Research needs for coal gasification and coal liquefaction

Research needs for coal gasification and coal liquefaction

Energy Vol. 5.p~. 1091-1116 Pergamon Press Ltd., 1980. Printed m Great Britain RESEARCH NEEDS FOR COAL GASIFICATION AND COAL LIQUEFACTIONT S. S. PJZ...

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Energy Vol. 5.p~. 1091-1116 Pergamon Press Ltd., 1980. Printed m Great Britain

RESEARCH NEEDS FOR COAL GASIFICATION AND COAL LIQUEFACTIONT S. S.

PJZNNER,$

S. B. ALPERT,V. BENDANILLO,J. CLARDY, L. E. FURLONG, F. LEDER,L. LEES,E. REICHL,J. Ross, R. P. SIEG, A. M. SQUIRES,and J. THOMAS

IEnergy

Center and Department University of California,

of Applied Mechanics and Engineering Sciences, San Diego, La Jolla, CA 92093, U.S.A.

(Received 20 March

Abstract-We describe technologies orocesses.

1980)

essential features of developing coal-gasification and summarize the current development status and important

and coal-liquefaction R&D needs for these

1. INTRODUCTION The Fossil Energy Research Working Group (FERWG), at the request of J. M. Deutch (now Under Secretary of DOE), E. Frieman (now Director, Office of Energy Research) and G. Fumich, Jr. (now Assistant Secretary for Fossil Energy), has reviewed and evaluated DOE-funded coal-gasification and coal-liquefaction technologies. These studies were performed in order to provide an independent assessment of critical research areas that affect the long-term development of these important coal-conversion processes. The findings of FERWG have been published in two extensive d&cuments’s2 from which this paper has been abstracted. Members of FERWG performed extensive schedules of site visits to process-development units and facilities, as well as to university and DOE laboratories, in order to familiarize themselves with current and planned research programs. Site-visit reports and evaluations, with emphasis on identified process and fundamental research needs, were prepared by participating FERWG members after each site visit. FERWG members held numerous discussions with the Under Secretary of DOE, the Director of the Office of Energy Research, the Assistant Secretary for Fossil Energy, members of their staffs, DOE program managers, directors of laboratories and’ development engineers who are involved in coal-gasification and in coal-liquefaction research and development (R&D) in both industrial and governmental organizations, and unitThis paper is based on studies performed by the Fossil Energy Research Working Group (FERWG) of the Department of Energy dealing with coal gasification (under DOE Contract No. ER-78-C-01-6335, 1978-79, with the Mitre Corporation) and coal liquefaction (under DOE Contract No. DE-AC01 ER10007. 1979-80, with the University of California). The following members of FERWG participated in all of the studies: S. B. Alpert (Technical Director of Advanced Fuels, Advanced Fossil Power System, Electric Power Research Institute, P.O. Box 10412, Palo Alto, CA 94303), L. E. Furlong (Director, Coal Research Program, Exxon Research and Engineering Co., P.O. Box 4255, Baytown. TX 77520), S. S. Penner, Chairman (Director, Energy Center, B-010, University of California, San Diego, La Jolla, CA 92093), E. Reich1 (President, Conoco Coal Development Company, High Ridge Park, Stamford, CT 06904), J. Ross (Department of Chemistry, Stanford University, Stanford, CA 94305), R. P. Sieg (Manager, Synthetic Fuel Division, Chevron Research Company, P.O. Box 1627, Richmond, CA 94802), A. M. Squires (Department of Chemical Engineering, Virginia Polytechnic Institute and State University, Blacksburg, VA 24061), and J. Thomas (President, Chevron Research Company. P.O. Box 1627, Richmond, CA 94802); V. Bendanillo (Manager, Fossil Energy Projects, Gas Research Institute, 10 West 35th Street. Chicago, IL 60616) and L. Lees (Environmental Engineering, California Institute of Technology, 1201 East California Blvd., Pasadena, CA 91109) were members of FERWG dealing with coal gasification and J. Clardy (Department of Chemistry, Cornell University, Ithaca, NY 14853) and F. Leder (Director, Exploratory and New Ventures Research, Occidental Research Corporation, P.O. Box 19601, Irvine, CA 92713) were members of FERWG working on coal liquefaction. The advice of very many active workers in the fields of coal utilization, and especially of I. Wender, is gratefully acknowledged. Willard E. Fraize of the Mitre Corporation made essential contributions to the FERWG studies on coal gasification. 1091

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versity-based scientists and engineers who perform research related to coal-liquefaction studies. In addition, FERWG received written comments from experts on coal gasification and liquefaction.

2. COAL

GASIFICATION

Coal-gasification technologies and processes have been developed and commercialized for a long time. Although the proliferation of named and identified technologies is very large (a National Research Council Report3 identifies 37 individual “representative processes” among perhaps 180 gasification technologies), the number of generically different, aboveground gasifiers is closer to 7 (e.g. fixed-bed gasifiers that produce dry ash or slag; fluidized-bed gasifiers that produce dry or agglomerating ash; entrained-flow gasifiers that yield dry ash or slag during primary gasification; and molten-bath gasifiers). 2.1 Introduction The coal gasification industry has been well established for some time, and the large body of accumulated knowledge and experience must be taken into account, relearned if necessary, appreciated, and applied. Numerous differing gasification techniques are necessary to produce the desired variety of products, including low-, medium-, and highBtu gas, from the wide range of available coal feedstocks. The needs of the electric power industry for gasification products are different from those of the gas utilities and these, in turn, differ from the requirements for production of, for example, chemical feedstocks, industrial power, and steam generation. The steady increase in environmental regulations has brought about the need for gas cleanup processes. Coal gasification is a mature technology but it is not now economically competitive, and potentially attractive alternatives to the Lurgi gasifier have been beset by operational difficulties of every conceivable variety. There have been “surprises,” and, according to W. G. Schlinger (manager of the Texaco entrained, downflow coal-gasification process), the absence of “surprises” on scaling would itself be “surprising.” Coal-gasification technologies are very sophisticated. Proposals for technological implementation clearly lead understanding and mundane operational problems may reflect gaps in basic understanding. For example, clinker formation in pilot-scale gasifiers may perhaps be elucidated through research on (i) the mechanisms and rates of nucleation during gas-phase combustion: (ii) forces between tiny particles, agglomeration, and growth kinetics on collisions between particles; (iii) surface forces in nonuniform structures of carbon and hydrogen; (iv) surface physics: and (v) surface kinetics. Coal scientists have had little impact on the development programs in the past, partly because the real problems are “dirty”, are extraordinarily complex, and do not lend themselves to ready modeling or useful first-order descriptions. The U.S. Bureau of Mines Mineral Industry Survey of 1 January 1974 yielded a demonstrated coal reserve base of 437 x lo9 tons. This number must be multiplied by a fraction recoverable for use (usually taken to be 0.5) and also reduced somewhat to correct low-Btu coals to some standard (e.g. 25 x i06 Btu/ton). Thus, demonstrated recoverable coal reserves are about 200 x lo9 tons, worth trillions of 1979 dollars. The ultimately recoverable resource, according to P. Averitt (1967) may be as large as 3.2 x 10” tons (not including Alaskan resources). At reasonable costing, the value of these ultimately available resources may exceed $50 trillion (1978 dollars), of which perhaps one-third ($15-320 trillion) may well become attributable to coal gasification processing. General background information, thermodynamic analyses, and descriptive material on selected process configurations appear in textbooks.4*5 2.2 Applications of coal-gasification technologies There are three principal areas for application of coal-gasification products. The gasdistribution companies require high-Btu syngas (SNG) that may be freely intermingled

Coal gasification

and coal liquefaction

1093

with natural gas. Electric utilities and industrial users of gaseous fuel generally find low-Btu gas most cost effective. The chemical process industries prefer mixtures of carbon monoxide (CO) and hydrogen (H,), as contained in medium-Btu gas. The user-oriented presentations in this chapter describe the initial process-related R&D needs of the coal-gasification industries. 2.2.1 High-Bru gas for the gus industry. The main interest of the gas utilities in coal gasification is to produce high-Btu, pipeline-quality SNG to augment the available supplies of natural gas. Current cost projections (197678) for a 250 billion Btu per day (Btu/d) coal-gasification plant to produce SNG, regardless of the process selected, will require a capital outlay of well over $1 billion. This amount approaches the total worth of the Nation’s largest utilities. Thus, one such coal-gasification plant could roughly double the net worth of a large gas utility, while adding only a small amount (- 1@15%) to the utility’s gas supply. Because of the high capital requirements, coal-gasification plants are difficult to finance and non-technical problems, primarily financial and regulatory uncertainties, are generally the principal obstacles to coal-gasification processes. At present prices of alternative energy sources, technical breakthroughs are needed to make the financial, economic, and regulatory aspects of the coal-gasification technologies more attractive. The Lurgi process is commercially available for coal gasification to produce high-Btu gas, and all of the commercial plants currently proposed for SNG production in the United States will be using this technology. Thus, the Lurgi process serves as the baseline for measuring the economic potentials of technical improvements in coal gasification. Table 1 shows the cost breakdown of a commercial Lurgi plant using noncaking Table 1. Cost breakdown for a Lurgi gasification plant using noncaking Western coals. Source: Private communication between Western Coal Gasification Company (WESCO) and V. Bendanillo. GR!. ?“t

2.5 3.0 15.6 6.2 27.3

16.6 10.0 26.6 -

14.8 -

1.7 3.2 2.6 3.3 10.8

4.3 3.5 7.8 -_

1.0 3.5 2.7 1.0 4.5 -

100.0 -__-.

