Coal combustion


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Coal combustion
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Table of Contents
    Front Cover
        Page i
        Page ii
    Letter of transmittal
        Page iii
        Page iv
    Table of Contents
        Page v
        Page vi
        Page 1
        Page 2
        Page 3
        Page 4
        Page 5
        Page 6
        Page 7
        Page 8
    Findings and conclusions
        Page 9
        Page 10
        Page 11
        Page 12
    Section 1. Coal and combustion research
        Page 13
        Page 14
        Page 15
        Page 16
        Page 17
        Page 18
    Section 2. Use and production of coal
        Page 19
        Page 20
        Page 21
        Page 22
        Page 23
        Page 24
        Page 25
        Page 26
        Page 27
        Page 28
        Page 29
        Page 30
        Page 31
        Page 32
    Section 3. Fluidized bed boilers
        Page 33
        Page 34
        Page 35
        Page 36
        Page 37
        Page 38
        Page 39
        Page 40
    Section 4. Existing alternatives to further coal combustion research
        Page 41
        Page 42
        Page 43
        Page 44
        Page 45
        Page 46
        Page 47
        Page 48
        Page 49
        Page 50
    Section 5. Other areas of coal combustion research and development
        Page 51
        Page 52
        Page 53
        Page 54
    Appendix. Energy conversion alternatives study (ECAS)
        Page 55
        Page 56
        Page 57
        Page 58
        Page 59
    Back Cover
        Page 60
Full Text












Serial YY



Printed for the use of the Committee on science and Technology


For sale by the Superintendent of Documents, U.S. Government Printing Office
Washing-ton, D.C.204 02
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OLIN E. TEAGUE, Texas, Chairman
DON FUQUA, Florida JOHN JARMAN, Oklahoma
ROBERT A. ROE, New Jersey LOUIS FREY, JR, Florida
MIKE McCORMACK, Washington BARRY M. GOLDWATER, JR., California
RAY THORNTON, Arkansas GARY A. MYERS, Pennsylvania
HENRY A. WAXMAN, California PHILIP H. HAYES, Indiana TOM HARKIN, Iowa JIM LLOYD, California JEROME A. AMBRO, New York CHRISTOPHER J. DODD, Connecticut MICHAEL T. BLOUIN, Iowa TIM L. HALL, Illinois ROBERT (BOB) KRUEGER, Texas MARILYN LLOYD, Tennessee JAMES J. BLANCHARD, Michigan TIMOTHY E. WIRTH, Colorado JOHN L. SWIGERT, Jr., Executive Director HAROLD A. GOULD, Deputy Director PHILIP B. YEAGER, Counsel FRANK R. HAMMILL, Jr., Counsel JAMES E. WILSON, Technical Consultant J. THOMAS RATCHFORD, Science Consultant JOHN D. HOLMFELD, Science Consultant RALPH N. READ, Technical Consultant ROBERT C. KETCHAM, Counsel REGINA A. DAVIS, Clerk MICHAEL A. SUPERATA, Minority Counsel

KEN HECHLER, West Virginia, Chairman
WALTER FLOWERS, Alabama GARY A. MYERS, Pennsylvania




Ron.OLIN. TEGUEWashington, D.C., October 1976.
Chairman, Committee on Science and Technology, House of Represent atives, Washington, D.C.
DEAR MR. CHAIRMN: During the oversight hearings on coal combustion research and development, the Subcommittee clearly identified that a very large gap in technology exists if this nation' intends to revive coal as a major source of our future energy requirements.
The combustion of coal and its use in an environmentally acceptable manner for the raising of steam to produce electricity and to generate heat was the basic subject of concern to the Subcommittee. Thle Subcommittee has identified the areas of concern which the hearings pointed out in the findings and conclusions accompanying this report, and urges the full Committee on Science and Technology as well as all interested parties to share this concern.
KEN HECHLER1, Chairman,
Subcommittee on Energy Research, Development and Demonstration (Fossil Fuels).


Letter of transmittal ----------------------------------------- i
Introduction ---------------------------------------------------- 1
Findings and conclusions ------------------------------------------ 9
Section 1--Coal and Combustion Research ---------------------------13
Section 2-Use and Production of Coal ------------------------------19
Section 3-Fluidized Bed Boilers ----------------------------------33
Section 4-Existing Alternatives to Further Coal Combustion Research- 41 Section 5-Other Areas of Coal Combustion Research and Development-_ 51 Appendix-Energy Conversion Alternatives Study (ECAS) ----------- 55

Digitized by the Internet Archive
in 2013

This Nation presently possesses one -fifth of the world's remaining coal resources--some 4 trillion tons. The coal already used in tlie United States fueled its initial growth as an industrial and world power. Coal fired steel mills forged the tracks that coal driven locomotives travelled in opening up the Western frontier. By the turn of the century, coal supplied 90 percent of the country's eneror consumption. In absolute terms, U.S. coal production has increased since the turn of the century, though there have been large fluctuations in total tonnage in the last 30 years (see figure 1). However, as domestic oil and natural gas became available at a competitive price, coal consuinption grew less rapidly. By 1950, coal provided 38 percent of the Nation's energy consumption and by 1972, only 17 percent.'
This decreased dependence on coal has also been strongly affected by the passage and enforcement of environmental legislation. The existing methods of mu*u*nz and usin coal made it unattractive from an environmental viewpoint. By 1910, the future of coal as a primary fuel was in question.
This uncertainty in the future role for coal was resolved in part by the Arab oil embargg in 1973, the subsequent price increase of oil and then the worsening natural gas shortages. These events highlighted once again the value of our coal resources and turned thoughts to strategies for increasing its production and use. Another factor in reviving coal is the recognition of the interconnection of our economy with energy consumption. As a consequence of these two factors, the Federal Energy Administration projects coal production in 1985 to be about one billion tons.* This represents an almost fifty percent increase over 1975 production of 635 million tons.
This increased coal production will be used in many ways, using both existing and soon to be developed technologies. r
1 U.S. Federal Energy Administration. National Energy Outlook (Washington, 1976) pp 163-165.
Thi : estimate was provided to the Committee in its hearing In July of 19-5. The President has recently announced a similar goal as part of his National Energy Plan.


Coal Consumption By Sector, 1935-72

Consumption (millions of tons) 600

Total Consumption


..O ., '
.Mo .". 0.


.ElectriC Utilites
300 ..,ow:*.*

Oe r ... Exp or

Reailods .
100 ,4

",,7- Railroads .._'. -', ., .,
,. . . *. I I t. 1

1835 40 45 50 55 60 85 70 72I



TAma 1.-Methods for coal to energy I. Direct Firing: requires clean coal or clean-up methods
for compliance:
1. Lump (grate) firing: Commercial
(i) Hand fired ------------------------Yes.
(ii) Stoker fired -----------------------Yes.
2. Crushed firing-fluid bed:
(i) Ballasted ----------------------- No.
(ii) Unballasted (Ignifluid) --------------Yes.
(iii) Fast fluidized bed (Szikla-Rozinek)___ No.
3. Pulverized (fine ground) firing:
(i) Standard pulverized coal combustion
(<100 microns) -------------------Yes.
(ii) Ultra-fine ground (<10 microns) ------No.
II. LOgas: Producer-gas/water (syn) gas (CO, H2, N2
(CH4)) (100 to 300 Btu sec. cubic foot) :
1. Fixed bed, vertical shaft (Wellman, Lurgi)counter flow ----------------------------Yes.
2. Fluid or fast fluid bed ----------------------No.
3. Entrained (fine grind: Koppers Totzek) --------Yes. NoT.-The last 3 are commercial on a proportionately small scale. II. Pyrolysis: Coking ovens-yields are:
(1) Tars (can be used for some chemical feedstock)
(2) Coal gas (500 Btu per cubic foot of H2, CO,
(3) Coke (feed for gas producers)
NOTE.-Emissions are under control using continuous vertical retorts. IV. HIgas: SNG from coal (1,000 Btu per cubic foot) :
1. HYGAS process --------------------------- No.
2. CO2 acceptor process -----------------------No.
3. Bi-gas process ----------------------------No.
4. Self-agglomerating burner ------------------- No.
5. Synthane process -------------------------- No.
6. Steam-iron process -------------------------No.
V. Liquefaction: SNO from coal:
1. Solvation (solvent refining) ------------------No.
2. Direct catalytic (Synthoil: CHo 9 to CH,1) ----- No.
3. Methanol: from syngas (CO+2H2 to CH3OH) --- Yes.
4. Fischer-Tropsch ---------------------------Yes.
5. Bergius ----------------------------------Yes.
NOTS.-(1) Units in principal can be atmospheric or pressurized.
(2) Most units are continuous ; small water gas may be intermittent.
(3) Sulfur is removed as H2S by standard methods for the cold gas; hot gas cleaning is a problem. (4) Gas can be delivered and used hot, with ash and S, or cold cleaned. (5) Efficiencies are 85 to 90 percent used hot; 70 to 75 percent used cold and clean.
VI. Combination FueZs:
1. Coal dispersion in oil -----------------------No.
2. Coal dispersion in methyl fuel ----------------No.
VII. Direct Power:
1. Diesel (ultra fine grind) --------------------No.
2. MHD ------------------------------------No.
3. Gas turbine: Yes.
(i) Low-Btu gas -----------------------Yes.
(ii) Direct fired clean coal ---------------No.
VIII. Mixed Methods:
1. Two stream cleaning options by deep cleaning:
clean stream (50 to 80 percent of total) to conventional equipment with no FGD necessary; dirty stream to specially equipped
boilers or gasifiers -----------------------No.
2. Partial pre-cleaning (low efficiency) with partial
(low efficiency) cleaning of inter stage gas with (low efficiency) FGD. Overall high control efficiency ----------------------------No.
NOTE.-Emissions are under control using continuous vertical retorts.
Source: Testimony of Dr. Robert Essenhigh before the Energy Research, Development, and Demonstration (Fossil Fuels) Subcommittee, July 31, 1975.


These technologies can be characterized under three headings: (1) direct combusion of coal or coal mixed with another fuel, (2) conversion of coal to liquid or gaseous fuels, and (3) combined cycles utilizing gas turbines or MilD generators in tandem with traditional steam turbines.
The direct combustion technologies were discussed before the subcommittee on July 29, 30, and 31, 1975. The hearings focused on the research and development required before these technologies could be used commercially. However, they also uncovered how these R. & D. programs must be tailored for the different needs of 'different users. The utility industries need large scale (100 to 1,000 Mw) installations with high reliability and straightforward maintenance. The other industrial users need smaller units (10-100/1NMw) for raising steam or process heat to be used for such products as steel, glass, refractories and cement. This smaller unit market is particularly important. Because of the direct correlation between industry and jobs, energy shortages have a dramatic effect in this sector. It suffers more quickly in an energy shortage and the costs associated with environmental clean up are higher relative to the larger 'Utility users. The hearings underlined the fact that a successful program will address such other issues which surround increased coal production.

The concerns discussed in this section have an impact on direct combustion technologies in various ways. For example, there are technical concerns which are specific to each method but technical improvements in the mining of coal will impact all coal tehnologies equally.
The immediate problems facing direct combustion of coal are two: more efficient combustion and emission controls. The need for more efficient combustion arises from the fact that even our vast coal resources are finite. In fact, of the 4 trillion tons of coal mentioned earlier, approximately 400 billion are recoverable with present technologies. Aside from the clear need for new coal recovery methods for the remaining 3.6 trillion tons (which was the subject of a subSequent set of hearings by the subcommittee, July 27, August 3, 4, 5, September 10, and 16, 1976), it is important to use coal as efficiently as possible. This is one of the motivations behind the development of fluidized bed combustion of coal.
The problems of emission control are governed by the Nation's continued commitment to a clean environment. Control of sulfur, in particular sulfur dioxide (SO2) emissions, has been of paramount importance. Though sulfates and nitrogen oxide emissions are becoming prominent, technical attacks have b;een mounted most aggressively on SO, removal. Table 2 lists some of the prominent desulfurization


TABLE 2.-Sulfur otrol strategic L Low sulfur coal
II. Pre-Combustion Cleaning:
(1) Mechanical (physical) (inorganic sulfur only):
(i) dry methods.
(ii) wet methods (floatation etc.: Trent process etc.).
(2) Chemical (total sulfur)
(i) hydrodesulfurization.
(ii) oxydesulfurization.
(iii) solvation or other removal of mineral matter. II. Inter-Cleaning:
(1) Gasification strategy: sulfur removed as HS in an inter stage of the
(i) Producer/water (synthesis) gas-including combined cycle operation.
(ii) Pyrolysis (destructive distillation in coke ovens).
(iii) Indirect methane production (HI gas).
(2) Liquefaction strategy:
(i) Solvation (SRC).
(ii) Synthoil production.
(i) Atmospheric.
(ii) Pressurized.
IV. Post-Cleaning
(1) Stack gas cleaning (FGD).
(2) Tall stack dispersion (dilution 1).


Many of the environmental problems facing direct combusion are common to any energy technology that utilizes coal. Among these are health and safety in mining technologies, reclamation of strip-mined land, and appropriate use of the scarce water resources in the West.
A concern common to the development of Western coal. and to some extent Eastern coal, is the impact on the small and relatively poor communities or Indian reservations where the coal mines and possibly electric power plants are likely to be built. During construction, a boom town situation will occur. The local service institutions including schools and hospitals may not be able to handle the burden without new facilities. Therefore, public and private efforts must go hand in hand with the resource development to avoid the adverse effects of this kind of development.


Though one can devise labels that separate environmental, regulatory and financial concerns, the reality of coal development intertwines all these areas. Environmental regulations have added real costs and inflationary costs due to time delays incurred by meeting all the requirements of regulating agencies. These have pushed the capital costs associated with a traditional coal burning electrical generation plant above those for a nuclear electric plant. In the case of the electric

'Dispersion is not advocated as a strategy for control of sulfur emissions but it is advanced as an interim strategy for control of ambient air levels.


utilities, the added costs, rapid inflation and an unadjusted rate structure have made front end capital difficult to obtain. This is especially so for new technologies like fluidized bed combustion. Industrial users have their problems in converting too, chief of which is the added Costs Of handling and using coal. These delay the decision to switch to coal and thus affect the commercial viability of improved combustion technologies.
The financial community is also concerned that a large amount of capital must be formed and devoted to the energy market as a whole if the country's energy goals are to be met. It is generally agreed that the economy can generate enough capital but it is not clear how the financial resources should be allocated to new technologies.

