United States
Environmental Protection
Agency
Office of Mobile Sources
Emission Control Technology Division
2565 Plymouth Road
Ann Arbor, Ml 48105
EPA 460/ 3-83-003
Air
&EPA
Preliminary Perspective on
Pure Methanol Fuel For Transportation
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Preliminary Perspective on
pure Methanol Fuel For Transportation
September 1982
Office of Mobile Source Air Pollution Control
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
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Table of Contents
Page
Executive summary i
Introduction . . 1
I. Raw Material Availability 7
II. Production Technology 15
A. Coal 16
B. Wood 34
C. Agriculture and Municipal Wastes 35
D. Environmental Effects 36
III. Practicalities of Distributing Another New Fuel .... 41
IV. use of Methanol in Vehicles 44
A. Emissions 45
B. Fuel Efficiency 48
V. Economics of Methanol Production and Use 52
A. Production 53
B. Distribution 72
C. Vehicle Effects . . • : . . 76
D. Economics Summary . 79
S~~ '
References 80
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EXECUTIVE SUMMARY
PRELIMINARY PERSPECTIVE ON PURE METHANOL FUEL
FOR TRANSPORTATION
BY THE
OFFICE OF MOBILE SOURCE AIR POLLUTION CONTROL
U.S. ENVIRONMENTAL PROTECTION AGENCY
This report was prepared by EPA's Office of Mobile Source Air
Pollution Control, whose primary responsibility is the control of
pollution from the nation's motor vehicles. It is intended for
use by the U.S. House of Representatives Subcommittee on Energy
and Power, chaired by Representative John D. Dingell, which has
been exploring the outlook for various alternative fuels.
The report examines the environmental advantages of pure
methanol fuel in motor vehicles designed for its use over
conventional fuels, and examines the issues involved in developing
a methanol production industry, such as technological availability
and economics, particularly when coal is used as a feedstock.
I. Conclusions
Based on early research by investigators at several
institutions, it appears that the use of pure methanol fuel may
offer certain significant environmental advantages over the
present use of diesel and gasoline fuels. This conclusion
presumes that methanol would be used in vehicles designed
especially for its use. This conclusion is somewhat tentative due
to the early nature of research on methanol-fueled vehicles and
more experimental work to confirm this early research is needed.
Coal appears to be the most likely large-scale feedstock for
methanol production. Although no methanol from a coal fuel
facility currently exists in the U.S., tne consensus of the
chemical and fuel industries is that the production of methanol
from coal is technically feasible. Although uncertainties still
exist, adequate supplies of coal are available and the technology
is relatively well understood compared to most other synthetic
fuels processes.
Methanol from coal via indirect liquefaction is potentially
more benign environmentally than direct coal liquefaction.
However, no quantitative comparisons are yet available due to the
fact that no completely integrated plants exist in either case in
this country. Based on the available process design studies,
almost all funded by DOE, pure methanol is projected to be less
expensive than direct coal liquids and Mobil M gasoline. Of
course, these comparisons will become'more firm as these synthetic
processes approach commercialization. However, the economic
merits of moving to an alternative transportation fuel, such as
methanol, from fuels derived from crude oil involve many
uncertainties which must still be assessed. Should alternative
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transportation fuels become a viable national option, methanol
could present very interesting possibilities compared to other
alternative fuels. * \
N • '>
II. Scope of the Report
This report surveys existing literature on the production of
methanol and its use in motor vehicles compared to the production
and use of other synthetic fuels from coal. The report does not
address synthetic fuels from shale and thus, makes no conclusions
in that area. However, as the conversion of coal will appear to
play an important role in providing this country's alternative
transportation fuels in the future regardless of the scenario
chosen, the conclusions of this report should still be pertinent.
The report also focuses on the. use of synthetic fuels in motor
vehicles, where the expertise of the Office of Mobile Sources
lies, and does not address the use of synthetic fuels in other
areas, such as electric power generation. EPA is currently
conducting its own scientific work on the environmental aspects of
the use of pure methanol in motor vehicles, but significant
results are not ^et available.
The report considers only the use of pure or neat methanol
and does not deal with methanol blended with gasoline for use in
existing automobiles. While methanol/gasoline blends could
provide an important intermediate market for methanol fuel, we see
the primary environmental advantages of methanol being associated
with its use as a straight fuel in rvehicles designed for its use.
The following sections present a summary of the findings of
the report.
III. Environmental Advantages (End-use)
Used in motor vehicles, pure methanol would reduce nitrogen
oxide emissions roughly 50 percent compared to diesel fuel and
gasoline, and produce almost no particulate matter, heavy organics
or sulfur bearing compounds,. The absence of participates and
heavy organics is in sharp contrast particularly with diesel
fuel.
Besides providing the above advantages over existing fuelsj
methanol could provide even greater environmental benefits over
certain future fuels, particularly certain future diesel fuels.
The quality of diesel fuel in the U.S. has been steadily declining
over the last five years due to the processing of heavier and
heavier crude oils each year. In the absence of widespread
utilization of available technology to curb this decline which
involves a significant cost, this trend is expected to continue,
even if petroleum continues to be the main source of diesel fuel,
and will likely accelerate with the advent of synthetic diesel
fuels. This reduction of diesel fuel quality will generally
result in an increase in diesel emissions, particularly that of
particulate matter. Thus, methanol should provide even greater
benefits relative to this lower quality fuel of the future.
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Methanol engines, however, may emit more aldehydes than
gasoline or diesel engines, including formaldehyde, a suspected,
carcinogen. Uncertainties exist as to whether the increases are
significant, since the current level of formaldehyde emission from
gasoline or diesel engines is not now thought to present a
problem. Even if the aldehyde levels from methanol engines would
appear to be a problem, research testing of catalytic converters
show them to be able to remove up to 90 percent of the aldehydes,
-indicating that the problem may be solvable.
One potential secondary benefit of fueling a vehicle with
methanol is the possibility that the catalyst used to clean up .the
exhaust could be of the base metal variety, such as copper,
chromium, or nickel, and not made up of noble metals, such as
platinum and palladium. Unlike gasoline, methanol does not
contain any sulfur or lead, which degrade base metal catalysts
very quickly. This would significantly reduce the cost of the
catalytic converter system. However, more importantly, this
change could improve the country's balance of payments, since all
noble metals must currently be imported. And while some base
metals are also imported-, their value would be significantly less
and still produce a net decrease in imports.
Pure methanol would require the use of vehicles designed
specifically for its use, but these vehicles may be no more
expensive than current vehicles and easily produced with current
technology. All the major automobile manufacturers have indicated
that the mass production of methanol-fueled vehicles would pose no
unsolvable technical challenges,
IV. Raw Materials Availability
Domestic raw materials for methanol production are in
plentiful supply, and include wood, biomass, municipal waste,
peat, natural gas and most importantly, all grades of coal.
This range of possible raw material may offer the long-term
advantage of a geographically diverse methanol fuel industry,
since resources are spread across the country. Coal, though, is
likely to be the first and-major raw material for pure methanol
fuel in the future. Thus, the major advantage of methanol over
those synthetic fuels produced via the direct liquefaction
processes is that its economics appear ..to be less dependent on
coal type, opening up the nation's resources of lignite and even
peat (considered a very young coal) to synfuel production.
V. Production Technology
The chemical industry already produces methanol from natural
gas and residual oil, so this technology is fully commercial.
However, since natural gas and petroleum supplies will not likely
be available for large-scale production of methanol fuel in the
future, the technological feasibility of producing methanol from
more plentiful feedstocks is a more relevant question. Methanol
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production from three domestic feedstocks was examined: coal, wood
and wastes (agricultural and municipal), as well as methanol from
foreign remote natural gas.
A. Coal Processes
In general, among the newer processes, methanol from coal is
more advanced than the processes using other raw materials.
Methanol is produced from coal via indirect liquefaction, a
two step process consisting of first gasifying coal into carbon
monoxide and hydrogen and then synthesizing this gas into
methanol. The second step of the process, methanol synthesis, is
the same regardless of the feedstock used to produce the synthesis
gas. Thus, this step is commercially proven whether natural gas,
residual oil, coal, wood, etc. is used as raw material to the
methanol process. The first step, coal gasification, is also
commercially proven, as first-generation gasifiers have been in
operation for thirty years. However, more efficient
second-generation gasifiers have been under development for over
twenty years and a number of these gasifiers now appear to be
ready for commercialization. Three such gasifiers are the Texaco,
BGC-Lurgi and Shell-Koppers gasifiers. Thus, the production of
methanol from coal appears to be achievable today and only waiting
for the proper economic conditions.
The other indirect liquefaction processes also are commercial
or near commercial. The Pischer-Tropsch process is definitely
commercially proven, as full-scale plants are currently operating
in South Africa using first-generation coal gasifiers. The other
indirect process, the Mobil M-Gas process, converts methanol into
gasoline. Op to the methanol conversion step, the technical
feasibility of this process is the same. as that for a methanol
from coal facility, which was already described above. The final,
methanol to gasoline step is not as commercially ready, however,
having been only demonstrated in small pilot , .plant units.
However, there appears to be firm interest overseas to scale up
this technology directly to a commercial-sized-plant. Thus, it
may be at approximately the same state of commercial readiness as
the other two indirect liquefaction processes^- -
Direct Liquefaction processes, on the other hand, are a
number of years away from commercialization. Large pilot plant
work is currently underway and progress is being made. However,
significant technical problems still remain to be overcome. In
addition, many of the key processing steps have not yet been
integrated, but have only been tested individually. Thus, most
plans call for a large-scale demonstration plant to be built to
develop confidence in the entire process before any commercial
plants would be planned. Overall, the direct liquefaction
processes are not in the same state of commercial readiness as the'
indirect liquefaction processes.
With respect to overall conversion efficiencies, methanol
synthesis is the most efficient of the indirect liquefaction
processes. The production of methanol from bituminous coal is
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about 49-57 percent efficient, while the Fischer-Tropsch and Mobil
M-Gas processes are roughly 5 percent less efficient. The direct
liquefaction processes are projected to be more efficient, around
56-64 percent. However, given that the direct liquefaction
processes are further from commercialization, .there is a greater
likelihood that these figures will decrease in the future relative
to those for the indirect liquefaction processes.
B. Wood Processes
Like methanol from coal, the production of methanol from wood
depends on the feasibility of the gasification step. Wood
gasification is not as far advanced as coal gasification..
However, in many ways the gasification of wood is inherently
easier than the gasification of coal. Thus, while wood
gasification is not commercially proven, its commercialization is
primarily awaiting commercial stimulization and not the overcoming
of large technical obstacles.
Direct liquefaction techniques based on wood, on the other
hand, are far from commercialization. Thus, if wood is to be used
in the near future to provide the nation with liquid fuel, it will
have to be based on indirect liquefaction (i.e., methanol, Mobil
M-Gas," or Fischer-iropsch). However, the cost of producing
methanol or other indirect liquids from wood, appears to be
significantly higher than that from coal. Thus, in the near term,
the actual use of wood for synthetic fuel production will have to
await a large relative increase in the price of coal or special
incentives to make wood-based synthetic fuels more economical.
C. Agricultural and Municipal Waste Processes
The gasification of agricultural and municipal wastes is at
about the same technological point as the gasification of wood.
In other words, the production of methanol and other indirect
liquids from these raw materials is feasible. However, the
economics of synthetic production based on these raw materials
would appear to be even less desireable than that based on wood.
Thus, there is currently little commercial activity in this area
and little likely in the near future.
D. Environmental Effects (Production)
While the report did not analyse the environmental impacts of
synthetic fuel production in great detail and there is a general
lack of firm information in this area, the report was able to make
a few general findings. The production of synthetic fuels from
coal will require the control of many pollutant streams regardless
of the processes employed. However, there appears to be a number
of aspects of indirect liquefaction processes relative to direct
liquefaction processes which could make the control of certain
pollutants easier and more likely to happen.
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One, sulfur must be almost entirely removed to protect either
the methanol or Fischer-Tropsch catalysts. otherwise, the
catalysts degrade uneconomically fast. Direct liquefaction
processes leave most of the- sulfur in the liquid hydrocarbon
product. This sulfur can be removed by hydrotreating, which would
upgrade the liquid product at the same time. However, the degree
to which direct liquid is upgraded will depend on economics and it
is entirely possible that the economics will call for a relatively
poor quality product. In this case, the level of hydrotreating
will be relatively low and much of the sulfur will remain in the
product. The same conclusion generally holds for nitrogen
impurities.
TWO, the hazard of exposure to the fuel itself should be less
with indirect liquids as compared to direct liquids. The products
of most direct liquefaction processes are mutagenic prior to
severe upgrading via hydrotreatment. The products of indirect
liquefaction processes are not. And while substantial exposure to
methanol is widely known to cause blindness and possibly death,
methods for its safe handling have been practiced for years in the
chemical industry.
Three, a methanol spill would be much easier to deal with
than a spill of any hydrocarbon fuel. Methanol dissolves in water
and would quickly disperse in the case of a spill on land or in
water. While the methanol would cause severe damage in the
immediate locale of the spill, it is quickly broken down to
non-toxic compounds in the environment and plant and wildlife
would return relatively quickly. Spills of hydrocarbon fuels, as
is well known, do not dissipate quickly and their effects remain
for some time.
V. Economics
All design studies available when this survey was performed
which estimated the cost of producing synthetic, fuels from coal
were examined and placed on a comparable economic basis. Using
these estimates, it appears that the production of methanol from
coal would be less expensive than the production of gasoline via
'the" Fischer-Tropsch, Mobil- M-Gas, or direct liquefaction
processes. While the distribution of methanol would cost more
than the distribution of gasoline, this additional cost does not
appear to outweigh the production savings.
In addition, the use of methanol in vehicles should almost
certainly allow the fuel efficiency of the engine to increase
relative to that of a gasoline engine, producing even greater
savings.
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Preliminary Perspective on
Pure Methanol Fuel For Transportation
\
This report surveys and analyzes available literature
prepared by other government agencies and industry on pure
methanol fuel. (It does not deal with methanol blends in gasoline
which may have substantial environmental problems if the
concentrations are too great.) EPA has begun very early
scientific research of its own on pure methanol, and the results
of this research were not available at publication time.
This report is intended to provide background material on the
possibilities of methanol as a transport fuel, and includes
limited discussions on the production technology, economics as
well as environmental effects of using methanol. It provides a
theoretical discussion of environmental effects during production,
but actual pollution discharge rates from methanol plants are not
yet available. This report therefore, provides only limited
comparisons of methanol against certain synthetic fuels, and does
not attempt to devise a total synthetic fuel or national energy
policy.
The report only examines pure methanol fuel as one possible
solution to the energy problem in the transportation sector. The
report concludes that pure methanol may potentially offer some
environmental advantages during end-use in motor vehicles, and
under certain conditions, may be economically competitive with
direct coal liquids, although many cost uncertainties are still
unresolved. The economic merits of moving to an alternative
transportation fuel, such as methanol, from crude-derived fuels
involve many uncertainties which must still be assessed.
Nonetheless, EPA encourages the experimental use of pure methanol
in motor vehicles especially designed for this purpose.
The mobile • source office of EPA first developed an interest
in methanol as an alternative transportation fuel over ten years
ago because of its potential for achieving low nptor vehicle
emissions. More recently, our interest has increased due to a
particularly difficult problem concerning the reduction of
emissions (in particular nitrogen oxides and particulate
emissions) from heavy-duty diesel engines.
The Clean Air Act as amended in 1977 (hereafter referred to
as the Act) requires that the emissions of nitrogen oxides (NOx)
from new heavy-duty engines be reduced by 75 percent beginning in
1985. EPA has been working closely with the manufacturers of
heavy-duty engines over the last two years.to assess their ability
to. meet this goal. While it appears that the full 75 percent
reduction can be achieved by heavy-duty gasoline engines with
technology similar to that used on today's automobiles, the task
is much more difficult for heavy-duty diesel engines. The only-
technology known today which could even conceivably achieve the
required degree of control without a significant fuel economy
penalty is an exotic ammonia/reduction-catalyst system. However,
this system would be extremely expensive and possibly a safety
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hazard and has therefore been rejected from further
consideration. other more reasonable, but still advanced,
technology, such as digital electronic engine controls, intake air
cooling and exhaust gas recirculation, appear to have the
potential to achieve at most slightly over half of the required
reduction. However, these techniques would still cost roughly
$700 per engine and could increase fuel consumption up to 10
percent at this level of emission reduction, Thus, even the
achievement of only half of the goal set forth by Congress would
be fairly expensive because the technology is simply not available
today or in the foreseeable future to inexpensively reduce NOx
emissions from a diesel engine.
Aggravating this problem are the high levels of particulate
matter being emitted from these heavy-duty diesel engines. These
particles are very small and easily respirable into the deepest
regions of the lung. Heavy polycyclic organic materials which
have been shown to be mutagenic are also present on these
particles. This has led to a concern that diesel particles may
cause cancer, which EPA is currently investigating. Vfoile the
Agency has not yet completed its study in this area, it is evident
that emissions of this particulate matter merit some degree of
control regardless of their carcinogenic potential, due to their
small size and prevalence at ground level in urban areas.
The most promising approach to controlling these particles is
the trap-oxidizer, which is a device which first traps the
particles and then burns them off periodically or continuously.
However, this device is expected to cost as much as $500-600 per
heavy-duty engine. Coupled with the cost of controlling NOx
emissions, the cost of a vehicle equipped with a heavy-duty diesel
engine could increase 1-7 percent due to the control of these two
pollutants.
Another concern which may present a problem with the use of
trap-oxidizers is that certain catalyzed trap-oxidizers may
increase sulfate emissions (sulfuric acid).[1,23 The potential
exists for higher sulfuric acid emissions from diesel engines with
catalyzed trap-oxidizers as compared to catalyst-equipped gasoline
engines due to the higher level of sulfur in diesel fuel as
compared to gasoline (7.7 g/gal vs. 0.5 g/gal).[3,4]
These are actually not only problems for heavy-duty diesel
engines, but for light-duty diesels (cars and light trucks) as
well. EPA has had to grant waivers of the congressionally-set 1.0
g/mi NOx standard through 1984 for most diesel passenger cars
because this standard was too difficult and costly for them to
achieve in the time available, without significantly increasing
particulate emissions. And light-duty diesels emit the same
small, organic-laden particles as the heavy-duty diesel engines.
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Diesel engines are also expected to significantly increase
their share of the heavy-duty engine market (from 35 percent now
to 54 percent by 1990), and the light-duty market as well.[5,6]
It is also expected that the current indirect-injection diesel
engines used in today's light-duty vehicles will be gradually
replaced with direct-injection engines (as is currently the case
for heavy-duty diesels). The direct-injection engines will
displace the indirect-injection engines primarily because they are
more efficient (10-15 percent better fuel economy). The two
primary reasons that indirect-injection engines are dominant today
in the light-duty vehicle market are that they have lower
emissions and are quieter. Thus, as light-duty diesel engines
convert to direct-injection, higher emissions and more difficult
control will be inherent.
Compounding these problems is the general expectation that
diesel fuel quality will progressively decline, in the next few
years as the demand for diesel fuel increases relative to
gasoline, diesel fuel composition will likely change and, in
particular, the fuel is expected to be a "broader cut" fuel that
is, the fuel would have an increased amount of lighter
hydrocarbons (from previous gasoline feedstocks) and heavier
hydrocarbons (from previous fuel oil feedstocks). Also, as the
better quality crude oil reserves are depleted, the sour, heavier
crudes may yield poorer quality diesel fuel. And finally, as
synthetic crudes (from oil shale and coal) enter the fuel system,
even more significant diesel fuel quality compromises could
occur. While diesel engines are expected to be able to burn these
liquids, the combustion quality will probably deteriorate and
emissions may increase. Technology is available to counteract
these trends, but the cost involved makes its application unlikely.
It was from this perspective that the Agency began inquiring
into the use of an alternative fuel for diesels that could solve
the emission problem at a potentially lower cost than the use of
engine modifications and add-on devices. While most EPA emission
standards have focused on the engine and required control there,
there are generally two ways to approach any emissions problem:
modify the engine or modify the fuel. In most of the situations
of the past, the easiest solution was to modify the engine (the
one major exception being the Agency's requirement that unleaded
gasoline be available for 1975 and later model light-duty
catalyst-equipped vehicles). However, in the case of the current
diesel engine emission problems, engine modification may not
necessarily be the least expensive way of achieving the goals of
Congress.
Vvhile a number of alternative natural and synthetic
petroleum-derived fuels were considered, none appeared to have the
potential to control these emissions any more cheaply than the
engine-related techniques already discussed. However, one_
nonpetroleum fuel, methanol, appeared to show promise for a number
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of reasons. One, methanol is well known as a high-performance
fuel, and a methanol-fueled engine should have a good chance of
achieving the fuel efficiency of a diesel engine. TWO, methanol
burns much cooler than diesel fuel because it already contains
some oxygen and this would likely have a direct, positive effect
on NOx emissions. Three, methanol is a lighter (lower boiling
point) fuel than diesel fuel and, based on our experience with
petroleum-based fuels which are lighter than diesel fuel, should
both produce less particulate matter and less heavy polycyclic
organic material than a diesel engine operating on diesel fuel.