-

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Western coals as reported by WESCO. Reference to Table 1 leads to the following conclusions: (a) The gasification section accounts for only about 15% of the total investment; however, its construction impacts heavily on what processes or operations are needed before and after the gasifier. (b) Gas purification and upgrading represent a high-cost area (27.3%) for high-Btu gas plants. For coal-gasification plants for electric power generation, only gas purification is required. (c) The costs of steam and oxygen plants (26.6%) exceed those of the gasification section. Research directed toward improving high-cost areas through process simplification and the use of improved materials, equipment, and instrumentation should reduce costs and increase plant operability and reliability. 2.2.2 Low-B& gas for electric power systems. Clean gaseous fuel can be produced and used in electric power systems by either (a) combined-cycle turbogenerators, (b) fuel-cell systems, or (c) direct firing of the fuel gas in boilers. In any of these cases, electric-generating equipment is not simply added to a coalgasification plant. Coal-gasification plants must be highly integrated with the power equipment in order to be cost-competitive with other electricity-generating systems. An operating, combined-cycle generating plant based on coal has not yet been built and operated in the United States. The Steag Ltinen plant has operated in West Germany at a scale of 170 MWe. It uses Lurgi coal gasification to produce fuel gas, which is combusted in a pressurized boiler. The pressurized flue gas is then used to generate electricity in a power-recovery turbine. In the Liinen experience: (a) environmental requirements are not comparable to those in the United States; (b) the configuration of the plant yields relatively low overall system efficiency; (c) the cycle is not representative of equipment offered in the United States; (d) improvements to increase efficiency and make the system competitive with present electricity-generating systems using coal combustion and flue-gas cleaning are improbable. A. Gasifer characteristics for the power industry The objective of advanced electric systems is the integrated operation of coal gasifiers with combined-cycle electric systems. Utility experience with gas-turbine, combined-cycle systems, which use oil or gas, corresponds to about 10,000 MWe of planned and installed capacity. To take advantage of this background, coal gasifiers should meet desirable criteria (see Table 2 of Ref. 1). No single gasifier technology can satisfy all of these criteria; however, a number of the second-generation coal gasifiers (now operating at scales in excess of 100 tons/d) incorporate satisfactory compromises that should be applied to electric power generation. Coal-gasification plants for electric power must emphasize factors relating to the economic competitiveness of presently available highcapacity generating systems that produce power in a cost-effective manner and meet today’s environmental standards. B. Incentives for combined-cycle generation In Table 2, we summarize and compare the estimated performance characteristics of coal-gasification and pulverized-coal powerplants. Powerplants using coal gasification are seen to be competitive; they provide for better resource utilization of coal and water and they markedly reduce emissions. The potential for improvements is large and involves advanced, high-reliability gas turbines, as well as advances in engineering and improved cycle configurations; the influence of the gasification process on the potential for further improvement is small. Of high priority for the power industry is integration of component units from separate technologies into an optimal system to assure that coal gasification is used to generate electricity in a reliable and economically competitive manner. 2.2.3 Medium-Btu gas (275425 Btu/SCF) as an industrial fuel and petrochemical feedstock. Gasification of coal to produce a mixture of hydrogen (H,), carbon monoxide (CO), and methane (CH,), termed medium- (or intermediate-)

Btu gas, is a particularly

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Table 2. Comparison of coal-gasification and pulverized-coal power plants (plant capacity = 1000 MWe); costs in mid-1976 dollars. Source: The Electric Power Research Institute. Palo Alto, California. TEXACO

I

coal

use,

tons/d

limestone use,

I tons/d

I

PULVERIZED

TEXACO

8,234

7,155

670-820

600-850

COAL

9,743

/

I

-O-

sulfur oxides Pb/MMBtu

produced,

make-up water GPM/l,OOO Mw

needed,

total

cost,

capital

8,616

BGC SLAGGER

are given

0.8

8,000 $/kW

I

770-940

I

800-930

I I

estimated

operating

costs, 36-41

mills/kWh

i

I

I

I

32-36

29-36 I

!

40-44

I

economical and environmentally sound route to coal-derived energy supplies. In addition to meeting most industrial fuel specifications, medium-Btu gas is also a potential gaseous feedstock for the petrochemical industry. Evaluations of medium-Btu gas production show that such gas can be produced with a higher thermal efficiency (i.e. a higher fuel-energy content of the gas relative to that of the coal) than syngas (SNG) (65-75% compared with 6&70%), generally at lower cost per unit of fuel energy. Low-Btu gas shows similar thermal and economic advantages over SNG but has more limited use as fuel and feedstock because of the large amounts of nitrogen diluent present. Unlike low-Btu gas, medium-Btu gas is generally considered to be economically transportable to industrial users and smaller utility generating stations within lO(r150 miles of a centralized gasification plant. Thus, the economy of large-scale plants is passed through to smaller end users. However, these advantages must be balanced against the high cost of constructing separate distribution networks. Medium-Btu gas is an excellent fuel for boilers and process heaters, equaling the benefits of oil or natural gas. It can be used in utility plants as a substitute for oil or natural gas. Its availability may permit continued industrial expansion, using boilers designed for gas that are available at a fraction of the cost of coal-fired units with scrubbers. Such a fuel gas is useful in process heaters. The investments for adapting existing oil- or gas-fired facilities so that they can burn medium-Btu gas are modest compared with retrofitting for direct coal or low-Btu gas combustion. A mixture of CH,, HZ, and CO meets a variety of industrial and utility needs. Hydrogen and CO feedstocks may be produced for the following purposes: manufacture of ammonia and methanol, hydrotreating and desulfurization of refinery streams, and reduction of ores to basic metals. The Hz-CO mixtures may be used by electric utilities as fuels in new, combined-cycle turbines and as feed in fuel cells for peaking and loaddistribution purposes; many existing oil- and gas-fired facilities could be retrofitted with relatively minor modifications. Essentially all pollutants can be removed from medium-Btu gas at a large centralized plant. This procedure not only reduces the total environmental impact of the industrial use of coal, but also allows dispersal of emission sources because the gasification plant may be located in remote areas.

I

S. S. PENNER

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et al.

Medium-Btu gasification is a basic building block and more attractive for direct use for a number of industrial and utility needs than most alternatives, but it is not currently economically competitive with oil and natural gas. Technological developments and demonstrations have not yet sufficiently reduced the high costs or economic and reliability risks to produce private-sector commercialization. 2.3 The principal coal-gasification systems and process-research recommendations The general principles involved in coal gasification are illustrated in Fig. 1. Three principal types of coal-gasification systems are discussed in this section: fixedbed (gravitating-bed) gasifiers, fluidized-bed gasifiers, and entrained-flow gasifiers. 2.3.1 Fixed-bed gasijcation. During the 1930s and 1940s some 11,000 individual gasifiers operated in the United States. Almost without exception, these were fixed-bed reactors. The first high-pressure reactors were simultaneously introduced into commercial practice in Germany by Lurgi. After the war, gasification of coal in the United States was discontinued. but the operating range of fixed-bed (gasification) systems was further extended by vigorous increase in the use of these reactors in the steel industry. Most of the older fixed-bed reactors were 6-8 ft in diameter and consumed 2&80 tons of coal per day. The use of high pressures raised this to 350-1000 tons per day. Modern blast furnaces consume more than 5000 tons of coke per day at slightly elevated pressure. Compared to fixed-bed systems, the impact of other gas/solid systems (reactor types) has been minor. The great advantages of the fixed-bed systems are extensive practical experience and inherent efficiency, because they are effectively countercurrent heat exchangers. The solid gasification fuel is preheated to the maximum temperature by heat recovery from the gaseous products, which generally leave at temperatures between 150” and 425°C. At higher pressure, the system also allows utilization of the heat released in the lower temperature zone by exothermic reactions of tar and char with hydrogen to form methane. Finally, countercurrency also ensures complete consumption of the coal substance and removal of ash, with only minimal unused carbon. These advantages are offset by important drawbacks, all of which relate to the high demand the fixed-bed gasifier places on the feed in terms of size consistency and free bulk flow through the reactor (freedom from sticking or hanging). Finally, these reactors favor the use of coals with high reactivity and high ash-fusion temperatures (these requirements must also be met in fluid-bed units).

(H$/(COD3

L

Catolytlc methonatlon 3t9co =

product gas (CH+ etc.) t

Cti4+H20

Kzo

1

u$1/(co)c3 CH H co:b$:

-

%O

catalytic sh,,: cOn”erSlO”

CW??S organic sulfur compounds

CO + H20= CO,+ tie

I

teed coal

or ligniig

coD, ~lOO-I,soO°F C+,MFCH,,AH
0

- CH4+H2+C,AM0

CO?t$,AH>O ~~,+.&KO I steam

Fig. I. General

devolatilizaiion

hydrogaslf~cal~on sleun-carbon wter-gas

or

reacliw

meihonation

reaction

reaction shdt

reaction

t heat

process scheme for producing methane from coal; endothermic spond to AH > 0 and exothermic reactions to AH < 0.