The utilities and smaller industrial users of coal must meet many sets of regulations including environmental regulations. These regulations affect land, air and water use and all of these requirements add to the time and costs associated with the plants. In addition the worst fears of the participating firms is that once the requirements are met, someone will change them. Industry could better address itself to solutions for environmental matters with a stable regulatory climate in the environmental area.
The rate structures of electrical utilities are determined by Federal and State agencies. The rate of return has been fixed for many years in most States and has not been adjusted for the increased rates of inflation in the recent past. To further complicate matters new plants cannot be written into the rate base, of most utilities during construction.
Energy policy as it evolves will be a joint effort by both the President and the Congress. The choices that must be made will have, to balance the contributions from programs to restrict consumption or ,change consumption patterns and programs which will increase energy supply. Near term needs must be' balanced against long term needs. The technologies using coal and uranium must be placed in the perspective of energy from the sun and possibly fusion. The size of the coal resource, its familiarity and the severity of the near- and midterm needs for energy assure that coal will be used. The form of its use and the timing of new technologies allow room for governmental action. The problems are ones of accelerating not simply developing devices and methods but -the meshing of Government programs with already functioning structures in private industry.
The significant role of coal and the need for research and development in coal technologies was acknowledged byCongress when it established the Office of Coal Research in 1961. More recently, passage of the Energ-y Supply and Environmental Coordination Act (Public Law 93-319, 88 Stat. 246) provides authority in section 2 for the Federal Energy Administration to order oil and natural gas burning electric generators to convert to the use of coal. This program was continued and intensified with the passage last year of the Energy Conservation and Production Act, Public Law 94-385. As a consequence, it is now


part of our national energy policy that more coal must be used. It now remains to develop more efficient, cleaner and economically successful techniques for insuring that coal is burned by the widest community of possible users. ORGANIZATION OFTms PAPER

This paper will examine research and development efforts in different coal combustion technologies. These efforts are set in a general perspective of how coal has been used and produced. In addition, a short history of coal research sets forth the background for the current problems. Then the status of specific technologies is examined. Fluidized bed combustion, viewed by many as the most exciting and novel coal combustion method is described. The other existing and less developed technologies are discussed as possible alternatives to fluidized bed combustion. Finally the energy conversion alternatives study (ECAS) which is to evaluate some of these combustion alternatives, is discussed in the appendix.

While the United States has recently adopted a policy to increase the use of coal as a boiler fuel 'for electric generating units, the subcommittee hearing record reveals the lack of any coherent, National policy on coal research and development even in the recent past. The Subcommittee found on the basis of the testimony it received that there had been no significant breakthrough in coal combustion technology since the late 1920's. While there apparently had been a gradual improvement in coal combustion technology and power generation efficiency, there had been nothing in the way of a new technology or dramatic change in this field. The only technology on the horizon is that for atmospheric fluidized bed boilers which will not be commercially operative until the 1980-85 time frame.
Furthermore, our hearings showed a desire, on the part of ERDA, to rely exclusively on one area of technology to improve the use of coal for combustion; i.e., the fluidized bed. Subsequent to our hearings, ERDA has expanded the number of technologies for their coal combustion research by adding a coal and oil slurry ,program. However, this was modestly funded; and the Subcommittee later learned it was not given a high priority. For example, when funds had to be reprogrammed for construction of an MHD facility, a long-term technology, the coal and oil slurry program was one of the first to go.
At Subcommittee insistence, this program of near-term technology was restored to almost its full level so that no cuts were made.
The Subcommittee feels that substantial benefits could be realized 'from increased research into the boiler use of coal and oil mixtures. ERDA should reconcile any technological problems remaining with this near-term option and should devise an accelerated program to rapidly transfer it to industry. Many non-technological constraints may inhibit the potential near-term impact of this technology.
Substantial additional National benefits can accrue from successful research in the retrofitting of industrial oil and gas boilers to the use of coal. Our National policy to increase the use of domestic coal will be furthered, but more importantly, jobs vulnerable to gas or oil curtailment will be protected.
In regard to this, it should be noted that ERDA is conducting research work on industrial-size atmospheric fluidized bed boilers for new plants. However, more work needs to be done on the potential for retrofitting industrial plant boilers with fluidized bed equipment. Such retrofitting would accelerate the utilization of coal in our Nation's economy. However, most of the testimony received showed a reluctance on the part of ERDA, the utilities, and industry to investigate the retrofitting option. In many cases this was based on a lack of information or misinformation as to outage times and economics. The Subcommittee hopes that ERDA's program in retrofitting industrial boil-


ers will include cooperation and coordination with industry to maximize the retrofitting option.
Low sulfur coal reserves in the West and the East are not being fully utilized. Testimony revealed that the increased production of low sulfur coal had not been seriously considered by the utility industry as an alternative to technologically intensive solutions. EPRI testified that they considered the option of installing new facilities for low sulfur coal to be equally desirable to high technology solutions such as coal gasification, where costs were equivalent. However, to date, the level of production necessary to justify their reliance on low sulfur coal has not come forth, requiring them to pursue these technologically intensive solutions.
Members of the subcommittee felt that the low sulfur coal reserve base represented a very real alternative to further capital expenditure by utilities for new technology. However, recognizing the large capital expense required to open new mines, members of the subcommittee wished to see further refinement of data. They wanted to know the amount of coal which can be obtained from either existing deep mines that are currently in operation or from those deep mines that have been shut down in the Eastern United States. Discussion between the panel and the witnesses revealed that the Bureau of Mines does not seek this data, on the basis that this is proprietary information of the coal companies. Members felt, however, that this presented a real option for the country's energy demand, and that ERDA should consider this question jointly with the Bureau of Mines and others; ERDA agreed to research this matter.
Further testimony from EPA indicated that the low sulfur coals of the West may pose further environmental problems. EPA stated, "Under the present environmental control standards set by the Environmental Protection Agency, many of the low sulfur coals will meet the standards, both sulfur dioxide and particulates, at the present time. It depends, though, critically on the nature of the coal. The very good Eastern coals, such as Mr. Hechler referred to, will meet both the particulate and the sulfur dioxide standards without difficulty. However, as you move into the West, some of the coals are really quite different. They have lower Btu content; they have higher ash content; and there are problems in that some of the coals which might have a .7 percent sulfur by weight would not meet the sulfur dioxide emission standards because of the different problems which are created by the lower heat content, the high ash content."
Such testimony indicates that the Eastern coal should be vigorously developed.
With regard to specific areas of research, the subcommittee found that the research and development program fluidized bed technology being conducted by ERDA, has only recently been accorded to high priority which it deserves. The 30 MWe fluidized bed boiler proik, being constructed by ERDA at Rivesville, W. Va., was begun iin October 1972, and is adually an extension of a program which began in 1965.


Witnesses testified that there had been an 18-month delay in the projected construction time due to longer order times than normal, in this inflationary period, and because of changes in West Virginia's environmental standards. While such delays are not unusual, some precautionary planning can be made. The Subcommittee, however, notes with approval the fact that ERDA is requesting authorization for a 200 MWe fluidized bed combustion demonstration plant this year. This plant would represent one module of a comamercial-size power plant.
Another area of coal combustion research that must be pursued is the structure and characterization of coal. An examination of the literature will show that much research has been done on particular seams of coal. However, any attempt to generalize from one type of coal to the other has met with unrewarding results.
More research work also needs to be done on the ability of coals to be cleaned. While the Bureau of Mines has been conducting extensive work on the washability of coals, attempts to measure the efficiency of coal-cleaning methods has been disappointing. This is due to the numerous variables inherent in the task. The variables include the characteristics of the coal to be cleaned, the particular method of operation, the amount and nature of impurities to be removed, the percentage of near-gravity material, and the size range.
This area of research could benefit from Government activity or funding, and would be corollary research to the efforts to categorize the structure and composition of coals.


Coal is a combustible natural solid formed from fossilized plants. It is generally found as a layer in sedimentary rock, which differs greatly in thickness, depth below the surface, and areal extent. It is dark brown to black in color and consists primarily of carbon (more than 50 percent by weight) in the form of numerous complex organic compounds. The composition of coal varies considerably from region to region and even within given fields. Coals are classified on the basis of three specific characteristics: (1) carbon content; (2) heating value; and (3) impurities. The first two characteristics are used in ranking the coal. Anthracite and bituminous coals are primarily ranked on the basis of fixed carbon content. Subbituminous coals and ligrnite, which contain less fixed carbon, are ranked on the basis of heating value. Approximately 70 percent of all U.S. coal is bituminous or subbituminous, while only about 1percent isanthracite.
In addition to being ranked, coals are graded on the basis of the impurities that they contain. Certain impurities (including, -moisture, ash and sulfur) present problems when coal is processed and utilized. Moisture content is related to rank; the higher the rank the lower the moisture content. Moisture ranges from 1 percent in some anthracite to more than 40 percent in some lignites. The ash content of coal varies considerably, even within a single seam, making proportional -generalizations, difficult. Ash is the amount of non-combustible inorganic materials that the coal contains, and affects the heating value of that coal. Ash varies greatly, from 2.5 to 32.6 percent. .The sulfur content of U.S. coal ranges from 0.2 to 7.0 percent varying considerably between geographic regions. Low sulfur coal (coal hav ing a sulfur content of 1 percent or less) occurs both in the Eastern and Western United States. The U.S. Bureau of Mines estimates that there is approximately 167 billion tons of coal west of the Mississippi ]River and 32 billion tons east of the Mississippi River, which is minable. However, the western coals have a lower heating value than do the eastern coals.
The characterization of coal is one area of research that has received little attention in the past. As can be seen from the foregoing discusSion, coal is characterized on the basis of its external properties, rather than its inherent structure and constitution. Members of the coal industry -have seen very little in the way of short-term rewards from such research, despite the fact that a breakthrough could have a significant potential payoff. One of the witnesses who appeared before our Subcommittee, Professor Robert T. Essenhigh, urged, further funding in this area. He said, "The chief problem is that the subject needs a good new idea that would. synthesize all the. diverse factual data we. have at present-in fact, it needs an equivalent to Niles Bohr to


invent the equivalent to the Bohr atomn. This is 'something that no one can write proposals on. However, even Bohr needs sufficient data to work from to stimulate the imagination." Further research work to gather such information is appropriate. This seems to be -an appropriate, area where the Government, rather than industry, will have to take the lead'in f unding.

Research on coal combustion and related matters has been conducted for well over a century. In fact, references to studies on coal can be found extending back for more than three centurie 's, but the first; known paper on coal combustion was published in 1845. This report appeared in the Philosophical magazine, and was concerned with an explosion which had recently occurred. For the next 60 or 70 years the
literature in coal research was mainly concerned with reports on explosions and methods for increasing safety of this combustion. Utilization of coal was given very low priority, and only minor advances were made in this area.
Gradually research on explosions involving coal gave way to direct research on the utilization of coal, but the research shifted in the nineteen twenties when engineers began to turn their attention to the more lucrative area of petroleum research. From then on, -most research conducted on coal was of a somewhat unsophisticated nature. IThe volume of literature published was large between World War I and World War 11, but the quality of research was not commensurate with research in other energy areas. In 1924, Harvey compiled 5,000 titles of papers on pulverized coal firing alone, and by 1930, in a list by Knabner, the list 'had grown to over 10,000.2 The list 'of papers on the subject of the combustion of coal was even more monumental.
-However, the quality did not keep pace with the quantity of literature. This is not to say, though, that some important work was not done. Papers by Nusselt on diffusion analysis, published in 1924 and ~a paper by Tu, Davis, and Hottel on carbon sphere combustion 3 were brought to the attention of the subcommittee.
Unfortunately, since World War 11 the pattern of research has continued to be irregular. The enormous volume of literature that has accumulated can be seen to be a complicating and inhibiting factor to any further systematic research for coal combustion and utilization. An examination of the literature will show that much research has been done on particular seams of coal. Any attempt to generalize from one type of coal to the other has met with unrewarding results. 'It is evident, that further work must be done on the structure and characterization of coal, in order to systematize further experimentation and work in this field.
The efforts of scientists and engineers have been devoted to four areas of research. They have mainly investigated pulverizing of coal, combustion of coal, cleaning of coal, and coal-oil mixtures and blending.
I A large portion of this section was taken from a paper delivered by Prof. Robert Essenhigh, NSF! OCR-R ANN Meeting, October 1974.
2 Ibid.
3 Ibid.


