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--> 6 Clean Fuels and Specialty Products from Coal Coal is currently a major source of fuel for power generation, industrial heat, and, on a smaller scale, manufacture of coke and by-product coal tar. In the mid to long-term, anticipated increases in the cost of natural gas and petroleum relative to coal are expected to increase the incentive for expanded efforts to convert coal to ash-free, low-sulfur transportation fuels and, ultimately, gaseous fuels for domestic use (see Chapter 3). As natural gas prices increase, substitution of gas from coal in natural gas-fired power generation plants may become economic. Advanced combined-cycle and fuel cell power generation technologies will also require the conversion of coal to clean gaseous fuels. In addition to the above major uses, economical use of clean gaseous and liquid products from coal can provide a source of feedstock for chemicals production. This chapter discusses the status of technologies for coal conversion to clean fuels and the role of the DOE in developing and promoting lower-cost, higher-efficiency processes to meet future needs. This discussion is divided into three major sections: gasification of coal, products from the gas obtained from coal gasification, and products from direct liquefaction and pyrolysis of coal.1 Opportunities for economic production of a range of coal-based products using coproduct systems, also known as coal refineries, is then addressed. The chapter concludes with the committee's major findings relating to clean fuels and specialty products from coal. 1 An extensive discussion of coal conversion technologies is provided in another National Research Council report on production technologies for liquid transportation fuels (NRC, 1990). The reader is referred to that report and the references therein for further details of conversion chemistry.
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--> GASIFICATION OF COAL Background Conversion of coal to a gaseous fuel that can be cleaned and used in homes and commercial installations has been practiced for over 200 years. It was a major industry in the United States and abroad until the 1940s. During World War II, the manufacture of liquid fuels was practiced by Germany to provide military fuel, and in this context significant advances were made in gasification technology that formed the basis for present-day gasifiers. The increasing availability of natural gas and petroleum in the United States and other industrialized countries resulted in the replacement of coal-based town gas with natural gas or heating oil. The oil embargo of 1973 and predictions of impending natural gas shortages, however, resulted in major industry and government programs in the United States and Europe to develop gasification systems for production of SNG from coal. This effort led to pilot plant studies incorporating many of the major engineering approaches for development of superior gasification technologies. However, when petroleum and gas prices fell and it became clear that domestic resources were adequate to provide low-cost natural gas at least through the year 2000, the incentive for the construction of facilities for SNG production was eliminated, leaving a relatively few surviving commercial coal gasification systems. These were primarily aimed at manufacture of high-value products, such as methanol, ammonia, and chemicals. Today's emphasis on increased power generation efficiency, and the availability of high-performance gas turbines and fuel cells, have created a strong incentive for development of high-efficiency gasification systems specifically designed to provide fuel for power generation. These systems can differ from systems optimized to produce highly purified synthesis gas for catalytic conversion to chemicals and clean fuels in that dilution by methane and nitrogen is acceptable and a higher level of impurities can be tolerated. State of the Art The status of gasification processes of current interest that are either commercially available or have reached the stage of major pilot plant development is shown in Table 6-1. Gasification processes can be divided into three major classes: entrained-flow, fluidized-bed, and moving fixed-bed. All involve operating pressures up to several hundred psi. For entrained-flow systems, powdered coal is generally first gasified with a mixture of steam and oxygen (or air) in a zone where the main part of the molten slag is collected. The high-temperature products require quenching or cooling prior to cleanup, with resulting loss of thermal efficiency. Entrained-flow gasification systems produce little methane, are relatively compact, and,
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--> TABLE 6-1 Status of Gasification Processes Developera Status Gasifier Exit Temperature °C (°F) Entrained-Flow Processes Texaco (U.S.), CCT Commercial 1260-1480 (2300-2700) Shell (Europe/U.S.) Commercial 1370-1540 (2500-2800) Destec (U.S.), CCT Commercial 1040 (1900) Prenflo (Europe) Commercial/ demonstration 1370-1540 (2500-2800) Koppers Totzek (Europe) -Atmospheric Commercial 1480 (2700) ABB/Combustion Engineering (Europe/U.S.), CCT Development 1040 (1900) IGC (Japan) Development 1260 (2300) HYCOL (Japan) Development 1480-1620 (2700-2950) VEW (Germany) Development Fluidized-Bed Processes KRW (Europe/U.S.), CCT Demonstration/ development 1010-1040 (1850-1900) High-Temperature Winkler/Lurgi(Europe) Demonstration/ development 950 (1750) Exxon Catalytic (U.S.) Development (currently inactive) 760 (1400) Tampella/UGas (Finland/U.S.), CCT Development 980-1040 (1800-1900) MCTI Pulse Combustor/Gasifier, CCT Demonstration/ development 1090-1260 (2000-2300) Moving Fixed Bed Processes Lurgi (dry ash) (Europe) Commercialb British Gas Lurgi (slagging), CCT Demonstration British Gas Lurgi (high pressure, 1,000 psi) Development DOE-Sirrine Advanced Moving Bed (U.S.) Research/ development 850 (1560) a CCT is technology demonstrated in DOE's Clean Coal Technology program (see Table 6-3). b Over 100 units in operation. Sources: COGARN (1987); DOE (1994b). because of the high operating temperature (1040 °C-1540 °C [1900 °F-2800 °F]), involve short reaction times. Entrained solid gasifiers are insensitive to most coal properties as long as the coal can be pulverized to about 80 percent below 200 mesh (44 micron) size. Entrained-flow systems, most notably the Texaco units, have found commercial application during the past decade for production of
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--> synthesis gas for chemical syntheses. The Texaco, Shell, and Destec processes are commercial technologies developed primarily in the United States. As a result of the required high reaction temperature and resulting high oxygen consumption, this class of gasifier has inherently lower thermal efficiency than fluidized-bed and moving fixed-bed gasifiers. The gas produced is relatively free of tars, hydrocarbons heavier than methane, and nitrogen compounds. Because of their proven performance, entrained-flow gasifiers have been chosen for IGCC demonstrations both in the United States and overseas. Such demonstrations primarily address systems integration issues rather than gasifier development. Fluidized-bed gasification systems operate at 760 °C to 1040 °C (1400 °F to 1900 °F), depending on the reactivity of the feed coal and ash softening temperature, and have the potential for higher efficiency. Because the temperatures on exiting the gasifier are well matched to the requirements for hot gas cleanup systems, fluidized-bed gasifiers offer overall efficiency advantages relative to higher-temperature entrained-flow systems that require gas cooling prior to