Coal Preparation, Coal-Liquid Mixtures, and Coalbed Methane Recovery
DOE programs addressed in this chapter—namely, coal preparation, coal-liquid mixtures, and coalbed methane recovery—currently constitute relatively minor components of the total DOE coal program. Brief descriptions of the technologies, the state of the art, and current programs are provided. The committee's findings are then presented, with emphasis on the future role of DOE programs vis-à-vis private sector activities, requirements for commercial technologies, links to other major DOE efforts such as power generation, and research opportunities.
Description of Technology
Coal preparation—or cleaning—is the removal of mineral matter from as-mined coal to produce clean coal, a quality-controlled product with a composition that adheres to specifications based primarily on environmental and combustion performance. Its primary purpose is to increase the quality and heating value (Btu/lb) of coal by lowering the level of sulfur and mineral constituents (ash). In most Eastern bituminous coals, roughly half to two-thirds of the sulfur occurs in a form that can be liberated by crushing and separated by mechanical processing. Western coals typically contain much lower levels of sulfur, have lower heating values and are not readily amenable to physical cleaning methods for sulfur reduction. All coals contain mineral matter that also can be removed through physical cleaning. Coal preparation as currently practiced in the coal industry involves four generic steps: characterization, liberation, separation, and disposition.
During characterization, the composition of the different-size raw coal particles is identified. The composition of the raw coal and the required clean coal specifications dictate the type of equipment that must be used to remove the mineral matter. Crushing liberates mineral matter. Complete liberation can only be approached by reducing the mined coal to very fine sizes, since particles containing both coal and mineral matter, called middlings, are also produced during crushing. Separation involves partitioning of the individual particles into their appropriate size groupings—coarse, intermediate, and fine fractions—and separating the mineral matter particles from the coal particles within each size fraction. Separation techniques for larger-size raw coal particles generally depend on the relative density difference between the organic coal and inorganic mineral matter particles. Separation techniques for fine raw coal particles utilize the difference in the surface properties of the particles in water. Disposition is the dewatering and storage of the cleaned coal and the disposal of the mineral matter.
Coal preparation began simply as a means of controlling the size of raw coal, but mechanized mining led to mechanized cleaning and the subsequent evolution of coarse, intermediate, and fine coal cleaning defined in terms of raw coal particle size ranges. All coals for the metallurgical and export markets are beneficiated, as well as coals sold for other industrial purposes. For most of its history, the primary objective of steam coal cleaning has been to reduce ash levels rather than sulfur content. The introduction of environmental requirements in the 1970s increased the interest in more extensive cleaning of coal to remove larger amounts of sulfur. Today, fine coal (less than 0.5 mm) cleaning is being further subdivided. Coal quality specifications have become more restrictive as a result of environmental regulations and as the impact of coal quality on boiler operating problems, such as slagging and deposition on tubes, has become better understood.
Coal preparation technology was first developed for the European coal industry and was licensed as needed by American companies. Mineral processing technology was also adapted for coal preparation. Significant technology development was conducted by the U.S. steel industry, since the coal used as feedstock for coke is required to meet very stringent specifications, particularly for sulfur content. The U.S. Bureau of Mines established internationally recognized in-house expertise in coal cleaning; this effort was continued under the DOE at the Pittsburgh Energy Technology Center (PETC). As a result of the tightening of coal specifications to comply with environmental regulations, EPRI (Electric Power Research Institute) established a Clean Coal Testing Facility (spun off in 1994 as an independent company, CQ, Inc.). In addition, a number of states, including Pennsylvania, West Virginia, Illinois, Ohio, and Kentucky, established research programs to improve the quality of their coals. Some research on coal
cleaning has also been conducted by those oil companies involved in coal production.
State of the Art
Coal preparation technologies are widely practiced by the coal industry. Recent R&D efforts (Feeley et al., 1994; Killmeyer et al., 1994; Hucko et al., 1994) have been aimed at developing processes that will further reduce both the sulfur and ash contents of coals. Coal cleaning techniques for the fine fractions also are now commercial. Many of these same techniques have been utilized to produce the very clean coals required for coal-liquid mixtures (see below). Sustained investigations into chemical and biological coal preparation techniques that remove organic as well as inorganic sulfur have not, however, produced any systems with a strong potential for commercialization, largely because of their high costs. Indeed, from the perspective of many coal users, the higher cost of coals subjected to advanced levels of preparation makes them unattractive relative to naturally occurring coals with lower sulfur and ash contents. Furthermore, many of the advanced power and fuel systems are designed to be fuel flexible, so there are limited markets for highly cleaned coals in the power generation sector.
