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OCR for page 57
4
Conversion Technologies and
R&D Opportunities
Various technologies can be used to convert heavy oil, tar sands, oil
shale, coal, biomass, and natural gas into liquid transportation fuels. These
technologies, opportunities to reduce their costs, fuel properties, environ-
mental aspects, and R&D recommendations for the U.S. Department of
Energy (DOE) are discussed in this chapter. More information on some of
the technologies can be found in the appendixes. The technologies are
addressed to the extent that they are major areas for DOE: some sections
are kept brief because of their lower relevance (see Chapter 6~.
The hydrogen-to-carbon (H/C) ratio of these resources must be adjusted
to that of transportation fuels; pyrolytic processes remove carbon, and hydro-
processing adds hydrogen. This adjustment is a major expense and con-
sumer of energy in these processes. In methanol production and indirect
liquefaction (Fischer-Tropsch [F-T] and methanol-to-gasoline [MTG]) proc-
esses, the entire feedstock is first converted to synthesis gas (mixture of
hydrogen and carbon monoxide) a major cost and energy consumption
step. The next section addresses R&D for cost reduction of hydrogen and
synthesis gas. The following sections address the individual conversion
technologies.
PRODUCTION OF HYDROGEN AND SYNTHESIS GAS
Production of hydrogen and synthesis gas (syngas) is central to convert-
ing fossil resources into transportation fuels. They are required to adjust
the H/C ratio of these resources and to remove undesirable elements (inor-
ganic, N. S. and O). Conventional transportation fuels have an H/C ratio of
approximately 2 (methanol has a ratio of 4; however, from an energy view-
point it can be considered approximately a mixture of CH2, the fuel, and
57
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58
FUEIS TO DRIVE OUR FUTURE
H2O). Coal clearly requires the largest adjustment in the H/C ratio, but
even tars and higher-boiling petroleum fractions require major adjustment
(Figure 4-1~. The same considerations apply to the manufacture of metha-
nol or hydrocarbon fuels from biomass.
Conversion of natural gas (CH4) to liquid transportation fuels, in con-
trast, requires reduction of the H/C ratio. The conventional pathway, as in
methanol manufacturing, is to convert the methane to syngas, the first step
in hydrogen manufacturing. This syngas can then be converted directly to
methanol or to hydrocarbon fuel or it can be processed further to produce
hydrogen for hydroprocessing. Production by steam reforming or produc-
tion by partial oxidation are the standard processes for syngas and hydrogen
manufacture.
These natural gas conversion processes are increasingly used in refining
and chemical manufacturing. The ample world supply of low-cost natural
gas indicates a continuing international engineering and R&D effort aimed
at efficiency improvement and cost reduction of these processes. While
there will be a continuing need for improved high-temperature materials
and catalysts, there is little need for a U.S. government-supported effort on
the high-temperature conversion section of these methane-based processes.
When international crude oil prices are greater than about $30/barrel, the
price of domestic natural gas is predicted to exceed $4/thousand cubic feet
(see Appendix D, Table D-1) and production of hydrogen and syngas from
coal becomes competitive. Since this is also the range of equivalent crude
prices where use of coal liquefaction and shale oil are competitive, attention
to reducing the cost of production of hydrogen and syngas from coal is
important.
Table 4-1 shows the amount of hydrogen consumed for conversion of
Illinois No. 6 coal to a syncrude suitable for further refining to transporta-
tion fuels. Hydrogen used for heteroatom removal is about the same or
greater than that added to the liquid product, and a larger fraction of con-
sumed hydrogen is found in C~-C3 gases. The total corresponds to 142 to
226 m3/barrel (5000 to 8000 ft3/barrel) of syncrude, and an additional amount
would be consumed in refining to transportation fuels. An eventual com-
mercial technology might achieve a 50 percent reduction in hydrogen losses
to the by-products.
Equipment for manufacturing this large amount of hydrogen from coal
requires a major fraction of the capital investment approximately 25 per-
cent and a similar fraction of total coal consumption.
In coal gasification water is the primary source of hydrogen through its
reaction with carbon to form carbon monoxide. This reaction is highly
endothermic, and a large amount of heat is supplied by burning coal with
oxygen. This can be done in a single reactor by using a mixture of oxygen
and steam or by circulation of hot solids or gas plus steam through a reac-
OCR for page 59
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60
FUEl~ TO DRIVE OUR FUTURE
TABLE 4-1 Hydrogen Sources and Uses in Direct Coal
Liquefaction
Pound/ Percent
100 lb Coal of Total
Hydrogen Sources
From coal fed 5.33 45
From H2 gas added 6.39 55
Hydrogen in Products
~ distillable liquids 8.23 70
In by-products
C~-C3 hydroc~n gases 1.26 1 1
Heteroatom gases 1.24 11
Resid arid unconverted coal 0.99 8
NOTE: Data for Wilsonville Run 257H, February 1989. Illi-
nois #6 coal, Buming Star Mine. Based on moisture- and ash-
free coal.
tor. Dilution by nitrogen is undesirable, and in the first case relatively pure
oxygen must be separated from air. In the second case heat is added to the
hot solids or gas in a separate vessel via combustion with air.
The reaction of coal with steam produces, in addition to carbon monox-
ide and hydrogen, carbon dioxide (CO2), hydrogen sulfide (H2S), methane
(CH4), ammonia (NH3), and particulates. These are currently removed in a
low-temperature cleanup train, and when hydrogen is the desired product
the gas composition is adjusted by the reaction
CO + H2O = CO2 + H2,
CO2 is removed and, where necessary, CO is removed by reaction with
hydrogen to form methane.
