CLEAN COAL TECHNOLOGIES INITIATIVE
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HEARING
BEFORE THE
SUECOMMITTEE ON
ENERGY DEVELOPMENT AND APPLICATIONS
OF THE
COMMITTEE ON
SCIENCE AND TECHNOLOGY
HOUSE OF REPRESENTATIVES
NINETY-NINTH CONGRESS
FIRST SESSION U'^-'IV OF MA.>S
LdK€5 A 'f.
MAY 8, 1985 ,, .,. . . . .^
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[No. 25]
Printed for the use of the
Committee on Science and Technology
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Boston Public Library
Boston, fAk 02116
CLEAN COAL TECHNOLOGIES INITIATIVE
HEARING
BEFORE THE
SUBCOMMITTEE ON
ENERGY DEVELOPMENT AND APPLICATIONS
OF THE
COMMITTEE ON
SCIENCE AND TECHNOLOGY
HOUSE OF REPRESENTATIVES
NINETY-NINTH CONGRESS
FIRST SESSION
MAY 8, 1985
[No. 25]
Printed for the use of the
Committee on Science and Technology
U.S. GOVERNMENT PRINTING OFFICE
50-513 O WASHINGTON : 1985
COMMITTEE ON SCIENCE AND TECHNOLOGY
DAN FUQUA,
ROBERT A, ROE, New Jersey
GEORGE E. BROWN, Jr., California
JAMES H. SCHEUER, New York
MARILYN LLOYD, Tennessee
TIMOTHY E. WIRTH, Colorado
DOUG WALGREN, Pennsylvania
DAN GLICKMAN, Kansas
ROBERT A. YOUNG, Missouri
HAROLD L. VOLKMER, Missouri
BILL NELSON, Florida
STAN LUNDINE, New York
RALPH M. HALL, Texas
DAVE McCURDY, Oklahoma
NORMAN Y. MINETA, California
MICHAEL A. ANDREWS, Texas
BUDDY MacKAY, Florida**
TIM VALENTINE, North Carolina
HARRY M. REID, Nevada
ROBERT G. TORRICELLI, New Jersey
FREDERICK C. BOUCHER, Virginia
TERRY BRUCE, Illinois
RICHARD H. STALLINGS, Idaho
BART GORDON, Tennessee
JAMES A. TRAFICANT, Jr., Ohio
Florida, Chairman
MANUEL LUJAN, Jr., New Mexico*
ROBERT S. WALKER, Pennsylvania
F. JAMES SENSENBRENNER, Jr.,
Wisconsin
CLAUDINE SCHNEIDER, Rhode Island
SHERWOOD L. BOEHLERT, New York
TOM LEWIS, Florida
DON RITTER, Pennsylvania
SID W. MORRISON, Washington
RON PACKARD, California
JAN MEYERS, Kansas
ROBERT C. SMITH, New Hampshire
PAUL B. HENRY, Michigan
HARRIS W. FA WELL, Illinois
WILLIAM W. COBEY, Jr., North Carolina
JOE BARTON, Texas
D. FRENCH SLAUGHTER, Jr., Virginia
DAVID S. MONSON, Utah
Harold P. Hanson, Executive Director
Robert C. Ketcham, General Counsel
Regina a. Davis, Chief Clerk
Joyce Gross Freiwald, Republican Staff Director
Subcommittee on Energy Development and Applications
DON FUQUA,
ROBERT A. ROE, New Jersey
RALPH M. HALL, Texas
FREDERICK C. BOUCHER, Virginia
TERRY BRUCE, Illinois
JAMES A. TRAFICANT, Jr., Ohio
DOUG WALGREN, Pennsylvania
ROBERT A. YOUNG, Missouri
DAVE McCURDY, Oklahoma
RICHARD H. STALLINGS, Idaho
GEORGE E. BROWN, Jr., California
Florida, Chairman
F. JAMES SENSENBRENNER, Jr.,
Wisconsin
CLAUDINE SCHNEIDER, Rhode Island
RON PACKARD, California
HARRIS W. FAWELL, Illinois
WILLIAM W. COBEY, Jr., North Carolina
JOE BARTON, Texas
D. FRENCH SLAUGHTER, Jr., Virginia
'Ranking Republican Member.
''Serving on Committee on the Budget for 99th Congress.
(II)
CONTENTS
WITNESSES
May 8, 1985: Page
Hon. William A. Vaughan, Assistant Secretary for Fossil Energy, U.S.
Department of Energy, Washington, DC; accompanied by Dick Harring-
ton, Deputy Assistant Secretary for Coal Utilization 2
Prepared statement 5
Prepared statement of Hon. Marilyn Lloyd 23
Prepared statement of Hon. Marcy Kaptur 27
Discussion 31
Prepared statement of Hon. Dennis Eckart 40
Eric Reichl, chairman. Clean Coal Use Panel, Greenwich, CT 52
Report of ERAB Panel on Clean Coal Use Technologies 54
Prepared statement 207
Discussion 214
Gene G. Mannella, director, Washington office. Electric Power Research
Institute, Washington, DC 220
Prepared statement 222
David O. Webb, senior vice president. Policy and Regulatory Affairs, Gas
Research Institute, Washington, DC 263
Prepared statement 266
Discussion 279
Panel II:
John M. Wooten, director of research and technology, Peabody Holding
Co., Inc., St. Louis, MO, testifying on behalf of the Clean Coal Technolo-
gy Coalition 283
Prepared statement 286
John McCormick, Environmental Policy Institute, Washington, DC 305
Prepared statement 308
Discussion 321
Appendix I:
Additional statements for record:
American Gas Association 326
Alex Radin, executive director, American Public Power Association.... 335
Daniel Kleman, city manager, city of Tallahassee 337
Bern E. Deichmann, vice president. Marketing Transamerica Dela-
val, Inc 342
Edison Electric Institute 348
Charles S. McNeer, chairman of the board, Wisconsin Electric Power
Co 360
Appendix II:
Additional questions and answers:
William Vaughan, Assistant Secretary, U.S. Department of Energy
in response to request by Don Fuqua, Rick Boucher, Jim Sensen-
brenner 366
Kurt Yeager, vice president, EPRI for Gene Mannella in response to
request by Don Fuqua, Jim Sensenbrenner 434
Summary comments from Senate briefing, June 19, 1985 441
David O. Webb, senior vice president. Policy and Regulatory Affairs,
Gas Research Institute, Washington, DC 457
John Wooten, director, research and technology, Peabody Holding
Co., Inc 461
(III)
CLEAN COAL TECHNOLOGIES INITIATIVE
WEDNESDAY, MAY 8, 1985
House of Representatives,
Committee on Science and Technology,
Subcommittee on Energy Development and Applications,
Washington, DC.
The subcommittee met, pursuant to call, at 9:30 a.m., in room
2318, Rayburn House Office Building, Hon. Don Fuqua (chairman
of the subcommittee) presiding.
Mr. Fuqua. The hearing today concerns the Clean Coal Technol-
ogies Initiative, an activity directed by Congress last year and con-
cluded recently by the U.S. Department of Energy. We will also
consider a recently completed report on clean coal technologies pre-
pared by doe's Energy Research Advisory Board.
A summary of events during the past 12 months seems some-
what appropriate. In April of last year the Secretary of Energy re-
quested that ERAB convene a panel to assess the principal technol-
ogies for clean use of coal. The requested report was accepted by
ERAB on May 1, just about 1 week ago.
Later in 1984 Congress directed DOE to determine the private
sector's interest in emerging clean coal technologies — those ad-
vanced concepts that could reduce the level of pollutants from coal-
fired utility and large industrial plants.
The response to DOE's solicitation of interest was very impres-
sive— 176 statements involving 12 specific technologies and 1
nonspecific technology, located in 28 States and the District of Co-
lumbia, significant levels of cost sharing, and a large number of in-
novative, imaginative approaches. We have reviewed the DOE
report and believe that it merits some discussion.
No one is surprised at the scope of the report. This committee
has authorized funds for research and development in all the tech-
nologies addressed. Through hearings, oversight, and other con-
tacts, we have heard both industry and Government justify expend-
itures on the bases of extension of knowledge, environmental
impact, resource utilization, and ability to exercise options. We un-
derstand that now all processes are not equal in stage of develop-
ment, but that eventually all processes will be available, through
development, offering valuable freedom of choice.
Probably no one is surprised at the lack of depth of the report.
We are disappointed that DOE has chosen to ignore the vigor and
intelligence of the private sector's response. This report would
seem to offer an excellent opportunity for DOE to provide technical
advice on the assistance necessary to get a technology to the stage
of commercialization. We certainly do not expect DOE to advise on
(1)
commercialization. We leave that up to those risk-takers in indus-
try who take the biggest risk when they attempt to commercialize.
The administration should realize that risk does not end when de-
velopment is complete.
We hope that our witnesses will provide the committee with con-
structive evaluation of the DOE report. We hope, also, that we can
review the ERAB report on clean coal technologies, which I men-
tioned earlier. That report may eventually prove to be more help-
ful to the Congress than the report we have recently requested and
received from DOE.
With information received today and at other congressional hear-
ings, we should be able to arrive at means of using coal more clean-
ly, more economically, more efficiently, and more quickly.
The efforts all our witnesses have made to be with us is appreci-
ated. We look forward to hearing from all of you.
Our first witness today will be Mr. William Vaughan, Assistant
Secretary for Fossil Energy, who is identified by the Secretary as
the DOE report implementer.
We welcome you. Bill, and await your testimony.
STATEMENT OF HON. WILLIAM A. VAUGHAN, ASSISTANT SECRE-
TARY FOR FOSSIL ENERGY, U.S. DEPARTMENT OF ENERGY,
WASHINGTON, DC, ACCOMPANIED BY DICK HARRINGTON,
DEPUTY ASSISTANT SECRETARY FOR COAL UTILIZATION
Mr. Vaughan. Thank you, Mr. Chairman. Recognizing that you
have several witnesses to follow this morning, I would like to
submit my formal statement for the record and briefly summarize
here some key points. I would like to discuss them in reverse order
from the way that the formal statement is structured.
Also, I would like to point out to you, Mr. Chairman, that I have
here at the table with me the Deputy Assistant Secretary for Coal
Utilization, Mr. Dick Harrington. I also have other staff members
here with us, so that we can answer the committee's questions in
some detail.
First of all, Mr. Chairman, I want to stress what I believe has
been the significant positive benefits that have resulted from this
clean coal report effort. These are outlined in the final page of my
formal statement, but I want to use them here at the beginning to
emphasize the fact that we believe valuable and beneficial results
have come from this effort.
First, the clean coal report we submitted to Congress last week
represents a snapshot of industry's interest in new coal technol-
ogies. It has told us that industry is prepared to move forward with
new concepts that offer significant environmental and economic ad-
vantages. While most of the submissions did indicate a need, or
perhaps more accurately a desire to receive Federal funds, there
are several projects that will likely move ahead on their own with
little, if any. Federal incentives.
For many energy companies the exercise served as an organizing
point to bring equipment manufacturers, architect-engineers and
other related firms into project teams. Should some of the proposed
projects proceed, many will incorporate a much wider diversity of
research, manufacturing, and marketing interests that might oth-
erwise have been the case.
The exchange of information between the private sector and the
Government has also been an especially valuable project of this
effort. We now in the Government have a better indication of the
direction the coal industry would like to take in the development
and application of new technology.
Finally, several interesting ideas emerged from the exercise that
may be of value to future planning of the Government's coal re-
search and development program. As we plan our fiscal 1987 and
future programs, we will have the benefit of some of the new ideas
expressed in several of the submissions in response to this request.
Mr. Chairman, the report we have prepared represents the De-
partment's and the administration's commitment to be fully re-
sponsive to the Congress. We devoted some 12,000 staff hours
within fossil energy alone, to the preparation of this report. More
than 50 professional staff members from our headquarters, Mor-
gantown and Pittsburgh Energy Technology Centers participated
in this effort. Furthermore, we extended the due date for submis-
sions at the request of the Congress, and then went what I consider
to be a significant step further, in accepting late arriving submis-
sions and incorporating them as much as possible into the final
report.
We take a special measure of pride in appendix C of the report,
the "Technology Assessments." Here is where we have tried to cap-
ture the key features of the technologies proposed and to profile
their economic, environmental, and technological potential. In
short, Mr. Chairman, we have completed a report which we believe
fully complies with the congressional directive contained in Public
Law 9873.
Now, having completed the required actions. Secretary Herring-
ton has asked us to go yet another step further. As described on
page 3 of my formal statement, we will attempt in a supplemental
effort to provide fuller characterization of clean coal technologies.
To do this, we will draw from this May 1 report, the recent report
of the Energy Research Advisory Board, the International Energy
Agency's most recent clean coal technology report, and other gen-
eral background material.
We hope to characterize various coal technologies against a set of
criteria such as environmental promise, cost, stage of development
and scientific feasibility, to name a few. This additional informa-
tion will be compiled into a final report and submitted to the Con-
gress.
While we continue to recommend to the Congress that the Feder-
al Government refrain from becoming a financial partner in large,
demonstration-scale projects, we believe such an effort will, that is,
the preparation of this additional report — will be helpful to the De-
partment, to the Congress, and to the coal industry in determining
the most productive approaches for development of clean coal tech-
nology.
In summary, Mr. Chairman, we are in wholehearted agreement
with the objective of increasing the use of American coal in an en-
vironmentally acceptable manner. We believe that the Government
has a legitimate research role in improving coal technologies and
to make this increasing use technologically possible.
The administration's Research Program has been designed to
bring about a more economical, cleaner technology for coal that
will benefit the domestic coal market as well as our environment
and our economy in general.
This concludes my opening remarks, Mr. Chairman. I will be
pleased to answer any questions.
[The prepared statement of Mr. Vaughan follows:]
Statement of
WILLIAM A, VAUGHAN
Assistant Secretary for Fossil Energy
U.S. DEPARTMENT OF ENEKGY
to the
Subcommittee on Energy Development and Applications
HOUSE COMMITTEE ON SCIENCE AND TECHNOLOGY
May 8, 1985
Mr. Chairman and Members of the Committee:
Seven months ago, as part of its Continuing Appropriations resolution,
the Congress directed the Department of Energy to solicit indications of
the private sector's interest in emerging clean coal technologies.
On May 1, 1985, following the evaluation of 17b responses, the
Department of Energy delivered to the Congress a 271-page report in
response to the Congressional directive. The report represents the product
of more than 12,000 cumulative hours of professional staff involvement
within tne Office of Fossil Energy -- the largest single effort to produce
a Congressional report even undertaken by this office. The report has
received the personal attention of Energy Secretary John S. Herrington and
reflect^s both the Secretary's and the Admi ni strati on' s commitment to be
fully responsive to Congress in this matter.
We are pleased to appear before the Committee this morning to summarize
that report.*
BACKGROUND -- ANALYSIS PROCEDURES
Following enactment of Section 321 of Public Law 98-473, the Department
published a Program Announcement in the Federal Register on November 27,
1984, requesting information on emerging clean coal technologies.
Simultaneously the Department issued a press announcement describing this
effort to more than 250 general, trade, and broadcast media outlets. On
December 7, 1984, an insert was also placed in the Commerce Business Daily
which called attention to the Department's interest in receiving clean coal
technology information.
* NOTE: Several submitters identified part or all of their submissions as
confidential and proprietary business information. To protect the
submitters' material and to provide a complete report to Congress, all the
confidential and/or proprietary submissions have been included in a
supplemental volume that has been made available to the Congress.
Together, these actions were intended to maximize public awareness of
the Department's clean coal tecnnology announcement. By the February 16,
ly85 deadline (wmch had been extended from January 18, 1965, in response
to a request of the Congress), 167 statements of interest and informational
proposals had Deen received from industry.
Once the deadline had passed for receipt of responses, it became
evident that several submissions were still being prepared and would
continue to arrive at tne Department at later dates. To ensure tnat tne
Department's report to Congress was as complete as possible, I directed the
Fossil Energy staff to incorporate the late responses into tne report if
this could be done without jeopardizing the preparation schedule.
In total, therefore, the Department had received 17b submissions at
the time the report to Congress was prepared. A subsequent submission was
received too late to oe analyzed but is included in the summary portion of
the report.
While many of tne logging and tracking procedures were similar to a
formal procurement evaluation, the Department could not adhere rigidly to
conpetitive procurement guidelines. Since the Department neither requested
nor was appropriated funds for any of the proposed activities, we made it
clear to the submitters that they could not be reimbursed for any expenses
they might incur in responding to the Department's announcement.
A senior staff team, made up of Fossil Energy Office Directors, was
formed to sort the submissions upon receipt, assign them to the appropriate
analysis team and provide specific instructions and guidance. Three
separate analyses teams were formed, each led by a member of the Senior
Executive Servi ce.
8
These teams mirrored the major coal-related technical office
subdivisions within the Office of Fossil Energy:
Coal Utilization Systems
Surface Coal Gasification Systems and
Advanced Conversion Systems
Underground Coal Gasification and Coal Liquids.
For each team, technical and analytical skills were drawn from Fossil
Energy personnel at Headquarters and the Morgantown and Pittsburgh Energy
Technology Centers. The Offices of General Counsel and Procurement Support
participated on a consulting basis. No personnel outside the employ of the
Department participated in or had access to the review process in any way.
Having completed the required actions under Section 321 of P.L.
98-^73, we would now like to explain our next steps in the clean coal area
and the approach the Secretary has asked us to undertake. Our general
approach will be to provide fuller characterizations of clean coal
technologies using such information as the Section 321 submissions,
information gained from our ongoing budget activities, the recent clean
coal report by the Energy Research Advisory Board, and other general
background material .
Specifically, the first effort will be to establish criteria against
which the technologies could be evaluated. These criteria will include
such things as environmental promise, cost, stage of development and
scientific feasibility to name a few. Second, the technologies will then
each be evaluated against the criteria. The pros and cons for each of
these technologies will then be expl^iined.
All of this additional information will be compiled into a final
report and submitted to the Congress. ^
I believe that such an effort will be helpful to the Department, the
Congress, and the coal industry in determining the most productive
approaches for development of clean coal technology.
SUMMARY OF RESPONSES
As indicated earlier, 175 responses were received, with project values
totalling in excess of S8 billion. Sixteen of the submissions did not
propose specific projects but instead provided general information or
support for individual projects or groups of projects, or endorsed the
program in general.
Responses were received for every Fossil Energy coal technology
program except one, waste management. Organizations in 28 states and the
District of Columbia submitted statements of interest or informational
proposals.
One hundred and five of the submissions identified specific locations
for their proposed projects. The sites were located in 29 states.
The following table summarizes the submissions received by category of
technology:
Technology Number of Submissions
Flue Gas Cleanup- „/ 31
Fluidized Bed Combustion— 27
Surface Coal Gasification 27
Coal Preparation 22
Heat Engines— 13
Advanced Combustion 10
Alternative' Fuel s 8
Fuel Cells 8
Coal Liquefaction 5
Underground Coal Gasification 4
Gas Stream Cleanup 2
Magnetohydrodynamics 2
Non-Technology Specific 16
175
— One submitter proposed two projects, so that
the total number of proposed projects is 32.
2/
— One proposal was evaluated in two categories
(Fluidized Bed Combustion and Heat Engines)
because it contained technology development in
both areas.
10
Flue Gas Cleanup
Of the 3Z projects described in this category, 14 concentrated on
in-boiler sulfur dioxide control using sorbents. Seven submissions were
received on dry waste flue gas desul furization processes. Five submissions
described regenerable flue gas desulfuri zation processes and the remaining
six represented a variety of mi seel laneous approaches.
Most of the submissions were targeted at the large utility boiler market
(the one exception was a coal-fired cogeneration process for the pulp and
paper industry).
The requested federal incentives, with one exception, were for direct
funding. The one exception asked instead for an innovative technology waiver
of sulfur dioxide New Source Performance Standards for two new 572 MWe plants
in return for installing the limestone injection multistage burner
technology.
In two of the submissions, work has already been performed or likely
will be completed regardless of federal funding. For 13 of the proposed
projects that are similar to existing privately-funded ones, an argument was
made for multiple demonstrations in order to provide greater confidence.
Lastly, several submitters stated that their projects would not be initiated
a^ all in the absence of federal support.
Advanced Combustors
Ten submissions were for projects that addressed advanced combustor
technology. These submissions varied significantly in cost, duration, size
and type of coal to be used; however, the projects could be grouped into two
general categories: three submissions proposed relatively mature slagging
combustor designs for utility retrofits, while seven projects would use less
mature concepts that require further development before they would be ready
for demonstration.
11
Proposed federal assistance was in the form of direct cost-sharing.
Where justification for federal support was provided, it entailed the
unavailability of private funds and the need to minimize risks for the first
users of the technology.
Fluidized Bed Combustion
In the Atmospheric Fluidized Bed Combustion (AFBC) area, 21 responses
were received (one was received too late for analysis and is included only in
the summary section of the report).
Ten projects were targeted at utility applications at scales of 20 MWe
to 235 MWe. Four would apply the circulating AFBC concept, three would use
the bubbling bed AFBC concept, and three indicated that a decision between
the two concepts had not yet been made.
Four projects were proposed at the industrial scale, i.e., 200,000 to
500,000 Ib/hr of steam production. Three would apply the circulating bed
technology to generate steam or for cogeneration, while one proposed the
bubbling AFBC concept.
Six statements of interest were received for projects that did not fit
in either the utility or industrial categories or were for research and
development efforts. One additional project was designated as proprietary
information by the submitter.
Many of the AFBC submissions did not provide justification for the
federal incentives proposed, but those that did offered the following
rationale for government funding support: (1) the hurdle of the significant
capital cost differentials between atmospheric fluidized bed combustors and
proven alternative technologies, (2) the need to offset partners' financial
commitments and not as a condition to complete the project, and (3) in the
case of immature technologies, to pay for the risks involved.
12
Six submissions were received in the Pressurized Fluidized Bed
Combustion (PFBC) Technology area. Three were for steam-cooled combined
cycle and turbocharged boiler systems, two were for advanced circulating
fluidized bed PFBC technology, and one was to operate a federally-funded
air-cooled circulating bed pilot plant which is currently Deing dismantled
(the 13 MWe Wood Ridge, NJ , PFB pilot plant).
The submissions describing steam-cooled combined cycle projects stated
that federal incentives would help offset the technology risk and initial
high costs of repowering or retrofitting existing utility boilers. The
project proponents state that demonstration of PFB technology under actual
utility operating conditions and scale is essential to determine its
performance and economics.
The three proposers suggesting circulating PFBC combined cycle concepts
each identified further research that would be conducted at units considered
to be at the pre-demonstration plant scale. This research would be necessary
before scale up could occur.
Coal Preparation
Although 22 submissions were received in the category of Coa'l
Preparation, only seven proposed demonstration projects. The remaining lb
were for technologies at scales less than demonstration.
Three of the demonstration projects were labeled as proprietary. The
others proposed to clean coal with (1) microbubble column flotation followed
by high speed centrifuge dewatering; (2) physical cleaning techniques,
followed by hot water drying, and acid extraction; (3) high gradient magnetic
separation; and (4) a combination of physical and microbial cleaning
techniques.
The federal incentives requested were almost exclusively direct funding
and were deemed necessary by the submitters (1) because internal funds were
not available to support a demonstration project; and (2) to make the
technology available to the industry by the late 1980s.
13
AUernati ve Fuels
Eight submissions were received in the alternative fuels category, and
all involved the application of coal-water mixture technology. Two of the
submissions were identified as "Confidential Proprietary Information" by the
submitters, and one did not propose a specific project.
The remaining five projects proposed (1) the development of a slurry
fuel by applying the oil agglomeration beneficiation technique, (2) the use
of a model to study and maximize the efficient use of coal in a blast
furnace, (3) the development of a coal-water-mixture/natural gas co-firing
fuel with a sulfur absorption additive, (4) the development of a coal-water
mixture fuel containing sulfur captor compounds, and (b) the assessment,
retrofit and operation of a gas-fired utility boiler using a coal-water
mixture fuel .
Six of the eight projects proposed in this category have been initiated
in some form. One has developed to the point where the next step is
commercial demonstration; the others range from bench scale to proof-of-
concept projects. All projects, with the exception of one, were applicable
to the industrial sector. The one exception entailed a retrofit to a utility
gas-fi red boi ler.
None of the submitters, with the exception of one proprietary proposal,
directly addressed justification for federal incentives. Where the type of
incentive was described, it was either a direct financial award or an award
in combination with a federal loan.
Gas Stream Cleanup
Two gas stream cleanup projects were submitted. One of the submissions
proposed a method for inbed desul furization within a coal gasifier using
mixed metal oxide sorbents. Federal financing, involving direct funding, was
requested for the entire development process, from basic research through
pi lot demonstration.
14
The second project cannot be discussed or described since the submitter
declared the entire proposal to be proprietary.
Surface Coal Gasification
Surface coal gasification was the core technoloviy in 11 submissions.
The projects were subsequently divided into three groups -- utility systems,
industri a 1 /residenti al systems, and special applications -- based on the
major application of the technology.
Utility Systems -- The 11 submissions that would apply to the utility sector
ranged from the development of a thermodynamic model for coal gasification to
the commercial demonstration of integrated gasification combined cycle
systems at scales of 5 to 400 MWe.
Many of the integrated gasification combined cycle projects specified
technology similar to that currently being demonstrated at the Cool Water
project 1 n California. One project, however, proposed the eventual
replacement of conventional combined cycle technology with advanced gas
turbines. Gasifiers included slagging fixed bed systems, fluid bed systems,
and entrained flow systems. Gas cleanup systems ranged from conventional
cyclones and wet scrubbers to one advanced in-bed desulfuri zation and hot
particulate removal system.
All of the submissions sought direct federal funding support for capital
costs and in some cases operating costs. Two principal reasons for this
assistance were cited: (1) the significant risks entailed in recovering
project costs in later years due to the heavy dependence on projected fuel
price differentials; and (2) the substantial cost of gasification/combined
cycle equipment which cannot be financed by the usual private utility means
due to its novelty and the lack of evidence that the technology is practical
and economi cal .
15
Industrial/Residential Systems -- Nine submissions were received for either
the demonstration of gasifiers applied to small to intermediate size
industrial/residential applications, or for coal-based concepts for producing
chemicals and synthetic natural gas. Proposed projects ranged from a small
(3.7iD ton per day) pilot plant to a near commercial size (1648 ton per day)
advanced gasification system. Federal incentives were advocated by the
submitters aue principally to the lower level of technical maturity and
higher degree of risk associated witn the gasifiers in this group.
Special Applications -- Seven projects proposed in this category could oe
further divided into two more specific categories:
(1) five proposed projects to convert coal to coproducts in addition to, or
as a preparatory step to, the production of synthetic gas. Sucn coproducts
include metallurgical grade coke as well as product chars with significantly
better properties {lower sulfur and ash and higher heating vaiuej than the
original coal. Facilities in this category ranged in size from small
laboratory research units to a 1000-ton per day demonstration plant. One
project in this category requested a price guarantee and loan guarantee,
while the others asked for direct federal funding.
(2) two submissions proposed advanced iron-making techniques that would use
coal gasification technology as part of the process. According to the
submitters, direct federal funding would be required for the projects, each
of which would produce 300,000 tons per year of high purity iron for
steelmaki ng.
Fuel Cells
Eight submissions were placed in the fuel cells category, seven of which
proposed the use of the phosphoric acid technology (the other suggested an
advanced molten carbonate concept).
Three submissions proposed to link a fuel cell with existing gasifiers
at either the Cool Water, Tennessee Valley Authority, or Twin Cities
16
projects, although none of the submissions showed a way in which true
integration could be accomplished with an existing gasifier. Two submissions
proposed a grass-roots design. Five of the submissions would rely on
conventional gas cleanup techniques, one left the gas cleanup and system
integration issues to be determined, and one did not address gas cleanup at
all. All but one of the projects would be applied to utility power
generation; the one exception would produce dc power for a chl ori ne/ sodium
hydroxide plant. All included direct federal funding, and in addition
several proposed the use of government facilities and price guarantees for
the product energy.
Heat Engines
t
While several submissions were received that included heat engine
technology as part of the overall energy system, 13 submissions could be
categorized as specifically focusing on the heat engine hardware.
Seven submissions would substitute coal fuels for distillate fuels in
locomotive propulsion. Concepts included dry powdered coal or coal-slurry
fueled gas turbines (two), a coal-derived gas-fueled turbine or diesel, a
hybrid steam-diesel concept, an advanced fluid bed combustor/boi ler combined
with a steam turbine-electric drive, and an advanced fluidized bed boiler to
drive a steam reciprocating cycle. One of the coal-slurry fuel gas turbine
proposals also included a slurry fuels diesel engine as an option.
Three submissions were assigned to the category of industrial
cogeneration, i.e. they would generate both process heat and electricity
simultaneously. One would employ a coal-fired gas turbine, one a coal-fired
fluid bed combustor, and one an air-blown gasifier, hot gas cleanup system, a
diesel engine and a heat recovery boiler.
Three submissions were assigned to the Combined Cycle Power Generation
Systems subcategory. All involve gas turbine component development for
subsequent integration with coal gasifiers. One of the submissions was
essentially a research and development effort. The other two proposed
modifications to enhance efficiency and improved environmental performance.
17
Federal support was requested primarily in the form of direct funding
although in one case a loan guarantee was proposed. Federal subsidies were
judged to be necessary by those submitte'"S assigned to the Locomotive
Propulsion Systems subcategory because both railroad operators and locomotive
manufacturers are reluctant to begin expensive research and development
projects without reasonable expectations of commensurate payback in the near
term. Federal support, according to the submitters, could result in initial
testing of coal-fired locomotives , within 3-1/2 to six years from the start of
development, as compared to the end of tne century if there was no federal
invol vement .
The submitters' justification for federal incentives in both the
Cogeneration Systems and Combined Cycle Power Generation Systems were based
generally on the relatively high initial development costs compared to
long-term payback uncertainties.
Magnetohydrodynami cs
Two submissions were received for retrofits of the magnetohydrodynami cs
(MHD) technology to the existing Montana Power Company's Bird plant. Both
proposed projects would be contingent upon continuation of proof-of-concept
testing by the Department of Energy, and both include the Bird plant as part
of the private sector's cost sharing (although the estimated value of the
plant varies by more than 100 percent depending upon the submission). The
addition of the MHD topping cycle to the existing facility would increase its
power output from 56 MWe to 38.5 MWe.
The federal incentive requested was direct funding at levels of about 50
percent when the submitter is given credit for the candidate base power plant
and assuming that continued federal support is provided for the ongoing MHD
program. This amounts to a 75 to 80 percent federal share of the direct
out-of-pocket expenses. The submitters cited the high-risk, long-range
nature of the MHD advanced power development effort.
18
Coal Liquefaction
Five submissions were received in this category. Two described
exploratory bench scale research efforts. One was an informational letter
documenting the submitter's ongoing interest in coal liquefaction and
encouraging the Department to recognize out-year needs for pilot plant
testing of new concepts. Two submissions addressed the co-production of
electric power and methanol from coal using the Tennessee Valley Authority's
Coal-to-Ammoni a' faci 1 ity at Muscle Shoals, Alabama.
Direct federal funding was the preferred government incentive with
cost-shanng described in only one of the suomissions, the TVA-proposed
"once-tnrough" methanol synthesis project at Muscle Shoals. Federal
involvement was necessary, according to the submission, to reduce
uncertainties associated with the scale up to commercial size, construction
and operating costs, and market potential for the methanol synthesis
technology.
Underground Coal Gasification
Four submissions involved underground coal gasification. Each
represented a totally separate technology or concept. One was a letter of
interest from a firm proposing to undertake several risk reduction research
studies. One submission suggested government funding for a research and
development program to use unmineable coal as a sacrificial energy source to
retort oil shale in place. A third proposal was for a cost-shared commercial
plant to produce synthetic gas for a Wyoming power plant. The fourth
proposed project was for a pilot and demonstration effort of underground
gasification in a steeply dipping anthracite seam in Pennsylvania.
Where included, the justification for feoeral involvement was generally
to reduce risks to sufficient levels to attract private capital.
19
THE ISSUE OF FEDERAL INCENTIVES
TO ACCELERATE COMMERCIAL AVAILABILITY
The Congress also requested the Department, through Section 321, to
identify the extent to which federal incentives might accelerate the
commercial availability of emerging clean coal technologies. After analyzing
the submissions, the Department concluded that federal incentives will not
accelerate commercialization of these technologies and may, in fact, be
counterproductive to their development.
The majority of submissions expressed a need for federal financial
assistance, mostly in the form of direct funding. However, several of the
emerging technical options addressed in the submissions are currently being
developed at near-commercial or commercial scale without federal funds.
It should also be noted that cost sharing offered by the proposers
varied significantly, not only in terms of the total amount but also in the
nature of the cost sharing. For example, some proposers offered the amount
of previous expenditures as "cost sharing" in return for 100 percent federal
financing of future costs. Others offered to share all future costs. In
many cases, cost sharing statements were not provided or were incomplete.
It should also be expected that several firms would opt for federal
funds, if they were available, and some of these firms could conceivably
delay the implementation of privately-financed development efforts while
waiting for federal financing to materialize. The possibility also exists
that some proposers who might have proceeded on their own would wait until
they see which technology is backed by the government, then decide if they
can effectively compete against a federally subsidized effort.
Some technologies that may not appear to be advancing rapidly to
commercial scale may be hindered by valid technological or economic reasons,
and therefore, may require additional research and development before they
are commercially viable.
20
other technologies may simply never be competitive, and the inability of
these technologies to attract sufficient private sector investment may
reflect investors' sound judgments as to their ultimate potential. Federal
financing in these cases would not be productive regardless of the amount.
In some cases, the pace of commercial development and deployment may not
hinge as much on technological issues as on the uncertainty of market demand
or the uncertainty of future emission regulations that could spur demand for
clean coal technologies.
Given the size and availability of U.S. coal reserves, the security of
the domestic coal supply, and the comparative economics of coal as a fuel,
free market forces are operating to select and commercialize the most
efficient and environmentally-effective clean coal technologies. Federal
subsidies could alter these market forces and adversely affect the
development of competing technologies both within and outside the coal
industry.
These conclusions are based on the Department's previous experiences
with federal incentives. Commercial or near-commercial scale projects
selected to receive assistance under prior incentive programs have been
largely unsuccessful in commercializing new fossil technologies. Moreover,
their lack of success has, in all probability, compounded the problems
associated with the introduction of new technology. It is quite likely that
related private sector projects have not been initiated because of the
perceived competitive disadvantage of competing against a federally
subsidized effort.
We are in wholehearted agreement with the objective of increasing the use
of American coal in an environmentally acceptable manner. We believe that
the government has a legitimate research role to improve coal technologies.
The Administration's research program has been designed to bring about a more
economical, cleaner technology for coal that will benefit the domestic coal
market as well as the environment and economy in general.
21
Accordingly, the Department recommends to the Congress that no federal
financial incentives be provided for the demonstration and commercial
development of emerging clean coal technologies. Rather, the Department
should continue to channel its resources into the highly productive areas of
more generic coal technology research and development.
BENEFITS OF THE CLEAN COAL SOLICITATION EFFORT
Even though we recommend no future federal funding for the projects
described in the submissions, significant value has already resulted from the
process of soliciting statements of interest and informational proposals.
For many energy companies, the exercise was used as an organizing point
to bring equipment manufacturers, architect-engineers, and other related
firms into project teams. Should some of the projects proceed, many will
incorporate the expertise of research, manufacturing, consuming and marketing
interests within the same project framework, due to the information exchange
that took place during this effort.
Information exchange between the private sector and the government was
also an especially valuable product of this effort. A better indication now
exists of the direction the coal and coal -related industries would like to
take in the development and application of new technology. In addition,
several interesting ideas emerged that may be of value to future planning of
the government's coal research and development program.
This concludes my fonnal testimony, Mr. Chairman. I will be pleased to
answer- any questions you or Members of the Subcommittee may have.
22
Mr. FuQUA. Thank you. And before we proceed, without objec-
tion, permission will be granted retroactively to take photographs
and make recordings and videos during the course of this hearing.
We also have a statement for the record by Congresswoman
Lloyd and also Ms. Kaptur, who is not a member of the committee,
but a Member of the Congress from Ohio.
[The prepared statements of Mrs. Lloyd and Ms. Kaptur follow:]
23
HON. MARILYN LLOYD
STATEMENT FOR THE RECORD
HearFng on the DOE Report on Emerging Clean Coal Technologies
May 8, 1985
Mr. Chairman and Members of the Subcommittee, I appreciate the opportunity to
provide my views on this hearing topic. I also believe that this hearing fs
both timely and Important. The subject of accelerating technology Integration
and development by cost-shared government demonstrations of clean coal
technologies Is critical. In recent years we on the Committee have seen the
budgets for civilian energy research and development decline drastically,
bringing some of these Important R&D programs to termination and others to a
barely viable level of research activity. Together with the constant
reductions In the civilian research and development budgets. Including fossil
energy base technology efforts, the Administration has also Implemented a
moratorium on government-funded technology development at any meaningful scale
placing the entire burden for pilot-plant or semi-works demonstration projects
on the private sector.
The private sector has responded to this challenge by coming forth with a
multitude of high quality proposals In response to the recent Administration
solicitation for cost-shared demonstration proposals. (This recent
solicitation was admittedly In response to a Congressional mandate.) From the
publ Ished responses to the DOE sol Icltatlon In the November 27, 1984 Ee^^rgi
Register. It Is apparent that the private sector Is keenly Interested In the
development of clean coal technologies but cannot make the large financial
commitment necessary to definitively prove the feasibility of these emerging
technologies.
The recently published Department of Energy report to the Congress on Emerging
Clean Coal Technologies contains the stunni ng statement that "Federal
Incentives will not accelerate commercialization of the technologies and will
be counterproductive to their development." How the DOE can substantiate this
sweeping conclusion Is beyond any knowledgeable observers of coal R&D. The
statement Is based on the Department's a priori conclusion that only free
market forces should be allowed to work In the selection of the most
appropriate advanced technologies for coal use. I am aware of one project
which Involves significant EPRI funding, the Atmospheric Fluldlzed Bed
Combustion (AFBC) project being developed jointly with TVA, DOE and the
Commonwealth of Kentucky In Paducah, Kentucky. However, I am at a loss to
name a specific technology presently being readied for commercialization at
the same scale without federal funding. I would also remind my colleagues on
the Committee that while "soft" oil prices and temporary "gluts" buy us time,
they should nevertheless provide even stronger Incentives for federal
tnvol vement.
Curiously, while the Department does not recommend that federal funds be used
for demonstration. It does recommend that the DOE channel .Its resources Into,
or "concentrate on", coal R&D. What appears paradoxical Fiere Is that when we
take a look at the DOE budget request fgr the past few years for fossil R&D,
we see that It has steadily declined under ONE pressure.
24
In direct contrast to DOE's stated position and optimistic, yet unfounded,
belief In free market forces, the report contains a project proposers' list of
the needs for federal assistance to bring their projects to commercialization.
The most common Justifications for federal assistance were listed as follows:
(I) the private sector does not have the required resources; (2) the proposed
projects are high technological risks, and (3) federal support TsT-equIred for
commercial Izatlon of processes that address a national need. It appears that
the private sector does. Indeed, take a quite different view of
commercialization than the Department. It Is also evident from the lack of
new commercial clean coal technologies entering the marketplace, that federal
Incentives are necessary.
Ironically, the DOE's own Energy Research Advisory Board (ERAB) panel report
makes a strong case for federal Involvement In commercializing technologies
when the ultimate user cost-shares the project on at least a 50? basis. The
panel. In fact, concludes that the current policy of no federal funding for
commercialization should be changed. The concensus was that the absence of
federal Involvement past the proof-of-concept stage has resulted In
abandonment of promising technologies because of the significant risks
attendant to seal Ing-up, Integrating large systems, etc. A federal role In
these cases would have been anything but "counterproductive."
Another problem described In the ERAS report was the Department of Energy's
rather poor track record In sustaining Its contractual obligations with the
private sector. This was a common concern of our private sector witnesses
during the ERP subcommittee hearings on the FY 1986 DOE authorization. The
outside witnesses expressed their frustration at the "sometime" partnership
they encountered with the Department and the disruptive Influence on their
research efforts of uneven financial support for the projects.
I believe It Is even more Important to provide some government funding for
demonstration projects In light of the recently released Office of Technology
Assessment (OTA) report on offshore oil and gas reserves. The OTA report
concludes that the 1981 Department of Interior estimates of offshore oil and
gas reserves were over-stated by a wide margin. Recent explorations have been
disappointing In terms of discovery of additional reserves. Also, the costly
development of some of these reserves Is a factor to be considered when we
attempt to plan for our future energy security. To have the "supply-oriented"
Administration announce these pessimistic prospects Is compelling evidence to
dispel the Illusions cast by today's "glut" and "soft" prices.
I understand that the Department is under some central nts Imposed on It by the
Office of Management and Budget (Of-B) regarding any Implementation of the
Congressional directive to fund clean coal technology demonstration projects.
Unfortunately, the Department's lack of Interest in fulfilling the spirit of
Congressional mandate Is so great that relative technical assessments and any
ranking of the projects are completely lacking. I am disappointed with the
quality of this first effort and hope to see much improvement in the DOE's
promised supplemental assessment. I would hope that the enthusiasm shown In
the private sector's response will be sustained at a high level until the
Department chooses to Implement the spirit of the Congressional mandate.
In order to work around Inadequacies and Inconsistencies In Departmental
25
policy, I would I fke to recommend two courses of action which I believe would
give the Department more certain guidance for developing clean coal research
programs. This Is the type of policy directive which the Congress Itself has
attempted to provide for the past several years. My first proposal Is to
transfer some additional funds from the SFC Energy Security Reserve fund and
provide It to the Department of Energy for use In complementary projects for
clean coal technology development Including small coal conversIon'"pII ot
plants. This money would be a supplement to any other funding authorized for
fossil R&D for use by the Department. The beleaguered Synthetic Fuels
Corporation still has $7.9 billion remaining In already appropriated monies,
but I'm afraid that It Is very likely that some of this funding will never be
utilized for Its Intended purpose. The changing public perception and
unfortunate perceived lasJs 2! urgency with respect to our national energy
needs are all part of the changing climate for the federal development of
synfuels In the private sector and In the Congress. These factors, albeit
regrettable, are pointing toward a further reduction In the SFC's already
reduced resource base even though there Is a mix of projects before the
Corporation which merit some funding. It thus makes sense to me to redirect
up to $1 billion In funding Into the companion clean coal technology
development and demonstration program now before us In the likely event that
the SFC certainly will not commit the entire $7.9 billion,
I do plan to Introduce a modified version of my Clean Coal Technology
Development and Utilization Act, a bill which I originally proposed In the
98th Congress. In fact, the proposal I Just outlined, which Is similar to the
transfer provisions of the earlier version, will be Included In the updated
version of the bill.
My second proposal deals with the $750 million provided for clean coal
technology development In last year's continuing resolution on Interior
Appropriations. I suggest that our Committee take a positive approach by
passing a generic authorization bill which would delineate the categories of
projects which should be funded by the Department and provide some carefully
crafted yet broad guidelines for their Implementation. In the past I have
taken the position that It Is Inappropriate to micromanage the Department and
I still believe that. However, realizing that we have limited resources, I
think that a cautious, cost-shared development plan between the Department of
Energy and the Industrial performers will be mor.ey well-spent for our energy
future. I also believe that we should not abrogate our responsibility as an
authorizing committee to appropriations. If the Congress must act because DOE
refuses to come forward with criteria for project selection In terms of
technological maturity, etc., we should "bite the bullet."
Finally, I would like to comment on the demonstration of emerging clean coal
technologies within the context of add precipitation. I have been an
outspoken advocate of the need to Intensify our research effort Into
cause-effect relationships In "acid rain" chemistry. Therefore, it Is
reassuring that the request for this research program received a substantial
Increase In FY 1985; It is still the sole avenue to any reasonable
cost/benefits analysis.
In concert with this focused acid rain research program, T bel leve we also
need to continue our work on developing clean coal technologies and bringing
them into the marketplace. Whether our research results show that sulfur
26
dioxide Is determined to be the major factor In acid precipitation or not, we
do need to utilize this Important natural resource In an environmentally sound
manner. This relatively small Investment In our energy future will surely
serve as an Insurance policy for a healthy future energy supply.
We have the opportunity to lay out a DOE clean coal technology program which
complements a limited SFC program on diverse synfuel technologies'.- We must
Ignore the Illusory supply circumstances which obscure our long-term liquid
fuels problem. We are running out of gas and oil and we must burn coal
cleanly to complement nuclear energy for a balanced supply of both electricity
and related Industrial process heat.
It would require an extended discussion to adequately document the
difficulties which have faced the synfuels programs In the SFC, but two points
are worth stating: First, the Administration's amblvalency and Ineptitude In
handl Ing SFC matters, aggravated by Congressional obstructionism and meddl Ing
on the part of SFC opponents, have diverted Industry resources which might
have better been devoted elsewhere. This Is particularly true In the
unproductive case where the Corporation withdrew solicitations after project
teams were already hard at work and considerable efforts were made In
developing proposals and supporting activities to refine designs. Secondly,
although In this deficit climate It Is particularly easy for Members to
support the "sham cut" In the Energy Security Reserve (since virtually no
outlays are Involved), we cannot wish away our long-term liquid fuels
problems. We have not even achieved technical confidence In converting coal
to oil and gas at significant scale, no less Improved the economics of these
schemes. Since lead times of Interest are certainly a decade or more for
these technologies, we can now project our synfuels uncertainty Into the end
of the next decade. We simply must Identify the most promising conversion
processes now so that we can have clean coal technologies by the late nineties
because the oil and gas route will become a "dead end" early In the next
century.
27
STATEMENT OF
THE HONORABLE MARCY fCAPTUR
TO
THE SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATIONS
COMMITTEE ON SCIENCE AND TECHNOLOGY
U.S. HOUSE OF REPRESENTATIVES
MAY 8, 1985
MARCY KAPTUR
COMMITTEES
BANKING. FINANCE AND
URBAN AFFAIRS
VETERANS' AFFAIRS
28
CongrtSB of the Bnited 3tatCB
iflonsc of TR.q»t«entatiDEB
^aDashlngton, ©£ 20515
1216 lONCWORTM BUILDING
WASHINGTON. OC 30619
1201) 116-4146
FEDERAL BUILDING
234 SUMMIT ST. BOOM 719
TOLEDO OH 43604
(419) 259-7600
Mr._ Chairman, thank you for allowing me to address the Subcommittee
today to express my support for Clean Coal Technology.
In 1984, Congress wisely recognized the need to support demonstration of
those Clean Coal Technologies near commercialization. In doing so, we realized
that certain short-term economic forces operated against the introduction of
new alternative cost effective energy technologies into the marketplac.
Specifically: (1) our current over dependency on oil and natural gas (2)
the glut of oil on the world market (3) depressed crude oil prices and (4)
the environmental problems associated with the burning of fossil fuels.
The realities of the situation were obvious. Imports now account for
roughly one-third of all of the oil we use, just as they did before the Arab
oil embargo of 1973. United States' consumers spend $57 billion annually on
foreign petroleum products. In New England and the Mid-Atlantic states, one-half
of total energy consumption still comes from oil. In ray state of Ohio, 94% of
the oil consumed in 1983 was imported into the state. That our trade deficit is
at historically record levels is quite well known. Further, there isn't one
of us that can forget the political, economic and strategic effects of being
caught "over the barrel" in oil embargoes in 1973 and 1979.
Congress has debated the difficult solutions to the enviromental problems
associated with the burning of fossil fuels for a number of years. For those
of us who represent the Northeast-Midwest, the problem of acid rain has long
been debated with no resolution in sight. No existing technology of lower
emissions from industrial areas, or any attempt to arrive at a solution
29
through regulation, has met with widespread support. Clearly, another approach
may have to be taken.
I believe strongly that Clean Coal Technologies can be that new approach.
Coal represents America's most abundant energy resource and is a key to
achieving greater self-sufficiency. Some would rename the coal belt that
lies between Pennsylvania, Ohio, West Virginia, Kentucky, Illinois, Indiana,
Energy Valley U.S.A. The Northeast/Midwest region's demonstrated reserve base
contains enough coal for 750 years of consumption at 1982 levels. In fact
just these states have as much coal energy in Btu's as the entire Middle East
on which this nation has become so dependent. The only difference between the
Btu's we have underKround in the U.S. compared to the Middle East, Saudi
Arabia, or Kuwait, etc. is that our Btu's are in solid form and theirs are
liquid. In my state of Ohio, 38% of our total energy consumption and 95% of our
electric utility consumption came from coal in 1981. We expect that level to
increase, both in Ohio and throughout the United States. By increasing our
reliance on coal, we can decrease our dependence on the imported oil that once
held us hostage. We can improve our trade imbalance. We can provide jobs
and investment that will invigorate our economy. Coal is still a cheaper fuel
than its alternatives, even with the cost of control technologies added.
Therefore, as consumers, we all benefit.
The real challenge in building a coal-based energy system in the United
States may rest with Congress. In order to burn coal in our industries
and homes tomorrow, we must learn how to burn it cleanly today. 175 submissions
of interest on Clean Coal Technology have been received by the Department of
Energy. These submissions would seem to IndtL-ati' that coal can be burned
cleanlv. W^ owe it to ourselves and the n.ition to find out. Although there
50-513 0—85 2
30
may be disagreement over the present acid rain problem, there is little
ditiagreement that effective action must be taken immediately.
Clean coal technologies can correct problems arising from the direct
burning of coal and improve the process of conversion and use of coal into
gaseous or liquid forms. Clean coal technology can effectively deal with
the problem of acid rain. For example, an Ohio firm, Calderon Automation,
has submitted a proposal to DDK to convert coal into gaseous and liquid
forms with no environniejiLal ly liazardous by-|)roduc ts . An assessment of till:-,
plan by the Bechtel Corporation stated that Liie Calderon process Is technical ly
feasible and economically souml .
Clean coal technology Is needed, but must be researched further and
brought to commercialization. The potential impact on our nation's economy is
great. In my own State of Ohio, where we have a huge reserve of high-sulfur
coal. Clean Coal Technologies would mean jobs and renewed industrial growth.
However, j',iveu the current oil glut and the environmental problems associated
with coal, this crucial research and commercialization needs to be encouraged
by the federal gove rniiien t . With the acceptance and support of .i Clean c;oal
lechnologies |)rogram, [iroposals such as the Calderon I'rocess for a clean coal-
based economy can bring us the benefits of a stronger economy and a healthier
environment. The Congress acknowl edgi'd these facts last year by authorizing
these funds. .''Ir. Chairman, members of the Subcommittee, I thank you in advance
for your support of Clean Coal Technologies.
31
Mr. FuQUA. Bill, in your statement, in your formal statement,
you are referring to the report and to the environmental promise,
cost, stage of development and scientific feasibility of some of the
technologies, and you said this will be submitted to Congress. Is
there any indication when we might expect that report?
Mr. Vaughan. I don't have a good idea quite yet, Mr. Chairman.
I believe it will take some months, however, to do a comprehensive
monograph-type inquiry using all these sources.
Mr. FuQUA. Is DOE going to do this in-house with your own em-
ployees, or do you plan to contract that out or hire consultants to
do that?
Mr. Vaughan. I believe, Mr. Chairman, that this particular fur-
ther report, and this is my personal opinion, can best be done by
an outside activity rather than inside personnel, one, for practical
reasons. We do have ongoing programs and we need to have these
50 people that were involved in this effort back in their mainline
jobs, and I simply feel that we cannot afford this additional activity
on their part. And second, I believe that those 50 scientists and en-
gineers gave this a very good shot, and that the most advantageous
stance now would be to have as objective and out-of-the-fray look at
the problem, as distant a look at the problem, as we can get. Of
course, we are actors in this process ourselves, and we think that
having a report done by an outside activity would be more useful.
Mr. FuQUA. But you haven't engaged anyone yet or signed any
contracts
Mr. Vaughan. No, we have not, Mr. Chairman.
Mr. FuQUA [continuing]. Or set a timetable, then?
Mr. Vaughan. In fact, we haven't really decided — it may well be
that the most effective format is a grant rather than a contract, so
that it truly is independent.
Mr. FuQUA. When you reach a decision about the timing of the
report, could you notify the committee so we might have a timeta-
ble of expectation, so that we could discuss it.
Mr. Vaughan. Yes, Mr. Chairman, I will be more than happy to
when we make decisions on this matter. I think it would be appro-
priate to draft a letter to the committee and inform you of the way
we think we should do it, and the timeframe that we have in mind.
Mr. FuQUA. Thank you. The report to DOE states that DOE is
unable to judge which of the emerging technologies is most likely
to be accepted for extensive future use by industry. Now, it would
seem that the issue is not of acceptance, which is an industry deci-
sion, but rather of technical readiness so that the industry can
make that decision.
In that context, is it the position of DOE to judge the future as to
when emerging technology will have completed development neces-
sary for an industry decision?
Mr. Vaughan. If I understand your question, Mr. Chairman, as
we try to put together the role as we see it in R&D, we are trjdng
to do the things that are long range, high risk generic, and which
we see that industry either is unwilling or unable to do itself. If we
find a promising idea that industry is doing on its own, we very
consciously do not put the Government into the same activity.
What we are talking about in the context of this report in gener-
al is not R&D. If you recall, this report specifically sought out sug-
32
gestions and ideas for demonstration projects. That is, really, the
step of taking financial risk, to take technologies that have been
brought through the technological question stage; that is, through
the proof-of-concept portal, and carry them to the market.
Mr. FuQUA. Let me maybe clarify what I'm talking about. De-
pending on the financial risk that someone is willing to take, would
that influence you or do you determine where the technology is
going to be? If someone comes in and wants to fund 75 percent of
it, another comes in and says, "Well, we want you to fund 75 per-
cent," would that give you an indication how much confidence they
had in their technology?
Mr. Vaughan. In general, that does give one an indication of
how confident the proposer or submitter is in his own work. He is
seeking to have, in general, minimum Government involvement so
that he has maximum latitude to move on and make his profits out
of the exercise. And then when you have a high cost participation
recommended that usually indicates that the proposer or submitter
is quite confident in the technology.
Mr. FuQUA. So DOE would not try to judge, necessarily, emerg-
ing technology that has completed the development stage, but let
that be an industry decision?
Mr. Vaughan. Absolutely, Mr. Chairman.
Mr. FuQUA. Let the market forces.
Mr. Vaughan. Absolutely. We have no interest and, really, we
think we have no proper role in making that kind of risk decision
for industry. And we think in the past when we have gotten in that
role we have been rather singularly unsuccessful in moving
projects forward. The Government's ability to make that kind of
decision based on the track record has not been a very good one.
Mr. FuQUA. Well, let me compliment you on that position.
There is also widespread reports that the Secretary has offered
to prioritize the "Emerging Coal Technologies" report, and I'm
trying to understand what does the term "prioritize" mean. Does it
refer to technology or letter of intent, or both? And when will this
be done? Who will perform the activity? And what value do you
place on the results of it?
Mr. Vaughan. I, frankly, cannot tell you precisely what the Sec-
retary meant in that dialog. I do know that he made very clear to
me what he did not mean, and he did not mean that he would rank
order these 176 proposals as item 1, 2, on through 176. He made
that very clear that is not what he had intended. He was hopeful
that we would be able to rank technologies or prioritize technol-
ogies. He is now more mindful of the fact that that is really an ex-
traordinarily difficult chore and, at best, has limited utility. Be-
cause it's ranking or prioritizing technologies for what purpose?
We give an example. If you are looking for something to be used
by utilities, one approach might well on balance, look to be most
promising. On the other hand, something to be used in the trans-
portation sector may be a totally different technology. You will
have different sets of criteria for different end uses for different en-
vironmental needs and those sorts of things; and even, perhaps, for
different coals.
33
Mr. FuQUA. Well, that was my next follow-up question. Would it
involve the different regional-type sources of coal? Or would that
be prioritized?
Mr. Vaughan. That is a factor. I think, though, it is hard in a
priorities sense. I think prioritize, perhaps, has the wrong connota-
tion because that might lead one to think that Eastern coal is more
desirable than Western coal.
Well, ask for what purpose? You have high and low sulfur coals,
you have high and low Btu content, high and low moisture and ash
content — these are the things that really make the difference. You
also have distance from mine, cost factors such as hauling and so
on. So, it seems to me that one must be very careful in an attempt
to prioritize technologies. I think that is, frankly, an exercise that
our predecessors attempted without a lot of success. Attempted to
decide that gasification is inherently better than liquefaction, and I
am not sure that that is a supportable conclusion. Better for what
purpose under what circumstances.
I think what we are trying to do, Mr. Chairman, is to offer the
widest possible array of technological choices for coal utilization for
the amount of funds that we feel we can afford to put to this use.
And so thus, we have set up some criteria such as if we know that
a company is proceeding with the technology and it looks like they
are doing fine, then we are happy with that and we don't attempt
to compete with them. Let them do it. We will go use those funds
somewhere else.
Clearly, if we are going to work with industry, we like the con-
cept of cost sharing, because we get to leverage those dollars. I
think I also, before this very committee, have a number of times
indicated that I think cost sharing should continue all the way
through the project. Unfortunately, in the former years, the tend-
ency was for there to be massive Federal funding available. There
was talk about cost sharing but the cost sharing came late in the
process. If the process ran into technological or economic difficulty,
somehow the private dollars were never put up. It seems to us that
we should learn from those lessons of the past, and we are propos-
ing to.
Mr. FuQUA. Let me commend you. I think your approach appears
to be a commendable one, and I hope the forces at DOE and 0MB
let you follow through in that fashion.
Mr. Boucher.
Mr. Boucher. Thank you, Mr. Chairman.
At the outset, I want to commend the chair for holding this very
timely hearing on what I think is a very important subject. I want
to thank Secretary Vaughan for joining us here today.
Secretary Vaughan, I can't say that I was entirely surprised, but
I was somewhat disappointed at the conclusion reached in your
report that the Government should not participate at this time in
cost sharing for the construction of demonstration-scale projects. It
seems to me that that conclusion is squarely in conflict with the
report that DOE requested and recently received from the Energy
Research Advisory Board, which finds that the emerging clean coal
technologies are not going to be promoted through the commercial-
ization stage, through the demonstration stage, in the absence of
some assistance from the Government. As a matter of fact that
34
report concludes that there is a very real role for DOE to play in
assisting with the construction of demonstration-scale projects, and
that the abandoning of these projects after the proof-of-concept
stage is going to result in exactly that, in their words, "abandon-
ment of the project." And I think that has been the history.
In light of that recommendation which DOE requested from the
Energy Research Advisory Board, why have you reached your con-
clusion? Do you just flatly disagree with the Advisory Board's rec-
ommendation made to your Department?
Mr. Vaughan. Well, first, Mr. Boucher, I don't believe we have
formally received that report, although I have read the two drafts
of the report and I think I certainly am aware of its thrust in its
basic conclusions. In fact, I am very much aware of those. I think
you have, perhaps, characterized the thrust of the report fairly ac-
curately. I would point out, however, that the report — I would
characterize that report as saying, first, it concentrates on utility
use of coal; secondly, it concentrates on doing that very rapidly, or
at an accelerated pace; and then it reaches the conclusion that in
order to do accelerated coal utilization in utilities it will be neces-
sary, in the ERAB panel's opinion, to have Federal Government in-
volvement in the demonstration and development phases.
Now, if that is one's mission; that is, to see that utilities use coal
at a much more accelerated rate, then I think perhaps the conclu-
sions of the ERAB report would be indeed hard to argue with. In
fact, I take no basic argument with the report itself. I think this
administration, however, has defined its role in a number of energy
areas in a significantly different manner. It has seen its role as
trying to make it technologically possible for our private sector, in-
cluding utilities and equipment manufacturers, coal producers, and
others, to make decisions and move forward as they see fit. We do
not see that it is necessary to use taxpayer funds in this process.
I do not think that we would argue that certainly the process
may be slower. I think that is brought about by several factors. The
first is we believe fundamentally that the government should not
be making these kinds of entrepreneurial risk-type decisions, and
clearly, in my judgment, the decision to fund a particular project
on a cost basis, any kind of cost basis, will grant to that particular
technology or project a competitive advantage and a real leg up.
Undoubtedly, it will move it faster, but what one needs to ask is
what about the situation we are, in fact, in? That is, limited funds
and a need to make those funds go as far as possible and to offer as
many choices as possible to the public at large. I think that is the
essential area of disagreement.
Now, ERAB I think very forthrightly calls into question that
policy difference and asks us to reconsider it. The Secretary asked
for that report in good faith, and I think I can assure you that he
will consider it in good faith. But he does, along with the rest of us
in the administration, have to balance a number of factors. So I
wdil not promise you, because I, frankly, do not know how he will
come out of that balancing process.
Mr. Boucher. Well, I am delighted to hear you say that the
ERAB report is going to be fairly and objectively evaluated in due
course by the Department, and I, for one, hope that in view of its
clear recommendations, which are in conflict with the recommen-
35
dations that your report contains, that some amendment to your
recommendations will be forthcoming.
I noticed a statement that you made during your response to the
chairman's question. That the Department should not be placed in
the position of competing with private concerns that are in the
process of constructing demonstration-scale facilities for emerging
clean coal technologies. I am, frankly, not aware of private con-
cerns that are in the process of doing that. We know that atmos-
pheric fluidized-bed combustion is being developed, but that was
done almost solely at Government expense, perhaps all at Govern-
ment expense. I am not aware of clean coal technologies today that
are being developed purely by private industry and that are being
placed in a demonstration-scale posture.
If you can enlighten me some on that and point to some areas
where the Government would be competing, I would very much
like to hear it.
Mr. Vaughan. Well, let me just, Mr. Boucher, go to the report
itself. I mean our report, now, and the submissions we received be-
cause we did receive several indications in that effort alone of such
activity. Southwest Public Service, a utility, asks only that we
assist in achieving regulatory changes with the EPA. It very specif-
ically did not ask for any fund sharing, not one dime.
Mr. Boucher. What kind of project were they proposing?
Mr. Vaughan. It was a lime injection — LIMB project.
Southwestern Public Service, the same company, in an AFB pro-
posal asked for, if I recall, $700,000 out of a $100 million project.
That is very close to asking for little to no funding, and it is hard
for me to believe that at the funding level they were discussing the
absence of the $700,000 will spell life or death.
Mr. Boucher. What kind of project was that?
Mr. Vaughan. That was an AFB project — atmospheric fluidized
bed.
Colorado Ute Utility currently has under construction a private-
ly financed, as I understand it, AFB project, sought no funding. In
a coal gasification process, K-fuel process, actually the company's
submission was in the tone of asking us not to recommend Federal
funding at the demonstration level pointing out that it had spent
millions of dollars of its own and that it would consider funding of
its competitors as an economic disadvantage and then saying, how-
ever, if you want to throw the taxpayers' money away we would
like to be refunded for the efforts we have put forward so we will
be on an even playing field.
There are several significant developments I think in coal/water
fuels — to get out of the report itself — that are aggressively moving
forward with essentially no Government funding. You can buy the
fuel. The manufacturer will sell it to you, enter into a contract
today, as I understand it. There are a number of fluidized-bed boil-
ers under construction with no Government participation.
So, I think there are instances in which progress is being made
without Government funding, and again at the demonstration
scale.
Mr. Boucher. Well, it is encouraging to hear that that is happen-
ing, and I appreciate your supplying that information. I know that
a number of proposals have been made for physical coal cleaning.
36
precombustion, which private industry frankly feels it cannot move
forward with on its own. I am not aware of any projects of that
nature that are slated for purely private funding at the demonstra-
tion-scale stage. It occurs to me that these are enormously promis-
ing, and I would hope that in any supplemental report that the De-
partment prepares that consideration would be given to cost shar-
ing with respect to that construction.
Let me ask one final question, if I may, and that relates to infor-
mation that has been received recently concerning the possible par-
ticipation of the National Coal Council in working with the Depart-
ment of Energy in establishing some priorities for the utilization of
emerging clean coal technologies.
Is that accurate information? Is the Department actively consid-
ering that? And if so, what would the National Coal Council's role
be in that effort?
Mr. Vaughan. As you know, we are currently underway in set-
ting up the National Coal Council, and I am aware of the informa-
tion that we may ask the National Coal Council to look into this
matter. I think perhaps that is a little, stated a little simply one of
the purposes, in fact, the prime purpose of setting up the National
Coal Council was to have available to the Federal Government the
advice of these persons asked to serve on this Council from a wide
range of backgrounds and interests in coal. And among the topics
that one would logically ask at some point is what does the Council
think about various technologies that affect the coal industry.
There are many other topics that affect the coal industry that we
would expect to ask the Council about, too. In fact, anything of in-
terest to coal utilization is fair game. Now, the confusion I think
comes in the context of this particular effort. I think that is indeed
confusion. We have ourselves just filed this report. As I mentioned
in my testimony the International Energy Agency's R&D arm just
completed, fairly recently, a report on coal technologies, and
ERAB, as we discussed here, is also completing a report, and we
will be looking at those and other information and certainly I
think it would be appropriate to seek some input from the National
Coal Council.
However, I think what we definitely do not intend to ask the Na-
tional Coal Council is how to divide up the $750 million. That is the
kind of flavor that came out in the trade press, and I think I can
assure you the Secretary did not have that in mind.
Mr. Boucher. Well, I want to commend you, Mr. Secretary, for
the suggestion that the Coal Council be involved in considering the
appropriate roles for the Government in funding for research and
development efforts. I know that one of the companies that will be
represented on your Council is very active in private R&D efforts,
and I think there is some very useful advice that could be forth-
coming that would significantly assist the Department.
My time has expired, Mr. Chairman. I want to thank you again,
Mr. Secretary, for your interest in this subject and for being with
us today.
Mr. Vaughan. Thank you, sir.
Mr. FuQUA. Mr. Brown.
Mr. Brown. No questions.
Mr. FuQUA. Mr. Fawell.
37
Mr. Fa WELL. No questions.
Mr. FuQUA. Mr. Packard.
Mr. Packard. Thank you, Mr. Chairman.
I am particularly excited about the renewed interest in coal and
its usefulness, and the efforts being made to clean up coal to where
it becomes a useful resource for us.
Mr. Secretary, the efforts in coal cleanup it would appear to me
could be done in different ways. You referred to the fact that high
sulfur content and high and low Btu capabilities may alter the
cleanup process so that it could be cleaned up specifically designed
to service a certain purpose. Would that mean that there could be
different processes or ways in which we would prepare coal for a
useful purpose?
Mr. Vaughan. Absolutely, Mr. Packard. Let me just briefly try
to take you through where I think is the broad area of effort. Our
research program is directed currently in three broad areas. We
are doing R&D on cleaning up coal as soon as you have mined it
and before you try to use it. That is generally referred to as coal
preparation, and there are a number of techniques that are being
seriously investigated in that area.
Then we are addressing the combustion process itself, and there
you have a twofold effort. You are trying to increase efficiency so
that you burn less coal for each unit of useful energy you get out of
the process. And secondly, we are looking at a number of tech-
niques as ways to improve the environmental response in the com-
bustion process itself and, very loosely put, try to burn up the pol-
lutants in the process itself or cause a chemical reaction to occur
during the combustion process that renders an otherwise harmful
pollutant inert.
And finally, we are doing work in the post-combustion phase;
that is, something that you hang on the flue gas end to try to im-
prove the environmental performance. It is in that area that the
term "retrofit" is often used because the country has considerable
capital stock in existing equipment that can use either the— you
either put much cleaner coal into the process on the front end or
you have to clean up the effluent on the back end because you are
fundamentally stuck with a combustor for the rest of its service
life.
And last, I think I ought to refer to yet a fourth area and I will
generally refer to that as the more exotic approach, and that is to
make totally new fuel forms such as coal/water mixtures, coal/oil
mixtures, and perhaps even a fuel of an ultra-fine powdered coal or
a mixture of partially refined coal and the chars and liquids that
we can produce. In that broad category I would also include gasifi-
cation. The technology there is proceeding both to gasify in place-
that is, in situ, as you find the deposit— and also to mine the coal
and put it in a retort for gasification purposes.
Mr. Packard. Is one of the primary objectives in a cleanup proc-
ess to resolve the acid rain problem?
Mr. Vaughan. It is certainly one of the primary objectives; yes,
sir.
Mr. Packard. In the R&D work that is being done on coal, what
are the tax incentives or the other incentives? In some resources
there are depletion allowances, there are research or exploration
38
benefits; are there any such benefits in encouraging the research
and development of coal use cleanup process?
Mr. Vaughan. Congressman, I do not believe that there are any
special tax incentives for coal R&D on the books today that are
above and beyond the usual tax expensing or cost of R&D for any
purpose.
Mr. Packard. Has there been any analyses to equate the re-
search and development of coal in relation to other either energy
or resource needs of the country?
Mr. Vaughan. If I understand your question correctly, Congress-
man, you are asking me have we investigated the relative role of
coal and promise of coal among our energy resources, and if that is
the thrust of your question, yes, we have rather extensively.
Mr. Packard. I am talking now about an analysis of the tax in-
centives or other incentives tied with other products in relation to
coal, or are we treating some resources, oil and forests and so forth,
taxwise differently than we are coal, and does that render coal and
those who research coal in terms of cleanup process, at a disadvan-
tage businesswise?
I may be asking questions that are not within your purview, I
am aware of that. But I am interested in knowing if there are in-
centives or if there could or should be incentives that equate to oil
and other energy materials.
Mr. Vaughan. I, frankly. Congressman, am not sufficiently in-
formed on the tax aspects to really fully answer your question.
May I take that question for the record
Mr. Packard. If you have someone on your staff that could pro-
vide that for the record, I would appreciate it.
Mr. Vaughan [continuing]. And consult with my colleagues over
in Treasury and other parts of the Government and give you a
comprehensive answer?
[The material referred to above follows:]
Tax Incentives Related to Coal R&D
We are not aware of any in-depth investigation done by DOE that compares exist-
ing tax incentives related to coal R&D and incentives for other energy resources.
However, it is our belief that existing incentives are such that rational, market-
driven decisions are being made with regard to funding coal R&D. Special incentives
or vehicles oriented toward R&D include the 25 percent tax credit, R&D limited
partnerships, and the passage of the legislation relaxing U.S. antitrust laws regard-
ing joint R&D ventures. All of these have proven very popular and effective, and
would certainly be applicable to coal-related R&D.
Mr. Packard. I think it would be at least of interest, if not per-
haps productive, in terms of looking at the future for coal.
One last question, Mr. Chairman, if you would permit. And that
is I heartily endorse the concept, and have in not only coal re-
search but in most other areas, of the cost-sharing concept with the
private sector. I also endorse the concept of repayment when our
Government funds are responsible to some degree of producing a
technology that is commercially marketable and that the private
sector can benefit from.
Is that being considered wherein the research that the Govern-
ment funds or are participating in that there is a reimbursement
agreement that if and when commercialization takes place the
39
company benefiting from such commercialization would repay Gov-
ernment participation in the research and development?
Mr. Vaughan. The answer to your question, Congressman, is
that one of our prime criteria for considering proposals generally
in R&D in the Fossil Energy Program is the degree and extent of
cost share offered by the private sector. And that is one of our
prime interests. I would point out very specifically that Congress in
laying out the charge for this particular report that we are discuss-
ing here this morning laid particular emphasis on that subject, and
the response is, indeed, informative; that there appears to be a
fairly high degree of willingness to engage in cost share.
With respect to the reimbursement, we have used that technique
on occasion, particularly where the Government portion of the
funding had been proportionately quite large. And we have projects
today where there is a reimbursement agTeement involved. I think
reimbursement agreement is quite useful, but I do think there is a
trap that one can get in with respect to reimbursement agree-
ments. The government only gets its funding back when there is
success in the marketplace.
Mr. Packard. I think that is appropriate myself.
Mr. Vaughan. A number of us would question, in this adminis-
tration, whether it is appropriate, particularly after one passes the
R&D phase, to provide funds to a project and have as the only
means of reimbursement. In that situation the company involved
has little to nothing at risk, and we think that is most undesirable.
Mr. Packard. I would agree with that.
Thank you, Mr. Chairman.
Mr. FuQUA. Mr. Walgren.
Mr. Walgren. Thank you, Mr. Chairman. Let me ask at the
outset, Mr. Chairman, if I could introduce into the record, with the
other members' consent, testimony of Congressman Dennis Eckart
given before the House Appropriations Subcommittee on the Interi-
or on behalf of the Northwest-Midwest Coalition. It is a useful
statement and one that I would like to make a part of our record if
I could.
Mr. FuQUA. Without objection, you can include that.
Mr. Walgren. Thank you, Mr. Chairman.
[The prepared statement of Mr. Eckart follows:]
40
(f?
\-
■K«'
CONGRESSIONAL COALITION
US House of Representatives
CO-CHAIRS
Howard Wolpe (Ml)
Frank Honon INYl
VICE-CHAIRS
Bob Edgar (PA)
Silvio 0 Conte (MA)
James L. Oberflar IMNI
TREASURER
Claud.ne Schneider (Rl|
STEERING COMMITTEE
Berkley Bedell (lAI
Sherwood L Boehlert iNY|
Roben A Borsk. (PA)
Beverlv B Bv'on (MDl
Thomas R. Carper (DE)
Will.arn F. Clinger. Jr, (PAl
Thomas J. Downev (NY)
Dennis E- Eckan lOH)
Lane Evans HL)
Edward F Feighan (OH)
Hamilion Fish. Jr (NY)
Frank J, Guanni (NJ>
Steve Gunderson (Wl)
Lee H Hamilton (IN)
Paul B, Henrv (Ml)
James M JeMords iVT)
Marcv Kaptur lOH)
Barbara B. Kennellv (CT)
Sian Lundine (NY|
Stewan B. McKmnev (CT)
Lynn Martin (ILI
Nicholas Mavroules (MA)
Parren J. Miichell tMO)
Barbara A Mikulski <M0)
Jim Moodv (Wl)
Henry J. Nowak (NY)
Donald J Pease (OH I
Carl 0 Pursell (Ml)
Thomas J, Ridge (PA)
Manhew J. Rinaldo (NJ)
John G. Rowland iCT)
Roben C. Smuh (NHI
Olvrripia J Snowe (ME)
Thomas J Tauke (lA)
Bruce F. Vento (MN)
Doug Waigren (PA)
Sidnev R- Yaies IlLI
EXECUTIVE DIRECTOR
Laurence Zabar
TESTIMONY OF
THE HONORABLE DENNIS E. ECKART
EErORE THE
HOUSE APPROPRIATIONS SUBCOMMITTEE ON INTERIOR
April 18, 1985
530 House Annex No. 2. Washington, D.C. 20515 • 1202) 226-3920-
t
J
41
Hr. Chairman and Members of the Committee:
As a member of the Steering Committee of the Northeast-Micwest Congressional
Coalition, I welcome this opportunity to testify on the treatment of the Clean Coal
Technology Reserve in the fiscal 1985 Interior Appropriations bill. My colleague,
Rep. Claudine Schneider of Rhode Island, will be testifying before you on other
issues in the Interior Appropriations bill of particular concern to the Coalition.
The Northeast-Midwest Congressional Coalition, formed in 1976, is a bipartisan
organization of nearly 209 nembera of the House from the 18 states of the region.
We seek to inform our members of the ramifications of national policies upon the
region and to Influence those Issues of greatest impcrtance to the states of the
Northeast and Midwest.
Earlier this year, in testimony before the House Budget Committee, the Coal-
ition supported a freeze of budgec authority for defense spending and for most
domestic programs at fiscal 1985 levels. We believe that a freeze such as the one
we advocate is necessary if Congress is to demonstrate its commitment to fairness
and equity, and must be accepted as the first step toward creating any deficit
reduction package.
At this time, I would like to address the importance of funds being
appropriated In the fiscal 1986 Interior bill for the Clean Coal Technology
Reserve. Last year the Congress established a $750 million Fund from the $5.1;
billion rescission from the Synthetic Fuels Corporation.
The reserve was established to support cost-shared demonstrations of tech-
nologies that are near commercialization and that could burn coal cleanly and
economically. The Coalition strongly urges that funds be appropriated so that at
least several projects can receive funding in fiscal 1986. It is clear that
substantial interest already existing In the private sector, as 175 statements of
-1-
42
interest have been received by the Department of Energy concerning the reserve.
The submissions have cone from 28 states, Including 14 states from the Northeast-
Midwest region.
Furtherance of clean coal technologies is of special importance to the
Northeast-Midwest region for several reasons:
o Coal is an abundant, indigenous energy resource and can continue to be an impor-
tant energy source for the future as long as it is developed in an
environmentally sensitive manner;
o The U.S. continues to Import substantial amounts of oil which contributes
significantly to our trade deficit: these imports potentially could be reduced
through use of other alternatives such as conservation, renewables, and clean
coal ;
o The Energy Information Administration predicts that overall coal use will in-
crease by nearly one-third in the next decade in both the utility and industrial
sectors;
o Most of the coal in the Northeast-Midwest region has a high sulphur content,
thereby raising environmental concerns about its use;
o Coal currently accounts for over half of all energy consumed by the utility
sector in the U.S. and for 30 percent of the energy used by utilities in the
Midwest;
o The coal mining industry has an important effect upon local employment.
Nationally, coal mining employment dropped from 229,000 in 1980 to 176,000 in
1983; In the Northeast-Midwest region, employment dropped from 71,000 to 57,000;
o Clean coal technologies burn coal more efficiently, economically, and with fewer
emissions.
The last point is key, as such advancements will permit greater use of coal as
part of our overall least-cost energy strategy providing as well some protection
-2-
43
for the high-sulphur coal industry of our region. Since states in the Northeast-
Midwest region accounted for nearly half of the total sulphur dioxide emissions in
1980, it is important to the region that clean coal technologies be brought to
commercialization as rapidly as possible.
While the Clean Air Act has achieved valuable Improvements in the quality of
the nation's air, many believ that coal use permitted under the act continues to
pose serious environmental threats. Present Clean Air Act regulations have had a
significant effect on the ccal market; future large-scale reduction programs would
have an even greater impact. Such a reduction plan would require retrofitting of
utility pj.ant3, the expense of which leads to concerns about adverse effects om
employment and electricity prices.
New Source Performance Standards provided for by the Clean Air Act are much
more stringent than those for existing facilities. However, many utilities have
chosen not to retire old plants, partially because of the cost of these standards.
Availability of clean coal technologies could help lower the costs of meeting the
standards and thereby encourage the expansion of "cleaner" facilities to meet
energy needs.
Another problem in our region involves "tall stack" industries. The courts
have ruled chat the use of taller stacks to disperse emissions over a wider range
no longer meets the requirements of the Clean Air Act. Obviously, the successful
demonstration of clean coal technologies would provide utilities and industries
with a range of options for meeting "tall stack" and "new sources" standards that
are much more effective. Without the options that can be provided by those new
technologies, future electricity growth could be hampered.
Industrial applications of clean coal technologies also are important. Indus-
tries with large, continuously operated boilers will find it attractive to burn
more coal In the future. Certain basic industries, such as steel manufacturing,
-3-
44
are facing numerous challenges in modernization and trade competition. Economical
ways to meet energy needs in compliance with Clean Air Act requirements would boost
the productivity of these industries greatly. Fluidized bed combustion is an
example of a technology with industrial applications where the federal role in
research and development has resulted in a technology that is both cleaner and
cheaper. The Clean Coal Technology Reserve can play a crucial role in developing
cost-effective ways of burning coal cleanly in Implementing present or future Clean
Air provisions.
In conoluslor, it should be r.otei that ./'•lile the administration did not
request appropriations for fiscal 1986 for the Clean Coal Technology Reserve, a
recent report prepared by the coal panel of DOE'S Energy Research Advisory Board
recommends that DOE give greater rupport to clean coal demonstration projects. The
reserve provides the opportunity to assure industries and utilties that investments
in clean coal technologies will result in cost-effective emission reduction. The
cost sharing required by the reserve spreads the cost of development and uses the
private sector to help identify those technologies with the best chance for suc-
cess. Funding for the development of clean coal technologies can play an important
role in revitalizing our regional goals of least-cost energy development, economic
growth and natural resource protection.
45
Mr. Walgren. I have to express some real disappointment in the
report that was submitted in response to the 1984 continuing reso-
lution. I think I feel that you understand, also, and feel the same
shortcomings of that report inasmuch as you state in your testimo-
ny that you are going to take some further steps now in pursuit of
that subject and that evaluation. I keep going back in my mind to
the idea that if we had had a proctor or somebody for whom we
were writing a thesis of some kind we could have been redirected
or told that simply the summary that was developed was not re-
sponsive to the mandate to assess these various technologies be-
cause there is very little assessing done in that process, and in that
sense we failed the task; and if the time on our Ph.D. was running
out, we would fear that we might not get the degree after all.
I wanted to ask, you indicate that your first effort will now be to
establish criteria against which these technologies can be evaluated
or assessed as I gather it. Given the fact that we have, certainly,
limited budgets, the danger in this area is that the Congress or the
administration would put all its eggs in very few baskets or put
them in the wrong baskets, and somebody, either the Congress or
the administration, has to be able to compare these suggestions.
And there is no way to compare them unless we do have some cri-
teria.
I wanted to ask very directly whether you are now embarked on
setting some criteria so that one could objectively measure these
proposals, and, hopefully, one of those criteria would be their near-
term effectiveness in reducing of the present emission levels that
we are all concerned about, and another criteria would be the
breadth of their application or the degree of the problem that those
technologies would reach literally. I mean we want to be pursuing
something that is broadly helpful in the long run. Would that be
your estimate of what the next step is now that we didn't do that
in the first instance?
Mr. Vaughan. When you ask that question. Congressman, do
you mean a prioritizing of these 176 proposals? Is that in the con-
text of what you mean, the question?
Mr. Walgren. Well, it is my understanding that the request that
was made for this study was focused on the 176 proposals. I would
gather out of that range of proposals there would be a way to focus
on groups of them. I am just looking for some way that somebody
other than the Tooth Fairy could make some judgments in this
area, and we don't seem to have it yet. And we are asking you to
set out some method of judgment so that we can both know that
you have gone through a proper process and so that someone else
can look at it and compare their judgment with yours.
Mr. Vaughan. I think. Congressman, what you are hitting at is
how or what we did in evaluating. As I think you are aware, sir,
this process was specifically designed to obtain informational pro-
posals. It was not a competitive procurement process, and that is
because the Congress did not appropriate funds. And it is not fit-
ting or proper for any agency of the Federal Government to go out
to the private sector and invite a series of proposals when it does
not have in hand funding to spend on those proposals and its policy
does not call for activity in that general area.
46
Mr. Walgren. Pardon me, Mr. Secretary, if I might. This was
the Congress asking that something be done. It was not the Execu-
tive deciding what it wanted to do or what it would Uke to do. The
Congress is in the position, as I understand it, of needing informa-
tion, and that law, which was signed by the President, became the
policy of the administration. You were to assess the potential use-
fulness of each emerging clean technology, or clean coal technolo-
gy, and you were to identify the extent to which the Federal incen-
tives would accelerate commercial availability.
Now, we can all say until we are blue in the face that we don't
believe we should accelerate the commercial availability, but that
is not what the administration was asked by the Congress, and that
is not what the President asked you to do when he signed that law.
So, my observation is that there was precious little assessing done
in that report, and there was literally no addressing of the question
that you were asked by law to do, which was to identify the extent
to which Federal incentives will accelerate the commercial avail-
ability.
Now, we can have that fight all the way down the road about
whether we should or shouldn't accelerate the availability. But, ul-
timately, that is for the Congress to decide if the President picks
up an initiative that comes out of the Congress, and it is not for an
administrative level of our system to refuse to cooperate with. And
I would almost characterize it in that degree. I don't want to be
antagonistic because it is not my nature and it is not my will, and I
don't think it is the most constructive thing, either. But I look at
that report and I say: "Gosh, here we were asking to be put in the
position where we could make this judgment if we felt it in the na-
tional interest, and we relied on the Department of Energy to pro-
vide information that would put the Congress in a very important
position, and apparently somebody's bias got in the way, and in
that sense, deprives the Congress for another 6 months or another
9 months from the ability to serve the national interest in a way
which the President and the Congress might find very much in the
national interest."
Mr. Vaughan. May I respond. Congressman. I believe that the
report does, in fact, contain rather comprehensive technology as-
sessments. I would specifically direct your attention to appendix C,
which is a rather lengthy technology assessment section. And be-
cause we have picked up some dissatisfaction with that effort,
which is not inconsiderable, the Secretary has directed that we go
even further in this particular area. However, I would point out to
you that technology assessments and characterizations still will not
give one an automatic process by which to make funding for
projects in my judgment. The only process I know of that effective-
ly works is a full competitive procurement process, which we did
not have.
Mr. Walgren. I guess what I am looking for is the criteria by
which we might, and the administration might, evaluate these
processes. I don't know that I am asking for a competitive submis-
sion, but I think it very important that we be able to make some
judgment about the near-term application and about the breadth of
application. And I would hope that in your effort now, as you say
your first effort will be to establish criteria against which technol-
47
ogies could be evaluated, I hope that you would look at those two
points and see what can be developed in terms of criteria that
would be responsive to that, so that if we feel and if the President
signs — and changes his mind. I mean things are not set in clay.
The President might feel that we really ought to do something in
this area at some later point — that we would be in a position to do
so.
Let me also ask one other thing sort of on a philosophical level. I
understand your reservations about not wanting to influence and
give competitive advantage to X, Y, and Z technologies. On the
other hand, I do also understand that some of these proposals for
funding, particularly one, this Penn Electric system up in western
Pennsylvania, where they were going to propose to use some Feder-
al funds to run some various tests on a limestone injection burning
system that they put in there. There they are not wanting to give
an advantage to one system or another, as I understand it, but
really only asking for some help in information collection.
Now, you indicate that some apparent advantage of Government
participation in certain circumstances would be improved informa-
tion dissemination. Would you agree with me that there would be a
very useful role of the Government to participate in any program
that would collect information, that we would think would be
useful, that would not otherwise be collected by the private sector
or make it more widely available so that other elements in the pri-
vate sector could have the benefit of at least that much of a leg up
on a technology or on a piece of knowledge?
That kind of Federal funding it would seem would not run afoul
of your feelings that we shouldn't give a competitive advantage to
anything. We would simply be giving knowledge, per se. Would you
agree with that thrust?
Mr. Vaughan. Certainly I would agree on a very broad basis,
Congressman. If, indeed, a proposal is for broad information. That
is what we mean by the criteria "generic" that we use in our R&D
criteria. That it has broad application. What we seek to avoid is
using taxpayers' funds for one particular commercial entity's spe-
cific project or specific mine and, in effect, provide a competitive
advantage. But in this, the broad proposition, yes, sir, I wholeheart-
edly endorse it.
Mr. Walgren. OK. Let me ask one other question, Mr. Chair-
man, and I know that I have used more than my time. That would
be that clearly in this area we have got to be hand in glove with
the EPA. After all, they are making a lot of the judgments that are
driving us, literally. That raises the most difficult governmental
problem of coordination, and coordination is not often appreciated
because it means people spending time without an awful lot to
show for it, meetings and the like. And none of us appreciate just
sending somebody to a meeting, but it is absolutely essential.
What is the intensity of the degree to which your office is work-
ing with EPA so that we know that there is not only full communi-
cation, but even a common purpose and a common intent and there
would be the opportunity for each to develop in response to the
other? Can you describe the intensity of that contact with EPA?
Mr. Vaughan. I believe there is a fair amount of contact be-
tween the two agencies. As you point out, certainly a number of
48
meetings and communications between the Departments. Very spe-
cifically, we jointly serve on the NAPAP [National Acid Precipita-
tion Advisory Panel], I believe is the correct terminology. But there
are different roles for the two agencies. EPA is essentially an en-
forcement agency, and we are an agency in the Department of
Energy that seeks to promote energy utilization in an environmen-
tally acceptable manner. All of our efforts are aimed at making it
possible to use various, and in the fossil fuel program's specific
case, fossil fuels in an environmentally acceptable manner; that is,
in compliance with EPA and State standards.
So, I believe there is the adequate cooperation. We routinely
review EPA regulations and proposed regs from an energy view-
point, and make our views known publicly and to EPA.
Mr. Walgren. Well, I would just like to encourage you in that
contact because I think each of you probably has some benefit that
could be gained from the other, and that we will, without creating
conflicts of interest, be better off in the long run with as close co-
ordination between your two entities as we can.
Thank you, Mr. Chairman.
Mr. FuQUA. Thank you, Mr. Walgren.
Mr. Vaughan. Mr. Chairman, may I say something?
Mr. FuQUA. Sure.
Mr. Vaughan. I do believe it's appropriate for me to point out
that the report does have, in view of Congressman Walgren's ques-
tions, a section that specifically addresses our views of the utility of
Federal incentives. That is in the report, and I feel obliged to point
that out.
Mr. FuQUA. Let me say before I recognize the next member that
the Chair has been very lenient in the 5-minute rule, and we do
have five more witnesses that have something important to say
today. Not that we are not interested in what the Secretary has to
say, but I hope we can try to bear that in mind.
Mrs. Schneider.
Ms. Schneider. Mr. Vaughan, I would just very briefly like to
ask you about your assessment of the ERAB report. I recognize the
value of the Advisory Board. It seems that year after year before
this committee we have had some outstanding testimony presented
and some interesting analyses and studies done by the ERAB. It is
my understanding after reviewing some of the testimony that Mr.
Reichl is going to make after you that there seems to be a conflict
in the conclusions that you reach and that he reaches in terms of
the need for Federal incentives in order to make some of these
technologies more commercially viable.
I wonder if you could just summarize your justification for your
points of view and how they differ from the ERAB report.
Mr. Vaughan. I think I can do that rather quickly. Congress-
woman. The administration believes that we should concentrate
our efforts on basic generic, long-term, high-risk R&D and that we
should not be involved in the commercial demonstration phase
with taxpayers'dollars. That is the essential difference.
The ERAB report, which the Secretary asked for in good faith,
and that panel certainly has on it some very prestigious individuals
and we tend to read that report rather seriously and to take its
advice into consideration. It is abundantly clear that ERAB calls
49
into question and specifically suggests that we reconsider this
policy position about demonstration and commercialization. I think
as briefly as possible that is the essential difference the two ap-
proaches.
We fully intend to consider what ERAB is telling us. On the
other hand, there are many factors to be balanced and ERAB is
only one of them. It is an advisory panel and its recommendations
are not binding upon the Secretary or the administration.
Ms. Schneider. I realize that. Who else acts as a think tank for
you, however?
Mr. Vaughan. Well, you act in part as your own, and then in
any technological area, if your people are doing their jobs, and I
think those in fossil are, they are continually aware of the theories,
thoughts, positions, and ideas throughout the community that is in-
terested. So I think that the Department in that sense is fully
aware; and I, for example, have looked at the testimony that is
coming to this committee from other witnesses, and I do not find
those positions surprising at all. As a matter of fact, they are quite
understandable and predictable.
Ms. Schneider. But they all seem to conflict with your direc-
tives.
Mr. Vaughan. Yes; they have one luxury I think that the ad-
ministration does not have. They don't have the problem of trying
to reduce Federal expenditures in some very trying times and still
move forward as best you can with limited funding. We believe
that the most effective use of our funding is to achieve a broad an
array technologically, and that is why we are concentrated back at
the technological end. We believe that we should stay out of the
commercial risk-taking side; that is not something the Government
is currently capable of doing well and certainly its track record in
the past when it was involved in these areas was extraordinarily
poor.
Ms. Schneider. Well, then it seems to me that you are caught
right in the middle of the decisionmaking process because the ad-
ministration and 0MB has as their first priority reducing the defi-
cit, does not have the expertise in the area of energy by any stretch
of the imagination, and yet they are making policy directives and
suggestions to you. Then, on the other hand, you are suggesting
that ERAB and some of your own technical experts within the De-
partment of Energy are making recommendations based on techno-
logical assessment and energy needs.
So, it seems to me that, if I were in your position, I would have
to take the technological requirements and the fiscal restraints and
make decisions that would serve the long-range energy needs of
this country. And in looking at the direction that you are succeed-
ing, I think that one of our greatest problems right now is that
there is a lot of taxpayers' dollars that have gone to waste to devel-
op or to do the R&D on energy technologies and those technologies
are essentially sitting on a shelf.
I think one of the greatest problems this country has both domes-
tically and internationally is that we do not have a good technology
transfer mechanism, particularly in the area of energy where we
are being beaten by the Japanese, the Germans, and everybody else
in getting this technology from the Department of Energy out into
50
the grassroots. It doesn't seem to me that that is part of your
thrust. From my point of view, that ought to be one of the highest
priorities.
Mr. Vaughan. Congresswoman, first I would Uke to say for the
record that while certainly the 0MB and the President give us
guidelines for budget planning, OMB did not dictate and has not
dictated the content of the fossil energy budget. The Secretary, and
I, and the people that work for me made those budget decisions,
and we set the priorities, we set the content. We did attempt to do
within the constraints of funding availability, as does everybody
else in the Federal Establishment, to try to live within the means
that were laid out for us. So, I think we have done that balance.
Obviously, there are people who will disagree with us. Again, to
talk about the dividing line or the area where the disagreement
occurs, there are many who believe that the Government should
have an active role in, I believe the terms are "assuring certain
end uses." This administration disagrees with that. We think we
should be involved in making it technologically possible for citi-
zens, commercial entities to have the fullest range of free choices
economically, but that the Government should not have predeter-
mined through the funding mechanism what specific end uses are.
As I indicated earlier, one of the premises of the ERAB report is
to cause coal utilization in utilities faster. And undoubtedly, if you
fund demonstration, coal utilization in utilities will be accelerated.
But the question that we would raise is, is that the wisest use of
available funds? And there we would differ. I think that is a place
where we would respectfully differ.
I have no quarrel with the members of this panel who drafted
this report because I think they, given the premises, the report
hangs together. In like fashion, I think given the premises that I
have stated our position is not surprising.
Ms. Schneider. Well, thank you. I am afraid that my time has
expired, but I will be anxious to hear from the witnesses that
follow whether or not they have any concern for fiscal restraint in
their policy recommendations. Because I think it is important that
that point reach you and that future decisionmaking be done in
that context.
Thank you, Mr. Chairman.
Mr. Vaughan. It may be useful to point out to the committee
that this effort, if you simply total up the amount of funding in-
volved, calls for some more than $8 billion of additional funding.
So, certainly in toto it would appear that fiscal restraint was not
an overriding factor by the submitters.
Mr. FutiUA. Thank you, Mrs. Schneider.
Mr. Stallings.
Mr. Stallings. No questions.
Mr. FuQUA. Mr. Cobey.
Mr. Cobey. No questions, Mr. Chairman.
Mr. FuQUA. Mr. Traficant.
Mr. Traficant. Yes, Mr. Chairman, thank you.
I just want to echo the comments, and I think the perception, of
the Congresswoman from Rhode Island. It is about right on, and
philosophically I have to embrace that.
51
Here is my particular question. Although I missed the earlier
part of your testimony, I keep hearing the short time I am here
about the use of taxpayers' dollars for commercial risk taking. My
question is when do we start investing rather than spending? Even
though I am new, I think we are still rather dependent on foreign
countries for energy needs in this nation. What is the long-term
prediction, if we are not going to spur investment by Government
intervention with the tremendous resource we have in coal that
right now is being underused, undermaximized, while we are still
spending literally millions of dollars in Third World nations that
have us rather dependent for energy needs?
So, in line with some of her questioning and comments relative
to ERAB and the think tank that exists, how do you foresee our
removing ourselves from this dependency? Because we are still
spending taxpayers' dollars, sir. We are spending them in other
areas. Perhaps maybe you can comment along those general lines
as far as your overall long-range goals of investment versus spend-
ing, which it seems we are doing for foreign oil and other energy
sources.
Mr. Vaughan. First, Congressman, other than the money that is
used to purchase oil for storage in the Strategic Petroleum Reserve,
and I feel I must point out it is spending surely for energy, but it is
spending by our citizens, not by the Government itself. Here we
are talking about what we are going to do with dollars that we
have collected in the form of taxes and then how we are going to
put them back in the system. In the specific case of fossil energy,
we are trying to develop in a fiscally constrained atmosphere the
widest array possible of technological options for our entrepreneur-
ial risk-taking private sector to then exploit as it sees fit; and I
think that is what we are trying to do.
Now, generally I think this administration has an unparalleled
record in the area of reducing dependence on foreign sources of
energy. Certainly, more progress has been made in this administra-
tion on that score than any of its predecessors.
Mr. Traficant. Well, then just briefly, how do you account for
the wide range between your think tank contained within DOE
and ERAB and their report?
Mr. Vaughan. ERAB's premises. Congressman, were to acceler-
ate the use of coal in utilities. That is basically what their report is
about. It is undoubtedly true that if you pour millions of dollars
from any source into that process, yes, you will accelerate the rate
at which coal is used by utilities. I do not argue with that at all. I
think there is no doubt that would occur.
The question is, is that the wisest use of limited Federal research
and development dollars? And there is the difference.
Mr. Traficant. I thank you, Mr. Secretary. No further questions,
Mr. Chairman.
Mr. FuQUA. Thank you very much. Bill. We appreciate your
being here this morning. I think you can tell from the questions
and so forth there is a considerable amount of interest in this sub-
ject, and we appreciate your being here with us today.
Mr. Vaughan. Thank you, Mr. Chairman.
Mr. FuQUA. Our next witness is Eric Reichl, who is most recently
a nominee to the Synthetic Fuels Corporation Board, and I think
52
that his background would be a very excellent addition to that
Board.
We want to welcome you to our subcommittee. Your comments
on the DOE emerging clean coal technologies will be appreciated,
and we also hope that you can discuss your clean coal use report
which was accepted by DOE's Energy Research Advisory Board last
week and has already been mentioned in questioning today. We are
very happy to have you.
STATEMENT OF ERIC REICHL, CHAIRMAN, CLEAN COAL USE
PANEL, GREENWICH, CT
Mr. Reichl. Thank you, Mr. Chairman. I appreciate the opportu-
nity to appear before the committee and to discuss the ERAB
report, which has been noted heretofore. I think it might be worth
pointing out, as Mr. Vaughan has already done, that ERAB is
really part of the Department of Energy. It is not independent of it
and feels to be very much a part of it. It is an independent think
tank supposedly and should bring to the Department the views
from the outside. That is what they have done.
As you know. Secretary Hodel, at the time, in April of last year,
had asked for this review of the clean coal use technology, and we
have prepared this report which has just been completed. I happen
to have been the chairman of the panel that is reponsible for the
report; however, I want to take this opportunity to note that obvi-
ously the cooperation that we received from the panel members,
both those that came ERAB itself and those that came from indus-
try outside and academia, was most helpful and the report couldn't
have been put together without it. I think we have had a set of ex-
perts that was second to none in this field.
I would like to make a few comments about the report, and then
I guess answer your questions.
First of all, as you have noted, the subject is quite diffuse. It isn't
a simple issue of how one uses coal cleanly, and for that reason, we
divided the report up technically in the specific areas that you
would normally think of in terms of dealing with coal before you
burn it, while you burn it. We then subdivided that issue into pul-
verized coal burning and fluidized bed burners and flue gas clean-
up. We added a section on waste management, which is an impor-
tant issue. And in order to get some feel about the importance of
the subject, we had asked for a summary of the coal use as it was
to be forecast for the next 150 years to see which direction this
technology should be driven.
I would like to also draw attention to another subject that I
think is quite important in considering the scope of this report.
Since I do wear two hats, as it were, one at the Synthetic Fuels
Corporation and one at ERAB, I want to draw your attention to the
overlap that does exist between technologies that relate to clean
coal combustion power generation and those that relate to synthet-
ic fuels. And quite narrowly we have assumed that the use of high-
pressure gasification with oxygen would be considered a synthetic
fuel technology, and it is not treated in this report, although we all
know it is an excellent means to use coal cleanly. The cool water
project, specifically, is a good example here.
53
I believe we have good reasons not to include it here because this
area is going to be covered very thoroughly with a lot of money if
we are permitted to do so through the Synthetic Fuels Corporation.
I am making a point of it because we have included in the scope
here the use of air-blown gasifiers, which are narrowly used for
clean coal combustion, and while this is a technical fine point I
think it is an important one to distinguish between moneys used in
clean coal technology and those used for synfuels.
I should say that the report was submitted to the full Energy Ad-
visory Board on May 1 and was accepted with minor changes, and
it will be issued shortly, as soon as these changes can be incorpo-
rated. And I would like your permission to insert this full report as
part of this testimony because it is in the report where you can
read all the details that the various panel members have suggest-
ed.
Mr. FuQUA. Without objection, we will make that part of the
record.
Mr. Reichl. Thank you.
[The report follows:]
54
Energy Research Advisory Board
to the
United States Department of Energy
1000 Independence Avenue, S.W.
Washington D.C. 20585
(2021 252-8933
Mr. Ralph S. Gens
Chairman
Energy Research Advisory Board
Washington, DC 20585
Dear Ralph:
I am pleased to submit to you the Panel's report on Clean Coal Use Technologies.
Changes that the Board discussed at the May 1 meeting have been incorporated,
and I consider this to be the Panel's final product.
The burning of coal for electric power generation and other purposes is expected
to increase into the 21st century. Because of the various potential
environmental and health consequences of coal combustion, the Panel believes
that the Department has a role to play not only in clean coal R&D but also in
selective demonstration of technologies. Principal R&D needs are spelled out in
the report. However, the Department should undertake a demonstration only when
co-funding of more than 50% is provided by industry to ensure early application
of the technology.
The Panel very much appreciates the cooperation and assistance of DOE
Headquarters and the Energy Technology Centers during the course of the study.
Mr. Eric Reich!
Chai rman
Clean Coal Use
Technology Panel
Attachment
55
ENERGY RESEARCH ADVISORY BOARD
CLEAN COAL USE TECHNOLOGY PANEL
JUNE 1984
♦Eric Reichl, Chairman
President (Retired)
Conoco Coal Development Company
*Betsy Ancker-Johnson
Vice President
General Motors
*John Landis
Senior Vice President
Stone & Webster Engineering Corp,
♦William McCormick, Jr.
President
American Natural Resources Co.
Joseph Mullan
Senior Vice President
National Coal Association
Frank Princiotta
Director
Industrial S Environ. Research Lab
Environmental Protection Agency
Edward Rubin
Di rector
Center for Energy & Environ. Studies
Carnegie-Mellon University
♦Victoria Tschinkel
Secretary
Dept. of Environmental Regulation
State of Florida
Kurt Yeager
Vice President
Coal Combustion Systems Division
EPRI
♦Lawrence Papay
Senior Vice President
Southern California Edison
Co.
♦Ralph Gens (Ex Officio)
Chairman, ERAS
Consulting Engineer
♦Ruth Patrick
Limnology Department
Academy of Natural Sciences
William Poundstone
Consultant
STAFF
Charles Cathey
Executive Secretary
ER-6, Forrestal Building
1000 Independence Avenue, SW
Washington, DC 20585
(202) 252-8933
*ERAB Member
56
ENERGY RESEARCH ADVISORY BOARD
May 1985
Ralph S. Gens, Chairman
Consulting Engineer
Betsy Ancker-Johnson
Vice President
Environmental Activities Staff
General Motors
Frank Baranowski
Consultant
Ivan L. Bennett, Vice Chairman
Professor of Medicine
New York University Medical Center
Melvin Calvin
Professor of Chemistry
Department of Chemistry
University of California
Wi 1 1 i am D . Ca rey
Executive Officer
American Association for the
Advancement of Science
Floyd L. Culler, Jr.
President
Electric Power Research Institute
Gerald L. Decker
President & Chief Executive Officer
Decker Energy International, Inc.
Mildred Dresselhaus
Professor
Massachusetts Institute of Tech.
Arthur Hansen
Chancellor
Texas A«M University System
Robert L. Hirsch
Vice President, Exploration &
Production Research
ARCO Gas and Oil Company
Charles J. Hitch
President Emeritus
University of California
John R. Huizenga
Chairman
Department of Chemistry
University of Rochester
John Landis
Senior Vice President
Stone & Webster Engineering Corpotion
Henry R. Linden
President
Gas Research Institute
William T. McCormick, Jr.
President
American Natural Resources Company
Lawrence T. Papay
Senior Vice President
Southern California Edison Company
Ruth Patrick
Limnology Department
Academy of Natural Sciences
David Pimentel
College of Agriculture
Cornell University
Robert H. Pry
Consultant
Center for Innovative Technology
Eric Reichl
President (Retired)
Conoco Coal Development Company
Louis H. Roddis, Jr.
Consulting Engineer
n
57
Francis G. Stehli
Dean, College of Geosciences
University of Oklahoma
Victoria J. Tschinkel
Secretary
Department of Environmental
Regulation
State of Florida
STAFF
Joel A. Snow
Acting Executive Director
Energy Research Advisory Board
Department of Energy
m
58
EXECUTIVE SUMMARY
This report by the Energy Research Advisory Board (ERAB) Panel on Clean Coal Use
Technologies has been prepared in response to a request, dated April 24, 1984
from the Secretary of Energy Donald Model.
The Panel was convened and met on four occasions. Individual members met with
DOE staff and visited the DOE Energy Centers to receive briefings on the DOE
program. Drafts of individual sections were reviewed by all Panel members and
the final draft was approved by the full ERAB at the May 1, 1985 quarterly
meeting.
To assure proper coverage of the subject, it was divided into sections dealing
with the following areas: pre-combustion; combustion in conventional systems
(pulverized coal); combustion fluidized beds; post combustion (flue gas cleanup)
and waste management. A section on the expected future use of coal in utility
and industrial furnaces was added to determine the markets where clean coal use
technologies are to be applied.
In defining the scope of the report, it was decided at the outset not to cover
the subject of health or environmental impact resulting from the use of coal —
although the development of control technology (i.e., the subject of this
report) must be conducted in close coordination with R&D on these impacts.
A second important definition of the scope relates to the areas where clean coal
use in combustion overlaps with synthetic fuels technology. Specifically, it was
decided that gasification of coal with oxygen under pressure would be considered
a synthetic fuels technology, where it actually occupies a very central position.
This does not deny the obvious importance of this step in clean power genera-
tion, but it is not included in the report and it is not recommended to DOE.
Alternate configurations of this technology are expected to receive very
extensive support from the Synthetic Fuels Corporation.
Conversely, the conversion of coal to low BTU gas in airblown gasifiers is
included among the clean coal use technologies, where it is treated as two-stage
combustion although it can also be viewed as a pre-combustion clean-up system.
The seven individual sections of the report cover their respective areas in
detail and the reader is urged to consult them for information on the status and
recommended programs to bring various new technologies to commercial readiness.
In most instances this requires testing at substantial scale, because the key
user, i.e. the electric utility industry, is uniquely sensitive to the need for
fully tested and proven reliability and effectiveness of a new technology before
it can be adopted for use in power generation. The scale suggested for each
technology is given in the report, as is an approximate estimate of total
program cost for a 5 year period.
At the present time, DOE policy does not include direct support of commercial
demonstration, leaving this final and most critical step to the private sector
alone. A key recommendation of the report to DOE is a reconsideration of this
policy as it applies to the clean use of coal.
IV
59
The conclusions from each subsection are summarized and discussed in the report.
Major items are the following:
3 The use of coal during the next quarter century is expected to grow at a
slow but steady pace (most of it consumed in utility boilers), with
particular emphasis on the continued use of coal in existing installations.
Therefore, demonstration of clean use technologies which can be retrofitted
warrants special consideration.
3 The Panel notes the wide range of available alternates and concludes that
selection of preferred systems will be extremely site specific. There is no
way to select any one preferred approach by ranking the many different
concepts. The factors which can affect the choice at any given site will
include plant size, plant life remaining, type and price of available coals,
location or space for added equipment, ponds, etc., applicable regulations
on emission, and others.
3 Therefore, a proper DOE program should offer a reasonable choice of alter-
nates, leaving selection of technology to the private sector. This
selection process by the marketplace will best determine which systems
deserve DOE support. By insisting on a major private sector contribution of
at least 50% of the project cost, the best assurance of early commercial
application can be obtained. DOE should require this level of co-funding,
particularly as the more costly demonstration phase is entered.
3 The report lists some 13 to 15 categories of technologies for clean coal use
and there are numerous competitive approaches available in most of these
categories.
If each of these categories is pursued all the way through proper demonstra-
tions by at least one major project to commercial readiness the total program
:ost, over a 5 year period, is estimated at $1.9 billion. Obviously, the cost
will be less since some technologies will fall by the wayside.
While most of the funds would be expected to come from the private sector, a
contribution by DOE of 30% on average is believed adequate and warranted to
assure an expeditious execution of the program.
The Panel believes this is necessary to assure the continued viability of the
coal option. The program relates to health and environmental issues, and is
thus a most appropriate area for direct DOE support and involvement.
60
REPORT OF ERAB PANEL ON CLEAN COAL USE TECHNOLOGIES
TABLE OF CONTENTS
VOLUME I Page
EXECUTIVE SUMMARY i v
I . BACKGROUND 1
II. THE FUTURE OF COAL IN THE U.S 2
III. COMMENT ON ECONOMICS OF CLEAN-UP TECHNOLOGIES 2
IV. GENERAL COMMENTS FOR DOE CLEAN COAL USE PROGRAM 3
V. TABULATION OF PROGRAMS 6
VI. REVIEW OF CLEAN COAL USE TECHNOLOGIES 11
VII. SUMMARY RECOMMENDATIONS 12
VOLUME II
A. THE CLEANING OF COAL: By W. Poundstone & E. Rubin 1
B. COMBUSTION - I. PULVERIZED COAL COMBUSTION: By
J. Landis & F. Princiotta 16
C. COMBUSTION - II. FLUIDI2ED BED COMBUSTION: By K. Yeager 54
D. AIRBLOWN GASIFIERS: By W. McCormick 86
E. POST COMBUSTION EMISSION CONTROL: By L. Papay 89
F. WASTE MANAGEMENT: By E. Rubin 106
G. PROJECTED COAL UTILIZATION IN THE U.S.: By J. Mullen 115
VI
61
REPORT OF ERAB PANEL ON CLEAN COAL USE TECHNOLOGIES
I. BACKGROUND
By letter dated April 24, 1984 Secretary Don Model requested ERAB Chairman
Ralph Gens to assess the principal technologies for the clean use of coal. For
each area, the letter asked for a review of:
0 the current Department of Energy, private sector, and foreign research and
development effort;
0 the relative cost-effectiveness of alternative technologies for the clean
utilization of coal resources;
0 the adequacy and timing of this work in reference to the national need.
A copy of the letter is Appendix A.
ERAB accepted this assignment and a Clean Coal Use Panel was established. The
membership list is on page i. (See also minutes of May 3-4, 1984 meeting of
ERAB ) .
The subject of the study is widely dispersed and to cope with this problem it
was subdivided into three major areas, covering respectively pre-combustion,
combustion proper and post-combustion technologies. Combustion proper is
subdivided into conventional (pulverized coal), fluid bed, and pre-gasification
combustion systems. Subpanels were established to cover each of these areas in
detail. In addition, an outline of the predicted use of coal for the period
198b to 1995 and beyond was provided to relate the several technologies to the
potential market.
This report concerns itself with the development of emission control technology.
It does not cover the environmental impact and health research programs at DOE
or elsewhere. The two areas are, of course, related to each other. Thus, R&D
efforts in both should be properly coordinated to assure that the various
control technologies take cognizance of the environmental and health effects
which may result from their application.
Another limitation of the scope of the present study relates to the obvious
overlap between certain clean coal use as against synthetic fuel technologies.
A key example is the pressurized oxygen blown gasification of coal. It was
decided to limit this report to those types of gasifiers which cannot serve the
conversion of coal to synfuels. Thus airblown atmospheric units are included
here, while oxygen blown pressurized units are omitted even though it is
recognized that the latter are one of the most significant new systems for clean
coal use in power generation (and synthetic fuels) which is receiving major
attention at tnis time.
The Panel met on July 31, November 14, 1984 and January 16. 1985 to review
progress and to dis<^us^-the^ initial drafts covering the assigned subjects.
50-513 0—85 3
62
There were numerous contacts and visits with representatives of DOE and of the
private sector in addition to these panel meetings. As a result of the large
volume of material to be reviewed and the broad magnitude of the task, it was
not possible to comply with Secretary Model's initial request for completion of
the report by November 1984.
Nevertheless, it is hoped that the resulting 6 month delay will not detract from
the usefulness of the study, which covers a subject of major interest to the U.S.
energy industry and which has recently received increased attention in Congress,
The Panel wishes to thank the management and staff of DOE who were ready at all
times to help and who supplied extensive written and oral information on DOE
programs, budget and goals. Finally it is a pleasure to report that we have
found the DOE Research Center facilities well maintained and the work
competently executed and reported. The intent of this report is not to be
critical, but to help point the work in the direction which is believed to be
most appropriate and in tune with the national goal of using coal cleanly.
II. THE FUTURE OF COAL IN THE UNITED STATES
As a result of several major independent trends, the use of coal in the U.S. is
expected to continue to increase at a reasonably steady pace for most of the
next 25 years. The two major influences causing this trend are the continued
high (compared to coal) price of oil and the reduction in the expected future of
nuclear power. Add to this the expected continued move toward electricity and
the importance of the future use of coal in power generation emerges as one of
the key long-range trends in the U.S. energy balance.
It was therefore particularly timely to determine whether U.S. efforts in
general and those of DOE in particular are properly directed toward assurance
that the increasing use of coal will be matched by an increased effort to
minimize the insult to the environment. Among the several uses of coal,
combustion is by far the largest contributor for the foreseeable future. Thus,
the present report focuses on this subject.
To establish a quantitative basis for the potential future application of the
results of Clean-Coal -Use R&D, Section G of Volume II of the study presents an
outline of the expected coal market in the near and intermediate term. This
section was prepared by Mr. Joseph Mull an. Senior Vice President of the National
Coal Association.
III. COMMENT ON ECONOMICS OF CLEAN-UP TECHNOLOGIES
In his original request. Secretary Hodel had specifically asked for information
on the relative cost-effectiveness of alternate technologies. After careful
review of the available information the Panel concludes that no clear-cut answer
to this question is possible.
This is not to say that estimates of the cost of the many types of processes are
not available or are meaningless. In fact, the several chapters in Volume II of
this report present a considerable range of such costs. However, the number of
63
specific coal use situations is so large and diverse and the specific problems
are so site-specific that no generally applicable answer can be presented. The
issue is particularly difficult when applied to retrofit problems which
represent the overwhelming majority of applications.
For any installation where coal is burned (new and existing) and where
technology is to be considered for reducing the emissions of pollutants into the
air water and soil, every technology discussed in this study deserves
consideration, at least in principle. This includes precombustion cleaning of
the coal, modification of the combustion apparatus proper (including its
replacement) and clean-up of the flue gas. Given the many specific facets of any
particular case it will then probably be possible to eliminate a good many of
the technologies out-of-hand, leaving the final choice subject to a very
detailed analysis of the relative cost-effectiveness of a few competitive
systems .
As a result, the relative cost-effectiveness promised by alternate technologies
cannot be a valid guide to selection of R&D programs, except in those cases
where projected costs are evidently well outside those of alternate systems.
Examples of this are noted in the chapters covering the several areas.
This entire subject ot clean use of coal and the related R&D i s a good example
of the potential danger of "central decision making". The subject is much too
complex to lend itself to a rigorous comparative economic analysis and is much
better left to the marketplace for selection. In effect, the best criterion for
inclusion of an R&D project in DOE's program would be significant co-funding by
a group of potential USERS of the technology. This co-funding issue arises
increasingly as a concept moves from initial conception and exploration on the
bench, to proof of concept and finally to demonstration.
DOE policy has recently excluded work beyond the proof of concept stage; this
report indicates where this limitation may prevent timely commercialization of
new technologies, and a revision of this policy is recommended. At the same
time, it is re-emphasized that as R&D costs rise sharply when demonstration is
undertaken, this must be accompanied by substantial (i.e. more than 60%) co-
funding to assure that the work will find early application.
Willingness by a group of potential users to co-fund a project is the best
assurance that a project promises to be cost-effective. No user is likely to
risk substantial k&O money unless he can see an early application given
technical success of the venture.
As an aside to clean-up economics, one should note that main attention has
generally been given to potential pollution of the air. This should, however,
be balanced by the recognition of possible trade-offs which may be required
between pollution of air. water and soil. Economic analysis must include the
impact resulting from any technology on all three of these areas.
IV. GENERAL COMMENTS FOR DOE CLEAN COAL USE PROGRAM
The preceding paragraphs have already suggested one particular useful criterion.
i.e., co-funding. However, there are some other considerations worth noting.
64
The need for Basic Research.
Coal has been the subject of R&D for 200 years and almost every conceivable
scientific discipline has been brought to bear on coal as it was developed.
An excellent central reference to these efforts is available in the several
editions of H. Lowry's "Chemistry of Coal Utilization" (John Wiley & Sons,
publisher) with the latest edition covering work up to about 1973. No work
should be undertaken before this source has been carefully checked to avoid
"re-inventing the wheel", which is not infrequent in this area.
The last 10 years have seen the arrival of some entirely new and very
powerful concepts in solid state physics, optics, etc. which are only now
beginning to be applied to coal and coal based operations. There is a
great need for NEW fundamental facts and knowledge about coal, because the
old available knowledge has been exhaustively applied and exploited; no
major innovation can be expected simply by "revisiting" it.
An important criterion for DOE should therefore be the accumulation of
new basic data related to coal. A specific area which is in need of better
insight is the occurrence, the origin, the composition and the forces
bonding mineral matter to the coal substance. Such knowledge might open
the door to improved coal cleaning concepts. However, there are certain
other coal-related areas which would also benefit from new fundamental
research, including combustion, coal composition, etc.
Distribution of Available R&D Funds Among Alternate Areas
Review of the DOE Fossil Energy budget shows that about 30% of the total
coal program is devoted to the clean direct use of coal (i.e., coal
combustion). Yet direct combustion will continue to represent over 90% of
all coal use for the rest of the century and beyond. Thus an imbalance
exists between the several coal uses and the related R&D budgets.
This brings up a problem, recognized by the Panel, i.e., the wide use of
Congressional Mandates for specific projects, which takes the selection out
of the hands of DOE. The problem is beyond the scope of this report, but
it points up the permanent need for good liaison and a continuing
educational process with the several Committees which have cognizance of
the R&D budget.
As to distribution of R&D funds within the several key areas of clean-use
technologies covered by this Panel, the best criterion will be the
"marketplace" as discussed in the preceding section. The best litmus test
will be the willingness for private sector co-funding and particularly co-
funding by a potential user group of the technology rather than a seller of
it.
Advice from Industry in Selection of Program
DOE cannot pursue all promising areas, and therefore selection or
establishing of priorities is required. In this context it is
recommended that the private sector be involved in the decision-making.
Use of special ad hoc advisory panels from industry is a possible
65
format. DOE personnel cannot have the needed day by day contact with
the operational problems arising from the many new technologies and an
industrial panel can bring this experience to the point where R&D
decisions are made.
Policies Outside DOE-which Influence R&D
Attention needs to be given to policies, or regulations, laws, etc.
which affect clean-up technologies now and even more to those
policies, etc. which are likely to arise in the future. These factors
must be kept in mind in choosing an R&D program.
Examples are Best Available Coal Technology (BACT), New Source Performance
Standards (NSPS), Acid Rain Legislation, and Resource Correction and
Recovery Act (RCRA). DOE must be concerned at all times about the
direction in which these policies or laws will take the nation, and
hopefully anticipate the needs when choosing an R&D program.
Inter-Agency Cooperation and Information Exchange
In the course of this study it became apparent that greater cooperation
between the several entities in the field would be desirable. This is
particularly needed between DOE and EPA, where more coordinated co-funding
could help speed up completion of certain urgent clean-up R&D programs.
However, this is not only a matter of co-funding, but also one of bringing
to bear the R&D strengths available from each organization in selected
areas to complement each other.
DOE Leadership
DOE has a unique opportunity and an obligation to exert leadership in Coal-
Use-Technology R&D, particularly because the general subject includes such
a wide range of topics.
The DOE budget, even if it were expanded, would not be sufficient to pursue
all projects (especially large-scale demonstrations) deserving support.
However, the concept of co-funding, which may involve well over 50% private
sector contribution, will allow DOE to cover a broad program by leveraging
the DOE funds. At the same time, DOE can assist industry by putting the
needed project-packages together and thereby assuring readiness of the
technologies when new laws and regulations may call for their deployment.
In this context, note that direct co-funding is only one way in which DOE
can help. DOE should also lead, when opportunities arise, in urging use of
tax incentives which could result in large private sector R&D efforts and
would reduce the need for direct DOE involvement.
Finally, leadership also calls for stability of program and purpose,
especially where co-funding is invol.ved. A prime concern of private sector
R&D management, when dealing with DOE, is assurance that program direction
and budget, once adopted, will not be changed arbitrarily. This is most
66
important to the larger multi-year projects where change in direction is costly
and wastes resources. In this connection the DOE track record is poor.
Improved stability would facilitate commercialization of viable new
technology.
V. TABULATION OF PROGRAMS
The reader is urged to consult Volume II of the report for detailed reviews of the
major technologies. Here, we summarize the overall findings in a compressed format
to make it easier to understand the relationship of the several sections. This is
done in tabular form in Table I, including very brief comments on application,
status, range of effectiveness, time of commercial readiness and an appropriate
estimate of the total program cost for the 5 year period of 1986 to 1990.
The entire program, assuming that every area will be developed to commercializa-
tion, would represent $1.9 billion, as shown on Table II. It is of course quite
unlikely that every option will be pursued to completion. Thus, the total cost
would be considerably less.
The Table does not indicate what part of this total cost would be contributed by
DOE, but it is expected that the majority will come from the private sector. A
reasonable DOE contribution would be up to 1/3 of the total on the average,
leaving choice of contribution to individual projects up to DOE management. In
chosing areas for particular attention, the following four points are noted:
0 With clean-up of existing coal burners representing the main challenge in
the near term, the early demonstration of RETROFITTABLE technology is most
urgent.
0 Using current Post-Combustion clean-up technology as a yardstick,
improvements to this and hopefully lower cost technology appears as the
appropriate target. This suggests limestone injection multi-stage burners
(LIMB) and improved flue gas desul furization (FGD) as the first priorities.
Aggressive pursuit of this target will make full deployment possible around
1989-1990.
0 Several alternates exist which can bring about the displacement of oil or
gas with coal in existing stationary combustion systems. This includes new
concepts for coal cleaning (combustion of coal/water mixtures), a new type
of slagging burners, and use of micronized coal. By definition,
displacement of oil or gas also implies the use of coal in a cleaner
manner.
0 For new facilities and certain retrofits, fluidized bed combustion offers a
new alternative. With atmospheric fluidized beds already in the market
place, the main DOE emphasis would properly be placed on the pressurized
version. If the promise of this technology stands up it may reach
commercial status in the early 1990s.
67
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71
TABLE II
Order of Magnitude Estimate of 5 Year Program Cost
(in $ Million)
Description
Total 5-Year
Cost of
Program
Precombustion
$ 120
Conventional Combustion
419
Fluid Bed Combustion
657
Airblown Gasifier
100
Post-Combustion
570
Waste Management
60
TOTAL
1,926
It is re-emphasized that for optimal allocation of resources (both of DOE and of
the private sector) every project must be specifically reviewed with regard to
these factors:
1) Potential contribution to emission control
2) Cost/benefit ratio
3) Time frame
4) Probaoility of technical and economic success
b) Industrial need (as measured by available co-funding)
VI. REVIEW OF CLEAN COAL USE TECHNOLOGIES
Volume II comprises the main substance of the report. The subject was divided
into five areas of technology and the lead for the review of each was taken by
the Panel members indicated below:
0 Precombustion
The Cleaning of Coal: W.N. Poundstone & E.S. Rubin
0 Combustion
A. Conventional (PC) Coal Combustion: J. Landis & F. Princiotta
1) Lime Injection (LIMB)
2) Two Stage Slagging Combustors
3) Coal Water Slurry Combustion
11
72
4) Micronized Coal Combustion
5) Low NOj^ Systems/Dual Fuel -Overfi ring
B. Fluidized Bed Combustion: K. Yeager
Atmospheric Fluidized Bed Combustion
Pressurized Fluidized Bed Combustion
C. Lo BTU-Gas Airblown Gasifiers: Wm. McCormick, Jr.
0 Post Combustion Emission Control: L. Papay
SOj^ Removal
NOj^ Removal
0 Waste Management: E.S. Rubin
Drafts for all sections were exchanged between all members of the Panel to
minimize overlaps and to bring to bear the maximum of experience available from
the Panel to the entire field.
These individual reports are in Volume 11. It is necessary to read each section
to understand the subject and to obtain the view of the Panel. However, in
order to give the reader a quick access to the major findings, they are
presented in summary form in Section VII.
VII. SUMMARY RECOMMENDATIONS
0 The total amount budgeted by DOE for FY 1986 in the field of Clean Use of
Coal is about $57 million. The figure appears too small by comparison with
the needs that the increasing use of coal implies. For ready reference,
the following excerpts from the FY 1986 Fossil Energy Budget are noted
here:
Coal Related R&D (Millions)
FY '85 FY '86
Subject Estimate Request
Control Technology $ 35.1 $ 27.2
& Preparation
Combustion Systems 30.2 29.2
Total: Coal 252.5 148.8
(incl . above)
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73
Within the clean use of coal area the overall DOE program is well dispersed
and all major technological areas are covered in some way. However, the
budget does not allow DOE to help with the transfer of the new technologies
to the private sector and to assure their commercialization. This is the
result of basic policy which should be reconsidered.
In most instances, the current policy of abandoning a technology after
Proof of Concept has been established will result in just that— abandonment.
The subject of clean use of coal is of major near-term and long-term
national importance and deserves a change in this policy. Specifically,
DOE should assure commercialization by participating in the needed larger
scale tests which are characteristic for utility operations before the
technology can be adopted. Obviously, careful selection of projects and
extensive private co-funding are a prerequisite. Specific examples of such
projects are noted elsewhere in this report.
As to R&D in Pre-Combustion (Coal Cleaning):
The DOE program has two distinct objectives: 1) to reduce SOp emission by
removal of pyrite, and 2) to allow use of coal in lieu of oil or gas in
systems designed only for the latter.
1) As to reducing SO2 emissions, it will be important to continue compa-
ring the cost of proposed advanced cleaning systems with the incremental
cost of SOp reduction by other means, (LIMB, F6D, low sulfur coal, current
commercial preparation process, etc.). Most of these costs are now well
defined and do not allow the use of very costly cleaning systems. Somewhat
higher costs might be justified if sulfur removal can be improved.
2) Displacing oil or gas with coal will require a particularly efficient
removal of ash which can be achieved only by extensive comminution and
separation of the coal from the mineral at sizes generally well below
current practice. This will be expensive. However, the difference in the
prices of coal vs. oil/gas allows a much greater cleaning cost than that
for systems designed for SOp reduction in coal-fired units. It will also
be important to determine the acceptable ash level by running large scale
combustion tests; 1 to 2% ash may be acceptable. This seems within reach
of new physical cleaning systems which DOE intends to explore jointly with
the Electric Power Research Institute (EPRI) at the Homer City, PA Coal
Cleaning Test Facility (CCTF). However, the cost of chemical cleaning, now
one of DOE's Key projects, will be very much higher (processing costs
roughly equal to the cost of coal) and an independent feasibility study of
the system is recommended based on results from the integrated unit now in
start-up.
Finally, DOE is urged to place particular attention in its coal cleaning
programs to those coal resources which represent the major U.S. reserves
and which are most in need of new technology because they are all difficult
to clean. These are the Indiana/Illinois #5 and 6, Kentucky #9 and 11,
Ohio/Pennsylvania/West Virginia's #8 and 9 (Pittsburgh and Sewickley)
seams. Too ofteli R&9 is carried out on coals that can be readily cleaned
using existing technology.
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74
As to Conventional (Pulverized) Coal Combustion:
The subject was further subdivided to draw attention to this important area
which represents by far the largest use of all coal now and in the
foreseeable future.
1) Furnace Limestone Injection/Multistage Burners:
DOE is virtually absent from this area. This is unfortunate because LIMB
is generally viewed (although not by all), as one of the potential SO2
abatement systems which can be retrofitted, and which may be considerably
less costly than FGD, though this is offset by the lower percentage
SOo removal. However, it may still promise to reduce emissions up to
6O1. There is hope, given added R&D, that this level can be pushed up
significantly higher, allowing NSPS standards to be reached in some
cases. An important R&D goal here will be reduction of any impact on
boiler reliability and particulate controls that the process may have.
The program is mainly supported by EPA and EPRI. The Panel urges DOE to
participate in this area. Specifically, this would involve test firing LIMB
on a lOOMW tangential ly fired boiler which represents almost 50% of
existing units ( a wall fired test is already committed). In addition, R&D
on improved sorbents and sorbent ash interactions is needed. DOE has
outstanding competence in its several National Laboratories which could be
brought to bear on this subject.
2) Slagging Combustors to Use Coal in Oil Fired Units:
This concept was in extensive use in the utility industry during the 1950s
and 1960s but was discontinued mainly for environmental reasons (high NO^).
New combustion R&D has recently yielded an updated version of the slagging
burner which is environmentally benign (low NO^^ plus possible SO2 reduction
through limestone addition) while retaining the key feature of removing up
to 90% of the ash from the main furnace. Furthermore, it is hoped that the
new burner will be retrof ittable. DOE is supporting this co-funded program
on industrial boilers. If the initial results are positive, DOE should be
encouraged to support larger capacity burner tests in the future.
3) Combustion of Coal/Water Slurry
DOE has a significant commitment in this area and has contributed very
effectively to the initial combustion tests and CWS evaluation. CWS as a
fuel is attracting considerable private sector attention because it opens
the door to more intensive coal cleaning at the finer sizes (mainly PC
grind: i.e., 80% under 200 mesh) which liberates additional minerals (see
section on coal cleaning); CWS implicitly eliminates the costly step of
drying the fine coal. Use of this CWS (70% pulverized ground coal) in
oil/gas designed boilers would require substantial capacity derating. Use
of CWS is also in the early stage of development as it applies to ultrafine
(i.e., micronized to -325 micron) coal. CWS is a technology primarily
aimed at replacing oil (particularly residual oil) with coal.
14
75
Acceptance of pulverized grind CWS by the utility industry will require
further extended large scale combustion tests. The private sector seems to
be ready to pursue this subject. However, the high cost of large-scale
tests will require substantial DOE assistance.
4) P.C. Combustion of Micronized (-325 mesh) Coal:
Ultrafine grinding is an alternate concept suggested to permit firing of
coal in oil-designed boilers without the penalty of capacity derating. A
special problem is the high energy required for fine grinding. Evidently
this system is being developed by the private sector without DOE involve-
ment. Some test firing of dry micronized coal has been conducted on
commercial scale boilers and it may become another useful technology for
increased use of coal if the test program is expanded. As practiced, it
had no impact on SO2 emission except through the use of cleaned coal.
Further demonstrations are planned with electrostatic cleaning after micro-
pulverization. One specific configuration is the use of micronized coal in
the form of coal/water slurry. However, the implication of CWS is broader
and point 3), above, covers this subject.
5) Low HQ^ Combustion Systems
This too is an area of importance where DOE is not currently involved
as far as any near term retrofit systems are concerned. While NO^^ can
be reduced by ammonia injection and catalytic reduction in various
configurations, this is a very costly step. DOE is exploring FGD
systems to remove NO in its long range R&D program. The NO^^ problem
may, however, require some attention in the near term and development
of modified (staged) burners offers substantial NO^^ reduction (50-75%).
Low-NO^ burner designs are nearing demonstration scale development by
the several U.S. boiler manufacturers. Advanced combustion staging
processes are also under development which offer the prospect for
greatest NO^^ reduction where applicable. One approach which has
shown promise in tests conducted by Southern California Edison is use
of a low nitrogen fuel (example methanol) for "over-firing". It
warrants further tests.
As to Fluidized Bed Combustion:
DOE has done an excellent job of encouraging this technology in the
U.S. The atmospheric version has begun to receive good acceptance by
the private sector both for new plant and even for retrofit by industry
and the utilities. Demonstration units up to 160 MW capacity are being
built. Thus, further direct support by DOE can be concentrated on
certain ancillary problems such as R&D on sorbents and heat transfer in
circulating beds operating under high fluidization pressure, etc.
The fluidized combustor can also be applied to pressurized systems
where further important advantages may be obtained by shop fabrication
and in terms of efficiency. Progress on these PFBC's will require
considerable further support from DOE. At this time, DOE funds are
mainly used to support to International Energy Agency (lEA) program at
Grimethorpe, England, and it is important that DOE continue support for
15
76
the remaining segment of this international project. Apart from the
basic merit of PFBC, this project gives DOE a chance to rebuild its
credibility as an international R&D partner, which was badly tarnished
by some precipitous withdrawals from other projects. Grimethorpe is a
PFBC-component test facility intended to yield engineering data for
design of future pilot- or semi-works units.
Finally, DOE should also support the properly co-funded design,
construction and operation of a pressurized fluidized bed boiler
module for use in the utility industry. A target of a lOOMW
unit, based on circulating bed configuration, may be the most
likely candidate.
As to Air-Blown Gasifiers (Low BTU Gas):
The use of gasification as the initial step in the clean use of coal
now constitutes the largest fossil fuel R&D project in the utility
industry. The lOOMW unit at the Cool Water Generating Station in
California is based on pressurized gasification using oxygen. This
process also represents a key step in virtually all conversions of coal
to synthetic oil or gas. Synthetic fuel development is receiving
extensive support in the U.S. and abroad and can be distinguished from
the clean coal use program in spite of certain overlaps. For this
reason, it was decided at the outset not to include it in the present
study.
Conversely, the airblown version of gasification can be viewed as
"two stage combustion, with intermediate gas clean-up" and
implicitly as part of the clean use of coal.
This is one of the oldest processes applied to coal, and it was
practiced in literally thousands of units all around the world from
about 1850 to 1950. The equipment used in the past would not be
acceptable today, but DOE has supported some recent tests using the
latest version of the atmospheric fixed bed gasifier, which was the
standard in earlier days.
The equipment is simple, low in cost and would find a market in certain
industrial applications where the low heating value of the gas (140-180
BTU/scf) does not require major revisions of the user's equipment.
Airblown gasifiers must be closely integrated with individual furnaces,
etc. because the cost of piping over longer distances is prohibitive.
DOE may encourage the application of airblown gasifiers by supporting
gasification tests to broaden the sizes and types of coal which can be
used reliably, both in the fixed bed and the fluidized bed equipment now
commercially available. Note that in the absence of low cost air pre-
heaters, the fluidized bed is the only system that can directly gasify
fine-sized coal using air (Winkler reactor). An interesting alternate is
the Kiln-Gas process currently under development.
Most important, however, will be the ongoing DOE program for the
clean-up of raw gas (including Lo BTU gas), preferably at elevated
16
77
temperature. Emphasis b> DOE has been on removal of particulates and
alkalies to allow use of the gas in turbines. To capture a broader
market would also require development of a low cost sulfur removal
step. However, the cost margin available is narrow, making this a
difficult target.
As to Post-Combustion Emission Control Technologies:
This approach to clean-up is the mainstay of current control technology
and is likely to remain so for a considerable time to come. It thus
requires particular attention. The extent to which it has already
penetrated the market and the forecast growth are given in Volume II,
Section E. It can be retrofitted, space permitting, to virtually any
combustion system, which adds to its importance. Above all, with costs
now fairly well defined it remains the "standard" to which alternate
systems must be compared.
With nearly 50,000 MW in operation, numerous activities are being
conducted to refine these operations for the near term. The resulting
improvements will make the systems more efficient and above all more
reliable, but they cannot materially reduce the capital costs which
generally range from $175 to 300/KW for retrofits (much higher costs
are possible) and $110 to 175/KW for new plants, with a levelized cost
of 8 to 2b mills/kwhr.
DOE should note that the long-term developing technologies, which make
up the bulk of DOE investments in the Post-Combustion area, would apply
only if emissions regulations (particularly for NO ) were much more
strict than at present (and thus may result in higher costs). This is
true, for example, of the E-beam units piloted at the Tennessee Valley
Authority's (TVA) Shawnee plant. The advantage sought in the
simultaneous removal of both SO and NO^ is a more reliable and less
labor intensive process that would reduce/eliminate the generation of
solid wastes. For lower levels of NO^ removal, NO^ can probably be
reduced more economically by combustion modification. As in other
areas, DOE would have to extend its presence well beyond the proof of
concept stage if any of these new SO^^/NO^ removal systems are to find
commercial acceptance, and even more so if the economic attraction is
not large.
At the same time, there is an urgent need for low cost, retrofittable
flue gas control technology, even if some lower removal efficiency
would result. This target requires increased attention by DOE. One
potential approach is the injection of sorbent into the fluegas ahead
of the bay house or electrostatic precipitator (ESP). To be acceptable,
this requires a substantial increase in the DOE efforts on particulate
removal, including R&D on the upgrading of existing ESP facilities.
DOE should support full scale testing of such low-cost, retrofit
systems in conjunction with EPA, EPRI and the utilities.
17
78
As to Waste Management:
Recent DOE efforts have been properly concentrated on characterization
of wastes currently produced by the many operating plants and on a
study of the potential impact of alternative disposal methods,
particularly those which may be needed under RCRA. Current
efforts to begin characterizing wastes from emerging technologies
is a necessary first step to insuring that solid waste disposal
problems do not pose unacceptable technical or economic barriers
to new process development. Any reclassification of utility or
other coal-related wastes (e.g., mining preparation) would have a
significant impact on the required DOE clean use of coal program,
but this is not foreseen as likely at this time. Increased
efforts by DOE to co-fund programs aimed at waste utilization
(rather than disposal) are recoiri iiaeo.
79
A. THE CLEANING OF COAL
by: William Poundstone and Edward Rubin
I. DEFINITION OF SUBJECT
Coal cleaning is the process by which impurities are removed from coal in order
to reduce its mineral content and increase its energy content per unit mass.
This is usually done by one or more mechanical processes which make use of
differences in the physical properties of coal and mineral impurities
{especially specific gravity) to accomplish the separation. Such processes are
often called "physical" or "mechanical" coal cleaning. Where chemical changes
in the coal are used to accomplish a separation, the process is called
"chemical" coal cleaning. Coal cleaning can potentially play a role in
achieving a number of DOE's stated goals or objectives. Current mechanical coal
cleaning technology and equipment can:
0 Reduce coal into two fractions: one having lower sulfur and ash content than
presently washed coals, and able to be used in normal coal burning
equipment; the other having higher sulfur and ash content, able to
be burned in an environmentally acceptable manner in a new fluid
bed combustor, with a consequent reduction in sulfur emissions.
This approach would be economically attractive because it enables
maximum BTU recovery to be achieved.
In addition, the new "super cleaning" process under development by DOE and by
the private sector, which mechanically cleans coal after it has been crushed to
very fine sized particles, can potentially :
0 Reduce ash in coal to levels that will enable coal to replace oil in certain
existing oil designed boilers.
0 Make an even greater reduction in ash and sulfur with an economically
acceptable BTU recovery.
New chemical coal cleaning processes can potentially:
0 Make an even greater reduction in ash and sulfur than is possible with
conventional cleaning or with the mechanical cleaning of finely ground coal.
0 Make a coal product that can be used as an oil replacement fuel from a wider
range of coals and in a wider range of applications than is possible with
super mechanically cleaned coal. Chemical coal cleaning processes can remove
organic sulfur and ash that cannot be removed by mechanical means, and can
potentially allow coal to meet even New Source Performance Standards (NSPS).
The principal interest in super cleaning is to enable coal to be used as an oil
replacement fuel. However, this concept would be used as a means of lowering
sulfur emissions in conventional coal combustion if the process costs prove to
be less than the cost of lowering sulfur emissions by other means such as flue
gas scrubbing, or switching to an inherently low sulfur coal.
80
Most coal cleaning, until recently, was done for economic rather than
environmental reasons, with the principal goal being to reduce the mineral
matter (ash content) of coal. The degree of cleaning and thermal drying for
moisture control has historically been determined by the need to achieve the
lowest total cost for mining, transporting, and converting coal to other forms
of energy. However, not all coals are, or need be, cleaned for economic reasons
as the most favorable economics frequently can be achieved by selective mining
(this is especially true in the case of surface mined coal).
Currently, there is a renewed interest in coal cleaning technology as a
potential means of sulfur reduction for acid rain controls; as a means of
allowing existing and new high sulfur coal sources to be used under current
allowable s-ulfur emission standards; and as a way of establishing new markets
for coal. While existing technology has not yet been fully employed, much
attention is currently being directed to new processes to mechanically or
chemically clean coal, which is first ground to liberate most of the mineral
contaminates from the pure coal substance. Inherent in these new processes is
the change in the nature of how the resulting finely sized clean coal must
be handled. It appears that this "super cleaned" coal either will have to
be cleaned at the point of use, or transported from the cleaning plant to
point of use by some unconventional means such as in slurry form, or
reagglomerated lump that can be handled as a conventional solid product.
II. STATE OF THE ART
Conventional coal cleaning as practiced today intentionally tries to keep the
coal in lump form as it comes from the mine except that the largest pieces are
usually limited to some convenient size (approximately six inches) by crushing.
In general the mined material that is processed through a coal cleaning plant
will contain the following:
1. Non-coal material (so-called partings and binders) that cannot be
economically segregated and removed from the coal in the mining process.
2. Material from the non-coal strata (so-called overburden and underburden) that
overlies or underlies the coal seam and is inadvertently mined with the coal.
3. Impurities in the coal seam, such as large pieces of pyrite ("sulfur balls")
that break free from the base coal in the mining process or in the subsequent
crushing that is done for convenient handling.
4. Coal containing various amounts of mineral matter finely dispersed throughout
its pure coal matrix, as well as certain organic impurities such as sulfur
and nitrogen.
Items 1, 2, and 3 are generally much higher in specific gravity than the coal
(with its finely dispersed mineral matter) and can usually be separated from the
raw coal mixture by conventional technology at a modest cost. The remaining
mineral matter, especially pyrite, is not always uniformly distributed in the
coal. A coal seam is usually made up of a number of beds of varying thickness
that were deposited at different times. Much of the variation in coal quality
is believed to stem from the variations in thickness of these beds. In
addition, pyrite and other mineral matter occur in coal in differing size and
81
shape particles. Because of this uneven distribution some pieces of coal will
have a somewhat higher specific gravity than others, and can thus be separated
into fractions containing less than average and more than average mineral ash.
Unfortunately, in most coals only a modest improvement in quality can be made
by lowering the specific gravity used in the cleaning process without
suffering a prohibitively high cost associated with the loss of heat value in
the rejected material. Consequently, conventional coal cleaning practice
generally does little to remove the mineral matter that is finely dispersed
throughout the coal matrix.
The cost of coal cleaning has three components:
0 Operating and maintenance costs (labor, power, and supplies).
0 Capital cost (the cost associated with the investment in cleaning equipment)
0 The cost associated with the loss of heat value of the material discarded.
This cost is incurred because of two types of losses. One is the loss of
clean coal due to the inefficiency of the process and due to the inability to
recover all of the extremely fine coal particles from the water used in the
cleaning process. The other is the loss of heat value associated with the
impurities removed in the process. Typically these impurities will have a
heating value of from 2000 to 4000 BTU per pound (BTU/lb), or roughly 20 to
30% of the heating value of clean coal. Even shale and pyrite rock have heat
contents that typically exceed 1000 BTU/lb.
It is much easier and less expensive to clean the lump coal than the small
particles. This is because most cleaning today is done by systems that use
water that must be removed from the clean coal as well as from the rejected
material. Lumps have relatively small surface area per unit of weight compared
to fine sized particles. Lumps can be dewatered or dried rapidly by mere
draining on a screen, whereas the small pieces have sufficient surface area that
they require more expensive technologies to remove or reduce the surface
moisture. The slower rate of settling of fine sized particles in a liquid also
adds to the difficulty and the cost of fine coal cleaning where liquids are used
in the separating process.
The most commonly employed cleaning processes use water or water and magnetite
(heavy media). However, some coal is also cleaned using air tables. Generally,
different size fractions of coal are cleaned in separate devices. The lump
sizes (typically larger than 3/8 inch) are usually cleaned in a Jig or in a
heavy media vessel. The intermediate sized (typically less than 3/8 inch in
size but larger than 28 mesh) are usually cleaned on Diester tables, water only
or heavy media cyclones, or in a "Batac Jig". In total, about a third of the
coal produced in this country is cleaned in some degree (beyond simple breaking
and crushing). Coal washing is applied mostly to underground production, of
which about 60% is washed, while less than 20% of surface-mined coal is cleaned
before use. Washing is used for nearly all metallurgical coal, while
approximately 20% of all utility steam coal is washed for ash or sulfur removal.
In general, the western low sulfur coals are not washed since they are quite low
in ash and sulfur as mined. Underground mined coal is more frequently washed
than surface mined coal because it is more likely to be contaminated with rock
82
from adjacent strata. Today there is a trend toward more coal cleaning because
of the demand for coals of lower sulfur content. At the same time, there is
also a trend toward increased coal recovery because the value of coal today
has reached the point that coal as fine as minus 28 mesh is rarely discarded
as was the case 20 years ago. In the past, it was frequently cheaper to
discard the fine sizes and mine additional coal in its place, rather than
clean this size fraction.
Currently, the lowest cost means of significantly reducing sulfur emissions for
a given coal is through the use of flue gas desulfurization (FGD) or FGD in
combination with some form of coal cleaning. The lowest overall cost of sulfur
reduction results when the mining process employs mining methods and cleaning
processes that have costs per unit of sulfur reduction less than the
incremental cost of sulfur removal via flue gas scrubbing. Not all high pyrite
coals used for power generation are currently cleaned and some are only
partially cleaned, but the trend is clearly toward more comprehensive coal
cleaning.
The current practice in cleaning for coals used for heat energy (thermal coal)
is to clean it in lump form essentially as it comes from the mine, which is
the least expensive approach. However, if we are to remove pyrite and other
impurities we must first separate or "liberate" these materials from the coal.
This is usually done by crushing prior to cleaning or, in the case of raw
coals containing clay materials, crushing after some precleaning. The
mechanical cleaning of finely ground coal ("super cleaning") can potentially
remove a higher percentage of pyritic sulfur and can make significant
additional reductions in the mineral ash of many coals. Since low sulfur
coals contain little or no pyritic sulfur, physical cleaning processes will be
of little help in reducing sulfur in these cases.
III. OUTLOOK FOR REQUIREMENTS FOR 2020
It is difficult to forecast with any precision the use of new coal cleaning
technology in the coming years because its use depends upon:
0 The success of new coal cleaning processes and their resultant cost.
0 The changes, if any, in environmental laws and regulations covering the
allowable emissions of sulfur and other contaminants associated with the
burning of coal and the disposal of its waste materials.
0 The changes, if any, in the environmental laws and regulations covering the
use of other sources of energy that compete with coal.
0 The availability and the cost of oil and gas.
0 The degree of improvement and the future cost of FGD, LIMB and other
alternative means of reducing sulfur emissions.
It seems likely that coal cleaning will be less expensive than FGD in many
locations if the desired reduction in sulfur emissions is moderate. It also
seems likely that at least some portion of the current oil market will be
83
replaced with coal, possibly in the form of coal water mixture fuels made with
coals that have been cleaned after being finely ground.
Together, the potential applications of improved coal cleaning systems
constitute a very substantial market (ultimately several hundred million tons
per year) and thus warrant diligent pursuit.
IV. CURRENT R&D
The overall goal of the DOE research and development program in coal preparation
is to develop the technology to reduce the ash and sulfur content of US coals so
that the product can be formulated into a high quality fuel that could replace
oil and/or natural gas in both new and retrofit applications. Thus, a
successful R&D program would allow coal to penetrate markets currently dominated
by other (typically cleaner) forms of fossil fuel. At the same time, the R&D
program seems not adequately directed toward the solid coal fuel market as it
currently exists (i.e., coal-fired power plants and industrial boilers).
However, this very much larger and more significant market also would benefit if
the economics of new cleaning technology proves favorable.
The DOE coal preparation program may be viewed in terms of four major
components: (1) physical cleaning processes; (2) non-physical cleaning
processes; (3) ancillary operations; and (4) coal characterization. As a
fraction of the total FY85 budget request of $11.15 million for coal
preparation, these areas amount to 49%, 31%, 13%, and 6%, respectively. Brief
summaries of current R&D programs in each are provided below, including some
processes also being developed in the private sector.
1. Physical Cleaning
Figure 1 provides an overview of advanced physical fine coal cleaning processes
under development at this time. Current R&D in physical coal cleaning is
directed to removing pyrite and mineral ash after the coal has been crushed--
frequently to smaller than 200 mesh size. While coals differ in the size and
form in which the pynte (and other mineral ash) occur. It is possible to
separate up to about 80% of the pyrite from some coals after grinding to
"pulverizer" size (80% minus 200 mesh). There are a great number of processes
under study by DOE and the private sector that accomplish the separation after
crushing. These processes can be grouped into three types:
A. Those that work on differences in specific gravity.
B. Those that work on differences in surface attraction through selective
coalescence. Both agglomeration and froth flotation processes function
because of differences in surface attraction.
C. Those that work on differences in other physical properties. These include
high gradient magnetic separation and electrostatic separation devices.
84
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High levels of ash and or pyrite removal have been achieved in the laboratory
on coals crushed to 200 mesh on a limited number of coals. However, the
economic merit of most of these processes are not clear as they have not yet
been tried on commercial sized equipment. Scale-up to the "proof-of-concept"
state is expected in the 1985-1988 period.
A. Separation by Specific Gravity
Some of the new processes that use specific gravity as a means of separation
involve low boiling point "true heavy gravity liquids" such as freon and
perchlorethylene. Since the interest in these processes is applied to fine
coal, cyclones are typically used instead of a static vessel in order to speed
up the separating process. The process liquid is recovered for reuse by heating
the wet clean product above the boiling point of the liquid used and
recondensing the vapor. These processes can make relatively sharp separations
and do not require the expensive water removal process, but may prove to have
difficult environmental problems associated with the escape of vapor from the
process equipment and from traces of liquid which are lost with the solid
streams leaving the process.
Another new specific gravity process is the "ultra fine" or "slimes jig". This
device is designed to process minus 28 mesh material by using a more rapid
jigging or pulsing action. Indications are that this device can effectively
separate finer sized particles than is possible in the fine coal jigs currently
in common use throughout the world for cleaning coals of minus 10mm (less than
3/8 inch).
B. Separation by Surface Attraction
There is much research underway on processes that use the selective coalescence
of fine coal particles in a liquid medium. Various of these processes use
either oil, liquid freon or liquid carbon dioxide as the agglomerating agent.
Each of these liquids has an attraction for clean coal and is not attracted to
shale, clay, and certain other contaminates. Unfortunately, pyrite normally
behaves like the clean coal and is attracted to the same liquids. Consequently,
it must be separated by some other means if the amount present dictates removal.
There is some indication that these processes may be less precise in separating
efficiency than true heavy gravity liquid, and are likely to be better ash
removers that sulfur reducers.
C. Separation by Other Physical Properties
Since pyrite and even shales are more magnetic than clean coal, very high
strength magnets may be used as a means of coal cleaning. In addition, a new
electrostatic process is currently being tested on a commercial size unit at a
power plant in Ohio. In this approach, fine coal (essentially bone dry) that
has gone through the pulverizer at a power plant is given an electric charge and
placed on the surface of a charged rotating drum similar to the ones used to
clean taconite iron ore. The difference in the dielectric properties of clean
coal and impurities (pyrite and ash particles) causes the impurities to fly off
the drum as it passes a second electric charge while the coal continues to cling
to the drum until it is scraped off after the drum has rotated another quarter
turn. However, the finely ground material to be cleaned must be placed on the
86
surface of the drum in a layer that is only one particle thick and the capacity
(and hence the cost) of a single drum is directly influenced by the particle
diameter. There is also some indication that the separating efficiency is such
that more than one pass may be needed to avoid high BTU losses in cleaning,
A new program to start in FY85 is a joint program between DOE and the EPRI to
promote the development and testing of advanced physical cleaning concepts using
EPRl's Homer City, Pennsylvania Coal Cleaning Test Facility, The Program will
solicit proposals for new concepts to achieve high removal of impurities from
finely crushed coal (28 mesh by 0), to be tested at a 1 ton/hr scale. Initial
projects are to be selected late in FY85.
2, Non-Physical Cleaning
To obtain still higher degrees of sulfur removal, a number of non-physical
process approaches to removing organic sulfur are being pursued. Figure 2 shows
the various types of chemical and biological cleaning processes that have been
pursued by both the public and private sectors. The centerpiece of the DOE R&D
program in this area is a chemical cleaning process (Gravimelt) which employs a
molten alkali salt to achieve the removal of more than 90 percent of all organic
and pyritic sulfur and even higher levels of ash removal. The process concept
has been successfully tested in the laboratory and is now being expanded to an
integrated continuous 20 Ib/hr bench scale unit. Plans also are being
formulated to design a continuous fully integrated system at the "proof-of-
concept" scale (500 Ib/hr or greater). Current economic studies indicate
processing costs of about $35-$55/ton of clean coal. This would more than
double the current F.O.B. cost of typical US utility coals, and would generally
be uncompetitive with conventional FGD systems, whose cost is approximately
$2b/ton of coal for typical new utility applications. Thus, chemically cleaned
coal (or derivative fuels) would most likely be viewed as a substitute for oil
or natural gas, where the economics appear to be closer to being competitive.
Another alkali-based chemical cleaning process currently being supported employs
microwave radiation to achieve lower process residence times. This scheme is
still at the laboratory scale and has not yet been tested in an integrated
system,
A third approach being explored for organic sulfur removal is microbial
desulfurization. The concept is to develop "bugs" that can biologically remove
sulfur from finely crushed coal. This project too is still being evaluated at
the laboratory scale.
DOE also is beginning to look at the feasibility of benef iciating chemically
conditioned coals to improve their grindability and other physical
characteristics. One external project is underway and another is scheduled to
begin this year.
Ancillary Operations
Methods for dewatering and drying ultra-fine sixed coal (less than 325 mesh), as
well as low rank (sub-bituminous and lignite) coals, are being pursued as part
of R&D on ancillary operations. There is also a project on the ultrasonic
communition of coal which holds the promise of achieving fine coal particle
87
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sizes with substantially lower power requirements than conventional technology.
This project has been tested at the laboratory scale and will now be scaled up
to a 1 ton/hr proof of concept stage.
Coal Characterization
This is the smallest element of the DOE R&D program. Its purpose is to
characterize the sulfur and ash reductions that may be possible for selected
Appalachian coals ground to ultra-fine sizes. This represents an extension of
earlier work by the US Bureau of Mines to develop an extensive data base of
washability characteristics for US coals. Additional aspects of the coal
characterization program are concerned with trace elements analysis, organic
sulfur stu'dies and enhanced sulfur liberation due to ultrasonic communition.
Coal-Water Mixture Fuels
Separate from the R&D Program on coal preparation is a DOE program on the
utilization of coal water mixture (CWM) fuels, details of which are described
elsewhere in this report. The goals of the coal preparation program, however,
are closely related to CWM in that coal water mixture fuels currently represent
one of the key vehicles for utilizing super-clean coal as an alternative to oil
or gas. The CWM research program is concerned not only with technical aspects
of slurry preparation, stability and rheology, but also with combustion
characteristics in various types of end use devices. The DOE program structure,
however, does not provide for the horizontal integration of projects in the coal
preparation and CWM combustion, including fine particle emissions and the fate
of stabilizing and surfactant additives, also remain to be characterized.
V. COMMENTS ON R&D PROGRAMS
The DOE'S research program on coal cleaning seems to contain all of the elements
necessary to address the subject. Work includes studies to determine the
potential of various coals for deep cleaning, basic coal surface investigation,
research on coal comminution (coal crushing), research on the handling and use
of super clean coal as a slurry and as a ultra-fine dry product, experimental
combustion tests, research on pelletizing and other means of reagglomeration, as
well as work on a number of mechanical, chemical and biological cleaning
processes.
The DOE program goals for coal cleaning are to find economical means of further
reducing sulfur dioxide emissions from coal burning, and to reduce the ash
content of coal so that it may become a viable replacement for oil fuel. The
price that we can afford to pay to achieve these goals is well defined. For
direct coal combustion systems, the goal of reducing sulfur emissions via coal
cleaning can be achieved only if the cost of the new cleaning processes are
competitive with the cost of existing alternative approaches such as coal
switching and FGD, and of new developing technologies such as LIMB. The goal of
enabling coal to become a viable oil substitute is an easier target to estimate
as the competitive price of super cleaned coal used for oil applications can
approach--but not equal --the price of oil.
10
89
Each coal and each application is likely to have different costs, thus, it is
difficult (and potentially misleading) to present specific cost numbers.
However, it is our belief that the target cost for sulfur reductions from coal
combustion systems is likely to be in the range of $200 to $500 per ton of
sulfur dioxide removed for most applications where the reduction required is
from 20% to 50%. These cost and percentage reduction amounts include both fuel
switching and the assumption that LIMB and similar new technologies will be
developed commercially. These costs per ton of sulfur dioxide removed translate
into costs of $4 to $10 per ton of coal (based on a 3% Pittsburgh Seam coal and
a reduction of 1% by super coal cleaning). This establishes the target range of
costs for any new system used to reduce SO2 emissions.
Various estimates have been made of the costs that can be expended to clean coal
if it can replace oil as a fuel. Again, the target cost for each application is
specific to the amount of boiler derating, the base coal cost, the cost of added
capital, and the increased operating costs associated with handling additional
ash and particulate matter, etc. These estimates are typically $35 per ton of
coal, or some 3 to 9 times higher than the likely cost of meeting the moderate
sulfur reduction goals for direct coal combustion.
An examination of some of the component costs of physical super coal cleaning
may be useful in addressing this subject. Grinding to pulverized coal (PC) size
(80% minus 200 mesh) is a key part of most if not all of the proposed new
processes. While this is a significant new cost to the coal cleaning process,
it is a cost that is currently being incurred by the coal user. Consequently,
the total cost of mining, grinding, cleaning and burning coal will be little
changed if the grinding is done at a location other than at the power plant,
except for the higher cost of electricity and differences in the percentage
operating factor (which could be better or worse than the current practice). If
a water based cleaning process is used to clean coal after grinding to PC size,
we can expect to incur a cost for additional thermal drying. Coal of this size
can be mechanically dried to about 30% surface moisture or some 25% higher
moisture than normal run of mine coal. The current cost of evaporative drying
(not including the cost of mechanical dewatering) is roughly $15 to $20 per ton
of water removed (including a capital charge). The drying cost alone for PC
size coal that has been water cleaned can be expected to be in the order of
$4.20 to $5.60 per ton of coal.
If true heavy gravity liquids having low boiling points are used to clean coal
that has been ground to PC size, we can expect to recover something less than
100% of the liquid used in the process due to losses to the atmosphere and
losses due to liquid retained in the coal. If the amount lost is only 1/10 of
one percent of the weight of the cleaned coal, and the cost of the liquid is
$1.00 per pound, the cost associated with this loss will be $2.00 per ton. In
any cleaning process some coal energy (heating value) also is lost. A
theoretical recovery of 90% to 95% of the total energy would be about the
highest possible if large ash reductions are to be achieved. If we start with a
$30 coal and assume a recovery of 90%, the cost associated with the energy lost
with the cleaning plant refuse (not including plant capital or operating cost),
win be $3.00 per ton^ of^>aw" coal. Also associated with cleaning processes are
capital and operating costs in addition to the cost associated with loss of
heating value. If the coal is cleaned after grinding to PC size the cost of
refuse disposal is likely to be higher than for washing a more conventional
11
90
sized coal. The current capital and operating costs for a large new cleaning
plant would typically be $3.00 to $4.00 per ton. Unless a new extremely fine
coal cleaning process is very clever it is likely to cost more than a current
technology plant that processes a conventionally sized coal.
From the foregoing discussion it can be seen that the goal of finding a new coal
cleaning process that can significantly reduce the sulfur content of a given
coal at a cost that meets our target cost ($4 to $10 per ton) will be a
difficult challenge if the coal must be ground to PC size in order to liberate
or free sufficient pyrite from the coal to permit the needed sulfur reduction.
It is also apparent that the water-based systems have an especially tough job
unless the coal is to be burned as a coal water slurry in an application where
savings in. handling and/or storing can offset some of the cost of coal cleaning.
It would appear that the processes that work on dry pulverized coal have
significant advantages if they can achieve good separating efficiencies (perhaps
using multiple passes of the process) at acceptable capital costs. It is also
evident that the target cost for coal cleaning for oil replacement is much
easier to achieve and does not preclude any of the approaches currently being
pursued. However, the key to meeting this goal will be the need for maximum
ash reduction. It would seem that this requires the process to work on very
fine (perhaps even finer than PC grind) coal, and to make very efficient
separation.
Chemical coal cleaning seems to be the most difficult and highest risk of the
various research undertakings. While this approach should be able to achieve
the highest degree of ash and sulfur reduction its costs are likely to be higher
than the physical cleaning schemes. Thus, we should examine where it has a
chance of improving upon the other processes. With respect to sulfur removal,
it seems unlikely that for modest sulfur reductions (20% to 50%) chemical
cleaning can compete with a $4 to $10 per coal ton figure. The better chance
would be for new plants where chemical cleaning could meet New Source
Performance Standards by removing 90% of the sulfur, potentially competing with
FGD. Here, however, the cost is a fairly well established (approximately $25
per ton of coal) and current estimates of the gravimelt process, for instance,
are well in excess of this figure. Thus, chemical coal cleaning has a hope of
being competitive principally in oil replacement applications, especially if
world oil prices increase. The real issue is how low the coal ash must be to
enable it to be used in a significant portion of the existing oilfired boiler
market, and whether these levels can be achieved with physical coal cleaning
alone at much less cost. This is not known at present, but many of the
combustion experts have suggested that ash levels of 2% may be practical.
Several of the companies developing new physical cleaning processes report
obtaining ash levels of 1% to 2% range on certain coals in the laboratory. If
2% ash coal can be widely used in oil boilers, and if these ash levels can be
obtained by physical cleaning means, there may not be a market for chemically
cleaned coal j_f its costs are as now projected.
VI, CONCLUDING COMMENTS AND RECOMMENDATIONS
The following suggestions may be helpful in further improving the DOE program:
12
91
1. Much of the Congressional interest in new coal cleaning processes is based
on the hope that they may be a means of further reducing sulfur emissions
without massive fuel supply disruptions and the consequent impact on labor, it
is thus important to make sure that the high sulfur coals that can be mined at
relatively low cost (but which are likely to lose their market if further
reductions in sulfur emissions are required) be included prominently in the test
work. This would include coals from several areas of such seams as the Illinois
and Indiana #5 and #6 seams, the Kentucky #9 and #11 seams and the Ohio,
Pennsylvania and West Virginia Pittsburgh and Sewickley seams. There is a
tendency of researchers in this field to work on the easiest-to-clean coals.
These often are coals sufficiently low in sulfur and ash after conventional
cleaning that they can be used in existing markets. The basic goal of the
research will not be achieved unless we can apply these new processes to the
higher sulfur coals that constitute the greatest reserves and which are likely
to need help to remain marketable.
2. To facilitate the full-scale use and commercialization of research results,
DOE should continue to actively seek private sector involvement in the
development of improved coal cleaning technology, especially as it relates to
sulfur removal applications in the bulk use of coal in industrial and utility
boilers. DOE also may wish to study the role of tax treatment or other measures
which may provide incentives for commercialization of low-cost sulfur removal
methods based on coal cleaning in much the same way that incentives currently
are offered for other types of pollution control technology.
3. After a new cleaning process has been demonstrated on a small scale and the
key operating data have been collected, a comprehensive projected cost study of
a commercial sized application should be made to assure that it has a chance of
economic viability before large sums are spent on full-scale demonstration.
These studies should ideally be made by people who have substantial experience
in the design, building and operating of commercial coal cleaning plants. As a
minimum requirement these economic studies should be carefully reviewed by
individuals with commercial experience. In the past, some cost studies have
been made by persons who lacked sufficient background for the job, and the
studies were of limited help in knowing if the process was worth pursuing. In
this area of research, many processes will work {both with respect to
mechanical as well as chemical coal cleaning), but things that work are not
necessarily economical ly' viable. All of tbtse processes compete within well-
defined cost limits established by either the cost of oil, the cost of
alternative low sulfur coals, or by the cost of flue gas desul furization in its
various forms. Thus, we should not pursue processes unless they offer
realistic hope of being competitive, at least within some reasonable time
frame. In coal cleaning research, the quality of the economic assessment may
well be the most important part of the program and should receive the utmost
attention.
4. Fundamental research on coal and its properties should be continued. In
this area, the electron microscope may be helpful in assessing the cleaning
potential of the various coals. If information on the size of pyrite and
mineral ash particles as determined by this technique could be correlated with
conventional float and sink tests, it would provide a faster and lower cost
rough means of assessing the potential for coal cleaning for a given type of
coal .
13
92
5. The planned DOE program should be carefully compared with past, present and
planned private sector coal cleaning activities to avoid duplication of effort
and to achieve program goals at lower costs.
6. Table 1 suggests the total estimated level of R&D funding needed for coal
cleaning projects over the next five years (1986-1990). This includes private
as well as public support, including some larger-scale projects for which DOE's
contribution would not exceed 50%.
14
93
TABLE 1
ESTIMATED FUNDING REQUIREMENTS
FOR COAL CLEANING RiD*
(MILLIONS OF DOLLARS)
AREA/YEAR
86 87 88 89 90 TOTAL
PHYSICAL
CLEANING
PROCESSES
10 10 12 15 15 62
CHEMICAL
AND OTHER
PROCESSES
5 5 7 10 10 37
ANCILLARY
OPERATIONS
21
TOTAL
18 18 24 30 30
120
♦Total estimated expenditure for public and private sectors.
16
:;n_:;T4 n — 8rl 4
94
B. COWUSTION
I. PULVERIZED COAL COMBUSTION
By John Landis and Frank Princiotta
1. INTRODUCTION
Despite the current surplus of oil and gas, there is considerable interest among
industrial and utility fuel consumers in further reducing their dependence
on foreign energy supplies by using coal. Environmental and cost concerns
have resulted in significant efforts to develop new and more effective ways
of burning coal both in existing coal fired boilers and as a replacement
fuel in boilers currently burning oil or gas. Such means include new coal
fuel forms (e.g., slurried and micronized) and advanced combustion systems,
such as slagging combustion, lime injection, and NO^^ suppression.
Five near-term coal technologies are discussed:
0 Dry micronized coal
0 Coal-water slurries (with conventional pulverized grind and micronized
grind coals)
0 Two-stage slagging combustor
0 Limestone injection with multistage burners (LIMB)
0 Low NO^ Systems/dual fuel overfiring
These technologies achieve clean coal use by two approaches: precombustion
cleaning integrated in the preparation process for the two new fuel technologies
and adjustments to the combustion phase in the others. These technologies are
described along with their applicability and status of development. Also
presented are proposed development programs including costs and schedules.
2. MICRONIZED COAL COMBUSTION
This section discusses the near term potential of burning dry micronized coal in
boilers designed for oil and gas. This fuel offers a potential means for using
coal as a substitute fuel in oil/gas designed boilers in an economically and
environmentally acceptable manner and with a minimum derating of plant capacity.
Grinding the raw coal more finely releases ash materials and sulfur compounds,
permitting more effective separation by available coal cleaning methods. This
fuel technology permits tailoring the fuel specification to the site-specific
boiler in a way that cost optimizes the combination of coal cleaning, fine
grinding, and plant capacity derating.
Background
Following is a discussion of the problems and potential for burning coal in
boilers originally designed for oil and gas. It emphasizes how boiler design
16
95
differences depend on fuel type and how coal preparation (including combinations
of coal cleaning and finer grinding) for dry and coal water slurry fuel forms
will permit coal to be used in oil/gas designed boilers in an economical and
environmentally acceptable manner and with a minimum derating of plant capacity.
Boiler Characteristics
Boilers originally designed for coal can frequently be reconverted to this fuel.
However, in many cases, the boilers were designed to burn oil or coal, with
little expectation they would ever use coal. As a result these boilers are
often too small to burn coal without considerable modifications or capacity
derating. Furthermore, many boilers designed in the 1960s and 1970s have only
oil or gas capability and are not compatible with conventional pulverized coal
or stoker firing. Due to their relatively recent vintage, these boilers are
unlikely to be retired and, unless new ways are found to convert them to coal,
their demand for more expensive fuels will continue.
Boilers designed for coal are intrinsically different from their oil or
gas designed counterparts. These differences can have a significant
effect on combustion characteristics when an alternative fuel is burned.
Typical oil-designed boiler differences are discussed below.
The overall dimensions of an oil designed boiler are considerably smaller than a
coal boiler of comparable capacity. Heat release rates for oil boilers may be
as high as 35,000 BTU per cubic foot compared to 20,000 or less for a coal-fired
boiler. This difference is reflected in a smaller furnace volume. Furthermore,
gas temperatures leaving the furnace can be much higher when a boiler is
designed for oil. In a coal designed boiler, the upper portion of the furnace
must provide sufficient radiant heat transfer surface to reduce gas temperatures
to as low as 2000°F. The value is determined for each case by the coal's ash
fusion temperature. High flue gas temperatures will allow carryover of molten
asn, which is then deposited on relatively cool boiler tubes or walls. Because
oil contains minimal quantities of ash, much higher furnace exit gas
temperatures can be accommodated and oil-firing boilers are designed
accordingly.
The configuration of the furnace bottom is also important. Stoker-fired
boilers include the means for introducing combustion air and for removing the
unburned ash. Pul verized-coal boilers typically have a deep hopper formed by
the water walls of the boiler and a wet bottom ash removal system. Oil-fired
boilers may have a flat or shallow sloped bottom with no provision for
continuous removal of ash. Ash can be removed only during a boiler shutdown.
The boiler may be installed with limited head room between the flat bottom
and the boiler house floor, making modification difficult or impossible.
17
96
may have only 2 inch spacing. Furthermore, a staggered arrangement of tubes may
be used to improve the contact of flue gases with tube surfaces. Finned tubes
may also be used in economizer sections. Staggered or finned tubes in a coal
fired boiler increases the likelihood of ash fouling and erosion.
Gas velocities through the convection sections may be significantly different.
For a coal-fired boiler, it is common to limit velocities to 60 ft/s or less to
minimize erosion by hard, refractory-like particles of ash. In an oil designed
boiler, velocities of 100 ft/s or more can be encountered.
A final point relates to space restrictions for balance-of -plant equipment.
Particulate collection equipment is always required at the back end of a coal-
fired boiler. Fans may be larger than those required for an oil-fired boiler
due to excess air requirements. Ash removal systems occupy valuable space
around the boiler. Coal -unloading and storage facilities for a coal-fired
boiler occupy significantly more land area than equivalent oil tankage and
transfer facilities. Coal bunkers, pulverizers, and pneumatic transport
systems are bulkier than their oil-handling counterparts. Oil-fired boilers
are often "shoehorned" into plant arrangements, allowing little flexibility
for future alterations.
Impact of Pulverized Coal on Oil Designed Boilers
The dimensional differences between coal designed boilers and oil/gas designed
boilers can result in significant impacts when the latter are converted to coal.
The important impacts include:
0 Tube bank erosion - Combustion of conventional pulverized coal results in a
large increase in ash loading in the flue gases. Due to their relatively
large sizes, ash particles separate from the flue gas when an obstruction
such as a convection section tube is encountered. At the high velocities
found in oil or gas designed boilers, erosion of the tubes would occur.
0 Inadequate furnace residence time - Pulverized coal burns more slowly than
either oil or gas and, therefore, cannot attain complete carbon burnout
before it passes into the convection section. Furthermore, the flame can
impinge on the tubes, increasing the potential for slag deposition and more
frequent tube maintenance.
0 Insufficient radiant heat transfer - Because the oil or gas designed
furnace is smaller than that required for coal, there is insufficient
radiant heat transfer surface. This may result in reduced steam
generating capacity or increased gas temperatures, and therefore
increased slagging and fouling.
0 Ash removal problems - The flat or shallow sloped bottom does not allow
large ash particles or slag deposits that fall from the tubes to be easily
removed. Extensive modifications may be necessary to remove bottom ash.
Furthermore, wall deslaggers may be required to control deposits on the
furnace wal Is.
18
97
0 Inadequate space - Auxiliary systems for coal storage and handling and for
ash removal can occupy large amounts of space. Boilers not designed for
coal firing may not have the space necessary for conversion to coal.
These impacts of converting oil/gas boilers to coal firing result in three types
of problems. In some cases, the conversion may be simply infeasible; for
example, lack of space may prevent conversion. In other cases, the problems may
be technically solvable, but the solution is uneconomical. Finally, it may be
necessary to significantly derate the boiler to (1) reduce gas velocities to
allow more complete combustion within the smaller furnace and (2) to lower gas
temperatures to reduce slagging and fouling.
Here we focus on the third type of problem, i.e., derating of boiler capacity
and how to minimize it. Derating is the inability of the boiler to reach its
rated capacity. This can result from a requirement to reduce the rate of fuel
feed to meet a furnace-boiler design limit or from the inability of auxiliary
equipment, such as fans, to maintain required performance. Derating should be
distinguished from efficiency losses, which can be costly, but may not prevent
the boiler from meeting its required load. Derating can create significant
problems in locations where boiler capacity is limited. Depending on the
specific boiler design, deratings of up to 50% or more have been projected for
conversion to coal-based fuels. The need to minimize boiler derating has led to
considerable research and development 1n advanced fuel and combustion
technologies. These include micronized coal in dry and coal water slurry forms
and the two-stage slagging combustor.
With micronized coal, higher combustion intensities produce shorter flame
lengths, which can be accommodated in the smaller furnace volume of oil/gas
designed boilers. In addition, the particle size of fly ash in the furnace is
reduced, which results in fly ash entrainment in the flue gas stream and minimal
deposition. Micronized coal achieves these results by a combination of coal
cleaning and finer grinding before combustion.
Dry Micronized Coal Development
Recent laboratory and large-scale demonstration tests of the concept of using
micronized coal for oil and gas fired boilers were sponsored by the Institute of
Gas Technology (IGT), Gulf States Utilities (GSU), and Mississippi Power and
Light Company (MP&L).
Micronized coal fuels are characterized by grinding coal finer than in
pulverized coal operations. Programs to use coal in internal combustion engines
have considered particle sizes as small as a few microns. However, for use as
a boiler fuel, a much more moderate degree of fineness is considered acceptable.
For a site specific application, the maximum particle size that could be
tolerated with soot blowing would be specified. For purposes of this paper,
micronized coal is defined as coal with a nominal top size of 325 mesh, or
approximately 44 microns. In Figure 1, the size of these particles is compared
to the size distribution of conventional pulverized coal. As shown, pulverized
coal contains a sign^fiaiMit fraction of particles greater than 200 mesh, and
about 2% exceed 50 mesh size. For a 500 MW power plant, that 2% of the largest
coal particles amounts to about 4 tons/hr. The larger particles are important
because they produce most of the ash-related impacts.
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98
.0017"
100% < 325 MESH ( ) 325 MESH
MICRONIZED COAL
70% < 200 MESH
f200\
^ESH/
.003"
28% lETWEEN
200 AND SO MiSH
PULVERIZED COAL
2% > 50 MESH
.013"
FIGURE 1 COMPARISON OF MICRONIZED AND CONVENTIONAL PULVERIZED COAl
PARTICLE SIZE DISTRIBUTIONS
20
99
The effect of particle size is illustrated in Figure 2. Here the flue gas
streams in the convection section of a boiler are illustrated. In the upper
view, ash-free flue gas, such as that from a gas fired boiler, is shown passing
smoothly around a boiler tube. However, if large ash particles are entrained in
the flue gas, their inertia causes them to separate from the flue gas stream as
it changes direction to travel around the tube. This results in impact
deposition on the tube and/or erosion as the particles are swept over the tube
surface. This is shown in the middle part of the figure. Another effect not
shown here is the tendency for the very large ash particles to drop out of the
flue gas stream before it leaves the furnace and to collect on the bottom.
In the third view, we see an illustration of the difference when fly ash
particle sizes are smaller, as from micronized coal. This smaller size allows
aerodynamic forces to overcome the inertial forces that tend to separate the ash
particles from the flue gas flow. The ash remains entrained in the gas and
passes around the tubes and is collected in a baghouse or electrostatic
precipitator.
A second important effect of finer coal particles is increased intensity of
combustion. As noted previously, one of the important differences between coal
designed boilers and those designed for oil or gas is the volume of the furnace.
Combustion of a solid coal particle is inherently slow, because oxygen is only
in contact with the outer surface of the particle. Combustion must proceed
inward from this surface. Smaller coal particles have a much greater surface
area per unit of mass and, hence, will burn much more quickly than larger ones.
This can allow more complete combustion and carbon utilization to take place in
the smaller volume and shorter residence time of oil/gas designed boilers.
These factors should make it feasible to burn micronized coal efficiently in the
smaller furnaces of oil/gas designed units without the need for major
modifications and/or derating. Boilers designed exclusively for gas would
probably require cleaner (less ash) and finer micropul verized coal.
For the combustion test performed at the I6T, a Pittsburgh No. 8 coal containing
7.24% ash was ground to three different size distributions, with mass mean
particle diameters of 6.6, 18.1, and 41.0 microns. Ten combustion trials were
conducted at firing rates and durations ranging from 1.6 to 2.5 x 10 BTU/hr and
2 to 75 hours, respectively. Analysis of solid and gas samples collected at
various locations along the furnace axis were compared for the different grind
distributions, as were differences in total radiant heat flux. Deposition rates
were determined using a specially designed convective pass probe, which
consisted of two-inch OD gas-cooled tubes located on four-inch centers. Flue
gas temperatures at the deposition probe were 2320-2370°F, while tube surface
temperature varied from 640 to 1090°F.
Combustion intensity achieved with the finest ground coal was found to be more
than twice that for the coarse-yround coal; i.e., 0.9 x 10^ BTU/hr-ff' versus
0.4 X 10^ BTU/hr-ft . Accordingly, flame length was determined to be sensitive
to coal size distribution and was reduced by about 60% from the coarsest to
finest grind fuel. Somewhat surprisingly, nitrogen oxide emissions did not
appear to change with coal particle size distribution. Deposition rates on the
convective pass probe were reduced by about 80%, as coal particle size was
reduced from the coarsest to the finest distribution.
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100
ASH FREE
FLUE GAS
CONVENTIONAL •'
PULVERIZED •'
COAL ASH I
MICRONIZEO
COAL ASH
FIGURE 2 COMPARISON OF ASH PARTICLE STREAMLINES
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101
To investigate the technical and economic viability of micronized coal as an
alternate fuel, GSU sponsored a similar program with the added objectives of
determining if soot blowing could control ash deposition from micronized coal on
tightly spaced superheater tube banks. Testing was performed by the Contract
Research Division of Babcock and Wilcox Company (B&W) at Alliance, Ohio.
Conventional and micronized grinds of three types of coal (one each from West
Virginia, Ohio, and Indiana), representing a range of ash contents and ash
fusion temperatures, were evaluated. Ash deposition testing was performed in
B&W's Laboratory Ashing Furnace (LAF), a 200,000 BTU/hr test furnace designed to
produce fly ash with properties similar to ash from a large utility boiler. The
LAF was operated with a furnace exit gas temperature comparable to that of an
oil designed unit (2400°F). The ash from each coal burned was collected and
analyzed for particle size, carbon content, and elemental ash constituents.
The size of fly ash particles from burning micronized coal was substantially
smaller than those from conventional pulverized coal. Ash particles from the
micronized coal did not agglomerate appreciably when these coals were burned in
the LAF and these particles were small enough to travel with the flue gas around
the simulated heat exchanger tubes, while pulverized coal ash particles did
not, but instead impacted and deposited on the tubes.
Based on the successful results of the LAF tests, scaled-up tests were conducted
in B&W's four million BTU/hr Basic Combustion Test Unit (BCTU) using the same
West Virginia Sewell No. 1 coal that was tested in the LAF. A 64-hour, around-
the-clock combustion/deposition test was performed using micronized coal. In
addition, some limited testing was performed using a finer micronized coal (mass
mean diameter of 8,3 microns as compared to 9.4 microns for micronized coal).
For comparison, some testing was performed using conventional pulverized coal.
During these tests, the flame from conventional pulverized coal filled the
entire BCTU furnace. When burning micronized coal, the flame occupied about 75%
of the furnace region. The flame from finely micronized coal occupied about
one-half of the furnace length. These results are similar to those obtained at
IGT. In addition, as was found in the IGT tests, nitrogen oxide emissions did
not appear to change as coal particle size was reduced.
Five parametric combustion tests using conventional pulverized coal were planned
to be conducted prior to the full power deposition test with soot-blowing.