cleanup. Relative to moving bed gasifiers, fluidized-bed units offer higher coal throughput rates, which reduce unit size and cost. Thus, fluidized-bed gasifiers offer an attractive method for producing a wide array of products from coal-derived gas. While no high-pressure systems are classified as commercial technologies, it should be noted that the atmospheric version (Winkler) has been in commercial use for over 65 years. Demonstration programs are under way in Europe and the United States. As discussed later in the section on technical issues and opportunities, the low-temperature Exxon Catalytic Process, with modifications, may offer the potential for high-efficiency, although this program is currently inactive. The lower-temperature, higher-pressure versions of fluidized-bed gasification processes produce methane as well as synthesis gas, which requires less oxygen and increases the efficiency. Due to the low temperatures, the residues (ashes) from fluidized-bed gasifiers are possibly less inert and may require more attention to their disposal in an environmentally secure repository. A special ash agglomeration section, as in the Tampella/U-Gas and KRW gasifiers, can reduce this problem. In the moving fixed-bed gasification process, approximately 2-inch x 1/2-inch-sized coal moves down the reactor counter currently to the gas flow. The countercurrent flow leads to higher efficiency. However, moving bed systems are more costly and more complex than stationary bed systems due to the equipment needed to maintain the flow of solids. Historically, the moving fixed-bed process is the most widely used gasification system. High temperatures above the oxidizing gas inlet decrease as the gases exchange heat and react with the incoming coal and exit temperatures are low. Some pyrolysis products (methane, light hydrocarbons, and tar) escape oxidation, and subsequent removal of the tar is required. The commercial Lurgi process yields an unfused ash clinker; however, a slagging version has been developed in cooperation with British Gas. A high-pressure version (6.9 MPa [ 1,000 psi]) with higher methane yields has been piloted. Use of
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--> in-bed limestone for sulfur capture is proposed, but hot gas desulfurization is also being considered. Because of the relatively long residence times and limitation on reactor diameter, moving fixed-bed units have lower coal throughput than is achieved with fluidized-bed units. Commercial moving bed gasifiers have capacities in the 800 to 1,000 tons/day range. The Shell, Destec, and Texaco high-temperature entrained-flow gasifiers have a single-train capacity, resulting from the small coal particle size and high operating temperature, of up to 2,000 tons of coal/day, corresponding to about 265 MW of electricity. The high-temperature Winkler circulating fluidized-bed system planned for the European KoBra demonstration after the year 2000 has a planned capacity of about 300 MW using brown coal. To date, Lurgi fixed-bed units have a lower capacity than do entrained-flow units. This difference in capacity is subject to change with further development. Gasification Technology and IGCC Performance The first-generation U.S. IGCC systems are scheduled for demonstration in the ongoing CCT program (see Chapters 7 and 8) using the Destec and Texaco entrained-flow gasifiers with design power generation efficiencies of 38 and 40 percent, respectively. Demonstration of the Shell gasifier as part of an IGCC system is under way in the Netherlands, and a Prenflo system demonstration is under way in Spain. Another IGCC demonstration project based on the moving bed British Gas/Lurgi slagging gasifier is included in DOE's CCT program but has not yet been contracted for. Also in the CCT program, a 100-MW IGCC system with a KRW fluidized-bed gasifier has been designed with an efficiency of 40.7 percent. Since all these systems make use of state-of-the-art 1300 °C (2350 °F) gas turbines, increases in efficiency to the 45 percent level projected for second-generation systems depend on the use of hot gas cleanup systems plus improvements in gasifier performance and optimized systems integration. In addition to the method of contacting coal and oxidant (entrained-flow, fluidized-bed, or moving fixed-bed), important gasification choices include the use of air or oxygen, and hot or cold gas cleanup. Table 6-2 presents results of a study of the effects of these variables on efficiency using Illinois No. 6 coal in two gasifiers still in the development stage, namely, the KRW fluidized-bed system and the Asea Brown Boveri (ABB)/Combustion Engineering (CE) air-blown entrained-flow system, both using a General Electric MS7001 (1300 °C [2350 °F]) turbine (Gilbert/Commonwealth, Inc., 1994).2 Both are scheduled for demonstration in the DOE CCT program. 2 The KRW air-blown in situ desulfurization version of the KRW process is scheduled for demonstration under CCT-IV at the Sierra Pacific Power Company. For this process, using Western coal, the ash is sintered and removed as agglomerate. The ABB/CE process is scheduled for demonstration at City Water, Light and Power in Springfield, Illinois, with CCT cost sharing. The first stage of the
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--> TABLE 6-2 Effect of Gasifier Design on IGCC Efficiency Case Number I 1a 2 2a 3 3a Gasifiera KRW fluidized-bed KRW fluidized-bed KRW fluidized-bed KRW fluidized-bed CE entrained-flow CE entrained-flow Oxidant air-blown air-blown air-blown oxygen-blown air-blown air-blown Gas cleanupb in situ plus cold gas in situ plus hot gas hot gas hot gas cold gas hot gas Carbon-to-gas efficiencyc 81.3 86.4 85.9 84.6 79.0 84.5 Coal-to-gas efficiencyc 80.5 85.5 81.8 80.5 77.4 82.8 Carbon-to-electricity efficiencyc 44.9 46.7 46.0 45.0 43.4 45.4 Coal-to-electricity efficiencyc 44.5 46.2 43.8 42.8 42.5 44.5 a KRW, Kellogg-Rust-Westinghouse; CE, Combustion Engineering. b In situ (Cases I and 1a) refers to limestone addition to the KRW gasifier for sulfur removal. Cold gas cleanup is at 315 °C (600 °F) for the KRW system (Case 1) and 230 °C (450 °F) for the CE system (Case 3). Hot gas cleanup is at 565 °C (1050 °F) for all systems and assumes use of candle filters for particulate removal and the General Electric barium titanate system for sulfur removal. c All efficiencies are given as percentages on a higher heating value basis (see Glossary). The carbon-to-gas efficiency refers to the production of cleaned fuel gas, excluding carbon losses. The coal-to-gas efficiency includes all losses. Carbon conversion efficiencies for the KRW system are 99.0 percent for the in situ sulfur removal (Cases I and la), 95.2 percent without in situ removal (Cases 2 and 2a), and 98.0 percent for the CE system (Cases 3 and 3a). Source: Gilbert/Commonwealth, Inc. (1994). The performance estimates in Table 6-2 show an overall thermal energy loss of approximately 15 to 20 percent in the gasification and gas cleanup steps. This results in a penalty of about five to 10 percentage points in electrical generating efficiency. Other findings from this study are as follows: When hot gas cleanup is used, changing from air to oxygen results in an efficiency reduction of approximately one percentage point (Cases 2 and 2a). This stems primarily from the energy requirements of oxygen production. For the air-blown systems, use of hot gas cleanup rather than cold gas entrained-flow system operates at 1480 °C to 1650 °C (2700 to 3000 °F) and produces a molten slag. The second-stage gas leaves at 1070 °C (1960 °F) and is then cooled to allow hot-gas cleanup (540 °C to 590 °C [1000 °F to 1100°F]) with the General Electric zinc titanate/zinc ferrite sulfur removal and candle filtration.