The energy for water splitting, shifting, and gas cleanup and oxygen
generation comes from fossil fuel combustion with additional generation of
CO2. If control of CO2 emissions becomes necessary, other energy sources
could be used. These include biomass, nuclear heat, and solar energy.
Biomass could be used to supply heat and hydrogen by modification of
technologies developed for coal. The direct use of nuclear heat will require
relatively low temperature gasification and would lead to a gasification
process specifically designed for integration with a nuclear heat source (see
Appendix K).
In the period between the oil price increases of the 1970s and the petro-
leum price collapse of 1983, there was a wide variety of R&D on hydrogen
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CONVERSION TECHNOLOGIES AND R&D OPPORTUNITIES
61
production processes with the anticipation of extensive use of these proc-
esses starting in 1990. Uncertainty about future oil prices has resulted in
abandonment of many of these programs. While no commercial coal lique-
faction plants were built, a few other applications of gasification are provid-
ing commercial experience on coal gasification in this country. Of particu-
lar interest is its use in conjunction with electric power generation.
The use of coal gasification for electric power generation is based on the
ease of removal of pollutants from the gas and on its potential for use in
more efficient combined-cycle systems where the gas is first burned at
pressure in a gas turbine followed by steam generation by the hot gas tur-
bine exhaust. The pioneer Cool Water demonstration program in Daggett,
California, which makes use of the Texaco entrained flow gasifier, is con-
sidered quite successful, and both Texaco and Shell are actively developing
and marketing this type of gasifier where finely ground coal is reacted with
oxygen at pressures of 150 to 600 psi in a high-velocity reactor with cocur-
rent flow of coal and gas. Temperatures approach 1650°C (3000°F). Lurgi
countercurrent moving bed gasifiers are in commercial use and have dem-
onstrated good performance at the Great Plains coal gasification plant in
Beulah, North Dakota.
Assuming there is a continuing market for specific gasifiers, it is ex-
pected that the continuing industrial R&D programs will leave little incen-
tive for DOE to engage in research aimed at evolutionary improvements in
these specific systems. While these systems have the advantages of being
available and generally applicable when hydrogen or syngas is needed, they
suffer from problems of durability, small scale, and inability to integrate
pyrolysis tar and gas recovery with the total liquefaction system.
The Texaco plants at Cool Water, for example, have a capacity of 1000
tons/day of coal. A design based on Wilsonville technology proposed use
of larger-scale gasifiers (6760 tons/day [wet]~. A lOO,OOO-bbVday plant
would require 12 of these gasifiers, 9 on-line and 3 standby. While mul-
tiple units are needed to allow for periodic repair of ceramic liners, it ap-
pears that much larger units may offer opportunity for cost savings for a
scale of operation consistent with the scale needed for producing transporta-
tion fuels. While these commercial systems could probably be increased in
size, other systems may be more amenable to major scale-up and integration
with the coal liquefaction process.
The separation of oxygen from air is a major expense in current commer-
cial systems, and the alternative of supplying heat from separately heated
solids or gas can be competitive. The sources of heat in this case would be
fuel combustion by air or, perhaps in the long term, nuclear heat. These
systems, in general, would operate at lower temperatures (below ash fusion)
than the oxygen-entrained flow systems. This reduces the problem of ceramic
life but introduces the problem of disposing of unfused ash, which would be
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62
Fuel TO DRIVE OUR FUTURE
more easily leached than fused ash. Production of by-product methane
increases as the temperature is reduced, and in the presence of catalysts
large amounts of methane are generated in situ, as in the Exxon catalytic
gasification process. Methane formation is a secondary reaction that can be
limited by short gas contact time or by the presence of a CO2 acceptor such
as calcium oxide. Use of fluidized bed technology appears to offer advan-
tages for large-scale solids-handling processes and potential for use in multiple
beds and stages.
Many variations of multiple bed systems for coal gasification have been
investigated (Kuo, 1984~. Figure 4-2 is a generic scheme, which provides
for coproduction of hydrocarbons from pyrolysis and can supply heat for
the endothermic char-steam reactions. The gasification reactor can produce
large amounts of methane, if conditions are chosen to encourage catalytic
gasification (as in the Exxon catalytic gasification process). Hydrogen of
purity sufficient for coal hydroliquefaction could be produced, under differ-
ent conditions, where circulated calcium oxide acts as a CO2 acceptor.
An additional set of alternative processes involves the use of hot iron or
iron oxide to produce hydrogen from steam. Iron oxide is reduced by
producer gas from reaction of coal with an air-steam mixture. The reduced
iron oxide (FeO) reacts in a separate vessel with steam to form hydrogen
I Gas
l
. .
J Tar
Flue
' Gas
, ~ 'Combustion
Hot Solids aim//////; Hot Solids
Coal Limestone
Air
Steam
Gas
Gasification
l ~
Waste
1 Solids
FIGURE 4-2 Schematic of a coal gasification process following pyrolysis and
combustion to obtain higher thermal efficiencies.
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CONVERSION TECHNOLOGIES AND R&D OPPORTUNITIES
63
and Fe3O4. A variation involving use of molten iron is being studied by the
Japanese.