However, before these could be completed, the deposition test section plugged
with ash (see Figure 3). This occurred within seven hours after starting up on
pulverized coal. Tube (surface metal) temperatures during this period ranged
from 400 to 600°F as compared to 950-1000°F when at full power.
In contrast, when micronized coal was fired, the deposits formed on the tightly
spaced tube bank in the BCTU were removed by sootblowing with air (see Figures 4
and 5). During this 64-hour continuous test, tubes were blown at intervals of
one to three hours, and base deposits (deposits on the tubes immediately after
sootblowing) did not appear to increase with time. These positive results
encouraged demonstration testing in a full-size boiler to confirm
these test results and address the question of erosion.
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102
FIGURE 3 PLUGGED TUBE BANK DURING PULVERIZED COAL
PARAMETRIC TESTING (WITHOUT SOOTBLOWING)
103
FIGURE 4 Air-cooled tubes prior to soot blowing.
FIGURE 5 Air-cooled tubes immediately after soot blowing.
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104
A step in this direction was taken when MP&L performed a unique test in which
micronized coal was fired in four of the twelve burners of a 100-MW unit at
their Delta station. Approximately 10,000 tons of coal ground to about 98% less
than 44 microns in a 20 ton/hr capacity fluid energy mill were burned. The coal
contained about 11.5% ash and accounted for one-third of the heat input to the
boiler co-fired with natural gas, which would be roughly equivalent to the use
of 4% ash coal (as was used in the GSU-sponsored BCTU tests) in a boiler
designed for oil or gas and with future coal capability. Relatively minor
accumulation of ash was found on the flat bottom furnace floor and convection
section surfaces.
Economic ^nd engineering evaluations have been performed to establish the merits
of dry micronized coal conversion for units in the 100 to 150-MW size range and,
depending on specific requirements at potential conversion sites, conditions may
be obtained which would justify conversion of existing oil/gas fired units to
dry micronized coal.
Principal efforts in this area currently are directed at reducing the energy
requirements of fluid energy grinding systems capable of micropul verizing coal.
Mechanical systems, such as a roller mill, consume less energy in
micropul verizing coal; however, transport air requirements are relatively high
in present designs and must be reduced to provide good combustion control. This
was accomplished in an industrial boiler conversion to micronized coal, by using
a semi-direct firing system in which excess air separated in a cyclone unit is
recirculated back to the pulverizer.
It is anticipated that as the data base is expanded and experience is
accumulated, fuel specifications will be able to be tailored to boiler
requirements for cost optimized operation by utilizing coal cleaning, fine
grinding and plant derate variables in the most effective manner.
Federal support is needed to accelerate the development and commercialization
effort because of the large cost of such a program, which is presented on the
estimate of funding requirements that follows. The proposed program is
described below.
Proposed Program For Development And Commercialization Of Dry Micronized Coal
The proposed program for the development and accelerated commercialization of
clean micronized coal fuels includes:
0 Research and Development
Expand the data base developed in the GSU and IGT testing program to
include combustion/deposition testing of a range of coal feedstocks
micropul verized to a range of fine grinds and with a range of depths of
coal cleaning. This data base would provide the information required to
establish fuel specifications with optimum combinations of fine grinding
and coal cleaning for various coal feedstocks. This would also provide
design information needed to address conversion requirements for a range of
site-specific boiler types to have optimum economics and environmental
impacts.
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105
0 Equipment Development
Perform the required engineering development and scaleup of micro-
pulverizers and coal cleaning systems. This will ensure availability of
equipment which will yield minimum plant capacity derating and acceptable
emissions.
0 Demonstration Testing
- Modify an oil/gas designed industrial boiler and demonstrate long-term
performance with micronized fuel operating with a minimal plant derate
in a cost effective environmentally acceptable manner.
- Scale up such a demonstration test to a 60 to 100 MW and then a 300+ MW
oil/gas design utility boiler plant.
- Another demonstration test is required for burning finer ground
micronized coal in boilers designed exclusively for natural gas. The
specification for this fuel would provide the appropriate combination of
ultra-fine grinding and deeper coal cleaning than required for oil/gas
designed boi lers.
3. COAL MATER SLURRY COMBUSTION
Recent progress in the development of coal water slurry fuels strongly indicates
that improved coal cleaning technology processes, integrated with coal slurry
fuel production plants, may be a particularly attractive route for increasing the
use of coal as a substitute for gas and oil in a cost effective and
environmentally compatible manner.
For most coals, the more finely the raw coal is ground the greater is the
release of ash materials and sulfur compounds. Efficient separation and
recovery of such coal fines has not been practiced in the past because the cost
of such operations and problems related to the safe transport and use of dry
powdered coal. However, coal slurry fuels production can have all the benefits
of fine coal cleaning while avoiding transport and storage concerns.
Coal slurry fuels are particularly attractive for those facilities where it is
impractical to convert to coal, such as oil and gas fired utility and industrial
boilers. Here space limitations generally preclude the needed equipment and
fuel storage requirements of coal. Use of pulverized coal in facilities
could be used in oil/gas designed facilities without significant derating,
could result in the eventual displacement of a significant fraction of the
approximately 2 million bbl/day of high and low sulfur fuel oil and 2 billion/cu
ft/day of natural gas consumed by utility and large industrial boilers.
As a result of extensive development programs supported by DOE and EPRI and
privately funded business development efforts, coal water slurry fuel using
conventional grind coal ^s now in the early phases of commercialization. Slurry
fuel suppliers have also developed the capability to prepare fuels with finely
27
106
ground coal of various size consistency, including ultra-fine coal water slurry
intended for use in gas turbine and internal combustion engines.
However, large scale demonstration of the production and use of coal water
slurry in oil/gas designed boilers is required to establish the relationship
between fuel specifications and boiler performance and to confirm fuel system
economics. Federal support of such a large scale demonstration could alleviate
private industry concerns related to energy project investments and bring about
a more rapid and extensive coal water slurry commercialization effort which
promises to benefit both national and private economic and environmental
interest.
Competitive interests now exist for fuel production, fuel handling equipment,
fuel transport, combustion systems, and coal cleaning processes which are
required to support a commercial coal water slurry industry. It can be expected
that appropriate fuel and equipment refinements will be developed by these
interests so as to optimize economic and environmental performance of coal
water slurry fuel as a function of user requirements.
Coal Water Slurry Fuel Technology
Coal water slurry (CWS) fuel is a method of processing coal to permit it to be
used in oil and gas fired boilers. By grinding coal, cleaning it, and adding
water and some chemicals, a fuel in liquid form similar to oil is produced.
Such a fuel can preserve the advantages afforded by a liquid fuel. It can be
processed offsite at a central preparation facility just as oil is at a
refinery. It can be transported to the user just as oil is, and once there, it
can be off-loaded, stored, pumped, and burned just as oil is.
"Dense phase" CWS fuel is typically a 70% pulverized coal/29% water mixture plus
a 1% chemical additive package to provide desirable flow characteristics and
storage stability. This CWS fuel uses coal ground to particle size at or near
that of conventional pulverized coal and is much different from "light phase"
CWS (50% coal/50% water), which was developed primarily for pipeline transpor-
tation of coal. Upon reaching the power plant, light phase CWS requires
dewatering and pulverizing prior to firing in a coal designed boiler.
The goal of coal water slurry developers is to produce a substitute for heavy
fuel oils which preserves the advantages of liquid fuels for the user while
offering the cost advantage of coal. At present, any facility capable of using
coal will be able to take advantage of such fuels in those instances where use
of dry coal is or may become impractical.
Slurry technology offers an approach whereby environmental benefits of advanced
coal cleaning systems can be utilized in a safe and efficient manner. Costs and
impacts of transportation and distribution of such fuels may also offer
advantages to prospective users.
Because of the ability of slurry developers to prepare a wide range of fuel
specifications, it is anticipated that industrial and utility fuel users now
dependent on oil and gas will have a cost effective environmentally compatible
fuel alternative based on coal. It is also expected that new plant designs may
incorporate the ability to utilize such fuels.
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107
Current Status of Development of Conventional Grind CWS Fuel
Considerable effort has been under way by firms in the US and other countries to
develop a CWS fuel. Limited commercial production and use of CWS fuel has been
achieved in Sweden where the tax on use of oil and excess generation capacity
permit acceptance of substantial derating in capacity. Ongoing development and
demonstration of CWS fuel in the US and Canada include, among others, programs
sponsored by prospective fuel suppliers, equipment suppliers, the EPRI, electric
utilities, DOE, the New York State Energy Research and Development Agency
(NYS-ERDA), industrial firms, and universities. Much of this research and
development has concentrated on the development of fuel characteristics
related to storage, handling, and combustion in coal capable boilers, but it
has not yet fully addressed ash impacts on oil and gas designed boilers.
Several producer organizations in the US and Canada are scaling up pilot plant
facilities to produce CWS, including such firms as B&W; Combustion
Engineering, Inc.; Foster Wheeler Energy Corporation; Atlantic Research
Corporation; and Al lis-Chalmers, Inc.
EPRI estimates that the combined production capacity of these suppliers by the
end of 1984 at about 350,000 tons per year. Government price supports or
private development activity could boost this capacity to as much as 1.5
million tons per year by 1986.
The EPRI coal slurry program has accomplished:
0 Standardization of slurry characterization tests
0 Development of slurry guideline specifications
0 Development of technology required to handle and burn CWS fuel
0 Performance of an industrial boiler demonstration test at the DuPont
facility at Memphis, Tennessee.
EPRI contractors tested properties of CWS fuels whose physical properties varied
considerably. Much of this variability can be addressed in the slurry
preparation stage. For example, intensive coal cleaning, which can
significantly reduce a slurry's ash and pyritic sulfur content, can be
incorporated as an integral part of slurry preparation. Because the final
product is liquid, the need for drying, the final step in conventional coal
cleaning, can be eliminated.
Combustion equipment development has kept pace with fuel development efforts.
Three domestic boiler companies — Combustion Engineering, B&W, and Foster Wheeler
Energy Corporation, using burners ranging from 15 million to 80 million BTU/hr —
have atomizer/burner systems in commercial-scale boiler tests lasting several
weeks. Sizes up to 125 million BTU/hr have been tested elsewhere.
A new generation of utility-scale (100 million BTU/hr) burners is under active
development. Performance goals include a turndown ratio of 3:1 or better,
minimum tip life of 2000 hours, air preheat of less than 300°F, maximum droplet
size of 300 microns, and carbon conversion efficiencies greater that 99%.
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108
Larger scale handling and combustion tests, each requiring the preparation of
firing of several thousand tons of slurry and lasting for at least one month,
have been performed in progressively larger boilers. Early tests in boilers of
8-20 MW capacity highlighted the need for prolonged tests in larger oil-designed
utility boilers to resolve performance uncertainties related to the considerably
higher ash content of CWS over oil. Results of these tests have been applied in
ongoing efforts to optimize burner designs and boiler conditions.
The largest-scale demonstration test conducted in the US to date was sponsored
by EPRI in 1983 at an industrial boiler operated by DuPont, in Memphis, Tennessee,
Over 35 days, 2500 tons of slurry were fired. Three burners were used, each
rated at 15 million BTU/hr and modified with new atomizers and air register
changes to .produce a high-swirl stable flame.
The DOE programs are complementary to the EPRI activities in investigating
handling, storage, and combustion of CWS. Universities have performed
experimental research and development studies supplying a broad base of data and
an understanding of the time history of atomization and combustion processes
with this fuel.
Rapid progress in CWS R&D has brought CWS to the threshold of commercial produc-
tion and use. The remaining technical issues are considered resolvable, and
other significant uncertainties are likely to be resolved, or at least clarified,
soon. The US Synthetic Fuels Corporation has solicited and received proposals for
production and use of CWS fuel to aid in accelerating its commercialization.
Micronized Coal Water Slurry Fuel
The CWS fuels being developed in activities described thus far contain coal
ground to particle sizes at or near that of conventional pulverized coal. Such
fuel would be suitable for use in coal designed boilers, but would require major
modifications and/or large plant capacity derating if used in oil and gas
designed boilers. Successful results in dry micronized coal test programs and
combustion tests of CWS fuel containing micronized coal show promise in
expanding the applicability of this technology to a broader user base with
increasing potential for improved environmental compatibility. These promising
test results now require an expanded data base and scaled-up testing and demon-
stration to confirm technical and economic readiness for commercial application.
Fuel developers have improved the physical characteristics of the fuel to be
compatible with available handling and storage equipment and continue to focus
attention on overall fuel cost reduction. Prospective users focus on the fuel
performance specifications needed to achieve reliable operation with a minimum
of plant derate and operational impact. Their primary goal is to develop confi-
dence in the technology through large-scale testing of competing fuel and
combustion equipment systems so that it may be used on oil designed equipment
with a minimal plant derate in a cost effective and environmentally compatible
manner.
Fuel cost and environmental quality concerns dictate the need for developing
coal slurry fuel cycles incorporating advanced coal cleaning system technology,
which should reduce coal feedstock costs; and cost effective transportation
systems, which reduce delivery costs.
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109
Proposed Micronized CMS Development and Commercialization Program
To encourage private interests in their efforts to improve and refine coal water
slurry and related equipment, a coal water slurry production and combustion
demonstration which would incorporate advanced physical coal cleaning and
pulverization equipment capable of producing a range of coal size distributions
finer than conventional grind in a fuel production facility is needed. The fuel
combustion plant would be of a design representative of the very large numbers
of relatively new oil/gas design boilers and be instrumented so as to be able to
define plant performance as a function of fuel specifications. The program
approach would be based on a scale-up of the current Northeast Coal Utilization
Program (NECUP) laboratory scale combustion/deposition test program. Included
among the NECUP sponsors are fuel suppliers, equipment manufacturers and fuel
users with the common objective of developing various coal water slurry fuels
for cost effective application in place of oil or gas.
The proposed program for the development and accelerated commercialization of
micronized coal water slurry fuels includes:
0 Research and Development
Expand the data base developed in the NECUP testing program to include
combustion/deposition testing of a range of coal feedstocks micropul verized
to a range of fine grinds and with a range of depths of coal cleaning.
This data base would provide the information required to establish fuel
specifications with optimum combination of fine grinding and coal cleaning
for various coal feedstocks. This would also provide design information
needed to address conversion requirements for a range of site-specific
boiler types to have optimum economics and environmental impacts.
ent and scale-up of
and coal cleaning systems. This
rh will yield minimum plant
Demonstration Testing
Design, construct and perform demonstration testing in a CWS preparation
facility which can, by varying the quality of coal feedstock and the
extent of fine grinding and coal cleaning, produce multiple streams of
end product to a range of fuel specifications. Also demonstrate highly
loaded (>80% coal) CWS handling and transport from the production
facility to the point of use, and fuel conditioning at the point of use,
in accordance with combustion system requirements.
Modify an oil/gas designed industrial boiler and demonstrate long term
performance with micronized CWS fuel, operating with a minimal plant
derate in a cost effective and environmentally acceptable manner.
Scale-up such a demonstration test to 60 to 100 MW and then a 300+ MW
oil/gas design utility boiler plant.
31
no
- Another demonstration test is rec^uitea Tor burning finer micronized coal
in boilers designed exclusively for natural gas. The specification for
this fuel would provide the appropriate combination of ultra-fine
grinding and deeper coal cleaning required for oil/gas designed boilers.
Federal support is needed to accelerate the development and commercialization
effort because of the large cost of such a program. This cost is reflected in
the following estimate of funding requirements. If effective utilization of
existing plants can be implemented in the performance of the program,
significant reductions in cost may be realized. Based on the cooperation
exhibited by fuel suppliers and users within the NECUP program and their
expressed interest in pursuing the commercialization of coal slurry fuels, it is
expected that such cooperation will be extended to allow for a cost effective,
cooperatively funded demonstration.
32
Ill
MICRONIZED COAL DEVELOPMENT
AND COMMERCIALIZATION PROGRAM
ESTIMATE OF FUNDING REQUIREMENTS (in millions)*
1986 1987 1988 1989 1990 TOTAL
RSD
Combustion/Deposition .5 1.6 1.5 3.5
Testing (4MM BTU/hr)
(Expand Data Base)
EQUIPMENT DEVELOPMENT .3 2.5 2.5 5.3
Micropul verizers
Coal Benef iciation
DEMONSTRATION TESTING
CWS Preparation Facili
ty
5
15
25
5.0
50
Industrial Boiler
Demonstration Test
.25
1.5
.5
2.25
Small Oil /Gas Utility
Boiler Demo Test
(60-lOOMW)
4
15
15
34
Large Oil /Gas Utility 12 40 52
Boiler Demo Test
(300+MW)
Small Gas Only Utility 4 4
Boiler Demo Test
TOTALS 6.0 19.25 34.5 32.5 59 151
♦These are estimates of total funding requirements; percentage of DOE and
private sector co-funding are unknown at this time.
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112
4. TWO STAGE SLAGGING COMBUSTORS
Two stage slagging combustion is a third advanced coal technology which could
enable coal to be used in oil and gas fired boilers. The characteristics of
this combustion process allow for highly efficient combustion of coal fuels with
sharply lower emission levels. Also, these combustors would allow the use of
coal in boilers and furnaces designed for oil and gas.
Description of Technology
The basic concept of two stage slagging combustion involves initial ignition of
pulverized coal in a small combustor vessel in a starved air (reducing)
environment. The combustion intensity in this primary vessel is very high,
resulting in complete gasification of combustion products as well as melting of
inert ash components of the fuel. The gaseous products which exit this vessel
are essentially a hot fuel/flue gas mixture which would be burned, with
additional air, in an existing furnace. The molten ash is collected in the
combustor and removed for quench and disposal.
The reducing environment of the primary stage avoids the creation of NO^^ during
combustion. The secondary combustion is controlled using conventional
techniques to maintain low levels of NO generation. Testing has proven the
ability of this process to hold N0„ leveis below 450 ppm (current coal NO
emission limits) and as low as 150-200 ppm (current oil/gas emission limits).
Refinements of the primary stage combustion process have included injection of
various sorbents in an effort to reduce SO2 formation. Experimentation with
various combinations of sorbent type, injection location, combustion duration
and slagging condition indicates that SO2 formation can be reduced
substantially. Testing has proven that many non-compliance coals can be burned
in slagging combustors within environmental emission limits with no need for
costly flue gas desul furization equipment.
Removal of molten ash from the primary combustor is of value since 1) the amount
of ash entering the furnace is reduced by up to 90% and 2) the ash remaining in
the flue gases is extremely small particulate (80% <10 microns). These features
may permit expanded use of coal on two fronts: retrofit of existing oil fired
equipment and improving design of new coal fired equipment. The combustor's
ability to reduce the quantity and size of ash particulate in the flue gases
allows coal to be used in boilers and furnaces designed for oil with little or
no impact on performance. Conventional pulverized coal combustion in such
boilers and furnaces would result in furnace slagging and convection section
plugging due to ash in the flue gases. Without these combustors, extensive
modification to the boiler and derating of unit capacity would be required to
avoid these problems. Future application of these combustors to new boilers and
furnaces may result in reduced capital cost and physical size of these units, as
well as improved emissions performance.
Applicability of Technology
In general, two stage slagging combustion technology is compatible with most
combustion equipment, specifically units for the indirect (radiation and
convection) heating of fluids and or solids. These include boilers, process
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113
heaters, and furnaces. This technology is also applicable to some direct fired
process heating equipment where the product would not be contaminated by the
small quantities of ash leaving the combustor. These include kilns for lime,
soda ash, or similar materials, and furnaces for some glasses and metals.
There are a few technical considerations that limit the applicability of two
stage slagging combustion in retrofit or new equipment applications. In most
cases feasibility will be determined by economic considerations.
Test results indicate that optimum combustor performance for slag recovery and
NO generation is difficult to obtain in burner sizes below 50 million BTU/hr.
This may be a lower size limit for applicability of these burners.
In retrofit applications, this technology is best suited to equipment designed
for oil fuels where little or no derating of capacity would be required.
Equipment designed for natural gas, especially boilers with high temperature
superheater sections, will be more sensitive to the fine ash particles in the
flue gas and would be subject to some level of derating.
To further assess the applicability of this technology, much study has been
performed to assess the economic feasibility of retrofit of boilers and furnaces
with two stage slagging combustion. These studies have addressed the costs of
the combustor installation including all required support and pollution control
systems. Additional study is underway as part of the TRW/DOE study program.
These studies have shown that, in most cases, conversion with the two stage
slagging combustors would be economically attractive. Payback of conversion
costs ranges from 2-3 years, although this has been adversely affected by the
recent softness in oil prices. The payback does show typical improvement for
larger applications where economics of scale come into play. Economic
attractiveness falls off sharply for small (<50 million BTU/hr) size
conversions. Also, by comparison, two stage slagging combustor conversion is
economically more attractive than conventional pulverized coal conversion.
Recently, studies have been initiated to assess the value of two stage slagging
combustors in reducing capital cost and reducing physical size of new boilers
and furnaces designed to be fired by these combustors. Boiler manufacturers
have undertaken studies to consider the costs of new two stage slagging
combustor fired units in comparison to conventional stoker and pulverized coal
units. Preliminary information indicates that substantial savings can be
realized on large industrial and utility boilers, as well as those designed for
low grade fuels.
Current Status of Development
The development of two stage slagging combustion is an outgrowth of DOE
sponsored work on Magnetohydrodynamics (MHO), This program required a source of
high pressure (6 atrft,), ^frigh temperature (4500°F) plasma for electric current
induction. Coal combustors developed for this application provided high
intensity two stage combustion with slag removal and were available for use,
with some modification, in atmospheric combustion. To account for the lower
pressure and the relatively cooler combustion gases, combustor geometry, air and
fuel injection, and slag collection and recovery were slightly changed.
35
114
Because of this, it is not surprising to find that the participants in the DOE
program for MHD are also the major participants in two stage slagging combustor
development. These include TRW (the final selected supplier of MHD combustors
for future DOE work), Rockwell International, AVCO, and Coal Tech (established
by personnel from GE sponsored MHD work).
Of these four, only TRW and Rockwell have progressed significantly towards
commercialization through construction and exhaustive testing of prototype
combustor units. AVCO and Coal Tech have continued limited development and
simulation, but have no prototype or combustion testing. AVCO recently began
limited testing of a combustor prototype under a DOE sponsored program. Due to
the early stages of this program, however, the status of TRW and Rockwell
represents the current state of the art.
The TRW and Rockwell combustors have taken different approaches to design and
operation and therefore can be contrasted on many features. The TRW unit
operates at a high combustion intensity requiring a relatively small combustor
vessel. A 100 million BTU/hr unit, for example, is about 4 feet in diameter and
11 feet in length. The high intensity requires high pressure combustion air and
water cooling of the bare metal combustor internals. While water cooling would
prevent corrosion of metal parts by combustion products, it may, in some
retrofit installations, lead to complicated integration requirements for heat
recovery.
The Rockwell unit is larger with less than half the combustion intensity. This
lower heat release allows for use of refractory lining for some metal combustor
internals. This reduces integration problems, but may complicate operation and
maintenance of the combustion unit. Refractory has a poor history for life and
reliability when operating in slagging environments and requires long warm up
and cool down cycles.
TRW has performed extensive short term (2-3 hours) testing on three prototype
units ranging in size from 1 to 50 million BTU/hr. Most testing was performed
on a 10 million BTU/hr unit. The TRW program focused first on slag capture and
NOjj control, features considered to be essential for retrofit of oil and gas
boilers. After optimization of these parameters, obtaining removal of 90% of
coal ash as slag and producing as little as 250 ppm of NO^^, TRW began testing
SO2 control methods. Current testing is continuing with emphasis on variation
of operating parameters to obtain simultaneous performance of 90% slag capture,
250 ppm NOjj and removal of 50-80% of fuel sulfur.
TRW has also initiated a program to provide long term (4,000 hours) combustor
performance testing through the retrofit of a small industrial boiler to fire
coal with a 50 million BTU/hr unit. This long term data is essential to
commercial acceptance of the combustor for retrofit or new installations. TRW
has assembled a Users Group of potential combustor users to partially fund this
demonstration. This ten member group also serves to advise TRW on combustor
design and performance preferences. Actual retrofit is underway with startup of
this demonstration unit expected in mid-1985, TRW is also performing an
extensive program to explore combustor operations to enhance sulfur capture and
36
115
operate on a wide variety of pulverized and coal water slurry fuels. This
program, funded by DOE, TRW and others, includes the installation of a boiler
simulator to obtain data regarding the interaction of the combustor with boiler
internals during retrofit operation.
Rockwell International has performed fewer short term tests than TRW and has, in
general, focused on low NO^^ and SOo emissions with little emphasis on slag
collection or removal. SOo and NO^ control and the slower combustion required
for this control have caused, to some extent, the larger size of the Rockwell
unit. Most testing has been performed on a 7.5 million BTU/hr combustor unit
which is partially refractory lined, but requires some water cooling. Testing
reported to date has obtained up to 90% sulfur removal and 150-220 ppm NOj^ with
no slag removal. Recent testing has begun to address the slag removal issue
with the installation of a slag capture tube bank. This method of slag removal
has possible operation problems, such as clogging at low load. Additional
testing is planned to prove this concept.
Rockwell is planning a long term demonstration of first a single and ultimately
multiple combustors in the 100 million BTU/hr size range. Rockwell has also
assembled a sponsor group of 4-5 utilities to fund this program, and advise and
comment on combustor design and testing. The planned schedule for this
demonstration is late 1985-1986.
A table summarizing TRW and Rockwell design, performance and testing is
attached.
Development Goals
Both TKW and Rockwell development programs are proceeding toward commercializa-
tion. The demonstration programs planned represent only the first of several
commercial demonstrations required prior to industry acceptance of this
combustion technique. Development of these technologies will require
substantial R&D expenditures.
The future of this technology will be greatly affected by the performance of
these first demonstration units. If operating problems are found, or unit
performance is below prediction, developers and interested users may be
discouraged and reduce funding support. The energy markets and continued
interest in coal conversion are also important components in the development.
Technically, several issues must be dealt with--optimization of simultaneous
slag capture, sulfur removal and low NO^^ generation. Also, testing is needed to
verify the ability of these combustors to perform on a variety of coals
(eastern, western, etc.) and coal slurries. Finally, scaling of the combustor
units from the proven 50-100 million BTU/hr sizes to the likely maximum size of
250-300 million BTU/hr must be accomplished.
The combustors as currently developed and operated are, in comparison to
conventional burners, complex. Accurate metering of multiple combustion air and
fuel feed points is required to maintain proper combustion, emission and
slagging performance. These complexities would be expanded in a multiple burner
boiler where up to 30 combustors would operate simultaneously.
37
116
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Testing has shown the combustion to be relatively insensitive to variations in
fuel moisture, heating value and ash content. Optimum operation, however, for
minimization of NOj^ and SOp emissions while maximizing slag capture, may require
operation within a small band of conditions. The ability of two stage slagging
combustors to operate on a regular basis and maintain near optimum operation
must be demonstrated.
As commercial utilization becomes a reality, development programs must be under-
taken to better define hardware integration issues. These include large
industrial and utility scale retrofit integration of combustor shell heat
recovery and slag collection and quench, mechanical interface between combustor
and boiler or furnace, and integration and simplification of combustor system
controls.
Proposed Future Development Program
The development and demonstration programs underway or planned will serve to
prove the combustor concept. Both the TRW demonstration program and the planned
Rockwell program will test the combustor in boilers originally capable of coal
firing. Also, these programs will test combustor units on the lower end of the
size range and for boiler service only. Prior to wide spread commercial
acceptance of tliis technology for retrofit of oil and gas fired industrial and
utility boilers and more complex applications, additional development and demon-
stration will be required.
These development and demonstration programs would provide for the improvement
of combustor performance to meet the operating requirements of larger, utility
scale coal firing of oil and gas designed boilers; operation with exotic or
waste fuels; and non-boiler applications.
Areas which will require development and demonstration programs are described
briefly below. The following table identifies funding required for these
programs over the next decade.
SOo Control Development/Improvement — SO2 control development programs would
explore the SOo removal process to improve the current 60% removal levels to a
90% level required for larger scale and utility applications.
Combustion Scaling — Combustor scaling from its current 50-100 million BTU/hr
size to a 250 million BTU/hr size will be required for large utility units. The
internal flow and combustion patterns will vary as the unit diameter increases.
Utility Scale Demonstration — A demonstration program will be required to prove
the combustor in large scale units and multiple burner applications such as
utility boilers. These boilers would represent the most stringent requirements
for NUj^ and SO2 control.
Direct Fired Gas Turbine Development/Demonstration — Much interest has been
expressed on the potential application of slagging combustors to direct fired
gas turbines. This would require improvement of slagging performance and demon-
stration to prove the concept.
39
118
Alternate Fuels — Alternate and waste fuels such as petroleum coke, lignite,
oil rig wastes, pump black liquor and coal wash plant tailings would allow use
of the combustor in a wider variety of applications. Each fuel, however, has
sharply different properties requiring development programs to optimize
combustion.
Complex Applications — There are several advanced applications of the slagging
combustor technology. These applications involve processes or combustion
systems which must be closely explored after the technology is proven and
accepted on a wide scale. Such applications are limitless but include, as a
minimum, combustor fired locomotive engines and combustor based steel reduction
furnaces.
40
119
SLAGGING COHBUSTOR DEVELOPMENT/DEMONSTRATION ACTIVITIES
FOR DEPART>1ENT OF ENERGY SUPPORT
DEVELOPMENT COSTS (MILLIONS $)
ACTIVITY
1986
1987
1988 1989 1990
TOTAL
Additional
Private Sec.
Co-funding
1985-1994
TOTAL
Industrial Demonstration
Underway — i
Commercial Support —
6
6
SO Control Development/
Improvement
0.5
1
1
2.5
2
4.5
Coal Water Slurry
Combustion
0.5
1
1.5
1
2.5
Combustor Scaling
2
1
3.0
1
4
Utility Scale Demon-
stration
3
9 4 2
18.0
4.0
22.0
Direct Fired Gas Turbine
(Development/
Demonstration)
2
2 3 5
12.0
4
16.0
Alternate Fuels
Petroleum Coke
Lignite
Oil Rig Wastes
Black Liquor
Wash Plant Tailings
1
2 3 3
9
1.5
10.5
Complex Applications
Locomotive Engines
Steel Reduction Furnaces
TOTAL 1
(TOTAL 1986-1990 = 70 MILLION)
10
14
11
11
47.0
13
70
41
120
5. LIMESTONE INJECTION MULTISTAGE BURNER (LIMB)
LIMB combines sorbent injection for 50,^ control with low-NO burners for NO
control. Low-NOj^ burners of various designs have been developed by both EPA and
private industry and are capable of retrofit applications. The SOj^ control by
sorbent injection is an emerging technology which has been developed by the EPA.
The reaction of SO^^ with sorbents (i.e., limestone and other alkaline solids) is
well known under proper conditions (e.g., wet FGD). LIMB is based on injection
of a sorbent directly into the furnace and its subsequent reaction with gas-
phase SOp to form a dry calcium sulfate. The amount of SO2 that can be captured
is dependent on the type and amount of sorbent, its mixing with combustion gases
and fly ash in the furnace, and its thermal history. The relative simplicity of
the technology lends itself to a relatively low cost retrofit on a wide variety
of systems. The technology has the potential to reduce both SO^^ and NO^^ by 50-
60% for retrofit applications and by 70%-90% for new sources at a cost of at
least $100/kw less than existing technologies such as FGD.
Applicability of the Technology
The technology is potentially applicable to pulverized coal-fired industrial and
utility boilers. The technology may be considered either for retrofit of the
existing population or on new systems for compliance with New Source Performance
standards.
Sulfur oxides (SO^^) and nitrogen oxides (NO^^) are two major pollutants resulting
from the combustion of fuels. Coal fired utility boilers account for about 70%
of the SO^ and 20-25% of the NO^^ emissions in the US. For the 180,000 MW of
boiler capacity east of the Mississippi River, this amounts to approximately 16
million tons of SO2 and 4-5 million tons of NO per year. Only about 10% of
these boilers are subject to NSPS controls for bO^^ and NOj^. Therefore, to
accomplish any significant reduction in SO^^ and NO requires a retrofit of
existing boilers which may have a remaining useful life from 5 to 30 years
or more.
Within this population of coal fired utility boilers there are two major design
types which must be addressed: 1) wall-fired boilers, which are manufactured by
B&W, Foster Wheeler and Riley Stoker; and 2) tangential ly-fi red boilers, which
are manufactured by Combustion Engineering. Each type is about 45% of the
existing population, with up to 10% in other designs. Due to significant
differences in the firing system, any technology which involves changes to the
combustion must be developed for each major type.
The biggest single advantage of LIMB for existing boilers is its potential cost
advantage over existing technologies. For a typical 500 MW plant the capital
cost savings (at $100/kw less than FGD would be $50 million. In addition,
recent cost modeling shows that LIMB can offer operating savings of between
$270 to $1000 per ton of SOo removed depending on a number of operational
factors. This represents operating costs that are 27% to 45% less than those
for FGD.
For existing boilers, application may be limited by the thermal profile within
the boiler and by access for satisfactory injection and mixing of the sorbent.
In cases where these factors are favorable, convective pass tube spacing and
42
121
particulate control systems must be capable of handling the increased solids
loading, however, the ultimate retrofit applicability will depend most
strongly on the mandated strategy for control of acid rain percursors.
There is an even stronger potential for new boiler systems. Dependent on the
assumed capacity growth, the use of LIMB instead of FGD for SO^ control on low
sulfur (up to 1.5%) coal fired NSPS boilers might produce capital cost savings
up to $10 billion. The operating cost savings estimate range from $800 to
$1900 per ton of SO2 removed, or 40 to 60% less than FGD.
New boiler systems can be designed from the ground up to accommodate the LIMB
system using relatively conventional boiler technology. The temperature
profile, injection points, convective pass spacing and particulate
control can be tailored to optimize the process. This application
appears particularly favorable for low to moderate sulfur coals (<1.5%)
where NSPS requires 70% control of SO2.
Current Status
The majority of the R&D in the US has been provided by EPA under funding both
in-house and at its contractors. There are modest efforts at various government
and private sector laboratories. The EPA's LIMB program has been structured to
give the best probability of achieving the stated goals of moderate SO and NO^^
control (50-60%) at low cost with applicability to the major portion of the
existing boiler population. The major research objective is to provide the
basis for widespread private sector commercialization based on successful demon-
stration of the technology on both a wall-fired and a tangential ly-fired boiler.
To achieve this objective the research program has been divided among the
following four areas: generic research and development, prototype testing,
full-scale demonstration and technology generalization. These four areas have
been used to discuss the progress to date as a result of all public and private
R&D. A brief description of the current status of each area is presented below.
Generic Research and Development. Much of the LIMB research in the US has been
based on the fact that a complete understanding of the process is necessary to
given the maximum probability of successful commercialization by the private
sector. R&D of this type is relatively independent of the hardware specific
constraints of practical boilers and provides information essential for
application of LIMB to all boiler designs.
The generic research and development has provided excellent insights on the
effects of critical process parameters on SOt capture. The research has
examined the effect process parameters have on sorbent activation and
subsequent sulfur capture, as a function of combustion system
conditions. Recent EPA test results from LIMB experimental boilers
indicate that limestone injection alone will only achieve 40% sulfur
removal efficiency, lower than originally estimated. However, other
tests have indicated that the LIMB SO2 removal goals can be met with at
least two alternate approaches: high surface area sorbents (calcitic
and dolomitic hydrated limes) or sorbents with mineral promoters (small
amounts of inexpensive innocuous materials to enhance sorbent
reactivity). The use of a high surface area sorbent or sorbents with
promoters will increase LIMB costs by about 10%, the estimated capital
43
s is
122
cost for LIMB would still be 20% to 30% that of a wet scrubber.
Additional R4D necessary to address these high activity sorbents
discussed in the next section. The R&D has also provided an
understanding of fly ash/sorbent mixture characteristics as related to
slagging, fouling and particulate capture.
Prototype Testing. The results of the pilot scale generic research must be
scaled up to large size boiler systems. As an intermediate step prior to a
demonstration, prototype testing is being carried out in large experimental
systems. Within the research area, alternate sorbent injection designs and
optimum injector locations are being evaluated, and scale up criteria are being
developed. These tests have shown that the burner design is not the dominant
factor in achievable SO2 capture and that sorbent selection and injection
conditions are critical.
Demonstrations. Initial LIMB development has focused on the wall-fired boiler
because research data and large scale experimental facilities were available. A
demonstration program for a representative wall-fired utility boiler was
initiated in FY 1984. EPA awarded a contract for such a wall-fired
demonstration in September 1984 to the Babcock and Wilcox Company (B&W). A 105
MW wall-fired boiler will be modified by B&W for the LIMB technology at the
Edgewater Station of the Ohio Edison Company. The final site specific design
for the installation will be completed in February 1986. Year long term testing
will begin in July 1987, and a report evaluating the LIMB performance will be
completed in March 1989, EPRI has initiated an effort to perform R&D testing on
a small boiler (20-100 MW) and to ultimately retrofit a 400 MW plant; however,
no arrangements have been announced. The Europeans are involved in numerous
boiler injection tests (most of which are low rank coals) which are atypical of
US fuels. The Weiher III testing in Germany using a black coal has EPA
participation in the measurement phase. Several tests in small boilers (<60 MW)
have been performed in the US with encouraging results.
Technology Generalization. Activity in this area has been limited to the
exchange of information with other researchers and potential users of LIMB.
This exchange included a joint EPA/EPRI Conference on LIMB which was held in
November 1984.
DEVELOPMENT GOALS
The technology is currently being aggressively carried through the development
stage by the US EPA LIMB program. In that program the research needs are
structured in the four categories previously described. The research needs
described are those which were identified during a recent OEET/ORD review of the
LIMB program and during the recent EPA/EPRI symposium.
Generic Research and Development. Recent research results have identified
increased sorbent surface area as a key factor in obtaining high sulfur capture.
It has been shown that high surface area can be generated external to the
combustion process and/or in situ. These high surface area materials have shown
the potential for sulfur ^capkfMre. in excess of 70%. The planned R&D addresses
methods for obtaining highly reactive sorbents, for optimizing reaction conditions
to achieve maximum capture, and for minimizing sorbent costs.
44
123
Another key factor is the interaction of sorbents with mineral matter, which can
either enhance or degrade the sorbent reactivity. The most promising results
indicate that it may be possible to add small amounts of relatively inexpensive,
innocuous promoters (mineral compounds) which will enhance the sorbent activity.
Sulfur captures approaching those of high surface area sorbents have been
achieved with promoted limestone in limited bench scale experiments. It also
appears that promoters can significantly improve the performance of high surface
area sorbents. A significant effort is necessary to understand the enhancement
mechanisms and to provide the basis for use in practical systems. It should be
noted that a similar understanding is necessary for other sorbent/mineral matter
interactions which can inhibit sulfur capture and which affect slagging, fouling
and collection characteristics of the particulate.
Process analysis has indicated substantial benefits may be derived from recycle
of unreacted sorbent and promoters. In addition, utilization of the spent
sorbent and fly ash has significant potential economic benefits. Pilot scale
R&D is necessary to evaluate the engineering feasibility of these process
options.
Specialized measurements, which are required for LIMB R&D and demonstrations,
are also provided in this area. These on-going activities include routine and
developmental analyses for sorbent characteristics and LIMB particulate form.
Prototype Testing. Prototype work is essential for scale up of the performance
improved sorbents and for tangentially fired boiler systems. This testing will
address criteria for injection of high activity sorbents into a thermal
environment representative of all US boilers. The testing on wall-fired
prototypes will build directly on previous experience with a wide variety of
burner designs. The optimum injection locations must be selected for each class
of sorbents based on smaller scale R&D. Injector designs must be evaluated and
scale-up criteria developed. Prototype testing for tangentially-f ired systems
will be initiated to examine similar design features in the presence of a vortex
flow field. Both cold flow modeling and large scale combustion tests are
planned. Finally, a cooperative program of testing on a small boiler (20-40 MW)
will be initiated to examine both sulfur capture and operabi lity/rel iabil ity
impacts. Flexible operation, including types of fuel and sorbents, will provide
an attractive R&D complement to full-scale boiler demonstrations. It may also
allow an assessment of applicability of LIMB to industrial boilers.
Demonstrations. As was previously mentioned, the utility industry will not
adopt the LIMB technology until it has been demonstrated in full-scale
facilities. There are two major types of boilers which represent about 90% of
the boiler population in this country. These are wall-fired boilers and
tangential ly-fired boilers. Because of the substantial difference between the
firing systems, technology developed for wall-fired systems is not directly
applicable to tangentially-fired systems.
The contract for the wall-fired demonstration has been awarded to the Babcock &
Wilcox Company, who will install LIMB on a 105 MW single wall-fired unit.
The final site specific design for the installation will be completed in
February 1986. Long term testing will begin July 1987 and a report
documenting the performance evaluation will be completed in March 1989. The
funding to complete the effort is provided in the FY85 budget and no outyear
45
124
contingency funds are identified. Any supporting work will be provided by
the generic R&D program.
Technology Generalization. For ultimate wide spread use of the LIMB technology
the R&D results must be integrated with the full scale boiler demonstration
results to provide guidance for commercialization by the private sector. The
program includes both process analysis to evaluate applicability and
economics for specific systems and process modeling to provide a methodology
useful for site-specific designs. In FY85 and FY86. the process analysis has
emphasized LIMB system options for application to different boiler classes in
the population and for minimizing the cost per unit SOo removal. The process
modeling will provide component models for thermal history, sorbent
activation and reaction, injection, and mixing. Funding is provided in FY87
to FY89 for integration of these models into an overall design tool.
PROPOSED FUTURE DEMONSTRATION
A tangential ly-fired demo is not provided in the current EPA budget scenario.
The generic R&D results provide the basis for application of LIMB to
tangential ly-fired boilers. However, only limited system specific development
has been done. One key factor in obtaining acceptable SO^ capture is injection
and mixing the sorbent at the proper combustion conditions. The injection and
mixing of sorbents is complicated by the vortex action produced in the
combustion gases by tangential firing. To date only limited small pilot scale
development has been performed with representative combustion conditions. It is
estimated that a full-scale demonstration will require $10-15 million government
funding, assuming 50/50 co-funding with the private sector. Due to the EPA lead
role in development of the technology, the Board strongly urges a cooperative
DOE/EPA program in this area.
46
125
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6. LOW NO. SYSTEMS/DUAL FUEL OVERFIRING
Advanced combustion modification technology can be utilized to achieve NO^^
reductions ranging from 50 to 85%. One such technology, known as dual fuel
overfiring or reburning, is capable of being used on new or retrofit
applications. It can also be applied in combination with other low NO^^
techniques, such as low-NO^ burners, to optimize the NO^ reduction. For
example, the two stage slagging combustor (described in another section)
could potentially utilize reburning to minimize NO^^ emissions.
Reburning also has potential for combined sorbent injection to achieve
simultaneous NO^ and SO^^ reduction.
Description of Technology
The basic concept of dual fuel overfiring, or reburning, involves the use of a
second combustion zone downstream of the primary flame zone. This "reburning
zone" is usually operated fuel rich in order to create a reducing zone in which
NO formed in the primary zone is reduced to N2 and H2O. Air to complete
burnout is injected downstream of the reburning zone. The fuel used for
reburning can be the same as that used in the primary zone, or can be
different. Bench-scale tests have shown that it is desirable to use a
fuel with a low fuel nitrogen content in the reburning zone in order to
maximize its effectiveness.
It is also desirable to operate the primary combustion zone at as low an excess
air level as is practical. This minimizes the amount of fuel needed to reach a
stoichiometric ratio of about 0.9 in the reburning zone.
It has been found that air staging can achieve NO^ reductions of the same
magnitude as reburning. However, the large reducing zone which is created to
achieve the same NO^^ reduction levels can create a severe tubewall corrosion
problem. With reburning the reducing zone can be very small and steps can be
taken to minimize or eliminate the corrosion problem.
Applicability of Technology
Reburning can be used on a wide variety of commercial combustors such as
boilers, kilns, and process heaters. However, its application and effectiveness
will vary depending on combustion design and fuel fired.
Application to any new design of combustor should be straightforward. However,
retrofit application will depend on factors such as heat release rate and fuel
avai labi 1 ity.
If applied to an existing coal-fired boiler, coal could only be used as the
reburning fuel if there is sufficient time for complete carbon burnout. In a
tightly designed boiler it may be necessary to use natural gas as the reburning
fuel.
It should be relatively easy to apply reburning to a precalciner cement kiln.
Since the kiln cannot be operated fuel rich due to the effect on clinker
quality, gases exiting the kiln could be passed through a reburning zone in the
precalciner section of the kiln.
50
129
Based on bench-scale tests reburning should also be applicable to other
combustor types, such as refinery process heaters. NO reduction levels
approaching 85% were achieved on a system using natural gas as both the primary
and reburning fuel .
Current Status of Development
Dual fuel overfiring is also known as fuel staging, in-furnace NO^^ reduction,
and MACT (Mitsubishi Advanced Combustion Technology). The process was
originally investigated in the late 1960s and early 1970s by J.O.L. Wendt and
C.V. Sterling, who coined the term "reburning". Further work was performed by
a! Myerson. Each of these investigators performed laboratory-scale research
which was reported at meetings of The Combustion Institute in 1973 and 1975.
Until 1981 little was heard about the technology. At the US/Japan Information
Exchange, which was held in Tokyo in May 1981, several Japanese companies
reported on results of bench- and pilot-scale tests using reburning to achieve a
50% NOj^ reduction.
Prior to the US/Japan Information Exchange, DOE had sponsored bench-scale tests,
performed by Acurex Corporation, to further investigate reburning. Following
the May 1981 meeting, EPA decided to sponsor further research to scale-up the
technology and evaluate its effectiveness on US designed boilers. EPA sponsored
laboratory-, bench-, and pilot-scale tests on 7,000 BTU/hr, 60,000 BTU/hr, and
10,000,000 BTU/hr test facilities, respectively, which were performed by Energy
and Environmental Research (EEK) Corporation, In addition, tests were performed
in-house by EPA on a 3,000,000 BTU/hr package boiler simulator and a 2,500,000
BTU/hr Scotch type boiler to evaluate application of reburning on package
boilers. The Gas Research Institute is currently sponsoring additional tests at
EER to obtain data for reburning with natural gas. Tests have also been
sponsored by EPRI on a 100,000,000 BTU/hr coal -fired test facility operated by
Riley Stoker. In Japan, reburning has been applied to several full-scale
utility boilers.
In general, tests performed to date have shown that the way reburning is applied
is critical to its success. If properly applied it is capable of achieving NO^
reductions of 50% to 85%, depending on the type of combustor, fuels fired, and
NO levels in the primary combustion zone.
DEVELOPMENT GOALS
It is desirable to apply the reburning technology which has been developed to
US-designed boilers, kilns, process heaters, etc. This technology can be used
on a new or retrofit basis and is an order of magnitude less expensive than the
alternative of flue gas treatment.
Further investigation is necessary to evaluate the potential of sorbent
injection in the reburning zone for simultaneous NO^/SO^ control. However,
bench-scale tests performed by EER have shown that this option has good
potential. The temperature and residence time in the reburning zone appear to
be ideal tor sulfur capture by a sorbent material.
As commercial utilization becomes a reality, development programs must be
undertaken to better define potential operating problems such as carbon burnout,
51
130
corrosion, and combustion efficiency. Evaluation of reburning on a wide variety
of combustors will be desirable.
PROPOSED FUTURE DEVELOPMENT PROGRAM
The bench- and pilot-scale programs that are currently underway or planned will
serve to prove the reburning concept. However, prior to widespread commercial
acceptance of this technology for new or retrofit application, additional
development and demonstration will be required.
These development and demonstration programs would provide for improved NO^^
reduction and for further evaluation of sorbent injection for SO^ capture. It
is recommended that DOE support such demonstration programs since they will lead
to increased coal usage in an environmentally acceptable manner. EPA should be
directly involved to ensure technology transfer and in order to maximize the
NO^SOjj reduction potential.
As reburning is applied to specific types of combustors it would be desirable to
involve relevant organizations both technically and financially, where possible
(e.g., EPRI for utility boilers, GRI for gas-fired combustors).
Demonstrations should be planned for industrial boilers, utility boilers, cement
kilns, refinery process heaters, and other combustors which emit relatively high
levels of NOj(. Its application should also be evaluated on two stage slagging
combustors. Reburning should be applicable to practically all combustor types.
52
131
LOW NOv SYSTEMS/DUAL FUEL 0VERFIRIN6
ESTIMATE OF FUNDING REQUIREMENTS (MILLIONS)
FY86 FY87 FY88 FY89 FY90 TOTAL
Application/Demonstration 0.50 1.0 1.5 1.0 4
of Reburning to Industrial
Boilers
Applicanon/Demonstration 2.0 5.0 5.0 5.0 17
of Reburning to Utility
Boilers
Application/Demonstration 5.0 10.0 10.0 25
of Reburning Combined with
Sorbent Injection to Utility
Boilers
Application/Demonstration 3.0 5.0 8
of Reburning to Cement Kilns
Appl ication/Uemonstration 3.0 3
of Reburning to Two Stage
Slagging Combustors
TOTALS 0.50 3.0 11.5 19.0 23.0 57
*These are estimated of total funding requirements; percentage of DOE, EPA
and private sector co-funding all unknown at this time.
53
132
C. COMBUSTION II.
FLUIDIZED BED COMBUSTION
by: Kurt Yeager
I. DEFINITION OF SUBJECT
This section will review the status and outlook for both Atmospheric Fluidized
Bed Combustion (AFBC) and Pressurized Fluidized Bed Combustion (PFBC).
Fluidized bed combustion (FBC) is an evolutionary improvement in coal-
fired boiler design that has the potential of providing significant
advantages over conventional pulverized coal boilers.
Interest in FBC technology stems from three primary characteristics: the
ability to control SOo and NOj. emissions without concern for ash properties or
quantity, and the potential to reduce both capital and operating costs when
compared with current technology. In the case of PFBC these advantages are
further augmented by the opportunity for higher thermal efficiency and increased
modular construction.
II. STATE OF THE ART
1. Atmospheric Fluidized Bed Combustion (AFBC)
The fluidized-bed boiler that operates at near-atmospheric pressure on the fire
side is a relatively simple boiler, no different in purpose than the
pul verized-coal and stoker boilers more generally used today. Fluidized-bed
boilers can generate steam at the pressure and temperature needed by modern
steam turbines through conventional heat transfer; only the firing system is
different.
In fluidized-bed combustion, the fuel, which can include almost any coal or
waste fuel, is fluidized at 1450°-1700°F. Air is forced through the bed at 4-
to 12-fps, a velocity sufficient to support the weight of the bed particles.
When the bed is fully fluidized, it acts like boiling liquid. Although the
burning coal typically makes up less than 2% of the fluidized bed, all the bed
particles are heated quickly by the turbulence in the bed.
Figure 1 illustrates a typical fluidized bed combustion boiler. Boiler tubes
submerged in the bed absorb heat directly from the turbulent solids. The heat
converts water in the tubes to steam or superheats the steam. Because of the
intimate contact of the boiler tubes with the fluidized bed, heat transfer is
highly efficient and, consequently, less boiler tubing surface is needed to
generate the same amount of steam as in a comparable conventional boiler. The
hign heat-transfer rates also permit lower combustion temperatures resulting in
the formation of relatively low levels of NO^^, and, since the temperatures are
below coal ash fusion temperatures, a variety of coals can be burned in a single
design.
By mixing limestone with the coal, the majority of sulfur in the coal can be
captured during the combustion process. The operating temperatures of the
fluidized bed are particularly appropriate to the efficiency of the reaction to
form calcium sulfite and sulfate. The furnace space above the bed, called the
54
133
Figure 1.
FLUID BED BOILER
Convection
pass superheater
55
134
form calcium sulfite and sulfate. The furnace space above the bed, called the
"freeboard", provides additional time for any unburned coal that escapes the bed
to burn and' to complete sulfur capture, tonvective heat exchanger tube banks
follow the furnace to further cool the gas and raise steam.
Over the last ten years, AFBC has steadily gained acceptance among small boiler
operators. This acceptance has been due primarily to the boiler's ability to
burn low-grade coals and waste fuels while meeting environmental regulations.
Currently 20 US boiler manufacturers offer first generation industrial AFBC
units on a commercial basis. Approximately 70 such units have been installed
and operated in the US and 30 are designed to burn coal. First generation AFBC
technology is considered commercial for large industrial boiler applications
of 200,000 pounds per hour of steam or more. However, significant
opportunities exist tor improving performance and reliability and for
expanding the technology into both the smaller-scale industrial boiler
markets and the much larger utility boiler applications.
Although these initial AFBC designs meet industry's need for process steam and
space heating, they cannot be directly scaled up to the size required for utility
power generation. Further private sector development of the technology has
therefore been directed to making AFBC suitable for utility application.
Because scale-up is a major issue, these efforts have involved progressively
larger test boilers: a 2 MW development unit, a 20 MW pilot plant, and now
three 110 to 160 MW commercial demonstration units.
Figure 2 indicates the fundamental effect of fluidization velocity on design.
When the gas velocity through the fluidized bed is relatively low, solids are
retained in the fluidized bed, hence, the term "stationary" or "fixed bed".
Because much of the gas passes through a stationary bed in bubble-like
pulses, the term "bubbling bed" is also used. Finally, because the original
fluidized bed reactor designs are stationary or bubbling beds, the term
"classical" is also used. If the velocity is increased to the point where
most of the solids fed are lifted out of the fluidized bed, captured in a
dust collector, and returned to the fluidized bed, it is termed a circulating
bed. Because the relationship between gas velocity and particle size
determines whether beds will bubble or circulate, it is possible to have a
high velocity classical bed, operating at 15 feet per second with 1/8"
particles, and a low velocity circulating bed, operating at 5 feet per second
with 100 micron particles.
Hybrid systems may also be possible in wnich a circulating bed of fine particles
co-exists with a bubbling bed of coarser particles where, due to staging of
combustion air, a bubbling bed exists at the bottom of a furnace that feeds
solids into a circulating bed above.
Bubbling and circulating fluidized bed boilers are at roughly equal stages of
development as far as utility-scale designs are concerned. The operational and
test data and design and cost estimates would not support the argument that
operating costs could be substantially different. Any estimated cost
differential may vanish or even reverse depending on experience in the larger
units now operating or near completion. Fortunately, both types of FBCs have
substantial promise, enthusiastic advocates and a growing list of practical
56
135
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applications that can provide the basis for confident scale-up. Fluidized bed
boilers could also have several possible configurations, depending on such
factors as the choice between natural or assisted circulation, the gas velocity
in the bed, the coal and air distribution systems, and the method of achieving
high combustion efficiency. The diversity of approaches has led to several
complementary AFBC demonstrations. Their common objective is to provide the
industry-wide experience necessary to confidently apply fluidized bed combustion
as a new steam raising option.
Electric utilities specify new boilers that meet their basic efficiency and
reliability requirements and expect hard evidence that these requirements will
be met. Electric utilities will opt for fluidized bed boilers when their
advantages outweigh the reliability risks of using a relative new technology.
Potential advantages of atmospheric fluidized bed combustion are:
0 Emission control without scrubbers
0 Dry solid waste
0 Furnace design independent of ash content or properties
0 No derating due to slagging or fouling
0 Fuel flexibility
0 Capital cost saving on power plant
0 Ability to use low-grade fuels
0 Improved cycling behavior
When the advantages listed above can be confidently achieved while meeting the
basic utility boiler performance and reliability requirements, atmospheric
fluidized bed boilers will compete effectively for new base-load and
intermediate-load power plants. The program established and funded by the
utility industry to implement the commercial demonstration of fluidized bed
combustion indicates that this objective can be achieved this decade.
2. Pressurized Fluidized Bed Combustion (PFBC)
If the furnace is pressurized to a fireside pressure of 90-200 psig, the
fluidized bed boilers system is called "pressurized fluidized bed combustion" or
PFBC. Combustion products from this system can be used to drive a gas turbine.
The hot combustion gases pass through a particulate removal system, then through
the power recovery expander. Next, they move through a heat recovery steam
generator and are finally exhausted to atmosphere. This use of the PFBC boiler
in a combined cycle system to produce both steam and hot pressurized flue
gas to drive a separate turbine-generator is a highly energy efficient use of
coal for power generation. Operation at elevated pressure reduces combustor
size and enhances several performance parameters. While substantial development
progress has occurred in recent years in Europe, PFBC is not yet as technically
mature as AFBC, represents a more revolutionary change in technology, and
Involves more risk today.
To reduce this risk, an alternative PFBC power cycle, called the PFBC
turbocharged boiler, uses convective heat exchangers to extract sufficient
energy to reduce the gas turbine inlet temperature to less than 1000°F. This
lower temperature allows a current technology gas clean-up system to remove
particulates from the combustion gases, minimizes turbine blade corrosion,
58
137
avoids expensive high-temperature gas piping, and eliminates the need for a heat
recuperation system and a final gas cleaning system in the turbine exhaust. The
gas turbine outlet gas exhausts directly to the stack. The turbine under these
gas conditions provides only power sufficient to drive the air compressor. The
projected overall system efficiency is 37%, about 2% less than the combined-
cycle system. However, it is an attractive candidate for PFBC power plants
because of reduced technical risk, expected increase in plant reliability over
the PFBC combined cycle, reduced capital cost, and the inherent ability to be
modularized. PFBC boilers thus can respond effectively to the trend toward
smaller new unit size plus utility priority on uprating the capacity of existing
units to bring generation on line quickly and at the lowest cost.
These advantages can translate into an effective reduction in capital cost by
better matching load growth and reduced construction work in progress (CWIP).
These two factors have been evaluated by the utility industry, and it was found
that the benefits of such modular technologies can produce an equivalent capital
cost savings of about 25%. PFBC provides the opportunity to add these
advantages to the inherent fuel flexibility and environmental control
capabilities of atmospheric fluidized bed combustion.
As a result, development emphasis is being placed on PFBC boilers which can
provide shop-fabricated, barge transportable, steam generation modules. These
may be rapidly field-erected to provide the desired uprating in unit sizes of
150 MW to 250 MW. This approach can also use coal to replace or increase the
capacity of existing oil- or gas-fired plants while meeting stringent siting and
environmental control constraints. It also provides the lowest potential busbar
energy cost of any coal -fired power generation option now under development.
Because of the reduced technical risk associated with the turbocharged boiler
concept, it is likely that PFBC commercialization can be accelerated to 1990.
The speedup could happen because all technical efforts could be focused on the
critical combustor and solids feeding/discharge problems instead of being
diffused among the other technical challenges of gas cleaning, conveying, and
expansion at the higher temperatures of the combined cycle. Future PFBC plants
could evolve into a combined cycle configuration by incrementally raising the
firing temperature of the turbine as experience is gained.
111. OUTLOOK FOR REQUIREMENTS FOR 2020
By the year 2020, even with a forecast of only a 3% average electricity demand
growth rate, utility generating capability can be expected to more than double
to 1,600,000 MW. With the current public perception of nuclear power, it is
likely that this growth must depend primarily on coal for the foreseeable future.
Technology being developed today to satisfy tomorrow's generation needs must,
however, be responsive to the new operating environment of the electric utility
industry. As utilities shifted from being declining cost producers to
increasing cost producers in the early 1970s, regulatory attempts to control
these costs have stepped up. The resulting widespread penalization of excess
capacity has led to a reversal in generation planning to virtually eliminate
capacity additions for many utilities. One approach to reducing the risks of
new capacity is to construct smaller coal-fired plants that take less time to
59
138
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If successful commercial demonstration of both AFBC and PFBC are achieved by
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TABLE 3
POTENTIAL FBC MARKET PENETRATION (10^ MW)
1990 2000 2010 2020
Total Generating Capacity
Total Coal -Generating Capacity
0 AFBC Capacity
0 PFBC Capacity
IV. CURRENT R&D
1. AFBC
The Development of AFBC for industrial application in the US has been the
primary DOE focus. This has resulted in a variety of industrial demonstrations.
These include AFBC boilers at the Great Lakes Naval Station, Georgetown
University, East Stroudsburg State College, and the City of Wilkes-Barre,
Pennsylvania.
Ten years ago the first attempt was made to operate a 30 MW AFBC boiler at a US
electric utility power plant. At the time, this was a factor of 60 scale-up
from the available process development pilots. Operation of this unit clearly
indicated the directions needed for development. In the ensuing ten years,
experience with AFBC for steam generation has advanced with the construction of
many industrial-scale boilers around the world. To meet the additional require-
ments of utility application, R&D led by EPRI and TVA has included several key
areas: investigation of fundamental fluidization phenomena; materials assess-
ment as applied to high pressure and temperature steam generation; process
turndown and load following control; development of an extensive AFBC process
data base; and scale-up of the process toward utility-size applications
involving 2 MW and 20 MW pilot facilities.
The 6 ft-by-6-ft fluidized bed cross section and high freeboard of the 2 MW
process development facility, known as the "6 x 6", was designed to simulate the
large bed area and long residence time that would be typical of utility-scale
units. An extensive parametric testing program begun in 1977 led to design
modifications for improving the process to meet utility efficiency requirements.
An important modification was the addition of a subsystem to recycle the
collected flyash back to the fluidized bed. The successful testing at the 5 x 6
provided the basis for proceeding to a larger utility design test unit.
62
141
In 1979, the TVA and EPRI developed plans for a 20 MW AFBC pilot plant, a
tenfold scaleup over the 2 MW 6 x 6 facility. This engineering pilot unit,
funded and built by TVA at their Shawnee steam plant in Paducah, Kentucky, was
designed to simulate utility power plant operating conditions and mechanical
features. Construction of the pilot plant was completed in May 1982. Over 7000
hours of test operations have since been accumulated on the facility.
These R&D efforts have led to the recent initiation of AFBC demonstration
projects that will integrate commercial AFBC steam generators into utility power
plants.
Three such complementary utility demonstrations are now proceeding under private
sector leadership. These are described in Table 4.
The results of these demonstrations are intended to provide the technical,
performance, and economic basis for commercial, utility application of AFBC
steam generating technology. The major phasjes of the projects will include (a)
development of detailed designs for a specific AFBC application in a utility
power plant, (b) fabrication and erection of the AFBC steam generator and
required balance of plant systems, (c) a three year or more test program,
with the AFBC, planned and implemented by EPRI, to demonstrate performance
and reliability over the range of operating conditions, and (d) operation
on economic dispatch of the remaining life of the plant.
The TVA/Duke Power/EPRI/State of Kentucky demonstration will build a new AFBC
boiler to repower and extend the life of an existing 160 MW steam
turbine/generator at the TVA Shawnee Power Station. This is the primary
demonstration effort to achieve a confident basis for applying AFBC as a utility
generating alternative by the 1990s. Availability of $30 million in DOE funding
has added to the prompt financial closure of this project.
The Northern States Power AFBC Demonstration provides a retrofittable utility
option to meet SO^^ and NO New Source Performance Standards (NSPS) as well as
reduce sensitivity to coal quality at existing, older power plants. Here, an
existing 100 MW pulverized coal boiler will be converted to AFBC while also
increasing its capacity to 12S MW and extending plant life by an expected 25
years. This conversion will also change the plant from base to peaking duty.
This demonstration will be built and operated as a commercial effort. As a
result, the cost will be offset by the resulting increase in generating
capacity, fuel flexibility and plant life, thus making it a more cost-
effective option than flue gas desulfurization. An examination of the
utility boiler population indicates that there are a substantial number of
candidate utility boilers for similar AFBC conversions. They total about
20,000 MW in 200 units built primarily during the period of 1945-1965.
The Colorado-Ute Project provides yet another option. Here, a new 110 MW
circulating AFBC boiler will be built to repower an existing 40 MW steam
turbine/generator as well as drive a new 70 MW steam turbine/generator. This
AFBC boiler offered by US manufacturers, but reflecting a European design base,
will provide a useful direct comparison, in terms of performance and
reliability, to the bubbling bed designs being installed by TVA and Northern
States Power.
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142
TABLE 4
PIONEER UTILITY FLUIDIZED-BED COMBUSTION
DEMONSTRATIONS
TVA/DUKE
NSP
Colorado-Ute
Location
Paducah, KY
Minneapolis, MN
Nucla, CO
Size (e)
160
125
110
FBC Type
Bubbling
Bubbling
Circulating
Scope
Add-on Boiler
Boiler
Conversion
Add-on Boiler
& T/G
Coal
High S
Bituminous
Low S
Subbituminous
Low S, High Ash
Bituminous
Startup
1988
1986
1988
Steam
Conditions
Reheat
No reheat
No Reheat
Feed Systems
Underbed
Overbed
In-Bed
Dust Collector
baghouse
ESP
baghouse
Structural
Design
Top Support
Top Support &
Bottom Support
Top Support
Dispatch
Schedule
Base Load,
Some Cycling
2-Shift,
5-day Cycle
Base Load
Startups
Per Year
20
250
<10
Boiler
Supplier
Combustion
Engineering
Foster-
Wheeler
Pyropower
(Ahl Strom)
The confidence to proceed with these demonstrations is based on resolution of a
variety of performance and reliability uncertainties at the 2 MW and 20 MW pilot
facilities. This and other supporting R&D for utility AFBC application has been
primarily funded by EPRI over the past decade at an average annual commitment of
about $10 million. This effort has:
Developed reliable heat transfer data
Quantified boiler tube corrosion rates for materials selection
Achieved New Source Performance Standards for SO2, NO^^ and particulate
Achieved acceptable solids feed and system control performance
Established commercial boiler design guidelines
characterized specific fuels and sorbents.
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143
The status of specific AFBC technology issues may be summarized as follows:
0 Turndown and Load Following — Single-bed performance results indicate that the
turndown and control goals are achievable when scaling to larger, multiple
bed AFBC configurations. The rate at which load can be safely changed has
reached 5% per minute. Transient response data from the 20 MW pilot will
enable control systems to be designed for fast output changes with multiple
beds.
0 Coal Feeding — Various configurations of overbed and underbed feed systems are
being considered, on the basis of cost and reliability, for application in
the commercial demonstrations. Overbed feeding involves the use of spreader-
stokers that throw the coal over the top of the bed where the furnace
pressure is neutral. The system is relatively simple, containing few
components and these are not subjected to severe duty conditions. The
overbed system may, however, require coal -fines control to achieve high
combustion efficiency with less reactive coals. By comparison underbed feed
system designs are sensitive to erosion and plugging but have demonstrated
generally higher process performance. Their complexity arises from the need
to split the feed stream into several separate streams to distribute coal at
the case of the bed. Design alternatives incorporating improved coal sizing
control, drying and pneumatic sealing seem to have resolved the pressing
reliability issues and will be used in the TVA/Duke Power/EPRI AFBC
demonstration project.
0 Materials — Corrosion and erosion of tubes immersed in the fluidized bed and
erosion of convection pass surface have been concerns. From a corrosion
perspective, tube material selection criteria have been developed for
evaporator, superheater and surfaces. Very few erosion incidents of in-bed
tubes have been reported at the 2 MW and 20 MW pilot units. In all cases,
there were localized phenomena caused by jetting or non-uniform tube
geometries. A data base has been compiled and is resulting in bed design
guidelines. Additional research to extend these data and guidelines is
encouraged,
0 Effect of Scale on Performance — Scale effects due to longer freeboard
residence time and turbulence have positive effects on performance. For low-
sulfur, high reactivity coal, carbon burnout and SO2 capture performance is
less sensitive to these scale effects as well as feed point spacing, recycle
rates and coal/limestone particle size. On the other hand, these design
variables become far more important with the less reactive, eastern
bituminous coals. Substantial effort has been directed to design
requirements at the 20 MW pilot and the resulting guidelines will provide the
basis for the TVA/Duke Power/EPRI demonstration. Testing has concentrated on
investigating the effects of recycle rate while maintaining near constant bed
depth, temperature and velocity. Two approaches to improved combustion
efficiency are being pursued. First, increasing the recycle rate and second,
increasing the collection efficiency of the recycle cyclones. Combustion
efficiency of at least 98% has been achieved with both eastern and western
coals using these guidelines.
0 Sulfur retention— The capture of SOp in a fluidized bed boiler is
primarily dependent on the amount or sorbent limestone in the boiler,
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144
sorbent surface area, and residence time (time in the unit when
reactions can take place. Operating parameters that control these
factors are the limestone-to-sulfur ratio expressed as the Ca/S
molar ratio, as well as recycle rate, bed depth, temperature,
freeboard height and superficial velocity. Since the Ca/S molar ratio has
the greatest impact on sulfur retention, testing has concentrated on investi-
gating the effects of Ca/S and char recycle on sulfur capture while again
maintaining near constant bed depth, temperature, and superficial velocity.
Results to date indicate that 90% sulfur retention can be reached using
underbed feed with a Ca/S ratio of 2 to 2.5 and recycle ratio of 2 to 3,
The overbed coal feed results show the same trend but with a slight reduction
in performance. Methods to further improve sulfur capture are presently
being evaluated. These include enhanced freeboard residence time and
turbulence, both of which are natural consequences of scale. Another process
improvement under current development is the grinding and reinjection of the
waste sulfated limestone. Grinding should free up the available limestone in
the case of the particles and, by reinjection make it available for
sulfation. Preliminary analysis shows that overall calcium utilization in
excess of 50% is achievable.
In recent years, circulating AFB (CAFB) has emerged as a promising candidate for
industrial and utility coal-fired boiler. Circulating AFB is characterized by
high superficial gas velocity and a high solids recirculating rate through the
bed, Lurgi, in West Germany, first introduced circulating AFB commercially in
the early 1970s for the chemical industry. At the same time, the Ahlstrom
Company in Finland started an active R&D program to commercialize circulating
AFB for coal and low-grade fuels. In the US, Battel le-Columbus Laboratory in
Ohio introduced the related Multisolid Fluidized Bed Boiler concept in 1978,
Industrial CFBC coal-fired boilers up to 100 MW are being marketed in the US by
Pyropower-Ahl Strom, Combustion Engineering - Lurgi, and Babcock i Wilcox -
Studsvik, Energitechnik.
CAFB designs offer further potential to simplify solids feeding, improve carbon
utilization, reduce limestone requirements and achieve greater NO reduction.
The need, however, to circulate the total bed inventory at higher velocities
creates a variety of offsetting technical issues that must be resolved.
Development and demonstration programs for circulating AFB should therefore
focus on determining penetration of the secondary air through a gas-solids
mixture with a density over 1 lb/ft •^, the performance and reliability of large,
parallel hot cyclones, and reduction of heat loss from large refractory-lined
components. Circulating AFBC designs may also be improved by applying aspects
of bubbling beds such as the water-cooled air distributor.
2. PFBC
The potential benefits of PFBC for power generation were first investigated^ in
1969 at the British Coal Utilization Research Association (BCURA).
Subsequently, a number of other pilot-scale combustors were operated, originally
with EPA support in the US. In addition to the BCURA facility, the Exxon
"Miniplant" and the Argonne National Laboratory facilities have been especially
important. Both the BCURA and "miniplant" incorporated cascades of turbine
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145
blades and have indicated the potential for future gas turbine operation. Two
larger PFBC facilities in the US were operated during the 1970s in conjunction
with gas turbines. The first was an adiabatic PFBC combustor by Combustion
Power Inc., and the second was a small air heater PFBC unit by Curtis-Wright.
Although the fundamental effects of pressure on fluidization and combustion are
not fully understood, certain enhanced characteristics relative to AFBC have
become apparent, based on test facility experience.
0 Combustion Efficiency— The superficial gas residence time or the excess air
is so great that combustion efficiency, in practice, will always be greater
than 99%. Factors which also assist in attaining these high efficiencies are
the better gas-solids contacting brought about by pressure.
0 Heat Transfer— Because fluidizing velocities (and therefore bed particle
sizes) are typically lower in PFBC than atmospheric units, the heat transfer
coefficients are correspondingly higher.
0 Sulfur Retention— Good sulfur retention efficiency depends on the development
of porosity in the sorbent particle. At high pressure the effectiveness of
limestone is reduced because calcination, on which porosity depends, is
curtailed. On the other hand, dolomites become much more effective since
they undergo two stages of calcination. The "half-calcination", reaction
CaCOj + MgC03 = (CaCOj + MgO) + CO2 proceeds rapidly, creating porosity while
curtailing decrepitation.
0 NO Emission--Experimental data have shown that increasing pressure reduces
the NOj^ emission approximately in proportion to the square root of pressure.
There were a remarkably large number of approaches to the development of PFBC.
Table 5 lists the major technical issues and different potential solutions.
Although the turbocharged PFBC boiler has less technical uncertainty than its
combined-cycle counterpart, considerable development is still required before
the commercial potential of this option can be realized. As indicated in
Table 6, this effort centers on the PFBC boiler and involves the design base for
the tube bundles in the bed as well as feeding, ash handling, hot gas cleanup
and control of the PFBC boiler system. Table 7 further describes these develop-
ment issues together with available facilities for their resolution.
PFBC development efforts are planned by two US boiler manufacturers. Babcock
and Wilcox (B&W) and Foster Wheeler are proposing to design and supply in-bed
heat transfer tube bundles for performance and reliability testing at the
Grimethorpe PFBC Test Facility, if access can be obtained. An alternative
approach with Combustion Engineering relies on a circulating PFBC boiler to
eliminate the need for in-bed heat transfer tubes. Unfortunately, at the
present time, no proof-of-concept PFBC facility for such a circulating bed
design exists. These efforts are a key stepping stone to implementing planned
PFBC demonstration projects with the utility industry.
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146
ISSUES
TABLE 5
TECHNICAL ISSUES FOR PRESSURIZED FLUIDIZED BED COMBUSTORS
ALTERNATE APPROACHES
I. Feeding Coal Across
Pressure Barrier
2. Combustor Design
1. A. Slurry Pump
B. Lock Hoppers
C. Dry Solids Pump
2. A. Circulating Bed/Separate
Fluidized-Bed Heat Exchanger
B. Bubbling Bed Combustor with In-Bed Tubes
C. Vertical Air Tubes
3. Hot -Gas Cleanup
4. Cold-Gas Cleanup
5. Sulfur Sorbent
6. Load Following
7. Pressure Ratio (which affects
steam/gas turbine work split)
8. First Cyclone Location
9. Gas Turbine Development
10. Turbine Erosion Protection
11. Turbine Corrosion Protection
A. Cyclones in Series
B. Electrostatic Precipitators
C. Ceramic Fabric Filter
D. Granular/Electrostatic Filter
E. Rigid Ceramic Filter
4. A. Do it all hot and at pressure
Protect gas turbine. Add cold ESP
or baghouse
B.
5. A. Oxidizing-Bed
1. Dolomite
2. Calcined Limestone
B. Reducing Bed Limestone
6. A. Bed-Slumping
B. Bed Removal to Satellite Vessel
C. Solids Circulation Rate Reduction
to Satallite Heat Exchanger
7. A. As low as 6:1
B. As high as 30:1
8. A. Within Combustor Vessel (large, but
few, vessels)
B. Separate vessel (s) (Smaller, but
more, vessels)
9. A. None; operate existing machine off-design
B. Modify blade path, harden blades
C. Optimize for maximum efficiency
10. A. Use "dirty gas" machine, i.e.,
cat cracker machine
B. Clean gas to < 10 ppm or +5 u
particles - clad or coat blades
11. A. Clad blades
B. Feed alkali "getter"
C. Run turbocharged boiler condition
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147
TABLE 6
TURBOCHARGED BOILER/COMBINED CYCLE PFBC COMPARISON
Status for:
Issue
Removal of 99% of particulate
at high temperature
at high pressure
Protection of gas turbines
from remaining particles:
from alkali vapors
Tube materials and design to
avoid corrosion/erosion
Controls for matching high inertia
PFBC and low inertia gas turbine
Gas turbine overspeed protection
Cool ash for depressurization
Need to use dolomite
Scale-up to utility size
Combined
Cycle
Turbocharged
Boiler
>1500°F
Yes
>1000°F
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
No
Yes
No
Yes
No
Yes
Yes
Yes
Yes
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148
Unfortunately, all of the development facilities indicated in Table 7 are
located in Europe, which makes communication and access difficult at best. As a
result. PFBC development in the US has been largely paced by access to results
from the 23 MW lEA Grimethorpe facility originally built and operated jointly by
the UK, US, and West Germany. This lEA sponsorship formally concluded in 1984
with any continued operation to be principally funded by the National Coal Board
(NCB) and Central Electricity Generating Board (CE6B) of the US. Continued DOE
participation is encouraged but remains uncertain.
This continued Grimethorpe experimental program, to be funded by the UK at a
cost of $30 million, is organized as follows:
1. Test Series A-1 (0-15 months)
0 Operation at 0.8 m/sec fluidizing velocity with new tube bank
0 Evaluation of tube bank over 1000 hours
0 Study combustion efficiency, heat transfer, SO3 and NO production, and dust
emission/elutriation/particle attrition as functions of operational parameters
0 Component evaluation and development
0 Dynamic and combustion response
0 Operation at a higher fluidizing velocity
2. Test Series A-2 (26-32 months - after facility modification)
0 New tube bank if required by A-1 results
0 Part load strategy
0 Effect of feed nozzles
0 Effects of high chlorine coal
0 Improved hot gas cleanup
3. Other activities, still depending on co-funding, includes:
0 Hot and cold modeling of tube bank designs (including US)
0 Fines recycling and feed system design studies
0 Staged combustion trials at CRE Stoke Orchard
0 Extended materials studies.
0 Ash removal
0 Test Series B, including installation of a gas turbine for combined cycle
development
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149
DOE has also constructed a unique and complementary 13 MW PFBC pilot facility
with Curtiss-Wright in New Jersey. The unique capability of this facility is
that it provides a complete PFBC system, that is, a combined combustor and gas
turbine and one directly available to US developers. Although the combustor
is used to heat air rather than steam, the system nevertheless can effectively
address several issues limiting confident PFBC system scale-up as follows:
0 Combustor operation and performance
0 Solids feeding and discharge
0 Hot gas cleanup technology capable of operating reliably beyond the
efficiency of inertial separators
0 Integrated PFBC boiler/gas turbine operation and control
0 System availability and operability under utility conditions
Unfortunately, DOE has decided to dismantle this $65 million facility before it
had a chance to operate. This decision was apparently based on the operating
cost and uncertain modification needs of the facility to achieve reliable
operation.
American Electric Power (AEP), working with STAL Laval and Deutsche Babcock, has
also made progress toward the development of a compact, combined-cycle PFBC
system. A 15 MWt component test facility is now operational in Malmo, Sweden,
as indicated in Table 7.
At the Aachen Technical University (West Germany), a commercial bubbling bed
PFBC is scheduled to start-up in May 1985 in order to generate electricity and
steam heating for the University. This 40 MWe plant is a true turbocharged
boiler operating at variable pressure from about 1 to 3.8 atmospheres. In
addition to providing power for the University, considerable experimental work
will also be performed. The equipment is manufactured and installed by
Steinmuller.
In support of these PFBC development efforts, EPRI has emphasized R&D on
materials and hot gas cleanup. Tests of boiler tubing have shown relatively low
corrosion rates for most boiler alloys. Superheater and reheater tubes will
likely be all austerjitic stainless steel in order to avoid dissimilar metal
welds in the furnace. Erosion has been identified as a serious problem in the
pilot unit at Grimethorpe in England. An effort to protect the tubes via
addition of studs and fins has not been very successful. However, an intense
parallel effort to understand the cause and eliminate the problem is underway in
cooperation with Grimethorpe at the US boiler manufacturers.
EPRI has also funded tests at two PFBC gas turbine simulators to provide the
data needed to select turbine blade materials. These tests have confirmed
expectations that damage to most alloys is severe at high dust loadings. Some
good candidate claddings have been identified, however. The main finding has
been the importance of hot-gas cleanup in removing the damaging particulate and
the importance of maintaining reduced turbine inlet temperature.
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150
Both woven ceramic fabric bags and a rigid silicon-carbide "candle" have shown
excellent filtration and appear to be rugged enough to survive the PFBC environ-
ment. A test of both is currently planned to determine long-term reliability.
Finally, tests sponsored by the US DOE have shown that an electrostatic precipi-
tator (ESP) would be expected to perform efficiently at the gas conditions of
the turbocharged boiler. Brown Boveri and Research Cottrell are also evaluating
the practical aspects of the ESP for turbocharged boiler application.
In 1982, an EPRI study by Brown Boveri identified the PFBC turbocharged boiler
as an attractive alternative to the combined cycle system more commonly asso-
ciated with PFBC systems. Efforts have been initiated by EPRI, individual
utilities, and boiler and turbine manufacturers to design engineering prototypes
of the turbocharged boiler based on these results. These studies have consi-
dered both bubbling and circulating PFBC designs. The latter eliminates in-bed
heat transfer surface, thus avoiding the troublesome erosion-corrosion problems
experienced to date in bubbling bed designs and also facilitating part-load
control .
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151
TABLE 7
KEY ACTIVITIES OF LARGE PFBC FACILITIES
ISSUE
1. Combustion Grimethorpe - NCB/CEGB
Malmo - STAL Laval
Aachen - Technical Hochschule
0 Process Perfonnance
- Comb. Efficiency
- SOx
- NO,
2. Solid Handling Grimethorpe
Malmo
0 Preparation
0 Pressurization/Depressurization
0 Feeding/Distribution
0 Cooling
3. Gas Filtration Grimethorpe
Aachen
0 Filter Media
- Collection Efficiency
- Life
- Pressure Drop
- Cleanability
4. Gas Turbine Grimethorpe (static)
Malmo (rotating)
0 Erosion
0 Corrosion
0 Fouling
0 Turndown
- Variable Speed
- Variable Flow
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152
These PFBC design studies have confirmed the potential for a significant
reduction in capital costs over pulverized coal systems with flue gas
desuUurization. One GE/BiS study was made site specific to Florida Power and
Lights' (FP&L) Palatka-2 Plant, a retired 80 MW^ plant located in North Central
Florida. GE, B4W and FP&L have continued to investigate this concept, including
sorbent testing and cold flow "in-bed" tube erosion tests in the CURL PFB test
facility in England and a hot gas cleanup system at GE's PFBC facility in Malta,
New York. The ultimate goal of this work is the demonstration of a full-scale
(100 MWg) module on a utility system.
V. COMMENTS ON R&D PROGRAM
1. AFBC
In the past 20 years, the Federal Government through DOE, EPA, TVA, and
predecessor agencies has funded approximately $500 million in research,
development and demonstration efforts on fluidized bed technology and has co-
sponsored seven international conferences. In 1978, Federal fluidized bed
boiler development responsibility for industrial and pressurized utility
application was assumed by DOE's predecessor, ERDA, while development
responsibility for atmospheric utility application was assumed by TVA.
Based on the ERDA/DOE effort, first generation AFBC technology is considered
commercial for large industrial boiler applications. Thus, DOE's role has been
redirected away from AFBC demonstration and commercialization activities
towards long-term, high-risk technology research which industry is not expected
to fund. DOE is currently pursuing advanced concepts of second generation AFBC
technology to improve economics and performance for small boiler application.
Second generation AFB technology is still in the applied research stage of
development. Conceptual studies for seven advanced AFB units were completed in
March 1983. These seven concepts are:
0 Battelle a. High velocity combustor and
b. Spouted combustor
0 A.D. Little Pulsed bed
0 Energy & Environmental Eng. Inc. Staged cascade FBC
0 Westinghouse Draft tube combustor
0 Aerojet Energy Conversion Col Moving distributor
0 M.W. Kellogg Internal circulating bed boiler
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153
The DOE plans to move the two most promising techniques into proof-of-concept
testing. This stage of development would be approximately 50-1500 pounds steam
per hour, with tests conducted over a 1.5 year duration. A subsequent pilot
plant unit of approximately 10,000 pounds of steam per hour would probably be
necessary before second generation AFB technology could be introduced
commercially. However, no large demonstration plant is considered necessary by
DOE if all technical milestones are achieved.
An additional program area is concerned with support projects and studies
including: risk, market and environmental studies; instrumentation and equip-
ment studies; agglomeration and low rank coal studies; erosion and bed dynamics;
modeling; data analysis and dissemination.
During 1985, the DOE AFBC R&D effort will specifically include:
0 Support for the TVA AFBC demonstration
0 Bench scale testing of two advanced AFBC concepts
0 AFBC fluidization research and heat transfer studies
0 AFBC model validation
0 Investigation of AFBC pollutant formation, transport and fate
0 Upgrade central AFBC data base.
Under the decenteralized DOE management approach, the Morgantown Energy
Technology Center (METC) is the designated lead center for the AFBC Technology
Program. The FY 1985 DOE request for AFBC totals only $17.5 million, of which
$15 million is for the TVA 160 MW AFBC demonstration.
While the objectives of the DOE AFBC program are comprehensive, the level of
funding is entirely inadequate to meet these objectives. Based on the large
private sector effort which is stimulating a variety of AFBC process designs,
the DOE effort would better focus on the generic issues constraining AFBC rather
than proprietary "second generation" designs. These R&D needs reflect the
operational problems encountered in AFBC and relate to:
0 solids handling
0 feed system design
0 recycle design
0 heat and mass transfer phenomena
0 freeboard design and performance
0 dynamic reaction kinetics and load control
0 combustion and pollution control characterization for the range of fuels
0 optimization of pollution control.
This latter category should include:
- Extensive chemical and physical characterization of solid wastes from all FBC
process streams
- Utilization of FBI waste products, e.g. to fixate fly ash or as scrubber
reagent.
- Development of solid waste management equipment meeting the unique
characteristics of FBC waste.
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154
- Separation of excess reagent from FBC ash.
In addition, US experience in circulating AFB development is very limited.
Specific areas of uncertainty requiring additional development attention are the
high combustion gas velocity, the high solids recirculation rates, and the lack
of internal heat transfer surface in the combustor. The lack of internal heat
transfer surface may pose the biggest problem for scale-up, especially for
utility size boilers. Since the percentage of heat removed from the
combustion zone diminishes as the combustor size increases, this may
constrain circulating AFBs to some maximum practical size, unless some
means can be found for introducing internal cooling surfaces without the
risk of erosion.
Such an expanded DOE support effort for both industrial and utility AFBC
applications is estimated to require about $20 million per-year for at least
five years and would involve modifications and instrumentation of a variety of
existing research, pilot and commercial AFBC facilities. Equivalent private
sector cost sharing for such a DOE initiative is considered realistically
available and appropriate to ensure rapid technology transfer to commercial
application. In addition, support for the demonstration of circulating AFBC in
both industrial and utility application is encouraged.
2. PFBC
Because PFBC is at an earlier, higher risk state of development, its R&D demands
are necessarily greater today. Unfortunately, DOE's efforts in the area have
eroded drastically to a probable total of $3.b million in 1985. This is about
one-fourth the 1983 PFBC appropriation. Although the stated goal of DOE
sponsored activities is to "develop a US technology base for PFBC scientific and
engineering technology through proof-of-concept and to support private sector
efforts to commercialize the technology," the available resources are not
consistent with this goal.
Historically, DOE PFBC development and testing has focused on the
lEA/Grimethorpe facility and the supporting Coal Utilization Research Laboratory
(previously BCURA). Fundamental research on combustion characterizations has
been performed at New York University and General Electric. PFBC technology
activities are continuing at a low-level with in-house efforts to investigate
fluidization regimes under pressure and concepts on the PFBC loop bed combustor
at Morgantown. Table 8 summarizes the major DOE PFBC projects and facilities.
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155
TABLE 8
MAJOR DOE PFBC PROJECTS
0 CURL Research Facility 5 ATM Component Pro-
(now CRE Stoke Orchard) 2'x4'; 20 ATM blem Identifi-
I'xl' Test Rigs cation
Coal Water and Large Size Coal
Contustion Testing. Elevated
Pressure Combustion Testing in
Progress, Erosion Mechanism
March 1984.
0 lEA Grimethorpe
Facility
12 ATM
25 MWg Boiler
Major Facility Test Series I Complete Dec. 1981
For Component Test Series II Complete May 1984
Test Final Reports December 1984.
0 Small Gas Turbine
Test Rig
(Curtis-Wright)
7 ATM
3' Dia Test
Rig
Cleanup/Turbine
Test. Data Ver-
tical Tube Air
Test Began in FY 1978. Com-
pleted 100 hr Turbine Test -
Dec. 1979. Hot Gas Cleanup
Subsystem Testing Complete.
Unit Being Dismantled and
Relocated to METC.
0
Combined Cycle
Pilot Plant
(Curtis-Wright)
7 ATM
13MWg
Major Integrated
System Test
Facility
0
NYU Test Unit
10 ATM
30' Dia
Combustion
Characterization,
Bed Geometry
0
GE-LTMT
10 ATM
1' Dia
Rig
Test
Gas Turbine
Materials Test
Facility
Construction Completed. Plant
Being Dismantled Without Any
Operating Experience.
Lignite and Low Grade Fuel
Combustion Testing Bed Geo-
metry Testing in Progress.
Long-Term Gas Turbine Materials
Corrosion/Erosion Test Programs.
Work stopped and rig demolished.
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156
Several critical issues remain which pface the demonstration of commercial PFBC
power plants and which should be the focus of a comprehensive DOE effort. These
Issues are:
1. Plant cycle decisions: a rational basis for bed temperature, cooling method
and working-fluid cycle.
2. Boiler: erosion/corrosion of in-bed and in-gas stream components.
3. Boiler: shell configuration and bubbling versus circulating design.
4. Coal Feeding: development of coal pumps or coal/water slurry feed system to
replace lock hoppers.
6. Ash cooling for safe decompression,
6. Plant control: startup, load following, and gas turbine overspeed control.
7. Scale-up of plant components.
8. Hot gas cleanup performance and gas-turbine tolerance to
corrodents/erodents/foul ing.
9. Reduce dependence on dolomitic limestone for SOp capture.
10. Performance characterization for the range of fuels and sorbents.
All of these issues can be resolved over the next five years but require
accelerated DOE support for operation of available integrated pilot plants and
process development units. Since the principal application of PFBC systems is
electric utilities, proof-of-concept should be based on facilities in the 10 to
2b MWg size range (equivalent to 100,000 to 250,000 lb per hr of steam). The
only existing facilities meeting this criterion are the Grimethorpe facility and
the Wood-Ridge (Curtis-Wright) pilot plant.
Continued US participation in the operation of Grimethorpe has been encouraged
by the UK and should be implemented jointly by DOE and EPRI. The total cost of
US participation in the next phase (1985-1987) of testing is about $18 mil 1 ion.
This participation should emphasize qualification of improved hot gas cleanup
technology and testing of heat transfer tube bundles for performance and
reliability. Both Babcock & Wilcox and Foster Wheeler are prepared to
provide tube bundle designs for this effort.
DOE should also support operation of the large Wood-Ridge PFBC pilot facility it
built in New Jersey. In order to ensure operation of this critical facility.
Public Service Electric and Gas of New Jersey and Burns and Roe Incorporated
have proposed a cost-shared project to DOE for a 21 month test program. The
modification and operation of this $6b million facility is estimated at $20
to $30 million over the next three years with DOE funding of $12 million required.
A major facility gap is the lack of a 10 to 20 MW proof-of-concept capability to
qualify a circulating fluid bed boiler design for PFBC application. Such a
capability could be implemented, for example, in conjunction with the existing
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157
Jood-Ridge facility to maximize common use of supporting facilities and
instrumentation. The estimated capital cost of such a proof-of-concept
;ombustion capability would be about $30 million. The advantage of the
■Irculating PFBC would be to eliminate the potential for in-bed tube erosion and
ilso to simplify coal feeding requirements.
Supporting PFBC research should also be expanded to combustor mechanics, hot gas
:1eanup, pollution control, and materials testing, plus application of non-
Intrusive diagnostic techniques to define critical performance parameters under
the severe operating environment of PFBC. This should be co-funded at least
tlO million per year over the next five years by DOE.
rhe ultimate goal of this R4D effort is the demonstration of a full scale PFBC
nodule on a utility system. Such a demonstration, estimated to cost about
H20 million, if the recommended supporting research and testing are
implemented, is technically feasible this decade. The pacing item is the
jvailability of Federal co-funding to match the already planned private sector
initiative.
EPRl has been the primary US supporter of PFBC R&D outside of DOE. EPRI's
primary objective has been to reduce the technical risks associated with
PFBC through the turbocharged boiler approach so that its commercial
advantages can be realized more rapidly. As indicated earlier, the
turbocharged boiler advantages stem primarily from reduced gas turbine
firing temperature. In addition, it lends itself to construction of shop
assembled, barge transportable power generation modules which can be rapidly
field erected.
EPRI's R&D efforts, in addition to turbocharged system design, control, and
economics, have focused to date on development of a reliable gas filtration
system and testing and qualification of combustor and turbine blade
materials. Filter media have been qualified and testing of a large-scale,
multi-element gas filtration module is planned. This latter effort is
controlled, however, by the availability of Grimethorpe and/or similar
facilities. EPRI funding for PFBC R&D, also paced by the limited DOE
commitment, is only about $2 million per year. Accelerated participation
in combustor development and testing is also planned, but is dependent on
the availability of proof-of-concept facilities.
As indicated earlier, the government and industry of foreign countries are
playing a significant part in the development of PFBC. Several proof-of-concept
PFBC facilities are operating in Europe with ASEA-PFBC, Deutsche Babcock and
Brown-Boveri providing primary technical and commercial leadership. As a
result, commercial PFBC plants are now planned in Sweden, Germany and with
American Electric Power (AEP). FP&L, PSE&G and Wisconsin Electric in the US, if
Federal co-funding becomes available.
VI. CONCLUDING REMARKS
FBC offers a particularly attractive option for strategically resolving the
various environmental issues which constrain the nation's growing dependence on
79
50-513 O— 85 6
158
coal while also improving the productivity and cost associated with its use.
The nation is rapidly learning how to produce power from coal through FBC in a
variety of forms meeting the demands of our diverse national energy system.
The question is whether we can advance this knowledge to practice In a period
when both regulatory uncertainty and financial disincentives constrain the
effort. The problem affects all phases of the development cycle but is greatest
in the financially intensive large pilot and demonstration steps necessary for
commercial confidence. A renewed Federal initiative, if jointly implemented
with industry, will substantially enhance the nation's ability to commercialize
the many developments in FBC technology.
The rate of commercialization and use of improved coal technology also depends
on the development of regulatory and economic incentives which encourage
introduction of innovative technology. Too often dependence on the adversarial
approach to issue resolution makes the conflicts restricting coal use more
severe and disruptive than necessary and restricts the introduction of
technological improvement. This is particularly true in the environmental
arena.
The coming decade will represent a major challenge to the utility industry in
terms of staying abreast with even modest growth in electricity demand. For
example, the 720,000 MW of peak generating capacity currently installed or under
construction, is only sufficient to support about a 1.5% per year average growth
rate in electricity demand between now and the end of the century. Each percent
increase in demand growth rate would require about 100,000 MW of additional
generating capability over the remainder of the century. This requirement is
likely to be increased by other uncertainties including additional environmental
legislation, further nuclear deferments, oil supply interruption and the, as
yet, unproven ability to concurrently increase both the availability and life of
existing capacity. A successful industry strategy to meet this challenge will
require a balanced improvement in productivity from existing capacity,
conservation and end use management, and additional generation capability.
On the supply side, fossil generating technology has not advanced appreciably
over the past 30 years. Over this period emphasis has been instead on taking
advantage of the economy of scale with average unit size increasing by about a
factor of five. Although this was practical during the period of rapid
electricity demand growth, these conditions are unlikely to apply again for
most utilities in the foreseeable future. An effect of this essential
freezing of fossil generating technology has been that the national average
thermal efficiency of generation has steadily declined since it reached a
maximum in the early 1960s. Also, even after adjusting for inflation, one MW
of new fossil generating capacity today is about three times as expensive as
in 1970. As a result, the economy of scale advantages gained earlier have
been canceled out since 1970.
Based on these changing realities, the utility industry stands at a threshold of
fundamental change in its technological base for power generation. The present
commercial technology is nearly at the end of its development potential and is
increasingly hard pressed to respond to the rapidly changing requirements being
placed on the industry. New options such as FBC which can meet increasingly
stringent siting and environmental demands and can be rapidly constructed in
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159
modular fashion over a range of unit sizes are particularly in demand. The
next 10 years will therefore be of paramount importance, both in assuring
future electricity supply and in controlling cost. Coping with this
transition will require an intensive commitment over this period on the part
of DOE, the utility industry, and its suppliers.
Historically the DOE program in fluidized bed combustion has been one of the
most effective of the Federal energy RiD efforts. This is particularly true in
the case of AFBC where the concerted Federal/private partnership has moved this
technology from a technical curiosity to broad industrial application and to the
threshold of large scale utility use. This integrated program has carefully and
methodically moved AFBC technology through the development cycle from process
development through engineering development to commercial demonstration and as
such is a model for future joint technology development efforts.
AFBC has become an important boiler alternative because it is an evolutionary
improvement in coal utilization, better meeting the requirements of the 1990s.
The capabilities which excite this interest include: (a) less sensitivity to
fuel quality, thus permitting users to operate more in a "buyers" fuel market;
(b) ability to control SO2 and NO^ within the combustion process; and (c) less
cost sensitivity to unit size.
Although AFBC is proceeding favorably into commercial application, considerable
opportunity for continued DOE support exists. Rather than concentrating on the
investigation of advanced, proprietary AFBC concepts, this support should be
redirected to resolution of the generic materials, fuel characterization and
environmental control considerations which pace its application. In addition,
special emphasis should be placed on the demonstration of circulating AFBC.
This DOE participation is particularly important since AFBC is largely a user-
driven technology. The large boiler manufacturers have historically viewed
AFBC as an alternative to their conventional coal-fired boilers. As such, they
have not considered AFBC as a means to increase their market share. R&D
support has therefore been heavily dependent on the user, DOE, and specialty
firms who view AFBC as an entrance to specific, but small portions of the
boiler market. Only recently have the large, traditional US boiler suppliers
taken on active roles in developing the technology. While this may have
eliminated shortcutting the development cycle, which often results from
premature commercialization, it nevertheless has constrained the R&D resources
available.
PFBC represents a much more critical R&D situation. This technology offers the
advantages of AFBC plus added potential for modular construction and higher
efficiency. It can be used to replace retiring coal-fired steam units, in new
plants, or for repowering existing oil- and gas-fired units. As a result of
approximately a decade of federally funded research, PFBC technology has now
reached the proof-of-concept stage of development where its advantages can be
confirmed. Unfortunately, as this critical threshold is reached, DOE support
has been essentially terminated, thus stalling PFBC's potential for commercial
application in the US.
Past PFBC R&D concentrated on high efficiency, large base-load combined-cycle
power plants. The technical barriers to this technology (primarily hot-gas
cleaning, hot-gas ducting and gas turbine erosion, fouling, and corrosion) are
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160
being reduced, but confidence in commercially applying such PFBC plants still
requires a major effort. By emphasizing the development of the PFBC
turbocharged boiler, the technology can be commercialized on an accelerated
schedule with reduced risk and can also be economically applied to utility plant
uprating or repowering by the early 1990s. Uprating of existing power plants to
raise total plant output by adding supplemental PFBC turbocharged boiler
promises to be the lowest cost incremental capacity available in this period.
By developing PFBC in this low-risk configuration and proving its feasibility in
financially attractive repowering applications, sufficient confidence can be
gained to increase the firing temperature in future plants to combined-cycle
conditions. This evolutionary path can eventually lead to the 40%+ efficient,
direct coal-fired, combined-cycle power plant.
A major joint DDE/private initiative should therefore be mounted which consists
of four primary elements: (a) supporting research on fluidization, materials
and sorbent performance; (b) proof-of -concept testing at the Grimethorpe and
Curtis-Wright facilities; (c) proof-of-concept development for circulating
PFBC; and (d) demonstration of a 100 MW PFBC repowering module.
RECOMMENDATION
There is no shortage of opportunities to improve efficiency, reliability and
environmental performance of coal combustion. The successful achievement of
this objective, however, requires a more constructive partnership between
government and the private sector. This new partnership should begin with
research, development and especially demonstration of promising technology
options. It should also be characterized by a concerted national effort to
better understand environmental risks and the most effective strategies for
their control, and should include incentives for the development and use of
improved technology for clean coal use rather than short range, parasitic
controls which have an unnecessary impact on productivity and cost.
The following specific budgeting recommendations are made concerning DOE
support for FBC.
The composite FY 1985 DOE budget request for FBC R&D is $22.5 million. It is
recommended that additional funding be available for FBC technology development
as discussed previously and summarized in Table 9. This will increase the DOE
FBC budget to $62 million in 1985 and $308 million over the next five years.
Priority should be placed on PFBC because of its relatively higher risk and the
cost effective opportunity it provides, through prefabricated transportable
modules, to satisfy the probable capacity gap facing the utility industry by
1995. At the same time, AFBC should be supported at a nominal level,
particularly circulating designs, to provide a confident technical base. In
the event additional resources are not made available, it is strongly
recommended that all FBC funds be focused on operation of the existing PFBC
proof-of-concept facilities, particularly Grimethorpe, as the key step in
establishing the confidence necessary in scale-up to demonstration.
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161
TABLE 9
ESTIMATE OF DOE FUNDING REQUIRE^ENTS
(DOLLARS IN MILLIONS)
A. AFBC
1986
1987
1988
1989
1990
lUIAL
DOE
ADD'L
PRIVATE
CO-FUNDING
(% of Total)
GRAND
TOTAL
1. Resolve Hardware
Issues
5
5
2
2
0
14
50%
28
0 Solids Handling
0 Feed System
0 Recycle
0 Freeboard
2. Optimization of
Pollution Control
2
2
2
2
0
8
50%
16
3. Fuels and Sorbent 2 2 2
Characterization
4. TVA Demonstration 15
Support
5. Circulating AFB 15 10
Demonstration
Support
6. Fluidization 5 5 2
Research, Model
Validation, Data
Base Analysis
TOTAL 29 29 18
13
15
30
14
89
50%
87%
75%
25
72
16
115
120
19
314
83
162
B. PFBC
1. Grimethorpe
Support
0 Contustor Design
& Control
0 Solids Feeding
& Discharge
2. Wood-Ridge
Operation
0 Integrated Com-
bustor/Turbine
0 Hot Gas Cleanup
0 Solids Feeding
& Developing
0 Turbine Reliability
3. Circulating PFBC
0 Proof -of -concept
Facility
4. PFBC Repowering
Demonstration Support
6. Supporting PFBC R&D
TABLE 9
(Continued)
ESTIMATE OF DOE FUNDING REQUIREMENTS
(DOLLARS IN MILLIONS)
TOTAL
1986 1987 1988 1989 1990 DOE_
10
10
10
0 Contustion Mechanisms
0 Hot Gas Cleanup
0 Sorbent Performance
0 Erosion & Corrosion
0 Fuels & Sorbent Charact.
0 Solids Feeding & Discharge
6. Plant Cycle Analysis £
and Design
10
10
10
25
25
TOTAL
40
42
39
36
14
10
21
29
65
35
11
171
ADD'L
PRIVATE
CO-FUNDING
(% of Total]
35%
25$
50%
50%
50%
50%
50
32
39
84
163
INFORMATION SOURCES
1. Chigier, N.A., Progress in Energy and Combustion - Science "Coal Combustion
and Applications," Vol. 10 Number 2, pp. 106-115, Pergamon Press, New York,
NY (1984).
2. Ehrlich, S., Keynote Address to the 3rd International Conference on Fluidized
Bed Combustion, The Institute of Energy, London, England (1984).
3. Howard, J.R., Fluidized Bed - Combustion and Applications, Applied Science
Publishers Ltd., London, England (1983).
4. Howe, W., et, al.. Progress on AFBC Development for Electric Utility
Application, 11th Energy Technology Conference, Washington, DC (1984).
5. Krishman, R.P., et. al.. Oak Ridge National Laboratory, A Review of
Fluidized Bed Combustion Technology in the United States, 16th International
Center for Heat & Mass Transfer Symposium on Heat & Mass Transfer in Fixed
and Fluidized Beds, Dubrovnik, Yugoslavia (September 1984).
6. Miller, S.A., et. al , Pressurized Fluidized-Bed Combustion Technology -
Technical Evaluations, Argonne National Laboratory, ANL/FE-82-3, Argonne, IL
(1981).
7. Atmospheric Fluidized Bed Summary Program Plan, US Department of Energy
Office of Fossil Energy, Washington, DC (1984).
8. FY 1985 Congressional Budget Request, Fossil Energy Research and Development
- Coal, Vol. 6, US Department of Energy, Washington, DC (1984).
9. Proceedings of the 3rd International Fluidized Conference, "Fluidized
Combustion — Is it Achieving its Promise?," The Institute of Energy, London,
England (1984).
10. Proceedings of the 7th International Conference on Fluidized Bed Combustion,
DOE/METC/83-48, Philadelphia, PA (1982)
11. Proceedings of the Pressurized Fluidized Bed Combustion Workshop, US
Department of Energy/Electric Power Research Institute, New Orleans, LA
(1982).
12. Technical Assessment Guide. Electric Power Research Institute, EPRI P-2410-
SR, Palo Alto, CA (1982).
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164
D. AIRBLOWN GASIFIERS
by: William McCormick
I. INTRODUCTION
Gasification of coal as a means to achieve an ultimately clean combustion of
this fuel represents one of the oldest chemical processing concepts; it was
widely used during the 19th century industrial revolution. Gasification
with air results in a BTU value of the gas in the 140-180 BTU/cb. ft.
range, usually referred to as Lo-BTU gas. With the arrival of tonnage
oxygen,- emphasis has been almost exclusively on new gasifiers using this
oxidant, particularly at elevated pressure, and these are now the essential
centepiece of virtually every system used to convert coal to synthetic
gases or liquids. Synthetics have become a major R&D goal in their own
right and are specifically excluded from the present study.
This is not to say that gasification with oxygen under pressure cannot be
considered for "clean use of coal". In fact, this configuration was and is
being demonstrated in several power plants (Lunen, Cool water, Plaquemines),
broadly speaking, as a source of clean gas for use as fuel or for synthesis,
etc.
II. DEFINITION
This study concerns itself with the use of airblown gasifiers as a means to
"burn coal in two stages", including removal of the key polluting emissions from
the raw gas. Accordingly, the R&D problems associated with this system can be
conveniently considered as they relate to the four steps comprising the system:
1) Gasification
2) Gas clean up
3) Use of Lo-BTU gas.
4) Solid and aqueous wastes
1. Gasification With Air
In principle, all the gas/solid reactors used in gasification can be operated
with air, fixed bed, fluid bed, entrained solids, etc. However, in practice
entrained solid reactors have been used only with oxygen. Historically, most
airblown reactors have been of the fixed bed type, but fluid beds can also be
run with air. Use of high air preheat may open the door to airblown entrained
solid gasifiers and recent advances with high temperature gas-to-gas heat
exchangers may be able to help, but no R&D program to this end is under
consideration.
As to air gasification in fixed or fluid beds, it is not necessary here to
recite the several commercial purveyors of such equipment. Generally the well-
known advantages and disadvantages of either, which apply to oxygen blown
operation, will also apply to operation with air. Thus the countercurrent
fixed bed units are highly efficient, but impose constraints on capacity
related to the size of the coal, its tendency to cake and to reactivity. The
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165
atmospheric fixed bed version has generally limited capacity subject to these
three properties of the feed coal. Countercurrency will also inevitably cause
tar to be evolved as the coal first reaches carbonization temperature (700 to
1,000°F). Several systems have been proposed and tested which minimize tar
yield, or render it innocuous.
In the past, these fixed bed reactors have generally been used on specially
selected coals (anthracite or coke of lump size) and a need exists to obtain
valid operating data on other coals in order to broaden the potential market for
this equipment. Standardized tests on a fixed bed reactor would be required to
compare the major US coal types (bituminous, sub-bituminous, lignite and
anthracite). For each, certain variables need to be systematically explored,
including among others:
a) Coal feed size limit (% fines) for stable operation;
b) Coal feed size ratio (breadth of size range);
c) Effect of degradation on operation.
The information would be required to allow proper procurement of coal for
industrial applications, where the market for Lo-BTU gas seems to be
concentrated.
For fine coal sizes (which would have to be agglomerated to permit their use in
fixed beds), the fluid bed reactor offers a good alternate, notably because it
can also accommodate larger capacity. The Winkler gasifier remains the most
demonstrated example, but its performance with air requires improvements,
particularly in terms of carbon conversion. Carbon loss through withdrawal from
the bed with the ash and through carryover with the product gas ranged from 20%
to 40%. Thus, operation of fluid bed gasifiers under conditions favoring
agglomeration (clinkering) of the ash is now being developed which would greatly
reduce carbon loss in the ash. The system has yet to be tested on a commercial
scale and DOE may consider support of the airblown, fluid bed, ash agglomerating
gasifiers if adequate private sector co-funding is available.
An interesting new development in airblown gasification is the Kiln gas process
currently being tested at a 600 ton per day scale. Completion of this project
may also be included in the DOE program if DOE decides that it is warranted.
2. Gas Clean-Up
A special R40 opportunity exists in the area of clean-up (desulfurizing) of raw
Lo-BTU gas. DOE is engaged in this area of gas clean-up, with major emphasis on
control of alkalis and particulates for use on hot pressurized gas streams
(supplying gas to gas turbine power units). In order to help introduction of
Lo-BTU gas to a wider industrial market, the program would also need to give
attention to the problem of HoS removal from hot, atmospheric pressure gas
streams in the range of 800° to 1,500°F, the exit temperatures of the various
gasifiers.
This subject of gas clean-up, hopefully at low cost, is probably the most
critical need before Lo-BTU gas can be expected to command a wider acceptance.
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166
3. Use of Lo-BTU Gas
The low heating value of this fuel does not permit wide range distribution by
pipeline grid; most installations will be tightly integrated with the final
user, where the gas is burned.
This raises the question about combustion technology and particularly the
potential problem of de-rating the capacity of the final user's equipment.
This is obviously a very site specific matter. There may be no generic R&D
program which addresses itself to all situations, but the potential of air-pre-
heat for Lo-BTU combustion systems as a means to reduce de-rating, deserves
study. This particularly is true since new alloys, etc. have recently been
developed that permit use of higher preheat levels. Another indirect approach
involves use of lower cost air separation techniques (membranes, etc.) to
produce enriched air for these gasifiers.
4. Solid and Aqueous Wastes
The solid wastes, ash, and waste liquor from gasifiers present different
disposal problems from those encountered with direct combustion of coal.
Ashes will tend to contain higher levels of residual carbon, and leaching must
be tested to assure proper disposal. Obviously, the problem is coal- and
gasifier-specific. Data related to this must be obtained to permit adoption of
the system.
Finally, it is known that almost all gasifiers will in most cases generate waste
waters which also need special attention. The only exception might be tar-free
gasifiers followed by hot gas clean-up. Research will therefore be needed to
define liquor treatment. Since Lo-BTU gas systems are likely to be fairly
small, the preferred disposal may be by way of municipal systems, but some pre-
treatment may be required to allow this method of disposal.
III. RECOMMENDATION
Without definition of a detailed R&D program for the Lo-BTU gas development, it
is estimated that up to $20 million per year would be required to cover all the
key issues in a program extended over a 5 year period. Obviously, much of this
money would come from the private sector, but some DOE involvement to serve as
lead agency and to contribute seed money would be desirable to assure timely
progress.
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167
E. POST-COMBUSTION EMISSION CONTROL
by: Lawrence Papa>
I. INTRODUCTION
Coal-fired boilers are required to comply with industry specific Federal and
state regulations that limit the emissions of sulfur oxides, nitrogen oxides and
particulate matter. Ambient air standards are also set for ozone, lead and
carbon monoxide emissions. In a Federal attainment area, the EPA or the
delegated agencies also make a case-by-case Best Available Control Technology
(BACT) determination for asbestos, mercury, berylium, vinylchloride and other
pollutants emitted above certain quantities. Specific technologies and measures
used to comply with regulatory requirements are at the discretion of the plant
operator as long as equivalent or superior performance can be demonstrated. In
addition, regulatory agencies periodically review their regulations (some
retroactively applied) to reflect technology development and new environmental
concerns. For effective acid rain precursor control, pollutant reduction will
be required for both new and existing power plants, and as such, there will be a
large potential market for novel, economical, retrofittable control technologies
for existing facilities.
II. DEFINITION OF SUBJECT
This section provides a summary of flue gas emission control systems and
identifies recommended federal involvement in the research and development of
these technologies. Pollution emission reduction from a coal-fired facility can
be achieved by various means including coal processing, combustion
modifications, and chemical additives in the combustion chamber as well as post-
combustion flue gas treatment. This section only addresses technologies
associated with flue gas treatment of sulfur oxides, nitrogen oxides and
particulates.
It should, however, be recognized that flue gas desulfurization (FGD) systems
will remain the most widely used environmental control concept for coal-fired
units for near- and medium-term. It should receive proper attention for this
reason alone. All other control options will have to be compared to FGD in
terms of efficiency, cost, availability and reliability.
III. STATE OF THE ART
1. SO2 Removal
Over 80% of the current 124 commercial utility FGD systems are wet
lime/limestone throwaway process or variations of the basic system. The acidic
sulfur oxides in the flue gas react with alkaline components of the slurry. The
waste slurry is then dewatered to about 50% water and 50% insoluble material.
The dewatered wastes are then either landfilled directly or treated further to
enhance the physical properties of the waste prior to disposal. In the case of
saleable product FGD systems, gypsum, elemental sulfur or sulfuric acid are
produced.
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168
Currently, there are six basic types of FGD systems in commercial operation: wet
lime/limestone, spray dryer, dual alkali, sodium sulfite, magnesium oxide, and
aqueous carbonate.
Despite its widespread use and a removal efficiency rate of over 90%, the wet
lime/limestone process still encounters some design and operational
uncertainties. The waste slurry is difficult to dewater and the resultant
soluble sulfite makes disposal difficult in many areas.
The lime spray dryer system, a "throwaway" process, is gaining in popularity.
Relative to the wet lime/limestone systems, this system has less corrosion
problems, has simpler design and produces a dry solid waste. The lime in the
slurry reacts with SO2 to form calcium sulfite/sulfate. Most of the water in
the slurry evaporates in the scrubber tower to form an essentially dry solid waste.
The dry sulfite/sulfate is collected in the baghouse together with the flyash.
Similar to the conventional FGD system, this process produces waste that contains
water soluble sulfite. The system removal efficiency ranges between 60%-90%. Due to
the high cost of reagents, its application is limited primarily to plants using low
or medium sulfur coal. The capital and levelized busbar costs are similar to those
of a conventional wet limestone FGD system. Most of the commercial systems are
meeting or exceeding the manufacturer's SO2 removal guarantees.
The "throwaway" dual alkali system involves a two step process. SO2 in the flue
gas first reacts with a sodium/potassium sulfite solution and the resultant
sulfite/sulfate is regenerated by the addition of lime/limestone to form
calcium sulfate/sulfite. The removal efficiency is approximately 90%.
This system is best suited for high sulfur coal facilities.
Even though saleable product FGD processes can achieve 90% SO2 removal and
alleviate most of the waste disposal problems, they are more complex and
expensive than the throwaway system. The Wellman-Lord process uses a sodium
sulfite solution to remove SO2 from the flue gas. The resultant bisulfite
solution is treated in a steam evaporator to regenerate the sulfite solution
while releasing a SOo rich gas stream which is then directed to a two step
reduction system to form elemental sulfur. In addition to high energy usage,
this process is sensitive to flue gas particles, HCl , and SO3. Thus, a
prescrubber is required, the MgO process uses magnesium oxide solution to
remove SOp f rom the flue gas to produce a magnesium sulfite slurry. The slurry
is then calcined (1800°F) producing SO2 gas and reusable magnesium oxide. The
SO2 is then reduced to elemental sulfur or converted to sulfuric acid. In the
aqueous carbonate process, a sodium carbonate solution is atomized in a spray
dryer to form sodium sulfite/sulfate solid waste which is collected in the
baghouse. In a three step process, the solid is then converted to elemental
sulfur and the regenerated reagent.
The availability of the scrubbing system is a function of a number of variables,
foremost being the type of system and type of service (i.e., base load,
intermediate or peaking) as well as the number of scrubbing modules installed.
For the year between March 1981 and March 1982, the availability of limestone
slurry systems averaged 73%, lime slurry systems 84% and dual alkali systems
96%. The use of additives such as magnesium salts or organic acids appears to
enhance availability of the lime/limestone systems.
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169
Table 1 summarizes the status of FGD systems In the United States as of
September 1984. Table 2 provides estimates of FGD capacity through the year
2020. These estimates assume a 2% per year growth rate beyond 1990 for new
coal-fired capacity, and assume that old plant retirements are non-FGD coal
technology applications are negligible.
2. NO^ Removal
Current federal regulations for NO^^ emissions are being met by methods that are
more cost-effective than other flue gas treatment. Full scale flue gas NO^^
control systems are not in commercial use in any US coal -fired power plants.
The current practice for flue gas NO^ removal in Japan is by selective catalytic
reduction (SCR), which provides a removal efficiency of 60% to 80%. Of the 93
SCR systems installed, 26 systems are on coal-fired units. Eight additional
installations have been planned by 1990 in Japan. The Japanese technologies are
being tested and demonstrated in the US on a^commercial demonstration size
(107.5 MW oil-fired unit) by the Southern California Edison Company and on
selected small refinery boilers. The Exxon thermal DeNO^ process (selective
non-catalytic reduction - SNCR) has been tested in Japan and in the US by the
Los Angeles Department of Water and Power,
Both the SCR and SNCR processes rely on the reduction of nitrogen oxides in the
presence of ammonia to form nitrogen gas and water. Difficulties identified
with these processes, such as maintaining the equimolar ratio of ammonia and
NO , undesirable organic compound formation, corrosion problems associated with
oxidation of SO^ to SO3, ammonia slippage and unknown catalytic life,
necessitate additional research and demonstration.
3. Particulate Matter Removal
The current commercial practice for particulate matter removal is by
electrostatic precipitation (ESP), fabric filter bag units (baghouses) and wet
scrubbers. ESP units are installed either upstream (hot ESP) or downstream of
the air preheater (cold ESP). Both arrangements electrostatically charge the
flyash by passing it through high voltage chambers, and the charged particles
are captured on collection plates. Most installed units are cold ESP. Better
than 99% particulate matter removal can be achieved. Particulate matter removal
in a baghouse is accomplished by passing the flue gas through fabric filter bags
mounted above flyash collection hoppers. The flyash is collected in the bags
and periodically removed by diverting the flue gas to a parallel bag collection
chamber and back purging the flyash from the bags into the collection hoppers.
A particulate matter removal rate of 99.9% can be achieved. Wet scrubber
particulate matter removal is usually used in conjunction with SOp removal.
Over 1400 ESP and 120 baghouse units are in operation or committed for utility
power plants. The role of the baghouse will likely increase because of higher
removal efficiency of fine particles (< 2 microns). On the other hand, ESP is
applicable to low resistivity flyash.
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TABLE 1
SUMMARY OF FGD PROCESS STATUS
(AS OF SEPTEMBER 1984; EPA/EPRI DATA)
Under
Contract
Ope
rational
Construction
Awarded
Total
TJ&7
MW
No.
MW
No. MW
No.
MW
THROWAWAY PRODUCT
Wet
Nonregenerable
Limestone
57
24.012
12
7,566
8 5.630
77
37,108
Lime
36
14.852
3
2.132
1 650
40
17,634
Sodium Carbonate
6
1.505
—
—
2 1,100
8
2,605
Regenerable
Dual Alkali
4
1.572
2
656
—
6
2,228
Dry (nonregenerable)
Lime
7
1,840
6
2.913
4 1.910
17
6,663
Sodium Carbonate
1
440
1
550
—
2
990
SALEABLE PRODUCT
Wet
Nonregenerable
Limestone
1
166
1
475
2
641
Lime
1
65
—
—
—
1
65
Regenerable
Wellman-Lord
7
1.959
7
1,959
Magnasium Oxide
3
724
—
—
—
3
724
TOTAL
THROWAWAY PRODUCT
111
44,221
24
13.817
15
9,190
150
67.228
TOTAL
SALABLE PRODUCT
13
3,014
1
475
"-
14
3.489
TOTAL
WET
115
44,855
18
10.829
11
7,280
144
62.964
TOTAL
DRY
9
2.380
7
3,463
4
1,910
20
7,753
TOTAL
NONREGENERABLE
109
42,880
23
13.636
15
9,190
147
65,706
TOtAL
REGENERABLE
15
4.355
2
656
--
---
17
5,011
TOTAL
CONTROLLED CAPACITY
124
50.870
25
14,656
15
9.248
164
74,774
TOTAL
SCRUBBED CAPACITY
124
47.255
25
14,335
15
9.190
164
70.780
92
171
TABLE 2
FORECASTS OF SCRUBBER COAL -FIRED CAPACITY
AT UTILITY POWER PLANTS IN THE US
(EPA Data)
31
104
178
268
378
12
31
43
53
62
1980 1990 2000 2UTI5 JoST
Total Coal Generating Capacity 253 338 412 502 61?"
(Gigawatts)
Scrubbed Capacity (Gigawatts)
Percent of Total , Scrubbed
Cost information related to the above discussed state of the art flue gas
cleanup technologies is presented in Table 3.
IV. OUTLOOK FOR REQUIREMENTS FOR 2020
The reyulatory requirements for SO^^, NO^^ and particulate matter emissions will
likely be tightened from current levels, especially in non-attainment areas.
This, together with the anticipated significant increase in coal generating
capacity by the year 2020 (see Table 2), will require improvement of existing
technologies or development of new technology options to reduce cost, increase
efficiency and reliability.
The technologies that would be adopted depend on progress in the development of
new processes or improvement of existing technologies. Unless significant
improvement can be made to the ESP, the baghouse will continue to be the
predominant system for particulate matter control in near-term new
installations. In the near future, a dry FGD scrubber with a baghouse will
likely be the technology of choice for post combustion SO2 control for
low/medium sulfur coal-fired facilities. For plants using high sulfur coal, wet
lime/limestone systems with some variation will continue to be used. If
combustion modification is not sufficient to achieve desired NO reduction,
selective catalytic/non-catalytic reduction systems will be available for post
combustion control. One of the new combined NOj^/SO^^ systems will probably
become the system of choice for the year 1992 and beyond. The removal
efficiency of these control systems for new plants will probably be greater in
most cases than for those already in operation.
V. CURRENT R&D
Technologies currently being developed can be applied to new plants as well as
existing facilities. The following discussion covers processes that are easily
retrofittable to existing facilities. Other emerging technologies, while being
developed mainly for new plants, can also be applicable to existing facilities
if the space and economic constraints can be overcome.
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172
TABLE 3
ESTIMATED COST OF STATE OF THE ART FLUE GAS
CLEANUP TECHNOLOGIES
(1982 Dollars)
$/kW
NEW FACILITY
Level i zed
Mills/kWh
SO2
ConventicSnal Lime/
Limestone (L, H)
110-175
8-18
Spray Dryer (L)
Dual Alkali (H)
Wellman-Lord (H)
MgO (H)
Aqueous Carbonate (H)
PARTICULATE MATTER
ESP
Baghouse
L = For Low Sulfur Coal Facility Only
H = For High Sulfur Coal Facility Only
L,H = For Both Low and High Sulfur Coal
Source: 1. Draft EPRI Report: "SO2 and NO^^ Retrofit Control Technologies
Handbook"
2. "The Economics of Fibric Filters and Electrostatic Precipitators",
1983, R.R. Mora, R. Carr, and P. Goldbrunner.
110
7.5
150-160
17
275
26
270
19
400
31
60
3.3
54
3.0
$/kW
175-317
148-252
157-272
252-492
340-378
500-560
75-84
67-76
RETROFIT
Level i zed
Mills/ kWh
17-23
10-18
15-22
22-32
21-27
34-43
3.6-4.6
3.3-4.2
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173
Table 4 shows the estimated capital and levelized costs for emerging
technologies that have been or are being demonstrated on a significant scale.
These technologies will be commercially available prior to 1992 if developmental
efforts are actively pursued. Similarly, Table 5 shows the estimated costs for
new technologies that are still in bench or pilot scale testing. Due to
uncertainties in this early development stage, commercialization prospects for
these technologies remain unknown, but could in no case occur sooner than 1992.
Thus, costs presented are highly speculative and should be used for comparative
purposes only.
1. Technologies for Existing Plants
Numerous activities are being conducted to refine existing operating emission
control systems. While these research activities are being performed by both
the private and public sectors, continued government presence is necessary for
smooth technology transfer. For particulate matter control, the research
efforts are centered on performance improvement and optimization. Due to
concerns related to trace element and inhalable particulate matter emissions,
substantial emphasis is being placed on the removal of submicron sized
particles. Examples of these research efforts include electrostatic,
electromagnetic and sonic horn augmentation for fabric filtration; two stage
ESP; and use of additives. Economically, the most attractive improvement for
existing wet FGD systems is the use of organic (e.g., adipic) acids or magnesium
salts to enhance SO2 removal efficiency and reagent utilization. Results
indicate that a removal efficiency of 95% can be achieved at reduced operating
cost.
The large fresh water consumption (up to 5 gallons per minute per MW capacity)
and the voluminous waste water discharge of a conventional wet FGD system may
impose siting and operational problems for coal power plants, especially in the
arid southwest. In this respect, reduced water consumption also lowers water
treatment and disposal costs. The private sector, in conjunction with EPRl, is
conducting research to reduce FGD water consumption, including recycling and
biofouling control as well as integrated water systems for power plants. Other
than indirect participation and information dissemination, no direct DOE
involvement is needed at this time.
For effective acid rain precursor control, there is a need for novel, low-cost,
low removal efficiency and retrofittable control technologies for the numerous
existing coal-fired facilities that do not have all the desirable environmental
control systems. Compared to high removal efficiency and higher cost systems,
the trade-off is centered on lower removal efficiency for lower capital
expenditures for facilities that have limited remaining useful lives and are not
likely to be operated continuously. The large number of these facilities (hence
the large market) together with large cumulative environmental improvements
deserve additional national developmental efforts.
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174
TABLE 4
ESTIMATED COSTS OF NEAR-TERM DEVELOPING CONTROL TECHNOLOGIES
(1982 DOLLARS)
NEW FACILITY RETROFIT
Level i zed Level i zed
$/kW Mills/kWh $/kW Mills/kWh
SO2
Chemical Addition Negligible+
(Organic Acid)
Dry Injection
(L)
90
7-20
CT-121 (H)
140
14
Saarberg-HoUe
ir (H)
130
16
DOWA (H)
175
14
NO,
SCR*
54-89
6-14
SNRC*
11
1.5
110-125
8-20
170-290
14-18
163-182
18-22
219-245
15-20
70-124
6-19
11-17
2-3
L = For Low Sulfur Coal Application
H = For High Sulfur Coal Application
* = Based on Japanese Experience; not in commercial use in US.
+ = Applicable to existing lime/limestone FGD systems only.
SOURCE: Draft EPRI Report, "SOg and NO^ Retrofit Control Technologies
Handbook".
96
175
TABLE 5
ESTIMATED COST OF LONG-TERM
DEVELOPING TECHNOLOGIES
(1982 DOLLARS)
NEW INSTALLATIONS
Level i zed
$/kW Mills/kWh
SO,
Flakt Boliden
390
CONOSOX
430
COMBINED
m^ and SO^
SULF-X
290
Copper Oxide
238
Carbon Absorption
117
Electron Beam
333
NOXSO
NA
30
45
20
22
23
33
NA
SOURCES: 1. Personal communications with EPRI, EPA and DOE. Since these
technologies will not be commercially available until the late
1990s, the estimated costs shown are highly uncertain and depend
on the success of technology development and breakthroughs.
2. Draft EPRI Report, "SOo and NO Retrofit Control Technologies
Handbook".
3. "Current Status of Dry NO - S0„ Emission Control Process". S.M.
Dalton, EPRI CS-3182, Vol. 1.
4. "Economic Evaluation of FGD Systems", EPRI CS-3342.
97
176
In most of the retrofit applications, major limitations include space
requirements, extensive and costly modifications to the existing facility,
capital cost requirements, loss of operating flexibility and potential output
derating, A promising low cost FGD option is the dry injection of sorbent in
the flue gas before the baghouse. This process has been demonstrated by EPRI in
a full-scale facility and is applicable to both new or exiting low-sulfur coal-
fired facilities. Additional research is needed for high sulfur coal
applications, for use in conjunction with ESPs, for improved waste fixation and
disposal, and for system optimization as well as for use with lower cost
alternate reagents. Based on the success of this process development, the
Public Service Company of Colorado has recently announced the use of dry
injection system for its new 500 MW coal-fired unit.
2. Technologies for New Facilities
Advanced limestone/gypsum FGD processes (Chiyoda Thoroughbred 121 [CT-121] and
Saarberg-Holter) are commercially availably in foreign countries, but have not
been fully demonstrated in the US. These systems have high probabilities for
commercial readiness in the US by the end of this decade as alternatives to
conventional wet scrubbers. These processes produce marketable gypsum by forced
oxidization of the spent slurry. The Saarberg-Holter system has been
demonstrated in Europe in full-scale coal-fired power plants while the CT-121
system was successfully tested by EPRI in a 23 MW prototype. While achieving an
SOp removal efficiency of 90% at a lower level ized cost, these processes also
make more complete use of reagents and eliminate plugging and scaling.
A modified dual alkali system, using aluminum sulfate instead of caustic soda as
the scrubbing reagent is being developed. The spent reagent from this process
(DOWA) is oxidized and regenerated with lime or limestone to form gypsum. The
DOWA process, commercially available in Japan, makes more efficient use of
limestone, has better load following capability and promises lower cost. A
disadvantage is that the soluble aluminum sulfate contained in the solid waste
may pose a problem for disposal or for sale. The DOWA process was tested by
EPRI at a 10 MW pilot plant and achieved a 90% removal rate.
Of the post-combustion cleanup technologies for nitrogen oxides control, the
selective catalytic and selective non-catalytic reduction systems are the most
advanced. Pilot scale systems of these two technologies have been tested on
flue gas from coal-fired power plants. They were found to be effective for
the cases tested. However, these processes are more expensive than combustion
modification. Demonstration-scale tests for US coal-fired power plants have
not yet been conducted. The selective catalytic reduction (SCR) process
converts nitrogen oxides to elemental nitrogen in the presence of gaseous
ammonia at 700°F and is capable of achieving 80%-90% removal of NO^. The use
of this system for coal-fired plants is limited only to pilot-scale studies.
The selective non-catalytic reduction (SNCR) process removes nitrogen at
elevated temperatures of 1700-2200°F in the presence of ammonia. Testing of
this process has been limited to pilot-scale coal-fired facilities, and it has
been found less effective (60% removal rate vs. 90% for SCR). Additional
research work is required for both the SCR and SNCR processes. Major
Improvements are needed in the process control subsystem, extension of
catalyst life, cost reduction, and elimination of ammonia slippage.
Almost all of the long-term research efforts are focused on advanced SOo control
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177
technologies or combined S02/N0j^ and particle removal. For advanced SOp control
technologies, the primary emphasis is placed on reagent regeneration ana
saleable product processes. Although these processes are usually more complex
to control and operate, they will eliminate or minimize the solid waste disposal
problems. The Flakt Boliden (sodium citrate reagent) and CONOSOX (potassium
salt reagent) processes are in pilot-scale development with projected commercial
availability for the late 1990s. Due to their high costs, these two
technologies will have difficulties in gaining commercial acceptance unless
major cost reductions and/or breakthroughs can be found.
There are numerous developing technologies that may have the capability of
simultaneous removal of NO and SO^. These technologies, sponsored primarily by
DOE, use more complex chemical processes not commonly used in the utility
industry. Bench scale/pilot tests were conducted for the copper oxide, carbon
absorption, electron beam, NOXSO and SULF-X processes. Other processes that
exhibit some degree of removal efficiency include glow discharge, zinc and
zeolite catalyst. However, these processes are not expected to be commercially
available prior to 1992, with the majority available after the year 2000.
In a copper oxide reduction system, a fixed-bed or a fluidized-bed of copper
oxide is used to absorb the flue gas SO2 and form copper sulfate. The copper
sulfate is then further processed to form elemental copper and elemental sulfur
in a two-stage process. The fixed-bed process has been used in a Japanese
refinery since 1973, achieving 90% SO^ and 40% NO^ removal. An EPA/DOE jointly-
sponsored pilot-scale test on a coal-fired boiler at Tampa Electric Company
achieved a removal efficiency of 90% for SOo and 70% for NO^. The fluidized-bed
process is being tested on a pilot scale byuOE at the Pittsburgh Energy
Technology Center. Preliminary results from Japanese large-scale testing
facilities indicate that it can achieve over 90% SOg and 70% NO^ removal.
Activated carbon can be used as a catalyst in reducing NO^^ to N2 in the presence
of ammonia while acting as an absorbent for SO2. The carbon is regenerated by
heating to release the SO2, which is then converted to elemental sulfur in a
two-stage process. Pilot-scale tests achieved a removal efficiency of 70% for
both SO2 and NOj^.
The electron beam irradiation process, being actively pursued by DOE, involves
the use of high energy electronic guns to dissociate the flue gas to form free
radicals with an anticipated removal efficiency of 90% for SO2 and 80% for NO^^.
In the Avco-Ebara process, flue gas is humidified and cooled to about 200°F and
electron beams are used to ionize the gas to form ammonium nitrate and ammonium
sulfate in the presence of ammonia. Under the sponsorship of DOE, this process
is being tested on pilot scale at an Indianapolis power plant. In the Research-
Cottrell process, a lime spray dryer is used for partial upstream removal of SO2
while the remaining SO2 and NO^^ are captured in the electron beam reaction
chamber. DOE is testing this process on a pilot scale at the TVA Shawnee Plant.
However, the cost of the electron beam gun must be reduced drastically for
conriercial viability of both systems.
The NOXSO process is a dry regenerative process using granular sodium oxide on
aluminum in a moving bed reactor to remove SO^^ and NO^ at 250-400°F. The spent
reagent is regenerated at elevated temperatures in the presence of H2S to form
elemental sulfur and nitrogen. This process is being tested by DOE on a bench
99
178
scale at the TVA Shawnee plant and has achieved a simultaneous removal
efficiency of 90% for both SOg and NO^.
The SULF-X process uses an iron sulfide slurry solution for combined NO^/SO^
capture. This process is being tested by the State of Pennsylvania on a pilot
scale at the Western Hospital Center in Canonsburg, Pennsylvania, achieving 90%
SOo and 70% N0„ removal. Efforts are underway to increase the NO removal rate
to^90%.
VI. COMMENT TO R&D PROGRAM
The DOE flue gas cleanup program is focused on the development of advanced
technologies with long-term commercialization schedules. DOE intends to develop
high risk, high payoff new technologies through the proof-of-concept stage,
leaving the demonstration, optimization and commercialization activities for the
private sector. It should be noted that it takes at least five years after the
proof-of-concept stage to demonstrate a new technology on a full scale prior to
its first commercial application. Thus, if the combined NOj^/SOo cleanup
technology options were to be developed by October 1990 as scheduled, they
would not be commercially available until 1995. The drastic termination of
governmental support after the proof-of-concept stage increases the
difficulties for the private sector to proceed with the demonstration and
commercialization phases. Uncertainties and risks associated with such large
demonstration projects are often beyond the financial capability of one utility
or supplier. Continued federal presence during the demonstration and early
commercialization phases will be necessary for effective and timely technology
transfer. While it is highly desirable for the private sector to take the lead
and have project management responsibility in a demonstration project, it is a
proper role for the government to provide financial and technical support and
timely information dissemination during the transition period.
For effective acid rain precursor control, there is an urgent need for low-cost,
low-efficiency control technologies for existing coal-fired facilities. The
current DOE schedule of September 1987 for the completion of acid rain
control technology (ARCT) development should be accelerated to meet this
need. By eliminating some of the paper studies, this program can be
accelerated by one year. In addition, DOE must carry out these ARCTs beyond
the proof-of-concept stage by direct funding and participation in full-scale
testing in conjunction with EPA, EPRI and the private sector. Failure to
participate in this carry-through effort will delay the commercialization of
these emerging ARCTs.
The EPA program concentrates on near-term commercialization of lower cost
variations of base technologies that already have commercial track records. The
EPA program goal is to ensure that best available control technology (BACT) is
available to meet the mandated environmental standards. In this respect,
increased interagency coordination and cooperation in the improvement and
development of spray dryer and dry injection technologies will be beneficial.
For retrofit application of dry FGD, DOE must take a lead role in improving the
performance of existing and new ESPs to handle varying ash loading and ash
alkalinity.
100
179
The private sector work Is primarily directed at near-term technologies to
improve the cost, reliability and operation of existing control systems. As
such, its program is directed at solving immediate problems, removing an
objectionable emittant, controlling and disposing of waste products, reducing
costs and optimizing system operation.
While there is good interaction among parties involved in flue gas cleanup
technologies, such coordination should be increased to ensure effective
execution of the DOE program plan. In particular, the private sector, which
will be the ultimate user of the developing technologies, can assist DOE in the
selection of processes to pursue, in early identification of scale-up and
operational problems, and retrofit practicality.
VII. CONCLUDING COMMENTS
The overall DOE program is comprehensive and generally well conceived. However,
it is deficient in two areas. First, technologies that reduce SOp and NO^^
emission from existing plants are not adequately covered. Secondly, technologies
being evaluated for long-term applications are so dispersed that procedures
should be established (with active industry participation and interagency
coordination) to better focus research efforts on the most promising processes.
To address the acid rain problem, more emphasis must be placed on the develop-
ment of low-cost, low-efficiency retrofittable control technologies. Such
technologies must be close to commercial readiness or at full-scale testing, be
cost effective, and have broad applications.
For existing facilities with FGD and/or particulate matter control systems,
every effort should be made to promote the use of additives to enhance system
performance. More full-scale testing should be conducted to demonstrate cost
savings and removal efficiency improvements. Although EPA has made some efforts
in this area, DOE should increase its participation in the overall program to
accelerate commercialization of these promising concepts.
For existing facilities with particulate matter control but no FGD systems, the
current research efforts in spray dryer and dry injection should be strengthened
to accelerate their commercialization. The use of existing ESPs for spray
dryer/dry injection should be further pursued. Alternative reagents for the dry
FGD systems should be developed to minimize the costs, especially for high
sulfur coal applications.
For N0„ control of existing facilities, combustion modification appears to be
the least cost option. SCR and SNCR are the most likely near-term post combus-
tion control processes if the catalyst life and the process control subsystem
can be improved. Full-scale demonstration would be the next stage of
development. Since these technologies are expensive, they should be pursued
only after funding for the above mentioned research needs in combustion control
and SOo removal processes are satisfied.
To increase technology options for new plants to be constructed before 1992,
continued effort to develop advanced limestone/gypsum FGD processes (in parti-
cular the CT-121 process) may be warranted for cost saving purposes. For new
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180
plants that come on-line after 1992, numerous new potential processes may become
available. However, there is not enough information to select superior techno-
logy(ies) at this time. The emphasis by DOE on a combined S02/N0jj particulate
matter control system that minimizes solid waste production appears to be well
placed. These new technologies have potential removal efficiencies of 90% for
NO and SOo and over 99% for particulate matter. Nevertheless, the cost of
these new technologies does not appear to be significantly lower than those of
existing systems. As indicated in Table 6, the new developing combined removal
technologies offer only minor economic advantage for plants using low sulfur
coal. For high sulfur coal, the advantage is more significant. The pursuit of
electron beam technology is viable only if the cost can be significantly reduced.
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181
TABLE 6
LEVEL I ZED COSTS FOR FLUE GAS CLEANUP SYSTEMS
(1982 DOLLARS; DOE/ERA/EPRI DATA)
PROCESSES
Low Sulfur
Coal
High
Sulfur Coal
Level i zed
Cost
Level i zed Cost
SO2 Control
A. Conventional Limestone
Mills/kWh
Mills/kWh
8
18
B. Lime Spray Dryer
8
C. Nacholite Injection
10
D. Trona Injection
9
E. CT-121
14
F. DOWA
14
G. Saarbert-Holter
16
H. Limestone Dual ALkali
16
I. Lime Dual Alkali
17
J. Wet Lime
20
K. Wellman-Lord
26
L. MgO
19
H. Flakt Boliden
30
N. Aqueous Carbonate
31
0. CUNOSOX
45
NO^ Control
SCR
10
SNCR
2
Particulate Matter
ESP
3
Baghouse
3
Combined N0j^/S02 Systems
Copper Oxides
22
Carbon Absorption
23
Electron Beam
33
NOXSO
NA
SULF-X
20
103
182
VIII. RECOMMENDATION
The past de-emphasis on flue gas cleanup technology development (other than
combined systems) has placed DOE in a catch-up situation. DOE's acid rain
control technology (ARCT) program should be accelerated. The experience of
other entities such as EPA, TVA, national laboratories, EPRI and the private
sector should be solicited and field tests should be conducted as soon as
possible. In addition, DOE's ARCT program should go beyond the "proof-of-
concept" stage. Instead of initiating new processes or totally separate
efforts, DOE should explore joint programs with other agencies and the private
sector.
DOE's long range program appears viable. However, the extensive emphasis on
electron beam technology should be reconsidered unless significant cost
reductions and technical breakthroughs are anticipated. The current federal
program on pollution control technology development is spread among different
federal agencies with overlapping responsibilities and missions. Unless the
agencies work closely together in coordinating their activities, certain needs
may not be fulfilled.
The highest priority in emission control technology development and demonstra-
tion must be placed on those emerging systems that are capable of meeting the
immediate need of the private sector while simultaneously meeting the national
goal of acid rain precursor control. The following composite ranking of action
items reflects the needs of the private sector, and as such, should be pursued
as part of the national effort, under the direction of Federal Government*
programmatic funding requirements to meet these needs are detailed in Table 7.
NEAR TERM NEEDS (commercially available prior to 1992)
0 Acid rain control technology (ARCT) development and demonstration:
- dry FGD systems, especially for use with existing ESPs and for high
sulfur coal applications;
- performance improvements and operation and maintenance cost reductions
for existing control systems;
- use of low cost additives for existing systems.
0 Develop and demonstrate low cost control technologies for use in conjunction
with conversion of existing oil/gas units to coal.
0 Full-scale demonstration of SCR on a coal -fired boiler.
0 Full-scale demonstration of the CT-121 process.
*In addition to flue gas cleanup, other emerging clean coal technologies that
should be pursued include: direct coal-water slurry firing, slagging combustor,
in-burner SOo and NO control, LIMB, coal cleaning, and atmospheric and
pressurized fluidized bed combustion, as well as coal gasification and
liquefaction.
lOA
183
LONG TERM NEEDS {commercially available after 1992)
0 Second generation dry FGD systems.
0 Combined SOg/NO^ particulate matter control technologies.
The composite FY 1985 DOE budget request is $14 million for flue gas cleanup
technologies. The current EPRI program plan anticipates an expenditure of $96
million for flue gas cleanup for the years 1985 through 1989. Should additional
funds be available for clean coal technology development, such funds should be
directed to the sponsoring of demonstration projects to meet both the near-
term and long-term needs. Cost estimates (Table 7) for the above necessary
programs are highly uncertain at this time, and can only be made more definite
upon the selection of demonstration sites.
Action Items
Near Term Needs
TABLt 7
ESTIMATED FUNDING REQUIREMENTS*
1986 1987 1988
Acid Rain Control Technology
Control Technology for Fuel
Conversion Facilities
Full Scale SCR
Full Scale CT-121
Long Term Needs
Second Gen. Dry FGD
Combined Systems
TOTAL
1989 1990 TOTAL
36
18
18
14
86
4
8
15
8
8
43
10
23
6
6
6
51
4
20
20
7
7
58
4
6
15
20
15
60
7
15
60
100
80
262
65
90
134
155
116
560
*Total estimated expenditure; highly site specific; percentage of private and public
contributions to each action item is unknown at this time.
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184
HASTE MANAGEHENT
by: Edward Rubin
I. DEFINITION OF SUBJECT
Coal utilization inevitably is accompanied by the production of solid wastes.
At coal-fired power plants, the principal waste materials traditionally have
been boiler bottom ash plus fly ash collected from the flue gas stream. This
represents a considerable quantity of material (roughly 80 million tons per
year) since ash typically accounts for 10% to 20% of the total mass of coal
burned. In .addition, power plants produce a number of "low volume" wastes from
auxiliary apparatus such as water demineralizers.
New environmental regulations enacted in the 1970s have resulted in the
generation of significant additional quantities of solid waste at coal-fired
power plants. Flue gas desulfurization (FGD) systems installed to comply with
sulfur dioxide air pollution regulations (now required on all new coal-fired
power plants) typically produce a calcium-based sludge in quantities that may be
up to 2 or 3 times greater than the amount of ash material generated by a
particular plant. New water pollution regulations which prohibit or stringently
limit thermal and chemical discharges to waterways also have resulted in the
installation of control technologies which invariably produce some quantity of
solid waste, typically in the form of a wet sludge. While these quantities are
small compared to fly ash and FGD wastes, their chemical composition also must
be carefully considered in the current regulatory environment.
Coal preparation plants represent the other major source of coal utilization
wastes (aside from the mining process itself, which is not considered in this
report). Preparation plant refuse may contain 5% to 20% of the original coal
mass, depending on the level of cleaning. These wastes consist primarily of
coal ash as well as some sulfur-bearing pyrite and coal unavoidably collected
with the refuse material. This waste leaves the coal preparation plant as a
slurry, which may undergo some degree of dewatering prior to disposal.
Federal legislation in recent years, particularly the Resource Conservation and
Recovery Act (RCRA), the Solid Waste Disposal Act (SWDA) and the Toxic
Substances Control Act (TSCA), has focused special attention on problems of
solid waste disposal. The principal concern is over the release of potentially
hazardous or toxic chemical compounds and elements (such as heavy metals) into
surface or groundwater systems as a result of direct runoff or chemical leaching
through soils. To a large extent, the focus of this concern has been on wastes
from various chemical processes as opposed to those from coal combustion or
processing. Nonetheless, as air and water pollution regulations have prohibited
or minimized the release of coal-related pollutants to the water and air, their
presence in the form of solid waste has grown in significance.
As with other environmental media, responsibility for the development and
promulgation of regulations governing the disposal of solid and liquid waste
lies with the U.S. Environmental Protection Agency (EPA), and with state or
local government agencies. At the federal level, the designation of wastes
under RCRA as either "hazardous" or "non-hazardous" is perhaps the most critical
factor affecting coal utilization processes. At the present time, EPA
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185
regulations treat high volume coal combustion wastes from electric utilities as
a special category not considered to be "hazardous" (as determined by specified
test procedures). A final designation, however, is still pending at EPA. In
addition, specific waste disposal requirements vary from state to state. Thus,
over the long term there still remains considerable uncertainty regarding the
future development of solid waste regulations, and their impact on the viability
and cost of both conventional coal utilization technology and advanced
technologies currently in the research and development stage. The important
message is that the "clean use of coal" does not simply refer to the solution of
air pollution problems. Liquid and solid waste management also must be an
integral part of any R&D program aimed at the clean use of coal.
II. STATE OF THE ART
Current solid waste disposal practices at power plants are highly variable, and
depend in part on whether or not the plant is equipped with an F6D system.
Older plants not required to have FGD generally dispose of their ash by
transporting it in a moist state to an ash disposal pond. To comply with water
pollution regulations, the supernatent liquid may be treated prior to discharge.
For plants with FGD systems, current waste disposal practice typically involves
mixing FGD sludge and fly ash (possibly with the addition of a fixing agent) and
co-disposal in a pond or dry landfill. Landfill operations are emerging as
the generally preferred disposal alternative for new power plants, though the
choice of disposal method often is highly site-specific. Depending on the
requirements of state and local authorities, solid waste disposal ponds also may
be required to have synthetic liners to prevent the leaching of materials into
the ground. Waste disposal sites more frequently have been constructed using
layers of natural clay to provide a nominally impermeable barrier to leachates.
In similar fashion, waste disposal practices at modern coal preparation plants
typically involve the sanitary landfill of dewatered coal refuse material.
Older plants, however, simply left ponds or coal refuse piles that are subject
to spontaneous combustion as well as to leaching and runoff into surface waters.
An alternative to the disposal of waste materials is their utilization as a
commercial by-product. Potential applications of conventional power plant waste
include use for structural fill, lightweight aggregate, cement manufacturing,
soil stabilization, concrete products, and liming agents. FGD processes also
can be designed to produce by-product sulfur, sulfuric acid, or commercial
grade gypsum. Wastes from coal cleaning plants are a potential source of low-
grade fuel (e.g., for fluidized bed boilers).
While the utilization of power plant ash and FGD wastes is relatively widespread
in parts of Europe and Japan, such applications are much less common in the U.S.
because of differences in commercial markets and the greater availability of
land for waste disposal. The use of fly ash as fill material for road
construction and as a lightweight aggregate for cement are the principal
utilization markets for power plant wastes at the present time. However, this
represents only a small portion of total waste production. While a few U.S.
power plants use regenerative FGD systems producing salable by-products, such
systems have not gained widespread use in this country because of their
generally unfavorable economics. This is why U.S. plants typically dispose of
the low-grade gypsum produced by conventional lime/limestone FGD systems rather
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186
than produce higher quality gypsum potentially suitable for wallboard and other
applications (as is common practice in Germany and Japan). Thus, while state-
of-the-art technology is capable of reducing solid waste generation by producing
potentially usable by-products, this remains an economically unattractive option
relative to waste disposal at the present time.
III. OUTLOOK FOR REQUIREMENTS FOR 2020
In general, the quantity of solid waste generated from coal utilization over the
next several decades can be expected to grow significantly as FGD systems
producing a wet or dry solid waste add to the traditional burden of mineral
matter (bottom and fly ash). As discussed below, many emerging technologies and
advanced coal utilization systems also generate larger quantities of solid waste
than conventional power plants, potentially exacerbating future problems. Thus,
the importance of solid waste as the ultimate disposal medium for coal-borne
contaminants is likely to increase in future years. Future developments in the
economic utilization of these materials may offer one avenue for offsetting this
growth in volume and potential adverse impacts.
IV. CURRENT R&D
The DOE Office of Fossil Energy (DOE/FE) maintains a Waste Management Program
with a current annual R&D budget of approximately $2 million. The following
paragraphs describe the DOE program objectives, current activities, and future
plans. Other federal and private R&D programs are then briefly reviewed.
The DOE Program
The DOE Waste Management Program has five stated objectives:
0 Advance the fundamental understanding of fossil fuel cycle waste
characteristics to define the required R&D for effective management of the
waste;
0 Conduct the necessary R&D to develop sound technological and economic
solutions for waste management in compliance with environmental constraints
and institutional criteria;
0 Conduct technical and economic assessments to select the waste management
concepts that not only meet the environmental constraints and institutional
criteria but also are the least disruptive to the economy, and to determine
the market penetration potential of the technology;
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187
0 Establish the technology and related economic data base necessary for private
sector assessment of the commercial viability of techniques and/or processes
for management (disposal) of fossil fuel cycle wastes, e.g., coal
preparation, flue gas cleanup, gas stream cleanup, and emerging technology
process waste by-products;
0 In addition to publication of reports, conduct, support, participate and co-
sponsor waste management symposia, conferences, and workshops, as necessary,
to provide a continuous exchange of information for technology transfer.
The recent emphasis of the the DOE waste management program has been on the
characterization of wastes from conventional electric utility plants. There has
been little work on the development of new disposal methods or control
technology per se, this being viewed as a longer-term objective of the
program that would be developed in response to any identified needs. Projects
dealing with waste recovery, re-use or utilization have been phased out of the
DOE program during the past two years.
Two studies initiated in the late 1970s represent recent major efforts of the
Waste Management Program. One is a study of utility waste characteristics,
completed in 1984. It characterized some 94 samples of coal feedstock, ash, and
FGD sludge for coal combustion systems at 18 U.S. power plant sites, with a
focus on trace metals and their leachability. Several samples characterized
wastes from emerging energy technologies at six DOE-sponsored projects (e.g.,
the H-Coal process, oil shale, tar sands, etc.). New work is now underway to
characterize organic compounds for these same samples. A more limited data base
is available for coal preparation plant wastes, obtained from other projects
supported under the waste management program.
A second major effort, initiated nearly six years ago, is a study of alternative
waste disposal methods and costs as they relate to fossil fuel utilization.
This addresses the range of potential impacts that could result from the
implementation of regulations under RCRA and related legislation. It looks at
three principal scenarios: the world before RCRA; the world after RCRA assuming
utility wastes are designated as non-hazardous; and the world after RCRA
assuming that wastes are designated as hazardous. The latter scenario includes
two cases representing minimum and maximum cost. This effort has involved case
studies of some 26 power plants, with the results used to project impacts for
nearly 400 plants nationwide. Completion of this study is expected in 1985.
Having recently brought to completion a number of projects dealing primarily
with the sampling and characterization of wastes from conventional coal
utilization processes, the current focus of the Waste Management Program is on
the characterization of wastes from emerging coal utilization technologies. DOE
lists a comprehensive set of waste streams to be studied:
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188
0 Coal preparation wastes (physical and chemical processes)
0 Conventional coal combustion wastes
0 Flue gas cleanup wastes
0 Gas stream cleanup wastes
0 AFBC and PFBC wastes
0 Oil shale residues
0 Coal conversion process wastes
0 Synfuel process waste by-products
0 Wastes from advanced coal utilization technologies, i.e., MHO, fuel cell.
Details of this program are still being formulated, though it is envisioned to
have three principal elements: acquisition of waste samples from emerging energy
facilities; laboratory characterization studies focused on trace metals and
organic compounds; and field studies to determine the actual fate of wastes and
leachates in the environment. In general, the technologies selected for these
studies will be prioritized according to their state of development, with
initial efforts expected to focus on coal gasification plants and atmospheric
fluidized bed boilers. A contractor recently has been selected to undertake a
waste sampling program for emerging energy technologies. Samples will be
distributed to several government laboratories that will be responsible for
characterization of the solid wastes and sludges. Details of this program are
still in the planning stage.
A request for proposals (RFP) recently was issued for the companion program of
field studies for disposed solid wastes from advanced energy processes. This
will be a major effort, intended to characterize the extraction and subsequent
migration of regulated constituents of advanced processes wastes, as well as
those factors which influence extraction and migration (such as soil attenuation
and evapotranspi ration). Sampling and monitoring at four sites over a several
year period are contemplated. This program is still in the procurement stage,
pending a revision to the original RFP. A start-up program is expected to begin
in late 1985. It will be highly complementary to another major field program
being carried out by the Electric Power Research Institute (EPRI), discussed
below.
Another project planned for this year involves the study of new methods for
extracting energy from existing coal preparation plant wastes. Such wastes
typically contain several percent of the feed coal heating value which is
unavoidably discarded with preparation plant refuse. This study will examine
the potential for extracting a liquid product based on pyrolysis of the wastes.
In another study, the feasibility of using energy derived from coal cleaning
wastes to generate sintering conditions capable of producing highly inert,
sintered granules of waste products of superior durability and resistance to
chemical attack will be investigated. Additional work on the characterization
of coal preparation plant wastes (physical cleaning processes only) also is
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189
planned for this year, focusing on the organic, inorganic, elemental and mineral
composition of the liquid and solid wastes from an Illinois No. 6 coal cleaned
by heavy media separation.
Longer-term DOE program plans call for continued emphasis on characterization
studies to identify potential environmental problems for conventional and
emerging energy technologies as early as possible. Development of new control
technology would follow in response to any identified needs. In the area of
conventional coal combustion, current projects are directed at studies of wastes
derived from low-rank western coals with high alkaline ash content. These
studies would expand the current data base on fly ash, bottom ash and FGD wastes
for conventional power plants. The analysis of institutional factors affecting
solid waste disposal also is envisioned within the long-term DOE program plan,
though no specific projects are currently underway.
Other Waste Management Programs
Within the federal government, the DOE/FE waste management program currently
represents the principal R&D activity concerned with coal utilization
technologies and related environmental control processes. While the EPA is
extensively involved in the regulation and management of solid and liquid
wastes, it is primarily concerned with hazardous and toxic materials, which do
not presently include coal-related wastes to any significant degree. Thus,
while EPA R*D programs in recent years have examined coal combustion and related
environmental control technology wastes in some detail, there is no continuing
R4D program in this area at this time. The last major effort was a recently
completed multi-year program of waste characterization and field studies to
determine the nature and fate of waste constituents from actual power plant
disposal sites, particularly as it related to the potential for groundwater
contamination. The results of this R&D study also are being used by the EPA
Office of Solid Waste Management in conjunction with regulatory requirements
under RCRA regarding the classification of wastes as either hazardous or non-
hazardous. While a comprehensive report to Congress on the situation with
regard to conventional power plant wastes still remains well behind schedule,
the results of tests to date have largely mollified earlier concerns that such
wastes might generally be found to be hazardous. Thus, current research efforts
at EPA related to the clean use of coal are directed primarily at advanced and
retrofittable air pollution control technologies, with little or no new work
currently planned in the solid waste area.
The largest private R&D effort in the U.S. related to the management and control
of coal-related solid wastes currently is found at the Electric Power Research
Institute (EPRl). Two major programs are underway. One is a long-term (10-
year) $50 million program of Solid Waste Environmental Studies (SWES) to develop
data and methods for predicting the fate of constituents present in solid wastes
at utility disposal sites. The ultimate goal of this project is to develop and
validate geohydrochemlcal models for predicting the release, transport,
transformation and environmental fate of chemicals associated with utility solid
wastes. It emphasizes basic studies of waste leaching chemistry; transport of
solutes in groundwater; chemical attenuation of solutes in the subsurface
environment; evaluation of existing predictive models; and evaluation of
groundwater sampling methods and related field measurement techniques. The
utility wastes currently being emphasized are fly ash, bottom ash, FGD wastes.
111
50-513 O— 85 7
190
mixtures of FGD wastes and ashes, and oil ash. Wastes which may be considered
in the future include those from coal cleaning, waste reprocessing, and advanced
coal combustion technologies. This program, begun in 1983, relates closely to
the planned DOE program of field studies of emerging energy technologies
scheduled to begin this year. Close communication between the EPRI and DOE
programs is anticipated, though they will remain separately funded.
A second EPRI effort, set to begin early this year, will focus on waste
management systems for five advanced methods of sulfur dioxide control for
electric utilities: atmospheric fluidized beds; furnace limestone injection; dry
sodium compound addition; spray drying of calcium; and advanced coal cleaning.
These are of interest because solid waste products from these processes have
physical and chemical properties different from those of fly ash or scrubber
sludge from conventional coal-fired power plants. For example, in all cases
except the coal cleaning residues, fly ash will be intimately mixed with sulfur-
bearing reaction products, and there will be a greater quantity of waste product
to handle. Compared to "conventional" wastes, those from calcium-based
processes will contain significant levels of unreacted lime, while sodium-based
processes will produce wastes with higher levels of soluble sodium compounds.
For coal cleaning refuse, the acidic nature of the leachate and its potential to
release heavy metals are among the areas of concern. In all cases, differences
in the nature of waste materials could require changes in current waste
management practices. This could have a substantial impact on the overall
economics and viability of these developing technologies. The objectives of the
EPRI study are thus focused primarily on the characterization of these wastes;
the design of appropriate waste management systems for each process (including
an evaluation of different liners that provide a barrier to chemical transport);
and the identification of potential by-product utilization methods and
applications for waste materials. These studies will involve the acquisition of
waste samples from various pilot and demonstration facilities, and will be
carried out over the next 3-4 years. The annual R&D budget for EPRI's waste
disposal programs is comparable to that of the DOE/FE Waste Management Program,
and is larger if waste utilization RfD also is included.
Finally, we note that a variety of other organizations, such as the National Ash
Association, also are involved in coal-related waste management RSD projects,
including studies involving the recycle or reuse of waste products. Similarly,
there have been substantial international activities in this area, both within
individual countries (particularly England, Germany and Japan), as well as
through international organizations (such as the lEA, OECD, etc.). While a
detailed survey of all coal -related waste management programs is beyond the
scope of this report, the interested reader will find many of these summarized
and discussed in the technical literature.
V. CONCLUDING COMMENTS AND RECOMMENDATIONS
The DOE Waste Management Program as it is currently conceptualized represents a
comprehensive and reasonable plan for addressing problems of solid wastes and
sludges generated directly or indirectly by coal utilization technology. Its
centerpiece is the characterization of wastes from conventional and advanced
(emerging) energy technologies and environmental control systems. Included here
are process emissions as well as laboratory and field evaluations of pollutant
transport in the environment. Control technology development is envisioned as a
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191
second major element of the program. This would be responsive to any unmet needs
jr problems identified by waste characterization studies, and would include
assistance and support to process development programs located in
jther parts of DOE. A third element of the waste management program design
involves the analysis of Institutional factors that may be critical to
implementing waste management measures. Finally, the dissemination of
information through reports, conferences, etc. represents the fourth major
element of the program.
In practice, however, the DOE Waste Management Program has rather limited
resources which substantially restricts the scope and nature of its activities.
Thus, it is perhaps more properly viewed as representing a minimum acceptable
effort to consider the potential environmental impacts of solid and liquid
wastes associated with conventional and advanced coal utilization technologies.
Fortunately, it is also complemented by an even larger R&D effort on the part of
the private sector. Given the current level of program funding (approximately
$2 million/year), and the DOE strategy of focusing R&D principally on long-range
energy technology, the current priority of the Waste Management Program (i.e.,
characterization of wastes from emerging technologies) is indeed appropriate.
In the past few years, however, the overall funding level of the Waste
Management Program has decreased by approximately one-third, with the
possibility of further reductions in FY 1986. This, at a time when the current
and potential future problems of solid waste disposal have increased in national
concern, and the recognition of "cross-media" environmental impacts -- in which
environmental problems are simply moved from one medium (i.e., air, water or
land) to another — has resulted in solid wastes becoming the final "sink" for
undesireable materials from coal utilization technologies. Thus, the ability of
the DOE program to adequately anticipate and deal with emerging environmental
issues in this area in a timely fashion bears continual scrutiny.
The elimination of programs seeking innovative means of waste utilization and
re-use is viewed with particular concern given the potential attractiveness of
this option and its importance in situations where the lack of suitable disposal
sites may limit or preclude certain energy alternatives. Projects of this
nature, ideally cost-shared with private industry, are recommended for
consideration in future DOE programs, along with the development of technology
for waste disposal.
Table 1 provides an estimate of the total R&D funding requirements needed in the
waste management area over the next five years. Included are private as well as
public expenditures for R&D to address problems of waste utilization as well as
waste disposal.
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192
ESTIMATED FUNDING REQUIREMENTS
FOR SOLID WASTE MANAGEMENT R&D*
(millions of dollars)
AREA/ YEAR 56 57 58 89 90 TOTAL
Waste 6 8 9 11 11 45
Disposal
Waste 2 2 3 4 4 15
Utilization
TOTAL 8 10 12 15 15 60
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193
6. PROJECTED COAL UTILIZATION IN THE UNITED STATES
by: Joseph Mullen
Total Coal Consumption
1400-
1200-
0)
z
o
1000-
800-
<n
z
o
600-
400-
n*vlUllullon
ModAfalt Qrewlh
SUgnallon
1973 1975
"~r"
1980
I
1985
YEARS
1990
1995
115
194
The two significant coal use areas are the utility and industrial markets, as it
is here that the efforts of the Clean Coal Panel can and will have its major
impact.
Electric Utility Market
Electric utilities, the principal market for coal, will continue to account for
more than 70% of total coal use through 1985.
TABLE I
Electric Utilities
900-
/
•
/
800 -
700 -
600 -
/^""^"^
500-
y
^
400 -
y
300-
^
RollilUallon
■^
Stagnation
1
1 1
1
1973 1975
1980
1985
YEARS
1990
1995
116
195
Coal's resurgence in the utility market in the post-1990 period results, in
large parts, from its perceived role as the only feasible option for new base-
loaded power generation. Although coal appears the logical choice, there are
uncertainties which could have a negative impact on its use: better load
management, cogeneration, conservation and plant life extension, no further oil-
to-coal conversions, imported electricity from Canada and imported coals which
reduce its competitive advantage, changes in public utility commission policies,
and costs of pollution control compliance. These factors are compounded by the
great uncertainty about future economic growth, structural changes in the
economy, and the price and availability of alternative fuels. The size of the
increase in utility coal demand through 1995 primarily will be determined by
electricity demand growth and economic growth. Increased coal use is also
sensitive to investment in coal-fired power plants and the competitiveness of
coal's delivered price. Investment hinges on decision maker's expectations of
future competitiveness of delivered coal. Delivered prices are also impacted by
production and transportation costs, public utility commission policies, and
costs of pollution control compliance.
Table I shows utility coal consumption in tons and average growth rates through
1995 under each of three scenarios — stagnation, moderate growth and
revitalization.
Table II shows a comparison of average annual growth rates for electricity
demand, by region and scenario.
TABLE II
COMPARISON OF AVERAGE ANNUAL GROWTH RAHS
FOR ELECTRICITY DEMAND, BY REGION AND SCENARIO
Forecast Scenario (1982-1995) NERC PROJECTION
NCA REGION Stagnation Moderate Growth Revitalization 1984-1993
+1.8
+2.1
+3.1
+3.9
+4.5
+3^1
+3.0 +2.7
Northeast
+1.1
+1.6
East North Central
+1.3
+1.7
Southeast
+2,0
+2.S
West North Central
+2.5
+3.1
West South Central
+2.9
+3.7
West
+2.0
+2.5
TOTAL U.S.
+1.9
+2.4
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196
Table III shows the total U.S. Electric Utility Capacity under the moderate
growth scenario.
Many questions have been raised relative to the present and anticipated size of
utility units. A review of information furnished by the utilities to the
National Electric Reliability Council and to DOE's Energy Information
Administration shows that large units appear to have peaked and that units in
the range of 500 to 600 MW, or even still smaller units, will play the major
role in new units expected to come on line through 2000.
TABLE III
TOTAL UNITED STATES ELECTRIC UTILITY CAPACITY,
MODERATE GROWTH CASE
(thousands of megawatts)
YEAR
COAL
NUCLEAR
OIL/GAS
HYDRO/OTHER
TOTAL
NERC Historical
1980
1982
237.1
252.3
50.8
55.7
206.8
196.0
78,4
82.1
573.1
586.1
Forecast
1985
1990
1995
276.2
291.8
325.0
82.4
111.6
117.3
209.0
214.0
221.7
87.4
91.1
94.9
655.0
708.5
758.9
Net Additions
1982-95
+ 72.7
+ 61.6
+ 25.7
+ 12.8
+ 172.8
A significant factor impacting on the decision to delay or cancel new units is a
relatively new trend directed at refurbishing existing coal-fired plants. A
recent APAA report noted that most utilities are postponing retirement of larger
units and are seriously beginning to consider the advantages of "refurbishing"
units to give them life for another 20 to 30 years. It was stated that small
operating units of 50 to 75 MW are likely to be retired while the 300-400 MW and
larger plants could last up to 60 years with refurbishment. A similar report by
a major equipment supplier calls attention to the fact that by 1990 20% of
the nations' power plants will be thirty years old or older.
Unfortunately, there is little substantive data available beyond the mid 90's,
but Figure I, based on data developed by EPRI, gives at least some insight into
the early part of the next century. Obviously, demand growth beyond the mid
90's remains a question, but extension of existing plant life continues to be a
significant factor.
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197
FIGURE I
ELECTRICITY SUPPLY AND DEMAND
B. Probable Scenario
GW Demand (thousands]
1.5
1.4
1.3
1.2 h-
1.1
1.0
0.9 H
0.8
0.7 H
0.6
n 3?o and 4% Demand Growth
Extend plant life 20 yrs
Reduce res. margin 5?o
1980 1985 1990
1995 2000
Year
2005 2010 2015
003077
119
198
The reductions in SO2 already achieved have been significant. For example, EPA
in February 1984 reported that nationally, total SO2 emissions dropped 26%
between 1973 and 1983. Emissions from power plants were down 17%, while utility
coal use grew by 53%.
Furthermore, emissions will continue to decline as older plants are replaced and
the results of the Clean Air Act's more stringent provisions on new plants are
felt. The Electric Power Research Institute estimates that, based on these
growth rates in electricity demand, SOp emissions from utilities will decline
another 25 to 40 % over the next two decades if the new clean coal technologies
discussed in this report are promptly implemented. If not, further SO2 emission
reductions will be substantially less. The Office of Technology Assessment
shows emissions declining steadily to about 50 % of current levels by 2015;
assuming a 40-year plant life, 2.5 % growth rate in demand and prompt
implementation of new clean coal technologies.
Certainly, another factor impacting on the degree to which a utility must
upgrade its existing facility is the acid rain issue. While no specific
legislation has passed in the Congress, many have questioned the need for
accelerated emission reductions based on the uncertain scientific base.
CONVERSION TO CUAL
Conversion of oil and gas fired units to coal offers an additional market
potential although there have been delays and cancellations. Many of the
conversions which took place in the 1970s (6,500 MWO involved fuel switching
by multi-fuel plants rather than significant modification of plant
facilities. All conversions to date have geen in the east, as is the case
for virtually all planned conversions as well. One utility in the west
(Arizona) currently plans to convert 267 to coal.
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199
CONVERSIONS BY REGION
COMPLETED CONVERSIONS (HW) BY REGION THROUGH 1983
New England
Massachusetts 1778 MW
Middle Atlantic
New Jersey 226 MW
South Atlantic
Delaware 234 MW
Florida 169 MW
Georgia 371 MW
Maryland 384 MW
Virginia 1920 MW
TOTAL 5007 MW
New England
PLANNED CONVERSIONS (MH) BY REGION
Connecticut 250 MW
Massachusetts 664 MW
New Hampshire 139 MW
Middle Atlantic
New York 750 MW
South Atlantic
Florida 361 MW
South Carolina 580 MW
Virginia 638 MW
Mountain
Arizona 267 MW
TOTAL 3649 MW
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200
Industriol/Retoil
150-
123-
100-
50-
1973 1975
/
RavtullZAIIon
ModoaK Qiowlh
1980
1985
YEARS
1990
1995
122
201
INDUSTRIAL/RETAIL MARKET
The Industrial /retail market of 72 million tons in 1982 is expected to expand
uniformly to 100-140 million tons in 1995. Future coal consumption depends not
only on economic recovery, but more importantly on the economy's capacity to
sustain growth.
Table IV gives some insight into the historical and projected industrial/retail
market through 1995 by region.
TABLE IV
INDUSTRIAL/RETAIL COAL CONSUMPTION BY REGION
(millions of tons)
CASE
Historical
1973
1980
1982
1985
Forecast
1990
1995
Eastern United States
Stagnation
Moderate Growth
Revitalization
Western United States
Stagnation
Moderate Growth
Revitalization
Toal United States
Stagnation
Moderate Growth
Revitalization
67
75
58
16
74
53
19
72
56
62
72
56
70
95
60
75
104
20
24
28
21
26
33
21
28
36
76
86
100
79
96
128
81
103
140
123
202
The industrial/retail market faces many of the same issues faced by utilities.
Of significance is the age of existing equipment. Table V shows that while 70%
of the industrial boilers utilizing oil or gas are 15 years old or greater, 95%
of the coal units are 15 years or older.
TABLE V
INDUSTRIAL BOILER AGE PROFILE
BY PERCENT OF FUEL TYPE, 1982
Less Than
Greater Than
15 Years Old
15 years Old
(Percent)
(Percent)
4.5
95.5
31.6
68.4
27.2
72.8
28.3
71.7
Coal
Distillate Oil
Residual Oil
Natural Gas
As noted, coal demand will continue to rise, but new coal fired units may play a
lesser role, with refurbishment units becoming a major factor. Thus, it appears
that in the near term, the efforts of the Clean Coal Use Panel may have a more
significant impact on the long term need to replace existing capacity with new
facilities.
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203
APPENDIX A
THE SECRETARY OF ENERGY
WASHINGTON DC 20585
April 27, 1984
Mr. Ralph S. Gens
Chairman
Energy Research Advisory Board
4046 SW Jerald Court
Portland, OR 97221
Dear Mr. Gens:
A vital component of the Nation's energy mix, coal generates nearly half of our
electric power and is a major industrial fuel. Since it is one of our most
plentiful resources, its use is expected to increase during the coming decades.
Finding ways to burn coal more cleanly and economically is a matter of very high
priority. It is essential that the Department of Energy focus its research and
development programs on those technologies that have the greatest promise, both
in the relatively near as well as longer term.
Many technologies are being explored by the Federal Government and the private
sector, in the United States and abroad, that could potentially be used to
limit the undesirable consequences of coal combustion. Technologies used
before, during, and after combustion are at various stages of development and
present differing cost and effectiveness uncertainties. In this regard, it is
important to understand the options available for replacement and retrofit of
aging plants with advanced coal use technology.
In order to improve our ability to deal with coal combustion technology, I am
asking the Energy Research Advisory Board to assess the status of the principal
technologies for the clean use of coal, including a comparative assessment of
their potential appropriateness in various situations. For each technology, you
should review:
0 the current DOE, private sector, and foreign R&D effort;
0 the relative cost-effectiveness of alternative technologies for the
clean utilization of coal resources;
0 the adequacy and timing of this work in reference to the national need.
This study should help to ensure that the R&D activities will provide an
adequate range of emission abatement technologies for application as they are
needed. The Assistant Secretary for Fossil Energy and the Director of the
Office of Energy Research will provide staff support and assistance for this
important task. I would appreciate your completing this assignment by
November 1984.
DONAL
204
Mr. Reichl. I think it would be helpful a little to spend a minute
on considering the scope of what we have said and where the R&D
efforts on clean coal use fit in the overall R&D picture. I believe
total Government expenditures in energy R&D range between $3
and $3.5 billion, of which the specific areas of interest would be
$150 million on fossil energy — that is the budget request for 1986 —
and out of that $150 million about $55 to $57 million is specifically
earmarked for clean coal use. I should admit there are various
ways of analyzing, or categorizing these numbers. This happens to
be the simplest one that I believe is valid.
What you can see here is that the percent of total Government
R&D spent on clean coal use is in the range of 1 to 2 percent of the
total. I think that is the important figure to remember for a
moment.
Now, as we have already heard, and I would like to reemphasize
this, there is really excellent agreement between what the Depart-
ment's in-house people say about the subject and what the ERAB
report says. The only point of disagreement is the one that has
been discussed here, which is a matter of policy and not of technol-
ogy selection or anything.
In a nutshell, the panel suggests that the figure should be in-
creased, and we are saying that because we expect, and I think
most people expect, the use of coal generally to increase as time
goes on. It is not a question of speeding up or increasing the use of
coal as the main concern, but rather to cleaning up the use of coal.
Coal is inherently a difficult fuel to use without some emissions,
and it is that area, which is really health related, which suggests
that an increase of attention should be given by the Government to
this area.
The assumption here — rather, the conclusion of the study was
that we expect that over the next 20 years coal use would remain
largely in the area of combustion, maybe up to 90 percent of use,
and that again the majority would be in large utility-type boilers.
The balance would be in industrial boilers, which are less signifi-
cant.
Now, equally important would be the fact we also expect that
over this same period most of this coal combustion will continue to
occur in existing boilers, and as a result, some priority should be
assigned to the issue of technologies to development and demon-
stration of technologies which can be retrofitted to the existing fa-
cilities.
To just repeat it again, the main problem as we see in the energy
picture for the next 20 years as it relates to coal is cleaning up the
existing stations. I think that is the message we would like to
leave.
Now, when it comes to how to do this the panel has noted, as has
DOE, that there is a wide range of alternate technologies which
must be considered, and the preferred answer will be extremely
site specific. There is no computer you can go to and prioritize and
say we have to go 1, 2, 3, because 1 is more important than 2. The
reasons why this is so depends on many factors at each site. And
just to name a few so that you get a feel for this, it is the size of
the plant, the age of the plant, remaining life of it, the type of
coals that are available, the price, the design of the plant that
205
exists, even the space that is available to add facilities to clean
up — all of those affect the preferred choice at any given site. So, as
Mr. Vaughan has said, a proper R&D Program should offer a
choice, the widest possible choice of alternate technologies.
Now, how does one then choose? And there I think the report
makes it quite clear. We say you leave that to the marketplace,
and the way that is expressed, as we suggest, is by the cofunding
that is being offered. I think that in itself will be a self-regulating
system by which those technologies which the private sector consid-
ers worthy of support will get support.
Of course we are coming to the point now where we have this
one point of disagreement. We feel that the R&D Program is ulti-
mately successful only if it is commercially accepted, and the key
step required for this varies, of course, between technologies and
industries. And there is a peculiar problem here. As we have said,
most of the coal use will be in large utility applications. The utility
industry is peculiarly sensitive to any innovation that puts at risk
the supply of electricity; therefore, its acceptance requires demon-
stration on a very substantial scale. That doesn't mean you always
have to go out and build a new plant from scratch. In most cases it
is using an existing facility, but a big one, to test a new technology.
That is quite costly.
Now, at the same time the utility industry has a research budget
that is prescribed by something like 50 different utility commis-
sions around the country. And while they do spend about $300 mil-
lion annually through their Electric Power Research Institute, this
is not enough in the view of ERAB to answer the problem that is
now before the Nation.
We certainly completely agree with DOE on the need to pursue
above all fundamental research and basic research related to coal.
There are several examples of it that are noted in the report, but
we have no disagreement with DOE in that area.
I had not planned here in any way go through the listing of the
individual subjects. That would take too long. You will find a good
discussion in the report on each area. But to give you a comprehen-
sive view, let me briefly sum it up this way. Mr. Vaughan just
mentioned that the total proposals received came up to a total cost
of $8 billion. That is not the kind of figure, of course, that we have
come up with here. What ERAB said is that if all the technologies,
and there are about 12 to 15 listed specifically, some areas that are
generic. If all of them were pursued through to commercial accept-
ance, through the demonstration level, the total cost of such a pro-
gram might be as high as $2.4 billion. That was the number we
came up with. That would be spent over a period from 5 to 7 years.
It is obvious that not all of these will see the light of day, so that
the total program in the end will cost much less than that. And of
course most important, that is not suggested as the amount of
money to be spent by DOE. I think we have been very aware of the
budget restrictions that the Department has to comply with, and it
is only our view, ERAB being an independent think tank, that we
think if you go from 1 Vi percent to something like 4 percent of the
total R&D budget, considering the importance of coal in the energy
picture for the next 20 years and the importance of the health
aspect and the cleaning up, that that would be a change in the em-
206
phasis that would be quite defensible. It doesn't say that you need
to get the money from any specific source. We did not get involved
in that.
I would also like to add a point here that I think is important. I
would think that it is important if you can somewhere get this
policy matter resolved, but I would be very concerned if we come
up with a set of specific technologies which are mandated by Con-
gress to be developed. I think that would be clearly the wrong
thing to do. I think the competence available to DOE in making
that decision is totally there; and furthermore, if you use the mech-
anism of cofunding as using a marketplace response to what is pre-
ferred, that would cover the issue of what is the right priority.
I would like to stop at this point and answer your questions.
[The prepared statement of Mr. Reichl follows:]
207
ICH. REICHL
ISMORE LANE, P.O. BOX 786, GREENWICH, CONNECTICUT 06830 . PHONE (203) 661-9723
THE ERAB REPORT ON
CLEAN COAL USE TECHNOLOGIES
Statement by Eric H. Reichl
May 8, 1985
before the House Committee on
Science and Technology,
Hon. D. Fuqua, Chairman
208
Mr. Chairman,
My name is Eric H. Reichl* and I am appearing before your
Committee to discuss some aspects of the report on Clean Coal
Use Technology about to be issued by the corresponding panel of
the Energy Research Advisory Board, or ERAB, of the Department of
Energy.
I have been a member of ERAB since 197 9 and I am the
chairman of The Clean Coal Use Panel which was established in
April 1984 in response to then Secretary Model's request. He
asked ERAB to review the subject and to recommend an appropriate
program for Research and Development for DOE.
We have been most fortunate in being able to assemble an
outstanding group of experts from within and outside ERAB, who
could bring to bear their wide experience with the several areas
of clean coal use. To give a logical structure to the report,
the subject which is quite broad and diffuse was divided into
three major sections: these are Pre-Combustion systems.
Combustion proper and Post-Combustion. Combustion was sub-
divided into Conventional Combustion, essentially pulverized
coal burners, and fluidized bed combustion, and a section on
solid-waste management was added. Further, to obtain a feel for
the scope of the future markets for coal and the specific clean
coal technologies to fit them, Mr. Joseph Mullan, V.P. of the
National Coal Association, joined the panel and prepared a
projection of coal utilization in the U.S.
