4
Coal

INTRODUCTION

Coal is the nation’s (and the world’s) most abundant fossil fuel. Domestic recoverable reserves amount to 6000 quadrillion Btu (quads), which is part of a total domestic resource of about 80,000 quads and a world resource crudely estimated at about 300,000 quads. 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.

The substitution of coal for natural gas and oil on a large scale, either directly or through synthetic coal-derived substitutes, would on these grounds seem a ready-made solution to the nation’s energy problems. The simple arithmetic of availability, however, does not tell the whole story. Doubling or tripling the use of coal will take time, investments amounting over the years to hundreds of billions of dollars, and determined efforts to solve an array of industrial, economic, and environmental problems.

Unlike oil and gas consumption, coal use is limited not by reserves or production capacity generally, but rather by the extraordinary industrial and regulatory difficulties of burning it in an environmentally acceptable and, at the same time, economically competitive manner. Coal is chemically and physically extremely variable, and it is relatively difficult to handle and transport. Its use produces heavy burdens of waste matter and pollutants. Even at its substantial price advantage, Btu for Btu, it cannot compete with oil and natural gas in many applications because of the



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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems 4 Coal INTRODUCTION Coal is the nation’s (and the world’s) most abundant fossil fuel. Domestic recoverable reserves amount to 6000 quadrillion Btu (quads), which is part of a total domestic resource of about 80,000 quads and a world resource crudely estimated at about 300,000 quads. 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. The substitution of coal for natural gas and oil on a large scale, either directly or through synthetic coal-derived substitutes, would on these grounds seem a ready-made solution to the nation’s energy problems. The simple arithmetic of availability, however, does not tell the whole story. Doubling or tripling the use of coal will take time, investments amounting over the years to hundreds of billions of dollars, and determined efforts to solve an array of industrial, economic, and environmental problems. Unlike oil and gas consumption, coal use is limited not by reserves or production capacity generally, but rather by the extraordinary industrial and regulatory difficulties of burning it in an environmentally acceptable and, at the same time, economically competitive manner. Coal is chemically and physically extremely variable, and it is relatively difficult to handle and transport. Its use produces heavy burdens of waste matter and pollutants. Even at its substantial price advantage, Btu for Btu, it cannot compete with oil and natural gas in many applications because of the

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems expense of handling and storing it, disposing of ash and other solid wastes, and controlling emissions to the air. Only in very large installations, such as utility power plants and large industrial boilers, is coal today generally economic and environmentally suitable to burn. Domestic coal production capacity today exceeds economic demand, and this may well remain true until the end of the century.1 The health problems associated with coal affect both its production and its use. The health of underground miners presents complex and costly problems, for example, and is in need of better management; black lung is the notable instance. 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. Chief among these is the risk that before the middle of the next century, emissions of carbon dioxide, an unavoidable (and essentially uncontrollable) product of fossil fuel combustion, may produce such concentrations in the atmosphere as to produce large and virtually irreversible alterations in the world’s climate. (See chapter 9.) Also worrisome is the water-supply situation, which could limit synthetic fuel production or electricity generation unless large-scale and possibly expensive steps are taken to minimize water consumption and manage water supplies. This is already a limiting factor in some western locations, but the eastern coal regions may be approaching trouble too. Coal-fired power plants burned nearly 70 percent of U.S. coal production in 1977, producing more than 45 percent of the nation’s electricity. Most of this was in large, centralized facilities with generating capacities of 300 megawatts (electric) (MWe) or more, designed to produce base-load power. (Smaller, less efficient oil- and gas-fired units and small, older coal units serve intermediate and peak loads.) Industry used one fifth of national production, slightly more than half of that in coke plants and the rest to produce steam and dry process heat. Almost all the rest (about 8 percent) was exported, mainly to make coke. Imports were less than 1 percent of U.S. production. In the future, the market for coal can be widened. Development of efficient, relatively clean coal power cycles for use in smaller electricity-generating units decentralized to serve local loads, for example, will be attractive to industry and to utilities with power plant siting problems. Coal use for industrial process heat and chemical feedstocks will be harder to stimulate, especially in smaller installations, because of the expense and difficulty of handling the coal and the various wastes and emissions from

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems its combustion. In small units, the capital and operating costs of dealing with this inconvenient fuel are proportionally larger than in larger ones. 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. Over the next 10–20 years some of the obstacles to increased demand will weaken as new technologies increase the efficiency and convenience of using coal, and as the prices of oil and gas rise while their reliability of supply declines. A number of the advanced electric power cycles for coal, now under development, would be suitable for smaller installations, and their relatively clean environmental characteristics would make it possible to locate them near users of their power. For smaller industrial users the fluidized-bed combustion and synthetic fuel processes now undergoing development would be especially valuable. Department of Energy regulations under the Powerplant and Industrial Fuel Use Act of 1978 (Public Law 95–620) will, when implemented and enforced, further improve the outlook for coal by banning oil and gas as fuels in most new power plants and large industrial heating units. This is not to imply that all the problems of coal use are solvable, or that coal can become the mainstay of the U.S. energy sector over the long term. Its environmental costs will remain high; mining and burning 2 or 3 times the present output of coal, even if it is done efficiently and with care, will be difficult (and increasingly expensive) if coal’s contributions to air and water pollution and land degradation are to be kept from increasing. With the foregoing in mind, we see the following as the prime objectives of national coal policy in the coming decades. Provide the private sector with strong investment incentives to establish a synthetic fuel industry in time to compensate as domestic and imported oil supplies begin to decline (probably some time near 1990). Continue the broad research and development program in fossil fuel technology to widen the market for coal by increasing the efficiency and environmental cleanliness with which it can be used. Improve health in the mines by strengthening industrial hygiene and by performing the necessary epidemiological research. The black lung problem especially should be clarified. (See chapter 9.) Devote the necessary resources to supporting long-term epidemiological and laboratory studies of the public health consequences of coal-derived air pollutants to put air quality regulation on a firmer scientific basis that allows more confident and efficient setting of standards, on which industry can depend in its long-range planning. (See chapter 9.) Develop a long-range plan, recognizing that coal presents some