Underground gasification of coal has been extensively studied in Russia
and in the United States. Early U.S. field tests used air injection to produce
a relatively low BTU product gas. Injection of oxygen and steam as gasifi-
cation agents was shown in later tests to substantially improve product heat-
ing values. A successful pilot scale test was carried out in a steeply dipping
seam in 1981 by a joint project between DOE and Gulf Research and Devel-
opment Company. This test (Rawlins II) produced good-quality synthesis
gas for 65 days at a rate of 130 tons/day. The work was terminated for lack
of funds (Singleton, 1982~. Estimated costs, using the test results, indicated
a substantial reduction in synthesis gas cost (Schulman and Biasca, 1989)
(see Appendix D, Table D-3. Because the steeply dipping coal seams
qualifying for this technique are considered "unmineable," a very low coal
value was used.
and
The most recent underground gasification field test, the Rocky Mountain
I test, was conducted in 1987 to 1988 by a consortium of the DOE and
several private concerns headed by the Gas Research Institute. This test
demonstrated successful long-term gasification of flat seams via the use of
the Controlled Retracting Injection Point (CRIP) technology developed by
the Lawrence Livermore National Laboratory (Cena et al., 1988~. The
Rocky Mountain I CRIP module gasified over 11,000 tons of coal in 93
days to produce a product gas with an average heating value of 287 BTU/
standard cubic foot. The gasifier operated at efficiencies in terms of energy
recovery per unit of oxygen/steam injected that were comparable with sur-
face gasifiers. With the potential of significant reductions in capital and
mining costs compared with surface gasifiers, underground gasification is a
promising technology for liquids production from coal, but several ques-
tions remain, including
· scaling-up in length of time and rate of gas production,
· effects on aquifer quality for a large operation,
· ability to predict and control performance for less ideal coal seams,
· evaluation of the amount of coal meeting the requirements of this
technique.
A joint industry-DOE commercial demonstration designed to answer the
above questions is recommended pending the environmental results from
Rocky Mountain. The syngas produced from this demonstration could be
used to produce ammonia or methanol.
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64
FUELS TO DRIVE OUR FUTURE
The DOE Program
Table 4-2 summarizes the 1988 and 1989 appropriations for work rele-
vant to coal gasification.
Advanced Research. The programs on gasification and pyrolysis chemis-
try, ash agglomeration, and gas separation are important areas. New pro-
grarns with particular relevance to integrated direct coal liquefaction sys-
tems should be established.
Systems for Synthesis Gas Production. The systems development and
modeling effort is essential to identification of the optimized gasification
approach and the corresponding research thrusts. The scope should proba-
bly be extended to include the total system of liquefaction, gasification, and
coproducts.
Systems for Coproduct Production. This large program appears to be
oriented toward stand-alone pyrolysis liquid-char producing systems. No
reference is made to processing pyrolysis liquids in the coal liquefaction
reactor in combined pyrolysis-gasificaiion-direct liquefaction systems. As
described in the 1990 proposed program, the program is aimed at directly
TABLE 4-2 The 1988 and 1989 Appropriations for Work Relevant to Coal
Gasification
Appropriations ($1000s)
1988 1989
Relevance to
Liquid Fuel
Production
from Coal
Advanced research 2,698 2,679 High
Systems for synthesis gas
production 1,958 2,679 High
Systems for coproducts
production 5,292 9,084 Medium
Total 9,948 14~442
Underground coal gasification 2,777 1,371 High
Systems for power production 11,176 5,926 Low
Systems for industrial fuel gas 1,369 848 Medium
Great plains coal gasification
(methane production) SOO 517 Low
Total 15,822 8,662
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CONVERSION TECHNOLOGIES ED Ray OPPORTUNITIES
65
marketable nontransportation products. The relevance to major transporta-
tion fuels should be improved.
Underground Coal Gasification. As discussed previously, this process
has potential for reduced cost from the use of low-value coal.
Production from Biomass. The 1990 DOE Solar Energy Program in-
cludes $1.1 million to begin small-scale biomass gasification research. While
aimed at methanol production, the same processes could be used to supply
hydrogen for manufacture of transportation fuels from fossil resources.
Synthesis gas or hydrogen produced from biomass has potentially no net
CO2 effect on the atmosphere if this synthesis gas is used to manufacture
methanol or F-T gasoline. If such production of methanol were to occur in
the economy, the amount of coal-based gasoline would be less, resulting in
less CO2 output. The alternative of using biomass-produced hydrogen for
coal liquefaction, however, results in a larger reduction in coal-produced
CO2 since more liquid fuel is produced per unit of hydrogen (synthesis gas)
by the coal liquefaction route than by manufacture of methanol from syn-
thesis gas.
Systems for Power Production. Much of the work on systems for power
production is quite specific to utility problems. Hot gas cleanup (H2S re-
moval) is less important for coal liquefaction since the process is sulfur
tolerant and since H2S must be removed from the spent hydrogen stream.
Hot CO2 removal with concurrent shifting might be of greater interest.
Systems for Industrial Fuel Gas Production. The program on systems
for industrial fuel gas production aims for lower-cost oxygen production
and operation of the Morgantown Energy Technology Center (METC) fluid
bed gasifier. This work can potentially make contributions to gasification
for hydrogen and synthesis gas production and should be managed with this
. .
In mend ..
Conclusions and Recommendations
Manufacturing of hydrogen and synthesis gas is a major economic and
energy cost and source of CO2 in the production of liquid transportation
fuels from natural gas and coal, shale, heavy oils, and biomass. Processes
for syngas manufacturefrom natural gas are widely used and of continuing
R&D interest to industry. The participation of DOE should be limited to
exploratory and fundamental studies that are relevant to manufacture from
both natural gas and coal.
When petroleum prices increase to the point where coal and shale lique-
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66
FUEL; TO DRIVE OUR FUTURE
faction are competitive, it is expected that increases in the price of natural
gas will cause a shift to coal gasification. Other sources of hydrogen (bio-
mass, electrolysis, photolysis, thermal water splitting) are expected to be
more costly. High priority should, therefore, be placed on reducing the cost
of hydrogen and synthesis gas manufacture from coal, reducing CO2 genera-
tion by using nonfossil sources of energy for process heat and hydrogen
production, and improving energy efficiency.