DOE currently performs or funds the majority of coal preparation R&D in the United States. This activity falls primarily within the Advanced Clean Fuels Research Program. The FY (fiscal year) 1994 program budget of $11.3 million included $4.6 million for work on technologies for producing premium fuels and removal of air toxic precursors; $2.25 million for continued testing of high-efficiency processes; and $4.1 million for continuation of in-house bench-scale and characterization research at PETC related to advanced physical and chemical cleaning concepts (DOE, 1994a). In addition to the direct funding of the coal preparation program, the AR&TD (advanced research and technology development) component of the DOE budget supports a number of closely allied programs of a more basic nature, such as the $1.9 million program on the bioprocessing of coal for sulfur and nitrogen removal, which is part of DOE's Advanced Manufacturing Technology program. This program recently shifted its emphasis to the removal of SOx and NOx from combustion gases, rather than from coal.
For FY 1995, DOE has proposed a 52 percent reduction in funding for coal preparation, to a total of $5.5 million. The main thrusts of the program include continued research on advanced physical coal cleaning methods to produce premium coal fuels very low in ash, sulfur and air toxic precursors at the proof-of-concept scale of technology development ($2.6 million), and continued in-house research on bench-scale development of advanced cleaning concepts ($2.0 mil-
lion) and related studies ($0.8 million). The AR&TD program on bioprocessing of coal would continue at its present level ($1.9 million), with emphasis on involvement with small and emerging companies.
Technical Issues, Risks, and Opportunities
Current physical coal cleaning techniques cannot reduce the sulfur content of coal to the levels needed to comply with most environmental regulations. Although the inorganic sulfur component of coal can be removed with other mineral matter, the organic sulfur is chemically bonded to the coal and is not amenable to physical separation. Biological and chemical methods for sulfur removal so far have not been promising for commercial-scale application. Because coal is an abundant and relatively low-cost fuel, the added cost of advanced preparation technology, combined with the cost of coal that is lost with separation process wastes, makes it extremely difficult for advanced cleaning methods to be economically competitive for applications involving direct coal use. The most promising applications for advanced beneficiation methods lie in the production of premium fuels that replace oil or gas (e.g., coal-liquid mixtures, discussed below). However, current and projected prices for oil and gas make it unlikely that significant markets for coal-based alternative fuels will emerge before the mid-term period. In the near-term, however, coal preparation might prove a desirable technique for selective treatment of coal to meet possible future hazardous air pollutant regulations by reducing trace element concentrations prior to combustion.
The utility industry is interested in promoting technical and economic improvements in coal beneficiation methods as an indirect means of reducing fuel-related costs. Lower-sulfur fuels provide better cost-benefit solutions for older boilers than scrubbers. Burning upgraded coal reduces the cost of maintaining boiler systems and increases combustion efficiency. SOx reduction in the flue gas reduces scrubber costs where flue gas desulfurization (FGD) is needed. Achieving maximum energy recovery requires improved liberation, improved separation efficiency, total cleaning, and process control. Size reduction and thermal drying account for about 75 percent of the capital costs and 50 percent of the operating costs for processing coal. The challenge for coal cleaning is to deliver coal at a price that is economically competitive with other sources of coal of comparable quality. Thus, the markets for cleaned coals are highly dependent on site-specific factors.
There is an emerging global market for this segment of the U.S. coal industry, particularly in India, Poland, and China, which have large reserves of relatively low quality coal. Improved U.S. coal preparation technology would make the United States more competitive in the international coal technology market. Improving the technology, in some cases, requires more development. For example, commercial preparation is not currently economically optimized. There is a need for testing and verifying new technologies, performing unit operations
analysis, developing instrumentation for process control, including computerized on-line analyzers, and improving dewatering for both fine high-rank coals as well as low-rank coals. However, the R&D and demonstration planning should use market-based decision tools and have extensive industrial participation.
DOE has contributed to the development of the fine coal cleaning technology that is now commercially available. Applied research to improve current commercial preparation processes may help such technology compete more effectively, especially in international markets. Advanced power and fuel systems are being designed for fuel flexibility and high-efficiency sulfur removal and may be unlikely to require coals that have been subjected to coal preparation beyond current commercial practice.