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems serious environmental and occupational health and safety problems, and that it does not relieve the nation of its need to develop truly sustainable energy sources for the long term. By 1985, given reasonably coherent policy and successful research and development, annual domestic demand for coal should approach 1 billion tons (about 20–25 quads). 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. Knowledge of the environmental impacts of coal production and use (especially the public health consequences of coal-derived air pollutants) should be improved to the point that the current regulatory uncertainties can be reduced. As the year 2010 is approached, coal use in the United States may reach 2 billion tons annually. By then, some of the clean, efficient techniques of coal use now being developed should attain full commercialization, and knowledge of the environmental and public health characteristics of coal may be sufficient for confident standard setting. At the same time, however, water supply will be increasingly critical, and the first signs of climatic effects from carbon dioxide emissions may be appearing. It is at about this time that truly sustainable energy sources must begin to become available, to provide new flexibility for energy policy and to relieve some of the pressure on coal. For now, however, there is little room for maneuver. Coal must be used in increasing quantities, and mainly with the current technologies, until at least the turn of the century, regardless of what happens with respect to such alternatives as nuclear fission or solar energy. However, because of the variety of environmental and social problems it presents, it cannot indefinitely provide additions to energy supply. To keep these problems under control in the meantime, it would be wise to approach coal conservatively, with an eye especially to its environmental risks. RESOURCES RANK AND QUALITY Coal is an extremely complex and variable material whose structure is inadequately understood despite centuries of use. The increased demand for coal is accelerating the effort to better understand its behavior and the nature of its effluents and by-products, under both direct use and conversion to synthetic fuels. Coals are classified by rank according to the state of “coalification” they

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems have reached.2 The categories of rank, which roughly indicate the stage of coalification, are, from lowest quality to highest, lignite (two varieties), subbituminous (three varieties), bituminous (five varieties), and anthracite (three varieties). (See Figure 4–1 and Table 4–1.) Low volatility and high carbon content together make anthracite the slowest and cleanest burning coal, qualities which made it the most desirable residential and commercial heating fuel before the advent of heating with oil and natural gas. However, for making coke the best coal is low-volatile bituminous. Per pound, the percentage of ash is lower and the Btu content is higher in low-volatile bituminous than in anthracite. The agglomerating or caking nature of bituminous coal, however, makes it ill suited for certain types of coal gasification processes, which become clogged by the fused carbon material. These processes require noncaking coal, which is usually subbituminous—a rank found almost exclusively in the West. Some gasification processes have been developed to use either type of coal. The quality of coal is determined in general by two classes of material: (1) the organic remains of plants and (2) inorganic substances contributed by the plants, by water seepage, and by the surrounding geological matter, generally referred to as mineral matter. The organic portion of coal consists of carbon rings linked by chains that contain nitrogen, hydrogen, sulfur, and oxygen. Many products therefore arise when coal is heated. These products may be commercially useful, but may also be potentially hazardous; they include small amounts of carcinogens, mutagens, and respiratory irritants. The inorganic or mineral portion of coal usually constitutes from 9 percent to about 30 percent of the coal by weight. It includes up to half the sulfur and small, potentially toxic amounts of antimony, arsenic, beryllium, cadmium, mercury, lead, selenium, zinc, heavy radionuclides, and asbestos.3 Sulfur products are currently the most important of all pollutants released by coal combustion (chapter 9); their health effects are the most widely discussed, and they are by far the most costly to control. Sulfur in coal occurs mostly in a form that is either combined with the coal material (“organic”) or attached to, but physically distinct from, the coal (“inorganic” or “mineral”). (An additional small amount occurs as a sulfate, a product of weathering.) The distinction between organic and inorganic sulfur is important because inorganic sulfur can be removed in large part by washing prior to combustion; the organic form, under most washing processes in use today, cannot. In coals with very low total sulfur content by weight (less than 0.6 percent), 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) are measured in terms of pounds per

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems FIGURE 4–1 Comparison of heat values per pound (moist, mineral-matter-free basis) of coal of different ranks (Btu’s per pound). Source: Adapted from Paul Averitt, Coal Resources of the United States, January 1, 1974, U.S. Department of the Interior, Geological Survey Bulletin 1412 (Washington, D.C.: U.S. Government Printing Office (Stock No. 024–001–02703), 1975), p. 17. million Btu of fuel burned. For enforcement purposes, the Environmental Protection Agency (EPA) assumes that all the sulfur in the coal is released as sulfur dioxide, the weight of which is twice that of sulfur. 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

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems TABLE 4–1 Composition of Some American Coals Typea Proximate Analysisb (percent) Elementary Analysisc (percent) Heating Valued (Btu per pound) Moisture Volatile Matter Fixed Carbon Ash S C H2 O2 N2 Anthracite 2.5 6.2 79.4 11.9 0.60 93.5 2.6 2.3 0.9 14,500 Bituminous                     Low volatile 1.0 16.6 77.3 5.1 0.74 90.4 4.8 2.7 1.3 15,600 Medium volatile 1.5 23.4 64.9 10.2 2.20 87.6 5.2 3.3 1.4 15,600 High volatile A 2.5 36.7 57.5 3.3 0.70 85.5 5.5 6.7 1.6 15,000 High volatile C 12.2 38.8 40.0 9.0 3.20 79.2 5.7 9.5 1.5 12.400 Subbituminous   A 14.1 32.2 46.7 7.0 0.43 80.9 5.1 12.2 1.3 12,100 C 31.0 31.4 32.8 4.8 0.55 74.0 5.6 18.6 0.9 8,800 Lignite 37.0 26.6 32.2 4.2 0.40 72.7 4.9 20.8 0.9 7,600 aThe analyses are meant to give an idea of the range of variation among coal types. There is considerable variation within each type, as well. bProximate analysis totals 100 percent by weight. cElementary analysis totals 100 percent by weight on a dry, ash-free basis. dHeating value is on a moist, mineral-matter-free basis. Source: Adapted from U.S. Environmental Protection Agency, Electric Utility Steam Generating Units: Background Information for Proposed Particulate Matter Emission Standards, Office of Air Quality Planning and Standards (Springfield, Va.: National Technical Information Service (PB-286–224), 1978), Table 3–6.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems September 18, 1978) that limit the possibility of using low-sulfur coal as the sole means of meeting the standard (The sulfur content of coals in the major U.S. producing areas ranges from 0.3 to 4.7 lb per million Btu.)5 The regulations and their impact are discussed in more detail in the section of this chapter entitled “Air Pollution Regulation and Control.” DISTRIBUTION OF RESOURCES While recoverable quantities of coal are found in at least 32 states (see Figure 4–2), 90 percent is found in only 10 states, distributed among four regions. These regions and states are the Appalachian basin (chiefly, in order of deposit tonnage, West Virginia, Pennsylvania, Ohio, and eastern Kentucky), the Illinois basin (also called the Eastern Interior region—Illinois, western Kentucky, and Indiana), and the Northern Great Plains and Rocky Mountain regions (Montana, Wyoming, Colorado, and North Dakota). A broad distinction is drawn between types of U.S. coal based on whether they are located east of the Mississippi (Appalachian and Illinois basins) or west (the Western Interior, Northern Great Plains, Rocky Mountain, Gulf, and Pacific regions). There are major differences between eastern and western coals, based on their different conditions of formation. The major deposits east of the Mississippi are generally the oldest and deepest, and are therefore of highest rank. Most western coals were formed about 150 million years later than eastern coal, at shallower depths; their coalification is less advanced, and their energy and carbon content are therefore generally lower, than those of eastern coal. 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. U.S. coal is generally in huge beds, ranging in thickness from a few inches to more than 100 ft, that extend with some interruptions for up to 30,000 mi2. The major Appalachian deposit is the Pittsburgh bed, which, because of size, the high heat value of the coal it contains, and its use in the creation of the Pennsylvania iron and steel industry, has been called the most important single mineral deposit in the United States. Fairly uniform and continuous over 6000 mi2 of western Pennsylvania, West Virginia, Ohio, and Kentucky, the Pittsburgh bed yielded through 1973 an

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems FIGURE 4–2 Coal fields of the coterminous United States. Source: Adapted from Paul Averitt Coal Resources of the United States, January 1, 1974, U.S. Department of the Interior, Geological Survey Bulletin 1412 (Washington, D.C.: U.S. Government Printing Office (Stock No. 024–001–02703), 1975), p. 5; and U.S. Department of Energy, Energy Information Administration, Coal Data (Washington, D.C.: U.S. Government Printing Office (DOE/EIA-0064), 1978), p. 1.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems estimated 9 billion tons or about one fifth of total U.S. production to that date, with much still remaining.7 The largest unbroken concentration of coal in the United States is the remarkable Wyodak bed, centered in Cambell County, Wyoming. This bed penetrates the surface continuously along a line extending for 120 miles at thicknesses ranging from 25 ft to 150 ft. To a depth of 200 ft, it contains an estimated 15 billion tons of strip-minable coal (or about 20 times total U.S. output in 1976). To a depth of 2000 ft, it contains perhaps 100 billion tons of coal.8 (Given the low heating value of this coal and current prices, however, these deeper deposits are not now economically recoverable.) Coal resources are generally reported in short tons. The latest U.S. Bureau of Mines estimate of the tonnage in U.S. coal beds that are legally and economically accessible (called the reserve base) is 438 billion tons, about 32 percent of it accessible by surface mining. The reserve base is part of a total U.S. coal resource estimated, much less reliably, at 4 trillion tons. In terms of the reserve base, practically all anthracite is found in Pennsylvania underground-minable deposits; all but 16 percent of bituminous deposits are found east of the Mississippi; all subbituminous deposits are found in the West; all lignite is found in surface deposits, practically all of it in Montana, North Dakota, Texas, and Colorado. The distribution of the U.S. reserve base by coal rank, type of mining, and region is shown in Table 4–2. 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. Table 4–3 shows a distribution of recoverable reserve energy that is not far different from the distribution of reserve base tonnages. This is because, in comparison to the eastern coal, the lower energy of western coal is compensated for by its greater recoverability.10 DISTRIBUTION OF PRODUCTION In 1976 (the most recent year of output unaffected by the 1977–1978 coal strike), surface mines yielded 57 percent of U.S. coal production tonnage. In that year, Appalachia supplied 60 percent of U.S. coal, with 45 percent of the region’s output produced by surface mines; the Interior supplied 24 percent, about two thirds of it surface mined; and the West supplied 16 percent, practically all of it surface mined. The most important of the 26 producing states in 1976 were all east of

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems TABLE 4–2 Distribution of U.S. Coal Reserve-Basea Tonnage by Coal Rank and Type of Mining (percent) Region Coal Rank Total Surface Total Deep Grand Totalb Anthracite Bituminous Subbituminous Lignite Surface Deep Surface Deep Surface Deep Surface Deep Eastc <0.5 2 9 35 0 0 <0.5 0 9 37 46 Westd <0.5 <0.5 2 6 14 25 7 0 23 31 54 TOTALb <0.5 2 11 42 14 25 8 0 32 68 100 aLegally and economically accessible deposits reported by the U.S. Bureau of Mines as of January 1, 1976, to be 438.3 billion short tons. Figures shown here are independently rounded. bTotals may not add due to rounding. cAppalachian and Eastern Interior basins (see Figure 4–2). dWestern Interior, Gulf, Northern Great Plains, Rocky Mountain, and Pacific (including Alaska) coal regions (see Figure 4–2). Source: U.S. Department of Energy, Coal Data—A Reference, Office of Energy Data and Interpretation, Energy Information Administration (Washington, D.C.: Energy Information Administration Clearinghouse (DOE/EIA-0064, Order no. 704), 1978), p. 2.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems TABLE 4–5 Regional Runoff and Consumption Statistics for 1975a Region Mean Annual Runoff (millions of acre-feet per year) Data for 1975 Consumption (millions of acre-feet per year) Per Capita Runoff (acre-feet per person per year) Consumption as a Fraction of Mean Annual Runoff New England 75.3 0.49 6.40 0.0066 Mid-Atlantic 97.2 1.78 2.43 0.018 South Atlantic Gulf 218.7 4.13 8.26 0.019 Great Lakes 81.0 1.22 3.65 0.015 Ohio 137.7 1.38 6.48 0.01 Tennessee 46.2 0.32 13.77 0.0068 Upper Mississippi 72.9 1.05 3.73 0.014 Lower Mississippi 81.0 6.16 13.77 0.069 Souris-Red Rainy 7.0 0.14 9.72 0.016 Missouri 60.8 19.44 6.80 0.32 Arkansas 81.0 12.96 12.96 0.16 Texas Gulf 35.6 10.53 3.40 0.30 Rio Grande 5.6 4.86 2.84 0.87 Upper Colorado 14.6 2.75 32.40 0.19 Lower Colorado 3.6 8.10 1.38 2.3 Great Basin 8.1 4.46 5.67 0.55 Pacific Northwest 234.9 14.58 35.64 0.062 California 69.7 27.54 3.32 0.40 Alaska 648.0 0.0062 1620.00 9.6×10−6 Hawaii 14.6 0.62 17.82 0.043 United States 2001.5 122.31 8.91 0.060 United States excluding Alaska and Hawaii 1338.9 121.50 6.32 0.091 aTotals may not add due to rounding. Source: Adapted from John Harte and Mohamed El-Gasseir, “Energy and Water,” Science 199 (1978):624. to the nation’s natural gas consumption. The quantities may seem large today, but considered in the light of prospects for other sources of energy to replace dwindling oil and gas supplies in 2010, they are not implausible. Suppose that 30 quads of this increment are directed to the production of electricity (yield, about 11.5 quads) and 10 quads to synthetic liquids (yield, about 6.5 quads). The total water consumption would be about 4.2 million acre-ft, on the basis of the factors in Table 4–7. How should such a burden be distributed? It might be argued that the nearer consumption is located to production, the more efficient it will be.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems TABLE 4–6 1975 U.S. Consumption of Freshwater by Different Categories of Use (millions of acre-feet) Use Consumption Domestic and commercial use 7.45 Industrial mining and manufacturing 4.54 Coal mining 0.16 Power plant cooling (fossil and nuclear) 2.11 Irrigation 93.15 Evaporation from artificial reservoirs 14.58 TOTAL 121.99 Source: Adapted from John Harte and Mohamed El-Gasseir, “Energy and Water,” Science 199 (1978):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. The gross runoff may include water that is available only at great cost, or water to which there is no longer access at desirable locations. The runoff may be subject to seasonal variations that affect the constancy of supply. The withdrawal of large amounts of water (added to such variations in flow) may so diminish flow that it will no longer support the ecological integrity of the river and its banks, in turn leading to other biological and environmental effects. ESTIMATING PERMISSIBLE CONSUMPTION LEVELS Clearly, some measurement of permissible flow is needed. A stringent one based on ecological considerations, proposed by Samuels,77 takes as a baseline the minimum weekly flow that can be expected each 10 years (in hydrologists’ terminology, 7Q10) and proposes that, annually, no more than 10 percent of it be used (0.1×52×7Q10). The Risk and Impact Panel analyzed the eastern and western groups of basins referred to above and for simplicity pooled the entire water supply within each group: this is equivalent to assuming that the distributions of water supply and demand are optimally matched. Under the 40-quad scenario, consumption in the western group is 20 times greater than the Samuels-derived criterion of 1.1 million acre-ft; for the eastern group, consumption is four times as great as the criterion of 1.8 million acre-ft.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems FIGURE 4–5 Water Resources Council hydrological regions in the coterminous United States, superimposed on a map of U.S. coal fields. Source: Adapted from Paul Averitt, Coal Resources of the United States, January 1, 1976, U.S. Department of the Interior, Geological Survey Bulletin 1412 (Washington, D.C.: U.S. Government Printing Office (Stock No. 024–001–02703), 1975), p. 5, for coal fields; and U.S. Water Resources Council, The Nation’s Water Resources (Washington, D.C.: U.S. Government Printing Office, 1968), for hydrological regions.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems TABLE 4–7 Estimated Freshwater Consumption Factors for the Coal Fuel Cycle (millions of acre-feet) Product Water Consumption Per Quad of Coal Per Quad of Product Electricitya 0.12 0.31 Synthetic gasb 0.05 0.07 Synthetic liquidsb 0.06 0.09 aAssumes that production of electricity from fossil fuels is to be 38 percent efficient and that 17 percent of the waste heat is dissipated directly to the atmosphere along with stack gases. Water consumption for the major cooling modes are (in millions of acre-feet per quad of electricity): once-through (no storage), 0.17–0.34: once-through (with storage), 0.43–1.28; wet-tower cooling, 0.34–0.51. Estimates apply to the following distribution of cooling modes: one-third once-through (no storage), one-third once-through (with storage), and one-third wet-tower cooling. Other combinations, of course, are possible, but for the kind of gross estimate with which this discussion is concerned, this distribution provides a useful example. bAssumes an average efficiency of conversion of 68 percent. Source: Adapted from John Harte and Mohamed El-Gasseir, “Energy and Water,” Science 199 (1978):627–628. Harte and El-Gasseir give a large range of values for each item based on known practice or estimates given in environmental impact statements. Their minimal estimates have been used in each case since engineering practice will tend to improve. In the examples given above, only two groups of hydrological regions were considered. It would appear that the water problems associated with the assumed 40-quad increment could be mitigated by employing other hydrological regions, those either with large freshwater supplies (Table 4–5) or with access to the ocean (Figure 4–5). Detailed studies at both the regional and local levels, however, will be needed to evaluate the resources. An equivalent problem has been studied in great detail by the six national laboratories, which analyzed the water requirements of the President’s National Energy Plan of 1977.78 That plan called for an additional 18 quads of coal—13.5 for electricity and 4.5 for industrial use—and the findings were considered to apply by and large to the plans under the subsequent National Energy Act of 1978. Using a less demanding water shortage criterion (critical surface supply) than that employed by the Risk and Impact Panel, the report concludes that such an increase is feasible, provided that great attention is paid to the many siting

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems problems that will occur. The problem will be not in mining the coal, but in its use. In addition to the control of siting, engineering practice may contribute to easing the problem. Dry cooling (or a mixture of wet and dry cooling) could be instituted at all new power plants, for example, and synthetic fuel plants could recycle water more thoroughly. Maintenance of plants could be scheduled for the dry seasons. In places where water is fully allocated, or nearly so, supplies might be bought from current holders of water rights—not all of whom now use water very efficiently. Water could in principle be moved by pipeline from basins in which it is relatively abundant to those where it is scarce, though political opposition by those in the donor basins would likely be serious. Brackish and otherwise unusable groundwater supplies could be tapped in some parts of the country. All of these would involve increases in the costs of the electricity or fuels produced. As energy development expands, the cost of water will become increasingly important as a factor in optimizing the design of facilities, and therefore as a component in the price of the products. Economics aside, in some places the arrival of new, large water consumers may be effectively barred by state water allocation systems, which can be very strict in their standards for use and strongly favor established users over newcomers. This means that even where water allocations are unused, it may be impossible for new facilities to obtain them. In conclusion, the analysis shows the increasing importance of water as a potential limiting factor for the increased production of electricity from fossil or nuclear fuel, and of synthetic fuels from coal. 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. Siting must be carefully planned, not only to prevent water-supply failure, but especially to obtain optimal use of our water resources. We recommend that all hydrological regions be studied, and that a national data bank be established. We note that water resources are largely under the control of the states, that two different approaches in law have been used to control them (the riparian doctrine and the appropriation doctrine), and that their use in national planning will not be a simple matter. The energy-water problem is, in fact, a part of a much broader one of water as a general limiting factor in the activities of society.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems GENERAL CONCLUSIONS Coal will remain a key element of U.S. energy policy well beyond the end of this century, regardless of the development of other energy sources. Its prime virtue is availability; it will be used increasingly over the next several decades to make up for delays in the development of other energy sources. In this role, it will help tide the nation over until truly sustainable energy sources can be used to replace dwindling supplies of oil and natural gas. It is impossible to predict very precisely how much coal will be needed annually as we approach the end of the century, but it is likely that demand, rather than supply, will be the limiting factor on coal use for as long as this study looks into the future. In making projections, it is important to distinguish between the near term—up to the late 1980s—and the longer term. First, since the lead time for construction of both coal-fired and nuclear power plants is of the order of 10 years, the electricity-generating capacity of these sources in the near term is already fairly well determined. Second, it is likely that the use of coal will be determined by the availability of facilities that can burn it in an environmentally acceptable manner rather than by the ability to produce or transport coal in sufficient quantities; any shortfalls in electrical output will have to be made up largely from oil- and gas-fired utilities, usually by delaying their phase-out or their transfer from base to intermediate and peak load use. Third, if the expansion of nuclear power is constrained by safety and related considerations, then the demand for coal in the near term will be little influenced by economic considerations or by its competitiveness with nuclear power. For the period beyond 1990 the situation becomes more complex. By then, oil and natural gas will be making smaller contributions to electricity generation, and coal and nuclear fission will tend to be more directly substitutable. If fears about safety, waste disposal, or related issues continued to constrain nuclear power, then coal demand would depend largely on the total demand for electricity and would be relatively insensitive to the competitiveness of its price or the severity of environmental regulations. 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. Expansion of production is not likely to be a limitation unless there is substantial vacillation and uncertainty about environmental

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems requirements. Because of the regional character of coal markets, uncertainty about environmental standards could affect the regional distribution of coal output while total supply remained the same. 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. To the extent that gases and liquids could be produced in situ from coal seams not otherwise accessible to mining, this particular competition with direct combustion could be decreased. Second (particularly if electricity growth is high), expansion of nuclear power will be increasingly limited by the availability and price of uranium unless advanced reactors and fuel recycling are permitted and well established by that time. If nuclear capacity is restricted to light water reactors on a once-through fuel cycle, the demand for coal in the early decades of the twenty-first century could accelerate. Third, if the carbon dioxide problem (chapter 9) proves serious, as seems quite probable, it would begin to become apparent shortly after the turn of the century—the same time at which total coal use would have reached the level where it could strain water resources. Thus, the first few decades of the twenty-first century could be a very critical time in balancing coal use with the exploitation of other alternatives, the principal one of which is likely to be nuclear fission. Among other things, this points to the importance of having as thorough a knowledge as possible of all aspects of the environmental, health, and climatic effects of coal use by the time the choices have to be made, On balance, it seems unwise to depend on coal use to increase much more than threefold in this country by the end of the century, though it would be technically possible to produce a good deal more than this. At about this level, the problem of water supply could become pressing, and the difficulty of dealing with air pollutant emissions is likely to be great. The climatic effects of carbon dioxide emissions may well become the overriding consideration at about this time. All of these factors, with their complex political and economic interactions, will combine to slow the growth of coal demand. Even so, at 3 times today’s production rate, or about 45 quads annually, coal is likely to supply perhaps one third to one half of the nation’s energy by the year 2000. This level of use, with all its costs and potential dangers, will have served its purpose if the intervening years are used to develop alternative, safe, and sustainable energy sources.

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems NOTES    1. Energy Modeling Forum, Coal in Transition: 1980–2000, 3 vols. (Stanford, Calif.: Institute for Energy Studies, Stanford University, 1978).    2. Plant matter that sank to the bottom of swamps 1 million to 600 million years ago formed peat which, when subsequently covered by sedimentation and rock, underwent chemical change. Heat in the absence of oxygen and the passage of time caused a progressive reduction in the amount of moisture and volatile matter in the coal and a progressive increase in the carbon and energy content. The amount of heat (which was a function mostly of depth of burial) and the length of time were the primary determinants of how far the process advanced.    3. H.M.Braunstein, E.D.Copenhaver, and H.A.Pfuderer, eds., Environmental, Health, and Control Aspects of Coal Conversion: An Information Overview, 2 vols., prepared for the U.S. Energy Research and Development Administration (Oak Ridge, Tenn.: Oak Ridge National Laboratory (ORNL/EIS-94), 1977), pp. 2–25, 30, 31; 4–138, 139; 5–5, 6, 7.    4. The 0.6 lb or less of sulfur per million Btu is equivalent to coal with 10,000 Btu/lb and 0.6 percent or less sulfur by weight. Each 1000-Btu increase in the coal’s energy allowed an additional 0.06 percent sulfur in the coal to meet the ceiling requirement.    5. New emissions standards in U.S. Environmental Protection Agency, news release on “New Standards for Coal-Fired Power Plants” (Washington, D.C.: U.S. Environmental Protection Agency (R-R-90), May 25, 1979). Distribution of coal by sulfur content in Francis X.Murray, ed., Where We Agree: Report of the National Coal Policy Project, 2 vols., sponsored by the Center for Strategic and International Studies, Georgetown University (Boulder, Colo.: Westview Press, 1978), vol. 2, pp. 291, 333, 393.    6. Braunstein, Copenhaver, and Pfuderer, eds., op. cit., pp. 2–32.    7. Paul Averitt, Coal Resources of the United States, January 1, 1974, U.S. Department of the Interior, Geological Survey Bulletin 1412 (Washington, D.C.: U.S. Government Printing Office (024–001–02703–8), 1975), pp. 63–75,    8. Ibid., pp. 71–72.    9. When the amount of coal in the reserve base is reduced by the amount expected to be lost in mining, it is called the reserve or the recoverable reserve. While the rate of coal recovery varies widely (from 25–30 percent in some deep mines to more than 90 percent in some deep and surface mines), 50 percent recovery has been estimated as the country’s average historical rate. This average is now rising as more surface deposits are mined and advanced underground technology is used to a greater extent.    10. The National Coal Policy Project (NCP) argues that the Montana and Wyoming underground subbituminous coal included by the U.S. Bureau of Mines in the U.S. reserve base is currently uneconomical to mine and should not be counted. If those deposits are subtracted, the West’s share of recoverable coal energy would drop from 53 percent to about 45 percent (Murray, ed., op cit., p. 286; calculated by taking 57 percent of NCP’s estimate of energy lost and subtracting it from the estimate of the Office of Technology Assessment (see Table 4–3) of western and total recoverable reserve energy).    11. U.S. Department of Energy, Coal—Bituminous and Lignite in 1976, Office of Energy Data and Interpretation, Energy Information Administration (DOE/EIA-0118/1[76]) (Washington, D.C.: Energy Information Administration Clearinghouse (703), 1978), p. 11; and National Coal Association [The first edition of Coal Facts published since the 1974–1975 issue], Coal Facts 1978–1979 (Washington, D.C.: National Coal Association, n.d.), p. 80, for rates of change,    12. Averitt, op. cit., p. 88, for federal government data.    13. The industry estimates that mines could produce 800–850 million tons in 1980 if there were demand for it, although there would be a short-term shortage of rail cars at that level of