Investigation into pulverized coal began in the 1920's. This renewed interest came about because engineers were trying to increase the steam rates in their boilers, but could not reach desired levels with the gratecombustion techniques then in use. This switch in technologies resulted in a wholly new approach to burning coal. Engineers now dealt with fine coal dust instead of large, gritty mixtures. This smaller sized coal lent itself to more technological innovation than did the earlier technology.
In 1922, Winkler filed an historic patent in Germany.4 His idea was to increase the rate of gas flow upward through a granular bed of coal to buoy up each particle in the bed. When the upward thrust on the particle was equaled by the downward drag of gravity, the particles flowed freely, and the bed took on the character of a boiling liquid. A decade later, American engineers coined the term "fluidization" to denote Winkler's procedure. Winkler commercialized this process in 1926, but very little further development was done on his technology.
An interesting ancedote suggests what coal combustion research may have missed with this process. In the mid-1930's, M. W. Kellogg Company and Esso were at work on a technique for cracking distillate oils by passing oil vapor together with a fine clay catalyst through a heated coil. Results obtained in a small coil were good, but the larger coal performed badly. A group of Kellogg and Esso engineers were returning from Germany, where they had just visited the Winkler gasifier.
One of the engineers suggested utilizing this fluid bed technique to crack the distillate oil. This idea was pursued and within a few weeks a pilot unit was in operation. The large catalytic cracking units in use in the petroleum industry today are the result of that visit to the Winkler process in Germany.
In the 1950's, Albert Godel developed his Ignifluid boiler. This consisted simply of a fluidized bed of coal upon a traveling grate. Godell made the remarkable discovery that the ash of almost all coals is selfadhering at a temperature in the vicinity of 11000 C, no matter how much higher the ash-softening temperature may be. Godell burned the pulverized coal at this temperature, causing the ash to agglomerate into larger and larger particles until the ash eventually fell out of the fluidized bed under its own weight. This technology was originally used for smaller boilers, but has recently been promoted for use in larger units, by Babcock-Atlantique.
Also in the 1950's, Pope, Evans and Robbins began development and promotion of their fluidized bed concept. This development was eventually adopted as a project by the Office of Coal Research. The history of this project will be discussed in further detail in the next section.
While research on pulverized coal has been in the area of combustion, most of the literature on pulverization of coal has been concerned with the correlation between the energy input to the process and the size reduction. Carey and Holton have calculated that of 30 Kw/hr needed to grind a ton of coal in the mill, 8 Kw/hr were lost to
4 F. Winkler, U.S. Patent 1,687,118 (October 9, 1928).


the atmosphere, 9 Kw/hr went into heating the air purged, 7 Kw/hr were used to evaporate moisture, and 6 Kw/hr heated the coal.5
Most of the literature also reveals that the energy input varies with fineness of grinding, ranging from 3 to 4 Kw/hr/ton for coarse crushing through 20-30 Kw/hr/ton for fine grinding to 100-1000 Kw/hr/ton for super-fine grinding.
Two important theories have been developed in pulverization research to explain the fundamental relationship between energy input and size reduction. The first theory is known as Kick's Law, according to which the energy needed to effect equal reduction of pieces does not vary with the size of the starting piece, and is applicable to homogeneous, elastic bodies.6 The second important pulverization theory is known as Rittinger's Law, according to which the energy is proportional to the increase in surface area, consequent upon the size reduction. In the latter, energy lost in plastic deformation and thermal vibrations is neglected, and in both cases the kinetic energy of fragments is neglected.7
Mr. Hahns Rohrbach has provided the only published technical statement on ILOK technology which was developed as being a way of pulverizing the coal and simultaneously removing all sulfur. This was in the Journal Motortechnishe Zeitschrifte on pages 379-385, (1971). The title was "On Some Problems of the Coal Dust Motor". This technology has aroused the interest of researchers, and is being investigated by numerous parties.
There have been numerous studies on the cleaning of coal, beginning with a publication by Stutz in 1880.8 However, the first systematic study of cleaning of coal to develop correlations was done in 1924.9
Another area of coal cleaning, coal washability, was begun in 1929, when the Bureau of Mines began a study of the washability (the ability of coal to be cleaned) of western coals. Since 1950, the Bureau of Mines has been conducting an extensive study on the eastern coals, specifically, from the States of Kentucky, Pennsylvania, Tennessee, Virginia and West Virginia to determine the washability characteristics of these coals.
While many fine studies have been done of the ability of coal to be cleaned, the attempts to measure the efficiency of the cleaning process have been disappointing. The main reason for this is that there is no standard method of measuring the efficiency which has developed. Numerous commentators have attempted this task, but after forty years of articles, no standard has been developed.'0
5 Carey, W. F., and Holton, E. M., Trans. Inst. Chem. Engrs. (London) 24, 102-8 (1946).
6 Kick, F. Dingleris Polytech. J., 247, 1-5 (1883).
"Rittinger, P. Von, Lehrbuch der Aufberitungskunde, Ernst Und Korn, Berlin, 1867, 595 EP.
8 Stutz, S., AIME, 9, 461-77 (1880).
9McMillan, E. R., and Bird, B. M., University of Washington Engineering Experiment Station, Bulletin, 28 (1924).
20 Handcock, D., Alabama Geol. Survey, Monograph No. 7, (1912), pp. 24-45. Delamater, G. R.. Coal Age. 5, 723-9 (1914). Drakeley, T. J., Trans. In8t. Mining Engr. (London),
54, 418-59 (1917-18); 59, 86 (1919-20). Fraser, T., and Yancey, H. F., Trans. Arter. Inst. Mining Met. Engrs., 69, 447-69 (1923). Campbell, J. R., Mining Congr. J., 14, 555-8 (1928). Chapman, W. R., and Mott, R. A., The Cleaning of Coal, Chapman & Hail, London, (1928), Chap. 21. MacLaren, W., Colliery Guardian, 144. 231-50 (1931). Tromp, K. F., Gltickaitf, 73, 121-31 (1937). Reed, W., and Grounds. A., Colliery Eng., 23, 319-22 (1946). Hancock, R. T., Colliery Eng., 24, 140-2, 191-3, 237-9 (1947). Anderson, W. W., AIME, Trans., 187, 256-64 (1950). Belugou, P., and Ulmo, V., Rev. ind. minerale, '31, 13-23 (1950.Rainesu, -, and Belugou, P., Rev. ind. Min~rale, 31, 24-41 (1950). Belugou, P., and vitonx, -, Rev. ind. Minrale, 31, 209-29 (1950). Lyons, 0. R., AIME, Trans., 193, 895-902 (1952).


The lack of a standard method of determining the efficiency probably results from numerous variables inherent in the task. The variables include the characteristics of the coal to be cleaned, the particular method of operation, the amount and nature of impurities to be removed, the percentage of near-gravity material, and the size range. This area of research ~would seem' to be m* need of Government activity or funding, and could be considered to be corollary research to the efforts to categorize the structure and composition of coals.
Finally, research on blending of coal and oil goes back approximately 50 years. An historic landmark of this research was a ship that crossed the Atlantic in 1932 using a coal and oil mixture." The subcommittee was greatly interested in two documents discussed in the hearings, which showed the development of this technology. The first was a study by Pennsylvania State College on colloidal fuels and their development for industrial uses. The second was a patent on oil and water emulsion.
u~ See "Oversight Hearings, Coal Combustion R.D. & D. for Utility Power Plants and Tndustriai Uses," Subcommittee on Energy Research, Development, and Demonstration (Fossil Fuels), House Committee on Science and Technology, p. 239.

As can be seen by the accompanying figure 1, coal has had a very erratic production rate in the past. Twice before in our history, coal production reached approximately 600 million tons annually, only to plummet down to almost half that amount. Production reached over 55-0 million tons during the period 1925-1930, only to fall to approxi ,mately 300 million tons with the advent of the Great Depression. Again, in World War 11, production reached over 600 million tons, only to gradually fall off to approximately 350 million tons by 1955.
However in an effort to stop the cycle, Congress made a significant policy decision in 1961 with the establishment of the Office of Coal Research. With this step and with increased funding for coal re-search, the Congress has encouraged the development of new uses and new markets for coal. The energy shortages early in this decade demonstrated the wisdom and foresight of that decision and reemphasized the necessity for developing coal. Congress, in passing the Energy Supply and Environmental Coordination Act, (P.L. 93319, 88 U.S. Stat. 246) provided authority in section 2 of the Act for the Federal Energy Administration to order oil and natural gas burning electric generators to convert to the use of coal. This established a national policy of converting our greatest energy resource users to the use of our most abundant resource--coal. This authority was reaffirmed by Congress by the passage of Public Law 94-385, the Energy Conservation and Production Act of 1976. With this national policy determination, we now can reverse the past trends of coal production oand instead of halving our production, we could double our production.

The U.S. Geological Survey estimates that there are 3.6 trillion tons of coal within 3,000 feet of the surface in the United States and 4.0 trillion tons within 6,000 feet of the surface. (See table 1.) However, the U.S. Bureau of Mines estimates that only 434 billion tons of coal is considered miinable with today's technology and economics; this amount is called the "demonstrated coal reserve base." (See table 2.) It should be remembered that only a certain percentage of the total (5 0-6O percent of underground mining by room and pillar techniques
and p t 90 forsuracemining) is recovered; the remainder is unavailable or lost during the mining process. The following table summarizes the demonstrated coal reserve base of the United nS ta te0s by coal rank and estimated total heating value.



Tons 650 600 550

Sooo /


400 350 300
1925 1930 1935 1940 1945 1950 1955 1960 1965 1970 1975

FIGuE 2-1.-Total bituminous coal production, 1925-74.

Source: National Coal Association statement by Carl E. Bagge before the Senate Committee on Public Works, June 10, 1975.


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Estimated total heat Reserves (billion tons) value
quadrillion Coal rank Underground Surface Total (Btu)

Bituminous....... ------------------------------------- 192 41 233 6, 100
Subbituminous----------------------------------- 98 67 165 2, 800
Lignite ........----------------------------------------- 0 28 28 400
Anthracite. --------------------------------------- 7 < 7+ 200

Total .------------------------------------- 297 137- 434- 9, 500

Source: U.S. Bureau of Mines, "Demonstrated Coal Reserve Base of the United States on Jan. 1, 1974," June 19, 1974, table 1.

The following maps (figure 2) show the location of the nation's coal

fields and the mining regions. Approximately two-thirds of the coal

reserve base is expected to be mined by underground methods and the

other one-third by surface methods.

1. Kentucky
2. West Virginia
3. Virginia
4. Tennessee
Region 2 S1. llinois 22. Indiana
3. Iowa 4. 4 Ohio
Region 3 .1. Pennsylvania Region 4
1. Colorado 2. Montana
3. New Merxico
4 Wyoming Region 5
1. Oklahoma Cost fields a 2. Kansas
3 Missouri Surface rainingon
1. North Dakota

1 West Virginta" ?. Pennsytianta Region 2
1. Aercer County. W Va I. 2 Mc~owetl County. 'A V3.
3 Wyomg Couvnty. W. Va. Fiegicci 3

2. Incana
3 Ohio
Region 4
1. Kentucii 2. Teinre~see
3 Virginia
Region 5 I U*3h
2. Colorado Region 6 Cool felds 1. Alabarna
Underground mirung *I>.e "s s .*: te te 1.>*: da ..
it. pC-. 1-t ( I o |. V -C'

FIGURE 2-2.-Coal fields of the United States.

Source: 1974 Keystone Coal Industry Manual.


[in millions of short tons]

Potential mining method
State Underground Surface Total

Alabama --------------------------------------------------------- 1,798 1,184 2,982
Alaska -- -------------------------------------------------------- 4,246 7,399 11,645
Arizona -------- ---------------------------------------------------------------- 350 350
Arkansas -------------------------------------------------------- 420 263 665
Colorado --------------------------------------------------------- 14,000 870 14,870
Georgia ---------------------------------------------------------- I -------------- I
Illinois ---------------------------------------------------------- 53,442 12,223 65,665
Indiana ---------------------------------------------------------- 8,949 1,674 10 623
Iowa ------ -- -------------------------------------------------- 2,885 -------------- 2' 885
Kansas -------------------------------------------------------------------- 1,388 1,388
Kentucky, east-.-------- ---------------------------------------- 9, i0- 3 450 12,917
Kentucky, west --------------------------------------------------- 8,720 3,904 12,624
Maryland-------- ---------------------------------------------- 902 146 1,048
Michigap -- ------------------------------------------------------ 118 1 119
Missouri --------------------------------------------------------- 6,074 3,414 9 488
Montana ------------- ------------------------------------------- 65,165 42,562 107:727
New Mexico ------------------------------------------------------ 2,136 2,258 4,394
North Carolina -- ------------------------------------------------- 31 (1) 31
North Dakota ------------------------------------------------------------------ 16,003 16,003
Ohio ------------------------------------------------------------ 17,423 3,654 21,077
Oklahoma ------------------------------------------------------ 860 434 1,294
Oregon ---------------------------------------------------------- I I
Pennsylvania ----------------------------------------------------- 29,819 1, 31,000
South Dakota ------------------------------------------------------------------- 428 428
Tennessee ------------------------------------------------------- 667 320 987
Texas --------------------------------------------------------------------- 3,272 3,272
Utah ------------------------------------------------------------ 3,*_ 262 4,042
Virginia -------------------------------------------------------- 2,971 679 3,650
Washington ------------------------------------------------------ 1,446 508 1,954
West Virginia----- ---------------------------------------------- 34,378 5,212 39 590
Wyoming -------------------------------------------------------- 27,554 231674 51:228
Total---- 297,235 136,713 433,948

Includes measured and indicated categories as defined by the USBM and USGS and represents 100 percent of the coal in place.
2 Less than 1,000,000 tons.
Source: Demonstrated coal reserve base of the United States on Jan. 1, 1974, Bureau of Mines.

Use of tonnage figures for U.S. coal reserves may be somewhat misleading. The subcommittee emphasized this fact in its hearings and
stressed that further consideration should be given to Btu content.


Billion Quadrillion
tons Percent Btu Percent

East ----------------------------------------------- 202.3 46.3 5,000 52.1
West ---------------------------------------------- 234.4 53.7 4,600 47.9
Total, national -------------------------------- 436.7 100.0 9,600 100.0

Includes anthracite.
Source: 1976 National Energy Outlook, FEA.
Note: As can be seen, the percentage of energy availability is reversed in this analysis.

2 law

One of the most important criteria for the marketability of coal
in the future is the amount of sulfur. The following tables 4 and a'
show a breakdown of the coal reserve base by State, by the percentage of sulfur in the coal, and by mining methods.

[In millions of short tonsl

Sulfur content, weight (percent)
State and mining method :51 1.1 to 3 >3 Unknown Total 2

Deep ---------------------------- 589.32 1,016.74 14.79 176.24 1,798.09
Strip_ 35.35 83.17 1.56 36.65 157.24
Deep ---------------------------- .33 0 0 .17 .50
Strip ---------------------------- 0 0 0 0 0
Deep ---------------------------- 1,034.68 5,848.37 33,647.64 12,908.44 53,441.86
Strip ---------------------------- 60.37 1,493.04 9,321.32 1,347.78 12,222.86
443.54 2,746.61 4,355.12 1,402 45 8,948.49
Strip ---------------------------- 105.25 559.23 907.20 101:56 1,674.08
Kentucky, eastern:
Deep ---------------------------- 5,042.70 2,391.88 212.67 1,814.03 9,466.48
Strip ---------------------------- 1,515.65 929.90 86.82 915.32 3,450.16
Kentucky, western:
Deep ---------------------------- 0 386.58 7 226.36 1,107.11 8,719.89
Strip ---------------------------- .22 177.83 2:017.45 1,708.69 3,904.02
Deep ---------------------------- 106.45 623.94 171.18 0 901.91
Sirip ---------------------------- 28.56 66.59 16.24 34.57 146.30
Deep ---------------------------- 4.59 84.93 20.78 7.03 117.64
Strip ---------------------------- 0 .49 .05 0 .56
North Carolina:
Deep ---------------------------- 0 0 0 31.25 31.25
Strip ---------------------------- 0 0 0 .37 .37
115.45 5,449.88 10,109.36 1,754.09 17 423.26
Strip ---------------------------- 18.87 990.96 2,524.87 117.93 3:653.89
Deep ---------------------------- 981.15 16,013.46 3,568.14 2,215.60 22,788.94
Strip ---------------------------- 55.45 717.21 231.52 83.57 1,091.07
Deep ---------------------------- 139.29 369.98 101.37 53.87 667.13
Strip ---------------------------- 65.54 163.19 55.22 34.12 319.59
Deep ---------------------------- 1,676.05 945.42 12.03 198.31 2,833.24
411.58 218.06 2.06 46.69 679.24
West Virginia:
Deep ---------------------------- 11,086.60 12,583.41 6,552.88 4,142.92 34,377.77
Strip ---------------------------- 3,005.46 1,422.82 270.40 509.55 5,212.02
Deep ---------------------- 21,220.15 48,461.20 65,992.32 25,811.51 161 516.45
Strip ---------------------- 5,302.30 6,822.49 15,434.71 4,936.90 32:511.40

I Includes only measured and indicated reserves.
2 Distribution may not add to total because of rounding.