Reduction of trace element concentrations in coal representing air toxic precursors may offer an R&D opportunity for meeting future, as yet undefined, hazardous air pollutant emission standards. Work in this area is addressed in the DOE's proposed program for FY 1995.
Coal-liquid mixtures consist of finely ground coal suspended in a liquid, such as oil or water, together with small amounts of chemical additives to improve stability and other physical properties. The primary purpose of coal-liquid mixtures is to make solid coal behave as an essentially liquid fuel that can be transported, stored, and burned in a manner similar to heavy fuel oil. The most mature coal-liquid mixture technologies are those using coal-oil and coal-water mixtures (CWM). Several of these technologies already have been offered commercially. Since coal-liquid mixtures are intended as a substitute for oil, their market penetration is heavily dependent on oil prices.
Initial development work on coal-oil mixtures (COMs) dates back to the last century (DOE, 1988). Extensive COM research was conducted in the United States during the 1940s because of wartime constraints on oil supply. More recent interest in COMs followed the 1973 OPEC oil embargo and the oil price hikes of the late 1970s. Utility and industrial boiler demonstrations using COMs were conducted in the United States, Japan, Sweden, and England between 1977 and 1981. Over 20 COM preparation plants are currently operating or have been operated in various countries.
The first combustion tests of CWMs—also known as coal-water slurries (CWSs)—were conducted in the United States, Germany, and the former Soviet Union in the 1960s. There was active development of CWMs in the United States in the 1980s, with emphasis on developing technologies to prepare mixtures with desirable physical and chemical properties, demonstrating retrofit in existing boilers, and developing specialized equipment for handling and transporting slurries. During this period, a number of private companies were actively involved in, or planned to enter, the CWS business. All have subsequently gone out of business or abandoned commercialization of slurries as oil prices declined in the early 1980s.
State of the Art
Areas for further performance improvements in COMs depend on advanced coal beneficiation to further reduce sulfur and ash content and improved additives or other means of increasing the weight percentage of coal in the mixture. CWSs also are a potential alternative to premium fuels (oil and gas) being used in industrial and utility boilers and were offered commercially in the early 1980s. Cost studies suggest that slurries could be prepared and used economically with oil prices around $25 to $30/bbl, given a production facility of sufficient scale and the infrastructure required to handle the fuel. Such studies also indicate that slurries are economical if the differential in cost between heavy oil and slurry is $1.50 per 106 Btu (Addy and Considine, 1994). Present oil price forecasts, however, make it unlikely that coal-based substitutes will be competitive in the near to mid-term. Nevertheless, one Pennsylvania utility (Penelec) is currently investigating cofiring its pulverized coal utility boilers with a CWS to provide 20 to 40 percent of fuel needs (Battista et al., 1994). This technology would allow the utility to purchase and utilize fine upgraded coal while reducing NOx emissions with no boiler derating.
Much of the current work on coal-liquid mixtures is being funded, at least in part, by DOE. Activities range from fundamental research on mixture preparation and properties, through bench-scale preparation and combustion, to commercial-scale demonstrations. The emphasis in all these programs is on CWSs rather than COMs.
Fundamental research on CWSs is being conducted at Adelphi University, Carnegie Mellon University, and Texas A&M University under the Coal Utilization Science program of DOE's AR&TD activity. Topics under investigation include the combustion system atomization processes, modeling, and measurement of viscosity and surface properties. The Pennsylvania State University is conducting a superclean CWS program with support from DOE and the Commonwealth of Pennsylvania to determine the capability of firing such slurries in an industrial boiler designed for firing heavy fuel oils, with no adverse impact on
boiler rating, maintenance, reliability, and availability. DOE, through the University of North Dakota Energy and Environmental Research Center, also is supporting the development of refuse-derived fuel/coal slurry fuels. DOE is managing a boiler conversion program at the Pennsylvania State University for the U.S. Department of Defense, with the objective of developing commercial CWS technology. The program will provide a military base with a commercially engineered CWS conversion system for firing its oil/gas-fired boilers.