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems    output. Constance Holmes, Vice President for Economics and Director of Foreign Trade, National Coal Association, personal communication, May 1, 1979.    14. U.S. Department of Energy, in National Coal Association, op. cit., p. 60; and U.S. Department of Energy, Monthly Energy Review, March 1979, Office of Energy Data, Energy Information Administration (DOE/EIA/0035/3 [79]) (Springfield, Va.: National Technical Information Service (NTISUB/E/127), 1979), p. 10,    15. Executive Office of the President, The National Energy Plan, Office of Energy Policy and Planning (Washington, D.C.: U.S. Government Printing Office (040–000–00380–1), 1977).    16. Environmental Protection Agency, “Electric Utility Steam Generating Units: Proposed Standards of Performance and Announcement of Public Hearing on Proposed Standards,” Part V, Federal Register 43 (September 19, 1978):42154–42184.    17. Energy Modeling Forum, op. cit., vol. 1.    18. Office of Technology Assessment, The Direct Use of Coal: Prospects and Problems of Production and Combustion (Washington, D.C.: U.S. Government Printing Office (052–003–00664–2), 1979), p. 96,    19. Ibid.    20. Energy Modeling Forum, op. cit., vol. 1, p. 35.    21. Environmental Protection Agency, “Electric Utinty Steam Generating Units,” op. cit.    22. Office of Technology Assessment, op. cit., p. 99.    23. Environmental Protection Agency, “Electric Utility Steam Generating Units,” op. cit.    24. A.Wunsch, “Combined Gas/Steam Turbine Power Plants: The Present State of Progress and Future Developments,” Brown Boveri Review 65 (October 1978):646.    25. U.S. Department of Energy, Fossil Energy Program Summary Document (Washington, D.C.: U.S. Department of Energy (DOE/ET-0087), 1979), p. 267.    26. Ralph M.Parsons Co., Preliminary Design Study for an Integrated Coal Gasification Combined Cycle Power Plant, prepared for the Southern California Edison Company (Palo Alto, Calif.: Electric Power Research Institute, 1978).    27. Fluor Engineering and Constructors, Effects of Sulfur Emission Controls on the Cost of Gasification Combined Cycle Power Systems (Palo Alto, Calif.: Electric Power Research Institute (AF-916), 1978).    28. William D.Jackson, “MHD Electrical Power Generation: Program Status Report,” in Scientific Problems of Coal Utilization, DOE Symposium Series no. 46 (Washington, D.C.: U.S. Department of Energy Technical Information Center, 1978).    29. Robert Farmer, “NWK 290-MWe Air Storage Plant at 5,300-Btu Heat Rate,” Gas Turbine World, March 1979, pp. 32–38.    30. Electric Power Research Institute, An Assessment of Energy Storage Systems Suitable for Use by Electric Utilities, prepared by Public Service Electric and Gas Co., Newark, N.J. (Palo Alto, Calif.: Electric Power Research Institute (EPRI-EM 264), 1976).    31. U.S. Department of Energy, Fossil Energy Research and Development Program (Washington, D.C.: U.S. Department of Energy (DOE/ET-0013[78]), 1978).    32. U.S. Department of Energy, Fossil Energy Program Summary Document, op. cit., p. 154.    33. Ibid., p. 152.    34. A.J.Molland and D.L.Olsen, “Preliminary Evaluation of Western Market for UCG-Derived Fuel Gas,” SRI International, Proceedings of the Fourth Annual Underground Coal Conversion Symposium, Steamboat Springs, Colo., 1978.    35. Harry Perry, “Clean Fuels from Coal,” in Advances in Energy Systems and Technology, vol. 1 (New York: Academic Press, 1978), p. 307.    36. National Research Council, Assessment of Technology for the Liquefaction of Coal (Washington, D.C.: National Academy of Sciences, 1977).

