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Air Quality and Stationary Source Emission Control CHAPTER 10 SOME METHODS OF REDUCING SULFUR OXIDES FROM POWER PLANTS (Chapter 10 was written by Harry Perry under the general supervision of the committee, which reviewed the work at several stages and suggested modifications that have been incorporated. While every committee member has not necessarily read and agreed to every detailed statement contained within, the committee believes that the material is of sufficient merit and relevance to be included in this report.) In this chapter a number of possible techniques for reducing emissions of sulfur oxides from powerplants are discussed and evaluated. They include: improved efficiency of conversion of fuel to electricity (this would reduce pollutant emissions per unit of electricity generated); shift to nuclear generation as rapidly as possible since no sulfur oxide (or particulate) is emitted from nuclear plants; shift fossil fuel plants to lower sulfur fuels; removal of sulfur from coal before combustion, or of the sulfur oxide after combustion, but before it enters the stack: the techniques to be considered are
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Air Quality and Stationary Source Emission Control coal preparation (conventional and advanced technology); solvent refined coal; low sulfur, low BTU gas from coal; fluidized bed combustion; shift fuel consumption from electricity to pipeline grade gas made from coal or to solar energy. Other possible techniques are discussed in Chapters 11 and 12. ASSESSMENT OF THE POTENTIALS FOR IMPROVED EFFICIENCY IN THE CONVERSION OF FUEL TO ELECTRICITY Summary Methods of generating electricity at increased efficiencies (in order to reduce the pollution load per unit of electricity generated) are not expected to come into widespread use until 1985 or later. As important as it is to continue R&D on these advanced power cycles, they offer no sollution for reducing sulfur oxide or particulate emissions in the period between 1975 and 1985. The average heat rates (i.e. the number of heat units required to generate one net kw-hr. of electricity) for utility power plants in the U.S. declined steadily from 25,175 BTU/kw-hr. in 1925 to 10,479 BTU/kw-hr. in 1972. This increase in conversion efficiency was the result of a number of technologic improvements, the most important of which were those that permitted steam turbine plants to operate at higher temperatures and pressures. Through experience it has been found that the best current practical efficiency of operation is 38 to 39 percent. (Heat rate approximately 9000 BTU/kw-hr.). The average heat rate was lowest in 1968 when it was 10,371 BTU/kw-hr., and it has increased steadily since that time for a number of reasons. The leveling off in the efficiency of new plants, the more widespread use of nuclear
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Air Quality and Stationary Source Emission Control plants with their higher heat rates and the need for additional electricity for pollution control are among the most important causes for the increase. With the efficiency limitation that exists when using the steam turbine cycle, the electric utilities have started to examine the potential for using advanced power cycles which have the potential for using less fuel per kw-hr. and thus reducing the amount of pollution generated. Among those systems receiving the greatest attention are: combined steam turbine-gas turbine systems (open cycle); magnetohydrodynamics (open cycle); and the use of binary cycles or working fluids other than steam. Steam Turbine-Gas Turbine Combined Cycles (open cycle) In this cycle a fuel is burned in a gas turbine and part of the energy released generates electricity in the gas turbine. The hot gases leaving the turbine are then used to generate steam for use in a conventional steam turbine. Steam turbine-gas turbine combined cycles are currently being used commercially on medium sized boilers using natural gas as a fuel. However, plants using these cycles would be unable to use coal as a fuel (unless it were first gasified and the particulates removed); they do not operate at sufficiently high temperatures to get the high conversion efficiencies desired, and when the temperatures are increased, do not have the service life required in a base load utility plant. A number of new developments will be required if these shortcomings are to be overcome. Efficient and low cost processes will have to be devised to convert coal into a clean gaseous fuel, turbine designs will have to be greatly improved to obtain the turbine life needed at central stations, and materials of construction will have to be developed that are
