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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 4 Thermochemical Conversion of Coal and Biomass 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.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 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. FIGURE 4.1 Summary of thermochemical conversion processes discussed in this chapter.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 gaso-
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts line, and naphtha and liquid petroleum gas (LPG). Sasol now produces transportation fuels from coal at the rate of more than 165,000 bbl/d. 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 450°C 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 more than 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 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 are described in this section.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 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 3000 tons/day. Biomass gasifiers have not generally been used to produce
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts FIGURE 4.2 Schematic of generic plant for indirect conversion of coal and/or biomass. Source: Tomlinson and Gray, 2007. synthesis gas. They are generally smaller and operate at lower pressures and tem-peratures than do coal gasifiers. Although there are many fixed-bed biomass gasifiers, fluid-bed and recirculating-bed systems have been developed. A 3000 tons/day coal gasifier would produce enough synthesis gas to yield transportation fuel at about 6000 bbl/d 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 1400°F to 2800°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
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts Sasol–Lurgi gasifier has been used extensively at the Sasol commercial plant in South Africa. Entrained-flow gasifiers operate at 1250–1600°C and accept coalfeed 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.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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. 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 those 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 1000°C, 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 on 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 tons/day operating in the United States, Europe, and Japan (IEA, 2007; Cobb, 2007). Those units have a broad variety of feedstocks, feed capabilities,
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts characteristics, product-gas cleanup approaches, and primary products. The Biomass Technology Group lists more than 90 installations (most are small) and more than 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 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 does, 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 acti-
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts vated 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 costs 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. DME is discussed in Chapter 9. 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
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 the 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 bbl/d. The plants were designated Sasol II and III. Twenty years later, the plants are profitable, but they received government subsidies for several years after start-up. 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 (R&D) at Sasol started experimenting with slurry-phase FT reactors in the early 1980s and built a 2,500-bbl/d prototype reactor at Sasol I to demonstrate and develop the technology. These reactors, which have operated on both iron and cobalt FT cata-
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 sector partnership might be necessary for the setup of the first few direct- or indirect-liquefaction plants. Environmental Impact Because coal’s hydrogen:carbon ratio is lower than that of petroleum, transportation fuels produced from direct liquefaction of coal would have much higher greenhouse gas emissions than gasoline has. 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 reductions in greenhouse gas lifecycle emission. That strategy has not been tested for direct liquefaction but should be investigated for potentially comparable reductions of greenhouse gas emissions. “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 and Gibson, 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 2000 tons/day (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 a 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.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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. Finding 4.1 Despite the vast coal resource in the United States, it is not a forgone 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 lifecycle emission will be more than 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
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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. 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 of 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 appli-
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts cation 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 showstoppers 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 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.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 that 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 dem-
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts onstrated 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 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
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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 those from 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. 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.
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Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts 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. REFERENCES Anderson, S., and R. Newell. 2004. Prospects for carbon capture and storage technologies. Annual Review of Environment and Resources 29:109-142. Argonne National Laboratory. 2005. The Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) Model. UChicago Argonne, LLC. Available at http://www.transportation.anl.gov/modeling_simulation/GREET/index.html. Accessed January 30, 2009. Bartis, J.T., F. Camm, and D.S. Ortiz. 2008. Producing Liquid Fuels from Coal: Prospects and Issues. Santa Monica, Calif.: RAND Corporation. Burke, F.P., S.D. Brandes, D.C. McCoy, R.A. Winschel, D. Gray, and G. Tomlinson. 2001. Summary Report of the DOE Direct Liquefaction Campaign of the Late Twentieth Century: Topical Report. Washington, D.C.: U.S. Department of Energy. Chu, W., R. Kieffer, A. Kiennemann, and J.P. Hindermann. 1995. Conversion of syngas to C1-C6 alcohol mixtures on promoted CuLa2Zr2O7 catalysts. Applied Catalysis A: General 121:95-111. Clifford, C.B., and H.H. Schobert. 2007. Development of coal-based jet fuel. In The 234th ACS National Meeting, Boston, Mass. Cobb, J.T., Jr. 2007. Survey of commercial biomass gasifiers. Paper read at American Institute of Chemical Engineers Annual Meeting, Salt Lake City, Utah, November 4-9, 2007. Comolli, A.G., E.S. Johanson, W.F. Karolkiewicz, L.K. Lee, G.A. Popper, R.H. Stalzer, and T.O. Smith. 1993. Close-Coupled Catalytic Two-Stage Liquefaction Process Bench Studies. Washington, D.C.: U.S. Department of Energy.
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