Four, it is well known that methanol is producible from a wide
variety of raw materials, including the nation's vast resources of
coal. This is not to say that methanol was seen as a quick and
easy solution to the emissions problem of the diesel. However,
methanol as an alternative fuel did meet more of the basic
requirements than any other fuel and appeared to merit further
consideration.
in approaching this alternative with the diesel manufacturers
themselves none doubted the low-emission potential of methanol.
And while some wondered whether a methanol engine would still be a
"diesel" engine as they knew it, none doubted that a methanol
engine could be built and have good thermal efficiency. (Whether
or not the efficiency would actually equal that of a turbocharged
direct-injection diesel was open to debate.) Many manufacturers
had in fact already considered methanol to at least some extent,
but had rejected it. Their rejection was often partially based on
the fact that methanol is not a good fuel for today's diesel
engine. (It has a low cetane number, which means that it does not
readily ignite under high compression as diesel fuel does.)
However, most had rejected methanol in a more, absolute fashion
based on a conviction that it would cost up to twice as much as
synthetic diesel fuel from coal or oil shale. Thus, while
methanol appeared to have significant potential as a low-emission
fuel and the diesel manufacturers were willing to talk about what
a methanol engine would mean technologically, fuel cost seemed to
be an inescapable problem.
However, while the studies cited by the diesel manufacturers
did conclude that methanol from coal would be far more expensive
than synthetic hydrocarbon fuels, the Agency was also aware of
studies which concluded that methanol would be no more costly to
produce than synthetic hydrocarbon fuels, and possibly even
cheaper. A search of the available literature revealed no study
that reconciled these conflicting results. This analysis by EPA's
Office of Mobile Source Air pollution Control (OMSAPC) attempts to
make such a reconciliation, and to determine if conditions exist
under which methanol may be economically competitive with, or less
costly' than, gasoline or diesel type fuels, both natural and
synthetic. This analysis does not attempt, however, to predict
whether these conditions will or will not occur. This assessment
was necessary to allow a preliminary determination as to whether
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or not pure methanol could be a practical alternative fuel for
diesel engines.
This study is not a comparison of methanol to all other
potential motor vehicle fuels. It is not even a comparison of
methanol to all other synthetic fuels. At this preliminary stage,
the analysis is limited to a comparison of methanol to other
synthetic transportation fuels from coal. Both direct and
indirect coal liquefaction processes are examined, specifically
the Mobil Methanol-to-Gasoline (MTG), Exxon Donor Solvent (EDS),
H-Coal, and Solvent Refined Coal II (SEC-II) processes. The
Fischer-Tropsch (F-T) process was not fully considered because
only a fraction of this process1 products are transportation
fuels[7] and because the available references show it to be
economically inferior to the other synthetic petroleum processes
mentioned above, particularly the Mobil MTG process.[8,9,10] We
are aware of some who say that Fischer-Tropsch can be competitive
with the other processes with catalyst improvements and with a
market for the methane produced.[11] We plan to investigate this
possibility further in the future. However, at this time the
comparison of methancl against the Mobil MTG process should be
adequate to deircnstrate whether or not methanol is competitive
with other indirect liquefaction processes which produce fuels
compatible with today's engines and distribution system.
This study also excludes any comparison of methanol with
fuels derived from shale oil. The production technologies are
quite different and the comparison needs to be postponed to a
later date when more information is available.
This report is only an examination of the advantages and
disadvantages of pure methanol as a transportation fuel in
comparison to other synthetic fuels from coal. It does not
attempt an in-depth comparison between methanol and non-coal
synfuels, or other energy policy options. In summary, therefore,
this report does not attempt to evaluate methanol against all
other alternate fuels strategies.
Methanol from coal will be discussed as a possible fuel for
both gasoline and diesel engines. If methanol were to become
generally available and methanol engines were used in current
diesel engine applications, it is extremely likely that methanol
engines would also capture a portion of the existing gasoline
engine market. Therefore, from the point of view of economics,
methanol is in competition with some combination of gasoline and
diesel fuel and not only one or the other.
The purpose of this paper, then, will be to generally examine
the technological and economic feasibility of methanol as an
automotive fuel, and particularly examine its potential to solve
the diesel emission problems described above. This will be done
in five steps. First, the availability of raw materials ana its
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potential impact on the economic feasibility of methanol and other
synthetic fuels will be discussed. Second, the technology needed
to produce these fuels will be discussed. Third, the effect and
cost of adding methanol to the automotive fuel distribution system
will be examined and compared to the effects of adding other
synthetic fuels to the distribution system. Fourth, the use of
methanol in motor vehicles and its effect on emissions and fuel
efficiency will be assessed. And last, the overall economics of
the production and use of these various synthetic fuels will be
presented from a preliminary viewpoint.
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I. Raw Material Availability
As previously mentioned, the primary purpose of this paper is
to compare two coal strategies? one which converts coal into
methanol and one which converts coal into conventional hydrocarbon
fuels. As such, this section will primarily deal with the
availability of coal, particularly any differences which may exist
relative to the two strategies. In addition, it will also discuss
other sources of methanol, both short-term and long-term. This
will be done from the point of view that, if methanol were to
become generally available from coal, it may open up markets for
methanol from other raw materials that do not currently have a
market. Since gasoline can be produced from methanol via the
Mobil MTG process, this discussion would apply equally to gasoline
via this process. This secondary discussion will not be performed
specifically for the hydrocarbon fuels since their markets are
well established and any economical process for producing these
fuels can easily fit into the existing refinery/distribution
network.
Estimates of the recoverable reserves of coal in the U.S. are
shown in Table 1 by coal type. As can be seen, almost two-thirds
of all recoverable U.S. coal is bituminous, while one-third is
sub-bituminous (based on energy content). Anthracite and lignite
together represent about 6 percent of the total U.S. recoverable
reserves.
These coal reserves are spread across much of the continental
U.S. (see Table 2). Roughly one-quarter (by weight) is located in
the Appalachian region. This coal is primarily bituminous, but
this region also contains the anthracite reserves shown in Table
1. coal in this region is primarily underground, with only
one-quarter being surface-minable.
The central midwest (.primarily Illinois) also contains about
one-fourth of recoverable U.S. coal. This coal is primarily
bituminous, with one-third- being surface-minable and the rest
underground-fliinable.
The northwest (Montana, North Dakota, Northeast Wyoming)
contains a full one-third of the recoverable U.S. reserves. While
this region contains most' of the nation's lignite, its coal is
primarily subbituminous. Half of this coal is surface-minable.
Finally, the central and southwest contain the remaining U.S.
reserves; about one-sixth of the total. This coal is a mixture of
subbituminous and bituminous, with the former being more
predominant than the latter. Roughly one-third of this coal is
surface-minable.
The total recoverable U.S. coal reserves shown in Table 1
amount to 5,306 quads (quadrillion Btu) of available energy.
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-8-
Coal Type
Anthracite
Bituminous
Subbituminous
Lignite
Table 1
Estimated Recoverable Reserves
Billions of Tons
3.7
114.3
84.2
16.5
218.7
Energy (Quads)
107
3200
1768
231
5306
Source: "The Direct Use of Coal," Office of Technology
Assessment, 79-600071, p. 63.[12]
-------
. -9-
Table 2
Locations of Recoverable U.S. Coal Reserves
Fraction of Fraction of 1976
Region U.S. Reserves U.S. Production Coal Type
Appalachian One-fourth 0.60 Primarily bituminous,
all of U.S. anthra-
cite
Central Mid- One-fourth 0.22 Bituminous
west
Northwest One-third 0.08 Primarily subbitu-
minous, majority of
U.S. lignite
Southwest One-sixth 0.10 Subbituminous and
and Central bituminous, some lig-
West nite
Source: "The Direct use of Coal," Office of Technology
Assessment, 79-600071, pp. 61-63.[12]
-------
Using a nominal liquid fuel conversion factor of 60 percent, this
coal represents 2,653 quads of liquid fuel, which is equivalent to
450 billion barrels of fuel oil (at 5.9 million Btu per barrel).
Since the nation consumes approximately 16 million barrels per day
of liquid fuel (and about the same, amount of nonliquid fuel),
there is easily enough coal to provide the country's
transportation fuel needs (either through methanol or synthetic
crude) well into the future.
However, this is not only true in the sense of having
sufficient overall reserves, but it is also true in the practical
sense of minability. in 1981, 820 million tons of coal were mined
in the U.S.[12] having a total energy content of nearly 19 quads
or 10 million fuel oil equivalent barrels per calendar day (FOEB/
CD). To provide 10 percent of the nation's transportation needs
(which in total is approximtely half of the nation's liquid fuel
needs or 8 million FOEB/CD), 147 million tons of coal would
nominally have to be mined (at a 50 percent conversion
efficiency). This would represent a 18 percent increase in total
U.S. coal production, a modest increase. In addition,
improvements in vehicle fuel economy, and conservation due to
rising prices, will also reduce the amount of coal necessary for
liquid transportation fuels. Converting as much as half of cur
transportation fuels to coal-derived liquid fuels would still
require less than a doubling of our 1981 coal production. Thus,
coal is indeed a viable source for our nation's alternative fuel
program.
In addition to the general availability of coal for
conversion to all liquids fuels, there are a few specific points
which should be made with respect to coal's specific availability
for conversion to methanol (or other fuels produced from methanol
or synthesis gas, i.e., hobil MTG gasoline and F-T liquids). One,
methanol and other indirect coal liquids can be produced from all
types of coal and, as will be seen later in Section V, the cost of
methanol from all coal types is relatively constant. While the
direct liquefaction technology appears to be available for all
types of coal to be converted to liquids, the cost curve would not
be flat. The cost of direct liquefaction liquids appears to be
sensitive to hydrogen consumption and hydrogen consumption
increases with oxygen content.[13] Thus, lower rank coals, such
as subbituminous and lignite, which have higher oxygen contents,
may be less likely to be converted via direct liquefaction than
high grade anthracite and bituminous coal due to economics.[13]
This would generally give the indirect liquefaction processes an
advantage of greater flexibility over the direct liquefaction
processes, though, of course, the final comparison depends on
where the two cost curves cross.
While the cost estimate presented in Section V will shed some
light on this issue, some indication can be obtained from the
projected sites of the various synfuel projects. Using EPA's
April, 1981, compilation .of U.S. synthetic fuel projects,[14] it
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-11-
can be seen that all of the large direct liquefaction projects
were projected to be located in the Appalachian/Western Kentucky
region, which contains high grade coal. On the other hand, the
indirect liquefaction projects are spread across all of the
coal/peat regions of the U.S. This does not mean that direct coal
liquefaction would necessarily be uneconomical in the other
regions. That cannot be deduced solely from this information, it
does confirm, however, the preference of direct liquefaction for
bituminous coal and -the non-preference of indirect liquefaction
processes. (The fact that the compilation is over a year old and
would now be out of date due to changes in the economics of crude
oil should not affect the point being made.)
For example, this flexibility of indirect liquefaction would
make available U.S. lignite fields for transportation fuel
production. There are 7.1-12.5 billion tons of
economically-recoverable lignite resources in the U.S., mostly in
North Dakota.[12,15] At a 47 percent conversion efficiency, which
is feasible today based on "wet" (undried) lignite,[16] this
resource could provide a total of 1.6 trillion gallons of methanol
or 19 billion barrels of gasoline equivalent.
Tentative plans already exist for one commercial-scale
lignite-based synthetic fuel plant. The Nokota Compani intends to
build a 10,900 ton per day methanol-from-1 ignite plant at Dunn
Center, North Dakota.[17] Construction is scheduled to begin in
1985 with a final completion date of 1991. Nokota has extensive
holdings of lignite in North Dakota totalling 3 billion tons. The
planned plant will consume about 368 million tons of this coal-
over 25 years.
Another example of > coal reserves that appear to be
economically convertible to methanol or other indirect
liquefaction products are the large stores of mining residue in
the anthracite coal regions of Pennsylvania. A study performed by
the American Energy Research Corp. for the Department of Energy-
found methanol production from these coal refuse piles to be
feasible and economical with today's technology.[19] From the 100
million tons of coal contained in these refuse piles,
approximately 24 billion gallons of methanol could be produced or
the equivalent of 290 million barrels of gasoline. Besides
bringing badly needed economic benefits to this region, the
removal of the refuse piles would. be of great aesthetic and
economic value to the towns and cities of the region. Most of the
piles are actually within city limits and cover land which would
otherwise be taxable and valuable for development.
While coal would be the primary feedstock for methanol fuel
production, once a methanol fuel market developed, smaller amounts
of methanol could be produced from a number of other sources, in
fact, methanol from these other sources need not necessarily wait
until a methanol fuel market develops. This is evidenced by a
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-12-
publicly-announced offer to build barge plants to process rcethanol
from remote sources of natural gas and to build peat-to-methanol
plants in the near future.[14,20] Methanol from these plants is
aimed primarily at the chemical industry, where the majority of
the methanol produced today is used. However, the promoters of
these plants are also looking at the fuel market[17,20] and as a
methanol fuel market would develop, the potential for producing
methanol from these sources would of course increase.
For example, 7.2 trillion cubic feet of natural gas is flared
each year around the world, because it is not economical to ship
it for sale elsewhere [20,21]. While some natural gas is
compressed and liquified and shipped in special tankers to this
country (about 2 percent of total U.S. natural gas use,[21] it is
actually cheaper to convert the natural gas to methanol and then
ship it as a liquid when transportation distances are greater than
3,000-4,000 miles.[22] Litton and others have already had
engineering plans drawn up to build methanol plants on barges to
service these areas and could have them operating by 1984.[20] It
is not likely that all of this gas will soon be converted to
methanol nor all of that converted shipped solely to the U.S.
However, to put this amount of gas into prospective, the flared
gas mentioned above would provide 88 billion gallons of methanol
per year, or the energy equivalent of 2.8 million barrels of
gasoline per day (about one-third of U.S. transportation fuel
consumption).
Peat, too, may be economically convertible to methanol, and
presumably, other indirect liquefaction products, if desired. The
U.S. has one of the largest peat reserves in the world, 52.6
million acres containing approximately 1,450 quads of
energy.[23,24] The Energy Transition Corp. is tentatively
planning a commercial peat-to-me.thanol venture in North
Carolina.[14] The plant will, use Koppers/Babcock-Wilcox
gasification technology and produce 3,700 barrels (500 tons) per
day of methanol. While proof of the economics of peat-to-methanol
conversion will only come if and when this plant is built, peat's
consideration for this project does at least demonstrate its gross
feasibility.
Also, while no commercial plants are currently planned, wood
may also be a possible long-term • resource for indirect
liquefaction conversion. According to a study done by MITRE
Corporation, the current potential gasification feedstock (made up
from residues, surplus growth, annual mortality and noncommercial
lumber) is 500 million tons of wood per year.[25] With the
introduction of silviculture energy farms a stable and renewable
550 million tons/year of wood could be realized by the year 2000.
Using a conversion efficiency of 55 percent (164 gal. methanol/ton
wood), this wood could be transformed into 82 billion gallons of
methanol/year (2.7 million bbl. gasoline/day) in the short term or
90 billion gallons of methanol/year (2.9 million bbl gasoline/day)
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-13-
\
by the year 2000. The first figure represents about 34 percent of
U.S. current transportation energy requirements while the second
value would be about 36 percent.
For long-term wood availability/ OTA estimates that the
maximum growth potential of U.S. forest is 1.1 billion to 2.3
billion tons of wood per year.[26] The percentage of felled
timber today that is left in the forests or unused is
approximately 40 percent. Therefore, if this percentage of unused
or waste wood remains and the same 55 percent conversion
efficiency is used, there could be up to 870 million tons of wood
or 150 billion gallons of methanol (4.9 million bbl gasoline/day)
.available each year. This represents about 61 percent of the
nation's current transportation energy needs. Thus, in the long
term, methanol from wood looks promising, not only because wood
could provide a stable and renewable energy source, but also
because methanol from wood (or gasoline from the methanol) could
supply close to one half of our current transportation energy-
needs.
Another renewable feedstock for indirect liquefaction besides
wood is agricultural waste. Although much of the current emphasis
has been on the production of ethanol from agricultural wastes, ,
various studies have shown that these wastes can be processed more;
efficiently into methanol. DOE estimates, for example, that the
same amount of residue could produce over twice as much methanol
on a Btu basis as ethanol.[27] This should roughly hold true for
Mobil MTG gasoline, also. DOE further projects that by the year
2000, over 278 million tons of agriculture residues could be
converted to 48 billion gallons of methanol per year.[27] This is
about 20 percent of our current transportation energy needs.
i >•. i «
Methanol production from agricultural wastes 'is not without
its uncertainties, however. These include the high acquisition
cost of many crop residues and the substantial storage
requirements as a result of seasonal production. Also, the
long-range environmental consequences of not returning
agricultural residues to the soil are unknown; in some areas the
lack of these residues may cause erosion problems.[27]'
Plans for one commercial methanol plant based on agricultural
waste and biomass appear to be in progress. BioTex Energy
Corporation has been working with DM International to construct a
60 million gallon per year (2000 bbl/day gasoline) methanol plant
using stover from various grains, hay and Johnson grass.[28]
The final raw material to be discussed, municipal solid waste
(MSW), avoids many of the uncertainties associated with
agricultural wastes, since municipal waste can be gasified into
carbon monoxide and hydrogen, it is a viable feedstock for
methanol. Like agriculture waste, MSW has a limited availability,
but also likewise it can be processed into a substantial amount of
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-14-
methanol. According to the same DOE report mentioned above, 116
million dry tons of MSW could be available by the year 2000.[27]
This could be transformed into 11.6 billion gallons of methanol
per year or about 5 percent of our current transportation energy
needs.[27]
Because of its heterogeneous nature, MSW must go through a
series of preparation steps before it becomes a suitable energy
feedstock. These steps, primarily designed to remove metal, glass
and other impurities, are currently a major constraint to the use
of MSW for energy purposes. However, it should be noted that
these so-called impurities are also valuable products. As the
value of these recoverable byproducts increases in the future,
along with the value of the methanol or other primary product
produced, converting MSW into useful liquid will become more
economical. It should also be noted that the need for smaller
landfills would be an additional economic benefit of MSW
conversion and resource recovery. Some areas, such as New York
City, are simply running out of useable landfill and will soon
require some alternative.[29] And while there are other
alternatives to indirect liquefaction of MSW, such as power
generation or biological conversion to methane, methanol and other
liquid fuels are definitely possibilities.
Overall, it can be seen that methanol and other indirect
liquefaction products can be produced from a wide variety of
natural resources. This has a number of advantages. One, it
gives methanol and Fischer-Tropsch processes a flexibility not
available to direct liquefaction- processes. TWO, much of the
long-term resource is renewable, or at least self-generating, such
as wastes, and would not be subject to depletion. (Methanol from
these sources currently appears to be more expensive than methanol
from coal and it may be a number- of years before methanol is
economical from these sources.[30]) Three, the wide variety of
raw materials available for conversion to methanol or other
indirect coal liquids will spread the economic and Asocial impacts
across the' nation. Even without considering renewable resources,
the viability of using anthracite, high-sulfur bituminous coal,
low sulfur bituminous coal, lignite and peat will spread the
economic benefits of synthetic fuel production to the midwest,
southwest, and north central coal regions, as well as to the
Appalachians and central west, where the'benefits of direct coal
liquefaction and shale oil would be highly concentrated. Thus,
from the aspect of raw materials, methanol and other indirect
liquids processes would appear to have some advantages over direct
liquefaction processes.
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-15-
II. Production Technology
Although methanol may be produced from a wide variety of raw-
materials, there are essentially only two practical methods of
production, both of which involve the production of a synthesis
gas.[31,32] Under the first method, the feedstock (regardless of
type) is gasified via partial combustion with oxygen or air at
high temperature to produce a synthesis gas containing mainly-
carbon monoxide and hydrogen. This synthesis gas is reacted with
steam to shift the ratio of carbon monoxide and hydrogen closer to
the optimum 1:2 ratio. Then the synthesis gas is purified to
remove all the acid gases, such as hydrogen disulfide, and other
impurities, such as carbon dioxide, methane, etc. The resulting
carbon monoxide-hydrogen mixture is then converted to methanol as
it is passed over a catalyst under pressure. The final product is
relatively pure methanol (97 percent) with no impurities other
than a slight amount of water and higher alcohols. The second
process, steam reforming, also produces a carbon monoxide-hydrogen
synthesis gas which is then converted to methanol in the presence
of a catalyst. In this case, the feed stock (usually-natural gas)
is reacted with steam to yield the above-described synthesis gas.
The two basic steps needed to make methanol, then, are
production of the synthesis gas and conversion to methanol. It is
the first step (gasification or reforming) which has to be
optimized for the individual feedstock. since the purified
synthesis gas always contains only carbon monoxide and hydrogen
(and minor impurities), the second, synthesis step for all
methanol processes is the same.
Methanol, unlike either synthetic crudes or MTG gasoline, is
currently being produced in large quantities. However, nearly all
of it is being produced from natural gas or residual oil. No
domestic large-scale plants currently exist which produce methanol
from any of the domestic raw materials mentioned in the previous
section. However, this should not be taken to imply that the
technology to produce methanol from these other feedstocks is not
currently available. Certainly, the synthesis technology is
available since it would not differ from that used today. The
gasification technology also appears to exist and to be ready for
use in commercial scale plants as soon as the decision to build is
made. Various coal gasification technologies will be examined
below, accompanied by a discussion of the other indirect and
direct liquefaction technologies. This discussion will then be
followed by brief discussions of the feasibility of producing
methanol from other raw materials, such as wood and agricultural
and municipal wastes. Finally, a discussion of the relative
environmental effects of these production processes will then
close out this section.