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--> cleanup results in an energy savings of 5 percent and a corresponding electrical efficiency gain of approximately two percentage points (Cases 1 and 1a, plus 3 and 3a). The efficiency advantage for hot gas cleanup is expected to be lower for oxygen-blown systems because of their lower mass flow rates and sensible heat loads. The most efficient system in this comparison is the air-blown fluidized-bed gasifier with hot gas cleanup plus in-bed sulfur removal (Case la). A gain of over three percentage points in net generating efficiency (HHV) is indicated compared to the oxygen-blown entrained-flow gasifier with cold gas cleanup (Case 3) of the type currently under demonstration. However, carbon dioxide emissions increase by 4.5 percent due to the calcination of limestone in the gasifier. The efficiency penalty for coal gasification can be attributed to losses involved in cooling the gasification product, the temperature cycling required by the gas cleanup system, the pressure drops incurred by all gas cleanup systems, and by flow through the gasification reactor. Continued R&D can likely reduce these losses, as discussed below. Technical Issues and Opportunities Improvements in the integration of coal gasification with advanced power generation systems are of greatest current interest. In the mid- to long-term periods (2006 through 2040), the production of hydrogen, clean low- and medium Btu gaseous fuels for industrial and utility use, and synthesis of liquid fuels and chemicals are expected to be major potential applications for coal gasification. For both power generation and fuels production, greenhouse gas concerns are expected to greatly increase the emphasis on improved efficiency. Thus, new and improved gasification processes with higher thermal efficiency will be required. The inherent problem of coal gasification is the high-temperature required to achieve a practical rate of reaction of coal with steam. The temperature varies—depending on the reactivity of the coal and the choice of gasifier—from about 800 °C to 1650 °C (1500 °F to 3000 °F) for uncatalyzed gasification. If the raw exit gases are cooled to the low temperature conventionally required for removal of hydrogen sulfide (H2S) and other contaminants, losses in useful heat are incurred despite use of bottoming cycles and transfer of heat to other process streams. These losses can be minimized by reducing cyclic heating and cooling of the gas. Several approaches are possible. Hot cleanup of the gasification product to minimize or eliminate cooling is currently limited to the temperature range of 650 °C to 760 °C (1200 °F to 1400 °F) and is primarily applicable to integrated gasification gas turbine or fuel cell systems for power generation. In these applications it has the potential for savings of one to three efficiency points relative to
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--> cold gas cleanup and is a major part of the DOE coal R&D program (see Chapter 7). Lowering the gasification temperature reduces these losses, but it also increases the direct formation of methane. The lowering of gasification temperature by increasing the reactivity of the coal (char) is achievable by use of catalysts; this has been studied extensively and piloted by Exxon. Acceptable reaction rates were obtained at temperatures down to 625 °C to 650 °C (1160 °F to 1200 °F). This approach remains a promising opportunity for cost reduction. While methane is an undesirable product for hydrogen or syngas manufacture, its direct formation is advantageous for both SNG manufacture and power generation, since the volumetric heating value of the fuel gas is higher and cleanup and compression energy requirements are reduced. The direct formation of methane during gasification, or by prior pyrolysis, reduces oxygen and steam requirements and reduces the volume and heat capacity of the fuel gases. Use of oxygen instead of air further reduces the heat capacity and volume of the gaseous mixture. The use of oxygen, rather than air, for production of SNG, hydrogen, and synthesis gas-based liquid fuels and chemicals also eliminates dilution from atmospheric nitrogen; most gasification systems have been developed for oxygen use. The manufacture of oxygen requires energy for air compression to drive the separation process and also represents a major capital expense. For gas turbine power generation, therefore, air-blown systems appear attractive. However, the larger volume of gas will increase both temperature cycling and pressure drop losses. Oxygen-blown systems produce about half the gas volume of an air-blown system but consume energy for oxygen manufacture. The cold gas cleanup losses (approximately 1 percent) can also be reduced by tailoring cold gas cleanup to match the emissions requirements for power generation, which are considerably less demanding than for catalytic synthesis of SNG or liquids. For fuel cell systems, to avoid electrolyte degradation, a high level of cleanup might be economically desirable. For use in clean fuel manufacture, air-blown systems that result in about 50 percent nitrogen dilution are impractical. Dilution by methane, while undesirable for stand-alone syngas plants, presents less of a problem in plants when electricity or steam generation can make good use of the waste gas from liquids and hydrogen manufacture. Oxygen-blown systems are, therefore, needed for these applications. As previously discussed (Table 6-2), the loss in power generation efficiency for oxygen-blown versus air-blown systems is about I percent for the KRW fluidized-bed system provided that hot gas cleanup is successful, and this small difference can likely be reduced by further research and optimization. With this small difference, the incentive for development of specialized air-blown systems is not clear. No single gasification process is likely to be optimal for all applications; the wide range of coal properties will, in itself, affect the choice. An overriding need is for mechanical simplicity. Solid reaction systems are notoriously difficult to
