United States
Environmental Protection EPA-600/7-82-045
Agency May 1982
SEPA Research and
Development
COMBUSTION OF OIL SHALE
IN FLUIDIZED-BED COMBUSTORS
AN OVERVIEW
Prepared for
Office of Environmental Engineering and Technology
Prepared by
Industrial Environmental Research
Laboratory
Research Triangle Park, NC 27711
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development. U.S Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields
The nine series are:
1. Environmental Health Effects Research
2 Environmental Protection Technology
3 Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6 Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of. and development of. control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service. Springfield. Virginia 22161.
-------
EPA-600/7-82-045
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
EPA Project Officer
John 0. Milliken
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, N.C. 27711
Contract No. 68-02-2693
Technical Directive No. 11
COMBUSTION OF OIL SHALE IN
FLUIDIZED-BED COMBUSTORS -
AN OVERVIEW
Final Report
May 1982
Prepared by
Douglas R. Roeck
GCA CORPORATION
GCA/TECHNOLOGY DIVISION
Bedford, Massachusetts
-------
DISCLAIMER
This Final Report was furnished to the U.S. Environmental Protec-
tion Agency by GCA Corporation, GCA/Technology Division, Bedford, Massa-
chusetts 01730, in fulfillment of Contract No. 68-02-2693, Technical Direc-
tive No. 11. The opinions, findings, and conclusions expressed are those of
the author and not necessarily those of the Environmental Protection Agency
or of cooperating agencies. Mention of company or product names is not to
be considered as an endorsement by the Environmental Protection Agency.
ii
-------
CONTENTS
Figures iv
Tables v
Acknowledgment vii
1. Introduction and Background 1
Introduction 1
Background 1
2. Technology Overview 6
Previous Experience with FBC Technology 6
Unique Concerns of Oil Shale Combustion 7
Raw Shale Combustion 8
Spent Shale Combustion 18
Combustion of Coal-Shale Mixtures 20
Preliminary Economic Analysis 29
3. Summary and Conclusions 35
References 41
Bibliography 43
Appendices
A. Calculations Regarding the Magnitude of an Oil Shale
Industry's Production and Disposal Requirements 45
B. Support Calculations for Preliminary Economic Analysis
Presented in Section 2 49
C. Support Calculations for Determining Total Solid Waste
Rates for Coal-Sorbent Tests Presented in
Tables 16b and 16c 54
iii
-------
FIGURES
Number Page
1 Principal oil shale deposits in the United States 4
2 Sulfur dioxide reduction for coal-limestone and coal-oil
shale mixtures 23
3 Conversion (measured with a TGA) of precalcined CaO to
CaSO^ in spent Green River oil shale at 700° to 1050°C
(1300° to 1920°F). Reaction conditions: precalcined,
20% C02-bal N2 (-50 +70 mesh); sulfation gas, 0.3%
S02-5% 02-20% C02 in N2 25
4 Conversion (measured with a TGA) of CaO to CaS04 in spent oil
shale, Tymochtee dolomite, Greer limestone, and Germany
Valley limestone, using 0.3% S02-5% 02 in N2 at 900°C
(1650°F) 26
5 Predicted 862 retention versus Ca/S ratio for oil shale at
various temperatures for a gas velocity of 12.5 ft/sec and
a bed height of 3.5 ft. Based on TGA data 27
6 Direct operating cost as a function of sorbent cost for
various coal-sorbent systems 33
iv
-------
TABLES
Number Page
1 Organizations Contacted During Study Relative to Oil Shale
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Summary of the Range of Observed Concentrations of Elements
Operating Conditions for Fluidized-Bed Combustion of Israeli
Oil Shale
Test Results During Combustion of Moroccan Oil Shale ....
B&W Test Conditions - 100 Percent Oil Shale
B&W Test Results
Chemical Composition of TOSCO II Spent Shale
Composition of Union Spent Oil Shales
Test Results from Coal-Oil Shale Combustion Tests Conducted
Concentrations (in wt %) of Major Constituents of Calcareous
Materials
Required Quantities of Green River Oil Shale, Germany Valley
Limestone, Greer Limestone, and Tymochtee Dolomite to Meet
an S02 Standard of 1.2 lb/106 Btu
Direct Operating Costs for a Conventional Fluidized-Bed
Comparison of Direct Operating Costs for a 250,000 Ib/hr FBC
Boiler Burning Coal with Limestone and Oil Shale Sorbents
Annual ized Cost Comparison Between Coal-Oil Shale Systems and
9
12
13
15
16
17
18
19
22
24
28
30
31
34
-------
TABLES (continued)
Number Page
16a Summary of Results from Direct Combustion of Virgin Oil 37
Shale
16b Summary of Results from Direct Combustion of Oil Shale-Coal
Mixtures 38
I6c Summary of Results of TGA Studies for Direct Combustion of
Coal-Sorbent Mixtures 39
vi
-------
ACKNOWLEDGEMENT
The author would like to express his appreciation to the EPA Project
Officer, John 0. Milliken, for his advice, technical guidance, and dilligent
review provided during the course of this project. I also wish to thank the
numerous people who supplied data and information for preparation of this
document.
Special thanks are also directed to Mr. Robert R. Hall who provided
excellent technical review of this report and to Sharon Pleskowicz and the
technical illustrators and typists who prepared the final manuscript.
vii
-------
SECTION 1
INTRODUCTION AND BACKGROUND
INTRODUCTION
The potential for using raw oil shale, spent shale, or coal-oil shale
mixtures as a direct fuel, fuel supplement, or S02 sorbent in atmospheric
fluidized-bed combustors (AFBC) has been examined. Such uses of the AFBC
could include the following:
• direct combustion of raw (low-grade) oil shales (<20 gal oil
per ton shale),
• direct combustion of retorted or spent shale,
• direct combustion of coal-oil shale mixtures wherein the
oil shale is utilized as an S02 absorption media,
• shale retorting processes.
Primary emphasis is placed upon those areas pertaining to direct combustion;
retorting processes are addressed only insofar as they impact the fuel
quality of the spent shale and the solid waste from combustion of spent
shale in fluidized-bed combustors.
The major information sources have been several literature references
and communications with research organizations and other companies involved
in oil shale-related activities. Those groups that have been contacted
during the course of this program and their areas of involvement are listed
in Table 1. In general, results of investigations being conducted by private
firms—either for themselves or clients—are unavailable due to the proprie-
tary nature of such data. On the other hand, work done under government
sponsorship is usually published and is readily available.
The current status and technical aspects of utilization of FBC technology
for oil shale combustion, perceived benefits and problems, available emission
data, and a preliminary economic analysis are presented in Section 2 of this
report while a summary and conclusions are provided in Section 3.
BACKGROUND
Deposits of oil shale are found in both the Eastern and Western U.S. as
shown in Figure 1.* Some of the richest oil shale deposits in the world are
found in the Green River formation of Colorado, Utah and Wyoming where beds
up to 1500 ft in thickness are found.^ Total U.S. resources are estimated
-------
TABLE 1. ORGANIZATIONS CONTACTED DURING STUDY RELATIVE
TO OIL SHALE COMBUSTION
(1)
(2)
(3)
(A)
(5)
(6)
(7)
(8)
(9)
(10)
Organization name
and location
Argonne National Laboratory
Argonne, IL
Morgan town Energy
Technology Center
Morgantown, WV
Pace Company
Denver, CO
Dorr-Oliver, Inc.
Stamford , CT
Lurgi Corp.
Eastern Division
River Edge, NJ
Institute of Gas Technology
Chicago, IL
Babcock and Wilcox
Research & Development Division
Alliance, OH
Hazen Research, Inc.
Golden, CO
U.S. EPA - Region VIII
Denver, CO
Denver Research Institute
Individ ual(s)
contacted
Irving Johnson
Joseph S. Mel
Charles Hook
Tom Hendrickson
Clarence J. Wall
Ted Polleart
R. David Matthews
J. B. Doyle
Rod Hodgson
Mike Hammer
Andrew Jovanovich
Area of
investigation8
3
1. 3
NDI
1
1
NDI
1, 3
1, 2
NDI
NDI
Chemical Division
Denver, CO
(11) State of Wyoming
Air Quality Division
Lander, WY
(12) U.S. EPA
Environmental Monitoring
Systems Laboratory
Las Vegas, NV
(13) Bartlesville Energy Research Center
Bartlesvilie, OK
(14) TOSCO
Denver, CO
Lee Gribb
Wesley Kinney
Mr. Linville
Dan Fratello
Warren Broman
NDI
NDI
NDI
1, 2
(continued)
-------
TABLE 1 (continued)
(15)
(16)
(17)
(18)
(19)
(20)
(21)
(22)
(23)
(24)
(25)
al
2
3
ND1
Organization name
and location
Foster-Wheeler
Development Corp.
Livingston, NJ
Science Applications, Inc.
Golden, CO
Occidental Petroleum Co.
Grand Junction, CO
Southern Indiana
Shale Oil, Inc.
Charlestown , IN
Union Oil Co.
Grand Junction, CO
Brea, CA (R&D)
U.S. Geological Survey
Grand Junction, CO
Superior Oil Co.
Engelwood, CO
Paraho Corp.
Grand Junction, CO
Dept. of Energy
Laramie , WY
Massachusetts Institute
of Technology
Cambridge, MA
Energy Resources Co.
Cambridge, MA
= Raw Shale Combustion
= Spent Shale Combustion
= Coal/Shale Mixtures
= Not directly investigating
Individual (s)
contacted
Joseph F. McMahon
Dr. Chang Yul Cha
Mr. Davis
C. R. Thomas
Mr. Heckel
Arnold Kelley
Donald Johnson
Lor en Young
Joseph Glassett
Bill Little
Prof. Wei
Dr. Tong
Robert Davis
Area of
investigation3
1, 2
1
NDI
NDI
NDI
NDI
NDI
NDI
NDI
NDI
NDI
2
-------
Tertiary deposits: Green River formation in Colcmtilo. Utah, and Wyoming. Monterey formation
in California: middle Tertiary deposits in Montan.i Black areas are known hiyh-grade
deposits
Mesozoic deposits: Marine shale in Alaska Boundary dashed where concealed or where
location is unknown.
Permian deposits: Phosphona formation in Montana.
Devonian and Mississippian deposits. Boundary dashed where concealed or where location
unknown. Shading indicates known areas of oil shale deposits; white indicates areas of
possible scattered oil shale deposits (extent not defined).
SOURCE: Duncan. O. C.. and V. E Swanson Organic-Rich Shale of the United States and World Land Areas. USGS Circular 523 Washington DC,
U.S. Geological Survey. 1965
Figure 1. Principal oil shale deposits in the United States.
-------
at over 2 trillion barrels of equivalent oil with about 1.8 trillion barrels
in the Green River formation. Not all of this oil is considered to be a
recoverable reserve due to current technology and economic conditions, but
the U.S. Geological Survey estimates that approximately 600 billion barrels
are potentially recoverable from the rich (those containing at least 25 gal
of oil per ton of shale) Green River deposits. Of these high grade deposits,
approximately 85 percent are located in Colorado's Piceance Creek Basin, 10
percent in Utah's Uinta Basin, and 5 percent in the Green River, Washakie,
and San Wash Basins of Wyoming. The estimate of 600 billion barrels represents
about a 90-year U.S. oil supply.
The oil shale in the Eastern U.S. is spread over a much larger area than
Western shale, but is of much lower quality, as determined by the Fisher
Assay test,* mostly being less than 15 gal/ton. These Eastern deposits are
estimated at approximately 400 billion barrels of equivalent oil in place,
but until recently have been considered nonrecoverable. However, ongoing
research at the Institute of Gas Technology in Chicago has involved a retort-
ing method utilizing hydrogen under pressure (hydroretorting) which can po-
tentially increase the shale's yield by a factor of 2.5.3 This would mean
potentially recoverable reserves of about 1 trillion barrels if this tech-
nology could be applied successfully to these Eastern deposits.
Optimistic production estimates for an emerging oil shale industry range
as high as 3 million bbl/day by the year 2000. A level of 0.5 million
bbl/day is probably more realistic. These figures can be compared to the
7 to 8 million bbl/day that the U.S. now imports from foreign countries.
Assuming that an oil shale industry capable of producing 1 million
bbl/day eventually becomes established, 20 commercial plants would be required
since it is generally assumed that each commercial plant would be capable of
producing 50,000 bbl/day. The amount of raw shale that would need to be mined
and retorted is equivalent to 1 to 2 tons per barrel of oil, depending upon
the quality of the shale. Since only 10 to 15 percent by weight of shale is
recoverable as oil, 1 to 2 tons of spent shale is also generated for each
barrel produced. For example, a surface retorting operation producing 50,000
bbl/day from high grade shale would use 60,000 ton/day of shale containing
35 gal/ton and would produce 51,000 ton/day of spent shale requiring disposal.
It is seen why spent shale disposal is one of the most serious environmental
Issues facing this industry. Calculations indicate that from 63 to 250 fluid
bed combustors would be required for each 50,000 bbl/day plant if all of the
spent shale were to be directly combusted (see Appendix A for calculations).
Since this is obviously unfeasible, a more realistic approach would be the
direct combustion of some fraction of the plant's spent shale for the purpose
of recovering energy for use at the facility.
*In a Fischer assay, small samples of crushed oil shale are heated to 932°F
under carefully controlled conditions. The oil yield by this method is the
standard measure of oil shale quality.
-------
SECTION 2
TECHNOLOGY OVERVIEW
This section of the report discusses technical aspects associated with
direct combustion of oil shale in an atmospheric fluidized bed unit. A
discussion is presented first that describes previous usage or experience with
FBC technology in the oil shale industry. Next, various problems or concerns
with respect to oil shale combustion that are considered to be unique to this
application are addressed. Following these brief discussions, past and on-
going investigations of the feasibility of direct combustion (raw or virgin
shale, spent or retorted shale, and coal-shale mixtures) are summarized.
Finally, a preliminary economic analysis of direct combustion of coal-shale
mixtures is presented.
PREVIOUS EXPERIENCE WITH FBC TECHNOLOGY
The concept of fluidized bed technology in the oil shale industry is
not new, although past uses have primarily related to retorting process
applications. During the late 1960s, Sinclair Oil Corporation (now part
of Atlantic Richfield Company) investigated FBC retort applications.
Brief summaries of several U.S. patents issued since that time include the
following:
• U.S. Patent No. 3,484,364, Dec. 16, 1969
to: Esso Research and Engineering Co.
Fluidized retorting of oil shale by contact of the
fluidized oil shale with a hot free hydrogen-
containing gas. ^
• U.S. Patent No. 3,925,190, Dec. 9, 1975
to: The Oil Shale Corp. (TOSCO)
Preheating of oil shale prior to pyrolysis in a
series of at least two dilute phase fluidized
beds.6
• U.S. Patent No. 4,075,081, Feb. 21, 1978
to: Cities Service Co.
Fluidized bed hydroretorting of oil shale.''
• U.S. Patent No. 4,137,053, Jan. 30, 1979
to: Chevron Research Co.
Fluidized bed retorting or gasification of
hydrocarbon-containing solids such as oil shale,
tar sands, etc.**
-------
• U.S. Patent No. 4,152,245, May 1, 1979
to: Atlantic Richfield Co.
Fluidized bed classifier for removing rock solids
from heat-carrier solids which are cycled in the
retorting process.
UNIQUE CONCERNS OF OIL SHALE COMBUSTION
Heat loss due to calcium carbonate decomposition, determining the optimum
shale size for combustion, and achieving high combustion efficiency are three
areas that require specific attention when evaluating oil shale combustion
processes.
Carbonate calcination is a potentially troublesome aspect of raw oil
shale combustion since oil shale contains appreciable amounts of limestone
and because the calcination (forward) reaction,
CaC03 s CaO + C02 (g)
is endothermic, absorbing 43 kcal/g-mole or from 650 to 750 Btu/lb of
reactant depending on the temperature. At room temperature, the reverse
reaction occurs almost exclusively while the forward reaction becomes more
favorable as the temperature is increased. The commercial production of
CaO is accomplished at 16500plO and therefore combustion of virgin oil shale
solely for heat recovery should be carried out at less than this temperature
to avoid this heat consuming reaction. Depending upon the quality of the
shale, heat loss through calcination can consume on the order of one-third to
two-thirds of the available energy content of the shale.
The size of the as-fired shale is also an important consideration.
Specific conclusions drawn by DOE regarding an optimum oil shale size for
combustion were as follows:H
• Excessive size reduction will cause the release of volatile
hydrocarbons trapped inside the shale; this is known to be
one of the causes of volatile hydrocarbon loss.
• Fines generated by size reduction operations combined with
excessive moisture can cause solid handling problems.
This is particularly true for pneumatic air feeding systems.
• Power consumption for oil shale size reduction can be
excessive. Inefficient application of power to oil shale
size reduction can be economically unattractive, and can
lead to operational problems.
A third concern regarding shale combustion is that the achievement of
suitable combustion efficiencies may be more difficult than with other fuels.
This would be partially due to the fact that small amounts of residual
carbon (1 to 3 percent) dispersed throughout a relatively large particle may
not burn satisfactorily since mass transfer of oxygen to the carbon that is
dispersed in the mineral substrate would be difficult.
-------
An additional area that has not yet been adequately addressed through
on-going research concerns the characterization of solid waste from direct
combustion of oil shale in an FBC unit. It would be important to know, for
example, whether or not AFBC technology represents a step forward in coping
with ultimate disposal of wastes from oil shale extraction processes. Data
that are currently available pertain to raw and retorted shale but not
to such shale that has been subjected to direct combustion. Table 2 reports
results of laboratory-based leachate studies on surface storage of raw and
retorted shale conducted at Colorado State University.12 These data provide
some perspective as to what constituents would be present in the feed to an
FBC unit burning spent or raw shale. In general, such material contains
significant quantities of total dissolved solids, sulfates, and bicarbonates,
such inorganic ions as calcium, magnesium, sodium, potassium, and silicon,
and lesser amounts of trace metals and organic compounds. Research presently
underway at B&W will attempt to assess the leachable character of solid waste
from direct combustion of oil shale in their pilot facility.*
Past and on-going investigations have and are attempting to resolve
some of the questions regarding calcination heat loss, optimum oil shale size,
combustion efficiency, and solid waste characterization. These investigations
are discussed in the following paragraphs in order of industry-wide activity
level.
RAW SHALE COMBUSTION
Direct combustion of oil shale is a possible alternative or adjunct to
oil recovery via retorting. There are only three known commercial applica-
tions in the world at the present time. The largest is in the Soviet Union
(Estonia), where a rich oil shale having a heat content of 2700 Btu/lb is
used directly for fuel in a 3200 MW power plant. A second unit is located
in Southern Germany. In the late 1950's, Lurgi's roasting technology was
applied industrially in the Lurgi-Rohrbach process for burning oil shale in
the city of Dotternhausen. •* In this application, the economics of the
process are favorably influenced by the fact that the cinders are suited for
the production of special grade cement. This plant has a capacity of 794
ton/day and has an electrical output of 6 MW. A third installation exists
in China at the Mourning Petroleum Company located in Kwang-tung. The boiler
there is rated at 32,000 Ib/hr steam and burns oil shale fines with a heating
value of 1,860 Btu/lb. This unit, commissioned in 1965, was the first
demonstration fluidized-bed combustion boiler in China. It has a circular
bed of 7.4 ft diameter and a superficial air velocity of 8.8 ft/sec. Bed
temperature is 1470°F.14 This unit is presently being shut down for repair.t
^Personal communication between Doug Roeck, GCA and John Doyle, Babcock and
Wilcox, October 28, 1981.
•(Personal communication between Doug Roeck, GCA and Jerry Shang, U.S.
Department of Energy, Morgantown Energy Technology Center, November 4, 1981,
8
-------
TABLE 2.
SUMMARY OF THE
OF ELEMENTS IN
RANGE OF OBSERVED CONCENTRATIONS
RAW AND SPENT SHALE LEACHATEa
Parameter
Al
As
B
Ba
Be
Ca
Cl
C03
Cr
Cu
EC
F
Fe
HC03
Hg
K
Li
Mg
Mn
Mo
Na
Ni
N03
Pb
PH
Se
Si
Sn
S04
TDS
Zn
Units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
p mhos /cm
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
-
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Colony
raw 'Shale
<0. 05-0. 75
<0.005
<0. 025-2. 75
0.07-0.48
<0.025
40-1550
1.1-22
0.03-1.6
<0. 025-0. 04
<0. 025-0. 41
240-5400
4.0-7.2
<0. 03-0. 89
50-558
<0.0005
1.7-59
0.02-0.151
5.5-140
0.074-2.74
0.09-0.65
5.8-145
<0. 05-0. 10
0.9-25
<0. 05-0. 64
7.06-8.18
<0.01
2.12-10.58
0.12-0.67
28-5150
110-7160
<0. 02-0. 68
Union natural
retorted shale
<0. 05-0.1
<0.005
0.165-0.39
0.028-0.35
<0.025
10-49
1.1-15
<1.0-22
<0. 025-0. 71
<0. 025-0. 33
300-1300
5.4-6.6
<0.05
168-585
<0.0001
9.2-74
0.14-0.51
30-108
<0.05
0.065-0.45
12-75
<0.05
0.5-8
0.05-0.16
7.2-8.81
<0.005
8.8-19.1
-
9-128
460-1200
0.02-0.15
Source: Reference 12.
-------
In the United States, there are no known commercial applications, although
research Is being conducted by several companies and government agencies. The
U.S. Department of Energy (DOE) has conducted tests on oil shale from Colorado,
Israel, and Morocco at their Morgantown Energy Technology Center (METC).
Babcock and Wilcox (B&W), Research and Development Division, has done combus-
tion tests on oil shale from Colorado in their Alliance, Ohio experimental
facility. Other companies involved in raw shale combustion investigations,
some of which cannot release data because of confidentiality, Include
Dorr-Oliver, Inc., Lurgi Corporation-Eastern Division, Hazen Research, Inc.,
Foster-Wheeler Development Corp., and Science Applications, Inc. (see
Table 1). Published results from DOE, B&W, and Foster-Wheeler are described
in the following paragraphs.
Department of Energy Experiments
In September 1978, oil shale from Colorado was successfully burned in
the METC's 18-inch diameter fluidized bed combustor. In July 1979, similar
testing was done on Israeli oil shale in both the 6-inch and 18-inch FBC
units. During 1980, DOE conducted additional tests on Moroccan oil shale
in the 6-inch unit.
The 6-inch laboratory-scale FBC is a refractory-lined cylindrical
vessel with a conical air distributor plate that has an open area equal to
2.8 percent of the total distributor area. The bed region is 16 inches
high and the expanded freeboard section is 8 inches in diameter and 64
inches high. Fluidizing air from the plenum passes through 64, 1/8-inch
diameter nozzles arranged in three concentric circles. Fuel from the hopper
is fed directly into the bed by a 1-inch, variable-speed metering screw which
is cooled by a water jacket.
The 18-inch FBC unit is 45 inches high with an expanded freeboard sec-
tion 24 inches in diameter and 27 inches high. The combustor is equipped
with horizontal water or steam cooled heat exchangers submerged in the bed,
comprised of six hairpin configuration, 1/2-inch, 316 stainless steel tubes,
any one of which can be placed in service. The freeboard area is equipped
with a single-pass heat exchanger used to provide heat transfer data and to
control exhaust gas temperature. Fuel is metered from a hopper which is
suspended from a weigh cell by a 1.1875-inch variable speed screw. Feed
rates of 280 Ib/hr were used with the oil shales. Bed temperatures are main-
tained by varying the bed level or fuel feed rate and through manipulation
of the bed heat exchangers.
Two different processes were explored in conducting the preliminary oil
shale combustion studies:
• The oil shales were combusted intensively for maximum combustion
efficiency with the objective of producing process heat for power
generation. (Test results reported subsequently were generated
while operating in this mode).
10
-------
• The oil shales were heated in a fluidized bed where partial
combustion was allowed to occur for the purpose of driving off
the hydrocarbons for fuels recovery. Since the current METC
facilities do not provide for recovery of hydrocarbon vapors,
these vapors were burned in the over-bed space.
Colorado Oil Shale—11
The Colorado oil shale combusted at METC came from the Piceance Creek
Basin section of the Green River formation and yielded a Fisher Assay from
10 to 25 gal/ton. The purpose of the combustion studies was to explore the
feasibility of direct combustion of Colorado oil shale in an AFBC and to
determine combustion characteristics by studying combustion efficiency,
sulfur retention, pollutant emissions, and extent of carbonate calcination.
(The Colorado shale contained about 18 percent by weight limestone).
The combustion of the Colorado shale led to the following conclusions:
• NOX emissions were mainly a function of air-to-oil shale ratio;
when this ratio exceeded 2.25 Ib air/lb oil shale, NOX emissions
exceeded 0.6 lb/10^ Btu. (The percent excess air during these
tests ranged from 33 to 66).
• SOX emissions were not affected by the air-to-oil shale ratio
and were mostly less than 0.2 lb/10*> Btu.
• Percent sulfur retention was found to be a function of bed
temperature and the percent of limestone calcined. High sulfur
retention (90 to 95 percent) was achieved with about 60 per-
cent of the limestone calcined at a bed temperature of 1300° to
1350°F. At a bed temperature of 1500°F, with 90 percent of
the limestone calcined, sulfur retention was below 90 percent.
• Combustion efficiency for the Colorado shale was found to be a
function of both air-to-oil shale ratio and bed temperature.
Greater than 99 percent efficiency was attained at an air-to-
oil shale ratio of 2.0 to 2.5 and a bed temperature range of
1300° to 1500°F.
Israeli Oil Shale—11'15
DOE has also test burned Israeli oil shale in the 6- and 18-inch com-
bustors. This shale came from the Efe deposit discovered in 1962 during a
survey of phosphorite in that area. The ultimate and ash analyses for this
shale are given in Table 3. The volatile matter and calcium carbonate con-
tents are 38 and 47 percent, respectively. Based on the ash analysis, this
oil shale has an inherent calcium to sulfur molar ratio of about 7.3.
The operating conditions explored during combustion of the Israel oil
shale in the 6- and 18-inch diameter units are shown in Table 4. The lowest
operating temperature occurred when burning shale with 18 percent moisture
without preheated air. The highest bed temperature, 1490°F, was attained
when the oil shale contained only 5 percent moisture and was burned in the
11
-------
TABLE 3. CHEMICAL ANALYSIS OF ISRAELI OIL SHALE3
Component (%)
Ultimate Analysis:
Moisture
Ash
Sulfur
Hydrogen
Nitrogen
Total carbon
Oxygen
Carbonate as C02
Heating value, Btu/lb
Volatile matter
Calcium carbonate
Ash Analysis:
Silicon, Si02
Aluminum, A120,
Iron, Fe_0_
Calcium, CaO
Magnesium, MgO
Sodium, Na-0
Potassium, K~0
Phosphorus , P^O
Titanium, Ti02
Sulfur, SO,
Shale fed to
6 in. FBC
7.93
55.28
2.43
1.45
0.44
14.69b
17.78
20.80
1,902
38.0
47.0
20.85
8.27
3.66
55.04
0.68
2.46
0.52
0.37
6.56
Shale fed to
18 in. FBC
8.15
56.93
2.35
2.05
0.29
14.94C
15.29
22.36
1,893
23.17
9.24
4.48
51.85
1.17
0.50
0.62
2.42
0.35
5.99
o
Source: Reference 15.
bCarbon (C02) = 5.62%, Organic carbon = 9.07%.
CCarbon (C02> = 6.10%, Organic carbon = 8.84%
12
-------
6-inch unit with air preheated to 600°F. Carbon combustion efficiencies of
98 percent or better were attained in the 6-inch combustion unit without
recycling of fines while efficiencies of 96 percent or better were achieved
in the 18-inch unit with recycling. The higher combustion efficiencies for
the laboratory-scale unit were attributed to that unit's higher freeboard
section which provided for a longer gas residence time. This was confirmed
by the much lower carbon monoxide and hydrocarbon concentrations detected
in the flue gases. Heat losses due to calcium carbonate decomposition were
minimized by maintaining low bed temperatures. Calcium carbonate decomposi-
tion was found to range from a low of 28 percent at 1180°F to a high of 86
percent at 1490°F.
TABLE 4. OPERATING CONDITIONS FOR FLUIDIZED-BED COMBUSTION OF
ISRAELI OIL SHALE3
Combustion unit
Parameters 6-inch diameter 18-inch diameter
Moisture content, % 2.0 - 18.5 8.0 - 16.0
Feed size, in. or mesh 1/8" x 0 & 14 mesh 1/4" x 0
Fuel feed rate, Ib/hr 18.5 - 52 180 - 300
Excess air, % 12-50 28 - 72
Preheated air temp. °F 70 - 675 70
Bed temperature, °F 1180 - 1490 1250 - 1400
Bed depth, in. 12 36
Superficial velocity, ft/sec 2.5 - 6.0 2.8 - 4.5
Source: Reference 15.
Because of the high ash, moisture, and calcium carbonate contents of
the Israeli oil shale, large quantities were required in order to maintain
the desired bed temperature. Such handling of the feed material and the
spent bed would be one of the specific operating problems that would need
to be considered in designing any commercial unit.
Some of the specific conclusions drawn from these combustion tests were
as follows:
13
-------
• Devolatilization of the Israeli oil shale was completed at
a temperature of 1076°F.
• Emissions of NOx and S02 from the 18-inch unit were low
(0.4 Ib NOX/106 Btu and 0.7 Ib S02/106 Btu).
• Overall heat transfer coefficients of 53.4 and 7.5
Btu/ft2-hr-°F were obtained for in-bed and freeboard
heat exchange tubes in the 18-inch combustor.
• A hybrid combustion system would be the best means for
the direct combustion of Israeli oil shale: devolatili-
zation would take place in the main section of the
fluidized bed reactor operated at substoichiometric con-
ditions and at a bed temperature less than 1300°F; sub-
sequent combustion of volatiles would be carried out in
the freeboard section. Heat in the spent bed material
could be partially recovered through a moving-bed cooler
for preheating the fluidizing air.
Moroccan Oil Shale —
Limited tests were conducted on Moroccan oil shale in DOE's 6-inch com-
bustion unit. This shale had a heating value of 2400 to 2700 Btu/lb and a
sulfur content of ^2.3 percent. The ultimate analysis showed about 62
percent ash, from 4 to 7 percent moisture, and about 16 percent total carbon.
Experimental results from burning this shale are shown in Table 5.
B&W Experiments
The Research and Development Division of Babcock and Wilcox in Alliance,
Ohio has performed various tests on both raw shale and coal-shale mixtures
(these latter tests are discussed further on in this section). The pilot
facility used is referred to as a 1 ft x 1 ft fluid bed combustion unit and
is 13-1/2 inches square by 16 ft high. The unit is equipped with an in-bed
heat exchanger and a high efficiency cyclone separator. A gas burner is
used to preheat the combustion zone prior to the introduction of solid fuels.
Fuel and reagent feed rates are independently controlled by variable speed
screws which discharge into a common chute through which material falls by
gravity to a rotary valve. At the rotary valve discharge point, material is
pneumatically picked up by an air eductor and sent to the furnace at suffi-
cient pressure to overcome furnace resistance.
The oil shale used in the B&W test program was obtained from the
Occidental Petroleum mine located in the Debeque, Colorado area. This shale
had a heating value of about 1000 Btu/lb (dry basis) , a Fisher-Assay of
10 gal/ton, an ash content of about 71 percent and a sulfur content of 0.2
percent. Planned and actual test conditions are provided in Table 6 while
experimental results are shown in Table 7.
14
-------
TABLE 5. TEST RESULTS DURING COMBUSTION OF MOROCCAN OIL SHALE*
Operating Conditions
Bed temperature, °F
Excess air, % vol.
Superficial velocity, ft /sec
Bed Ht. (static), inches
Fuel size, mesh
Ca/S molar ratio
Results
Combustion efficiency, %
CaCOo calcination, %
c
Heat loss through calcination, %
Flue Gas Analysis:
C02, % vol.
CO, % vol.
02, % vol.
S02, ppm
S02, lb/106 Btu
NO/NOX, ppm
NOX, lb/106 Btu
THC, ppm
Bed temperature, °F
Fluidization velocity, ft /sec
Bed depth (static) , inches
Excess air, %
1250 to 1600
Stoichiometric to 85
2
99.24
77.62
3.45
12.5
0.05
7.0
100
0.27
800
1.09
100
1400
2.84
6
47.73
2.0 to 4.0
4 to 6
12 x 0
•V4 to 5
Riin Mr*
txun wo •
3
98.79
75.50
3.52
14.5
0.93
0.0
100
0.33
900
0.92
4000
1400
1.97
6
0.0
4
97.91
79.71
4.81
14.0
0.14
6.25
100
0.29
700
1.0
100
1450
3.96
4
40.0
a
Source: Reference 11.
Based on solid analyses.
"(Heat loss/total heat input) x 100.
15
-------
TABLE 6. B&W TEST CONDITIONS - 100 PERCENT OIL SHALE3
Test No.
Oil shale size
Superficial velocity, ft/sec
Bed depth, in.
Flue gas 0-, %
Windbox air temp., °F
Transport air, Ib/hr
4 5
Planned Actual Planned
1/4x0 1/4x0 1/4x0
7 to 8 7.5 7 to 8
30 to 36 33 30 to 36
2.8 to 3.5 2.8 2.8 to 3.5
400 432 400
108
Actual
1/4x0
7.4
39
3.0
443
108
6
Planned Actual
1/4x0 1/4x0
7 to 8 7.2
30 to 36 33
2.8 to 3.5 1.4
400 424
106
fl
Source: Reference 16.
-------
TABLE 7. B&W TEST RESULTS
= =...« .. -r : - - : : -s. ? -ri *
Test No.
Date
Oil shale, Ib/hr
Heat input, 106 Btu/hr
Bed temp. , °F
r* /o i *. •
irfci/o itioiar racio
S02 out, lb/106 Btu
S02 reduction, %
NOX out, lb/106 Btu
4
11/3/78
360
0.339
1473
_
0.05
99
3.0
5
11/3/78
355
0.335
1450
i\J, 7
«H /
0.05
99
3.0
6
11/3/78
358
0.338
1398
_
0.05
99
2.92
a
Source: Reference 16.
The goal of the test program—to successfully burn oil shale as a fuel
without the need for auxiliary fuel— was achieved. However, due to the low
heat content of the shale, a normal heat input to the unit (0.7 x 106 Btu/hr)
could not be attained. The B&W tests showed that oil shale could be burned
as a primary fuel in a fluid bed combustor without the need for auxiliary
fuels to maintain combustion. The major drawback to this mode of operation
was the high NOX emissions (3.0 lb/10° Btu). In reviewing the chemical anal-
ysis of the fuels, B&W noted that the total theoretical fuel-bound nitrogen
contained in the oil shale was approximately double that of the coal tested
on a lb/106 Btu basis. The percentage of the total fuel-bound nitrogen which
appeared in the outlet gas averaged about 42 percent compared to an average
of 13 percent for the coal-oil shale mixtures. B&W concluded that the con-
version of fuel-bound nitrogen to NOX for oil shale was similar to that of a
typical oil.
Other Investigations
Foster-Wheeler Development Corporation has also performed combustion
tests on oil shale in a fluidized bed.l^ Their fluid bed combustor consists
of a refractory-lined steel cylinder 7 ft in height, 1.5 ft internal diameter
at the bottom, and 2.0 ft internal diameter in the freeboard section. The
unit is equipped with two compound-flow multiple-pass tube bundles, one in
the bed zone, the other in the convection pass. Products of combustion leave
the furnace through a water-cooled stack and then pass through two stages of
cyclone separators. Following the cyclones, gases can either be piped through
a dilution flow mixer and then into a baghouse filter or directly out of the
building. Bed material and fuel are metered from bulk hoppers to a common
feed air lock by variable-speed screw feeders. After mixing in the air lock,
the bed/fuel mixture is pneumatically conveyed to a vertical feed pipe which
discharges material about 3 ft above the bed. While most of Foster-Wheeler's
tests were on coke breeze and various grades of coal, one test was conducted
with oil shale from Utah. This oil shale contained 73 percent ash, 1.15 per-
cent sulfur, and 22.5 percent carbon. Test results were as follows:
17
-------
superficial velocity, 8.6 ft/sec; average bed temperature, 1550°F; 14 percent
excess air; combustion efficiency (no recycle), 99 percent; and NOX emissions,
430 ppm (v). No specific conclusions were drawn concerning this one oil shale
test run.
Other companies are known to have conducted proprietary tests on the
combustion of raw oil shale in fluidized-bed combustors. These include:
Dorr-Oliver, Inc. (Stamford, Conn.); Hazen Research, Inc. (Golden, Colo);
Lurgi Corp.-Eastern Division (River Edge, N.J.); and Science Applications,
Inc. (Golden, Colo.).
SPENT SHALE COMBUSTION
Spent shale refers to oil shale that has been retorted by any one of
various processes for recovery of oil. The properties of the retorted or
spent shale depend on the raw shale characteristics and on the type of
retorting procedure used. Spent shale from an indirectly heated retort will
contain an organic carbonaceous residue which remains after pyrolysis of the
kerogen—the organic component of shale rock. For example, the indirectly
heated TOSCO II retort produces a spent shale resembling black talcum powder.
The chemical composition of this spent shale is shown in Table 8.
TABLE 8. CHEMICAL COMPOSITION OF TOSCO II
SPENT SHALE3
Component Weight %
SO 3
Total carbon
Inorganic carbon
Organic carbon
Si02
A1203
Fe203
CaO
MgO
Na20
K20
2.63
9.83
4.41
5.41
33.07
9.14
3.24
17.56
7.74
0.77
1.39
Source: Reference 18.
18
-------
Although more of the carbon residue is consumed in the combustion process,
spent shale from directly heated retorts still contains a small percentage of
carbon. The directly heated Union "A" retort produces a gray decarbonized
spent shale resembling coal ash and clinkers. The composition of the spent
shale from Union Oil Co.'s "A", "B" (indirectly heated), and SGR (indirectly
heated) retorts is given in Table 9. From a process in which none of the
carbon residue is burned in the retorting process, the organic carbon may
represent about 140 Btu/lb for every 1 percent of residual organic carbon
(based upon a heat of combustion for carbon of 14,087 Btu/lb). While reported
values of residual carbon in spent shale from the various retorting processes
range from 0.3 (Union SGR) to 5.4 percent (TOSCO II), thus indicating poten-
tial heat contents of as much as 750 Btu/lb, actual values may realistically
be lower since modifications to indirectly heated retorting processes will
attempt to utilize much of this available heat energy. For example, TOSCO
has patented processes to burn the retorted shale as fuel for their ball
heater while the indirect Lurgi-Ruhrgas process also incorporates integral
use of available carbon residue.19
TABLE 9. COMPOSITION OF UNION SPENT OIL SHALES3
Union Ab
Union Bc
PH
gravel to
silty gravel
12.5 - 13.0
gravel
8.7
Source: Reference 19.
Directly heated.
"Indirectly heated.
Union SGRC
Si02
CaO
MgO
A1203
Fe203
Na20
K20
SO 3
P205
Mineral C02
Organic C
Inorganic C
Texture
35.3
27.2
9
8.5
7.3
5.5
2.8
0.1
2.2
1.6
0.5
-
graded
31.5
19.6
5.7
6.9
2.8
2.2
1.6
1.9
0.4
22.9
4.3
-
silty
39.2
27.3
8.2
8.9
3.8
3.7
2.7
1.4
0.5
3.1
0.3
-
silty
gravel
12.5
19
-------
Four companies are known to be Investigating combustion of spent shale;
however, no test data are available due to confidentiality. Hazen Research,
Inc. (Golden, Colo.) has conducted tests for a fluidized bed combustor
manufacturer.* Foster-Wheeler Development Corp. (Livingston, N.J.) has
performed spent shale combustion tests and state that they hope eventually
to be able to offer industrial size units up to 500,000 to 600,000 Ib/hr steam
for the burning of shale.t TOSCO (The Oil Shale Corp.—Denver, Colo.) is also
investigating direct combustion of spent shale.t Because their program was
proprietary, it could not be determined if direct combustion in a fluidized-
bed combustor was the method being evaluated. Energy Resources Co. (Cambridge,
Mass.) has previously conducted spent shale tests in their 20-inch I.D. combus-
tor. These tests were done on spent shale from TOSCO's retorting process and
the results showed that this shale could be successfully combusted.! It would
seem reasonable that other companies involved in oil shale projects are also
investigating the prospects of spent shale combustion.
COMBUSTION OF COAL-SHALE MIXTURES
Various research efforts have been conducted with respect to the burning
of oil shale-coal mixtures for the purpose of S02 removal from the coal.
Because oil shale contains appreciable amounts of calcium, it is felt that
the shale can be used as a replacement for limestone in conventional firing
of FBC boilers. One difference between the firing of such mixtures and the
direct combustion of spent or virgin shale for pure energy recovery is that
bed temperatures are higher in the former case so as to promote the calcina-
tion reaction of CaCOs to CaO. This will enhance S02 capture because the
calcium oxide is the eventual reactant with the sulfur dioxide pollutant.
The following paragraphs describe ongoing and past work in this area.
Testing of coal-oil shale mixtures has been performed at the Research
and Development Division of Babcock and Wilcox in Alliance, Ohio. Results
of this test program were presented at a recent symposium and are summarized
here.16 The FBC unit operated by B&W was started with Ohio No. 6 coal as the
fuel and a bed of spent limestone from a previous test. (No fresh limestone
was used in the B&W program described herein). The unit went through a normal
startup mode with coal as the fuel source until steady-state conditions were
achieved (as determined by a leveling out of the S02 outlet concentration).
Once steady-state was achieved, a transition was made from coal to oil shale
by slowly adding shale while backing off on the coal feed. Bed temperature
dropped during this transition due to the low heat content of the shale and
*
Personal communication between Doug Roeck, GCA and Rod Hodgson, Hazen
Research, Inc. May 19, 1981.
Personal communication between Doug Roeck, GCA and Joseph F. McMahon,
Foster-Wheeler Development Corp. May 22, 1981.
iPersonal communication between Doug Roeck, GCA and Warren Broman, TOSCO
June 26, 1981.
§
Personal communication between Doug Roeck, GCA and Robert Davis, Energy
Resources Co. June 29, 1981.
20
-------
because the quantity of transport air had to be increased to compensate for
the higher solids loading in the feed system. To maintain bed temperature
near the 1500°F level, the effective heat transfer surface in the bed was
reduced.
During the transition from coal to oil shale it was noted that the out-
let S(>2 concentration dropped significantly as soon as the oil shale had
been added. A series of tests were performed to investigate this phenomenon
and are shown in Table 10. Tests 3 and 7-12 were designed to study the effect
of the shale on S02 reduction. Also shown in this table are two earlier
tests (13 and 14) that had been conducted with high sulfur coal and a high
grade limestone as the reagent. As can be noted from the results, the oil
shale was far superior to the limestone in regards to reacting with sulfur
dioxide on a molar basis. The NOX emissions were equivalent to that of the
coal-limestone mixture tests conducted previously. Total carbon conversion
of the coal and oil shale was at least equivalent to that of the coal alone.
A plot of S02 reduction versus Ca/S molar ratio for the coal-oil shale and
the coal-limestone tests is shown in Figure 2. Although the total quantity
of oil shale required for a given S02 reduction is about double that of the
limestone requirement, this is partially offset by the fact that the oil shale
is a contributor to the system heat input. As a result of these studies, B&W
concluded that a coal-oil shale mixture is an attractive fuel for use in a
fluid bed combustor; the heat content of the oil shale can be efficiently
converted to energy and high sulfur coal can be burned with oil shale to
effectively reduce S02 emissions.
Other testing of coal-oil shale mixtures has been performed by the
Department of Energy at the Morgantown Energy Technology Center (METC) and
the Argonne National Laboratory (ANL).
Testing at METC, done in early 1979, involved the burning of Colorado
oil shale containing 18 percent limestone and Pittsburgh seam bituminous
coal having a sulfur content of 4.5 percent.H These tests showed 95+ percent
sulfur retention at bed temperatures of 1500° to 1600°F. Observations with
an electron microscope revealed that the limestone in the oil shale had
"blossomed" into a flower-like fossil structure, thereby making surface area
available for SC>2 absorption. The presence of coal was found to reduce the
nitrogen oxides emissions to well below 0.6 lb/10" Btu, possibly due to
reduction of the oxides by the coal char.
Additional testing for DOE has been done at the Argonne National
Laboratory (ANL) in Argonne, Illinois.20-22 These tests were designed to
compare virgin and spent Green River oil shale with two limestones (Germany
Valley and Greer) and one dolomite (Tymochtee) for S02 reactivity and attri-
tion rate. The compositions of these materials are indicated in Table 11.
As seen in this table, the virgin oil shale contained 28 percent limestone
and the spent shale (prepared by heating virgin shale in air at 750°F for
3 hours) contained 34 percent limestone. Oil shale reactions with S02 were
studied with a thermogravimetric analyzer (TGA) at temperatures of 1300° to
1920°F. The conversion of CaO to CaS04 in virgin shale was slightly lower
21
-------
TABLE 10. TEST RESULTS FROM COAL-OIL SHALE COMBUSTION TESTS CONDUCTED
AT BABCOCK & WILCOX, ALLIANCE, OHIOa
Test number
Dace
Coal, Ib/hr
Oil shale, Ib/hr
Limestone, Ib/hr
Heat input, 106 Btu/hr
Calcium/sulfur
Ib oil shale/lb ccal
Bed temp. , °F
Bed depth, in.
Gas velocity, ft /sec
S02 out, lb/106 Btu
502 reduction, %
NOX out, lb/106 Btu
Carbon conversion, %
aSource: Reference 16.
1
10/27/78
41
130
0.626
6.9
3.2
1605
36
7.5
O.I
98
-
10/27/78
24.5
282
0.567
25.1
11.5
1565
36
7.6
0.1
99
-
3
11/01/78
53
43
0.691
1.8
0.81
1554
36
7.1
1.1
82
0.38
93.0
7
11/30/78
35.6
23.9
0.468
1.6
0.67
1596
30
5.9
1.3
78
0.49
94.5
8
01/11/79
47.9
56.6
0.649
3.0
1.11
1530
36
7.2
0.8
86
0.44
93.7
9
01/11/79
50.1
41.0
0.660
2.1
0.82
1571
36
7.2
1.3
78
0.38
89.6
10
01/31/79
48.6
37.1
0.647
1.7
0.76
1552
33
7.2
1.6
74
0.39
88.7
11
02/02/79
46.7
54.1
0.639
2.4
1.16
1558
36
7.4
1.0
84
0.38
88.5
12
02/06/79
51.8
40.0
0.689
1.7
0.77
1589
36
7.5
2.1
66
0.35
99.1
13
03/07/78
51.0
26.5
0.612
5.6
0.52
1525
35
6.6
b
82
84.0
14
10/05/78
78.0
36.0
0.822
3.6
0.46
1555
30
6.8
1.3
80
0.4
93.0
502 outlet concentration was measured but not recorded.
NOTES:
(1) Tests 1-3 and 7-12--with Ohio No. 6 coal,
12,000 Btu/lb, 3.6% S and Colorado oil shale,
900 to 1000 Btu/lb, 0.2* S.
(2) Test 13—with Pittsburgh No. 8 coal, 12,800 Btu/lb,
3.0% S and Lowellville limestone, 92% CaC03
(3) Test 14— with Illinois No. 10 coal, 10,500 Btu/lb,
4.5% S and Lowellville limestone, 92% CaO>3.
-------
100
90
80
o
o
D
O
LU
(T
CM
O
Vt
70
60
50
40
30
«
e
KEY:
• OHIO #6 WITH OIL SHALE
D ILLINOIS -#10 WITH
LOWELLVILLE LIMESTONE
Ib OIL SHALE/Ib COAL =1.0
1.0 2.0 3.0 4.0
Co/S MOLAR FEED RATIO
5.0
Figure 2.
Sulfur dioxide reduction for coal-limestone and
coal-oil shale mixtures.
Source: Reference 16.
23
-------
(73 percent) than for the spent shale (86 percent). A plot of this conver-
sion rate for spent shale is shown in Figure 3.
TABLE 11. CONCENTRATIONS (in wt %) OF MAJOR CONSTITUENTS OF
CALCAREOUS MATERIALS3
CaC03 MgC03 Fe203 A1203 Si02 Na20 K20 S
Virgin Oil
Shale 27.7 13.8 2.60 4.14 30.1 2.19 1.21 0.89
Spent Oil
Shale 33.5 16.7 3.14 5.0 36.4 2.64 1.46 0.66
Tymochtee
Dolomite 51.8 43.3 0.41 1.46 3.61 0.07
Greer
Limestone 80.4 3.50 1.24 3.18 10.34 2.23
Germany
Valley
Limestone 97.75 0.6 0.1 1.8 0.2 0.25
Source: Reference 21.
The inverse variation of reaction rate with temperature shown in Figure 3
was attributed to other competing reactions at the higher temperatures. How-
ever, the shale sulfated between 700° and 800°C (1300° and 1500°F) resulted in
the formation of a complex, highly water-soluble salt that might pose a waste
disposal problem. Therefore, the experimental kinetic data at 900°C (1650°F)
were later used to estimate the quantity of oil shale necessary to meet an
S02 emission standard of 1.2 lb/10^ Btu. The comparison of spent shale, dolo-
mite and the two limestones at this temperature is shown in Figure 4. It is
seen that although during the first hour of reaction the percent of Ca changed
to CaS04 was higher for the oil shale than for the highly reactive Tymochtee
dolomite, by the end of the 3 hoars, 98 percent of the CaO in the dolomite had
been utilized to capture S02 compared with 84 percent for the spent shale.
The reaction rates for the two limestones were much lower than those for the
shale and dolomite.
The S02 reactivity data were converted to S02 retention versus Ca/S ratio
for prediction of the quantity of calcareous material necessary per unit of
coal to meet the S02 emission standard. Figure 5 shows these results at the
different temperatures studied.
The results of these analyses in terms of quantities of materials re-
quired are given in Table 12. The major conclusions of the ANL studies were
as follows:
24
-------
o
00
o
O
o
o
O
Ld
_)
m
u_
o
cr
UJ
>
2
O
O
REACTION ' EMP
700°C
750°C
800°C
o 900°C
(1300°F)
(1380°F)
(1470°F)
(1650°F)
IOOO°C (1830°F)
I050°C (1920°F)
TIME, h
Figure 3. Conversion (measured with a TGA) of Precalcined CaO to
in Spent Green River Oil Shale at 700° to 1050°C (1300° to
1920°F). Reaction conditions: precalcined, 20% C02-bal N2
(-50 +70 mesh); sulfation gas, 0.3% S02-5% 02-20% C02 in N2.
Source: Reference 20.
25
-------
100
T
SPENT OIL SHALE
TYMOCHTEE DOLOMITE
GREER LIMESTONE
GERMANY VALLEY
Figure 4. Conversion (measured with a TGA) of CaO to
in Spent Oil Shale, Tymochtee Dolomite, Greer
Limestone, and Germany Valley Limestone, using
0.3% S02-5% 02 in N2 at 900°C (1650°F).
Source: Reference 21.
26
-------
345678
INTERNAL Ca/S RATIO
Figure 5. Predicted S02 retention vs. Ca/S ratio for Oil Shale
at various temperatures for a gas velocity of 12.5
ft/sec and a bed height of 3.5 ft. Based on TGA data.
Source: Reference 20.
27
-------
CO
oo
TABLE 12. REQUIRED QUANTITIES OF GREEN RIVER OIL SHALE, GERMANY VALLEY LIMESTONE, GREEK
LIMESTONE, AND TYMOCHTEE DOLOMITE TO MEET AN S02 STANDARD OF 1.2 lb/106 Btua
Calcium-based
stone
Spent oil shale
Virgin oil shalec
Germany Valley
limestone
Greer limestone
Tymochtee
dolomite
CaVS ratio required
1.23% S 2.0% S 3.0% S 4.3% S
0.5 1.2 1.9 not
possible
0.6 1.1 3.1 4.3
1.3 2.5 3.8 7.5
1.6 2.8 3.1 3.8
0.4 0.7 1.0 1.5
Unit wt. stone/unit wt.
coal required
1.23% S 2.0% S 3.0% S 4.3% S
0.06 0.20 0.58 not
possible
0.10 0.25 1.4 3.3
0.05 0.16 0.36 1.0
0.08 0.23 0.36 0.6
0.03 0.03 0.18 0.4
Basis: 12,183 Btu/lb coal. FBC operates at 12.5 ft/sec and 3.5 ft bed depth.
Spent shale contains 0.66% S.
°Virgin shale contains 0.9% S and has a heating value of 3,020 Btu/lb.
Source: Reference 22.
-------
• more oil shale than either limestone or dolomite would
be required for equivalent SO2 reduction
• the use of oil shale as an SO2 sorbent may be desirable
if the FBC is operated at low gas velocity (<12.5 ft/sec)
or with low sulfur coals (<3 percent)
• Green River oil shale should not be used in an FBC that
employs a carbon burnup cell (CBC) because the high
silica content (V30 percent) of this shale would lead to
SO2 being released at the high temperatures (1800° to
2000°F) encountered in a CBC
• the attrition rate of virgin oil shale was found to be
similar to that of the dolomite and limestone tested.
It was noted by the ANL investigators that their results apply specif-
ically to atmospheric FBCs operated at a high superficial gas velocity.
Decreasing the velocity and/or increasing the combustion chamber pressure
may decrease shale requirements considerably. In addition, only Green River
oil shale was used in the test program and since 802 reactivity and attrition
rates of limestones vary widely, a large variation would also be expected for
shales of differing compositions.
PRELIMINARY ECONOMIC ANALYSIS
Of the three options considered in the previous discussions (combustion
of raw and spent shale, and coal-shale mixtures), the most viable alternative
would seem to be the use of oil shale as a sorbent with coal. Therefore, an
economic analysis has been performed so that operating costs for such coal-oil
shale firing can be compared to a conventional FBC system using limestone
sorbent. The base case for this analysis is a DOE study23 which assessed the
costs for a 250,000 Ib/hr (steam) FBC unit. The coal used for this study was
a mid-western bituminous coal with a high heating value of 10,430 Btu/lb, a
sulfur content of 3.5 percent, and an ash content of 9.2 percent. Based upon
a coal firing rate of 34,012 Ib/hr, the heat input is 355 x 106 Btu/hr. The
system is designed to meet an SO2 emission standard of 1.2 lb/10" Btu input
plus 85 percent reduction and a particulate emission standard of 0.03 lb/10^
Btu input plus 99 percent reduction and 20 percent opacity.
The costs determined by DOE for the FBC system are shown in Table 13.
For the purposes of determining costs for comparison with the $4.28/1000 Ib
steam direct operating cost figure shown in Table 13, three sets of oil shale-
coal test data summarized in this report were chosen for economic analysis
(one developed by B&W and two determined by thermogravimetric analysis at
Argonne National Laboratory). These three sets of data were discussed
previously in conjunction with Table 10 (Test No. 11) and Table 12. (These
data are also described and expounded upon more fully in Section 3, Table 16b—
B&W Test No. 11 and ANL Test No's. 17 and 20).
29
-------
TABLE 13. DIRECT OPERATING COSTS FOR A CONVENTIONAL
FLUIDIZED BED COMBUSTION SYSTEM3
Coal
Limestone
Electricity
Oil
Labor
Solid waste
removal
Unit costb
$35 /ton
$25/tonC
$0.0325/kwh
$0.50/gal
$16/mhr
$6/ton
Cost
Load ($/1000 Ib steam)
34,012 Ib/hr
12,256 Ib/hr
2800 kw
35 gal/hr
11 men
13,484 Ib/hr
Total
$2.38
0.61
0.36
0.07
0.70
0.16
$4.28
The costs shown reflect first year operating costs and an
annual load factor of 68 percent.
Unit costs are site specific for Fort Wayne, Indiana area.
Q
Limestone is delivered precrushed to Fluid Bed facility.
Source: Reference 23.
The test data chosen for analysis are referred to as Case No's. 1, 2 and
3 in the remainder of the discussion. To facilitate comparison with the DOE
cost data, oil shale and coal feed rates as described by the B&W and ANL
investigators were scaled up to the 250,000 Ib/hr (steam) FBC size by equating
to the heat input rate of 355 x 106 Btu/hr. All calculations for this assess-
ment are included in Appendix B. Direct operating costs for the oil shale-coal
systems have been determined only for coal, shale, and solid waste removal.
Limestone costs are replaced with costs for shale while electricity, oil, and
labor costs are assumed to remain unchanged. The results of this preliminary
economic assessment are provided in Table 14. Sorbent costs (especially for
shale) are potentially subject to wide variation and therefore total direct
operating costs are computed for shale costs ranging from 5 to 30 dollars per
ton. The costs at the low end of this range are reasonable based upon informa-
tion supplied by two industry sources wherein the shale would be mined close
to the surface of the ground and made available to a plant at or very near
the mine mouth.* Unit costs above the $57ton figure for shale are basically
^Personal communication between Doug Roeck, GCA and John B. Doyle, Babcock and
Wilcox, and between Doug Roeck, GCA and Dr. Vyas, Davy McKee Company,
October 28, 1981.
30
-------
TABLE 14. COMPARISON OF DIRECT OPERATING COSTS FOR A 250,000 Ib/hr FBC BOILER BURNING
COAL WITH LIMESTONE AND OIL SHALE SORBENTS
Cost cata (S/1000 Ib steam)
Solid
Sorbent Sorbent waste
S02 Solid Coal removal Toi=l
Feed Feed Ca/S reduc- waste at at at at at at at direct
Test Sulfur rate Hm race Hm molar tlon rate IS35/ (S5' ISIO/ (S20/ (S25/ ($30' (S6/ oaeratlng
description CO (Ib/hr) Cicu/lb) Type (Ib/hr) (Stu'ib) ratio (.',) (Ib/hr) t-n) ton) ron) :on) ton) ton) ton) ccsr8
Base caseb 3 5 34,012 10.130 Limestone 12,256 - 3.0 85 13,461 2 38 - 0 25 0.16 3.SJ
0.49 0.16 i.'.i
0 61 0.16 -.15
0 74 0.16 i.-!
Case 'to. 1 3.6 26,377 12.300 Virgin 30,557 1,000 24 84 31,257 1.85 0.31 0.38 3.47
(BSW Test shale 0.61 0.38 3 97
No. 11) 1.22 0.38 i.58
1.83 0.38 5 .;
Case No. 2C 3.0 21,632 12,183 Virgin 30,285 3.020 31 87 5 23,168 1.51 0.30 0.28 3.12
{ANL Test shale 0.61 0.28 3 53
No. 17) 1.21 0.28 - .3
1.82 0 28 4.7.
U> Case No 3° 2.0 28,950 12,183 Spent 5,790 400 12 95 9 8,546 2 03 0.06 0.10 3.32
1-1 (ANL Test shale 0 12 0.10 3.3:
No. 20) 0.23 0.10 3 -9
0.35 0.10 3.41
shown in this table are other components of the total direct operating cost electricity, oil, and labor
Source. Reference 23.
'Tests done at Argonne National Laboratory (ANL) were by thermogravlnetric analysis
-------
indicative of costs that would be incurred for purchasing shale at increasingly
further distances from the shale source. Whereas the DOE base case utilized
only one cost for limestone ($25/ton), additional unit costs have been used
here for sake of comparison. Figure 6 depicts the total direct operating cost
for each of the cases as a function of the sorbent cost. In all, 9 of 12 data
points from the three example case curves are indicated to be lower than the
base case cost of $4.28/1000 Ib steam. It should be reiterated, however, that
test data for Case No's. 2 and 3 (Argonne National Laboratory Test No's. 17 and
20) were developed with thermogravimetric analyzer data which may not be as
realistic as pilot plant tests results such as those determined in B&W Test
No. 11 (Case No. 1).
A comparison of the annualized operating costs for each of the example
cases with the coal-limestone base case is shown in Table 15. For this
comparison, the indirect operating cost (which is a function of the system's
capital costs) is assumed to remain unchanged for all examples. In actuality,
the Indirect cost may be higher (for Case No's. 1 and 2) since total system
feed rates (coal plus shale) are higher than coal plus limestone for the
base case (see Table 14) thus requiring larger sized equipment and hence,
Increased capital expenditure. However, any such increases in capital invest-
ment are not expected to significantly affect this analysis. Compared to the
base case, annualized operating costs range from -15 to +13 percent for the
systems using oil shale as an 802 sorbent material.
Taking the scope and nature of the budgetary costs developed in the DOE
base case study into consideration as well as the assumption that indirect
costs would be the same for the coal-shale systems, the resulting annualized
cost estimates for both limestone and shale are probably accurate to + 30
percent and thus should be judged to be very similar.
32
-------
60
5.0
<
in
O
O
O
. 4.0
I-
co
O
O
4
flC
UJ
O.
O
H
U
UJ
(T
O
3.0
2.0
I
I
I
10 15 20
SORBENT COST. $/lon
25
30
Figure 6. Direct operating cost as a function of sorbent cost
for various coal-sorbent systems.
33
-------
TABLE 15. ANNUALIZED COST COMPARISON BETWEEN COAL-OIL SHALE SYSTEMS AND DOE BASE CASE
Cost, $/1000 Ib steam (percent change over base case)
Test Qase No. 1 with shale Case No. 2 with shale Case No. 3 with shale
description Coal- at 5/ton at $/ton at $/ton
parameter N. base case 5 10 20 30 5 10 20 30 5 10 20 30
Direct operating cost 4.28 3.67 3.97 4.58 5.1* 3.22 3.53 4.13 4.74 3.32 3.36 3.49 3.ol
(-14.3) (-7.2) (+7.0) (+21.3) (-24.8) (-17.5) (-3.5) (+10.7) (-22.4) (-21.0) (-18.5) (-15.7)
Indirect operating cost 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93 2.93
Annualized operating 7.21 6.60 6.90 7.51 8.12 6.15 6.46 7.06 7.67 b.^5 0.31 b.4^ 0.54
cost (-8.5) (-4.3) (+4.2) (+12.6) (-14.7) (-10.4) (-2.1) (+6.4) (-13.3) (-12.5) (-11.0) (-9.3)
-------
SECTION 3
SUMMARY AND CONCLUSIONS
The use of fluidized bed combustors in the United States for direct
combustion of oil shale is primarily in the research phase at this point
in time. Commercial applications of direct combustion of oil shale are
limited at this time, and exist only in China, West Germany, and the Soviet
Union. To date there are no commercial applications of this technology in
the United States.
As discussed in Section 2 of this report, most published research
efforts regarding direct combustion of oil share are or have been performed
by fluidized bed combustion equipment manufacturers and the U.S. Department
of Energy. Results to date have been encouraging in terms of the technical
feasibility of combusting both raw and spent shale.
Combustion of raw or virgin shale has been successfully demonstrated by
DOE's Morgantown Energy Technology Center and by Babcock and Wilcox Company.
DOE successfully burned oil shales from Colorado, Israel, and Morocco, all
with combustion efficiencies over 90 percent, while B&W performed favorable
tests on a different Colorado shale. Emissions of nitrogen oxides are a
potential concern when combusting raw oil shale and during the B&W test pro-
gram averaged about 3.0 lb/10^ Btu. Although all of these tests demonstrated
the combustibility of virgin oil shale, it is not expected that this will see
much widespread application. At present, oil shale research and development
efforts are more directed toward retorting technology. One exception could
be Eastern U.S. shale which has a low hydrogen to carbon ratio and is more
difficult to liquefy than Western shale. However, the HYTORT process being
developed at the Institute of Gas Technology (Phillips Petroleum Co. has
since purchased the rights to this process*) is aimed specifically at
retorting Eastern shale.
Spent shale combustion has also been demonstrated in fluidized bed
units with encouraging results. Because spent shale has been subjected to
retorting, the type of retort process employed will determine whether or not
the shale can be submitted to further useful combustion. Some retorts
^Personal communication between Doug Roeck, GCA and C. R. Thomas, Southern
Indiana Shale Oil, Inc. May 27, 1981.
35
-------
(directly heated) utilize all or part of the available organic carbon in the
shale as part of the overall process and therefore discharge a product
containing very little residual carbon, about 2 to 3 percent or less. Such
retorting proceses may produce an off-gas having a heat content of about
100 Btu/scf. Examples of such processes include the Faraho, Union "A", Lurgi-
Ruhrgas, and the Superior retorts.
Indirectly heated retorts, on the other hand, produce a spent shale that
may contain 4 to 5 percent residual carbon and an off-gas containing 800
Btu/scf. The Paraho (can be operated in both modes), Petrosix, Union "B",
TOSCO II, and Gas Combustion processes are all examples of indirectly heated
retorts. Because of these aforementioned spent shale characteristics, only
processed shale from indirect mode retorts could be considered for fluidized
bed combustion. Although several companies are reportedly investigating
direct combustion of spent shale in an AFBC, no data are yet publicly
available.
Testing of coal-shale mixtures has been performed by several groups since
it is felt that oil shale may meet the same three criteria as limestone for
use as an SO2 sorbent in an FBC unit:
1. high calcium carbonate content and hence high S02 reactivity
2. low cost
3. wide availability
Testing conducted by the Argonne National Laboratory, the Morgantown Energy
Technology Center, and Babcock and Wllcox Co. have all shown favorable S02
retention as compared to limestone and dolomite absorbents. Those tests con-
ducted at ANL showed that spent shale had better reaction kinetics than
virgin shale. Although more shale would be required than either limestone
or dolomite on a unit weight basis for equivalent S02 reduction, this can be
partially made up for by the heat contribution of the shale. The high calcium
content shales that would be desirable for burning with coal are generally
found in the Western U.S., whereas high sulfur coals are generally found in
the East. A transportation cost penalty would therefore be incurred if such
shales were to be used in conjunction with these coals. However, since New
Source Performance Standards for combustion units require some degree of
sulfur reduction for all coals regardless of sulfur content, the Western
shales could be used with the lower sulfur Western coals to achieve the desired
removal efficiency. In fact, the ANL tests showed that spent shale requirements
were about equivalent to both limestones tested when used with 1.23 and 2.0
percent sulfur coals. Another encouraging aspect of the coal-shale tests
(conducted by B&W) was that NOX emissions were consistently below 0.6 lb/10^
Btu.
A summary of all available combustion tests performed with raw shale
and coal-shale mixtures is provided in Table 16. Most of the data are from
the coal-shale tests conducted at Babcock and Wilcox and the Argonne National
Laboratory. To provide a means of comparing the tests wherein raw shale,
spent shale, limestone, and dolomite are used as SO. sorbents, calculations
36
-------
TABLE 16a. SUMMARY OF RESULTS FROM DIRECT COMBUSTION OF VIRGIN OIL SHALE
Test number
Parameters 12 3 45
Testing done bya METC METC METC B&W FW
Shale feed (Ib/hr) 18.5-52 180-300 - 358
Type Israel Israel Morocco Colorado Utah
Sulfur % 2.4 2.4 2.3 0.2 1.15
Ash % 56 56 62 71 73
HHV (Btu/lb) 1,900 1,900 2,400-2,700 1,000
Sorbent feed Ca/S mole ratio 7.3 7.3 4.6 ^47
Emissions
S02 (lb/106 Btu) 0.7 0.7 0.27-0.33 0.05
S02 reduction % ~97 ~97 99
NOX (lb/106 Btu) 0.4 0.4 0.92-1.09 V3.0
NOX, ppm(v) - - 700-900 - 430
METC = Morgantown Energy Technology Center
B&W = Babcock & Wilcox
FW = Foster-Wheeler
37
-------
TABLE 16b. SUMMARY OF RESULTS FROM DIRECT COMBUSTION OF OIL SHALE-COAL MIXTURES
U)
00
Coal-shale mixture tests using virgin shale
Parameters
Testing done bya
Shale feed
(Ib/hr)
Type
Sulfur Z
Ash Z
HHV (Btu/lb)
Coal feed (Ib/hr)
Type
Sulfur Z
Ash Z
HHV (Btu/lb)
Sorbent feed
(Ib/hr)
Ca/S mole ratio
Emissions
S02 (lb/106 Btu)
502 reduction Z
NOX (lb/106 Btu)
Solid waste rate
(Ib/hr)
6
43
^
0.2
71
1,000
53
3.6
%8.0
12,300
43
1.8
1.1
82
0.38
46.3
7
23.9
0.2
71
1,000
35.6
3.6
^8.0
12,300
23.9
1.6
1.3
78
0.49
26.4
8
56.6
0.2
71
1,000
47.9
3.6
•vfl.O
12,300
9
41.0
- Colorado •
0.2
71
1,000
50.1
Ohio No. 6
3.6
i8.0
12,300
56.6 41.0
3.0 2.1
0.8
86
0.44
57.0
1.3
78
0.38
43.3
10
37.1
0.2
71
1,000
48.6
3.6
•w.o
12,300
37.1
1.7
1.6
74
0.39
40.0
11 12
54.1 40.0
0.2 0.2
71 71
1 ,000 1 .000
46.7 51.8
3.6 3.6
"4. 0 ^8.0
12.300 12.300
54.1 40.0
2.4 1.7
f.O 2.1
84 66
0.38 0.35
55.3 42.6
as sorbent (except tests 13 & 14)
13
-
-
-
-
-
51.0
Pittsburgh
No. 8
3.0
MO.O
12,800
26.5
5.6
_
82
23.7
14
-
-
-
-
-
78.0
Illinois
No. 10
4.5
MO.O
10,500
36.0
3.6
1.3
80
0.4
35.1
15
j
10
^
0.9
-
3,020
100
-
1.23
10
12,183
10
0.6
1.2
82
18.5
16
25
0.9
-
3.020
100
2.0
10
12,183
25
I.I
1.2
84.9
30.1
17
140
18
330
Colorado (Green
0.9
-
3.020
100
-
3.0
10
12,183
140
3.1
1.2
87.5
107.1
0.9
-
3,020
100
-
4.3
10
12,183
330
4.3
1.2
89.8
233.6
Coal-shale mixture
tests using spent
shale as sorbent
19 20
6 20
0.66 0.66
-
400 400
100 100
-
1.23 2.0
10 10
12.183 12,183
21
58
0.66
_
400
100
-
3.0
10
12,183
6 20 58
0.5 1.2 1.9
1.2 1.2
95.7 95.9
16.2 29.5
1.2
96.1
62.0
aB&U - Babcock & Wllcox
ANL - Argonne National Laboratory
Note: ANL tests (15-21) are by thermogravlmetrlc analysis (TGA).
-------
TABLE 16c. SUMMARY OF RESULTS OF TGA STUDIES FOR DIRECT COMBUSTION OF COAL-SORBENT MIXTURES
GJ
Coal - limestone tests
Parameters
Testing done by
Coal feed (Ib/hr)
Sulfur %
Ash %
HHV (Btu/lb)
Sorbent feed (Ib/hr)
Type
Ca/S mole ratio
Emissions
S02 (lb/106 Btu)
502 reduction %
Solid waste rate (Ib/hr)
22
^
100
1.23
10
12,183
23
100
2.0
10
12.183
24
100
3.0
10
12,183
25
100
4.3
10
12,183
5 16 36 100
< — Germany Valley limestone — >
1.3 2.5 3.8 7.5
1.2
40
15.5
1.2
63.4
26.9
1.2
75.6
46.5
1.2
83
104.4
26
- Argonne
100
1.23
10
12,183
8
L.6
1.2
40
16.4
27
National
100
2.0
10
12,183
28 29
100 100
3.0 4.3
10 10
12,183 12,183
23 36 60
3reer limestone >
2.8 3.1 3.8
1.2
63.4
28.0
1.2 1.2
75.6 83
38.6 56.6
Coal - dolomite tests
30
100
1.23
10
12,183
3
0.4
1.2
40
12.9
31
100
2.0
10
12,183
3
Tymochtee
0.7
1.2
63.4
12.8
32
100
3.0
10
12,183
18
dolomite
1.0
1.2
75.6
25.6
33
100
4.3
10
12,183
40
1.5
1.2
83
41.3
-------
have been made to determine total solid waste rates for each test. The solid
waste rate is shown in the last column of the table and includes the calcium
sulfate reaction product as well as any unused sorbent and uncombustible
material (ash) from both the coal and the sorbent. Although solid waste rates
are consistently higher when shale is used as compared to conventional
sorbents, they are not so excessive (especially in the case of the lower sulfur
coals evaluated by ANL) as to be ruled out for use as a sorbent. The basis
for the solid waste rate calculations is provided in Appendix C.
In view of the experimental work done to date on oil shale combustion,
it seems that the concept is technically feasible but as yet untried on
a commercial basis. Because of the tremendous quantities of spent shale
that will be generated once the industry gets underway, it is expected that
companies involved in major oil shale projects will make additional efforts
to extract all available energy from the shale (assuming that such energy
is usable at the facility) prior to ultimate disposal. Although the FBC
represents a method for such heat recovery, it is not the only alternative
and the peculiarities of each retorting facility will determine the best means
for any direct combustion of the shale. As the large oil shale plants get
closer to reality, the companies involved will undoubtedly become more
interested in evaluating potential combustion techniques such as FBC.
The concept of using oil shale as an S02 sorbent with coal appears
promising but will depend on the costs of conventional sorbents as well as
other costs related to transporting the raw or spent shale to an industrial
or utility coal-burning facility. Alternatively, a major oil shale plant
using in-situ retorting technology could generate its own power in a coal-
burning power plant using the raw shale removed from the underground mine
as the SO2 sorbent. It would also seem feasible that oil shale could be
co-fired with high sulfur refinery residuals, Canadian tar sands, or Mexican
sour crudes in an atmospheric fluidized bed combustor.
Since all of the oil shale combustion tests to date have been conducted
in fluidized bed reactors of 18 inches diameter or less, further testing in
larger scale equipment would seem warranted before firm conclusions can be
drawn concerning the prospects of scaling up to commercial application.
The preliminary economic analysis performed in Section 2 would seem to
indicate that costs for operating an FBC unit using oil shale as an S02 sorbent
are economically competitive with similarly-sized FBC's using conventional
limestone sorbent. Direct operating costs were shown to range from -25 to +21
percent of the same cost for the coal-limestone base case while total annualized
operating costs ranged from -15 to +13 percent compared to the base case. These
costs are highly dependent on the purchase price of the shale which in turn
would be a function of the distance of the FBC facility from the shale source.
Given that the test data used for this cost comparison were developed from
FBC units of 18-inches diameter or less, such an assessment should be
repeated using test data resulting from larger-scale equipment if and when
such data become available.
-------
REFERENCES
1. Duncan, D. C., and V. E. Swanson. Organic-Rich Shale of the United
States and World Land Areas. USGS Circular 523. Washington, D.C.
U.S. Geological Survey, 1965.
2. Wayne, M. Cracking the Shale Resource. EPRI Journal, November 1980.
pp. 6-13.
3. Tarman, P. B., et al. Hydroretorting Process for Eastern Shale.
Society of Petroleum Engineers, Eastern Regional Manufacturers.
Paper No. SPE6628, October 27-28, 1977.
4. Ellington, R. T. Fluidized Bed Retorting of Oil Shale. Society of
Mining Engineers, AIME Transactions - Vol. 254. September 1973.
pp. 264-269.
5. Hemrainger, C. E. (to Esso Research and Engineering Company), U.S.
Patent 3,484,364. December 16, 1969.
6. Whitcombe, J. A., K. D. Van Zanten, and G. C. Kane (to The Oil Shale
Corporation), U.S. Patent 3,925,190. December 9, 1975.
7. Gregoli, A. A. (to Cities Service Company), U.S. Patent 4,075,081.
Feb. 21, 1978.
8. Mitchell, D. S., and D. R. Sageman (to Chevron Research Company),
U.S. Patent 4,137,053. January 30, 1979.
9. Abdul-Rahman, Y. A. K., and H. B. Wolcott, Jr. (to Atlantic Richfield
Company), U.S. Patent 4,152,245. May 1, 1979.
10. Petrucci, R. H. General Chemistry - Principles and Modern Applications.
The MacMillan Company, New York, New York, 1972. p. 525.
11. Pitrolo, A. A., and J. Y. Shang. Fluidized Bed Combustion of Oil Shale.
Prepared by U.S. Department of Energy, Morgantown Energy Technology
Center, Morgantown, W. Va. October 1980.
12. Bates, E., R. Wolf, and D. McWhorter. Reconnaissance Study of Leachate
Quality from Raw Mined Oil Shale - Laboratory Columns. EPA-600./S7-80-
181. March 1981.
41
-------
13. Petersen, V., et al. Combustion in the Circulating Fluid Bed: An Alter-
native Approach in Energy Supply and Environmental Protection. In:
Proceedings of the 6th International Conference on Fluidized Bed Combus-
tion, Atlanta, Ga., April 9-11, 1980. Vol. 2. p. 212.
14. Xu-Yi, Z. The Progress of Fluidized-Bed Boilers in People's Republic
of China. In: Proceedings of the 6th International Conference on
Fluidized Bed Combustion, Atlanta, Ga., April 9-11, 1980. Vol. 1.
p. 36.
15. Mei, J. S., et al. Fluidized-Bed Combustion of Israeli Oil Shale.
In: Proceedings of the 6th International Conference on Fluidized Bed
Combustion, Atlanta, Ga., April 9-11, 1980. Vol. 3, pp. 834-839.
16. Doyle, J. B. Fluid Bed Combustion of Coal-Oil Shale Mixture. Presented
to the Fourth Annual Oil Shale Conversion Symposium, Denver, Colorado.
March 24-26, 1981.
17. Taylor, T. E. Experimental Results from An 0.46 m Diameter Fluid Bed
Pilot Plant. Fluidization. Cambridge University Press, New York, N.Y.
1978. pp. 258-263.
18. Nevens, T. D., W. J. Culbertson, and R. Hollingshead. Disposal and Uses
of Oil Shale Ash. Interim Report No. 1, USBM Project SWD-8, University
of Denver, Denver Research Institute, Denver, Colorado, 1961.
19. Bates, E. R., and T. L. Thoem. Environmental Perspective on the Emerging
Oil Shale Industry. Prepared by EPA Oil Shale Research Group.
EPA-600/2-80-205a.
20. Johnson, I., et al. Support Studies in Fluidized-Bed Combustion -
Quarterly Report January-March 1978. Prepared by Argonne National
Laboratory for U.S. Department of Energy and U.S. Environmengal Protec-
tion Agency. ANL/CEN/FE-78-3. June 1978. pp. 7-15.
21. Johnson, I., et al. Support Studies in Fluidized-Bed Combustion -
Annual Report July 1977 - September 1978. Prepared by Argonne National
Laboratory for U.S. Department of Energy and U.S. Environmental Protec-
tion Agency. ANL/CEN/FE/78-10, pp. 36-42.
22. Wilson, W. I., R. B. Snyder, and I. Johnson. The Use of Oil Shale for
SO2 Emission Control in Atmospheric-Pressure Fluidized-Bed Coal Combus-
tors. I&EC Process Design and Development, Vol. 19. January 1980,
pp. 47-51.
23. Myrick, D. T. DOE Cost Comparison Study: Industrial Fluidized Bed
Combustion vs. Conventional Coal Technology. Prepared by Combustion
Engineering, Inc. for U.S. Department of Energy under Contract No.
EX-76-C-01-2473. Publication No. FE-2473-T7. January 2, 1980.
42
-------
BIBLIOGRAPHY
Canby, T. Y. Synfuels - Fill'er Up With What? Special Report: Energy
National Geographic. February 1981. pp. 74-95.
Gale, C. (ed.). Oil Shale Symposium: Sampling, Analysis and Quality
Assurance - March 1979. EPA-60079-80-022. June 1980.
Grover, R. Move's on to Exploit Rich Eastern Oil Shale. Chemical
Engineering. June 2, 1980. pp. 42-44.
Kosstrin, H. M., and R. D. Davis. Fluidized Bed Reactor Applications.
In: Proceedings of the Symposium on New Fuels and Advances in Com-
bustion Technologies. New Orleans, Louisiana, March 26-30, 1979.
pp. 421-432.
Langsjoen, P. L., and E. A. Fletcher. Observations on the Combustion of
Oil Shale in a Fluidized Bed. Presented to: Western States Section/
The Combustion Institute Spring Meeting, Salt Lake City, Utah.
April 19-20, 1976.
Norris, T. G. Shale Oil Prospects are Bright. Hydrocarbon Processing,
Vol. 60, No. 6, June 1981, pp. 131-132.
Nulty, P. Shale Oil is Braced for Big Role. Fortune, September 24, 1979,
pp. 41-48.
Shih, C. C. et al. Technological Overview Reports for Eight Shale Oil
Recovery Processes. EPA-600/7-79-075. March 1979.
Aerosol Characteristics of Fly Ash from the Fluidized Bed Combustion of
Paraho Oil Shale and Organic Characterization of Effluents from the
Fluidized Bed Combustion of Coal and Oil Shale. Prepared by
Inhalation Toxicology Research Institute, U.S. Department of Energy,
Lovelace Biomedical and Environmental Research Institute, Inc.
Annual Report, October 1, 1978 through September 30, 1979.
December 1979, pp. 277-293.
An Assessment of Oil Shale Technologies. Prepared by the Congress of the
United States - Office of Technology Assessment. June 1980.
43
-------
Environmental Assessment - Perspective on the Emerging Oil Shale Industry.
Prepared by the EPA Oil Shale Research Group. Technology Transfer
Report EPA-625/9-81-005. January 1981.
EPA Program Status Report: Oil Shale 1979 Update. Prepared by EPA Oil Shale
Work Group. EPA-600/7-79-089. June 1979.
Oil Shale and the Environment. Prepared by U.S. EPA, Office of Research and
Development. EPA-600/9-77-033. October 1977.
Proceedings of the Seventh Oil Shale Symposium. Vol. 69, No.2. April 1974.
44
-------
APPENDIX A
CALCULATIONS REGARDING THE MAGNITUDE
OF AN OIL SHALE INDUSTRY'S PRODUCTION
AND DISPOSAL REQUIREMENTS
-------
The following calculations are presented to provide some perspective
of the magnitude of shale mining and disposal requirements for an estab-
lished oil shale industry in the latter part of this century.
Assumptions
• By the 1990-2000 time frame, it is generally assumed that
a domestically established oil shale industry will range
in size from 400,000 to 1.0 x 106 bbl/day.
• Each individual plant will be sized at 50,000 bbl/day.
Thus, from 8 to 20 commercial plants would be required.
• Calculations are performed with Fischer assay values of
35, 25, and 15 gal/ton. For these qualities of shale,
the weight percent of oil is about 15, 10, and 6 percent,
respectively.
Calculations - (per plant)
(1) Ratio of spent shale to oil—(ton spent shale per bbl oil)
@ 35 gal/ton:
50,000 bbl
day
42 gal
bbl
ton shale
35 gal
= 60,000 ton shale/day
60,000 ton shale/day = 51,000 ton spent shale/day
9,000 ton oil/day
51,000 ton spent shale . . .
50,000 bbl oil :
@ 25 gal/ton:
50,000 bbl
day
42 gal
bbl
ton shale
25 gal
= 84,000 ton shale/day
84,000 ton shale/day = 75,600 ton spent shale/day
8,400 ton oil/day
75,600 ton spent shale s . _ .
50,000 bbl oil '^
46
-------
@ 15 gal/ton:
50,000 bbl
day
42 gal
bbl
ton shale
15 gal
- i **u » uuu con s na-Le / a ay
140,000 ton shale/day = 131,600 ton spent shale/day
8,400 ton oil/day
131,600 ton spent shale _ , .
50,000 bbl oil '°:
(2) Spent shale disposal requirement—
Assume that 25 gal/ton is typical and that the total industry produces
1.0 x 106 bbl/day.
1.0 x 106 bbl oil
day
@ 24 hr/day operation:
1.5 ton spent shale
bbl oil
20 plants = 75'°°° ton
shale/day
per plant
75,000 ton
day
day
24 hr
2000 Ib
ton
6.25 x 10° Ib spent shale/hr
@ 8 hr/day operation:
75,000 ton
day
day
8 hr
2000 Ib
ton
= 18.75 x 106 Ib spent shale/hr
(3) Use of FBCs for spent shale combustion —
The largest FBC unit (industrial) built to date fires 338 ton/day or
84,500 Ib/hr.
Case A (worst case) -
FBC operates 8 hr/day @ 75,000 Ib/hr:
18.75 x 106 Ib/hr ___ _,,... ,
25° FBC units P« plant
75.000 Ib/hr
Case B (best case) -
FBC operates 24 hr/day @ 100,000 Ib/hr:
6.25 x 106 Ib/hr
100.000 Ib/hr
,, _„ .
63 FBC units
47
-------
Either case indicates that it is most unlikely that all spent shale could
be disposed of in this manner. It is more likely that some portion of the
shale could be directly combusted for recovery and use of energy in various
areas of the plant. The remainder of the shale could be disposed of by more
conventional methods such as returning to the mine or landfilling.
48
-------
APPENDIX B
SUPPORT CALCULATIONS FOR
PRELIMINARY ECONOMIC ANALYSIS
PRESENTED IN SECTION 2
49
-------
A. DOE Base Case—
250,000 Ib/hr (steam)
34,012 Ib/hr (coal)
10,430 Btu/lb (coal)
12,256 Ib/hr (limestone)
13,484 Ib/hr (solid waste)
_ 34,012 Ib
10.430 Btu
,C(. ,_ „,. /u
355 x 10 Btu/hr
Heat input = — — | ~.™
B. Case No. 1 (B&W Test No. 11) —
• 54.1 Ib/hr (shale)
• 1000 Btu/lb (shale)
• 46.7 Ib/hr (coal)
• 12,300 Btu/lb (coal)
« 55.3 Ib/hr (solid waste)
(1) Determine coal and shale feed rates scaled to 250,000 Ib/hr
(steam) boiler size—
x = shale feed rate, Ib/hr
y = coal feed rate, Ib/hr
x = 54.1
y 46.7
• Assume same heat input as base case:
1000 x + 12,300 y = 355 x 106 (b)
Simultaneous solution of Equations (a) and (b) yields:
x = 30,557 Ib/hr (shale)
y = 26,377 Ib/hr (coal)
(2) Determine total solid waste rate—
• Assume that the ratio of solid waste to coal and sorbent
feed rates is the same for the scaled-up system, s = new
solid waste rate
55.3 S
54.1 + 46.7 30,557 + 26,377
S = 31,257 Ib/hr (solid waste)
50
-------
(3) Determine impact on direct operating cost—
a. Coal—
26.377 Ib | ton | $35 hr
hr 2000 Ib
b. Sorbent—
30.557 Ib ton
ton
$5
250 x 103 Ib steam
hr
= $1.85/103 Ib steam
hr 2000 Ib ton 250 x 103 Ib steam
shale @ $10/ton
shale @ $20/ton
shale @ $30/ton
Solid Waste Removal—
31,257 Ib ton $6 hr
hr 2000 Ib ton 250 x 10" Ib steam
C. Case No. 2 (ANL Test No. 17) —
• 140 Ib/hr (shale)
• 3,020 Btu/lb (shale)
• 100 Ib/hr (coal)
• 12,183 Btu/lb (coal)
• 107.1 Ib/hr (solid waste)
(1) Coal and shale feed rates—
x 140
y = 100
3,020 x + 12,183 y = 355 x 106
x = 30,285 Ib/hr (shale)
y = 21,632 Ib/hr (coal)
(2) Solid waste rate—
107.1 _ S
100 + 140 " 30,285 + 21,632
S = 23,168 Ib/hr (solid waste)
= $0.31/103 Ib steam
= $0.61/103 Ib steam
= $1.22/103 Ib steam
= $1.83/103 Ib steam
= $0.38/103 Ib steam
(a)
(b)
51
-------
(3) Impact on direct operating cost—
a. Coal—
26.632 Ib ton $35 hr
hr 2000 Ib
b. Sorbent—
30.285 Ib ton
ton
$5
250 x 10s Ib steam
hr
hr 2000 Ib ton 250 x ICTlb steam
shale @ $10/ton
shale @ $20/ton
shale @ $30/ton
Solid waste removal—
23,168 Ib ton $6 hr
D.
hr 2000 Ib ton 250 x 10" Ib steam
Case No. 3 (ANL Test No. 20) —
= $1.51/103 Ib steam
= $0.30/103 Ib steam
= $0.61/103 Ib steam
= $1.21/103 Ib steam
= $1.82/103 Ib steam
$0.28/103 Ib steam
•
•
•
20 Ib/hr (shale)
400 Btu/lb (shale)
100 Ib/hr (coal)
12,183 Btu/lb (coal)
29.5 Ib/hr (solid waste)
(1) Coal and shale feed rates—
x 20
y 100
400 x + 12,183 y = 355 x
x = 5,790 Ib/hr (shale)
y = 28,950 Ib/hr (coal)
(2) Solid waste rate—
29.5 S
100 + 20 28,950 + 5,790
S = 8,546 Ib/hr (solid waste)
(a)
(b)
52
-------
(3) Impact on direct operating cost—
a. Coal—
28,950 Ib
hr
ton
2000 Ib
$35
ton
hr
250 x 10J
b . Sorbent —
5,790 Ib
hr
ton
2000 Ib
$5
ton
hr
250 x 10°
Ib steam
Ib steam
shale @ $10/ton
shale @ $20/ton
shale @ $30/ton
Solid waste removal—
8,546 Ib
hr
ton
2000 Ib
$6
ton
hr
250 x 10 3 Ib steam
= $2.03/103 Ib steam
= $0.06/103 Ib steam
= $0.12/103 Ib steam
= $0.23/103 Ib steam
= $0.35/103 Ib steam
= $0.10/103 Ib steam
53
-------
APPENDIX C
SUPPORT CALCULATIONS FOR DETERMINING TOTAL SOLID WASTE
RATES FOR COAL-SORBENT TESTS PRESENTED IN TABLES 16b AND 16c
-------
Solid waste rates have been determined for FBC systems burning coal with
both oil shale and conventional sorbents. The calculations are based upon
available dnt.-i In each of the referenced reports c I.ted in the text.
Solid waste rate is defined as the total weight of material that is
discharged from the FBC system and includes the following: the sorbent/S02
reaction product, calcium sulfate (CaS04); unreacted calcium oxide (CaO);
inerts in the sorbent; and the ash contained in the coal. The following
equation is used:
CaO:
sorbent
ash:
SWR = SFR
-F
+ F
as
coal ash:
CFR (Fac)
where:
SWR
SFR
Fs
Ca/S
136
solid waste rate
sorbent feed rate
fractional sulfur removal
calcium to sulfur molar ratio
CaSOA
... calcium
s _ utilization factor
Ca/S (dimensionless)
100
weight ratio of
CaC03
F = fraction of ash in the sorbent, or
as
1-F = CaCOo content of sorbent
clS *J
56 = weight ratio of Ca°
100
CFR = coal feed rate
CaCO-
F = fraction of ash in the coal
ac
The solid waste rate calculations have been performed for test numbers 6
through 33 as presented in Tables 16b and 16c of the text. For test no's. 13
and 14 (B&W) , it was assumed that the coal contained 10 percent ash. For test
no's. 15 through 33 (ANL) , several assumptions had to be made:
• ash content of coal = 10 percent
• heat content of spent shale = 400 Btu/lb
55
-------
78 percent of the sulfur in the shale is converted to SO
22
• a basis of 100 Ib/hr coal feed is used for all
calculations
Wherever possible, limestone, dolomite, and shale analyses have been
used. For example, the limestone analysis as indicated in the footnote to
Table 10 is used for B&W Test No's. 13 and 14. Also, the shale, dolomite and
limestone constituents as provided in Table 11 are used in the calculations
for all ANL tests. Since all of the sorbents shown in Table 11 contain magne-
sium carbonate (MgCOo), corrections have been made for the fact that this com-
pound does undergo calcination (to form MgO) but does not react with sulfur
dioxide. (See Example calculation (5)).
Since reference 22 only provided information on Ca/S ratios and unit
weights of sorbent per unit weights of coal required, percent sulfur reduction
had to be determined. Table C-l provides this information.
TABLE C-l. UNCONTROLLED S02 LEVELS AND REMOVAL EFFICIENCIES
REQUIRED FOR ANL TEST DATA
Uncontrolled S02 levels
(Ib S02/106 Btu)
Efficiency required
to meet
1.2 Ib S02/106 Btu
au.Lrur concent
of coal
(%)
1.23
2.0
3.0
4.3
1.23
2.0
3.0
4.3
Coal
2.0
3.28
4.92
7.06
Coal
2.0
3.28
4.92
7.06
Raw
shale
4.68
4.68
4.68
4.68
Spent
shale
25.74
25.74
25.74
25.74
Total
6.68
7.96
9.6
11.74
Total
27.74
29.02
30.66
32.8
Coal
only
40
63.4
75.6
83.0
Coal
only
40
63.4
75.6
83.0
Shale +
coal
82.0
84.9
87.5
89.8
Shale +
coal
95.7
95.9
96.1
96.3
Several sample calculations are provided as follows:
(1) Uncontrolled SC>2 levels in raw and spent shale and coal for ANL tests:
Raw shale—
0.9% S, 3,020 Btu/lb
Basis: 100 Ib raw shale
0.9 Ib S
2 Ib S02
0.302 x 10° Btu
Ib S
= 4.68 Ib S02/106 Btu
56
-------
Spent shale—
0.66% S, 400 Btu/lb
Basis: 100 Ib spent shale
0.66 Ib S
0.04 x 100 Btu
3.0% S Coal—
2 Ib S02
Ib S
0.78
= 25.74 Ib S02/106 Btu
3.0% S, 12,183 Btu/lb
Basis: 100 Ib coal
3 Ib S
1.2183 x 100 Btu
2 Ib S
Ib S02
4.92 Ib S02/106 Btu
(2) Solid waste rate for B&W Test No. 10 (Table 16b) —
+ 0.71/ + 48.6 (0.08)
SWR = 6.37 + 3.40 + 26.34 + 3.89
SWR = 40 Ib/hr
(3) Solid waste rate for ANL Test No. 20 (Table 16b) —
• 2.0% S coal requires 95.9 percent reduction to meet 1.2 Ib S02/10 Btu
(from Table C-l)
• amount of sorbent (spent shale) required = 0.2 Ib spent shale/lb
coal (from Table 12)
Basis: 100 Ib/hr coal feed
lfi,/40.3\
•167\84T3/
SWR = 20( 1^^1(4^1(0.335) + [l-^r^] h-f£l(0.335l + 0.493 + 0
+ 100 (0.10)
SWR = 7.28 + 0.75 + 11.46 + 10
SWR = 29.5 Ib/hr
(4) Solid waste rate for ANL Test No. 25 (Table 16c) —
• 4.3% S coal requires 83.0 percent reduction to meet 1.2 Ib
S02/106 Btu (from Table C-l)
• amount of sorbent (Germany Valley limestone) required = 1.0 Ib
limestone/lb coal (from Table 12)
Basis: 100 Ib/hr coal feed
57
-------
SWR = 100
\ 7-5 /
0.0235 + O.i
+ 100 (0.10)
SWR = 14.71 + 48.68 + 31.03 + 10
SWR = 104.4 Ib/hr
(5) Solid waste rate for ANL Test No. 32 (Table 16c) —
• 3.0% S,coal requires 75.6 percent reduction to meet 1.2 Ib
S02/10 Btu (from Table C-l)
• amount of sorbent (Tymochtee dolomite) required = 0.18 Ib
dolomite/lb coal (from Table 12)
Basis: 100 Ib/hr coal feed
ll/o.
sm. is 545£W4£Wo.
(ly '
0.0555 + 0.433
+ 100 (0.10)
SWR = 9.59 + 1.27 + 4.72 + 10
SWR = 25.6 Ib/hr
58
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing}
REPORT NO
EPA-600/7-82-04 5
2.
3. RECIPIENT'S ACCESSION-NO.
I TITLE ANOSUBTITLE
Combustion of Oil Shale in Fluidized-bed
Combustors—an Overview
6 REPORT DATE
May 1982
6. PERFORMING ORGANIZATION CODE
AUTHORIS)
Douglas R. Roeck
PERFORMING ORGANIZATION REPORT NO
PERFORMING ORGANIZATION NAME AND ADDRESS
GC A/Te c hnology Div is ion
213 Burlington Road
Bedford, Massachusetts 01730
10. PROGRAM ELEMENT NO.
11 CONTRACT/GRANT NO
68-02-2693, Task 11
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 5-11/81
14 SPONSORING AGENCY CODE
EPA/600/13
is SUPPLEMENTARY NOTES IERL-RTP project officer is John O. Milliken, Mail Drop 61,
919/541-7716.
is ABSTRACT -phc report gives an overview of the combustion of oil shale in fluidized-
bed combustors. Oil shale can be combusted directly, or as a supplement to coal
fuel, and can function as an SO2 sorbent in atmospheric fluidized-bed combustion
(AFBC). Spent shale from retorting processes may provide for SO2 sorption and
add some residual fuel value in AFBC. Commercial applications of direct combus-
tion of oil shale in AFBC are limited, and known to exist only in Estonia (Soviet
Union), China, and southern Germany. Pilot- and laboratory-scale combustion of
shale and coal/shale mixtures in AFBCs in the U.S. has been investigated. Technical
concerns include calcination heat loss, optimal shale sizing, and combustion effic-
iency. Direct combustion of western U.S. shale in a pilot AFBC produced NOx
emissions as high as 3 Ib/million Btu; although, for coal/shale mixtures, NOx
emissions were < 0. 6 Ib/million Btu. Because of its calcium carbonate
(CaC03> content, shale can act as an effective SO2 sorbent in AFBC, and has pro-
duced SO2 reduction efficiencies of > 85% in AFBC tests with coal/shale mixtures.
A preliminary economic analysis indicates that substituting oil shale for limestone
in an AFBC may have significant cost advantages, especially where shale (or spent
shale) is readily available and at low cost.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c COSATI Field/Group
Pollution
Oil Shale
Combustion
Fluidized Bed Processing
Desulfurization
Pollution Control
Stationary Sources
13B
08G
21B
13H,07A
07D
13 DISTRIBUTION STATEMENT
Release to Public
19 SECURITY CLASS (Thu Report)
Unclassified
21 NO. OF PAGES
66
20 SECURITY CLASS (Thispage)
Unclassified
22 PRICE
EPA Form 2220-1 (»-7J)
59
------- |