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4
Thermochemical Conversion of Coal and Biomass
INTRODUCTION
This chapter reviews the thermochemical conversion of coal, biomass, and
combined coal and biomass to liquid transportation fuels. It addresses the questions
raised in the statement of task related to the application of thermochemical conversion to
the production of alternative liquid transportation fuels from those feedstocks by
discussing the following:
• The development status of each major technology with estimated times of
commercial deployment.
• Projected costs, performance, environmental impact, and barriers to deployment
by 2020.
• Potential supply capability, plant carbon dioxide (CO2) emissions, and life-cycle
greenhouse-gas emissions.
• Challenges and needs in research and development (R&D), including basic-
research needs for the long term.
The available technologies are described first, and their status and technical and
commercial readiness are assessed. Detailed cost and performance analysis, R&D and
demonstration needs, environmental impacts, and analysis of greenhouse gas life-cycle
emissions of the key technologies are discussed.
STATUS AND CHALLENGES OF TECHNOLOGY ALTERNATIVES
Thermochemical conversion involves either the gasification of biomass or coal
followed by synthesis to liquid fuels (indirect liquefaction) or the direct conversion of
coal to liquid fuels (direct liquefaction) with high-pressure hydrogen (H2), as shown in
Figure 4-1. Those thermochemical conversion processes are considered to be ready for
deployment between now and 2020. Because of its chemical complexity, biomass can
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also be converted to liquid fuels by pyrolysis or liquefaction. Those routes are not as well
developed.
For each of the technologies, the panel has considered the technological readiness,
costs, environmental impacts, characteristics of the finished products, and barriers to
deployment. The panel also projected the potential commercial contribution that
thermochemical conversion could make in the period 2020–2035 and beyond 2035.
Gasification Options
Processes that break the carbon-containing material down into gaseous products
by gasification and then use those to produce liquid fuels are referred to as indirect
processes to distinguish them from “direct” processes that break coal down into liquid
products without going through gaseous intermediates.
For the indirect route of principal interest, solid feedstock is gasified by reacting it
with sufficient oxygen to increase its temperature to a point where steam can react with
the remaining carbonaceous material to produce syngas, a mixture of carbon monoxide
(CO) and H2. Next, the syngas is cleaned to remove contaminants—such as particles,
sulfur, ammonia, and mercury—and further processed to adjust the ratio of H2 to CO by
using the water–gas shift reaction. The clean syngas is then used to make either a single
product, such as fertilizer or methanol, or multiple products, such as fuels, H2, steam, and
electric power.
Gasification has been used commercially around the world for nearly a century by
the chemical, refining, and fertilizer industries and for more than 35 years by the electric-
power industry. More than 420 gasifiers are in use in some 140 facilities worldwide,
including 19 plants in the United States. Gasification technologies can also be used on the
vast Canadian oil-sand deposits to gasify coke or bitumen to produce H2 and to produce a
substitute natural gas from America’s abundant coal resources (Furimsky, 1998). The
gasification process can convert combined feedstocks, such as coal and biomass, in the
same gasifier at the same time. Thermochemical conversion would use nonfood biomass
feedstocks—such as lignin, cellulose, and plastic wastes—and thus would not raise issues
of competition between the markets for fuel and food.
Synthesis Options
Broadly speaking, two technologies for converting synthesis gas to liquid
transportation fuels have been proved on a commercial scale:
• Fischer-Tropsch (FT) technology. This technology was developed in Germany in
the 1920s, and commercial plants constructed there in the middle 1930s were later used
to produce transportation fuel in World War II. FT technology was commercialized in the
South African Synthetic Oil Corporation (Sasol) complexes beginning in the middle
1950s. The process involves the catalytic conversion of the H2 and CO in synthesis gas
into fuel-range hydrocarbons, such as diesel or gasoline, and naphtha and liquid
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petroleum gas (LPG). Sasol now produces transportation fuels from coal at the rate of
more than 165,000 barrels per day (bpd).
• Technologies based on methanol synthesis. Synthesis gas can also be converted to
methanol with available commercial technology. The methanol can be used directly or
can be upgraded into high-octane gasoline with a proprietary catalytic process developed
by ExxonMobil and referred to as the methanol-to-gasoline (MTG) process. Methanol
can also be converted to a mixture of gasoline and diesel with a variant of the MTG
process called the methanol-to-olefins, gasoline, and diesel (MOGD) process.1 Methanol
synthesis can also be the starting point for producing dimethyl ether (DME) and a broad
array of other chemicals.
Direct-Liquefaction Technology
Direct liquefaction of coal involves a selective depolymerization of coal by
breaking apart the coal structure into smaller units. The depolymerization is typically
accomplished by thermal degradation of the coal with high temperatures and by
simultaneous addition of hydrogen under high pressure. The hydrogen can be added from
the gas phase or through hydrogen donation from suitable solvents in the presence of a
catalyst.. The direct-liquefaction procedures are carried out at about 450oC and at high
pressures up to 30 megapascals (MPa). The product is a synthetic crude oil that can be
refined into liquid transportation fuels. Commercial-scale direct liquefaction started in
Germany in 1926; by 1939, production had reached over 1 million tons a year. A
commercial-scale plant was started up in the United Kingdom in 1935. In the 1970s, pilot
plants were constructed in Japan and in the United States after the oil embargo. All those
plants have been dismantled because of the collapse in world oil prices in the early 1980s.
Although direct liquefaction of coal has been demonstrated and is being scaled up
in China, it is not ready for commercial deployment. Many questions associated with the
design and operation of a direct coal-liquefaction plant require resolution. Most of the
unresolved issues require process demonstration operations and then commercial
demonstration. That would require a closely coupled R&D program to resolve issues and
advance the technology. The panel does not deem the technology ready for commercial
deployment and estimates that an aggressive process and commercial demonstration
program could make it ready for commercial deployment if it shows an advantage for
commercial potential relative to other options for conversion of coal to clean
transportation fuels.
Carbon Capture and Storage
During the conversion of coal and biomass to liquid fuels via direct or indirect
liquefaction, large quantities of CO2 are produced. To minimize emission to the
atmosphere, the CO2 must be captured and stored. CO2 from the off-gas streams of the
1
Some would place the option of methanol to olefins, gasoline, and diesel (MOGD) on the list of synthesis
options. Because of the lack of data and operating experience with that option, only the Fischer-Tropsch
and MTG processes will be described in this section.