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Air Quality and Stationary Source Emission Control able to operate at the high temperatures needed for obtaining high conversion efficiencies. Estimates vary as to when commercial plants using this type of advanced technology with coal as a fuel will be in operation, but no large number of such plants could be operational before 1985. Magnetohydrodynamics (open cycle) Magnetohydrodynamics (MHD) is a method for converting the energy in a hot moving gas stream into electricity by passing a conducting gas through a magnetic field. The gas must be heated to very high temperatures to make it conducting, and even the, “seed” materials may have to be added to obtain the levles of gas conductivity required to operate satisfactorily. In open cycle MHD, the hot gases leaving the MHD duct would be used to raise steam for generating electricity in a conventional steam generator. Numerous studies have been conducted both in the U.S. and abroad aimed at solving the multitude of problems that still must be overcome before MHD is commercially available. A demonstration size unit, using natural gas as a fuel, is now being tested in the USSR. Even when using clean fuel, MHD ducts still need to be developed that will have a useful life in the extreme temperature conditions expected in ducts; methods for recovering the seed material and removing nitrogen oxides must be found and materials must be developed for the electrodes that will have the needed electrical properties and the ability to withstand high temperatures for extended periods. If coal were first converted into a clean gas (free of particulates) before it was burned in an MHD unit, the same problems would have to be overcome as when natural gas is the fuel. If coal were to be used directly as the fuel for MHD generation, all of these already difficult problems would be compounded. The presence of coal ash in the gases in the form of a liquid slag, could cause serious erosion and corrosion problems that could shorten insulation, duct and electrode life. In addition, seed recovery will
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Air Quality and Stationary Source Emission Control be much more complex in the presence of coal ash. If MHD could be used commercially, conversion efficiencies of from 50 to 60 percent should be attainable. While there is considerable controversy over whether a greatly expanded research effort can be justified, there is general agreement that widescale commerical application will not occur until 1985 or later. The Use of Binary Cycles or Working Fluids other than Steam The efficiency limitations of modern steam electric plants arise from the high temperatures and pressures required when using water (steam) as the working fluid. In order to extend these currently used steam conditions, special steels would be required and the capital costs would exceed the costs of the fuel savings. If a working fluid which possessed a higher temperature than steam at a given pressure were used, it would be possible to increase the quantities needed of the more expensive second fluid, a binary cycle would be used with the second fluid being used for the high temperature part of the cylce and a conventional steam cycle being used at the lower temperatures. A few such binary plants were built and operated in the mid-1930s using mercury as the second fluid. Because of health hazards and a variety of maintenance and operating problems, these plants were abandoned. The binary cycles now under consideration would probably use potassium (or a mixture of sodium and potassium) as the high temperature fluid because of the experience gained with using these fluids in turbines in Atomic Energy Commission and NASA programs. Other working fluids (carbon dioxide, helium) might cause fewer operating problems and are also being considered for possible use. Efficiencies as high as 50–55 percent might be obtained in binary plants but, as with the other advanced power cycles, extensive commercial utilization will not occur until the period beyond 1985.
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Air Quality and Stationary Source Emission Control SHIFT TO NUCLEAR GENERATION AS RAPIDLY AS POSSIBLE Summary If the necessary Federal and State actions are taken to restore the originally planned nuclear capacity (with associated reduction in particulate and sulfur oxide emissions) coal consumption could be reduced by about 75 million tons in 1980. Commercial nuclear power plants use light water reactor technology (except for one demonstration and one full scale gas-colled reactor) but are only now beginning to produce significant quantities of electricity. There are currently 32,500 MW of capacity with operating licenses, 56,800 MW of capacity are under construction and 147,000 MW that have limited work authorizations are being planned. Because of the difficulty that utilities are now having in raising capital for construction of new plants and the higher capital costs of nuclear plants compared to fossil fuel plants, a number of utilities have announced that they will delay or cancel construction of nuclear plants that had been ordered. Moreover, since many utilities are able to “pass through” to the consumer (without waiting for regulatory approval) the increased costs of fuels, an economic incentive is provided to continue to operate existing fossil fuel plants and to build new ones. Under other conditions new nuclear plants which do not emit particulates or suflur oxide, but which have higher capital costs and do not benefit from the automatic fuel clause would be constructed. As a result, construction schedules, for nuclear power plants are being delayed. The AEC’s 1972 projection of 1980 nuclear capacity was 132,000 installed megawatts. By last year, (1973) the forecast had been reduced to approximately 100,000 megawatts. The current projection (late 1974) is for nuclear capacity in the range of 60–70,000 megawatts by 1980. FEA estimates1 that nuclear plant construction schedules could be accelerated so as to permit recovery of about 30,000 megawatts