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--> extrapolate, making development of any system to commercial scale a costly operation (about $0.5 billion for each process). Thus, careful selection of R&D and demonstration programs to be pursued is extremely important. For maximum efficiency, the following general guidelines are offered: minimum gasification temperature to reduce temperature cycling and oxygen consumption and to maximize methane production. Production of fused ash to minimize solid waste removal/disposal problems also is an important goal. The use of catalysts to allow lower-temperature operations appears attractive to achieve significant improvements in efficiency and to minimize the production of tars. The cost of using catalysts would be a disadvantage. Current Programs DOE's participation in R&D and demonstration of gasification technologies falls into three categories: CCT programs,3 development programs, and advanced research programs related to gasification. The last two fall within the scope of the coal R&D program in DOE's Office of Fossil Energy. The CCT programs summarized in Table 6-3 all involve gasification for power generation. The gasifiers, while constituting a fraction of the total program cost, are an essential feature of each demonstration. The gasification systems being demonstrated represent technologies of commercial interest to companies within the United States, including affiliates of overseas companies. Overall, the program should provide a basis for commercialization of IGCC power generation plants, as well as a framework for future advances in gasification efficiency and cost reductions for power generation. Of the seven programs, five plan to use the currently experimental hot gas cleanup—one on a 10 percent slipstream. Use of cold gas cleanup reduces efficiency by approximately two percentage points (see Table 6-2). Four of the programs will use air as the oxidant with an efficiency advantage of approximately 1 percent over the use of oxygen. These advantages are specific to dedicated power generation systems and would not be applicable to the supply of hydrogen or syngas for coproduction of liquid fuels. Recent DOE budgets for surface coal gasification are shown in Table 6-4. The major expense is for construction of facilities for development of an Advanced Hybrid Gasification System. This facility is designed for development of an air-blown moving fixed-bed system with hot gas cleanup. The proprietary CRS Sirrine Engineers, Inc., PyGasTM staged gasifier has been selected for development with 20 percent industry cost share (CRS Sirrine Engineers, Inc., 1994). Given the committee's concern regarding optimization of gasification systems and the central role of the PyGasTM staged gasifier in the DOE program, the proposed technology is discussed below in some detail. 3 The general nature of CCT programs is discussed in Chapter 8.
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--> TABLE 6-3 Gasifier Systems Being Demonstrated for Power Generation Under the CCT Program Gasification Technology Name, Location Oxygen or Air-blown Hot or Cold Gas Cleanup Total Project Costa (millions of current $) DOE Cost Shareb (millions of current $) Entrained-flow Texaco, Polk Power Station, Tampa Electric Co. Oxygen Cold plus 10 percent hot 241.5 120.7 Destec, Wabash River Station, PSI Energy, Inc. Oxygen Cold 396.0 198.0 ABB Combustion Engineering, Lakeside Station, City Water, Light and Power Air Hot 270.7 129.4 Fluidized-bed KRW, Tracy Station, Sierra Pacific Power (Pinon Pine) Air Hot 270.0 135.0 MCTI Pulse Combustor, Caballo Rojo Mine Air Hot 37.3 18.7 Tampella U-Gas, Toms Creek Mine, Va. Air Hot 196.6 95.0 Moving fixed-bed British Gas Lurgi, slagging, Camden IGCC, Duke Energy Corp. Oxygen Cold 780.0 195.0 a Total value of projects is $2,192.1 million. b Total DOE cost share is $891.8 million (40 percent). Source: DOE (1994b).
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--> Coal, air, and steam are contacted in a co-current flow duct where the temperature rises to 815 °C to 980 °C (1500 °F to 1800 °F) and pyrolysis of the coal occurs. The hot pyrolyzed coal (char) falls to the top of a countercurrent fixed-bed gasification section, and dry ash is withdrawn at the bottom. Remaining tars are cracked in a tar cracking zone where the temperature is increased by addition of air. The pyrolyzed gases join the hot gas leaving the countercurrent section to produce a 112 Btu/dry standard cubic foot gas stream. The product gas temperature is expected to be around 815 °C (1500 °F). In Phase I of the project, limestone will be included to capture sulfur in the bed. The spent lime, which exceeds the amount of coal ash, must be treated to oxidize the calcium sulfide before disposal. Use of hot gas cleanup is proposed for a later phase of the program. This system appears to have potential for efficient integration with hot gas cleanup in a power generation system. However, because it is air-blown it would not be a good choice for coproduction of clean gaseous or liquid fuels. In addition to the programs given in Table 6-4, there is a program for developing the Wilsonville facility centered around hot gas cleanup. In January 1992 the hot gas particulate removal test facility at Wilsonville, Alabama, was expanded to include system development and integration studies for advanced power systems and was renamed the Wilsonville Power Systems Development Facility. The facility could ultimately be reworked for gasifier research. The proposed FY 1995 budget for this facility is $12.9 million. The two gasification research programs suffered a 58 percent reduction in funding in FY 1994, with a further reduction proposed in the FY 1995 budget request. These small programs ($0.8 million) are not sufficient to take advantage of the opportunities identified for further improvements in efficiency of gasification systems. Some additional discussion of advanced research opportunities for gasification can be found in Chapter 9. TABLE 6-4 DOE Budget for Surface Coal Gasification (thousands of current dollars) FY 1993 FY 1994 FY 1995 (request) Design and construction of advanced hybrid gasification systems 5,350a 8.205 10,140 Systems analysis and small-scale experimentation for syngas and hydrogen 765 453 395 Modeling, advanced gasification concepts, and catalytic gasification 1,447 471 410 a Involves industry participation with 20 percent cost share. Source: DOE (1994a).