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-16-
A. Coal
The gasification of coal began in the early 1800's when it
was discovered that coal gas could be burned more efficiently than
solid coal and it was cleaner and easier to use. The technology
developed fast and by the late 1850's gas lights for streets in
London were commonplace. Between 1935 and 1960 there were close
to.1/200 municipal "gasworks" serving larger towns and cities in
the U.S. However, the introduction of natural gas pipelines in
the 1930's initiated the decline and essential disappearance of
coal gasification within the U.S. Currently, the only operating
large-scale coal gasification facilities are located outside of
the U.S. and are used mainly for the production of ammonia, with
one large exception. These gasifiers are very similar to. the
gasifiers used in methanol synthesis since they produce
essentially the same medium Btu gas that is required for methanol
production. The exception is the largest synfuel facility
currently in operation, at Sasol, South Africa, where the sasol-i
and Sasol-II plants gasify about 36,000 tons per day of coal into
a medium-Btu gas and from this produce a wide range of products,
including gasoline.
Before discussing the individual gasifier types it is first
important to examine the properties of coals used in the U.S.
There are four properties of coal which are important in the
process selection of gasifiers: 1) Reactivity, 2) Ash Fusion
Temperature, 3) Free Swelling Index (FSI), and 4) Moisture.
Reactivity refers to the coal's ability to catalyze the reaction
between carbon and steam. The ash fusion temperature is that
temperature at which the ash becomes fluid. FSI is a measure of a
coal's tendency to agglomerate or cake when heated; the higher the
FSI, the greater the agglomeration.
Eastern coals have relatively. poor reactivity due to their
low content of alkali metals. These coals (predominantly
bituminous) also typically have low fusion temperatures
(1990-2200°F), moderate to high FSI, low moisture (4-10 percent by
weight as received) and, incidentally, high sulfur (3-5 weight
percent). Western coals (mainly subbituminous) exhibit high
reactivity and fusion temperatures (2300-2400°F), low FSI, high
moisture (28 weight percent) and low sulfur (0.3-0.5 weight
percent). Lignite, which is found predominantly in North Dakota,
has an even higher moisture content (35 weight percent) and a
lower percentage of sulfur (0.2 weight percent).
Coal gasifiers are primarily classifed according to the way-
coal is fed to them. The three main gasifier categories are the
fixed or slow-moving bed, the fluidized bed and the entrained bed
gasifiers. Table 3 highlights the advantages and characteristics
of the various gasification technologies.
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-17-
Name
Bed Type
Commercial
Coal
Flexibility
By-Product
Efficiency
Capacity
(STPD Coal)
Table 3
Comparison of Gasification Systems[33]
Koppers
Lurgi BGC-Lurgi Winkler Totzek
Texaco
Shell-
Koppers
Fixed Fixed
Yes Near
Western Western
Yes
64
500
Yes
72
800
Fluid Entrained Entrained Entrained
Yes Yes Near . Near
Western All All All
No No
57 58
1,000 400
No
68-72
1,000
No
75
1,000
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-18-
Fixed or slow-moving bed gasifiers consist of beds that carry
or move the coal vertically downward through the zone where it is
heated and -decomposed (oxygen is injected at the bottom of the
gasifier and travels upward as it reacts with the coal). one of
the main problems with the updraft fixed-bed gasifier is that the
product gas contains large amounts of byproducts including tars,
phenols, and methane. These extra products are largely the result
of their relatively low operating temperatures. Because of their
low temperatures, fixed-bed reactors work best with (and are
somewhat limited to) the high reactivity western coals which have
high fusion temperatures and low FSls. The non-caking aspect of
western coals is also beneficial to the operation of fixed-bed
gasifiers.
As shown in Table 3, the Lurgi and BGC-Lurgi gasifiers are
examples of low temperature fixed-bed gasifiers. The Lurgi
"dry-ash" fixed bed gasifier is a first generation unit which has
been commercially proven and is used worldwide.[33,34] The
Sasol-I plant in South Africa which has been operating for over 25
years utilizes the Lurgi gasifier (and also the Fischer-Tropsch
synthesis unit) to produce 10,000 barrels per day of fuel. (This
is the only fully operational commercial-size coal-liquefaction
plant in the world. The sasol-II plant is operating at 75 percent
capacity also using Lurgi gasification and is expected to be fully
operationaly soon. [35]) The main disadvantages of the Lurgi
gasifier are that it 1) has problems with the low-reactivity
eastern coals, 2) produces byproducts, 3) has high steam
requirements and 4) has a low capacity per volume of gasifier.
The BGC/Lurgi slagging gasifier is a second generation
reactor which completed a testing program in 1979 in Scotland by
Lurgi and British Gas Corp with support from 13 U.S. companies and
DOE.[36] The slagging gasifier is still being tested by BGC and
the latest papers describe this technology as near
commercial.[33,34] Its improvements over the older Lurgi dry-ash
gasifier are a higher efficiency and a reduction in steam use.
However, it still has problems with low-reactivity eastern coals
and still produces by-products.
The fluidized-bed reactor accomplishes an efficient contact
between gases and solids by blowing gas upward through a bed of
solid coal so rapidly that the suspended -bed churns as if it were
a fluid. Fluidized-bed gasifiers have higher, more uniform
temperatures which tend to reduce the amount of byproducts
produced, but the higher velocity of the gas tends to carry out
ash and char with it that must be removed later. Since the
typical temperature is low with respect to the ash melting
temperature of coals, the fluid-bed gasifier also has problems
with eastern coals. The Winkler fluid-bed gasifier is a first
generation unit which is commercially proven and used around the
world. [33] According to~, DM international over 70 Winkler
gasifiers have been built.V(M6] The two main disadvantages with
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-19-
the Winkler are that it operates at atmospheric pressure (large
volume per throughput) and that it has a tendency to clog when
using eastern coals. A pressurized modification of the Winkler is
now under development which should improve its efficiency.[16]
In an entrained-bed gasifier fine particles of coal are
suspended in a stream of oxygen which moves rapidly into and
through the decomposition zone, since entrained bed gasifiers are
typically operated at temperatures above the melting point of coal
ash, reaction rates are much faster, allowing many of the
undesirable byproducts associated with fixed and fluid-bed systems
to be destroyed. These gasifiers are also called "slagging"
because they remove the ash in a molten, slag form. One of the
big advantages of entrained bed gasifiers is that they can utilize
any type of coal. As shown in Table 3, Koppers-Totzek, Texaco and
Shell-Koppers are all entrained bed gasifiers.
The Koppers-Totzek gasifier is a first generation technology
which, like the Winkler and Lurgi, has had extensive commercial
experience. [33,34], It will handle all types of coal but does
require large raw gas compressors since it operates at atmospheric
pressure.
The Texaco gasifier is a coal-slurry fee, high-capacity
gasifier which handles all types of coals and produces very little
byproduct. Although the Texaco gasifier has not yet been used on
a commercial scale it has been successfully tested in two large
demonstration plants (165 tons of coal per day).[37] Of the
newer, second-generation technologies Texaco appears to be leading
the race to commercialization, as it is currently planned for
utilization in two new commercial plants which are now under
construction: Tennessee Eastman's project to produce acetic
anhydride and other chemicals from methanol made from coal, and
Southern California's cool-Water power generation station near
Barstow, California.[34]
The Shell-Koppers gasifier is very similar to the Texaco
gasifier in that it can also use any coal and produces very little
byproduct. Shell is currently designing two prototype plants to
be built in Europe which are scheduled for commissioning in 1985
or 1986.[38]
Until recently, industry has been slow to reimplement coal
gasifiers in the U.S. However, the increasing cost of natural gas
has sparked a new interest in coal gasification and the majority
of the coal or shale-based synthetic fuel projects currently being
planned use coal gasification.[14]
One example is the previously-mentioned Cool Water
combined-cycle power-generation demonstration plant, to^be located
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-20-
in Barstow, California. It will gasify 1000 tons per day of coal
to produce 100 MW of electricity, The facility, which uses the
"proven" Texaco Coal Gasification Process, was to begin
construction in July 1981 and be ready for start-up before the end
of 1983,[39] but has been delayed due to a lack of necessary
financing.[40] The project still appears to be a viable one,
however, as new sources of capital are appearing and the key step
appears to be obtaining $75 million from the synthetic Fuels
Corporation.[40]
According to a recent study by GAD (July 1980), methanol from
coal technology has also been available for years.[21] Prior to
the availability of relatively inexpensive natural gas as a
methanol feedstock, France produced methanol from coal in the late
1940's, and in the mid-1950's, the Dupont Chemical Company
operated a methanol from coal plant in the united States. A
methanol from coal conversion plant, located in a suburb of
Johannesburg, South Africa, has been in operation since 1974. As
a smaller part of a larger coal to ammonia chemical plant, this
process utilizes Koppers-Totzek gasification technology and the
ICI synthesis process, and puts out about 90 metric tons of
methanol per day.
It should be noted, however, that previous foreign coal
methanol facilities produced methanol for chemicals, not fuel
purposes. New methanol fuel plants would be much larger than any
previous chemical plants, perhaps up to 100 times greater in
scale. Therefore, previous operating experience with methanol
chemical plants may not be totally applicable to new methanol fuel
facilities.
Concerning methanol synthesis in the U.S., industry officials
have told GAO that a commercial-sized methanol-from-ccal plant
could, with existing technology, will be in operation within 5
years.[21] Presently, W. R. Grace is in the final stages of a
feasibility study for a 500-700 ton per day methanol-from-coal
plant that would be on line by 1985-86.[14] They had originally-
planned to build a 5,000 ton per day methanol plant, but could not
ascertain that there would be enough demand for the methanol. In
addition, DM International has completed designs for a large-size
lignite-to-methanol plant and are prepared to provide commercial
guarantees of the plant's technical and process workings.[22]
Table 4 shows a list of 9 methanol projects in which the
production of methanol is tentatively planned to be on stream by
1987 or sooner. The planned facilities are well distributed
across the country, representing over 8 different states, while
utilizing a wide range of coal types, from eastern bituminous to
lignite and peat. The first two plants are already under
construction, although the Great Plains project is more oriented
toward substitute natural gas (SNG) and the Tennessee project only
produces methanol as an intermediate product. While there is much
doubt that many of the planned projects will ever be able to
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-21-
Table 4
Coal to Methanol Projects
Plant Size (Barrels Construction On Stream
Project Name Methanol/day) pate Date
1. Great Plains Coal 125 July 1981 1984
Gasification Project
Mercer County, ND
2. Coal-to-Methanol-to- 4,200 1980 1983
Acetic Anhydride
Tennessee Eastman
Kingsport, IN
3. *Beluga Methanol 54,000 N/A*** N/A
Project, Granite
Point, AK
4. Grants Project 3,608 N/A N/A
**(ETCO), Grants, MM
5. Mapco Synfuels 35,000 N/A N/A
Carmi, IL
6. Peat-to-Methanol 3,714 N/A N/A
**(ETCO), Creswell, NC
7. Keystone Project 100,000 N/A N/A
Cambria and Somer-
set Counties, PA
8. Dunn Nokota[18]**** 40,000 1985 , - 1989
Lignite-to-^Methanol
Dunn County, ND 40,000 1988 1991
9. Chokecherry 3,608 N/A N/A
**(ETCO), Moffat
County, CO
Source: EPA, April 1981.[14]
* Feedstock is 60 percent natural gas, 40 percent coal.
** Energy Transition Corporation (ETCO).
*** Firm dates not available.
**** Two-stage construction with a final capacity of 80,000 BPD.
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-22-
\
obtain the necessary financial backing without government
guarantees, there appears to be less doubt of these projects'
technical feasibility. Thus, with the confirmation of a currently
operating coal-to-methanol plant in south Africa and the number of
coal-to-methanol facilities under construction or planned, there
appears to be little doubt that coal-to-methanol technology is
ready for implementation in the U.S.
The observations made above concerning the production of
methanol also apply to the Mobil MTG process since it produces
gasoline from methanol.[33] After its production by indirect
liquefaction, methanol is catalytically converted into a mixture
of gasoline (roughly 85 percent) and liquified petroleum gas (LPG)
(15 percent) in either a fixed-bed or fluidized-bed reactor.
The MTG process has been demonstrated in both reactor types
by 4 barrel per d«i pilot plants.[41,42] The fluidized-bed
approach offers advantages of superior heat transfer and somewhat
higher gasoline selectivity than the fixed-bed process, but
requires more extensive . scale-up and engineering development
efforts based on accomplishments to date.[41,43] A four-year plan
to construct and operate a 100 barrel per day fluidized-bed unit
has been proposed to demonstrate scale-up and to provide;
additional data for commercial design.[41]
Currently, the fixed-bed design is receiving primary
commercial attention as the New Zealand government has tentatively
selected this process to provide about one-third of that country's
gasoline needs.[42] This MTG plant would be a 13,000 barrel per
day facility and use off-shore natural gas to produce the
methanol.[42] This would be the first commercial application of
the Mobil MTG process.
Now that the technolgical feasibility of the indirect
liquefaction processes have been examined, the next step will be
to examine the direct liquefaction process. Three
direct-liquefaction processes will be examined here, the Exxon
Donor Solvent (EDS) process, the H-Coal process, and the
Solvent-Refined Coal-II (SRC-II) process. These are the processes '
that have been receiving the most attention and the most
government support.
The H-Coal process is a development of Hydrocarbon Research,
Inc. (HRI). The central sections of the process have been
thoroughly tested on bench scale and process development units
(PDO). This work was initiated over 16 years ago and has
continued until now through funding arrangements with government
and industry. As a result, more than 65,000 hours of data at the
bench scale level and more than 14,000 hours of data for 3 ton per
day PDU are available.[44]
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-23-
A large-scale pilot .plant has been constructed at
Catlettsburg, Kentucky, that is designed to process 200 to 600
tons per day of coal to produce from 600 to 1,800 barrels per day
of liquid product.[44,45] Ashland Oil is responsible for the
operation of the plant, which uses commercial siie equipment.
Starting in February, 1980, the pilot plant was "broken in" by
various petroleum liquid feeds, starting with light gas and
working toward residual fuel oil to eliminate any deficiencies in
the operating equipment and to provide operator training.
Starting on May 29, 1980, the plant was operated intermittently in
the syncrude mode on Kentucky #11 coal, at a feed of about 220
tons per day. Only intermittent operation was achieved due to
mechanical problems.[44,45]
In February, 1981, the pilot plant was switched to Illinois
#6 coal. Uninterupted operation of 45 days was achieved.[44] Hie
overall amount of coal processed during this period was 8,500 tons
or 85 percent of the 220 tons per day design rate characteristic
of syncrude mode operation on Illinois 16 coal. Illinois 16 coal
was reintroduced on April 26 for more investigation.[44]
Many maintenance problems were encountered during these
initial starting periods. High temperature, erosive wear,
breakage of components, and other mechanical difficulties have
plagued much of the operations. Most of these problems hve been
corrected, however.[44]
Plans for a commercial plant began in April, 1980, by a
cooperative agreement with Ashland, Airco and the Department of
Energy.[44] This plant is to be located in Breckinridge County,
Kentucky, and will be designed to convert about 23,000 tons per
day of Illinois #6 coal into 50,000 barrels per day of liquid
hydrocarbon products and about 30 thousand standard cubic feet per
day of SNG. The commerical plant is approximately 100 times the
size of the pilot plant. However, - the H-Coal commerical plant
would have several reactors in parallel, depending on the economy
of scale desired by the operator and'the availability of capital.
In terms of the individual reactor train, the commercial-scale
reactor would have about ten times the throughput of the
Catlettsburg pilot plant with a diameter scale up of about a
factor of three.
Construction of the commercial plant is projected to begin in
1983.[46] By 1988, construction should be completed followed by
efforts for plant startup, in 1991, the plant is projected to be
operating at full capacity. All of this, of course, depends on
successful operation of the pilot plant now in operation and the
availability of financing, including government support.
The EDS process was developed by Exxon as a private venture
from 1966 until 1976.[47] During this time, Exxon developed and
demonstrated the primary liquefaction process in laboratory scale
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-24-
reactors up to 1 ton per day of coal, in July 1977, ERDA (now
DOE) agreed to fund 50 percent of a project to design and
construct a $268 million 250 ton per day pilot plant.
Construction of this pilot plant in Baytown, Texas, was completed
in March, 1980, and is being followed by a thirty month
operational program.
Engineering design and technology studies, bench scale
research and small pilot unit operation are being integrated to
support operation of the 250 ton per day coal liquefaction pilot
plant.[47] Work is also in progress to evaluate the use of a
bottoms partial oxidation unit for the generation of hydrogen or
fuel gas.
Sixteen process goals were established for the first four
months of operation of which eleven were reached. Ihe goals
reached included operation on 8 mesh coal, demonstration of the
ability to dry coal to 4 percent moisture, achievement of a 50
percent on-stream factor, and several fractionation section
objectives. The original goals not reached include steady
operations at conditions near the design coal feed rate and a
1.2:1 solvent-to-coal ratio, operation of the reactor solids
withdrawal system, and operation of the slurry drier.[47]
During the first four months of operation the problems
experienced by the plant were primarily mechanical rather than
process oriented. The mechanical problems included erosion of the
vacuum tower transfer line, breakdown of the solids handling
systems and plugging of the slurry heat exchangers. The key to
sucessful operations was avoiding solidification of heavy
materials and solids plugging. The service factor was strongly
dependent upon the time required to unplug the equipment after a
coal outage due to solidification-based plugging.[47]
A preliminary observation indicated a lower plant efficiency
than expected. This observation has not been resolved. However,
it should be mentioned that the efficiency of the EDS that will be
stated below was that expected prior to the operation of the pilot
plant and used in Exxon's latest commercial plant design.[48] If
the lower efficiency seen at this time in the pilot plant is not
improved in future operations, then the projected efficiency of a
commercial EDS plant would also have to be lowered.
According to Exxon's commercialization estimates, after
operation of the 250 ton per day pilot plant in the 1980-1982 time
frame, a design basis for an EDS demonstration plant could be
available in 1982.[49] With a three year design and construction
period, construction of the demonstration plant could begin in
1985 and be completed in 1988 or 1989.[49] The 13,000 ton per day
demonstration plant would be equivalent to one train of a 25,000
ton per day commercial plant. Each train would include two
identical liquefaction lines. Therefore the commercial plant
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-25-
would have four liquefaction lines processing 6,250 tons of coal
per day per line. The scale-up factor from the 250 tons per day
pilot plant to the demonstration plant would be twenty-five.
Design of a commercial plant could begin after the demonstration
plant was in operation for one year. [49] This would mean
beginning the design in 1989 and construction in 1992. Therefore
Exxon projects that 1997 would be the earliest possible start-up
date for a commercial plant.[491
The Pittsburg and Midway Coal Mining Co. (P & M), a wholly
owned subsidiary of Gulf Oil Corp., has been working on .the
development of the SEC-II technology for 18 years, primarily under
the sponsorship of DOE. During the last four years, a 30 ton per
day pilot plant has been in operation at Fort Lewis, Washington.
Following the pilot plant operation, a 6000 ton per day
demonstration plant was to be built and operated near Morgantown,
West Virginia using high-sulfur West Virginia and other bituminous
coals.[50]
Initial work on the demonstration plant contract involved
developing a preliminary design for the 6000 tons per day
demonstration plant, a conceptual design for a 30,000 tons per day
commercial plant based on an expansion of the demonstration plant,
and a conceptual design for a 30,000 tons per day grass-roots
commercial plant. All of this work was completed in what was
known as Phrase Zero of the demonstration plant project in July,
1979. Phase One of the demonstration plant project, which is in
progress, was started in July 1979.[50]
In the Phase One design, the SEC-II process has been based on
the results from: 1) bench-scale laboratory units at the Merrian
Laboratory, 2) a 1 ton per day process development unit at the
Harmarville Research Laboratory and, 3) the 30 ton per day pilot
plant at Fort Lewis, Washington. The Phase One design is also
based on a specific West Virginia coal rather- than the
hypothetical coal used for the Phase Zero design.
Some key features of the demonstration plant that were to be
tested are: dissolving; efficient cooling and separation at
higher temperatures; handling and pumping of hot vacuum bottoms to
high pressure? mixing and pumping of hot slurries at the incipient
gel stage; and operation of the slurry preheater at flow rate and
heat flex comparable to the demonstration plant design.
Projections of the main product slate of the demonstration
plant include pipeline gas (SNG), liquid propane, naptha, and fuel
oil. Excess synthesis gas (above that required for reactant
hydrogen) would be used as plant fuel. The pipeline gas, propane,
by-product sulfur and ammonia will be produced to industry
specifications and marketed accordingly.
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-26-
The united States, west Germany, and Japan were responsible
for financing this demonstration plant. Pittsburg and Midway Coal
Mining was responsible for development of the plant under DOE
supervision. Latest estimates show that the design (Phase I) of
this plant, which began in October, 1979, was to be completed in
July, 1984.[51] Phase II, or construction of the plant, was the
start in June, 1981, and to be completed in September, 1985.
Phase III, or the operation of the plant, was to begin in July,
1986 and end in June, 1988. However, .recently the U.S., West
Germany, and Japan agreed at a meeting in Bonn to terminate all
phases of the SRC-II process as soon as possible.[52] This
decision was made primarily because of the cost involved and
because of the U.S. position that synthetic fuel development is
primarily the responsibility of the private sector. The future of
this process is therefore unknown, since it now appears to rest
with the private sector, which has not yet made public any plans.