reactions

corre-

Coal gasification and coal liquefaction

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The identified characteristics suggest directions for improved fixed-bed systems. Current activities in these areas are substantial, and most are taking place outside the United States. The primary developments are being implemented by the South Africa Coal, Oil, and Gas Corporation (SASOL) and the British Gas Corporation (BGC). A. Increased reactor sizes The principal problem with larger reactors relates to the ability to manage the countercurrent flows of solids and gases at larger reactor diameters without channeling. Past and present approaches to this problem have been empirical. A useful model is the 5&55 ft dia. blast furnace, for which efficient operation was accomplished by establishing a centrally located “deadman” so that the reaction zone is actually an annulus, with depth controlled by bed penetration of the air injected through the tuyeres. However, blast furnaces are generally operated at pressures close to atmospheric. When the gasifier is operated at elevated pressures (Lurgi units are now designed for 450 psig), the use of a central deadman may set a practical limit to reactor size. A 16.5-ft internal diameter unit by Lurgi has a capacity exceeding 1000 tons per day. The development of the blast furnace has led to a useful, empirical solution for the problem of scaling a Lurgi-type reactor. Empirical searches for acceptable experimental configurations may be aided by better understanding of scaling and modeling and by better understanding of the fluid mechanics of multi-phase flow processes under gasification conditions. To be successful, improved diagnostic systems must be developed and used in conjunction with models and empirical scaling. B. Operations at increased pressures Current R&D for syngas (SNG) production is aimed at maximum formation of methane by direct hydrogenation of volatiles and char. These reactions are favored by higher pressure. A Lurgi reactor operating at 1OOOpsigis under development. Apart from enhanced methanation, the higher pressure will result in higher specific throughput because limiting the upflow velocity of the gas at operating conditions will yield a higher mass flow. The limiting gas flow is a function of pressure drop (hanging of the burden must be avoided) and of the fines in the coal feed that are blown out of the reactor at excessive gas velocity. Quantitative understanding of how elevated pressures enhance methane production requires detailed knowledge of coal chemistry. The rates of methane formation are determined by a complex interplay of pyrolysis and gas-phase processes. Basic research on coal chemistry, including efficient characterization of coal feeds and improved quantification of the kinetic processes leading to methane production and removal, may ultimately help designers to construct improved high-pressure, fixed-bed reactors. C. The use of increased reactor temperature and slagging The fixed-bed reactor, with a mechanical grate for solid (dry) ash removal, requires special provisions to protect the grate, including additions of steam to prevent excessive temperatures, ash clinkering, and ash fusion. This steam cools the reactor and thus lowers the rate of gasification, which is a drawback for unreactive coals (including most U.S. coals from regions East of the Mississippi). It is therefore tempting to apply slagging, which requires the raising of bottom temperatures so that the coal reactivity is less important. The use of excess, nonreacting steam is reduced, there is no need for a mechanical grate, and the process approaches the operation of a blast furnace. The use of slagging, fixed-bed gasifiers is well established and recent work has made it possible to apply the concept to high-pressure systems. The solution to the difficult problem of removing molten (1480°C) slag from a highpressure reactor has been demonstrated by the British Gas Corporation at a large pilot plant originally designed by Lurgi. The use of a slagging gasifier leads to a specific throughput (pounds of coal handled per square foot) that is about three times larger than that obtained in the “dry” bottom system, even with unreactive coals. Fundamental work, which may prove to be useful in the design and control of slagging reactors, relates mostly to materials problems and possibly also to catalytic processes involving coals.

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D. Feed preparation and size consist Fixed-bed reactors require coarse feed. However, the limiting size is a strong function of operating pressure. A Lurgi reactor will handle coals down to the l/%in. size. Fines are carried out by the gases leaving the stack. Excessive fines result in higher pressure drops and “hanging” of the solid bed. The use of modern mining equipment often leads to large amounts of fines in the raw coal. Depending on local circumstances, the fines can be sold to the extraneous fuel market. A partial solution for the more complex SNG plants may involve the use of fine coal sizes in the associated steam boiler. Even though fines disposal is not likely to limit the application of fixed-bed gasification, there is merit in the development of a low-cost method of agglomeration. The fixed-bed gasifier does not represent a difficult target (compared, for example, to the blast furnace) in terms of size or strength. Briquetting, pelletizing, coking on traveling grates, and extrusion are available for the control and use of fines. A special feature of slagging, fixed-bed systems is the opportunity to inject the fines into the tuyeres; this practice is used commercially in blast furnaces. Although the use of fines disturbs the normal countercurrent flow and leads to reduced yields of methane from the fine coal fraction, these are minor drawbacks. A particular problem in feed preparation arises when fixed-bed gasification is applied to the residue left from coal liquefaction. These residues appear as slurries of uncoverted coal and ash in nondistillable, heavy liquids (usually at about 315°C as vacuum-tower bottom products). Thus, it may be necessary to recover solvent and other liquids from this stream, especially when the total amount is large (40-50x of the feed coal). This recovery requires thermal cracking or carbonizing. If either process takes place in a fluid-bed reactor, the resulting dry solid will be too fine for use in a fixed-bed gasifier, but pilot-scale tests have shown that this residue stream can be carbonized and the solids are obtained in coarse size, as desired, by hot pelletizing at the 480°C level. E. Feed preparation and caking The free flow of solids down a gasifier shaft can be easily disturbed by any tendency of the solid to “stick” or cake, which is characteristic of most Eastern U.S. coals. The tendency is further augmented if the partial pressure of hydrogen is increased or if the temperature, at which coal undergoes thermal cracking or caking, is increased (e.g. from 340” to 540°C). Two basic approaches to cope with this problem are under study: (a) treatment ahead of the gasifier and (b) mechanical agitation inside the gasifier. The former may involve preoxidation, but this method is not very effective for coarse coal sizes. Preoxidation will yield a satisfactory solid, but it removes some of the most desirable volatile components of the coal. These contribute much of the desired direct methane. A mechanical agitator (or plough) has been successfully demonstrated at the Morgantown Energy Technology Center (METC) of the Department of Energy (DOE) and appears to offer an acceptable solution. The agitator is effective for the most highly caking coals (e.g. Pittsburgh Seam Coal) and at the high throughputs obtained with slagging bottom operation. F. Mechanical improvements Coarse coal (up to 2-in. in diameter) is routinely fed against high pressure by the use of lockhoppers. For large vessels and high throughput, the capacity of existing hardware is severely taxed. Therefore, efforts are underway to develop novel pressurizing systems that will operate continuously and not require large volumes of lockhopper gas. 2.3.2 Fluidized-bed gasijcation. Current opinion on fluidized-bed gasification of coal is colored by the prevailing negative impression of the Winkler system and by other problems encountered during the past 30 yr. Experience with complicated systems that featured too many novelties has often hidden the potential of the fluidized-bed approach and has provided little information of fundamental value. Several fluidized-bed technologies for gasification of coals or chars with air or mixtures of air or oxygen with steam exist. The advantages claimed for fluidized-bed prac-

Coal gasification and coal liquefaction

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tices include flexibility and close control of process conditions; flexibility concerning the fuel that can be processed, including the level of mineral matter in the fuel and the range of particle sizes used; the ability, shared with the entrained-flow gasifier, to provide a raw product largely free of tar species; potential for operating at large coal throughputs; inherent safety because of the large inventory of carbon (a feature shared with gravitating-bed designs) against upsets in operation arising from momentary excursions in the flow of a feed stream. Suspension (entrained-flow) gasifiers require finely ground coal, while gravitating-bed units usually need coarse coals free of fines. Fluidized-bed designs can be provided both for coarse coals containing fines and also for finely ground coals. Pulverized-coal boilers occasionally blow up (e.g. after momentary interruption of the flow of air). Suspension gasifiers operate under similar conditions of risk and therefore require elaborate safety controls. A disadvantage of fluidized-bed gasification is that a purge to extract ash from a bed of essentially uniform composition will usually lead to an appreciable loss of carbon with the ash. A simple, single-zone, fluidized-bed gasifier will only partially gasify the coal. Research on selective withdrawal of ash matter is currently underway. Many of the perceived disadvantages of fluidized-bed gasification are associated with efforts to convert finely ground coal that was pretreated by light oxidation to reduce agglomerating tendencies and was gasified at low fluidizing-gas velocities (generally co.25 m/s). Temperatures were below 1000°C. Micron-size carbon fines that are difficult to deal with appear in these systems beyond a critical carbon-conversion level. Pretreated bituminous coals swell to form light, vesicular particles that lead to a low fluidized-bed density. Beds blown with steam and oxygen have a tendency to form clinkers in the vicinity of oxygen-inlet ports, A carbon particle undergoing gasification is microporous, and gasification reactions occur throughout its volume. When a particle has lost a critical amount of carbon, it shatters into many bits, thus creating small fines. Losses in carbon fines usually amount to more than 20% of the fuel value of the starting coal. To prevent incomplete gasification of carbon. a carbon burnup zone is combined with a bed in which carbon conversion is limited to a level below that at which carbon fines appear. In successful tests, a separate carbon burnup zone was used to consume the carbon fines, The tendency to form clinkers is pronounced for particles formed in pretreated bituminous coals, Heat is dispersed in a fluidized bed through large-scale movement of the solid. Solids of lower density and lower heat capacity carry less heat. To minimize the formation of clinkers, fluidization techniques that do not require pretreatment to reduce agglomerating tendencies are used. These involve gas velocities far greater than 0.25 m/s. A. Caking coals At high fluidizing-gas velocities (more than 3-5 m/s), untreated bituminous coals may be fed to the fluidization medium. A number of approaches has been used. (a) Workers at Westinghouse have successfully operated a “draft tube,” developed earlier by Conoco, for feeding caking coals. The velocity in the draft tube is probably several m/s. The tube is supplied with a large flow of hot solids at the bottom from a surrounding bed fluidized at a low velocity. Raw coal is introduced at a central point into the rapid upward flow of hot solids through the tube. (b) The fast fludized bed is essentially a draft tube without the surrounding lowvelocity fluidized bed. The fast bed may be fed with solids at the bottom from a standpipe and has a higher gas-treating capacity than a low-velocity bed fitted with a draft tube. A coke byproduct is discharged as coarse particles when the fast bed is superposed above a bubbling bed. When coals of a great size range are fed to the fast bed zone, the larger sizes fall at once into the lower bubbling bed. (c) Another option is a char-bead-accreting bed in which char beads are fed along with finely divided bituminous coal. This system was operated successfully on a small scale with a bed that was a few inches in diameter. By-product coke appears in the form of beads (2-12 mm in diameter).