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conversion processes can be readily captured with commercially available technologies.
Permanent geologic storage of the large quantities of CO2 that would be produced by a
full-scale liquefaction industry appears feasible but has been demonstrated at only a few
locations worldwide. Although carbon capture and storage are discussed in the context of
the technical overview of indirect liquefaction in this chapter, the issues of feasibility and
commercial readiness apply to both direct and indirect liquefaction of coal.
INDIRECT-LIQUEFACTION TECHNOLOGIES
This section describes the overall indirect-liquefaction process that converts coal,
biomass, or coal–biomass mixtures into liquid transportation fuels (Figure 4-2). Key
elements of this process are gasification, syngas cleanup and conditioning, synthesis, and
product upgrading. The process economics and greenhouse-gas emissions of different
options of indirect liquefaction are compared in a model analysis later in this chapter. The
technical challenges and product characteristics are also discussed.
Process Technical Overview
Gasification involves creating a contact between a carbon-containing feed
material and oxygen (or air) and steam at high temperatures to produce synthesis gas. The
several basic gasifier designs are distinguished by the use of wet or dry feed, the use of
air or oxygen, and the reactor’s flow direction (upflow, downflow, or circulating).
Today’s pressurized entrained-flow coal gasifiers—such as those developed by General
Electric, Conoco Phillips, Siemens, and Shell—can process feedstock at about 3,000
tons/day (tpd). Biomass gasifiers have not generally been used to produce synthesis gas.
They are generally smaller and operate at lower pressures and temperatures than coal
gasifiers. Although there are many fixed-bed biomass gasifiers, fluid-bed and
recirculating-bed systems have been developed.
A 3,000-tpd coal gasifier would produce enough synthesis gas to yield
transportation fuel at about 6,000 bpd by indirect liquefaction. After being ground into
very small particles, the coal can be slurried with water or fed dry into the gasifier with a
controlled amount of air or oxygen and steam. Temperatures in a gasifier range from
1,400°F to 2,800°F. At such high temperatures in the gasifier, steam reacts with the
carbonaceous material of the feedstock to form syngas.
Coal Gasification
A number of technologies have been developed for coal gasification; they include
moving-bed, fluid-bed, circulating-bed (transport), and entrained-flow gasifiers (MIT
2007). The operating temperature and the size of coal feed vary with the type of gasifier.
The moving-bed gasifier was developed by Lurgi and improved by Sasol. It operates at
425–600°C and accepts coal feed sizes of 6–50 mm. The Sasol–Lurgi gasifier has been
used extensively at the Sasol commercial plant in South Africa. Entrained-flow gasifiers
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operate at 1250–1600°C and accept coal-feed particles smaller than 100 µm. Those
oxygen-blown, high-pressure gasifiers have been developed by General Electric (it was
formerly referred to as the Texaco gasifier), Shell, Conoco Phillips (E-Gas), and Siemens
(formerly referred to as the Future Energy gasifier). Fluid-bed gasifiers are less
developed than the other two types. They operate at 900–1050°C and can use coal feed of
6–10 mm. In most types of gasifiers, avoiding soft ash particles is essential because the
particles stick together, stick to process equipment, and typically lead to shutdown (MIT
2007).
Coal gasification is commercially deployable today by using any one of several
gasification systems that are being commercially used. Producing coal-to-liquid (CTL)
fuels and other applications of gasification will lead to further improvements in the
technology so that it would become more robust and efficient by 2020. Those
improvements are part of the usual evolution of any new technology.
Coal and Biomass Gasification
Adding sustainably grown and harvested biomass to the coal feedstock would
allow an increase in domestic fuel supply while reducing total greenhouse-gas emissions
in two ways. First, the emission of carbon in the burning of the fuels made from biomass
is countered by the removal of carbon from the atmosphere by the biomass through
photosynthesis during its growth. Second, the biomass and coal carbon that is converted
to CO2 during the conversion to transportation fuels could be captured and stored.
The notion of gasifying mixtures of coal and biomass to produce liquid fuels is
relatively new, and there has been little commercial experience. Many gasifiers can
gasify biomass, but most of them are small in scale, use air instead of oxygen, and
operate at lower temperatures and at low or atmospheric pressure. Under those less severe
conditions, pyrolysis dominates, and the main products, in addition to syngas, are light
hydrocarbons, bio-oils, tars, and char. Those products make such gasifiers less suitable
for producing FT liquid fuels.
The NUON Shell 253-megawatt electric (253-MWe) integrated gasification
combined-cycle (IGCC) facility in the Netherlands has proved that gasification of
combined wood (30 percent by weight) and coal can be achieved for the generation of
electric power. It has also gasified other biomass feedstocks, including chicken litter.
The operation of a combined coal-and-biomass-to-liquids (CBTL) plant would be
similar to that of a CTL plant, except that biomass is gasified in addition to coal (Figure
4-2). Separate gasifiers could be used for the biomass and the coal, but it might be more
efficient and cost-effective if the same gasifier could convert both feeds simultaneously.
That would be similar to the situation at the NUON discussed above in which the Shell
gasifier was able to gasify both wood and other biomass with the same lock-hopper high-
pressure feeding system.
Combined coal and biomass gasification is deployable today, although the amount
of biomass relative to coal feed is small, as discussed above. Further commercial
development of the technology will make it more robust and efficient and enhance its
ability to use higher fractions of biomass by 2020.
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Biomass Gasification
Published data on high-pressure biomass gasifiers are sparse. Because of the
fibrous nature of most biomass sources, the material is difficult to pretreat and feed into a
high-pressure gasifier. Typical problems include clumping and bridging.
Biomass gasification exhibits many similarities to coal gasification, including the
variety of gasifier types and different available approaches to gasification technology.
However, the reaction conditions are generally milder than for coal gasification because
of the higher reactivity of biomass.
Gasification with direct firing with oxygen at higher pressures and temperatures
produces a relatively pure syngas stream with small quantities of CO2 and other gases.
For temperatures greater than 1,000oC, little or no methane, higher hydrocarbons, or tar is
present.