Overall, then it can be seen that the technological
feasibility of the various gtocesses differ to a fair degree.
Methanol processes are technologically feasible and available,
though the most efficient, second generation gasifiers have yet to
be fully commercialized, but will soon be in some cases. The MTG
process is only a step behind, though it is an important step.
The actual start of construction on the New Zealand plant will be
a key show of confidence and its successful operation will be an
important demonstration, though this is some years away. The
direct liquefaction processes are even further away from
commercial feasibility, since DOE recently withdrew funding for
the EDS and H-Coal pilot plants, the fate of these two projects,
in addition to the above mentioned SKC-II, appears to be in the
private sector. The pilot plant results will be of utmost
importance in establishing confidence in the projected costs and
.efficiencies which are needed to . provide capital for
commercialization.
Now that the technological feasibility (and commercialization
status) of the various coal conversion technologies has been
discussed, the next step will be to examine the thermodynamic
conversion efficiencies and the product mixes of these same
technologies. The information presented has been taken from the
most recent sources which were available to the public. The
actual efficiencies presented may differ somewhat from those found
in the original source documents as an effort was made to put all
of the efficiencies on the same, and most comparable, basis. For
example, all off-site use of power was included as energy input,
not only as kilowatt-hours of electricity, but as Btu of coal
required by a typical power plant to generate that
electricity.[48] Also the inefficiency of any refining of the
fuel that would be required to meet standard petroluem product
specifications was also included as was appropriate in each
process. The energy content of byproducts was excluded to place
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-27-
more emphasis on useable fuels and to de-emphasize the production
of byproducts such as sulfur. In reality, this last adjustment
has little relative effect since all the processes examined
produce a small amount of byproduct.
The efficiencies and product mixes of the various processes
are summarized in Table 5. As can be seen, the efficiencies of
two methanol processes are presented. AS described above, there
are many types of gasifiers and each has its own efficiency.
There are also a number of methanol synthesis processes, such as
the IGI low-pressure, the Lurgi low-pressure, and the Chem Systems
liquid-phase processes. The first two are fully commercial, gas
phase processes. The latter is a new process which has not been
demonstrated on a large scale as of yet.[53] However, the
efficiencies of the synthesis processes are close to one another
and the differences in gasifier technology dominate the
differences in overall process efficiencies.
The two efficiencies shown for methanol represent the range
of efficiencies expected for nine different gasifier/synthesis
combinations for which designs were available.[7,10,16,54,55,
56,57,58] The; Koppers-Totzek gasifier (49.3) percent) is
commercially available and represents the lowest efficiency of
these gasifiers. The "slag-bath" gasifier shown is a second-
generation gasifier and represents the best efficiency of this
group of gasifiers.
in all cases, the process designs mentioned called for the
sole production of methanol as a product. Only such- processes
were presented to emphasize that the problem being addressed by
this paper is a liquid, transportation fuels problem and not
simply an energy problem. The efficiency of producing methanol
can be improved to 67 percent by co-producing substitute natural
gas (SNG).[10] Since this improvement occurs in the gasifier/
synthesis-gas purification portion of the plant, it applies in a
similar fashion to other indirect liquefaction processes such as
the Mobil MTG and F-T processes. Using the results of the Mobil
study, it would be more economical to co-produce SNG if it could
be sold for 50 percent of the energy value of the methanol or MTG
gasoline.[10] If in the future SNG will be able to demand that
price or more in the market place (which should be fairly likely),
then methanol will be able to be made more efficiently than that
shown in Table 5 and more economically than when produced as the
sole product (see Section V).
The other indirect liquefaction technology presented in Table
5 is the Mobil MTG process. Since Mobil MTG produces gasoline
(and some liquified petroleum gas (LPG)) from methanol, its
efficiency must be less than that of producing methanol. Mobil
estimates that the thermal efficiency of its fixed-bed reactor
technology is 86.7 percent.[10] Adding this to the efficiencies
-------
-28-.
Table 5
Process Efficiencies and Product Mix
o£ Various Coal Liquefaction Processes
Process
Crude petroleum
Conversion Efficiency
92%
Indirect Liquefaction
Modified Lurgi Gasification 57.3%
Lurgi Synthesis
Koppers Totzek gasification 49.3%
ICI Synthesis
Mobil MTG - Fixed Bed
- Fluidized Bed
Direct Liquefaction**
Exxon Donor Solvent
(EDS)
43-50%
45-53%
55.8%
H-Coal
61.8%
Solvent Refined Coal
(SRC) II
63.6%
Product Mix
(Energy Basis)
50% Gasoline
33% Distillate
15% Residual
2% LPG
100% MeOH*
100% MeOH*
88% Gasoline
12% LPG
32.7% Reg. Gasoline
14.0% Prem. Gasoline
25.6% No. 2 Fuel Oil
9.6% LPG
18.1% SNG
33.1% Reg. Gasoline
11.2% Prem. Gasoline
20.4% NO. 2 Fuel Oil
22.3% LPG
13.0% SNG .
64.7% Gasoline
12.1% LPG
23.2% SNG
**
MeOH = 95-98% methanol, 1-3% water and the remainder higher
alcohols.
These efficiencies include the effect of refining where
needed. However, the refinery product slates are not
identical for each of the direct liquefaction processes.
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-29-
shown in Table 5 for methanol results in the 43-50 percent range
of efficiencies shown in Table 5.
Mobil has also been developing a fluidized-bed reactor which
is projected to increase the efficiency of its MTG process to 91.7
percent. However, as mentioned earlier, the fluidized-bed reactor
is further from commercialization and its efficiency is more of a
projection than the value for the fixed-bed reactor. Overall,
with this reactor, the MTG process is 45-53 percent efficient.
The Mobil MTG product is primarily high-octane (83 MON, 93
RON, unleaded) gasoline (roughly 85 percent) with the remainder
being LPG.UO] This is an excellent product mix from a
transportation point of view. The one possible drawback in the
area of product quality would be the presence of a considerable
amount of durene in the gasoline (3-6 percent).[59] Durene is a
relatively large molecule (C-10 adkyl-benzene) and has a freezing
point of 175°F. Tests by Mobil have shown some driveability
problems (fuel crystalization in carburetor) under certain
conditions at durene levels of 5 percent, but the effects at 4
percent were only minimal. Two solutions are possible. One, the
catalyst may be able to be modified to reduce the amount of durene
produced. Or two, MTG gasoline could be blended with petroleum-
derived gasoline to reduce durene to acceptable levels.
To obtain the overall efficiencies for the direct
liquefaction technologies> estimates for the efficiencies of the
direct liquefaction plants and the efficiencies of the coal
syncrude refineries (processing only the €5+ liquefaction
product) are necessary. The efficiencies of the direct
liquefaction plants are available from the latest design
projections made by Exxon (EDS), P&M (SEC-II) and HRI (H-Coal).
However, refinery efficiencies were not directly available in each
case. In the following paragraphs, refinery efficiencies will be
discussed. Then direct liquefaction efficiency and overall
process efficiencies will be presented.
One refining study has been performed by Chevron on the
refining of the SBC-II syncrude.[59] This study was based on
laboratory data along with general petroleum processing
correlations obtained from refineries constructed by Chevron. A
less detailed study was performed by UOP on the refining of the
H-Coal syncrude.[60] This study used linear programming
techniques based on UQP's experience with refining and their
knowledge of the H-Coal syncrude. A detailed study on the
refining of EDS crude has not yet been performed.
The Chevron/SRC-II refinery was designed to produce 100
percent gasoline. An analysis of this refinery indicated a
thermal efficiency of 83 percent. An analysis of the UGP/H-Coal
refinery indicated a thermal efficiency of 95 percent. This
refinery was designed to meet a gasoline/distillate ratio of 2.0.
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-30-
Modern petroleum refineries which use heat-recovery devices and
up-to-date technology have thermal efficiencies of about 92
percent.[61] Since the H-Coal, EDS, and SHC-II syncrudes are
hydrogen deficient and high in nitrogen and oxygen relative to
petroleum, and their refining would require more hydrogen per
barrel, it would appear unlikely that the refining of the coal
syncrudes would be more efficient than the refining of petroleum.
Since the Chevron/SRC-II refinery produces 100 percent gasoline,
which requires high-severity refining, its thermal efficiency of
83 percent is reasonable, and will be used in this report for the
SRC-II process. However, the H-Coal refining efficiency is higher
than the 92 percent petroleum refining efficiency. One answer for
this could be that a grass roots H-Coal refinery does not require
vacuum bottoms processing because of the properties of the H-Coal
syncrude feedstock. However, atmospheric processing for the
H-Coal syncrude would still be much more severe than that for
petroleum processing because of the syncrude's hydrogen deficiency
and high nitrogen and oxygen content. Another reason for the high
thermal efficiency of the H-Coal case might be that UQP did not
focus their attention on efficiency since neither efficencies nor
heating values of feedstocks and products are included in their
report. It appears reasonable, then, to reduce the efficiency of
the H-Coal refinery to 0.92, the same as that for a modern
petroleum refinery.
Since there has not been any detailed refining study for the
EDS syncrude, a representative efficiency will be estimated. The
quality of the EDS syncrude is a bit poorer than that of the
H-Coal crude since the EDS syncrude has a lower hydrogen content
and higher nitrogen and oxygen contents (see Table 6).[48,60] The
theoretical hydrogen requirement necessary to bring the hydrogen,
nitrogen, oxygen, and sulfur levels of the EDS crude up to the
quality of the H-Coal oil is 248 standard cubic feet (scf) per
barrel of the EDS crude. That for SBC-II syncrude is 469 scf per
barrel.[59,60] Of course, during actual refining the amount of
hydrogen would be greater since this theoretical level could not
be attained. Therefore, the thermal efficiency for refining the
EDS syncrude would be lower than that of the H-Coal crude given
identical product slates, but about the same amount above that of
the SRC-II refinery given its product slate. Therefore, the
thermal efficiency chosen for EDS syncrude refining will be 88
percent, a rough mean between the two available values.
It should- be noted, however, that even if these refining
efficiencies are off by 2-3 percent, the effect on the overall
direct liquefaction efficiencies will be less than 1-2 percent.
Also, these efficiencies take into consideration hydrogen from
naptha reformation.
Before the overall direct liquefaction efficiencies are
determined, the efficiencies and the product slates from the
direct liquefaction processes will be presented. Based on the
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-31-
Table 6
Refinery Feedstock Property Data
Specific Gravity
Gravity, °API
Total Nitrogen, Wt-%
Oxygen, Wt-%
Sulfur, Wt-%
Carbon, Wt-%
Hydrogen, Wt-%
Ramsbottom Carbon, Wt-%
Conradson carbon Residue, Wt-%
Benzene Insolubles, Wt-%
Cy Insolubles, Wt-%
Ash, ppm
Bromine Number
Pour Point, °F
Viscosity, CS at 100°F
ASTM D 86/D 1160 Distillation, °F
at Vol-% Distilled:
^ Start/5
10/30
50
70/90
95/End Pt.
Distillation, °F vs. Vol-%
Distilled
13.87 Vol-%
30.84
10.4
40.89
3.99
H-Coal[131* SBC-IItll]** EDS***
0.8733
30.5
0.37
1.72
0.15
86.7
11.0
0.10
0.10
67
41.7
C6/350°F
350/399
399/650
650/880
0.9427
IS.6
0.85
3.79
0.29
84.61
10.46
0.70
0.03
40
70
-80
2.196
154/217°F
281/382
438
484/597
699/850
0.928
21.0
0.48
1.75
0.479
86.73
10.56
**
Derived from Burining Star Mine, Illinois No. 6 coal.
Derived from Blacksville No. 2 Mine, Pittsburgh Seam coal.
*** Derived from Monterrey, Illinois No. 6 coal.
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-, -32-
\
latest available projections,- the efficiencies of the EDS, H-Coal,
and SEC-II processes are 61.6, 63.1 and 72 percent,
respectively.[48,62,63,64] The actual product slates from -the
direct liquefaction processes before refining are presented in
Table 7 as a percentage of total energy. A breakdown of the
refinery feedstocks are also presented in this table.
NOW that the refinery and direct liquefaction efficiencies
have been determined, the overall thermal efficiencies and product
slates for the direct liquefaction technologies may be obtained.
These are shown in Table 5. Note that not all of the products
from direct liquefaction need refining and therefore the refining
efficiency penalty is only applied to those products needing
refining. As can be seen, the indicated conversion efficiency for
the EDS process is 55.8 percent, in the upper-middle of the range
of methanol efficiencies. This figure is based on Exxon's latest
projection of EDS efficiency[48] and an average refining
efficiency of 88 percent for those products requiring refinement.
As mentioned earlier, the EDS process efficiency is based on
projections made in 1978 (design published in March, 1981) prior
to operation of their pilot plant in 1980 when their latest design
study was begun.[48] The latest information on their pilot plant
operation indicates that it is not attaining this projected
efficiency. [47] At this time it is not known whether this is
correctable or whether it is an indication of a true lower process
efficiency. In their latest estimate, Exxon had already lowered
the projected efficiency of the liquefaction process significantly
from their estimates made in 1975 (design published in 1978) based
on development work between 1975 and 1978.[48] However, they were
able to retain the overall process efficiently by improving their
processing of the vacuum bottoms produced in the process.[48]
The efficiency of the H-Coal and SEC-II processes were also
taken from the latest available, projections.[62,63,64] The
overall efficiency of the H-Coal case is 61.8 percent. This is
based on an average efficiency obtained from the high and low
estimates reported by Fluor Corp. for the liquefaction
section,[63] and a 92 percent efficiency for the refinery.[59]
The overall efficiency for the SEC-II case is similarly 63.6
percent.[60,62] As was the case with the EDS process, the H-Coal
estimate has not been confirmed by pilot plant operation, but
estimates of the pilot plant efficiency should be available in the
near future. The estimate of the SBC-II efficiency has also not
been confirmed by pilot plant operation of the scale now being
undertaken by Exxon and HRI (250-600 tons of coal per day).
Pittsburg and Midway Coal Mining have been operating a 30 ton per
day plant for a number of years, as mentioned earlier, and it is
likely that the SEC-II efficiency estimate was based on at least
some data from this plant.
The overall product mixes for the three liquefaction
processes are also shown in Table 5. The overall product mix is
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-33-
Table 7
Products from Direct Liquefaction and
Feedstocks to Refinery as a Percentage of Total Energy*
Liquefaction Products
Naptha
Fuel Oil No. 2
Distillate/
Boiler Fuel
LPG
Butane
Propane/Ethane
Methane
H-Coal
29.2
38.8
22.8
—
5.8
3.5
—
EDS
34.6
33.7
28.9
2.8
—
—
—
SBC-II
18.9
63.3
5.3
—
0.1
2.0
10.3
Refinery Feedstock
H-Coal
32.2
42.7
25.0
EDS
35.5
34.7
29.7
SBC-II
21.6
72.31
6.1
Note that not all products from direct liquefaction need
refining and therefore the refining efficiency penalty is
only applied to these products which do.
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-34-
based on finished products being produced by the refinery and the
liquefaction plant. Finished product output from the liquefaction
plant includes only LPG, SNG, and some finished gasoline being
produced in the H-Coal case. The remainder of the output from the
liquefaction plants are the raw coal syncrudes which are sent to
the refineries. The Chevron/SRC-II refinery produces 100 percent
gasoline, while the H-Coal and EDS cases are designed to meet a
gasoline/distillate ratio of 2.0. Therefore, these overall
product slates for the direct liquefaction technologies contain a
large portion of transportation fuels. The overall percentage of
gasoline produced for the three processes ranges from 44 to 65
percent. LPG may also be used as a transportation fuel in a
retrofitted gasoline engine. The percentage of LPG produced by
the processes ranges from about 10 to 22 percent. However, the
distillate produced by these processes will probably not be
available for use as diesel fuel. Coal liquefaction distillates
need to be severely hydrotreated to reduce the aromatic content to
a sufficient degree (less than 25 percent aromatics) so that a
cetane number of 36-39 can be obtained.[62,65] These cetane
numbers are still lower than the minimum ASTM specification of
40,[66] and well Jaelow the current national average of 46.[67]
Therefore, additives to boost the cetane number would'be required,
before even severely hydrotreated coal distillate could be used as
diesel fuel. This would be more severe hydrotreatment than
indicated in Table 5 and would lower the indicated efficiencies
and yields.
The relatively high levels of SNG from the EDS and SBC II
processes also make a plant co-producing SNG and methanpl or SNG
and gasoline (MTG) more reasonable. While we believe that
transportation fuels are needed the most from the U.S. synthetic
fuel industry, it is also appropriate to compare processes on
equal bases. It may be more appropriate to compare these direct
liquefaction processes with methanol and MTG gasoline plants
co-producing some SNG than to plants producing 100 percent
methanol or gasoline.
B. Wood
Methanol from wood was first produced by pyrolysis as a minor
by-product of charcoal manufacturing. However, this process is no
longer economical. The most efficient way to produce methanol
from wood today is in the same manner that it is produced from
coal, which has already been described. According to the Solar
Energy Research Institute (SERI), wood has a number of advantages
over coal in terms of conversion to methanol: 1) wood is easier to
gasify than coal, 2) it contains its own oxygen and water, 3) its
ash content is less than 2 percent, and 4) its sulfur content is
less than 0.1 percent (compared to 2-4 percent in coal).[68]
Unfortunately, these advantages are somewhat offset by: 1) the
need to dry the wood to the correct moisture content, 2) wood's
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low energy density, and 3) the lack of large concentrations of
wood, thus requiring smaller, higher cost methanol plants.[68]
One proposed solution to these problems is wood
densification. According to SERI, densification of wood refuse
into pellets ("instant coal") would require only 1-2 percent of
the total energy contained in the wood.[68] In addition to
reducing transportation costs and being a superior feedstock,
these pellets can also be dried more efficiently by using the gas
fuel they produce. In fact the drying energy is largely recovered
in the more efficient gasification of the pellets. However, the
economics of densification are likely to vary and may not be
profitable in all situations. It has also not been demonstrated
on a large scale.
Wood gasification originally started around the early 1800's
and by the time of World War II (during petroleum shortages) there
were almost a million small gasifiers being used to run cars,
trucks, and buses primarily on wood. Although the attention on
gasification has since been focused on natural gas, and then coal,
there is a large amount of research presently being done on wood
gasification. According to DM International (formerly Davy
Powergas, Inc.), which has designed 60-65 percent of the installed
capacity currently producing methanol from natural gas, the
technology to gasify wood for methanol production exists, but
gasifiers have not yet been optimized for wood utilization. [69]
DMI is currently in the process of designing a 2,000 ton per day
methanol plant for use in Brazil which is based on . wood
gasification.
Although conventional fuels can also be made directly from
wood, most of this technology is still in ' "the development
"stage.[26] For instance, pyrolytic oil can be produced by slowly
heating pressurized biomass (direct liquefaction) while olefins
can be made by fast heating or flash p^rolysis (indirect
liquefaction).[26] Presently, research is being conducted with
pyrolysis and some day these processes may be proven and
profitable. Genetic engineering efforts are also addressing the
conversion of wood into more useful products and this may hold
some promise for the future. However at this time there appear to
be no gasoline or diesel fuel precursors that can be economically
produced from wood.[26]
C. Agriculture and Municipal Wastes
Like coal and wood, the technology to gasify agricultural and
municipal solid wastes (MSW) is for the most part proven, though
gasifiers must be optimized to run on these fuels, in fact, a 200
ton per day MSW gasification facility designed by Union Carbide
Corporation is currently operating in south Charlestown, West
Virginia.[68] DOE has estimated that the conversion efficiency
for agricultural residues may be as high as the 58 percent quoted
for wood, while Stanford Reseach Institute claims a 46 percent
conversion efficiency for MSW. [27,30] One of the biggest
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challenges with gasifying MSW is simply keeping slag (unburnables)>
and gaseous impurities down as low as possible, since the MSW raw
material is far from uniform and contains metal, glass, etc.
D. Environmental Effects
The previous discussions have described the availability of
the various technologies that produce both methanol and synthetic
gasoline from coal and other raw materials. These processes will
all affect the environment to some extent, as will the
distribution and storage of the fuels themselves. in this
section, some of the environmental effects will be examined,
particularly when one process or fuel may have relative advantages
or disadvantages. The emphasis will be placed on coal-based
processes and fuels. The production of methanol from wood or peat
may be inherently safer environmentally than the production of any
fuel from coal, since the raw material will contain very little
sulfur and lower amounts of most heavy metals (mercury being the
most notable exception). Thus, very little needs to be said about
these processes, of course, this assumes that proper care is taken
in harvesting the wood or digging the peat, improper harvesting
or overharvesting of wood can deplete forests and damage
ecosystems, harming wildlife, recreation and agricultural
activities, similarly, the harvesting of peat can damage the
ecosystem, in addition, improper wood gasification could release
potentially harmful organic substances into the air similar to the
gasification or liquefaction of coal.
Ihe environmental analysis of production and distribution of
synthetic liquid fuel from coal is not intended to be a complete
analysis and is largely qualitative, rather than quantitative.
The necessary scientific data do not yet exist for such a complete
analysis to be possible.
