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4 Coal
Pages 146-209

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From page 146...
... Of this huge supply, we currently consume about 14 quads each year, or less than 0.3 percent of domestic recoverable coal reserves. In contrast, as noted in chapter 3, the nation extracts each year almost 10 percent of its 420-quad recoverable reserves of oil and natural gas.
From page 147...
... At the other end of the fuel cycle, the evolving state of air pollution regulations to deal with the emissions of coal combustion complicates planning for increased demand, and thus in turn inhibits investment in mines, transportation facilities, and coal-fired utility and industrial boilers. The future is obscured also by a number of more speculative, less easily surmountable problems, which may result in further regulatory restrictions on the use of coal.
From page 148...
... The domestic and foreign market for metallurgical coal (used in blast furnaces, smelters, and chemical plants) amounts to 15-20 percent of the nation's coal production; it is tied primarily to the world steel industry and is not expected to grow rapidly in the near future.
From page 149...
... . Commercial techniques for using coal will have changed little, but some synthetic fuel technologies will be on the verge of commercialization, and improved techniques for direct coal combustion will begin to enter the market.
From page 150...
... , most of the sulfur is organic; but when total sulfur makes up a greater percentage of the coal, the amount of inorganic sulfur is greater, commonly about 50 percent. Emissions of sulfur dioxide (SO2)
From page 151...
... The ceiling on emissions is 1.2 lb of sulfur dioxide per million Btu, which under earlier EPA regulations could be met by burning coal with 0.6 lb or less of sulfur per million Btu.4 in May 1979, however, the EPA imposed additional control requirements on new plants (construction or alteration begun after
From page 153...
... Created from different plants and under different geological conditions, western coal has a carbon structure and mineral content generally different from that of eastern coal; these characteristics must be allowed for and sometimes counteracted in designing boilers, controlling effluents, and choosing coal for coking or for conversion to synthetic fuels 6 (Boilers, for instance, suffer an efficiency loss when a nondesign coal type is substituted for the type originally intended.) Lastly, much eastern coal was formed under salt water, giving it a high sulfur content compared to most western coal, which formed under fresh water.
From page 154...
... n C = g_~/ ~ ~ ~ e ~ ~ O ~ _ ; E ~ o 5 ~ ~ ~ y '~mm cn ~ V ~ ~ i~i bm0 ° ~ O ~ .
From page 155...
... The distribution of coal energy resources is also of interest. The Bureau of Mines reserve base tonnages were converted to recoverable reserves and to corresponding average energy content figures by the Congressional Office of Technology Assessment using a recovery factor of 57 percent in underground mines and 80 percent in surface mines.9 The resulting regional distribution of recoverable coal reserves by energy content and method of mining is summarized in Table 4-3.
From page 156...
... o o c .s is o to c c D C o o~ Hi: V)
From page 157...
... multiplied by 60 percent for an estimate of total recoverable reserve energy in those states, Francis X Murray, ed., Where We Agree: Report `~1 the National Coal Policy Project.
From page 158...
... Under the National Energy Plan (NEP) of 1977, which called for a near doubling of coal use by 1985, industrial coal consumption was projected to increase at nearly 12 percent annually, and electric utility coal consumption at about 6 percents The nation's utilities may be able to meet the forecast rate of increase, because under the Powerplant and Industnal Fuel Use Act of 1978 (Public Law 95-620)
From page 159...
... Odice of Energy Data and Interpretahon, Energy Information Administration (Washtagton, D.C.: Energy information Administration Clearinghouse (DOE/EIA-0119, Order no.
From page 160...
... Based on utility coal conversion efficiency measured in 1978, this would require 1640 million tons of coal, 3.4 times as much as utilities consumed in 1978 and 2.5 times total 1978 domestic coal production. Any shortfall in nuclear capacity would of course increase this demand.
From page 161...
... A 1000-MWe coal-fired powor plant consumes about 2.5 million tons of coal each year and produces approximately 6.5 billion kWh of electricity. With flue gas desulfurization equipment it occupies an area of about 600 700 acres, which houses the plant and allows for disposal of the various solid wastes produced in the course of 35 40 years of useful life.
From page 162...
... Under the authority of the 1977 amendments to the Clean Air Act, EPA proposed new, tighter standards governing the sulfur dioxide, nitrogen dioxide, and particulate emissions of all new or substantially modified fossil-fueled steam power generating units that consume more than 250 million Btu of fuel energy per hours This is equivalent to about 10 tons of coal per hour—enough to fuel a 10-MWe unit. The standards apply, regardless of the ambient air quality, to plants whose construction or alteration begins after September 18, 1978.