While general-purpose coal gasification processes are now in limited
commercial use, it is believed that important opportunities exist for devel-
opment of gasification processes specifically chosen for integration with
direct coal liquefaction to reduce both cost and CO2 production. Such an
optimized process might incorporate features such as coproduction of py-
rolysis liquids and low-cost methane, larger-scale equipment, and use of air
combustion, biomass combustion, or possibly nuclear heat in the long run.
Demonstration and broader evaluation of underground coal gasification are
also recommended.
The 1989 DOE program is, in general, well chosen; however, it is recom-
mended that increased emphasis be placed on identifying opportunities for
reducing transportation fuel cost and CO2 output by integration of direct
coal liquefaction and biomass processes in an era when natural gas prices
are high. When such opportunities are identified, the program should be
expanded with the goal of working toward a demonstration.
HEAVY OIL CONVERSION
The carbon rejection and hydrogen addition processes for heavy oils are
difficult primarily because of the high concentrations of contaminants like
sulfur, nitrogen, metals (mostly nickel and vanadium), and coke-forming
molecules (known as "carbon residue") in the heavy oils. Metals poison
catalysts and reduce upgrading efficiency, and sulfur and nitrogen must be
removed in a cost-effective and environmentally acceptable manner. Many
of these processes for converting heavy oil or crude oil vacuum residuum
(vacuum resid) are commercial and standard in the petroleum industry. The
petroleum sector is profiting from early investment and licensing of these
procedures. A brief description follows (for more details, see Appendix E).
Commercial Processes
There are a number of commercial carbon rejection processes that up-
grade heavy oil to liquids, coke, and gas, the liquids generally of a poor
quality. The liquids must usually be hydrotreated before being used as
reformer or fluid catalytic-cracking (FCC) feeds to make transportation fuels.
These processes include the following:
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CONVERSION TECHNOWGIES AND R&D OPPORTUNITIES
67
1. Delayed coking heavy oil or vacuum resid is thermally cracked in a
vessel yielding liquids, gas, and high-sulfur coke.
2. Fluid coking heavy oil is thermally cracked in a reactor containing
a bed of fluidized coke particles. Sulfur oxides (SO) need to be controlled.
3. Flexicoking an extension of fluid coking, in which most of the coke
is gasified to low-Btu gas and the need for a coke market is eliminated.
Sulfur is removed as hydrogen sulfide.
4. Resid FCC and heavy oil cracking resid is fed to a fluidized bed
with a cracking catalyst, yielding gasoline-range boiling materials with car-
bon residue deposited on the catalyst. Since heavy metals may poison the
catalysts, upstream processing of the resid is usually required.
Commercial hydrogen addition processes include catalytic or thermal
hydrocracking, or the donor solvent type. They include (1) fixed-bed resid-
uum or vacuum residuum desulfurization (RDS/VRDS), developed 20 years
ago, is increasingly used as heavy oils become heavier. In this process
atmospheric or vacuum resid oil contacts catalyst and hydrogen, removes
most of the metals and sulfur, and creates an acceptable feedstock for fur-
ther upgrading in an FCC. (2) Bunker flow or hycon process is similar to
RDS/VRDS, except that the catalyst can continuously be added and re-
moved. (3) Ebullating bed processes, known as LC-fining or H-oil, involve
hydrocracking and remove metals and sulfur of any heavy oil. The distil-
late products are of low quality and require further hydrotreating and up-
grading.
Processes with Limited Commercial Application
Asphalt residue treatment (ART) is a carbon rejection process with a
reactor similar to an FCC. The feed contacts a high-temperature solid and
is volatized, and the coke is burned off the solid in a regenerator to produce
the required heat. The liquid product yield is high but requires further
upgrading.
Hydrogen addition processes include many slurry hydrocracking proc-
esses, a variation of thermal high-pressure hydrocracking. A dilute slurry is
added to a cracking reactor to suppress coke formation and attract metal
contaminants. Conversions of vacuum resid are high, but the products are
high in sulfur and nitrogen, requiring further hydrogenation.
Fuel Properties
The product qualities resulting from the various heavy oil upgrading
technologies are quite variable and are strongly dependent on feed type,
process type, and processing conditions. However, producing fuels of ac-
ceptable properties is possible (in all cases) with existing petroleum proc-
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94
FUELS TO DRIVE OUR FUTURE
1990s in Japan. The West Germans have operated a 200-ton/day pilot plant
at Bottrop since the early 1980s, but it was recently converted to the study
of upgrading petroleum residuum. The West Germans have an unmatched
backlog of experience in coal liquefaction on a large scale, although their
process has some drawbacks compared to recent U.S. developments. The
British are building a pilot plant about the size of Wilsonville in North
Wales, at Point of Ayr. Their smaller-scale work was very encouraging,
and this process may be a strong competitor if it works out on the larger
scale. All of these projects are government funded.
Fuel Properties
Products of direct coal liquefaction are expected to meet all current speci-
fications for transportation fuels derived from petroleum. Major products
are likely to be gasoline, propane, and butane. Distillate fuels can be made
but would likely require large volumes of hydrogen. Gasoline may be a
particularly attractive product because it would have a relatively high oc-
tane.
High octane is achieved by the high aromatic content of the liquids. If
regulations are established limiting the aromatic content of gasoline for
environmental reasons, the cost of liquid fuels produced from coal by direct
liquefaction would rise. While the benzene content of gasoline made from
coal is extremely low, the concentration of other aromatics is high, and they
could be hydrogenated to produce naphthenes at a moderate increase in
cost. This would increase the volume of the products, decrease octane
number, and increase hydrogen consumption.