In addition to discussing environmental problems common to
both indirect and direct liquefaction technologies, this analysis
also examines the theoretical environmental advantages and
disadvantages of indirect liquefaction (relative to direct
liquefaction) during production. It also reviews current
scientific literature on the environmental effects during end-use
(the latter is done in Section IV). In general, more
environmental data are available on the end-use of pure methanol
fuels, than on the production of methanol. It should be noted,
however, that current data on using pure methanol fuel are based
on methanol produced from natural gas. Coal-based methanol may
contain more impurities than methanol from natural gas. These
impurities could potentially cause additional environmental
effects. Any such impurities, however, should be present in very
small quantities because it is necessary to purify the feedr-gas to
the methanol synthesis catalyst.
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Coal itself contains many elements and compounds in addition
to hydrogen and carbon, such as organic nitrogen-containing
compounds, organic and inorganic sulfur, and trace metals, such as
lead, arsenic, etc. The conversion of coal to other fuels offers
a number of opportunities for these pollutants to reach the
environment in harmful ways, regardless of the particular
conversion process used.
The Federal interagency' Committee on the Health and
Environmental Effects of Energy Technologies has attempted to
identify potential adverse effects of coal gasification and
liquefaction technologies.[70] The committee focused on such
issues as water quantity, direct aquatic discharges of organics,
inorganics, and trace elements, airborne contaminants and their
impact on water quality, and solid waste. The highlights of its
findings and pertinent points by other reseachers are discussed
below.
The availability of water for coal conversion technolgies may
be a problem in both the eastern and western regions of the U.S.
However, since many western regions receive one fourth or less as
much surface precipitation as regions in the east, water
availability is inherently a greater problem there. Also,
seasonal fluctuations of stream flow are greater in the west. In
order to evaluate the impact of coal conversion technologies on
water supply, the committee identified a need to quantify the
amount of water available both as surface and ground water during
an average year and during periods of low precipitation. Also,
instream flow requirements need to be established to protect
aquatic biota. It should be noted that a closed-loop, or "zero
discharge," aqueous stream approach appears possible for coal
conversion technologies. This system would greatly reduce water
requirements as well as limit direct aquatic pollution (discussed
below).
The aqueous discharge of trace organics may present an
environmental problem, especially since several of the organic
substances anticipated to be generated by coal conversion
facilities are known carcinogens.[70] The Interagency Committee
further anticipates that organics could, be released at levels
which may be toxic to aquatic life. The transport and
transformations of trace organics need to be determined, however,
before the extent of potential adverse effects can be quantified.
Inorganic substances such as ammonia, cyanide, and thiocyanate
were also identified as potential toxic agents to aquatic
organisms.
One potential advantage of gasification over direct
liquefaction is the fact that most of the organic nitrogen and
sulfur is broken down to simple compounds like ammonia and
hydrogen sulfide. These are relatively easy to separate from the
carbon monoxide and hydrogen which make up the major part of the
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synthesis gas. Also, since the carbon monoxide and hydrogen
entering the methanol synthesis unit must be essentially free of
sulfur to prevent rapid catalyst deactivation, there is an
economic necessity for its removal.
Coal liquefaction, on the other hand, inherently leaves some
of the sulfur and nitrogen in the liquid phase, bound with the
organics. The most effective technique to remove these elements
is hydrogenation, which also is used to upgrade the fuel.
However, hydrogenation is expensive, because of the large amounts
of hydrogen consumed, and will likely be limited to only the
degree that is necessary to market the fuel.[14] If the fuel is
upgraded to gasoline or high quality No. 2 fuel oil, most of the
sulfur and nitrogen will be removed and there should not be any
significant problems. However, that portion of the synthetic
crude which may be burned with little or no refinement could
contain relatively high levels of these elements (up to 0.5
percent sulfur and 0.8 percent nitrogen) and represents more of an
environmental hazard than gasification products.
In addition to lead and arsenic, mentioned above, other trace
elements found in coal include antimony, boron, bromine, cadmium,
fluorine, mercury, nickel, uranium and thorium. These substances
could accumulate in sediments and prove to be toxic to aquatic
life. Most trace metals, however, will be removed with the coal
ash. Under the zero aqueous discharge approach, dissolved metals
would be concentrated in brines for ultimate disposal.
Several potential problem areas concerning airborne
pollutants from -.. coal conversion facilities have been
identified.[70] Among these problems is the potential loss of
volatile photochemically reactive organic vapors which could serve
as precursors for such pollutants as ozone, peroxyaqyl nitrates,
aldehydes, sulfate and nitrate aerosols and cresols. Such
hydrocarbon emissions may also be toxic or produce toxic
substances when photo-oxidized. Emission of these materials could
come from unincinerated vent gases from acid gas removal, leaks in
valves, flanges and other fittings, or equipment failures.
Atmospheric emissions of volatile, potentially toxic chemicals can
also occur from the aqueous condensates in cooling towers. These
cooling tower emissions could give rise to both health and
environmental problems.
In addition to the pollutants just described, direct stack
emissions from steam boilers of sulfur dioxide, oxides of nitrogen
and particulate will also" occur. Their control, however, should
be rather straightforward due to the similarity between these
steam boilers and existing industrial and power plant boilers.
As alluded to above, coal conversion facilities will generate
large quantities of solid wastes. Since pollutants such as heavy
metals are more easily removed by processes using gasification
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than direct liquefaction, one might project that direct
liquefaction products would contain greater amounts of these heavy
metals than indirect liquefaction products. However,, it is likely
that the heaviest fraction of the direct liquefaction product,
that containing most of the heavy metals, will be gasified to
produce hydrogen. If this is the case, there will be little
inherent difference in the solid wastes of direct and indirect
liquefaction processes.
This discussion brings up the issue of catalyst disposal.
Both indirect and direct liquefaction processes utilize
catalysts. Although most catalysts are reprocessed when spent,
some cannot be reprocessed economically and therefore require
disposal. Methanol and the F-T process utilize one type of
catalyst and the Mobil MTG process utilizes two types of catalyst
in their liquefaction steps. While, in the case of methanol, the
catalyst is currently being disposed of in the U.S. with no known
problems, the use of coal as a feedstock could potentially
increase the impurities reaching the catalyst and therefore
residing on the disposed catalyst. The H-Coal process also
utilizes a catalyst in its liquefaction step while the SRC-II- and
EDS processes utilize catalysts at other steps. Thus, there
apprears to be no distinct advantage for either direct or indirect
processes in this area.
The remaining distinct difference between the environmental
effects of coal gasification and coal liquefaction processes
(prior to end-use) is in exposure to the fuel itself, after
production and in distribution. While coal liquids are for the
most part hydrocarbons and, as such, are similar to petroleum,
they have a higher aromatic content and some may contain
significant quantities of policyclic ' and heterocyclic organic
compounds. Some of these compounds are definitely mutagenic in
bicassays and many have produced tumors in animals. Thus, while
the noncarcinogenic health effects of these materials would be
more similar to those of crude petroleum, they would definitely
have the potential to be more carcinogenic. There is also some
evidence that much of this bioactivity can be removed by moderate
to severe levels of" hydrogenation which would occur if high grade
products were produced. Thus, again .the potental hazard is
dependent upon the degree of hydrogenation given the products.
indirect liquefaction products, on the other hand, do not
appear to exhibit mutagenicity or carcinogeniciti. Methanol is
neither mutagenic nor carcinogenic and early tests run on
M-gasoline have shown it to be nonmutagenic, similar to
petroleum-derived gasoline. Thus, either of these two products
offers some degree of benefit over direct liquefaction products.
It is possible that methanol produced from coal may contain
impurities and that such impurities may affect exhaust products
when used. However, little research exists on this issue and such
impurities, if any do indeed exist, may be removed during
processing.
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Methanol, of course, is highly toxic in heavy exposures,
leading to blindness or death. Much of its notoriety in this area
is due to people confusing it with ethanol and drinking it in
large quantities. Hydrocarbon fuels, while also being toxic, do
not suffer from this confusion and are not often taken
internally. With proper education of the public, methanol's
confusion with ethanol should be curtailed. However, more work is
still needed in this area.
The absorption of methanol through the skin is also
hazardous, more so than gasoline (though the presence of benzene,
a carcinogen, in gasoline complicates this issue). Given the
public's rather careless use of gasoline, widespread use of
methanol would have to be accompanied by an intense campaign to
inform the public of the dangers involved. However, given proper
warning and identification, and the public's ability to handle
other harmful but widely available products, such as pesticides
and herbicides, it would appear that a satisfactory level of
safety should be attainable.
The final point which deserves mention here is the difference
between the effect of an oil spill and a methanol spill. The
effects of oil spills are well known; oil films stretching for
miles, ruined beaches, surface fires, etc. The effects of a
methanol spill are expected to be quite different, primarily
because methanol is soluble in water. While high levels of
methanol are toxic to fish and fauna, a methanol spill would
quickly disperse to nontoxic concentrations and, particularly in
water, leave little trace of its presence afterward.[71] Sea life
should be able to migrate back quickly and plant life should begin
to grow back quickly, though complete renewal would take the time
necessary for new plants to grow back. Also, if a methanol fire
would start, it could be effectively dispersed' with water, which
is not possible with an oil fire. However, methanol flames can be
invisible, which would be a disadvantage relative to gasoline.
This- disadvantage could potentially be. reduced or eliminated
through the use of additives which would provide flame luminosity.
The various relative environmental aspects of synthetic fuels
mentioned above are those which appear to stand out at this time.
More work, however, is still needed in most areas. Although
natural gas to methanol plants exist and have led to much
experience in handling methanol, questions related to methanol
production from coal have not been answered with absolute
certainty since such large scale facilities do not.currently exist
in the U.S. (Methanol is commercially produced from coal in South
Africa, but without acceptable pollution controls by U.S.
standards.) Similarly, no real life experience of the effects of
the production of synthetic crudes exists, nor of their use.
Given these caveats and the need for further research, however,
the indirect liquefaction route to yield methanol or gasoline
(from methanol) appears to have some potential environmental
advantages over direct liquefaction processes.
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\
\
III. Practicalities of Distributing Another New Fuel
AS was just shown, the production of methanol appears to have
a fair number of technological and environmental advantages over
the production of syncrudes. After production, however, the
methanol must be distributed to retail fuel outlets for final
purchase. This would mean adding a new fuel to the distribution
system. This problem has often been cited as a major one for
methanol, both because of the initial cost of conversion and
because roughly twice the volume of methanol must be distributed
as that of gasoline due to methanol's low energy density. In this
section,, the difficulties of adding another fuel to the
distribution system will be presented. The economics of
distribution will be discussed later in conjunction with the
economics of producing and using methanol (Section V).
While some have emphasized that introducing methanol would be
a tremendous task, and. this may be true, it is important to note
that the nation has already successfully encountered the problems
associated with the somewhat analogous introduction of a new fuel
in the very recent past. This occurred when unleaded gasoline was
required for use in all post-1974 cars that were equipped with
catalytic converters. The required addition of this new fuel to
the marketplace went through a remarkably smooth transition, j This
was in spite of the fact that in the period of only one year, use
of unleaded gasoline went from near aero to roughly 10 percent of
the gasoline market. The government requirement that gas stations
over a certain size carry unleaded gasoline helped significantly,
particularly in the early days of the 1975 model year.
Since it is not expected -that use of methanol would be
required for all or most of the new vehicles in a certain model
year, the introduction of neat methanol could follow a slower
pace. Of course, a slower introduction would mean that methanol
would initially be supported in the market place by a smaller
sales volume and that per gallon mark-ups may need to be greater
than they were for unleaded gasoline. However, before methanol
becomes available on a commercial scale at retail outlets, it is
expected that fleets will be the first significant users of
methanol. This is due primarily to the fact that fleets tend to
operate from fixed central locations. Thus, with little total
investment, fleets can have their own facilities to store and
distribute methanol fuel and not have to be concerned that
methanol is not yet available everywhere.
This is already actually occurring on an experimental basis.
The Bank of America is experimenting with the use of neat methanol
in its corporate fleet. It's current fleet test of methanol has
accumulated more than 500,000 miles so far. By 1985, it is
expected that 500-600 Bank of America vehicles will be converted
to methanol. Eventually, the Bank of America intends to convert
its entire fleet of 1,800 vehicles to methanol or methanol-blend
fuel.
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Another "segment of the transportation spectrum that could
utilize methanol fuel before it was widely available would be
intracity transit bus fleets. These vehicles also tend to
originate and return to fixed central locations that could also
easily convert to methanol distribution. Given that methanol
engines are expected to be able to at least approach and possibly
attain the fuel efficiency of the diesel (see next section)
without the presence of diesel smoke or odor, which are easily
noticed by the public, transit authorities may have some
incentives to consider methanol as an alternative to diesel fuel.
Eventually, however, methanol will need to be available at
commercial outlets. TWO factors will help make the transition
easier than would otherwise have been the case. One, use of
leaded gasoline will be decreasing steadily between now and the
early 1990's. This will provide storage tanks and pumps for a new
fuel, since the same equipment can to a large extent be used to
store and pump methanol with only minor changes to rubber
components. (it should be noted that some storage tanks,
particularly newer ones, are made of fiberglass, which is not
compatible with methanol. These will need to be either replaced
with carbon steel tanks or with new fiberglass tanks lined to
prevent contact with the fiberglass.) TWO, as evidenced by the
existing diesel passenger car market, not every gas station has to
market a given fuel to support a small fleet of vehicles.
Certainly, very few urban gas stations currently market diesel
fuel. Yet the diesel car market is flourishing. The same could
be true for methanol-fueled cars. Indeed, the diesel truck fleet
has survived for a long time on a small number of stations
carrying diesel fuel. The stations are simply along the routes
most frequently traveled by line-haul trucks.
The largest problem facing the introduction of methanol fuel
will likely be coordinating methanol production/distribution with
the production of methanel-fueled vehicles. Each industry usually
points to the other and says that we will produce the cars when
the fuel is available-or we will produce the fuel when the cars
are available. of course, neither can afford to invest in
producing the fuel or the vehicles without some guarantee that the
other will occur simultaneously.
Consumption of neat methanol would likely begin with
corporate and transit fleets with captive fuel supply systems.
The next step would be the biggest one, to a distribution system
which would support the public sale of methanol-fueled vehicles.
This could require government incentives or requirements to carry
neat methanol fuel or it could occur through the government
purchasing such vehicles and a small fuel supply market growing to
supply this fleet. After this the market would decide the rest
and determine if methanol was an economical fuel vehicle choice or
not.
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Overall, there are a number of distribution-oriented problems
to be solved before methanol could be widely available as an
automotive fuel. Indeed, overcoming the inertia of the presence
of the existing distribution network for gasoline and diesel fuel
is probably the greatest obstacle facing the introduction of
methanol as an automotive fuel. Surely there would be conversion
costs involved and possibly some expansion because of methanol*s
lower energy density. However, the great majority of the capital
represented by the existing distribution network is compatible
with methanol and would not require total replacement. Conversion
costs need to be fully considered when determining whether or not
methanol is an economic alternative. However, the greater problem
appears to be simply organizing the various parties involved so
that each can be confident of the other's actions in moving ahead
with a new fuel.
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IV. Use of Methanol in Vehicles
As suggested in the introduction, there are many potential
uses for methanol fuel. in the electric power generation
industry, methanol may be an attractive fuel for peaking turbines
and may also be suitable for base-load plants (with no need for
costly scrubbers).[15,72,73,74] Methanol can also be used as a
chemical feedstock.[15,75] However, the emphasis here will be
placed on the use of methanol in motor vehicles. It is in the
motor vehicle area that methanol has the greatest potential for
displacing foreign crude, since transportation uses account for
more than half of all petroleum currently consumed by the nation.
The following represents a review of existing research and
literature produced by other government agencies, industry, and
other private institutions. EPA, itself, has begun an evaluation
effort of its own on pure methanol use in motor vehicles, although
the results of this early work was not available to be included in
this report. However, it is expected to closely follow the
results of the promising data produced here by other institutions,
although considerable work remains to be done.
•Hie emission characteristics of methanol engines will be
discussed first, followed by the fuel consumption characteristics
of such engines. The data presented were obtained from tests of
actual methanol engines. However, two things should be said about
these data. One, the data were taken using engines which were
only roughly converted to use of methanol and optimized engines
would be expected to show further improvements in fuel efficiency
and emissions. TWO, these data should not be taken as a literal
demonstration that methanol engines could be mass produced
immediately for use in all regions of the U.S. There are some
technical difficulties associated with the use of methanol which
have yet to be solved to full satisfaction, though serious
attempts to solve these problems have only begun very recently.
It is safe to say that these problems are relatively minor and
that if the fuel were available there would be engines available
to use it. This has been stated clearly by the domestic auto
industry.
The worst problem centers around methanol's low vapor
pressure and high heat of vaporization. These properties make it
difficult to start a neat methanol engine in cold weather.[76]
Also, methanol has a very low cetane number of 3, which means that
it is very difficult to ignite in a compression-ignition engine
(e.g., a diesel). problems associated with materials
compatibility and lubrication also exist, but these problems
already appear to be solvable with existing technology, requiring
only that the auto designer know that methanol is going to be the
engine fuel.
v
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Various techniques are already being tasted which will
improve the cold-starting capability of gasoline engines operating
on methanol, such as better mechanical fuel atomization,
electrical fuel preheating, and the blending of volatile, low
boiling point components into the methanol. Methanol's ignition
problems are more serious in diesel engines, but several possible
solutions are being investigated, such as intake air preheating,
turbocharging, glow plugs and spark ignition. Brazil already has
an experimental methanol-fueled diesel running on the road which
uses relatively inexpensive glow plugs as ignition aids and M.A.N.
in Germany has designed a diesel bus engine with spark ignition
which runs on methanol.[77,78]
As will be evidenced by the section on fuel consumption, the
fuel properties of methanol which lead to these difficulties also
lead to many advantages, such as increased thermal efficiency. As
has been the case with both gasoline and diesel engines in the
past, the disadvantages of a fuel can usually be overcome to allow
exploitation of the advantages.
A. Emissions
Methanol engines promise improved emission characteristics
over gasoline and diesel engines in a number of areas. Especially
important are low emissions of nitrogen oxides (NOx) and an
absence of emissions of particulate matter, heavy organics and
sulfur-bearing compounds. One possible side benefit of methanol
use could be that precious metal catalysts might not be needed.
Because methanol fuel will contain no sulfur, phosphorus, lead, or
other heavy metals, base metal catalysts (e.g., nickel, copper,
etc.) may suffice. One likely negative impact of methanol engines
would be an increase in ' engine-out aldehyde emissions,
particularly formaldehyde, catalytic converters, however, would
be expected to reduce aldehyde emissions by at least 90 percent.
Ihe available data supporting these effects are discussed below.
A search of the literature shows a general consensus that
methanol engines produce approximately one-half of the NOx
emissions of gasoline engines at similar operating conditions,
with individual studies showing reductions between 30 percent and
65 percent.[78,79,80,81,82] One of. the major engine design
changes expected with methanol engines is the use of higher
compression ratios to increase engine efficiency. Experiments
have confirmed the theoretical expectation that these higher
compression ratios, with no other design changes, will increase
NOx emissions considerably due to the higher combustion
temperatures.[83,84] However, with high compression ratios, less
spark timing advance is needed. Retarding spark timing is known to
reduce both NOx emissions and engine efficiency. Fortunately, it
has been shown that the combination of a much larger compression
ratio with a few degrees of spark timing retard can both increase
thermal efficiency and decrease NOx emissions,[84] This raises
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the possibility of methanol light-duty vehicles being able to meet
the current 1.0 gram per mile NOx emission standard without the
need for a NOx reduction catalyst.
Use of methanol in a diesel engine should also reduce NOx
emissions by the same degree as that described above. Diesel
engines have higher peak combustion temperatures and the effect of
a cooler-burning fuel should actually be even more apparent in a
diesel than in a gasoline engine. Unfortunately, no data to
confirm this is yet available from a diesel engine running on pure
methanol. However, emission tests have been performed on a
dual-fuel diesel, where a small amount of diesel fuel is injected
to initiate combustion of the methanol. These tests have shown
NOx emission reductions as high as 50 percent.[85,86]
Finally, the use of methanol should also provide a method for
heavy-duty engines to reduce NOx emissions closer to the
congressionally-mandated level without giving up any of the fuel
economy advantage of the diesel, as will be seen later.
Ihe lack of hard data on diesels operating on pure methanol
indicated above will also be evident below as other aspects of
methanol-fueled diesel engines are discussed. The basic reason
for this lack of data is that until recently methanol has not been
seriously considered to be an acceptable fuel for a diesel engine
because of its very low cetane number of about 3. For many years,
studies examining methanol as an engine fuel concentrated on
gasoline-type (fuel inducted with combustion air) engines.
However, as the more recent studies are indicating, it appears
possible to burn methanol in a diesel accompanied with some kind
of ignition assist and, therefore, utilize the efficiency of the
diesel concept.
In addition to the positive effect on NOx emissions, use of
methanol engines should provide even greater benefits with respect
to emissions of particulate matter and heavy organics from
diesels. Gasoline engines operated on unleaded fuel emit only
small quantities of particulate matter, which is primarily sulfate
emissions. Thus, any improvement in particulate emissions from
switching to methanol from gasoline would be small.