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Air Quality and Stationary Source Emission Control between now and 1980 yielding a total installed capacity in that year approaching 100,000 megawatts. To accomplish this, it would be necessary for state regulatory commissions to take steps to alleviate the financial strains on utilities. Some action on the federal level to assure priorities for critical materials and components will also probably be needed. Without this assistance, it is unlikely that the industry will be able or willing to finance capacity in excess of 60–70,000 megawatts by 1980. If these actions are taken and 30,000 MW of nuclear capacity, which would otherwise not be operational, are on stream by 1980 it would reduce coal consumption in that year by about 75 million tons. However, using nuclear fuels for generating electricity creastes other types of environmental problems. These include possible radiation releases during routine plant operation and in the event of an accident, unresolved problems with respect to the long term disposal of high level radioactive wastes, and prevention of the theft of highly radioactive material from which nuclear weapons could be produced. SHIFT TO LOWER SULFUR FUELS Summary Existing and projected shortages of natural gas will further reduce the amount of this clean fuel (low in sulfur, low in particulates) available for electric utility use. Domestic petroleum production has not been able to supply domestic demand for a number of years and new national policies are aimed at further reducing the imports that have made up the deficiency. As a result the electric utility industry will have even less petroleum to use in the future than it has in the past. Eastern low-sulfur coal reserves are large but much of the reserves are not available to the electric industry. Existing production capacity for these low-
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Air Quality and Stationary Source Emission Control sulfur coals is inadequate and is expected to remain so. By shifting available low-sulfur coal to plants not meeting primary standards from plants which could burn higher sulfur coal and still meet the primary standards, some improvement in ambient air quality could be achieved. It is estimated that a shift of as much as 36 million tons could be made to reduce the tonnage in violation by about 15 percent. Low sulfur western coals will be usable in new coal fired plants designed to burn them if transportation capacity is increased but their use in retro-fitted plants will be limited. Natural Gas Since 1968, except for the Alaskan natural gas discoveries, the amount of gas that has been consumed each year has been greater than that which has been discovered. As a result there has been a steady deterioration in the absolute quantity of gas in the proven reserve category. Natural gas production on the other hand continued its rapid growth until about 1973; since then production has about leveled off. This is the result of inadequate gas supplies since unfilled demand for gas, the cleanest of the fossil fuels, remains at an all time high. As a result of the apparent peaking of production, gas curtailments have been made by the pipeline transmission companies to a large number of gas distribution systems with the greatest curtailments made for those that serve geographic areas far from the gas producing regions. During the winter period of 1973/1974 curtailments to East Coast gas distributors were approximately 25 percent. Some transmission companies have announced that curtailments on their system during the 1974/1975 heating season will be even greater. Transco, the gas transmission line serving many East Coast distributors, has indicated that curtailments could reach 30–35 percent this winter. Priorities have been assigned to various types of gas consumers. The highest priority customers are mainly the residential and small commerical users of gas who would have the
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Air Quality and Stationary Source Emission Control greatest difficulty in shifting to other fuels and who, even from a pollution abatement standpoint, should receive the highest priority since, in nearly all instances these customers are equipped with short stacks for discharging the combustion products into the atmosphere. If they used a polluting fuel they would make a much greater contribution to deteriorating ambient air quality than large consumers with tall stacks the use of which dilutes air pollutant concentrations by providing for mixing of the pollutants with large volumes of cleaner air before reaching ground levels. As a result of all of these factors less natural gas will be available to the electric utility industry and to large industrial customers than there has been in the past. In the President’s Message to Congress on October 8, 1974, he urged that all existing plants burning oil and gas that could be converted back to coal should do so, and that all plants due to come on stream that were designed for these other fuels should be modified to burn coal. Petroleum and its products A small quantity of petroleum products is indispensable to the operations of the utility industry. Coal fired plants need petroleum to start up new furnaces and to stabilize coal fired flames when the boilers are operated at low loads. In addition, small quantities of petroleum products are needed for diesel electric generator sets and to fuel gas turbines used largely for peaking operations. The bulk of the petroleum used by the utility industry, however, is residual fuel oil burned to supply the heat for base load steam electric generating plants. Some of the plants using residual oil were converted from coal to oil to meet the sulfur oxide air pollution regulations. National policy is now aimed at reducing the use of oil in utility boilers in order to reduce oil imports; shifting to low sulfur oil to reduce sulfur oxide and particulate emissions would frustrate this national goal. Even the