[In millions of short tons]

Sulfur content weight.(pereent)
State and mining method <1. 0 1.1-3.0 >3. 0 UnknDwn TDta I

Deep ---------------------------- 4,080.8 163.3 0 0 4,246.4
Strip ---------------------------- 7,377.8 21.0 0 0 7,399.0
Arizona: Strip ------------------------ 173.2 176.7 0 0 350.0
Deep ---------------------------- 43.4 310.3 29.2 19.1 402.4
Strip ---------------------------- 37.9 152.9 17.1 55.2 263.3
Deep ---------------------------- 6,751.3 640.0 47.3 6,547.4 13,999.2
Strip ---------------------------- 724.2 146.2 0 0 870.0
Iowa: Deep -------------------------- 1.6 226.7 2,105.9 549.2 2,884.9
Kansas: Strip ------------------------- 0 309.3 695.6 383.2 1,388.1
Deep ----------------------------- 0 134.2 3,590.2 2,350.5 6,073.6
Strip ---------------------------- 0 47.8 1,635.8 1,730.0 3,413.7
Deep ---------------------------- 63,464,4 1,939.9 456.2 0 65,834.3
Strip ---------------------------- 38,182.5 2,175.4 46.4 2,166.7 43,562.0
New Mexico:
Deep ---------------------------- 1,894.4 214.1 .8 27.5 2, 1363
Strip ---------------------------- 1 681.1 579.4 0 0 2,258.3
North Dakota: Strip ------------------- 5:389.0 10,325.5 268.7 15.0 16,003.0
Deep ---------------------------- 154.5 238.4 202.6 264.3 860.1
strip ---------------------------- 120.5 88.2 38.8 186.2 434.1
Deep ---------------------------- 1.0 0 0 0 1.0
Strip ---------------------------- .5 3 0 0 .9
South Dakota: Strip ------------------- 103.1 287.9 35.9 1.0 428.0
Texas: Strip -------------------------- 659.8 1,884.7 284.1 444.0 3,271.9
Deep ---------------------------- 1,916.2 1,397.6 6.8 460.3 3,780.5
Strip ---------------------------- 52.3 149.2 42.6 18.0 262.0
Deep ---------------------------- 431.0 957.7 13.2 42.9 1,445.9
Strip ---------------------------- 172.5 307.7 25.8 2.2 508.1
Wyoming: Deep ----------------------- 20,719.1 4,535.0 1,275.6 2,955.0 29,490.8
Stri p ---------------------------- 13,192.9 10,122.4 425. 5 105.3 23,845.3
Total 1:
Deep ---------------------- 99,457.7 10,757.2 7,727.8 13,216.2 131,155.6
Strip ---------------------- 67,866.8 26,774.3 3, 516. 5,106.8 103,256.8
Grand total --------------------- 167,324.5 37,531.5 11,244.1 18,323.0 234,412.4

1 Distribution may not add to total because of individual rounding.

It should also be noted that much of the eastern low sulfur coal
that is readily mi-nable is now reserved for the metallurgical and export markets.
One of the final, but not least important considerations in the development of new coal fields is the recoverability of the resource. The
two most important factors to be considered here are the bed depth
and seam thfckness. Although both are major economic factors, bed
depth is often the more important. In 1965, the average depth of coal
being mined from the surface was 55 feet and the average seam thickness was 5.2 feet, giving a ratio of overburden to seam thickness of
roughly 10:1. This ratio has been increasing as mining technologies
have advanced, and a 30:1 ratio is now suggested as reasonable for the1970's.
For the development of our coal fields and managing the resource,
tbe Bureau of Mines divides the Nation up into four provinces-


Eastern,, Interior, Northern, and. Rocky Mountain. The Eastern province is comprised of three regions: Appalachian, Pennsylvania A-nthracite,, and Atlantic Coast. Th is province has more than eighty percent of the U.S.'s remaining identified high-ranked bituminous coal. The sulfur content of eastern coals varies consideraly app roximately 65 percent of the province's identified resources have a sulfur content of more than 1 percent. Surface water supplies in the province are abundant, and precipitation Averages between 35 and 50 inches per year.
The Interior Province is comprised of four regions: Northern, Eastern, Western, and Southwestern. Most of the coal in this region is bituminous, a small amount of anthracite in Arkansas being the exception. Except for low-volatile coal found in Arkansas and eastern Oklahoma, bituminous is' highly- -volatile. The 'moisture content is generally low except for coals in the northern part of the province, and sulfur content tends to be high, generally in excess of three percent. Although most of the province is well supplied with water, competition for its use is generally keen. The annual rainfall ranges from about 32 to 48 inches.
The Northern Great Plains Province is composed of six regions, the two largest being Fort Union and Powder River. Most of the coal within the province is relatively low in rank, with lignite in the Fort Union region and thick deposts of sub-bituminous in the Powder River region. Near the edge of the Rocky Mountains, the coal is somewhat higher in rank. The moisture and volatile matter content of both Fort Union and Powder River coals are relatively high and, as indicated by their low rank, both tend to be low in energy value. Water supplies are not abundant, and most of the surface water is found in the northern Missouri River drainage basin. Much of this water comes from -run-off from the mountains to the west. The average annual runoff ranges from less than 1 inch to 10 inches.
The Rocky Mountain province is composed of eight regions, the largest of which are the Green River, Uinita, and San Juan River. The Province has the greatest variety in ranks and geologic setting of any province in the U~nited States. Moisture content tends to be low and volatile matter content relatively high. Heating values range from 5,000 to more than 14,000 Btu's per pound. Sulfur content is generally low with almost 90 percent of identified resources having a sulfur content of 1 percent or less. Except for the high mountains, precipitation
-averages less than 16 inches per year, and large semidesert areas receive less than 8 inches. As a consequence, water is almost universally scarce in the province.
ByN' far the largest -single owner of the coal reserves in the LUnited StateIs is the Federal Government. The Federal Government owns aPProximately 48 Percent of all coal lands located in Alaska, Colorado. Montana, North Dakota, Oklahoma, Utah and Wyoming. Federal Ownership in these states ranges from 4 percent in Oklahom a to '97 percent in Alaska. In contrast, the major coal lands in-the eastern and western U.S. are privately owned.


With regard to private ownership, a study prepared by Mitre Corporation for the FEA, Analysis of Steam-Coal Sales and Purchases, concluded that the coal industry was top heavy; the top 15 companies control 47 percent of the market; the other 5,000 companies share the rest. However, the large coal companies are limited in their flexibility and their abillity to take advantage of fluctuations in coal prices. The Mitre study showed that these companies have 95-100 percent of their coal committed to long-term contracts. For the small companies interviewed by Mitre, the rate was 10-20 percent. These long-term contracts are traditionally between the coal producer. and the public utilities, and usually are drawn up for periods of thirty years. It should also be noted that many utilities themselves own coal reserves. For example, the Tennessee Valley Authority presently owns four tracts of miserable coal reserves: Red Bird, in Eastern Kentucky, Koppers in Tennessee, Franklin County in Illinois, and Breckenridge in Western Kentucky. TVA is presently receiving coal from two of
these tracts.
Recently, public attention has been focused on the acquisition of coal companies by some of the major oil companies, which has been occurring over the past decade. Weekly Energy Report stated that in many cases the recently acquired coal production divisions of certain oil companies meant the difference between loss and profit for those companies, citing Standard Oil of Ohio and Occidental Petroleum Company. The following table 2 shows the ownership of coal companies by some of the major domestic oil companies and their relative productions. The next table 3 shows the production by coal companies and their parent companies from 1964 to 1974. The original table provides the 7-company output as a percent total for the entire 10 years; however, by eliminating the production levels for the coal companies, in the years before acquisition by an oil company, the actual share of coal production by the oil firms can be seen. This is illustrated on the last line of the table which has been added by the subcommittee. That line illustrates the steadily rising percentage of coal production which is controlled by some oil firms.
1 Weekly Energy Report, August 4, 1975, p. 5.
2Submission of Exxon Co., U.S.A. (A Division of Exxon Corp.), before the House Judiciary Subcommittee on Monopolies and Commercial law, September 11, 1975.
Million Percent of
tons U.S. output Rank
Continental Oil (Consolidation Coal) ------- 51.8 8.6 2
Occidental Petroleum (Island Creek) ------------------------------- 20. 8 3. 5 3
Ashland-Hunt (Arch) ---------------------------------------- 13. 9 2. 3 8
Sohio (Big Ben) -------------------------------------------------- 9. 5 1. 6 10
Gulf Oil (Pittsburg & Midway) ------------------------------------- 7.5 1.3 13
Exxon ------------------------------ -------------------- 2.5 .4 37
Belco (Hawley Fuels).._. ----------------------------------------- 1.3 2 61
Total of oil companies- ---- ------------------------- 107' 3 17.9 .....
Total U.S. coal output ---------- .------ ------------- ._ ------------- 601.0 ------------------Source: Keystone News Bulletin, vol. 33, Nos. 2 and 3, Feb. 26 and Mar. 25, 1975.


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In the last ten years, the total production of coal has risen slowly.
By 1970 it reached 603 million tons, an. increase of 18 percent over the
1965 level, or a little over 3 percent per year. From 1973 to 1975,
however, U.S. coal production has held relatively constant at 590-600
million tons. (Prelimiary reports from the Bureau of Mines shows
a level of 665 million tons for 1976.)
The following table 8 shows production for 1971 and 1973 by state.


1971 1973
1973 tonnage Percent Percent Percent Percent
(millions) surface underground surface underground

Alabama----------------------------- 19.8 62 38 60 40
Alaska ------------------------------- .7 100 0 100 0
Arizona------------------------------ 3.0 100 0 100 0
Arkansas ----------------------------- .5 85 15 100 0
Colorado----------------------------- 6.2 38 62 46 54
Illinois ------------------------------ 61. 5 50 50 47 53
Indiana ----------------------------- 25.2 83 17 97 3
Iowa -------------------------------- .9 58 42 55 45
Kansas ------------------------------ 1. 100 0 100 0
Xentucky---------------------------- 127.0 55 45 so 50
Maryland ---------------------------- 1.6 89 11 97 3
Missouri ----------------------------- 5.0 100 0 100 0
Montana----------------------------- 10.0 100 0 100 0
New Mexico -------------------------- 9.3 88 12 89 11
North Dakota ------------------------- 7.4 100 0 100 0
Ohio------------------------------- 45.3 75 25 64 36
Oklahoma ---------------------------- 2.6 92 8 97 3
Pennsylvania ------------------------- 76.6 39 61 40 60
Tennessee---------------------------- 9.0 62 38 47 53
Utah -------------------------------- 5.1 0 100 0 100
Virginia ----------------------------- 33.9 29 71 31 69
Washington --------------------------- 3.2 97 3 99 1
West Virginia------------------------- 115.2 22 78 17 83
Wyoming----------------------------- 13.6 98 2 95 5
Other St3tes -------------------------- 6.9 ---------------------------- 100 0
Total-------------------------- 591.0 50 50 51 49

Source: U.S. Bureau of Mines.


13v far, the largest users of coal in the United States arie public utility electric powerplants. The present level (approximately 71 percent
of coal consumption) is a significant change from the earlier part of
thle century; for example, in 1935 coal consumption for generation
purposes stood at only 9 percent. This fact is illustrated by the following table 9.4

'"46Bituminous Coal Data," National Coal Assn.; U.S. Dept. of the Interior.

[in millions of tons]

Steel .and Retail
Electric Bunker Rail- Beehive Oven anrd mining dealer
power foreign roads coke coke rolling Cement in- deYear utilities trade (class 1) plants plants mills mills dustries liveries Total

1935 --- 30.9 2.3 77,1 9 1.5 49.0 16.5 3.5 94.5 80.4 356.3
1940 --- 49.1 3.0 85,130 4.8 76.5 14.1 5.6 107.8 84.6 430.9
1945---. 71.6 3.2 125,120 8.1 87.2 14.2 4.2 126.5 119.2 559.5
1950---. 88.2 2.0 60,969 9.1 94.7 10.8 7.9 95.8 84.4 454.2
1955 --- 140.5 1.5 15,473 2.9 104.5 7.3 8.5 89.6 53.0 423.4
1960 --- 173.8 .9 2,101 1.6 79.3 7.3 8.2 76.4 30~.4 380.4
1961---. 179.6 .8 (1) 1.5 72.3 7.4 7.6 77.2 27.7 374.4
1962 -- 190.8 .7 (1) 1.3 72.9 7.3 7.7 78.7 28.1 387.7
1963 --- 209.0 .7 (1) 1.6 76.0 7.4 8.1 82.7 23.5 409.2
1964 --- 223.0 .7 (1) 2.0 86.7 7.3 8.7 82.9 19.6 431.1
1965 --- 242.7 .7 (1) 2.7 92.0 7.4 8.9 85.6 19.0 459.1
1966 --- 264.2 .6 (1) 2.4 93.5 7.1 9.1 89.3 19.9 486.2
1967-- 271.7 .5 (1) 1.4 90.9 6.3 8.9 83.5 17.0 480.4
1968--- 294.7 .4 (1) 1.3 89.4 5.6 9.4 82.6 15.2 498.9
1969 --- 308.4 .3 (1) 1.2 91.7 5.5 (34) 85.3 14.6 507.2
1970 --- 320.4 .3 (1) 1.4 94.5 5.4 (1) 82.9 12.0 517.1
1971--- 326.2 .2 (1) 1.3 81.5 5.5 (4) 68.6 11.3 494.8
1972---. 348.6 .2 (1) 1. 1 86.3 4.8 (4) 67.1 8.7 512.7
1973---. 386.9 1 (1) 1.2 92.3 6.4 (4) 60.8 8.2 556.0
19742_ 391.0 .1 (1) 1. 1 90.0 6.4 (4) 60.0 8.0 551.3

1 Canvass discontinued.
2 Preliminary.
3 1969 consumption figures were revised. No revised breakdown between "Cement mills" and "Other manufacturing and mining industries" was available.
4 Included with "Other manufacturing and mining industries" 1969-74.
Sources: "Bituminous Coal Data," National Coal Association; U.S. Department of the Interior.