However, diesel engines emit significant quantities of
particulate matter. This type of particulate emission is of
particular concern due to its small size, its impact on air
quality where people live and work relative to other large sources
of particulate emission, and the finding that its extractable
organic fraction is mutagenic in short-term bioassays. Recent,
more detailed biological studies appear to be predicting a lower
level of carcinogenicity than originally thought might be
present. Still, even absent an absolute finding on the cancer
issue, particulate emission standards have been promulgated for
diesel passenger cars and light trucks by EPA and recently
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standards have been proposed for heavy-duty diesel trucks. Diesel
particulate matter consists of solid carbonaceous particles (soot)
and liquid aerosols. The former are generally formed when
fuel-rich mixture pockets burn and form carbon particles. These
solid particles can then serve as nuclei for organic species to
adsorb onto and as "vehicles" for such compounds to reach (and
possibly lodge in) the deep regions of the lung. Although large
reductions in diesel engine particulate have been reported,
particulate matter seems to be an inherent pollutant in
diesel-fueled compression ignition engines.
Methanol, on the other hand, has no carbon-carbon bonds and
is a "light" fuel relative to diesel fuel and should produce far
less carbonaceous particles, in addition, since methanol does not
contain inorganic materials like sulfur or lead, there should not
be any other types of solid particulate formed. Accordingly, with
pure methanol there would be no nuclei for liquid aerosols to
adsorb onto and total particulate emissions would be expected to
be near zero.[87] This is certain to be the case with a well
designed methanol-fueled spark-ignition engine, which itself may
attain the fuel economy of a diesel.[88] Unfortunately, however,
we know of no studies which have measured particulate from
compression ignition engines burning neat methanol. Several
studies (all of which used a small amount of diesel pilot fuel)
have reported much lower smoke levels, both in single-cylinder
tests and in a 6-cylinder, turbocharged, direct-injected
engine.[77,85,89] There seems to be very little question,
however, that neat methanol combustion in compression ignition
engines would result in very low (and possibly zero) particulate
emissions. This would result in a very important environmental
advantage compared to diesel fuel combustion and would appear to
remove the primary concern associated with- - 'large-scale
dieselization, that being the diesel particulate/cancer issue.
This discussion of.the diesel particulate/cancer issue raises
the question of formaldehyde emissions from methanol engines.
There is some concern that formaldehyde is carcinogenic.
Formaldehyde is an intermediate product in methanol oxidation and
would be expected to be emitted from methanol engines in greater
quantities than either diesel or gasoline engines. Many studies
have shown total aldehyde emissions (mostly formaldehyde) from
methanol engines to be. two to ten times greater than aldehyde
emissions from gasoline engines,[90,91,92,93]
Catalytic converters have been shown to be effective in
removing approximately 90 percent of exhaust aldehydes.[79,80,
93,94] Much research has been performed regarding the parameters
which influence aldehyde formation in gasoline engines, with low
exhaust temperatures and high oxygen concentrations identified as
leading to higher formaldehyde formation rates, and this knowledge
should facilitate aldehyde control in future engine
designs.[92,95] Aldehyde emissions from methanol combustion in
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-48-
diesel engines are also expected to be greater than from diesel
fuel combustion. Additional work on the control of aldehyde
emissions from methanol engines would be beneficial.
The last benefit of methanol engines to be discussed concerns
sulfur emissions. Because of the way methanol is produced it
contains essentially no sulfur. And, if there is no sulfur in the
fuel, no emissions of sulfur-bearing compounds, such as sulfur
dioxide, sulfuric acid, or hydrogen sulfide, can occur. This is a
slight improvement over gasoline emissions, since gasoline does
have a small amount of sulfur in it. Catalyst-equipped gasoline
engines currently emit between 0.005 and 0.03 grams per mile of
sulfate and this would disappear with the use of methanol, even if
catalysts were still used.
The improvement over the diesel, however, would be more
pronounced. Diesel fuel currently contains 0.2-0.5 percent sulfur
by weight. This translates into about 0.25 grams per mile of pure
sulfur from diesel trucks (0.5 grams per mile of sulfur dioxide,
or 0.75 grams per mile of sulf ate, equivalent). Diesel ;cars emit
about one-fifth; this amount, since the sulfur level in diesel
fuel is expected to rise in the future, these emission levels
would also rise in the future. With the use of methanol these
emissions would; disappear altogether. I
A very important secondary effect of removing sulfur from
automotive fuel should be mentioned. Along with lead, phosphorus
and trace heavy metals, sulfur is one of the more significant
deactivators of automotive catalysts (as was mentioned earlier).
The presence of these elements is the main reason why precious
metal catalysts, such as platinum and paladium, have been
necessary. Base metal catalysts, such as iron, copper, nickel,
etc., have been shown to be effective but are deactivated too
quickly. With methanol, however, not only sulfur, but all of
these elements, are removed in production. Thus, catalysts on
methanol engines may be able to be of the base metal variety and
not include precious metals. This would be a significant economic
benefit, since all of our precious metals are currently imported.
B. Fuel Efficiency
The fuel efficiency aspects of using methanol as a fuel will
be discussed next. Methanol's effect on the thermal efficiency of
an engine will be the focus of discussion, as opposed to its
effect on fuel economy (i.e., miles per gallon), since methanol's
energy density (Btu's per gallon) differs drastically from
petroleum-type fuels. This will be consistent with the next
section of the presentation concerning economics, which will focus
on the cost per Btu of producing and distributing fuels.
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-49-
For simplicity of presentation, the discussion will be split
into two parts. The first will discuss the effects of using
methanol on the thermal efficiency of spark-ignition engines
(e.g., the gasoline engine). The second will present the same for
compression-ignition engines (e.g., the diesel engine).
There is general agreement among researchers that methanol is
a more energy efficient vehicle fuel than gasoline. There are
several theoretical reasons why this is so. Methanol's lower
,flame temperature reduces the amount of heat transfer from the
combustion chamber to the vehicle coolant system. Its high heat
of vaporisation acts as an internal coolant and reduces the
mixture temperature during the compression stroke. These
characteristics increase a methanol engine's thermodynamic
efficiency, and are realized in experiments without having to make
any major design changes in current gasoline engines. Studies
have shown these inherent properties of methanol to increase the
energy efficiency of a passenger vehicle by 3 to 10 percent with a
middle range of about 5 percent.[79,82,83]
Other properties of neat methanol combustion allow even
greater efficiency improvements. Its wider flammability limits
and higher flame speeds relative to gasoline allow methanol to be
combusted at leaner conditions while still providing good engine
performance. This lean burning capability decreases the peak
flame temperature even further and allows more complete
combustion, improving energy efficiency. Early testing on a
single-cylinder engine yielded estimated energy efficiency
improvements of 10 percent due to leaning of the methanol mixture
as compared to gasoline tests.[96] subsequent vehicle testing has
shown relative efficiency improvements of lean methanol combustion
of 6 to 14 percent.[78,79] Given these results, it would appear
that methanol's lean burning capability yields approximately a 10
percent efficiency improvement over and above the 3-10 percent
improvement mentioned above. Of course, stratified charge engines
have been developed to allow leaner combustion of gasoline as
well, and this efficiency advantage of methanol- would be minimized
with respect to a stratified charge engine.
Methanol's higher octane number allows the usage of higher
compression ratios with correspondingly higher thermal
efficiencies. Early single-cylinder testing has estimated the
thermal energy efficiency improvements of the higher compression
ratios to be in the range- of 16 to 20 percent. [84,96]
Unfortunately, little vehicle data exist to confirm these figures,
but it must be expected that improvements of at least 10 to 15
percent are likely.
Adding up the possible improvements indicates that methanol
engines may well be 25 to 30 percent more energy efficient than
their gasoline counterparts when the'methanol engine is designed
specifically for methanol. Volkswagen has reported energy
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-50-
efficiency improvements of approximately 15 percent for its
mid-1970's vehicles modified to run on methanol, with a
corresponding power output increase of about 20 percent.[97]
While it is true that emission concerns may force some tradeoffs
in terms of efficiency, it is also true that, so far, methanol
vehicle data have been taken with modified gasoline-fueled
vehicles. As with emissions, time and resources will allow much
methanol-specific optimization which should improve the energy-
efficiency of methanol-fueled spark ignition engines even further.
Before moving on to discuss the effect of methanol on the
efficiency of compression-ignition engines, it should be noted
that the above-stated 25 to 30 percent unprovement in the
efficiency of gasoline engines is about the same efficiency
advantage that is usually quoted for the diesel engine over the
gasoline engine. While the relative fuel economies of diesel and
gasoline-fueled vehicles may often show a larger advantage for the
diesel, it must be remembered that diesel fuel contains 10 percent
more energy per gallon than gasoline and that the performance of
the diesel is not always the same as the gasoline engine being
compared. Thus, with methanol, it may indeed be possible to
attain the fuel efficiency of the diesel without its physical size
and weight and without its noticeable smoke, odor, noise, and
particulate emissions.
As was true with the amount of information available on the
emissions of methanol-fueled compression-ignition engines, there
is limited data on the fuel efficiencies of such engines. The
most comprehensive data involving neat methanol in a diesel engine
is from the MAN-FM direct injection diesel engine which utilizes
spark ignition and a unique type of mixture formation. Ihe
majority of the methanol is deposited on the wall of the spherical
combustion chamber in the piston. „• Ihe methanol evaporating from
the film forming on the wall is successively fed into the flames
by the air rotating in the combustion chamber, with most of the
heat necessary for evaporation supplied by flame radiation.
Initial tests of this design were conducted in a non-commercial
air-cooled 4-cylinder engine in a small cross-country military
vehicle. Results over an unspecified test cycle showed an energy
efficiency improvement of 12 percent with methanol as compared to
operation on diesel fuel. Ihe same design was then utilized in a
6-cylinder engine installed in a commercial city bus. with a
low-speed stop-and-go test cycle to simulate urban traffic
conditions, the bus yielded 5 percent better energy economy with
methanol than with diesel fuel. Previous testing had indicated
that methanol's efficiency advantage over diesel fuel would likely
be greater at heavier loads.[98]
A second set of data involving neat methanol (with 1 to 2
percent castor oil for lubricity) utilized a 3.9-liter,
four-cylinder engine with glow plugs to initiate ignition, a
design concept which takes advantage of the high detonation
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-51-
("knocking") resistance and low surface (or "hot spot")
pre-ignition resistance of methanol.[77] (While methanol requires
higher air-fuel mixture temperatures to self-ignite, the presence
of a hot surface has been shown to trigger pre-ignition of
methanol to a greater extent than for other fuels. This is likely
due in part to the dissociation of methanol at high temperatures
to carbon monoxide and hydrogen, with the latter breaking down
into various radicals triggering pre-ignition.[99] While this
surface ignition phenomenon would be of some concern in a
spark-ignited engine because of the possibility of the center
electrode of. the spark plug promoting pre-ignition in advance of
the spark, it might be advantageously utilized in a compression
ignited engine to initiate combustion.) Steady-state tests with
this engine have shown significantly higher brake thermal
efficiencies for methanol compared to diesel fuel above 30 percent
load, ranging as high as 22 percent greater, while diesel fuel was
more efficient at lower loads.[77] One other study, utilizing a
single-cylinder, dualfuel engine (methanol and diesel fuel)
reported slightly higher efficiency for methanol, while two other
dual fuel studies, one with a single-cylinder engine and the other
with a 6-cylinder turbocharged engine, also showed methanol to be
somewhat more efficient at higher loads but similar to diesel fuel
at lower loads.[85,86,89]
It cannot be overstated that much work needs to be done in
the area of methanol use in diesel engines. The primary problem
has been the initiation of combustion, and researchers continue to
examine several solutions including pilot fuels (usually diesel
fuel), glow plugs, spark ignition, cetane-improving additives,
etc. Based on the early engine results reported above and the
huge opportunity for basic improvements in this area, it seems
likely that, should methanol prove feasible in diesel engines, it
will actually be a slightly more energy efficient fuel. Even if it
should only match diesel fuel in cycle efficiency, it would still
provide many environmental benefits (primarily-particulate and NOx
emissions reductions) compared to diesel fuel.
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V. Economics of Production and Use
There have been many studies undertaken in the last five to
ten years to determine and compare the costs of producing and/or
using synthetic fuels (including methanol). However, a
superficial review of the conclusions of these studies would
quickly reveal that there is a wide variety of conclusions and
recommendations being put forth.
We have analyzed a large number of these studies to date and
have found a number of reasons why this is so. One, the economic
bases used by the various studies often differ, affecting costs by
as much as 100 percent. Two, each study uses the best information
available at the time of the study. Since the product mixes,
efficiencies and costs of many of these processes, especially the
direct liquefaction processes, change frequently as more is
understood about the process, studies performed even 2 or 3 years
ago cannot be compared to the latest studies. This is especially
true in cases where jLnformation was at first totally lacking and
assumptions had to be-made.
We have attempted to go back in each instance to the original
engineering studies to assess the reasonableness of the cost
estimates. We also have compared the available designs of each
process to ascertain which are out-dated or based on now
inaccurate assumptions. After doing this, placing everything on
the same economic basis, and adjusting for plant size, we have
found surprisingly good agreement within each process. For some
processes, for example, ECS, this is not surprising since there is
really only one spokesman for the process details, Exxon. For
others, though, such as methanol production where there are many
cost estimates, most of the differences can be attributable to
differences in gasifier/synthesis technology. in those cases
where there is only one spokesman, we have attempted to compare
the results to^ other similar processes to insure that the
assumptions and estimates were reasonable. This last step has not
yet been completed as there are some significant economic
differences between the processes which are not totally
explainable as of yet. These will be highlighted below as the
pertinent costs are described.
The results of this analysis indicate that methanol from coal
will, be less expensive than transportation fuels from direct coal
liquefaction. However, several caveats could affect this
conclusion. This analysis did not attempt to standardize the
engineering techniques used by the outside references in deriving
costs. These may differ and assumptions about such factors as
reliability, redundancy and process designs, have not been
examined. The analysis only standardized economic assumptions.
However, the level of engineering design applied in each study was
a factor considered in arriving at the best cost estimates for
each technology. Thus, the cost estimate for each technology
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represents the greatest degree of engineering detail available at
this time, The final answer will, of course, remain unclear until
commercialization and the conclusions of this economic analysis
must be considered preliminary.
While the difficulties and apparent discrepancies described
above primarily involve the costs of producing synthetic fuels,
the overall economic picture involves more. The entire process of
producing synthetic fuels and using them in motor vehicles will be
broken down into three areas. The first area consists of the
production of a usable liquid fuel from raw materials. The second
area consists of distribution of this fuel. Finally, the third
area includes the use of these fuels in motor vehicles.. All costs
will be presented in 1981 dollars.
In the first two sections, the costs of producing and
distributing all synfuels will be determined on a per energy basis
($ per million Btu (mBtu)). However, it must be remembered that
the total amount of energy being produced and delivered will be
different for the various fuels being examined. Specifically,
engines running on methanol are expected to attain fuel
efficiencies 25-30 percent higher than that of a gasoline engine
and equal that of a diesel engine. To be conservative here, since
there are no production methanol engines yet to confirm this
improvement, only a 20 percent increase in efficiency will be
used. Assuming that the amount of vehicle miles travelled remains
constant, the total amount of energy consumed in the form of
methanol would be 16.7 percent less than would have occurred if
gasoline were the fuel. This energy (and cost) savings will be
considered in the third section and will be presented in the form
of an annual fuel savings. :
A. Production
Determining the economics of the production of usable
synthetic liquid fuels is probably the most difficult of the three
areas to be examined here. As mentioned above, we have attempted
to go back to the original engineering studies and place all of
the costs on the same engineering and economic bases. The
engineering and financial bases that have .been chosen are shown in
Tables 8 and 9.
As shown in Table 8, two different sets of financial
parameters were chosen. These were selected from a survey of
recent studies(9,58,75,100,101,102] done on coal liquefaction
processes and represent two extreme cases for- capital charge. The
low capital charge rate and accompaning parameters were chosen
from the ESCOE[9] report while the high capital charge data .were
taken from the Chevron Study.[100] The important factors yielding
these two CCRs are also shown in Table 8.
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-54-
Financial Parameters
Capital charge Rate,
Percent
Debt/Equity Ratio
Discounted Cash Flow
Rate of Return on In-
vestment, Percent
Project Life, Yrs.
Construction Period, Yrs.
Investment Schedule,
%/Yr.
Plant Start Up Ratios
Debt Interest, Real
Rate, percent *
Table 8
Common Financial Parameters
Low Cost case[9]
11.5
40/60
Not Available
20
4
9/25/36/30
50, 90, 100...
10
Investment Tax Credit, % 9
Depreciation Method sum of Year's Digits
Tax Life, Yrs. 15
Interest Rate During 6
Construction,Percent *
High Cost Case[100]
30
0/100
15
20
4
10/15/25/50
50/100
10
Sum of Year's Digits
13
6
* Excludes the effect of inflation. All calculations performed
in constant 1981 dollars.
-------
Table 9
Process Cost Inputs and Other
Factors Common to All Studies
Cost Inputs and Other Factors
Product Yield
Coal
a) Bituminous
b) Subbituminous
c) Lignite
Operating Costs
a) Utilities
b) Working Capital Interest
c) Fuel Cost
Scaling Factors
a) Capital Costs
b) Labor Costs
c) Maintenance, Taxes,
Insurance, General
ci) Coal, Catalysts and
Chemicals, utilities,
Fuel, Natural Gas
By-Product Credit
a) sulfur
b) Ammonia
c) Phenol
Contingency factor
Inflation Rate
a) 1976
b) 1977
c) 1978
a) 1979
e) 1980
Real Cost increases (%/year)
a) Fuel Oil
b) Natural Gas
c) Coal
Value
50,000 FOEB/CD
$27.50/ton
$17.00/ton
$10.00/ton
$0.035/kw-HR
6% of working
capital per year,
$35/bbl
0.75
0.20
Same percentage
of plant invest-
ment as specified
by each indiv-
idual studi.
Amount varies
directly propor-
tional to plant
size.
$50/ton
$180/ton
$112.6/bbl
15%
5%
6%
7%
9%
9%
2%
2%
0%
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-56-
The investment schedules which were published for each of
these two sets of parameters were also chosen for this report.
These are also shown in Table 9. The investment adjustment factor
is multiplied by the instantaneous capital to get the full-life
capital cost investment for a plant scheduled to begin production
in 1990. The real opportunity cost of the investment used was 6
percent per year.[75]
Table 9 shows the remaining input factors. All plants were
normalised to 50,000 fuel oil equivalent barrels per calendar day
(FOEB/CD)(one FOB equals 5.9 mBtu, higher heating value). The
costs selected for bituminous, subbituminous and lignite coals are
respectively $27.50, $17.00, and $10.00 per ton. Because capital
costs do not usually vary in direct proportion to plant size, a
scaling factor is normally used (an exponent) to modify the ratio
of plant sizes (by yield). The scaling factor used here was 0.75,
which is an average of factors found from various
studies.[75,102,103,104] To adjust labor and supervision costs a
scaling factor of 0.2 was used. [9,103] The rest of the operating
costs were assumed to vary directly with plant size. The
inflation rate for adjusting the costs of studies to $1981 was
based on the Chemical Engineering plant cost index.
The costs of producing finished products from five synthetic
fuel processes (from coal) will be presented below: EDS, H-COAL,
SRC-II, methanol, and MTG. The costs and their sources of each
will be presented in the order shown above and then compared as
much as possible. Following this, the cost of producing methanol
from wood will be discussed briefly.
EDS: There have been a number of reports and papers
presented in the literature which discuss the economics of the EDS
direct liquefaction process or simply present the cost of the EDS
products.[9,45,75,105] These reports include the ICF and ESCOE
studies mentioned earlier. All of these reports were based on the
1975/1976 study design prepared by Exxon Research and Engineering
(ER&E).[106] All of the economic figures presented here are based
on the most recent study design published by ER&E in March,
1981.[48] This recent study design covered the conceptual design
of an EDS coal liquefaction commercial plant feeding Illinois No.
6 bituminous coal. This design depicts the state of EDS
technology in 1978 as this technology' might be applied in a
commercial facility.[48] About 20 man-years of effort were
required for this work.[48]
Table 10 presents an economic summary of the capital and
product costs for the EDS direct liquefaction process. The total
instantaneous plant investment as presented in the most recent
Exxon study design was used and then placed on a consistent
economic basis with the other liquefaction technologies being
compared in this study, product costs based on two different
capital charge rates (CCR) (11.5 and 30 percent) are shown. With
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Table 10
Direct Liquefaction Product Cost Estimates
(Millions of 1 Q 1981 Dollars)
11.5% CCR*
Millions of Dollars EDS
Total Instantaneous**
Investment 2649
Annual Capital Charge 345
Annual Operating Cost 424
Total Annual Charge 769
Liquefaction
Product Cost
$/FOEB of Product 42.16
$/mBtu of Prod. 7.15
H-Coal
3300
430
302
732
35.34
5.99
SBC-II
3400
440
346
786
41.60
7.05
EDS
2649
887
424
1311
71.83
12.18
30% CCR*
H-Coal
3300
1100
302
1402
67.67
11.47
SBC-II
3400
1140
346
1486
80.00
13.56
* CCR = Capital Charge.
** investment if all capital equipment were purchased and
installed in one day, i.e., an instant plant.
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a capital charge rate of 11.5 percent the product cost is
$42.16/FOEB ($7.15 per mBtu). With a 30 percent capital charge
rate the product cost is $71.83/FOEB ($12.18 per mBtu).