A major difference between biomass gasification and coal gasification is that the
former generally involves smaller units than the latter because of the limits of the
availability of biomass in a reasonable harvesting area. Biomass gasification therefore
will not have the benefit of economies of scale that larger-scale coal gasification has. The
lack of economies of scale will increase the cost per unit product of biomass gasification
unless major process simplification and capital-cost reduction can be achieved. Like coal
gasifiers, biomass gasifiers can be lumped into specific types, each of which has many
variations.
Several U.S. and European organizations are developing advanced biomass
gasification technologies, and about 10 biomass gasifiers have a capacity greater than 100
tpd operating in the United States, Europe, and Japan (IEA, 2007; Cobb, 2007 ). Those
units have a broad variety of feedstocks, feed capabilities, characteristics, product-gas
cleanup approaches, and primary products. The Biomass Technology Group lists over 90
installations (most are small) and over 60 suppliers of equipment that is used in
gasification (Knoef, 2005). Although several of the available technologies have been
commercially demonstrated, they have yet to be fully demonstrated commercially for
integrated biomass gasification and transportation-fuel production. The panel considers
biomass gasification to be technically ready for aggressive commercial demonstration but
not yet well enough understood to ensure efficient, effective commercial deployment
today. Many variations require understanding and improvement. With an aggressive
commercial development program, biomass gasification technology could be ready for
full-scale commercial deployment by 2015. The major issues to be resolved are related to
engineering, particularly the extent of biomass pretreatment necessary and effective
feeding of biomass to high-pressure gasification reactors. An example of the conversion
of biomass into liquid transportation fuels is the partnership of Choren Industries and
Shell. Choren provides the Carbo V gasification process, and Shell provides the FT
synthesis technology.
Most of the gasification technologies present technical or operational challenges,
most of which can probably be resolved or managed with commercial experience.
Gasifier choice depends on the type of biomass feed and on the specific application of the
gasification or pyrolysis products. The gasifier units will generally be smaller than large-
scale coal gasifiers because of the economics and logistics of the feed supply. The most
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persistent problem appears to be related to biomass feeding, processing, and handling,
particularly if a gasifier has to contend with different biomass feeds.
Syngas Cleanup and Conditioning
The raw syngas produced in the gasification of coal and biomass contains many
impurities, such as CO2, hydrogen sulfide, carbonyl sulfide, ammonia, chlorine, mercury,
and other toxic chemicals. Biomass has much lower sulfur content than coal, and sulfur
impurities in the syngas are correspondingly lower. However, biomass ash can contain
high concentrations of sodium, potassium, and silicon that might pose additional
requirements for the cleanup system. The impurities have to be removed before the
syngas is allowed to contact the synthesis catalysts; otherwise, catalyst poisoning and
deactivation will result. For example, in the conceptual configuration shown in Figure 4-
2, carbonyl sulfide is hydrolyzed to hydrogen sulfide. Ammonia is scrubbed out and
mercury is removed with activated carbon, and CO2 and hydrogen sulfide are removed
with Selexol or another acid-gas removal system. The processes for removing the
contaminants are all commercially available.
In addition to cleaning, the H2:CO ratio is adjusted to be compatible with the
synthesis process by using the water-gas shift process. In this process, CO is converted by
reaction with steam to H2 and CO2. The CO2 can then be removed in the acid-gas
removal system to produce a concentrated stream of CO2 that is suitable for storage. The
same is true for biochemical conversion of biomass to ethanol. The fermentation step
produces a stream of pure CO2 that can be compressed and geologically stored. The
transport and storage cost will be somewhat higher because the amount of CO2 will
typically be smaller for the biochemical conversion route than for a thermochemical
conversion route with an equal biomass feed rate. Because synthesis catalysts are readily
poisoned by minute quantities of sulfur, a polishing reactor that removes sulfur down to
parts per billion is included before the synthesis reactor. Ultimately, the hydrogen and
carbonyl sulfides are converted (99.99 percent) to elemental sulfur, and the mercury is
removed.
Syngas cleanup and conditioning technology is ready for full-scale commercial
deployment today. It will undergo substantial improvement as a result of normal process
evolution and become more robust and efficient by 2020.
Synthesis
Once the syngas produced by gasification of the carbonaceous feed has been
cleaned of impurities and shifted to the desired H2:CO ratio, it can be used to synthesize
liquid transportation fuels. Two major commercial synthesis processes can be used to
produce transportation fuels, such as gasoline, diesel, and jet fuel. These are FT and
methanol synthesis followed by MTG. DME can also be produced by dehydration of
methanol, but it is not a liquid fuel under ambient conditions; it is discussed in Chapter 9.
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Fischer-Tropsch Synthesis
The clean synthesis gas is sent to FT reactors, where most of the clean gas is
converted into zero-sulfur liquid hydrocarbon fuels. If the major required product is
distillate or diesel boiling-range fractions, slurry-phase reactors are used. One of the
limitations of FT synthesis is that it produces a wide array of hydrocarbon products in
addition to some oxygenates. The array of products depends on the probability of chain
growth relative to chain termination. The probability function can theoretically be
modeled with the Schultz–Flory–Anderson relationship, in which the parameter alpha
determines the shape of the probability curve; the higher alpha, the longer the
hydrocarbon chains. To maximize liquid products in the naphtha and diesel boiling range,
it is best to produce waxes first and then to crack the wax selectively to lower-boiling-
point materials.
The low-temperature FT process produces about 10 percent hydrocarbon gases,
25 percent liquid naphtha, 22 percent distillate, and 46 percent wax and heavy oil. The
wax can then be selectively hydrocracked into distillate. With this approach, the overall
product distribution can be skewed in favor of diesel. The clean fuels are recovered, and
the wax is hydrocracked into more diesel fuel and naphtha. The naphtha can be upgraded
into gasoline, but substantial refining is necessary to produce high-octane material
because of the paraffinic nature of naphtha. The CO2 in the FT tail gas is removed for
storage, and the remaining synthesis gas is returned to the FT reactors for additional
liquid production.