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Air Quality and Stationary Source Emission Control discovery of large domestic resources of either oil or gas on the Outer Continental Shelf (particularly the OCS Atlantic which is close to the oil burning plants and to regions with high ambient concentrations of sulfur oxides) would probalby not result in any significant change in this situation. If the OCS Atlantic leasing were to start as early as 1975 and if important discoveries were made, it would be 1979 or 1980 before large volumes of these fuels would be available for use from this source. Moreover, it is abvious that use of these fuels, which are in short supply now and are certain to be in the future, by the utility industry would not represent the best use of these fuls to obtain short term environmental relief. There are approximately 64,300 MW of oil burning steam electric capacity in operation in 1974 with 24,000 MW of new oil burning capacity being constructed. Of the existing capacity, 23,600 MW at 73 plants, or about 30 percent, could be converted to coal. These plants are concentrated mainly along the East Coast—New England and the Mid-Atlantic states—with a few in mid-western areas where residual fuel can be delivered at low cost by water. Because of the geographic locations of these plants with respect to coal suppliers and the high concentration of plants in a relatively few areas, supplying coal that they require, even coal with a high sulfur content, may be more difficult than it first appears because of a shortage of coal production capacity and of railroad cars. Coal The coal resource base of the U.S. is large anough that, no matter what projections are made for its use as a boiler fuel or for its conversion into synthetics, there will be adequate supplies available to last until beyond the end of the century. Unfortunately, most of the coal currently being mined in the U.S. has a higher sulfur content than the new SOx source performance will permit (in the absence of stack gas desulfurization). In 1972, the electric
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Air Quality and Stationary Source Emission Control utility industry consumed 352.9 million tons of coal of which only somewhat over 1 percent had a sulfur content 0.5 percent or less, about 12 percent had a sulfur content of 0.6 to 1.0 percent, 56 percent had sulfur content between 1.1 and 3.0 percent, while 31 percent had a sulfur content over 3 percent. The average sulfur content sulfur content of coal provided to electric utilities was approximately 2.5 percent. From FPC records (which have been kept since February 1973) the average sulfur content of coals delivered each month to electric utilities was 2.3 percent until May 1974 when it rose to 2.4 percent. In commenting on this increase in sulfur content the FPC noted “In the past few months as coal purchases have continued to register year-to-year gains, the bulk of the increase has been in the higher sulfur categories.” The increase in coal production in the first ten months of 1974 of about 5.0 percent over the comparable period of 1973 appears to have come mainly from increasing the capaicty of old mines (working additional time, and opening up new sections) rather than from the opening of new mines. Immediately following the passage of the Coal Mine Health and Safety Act of 1969, 21.5 million tons of deep mine capacity was closed in 1970, 19.7 million tons in 1971 and 21.0 million tons in 1972, for a total of 62.2 million tons. This represented a total of 1585 mines of which 1341, or about 85 percent, were mines producing less than 50,000 tons per year. With the disappearance of the small underground mines that were unable to meet the new health and safety regulations and with the large demand for coal and the high price it commands, the number of closings in 1973 and 1974 was probably smaller but is still probably in the range of 15 million tons per year. Deep mine openings in these same resulted in added capacities of 33.2 million tons, 23.5 million tons and 17.6 million tons respectively, for a total of 45.6 million for the three year period. Deep mining capacity, therefore, decreased 16.6 million tons in three years. The new strip mine productive capacity that was installed was 26.5 million tons in 1970,