Environmental Considerations
With regard to environmental emissions with local impact, a coal lique-
faction facility is broadly comparable to a refinery with up-to-date emission
control systems. As in many conversion processes, sulfur and nitrogen are
removed from the feedstock and appear in the product fuels at greatly re-
duced levels. Wilsonville has successfully shown that local emissions can
be controlled satisfactorily (see Chapter 5 regarding greenhouse gas emis-
sions). Direct coal liquefaction is fairly energy efficient; about two-thirds
of the coal fed comes out as liquid product, and the rest is consumed to run
the process.
One area of concern is industrial hygiene. The intermediate products ot
coal liquefaction (internal to the process plant) are polynuclear aromatic
hydrocarbons, which are well-known carcinogens and mutagens. Industry
and government programs over the past 20 years have demonstrated that
proper attention to hygiene can make coal liquefaction plants safe places to
work (U.S. DOE, 1989b).
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CONVERSION TECHNOLOGIES AND R&D OPPORTUNITIES
Potential Cost Reduction
95
The improvements demonstrated at Wilsonville were incorporated in a
new design that is an update of the DOE-funded Brechenridge Project,
which used the H-coal process and was completed in 1981. The new design
uses two reactors in series in place of the single-stage H-coal design and
includes a simplified product distillation system, the new solids removal
technology, and the simpler water treatment methods proved at Wilsonville;
the process upgrades most of the liquid products to gasoline blending com-
ponents (Lumpkin, 1988~. The result is a projected cost decrease of about
60 percent, to about $40/barrel (crude oil equivalent).
Substantial improvements are still likely if research continues. Recent
runs at Wilsonville have achieved a doubling of coal feed rates from that
assumed in the above design by making the reactor temperatures more uni-
form. These high rates may reduce costs by $2 to $3/barrel. Equipment is
being installed to allow better distillation of the product liquids, which will
in turn reduce the amount of high boiling components in the products. This
change may reduce costs another $2/barrel.
There is a large incentive to learn how to process different coals. Most
recent Wilsonville trials used Illinois coal. Runs with a higher-rank, bitu-
minous Ohio coal have demonstrated very high liquid yields, but the quality
of the liquids needs to be improved. Lower-rank coals, either subbitumi-
nous or [ignites, are relatively cheap and convert to high-quality liquids.
However, their high moisture content and high levels of oxygen lead to
problems that have not been entirely resolved at Wilsonville. Resolution of
these problems could reduce costs by as much as $4/barrel.
Removal of ash, and perhaps the unreactive parts of the coal itself, be-
fore liquefaction could improve conversion, reduce erosion, and eliminate
the need for the current solids separation process. Technologies are under
development, funded primarily through DOE or the Electric Power Research
Institute, that might be used to clean liquefaction feedstock, although they
are primarily intended to prepare cleaner power plant fuel. Capital invest-
ment at Wilsonville is needed to adapt these technologies and determine
their economic attractiveness.
There are clearly many opportunities to improve the economics of direct
coal liquefaction. The DOE hopes to reduce costs at Wilsonville by 15
percent within the next 3 or 4 years. This target seems conservative.
Direct liquefaction is capital intensive, and its total cost is relatively
insensitive to most individual improvements. Multiple improvements are
needed to significantly reduce costs. Such improvements are likely if re-
search continues.
Environmental requirements to reduce the aromatic content of gasoline
may increase the costs of producing this fuel from coal.
Although it is impossible to predict whether major technical breakthroughs
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FUELS TO DRIVE OUR FUTURE
will occur, the possibility should not be discounted. The high level of U.S.
and foreign fundamental research on coal structure and chemistry for the
past 10 years could lead to a superior means of conversion.
DOE Program on Direct Liquefaction
The recent assessment of research needs conducted by DOE's Office of
Program Analysis outlines an excellent program aimed at bringing down the
cost of direct liquefaction (Schindler, 1989~. Industry members of the as-
sessment panel particularly stressed the need for federal funding of a large-
scale pilot plant, as large as the German effort at Bottrop or the planned
Japanese pilot plant (i.e., processing 150 tons per day or greater) to develop
hardware and perform chemical studies. A broad range of fundamental and
exploratory research was also recommended, based on the recognition that
possible improvements in the current technology appear limited but that
breakthroughs may bring down the cost of liquid fuels produced from coal
to below $20/barrel. The committee concurs with these research recom-
mendations.
In between these two extreme types of development, intermediate-size
flow units are needed. Wilsonville, or an alternative plant of about the
same size, would be useful to test changes in process configuration at rea-
sonable cost. Smaller pilot plants are also needed to test catalysts, explore
operating conditions, and provide low-cost testing of new ideas. The com-
mittee recommends that such small-scale work continue to be sponsored by
DOE, with the work performed by private contractors in industry and uni-
versities. In this way a wide variety of experts can contribute and technol-
ogy transfer to industry will be enhanced. The general purpose pilot plant
proposed for installation at the Pittsburgh Energy Technology Center is less
attractive due to lower industrial participation.
The DOE-funded programs that are relevant to the conversion of coal
into transportation fuels in fiscal year 1990 allocate approximately twice as
much money to process development as to each of the other categories (see
Appendix G for definitions of fundamental, exploratory and catalyst, and
process research). This emphasis on development may be unavoidable when
industry is reluctant to participate because of the long time scale and uncer-
tainty involved. The accuracy of the funding split is somewhat uncertain,
since it is based on brief project descriptions that DOE provided the com-
mittee. However, process demonstration, which is the step following proc-
ess development, is receiving no funding, and without money for this pur-
pose over the long run the United States will fall behind its foreign com-
petitors.