Demonstration projects using CWS include a CCT (Clean Coal Technology) Round V program to demonstrate clean coal diesel technology. The diesel system will use a CWS produced from Ohio coal by a two-stage coal cleaning and slurrying process. Another CCT program is demonstrating the combustion of injected coal in the tuyeres of two blast furnaces at Bethlehem Steel. Blast furnace coal injection technology, where granulated or pulverized coal is injected into a blast furnace in place of natural gas (or oil) as a fuel supplement or reductant to lower the coke rate and hot metal cost, may incorporate CWS technology in the future. A University of North Dakota project on power generation from an Alaskan coal-water fuel has demonstrated the preliminary process economics of a concentrated low-rank coal-water fuel. The second phase of the program is aimed at developing a low-cost indigenous replacement for the imported diesel fuel used in many native villages of the Alaskan interior.
While a specific breakdown of DOE funding for coal-liquid mixture R&D is not provided in the FY 1995 budget request, the overall funding for the AR&TD Coal Utilization Science program is projected to decrease from $3.1 million in FY 1994 to $2.2 million in FY 1995. Part of this decrease is due to a reallocation of some projects to other coal program budget lines. A more detailed discussion of DOE's advanced research budgets appears in Chapter 9.
COM and CWS technologies are either commercially available or on the verge of commercialization. Aside from some niche market opportunities, the private sector currently has little current interest in adopting these technologies. However, if oil or gas prices increase significantly above current or projected near-term levels, COMs are available for commercial application. At that time, there may be a need for programs that assist the private sector in taking CWS technology to the marketplace.
COALBED METHANE RECOVERY
The coal formation process occurs when organic debris is converted to coal and various by-products, including water and methane (CH4) gas. The latter may
be found in the coal itself or trapped in the strata surrounding the coal. For every ton of coal formed, as much as 5,000 cubic feet of ''coalbed methane" may be generated in situ (DOE, 1994b). Coalbed methane liberated into mine workings by underground coal mining can be a serious safety hazard, since methane is highly explosive in volume concentrations of 5 to 15 percent. Thus, underground mines in the United States are required to maintain methane concentrations below I percent of the concentration of the air in the mine (CFR, 1988).
Methane has attracted recent attention as a greenhouse gas that may contribute to global warming (see Chapter 3). The Clinton administration's Climate Change Action Plan (Clinton and Gore, 1993) identifies coal mines as one of the primary sources of methane emissions in the United States and requires the EPA (U.S. Environmental Protection Agency) and DOE to launch a coalbed methane outreach program to raise awareness of the potential for cost-effective emissions reductions with key coal companies and state agencies. In addition, the Climate Change Action Plan requires DOE to expand its research, development, and demonstration (RD&D) efforts to broaden the range of cost-effective technologies and practices for recovering methane associated with mining.
State of the Art
While all coal seams contain some methane, the highest levels of coalbed methane in the United States occur in seams in Virginia, West Virginia, Utah, and Colorado. To mine these gassy seams, mining companies have developed a number of techniques to eliminate or reduce the amount of methane liberated during mining. The primary technique is to design the mine ventilation system with enough capacity to keep the concentration at acceptable levels well below the lower explosive limit—generally less than 1 percent methane by volume. Other methods involve vertical drilling into the coal seam to vent methane before and after mining and drilling horizontally into the seam and venting the gas to the surface. There are instances where mining companies collect high-concentration methane and, after limited cleaning, sell the gas to a commercial pipeline. The economics of collection and sale to a user or distributor can either be based on a direct payback basis or justified by a reduction in mine ventilation costs.
Section 1306 of EPACT requires DOE to study barriers to coalbed methane recovery, to assess environmental and safety aspects of flaring coalbed methane liberated from coal mines, and to disseminate information on state-of-the-art coalbed methane recovery techniques to the public. DOE is further required to establish a coalbed methane recovery demonstration and commercial application program, with emphasis on gas enrichment technology. DOE requested $300,000 in the FY 1994 budget for coalbed methane activities, but that funding was not
approved. The administration's FY 1995 budget request includes coalbed methane recovery activities in the natural gas portion of the Fossil Energy program. As required by the Climate Change Action Plan (see above), EPA recently launched an outreach program to encourage coal companies to install methane recovery equipment at mines across the United States. The goal of this program is to reduce methane emissions from coal mines by at least 500,000 metric tons (25 billion cubic feet) by 2000 (Wamsted, 1994). DOE has developed a plan to expand RD&D for methane recovery from coal mining; DOE and industry will cofund projects on a 50 percent cost-sharing basis. This activity will be coordinated with the EPA outreach program.