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Air Quality and Stationary Source Emission Control or they are designed to produce a refinery feedstock rather than a clean boiler fuel. Low-BTU Low-Sulfur Gas from Coal Gasification of coal was a commerically used process both in the U.S. and abroad for many years, but was abandoned in favor of natural gas when large supplies of natural gas became available. Town gas produced for distribution by the local gas companies was made from the distillation of bituminous coals and by producing “water gas”, a mixture of carbon monoxide and hydrogen, made from coal. The water gas was enriched with light gaseous hydrocarbons made by thermally cracking petroleum to make a gas with a 550 BTU per cubic foot heating value. The process was cyclic, inefficient and expensive. When a clean dust-free gaseous fuel was needed by industry (e.g. at glass works), it was made by gasifying coal with a mixture of steam and air in a continuous process. The hot gas produced (producer gas) had a low BTU content (130 BTU per cubic foot) because of the dilution with the nitrogen in the air from which it was made. As a result it could not be transported economically very far. On the other hand the gas could be made at lower cost than the higher heating value “water gas.” Most of the sulfur that was in the coal appeared in the producer gas as hydrogen sulfide. Since air pollution from sulfur oxides was not considered a problem at the time, the hot gas was burned with the hydrogen sulfide still in it. In a few installations the hydrogen sulfide was removed. When interest in coal gasification was revived in this country it was because the pipeline transmission companies and the gas distribution companies became concerned that they would be unable to continue their growth as natural gas supplies were depleted. Thus, all the early research was directed at making a high BTU gas as a substitute for natural gas. A large number of new processes to make town gas had been tried in Europe after World War II since at that time coal was still their main
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Air Quality and Stationary Source Emission Control energy source. Almost all the processes were designed to be continuous in order to avoid the high costs of cyclic operation and the air that was used in making producer gas was replaced by oxigen. The large scale use of oxygen became possible as the result of development of such plants for use in other types of commercial industrial processes. In addition, if the process was able to operate under pressure, there were economic advantages over the older atmospheric pressure operations. With the continuous processes made possible by the use of oxygen in place of air, the new processes were also designed to operate at pressure. Three processes for making town gas from coal had been used in a significant number of installations so that they can be considered commercial. There are the fixed bed, high pressure Lurgi process, the atmospheric pressure entrained Kippers Totzek process and teh Winkler fluid bed atmospheric process of Davey Power Gas, Inc. Commercial scale plants using any of these processes could be built with a high degree of confidence that satisfactory operation would be achieved. However each of these processes has disadvantages so that more advanced processes are being studied in an effort to overcome these shortcomings. A large number of new processes are under study and two have been operated intermittently on a large pilot plant scale for several years (IGT-Hygas and CO2 Acceptor). A third large pilot plant, the Synthane process, is due to start operation in late 1974 or early 1975. Construction on a fourth plant using the Bigas process was started recently. Unless there are unexpected breakthroughs the first commerical plant using any of these technologies will not be operational until about 1981 to 1983. In the last several years, interest has turned to making a low-BTU low-sulfur content gas for use under industrial and utility boilers. This type of gas should be able to be produced at lower costs than high BTU gas since oxygen is replaced with air and a number of downstream process steps are eliminated. Moreover, the overall efficiency of conversion
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Air Quality and Stationary Source Emission Control is expected to be as much as 85 percent compared to the 65–70 percent for high BTU gas. Although it is believed that most of the processes that were under investigation for making high BTU could also be used for making low BTU gas there has been no testing of any of the commercial processes (Lurgi, Kioppers Totzek or Davey Power Gas, Incorporated) in the U.S. A Lurgi generator, using air instead of oxygen, has been under test in Germany for several years. The Lurgi generator is operated under pressure, then to a pressurized steam boiler to produce steam to generate electricity and to a gas turbine to produce additional electricity. The exist gases from the turbine are used to preheat steam. Total output of the power plant is 170 MW of which 74 MW is produced by the gas turbine. The test results on this plant have not been reported in detail so that it is not known how successful it has been, but no new installations using the process have been announced. Plans are being made to test a Lurgi unit in the U.S. for making low-BTU low-sulfur gas. Commonwealth Edison COmpany and the Electric Power REsearch Institute have announced that they intend to construct a Lurgi unit which will produce a clean gas to operate one of Commonwealth Edison’s small coal-fired electric-generating units. As of January 1975 no announcements have been made that contracts have been awarded for this plant. Full scale, long term tests are required before even the Lurgi gasifier for making low-BTU low-sulfur gas can be considered to be available for commercial use. Illinois coals that are used extensively by Commonwealth Edison possess some mild coking properties. Tests in a specially designed Lurgi gasifier were conducted in the U.K. and appear to indicate that coking coals can be used successfully, but this still must be confirmed by additional testing. The gas cleaning system that has been developed creates potential environmental problems and improved and lower cost methods for gas clean-up would be desirable. According to Commonwealth Edison’s timetable, their first commercial plant using
