m-line processes offer economic and
mental options that must be evaluated before converting a dirty fuel to a clean fuel
Status of coal gasification David A. Tillman Materials Associates Washington, D.C. 20037
Koppers-Talzek. Modderfontein piani in South Africa is 13th since 1952: 4 oihers are under consiruciion 34
Environmental Science 8 Technology
The decision to gasify coal and then burn the gas implies that an environmentalleconomic choice has been made. Coal gasification followed by gas combustion is inherently less efficient than the direct burning of coal. More land must be disturbed in mining for coal; more water may be consumed in fuel preparation. Yet gasification provides a cleaner burning fuel, and reduces air pollution. Within the available gasification schemes, limited environmental tradeoffs regarding operating efficiency and water consumption occur. These suggest certain approaches to gasification system optimization: either to minimize coal consumption and mining or water consumption. These system optimization criteria also provide certain guides to operating cost parameters. They emphasize capital cost and system reliability on the economic side, while equally encouraging surface mine rehabilitation and water pollution abatement strategies on the environmental side. Near-universal agreement now exists: Coal must replace oil and natural gas as the primary energy source in the U.S. Coal reserves exceed 3.000 billion tons, a quantity larger than the combined resources of oil, natural gas. oil shale and bituminous sandstone. Oil, gas. oil shale, coal and current nuclear fuels offer 35.800 quadrillion Btu's of energy potential: coal, alone, offers 32.000 quads. Further, the coal industry has embarked upon an expansion program. Peabody Coal brought four new mines into production in 1974, with a combined annual capacity of 14.5 million tons. AMAX Coal projects a doubling of its capacity by 1978. Consolidation Coal recently completed three new mines, and has projects underway to open two more and expand five existing operations. Other companies have similar programs. Several studies indicate that the most serious constraints to the increased use of coal are the environmental problems associated with its mining and combustion. Sulfur and ash make coal a dirty fuel. The failure of scrubbing technologies to reach an environmental and economic viability, plus the limited acceptability of tall stacks as a remedy, inhibit coal demand. Coal gasification facilitates sulfur and ash removal. Environmental issues also exist with coal conversion pro-
cesses. Two problems are of sufficient significance to be major factors in defining economic limitations to this technology. These factors are the efficiency with which any system converts coal to gas, and the rate at which conversion systems use water. The efficiency issue delineates the amount of land required to support gasification; it suggests the acreage needed for coal mining. Water consumption affects the degree to which mine-mouth gasification can proceed in the arid and semi-arid climates of the west. Those concerns, then, impose constraints on the overall environmentalleconomic acceptability of coal conversion. Fuel markets Popular conceptions of coal gasification largely involve producing substitute natural gas (SNG): many current programs are aimed at improving that technology. That is. however, but one market for coal gasification. Industrial applications using low Btu gas (100-200 Btdscf) and medium Btu gas (300-500 Btulscf) must be considered as well. They may, in fact. emerge as the larger market for coal conversion because the industrial sector will lo9e its natural gas supplies sooner than residential customers. The market characteristics between industrial gas and SNG differ significantly. The industrial gas users must transport the solid coal to sites relatively close to the point of fuel utilization before gasification proceeds; low and medium Btu gases are not economically transportable over long distances. Further, industrial users must change their burner ports and feed apparatus. Where natural gas combustion requires a mixture of ten parts of air to one part of methane, low Btu gas utilization needs a more equally balanced mix. Finally, industrial users will tend to size their gasification plants to their specific requirements, rather than build the largest unit possible for optimized economies of scale. SNG users, on the other hand, receive and use the coal-derived fuel in the same manner as natural gas. They pay more for fuel, substituting higher operating costs for the expense of combustion equipment modification.