Each area was then assigned to one or two panel members
for review and recommendations. The key individuals and authors
of their respective sections were as follows:
Coal preparation: Mr. William N. Poundstone, retired Executive
Vice President of Consolidation Coal Co. and Dr. Edward
Rubin, Director/Center for Energy & Environmental Studies/
Carnegie-Mellon University
Conventional Coal Combustion: Mr. John Land is, Senior Vice
President, Stone & Webster Eng . Co. and Mr. Frank
Princiotta, Director of Industrial and Environmental
Laboratory /EPA
Fluidized Bed Combustion; Mr. Kurt Yeaqer, Vice President/
EPRI-Coal Combustion Division
Post Combustion Control Technology: Mr. Larry Papay, Senior
Vice President/Advanced Engineering, Southern California
Edison Co.
V7aste Management; Dr. Edward Rubin (see above.
*A brief Resume of my experience is attached for your records.
209
Throughout the preparation of the reports the panel
members visited selected DOE facilities and received full
cooperation and help from DOE staff at all times. It is a
pleasure for me to acknowledge this assistance at this occasion.
And I would especially like to recognize the substantial time
and effort contributed by the panel members, all of whom are
heavily engaged in their regular activities in industry,
academia or in government service.
The seven separate sections of the report were circulated
for comments to all panel members,, and the entire panel met
three times for discussion to assure as good a consensus as
possible. A summary was prepared by me to highlight the major
findings.
The finished DRAFT was then submitted to the entire ERAB
for consideration at the quarterly meeting of the Board on
May 1-2.
Speaking now for the Coal Use Panel as a whole I would
like to point out for you the key findings about DOE ' s R&D
program on Clean Coal Use Technology, but before I list then I
would like first to set the stage by noting a few general
observations:
° An order of magnitude set of figures for all energy
related R&D expenditures at this time shows the following
figures in $ ' s per year:
Private industry, companies: $3,500.- Million (including
($3,000 MM for oil explo-
ration)
Private industry, regulated: $450.- Million (EPRI plus
GRI)
Government: DOE, Total: $3,100.- Million ('86 Request,
excluding weapons)
To this one might add, maybe $4-500 million/yr for
the Synthetic Fuels Corp. if it is permitted to complete
the limited program it has proposed.
Thus the total U.S. energy related R&n could approach
$8 Billion; $3.5 of this spent is spent by the government.
° The figure includes some $150 million requested by
DOE for FY '36 for Fossil Energy, of which some $55
million aim at Clean Coal Use. This then would represent
about l'i% of all Government R&D related to energy.
210
" In a nutshell, Mr. Chairman, the panel suggests that
this figure be increased by a factor of 2 to 3. This is
obviously not any massive rearrangement of the R&D budget
as a whole and should be achievable within the available
total funds.
" The panel suggests that in view of the quite obvious,
major and increasing, contribution the combustion of coal
will make to U.S. energy supply over the next 25-30 years,
it warrants immediate and significant attention, larger
than it is currently receiving. This applies both to
Government and the private sector. The evident need is
for improved cleanliness when coal is used as fuel.
That is the key message of the panel's report. Now
allow me to note a few observations made by the panel:
° Coal consumption in the U.S. will approach the
billion ton per year level in the early 1990 's. Some 80%
of it will be consumed by electric utilities and a good
part of the balance in industrial boilers and furnaces.
This combustion is THE coal use which requires
attention with main emphasis on the large utility coal
burner.
° Equally important is the fact that the bulk of this
coal combustion will continue to occur in existing
boilers. This then sets a priority on clean coal use
technology which can be retrofitted to existing
facilities.
" The panel further notes that there are a wide range
of alternate technologies to be considered and the
preferred answer will be extremely site specific. There-
fore there is absolutely no way to select one preferred
approach.
The relative cost effectiveness at any given site
depends on a large number of factors which will vary all
over the place.
To name a few: size of plant, age, type of coals
available, at what price, plant design, even available
space and existing or expected, regulations on emissions,
etc.
A proper R&n program must offer a choice of
approaches leaving selection of the technology to the
user.
211
" In effect the panel notes, that the marketplace will
be the best selection mechanism for choosing the tech-
nologies which deserve support.
In turn this is best determined by insisting on a
major private sector contribution and this must increase
as a technology moves into the critical and costly
demonstration phase.
*• This led the panel to a particularly important
comment on DOE ' s R&D policy.
No R&D program is ultimately useful unless it leads
to commercial acceptance. The key step required for this
varies of course among industries, but electric utilities
must be uniquely wary before any innovation can be adopted
and there is simply no way to bypass the need for large,
even full commercial, scale testing.
As matters stand, DOE policy has frequently kept the
Department from participation in such test-, or demon-
stration programs. The panel recommends, that DOE do
participate, or even lead, in such tests.
This does not deny the need for major private sector
contribution. In fact DOE may be a less than 50% contri-
butor, but DOE leadership is needed.
" The panel fully agrees with DOE on the urgent need
for increased exploratory and basic research. In fact our
fundamental knowledge has been exhausted and we badly need
new insights. DOE has unique capabilities in the several
National Laboratories which should be mobilized in this
direction. I want to be clear, the panel is not thinking
in terms of engineering, or process-development, but of
basic knowledge about the composition and distribution of
mineral matter in coal, its behavior in a flame, etc. One
of the finest examples of such work is the laser supported
combustion research at Sandias Livermore laboratory, to
give you a feel for the type of study we need.
DOE is quite properly planning to continue or even to
increase Basic Research in coal related subjects. Inci-
dentally, in terms of cost this is minor compared to the
overall budget.
° Tine obviously does not permit us here to go into any
detail of the several specific suggestions the panel made
in its report. I would like permission to place the
report into my testimony as an addendum and urge you to
read the individual sections where the rationale for the
various technologies is presented.
212
You will find near the end of each section a Table of
the order of magnitude, in dollars and time, required to
bring the technology to commercial acceptance. Be sure to
understand this is NOT the amount suggested for DOE
support, but the total cost of a program.
" To give DOE a ready comprehensive view these figures
were summarized in a table (on pages 15A to E) and to be
consistent, the total costs of a possible 5 year program
for the years '86 to '90 were given for each technology.
The total, about $2.4 billion includes:
$120 million for Precombustion, or cleaning
technology
$628 million for Conventional Combustion
$930 million for Fluidized Bed Combustion
$100 mdllion for Airblown gasifiers, or 2-stage
combustion
$562 million for Post-Combustion, flue gas clean-up,
and
$ 60 million for Waste Management.
It should be obvious, that not all of these options,
some 15 to 20 are discussed in the reports, will come to
fruition, thus the total spent woiild be substantially
less.
And finally, the report suggests an area of magnitude
contribution towards this overall program which might be
appropriate for DOE. The panel's figure is about 30%, or
$740 million over the 5 years. This compares to $275
million, DOE would contribute if the '86 Budget request
were maintained without change thru 1990. This corre-
sponds to some 2 3/4 times greater efforts in clean coal
use R&D than is now contemplated.
Although this is a major change for this program, it
is not major in the context of DOE's Total R&D budget.
But it is an important adjustment in emphasis which the
panel believes to be called for if we want to keep the
coal option open.
° I have tried to give you a brief overview of the E^AB
report on Clean Coal Use Technology and would like to
conclude by thanking the Committee for this opportunity to
present our views.
I shall be happy to try answering any questions you nay
have.
213
\ BIOGRAPHICAL RESUME: ERIC H. REICHL
Personal ; Born in Vienna, Austria, December 3, 1913
• U.S. Citizen - Married, two daughters
Education: Equivalent degree to MS Chemical Engineer
Technische Hochschule - Vienna, 1937
Employment:
19 38 Babcock & Wilcox Company
Field Engineer (construction)
1938-1944 Winkler-Koch Engineering Company, Wichita, Kansas
(and subsidiaries)
Research, plant design - construction, operations
194 4-194 6 • Stanolind Oil & Gas Company, Tulsa, Oklahoma
(now Standard Oil of Indiana)
Process research on synthetic liquid fuels
including tour of duty with U.S. Navy as civilian
technician to evaluate German synthetic oil in-
dustry - January - June 194 5
1946-1948 California Research Corporation
(Standard Oil of California)
Process Research - Petrochemicals
1948-1954 Consolidation Coal Company - Research Manager
1954-1962 Consolidation Coal Company - Director of Research
1962-1974 Consolidation Coal Company - Vice President, Research*
1974-1978 Conoco Coal Development Company - President
(subsidiary of Continental Oil Co)
Retired 12/31/78
1979- Consultant
Professional
Associations ; American Chemical Society
American Institute of Chemical Engineers
Member, National Academy of Engineers
Member, Energy Research Advisory Board (ERAB) /DOE
Past Member, Research Coordination Panel/Gas Research Inst.
Member, Gov't. Tech. Adv. Comm./USERDA 1973
Chairman, Coal Task Group/National Petroleum
Council Energy Study - 1972.
Chairman, Coal Conversion Panel/National
Academy Energy Study (CONAES) - 1977
Past' Member, Liaison Committee of International
Institute for Applied Systems Analysis
*Note : Consolidation Coal Company's research and development program
includes pipelining of coal; conversion to liquid, gases and
chemicals; sulfur recovery; continuous coking.
3/19/82
214
Mr. FuQUA. Well, thank you, very much. ^
On that point that you mentioned, in making the marketplace
the selection mechanism, from what you are saying you feel that
Congress should not get involved?
Mr. Reichl. Not in the sense of
Mr. FuQUA. Of specific technologies.
Mr. Reichl [continuing]. Specific technologies.
Mr. FuQUA. How would the marketplace work in this way? Could
you outline that to us as you envision it?
Mr. Reichl. Well, if the Department were to consider, say, the 10
technologies or areas that we have outlined, which they, them-
selves, have also selected of course, and tried to develop projects in
each area, and then ask for proposals to come in which require a
minimum of cofunding that is in the range that they feel appropri-
ate, and it ought to be very high. Then, that would be a practical
mechanism by which that can be achieved.
Mr. FuQUA. You also indicated that you felt that DOE probably
would be a less-than-50-percent contributor.
Mr. Reichl. Yes; I would have thought that on the whole in that
range. It wasn't I, please. That is the panel and ERAB that says
that. That a range of about one-third would be a reasonable figure,
although that need not apply to any one specific area. For the pro-
gram as a whole, a one-third contribution might be adequate.
Mr. FuQUA. Should we include that in the language, that it was
not the intent of Congress that any more than 50 percent be DOE
funding, or should that be a higher figure, or should we not address
that?
Mr. Reichl. I would think it is a
Mr. FuQUA. Congress is going to be concerned about that.
Mr. Reichl. Yes; I think your question is appropriate all right.
The problem is that different types of projects may call for differ-
ent levels of proper private sector contribution. And I wouldn't
know at this moment how to answer you.
Mr. FuQUA. Write a formula.
Mr. Reichl. Yes, how to write a formula. I would have thought
that the subject is of more importance at the larger scale tests.
That is obviously the problem. I would like to think about it a little
bit before I say anjdihing on that subject.
Mr. FuQUA. I would appreciate maybe getting your comments.
Mr. Reichl. Maybe I could do it in writing.
Mr. FuQUA. Yes, that is what I meant. In writing, after you have
had a chance to reflect on that. Because I think what you are
saying is a very important key as I look at it. You then determine
the technologies that are most available and that the people feel
have the best potential by the amount that they would be willing
to put up.
Mr. Reichl. Correct.
Mr. FuQUA. So that, along with the other technical part of it,
would be a very good criterion.
Mr. Reichl. It is self-controlling criteria, in answer to Mr. Wal-
gren's issue. To give you a good example, you will find in the
ERAB report a very large dollar figure on atmospheric fluidized
bed and an almost equal figure for pressurized fluid bed. It is quite
clear already from what Secretary Vaughan said that the atmos-
215
pheric bed could require relatively little further contribution from
DOE. It is, indeed, moving along well in the private sector. That is
not true for the pressurized.
So, a generic formula somewhere needs to be thought through
fairly carefully before we say anything.
Mr. FuQUA. Thank you very much.
Mr. Boucher.
Mr. Boucher. Thank you, Mr. Chairman. I have just a couple of
questions.
When Secretary Vaughan was testifying earlier today, he indi-
cated that one of the reasons the Department has made a recom-
mendation not to have Federal participation and cost sharing for
the construction of demonstration facilities for emerging clean coal
technologies is that it would place the Federal Government in the
position of competing with private industry that may be developing
these technologies on its own.
Now, it seems to me that he is wrong in that respect. That by
having the Government participate and accelerating the develop-
ment of these technologies, we are advancing the interests of the
industry as a whole. That is my personal position.
But I would be very interested in hearing what the Research Ad-
visory Board has to say about that. What is your view of the state-
ment that the Secretary made concerning the Government's par-
ticipation and whether or not that, in fact, is competition with the
private sector?
Mr. Reichl. Well, I would have to agree with Mr. Vaughan on
this, and I think maybe his answer wasn't quite properly under-
stood or clear. What he said was that in a specific case, suppose
you take a specific type of fluidized bed development which is being
pursued by a private company, and now the Government appears
on the scene and says, "We'll have another one that I think we will
support." That is, in effect, an unfair competition.
There have been several instances where the private sector has,
in fact, made its view known. Not only here, but at the Synthetic
Fuels Corporation we run into exactly the same problem. In coal/
water mixtures, for example, where we had classified, categorized
it as a proper subject for synthetic fuels development — and I was
the one who did it to some extent. However, we had some major
corporation say, "We are doing this job, we don't need your help,
please stay out of it." So we stay out of it.
I think that is applicable here. But where such an area is not yet
in the private sector I think there is no objection to do this here.
Mr. Boucher. I sense that the Secretary was using a philosophy
which would keep the Government from competing with private in-
dustry as a rationale for the Government not participating in cost-
sharing projects at all. Now, perhaps I misunderstood his state-
ment. But I would assume that your conclusion would not be to
that end.
Mr. Reichl. Would not be to that end. But I don't really think
that is what he meant.
Mr. Boucher. All right.
Mr. Reichl. I don't know what he meant.
Mr. Boucher. Well, I am certainly not asking you to speak for
him.
216
I notice that you suggest that market forces should drive the de-
cisions as to which particular projects are selected for Government
funding. Do you suggest that the indicator of the market's choice
would be the percent of private funding that would be forthcoming
for a given project? Should that, in your opinion, be the sole crite-
rion, or should there be other considerations?
Mr. Reichl. You have to. I think, blend several criteria that in
the final analysis become personal, and I don't know how you ever
override that. K the man in charge of the decision in DOE happens
to be in, you know, his Department says fluidized bed combustion,
in the final analysis he has to decide what he wants to support and
you have to live with his judgment.
The important thing is to have people that have good judgment,
and I think you are well-ser%'ed on that score. There is no computer
you can go to that really vsill come out and say that is the obN-ious
one to support.
Mr. Boucher. So while this would be a primar\" consideration,
the Department should not limit itself solely to an evaluation of
the percentage of private industry cost share in deciding which
projects to fund?
Mr. Reichl. Absolutely not. For instance, you have to see what
the competence is of the man who promotes it, sponsors it. You
have to look at the data base that is behind it. You know, one that
offers more money may have a much poorer data base, and that
may be an unreasonable risk. You have to finally live \s'ith the per-
sonal judgment of the people in charge, and I think we should be
perfectly willing to do that.
Mr. Boucher. Your testimony has a summar>- of the amounts of
funding that are being spent on coal research and development na-
tionwide. I wonder if you could give us some indication, if you have
this information available, of the amount of dollars that private in-
dustr]»- is spending on either precombustion or combustion coal re-
search and development.
Mr. Reichl. I certainly do not have that here. It is not an easy
figure to come up with precisely. I had in the testimony an overall
picture of about S3. 5 billion in energ\'-related research. Most of it is
in petroleum exploration. As far as the coal, the private sector
coal-related R&D. I can generically tell you from experience it is a
small amount compared to what we are talking about.
Mr. Boucher. Could you acquire those figures? Is that at your
disposal?
Mr. Reichl. WeU, let me say I could tr>-. Whatever help I need, I
am a one-man show. I don't have any access to that.
Mr. Boucher. Well, if it is possible to obtain it, I would be inter-
ested in seeing that. There is a coal company in my congressional
district which spends about SI million annually of its o\^ti dollars
on combustion research, which I think is a fairly substantial contri-
bution for one company to make. But I am not aware of what other
companies are doing. And if there were some way to collect that
information, it would be very helpful.
Mr. Reichl. I will try. There are several agencies that have made
a point of collecting it annually. Maybe we can get it that way.
217
Mr. Boucher. Thank you very much. I want to commend you for
the statement that you have presented this morning, and I, for one,
appreciate very much your conclusions.
Mr. Reichl. Thank you.
Mr. Boucher [presiding]. My time has expired.
Mr. Packard.
Mr. Packard. Thank you, Mr. Chairman.
In your testimony you indicated that only a small percentage of
the research and development in all of our energ\' areas is targeted
toward coal research. \\Tiat figure, or what percentage do you feel
our total research program in energy now is targeted toward coal,
and how much do you think should be?
Mr. Reichl. Well, oddly enough, it isn't quite as easy to come up
with a quick answer to your question. The specific budget request,
as I understand it, for fossil energ>' R&D in DOE is about SI 50 mil-
lion, which is down from S250 million last year. These figures vary
from month to month, and I have got to excuse myself if they are
not exactly precise. Of that, roughly one-third, or about SoO mil-
lion, is narrowly aimed at clean coal use.
First, let me say that there is, of course, coal-related research,
and you have got to classify it as that, in the S>Tithetic Fuels Cor-
poration, which is a very much larger figure. The reason being that
the kind of projects that are required to bring synthetic fuels on
are much larger than those demonstrating clean coal use technol-
ogies. Order of magnitude, over there you are looking at projects
costing a half to SI billion class. For development to commercial
scale of clean coal use, you are looking at the S50 million to S200
million class. Order of magnitude. That is total cost, not per year,
of course.
Now. the question you asked, is the percent, is the distribution of
R&D effort that DOE places on, say, fusion, nuclear, coal, oil, ap-
propriate? The first thing you have got to recognize is that differ-
ent technologies require totally different amounts of money. The
fact that w^e spend, say, half a billion annually on fusion, all of it
government money, simply reflects the fact that that is the level
that you must have to make any progress. Conversely, that is not
required for coal.
I don't, again, think I can come up with a proper figure of what
is an appropriate percentage of the total. But I do think v^dthin the
fossil area I can do so. I feel that the distribution that DOE has in
the clean use versus the rest of fossil is too low, and that a dou-
bling of that effort would be appropriate.
Mr. Packard. In foreign countries, because of a variety of rea-
sons, perhaps lower en\'ironmental standards than the United
States has. the use or the consumption of coal I think generally is
higher than it is in the United States, per capitavsise at least.
Is foreign research and development ahead of or equal to or lag-
ging behind or the commitment greater than we have here in the
United States?
Mr. Reichl. I don't think that we have to apologize for our level
of effort. I think it is often claimed that it is higher over other
places. I don't think that is really right.
But the point you made I don't think is quite clear. Japan, for
instance, as far as I know has tighter rules than we have in many
220
will be reflected in future Government policy. And you and the
members of your committee deserve tremendous credit for what
you have put together.
Thank you, Mr. Chairman.
Mr. Reichl. Thank you.
Mr. Boucher. Thank you, Mr. Walgren.
Mr. Reichl, we appreciate very much the contribution you have
made and your presence here today.
Mr. Reichl. Thank you.
Mr. Boucher. Our next panel will consist of Mr. Gene Mannella,
the director of the Electric Power Research Institute's Washington
office; Mr. David O. Webb, senior vice president, policy and regula-
tory affairs, of the Gas Research Institute.
In view of the time, the Chair would ask the witnesses to please
restrict their opening statements to approximately 10 minutes.
Without objection, the full statements of the witnesses will be
made a part of the record.
The Chair recognizes Mr. Mannella.
STATEMENTS OF GENE G. MANNELLA, DIRECTOR, WASHINGTON
OFFICE, ELECTRIC POWER RESEARCH INSTITUTE, WASHING-
TON, DC, AND DAVID O. WEBB, SENIOR VICE PRESIDENT,
POLICY AND REGULATORY AFFAIRS, GAS RESEARCH INSTI-
TUTE, WASHINGTON, DC
Mr. Mannella. Thank you, Mr. Chairman. Thank you for the
opportunity to appear here today and present testimony. I have a
very complete statement by Mr. Kurt Yeager, the vice president of
our coal combustion systems division, which I would ask be insert-
ed in the record in its entirety.
Mr. Boucher. Without objection.
Mr. Mannella. And I certainly express my thanks for allowing
me to pinch-hit for him. As of 8 o'clock last night, he was still
trying to figure out how to get from San Francisco, to Washington,
to Beijing. He couldn't make it, so I am sitting in for him.
We have testified before on this subject, and I think that we have
covered it rather extensively. What I would like to do today very
briefly is to make a number of points. None of them are really
new, but perhaps in putting them in the order that I composed
them our support for this program will become clear.
First, coal is our most abundant energy source.
Second, 80 percent of the coal produced in the United States and
90 percent of the coal actually utilized in the United States is for
production of electric power.
Third, electricity consumption has grown at almost exactly the
same rate as the GNP over the past 10 years; that is, about plus 29
percent, even though the total energy usage during this period
dropped by 1 percent because of extensive conservation measures.
Fourth, an average annual electricity usage increase of 2.5 per-
cent per year will result in the need for 100,000 megawatts of new
capacity by the year 2000.
Fifth, to meet any new demand, coal will almost certainly be the
fuel of choice.
221
Sixth, environmental concerns cast a cloud over the degree to
which coal utilization technologies must be upgraded to be viable
options.
Seventh, advanced technologies for clean coal combustion are
and have been under intensive development.
Eighth, these technologies must be demonstrated at utility scale
in order to penetrate the marketplace.
Ninth, because it is an economically regulated industry where
risk and reward are decoupled, the utility industry cannot under-
write the total cost of demonstrating these technologies on the
scale and in the timeframe that will probably be required.
Tenth, and last, since an adequate, dependable supply of environ-
mentally and economically acceptable electric power is a national
imperative, the Federal Government must underwrite a portion of
the cost and risk of bringing new clean coal technologies to the
marketplace in an expeditious fashion.
Mr. Chairman, it is for these reasons that we support the Nation-
al Clean Coal Technology Initiative.
I would be happy to answer any questions you might have.
[The prepared statement of Mr. Yeager follows:]
rin-.nia O-
222
TESTIMONY
BY
KURT E. YEAGER
VICE PRESIDENT, COAL COMBUSTION SYSTEMS DIVISION
ELECTRIC POVJER RESEARCH INSTITUTE
BEFORE THE
ENERGY DEVELOPMENT AND APPLICATIONS SUBCOMMITTEE
COMMITTTEE ON SCIENCE AND TECHNOLOGY
tT.S. HOUSE OF REPRESENTATIVES
MAY 8, IPRS
223
ntroductorv Statement
fr. Chairman, Members of the Subcommittee:
• am Kurt E. Yeaqer, Vice President and Director of the Coal
'ombustion Systems Division of the Electric Power Research Insti-
•ute (EPRIK I appreciate this invitation to meet with you to
iiscuss promisina clean coal technologies and opportunities for
■heir accelerated development and application. These opportun-
ities have siqnificant implications for the electric utility
industry and therefore are of qreat importance to EPRI.
rhe Electric Power Research Institute was established by the
:'lectric utility industry in 1972 to conduct a broad research
and development proqram for the entire electric utility industry
and its rate payers. EPRI's R&D mission is to develop new and
improved technologies for electric power production, delivery and
jse, and to help accelerate their availability to insure an ade-
quate supply of economic, reliable and environmentally accept-
able electricity.
RPRI is supported hv voluntary contributions from investor-owned,
novernment-owned and cooperatively-owned electric utilities
across the nation. During the next five years, FPRI will direct
over «;5«?n million to improving coal utilization. This commit-
ment is based on the premise that coal utilization and environ-
mental protection are mutually compatible and that improved
technoToqy is the key to compatibility. Answers are urqently
needed for the important questions concernino coal utilization
and the environment, if we are to make effective decisions con-
cerning the stewardship of our national resources. Accordinnly,
EPPI and the utility industry are focusing on three fundamental
issues:
Defininq what resources are at risk.
Developinn the technoloqy necessary to
control these risks.
Determining where and when control measures
can be most effective.
The scope and urgency of this effort, however exceeds the
capability of the private sector alone, and will require
an accelerated national effort.
Current environmental control capabilities must also be improved
by reducinq capital and operatinq costs and preservino overall
plant productivity. The importance of this effort is under-
scored by the fact that approximately 40% of the capital invest-
ment and 30% of the total cost of power for new, coal-fired power
plants are related to environmental control. This includes sul-
fur dioxide (SO-) scrubbing, particulate control, solid waste _
disposal, water treatment and plant cooling. These controls in
their current form have a maior impact on plant efficiency and
222
TRSTIM0^7y
BY
KURT E, YEAGER
VICE PRESIDENT, COAL COMBUSTION SYSTEMS DIVISION
ELECTRIC POVJER RESEARCH INSTITUTE
BEFORE THE
ENERGY DEVELOPMENT AND APPLICATIONS SUBCOMMITTEE
COMMITTTEE ON SCIENCE AND TECHNOLOGY
U.S. HOtJSE OF REPRESENTATIVES
MAY R, 1985
223
introductory Statement
Mr. Chairman, Members of the .Subcommittee:
I am Kurt E. Yeaqer, Vice President and Director of the Coal
Combustion Systems Division of the Electric Power Research Insti-
tute (EPRI). I anpreciate this invitation to meet with you to
rliscuss promisina clean coal technologies and oonortunities for
their accelerated development and application. These opportun-
ities have significant implications for the electric utility
industry and therefore are of qreat importance to EPRI.
The Electric Power Research Institute was established by the
electric utility industry in 1972 to conduct a broad research
and development program for the entire electric utility industry
and its rate payers. EPRI's R&D mission is to develop new and
improved technologies for electric power production, delivery and
use, and to help accelerate their availability to insure an ade-
quate supply of economic, reliable and environmentally accept-
able electricity.
FPRI is supported bv voluntary contributions from investor-owned,
aovernment-owned and cooperatively-owned electric utilities
across the nation. During the next five years, EPRI will direct
ove r "^sqn million to improving coal utilization. This commit-
ment is based on the premise that coal utilization and environ-
mental protection are mutually compatible and that improved
technoloav is the key to compatibility. Answers are urgently
needed for the important questions concernina coal utilization
and the environment, if we are to make effective decisions con-
cerning the stewardship of our national resources. Accordinnly,
EPRI and the utility industry are focusing on three fundamental
issues:
Defining what resources are at risk.
Developinn the technoloav necessary to
control these risks.
Determining where and when control measures
can be most effective.
The scope and urgency of this effort, however exceeds the
capability of the private sector alone, and will require
an accelerated national effort.
Current environmental control capabilities must also be improved
by reducing capital and operating costs and preservinn overall
plant productivity. The importance of this effort is under-
scored by the fact that approximately 40^ of the capital invest-
ment and 30* of the total cost of power for new, coal-fired nower
Plants are related to environmental controH This includes sul-
fur dioxide (SO-,) scrubbing, particulate control, solid waste ^
disposal, water treatment and plant cooling. These controls in
their current form have a maior impact on plant efficiency and
224
reliahilitv. Closelv associated with this issue is the increas-
ina riifficultv in sitina new utility and other enerav facilities
Since its inceotion, EPRI has worked with the Department of
f!;nerav (DOE and its predecessor aaencies), the Environmental
Protection Aqency, and other Federal agencies with enerqy
research and development responsibilities to achieve mutual
technical objectives. In the spirit of that lonq-standina
cooperation, EPRI and others recommend an accelerated national
proqram to better understand the environmental issues constrain-
inq the use of coal and to develop, demonstrate and promptly
apply improved, clean coal technology. This effort would build
on activities already underway within the Federal and private
sectors. The Clean Coal Technoloqy Initiative and the result-
ing November 1984 DOE solicitation for opportunities in emerq-
inq clean coal technoloqies is responsive to this recommen-
dation.
The Role of Coal
Coal is by far our most abundant domestic fossil fuel resource
and has been the cornerstone of the national qoal to achieve
increased enerqy self-sufficiency under each of the last four
administrations. The imperative for coal has qrown ranidly over
this period as the reliability and security of our petroleum
supply has become more uncertain and the nuclear power initiative
has been increasinqly delayed. Today 75% of the 90n million tons
of coal produced annually in the United States provides about fiO%
of our electricity. This qrowinq interdependence of coal and
electricity reflects the unique opportunity that electricity pro-
vides to transform coal into a versatile, broadly available,
enerqy form.
Despite its abundance, coal has never been the most desirable
fossil fuel form. It contains less enerqy per unit mass than
natural qas or oil, it is cumbersome to transport and it has
created a variety of environmental issues. As a result environ-
mental requirements have joined cost reduction as the primary
consideration in the design and operation of coal-fired power
plants and are the drivinq forces pushing coal utilization tech-
noloqy in new directions.
Conflictinq perceptions about the effectiveness of clean air
proqrams, which have already produced a 33% reduction in
emissions, have driven the emission control debate for the
last several years. in essence the debate has been reduced
to an arqument over which sources should be forced to
further control S0~ emissions, by what means, and at whose
expense. with the qrowinq understanding of the complex
interaction amonq pollutants, the strict S0_ focus no lonqer
seems as relevant. Instead, the nation should be concen-
tratinq on develoninq'^^n -effect ive, sustained strategy to
maintain and continue the substantial progress which has
225
been made in all aspects of eTiission control. An impor-
tant element is viaorous aoplication of the new coal utili-
zation technoloaies which combine emission control with the
combustion or conversion process.
The utility industry has been a leader in this effort and as
effort.
Current Limitations
Throuqh one qeneratinq technoloqy or another, coal must play a
larqer role in meetinq the qneratinq needs for the rest of the
century and beyond. Rut the ways in which utilities are able to
use coal will have important imoacts on their ability to install
needed canacity, on the nrice of electricity and on the environ-
ment .
Conventiona] pulverized coal units todav are the onlv avail-
able technolooy that has been proven for the Generation of
larqe amounts of electriity. In the circumstances now facinq
the industrv, these conventional coal nits with their Federally
mandated flue qas scrubber have maior disadvantaqes. Because
these units are characterized by economies of scale, they are
relativelky larqe units requirinq lonq construction periods
and larqe caoital investments. (A typical new 1*]^^^ '^W power
plant will cost over SI. 3 billion). About 40% of this invest-
ment will be for environmental control. Licensinq and con-
struction may take eight years or more.
The most technically and economically visible element of environ-
mental control on today's pulverized coal-fired power plants is
the flue qas desulf urization system or "scrubber." Wet scrubbinq
is a simple concept, but in practice is complex and expensive.
An alkaline reaqent, usually lime or limestone, is mixed with
water to form a slurry and then sprayed into the flue qas pro-
duced by the coal combustion process. The sulfur oxides present
in the flue qas are absorbed in the slurry, and calcium sulfite
and/calcium sulfate (qypsum) precipitates out for disposal or
use. Alternate, but more expensive, options can transform the
absorbed sulfur oxides into sulfuric acid or elemental sulfur.
This technolooy has been defined by the V,'^. Environmental Pro-
tection Aoency (FPA) as the "Best Available Control Technoloqy"
for the required control of sulfur oxide emissions. It has been
effectively required on all new Dulverized coal-fired power
plants since 1^T7 . As a result, the U.S. electric utility indus-
trv is today operatinq IIQ of these wet scrubber systems on over
5n,ono MW of coal-fired boilers. Unfortunately, scrubbers have
proven to be amonq the most costly and least reliable pieces of
equipment Tn the utility industry.
226
In a new power olant, the scrubber will comraonly cost 5140 to
S17S/kW. In an apolication to an existing plant it typically
costs 10-40% more, but this premium may be as hiah as 100%,
Hioh cost derives from more than desian and construction.
Scrubbers yield larqe volumes of wet waste reguirina extensive
land areas for ponds or landfills, for example, about one square
mile a foot deep for each year of operation by a 1000 MW power
plant burnina 3% sulfur coal. This is a significant environ-
mental side effect of today's flue qas desulf ur ization systems.
Scrubhinq also uses huqe amounts of water (1000-3000 qal/min),
and these processes still often have problems with pluqqinq and
foulina of equipment and corrosion of fans and ductwork down-
stream, matters that add to ooeratinq cost and reduce power plant
reliability. Pinally, scrubbers extract a penalty of 3-R% of
plant output enerqy, simply to run pumps, fans, and flue qas
reheat systems, and maintenance costs are two to twenty times
that of the rest of the power plant.
Some years aqo, Federal leadership for the development of im-
proved flue oas cleaning systems was transferred to the nnp.
This was applauded as a prooressive step promotinq resolution
o,f the technical problems limitinq the effectiveness of
Federally mandated control technoloqy. Unfortunately, very
little Federal participation has been achieved, althouqh
many opportunities exist. The effectiveness of government
participation will depend on a much more aggressive R&D policy
which focusses on the key problems and iointly commits to the
major technology projects reguired for their resolution.
By comparison, EPRI alone is investinq annually more than four
times the current DOE effort in flue qas cleaning technoloqy.
The Need for New Technoloqy
From the time of Thomas Edison's first electric qeneratinq
station in 18S0 to the 1960s, the pace of coal-fired power
plant technoloqy advancement continued at a remarkable rate.
Efficiency increased eight fold while power plant size in-
creased by a factor of 20,000 over this period. Power plant
costs dropped in correspondim fashion. Over the past 20
years, however, further progress has stagnated in the face
of a variety of new constraints including escalatinq capital
cost, declininq construction productivity, new environmental
control requirements, declininq coal quality, and licensinn
delays. As a result, it costs three times more today, in
constant dollars, to install a kilowatt of coal-fired electric
generatino capacity than in 1967 and even more than in 1920.
This, in turn, is reflected in rising electricity rates. In
short, the fruits of technical progress achieved in the SO
years prior to 1967 have been lost in the past 17.
Based on these changing realities, only a fundamental improvement
in coal-fired power plant technoloqy can effectively respond to^
the qrowinq constraints on coal-fired power generation and
restore economic progress in electricity production.
227
As a result, the electric utility industry stands today at a
threshold of chanqe in its technological base for coal-fired
power qeneration. Successful new technology must satisfy two
basic and interconnected requirements.
a. Reduced Cost and Risk This requires modular oower plants
that can he ranidly constructed over a range of sizes
to better match demand growth, and can utilize
a wide range of coal quality in a single design.
h. Improved Environmental Control. This reguires tech-
nology that can meet existing and emergino environ-
mental requirements while minimizing the need for
expensive, inefficient "band-aid" control hardware
such as scrubbers.
An accelerated, two-oronqed approach to achieve this transition
is necessary: First, promptly transfer improved coal technolooy
from development to application and second, extract the last^
measure of performance from the existinq electricity qeneratinq
base to span this transition period. Copino with this transition
will require an immediate and intensive commitment over the next
"five years on the part of the utility industry, its suppliers and
'government if we are to assure electricity supply and control
cost while protecting the environmentV
The urgency of this ioint commitment is underscored by the chal-
lenge to the nation's electricity supply capability over the
remainder of the century. For example, the electricity gene-
rating capacity currently installed or assured of construction
completion will only support an average growth rate in elec-
tricity demand of less than one percent per year over the
remainder of the century. By comparison, electricity demand
over the turbulent past 12 years increased an average of 2.3%
per year. This period saw two oil-interruptions, dramatic
escalation in energy costs, resulting economic recessions, and
maior efforts in enerqy conservation.
Based on this recent experience, we can expect electricity
demand to continue to pace economic growth. Satisfying even
modest growth over the remainder of the century will reguire
a balanced strateqy involvino additional improvements in
conservation and end use management, greater productivity from
existing generation capacity (reliability and life extension),
plus new generation capacity. Assuming such a balanced strateqy
can be implemented, the nation will still require inn,nnn to
200, nnn mw of additional new capacity this century, essentially
all of which must depend on coal. New clean coal technoloqy now
under development could reduce the cost of this capacity by 30*
to 50%. Time is of the essence, however, if this improvement is
to be realized in time.
A particular element at risk in this overall strategy is life
228
extension for existinq plants. Despite the problems that aainq
units present, utilities are often finding it less costly to
refurbish existinq units than replace them with new capacity.
As a result, 115,000 MW of existinq capacity is expected to be
more than 40 years old by the end of the century. This important
qeneration component would be reduced drastically, however, if
utilities were required to add flue qas scrubbers and other
costly emissions control equipment to those units. In that
event, the number of retirements would increase sharply
because of the cost and the fact that in some cases the addi-
tional equipment could not he physically accommodated. This
would correspondinnly increase the requirement for new capacity.
Rv comparison, essentially no new electricity qeneratinq capa-
city has been committed over the ]ast several years and very
little additional is planned for commitment over the next five
years. This reluctance to invest in new power plants reflects
their rapidly escalatinq cost and the lack of risk compensat inq
incentives for requlated utility investment. The result has
been a virtual elimination of capacity additions from the indus-
try's qenerativon planninq process for the 19Q0s. Unless prompt
action is taken to reduce the present disincentives to capacity
addition, includinq reducinq the risks of demonstratinq and
introducinq new, less costly and more environmentally effective
technoloqy, it is probable that inadequate electricity capacity
will result this century.
Technology Options
The inefficiencies and cost of current flue qas scrubbinq tech-
nolooy coupled with the uncertain possibility that existinq
plants may require retrofittinq of further emission control leads
to the need for new, simplified emission control options. These
ranqe from improved physical coal cleaning, to low NO
combustion, furnace sorbent injection and dry scrubbinq. No one
of
these
options
will
satisfy the
wid
ely
varying condi
tions over
the
ranqe of exis
t inq
coal
-fired
util
ity
and industria
1 powe r
plants.
As a set
, however
, they
can
substantially red
uce the
cos
t and
productivity
limi
tations
of
emission control
today.
Selection will depend on a number of variables includinq control
requirements, cost and functional criteria such as plant desiqn
and space limitations. This third cateqory can be a particularly
important constraint when considerinq retrofit to existinq
plants. Unlike new plants where the boiler and emission con-
trols can be desiqned as an inteqrated unit, retrofit requires
adaptation to a plant not desiqned for such modification. This
can lead to compromise and additional expense.
The more effective approach is the use of new coal utilization
technoloqies such as fluidized bed combustion (FBC) or qasifi-
cation combined cycle (GCC)~ These technoloqies combined emis-
sion control within the combustion or conversion process. The
result is both qreater emission control efficiency and improved
229
generation productivity to f undaFientally resolve conflicts be-
tween enerqv and the environment. This underscores the value of
economic and requlatory incentives that encouraae prompt tran-
sition to these improved coal utilization options.
The principal appeal of these technologies is that they directly
address the maior factors affectinq coal-fired power generation -
notahlv, cost and emission control. Combining emission control
with the combustion or conversion process is inherently less
costly, less energy-intensive and more efficient than removing
pollutants from the flue gas. As a result, they are a more
effective use of national re"sources than additions of flue gas
(iesulf ur ization systems to current coal-fired capacity.
Piaures la and lb compare the short duration and relatively
limited control capability of retrofit control reguirements with
the much greater potential of these new clean coal
technologies. For example, proposed acid rain control
legislation that would retrofit flue gas scrubbers on up to
inn,noo mw of existing, high sulfur coal-fired generating
capacity would cost the nation !>2no billion over the remaining
life of the affected plants. A more effective alternative would
be introduction of new, clean coal technologies that offer
greater emission control efficiency and improved generation
productivity. If the S20n billion necessary to implement the
scrubber retrofit strategy were instead invested on plants using
advanced coal technologies, it would provide about half of the
new generating capacity the nation is likely to reguire over the
next 30 years. Such an investment in advanced clean coal
technology would at the same time provide superior environmental
control, not only for sulfur oxides but for nitrogen oxides and
solid waste as well"! while also improving the productivity and
cost of power generation.
The most effective national coal utilization program therefore
should have four maior obiectives. Based on the existing
development foundation, all four obiectives can be achieved
within the next five years. It will reguire, however, a maior,
ioint private/Federal effort to share the costs and risks, par-
ticularly at the technology demonstration scale.
a. Fstablish a sounder scientific base to guide the
nation on the needs and appropriate timing of
emission controls.
h. nemonstrate the array of potentially more effec-
tive retrof ittable emission control alternative's"
to current flue gas desulfur ization ( scrubber)
technology.
c. Demonstrate the advanced coal utilization technologies,
e.g. atmospheric fluidized bed combustion, pressur ize"d"
fluidized bed combustion, and gasification combined-
cycle, over a sufficient range of conditions to establish
230
performance, cost, and reliahility.
d. Estahlish incentives to encourage the prompt commercial
implementation ot these technoioqies.
In order to meet these objectives, the utility industry, its
suppliers, and FPRI, have therefore jointly proposed over S2
hillion in joint demonstration projects to OOE. Only 3»^ of
the required funding would he Federally provided. These are
in response to the November, TW^ noR program announcement on
emerging clean coal technoioqies.
These proposed projects are remarkably consistent in scope and
cost estimate with the independent recommendations of the DOF's
Energy Research Advisory Board (ERAR) Panel on Clean Coal Use
Technoioqies which encouraqes expanded nOE participation in coal
technology development and demonstration. These projects reflect
both the broad scope of opportunities to expand improved coal
utilization and the major investment which the utility industry
and its suppliers are prepared to make in developing and demon-
strating these improvements. Table 1 and the Attachment des-
cribe these opportunities in more detail.
The EPRI Contribution
For EPRI this means accelerating our already substantial R&D
effort in environmental assessment, clean coal technology, and
as a management focus for utility coal utilization projects.
For example, EPRI funding for clean coal resarch development
and demonstration during the period 1985-1989 will encompass
the following effort:
1985-1989 EPRI
Expenditures (Million?)
Environmental Assessment 78
Power Plant Performance Imnrovement 41
Coal nuality 43
Emission & Effluent Treatment 139
Fluidized Bed Combustion 127
Coal Conversion 164
582
This represents one-third of the Institute's planned budget over
the next five years and is in addition to the over S500 million
already spent by EPRI on these R&D programs. The breadth of this
program reflects the great diversity among utilities in their
generating mix, environmental requirements, fuel availability
and cost. No single technology can satisfy all situations. A
flexible selection of clean coal options is essential to a
healthy and responsive electric utility industry in thel990s
231
and bevond. Over half this total will be directed to technoloqy
demonstration orojects.
EPRI has been pleased to he both a partner and a catalyst over
the past decade to accelerate the commercialization of clean
coal technoloqv. An important question which must be resolved
before large scale application of these options can proceed Fs"
proof of their long term reliability under utility operating
condi t ions. The FPRI program, therefore, stesses the demon-
stration of these options at sufficiently large scale to verify
their commercial reliability. In the case of the atmospheric
fluid bed combustion and coal gasification, ioint private/
Federal efforts with EPRI have culminated in the necessary
commercial demonstrations as indicated by the Cool Water gasi-
fication combined cycle proiect and the three AFBC demonstra-
tions with TVA, Puke Power and the State of Kentucky; Northern
States Power; and Colorado-Ute Rural Electric Cooperative. It
is the Federal participation with the private sector during
development and prototype testing which has helped provide the
confidence for these demonstrations to proceed under private
sector initiative. In addition, sustained Federal participation
in both Cool Water and the TVA AFBC demonstration has been cru-
cial to the prompt implementation of these pioneer clean coal
utilization projects.
It is Federal participation as a risk sharing investor in demon-
strations initiated and managed by the private sector which has
been the key to the successful government/industry partnership
in these projects. The success of this approach provides a con-
fident prototype for the necessary continued joint Federal/indus-
try effort in clean coal technoloqy commercialization.
The Clean Coal Technology Reserve provides a mechanism to extend
this Federal participation to other deserving clean coal tech-
noloqies. In its absence opportunities on coal cleaning, pres-
surized fluidized bed combustion and other combustion improve-
ments as well as environmental control technology will be con-
strained from application. All of these opportunities can have
a fundamental impact on the quantity and quality of coal utili-
zation and electric power qeneration over the coming years.
Issues Facinq the Private Sector
The role of the private sector in carryinq out this R&D must
consider the unique aspects of the primary usinq industry-the
electric utilities and their technoloqy suppliers:
o The electric utility industry is a financially stressed,
regulated industry. Rates of return are regulated and
therefore, profits do not necessarily reflect risks to
investors.
o Major financial risk is associated with incorporation of
innovative technoloqy into an established and complex
232
electric power system that must remain economical and
reliable. The task of ensurino that planned capacity
additions are sufficient to meet suply has tranditionally
been the province of utility mananement, but the disincen-
tives to investment have forced manaaement to place first
priority on delayina commitments to new plant. ■
o TJtility supplier firms are not assured of a sufficient
"return on R&D investment to maintain technical leadership
in the current limited domestic market situation. R&D is
only the first step in a proiect which, if successful, will
reaiiire time and order-of-maqnitude qreater expenditures for
enqineerinq, manu^acturinq , marketino and capital before a
profit is realized. The possibility of chanqes in qovernment
policies over the period further amplifies the risk.
o Energy tax credits for new technoloqy, permitted by other
industries, are not available to electric utilities. This
is at a time when the utility industry must assume a qrow-
inq leadership for the development of its essential tech-
noloqical improvements. Contrary to popular conception,
the utility industry is one of the most technoloqically
intensive and it is technoloqy which must solve the diffi-
cult demands of the future.
o The producers and users of coal represent hiqhly diversi-
fied and decentralized industries. This reality presents
a special problem in both the ranqe of technoloqies necessary
to meet the diverse needs and the ability to focus sufficient
resources. EPRI has provided a unique capability for a larqe
fraction of the utility industry but it is unable to satisfy
the industry's needs under the present requlatory and invest-
ment environment.
o Financial problems facinq the industry and its inability to
qenerate capital funds for improvement or expansion makes
additional R&n fundinq even more difficult. As a result,
EPRI is able to fund less than half the scope of its pro-
gram at a time when the needs are increasinq dramatically".
Ourinq this period of fundamental chanqe in power qeneration
technoloqy, full recovery of all reasonable R&D expenditures
should he allowed.
o Foreiqn countries, where a more cooperative partnership
between qovernment and industry exists, are aqqressively
movinq to assume leadership in the development and commer-
cialization of improved coal utilization technoloqy.
o Loss of technological leadership may force the utility
industry and its suppliers to depend on these foreiqn
sources. Other, far-reachinq implications for supplier
confidence "anc^'thTe U.S. international position are self-
evident in such foreiqn dependence.
10
233
successful risk takina.
The issue becomes esoecially critical when it is necessary to
build larqe scale demonstrations. These are essential elements
in Drovina out the reliability, economics and technical caoa-
bility of new technoloqies . It is also often necessary to qain
experience with several such larae scale projects before the
risks are reduced to the level of broad commercual acceptability,
especially in he utility industry where reliability of service
must take first priority. Thus, there are a number of programs
in coal utilization related technology for which the funding
mechanism to achieve prompt development and application is not
evident. These are necessary to resolve the issues constraining
coal use today and for the foreseeable future.
The rate of market penetration of these new coal utiliation
options would also be enhanced by the development of regulatory
and economic incentives which encourage introduction of inno-
vative technology. Particularly important is the development of
a Quantitative basis for environmental regulation, plus incen-
tives to offset any operational uncertainties associated with
new power Generation technology. These economic incentives
could include making exempt, pollution control bonds available
for any clean coal utilization technology. Other economic
instruments encouraaina the use of such processes might include
accelerated depreciation treatment and enhanced tax credits or
bond guarantees.
The Federal ^ole
The Federal aovernment can play an important role in fosterino
the early introduction of new technologies that can be applied
to meet the needs of clean, coal-fired, power generation this
century. Unfortunately, Federal programs are not aiving
sufficient emphasis to that objective. Indeed, the trend in
Federal spending has been toward long range P&D projects whose
potential benefits lie in the more distant future while turn-
ing away from the early commercialization of promising tech-
nologies. '
The best criterion for the distribution of Federal R&D funds
will be the "Marketplace"; i.e., the willinaness for private
sector cofunding, particularly cofunding by the technology user.
The Appendix discusses a number of these "marketplace" oppor-
tunities which are proposed by the private sector. In this time
of budaet strinaency, every expenditure should be put to a
11
234
severe test of cost effectiveness. All promisina areas cannot
be nursueri and priorities must be set. In this context the
private sector should also be more involved in the prioritv-
settino process.
The total amount budoeted by noE for FY 19R6 in the-field of
Clean tise of Coal, is about SS7 million. This is about half the
correspondina commitment by EPRI alone. This continuinq budqet
decline is inconsistent with the needs which the increasinq use
of coal implies. Within the Clean Use of Coal area, the overall
DOE proqram is only able to touch on most relevant technical
areas. Most critically, the budqet does not allow DOE to aid
in the transfer of the new technoloqies to the private sector nor
to assure their prompt commercialization. Specifically, as
recommended by DOE ' s ERAB Clean Coal Use Technoloqy Panel, the
Federal qovernment should participate in the needed demon-
strations which are characteristic for utility acceptance of
new technoloqy and which are necessary to respond to qovernment
policies and requlations. This recommendation also reflects the
diversufied and decentralized nature of the coal usinq and pro-
ducinq industries and the resultinq ranqe of technoloqy options
required plus the limitations in focusinq sufficient private
sector resources.
An example of the impact of the current lack of Federal partici
pation in private sector technoloqy demonstration and
commercialization initiatives is particularly evident in the
Pressurized '='luidized Red Combustion development proqram. •'aior
progress has been made over the past several years in convertinq
this techoloqy from an enqineerinq possibility to an important
electric power producinq technoloqy havinq the lowest busbar
enerqy cost potential of any near term coal utilization option.
The effective cancellation of federal support on the brink of
successful proof of concept is indeed "seizinq defeat from the
iaws of victory."
The Federal qovernment has a unique opportunity to work closely
with the private sector to resolve the various constraints, often
resultinq from other qovernment actions, on the nation's ability
to make use of coal. Obviously, careful selection of projects
and extensive private cofundinq are prerequisites. The Federal
role should be patterned after the successful experience in the
Cool VJater and TVA AFBC demonstrations where its participation
was as a risk sharinq investor in privately initiated and manaqed
demonstrations with a clear commercialization objective.
This approach would also improve stability of support and pur-
pose for cofunded projects. A prime concern of private sector
R&D manaqement is that proqram direction and budqet, once
adopted, will not be chanced arbitrarily. This is particularly
important to multi-year demonstration projects where chanqe in
direction is costly and wasteful. This improved stability
would facilitate commercialization of improved coal technoloqy.
12
235
Conclusions
The nation stands at a threshold of funfiatnental channe in its
technological base tor coal-fired power generatioTTI The nresent
commercial technolonv is nearina the end of its development
potential and is increasinqly hard pressed to respond to the
rapidly chanaino requirements beinq placed on the industry. An
accelerated, two-pronqed approach is necessary: first, promptly
transfer improved coal technoloqy from development to application
and second, extract the last measure of performance from the
existinq qeneration base necessary to span this transition
period. Copinq with this transition will require an intensive,
•joint commitment over the next 5 to If) years on the part o~
industry and government.
The actions of the Federal qovernment in direct support of enerqy
related research, development and demonstration, and in the form
of incentives, have a profound effect on the private sector's
ability to develop and utilize clean coal technologv. Federal
programs need to consider the underlyinq circumstances affectinq
private industry and the importance of electric enerqy and coal
to the nation's economy and security needs. The rate of commer-
cialization and use of improved technoloqy also depends on leqis-
lative and requlatorv incentives. Too often our dependence on
the adversarial approach makes the uncertainties and conflicts
restricting coal use more severe and disruptive than necessary
and restricts the introduction of technological improvements.
There is no shortage of opportunities to improve the efficiency,
reliabiity and environmental performance of emerqinq clean coal
technoloqies. We are learninq how to produce power cleanly from
coal in a varity of forms meeting the demands of the diverse
national energy system. The question is whether we can reduce
this knowledge to practice in a period when both regulatory un-
certainty and financial disincentives constrain the effort^
The future is now, and success depends on prompt aggressive
action by government and industry. The problem affects all
phases of the development cycle, hut is greatest in the
financially-intensive large pilot and demonstration steps
necessary for commercial confidence. The Clean Coal Tech-
nologv Reserve to provide federal participation in private
sector demonstration initiatives can substantially enhance
the nation's ability to commercialize the many developments
in clean coal technoloqy. EPRI is prepared to do its part
in formulating and implementinq these efforts, includinq the
investment of $5R0 million over the next five years alone.
13
236
Table 1
PROPOSEO CLEAN COAL DEMONSTRATIONS WITH EPRI PARTICIPATION
(Million $)
Recommended
Technoloav Total Federal
Demonstration Funding Part icipation
Coal Quality
1. . Intensive sulfur and 40 20
ash separation
2. Efficient Fine Coal 60 15
Cleanina & Recovery -
EPPI CCTF
3. \ - Fuel Cleanim 39 10
and TJelletizina
&. Bioloqical Coal 20 in
Desulfurization
S. Automated Coal Cleanina 20 10
Plant Process Control
Combustion Technoloav
1. Coal-VJater Slurry 50 20
2. Furnace Sorbent 60 25
Iniection for S0_
Control (LIMB)
3. Low NOjj Combustion 25 10
4. Combustion Diaqnostics 50 25
and Coal Variability
Impact Reduction
Flue Gas Cleanup
1. Southern Company/Chiyoda 40 10
121 Process
2. EPRI Hiah Sulfur Coal 35 5
Test Center
3. Reqenerable NO /SO 27 13
Control ^ "
4. Baqhouse Sorbent 25 5
Iniection for S0_
Control
Pressurized Fluidized
Bed Combustion
14
237
1. Turbocharqefi PFB Roller 90 4S
?. PFB Combineti Cycle 120 60
3. Circulatinq pfr 70 40
Prototype
E. Atmospheric Fluitiized
Bed Combuston
1. NSP Conversion 56 5
2. Colorado-Ute Circulatinq 117 30
AFB
3. 100 MW Coal Refuse 125 30
Combustor
F. Inteqrated Gasification
Combined Cycle
1. Slaoqinq Gasifier S 440 IRO
Advanced Turbine IGCC
2. IGCC Methanol & 40 20
Flectricity Production
G. Fuel Cell - Coal Gasification
1. Phosphoric Acid Fuel Cell SO 20
2. Carbonate Fuel Cell 150 QO
H. Fnvironmental Assessment
1. Impact Mitiqation 20 5
2. Atmospheric Tracer 200 40
Demonstration
Total 1969 743 (3R%)
15
238
Figure lA
ANNUAL UTILITY SOj EMISSIONS
3% Peak Growth
40 year plant life
I^^^ 55 year plant life
SO2 Emission (10^ t/yr)
120
100
80
60
40
1970
Uncontrolled /
/
/
/
/
/
CURRENT NSPS
New
technology
Retrofit-
acid rain
1980
1990
239
Figure IB
ANNUAL UTILITY NO, EMISSIONS
40- Yr Plant Life; 3% Peak Growth
NO, Emissions (10^ t/yr)
45
40
35
30
25
20
15 I —
/
/
/
/
/
Uncontrolled /
/
/ NSPS—
retrofit
240
Attachment
I
EMERGING CLEAN COAL TECHNOLOGIES
ENGINEERING DEMONSTRATION PROGRAM
The need for this program is great because of the nation's very
limited current ability to transfer potentially superior coal
utilization technology into commercial application. "The present
lack of an adequate funding mechanism to build the facilities
necessary, to demonstrate the reliability, economics and per-
formance of new coal technology is a source of national con-
cern. While private sector efforts have been maintained, they
are insufficient in the face of declining Federal participation
and in the absence of corresponding incentives for additional
private investment. As a result, there are a number of pro-
grams in direct coal combustion where the funding to achieve
prompt demonstration and commercialization is not evident. This
may have profound consequences for the 1990 's when new electric
generating demands, which must rely on coal, collide with the
growing environmental ethic of our society. Specific tech-
nologies requiring an accelerated Federal and private sector
initiative include:
1 . Coal Quality Improvement
a. Coal Cleaning
Coal quality is central to the efficiency, reliability and
environmental performance of coal combustion. Coal cleaning
was once a method restricted to high value industrial processes
such as steelmaking. More recently, physical cleaning has
come to be applied broadly for steam coal as a means of reduc-
ing fuel transportation costs, improving plant reliability
and reducing emissions.
Today, essentially all commercial coal cleaning relies
on physical separation methods. These methods are
applied in varying degrees today to over 50% of the
high-sulfur steam coal used by the utility industry.
This application has been primarily for economic
reasons. First, to reduce transportation and waste
disposal costs and second, to reduce operating and
maintenance costs in the boiler and coal handling
equipment caused by uncombustible impurities. The
increasing variability in coal quality and the result-
ing impact in power plant performance and availability
has also led the utility industry to increase its atten-
tion to quality control by increased cleaning of its
coal feedstock. The third major benefit of coal clean-
ing is emission reduction.
Physical coal cleaning is most effective for bituminous
coals with high pyritic sulfur content, particularly those
mined in north Appalachia and the Illinois Basin where
20% to 30% of the total sulfur content can typically be
removed. -However, part of this SO2 emission reduction
241
potential has already been realized in the cleaning
done today. For example, over one-half of the sulfur
removal potential is already being achieved in the
Illinois Basin and about one-third in north Appalachia.
On the other hand, physical coal cleaning to remove
sulfur is typically ineffective for the low-sulfur
southern Appalachian and western coals. As a result,
cost effectiveness varies from about $200 per ton of
sulfur removed for some Illinois Basin coals (Illinois,
Indiana, west Kentucky) to over $2000 per ton of sulfur
removed from some low-sulfur coals.
The opportunities to improve sulfur and ash removal
through coal cleaning, therefore, vary widely and depend
on upgrading existing coal cleaning facilities as well as
installation of new plants. The limiting cost factor in
physical coal cleaning is the loss of coal during the
cleaning process and the effective heating loss from in-
creased moisture content. To achieve its full potential,
EPRI and the utility industry are active in the develop-
ment of improved coal cleaning technology plus char-
acterization of steam coal cleanability and cost. The
emphasis is on finer (smaller particle size) coal clean-
ing and drying techniques to improve coal recovery and
thus reduce cost. It is also anticipated that finer
cleaning will require even greater R&D emphasis as we try
to achieve more ash and pyrite liberation.
This coal cleaning RiD program involves an EPRI commit-
ment of more than $7 million a year plus significant co-
funding by individual utilities, and others. A focal
point for this program is the EPRI Coal Cleaning Test
Facility (CCTF) located near Homer City, Pennyslvania ,
and operating since 1981. Built entirely with private
funds at a cost of $14 million, this is the newest and
most advanced facility of its type. Based on commercial
equipment, the CCTF is demonstration scale with a maxi-
mum coal handling rate of 20 tons per hour. Unlike
other test facilities, it is not dedicated to a single
cleaning process but can accommodate a variety of pro-
jects resulting from EPRI research as well as others in
the coal R&D community. Other objectives include opera-
tor training and development of a coal cleaning data
base for the utility industry.
There is also substantial uncertainty concerning the per-
formance and utilization of existing coal cleaning facil-
ities. As a result, accurate determination of the oppor-
tunities to use excess capacity in existing cleaning
plants and upgrade their sulfur removal capacity is
difficult. Because of the heterogenous nature of coal.
242
the cleanability and associated cost and benefits can
vary widely. For the high-sulfur north Appalachian and
Illinois Basin coal producing regions typical costs are
indicated in Table A-1.
In some cases, further savings in addition to trans-
portation and waste disposal may also be achieved through
improved boiler reliability and reduced maintenance. Much
remains to be done, however, in correlating these
effects on a site specific basis. On the other hand, it
should also be noted that the large majority of coal
cleaning is accomplished by the coal producer, at or
near the mine. As a result, the actual price premium
associated with cleaned coal may be substantially higher
than the actual cost of cleaning, depending on the market
factors existing at the time.
Unfortunately under the limitations of most of the pro-
posed acid deposition legislation, it is unlikely that
this SO2 reduction potential of coal cleaning will be
realized. SO2 reduction requirements of 50% or more
and/or very low emission limits exceed the cleanability
potential of coals currently burned in the affected
region. Alternatively, the relatively small quantity
of low-sulfur coal used has an inherently low sulfur
removal potential. As a result, it is unlikely, unless
more compliance flexibility is encouraged, that addi-
tional SO2 reduction through expanded coal cleaning will
exceed 0.5 MMTPY although the potential exists for 1.5
MMTPY or more of additional SO2 reduction.
As a first priority, additional resources should be
directed to increasing the scope of the joint DOE/EPRI
advanced coal cleaning development project which will use
the CCTF to test various advanced physical and chemical
cleaning processes. These additional resources would
both accelerate the availability of results and assure
large scale testing of a broader range of cleaning pro-
cesses. Additional priority coal quality objectives
should also include:
- Improved sampling and analytical procedures to
insure confidence in coal reserve quantity and
quality estimates.
Techniques for improving the slagging and fouling
characteristics of lower rank coals.
- More economical chemical cleaning techniques pri-
viding thorough sulfur and ash removal.
Development of physical coal cleaning methods as a
part of advanced coal utulization technology such as
coal gasification and coal-water slurries.
243
TABLE A-1
TYPICAL HIGH SULFUR COAL CLEANING COSTS
Upgrade
New Intensive Plant To Intensive
Cleaning Plant* Cleaning Capability*
Capital cost ($/KW) 45 20
Levelized Cost ($/MBtu) 0.30-0.45 0.14-0.17
Cost per ton clean coal ($) 7-10 3-4
Cost per ton SO2 removed ($) 400 - 800 500 - 800
*1000 tons/hr capacity, 1983$, 30 year levelized cost basis,
capacity factor 40%, availability 80%, high sulfur North
Appalachian and Illinois Basin coal.
244
Automated cleaning process control and on-line
continuous measurement techniques to improve reli-
ability and produce quality.
More efficient and economical fine coal cleaning
and recovery techniques.
Combustion Control
a. Combustion Diagnostics and Effects on Power Plant
Performance.
Areas requiring additional effort include:
o Characterization of coal ash chemistry and
its effect on combustion.
o Standardization of slagging indices.
o Effect of coal particle size on fouling/
slagging.
o Effect of coal variability on power plant
performance.
Achievement of these objectives, which may be further accen-
tuated if coal cleaning and switching are increased to meet
emission control requirements, will first require expanded
combustion testing facilities. These should include a 100
million Btu/hr facility whose results could be directly
extropolated to commercial scale furnaces and boilers. It
is also essential that smaller facilities be instrumented
to measure the transient chemical and physical parameters
throughout the combustion process as well as the properties
of the resulting gaseous and particulate products. This
capability could, for example, apply state-of-the-art
measurement techniques developed with DOE support at the
Sandia Combustion Facility. It might be most effectively
implemented in conjunction with a stable university research
program to achieve much needed national centers of excell-
ence in coal science.
b. NOj^ Combustion Control
Historically, combustion modifications have been the
commercially available means of controlling NO^^ emissions
at coal-fired utility boilers. For reasons of cost
effectiveness and reliability, combustion controls offer-
ing significant NOj^ reductions are also likely to con-
tinue to be the preferred NO^^ control approach for both
new and retrofit applications. In general, it appears
245
that the most viable near-term and cost-effective retro-
fit combustion control options are low excess air firing,
overfire air and low-NO^^ burners.
Among these options, low NO burners have the greatest
potential and are receiving substantial development
attention here and abroad. Although each boiler manu-
facturer currently offers a distinctive low-NO^^ burner
design, there is one common goal. Specifically, these
burners are designed to control the mixing and stoi-
chiometry of fuel and air in the near-burner region of
the furnace to retard conversion of fuel bound nitrogen
to NO while still maintaining high combustion effic-
iency. This is accomplished by controlling the momen-
tum, direction and quantity of fuel and air streams at
the burner throat as they are injected into the furnace
chamber.
Low-no burners are a relatively attractive retrofit con-
trol alternative for a number of reasons. These include:
(1) The existing burner would generally be modified or
replaced without involving the expense of new major
furnace components (such as ductwork, control
dampers and new furnace wall openings necessary
for overfire air systems).
(2) NOj^ reductions of up to 50 to 60% (300-400 PPM) can
be anticipated — i.e. greater than the reductions
achievable with low excess air or overfire air
ports .
(3) In some cases, installation of low-NO^^ burners may
lead to improved combustion efficiency or furnace
operation, especially where existing burners are
deteriorated or of outmoded design.
(4) Low-NO burners may provide the necessary conditions
for application of furnace limestone injection to
control 302- The result may be potentially simple
and relatively lower cost, combined S02/N0jj control
system for existing coal-fired boilers.
While it appears that many coal-fired utility boilers
could be retrofitted with low-NO^^ burners by relatively
straightforward replacement of existing burners, the
different flame shape encountered with low-NOj^ burners
and the specific geometrical and mechanical require-
ments can represent significant changes from existing
equipment. The boiler engineering/operational impacts
would need to be addressed on a site specific basis.
246
Advanced NO combustion control concepts are also being
developed to more closely control the fuel/air mixing,
temperature, and combustion chemistry in the furnace.
Alternative fuel-rich/air-rich burner configurations and
fuel staging concepts have been developed to separate and
control the various combustion zones. Much of this ini-
tial development work has taken place in Japan. "Re-
burning" or overfiring techniques pioneered in Japan are
under development to destroy NO^^ formed in other furnace
regions. Reburning has been reported to produce a 5U%
further reduction beyond that of low-NOj^ burners. Other
combustion staging concepts have also emerged. For
example, EPRI has sponsored the development of a primary
combustion furnace concept with Babcock & Wilcox and is
currently sponsoring several retrofit development pro-
grams with the boiler manufacturers. EPA is also de-
veloping the distributed mixing low-NOj^ burner that is
expected to be demonstrated on a full scale boiler.
Furnace Sorbent Injection
One of the most publicized "new" technologies under
development for reducing SO2 emissions is furnace sor-
bent injection, also known as LIMB. Attempts to apply
this process date from the 1960's, but because the pro-
cess chemistry was not well understood, SO2 removal
efficiency was poor. The potentially exorbitant costs
of retrofit scrubbing, however, have led to a renewed
examination of limestone injection by industry and EPA.
Applicability limits will probably be determined by
degree of upper furnace mixing, unit size, back pass heat
transfer surface geometry, and system economics as
affected by age and capacity factor. SO2 control capa-
bility appears limited to about 50% for high-sulfur coal.
There are also a number of issues that must be resolved
before commercial commitment to furnace sorbent injec-
tion technology can be confidently considered. The major
issues identified by both U.S. and West German developers
regarding utility boiler retrofit applications are:
(1) Effects on furnace slagging and fouling which
degrade boiler availability and efficiency.
(2) Uncertainty in scaling up laboratory SO^ removal
and process design data to full scale boilers.
For example, it now appears preferable to have
sorbent injection in the upper furnace separate
from NOj^ control modifications. In addition, ash
composition has been shown to have a major impact
on SO2 removal efficiency.
247
(3) Need for particulate control upgrading because of
a 200% to 300% increase in fly ash loading and
altered ash electrical properties,
(4) Ash disposal constraints. Limestone injection
could substantially increase the total quantities
for disposal.
The goals of the various research programs, therefore are
similar but the specific research approaches are quite
different, although complementary. In the U.S. develop-
ment is principally supported by EPA and EPRI. To date
research has focused on laboratory programs to both ac-
quire the necessary process data and to evaluate power
plant impacts prior to committing to commercial scale
demonstrations.
Because of the developmental status of the technology,
no actual process cost data are available. However,
retrofit cost estimates have been made for furnace lime-
stone injection based on standard EPRI economic premises.
The results indicate a probable capital cost in the range
of $40 to $100/kW, including particulate control system
upgrading and a total levelized cost of 6 to 12 mills/kWh
for high-sulfur coal. This does not include the cost of
any reduced boiler performance or increased maintenance
resulting from application of this technology. This
again is based on a SO2 removal efficiency of bO% which
leads to a cost per ton of SO2 removed in the range of
$650 to $1000. Thus the relatively low SO2 removal
efficiency and high limestone requirement may tend to
offset the capital cost advantage.
Retrofit demonstrations of in-boiler sulfur control
technology should be emphasized as a relatively low cost,
near-term approach to reducing SO2 emissions from exist-
ing boilers. The research projects conducted to date
have laid the groundwork for prototype tests at a number
of utility boilers in the 50-150 MWe size range. These
prototype tests are an integral part of the development
process and are necessary to provide confidence for
commercial application. The issue here is the impact
on the performance and reliability of the boiler and
particulate control system, not just SO2 removal effic-
iency .
At least seven utility companies are interested in parti-
cipating in this prototype effort, including financial
support and hosting the tests. We estimate that four
prototypes will be necessary to qualify the limestone
248
injection technology over the range of desired boilers
and coal conditions. Only one is proceeding today at
Ohio Edison with EPA support.
Unfortunately the development of this technology is
limited by the lack of funding necessary to implement
these planned prototypes. Less than half the approxi-
mately $60 million necessary to develop and demonstrate
this technology over the next few years is budgeted by
the Federal and private sectors.
d. Coal-Water Slurry
The retrofit of an oil-fired boiler or at least 100 MWe
using clean coal is a valuable objective and should focus
on the use of coal-water slurry (CWS) in a boiler orig-
inally designed for oil. The slurrying of deeply cleaned
coal aids the cleaning process and enhances its handling
and storability in the fuel system associated with oil-
fired plants. Eighteen utilities are now participating
with EPRI in the engineering evaluation of alternative
sites for such a demonstration. Such a demonstration
could be performed by 1986, if sufficient CWS produc-
tion capacity can be established. A demonstration in
the 400 MWe size range would be particularly advan-
tageous if price guarantees or other support to achieve
CWS production of about 1 million tons per year can be
provided. To assure the technical foundation of such a
large scale CWS application, further R&D attention should
also be given to:
- Development of more reliability CWS burners
- Development of erosion resistent convection
pass tubing materials.
This would logically complement EPRI and DOE efforts in-
volving slurry characterization, development of utili-
zation guidelines, and testing of slurry handling, pump-
ing and firing equipment. From a regulatory standpoint,
it is essential that boilers converting to deeply cleaned
coal in any form be permitted to meet their existing
emission requirements and not be forced to meet New
Source Performance Standards (NSPS ) . Otherwise, commer-
cial acceptance will be minimal.
Flue Gas Cleaning
a. Flue Gas DesHlfurization
Today, flue gas cleaning for SOj control depends on
scrubbers using primarily a slurry of lime or limestone
249
and water. Because of its high SO2 control efficiency
relative to other available options (up to 9U%), the
emphasis on scrubbers rapidly increases as control
requirements become more stringent. Unfortunately,
scrubbers are complex chemical engineering facilities
which are expensive and difficult to apply options for
existing plants. They also have a major impact on reli-
ability and efficiency and create undesirable environ-
mental side effects. As of December, 1984 the electric
utility industry had 119 scrubbers in operation and an
additional 101 under construction or planned as mandated
by the Clean Air Act. This represents a present commit-
ment to scrubbers of over 110,000 MW, greater than the
rest of the world combined.
This commitment also represents the largest single cost
element in the environmental investment for a new coal-
fired power plant. This investment is typically 20% or
more of the total cost of the plant. The $175/kW or more
capital cost of FGD on a new plant is exceeded only by
the cost of the -boiler itself. Maintenance cost for the
FGD system is two to twenty times the maintenance cost
for the rest of the power plant. As a result, the
National Research Council in its 1980 report on FGD tech-
nology recommended that highest priority be given to im-
proving the reliability of FGD systems for application to
high sulfur coal. Although average FGD availability on
medium and high sulfur coal has increased from 53% in
1978 to 85% in 1982, this is still not consistent with
utility requirements and represents a substantial loss
in available electric generating capacity.
The EPRI RiD program to improve this unacceptable FGD
performance is the largest of its type in the country
with $50 million invested to date and an equivalent
amount planned for the next five years. It emphasizes
failure cause analysis, improvements in process chemis-
try, materials of construction, water and energy use,
hardware design, plus performance data collection and
interpretation. In addition, EPRI is actively pursuing
the development of improved FGD designs capable of re-
ducing byproduct production and substantially improving
cost and reliability.
The levelized cost of retrofit FGD installations may
typically rival the present busbar cost of the elec-
tricity produced by the power plant. This is especially
influenced by the remaining life of these plants. Pre-
vious cost estimates of acidic deposition control stra-
tegies have typically underestimated these retrofit FGD
costs .
250
These known problems with FGD systems make them an ex-
pensive and difficult option for retrofit to existing
plants. In our judgement they represent a band-aid so-
lution, often creating as many problems today as they
solve and should be replaced by more effective tech-
nology as rapidly as possible. Adding them to older
plants is generally uneconomic and should be avoided
except in cases where the risk to the ecosystem is found
to be unacceptably large and no other alternative is
available. Typical retrofit planning values for both
limestone scrubber and lime spray dryer FGD systems on
a 5Q0 MW power generating unit burning 2.5% sulfur con-
tent coal with a 60% capacity factor and 15 years remain-
ing life are listed in Table A-2.
The highest priority should be placed on resolving the
reliability, byproduct disposal and cost issues impeding
the effectiveness of flue gas desulf urization (FGD) , es-
pecially for retrofit on existing coal-fired power
plants. A variety of simplified and improved FGD pro-
cesses have been developed by the private sector, such
as the Chiyoda 121 Process, which should be demonstrated
at the 100-150 MWe scale as soon as possible. The effort
should not, however, be limited to processes capable of
90% SO2 removal. Simplified processes with somewhat
lower removal efficiencies may be very useful in the
event that retrofit control requirements develop.
Federal participation is also encouraged in the New EPRI
High Sulfur Test Center being built to address the chem-
istry and materials issues limiting FGD performance and
reliability. This could have, for example, a substantial
impact on any acid rain control strategy requiring retro-
fittable FGD. The Center will consist of a series of
scrubber pilot plants with supporting laboratories all
operating on high sulfur flue gas produced by a coal-
fired utility boiler. EPRI and the utility industry have
committed $12 million for the construction of this facil-
ity with an additional $25 million for operating costs.
The inclusion of a demonstration of a combined SOj^/NOj^
removal system within the next five years is speculative.
Although DOE is today supporting development of several
such technologies including the Sulf-X and E-Beam pro-
cesses, these are still at relatively small scale and a
preliminary stage of development. They are unlikely to
achieve sufficient performance or cost confidence within
the near future tojustify large prototype facilities.
Increased funding for smaller pilot scale development
would probably be more effective within this time frame.
251
TABLE A- 2
TYPICAL HIGH SULFUR COAL SCRUBBING COSTS
Limestone
Scrubber (1983$)
Lime
Spray Dryer
Capital Cost - 230 $/kW
- Total Levelized Cost
- Energy Use
- Land Use (fixed
landfill)
- Solid Waste
- Water Use
FGD Availability
190 $/kW*
(1)
(1)
20 mills/kWh*"" 21 mills/kWh
3-5% of plant ioput 1-2% of plant input
^-ft/yr*'^' 250 acre-f t/yr^^'
240 acre-
220,000 TPY
500-2500 GPM
80-90%
-5%
(2)
- Power Plant
Reliability Impact
- SO- Removal Efficiency 80-90%
- Cost/Ton SO2 Removal 1000-1200$
(i:
240,000 TPY
400-600 GPM
80-90%
-5%
(2)
60-85%
1100-1400$
(1)
♦Includes Fabric Filter Baghouse
(1) Does not include cost of any lost generating capacity,
(2) Wet disposal may double these quantities.
252
b. Electrostatic Precipitator Performance Improvement
The retrofit application of in-furnace or certain
other flue gas emission control technologies will
have a detrimental effect on the performance and
reliability of existing electrostatic precipitator
(ESP) facilities at these plants. This degradation
will result from both the increased particulate load-
ing as well as the effects on fly ash resistivity,
adhesivity, and particle size resulting from changes
to fly ash and flue gas composition by the retrofitted
control process.
It will, therefore, be necessary to upgrade existing
ESP technology including development of improved
flue gas conditioning additives, pulsed power supplies,
on-line performance diagnostic instrumentation and im-
^ proved fly ash properties prediction methods. This
effort should include full scale field evaluation of
retrofit effects plus verification of performance im-
provements. The result will be utility proven tech-
niques for maintaining and upgrading ESP performance
and reliability plus guidelines for the operation and
maintenance of the upgraded ESP facilities responding
to SO2 and NOj^ control requirements.
c. Water and Solids Integration
Little attention has been given to date to secondary
pollution questions of air pollution control, notably
compliance with Clean Water Act/NPDES and the Resource
Conservation and Recovery Act (RCRA). In addition to
a very large increase in both solid and liquid waste
products created by retrofit control requirements, the
composition of these byproducts will also be affected.
New approaches will produce byproducts of different
characteristics — e.g., more soluble calcium in waste
solids from furnace limestone injection than conven-
tional wet limestone scrubbing.
In conjunction with planned EPRI/utility programs, a full
scale integrated water treatment and solids management
system at one or more existing plants should be con-
structed and tested. The system should focus on retro-
fit applications and be designed along with retrofit SO2
controls. The effort would demonstrate application of
retrof ittable water quality control technology plus
design and operating guidelines for retrofit water and
solids systems.
253
TABLE A- 3
Pioneer Utility Fluidized-Bed Combustion Demonstrations
Location
Size, MW (e)
FBC type
Scope
Coal
Coal feed
system
Dust
collector
Dispatch
schedule
Start-ups
per year
Boiler
supplier
Cost
Federal
funding
TVA/Duke
Paducah, KY
160
bubbling
add-on boiler
high S
bituminous
underbed
baghouse
base load
some cycling
30
Combustion
Engineering
$220 Million
$ 30 Million
Provided
NSP
Minneapolis, MN
125
bubbling
boiler
conversion
low S
subbituminous,
high S bitximinous
& municipal
refuse
overbed
electrostatic
precipitator
2-shift,
5-day cycle
250
Foster-
Wheeler
$50 Million
$ 5 Million
Requested
Colorado-Ute
Nucla, CO
110
circulating
add-on boiler
& T/G
low S, high ash
bituminous
in-bed
baghouse
base load
<10
Pyropower
(Ahlstrom)
$100 Million
$ 30 Million
Requested
50-513 0—85 9
254
TABLE A-4 (a)
Wet Limestone
AFBC
FGD Retrofit
(1983$)
Conversion
93 MWe
115 MWe
$590 (b)
$480
45
45
Net Capacity after conversion
Capital Cost ($/kWe)
Total Capital Requirement: (10 $)
Levelized Cost (mills kWH) :
- Capital 22 22
- O&M (c) 22 25
- Derating (d) 3 (-33)
- Fuel -7 2
Total 40
16
SO^ Removal Efficiency 90% 90%
(a) Based on Northern States Power Co. experience.
(b) Includes wet limestone FGD retrofit at $390/kVJe, and $200/kWe,
for plant refurbishment,
(c) Total fixed and variable O&M for power plant and emission
control.
(d) Consists of both a capacity and replacement power charge.
Replacement capacity provided by combustion turbine at
$270/kWe and fuel at $5/MBtu.
255
Fluidized Bed Combustion
a. Atmospheric Fluidized Bed Combustion
Development of Atmospheric Fluidized Bed Combustion '.AFB)
has successfully progressed from the process confirmation
stage to engineering prototype, making commercial scale
utility application possible this decade.
AFB has become an important boiler alternative because it
is an evolutionary improvement in coal utilization,
better meeting the requirements of the 1990's. The capa-
bilities which excite this interest include: (a) less
sensitivity to fuel quality, thus permitting users to
operate more in a "buyers" fuel market; (b) ability to
control SO2 and NOj^ within the combustion process; and
(c) less cost sensitivity to unit size.
This provides the technical basis for 100-200 MW commer-
cial demonstrations by the utility industry which will be
operational this decade. Three such complementary
utility demonstrations are now being implemented with
$350 million in private sector funding at TVA, Northern
States Power, and the Colorado Ute Electric Cooperative.
These are described further in Table A-3.
In each case the utility industry will fund the largest
share of these demonstrations with EPRI and the suppliers
sharing the f irst-of-a-kind risk costs.
As a retrofit AFB project. Northern States Power is con-
verting and repowering an existing coal-fired boiler at
the Black Dog Power Station to AFBC as a more cost-
effective approach than scrubbing. the conversion is
scheduled to begin operation in 1986.
Table A-4 compares such an AFB conversion with the alter-
native of an FGD retrofit. This comparison is based on
modifying a 25 year old unit burning 3% sulfur coal with
a capacity factor of 40% and having a gross capacity be-
fore conversion of 85 MWe . Modification is also intended
to extend life to a nominal 50 years.
Although AFB is proceeding favorably into commercial
application, considerable opportunity for continued
development exists. Rather than concentrating on the
investigation of advanced, proprietary AFB concepts,
this support should be directed to resolution of the
generic materials, fuel characterization and environ-
mental control considerations with pace its application.
256
I
In addition, special emphasis should be placed on the
demonstration of circulating AFB in both industrial
and utility applications.
The continuity and success of the combined Federal/
private development effort is making these pioneer AFB
demonstrations possible primarily through private sup-
port. This provides a successful prototype for similar
utility and government collaboration in other areas of
coal utilization RSrD,
Pressurized Fluidized Bed Combustion
The new and dynamic utility climate also influences
pressurized fluidized bed combustion (PFB) develop-
ment. The influence results from the trend toward
smaller new unit size plus utility priority on up-
rating the capacity of existing units to bring gene-
ration on line quickly and at the lowest cost. These
advantages can translate into an effective reduction
in capital costs of $200/kW to $300/kW by better match-
ing load growth and reducing the cost of work in pro-
gress (CWIP). PFB provides the opportunity to add
these advantages to the inherent fuel flexibility and
environmental control capabilities of atmospheric flui-
dized bed combustion.
As a result, development and demonstration emphasis
should be placed on PFB turbocharged boilers which can
provide shop-fabricated, barge transportable, steam
generation modules. These may be rapidly field-
erected to provide the desired uprating in unit sizes
of 50 MWe to 250 MWe. This approach can also use
coal to replace or increase the capacity of existing
oil-or gas-fired plants while meeting stringent sit-
ing and environmental control constraints. It also pro-
vides the lowest busbar energy cost of any coal-fired
power generation option now under development. The
primary physical difference between the turbocharged boiler
and the PFB-combined cycle that has been previously empha-
sized is the reduction in gas turbine operating temperature.
This substantially reduces the development risk and cost, and
improves the reliability of the boiler system.
By developing PFB in this low-risk configuration and
demonstrating its feasibility in financially attractive
repowering applications, sufficient confidence can be
gained to increase the firing temperature in future
plants to combined-cycle conditions. This evolutionary
path can eventually lead to the 40% + efficient, direct
coal-fired, combined-cycle power plant.
The development effort today centers on the PFB boiler
and involves the design base for the heat transfer tube
bundle within the bed as well as coal feeding, ash han-
dling, and control of the PFB boiler system. The only
257
available facilities for resolution of these technical issues
are the International Energy Agency (lEA) Grimethorpe PFB
Pilot Facility and Supporting Coal Utilitization Research
Laboratory (CURL) in England. Unfortunately the just con-
structed Curtiss-Wright Wood-Ridge, New Jersey PFB pilot has
been terminated by DOE before having the opportunity to operate
Tests at Grimethorpe are planned with two U.S. manufacturers,
Babcock & Wilcox and Foster Wheeler. In both cases, the manu-
facturers will design and supply heat transfer tube bundles
for performance and reliability testing. EPRI is committing
$5 million to these tests and strongly encourages at least a
similar level of DOE participation. These tests are a key
stepping stone to implementing planned PFB demonstration pro-
jects with the utility industry. As a result of approximately
a decade of federally funded research, PFB technology has not
reached the proof-of -concept state of development where its ad-
vantages can be confirmed. Unfortunately, as this critical
R&D threshold is reached, DOE support has been essentially
terminated, thus stalling PFB's potential for commercial
application in the U.S.
A new joint DOE/private initiative should therefore be
mounted which consists of four primary elements: (a)
supporting research on f luidization, materials and sor-
bent performance, (b) proof-of-concept testing at the
Grimethorpe and Curtiss-Wright facilities, (c) pilot
scale development of circulating PFB, and (d) demon-
strations of 100 MW PFB modules for both bubbling and
circulating boiler designs. Such demonstrations, esti-
mated to cost about $100 million each, are technically
feasible this decade. The pacing item will be the avail-
ability of Federal support for the already planned
private sector initiatives by Florida Power & Light, Wis-
consin Electric, Public Service Electric & Gas, and Amer-
ican Electric Power.
Gasification Combined Cycle (GCC)
Coal gasification integrated with combustion turbne combined
cycle power generation is an attractive new technology cur-
rently being demonstrated at Southern California Edison's
Cool Water site near Daggett, California. This project, the
capital cost for which was provided by EPRI and the private
sector, employs a 1000 ton/day oxygen blown Texaco water
slurry fed entrained gasifier and a currently commercial
General Electric Frame 7 gas turbine. The design coal is a
Utah bituminous coal and the net plant output is about 100
MW. Synthetic Fuels Corporation (SFC) price supports of up
to $120 million are currently provided to oftset the oper-
ating costs for this first of a kind plant. Performance
of this plant to date has exceeded expectations in many
areas, particularly with respect to emissions where very low
levels of sulfur oxides, nitrogen oxides, and particulates
258
have been achieved.
The Cool Water experience and other EPRI studies show that
GCC plants based on this technology can be economically com-
petitive and environmentally superior to other coal tech-
nologies. Major advantages are: (a) higher efficiency (b)
lower emissions (c) lower water and land requirements. Com-
mercial plants in the 200-500 MW range will comprise multiple
trains of similar sized components (gasifiers, gas turbines)
already demonstrated at Cool Water. These plants can be in-
stalled in phases using modular shop fabricated components,
thus enabling utilities to add capacity in a manner that
better matches load growth without the extended construction
periods and attendant financial exposure experienced with
large conventional power plants. The multiple train con-
figuration of such GCC plants should also result in high
overall plant availability.
Another attractive opportunity for the introduction of GCC
technology into the utility industry is to first install gas
turbine or combined cycle capacity based on conventional oil
and gas fuels and to add coal gasification later when either
(a) base load demand has grown or (b) conventional oil and
gas fuel costs have risen unacceptably . This strategy is
currently being investigated by EPRI and contractors with ten
individual utilities for their specific systems.
EPRI is also planning to support the further development of
other competing coal gasification processes such as the
British Gas/Lurgi slagging gasifier and the Shell entrained
gasifier. A program of test runs on U.S. bituminous coals is
currently planned on a 600 ton/day British Gas/Lurgi gasifier
in Scotland starting in 1985 under joint funding- from EPRI,
the Gas Research Institute and the British Gas Corporation.
The British Gas/Lurgi slagging moving bed gasification tech-
nology is particularly suited to the use of the abundant high
sulfur bituminous Appalachian and Mid Western coals which are
currently under utilized. The British Gas/Lurgi moving bed
technology differs markedly from the Texaco entrained gasi-
fier used at Cool Water and we believe offers certain ad-
vantages in efficiency and oxygen consumption. DOE and EPRI
both participated in the earlier stages of development of the
British Gas/Lurgi technology and formerly planned to proceed
to a "demonstration" plant. Accordingly EPRI believes that
the next logical step for GCC technology development would be
the demonstration of the British Gas/Lurgi slagging gasifier
based on highr salfur Eastern or Mid Western coal. The value
of such a project could be markedly enhanced by the in-
clusion of a high firing temperature, more efficient gas
turbine in the plant configuration. Both DOE and EPRI have
I
259
previously supported considerable prior work with the gas
turbine manufacturers on such improvements, which have now
advanced to the stage where full scale implementation is
justified.
A GCC project based on these technologies and concepts is
currently being studied by EPRI, Detroit Edison and Con-
sumers Power. A plant capacity in the 150-200 MW range is
contemplated with a total estimated cost of about $400
raillon. DOE support of $150 million is being requested tor
this project.
GCC systems also offer attractive opportunities for the co-
production of other energy forms such as steam, substitute
Natural Gas (SNG) and methanol. The coproduction of meth-
anol is of particular interest to utilities since it can pro-
vide a source of peaking fuel, the "once through" methanol
concept which has been under development with DOE, EPRI and
other private support is now ready for a larger scale test at
a coal gasification site. The most logical and suitable lo-
caton is at TVA's Ammonia from Coal project in Muscle Shoals,
Alabama. Additional DOE support of about $20 million for
this facility at TVA is strongly recommended to provide a
test center for the above mentioned once through methanol
concept at the 125 tons/day capacity.
Fuel Cell - Gasification
Fuel cells are modular, environmentally acceptable power
units that offer the most efficient use of petroleum and
natural gas in the near-term and coal derived fuels in- the
longer-term.
Phosphoric acid fuel cells are expected to achieve commer-
cial status by 1990. A market potential of 45,000MW is g
projected for the year 2000 with savings approaching 90 x 10
barrels of oil equivalent) per year. The importance of this
technology to the electric utility industry is described in
separate testimony provided by the Fuel Cell Users Group of
the Electric Utility Industry. Further evidence of the im-
portance of phosphoric acid fuel cells to electric utilities
is provided by the increased commitments of five Japanese and
two U.S. manufacturers to large scale demonstration and com-
mercial prototype projects.
However, the commercial success of phosphoric acid fuel cells
is not assured and will depend upon continued technology im-
provements to achieve the reliability and the capital costs
necessary to penetrate the market and achieve the projected
260
benefits. The absence of any funding for phosphoric acid fuel
cells in the Department's FY86 budget is alarming and ignores
the needs of on-going programs as well as the progress being
made under the coordinated support of DOE and EPRI . These
efforts if sustained at current levels promise to achieve the
targets while improving the power plant efficiency from the
current 40% to as much as 47%. Beyond this, the integration
of fuel cells with coal gasifiers need to be explored to con-
firm the projected coal to A.C. power efficiency of 37%. Inter-
est in using phosphoric acid fuel cells with coal was emphas-
ized by the submission of nine oroposals in response to
doe's recent program announcements regarding emerging clean
coal technologies. EPRI has bedgeted over $50 million to
support the continued development and commercial introduction
of phosphoric acid fuel cell power plants during the 1985-1989
time period .
EPRI also supports the longer-range molten carbonate and
solid oxide fuel cell technologies. We feel that the
Department's FY86 request for these technologies is adequate.
Advanced Coal Liquefaction
The Wilsonville Advanced Coal Liquefaction Research & Devel-
opment Faciligy has made a significant contribution to
advancing coal liquefaction technology. During 1985, EPRI
will provide funds to add approximately $900,000 in capital
improvements to the Wilsonville pilot plant. This new
equipment will provide for the testing in FY '86 of new process
configurations which may further improve the process effici-
ency, reduce capital cost, and provide a better understanding
of this complex process. Current programs which are planned
through 1986 would advance this technology to technical
readiness for scale-up to commercial application. The
Wilsonville program for FY '86 is not expected to produce a
"breakthrough" which will allow direct coal liquefaction
to compete with the current crude oil price of $25 to $30
per barrel. However, it is expected to produce a data base
that can be used to design a two-stage process to produce a
given product slate whenever economics or national commit-
ments require. We currently estimate that distillate pro-
ducts would cost $45 to $55 per barrel (in 1984 dollars) .
The major objectives can be reached by the end of 1986.
Unless there is a drastic change in the nation's outlook for
oil, the plans for Wilsonville will include completion of
the facility at the end of 1986. $6.5 million in DOE
participation in FY '86 is encouraged to permit achievement
of these objectives.
261
The Wilsonville facility has become a unique national asset
in that it has the broadest capability of any liquefaction
pilot plant in the United States, is open for the testing of
proprietary technology developed by others at a meaningful
scale, and produces sufficient quantities of products for
small-scale combustion testing and product upgrading research.
The project has consistently operated within budget.
If the program is ended before the proqram goals have been
completed, the data obtained to date will lose a significant
part of their value. Currently the data are in the form of
discrete points. These data cannot be used to predict what
product slates can be expected from operation at conditions
that were' not tested. Modeling of individual process units
is an essential step before the presently unrelated data can
best be understood.
Environmental Assessment and Mitigation
Major benefits to coal utilization could be obtained by a
substantial experiment in lake liming and a massive tracer
investigation of the transport of SO^.
Environmental Impact Mitigation
In Sweden where a similar situation exists, a major national
program is underway to mitigate acidification and introduce
a fish stocking program. Currently, about $4 million per
year is being spent to manage between 10,000 and 20,000 lakes.
However, several questions remain.
Some ecologists are concerned as to possible secondary
effects of using lime or limestone in surface waters. In
a $3 million three year study entitled Lake Acidification
Mitigation Project (LAMP) , EPRI has initiated an investigation
of the ecological consequence of neutralizing waters in three
Adirondack Lakes. Swedish investigators will provide data on
a few of the lakes to compare with the EPRI-derived data.
However, no systematic program for analyzing the costs and
effectiveness of various mitigation systems has been started.
Currently, there are a nximber of options for delivery of the
neutralizing material: by airplane, helicopter, truck, tanker,
truck, boat, etc. Also, there are a number of substances
which can be used to neutralize the water: lime, quick-lime,
limestone, and, there exist a number of ways of delivering
the materials: by single treatment in the water, by multiple
treatments of the water, by treating the lake itself or by
treating streauns , the shoreline, or the entire watershed.
262
While a good deal of data exists from the Swedish experience
and a little data from Canadian and U.S. experience, there is
a need ror a systematic cost and efficiency assessment of
mitigation alternatives in the U.S. A major experiment pro-
viding experience on 250-500 lakes could be performed for
about $20 million.
Determination of contributions from local and distant sources
If there were a decision to reduce emissions in order to
reduce deposition in certain sensitive ecological areas, the
current- understanding of the atmospheric processes is not
sufficiently developed to enable targeted options to be reli-
ably chosen. Whether nearby sources or distant sources are the
most important contributors to acidic deposition in the sen-
sitive areas makes a huge difference in the potential cost
of a control program.
For example, if distant sources were the major contributor,
to achieve a reduced deposition a general reduction in
emissions would have to be used. On the other hand, if local
sources were more important, a much more limited emissions
control program would be possible. In analyses of such
possible differences, it has been found that the cost of
emissions control might be reduced by as much as a factor of
ten if we can get the data needed to design such an efficient progr
EPRI has examined how this atmospheric information might be
acquired. Current knowledge of atmospheric physics and
chemistry and current modeling capability do not now provide
enough information to accurately predict source-receptor
relations. Nor do improvements in these areas of science
over the next ten years seem likely to provide the accuracy
needed.
However, EPA, NOAA, DOE and EPRI have experimented with
utilizing tracers to obtain the needed source-receptor
information. In addition, EPA has designed a small regional
experiment while EPRI has designed an experiemnt to encompass
the entire eastern one-half of the U.S. Currently, the
identified major difficulties in implementing such an
experiment are being studied. An experiment of this type
would cost about $200 million and could be initiated in 198G.
263
Mr. Boucher. Thank you, Mr. Mannella.
We will hear from Mr. Webb.
Mr. Webb. Thank you very much. I appreciate the opportunity to
appear before you today to discuss the Gas Research Institute's
views and recommendations on the clean coal technologies initia-
tive established by Congress last year.
It is particularly encouraging that 175 private sector firms re-
sponded to the Department of Energy's request for statement of in-
terest. This response is amazing when you consider DOE made it
extremely clear in its announcements that no funds were currently
available, and furthermore, DOE did not intend to request funds to
start any of the proposed projects. The private sector response
clearly indicates a need for Federal funding to accelerate research
for and demonstration of emerging clean coal technologies. GRI
fully supports funding made available to DOE for clean coal tech-
nology demonstrations, especially for near-term applications. We
are particularly encouraged that some of the applications proposed
recognized the use of natural gas in combination with other tech-
nologies for flue gas cleanup and, in the longer term, for coal gas-
ification.
GRI is an independent, not-for-profit scientific research organiza-
tion that manages the cooperative research and development pro-
gram for the gas industry and its customers. We are not a govern-
ment contractor; however, we do cofund and coordinate much of
our research with DOE, therefore Congress' actions on the DOE
budget do have a direct impact on the gas industry's research pro-
gram.
To summarize briefly, a review of the DOE report to Congress in-
dicated the largest number of industry responses were in four tech-
nology areas that could have the most near-term impact. These
technologies — flue gas cleanup, surface coal gasification, fluidized
bed combustion and coal preparation — are all at the state of devel-
opment where the next logical step is a field demonstration. Over
60 percent of the private sector respondents, or 70 percent if you
include only those that had specific proposals, recommended work
in these four areas. I think they should be given a priority in any
clean coal initiative.
Also, the DOE report noted that nearly all of the submissions re-
quested direct cost sharing rather than other forms of financial as-
sistance. I think this indicates direct Federal support through co-
funding is required to accelerate the commercialization of new
clean coal technologies.
The ERAB report emphasized a couple of factors that I think
were important in reviewing the role of the Federal Government.
One was that the number of coal-use situations is so large and di-
verse and the specific problems are so site specific that no one tech-
nology or solution will solve the problem. This is particularly true
for retrofit applications which represent the overwhelming majori-
ty of the market.
The ERAB report also noted DOE policy has recently excluded
work beyond the proof-of-concept stage. This policy limits timely
commercialization of new technologies, and a revision of this policy
is recommended.
264
Another factor to consider in determining the most prudent Fed-
eral role is the extent to which the United States must rely on coal
to meet its electric power generation demands between now and
the year 2010. Under any reasonable scenario of growth, electricity
demand through the 1990's will continue to increase and require
the construction of new generating plants. I noticed just last week
the North American Electric Reliability Council in their annual
projection indicated that current projected capacity, including all
plants currently planned, can only support a 2.2-percent peak
demand growth between now and the year 2000. If historical rela-
tionships between GNP growth and electric demand continue, we
either will have a stagnant economy with increasing unemploy-
ment and the rising misallocations of funding due to that or else
we are liable to have a shortage in electric peak capacity in the
late 1990's. Therefore, I think it is urgent that we initiate a pro-
gram for clean coal technologies.
This scenario becomes especially convincing when you consider
that the United States holds one quarter of the world's known coal
reserves, and electricity use, even with all of the conservation due
to higher energy prices and economic downturns, has grown by ap-
proximately 30 percent since 1973.
In evaluating the urgency of moving forward with the clean coal
technology demonstrations, I think it is informative to recap the
action since the Energy Security Act in June 1980. With the Irani-
an crisis in 1979, the United States was faced, for the second time
in 6 years, with skyrocketing crude oil prices. Responding to the
need to develop domestic sources of energy. Congress created the
Synthetic Fuels Corporation to provide financial assistance to the
private sector- to undertake commercial synthetic fuels projects.
However, at that same time DOE had a large and very aggressive
Fossil Fuels Demonstration Program, on the magnitude of $700
million to $1 billion per year. It was assumed the technology devel-
oped in these DOE demonstrations would be available for the SFC
and the private sector to draw upon for commercial demonstra-
tions. However, today, the DOE Fossil Fuels Demonstration Pro-
gram has been terminated. The result is a serious technology gap
between the long-term generic research and commercialization.
Yet, DOE continues to stress research and demonstrations are the
role of the private sector, who will be guided by market forces.
I would like to refer you to an ERAB report done in 1982 for
DOE on energy R&D priorities. I quote:
A little over half our primary energy finds its way to consumers through the elec-
tric and gas utilities, and these utilities are regulated, price-controlled industries
selling their products not at free market prices, but at controlled prices. Both these
regulated industries have weak incentives to spend on R&D. If successful, the bene-
fits go to the ratepayer; if unsuccessful, the expenditures may be disallowed as "im-
prudent."
In this environment, the utility sector simply does not have the
incentives to make all of the necessary research investments to
adequately demonstrate currently needed clean coal technologies.
One other note in that area on the economic incentives that I
think is important for clean coal technologies is mostly in response
to Federal laws and regulations. Surely, if the changes in Federal
law require new technology, then there is a Federal role — primari-
265
ly at DOE — in accelerating the demonstration and commercializa-
tion of the required technology, especially if it is to bring existing
boilers into compliance with changing Federal laws.
Finally, in summary, I think I would like to make one other com-
ment before I make specific recommendations. There was an issue
raised this morning on whether it is an investment or a cost in
cleaning up our Nation's coal. I believe I am correct that the cost
of oil imports in 1984 was approximately $60 billion. I think the
Secretary pointed out that this was dollars spent by individuals.
That is correct, but it also contributed to the Federal deficit; to the
trade balance, which leads to higher interest rates.
Also, I think it should be pointed out that the cost of the pro-
gram to DOE that Congress is imposing is about $750 million. I
would like to point out that the cost of one carrier to defend the
Persian Gulf would cost more than the $750 million proposed for
this entire program.
Finally, Mr. Chairman, after considering these factors, I would
like to recommend the following:
Congress should recognize that DOE has a leading role in demon-
strating clean coal technologies and appropriate funds in fiscal
year 1986 to initiate a limited number of the proposed demonstra-
tions.
Priorities should be given to the near-term technologies: flue gas
cleanup, coal gasification, fluidized bed combustion, and coal prepa-
ration. Use of natural gas in the demonstration of flue gas cleanup
should be assigned a top priority.
Second, the private partner should be responsible for providing a
significant portion of the construction and operating cost. It is im-
portant that cofunding by the user of the technology be required.
Third, the executive branch should leave day-to-day management
of the project to the industrial partner.
Fourth, in determining which proposals to select, it should be
recognized that a stand-alone plant, which usually will be the most
expensive type of demonstration, should be considered as a last
resort. Priority should be given to proposals that use existing host
facilities.
And finally, the Synthetic Fuels Corporation should be encour-
aged to make provisions in its future financial assistance for com-
mercial synthetic fuel plants to require the capability for testing
advanced clean coal technologies at the plantsites in the future; in
other words, that they would serve as a host site for these demon-
strations, and that would significantly reduce the cost.
In conclusion, the Federal energy research policy has created a
technology gap by restricting the DOE role to proof of concept.
Congress can take a bold step today toward closing this gap by ap-
propriating funds in fiscal year 1986 for clean coal technology dem-
onstrations to be cofunded with industry.
Mr. Chairman, this completes my testimony. I would like to ask
that my complete statement be included in the record. And I would
be happy to respond to any questions that you or any members
may have at this time.
Mr. Boucher. Without objection, the statement will be received.
[The prepared statement of Mr. Webb follows:]
266
TESTIMONY OF DAVID 0. WEBB
VICE PRESIDENT, POLICY AND REGULATORY AFFAIRS
GAS RESEARCH INSTITUTE
BEFORE THE SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATION
COMMITTEE ON SCIENCE AND TECHNOLOGY
U.S. HOUSE OF REPRESENTATIVES
MAY 8, 1985
I appreciate the opportunity to appear before you today to discuss the Gas
Research Institute's views and recommendations on the clean-coal technologies
initiative specified in Section 321 of the Department of the Interior and
Related Agencies Appropriations Act for FY 1985 enacted by House Joint
Resolution 648, Public Law 98-473. It is particularly encouraging that 175
private-sector firms responded to the Department of Energy's request for
statements of interest. This response is amazing when you consider that DOE
made it extremely clear in its announcement that no funds are available and,
furthermore, that DOE does not intend to request funds to start any of the
proposed projects. The private-sector response clearly indicates a need for
federal funding to accelerate research for and demonstration of emerging
clean-coal technologies. GRI fully supports funding being made available to
DOE for clean-coal technology demonstrations, especially for near-term
applications that use natural gas in combination with other technologies for
flue-gas cleanup and for coal gasification to provide one of the most
cost-effective long-term methods to clean up our vast coal resources. In the
near-term, the use of gas in a reburn mode for nitrogen oxides (NOy)
reduction and as a transport medium for sorbent injection to reduce sulfur
dioxide (SO2) in coal combustion systems offers the potential for early
retrofit in many utility and large industrial boilers. These technologies
should be given high priority in any demonstration program.
GRI is an independent, not-for-profit scientific research organization that
plans, manages, and develops financing for a cooperative research and
development program for the mutual benefit of the gas industry and its present
and future customers. The R&D program is implemented through contracts with
research organizations, engineering, and other professional service firms,
universities, energy companies, and manufacturers. Even though GRI is not a
government contractor and does not accept federal funds, GRI cofunds and
coordinates many of its research programs with DOE. Therefore, Congress's
actions on the FY 1986 DOE budget have a direct impact on the gas industry's
research program.
A review of the DOE report to Congress, Emerging Clean Coal Technologies dated
May 1985 indicates the largest number of responses were in the four technology
areas that could have the most near-term impact on allowing the U.S. to
utilize its vast coal resources in an environmentally acceptable way. These
technologies — flue-gas cleanup, surface coal gasification, fluidized bed
combustion, and coal preparation — are all at a state of development where the
next logical step is field demonstration. Particularly encouraging to GRI is
that two of the technologies — flue-gas cleanup and coal gasification — would
use natural gas to clean up our nation's coal. These applications of natural
gas have tremendous potential. Since these four technolgies were proposed by
over 60 percent of the private-sector firms that responded, their
demonstration in cofunded field tests should receive immediate attention and
top priority.
267
Also, the DOE report noted that nearly all of the submissions requested direct
cost-sharing rather than other forms of financial assistance. This
cost-sharing is necessary due to the significant risks associated with the
technologies; the current softening of world oil prices; the inability for
many utilities to recover capital costs due to the novelty of the
technologies; a lack of evidence that the technologies are practical, useful,
and economical; and the need to accelerate the commercialization of the
technology through demonstrations so the technologies are available to
industry in the early 1990s. These factors convincingly indicate that direct
federal support through cofunding is required to accelerate the
commercialization of clean-coal technology. Without this federal support,
many of these technologies will not be demonstrated. Others eventually will
be demonstrated by the private sector but not in time to meet the nation's
need for future energy demands.
Another factor emphasized by the draft Energy Research Advisory Board (ERAB)
report on clean-coal technologies that must be recognized is that the number
of coal-use situations is so large and diverse and the specific problems are
so site-specific that no generally applicable technology or solution can be
presented. This is particularily true for retrofit applications which
represent the overwhelming majority of the market. The draft ERAB report also
noted, "DOE policy has recently excluded work beyond the proof-of-concept
stage; this policy limits timely commercialization of new technologies, and a
revision of this policy is recommended." Therefore, the use of federal funds
to cofund the demonstration of multiple technological approaches with industry
is the most viable solution to using our coals cleanly.
ROLE OF GAS IN CLEAN COAL TECHNOLOGIES
Federal policy has long overlooked the significant role natural gas can play
in helping the nation use coal in an environmentally acceptable manner.
Therefore, it is particularly encouraging to GRI and the gas industry that
several of the responses to demonstrate flue-gas cleanup include the use of
gas for both NOy control and to assist in SO2 control. In fact, for
near-term and many retrofit applications, gas used in combination with coal
combustion systems is probably the best solution.
Natural gas is our nation's cleanest fossil fuel. Its combustion emits
virtually no particulates, sulfur oxides, or reactive hydrocarbons, and it
produces far lower emissions of nitrogen oxides and carbon monoxide per unit
of energy than coal or oil. Used selectively, either alone or with other more
polluting fuels, relatively small quantities of natural gas could contribute
significantly to protecting our air quality in a least-cost manner. Given the
size of the gas resource base and the economics of gas production, the
competitive position of gas relative to other environmental control options
should remain favorable. In addition, a million-mile pipeline and
distribution network is already in place which extends to most potential
select gas-use customers. Thus, cost-effective solutions to using coal
cleanly are both possible and practical by using natural gas.
Gas can be used in one combustion unit to offset the emissions from dirtier
fuels, such as coal, in another unit; it can be used for simultaneous
combustion of gas and coal in a single combustor; and it can be used in
flue-gas cleanup systems as a transport mechansim for sorbent injection to
reduce sulfur oxides (SO^) and in a reburn mode to reduce NO^. Therefore,
268
using gas as part of the overall approach to controlling pollutant emissions
during coal use should become one element of national energy policy.
Additionally, coal gasification is another route, though longer-term, to using
our coal in an environmentally acceptable way.
FEDERAL ENERGY R&D FUNDING POLICY SHIFTS
It is important to review the shift in priority this Administration has
assigned to energy R&D when examining the need for DOE support for clean-coal
technology demonstrations. The dramatic decline in energy R&D funding is very
evident when comparing the FY 1981 and 1986 requests after deleting the
business-related functions. This decline is easily obscured since the
Administration included $2.4 billion of weapons R&O and $685 million of
general science activities in the FY 1986 energy R&D budget category. When
these non-energy-specific items are removed from the energy R&D budget, in
FY 1986 the Administration requested only 20 percent, or a $2.3 billion
allocation, for energy R&D programs, while in FY 1981 it requested about
60 percent, or $5.9 billion, for energy R&O.
Another factor limiting technology demonstration and transfer to industry is
that DOE has established a general policy of not funding research beyond
proof-of-concept. This policy of leaving hardware development solely to
industry sounds nice, but it hasn't worked. The result is a technology gap
that is widening as DOE continually withdraws to long-term and basic
research. The justification for intermediate-range energy applications R&D is
as strong as ever. DOE must once again reemphasize energy R&D and establish
technology development resulting in hardware projects and demonstrations as a
focal point for fossil energy research.
Energy R&D
General Sciences
Department Management
Defense Programs
DOE R&O AND DEFENSE
PROGRAMS
($ Billions^
FY 1981
FY 1986
$ 5.922
$ 2.295
0.523
0.685
ment 0.362
0.299
3.443
8.060
TOTAL $10,250 $11,269
If national energy policy continues this trend of constant reduction in energy
R&O spending and no federal support for technology demonstrations, we will
soon find ourselves without technology for full development of our vast
domestic fossil fuel resources. The result will clearly be to increase our
reliance, once again, on unstable foreign imports.
U.S. FUELS OUTLOOK
Another policy to consider in determining the most prudent federal role in
supporting demonstrations of clean-coal technologies is the extent to which
the U.S. must rely on coal to meet its electric power generation demands
269
between now and 2010. As a result of several major independent trends, the
use of coal in the U.S. is expected to continue to increase at a reasonably
steady pace for most of the next 25 years. The two major influences of this
trend are the continued high (compared to coal) price of oil and the reduced
contribution of nuclear power. Both private and federal forecasts agree that
the U.S. will continue to rely on fossil fuels for over 75 percent of its
energy supplies during the next 25 years.
Natural gas will continue to maintain an important role in a highly
competitive energy mix throughout the remainder of the century. In fact, GRI
projections indicate that with development of advanced technology for
extracting gas from tight formations there will be sufficient gas supplies at
competitive prices to increase annual consumption from today's level of
18 trillion cubic feet per year to approximately 20 trillion cubic feet per
year. With development and demonstration of new technology, gas can help meet
some of the new electricity demand in the 1990s.
However, unless technology is developed and demonstrated to allow the U.S. to
utilize its coal in an environmentally acceptable manner, the U.S. faces the
possibility of shortages in electric generating capacity in the 1990s. Recent
forecasts by our National Energy Plans have shifted from 4-percent-per-year
growth in the economy in the early 1970s to almost no growth forecasted in the
mid-1970s to about 2-percent-per-year growth in the early 1980s. At the same
time, during the past decade, electricity growth has ranged from an increase
of 7 percent per year to negative growth in 1983 for the first time in ^0
years. Under any reasonable scenario of growth, electric consumption will
increase. As stated by DOE Secretary Herrington in a speech on April 23,
"Demand for electric power has continued to show a strong relationship with
the growth of our economy." GRI's modeling efforts indicate future
electricity growth will be at a rate equal to approximately 85 percent of the
rate of growth of the economy. Therefore, unless our economy is totally
stagnant with resulting rapid increases in unemployment and misallocation of
resources, electricity demand in the 1990s will continue to increase and will
require the construction of new generating plants. If nuclear power does not
make a quick resurgance to survive as a viable future U.S. energy option, coal
is the major domestic energy option with sufficient long-term resources to
fuel the majority of these power plants. This scenario becomes especially
convincing when you consider that the U.S. holds one-quarter of the world's
known coal reserves, and electricity use, even with all of the conservation
due to higher energy prices and economic downturns, has grown by approximately
30 percent since 1973.
While the electric utilities and EPRI have done a good job of funding research
on options to burn coal cleanly, a clear need exists for a major DOE role in
demonstrating clean-coal technologies. The activation of the $750 million
clean-coal technology fund to allow DOE tc demonstrate clean-coal technologies
in partnership with the private sector would be a valuable investment for
securing our future energy needs under environmentally safe conditions.
A "TECHNOLOGY GAP"
In evaluating the ufgepcy pf moving forward with the clean-coal technology
demonstrations, it is informative to briefly recap the actions leading to the
Energy Security Act in June 1980. With the Iranian crisis in 1979, the U.S.
was faced, for the second time in six years, with skyrocketing crude oil
-4-
270
prices. Responding to the need to develop domestic sources of energy,
Congress created the Synthetic Fuels Corporation to provide financial
assistance to the private sector to undertake synthetic fuels projects. The
Energy Security Act authorized up to $88 billion for synthetic fuels
development, of which $20 billion was appropriated in 1980 for Phase I.
At the same time, DOE had a large and very aggressive fossil fuels
demonstration program. It was assumed that technology developed in these DOE
programs would be available for the SFC to draw upon for commercial
demonstrations, especially in Phase II. However, today the DOE fossil fuels
demonstration program has been terminated, and the SFC is under attack with
the possibility of having the financial resources available to assist
commercial synfuels projects either severely limited or terminated.
The result is a serious technology gap between long-term generic research and
conmercialization. DOE's current R&D policy does not fund "process"
development or pilot plant activities. However, the process development stage
is perhaps the most crucial stage in the development of a new technology. It
is during this stage that a good technical idea is turned into a process with
commercial potential. The construction and operation of a process development
unit (POD) leading to demonstration of the technology at pilot or pioneer
plant scale are both essential steps in advancing technology. Neither step
can be skipped. Yet DOE has determined these research activities are the role
of the private sector and will be guided by market forces.
However, in some industries, market forces are not sufficient. Many of the
markets in which energy is sold are not "free." As the Energy Research
Advisory Board (ERAB) noted in its 1982 report to DOE Energy R&D Priorities:
A little over half our primary energy finds its way to
consumers through the electric and gas utilities, and these
utilities are regulated, price-controlled industries
selling their products not at free market prices, but at
controlled prices. Both these regulated industries have
weak incentives to spend on R&D. If successful, the
benefits go to ratepayers; if unsuccessful, the expenditure
may be disallowed as "imprudent." A strong R&O response to
price signals requires both motivation and capability. In
many cases the capability is simply lacking.
If there is one thing the energy crisis of the past 12 years has taught us, it
is that uncertainty is the only certainty. Long-term energy forecasts have
proven to be consistently wrong. We cannot make policy assumptions with any
confidence regarding the direction of energy demand, production, and prices.
The real interest rates are double the historical experience, and the cost of
capital for construction is high. Also, it must be recognized that the
economics of many emerging clean-coal technologies are driven by the price of
world oil, and this price is not based on production costs but is established
by a cartel. In other words, the typical utility executive must make major
energy decisions in a very unstable and uncertain operating environment.
In this environment, the utility sector simply does not have the incentives to
make the necessary research investments to adequately demonstrate urgently
needed clean-coal technologies. Therefore, the DOE policy has created a
serious technology gap. The use of the clean-coal technology reserve to give
DOE the resources to cofund these demonstrations with private industry is
needed to close this gap.
-5-
271
Two gas-related technologies that can make a major contribution to using our
nation's coal cleanly are coal gasification and gas-enhanced dry sorbent
injection and reburn. Both require federal support for field demonstrations
to close the "technology gap."
Coal Gasification
The establishment of a commercial coal gasification industry depends not only
on the development of technically and economically viable coal conversion
processes, but also on the extent to which those processes are compatible with
the environment. New technologies are required to meet the nation's
increasingly stringent environmental standards. Advanced coal gasification
technologies, with the potential for significant technical, economic, and
environmental improvements compared to the commercially available technology,
have emerged from the extensive R&D programs that have been supported by the
federal government, by GRI, and by other organizations.
In response to the DOE Office of Fossil Energy solicitation for statements of
interest for projects related to development of emerging clean-coal
technologies, GRI submitted a proposal for a coal gasification test facility
at an existing host site. This project would result in the large-scale
validation of advanced coal gasification processes for combined-cycle power
applications, for producing pipeline-quality gas from coal, for gas cleanup
and methanation, and for testing components and instrumentation.
For these advanced technologies for producing gas from coal (whether for power
generation or pipeline-quality gas) to receive adequate consideration as a
supplemental energy option, engineering performance data must be available
from commercial-size or near-commercial-size systems in the mid-1990s. This
will permit the reliable definition of capital requirements and end-product
gas costs under conditions where the technical risks associated with the
scale-up of the advanced technologies have been reduced to an acceptable level.
GRI is proposing to place a commercial-size or near-commercial-size advanced
coal gasification process in an industrial environment where existing
supporting systems and utilities are available and where the gasifier products
could be utilized in the industrial operation. The gasifier should be
oxygen-blown and operate at a pressure of ^50 psi to 500 psi in order to
provide data relevant to gas production. The program should be structured to
accommodate the integrated slip-stream testing of the advanced downstream
processing components that would be used to upgrade the gasifier products to a
pipeline quality gas.
In 1984, at the request of the Congress, the U.S. Department of Energy
conducted a preliminary study to examine the feasibility of installing and
operating a semi-works, fluid-bed gasifier at the Great Plains Coal
Gasification plant. The study was prompted by the recognition of the need to
develop engineering data at a large scale for the advanced gasification
technology that was under development in the U.S. and the existence of a large
coal gasification plant infrastructure that could help defray the costs
associated with developing the required system performance data. In addition
to providing detailed technical data on gasifier operation and environmental
interactions, substantial experience would be gained in operating
commercial-size units based on the fluid-bed, ash-agglomerating technology.
272
Project Schertilft I arqe Srjtle DemnnsUration- Emercdna SNG TectinQiQav
Activity
1986 1987
1988
1989
1990
1991
1992
DetaUed Project Definition
Engineering Design
Gasifier Constnction
Gasifier Operation
Direct Methanation Uhit Design
[Direct Methanation
Construction
Integrated Operation
Advanced Clearnjp System
(Jestgn
Advanced Clean-U|3 System
Construction
Integrated Operation
msmm
v/m/mm
WM/mm/m
vm/)///////////////mm//m/mm7mm.
wM/mm/mm/mmm
wmmm,
>m/mmm;m
v/mmm/mm.
-7-
273
The DOE study concluded that the concept of continuing the development of
advanced fluid-bed coal gasification technology at the semi-works (600- to
l,odo-tons-per-day) scale at the Great Plains coal gasification plant was
feasible and had merit. The attitudes of the owners and all levels of
management at the Great Plains facility were very supportive of the concept
and the use of the facility for such purposes. The developers of the gasifier
technologies that might be candidates for continued development at the
semi-works scale at the gasification facility also supported this approach to
advanced gasifier technology development.
The study considered a test program that would be more comprehensive than just
an advanced gasifier activity and would provide for the testing of additional
gas processing components. Such components could include advanced downstream
processing systems designed for the production of pipeline-quality gas and
systems for integration with advanced electric power generation systems, i.e.,
hot gas cleanup, combustion turbines, etc.).
It is estimated that the design and construction of a l,p00-ton-per-day unit,
and the necessary modifications to the existing facility would cost
approximately $80 million and would have attendant annual operating costs of
approximately $12 million. Assuming six years of operation, the total project
cost would be about $150 million. A government/ industry 50-50 cofunded
project is appropriate at this time because short- and mid-term uncertainties
of energy supply make it impossible to identify sufficient short-term
incentives that justify capital expenditures for technologies where technical
risks have not been demonstrated to be low.
No current commercial system has been satisfactorily demonstrated for
high-sulfur caking coals, which are predominantly found in the eastern parts
of the U.S. Some advanced concepts, however, have emerged from the extensive
R&D efforts and appear to offer the potential for significant improvements
over the technology that is commercially available for converting eastern coal
to gas. These improvements are in the form of increased flexibility, lower
capital costs, lower operating costs, reduced end-product gas costs, and
reduced environmental impacts.
GRI's proposed coal gasification gas test facility project has the following
principal objectives:
1. To demonstrate that the emerging coal gasification technologies have
direct application to the production of pipeline-quality gas from eastern
coal and offer significant technical, environmental, and economic
advantages over the commercially available state-of-the-art technology.
2. To validate the performance characteristics of the emerging coal
gasification technologies at a scale that will provide the heat balance,
material balance, environmental data, and operational data needed to
develop reliable cost estimates for future coal-to-gas plants based on
these technologies.
3. To demonstrate the integrated performance of advanced gasifier technology
and advanced downstream processing technology such that commercial systems
could be constructed to maximize the technical, economic, and
environmental advantages of these technologies.
-8-
274
Federal cofundinq of this advanced coal Qasification test facility with the
private sector through the use of funds from the clean-coal technology reserve
would be a cost-effective and prudent investment in the U.S. energy future.
This should be assigned a high priority in any clean-coal technology program.
Gas-Enhanced Dry Sorbent Injection and Reburn
Concern over acid precipitation and anticipated acid deposition legislation
has created an incentive for government and industry to develop more
cost-effective technologies to control both sulfur and nitrogen oxides from
coal and oil combustion, particularly utility and large industrial boilers.
To accelerate the development of flue-gas cleanup technology and to
demonstrate the use of gas for both reburn technology to reduce NOx and
sorbent injection technology to reduce SOx. GRI recommends that DOE give top
priority to cofunding a project demonstrating those approaches as part of the
clean-coal technology initiative.
The tests should be conducted in a boiler situated in the Midwest to provide
easy access to all eastern coal-producing states. The tests would be based on:
1. Pollutant emissions (absolute reduction of NOx ^"^ ^"^x)
2. Impact on boiler performance and operability.
3. Cost of the technology (dollars/ton of pollutants removed).
i*. Tolerance to boiler design and coal variations.
GRI and the U.S. Environmental Protection Agency are currently cofunding the
Energy and Environmental Research Corporation (EERC) of Irvine, California, to
develop dry sorbent injection technology combined with combustion modification
technigues to control SOx and NOx emissions from coal and oil combustion.
GRI's portion of this study is to examine control of NOx and SOx emissions
from coal combustion by incorporating two developing gas combustion
technologies which can be applied individually or as an integrated system.
1. Reburn Technology. Use of natural gas as a reburning fuel to reduce NOx
emissions.
2. Sorbent Injection Technology. Use of natural gas to generate more
reactive and higher capture efficiency of sorbents for enhanced SOx
reduction.
The EPA and other research groups within the government and the private sector
are investigating methods to enhance the cost-effectivelness of sorbent
injection technologies, e.g., limestone injection multistate burner (LIMB),
for SOx a"«^ NOx control from coal and oil combustion systems. EPA has
provided $860,000 ($^00,000 in FY 1983 and $/i60,000 in FY 1984) in coordinated
funding for the project via their existing reburn/sorbent injection contract
with EERC. (»rs project ($937,900), which began in April 1984, expands EPA's
original focus on coal-fired reburning/sorbent injection at EERC to include an
evaluation of the additional benefits (e.g., cost reduction, increased
emissions control, etc.) obtainable from the use of gas.
275
GAS APPLICATIONS
RESEARCH
Gas Consumption
10-20% of Load
Gas + Air +
Sorbent
Coal
Gas Enhanced Dry Sorbent Injection
Plus Gas Reburn -
SOx/NOx - Control
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276
Sulfur oxides can be controlled by removing sulfur from the fuel or sulfur
oxides from the products of combustion. However, current methods such as
scrubbers or coal cleaning generally are capital intensive with high operating
and maintenance costs or do not provide the necessary degree of SO^
control. One of the more promising SOy control strategies is to inject
calcium based sorbents into the combustion chamber and capture the sulfur
prior to the boiler outlet. This process was investigated in the late 1960s
and was abandoned because it could not achieve the desired SOx control and
also tended to create operational problems. Recently, there has been
sufficient incentive to re-examine the limestone injection process (e.g.,
LIMB) as a cost-effective alternative that could approach FGO sulfur removal
at a lower cost. The EPA's efforts in recent years have focused on the
development of this technology for coal-fired boilers. Q^I's program with
EERC is to enhance the cost-effectiveness of this technology through the use
of gas combustion technology. Gas may offer significant sorbent injection
performance benefits because it can be used to more effectively control the
conditions at which limestone sorbent is calcined and mixed with the coal or
oil combustion flue gases; it can avoid coal-ash/sorbent interaction problems
that decrease sorbent surface area; and it can be used more effectively to
optimize the temperature profile of the sulfation zone where sulfur capture
occurs.
Nitrogen oxide emissions are also considered, although historically to a
lesser extent, as a contributing factor to acid deposition. The attention to
NOx as an acid deposition processor is increasing as scientific evidence
tends to indicate that both SOx ^^^ ^^x ^^^ contributors. The formation
of NOx during the combustion of fossil fuels can be minimized by appropriate
modification of the combustion mixing process.
Recently, the Japanese have been exploring a new NOx control strategy which
involves in-furnace NOx reduction by downstream injection of fuel. EPA is
currently conducting research programs to evaluate the potential of this
technique for application to U.S. boilers. The term "reburning" has been
coined in the U.S. to refer to this process. Where using gas as the reburn
fuel, it is believed that this technology is capable of reducing NOx ^y
approximately 50 to 60 percent beyond the current NSPS level achievable with
low NOx burners. The use of coal or oil as a reburning fuel may introduce
operational problems because of poor carbon burnout resulting in a loss of
efficiency as well as slagging in the platens or primary superheater region.
The specific technical benefits of using gas as the reburning fuel are that
gas can be applied without the combustion problems associated with coal-firing
in upper boiler regions; gas allows lower exhaust NOx emission levels to be
achieved since it is nitrogen-free; and gas avoids the presence of molten ash
in the superheater boiler region, thereby minimizing slagging and fouling
problems.
The use of gas technologies could also have an application in those instances
where oil-fired boilers are being converted to coal/water slurry mixtures.
Combustion systems which burn coal water slurries efficiently in boilers
designed for oil rely upon efficient fuel air mixing, precisely those
conditions which promote the formation of nitrogen oxides. Consequently, any
conversion could result in a considerable increase in both SOx ^^^^ ^^x
emissions. An additional problem associated with conversion to coal-water
slurries is the need to derate the unit to prevent excessive erosion in the
convective sections. Natural gas used as a reburning fuel with or without
sorbent injection can help solve two problems — pollutant emissions and unit
derating.
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277
Potential benefits of gas use are both environmental and economic. The
development of more cost-effective SOy, NO^ and combined SO^/NOx
control technologies using gas would lower energy costs and improve air
quality. The economic benefits are broad-based and provide an alternative to
high-cost flue-gas scrubbing technologies and increased ability to use the
nation's natural resources along with a decreased dependency on imported oil.
The environmental benefits would accrue by significantly reducing the quantity
of pollutants emitted by coal or oil burning.
In conclusion, gas has the unique advantage of allowing the simultaneous
application of reburn and sorbent injection technologies in the same boiler.
Over the next five years, GRI plans to spend approximately $5 million to
$6 million to support research and development of the reburn/sorbent injection
technology for application to industrial and utility boilers. By using
natural gas to enhance reburn/sorbent injection technology, GRI's goal is to
increase the NOy/SOx capture performance of this technology to NOy
levels lower than attainable with low-NO^ burners and to attain SO^ levels
approaching that of wet scrubbing but at a significantly lower cost.
Different technology variations are being explored at both bench and pilot
scales. The next step is to initiate full scale testing of reburn technology
starting in 1986. This testing should be performed using an industrial boiler
to demonstrate retrofit applications. —
Multiple field tests of reburn/sorbent injection technology are required as
application techniques are likely to vary significantly with boiler type
(cyclone, pulverized coal, stoker, etc.) It is estimated that field testing
of these two technologies will require an investment of approximately
$25 million to $30 million dollars over the next five to seven years.
Government participation to demonstrate the use of qas in reburn/sorbent
injection technology development as a central element of the clean-coal
initiative is needed to provide incentives to the utility industry via
mitigation of the financial risks.
RECOWENDATIONS
As a result of reviewing the DOE report, the draft ERAB report, and the
current status of coal gasification and gas reburn and sorbent injection
technology, I recommend the following:
1. Congress must recognize that DOE has a leading role in demonstrating new
clean-coal technologies. There is a clear need for the federal government
to continue the natural progression of development for a new technology
from the laboratory and proof-of-concept state through the technology
demonstration phase.
2. Congress should appropriate funds in FY 1986 to initiate a limited number
of the proposed clean-coal technology demonstrations. Priority should be
given to the four technologies proposed in over 60 percent of the
responses — flue-gas cleanup, coal gasification, fluidized bed combustion,
and coal preparation. Use of natural gas in the demonstration of flue-gas
cleanup should be assigned a top priority.
3. The private partner should be responsible for providing a significant
portion of the construction and operation costs of the facility. By
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278
requiring the industrial partner to bear a substantial risk, the
government can expect the private partner to utilize its full capabilites
in designing, constructing, and operating a successful facility. It only
makes sense, then, for the private partner to be responsible for selecting
the process, site, size, energy source, management, and end product for
the project.
The executive branch should leave the day-to-day management of the project
to the industrial partner. The Energy Security Act incorporated a sound
philosophy on the role of the SFC program managers in joint ventures that
should be adopted by DOE in any demonstration program. Participation is
"limited to financial participation only and shall not include any direct
role in the construction or operation of the module." Even in the case of
direct funding by the SFC, the Act makes it clear that "In no event . . .
shall the persons in the joint venture agreement be denied the primary
responsibilty for management of the joint venture."
In determining which proposals to select, it should be recognized that a
stand-alone plant will usually be the most expensive type of technology
demonstration and, therefore, should only be considered as a last resort.
Priority should be given to proposals that use existing sites.
The SFC should be encouraged to make provisions in its financial
assistance program for commercial synfuels plants to require the
capability for testing advanced technologies at the plant site in the
future.
CONCLUSION
In conclusion, the current federal energy research policy has created a
"technology gap" for fossil fuels research by restricting the DOE role to
proof-of-concept research. There is a need for a viable federal role in the
applied and engineering research phases of coal conversion and utilization
processes. Congress can take a bold step toward closing this "gap" by
appropriating funds in FY 1986 for clean-coal technology demonstrations to be
cofunded with industry. Without this federal support, the timely development
of advanced processes to use the nation's vast coal resources in an
environmentally acceptable manner will be seriously delayed. A joint
DOE/ industry program is needed now.
Mr. Chairman, this completes my testimony. I will be happy to respond to any
questions.
questions
279
Mr. Boucher. I thank both of the witnesses for their thoughtful
testimony this morning.
As you may have heard previously, Secretary Vaughan reported
on the conclusions of the Department of Energy with respect to
whether or not there should be a Government role in helping to
finance the demonstration-scale phase of these emerging coal tech-
nologies. And his conclusion is that the Government should not,
based upon his conclusion, apparently, that these technologies will
be commercialized on their own. That private industry will carry
the freight on that, and that there is no appropriate role for the
Government for that reason.
Now, I gather from your testimony that you disagree with that
conclusion. Why is Secretary Vaughan wrong in that? What can
you tell us that would lead us to conclude that these technologies
will not be commercialized absent a significant Government role?
Mr. Mannella. Mr. Chairman, let me answer part of that at any
rate. I think that the difference comes in the interpretation of the
time frame in which they are needed. With regard to many of the
technologies that EPRI is investigating and discussing one could
say that in the long run ultimately they probably would be demon-
strated by the private sector. The problem that we have is that the
generating capacity will be needed by the year 2000, or before the
year 2000. And if you look at a calendar and you begin to work
backwards. Considering the length of time it takes to bring this
generating capacity on line, you begin to see that there is a window
now and for the next year or two. If one could move out, demon-
strate these technologies, operate the plants for the requisite 2 or 3
years it would take to build the confidence to decisionmakers to go
ahead and make those decisions, construction might then begin in
the early 1990's and that generating capacity would be available in
the mid to late 1990's.
Absent that we will have the situation that my colleague, Mr.
Webb, described so graphically, shortages and perhaps stifling of
the economy. So, it is a matter of the interpretation of the time-
frame in which it is needed that I think is the basis of difference of
opinion.
Mr. Boucher. That being the case, what is your recommended
level for funding for the clean coal technology reserve in fiscal year
1986? $750 million is authorized. Obviously that total amount could
not be expended in 1 fiscal year; at least in the first. What is your
recommended funding level for the next year?
Mr. Mannella. Well, I would feel a lot more comfortable in an-
swering that if I had seen all of the submissions and the imputed
values that they suggest. I think that in addressing the question of
the amount we have to bear a couple of things in mind. When the
Federal Government signs a contract with anybody for goods or
services, by definition it is spent at that point. Now, it is true the
contractor has not spent it. There is an account set up in the
Treasury, and as vouchers come in as work is performed that
amount is drawn down.
So, in answering the question I would say that I would be sur-
prised, if, within the totality of the 175 submissions totaling $8 bil-
lion, as Mr. Vaughan indicated this morning, that one could not
find 200 million dollars' worth of work to begin. And that if you
280
take them in order of priority, you don't start small and work big
as you go down the list. Quite the reverse; you start big and go
small as you work down the list of priorities.
Mr. Boucher. Mr. Webb, do you care to comment?
Mr. Webb. I would just add one thing. I think what I would do is,
if it were my decision to make, say, OK, let's concentrate on the
near-term technologies. That ought to be the initial thrust. Author-
ize, not actual outlays, authorize somewhere approximately a third
of the clean coal reserve over the next 2 years. Because I don't
think they can get the mechanics going such that you could get all
of it in place.
Additionally, I would say give priority to those proposals that
come in and are going to do the demonstration at an existing facili-
ty, so as much as possible of the capital and construction costs can
be eliminated.
And finally, give a preference to co-funding, particularly if the
cofunder is the user, not the industrial firm that will capture some
of the economic rent. The electric utilities, per se, like EPRI repre-
sents come in a user class. They are not going to make any profit
off the technology if they can get it out there. They serve their
members and, in turn, the citizens of this country.
So that is the way I would approach it. I would say put about a
third of it available for authorization over the next 2 years, focus
on the near-term technologies, go out with the RFP's, get the re-
sponses back, evaluate them against some set of criteria, and make
some awards and let's get started.
Mr. Boucher. The suggestion was made, and I think there is gen-
eral agreement, that to the extent that we have a program there
should be a selection based in large measure on market forces in
terms of the Government's role in funding projects. One criterion
to look at, obviously, is the percentage of private industry invest-
ment that would be applied to a particular project.
Would you agree that that should be the primary criterion, and
should there be other criteria that should be looked at as well?
Mr. Webb. If I may respond, I think it should be at least one of
the two major criteria. I think the second one ought to be, as Eric
Reichl stated, the data base behind the technology proposed. Be-
cause a fellow could come in and propose 50 percent co-funding in a
technology that truly can't have any impact before the year 2000
and has a data base so small that the risk of it ever being success-
fully implemented by a conservative investment like the utility
sector of something around 10 percent. That is not a good invest-
ment of taxpayers' money.
So I think you need both criterion, but cofunding certainly is at
least as important as any other one.
Mr. Boucher. Mr. Mannella, would you care to comment?
Mr. Mannella. Well, I agree with what Mr. Webb said and what
Mr. Reichl said earlier. I think that we would like to add a good
measure of evaluation of the particular technology and the role to
which it fits, the broad spectrum of, in our case, utility applica-
tions. I think one has to weigh the technology that is, say, ideally
suited for new baseload versus retrofit versus when it can be used
for both. Inasmuch as there are a significant number of utilities
out there representing very different geographical and economic
281
considerations I think that evaluation of the technology and the
extent to which it fits would be an important criterion that we
would like to focus on.
Mr. Boucher. Thank you. My time has expired.
Mr. Packard.
Mr. Packard. Thank you, Mr. Chairman.
Do either of you gentlemen have any information as to what our
present coal consumption is in this country?
Mr. Mannella. Somewhere in the neighborhood of 600 million
tons a year I believe.
Mr. Packard. I believe that one of the previous witnesses indi-
cated that it could conceivably in the early part of the 1990's reach
over a billion tons. Do you agree with that?
Mr. Mannella. I really don't have any basis for agreeing or dis-
agreeing. I do recall a number of years ago when there was interest
in increasing the use of coal that there was talk about a billion
tons per year as sort of an upper limit.
Mr. Packard. And I would have to assume that that is if we find
technology to clean it up.
Mr. Mannella. I would say that is correct.
Mr. Packard. What kind of a savings would that bring to the in-
dustry?
Mr. Mannella. Well, compared to what? Compared to the use of
oil?
Mr. Packard. Well, I would assume that much of that increase
will replace other energy sources.
Mr. Mannella. Well, that certainly could happen, Mr. Packard,
but I think that Mr. Reichl touched on a very interesting point in
his presentation this morning. And that is that we have the overall
problem of using coal cleanly in existing and in a new capacity
that would come onstream for national health effects and concerns.
Mr. Packard. So your general feeling is that the increased use of
coal, if we can find the technology that can clean it up, would be to
accommodate additional industry and use, rather than replace ex-
isting oil and gas usage?
Mr. Mannella. I think there would be some of that as well. I
think it would serve a number of different needs.
Mr. Packard. It would appear to me, particularly in light of your
statement, that 80 to 90 percent of the coal use will be in producing
electricity and that we would probably see utilities replacing exist-
ing sources of energy— gas, oil— with coal. In your judgment, do
you think that is a true statement?
Mr. Mannella. Well, a lot of that has already happened, and
more of it certainly will as the technologies become available.
Mr. Packard. In your sixth statement, Mr. Mannella, "environ-
mental concerns cast a cloud over the degree to which coal utiliti-
zation technologies must be upgraded to be viable options," I don't
know whether I am reading into it an implication that is not there,
but I would like your comment. The implication may be that either
we should reduce environmental standards and regulations or it
may cast doubts on our ability to develop technology to make coal
a more viable use for energy.
Mr. Mannella. No, that is not what I meant to convey there.
What I meant to convey there is that while we are developing tech-
282
nology that will perform certain beneficial functions, and always
keeping in mind the need to do it at an economical cost, that there
is somewhat of a moving target for the degree to which the tech-
nology must perform. There is some uncertainty as to the direction
or the extent of the need for environmental action.
Mr. Packard. Like hazardous waste and Superfund problems,
the question always comes up how clean is clean. In your judg-
ment, is that going to be a problem with coal and its usage?
Mr. Mannella. All I can say is that the industry will comply
with whatever regulations are on the books.
Mr. Packard. And you are not suggesting those regulations need
to be altered, then?
Mr. Mannella. I am not making that suggestion.
Mr. Packard. Do you have a feel for when we might be able to
reach, if we go at the concurrent levels of research and develop-
ment, when we might reach a point where coal can be used in an
unlimited fashion, meeting and complying with existing environ-
mental regulations?
Mr. Mannella. Well, we are using a lot of coal now, and we are
meeting the environmental regulations, particularly I believe for
the newer plants that come under the New Source Performance
Standards. And there are technologies under demonstration now
such as the integrated gasification combined cycle at Cool Water
that has been mentioned, and the atmospheric fluidized bed work
that has been mentioned that will be going into TVA, Northern
States Power, and Colorado Ute. So it is certainly not a question
that we do not have any options whatsoever on how to burn coal
cleanly.
Mr. Packard. That is true.
Mr. Mannella. It is a question — and I believe that Mr. Fuqua
touched on it in his opening comments — of having the technology
readiness for the decisions to be made at such time that the econo-
my dictates that they must be made.
Mr. Packard. Thank you, Mr. Chairman. My time is up.
Mr. Boucher. Mr. Bruce.
Mr. Bruce. No questions.
Mr. Boucher. Gentlemen, I would like to thank you very much
for your thoughtful testimony this morning. We appreciate very
much your presentation.
Mr. Webb. Thank you, Mr. Chairman.
Mr. Mannella. Thank you.
Mr. Boucher. The next panel consists of Mr. John Wootten, di-
rector of research and technology for Peabody Holding Co. and Mr.
John McCormick of the Environment Policy Institute.
Gentlemen, we welcome you this morning. I would also ask the
witnesses to restrict their opening statements to approximately 10
minutes and, without objection, the written statements will be re-
ceived and made a part of the record.
The Chair recognizes Mr. Wootten.
283
STATEMENTS OF JOHN M. WOOTTEN, DIRECTOR OF RESEARCH
AND TECHNOLOGY, PEABODY HOLDING CO., INC., ST. LOUIS,
MO, TESTIFYING ON BEHALF OF THE CLEAN COAL TECHNOLO-
GY COALITION; AND JOHN McCORMICK, ENVIRONMENT POLICY
INSTITUTE, WASHINGTON, DC
Mr. WooTTEN. Thank you, Mr. Chairman.
Members of the subcommittee, my name is John Wootten. I am
director of research and technology for Peabody Holding Co. I am
appearing before you today as a member of the Clean Coal Tech-
nology Coalition, which is a group of utilities, equipment suppliers,
coal producers, architect-engineers and the National Coal Associa-
tion. A membership list along with a copy of the coalition's state-
ment in support of the clean coal program is attached to my state-
ment. I intend to summarize my testimony in the essence of time.
Members of our coalition have joined together as varied public
and private entities to promote the rapid implementation and fund-
ing of the clean coal technology development program. As you re-
quested, Mr. Chairman, I intend to comment on the Department of
Energy's report, which addresses the clean coal technologies.
The coalition does not agree with the Department's conclusion
that Federal incentives will not accelerate commercialization of
clean coal technologies. I believe the TVA atmospheric fluidized
bed demonstration project, of which Peabody is a supporter, is a
prime example of just the opposite conclusion. Federal Government
participation is accelerating development of that project.
On the same day that the Department transmitted its report to
Congress on clean coal submissions, the Energy Research Advisory
Board, DOE's own panel of outside experts, disagreed with that
very conclusion. I think there has been enough comment on that,
but I will just say that the Coalition also agrees with the ERAB
recommendation that DOE should intervene in that area. The De-
partment's clean coal report simply reflects and restates pre-exist-
ing policy, that private industry should do the demonstrations.
The need to develop new coal utilization technologies is premised
on two related factors. First, new electrical generation not current-
ly planned or under construction will be needed in the 1990's to re-
place aging facilities, to reduce the dependence on oil and gas-fired
power generation and to ensure that economic growth is not sty-
mied for lack of adequate electrical supplies.
Second, the continued or expanded use of coal will be dependent
in part upon the development of new technologies which offer cost
effective means for protecting the environment while producing a
reliable source of electrical energy.
This subcommittee may know that there are currently wide dif-
ferences in projected future demands for electrical power. There is
a consensus, however, that new capacity will be needed, even
though the rate of increased demand is not agreed upon. For an
annual growth rate of IVi percent, sometime in the early to mid-
1990's peak electricity demand is expected to exceed installed ca-
pacity and some new capacity above that which is already planned
will have to be installed. Current trends in the utility industry
strongly suggest that a new capacity may not be built in time to
meet this increased need. If, for example, the projected capacity
284
needs of the mid-1990's are being met with conventional generating
units that take from 7 to 10 years to permit, design, construct and
place in service, utilities must undertake those new power plants
now. This construction is not being undertaken.
Further, many utilities have canceled or abandoned the construc-
tion of large baseload facilities and are now unlikely to undertake
major new construction programs. Also, new demand, and there-
fore new capacity, requirements of many utilities will come in
much smaller increments which do not warrant construction of
large-scale conventional power plants.
These and other circumstances cause considerable uncertainty
within the electric utility industry, and this uncertainty simply
means that the utilities will be even more cautious in adding ca-
pacity, especially adding capacity which utilizes new technologies.
Beyond the need for additional capacity in the 1990's, coal use
will be paced by our ability to protect the environment. Conven-
tional coal-fired powerplants can comply with current and proposed
environmental requirements, but the dollar cost is high. For exam-
ple, the cost to retrofit a flue gas desulfurization system on a 10-
year-old powerplant can easily exceed the original investment in
that facility. As the demand for coal-fired power production in-
creases, the current requirement for emission limitations will con-
tinue or may be made more stringent. If proposed acid rain legisla-
tion is enacted, utilities could pay approximately $200 billion over
the remaining life of the plants in question in order to comply.
Utilities would have no choice but to spend their limited funds to
comply rather than the construction of clean coal projects.
A more desirable approach to meet the demand for electricity
and to protect the environment is the timely development of new
coal utilization technologies. Chart 6, which is the last chart on my
testimony, attempts to depict the possible advances in emission
control likely to result from development of these various clean
coal technologies. Further, a number of these clean coal technol-
ogies offer shorter construction leadtime, improved fuel conversion
efficiency, the ability to burn a wider variety of coals, and the op-
portunity to construct powerplants in modules which better match
capacity additions to the need for the electricity.
While the development of these technologies may be attractive,
there are a number of factors which stymie aggressive utility devel-
opment. The utility industry does not operate in a free market-
place. Return on the electric utilities' investment in a new technol-
ogy is governed by the Public Utility Commissions which are gener-
ally charged with the task of minimizing ratepayer costs. Risks un-
dertaken by utilities in technology development may be placed pri-
marily upon the shareholders of the utility and not the ratepayers.
Given that the domestic power generation market may be very
limited for some time to come, coal companies and utility equip-
ment suppliers are unable to contribute substantial dollars to the
costly demonstration of new clean coal technologies.
Our coalition agrees with the DOE that the private marketplace
should be responsible for the widespread commercialization of new
coal technologies. However, in order to accelerate the commercial-
ization of these technologies in the required timeframe, the sharing
of the cost by the Federal Government is necessary. For its part,
285
the private sector is willing to provide very significant private
moneys toward the demonstration of new high risk technologies.
The Federal Government is being asked to participate with the pri-
vate sector in the commercial demonstration phase by sharing a
portion of the cost for these new technologies.
Mr. Chairman, there is little time in which to address the elec-
tricity needs of the 1990's. If new coal technologies are to be uti-
lized to meet expected capacity demands during the mid to late
1990's, those new technologies must be commercially demonstrated
and available in the 1990 to 1993 timeframe. It takes approximate-
ly 3 years to design and construct a demonstration and 2 years to
adequately test it. Therefore, to be available in the early 1990's,
these clean coal technology demonstrations must be initiated in the
1985 to 1988 timeframe. This timeframe is already upon us.
Further, pending legislation calling for emission reductions from
existing powerplants make the timely development of clean coal
technologies even more acute. Compliance dates between 1990 and
1995 require that new retrofit technologies be available for use in
existing plants in the 1987 to 1990 time. Given this timeframe, the
commercial demonstration of technologies which can be used in
retrofitting existing plants must also be conducted over the next 3
years. Otherwise, this option for compliance may not be available.
The next 10 years are very important for both assuring future
environmental acceptable electrical supply and for controlling the
cost of electricity. The commercial demonstration of clean coal
technologies is at least one important option which this country
would be wise to pursue in planning for ways to meet increased
demand in an environmentally acceptable manner.
This concludes my statement, and I would be glad to answer any
questions that I can.
Mr. Boucher. Thank you, Mr. Wootten.
[The prepared statement of Mr. Wootten follows:]
m r 1 1
286
STATEMENT OF MR. JOHN M. WOOTTEN
ON BEHALF OF THE CLEAN COAL TECHNOLOGY COALITION
Mr. Chairman, Members of the Subcommittee, my name is John
M. Wootten. I am Director of Research and Technology for
Peabody Holding Company, Inc., the parent company of Peabody
Coal Company. Peabody Coal is the largest coal producer in the
United States with active operations and reserves in both the
low-sulfur coal producing areas of Appalachia and the western
United States, and well as the high-sulfur coal producing areas
of the Midwest.
While Peabody did not submit a proposal to the Department
of Energy as a part of the clean coal technology solicitation
we are very interested in and supportive of this endeavor. Our
company, as you may know, is a participant in the 160 megawatt
atmospheric fluidized bed combustion project sponsored
principally by the Electric Power Research Institute (EPRI),
TVA, Duke Power and the State of Kentucky. The project is
located in Paducah, Kentucky; it is currently under
construction and is scheduled for start-up in 1989. Without
$30 million being provided to the project by the government,
which enabled the project sponsors to close a gap in the
financing, this important clean coal utilization facility might
have been undertaken at a much slower pace. Government
assistance has clearly accelerated development.
In addition, Peabody has committed funds to two other
projects and is evaluating participation in four others, all of
which have submitted clean coal technology proposals to DOE. A
complete commercial demonstration of these projects will
require significant private sector support with an equal or
lesser degree of support from government. Without government
support, the commercial demonstration of these projects and
other equally important clean coal projects will be slowed or
left undone, preempting their timely application to meet this
country's future energy and environmental goals.
INTRODUCTION;
I am appearing before your Subcommittee as a member of the
Clean Coal Technology Coalition, an ad hoc group of utilities,
equipment suppliers, coal companies and architecture,
engineering and construction firms and the National Coal
Association. I ask that the membership of our group, along
with a copy of the Coalition's statement in support of the
clean coal program, be included in the hearing record at the
conclusion of my remarks.
287
The Clean Coal Technology Coalition was organized earlier
;his year to provide a means by which interested private and
jublic sector parties might communicate to Congress and the
administration a collective viewpoint in support of the clean
:oal technology development program. Thus, no matter what
Interest an individual company or state government might have
Ln obtaining government assistance for a particular technology
)r project, we have joined together in the hope of
demonstrating to Congress that varied private and public
entities support the need for a federally-assisted clean coal
lechnology development program. Our interest as a coalition is
:o promote the rapid implementation and funding of a program
tfhich we believe makes imminently good sense.
On behalf of the member companies, industry associations
and state governments associated with the Clean Coal Technology
:oalition, I want to thank you for this opportunity to comment
on th§ need for the program. Also, as you requested,
vir. Chairman, I intend to comment on the Department of Energy's
recently submitted report to the Congress which addresses those
proposals and statements of interest that were submitted to the
DOE last February as a result of a Department of Energy
solicitation directed by provisions of Public Law 98-473.
We do not agree with the Department's conclusion that
"Federal incentives will not accelerate commercialization of
these [clean coal] technologies and may be counterproductive to
their development." (See page 1-4 of the Report to Congress on
Emerging Clean Coal Technologies. May 1985.) The DOE states
in the report that this conclusion was reached based upon ^the
Department's previous experiences with Federal incentives."
According to the Department, most projects that have received
Federal assistance in the past have not led to successful
commercialization of new fossil technologies. I believe the
Paducah fluidized bed combustion project is an example of just
the opposite conclusion. Federal government participation is
accelerating development and will greatly assist the private
sector participants in providing the experience required for
near-term widespread application of this technology in utility
settings.
Ironically, perhaps, on the same day that the Department
transmitted its clean coal report to the Congress, the Energy
Research Advisory Board (ERAB), DOE's own panel of outside
energy research experts, adopted a report to the Secretary ot
Energy which states in part:
"Within the clean use of coal area the
overall DOE program is well dispersed and
all major technological areas are covered
in some way. However, the budget does not
288
allow DOE to help with the transfer of the
new technologies to the private sector and
to assure their commercialization. This is
the result of basic policy which should be
reconsidered.
In most instances, the current policy of
abandoning a development after Proof of
Concept has been established will result in
just that, abandonment." (Page 19, emphasis
added. )
The current DOE policy is to stop government involvement in
technology development before the demonstration or process
development stage (see Chart 1). The conclusions reached by
the Department in the clean coal report simply reflect and
restate this policy notwithstanding the contrary advice given
by the government's own panel of outside experts.
Industry's response to the recent DOE solicitation, in
which 175 submittals were made, including 159 submissions
proposing specific emerging clean coal technology projects in
29 states, also evidences a view contrary to the DOE ' s
conclusion. The private sector will proceed with, and not
abandon, clean coal technology development if government
support is provided to complement very substantial private
sector cost-sharing. The willingness of industry to provide
significant amounts of private funds, often equaling or
exceeding fifty percent of the projected cost of the project,
strongly evidences a commitment to projects and technologies.
Any lack of success in commercializing new fossil
technologies with respect to prior DOE assisted technology
development projects cannot and should not be solely attributed
to DOE involvement as the Department's clean coal report
suggests. If such a conclusion has validity, then the solution
is to fashion a government/private sector partnership that
works rather than to conclude that commercialization has been
unsuccessful whenever the government gets involved. As the
ERAB report suggests, the alternative is equally unappealing,
that is, technologies will be abandoned if government
assistance beyond research and development is not provided.
THE NEED FOR NEW COAL UTILIZATION TECHNOLOGIES;
The need to develop new coal utilization technologies is
premised upon two related factors. First, new electrical
generation, not currently planned or under construction, will
be needed in the 1990's to replace aging facilities, to reduce
dependence upon oil- and gas-fired power generation and to
ensure that economic growth is not stymied for lack of adequate
289
electrical supplies. Secondly, the continued or expanded use
of coal will be dependent, in part, upon the development of new
technologies which offer cost-effective means of producing
electricity or providing energy for industrial use while also
assuring environmental protection.
I . NEED FOR NEW ELECTRICAL CAPACITY
Projecting future electricity demand has been
particularly difficult and controversial for many utility
planners and outside analysts who have projected growth of
electricity demand ranging from less than one percent to about
five percent annually over the next 10 to 15 years. The Edison
Electric Institute, recognizing these widely varying
projections, states in its recently published report on nuclear
power: "It is possible that the additional generating capacity
needed by the year 2000 could be as little as a few million
kilowatts and as much as 500 million kilowatts — or about
three quarters of today's installed capacity." (At page 17,
Report of the Edison Electric Institute on Nuclear Power,
February 1985.) These wide differences in projected future
demand result, in part, from unknown factors about economic
growth and the future use of electricity. Further, other
significant unknowns include possible additional environmental
legislation and regulation which might impact the continued
service of existing units, further nuclear deferments, oil
supply interruptions, the yet-to-be-proven ability to
concurrently increase both the availability and life of
existing capacity and the success of further conservation, load
management efforts and other demand-reducing programs.
There is general consensus that new capacity will be
needed even though the rate of increased demand is not agreed
upon. The electric utility industry through the projections of
individual companies aggregated by the North American Electric
Reliability Council is projecting growth in electricity demand
of 2.5 percent annually through 1993.
According to the Edison Electric Institute:
"With demand growth of 2.5 percent and a
capacity margin of 20 percent, additional
capacity is needed by 1992 and a total of
152 million kilowatts of new capacity or
demand reductions will be needed by the
year 2000. Of this need, 34 million
kilowatts of capacity have been reported to
North American Electric Reliability Council
as planned but not under construction.
290
In the present economic and regulatory
environment, some of the nuclear units now
under construction may not be completed or
permitted to operate. For example, if 8
million kilowatts of the capacity under
construction are cancelled and if one third
of the units over 40 years are retired, the
capacity needed by the year 2000 would
total 192 million kilowatts with demand
growth of 2.5 percent." (Report of the
Edison Electric Institute on Nuclear Power,
February 1985, at page 20.)
The EEI has concluded that "100 to 200 million kilowatts of new
generating capacity will be needed — in addition to units
still under construction today — before the year 2000."
Attached to this statement are chart 2, which depicts U.S.
electric generating capacity and peak demand between 1984 and
2000 and chart 3, which depicts U.S. electric generating
capacity and peak demand with possible cancellations and
retirements between 1984 and 2000. Each chart attempts to
display how different projected growth scenarios will impact
upon electricity capacity. If, for example, a demand growth
rate of 2.5 percent is achieved then sometime in the early
1990's peak electricity demand is expected to exceed installed
capacity and some new capacity above what is already planned
will be required.
Current trends and the recent history of the utility
industry strongly suggest that new capacity may not be built in
time to meet increased demand. If, for example, the projected
capacity needs of the mid-1990 's are to be met with
conventional generating units that take from 7 to 10 years to
permit, design, construct and place in service, utilities must
undertake those new power plants now. That construction is not
being undertaken and, in fact, the electric utility industry is
entering a period in which relatively little new generating
capacity will be under construction and many companies have
completed or will soon complete building programs. Further,
many utilities, which only recently were forced to cancel or
abandon the construction of large base load facilities,
including conventional coal-fired power plants, are not now
likely to undertake major new construction programs. Also, it
is projected that new demand and, therefore, new capacity
requirements for many utilities will come in much smaller
increments which do not warrant construction of large scale
conventional power plants. And, finally, because the growth of
electricity demand has slowed considerably, so that electricity
growth now about equals the growth of the economy, any
miscalculations by utility planners in projecting demand could
result in excess capacity being built. The cost of such
291
capacity cannot be easily recovered when there is no longer the
periods of rapid growth which once characterized the utility
industry and ensured that excess capacity would be quickly
utilized. In fact, regulatory commissions have little sympathy
toward allowing the recovery of investments for capacity built
in excess of real demand and have, in some instances, forbidden
the recovery of new, excess installed generation. These and
other circumstances cause considerable uncertainty within the
electric utility industry and this uncertainty simply means
that utility executives will be ever more cautious in adding
capacity.
There appears, therefore, to be little impetus and even
less time in which to address the electricity needs of the
1990's. If new clean coal technologies are to be utilized to
meet expected capacity demands during the mid- to late 1990's,
those technologies must be commercially demonstrated and
available in the 1990 to 1993 time frame. It takes
approximately 3 years to design and build a commercial
demonstration and 2 years to conduct testing. Therefore, to be
available in the early 1990's these clean coal technology
demonstrations must be initiated in the 1985-1988 time frame.
That time frame is already upon us. The next ten years are
very important in both assuring future environmentally
acceptable electricity supply and in controlling the costs of
electricity. The commercial demonstration of clean coal
technologies is at least one important option which the country
would be wise to pursue in planning for ways to meet increased
demand.
II. NEED TO DEVELOP COST-EFFECTIVE COAL UTILIZATION
TECHNOLOGIES WHICH ENSURE CONTROL OF EMISSIONS
The important goal of protecting the environment and
minimizing sulfur dioxide, nitrogen oxide and particulate
emissions which result from the combustion of an inherently
dirty fuel might be achieved in a number of ways. To date,
industry has responded to regulatory controls by fuel
switching, by pre-combustion coal cleaning, and by installing
post-combustion pollution control devices. Conventional coal-
fired power plants can comply with current and proposed
environmental requirements, but the dollar costs are high. To
put these costs in perspective, the cost to retrofit a flue gas
desulfurization system to a 10-year-old power plant can exceed
the original investment in the facility. Also, approximately
40 percent of the capital investment and 30 percent of the
total cost of power for new, coal-fired power plants are
related to environmental control. Finally, the use of flue gas
desulfurization technology and other pollution control devices
has a major impact on the efficiency and reliability of
coal-fired power plants.
292
As the demand for coal-fired power production increases,
the current requirements for emission limitations will continue
or these emission limits might be made more stringent by new
legislation or regulation. The resulting costs associated with
protection of the environment are a large and growing
percentage of the cost of each kilowatt generated. It is
important to understand that if the public demands even more
stringent requirements for greater protection of the
environment, the cost of compliance will take utility dollars
away from clean coal technology development projects. For
example, the Electric Power Research Institute has testified
before the Congress that proposed acid rain control legislation
that would require retrofitting flue gas desulf ur ization
equipment on up to 100,000 megawatts of existing power plants
burning high sulfur coal would cost approximately $200 billion
over the remaining life of the plants in question. If these
requirements were imposed, utilities would have no choice but
to expend limited funds to comply with new regulations.
Another option to assuring protection of the environment
besides simply promulgating additional regulations is to
encourage the timely development of clean coal technologies.
These new coal utilization technologies, besides assuring
compliance with emission controls, also promise more cost-
effective generation of electricity from a greater variety of
coal resources. An opportunity for the timely development of
these technologies should be provided.
Much has been written about the development and potential
of new coal utilization technologies. Charts 4, 5 and 6, which
are attached to this testimony, attempt to describe the variety
of technological options which are currently being pursued.
These emission control options range from improved physical
coal cleaning to furnace sorbent injection (e.g. LIMB),
improved methods of combustion and advanced scrubbing
technologies. Importantly, these technologies promise very
significant improvements in the control of emissions from the
use of coal. Chart 6 attempts to depict the possible advances
in emission control likely to result from development of these
various technologies. Further, a number of these clean coal
technologies offer control of both sulfur dioxide and nitrogen
oxide emissions, shorter construction lead times, improved fuel
conversion efficiency, an ability to burn a wider variety of
coals and the opportunity to construct power plants in modules
which better match capacity additions to anticipated increased
demand.
Pending legislation calling for emission reductions from
existing power plants make the problem of timely development of
clean coal technologies even more acute. Compliance dates
between 1990 and 1995 require that new retrofit technologies be
293
available for use in existing plants in the 1987-1990 time
frame. Given this time frame, the commercial demonstration of
technologies which can be used in retrofitting existing plants
must be conducted over the next three years. Otherwise, this
option for compliance might not be available.
It should be emphasized that no single clean coal
technology is now thought to satisfy the variety of existing or
projected coal-fired utility or industrial power generation
requirements. All of those technology options which are mature
and ready for commercial-scale demonstration should be
considered likely candidates for the clean coal technology
development program.
FACTORS WHICH INHIBIT PRIVATE SECTOR
DEVELOPMENT OF CLEAN COAL TECHNOLOGIES
The principal user industry of new clean coal
technologies will be the electric utility industry. This
industry is constrained in the amount of effort that can be
directed toward large-scale, high-risk demonstration projects.
This constraint is principally a function of the fact that the
utility industry does not operate in a free marketplace.
Return on an electric utility's investment is governed by
public utility commissions that are generally charged with the
task of minimizing ratepayer costs; risks undertaken by
utilities in clean coal technology development will not
necessarily be reflected in allowed profits or rewards.
Indeed, if failure occurs, the burden may be placed primarily
upon the shareholders of a utility not the ratepayers. At a
minimum, the costs involved in constructing a clean coal
project, unless somehow characterized as research and
development, must be carried by the utility until that time
when the plant is placed into service. This burden of carrying
construction costs when added to the prospect that the facility
might not be reliably placed into service at all creates too
great a financial exposure for many utilities.
Furthermore, many utilities still face severe financial
problems and cannot even raise capital funds for improvement or
expansion of existing or new conventional electric power
generation. This circumstance makes funding high risk clean
coal technology development projects even more difficult.
Coal companies and utility equipment suppliers are also
not able to bear the burden alone of significant investments in
new technology development. Given the possibility that the
domestic power generation market may be very limited for some
time to come, such entities are reluctant to contribute
substantial dollars to the costly demonstration of new clean
coal technologies when the returns on their investments may be
very limited.
294
A final factor which inhibits private sector development
of new clean coal technologies is that once the demonstration
stage of technology development is reached enormous
expenditures for engineering, construction, manufacturing,
capital formation and operation are required. A new,
"greenf ields" clean coal technology project may require 5 years
to design and construct and test. The exposure to project
participants during the construction and demonstration phase
which may result from changes in government policy or any
number 6f other unanticipated occurrences can be so great as to
result in utilities and other interested parties simply
refusing to take significant risks. In addition, major
modifications to the technology may be required after start-up,
thus necessitating the expenditure of additional capital.
The Clean Coal Technology Coalition agrees with the DOE
that the private marketplace should be responsible for the
widespread commercialization of new clean coal technologies.
However, the normal cycle of development which generally
provides the private sector with sufficient time to
commercialize a technology has been significantly disrupted.
The private marketplace is currently faced with a dramatically
changing picture in which the supply of electricity, now is
surplus, may soon be outstripped by demand. Further
regulations or new legislation may require costly modifications
to existing facilities or more costly generation from any
newly-constructed conventional power plants.
These changes, some of which may be imposed by government,
necessitate a program of parallel government assistance like
that envisioned by the clean coal program so as to assure
timely development of technologies which may prove useful in
cost effectively addressing these changes. Thus, in order to
accelerate the commercialization of clean coal technologies
and, in some instances, to ensure that the technology is not
abandoned after the research and development stage, some
sharing of the costs by the federal government is highly
desirable. For its part the private sector is willing to
provide very significant private monies toward the
demonstration of new, high risk technologies. The federal
government is being asked to participate with the private
sector in the commercial demonstration phase by also sharing a
portion of the costs of new technology development.
THE ROLE OF THE FEDERAL GOVERNMENT IN THE
DEVELOPMENT OF CLEAN COAL TECHNOLOGIES
The clean coal technology development program
envisions a partnership between the federal government and the
private sector. This relationship is justified if the public
receives benefits for the public funds sought to be expended.
295
Although it is possible that some technologies which could
be supported by the clean coal program may never be
commercialized, the fact that the private sector will be
required to provide a large portion of the funds for a project
increases the likelihood that early commercialization will
occur. Therefore, an important public benefit is that this
clean coal program is designed to provide the greatest
assurance that these technologies, once demonstrated with the
assistance of public funds, are likely to then be used in
widespread near term commercial applications.
Accelerated commercial demonstration is also very
important if the Nation is to receive the benefit of new
technologies when the need for new capacity arises in the
1990's. Early and widespread application of new coal
utilization technologies which are less costly than current
alternatives, which can be constructed and brought on line more
quickly than current alternatives and which can be constructed
in smaller — even modular — units to more nearly meet current
demand requirements, are all benefits to be received by the
public from successful implementation of the program. Also,
technologies that might enable retrofitting of existing power
plants to reduce or better control emissions and/or increase
efficiency might also be demonstrated under the clean coal
program.
The public benefits of early commercialization of clean
coal technologies, which include the promise of better
environmental protection, more cost-effective production of
electricity and more efficient use of our coal resources, are
compelling reasons to implement the clean coal technology
program rapidly.
CONCLUSION
Mr. Chairman, on behalf of the Coalition, we applaud your
interest and leadership in this important program. We have an
opportunity to create a unique partnership between the
government and the private sector. The marketplace has
identified the technologies to be commercialized; the private
sector is ready to commit very substantial funds to these
projects; and our members are willing to put their projects
into the competitive arena.
From the point of view of the Clean Coal Technology
Coalition, we would encourage rapid implementation and
sufficient first-year funding to ensure that industry will
aggressively participate in this program.
296
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303
CLEAN COAL TECHNOLOGY COALITION
1050 Thomas Jefferson Street, N.W.
Seventh Floor
Washington. D.C. 20007
(202) 331-9400
Co-Chairs:
The Signal Companies
American Electric Power
Statement of Support for the Clean Coal Program
The Clean Coal Technology Coalition supports the timely
implementation and funding of a clean coal progreim which
will result in the demonstration of technologies that use
coal in an environmentally acceptable manner, at reasonable
cost and which will operate reliably in utility systems and
in large industrial applications.
Clean coal techno>logies must be demonstrated at or near
commercial scale before they will have the confidence of
the electric utilities industry and the agencies which
regulate it. Most of these emerging technologies are not
yet sufficiently advanced to have gained this acceptance.
A regulated utility acting alone is constrained in its
ability to support new technologies. Current regulatory
policies impede the incorporation into the rate base of the
research and development expenses associated with the
commercialization of clean coal technologies. This requires
utility companies to shoulder significant financial burdens.
The Clean Coal Technology Reserve created by Congress in
Public Law 98-473 would provide the stimulus necessary to
assure the earliest practicable commercial availability of
these emerging technologies.
The private industry/government partnership created by the
Clean Coal Program is the least costly and most effective
course the United States can pursue to ensure environmentally
and economically acceptable use of our most abundant fossil
energy resource. Furthermore, successful commercialization
of clean coal technologies will significantly advance the
national goals of utilizing this immense domestic energy
resource in an environmentally acceptable manner, while
providing electric utility customers and industrial users
of coal with a more secure energy supply at reasonable prices.
304
CLEAN COAL TECHNOLOGY COALITION
Membership - May 7, 1985
Babcock & Wilcox
1735 Eye Street, N.W.
Suite 814
Washington, D,C. 20006
Southern Company Services
1101 17th Street, N.W.
Suite 405
Washington, D.C. 20036
Transamerica Delaval
8181 Professional Place
Suite 116
Landover, Maryland 20785
Peabody Holding Company
1120 20th Street, N.W.'
Suite 720
Washington, D.C. 20036
Public Service Co, of Indiana
1920 N Street, N.W.
Washington, D.C. 20036
Southern California Edison
1111 19th Street, N.W.
Suite 303
Washington, D.C. 20036
Florida Power & Light Company
1111 19th Street, N.W.
Suite 1102
Washington, D.C. 20036
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, New York 13202
Baltimore Gas & Electric Company
1100 Connecticut Avenue, N.W.
Suite 530
Washington, D.C. 20036
MEI Systems Inc.
3121 West Spei^ce:;- Stjreet
Appleton, Wisconsin 54914
Black, Sivalls & Bryson
P.O. Box 27125
Houston, Texas 77227
American Electric Power
Service Corporation
1667 K Street, N.W.
Suite 450
Washington, D.C. 20006
Stone & Webster Engineering
1875 Eye Street, N.W.
Suite 550
Washington, D.C. 20006
The Signal Companies, Inc.-
2550 M Street, N.W.
Suite 600
Washington, D.C. 20037
TRW
1000 Wilson Boulevard
Suite 2600
Arlington, Virginia 22209
Duke Power Comoany
P.O. Box 33189
Charlotte, North Carolina 28242
National Coal Association
1130 17th Street, N.W.
Washington, D.C. 20036
General Electric Corporation
National Place, Suite 895
1331 Pennsylvania Avenue, N.W.
Washington, D.C. 20004
Consolidation Coal Company
1701 Pennsylvania Avenue, N.W,
Suite 900
Washington, D.C. 20006
Public Service Electric & Gas C
80 Park Plaza
Newark, New Jersey 07101
305
Mr. Boucher. We will proceed momentarily to Mr. McCormick's
statement. We have a call of the House pending at the moment,
and I am going to ask that the subcommittee recess for approxi-
mately 10 minutes. When we return we will hear your statement
and ask questions of both witnesses.
The committee stands in recess.
[Recess.]
Mr. Boucher. The subcommittee will reconvene.
At this time we will be glad to hear the statement of Mr. John
McCormick.
Mr. McCormick. Thank you, Mr. Chairman.
Mr. Chairman, my name is John McCormick. I am a Washington
representative of the Environmental Policy Institute. It is a pleas-
ure to be here this morning to discuss an issue of vital importance.
Mr. Chairman, I have a lengthy statement that I would like to
submit to the record
Mr. Boucher. Without objection, the statement will be received.
Mr. McCormick [continuing]. And make some comments before I
address the specifics of the hearing this morning.
Mr. Chairman, our organization of many environmental groups
have been opposed to massive Federal outlays of subsidies for syn-
thetic fuels development. Since 1974 we have held that view, and I
think history has borne us right, that we took the correct view. Be-
cause had some of those plants been built in the early 1970's, I
think many of those companies would be hammering on the doors
of the Congress begging for additional price supports.
Well, now, Mr. Chairman, we are faced with a new proposal, and
I think this proposal has a great deal of merit, Mr. Chairman, if it
is directed at the most pressing needs of the day; and that is, how
to help the electric utility industry, which, as we heard this morn-
ing, is a consumer of about 80 percent of the U.S. coal produced.
How are we going to help that industry to cope with the increasing
demands that we will make on it in terms of pollution control?
Mr. Chairman, this program could address those very pressing
needs and wouldn't require a great deal of money, nor a great deal
of time. Because, fortunately, we haven't been standing still in the
10 years that we have been discussing synthetic fuels, we have
been moving on some very promising coal utilization technologies;
and in particular, the limestone injection multistage boiler, which
EPA has headed up for about 5 years, and the team of combustion
engineers that Frank Princiotta of EPA at Research Triangle Park
has put together are very capable of taking on a large part of the
responsibilities that a clean coal technology program might have.
And having said that, Mr. Chairman, I would like to go into sev-
eral criteria or goals or, let's say, constraints on how this program
might be conducted so that we get maximum return for the taxpay-
ers' dollar.
To begin with, Mr. Chairman, we recommend that the EPA must
have consultation and concurrence roles and preferably at the level
of the Assistant Administrator for Research and Development. And
given the work that the EPA has done on the LIMB Program and
on scrubber technology, I think they are totally suited to that role.
Second, Mr. Chairman, those pollution control technology candi-
dates which promise attainment or better than attainment of cur-
306
rent air pollution standards under the Federal and State laws
should have first access to the funds. And there, Mr. Chairman, I
am saying that where we have States with low State implementa-
tion plan requirements for sulfur dioxide emissions there is still a
need to improve where those States in the Midwest have less strin-
gent air pollution control requirements, and in any of the acid rain
proposals that have been offered to the Congress it would require
significant reductions in those Midwest States.
Utilizing existing laboratories and equipment and facilities
would obviously save money, and I think the academic, industrial,
and Government research centers should be used to the utmost.
Where possible share research projects with the Canadian Gov-
ernment. We understand that the fiscal year 1986 EPA budget does
not have enough money for the LIMB demonstration of a tangen-
tial-fired boiler unit. While its cousin, the wall-fired boiler is pres-
ently being retrofitted for LIMB, we feel that demonstration of
LIMB on a wall-fired boiler doesn't provide much assurance to the
operator of a tangential-fired boiler that LIMB can work on that
equipment as well. It just so happens that in Saskatchewan there
is a 300 megawatt, tangential-fired unit that is burning lignite,
which could, if the engineers can work out the details, be a host for
demonstration of LIMB on a tangential-fired boiler using Midwest
high sulfur coal.
Candidate projects designed to meet and improve upon the new
source performance standard should be accorded the highest priori-
ty among candidate technologies.
Mr. Chairman, we have been looking at the numbers of the
growth in the electric utility sector, and while that is still a very
iffy question, the ultimate new capacity of the utility sector at any
given time in the future, we see the potential for new growth in
emissions from the utilities sector at the same time we are trying
to reduce overall emissions through hopeful enforcement of an acid
rain control law.
The second highest priority should go to those technologies de-
signed to retrofit existing equipment while achieving at least a 70-
percent reduction of SOx and NOx emissions. It is becoming appar-
ent that the electric utility industry for all the obvious economic
reasons is having to hold onto its older equipment longer. That is a
frustration of the goals of the Clean Air Act, because it was intend-
ed that as these older plants would live out their useful life new
source performance standard plants would replace them and we
would see a constant downturn in emissions. But that isn't going to
happen the way it was intended. It is a glitch in the Clean Air Act
which must be addressed, and we are proposing that Congress con-
sider mandatory guidelines for the retrofit of old boilers. And while
it may be in the consumers' interest to hold those older plants on
line longer, it is in the interest of those living downwind of those
plants to see that emissions are reduced in the course of that retro-
fit.
Candidate technologies should have no more than 24- to 36-
months startup and shakedown schedule. We are looking again,
Mr. Chairman, at immediate results. We feel that there are enough
candidates among that 174 provided the DOE that we could take
from that those which are on the verge of going to commercializa-
307
tion, and this 24- to 36-month timeframe would force those — well, it
would help in making the decision which technologies this money
could force into commercialization.
And finally, Mr. Chairman, waste disposal research should be
given a high priority as well. We recognize the problems that use
of stack gas scrubbers causes, but we also know that in countries
like Japan they are finding uses for the byproducts of coal-fired
electric generation. They are finding that the spent ash can be up-
graded and used as a soil fertilizer, and in the U.S. companies are
contracting with electric utility companies using scrubbers to buy
their sludge and to upgrade that sludge and it becomes usable
products for wallboard, for light construction material.
Mr. Chairman, to sum up my statement, let me say that for this
program to win the support of the Congress, and particularly the
Appropriations Committee, we believe it is going to take the sup-
port of the downwind States to fund this program. I think it is
going to be a bit much to ask those legislators who can't find
money to increase EPA's research for even indoor air pollution to
spend another $100 million on clean coal technology when there
isn't real assurance that their constituents are going to get much
in return for it.
With that, Mr. Chairman, I want to say that we will work with
you to design a program that will meet the goals that the Nation,
and particularly the electric utility industry, deserves if we are
going to outlay another $100 million.
Thank you, Mr. Chairman.
[The prepared statement of Mr. McCormick follows:]
308
Environmental Policy Institute
TESTIMONY OF JOHN L. McCORMICK
BEFORE THE SCIENCE AND TECHNOLOGY COMMITTEE
CLEAN COAL TECHNOLOGY RESERVE
MAY 7, 1985
Mr. Chairman, and Members of the Committee,
It is a pleasure to appear before you this morning to discuss an
issue which has the potiential to make a very important contribution
to the Nation's energy and air quality debates.. The Environmental
Policy Institute has been involved in this issue of energy research
since our establishment in 1972. From the outset, let me assure
you that we are not opposed to the mining or utilization of coal.
We worked with Chairman Udall and Senators Jackson and Metcalf
for seven years until the Congress enacted the federal coal strip
mining law in 1977. We continue our involvement in the federal
coal leasing and synthetic fuels debates also.
The nation's repeated efforts to adopt and maintain an organized
energy policy have not produced any agreement of a total package.
Instead, we discuss energy conservation, importing fuels, burning
certain fuels while banning others, and even the control of the
pollutants from our use of energy in separate and isolated pieces.
This Committee has an opportunity to integrate some of these vital
components in one piece of legislation. We come to vou with a
list of criteria which this Cormnittee should consider as it proceeds
with the establishment and funding of a Clean Coal Technology Reserve
2IS I ) St!\-it. S I W-isliiiiL'ton \ ) (. 2 V iJiiJi S44-2(in(i
309
Before I begin, though, there are several points which must be made.
a. The regulation of the coal surface mining industry since
1977 has not damaged its market. While a much improved
regulatory process has been enforced by State and federal
agencies, the tonnage rates have increased steadilv. '<Tiere
major contracts for strip mined coal have been cancelled
or cut back, it is the quality of the coal that was at
issue; not that its producer had to backfill a highwall.
b. Coal has not yet taken the economic nosedive that the
nuclear power industry has, but it would not be wise to
rule that prospect out at this time.
c. The international coal market is fightinp, to capture
larger markets at the same time its governments are
funding research to understand the planet's feedback
about the possible consequences of a buildup of carbon
dioxide in the atmosphere.
d. There is a growth potential for coal utilization which
the U.S. can accommodate; but it is nowhere near the
projections which have consumption doubling by the turn
of the century, or sooner. There are no signs to confirm
the logic of that optimistic view.
310
e. The U.S. coal industry's real problems are in the here
and now. And, we have scientific knowledge and equip-
ment readily available to meet the needs of todav's
coal producers and users.
f. The Clean Coal Technology Reserve is a part of the
Congressional "air pollution/acid rain" debate, but it
is NOT THE SOLUTION. That debate must continue to sharper
its focus as the engineering coinmunity teams up with the
environmental regulators to get on with the task of
making our coal use policy fit with our larger environ-
mental and public health goals. We have the means to
accomplish this.
Mr. Chairman, as you know, we took a hard line position in the
mid-1970 's against the creation of a federal guaranteed loan progran
for the establishment of a synthetic fuels industry in the U.S. Whe
other Committees began to get involved in that matter it became
increasingly more cloudy and less popular and the results of the
past decade are a vindication of those who opposed massive federal
involvement in a non-existent industry for unknown costs . Had some
of those Southwest coal gasification proposals been built in the lat
1970 's som.e corporations would be banging on the Capital door plead-
ing for price supports for $8 gas in a $3 market.
311
The last vestage of this approach to federal intrusion into the
domestic energy supply industry will hopefully slip into the abyss
when the House approves Synthetic Fuels Corporation deauthorization
legislation pending in the House Energy and Commerce Committee.
This debate has been lengthy and expensive in terms of the time
the Congress has devoted to the discussion of exotic fuels production
technology while ignoring the obvious needs of our basic fuels pro-
duction industry - the domestic coal industry.
If this Committee intends to convince the Appropriations Committee
to fund the Clean Coal Technology Reserve, it will need the politi-
cal support of those legislators living downwind of smokestack
plumes from today's coal burning furnaces. These are the same
politicians who have to explain why the E.P.A. budget for air qual-
ity monitoring equipment and the research of air pollution effects
on forests and public health cannot be increased in a year of tough
federal spending debates. The Environmental Policy Institute is
willing to carry this Committee's bill to some o^ those legislators
and urge them to support it. But, it would have to accomplish
certain goals and contain several requirements and limitations on
the Program's goals. The following are criteria and procedures
which should be applied to the Program. We urge this Committee
to consider them as it authorizes a federal/private sector research
program that will return a dividend on the taxpayer's investment.
312
1. THE E.P.A. MUST HAVE CONSULTATION AND CONCURPJINCE ROLES,
PREFERRABLY AT THE LEVEL OF ASSISTANT ADMINISTRATOR FOR
RESEARCH AND DEVELOPMENT
The on-going research of the various coal combustion technologies
by the E.P.A. is underfunded but competently managed. The team
of combustion engineers that Frank Princiotta, Director of Indus-
trial Environmental Research Laboratory assembled at RTP are first-
class engineers and their development of the LIMB demonstration
program is on time and on track. Their efforts are direct respon-
ses to the air quality regulation needs of the Agency and that
kind of integrated approach will continue to assure that the
research fits rational goals and immediate tasks. His shop is
not "supply" oriented. It's focus is on pollution control and
emissions reduction. Limited funding of the Clean Coal program
should be no great problem for a lean and productive effort such
as Princiotta manages.
2. THOSE POLLUTION CONTROL TECHNOLOGY CANDIDATES VTHICH PROMISE
ATTAINMENT -OR BETTER THAN- OF CURRENT AIR POLLUTION STANDARDS
UNDER STATE AND FEDERAL LAWS SHOULD HAVE FIRST ACCESS TO FUNDS
A coal research program with a budget of $100 million must be
strictly focused or it will squander its resources quickly and have
lit.tle or nothing to show for its investment. Looking at the
potential research candidate list and the project costs they rep-
resent, it is clear that the energy supply projects are very expen-
313
sive in contrast to those which are designed to limit pollution
emissions. The problems of fuel supply, in the U.S., are partially-
being solved by market forces. Shifts within the industrial fuels-
buying market are taking place constantly and individuals are making
changes in their lifestyles and consumer habits which have been
acceptable. Therefore, the Program should not even consider those
candidates which add new fuel sources to the market. We may need
them over time but not now and not at $100 million per year.
3. UTILIZE EXISTING LABORATORIES, EQUIPMENT, FACILITIES AND
PERSONNEL TO HOLD DOWN COSTS AND TAP AVAILABLE EXPERTISE IN
THE ACADEMIC, INDUSTRIAL AND GOVERNMENT RESEARCH CENTERS.
The work the Electric Power Research Institute has underway is a
valuable investment for the Nation's electric utility customers.
Under the leadership of Curt Yeager , Vice President of the Coal
Combustion Systems Division, EPRI is making headway on the use of
f luidized-bed coal combustion equipment for large base-load elec-
tric generation and for the retrofit of older boilers. Its work
on lime sorbents and low NOx boilers can be expanded auickly if
the Clean Coal Program has the flexibility to dovetail the efforts
of each.
The Department of Energy's Pittsburg and Morgantown facilities
are located where the longterm needs of the coal industry are most
acute; in the high sulfur coal regions. The acceleration of chemical
coal washing research must be included on any list of priorities in
314
the Clean Coal Program. And, the full spectrum of concerns about
down stream pollution control needs should be incorporated in the
design of coal cleaning technologies where large amounts of residues
are generated.
4. WHERE 'POSSIBLE, SHARED RESEARCH PROJECTS WITH CANADIAN GOVERN-
MENT AND INDUSTRY SHOULD BE ENCOURAGED.
The EPA's LIMB demonstration program has no funding for the design
and testing of that SO and NO control equipment on a tangential-
fired boiler. That the wall-fired boiler LIMB test is proceeding
is good news indeed. But, operators of tangential boilers (about
457o of the U.S. boiler market) will learn very little from that
success. However, the Canadians have tested LIMB on a tangential
boiler in Saskatchewan Power Corporation's Boundary Dam Unit #6.
This 300 MW, lignite-fired boiler may have the capability to be
modified for a test burn of medium and high sulfur bituminous coals
mined in the Midwest and Northern Appalachian fields. The costs
would be minimal compared to the capital demand for such a test in
a boiler not already LIMB retrofitted. The costs of shipping the
coal to the Saskatchewan plant would be minimal and test results
would be available within 18 months. This should be discussed with
the Canadians and I will furnish this Committee with the names of
company officials to whom I was referred by Canadian representatives
Since the concerns of the Canadians about U.S. footdragging on the
"acid rain" issue will not be satisfied by Congressional pollution
315
control legislation any time soon, it would be a welcome jesture
to extend to our neighbors that we do want to find a resolve to
the transboundary air pollution problems we share.
5. CANDIDATE PROJECTS DESIGNED TO MEET AND IMPROVE UPON NEW SOURCE
PERFORMANCE STANDARDS OF THE CLEAN AIR ACT SHOULD BE ACCORDED
THE HGIHEST PRIORITY AMONG CANDIDATE TECHNOLOGIES.
The coal and electric utility industries remain strong critics of
the utility and costs of stack scrubber equipment. They site the
obvious complaints of the high capital and maintenace costs and the
scrubber sludge disposal problems. Now is the time to take their
concerns to heart and offer them support for finding a cheaper and
more efficient means of achieving the "Percentage Reduction"
requirements of the Clean Air Act. Coupling coal washing to the
LIMB technology is only one means of further reducing emissions from
a stand alone technology. Since the standard for high sulfur coal
is 907o SO^ removal under the NSPS , that is the mark which candidate
proposals should have to achieve or improve upon. Any improvements
above 907o removal should be encouraged up to the limits of the funds
available but should not represent the bulk of committed research
dollars .
316
6. THE SECOND HIGHEST PRIORITY SHOULD GO TO THOSE TECHNOLOGIES
DESIGNED TO RETROFIT EXISTING EQUIPMENT WHILE ACHIEVING AT
LEAST 707o REDUCTION OF SO2 AND NO^ EMISSIONS.
I
Mr. Chairman, the economics of the electric utility industry in the
U.S. have changed dramatically in some regions of the Nation over
the past ten years. Traditional doubling of demand each decade has
shrunken to less than TU annual growth in electricity demand almost
over night. This has placed an overwhelming financial burden on
those companies heavily capitalizing in huge nuclear and coal
base load generators while its electricity market evaporates. For
some, this has meant a complete restructuring in their planning and
load management. Now, companies are looking to hold onto existing
units beyond their normal book life in order to save capital while
revenues are plummeting or debt service costs escalate. That is
a fundamental flaw in our Nation's plan to steadily improve on air ,
quality because it was predicated on the understanding that companie
would gradually retire the ,old and dirty boilers and replace them
with New Source Performance Standard regulated equipment.
When I brought this complaint to an Energy and Commerce Subcommittee
in February, I called for the imposition of National Guidelines on
the retrofit of old electric utility and industrial boilers. Elec-
tric utility company representatives on our panel concurred with
that view. They reason that the retrofit investment may be threat-
ened if the Congress comes up behind them with an acid rain control
measure which requires further retrofit for pollution control equip
ment .
317
The West Germans have defined a new catagory of existing and
polluting boilers which must be cleaned up if they operate beyond
a predetermined number of hours. Thus, a boiler operator could
spread the allowed remaining hours of operation over a long period
of time without modifying its pollution control capability but it
would have to make those investments if it wanted to operate the
units beyond that imposed limit. That would give the boiler operator
the option to plan its retirement or its future in the context of
operating finances and need for rate increases.
Fluidized-bed retrofit of existing units are being planned and
researched at the present time and their success will offer huge
returns to the coal user market. But, the costs may be quite high
on a per-kilowatt of installed capacity basis. Whether it is
flu-bed, LIMB, or another type of boiler modification, it is a
lucrative market for vendors and the target boilers are caught up
in the E.P.A.'s tall stacks rule-making procedure. Many of those
units have been included in the acid rain legislation considered
by Chairman Henry Waxman in the 98th Congress markup of acid rain
legislation. Whatever the rationale, the retrofit of old and dirty
boilers must get attention in the Clean Coal Program because 257o
of the Nation's boiler capacity will be 25 years or older by 1990.
By the year 2000 that number will exceed 507o. The acid rain problem
will not go away, ^s the coal industry has boasted, as long as the
emissions from those older units are not reduced. This Congress must
face that reality. The acid rain battle cannot be won by attrition.
50-513 0—85-
318
7. CANDIDATE TECHNOLOGIES SHOULD HAVE NO MORE THAN A 24 TO 36
MONTH STARTUP AND SHAKEDOWN SCHEDULE.
This is a difficult criterion to establish with assurance that
it will force efficiency into the Clean Coal program. However, it
should be a consdieration in any strategy which accounts for the
urgency of complying with the tall stacks regulation when it is
finally adopted and promotes technologies already moving down
the path towards commercialization. This is not the time to begin
conceptual work on pollution control technologies. We must improve
on what we now have and get them ready for commercialization as soo
as possible. That will not cause us to back away from the more
frontier oriented research on the drawing boards and in the pilot
stage. They should proceed but their timed arrival does not fit
the more pressing needs of the coal customers today.
8. ONLY THOSE TECHNOLOGY RESEARCH PROJECTS 1-JHICH MOVE DESIGNS
FROM THE PILOT STAGE OR, PREFERRABLY, THE PRE -SCALE UP STAGE
TO THE READY-FOR-COMMERCIAL-USE PHASE SHOULD BE CONSIDERED IN
THE FIRST THREE YEARS OF THE PROGRAM.
This is a reiteration of the point made above. There will not be
the long-term funding needs committed to Clean Coal candidates whicl
have not already passed several thresholds in its research life. A
great deal of time, talent and money have already been invested in
this area of research
Reinventing what we already know may create jobs for consultants am
e
319
ngineers but this Nation's fiscal budget cannot afford that
pproach and the public deserves better planning and higher goals
rem the Clean Coal Technologies Reserve.
). WASTE DISPOSAL RESEARCH SHOULD BE GIVEN A HIGH PRIORITY.
rhe enactment of the Resource Conservation and Recovery Act and
:he debate over reauthorization of the Superfund law have raised
a tremendous amount of awareness about the serious problems we fac
in controlling toxic runoff from the piles of hazardous wastes
□eing dumped upon the land. Whether it is stack gas scrubber
sludge, wastes from a coal cleaning plant or disposal of fly ash
and the spent-bed material from a f luidized-bed coal boiler, each
residue has its own particular hazards and requires special disposal
procedures to assure that pollution control equipment does not
create a new wave of pollution problems. Fortunately, the Japanese
and Europeans are wrestling with similar problems and there is a
growing list of options for utilizing those wastes by treatment
or recylcing rather than disposal into the land. The enforcement
of RCRA and Superfund laws should not be a threat to the utility and
industrial sectors. They will find that the liquid and solid wastes
have potential for raising new revenue if special attention
is given to finding those methods of treating the wastes and
marketing them for profit.
320
i
Mr. Chairman, before I conclude my statement, let me reiterate
our commitment to winning federal funding for a carefully desip,ned
and goal-specific Clean Coal Program. We believe that sufficient
political interest will be drawn to a plan which focuses upon the
research of coal boiler emission reductions. Those legislators
frustrated by the 99th Congress' faltering on the enactment of
the Clean Air Act reauthorization can push for adequate appropri-
ations because the increased federal spending will have a direct
benefit to their constituents living downwind of the millions of
tons of sulfur dioxide and nitrogen oxides spewing from Midwestern
coal-burning power plants.
As the successful demonstration of these clean coal technologies
point the way to cheaper and cleaner air pollution control options,
those same legislators will find it easier to convince the Congress
that the Nation can cut its air pollution levels in half. Meanvjhil
industry's increasing dependence upon our most abundant domestic
fuel supply - the more than 150 billion tons of readily recoverable
coal- can be accommodated without causing the environmental damage
which threatens to blunt the potential for using more coal.
321
Mr. Boucher. Thank you, Mr. McCormick. That is a very encour-
aging and very thoughtful statement, and we appreciate it very
much.
Mr. Wootten, we welcome you here, and note in passing that
your company, Peabody, is the largest coal producer in the United
States. I would assume that your largest customer is the electric
utility industry. Would I be correct in that assumption?
Mr. Wootten. Yes; approximately 96 percent of our 65 million
tons goes to the utility industry.
Mr. Boucher. Do you have within Peabody Holding Co. a divi-
sion that conducts combustion or precombustion research and de-
velopment?
Mr. Wootten. Yes; within the Holding Co. we have a function,
the research and technology function, which I head up, and the
concerted effort is involved in a number of projects. Right now we
are committed to the TVA project, we are committed to the Colora-
do Ute project, and we have committed to the Public Service of In-
diana sorbent injection project. Both of the last two are projects
which have been submitted for consideration as clean coal technol-
ogies. We are also evaluating participation in some four other
projects involved there. So, yes, we are trying to use our resources,
limited as they are, to in fact enhance these sort of projects.
Mr. Boucher. Can you tell us the approximate budget for com-
bustion or precombustion research that your company has every
year, if that is not proprietary?
Mr. Wootten. It is approximately in the million dollar range. It
will climb as these projects that we have committed to come into
being and the expenditure cycles demand more and more input.
Mr. Boucher. And that is research you conduct in-house?
Mr. Wootten. Well, this is contracted research or participation
with others. We don't have any actual in-house combustion capa-
bilities.
Mr. Boucher. You contract with universities?
Mr. Wootten. Yes; we are involved with M.I.T., and there is a
group within the State of Illinois called the Center for Research of
Sulfur In Coal.
Mr. Boucher. Can you give me some indication — and I would ask
Mr. McCormick to comment on this as well — of which of the
emerging clean coal technologies have the potential for providing
the most rapid benefit to the electric utility industry?
Mr. Wootten. Well, let me give you my perception, and I would
have to speak as a Peabody representative, not a Coalition repre-
sentative, because there are varied interests and there would be
varied outlooks from the Coalition. But in looking at that I think
you have two significantly different approaches. One is the retrofit
problem that may be necessitated by controls placed on existing
units. Those types of uses would force one into looking at those
technologies that could be put in place with less difficulty at a
lower cost and with a comparable environmental benefit to the
technologies we have today, which primarily are fuel switching and
the addition of flue gas desulfurization devices. Both have either
cost or some socioeconomic impacts.
I think LIMB, which EPA has already began a demonstration of,
is a very good one. As Mr. McCormick indicated, that is on one
322
type of boiler. There are LIMB applications that would be appropri-
ate on other types of boilers. It is the applicability to the boiler
family that the technology might serve which is important.
Absorbent injection is another one. Most of the major utility in-
stallations are equipped with particulate control devices. We may
somehow combine sulfur removal such that those particulate con-
trol devices become the ultimate collector. Basically you take some
lime-based substance, inject it, it reacts with the sulfur and you
produce a particulate. The sulfur gas by going to a particulate, you
can collect the particulate with existing equipment. That would be
an easy application. There are other dry scrubbing techniques that
could be maximized the same way.
That would be one application. Coal preparation would be an-
other area. If we can find better ways to go at coal preparation, we
may be able to in some circumstances, depending on the amount of
reduction that is required, be able to maximize our efforts there. It
is conceivable that you could begin to look at a coal preparation
plant as a refinery, where you would take one product of a certain
quality and it would go to one setting where the environmental
constraints would be more stringent, maybe an urban setting; and
you may be able to go to a rural setting with another quality
where the regulations would maybe not have to be so tight. We
have some limitations there based on the type of sulfur that is in
coal, whether it be organic or pyritic, and what we can do in the
form of transportation. So there are some limitations there.
We are looking at a project, the Northern States Power project
where they are going to retrofit fluidized bed combustion to an ex-
isting power plant. Actually cut the bottom out of it. That is a tech-
nology that is being done today.
What is not being done, and I think is important in a number of
these areas, is to test other coal. The coal that is being fed into
Northern States Power is a Western subbituminous coal. Midwest-
ern coals or Eastern coals should also be tested in that facility, as
well as in the Colorado Ute facility. The TVA facility is designed
for Midwestern coal, but there are probably other coals to be
tested. I think the moneys that are in the clean coal technology are
for expanding the data base. Private industry has already said
these are technologies we are going to develop. But the Midwestern
utility sector would like to know, all right, what does that do to the
type of coals that we have? It is somewhat of a regional issue, but I
don't think it is exactly as Mr. Vaughan described it.
In the case of new systems, fluidized bed is one. We are looking
at new coal gasification techniques, some of them that incorporate
a second phase from the cool water project where we look at a gas
turbine, a hot gas cleanup system, and a fixed bed gasifier. There
are many of those that are going to, in fact, represent better ways
to install capacity to meet a limited amount of demand. Whereas
normal economics would say install a 600 megawatt facility, your
demand may not support that; and therefore, your return from
your utility commission may not support it, either, and you may
want to put in a 100 megawatt block. Well, right now you cannot
use coal in that sort of an installation. So coal would be locked out
of that market if we don't do something to advance that technolo-
gy. If that technology needs to be put in place commercially in the
323
mid-1990's, I tried to point out to you that we have to begin that
today.
I would stop there and let Mr. McCormick respond.
Mr. Boucher. Thank you.
Mr. McCormick, would you care to comment?
Mr. McCormick. There isn't much I can add to what was a very
excellent answer, Mr. Chairman. But if you are stressing what are
the most immediate technologies, then I would like to add one
thing, and that is that we can combine some of the processes that
we now have a lot of experience with. For instance, cleaning coal
more thoroughly reduces the load on a LIMB-retrofitted boiler. I
think we can start looking at some of these combinations, and that
might be the only addition I would make to Mr. Wootten's state-
ment.
Mr. Boucher. I assume that the boiler efficiency and the boiler
life could be improved if the coal were washed in a better way
before the LIMB technology used that coal. Is that correct?
Mr. McCormick. I think the American Electric Power Co. has
proven that to itself. That it adds something like 10 percent to its
on-line capacity by removing more of the ash from the coal, there-
by cutting down on the wear and tear of the boiler.
Mr. Boucher. Well, I gather from your answers that there are a
variety of emerging coal technologies that can be useful and can be
implemented by the electric power industry rather quickly and
would help meet the growing demand which you have forecast.
What level of funding should we be looking at for fiscal year
1986 to assist in the commercialization of those technologies?
Mr. WooTTEN. Well, first of all I think what Congress has to send
to the industrial sector is a significant commitment that they are
willing to follow through on this. I think the private sector has
sent a signal back to Congress through DOE that they are willing
to commit a substantial amount of their funds. If Congress can now
find a way to respond to that with a meaningful amount of money,
I don't think we are talking about $10 or $20 million, I think we
are talking about hundreds of millions of dollars.
Now, Mr. Chairman, whether that has to be spent all in fiscal
year 1986 is not certain. There is generally with projects an ex-
penditure cycle where you begin slowly, you build in the middle
years, and then you tail out with the testing phase. Maybe that
should be looked at. But the first thing that has to happen is that
there has to be a significant amount of money put forward to
ensure that industry feels confident that you will go ahead so that
they will, in fact, begin and commit these funds. Their own funds.
Mr. Boucher. Mr. McCormick.
Mr. McCormick. Mr. Chairman, I would say before we try to
decide on an amount of money I think we ought first to decide on
an authorization. I think the Appropriations Committee might de-
serve to hear from this committee and perhaps the Energy and
Commerce Committee just what you consider ought to be the goals,
and then decide how much money would be needed to attain that.
But if you held that a Federal-private cost-sharing ratio of some-
thing like 30-70, and I think I heard that figure discussed this
morning, then you could leverage $100 million quite a long way.
But I would say that if there isn't some authorization legislation
324
preceding an appropriations number, then I think the Appropria-,
tions Committee will find it difficult to approve it. W^
Mr. Boucher. Mr. Wootten.
Mr. Wootten. I would try to echo Mr. Eric Reichl's statement
that depending on the technology there may be a different formula
for what is acceptable participation and what is not. I think the
amount of risk in each of these technologies warrants some consid-
eration. Also, the magnitude of the expenditure on the cycle. It
may be a $20 million proposition to retrofit a boiler with LIMB
technology, but it may be a $500 million proposition to build a new
second generation combined-cycle utility system. So, if I could pose
upon you to think that through, there would be quite a different
formula, maybe, for the large expenditure than there would be for
the smaller expenditure.
Mr. Boucher. I guess Congress is going to have to face this year
assuming that the judgment is made to provide a demonstration
scale cost-sharing program. The determination is going to have to
be reached with regard to the level of funding, and that determina-
tion will need to be reached fairly quickly. The fiscal year begins in
October.
Mr. Mannella had suggested an initial funding level of about
$200 million. Is that in the right ballpark do you think?
Mr. Wootten. Yes, I would think so. I think a way to get a good
handle on that, if Secretary Vaughan and the Department's efforts
of going in and categorizing the 175 or 177 demonstrations could be
done. If they could be forced upon to do that quickly, I think that
the wheat could be cut from the chaff very quickly and you could
begin, then, to get a feel in those technology areas about how much
moneys would be needed to demonstrate them.
I don't think it is $8 billion — was it $8 billion that he stated — but
I think that characterization could be done fairly quickly if they
were forced.
Mr. Boucher. Mr. McCormick, do you want to comment further
on that?
Mr. McCormick. Well, I am sort of still hovering around the
$100 million range but I am not sure why. I also see this as a mul-
tiyear program.
Mr. Boucher. It is.
Mr. McCormick. And I think it is in the out-years that we will
see the larger spending. So again I go back to let's design the corral
before we decide how many horses we will put in it.
Mr. Boucher. Assuming that Congress does make the judgment
to provide this program and provides funding for the 1986 fiscal
year, what kind of structure would you contemplate the Depart-
ment of Energy establishing for the purpose of evaluating the
projects and making awards? Would there be a call by the Depart-
ment on the private sector to offer advice, and should that be insti-
tutionalized in some way? Should we, perhaps, call on the National
Coal Council for its recommendations in that regard? What general
comments do you have in response to that question?
Mr. Wootten.
Mr. Wootten. The one of management, of how you implement
actually selection of those projects is an important one. I think
there is considerable expertise both in the National Coal Council in
325
DOE and in the private sector, and there may be mechanisms to
bring that together as long as that implementation helped to expe-
dite it and did not become another layer. I think you know what I
mean.
I think that there are some of these technologies in some of the
responses that are obvious and clearly are things that are right on
the threshold and moneys could be expended fairly easily. The De-
partment of Energy could act as a means to funnel those moneys to
them much as they have with TVA and some other projects, full-
scale demonstration projects. Other projects, because of their stage
of development, may require some kind of competitive situation
and evaluation because there may be more than one technology,
there may be the conditions of needing to evaluate not only the
technology part of it but the data base and whether the proposers
have the substance to carry through their plans. So that may take
a different approach, and that, in fact, may take a blue ribbon
council of some kind or those kind of ideas.
I think that is something that our Coalition is going to try to
give some thought.
Mr. Boucher. Very good.
Mr. McCoRMiCK. Mr. Chairman, if the Congress is very emphatic
about the goals of this program, if it is going to lay out that money,
and it makes the EPA an equal partner with DOE, then I think
you are going to find a lot of the wheat and the chaff separating
very quickly. Then if you add to that the EPRI and the National
Coal Council, then I think you have the input from the four main
players. And I don't think it would take more than a few weeks to
come down with the first cut of the sensible list of candidates to get
the first amounts of money.
Mr. Boucher. Thank you very much. I don't have any further
questions. If neither of you cares to add anything further, that will
conclude our testimony today.
I want to thank you very much for your very helpful presenta-
tion. I am personally very glad to see the interest that the panel of
witnesses has expressed in developing a Federal role in support of
demonstration-scale facilities for emerging clean coal technologies.
I am glad to see that there is substantial support here on this sub-
committee for that as well. And I, for one, am very hopeful that
Congress will approve a program this year.
There being nothing further, the subcommittee is adjourned.
[Whereupon, at 12:50 p.m., the subcommittee was adjourned, to
reconvene subject to the call of the Chair.]
326
APPENDIX I
Additional Statements Submitted for the Record
STATEMENT OF
THE AMERICAN GAS ASSOCIATION
BEFORE THE
SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATIONS
COMMITTEE ON SCIENCE AND TECHNOLOGY
UNITED STATES HOUSE OF REPRESENTATIVES
ON EMERGING CLEAN COAL TECHNOLOGIES
May 29, 1985
The American Gas Association (A.G.A.) is a national
trade association comprising nearly 300 natural gas
distribution and transmission companies serving more than
160 million consumers in all 50 states. Collectively, these
companies account for nearly 85 percent of the nation's
total annual gas utility sales.
A.G.A. is pleased to submit this statement on emerging
clean coal technologies. Although we are not in a position
to propose specific projects, we would like to be certain
that this Subcommittee is aware of new technologies that
could be funded from the Clean Coal Technology Reserve and
that either: (a) combine the use of natural gas with coal
to reduce emissions; or (b) otherwise help to utilize coal
in a more environmentally attractive manner.
NECESSITY FOR FEDERAL INCENTIVES
In its Report to Congress on Emerging Clean Coal
Technologies, the Department of Energy (DOE) recommended
327
that the Federal Government should not provide incentives
(i.e., loan guarantees, cost sharing, etc.) for emerging
clean coal technologies. The DOE determined that free
market forces will "select and commercialize the most
efficient and environmentally-effective technologies for
processing and using coal . . . ." The DOE further stated
that Federal incentives would only interfere with the
operation of market forces and could affect adversely the
development of nonsubsidized technologies.
\ A.G.A. does not believe that Federal incentives would
interfere with the commercialization of these technologies.
Although free market forces will ultimately determine which
of the emerging coal technologies will be best suited for
commercialization, substantial expenditures will be
necessary to develop these technologies prior to
commercialization. Federal incentives are necessary to
develop and demonstrate the potential for these new
technologies: i.e., to bring them to the point at which the
market can choose between them.
As a related point, regulatory policies often constrain
rate-regulated gas and electric utilities from gambling on a
promising new technology. These regulated companies
frequently need to share risks with governmental agencies
until the new technology is proven through experience with
pioneer plants.
A.G.A. also disagrees with the DOE ' s suggestion that
past experiences with Federal assistance in the development
328
of new fossil technologies has been completely unsuccessful.
A recent and prominent example is the Cool Water plant in
Daggett, California. This small-scale powerplant produces
on-site medium BTU coal gas at a rate equivalent of 1000
barrels of crude oil per day for use in combined cycle power
generation. Although Federally assisted, the project has
reportedly been so successful that it is now emerging as a
possible model for large-scale private sector efforts.
SELECT GAS USE
Select gas use (select use) refers to a relatively new
concept in fuel combustion: the burning of natural gas with
less environmentally attractive fuels in the same or
separate combustion units for environmental control
purposes. Natural gas combustion emits virtually no sulfur
dioxide or particulate matter, and far less nitrogen oxides,
nonmethane hydrocarbons and carbon monoxide than other
fossil fuels.
As one option, select use may involve the combustion of
gas and another fuel (most often coal) in the same
combustion unit as a fuel mixture. A more common approach,
and less difficult from an engineering perspective, involves
the concurrent combustion of gas and some other fuel in
separate combustion units, with subsequent averaging of the
emissions from the two sources. This latter approach
(termed a bubble), when approved by the Environmental
Protection Agency (EPA), may be used to meet the air quality
329
guidelines of a State Implementation Plan (SIP). A third
approach (not currently sanctioned by the EPA) entails the
seasonal substitution of gas for other fuels. Coal or
high-sulfur oil could be burned for a portion of the year
and natural gas could be burned for the remaining portion of
the year to offset the coal- or oil-derived emissions.
These concepts have advanced from the theoretical stage
to the implementation stage. More than two dozen select use
applications have been implemented, including four cases of
concurrent combustion in a single unit. Furthermore, at
least four major institutions are conducting additional
research into the simultaneous combustion of gas and other
fuels in a single unit. The research relating to gas and
coal combustion is focused in three areas: (1) reburn
technology to reduce NOx and SO^ emissions; (2) gas use to
assist the burning of coal-water mixtures; and (3) gas use
to assist oil-to-coal conversions (utilizing either
coal-water or dry coal).
(1 ) Reburn Technology
Reburn is a post-combustion pollution control method
that can be used to reduce NO^ levels found in the
combustion products of coal-fired electric utility or
industrial boilers. Natural gas (or another fuel) is
injected into the exhaust from a coal-fired boiler, creating
a fuel-rich zone in which the NOx reacts and produces free
nitrogen; air is then added to complete the combustion
330
process. Preliminary testing indicates the reburn process
using gas could easily reduce NO2 emissions by 50 percent.
The Gas Research Institute and the Energy and Environmental
Research Corporation are currently conducting research on
the reburn process to determine: (a) how close the
reburning fuel should be relative to the combustion zone;
and (b) how much time should be allowed for reburning before
air is injected into the process.
( 2) Assisting Coal-Water Mixtures
Coal-water mixtures were originally proposed as a way
to displace foreign oil with domestic coal. More recently,
however, it has become evident that coal-water mixtures may
appeal to those who use coal but want to avoid the
environmental impact associated with the direct combustion
of dry coal. One reason for this expanded market for
coal-water mixtures is that developers of such mixtures have
been developing innovative methods for cleaning the coal
before it is integrated into a mixture. Unfortunately, the
use of coal-water mixtures may lead to substantial
deratings, slagging, fouling, flame instability and other
problems. Recent gas industry sponsored research indicates,
however, that cofiring coal-water mixtures with natural gas
offers an economic and environmentally attractive solution
to these problems. We cite as examples three recent papers:
(1) J. Dooher, T. Kanabrocki, and D. Wright, Co-firing
of Coal Water Slurries with Natural Gas, ( Adelphi
Center for Energy Studies, Adelphi University,
Garden City, New York) .
331
(2) Robert H. Essenhigh, E.G. Bailey, Kyu-il Han, and
Zongwen Li, Performance Characteristics of a
Hot-Wall Furnace Fired With Coal Water Slurry (CWS)
Using Gas/Air Atomization (The Ohio State
University, Columbus, Ohio).
(3) Alex E.S. Green, Coal-Water Mixtures - A Market
Opportunity for Natural Gas (University of Florida,
Gainesville, Florida) .
(3 ) Oil to Coal Conversions
In addition to the use of coal-water mixtures,
economically and environmentally advantageous conversions of
oil-fired boilers to coal have been proposed using a
precombustor/ash separator unit. A research team at the
Unversity of Florida is currently using natural gas to
assist a full scale oil to coal conversion. We cite for
example :
(1) A. E.S. Green, An Alternative to Oil: Burning Coal
with Gas (Gainesville, FL, University Presses of
Florida, 1981).
COAL GASIFICATION
Gasified coal can be combusted without the adverse
environmental impact associated with direct combustion of
pulverized coal. A coal gasification plant gasifying
western coal produces from 5 to 58 percent of the air
pollutants emitted by a coal-fired electricity generation
plant with scrubbers. Furthermore, a coal gasification
plant emits bniy 40 percent of the solid wastes produced by
a coal-fired electricity generation plant.
332
Funds from the Clean Coal Technology Reserve could be
used to promote second- and third-generation gasification
processes. We view as particularly promising the U-Gas
technology (which was developed by the Institute of Gas
Technology and would have been demonstrated commercially if
the Memphis onsite medium Btu coal gas project had received
Federal assistance and become operational); the Kellogg-Rust
Westinghouse (KRW) technology (which is currently being
utilized at a Pennsylvania test facility that receives both
industry and government support); and any other technology
which entails ash agglomerating fluidized bed gasification.
It is the considered opinion of our Coal Gasification
Subcommittee and Advanced Technology Task Group that these
second-generation technologies — when compared with the
currently available Lurgi technology — could potentially
reduce unit production costs by at least 20 to 25 percent.
In addition, our most knowledgeable member company advisory
groups are convinced that second-generation technologies
could also reduce substantially the environmental impact of
currently available coal gasification technologies.
Additional research facilities for these
technologies, such as a test facility that we propose to
site at the Great Plains gasification plant, would be
valuable. However, we also believe that the
second-generation technologies are now ready to proceed to
the stage of small-scale commercial projects.
333
PROJECT SELECTION PROCESS
The Environmental Policy Institute has suggested that
funding recommendations for specific clean coal projects
should be determined by the DOE, EPA, National Coal Council
(NCC) and Electric Power Research Institute (EPRI). A.G.A.
strenuously opposes the selection of coal projects by such
an exclusive group of organizations. The NCC and EPRI
represent narrowly focused interests whose primary research
concerns may not encompass the vast array of clean coal
technologies. For example, EPRI is concerned primarily with
the development of coal technologies that can be used to
generate electricity. Although we support clean coal
research for electricity generation, we believe that clean
coal research for purposes other than electricity generation
would also serve the public interest. Research on select
use and coal gasification would result in the development of
both industrial and electric generation uses for coal that
offer significant environmental benefits.
A.G.A. strongly recommends that decisions on specific
coal projects be made by the appropriate government agencies
and a broad-based consortium of energy research
organizations representing all of the segments of the energy
research community that are interested in clean coal
research. A diverse group of organizations could determine
by consensus the coal research that would most benefit the
public .
334
CONCLUSION
A.G.A. believes that select gas use and
advanced-generation coal gasification offer the potential
for significant advances that will permit coal to be used in
a clean, environmentally sound and cost-effective manner.
V7e also believe that the process for selecting coal projects
should reflect the consensus of the energy research
community and the government on the coal research projects
that would be in the public interest.
335
AMERICAN PUBLIC POWER ASSOCIATION
2301 M STREET NW WASHINGTON DC 20037 • 202/7'5t300
P'M.tfti' JACK K SPRUCE
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ROBERT C YOUNG
Bo'lirigion Vermoni
May 7, 1985
The Honorable Don Fuqua
Chairman, Subcommittee on Energy Development
and Applications
Committee on Science and Technology
U.S. House of Representatives
Rayburn House Office Building
Washington, D.C. 20515
Dear Congressman Fuqua:
The American Public Power Association would like to express its
support for the Emerging Clean Coal Technologies program as described
in Section 321 of the House Joint Resolution No. 648 of 1984. The
reasons for our support ire detailed below.
The American Public Power Association (APPA) is the national
trade organization representing 1,750 local, publicly-owned electric
utilities throughout the United States, Canada, Puerto Rico, the
Virgin Islands, American Samoa, and Guam. Most APPA members are
municipally-owned systems. About 500 public power systems generate
electricity in addition to distributing it to consumers.
APPA endorses strengthened Federal support for the demonstration
of emerging clean coal technologies for several reasons:
• First, coal is our most abundant domestic energy resource, for
which increased utilization is in the national interest.
• Second, much of the electricity generated by APPA members
occurs within municipal city limits or other areas of
relatively high population density. For reasons of public
acceptance and general public welfare, clean conversion
technologies must be employed to foster the greater use of coal
at these generating sites.
• Third, current technologies for controlling the air emissions
from coal-fired generation of electricity impose other
environmental burdens in solid waste disposal and may add as
much as 25 percent to installed costs of new generation.
• And fourth, as you may be aware, the American Public Power
Association supports a least-cost emission reduction program to
control acid precipitation. In order to ensure the lowest
long-term electricity costs to consumers, newer, less costly.
and cleaner coal conversion technologies must be developed to
balance future energy and environmental goals.
336
APPA believes there are emerging coal technologies that can promote these
objectives. APPA recommends that due consideration be given to these
technologies as the clean coal technology program evolves and receives funding.
Foremost on the list of promising technologies is fluidized-bed combustion
(FliC). FBC offers fuel flexibility, rigorous emission control, a more easily
handled solid waste, the potential for modular construction, and the ability to
be retrofitted for existing boilers. To date, demonstration projects are
planned by investor-owned electric utilities, rural electric cooperatives, and
Federal systems. Yet due to its modular nature and ability to burn many wastes
found at the local level (including municipal solid waste, certain forms of
industrial o-r process wastes, or agricultural residues), FBC may be especially
appropriate for municipal electric utilities.
Another approach to meeting the objectives of the Emerging Clean Coal
Technologies program is to emphasize combined heat and power production with
coal-fired capacity. Through such cogeneration, a greater amount of useful
energy services are provided to the consumer for a given amount of fuel input.
Combined heat and power production means that fixed costs and air emissions are
spread over a larger output of useful energy, thereby acting to lower costs to
consumers and to decrease emissions per unit of desired energy services.
Means to gasify coal -- either in combination with conventional boilers or
with advanced technologies -- are notably appropriate for such applications.
Examples include the use of gasified coal in district heating and cooling
systems and in fuel cells. Both examples lend themselves well to cogeneration.
APPA urges strong consideration of these approaches as well.
As the electric utility industry grapples with needed capacity additions
over the coming decade against a backdrop of uncertainties in fuel availability
and more stringent environmental controls, the demonstration of appropriate
coal conversion technologies is a matter of national import. APPA urges
support for the Emerging Clean Coal Technologies program. We encourage that
support be matched with an appreciation for the needs and opportunities of
public power systems that provide electricity to one in e\iery seven Americans.
Sincerely yours.
Alex Radin
/da
337
HURLEY W RUDD
MAYORCOMMISSIONE-R
JACK L Ml lean JR
MArOR PRO TLM-COMMltjblONER
CAROL BELLAMY
COMMISSIONER
BETTY G HARLEY
COMMISSIONER
FRANK VlSCONTl
COMMISSIONER
CITY HALL
32301
May 6, 1985
Honorable Don Fuqua
Representative
U.S. Coj*^r^ess
2269 Raiybuin House Office Building
Washintton/ D.C. 20515
DANIEL A KLEMAN
CITY MANAGER
ROBERTS INZER
CITY TREASURER-CLERK
STEVEN BORDELON
CITY AUDITOR
JAMES R ENGLISH
CITY ATTORNEY
TELEPHONE
. 904 I 599-8100
Dear Con«ra§,j<jian Fuqua:
Subject': City of Tallahassee's Testimony to
Subcommittee on Energy Development and
Applications
The City of Tallahassee is submitting the
enclosed testimony to you as Chairman of the Committee
on Science and Technology. This testimony is being
submitted for the record to the Subcommittee on Energy
Development and Applications in conjunction with the
Subcommittee's hearings on May 8, 1985. Also,
Tallahassee will be represented at the May 8, 1985,
subcommittee hearings because of the importance your
Clean Coal Technology Program is to Tallahassee and the
nation.
Tallahassee is the only municipal system at
this time involved in the Clean Coal Technology Program
and we appreciate this opportunity to express the views
of a municipally owned system.
ely.
5aniel A. Kleman
City Manager
DAK/RTK/mgm
Enclosure
338
TESTIMONY SUBMITTED FOR THE RECORD TO
THE SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATIONS
OF THE COMMITTEE ON SCIENCE AND TECHNOLOGY
U. S. CONGRESS, WASHINGTON, D. C.
BY
THE CITY OF TALLAHASSEE
DANIEL A. KLEMAN, CITY MANAGER
MAY 8, 1985
Mr. CHAIRMAN, Members of the Subcommittee on Energy
Development and Applications and Staff, the City of Tallahassee
is pleased to present this testimony for the record on the
Emerging Clean Coal Technology Program. The City of
Tallahassee feels that the Emerging Clean Coal Technology
Program is necessary in order to demonstrate new technology for
power generation that is both cost effective and
environmentally benign. If the Emerging Clean Coal Technology
Program does not go forward, then new innovative technologies
that would benefit society by reducing acid rain and foster the
use of abundant domestic energy sources such as coal would not
be demonstrated soon enough for at least the electric utility
industry when they re-enter the marketplace for new apparatus
in the early to mid-1990's.
During the mid-1970's, when motorists in the United States
were introduced for the first time to dollar-a-gal Ion gas and
long lines at the pumps, the public learned that this country
had an energy crisis. Today, after nearly 10 years of rising
prices and even more uncertain energy supplies, the crisis has
drifted away from public thought. Today's concentration is on
the economy: high interest rates, unemployment, low
productivity and America's decline in the world marketplace.
While many people fail to recognize a critical connection
between the two topics, there is a key linkr and it is
America's ability to produce electricity, at a reasonable cost.
Much of the economic difficulty that confronts the power
industry and the nation today has its roots in the rapid
escalation of petroleum prices during the decade of the 70 's.
Thirty-six percent of all U.S. electrical generating capacity
339
is oil or gas fired, equivalent to 2.6 million barrels of oil
per day. About 40 percent of the oil and 80 percent of the
natural gas used in the United States are for heating (space,
water and industrial process heat), much of which can be done
efficiently with electricity.
The United States depends on foreign sources to meet about
30 percent of its total oil demand. The economic impact of the
oil consumed by electric utilities totaled approximately $13
billion in 1981. This is equivalent to 29 percent of imports
from OPEC, and equal to approximately half our merchandise
trade deficit for that year. To be competitive economically,
the United States must utilize its coal resources. A 1980
survey of 44 U.S. utilities showed that coal maintained a
dramatic cost advantage on a kwhr basis - 2.5 cents for coal,
versus 5.4 cents for oil. In spite of this domestic advantage,
however, we continue to rely on higher-priced, foreign fuels.
With deregulation of natural gas pricing, gas, which is a
substitute fuel for many other uses, is expected to reach a
value close to oil in five to ten years.
Fluidized bed combustion can provide utilities the ability
to fire U.S. coal while keeping the costs for environmental
compliance under control. We believe the fluidized bed
combustion system, in comparing it to a pulverized coal boiler
with fuel gas desul fur ization (FGD) , would offer the following
advantages to the utility industry:
1. Reduced ash/waste disposal quantities.
2. Superior ash physical, chemical and leeching properties.
3. Reduce fuel preparation requirements.
4. Flexibility to burn variable quality fuels.
5. Reduce NOX emissions.
6. Improve economics, both capital and operating.
7. Eliminates the need for dry or wet FGD systems.
8. Chlorine and fluorine compounds are largely retained in
the ash.
9. More siting flexibility since FGD systems are not
required .
In our opinion, the Emerging Clean Coal Technology Program
is necessary to demonstrate the circulating fluidized bed
boiler technology since it has not been demonstrated at this
size previously. The risk associated for a small municipal
340
utility to proceed with innovative technology that could
possibly provide us with the advantages stated previously is
much greater than what we can afford to take on by ourselves,
especially when this technology, once demonstrated, would have
wide application to all other generating utilities due to the
size of the boiler and quality of coal that would be
demonstrated through our project and other innovative
technologies that have been proposed. The role of the Federal
Government in assisting the private sector in bringing to the
commercial forefront new technology by federal incentives,
including grants, loan guarantees, low interest loans or price
supports is vital when you consider the significant benefit to
our society from these technologies. In addition, the reasons
for the development of new and innovative technologies as were
recommended in the Emerging Clean Coal Technology Program is
based on the overall impact on society in the areas of
environmental protection as mandated by federal EPA
regulations, national energy security and quality of life in
general .
The circulating fluidized bed (CFB) technology offers
several unique advantages over bubbling fluidized bed (BFB)
technology;
The CFB can burn a wider variety of fuels including coals
with high sulfur and high ash contents, lignite, peat,
wood, bark, petroleum coke and other refinery residues.
Typically, many of these fuels are difficult and/or
uneconomical to burn in BFB systems. The CFB also has
sufficient flexibility to burn different types of fuels in
the same combustor. This fact reduces dependency on oil.
Higher carbon burn-out (over 99%) can be achieved for all
fuels including those with low heating values and/or low
proportion of volatiles.
Higher degree of desul fur ization can be achieved. Over 90%
S02 removal can be obtained with a calcium-to-sulfur (Ca/S)
molar ratio of 1.5.
Lower NOX emissions (less than 300 volumetric parts per
million, vppm) can be obtained through "staging" the
combustion air. This responds to the overall objective of
improving the quality of the air.
Higher carbon burn-out (combustion efficiency) and the
lower consumption of limestone required for desul fur ization
contributing to higher overall thermal efficiencies (90-92%
based on^ th^" lower heating value).
CFB ' s offer simpler fuel preparation and feed systems.
341
The CFB is clearly a very versatile system which can be
used for thermal energy production in industry, and for
electricity production in utility power plants and cogeneration
plants .
In summary, CFB combustion is very effective in situations
where hard-to-burn and/or low grade fuels are to be utilized,
where strict environmental control is required, and where an
efficient and flexible operation is required.
The City of Tallahassee submitted to the U.S. Department of
Enrgy a Statement of Interest for our Arvah B. Hopkins
Generating Station, Unit #2 for a circulating fluidized bed
replacement boiler, with reheat. Our proposed circulating
fluidized \bed combustion boiler would utilize 640,000 tons of
high sulfur eastern coal per year producing 235 megawatts of
power. In addition, a life extension and uprating would be
conducted on the existing turbine generators which could
produce an additional 5% to 15% of additional megawatts.
Therefore, we feel the Emerging Clean Coal Technology
Program must go forward and cover several areas of innovative
technology to be demonstrated. In our opinion, we feel one of
these technologies should be circulating fluidized bed
combustion based in the advantages and merits as discussed
above.
342
Transamenca
Delaval
STATEMENT BY
Bern E. Deichmann
Vice President, Marketing
Transamerica Delaval, Inc.
Hearing on Clean Coal Technology
343
Transamenca
Delaval
1
I am Bern E. Deichmann, Vice President of Marketing for Transamerica
Delaval Inc. Transamerica Delaval is headquartered in Lawrenceville,
New Jersey and has manufacturing facilities at 20 locations in
the United States and overseas.
We are most grateful for the opportunity to testify on behalf of the
Clean Coal Technology program and to acquaint the Committee with our
proposal. We believe strongly in the necessity to accelerate the wise,
efficient and clean use of our coal reserves. We joined the Clean Coal
Technology Coalition to assist the Congress in this, and we fully
endorse their statement of support.
The overall objectives of our Coal Gas Diesel (COD) program are the
timely research, development and verification testing needed to
achieve:
1. OVERALL EFFICIENCY GREATER THAN 50%
(coal pile to bus bar)
2. COST OF ELECTRICITY LESS THAN THAT FOR COAL FIRE CONVENTIONAL
STEAM PLANTS WITH FLUE GAS DESULFURIZATION .
•J. EMISSION OF ATMOSPHERIC POLLUTANTS WITHIN LIMITS SET BY
FEDERAL STANDARDS.
4. FULLY DEVELOPED AND COMMERCIALLY AVAILABLE BY THE 1990'S.
These objectives are realistic; the technology can be applied and
verified; hardware modifications are within the current state of the
art; the economics are real and attractive; and the need is great.
To accomplish these objectives a pilot plant consisting of the
following major components is required: (See Schematic 1 attached)
1. LOW BTU GASIFIER.
2. GAS CLEAN UP SYSTEM.
3. A MEDIUM SPEED, DUAL FUEL ENGINE SYSTEM.
4. WASTE HEAT RECOVERY SYSTEMS.
Transamerica Delaval proposes to study, develop and test a system that
will provide an economical way to burn coal cleanly. We propose to
build a full scale pilot plant to demonstrate the technology, the
economics and the low enviromental impact. The testing proposed will be
phased from burning cold clean Low BTU coal gas at the start and
moved toward burning hot dirty gas. The objective is to determine how
hot and how dirty the gas can be for the engine to burn It economically
and still meet all environmental criteria.
PAGE 2 May 16, 1985
344
Transamenca
Delaval
r
We propose that a dual-fuel, heavy-duty medium-speed diesel engine of
proven design be employed, driving a generjitor to produce electricity,
fueled by low BTU gas produced from coal.
The developmental aspects of our proposal are in two principal areas:
FIRST, apply the most modern, cost-effective technology to remove
sulfur and other pollutants from the produced gas so that the
atmosphere remains clean, and SECOND, developing the necessary
modifications to the engine to most efficiently burn the low-BTU fuel
and achieve the maximum power rating.
We believe the proposal we have submitted will lead to the mitigation
of acid rain as more coal is burned in the future by utilities and
industry. At the same time, our proposed plant will:
1. Provide measureable savings in fuel consumed per unit of
electricity generated,
2. Rationalize the expenditure of capital to meet electrical needs
of industry and smaller communities
3. Shorten lead times for construction to twenty-four months or
less.
We believe our experience in burning medium BTU sewage gases
particularly well qualifies us to undertake this development and we are
confident of our ability to execute the program within the time and
cost constraints we have offered.
Transamerica Delaval has been performing preliminary research and has
found its engine has the ability to burn low-Btu gas. The test program
was conducted at our facility in Oakland, California early in 1984 and
the gas was a simulated gas. Combustion characteristics and results
were excellent.
We also conducted preliminary testing of coal tars produced from a Utah
coal. The results of the tests were most encouraging. With additional
R&D and improvements in components, our engine will be able to utilize
both the gas and the tars of a gasifier and convert them to electrical
energy.
Concerning sulfur removal, we propose working with a company having
broad experience in this field to develop a commercial gas purification
unit to incorporate into the total gasification and heat engine system.
With regard to the market for such a system, there is an increasing
trend toward smaller power plants to service the industrial and utility
sectors. Some conclusions from studies are:
1. Large, conventional, coal-fired plants are costly due to
PAGE 3 May 16, 1985
345
Transamenca
Delaval
1
excessivley long design, permitting, and construction times, as
well as stringent environmental controls.
2. Regulatory control making it difficult to incorporate all costs
into the rate base.
3. Studies show that small units can be very competitive because:
A. -They can be factory-built and modularized.
B. -Utilize cogeneration to boost plant efficiencies.
C. -Technology has improved the performance of older methods of
power production, such as diesel engines, and of clean up
systems associated with them.
As noted previously, when it is demonstrated in this program that a
large bore, medium speed diesel engine can be run economically in an
environmentally sound way on cold, clean, low BTU gas from a coal
gasifier, we propose further research to expand the envelope from
burning cold, clean gas toward establishing the limits of burning hot,
dirty gas. Thus simplifying the total facility and improving the
economic evaluation.
This phase of the project includes the study, development and testing
of:
1. Improved gas clean up technologies.
2. Improved emissions control technologies for diesel engines.
3. Advanced materials for diesel engines.
4. Improved gasifier technologies.
As you can see, this program seeks to build a strong technology base
for the utilization of coal-derived fuels.
Without a strong federal role supporting fuel utilization technology,
advanced heat engine capabilities will be slow in developing and there
will be less incentive to bring these fuels to the marketplace. Such an
approach would be a costly strategic error, probably delaying the
penetration of coal-derived fuels into the petroleum market for many
years.
The most effective approach for accomplishing the objectives is to
heavily involve industry in all the technology programs but to rely on
Government funding for basic and applied technology development and to
support high cost experimental facilities. This approach will provide
for a wide range of technology options and is expected to reduce costs
PAGE 4 May 16, 1985
346
Transamerica
Delaval
r
and accelerate market entry of the systems.
In summary', Transamerica Delaval proposes to study, develop and test
full scale pilot plant that will provide an economical way for industry
and utilities to burn coal cleanly. The result will be a pilot plant to
demonstrate the technology, the Integration of component systems, the
economics and low enviromental impact for industries and utilities as
they continue a transition to coal - a fuel that is not only more
abundant than almost any other fossil fuel but one that reduces our
dependence on foreign countries. This project will be a joint venture
between the Federal government and industrial partners, and one that
will provide a good return on investment for all of the participants.
Thank you
PAGE 5 May 1G, 1985
347
Transamerica Delaval Inc. Presents
To The Department Of Energy
A Clean Coal Technology Program
Low
Emission
Exhaust \
Waste
Heat
Recovery
Dual
Fuel
Enterprise
Engine
Witn
Selectomatic
J W
Heat
Recovery
[ GEN I
Bus Bar
Coal to Bus Bar Efficiency 50%
348
THOMAS R KUHN. Executive Vice President
EDISON ELECTRIC
I |k| O T I T I I T E ^*^^ association of electric comfwrm
nil 19th Slfeei, N W
Washington, D C 20035-3691
Tel (202)828 7400
May 29, 1985
The Honorable Don Fuqua
Chairman
House Science & Technology Coininittee
House of Representatives
2321 Rayburn House Office Building
Washington, DC 20515
Dear M«:-_Xto4^cman:
I appreciate the opportunity to submit the enclosed testimony regarding the
clean coal technology reserve on behalf of the members of the Edison Electric
Institute (EEI).
EEI is the association of electric companies. Its members serve 96% of all
customers served by the investor-owned segment of the industry. They generate
approximately 75% of all electricity in the country and service 73% of all
ultimate customers in the nation. We support the clean coal program and ask
that the following statement be made part of your hearing record.
Sincerely,
Thomas R. Kuhn
TRK:llj
Enclosure
349
CLEAN COAL TECHNOLOGY RESERVE
A NATIONAL PRIORITY
SUBMITTED BY
THE EDISON ELECTRIC INSTITUTE
TO THE
SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATIONS
HOUSE COMMITTEE ON SCIENCE AND TECHNOLOGY
Rfl-rilR O — 85 1
350
CLEAN COAL TECHNOLOGY RESERVE
A NATIONAL PRIORITY
On behalf of the Edison Electric Institute (EEI), we welcome
the opportunity to discuss the potential role of clean coal
technologies as a supply option to provide for the continually
growing demand for electricity. EEI is the association of
electric companies. Its members serve 96 percent of all
customers served by the investor-owned segment of the industry.
They generate approximately 75 percent of all electricity in the
country and service 73 percent of all ultimate customers in the
nation. VJe appreciate the willingness of the Committee to
conduct this timely and important hearing.
SUMMARY
The evolution of the forces affecting utility planning has
made the characteristics of the alternative clean coal
technologies of great interest. Current circumstances, however,
may prevent full utilization of the benefits which these
technologies offer.
During my testimony today I will describe the need for nev;
capacity, the resource options being implemented to balance
supply and demand, the investment planning considerations, and
other technology options available to electric utilities. The
advantages of using clean coal technologies to advance the list
of generating options for providing power in the future include:
o Environmental benefits of reduced SO , NO and
particulate removal on a cost-effective bisis
o Modular Construction
o Wider Fuel Selection
o Improved Efficiency and Availability
o Greater Coal Utilization
This program provides a unique opportunity for technology to
drive regulation based upon marketplace rather than regulatory
criteria. As an incremental investment banker in these projects,
the federal government has a unique opportunity to reduce the
risk of technology demonstrations.
- 1 -
351
NEED FOR NEW CAPACITY
The past 15 years have been tumultuous ones for energy and
electricity. Twice, oil imports were curtailed — first, by the
embargoes and second, by the Iranian revolution. Also, we should
not forget that during the mid-1970's natural gas curtailments
led to unemployment. The promise of nuclear power has been
tarnished by well-publicized problems affecting some plants.
And, of course we all know what happened to prices of all forms
of energy. These events reduced economic growth, contributed to
the changing structure of the economy, and affected our personal
behavior and attitudes.
NOV7, because we appear to be in a period of energy
stability, there is a danger of complacency. Oil, natural gas,
and coal supplies are abundant and market prices soft. For most
electric utilities, construction programs are coming to an end.
In addition, new electricity supply sources and demand side
management are growing. It is unlikely that we will return to
former use patterns and high consumption growth.
However, this appearance of stability offers little solace
to electric utility planners. Because more moderate growth
continues and because construction leadtimes in this industry are
so long, difficult planning decisions for adequate power supplies
in the 1990 's must be made soon. New capacity is needed to
support economic growth, to provide for retirement of plants, and
to reduce dependence on oil and gas.
Virtually all forecasters expect continued growth in elec-
tricity demand. Most long-run forecasts for electricity consump-
tion growth fall in a range of 2.0 to 4.0 percent per year. The
electric utility industry is planning for growth in consumption
of 2.7 percent and growth in peak demand of 2.5 percent over the
next decade. This implies a 30 percent increase in consumption
over that period. These growth rates, although low by long-run
historical standards, represent a continuation of the relative
growth trends of energy and electricity. Since the oil embargo,
annual total energy use has actually declined while electricity
sales have risen 3.4 percent over this 12 year period.
The fraction of energy use accounted for by electricity will
continue to grow. In 1950 electricity accounted for 15 percent
of total energy use. By 1960 the share was 19 percent. As we
reached 1970 and 1980 it rose to 24 percent and 33 percent re-
spectively. The share is expected to rise to over 40 percent in
the 1990's. Coal's contribution to electricity production is
also expected to increase.
As plants grow older, just like any industrial facility,
they must be replaced. With fewer new plants coming on line, the
average age of facilities in place will be rising throughout the
balance of the 1980 's. While the effects of aging can be
mitigated by appropriate investments and plant-life can be
extended in some cases, the plants must ultimately be replaced.
- 2 -
k
352
In some cases new capacity is also needed in order to reduce
dependence on high-cost oil and gas, especially imported oil.
Since the 1973 embargo, electric utilities have reduced oil
consumption by over 50 percent and gas consumption by 20 percent.
Host energy analysts agree that utilities should continue to work
toward becoming less dependent on these high-cost fuels.
Not only is there a consensus that new capacity is needed,
there is also wide agreement about when it will be needed.
Approximately 131 gigawatts (GW) of generating capacity are
planned to come on line from 1984 to 1993. This is equivalent to
approximately one new large plant each and every month for the
next ten years. Even with this expansion program, sometime in
the early 1990 's peak electricity demand is expected to exceed
installed capacity.
We concur with the conclusions drawn by the Department of
Energy in publication DOE/IE0003, Staff Report Power Supply
and Demand for the Contiguous United States 1984-1993. This
publication states that there is "potential for inadequate power
supply in some regions" during the 1991-93 period even assuming
all planned capacity is brought on-line as scheduled.
Without question, uncertainties surround all of the factors
affecting the need for new capacity. Yet, projecting a plausible
range of very modest growth rates and projecting a minimum level
of replacement of aging and high-cost facilities, some new
capacity above and beyond what is already planned will be
required in the 1990 to 1995 timeframe. There is a continuing
need for new generating plants and the critical planning focus is
now on the early 1990 's.
Utility Investment Planning Considerations
The economic and regulatory environment in which utilities
operate affect the choice of resource options which will be
selected to meet this need for new capacity. Conditions today
favor selection of technologies with certain characteristics.
Expectations are for electricity sales to grow near or
slightly below the growth of the economy. Although some years
will exhibit strong growth (for example, sales were up 5.6
percent in 1984) , new capacity will need to be added at a slower
rate than in the past. For many utilities, increments of new
demand are smaller. The first implication is that needed
increments of supply are smaller, as well. A second implication
is that a planning error on the high side is not quickly
corrected by high growth. A given increase in supply takes
longer to be absorbed by growing demand than in the past. Nor
can a planning error on the low side be quickly corrected.
Consequently, increments in supply should closely match
increments in demand.
- 3 -
353
The cost characteristics of generating electricity today
reinforce this point. Previously, the addition of a new
generating plant actually lowered the unit cost of electricity.
Productivity improvements and learning curve effects made
economics of scale the rule. Building ahead of demand actually
lowered costs. The situation is now reversed. The next kilowatt
is more expensive than the last and cost recovery has become
contentious. Any deviation between increments of demand growth
and increments of supply growth can be a source of economic and
regulatory problems for the company involved.
Financial exposure when adding new capacity is now a
daunting consideration. In some cases, the cost of adding a
baseload generating plant can exceed the net worth of a company.
Frequently construction is a threat to the financial standing of
a company. Company expenditures rise, costs must be carried
until the time the plant goes into service, and cost recovery
with a competitive return is not assured. Financial incentives
are to forego construction if at all possible. Electricity sales
may be slowed by escalation in world oil prices. Changed
standards for environmental controls and revised regulatory
treatment pose potential financial threats against the earnings
of a utility. Along with reduced sales, these factors may result
in earnings levels which can not support technology commer-
cialization. Commercialization of a new technology is limited by
these financial factors and the uncertain treatment of the
financial risk by public utility commissions.
Finally, the real crux of the planning problem that can
cause a mismatch of supply and demand is the lead time necessary
to respond to uncertain forecasts. Uncertainty is inescapable.
But, the lead time problem is controllable. Many of the problems
of the industry would be greatly mitigated by shortening the time
from the decision to build a plant to commercial operation.
Existing short lead time technologies can be selected. Today
such technologies are limited to high cost oil and gas turbines.
Because of the incentives not to build new plants, there is a
danger that this choice will be made by default to satisfy the
demands of the 1990 's. New clean coal technologies may offer an
opportunity for reduced construction lead time.
In summary, we are now in a slower growth, rising cost
planning environment. The strategic implications of this are:
(1) to build smaller scale plants relative to the past; (2) to
consider renovating existing facilities; (3) to add capacity
which better tracks demand growth and fluctuations; and (4) to
select technologies with a higher ratio of variable to total
costs.
- 4 -
354
The Technology Options
Utilities have a number of supply options with which to meet
growing demand. Current technologies can meet future demand.
But, current planning considerations compel a search for new
options. A quick review of conventional choices illustrates the
point.
Because of a decade's accumulation of regulatory,
management, and public decisions, the promise of nuclear power is
now eclipsed for any utility needing additional capacity before
2000. Under present regulatory and institutional arrangements,
American electric utilities are not evaluating ordering nuclear
plants. The cost and risks of nuclear development in the United
States presently tend to price it out of the current market.
Conventional coal technology, although capable of filling
the need, comes with its own set of problems. Coal plants can
satisfy all existing and proposed environmental regulations; but,
the cost is high. Currently, 34 percent of the physical cost of
a plant is for environmental control. Also, economies of scale
make an efficiently sized plant too large for the demand
increments of many utility systems. Finally, the conventional
method of burning pulverized coal is technologically mature.
There have been no significant improvements in heat rate (coal
burned per kilowatthour produced) in many years.
Other options are becoming a part of utility resource plans.
Utilities are buying power from third-party producers
(cogeneration and small power production) . Utilities are also
actively pursuing other non-conventional generating technologies
such as low-head hydro, wind, geothermal, biomass, solar thermal,
photovoltaics, and fuel cells. The costs and technological risks
associated with these technologies place limits on their
development over the next decade.
Although the focus today is on generating capacity, we
should also note that utilities are pursuing demand-side
management. These techniques can hopefully give us some control
over the timing of capacity needs and modify demand to allow
efficient use of capacity that is in place.
THE BENEFITS OF CLEAN COAL TECHNOLOGIES
There are a variety of technical benefits to clean coal
technologies including modular construction, short construction
lead times, environmental enhancements, wider coal selection, and
improved efficiency in the conversion of raw BTU's to electricity
which address the challenges described above. All of these are
important national benefits also.
^ 5
355
Environmental Benefits
Environmental quality is a public benefit that has been a
goal of governing policy for years. The inherent characteristics
of clean coal technologies lead us to believe that the
environmental benefits will be significant. Clean Coal
technologies appear to have the potential to reduce emissions
levels more than existing technologies. Table 1 below indicates
the emissions control potential associated with these
technologies:
TABLE 1
EMISSIOnS CONTROL POTENTIAL
Technology
^°x
(% remSval)
Conv PC/FGD* 1
90-98
AFBC 2
90-95
Adv PC/FGD 3
90-95
PFBC 4
90-95
GCC 5
90-99
Fuel Cell GCC
99+
Slagging
Combustor 6
90-95
NO^
(lb/10-Btu)
0.5-0.6
0.2
0.2-0.3
0.1
0.1-0.3
0.003
0.1
Particulate
(Ib/lO^Btu)
0.03
0.01
0.01
0.01
0.003
nil
0.01
* New Source Performance Standards (values listed are legal
maximum emissions — not the potential)
1 Conventional Pulverized Coal with Flue Gas Desulf urization
(FGD)
2 Atmospheric Fluidized Bed Combustion
3 Advanced Pulverized Coal/FGD
4 Pressurized Fluidized Bed Combustion
5 Gasification Combined Cycle (GCC)
6 Limestone injected with Staged Combustion/Baghouse or ESP
For varying technologies, these potential benefits may be
realized either on new generating capacity, or through the
retrofit of existing sources to meet demands for reducing
emissions from existing coal-burning pov;er plants.
-6-
356
All of these potentially offer significant advances over
current technologies. Of the advanced technologies, performance
data are available only on the gasification combined cycle system
now being demonstrated in California. After 10 months of
operation, the SO and NO emissions are well within the design
standards of the ^lant anS are significantly lower than existing
coal-fired plants with flue gas desulfurization systems. VJhile
this is only one plant relying primarily on one type of coal, we
believe it offers significant insights into the potential of
these technologies in both new and retrofit situations to utilize
all qualities of coal in environmentally acceptable v/ays.
Because several technologies appear potentially to offer similar
reductions in emissions, all of these technologies need
widespread demonstration to enable our industry to evaluate
adequately the most cost-effective technology.
Current Flue Gas Desulfurization (FGD) technologies
represent economic costs to our industry. EEI's Construction
Committee has estimated that FGD adds 34 percent to the cost of
new coal-fired power plants. FGD systems are complex chemical
engineering facilities that are difficult to apply to existing
facilities. According to EPRI calculations, maintenance costs
for FGD systems are two to twenty times the maintenance costs for
the rest of the power plant. Difficulties with FGD systems have
reduced the availability of coal-fired power plants, thereby
adding to utilities costs. Clean coal technology demonstrations,
including less costly and more reliable FGD systems, offer an
opportunity for utilities to evaluate the effectiveness of new
technologies in meeting national environmental goals.
TechnoloQV Driving Regulation
An important element of the federal role is to assure that
technology drives regulation in industries where that is appro-
priate. I have noted above the high cost and unreliable nature
of current flue gas desulfurization systems. It would be indeed
unfortunate if that system were to be the only technology choice
for burning coal in an environmentally acceptable manner. We
believe that the thorough demonstration of these various
high-technologies offers us a potential to demonstrate the best
means for environmental control based upon technology
performance. Cost-based performance and selection, rather than a
regulatory-imposed selection, can provide the most cost-effective
benefits to the American people. Technology selection would
apply to our industry's need at a plant to be retrofitted or a
new one.
Modular Construction
New technologies are characterized by modular construction
techniques. This results in fabrication of the system components
off-site and transportation to the plant location by truck,
barge, or rail. Modular construction may also result
-7-
357
in parts of a system being brought on line at different times to
meet elements of growing load demand. For example, a turbine
might be brought on line fueled by oil or gas as the first
element of a combined-cycle plant; later the turbine v/ould use
fuel produced by the plant after plant construction. In this
way, modular construction is able to assist in meeting rapid
growths in electric demand.
One particular advantage of modular construction is that
rapid assembly is possible. To date, the Cool Water Gasification
Combined Cycle Plant in California is the most prominent example
of modular construction. Due to its modularity, it was
constructed in 28.5 months from ground-breaking to the time of
operation. This construction time of under 2.5 years is about
one-third that of a conventional coal-fired generating station.
Shorter construction times make it possible for utilities to
respond more precisely to changes in demand thereby reducing
construction costs as well as financial risks. In the case of
Cool Water, the actual cost was $31 million below estimated
costs. Modular construction would result in pov/er stations
resembling a chemical plant, and like chemical plants, they would
be available in different sizes.
Wider Fuel Selection
Today utilities frequently design a boiler to burn a coal
with specific qualities. The entire plant is designed around
parameters of the coal such as heating value, ash, sulfur, and
trace metals contents. Clean Coal technologies, particularly
gasification combined cycle and fluidized bed systems, appear to
offer the potential to use a broader range of coals. They would
permit wider competition in the coal market to serve utilities
and industrial customers. The entire coal market would
potentially be increased because coal could be used where
environmental standards may otherwise preclude it.
Improved Efficiency and Availability
The technology of burning pulverized coal has been in
existence, essentially unchanged, for about the last 50 years.
Improved thermodynamics in the conversion process of coal to
electricity assist in raising generating station efficiency and
lowering electricity cost. New technologies can become the basis
of improved efficiences because of the various means that offer
enhanced thermodynamics.
Similarly, because these plants are modular and may be built
in series, repairs and maintenance of a system component may not
shut the entire plant down as is likely to today. Instead, it is
possible that throughputs of a production stream can be increased
to compensate for a shut-dov/n component resulting in power
production remaining at the same level. This will lessen the
-8-
358
risk that a single plant component would be able to shut down
a single unit or plant. Through these techniques, the avail-
ability or time the plant is producing power can be increased
which reduces the amount of capacity needed to meet electrical
load. Overall, this has the potential of reducing financing
costs for plants not used regularly.
Regulatory Agency Limitations
Federal Energy Regulatory Commissioner Charles G. Stalon has
noted that state regulatory agencies have limited abilities to
approve utility expenses that are incurred beyond the narrow
definition of producing utility services. He concluded that the
processes of regulatory agencies are not designed to make good
decisions on research funding.
Current regulatory policies for the most part impede the
recovery of costs associated with the commercialization of clean
coal technologies. This requires utility companies to shoulder
significant financial burdens.
The Chief Operating Officer of Virginia Power Company, Jack
H. Ferguson, observed in February that, "Without Federal support
we could easily have a situation in which utilities will not
embrace, and their regulators will not permit, new technology
until it is demonstrated by another company. Everyone could be
waiting for someone else to take the hazardous trek across the
desert in search of the fertile lands beyond. That policy could
reflect the observation that it is often not the pioneers but the
followers who gain the greatest benefits with the least cost.
While this may be a prudent approach for each utility and its
regulators, it will not be in the best interest of the nation."
As an incremental partner with utilities and private
industry, the Federal Government can help assure that this course
of action does not occur.
THE APPROPRIATE ROLE OF THE FEDERAL GOVERNIIENT
Unquestionably the Federal Government should be involved in
the development of clean coal technologies.
If it is in the national interest to further technologies
such as clean coal combustion, then the government must consider
moving down the road from generic R&D toward commercialization.
Government participation can help overcome technical, financial,
and institutional barriers and enrich the choices for
commercialization. Federal involvement should be structured
along the lines of an investment banker where funds are advanced
to specific parties for demonstration of promising technologies.
-9-
359
There is a guarantee of a stream of information that
indicates whether a certain technology is cost-competitive when
applied to utility scale applications. The information stream is
probably most important for our industry for future planning for
the retrofit of old plants and construction of new ones.
Government support for this program should not stop at the
proof of concept scale as currently advocated by the DOE, but
should be carried through the stage of commercial demonstration.
The Energy Research Advisory Board (ERAB) has correctly noted the
difficulty in bringing many of these clean coal technologies into
full-scale utility application.
CONCLUSION
Clearly the advantages of clean coal are substantial. Some
of these advantages such as modular construction are reflected in
the investment decision process and will be captured by electric
utilities and their customers. Others, particularly the
environmental benefits of SO , NO and particulate removal,
reflect larger public concerns, it is the responsibility of the
government to assure achievement of these benefits for both new
and retrofit applications.
To do that, the government must focus on two issues. First,
it must act now. The decision window for planning facilities
which will be needed in the 1990 's is now. Without prompt action
the probability of additional conventional facilities is greater.
Without prompt action the United States will be handicapped in
world technology competition.
Second, the government must recognize the role it can con-
structively play to move technology from R&D to
commercialization. The primary role is with the private sector.
But, when the public benefits are large and not fully reflected
in the private investment criteria, then it is the proper
function of the government to take action to capture those
benefits for the public good.
We appreciate the opportunity to present our views on this
program of vital interest to our industry and the health and
well-being of our Nation.
~ IQ-
360
STATEMENT OF CHARLES S. MC NEER
CHAIRMAN OF THE BOARD & CHIEF EXECUTIVE OFFICER
WISCONSIN ELECTRIC POWER CO.
TO THE
ENERGY DEVELOPMENT AND APPLICATION SUBCOMMITTEE
OF THE HOUSE SCIENCE AND TECHNOLOGY COMMITTEE
MAY 8. 1985
Mr. Chairman and members of the subcommittee, I am Charles McNeer,
chairman and chief executive officer of Wisconsin Electric Power Co., Wisconsin's
largest electric utility. We supply energy services to more than two million
people in a 12,000 square mile service territory in both Wisconsin and Upper
Michigan. I welcome the opportunity to provide this statement in support of
the Clean Coal Technology program and the system known as pressurized fluidized
bed combustion.
I am sure you are all keenly aware of the important role that coal plays not
only in the generation of electricity in the United States, but also in the
economy of various regions of our country. Let me provide some additional per-
spective. The electric utility industry is and will continue to be the nation's
major consumer of coal. By 1995, electric utilities are expected to account for
86 percent of total U.S. coal consumption. Coal will be used to generate 55 percent
of total electricity produced in this country by 1995, up from 51 percent in 1980.
Coal from the Eastern and Midwestern United States has played a major role
in meeting our energy needs. But its future and the jobs that go with it are
clouded by uncertainty, as proposed restrictions on sulfur dioxide emissions
could make Eastern and Midwestern coal less desirable.
At Wisconsin Electric, about 60 percent of our electricity comes from coal-
fired generating plants. Fifty-three percent of the coal we use comes from
Kentucky and Illinois. Ten years ago, 70 percent of our coal came from Midwest
suppliers.
With electricity a major factor in economic growth, it is important that the
nation's No. 1 fuel — coal — be given high priority when we make decisions about
our economic future. Western coal will continue to be a popular product because
of its low-sulfur content. However, while our country's coal reserves are enough
to last 300 years, the uncertainties that surround the use of higher sulfur coal
have placed those reserves in doubt. They also have forped electric utilities
around the country to seek more expensive alternatives. Those alternatives include
the use of low-sulfur coal or the construction of power plants with expensive
pollution control systems.
The uncertainties surrounding higher sulfur coals stem mainly from the public
perception that acid rain is menacing our environment. The public is asking for
two things — first, a clean environment and second, adequate and economical
supplies of electricity. The two concerns need not be in conflict.
361
Acid rain is a phenomenon that needs to be handled in a coordinated way,
on a national and international basis, with the costs shared equitably. Earlier
this year, I sent letters to all members of the Wisconsin congressional delegation,
noting that Wisconsin Electric can and will support appropriate national
legislation to address concerns about acid rain. I have attached a copy of one
of those letters to my statement here today. In it, I proposed that any national
legislation be implemented in two phases. The first would set reasonable, cost-
effective requirements to address emissions around the country. The second phase
would take into account all of the research that is now starting to come together,
along with the new clean coal technologies that are being developed.
With the expected increase in the use of coal, it is even more important that
we begin today to demonstrate these technologies so that we will have options
available in the 1990s. Other options, such as scrubbers or the use of low sulfur
coal, are expensive, threaten the loss of thousands of jobs and represent short-
sighted solutions to a long-term need.
That is why support for the Clean Coal Technologies Program is vital. That
is why I ask your support for what I believe is the boiler of the future — the
pressurized fluidized bed combustion project that Wisconsin Electric has proposed
to construct in cooperation with Foster-Wheeler Development Corp., Brown Boveri
Corp., Gilbert/Commonwealth and Research-Cottrell.
Wisconsin Electric has a long and successful tradition of leadership in research
and development programs for coal-fired power plants. Early in this century, we were
the first utility in the world to burn pulverized coal for the generation of electri-
city, and we constructed the world's first plant built to burn pulverized coal
exclusively. Our pioneering efforts in coal research led to world records in power
plant efficiency.
We haven't ignored the customer side of our business. Wisconsin Electric has
been a leader in successfully controlling increases in demand for electricity, and
reducing the need for new power plants, through innovative conservation, rate and
load management programs. One measure of our success was our ability to reduce
rates three times in the past 15 months — a record unmatched by any major U.S.
utility.
Our latest project — the pressurized fluidized bed combustion system — will
reduce sulfur dioxide emissions by up to 90 percent — even while using Midwestern
coal. The system readily meets new source performance standards for nitrogen oxide
emissions, and it has the potential of operating as much as 15 percent more effi-
ciently than today's conventional coal-fired power plants. This along with the
potential for shorter construction times and lower construction costs could
effectively reduce electric energy costs to our customers. This revolutionary
system can mean a strong future for coal mined east of the Mississippi River.
It can mean economical electricity production. And it can mean a cleaner
envi ronment.
Not only is^ouA'cou^itry involved in an acid rain debate that could limit our
use of coal, we also find ourselves in an era when adding new nuclear power plants
is not a practical option. Because of cost and regulatory uncertainty, the elec-
tric utility industry simply cannot plan today for additional nuclear plants.
That establishes a persuasive case for the need to demonstrate practical Clean
Coal Technologies.
362
Wisconsin Electric cannot ask its customers and stockholders to take on the
sole responsibility for demonstrating the PFBC. We believe it is a project that
could benefit the entire nation and as such should appropriately receive national
support. Neither can we ask the federal government for total financial support.
That is why Wisconsin Electric has started an ambitious national campaign to seek
additional funds for this project from the coal and utility industry and others
that would benefit from a demonstration of the commercial viability of the PFBC
technology.
Our PFBC project is vital to the economic future of our country, and can help
us maintain. our energy independence. I urge your support for the clean coal tech-
nology program and for the Wisconsin Electric PFBC demonstration project I have
described.
Thank you for the opportunity to provide this statement.
363
Wisconsin Electric pomR company
231 W. MICHIGAN. PO BOX 2046 MILWAUKEE, Wl 53201
February 19, 1985
Hon, James Sensenbrenner, Jr.
2444 Rayburn House Office Building
Washington, D.C. 20515
Dear Congressman Sensenbrenner:
The legislation proposed by the National Governor's Association offers the
framework for a reasonable approach to the concerns about acid rain, but also
contains provisions that wuld significantly Increase the price of electricity
In Wisconsin.
While I cannot support the NGA proposal as written. It does address some
Important elements that should be Included In any national approach to this
issue. Those elements are:
—a two-phase sulfur dioxide emissions reduction program;
—a first phase requiring reasonable reductions In sulfur dioxide
emissions that can be obtained in a cost-effective Banner;
—an expanded and accelerated research program;
—a second phase that would be implemented only If the research and an
assessment of the first phase results demonstrate the need for more
controls; and
—an Implementation schedule for phase two that will allow for
cost-effective advanced technologies for sulfur dioxide emissions
reductions to become comnercially available.
I should point out that the NGA bill is by no means the moderate bill some
have suggested it is. In fact. It goes far beyond the Issue of acid rain. It
virtually requires a minimum 10-mi 11 ion-ton sulfur dioxide emissions reduction
and it gives unprecedented decision-making power to the EPA administrator.
These provisions make the bill unacceptable as a whole. Let me explain further.
As written, the NGA bill would likely force Wisconsin Electric to install
scrubbers on one or more of our power plants In phase one. Rate Increases of at
least 10 percent would be necessary If these scrubbers are required.
An alternative that we favor would be first phase reductions on the order
of three million tons of sulfur dioxide a year from 1980 levels, and
flexibility for utilities In how they meet such reductions. This would allow us
to avoid making huge financial commitments to retrofit older units with
extremely expensive scrubbing equipment that may later prove unnecessary.
During phase one, we should proceed with an expanded research program that
would be used along with the results on the phase one reduction program to
determine whether it is necessary to proceed with additional controls.
Reductions in the second phase should be tied to the demonstrated need for more
controls and to the availability of cost-effective emissions reduction
technologies.
364
The NGA bill takes the opposite approach. It says the second phase could
be reduced or eliminated only if the EPA administrator convinces Congress that
such a change will increase protection of resources. This is an impossible
test. If the Congress is unconvinced, or if one tree or lake could be said to
be potentially susceptible to damage, the additional phase two reductions must
take place.
In addition, the bill authorizes the EPA administrator to further increase
sulfur dioxide reductions and require nitrogen oxide emissions reductions in
the second phase. He would have to explain to Congress only if he chose not to
require nitrogen oxide reductions.
We believe decisions about implementation of the second phase, or about
even more stringent emissions reductions, should be made by Congress, not the
EPA administrator. These decisions should be based on technical, economic and
public policy information. To leave such decisions in the hands of the EPA
administrator, as the NGA proposes, authorizes an inappropriate exercise of the
administrator's judgment and authority.
Equally troublesome is the fact that the NGA bill undermines the powers of
the existing Clean Air Act, which is the vehicle already established by
Congress for dealing with such issues as ambient air quality, health effects
and visibility. The NGA bill's broad statement of purpose seems to empower the
administrator to circumvent this vehicle and its well-established health and
welfare standards.
Acid rain is a national Issue, and as such should be dealt with on a
national level. This bill, however, does so In an unacceptable manner. I urge
you not to join as a co-sponsor of this bill until modifications are made.
Despite the national nature of the acid rain issue, Wisconsin has taken
steps to reduce sulfur dioxide emissions. These actions Include:
—state legislation placing a cap on utility sulfur dioxide emissions;
—new state Department of Natural Resources rules requiring further sulfur
dioxide emissions reductions;
—a $1.7 million research project into the causes and effects of acid
rain, conducted jointly by state agencies and utilities, with the
utilities providing $1 million. This research so far shows no evidence
of acid rain damage to lakes or forests in Wisconsin.
On its own, Wisconsin Electric recently has embarked on a revolutionary
new sulfur dioxide emissions control project. We have Indicated our desire to
be the host site for a pressurized fluidized bed combustion (PFBC) demonstra-
tion unit at our Port Washington Power Plant. This unit could remove some 90
percent of the sulfur from the coal as it is burned, and could yield important
data that would help bring such PFBC units to connerical availability.
I am concerned that in the absence of preemptive federal action, Wisconsin
and other states will take further uncoordinated steps to Independently reduce
sulfur dioxide emissions. This would be counterproductive on two fronts. If
Wisconsin acts alone in reducing sulfur dioxide emissions, those reductions
would be so insignificant on a national basis that they would have no
measurable effect, positive or negative, on the environment. And, by standing
365
alone to require emissions reductions, Wisconsin would put its businesses and
its citizens at an economic disadvantage. Acid rain is a phenomenon that needs
to be handled in a coordinated way, on a national basis and with the costs
shared evenly.
Finally, while I don't mean to suggest that acid rain will just go away,
there are several developments on the horizon that will help mitigate its
effects. For instance, as older plants are retired, newer plants burning lower-
sulfur coal will come on line. New sulfur and nitrogen oxide emission reduction
technologies that can be retrofitted onto older units may soon become
comnercially viable. Given time, these two factors alone could make a big
difference in the scope of the problem. This, combined with the expanded
research program proposed by the NGA should make it easier for us to determine
whether additional control measures are necessary.
This NGA bill also contains numerous other provisions that are objection-
able and that I would be pleased to discuss with you in more detail. Do not
hesitate to call.
Sincerely,
ciXM%^
Charles S. McNeer Chairman of the Board and
Chief Executive Officer
cc: Governor Anthony Earl
Secretary Carroll Besadny
Chairman Ness Flores
Coimissioner Branko Terzic
Conmissioner Mary Lou Hunts
366
APPENDIX II
Department of Energy
Washington, DC 20585
June 14, 1985
Honorable Don Fuqua
Chairman, Committee on Science
and Technology
House of Representatives
Washington, D.C. 20515
Dear Mi;. Chairman:
On May 8, 1985, Assistant Secretary William Vaughan appeared
before the Science and Technology Subcommittee on Energy
Development and Applications concerning the clean coal
technologies initiatives.
Following that hearing, you submitted written questions for
our response to supplement the record. Enclosed for your
information are the answers to those questions, which also
have been sent directly to the Committee staff.
If you have any questions, please call Ingrid Nelson or
Cathy Hamilton of my staff on 252-4277. They will be happy
to assist you.
Enclosures
Sincerely,
■ /
. Raoben
Robert G.
Assistant General Counsel
for Legislation
367
EMERGING CLEAN COAL TECHNOLOGIES
Question //I: There has been mention of using the National Coal Council in
the Emerging Clean Coal Technologies Initiative. Please expand
on this possibility. Please characterize that group as to
occupations, coal industry experience, availability, and
geographical representation.
Answer: The Charter of the National Coal Council states, in part, that the
National Coal Council can provide advice and recommendations on
such matters as "scientific and engineering aspects of coal
technologies, including emerging coal conversion, utilization, or
environment control concepts." Therefore, it would not be
inappropriate for the Council to be asked by the Department
(Secretary) to provide recommendations Involving emerging clean
coal technologies.
The Council is in the very early stages of organization, with the
first meeting scheduled for June 10. Clearly, the Initial emphasis
will be on developing a workable organizational framework that will
permit the Council to function effectively in its advisory
capacity. Once the Council is in a position to accept assignments
from the Secretary, emerging clean coal technology could be a study
topic.
The Coal Council was established with the objective of bringing
together a wide diversity of professional backgrounds and
geographic representation. Twenty individual categories of
coal-related expertise are represented on the Council with members
from producers, shippers, transporters, equipment manufacturers,
industrial and utility consumers, research organizations,
368
environmental groups, union and non-union labor, tribal councils,
and related fields.
Representatives were also selected with the objective of providing
as broad a geographic representation as possible. Accordingly,
members are included from more than 30 states.
A specific attempt was made to include senior level representatives
of corporations and institutions. Typically representation is at
the Chief Executive Officer, President, or Board Chairman level, as
appropriate. Many of these individuals have more than four decades
of personal experience in coal mining and related industries. One
of the principal attributes of the Coal Council is that it makes
available to the Executive Branch an exceptionally high degree of
industry experience.
Regarding the availability of Council members, the charter requires
that all members convene twice each year in a meeting of the entire
Council. Members, of course, can and will meet more frequently as
specific projects are undertaken.
369
EMERGING CLEAN COAL TECHNOLOGIES
Question //2 : In DOE's Emerging Clean Coal Technologies Report's assessment
of alternative fuels, the potential for significant oil
displacement by coal water mixtures is examined. The Report
anticipates that the highest displacement will occur at the
higher-risk end of the technology spectrum, including heat
engine applications. The assessment concludes that this area
"is prime for Federal stimuli and one for which DOE's program
is focused.
Please address how DOE is and intends to focus on stimulating
research and development of the application of coal water
slurries to heat engines.
Answer: Under its Heat Engines Program, DOE is procuring experimental
quantities of advanced coal water slurries and highly-benef iciated
dry coal for evaluation in engineering tests under simulated heat
engine operating conditions. The objective of these tests is to
provide the data to solve major engineering, design, durability,
and performance problems associated with the substitution of coal
or coal-derived fuels for distillate fuels and natural gas in
firing gas turbines and diesel power conversion systems. In this
way, DOE is evaluating advanced fuel forms with the view toward
heat engine application.
370
EMERGING CLEAN COAL TECHNOLOGIES
Question #3: Please respond to the statement in ERAB's report that,
"Acceptance of coal water slurry by the utility will require
further extended large scale combustion tests. The private
sector seems to be ready to pursue this subject; however, the
high cost of large-scale tests will require substantial DOE
assistance."
Answer: .The DOE has sponsored extensive combustion tests to establish the
feasibility of using coal water slurries in oil designed utility
boilers. We would agree with ERAB that, partly because of the
results of these tests and other privately sponsored tests, "the
private sector seems ready to pursue this subject." However, we do
not agree that "substantial DOE assistance" is appropriate or
required. Sufficient progress has already been made in the
development of coal water slurries for large utility boiler
applications to make this fuel ready for private sector
commercialization.
For example, Babcock & Wilcox and Combustion Engineering are
developing utility-size coal-water slurry burners. The Electric
Power Research Institute is conducting a comparative evaluation of
utility-sized burners using coal-water fuels from several
manufacturers. Boston Edison recently tested coal-water slurry in
two burners of a 125-megawatt boiler. Coal-water fuels produced by
the Cape Bretton Development Company's Nova Scotia plant are being
burned in a small, coal-capable utility boiler at New Brunswick
Electric Power Company's Chatham Power Station in an extended
demonstration. Also, Nycol of Sweden is supplying commercial
quantities of coal-water fuel to the Sundbyburg power station in
suburban Stockholm.
371
In view of this, we believe the proper DOE role should now be
focused on the higher risk small industrial, residential, and
commercial markets which have significant potential for oil and gas
displ acement .
372
EMERGING CLEAN COAL TECHNOLOGIES
Question //4 : ERAB's report recommends that DOE increase its efforts to
co-fund programs aimed at waste utilization rather than
disposal. How does DOE plan to respond to this recommendation?
Answer: The Waste Management Program is not supporting work in the waste
utilization area as a matter of DOE/FE policy. This policy is
■ based on a number of considerations. First, extensive R&D has been
conducted in the area of coal waste (mostly ash in some form)
utilization over the past several decades. This technology is
largely mature and in general has not been very cost effective.
Second, research in waste utilization has been an open-ended R&D
area which has seldom resulted in new products. Third, even the
more successful coal utilization schemes have done little to
mitigate the waste disposal problem.
In the effort to assist the private sector for greater utilization
of coal use waste products without developing new methods, the
Department of Energy will support a project to develop and publish
a textbook dealing with engineering design practice for high volume
coal combustion ash by-product and flue gas scrubber waste
utilization technology.
To complement the waste utilization work that was done in the past
and is now being conducted by the private sector, DOE has focused
its efforts on the characterization and assessing the leachage and
behavior of the wastes from the advanced technologies being
developed in the fossil energy program. In addition, DOE is
researching methods of energy recovery from coal preparation
wastes.
373
EMERGING CLEAN COAL TECHNOLOGIES
Question #5: Would it be within the Administration's definition of the
"proper" federal R&D role for DOE to fund a test program in
which the various coal locomotive concepts are demonstrated and
compared in conjunction with the private sector to allow the
private sector to pick the concepts most commercially feasible?
Please respond to the points discussed in the following
background .
Background Such a program would fulfill Congressional and
other requests for federal financial support of a coal
locomotive prototype while minimizing the federal role in
choosing between technologies. Such a program could be
operated on a cost-shared basis with the combustion system
manufacturers as well as with other interested private sector
parties. Concepts suitable for such a program include, but are
not limited to: AFB, coal-water mixture, pulverized coal,
producer gas, coal-fired diesels and coal-gas turbines.
Answer: In the Administration's view, the federal government should not
fund a test program in which the currently proposed coal-fired
locomotive concepts would be demonstrated under conditions that
would permit the private sector to compare their commercial
feasibility for the following reasons. Nine different concepts
were proposed ranging widely in development requirements, costs,
schedules, risks, and potential pay-back. To ensure an equitable
basis for comparison, such a program could cost upwards to a
billion dollars and take 6 to 10 years. A crash program of this
kind is not justified by technical considerations. Some of the
concepts presented represent merely evolutionary improvements over
the last generation of post World War II steam locomotives.
Others, like the coal-fired diesel or gas turbine, are
revolutionary in nature. Still others apply relatively well
established coal utilization technologies to steam reciprocating
engines. In our view, it is clearly not a proper government role
374
to indiscriminately fund demonstration programs of such disparate
concepts in order to facilitate commercial assessment.
Rather, the proper federal R&D role in this technology area is to
conduct long-range, high-risk research to determine if it is
feasible to use coal in dlesel engines to provide power to
stationary sources or the transportation sector. This effort is
currently being conducted under the Fossil Energy R&D Heat Engines
program. A copy of a recent DOE news release related to this area
is attached.
375
U.S. DEPARTMENT OF ENEROY
OFFICE OF THE PRESS SECRET ARV
WASHINGTON. OC 20SM
DOENEWS:
NEWS ICDIA CONTACTS:
Robert C. Porter (Washington) 202/252-6503
Claire H. Sink (Horgantown) 304/291-4620
FOR IMMEDIATE RELEASE
May 14, 1985
ENERGY DEPARTMENT AWARDS CONTRACTS TO RETURN COAL TO DIESELS
Three research teams, each Including a major U.S. diesel manufacturer,
have been awarded government contracts to determine If It Is feasible to use
coal In diesel engines to provide power to stationary sources and to run
locomotives and small ships. Secretary of Energy John S. Herrington
announced today.
The contracts were awarded by the U.S. Department of Energy's Morgantown
(WV) Energy Technology Center, Their total value exceeds $5 million and
Includes more than $725,000 of private sector cost-sharing.
"The results of these three contracts will help provide the groundwork
for Industry to decide if U.S. manufactured diesel engines can be fueled
with coal, which Is our most abundant domestic resource," Herrington said.
"A positive result could assist us in our long-term goal of reducing the
country's need for foreign oil."
One team, made up of Arthur 0. Little, Inc., of Cambridge, Mass.;
Cooper-Bessemer Diesel, of Grove City, Peon.; and the Massachusetts Institute
of Technology, Boston, will study large, coal-fired, stationary industrial
cogeneration and maritime diesel applications. It will receive $1,330,000 in
federal funds and will contribute another $98,000 of private funding.