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--> processes with electricity as a coproduct may offer research opportunities specific to coal. The results of DOE-sponsored design and systems studies on the cost of coal liquids production for stand-alone indirect liquefaction plants and for coproduction of coal liquids with gasification-based power generation are discussed below (see Coal Refineries and Coproduct Systems). PRODUCTS FROM DIRECT LIQUEFACTION AND PYROLYSIS OF COAL Direct Liquefaction Background In direct liquefaction, hydrogen is added to coal in a solvent slurry at elevated temperatures and pressures.5 The process was invented by Friedrich Bergius in 1913 and was commercialized in Germany and England in time to provide liquid fuels during World War II. The first U.S. testing of direct liquefaction processes followed World War II (Kastens et al., 1949); efforts in the area declined when inexpensive petroleum from the Middle East became available in the early 1950s. Interest revived when the Arab oil embargo of 1973 caused high oil prices, resulting in increased federal funding for such research. A variety of process concepts were examined on a small-scale (10 to 20 tons/day), and three—Solvent Refined Coal, Exxon Donor Solvent, and H-Coal—were tested on a large scale (200 to 300 tons/day) in the late 1970s and early 1980s (NRC, 1990). The DOE provided much of the funding for these successful demonstrations, but none of the processes proved economical when oil prices fell in the early 1980s. Overseas, Veba Oil and others built and operated a large-scale pilot plant at Bottrop, Germany, in the late 1970s and early 1980s. The facility is currently being used to hydrogenate chlorinated wastes. This facility was funded primarily by the German government. Demonstration of the liquid solvent extraction process developed by the British Coal Corporation is continuing at the Point of Ayr Plant in Wales with both industrial and government support. In the late 1980s the Japanese operated a 50-ton/day liquefaction plant in Australia (NRC, 1990). State of the Art Products of direct coal liquefaction can be refined to meet all current specifications for transportation fuels derived from petroleum. Major products are likely to be gasoline, propane, butane, and diesel fuel. Production of high-quality 5 Direct liquefaction is generally believed to be 5 to 10 percent higher in efficiency than indirect liquefaction because of lower consumption of gasified coal (Stiegel, 1994).
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--> distillate fuels requires additional hydrogen to decrease smoking tendency and to increase cetane number for use in diesels. High octane is achieved by the high aromatic content of the liquids. At one time, this was considered to be an advantage; however, the CAAAs (Clean Air Act amendments) of 1990 place sharp limits on the aromatic content of motor fuels in the United States. Fortunately, the benzene content of gasoline made from coal is extremely low; the concentration of other aromatics can be reduced by hydrogenation to produce naphthenes at a modest increase in cost. This increases the volume of the products, decreases the octane number, and increases process hydrogen consumption. The projected cost for direct coal liquefaction has dropped by over 50 percent since the early 1980s (Lumpkin, 1988). Recent improvements in economics cannot be attributed to any single breakthrough but rather to the accumulation of improvements over several years of operation, notably the following: A more effective and reliable process was developed to remove solids from the liquid product by controlled precipitation, replacing a filtration process. A second catalytic reactor was added to improve control over the chemistry of liquefaction. This reactor was first installed downstream of the solids removal and distillation systems; moving the reactor upstream further improved operation. Some of the recycled liquid used to slurry the feed coal was bypassed around the solids removal unit, increasing the efficiency of the unit. Improved catalysts were added to both the first and second reactors. This series of modifications led to higher liquid yields, improved conversion of nondistillable liquids, less rejection of energy along with discarded coal minerals, and increased throughput relative to early two-stage systems. The success of this evolution shows that steady R&D can achieve major technological advances over time. The current U.S. direct liquefaction technology appears to be the best for U.S. coals, but work continues overseas with emphasis on other coals. All of the foreign projects have had the bulk of their financing contributed by government. Current Programs U.S. research into direct coal liquefaction continued after the big pilot plants were abandoned in the 1980s, but both industrial and DOE activities have steadily decreased with time. Small test units capable of continuous operation for sustained periods of time were available at Hydrocarbon Research, Inc., Exxon, Lummus-Crest, the University of Kentucky, and Amoco Corporation, but today are either shut down or only in limited use. The Advanced Coal Liquefaction R&D Facility in Wilsonville, Alabama, operated full-time through 1991. Hydrocarbon Research, Inc., started up a smaller facility in the second half of 1992 under DOE sponsorship. The unit operates approximately half-time, but funding
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--> beyond 1994 is uncertain. Research at West Virginia University on the production of coal-derived precursors using solvent extraction techniques as carbon product feedstocks has been supported by DOE. However, DOE funding for advanced research in direct liquefaction has decreased in recent years (see Chapter 9). Technical Issues, Risks, and Opportunities A 1989 assessment of research needs conducted by DOE's Office of Program Analysis outlined a comprehensive program aimed at bringing down the cost of direct liquefaction (Schindler, 1989). Industry participants in the aforementioned study stressed the need for federal funding of a large-scale pilot plant capable of processing 150 tons or more of coal per day, but such a unit was never funded. In addition, funding of intermediate-size flow units of the size of the Hydrocarbon Research, Inc. facility was recommended to test changes in process configuration at reasonable cost. Smaller pilot plants are needed to evaluate catalysts, explore operating conditions, and provide low-cost testing of new ideas. A design and system analysis study, based on runs at the DOE Wilsonville plant, was carried out by a Bechtel-Amoco team under contract to PETC (DOE, 1993b).6 Using Illinois No. 6 coal (bituminous), the equivalent crude price was approximately $33/bbl, compared to estimates of $44/bbl prepared for an earlier study (NRC, 1990). This cost reduction results from the incorporation of more recent results from the DOE Wilsonville plant, improved gasification, and from inclusion of 3 percent inflation in the DOE-sponsored estimates. The earlier estimates assumed 10 percent return and did not include inflation. If inflation were eliminated from the current DOE-sponsored calculations, the equivalent crude cost would be increased by approximately $5/bbl. An extension of the Bechtel-Amoco study will be based on lower-cost Wyoming coal and is expected to reduce the equivalent crude costs to slightly less than $30/bbl. On the basis of achievements to date, there is now optimism at DOE and among some industry groups that the $25/bbl target (in 1991 dollars) set by DOE (DOE, 1993a) may be attainable by sustained R&D and continued optimization studies. The 1989 assessment (Schindler, 1989) also recommended a broad range of fundamental and exploratory research, based on the recognition that possible improvements to the current technology may be limited but that advances in conversion chemistry may bring down the cost of liquid fuels produced from coal to be competitive with petroleum products. Possible approaches to conversion chemistry that might achieve costs below the current $25/bbl goal include low-pressure reaction (2.17 MPa [300 psig] or less), direct use of gasifier product, use 6 This study assumed nth plant costs with 3 percent per year price inflation over the plant life, 25 percent owner equity with 15 percent return, and 8 percent interest charges for the 75 percent loan.