The FT process has been used for decades by Sasol and involves reacting
synthesis gas over metal-based catalysts to yield a variety of hydrocarbons that can be
converted to high-quality transportation fuels (gasoline, diesel, and jet fuel). The first
such plant, known as Sasol I, used a combination of fixed-bed and circulating-fluid-bed
FT reactors to produce the fuels. Recently, the Sasol I plant changed from coal to natural
gas as feedstock, and it is now a gas-to-liquid (GTL) plant. In the early 1980s, Sasol built
two large FT-based indirect coal-liquefaction facilities that together produce
transportation fuels at over 160,000 bpd. The plants were designated Sasol II and III.
Twenty years later, the plants are profitable, but they received government subsidies for
several years after startup. They would not have been economically viable in a market
economy with relatively cheap oil and without government assistance.
FT synthesis is continuously being improved; since the building of the large Sasol
plants, there have been substantial advances both in coal-gasification technologies that
produce synthesis gas and in FT technology that produces clean fuels. The Sasol II and
III plants originally used circulating-fluid-bed Synthol reactors, which were later replaced
by fixed-fluid-bed Sasol advanced synthol reactors. These are less expensive, are easier
to operate, and have a much greater fuel-production capacity than synthol reactors.
Research and development at Sasol started experimenting with slurry-phase FT reactors
in the early 1980s and built a 2,500-bpd prototype reactor at Sasol I to demonstrate and
develop the technology. These reactors, which have operated on both iron and cobalt FT
catalysts, formed the basis for the huge slurry reactors that have been installed at the
Oryx GTL plant in Qatar. The slurry reactors, with a diameter of about 36 ft, are each
capable of producing fuels at 17,000 bpd.
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Other companies are also developing FT reactor technology. Shell has developed
the fixed-bed FT process known as the Shell middle-distillate synthesis process. Its GTL
plant in Bintulu has been operating since the late 1980s, and recent improvements in the
reactors and catalysts have increased the fuel-production rate substantially. ExxonMobil
has developed a slurry-bed FT process with a patented cobalt-catalyst system that was the
basis of its Qatar GTL plant design. The company withdrew that project from
consideration in 2007 in favor of a liquefied-natural-gas plant. Conoco Phillips also has
developed a FT system that was demonstrated on a pilot scale in Oklahoma. Syntroleum,
another U.S. company, has also developed a somewhat different FT process for its GTL
system. It has produced sufficient quantities of FT jet fuel for testing by the U.S. Air
Force. The U.S. company Rentech has been developing an FT technology based on a
slurry-bed reactor for a number of years and has recently built a pilot facility in Colorado.
Other experimental FT systems are under development, including a microchannel reactor
being tested by Velocys.
No commercial plant that combines advanced2 coal gasification with advanced FT
technologies has been built. The only operating commercial-scale indirect CTL plants in
the world are the Sasol plants. China—a country with increasing consumption of liquid
fuels, a scarcity of domestic petroleum, and large coal resources—is moving rapidly
toward commercialization of CTL technologies. The Shenhua direct-liquefaction process
in Inner Mongolia launched its first trial operation of fuel production in December 2008.
FT synthesis technology can be considered commercially deployable today. Like
several other ready-to-deploy technologies, it will undergo substantial process
improvement by 2020, which will lead to more robust and efficient technology for
producing liquid transportation fuels.
Methanol Synthesis and Conversion to Gasoline
The other major indirect liquefaction route involves the synthesis of methanol and
its conversion to liquid transportation fuels. Methanol synthesis is a large-scale,
commercial technology that can be supplied by several license holders and is used
commercially to produce methanol from coal. It is well developed, is highly selective,
and is used primarily to convert synthesis gas made from natural gas. The largest
methanol plants can each produce about 5,000 tpd. Methanol is a feedstock for the
manufacture of many chemicals and can be used as a fuel itself. Because of the ubiquity
of methanol manufacture, that process will not be discussed in detail here (Kung, 1980).
The MTG technology developed by Mobil Oil was demonstrated in a commercial
plant in New Zealand (S. Tabak, ExxonMobil Research and Engineering Company,
presentation to the panel on February 19, 2008). MTG technology produces mainly high-
octane gasoline. A variant of MTG involves the conversion of methanol to olefins and
their conversion to gasoline and diesel fuel and is referred to as MOGD. It has not been
demonstrated commercially.
2
Advanced technologies are technologies that are developed or have been improved since the Sasol plants
were deployed. Examples of advanced technologies include the use of cobalt catalysts and improved
reactor designs.
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The key to the MTG process was the development of shape-selective zeolite
catalysts that produce hydrocarbon molecules in the gasoline size range. The principal
product is high-octane gasoline, and the secondary product is LPG. A plant with a
capacity of 14,500 bpd was started in 1985 in New Zealand. It used natural gas as the
feedstock and operated successfully for about 10 years. The drop in crude-oil and
gasoline prices at the time resulted in curtailment of gasoline production and conversion
of the plant to production of chemical-grade methanol. However, the improvements
learned from the commercial operation in New Zealand are being incorporated into a
second-generation plant under construction in Shanxi, China, by Jincheng Anthracite
Coal Mining Company. The plant will feed coal-derived methanol and was scheduled to
start in late 2008. The process uses gas-phase conventional fixed-bed reactors. A coal-to-
fuels project in the United States is also planning to use MTG: a small-scale plant is
under development by Consol Energy and Synthesis Energy Systems to convert West
Virginia coal into gasoline at about 6,000 bpd with the U-GAS® process followed by
MTG. The development of that plant, however, was on hold in 2008 because of
unfavorable economic conditions.
Figure 4-3 shows the schematic flow diagram of the New Zealand natural gas-to-
gasoline complex (Tomlinson et al., 1989), which converts methanol to 38.7 percent
gasoline, 0.7 percent fuel gas, 4.6 percent LPG, and 56 percent water by weight. The
water is recycled as process water. Gasoline produced by the process is completely
compatible with the conventional gasoline infrastructure, and it contains zero sulfur and
is low in benzene (Tomlinson et al., 1989).
The panel considers standard MTG technology to be commercially deployable
today, and, as indicated above, several projects are moving toward commercial
deployment. Several variations of the technology are ready for commercial demonstration
and could provide improvements in the standard MTG technology. They will evolve with
commercial application and become more robust and efficient by 2020.
Challenges and Barriers to Deployment
Because the nation has more than 250 billion tons of recoverable coal reserves
and because there is a considerable potential to provide large quantities of biomass, there
is an opportunity to use the technologies described above to enhance U.S. energy security
by producing clean, fungible transportation fuels to supplement the conventional
petroleum supply. In spite of the large quantity of coal and continued high oil prices,
there were no coal-liquefaction plants in the United States in 2008; but several potential
plants are in the development phase. This section discusses the environmental, economic,
commercial, and social barriers to deployment.
The key components of CTL fuel technology have been commercially
demonstrated and are ready for commercial deployment. However, from a technical and
engineering standpoint, the integration of advanced entrained coal-gasification
technologies, an advanced syngas cleanup process, and advanced slurry-phase FT
synthesis technologies has never been demonstrated on the scale of a large synthetic
liquid-fuel plant. The lack of experience poses a degree of technical risk that would be
considered unacceptable by potential process developers and project funders. The panel
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believes that the technical barriers will be substantially reduced as soon as several first-
mover plants become operational. The financial barriers will still be of concern because
of the potential high variability of the energy markets. The technology is expected to
evolve and improve with commercial experience and to become more robust and
efficient.
Because of concerns about global climate change and GHG emissions, another
major technical barrier is the demonstration that captured CO2 can be stored in geologic
formations for extended periods in a safe, effective, and efficient manner. Resolving
issues of potential long-term leakage and safety will require an aggressive program to
demonstrate geologic storage and to develop data and procedures related to evaluation,
permitting, injection, monitoring, and closure. That will also be needed to gain the
political and popular support required to make geologic storage ready for multiple
commercial deployments. The current status of the technology and the desired work
remaining suggest that it will not be commercially deployable on a broad scale before
2015. Ideally, funds and programs for the design, construction, and operation of three
commercial demonstrations of geologic storage in different geologic formations focused
on gaining the CO2 storage information outlined above will be available soon. Such
programs could be linked to indirect-liquefaction plants that use advanced technologies
or coal-based power plants as total commercial demonstration of technologies with
integrated carbon capture and storage (CCS). Two of the integrated facilities would be
fed by coal of different rank and one by coal and biomass. One or two of the facilities
could be operated to demonstrate geologic CO2 storage independently if integration of
generation and storage causes a substantial delay in the demonstration of geologic
storage.
Carbon Capture and Storage
The central issue in using coal in a carbon-constrained world is its inherently low
ratio of hydrogen to carbon, which results in large CO2 emissions. Unless the resulting
CO2 is captured during conversion and stored permanently (underground or by
incorporating it in some other product), the lifecycle GHG emissions in converting coal
to liquid fuels are about twice as great as those in producing and using fuels based on
petroleum (Jaramillo et al., 2008; Bartis et al., 2009). Therefore, use of coal to produce
liquid fuels in quantities needed to substitute for transportation fuels will require
developing and demonstrating CCS on a large scale, which involves efficient and
economic capture of CO2 and safe and efficient geologic storage. Demonstrating “the
technical, economic, and environmental performance of the technologies that make up all
of the major components of a large-scale integrated CCS project” (MIT, 2007, p. xi) will
take billion-dollar investments by industry and government and could take a decade.
Therefore, it is critical to start those demonstrations, with research involving multiple
fully integrated monitoring and data-gathering activities, immediately (MIT, 2007). To
date, few geologic storage of CO2 demonstrations have been carried out on the needed
scale. Governments and private companies have been hesitant to make the necessary
investment that would ensure that the United States has a robust set of technologies that
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policy and declining oil prices (Burke, 2001). The entire infrastructure (including pilot
plants) of direct liquefaction in the United States was dismantled.
Process Technical Overview
The fundamental concept of direct liquefaction is simple. The intent is to convert
coal into a petroleum-like liquid that can be refined into synthetic products that are
comparable with current refinery products, such as gasoline, jet fuel, and diesel fuel. One
can conceive of the empirical formula of a molecule of “petroleum” as CH1.8 and that of
“coal” as CH0.8. Chemically, one can write
CH0.8 + ½ H2 → CH1.8.
That simple chemical equation has proved to be difficult to reduce to successful
engineering practice.
It is generally agreed that the hydrogenation of coal can proceed best when the
coal is undergoing active thermal decomposition. For most coals, that means operating at
350°C or higher. Such temperatures are thought to be necessary to achieve adequate
reaction rates. The reactions take place in a liquid medium, a process solvent in which
primary reaction products from the coal dissolve. Because of the inverse dependence of
the solubility of a gas (for example, H2) on temperature, the liquefaction reactions needs
to take place at a high pressure of over 134 bar at the reaction temperature.
Continuous feeding of a solid into a pressure vessel is a challenge. Therefore,
virtually all direct-liquefaction process schemes rely on slurrying the coal in a liquid
vehicle. The slurry is then pumped into the reactor. Various concepts for direct
liquefaction used a process-derived recycling solvent as the slurry vehicle. That solvent
might not be expected to participate actively in the chemical processes of liquefaction.
Two potential sources of hydrogen are considered. One approach is to use
gaseous H2. The use of gaseous H2 in direct liquefaction would require the presence of an
active hydrogenation catalyst. Iron compounds were favored as liquefaction catalysts
because of their low cost although other metals, such as molybdenum, are more active
catalysts. The other approach is to use relatively hydrogen-rich compounds in the liquid
to transfer hydrogen to molecular fragments liberated during the decomposition of the
coal. The so-called hydrogen-donor compounds are exemplified by tetralin (1,2,3,4-
tetrahydronaphthalene). Tetralin can transfer four of its hydrogen atoms to the coal
fragments and be converted to naphthalene at the same time. Presumably, the “spent”
hydrogen donors could be regenerated by hydrogenation during the liquefaction reaction
or as a separate operation. Gaseous H2 and a hydrogen-donor solvent can be used
together.
Process concepts also differ in the number of reaction stages to be used. In
principle, a multistage reaction offers an opportunity to optimize the process chemistry
for the specific coal being liquefied. Stages can be operated at different temperatures and
pressures; one could (conceptually) rely entirely on thermal processing in a donor
solvent, a second could involve H2 in the presence of a catalyst, and so on.