However, despite the predominance of electric generation as a consumer of coal, the converse is not also true. Coal has been steadily
declining in its share of the electric generation market. The tendency
to use boiler fuels other than coal has accelerated, particularly in the
1960's. -Most new fossil fired plants were designed for oil and natural
gas, and in addition, from 1965 on an increasing number of existing
boilers we re converted from coal to oil. Between 1965 and 1972, 398
boilers withl a total name plate capacity of 28,785 megawatts were
In the early 1960's, most of these conversions f rom coal to oil were
based on economics. It was che-aper to import residual oil1 to burn in
east coast power plants than to sipj coal from Appalachian areas.
.In some cases, particularly in urbanized areas later in the decade, air
pollution regulations motivated the switch. As the Clean Air Act
Amendments of 19 70 made their way thi'oughi Congress. environmental
concerns became more important and the pace of conversions quickened, peaking in 1971 and 1972.
Despite the legislation which motivated electric powerplants to
switch from coal to oil, -coal also appeared uneconomic. Estimates


of 1972 capital Costs Der kilowatt of installed capacity for plants with
no stack gas cleaning are $180 for coal, $150 for oil, and $100 for gas.3
Clearly, if coal is to play a major role in our future energy supOies,
new research and technological development must occur in order to
improve the position of coal.
Despite the unfavorable environmental and cost characteristics of
coal fired venerating plants, the National Coal Association predicts a
significant" increase in the number of coal fired electric generation
plants in the next five years. The NCA has prepared a study of announced electric generating units scheduled to go on-stream during
the remainder of this decade. The conclusions of this studv are in the
following table 10. The announced coal fired units that W'11 come onstream during this period will require 203.5 million tons of coal annually. Furthermore, recently announced conversion orders from FEA
would increase the demand for coal b 1978 to 16.2 million tons annually. This is accomplished gradual-T in steps beginning with the
demand of 0.7 million tons in 1975, 4 million tons in 1976, and 13.6
million tons in 1977.

Energy Alternatives: A comparative analysis, by the Science and Public Policy Program, University of Oklahoma, Norman, Oklahoma, p. 12-21. The authors of this report note that present construction prices have increased significantly. The ABC estimated capital costs at $66OKW for nuclear and $55OKW for coaf-in 1974, just 2 years later.


Associated Associated
Number of capacity Number of capacity
State units (megawatts State units (megawatts)

Connecticut ------------------ 0 ------------ South Carolina --------------- 2 630
Maine ----------------------- 0 Vi '"*,a---: ------------------ 0 -----------Massachusetts--------------- 0 ------------ West rginia ----------------- 3 2,576
New Hampshire-------------- 0 -----------Rhode Island -- -------------- 0 ------------ South Atlantic, total---- 13 9,427
Vermont --------------------- 0 -----------Alabama -------------------- 4 1,720
New England, total--- 0 ------------ Kentucky ------------------ 4 1,720
Mississippi- 3 860
New Jersey ------------------ 0 ------------ Tennessee------------------- 0
New 0 -----------Pennsylvania---------------- 4 3,125 East south-central, total- 11 41300
Middle Atlantic, total---- 4 3,125 Arkansas-------------------- 4 4,229
Louisiana -------------------- 2 1,125
Illinois ---------------------- 7 3,315 Oklahoma------------------- 4 2,161
Indiana --- ------------------ 9 5,049 Texas ----------------------- 17 10,054
Michigan -------------------- 2 140
Ohio ------------------------ 7 3 715 West south-central, total- 27 15,769
Wisconsin____________------- 3 10373
Arizona- 8 3,156
East North-central, total- 28 13,592 Colorado-------------------- 6 2,070
0 -----------Iowa ------------------------ 4 2,045 Montana -- ------------------ 4 2,106
4 2,305 Nevada ---------------------- 3 500
2 1,440 New Mexico ----------------- 2 820
Missouri --------------------- 5 2 459 Utah ------------------------ 2 800
Nebraska -------------------- 3 1:316 Wyoming -------------------- 5 2,330
North Dakota ---------------- 4 1,899
South Dakota---------------- 1 440 Mountain total --------- 30 11,782
West North-central, total- 23 11,904 California ------------------ 0 -----------0 -----------Delaware -------------------- 1 400 Washington ------------------ 0 -----------District of Columbia -- -------- 0 -----------Florida ---------------------- 1 445 Pacific total ------------ 0
Georgia------ 3 2,856
Maryland -------------------- 0 ------------ N allonal total 136 69,898
North Carolina --------------- 3 2,520

Source: Statement by Carl E. Bagge of the NCA before the Senate Committee on Public Works, June 10, 1975.

The hearing testimony revealed that there had been no significant breakthroughs in coal combustion technology since the late 1920's. While there apparently had been a gradual improvement in coal combustion technology and power generation efficiency, there had been nothing in the way of a new technology or dramatic change in this field. The only thing on the horizon was the atmospheric fluidized bed boilers which will not be commercially operative until about 1980-85.
Members of the subcommittee expressed concern that the research and development program on fluidized bed technology being conducted by ERDA, has only recently been accorded the high priority which it deserves. The 30 MlVe fluidized bed boiler project, being constructed by ERDA at Rivesville, West Virginia was begun in October, 1972, and is actually an extension of a program which began in 1965. Witnesses testified that there had been an 18-month delay in the projected construction time due to longer order times than normal, in this inflationary period, and because of changes in West Virginia's environmental standards. While such delays are not unusual, some precautionary planning can be made. At the time this report was written, ERDA was requesting authorization for a 200 MWe fluidized bed combustion demonstration plant.
However, despite the fact that the Government's program was started only a decade prior, the fluidized bed concept has been utilized for some time.
The technology for fluidized bed combustion has its origins in petroleum engineering; a number of refinery operations are based on fluidized bed technology. The coal combustion technology is really building on oil industry knowledge of fairly large fluid beds of twenty to forty feet in diameter, where much of the engineering experience has been gained over the years.
The Federal government's program began approximately five years after the creation of the OCR. In February, 1965, the Office of Coal Research awarded the construction firm Pope, Evans and Robbins a contract to build and operate a small atmospheric fluidized bed boiler. The objective of the program was to attempt to meet rigorous air pollution standards while burning high-sulfur coals and simultaneously eliminate ash, fouling, and sagging problems. This small pilot plant accomplished these goals and also indicated the promise of improved power plant efficiency and cleanliness when burning, chars, anthracite, or conventional coal, 'and the possibility of eliminating the need for pulverization of the coal feed.'
I See "Study of the Characterization and Control of Air Pollutants from a Fluidized Bed Boiler-The S02 Acceptor Process" by J. S. Gordon, et al; Pope, Evans and Robbins, Inc.-EPA-R2-72-021, July 1972.


Pope, Evans and Robbins was awarded another OCR contract in May, 1972, to perform additional experimental work on a small (0.5 Mw) unit. Four types of fuels were burned to demonstrate the feasibility of fluidized bed combustion and to examine the effect of lignite, high-sodium content. One of the major results of this contract was to show that sulfur-oxide emissions were reduced to levels well below the emissions standards of existing and proposed Federal and local regulations. The project also indicated that the addition of small quantities of common salt to the fluidized bed was a, useful method for increasing limestone utilization.
The Office of Coal Research also awarded a contract in October, 1972, to design, construct, and operate a 30 MWe size multicell fluidized bed boiler under practical utility conditions. Steam pressure and temperature conditions of the boiler were designed to meet the requirements of the site at which the boiler was installed-the power plant of the Monongahela Power Co. at Rivesville, W. Va. The Foster-Wheeler Energy Corp. was awarded the contract for the construction of this boiler. The following figure is a schematic diagram of this facility.




1.p.Cal Sec(tlo thrU Cois

Fluidized Bed Steam Generator Multicell
Demonstration lnit Indicating the heat transfer
surface arrangement.

During 1974, shop fabrication of the 30 MWe boiler was completed in the field direction work and the Monongahela Power Co. powerplant was started. Auxiliary systems and plant general construction including boiler and plant controls, and laboratory construction work was also started in 1974. Boiler installation was completed during 1975 and operations started in 1976.

This type of fluid bed combustor seems to offer the greatest potential for early commercialization, possibly by 1979. It also appears to be very attractive for industrial use and for utility applications because it improves combustion efficiencies, significantly reduces emission levels, has a very attractive capital costing, and can use the cheaper, highsulfur coal.
The subcommittee received testimony that the costs of the fluidized bed boiler, when compared to a conventional boiler with stack scrubbing, were very favorable. For power plants operated in a base-load mode (average annual capacity factor about 65 percent), the cost of power generation is the same for the two types of boilers. EPRI supplied the following table of estimated costs:

Power plant
capital costs Power costs,
dollars per cents per
Boiler type kilowatt kilowatt hour
Atmospheric fluidized bed__--530 3.1
Conventional boiler with stack gas scrubbing ----------------------------------- 50 3. 1

The above capital costs for complete power plants are based on 1975 construction costs and include engineering fees, contingency, interest during construction and start-up costs. Power costs are based on coal costs of $1/MMBTU (about $21/short ton), and limestone costs of $97 short ton.
The capital costs of the fluidized bed plant are about 10% lower than for the conventional plant. This cost advantage is largely due to the fact that the fluidized bed boiler is much smaller than a conventional boiler with a similar rating, due to the higher heat-transfer capability of the fluidized bed. Some cost saving is also anticipated from shop fabrication of modular fluidized bed boilers against more expensive field fabrication of conventional boilers.
Operating costs for the fluidized bed plant may be higher however since limestone consumption is estimated to be three to four times greater than for the stack gas scrubbing system. First of all, the unit size is smaller because fluid bed combustion can increase volumetric heat release rates by as much as an order of magnitude above rates realized in present combustors. Overall heat transfer rates are improved correspondingly. Also, boiler tubes spacing can therefore be much closer than in conventional fixed-bed boilers, providing unit compactness.
Emission control for fluidized-bed boilers centers in the combustion zone. Sized coal is burned in a fluidized bed of inert ash and limestone or dolomite. The limestone or dolomite reacts with SO_ to form a solid sulfate material. Owing to increased thermal efficiencies, fluid-bed boilers can be operated at bed temperatures lower than conventional boilers thus inhibiting the formation of nitrogen oxides. An atmospheric pressure coal-fired fluidized-bed boiler having a capacity of 5,000 pounds of steam per hour has been successfully operated at furnace temperatures of approximately 1,600 degrees Farenheit. It has


demonstrated that all types. of coal can be burned in an environmentally acceptable manner.
One problem that has not been solved is the matter of handling the limestone sorbent after it is no longer active. There are two approaches being expl(wed at the present time .One is to collect the limestone and to simply dispose of it in an acceptable manner, many options of which are being pursued. Because it comes out dry, it presents no material handling problem, as opposed to the wet sludge which is the byproduct of stack gas treatment. The other approach being pursued is to regenerate or reactivate the limestone, recirculate it, and remove the sulfur in the elemental form for disposal. The Subcommittee received testimony that a number of companies were investigating the use of limestone sorbent as land-fill material. It is attractive to them because it is dry, only partially sulfated, and contains -ash and other aggregate material. Conversion to an acceptable land-fill material would be easier with this sort of partially-sulfated limestone than with the wet sludge from scrubbers. ERDA has also supplied samples of the limestone sorbent to a few agricultural firms for- -use as a soil conditioner. In 1974, peanuts were successfully grown using this spent limestone in place of lime and other nutrients, that are required in the soil.
Members of the Subcommittee noted that the disposal of these large volumes of waste was a significant environmental problem. Agency officials who testified felt that these problems were being dealt with and can be solved.
Another dimension to this disposal problem is the investigation of alternative sorbets for the fluidized bed boiler, such as dolomite in addition to limestone as a natural material. Also, the Argonne National Laboratory is investigating creating a synthetic material which contains lime, that could be regenerated without losing the lime. It is in the form of p pellets that could be easily recirculated and re-used without loss of lime or any of the other active ingredients.
The members of the Subcommittee were impressed by the versatility of the fluidized bed concept. The fluidized bed boiler can burn a number of materials. It can burn culm, which is a. waste material with anthracite in it, or gob, which is a similar waste material but with bituminous coal in it. ERDA is also testing chars which are a product of the gasification process. The fluidized b ed must be designed for a specific sized fuel material. Variation in size of the fuels or wastes to be burned would mean that a fluidized bed would have, to. be re-equipped to take various sizes. The size problem arises in the dynamics of the bed. The gas in the bed supports particles that are not all identical, but of a fairly uniform size. Very fine particles fly off the top and are captured by the precipitator, while the larger particles would rapidly settle to the bottom and not be combusted. Therefore where particle size is uniform with deminimus variations, the problem is manageable. However, where there is a broader range of sizes, the problems accelerate beyond control.
This is the next generation of technology for fluidized beds and will result in considerable increases in thermal and design efficiencies.


The basic technology for the pressurized system is similar to the atmospheric system except that the coal and bed material must be injected into a pressurized combustion chamber and the process converted to a combined cycle system.
The higher through-put capability of pressurized systems further reduces the size of the" combustion unit. The use of combined cycle systems (steam and gas turbine) will increase the overall plant efficiency (coal to power) from 39 percent for atmospheric boilers to 43 percent for the pressurized systems, with a potential of exceeding 50 percent.
Objectives for the pressurized program are similar to the atmospheric, except that developmental problems are greater and more complex, and the first commercial units would be at least 2 years further down the road. Limited tests of American coals were performed in a 5-6 atmospheres pressure test unit at Leatherhead, England and have shown that this approach is feasible from a technological standpoint.
For the past 7 years, Combustion Power Co., Inc. of Menlo Park, Calif. has been conducting a research and development program under the sponsorship of EPA, to convert the heat energy of solid wastes to electrical energy through the use of its pressurized fluidized bed and gas turbine system. With the cooperation of EPA, OCR contracted with Combustion Power in June of 1973 to conduct a research and development program to demonstrate the combustion of high-sulfur coal in this system. Z
Under the current contract, CPC has conducted evaluations of coal combustion in a model of this combination combustor. using caking and non-caking high-sulfur coals. The caking coal used was lower Kitt anfing seam; the non-caking coal used was Illinois No 6. The coals w ere tested at various pressures and temperatures.
CPC then modified the fluidized bed system to provide the capability for coal and dolomite storage and feeding. This modified system became the process development unit. Long-duration tests were conducted in this process development unit, using the data from the model experiments to determine and minimize cihaust emission levels of noxious gases and particulates. In addition, candidate turbine blade materials and coatings were installed in the turbine rotors and stators to evaluate corrosion and erosion effects.
The results of the test indicated that the dolomites used were effective in suppressing SO2, the relative effects of superficial velocities and bed temperatures was slight, and the optimum calcium-sulfur ratio was 1.5. Limestone was consistently ten to fifteen percent less effective than dolomite under all test conditions. The most serious problem encountered during the test was that the separators installed in the process development unit were found to be inadequate to insure acceptable turbine blade life or to meet current EPA particulate exhaust emissions standards. Further engineering is being conducted.
Supporting studies are being carried out at the Argonne National Laboratory under the sponsorship of ERDA. Initial research and development of the pressurized fluidized bed combustion done by this laboratory included eleven experiments to measure the effects on variables of temperature, fluidizinge gas velocity, and ratio of calcium content of the dolomite to the'surfur content of the coal. In these


experiments, Pittsburgh seam coal was burned at 8 atmospheres in a 3-foot-high fluidized bed and with 3 percent oxygen in the flue gas. The results indicated that:
(1) For calcium ratios above 2.0, more than 90 percent of the
sulfur dioxide was retained in the dolomite bed; the amount retained decreased as the calcium-sulfur ratio decreased.
(2) Nitrogen oxide levels were extremely low, ranging between
0.40 and 0.15 pounds of nitrogen oxide per million Btu, as compared to the EPA emission sta: dards of 0.70.
(3) Combustion efficiency varied directly with combustion temperature, ranging from about 89 percent at 1,4501 F to about 97
percent at 1,6501 F.
(4) Values of heat transfer coefficient varied directly with gas
velocity, ranging from about 40 Btu/hour per sq. ft. per degree
at a gas velocity of about 2 ft./sec to about 115 at 5 ft per see.
Although electric -utilities have received the most attention with respect to potential for conversion to coal,. American industry consumes more total energ and more energy-primary fuels than utilities.
In 1974, industry consumed about 40 percent of total U.S. energy input, including about 42 percent of total electricity. About 10 to 12 percent of the energy materials used directly by industry (other than coking plants) goes to feedstocks, the rest for fuel. The fuel is used for direct process heat (about 40 percent) and for steam (about 60 percent). About 30 percent of the steam is used to generate electricity.
Industry boilers have firing rates generally between 100,000 to 200,000 pounds of steam per hour and there are thousands of them. Only about 25 percent of all industrial steam is produced in plants generating 1 million pounds per hour or more, and about half in plants generating 250,000 pounds per hour or more.
Industrial energy consumption is concentrated in six major industries. Primary metals, chemicals, petroleum refining, food, paper, and stone, clay, and glass account for about 70 percent of total industry consumption.
Thus a technological breakthrough which would allow industry to convert to coal could have a significant impact on our national consumption of oil and gas.
ERDA is conducting a project which will consist of a, feasibility study and preliminary design for potential industrial and institutional application of pressurized fluidlized-bed concepts. The design, construction, and operation of prototypes on industrial and/or institutional sites for such purposes as captive in-plant g generation of power, Ilse of surplus heat for space heating, manufacturing processes, waste disposal, and so forth, will follow.
Although industrial boiler and process heater needs are quite diversified, a relatively small number of equipment configurations define the majority y of applications. Thus, key components can be constructed on an industrial scale to determine the' applicability of fluidized-bed combustors to industrial units.


ERDA has issued a program opportunity notice (PON) covering four different categories of industrial fluidized-bed boilers and process heaters. This PON identifies four categories of application of the fluidized bed concept, i.e., indirect steam generator, industrial boiler, indirect and direct fired heaters. The PON was released Septemiber 11, 1975, and thirteen responses were received. On June 17, 1976, ERDA announced that eight groups had been chosen to negotiate contracts. Contractors will share up to 50 percent of the costs.
Members of the subcommittee expressed a desire during the hearings to see more work done on the potential for retrofitting industrial and powerplant boilers. It was their opinion that such retrofitting would accelerate the utilization of coal in our Nation's economy. However, most of the testimony received showed a reluctance on the part of the utilities and industry to investigate the retrofitting option. In many cases this was based on a lack of information or misinformation as to outage times and economics. In fact, testimony that was received on an example of an industry retrofitting its boilers, showed that it occurred during a period of the most extreme emergency, i.e., ti cutoff of fuel. The subcommittee hopes that ERDA's program for the retrofitting of industrial boilers will include cooperation and coordination with industry to maximize the retrofitting option.


A logical next step in this review is the examination of the existing solutions to the problems of coal combustion and clean-up. To begin, the presently available systems for direct combustion of coal will be examined. There are three such'-systems: pulverized-coal systems, bin
systems, and direct-firing systems.

The fuilction of a pulverized-coal system is to pulverize the coal, deliver it to the fuel-burnig equipment, and accomplish complete combustion in the furnace with a minimum of excess air. The system must operate as a continuous process and, within specified design limitations, the coal supply or feed must be varied as rapidly and as widely as required by the combustion process.
*A small portion of the air required for combustion (15 to 20 percent in current installations) is used to transport the coal to the burner. This is known as primary air. In the direct-firing system, primary air is also used to dry the coal in the pulverizer. The remainder of the combustion air (80 to 85 percent) is introduced at the burner and is known as secondary air.
The two basic equipment components of a pulverized-coal system are:
(a) The pulverizer which pulverizes the coal to the fineness
(b) The burner which accomplishes the mixing of the pulverized-coal-primary-air mixture with secondary air in the right proportions and delivers the mixture to the furnace for
Two principal systems-the bin system and the direct-firing system-have been used for processing, distributing and burning p-ulv-erized coal. The direct-firing system is the one being installed almost exclusively today.
The bin system is primarily of historical interest, although a large number of units of this type remain in operation. Its use was required before pulverizing equipment had reached the stage of development where it could be relied upon for uninterrupted operation, flexibility and consistent performance.V
In this system the coal is processed at a location apart from the furnace, and the end product is pneumatically conveyed to cyclone collectors which recover the fines and clean the atmosphere. The pul(41)


verized coal is discharged into storage bins and later conveyed by pneumatic transport through pipelines to utilization bins which may be as far as 5,000 ft. from the point of preparation.
Although bin systems installed in older plants are still operating quite satisfactorily, this system is no longer competitive with the direct-firing system. Furthermore, the drying transportation and storage of pulverized coal other than anthracite, involves a fire hazard from spontaneous combustion.

The bin system has been superseded by the direct-firing system because of improvements in safety conditions, plant cleanliness, greater simplicity, lower initial investment, lower operating cost, and less space requirements.
The pulverizing equipment developed for the direct-firing system permits continuous utilization of raw coal directly from the bunkers where coal is stored in the condition in which it is received at the plant. This is accomplished by feeding the raw coal directly into the pulverizer, where it is dried as well as pulverized, -and then delivering it to the burners in a single continuous operation.
There are two direct-firing methods in use-the pressure type, which is more commonly used, and the suction type. In the pressure method, the primary air fan, located on the inlet side of the pulverizer, forces the hot primary air through the pulverizer where it picks up the pulverized coal, and delivers the proper coal-air mixture to the burners. In the suction method, the air and entrained coal are drawn through the pulverizer under negative pressure by an exhauster located on the outlet side of the pulverizer.
Finally, it should be noted that there are significant differences between coal-burning power generation systems and oil-burning systems. Therefore, plans to convert oil burning plants which have not been designed to use coal require not only particulate and sulfuroxide emission controls, but additional power generating capacity as well. Any boiler which uses coal to produce electricity generally is less efficient than a boiler that operates on oil.

Members of the Subcommittee raised the issue durn the hearingIs about what excess capacity exists in the electric utility business. If little new capacity is needed before 1980 or 198.5, then the foc-us of research f unding would change. It would also indicate whether or not any new techinology would be assimilated into the economy quickly, with expansion, or only as replacements, as unit life expires. If the latter is the case, then the technology of retrofitting existing boilers should be vigorously pursued. Z
Electricity cannot be efficiently stored, causing the electric utility business to operate its supply and demand relationships in essentially instantaneous terms. Energy consumption in peak capability (installed and available 1Kw) are important subjects to the


utility business. Daily, weekly, and seasonal variations in load affect both of these and require that some power generation units be predominantly steady-state (base-load). Other units vary with load swings, and yet others start up solely to meet short-term peak demands. The accompanying figure shows a typical weekly electricity demand:


17 5
_n 9

-.'' '
C Pumped-Storap Hydroelectric .7 NUCLEAR & FOSSIL
2 "': 00 Conventional Hydroelect~ric UNITS
2 .* : .. UNITS
S,,. -E= Nuclear or Fossil-Fueled Stearn-Electric
%.t. r Pumping Energy Supplied by Nuclear or Fossil-Fueled Steam-Electric Plants '
0 .
FIGURE 4-1.-U.S. typical weekly electricity demand.
Source: "U.S. Engineering Prospects; An Engineering Viewpoint," NAE, 1974, p. 50.

As can be seen from this typical-demand chart, there is a portion of reserve capacity. Testimony received by the subcommittee concluded that this excess capacity was almost entirely used up, in normal operation. This excess capacity is relied upon for general maintenance and for unexpected and unscheduled outages. In discussion with the witnesses, the members also concluded that this reserve capacity could not be relied upon for the flexibility necessary in outages for retrofitting existing plants. It could therefore be concluded that such existing excess capacity was normal operating procedure and did not indicate any "slack" in our Nation's electric generating capacity.
Finally, consideration of testimony by the National Coal Association showed a substantial increase in the number of coal-fired electric generation plants over the next five years.' Thus excess capacity is not an alternative to further research on new coal combustion technologies because new units are needed and will be constructed in the future.
1 136 new units planned or committed. Testimony by Carl Bagge before the Senate Committee on Public Works, June 10, 1975.



EPA in a report required by the Energy Supply and Environmental Coordination Act said that of the 390 million tons of coal used in power plants in 1974, 194 million tons would meet requirements contained in State air quality implementation plans. Of the remainder, the use of 85 million tons are subject to litigation and 111 million tons are nonconforming. Plans have been developed for compliance where 46 million tons of noncomplying coal are burned, but have not been developed for the remaining 65 million tons.
This problem of noncomplying power generation plants could conceivably be solved by the use of this Nation's vast supply of low-sulfur coal. The U.S. Bureau of Mines estimated in 1974 that east of the Missisippi there were 33 billion tons of high-Btu coal, with one percent or less sulfur content. The table which follows is the latest estimate by the U.S. Bureau of Mines of total coal reserve base according to sulfur range:

In millions of tons]

Sulfur range, percent
Less than 1 i to 3 More than 3 Unknown Total

East of the Mississippi River:
Underground minable-------------- 27,471.2 48, 642.9 65,992.3 26, 545.5 168.684. 2
Surface minable------------------ 5, 385.4 6, 823.7 15, 434.7 5,969.3 33,628.2
Total------------------------ 32, 856.6 55, 466.6 81, 427.0 32, 514.8 202,312.4
West of the Mississippi River:
Underground minable-------------- 99, 457.6 10, 757. 3 7,727.9 13,216. 1 131, 155.5
Surface minable------------------ 67, 866.8 26, 773.7 3,516.2 5, 106.8 103,257.5

Total ----------------------- 167, 324.4 37, 531.0 11, 244. 1 18,322.9 234,413. 0
Total east and west of the Mississippi
River -------------------------- -200, 181.0 92,997.6 92,671. 1 50, 837.7 436,725.4
Underground minable:
East of the Mississippi River ---------27, 471.2 48, 642. 9 65, 992.3 26, 545.5 168,684.2
West of the Mississippi River ---------99, 457. 6 10, 757.3 7, 727. 9 13,216. 1 131, 155. 5
Total------------------------ 126, 928.8 59, 400. 2 73, 720.2 39,761.6 299, 839.7
Surface minable:
East of the Mississippi River--------- 5,385.4 6, 823.7 15, 434.7 5,969.3 33,628.2
West of the Mississippi River --------67,866.8 26,773.7 3,:516.2 5, 106.8 103,257.5
Total------------------------ 73,252.2 33, 597.4 18,950.9 11,076. 1 136, 885.7
Total underground and surface minable --- 200,181.0 92,997.6 92, 671. 1 50,837.7 436, 725.4

I Data may not add to totals shown due to rounding.
Source: U.S. Bureau of Mines Mineral Industry Survey, Demonstrated Coal Reserve Base of the United States by Sulfur Category, on Jan. 1, 1974, publIished May 1975.

This shows an amazing total of -over '200 billion'tons of minable low-sulfu r coal available in the United States.
However, -there is an economic tariff that must be paid in converting to low-sulfurcoal. Electric Power Research Institute estimates that the capital cost of converting a coal-burning plant from high-sulfur coal to low-sulfur coal varies with plant size, averaging about $20 per


kilowatt of electric generating capacity. This expense includes minor boiler modifications plus upgrading of the particular emission control mstem. Low-sulfur coal prices, although highly variable, are generally higher than for high-sulfur coals. EPA estimates this differential at from 10-250 per million Btu on an average cost of about 700 per million Btu of coal.
However, these economic considerations may soon be eclipsed by more stringent environmental standards. Proposals for achieving national sulfur oxide ambient air quality standards require that approximately 80 percent of all coal consumers in existing powerplants in the United States after 1975 be less than I pound sulfur per million Btu. The Environmental Protection Agency's new source performance standards will similarly require all new coal-fired powerplants to consume coal with less than 0.6 lb. sulfur per million Btu.
The Western coal from the Rocky Mountain Region at the 0.6 lb. sulfur per million Btu level could potentially support Eastern coal burning steam generation demands for many years. However, 1974 Western production for electric generation is only estimated at 60 million tons per year, and the most optimistic 1985 production estimates
are set at only about 116 million tons per year.
With these difficulties arising in increased production of Western coal I it seems apparent that we should explore the possibility of increased production of Eastern low-sulfur coal. The U.S. Bureau of Mines estimate that there is approximately 32.8 billion tons of lowsulfur coal in the East,3 with 13 billion tons of recoverable low-sulfur,
deep-mined bituminous coal in West Virginia alone.
Testimony revealed that the increased production of low sulfur coal had not been seriously considered by the utility industry as an alternative to technologically intensive solutions. EPRI testified that they considered the option of installing new facilities for low sulfur coal to be equally desirable as the high technology solutions, where costs were eq talent. However to date, the level '5'T production necessary to j usti their reliance on ) this option has not come forth, requiring them to pursue these technologically intensive solutions.
Members of the subcommittee felt that the low sulfur coal reserve base represented a very real alternative to further capital expenditure by utilities for new technology, to burn coal in an environmentally acceptable manner. However, recognizing the large capital expense req1ured to open new mines, members of the subcommittee wished to see further refinement of the data. They wanted to know the amount of coal which can be obtained from either existing deep mines that are currently in operation or from those deep mines that have been shut down in the Eastern United States. Discussion between the panel and the witiiesses revealed that Bureau of Mines does not seek this data,.on the basis that this is proprietary information of the coal coinTanies. Members felt, however, that this presented a real alternati-v further funding of research, and that ERDA should consider this question jointly with the Bureau of Mines and others; ERDA agreed to research this matter.
2 Carl Bagge, NCA, Ibid.
3 U.S. Bureau of Mines Mineral Industrial Survey, January 1, 1974, published Afay, 1975. A Ibid.


Further testimony from EPA indicated that the low sulfur coals of the West may provide further environmental problems. EPA stated "Under the present environmental control standards set by the Environmental Protection Agency, many of the low sulfur coals will meet the standards, both sulfur dioxide and particulates, at the present time. It depends, though, critically on the nature of the coal. The very good eastern coals, such as Mr. Hechler referred to, will meet both the particulate and the sulfur dioxide standards without difficulty. However, as you move into the west, some of the coals are really quite different. They have lower Btu content; they have higher ash content; and there are problems in that some of the coals which might have a .7% sulfur by weight would not meet the sulfur dioxide emission standards or the particulate emission standards because of the different problems which are created by the lower heat content, the high ash content."
Such testimony indicates that the eastern coals should be at least as vigaorously developed as the western low-sulfur coals.
Flue gas destilfuirization, the center of a continuing controversy, is a relatively new technology for electric utilities. Part of the controversy relates to the question of its reliability in operation, part to its demand for capital, and part to its necessity compared to other control options, particularly tall stacks and noncontinuous controls.
As of October, 1974, there were 19 flue g-as desulfurization (FGD) systems in operation in the U.S. on units with electric generating capacity of 3,291 megawatts. Eighteen units were under construction, nine construction contracts had been awarded, and an additional 53 systems were under cosdrain
EPA, in its report (dated Februiary, 1975), lists flue gas desulfurization (FGD) among the available compliance options and claims that "newer units are expected to realize 95 to 99 percent availability over long time periods" and that "the lime/limestone scrubbing, MagOx, and Cat-Ox processes are the most advanced and hold the greater promise for near-term commercial applications." An NAS-NAE-NRC report, however, does not consider Mag-Ox and Cat-Ox as having been operated long enough on coal-fired units to provide a basis for judgment of availability. Another report, by the AEC to the Council on Environmental Quality, however, agreed with EPA and rated the magnesium oxide and catalytic oxidation systems as being the most readily available for commercialization purposes. The results of that study appear in the following table:
5 EAReport, February 1975,, EPA-450/1-75-OO1.

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During the hearings, the Subcommittee received testimony from EPIRI on the details of operating FGD and some problems that have been encountered therewith. EPRI testified that there were, at present, two FGD systems:
Throwaway systems, in which spent materials must be disposed of, and "tregenerative"l processes, wherein saleable products are produced. For both system types very limited full-scale experience has been obtained. The operating procedure for throw-away systems calls for the flue gas to be scrubbed with a 5 to 15 percent slurry of calcium sulfite/sulfate containing small amounts of continuously added lime or limestone. The resulting reaction converts the sulfur dioxide gas to a slurry sulfate or sulfite. These processes require a scrubber incorporating liquid contactors and mist eliminators, gas fans, ductwork, and dampers and gas reheaters to restore plume bouyancy. If fly ash particles are not removed by an electrostatic precipitator, the scrubber system must be designed to allow for particulate as well as SO2 removal. The processes are complicated by simultaneous dissolution and crystallization of the solids in the scrubber. Calcium scaling and plugging can occur in the scrubber and demister, and sufficient residence time and liquid recirculation must be provided for reaction of the solids with the sulfur dioxide. In addition, the high solids concentration tends to cause equipment corrosion and erosion. The key to control of these problems is careful maintenance of the scrubber operating conditions.
A number of regenerable systems have been developed to produce a saleable product, such as elemental sulfur, or sulfuric acid. Elemental sulfur appears the most attractive product in terms of environmental impact, production rates, and potential storage volume. About 90,000 tons per year of sulfur would be produced by a :1,000-MWe power plant using 3 percent sulfur coal. At this rate, the control system of 100 Gwe of coal-fired capacity would produce sufficient sulfur to meet the total U.S. sulfur demand. The lack of long-term experience with these regenerable systems currently is a disadvantage; however, promising results have been obtained in a number of pilot and demonstration scale plants.
Investigations of possible uses for sludge as a raw material have failed thus far to show that scrubber sludge has a ready market. One problem complicating this issue is the variability of scrubber sludges formed from coals, as well as limestones of different properties, coupled with the presence of fly ash in the sludge. These sludges contain various proportions of calcium sulfite, gypsum, fly ash, and water.
Practical -application of flue gas desulfurization technology to existing coalfired power plants is affected by considerations such as plant design, available space, age, and capacity-use factor. These characteristics have a very important impact on installed process costs and can be expected to limit the utilization of flue gas desulfurization in existing coal-fired power plants to about 40 percent of presently existing plants.
With reprardI to the capital costs, FEA estimates that FGD will cost about 67 per kilowatt in new power plants, while EPA estimates between 1,60 and $100 per kilowatt. The NAS report also estimates $60 to $100 per kw on the basis of -reports from utilities and vendors, with "the majority believing that the costs will be closer to $100/kw."
For retrofitting existing power plants for FGD, FEA estimates an average capital cost of $87 per kw. The NAS report shows that retrofitting is estimated to cost 20 to 30 percent more than for a new plant, Nxhile Ebasco Services, in a report to FEA on the cost of converting 10 specific oil burning plants to coal, estimates the total air quality control system at $175 to $300 per kw, with the FGD component ranfring from $90 to $160 per kw.
Most estimates of loss of generating capacity from FGD range between 3 and 6 percent. NAS, in it report, estimates 5 to 7 percent. FEA, in. its ESECA Environmental Impact Statement, estimates FGID operating costs at 1.9 mills per kwh, while the NAS study shows a 2.0 to 2.5 mul per kwh range and a judgment that this range is probably too low.


FEA estimates that a price differential of $10 or more per ton between low and high sulfur coal makes FGD economic compared to low ,sulfur coal. The differential is not currently that great on the average but low sulfur coal prices can be expected to increase along with the mandated demands for emission limitations.


This last alternative is the most widely utilized and the lowest cost option today. Its effect is limited because it does not remove 100 percent of the sulfur or other potential pollutants. EPA estimates that 13.6 percent of U.S. coal reserves can be cleaned to new source performance standards specifications (1.2 pounds of SO. per million Btu) and an additional 54.6 percent can be. cleaned to less than 4 pounds of SO. per millioii Btu. Thus this technology may present an attractive alternative to further research funding for the next term and may also offer the best chance of near term results in R & D.
EPRI offered testimony on the status of present precleaning technology and its utilization. It stated:
Sulfur in coal exists in two principal forms, organic and inorganic. The organic sulfur is chemically bound to the coal substance and cannot be physically removed. However,, inorganic sulfur (pyritic) is not bound chemically, and may be removed in a two-step process. This process involves (1) crushing, and (2) physical separation, which most commonly is effected by exploiting the difference Jn specific gravity between coal and pyrites. The degree of removal is dependent upon pyrite size and distribution, coal size, and other physical characteristics. Typically, the costs associated with this technology for high-efficiency pyrite removal are $1.00 to $5.00 per ton of coal cleaned.
Existing cleaning processes, while removing impurities from coal, also reduce the total energy content available because some of the coal is lost with the refuse. However, the heating value of the cleaned coal increases due to removal of low heating value impurities. In practice an economic balance must be achieved between the Btu loss and the improvement in coal quality. This balance is further influenced by environmental considerations in disposal of the reject material, which has an extremely high water pollution potential because of its concentrated sulfur, iron, and trace metal content. In practice these trade-offs demand at least 90 percent Btu yield from the feed coal. This typically results in the rejects containing 15 percent of the. feed weight. Another negative environmental factor associated with physical coal cleaning includes fugitive dust emissions from storage and refuse piles, as well as conveyor systems. Thermal drying to reduce washed coal moisture content can also contribute particulates, sulfur oxides (SO.) and nitrogen oxides (NO.) if low grade heating fuels are used and emission control systems are not applied. These emissions are effectively prohibited in new coal preparation plants by the new source performance standards.
The most environmentally acceptable approach is to achieve utilization of all materials in the coal. The refuse material would be processed into various products: rock refuse for nonpolluting disposal; a pyrite concentrate that subsequently could be commercially converted to sulfur acid; and coal products of various sulfur levels for burning.
The major limitation to the use of physical coal cleaning as an environmental control method is the degree of 'sulfur removal. Sulfur reduction studies of U.S. coals have beem performed by the Bureau of Mines and EPA on 332 coal samples representing most mine-producing seams. The results Indicate an average total sulfur reduction of only 30 percent at a raw coal top size of % inch and washed to a 90 percent Btu yield. This restricts coal producing regions to a limited number in which the potential exists for washing coal to a total of 1 lb. sulfur per 1W Btu or less. Those regions would include the Northern Appalachian, Southern Appalachian, and Eastern Interior. Within these regions only about 15 percent of total bituminous coal production appears to be physically cleanable to ](,,,s than 1 lb. sulfur/million Btu. The potential for washing coal is greatest in tile northern Appalachian underground mines.

r n

This alternative requires further technical research in combustion, nd appears to be one of the most adaptable options for burning coal in an environmentally acceptable manner. Coal can be pre-cleaned at either the mine, en route, or just prior to combustion.
One of the simplest technological methods of controlling sulfur emissions is with a combination of careful weather monitoring and tall stacks. The Tennessee Valley Authority stated that, "at existing plants, TVA believes that curtailment of load during adverse meteorological periods in combination with tall stacks provides the most cost-effective method for compliance with SO ambient standards."
TVA has used this method in western Kentucky, lanarea with coal of four and a half percent sulfur at a plant in Paradise, Kentucky, which has stacks over 600 ft. in height. The first step in their program was to compile an atmospheric model to study the conditions that brought on high ground level concentrations of sulfur. From this model, a predicting procedure was developed with airplane flights to confirm the temperatures and other meteorological conditions. By instituting load curtailments when conditions were unfavorable, TVA was able to avoid building up a reservoir of sulfur dioxide that would later be brought down to ground level when air currents shifted. But utilizing this program for over 3 years, they testified they were able to hold'sulfur dio I xide emissions below the standards established by their own health and safety department and below those standards later established by the EPA.
EPRI offered testimony, which, in general, agreed w*"-Ih the success claimed by the TVA. EPRI also concluded that such strategy would be effective if stack heights at other plants were sufficient. When atmospheric conditions are unfavorable, such as an air inversion, low sulfur fuel or production restrictions are used.
EPRI noted the limitations which this technique has:
(1) An accurate inventory of source emissions and regional
meteorological data must be compiled.
(2) An accurate regional research program must be conducted
on the atmospheric transformations affeAing hydrocarbons, oxides of nitrogen, ?xidants, and sulfates.
However, these requirements are not technologically intensive, nor do they depend on new generations of hardware.
EPRI concludes that this technique can only be relied upon as a tactical, near term expedient until reliable impact and control criteria for sulfates and other secondary particulate emissions can be defined. More stringent air standards will require more sophisticated technology to control the emissions. The use of tall stacks will be inadequate, concludes EPRI, for achieving the necessary ground level ambient conditions.

Pulverized coal offers the advantages of (1) the most thermally efficient way to utilize coal and (2) simplicity of operation. Industry prefers this type of direct firing of coal, for just these reasons. However, utilities object to pulverization of coal for their operations because it uses up too much energy for the amount of energy derived, At present, there are commercially'available grinding processes which will yield particles of coal less than 100 microns in size. For future development are systems to pulverize coal to less than 10 microns in size.
The main problem with pulverizing coal is that there is a large amount of energy consumed in further reducing the size of the coal particles. The decreasingly smaller sizes result from. repeated passes through the equipment, or more equipment in line. There comes a tradeoff point where the amount of energy expended in further pulverization will go beyond the amount of energy derived from the coal itself. In engineering, this relationship is expressed as Bohr's Law.'
Calculations of pulverization to various sizes yields some interesting results, regardingr the amount of energy consumed. The ratio of the energy Irequired'to produce various-sized particles significantly increases as the size decreases. For example, a comparison of 74 micron coal to 10 micron coal, to 5 micron coal yields an energy consumption ratio of 1:2.72:3.85.2
2 1 10~(j 10)/(W1)

where E Is energy per ton to produce a product of which 80 byweght Is less than size XP, from a feed of 80% by weight of less than MY, in size.
This energy consumption ratio is related to the amount of capital which must be invested to achieve these increasingly smaller sizes. Thus, it would require roughly four mills to produce five micron material, compared to one mill for the conventional size pulverized coal of 74 microns.
At present, there are three types of mills which can produce this pulverized coal.$
The first type of mill is the roll-race mill, commonly used for grinding coal to prepare pulverized fuel. It has been used in the German cement industry to prepare fine finished cement. The second type of mill is the high speed hammer mill, again used in Germany, to prepare pulverized fuel. The use of extra stages with higher hammer velocities and repeated passes through the machine can give fine sizes.
1Testimony of Dr. Robert Essenhigh, Pennsylvania State UniversIty, to the Subcommittee on Energy Rsearch, Development and Demonstration (Possil Fuel), July 1975, App. 4.
3 Ibid.


The third type of mill is the conventional tumbling ball mill, which will reduce coal to fine sizes. Ball mills are used in industry and produce up to two tons per hour; this rate of output is considered too small for utility purposes.
The Ilok technology claims to be able to remove pollutants from finely pulverized coal by a process of thermal shock treatment. The coal is reportedly reduced in size f rom 4 microns to 1/300 micron and simultaneously stripped of all contaminiants-'ashi as well as organic and inorganic sulfur. Testimony received by the Subcommittee was somewhat skeptical of these claims. The mill that is used in this process was invented by Dr. Hans Rohrbach, and has been recently advertised by the Perolite Co. Dr. Rohrbach has provided only one public, technical statement on the Ilok technology. This was in the Journal, Motortechnicsche Zeitschrift, on page 379V(1971). The title was, "On Some Problems of the Coal Dust Motor." Testimony before our subcommittee revealed that a search of the hearings of other House Committees and of patent records has revealed no patents on the mill.
The subcommittee received testimony that the theory of operation of the Ilok technology is supported by various studies. The inorganic sulfur in coal, called' pyrites, are bonded together. Once the coal is pulverized to a very small size, the pyrites will separate out into separate particles. One process that could be used to separate the pyrites out would involve a vertical pipe with a high velocity stream of nitrogen. The nitrogen would travel at 200-300 miles an hour, and hit an analus, reducing the velocity, and then travel around a bend. The mineral matter would then collect on the outer side of the bend, and could then be tapped off.
In addition, magnetic separation could be used to separate the pyrites. This could be done by first lightly oxidizing the coal, and then passing it through a magnetic field. The oxidation increases the magnetic potential of the pyrites and will permit a high percentage of separation. The organic sulfur would be separated by the further reduction of the coal to %00 micron.

These mixtures are particularly attractive in process furnace applications. They are easy to adapt to the existing equipment. After adaptation to process furnaces, it quite naturally follows that industrial furnaces would pick up such a fuel type. With our current energy resource shortages, this could result in a substantial amount of furnace capacity being converted to coal and oil mixtures by 1980 or 1985. The Subcommittee received convincing testimony that industry was ready to rapidly assimilate such technology when and if it becomes available. General Motors is now conducting an accelerated program to develop the necessary engineering to convert its boilers to coal/oil' mixtures.
Research and development on coal and oil mixtures ha's been going on for 50 years, particularly at Penn State University. In 1932, a ship crossed the Atlantic with all 5 boilers fed by coal/oil mixtures. Recently, Penn State has published a study on this type of fuel, entitled, "Colloidal Fuel Develpment for Industrial Use."


There are many attractive aspects of coal and oil mixtures which would cause industry to utilize this fuel type. In the first place, it requires only a modification of existing equipment to accommodate the new volumes of fuel. It does not require any major degree of replacement of existing equipment. Secondly, sulfur emissions can be handled by varying the type of coal and oil mixture. Either a highsulfur coal and a low-sulfur oil can be used in varying percentages, or the reverse could be tried. In any event, this would provide an attractive interim solution to sulfur emission problems.
EIRDA issued a, program opportunity notice (PON) in February, 1976 seeking proposals to modify, operate and test existing boilers, heaters and furnaces, including the construction of a slurry mixing!/ distribution facility. Seven firms submitted proposals to the Energy IResearch and Development Administration for the combustion of coal-oil slurry as a principal fuel for industrial and utility use, and four groups have been chosen.


PurPosE, oF THE~ STuDY
The primary goal of the ECAS study is the identification and comparison of options for the future generation of electricity, using coal and coal-derived fuels. ECAS was conducted using a common basis of technology and performance to compare each of ten different power generation systems. ECAS put together some development plans for the various advanced systems, providing estimates of both cost and risk, and also providing a basis for establishing needed technology or development programs. The evaluation of alternative systems on a comparable basis is needed so that cost-benefit analysis may be performed and the preferred systems selected for further development. ,In particular, those Federal agencies concerned with power plants and electric generation for the future need these answers to develop a coordinated strategy for future energy. development. The ECAS study combines the funds of three agencies, the NSF, ERDA, and NASA, the cooperation of the Department of -the Interior and the Environmental Protection Agency, and the combined expertise and experience of the Westinghouse Corporation and General Electric Company. Overall coordination is provided by NASA's Lewis Research Center.
The-importance and need of this study is readily apparent. Electric utilities provide approximately 25 percent of our Nation's energy output. However, they are at present less than 40 percent efficient in conIrerting our energy resources to electricity. In this period of our Nation's energy shortages, we must strive to conserve energy at every level. Both the Federal Government and the public utilities have many types of electrical generation systems for future needs. However, they do not have a common basis on which to evaluate many of the proposed systems. Decisionmakers in the Government and in public utilities need some way to evaluate these systems, so that they may decide which technology will make 'the most efficient use of our Nation's energy resources. T u r p o m S u y

The ECAS study was organized to take advantage of the offices of the principal agencies, ERDA, NASA, and EPA. The study itself was conducted in parallel by two contractors, Westinghouse and General Electric. As can be seen from the accompanying organizational chart (figure 1), there are many steps of review for the results of this study, consisting of both a technical review panel and a utility review panel. Also to be noted are the separate contracts to develop data for impact and benefits assessment.


. . ECAS- "


Source: NASA.
In designing the ECAS study, NASA chose from numerous proposals, and selected the following ten candidates for electric generation systems: Advanced Steam, Open Cycle Gas Turbine; Closed Cycle Gas Turbine; Open Cycle MHD; Closed Cycle MHD; Liquid Metal MHD; Super Critical C02; Liquid Metal Rankin; Fuel Cells; Combined Cycle (Gas Turbine and Steam).
Each of these advanced concepts is backed by an industrial proponent who sincerely believes that his option has merit and should be pursued. Obviously, the ECAS study cannot pursue every option with equal priority. It is the purpose of ECAS, however, to undertake a study to relate these various approaches to a common frame of reference.
The ECAS study was divided into two phases. In the first phase, the contractors evaluated the potential of the ten candidate systems of advanced energy conversion, with various coal-to-thermal energy processes. In this phase of the study, the contractor examined plant efficiency, capital costs, and the cost of electricity. The second phase consisted of two parts. The first was a conceptual design of promising specific plants. The second part of this phase was an implementation assessment of each of these conceptual designs. In this last phase, NASA assessed the implementation of the conceptual designs along the following criteria: Economic Viability; Efficiency/Fuel Conservation; Natural Resource Requirements; Environmental Impact; Reliability; Safety; Life Limitations; System Component Compatibility; Siting; Application Flexibility; Operation/Control; Maintenance; Retrofit Potential; Byproduct Production; and Power Grid Compatibility.


The plan included an explanation of the power generation systems on a common basis by NASA.
One area of particular interest to members of the subcommittee was the inter-agency cooperation that is necessitated by this organization. The subcommittee was particularly interested in the manner in which the various principal agencies were able to assimilate the expertise that was developed in each agency. NASA has developed experience dealing with certain large-scale system studies, whereas some of the ERDX predecessor-organizations did not have that type of experience. On the other hand, the Department of the Interior had possessed de.tailed knowledge of the coal resource base and utilization in the economy, whereas NASA would have had to develop this capability. It was noted in the hearings that in coordinating earlier programs the Office of Coal Research had worked out an agreement with NASA concerning developments in the area of coal combustion. However, there was a reluctance on the part of the Department of the Interior to let a new agency such as NASA get into an area where OCR had done a significant -amount of work through the years. The Subcommittee was very much concerned that any type of bureaucratic delay would translate into a delay of the ECAS study.
Upon further questioning the subcommittee noted that the main problems in implementing working agreements between NASA and other agencies were legal ones, involving the differences between interpretations of the basic laws for each agency, specifically, the patent policies of those laws. In some cases- it took more than a year to negotiate these differences, and some of these differences still remain in relationships between NASA and with the, Department of the Interior; whereas negotiations are much further along with ERDA.
Other agencies perceive NASA's patent p o ilicy to be much more liberal than the policy under which they operate.' NASA has by legislation the option, in judging whether or not to retain patent rights, or to require background rights, to consider simply whether or not such retention or requirements would advance the dissemination of the technology into the private sector. They have the discretion to make a j ud gment whether or not the company keeps the patent, or has a license to it, or whether NASA retains the patent. This gives NASA an advantage in working with a highly developed technological industry. The industry realizes that in appropriate cases they can retain vast amounts of background information, on a proprietary basis. However, if the industry were working with another agency, the industrial applicantlor federal assistance would have to release the patent and information if it were to take the contract, because most other agencies do notleel that they have that discretion.
However, the testimony shows that the agencies have started to niake progress on interagency agreements. NASA does have a general agreement with ERDA and a general agreement with the Department of .the Interior, and specific agreements on projects in solar energy. It is
7-Cf. H.R. Rep' No. 1563, 93d Congress, 2d session at 26 (1974). The Conference Committee on S. 128i in their report to both Houses pointed out that the basic structure of section 9 was derived from the space Act with some modifications derived from the Atomic Energy Act. Some of the detailed criteria of section, 9 were stated Ps being adopted primarily from NASA and AEC regulations, as well as from the Presidential Pateut Policy Statement.

now actively developing agreements with ERDA in the fossil energOy area. ECAS has an agreement that is already operating. It therefore appears that interagency agreements by which the special expertise of various government groups will be applied to a common problem can be achieved.
Another area of interest to the subcommittee was the parallel studies that were being conducted by two contractors in the ECAS study. This could possibly raise charges of duplication of work. It was noted in the hearing that this charge is not always applicable because an agency can move competitively toward a goal, even though it may seem that two groups are doing similar work on the same'..problem. The point was raised that by having two independent and parallel studies being conducted, there will be a degree of advocacy in the evalui',tions of the study. The agency, NASA,'can then evaluate one study IV ith the other, and by using a data base, developed independently, the contracting agency can develop an improved and more objective conclusion.
The Subcommittee also received testimony on one aspect of the commercial development which affects the rate of assimilation of the new technologies into the economic structure: the establishment of a normnal commercial warranty for the new technology. In order to accomplish the transition from development stage to normal commercial equipment, the new technology must go through a demonstration phase, sometimes involving years of experience with both normal and abnormal operating conditions. The companies offering the new technologoies must collect sufficient experience to justify any warranty they would be willing to give to the vendee. Until the vendor is ready and willing to give such a warranty, the acceptance of the new technology will, of necessity, be much slower than desired. The Subcommittee feels that the ECAS study should address this problem also and ERDA should similarly consider the impact of the need for a demonstration phase before a new technology will be commercially acceptable.
Members of the Subcommittee were very interested in the role of the Sierra Club in the ECAS study. The Sierra Club is considered valuable for its ability not only to assess real problems of a technology that will affect the environment, but also to identify and discuss perceived problems that may arise in the future. As long as a problem is perceived by a large mass of the public, it must be treated as a real problem before a new technology can be adequately accepted into our economic structure. Similarly, members of the Subcommittee expressed a desire to see representatives of a consumer organization on the review panels of the ECAS study. These representatives' input would be valuable to assess the effects of these new technologies on the consumers and, in general, to let the consumers have a greater opportunity to affect these decisions.
Phase I, the parametric analysis, has been completed and a report on the results thereof was issued in February, 1976. The results include performance and economic data, such as plant capital cost and cost of electricity, and emissions and natural resource requirements for selected cases. This report provides a comparative evaluation of the contractor results on both a system-by-system and an overall basis. Ground rules specified by NASA, such as coal specifications, fuel


costs, labor costs, method of cost comparison, escalation and interest during construction, fixed charges, emission standards, and environmental conditions, are presented. Each system discussion includes the potential advantages of the system, the scope of each contractor's analysis, typical schematics of systems, comparison of cost of electricity. (COE) and efficiency for each contractor, identification and reconciliation of differences, identification of future improvements, and discussion of outside comments. Considerations common to all systems, such as materials and furnaces, are also discussed. Results of selected in-house analyses are presented, in addition to contractor data. The results for all systems are then compared. Maximum efficiency with corresponding COE and capital costs, minimum capital cost
ith corresponding efficiency and COE, and minimum COE with corresponding efficiency and capital costs are tabulated for each system and contractor. Plots of COE against overall energy efficiency for each system and contractor provide an insight into the effects of fuel, bottoming cycle, or gasifier and permit a ready comparison with the advanced coal-fired steam system. The sensitivity of COE to changes in capital costs, construction time, fuel costs, capacity factor, interest rate, escalation rate, and fixed-charge rate is determined as well as sensitivity to comparisons based on different methods of calculating COE.
Phase II of the study which was the conceptual design work has also been completed. NASA and the two technical teams headed by General Electric and Westinghouse made their results public in October,1976.
Their evaluation indicates (even though uncertainties exist) that relative to the base case of conventional fossil fuel steam plants significantly lower cost of electricity and improved overall efficiency can result in the near term from the use of two technologies; fluidized bed combustion for power plants using conventional steam conditions and combined cycle plants in which an advanced open cycle gas turbine discharging into a steam bottoming plant is fueled by an integrated low-Btu gasifier.
Two technol4es, closed cycle gas turbines with an organic bottomin-a cycle, and a liquid metal (potassium) cycle with a steam bottommi cycle were found to offer ii improved efficiencies with projected costs of electricity comparable to those of conventional steam plants. Enough uncertainty exists to warrant continued investigation of such systems.
Two technologies, open cycle (direct coal fired) MHD with a steam bottoming cycle and high temperature fuel cells operating with an integrated gasifier were found to offer substantially hirrher efficiencies, near 50 percent, and lower costs. These processes are in earlier phases of development.
The Energy Conversion Alternatives Study has been successful in determining the relative potential of the leading advanced technologies under the specified conditions. Further evaluation and implementation assessment is now being conducted by NASA.


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