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--> of low-cost subbituminous coal or lignite, removal of oxygen in coal as carbon dioxide, and elimination of product hydrocarbon gases (increased selectivity). Integration of direct coal liquefaction with an existing petroleum refinery could take advantage of existing facilities and ease the transition between petroleum and coal feedstock. DOE sponsored work on simultaneous processing ("coprocessing") of coal with heavy petroleum fractions in an ebullated-bed hydroprocessing reactor. One CCT program submission utilizing this technique was selected for funding but was unable to find the private sector funding needed to proceed. Coal Pyrolysis Pyrolysis of coal dates back to the eighteenth century, using temperatures below 700 °C (1290 °F) in fixed- or moving fixed-bed reactors. The primary product was a low-volatile smokeless domestic solid fuel, although the value of the liquid products was also soon recognized. During the 1920s and 1930s there was a great deal of R&D in low-temperature processes, but interest dwindled 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). Pyrolysis kinetics are reasonably well understood and have been modeled extensively (Solomon et al., 1993). Both yield and liquid fuel properties depend on pyrolysis conditions. Pyrolysis under mild temperatures (500 °C to 700 °C [930 °F to 1290 °F]) and pressures (up to 50 psig) with rapid heat-up can produce high liquid yields without adding hydrogen. However, a significant part of the feed coal remains as char with market value comparable to or somewhat less than that of the feed coal. Coal pyrolysis offers some promise of lower liquid costs if the char can be upgraded to higher-value specialty products, such as form coke, smokeless fuel, activated carbon, or electrode carbon, or if the liquid yield can be significantly increased by using low-cost reactants (steam and carbon dioxide) or catalysts. Pyrolysis liquids have a low hydrogen-to-carbon ratio, generally less than one, in contrast to petroleum tars and bitumens (around 1.4) and high-quality petroleum products (approximately 2.0). They also contain substantial amounts of oxygen, compared to tars, and thus require more extensive hydrogen addition to produce specification fuels. Their tendency to polymerize on standing can cause operational problems, which also must be addressed. Little heat is required to produce pyrolysis liquids from coal, however, and production as a side stream to coal gasification or fluidized-bed combustion is efficient. Pyrolysis reactors generally operate at modest pressures and temperatures compared to other coal conversion systems and offer high throughput. Both of these features lead to low capital cost. The cost of pyrolysis liquids could thus be low and might be competitive with bitumen or for integration with oil refinery
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--> hydroconversion operations where their solubility characteristics could improve the operability of hydrocarbon units. They could also be combined with direct coal liquefaction. When made from low-sulfur coal, pyrolysis liquids have limited potential as a substitute without refining for petroleum fuel oil, and an ongoing CCT program (ENCOAL Mild Coal Gasification project) is aimed at this market. Pyrolysis liquids have traditionally been a source of coal tar chemicals, and the DOE Mild Gasification program is aimed, in part, at this market (see below). The budget for the DOE Advanced Clean Fuels Program within the FE coal R&D activity underwent a 30 percent reduction between FY 1993 and FY 1994, and a further 45 percent reduction is proposed for FY 1995 (see Table 2-1). These budget decisions reflect a diminished commitment to the use of coal for production of clean liquid fuels by either indirect or direct liquefaction. Of particular note is the proposed reduction of 84 percent in FY 1995 funding for Advanced Research and Environmental Technology; programs in this area are expected to lead to improvements in efficiency and cost reductions for liquid fuel production (see Chapter 9). COAL REFINERIES AND COPRODUCT SYSTEMS A coal refinery or coproduct system is defined as ''a system consisting of one or more individual processes integrated in such a way as to allow coal to be processed into two or more products supplying at least two different markets" (DOE, 1991). The concept resulted from the realization that coal must be processed in nontraditional ways to meet the needs of potential expanded markets. A key feature of the coal refinery concept is the production of more than one product form, for example, steam and electricity or fuel gas and electricity. The concept can be generalized to include cogeneration of steam and electricity, production of fuel gas for both industrial heat and electricity generation, production of syngas for manufacture of chemicals and/or fuels, capture and use of pyrolysis tars for chemicals and fuels manufacture, and production of specialty cokes. Cogeneration Cogeneration was initially practiced in energy-intensive industrial plants to meet internal needs for steam and electricity. Steam and electricity coproduct systems are now a major commercial activity. With few exceptions cogeneration facilities are designed to use natural gas because of the lower investment compared to a plant that uses coal. As natural gas prices rise to a level that renders the higher investment in coal facilities economically advantageous, advanced cogeneration systems, where the first step is gasification, could also supply coal liquids, fuel gas, and syngas made from coal. Currently, there appears to be ample
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--> opportunity for a variety of coproducts produced by the primary coal gasification process. Steam and electricity would continue to be major products. It seems reasonable to expect that the time for introduction of cogeneration systems based on coal would approximately correspond to the time when the projected cost and/or availability of natural gas would justify investment in new coal-based, power-generating facilities, perhaps during the mid-term period (2006-2020). This time might well arrive before manufacture of synthetic natural gas is required to meet domestic demand. The large world resources of petroleum and bitumen, combined with low prices, are expected to defer manufacture of liquid transportation fuels from coal until the price range is $25 to $30/bbl, although security considerations could call for an earlier date. The first major opportunity for coproducts would then arise from the predicted mid-term need for new high-performance coal-based, power generation systems. These high-performance systems will probably involve coal gasification offering the possibility of coproducts from the gasifier (syngas, fuel gas, and pyrolysis tar). The production of coproducts, in conjunction with SNG manufacture, was of major commercial and DOE7 interest until the 1980s, when low oil and gas prices and ample supplies eliminated the near-term economic incentive for synthetic fuels processes. The expected growth in coal-based power generation appears to offer a more robust opportunity for fuel and chemical coproducts than the traditional single product or dedicated plant approach. The business environment and regulatory changes that have encouraged cogeneration could provide a framework for extension to the use of coal as a source of energy and a resulting greater variety of coproduct streams. Recent industrial concerns regarding efficient production of major products and conservation of capital are resulting in steam and power being supplied by external companies that build and operate facilities for supply of steam and electricity to both local manufacturing plants and utilities. In some cases these companies are subsidiaries of a utility. Such companies might supply fuel gas and syngas to chemical and petrochemical companies. Nonetheless, the complexity of the potential business relationships and the need for a flexible approach should not be underestimated. With today's emphasis on increased generation efficiency and the availability of high-performance gas turbines and fuel cells, an incentive for development of high-efficiency gasification systems specifically designed to provide fuel for power generation has been established. As discussed earlier, these systems can differ from systems optimized to produce highly purified synthesis gas for conversion to chemicals and clean fuels in that dilution by methane and nitrogen is acceptable; a higher level of impurities can also be tolerated. 7 Prior to the formation of DOE in 1977 programs were conducted under the auspices of the Energy Research and Development Administration.