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems       37. L.E.Swabb, Jr., “Coal—Conversion to Fluid Fuels” (Paper presented at Exxon Energy Research and Development Symposium, New York, N.Y., September 27, 1978).    38. U.S. Department of Energy, Fossil Energy Research and Development Program, op. cit., p. 78.    39. Perry, op. cit., p. 282,    40. Ibid., p. 283.    41. National Research Council, Assessment of Technology for the Liquefaction of Coal, Commission on Sociotechnical Systems, Committee on Processing and Utilization of Fossil Fuels, Ad Hoc Panel on Liquefaction of Coal (Washington, D.C.: National Academy of Sciences, 1977), pp. 131–152.    42. Institute of Gas Technology, Assessment of Applications for Direct Coal Combustion, prepared for the National Science Foundation (Springfield, Va.: National Technical Information Service (PB-263651/AS), 1976).    43. Congressional Budget Office, Replacing Oil and Natural Gas with Coal: Prospects in the Manufacturing Industries (Washington, D.C.: U.S. Government Printing Office, 1978).    44. Executive Office of the President, Replacing Oil and Gas with Coal and Other Fuels in the Industrial and Utility Sectors (Washington, D.C.: Office of Energy Policy and Planning, 1977).    45. D.E.Nichols, P.C.Williamson, and D.R.Waggoner, “Assessment of Alternatives to Present Day Ammonia Technology with Emphasis on Coal Gasification” (Paper presented at the Symposium on Nitrogen Fixation, Madison, Wisc., June 12–16, 1978).    46. U.S. Department of Energy, Coke and Coal Chemicals in 1976, Office of Energy Data and Interpretation, Energy Information Administration (DOE/EIA-0120/76) (Washington, D.C.: Energy Information Administration Clearinghouse (706), 1978); and U.S. Department of Energy, Coke Producers in the United States in 1977, Office of Energy Data and Interpretation, Energy Information Administration (DOD/EIA-0122/1) (Washington, D.C.: Energy Information Administration Clearinghouse (708), 1977).    47. National Coal Association, op. cit., p. 76.    48. See note 5.    49. See note 5.    50. Office of Technology Assessment, op. cit., pp. 121–122.    51. National Research Council, Coal Mining, Commission on Sociotechnical Systems, Committee on Processing and Utilization of Fossil Fuels, Ad Hoc Panel on Coal Mining Technology (Washington, D.C.: National Academy of Sciences, 1978), pp. 55–60.    52. Ibid.    53. Office of Technology Assessment, op. cit., pp. 121–146.    54. U.S. Department of Energy, Coal Data—A Reference, Office of Energy Data and Interpretation, Energy Information Administration (DOE/EIA-0064) (Washington, D.C.: Energy Information Administration Clearinghouse (704), 1978), p. 14.    55. Office of Technology Assessment, op. cit., pp. 276, 278–289,    56. Ibid., pp. 282–286, 289.    57. Ibid., pp. 259–263,    58. Ibid., pp. 265–275.    59. In 1976, 63 percent of underground production came from continuous-mining machines and 4 percent from longwall mines. U.S. Department of Energy, Coal—Bituminous and Lignite in 1976, op. cit., p. 30.    60. Averitt, op. cit., p. 55.    61. Office of Technology Assessment, op. cit., p. 147.    62. Ibid., p. 382.    63. Ibid., p. 110.    64. The following material draws on Office of Technology Assessment, op. cit., pp. 111–120,

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Energy in Transition, 1985-2010: Final Report of the Committee on Nuclear and Alternative Energy Systems       65. Ibid., p. 112; and U.S. Department of Energy, Monthly Energy Review, March 1979, op. cit., p. 95, for 1978 data,    66. Federal Energy Regulatory Commission, Washington, D.C., unpublished data, 1978.    67. Thomas Petzinger, Jr., “Captive Customers? Utility-Owned Mines, Meant to Assure Fuel, Often Lift Power Cost,” The Wall Street Journal, May 10, 1979, p. 1.    68. Alexander Gakner, Chief, Branch of Fuel and Environmental Analysis, Federal Power Commission, in testimony, The Energy Competition Act, as cited in Office of Technology Assessment, op. cit.    69. U.S. Department of Energy, Coal—Bituminous and Lignite in 1976, op. cit., p. 4.    70. Charles River Associates, Coal Price Formation, prepared for Electric Power Research Institute (Palo Alto, Calif.: Electric Power Research Institute (EA-497, Project 666–1), 1977), pp. 4–40; see data for companies issuing annual reports in Office of Technology Assessment, op. cit., p. 120; and Fred Dunbar, Charles River Associates, Cambridge, Mass., personal communication, May 1, 1979.    71. U.S. Department of Energy, Coal—Bituminous and Lignite in 1976, op. cit., pp. 49–51; and U.S. General Accounting Office, U.S. Coal Development—Promises, Uncertainties (Washington, D.C.: U.S. General Accounting Office, (EMD-77–43), September 22, 1977), p. 5–5.    72. Office of Technology Assessment, op. cit., p. 160.    73. Teknekron, Inc., Projections of Utility Coal Movement Patterns: 1980–2000 (Washington, D.C.: Office of Technology Assessment, 1977).    74. Office of Technology Assessment, op. cit., p. 160; and National Coal Policy Project, “Summary and Synthesis,” in Where We Agree: Report of the National Coal Policy Project, sponsored by the Center for Strategic and International Studies, Georgetown University (Washington, D.C.: Automated Graphic Systems, 1978), p. 35.    75. See John Harte and Mohamed El-Gasseir, “Energy and Water,” Science 199:623–634; and Ecosystems Impact Resource Group, “Energy and the Fate of Ecosystems,” in National Research Council, Risks and Impacts of Alternative Energy Systems, Committee on Nuclear and Alternative Energy Systems, Risk and Impact Panel (Washington, D.C.: National Academy of Sciences, in preparation), chap. 6.    76. An acre-ft is the amount of water that would cover an acre to a depth of 1 ft. It is equivalent to 325,829 gal. Runoff is water from precipitation that is not lost through evaporation or transpiration by plants.    77. G.Samuels, Assessment of Water Resources for Nuclear Energy Centers (Oak Ridge, Tenn.: Oak Ridge National Laboratory (ORNL-5097 UC-80), 1976).    78. U.S. Department of Energy, An Assessment of National Consequences of Increased Coal Utilization, Executive Summary, vols. 1 and 2, report prepared by the staff of the six national laboratories: Argonne, Brookhaven, Lawrence Berkeley, Los Alamos, Oak Ridge, and Pacific Northwest (Washington, D.C.: U.S. Department of Energy (TID-29425), February 1979).