The numerous process concepts developed for direct liquefaction all represent
approaches to adding hydrogen to coal to produce a petroleum-like liquid. The processes
differ in the nature of the solvent to be used, how (if at all) spent solvent would be
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replenished, number of process stages, temperatures and pressures in each, residence time
in each, hydrogenation catalysts to be used, and catalyst recovery and regeneration.
At the end of the last stage of liquefaction, the liquid products have to be
separated from unconverted coal and mineral residue. The solid or liquid separation is a
formidable operation, in part because the temperature of the liquid is dropping and, with
pressure letdown, dissolved light molecules are probably flashing to vapor. Both effects
raise the viscosity of the liquid, so the challenge is to separate finely divided solids from
a highly viscous liquid. Centrifugation, solvent deashing, and pressure filtration appear to
be the operations of choice.
The primary liquid will need further refining downstream to be converted to
acceptable marketable products. The refining will probably include some combination of
hydrotreating to remove heteroatoms, hydrogenation for further aromatic saturation, and
hydrocracking to shift the products to lower-boiling-point materials. It has usually been
presumed that the additional refining could be achieved in operations typical of oil
refining.
A direct-liquefaction plant in Inner Mongolia, China, was in trial operation in
December, 2008. It ran for 300 hr during the trial. The plant, a $2 billion facility, will
consume about 3.5 million tons of coal per year and produce 1.8 million tons of products,
of which 70 percent is estimated to be clean diesel fuel. This project was initiated in
1996.
In 2006, the planning of another direct-liquefaction plant in Inner Mongolia, with
Shell as a partner, was announced. The planned plant is estimated to have a capacity of
70,000 bpd, which is about 1 percent of Chinese petroleum consumption. The estimated
cost of this plant is about $5–6 billion (although construction costs in China are not
comparable with those in the United States). It is expected to come on line in 2012.
Overall projections are for Chinese liquid-fuel production via direct liquefaction to reach
50 million tons/year by 2020. As far as is known, no other large-scale projects in direct
liquefaction are under way elsewhere.
Technical Challenges
Downstream of the reactor, material selection for internals in pressure-letdown
valves and selection of effective solid and liquid separation processes remain challenging.
Not all coals are equally amenable to direct liquefaction. However, high-sulfur coals,
which are undesirable for combustion, could be excellent liquefaction feedstocks because
the pyrite in the coal serves as an in situ liquefaction catalyst. (In contrast, low-sulfur
coals are preferred for indirect liquefaction because sulfur has to be removed from the
syngas produced by coal gasification before synthesis.)
The optimal operating conditions for and the product yield slate from direct
liquefaction are known to depend heavily on the specific coal feedstock being processed.
It is questionable how far a universal approach could be used for the design and operation
of plants if, for example, one used Powder River Basin coal, another Illinois Basin coal,
and a third Appalachian coal.
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Direct liquefaction requires substantial amounts of H2. Although H2 could come
from a variety of sources, there would probably be a need to include a coal-gasification
plant for H2 production in or alongside the liquefaction plant.
One of the keys to future commercial development of direct liquefaction is to find
low-severity process routes (for example, low temperature and low pressure) to obtain
liquids from coal. That is likely to require a greater focus on fundamentals of coal
chemistry than on process engineering.
Process Economics
A thorough and detailed economic analysis of direct liquefaction has not been
done in almost 20 years. Numerous studies from the 1970s and 1980s are available. The
numerical results of those studies need to be interpreted and used with caution. The panel
estimated the costs of direct liquefaction on the basis of the DOE study Direct Coal
Liquefaction Baseline Design and System Analysis (1993). Although the cost estimates
are updated to reflect 2007 costs, they are not considered to be as accurate as or to be
fully consistent with the estimates for indirect liquefaction.
The products of direct liquefaction are typically aromatic and contain large
amounts of sulfur, nitrogen, and oxygen. Costs associated with the production of clean
fuels that meet U.S. specifications have typically not been included in published
estimates. For the panel’s work, estimates were applied to include the cost of upgrading
all product streams so that only clean transportation fuels are produced. Plant capital cost,
including complete upgrading, is estimated at $5.5 billion, or about $115,000 per stream-
day barrel. The overall thermal efficiency approaches 60 percent. The yield is below 2.5
bbl of liquid fuel products per ton of coal. Plant emissions are projected at 8.5 kg of CO2
per gallon of product. The total plant CO2 emissions, including fuel, are slightly less than
those of an FT plant. The estimated cost of the liquids produced is about $0.20/gal higher
than for a comparable CTL plant using FT. The overall greenhouse-gas footprint of the
venting plant is expected to be similar to or slightly better than that of the CTL plant
using FT and venting CO2. The direct-liquefaction plant with CCS is at a disadvantage
relative to the indirect-liquefaction plant because it has more flue-gas CO2 to be
recovered. The recovery of CO2 from several flue-gas streams in a direct-liquefaction
plant needs additional equipment and is much more expensive than CO2 recovery in an
indirect-liquefaction plant. That disadvantage could be eliminated through engineering
modification of the plant design, but such changes would come at a cost.
The performance estimate is consistent with data on the Chinese plant under
construction. The product quality of the Chinese plant might fit meet the quality of the
Chinese transportation-fuel system, but transportation-fuel blending stocks in the United
States have to meet essentially the quality of petroleum blending stocks because of tight
specifications for final fuel. Either indirect or direct coal liquefaction requires about $5
billion in capital for a commercial-scale plant. Raising such capital may require
substantial government intervention in the form, for example, of loan guarantees,
incentive programs to offset capital and operations and maintenance costs, or guaranteed
purchases of products to get the industry started. A government–private partnership might
be necessary for the setup of the first few direct- or indirect-liquefaction plants.
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Environmental Impact
Because of coal’s lower hydrogen:carbon ratio than that of petroleum,
transportation fuels produced from direct liquefaction of coal would have much higher
greenhouse-gas emissions than gasoline. If nonfossil sources of energy were used for
hydrogen production and process heat for the conversion processes, the net effect of coal-
based fuels would be about the same as that of fuels from petroleum (NRC, 1990). As
discussed earlier, using biomass–coal mixtures in indirect-liquefaction plants could result
in substantial reduction in greenhouse-gas life-cycle emission. That strategy has not been
tested for direct liquefaction but should be investigated for potentially comparable GHG
reductions.