When the pilot scale demonstrates that processing 150 tons or more of
coal per day has provided scale-up information, proceeding with a commer-
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97
cial-scale demonstration facility should be seriously considered. This facil-
ity should be a single-line plant with enough redundancy of critical equip-
ment that an acceptable plant on-stream factor can be achieved. Only by
operating a commercial-scale facility can its true economics be determined.
It would be best if this commercial-scale demonstration could be fi-
nanced on an international scale. Countries such as West Germany, France,
Italy, and Japan depend on imported oil for transportation fuel. An interna-
tional project funded by their governments and the United States on a cost-
sharing basis, with participation of the private sector in the form of project
management, engineering, and construction, operations, and maintenance,
as well as private sector investment, would help ensure a successful effort.
The Research, Development, and Demonstration organization of the Inter-
national Energy Agency might coordinate and monitor the project. A suc-
cessful commercial-scale demonstration would be valuable for the United
States should it become desirable for the supply of liquid transportation
fuels to be augmented through direct coal liquefaction technology.
Conclusion
Over the next 5 years research effort directed toward new catalysts and
new processes should be stressed with a goal to selecting the best coal
conversion processes for demonstration in a large pilot plant within this
time frame. Achievement of this goal will require establishing technical
confidence, achieving anticipated environmental requirements, and reduc-
ing the cost so that industry is willing to participate. The program should
include high-quality economic and technical evaluations by engineering firms,
petroleum industry operating companies, and qualified consultants to guide
the selections of the best technologies to move forward.
COAL-OIL COPROCESSING
Coal-oil coprocessing is a technology that simultaneously converts heavy
petroleum residuum and coal to liquid transportation fuels. Incentives for
coprocessing depend strongly on the existence of synergisms between the
coal and resid as they are processed together. Coal may aid operability due
to the solvency of coal liquids, and coal ash may scavenge metals from the
resid to extend catalyst life. Other synergies may exist. In the 1970s the
Canada Centre for Mineral and Energy Technology (CANMET) showed
that the addition of less than 5 percent coal to a petroleum feedstock signifi-
cantly improved distillate product yields (Rahimi et al., 1987~. This proc-
ess was employed in a 5000-bbl/day plant started up in 1985 by Petro-
Canada, near Montreal (Kelly and Fonda, 1984~. Background, state-of-the-
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FUELS TO DRIVE OUR FUTURE
art, and R&D opportunities for coprocessing technology are summarized in
two recent reports (Schindler, 1989; Schulman et al., 1988~.
The most significant disadvantage of using coal in petroleum upgrading
is its impact on capital and operating costs—coal handling, hydrogen gen-
eration, catalyst replacement, and waste amelioration.
Recent Developments
Various coprocessing technologies have undergone some development.
Chevron Corporation ran a 6-ton/day coprocessing pilot plant at its Richmond,
California, facility in 1983 (Shine et al., 1984~. Results reported for this
close-coupled thermal catalytic system included good operability, a synergy
for resid conversion, and demetallation of high-metal-content reside. In
1984 Kerr-McGee tested a process in which the bottoms from a resid hy-
drotreater replace about one-half the recycle oil in a thermal catalytic two-
stage coal liquefaction process (Rhodes, 1985~. Lummus coprocessing tech-
nology includes two process flow schemes (Greene et al., 1986~. In one,
coal and hydrotreated resid are fed to a two-stage process consisting of a
short contact time (SCT) thermal reactor and an expanded bed LC-fining
system. In the second scheme the resid is fed to the LC-finer only. In
either case a solvent stream is recycled to the first stage, the product vac-
uum bottoms are fluid coked, and the coke is gasified.
Significant foreign developments have occurred in the West German 250-
ton/day pilot plant operated by Veba Oil at Bottrop (Schulman et al., 1988~.
It was used as a coal liquefaction pilot plant until 1986 and thereafter
processed petroleum vacuum reside. Although not used for coprocessing,
its operation with both coal and petroleum resid indicates the flexibility of
the technology to accommodate different feedstocks.
Current Developments
The DOE is supporting the development of coprocessing in two pilot-
scale programs at Hydrocarbon Research, Inc. (HRI), and UOP, Inc., and in
various smaller-scale research projects. In addition, under the first round of
DOE's clean coal technology program the department selected a 12,000-
bbVday coprocessing project, using HRI technology, sited in Ohio. If this
project is completed, it could mark the first large-scale demonstration of
coprocessing technology. Further descriptions of the Signal-UOP and HRI
technologies are given in Appendix H.
In addition to these pilot-scale projects, advanced and fundamental
coprocessing research is being conducted at U.S. universities and research
institutions. Studies concern coal-oil interactions and process chemistry,
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99
with the goal of improving existing processes and identifying new process
concepts. Some research on direct liquefaction and heavy resid upgrading
may also apply to coprocessing.
Fuel Properties
Coprocessing is similar to direct coal liquefaction in that it produces
fuels that are compatible with existing fuel markets. In particular, it is
directed toward producing transportation fuels because these are the highest
value-added products. Therefore, the emphasis has been on producing re-
finery feedstocks and finished products that can meet motor and jet fuel
specifications. The mid-distillate and vacuum gas oil products from
coprocessing are low in sulfur and nitrogen (ruddy et al., 1986) and could
be used as low-sulfur fuel oil or turbine fuel for utility applications.