Table 11 presents a breakdown of the investment and operating
cost for the EDS liquefaction plant. The total instantaneous
investment in first quarter (1Q) 1981 dollars is $2.65 billion.-
The total annual operating cost per year is $452 million before
taking a byproduct credit of $28 million. Coal represents about
50 percent of the operating costs while repair materials account
for 21 percent and utilities 14 percent.
Table 12 presents a breakdown of the annual capital charge
and operating costs as a percentage of product cost. With a CCR
of 11.5 percent the annual capital charge accounts for 42 percent
of the product cost while coal accounts for 29 percent. With a
CCR of 30 percent the annual capital charge accounts for 65
percent of the product cost with coal accounting for 17 percent.
It should be noted that none of these costs include the cost of
refining. For all three direct liequefaction precesses, the
refining costs will be presented later and then included in a
summary table.
H-Coal; The cost estimates of the H-Coal product was based
on cost estimates of a 50/000 barrels per day commercial plant by
Ashland Oil.[44,46] A few other studies have also determined
product costs for H-Coal.[9,75,106] However, the Ashland analyses
should best represent the product costs of H-Coal liquefaction,
primarily because the Ashland studies are very recent (1981) and
have a more accurate description of the process costs. Although
another study performed by EPRI is also recent (1979), the
projected technology and costs have changed dramatically even
within those two years (i.e., from 1979 to 1981). Costs
associated with the updated technological and process developments
have escalated much more rapidly than inflation. Thus, the
Ashland product costs should be the most accurate available to
date. These costs were then adjusted using the common financial
and engineering parameters shown in Tables 8 and 9.
Table 13 shows the capital and product cost estimates. The
instantenous capital investment, which. includes a 15 percent
contingency and a refinery cost for light naphtha to reformats
(does not duplicate later refinery costs) is $3.3 billion. The
annual operating costs, as estimated by Ashland, are $134 million
which does not include feedstock costs and capital recovery. The
annual capital recovery, with the adjustment lifetime investment
from instantaneous investment, and with the appropriate capital
charge rates, is $0.43 - $1.10 billion (depending on the CCR).
The feedstock cost is estimated to be $181 million per year, and
by-products credits amount to $13 million per year. The total
annual cost is estimated to be $732 million to $1,402 million per
year. Total product cost is $35.34-67.67 per FOEB/CD, depending
on the CCR ($5.99-11.47 per mBtu)(see Table 10).
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Table 11
EDS Investment and Operating Costs (1st Q 1981 Dollars)
50,000 FOEB/CD
Investment Cost
(Millions of Dollars)
Onplot Investment 1281
Offplot Investment 780
ER&E Charges 60
Subtotal 2121
Contingency 309
Total Instantaneous Plant Investment 2430
Working Capital and Startup Costs 219
Total Instantaneous Capital
Investment 2649
Operating Cost
(Millions of Dollars
Per Year)
Capital-Related
. Interest on Working Capital 7.1
Repair Materials 114
. ^
Salaried and Related Costs
Wage Earners 34.7
Salaried 9.1
Overhead, Supplies, etc. 8.S
Coal 210
Catalyst & Chemicals 8.6
Utilities, Power 59.7
Subtotal " 452
By-product Credits
Sulfur 12.8
Ammonia 5.4
Phenol 10.0
Annual Operating Cost 424
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-60-
Table 12
Liquefaction Product Cost Breakdown, % of Cost
11.5% CCR*
Annual Capital
Charge
Coal
Repair Materials
Plant Maintenance
Utilities, Cata-
lyst and Chem-
icals
Labor & Super-
vision --
Local Taxes
and Insurance
Overhead, Sup-
plies
Other
EDS
42
28.9
6.3
-
9.4
5.3
5.6
1.1
4.8
H-Coal
58
24.6
-
6.6
0.7
1.6
7.1
1.9
1.0
SCR-II EDS
56 65
16.4 17.4
4.1
. _
5.6
3.2
3.4
0.6
39.7** 2.9
30% CCR*
H-Coal
78
12.9
-
3.4
0.4
0.8
3.7
1.0
0.5
SRC-II
77
8.6
-
-
-
-
-
14. 5*1
Byproduct Credit (3.9) (1.8) (1.7) (2.3) (1.0) (0.9)
* CCR = Capital Charge Rate.
** these include the annual operating costs other than feedstock
costs. For SRC-II, annual operating costs could not be
broken down further, based on available data.
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-61- :
Table 13
H-Coal Investment ana Operating Costs (1st Q 1981.Dollars)
Ashland Case 50,000 FOEB/CD
Investment Cost
(Millions of Dollars)
Direct costs
Liquefaction Plant 690
Oxygen and Hydrogen Plants 320
Other Refinery Units 125
Tankage, Interconnecting Piping 120
Coal Handling, Boilers 360
Wastewater/Solids Treating 200
Other Offsites 185
Field Indirect Cost 400
Miscellaneous Field Costs 80
~.Engineering and Fee 280
Subtotal 2760
Contingency 400
Total instantaneous Investment 3160
Working Capital 140
Total Instantaneous Capital Investment 3300
Operating Costs • •> ,.
(Millions of Dollars per Year)
Coal , - 181
Plant Maintenance 43.9
Salaried and Related Costs
Direct Labor and supervision 10.7
Overhead, Supplies, etc. 12.5
Power, Catalyst, and Chemicals 4.6
Indirects, G & A 7.0
Local Taxes and Insurance 47.5
Interest on Working Capital 7.6
By-Product Credits
Sulfur 0.1
Ammonia 13.0
Phenol 0.4
Annual Operating Costs 302
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-62-
SRC-II: The cost estimates of the SRC-II product were based
on cost estimates by DOE and Pittsburg and Midway Coal Mining
(P&M).[51,63,64] The latest cost estimates from DOE and P&M were
based on 1981 cost estimates of the 6000 TPD demonstration plant
that was to be constructed in Morgantown, West Virginia. The cost
estimates of the demonstration plant were then scaled up to a
50,000 FOEB/CD commercial size plant (see Table 14). Although an
EPRI study also performed a detailed cost analysis of the SRC-II
process,[107] their cost estimates were mid-1976 estimates and
could not simply be inflated to 1981 dollars ^because of the rapid
increase in process costs due to actual design changes and not
simply inflation.
The product and capital costs for SEC-II are shown in Table
10. The capital costs amount to $3.4 billion dollars when scaleo
to a production of 50,000 FOEB/CD, including a 15 percent
contingency factor.[51] With the appropriate capital charge rate,
the annual capital recovery cost is $440-$!,140 million. The
annual operating cost is $346 million, not including a feedstock
cost of $168 million per year. By-product. credit is about $17
million per year. The total annual cost is $760-$!,460 million.
The average product cost is $41.60-80.00 per FOEB ($7.05-13.56. per
mBtu)(see Table 10).
Syncrude Refining; Investment and operating costs for coal
liquid refineries have been reported in a few different studies.
Cost estimates for SEC-II syncrude have been made by Chevron and
ICF.[59,75] Cost estimates for H-Coal syncrude have been made by
UCP, ICF, and Exxon.[60,75,108] The only estimate available for
the EDS syncrude was made by ICF.[75] Also Exxon has prepared a
rough study which presents a range of costs^ for upgrading a coal
liquid in general.[ 109 ] '•'.'•
The economic basis for the refining costs is identical to the
basis discussed previously, except that the plant size for the
refineries was adjusted to a feedrate of 54,500 BPCD using a
capital scaling factor of 0.75.
An analysis of the Chevron/SEC-II- "and UQP/H-Coal studies
indicated that they were based on a significantly higher level of
engineering design than the other studies. Thus, their cost
estimates were used to estimate the refining costs for the SKC-II
and H-Coal syncrudes. since no detailed study was available on
the refining of the EDS syncrude, this needed to be estimated,
similar to the situation earlier with refining efficiency and
product slate. The ICF study mentioned earlier did address EDS
refining, but in much less detail than Chevron or UQP.[75] ICF's
EDS refinery only hydrotreated the various straight-run products
and used natural gas to produce the necessary hydrogen.[75]
Neither the resultant efficiency nor the product slate was
comparable to the chevron or UOP refineries, so the ICF results
were not used. Instead, estimates of the EBS efficiency and
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-63-
Table 14
Cost Estimates for SCR-II
(Millions of 1st g 1981 Dollars)
6000 TPD
Demonstration Plant
Design
Construction
Start-up
Contingency
(15 percent)
Total Lifetime Capital Lost*
Average Annual
Operating Costs
Feedstock Costs
Bi-prcduct Credit
292
1415
286
299
2292
160
59
6
50,000 FOEB/CD
Commercial Plant
632
3058
619
647
4956
320
168
17
Not instantaneous capital
schedule and interest rate.
cost. Uses DOE construction
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-64-
product mix were based on the Chevron and UGP results, with
respect to refining costs the ICF estimates appeared very
reasonable compared to the Chevron and UQP results for the 30
percent CCR, but not the 11.5 percent CCR. Thus, an interpolation
of the Chevron and UQP costs was used instead of the ICF cost
estimates.
Table 15 presents the economic summaries of the investment,
operating, and refining costs in first quarter 1981 dollars for
the three coal liquid refineries. The operating costs do not
include the cost of the syncrudes. The refining cost per mBtu of
refined product for the SRC-II/ H-Coal, and EDS syncrudes are
$1.84, $1.06, and $1.31 for the 11.5 percent CCR; and $3.80,
$2.10, and $2.58 for the 30 percent CCR, respectively.
These refining costs can now be added to the liquefaction
costs to obtain an overall cost of producing finished products.
These overall, or average, costs can then be allocated among.the
various products in a manner that will simulate their market
demand (i.e., more costs per mBtu are allocated to those products-
which will demand higher market values). However, the first step
is not simply a matter of adding the average liquefaction cost ($
per mBtu) to that for the refining. First, not all of the
liquefaction products go through the refinery so the refinery cost
should not be added to them. Second, some of the liquefaction
product is lost in the refinery (it is not 100 percent efficient)
and its cost must be included.
While accounting for these two factors is a simple algebraic
matter, allocating costs among the various products is more
difficult. There is no right answer since no one can-exactly
predict the future.' ' Fortunately, all the ' processes being
discussed here produce a large amount of gasoline (or methanol)
and changes in the relative values of the other products will not
have as large an effect as it would if the processes were
producing large amounts of medium-Btu gas, residual oil, etc.
It is generally appropriate to attempt to allocate the costs
of processing in accordance to the expected market values of the
various products. To do otherwise would be to mislead oneself
that the premium products of a process were relatively inexpensive
(while the low quality products would also be misleadingly
expensive). Thus, some relationship between the values of the
various fuels was needed in order to determine representative
costs for each fuel.
A product value approach was utilized here to estimate costs
for individual products. This technique assumes that future
energy prices for particular products will maintain a fixed ratio
to each other. All prices are normalized relative to a reference
product, which here was chosen to be gasoline. In this report, a
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Table 15
Refining Cost Estimates
(Millions of 1 Q 1981 Dollars)
11.5% CCR* 30% CCR*
Millions chevron/ UQP/ Chevron/ UOP/
of Dollars sac-Ill51] H-Coal[52] EDS SBC-II[51] H-Coal[52] EDS
Total instan- 781 454 - 781 454
taneous Invest-
ment
Total Adjusted 1034 602 - 1022 595
Capital Invest-
ment
Annual capital
Charge
Annual operat-
ing Cost
Total Annual
Charge
Refining Cost:
$/bbl of
Product
4/mBtu of
Product
119
58
177
9.76
1.84
69
42
111
5.75
1.06
307
58
364
6.90 20.13
1.31 3.80
178
-42
220
11.41
2.10
"
-
-
15.22
2.58
* CCR = Capital Charge Rate,
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relationship between various fuels similar to that reported in the
ICF report was used and is as follows:
1. If the cost of unleaded regular gasoline is $G/mBtu,
2. The cost of No. 2 fuel oil is (0.82) (G)AiBtu, ana
3. The cost of LPG is (0.77)(G)/mBtu.[75]
Since unleaded premium gasoline is produced in some cases (EDS and
H-Coal), a relationship between this fuel and regular gasoline is
necessary. Since.a history of the relationship between these two
fuels was not readily available, a history of the cost ratio of
leaded premium to leaded regular gasoline was used. This
relationship indicated a cost ratio of 1.075.[110] This product
cost relationship was then applied to premium and regular unleaded
gasoline.
A price relationship between SNG and the reference was also
needed. This may be determined by assuming that SNG will have the
same relationship to gasoline as natural gas. However/ the
well-head price of natural gas is just in the process of being
deregulated; therefore, it is incorrect to use the current
gasoline/ natural gas price relationship. Instead, a method used
by Mobil, and a method which relates the natural gas price to that
of No. 2 fuel oil were both utilized. These two methods are
described below.
As discussed earlier, one of the scenarios examined by Mobil
was the co-production of SNG and gasoline. [10] To obtain a
realistic value for the SNG produced, Mobil estimated the cost of
SNG from a coal-gasification plant producing essentially 100
percent SNG. Using this cost for SNG, they then allocated the
remaining cost to the gasoline. The result was that the SNG cost
77 percent as much as the gasoline on an energy basis (i.e., it
was cheaper on an energy basis to produce SNG solely than to
co-produce SNG and gasoline).
Another technique to obtain a representative SNG/gasoline
cost relationship is to assume that SNG has the same value as NO.
2 fuel oil. This is reasonable since both have at least one large
common market in industrial and domestic heating. Using this
method, the cost ratio of SNG to gasoline would be the same as
that for No. 2 fuel oil, 0.82.
Since the two techniques yielded very similar results, it was
decided to average the two cost ratios. Therefore, the
SNG/unleaoed gasoline cost ratio used in this report is 0.80.
Table 16 shows the results of combining the costs of
liquefaction and refining and of allocating these costs among the
various products. (Also shown are the costs for methanol and MTG
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Table 16
Product and Capital Costs of Coal
Liquefaction Processes(1981 Dollars)
Product Cost capital
($ABtu) cost **
Process
Direct Liquefaction
EDS (Bituminous)
H-Coal (Bituminous)
SEC-II (Bituminous)
indirect
Liquefaction
Texaco (Bituminous)
Koppers (Bitum. )
Lurgi (subbit.)
Modif ieo. Winkler
(Lignite)
Lurgi Mobil MTG
(Subbit.)
Product Mix
32.7% Reg. Gasoline
14.0% Prem. Gasoline
25.6% NO. 2 Fuel Oil
9.6% LPG
18.1% SNG
33.1% Reg. Gasoline
11.2% Prem. Gasoline
20.4% No. 2 Fuel Oil
22.3% LPG
13.0% SNG
64.7% Gasoline
12.1% LPG
23.2% SNG
100% MeOH*
100% MeCH*
47.9% MeOH*
49.7% SNG
2.4% Gasoline
100% KeCH*
41.2% Reg. Gasoline
53.3% SNG
5.5% LPG
11.5%
CCR
$10.00
$10.80
$ 8.20
$ 7,70
$ 8.00
$ 7.79
$ 8.37
$ 6.38
$ 6.00
$ 6.23
$ 9.87
$ 7.60
$ 7.90
5.90-6.48
7.23
7.04
5.63
7.04
,5.70
8.01
6.41
6.25
30% (Billions
CCR of Dollars)
$17.29 $2.65
$18.67
$14.18
$13.31
$13.83
$14.97 $3.30
$16.09
$12 .27
$11.52
$11.97
$19.06 $3.40
$14.68
$15.24
9.44-10.41. 1.99-2.21
12.42 2.92
12.48 2.59
9.98
._12.48
9.56 2.17
14.35 2.95
11.48
11.20
MObil MTG
incremental cost
85-90% Reg. Gasoline
10-15% LPG
1.45
2.87
0.68
* hear = 95-98% methanol, 1-3% water, and the remainder higher
alcohols.
** capital costs are instantaneous costs and do not include
refinery capital costs.
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gasoline, vvhich are discussed below.) Comparison of these direct
liquefaction costs will be delayed until the methanol and WTG
gasoline costs have been presented.
Methanol; To estimate the cost of producing methanol,
thirteen independent studies from nine reports[7,10,16,54,55,56,
57,58,111] were normalized to a production yield of 50,000 FOEB/CD
and inflated to $1981 according to the financial assumptions
previously mentioned (Tables 8-9). Of these thirteen studies,
nine used bituminous coal, two used subb it ominous coal and two
used lignite to produce the methanol. The studies included eight
different coal gasification technologies (Foster Wheeler,
BGC/Lurgi, Koppers-Totzek (2), Texaco (4), Lurgi (1), "slag-bath"
(1), modified Winkler (2) and Koppers-Shell) and four different
types of methanol synthesis units (Lurgi (2), ICI (5), Chem
Systems (5), and Wentworth Bros. (1)). As previously mentioned
only the Winkler, Lurgi and Koppers-Totzek gasifiers are proven on
a commercial scale and the Texaco process is very close to
commercialization, of the synthesis units, ICI and Lurgi are used
extensively today. Wentworth Bros, claim that their process is
commercial and Chem systems is a new process which is still being
tested. [112] Lurgi and ICI have been competing for the last ten
years and both have highly developed processes, good efficiencies
and, according to EPRI,[7] room for further improvement is small.
In addition, EPRI states that the Chem Systems process only shows
a slightly higher thermal efficiency and lower capital cost than
the ICI system. Since the costs of the proven ICI and Lurgi
synthesis processes are indistinguishable and it appears that the
cost for the Chem Systems process is only slightly lower, it has
been cecided to place most of the emphasis here on the effect of
the various gasification technologies which appear to have
significant effects on costs.
The original range of product and capital costs reported by
the- thirteen studies are very large due at least in part to the
large range in plant size ($3.74-12.55 per mBtu for product cost
and- $0.401-$5.05 billion for capital, $1981, for plants ranging
from 2,000-58,000 ton per day of methanol). with this type of
data it is very difficult to estimate the actual cost of methanol,
let alone compare it with any other coal technologies. After
normalizing the costs for the thirteen studies the ranges of costs
are much smaller. For bituminous coals the product cost ranged
from $4.65-9.05 per mBtu for the low CCR ana $8.14-12.54 per mBtu
for the high CCR. However, since four of these studies had to be
scaled up or down significantly (factor of three or
more)[55,56,57] it was decided to place the most emphasis on the
five remaining studies whose original designs called for methanol
plants producing near 50,000 FGEB/CD.
The range of methanol costs from these studies is much
smaller, $5.30-$7.23 per mBtu for low CCR and $8.74-$12.42 per
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mBtu for high CCR. The gasifiers used in these studies are
Foster-Wheeler, BGC-Lurgi, Koppers-Totzek, and Texaco(2). Since
the Foster-Wheeler and BGC-Lurgi gasifiers are still being
developed, it was decided to drop these two studies also. Thus,
three studies were left and their product costs are shown in Table
16.
The cost using the Texaco gasifier is $5.90-$6.48 per mBtu
for the low CCR and $9.44-$10.41 per netu for the high CCR. The
cost using the Kopper-Totzek gasifier is $7.23 per mBtu for the
low CCR and $12.42 for the high CCR. In retrospect, the resulting
price range of $5.90-$7.23 per mBtu for the low CCR and
$9.44-$12.42 per mBtu for the higher CCR lies approximately in the
middle of the original ranges of $4.65-$9.05 per mBtu and
$8.14-$12.54 per mBtu for the original nine studies.
Both of these reactors are entrained bed units which seems to
emphasize the statement that entrained bed gasifiers are the only
commercially-available reactors today which can economically
gasify eastern bituminous coals (seven of the original nine
studies used entrained bed gasifiers).
The capital cost range for the original nine studies was
$1.93-$2.92 billion (50,000 FOEB/OD plant), which was also the
same for the smaller group of five. As shown in Table 16, the
instantaneous cost for the methanol plant using bituminous coal
was $1.99-2.21 billion when the Texaco gasifier was used and $2.92
when the Koppers-Totaek gasifier was used.
The range of product and capital costs for methanol from
subbituminous coals and lignite are smaller than that of
bituminous. Of the two studies using subbituminous coals, one
uses a proven gasification and synthesis technology, Lurgi/
Lurgi,[10] while the other uses a gasification technology which
the manufacturer claims is "here and now," and a proven synthesis
process, modified Winkler/ICI.[58] The average product cost range
is fairly small, $6.16-$6.34 per mBtu for the low CCR and
$10,26-$ll .24 per inBtu for the high CCR. The instantaneous
capital investment range is $2.10-$2.59 billion. Although the
costs seem to compare favorably, only the Lurgi/Mobil prices are
shown in Table 16. This is because the modified Winkler/ICI plant
size had to be scaled up significantly where as the Lurgi/Mobil
plant size was much closer to the selected 50,000 FOEB/CD and was
therefore probably more accurate.
For lignite there was a slightly larger range of product cost
between two studies, $5.70-$6.92 per mBtu for the low CCR and
$9.56-$12.24 per mBtu for the high CCR. The range for capital
investment was $2.17-$3.00 billion. Since there was some question
as to whether the process of the one study [111] was commercially
available, the other study (modified Winkler/ICI,, [ 16 ]), for which
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its manufacturer is prepared to offer commercial guarantees, was
chosen. The costs from this study are shown in Table 16.