Process technologies Three gasification units merit comparison in terms of environmental issues: the Wellman-Galusha, the Koppers-Totzek. and the Lurgi gasifiers. All of these technologies are now used in commercial applications. The Glen-Gery Corp. of Shoemaker, Pa., uses Wellman-Galusha gasifiers to supply fuel for the manufacture of bricks. Seventeen Koppers-Totzek units are operating around the world in Finland, East Germany and South Africa; none operate in the U S . Lurgi units (licensed to Wheelabrator-Frye for U.S. distribution) have long been used by Sasoi. Ltd.. of South Africa. They will be installed in Farmington. New Mexico, to produce SNG for El Paso Natural Gas Go. Additionally, a major installation operates in Westfield. Scotland. These three systems have passed through the pilot and demonstration phases that the new Synthane. Hi-Gas, and C02-Acceptor processes have recently entered. The three basic commercial process technologies differ in size. approach to gasification, and end-product fuels. These distinctions imply process-specific potentials and limitations on user markets and geographical applicability. The Wellman-Galusha reactor, now produced by McDowell-Wellman Engineering Go.,is a relatively small unit; its maximum capacity is 85 tons of coal per day. Such a size economically precludes its being used in SNG operations; it is an industrial system. in the Wellman process, coal is fed into the top of a vertical reactor. Drying occurs first followed by pyrolysis and coking as the coal proceeds downward. Finally, the reacted coal reaches the combustion zone where it is fired with minimal quantities of air. In this countercurrent scheme, hot gases rise upward against the flow of solid coal. This configuration maximizes thermal efficiency, but generates large volumes of tars and reduces the rate of gasification. The Wellman system is air blown and works at atmospheric pressures; a stirring device facilitates the handling of both caking and non-caking coals. It is cooled by a water jacket that surrounds the reactor; process water is drawn from the cooling jacket into the reactor to supply hydrogen. Volume 10, Number 1. January 1976
35
Wellman-Galusha. Fourteen unit gasification system in Cuba; unit can use about 85 tons of coal per day Low Btu gas, containing 150-170 Btulscf, leaves the reac-. tor at 1000-llOO°F. The composition of the gas is 2.7% methane, 28.6% carbon monoxide, 15.0% hydrogen, 3.4% carbon dioxide and 50.3% nitrogen when gasifying bituminous coal. The Koppers-Totzek reactor, a suspension system, also takes an atmospheric approach, although this system is much larger than the Wellman. It handles all types of coal, dried and pulverized to a 200-mesh size. These particles along with pure oxygen and steam are fed into the gasification chamber where the conversion reactions occur almost simultaneously. These systems, which range in size from 450-850 tons per day of bituminous coal, require auxiliary support systems for feeding oxygen and steam. They are less self-contained than the Wellman units. The fuel gas leaves the Koppers-Totzek unit at 33003500'F. It is a medium Btu gas with a heat value of 290-300 Btulscf. It contains the following constituents: carbon monoxide, 55.9%: hydrogen, 35.4%; carbon dioxide, 7.2%; nitrogen, 1.1%; hydrogen sulfide, 0.3%: and other materials, 0.1%. Lurgi systems can use either air or oxygen along with steam as feeds to the coal reactor. Both the air- and oxygen-
fed units are modified fixed-bed-pressurized reactors. Operationally, air has been preferred for industrial applications while oxygen has been chosen when the reacted gas is to be methanated. Commonwealth Edison will use air-fed units at its Powerton, Illinois, combined-cycle station; Ei Paso Natural Gas will use oxygen-fed reactors at its Farmington operations. While Lurgi units traditionally run on non-caking coals, the experience in Westfield. Scotland, indicates that Illinois and Pennsylvania bituminous coals, which are moderately to highly caking, can be gasified successfully. All coals must be sized, and the fines must be removed. In the Lurgi system, coal is fed into a lock hopper at the top, and from there distributed into the vessel. While coal enters from the top, steam plus air or oxygen are fed through the bottom of the chamber. These reactors, which may be as large as 950 tons per day, gasify coal at 300-450 psig. The air-fed Lurgi units produce a gas containing 110-180 Btulscf. The gas contains 3 % methane, 11% carbon monoxide, 17% nitrogen, 11% carbon dioxide, 31% nitrogen, 26% moisture and 0.5% hydrogen sulfide. Fuel values from the oxygen-fed Lurgi reactors are in the 500 Btulscf range. Like Koppers-Totzek units, oxygen-based Lurgi reactors produce a synthesis gas devoid of nitrogen. Unlike the former system, however, the Lurgi produces a synthesis gas with 10% methane. System efficiencies