From page 163...
... The percentage reduction requirement in effect means that all regulated coal-fired power plants must install flue-gas scrubbers to remove sulfur. The use of lowsulfur coal thus is no longer acceptable as the sole means of reducing sulfur emissions at a power plant; this is expected to reduce the market for lowsulfur western coal in the Midwest and East, but the magnitude of the reduction and its precise effect on western coal production are very uncertain.
From page 164...
... In addition, the proposed regulations would require sulfur emissions to be reduced by 70 90 percent from the uncontrolled levels, with the precise reduction determined by the effort required to reduce emissions to the threshold value of 0.6 lb per million Btu. These percentage reduction requirements could be met by any combination of flue-gas desulfurization, coal cleaning, conversion to synthetic fuels, or other means of removing sulfur before, during, or after combustion.
From page 165...
... This removes about 70 percent of the coal's inorganic sulfur (which may range from 60 percent of total sulfur in Appalachian coals to very small amounts in some western coals) and is almost entirely ineffective in removing organic sulfur.
From page 166...
... Fluidized-bed combustion, now under development for use in industrial and utility boilers, holds the potential for somewhat more economical sulfur oxide control, and in addition should reduce nitrogen oxide emissions. It is described below in the section entitled "Advanced Technologies for Coal Combustion." Nitrogen Oxides The 1977 Clean Air Act Amendments, as interpreted by the Environmental Protection Agency in the proposed New Source Performance Standards, limit nitrogen oxide (NOR)
From page 167...
... Particu/ates The new EPA proposed standards for utility boilers would limit overall emissions of particulate matter to 0.03 lb per million Btu and at the same time set standards for the opacity of existing flue gases. They would require that particulate emissions be reduced by over 99 percent of the uncontrolled emissions.
From page 168...
... Fabric filter baghouses are the most effective of all particulate control methods against small particles, but the pressure drop involved in forcing the gas through the necessary fine filters increases operating costs. The devices have been used in industrial particulate control for many years, but the high temperatures and corrosive chemicals in coal combustion gases, among other problems, have limited their use with utility boilers.
From page 169...
... The lower combustion temperatures substantially reduce emissions of nitrogen oxides. The process is under development now, particularly for small units; the current development goals are high efficiency, durability, low emissions of nitrogen and sulfur oxides, and reliability.
From page 170...
... In this configuration, a medium-Btu gasifies would be integrated with a combined-cycle power plant, essentially as a means of precombustion emission control. Eventually, coal-to-electricity efficiencies of up to 45 percent (far above the 35 percent typical of standard scrubber-equipped steam turbines fed by pulverized coal)
From page 171...
... . This is one of the potential attractions of the concept: Even tightening the current sulfur emission standards by an order of magnitude is estimated to increase generating costs in such a system by only 7-8 percent 27 Fuel Cells Fuel cells convert Mel energy to electricity electrochemically rather than thermally.
From page 172...
... The emissions from an MHD plant would be almost free of sulfur, even if raw coal combustion gases were used, because the potassium salt used to render the gas conductive would combine with the sulfur, which would be separated out as the potassium was recycled. Efficiencies of as much as 50 percent, from coal to electricity, could be achieved using raw coal combustion gases.29 Exhaust gases are at high temperatures, and their heat could be captured and used in a steam turbine bottoming cycle.
From page 173...
... There would be some difficulties in fuel delivery and ash removal, but this option should be studied carefully. SYNTHETIC GAS FROM COAL Coal gasification has been a commercial operation for more than 150 years.
From page 174...
... Low- and Medium-Btu Gas The low-Btu gas produced by an air gasification system has a heating value too low to be economically transported or used in equipment designed for natural gas. It could, however, be used to power on-site industrial boilers and electric power generating equipment.
From page 175...
... The allocation of emphasis between gas and electricity as the ultimate products of coal use must be decided carefully for each region, considering the value of using gas distribution systems where they already exist. The most nearly available high-Btu coal gasification technique is the methanation of medium-Btu gas.
From page 176...
... Of particular interest in the federal research and development program are "steeply dipping beds," or those that slope more than 35 degrees from the horizontal; such beds in the United States are estimated to contain more than 100 billion tons of coal,33 and coal in these formations may be easier to gasify in situ than that in conventional beds. Underground coal gasification has several potential health, safety, and environmental advantages over conventional mining followed by gasification.
From page 177...
... As the supplier industries develop an infrastructure, experience is gained, and technical refinements are made, costs should fall, as they have in other similar developing industnes. Research and Development Priorities Economic Comparison of Gasif cation Options Pilot plants already constructed should be operated to supply data complete enough to permit capital, operating, and product costs for all types of commercial plants to be estimated and compared.
From page 178...
... The approaches to coal liquefaction fall into four categories: indirect liquefaction, pyrolysis, solvent extraction, and catalytic liquefaction. Indirect liquefaction is the only liquefaction process in commercial use; the SASOL plants in the Union of South Africa will soon be producing about 40,000 barrels of gasoline and fuel oil per day.
From page 179...
... It has benefited from a good deal of effort in this country during the past 15 years, first as a means of providing a high-grade, clean-burning solid fuel (SRC-I) for use in utility and industrial boilers, and more recently as a source of liquid fuels for a broader market.
From page 180...
... The National Research Council's Committee on Processing and Utilization of Fossil Fuels4' was able to make estimates "merely indicative of the general level of cost." its report states that product costs (in January 1977 dollars) might be as little as $24 per barrel of oil equivalent (at 6 million Btu per barrel)
From page 181...
... This increases the expense of hydrogen, which is a key part of the cost of producing and refining coal liquids. Pollution Problems The environmental and health benefits of using coal liquids as substitutes for coal in power plants and large industrial boilers are not clear.
From page 182...
... COAL FOR INDUSTRIAL PROCESS HEAT U.S. industry burned nearly 60 million tons of coal (about 1.5 quads)
From page 183...
... However, the Powerplant and Industrial Fuel Use Act of 1978 will, when its regulatory provisions are formalized by the Department of Energy, impose rather strict limits on the use of oil and natural gas in new "major fuel burning installations," defined as those consuming more than 100 million Btu/hr (about 4 tons of coal) per individual unit or 250 million Btu/hr for each multiunit facility.
From page 184...
... In the case of ammonia, for instance, it takes 34.5 million Btu of natural gas as a source of Gel and feedstock to produce I ton of ammonia, while it takes 41 million Btu of coal to produce the same result. (At current rates of ammonia production—about 18 million tons/yr—it would take 0.740 quads of coal to meet the needs of the ammonia industry, or about 32 million tons—5 percent of 1978 production.)
From page 185...
... reserve base that were of potential coking quality (i.e., of rank higher than highvolatile C bituminous, with an ash content not greater than 8 percent and sulfur content not greater than I percent) .47 Discounting mining losses puts recoverable coking coal reserves somewhere in the neighborhood of 12 billion to 16 billion tons.
From page 186...
... The Environmental Protection Agency has estimated new power plant construction and regional coal production by 1995 to total 220 new coalfired power plants in the East and Midwest, and 130 in the West and in the West South Central region, for a total of 258 GWe.4s Coal production would increase over 1975 production by 1.1 billion tons—65 percent from the West, 27 percent from the Midwest, and only 8 percent from Appalachia. CONAES has made no independent studies of the regional distribution of coal consumption.
From page 187...
... Since the uMw-organized surface mines tend to be the smaller ones, their workers probably produced less than 21 percent of all surface coal. Overall, UMW workers probably mined about 50 percent of total output so The problems of using coal, discussed in the previous section, make it appear unlikely that rapid increases in coal demand will occur through 1985.
From page 188...
... has estimated that if output rises from about 0.7 billion tons in 1977 to 1.5 billion tons in 2000 at constant labor productivity and injury rates, total annual fatalities would rise from 139 to 259 and disabling injuries would grow from 15,000 to 29,000. The estimate shows almost the entire increase in each category would occur in underground mines.
From page 189...
... Source u.s Department of Energy, Energy information Administration, Annual Report to Congress, 1978.
From page 190...
... High petroleum and natural gas prices could provide increasing leeway for investment in improved coal mining technology without eroding the competitive position of coal.
From page 191...
... Rising coal prices since then have probably pushed the ratio higher 60 The equipment used in most surface mining includes conventional earth moving equipment and adaptations such as the "dragline," an enormous shovel with a boom 180 375 fl long and a bucket up to 200 yd3 in volume. One reason that a labor force is more easily recruited for surface mining than for deep mining is that the surface-mining skills are transferable from the established machine operators' trade.
From page 192...
... FEDERAL LEASING POLICY In 1971 the federal government imposed a moratorium on leasing of federal lands for coal production, to gain time for an examination of comprehensive changes in its procedures. At that time, outstanding leases included 17 billion tons of recoverable reserves (about 5 percent of federally owned coal reserves)
From page 193...
... The average coal price for these selected utilities was $20.37 or about 89 cents per million Btu, with 70 percent of it surface coal and 80 percent of it on contract 66 Utilities are acquiring coal mines to gain more control of the supply and price of the coal they burn. In 1977, the Federal Power Commission predicted that by 1985 utility coal consumption would rise to 770 million tons and that the amount produced by the utilities themselves ("captive coal")
From page 194...
... Oil and gas companies account for about 40 percent of planned new capacity, and while they are not expected to undertake all of the planned expansion, they are expected to produce 260 360 million tons of new steam coal in 1986, bringing their share of nonmetallurgical, nonexport production to 48 percent. Seven companies account for two thirds of the capacity additions planned by oil and gas firms.
From page 195...
... Thus, coal prices will tend to follow closely world petroleum prices, suitably discounted for the greater cost of burning coal as compared with fluid fuels. On the positive side, continued high profitability of the industry, and capital availability from the oil and gas companies, will make possible a higher rate of introduction of new technology, and thus rapid improvements in productivity, safety, and responsible environmental behavior could ensue.
From page 196...
... Short-term surges of output, however, could exceed the railroads' shortrun ability to add to their rolling stock. The models used in one transportation study73 showed that Appalachian coal production is more sensitive to coal mining costs than to transportation costs, while western coal production exhibited the opposite tendency—it would be stimulated more by holding transport costs down than by holding western mining costs down.
From page 197...
... Much will hinge on what can be done in arid regions, but water concerns elsewhere are also of specific importance. Potentially most troublesome will be providing water needed in using coal (primarily to produce electricity and synthetic fuels)
From page 198...
... Looking toward a future that probably will involve large increases in the production of coal, electricity, and coal-derived synthetic fuels, what projections might be made about water supply as a limiting factor? PROJECTED WATER CONSUMPTION In the West, the stringency of water supply is well known.
From page 199...
... . The total water consumption would be about 4.2 million acre-ft, on the basis of the factors in Table 4-7.
From page 200...
... tram nrolicinl reservoirs TOTiL 7.45 454 0.~6 I.11 93.ts 4.58 '~ .99 Source Adapted Irom John Hnrte ens Mohnmed I l-GnsscirN~Energy and Water, 5eience 199 (197S) 624 In the case of the eastern group of three river basins, which in 1975 had a water consumption of 2.8 million acre-ft, use of the 40 quads would increase water consumption to 7 million acre-ft, or about 2.7 percent of runoff Although such gross analysis appears favorable, other considerations are important.
From page 202...
... Water consumption for the major cuolmg modes are tin millions ol acre feet per quad of electricity) once-thrnugh (no storage)
From page 203...
... We judge that tripling present coal production for these ends will be contingent on facing the water problem squarely. The technical means of reducing water consumption should be stressed.
From page 204...
... If concerns about nuclear fission subside, then the choice between coal and nuclear power will likely be made increasingly on an economic basis; the demand for coal would be more sensitive to environmental standards and to the cost and reliability of pollution controls. In both the short and long term, emission standards will have an impact on the regional distribution of coal production and hence on transportation requirements.
From page 205...
... Beyond the turn of the century the situation will change again for several different reasons. First, coal will be increasingly required to produce synthetic fuels to substitute for declining oil and gas production.
From page 206...
... U.S. Department of Energy, Coal—Bituminous and Lignite in 1976, Office of Energy Data and interpretation, Energy information Administration (DOE/EIA0118/1[76]
From page 207...
... p b0; and U.S. Department of Energy, Monthly Energy Review, March 1979, Office of Energy Data, Energy Information Administration (DOE/EIA 0035/3 [79]
From page 208...
... U.S. Department of Energy, Coal Data—A Reference, Office of Energy Data and Interpretation, Energy information Administration (DOE/EIA-0064)
From page 209...
... p. 160; and National Coal Policy Project, "Summary and Synthesis," in Where We Agree Rep rt of the National Coal Policy Project, sponsored by the Center for Strategic and international Studies, Georgetown University (Washington, D.C.: Automated Graphic Systems, 1978)


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