1100

S. S. PENNERrt (11.

Option (c) shows that a high-velocity fluidized bed may operate with some sticky matter in the bed. The tiny coal particles melt and stick to the surface of a char bead. Fludization proceeds if the fluidized-gas velocity exceeds a critical limit. The sticky coal dries in a few tenths of a second. The beads are dense and relatively non-porous. In options (b) and (c), the steam-carbon reaction is ineffective unless the temperatures are well above 1000°C. It is generally preferable to operate the unit as a coal devolatilizer. The temperature should be high enough to prevent tar formation in the product gas. B. Withdrawal of ash A problem with air- or oxygen-blown lluidized-bed gasifiers is formation of clinkers near the inlet of the oxidizing gas. Sticking of ash in coal occurs at low temperatures. A gas velocity of at least 0.6 m/s was needed to fluidize a bottom ash ( - 30 to + 40 mesh) at 84O”C, although the minimum fluidization velocity without sticking is less than 0.1 m/s. At higher temperatures, higher velocities were needed (1.2 m/s were required at 930°C). Clinkering near oxygen inlets for fluidized-bed gasifiers operating below 0.25 m/s is not surprising. The stickiness of ash may rule out fluidized-bed gasification using pretreatment of a bituminous coal to destroy caking tendencies, because this treatment produces a weak, fluffy char that is impossible to fluidize at a high velocity. Three approaches to handling ash agglomeration in fluidized-bed zones, operating at high velocity, have been demonstrated at various scales. (a) Coal may be gasified with air at lOOO_1400°C and at fluidizing-gas velocities of about 15 m/s. This gasification is performed in a commercial boiler, the Ignifluid. Ash agglomerates with diameters of several cm form in the bed and remain freely fluidized until they are transferred by eddy diffusion to an ash collection point. In the Ignifluid, this is a pad of sticky clinker, formed on a traveling grate that supplies fluidizing air to the coke bed. (b) Coal can be burned in a fluidized bed of roughly spherical, dense ash beads at temperatures above about 1100°C. The beads grow through capture and accretion of ash. The fluidizing gas must be maintained above a critical velocity to prevent defluidization of the bed. This technique has been proposed for use in a carbon burnup step. (c) A jet zone created by air- or oxygen-steam mixtures at the bottom of a fluidized bed of coke creates a region of high temperature and high gas velocity where ash forms and grows. In the Westinghouse gasifier, ash agglomerates and escapes from the hightemperature region via a gravitating bed cooled with recycle gas. Useful basic studies of ash agglomeration for U.S. coals could be conducted in a small Ignifluid boiler. Molten coal has a high surface tension (hundreds of dynes per cm) and does not wet carbon. The mineral matter in char heated above about 1200°C is exuded from the interior and forms tiny spherules on the surface of the particle. As the particle is consumed, the surface ash accumulations grow to several hundred pm in diameter. Eventually, either the accumulation breaks off or all the carbon is consumed. The ash agglomerate floats freely in the fluidized bed and grows by capture of smaller particles. In the Ignifluid bed, ash agglomerates comprise about 20% by weight. C. Research problems relating to coal gasification with air- or oxygen-steam mi.utures Research is needed on scaling the jet zone in fluidized beds to larger sizes, Mechanical arrangements, other than a rising grate, are needed to provide a pad of sticky clinker for capturing ash agglomerates from a high-velocity gasification bed. Carbon has been utilized, with better than 90% efficiency, in the Ignifluid for coals with ash contents of up to about 20%. Carbon utilization decreases with coals with higher mineral contents. The Ignifluid typically processes coal at 0.5 cm diameter. At high fluidizing-gas velocities, the carryover may amount to about one-half of the coal feed. The carryover is coarse (particle sizes are roughly 10 times larger than those of power station fly ash from pulverized-coal combustion). The carryover is reinjected via a high-velocity steam lance directed toward the deep end of the Ignifluid bed. The reinjected carbon dust remains in the Ignifluid bed for at least several minutes. The high temperatures and presence of oxygen in the bed may well limit the lifetime of a carbon

Coal gasification and coal liquefaction

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particle to a few round trips through the dust-collection and reinjection equipment. Some of the dust may be burned in the boiler zone of the Ignifluid, where secondary air is injected to burn the fuel gas produced in the fluidized bed. Research is needed to define the life history of fine carbon particles. These studies may allow us to construct an efficient single-zone gasifier. Carbon burnup zones should be studied. Workers at Conoco have proposed the use of an airblown carbon burnup cell at high pressure to handle char from an air-fluidized bed producing low-Btu gas at high pressure. Off-gases from the carbon burnup cell then enter the second bed along with air and, probably, steam. An airblown carbon burnup cell at high pressure could be a valuable tool in coal gasification. It might take the form of an ash-bead-accreting fluidized bed or it might operate at a lower temperature with the discharge of dry ash. Another possibility is the slagging combustor developed for operation at elevated pressure by the National Coal Board’s laboratory at Leatherhead, England, on behalf of the COGAS group. D. Equipment for &sh hydrogenation High-velocity fluidized beds may be suitable for flash hydrogenation. Both the fast fluidized bed and the coke-accreting bed should be considered. Because reaction times are short, throughputs per unit volume must be large. Only the vapor product should be quenched, leaving the solid residue hot for further reaction. Heat from the quench zone should be recovered so that fresh hydrogen is heated. E. Basic engineering studies ofjiuidized beds Several unit operations have been lumped together under the term fluidization. Research on applications of these unit operations to coals will be informative. The basic research will not be cheap, because meaningful fluidization experiments must be performed on a large scale. Recent commercial developments, as well as scientific study of models at atmospheric conditions, have indicated advantages for fluidization at high gas velocities. Processing capacities are greater and gas-to-solid contacting efficiencies are improved. Gas flow in bubbling fluidized beds is subject to a high degree of backmixing. This backmixing declines sharply at velocities that produce turbulent fluidization and vanishes almost completely in fast fluidization (i.e. in a recirculating fluidized bed). There has been little scientific study of fluidized beds on a meaningful scale and at velocities above the bubbling regime for elevated pressures. Such work is costly but necessary because pressure effects in fluidization are significant. Useful data may be obtained from large models working at atmospheric temperatures. The studies should first focus on gas- and solid-mixing characteristics of the beds and may later include studies of low-temperature chemical reactions. 2.3.3 Entrained-jaw gasification. Entrained-flow gasification has been an established practice outside the United States since 1950. Commercial plants in Europe and Asia have operated on a variety of high-ash coals to produce synthesis gas (hydrogen and carbon monoxide) for industrial chemical applications, including the manufacture of ammonia and methanol. A. Adoantages The advantages of entrained gasification result from rapid mixing and contacting of coal and oxidizing gas and include relative simplicity of the gasifier concept, high potential rates of converting coal, products free of tars, the ability to utilize essentially all of the carbon in the coal, and flexibility of entrained-flow systems to handle a large variety of caking and noncaking coals. Entrained-flow gasifiers are devices in which pulverized coal, oxygen (or air), and perhaps steam react at high temperatures and high velocities. The reactants are introduced into the gasifier through burners or nozzles. Flame temperatures at the burner

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discharges are in the range of 1370”-1925°C and melt all (or a substantial portion of) the ash in the coal. Determination of the preferred temperature range to achieve high carbon conversion in an entrained-flow gasifier is a complex process based on empirical testing. The temperature must be sufficiently high to melt the ash. This temperature depends crucially on the chemical composition of ash in the coal and on its behavior in the reducing atmosphere of the gasifier. The molten ash is partly carried out of the gasifier and may be deposited, as slag, on cooler surfaces. The molten ash is corrosive and will attack metal surfaces. In some gasifiers, the molten ash is removed as a slag at the bottom of the gasifier. The molten ash has a low carbon content after quenching or cooling. Carbon losses in entrained-flow gasifiers are characteristically low ; carbon-conversion levels generally fall between 90 and 100%. Because of the high temperatures reached in entrained-flow gasifiers, the principal gaseous products leaving the gasifier are hydrogen, carbon dioxide, nitrogen (if air is used), and unreacted steam. Most of the sulfur in the coal is in the form of hydrogen sulfide (H,S) with lesser quantities appearing as COS and CS2. Because of the high temperatures reached in entrained systems, little if any methane is produced and a high CO/H, ratio is obtained. Entrained-flow gasifiers have not been considered to be well suited for the production of SNG but they are preferred for the production of synthesis gas, which can be converted to industrial chemicals or hydrogen. Entrained gasifiers are easily and rapidly started up and shut down. However, the very low carbon holdup in the reactor provides a hazard if coal feed is interrupted. Entrained-flow gasification of coal is usually carried out in refractory-lined vessels. These refractories have been developed for use in commercially available gasifiers that operate at atmospheric pressure. Reliable service life is required for gasifiers operating at elevated pressure, and this has not yet been achieved. Problems in the operation of entrained-flow gasification are associated with the high temperatures reached during partial combustion of coal. The high temperatures may lead to severe material attack while the oxidant requirements are relatively high. The high capacity of the entrained-flow gasifiers also requires special attention because of erosive action of flowing, pulverized coal in nozzles, feeding systems, valves, and piping. Entrained-gasification products leave the primary, oxidizing reaction zone at relatively high temperatures. The recovery of the sensible heat in heat-recovery equipment has been accomplished (or alternatively disregarded if coal was low in cost) at atmospheric pressure. The thermal and economic penalties paid in losing sensible heat are generally undesirable. Development of waste-heat boilers and heat exchangers for service at elevated pressure is of high priority. This problem is receiving attention in several programs designed to utilize the sensible heat in the product gases in the form of high-pressure steam. Several techniques are employed to convey the pulverized coal to the gasification device. Concentrated water-coal slurries (up to 70% coal in water) are used. These mixtures are pumped into gasifiers operating at elevated pressures. The water is evaporated in the gasifier; heat is required for evaporation. Thus, water slurries (which represent a relatively reliable way to feed coal to the system) introduce thermal penalties. For coals containing large amounts of water as mined (lignites and some Western subbituminous coals), this thermal penalty may represent a major economic and technical drawback. Conventional equipment is available to feed the pulverized coal to atmosphericpressure, entrained-flow gasifiers. Such feeding systems have been established and operated reliably in commercial plants. During recent years, considerable equipment has been sold for entrained-flow gasifiers. Since the 1950s about 50 Koppers-Totzek gasifiers have been installed in foreign countries, usually to process high-ash, low-cost coals. This equipment uses oxygen and operates at atmospheric pressure. A wealth of practical engineering experience is available from these plants. Unfortunately, no such units have been installed in the United States. Operation of these units in the United States would provide readily accessible benchmarks for improvements.

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B. Increased-pressure operations Currently funded federal and industrial R&D programs are directed at developing improved entrained-flow gasification systems. The high-pressure, pilot-plant programs at the Texaco Oil Co. and at Shell-Koppers, Inc., handle about 150 tons of coal per day. The experience gained will serve as the basis for scale-up to demonstration and commercial scales. The Federal Republic of Germany has supported the design, construction, and operation of a 150 ton-per-day Texaco, entrained-flow, coal-gasification plant at Ruhrchemie/ Essen. The Texaco entrained-flow gasifier was developed on the basis of extensive experience the company had gained in marketing systems for the partial oxidation of petroleum feedstock. The Texaco units have been installed in more than 70 plants worldwide to convert petroleum feedstock to synthesis gas and hydrogen. Two Texaco plants, each of about 1.50tons per day capacity, are under construction or in startup in the United States, It was recently announced that a 1000 ton-per-day Texaco gasification plant will be used to generate fuel gas for power generation (in a combined-cycle system) for the Southern California Edison Company. The DOE is currently considering the design of a Texaco-based demonstration plant to gasify coal for the production of ammonia. The Shell Oil Co., in cooperation with Krupp-Koppers, has successfully operated a 150 ton-per-day unit at a Harburg, F.R.G., refinery. A dry-feed system is featured in this gasification process. The reliability of these systems for operations at 20-30atm represents an opportunity for improving the efficiency of gasifiers for fuel-gas and synthesis-gas generation. DOE has been supporting work on several dry-coal feeders for high-pressure operation. Texaco has a pilot plant at Montebello, California, under construction for operation at 80atm. C. Staged systems

Staged systems involve an arrangement of equipment to take advantage of the sensible heat in the combustion zone to carry out pyrolysis reactions on coals mixed with hot gaseous combustion products. The Combustion Engineering Co. in Connecticut operates a staged, airblown, entrained-flow gasification system capable of handling 5 tons of bituminous coal per hour to produce fuel gas. The system operates at atmospheric pressure. Several operating runs have been carried out in this program. The BiGas process is a staged, entrained-flow gasifier capable of converting 5 tons of coal per hour using oxygen at a plant in Pennsylvania. Staged, entrained-flow gasification is an important topic of process research and development for both atmosphericand high-pressure operations. The advantages over single-stage systems remain to be proven in pilot-plant work currently in progress. Claimed advantages for staged systems include higher thermal efficiencies than are achieved in single-stage systems and cost advantages for producing fuel gas from coals. Advanced, entrained-flow concepts that involve mechanical and process improvements are under investigation by workers at the Bell Aerospace Corporation and at Brigham Young University (Eyring Research Institute). Rocketdyne is investigating a coal-hydrogen entrained system. D. Instrumentation To provide plant operators with required data, instruments with improved reliability and sensitivity are required. Direct temperature measurements, using reliable diagnostic techniques for temperatures in the 1370”-1925°C range under gasifier environments, need to be developed. Process control and safety depend on rapid sensing of failures of the flow of coal to the gasifier and variations in oxidant supplies. Online sensing of refractory-lining integrity will be useful. Pilot-plant equipment will have to be operated to determine required improvements in instrumentation. Pilot-plant operations should be surveyed and summarized periodically to provide guidance for fundamental work in this critical area.

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E. Refractories The development of improved refractories and test programs on pilot-plant gasifiers should pay off in improvements and longer service life when entrained-flow gasification is applied commercially in the United States. F. Mechanical improvements Entrained-gasification processes will probably become commercially applied in a variety of ways during the mid-1980s. Improvements in the handling of pulverized coal by feeder systems against a pressure of 100 atm require attention. Duplication of current efforts on the development of feeding systems with limited applications should be avoided. Other mechanical components worthy of attention involve the integration of reliable steam-raising equipment suitable for “dirty” gas service and pressure letdown systems to handle cooled, slagged ash. Pressure letdown valves for handling gases containing particulates and corrosive components also need attention. Quick-response instrumentation to ensure the sensing of performance changes when the gasifier follows demand changes is a priority item for utility applications. G. interfacing with power-generation equipment and industrial end use Interfacing the products of entrained-flow gasifiers with power-generation equipment represents a series of special problems that has received little attention. Optimization procedures for using clean fuel gas (produced at pressures ranging from 1 to about 100 atm) and predictions of compositions for low- and high-pressure steam-product streams are inadequately understood. Each gasifier system presents its own interface problems, which may be further complicated by the particular applications involved. Retrofits to existing boilers and to combined-cycle generating equipment have been shown to lead to difficulties. In new electricity generating plants, specially designed gas-fired boilers or combustion cans may be required to handle gaseous fuels with particular combustion characteristics. Complications in the overall systems operation result from the requirement for coalgasification systems to follow changes in the electric or plant load. Instrumentation and control strategies for systems aimed at the power or process industries are needed. 2.3.4 Other gasijication systems. The Department of Energy has been supporting other gasifiers involving the use of molten iron and alkali salts as contacting media. Work is also being done on gasifiers with very short residence times using fluid-dynamic controls. The technology for in situ gasification is being studied and developed. These devices and techniques have special R&D requirements, as well as special needs for supporting research. The required basic studies generally constitute integral components of the small-scale systems developments that are currently in progress. We regard innovative work on these nonconventional techniques as worthwhile and important. 2.4 Ash disposal Every use of coal inevitably leads to the need for disposal of ash. In the United States, almost all coal is used in direct combustion, with a large percentage used in central powerplants with pulverized-coal burners. The total amount of ash created annually is in excess of 50 million tons. Most of this ash is disposed of in landfills. In some countries, notably France and the U.S.S.R., the use of fly ash as an additive to or replacement for cement has reached proportions exceeding 25% of the fly ash produced. In the U.S., economic factors have thus far prevented the wide acceptance of fly ash for this application. However, fly ash is not currently being used as an additive in the U.S. Trade associations are promoting the use of fly ash. As fuel costs rise and, with them, the costs of producing cement, fly ash will find increasing acceptance as a cement extender. The steel industry is the other major user of coal; it produces ash as part of its

Coal gasification and coal liquefaction

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blast-furnace slag. This industry has some special applications for ash in aggregates. Some 10 million tons of slag per year are being disposed of in aggregates in the United States. Gasification is not expected to introduce ash-disposal problems different from those encountered today in either combustion or steelmaking. An important characteristic of the ash produced in gasification is its very low (O--10%) carbon content, resulting from combustion with the usual amounts of excess air. If the gasification process does not consume nearly all of the carbon, the resulting residue will probably be disposed of by adding it to other coal for use in combustion with excess air. Thus, the usual ash-disposal problem will remain. The countercurrent, fixed-bed gasifier has the advantage of ensuring nearly complete carbon use because, at the point of exit, the ash and carbon are in contact with excess air or oxygen and total carbon conversion is readily obtained. This efficient conversion does not occur with the concurrent, suspended-phase or the fluid-bed reactor systems. The suspended-phase or flame reactors involve high temperatures, fine solids sizes, and adequate levels of turbulence to assure high levels of carbon conversion. In this context, they resemble pulverized-coal burners. However, the pulverized-coal burner has excess oxygen available throughout the length of the reaction zone, whereas some parts of the gasifiers must operate with oxygen-depleted mixtures. Thus, fine solids, bearing a significant amount of residual carbon, are carried out. These are usually recycled. The fly ash is finally removed from the system as liquid slag. Fluid-bed reactors require special provisions for carbon conversion. The ash removed from the primary gasifier contains an appreciable amount of carbon and is often pyrophoric and difficult to handle. For this reason, past studies have been designed to develop ways to allow removal of a carbon-free ash from the fluid bed at specific locations at the reactor where excess oxygen ensures total carbon utilization. Fine ash disposal from fluid-bed gasifiers with acceptable carbon use does not pose problems greatly different from those involved in fine ash disposal at powerplants. We are not aware of special R&D requirements on ash disposal to assure wide-scale applications. However, for any given project, the ash produced must be thoroughly analyzed. Its composition must be defined in terms of leachability for heavy metals, pyrophoric and hydraulic’ properties, and dustiness. All of these properties must be known in. order to design a proper disposal site that is consistent with local environmental regulations. This research may also be necessary to comply with the Resource Conservation and Recovery Act of 1976, Public Law 94-580. Generally, gasifiers (both the suspended-phase and moving-burden types), which operate under slagging conditions, will produce glassy slag, which is particularly inert, nondusty, and easier to handle than other types of ash. To the extent that these slags retain significant amounts of calcium sulfide (as does blast furnace slag), the slags represent a nuisance because of this slow release of hydrogen sulfide (H2S) on exposure to rain. This problem must be dealt with adequately. Ash resulting from the use of coal (including ash or refuse removed from coal by washing prior to use) has been explored widely as a possible raw material. Refuse inevitably contains considerable amounts of coal, which can supply the heat required for processing, particularly if the product is a light-weight aggregate. This type of processing is possible, however, only when the refuse or ash has proper swelling properties. Commercial use of this operation exists in the United States. Considerable R&D has occurred to recover minerals from coals. Among the minerals recovered are pyrite and alumina. These are usually washery rejects or refuse. No property inherent in the ash and resulting from gasification is expected to make the mineral values more accessible to recovery. The recovery of mineral values is likely to be used locally under special conditions and will probably not be of national importance. 2.5 Shif and$nishing process We have noted that the gasifier itself requires a capital investment corresponding UIYS/lI--s

to

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IO-20% of the total investment in an SNG coal-gasification plant. Its detailed design affects strongly both the upstream and downstream systems components, and we have not attempted to analyze the systems-integration problems in their entirety. This analysis is properly the subject of an independent study. A component of the gasification plant that is especially closely coupled to the gasification unit is the gas-purification system. Here, we discuss gas-purification systems for combined-cycle operation and high-Btu syngas (SNG) production. As a percentage of total plant cost, gas cleanup contributes relatively little to the cost of an integrated gasifier/combined cycle power system; gas cleanup represents 7-15x of the cost of high-Btu SNG production. Areas of process research suggested by high-Btu gas cleanup problems are noted briefly. A. Gas purijiccrtion systems for combined cycle operation The removal of acid gases and trace compounds from gas streams is well established in many types of plants. Installations worldwide are converting petroleum feed stock, coke, and coal to provide gaseous products for the synthesis of petrochemicals, industrial chemicals, and hydrogen. In these plants, gases are routinely purified by a variety of chemical, physical, and cryogenic methods to achieve specifications required for environmental and process reasons, including low tolerance levels for catalysts that can be poisoned by trace compounds. In addition, detailed designs of synthetic natural gas plants and conversion plants indicate that stringent environmental standards can be met by the proper selection of proprietary gas-purification systems. The removal of acid gases (hydrogen sulfide and other sulfur compounds), ammonia, and carbon dioxide is based on applications of chemical principles involving the use of chemical solvent. physical solvent, direct conversion, dry-bed, and specialty solvent processes. An evaluation of the scientific considerations involved in the selection of processes for a particular application is beyond the scope of this discussion. Major factors include the target-purification specifications and the concentrations of the components involved. Gas purification is carried out commercially on gaseous streams to remove selectively hydrogen sulfide, carbon dioxide, and all acid-gas constituents. The presence of compounds such as COS and HCN in significant concentrations will complicate the selection of processes because these substances may contribute to solution degradation.’ However, industrial gas-purification systems satisfactorily handle such applications in commercial plants. The sulfur compounds in coal are generally converted, either directly or through a sequence of processing steps, to solid sulfur, which can either be sold or safely stored as a solid. B. Incentives for new purification systems Table 3 shows the cost breakdown for coal-gasification, combined-cycle plants, by plant section. The investment in the purification system is seen to be a small portion of the plant investment because of the added cost to the power-generation equipment and corresponds to about a 4% investment for the base case of 80% sulfur removal and 8% for a plant that removes 90% of the sulfur originally present in the coal. For the gasification plant alone, gas purification consumes 7-15X of plant investment, a value comparable to that noted earlier for SNG plants. C. Purijication systems for high-Btu gas units Existing coal-gasification processes and those under development operate at temperatures ranging from 425 to 1650°F and at pressures from near atmospheric to more than 1000 psi. Their gas-solids contacting modes also differ. These and other conditions produce raw gasifier products consisting mostly of water vapor, carbon dioxide, hydrogen, carbon monoxide, methane, other hydrocarbons, and many impurities including coal or char fines, tars, oils, phenols, sulfur compounds, nitrogen compounds, and some trace metals. Therefore, to obtain the desired gaseous products, several purification steps are

Coal gasification and coal liquefaction Table 3. Plant-investment breakdown for gasification in combined-cycle Source: Electric Power Research Institute.

plants.

Percentage of installed plant cost for

Pl-OCeSS coal preparation oxidant feed gasification and ash handling

80% Sulfur removal

90% Sulfur removal

3.89

3.69

19.54

18.53

4.03

3.82

14.51

13.61

acid-gas removal

3.51

8.10

sulfur recovery

1.30

2.02

45.48

42.76

0.17

0.16

gas cooling

combined-cycle system steam, condensate, and BPW

7.57

7.31

tOta

100.00

100.00

plant investment, $/kW

646

705

SUppOrt facilities

required. The type of purification method needed differs with the desired end product (e.g. low-Btu gas, hydrogen production). For 1owBtu gas production, the raw gases are cleaned only to the degree needed to meet local environmental standards. For high-Btu gas production, the raw gases must be upgraded through gas synthesis and purification. Upgrading to pipeline quality requires that most environmental pollutants be removed and valuable by-products recovered. The concentration of sulfur compounds must also be reduced to very low levels to prevent deactivation of the methanation catalysts used in the process. Huge volumes. of carbon dioxide (approx. 200400 million SCF per day for a commercial coal-gasification plant) must be removed to prevent dilution of the product gas. Purification steps are involved in about 50% of the sub-processes in the overall system and account for a major portion of the facility cost (see Table 3). The following processes are involved : stack-gas cleanup, acid-gas removal, sulfur recovery, tail-gas treatment, sulfur cleanup prior to methanation, gas quenching, gas scrubbing, phenol recovery, ammonia recovery, and wastewater treatment. A wide variety of acid-gas systems is commercially available or under development. D. Incentivesfir new systems For high-Btu coal-gasification plants, purification systems account for a sizeable percentage of the total plant investment. The WESCO Lurgi plant, using subbituminous coal, required the following percentages of capital investments for gas cleanup: for acid-gas removal, 15.6%; for sulfur recovery, 3.3%; for gas cooling, 3.0%; for phenol recovery, 3.2%; for tar and oil recovery, 2.6%; for effluent water treatment, 1.7%. Thus, 29.4% of the total capital investment was allocated for cleanup facilities. Acid-gas removal and sulfur recovery are major areas of concern. The commercial concept designs for the DOE-sponsored Hygas and Bigas processes show that 28-30X of the plant investment is allocated to purification processes; the gasification section requires only about lO-15%. Furthermore, the operating costs for the purification processes presently used, especially for acid-gas removal, are quite substantial. Many acid-gas solutions are regenerated by steam-stripping. Steam requirements affect the size of the boiler house and its stack-gas cleanup. Some systems also have high solvent losses, use high-cost solvents, allow high hydrocarbon losses, and are ineffective in removing some of the trace pollutants.

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2.6 Summury of research recommendations We recommend substantial research programs areas :

on each of the following problem

(a) Gasification of coal is only a first step in producing final products (e.g. electricity or pipeline gas); systems-integration aspects must be properly considered. (b) Improved provisions must be made for integrating research and development (R&D) support within pilot and demonstration plant programs. (c) A balanced program of laboratory research, modeling studies, and diagnostic measurements, to support the use of models in the scaling and control of specific coalgasification systems, must be developed. (d) Improved instrumentation must be developed for the measurement and control of all phases of coal-gasification systems, including characterization and control of effluents. (e) An augmented and integrated effort must be made to solve or avoid materials problems in the design and operation of coal-gasification systems. (f) Effluents produced in coal gasification must be identified and measured and their impacts assessed. (g) Additional research on the physics and chemistry of coals is needed to characterize a wide range of individual coals for given coal-gasification processes and to optimize the design of the processes for given coals. Each of the following activities merits support: Acquisition of data leading to a good model of the pyrolysis of coal through further investigation of the kinetics and mechanism of bond rupture, gas and vapor production, and regressive reactions during the transformation of coals in various atmospheres, as functions of temperature, pressure, and contact time. Research on the mechanisms of the coal reaction paths leading to the direct formation of methane, as a function of reaction medium, contact time, temperature, and pressure. Measurements of variations in the numbers and types of scissile bonds with the rank of the coal and their reactivity under gasifier conditions. Information for the engineering modeling of coal pyrolysis, such as the fluid-dynamics of the vitrinite melt, gas and heat transport in the melt, and changes in particle geometry. Determinations of intermediate compositions formed during coal reactions and coal pyrolysis, using ’ 3C and high temperature nuclear magnetic resonance spectroscopy. Development of methods to identify species and quantify the groups of oxygen, nitrogen, and sulfur compounds in coals and coal chars. Investigations of the relationship of the semiconductor behavior of doped carbons with the reactivities of various coals under gasification conditions. Utilization of the techniques of material science to study solid surfaces and define the topochemistry of coals. The development of analytical procedures that are fast and easily instrumented and that lend themselves to computerization. Discovery of information on the distribution of trace-elements in coals and their effects on coal reactivities. Investigations of the transfer of trace inorganic elements to raw fuel products in various gasification technologies. Studies of the mechanisms of ash agglomeration. (h) Significant opportunities exist for improving coal gasification through research in catalysis in order to improve selectivity in the chemical reactions involved in gasification and downstream processing. (i) A program of fundamental research is needed on unit operations for contacting solids with gases and on two-phase behavior of flowing solid-gas systems. No consensus on the prioritized ordering of the identified research areas for funding purposes exists; but, several FERWG members believe that the greatest intermediateterm (i.e. later than the year 2000) benefits will be derived from basic and applied research on coal chemistry, catalytic chemistry involving coals, and materials. Our estimate is that nearer term payoff is likely to result from work on scaling and modeling and fluid-bed and fixed-bed technologies. Several of us anticipate that work on trace elements and compounds, environmental controls, and solids disposal will have the smallest impact on the design of efficient

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and coal liquefaction

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gasification plants. Nevertheless, these efforts must be undertaken to ensure that coalgasification technologies will meet ever-tightening environmental requirements. Research on instrumentation has been deliberately omitted from the preceding list. Adequate instrumentation is a key factor in quantitative diagnostic measurements; without it, no validation and, hence, no real progress in understanding are possible. Therefore, both instrumentation and diagnostics must be assigned first priority. The development of adequate instrumentation for coal gasifiers is a challenging problem that can succeed only if adequate scope is given for innovation. Powerful new techniques are available, but none has been used successfully in the severe environments that characterize coal beds. Innovative research in any of these areas, of a nature and type not now specifiable, may ultimately lead to the most significant technical advances and economic payoff.

3. COAL

LIQUEFACTION

The objectives of the development of coal-liquefaction technologies have included each of the following: (i) The production of a solid fuel to replace coal in utility and industrial boilers, as exemplified by the SRC-I process. (ii) The manufacture from coal of a substitute for heavy liquid boiler fuel to replace petroleum-derived residual fuels. (iii) The synthesis from coal of a substitute for refinery feedstocks, normally derived from crude oil, for the manufacture of transportation fuels and distillate fuel oils. The synthesis of fuels for transportation applications is currently judged to be one of our most urgent national programs. 3.1 Introduction There are currently under development three generic approaches to producing liquids from coals: (i) Pyrolysis, which involves the direct thermal decomposition of coals. (ii) Hydrogenation, which involves the addition of -Hz to the coal structure from the gas phase or from donor solvents and leads to the production of coal fragments. (iii) Indirect synthesis from CO/H, mixtures, which requires gasification of coal to produce the CO and Hz mixtures. This step is followed by catalytic synthesis. Pyrolysis is practiced commercially in the manufacture of metallurgical coke for s-tee1 making. The liquids are by-products and are coal tars or creosote oils. Liquid yields are normally in the range of 10-15’~ by weight of the coal fed to the coke ovens. Current research on pyrolysis is directed at producing higher yields of lower molecular weight liquids by several techniques, including the rapid heating of coals followed by rapid quenching of the products and rapid heating of coals with Hz addition for product stabilization. The major product is coke or char, which is either burned or gasified. Direct hydrogenation of coal was practiced commercially during the thirties and forties, especially in Germany. Very severe conditions, notably hydrogen pressures of 400&10,000 psi, were used in conjunction with mild catalysts (e.g. iron compounds). Relatively high yields of refinable liquids were obtained. The plants had small unit sizes. The cost of liquids produced in this manner is very high. Current research on direct coal hydrogenation is directed at producing high-quality liquids under milder processing conditions by using catalysts and solvents to aid in the transfer of the hydrogen. There are no commercial direct hydrogenation plants in operation; several large-scale pilot plants (lW250 tons/day) have been started up and two demonstration plants (6000 tons/ day) are currently under construction. The ranges of temperatures and pressures used in early German and in currently developing technologies are shown in Fig. 2. The production of liquids by synthesis from CO/H, mixtures has been practiced commercially since the thirties, using Fischer-Tropsch technology. This approach is currently used in South Africa (SASOL), where significant capacity expansions are in progress. The overall process efficiency of this route to liquids is low, the liquids produced are broad in boiling range, and are relatively expensive. The high costs and inefficiences are the result of the primary production of synthesis gas. Current research is directed at

1110

S. S. PENNI:H CI crl

‘:

lo,000

-

9000

-

6000

-

7000

-

Pre- 1945 Germon technologies

as

6000-

E :

5000-

: P

4ooo

_

Hydropracessing of petroleum residuals \

-x___-

3000

Developing processes

/

2000

coal-liquefoctlon

r

,000 1

so0

6&O

_ 760

660 Temperature,

Fig. 2. Identification

of pressure end temperatures coal-liquefaction

9bo

Id00

“F

regimes for early German technologies.

and for developing

developing more efficient processes for the generation of CO/H, mixtures from coal and at more selective catalysis in the conversion of CO and Hz to liquids. Advanced processes in both of these areas are currently being considered for large pilot plants and rapid commercialization is anticipated.

All processing sequences used for direct hydrogenation in the production of coalderived liquids involve the following steps: (i) Addition of hydrogen to supply the needed constituents for the required increase in hydrogen to carbon ratio. (ii) Cracking of the coal in the presence of hydrogen (hydrocracking) to produce compounds of reduced molecular weight. (iii) Removal of sulfur- and nitrogen-containing compounds (e.g. H2S, NHJ) that have been formed by hydrocracking, as well as removal of water produced by reaction with oxygen atoms contained in the coal. (iv) Appropriate bottoms processing to separate the desired liquids from ash and any remaining unreacted coals. A generalized flow diagram for direct coal liquefaction is shown in Fig. 3. This diagram contains the major processing steps that occur in the Gulf Oil Company solvent-refined coal procedure (SRC-II), the Exxon donor solvent process (EDS), and the catalytic Hydrocarbon Research process known as H-Coal. Reference to Fig. 3 shows the following processing features. The raw coal is first dried and ground (0) to produce the feed coal that is mixed (a) with a (recycled) solvent to produce a coal slurry to which hydrogen feed is added in appropriate amounts (0). The liquid mixture of coal, solvent and hydrogen is then preheated and dispersed (a) before entering the liquefaction unit (0). The liquefier may be a catalytic reactor (as in the H-Coal process) or a thermal reactor (as for the SRC-II and EDS processes). Because of the necessary presence of mineral matter, both in the coal and in the (recycled) solvent, the so-called thermal liquefaction of the SRC-II and EDS processes will also involve catalyzed reactions. After liquefaction, the reaction products undergo a series of separation steps. beginning with gas removal (a) and pressure reduction or let-down (0) during which low molecular weight hydrocarbons (light ends) are separated. At this point, some of the heavy product may be recycled to the feed slurry, as in the SRC-II process (@). However, most of the heavier remaining material is now subjected to one or more processing steps to separate the principal liquid products from heavy liquids and solids (@). The latter may be partially pyrolyzed to generate feed hydrogen ( @) and ash (0 f while the principal liquefaction products enter a separator ( 0) from which

Coal

gasification

and coal liquefaction

1111

both desired liquefaction products are recovered ( @J) and recycle solvent is bled (0 ) for prior solvent hydrogenation in the EDS process ( 0) or for direct reuse in the coal slurry (as in a version of the SRC-II process). The generalized flow diagram of Fig. 3 is augmented by detailed descriptions of processing sequences in connection with discussions of site visits to individual direct coal-liquefaction processes (see Appendix C of Ref. 2 for details).

The reaction of CO with ,H2 to form CH4 was investigated about 100 yr ago. An important discovery was made around 192.5 when Fischer and Tropsch succeeded in developing catalysts which yielded straight-chain hydrocarbons from CO and H, at atmospheric pressure and relatively low temperatures. However, it took ten years until a practical clean-up system and special reactors could be developed to protect the very sensitive catalyst from poisoning and from over-heat. Research follow.ed to replace the tricky cobalt-thoria catalyst with iron and to design more practical reactor systems operating at medium pressures of 300400 psi. This work led to commercial application in 195.5 in the Sasol plant (South Africa), based on use of activated fused iron powder in an entrained solid circulation system. This system serves as the basis of two 50,000 bbl/ day plants, which are scheduled to begin operation in 1984. after 25 years of successful liquefaction on a smaller scale. Individual reactors now have about 100 times greater capacity than the fixed-bed units that were first applied in Germany. The Sasol procedure is the only coal-liquefaction process that is available for immediate commercialization with unit scale-up of about a factor of ten. The product slate consists of a mixture of gases, transport fuels, and chemicals. The Sasol process utilizes a Lurgi gasifier that is not suitable for handling either (Eastern) caking coals or coal fines. Starting with syngas, coal-derived liquids may be processed in a Synthol reactor (as in Sasol II) to produce hydrocarbons (olefins. paraffins) and alcohols containing up to CZO. The key disadvantage in the Sasol process remains the same which characterized the original Fischer-Tropsch work, namely, poor product quality and yield pattern. Work is now being directed toward synthesizing a narrower range of hydrocarbon liquids. The raw product contains a wide range of oxygenated compounds and much of the product falls into the LPG range (C&J. As we have already noted, the principal cost item (7&80x) in indirect liquefaction involves the conversion of coal to syngas. whereas the production of Hz from syngas

Fig. 3. Generalized

flow diagram

for coal liquefaction

(after R. H. Fischer)

S. S. PENNER

1112

et al.

followed by the water-gas shift reaction in direct liquefaction processes is generally considered to represent 3@40% of total cost. Thus, the design of efficient gasifiers is even more important in indirect than in direct liquefaction. Commercially available gasifiers include the dry-gas Lurgi gasifier (for non-caking coals), Koppers-Totzek gasifier (an entrained how gasifier), and the Winkler fluidized-bed gasifier; promising developing gasifiers are the Texaco and Shell-Koppers, entrained flow, partial oxidation gasifiers. which are currently being tested on scales of several hundred tons of coal per day (compare Section 2). A major advance in indirect liquefaction technology is the result of recent developments involving shape-selective zeolite catalysts. Workers at the Mobil Oil Company have tested catalysts of this type with good success on the selective conversion of methanol to aromatic, high-octane motor fuel. Thus, the syngas may be converted to methanol (which is currently produced commercially either by the ICI or by a Lurgi process) for direct use (e.g. in turbine combustors or as an additive to gasoline) or for conversion to high-octane gasoline or to jet- and diesel-oil using the Mobil shape-selective (zeolite) catalyst system, which has been tested in a 4 bbl/d pilot plant. Compared with synthesis, 64% higher gasoline yields, 47% higher liquid fuel yields, and 8% higher thermal efficiency have been claimed. It has been suggested that the combination of a gasifier producing syngas with a low H,:CO ratio (using Koppers-Totzek, Texaco, Shell-Koppers, or Slagging-Lurgi units) with a Fischer-Tropsch slurry reactor and involving an internal water-gas shift reaction may produce an excellent feed for the Mobil catalytic process. Research on indirect liquefaction seems particularly promising and may well lead to novel and innovative processing techniques yielding clean products. For this reason, it is possible that the indirect route to transportation fuels will turn out to be cost-competitive with the direct liquefaction processes referred to in the preceding paragraph. This last statement is made advisedly and in spite of the fact that indirect liquefaction necessarily entails a significant energy penalty that is associated with the requirement of decomposing the entire coal structure in order to manufacture the raw materials needed for indirect liquefaction. A key issue for any given project will be the quality of coal selected for processing. It is possible that the coal response to gasification or hydrogenation will lead to preferential selection of one of these two routes for liquefaction. A schematic overview of indirect coal-liquefaction processes is given in Fig. 4. gasoline. diesel oils. chemicals

FischerTropsch

methane

styrena.

,-r, _.ackinQ of naphtha

ethylene

t

synthesis gas ICO + HJ

tolllena

)

methanol

d

J Ah

ethylene QlyCOl. methanol

Fig. 4. Schematic

overview

(@TX). gasoline. jet and die581 fuels

aromatics

of indirect

coal-liquefaction

processes

acetic acid

(after 1. Wender).’

HCHO

Coal gasification and

hque~dction

Cod

1113

3.4 Other coal-liquefaction processes

In addition to the processes described in Sections 3.2 and 3.3, exploratory and commercial work has been in progress on a number of different procedures. These include Conoco’s ZnCl,-“catalyzed” process, Dow’s direct liquefaction procedure, variants on the Mobil process, flash pyrolysis, supercritical extraction, extraction followed by hydrotreating, pyrolysis followed by gasification, proprietary systems (e.g. at Exxon), and others. Essential features of some of these processes are described in Appendix C of Ref. 2. 3.5 Past, current and projected unit sizes of direct coal-liquefaction plants An overview of past, current and projected unit sizes of direct coal-liquefaction that have received major DOE support is presented in Table 4.

plants

Table 4. Scales and operating schedules for selected direct coal-liquefaction processes. Operating scale PrOCesS

Industrial

lesignation

developnent Southern

jRC-I

coal

Service

Wilsonville,

per

Ft.

Oil

(Exxon

Corp.

1

to 1979

30

1978-79

bOO0

mid-eightie

coal-lique-

faction

unit

(CLPP-

CLPP-

2.5x

(RCLU)

Coal-liquefaction plant

Time period

Lewis,

Corp.

Recycle

EDS

day

6

Washington Gulf

of

Co.,

Alabama

PAMCO,

jRC-II

in tons

Experimental plant

before

1965

pilot 1)

2

faction

1o-2

0. 5

1965-69

1

197 5-79 projected:

coal-lique(ECLP)

250

1980-82

Commercial-scale demonstration H-Coal

Process

(Hydrocarbon

unit

plant

-

25,000

after

1988

developllent

(PDU)

3.5

plant

200-600

1964-79

Research, Inc.

)

Pilot

projected

fo

1980-82 Commercial-scale demonstration

probably plant

-

25,000

after

1988

3.6 Comparisons of direct und indirect coal liquefaction The Germans made about 80% of their .fuels by direct liquefaction during World War II. Their largest plant used about 600 tons of coal per day. This scale is not much larger than the pilot plants that will come on stream in the U.S. and in the F.R.G. in the near future. The indirect route, the Fischer-Tropsch process, was more costly and less energy efficient than the direct route. Furthermore, the Germans did not have a good clean-up system for the removal of sulfur from their synthesis gas. Since the Fischer-Tropsch catalyst is highly susceptible to sulfur poisoning, extensive use could not be made of the indirect route in Germany, although plants of this type were built in Manchuria, Japan, and other countries. After the war, South Africa chose the Fischer-Tropsch process to make synthetic fuels and chemicals. The South Africans have the only commercial plants for coal liquefaction in the world today. This development was not an easy job. More than 20 years of research and development were required to solve innumerable problems concerned with

1114

S. S. PENNER et al.

operation of the Lurgi gasifiers, the clean-up systems, the catalytic converters, and the separation of the array of products which contained paraffins, olefins and oxygenated compounds in a wide range of molecular weights. But they persisted and the larger Sasol II and Sasol III units will be coming on stream in the next few years. . Thus, this technology, while it may not be the best, is known and can be implemented immediately in the U.S. Although 70-80°/0 of the cost of indirect liquefaction resides in the gasification of the coal (as compared with 3&40% for direct liquefaction), given a clean synthesis gas (medium-Btu gas), the possibilities for its conversion to clean, petroleum-like liquid fuels, to methanol, to synthetic natural gas, and to petro-chemicals (both aliphatic and aromatic) exist. Many large chemical companies are actively engaged in searching for new selective catalysts for use in synthesis gas conversion. The Mobil route from synthesis gas to methanol to high octane gasoline will be tried on synthesis gas made from natural gas in New Zealand. The 100 barrel per day fluid-bed Mobil unit to be built in the F.R.G. is designed to produce jet and diesel fuels, in addition to gasoline. The products of indirect liquefaction are essentially devoid of sulfur and nitrogen and have very low, if any, worrisome toxicity. Three pilot plants using direct liquefaction are being built in the U.S. and one F.R.G. process should be in operation in 1980. As mentioned earlier, gasification plays a smaller though necessary part in direct liquefaction; hydrogen manufacture is still about 3040% of the cost. But direct liquefaction promises to be more energy-efficient and possibly cheaper than indirect liquefaction. There are developments in catalysis that can offer major improvements in this field. A promising approach involves matching a dissolver with a following catalytic unit that deals with a slurry or a solution that is readily amenable to catalytic action. Most poisons and coke-forming constituents must be removed before the catalytic unit. Direct liquefaction can produce finished liquid fuels that are no more toxic than fuels produced by indirect liquefaction. Modern upgrading methods, offshoots of petroleum technology,.can eliminate essentially all of the sulfur and nitrogen from these fuels and reduce polynuclear aromatics to partially saturated and paraffinic products. There is a danger, however, that the public will not be made aware of these facts. There is currently wide publicity dealing with the carcinogenic properties of the primary products produced from coal by direct liquefaction and little follow-up on the already accomplished upgrading of these substances to clean, environmentally acceptable fuels. The problem may well be a result of the published analysis of intermediates produced by direct coal liquefaction, but these may be handled as easily as similar intermediates in petroleum refineries. It is important that the public is properly informed, that questions and answers are openly discussed, and that the solutions are properly presented. This information must be promptly disseminated to allay the public perception that the products of direct coal liquefaction are too toxic to handle. There is little doubt that both direct and indirect routes to coal liquefaction will be used. Indirect liquefaction has arrived sooner but direct liquefaction may perhaps be the route that will eventually be used to make most of our liquid fuels. Only continued and well-funded research will answer the many questions raised in these debates. 3.7 Summary of research recommendations We identify below important R&D areas, each of which has been judged by FERWG to require substantial additional funding (i.e. more than $106/yr). (a) Research is needed on each of the following topics: the basic physics and chemistry, structure, composition, and thermochemistry of coals; volatilization; kinetics and mechanisms of bond scission; subsequent free radical and ionic reactions, including reaction steps involving unstable intermediates; transport properties and fluid mechanics of multiphase flows. (b) Major opportunities exist for improving direct and indirect coal liquefaction through research in homogeneous and heterogeneous catalysis, using either recoverable or

Coal gasification

and coal liquefaction

1115

disposable catalysts. Fundamental research should concentrate on mechanisms, kinetics and surface chemistry. (c) Bottoms processing is likely to limit commercialisation of direct coal liquefaction processes. An integrated program of R&D is needed, using bench-scale tests and pilot plants processing up to 100 tons of coal per day. These should be used to study gasification, combustion, and coking of residues. (d) Scale-up and optimization of coal-liquefaction processes require improved understanding of processing steps, including two- and three-phase flows with heat and mass transfer and chemical reactions. (e) A review of environmental and health effects has not been performed by FERWG. We are aware of work in this field. We recognize the need for careful studies on methods of analysis and toxicology in order to assure the definition of adequate environmental and health standards. The emphasis should be on determining health effects of the finished products in parallel with development. (f) Improved instruments must be developed for the measurement and control of all phases of the coal-liquefaction technologies, including the characterization and control of effluents. (g) An augmented and integrated effort must be made to solve, control, or avoid the many physical and chemical materials problems that have been encountered in the development of a variety of coal-liquefaction technologies. (h) Additional research is needed on the characterization of a wide range of individual coals for different coal-liquefaction processes and on optimizing the designs of coalliquefaction processes for particular coals. (i) Research on flash pyrolysis of coal and on coke utilization may lead to attractive alternative routes to coal liquids. (j) Fundamental research is needed on the escape of pyrolysis products from a coal particle and on their subsequent chemical reactions, both within the particle and in the vapor phase. (k) Basic research is needed on mechanisms to control regressive reactions that lead to high viscosity of vacuum bottoms and to formation of sticky reactor residues. These studies are needed to assure system operability, good product recovery, and long catalyst life.

Table

5. Costs and cost distributions

in coal liquefaction.

Range for EDS, SRC-II. Dow, and Zinc Chloride Processes Capital Liquid

cost,

$/(ton

products,

Capital

cost,

Capital

cost

of coal/day)

$/(bbl

of syncrude/ day)

distribution,

manufacture

Other (power, offsites)

Note:

utilities,

- 96,300

15,700

- 47,000

%

Liquefaction Hydrogen

54,900

1.9 - 3.5

bbl/ton

and cleanup tankage,

18.0

- 35.7

15.2

- 41.2

40. 1 - 63.5

All costs are adjusted to 1979 dollars at 7%/yr. No attempt was made to place all of the processes on the same economic basis, except that 1979 dollars are used.

1116

S. S. PENNERet

al.

(1) Fundamental and applied research should be pursued on separation of liquid streams and solids from the reaction products formed during coal liquefaction. These studies are needed in order to improve recycle systems to reduce processing costs. Vapor/ liquid equilibria should be better defined, especially in regions near the critical points. (m) Downstream refining facilities should be leased or built for experimental refining of coal-derived oils to produce commercially usable liquids for engine development and also for use in turbines and boilers. 3.8 Costing of coal liquids A limited costing study for coal liquids is described in Ref. 2. The results of this analysis are summarized in Table 5.

REFERENCES I.

2. 3. 4. 5. 6.

“Assessment of Long-Term Research Needs for Coal-Gasification Technologies”, by the Fossil Energy Research Working Group, Mitre Tech. Rep. MTR-79WOO160. The Mitre Corporation, Metrek Division, 1820 Dolley Madison Boulevard, McLean, VA 22102, April 1979. “Assessment of Long-Term Research Needs for Coal-Liquefaction Technologies”, by the Fossil Energy Research Working Group, Energy Center, University of California San Diego, La Jolla, CA 92093. March 1980. “Assessment of Low- and Intermediate-Btu Gasification of Coal”, prepared by the Ad Hoc Panel on Low-Btu Gasification of Coal of the Committee on Processing and Utilization of Fossil Fuels, National Research Council/National Academy of Sciences, Washington,D.C., 1977. E. J. Hoffman, Coal Conversion, 464 pages, The Energon Company, Laramie, Wyoming, 1978. W. H. Lowry, Chemistry of Coal Utilizarion. Wiley, New York (1963). Handbook of Gasijiers and Gus Treatment Systems, prepared by the Dravo Corporation, Pittsburgh, Pennsylvania, FE 1772-l 1. Contract E49-I8 1772, U.S. Department of Commerce, Feb. 1976.