Lurgi. Long used by Sasol, Lid. of South Africa, process wi// be used in Arizona and Scotland
36 EnvironmentalScience 8 Technology
System efficiencies determine the amount of coal that will have to be mined to obtain the required quantities of energy to fuel electric power plants, manufacturing installations, and residential dwellings. Efficiency implies the amount of Btu's delivered to the customer in gas form expressed as a percentage of the incoming energy contained in the coal. Additionally, this calculation includes by-product energy exports and additional energy imports for gasifier operations. Within that framework, the systems were analyzed for the production of industrial gas; Koppers-Totzek and Lurgi units were also evaluated in terms of methane production. Low and medium Btu gas calculations, for all systems, were made by including sensible heat, tars, and volatiles in the coal gas energy: these efficiencies were also developed utilizing only the calorific content of the gas. Methanation schemes included only the calorific value of the gas, since synthesis gas must be cooled and cleaned before undergoing the shift reaction and methanation. The Wellman reactor operates at one of the highest efficiencies in the industry. According to Wallace Hamilton, senior consultant to McDowell-Wellman, when the sensible heat plus the tars and volatiles are employed by the gas user, a 92% efficiency can be achieved. R. W. Damon. vice president of Glen-Gery. confirms that their reactors achieve a 90% efficiency operating on anthracite coal. When gas pro-
duced by the Wellman unit is cooled and cleaned prior to combustion, the efficiency drops to 75%. Unlike the Wellman unit, the Koppers-Totzek reactor requires additional energy inputs. A ton of eastern coal, containing 25,392.000 Btu's is accompanied by 57.000 Btu's of sensible heat in the dried coal feed; additionally, the oxygen carries 57,240 Btu's and the steam brings 667.290 Btu's to the reactor. These added energy inputs help to account for the higher coal throughput of the unit, while they do not impede its overall efficiency seriously. The Koppers-Totzek reactor, operating in an industrial gas production mode, offers a higher heating value efficiencyranging from 85% when operated on Illinois coal to 90.3% when gasifying eastern bituminous coal. The efficiency, when operating on western coal, is 88.2%. The efficiency range is from 83-89% when the calorific value plus the sensible heat is calculated. but the energy contained in the water vapor element of the product gas is discarded. When only the calorific value plus the sensible heat gleaned in a recuperator (waste heat recovery system) is available for utilization, the efficiencies are as follows: eastern bituminous coal, 75.2%: Illinois coal, 74%; and western coal, 75.5%. These are the efficiencies of burning cooled, cleaned gas. Lurgi reactors, operating in an air-blown mode, offer a hot gas efficiency of 79.6% (exclusive of the energy contained in the gas pressure). The lower heating value, including some sensible heat regained through heat exchangers, is 70.2% according to B. J. Kristensen, senior process engineer for Rust Engineering. Operating the Lurgi air-fed reactor in connection with a combined-cycle-electricity-generating unit, however. capitalizes on the energy inherent in the gas pressure. J. Agosta and associates note that the volume of low Btu gas that will produce 493 MW from a conventional electricity plant will generate 534 MW from a combined-cycle operation: This represents an end-use efficiency increase of 14%; some of this increase comes from the electricity plant's ability to use the pressure, and the rest comes from the energy inherent in the gas pressure. Thus, apparent lower efficiencies of the industrial Lurgi gasifier are offset when the unit is linked to a power station that incorporates advanced power generation designs. Both Koppers-Totzek and Lurgi gasifiers can generate raw gas for synthesis into methane. In such a situation, the Lurgi unit also uses an oxygen feed system. In methanation schemes, the Koppers-Totzek unit offers a net energy effi-