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--> Indirect Liquefaction DOE-sponsored design and systems studies by the Mitre Corporation and Bechtel (Gray, 1994; Tam et al., 1993) have provided information on cost for both present-day stand-alone indirect liquefaction plants and coproduction of coal liquids with gasification-based electrical power generation.8 For the stand-alone F-T synthesis, the Mitre study found an equivalent crude price of $35/bbl. Coproduction with electricity reduced the equivalent crude cost by $5 to $6/bbl to approximately $30/bbl. The savings for coproduction were attributed to a combination of better heat integration and the economies involved in once-through operation. The study by Bechtel estimated a difference in equivalent crude cost of coal liquids produced by stand-alone and coproduction methods of approximately $7/ bbl. For coproduction, the gasoline boiling range fraction was sent to the turbines, thus reducing total liquid production but also avoiding the costs of upgrading the low-octane-number naphtha produced by this process. While the required selling price was similar to that for the Mitre study, the assumed refined product values were higher, with a larger assumed premium for the diesel fuel. This assumption, together with other cost differences, makes comparison of the two studies difficult. The Bechtel study estimates an equivalent crude price for coproduction of somewhat less than $25/bbl. The cost estimates from the Bechtel and Mitre studies differ significantly from those found in a previous National Research Council study (NRC, 1990), where the estimated equivalent crude price was greater than $40/bbl for the stand-alone plant. The difference results from a combination of the inclusion of inflation in the DOE-sponsored studies, higher product values, improved gasification technology, and use of the slurry reactor. World oil prices in 2010 are projected to be in the range of $18 to $34/bbl (EIA, 1994). For the EIA reference case, the projected oil price in 2010 is $28/ bbl, indicating that, on the basis of the estimated costs discussed above, indirect liquefaction could be of commercial interest within the mid-term timeframe (2006-2020). However, it is important to note that the estimated costs from the Mitre and Bechtel studies are for the "nth" plant and are below pioneer plant costs. As in the case of advanced power generation technologies, early market entry would likely require some federal cost sharing (see Chapter 8). Direct Liquefaction Coproduction of coal liquids and electric power based on IGCC systems offers additional opportunities for cost reduction in the production of hydrogen, which could be used for direct liquefaction. No estimates of the magnitude of possible benefits are available for direct liquefaction; however, they would prob- 8 See Chapter 2 and the Glossary for discussion of financing options.
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--> ably be somewhat less than those predicted for the F-T process because of lower synthesis gas consumption. Current Programs The U.S. Congress, in EPACT, directed DOE to examine the potential of coal refineries, evaluate their potential for meeting new markets, outline R&D needs for potential commercialization, and prepare a report on the subject for congressional consideration (see Appendix B). DOE activities related to this directive have included continuation of the program sponsored by DOE's Morgantown Energy Technology Center aimed at commercialization of the mild gasification process, which is based on pyrolysis and is directed toward producing specialty cokes and tars for production of chemicals. No further funding for the program has been requested for FY 1995. In addition, the ENCOAL mild coal gasification project is being funded by DOE on a 50/50 cost-share basis with ENCOAL Corporation under Round III of the CCT program. The two year operational test period began in July 1992, and solid process-derived fuel and coal-derived liquids have been produced. DOE has also issued the mandated report to Congress (DOE, 1991). DOE coal R&D funding for systems for coproducts is divided into two categories: the mild gasification program and conceptual studies of coproduction of electricity and coal liquids. The former activity at the Illinois Mild Gasification Facility is cost shared with Kerr/McGee. It received $1.5 million in FY 1993 and $3.9 million in FY 1994; no funding was requested for FY 1995. A similar process is addressed in the ENCOAL CCT project, thereby reducing the incentive for major continuation of funding under the coal R&D program. A conceptual study of electricity and coal liquids production—as proposed in the FY 1995 congressional budget request—could extend the existing preliminary studies. In FY 1995, $0.6 million was requested for this study; there was no funding for this activity in FY 1993 and FY 1994. FINDINGS Coal Gasification Technology Technology for the manufacture of clean gas is unique to coal-based systems; technology development is not addressed in DOE Fossil Energy programs other than those relating to coal (FE coal R&D and CCT). The expected major future use of coal gasification in power generation has stimulated industrial R&D for gasification systems tailored to high-efficiency power generation requirements. Seven systems are scheduled for demonstration in the CCT program. However, further improvements in gasifier performance are
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--> required to achieve DOE's 45 percent efficiency goal for second-generation IGCC systems. Use of coal gasification for supply of clean gaseous and liquid fuels, in addition to uses for power generation, provides an incentive to develop improved processes for this set of interacting needs. Fluidized-bed systems, with possible use of catalysts, offer an attractive method for providing the entire array of products from coal because of their temperature characteristics and compatibility with hot gas cleanup systems. There are systems integration and research opportunities for further improvement in combined gasification/gas cleanup efficiency. The air-blown fixed-bed gasifier scheduled for development at the DOE Gasification Product Improvement Facility may be competitive for use in a hot gas cleanup combined-cycle power generation system. If cold gas cleanup is used, the overall advantage over current commercial systems is not clear. Despite opportunities for technology improvement, the proposed FY 1995 budget indicates reductions in funding for gasifier development, systems studies, and research. Gaseous Products Manufacture of low- and medium-Btu gas is expected to play a major role in high-efficiency power generation systems, as a source of syngas and hydrogen for manufacture of coal-based liquid fuels, and for production of industrial chemicals. Improvements in gasification efficiency and reductions in capital cost offer major R&D opportunities. While domestic natural gas is currently favored as fuel and as a source of hydrogen and synthesis gas, projected increases in price and decreased availability will increasingly favor use of coal-based gases. Displacement of natural gas by coal-based low- and medium-Btu gas can extend the supply of low-cost natural gas for domestic and commercial consumers and postpone the need for synthetic natural gas facilities. Minimum CO2 production, as well as cost, will be important factors in the choice of processes to manufacture gaseous products from coal. Efficient separation of gaseous products and gas cleanup processes offer opportunities for improvement. Liquid Fuels from Coal Advances in coal gasification and liquefaction technology have reduced estimated costs to approximately $33/bbl equivalent crude oil cost for mature (i.e., not pioneer) single-product plants using direct liquefaction with Illinois No. 6 coal.
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--> Experience with sustained R&D indicates that DOE's goal of $25/bbl (1991 dollars) for coal-based liquids may be attainable with continued research and systems studies. Industrial programs have been drastically reduced. The DOE budget for FY 1995 proposes a drastic reduction in liquefaction activities. Coal Refineries and Coproduct Systems The concept of coal refineries or coproduct systems, defined as the production of more than one commercial product from coal, offers opportunities for optimization and significant cost reduction of coal conversion systems relative to single-product plants. Coproduction with electricity has the potential to reduce indirect coal liquefaction costs by $6/bbl or more, indicating that pioneer production of liquids may become economically attractive in the timeframe projected for widespread construction of advanced gasification power generation facilities. Opportunities for coproducts could determine the choice of gasification technology. Systems studies are needed to identify the major research, development, and commercialization opportunities. The first major opportunities for implementation of coal refineries will likely involve electric power as the major product. Indirect liquefaction could well be the first application of coproduction with electricity. The large reduction in FY 1995 funding for DOE coal R&D programs relating to coproduct systems is caused by discontinuation of the mild gasification activity. DOE has proposed $0.6 million for conceptual studies of coproduction of liquids and electricity. REFERENCES CRS Sirrine Engineers, Inc. 1994. Gasification Product Improvement Facility Status. Paper presented at the Contractors Conference, U.S. Department of Energy, Morgantown Energy Technology Center, Morgantown, West Virginia, June. COGARN. 1987. Coal Gasification: Direct Applications and Syntheses of Chemicals and Fuels. U.S. Department of Energy Coal Gasification Research Needs (COGARN) Working Group, DOE/ ER-0326. Washington, D.C.: DOE. DOE. 1991. Report to Congress: Coal Refineries, A Definition and Example Concepts. U.S Department of Energy, Office of Fossil Energy, DOE/FE-0240P. Washington, D.C.: DOE. DOE. 1993a. Clean Coal Technologies: Research, Development, and Demonstration Program Plan. U.S. Department of Energy, DOE/FE-0284. Washington, D.C.: DOE. DOE. 1993b. Direct Coal Liquefaction Baseline Design and System Analysis: Final Report on Baseline and Improved Baseline, Executive Summary. Prepared for U.S. Department of Energy, Pittsburgh Energy Technology Center, under contract no. DEAC22 90PC89857. Pittsburgh, Pennsylvania: DOE. DOE. 1994a. FY 1995 Congressional Budget Request. U.S. Department of Energy, DOE/CR-0023, Vol. 4. Washington, D.C.: DOE.
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--> DOE. 1994b. Clean Coal Technology Demonstration Program: Program Update 1993. U.S. Department of Energy, DOE/FE-099P. Washington, D.C.: DOE. EIA. 1994. Annual Energy Outlook 1994. Energy Information Administration, U.S. Department of Energy, DOE/EIA-0383(94). Washington, D.C.: DOE. EPRI. 1984. Coproduction of Methanol and Electricity. AP-3749. Palo Alto, California: Electric Power Research Institute. Gilbert/Commonwealth, Inc. 1994. Optimization of Gas Stream Cleanup in Three IGCC Systems. Prepared for U.S. Department of Energy under contract DE-AC01-88FE61660. Reading, Pennsylvania: Gilbert/Commonwealth, Inc. Gray, D. 1994. Coal Refineries: An Update. Prepared for Sandia National Laboratories by the Mitre Corporation under contract no. AF-7166. McLean, Virginia: The Mitre Corporation. Kastens, M.L., L.I. Hirst, and C.C. Chaffee. 1949. Liquid fuels from coal. Industrial and Engineering Chemistry 41: 870-885. Khan, M.R., and T.M. Kurata. 1985. The Feasibility of Mild Gasification of Coal: Research Needs. U.S. Department of Energy, Morgantown Energy Technology Center, Technical Note DOE/ METC-85/4019. Washington, D.C.: DOE. Lumpkin, R.E. 1988. Recent progress in the direct liquefaction of coal. Science 239: 873-877. NRC. 1990. Fuels to Drive Our Future. Energy Engineering Board, National Research Council. Washington, D.C.: National Academy Press. NRC. 1993. Advanced Exploratory Research Directions for Extraction and Processing of Oil and Gas. Board on Chemical Sciences and Technology, National Research Council. Washington, D.C.: National Academy Press. Oil and Gas Journal. 1994. Alternate fuels: China's. Oil and Gas Journal 92: 35. Probstein, R.F., and R.E. Hicks. 1982. Synthetic Fuels. New York: McGraw-Hill. Schindler, H.D. 1989. Coal Liquefaction: A Research and Development Needs Assessment. Prepared for the U.S. Department of Energy, Office of Energy Analysis, DOE/ER-0400. Washington, D.C.: DOE. Solomon, P.R., T.H. Fletcher, and R.J. Pubmire. 1993. Progress in coal pyrolysis. Fuel 72(5):587-597. Stiegel, G. 1994. Indirect Liquefaction. Paper presented to the Committee on Strategic Assessment of DOE's Coal Program, National Academy of Sciences, Washington, D.C., Jan. 14. Tam, S.M. 1993. Indirect Coal Liquefaction via Fischer-Tropsch Technology for the Baseload IGCC Plant. Paper presented at the IEA Second International Conference on the Clean and Efficient Use of Coal and Lignite: Its Role in Energy, Environment and Life, Hong Kong, Nov. 30-Dec. 3. Tam, S.S., D.C. Pollack, and J.M. Fox. 1993. The combination of once-through Fischer-Tropsch with baseload IGCC technology. P. 306 in Alternate Energy '93 held April 28-30, 1993 in Colorado Springs, Colorado. Arlington, Virginia: Council on Alternate Fuels.
Representative terms from entire chapter: