would be
considered a wide cut because of its wider boiling range. The word
"cut" is associated with the technology of separating hydrocarbons of
different boiling point by distillation (or fractionation). The
separations are made at specific temperatures or "cut points." The
various products from such distillations may be referred to as "cuts"
or "fractions." The lowest boiling fraction is withdrawn from the top
of the distillation column (tower, fractionator, "still") and may be
called an overhead product or simply "overhead." The highest boiling
material withdrawn from the bottom of the distillation column is
called a residuum, distillation residue, or "bottoms." Residual fuel
oil used to be the bottoms product from the distillation of crude oil.
However, the need for fuel oils of low sulfur content has led to addi-
tional processing steps for residual fuels after their initial separa-
tion from crude oil by distillation. Such processes, which include
hydrodesulfurization, are often referred to as bottoms upgrading pro-
cesses and are broadly applicable to conventional and synthetic crude
oils.
oil equivalent - refers to the energy content of a particular energy
resource in terms of the equivalent amount of energy in the form of
petroleum. As the term oil equivalent (O.E.) is commonly used,
reference may be to "crude oil equivalent" or to "fuel oil equivalent."
In general, the former is applied to primary input energy while the
latter is applied to the energy content of products. Unfortunately,
the energy contents of "crude oil equivalent" and "fuel oil equivalent"
(F.O.E.) are not precisely defined as BTU quantities. Approximately,
however, one barrel of crude oil equivalent contains 5.75 million
BTU's while one barrel of F.O.E. contains 6 million BTU's.
oil-in-place - original oil-in-place less the cumulative production.
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oil shale - a convenient expression used to cover a range of materials
containing organic matter (kerogen) which can be converted into crude
shale oil, gas and carbonaceous residue by heating (compare shale oil).
original oil-in-place - the estimated number of barrels of crude oil in
known reservoirs prior to any production, usually expressed as "stock
tank" barrels or the volume that goes into a stock tank after the
shrinkage in volume that results when dissolved gas is separated from
the oil.
overburden - material of any nature, consolidated or unconsolidated, that
overlies a deposit of useful materials, ores or coal, especially those
deposits that are mined from the surface by open cuts.
particulate matter - any matter, except water, that exists in a finely
divided form as a liquid or solid.
primary fuel - fuel consumed in original production of energy as contrasted
to a conversion of energy from one form to another. The heat, or BTU,
content of the primary fuel may be referred to as primary input energy.
In the conversion of coal (or oil shale) to a synthetic crude, the
energy (i.e., heat) content of all of the final products plus the
energy used in the conversion process must be equal to the input energy.
In electricity generation, the heat equivalent of the electricity
generated (3,412 BTU per KW) plus the energy consumed in the generation
process is equal to the primary energy input to the generator. In the
case of nuclear energy, it is important to distinguish between the heat
content of the primary (nuclear) energy input and the heat equivalent
of the electricity output. For light water reactors the latter is
about one-third of the former, i.e., the electrical conversion
efficiency is about 33%. Similar considerations apply to the input and
output energies associated with the production of hydroelectricity.
rank of coal - is a term that characterizes the degree of "coalification"
that has occurred in a particular deposit and, hence, reflects the
average BTU content of the deposit. While there is a broad spectrum
of coal composition such that the lines dividing one rank of coal from
another are blurred, it is convenient to follow the National Petroleum
Council's classification of:
(a) bituminous coal (11,500 BTU/lb., or 23 million BTU/short ton)
(b) sub-bituminous coal (8,500 " " 17 " " " )
(c) lignite (6,750 " " 13.5 " " " )
Most of the U.S. resources of sub-bituminous and lignite coals are in
the western states.
retort - a vessel used for the distillation of volatile materials, as in the
separation of shale oil from oil shale.
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royalty bidding - competitive bidding for leases in which the lease is
offered to the company offering to pay the landowner the largest share
of the proceeds of production, free of expenses of production. A lease
bonus sale is a competitive bidding procedure used extensively by the
Federal government wherein the lease for a particular tract of land
(or offshore acreage) is awarded to the company submitting the highest
bonus bid. The high bidder is then entitled to produce hydrocarbons
(or coal, or oil shale) from the particular tract. The Department of
the Interior's prototype leasing program for six tracts of oil shale
land is being conducted by a combination of bonus bid plus production
royalty.
seasonality - is a term used to recognize that the demand for different
products may vary throughout the year. For example, the demand for
gasoline peaks in the summer while heating oil (i.e., distillate fuel)
demand peaks in the winter. When the different products are derived
from the same source (i.e., petroleum), the refining operations must
have the flexibility of adjusting to variations in seasonal demand for
each product. This is accomplished partly by balancing domestic demand
with imports, partly by seasonal storage, and partly by changing pro-
cessing conditions to emphasize the production of one product during
part of the year and another product during another part of the year.
These adjustments to processing conditions are referred to as seasonal
changes In yield pattern.
secondary recovery - oil and gas obtained by the augmentation of reservoir
energy; often by the injection of air, gas, or water into a production
formation.
shale oil a liquid similar to conventional crude oil but obtained from oil
shale by conversion of organic matter (Kerogen) in oil shale.
stack gas desulfurization - treating of stack gases to remove sulfur compounds,
syncrude - synthetic crude oil derived from coal, oil shale, or tar sands.
syngas - synthetic gas or substitute natural gas (SNG).
synthetic fuel - gaseous or liquid hydrocarbon material produced from solid
or liquid carbonaceous material other than petroleum.
tar sands - hydrocarbon bearing deposits distinguished from more conventional
oil and gas reservoirs by the high viscosity of the hydrocarbon, which
is not recoverable in its natural state through a well by ordinary oil
production methods.
tertiary recovery - fluid injection method that will recover oil above that
attainable by either natural or artificially induced water displacement.
topping - the distillation of crude petroleum to remove the light fractions
only.
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unit train - a system developed for delivering coal more efficiently in
which a string of cars, with distinctive markings, and loaded to
"full visible capacity," is operated without service frills or stops
along the way for cars to be cut in and out. In this way, the customer
receives his coal quickly and the empty car is scheduled back to the
coal fields as fast as it came.
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LIST OF ABBREVIATIONS
AEC - Atomic Energy Commission
AGA - American Gas Association
API American Petroleum Institute
B or Bbl - barrel (42 U.S. gallons)
BWR - boiling water reactor
CRG - Catalytic Rich Gas (process)
DCF - discounted cash flow
D.O.I. Department of the Interior
D.O.T. - Dept. of Transportation
EPA - Environmental Protection
Agency
FBR - fast breeder reactor
FPC - Federal Power Commission
GW - gigawatt (1000 megawatts)
GNP - gross national product
H2S - hydrogen sulfide
HTGR - high-temperature gas-
cooled reactor
KWH - kilowatt hour
LNG - liquefied natural gas
LPG - liquefied petroleum gas
LWR - light-water reactor
MB/D - thousand barrels per day
MCF thousand cubic feet
MMB/D - million barrels per day
MMCF - million cubic feet
MRG - Methane Rich Gas (process)
MTU - metric tons of uranium
MW - megawatt (1000 kilowatts)
MWe - megawatt electrical generating
capacity
NGL - natural gas liquids
NOx - nitrogen oxides
DCS - Outer Continental Shelf
OIP - oil-in-place
OPEC - Organization of Petroleum
Exporting Countries
PAD - Petroleum Administration for
Defense
PGC - Potential Gas Committee
PWR - pressurized water reactor
R/P - reserves/production (ratio)
SNG - substitute natural gas
S02 ~ sulfur dioxide
ST - short ton
TCF - trillion cubic feet
TVA - Tennessee Valley Authority
USGS - U.S. Geological Survey
Notes: (1) The above Glossary and list of abbreviations draw heavily
from the NPC's "U.S. Energy Outlook," December 1972.
(2) Depending on context, B/D may imply Barrels per Stream Day
(B/SD) or Barrels per Calendar Day (B/CD). The latter may
be annualized by multiplication by 365. The former applies
to the capability of a plant while it is operating at full
capacity. However, all plants are shut down occasionally
for routine maintenance and other reasons. Many petroleum
units achieve an operating factor of about 90-92%. This is
equivalent to 330-335 Stream Days per Calendar Year. Thus,
at an operating ratio of 90%, 0.9 B/CD is equivalent to 1 B/SD.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA-460/3-74-009-b
4. TITLE AND SUBTITLE
Feasibility Study of Alternative Fuels fo
Transportation - Volume II, Technical Sec
7. AUTHOR(S)
F. H. Kant, R. P. Cahn, A. R. Cunningham,
W. Herbst, E. H. Manny
9. PERFORMING ORG '\NIZATION NAME AND ADDRESS
Exxon Research and Engineering Co.
P.O. Box 45
Linden, New Jersey 07036
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
Office of Mobile Source Air Pollution Con
Alternative Automotive Power Systems Divi
2929 Plymouth Road, Ann Arbor, Michigan
3. RECIPIENT'S ACCESSION1 NO.
5. REPORT DATE
r Automotive June 1974
tlOn 6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
M. H. Farmer,
10. PROGRAM ELEMENT NO.
1A2017
11. CONTRACT/GRANT NO.
68-01-2112
13. TYPE OF REPORT AND PERIOD COVERED
Final June 1973- June 1974
trol 14. SPONSORING AGENCY CODE
sion
48105
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This study identifies feasible and practical alternatives to
automotive fuels derived from petroleum for the 1975—2000 time period.
The alternative fuels are liquids derived from domestic coal and oil
shale — specifically, gasolines, distillates, and methanol. While many
uncertainties remain, initial production of the new fuels is likely within
the next five to seven years.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Automotive fuels
Substitutes
Feasibility
Forecasting
Oil-shale
Methyl alcohol
Gasoline
18. DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Automotive Fuels ^ fi
Non-petroleum fuels
Synthetic gasolines
Goal liquids
19. SECURITY CLASS (This Report) 21. NO. OF PAGES
Unclassified 238
20. SECURITY CLASS (This page) 22. PRICE
Unclassified
EPA Form 2220-1 (9-73)
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