ciency of 64.7% before the gas is pressurized for transmission. Lurgi efficiencies, including the export of by-products, are 70.1 %, according to Mr. Kristensen; that rate is based on the El Paso Natural Gas project. Much of the apparent advantage comes from the Lurgi unit's production of methane in the generation of synthesis gas, plus the pressure inherent in the fuel. These efficiency data can be utilized to determine the amount of coal required by each technology to produce IOl5 Btu's of energy useful to the US. economy. Based on the system efficiency calculations presented previously, a network of Wellman-Galusha reactors feeding hot gas to boilers would require 56,800,000 tons of high-grade western sub-bituminous coal containing 9,500 Btu's per pound. If these same reactors fed cold gas to the economy, they would consume 70,200,000 tons of coal. If methanation becomes the exclusive mode of operation, a Koppers-Totzek system would consume some 81,300.000 tons of coal, while a Lurgi-based network would require 75,100.000 tons. Economically, these ranges transfer to the energy feedstock costs of the systems. If eastern coal is used at a cost of $25/ton, the use of hot Wellman-Galusha gas gains a $457.500.000 advantage in the cost of coal when compared to a Lurgi-based methane production network (in terms of Droducinq IOi5 Btu's in gas form). If western coal is used at a cost of- $8lton, the- coal cost differential is some
$146,400,000. Environmentally, these efficiency ranges imply the number of acres temporarily disturbed in the mining operations required to support gasification systems. As an example, tabulations can be made by supporting the annual production of IOl5 Btu's in gas form from western coal deposits averaging 10 fl in thickness. Such seams are common in Arizona. Colorado and Utah. Using this example, and assuming that all of this energy could be generated by using Wellman-Galusha reactors producing hot gas. only about 4.500 acres would be disturbed annually by the associated coal mining activities. If, however, Koppers-Totzek-based methanation systems were used, approximately 6,500 acres annually would be temporarily disrupted. Underground mining, used to support the gasification network, would increase the acreage involved substantially. if 5-fl thick seams are assumed, the hot gas Wellman system will consume coal from 18,000 acres annually; the Koppers-Totzek methanation system will require 26.000 acres annually in the support of its gasification activities.
tactors t o consider in calculating sysrem eniciencies' Coal gas energy + by-product energy
____~
Feed cod enerqy + auxiliary system energy
Cross comparison of coal gasification systems Industrial gar Gasification system
Maximum size
Gas quality
efficiency0
Wellman.Galusha Kopperr-Totzek Lurgi
85 TPD 850 TPD 950 TPD
160 Btu/scf 300 Btu/scf 150 Btulscfh 500 Btu/scfc
92% 88.2%d
79.6%e
Potential use in methane production
No Yes Yes
Methanation efficiency
64.7% 70.1%
Volume 10. Number 1. January 1976 37
sociates found no substantial difference between the net water requirements of industrial and SNG gas systems when both are optimized around this parameter. Finally, a ranking of systems indicates that the KoppersTotzek reactor requires the least water and the Wellman-Galusha consumes the most water. The differences are relatively small. Thus, water consumption data available indicate a far different optimization than system efficiency. A summation
Gasifiers, Six units are used in the Modderfontein plant (Koppers-Totzek) to converi coal into ammonia These differences in environmental impact result from the mining methods involved. Western coals can be strip mined with 80% recovery rates. Upon completion of mining activities, the surface and land structure must be restored. Underground mines achieve 40-50% recovery rates, and they leave at least as much coal in the grobnd as they remove. in conventional underground mining, rooms eventually collapse after the coal has been extracted and this may cause subsidence on the surface. Subsidence is most prevalent if the coal seam is not particularly deep. Long-term environmental degradation, from either form of mining, can usually be avoided, but such protection necessarily implies an economic cost. Water consumption Data available on water consumption remain less precise than that for system efficiency. Water provides hydrogen for gasification reactions: it can also be used to moderate the reactions, and to carry away waste heat. Water consumption for hydrogen supply cannot be altered substantially. Water used as a reaction control agent can be modified to a limited extent. Cooling, by using water, can be adjusted substantially: it can vary from 15-100% of the cooling requirement depending on the availability of water. Air can be used as an alternative medium for waste heat removal. Finally. water requirements can be supplied by rivers or other traditional sources, from the varying quantities of moisture in the coal itself, and from the methanation reaction that produces water as a by-product. Thus, the number and complexity of variables in water consumption far exceed those in system efficiency calculations. Variations in the data available make precise quantification of water consumption trying at best. The U.S. Geological Survey estimates that, for the production of pipeline quality gas, water requirements will range from 37-150 gal per IO6 Btu's produced. Although Probstein and associates place the net water requirements at lower levels, their ranges are equally wide. Yet, certain conclusions remain. Power or industrial gas requires less input water than synthesized methane. The low and medium Btu gas systems operate at higher temperatures. Further, the hydrogen requirements of industrial gas remain lower than those of synthetic natural gas Water demands for methanation schemes are higher, principally because of the requirement for hydrogen and cooling. The shift reaction that precedes methanation (CO 8 H20 C02 8 H2) is exothermic, as is the methanation reaction itself. Since cooling can be accomplished by using either water or air, and since methanation produces water, Probstein and as-
-
38
Environmental Science & Technology
Both coal and water cost money. Mine rehabilitation and water purification require considerable effort and expenditure. Thus, the environmental issues of land use and water consumption contain certain strong economic implications. To maximize coal utilization, and minimize land disturbance, industrial systems offer a preferable approach. Within that category, relatively small energy requirements appear to be best met through application of the Wellman-Galusha reactor system if water is not scarce. Large users may opt for a Koppers-Totzek or Lurgi system. If electrical power generation is desired, the Lurgi enjoys an advantage: its pressure enhances the economics of combined-cycle plants. If methanation becomes the dominant mode because of an existing transportation network, the Lurgi units profit from their somewhat higher efficiencies: on the other hand, Koppers-Totzek units require less water in operation. Coal gasification does provide one route to the clean combustion of this fossil fuel. It is less efficient than direct coal combustion. Opting for coal conversion implies that one environmental choice has been made. Within the choice of coal gasification, certain reactors do provide limited optimization of either process efficiency or water consumption. Such performance maximization is application-specific and site-specific. The choice of gasification systems depends, in large measure, on the requirements and locations of the end-use markets. Such a selection, based on the environmental criteria of land and water consumption, can aid in determining the most economically viable unit for the project under consideration. Additional reading Bhutani. J.. et al., An Analysis of Constraints on Increased Coal Production. Mitre Corporation. January, 1975.And The Hudson Institute. Policy Analysis for Coal Development at a Wafime Urgency Level to Meet the Goals of Project Independence. The Office of Coal Research, R&D Report No. 87.February. 1974. Agosta. J., Illian. H.F., Lundberg. R. M.. Tranby. 0. G., Ahner. D. J.. and Sheldon, R. C.. "The Future of Low Btu Gas in Power Generation." April, 1973. National Academy of Sciences. The RehabilitationPotential of Western CoalLands. Ford Foundation Energy Project. 1973. Davis, G. H., and Wood, L. A,. "Water Demands for Expanding Energy Development." U.S. Geological Survey Circular 703. 1974,p. 12. Probstein, R. F., Goldstein. D. J.. Gold, H.. and Shen, J.. "Water Needs for Fuel-to-Fuel Conversion Processes." AlChE Annual Meeling. De=. 3. 1974.
David A. Tillman is vice president of Materials Associates, Inc. Washington, D.C., and contributing editor to Area Development magazine. Prior to his present position, he was editor of Vermont Business World. Mr. Tillman is writing a book on industrial and municipal waste recycling for McGraw-Hi// Book Co. Coordinated by LRE