“The conversion of coal into synthetic fuels can embrace practically any potential
form of pollution and health hazard which can be associated with coal, including
combustion products and ash, phenolic liquors and coal liquids which are exceptionally
rich in known or suspected carcinogens” (Grainger, 1981).
Data on water use, especially in the last few years, seem to be sparse. One
estimate suggests water consumption of about 200 million gallons per year for operation
of a plant with a coal capacity of 2,000 tpd (Comolli et al., 1993). The estimate of about 2
gal of water per gallon of product is consistent with water needs for indirect liquefaction.
Product Characteristics
Finished products from direct liquefaction are intended to be fully fungible with
respect to comparable petroleum products, but that has not been adequately
demonstrated. Direct liquefaction produces low-cetane fuel (cetane index, about 45)
(Mzinyati, 2007). As replacement for fuel oils, coal liquids are considered to be more
difficult to store, to have higher concentrations of potential carcinogens, to produce
higher quantities of nitrogen oxides, and to have a greater soot-forming tendency. Blends
of coal products with petroleum might form precipitates. Production of lighter
transportation fuels appears to be accompanied by high rates of catalyst deactivation and
to require high hydrogen consumption.
FINDINGS AND RECOMMENDATIONS
Gasoline and diesel can be produced from the abundant U.S. coal reserves to have
greenhouse-gas life-cycle emissions similar to or less than those of petroleum-based fuels
in 2020 or sooner if existing thermochemical technology is combined with geologic
storage of CO2. Widespread deployment of such facilities will require major increases in
coal mining and transportation infrastructure either for moving coal to the plants or
moving fuel from the plants to the market.
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Finding 4-1
Despite the vast coal resource in the Unites States, it is not a foregone conclusion
that adequate coal will be mined and be available to meet the needs of a growing
coal-to-fuels industry and the needs of the power industry.
Recommendation 4-1
The U.S. coal industry, the U.S. Environmental Protection Agency, the U.S.
Department of Energy, and the U.S. Department of Transportation should assess
the potential for a rapid expansion of the U.S. coal-supply industry and delineate the
critical barriers to growth, environmental effects, and their effects on coal cost. The
analysis should include several scenarios, one of which assumes that the United States
will move rapidly toward increasing use of coal-based liquid fuels for transportation to
improve energy security. An improved understanding of the immediate and long-term
environmental effects of increased mining, transportation, and use of coal would be an
important goal of the analysis.
Geologic storage of CO2, however, would have to be demonstrated at commercial
scale and implemented by then. Without CCS, the greenhouse-gas life-cycle emission
will be over twice those from petroleum-based fuels. Coal can be combined with biomass
at a ratio of 60:40 (on an energy basis) to produce liquid fuels that have greenhouse-gas
emissions comparable with those from petroleum-based fuels if CCS is not implemented.
With CCS, fuels produced from coal and biomass would have a slightly negative to
roughly zero carbon balance. Cellulosic dry biomass also can be converted
thermochemically to synthetic gasoline and diesel without coal. The greenhouse-gas life-
cycle emissions from those fuels should be close to zero without CCS and highly
negative with CCS, but the cost of fuel products will be higher than the cost of those
produced from coal or combined coal and biomass.
Finding 4-2
Technologies for the indirect liquefaction of coal to transportation fuels are
commercially deployable today; but without geologic storage of the CO2 produced
in the conversion, greenhouse-gas life-cycle emissions will be about twice those of
petroleum-based fuels. With geologic storage of CO2, CTL transportation fuels could
have greenhouse-gas life-cycle emissions equivalent to those of equivalent petroleum-
derived fuels.
Finding 4-3
Indirect liquefaction of combined coal and biomass to transportation fuels is close to
being commercially deployable today. Coal can be combined with biomass at a ratio of
60:40 (on an energy basis) to produce liquid fuels that have greenhouse-gas life-cycle
emissions comparable with those of petroleum-based fuels if CCS is not implemented.
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With CCS, production of fuels from coal and biomass would have a carbon balance of
about zero to slightly negative.
Finding 4-4
Geologic storage of CO2 on a commercial scale is critical for producing liquid
transportation fuels from coal without a large adverse greenhouse-gas impact. This
is similar to the situation for producing power from coal.
Recommendation 4-2
The federal government should continue to partner with industry and independent
researchers in an aggressive program to determine the operational procedures,
monitoring, safety, and effectiveness of commercial-scale technology for geologic
storage of CO2. Three to five commercial-scale demonstrations (each with about 1
million tonnes CO2 per year and operated for several years) should be set up within the
next 3-5 years in areas of several geologic types.
The demonstrations should focus on site choice, permitting, monitoring, operation,
closure, and legal procedures needed to support the broad-scale application of geologic
storage of CO2. The development of needed engineering data and determination of the
full costs of geologic storage of CO2—including engineering, monitoring, and other costs
on the basis of data developed from continuing demonstration projects—should have
high priority.
The configuration of the thermochemical conversion plants produces a
concentrated stream of CO2 that must be removed before the fuel-synthesis step, even in
noncapture designs. Thus, the requirement for geologic storage has only a small effect on
cost and efficiency. On a plant basis, the engineering cost of CO2 avoided is about $10–
15/tonne, but the cost is based on a “bottom-up” engineering estimate of expenses for
drying, compression, transport, land purchase, drilling wells and injecting CO2,
monitoring, and capping wells. Experience with a variety of energy technologies suggests
that the full cost of geologic storage cannot be captured by such an approach, because
some implementation barriers increase costs and are difficult to quantify in advance.
Accordingly, the numerical geologic cost used in this report, which is based on factors
quantified by an engineering analysis, and life-cycle costs for fuels that entail carbon
storage may constitute a lower bound on future costs.
Finding 4-5
There do not appear to be any technical issues that cannot be resolved or any cost
show-stoppers associated with geologic storage of CO2. There is, however, much to
be developed in siting, permitting, monitoring, and site closure; it is essential that
public and political uncertainty be resolved and that costs be better defined.
Uncertainty among the general public and policy-makers about the efficacy and
regulatory environment has the potential to raise storage cost. Ultimately, the
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requirements for siting, design, operation, monitoring, carbon-accounting procedures,
liability, and the associated regulatory frameworks need to be developed to avoid
unanticipated delays in initiating demonstration projects and, later, in permitting and
licensing of individual commercial-scale projects. Extensive experience with storage in
deep saline aquifers has yet to be gained and evaluated. A full assessment of the future
cost of CCS should emphasize, at least qualitatively, the uncertainty arising from such
factors.
Recommendation 4-3
The government-sponsored geologic CO2 storage projects need to address issues
related to the concerns of the general public and policy-makers about geologic CO2
storage through rigorous scientific and policy analyses. As the work on geologic
storage progresses, any factors that might result in public concerns and uncertainty in the
regulatory environment should be evaluated and built into the project decision-making
process because they could raise storage cost and slow projects.
The key technologies required to convert coal and cofed coal and biomass to
liquid transportation fuels have been commercially demonstrated and are ready for
commercial deployment. With geologic storage of CO2, coal can be used to produce
liquid transportation fuels that have greenhouse-gas life-cycle emission that is equivalent
to that of petroleum-derived fuels. Cofed biomass and coal can be used to produce liquid
transportation fuels that are equivalent to those produced from petroleum with respect to
greenhouse-gas life-cycle emission without geologic storage of CO2 and fuels that have
lower greenhouse-gas life-cycle emission with geologic CO2 storage. Technology for
producing liquid transportation fuels with biomass only (BTL) has been demonstrated but
requires additional development to be ready for commercial deployment. It can produce
carbon-neutral fuels; with geologic CO2 storage, liquid transportation fuels so produced
can have negative greenhouse-gas life-cycle emission. Carbon storage in soils by the
biomass crops can enhance the favorable effect of biomass conversion to fuels but is hard
to project because it depends on many situational and agricultural factors. Liquid
transportation fuels produced from biomass alone would be more expensive than CTL
fuels because of the high cost of biomass and the diseconomies of scale for plants that are
small because of limited regional biomass availability. Using both coal and biomass
(CBTL) allows larger plants that can benefit from economies of scale, that have lower
capital costs and use cheaper coal, and therefore, have lower production costs.
Finding 4-6
The advanced technologies for gasification, syngas cleanup, and Fischer-Tropsch
synthesis have been demonstrated on a commercial scale. Their integration on the
scale required to have a substantial impact on fuel production has not been
demonstrated but is not considered a major issue. For first-mover projects to produce
liquid transportation fuels from coal on the scale of a large plant poses a degree of
technical risk; in addition, the risk of price and cost volatility that energy markets have
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shown recently has to be considered. The risk greatly increases the difficulty of
developing and funding first-mover projects.
Finding 4-7
Technologies for the indirect liquefaction of coal to produce liquid transportation
fuels with greenhouse-gas life-cycle emissions equivalent to those of petroleum-
based fuels can be commercially deployed before 2020 only if several first-mover
plants are started up soon and if the safety and long-term viability of geologic
storage of CO2 is demonstrated in the next 5-6 years.
Recommendation 4-4
A program of aggressive support for first-mover commercial plants that produce
coal-to-liquid transportation fuels and coal-and-biomass-to-liquid transportation
fuels with integrated geologic storage of CO2 should be undertaken immediately to
address U.S. energy security and to provide fuels with greenhouse-gas emissions
similar to or less than those of petroleum-based fuels. The demonstration and
deployment of “first-mover” coal or coal-and-biomass plants should be encouraged on
the basis of the primary technologies, including CCS to demonstrate the technological
viability of CTL and CBTL fuels and to reduce the technical and investment risks
associated with funding of future plants. If decisions to proceed with commercial
demonstrations are made soon so that the plants could start up in 4-5 years and if CCS is
demonstrated to be safe and viable, those technologies would be commercially
deployable by 2020.
Recommendation 4-5
The first-mover coal or coal–biomass plants recommended above should be sited so
that they provide CO2 for several of the sponsored geologic CO2-storage projects,
and their progress should be expedited to facilitate the geologic CO2-storage
projects and the further development of conversion technologies. To the extent
possible, the conversion plants and geologic storage should be implemented as a
package. As a first step, a few CTL plants and CBTL plants could serve as sources of
CO2 for a small number of CCS demonstration projects. However, so-called capture-
ready plants that vent CO2 would create liquid fuels with higher CO2 emissions per unit
of usable energy than petroleum-based fuels; their commercialization should not be
encouraged before commercially available CCS is proved to be safe and sustainable.
Finding 4-8
The technology for producing liquid transportation fuels from biomass or from
combined biomass and coal via thermochemical conversion has been demonstrated
but requires additional development to be ready for commercial deployment.
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Recommendation 4-6
Key technologies should be demonstrated for biomass gasification on an
intermediate scale, alone and in combination with coal, to obtain the engineering
and operating data required to design commercial-scale synthesis gas-production
units.
Finding 4-9
Conversion plants that use 60 percent coal and 40 percent biomass as feedstock can
be configured to eliminate recycling of unconverted synthesis gas and thereby
generate a substantial amount of additional electric power. If the CO2 captured
from such a plant is stored geologically, both the liquid transportation fuels and the
electric power produced for sale to the grid could have zero greenhouse-gas life-
cycle emissions. That approach might present a key opportunity to address emissions
from both transportation and power.
Recommendation 4-7
A thorough systems analysis should be developed for process configurations of coal-
and-biomass-to-liquids plants that eliminate recycling of unconverted synthesis gas
and generate substantial additional electric power. The plants’ fuel cost and power
costs, potential to address greenhouse-gas emissions, and potential impact on U.S. oil
consumption should be assessed thoroughly.
Finding 4-10
Technologies for direct liquefaction of coal are less well developed, and the
uncertainties of capital costs and of the refining necessary to produce high-quality
transportation fuels are substantial. The uncertainties will be reduced after the Chinese
Shenhua plant reaches full operation if adequate data are made available.
Recommendation 4-8
The performance, product spectrum, and projected economics of direct and indirect
coal liquefaction should be evaluated and reviewed on the basis of commercial
demonstrations in China and other countries.
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