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Air Quality and Stationary Source Emission Control this process (should the tests be successful) would be operational in about 1981 or 1982. As with solvent refined coal it is difficult to estimate the costs accurately in the absence of any large scale plants. With coal at $20 per ton (80 cents per million BTU) low-sulfur, low-BTU gas (in 1974 dollars) would cost in the range of $1.75 to $2.00 per million BTU. In order to operate the Kippers Totzek process with air instead of oxygen, changes in design would be required. No experimental data have been reported although Koppers is said to be planning to run a test with air on one of the commerical gasifiers that is already in operation abroad. No recent data has been reported on air operation of Davey Power Gas, Incorporated’s gasifier so that commerical plants using either of these processes can probably be expected to be operational only some time beyond 1982. The timetable for commerical operation of the advanced processes to make a low-BTU low-sulfur gas that are still in the prototype or pilot plant stage to make a high-BTU gas is even less favorable. Combustion of low-BTU gas produces very low emissions of NOx. Low Sulfur Oil from Coal Liquid fuel from coal was produced during World War II in Germany using two different processes and the product was used as a refinery feedstock. Because of the existence of these processes and the expectation that when oil resources were depleted, coal liquefaction to a refinery feedstock would again be needed; most of the research on coal liquefaction was directed toward making this type of product. The need to make a clean fuel from coal for boiler use has changed the emphasis on coal liquefaction R&D, just as it did for coal gasification research. Unfortunately, coal liquefaction research was not pursued as intensively as coal gasification during the 1950s and 1960s. The oil industry expected that our limited domestic oil resources would be first supplemented by imported oil since oil
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Air Quality and Stationary Source Emission Control transport costs by sea are low and large reserves are found in other parts of the world.8 One of the two German processes (The Fischer Tropsch) would not be a useful method to pursue if a low-cost low-sulfur boiler fuel is all htat is needed. The Fischer Tropsch process first completely gasifies the coal and then recombines the carbon monoxide and hydrogen over a catalyst in a fluidized bed to produce relatively low molecular wight products. If a fixed catalyst bed is used, higher molecular weight products are formed. The other German process used (Bergius) dissolved the coal in a suitable hydrogen donor solvent. However, the process would not have to be modified extensively to take advantage of the development of new types of hydrogeneration catalysts and of advances in chemical engineering. As a result, if a low sulfur oil is now the desired commercial product, one of the several coal hydrogenation processes that have been tested only on a bench scale would have to be used. In addition to operating the low-sulfur low-ash process at more severe pressures and temperatures to make a liquid product, (see the discussion above of low-sulfur, low-ash coal) the Synthoil process of teh Bureau of Mines and the H-coal process of Hydrocarbon Research Incorporated could be considered as likely process candidates. If a successful modification of any of these processes can be accomplished, it might be possible to have a first commercial plant in operation in the priod 1982–1983. If any of the processes still at an early state of investigation must be developed for producing a low-sulfur oil for boiler fuel, commercial plants will probably not be in operation until 1985 to 1990. Fluidized Bed Combustion Because of the shift in interest away from producing synthetic high BTU pipeline gas and refinery feedstock from coal to producing a clean boiler fuel, methods for using coal directly have also been receiving increasing