In sunanary, the prices which have been chosen for this study
represent two commercially proven gasification technologies,
Koppers-Totzek, Lurgi, a nodified Winkler, for which its
manufacturer will back financially, and the near commercial Texaco
gasifier. For bituminous coals, the Koppers-Totsek prices are
higher than Texaco because the first operates at atmospheric
pressure. In general, the prices for methanol decline as the rank
and cost of coal decline.
MTG;
To evaluate the cost of producing gasoline from coal
utilizing Mobil's methanol-to-gasoline (MTG) process, two
different studies [10,1131 were analysed in the same manner as the
methanol studies. Initially, it was assumed that an incremental
product cost and capital cost for Mobil's hTG gasoline relative to
methanol could be determined from both studies since methanol
costs (capital and product) were available for the same technology
by the same designers. [10,56] When the cost of gasoline was
compared to that of methanol, the incremental cost of gasoline for
both studies was very close, confirming the original assumption
also shown in Table 16.
The Mobil MTG gasoline prices from one of the studies[10] are
shown in Table 16 and should be compared to the Lurgi methanol
example because the methanol used was produced in that plant. The
product costs for gasoline, SNG, and LPG are respectively $8.01,
$6.41, and $6.25 per mBtu for the lower CCR and $14.35, $11.48,
and $11.20 per mBtu for the higher CCR. The instantaneous capital
investment is $2.95 billion. These prices result in an
incremental gasoline cost of $1.45 per mBtu for the lower charge
and $2.87 per mBtu for the higher charge. The incremental cost
for this plant is $0.34 billion. When comparing these incremental
costs with the other Mobil MTG process which does not produce any
SNG, the incremental product cost are the same and the incremental
capital cost is twice as large. This is logical since the
.incremental operating and raw materials costs and capital charges
for a process unit should roughly double with the doubling of
production, thus leaving the incremental product cost per mBtu the
same. Likewise, the capital investment would be expected to
double and this is why $0.68 billion which is twice the
incremental cost of the one half siie plant is listed. When the
incremental costs of gasoline are applied to the methanol costs,
the range for Mobil MTG gasoline would be $7.15-$8.37 per mBtu for
the lower CCR and $12.43-$15.11 per mBtu for the higher CCR.
Now that all of the product costs have been determined, a
comparison can be made. This comparison must be qualified by the
fact that no adjustment has been made between processes except for
-------
that already describee! (e.g., plant size, financial basis,
inflation). No attempt has been made to determine if one process
design was more thorough or conservative than another. We have
relied on the respective engineering firms for thoroughness,
accuracy, and good engineering judgment, it can be said that the
costs for the Mobil MTG process incremental to methanol were
confirmed by both Badger and Mobil, though- it is likely that
Badger used Mobil's basic design information. Also, the figures
for methanol were taken from a large number of studies, and do not
represent either the lowest or the highest cost designs. To go
beyond this point, one would need to do an in-depth engineering
analysis of each process detail, which would probably cost as much
as any one of the designs and is beyond the scope of this study.
The cost figures for all five processes are shown in Table
16. As can be seen, the capital costs range from $1.99 billion to
$3.4 billion. The methanol plants tend to have the lowest capital
costs ($2.0-3.0 billion), while that of the ELS process is in the
same range. Using the incremental cost of the MTG process, a
gasoline-from-coal plant would cost between $2.7 billion and $3.7
billion. The H-Coal and SBC-II processes are next at $3.3-3.4
billion each. (The capital costs do not include refinery costs
since it is unlikely that new refineries would be built.)
The product costs follow a similar pattern, though not
exactly. Speaking first of the low cost scenario, methanol is the
cheapest product, ranging from $5.70-$7.23 per mBtu for fully
commercial gasifiers and $5.90-$6.48 per mBtu for the
near-commercial Texaco gasifier. Gasoline via the Mobil MTG
process would be $1.45 per mBtu more, or $7.15-$8.68 per mBtu
using fully commercial gasifiers and $7.35-$7.93 per mBtu with the
Texaco gasifier. H-Coal gasoline costs at $7.79 per mBtu, while
SBC-II gasoline is projected to cost $9.87 per mBtu. Finally, EDS
gasoline is projected to cost the most of the automotive products
at $10.00 per mBtu.
A similar order holds for the higher cost scenario. However,
the absolute difference between methanol costs and the cost of
gasoline from the other processes increases because the capital
cost of the methanol plant is lower. The same is true for MTG
gasoline in most cases. A large change -occurs in the difference
between EDS and H-Coal process costs. While with the low CCR, the
EDS costs were 28 percent higher, with the high CCR, they are
about 15 percent higher. Also, SBC-II . has replaced EDS as the
process yielding the highest cost product. This is primarily due
to the higher capital costs involved for SBC-II.
In general, it would appear that the indirect coal
liquefaction processes can produce usable fuel cheaper than the
direct liquefaction technologies.
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Methanol from Wood; So far, onli methanol from coal has been
consideredand,indeed, most of the domestic methanol to be
produced for fuel will come from coal. While these coal-Lased
cost estimates will be used later in examining the overall
economics, it would be helpful to briefly examine the relative
cost of methanol from wood and to examine when methanol from wood
might be as economical as methanol from coal.
The conversion efficiency for methanol from wood is estimated
to be between 48 and 58 percent, which is achievable from
coal.[114,115] Some of the estimates for the cost of methanol
from wood (per mBtu) are $7.8 (SRI[30,68j), $8.9 (T. Reed[68]),
$10 (MITRE[25,68]) and $11.8 (Intergroup/Canada[68]), while the
latest figures for methanol from coal are $5.25-6.97/mBtu (for the
0.115 CCR) which were already presented.
A recent report by SERI has compared capital costs vs. plant
size (in terms of tons of methanol per day) using cost estimates
from the various studies available and has drawn a "best estimate"
line through these points.[68] Upon comparison of coal and wood
utilization, wood requires about the same capital investment for
smaller plants (a 2,000 ton per day methanol facility would cost
$220 million for wood and $238 million for coal) and then becomes
less expensive than coal for larger plants. However, this
advantage cannot effectively be realized, since wood cannot be
economically obtained in the large quantities exemplified by coal.
Although the production of methanol from wood will be limited
by capital and local wood availability, its economic feasibility
will ultimately depend on the relative price of coal and wood.
While methanol from coal plants will always be large to take
advantage of the economy of scale (15,000-60,000 tons
methanol/day), most methanol from wood plants will be relatively
small (600-10,000 tons methanol/aay) and limited to the amount of
readily available biomass. However, since the price of coal coula
rise faster than that of wood or wood refuse, it may be only a
matter of time before methanol from wood will become attractive
economically. As an extreme example, using the lowest previously
quoted price for methanol of $7.8/mBtu using wood at $30/ton and
$7/mBtu for coal at $27.5/ton (and typical relationships between
coal price and methanol price), wood could be competitive with
"coal when the price of coal was $40/ton and wood prices did not
increase. This will not happen overnight, but could occur by the
time .the forest industry could gear up for large-scale methanol
production near the end of this century.
5. Distribution
Since distribution systems already exist for gasoline, the
short-term economics in this area would, of course, favor the
continued use of this fuel over the introduction of methanol. in
addition, gasoline also has the advantage of possessing a higher
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-73-
energy density: 115,400 Btu/gal for gasoline compared with 56,560
Btu/gal for methanol. Because transportation costs depend
primarily on volume, gasoline would necessarily be less expensive
to transport per Btu on a long-term basis.
The costs of distributing a fuel can most easily be divided
into three areas? 1) distribution from refinery or plantgate (if
no refining is required) to the regional distributor, 2) distribu-
tion from the regional distributor to the retailer, and 3) distri-
bution by the retailer (i.e., the gas station). The economics of
these three aspects of distribution have been examined in a study
by EPA [116], the results of which will be discussed below.
It should be noted that some studies have also included
federal and state fuel excise taxes in the cost of distribution.
While it is true that excise taxes affect the price of fuel at the
pump, these taxes actually represent the cost of building and
maintaining roads rather than the cost of using a particular
fuel. , Taxing fuel is simply the way roost governments have chosen
to distribute the cost of the particular state or federal highway
system. As a switch to methanol should not affect the cost of
building or maintaining roads, excise taxes do not need to be
considered in this analysis. Also, as demonstrated by the current
case;with gasohol, excise taxes, or the waiver of them, may be
used! as an incentive to use a certain fuel.! Thus, besides being
technically unaffected by a switch of fuels, excise taxes can be
manipulated to encourage a public goal and are not even always
based on an equitable distribution of highway costs. Because of
these reasons, excise taxes will not be considered here.
1. Long-Range Distribution
TWO long-range distribution scenarios were analysed. One
represents the transportation costs (1000 miles) from a typical
synfuel plant located in the western U.S. (Wyoming)-, and the other
transportation costs from an eastern synfuel plant (Illinois) to
nearby narkets (100 and 300 miles). Longer pipelines would be
needed in the West since major markets are further from the coal
fields than they are in the East. The basis for the cost
estimates of transporting methanol was a studi by DHR, Inc.
[117]. Pipeline cost information contained in this study was then
used to estimate the cost of transporting synthetic gasoline.
In the eastern scenario, methanol was found to cost $0,56 per
mBtu to distribute to a bulk terminal via pipeline, and synthetic
gasoline was found to cost $0.37 per mBtu [116]. In the western
scenario, the cost of similar methanol distribution was estimated
to be $0.73 per mBtu compared to $0.50 per n£>tu for gasoline
[116]. Nationwide, assuming an equal number of plants in the East
and West, long-range distribution of methanol would cost an
average of $0.65 per mBtu while synthetic gasoline would cost
$0,44 per mBtu. It was assumed that the volume of methanol
transported would be twice that of gasoline.
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-74-
The conversion costs associated with a switch to methanol
would be more related to the increase in volumetric capacity than
differences in chemical properties. Pipelines and pumps are
almost entirely composed of steel or brass, with which methanol is
compatible. Rubber seals on pumps may need to be replaced with
compounds compatible with methanol, but this should be a minor
cost. A second seal may also have to be added to floating roof
tanks to prevent the ingress of water. .
Since coal-based methanol plants would likely be located near
the coal fields and existing petroleum pipelines do not generally
service these areas, new pipelines would have to be constructed to
transport methanol to the large urban markets. However, the same
would be true for coal-based plants producing synthetic gasoline.
The capital cost of a methanol pipeline for the western scenario
would be approximately $165 million, while that for the gasoline
pipeline would be $118 million [116]. Hie capital cost of the
methanol pipeline network for the eastern scenario would be $65
million and that for gasoline would be $46 million [116]. (Each
pipeline network would transport 50,000 FOEB/CD of synthetic fuel
in each case.) AS can be seen, the capital costs are 30 percent
less for transporting gasoline than methanol. However, a
comparison of these figures with the capital costs of the synfuel
plants described earlier shows that: 1) the pipeline costs are
less than 10 percent of the production plant costs, and 2) the
differences in the pipeline costs are also less than 10 percent of
the differences in production plant costs. Thus, the capital
costs of producing the synfuels dominate the capital costs of
long-range distribution.
2.,.s Local Distribution
As mentioned earlier, local distribution consists of
transporting fuel from the regional distributor to the retailers.
This distribution .is primarily done by tanker truck, While some-
economy of scale would be realized from the increase in volume
accompanying a switch to methanol, the cost of local distribution
essentially varies proportionately with distance ana volume
hauled. Overall, more trips will have to be made overall with
methanol than gasoline, since most trucks cannot increase
sufficiently in size due to state weight limitations. TO be
conservative, it was assumed that the cost per volume would remain
constant with a switch to methanol and that a typical haul was 50
miles. Local distribution of methanol was then found to cost
$0.28 per mBtu while that of synthetic gasoline would cost $0.14
per mBtu.[116]
With respect to local distribution, the cost of conversion to
methanol should be small. The only change required to the exis-
ting fleet should be new rubber seals and hoses, if they were not
already made from a material compatible with methanol. Of course,
the size of the existing tanker fleet would also have to be
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erdarged to handle the increased volume associated, with methanol,
if the existing tankers could not be used more frequently.
3. Retailer Costs
The costs of retailing fuel are more like that of long-range
distribution than local distribution. The costs of retailing are
primarily fixed costs, such as land or rent, taxes, lighting, and
a minimum level of labor required to operate the station even if
only a small number of people buy fuel. Thus, the cost of
operating a. station would remain essentially constant with a
switch to methanol. Also, retailing differs from both long-range
and local distribution in that fuel energy is the critical
marketing factor, not volume.[116] This is due in part to the
intense competition which exists among fuel stations, evidenced by
the large number of gas stations which have closed in the last few
iears. This means that the number of stations retailing fuel
depends more on the amount of energy being distributed than on the
volume of fuel being distributed. As described earlier, the
expected fuel economy advantage of methanol engines is expected to
reduce fuel consumption on an energy basis. Thus, the number of
fuel retailers could either 1) remain constant with a switch to
methanol, or 2) decrease through competition in proportion to the
decrease in energy being distributed as methanol relative to the
replaced gasoline. If the number of retailers (and the cost of
retailing) remains essentially constant with a switch to methanol,
the cost per unit energy will increase in proportion to the net
reduction in energy being distributed, if, on the other hand,
competition reduces the number of stations to compensate for the
reduction in energy being distributed in the form of methanol, the
cost per unit of energy distributed would remain the same as
gasoline. Both outcomes were used to determine a range of
possible costs.[116]
Typical retailer mark-ups are estimated to be in the range of
$0.05-0.18 per gallon of gasoline.[118] However, since the lower
mark-ups are usually associated with the high-volume stations, the
average mark-up per gallon of gasoline sold in the U.S. should be
nearer to the lower limit, or approximately $0.09 per gallon
($0.76 per mBtu). For methanol, the cost of retailing would lie
between this value and 25 percent more since the total amount of
energy distributed as methanol would be 20 percent less than that
of gasoline due to the expected higher efficiency of methanol
engines. Thus, the cost of retailing methanol would be $0.76-0.95
per mBtu.[116]
It should be noted that in the cases of long-range, and local
methanol distribution, no efficiency improvement was assumeci for
methanol vehicles. Thus, the volume of iðanol distributee was
twice that of synthetic gasoline. Although this approach appears
inconsistent with that followed to determine retail costs, each
procedure is conservative with respect to the estimation of
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methanol aistribution costs. That is, in all instances the
assumptions were made which would tend to increase the cost of
distributing methanol relative to gasoline. This was done to help
assure that the costs of distributing methanol were not
underestimated, since some of the costs of conversion are
inevitably overlooked.
The only changes in distribution equipment that would be
required with a changeover to methanol would be replacement of
rubber seals and possibly the hoses on the fuel dispensers
(pumps). The underground carbon steel tanks currently used to
store gasoline or diesel fuel should be completely compatible with
methanol; therefore, tanks that have been previously used for
premium leaded or other special blends should be available for
methanol storage. (Fiberglass tanks currently used at some
stations will not be available for storage of methanol.) The
expected increased use of diesel fuel will also compete for these
tanks, in the long term, economics will dictate whether or not
additional tanks and pumps will be needed and built to satisfy
increased demand, since the possibility exists for more frequent
tanker trips to each retailer, more tanks may not be needed.
However, it is possible that new tanks would still be built rather
than increasing the frequency of tanker trips. However, this
should only occur if the cost of more tanks was less than the cost
of more frequent trips. Thus, the estimates made here should be
sufficient in either case.
4. Total Distribution Costs
The total cost of distributing methanol and gasoline can now
be calculated by simply combining the costs presented in the last
three sections. Methanol would cost $1.69-1.88 per mBtu to
distribute; gasoline would cost $1.34 per mBtu (See Table 17).
Gasoline has a significant advantage over methanol in terms of
percentage (21-29 percent lower), but the absolute difference is
only $0.35-0.54 per mBtu.
Of course, more detail could be added to this analysis to
improve the resulting estimates and this will be done in the
future. However, the general conclusions should not change
substantially.
C. Vehicle Effects
The primary effect that must be examined in this section is
the economic effect of changes in the efficiency of the internal
combustion engine aue to the use of various fuels. A secondary
effect would be differences in the cost of such engines.
As has already been discussed in Section IV, the methanol
engine may well have a fuel efficiency like that of a diesel,
which is 25-30 percent better than that of a gasoline engine.
-------
Production
Plantgate
Cost
Distribution
Long-Range
Local
Retail
Cost at Pump
-77-
Table 17
Synthetic Fuel Costs ($ per iriBtu)*
Indirect Coal
Liquefaction
Methanol
Gasoline
Direct Coal
Liquefaction
Gasoline
5.90-12.42
0.65
0.28
0.76-0.95
7.59-14.30
7.35-15.29
0.44
0.14
0.76
8.69-16.63
7.79-19.06
0.44
0.14
0.76
9.13-20.40
Annual Fuel Savings (Relative to Gasoline
at $8.69-16.63 per mBtu)**
$23-243 $0 $-(20-172)
Added_Engine Cost over Gasoline Engine
000
**
Range of plantgate cost is the lowest cost using the low CCR
and the highest cost using the high CCR for bituminous
feedstocks.
Includes effect of increased engine efficiences and
differences in at-the-purap fuel costs.
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However, since such, nsethanol engines are not available for mass
distribution today, this section will use a more conservative fuel
efficiency advantage for methanol engines over their gasoline
counterparts of 20 percent, using a fuel economy of 30 miles per
gallon for the average gasoline-fueled vehicle, this average
vehicle would require about 0.0038 mBtu per mile to operate. A
methanol-fueled vehicle would be expected to use at least 20
percent less energy or about 0.0030 mBtu per mile.
Using 12/000 miles per year and the average delivered fuel
costs, calculated by combining production and distribution costs,
the annual fuel savings relative to gasoline produced via indirect
liquefaction (Mobil MTG process) were determined. These savings
include two separate effects. One, they include the effect of
differences in at-the-pump fuel costs. Two, they also include the
effect of methanol engines being more fuel efficient than gasoline
engines. For consistency, all fuels were assumed to be derived
from bituminous coal. As was pointed out earlier methanol (and
hence Mobil gasoline from methanol) can be derived from relatively
cheap sources such as lignite. Thus, comparisons between methanol
and Mobil MTG gasoline from lignite would be the same as those
cited below but gasoline from direct liquefaction would compare
less favorably since its costs cited are based on the more
expensive bituminous coal. No estimates are available which
detail the costs of producing synthetic gasoline by direct
liquefaction using other feedstocks.
For example, the annual fuel cost of a vehicle operating on
methanol relative to one operating on indirect liquefaction
gasoline will be calculated below. Focusing on the upper limit
( .fuel costs of Table 17, methanol at the pump costs $14.30 per mBtu
and indirect liquefaction gasoline costs $16.63 per mBtu. The
methanol vehicle, having a more efficient engine due to the nature
of methanol fuel, uses 0.0030 mBtu per mile, or $0.0429 per mile
for fuel. At 12,000 miles per year, the methanol-fueled vehicle
consumes $515 worth of fuel annually. The gasoline-fueled
vehicle, on the ether hand, uses 0.0038 mBtu per mile, or $0.0632
per mile for fuel. At 12,000 miles per year, the annual fuel cost
for this vehicle is $758. The difference is $243 per year, which
is the upper limit of the range of savings shown in Table 17 for
methanol.
Following this procedure and using the lowest fuel cost
(based on the low CCR) and the highest fuel cost (based on a 30
percent CCR), methanol would produce a savings of $123-243 per
year. Direct liquefaction gasoline would cost an extra $20-172 per
year over MTG gasoline, because of its potentially higher
at-thepump cost.
To this fuel savings must be added any difference in engine
or vehicle cost. While a methanol-fueled diesel engine nay be
developed with a fuel efficiency advantage comparable to that of a
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-79-
standard diesel, the conservative 20 percent efficiency advantage
over the gasoline engine should be attainable with engines similar
to the gasoline engine in terms of both design and cost. While a
larger fuel tank and a special cold start system nay increase
costs, savings should be attained with respect to emission
control, particularly if NOx reduction catalysts are no longer
needed and if base metal oxidation catalysts can be used instead
of platinum and paladium. Thus, whether a methanol engine will
cost more or less than a gasoline engine in the long run is still
an open question at this time. It would be rather safe to
project, however, that any potential extra cost would not override
the kind of fuel efficiency benefit described earlier.
D. Economics summary
The results of the past three sections are shown in Table
17. As can be seen when the results are combined, methanol
compares favorably to the other fuels. With respect to synthetic
gasoline, methanol appears to cost less at the plant gate. This
is true whether the low CCR is used or the high CCR. Higher
distribution costs lower the difference, but even after
distribution, methanol appears to still hold some advantage. This
advantage is $1.10-$2.33 per mBtu over t£I<3 gasoline and
$1.54-$6.10 per mBtu over direct liquefaction gasoline. Placing
this in terms of annual fuel savings, including an allowance for
the increased efficiency of a methanol engine, methanol would save
$123-$243 per year over MTG gasoline and $143-$415 per i-ear over
direct liquefaction gasoline. Without including the increased
engine efficiency, these savings would be $50-$106 per year and
$70-$278 per year, respectively. Again, it should be stated that
no comparison was made between methanol and diesel fuel since none
of the coal conversion processes examined produces diesel fuel of
sufficient quality for today's diesel engines. All of these
economic results are of course subject to the qualifications which
have been stated previously? the primary ones being that the
detail of the engineering designs could no't be standardised across
processes and that the cost estimates reflect different points of
development for the different synfuel technologies.
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-80-
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