R-85-045
376
A second team. Involving the Locomotive Division (Erie, Penn.) and the
Corporate Research and Development Center of the General Electric Co.
(Schenectady, New York) will Investigate locomotive applications for coal-
burning diesels. Federal funding for this effort will total $1,730,000 with
another $297,000 to be provided by the private participants.
The third team Includes the Allison Gas Turbine Division (Indianapolis,
Ind.) and the Electro-Motive Drive Division (LaGrange, 111.), both part of
General Motors, and the Southwest Research Institute of San Antonio, Tex. It
will also study locomotive applications using $1,290,000 of federal funds and
$320,000 of private funds.
Each contract will run for two years.
The Energy Department's objective Is to develop ways of reintroducing
coal into an engine that once was intended to burn coal but now is fueled
solely by oil.
When Rudolf Diesel conceived the diesel engine in the 1890s, he
envisioned it as a way to produce power by burning both solid and liquid
fuels. Research in the 1920s through the early 1940s, principally in
Germany, dealt with the burning of solid fuels in low-speed diesels commonly
used in Europe. After World War II, inexpensive and abundant petroleum
pushed the abrasive, solid coal fuels out of the diesel market.
The oil shocks of the 1970s revived interest in the coal -fueled diesel.
Exploratory tests in the early 1980s and further development in related
areas such as cleaning coal of ash and sulfur, and grinding and slurrying
very fine coal have increased the Energy Department's confidence that coal
could still become a candidate fuel for U.S. manufactured diesels.
The U.S. effort to be undertaken by the three firms will focus on the
medium-speed diesel engine, the major source of power for domestic locomotive
and Inland waterway transportation. Such diesels are also used in small
utility and industrial applications. Together, these applications today
consume more than 1.8 million barrels of oil daily.
-DOE-
R-85-045
377
EMERGING CLEAN COAL TECHNOLOGIES
Question //6: What is DOE's opinion on the comparative applicability of these
concepts to locomotive use?
Answer: In the DOE's opinion, the coal-fired diesel-electric locomotive is
probably the most currently useful concept because it would retain
the flexibility and efficiency of the basic diesel cycle while
conserving a major part of the current capital inventory. The
coal-fired gas turbine-electric traction drive is less attractive
from the standpoint of flexibility but may have an advantage over
the diesel as it could prove to be more tolerant to ash forming
impurities in the coal fuel. Both major U.S. locomotive
manufacturers are comparing the two concepts in engineering studies
and experimental work under DOE contract. In addition, locomotive
manufacturers and railroad operators are cooperatively studying
both systems - as well as others - analytically and experimentally.
The remaining concepts rely principally on steam cycles - turbines
or reciprocating engines - and, while there is little doubt
concerning their ultimate technical feasibility, there is
considerable uncertainty about their applicability and ultimate
economic benefit to the transportation industry.
378
EMERGING CLEAN COAL TECHNOLOGIES.
Question #7: What are your views on the technical and international merits
of the joint U.S. - China development of a new coal-fired steam
locomotive? Please respond to the points discussed in the
following background.
Background This concept is based on the competitive evaluation
of applicable clean-combustion technologies in an existing
Chinese production steam locomotive. Such a concept appears to
have three significant advantages. First, it will introduce a
commercially feasible, environmentally acceptable new
coal -based locomotive to American railroads in the shortest
possible time. Secondly, it is not locked into a specific coal
combustion technology, but will promote joint coal-combustion
technology development between the United States and China.
Answer: The Department of Energy agrees that the development of this
concept would provide a basis for comparing various coal processing
and combustion technologies in locomotive duty cycle service. The
resulting product would indeed represent a class of "new coal-based
locomotives" which could probably be built and run in "the shortest
possible time." The concept is similar, in principal, to other
proposed concepts that apply new coal processing and combustion
technologies to steam reciprocating engine drives. The locomotives
would not, however, preserve the efficiency and flexibility
advantages of modern diesel powered locomotives. Their ultimate
pay-back to the railroads would be limited, we believe, by this
fact. As to the suggestion that this concept's inclusion of
various technologies would avoid its being "locked-in" to one in
particular, we see little merit in this. If serious consideration
were given to a limited-objective coal-fired steam locomotive, it
would clearly be in order to first critically study the options and
then select the preferred one, with a possible back-up, for
engineering evaluation. Furthermore, we believe there are more
379
suitable mechanisms for the conduct of joint coal technology work
with foreign nations than through a market-oriented program such as
that proposed here.
This is particularly true when the markets and existing capital
equipment base are as different as they are between the U.S. and
China.
380
QUESTIONS SUBMITTED BY CONGRESSMAN RICK BOUCHER
Question #1A: The appropriateness of clean coal technologies vary widely
according to numerous factors including characteristics of the
fuel, the age and size of the facility, and the emission
reduction goal. Therefore, no one proposal could be expected
to present the single technology for all purposes.
Would it be the Intention of DOE to develop as wide a range of
technologies as possible?
Answer //lA: Yes, the appropriateness of different clean coal technologies
varies according to several factors and no one technology or
subsystem can be expected to solve all of the problems Involved
In expanded coal utilization.
Question #1B: Would an integrative approach be taken whereby those
technologies would be developed that could be joined together
In different ways, for example coal cleaning with limestone
injection multi-stage burners (LIMB), to achieve overall
emission reduction targets?
Specifically, what are the kinds of technologies with the
greatest potential for integration with other kinds of
technologies and for what kinds of applications?
Answer //IB: The DOE coal research program is intended to result in the
introduction of total systems (from coal mine to end user) which
will allow for cost-competitive and environmentally acceptable
utilization of coal not only in the existing and future utility
market but the industrial, residential/commercial and
transportation sectors as well. We make every effort to
consider each of the technologies within the context of how they
will fit into an integrated system. The example cited by
Congressman Boucher is but one of many ways in which subsystems
can be integrated to form a total coal-based system. We have
not done an analysis to determine which technologies have
greater potential for integration. However, a few general
observations can be made:
381
o All of the coal technologies being pursued by DOE have the
potential for integration into total systems. Some are more
amenable to limited applications while others, if developed to
the point of being cost-competitive, could be a part of
coal-based systems serving all of the consuming sectors.
o Coal cleaning and gas cleanup should be considered as
potentially a part of most coal-based systems.
o Technologies are commercially available for using coal in the
utility sector, but with just a few exceptions, environmentally
acceptable and cost-competitive coal-based systems are not
available for the other consuming sectors.
382
QUESTIONS SUBMITTED BY CONGRESSMAN RICK BOUCHER
Question //2 : The new report by DOE on the reserve states that DOE's previous
experience with federal incentives have "with few, if any
exceptions been unsuccessful in commercializing new fossil
technologies." Federal support for energy technologies,
however, have been apparently successful in a number of areas.
Atmospheric fluidized bed technologies are now being
commercialized. U.S. research and development on heat pumps
and photovoltaics has been adapted and commercialized by the
Japanese. Wall-fired LIMB technology has been successfully
demonstrated by EPA with potential application to 40% of the
utility market.
What has been the role of the federal government or other
governments in the development and commercialization of these
technologies?
Are there other examples of successful government demonstration
and commercialization of energy technologies in this country or
by other countries using either their own research and
development or R&D results obtained by U.S. efforts?
Answer: In general, most Government-sponsored, large-scale development work
on energy technologies have resulted in one of three outcomes:
1. The large-scale unit did not realize its technical objectives,
with the resulting loss of private sector interest.
2. By the time large-scale testing was completed, the clearer
picture of technology costs coupled with perceptions of the
future cost of competing options created an unfavorable outlook
for commercial application.
3. Large-scale testing created some commercial interest, but so
far application has been limited to special situations, which
in some cases are dependent on Federal tax subsidies.
There have been some Isolated cases where the Government has
sponsored large-scale testing on technologies that have ultimately
gained market acceptance. The DOE-sponsored atmospheric fluidized
383
bed combustor demonstrations are an example, even though It is
difficult to say how much these tests may have accelerated the
commercial deployment that is occuring today. Photovoltaics is an
example of a technology that has filled some specialized niches
thus far, although it is unclear when large-scale deployment may
occur. The LIMB technology has technical promise as well as
considerable uncertainty as to its attractiveness with a variety of
coals and boilers, but cannot really be considered "commercial"
yet.
Thus, the lesson from past experience seems to be that, while it is
possible that there are cases where Government-assistance could
help to accelerate commercialization, the track record has not been
good and there is no reason to believe that it would be any better
in the future.
384
QUESTIONS SUBMITTED BY CONGRESSMAN RICK BOUCHER
Question #3: Report language relating to the reserve clearly states that
the purpose of clean coal technologies is "for using coal in
electric utility and large industrial applications that reduce
sulfur and other emissions resulting from such uses to levels
that are required, or may be required, for compliance with the
Clean Air Act, as amended (P.L. 98-473, Senate Energy and
Natural Resources report 98-578)."
Question' i'/3A: Given the limited amount of funds available for coal research
and development and the desire to develop the widest range of
clean coal technologies possible, would DOE try to emphasize
proposals with the greatest potential yield in terms of market
application and emission reductions?
Answer i'/3A: If funds were appropriated by Congress for this program, the
Department of Energy would recommend a course that would result
in eligibility of the broadest range of technologies and market
applications. As discussed in Appendix C of DOE's "Report to
Congress on Emerging Clean Coal Technologies," each technology
has unique advantages and disadvantages as compared with others
and therefore should be given the opportunity to compete on its
merits.
We would expect that under a competitive solicitation there
would be significant proposals from the electric utility and
large industrial sectors. However, any future program should
not be limited to electric utility and large industrial boiler
applications where coal will be the fuel of choice under most
future energy scenarios. The principal U.S. markets for oil and
natural gas are and will continue to be in the light industrial,
commercial, residential and transportation sectors. Therefore,
interesting^ projects which have the potential to move coal into
these markets should not be precluded.
I
385
Question //3B: Specifically, what technologies, if successfully demonstrated,
would have the quickest market applications?
Answer #3B: This question is very difficult if not impossible to answer at
this time. Factors like energy prices, economic conditions, the
financial health of the utility and other industries, future
environmental requirements, etc. will affect market decisions to
use new technologies. Because we have little to no control over
these factors, the DOE's posture has been to develop data on a
suite of technologies from which the private sector can choose
to suit their particular needs.
Question //3C: How long would market commercialization take for these
technologies?
Answer #3C: Again, market conditions, influenced by a number of potentially
applicable future circumstances such as comparative fuel prices
and strength or leniency of pollution emission regulations, will
determine how long it will take for the successfully
demonstrated technologies to be commercialized. However, it is
expected that the more the private sector cost-shares in a
demonstration project, the more likely they will aggressively
market the technology demonstrated.
Question //3D: Specifically, what technologies if successfully demonstrated,
would have the widest market applications?
Answer i'/3D: The information on the market applications for the emerging coal
technologies being researched by DOE is attached.
Question //3E: To what extent could these technologies be expected to
penetrate those markets?
Answer //3E: Although certain potential markets may be preliminarily
identified, as DOE has done in the Technology Assessment section
of its report, there is no way of knowing the extent to which
386
the emerging coal technologies will penetrate the user markets.
Prevailing market conditions in the future will, rather, dictate
the extent of such penetration.
Question #3F: Under these assumptions, what would be the overall emission
reduction potential by kind of pollutant and economic activity
of commercializing clean coal technologies?
Answer #37: Advanced clean coal technologies have the potential to reduce
emissions of several pollutants normally emitted to some degree
from coal including sulfur dioxide (SO.), nitrogen oxides (NO ),
particulate matter, and trace metals. Of these pollutants, SO
and NO have received the greatest interest and quantification.
X
Additionally, some advanced technologies are apt to be used in
applications where coal is already used, such as electrical
generation, and yield benefits of lower cost and reduced
emissions. Other potential applications, such as in light
industry or transportation, will allow less expensive coal to be
used in lieu of petroleum products or natural gas, but in these
cases, emissions are not likely to be significantly lower than
with current fuels. Since the penetration of advanced
technologies is so difficult to anticipate in terms of specific
technologies, pollution reductions stated in absolute terms
would be extremely speculative. The table below offers relative
pollution reduction potential for SO and NO , where it can be
reasonably estimated, for various categories of technology where
advanced coal technology would replace conventional coal use.
387
Technology Potential Reduction (%)
S02 NOx
Dry discharge FGD (e.g., CuO, E-beam, NO SO) 90 90
Limestone Injection with Multistage Burners (LIMB) 50 70
Atmospheric Fluidized Bed Combustion (AFBC) 90 70
Pressurized Fluidized Bed Combustion (PFBC) 98 unknown
Advanced Combustors (slagging combustors) 60 50
Advanced Physical Coal Preparation 65 0
Advanced Chemical Coal Preparation 99 0
Integrated Gasification, Combined Cycle Power 99 85
Emission reductions would come primarily from economic sectors
currently using conventional coal combustion technology. These
sectors Include electric utilities and large industrial boiler
users, the latter dominated by the chemical, petroleum, primary
metals, stone/clay /glass, paper, and food Industries.
Question #30: Also under these assumptions, what technologies could, alone
or in conjunction with other technologies, achieve the
quickest reductions in emissions?
Answer #3G: In practical terms, advanced coal technologies offer the
quickest reductions in emissions if they are capable of retrofit
to existing coal combustion processes. In the U.S.,
approximately 6A% of man-made SO^, and 28% of man-made NO^
emissions are from coal-fired powerplants. Industrial coal
combustion accounts for another 7% and 2% of these pollutants,
respectively. Of the technologies Identlfed above, advanced
coal preparation probably offers the fastest reductions in
emissions because of the stage of development of the technology,
and the comparatively short lead time required to construct
preparation facilities. Other near-term technologies which
could be retrofitted include dry discharge FGD, LIMB, and AFBC.
Question //3H: How long would it take to achieve the overall emission
reduction potential of commercializing clean coal
technologies?
388
Answer //3H: Retrofit of existing stationary source emitters of SO- and NO
2 X
would likely require 5 to 10 years after demonstration of the
requisite technologies, if a program Is designed to achieve
major reductions (over 50%) In emissions. However, the ultimate
potential emission reductions of advanced coal teclinologles will
not be realized until existing equipment is retired and/or
replaced by new equipment Incorporating advanced technology
designs, like IGCC or PFBC. This ultimate achievement will not
take place before the year 20A0, an estimate based upon the
anticipated remaining useful lives of equipment now in
operation, unless currently operational equipment is forced to
retire early.
389
Attachment
EMERGING COAL TECHNOLOGY
MARKET APPLICATIONS
Flue Gas Cleanup Technologies
The potential markets for these technologies will be primarily large
Industrial and utility coal-fired boilers for both new and retrofit
applications. Some of the technologies, like the E-beams being developed by
DOE, are being designed for new utility boilers to meet the Federal New
Source Performance Standards more economically than conventional SO-
scrubbers. The LIMB technology, on the other hand, may be better suited as a
retrofit technology in the event acid rain controls beyond currently existing
SO^/NO emission restrictions are imposed in the future.
2 X
Advanced Combustors
The potential markets are expected to be for large Industrial and utility
boilers in new coal-fired applications and as a retrofit coal-based systems
for large boilers now using oil or natural gas. DOE's research program is
also addressing the use of advanced combustors for light industrial,
commercial and residential applications.
Fluldized Bed Combustors (FBC)
Both Atmospheric and Pressurized FBC are suited for new coal-fired utility
applications as well as for the repowering of oil and gas-fired utility
boilers. AFBC is being used commercially in the large industrial boiler
market at this time. In addition, research is being conducted to develop
390
AFBC's for light Industrial, commercial and possibly residential
applications. PFB may also be desirable as a pollution control, capacity
boosting, technology for existing coal-fired powerplants.
Coal Preparation Technologies
Coal preparation technologies have potential application in all markets where
coal is used. In addition, prepared coal, either slurried with water or dry,
can provide the feedstock for a number of the advanced coal technologies
presently under development as well as a coal-based fuel substitute for oil.
Alternative Fuel
Coal water mixtures have the potential to be used in a wide variety of
markets where coal, oil and possibly natural gas now dominate. These include
the electric utility, industrial, commercial, residential and heat engines
markets.
Gas Stream Cleanup Technologies
These technologies are being developed to enable the cleaning of hot gases
from some of the emerging coal technologies to improve their economic and
environmental performance. Such technologies will be used with surface coal
gasification, fuel cells using coal, pressurized fluldized bed combustors and
direct fired turbines.
391
Coal Gasification Technologies
Coal gasification technologies are being used and will potentially be used
for a wide variety of market applications, including in the production of
industrial fuel gas (low and medium Btu gas), as a component of combined
cycle units for utility applications, in the production of feedstock used in
turn to produce chemical feedstocks and methanol, and, in the production of
high Btu gas for direct substitution for natural gas in applications ranging
from utility fuel to residential uses.
Fuel Cell Technologies
Fuel cell powerplants are expected to see their earliest applications using
natural gas or distillate fuels in electric utility power generation and
primarily for peaking power. Later, fuel cell plants operating on coal could
expand the potential market to base load power generation and, even later,
into the industrial sectors.
Fuel cells may also be utilized in the residential and commercial sectors,
very likely using natural gas as the fuel.
Heat Engines Technologies
Gas turbine technologies are currently used by utilities and industry for new
peak power generation, combined cycle, and cogeneration applications. The
new coal-fired gas turbine technologies under development by DOE are aimed at
the same markets with the potential for expansion into intermediate and
possibly baseload power generation markets.
392
Coal-fired diesels can potentially be used In large systems currently using
dlesel fuel such as electric utilities, basic industries, railroads and
inland waterways and marine shipping interests.
Magnet ohydrodynamics
The MHD technology is targeted primarily at the baseload electric utility
market.
Coal Liquefaction
Coal liquefaction technologies can produce both clean solid and liquid fuels
from coal. As a result, coal derived liquids can be used as substitutes for
petroleum products in almost all of its applications.
393
QUESTIONS SUBMITTED BY CONGRESSMAN RICK BOUCHER
Question #4: The report of the Energy Research Advisory Board supports
demonstration projects for clean coal technologies for electric
utility retrofit applications.
Specifically, what would be the emission reduction potential of
retrofitting electric utilities with clean coal technologies in
terms of extent and timing of reductions?
Answer: It would be extremely cost-ineffective to retrofit all existing
emitters of SO. and NO . This fact has been recognized by the
various legislative proposals to control acid rain precursors and
has resulted in different approaches to additional controls on
those sources that are or will be least expensive to control. If
one such approach were selected and one assumed all existing
powerplants with S0„ emissions exceeding rates allowed by New
Source Performance Standards (1.2 //S0„/mmBtu) were retrofitted with
an advanced technology capable of removing 90% of S0_ and NO , then
1980 emission levels could be reduced by 13 million tons per year
of SO- and 3 million tons per year of NO . Such technologies are
expected to be mature by the early 1990's, which means they could
be used in large numbers by the late 1990's. Less ambitious
reduction programs could be achieved sooner using advanced coal
preparation technologies.
394
QUESTIONS SUBMITTED BY CONGRESSMAN RICK BOUCHER
Question #5: Projections by the Energy Information Administration Indicate
that Industrial use of coal, especially by Industries with
large, continuously operating boilers, is expected to increase
substantially in the future. A recent report by the Office of
Technology Assessment predicts that industrial emissions will
be a significant portion of the total growth in emissions in
the coming years-
Question ?/5A: Specifically, which industries have the particular need to
develop clean coal technologies for expanded coal use or for
compliance with Clean Air Act regulations?
Answer //5A: Compliance with current Clean Air Act requirements is generally
not a driving force for the use of advanced coal technologies.
Only the State of California, with its unusual air quality
^ problems, has regulations so stringent that conventional coal
technologies cannot be used. Given today's general regulatory
environment, then, the need for advanced coal technologies is
derived primarily from the need for expanded use of coal to
replace oil and natural gas as fuels, anticipated over the next
few decades. Since coal is less than one-half the price of oil
or gas (per Btu), the current expanded coal use capitalizes on
an economic market advantage of U.S. -based industry. Most
Industries which use large amounts of energy can benefit,
economically as well as environmentally from clean coal
technologies.
Question #5B: What kinds of technologies are most appropriate for industrial
applications?
Answer #5B: Atmospheric Fluidized Bed Combustion technology Is already
considered commercial for industrial sized units. Other
attractive technologies include advanced combustors, which may
allow burning of coal in boilers designed for oil, advanced coal
preparation, coal-fired turbines and diesels, coal gasification
395
(with and without hot gas cleanup), and coal/liquid mixture
fuels. The technologies that allow direct reduction of iron by
coal (without the use of coke) could possibly lend a competitive
edge to U.S. manufacturers, since the direct pr.j ess uses a much
less expensive grade of coal. In the final analysis, however,
the market will strike an appropriate balance between advanced
and conventional technologies and other alternatives such as
conservation.
Question #5C: How could new EPA regulations concerning "tall stacks" affect
this need?
Answer #5C: DOE has not evaluated the effect on the industrial sector of
EPA's proposed regulation of tall stacks. EPA's published
impact analysis for the proposed regulations is only three
paragraphs long and considers only powerplants. It is
reasonable to assume that the proposal, if implemented, would
require additional reductions of SO from industrial sources.
Depending on the schedule of new requirements, advanced coal
technologies might facilitate compliance.
Question #5D: What industrial efforts are currently underway to meet these
needs?
Answer //5D: There are substantial industrial technology development
activities sponsored by industry or by equipment vendors now
under way. Coal technologies involved in such private sector
research include advanced combustors, advanced coal preparation,
coal/liquid mixtures, and direct iron reduction.
396
QUESTIONS FOR SECRETARY VAUGHAN
Question #1: In your testimony, you indicate that several of the emerging
technological options addressed in the submissions are
currently being developed at near-commercial or
commercial-scale without federal money. I would like to know
which of these technologies are at this stage of development.
Answer: A large number of emerging coal technologies are at the point of
. demonstration and/or commercial operations. Summary information on
those activities categorized by technology is provided below.
397
Sununary of Attachments
Emerging Coal Technologies
Commercial Activities
Flue Gas Cleanup
(1) Aqueous carbonate-regenerable flue gas desulf ur ization unit.
A 100 MW demonstration at Niagara-Mohawk, New York, was down
early in 1985 because of problems. Rockwell International
was the process developer. Sponsors were ESEERCO (Empire
State Electrical Research Co.), NY ERDA, EPA and DOE.
(2) Limestone Injection Multistage Burner Projects
o A 300 MW lignite fired boiler was retrofitted and tested
in Canada.
o Currently, 6 boilers, ranging in size from 20 to 330 MW,
are operational in Austria, using Austrian brown coals.
o Two boilers totaling 100 MW are undergoing shakedown
tests in Germany. Plans are to retrofit an additional
16 boilers, totaling 2,600 MW with LIMB systems within
the next two years.
o In France, sorbent injection tests were performed on a
50 MW boiler using a variety of sorbents.
Coal Preparation
(1) Electrostatic separation. A 10 ton per hour unit is being
tested at American Electric Power Picway Station in Columbus,
Ohio.
(2) True heavy liquid cyclones. A several tons of coal per day
demonstration unit is planned by American Electric Power
Company.
Atmospheric Fluidized Bed Combustion
(1) Utility Applications
o A 160 MWe "grass roots" power plant located in Paducah,
Kentucky, is scheduled for operation in the late 1980's.
TVA, Duke Power, EPRI and the State of Kentucky are
among the projects' sponsors.
398
o A 125 MWe retrofit to a Northern States Power Company
plant is under construction in Burnsville, Minnesota
by Northern States Power. Operation is scheduled for
mid-1986.
o A 100 MWe "grass roots" circulating bed, scheduled for
operation in late 1987 is planned by Colorado.
(2) Industrial Applications
Eighteen U.S. boiler manufacturers are offering commercial
units for industrial boiler applications. A partial list-
ing of the more than 100 commercial industrial AFB ' s
located in the U.S. is provided in Attachment 1 (taken
from Power Magazine - February 1985).
Pressurized Fluidized Bed Combustion
(1) The City of Stockholm, Sweden is proceeding with the retro-
fit of a cogeneration plant in Stockholm which will produce
235 MW heat and generate 133 MW electricity, using 2 coal-
fired PFBC modules. The PFB modules will be supplied by
ASEA-PFB, Sweden (formally Stal-Laval), and will be com-
missioned in 1989.
(2) Demonstrations under consideration include:
o Deutche Babcock
Designing a 335 MW PFB combined cycle power plant for
proposed demonstration in Germany in the early 1990s.
The output from the proposed utility demonstration
plant would consist of 75 MW from the gas turbine
and 260 MW from the steam turbine.
o Florida Power and Light Company teamed with Babcock and
Wilcox and the General Electric Company are investiga-
ting the feasibility of demonstrating a 80-100 MWe
turbocharged PFB module at Florida Power and Light's
Palatka, Florida, station.
o The American Electric Power Company, Stal-Laval and
Deutche Babcock are investigating the feasibility of
demonstrating a 70 MW combined cycle demonstration
plant at AEP's Tidd Station near Brillant, Ohio.
399
Advanced Combustors
(1) TRW is planning to demonstrate a 50 million Btu/hr slagging
combustor system in their Cleveland Airport Components Group
Plant in a coal designed boiler.
(2) Rocketdyne is working with a group of utilities in an effort
to demonstrate their combustor.
Alternative Fuels
Considerable private sector activity both domestically and inter
nationally is underway in the marketing of coal-water mixtures.
Attachment 2 provides summary information on many of those
activities.
Surface Coal Gasification
A considerable amount of commercial activity in demonstrating
gasification processes and utilizing them in commercial appli-
cations has occurred. Attachment 3 provides summary informa-
tion on many of those activities.
Phosphoric Acid Fuel Cells
(1) Two 4.8 MW electric utility preprototype power plants. A
project initiated in 1976, sponsored by UTC, DOE, EPRI and e
utility consortium led by Consolidated Edison resulted in tl
installation and checkout of a 4.8 MW (4.5 MW AC) phosphoric
acid fuel cell power plant in New York City. The plant was
inactivated without operating due to damage to the cell
stacks during storage.
A second similar 4 . 8 MW power plant was purchased from UTC
by the Tokyo Electric Power Company and has been installed
and is operating in Goi, Japan.
(2) Field Test of 40 kW power plants. A field test of 43 40 kW
UTC power plants was initiated by DOE and GRI with 36 com-
panies participating by hosting test sites. The units pro-
duce coproduct heat for use at the test site in addition to
40 kW of electricity. Over 120,000 hours of operation have
been achieved to date. Thirty-five power plants are in-
stalled and the final plants are expected to begin oper-
ation in June 1985. A list of the sites is provided in
Attachment 4.
400
(3) Formation of International Fuel Cells Corporation, On
April 8, 1985, International Fuel Cells Corporation was
formed to develop, manufacture and sell fuel cells world-
wide. The Corporation is a U.S. company in which United
Technologies Corporation and Toshiba Corporation each own
50 percent of the corporate stock. Commercial orders for
power plants are expected in 1985 with earliest deliveries
in 1989.
401
Power Magazine Feb. 1985
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410
Attachment 3 Cont'd
LIST OF FOREIGN COAL GASIFICATION FACILITIES*
♦List contains facilities which are currently
operating or which have been shut down for
less than five years
411
LIST OF FOREIGN COAL GASIFICATION FACILITIES
Lecatlofi
Caatrtar
h Nuabar
Oataa
Coal Typa
rro<)uct Caa
(Application)
Capacltr
iwr Unit
lulKarla
Dlaltroffsrad
Wlnklac
4
19SI to
fraaant
HedliM-Bttt
16.1 HHSCFD
Stara Zagor*
Vlnktar
5
1962 to
fraaant
MedluB-Btu
27 HHSCFO
C'choalovakla
Chowitov
Wocxlall*
Duckhao
14
f to
Ltgnlta
Low-ttM
(Hetal WorVa)
Approx.
2 MKSCrO
Caat Caraanr
Schwaraa fuapa Lurcl
tctiwarca fuapa Vlnklar
Sohlan
tohlan
ZaItB
Vlnklar
3
Lurgl
10
Wlnklar
1
Karl-IUrm Stadc Koppara*
Totaak
1966 to
19B0
19S0 to
fraaant
1938 to
fraaant
tlcnlta
Llgnlta
Ltgnlta/Coka
1960/6)** Llgntta
to T
Hedlua-BtU
(Tovn Caa)
LowBta
8*ngaa
(lljorogen)
Hedlua-Bty
(Town Caa)
19<il to
fraaant
1966 to
fraaant
Llgiilta
on Realdua
(Coka)
Syitcaa
(fl
jrdrogen)
Syngaa
(Auonla)
26 mBcro
SB rttSCFD
27 HHSCFO
Approa.
Z.i HKSCrV
20 HHSCFO
11.4 HI1SCFU
Weat Ccraany
t4Moan
Lurgl
1969/70
to 1979
Subbltua.
Low-Btu
(Uat Turblna)
Great Britain
Uaatflald
Lurgl
1960/62
to 1974
BItua./
Subbltua.
Mc<llua-Btu
(Town Caa)
Craaco
ftolaaala
Koppara-
Totaak
19S9/69/
10 to
fraaant
Llgnlta
Syngaa
(AMonla)
Ai>|iroii.
6s fiMScru
9 (IMSCFD
6 to 9
IMSCFO
412
LIST OF FOREIGN COAL GASIFICATION FACILITIES
Location
India
t
Raaagundaa
Korba
Talchar
Jaalgora
Aaanaol
Hadraa
CatirUr
Typa
fc Nuabar
WelUan-
Calusha
ft
Coppcra-
Tottak
(« headad)
)
Koppera-
Totiak
(4 headed)
Kopparf
Tottek
(4 headed)
3
Uirgl
I
tllay-
Horgan
2
VInklar
3
Pataa Coal Typa
1980 to
Praaant
I972*
Com t ruc-
tion Cloea
to Coapta-
tion
1980 to
Fraaent
1961 to
Praacnt
I9S2/U
to
Prcacnt
1961 to
1979
Varloua
■Itua.
Lignite
(now oil)
Product Caa
(At)pl Icat Ion)
Syngaa
(Aaaonla)
Syngaa
(Aaaonla)
Syngaa
{Ammolilm}
Capacity
per Unit
19 rMscro
19 NHSCFU
19 mscrp
Syngaa
(Aaaonla)
17.8 HHSCFO
Portugal
Llabon
Koppars-
Toctak
I9S6 to Lignica/
Praacnt Antliraclta
Syngas
(Aaaonla)
Approx.
4 MMSCFl)
South Africa
Saaolbura
(Saaol 1)
Lural
1?
I9i4/S8/ SubbltuB.
66/71/80
to Praaant
Syngas
(Liquid llydro-
carbona) ,
AMonIa, Fuel
Caa
3) MHSCFO
to 100
Sacunda
(Saaol 11)
U.r^l
1979/80
to
Praacnt
Subbltua.
Syngas
(Liquid Hydro-
carbons)
31 IIHSCFD
Ho<J<Jerrontalo
(Juliannasburg)
Koppara-
Tuttak
*
1974 to
Present
iltua.
Syngaa
(Aaaonla)
Anproa .
14 WISCFU
Vaal Pottarl
las
Wellaan-
Caluaha
1
I9SS tu
Praaant
Low-ttu
(Furnace)
Union Scaal
Wallaan-
Csluaha
7
19il to
Praaant
LoH-8tu
(Natal Uorka)
Wcllaan-
Calusha
1
1949 to
Present
Luw-Itu
(•rIck-KIln)
413
LIST OF FOREIGN COAL GASIFICATION FACILITIES
tocat Ion
Caalflor
Typ.
& Nu>bar
Data*
South Africa
(Cont'd)
Scaw Hatala
Vcliaan-
Caluaha
1
I9SS to
Praaont
Lytleiibors
Stole
1
1974 to
Praaant
Orlafontain
Stole
1
1971 to
Praaant
Pratorla
Riley
Itorean
1913/41
to
Prcicnt
Dundaa
Rllay
horsan
1950 to
Preaant
Springs
Voodall-
Duckhaa
2
T to
Praaant
Hayartun
Voodall*
Duckhaa
1
T to
Johanneaburg
Voodall-
Duckhaa
2
T to
Praaant
Stewart* b
Lloyda
Voodall-
Duckhaa
T to
Cacault
Uoodall-
Duckltaa
i
t to
Preaant
Handial
Woodall-
Duckhaa
2
T tu
Praaant
Orlcfontaln
Woodall-
buckhaa
2
T to
Varaanlgnlf^
Woodall-
Duckhaa
3
Y to
Stewart* fc
Lloyda
Wcllaan-
IncanUaacant
T to
Praauot
Cull lna«
Wallaan-
liicandaacant
4
I964/6S/
73 to
Scaw HataU
Wallaan-
Incandeacaiit
i
I961/6B/
75 to
Praaant
JoliannesUiig
UalUan-
Incandeacant
*
1961/48/
75 to
Alyaaf
Wcllaan-
Incandeacant
4
I97B to
Praaant
lua.
t«MI.
tua.
tua.
tua.
tua
tua.
Prcxluct Ca*
(Application)
Low-Rtu
(Nfttal Work*)
Lov-Rtu
(Hetal Worka)
Low-Rtu
(Brick Clin)
Low-Rtu
(Heeal Works)
LowRtu
(Ctais Work*)
LowRtu
Low-Rtu
(Furnace)
Low-Rtu
(Steel Work*)
Low-Rtu
(Steal Work*)
Low-Rtu
(Furnace)
Low-Rtu
Ca|>nclty
pir Unit
tua.
Low-Rtu
(Refractory
Worka)
LowRtu
(Steel Worka)
Low-Rtu (T)
(Refractory
Worka)
Low-Rtu (T)
(Steel Work*)
Low-Rtu (T)
(Metal a Worka)
Low-Rtu (T)
(Ht:tal Wurka)
Approi.
2 HTISCFD
Approi.
2 l>ISCFV
414
LIST OF FOREIGN COAL GASIFICATION FACILITIES
Location
Caairior
L Nuaber
Dataa
Coal Trp*
Product Caa
(Appllcat Ion)
Capacity
per Unit
South All
lea
(Cont'd)
Crootroncaln
Vallaan-
Incandcacant
1
1970 to
Praaant
■Itua.
Low-Btu (T)
(Metal Worka)
South Crota
Staal
Vcllaan-
Incandaaccnt
' 4
1968/76/
BO to
Praaant
■Itua.
Low-ttu (T)
(Steel Worka)
lllehvald
Stai
>l Wallaan-
Incandaacant
4
1968/74
to
•ItUB.
Low-8tu (T)
(Steel Uorka)
USCO
WelUan-
Incandeacant
197] to
Praaant
•Itua.
Lov-Btu (T)
(Steel Worka)
Salccor
Ucllsan-
tncandeacant
197) to
Praaent
■Itua.
Low-Itu (T)
(Paper Worka)
Union Steal
Veliaan-
Incandeicant
i
I96S/48
to
Lo»-8tu (T)
(Steel Worka)
ConioUdi
Claaa
itad
UclUan-
IncanJeiccnt
1967 to
Praacnt
Lvw-Rtu (1)
(Claai Worki)
Thailand
Laapans
Koppera-
Totxck
S
1961/66
to
LIgnlta
Syngaa
(Aa«onla)
Appro! .
to f»tSCFD
Turhey
Kutahya
Koppora-
Totiak
4
1966 to
Praaant
Llsnlta
Synjjaa
(Aaaonla)
Approa.
9 HIISCFD
KuLahya
WlnkUr
2
I9S9 to
Praaant
Llcnlta
Synijaa
(Auonla)
Approa.
9 HMStFD
latanUil
Woodall-
Duckhaa
1
1
LIgnlta
U.S.S.R.
Salawad
Wlnklar
7
I9S0 to
Praaant
Hadlua-Itu
31 fttUiCrO
■aachklrl
•■
WlnkUr
4
I9&0 to
Praaent
HedluB-8tu
57 mscfo
415
LIST OF FOREIGN COAL GASIFICATION FACILITIES
tocatlon
CaalfUr
Typa
I Nuabar
Ontea
Coal Tyi»a
Prduct Caa
(Api>llcatlo<i)
Capacity
|ier Unit
Yueoilavia
Jandlnjanja
WallAan>
Valuaha
1
Coratda
Ulnklar
1
19S2 to
Praaant
Subbltua.
Syncae
(Aaaonla)
6. J mSCFD
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423
POST-HEARING QUESTIONS AND ANSWERS
RELATED TO THE
MAY 8, 1985 HEARING
BEFORE THE
SUBCOMMITTEE ON ENERGY DEVELOPMENT AND APPLICATIONS
HOUSE SCIENCE AND TECHNOLOGY COMMITTEE
U.S. HOUSE OF REPRESENTATIVES
WITNESS: ASSISTANT SECRETARY VAUGHAN
424
Questions for Secretary Vaughan:
1. In your testimony, you indicate that several of the emerging
technological options addressed in the submissions are
currently being developed at near-commercial or
commercial-scale without federal money.
I would like to know which of these technologies are
at this stage of development.
2. Before Congress does address the Clean Coal Initiative in
a legislative context (i.e. consider legislation to
appropriate funds for demonstrating these initiatives),
I would like to say I share your concern over the
interpretation of private sector "cost-sharing".
I think it is only fair that the private sector be
committed to sharing in all future costs (not counting
their previous R&D efforts toward their contribution).
Also, private sector contributions should be in the
form of money. Donation of a facility is not sharing
in the risk.
If demonstration projects are in fact brought on line in
the near future, and if these facilities produce a
product as well as offer a source for data collection,
can DOE negotiate agreements that the private partner
pay back the federal government for its share of assistance
since the technology will be making money for the private
entity?
425
QUESTIONS FOR SECRETARY VAUGHAN
Question #2: Before Congress does address the Clean Coal Initiative in a
legislative context (i.e., consider legislation to appropriate
funds for demonstrating these initiatives), I would like to say
I share your concern over the interpretation of prlvata sector
"cost-sharing". I think It is only fair that the private
sector be committed to sharing in all future costs (not
counting their previous R&D efforts toward their contribution).
Also, private sector contributions should be in the form of
money. Donation of a facility is not sharing in the risk.
Answer: The Department of Energy fully endorses the concept of upfront and
significant (greater than 50%) cost-sharing in the form of cash
from day one of a demonstration project.
426
QUESTIONS FOR SECRETARY VAUGHAN
Question #3: If demonstration projects are in fact brought on line in the
near future, and if these facilities produce a product as well
as offer a source for data collection, can DOE negotiate
agreements that the private partner pay back the federal
government for its share of assistance since the technology
will be making money for the private entity?
Answer: Repayment provisions can be stipulated in Government contracts.
However, such provisions should not replace the requirement for
significant upfront cost-sharing by the private sector in
demonstration projects. Since repayment is never guaranteed and
since it, in any event will likely occur many years into the
future, should it occur at all, it cannot substitute for cost
shari ng.
Nonetheless, we agree that repayment clauses in addition to cost
sharing are a logical and desirable component as applied R&D, even
at stages somewhat earlier than demonstrations.
427
QUESTIONS
U.S. DEPART^€NT OF ENERGY'S REPORT ON EMERGING CLEAN COAL TECHNOLOGIES
May 8, 1985
MEj. Vaughan
1. There has been mention of using the National Coal Council In the
Emerging Clean Coal Technologies Initiative. Please expand on
this possibility. Please characterize that group as to
occupations, coal Industry experience, availability, and
geographical representation.
2. In DOE'S Emerging Clean Coal Technologies Report's assessment of
alternative fuels, the potential for significant oil displacement
by coal water mixtures Is examined. The Report anticipates that
the highest displacement will occur at the higher-risk end of the
technology spectrum. Including heat engine applications. The
assessment concludes that this area "Is prime for Federal stimuli
and one for which DOE's program Is focused.
Please address how DOE Is and Intends to focus on stimulating
research and development of the application of coal water slurries
to heat engines.
3. Please respond to the statement In ERAB's report that, "Acceptance
of coal water slurry by the utility Industry will require further
extended large scale combustion tests. The private sector seems
to be ready to pursue this subject; however, the high cost of
large-scale tests will require substantial DOE assistance."
4. ERAB's report recommends that DOE Increase Its efforts to co-fund
programs aimed at waste utilization rather than disposal. How
does DOE plan to respond to this recommendation?
5. Would It be within the Administration's definition of the "proper"
federal R&D role for DOE to fund a test program In which the
various coal locomotive concepts are demonstrated and compared In
conjunction with the private sector to allow the private sector to
pick the concepts most commercially feasible? Please respond to
the points discussed In the following background.
Background Such a program would fulfill Congressional and other
requests for federal financial support of a coal locomotive
prototype while minimizing the federal role In choosing between
technologies. Such a program could be operated on a cost-shared
basis with the combustion system manufacturers as well as with
other Interested private sector parties. Concepts suitable for
such a program Include, but are not limited to: AFB, coal-water
mixture, pulverized coal, producer gas, coal-fired diesels and
coal-gas turbines.
6. What Is DOE's opinion on the comparative applicability of these
concepts to locomotive use?
428
What are your views of the technical and International merits of
the Joint U.S. - China development of a new coal -fired steam
locomotive? Please respond to the points discussed In the
following background.
Background This concept Is based on the competitive evaluation of
applicable clean-combustion technologies In an existing Chinese
production steam locomotive. Such a concept appears to have three
significant advantages. First, It will Introduce a commercially
feasible, environmentally acceptable new coal-based locomotive to
American railroads In the shortest possible time. Secondly, It Is
not locked Into a specific coal combustion technology, but will
promote Joint coal -combustion technology development between the
United States and China.
429
. ' Questions from Congressman Rick Boucher
1) The appropriateness of clean coal technologies vary widely according to
numerous factors including characteristics of the fuel, the age and size of the
facility, and the emission reduction goal. Therefore, no one proposal could
be expected to present the single technology for all purposes.
Would It be the intention of DOE to develop as wide a range of technologies
as possible?
Would an integrative approach be taken whereby those technologies would be
developed that could be Joined together in different ways, for example coal
cleaning with limestone injection multi-stage burners (LIMB), to achieve
overall emmlssion reduction targets?
Specifically, what are the kinds of technologies with the greatest
potential for Integration with other kinds of technologies and for what
kinds of applications?
2) The new report by DOE on the reserve states that DOE'; previous experience
with federal incentives have "with few, if any exceptions been unsuccessful in
commercializing new fossil technologies." Federal support for energy
technologies, however, have been apparently successful in a number of areas.
Atmospheric fluidlzed bed technologies are now being commercialized. U.S.
research and development on heat pumps and photovoltalcs has been adapted and
commercialized by the Japanese. Wall-fired LIMB technology has been
successfully demonstrated by EPA with potential application to A0% of the
utll ity market.
What has been the role of the federal government or other governments in
the development and commercialization of these technologies?
Are there other examples of successful government demonstration and
commercialization of energy technologies in this country or by other
countries using either their own research and development or R4D results
obtained by U.S. efforts?
3) Report language relating to the reserve clearly states that the purpose of
clean coal technologies is "for using coal in electric utility and large
industrial applications that reduce sulfur and other emissions resulting from
such uses to levels that are required, or may be required, for compliance with
the Clean Air Act, as amended (P.L. 98-473, Senate Energy and Natural Resources
report 98-57 8)."
Given the limited amount of funds available for coal research and
development and the desire to develop the widest range of clean coal
technologies possible, would DOE try to emphasis proposals with the
greatest potential yield in terms of market application and emission
reductions?
Specifically, what technologies, if successfully demonstrated, would have
the quickest market applications?
How long would market commercialization take for these technologies?
Specifically, what technologies If successfully demonstrated, would have
the widest market applications?
430
To what extent could these technologies be expected to penetrate those
markets?
Under these assumptlonst what would be the overall emission reduction
potential by kind of pollutant and economic activity of commercializing
clean coal technologies?
Also under these assumptions^ what technologies could* alone or In
conjunction with other technologies* achieve the quickest reductions In
emissions^
How long would It take to achieve the overall emission reduction potential
of commercializing clean coal technologies?
4) The report of the Enorgy Research Advisory Board supports demonstration
projects for clean coal technologies for electric utility retrofit
appl Icatlons.
Specifically* what would be the emission reduction potential of
retrofitting electric utilities with clean coal technologies In terms of
extent and timing of reductions?
5) Projections by the Energy Information Administration Indicate that
industrial use of coal* especially by industries with large* continuously
operating boilers* is expected to Increase substantially In the future. A
recent reporc by the Office of Technology Assessment predicts that industrial
emissions will be a significant portion of the total growth in emissions in the
coming years.
Specifically* which Industries have the particular need to develop clean
coal technologies for expanded coal use or for compliance with Clean Air
Act regulations?
What kinds of technologies are most appropriate for Industrial
applications?
How could new EPA regulations concerning "tall stacks" affect this need?
What industrial efforts are currently underway to meet these needs?
431
EPRI
Electric Power
Research Institute
July 1 , 1985 R ^ C F ' ' ' ^ ' '
Mr. Don Fuqua
Chairman
U.S. House of Representatives
Committee on Science and Technology
Suite 2321
Rayburn House Office Building
Washington, DC 20515
Dear Mr . Fuqua :
Attached please find responses to questions transmitted
in your letter of May 21, 1985 to Dr. Mannella. These
supplement his May 8, 1985 testimony before the Sub-
committee on Energy Development and Applications. I
appreciate your and Mr. Harvey's patience in awaiting
this response during my recent overseas travel schedule.
I am also attaching a copy of a recent briefing I gave to
Senate staff concerning the Clean Coal Initiative. Some
of the graphs and tables may be of interest to you and
your staff.
Please contact me if I can be of further assistance.
Sincerely,
Kurt
Vice President
Coal Combustion Systems Division
KEY : vbe
Attachments
cc: W. T. Harvey
3412 Hillview Avenue. Post Office Box 10412, Palo Alto. CA 94303 Telephone (415) 855-2000
Washington Office: 1800 Massachuserfs Ave , NW. Suite 700. Wasfimgton. DC 20036 (202) 872-9222
432
Question 1 :
When will the Paducah atmospheric fluidized bed combustion
boiler construction be completed? Upon completion, what
amount of operating experience will be necessary to convince
the utility industry that the technology is ready for use?
Construction of the 160 MW atmospheric fluidized bed (AFB) demon-
stration at Paducah, Kentucky by EPRI, TVA, Duke Power, and the
State of Kentucky will be completed in 1988. A basic test pro-
gram of four years duration is planned. The first two years will
focus on the factors needed to confidently design and operate the
AFB technology across the electric utility industry. These in-
clude confirmation of heat transfer performance, plant control-
ability and safety, carbon utilization and emission control
efficiency, operator-training, system design integrity and po-
tential for scale-up in unit size. Thus, by 1990 confirmation
of a confident design base for the utility industry and its
suppliers should be available to reinforce the results of the
current on-going 20 MW AFB prototype test program also at
Paducah. The second two years will concentrate on testing alter-
native fuels and sorbents as well as determining the limits of
off-design operating conditions and load change characteristics.
Following this basic performance test program, the demonstration
power plant will be operated for at least an additional six years
to monitor long-term component reliability and performance.
It should be noted that two additional large scale commercial
applications of AFB technology are currently proceeding under
private sector funding. These are the 125 MW Northern States
Power AFB conversion and the 110 MW Colorado-Ute circulating
AFBC repowering project. These projects will also include ex-
tensive demonstration testing to both complement the TVA demon-
stration and provide a broader range of design and operating
conditions. In addition, a variety of AFB units in the 20 MW
to 150 MW scale are being commercially implemented today as
cogeneration projects with the electric utility industry or as
repowering projects in electric utility plants.
Question 2:
What balance of funds in the DOE coal program would you suggest
for the various ranks of coal in the United States? Bituminous,
subbituminous, lignite?
The balance of funds among coal types depends heavily on the
objective of the prgram being considered. The present DOE coal
program, for example, focuses on "long range/high risk" tech-
nology development. Here a relatively even balance between
bituminous and lower rark coals might be appropriate since
coal production is shifting toward the lower sulfur, lower rank.
Western coal where our knowledge base is relatively limited.
433
Also, many of the more advanced coal utilization technologies
are less sensitive to coal type and thus would be more gene-
rally applicable to all ranks of coal.
In a program with more immediate demonstration and commerci-
alization objectives, however, the funding balance might be
more heavily weighted toward the bituminous rank of coal.
The approximate production split among the three coal ranks
today and their relative sulfur content may be summarized as
follows :
Production Greater
( 106 Tons) Than 1% S
Bituminous 640 70%
Subbituminous 200 1%
Lignite 50 10%
890
In this regard, the type of technology being considered can also
have a significant bearing. For example, coal cleaning tech-
nology may be quite different, dependent on the composition of
the coal. Cleaning of bituminous coal will emphasize removal
of ash and pyritic sulfur. Cleaning of lower rank coals, on
the other hand, will emphasize coal drying methods plus removal
of alkaline compounds affecting ash melting temperature. In
comparison, fluid bed combustion, and to a lesser degree, coal
conversion and flue gas scrubbing technology will be less depen-
dent on coal rank or composition. Balancing of program funds
according to coal rank must therefore consider these technology
circumstances .
The following general balance by technology category is there-
fore indicated.
Bituminous Subbituminous Lignite
Coal Cleaning
50
35
15
Flue Gas Cleani
FBC
IGCC
Combustion
ng
60
33
50
50
20
33
35
35
20
33
15
15
Technology
Average
50"
30
20
Considering both utilization and technology suggests the follow-
ing near-term balance of funds by coal type:
Bituminous 50-70%
Subbituminous 30-20%
Lignite 20-10%
434
Question 3:
What is the latest forecast in the utility industry on annual
coal requirements in the year 2000, compared to the amount
consumed by the industry in 1984?
In 1984 the electric utility industry consumed 664 million tons
of coal to produce 1,342 billion kWh of electricity. This repre-
sents 85% of total U.S. coal consumption and 56% of U.S. elec-
tricity prod.uction. Based on a 2.5% per year industry projection
of electricity demand growth, coal is expected to produce 2,100-
2,300 billion kWh of electricity by the year 2000. This repre-
sents 58-63% of the forecast total U.S. electricity production
at the end of the century. This, in turn, requires a growth in
electric utility coal consumption to 1.0-1.1 billion tons per
year.
The coal-fired electricity production in 1984 was achieved by
260,000 MWg of generating capacity. By the year 2000, at least
an additional 130,000-175,000 MW^ of new coal-fired generated
capacity will be required to provide this forecast demand growth,
assuming successful improvements in the availability of existing
capacity.
Question 4:
What work has been performed to determine the relationship be-
tween degrees of cleaned coal and resulting boiler life, oper-
ating efficiency, and/or availability? What work is being done
now on the relationship?
EPRI has initiated a major R&D effort to quantify the effects of
coal quality on power plant performance. This effort involves:
development of new, more effective measures of coal quality;
cleaning of major steam coals in a controlled manner to provide
combustion test coal samples with known mineral matter compo-
sition changes; pilot scale (3.5 million Btu/hr) combustion test-
ing; and development of new diagnostic technology for direct,
accurate measurement of phenomena occurring in full scale utility
furnaces . To provide a methodology for predicting how coal
quality changes will effect power plant generation costs, a pro-
ject to develop a coal quality impact model has been started.
This model is being based on a state-of-the-art survey of coal
quality effects completed in 1984. Combustion testing completed
or in progress includes:
o Illinois No. 6 coal in a joint project with a
utility. Currently, this effort involves full
scale tests on a 600 MW unit.
o Kentucky No. 9 coal.
435
o An Eastern Canadian coal (joint project with
a Canadian Federal government).
Despite R&D underway, development of accurate techniques and
data bases for predicting coal quality effects will take con-
siderable time and resources. Further, it will require develop-
ment of new analytical techniques (for both coal and combustion
measurements) and probably a new type of combustion research
furance(s). This will require an investment of at least $35
million over the next five years.
Question 5:
What work has been performed to determine the relationship
between clean coal cost and flue gas cleanup cost? It would
seem that cleaner, more expensive coal would require less ex-
pensive exhaust emission reduction. Please comment.
EPRI has used a case study approach to assess the impact of
coal cleaning on new coal-fired power plants, but has not
performed detailed analyses for the impact of combined coal
cleaning and FGD on existing power plants. Cost models that
will allow assessment of combined coal cleaning and FGD for
existing plants are, however, being developed. Analysis of
the existing plant situation is complicated because of: site
effects, particularly, on the cost of FGD retrofit; until
recently, lack of a good coal cleaning cost model; and,
limited coal cleanability data.
Table 1 summarizes results from the EPRI new power plant case
studies performed in 1980. This study considered seven coal-
fired power plant combinations supplied with coal at three
quality levels; Level A — 50 mm x 0 run-of-mine (uncleaned)
coal; Level B — partially cleaned coal; and. Level C — in-
tensively cleaned coal. Table 1 summarizes the cost differ-
ences between firing Level A coal, uncleaned coal, and coal
cleaned to Level C in new, 1000 MW power plants (twin 500 MW
units). All plants are specifically designed to fire the
specific coal supplied to them, either run-of-mine or clean
coal .
In Table 1 the first column under Annual Generation Levelized
Cost Savings, No Availability Increase, presents estimated
levelized (levelized over 30 years) annual cost differences
between plants firing run-of-mine and cleaned coal with assumed
equal availabilities. Cost differences in parenthesis are
negative values. The second column under Annual Generation
Levelized Cost Savings presents estimated cost differences
assuming that the plant firing clean coal realizes a 5-percent-
age point higher availability compared with the plant firing
uncleaned coal. The Investment Cost Savings column presents
estimated investment savings for plants firing clean coal. This
savings includes the cost of both the coal cleaning plant and
436
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437
the power plant. In five of the seven cases, the investment
required for the Level C coal cleaning option is less than for
the uncleaned coal option. For these cases, the investment
associated with coal cleaning was more than offset by savings
in power plant investment requirements .
Question 6:
The Cool Water, California, integrated gasification combined
cycle facility has operated at satisfactory rates since an
uneventful start last year — significant performance. From
this good beginning, how long will the facility need to operate
to convince the utility industry of its commercial application?
In EPRI's judgement, a minimum of 8000 hours of successful
operation will be required to achieve a confident basis for
commercial application decisions concerning integrated gasifi-
cation combined cycle (IGCC) . This will encompass the first
two years of the demonstration test program. The majority of
the operation during this period will be on Utah low-sulfur
bituminous coal with two months on Pittsburgh seam, eastern
high sulfur bituminous coal.
An additional three years of test operation is planned to
confirm equipment design and reliability. This is intended
to provide the necessary basis for proceeding with commercial
IGCC facilities at normal risk.
50-513 0—85 15
438
Mr. Sensenbrenner ' s Questions
Question 1:
In your testimony you seem to indicate that the system known
as Pressurized Fluidized Bed Combustion has many advantages
over other technologies, including the fact it is more
cost effective and more efficient. In addition to controll-
ing emissions, would you say that PFBC is the best demonstra-
tion project for the future and why?
PFBC has several advantages which make it a leading demon-
stration project for clean coal utilization. In addition to
improved emission control, PFBC provides a unique opportunity
for modular, transportable and quickly constructed power
plants which can be used either as stand alone units or to
repower existing plants- The result is both low unit capital
and busbar energy cost plus better ability to match demand
growth.
PFBC technology is maturing rapidly primarily through efforts
in Europe. As a result, several utilities, including Wis-
consin Electric Power Company (WEPCO) have proposed heavily cost
shared PFBC demonstration projects for immediate implementation.
EPRI strongly encourages the prompt implementation of PFBC demon-
strations based on the progress in AFBC and PFBC development,
bolstered by the active U.S. utility interest in PFBC. This step
is necessary to make the technology available for commercial use
by utilities in the 1990s when the demand for rapidly con-
structed, clean coal based, new generating capacity will be
substantial. \
Based on the performance attributes of PFBC, the quality and
cost sharing of proposed utility demonstrations, the manage-
able risks associated with the technology and its ability
to prevent a potential electricity "generation gap" in the
1990s, we place it at the top of our list of clean coal
technology demonstration requirements.
Question 2:
In your judgement, would the construction of one or more PFBC
units in the next few years be enough to demonstrate its commer-
cial viability?
Yes. This is based on our experience in the implementation
of three complementary AFBC utility demonstrations which cover
the range of design, fuels, and operating conditions faced by
that technology. These demonstrations serve as the culmin-
ation of an extensive 10 year development program in AFBC for
utility application. We believe a parallel PFBC program should
be promptly implemented and can achieve the same degree of
utility acceptance.
439
The PFBC demonstration program should therefore contain both
a turbocharged PFBC boiler to repower an existing power plant,
and a stand alone combined cycle PFBC installation. This
would demonstrate the two complementary applications of PFBC
power plant technology. In addition, it is recommended that
the program support a circulating PFBC prototype boiler as a
demonstration support facility.
As in the case of AFBC, this PFBC demonstration approach will
build on the development program which has been underway for
several years on PFBC boiler, turbine and hot gas cleanup
technology. It would also recoup the development capability
lost through the DOE aborted Curtiss-Wright PFBC pilot and
the role-back in DOE support for U.S. boiler manufacturer test-
ing at the Grimethorpe facility in the U.K. Finally, it would
assure a viable domestic PFBC supply capability.
Question 3;
What do you see as the prospect for PFBC if there is no federal
funding, and the utility industry has to go it alone?
Under current cost recovery restrictions, the regulated electric
utilities cannot underwrite the full cost of large, first-of-a-
kind, technology demonstrations. EPRl and the equipment sup-
pliers have been able to help close the gap but government finan-
ancial risk sharing is necessary if these demonstrations are to
proceed in a timely manner. Most recently, AFBC and gasification
- combined cycle demonstrations have been successfully imple-
mented in this joint manner.
Unless such risk sharing participation by government is extended
to PFBC, its availability to the electric utility industry will
be delayed by 5 to 10 years. It would thus be unavailable to
meet the major new electric generating capacity needs of the
1990s. Secondly, it would probably only be available then from
foreign developers and boiler suppliers with domestic sources
licensed from Europe. As such, it would place the hard pressed
U.S. boiler manufacturers in an increasing difficult competi-
tive position, make utilities dependent on foreign sources,
and represent an ultimately very expensive drain on U.S. tech-
nology for coal utilization.
Question 4:
You mentioned in your appendix that one project being proposed
is by Wisconsin Electric Power Company. I represent the
District in which Wisconsin Electric Power Company proposes
to construct the PFBC and I would like your appraisal of the
WEPCO proposal.
440
The WEPCO proposal represents a direct application of an EPRI
project evaluating alternative PFBC approaches. This EPRI pro-
ject identified the turbocharged PFBC power plant design as the
most cost effective, quickest to install, and least risk approach
to the comitiercial implementation of PFBC technology. This evalu-
ation effort concluded with preliminary engineering designs and
cost estimates.
EPRI is pleased to continue this technical and financial parti-
cipation in the on-going design phase of the proposed turbo-
charged PFBC demonstration to repower WEPCO 's Port Washington
Boiler No. 5. This directly translates the earlier, EPRI
supported, engineering design to WEPCO 's site specific appli-
cation. In our judgement, the WEPCO demonstration represents
a particularly attractive application of PFBC which can have
broad and immediate value to the utility industry in the 1990' s,
if implemented promptly.
The participants in the WEPCO proposal have been leaders in
the development of turbocharged boiler and PFBC technology.
Their proposal reflects a well thought out program with a
utility which has long been a leader in technology innovations
for the utility industry. In fact, WEPCO demonstrated the
first pulverized coal utility power plant in 1920 and has
been the first to apply a variety of coal combustion improve-
ments in the years since.
441
Briefing To Senate Staff
By Kurt E. Yeager
EPRI
Palo Alto, CA
June 19, 1985
SUMMARY COMMENTS
FIGURE 1 A kW of new generating capacity, in constant
dollars, costs more than three times what it
did in 1967 and even more than in 1920.
o This escalation results from the impact of
increased environmental control, stretch out
of licensing and construction schedules, loss
of productivity, and resulting increases in
interest charges during construction.
o As a result, fundamental improvements in
power plant technology are required to sub-
stantially reduce these cost penalties. These
improvements must more effectively integrate
environmental control with the coal combustion
process and provide smaller, modular plants
with reduced construction times.
FIGURE 2
and 3
FIGURE 4
There is an urgent
in power plant tech
dependence on coal
increase in coal us
primarily in the el
about 170,000 MW of
capability. Implic
improvements in ene
productivity from e
improvements do not
generating capabili
need for these improvements
nology if growing national
is to be satisfied. The
e by the year 2000 will be
ectrical sector and reflects
new net coal-fired generating
it in this projection are major
rgy conservation plus improved
xisting power plants . If these
occur then the need for new
ty is even greater.
If this "generation" gap of the 1990s is to be
resolved without major economic dislocation, a
more aggressive national effort is required to
demonstrate and commercialize the improved coal-
based technology currently under development.
A variety of options for improving the cost and
efficiency of emission control for existing and
new coal-fired power plants are under consideration.
These include commercially available physical coal
442
cleaning and flue gas wet scrubbing which reflect
relative extremes in control efficiency and cost.
By comparison a variety of other developmental
capabilities (reflected by the dashed lines) pro-
vide the potential for both substantially improved
efficiency and reduced cost. In each case, prompt
commercial application depends on demonstration.
Only in the case of Atmospheric Fluidized Bed Com-
bustion (AFBC) and Integrated Gasification Com-
bined Cycle (IGCC) are any substantial demonstra-
tion activities underway.
For those technologies whose function is solely
environmental control, the levelized costs reflect
total capital and operating cost (i.e., coal clean-
ing, dry sorbent injection, NO^^ control, flue gas
scrubbing) . The levelized cost associated with
AFBC and PFBC reflect that portion of total process
cost directed to environmental control (e.g. 15-
25%) . Natural or syn-gas cost reflects the incre-
mental cost of these alternative, very clean fuels.
A more complete description of these technologies
and their demonstration opportunities are provided
in Tables A, I, and II. Federal participation as a
risk sharing investment banker is required to acce-
lerate the first-of-a-kind demonstration of these
improved options.
FIGURE 5 The advanced coal technology options (AFBC, PFBC,
and 6 and GCC) all provide substantial opportunity to
reduce the busbar cost of electricity relative
to current pulverized coal power plants with flue
gas scrubbing (PC and FGD) . These savings are
particularly dramatic for the smaller 200 ^W size
plant. This results from the increased opportunity
for modularity and reduced construction time, in
addition to savings in environmental control cost.
The fuel flexibility of AFBC also adds an additional
cost savings dimension. Capital cost savings (plant
and envirionment) are greatest in PFBC re-powering
applications where the technology can be used to
supply additional steam to increase the output of
existing power plants. Although the busbar cost
savings of GCC is not as large, this is driven by
the cost of natural or synthetic gas, not the
power plant itself. GCC also provides the greatest
environmental control potential of the various coal-
based options.
443
Conclusions
The nation stands at a threshold of fundamental
change its technology base for coal-fired power
plant generation. Coping with this transition
will require an intensive, joint commitment over
at least the next five years on the part of indus-
try and government.
There is no shortage of technical opportunities
to improve the cost and environmental performance
of coal utilization. The future is now and
success depends on satisfying four objectives
this decade:
o Develop a confident scientific basis for
decisions concerning the need and appli-
cation of emission controls.
o Demonstrate the array of potentially more
effective retrof ittable control alternatives
to flue gas scrubbers. No one of these options
will satisfy the range of conditions required
by all coal-fired plants. As a set, however,
they can meet this requirement and thus provide
a necessary bridge during the transition to
advanced, clean coal technology.
o Demonstrate the advanced coal utilization tech-
nologies, e.g., AFBC, PFBC, and IGCC, which can
fundamentally resolve the conflicts between coal
and the environment while substantially improving
efficiency and cost.
o Establish incentives to encourage the prompt
commercial implementation of these advanced
technologies by the regulated electric utility
industry.
Experience has shown that Federal participation as
a risk sharing investor in demonstration projects
initiated and managed by the private sector has
been the key to successful government/industry
partnerships . Examples have been the TVA/EPRI
AFBC and Coal Water IGCC demonstrations.
Mechanisms which provide for prompt selection of
proposed private sector demonstrations for Federal
investment are critical to meeting the objectives
of the Clean Coal Initiative.
444
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445
COMPARISON OF PRIMARY
U.S. ENERGY CONSUMPTION
(Quads)
77 Quads
■// 21,,* = *^
•^ -*
92 Quads
;, «- V ■ _ -' 4 -l «
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Oil imports
irr-3
Gas imports
L 1
Renewables
i: :;,:]
Nuclear
KSS^i
Coal
EZS3
Gas
r '^ 1' 1
Oil
1984
2000
Industry
Average
446
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447
COMPARISON OF COST & EFFICIENCY
FOR EMISSION CONTROL
Levelized Cost (mills/kWh)
45
40
35
30
25
20
15
Levelized Cost (S/t coal)
99
Natural
or
Syn-Gas
Flue-gas
wet scrubbiri^"^--^
/
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.'Advanced phys
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I / Dry
sorbent ^ " i
injection *^
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Post-combustion
NOx
88
Combustion NOy
-I I 1
22
11
30 40 50 60 70
Percent SO2 or NO, Emission Reduction
80
90
100
448
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449
QUALITATIVE COMPARISON OF CHARACTERISTICS
Technology
Characteristics
Adv
PC/FGD
AFBC
PFBC
GCC
Fuel Cell
GCC
Economical in Small Sizes
0
+
++
+
++
Fuel Flexibility
0
++
+
0
0
Low Emissions
+
+
+
++
++
Short Construction Time
0
+
++
+
++
Reduced Resource use
+
+
+
++
++
(water, etc.)
Higher Efficiency
+
0
+
+
++
Legend:
0 Same as present conventional pulverized coal technology
+ Better than present
++ Much better than present
450
PROPOSED CLEAN COAL DEMONSTRATION AREAS INCLUDING
EPRI PARTICIPATION
(Million $)
Technology
Demonstration
Coal Quality
1
B. Combustion Technology
1. Coal-Water Slurry
2. Furnace Sorbent
Injection for SO2
Control (LIMB)
3. Low NOj^ Combustion
4. Combustion Diagnostics
and Coal Variability
Impact Reduction
Total
Fund ing
Intensive sulfur and 40
ash- separation
2. Efficient Fine Coal 60
Cleaning & Recovery -
EPRI CCTF
3. K - Fuel Cleaning 39
and Pelletizing
4. Biological Coal 20
Desulfurization
5. Automated Coal Cleaning 20
Plant Process Control
50
60
25
50
Flue Gas Cleanup
1. Southern Company/Chiyoda
121 Process
40
2. EPRI High Sulfur Coal
35
Test Center
3. Regenerable NOj^/SOj^
27
Control
4, Baghouse Sorbent
25
Injection for SO2
Control
Recommended
Federal
Participation
20
15
10
10
10
20
25
10
25
10
5
13
5
Pressurized Fluidized
Bed Combustion
1. Turbocharged PFB Boiler
90
45
451
2, PFB Combined Cycle 120 60
3. Circulating PFB 70 4U
Prototype
E. Atmospheric Fluidized
Bed Combuston
1. NSP Conversion 56 5
2. Colorado-Ute Circulating 117 3U
AFB
3. 100 MW Coal Refuse 125 30
Combustor
F. Integrated Gasification
Combined Cycle
1. Slagging Gasifier & 440 180
Advanced Turbine IGCC
2. IGCC Methanol & 40 20
Electricity Production
G. Fuel Cell - Coal Gasification
1. Phosphoric Acid Fuel Cell 50 20
2. Carbonate Fuel Cell 150 90
H. Environmental Assessment
1. Impact Mitigation 20 5
2. Atmospheric Tracer 200 40
Demonstration
Total 1969 743 (38%)
452
Table I
ILLUSTRATIVE RETROFIT COSTS (i;
Retrofit
Technology
Physical Coal
Cleaning
Coal Switching
Illinois to PRB
Illinois to Cent App
Illinois to Colorado
Limestone FGD
Dual Alkali FGD
Chiyoda FGD
Forced Oxidation FGD
Wellman-Lord FGD
Spray Dry FGD
Furnace Sorbent
Injection
AFBC
Post Furnace Injection
Post Comb NOx
Low NOx Burners
Coal Gasification
Capital Cost
($/kW)
20-45
(2)
80-280 (4)
45
95
175-317 (5)
157-272 (5)
172-291 (5)
293-323 (5)
252-492 (5)
148-252 (7)
25-120 (9)
70-245 (11)
70-100 (12)
54-89 (15)
8-14 (17)
Total Cost
Level ized Cost Effectiveness
(mills/kWh) ($/ton SOp Removed)
3.6-0.9
(2)
13.4-18.7 (4)
21.1
23.4
17.0-23.4 (5)
15.2-22.4 (5)
14.1-17.8 (5)
25.9-20.8 (5)
21.7-31.5 (5)
9.6-30.6 (7)
6.0-14.0 (9)
9.5-17.6 (11)
8.4-19.6 (13)
5.7-13.5 (15)
0.2-0.4 (17)
336-923
394-553
627
694
576-1125
560-988
425-935
560-1048
754-1429
778-2831
(3)
(4)
(6)
(6)
(6)
(6)
(6)
(8)
630-790 (19) 28-41 (19)
512-812 (10)
550-1074 (11)
1462-2651 (14)
•229-850 (16)
8-14 (18)
1595-2255 (19)
453
Table I (continued)
Notes
(1) All costs assume the fallowing unless noted otherwise:
End of year (EOY) 1982 dollars
30 year levelization period (1983-2012)
65 percent capacity factor
2 X 500 MW plant
Midwest location
90 percent SO^ removal
(2) Cost range for Level 4 cleaning (all size fractions) of an Illinois Basin
or Northern Appalachian coal. Does not Include capital cost of cleaning
plant.
(3) 27 percent sulfur removal from an Illinois basin coal.
(4) Lower value assumes no derating; upper value assumes major derating. SOj
removal range 85-88 percent. PRB means Powder River Basin.
(5) Lower value assumes an easy retrofit using 2 percent S-coal; upper value
assumes a difficult retrofit on 4 percent S-coal.
(6) Lower value assumes an easy retrofit using 4 percent S-coal; upper value
assumes a difficult retrofit using 2 percent S-coal.
(7) Lower value assumes an easy retrofit using 0.5 percent S-coal and 70 per-
cent SO, removal; upper value assumes a difficult retrofit using 2 percent
S-coal and 70 percent SO2 removal.
(8) Lower value assumes an easy retrofit using 4 percent S-coal and 80 percent
SO, removal; upper value assumes a difficult retrofit on 0.5 percent S-coal
ana 70 percent SO, removal.
(9) Cost range basis same as footnote 5 except 50 percent SO^ removal assumed.
(10) Cost range basis same as footnote 6 except 50 percent SO^ removal assumed.
(11) Capital cost range reflects fraction of total AFBC capital cost {$990/kW)
accountable to environmental control. This ranges from 7% for SO? con-
trol alone to 2S% for all aspects of environmental control. Total level-
1zed cost includes cost of consumables (limestone waste handling). No
capacity credit or fuel cost savings are included. Illinois No. 6 coal,
41 sulfur content.
(12) Costs shown are for new units assume a fabric filter retrofit is required.
Retrofit costs could be higher.
(13) Lower value assumes a nahcolite system, reagent costs of $50/ton, 0.48 per-
cent sulfur coal and 75 percent SO^ removal; upper value assumes reagent
costs of $150/ton. a 1 percent S-coal, and 75 percent SO, removal. Costs
are for new units only; retrofit costs could be higher.
(14) Lower value assumes a nahcolite system, reagent costs of $50/ton, a
1 percent sulfur coal and 75 percent SO, removal; upper value assumes
reagent (nahcolite) costs of $150/ton, I percent S-coal, and 75 percent SO,
removal. Costs are for new units only; retrofit costs could be higher.
(15) Lower value assumes 60 percent NO^ reduction at 200 ppm inlet NO using
4 percent S-coal; upper value assumes 80 percent NO reduction af 800 ppm
Inlet NO^ using 0.5 percent S-coal. Costs are for new units; retrofit
costs could be higher.
(16) Lower value assumes 80 percent NO, reduction at 800 ppm inlet NO using
4 percent S-coal; upper value assumes 60 percent NO reduction a{ 200 ppm
Inlet NO, using 0.5 percent S-coal. Costs are for new units; retrofit
costs could be higher. Costs in $/ton of NO, removed.
(17) Lower value assumes retrofit of a face-fired or horizontally opposed-fired
boiler; upper value assumes retrofit of a tangentially-f ired boiler.
(18) Same assumptions as footnote 17; costs In $/ton of NO, removed.
(19) Capital cost range reflects costs of Texaco coal gasification and Integrated
Gasification Combined Cycle (IGCC) plants reported in EPRI AP-3109. Raw
coal cost of $1.89 MBtu, Illinois No. 6 coal, 41 sulfur content. No capa-
city or by-product credits are included.
454
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457
1019 19th Street, N.W.
Suite 910
Washington, D.C. 20036
202/887-0426
DAVID O WEBB JLine 4, 1985
Senior Vice President,
Policy and Regulatory Affairs
The Honorable Don Fuqua
Chairman
Committee on Science and Technology
2321 Rayburn House Office Building
Washington, D.C. 20515
Dear Don:
I appreciated the opportunity to present GRI's views on the clean coal tech-
nology initiative before the Subcommittee on Energy Development and Applica-
tions on May 8. I have attached GRI's answers to the Subcommittee's questions
regarding DOE's report.
If you need additional information, please call me.
Sincerely,
/S>a4u<:^
David 0. Webb
Attachment
cc: William T. Harvey, Jr.t/
Gas Research Institute, 8600 West Bryn Mawr Avenue. Chicago, Illinois 60631 312/399-8100
458
RESPONSE TO QUESTIONS ON U.S. DEPARTMENT OF ENERGY'S
REPORT ON ENCRGING CLEAN COAL TECHNOLOGIES
May 8, 1985
Question: Surface coal gasification technology is conducted in a variety of
methods — fixed-bed, fluidized-bed, entrained-bed — and at a variety of
pressures. Specifically, what processes must be fully defined to characterize
the technology, and what is the present status of each?
Answer: GRI interest in surface coal gasification processes is concentrated
on current and emerging gasifiers suitable for economic production of
substitute natural gas (SNG). Our economic analyses indicate that lowest cost
SNG is achieved using processes that maximize production of methane within the
gasifier, thereby reducing downstream processing costs. This is achieved in
gasifiers that operate at lower temperatures and high pressures of ^00 to
600 pounds per square inch (psi). Gasifier temperatures that control methane
formation vary from approximately 9000F to 3,000OF and are dependent upon
coal type, coal/steam/oxygen ratios, pressure, and the reactor configuration.
The counter flow, fixed-bed (or moving-bed) gasifier will have nominal
temperatures at the top of the bed in the range of 900°F to 1,200°F.
Temperatures at the top of an ash-agglomerating fluid-bed gasifier will be
1,600°F to 1,900°F, and the reactor exit temperature for an entrained-flow
gasifier will be 2,300°F to 3,000°F. At the very high temperatures
associated with the entrained-flow reactors, methane is thermodynamically
unstable and is generally not present in the product stream. At the lower
temperatures associated with the fixed-bed and fluid-bed reactors, methane is
more stable and will constitute a significant percentage of the gasifier
product stream. Depending upon the specific coal and reactor conditions, as
much as 40 percent of the final methane production can be achieved in the
gasifier.
Lower operating temperatures also reduce oxygen requirements, which contribute
to lower SNG cost. Operating pressures of 400 psi to 600 psi are compatible
with the requirements of the gas clean-up and conversion processes downstream
of the gasifier and, therefore, do not add unusual cost to the overall
process. Operating pressures above 400 psi to 600 psi have diminishing
impacts on SNG cost.
A coal gasifier is a very complex reactor. It operates at high temperatures,
at elevated pressures, and is continuously fed gaseous streams and solid
material that has both organic and inorganic constituents. In addition, it
generates gas streams on a continuous basis that are both reactive and
corrosive and discharges high-temperature ash on a continuous basis. Finally,
a commercial reactor will have the capacity to process coal at rates of the
order of 1,000 tons per day.
Because of the inherent complexity of these reactors, serious consideration of
advanced technology for commercial applications will only occur when there is
an adequate data base available that can be used to predict total systems
performance and costs with a high degree of confidence and when the
engineering risks have been reduced to a low level. This is due to the
limited experience with reactors of these types and because of the large
investments required for coal-to-SNG plants. The uncertainties associated
with the scale-up of coal gasification technologies dictate that this data
base must include both performance data (i.e., heat and material balances) and
operational data on commercial- or near-commercial-size units.
459
Data needed to be developed include specific coal conversion rates, steam and
oxygen feed rate requirements, carbon conversion, fines utilization and
carryover, gas and ash composition, and reactor temperature variations. While
each of these can be predicted from the results of smaller-scale experiments,
uncertainties concerning flow profiles in the reactors and uncertainties with
respect to gas-solids contacting make it difficult to predict large-scale
gasifier performance to the degree required to accurately specify, design, and
cost the other components of the plant.
In addition to the basic heat and performance data, the operational
characteristics of the unit must be evaluated over an extended period of
time. This is necessary to validate the reliability and operability of the
engineering extrapolations in the harsh environments that exist in the
different areas of the gasifier.
Based on GRI economic analyses, dry-ash, fixed-bed, slagging moving-bed, and
agglomerating-ash fluid-bed gasifiers are the best candidates for SNG
production. Entrained-bed gasifiers have the dual disadvantages of high
oxygen utilization and essentially no methane production at any pressure
because of their high operating temperatures.
Question: If the goal is to produce synthetic natural gas, which method or
methods appear to be the most effective candidates?
Answer: GRI discussed the current and emerging processes of principal
interest for SNG in our clean coal submission. We believe that the commercial
Lurgi dry ash process will be adequately demonstrated by Great Plains if that
plant continues operation. Briefly, emerging processes that are candidates
for large-scale demonstration include the British Gas/Lurgi moving-bed,
slagging gasifier and the agglomerating-ash fluid-bed processes Westinghouse
and U-GAS are developing.
The slagging process is now approaching commercial scale (550 tons per day),
in the UK, whereas both Westinghouse and U-GAS are at the process development
unit (POU) scale (2^ tons per day). Even though larger-scale evaluation of
U-GAS and Westinghouse technology (at 200 to 300 tons per day) is planned in
France and China (respectively) in the next few years, neither of these
planned projects address SNG as the end product. A large-scale demonstration
of the agglomerating-ash fluid-bed process is urgently needed to provide
operational data at higher coal throughput and/or operating pressure for
agglomerating-ash gasifiers on eastern coals. This step is essential before
these processes can be conmercialized.
Question: You point out that 60 percent of the Emerging Clean Coal
Technologies responses related to four technologies — flue gas cleanup, coal
gasification, fluidized bed combustion, and coal preparation. What factors
besides numerical response justify emphasizing support of those processes?
Answer: Additional factors that should be considered in determining which
clean coal technologies should receive priority in any initial funding phase
are:
1. The extent of cofunding offered by the industrial sector.
2. The involvement of technology users (not sellers) who ultimately determine
its market acceptability.
460
3. The extent to which existing facilities are proposed in order to minimize
total demonstration costs.
it. The cost-effectiveness of the proposed demonstration. In other words, the
project should be the minimum size required to demonstrate technical and
commercial feasibility; i.e., it shouldn't demonstrate at a
500-ton-per-day level if 200 tons per day is sufficient.
5. The potential for early commercialization if the technology is
successfully demonstrated.
Question: Should Congress support demonstrations of other processes?
Answer: The longer-term, higher-risk processes proposed by some respondents
should not be included in the initial phase of the program. These
technologies, while promising, still require additional research and
smaller-than-commercial-scale demonstrations before they can be
commercialized. The initial program should be limited to processes which, if
successfully demonstrated, could be moved immediately into the market in order
to take advantage of the "window of opportunity" available between now and the
early 1990s.
Advanced proccesses such as fuel cells, MHO, etc. should continue to receive
research funding as part of the regular DOE Fossil Energy Program.
-3-
461
PEABODY HOLDING COMPANY, INC
301 NORTH MEMOR[AL DRIVE • P. O. BOX 373
ST. LOUIS. MISSOURI 63166
TELEPHONE (314) 342-3400
JOHN M WOOTTEN
DIRECTOR
RESEARCH a TECHNOLOGY
June 3, 1985
The Honorable Don Fuqua
Chairman
Committee on Science and Technology
U. S. House of Representatives
Suite 2321
Rayburn House Office Building
Washington, D.C. 20515
Dear Chairman Fuqua:
The following is my response to the additional questions posed to me by
the members of the Subcommittee.
1. As an investor in the Paducah Atmospheric Fluidized Bed Utility
Boiler Demonstration, your company has shown active interest in an
emerging clean coal technology. How long do you suspect the plant
must operate satisfactorily to convince the utility industry that
the technology is ready for use?
Answer: To respond to this question, I have reviewed the three fluidized
bed demonstration projects - TVA, Colorado Ute and Northern States
Power - to determine the length of their proposed test demonstra-
tion schedules. TVA has proposed a 48-month testing and commercial
demonstration schedule; the first six months of that would be for
shakedown, during which period the systems composing the FBC
technology would all be brought into full service. Following this
would be a 17-month parametric testing phase. This would be a
phase for achieving operation at design conditions and for verifi-
cation of design assumptions. The boiler and its subsystems would
also be verified at various operating conditions. Following this
will be a 2A-month continuous commercial operation run. This run
will assess the impacts that an extended period of operation under
commercial conditions will have on the technology.
Colorado-Ute has proposed a 28-month program divided into two
phases. The first phase would be operation at design conditions
for verification of design assumptions and scale-up considera-
tions. The second phase would be to test alternate fuels and
sorbents (limestone) so that the data base for designing circu-
lating fluidized bed units and the transfer of the technology to
the utility industry would cover a number of representative fuels.
Colorado-Ute has proposed that this testing phase be provided
funding by the Clean Coal Technology Fund.
462
Northern States Power has proposed a 42-month test program. The
first six months of this test program would be to guarantee the
performance of the unit and would entail extensive testing by the
boiler manufacturer to verify that the guaranteed performance
conditions were being achieved. Following this would be a 3-year
phase for testing various fuels and sorbents. It is anticipated
that after testing with coal, a refuse-derived fuel would also be
tested in the unit.
In summary, ,it appears that testing to insure commercial
acceptability ranges for a period of two to four years, depending
upon the complexity of the project. At least a 2-year test of a
clean coal technology is required. That 2-year test should be
broken into three major phases. The first phase being shakedown
to ensure the opeation of the system itself; phase two would be
operational testing at design conditions; and finally, phase three
would be an extended opertional run under commercial conditions.
The extent of a program would depend upon the complexity of the
system as well as the desire for testing alternate fuels and, in
the case of systems using a sorbent, alternate sorbents.
Among the several ranks of coal mined by your company, do you see
any one as needing more R&D attention than the others? Why?
Existing and new markets of high sulfur bituminous coal require
new technologies for environmentally acceptable and economically
viable use of this coal. At the present time, these coals because
of their sulfur content are at a disadvantage in the marketplace
relative to lower sulfur bituminous and subbituminous coals. In
addition, these coals retain this disadvantage when they are
considered for use in new applications even though technology for
sulfur removal is required on all new utility steam electric
generating units. The cost to apply flue gas desulfurization
systems to high sulfur coal is significantly larger than the cost
to apply the same technology to a medium or low sulfur coal. In
many instances, this differential between "scrubbing high sulfur
coal" will more than offset the transportation differential that
may occur when comparing a low sulfur coal to a high sulfur coal.
Therefore, to ensure that the large midwestern and eastern
reserves of higher sulfur coals can fulfill their traditional
market role, clean coal technologies which can address this sulfur
emission problem at a competitive cost must be developed.
It is estimated that total U.S. production in 1985 will
approximate 905 million tons and that 1995 production must reach
1.2 billion tons to meet domestic and foreign needs. What amount
of mining R&D will be necessary to assist the industry to increase
production by one-third in ten years?
ICF has projected that the production of coal in the United States
will reach 905 million tons in 1985. Beyond this 905 million tons
of production in 1985, there will remain 54 million tons of excess
production capacity in the East and 75 million tons of excess
production capacity in the West, or approximately 130 million tons
463
total. ICF further projected that the production level will reach
1,113 million tons in 1995. This means that the coal industry
will have to expand by approximately 10% over the next ten years
to exactly equal the required production level. In addition to
this 10% expansion, it will be necessary to replace mines that
deplete in that period in order to reach the required production
levels. Therefore, it is unlikely that additional research will
be required to meet the production goal. However, this is not to
say that coal mining research is not required. There are a number
of major areas where continued research is necessary. The areas
are productivity, safety, environmental (reclamation and
subsidence) and coal preparation. Because coal will continue to
be the mainstay of the U.S. energy supply, it is important that
adequate research, both private and public, be assigned to these
areas.
4. What emerging clean coal technologies could have the quickest
benefit to the coal industry?
Answer: This question needs to be addressed from two aspects, short-term
and long-term benefits to the coal industry. In looking at the
short-term or quickest benefits, the technologies which will
reduce sulfur at a cost lower than present technologies, such as
flue gas desulfurization systems or scrubbers, are the most
desirable. Secondly, those systems that can combine both the
removal of sulfur and nitrogen have a double benefit
environmentally if it can be accomplished at a reasonable cost. A
third factor is the need to have technologies which are
retrofitable to existing facilities in order that these
facilities, in the face of a major piece of environmental
legislation or regulation, can continue to burn their historical
fuel supplies. With those factors in mind, the following clean
coal technologies will produce the quickest benefits:
Sorbent injection, either in the furnace or in the back pass
of the boiler prior to the particulate collection equipment
(electrostatic precipitator or baghouse);
limestone injection multistage burner (LIMB) applications to
the various boiler configurations (wall fired, corner fired
and cyclone) ;
dry scrubbing technology on high sulfur coal followed by
particle collection either a baghouse or an electrostatic
precipitator;
advanced physical coal cleaning for those applications where
gas or oil-fired units can be converted to coal; and,
finally,
atmospheric fluidized bed combustion and circulating
fluidized bed combustion are alternatives for construction of
new boilers as well as, in the case of AFBC, retrofitting to
existing boilers.
464
These technologies will provide the quickest benefits to the coal
industry. In the long run, however, chemical coal cleaning, the
development of a slagging combustor for retrofitting to current
oil and gas-fired units, the development of Pressurized Fluidized
Bed Combustion and the second generation of gas turbines that
utilize a coal or coal-derived fuel gas with hot gas cleanup are
clean coal technologies which will enhance the use of coal in
existing and new facilities.
5. What advice can you provide the Committee on possible addition,
reduction or emphasis changes in the DOE coal R&D budget?
Answer: The response to this question is fairly straightforward when one
reviews the projected FY85 expenditures for the DOE R&D budget.
Projections are that approximately $150 million would be spent on
coal-related R&D out of a potential expenditure of $2.8 billion,
discounting weapons, naval reactor and defense R&D expenditures
from the total $5.2 billion budget. The coal-related R&D
expenditures are a mere 5% of the non-weapons related R&D budget.
This small degree of expenditure does not compare with the
proportion of this country's present and future energy needs which
will be supplied by coal. Nuclear energy, for the time being, has
faded in importance for supplying the country's energy needs over
the next 10 to 20 years. Furthermore, the present price of oil
has rendered the production of synthetic fuels non-enconomical for
the private sector. This does not, however, relieve the concern
of depleting domestic oil supplies and the increased use of
imported oil. It would seem that a reemphasis away from nuclear
and back to coal would be appropriate. The direct combustion of
coal as well as new, lower-cost methods for producing synthetic
fuels from coal would be an appropriate emphasis for the the
reassigned monies.
6. To what extent are your utility customers willing to pay more
money for cleaner coal - lower ash and sulfur? Could you envision
providing coal at ash below 1% and sulfur below . 1% and receiving
premium pay from a utility which would not need to scrub the
boiler exhaust gas or to use baghouses to meet clean air
standards?
Answer: The attached table depicts 1980 delivered costs of coal by S02
emission level for selected states. Data for 1980 was selected as
a year in which demand produced costs which are representative of
what one would expect to pay for premium fuels. As can be seen
from the table, the differential between high and low sulfur coal
can be considerable. It is this differential which can be
classified as the premium a utility is willing to pay for a higher
quality coal. It is evident and, I believe, extremely likely that
a utility would pay a higher price for a coal quality that would
allow them to avoid the use of flue gas desulfurization systems,
that would reduce the amount of coal that would have to be handled
and ground, as well as the amount of ash that would end up in the
boiler and ultimately have to be disposed of. This premium would
result primarily for conventional pulverized coal combustion. If
465
an advanced technology, such as fluidized bed combustion were
used, the fuel characteristics become less important. In fact,
the use of lower quality coals becomes a positive point for these
technologies. Atmospheric fluidized bed combustion is perhaps the
most important of these in that the ash is required as a heat
transfer medium within the boiler and only about one to two
percent of the material in the boiler at any one instance is
actually combustible material. The technology for removing ash
from the flue gas is fairly simple and inexpensive and, therefore,
premium fuels would not be required in these applications. The
use of coal in an integrated combined cycle plant may or may not
be influeneced by the amount of sulfur and ash in the fuel
depending upon the type of cleanup systems required. As a general
rule, the lower the ash and the lower the sulfur, the lower the
operating cost for any system in which sulfur and ash must be
removed. Therefore, utilities will pay a premium price to avoid
the addition of control equipment or to lessen the operating costs
of that control equipment.
If I can provide further information to you or the other Committee
members, please contact me.
Sincerely,
John M. Wootten
466
1980 DELIVERED COST OF COAL
BY S02 EMISSION LEVEL
FOR SELECTED STATES
Cents/MM Btu
State
Alabama
Florida
Georgia
Illinois
Indiana
Kentucky
Michigan
Mississippi
Ohio
Texas
West Virginia
Wisconsin
Between Between Greater
Less than 1.0 1.1 and 3.0 3.1 and 5.0 Than 5.0
Lbs S02/MM Btu Lbs S02/MM Btu Lbs S02/MM Btu Lbs S02/MM Btu
2A1.9
251.1
299.8
222.2
206.0
307.6
207.0
229.2
198.6
180.4
197.6
199.4
2A9.9
187.4
190.2
181.4
272.2
149.1
150.8
142.1
183.9
137.1
210.3
156.9
235.3
196.1
182.5'
149.8
109.1
137.6
182.6
145.5
172.4
177.6
172.2
153.0
138.2
127.0
166.9
126.9
165.4
O
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