Environmental Considerations
The aromatic nature of coal tends to impart aromatic content to the prod-
ucts, which improves the octane value of the product naphtha for use as a
gasoline-blending stock.
Burning fuels from coprocessing will emit no more pollutants than their
petroleum-derived counterparts. However, all fuels are produced at some
loss in thermal efficiency and CO2 is produced. Other environmental im-
pacts of coprocessing should be within the scope of existing petroleum
refining and coal utilization practices.
Opportunities for Cost Reduction
Determining the existence and extent of synergism between coal and
resid is needed to assess the economics. Several investigations place the
product costs of coprocessing between those of heavy resid upgrading and
direct coal liquefaction (Schindler, 1989; Schulman et al., 1988; Duddy et
al., 1986; Huber et al., 1986~. Cost reduction will come from determining
how to maximize the benefits of any synergisms that might exist. In par-
ticular cases a combination of appropriate refinery equipment, resid costs,
and coal availability might justify coprocessing.
It appears unlikely that coprocessing will find application as a stand-
alone technology. The economics of coprocessing require a significant
difference between coal and resid costs to justify the additional capital
expense to add coal to an existing refinery. Such a gap between coal and
petroleum prices could justify construction of a coal liquefaction plant rather
than a grass-roots coprocessing plant, to take greater advantage of coal as
the less expensive feedstock. Of course, a coal liquefaction plant would
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FUELS TO DRIVE OUR FUTURE
probably be capable of coprocessing or resid hydrocracking if resid costs
decrease.
Other opportunities for cost reduction in coprocessing are the same as
those in direct coal liquefaction: increased throughput, reduced hydrogen
cost, lower coal costs, better catalysts, better engineering design, and iden-
tification of new process concepts.
Recommendation for the DOE Program
Coprocessing of heavy oils or residuum with coal may offer an opportu-
nity for the introduction of coal as a refinery feedstock. A demonstration
plant for production of a clean boiler fuel is part of the DOE's clean coal
technology program. Funding of basic bench-scale research should be con-
tinued over the next 5 years to define the extent of synergism for coprocessing
coal-resid combinations, followed by a thorough economic analysis quanti-
fying the impact of this synergism. If favorable, the impact of synergism
should be confirmed at the Wilsonville test facility to define optimum proc-
essing conditions. If little or no synergism is found, work in this area
should be terminated.
COAL PYROLYSIS
Description of the Technology
Pyrolysis of coal dates back to the 18th century, using temperatures
below 700°C in fixed or moving bed reactors. The primary product was a
low-volatile smokeless domestic fuel, although the value of the liquid prod-
ucts was also soon recognized. During the 1920s and 1930s there was a
great deal of R&D in low-temperature processes, but interest died in the
mid-1940s when gas and oil became readily available at low prices. With
the oil embargo and increased oil prices of the early 1970s, interest renewed
in coal pyrolysis, but in more recent times interest has again declined along
with petroleum prices (Khan and Kurata, 1985~.
In the most recent work, development was aimed at processes that maxi-
mize the yields of liquid products. These processes require rapid heat-up,
using fluidized or entrained bed reactors. A number of the processes re-
quire the addition of reactants (steam, carbon dioxide, and hydrogen) at
greater than atmospheric pressure to increase yields and limit secondary
reactions. Reactor type, temperature, pressure, residence time, and coal
type all have significant impacts on product yields (see Appendix I, Tables
I-1 and I-2.
Pyrolysis under mild temperatures (500° to 700°C) and pressures (up to
50 psi") with rapid heat-up can produce high liquid yields without adding
hydrogen (hydrogen would have to be added to these liquids to produce
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101
transportation fuels). However, a significant part of the feed coal remains
as char with less market value than the feed coal. As a result, coal pyroly-
sis offers the promise of lower liquid costs only if the char can be upgraded
to a higher-value product, such as form coke, smokeless fuel, activated
carbon, or electrode carbon, or if the liquid yield can be significantly in-
creased by using low-cost reactants (steam and carbon dioxide) or catalysts.
Fuel Properties
Different liquid fuel properties of the products of coal pyrolysis result
from different processes. Processes include the Coalite process, a slow
heating process that produces more gases and char than tar (Khan and Kurata,
1985~; the Occidental Research Corporation flash pyrolysis process, a rapid
heat-up process that produces more tars (DeSlate, 1984~; and the FMC
COED process (see Appendix I for properties). For the above order of
processes the desirability of the char as a fuel decreases because of the
increase in ash and sulfur content on a heat content basis and the deteriora-
tion of its size consistency, which can lead to material handling problems.
Pyrolysis liquids require extensive hydrogenation to be useful as trans-
portation fuels. Another approach is to combine coal pyrolysis with pro-
duction of synthesis gas to potentially increase the liquid yields for conver-
sion processes producing transporation fuels.
Environmental Considerations
The environmental impacts of using liquid and char coproducts from
coal pyrolysis will be very similar to those associated with the feed coal.
Coal pyrolysis in the presence of alkaline material can result in the reten-
tion of sulfur in the char with a corresponding reduction in the liquid prod-
ucts. Care must then be taken to avoid uncontrolled releases of hydrogen
sulfide from the char alkaline mixture (Gessner et al., 1988~.
Economics
The timing of a commercial application of mild pyrolysis will depend on
the marketability of the char and the quality of the liquids. Spot market
prices for metallurgical coke now exceed $130/ton. Assuming that form
coke can command a comparable cost, mild pyrolysis could be economi-
cally viable in the immediate future.