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Air Quality and Stationary Source Emission Control attention. Pulverized coal combustion (used almost universally in large power plants) has reached a high degree of perfection although there remain areas in which improvements are possible. These include optimization of the configuration of the heat transfer surfaces, the use of alloys capable of handling higher steam temperatures and pressures and the development of methods to reduce the fouling and corrosive effects of the ash of certain coals. Other important drawbacks to using pulverized coal boilers include the fact that nearly all of the sulfur in the coal is converted into sulfur oxides which appear in the flue gases and that emissions of nitrogen oxides are high. Fluidized bed combustion, another method of burning coal directly in boilers, offers the potential for overcoming most of the difficulties that arise when pulverized coal is used. With fluidized bed combustion sulfur oxide and nitrogen emissions can be reduced, the efficiency and reliability of the units are expected to be increased and the size, weight and cost of the boiler may be reduced. In fluidized bed combustion, crushed coal is burned in a bed of limestone or dolomite particles (1/16" to 1/8") which absorb the sulfur that is released from the coal on combustion to form CaSOx. In some pilot scale tests, it was possible to operate so that only about 1 to 4 percent of the sulfur in the coal appeared in the flue gas with pressurized fluidized bed combustion and about 10 percent with atmospheric combustion. The heat transfer tubes are embedded in the fluid bed so that combustion tempertures are much lower than in pulverized fuel furnace while still giving much greater heat release rates per unit of boiler volume. Fluidized bed combustion studies have been supported by several government agencies for a number of years. In the early work of EPA it was contemplated that fluidized beds would be used both in smaller units such as those represented by the industrial water tube boiler market and in the large base load coal fired utility plants. This research drew heavily on
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Air Quality and Stationary Source Emission Control the fluidized combustion experience of the oil industry. Limited tests on American coals were run for EPA in the U.K. on a small fluidized pressure boiler operating at 5 to 6 atmospheres pressure. The research supported by OCR was done at atmospheric pressure in a small fluidized bed unit having a capacity of 7000 pounds of steam per hour. Furnace temperatures of 1500°F were used and it was demonstrated that all types of coals could be burned in the unit in an environmentally acceptable manner. A 30 MW atmospheric unit, which is a scale-up of the successful pilot plant design, is being constructed and installed in a power plant in West Virginia. The plant is scheduled to be operational in June of 1975. If no unexpected difficulties are encountered during testing of this unit, a 200 MW plant would be constructed. The design of this larger unit has already started and it could be in operation by late 1977 or early 1978. If successful, an 800 MW unit would be designed and constructed and could be operational by 1980 or 1981. Research on pressurized fluid bed combustion is not as far advanced as atmospheric operations. However, pressurized operation should further reduce the size and capital cost of the combustion equipment and would be particularly attractive for use in combined gas-turbine steam-turbine plants (see the dicussion above of nuclear generation). A pressurized fluidized bed 1.8 MW pilot development unit is to be used to provide design, materials and environmental information for the construction of larger pilot plant unit. A 20 to 60 MW, combined cycle plant is now being designed, as is a component test program for larger scale equipment. The pressurized fluid bed research is thought to be about 2 years behind that of the atmospheric pressure research. This would indicate that the first full scale commerical pressurized fluid bed combustion units might be achieved in the 1982 to 1983 period.
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Air Quality and Stationary Source Emission Control SHIFT FUEL CONSUMPTION FROM ELECTRICITY TO PIPELINE GRADE GAS MADE FROM COAL Summary The average cost of heating structures with natural gas made from coal is about one-half that of the average costs of heating the structure with electricity made from coal when using resistance heating. When using a heat pump with electricity, the average costs are about the same as for gas made from coal. Solar heating (including hot water) might also be competitive in some geographic areas with either gas or electricity made from coal. A national policy of energy self-sufficiency will require an increase in the use of nuclear fuels and coal and a decrease in the use of natural gas and oil. The rate at which new nuclear electric generating capacity would be installed in the next 10 years was estimated above. The shift away from oil and gas can be accomplished most easily in the industrial markets, less readily in the commerical/residential sector and with greatest difficulty in the transportation sector. For many uses, particularly in new installations, either electricity or a pipeline gas made from coal could be used to supply energy requirements. The choice of which route to select should be based on supplying energy at the lowest marginal social cost to the user. Pipeline gas from coal can be produced at the gasification plant for approximately $2.50 to $3.00 per million BTU. Electricity produced at a new coal-fired base load plant (equipped with air and water pollution controls) would cost about 2.6 cents per kw hour or $8.10 per million BTU. With resistance heating (100 percent efficiency conversion of electricity to useful heat) electric costs would be approximately twice that of natural gas (excluding transmission and distribution costs for both fuels). Under the same assumptions, with a heat pump with a seasonal performance factor of 2, electricity would cost 30 to 60 percent more than gas.