Issues, Risks, and Opportunities
Technology for the recovery of coalbed methane from gas streams with high methane concentrations is commercially available and practiced by the gas and mining industries where conditions justify the investment. However, the collection and sale of methane are not widespread in the coal mining industry because of a number of technical and commercial issues. These include ambiguities in mineral rights concerning gas ownership, trade-offs between the selling price of methane and tax credits to encourage investments, the dependence of methane recovery on gas concentration and porosity of the coal or strata, the quantity and quality of gas to be vented, and constraints on the underground mining technique used (e.g., room and pillar versus longwall).
Technology for the use or control of coalbed methane emissions in very dilute gas streams (methane concentration less than 1.0 percent) is not currently available. Low-quality mine gases must be upgraded or enriched for sale to a distribution system. In view of the importance of methane as a greenhouse gas (see Chapter 3), opportunities exist to encourage the utilization of dilute methane streams emitted from coal mines by developing relevant technologies.
Possible research areas include new techniques for methane separation and the combustion of very dilute methane streams. Separation of methane from dilute ventilation air by conventional methods is expensive and energy intensive. Research aimed at finding new materials for selective adsorption or selective diffusion through membranes is of interest (see Chapter 9). Ventilation air streams are too dilute to burn in conventional combustion equipment without use of additional fuel, which would generate additional greenhouse gases. Catalytic combustion systems offer some promise, and advances made for other applications are of interest (see, for example, Haggin, 1994).
Coalbed methane recovery is a commercially available technology that is being practiced where concentrations are sufficiently high and where merited by the return on investment or benefits to mining.
Technologies for the capture and use of dilute coalbed methane streams are not sufficiently mature for commercial implementation. Given the increased emphasis on reducing emissions of greenhouse gases, including methane from coal mining, there are potential research opportunities directed toward the recovery of coalbed methane from very dilute gas streams.
Addy, S.N., and T.J. Considine. 1994. Retrofitting oil-fired boilers to fire coal-water-slurry: An economic evaluation. P. 341 in The Greening of Coal. Washington, D.C.: Coal & Slurry Technology Association.
Battista, J.J., T. Bradish, and E.A. Zawadzki. 1994. Test results from the cofiring of coal water slurry fuel in a 32 megawatt pulverized coal boiler. P. 619 in The Greening of Coal. Washington, D.C.: Coal & Slurry Technology Association.
CFR. 1988. Code of Federal Regulations, Title 30, Mineral Resources: Part 75—Mandatory Safety Standards—Underground Coal Mines. Washington, D.C.: Office of the Federal Register, National Archives and Records Administration.
Clinton, W.J., and A. Gore, Jr. 1993. The Climate Change Action Plan. Washington, D.C.: The White House.
DOE. 1988. Energy Technologies and the Environment—Environmental Information Handbook. U.S. Department of Energy, DOE/EH-0077. Washington, D.C.: DOE.
DOE. 1994a. FY 1995 Congressional Budget Request. U.S. Department of Energy, DOE/CR-0023, Vol. 4. Washington, D.C.: DOE.
DOE. 1994b. Meeting the Climate Change Challenge. U.S. Department of Energy, Office of Fossil Energy. Washington, D.C.: DOE.
Feeley, T.J., W.B. Barnett, and R.E. Hucko. 1994. Advanced physical coal cleaning for controlling acid rain emissions. Presented at 12th International Coal Preparation Congress, May 23-27, Cracow, Poland.
Haggin, J. 1994. Catalytic oxidation process cleans volatile organics from exhaust. Chemical and Engineering News 72(26): 42-43.
Hucko, R.E., B.K. Schimmoller, and P.S. Jacobsen. 1994. The prep plant of tomorrow: Different from yesterday, more different tomorrow. Coal Magazine. Apr.: 50-53.
Killmeyer, R.P., C.P. Maronde, B.R. Utz, and R.E. Hucko. 1994. The Initiation of Research in the U.S. Department of Energy's Coal Preparation Process Research Facility. Paper presented at the 12th International Coal Preparation Congress, May 23-27, Cracow, Poland.
Wamsted, D. 1994. EPA urging methane recovery at coal mines. The Energy Daily 22(72): 3.