Recommendations for DOE Research
To realize the potential of mild pyrolysis as a source of transportation
fuels, a number of research issues must be resolved. The DOE's current
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FUELS TO DRIVE OUR FUTURE
research program partly addresses these issues. Under its Surface Coal
Gasification Program, research is focused on the development of advanced
continuous mild gasification systems to produce optimal readily usable
coproducts. The program is funding the development of four 100-lb/hour
pilot units using fundamentally different approaches.
The DOE should continue funding this program, with special attention to
the quality of the liquids produced, the value and marketability of the char,
and the size of the coal resource base that can be used with this technique.
In the future DOE should attempt to scale up one or a combination of the
most promising processes to obtain adequate design data for a commercial
demonstration.
The committee concurs with a number of recommendations on coal py-
rolysis R&D made by an assessment panel to DOE (Schindler, 1989~. The
first was to study the chemistry and mechanisms of catalytic hydropyroly-
sis. Another important recommendation was to conduct a systems analysis
of pyrolysis or hydropyrolysis coupled with gasification and combustion as
a means of utilizing the char.
DIRECT CONVERSION OF NATURAL GAS
Recently, substantial research activities have been conducted in the area
of natural gas (methane) conversion to methanol without the use of syngas
(Kuo, 1984; Kuo et al., 1987~. The primary commercial goal of this re-
search is to convert remote natural gas, which cannot easily be brought to
market and is of little commercial value, into more easily transported liquid
fuels. Except for Alaska, all of the remote low-cost gas is located in other
countries.
Technology and State of Development
Numerous direct methane-to-methanol conversion routes are being stud-
ied at the bench scale by various companies, government agencies, and
universities. These include cold flame oxidation (direct partial oxidation)
in which the main chemical reaction is the oxidation of methane to metha-
nol, direct oxidation involving the catalytic coupling of methane and an
oxidant to produce C-2 products and hydrocarbons, oxychlorination, indi-
rect oxidation with oxidative coupling to ethylene, and catalytic pyrolysis
involving contact of methane with a catalyst. ARCO Oil and Gas Company
appears to be a leader in indirect oxidation, and recent success has been
reported with its REDOX process. Other conversion routes include strong
acid conversion and biological conversion (see Appendix J for additional
technical details).
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Economics
103
Although the technology exists for converting natural gas into liquid
fuels, the cost is too high when the technology involves first converting
natural gas into syngas. The costs for syngas-based fuels from natural gas,
expressed as 1988 dollars per crude oil equivalent barrel, depends on the
technology and assumed rate of return and vary as follows: (1) methanol
from natural gas, $45 to $50/barrel; (2) methanol to gasoline, $60 to 68/
barrel; and (3) the Shell Middle Distillate Synthesis process, $58 to $64/
barrel (see Chapter 3 and Tables D-3 and D-4.
The direct conversion routes have the potential of being more energy
efficient and less expensive since they bypass the formation of syngas.
However, the current level of development has not achieved the potential
significant cost reductions. Gasoline from ARCO's REDOX process costs
more than Mobil's MTG (fluidized bed) process (Schumacher, 1989~.
An analysis of the cold flame oxidation route, showed that based on an
optimistic design the cost of gasoline would be reduced only 7 to 15 percent
(with zero cost for natural gas) compared to the conventional MTG technol-
ogy (Fluor Corporation, 1988~. This analysis also indicated that the cold
flame oxidation route did not have any overall thermal efficiency advan-
tage.
Liquid fuels from domestic natural gas are expensive because of the high
value of domestic natural gas for conventional markets. For example, natu-
ral gas at $5/million Btu represents $33/barrel of the $60/barrel (10 percent
discount rate) cost of MTG gasoline using the fluid bed reactor design.
Even if a direct methane conversion process were developed that used 20
percent less natural gas, the cost of natural gas would represent $26/barrel
of crude oil equivalent of the gasoline cost.
Although Alaskan natural gas would be significantly less costly, higher
capital and transportation costs for liquid fuels produced in Alaska would
offset the gas cost advantage. Estimates show that a natural gas-to-metha-
nol plant would cost 70 percent more to construct at Prudhoe Bay than at a
U.S. Gulf Coast location. Also, shipping methanol to Southern California
would cost about $40/barrel oil equivalent from Prudhoe Bay compared to
$7/barrel from the U.S. Gulf Coast (California Fuel Methanol Study, 1989~.
Even if liquid fuels from natural gas were to become viable owing to a
combination of cost reductions and special situations, exploitation would
use foreign natural gas.
At foreign locations, such as in the Middle East, South America, and the
Caribbean, natural gas would be significantly less costly than domestic U.S.
gas because no local market exists and production costs are low. These
foreign locations also meet the criteria of a reasonable construction cost
environment and low transportation costs to major world markets. For
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FUEI~i TO DRIVE OUR FUTURE
example, methanol plant costs are only 10 to 25 percent more in Middle
Eastern, South American, and Caribbean locations than on the U.S. Gulf
Coast. Transporting methanol from these sites to Southern California was
estimated to cost only $4/barrel oil equivalent (California Fuel Methanol
Study, 1989~.
Recommendations for the DOE
Numerous direct methane conversion routes are being studied at the bench
scale by various companies, government agencies, and universities that avoid
the need to produce syngas as an intermediate. These direct conversion
routes have the potential of being more energy efficient and less expensive
since they bypass the energy-intensive and expensive step the formation
of syngas. However, the current level of development has not achieved the
potential significant cost reductions.
Even if liquid fuels from natural gas were to become viable owing to a
combination of cost reductions and special situations, exploitation would
use less valuable foreign natural gas in a remote location. Therefore, gov-
ernment-sponsored research on direct methane conversion technology should
be limited to fundamental research.
Representative terms from entire chapter:
tar sands