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Air Quality and Stationary Source Emission Control Average transmission distances for synthetic gas made from coal would be about 500 miles so that transmission costs would be between 25 and 30 cents per million BTU. Distribution costs vary widely from city to city but the average costs for all types of consumers in the U.S. were 40 cents per million BTU in 1971. All the synthetic gas would not require new distribution facilities since part of that gas would serve as a replacement for the decline in natural gas production. However, assuming that new facilities would be needed for all of the gas and that new distribution costs would be 50 percent more than the 1971 costs, then total costs per usable BTU to the consumer would be $5.70 to $6.50 per million BTU. This assumes 60 percent efficiency in use. Average transmission costs for electricity in 1968 were 1.98 mills per kw hour or about 60 cents per million BTU. As with gas, distribution costs for electricity vary widely among cities but the average distribution cost for electricity was 5.69 mills per kw hour or $2.76 million BTU in 1968. Total costs to the consumer for electricity (after adjusting transmission and distribution costs upward by 50 percent over the 1968 costs) using resistance heating (at 100 percent efficiency) would be about $12.80 per million BTU or from 100 percent to 120 percent more than synthetic natural gas made from coal. If a heat pump were used (with a seasonal performance factor of 2) the cost would be about $6.40 per million BTU, or about the same (or perhaps 10 percent higher) than the same usable BTUs from gas made from coal. Capital investments in the gas conversion plants are estimated at $7.25/million BTU/year. After correcting for a 60 percent efficiency in use, this becomes $12/million BTU/year. For the electricity generating plant, the cost is $22/million BTU/year. If a heat pump with a seasonal performance factor of 2 is used, the investment becomes $11/million BTU/year. The incremental investment cost over gas to the home-owner of using a heat pump, however, is approximately $1500/home for heating services above and about $500/home higher than gas for heating and air conditioning service (a separate
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Air Quality and Stationary Source Emission Control electric air conditioner for the gas heated home is assumed). A 1000 MW electric power plant would be able to serve 500,000 homes using a heat pump so that the investment cost (by the consumer) for using electricity is then $750 million or more than the generating plant. Another alternative for heating structures is the use of solar energy. Capital investment by the homw-owner for a solar heating (including hot water) system would be in the range of $1500 to $2500 (collector costs of $2 to $4 per square foot). Depending on the amount of backup electrical installation that must be available for reliable service, solar energy for heating might be less costly than electric heating even when using a heat pump in some geographic areas. FOOTNOTES 1 Derived from preliminary information supplied by Office of Energy Conservation, FEA. 2 Assessment of the Impact of Air Quality Requirements on Coal 1975, 1977, 1980. U.S. Bureau of Mines, January 1974. 3 The Clean Fuels Deficit—A Clean Air Act Problem Federal Energy Administration, August 1974. 4 Under normal circumstances a large new strip mine can be installed in 2–3 years and an underground mine in 3–4 years. Because of shortages of certain types of equipment and other factors, the time to open a new mine (either underground or strip) is now somewhat longer than this. 5 Bureau of Mines, Demonstrated Coal Reserve Base of U.S. on January 1, 1974, June 1974. 6 Bureau of Mines Circular 8655—Reserve Base of Bituminous Coal and Anthracite for Underground Mining in Eastern U.S., 1974. 7 EPA Contract No. 68–02–1302—Proj. No. 30, Nov. 1974. 8 Supplemental natural gas imports were not thought to be a useful method to supplement domestic supplies until the late 1960s because of the high cost of liquifying and
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Air Quality and Stationary Source Emission Control transporting the natural gas in the form of a very low temperature liquid.
Representative terms from entire chapter: