United States
Environmental Protection
Agency
Research and Development
Office of Environmental Engineering EPA-600 7-
and Technology (RD-681! " September 1980
Washington D.C 20460
Environmental, Operational
and Economic Aspects
of Thirteen Selected
Energy Technologies
Interagency Energy-Environment Research and Development Program Report
-------
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.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/7-80-173
SEPTEMBER 1980
ENVIRONMENTAL, OPERATIONAL, AND
ECONOMIC ASPECTS OF THIRTEEN
SELECTED ENERGY TECHNOLOGIES
EPA CONTRACT NO. 68-01-4999
FOR
OFFICE OF ENVIRONMENTAL ENGINEERING AND TECHNOLOGY
OFFICE OF RESEARCH AND DEVELOPMENT
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
-------
PREFACE
As a result of significant increases in the cost of fuel and the
desire for a clean environment, there has been increased emphasis placed
on economic and environmental aspects of fuel utilization. These fac-
tors contributed to the need for a report that would address selective
fuel utilization and conversion technologies. This being the case, the
EPA, Office of Environmental Engineering and Technology (OEET) felt it
imperative to sponsor such a report in a form suitable for general dis-
tri bution.
This effort was completed in fulfillment of Task A of EPA Contract
No. 68-01-4999, Morris H. Altschuler and William N. McCarthy, Jr., EPA
Project Officers.
LEGAL NOTICE
This report was prepared by the Hoffman-Muntner Corp-
oration as an account of work sponsored by the U. S.
Environmental Protection Agency (EPA). Neither the
EPA, the U. S. Government, the Hoffman-Muntner Corp-
oration, or any person acting on behalf of either:
(a) makes any warranty or representation, express or
implied, with respect to the accuracy, completeness,
or usefulness of the information contained in this
report, or that the use of any information, apparatus,
method, or process disclosed in this report may not
infringe privately owned rights; or (b) assumes any
liabilities with respect to the use of, or for damages
resulting from the use of, any information, apparatus,
method, or process disclosed in this report.
-------
EXECUTIVE OVERVIEW
Approximately one-third of the total energy used annually in the
United States is devoted to the generation of electricity. The U. S.
Department of Energy estimates that by 1990, this share may substantially
increase. To meet this increasing demand will require the substantial
addition of generating capacity.
Currently, about 48 percent of our electric energy is produced from
coal-fired plants, with the combined outputs from nuclear and hydroelec-
tric contributing another 24 percent. This still leaves about 28 percent
being produced with natural gas and oil, whose price and continued avail-
ability lack the stability on which to base a reliable electric power
generating industry. Further, these increasingly scarce fuels are re-
quired for heating, industrial purposes, and transportation.
Technologies must be developed which can make greater use of our
abundant reserves of coal in an environmentally acceptable fashion. The
technologies addressed in this report are those which potentially could
use our available and under-utilized fossil fuel resources (coal, heavy
crudes, and oil shale) in an environmentally acceptable manner. Some are
more costly than others and this has to be weighed against their relative
operational and environmental aspects.
This report is intended to-give the reader a better understanding of
the current status of possible options as they might be applied to the
future generation of electricity and other energy needs. Brief coverage
of the technologies follows. For a more comprehensive assessment, the
reader is referred to the individual sections.
In the case of conventional coal-fired steam-electric power plants,
current efficiencies range from approximately 31 to 38 percent. The pros-
pect for the foreseeable future is that newer plants will have efficiency
values below 40 percent. It is unlikely that truly operational efficiency
values in excess of 40 percent from conventional plants will be realized
within the foreseeable future. In the absence of pollution control meas-
ures, coal fired steam-electric plants would provide very substantial un-
desirable environmental impacts. However, the current state-of-the-art
of environmental control and resulting control measures are capable of
substantially mitigating currently identified undesirable pollution and
other environmental effects. Continuing environmental control activities
are expected to provide the means of control for the near-term any poten-
tial overall undesirable effects resulting from increasing use of coal to
fire steam-electric plants.
Diesels have been commercially utilized in excess of 80 years. They
are used extensively to power moderate size stationary electric generators
for a variety of services. Even though the output of a large diesel gen-
erator is small compared to the output of a typical utility fossil-fuel
i i i
-------
steam-electric generator, the attainable efficiency is generally as great.
Recently, concern has developed relating to the potential carcinogenic as-
pects of diesel exhaust. Future utilization of stationary diesel gener-
ators may well depend on diesel emission control standards. The cost of
diesel derived electric energy is somewhat higher than that from a con-
ventional steam-electric plant. This is due to the relatively high oper-
ating cost (per kwh electric energy) of a diesel generator installation.
DOD experience indicates diesel derived electric energy is at least twice
as expensive as that purchased from an electric utility. Even so, for
selected applications, diesel generators are very appropriate.
Current f1uidized-bed combustion efforts are largely in the research,
development, and demonstration stages. Some manufacturers have recently
begun to advertise the availability of atmospheric commercial/industrial
scale units. The attainable boiler efficiency is limited by the same
general loss components as for a conventional boiler. Boiler efficiency
values equal to those attainable by conventional boilers will depend on
the ability to achieve substantially complete carbon burn-up. The envi-
ronmental aspects of a fIuidized-bed boiler are similar to that of an
equivalent capacity conventional boiler with flue gas desuIfurization
(FGD) burning the same coal. A major difference is the relatively low NO
emission and the amount and nature of the spent bed material as compared x
to the effluent from a FGD system. For fIuidized-bed combustion with
the same SO removal, almost three times as much limestone is required.
Spent bed material from a fIuidized-bed boiler contains appreciable CaO
(i.e., quicklime) that may present handling and disposal problems. Hope-
fully, commercial uses will be found for the spent bed material. In the
near term, fIuidized-bed boilers are projected to compete with industrial/
commercial scale conventional boilers with SO emission control. Such
units when developed would permit coal to be burned more conveniently at
such locations as schools, hospitals, shopping centers, office buildings,
small industrial parks, etc.
There are many gas turbine-steam combined-cycle power plants cur-
rently in operation which achieve overall efficiencies around 40 percent.
However, these systems currently rely upon gas or oil the price and fu-
ture availability of which have become of serious concern. Therefore,
there is major emphasis on making today's turbines run more efficiently
on these scarce fuels and to develop improved turbines that will operate
efficiently on the synthetic fuels that will one day replace oil and
natural gas. In addition to improved efficiency, such combined-cycle
power plants utilizing gas-turbine and steam-turbine technology have a
number of other key features which could make them particularly appealing
to the utility industry. Besides very fast start-up capabilities, these
features include relatively low capital investment per kilowatt of elec-
tric generation, relatively low operating costs, and the capability for
use as a base-load or peaking power plant. Another potentially promising
i v
-------
aspect of the combined-cycle power plant is its projected ability to use
low-energy gas from coal. The environmental implications of this are
significant. Since such low-Btu gas can be clean burning, much of the
environmental control problems and expense associated with conventional
coal-fired steam generating plants would be avoided. A variation of the
combined gas turbine and steam-turbine system features the direct combus-
tion of coal in a pressurized fIuidized-bed (PFB). Although internal
particulate control is still required, the PFB offers the potential for
direct combustion of high-sulfur coal without stack gas cleanup while
achieving an overall coal pile-to-bus bar plant efficiency of approxi-
mately 40 percent.
The low/medium-Btu gasification of coaI is essentiaI 1y an exi sti ng
technology. In fact, gas manufactured from coal was first produced in
the eighteenth century. Currently, low/medium-Btu coal gasifiers are in
use in Europe, South Africa, and to a very limited extent, in the United
States. Coal can be gasified by any of several processes: synthesis,
pyrolysis, hydrogasification. In synthesis, coal or char is reacted with
steam and oxygen or air and produces the heat for a reaction that pro-
duces a mixture of hydrogen and carbon monoxide. In pyrolysis, coal is
heated in a starved air atmosphere. In the process, some gas and liquids
result, the major product being a coke residue. In hydrogasification,
coal, coke, or char is reacted with hydrogen to form methane. Pipeline
gas is produced by upgrading a medium-Btu gas. Environmental problems
common to coal associated energy generating systems will generally also
apply to coal gasification facilities. Additional adverse environmental
aspects of proven and pilot plant processes are difficult to assess be-
cause of the very limited data available from such operations. The con-
version efficiency as based on total energy input, is somewhat process
and site specific and is estimated to be in the 70 to 80 percent range
including raw gas cleanup. The value without gas cleanup (i.e., raw hot
gas output) is estimated to be as high as 90+ percent when the sensible
heat of the gas is included. Since this is basically a developed tech-
nology, over the foreseeable future, efficiencies are not expected to
improve significantly. The cost is currently estimated at $2.50 to $4.00
per mi I I ion Btu.
The chemically active fluid bed (CAFB) process uses a shallow fluid-
ized-bed of lime or lime-like material to produce a clean, hot gaseous
fuel from high sulfur feedstock (e.g., residual oil). Solid fuel feed-
stocks such as coal are also feasible. The initial CAFB pilot unit (2.39
Mw) was developed by the Esso Research Centre in Abingdon, England. A
10 Mw demonstration plant has subsequently been constructed by Foster
Wheeler at the La Palma Power Station (Central Power and Light Company)
in San Benito, Texas. EPA is sponsoring the demonstration of this tech-
nology. Environmental data are very limited. Principal environmental
concerns relate to the size of the particles in the product gas stream,
the vanadium (bound in a mixture of oxides) emission level, and the dis-
posal of spent, sulfided limestone. The solid waste disposal problem
-------
appears to be the major environmental concern. Since all activities are
R&D, no actual full scale performance data are available. In this regard,
the total gasification efficiency is estimated to be approximately 87
percent. Similarly, economic values are also projections. EPA estimates
that a retrofit CAFB plant to fuel a 500 Mwe plant would cost $172 per kw
of installed capacity; the operating cost is estimated at 2-3 mills per
kwh (1977 dollars).
CoaI Iiquefaction provides the means to produce liquid fuels from
coal. In indirect liquefaction, the coal is gasified to make a synthesis
gas and then passed over a catalyst to produce alcohols (methanol) or
paraffinic hydrocarbons. In direct liquefaction the coal is liquefied
without a gasification intermediate step. Specific processes are gener-
al ly directed toward converting coal to liquid fuels with minimal pro-
duction of gases and organic solid residues. The liquid products that
are produced vary with the type of process and the rank of coal that is
utilized. Research and development of coal liquefaction has been under-
way for many years. The first practical uses of coal-derived liquid fuels
were about 1790 when the fuels were used for experimental lighting, heat-
ing, and cooking. During World War II, Germany produced liquid fuels
from coal in industrial amounts (45 million bbl/year). Since then, coal
liquefaction plants have been constructed in a number of countries but
currently only South Africa is producing liquids from coal. Commercial
demonstration of coal liquefaction has never been accomplished in the
United States. Current U. S. activities are limited to research and de-
velopment and pilot plant programs. Environmental problems common to
fossil energy facilities will also apply to coal liquefaction facilities.
Liquefaction processes present some unique problems such as the need for
the characterization of materials with carcinogenic effects, character-
ization and treatment of wastes, fugitive emissions, and effluents and
the disposal of sludges and solid wastes. These problems are generally
common to a I I liquefaction processes, however, since no large scale plants
are in operation in the U. S., the only available data on emissions and
effluents are estimated from pilot plant operations and cannot be com-
pletely quantified for a commercial operation. Projected efficiencies for
coal liquefaction facilities are in the 55 to 70 percent range. Accurate
values for coal conversion efficiencies are difficult to estimate and thus
an exact value cannot be given until commercial demonstration takes place.
Estimated costs for indirect coal liquefaction plants are in the $7-10
per mi I I ion Btu range (1980 dollars). Generally, the estimated cost for
direct coal liquefaction plants is less than for indirect liquefaction.
High-Btu gasification of coal can be accomplished by any of several
processes: synthesis, pyrolysis, or hydrogasification. In synthesis,
coal or char is reacted with steam and oxygen and produces the heat for
a reaction that produces a mixture of hydrogen and carbon monoxide. In
pyrolysis, coal is heated in a starved air atmosphere. In the process,
some gas and liquids result, the major product being a coke residue. In
hydrogasification, coal, coke, or char is reacted with hydrogen to form
v i
-------
methane. To produce a pipeline quality gas, medium-Btu gas (e.g., from
hydrogasification) is cleaned and further treated. This further treat-
ment could include a shift conversion to obtain the proper carbon monox-
ide to hydrogen ratio followed by a second purification process, followed
by a methanation process. To an extent, environmental concerns common
to coal-fired boiler facilities will also generally apply to coal gasifi-
cation facilities. Additional unique adverse environmental impacts are
difficult to estimate. No commercial plants are in operation anywhere
in the world and assessments must be based on limited information from
pilot plants. In addition, information from a pilot plant may not be
representative of a commercial operation. Projected overall energy effi-
ciencies for coal gasification have been estimated to be approximately
75 percent. The estimated at gate costs of high-Btu gas produced by a
gasification plant are $4 to $6 per million Btu (1977 dollars).
Oi I shaIe resources can be processed either by conventional mining
fo1 I owed by surface process i ng or by i n situ (in pi ace) process i ng. In
situ processing can be accomplished by either true or modified in situ
methods to extract oil from shale. Oil shale resources in the United
States are estimated to exceed two trillion barrels of petroleum and of
the total, 25 to 35 percent is presently projected as commercial. Shale
oil has been produced commercially at various time intervals in eleven
countries since the initiation of shale oil operations in France in 1838.
In Canada and the Eastern United States, a very small industry was oper-
ating around 1860, but disappeared when petroleum became plentiful. Cur-
rently, the only commercial production is in Russia (Estonia) and China
with a combined production of approximately 150,000 barrels per day. The
conventional process (conventional mining and surface retorting) to pro-
duce a crude is composed of four major steps: mining the shale; crushing
it to the proper size for the retort vessel; retorting the shale to re-
lease the oil; and refining the oil to a high-quality product. True in
situ processes involve fracturing the shale bed via vertical well bores
to create permeability without mining or removal of material followed by
underground retorting. Retorting can also be done via well bores util-
izing natural permeability where it may exist. The modified in situ pro-
cess involves mining or removing by other means (such as leaching or
underreaming) up to 40 percent of the shale (i.e., in the retorting sec-
tion) in order to increase the void volume and allow rubblization before
retorting. In modified in situ, the mJned shale can be surface retorted.
Considerable environmental questions are associated with oil shale pro-
cessing and until these uncertainties as well as the demonstration of an
economically acceptable commercial scale viable technology are resolved,
future development of a viable oil shale industry is uncertain.
The fgeI ceI I, by converting chemical energy directly to electric-
ity, can efficiently use fuels without an intermediate mechanical step.
Fuel cell power plants offer many attractive characteristics such as mod-
ular construction, low environmental emissions, high efficiency and rapid
response to load demand fluctuations. Because of the modular construc-
tion, fuel cells are easily transported and installation times and costs
v i i
-------
reduced. The fuel cell concept itself is not new: such cells have al-
ready provided power for moon landings and, between 1971 and 1973, pro-
vided electric power to 50 apartment houses, commercial establishments,
and small industrial buildings. What is new is an effort to capitalize
on the fuel cell's inherent flexibility, safety, and efficiency by put-
ting together a generator system that can use a variety of fuels to meet
today's utility-scale power need economically. Environmental considera-
tions like low water requirements, limited emissions, and quiet operation
help make fuel cell plants an attractive power option. Whereas fossil
fuel and nuclear plants require large quantities of water for cooling,
fuel cells generate less heat and can be air-cooled by low speed fans.
Because fuel cells can use a variety of hydrocarbon fuels, they share
with conventional generating processes the environmental problems current-
ly associated with extracting and processing fossil fuels. The required
hydrogen for the fuel cell power section can be derived by gasifying
coal. In such a case the coal gasifier would be an integral part of the
fuel cell power plant. The Energy Conversion Alternatives Study (EGAS)
team estimated an overall efficiency of 50 percent for its conceptual
molten carbonate fuel cell power plant. Although still in the prototype
stage, the fuel cell offers a means to produce electricity efficiently
on both small and large scales. These systems could be used to comple-
ment existing facilities or supply new generating capacity where environ-
mental considerations restrict conventional combustion plants.
Magnetohydrodynamics (MHD) is a potential energy alternative in which
electricity is generated directly from thermal energy, thus eliminating
the conversion step of thermal to mechanical energy encountered in conven-
tional steam-electric generators. However, due to the nature of the pro-
cess, it would be inefficient to apply MHD by itself to the large scale
generation of electricity. Therefore, its eventual implementation is be-
ing planned around combining MHD with a conventional steam plant to make
use of the waste heat from the MHD generator. The efficiency of such a
combined MHD/steam plant is predicted to be about 50 percent as compared
to 38 percent projected for conventional coal-fired power plants with
flue gas desuIfurization (FGD) systems. Unlike rotating machines, much
of this increase in efficiency is attributed to the fact that all the
rigid structures in MHD generators are stationary, thus permitting oper-
ation at elevated temperatures approaching 5000 F. These temperatures
are much higher than even the most advanced contemporary plants, result-
ing in much higher efficiencies through the entire thermal cycle than
are attainable in such conventional plants. Although much work remains
before the widespread application of the magnetohydrodynamic energy con-
version process to electric utility power generation, there is experi-
mental evidence that MHD can significantly improve overall power plant
efficiencies. Another promising aspect of this technology is the ability
to remove, during the process, pollutants such as SO , NO , and particu-
lates generated in the combustion of coal, thereby eliminating the need
for external flue gas scrubbing to meet environmental standards.
VIII
-------
TABLE OF CONTENTS
PREFACE i i
EXECUT I VE OVERV I EW i i i
LI ST OF F I CURES x i 1
L I ST OF TABLES xv
ACKNOWLEDGEMENT xv i i
I NTRODUCT I ON 1
TECHNOLOGY ASSESSMENTS 5
1. Conventional Coal-Fired Steam-Electric Power Plant 5
1 .1 Overv i ew 5
1.2 Process Description 6
1.3 Applications 12
1.4 Environmental Considerations 13
1.5 Performance 22
1 .6 Econom i cs 24
References 26
2. Diesel Generators 28
2.1 Overview 28
2.2 Process Description 28
2.3 Applications 31
2.4 Environmental Considerations 32
2.5 Performance 32
2.6 Econom i cs 33
References 34
3. Fluidized-Bed Combustion (FBC) 35
3.1 Overvi ew 35
3.2 Process Description 36
3.3 Applications 46
3.4 Environmental Considerations 47
3.5 Performance 52
3.6 Econom i cs 53
References 54
IX
-------
TABLE OF CONTENTS (Cont'd)
7.
Combined Cycle Power Plant
4 . 1 Overv i ew
4.2 Process Description
4.3 Appl i cations
4.4 Environmental Considerations
4. 5 Performance
4 . 6 Econom i cs
References
Low/Med i um-Btu Gas i f i cation
5. 1 Overview
5.2 Process Description
5.3 Appl i cations
5.4 Environmental Considerations
5.5 Performance
5 . 6 Econom i cs
References
Chemically Active Fluid Bed (CAFB)
6. 1 Overview
6.2 Process Description
6.3 App I i cations
6.4 Environmental Considerations
6.5 Performance
6 . 6 Econom i cs
References
Indirect Coal Liquefaction
7. 1 Overview.
7.2 Process Description
7.3 Appli cations
7.4 Environmental Considerations
7. 5 Performance
7 . 6 Econom i cs
References
High-Btu Gasi f i cat ion
8. 1 Overview
8.2 Process Description
8.3 Appli cations
8.4 Environmental Considerations
8.5 Performance
8 . 6 Econom i cs
References
Page
56
56
57
65
68
71
72
75
76
76
, 77
85
90
92
93
94
95
, 95
95
99
, 100
102
103
104
105
105
106
115
115
118
119
120
. 122
122
122
133
135
138
140
141
-------
TABLE OF CONTENTS (Cont'd:
9. Surface Oil Shale Processing 142
9.1 Overview 142
9.2 Process Description 143
9.3 Appl ications 148
9.4 Environmental Considerations 149
9. 5 Performance 1 53
9.6 Econom i cs 154
References 1 55
10. In Situ Oil Shale Processing 156
10.1 Overview 156
10.2 Process Description 157
10.3 Appl ications 164
10.4 Environmental Considerations 166
10.5 Performance 171
10.6 Economi cs 172
References 1 73
11. Di rect Coa I Liquefaction 174
11.1 Overview 174
11.2 Process Description 175
11.3 Appl ications 182
11.4 Environmental Considerations 185
11.5 Performance 188
11.6 Econom i cs 189
References 1 90
7
Fuel Cel I 191
12.1 Overview 191
12.2 Process Description 192
12.3 App I ications 1 97
12.4 Environmenta Considerations 200
12.5 Performance . 202
12.6 Econom i cs 202
References 204
13. Magnetohydrodynamics (MHD) 205
13.1 Overv i ew 205
13.2 Process Description 206
13.3 Appli cations , 215
13.4 Environmental Considerations 216
13.5 Performance 219
13.6 Econom i cs 220
References 221
x i
-------
LIST OF FIGURES
Number Page
1 Conventional Steam-Electric Plant 7
2 Heat Flow Diagram for Conventional
Coal-Fired Steam-Electric Plant 12
3 Diesel Driven Generator Plant 30
4 Heat Flow Diagram for Diesel Generator 31
5 Fl u i di zed-Bed Steam Generator 38
6 Schematic Diagram for Atmospheric
Fl u id i zed-Bed System 39
7 Schematic Diagram for Pressurized
FI u i d i zed-Bed System 40
8 Heat Flow Diagram for Atmospheric
Fl u i d i zed-Bed Combustor 45
9 Estimated Heat Flow Diagram for Advanced
Cycle - Pressurized Fiuidized-Bed Electric Plant 45
10 Simplified Schematic of Combined Gas
and Steam Cycle Generating System 58
11 Simplified Schematic of High Temperature
Combined Cycle Using Coal Derived Liquid Fuel 60
12 Simplified Schematic of High Temperature
Combined Cycle with Integrated Low-Btu Gasifier 61
13 Simplified Schematic of Supercharged Boiler
Combined Cycle Using Pressurized Coal-Fired
Fluid! zed-Bed Bo i I er 62
14 Heat Flow Diagram Based on Table 13 65
15 Generalized Flow Diagram - Low/Medium-Btu Gas 77
16 Lurgi Low-Btu Coal Gasification Process 79
17 Koppers-Totzek Coal Gasification Process 80
18 Westinghouse Electric Corp. Low-Btu
Gasification of Coal Process 81
19 Combustion Engineering, Inc. Low-Btu
Gasification of Coal Process 83
20 Heat Flow Diagram for Low-Btu
Gasification Plant 87
21 Heat Flow Diagram for Medium-Btu
Gasification Plant 89
XI I
-------
LIST OF FIGURES (Cont'd)
Number Page
22 General i zed Schematic of the CAFB 97
23 Estimated Heat Flow Diagram for
Coal Fed CAFB Plant 99
24 Synthes i zed Gaso I i ne From Coa I 1 09
25 Mob i I Cata I yt i c Process 110
26 Fischer-Tropsch Synthesis 112
27 Generalized Flow Diagram - High-Btu Gas 123
28 Carbon Dioxide Acceptor Process Schematic 126
29 Bl-GAS Process Schematic 128
30 HYGAS Process Schemat i c 1 30
31 Synthane Process Schematic 132
32 Estimated Heat Flow Diagram for High-Btu
Gasification Plant 135
33 Pyrolysis and Oil Recovery Unit
TOSCO II Plant.. 146
34 Estimated Heat Flow Diagram for
TOSCO II Plant. 148
35 True In Situ Retorting.... 159
36 Occidental Oil Shale Process
Retort Operation. 161
37 Flame Front Movement in the Occidental
Modified In Situ Process... 163
38 Estimated Energy Balance Schematic For
The Retorting Sections of an Occidental
Modified In Situ Plant 166
39 H-Coal Process 178
40 SRC-I Process 179
41 SRC-1 I Process 180
42 Donor Solvent Liquefaction Process 181
43 Energy Flow Diagram for a Commercial
Scale EDS Plant 184
44 Typical Fuel Cell 193
45 Fuel Cell Power Plant 195
XIII
-------
LIST OF FIGURES (Cont'd)
Number
46 Heat Flow Diagram for Fuel CelI
Power Plant 198
47 Faraday MHD Generator 206
48 Open-Cycle MHD/Steam Plant -
Schematic of Possible Configuration 209
49 Simplified Schematic of Closed-Cycle
Inert Gas MHD Topping Cycle 211
50 Simplified Schematic of Closed-Cycle
Liquid Metal MHD Topping Cycle Fired
by Fluidized Combustor 212
51 Projected Heat Balance for Nominal
2000 MWe Open-Cycle MHD/Steam Plant 214
x i v
-------
LIST OF TABLES
Number Page
1 Summary of Representative Current and
Projected Efficiencies of the Thirteen
Energy Technologies 3
2 Projected Generation Mix 5
3 Heat Balance for 500 MWe Conventional
Coal-Fired Steam-Electric Plant 11
4 Emissions and Effluents from
Conventional Power Plants 14
5 Base Case FI ue Gas Po I I utants 16
6 Base Case Estimate of Potential Trace
Elements Discharged to Atmosphere
Without Scrubber 19
7 Regional Heat Values for Utility
Steam-Electric Plants 23
8 Heat Balance for 5 MWe Diesel
Electric Plant 30
9 Estimated Heat Balance for 100 MBtu
Output Atmospheric Fl u i di zed-Bed Boiler 43
10 Estimated Heat Balance for 903.77 MWe
Advanced Steam Cycle - Pressurized
Fluidized-Bed Electric Plant 44
11 Emissions and Effluents from
Fluidized-Bed Boiler 48
12 Base Case Estimate of Potential Trace
Elements Discharged to Atmosphere
Without Scrubber 51
13 Estimated Heat Balance for 1200 MWe
Coa Fueled Combined Cycle Power Plant
with Integrated Low-Btu Gasifier 64
14 Estimated Heat Ba ance for Commercial
Scale Low-Btu Gasification Plant 86
15 Estimated Heat Balance for Commercial
Scale Medium-Btu Gasification Plant 88
16 Estimated Heat Balance for Coal Fed
Commercial Scale CAFB Plant ,
xv
-------
LIST OF TABLES CCont'd)
Number Page
17 Thermal Efficiencies 114
18 Estimated Heat Balance for a 270 Billion
Btu per day High-Btu Gasification Plant 134
19 Composition of Synthane By-Product Water 137
20 Representative Proximate and Ultimate
Analyses of Coals and Chars, Weight
Percent (Synthane Process) 139
21 Estimated Energy Balance For a TOSCO II
Plant Producing 47,000 BPSD Upgraded Oil
From 35 Gallons Per Ton Oil Shale 147
22 Estimated Energy Balance for the Retorting
Sections of an Occidental Modified In Situ
Plant for 35 Gallons Per Ton Oil Shale 165
23 Estimated Heat Balance for a Commercial
Scale EDS Plant 183
24 Comparison of Fuel Cell Types 195
25 Heat Balance for 500 MWe Fuel CelI
Power Plant 197
26 1975 Capital Cost Estimate Summary
for Integrated Coal Gasifier Fuel
Cell Power Plant (635-MW Plant) 203
27 Projected Heat Balance for Nominal
2000 MWe Open-Cycle MHD/Steam Plant 213
XV I
-------
ACKNOWLEDGEMENT
The authors of this report gratefully acknowledge the
technical support, consultations, and review provided
by Mr. Morris H. Altschuler and Mr. William N. McCarthy,
Jr., of the U. S. Environmental Protection Agency, Office
of Environmental Engineering and Technology, Washington,
D.C., in the preparation of this study.
XV I I
-------
INTRODUCTION
In an era of increasing fuel scarcity and environmental concern, it
is necessary to consider the implications associated with the various op-
tions for electric power generation, steam generation, and the conversion
of fossil energy values into alternative forms. This report provides a
review of 13 fossil fuel associated processes that currently, or in the
future, could be used for generating energy or converting fuel from one
form to another. The processes covered are either on-line or are in var-
ious stages of research and development. These processes are those at
the forefront of current capabilities or are believed to hold significant
future promise. The 13 processes are:
1. Conventional Boiler (with steam turbine)
2. Diesel Generator
3. Fluid!zed-Bed
4. Combined Cycle
5. Low/Medium-Btu Gasification
6. Chemically Active Fluid Bed (CAFB)
7. Indirect Coal Liquefaction
8. High-Btu Gasification
9. Surface Oil Shale Processing
10. In Situ Oil Shale Processing
11. Direct Coal Liquefaction
12. Fuel CelIs
13. Magnetohydrodynamics (MHD)
The ordering of the processes roughly corresponds to our estimate of
current and future significant commercial utilization. To assure consist-
ency and also provide an aid for comparative purposes, a uniform format
is used for each technology writeup. The major sections are as follows:
Overv i ew
Process Description
AppIications
Environmental Considerations
Performance
Economics
The Overview section provides a general summary of the particular
process. The Process Description section describes the process/technol-
ogy from both a theoretical and operational viewpoint. Included in the
Detail portion of the Process Description sections are energy balances
for the individual energy conversion or generation processes. The Appli-
cations section covers current (where applicable) and projected with em-
phasis on utility applications. The Environmental Considerations section
is subdivided into identified pollutants and regulatory impacts. As ap-
propriate, the emphasis is on utility applications. The ability of each
technology to comply with the current New Source Performance Standards
-------
(NSPS) is identified as appropriate. Since the composition of the emis-
sions and effluents associated with many of the new and developing tech-
nologies have yet to be fully characterized, only the major identified
emissions and effluents are emphasized. The Performance section and the
Economics section cover current and projected values. When there is no
operating experience, projections are provided.
Table 1 lists the thirteen addressed technologies including the
input fuel(s) and the specific output(s) of each. As an example, the
atmospheric fIuidized-bed combustor provides steam and the chemically ac-
tive fluid bed, (low-Btu) gas. For each technology, the current status
(e.g., commercial) is given along with an estimate of the current (1980)
and projected (1990-2000) efficiency. The efficiencies as expressed are
based on accepted definitions as related to the specific process and out-
put (e.g., diesel generator; electrical energy). It must be emphasized
that the efficiency values are for the specific process and not necessar-
ily a value to produce electricity. For example, the chemically active
fluid bed is projected to have a process efficiency of 81%. However,'
the overall efficiency to produce electricity (via steam generator) would
be 51%. It should be noted that for all processes a range of efficiency
values are to be expected and the provided values are typical efficiency
values for each individual technology.
The presented material is based on information obtained from avail-
able technical literature as well as from government and industry sources.
Every effort was made to include the most timely and relevant information.
A customized on-line data search of the National Technical Information
Service (NTIS) data base containing in excess of 500,000 reports was per-
formed and appropriate reports obtained. This information was reviewed
as to its relevance to the 13 processes and used as appropriate for re-
port development.
This report is intended to give the reader a general understanding
and appreciation for the relative environmental, operational, and economic
characteristics of the 13 processes addressed. Should further detail be
required beyond these Limited assessments, the reader is referred to the
list of references appearing at the end of each technology section. Cur-
rent and projected emission levels, economic data, and other values quoted
for each of the processes were obtained from the reference materials.
The reader is cautioned that these values are considered to be generally
representative of the particular processes under given conditions and are
not to be cons.trued as absolute. These values will vary with the speci-
fic installation, system configurations, heat content of fuel, or any one
or combination of a myriad of other variables. In the case of commer-
cially available technologies, the data presented can be traced to actual
achieved performance. When dealing with the new or developing technolo-
gies still undergoing intensive research, performance data have been pro-
jected by a number of researchers based on conceptual models., laboratory
experiments, or, in some cases, pilot plant operations. Needless to say,
such data must be considered rough engineering estimates and evaluated
as such by the reader.
-------
Table 1
Summary of Representative Current and Projected
Efficiencies of the Thirteen Energy Technologies
Technology
Status
Input
Fuel(s)
r. . . . Process Efficiency (%}
^rinc!Pa Current Projected
Output(s) ()g80) (]99o.s)
Comments
1. Conventional Steam
Electric Plant
2. Diesel Generator
3. a) Atmospheric
Flu i d i zed-Bed
Combustion
b) Pressurized
Flu i d i zed-Bed
Combustion
4. Combined Cycle
5. a) Low-Btu
Gasi f ication
b) Medium-Btu
Gasi f ication
6. Chemically Active
Fluid Bed (CAFB)
Commerc i a I CoaI
Electricity 34
Commercial Diesel Oil
Commerc i a I CoaI
and R&D
R&D
R&D
Coal
Commercial Gas or OiI
and R&D (or Coal)
Commerc i a I CoaI
and R&D
Commercial Coal
and R&D
Heavy Resid-
ual Oil or
Coal
Electricity 33
Steam (a)
Electricity (a)
Electricity 38
Low-Btu Gas
MedIum-Btu
Gas
Gas
86
80
(a)
38 Values for plants with
flue gas desuIfurization
(FGD). Without FGD, val-
ues are 35.4 and 39.5 re-
spect i vel y.
36 Established technology.
85 Insufficient operating
hi story to establi sh
ef f ic iency vaIue.
39 A combined cycle concept.
43 Currently fueled by gas or
oil. Projected efficien-
cy is based on an inte-
grated coal fed gasifier.
90 The efficiency values In-
clude the sensible heat
component and export power.
83 The efficiency values in-
clude the sensible heat
component.
87(b) The efficiency value in-
cludes the sensible heat
component.
(a) No U.S. commercial plants in existence or with an operating history
(b) Projected overall efficiency to produce electricity (via steam generator) is 31 percent
-------
Table 1 (Cont'd)
Summary of Representative Current and Projected
Efficiencies of the Thirteen Energy Technologies
7.
8.
9.
10.
11.
Technology Status _ , , .
a' Fuel (s)
Indirect Coal Commercial Coal
Liquefaction and R&D
High-Btu Gasification R&D Coal
Surface Oil Shale R&D Oil Shale
Process i ng
Modified In Situ Oil R&D Oil Shale
Sha 1 e Process i ng
Di rect Coal R&D Coal
Liquefaction
Pri nci pa 1
Output(s)
Hydrocarbon
Products
High-Btu
Gas
Oi 1 and
Gas
Oi 1 and
Gas
Hydrocarbon
Products
Process
Current
(1980)
(a)
(a)
(a)
(a)
(a)
Efficiency (%)
Projected
(1990's)
58
75
68
68
63
Comments
Commercial in South Africa,
al 1 U.S. activities R&D.
Efficiency value very de-
pendent on product mix.
The efficiency value in-
cludes credit for export
electric power.
Substantial variation In
obtainable value depend-
ing on very site specific
conditions.
Substantial variation in
obtainable value depend-
ing on very site specific
cond itions.
Value for EDS process.
Includes credit for by-
12. Fuel Cells
R&D
13. Magnetohydrodynamics R&D
(MHD)
FossiI Fuel
(e.g., gas
obta i ned
from coaI)
Coal
Electricity
(a)
Electricity
(a)
products.
50 The efficiency value is
for a coal fueled (via
gasifier) plant with a
steam-turbine bottoming
cycle.
48 The efficiency value is
for an open-cycle MHD/
steam plant.
(a) No U.S. commercial plants in existence or with an operating history
-------
TECHNOLOGY ASSESSMENTS
1. Conventional Coal-Fired Steam-Electric Power Plant
1.1 Overview
The conventional boiler steam-electric plant (also referred to as
boiler-turbine plant) is by far the most employed means of generating
electric utility produced electric energy in the United States. In
1978, over 72 percent of electric utility produced electric energy was
from coal, oil or gas-fired boiler steam-electric plants. Of the total
fossil fuel derived utility electric energy in 1978, over 61 percent
was from coal firing.
Recent and projected electric utility supplied electric energy mix
as based on reference 1 is provided in Table 2. Undoubtedly, steam-
electric plants will be the backbone of the U.S. electric utility indus-
try in the foreseeable future.
Table 2
Projected Generation Mix
(Based on kilowatt-hours)
Type
Generation
Coal
Oi I
Gas
Foss i I Fuel Tota I
Nuc I ear
Hydro
Other
Total
1976 Actual
Percent
46.3
15.7
14.4
76.4
9.4
13.9
0.3
100.0
1981
Percent
47-7
17.7
6.6
72.0
19.0
8.5
0.5
100.0
1986
Percent
47.7
14.6
2.8
65.1
27.8
6.5
0.6
100.0
The current efficiency of on-line steam-electric plants range from
approximately 31 to 38 percent. The prospect for the foreseeable future
is that newer plants will have efficiency values below 40 percent. It
is unlikely that truly operational efficiency values in excess of 40
percent from conventional plants will be realized within the next 15 to
20 years.
-------
In the absence of pollution control measures, coal-fired steam-
electric plants would provide very substantial undesirable environmental
impacts. However, the current environmental control state-of-the-art
and resulting control measures are capable of substantially mitigating
currently identified undesirable pollution and other environmental ef-
fects. Continuing environmental control activities are expected to
provide the means to control potential overall undesirable effects re-
sulting from increasing use of coal to fire steam-electric plants.
1.2 Process Description
Concept
The conventional boiler steam-electric plant basically consists of
a fossil fuel fired boiler to generate steam that in turn drives a tur-
bine generator. In addition, a full plant contains many other associated
elements. These include: (1) coal handling components, (2) ash handling
units, (3) a steam condenser with associated water cooling provisions
(e.g., tower, pond), (4) plant water treatment elements, and (5) often a
stack gas cleanup system with associated reagent and effluent handling
elements. A typical basic diagram of a conventional system is provided
in Figure 1.
Heat for the production of steam is obtained from the combustion of
a fuel in a furnace. The energy released by the combustion of fuel is
absorbed by the operating medium (usually water and its vapors) in a
boiler. The boiler is a closed vessel in which water is confined and
heated, steam is generated, steam is superheated, or any combination
thereof, usually under pressure by the application of heat from combus-
tion of fuels. In practice, the boiler is generally a combination of
tubing with one or more cylinders called drums. Steam produced in the
boiler drives a turbine. The shaft of the turbine assembly is coupled to
an electric generator.
Deta iI
For the fuel combustion process to adequately take place in a furn-
ace, it is necessary to:
1. Introduce fuel and air for combustion,
2. Burn the fuel,
3. Remove the products of combustion and refuse
remaining after combustion.
The five requirements for perfect combustion are:
1. Proper proportions of fuel and air,
2. Adequate mixing of fuel and air,
3. Sufficient boiler surface heat transfer area,
-------
Emitted Flue Gas
Reagent
Water
1
mestone)
Stack Gas
Scrubber
( i f used )
•»•
Spent
Reagent
I
Coal
Air
Electrostatic precipitator
Stack Gas
Roi ler
(NOTE: For simplicity, items such
as economizer, airheater, etc.
are not shown.)
llowdown
*
Condensate
Poli sh i ng
El ectrica 1
Output
Water
Treatment
Figure 1
Conventional Steam-Electric Plant
Cooli ng
Tower
Slowdown
Steam
Condenser
-------
4. Sufficient combustion temperatures, and
5. Adequate fuel residence time to allow for complete
combustion.
The efficiency of a steam-electric power plant is defined as the
ratio of electrical energy output to the total plant energy input.
Overall plant efficiency is determined by many factors including boiler
efficiency, turbine performance in relation to supplied energy, gener-
ator efficiency, plant losses, auxiliary power requirements, etc.
Boiler efficiency is defined as the ratio of heat absorbed by the
water and steam to the heat in fuel fired. In this regard, the state-
of-the-art in boiler plant design and manufacture is well advanced.
Modern utility boiler plants are generally very efficient with factors
affecting losses in efficiency well understood.
For modern utility boilers, boiler efficiencies in the range of 85
to 90 percent are representative of the current state-of-the-art. The
major components with their representative loss values are the following:
1. Heating excess combustion air (~0.1-0.!
2. Incomplete fuel combustion (less than
3. Heating of moisture in coal and air (4-10$)
4. Losses associated with energy in flue gas (4-6$).
In a steam-electric power plant, the steam from the boiler, as pre-
viously indicated, is fed to drive a steam turbine. The steam turbine
is a heat engine that takes energy from a high temperature, high pres-
sure steam, converts the extracted heat energy to mechanical energy,
and rejects unusable waste heat at a lower temperature and pressure.
The discharged steam is condensed to water in a condenser. This same
water is then pumped back into the boiler to be reheated and start the
cycle over again. The heat from the condenser is rejected to the envi-
ronment usually via a cooling tower or cool body of water.
In actual practice, the turbine assembly is composed of several
units. Typically, the spent steam output from the first or high-pressure
turbine is reheated and fed to the second or intermediate turbine. The
spent steam output of the second turbine then feeds the low pressure
turbine. After the turbine, the discharged steam is converted to water
by the condenser and is continuously directed back to the boiler (often
after processing to remove undesirable contaminants) to continue the
cycle. During the cycle, some of the boiler working medium (steam and
water) is lost or possibly purposely rejected to dispose of undesirable
boiler water constituents. Makeup feedwater is processed to be more
acceptable to the boiler and fed to the boiler to compensate for system
working medium losses.
-------
According to the second law of thermodynamics, a heat engine such
as the steam turbine cannot convert all of the transferred heat into
mechanical energy. That is, given a source of heat coupled with a heat/
work cycle, only a portion of the heat can be converted to work and the
remainder is rejected as heat to a sink such as the atmosphere. The Car-
not cycle is a theoretical concept which depicts a heat engine operating
within the second law of thermodynamics. This cycle has no real counter
part in practice but is useful as a standard in evaluating the perform-
ance of actual heat engines.
The Rankine cycle is a reversible cycle, similar to the Carnot
cycle. As compared to the Carnot cycle, the Rankine cycle more nearly
approximates steam turbine energy system efficiencies. If a Rankine
cycle is closed in the sense that the same working fluid is used in a
continuous fashion, it is termed a condensing cycle. There are two mod-
ifications as to boiler/turbine interconnect that can improve the thermal
efficiency of the Rankine cycle (and the steam turbine). These are:
1. Reheat - This involves a process where a portion of the
steam that has partially expanded in the turbine is re-
heated in the boiler and then returned to the turbine
to complete the expansion process. The output from one
turbine section can be reheated in a boiler and then
returned to a second turbine section.
2. Regeneration - This involves extracting a portion of
the steam from the turbine after (only) partial expan-
sion and transferring heat energy to boiler return water
prior to entering the boiler.
The Carnot cycle efficiency is a theoretical value that cannot be
achieved in practice but can serve as a measure of performance for actual
cycles. This cycle offers maximum thermal efficiency attainable between
any given temperature of heat source and sink and depends only on these
two temperatures. The Carnot efficiency is given by:
T - T T
r- _ ' fi — 1 £L
E " T, " 1 " T,
where:
E = thermal efficiency of heat to work conversion
(decimaI vaIue)
T. = abso ute temperature of heat source, R
T7 - absolute temperature of heat sink, R
-------
The equations show that the thermal efficiency is improved by in-
creasing the temperature of the heat source and decreasing the temper-
ature of the heat sink.
A turbine generally has a maximum inlet steam temperature of approx-
imately 1000 F (1460 R) and a minimum sink temperature of 70 F (530 R).
This corresponds to a Carnot (i.e., theoretical) conversion efficiency of
64 percent.
In actual practice, the value is considerably less for a number of
reasons. The actual turbine cycle efficiency does not approach that of
the Carnot cycle. In addition, there are a number of losses which in-
clude but are not limited to the following:
1. Residual velocity loss. The steam leaving the turbine
also carries with it residual velocity loss which dis-
sipates into increased enthalpy of the steam entering
the condenser,
2. Steam leakage losses at shaft glands, or packing, be-
tween stages,
3. Nozzle losses due to friction and turbulence,
4. Blade losses caused by friction and turbulence,
5. Rotational losses caused by the friction between the
blades and rotating parts of the turbine turning in
the steam,
6. Bearing and external losses,
7. Radiation loss (usually relatively negligible).
In addition, when considering the entire steam electric system,
there are generator losses which generally are relatively minor. The
efficiency of the electrical generator (which varies with load) is
generally in excess of 98 percent.
A reasonable heat balance (Table 3) for a plant with full FGD and
an overall plant efficiency (including the FGD system) of 35 percent
(nominal) follows. The tabulation is based on a 500 MWe plant and is
provided both in terms of Btu flow per hour and percent of Btu flow.
The values are consistent with the above discussion and represent a
plant within the size and efficiency ranges of utility plants currently
in service.
DiagrammaticaIly, this can be illustrated by the heat flow diagram,
Figure 2. This diagram indicates the energy disposition on a percentage
of the total input basis and is consistent with Table 3.
10
-------
Table 3
Heat Balance for 500 MWe Conventional
Coal-Fired Steam-Electric Plant
Btu/hour Percent of Total
(10 Btu's) Energy Input
Net Electrical Energy Output 1,706.10 35.0
Furnace Losses
Heating excess combustion air 9.75 0.2
Incomplete fuel combustion 39.00 0.8
Heating moisture in coal and air 243.70 5.0
Energy in flue gas 243.70 5.0
Miscellaneous (heat loss, etc.) 24.40 0.5
Heat Rejected
Heat rejected to cooling tower
and otherwise lost (e.g.,
through boiler blowdown) 2,456.78 50.4
Energy Consumed (Auxiliaries and
others)
FGD system 70.70 1.45
Coal preparation 21.94 0.45
Cooling tower pumps and fans 19.50 0.40
Other (electrostatic precipitators,
system fans, etc.) 39.00 0.80
Total Energy Input 4,874.57 100.0
Based on coal with 11,500 Btu/lb, 3 percent sulfur by weight.
-------
100$
Heat input from coal
Furnace losses
11.5%S
Dsses \
3.1$
Energy consumed
50.4$
Heat rejected
35$
Net electrical energy output
Figure 2
Heat Flow Diagram for Conventional Coal Fired Steam Electric Plant
1.3 AppIications
Current
In 1978, coal supplied approximately 44 percent of the total input
energy for utility electrical power generation in the United States (2).
According to Reference 3, there was a 6.9 percent increase in Btu's
supplied by coal to electric utilities for 1977 as compared to 1976.
For 1979, coal was estimated to fuel approximately 1,075 X 10 kwh out
of a total of 2,248 X 10 or 47.8 percent of the total (2). The energy
supplied by this coal would be used to fuel conventional steam-electric
pi ants.
During 1978, 61.2 percent of utility electric power produced by
fossil-fired plants was from burning coal. This represents 974.3 X 10
kwh out of a total fossil fuel level of 1,592 X 10 kwh. During the
12
-------
q
same period, nuclear accounted for only 255 X 10 kwh of electrical ener-
gy. In the United States, coal provides for substantially more electric
power than any other fuel (3).
Projected
The 1979 issue of the National Coal Association publication en-
titled "Steam Electric Plant Factors" (3) has identified 269 coal fired
steam-electric plants projected to come on stream by the end of 1988.
These 269 plants have a capacity of 140,887 MW. In contrast, only 11
oil fired plants with a total capacity of 6,722 MW have been identified
for the same period.
AM indications are that the U.S. electric power industry will be-
come increasingly dependent on coal. In the foreseeable future, it is
expected that essentially all new coal fueled utility plants will be the
conventional boiler-turbine variety covered by this report.
1.4 Environmental Considerations
Emissions from power plants can be classified as continuous, sched-
uled intermittent, and unscheduled intermittent. Continuous emissions
include pollutants that are contained in the flue gas discharged from the
furnace stack. Scheduled intermittent emissions include discharge of
limestone and ash to storage piles, and aqueous wastes from cleaning
equipment. Unscheduled intermittent emissions include transients due to
operating upsets, fugitive dust from coal, and storm run-off. For each
operating or projected power plant, all of these pollution sources must
be thoroughly considered and adequately controlled. Pollution control
methods may vary and will depend to a considerable extent on the specific
plant design and operating situation. While some variability certainly
exists, this evaluation of the potential environmental intrusion of a
modern power plant using a conventional furnace provides a framework to
guide the evaluation of emissions from fossil fuel fired power systems.
It also represents a base case against which new energy conversion sys-
tems can be compared, to see in what respects they are better or worse
than present technology. The provided environmental material was de-
rived in whole or part from reference 4. References contained in refer-
ence 4 are also provided herein.
Identified Pollutants
Areas of environmental concern are summarized in Table 4. In the
following detailed discussion, emissions to the air will be discussed
first, in the order of process flow, followed by a similar discussion
of solids and liquid effluents, and then trace elements.
-------
Table 4
Emissions and Effluents from Conventional Power Plants
Emissions to Atmosphere
Wind action on coal storage and
hand Ii ng
Wind action on limestone and waste
Waste vapor from grinding
Cleaned fIue gas
Vacuum pump on steam condenser
Air and mist from cooling tower
Possible fugitive dust from area
Transients due to upsets, cleaning,
etc.
Potential noise and odors
Effluents - Liquids and Solids
Rain runoff - coal, limestone, and
waste areas
Ash Slurry
Slurry of waste from stack gas
cleanup '
Sludge and chemicals from water
treat!ng
Trace Elements
Leaching associated with disposal
of ash and Iimestone waste
Fate of volatile toxic elements in
coal feed
Emissions as gas and PM and POM
with stack gas
Potential Concerns
Dust, fire, odors
Dust
Dust, H2S
NO , plume dispersion,
Xdust, SO , POM*
x
Minor
Plume, mist deposition,
trace chemicals
Dust nuisance
Dust, smoke, fumes
Machinery, maintenance
Suspended and dissolved
matter
Groundwater contamination
Groundwater contamination
and land use
Mi nor
Soluble toxic elements
Contamination of local
a i r and water
Health hazard
= Polynuclear Organic Materia
14
-------
Air Emissions
The first area to consider is the coal preparation area, primarily
coal storage and grinding. Wind action on the coal pile can cause a
dust nuisance especially during loading and unloading operations.
The grinding process, prior to firing in a pulverized coal fired
boiler, reduces the coal to smaller than 200 mesh. Moisture laden
grinding effluent gas from drying may contain sulfur compounds, combust-
ibles, and other trace components. Depending on its composition, the
stream may need to be either scrubbed or incinerated prior to venting.
The precautions used to prepare the stack gas scrubbing reagent
should be similar to those of coal, since the scrubber reagent (e.g.,
limestone) is often stored, ground, and used in a manner comparable to
coa I .
Ground coal is fed to the furnace where it is essentially complete-
ly burned. The ash residue (bottom ash) is withdrawn and quenched with
water, care being required to see that vapors and fumes from quenching
are collected and returned to the system rather than becoming an. efflu-
ent to the air. Ash is handled as a slurry to prevent dusting.
Flue gases from the furnace are a major environmental concern since
they contain many pollutants including SO , NO , polynuclear organic mat-
ter (POM), trace elements, etc. At present, there is no fully accepted
way to remove NO from flue gas, but NO can be controlled by modifying
combustion conditions to minimize its formation. Flue gas recircuIation
staged combustion, and reduction of excess air are methods that have been
effectively demonstrated on full size equipment (5). These methods tend
to decrease flame temperature, and/or the availability of oxygen. Cur-
rently the U.S. Environmental Protection Agency through its laboratory
in North Carol i.ia is pursuing a substantial program addressing NO reduc-
tion by burner/combustion modification techniques. Limestone scrubbing
is used primarily to remove sulfur oxides but can also be effective in
removing particulates, associated trace elements, and other contaminants.
Electrostatic precipitators remove most of the dust ahead of the lime-
stone scrubber. Electric precipitators are very effective in removing
particles greater than a micron. Submicron particles, on the other hand,
are not removed efficiently by these precipitators.
Adjusting the data presented by Crawford et al. (5) for an 800 MWe
power plant using a tangentially fired furnace operating at 24.2 Mpa/
811 K with Black Mesa Subbituminous coal which contains 1.4% N (moisture
free) for the specific example in this base case, potential emissions
are compared with Federal standards in Table 5, in order to show the
degree of removal or cleanup required.
-------
Table 5
Base Case Flue Gas Pollutants
SO (as SOQ)
x 2
NO (as N00)
x 2
Part icu 1 ates
CO
1 n Raw Gas
g/J
3.10
0.28
3.84
0.02
New Source
Performance Standard
g/J
0.31*
0.215
0.013
None
% Remova I
Requ i red
90.0
23.0
99.66
None
* See NSPS for SO emission criteria as a function of coal
suI fur content.
In a stack scrubber, generally some water is evaporated to cool the
gas by adiabatic humidification. The scrubbed gases are then released
to the atmosphere. The scrubbing system should be designed to minimize
and control mist and spray carryover. It is important to control and
minimize entrainment and loss of the scrubbing liquid in the vent gas,
since it may cause objectionable residues, deposits and other problems.
As more information is obtained, other pollutants in the flue gas
may become of concern. For example, nitrates, HCN, suI fates, and organic
matter are areas now being examined. Also, it is known that chlorides in
the coal are volatilized during combustion, and can leave in the flue
gases as HCI. In many operating power plants, the HCI formed is presum-
ably released to the air, but with limestone scrubbing, it will be re-
moved by reacting with the limestone to form soluble CaCI?.
Periodic cleaning of furnace equipment is required and precautions
are needed to avoid emissions to the air at such times. One method of
on-stream cleaning of heat transfer surfaces is called "soot blowing,"
using high velocity jets of steam to dislodge deposits. Most of the
additional dust load will be recovered in the electrostatic precipita-
tor and scrubber but if the system is overloaded, there can be serious
emission of pollutants. The deposits are made up of fine particles,
which will be high in volatile trace elements according to indications
from related studies (6). Equipment cleaning at shutdown or during
turnaround can also cause dust nuisances, or even a hazard in the case
of deposits of toxic materials.
16
-------
The final air emission consideration is the cooling tower. The air
flow through it is by far the largest stream in a plant, and its contam-
ination is therefore a major concern. Fortunately, it appears that it
will be clean and not subject to contamination. The cooling water in a
power plant is used almost exclusively for condensing steam under vacuum,
and very little is exchanged with lubricating oil or scrubbing liquid
where leaks could cause contamination (7).
Solid and Liquid Effluents
The first effluent of solids and liquids covered are those from the
coal and limestone storage piles and handling area. Here, rain runoff
will contain suspended solids and may also contain soluble sulfur and
iron compounds. The coal pile is subject to oxidation and weathering,
with conditions similar to those associated with acid mine water. As
one precaution, curbing should enclose the storage pile and coal prepar-
ation area, so that runoff can be segregated and sent to a storm pond for
settling. The water can then be treated prior to disposal or treated and
used for makeup.
The next consideration is ash disposal from the furnace. The ash
is slurried with water for handling and will go to an ash pond in some
cases for settling, so that the water can be recycled. Ash is then peri-
odically removed from the pond bottom for offsite disposal as landfill,
construction raw material , or for some other application. Ash disposal
poses serious problems with regard to dusting when it dries out, and in
the presence of water it can cause problems from possible leaching of
sulfur, trace elements and soluble salts. Therefore, the ash pond may
have to be lined, and the extent of leaching determined and controlled
for any specific situation. Some preliminary studies have been made in
this area (8); but much more work is needed.
Wastes from stack gas cleanup constitute the largest effluent of
solids and liquids from the power plant. For a limestone system, the
solids consist mostly of calcium sulfite, with some sulfate, plus unre-
acted I imestone and other reaction products. As mentioned earlier, HCI
can be formed during combustion, forming CaCI~ in the scrubber. Also,
nearly all limestones contain some magnesium as well, which can form
soluble MgSO.. Calcium sulfate is sufficiently soluble to result in
very hard wafer. Disposal of the large volume of scrubber waste could
pose a formidable problem. It may be handled as a slurry containing 50
wt. percent water, and be sent to retention ponds. The high value land
used for such disposal will not be available in many plant locations.
The land area required for twenty years accumulation based on 65 percent
load factor is very significant.
One approach to disposal is chemical stabilization of the waste to
make it suitable as landfill. Chemical stabilization is being tested
17
-------
at TVA in EPA sponsored programs (9) using processes offered by Dravo
Corporation, Chemfix Inc., and IU Conversion Systems, Inc. Leaching
of these wastes must be considered, including the transport of soluble
salts (sodium salts, etc.) introduced by slurrying with blowdown water.
Perhaps the waste could be developed into a useful soil conditioner, or
used as raw material for bricks, road construction, sewer pipe, etc.
Slagging the waste would probably stabilize it as a road base, if the
cost could be justified. Leaching of sulfurous compounds needs to be
considered, in addition to leaching of soluble compounds such as those
mentioned above. The latter are of particular concern, since many vola-
tile trace elements in the coal will appear in the scrubber waste, and
many of these volatile elements are toxic.
The net discharge of waste water from the plant is included with
the scrubber waste, which is slurried mainly with blowdown water from
the cooling tower. The latter water stream contains about 3,000 ppm of
soluble salts brought in with the makeup water and concentrated in the
cooling water circuit by evaporation in the cooling tower. In addition,
the dissolved solids may be increased more than twofold by the contrib-
utions of CaCI-, MgSO., and CaSO. discussed earlier. Thus, the water
portion of the slurry waste could lead to unacceptable hardness and
solids content if it gets' into groundwater supplies. It does not appear
to be acceptable for irrigation, or for discharge into inland rivers,
although ocean disposal might be acceptable, where applicable. At pres-
ent, the only possible disposal method seems to be storage in a very
large pond, with positive control of seepage and overflow. Evaporation
to a paste would ease the storage problem.
As previously mentioned, blowdown from the cooling tower is used
to control buildup of dissolved solids in the cooling water circuit.
Similarly, blowdown from the boiler controls solids content in steam
generation, and serves as partial makeup to the cooling tower. Other
miscellaneous waste streams of sludges and liquids come from treating
the fresh water to make it suitable as makeup to the cooling tower or
boilers. Chemicals used in water treating could include a I urn for coagu-
lation and separation of suspended matter, lime to precipitate hardness,
plus spent sulfuric acid and caustic from regenerating ion exchange re-
sins used to demineralize boiler feedwater. These can be combined, neu-
tralized, and included with the waste stream from limestone scrubbing.
Trace Elements
A great many trace elements are contained in coal; and although the
concentration may be low, the total potential emissions can be very
large when considering the total coal consumed in the U.S. Many of the
trace elements are toxic; moreover, the emissions are concentrated at
large power plant locations. For orientation, typical content of trace
elements is given in Table 6 for Illinois No. 6 coal, together with a
-------
Table 6
Base Case Estimate of Potential Trace Elements
Discharged to Atmosphere Without Scrubber
Element
Antimony
Arsenic
Beryl 1 i urn
Boron
Bromi ne
Cadmi um
Ch lor i ne
F 1 uor i ne
Lead
Mercury
Mo 1 ybdenum
Sel en i um
Vanad i um
Zi nc
Total
ppm in Coal
(Dry Basis)
0.5a
8-45
0.6 - 7.6
13 - 198
14. 2a
0.149
400 - 10003
50 - 167
8-14
0.04 - 0.49
0.6 - 8.5
2.2a
8.7 - 67
0-53
Average
% Emitted
25
25
25
25
100
35
100
100
35
90
25
70
30
25
Emitted
kg/d
0.81
13 -
1.0
21 -
92.0
0.32
2600
320
18 -
0.2
1 .0
10.0
17 -
0 -
3094
73
- 12
320
- 6500
-1100
32
- 2.9
- 14
130
86
- 8373
a - Not given in EGAS basis and therefore, not estimated.
b - Based on a feed rate of 6892 tpd of I I Iinois No. 6 coal.
total estimated discharge to the atmosphere for a 800 MWe plant based on
CGA estimates (7) that used national average efficiencies for contact
devices. It must be emphasized that these estimates do not take into
account the effect of the FGD scrubber on controlling trace element emis-
sions. Only actual tests at a power plant using Illinois No. 6 and the
flue gas treatment equipment specified in this design could provide the
data to assess the potential trace element problem.
-------
The very large combined amount of these trace elements may be cause
for concern as to possible environmental and health hazards. Many ex-
periments have shown that all of the elements listed are partially vola-
tile at combustion conditions, and most of them are known to be toxic in
sufficient concentration. Tests also show that many of these elements
become concentrated on the fly ash carried out with combustion gases, and
the relative concentration of trace elements in particulates increases
with decreasing particle diameter (6). Particulates leaving the stack
after electrostatic precipitation have the highest concentration of all.
Some elements such as Br, Cl, F, and Hg, are reported to leave in vapor
form with the flue gases, as can be seen from the estimated '$ emitted'
column in Table 6.
The concentration of trace elements in fine ash, such as that col-
lected in an electrostatic precipitator, raises questions as to safe
methods for handling or disposing of such wastes. For example, if the
wastes are dumped or used as land fill, there are serious questions of
leaching and possible contamination of vegetation or groundwater. Fines
collected in a stack scrubber raise similar questions about disposal. If
fines are not adequately removed from the stack gas, then these contamin-
ated particles may be dispersed into the air we breathe. Moreover, these
fine particles also absorb liquid from the stack gas,, giving an acid con-
densate containing sulfurous and suIfuric acid. HCI is apparently formed
in the combustion process and may also be present. Therefore, a highly
acid condition exists on the surface of the particle, which may activate
or solubilize the trace element contaminants.
In one program (10), the fate of 37 trace elements in coal was
traced through a power plant combustion system. Results showed that many
of the 37 elements were appreciably volatile, becoming concentrated on
the fine particles collected by electrostatic precipitation. Uncol-
lected particles were even higher in concentration of trace elements.
It was concluded that most of the bromine, chlorine, and mercury remain
in the gas phase, along-with much of the selenium. Appreciable vola-
tility during combustion was also found for arsenic, cadmium, copper,
gallium, lead, molybdenum, and zinc. Most of these have already been
designated as toxic.
The flue gases entering the scrubber can contain mercury, arsenic,
selenium, and possibly also chlorine, fluorine and bromine. The degree
of removal of these materials in the scrubber will be a function of the
scrubbing medium. It is likely that the halogens will be present as
acids and be removed by aqueous scrubbing, but this is not certain, and
it is therefore important to determine the form in which trace elements
appear in order to develop suitable methods for their removal and deact-
ivation. Stack gas cleanup may use scrubbing with lime, limestone, su I -
furic acid, or other liquids. The chemical reactions that occur with
trace elements will be different and need to be considered and evaluated
on an individual basis.
20
-------
It is clear that sizable amounts of undesirable or toxic elements
are present in coal, that many of these are partially volatile during
combustion and become concentrated on the finer particles, and appear to
present a potentially serious environmental hazard. Studies are needed
to show how to deactivate and dispose of them in an environmentally
acceptable manner. It is most important that these studies be made be-
fore the potential problems become difficult and urgent.
Noi se
Noise affects power plant employees and those in the immediate vi-
cinity but does not have much impact on the rest of the surroundings.
Thus, noise pollution is an occupational rather than an environmental
problem. The occupational hazard of noise, as well as its general annoy-
ing influence in residential as well as commercial areas, has been the
subject of recent Federal legislation. The Department of Labor Occupa-
tional Noise Exposure Standards specifies the Permissible Noise Exposure
which relates to hearing protection.
Recently, Heymann, et a I. (11) presented data indicating that the
average sound pressure level around steam turbine generators rated at
700 MW is 94 dBa. Thus, according to the Department of Labor Occupa-
tional Exposure Standard, personnel may not be exposed to such a noisy
environment for more than four hours per day. The noise level of other
components of conventional power plants was measured by Broderson, et al.
(12). Broderson et a I. also established that power plant workers exhibit
significantly greater hearing loss than the normal, non-noise exposed
population. The hearing loss fits the general pattern of compensable,
noise-induced hearing loss which increases with time exposure. The study
established that 37 percent of the employees received an unacceptable
high noise dose, resulting in an average hearing loss greater than 20 dB
at 4000 Hz in 39 percent of the employees in the 35-50 age group, and 86
percent of the employees in the over-51 age group.
In order to avoid this occupational problem in power plants, a num-
ber of component manufacturers offer noise control options with poten-
tial ly noisy equipment. The options include acoustically designed pipe
laggings and enclosures for coupling, special enclosures for rotating
equipment and valves, and acoustical treatment for the generator housing
(13).
Regulatory Impacts
Currently, there is a substantial body of regulatory control over
the electric utility industry. There are Federal and state emission
standards covering existing plants for air, water, and solid waste. In
addition, trace elements are receiving increasing attention. In the
21
-------
future, as more and more coal is utilized, pollution levels (e.g.,
production, acid rain, inhalable particulates) would substantially
increase without additional mitigating measures.
1.5 Performance
Current
The limitations on the obtainable efficiency from a coal fired
steam-electric plant is well understood. Obtainable efficiency is sub-
stantially less than the ideal thermodynamic value. Even though boiler
efficiencies are generally high in that most of the available energy in
the fuel is transformed to the boiler working medium, it does not neces-
sarily follow that the energy is substantially usable by the turbine.
Turbine output is based not only on the energy available in the steam,
but also on the energy in the steam flow and the steam temperature. As
previously indicated, using 1000°F steam temperature and a body of water
at 70°F for condensate cooling, we have a Carnot efficiency value of 64
percent. The only way to increase the Carnot efficiency value is to
either increase the steam temperature (to the turbine) and/or reduce the
heat sink temperature (for condensate). Furthermore, the actual turbine
cycle is not as good as the Carnot cycle and, in addition, there are a
number of system losses (e.g., friction, nozzle, etc.).
Unfortunately, the steam temperature to the turbine is limited by
the metallurgical state-of-the-art coupled with very severe economic
restrictions. In essence, materials that can tolerate higher than
currently employed temperatures are rare, extremely expensive, and very
difficult to fabricate.
On the turbine output side, the available energy from the boiler is
not available when the working fluid reaches the sink temperature. In
actual practice, the theoretical efficiency of each stage of a turbine
can be calculated from the energy dissipated by the throughput working
medium. The actual turbine efficiency is reduced by a number of unavoid-
able losses as previously indicated.
In the past (not currently), the National Coal Association, in
their annual publication entitled "Steam Electric Plant Factors," pro-
vided steam-electric utility heat rates by region. The heat rate is the
average number of Btu's required to produce a kwh of electrical energy.
Table 7 provides regional heat rate values for coal fired plants for CY
1972 (14).
The values in the Table are believed to be fairly representative of
the current overall situation. There are a number of recently completed
plants around the world that achieve significantly higher efficiencies.
22
-------
Table 7
Regional Heat Rate Values for Utility Steam Electric Plants
Area
Heat Rate
Average Regional Efficiency
United States
New England
Middle Atlantic
E. North Central
W. North Central
South Atlantic
E. South Central
W. South Central
Mounta i n
10,176
10,770
10,264
10,300
11,012
9,781
9,882
10,639
10,458
33.5$
31.7$
33.2$
33.1$
31.0$
34 . 9$
34.5$
32.1$
32.6$
The following, obtained from reference 15, is an indication of the cur-
rent state-of-the-art in coal fired electrical generating systems. These
U. S. coal fired boi ler-turbine units are among the best in the world.
The stated efficiencies are defined as:
Efficiency =
100 x NEO
TEC
where:
NEO
Net electrical output, expressed as units exported
from the station during the year (having deducted
all house load and auxiliary unit usage)
TEC = Total energy consumed in that year, expressed in
kwh and based on the gross or higher calorific
vaIue of all fuel.
Utility Power Station Size Load
Name Name Year (MWe) Factor Efficiency
TVA Bull Run 1975 950 74.9$ 38.28$
Duke Power Be lews Creek 1975 1100 57.5$ 38.21$
Duke Power Marshall 1975 650 58.8$ 38.07$
23
-------
The values indicated, as based on available information, are assumed
to not include efficiency reductions for flue gas desuIfurization sys-
tems. A full scale flue gas desuIfurization system is estimated to use
an amount of energy equal to four percent of the output energy. This
value includes one percent used for flue gas reheat. A fIue gas desuI -
furization system that would only treat fifty percent of the flue gas is
not expected to require reheat and correspondingly- would use an energy
level of one to one and one-half percent of the plant output. The above
systems would have overall efficiencies of approximately 36.7 percent
with full scale flue gas desuIfurization and 37.7 percent if only half
the gas is cleaned.
Projected
The peak efficiency value of on-line coal-fired conventional steam
electric plants is not expected to show any significant improvements
through the 1990's over what is currently being attained. The genera-
tion of electric energy by conventional boiler steam turbine plants is
certainly a very mature technology. The losses and limitations are very
well understood. At best, a coal-fired steam-electric plant is not ex-
pected to achieve a 40 percent overall operational efficiency value.
The expectation, based in part from inputs by industry sources, is that
without FGD, the value could be between 39 to 40 percent. With FGD, a
peak efficiency value of 38 percent appears reasonable. This equates to
a projected 4 percent improvement over current capabilities.
1.6 Economics
Current
The economics of the current situation is indicated by the cost of
a new coal fired steam-electric plant and the present selling price of
utility generated electric energy. It should be noted that considerable
spread exists on electric rates and on construction costs. In addition,
when making comparisons, it is necessary to define what is included in
cost vaIues.
The time it takes to bring a new plant on-line has increased over
the past ten to fifteen years. This is due in part to additional legal
requirements (i.e., site justification, impact studies, inprocess inspec-
tions, various permits, etc.). Increased construction time combined with
the high cost of money has a significant impact on a final cost. Total
construction cost includes, but is not limited to: (1) land for plant
and possible effluent disposal, (2) coal handling and associated facili-
ties, (3) steam turbine plant, (4) electrical system, (5) A-E cost with
contingency, (6) interest during construction, (7) escalation during
construction, (8) permits, assessments, etc. In view of the above, ref-
erence 4 provides the following CY 1976 per kWe cost for a 800 MWe unit
as foI lows:
24
-------
Furnace/steam boiler $ 110
Steam turbogenerator 66
Stack-gas cleanup 139
Balance of plant 520
$ 635 per kW of installed capacity
The indicated values do not include land cost and provisions for
on-site disposal. A general rule of thumb is that a complete plant will
cost in the area of $800 to $1000 per kW installed capacity.
The mid-1979 selI ing price of electric energy to industrial custo-
mers varied from approximately 27 to 40 mills per kilowatt-hour. The
breakdown of cost components is typically as follows:
1. capital component - 66.6 percent (of total),
2. operation and maintenance - 7.4 percent, and
3. fuel component - 26 percent (16).
Projected
As in any economic projection, there is an element of uncertainty.
Even so, for a number of reasons, electric plant and electric energy cost
have risen faster than the cost-of-living index. It is expected that
future cost in terms of current dollars will similarly increase. This
would be due in part to rising construction cost, high interest rates,
rising fuel costs, and increasing environmental expenses necessitated
by increasing use of coal. Both plant capital cost and electric rates
are expected to increase at 3 to 7 percent per annum over the inflation
level through 1985 (17).
25
-------
References - Conventional Coal-Fired
Steam-Electric Power Plant
1. U.S. Department of Energy (DOE). Status of Coal Supply Con-
tracts for New Electric Generating Units, 1977-1986, First
Annual Supplement. DOE/FERC-0004/1, U.S. DOE, Federal Energy
Regulatory Commision, Washington, D.C., May 1978.
2. U.S. Department of Energy. Annual Report to Congress, Volume
11. DOE/EIA 0173(79)72, U.S. DOE, Energy Information Admin-
istration, Washington, D.C., 1979.
3. National Coal Association. Steam Electric Plant Factors.
Washington, D.C., 1979.
4. Jahnig, C.E., and Shaw, H. Environmental Assessment of an
800 MWe Conventional Steam Power Plant. Government Research
Laboratories, Exxon Research and Engineering Company, Linden,
New Jersey, September 1976.
5. Crawford, A.R., Manny, E.H., Gregory, M.W., and Bartok, W.
The Effect of Combustion Modification on Pollutants and
Equipment Performance of Power Generation Equipment. Sym-
posium on Stationary Source Combustion (EPA), Atlanta,
Georgia, September 24-26, 1975.
6. Davison, R.L., Natusch, F.S., Wallace, J.R., and Evans, C.A.
Trace Elements in Fly Ash Dependence of Concentration on
Particle size, Environmental Science & Technology, 8, 13,
p. 1107-1113, December 1974.
7. Suprenant, N., et. al. Preliminary Emissions Assessment of
Conventional Stationary Combustion Systems. EPA 600/2-76-046a
and b, March 1976.
8. Beckner, J.L. Trace Element Composition and Disposal of
Gasifier Ash. AGA Conference, Chicago, Illinois, October
27-29, 1975.
9. Stern, R.D., Ponder, W.H., and Christman, R.C. Symposium
on Flue Gas DesuIfurization. New Orleans, March 1976 -
EPA 600/2-76-136a and b, May 1976.
10. Klein, D.H., Andren, A.W., Bolton, N. et al. Pathways of 37
Trace Elements Through Coal-Fired Power Plant. Environmental
Science & Technology, 9, 10, p. 973-980, October 1975.
26
-------
11. Heymann, F.J., Bannister, R.L., and Niskode, P.M. Steam Tur-
bine Noise - A Status Report. ASME Paper 75-Pwr-7, 1975.
12. Broderson, A.B., Edwards, R.G., and Green, W.W. Noise Dose
and Hearing Loss in a Coal-Burning Power Plant. Sound and
Vibrations, 9, 22-30 (1975).
13. Magee, E.M., Hall, H.J., and Varga, G.M. Potential Pollu-
tants in Fossil Fuels. EPA-RZ-73-249, June 1975 - NTIS
225 039.
14. National Coal Association. Steam-Electric Plant Factors.
Washington, D.C., 1974 Edition, p. 102.
15. World's Top Ten Power Stations for 1975 or Nearest Fiscal
Year, Combustion, Volume 49, September 1977, p. 15.
16. Based on unpublished information obtained from the Utilities
Division of the Naval Facilities Command. 1979.
17. Hoffman, L. Projected Price of Utility Supplied Electric,
Power to Industrial Users. Hoffman-Muntner Corporation,
Silver Spring, Maryland, November 12, 1975.
27
-------
2. Diesel Generators
2.1 Overview
The diesel generator is an internal combustion engine that works on
the cylinder and piston principle. Fuel is injected after the air is
compressed and because of the thereby attainable high compression ratios,
efficiencies greater than for the conventional gasoline internal combus-
tion engine are achievable.
Diesels have been commercially utilized for in excess of 80 years.
They are used extensively to power moderate size stationary electric
generators for a variety of services. Even though the output of a large
diesel generator is small compared to the output of a typical utility
fossil fuel steam-electric generator, the attainable efficiency is gen-
erally as great or greater.
Recently, concern has developed relating to the potential carcino-
genic aspects of diesel exhaust. Future utilization of stationary diesel
generators may well depend on diesel emission control standards.
The cost of diesel derived electric energy is somewhat higher than
that from a conventional steam-electric plant. This is due to the rel-
atively high operating cost (per kwh electric energy) of a diesel-gener-
ator installation. DOD experience indicates diesel derived electric
energy is at least twice as expensive as that supplied by an electric
utility. Even so, for selected applications, diesel generators are very
appropriate.
2.2 Process Description
Concept
The diesel generator is simply a diesel engine mechanically coupled
to an electrical generator. Diesel engines have been commercially em-
ployed for over 80 years. With advancements in metallurgy, refinements
in engine design, and improvements in lubricating capabilities, modern
diesels generally operate at substantially higher rpm and (consequently)
are much lighter than older engines of the same output capability. Cur-
rently, stationary diesel engines adaptable to electric generation are
catalog listed with ratings up to 48,000 horsepower (1).
The diesel is an internal combustion engine and works on the cylin-
der and piston principle. Depending on application, these cylinders may
be in-line, opposite, a V arrangement, or radial. Radial groups can be
stacked to form the so-called pancake arrangement.
28
-------
Diesels are compression ignition engines. In the "ideal" (i.e.,
commonly termed) diesel cycle, a charge of air is compressed without
heat being added or rejected (i.e., adiabaticaI Iy). Compression (400 to
700 pounds/square inch) is limited by the strength of the engine with
compression ratios generally between 12 to 22. Fuel is injected at or
near the end of the compression cycle. Due to the high temperature of
compressed air, burning begins as soon as the fuel enters the combustion
volume within the cylinder. Ideally, the rate of injection of the fuel
should be adjusted to the travel of the piston so as to maintain constant
pressure until the fuel injection is stopped. The next two operations
are like those of a normal gasoline cycle (Otto cycle) engine, adiabatic
expansion of the gas and cylinder heat rejection. In practice, it is not
possible to obtain constant pressure burning (2,3).
The relative high efficiency (as compared to a gasoline cycle) is
due to the attaining of substantially high compression ratios. Higher
compression ratios are attainable since the fuel is injected at or near
the end of the compression cycle. Analyses indicate that the efficiency
of the diesel cycle increases with increased compression ratio and is
greater at less than full load (2).
Deta i I
The Otto cycle or the four stroke constant combustion cycle is the
one used in most internal combustion cycles. The Diesel cycle is simi-
lar to the Otto cycle except heat is supplied at constant pressure com-
pared to constant volume for the Otto cycle. The modern diesel engine
does not exactly follow the so-called diesel or constant combustion
pressure cycle and has a higher thermodynamic efficiency value. The
diesel fuel oils are crude oil distillates i ntermed iate in voI ati I i ty
between kerosene and lubricating oils. As a rule, no ignition provi-
sions are required for the higher compression ratio engines. Engine
speed control in reaction to lead changes is contro led by varying the
quantity of injected fuel (4).
Diesel engines are often used as prime movers for smaI I power plants.
Large, relatively slow rpm diesel engines have outstanding reliability,
and the obtainable efficiency rivals that of the best fossil fuel fired
steam-electric plants. However, the largest diesel plant size is smaller
than a conventional fossil fuel fired steam-electric plant of the same
output capacity.
Figure 3 is a diagram of a typical diesel driven generating plant.
The heat balance of a diesel driven generator is relatively simple. The
input energy is supplied by diesel fuel oil. The input energy less
losses equal the output power. Table 8 indicates a reasonable heat bal-
ance for a diesel generator plant producing 5 MW of electrical energy.
Figure 4 diagrammaticaI Iy indicates the distribution of the total input
energy.
29
-------
Bulk
Oi 1 St
Oil Ho 1 d i ng
^ Tank
1
1 1 1 1
Fuel Diesel
orage Engine
'
i
Generator
j
Coo ling
(Heat Exchanger)
Figure 3
Diesel Driven Generator Plant
Table 8
Heat Balance for 5 MWe Diesel Electric Plant
Btu/hour
(10 Btu's)
Percent of Tota I
Energy Input
Net Electrical Energy Output
Losses
Incomplete fuel combustion
Diesel engine losses (friction,
etc.)
Heat rejected (cooling and
exhaust gas)
Generator losses
Total Energy Input
17.06
0.10
3.00
30.81
0.73
51.70
33.0
0.2
5.8
59.6
1 .4
100.0
30
-------
100$
Energy input from fuel
Diesel engine losses
and incomplete fuel
combustion
=» I A%
Generator
losses
59.6%
Heat
rejected
Net electrical energy output
Figure 4
Heat Flow Diagram for Diesel Generator
2.3 AppI ications
Current
Diesel driven generators with their attractive thermal efficiencies
and proven high reliability have made the diesel very popular for small
power plants. Such plants are being used as the main or backup source
of power for many consuming sectors. These include electric utilities,
major military installations, hospitals, shopping centers, office build-
ings, schools, industrial activities, and others.
There are many reputable domestic and foreign manufacturers of sta-
tionary diesel engines. A partial listing of manufacturers include
Worthington, Fairbanks Morse, Electric Motor Division of General Motors,
31
-------
General Electric, Alco Power, Sulzer Bros. Ltd., and Copper Bessemer.
Some foreign designs are manufactured by domestic manufacturers. The
majority of units used by utilities, the military services and others
are less than 5,000 horsepower. Even so, a number of larger units are
currently being utilized (1).
Projected
The projected applications are the same as current applications.
2.4 Environmental Considerations
Diesels emit significant amounts of soot-like exhaust and associated
other constituents. Until relatively recently, the environmental con-
cerns associated with diesel emissions have not received much attention.
This is due in part, especially in a period of fuel availability concerns,
to the reputation diesels have for high efficiencies as compared to the
internal combustion gasoline engine.
The principal emissions from a diesel engine are particulates, CO,
and NO . The level of emissions (for diesels as a class) varies consid-
erably with engine design and operating conditions. The particulates
from the diesel exhaust are composed of large particles (up to 10 A) and
small particles (100-800 A). The particles are composed primarily of
carbon but up to thirty percent of the particle may consist of hydrocar-
bons with at least three but usually up to six condensed benzene rings.
Some of these aromatic hydrocarbons are known carcinogens (5).
Recently, there has developed considerable concern relating to the
carcinogenic potential of the very fine soot-like particle emissions
(polynuclear organic material) and the high NO emission associated with
diesel exhaust. This concern has been substantially heightened by the
high emission levels from diesel powered automobiles. This is an area
just starting to receive significant attention. The U. S. Environmental
Protection Agency is currently investigating the potential health effects
and investigating pollution control technology. Currently, there does
not appear to be a viable means to satisfactorily reduce or restrict
emissions of concern. It is suspected that any effective emission con-
trol measures would have a significant adverse effect on the obtainable
engine efficiency.
2.5 Performance
Current
The first diesel engine for commercial service was installed in
St. Louis, Missouri in 1898. Within a few years, thousands of diesels
32
-------
were in use. Today, diesels range in size from 15 to 45,000 horsepower.
A general rule of operation is that to prevent operational impairment,
a stationary diesel should not be run at no load or with slight load (1),
A state-of-the-art diesel driven generator carrying a 70 to 75 percent
load, should have an efficiency value of approximately 33 percent (1).
Even so, it should be noted that many large diesel generators show over-
all efficiency values of 37 percent (6).
Projected
The projected use of diesel generators is the same as the current
use. The technology is very mature and future efficiency values are
not expected to be higher than those currently attainable. However, it
should be noted that if stringent environmentally related restrictions
are placed on diesel emissions, future utilization prospects could be
severely impaired.
2.6 Economics
Current
The cost of diesel generated power to an industrial user, in part
due to economy of scale factors, is generally significantly higher than
electric utility provided power. The real cost of diesel generated
power must include the capital (i.e., amortization) component as well as
the operation and maintenance component.
Currently, DOD estimates the capital cost of a 1,000 kW skid
mounted diesel generator assembly at approximately $500 per kW capacity.
For a 1,500 kW unit, the estimated capital cost is approximately $400
per kw capac ity (1).
A recent diesel generator operation and maintenance cost associated
with the generation of 65,000 Mwh of electrical energy (over a one year
period) was in excess of 60 mills per kwh (1). This value does not in-
clude the capital amortization component. In essence, the overall cost
to provide a kwh of electrical energy via a diesel generator is consid-
erably higher than utility provided power. Even so, for selected appli-
cations, the utilization of diesel generators are fully justifiable.
Future
The cost of electrical energy from diesel generators is expected
to increase somewhat faster than the rate of inflation. This is mainly
due to the expected continuation in the foreseeable future of the recent
cost trend of diesel fuels (7).
33
-------
References - Diesel Generators
1. Based on unpublished information obtained from the Utilities
Division of the Naval Facilities Engineering Command, 1979.
2. Emswiier, J.E. Thermodynamics. McGraw-Hill Book Company, Inc.,
New York, New York, 1943.
3. Baumeister, T., Aval lone, E. A., Baumeister III, T., Eds.
Marks' Standard Handbook for Mechanical Engineers, Eighth
Edition. McGraw-Hill Book Company, Inc., New York, New York,
1978.
4. Butterfield, T. E., Jennings, B. H., Luce, A. W. Steam and
Gas Engineering, Fourth Edition. D. Van Nostrand Company,
Inc., New York, New York, 1947.
5. U. S. Department of Energy. Environmental Readiness Document -
Cogeneration. Commercialization Phase III Planning. DOE/ERD-
0003, U.S. DOE, Washington, D.C., September 1978.
6. Knowlton, A. E., Ed. Standard Handbook for Electrical Engin-
eers, Eighth Edition. McGraw-Hill Book Company, Inc., New
York, New York, 1949.
7. The Hoffman-Muntner Corporation. Assessment of Availability
and Price of Fossil Fuels for Utility Purposes Through 1985.
For: The Naval Facilities Engineering Command and the Office
of Naval Research. Silver Spring, Maryland, June 1975.
34
-------
3. Fluid!zed-Bed Combustion (FBC)
3.1 Overview
A fIuidized-bed boiler involves passing air upward through a thick
(several feet) bed of granular, noncombustible material such as coal ash
with limestone or dolomite. The air fluidizes the granular particles
and, with the relatively small amount of air used to inject the fuel,
serves as the combustion air. The basic advantages are 1) the ability
to burn high-sulfur fuel with resulting low SO and NO emissions and
XX
2) the potential for boilers of reduced size and weight (i.e., as com-
pared to conventional boilers of equivalent capacities).
Two variations of fIuidized-bed technology, atmospheric and pres-
surized, are being supported by the U. S. Department of Energy. Atmos-
pheric fIuidized-bed combustion can be used for the same purposes as a
conventional boiler. Pressurized fIuidized-bed combustion is oriented
for use with combined cycle gas/steam turbine systems to generate elec-
trical energy. The viability of a pressurized fIuidized-bed combustor
may well depend on the ability to adequately remove particulate material
from the gas before it reaches the turbine.
Current fIuidized-bed combustion efforts are largely in the R&D
stages. Some manufacturers are just starting to advertise the availa-
bility of atmospheric commercial/industrial scale units. The attainable
boiler efficiency is limited by the same general loss components as for
a conventional boiler. Boiler efficiency values equal to those attain-
able by conventional boilers will depend on the ability to achieve sub-
stantially complete carbon burn-up.
The environmental aspects of a fIuidized-bed boiler are similar to
that of an equivalent capacity conventional boiler with flue gas desul-
furization (FGD) burning the same coal. A major difference is the amount
and nature of the spent bed material as compared to the effluent from a
FGD system. For atmospheric fIuidized-bed combustion with the same SO
removal, almost three times as much limestone is required. Spent bed
material from a fIuidized-bed boiler contains appreciable CaO (i.e.,
quicklime) that may present handling and disposal problems. Hopefully,
commercial uses will be found for the spent bed material.
In the near term, fIuidized-bed boilers are projected to compete
with industriaI/commerciaI scale conventional boilers. Currently oper-
ating fIuidized-bed boilers are mainly in the development, test and
evaluation categories. It is expected that fIuidized-bed boilers will
be economically competitive with conventional units with SO emission
controI.
35
-------
3.2 Process Description
Theory
A f I uidized-bed boiler involves passing air upward through a thick
(several feet) bed of granular, noncombustible material such as coal ash
with limestone or dolomite. The air fluidizes the granular particles
and, with the relatively small amount of air used to inject the fuel
(usually coal but possibly other fuels), serves as the combustion air.
Some of the heat transfer can be through tubes embedded in the fluid!zed-
bed because combustion takes place at temperatures (approximately 1,600 F!
that hopefully will not damage the tubes (1).
The f luidized-bed boiler, which can combust coal in a bed of inert
ash with limestone or dolomite, hopefully, has two basic advantages.
These are:
1) The ability to burn high-sulfur coal (all ranks) with
resulting low sulfur dioxide and nitrogen oxides emis-
sions. The sulfur dioxide formed during combustion of
the coal will react with the limestone or dolomite sor-
bent to capture a major portion of the sulfur values from
the combustion gas. Due to the low operating temperature,
the formation of nitrogen oxides is minimized as compared
to a conventional boiler.
2) If it is found that dependable cost effective operation
is possible with a portion of the boiler tubes embedded
in the fIuidized-bed, then the attainable high release
rate and heat transfer coefficient would permit reduced
boiler size and weight. However, a substantial opera-
ting history will be required to fully substantiate that
embedded boiler tube operation is indeed cost effective.
Two variations of fIuidized-bed combustion technology, atmospheric
and pressurized, are being pursued by the U. S. Department of Energy.
Atmospheric fIuidized-bed combustion can be used for generating elec-
tricity. However, current indications are that it will principally be
employed for process or space heating due to efficiency considerations.
Pressurized fIuidized-bed combustion is oriented for use with a com-
bined cycle gas/steam turbine system to generate electricity. In the
pressurized variation of fIuidized-bed technology, combustion takes
place at an approximate 100 F higher temperature. Pressure within the
cornbustor is maintained at a design value of 4 to 16 atmospheres (2).
In the pressurized-bed combustor, particulate removal must be accom-
plished before the gases enter the gas turbine in order to prevent blade
damage. The viability of pressurized fIuidized-bed technology may well
rest on the yet unproven ability to adequately and efficiently clean the
turbi ne gas feed.
36
-------
Deta iI
FIuidized-bed combustion is a technology which involves the combus-
tion of coal in a bed of inert ash with limestone or dolomite that has
been fIuidized (held in suspension) by the uniform injection of air
through the bottom of the bed at controlled rates. The sulfur dioxide
formed during the combustion of the coal reacts with the limestone or
dolomite sorbent to form a dry calcium suIfate solid. No additional
sulfur control devices are anticipated to enable FBC to meet current New
Source Performance Standards (NSPS) and emission standards for S0? for
selected applications. Users may elect to remove pyritic sulfur in coal
preparation plants prior to combustion if economics favors such opera-
tion. NO emissions will also meet current standards. The formation of
NO is minimized because of the low operating temperature in the fluid-
ized-bed (approximately 1600 F) as compared to conventional combustion,
in which temperatures may reach 3000 F (2).
The advantages envisioned by DOE for FBC include increased energy
conversion efficiencies through the ability to operate using coal as the
fuel without the operational requirement to power a scrubber system, rel-
atively early commercial availability, a projected cost competitive with
other near-term technologies, reduced emissions of SO,., and NO , and the
abi I ity to burn alI types and ranks of coal as welI as char and refuse.
Figure 5 is a conceptual presentation of a fIuidized-bed steam gen-
erator and does not indicate various arrangements (e.g., fuel feed).
Figure 6 is a schematic diagram for an atmospheric fIuidized-bed system
with a steam turbine load. Figure 7 is a schematic diagram for a pres-
surized-bed system with both steam turbine and gas turbine loads (3).
Atmospheric fIuidized-bed combustion is controlled in the tempera-
ture range of 1500-1650 F with excess air values of 20-25 percent.
Steam produced in tube bundles and/or water walls located within the
combustor may be converted to electricity in a conventional steam tur-
bine cycle or may be used for process and/or space heating. S0~ and NO
control is accomplished in the combustion zone by reaction of SO- with
limestone and reduced temperatures, respectively (2).
The portion of the coal ash which is small enough to be elutriated
from the bed must be removed, along with attrited limestone, prior to
releasing the flue gas to the atmosphere. Particulate removal can be
achieved with cyclones, precipitators, and advanced fabric filters. The
balance of the ash, along with the large particles or reacted limestone,
is drained out of the bed (2).
The elutriated ash may be high in unburned carbon and its direct
disposal would result in a lowered combustion efficiency. It is antici-
pated that atmospheric units will employ either a carbon burnup cell
(CBC), a high-temperature, high-excess-air bed to which the collected
ash is fed and burned, or will allow for the reinjection of collected
ash into the combustor (2).
37
-------
Fuel Injection Pipes
-Boiler Tubes
"t)
Boiler Tubes
(Embedded)
Y Air Distribution Grid L
I
I
I
Plenum
Air
Figure 5
Fluidized-Bed Steam Generator
The first U. S. pilot plant (30 MWe) for atmospheric fIuidized-bed
combustion began test operations in late 1976 at Rivesville, West Vir-
ginia. Demonstration-scale industrial applications are in the design,
construction, and evaluation stages. Preliminary design is also under-
way for an AFBC demonstration plant in the 200 MWe range, with operation
expected in approximately 1982. The use of AFBC for industrial heat
and steam is anticipated in the early 1980's (2).
38
-------
v£>
Coal Limestone
1 1
Solids Handling
Sta-.k
Air
AFB
Furnace
Reheat
Steam
Solids Disposal
High
Turbine
Inter-
mediate
Turbine
f
Low
Turbine
ft
Generator
Feedwater
Figure 6
Schematic Diagram for Atmospheric Fluidized-Bed System
-------
Coal Dolomite
J L
Solids Handling
Spent Solids
Handling
Solids Disposal
PFB
Furnace
Inier-
mediate
Turbine
Air-
Stacks
Figure 7
Schematic Diagram for Pressurized Fluidized-Bed System
-------
In the pressurized variation of FBC technology, combustion occurs
in a fluidized bed of sorbent which may be dolomite, with excess air
ranges similar to those found in the atmospheric boiler and at tempera-
tures approximately 55 C (100 F) higher. Pressure within the combustor
is maintained at a design value of 4 to 16 atmospheres, possibly result-
ing in a significant size reduction compared to an atmospheric fluidized-
bed combustor (2).
Exxon, under EPA sponsorship, has developed and operated a 0.63 MW
equivalent pressurized FBC miniplant with sorbent regeneration. The
purpose of the miniplant is to permit assessments of and develop controls
for particulate, SO,,, and NO emissions from a pressurized FBC. This
same pressurized miniplant has been used by DOE to assess tube performance
in a pressurized FBC environment.
Pressurized fIuidized-bed combustion systems are being developed for
combined-cycle operation where energy conversion is achieved through gas
turbines as well as through a conventional steam turbine cycle. One sys-
tem being studied by General Electric for DOE is a pressurized fluidized-
bed boiler with a power recovery gas turbine. A 13 MWe combined cycle
pilot plant is being designed by Curtiss-Wright for operation at Wood-
ridge, New Jersey. This plant will use a pressurized fIuidized-bed com-
bustor/air preheater coupled to a gas turbine and then to a heat recovery
boiler. In pressurized FBC, particulate removal must be accomplished
before the gases enter the gas turbine to prevent turbine blade damage.
Devices (not yet proven) such as granular bed filters, ceramic filters,
or felt metal f i Iters will be needed to clean the gas sufficiently., and
it is desirable to do this at the combustor exit. To improve combustion
efficiency, the larger ash particles will be recycled to the combustor.
The power output of a typical combined-cycle unit will be divided between
the steam and gas turbines. Pressurized FBC systems for commercial util-
ity use are not expected until approximately 1995 (2).
For both atmospheric and pressurized FBC systems, problems associ-
ated with disposal of spent sorbent, as well as raw sorbent requirements,
can be largely reduced by employing a regeneration process, where suifated
sorbent is withdrawn from the combustion bed, regenerated, and returned
to the bed for reuse. For commercialized systems, it is anticipated that
the S0? (or H?S) - rich gas produced in the regeneration process will be
fed to a conventional sulfur recovery operation (located on site) and
converted to either sulfur or sulfuric acid. Spent sorbents are being
evaluated by DOE and EPA for utilization in agriculture and industry and
for stable landfill disposal (2).
The energy loss components are essentially the same as for the con-
ventional boiler and result in part from the following:
1. Heating excess combustion air
2. Incomplete fuel combustion
41
-------
3. Heating of moisture in coal and air
4. Losses associated with energy in flue gas.
It should be noted that pulverized coal firing provides extremely
efficient combustion of coal with the unburned combustible loss gener-
ally being less that 0.5 percent for bituminous coals. With stoker
firing, the unburned combustible loss can be held to approximately 5
percent (i.e., with reinjection of initially unspent carbon).
Currently, the unburned combustible loss can be 10 to 15 percent
for single pass combustion in a FBC unit. The most significant factor
contributing to this loss is that the combustion temperature must be
limited to 1500 to 1650°F range to achieve efficient S02 capture. Even
though it may be possible to improve over the single pass FBC efficiency
by collecting and firing the unspent carbon in a separate combustor, it
is most unlikely that the attainable boiler efficiency of the FBC will
ever reach that obtainable by a pulverized coal fired unit (4). It is
expected that the unburned combustible loss for FBC with the collecting
and firing of initially unspent carbon can be made to approach the stoker
f i red boi Ier vaIue.
The required calcium to sulfur molar feed ratio may be 2? to 3?
with the atmospheric FBC process to achieve 85 percent SO,-, removal with
a 3 percent sulfur coal (i.e., meeting the NSPS). By contrast, the Ca/S
feed for limestone scrubbing with the same coal is approximately 1.1.
With a more restrictive S0? emission standard, the Ca/S ratio to provide
a 90 percent removal could be 4 to 5 for FBC as compared to 1.3 to 1.4
for limestone scrubbing.
However, a pulverized coal fired boiler with FGD requires energy to
operate the FGD system and often requires additional energy for flue gas
reheat after cleaning. The additional energy required could equate to
3 to 4 percent of the rated energy output of a coal fired steam-electric
pI ant.
Reference 4 indicates that there are considerable operational un-
certainties including such items as 1) effects of in-bed tube corrosion
under different gas flow velocities, 2) load responsiveness, 3) oper-
ationally achievable boiler efficiencies, and 4) realistic "overall"
capital and operating cost. In essence, even though there is very con-
siderable research and development in the FBC area, uncertainties exists.
Undoubtedly, final utilization will depend on fuel availabilities, appli-
cable environmental standards, capital and operating economics, and other
items. It may well turn out that atmospheric FBC will prove attractive
for commerciaI/industriaI steam raising applications, but not for util-
ity electric generating purposes where the overall efficiency depends
not only on boiler efficiency but also on the steam quality fed to the
turbi nes.
42
-------
As previously indicated, in the near term, f I uidized-bed boilers
are projected to compete with conventional industrial/commercial scale
boilers. Table 9 provides a reasonable anticipated heat balance based
on relating the projected losses of an atmospheric fIuidized-bed combus-
tor with those ot currently available spreader stoker fired boilers.
Since the atmospheric fIuidized-bed boiler is initially expected to com-
pete with conventional industrial/commerciaI boilers, the provided table
only covers boiler operation. The information in Table 9 can diagram-
matical ly be illustrated by the Figure 8 heat flow diagram. It should
be emphasized that the provided heat balance is at best a projection.
The heat balance does not take into account the differential between heat
of calcination (endothermic) and sulfonation (exothermic) reactions
associated with the fIuidized-bed. It is possible that for all practical
purposes these values will offset each other.
Table 9
Estimated Heat Balance for 100 MBtu Output
Atmospheric Fluidized-Bed Boiler
Btu/hour
MO Btu's)
Percent of Tota
Energy Input
Net Heat Energy Imparted to Boiler
Fluid
100.0
85.0
Furnace Losses
Heating excess combustion air
Incomplete fuel combustion
Heating moisture in coal and air
Energy in flue gas
Miscellaneous (heat loss, etc.)
Total Energy Input
0.24
5.88
4.71
4.71
2.12
1 17.66
0.2
5.0
4.0
4.0
1 .8
100.0
As previously
oriented for use w
indicated, pressurized f I uidized-bed combustion is
ith combined cycle gas/steam turbine systems to gener-
Table 10, based in part on reference 5, provides
heat balance for a pressurized fIuidized-bed
DiagrammaticaI Iy this can be illustrated by the
Figure 9. It must be emphasized that pressurized
fIuidized-bed systems are only in the early research and development
stages and at best commercial utilization is many years off.
ate electrical energy.
a considered projected
combined cycle plant.
energy balance diagram,
43
-------
Table 10
Estimated Heat Balance for 903.77 MWe Advanced
Steam Cycle - Pressurized Fluidized-Bed Electric Plant
Btu/hour Percent of Total
(10 Btu's) Energy Input
Electric Power Output
Gas turbine derived power 699.49
Steam turbine derived power 2520.31
Less power (i.e., losses for
fans, coal handling, pumps, (136.01)
transformers, etc.)
39.14*
Boiler Losses
Heating moisture in coal and air 315.126 4.00
Incomplete fuel combustion 157.563 2.00
Heating excess combustion air 15.756 0.20
Miscellaneous (heat losses, etc.) 63.025 0.80
System Losses
Stack Loss 441.176 5.60
Mechanical, frictional, etc. 157.563 2.00
Heat rejected to cooling towers
and otherwise lost (e.g., 3644.432 46.26
through boiler blowdown)
Total Fuel Energy Input (Coal) 7878.15 100.00
(Totals may not add due to independent rounding)
* Net value
44
-------
Heat Input from coal
Heating excess
combust!on
ai r and
Mi seellaneous
5$ <3
Incomplete fuel
combust!on
Heating moisture
i n coaI
85$
Energy in steam output
Figure 8
Heat Flow Diagram for Atmospheric Fluidized-Bed Combustor
100%
Heat input from coal
Mechan icaI,
friction, etc.
losses
1%.
BoiIer losses
, 5.6$
Stack
losses
46.26$
Heat
rejected
39.14$
Net Electrical Energy Output
Figure 9
Estimated Heat Flow Diagram for Advanced
Cycle - Pressurized Fluidized-Bed Electric Plant
45
-------
3.3 Applications
Current
Fluidized beds have been used for many years in the chemical industry
for ore treating purposes. In contrast, the use of FBC for steam raising
purposes is relatively new. Currently, FBC activities, oriented at steam
raising purposes, are being pursued in a number of industrial countries
around the world. In Europe, fIuidized-bed combustors have been devel-
oped in which the boiler tubes are more conventionally located (6, 7).
Past and current FBC efforts for steam raising purposes have been
pursued in England, France, Czechoslovakia, Germany and undoubtedly other
countries. As indicated, past developments are take-offs of chemically
related roasting concepts including those to desulfurize copper ores and
to produce sponge iron. Past FBC steam raising concepts do not have the
potential advantages of currently pursued U. S. efforts.
For all practical purposes, FBC activities in the U. S. are still
in the research, development, and evaluation phases. Several reputable
firms have recently begun to market commercial/industriaI size units.
Projected
The projected applicability of FBC systems would be primarily for
industriaI/commerciaI boiler utilization. A Federally funded study (8)
on the potential application of industrial steam raising FBC systems in-
dicates that the potential is substantial and would make inroads when:
1) A reliable FBC technology is demonstrated and resulting
units are capable of achieving continuous boiler oper-
ation (of about one year duration) with effective control
of emissions, and
2) The economics of FBC technology are demonstrated to be
competitive with alternative ways of firing solid coal.
Reference 8 indicates that the nationwide potential for FBC tech-
nology, assuming timely development and acceptable economics, is:
1 5
Cumulative Number of 10 Btu
Year Industrial FBC Boilers per year
1980 7 0.01
1985 200 0.29
1990 685 0.99
1995 1170 1.69
2000 2050 2.97
1 5
(1 x 10 Btu, i.e. one Quad, equates to approximately 165
mi I I ion barrels of oil)
46
-------
Most of the estimated potential is expected to be in the chemicals,
petro-chemicaIs, petroleum refining, paper, primary metals, and food
industries. Even so, it must be remembered that wide-scale industrial
acceptance is uncertain.
The potential for generating utility produced electrical energy, as
previously implied, is totally speculative and, at best, is much more
remote. Currently, as based on competing options, the outlook would de-
pend to a large extent on the successful development of a pressurized
FBC capability so as to achieve significant improvements in the overall
electric generating efficiency.
3.4 Environmental Considerations
Emissions from a fIuidized-bed boiler can be classified as continu-
ous, scheduled intermittent, and unscheduled intermittent. Continuous
emissions include pollutants that are contained in the flue gas dis-
charged from the furnace stack. Scheduled intermittent emissions in-
clude discharge of limestone (or dolomite) and ash to storage piles, and
sulfur bearing wastes ejected from the bed. Unscheduled intermittent
emissions include transients due to operating upsets, fugitive dust from
coal, and storm run-off. For each boiler plant, all of these pollution
sources must be considered thoroughly and controlled adequately. Pollu-
tion control methods may vary and will depend to a considerable extent
on the specific plant. The environmental aspects of a fIuidized-bed
boiler bears a very close resemblance to that of a conventional boiler
plant. The pollutants and their source are almost identical. A princi-
pal difference is the pollution associated with the spent bed effluent
from a conventional plant. Conceivably, there may be a difference in
the combination products due to low temperature burning. This could
change the organic and trace element emissions.
Identified Pollutants
Areas of environmental concern are summarized in Table 11, based in
part on an EPA funded study (9). In the following detailed discussion,
emissions to the air will be discussed first, followed by a similar dis-
cussion of solids and liquid effluents, and then trace elements which are
treated separately. The following is based, in part, on an assessment
of the environmental aspects of a pulverized coal-fired boiler plant (9).
Air Emissions
The first area to consider is the coal preparation area, primarily
coal storage and sizing. Wind action on the coal pile can cause a dust
nuisance, especially during loading and unloading operations. Conveyors
47
-------
Table 11
Emissions and Effluents from Fluidized-Bed Boiler
Emissions to Atmosphere
Wind action on coal storage
and hand Ii ng
Wind action on limestone and
waste
Cleaned fIue gas
Possible fugitive dust from area
Transients due to upsets, clean-
ing, etc.
Potential noise and odors
Effluents - Liquids and Solids
Rain runoff - coal, limestone,
and waste areas
Spent bed ef f I uent
Sludge and chemicals from water
treat i ng
Trace Elements
Leaching associated with disposal
of spent bed waste
Fate of volatile toxic elements in
coal feed
Emissions as gas and PM and POM
with stack gas
Potential Concerns
Dust, fire, odors
Dust
NO , plume dispersion,
Xdust, SO , POM
x
Dust nuisance
Dust, smoke, fumes
Machinery, maintenance
Suspended and dissolved
matter
Ground water contamin-
ation and land use
Mi nor
Soluble toxic elements
Contamination of local
a i r and water
Health hazard
48
-------
should be covered to contain the dust, and water sprays may be needed at
transfer points. As in all solids handling operations, leaks and spills
are to be expected, and provisions should be provided for cleaning them
up and hosing down the area so as to wash dust to a collecting pond be-
fore it becomes airborne (9).
The precautions used to prepare the limestone for the bed should
be similar to those of coal, since the bed reagent (e.g., limestone) is
often stored, sized, and used in a manner comparable to coal.
Sized coal and limestone is fed to the furnace where the coal is
burned in an inert bed of ash and limestone. Spent bed material is gen-
erally dropped from the bed by gravity and removed by a water cooled
screw, the spent material remaining in a dry state. Care must be taken
to prevent dust emissions (10).
Flue gases from the furnace are a major environmental concern since
they contain many pollutants including SO , NO , polynuclear organic
matter (POM), trace elements, etc. At the present, there is no fully
accepted way to remove NO from flue gas. However, in a fIuidized-bed
boiler, the formation of NO is reduced due to the low fuel burning tem-
perature. S0~ is removed by the limestone reacting with sulfur dioxide
formed during combustion of the coal. Means such as baghouses, electro-
static precipitators, or scrubbers are used to reduce particulate emis-
sions. It should be noted that submicron particles which are suspected
of causing respiratory problems are not efficiently removed by an elec-
trostatic precipitator.
As more information is obtained, other pollutants in the flue gas
may become of concern. For example, nitrates, HCN, sulfates, and organic
matter are areas now being examined. Also, it is known that chlorides
in the coal are volatilized during combustion, and can leave in the flue
gases as HCI. In many operating power plants, the HCI formed is presum-
ably released to the air, but with limestone in the fIuidized-bed, it
conceivably could be removed by reacting with the limestone to form
soluble CaCI2.
Periodic cleaning of furnace equipment is required and precautions
are needed to avoid emissions to the air at such times. One method of
on-stream cleaning of heat transfer surfaces is called "soot blowing,"
using high velocity jets of steam to dislodge deposits. Most of the
additional dust load will hopefully be recovered in the particulate
collection system (e.g., bag-house). The deposits are made up of fine
particles, which could be high in volatile trace elements according to
indications from related studies. Equipment cleaning at shutdown or
during the turnaround can also cause dust nuisances, or possibly a haz-
ard in the case of deposits of toxic materials (9).
49
-------
Solid and Liquid Effluents (4, 9)
The first effluent of solids and liquids covered are those from the
coal and limestone storage piles and handling area. Here, rain runoff
will contain suspended solids and may also contain soluble sulfur and
iron compounds. The coal pile is subject to oxidation and weathering,
with conditions similar to those associated with acid mine water. As one
precaution, curbing should enclose the storage pile and any coal prepar-
ation area, so that runoff can be segregated and sent to a storm pond for
settling. The water can then be treated prior to disposal or treated and
used for plant purposes.
The next consideration is disposal of the spent bed material from
the furnace. The spent material is usually removed in a continuous form
and kept in a dry state. Because of the low calcium utilization, the
spent solids contain substantial CaO in addition to CaSO., along with
trace elements and other substances (e.g., MgO, SiCU, A 1^0,, iron oxide,
ash, etc.). The presence of CaO (i.e., quick lime) may make the material
unsuitable for direct landfill except in lined cavities and thereby sub-
stantially complicate disposal. CaO poses the potential for personnel
hazard and any leachate may have a high pH. Hopefully, the waste will
have economic value for such uses as building material, fertilizer, and
neutralization of acid mine drainage. Some preliminary studies have been
made by EPA and DOE with regard to bed waste, but much more work is needed,
The waste streams would be from rain runoff of coal and possibly
exposed limestone and waste areas along with sludge and chemicals from
boiler blowdown and boiler water treatment. Chemicals used for boiler
water treatment could include a I urn for coagulation and separation of sus-
pended matter, lime to precipitate hardness, along with many other cur-
rently used water treating agents. Rain runoff from coal has received
considerable attention and control procedures are in current use. Ade-
quate disposal of streams associated with boiler water conditioning and
boiler waste has been ongoing. In essence, waste streams control should
not pose any new or unique problems.
Trace Elements (9)
A great many trace elements are contained in coal; and although the
concentration may be low, the total potential emissions can be very large
when considering the total coal consumed in the U. S. Many of the trace
elements are toxic; moreover, the emissions are concentrated at large
boiler plant locations. The trace elements content of a No. 6 Illinois
coal is given in Table 12, together with the average percent emitted as
based on CGA (11) estimates that used national average efficiencies for
contact devices. It must be emphasized that these estimates do not take
into account the effect of particulate and S0? emissions control on con-
trolling trace element emissions and are therefore upper bounds.
50
-------
Table 12
Base Case Estimate of Potential Trace Elements
Discharged to Atmosphere Without Scrubber*
El ement
Antimony
Arsen ic
Beryl I i urn
Boron
Bromi ne
Cadmi urn
Ch lori ne
Fl uori ne
Lead
Mercury
Mo I ybdenum
Selen i urn
Vanad i urn
Zi nc
ppm in Coal
(Dry Basis)
0.5**
8-45
0.6 - 7.6
13 - 198
14.2**
0.14**
400 - 1000**
50 - 167
8-14
0.04 - 0.49
0.6 - 8.5
2.2**
8.7 - 67
0-53
Average %
Emitted
25
25
25
25
100
35
100
100
35
90
25
70
30
25
* - Based on a No. 6 I
** - Not oiven in FCAS
II i no i s coa I .
basis and therefore estimatf
=d (oer Reference 9).
The very large combined amount of these trace elements may be cause
for concern as to possible environmental and health hazards. Many experi-
ments have shown that all of the elements listed above are partially
volatile at combustion conditions, and most of them are known to be toxic
in sufficient concentration. Tests also show that many of these elements
become concentrated on the fly ash carried out with combustion gases, and
the relative concentration of trace elements in particulates increases
with decreasing particle diameter (12). Particulates leaving the stack
after electrostatic precipitation have the highest concentration of all.
Some elements such as Br, Cl, F, and Hg, are reported to leave ;n vapor
form with the flue gases (see Table 8) (9, 11).
The concentration of trace elements in fine ash, such as that col-
lected in an electrostatic precipitator, raises questions as to safe
methods for handling or disposing of such wastes. For example, if the
wastes are dumped or used as land fill, there are serious questions of
leaching and possible contamination of vegetation or groundwater. Fines
51
-------
collected in a stack scrubber raise similar questions about disposal.
If fines are not adequately removed from the stack gas, then these con-
taminated particles may be dispersed into the air we breathe. Moreover,
these fine particles also absorb liquid from the stack gas, giving an
acid condensate containing sulfurous and sulfuric acid. HCI is appar-
ently formed in the combustion process and may also be present. There-
fore, a highly acid condition exists on the surface of the particle,
which may activate or solubilize the trace element contaminants (9).
In one program C13), the fate of 37 trace elements in coal was
traced through a power plant combustion system. Results showed that
many of the 37 elements were appreciably volatile, becoming concentrated
on the fine particles collected by elctrostatic precipitation. Uncol-
lected particles were even higher in concentration of trace elements.
It was concluded that most of the bromine, chlorine, and mercury remain
in the gas phase, along with much of the selenium. Appreciabl/ vola-
tility during combustion was also found for arsenic, cadmium, copper,
gallium, lead, molybdenum, and zinc. Most of these have already been
designated as toxic.
It is clear that sizable amounts of undesirable or toxic elements
are present in coal, that many of these are partially volatile during
combustion and become concentrated on the finer particles, and appear
to present a potentially serious environmental hazard. Studies are
needed to show how to recover them, or how to deactivate and dispose of
them in an environmentally acceptable manner. It is most important that
these studies be made before the potential problems become difficult and
urgent (9).
Regulatory Impacts
Currently, there is a substantial body of regulatory control that
would apply to fIuidized-bed boiler plants. There are Federal and state
emission standards covering coal fired plants for air, water, and solid
waste. Recently, more stringent NSPS have been promulgated for SO , NO ,
and particulate emissions from utility sources. In addition, trace ele-
ments are receiving increasing attention. In the future, as more and
more coal is utilized, pollution levels would substantially increase
without additional mitigating measures.
3.5 Performance
Current
Current activities are mainly in research, development, and demon-
stration stages. Existing boilers are still in the development stages
and therefore, current performance value would not necessarily be repre-
sentative of future operations.
52
-------
Projected
The expectation of proponents of FBC technology is that a fluidized-
bed boiler will favorably compete with conventional boilers with FGD
systems. Even so, it should be noted that more restrictive S0? emission
limitations might not be readily achievable with a f I uidized-bed fired
boiler and the amount of limestone required for the same S0? removal
would be substantially greater than for the FGD approach.
Boiler efficiencies of fIuidized-bed boilers are not expected to
surpass the values obtainable for conventional pulverized coal fired
boilers with an FGD system. It is expected that the principal reasons
would be due to incomplete carbon burnup and the amount of energy re-
quired to maintain the air flow through the fIuidized-bed.
FBC Technology is expected to have the greatest near term impact in
the commerciaI/industria1 boiler size categories. Developed units would
permit the more readily burning of coal at such locations as schools,
hospitals, shopping centers, office buildings, small industrial parks,
etc. The applicability of FBC technology to the utility sector is be-
lieved to depend on the successful development of a pressurized FBC
capability. This appears to be considerably in the future.
3.6 Economics
Current
As previously indicated, all domestic FBC activities are basically
developmental and testing. There are no commercially operating plants
that could provide current (non-R&D) economic operating costs.
Projected
Current projections by the U. S. Department of Energy are that the
capital cost of an atmospheric fIuidized-bed boiler plant would be about
the same as for a conventional boiler plant with a FGD scrubber. In ad-
dition, the total operating costs are expected to be comparable. The ex-
pectation is that even though the limestone requirement will be greater,
this would be offset by a reduction in labor costs.
53
-------
References - Fluidized-Bed Combustion (FBC)
1. University of Oklahoma, The Science and Public Policy Program.
Energy Alternatives: A Comparative Analysis. Norman, Oklahoma,
May 1975.
2. U.S. Department of Energy. Environmental Development Plan
(EDP) - Direct Combustion Program, FY 1977. DOE/EDP-0010, U.S.
DOE, Washington, D.C., March 1978.
3. Institute for Energy Analysis, Oak Ridge Associated Universities.
Energy Requirements for Fluidized Bed Coal Combustion in 800-
1,000 MW Steam Electric Power Plants. ORAU/IEA(M)-77-4, February
1977.
4. Smith, J. W. A Comparison of Industrial and Utility Fluidized
Bed Combustion Boiler Design Considerations. In: The Proceedings
of the Fifth International Conference on Fluidized Bed Combustion,
Vol. 11, Near-Term Implementation. Sponsored by U.S. DOE, U.S.
EPA, TVA, and EPRI. Washington, D.C., December 12-14 1977.
5. General Electric Company. Energy Conversion Alternatives Study
(EGAS). Phase II Final Report to the National Aeronautics and
Space Administration. NASA-CR 134949. December 1976.
6. Based on unpublished material obtained from the U.S. Department
of Energy in March 1979.
7. Bliss, C., Ed. The Proceedings of the Fifth International Con-
ference on Fluidized Bed Combustion, Vol. 1, Overview. Sponsored
by U.S. DOE, U.S. EPA, TVA, and EPRi. Washington, D.C., December
12-14 1977.
8. Farmer, M. H., Magee, E. M., Spooner, F. M. Application of
Fluidized-Bed Technology To Industrial Boilers. Prepared for
U.S. EPA, Office of Research and Development. Exxon Research and
Engineering Company, Linden, New Jersey, September 1976.
9. Jahnig, C. E., Shaw, H. Environmental Assessment of an 800 MWe
Conventional Steam Power Plant. Prepared for U.S. EPA, Office
of Research and Development. Exxon Research and Engineering
Company, Linden, New Jersey, September 1976.
10. Based on unpublished material obtained from the U.S. Department
of Energy in ApriI 1979.
11. Suprenant, N., et al. Preliminary Emissions Assessment of Con-
ventional Stationary Combustion Systems. EPA 600/2-76-046a and
b, March 1976.
54
-------
12. Davison, R. L., Natusch, F- S., Wallace, J. R., Evans, C. A.
Trace Elements in Fly Ash Dependence of Concentration on
Particle Size. Environmental Science and Technology, 8, 13,
p. 1107-1113, December 1974.
13. Klein, D. H., Andred, A. W., Bolton, N. et al. Pathways of
37 trace Elements Through Coal-Fired Power Plant. Environmental
Science & Technology, 9, 10, p. 973-980, October 1975.
55
-------
4. Combined Cycle Power Plants
4.1 Overvlew
In the context of power generation, the term combined cycle was, un-
til recently, applied only to the combination of two turbine cycles util-
izing two different working fluids in electrical generation plants in
which the waste heat from the first turbine cycle provided the heat energy
for the second turbine cycle. However, with the development of more ad-
vanced generating technologies which do not necessarily rely on turbines,
the term now encompasses any combination of cycles using separate work-
ing fluids operating at different temperatures. Combined cycles of gas
turbine-steam, diesel-steam, and mercury-steam have seen varying degrees
of commercial service. Of these, the combined open-cycle gas turbine
and steam turbine power plant appears to offer the best prospects for
having its existing technical problems solved in the near future. Some
configurations being developed could provide generating efficiencies of
over 50 percent based on the heating value of the clean fuel as delivered
(1). This value would be degraded by the energy losses incurred in pro-
viding the clean fuel (e.g., coal conversion). However, efficiencies of
40 percent or better are projected.
There are many gas turbine-steam combined-cycle power plants cur-
rently in operation which achieve overall efficiencies around 40 percent
(2). However, these systems currently rely upon gas or oil whose price
and future availability have obviously become of serious concern. There-
fore, there is major emphasis on making today's turbines run more effi-
ciently on these scarce fuels and to develop improved turbines that will
operate efficiently on the synthetic fuels that will one day replace oil
and naturaI gas (3).
In addition to improved efficiency, such combined-cycle power plants
utilizing gas-turbine and steam-turbine technology have a number of other
key features which could make them particularly appealing to the utility
industry. Besides very fast start-up capabilities, these features in-
clude low capital investment per kilowatt of generation, low operating
costs, and the capability for use as a base-load or peaking power plant.
Another potentially promising aspect of the combined-cycle power plant is
its projected ability to use low-energy gas from coal. The environmental
implications of this are significant. Since such low-Btu gas could be
clean burning, much of the environmental control problems and expense
associated with conventional coal-fired steam generating plants could be
avoided (4).
A variation of the combined gas turbine and steam turbine system fea-
tures the direct combustion of coal in a pressurized fIuidized-bed (PFB).
Although internal particulate control is still required, the PFB offers
the potential for direct combustion of high-sulfur coal without stack gas
c eanup while achieving an overall coal pile-to-bus bar plant efficiency
in excess of 40 percent (5).
56
-------
Some of the more exotic generation technologies currently under de-
velopment fall into the category of combined cycle because of the manner
in which they might be efficiently applied as a power system. These
combined cycles which have been proposed include steam-organic fluid,
gas-organic fluid, liquid metal-steam, and MHD-steam (6). Since these
systems are substantially different from the other combined cycles being
considered and are at such varied levels of development, they will only
be discussed to a limited degree in this section.
4.2 Process Description
Concept
A combined cycle has been described as a synergistic combination of
cycles operating at different temperatures, each of which could operate
independently (6). Synergistic is an appropriate modifier in that the
heat rejected by the higher temperature cycle is recovered and used by a
lower temperature cycle to produce additional power, thus as a system
realizing improved overall efficiency. To qualify as a combination, the
individual cycles must operate on separate fluids. Among these combina-
tions which have been commercially applied are diesel-steam, mercury-
steam, and gas turbine-steam. Still in the development stages are com-
bined cycles of steam-organic fluid, gas-organic fluid, liquid metaI -
steam, and MHD-steam (6).
As stated above, each cycle in the combination is operating at a
different temperature. The higher temperature cycle is referred to as
the topping cycle and the lower temperature cycle as the bottoming cycle.
By generic category, topping cycles which have been practically applied
include Otto, Brayton, and Rankine cycles. All bottoming cycles have
been of the Rankine type.
In practice, a topping cycle consisting of a gas turbine or diesel
engine is used to drive electric generating equipment. Should MHD be the
topping cycle, the electric current would be generated directly. The
principal heat rejected by these possible topping cycles is in the form
of sensible heating in the exhaust products of combustion. This is the
heat that becomes available to the bottoming cycle as the exhaust gas is
cooled through a range of temperatures. The heat is imparted to the
working fluid of the bottoming cycle, typically steam, which drives
additional power generating equipment. Depending upon the overall eco-
nomics of the particular system, it may be advantageous to supplement
the heat recovered from the topping cycle with additional heat to oper-
ate the bottoming cycle. However, whether the bottoming cycle is unfired
or supplementary fired, it is this "captured" heat, which would other-
wise be lost, that is the key to the improved efficiency of combined
cycle systems.
57
-------
For most bottoming cycles, it appears that steam will remain the
predominant fluid for the foreseeable future. The advantages of steam
Rankine bottoming cycles have so far prevailed and, with the exception
of a few experimental installations, all commercial bottoming cycles
have used this medium (6). Some of the advantages of steam are low
cost, chemical stability and inertness, high specific heat, and high
heat transfer rates. The disadvantages of steam include low molecular
weight, high latent heat, and high critical pressure. However, some of
these disadvantages can and are being mitigated at the expense of some
cycle complexity.
Deta iI
As noted earlier, gas-steam turbine combined cycle generating sys-
tems are currently available to efficiently serve utilities in base, in-
termediate and peaking modes. Unfortunately, these contemporary systems
rely on premium fuels. A schematic representation of such systems and
the typical efficiency attainable under current technology is provided
by Figure 10 (3). Gas and light distillate oils have been the most wide-
ly used fuels in the past. Heavy distillates, residual, and crude oils
have also been used, but treatment is necessary to remove or inhibit the
contaminants
fuel in
Simple
gas turbine
cycle
compressor
combustor
29% ol luel energy
out as electricity
Steam
turbine
condenser
cooling system
15-18% waste
heat energy
out as electricity
Total
combined cycle
efficiency 40%
Figure 10
Simplified Schematic of Combined Gas and Steam
Cycle Generating System
58
-------
normally present which cause corrosion. To cope with the ever increasing
problem of supply and price of these premium fuels, greater use of coal
and coal derived liquid and gaseous fuels is seen as a viable alternative.
Therefore, the most promising combined cycle plant configurations being
considered are directed at using such fuels along with improved gas tur-
bine performance.
Although there are many such configurations in various stages of
conceptual and practical design, there are four possible combined cycle
power plant systems which have been and are being actively studied (1, 7).
These systems, three of which were assessed by Energy Conversion Altern-
atives Study (EGAS) are: 1) a high-temperature combined cycle using coa I -
derived gaseous and liquid fuels; 2) a high-temperature combined cycle
using a low-Btu coal gasifier integrated into the compressed-air path of
the combined cycle; 3) a supercharged boiler combined cycle using a pres-
surized coaI-fired fIuidized-bed boiler in the compressed-air path of the
combined cycle; and 4) a low-temperature (1600-1800 F) combined cycle us-
ing a pressurized coaI-fired fIuidized-bed combustor in the compressed-air
path of the combined cycle. All of these combined cycle systems are only
conceptual at this point.
High Temperature Combined Cycle Using
Coal Derived Liquid Fuel
This particular combined cycle configuration, depicted in Figure 11,
is arranged essentially like existing gas-steam turbine combinations.
The differences are the higher operating temperatures and the use of a
clean, coal-derived liquid fuel. Under the conditions assumed for this
combined cycle arragement, the topping cycle is an advanced gas turbine
with inlet temperatures around 2400 F coupled with a heat recovery steam
generator. Based upon the Btu content of the clean, coal-derived fuel,
an overall thermal efficiency of near 50 percent is projected. This will
be degraded to about 40 percent if consideration is given to the energy
lost in the conversion process. Such a fuel must not only be clean
enough to meet environmental standards, but also must have low erosion
and corrosion properties to protect the gas turbine blades. Variations
in the steam bottoming cycle include options for supplementary fired
steam boilers, alternative steam pressure levels, and the use of steam
induction that affect both cycle efficiency and plant cost, and there-
fore, the ultimate cost of electricity.
The higher gas turbine inlet temperature of this configuration re-
quires the use of either cooled or ceramic blades. Turbine inlet temper-
atures in excess of 1800 F require either cooling of the vanes and blades
so as not to exceed critical rneta I temperatures or the use of high tem-
perature ceramic construction. Air cooling of vanes and blades is pres-
ently used by the industry for turbines operating in the range of 1900 F
with units under development capable of reaching 2100 F. Advanced gas
59
-------
To
Stack Steam
Turbine
Fuel
Figure 11
Simplified Schematic of High Temperature Combined Cycle
Using Coal Derived Liquid Fuel
turbine cooling concepts include extension of air cooling to 2500 F, the
use of water cooling to reach 3000 F, and the use of ceramic vanes and
blades capable of withstanding temperatures from 2400 to 3000 F (1).
The simplicity, environmental acceptability, and high projected ef-
ficiency of this combined cycle configuration is particularly appealing.
However, further advances in high temperature gas turbine technology, and
the development of an economically sound process to produce a high-Btu
liquid from coal will determine the future application of this combined
cycle arrangement in the electric power generating industry.
High Temperature Combined Cycle With
Integrated Low-Btu Gasifier
As shown in Figure 12, this configuration employs a gasifier with
its own cleanup system to provide the gas turbine topping cycle with a
low-Btu gas. The technical and economic feasibility of this arrangement
is based upon this coal derived gas being sufficiently free of particu-
lates, sulfur, and nitrogen to eliminate the need for any final emission
control apparatus as well as not being damaging to the gas turbine compo-
nents. As shown in Figure 12, the air-blown pressurized gasifier and
associated cleanup equipment fit into the compressed air flow path of
the gas turbine to provide for coal firing of the turbine. Development
efforts currently are centered on both fixed-bed and fIuidized-bed gas-
ifiers, but future development may include entrained-bed gasifiers (1).
60
-------
Process Water
To
Stack
Steam
Turbine
Heat
Recovery
Steam
Generators
Figure 12
Simplified Schematic of High Temperature Combined Cycle
With Integrated Low-Btu Gasifier
The inclusion of a gasifier in the compressed-air flow path has the
effect of reducing the overall efficiency as compared to the previously
discussed combined cycle system using coal derived oil. Based upon vari-
ous configurations of this combined-cycle arrangement addressed by the
EGAS, efficiencies approaching 47 percent were the upper limit (based on
the Btu content of the clean, coal derived gas). Since the bottoming
cycle is the same, this drop in efficiency is definitely attributed to
the gasifier addition. Two particular gasification concepts were invest-
igated by EGAS: 1) an air-cooled gas turbine with a fixed-bed gasifier
and a cold gas cleanup train; and 2) an air-cooled gas turbine with a
fIuidized-bed gasifier and a hot gas cleanup train. The desuIfurization
of the low-Btu gas occurs in the cleanup train with the fixed-bed units
and in the gasifier with the fIuidized-bed units. The cold gas cleanup
train removes particuIates, heavy oils, and sulfur compounds. The hot
gas cleanup train removes particuIates. It is the cooling of the fuel
gas that introduces an efficiency loss.
61
-------
As noted previously, this combined cycle plant configuration is only
conceptual at this point. The success of such an advanced power gener-
ating concept will rely on continued achievements in air cooling of tur-
bines, economic low-Btu gasification of coal, and economic gas cleanup
systems.
Supercharged Boiler Combined Cycle Using
Pressurized Coal-Fired Fluidized-Bed Boiler
As seen by the schematic representation presented as Figure 13, this
is the most complex combined cycle configuration addressed thus far. The
thrust of this design is to use a gas turbine to augment the output from
a pressurized coal-fired fIuidized-bed boiler plant. The gas turbine,
operating on gas furnished by the fIuidized-bed, is used to pressurize the
boiler and the gas turbine exhaust is used to heat the boiler feedwater
above 190 F. Power from the gas turbine is added to that produced by the
steam cycle side of the plant to provide about 20 percent of the net power
from this conceptual generating system.
Coal Dolomite
I
Air
Figure 13
Simplified Schematic of Supercharged Boiler Combined Cycle
Using Pressurized Coal-Fired Fluidized-Bed Boiler
62
-------
The performance of this configuration is limited by the permissible
outlet temperature from the fIuidized-bed combustor/boiIer. Since the
gas leaving the fIuidized-bed to feed the gas turbine is not over 2000 F,
the temperature at the gas turbine inlet is equally low. In spite of
this, the overall efficiency is projected to be close to 40 percent since
the arrangement permits the direct burning of coal without any associated
conversion or external environmental control losses.
Several power plant design options are available: steam turbine
inlet conditions, ratio or gas turbine power to total plant power, and
gas turbine inlet conditions. The best steam conditions appear to be
near or above critical steam pressure but with 1000 F throttle and reheat
temperatures. The capital cost rises sharply as more austentic steels
are required in the steam system, offsetting the small reduction in elec-
tricity cost that accompanies an improved heat rate. The cost of elec-
tricity from a power plant with a supercharged boiler is also relatively
insensitive to gas turbine inlet temperatures and to the gas turbine-to-
steam turbine power ratio at values below 0.2 (1).
Again, we are looking at a conceptual design whose practical imple-
mentation is contingent upon an economic and technically sound pressur-
ized fIuidized-bed boiler, development of efficient and reliable hot gas
cleanup equipment, and development of a 1600 to 1800 F gas turbine with
the construction to withstand the increase loading of gas-borne contami-
nants directly into the turbine.
Low-Temperature Combined Cycle With Pressurized
Coal-Fired FIuidized-Bed Combustor
Another possible variation of the combined cycle utilizing fluidized-
bed is to replace the standard combustor used in a gas turbine (see Fig-
ure 11), with a coal-fired pressurized fIuidized-bed combustor without
in-bed heat removal. Designs of this type are characterized by higher
heat rates than are presently being projected for other combined cycle
configuration because of the lower gas turbine inlet temperatures (1600-
1800 F). Whether or not units of this type will ever serve in base load
utility plant application is doubtful. However, smaller scale industrial
sized plants may find acceptance since they would permit the direct burn-
ing of coal in an environmentally acceptable fashion.
As in the previous combined cycle design, the ultimate success
hinges on development of efficient and reliable f I uidized-bed combustors,
hot gas cleaning equipment, and gas turbines capable of satisfactorily
operating at higher dust and corrosive loadings in the working gas.
There have been many indepth studies addressing the performance of
combined cycle power plants. Of particular current interest are combined
cycle concepts that are fueled by coal through the use of an integrated
gasifier. Such a configuration, the High Temperature Combined Cycle with
Integrated Low-Btu Gasifier, has previously been described. Reference 8
63
-------
addresses the energy balance of such a concept employing the Combustion
Engineering Low-Btu coal gasification process. The reference 8 analysis
is predicated on advanced gas turbine designs with a 2400 F combustion
outlet temperature. Such turbines are not presently available, but with
development, reference 8 indicates an expected availability in the 1981
to 1985 time period.
Table 13 provides a heat balance based on reference 8. Diagrammatic-
ally, this can be illustrated by the heat flow diagram of Figure 14. This
diagram indicates energy distribution on a percent of total input basis.
Table 13
Estimated Heat Balance for 1200 MWe Coal Fueled Combined
Cycle Power Plant with Integrated Low-Btu Gasifier
Btu/hour Percent of Total
(10 Btu's) Energy Input
Net Electrical Power Output
Gas turbine derived power 3,024 28.26
Steam turbine derived power 1,050 9.81
System Losses
Ash/slag (combustibles and sensible 138 1.29
heat)
Gasifier loss (heat loss) 153 1.43
Sulfur product 103 0.96
Power losses (electrical, mechanical 154 1.44
etc.)
Condenser (steam turbine and compres- 3,505 32.76
son turbine)
Fuel gas compressor coolers 819 7.66
Cooling for gas cleanup unit 179 1.67
Stack losses 1,541 14.40
Waste water steam heat losses 34 0.32
Total Energy Input 10,700 100.0
(Input energy: 95% coal, 5% from aux-
iliary power, blower and turbine air.)
Based on gasifying 10,000 ST/day of Illinois No. 6 coal with a coal
feed rate of approximately 420 tons per hour and a plant rating of
approximately 1,200 MWe.
64
-------
100? —
Energy input
95?
From coal
7.11?,
Heat losses associated
with ash/slag, gasifiers,
sulfur product gas cleanup,
etc. and power losses.
Gas
turbi ne
deri ved
power
— 5?
(other)
4.40?
/Stack losses
32.76?
Losses from
Condensers
Steam turbi ne
derived power
7.66?
Losses via Fuel
Gas Coolers
38.07?
Net Electrical
Energy output
Figure 14
Heat Flow Diagram Based on Table 13
4.3 Applications
Current
There are numerous gas turbine-steam combined cycle plants present-
ly operating in intermediate and base load capacities at utility plants
in various parts of the country. For example, the Westinghouse Electric
Corporation has installed many units during this decade for Public Ser-
vice of Oklahoma, El Paso Electric, Florida Power and Light, Southern
California Edison, and others. These have been units rated at up to 260
MW, installed either singularly or in series which are capable of burning
various grades of oil and/or gas (9). The other major domestic manufac-
turer of such plants is General Electric with United Technologies, Curtis
Wright, Brown Boveri, and others offering various combined cycle configur-
ations.
65
-------
Certainly, plants consuming these increasingly scarce and costly
fuels (oil and gas) do not provide a long term solution to meeting this
country's electric power generating requirements. Therefore, any large
scale implementation of such combined cycle plants will only be strate-
gically and economically acceptable with the advent of clean burning syn-
thetic fuels most probably derived from coal. Even so, on a near-term
basis, there is a role for combined cycle plants.
An example of such a near-term role is where, because of environ-
mental constraints, power plants cannot be converted to burn cheaper,
more abundant coal. In this situation, combined cycle power plants
could provide more economical and efficient base load power generation
than conventional oil and gas burning systems. The more obvious and
most immediate application of the existing gas turbine-steam combined
cycle design is in areas such as the Southwest where fuels such as nat-
ural gas are, for the moment, plentiful locally (3).
Another contemporary application of combined-cycle is the repower-
ing of existing conventional plants by the addition of a combustion
turbine. Based upon the desired impact, a wide variety of repowering
configurations are available. Some of the basic reasons for repowering
may i nclude (10):
• Efficiency improvement resulting from repowering,
« Increase in capacity at existing sites,
® Increase in capacity without increase in cooling
water requirement,
• Shortage of new sites for new power plants,
* Air pollution difficulties with the existing plants,
• Minimum environmental impact of the repowered plant,
e Avoidance of cost, difficulty and delay involved
in approval of new sites,
• Boiler plant in need of extensive overhaul or
rep Iacement.
One of the simplest forms of repowering consists of using the ex-
haust heat from the combustion turbine to heat the feedwater for a con-
ventional gas or oil fired steam plant in place of the steam extracted
from the steam turbine. Under this arrangement, additional power is
produced by the combustion turbine and by the steam no longer used by
the feedwater heaters now expanding to the condenser. Repowering can
also be applied to puIverized-coaI burning plants. Unfortunately, such
66
-------
an application presents a variety of technical and economic problems
which may negate the potential benefits. For example, when combustion
turbine exhaust gas is used as the source of boiler oxygen, the flow Cand
velocity) of exhaust gas through the boiler is increased. However, the
intake of oxygen to pulverized coal fired boilers is deliberately limited
to minimize fly ash erosion. Therefore, the increase in gas velocity
resulting from the increased exhaust gas flow may be unacceptable. Under
such conditions, steam flow of a repowered coal-fired boiler may have to
be restricted. Additionally, the economizer would have to include soot
blowing and water wash capabilities to control fouling. Further, a spe-
cial low-oxygen burner is also needed, as well as a primary air mover
because the conventional air preheater will be removed. A final feature
limiting the application of repowering to coal-fired plants is that the
equipment costs are higher than for their oil and gas fired counterparts
(11).
Repowering has only been applied to a limited degree in the past be-
cause the availability of relatively inexpensive fuels has until now min-
imized the importance of achieving higher thermal efficiencies. However,
as the price of gas and oil continues to go up along with their question-
able long term availability, the improvement in heat rate offered by re-
powering makes it more attractive than ever for utility applications (11).
Besides being economical, a repowered plant would be more efficient, us-
ing as much as 20 percent less fuel than the conventional oil-fired plant.
It is estimated that twenty thousand or more megawatts of this nation's
old, inefficient oil-burning capacity cannot be converted to coal for
economic or environmental reasons. If those plants were repowered with
combined cycle systems, the greater efficiency made possible by the gas
turbine's waste heat recovery system could save over 150,000 barrels of
oi I per day (2).
Projected
There has been a slump in the United States market for gas turbines
since 1973 when it became clear that the future price and availability of
clean fuels was less than desirable (12). However, the General Electric
Company, one of the principal turbine manufacturers, now forecasts a two-
thirds increase in the worldwide gas turbine market during the next ten
years over the previous decade. This projected increase will be mainly
due to the development of larger, more efficient units and their use in
gas-steam turbine combined cycle power plants (13). In addition to
achieving efficiencies in excess of conventional fossil plants, there are
other attributes of such combined cycle systems which can make them more
attractive for power generation in the near future. These include lower
installation cost, shorter installation schedules, more flexible oper-
ational capabilities, and half the water requirements of a conventional
steam plant. Another factor that makes combined-cycle plants attractive
to utilities is the ready availability of factory-constructed portable
67
-------
control rooms providing computer control systems that load units auto-
matically to achieve a desired megawatt demand (4). These highly sophis-
ticated control systems can start each piece of equipment, accelerate
and synchronize the turbine generators, and direct a complete plant shut-
down in the event of a normal stop mode. The systems not only get the
unit on and off line faster, but also provides less chance for equipment
damage by reducing the number of personnel required to operate a plant
and the level of training and experience necessary to achieve reliable
performance.
n this country, one of the primary factors giving impetus to the
use of such gas-steam turbine combined cycle plants fueled by natural
gas and light distillate oil is their envi ronmentaI acceptabiI ity. In-
creasingly stringent emission regulations, permit requirements, and cit-
izen opposition to other, less costly, alternative energy sources such
as coal encourage a continued expansion of this generating approach.
However, as stated before, the use of these high grade clean fuels is
strategically and economically unacceptable in the long run. Therefore,
any new generating capacity of this type should have the capability to
not only burn residual and other low grade fuels, but also synthetic
fuels which will eventually be derived from coal and oil shale. Thus
this technology could continue to be an alternative for efficient elec-
tric power generation through the time of dwindling oil and natural gas
supplies to a time of more abundant synthetic fuels. When such fuels
are available, then i.t will be practical to implement them on other than
a peaking and intermediate load basis.
On a large scale, combined cycle plants will be very desirable when
fIuidized-bed combustor/boiIer technology is perfected for utility size
application. This will permit the direct combustion of high sulfur coal
without the energy losses attributed to conversion and external environ-
mental controls. Another promising, but more indefinite, role for com-
bined cycle power systems will come toward the end of the 1990's when
fuel cells and MHD are projected to be commercially available. These
technologies are discussed separately in their respective sections of
th i s pub I ication.
4.4 Environmental Considerations
As discussed previously, there is not one single unique combined
cycle power plant, but instead, a potentially infinite number of cycle
combinations to comprise such a system. Therefore, when addressing the
environmental aspects of combined cycle power plants, it is more appro-
priate to identify the effluents associated with the individual cycles.
These cycles may be applied in a topping or bottoming role, depending
upon the particular generation system configuration.
68
-------
Identified Pollutants
Of the combined cycle systems which have seen commercial service,
only the gas-steam turbine type can be considered to be currently applic-
able to electric power generation. There are no significant liquid or
solid pollutants from this system and the air emissions are currently
quite low since present configurations use gas turbines burning high
grade fuels (light distillate oil and gas). Subsequent generations of
the gas-steam turbine combined cycle systems will be designed to consume
lower grade, hotter burning fuels which will result in an associated in-
crease in air emissions. Those combined cycle systems incorporating a
fIuidized-bed combustor/boi Ier have their own set of air, liquid, and
solid effluents. This also applies to the combined cycle configurations
with an integrated low-Btu gasifier. The effluents associated with more
advanced cycles such as fuel cells and MHD have been projected and are
covered in their respective sections of this document.
Air Emissions
Contemporary gas-steam turbine combined cycle systems burning light
disti late or natural gas have no significant sulfur or particulate emis-
sions. The only emission of any consequence is NO . Although it results
in an increase in the carbon monoxide emitted, NO is controlled by the
injection of demineraI ized water or steam into the combustor. Since the
injection technique requires water of high purity to avoid deposits on
turbine blades and other components, water treatment (and associated
sludge disposal) may be required. Alternative control techniques for re-
ducing both thermal and, to a lesser extent, fuel NO include: alter-
ations to the combustion temperature and residence time; use of a two-
stage combustion system; or use of a catalytic combustor. Fuel refining
to reduce nitrogen content of fuels, or stack gas scrubbing, are being
considered for controlling fuel-related NO (14).
s x
The gas-steam turbine combined cycles configurations utilizing a
pressurized fIuidized-bed (PFB) boi Ier/combustor offer several environ-
mental advantages. The fIuidized-bed, with limestone or dolomite addi-
tion, permits the direct combustion of high sulfur coal without need for
flue gas desu I f ur i zation. As the sulfur in the coal burns to SO,,, it is
removed from the combustion gases through the reaction of the S0? and
CaCO, (limestone) and a i r to form solid CaSO. and CO,, gas. Based upon
various proposed configurations, S0? can be reduced to within the utility
New Source Performance Standard (NSPS). The NO emissions from a PFB are
also substantially below the levels encountered in conventional coal
fired furnaces since conversion of air nitrogen is eliminated by low com-
bustion temperatures and NO from fuel-bound nitrogen is lessened due to
partial reduction by the dofomite sulfation reactions (5). Total NO
emissions are projected to be between 0.2 and 0.3 Ib per MBtu as compared
to the utility NSPS of 0.5-0.6 Ib per MBtu. Anticipated particulate emis-
sions are also quite encouraging, projected to be well below the utility
69
-------
NSPS of 0.03 Ib per MBtu. Although it has not been proven in utility
size units, the PFB boiIer/combustor integrated with a gas-steam com-
bined cycle plant is projected to not only meet the current emission
limits, but also have the capability to meet the progressively more
stringent standard anticipated in the future. Some of the other envi-
ronmental aspects of fIuidized-bed combustion such as trace element
emissions are discussed under the appropriate section of part 4.
Gas turbine cycles of the future, designed to burn coal-derived
low-Btu gas or liquid fuel, will have relatively low emission of sulfur
dioxide and particulates. This is so since most of these contaminants
are removed before reaching the turbine to protect it from corrosion
and erosion.
The high temperature combustion used in these future combustors
could increase nitrogen oxide formation above that of contemporary tur-
bines. NO from the open cycle gas turbine combustor would consist of
thermal NO produced from conversion of atmospheric nitrogen) and fuel-
bound NO Tproduce-d from conversion of fuel-bound nitrogen). Coal-
derived liquid fuels are expected to produce higher emissions of NO than
low-Btu gas, since the liquid fuels are more conducive to the formation
of thermal NO and contain more fuel-bound NO (.14).
x x
The gas turbine combustor should emit negligible amounts of carbon
monoxide and unburned hydrocarbons under full load operating conditions
when combustor efficiency approaches 100 percent. However, for startup
or partial load conditions, the combustor efficiency would decrease,
increasing emissions of CO and HC. Some unburned carbon particles also
may be emitted under partial load conditions, but under normal, full
load conditions, all the carbon should be combusted.
Particulate emissions from open cycle gas turbines should not be a
problem since removal of the particulates from the combustion gases to
levels well below environmental standards is necessary to prevent ero-
sion of the turbine blades, walls, and ducting system. If the turbine
erosion does occur, erosion products could present a potential emission
problem. Trace elements such as nickel, chromium, cobalt, and molyb-
denum may be generated from the erosion of turbine materials, ceramic
coating, and refractory composites, and from the fuel itself.
Liquid Effluents and Solid Waste
As stated above, contemporary gas-steam turbine combined cycle power
plants consuming light distillate oil or natural gas have no liquid or
solid waste of any consequence. However, for those combined cycle config-
urations involving fIuidized-bed, low-Btu gasification, or coal liquefac-
tion, the environmental problems attributed to liquid or solid effluents
70
-------
are those associated with the particular process rather than its applica-
tion in a combined cycle power generation scheme. Therefore, the reader
is referred to the appropriate sections within this publication where
such environmental aspects are discussed for the specific process.
4.5 Performance
Current
In the days of "cheap" gas and oil, a gas turbine with its relatively
low initial cost and short delivery was the natural choice for generating
power at small dispersed stations, meeting peak loads at larger central-
ized utility plants, and in many cases, for base load service. Today,
the initial cost is still relatively low and the delivery time the best
of any comparable rated equipment.
A typical gas turbine-generator currently being produced converts
approximately 30 percent of the fuel input energy into electrical power.
Combined cycle concepts have received attention as a means of utilizing
turbine waste heat to produce additional electric energy thereby provid-
ing greater overall system efficiencies. Current operating combined
cycle plants typically have efficiency values on the order of 40 percent.
Unfortunately, existing combined cycle plants depend on clean petroleum
based fuels.
Projected
As stated above, current combined cycle power plants are reasonably
efficient and environmentally safe performers. Unfortunately, such per-
formance depends upon clean fuels whose price and availability lack the
stability on which to base a reliable electric power generating industry.
Therefore, although promising, the future for combined cycle systems is
limited by many technological hurdles now under intense research and de-
velopment. These R&D areas being sponsored by EPA, DOE, industry, and
others include: 1) advances in high-temperature (2500-3000 F) gas tur-
bine design; 2) development of improved gas turbine construction to with-
stand hot, corrosive and erosive particulate gases from low-grade fuels;
3) commercialization of economically viable processes to convert coal to
a suitable liquid or gaseous fuel; 4) hot gas cleanup of particu lates;
5) perfection of f I u id i zed-bed combustion applicable to utility sized
plants; and 6) implementation of advanced power systems such as fuel
cells and MHD. The first five of these areas are essentially directed
at solving the fuel problem faced by contemporary combined cycle power
plants. As achievements are realized, a second generation of combined
cycle plants will evolve which will be capable of efficiencies compar-
able (40+$) or greater than present systems, but more importantly, will
not rely on scarce clean fuels. The advanced concepts like fuel cells
and MHD represent an entirely different topping cycle concept which, as
71
-------
discussed in their respective sections, when combined with a steam bot-
toming cycle, offers the prospect for coal-to-electricity efficiency
levels of near 50 percent. However, as a practical combined cycle tech-
nology, these concepts are not anticipated to be implemented until the
near 2000 period and are therefore not considered in further detail.
In the area of turbine technology, work sponsored by DOE and others
is directed at the development of gas turbines which can operate effi-
ciently on lower grade, more readily available fuels. Prime candidates
for use in the near term are residual oils and fuels made from agricul-
tural and urban waste products. In the longer run, these fuels will be
replaced by the synthetic fuels that should eventually be derived from
coal and oil shale. Because many different liquefaction, gasification,
and other fuel-cleanup processes are being developed, future turbines
must have the capability to burn a broad spectrum of fuels with a wide
range of contaminant levels (12). Such lower grade fuels burn hotter and
contain more contaminants than do light distillate oil and natural gas.
To cope with this, improved turbine combustors and blades are being de-
veloped which can withstand the hot, corrosive gases resulting from these
lower grade fuels. Other gas turbine development efforts are focused on
improved cooling systems intended to increase turbine durability when
hot-burning fuels are used. One method of this type involves fabricating
the turbine blades with internal channels to carry cooling fluid.
When synthetic liquid and gaseous fuels become commercially avail-
able and advanced turbine technology permits inlet temperatures in the
2500-3000 F range, then we will see combined cycle electric generating
efficiencies of over 50 percent based upon the heating value of the
clean fuel as delivered (1). The inefficiency of an off-site fuel plant
for conversion of the coal to a clean fuel would reduce the coal-to-
electricity efficiency level to approximately 40 percent. It is these
energy losses attributed to coal conversion that create strong incentives
to design more efficient gas turbines and to use them in combined cycle
systems for base load and intermediate service. If an integrated low-
Btu gasifier configuration of the type discussed earlier were employed
as the fuel supply system and comparable gas turbine inlet temperature
(2500-3000 F) were acceptable, coal-to-electricity efficiencies could
reach 44 percent.
The gas-steam turbine combined cycle configurations using the pres-
surized fluidized-bed combustor/boiIer also would be capable of effi-
ciencies close to 40 percent.
4.6 Economics
Current
When looking at the cost of contemporary combined cycle power plants
versus conventional coal or nuclear facilities, one must not only address
72
-------
the initial plant cost, but also the price and availability of suitable
environmentally acceptable fuels. As mentioned earlier, the gas-steam
turbine combined cycle plants currently being offered by the industry
have initial capital costs and lead times significantly less than those
of alternate generating systems. For example, combined cycle plants
fired by gas and/or oil have an initial capital cost of less than $400
per kilowatt and can be installed and operating in less than three years.
This compares with a coa -fired steam plant cost with FGD of about $350
per kilowatt taking five to ten years to plan and build and a nuclear
facility cost of $1,100 or more per kilowatt requiring 10 to 13 years
lead time (3). However, this is just the "tip of the iceberg." In spite
of this low capital cost and reasonable efficiency (40+$), the cost of
electricity generated by contemporary combined cycle systems approaches
40 mills per kilowatt hour based upon today's clean fuel prices ($3.00
per MBtu for natural gas), as compared to around 30 mills/kwh for a coa I -
fired steam plant with FGD. If the quality of fuel was reduced, savings
realized would be more than offset by the increased overhaul and mainten-
ance cost. The poorer the fuel, the ower the turbine reliability, the
more frequent the overhaul, and thus, the greater the operating costs.
When running on distillate oil, a gas turbine can last 30,000 to 50,000
hours before overhaul and when natura gas is used, this period is
doubled. However, when today's gas turbines are run on the more abund-
ant residual fuels, turbine life can be as short as 2000 to 5000 hours
before overhaul is necessary (3).
Projected
As noted earlier, the term combined cycle covers a broad range of
systems comprised of cycles having well established technologies as well
as those barely beyond the conceptual stage. In these latter cases,
since there are so many uncertainties with respect to the point of
eventual imp ementation, equipment costs, and environmental regulations,
the overall economics of these systems remain to be established with
reasonable certainty. For example, projections have been made that
electricity generated by MHD combined cycle systems will cost about 32
mills per kilowatt hour in the 1990's as compared to 45 mills/kwh from
conventional coal-fired plants at that time (15). Needless to say, the
accuracy of such an estimate is subject to many poorly defined technica ,
environmental, and economic issues. However, with the more established
technologies that have near term prospects, the economics are better
defined. These are mainly contingent upon achieving improved heat rates
with high temperature turbines capable of withstanding the corrosive
gases from burning low grade synthetic and natural fuels. Obviously, the
overall economics are further sensitive to the ultimate costs of such
equipment and fuels. It is safe to say that the coming generation (early
1980's) of gas-steam turbine combined cycle plants will achieve heat rates
below 8000 Btu per kilowatt hour. At a clean fuel (e.g., natura gas)
cost of $3.00 per MBtu and a plant cost of $400/kW, the cost per ki owatt
hour from a 320 megawatt power station will be over 38 mills per kwh.
73
-------
This is based upon an 18 percent per year capital charge and the plant
functioning in a base load capacity (5000+ hours per year). Even though
this projected plant is over 40 percent efficient, its cost, in terms of
current dollars, is high because of the clean fuel cost. Therefore, as
the various synthetic fuel processes evolve, they will essentially dic-
tate whether the combined cycle is an economic alternative.
74
-------
References - Combined Cycle Power Plants
1. National Academy of Sciences. Assessment of Technology for
Advanced Power Cycles, 1977.
2. Marks' Standard Handbook for Mechanical Engineers, Eighth
Edition. McGraw-Hill Publishing Company, 1978.
3. U.S. Department of Energy. Gas Turbines for Efficient Power
Generation. Assistant Secretary for Energy Technology, DOE/OPA-
0003, Washington, D.C., February 1978.
4 Uram, R. Computer Control of Combined-Cycle Power Plants.
IEEE Spectrum, October 1977.
5. Peterson, J. R., and Lucke, V. H. Commercial Powerplant Design
Development for the Coal Fired Combined Cycle. Combustion,
January 1979.
6. Foster-Pegg, R. W. Steam Bottoming Plants for Combined Cycles.
Combustion, March 1978.
7. General Electric Company. Energy Conversion Alternatives Study
(EGAS). Phase II Final Report, NASA-CR 134949, December 1976.
8. Chandra, K., McElmurry, B., Neben, E. W., and Pack, G. E.
Economic Studies of Coal Gasification Combined Cycle Systems
for Electric Power Generation. Fluor Engineers and Constructors,
Inc. for EPRI, EPRI AF-642, Palo Alto, California, January 1978.
9. DiNenno, P. A. Combined Cycle Update. 1977 Electric Utility
Engineering Conference, March 13-25, 1977.
10. Foster-Pegg, R. W. Combustion Turbine Repowering of Conven-
tional Steam Power Plants. 1977 Electric Utility Engineering
Conference, March 13-25, 1977.
11. Pruce, L. M. Combined-Cycle Repowering: More Attractive Than
Ever. Power, March 1979.
12. R&D Aimed at Burning Coal-Derived Fuels. Power, November 1977.
13. For Higher Efficiency...Look to the Combined Cycle. Turbo-
machinery International, September 1978.
14. U.S. Department of Energy. Environmental Development Plan
(EDP) - Advanced Power Systems Program. Assistant Secretary
for Environment, DOE/EDP-0021, Washington, D.C., March 1978.
15. MHD's Target: Payoff by 2000. IEEE Spectrum, May 1978. pp.
46-51.
75
-------
5. Low/Medium-Btu Gasification
5.1 Overview
No fixed energy values are associated with the definition of low
and medium-Btu gases. However, 100 to 200 Btu's per cubic foot is
generally considered low and 300 to 650 Btu's is generally considered
medium (1). The Iow/medium-Btu gasification of coal is essentially an
existing technology. In fact, gas was first manufactured from coal in
the eighteenth century. Currently, Iow/medium-Btu coal gasifiers are
in use in Europe, South Africa, and to a very limited extent, in the
United States.
Coal can be gasified by any of several processes: synthesis, pyrol-
ysis, and hydrogasification. In synthesis, coal or char is reacted with
steam and oxygen and produces the heat for a reaction that produces a
mixture of hydrogen and carbon monoxide. In pyrolysis, coal is heated
in a starved air atmosphere. In this process, some gas and liquids
result, the major product being a coke residue. In hydrogasification,
coal, coke, or char is reacted with hydrogen to form a methane product.
A number of Iow/medium-Btu coal conversion processes have been in-
vestigated. The U. S. Department of Energy, together with the Electric
Power Research Institute and others, are sponsoring the development of
several advance conversion processes, two of these being the Lurgi and
the Koppers-Totzek. In addition, the U. S. Department of Energy is
supporting efforts relating to the in situ gasification of coal.
Environmental problems common to coal associated energy generating
systems will generally also apply to coal gasification facilities. Addi-
tional adverse environmental aspects of proven and pilot plant stage
processes are difficult to assess because of the very limited data avail-
able from such operations.
The conversion efficiency as based on total energy input is some-
what process and site specific and is estimated to be in the 70 to 80
percent range including raw gas cleanup. The value without gas cleanup
(i.e., raw hot gas output) is estimated to be as high as 90+ percent
when the sensible heat of the gas is included. Since this is basically
a developed technology, efficiencies are not expected to improve signif-
icantly over the foreseeable future.
Estimates of the cost of Iow/medium-Btu gas depend on many factors
including utility or private financing, coal cost, effluent disposal
requirements, etc. Current estimates range between $2.50 and $4.00 per
million Btu for low-Btu gas and $5.00 to $8.00 for medium-Btu gas.
76
-------
5.2 Process Description
Current
Figure 15 is a generalized diagram that shows the basic processing
steps common to different types of gasification processes. An overview
of the overall process consistent with the figure follows.
H2 or
Steam
Oxygen
or Al r
LJ
Coal
Mechan lea 1
Preparation and
Possible Pre-
treatment
Gasl f Icat Ion
Gas
Cleanup
Low or Medl urn
Btu Gas (low Btu
if air used)
CO-
By-products
and Waste
f
Sulfur Recovery
Figure 15
Generalized Flow Diagram - Low/Medium-Btu Gas
The first step, coal preparation with possible pretreatment, can be
simple or complex depending on the characteristics of the specific gasi-
fication process. This step can range from crushing or grinding to
proper size to more sophisticated preparation including sizing, physical
beneficiation, and drying. In addition, in certain processes, it may be
necessary to' pretreat an agglomerating coal feed to destroy the coking
properties (1 , 2).
The three primary ingredients needed to chemically synthesize gas
from coal are carbon, hydrogen, and oxygen. Coal provides the carbon;
steam is the most commonly used source of hydrogen, although hydrogen
is sometimes introduced directly from an external source; and oxygen is
usually supplied as either air or pure oxygen. Heat can be supplied
either directly by combusting coal and oxygen inside the gasifier or
from an external source (1).
77
-------
Coal can be gasified by any of several processes: synthesis, py-
rolysis, or hydrogasification. In synthesis, coal or char is reacted
with steam and oxygen and produces the heat for a reaction that produces
a mixture of hydrogen and carbon monoxide. In pyrolysis, coal is heated
in a starved air atmosphere. In the process, some gas and liquids re-
sult, the major product being a coke residue. In hydrogasification,
coal, coke, or char is reacted with hydrogen to form methane.
Three combustible gases produced by coal gasification processes are
carbon monoxide (CO), methane (CH.) and hydrogen (H2). Methane, the
primary component of natural gas, is similar to natural gas in heating
value. Carbon monoxide and hydrogen heating values are approximately
equal, being about one-third the methane/natural gas value. Several
noncombustible gases are also produced, including carbon dioxide, hydro-
gen sulfide, and nitrogen (1).
Gas manufactured from coal was first produced in the eighteenth
century. More recently (i.e., last twenty years), a large number of gasi-
fiers have been proposed and a number built and tested. It is possible
to classify gasifiers by various means as indicated in references 1 and
2. These include: a) the method of contacting reactants, b) the gasify-
ing medium, and c) the means of supplying heat.
Deta i I
The U. S. Department of Energy has been actively supporting the de-
velopment of low, medium, and high-Btu gasification technology. Cur-
rently there are a number of commercially proven processes, a number of
process development programs, and efforts relating to in situ gasifica-
tion of coal. An overview of selected commercially available processes
and processes under development follows.
Fixed Bed Gasifier—Lurgi (1)
Only noncaking coals can be used in this process. As indicated in
Figure 16, pulverized coal is introduced into a pressurized reactor ves-
sel through a lock hopper. The coal passes downward and is distributed
onto a rotating grate. Steam and oxygen are introduced below the grate.
All coal is combusted, leaving only ash which is allowed to fall through
the grate. Product gas from the combustion zone above the grate leaves
the reactor at 800 to 1000°F. A single 12 foot diameter gasifier section
in a commercial plant would produce approximately 10 million scf/day.
Typical gasifier section outlet composition is approximately (3):
Gas Mo I. % (dry)
CH 10
H2 38
CO 24
CO 28
78
-------
Coal
Low Btu Raw
Synthetic Gases
(Medium if oxygen
Is used)
Dust and Tar
Air(or
Oxygen)
Ash
Figure 16
Lurgi Low-Btu Coal Gasification Process
Entrained Gasitier—Koppers-Totzek (1)
For this process, finely ground coal is mixed with oxygen and steam
and then pumped into an atmospheric-pressure vessel (see Figure 17).
Because of the low pressure used and the entrained flow of the material
injected, a complex system of hoppers is avoided. Combustion occurs at
high temperatures (about 3000 F) in the center of the reactor vessel and
the product gas exits upwards through a central vertical outlet. A typ-
ical large gasifier is about 10 feet in diameter and 25 feet long. A
single Kopper-Totzek reactor will produce about twice the gas of a Lurgi
reactor. Typical gasifier section outlet composition is approximately
(2, 3):
Gas
CO,
N2
Mol. % (dry)
36
56
6
2
79
-------
Coal
Quench, Heat
Recovery and
Gas Cleanup
Medium Btu Raw
Synthesis Gas
Gasi f ier
P=atmospheric
T=3000°F
T
Molten Slag
Figure 17
Koppers-Totzek Coal Gasification Process
U. S. Department of Energy Supported R&D Efforts
Westinghouse Coal Gasification Effort (4)
In this process, coal, is crushed to a topsize of 6 mesh, dried, and
transported to a reactor vessel for devolatiI ization and partial hydro-
gasification (see Figure 18). A central draft tube is used primarily for
recircuIating solids. Recycled solids required to dilute the feed coal
and temper the hot inlet gases flow downward in the fluid!zed bed sur-
rounding the draft tube. The fluidizing agent is a portion of the gases
entering the unit. Recirculating solids have flow rates up to 60 times
the coal feed rate to prevent the agglomeration of the feed coal as it
devoIatiIizes and passes through the plastic or sticky phase. Dense, dry
char collects in the fluidized bed at the top of the draft tube and is
withdrawn at this point. Dolomite or calcium oxide (sorbent) may be
added to the fluidized bed to absorb the sulfur present as hydrogen sul-
fide in the fuel gas. Spent sorbent could be withdrawn from the bottom
of the reactor and regenerated. Heat for devolatiIization is supplied
primarily by the high-temperature fuel gas produced in the gasifier-
combustor. After separation of fines and ash, product gas is cooled and
scrubbed with water for final purification.
80
-------
it CAS TO COAL
CAS TOCllANUf
CO
9 CYCLONI
^ _i— SEPARATOR
1 * r9
SOHttHT 1
HAKtUf 1
COAL
PREPARATION
1 DAKO COAL
.
1
SORBENT
RECENER
AT ION
t
;
AMO CAS
\ c
OEVOLATILI
ZER-
CAS __
CYCLONE
tEPARATC
«>*« _
i
FLUIOIZEO BED
»-
N.
V^
i
Mi
)
-X
1
t
JL 1
R Y /uw ro
1 OlifOSAL
CHAR
SEPARATOR
\
1
fines
r
^
COM8USTOP
\
\
Alt /*" ^
4MO
triAH
3OOff
J
/
r
L
c
-. COOLER
ASM ro
OlSfOSAl
T
TO
OlSfOSJU.
Figure 18
Westinghouse Electric Corp. Low-Btu Gasification of Coal Process
-------
Final gasification occurs in a fluidized bed gasifier combustor.
Char from the devolatiIizer is burned with air in the lower leg of the
gasifier at 1900-2000°F to provide the heat for gasification. Heat is
transported from the combustor to the gasification zone by combustion
gases flowing upward and by char circulating between the combustion and
gasification zones. Ash from combustion of fines agglomerates on the
ash from the char and segregates in the lower bed leg for removal.
Combustion Engineering Entrained Gasifier (4)
The Combustion Engineering gasification process is based on an air-
blown, atmospheric-pressure, entra i ned-bed gasifier. A schematic of the
process is provided in Figure 19. In the process, a portion of the pul-
verized coal and recycled char are fed to the combustion section of the
gasifier and burned to supply the heat necessary for the endothermic
gasification reaction. In the combustion section, nearly all of the ash
in the system is converted to molten slag, which is then drawn off the
bottom of the gasifier. The remainder of the pulverized coal is fed to
the reduction portion of the gasifier where it is contacted with hot
gases entering the reduction zone from the combustor. The gasification
process takes place in the entra inment portion of the reactor where the
coal is devo I at i I i zed and reacts with the hot gases to produce the de-
sired product gas. This 1700 F product gas is then cooled to 300 F. At
this point, the gas contains solid particles and hydrogen sulfide that
must be removed. Solids are removed and recycled by means of a spray
drier, cyclone separators, and venturi scrubbers. Hydrogen sulfide is
removed and elemental sulfur is produced by the Stretford process. The
clean low-Btu gas (about 120 Btu per standard cubic foot) can then be
delivered to the burners of power boilers, gas turbines, or combinations
of the two in a combined-cycle power generator.
Operating conditions will have a variety of effects on the cost and
quality of the gas produced in this system. For example, oxygen could be
substituted for air in the gasifier combustor, thereby increasing the
heating value of the product gas from 120 to 285 Btu per standard cubic
foot. Conversely, this change will also increase the cost of producing
the gas, depending on the price of oxygen and the quantity used.
Underground Gasification
A very substantial portion of our underground coal resources is not
expected to become economically recoverable by conventional mining meth-
ods in the foreseeable future. Underground coal conversion would permit
the recovery of some of this so-called unmineable coal by converting it
in place to a gaseous fuel that could be extracted, cleaned and possibly
upgraded prior to use.
82
-------
CO
GASIFIER
1600 F
I urn
SUPERHEATER
CAS
REDUCTOR
AIR
IOH OXYGfNI
£T
cL
1
CAS
CHA*
SLURHY
t
SPRAY
DRIER
\ /
\/
1
GAS .
1
1
VENTURI
SCRUBBER r
/SEPARATOR
i
ClMfl
S ^LIQUID
\
LIQUID
r
i_
THICKENER
t
AM) SOLIDS
'
SLURRY
Figure 19
Combustion Engineering, Inc. Low-Btu Gasification of Coal Process
-------
The concept of converting coal into fuel gas in the ground or "in
situ" is an old concept. The idea was first suggested by the British in
1868 and by the Russians in 1888. These two countries have conducted
the largest efforts to date. Underground gasification of coal has been
tested in the Soviet Union since the early 1930's. Major projects were
undertaken in the early 1950's and reached a peak in the late 1960's.
The Soviets now have three underground gas plants in operation. It
should be noted that only a very smaI I amount of the energy needs of
the U.S.S.R. are supplied by this technology (2, 5).
Large scale experiments were conducted by the British from 1949
to 1959. Following World War II, Belgium, Morocco, the United States
and Germany have committed resources to underground gasification pro-
grams (2, 5).
Coal is gasified underground by drilling boreholes in the seam and
injecting air (or oxygen) and steam into the underground reaction zones.
The hot gases are forced through the seam to the exit borehole and are
carried to the surface, where they are cleaned and upgraded for use (5).
There are a number of identified potential disadvantages associated
with underground coal gasification. These include (5):
e Possibility of being unreliable or uneconomical due
to uncertainties in underground conditions,
• Possible disruption of aquifers and pollution of
groundwater,
• Ground subsidence that could cause gas leakage or
damage to surface equipment, and
• Low-Btu gas (from air injection) is uneconomical to
transport over long distances; thus markets for this
gas must be near the plant site.
Changes in groundwater quality and the possible effects of subsi-
dence and ground movement introduced by the underground gasification
cavity represent significant environmental concerns associated with in
situ gasification process. Measurement by the Lawrence Livermore Lab-
oratory of gasification experiments indicate that the reaction products,
such as ash and some coal tars that remain underground following gasifi-
cation are a potential source of localized groundwater contamination.
The concentration of important contaminants, such as phenols, shows a
significant decrease due to absorption by the surrounding coal. There
is also concern relating to roof collapse connecting the gasification
cavity with overlying aquifers. It is quite conceivable that hydrogeo-
logical site selection criteria may be of considerable environmental
importance in choosing comme'rcia I-sea I e operations (6).
84
-------
In summary, there is substantial uncertainty as to the environmental
aspects of a large in situ coal gasification complex. The technology as
applied to domestic coal resources is still in the R&D stage. The poten-
tial, including associated economics, has not been adequately assessed.
As previously indicated, a number of gasification processes have or
are currently receiving R&D support from the Department of Energy. One
such process previously discussed is the Combustion Engineering Entrained
Gasifier. When air is used as the oxidant, the produced fuel gas is in
the low-Btu category and has the economic advantage of not requiring an
air separation plant. When an oxygen blown device is used the fuel gas
will be in the range considered as medium-Btu. Reference 7 contains pro-
jected heat balances for both a commercial scale air blown (low-Btu)
gasifier and an oxygen blown (medium-Btu) gasifier. An estimated heat
balance (based on reference 7) for an air blown gasifier is given in
Table 14. DiagrammaticaI Iy, this is illustrated by the heat flow dia-
gram, Figure 20. Table 15, also based on reference 7, provides a heat
balance for an oxygen blown gasifier. DiagrammaticaI Iy, this can be
illustrated by Figure 21. The heat balances are based on plants gasify-
ing 10,000 standard tons of .Illinois No. 6 coal a day. The Btu values
per standard cubic foot of gas as indicated by reference 4 are within 10
percent of the values indicated by reference 7-
5.3 AppI ications
Current
Currently, according to the U. S. DOE, there are several commercial
users of low-Btu gas and no medium-Btu commercial plants in the United
States. This is the case even though low/medium-Btu gasification of
coal can be considered an existing technology.
Projected
The significant utilization of low/medium-Btu gas derived from coal
basically depends on the overall economics (including environmental con-
trol) as compared to other options. In this regard, DOE is currently
providing support to industry and other potential users of low-Btu gas
in order to accumulate and analyze technical and economic data on oper-
ating systems, and to decrease the near-term consumption of natural gas
and fuel oil.
Six proposals were selected including four that would employ avail-
able fixed-bed gasifiers. EPA is supporting the environmental assess-
ment for each demonstration project in the overall DOE supported program.
In essence, the significant use of a low or medium-Btu gas derived
from coal is uncertain. We currently have the technical capability and
yet the current use is insignificant.
85
-------
Table 14
Estimated Heat Balance for Commercial Scale
Low-Btu Gasification Plant
Btu/hour Percent of Tota
(10 Btu's) Energy Input
System Output
Product gas heating value 6,919 67.86
Product gas sensible heat 817 8.01
Export power (at 3414 Btu/kwh) 382 3.75
System Losses
Product gas latent heat 243 2.38
Ash combustibles and sensible heat 85 0.83
Gasifier radiation loss 153 1.50
Sulfur product heating value 102 1.00
Steam turbine condenser (latent 965* 9.46
heat)
Isobutane condenser (latent heat) 80 0.79
Blower driver condenser (latent 201 1.97
heat)
Stretford miscellaneous (sensible 179 1.76
and latent heat)
Coal pulverizer 94 0.92
Sensible and latent heat capture (76) (0.74)
(blower a i r, etc.)
Other miscellaneous 52 0.51
Energy Input
Coal heating value 10,196 100.0
* Approximately 65$ of total associated with export power
Coal input - Illinois No. 6; 10,000 ST/day; 12,235 Btu/lb;
Sulfur 4.29$ (by wt.)
Gas Output - 113 Btu/scf heating value (not including sensible
heat)
86
-------
4.21?
Losses from ash, sulphur
product and latent heat
of gas
3.26?
Gasifier radiation loss and
Stretford misc. losses
0.69?
Losses via coal pulverizer,
misc., less heat recapture
8.01? '
Product gas
sensible heat
Energy input from coal
Product gas heating value
12.22?
Various.
condenser
losses
(latent heat)
3.75?
Export power*
(based on 3413 Btu/kwh)
75.87?
Product gas available heat
Figure 20
Heat Flow Diagram for Low-Btu Gasification Plant
* If export power is calulated on the basis of 9000 Btu/kwh (the energy
required to generate the equivalent output), the system efficiency is
85.75$S (vs. 19.62%} (i.e., for product gas heating and sensible heat
values plus electrical energy based on Btu's required to produce
equivalent electrical energy).
87
-------
Table 15
Estimated Heat Balance for Commercial Scale
Medium-Btu Gasification Plant
Btu/hour Percent of Total
(10 Btu's) Energy Input
System Output
Product gas heating value
Product gas sensible heat
System Losses
Product gas latent heat
Ash combustibles and sensible heat
Gasifier radiation loss
Sulfur product heating value
Steam turbine condenser (latent heat)
Compressor driver condenser (latent
heat)
Blower driver condenser (latent heat)
Air compressor intercooler (sensible
heat)
Air compressor aftercooler (sensible
heat)
Stretford miscellaneous (sensible
and latent heat)
Coal pulverizer (sensible and latent
heat)
Sensible and latent heat capture
(compressor suction air, etc.)
Other miscellaneous
Energy Input
Coa I heati ng va I ue
Electric power (at 3414 Btu/kwh)
Tota I I nput
8,020
185
139
85
153
102
70
800
42
213
189
179
94
(77)
36
10,196
34
10,230
78.40
1 .81
1 .36
0.83
1.49
1.00
0.68
7.82
0.41
2.08
1 .85
1.75
0.92
(0.75)
0.35
99.67
0.33
100.0
Coal Input - Illinois No. 6; 101,000 ST/day; 12,235 Btu/lb;
Sulfur 4.29$ (by wt.)
Gas Output - 312 Btu/scf heating value (.not including sensible
heat)
-------
100? Heat input-
(99.61% from coal, 0.33 electrical*)
Losses from ash,
sulfur product and
latent heat of gas
3.24? d
Gasi f ier rad i at ion
loss and Stretford
misc. losses
0.52?
Losses via coal
puIveri zer, mi sc.,
less heat recapture
78.40?_
Product gas heating value
8.91?
Various condenser
losses (latent
heat)
3.93?
Product gas
sensible heat
1.81?
Product gas
sensible heat
80.21?
Product gas available heat
Figure 21
Heat Flow Diagram for Medium-Btu Gasification Plant
Electrical input based on 3413 Btu/kwh
89
-------
5.4 Environmental Considerations
Identified Pollutants
This discussion does not cover coal extraction and transportation.
Reference 2 indicates that the data base for evaluating environmental,
health and safety aspects is very limited and reported information is
frequently contradictory. This same reference also indicates that ad-
verse health effects expected are particularly difficult to estimate
because operational experience is so limited. The provided material,
based mainly on analyses and very limited actual data, are derived from
the indicated referenced sources.
Air Emissions
The type and sources of potential air pollutants from coal conver-
sion are as follows (8):
Pol Iutant Process-Generated Combustion-Generated
Particulate matter X X
SuI fur oxides X X
Reduced sulfur X
compounds
Nitrogen oxides X
Hydrocarbons X X
Carbon monoxide X X
Trace metaIs X X
Odors X
Other gases (includ- X
ing NH3, HCN, HCI)
Sulfur dioxide is emitted principally from the tailgas stream of the
sulfur recovery plant and from stack gases of auxiliary systems requiring
fuel oxidation. These include plant boilerhouse and miscellaneous fossil
fuel fired process heaters.
Particulate matter can be released as a fugitive dust and as a pro-
cess or combustion-based stack emission. Fugitive emissions have a poten-
tial for occurring at receiving, handling, and storage areas for coal,
solid waste, and from leakage from process equipment elements. Process
stack emissions would include the exhaust of pollution control equipment
(e.g. scrubbers and precipitators). Fuel combustion would provide the
potential source of particulate matter.
Nitrogen oxide emissions would result from fossil fuel firing of
boilers. Hydrocarbon emissions could occur from liquid storage areas,
90
-------
system leaks, and from the evaporation of hydrocarbon liquids dissolved
in cooling systems. Reduced sulfur compounds occur in the initial pro-
duct stream of virtually all coal conversion processes.
Trace element emissions of such substances as mercury, beryllium,
arsenic, and other heavy metals which are contained in coal in small
amounts are expected in view of experience from coal fired boilers. In
addition, other gaseous emissions, especially hydrogen cyanide and ammo-
nia (as well as hydrogen chloride and gaseous odorants) may also be
associated with coal conversion plants.
Liquid Effluents
Waste waters from coal conversion processes can originate from a
number of sources. These include water of constitution, water added for
stoichiometric process requirements, and water induced for gas scrubbing
and by-product recovery. Such process waters come into contact with con-
taminants in coal and are likely to be a principal source of potential
poI Iution.
There are potential sources of water effluents from boiler blowdown,
the raw gas cooling system, and overfill of water clarifiers. It is
expected that blowdown and raw gas cooling waters will be recycled via
a clarifier and filter system for reuse. It has been estimated (i.e.,
for the Koppecs-Totzek process) that 1.3 million gallons will be produced
for every 10 Btu's of coal input to the gasifiers. In addition, the
clarifiers will require 80 gallons per minute in makeup water because of
evaporation losses in quenching the ash from the gasifier (1).
Sol i d Wastes
The solid waste generated by low-Btu gasification ranges from 3,500
to 8,500 tons for each 10 Btu's of coal input. The value is dependent
on the heat and ash values of the coal. If the sulfur recovered in the
process cannot be sold, it also will require disposal. The solid waste
from the gasifier will resemble waste from coal cleaning and boiler plant
operations. This waste (from a gasifier) contains small quantities of
radioactive isotopes. Analyses for an agglomerating gasifier provided
estimated levels of 0.00076 curie of radium-226?and 0.0128 curie of
radium-228 and thorium-228 and 230 for each 10 Btu coal input to the
gasi f i ers (1).
Regulatory Impacts
The environmental aspects of gasification are, to an extent, site
specific. Reference 2 indicates that potential air pollutants are similar
-------
in nature to those of a power plant and generally the same pollution con-
trol applies. Waste water pollution control would have to be tailored
to the specific gasification process. Disposal of solids would have to
take into account the potential for leaching and special treatment may
be required prior to burial.
Currently, there is a substantial body of legislation that directly
relates to the gasification of coal. There are Federal and state emis-
sion standards covering air, water and solid waste. There exists legis-
lation and regulations covering toxic substances, safe drinking water,
occupational health and safety, protection of fish and wildlife and
others. Any viable conversion technology would necessarily have to be
consistent with the substantial body of environmental, health and safety
legislation and regulations in being.
5.5 Performance
Current
In the March 15, 1979, issue of the Commerce Business Daily, the
U. S. Department of Energy stated as part of a procurement statement:
"Processes for producing environmentally acceptable gas from coal are
available commercially. Although there are numerous low and medium-Btu
gasification plants operating overseas, there are only two commercial
users of low-Btu coal gas and no medium-Btu commercial plants in this
country today. Uncertainty of costs, operating reliability and retrofit
impacts; effect of gas on product quality and plant processes; plant
siting and environmental factors; gas distribution costs and safety;
regulatory impacts; coal supply and transportation; capitaI/financing
arrangements, etc., are considerations which a potential owner/user must
weigh when seriously considering the use of low and/or medium-Btu coal
gas as an alternative fuel option. The lack of commercial operating
experience in this country from which answers to many of those questions
can be readily obtained, in combination with the availability of cheaper
fuels today, removes any strong motivation by industry to assess in-depth
the utilization of low and medium-Btu gas from coal."
In essence, the technology exists and is proven. However, there is
little domestic operating experience to go on. In addition, it should
be noted that there appears to be a very limited number of situations
where use of a low or medium-Btu gas obtained from coal would be more
attractive than the direct use of coal. This has been somewhat indicated
by conversion assessments of industrial boiler plants and industrial
operations and the low demand for gasification facilities.
The conversion efficiency as based on total energy input is somewhat
process and site specific and is estimated to be in the 70 to 80 percent
range including raw gas cleanup. The value without gas cleanup (i.e.,
92
-------
raw hot gas output) is estimated to be as high as 90+ percent when the
sensible heat of the gas is included (2, 9),
Projected
This process, for all practical purposes, is a developed technology.
Projected performance is not expected to improve significantly over pre-
sent capabilities during the foreseeable future.
5.6 Economics
Current
We do not have an operating history to go on. Estimates of the cost
of low/medium Btu gas depend on many factors including utility or private
financing, coal cost, effluent disposal requirements, etc. Current esti-
mates for low Btu gas range between $2.50 and $4.00 per million Btu (9).
Medium Btu gas is estimated to range between $5.00 and $8.00 per million
Btu. The range in price depends on many changing factors including raw
coal cost, processing conditions, and pollution control requirements (9).
Projected
The projected price in terms of current dollars is expected to re-
main fairly stable. However, large escalation in the cost of coal could
upset this expectation.
93
-------
References - Low/Medium-Btu Gasification
1. University of Oklahoma. Energy Alternatives: A Comparative
Analysis. The Science and Public Policy Program, University of
Oklahoma, Norman, Oklahoma, May 1975.
2. Advances in Energy Systems and Technology, Volume 1. Academic
Press, Inc., 1978.
3. Neben, E. W., and Pack, G. E. Screening of SNG Alternatives.
In: Fourth Annual International Conference on Coal Gasification,
Liquefaction and Conversion to Electricity. University of Pitts-
burgh School of Engineering, August 2-4, 1977.
4. U.S. Department of Energy. Coal Gasification, Quarterly Report,
January-March 1978. Division of Coal Conversion, DOE/ET-0067-1,
Washington, D.C., September 1978.
5. Energy Research and Development Adminstration. Underground Coal
Gasification Program. Division of Oil, Gas and Shale Technology,
ERDA 77-51, Washington, D.C., March 1977.
6. Mead, S. W., Wang, F. T., and Ganow, H. C. Control Aspects of
Underground Coal Gasification: ILL Investigations of Groundwater
and Subsidence Effects. For: DOE Environmental Control Sympo-
sium, Washington, D.C., UCRL-81887. Lawrence Livermore Labora-
tory, November 10, 1978.
7. Kimmel, S., Neben, E. W., and Pack, G. E. Economics of Current
and Advanced Gasification Processes for Fuel Gas Production.
Fluor Engineers and Constructors, Inc., for EPRI, Los Angeles,
California, July 1976.
8. Rubin, E. S., and McMichael, F. C. Some Implications of Envi-
ronmental Regulatory Activities on Coal Conversion Processes.
In: Symposium Proceedings: Environmental Aspects of Fuel Con-
version Technology. Prepared for the U.S. EPA, Office of
Research and Development, Washington, D.C., May 1974.
9. Personal communications with the U.S. Environmental Protection
Agency, July 1980.
94
-------
6. Chemically Active Fluid Bed (CAFB)
6.1 Overview
The Chemically Active Fluid Bed (CAFB) process uses a shallow fluid-
ized bed of lime or lime-like material to produce a clean, hot gaseous
fuel from high sulfur feedstock (e.g., residual oil). A solid fuel feed-
stock such as coal is also feasible.
In applying the process to residual oil, oil is fed to a reactor
that contains a fluidized bed of fine particles of limestone. The oil
is vaporized in the reactor through a series of catalytic cracking and
oxidation reactions. Sulfur values are released from the vaporized oil
to be absorbed by the lime in the boiling limestone. The remaining hot,
low-Btu, low sulfur fuel gas produced in the process is available for
combustion (e.g., in a steam boiler).
The CAFB reactor contains two sections, one for gasification of the
oil and one for regeneration of the limestone sorbent. In the regener-
ation step, sulfur dioxide is released from the limestone and is avail-
able for converting to elemental sulfur.
The initial CAFB pilot unit (2.39 MW) was developed by the Esso
Research Centre in Abingdon, England. A 10 MW demonstration plant was
subsequently constructed by Foster Wheeler at the La Raima Power Station
(Central Power and Light Company) in San Benito, Texas.
Environmental data is very limited. Principal environmental concerns
relate to the size of the particles in the product gas stream, the vana-
dium (bound in a mixture of oxides) emission level, and the disposal of
spent, sulfided limestone. The solid waste disposal problem appears to
be the major environmental concern.
Since all activities are R&D, no actual full-scale performance data
is available. Even so, the total gasification efficiency is estimated
to be approximately 85 percent. Similarly, economic values are also pro-
jections. EPA estimates that a retrofit CAFB plant to fuel a 500 MWe
plant would cost $172 per kW of installed capacity (1977 dollars). The
operating cost is estimated at 2 - 3 mills per kwh.
6.2 Process Description
Concept
The Chemically Active Fluid Bed (CAFB) process uses a shallow fluid-
ized bed of lime or lime-like material to produce a clean, hot gaseous
fuel from heavy high sulfur feedstocks, such as residual oils or refinery
bottoms. Solid fuels, such as Texas lignite, have also been tested. The
95
-------
CAFB performs three operations simultaneously: (1) gasification and/or
cracking of the feedstock; (2) removal of sulfur; and (3) partial removal
of vanadium and other metals. The sulfur, vanadium and other metals are
captured by the chemically active fluid bed. The CAFB has operated at
temperatures in the range of 870-920°C for that portion of the bed receiv-
ing the feedstock. This portion is commonly called the gasifier. The
necessary heat release to maintain this temperature in this portion of
the bed, or gasifier, is accomplished by partial combustion of the feed-
stock. Flue gas recycle has been used to control the bed temperature.
The amount of air to the CAFB is about 20 percent of that required for
complete combustion of the feedstock, and is varied from this percentage
to match the attributes of the feedstock to the capabilities of the pro-
cess (1 ).
As the feedstock is gasified, the sulfur is captured by the CAFB as
calcium sulfide, because the reaction occurs in an oxygen deficient or
reducing atmosphere. The bed material is then moved, via fluidization
technique, to a regenerator section of the reaction vessel. In current
practice, this regenerator section is separated from the gasifier portion
by a refractory divider and has a separate plenum or air passage to sup-
ply air for the regeneration reaction. The regeneration reaction is
accomplished by passing air through the fluid bed. The calcium sulfide
in the bed is oxidized to sulfur dioxide and calcium oxide. A minor
amount of calcium sulfate is also produced during the regeneration step.
The heat required to sustain the regeneration reaction at about 1050 C
is produced by the oxidation of the calcium sulfide, externally supplied
coal, and from the oxidation of carbon deposited on the surface of the
bed material. The gaseous stream from the regenerator contains 6 to 10
percent by volume of sulfur dioxide with 1 to 4 percent carbon dioxide
and virtually no oxygen. This gas stream can be converted to either
elemental su fur or other products using existing technology (1).
The regenerated bed material is returned, via fIuidized techniques,
to the gasifier portion of the vessel and the cycle is repeated.
The c ean, hot product low-Btu gas for the gasifier is ducted,
through cyclones, to a boiler and burned in the normal manner, using
burners designed specifically for the hot, low heating value product
gas (1 ) .
The process, as developed under U.S. Environmental Protection Agency
sponsorship, operates at atmospheric pressure. Pressure differentials
throughout the system are required to induce fuel and materials flow and
are on the order of those found in conventional boiler installations (1).
Deta i I
The initial CAFB unit, a 2.39 MW pilot plant, was constructed at the
Esso Research Centre, Abingdon, England facility. A 10 MW demonstration
96
-------
plant was subsequently constructed
ation (FWEC) at the La Raima Power
Light Company in San Benito, Texas
by the Foster Wheeler Energy Corpor-
Station of the Central Power and
(2).
Figure 22 is a generalized schematic diagram of the CAFB showing
principal unit operations and material flows. Limestone and oil are fed
continuously into the gasifier at a Ca ( I imestone)/S (oil) molar ratio
of unity. Limestone (CaCO,) is rapidly converted to lime (CaO) and C0~
and the lime is maintained in a fluidized state by a preheated air/flue
gas mixture. The air input rate is equal to roughly 20 percent of
stoich iometric with respect to oil. Fuel oil is consecutively vaporized,
oxidized, cracked and reduced at 870°C (1600 F) to produce a low-Btu gas.
Over 80 percent of the input feed sulfur is removed by the lime. The
gas travels from the gasifier through cyclones for particulate removal
and then into a boiler for combustion. Lime is continuously cycled be-
tween the gasifier and the generator where the lime which is sulfided in
the gasifier is oxidized to CaO. Approximately 7 percent of the input
limestone as CaO is reduced to CaS on each pass through the gasifier.
Su I f uc d ioxi de produced in the regenerator is fed to a Foster Wheeler
RESOX unit where it is processed into elemental sulfur (2).
Sulfur
Spent Limestone
Figure 22
Generalized Schematic of the CAFB
97
-------
The heat balance for a coal-fed CAFB plant nominally sized to fuel
a 500 MWe steam-electric plant has been estimated based on data obtained
from the existing pilot and demonstration plants. The provided heat
balance information, Table 16, is based on a projected mass balance and
related heat balance assessment obtained from reference 3. The heat
balance is shown diagrammaticaI Iy by Figure 23. It should be noted that
Table 16 (and Figure 23) are projections for a commercial scale plant
using Illinois No. 6 coal.
Table 16
Estimated Heat Balance for Coal Fed Commercial Scale CAFB Plant
Btu/hour
(10 Btu)
Percent of TotaI
Energy Input
,55
,94
System Output
Product gas heating value 4,364.15 75.17
Product gas sensible heat 690.85 11.90
System Losses
Product gas latent heat 90.00
Gasifier radiation loss 112.36
RESOX associated radiation loss 4.67
Gas ifier/regenerator sensible heat 35.09
of ash and reacted Iimestone
Ash combustibles 56.00
Sulfur product heating value 78.23
Various latent heat, sensible heat 374.06
and radiation losses (RESOX
associated condensers, blowers,
coo Iers, etc. )
Energy Input
0.08
0.60
0.97
1 .35
6.44
Coa I heati ng va I ue
Activated coal, coke and anthra-
cite to RESOX unit
Electric power (at 3414 Btu/kwh)
Total Input
5,617.78
146.67
40.96
5,805.41
96.77
2.53
0.70
100.0
Nominally sized to fuel 500 MWe conventional steam electric plant
Coal input - Illinois No. 6; 520,743 pounds/hour; 10,788 Btu/lb;
ash 9.6/o, sulfur 3.9$ (by wt. )
TM
Note: RESOX is a trademark
98
-------
1.55? 1
Product gas latent heat
,_ Heat Input 100?
(Bituminous coal 96.77?, anthracite
2.53?, electric power 0.70?)
2.02? 4=
Gasi fier and RESOX
associated radiation
losses
75.17? .
Gas heating value
1 2.92?
Ash and spent
limestone associated
losses
6.44?
Various latent,
sensible, and radiation
heat losses
I I.90?
Gas sensible heat
87.07?
Product gas available heat
Figure 23
Estimated Heat Flow Diagram for Coal Fed CAFB Plant
6.3 AppIications
Current
Currently, there is not a single commercial CAFB anywhere in the
world. All current and past activities are in the research, development
and demonstration categories. The CAFB has operated successfully on oil.
In the Fall of 1980, the CAFB system will be operated for 2 to 3 months
on coal. This demonstration effort will cover Texas lignite to further
demonstrate the technology and to provide addi.ional data for environ-
mental assessments.
99
-------
Projected
Many utilities are required to burn only low sulfur fuel in order to
meet Federal and State emissions regulations. This means that large sup-
plies of heavy residual oils remain untapped as sources of fuel for power
plants. In the face of the growing shortage of domestic oil supplies, it
is important that maximum use be made of all grades of petroleum. By
efficiently converting high sulfur residual oil to clean gaseous fuel,
the CAFB process potentially offers an environmentally sound means of
freeing this resource for the production of energy (4).
The process has particular importance as a retrofit mechanism for
the numerous gas-fired power plant boilers in the southwest. The major-
ity of these boilers cannot be converted to the use of oiI or coal.
Natural gas for these boilers is expected to be in short supply in a few
years. These boilers are in power plants that currently produce approx-
imately 120,000 megawatts of power. Use of the CAFB process could per-
mit this level of energy production to be maintained throughout the
useful life of these boilers (4).
In addition, the CAFB process offers a technological advantage over
other methods of contaminant removal by avoiding the necessity of cool-
ing and scrubbing the gas. These methods lower the heating value of the
product gas and the efficiency of the gasification process (4).
However, it should be noted that potential use of CAFB technology
would depend on:
1) The need to find an alternate for natural gas firing for
boilers that cannot be converted to an alternate fuel
(e.g., fuel oil),
2) The ability to handle in an environmentally acceptable
fashion the solid waste and possible trace element air
effluents, and
3) The applicability of the CAFB as compared to other fuel
supplying alternatives.
6.4 Environmental Considerations
Data applicable for environmental assessments of the overall gasi-
fication process is very limited. Any environmental assessment must
accordingly be recognized as estimates until data from commercial scale
system(s) becomes available.
It should be emphasized that a CAFB is not for consuming fuel but
for converting fuel from one form to another. Therefore, the overall
effluents should be small as compared to a fuel consuming unit (e.g.,
coal-fired boiler) of the same fuel input level.
I 00
-------
The following was obtained from reference 2 and is based on the EPA
supported Esso pilot unit and an assessment of a proposed 250 MW demon-
stration faci I ity.
Air Emissions
Fugitive air emissions were identified as resulting from the storage
and handling of oil, limestone and coal, the latter material being used
in the FW's RESOX process to reduce sulfur dioxide emanating from the
regenerator to elemental sulfur, and from cooling tower discharges. One
of the two fuels used at the pilot plant, bitumen, was found possibly to
contain polycyclic organic matter (POM); thus emissions from storage of
this material, as well as from other oil feeds, must be investigated fur-
ther. Cooling tower drift losses would also occur.
Sampling and analysis programs were carried out at the pilot plant
operation to quantify stack emissions. Samples were collected during
seven separate runs: four fuel oil gasification runs, two bitumen gasi-
fication runs and one combustion/startup bitumen run. The field measure-
ment program entailed on-site quantification of S0?, SO,, NO , hLS, total
particulate and particulate size distributions. In addition, vapor and
particulate samples were collected for subsequent chemical analyses.
Sulfur dioxide emission rates for fuel oil gasification averaged 0.63 Ib/
10 Btu. Bitumen gasification under conditions of saturated gasifier
bed stone (caused by clogging in the gasifier-regenerator stone transfer
duct) resulted in an S0? emission rate of,1.6 lb/10 Btu. Sulfur tri-
oxide emission rates averaged 0.023 lb/10 Btu for these same three runs.
Total nitrogen oxide emissions ranged from 0.067 to 0.085 lb/10 Btu. No
significant hLS was detected in,any run. Total particulate emissions
ranged from 0.063 to 0.10 lb/10 Btu for normal gasification. During
fresh stone feed, this rate increased to 0.19 lb/10 Btu due to attrition
of fresh particles. Particulate size distribution measurements made
under gasification conditions for both fuel oil and bitumen feeds indi-
cated roughly one-third of the escaping stack particulate is in the res-
pirable size range.
Laboratory analysis of stack particulate employing spark source mass
spectrometry (SSMS), atomic absorption spectroscopy (AA) and electron
spectroscopy for chemical analysis (ESCA) demonstrated that vanadium,
which is bound in a mixture of oxides, is emitted at a rate of almost 90
percent of the EPA established critical value. No other trace element
emissions were found to be of concern. Both particulate and gaseous
stack samples were also analyzed for organic functional groups by the
procedure outlined by the EPA Level 1 protocol. Flue gas analysis re-
sults indicated that emissions of hydrocarbons, quinone and carbonyl
compounds are potentially of concern.
101
-------
Liquid Effluents
Identified liquid effluents are similar to those found in conven-
tional combustion systems. Potential discharges to ambient water could
come from coal pile runoff, cooling tower blowdown and boiler blowdown.
Sol id Waste
The principal identified solid waste environmental concern would be
associated with the disposal of spent, sulfided limestone. Spent stone
from a CAFB cannot be disposed of as a solid landfill in an environment-
ally acceptable manner without treatment. The stone of from 3 to 5
percent CaS would react with moisture in the air to liberate hLS. The
H9S would be oxidized in the atmosphere to SCL. This S02 would be in
addition to the S0? emissions from a CAFB unit. It has Been estimated
that for a typical feedstock that if 90 percent of the fuel sulfur is
retained in the CAFB bed and 70 percent of the waste sulfide is con-
verted to sulfate, then the total emissions from the CAFB and the spent
stone disposal pile would exceed the current Federal SO- emission
standard. Clearly, the waste stone would have to be treated to remove
the sulfide or render it inert.
6.5 Performance
Current
Currently, there is not a single operational CAFB anywhere in the
world. Even so, based on data obtained from the Esso pilot plant,
assessments of anticipated performance have been addressed.
The Esso pilot plant had trials with petroleum, pitch, coal, and
lignite feedstock. Test results indicated that these feedstocks were
usable for the CAFB process. As previously indicated, the pilot plant
provided significant reductions in SO , NO as well as reductions in the
emission of vanadium and other metalsx(5).x
There is very limited information on the expected overall energy
efficiency of a CAFB facility. Reference 3 indicates that readily ident-
ified energy losses associated with the overall system add to an expected
loss value of 13 percent of the feedstock input energy. This loss value
does not include the sensible heat component of the product gas. It is
assumed that the sensible heat would be utilized (see Figure 23).
Projected
According to reference 6, the fuel conversion efficiency limit for
the fluid bed portion of a CAFB system is 89 percent. This same refer-
ence projects an 81 percent efficiency value by 1990 (i.e., for the
102
-------
fluid bed portion of the overall CAFB system). In contrast, as previ-
ously indicated, reference 3 indicates a projected overall system
efficiency value of 87 percent. In essence, there is some uncertainty
as to the obtainable efficiency of a commercial scale CAFB system.
6.6 Economics
Current
We do not have an operating history to go on. All current activi-
ties must be classified as R&D.
Projected
As with any developing or new technology, the cost to process a
MBtu is, at best, an estimate. EPA estimates a retrofit CAFB plant to
fuel a 500 MWe plant at $172 per kW installed capacity (in 1977 dollars).
The operating cost was estimated at 2 - 3 mills per kwh of gaseous energy
feed (5).
103
-------
References - Chemically Active Fluid Bed (CAFB)
1. Rakes, S. L. Capstone Review of the EPA Chemically Active Fluid
Bed Program. Energie Spectrum (Netherlands), May 1978.
2. Werner, A. S., Young, C. W., Bornstein, M. I., Bradway, R. M.,
Mills, M. T., and Durocher, D. F. Preliminary Environmental
Assessment of the CAFB. For: U.S. Environmental Protection
Agency, Office of Research and Development, EPA-600/7-76-017,
Washington, D.C., October 1976.
3. Personal communications with Foster Wheeler Energy Corporation.
4. U.S. Environmental Protection Agency. Advanced Fossil Fuels
and the Environment - Decision Series. Office of Research and
Development, EPA-600/9-77-013, Washington, D.C., June 1977.
5. Based on unpublished interoffice memorandum on CAFB/Combustion
Engineering Gasifier Comparison in the U.S. Environmental
Protection Agency, 1979.
6. Monsanto Research Corporation. Efficiencies in Power Gener-
ation. For: U.S. Environmental Protection Agency, PB-234 160,
March 1974.
104
-------
7. Indirect Coal Liquefaction
7.1 Overview
Coal liquefaction is an emerging coal conversion alternative that
holds promise for near-term commercialization allowing greater utiliza-
tion of the nation's coal reserves. The liquid products vary with the
type of process and the rank of the coal that is utilized.
Coal liquefaction processes can be classified into four types -
direct hydrogenation, solvent extraction, pyrolysis, and indirect lique-
faction. In direct hydrogenation, hydrogren is added cataIyticaI Iy to
coal in a reactor under high pressure and temperature resulting in vapor
and liquid phases which are cooled to separate the products, refined to
remove by-products and, depending on the fuel product desired, further
processed. In solvent extraction, a solvent is used as a hydrogen carry-
ing agent to promote liquefaction under high temperature and pressure to
produce the liquid fuels, after purification. In pyrolysis, crushed coal,
thermally decomposed in the absence of oxygen, yields solids (char),
liquids, and gases. In indirect liquefaction, the coal is first gasified
to make a synthesis gas and then passed over a catalyst to produce alco-
hols (methanol) or paraffinic hydrocarbons.
Research and development of coal liquefaction processes has been
underway for many years. The first practical uses of coal-derived liquid
fuels were about 1790 when they were used for experimental lighting,
heating, and cooking. During World War II, Germany produced liquid fuels
from coal in industrial amounts via both direct and indirect liquefaction.
Since then, coal liquefaction plants have been constructed in a number of
countries but only one plant in Sasol, South Africa, is still producing
liquids from coal (via indirect liquefaction). A second plant, SASOL II,
has recently begun operation. Commercial demonstration of coal lique-
faction has never been accomplished in the United States; current U. S.
activities has been limited to research and development and pilot plant
programs.
A particular advantage of indirect liquefaction is that essentially
all of the sulfur and nitrogen present in the coal can be separated in
the gaseous phase and thus eliminated from the liquid products. These
materials are difficult and expensive to remove to a very low concentra-
tion with direct processes.
The two indirect liquefaction processes receiving significant atten-
tion are the Fischer-Tropsch and the Mobil M (methanol). A modification
of the Fischer-Tropsch process is in commercial use in South Africa. A
range of hydrocarbon products are obtainable with this process. The
Mobil process is in the development stage. The principal product of this
process is gasoline.
105
-------
Environmental problems common to fossil energy facilities will also
apply to coal liquefaction facilities. Liquefaction facilities do pre-
sent some unique problems due to incomplete combustion resulting in a
wide variety of organic compounds, reducing conditions resulting in H^S
and other reduced sulfur compounds and catalytic processes producing
spent catalyst with associated environmental concerns. These problems
are generally common to all liquefaction processes. Since no large scale
plants are in operation in the U.S., the only available data on emissions
and effluents are estimated from pilot plant operations and cannot be
quantified for a commercial operation.
Projected thermal efficiencies for indirect coal plants (i.e.,
Fischer-Tropsch and Mobil) producing pipeline quality synthetic natural
gas (SNG) and gasoline and/or diesel fuel are in the 50-60 percent range;
the Mobil process being the more efficient. Liquid fuels from indirect
liquefaction plants are projected as being more costly than from direct
processes. The estimated cost, depending on process in terms of 1980
dollars, is estimated to vary between $7 - 10 per million Btu. This is
based on plant coal cost at $1 per million Btu.
Although there remain unanswered questions relating to coal lique-
faction (e.g., commercial demonstration, environmental impacts, costs),
the successful development of a technology would provide a valuable
energy alternative and allow greater utilization of our nation's coal
reserves. Additionally, liquid fuels are generally easier to store,
transport, and utilize than solid fuels, and during liquefaction, im-
purities (e.g., sulfur) can be removed making it possible to produce an
environmentally acceptable liquid fuel from various ranks of coal.
7.2 Process Description
Concept
The basic objective of coal liquefaction is to convert coal to
liquid fuels with minimal production of gases, liquids, and organic
solid residues. AM ranks of coal can be liquefied although some are
more attractive than others. The liquid products vary both with the
type of coal used and the particular process applied.
There are several methods for producing a liquid fuel from coal. As
with gasification, either hydrogen has to be added or carbon removed from
the compounds in the coal. In bituminous coal, for example, the carbon-
to-hydrogen ratio by weight is about 16 to 1; in fuel oil the ratio is
about 6 to 1. Although liquefaction is a complex process, it can be
viewed as a change in the carbon-to-hydrogen ratio that can be accom-
plished by one of several processes (e.g., indirect liquefaction). The
chemical structure of the coal influences the type of chemical reactions
that will take place during liquefaction. This structure varies with
rank of coal (1).
106
-------
Detai I
Coal liquefaction processes can be grouped into four distinct cate-
gories (2, 3, 4):
• Direct hydrogenation (e.g., H-CoaI )
» Solvent extraction (e.g., Solvent Refined Coal)
* Pyrolysis (e.g., Clean Coke)
• Indirect liquefaction (e.g., Fischer-Tropsch)
In direct hydrogenation, hydrogen is added cataIyticaI Iy to coal
in a reactor under high pressure and temperature resulting in vapor and
liquid phases which are cooled to separate the products, refined to re-
move by-products and, depending on the fuel product desired, further
processed. The process conditions (temperature, pressure, and amount
of hydrogen added) determine the fuel produced. Processes and products
in this category include:
» H-CoaI produces boiler fuel or synthetic crude
• SynthoiI produces synthetic crude or fuel oil
The solvent extraction process liquefies coal through indirect
transfer of hydrogen to the coal using a process-derived solvent and a
hydrogen atmosphere. Processes and products in this category include:
» Solvent Refined Coal produces boiIer fuel or
low-sulfur solid fuel
• CQ-Steam produces fuel oi I
« Donor Solvent produces liquid and gas products
In pyrolysis, crushed coal, thermally decomposed in the absence of
oxygen, yields solids (char), liquids, and gases. These products, via
the same action, have been produced from coal for well over 100 years
as the by-product of coking operations. Processes and products in this
category i ncIude:
» Hydrocarbon i zation produces fuel oiI
« Clean Coke produces coke and I iquid fuels
« Flash Pyrolysis produces fuel oil, coke, gas
107
-------
Indirect liquefaction involves the initial gasification (see Sec-
tion 5, Low/Medium-Btu Gasification) of coal to produce a mixture of CO
and H? (synthesis gas), which is purified and converted to liquid fuels
by reaction over appropriate catalysts to produce alcohols (methanol) or
paraffinic hydrocarbons (3, 4). A particular advantage of indirect
liquefaction is that essentially all of the sulfur and nitrogen present
in the coal can be separated in the gaseous phase and thus eliminated
from the liquid products (5). These materials are often difficult and
expensive to remove to a very low concentration with direct processes
(5). A major environmental difference between direct and indirect lique-
faction is that direct processes produce a significant amount of poten-
tial ly carcinogenic aromatic organic compounds. The indirect category
processes and products include:
• MobiI Process produces gasol ine
• Fischer-Tropsch produces liquid fuels and
chemical products.
The Fisher-Tropsch process is significant in that it is the only
large commercial coal liquefaction plant in operation. (It is located in
Sasol, South Africa.) Discussions on the above two indirect liquefaction
processes foI low:
Mobil Methanol Technology (1, 6, 7)
The Mobil Oil Corporation is developing an improved process for pro-
duction of motor fuels by indirect liquefaction. The product gasoline
has a high octane rating and is free of heavy ends so that product up-
grading is not necessary.
The Mobil process involves the conversion of methanol to gasoline.
When starting with coal, coal is first converted to a synthetic gas with
subsequent conversion to methanol by proven commercial technology. The
methanol is then converted to gasoline by means of the Mobil process.
Figure 24 indicates the basic concept.
The Mobil process is claimed to be about 92 percent energy effi-
cient. The process does not appear to have any materiaI-of-construction
problems and is said to be essentially free of undesirable by-products.
Solid-liquid separation problems are avoided as the coal feed is gasified
The amount of durene, a gum forming material, formed by this process con-
ceivably could be a disadvantage. In high concentration above 5 to 6
percent, it can cause drivability problems. It has a high octance and
is a desirable constituent if the concentration can be kept down. Mobil
claims knowledge to date indicates they can control the durene content
to less than 4 percent, a value within desired limits.
108
-------
Coal ->.
Oxygen -».
Steam ^
Coal
Gas i f i er
|
Synthesi s
Gas __
1
Methanol
Process
Methano 1
Mobi 1
Process
U/^ + ^r-
Gasol i ne
Methane
Figure 24
Synthesized Gasoline From Coal
In the overall Mobil indirect liquefaction process (Figure 25),
synthetic gas is produced from coal via any of the existing medium-Btu
coal gasification processes (e.g., Lurgi, Koppers-Totzek, Texaco). When
the synthesis gas is shift converted to the proper carbon-to-hydrogen
ratio, methanol becomes an alternative product from any process than can
produce high-Btu gas. In practice, the synthesis gas is converted to
methanol by any of a number of proven processes (e.g., the low pressure
ICI methanol process). The yield of methanol is maximized by a combin-
ation of optimum reactor conditions and catalyst and the recycle of
unreacted gases. High catalyst selectivity limits the production of
ethers, ketones, and higher alcohols. Carbon dioxide is removed prior
to converting the synthesis gas to methanol thereby qualifying the
product as a feed for the Mobil process.
The Mobil process converts methanol into a high-octane gasoline by
dehydration over a shape selective zeolite catalyst. The secret of the
process is really the catalyst, a unique zeolite identified a few years
ago. Mobil's initial developmental efforts are directed at the fixed-
bed reactor configuration. Even so, considerations are also being given
to tubular and fluid-bed catalytic reactor units.
In the process, methanol is blended with water and charged as a
vapor into the reactor. The product is separated from the catalyst,
filtered and condensed and the water is separated from the hydrocarbon
components. The principal output components are premium gasoline
(approximately 90% of Btu output) and LPG (approximately 10/6 of Btu
output).
109
-------
o
COAL
GASIFICATION
LJ
ICIOR
OTHER
METHANOL
PROCESS
• WATER
FEED PREPARATION
LIQUID FEED
VAPOR FEED
LIQUID
HYDROCARBONS
Figure 25
Mobil Cataly-tic Process
-------
Fischer-Tropsch Technology (5, 6, 7)
The Fischer-Tropsch (F-T) indirect liquefaction process is based
on the F-T catalytic reactions that were discovered in 1923. The F-T
reactions can cover a range of combinations using different metallic
oxide catalysts to react hydrogen and carbon monoxide to form a mixture
of olefins, paraffins, and alcohols. These reactions are exothermic and
are not specific to the formation of any single compound. The range of
products from the F-T process depends on the reaction and temperature
conditions as well as the type of catalyst used and the composition of
(input) reactants.
In the complete scheme of the F-T process, the coal is initially
gasified (e.g., using a Lurgi gasifier), then cleaned of hydrogen sul-
fide, carbon monoxide and impurities, and finally shift converted before
it enters a catalytic reactor.
The major reason for interest in the F-T process is that a commer-
cial plant using a modification of this method is currently operating in
South Africa (SASOL I). In the commercialized process, two reactors
using different catalysts and temperatures and pressures, process gases
with different carbon and hydrogen ratios into different products. Its
main drawbacks are that a great deal of reaction heat is produced (i.e.,
efficiency suffers) and the process is apparently expensive. As previ-
ously indicated, the process can produce a wide variety of hydrocarbons
ranging from methane to light oils. The different products are produced
with varying degrees of overall thermal efficiency.
The gasification can be accomplished with any of a number of differ-
ent gasifiers. SASOL I, as shown in Figure 26, employs 13 Lurgi high-
pressure, steam-oxygen coal gasifiers to produce a product gas contain-
ing carbon monoxide, tars, and oils as the main components. The crude
product gas is cleaned of carbon monoxide, hydrogen sulfide, organic
sulfur, ammonia, and phenol. The cleaned gas is partitioned into two
streams. One stream is adjusted to a hydrogen-to-carbon monoxide ratio
of two to one and fed to a fixed-bed catalytic reactor (ARGE) that is
operating at 450 F and 360 psi. The products from this reactor are
mainly straight chain and medium boiling oils, diesel oil, LPG, and some
a Icohols.
The remaining stream of purified gas (i.e., gas from the Lurgi gas-
ifiers) is combined with reformed product gas (to increase the hydrogen-
to-carbon monoxide ratio) and sent to a fIuidized-bed reactor (i.e.,
Synthol: the U.S. developed Kellogg synthesis). The operating condi-
tions are 620 F and 330 psi. The products from this reactor are mainly
gasoline, fuel oil fractions, and various chemical products. The gasoline
has a lower octane rating than the natural petroleum-based gasoline that
is currently marketed in the United States.
1 11
-------
RAW COAL
SYNTHESIS
IT
TAR CREOSOTE
KELLOGG
FLUIDIZED-BED
SYNTHESIS
620°F
330 psi
ARGE
FIXED-BED
SYNTHESIS
450°F
360 psi
PRODUCTS
SEPARATION
REFORMER
AMMONIUM
SULPHATE
PLANT
AMMONIUM
SULPHATE
LIQUID PRODUCTS
ILPG, PETROL, OIL,
WAX, ALCOHOL)
ARGE
TAIL GAS
PRODUCT GAS
KELLOGG
TAIL GAS
PRODUCTS
SEPARATION
LIQUID PRODUCTS
(PETROL, ALCOHOL,
MINOR OIL AND WAX)
Figure 26
Fischer-Tropsch Synthesis
-------
Overviews on SASOL I and SASOL II, based on reference 8, follow:
SASOL I
LOCATI ON:
DESCRIPTION:
SIZE:
STATUS:
YEARS OPERATION:
COAL TYPE:
MAJOR PRODUCTS:
LOCATI ON:
DESCRIPTION:
SIZE:
STATUS:
COAL TYPE:
MAJOR PRODUCTS:
Sasolburg, South Africa
Gasification in Lurgi gasifiers
Two Fischer-Tropsch synthesis units;
1) ARGE fixed-bed unit, temp. 230°C;
press. 23 atm.; catalyst, pelleted
precipitated iron.
2) Kellogg SYNTHOL process, high-
velocity entrained-flow reaction
using a doubly promoted iron
catalyst.
10,000 bpd
In commercial production since 1956
24
Subb i tumi nous
Liquid fuels, chemicals, and fuel gas.
SASOL I i
Secunda, South Africa
Gasification in Lurgi gasifiers,
Fischer-Tropsch synthesis unit using the
Kellogg SYNTHOL process
Nominal 40,000 bpd
Anticipate ready for commissioning in 1980
Subbi tumi nous
Liquid fuels (gasoline is the major product)
Process variabilities for indirect liquefaction processes are such
that any efficiency value must be used with caution. Due to the pro-
prietary nature of indirect liquefaction technology (e.g., SASOL), a
detailed heat balance was not obtainable. Even so, a specific compar-
ison between the Fischer-Tropsch (F-T) and the Mobil processes was
obtained. Reference 9 provides a performance comparison between the
Mobil methanol-to-gasoline technology and the commercially available F-T
technology for the production of the motor gasoline meeting U.S. quality
standards. This reference covers complete conceptual plant complexes
using the Lurgi dry-ash, pressure technology to gasify subbituminous
113
-------
coal. Except for the Mobil process, processes used are commercially
available. Co-production of products, namely SNG, LPG, and gasoline is
practiced. Efficiency values contained in reference 9 are not based on
detailed mass balances and associated heat balances, but on the known
performance of specific processes. A thermal efficiency comparison
(reference 9) between the commercial F-T technology and the Mobil meth-
anol-to-gasoline technology for the production of motor gasoline (with
other output products) from U.S. subbiturn!nous coal is provided by Table
17. A typical heat balance for the gasification portion of indirect
liquefaction appears in Section 5.
Table 17
Thermal Efficiencies
MethanoI-to-GasoIi ne
Btu/hour Percent of
(10 Btu) Input
Fi scher-Tropsch
Btu/hour
(10 Btu)
Percent of
I nput
Coal 19,383
Coal Fines (excess) (872)
MethanoI —
Total Input 18,511
19,708
3
19,711
Ou_tpu±
SNG
C LPG
e LPG
10 RVP Gasol ine
Diesel Fuel
Heavy Fuel Oi I
Subtotal
A I cohol s
Sulfur
Ammonia
Power*
Total Output
6,067
247
385
4,689
11,388
19
83
18
11,508
32.8
1.3
2.1
25.3
61 .5
0.1
0.5
0.1
62.2
7,243
176
26
2,842
514
147
10,948
290
19
83
11
11,351
36.8
0.9
0.1
14.4
2.6
0.7
55.5
1 .5
0.1
0.4
0.1
57.6
Direct thermal equivalent value (thermal efficiencies are highly
dependent on product mix, see Section 7.5)
114
-------
7.3 Applications
Current
The conversion of coal to liquids has never been accomplished com-
mercially in the United States. In the past, coal to oil plants were
constructed in a number of countries. Currently there is only one plant,
in South Africa, producing liquids from coal. This plant, SASOL I, em-
ploys an indirect liquefaction process.
Projected
The successful development and commercial demonstration of a coal
liquefaction technology would provide a valuable energy alternative and
would allow greater utilization of the nation's coal resources. There
are many advantages to liquefying coal. Liquid fuels are generally more
attractive than solid fuels in that they are easier to store, transport,
and utilize. Also, during liquefaction, impurities found in coal (e.g.,
sulfur, metals, and ash) can be removed or their concentrations greatly
reduced. Thus, it is possible to produce clean, environmentally accept-
able liquid fuels from various ranks of coal. The development and future
commercial use of a coal liquefaction technology are dependent on many
factors. Some of the more important include:
• The demonstration (large scale) of a viable technology,
• The ability to satisfy environmental concerns, and
• The ability to produce a commercially usable liquid
fuel with an acceptable overaI I efficiency rating
and cost.
7.4 Environmental Considerations
Although many of the environmental issues associated with conven-
tional fossil fuel utilization are common to coal conversion processes,
liquefaction technology presents some unique problems (2). These include:
the identification of materials with carcinogenic, mutagenic, and related
effects; characterization and treatment of wastes and fugitive emissions
and effluents; and disposal of sludges and solid wastes. These problems
are generally common to all liquefaction technologies; however, particu-
lar processes may have to be evaluated individually. Liquefaction does
have the inherent advantage of separating the processing of the coal from
the ultimate utilization. Since impurities can be removed from the coal
during liquefaction, a "clean" fuel can be delivered to the utilization
site (possibly an urban area) and thus the fuel using facility will not
have to cope with the impurities.
115
-------
1 dent i f i ed PoI Iutants
Air Emissions
Development and commercialization of a coal liquefaction industry
creates a concern with regard to the introduction of air pollutants into
the atmospheric environment (2). The typical materials produced in a
coal liquefaction facility which could have a detrimental impact on air
quality include: hydrogen sulfide, ammonia, particulate matter (e.g.,
coal dust and process fines), hydrocarbons, sulfur dioxide, hydrogen
cyanide, small amounts of nitrogen dioxide, polycyclic hydrocarbons, and
heavy metals. These emissions result from such activities as coal hand-
ling and preparation, fuel combustion, coal gasification, raw gas and
liquid product cleanup, sulfur recovery, catalyst regeneration, and
product upgrading and storage.
The major air emissions from liquefaction facilities are generally
known and conventional control techniques possibly could be effectively
applied. The Dravo Corporation, in a 1976 handbook produced for the U.S.
Government, provides information on a number of industrial sulfur removal
systems. (Handbook of Gasifiers and Gas Treatment Systems, FE-1772-11,
February 1976.) The majority of the proprietary systems described are
for removing hLS from industrial gases. Some systems in addition to
removing hLS also remove other gaseous effluents (e.g., CO,-,, NHL, HCN).
Almost all of the addressed systems have been in existence for many years
with significant industrial usage. Such systems include the Rectisol and
the Stretford processes that have been used for selectively cleaning up
gaseous impurities from processes used to convert oil or coal to other
fuel form(s). Liquefaction air emission streams may contain impurities
which could reduce the capabilities of commercially available control
technolog ies.
However, in some instances, advanced controls may have to be devel-
oped before coal conversion plants are constructed on a commercial scale.
In addition, airborne pollutants will be transported into the general
environment and possibly transformed into other compounds after emission
from coal liquefaction facilities.
The 1977 Clean Air Act amendments mandate that fossil energy facil-
ities, including coal conversion plants, utilize the best available
technology to control pollutants. Coal liquefaction (and other process
facilities) constructed in non-attainment areas will be subject to emis-
sion trade-off policies. The energy and cost penalties of applicable
air pollution controls must be characterized as well as the secondary
pollutants which may be emitted by the controls.
Liquid Effluents
Coal liquefaction processes may produce waste effluents which have
broad temperature and pH ranges and may contain a variety of materials
1 16
-------
such as: suspended particles, ammonia, toxic trace metals, phenols,
aromatic hydrocarbons, thiophenes, aromatic amines, and other organic
compounds (2). Conventional control and wastewater treatment techniques
can be applied to most of these materials. However, particularly trouble-
some areas requiring more study include: phenols, trace metals and the
final disposal of the effluents (2).
Water quality may also be affected by gaseous streams, fugitive
effluents and air emissions which may settle or be washed into water
bodies by rain. Improper handling or disposal of solid wastes may also
release dissolved and suspended solids and organics. Control and treat-
ment options compatible with water discharge standards should be identi-
fied and their effects evaluated.
Effluent constituents may accumulate and/or be transformed in the
water column and biotic sediment or aquatic ecosystems. Current methods
for predicting the movement of waste contaminants through surface and
groundwater systems must be evaluated for locations where liquefaction
facilities may be located.
Sol id Waste
Solid wastes generated by coal liquefaction processes consist pri-
marily of (gasifier) ash and refuse removed from the coal and sludges and
solids recovered from waste treatment processes. The major solid waste
streams, as well as minor ones such as spent catalyst, must be character-
ized and appropriate disposal techniques determined. Where appropriate,
new treatment and disposal techniques may need to be developed.
Conventional disposal of solid wastes (especially ash) in offsite
landfills will require transport and handling equipment and relatively
large areas of land. The handling, transportation and disposal of wastes
must be controlled to prevent fugitive dust emissions and accidental dis-
charges. Groundwater leaching is another concern which must be evaluated
if landfills are used as disposal areas for coal liquefaction wastes.
Physical and chemical reactions involved, effects of various methods of
disposal upon Ieachabi Iity, effective control and containment techniques,
and compliance with new State hazardous waste disposal regulations must
all be evaIuated.
A DOE publication has estimated that the total solid wastes to be
disposed of by a large-scale Fischer-Tropsch facility would be about
1000 to 4500 tons per day (2). Most of these wastes wiI I be in the form
of ash. Disposal of these solid wastes (from a Fischer-Tropsch plant)
would cover approximately 250 to 1125 acres to a depth of 10 feet over a
20-year period.
117
-------
Regulatory Impacts
Each liquefaction technology will have to be evaluated separately
as to regulatory impacts. Because of the difference in technologies and
also varying state and local regulations, siting of a major coal lique-
faction facility must be approached on a case-by-case basis.
A coal conversion facility must comply with regulations and stand-
ards including requirements of the Clean Air Act, the Clean Water Act,
the Safe Drinking Water Act, the Resource Conservation and Recovery Act,
the Toxic Substances Control Act, the Federal Nonnuclear Research and
Development Act, and the National Environmental Policy Act as well as
applicable State laws. Failure to comply has the potential of halting
all progress toward commercialization.
Current standards for hazardous air pollutants limit mercury, beryl-
lium, and lead emissions. These standards conceivably could put a limit
on coal types than can be utilized in future demonstration plants. Since
effluent guidelines have not been developed for most fossil energy tech-
nologies, permit requirements are determined on a case-by-case basis by
States or by EPA (2).
Disposal of specific materials used in coal liquefaction may be
regulated in the future. Currently, solid waste disposal must comply
with stringent standards. Monitoring is required and State or EPA per-
mits for all landfills will be required by 1 April 1988.
The Resource Conservation and Recovery Act of 1976 (RCRA) has guide-
I ines for the land disposal of solid wastes (40 CFR 241). These standards
set minimum levels of performance for any solid waste land disposal site.
Additional standards have been proposed for disposal of solid wastes that
contain hazardous pollutants. All future coal liquefaction facilities
will have to abide by these solid waste standards (10).
Undoubtedly, the coal conversion industry would benefit from the
experience of the petroleum industry in dealing with complex organic
substances and new processes while complying with governing statutes.
7.5 Performance
Current
Currently, there are no commercial coal liquefaction plants in the
United States. Therefore, all projections are based on available data
associated with SASOL I and assessments relating to SASOL II and efforts
in the U.S. still in the developmental stage.
The overall thermal efficiency of the Fischer-Tropsch is dependent
on the output product mix. The projected overall thermal efficiency of
-------
a modern Fischer-Tropsch plant that would predominately produce pipeline
quality SNG with a lesser amount of liquid fuels (32% on a Btu basis) is
estimated by reference 9 to be approximately 55 percent (see Table 17).
The same reference projects that the Mobil process producing pipeline
quality SNG with almost as much gasoline (i.e., on a Btu basis) would
have an overall thermal efficiency of approximately 60 percent. Note-
worthy is the fact that a greater percentage of the Mobil process output
is in the form of gasoline and that these efficiency values are based on
giving credit to all output products. When these processes are optimized
for gasoline yield and credit is not given for product gas the efficiency
values are significantly less (e.g., 32% for F-T per reference 11).
Projected
The general expectation, based on substantial development efforts
and overseas experience, e.g., SASOL I, is that efficiencies of indirect
liquefaction processes will not measurably improve (over currently antic-
ipated values) in the forseeable future. System losses are well under-
stood and substantial efforts have already been directed at utilizing
all system available energy.
7.6 Economics
Current
Since there are no commercial coal liquefaction processes currently
in operation in the United States, the economics must be projected.
Projected
The cost to produce a million Btu of a liquid fuel is, at best, an
estimate. There are many factors that could greatly influence the cost
of fuel from an indirect liquefaction plant. These include inflation,
interest rates, fuel cost, pollution control, process efficiency; and
others. It should be noted that the projected cost of liquid fuel from
an indirect liquefaction process is consistently higher than for a direct
process. Reference 12 projects the costs of liquid fuels from indirect
liquefaction processes to be in the range of $7 - 10 per million Btu.
This is in terms of 1980 dollars with coal costs at one dollar per mil-
I ion Btu.
-------
References - indirect Coal Liquefaction
1. University of Oklahoma. Energy Alternatives: A Comparative
Analysis. The Science and Public Policy Program, University
of Oklahoma, Norman, Oklahoma, May 1975.
2. U.S. Department of Energy. Environmental Development Plan
(EDP) - Coal Liquefaction Program FY 1977. Assistant Secre-
tary for Environment, DOE/EDP-0012, Washington, D.C., March
1978.
3. U.S. Department of Energy. Environmental Readiness Document -
Coal Liquefaction, Commercialization Phase III Planning.
Assistant Secretary for Environment, DOE/ERD-0015, Washington,
D.C., September 1978.
4. Perry, H. Clean Fuels from Coal. In: Advances in Energy
Systems and Technology, Vol. 1, P. Auer, Ed. Academic Press,
1978. pp. 244-324.
5. Rogers, K. A., and Hill, R. F. Coal Conversion Comparisons.
The Engineering Societies Commission on Energy, Inc. for the
U.S. DOE, FE-2468-51, July 1979.
6. Hittman Associates, Inc. Proceedings of EPA/Industry Coal
Liquefaction Conference, Chicago, Illinois, October 23-24,
1979.
7. Wilson, S. C., Reznik, R. B., Knapp, E. M., and Tsai, S. M-H.
Environmental Implications of the President's Energy Initia-
tive. Monsanto Research Corporation for the U.S. EPA, Septem-
ber 1979.
8. U.S. Department of Energy. International Coal Technology
Summary Document. Assistant Secretary for Policy and Evalu-
ation, HCP/P-3885, December 1978.
9. Schreiner, M. Research Guidance Studies to Assess Gasoline
from Coal by Methanol-to-Gasoline and SASOL-Type Fischer-
Tropsch Technologies. Mobil Research and Development Corpor-
ation for the U.S. DOE, FE-2447-13, August 1978.
10. Gibson, E. D., and Page, G. C. Low/Medium Btu Gasification:
A Summary of Applicable EPA Regulations. Radian Corporation,
DCN #79-218-143-92, Austin, Texas, February 1979.
120
-------
11. Rogers, K. A., Wilk, A. S., McBeath, B. C., and Hill, R. F.
Comparison of Coal Liquefaction Processes. The Engineering
Societies Commission on Energy, Inc., for the U.S. DOE,
FE-2468-1, ApriI 1978.
12. Rudolph, P. F. H. Synfuels from Coal - How and At What Cost?
Paper presented at the 7th Energy Technology Conference,
Washington, D.C., March 24-26, 1980.
121
-------
8. High-Btu Gasification
8.1 Overview
High-Btu gasification of coal will provide a means to augment our
supply of natural gas. Coal can be gasified by any of several processes:
synthesis, pyrolysis, or hydrogasification. In synthesis, coal or char
is reacted with steam and oxygen and produces the heat for a reaction
that produces a mixture of hydrogen and carbon monoxide. In pyrolysis,
coal is heated in a starved air atmosphere. In the process, some gas and
liquids result, the major product being a coke residue. In hydrogasifi-
cation, coal, coke, or char is reacted with hydrogen to form methane.
To produce a pipeline quality gas (900 to 1,050 Btu/ft ), medium-Btu
gas (e.g., from hydrogasification) is cleaned and further treated. This
further treatment could include a shift conversion to obtain proper car-
bon monoxide to hydrogen ratio followed by a second purification process,
followed by a methanation process. The second purification process re-
moves carbon dioxide and hydrogen sulfide. The shift conversions and
methanation steps are catalytic process operations.
A number of high-Btu gasification second generation processes have
or are being investigated by the U. S. Department of Energy. These in-
clude the CO- Acceptor, BI-GAS, HYGAS, and the Synthane processes. Each
of these processes have unique characteristics and research and develop-
ment must proceed accordingly. Beside the above, there are a number of
other processes some of which have not been fully considered by DOE.
To an extent, environmental concerns common to coal fired boiler
facilities will also generally apply to coal gasification facilities.
Additional unique adverse environmental impacts are difficult to esti-
mate. No commercial plants are in operation anywhere in the world and
assessment must be based'on limited information from pilot plants. In
addition, information from a pilot plant may not be representative of a
commercial operation.
Projected overall energy efficiencies for coal gasification have
been estimated to be in the 58 to 68 percent range. A 1977 estimate of
the gate cost of high-Btu gas produced by a gasification plant was $4
to $6 per million Btu. Current estimates are somewhat higher.
8.2 Process Description
Concept
Figure 27 is a generalized diagram that shows the basic processing
steps common to different types of gasification processes. An overview
of the overall process consistent with the figure follows.
122
-------
Coal-
Steam Oxygen Steam
Mechanical
Preparation A
Possl ble Pre-
treatment
J I 1
Sh 1 f 1"
Cleaning) "'* "" Conversion
1
^
i
By-product
recovery
(Tars, ol Is,
Gas
Purification
i
i
co2
]
Sul
"^ Methanatlon
H2S
fur
Recovery
naphtha, ammonia)
High
Btu
Gas
Figure 27
Generalized Flow Diagram - High-Btu Gas
-------
The first step, coal preparation with possible pretreatment, can be
simple or complex depending on the characteristics of the specific gasi-
fication process. This step can range from crushing or grinding to
proper size to more sophisticated preparation including sizing, physical
beneficiation, and drying. In addition, in certain processes, it may be
necessary to pretreat an agglomerating coal feed to destroy the coking
properties (1, 2).
The three primary ingredients needed to chemically synthesize gas
from coal are carbon, hydrogen, and oxygen. Coal provides the carbon;
steam is the most commonly used source of hydrogen, although hydrogen is
sometimes introduced directly from an external source; and oxygen is sup-
plied (i.e., for medium-Btu gas) as pure oxygen. Heat can be supplied
either directly by combusting coal and oxygen inside the gasifier or from
an external source (1).
Coal can be gasified by any of several processes: synthesis, pyrol-
ysis, or hydrogasification. In synthesis, coal or char is reacted with
steam and oxygen and produces the heat for a reaction that produces a
mixture of hydrogen and carbon monoxide. In pyrolysis, coal is heated in
a starved air atmosphere. In the process, some gas and liquids result,
the major product being a coke residue. In hydrogasification, coal,
coke, or char is reacted with hydrogen to form methane.
Three combustible gases produced by coal gasification processes are
carbon monoxide (CO), methane (CH.) and hydrogen (hL). Methane, the
primary component of natural gas, is similar to natural gas in heating
value. Carbon monoxide and hydrogen heating values are approximately
equal, being about one-third the methane/natural gas value. Several non-
product gases are also produced, including carbon dioxide, hydrogen sul-
f i de, and n itrogen (1)-
A major goal for most coal gasification processes is to produce a
high quality gas during the initial gasification stage. The product from
each process is determined primarily by the methods used to introduce hy-
drogen, oxygen, and heat into the gasifier. To produce a pipeline quality
gas, medium-Btu gas (e.g., from hydrogasification) is cleaned and further
upgraded. Three steps are involved in upgrading raw gases produced during
the gasification stage: shift conversion, purification, and methanation.
Shift conversion combines carbon monoxide and water to produce carbon di-
oxide and hydrogen (CO + H20 —>• C02 + hL + heat). This shift is neces-
sary to adjust the hydrogen and caroon monoxide to the 3:1 ratio required
for methanation. A catalyst is used in this reaction. After shift con-
version, the gas is purified to less than 1.5 percent carbon dioxide by
volume and less than one ppm of hydrogen sulfide. Methanation follows,
reacting carbon with hydrogen to produce methane (CO + 3hL —> ChL + hUO
+ heat). Catalysts are used for this reaction. The basic upgrading pro-
cess is fairly standardized, and the major choices involve engineering
details rather than alternative processes (1).
124
-------
It should be noted that gas purification can largely be accomplished
using developed processes. The Dravo Corporation, in a 1976 handbook
produced for the U. S. Government, provides information on a number of
industrial sulfur removal systems. The covered proprietary systems are
for removing I-LS from industrial gases. Some systems, in addition to
removing I-LS, also remove other gaseous effluents (e.g., C0?, NHL, HCN).
Almost all of the addressed systems have been in existence for many years
with significant industrial usage. Such systems include the Rectisol and
the Stretford processes that have been used for selectively cleaning up
gaseous impurities from processes used to convert oil to other fuel
form(s). There are over 35 Rectisol and 50 Stretford plants currently
in operation worldwide.
Deta i I
A large number of high-Btu gasification processes have been proposed
Major high-Btu processes that have or are currently being investigated by
the U. S. Department of Energy include: CO- Acceptor, BI-GAS, HYGAS, and
Synthane. Detailed overviews of these processes based on a DOE report
follow (3).
CCU Acceptor
A diagram of the carbon dioxide acceptor process is shown in Figure
28. The pilot plant is located in Rapid City, South Dakota. In this
process, raw coal is crushed to 8 x TOO mesh in hot-gas-swept impact
mills, where the moisture content is also reduced from approximately 38
weight percent to about 16 weight percent. The hot gas, at approximately
850 F, is supplied by the combustion of coal fines recovered from mill
offgas. The temperature of the furnace flue gas injected into the mills
is moderated with recycle of mill offgas.
The crushed and partially dried coal is dried to 0-5 weight percent
moisture in flash dryers operating at about 240 F. The dried coal is
conveyed in fIuidized-bed preheaters where the temperature is raised to
approximately 500 F. The preheated coal is fed into the gasifier near
the bottom of a fluidized bed of char. Rapid devolati Iization occurs,
followed by gasification of the fixed carbon with steam.
The gasifier temperature ranges between 1480 F and 1550 F. Heat for
the gasification reactions is suppl ied by a circulating stream of calcium
oxide called acceptor. This acceptor which can be either limestone or
dolomite, supplies the heat needed for gasification, primarily through
the reversible exothermic/endothermic carbon dioxide acceptor reaction:
CaO + C02 5=± CaC03 + heat
The acceptor, reduced to the desired size distribution (generally
6 x 14 mesh) enters the gasifier above the fluidized char bed, showers
125
-------
M
ON
PHIHEATER
WW '
Figure 28
Carbon Dioxide Acceptor Process Schematic
-------
through the bed, and collects in the gasifier boot. Steam needed for
hydrogasification enters through the gasifier boot and the distributor
ring. Spent dolomite, used during startup to avoid plugging, is replaced
by fresh acceptor after circulation rates are established and the system
is at process temperature and pressure. Product gas from the gasifier
passes through a steam-generating heat exchanger, then goes to the gas
cleanup section. The regenerator is used for calcining the acceptor.
Both the flue gas from the regenerator and the product gas are
cleaned; the clean flue gas is either returned to the regenerator or
flared, and the clean synthesis gas is sent to the methanation unit where
the heating value of the gas is raised to pipeline quality, approximately
1000 Btu per standard cubic foot. The methanation facilities include a
shift converter, carbon dioxide absorber, hydrodesuIfurizer, zinc oxide
sulfur guard, and a packed-tube methanator. A Dowtherm system is used
to remove the heat generated by the strongly exotf ,iic methanation re-
action.
B I -GAS
The BI-GAS process is a two-stage, high-pressure, oxygen-blown sys-
tem using pulverized coal and steam in an entrained flow. The pilot plant
is located in Homer City, Pennsylvania. A diagram of the BI-GAS process
is provided in Figure 29.
Raw coal is first pulverized so that approximately 70 percent will
pass through 200-mesh. The coal, mixed with water, is fed to a cyclone
where the solids are concentrated into a slurry. Coarse underflow from
the cyclone is sent to a wet grinding mill for further crushing. The
slurry is further concentrated in a thickener and centrifuge, repulped
and mixed with flux to generate the desired concentration, and fed to
the downstream high pressure feed system.
A high pressure slurry pump picks up the blended slurry and trans-
ports it under pressure to a steam preheater. The hot slurry is then
contacted with hot recycle gas in a spray dryer for nearly instantaneous
vaporization of the surface moisture. The coal is conveyed to a cyclone
at the top of the gasifier vessel by the stream of water vapor and inert
recycle gas, as well as additional recycled gas from the methanator. The
coal is separated from the hot recycle gas in the cyclone and flows by
gravity to the gasifier.
The coal enters the gasifier through injector nozzles near the throat
separating the stages. Steam is introduced through a separate annulus in
the injector. The two streams combine at the tip and join the hot syn-
thesis gas rising from Stage 1. A mixing temperature of about 2200 F is
attained rapidly and the coal is converted to methane, synthesis gas, and
char. The raw gas and char rise through Stage 2, leave the gasifier at
127
-------
HIGH ITU GAS
CO
RCCrCLC CAS
TO GASlFlfH
J
COAL
PREPAR
ATION
t
SLURRY
PREPAR-
ATION AND
FEED
SYSTEM
1
GAS ^ 1 \ \
CYCLONE t
SEPARATOR |
\
GAS AND CHAR ^
}
/1^\
STAGE 2
J
ntciTLin
STAGE 1
*4f 1 HAHA TOH
1 t/UU f
lOOtlm
1
GASIFIE
3700 f
r
3OOO F
y
/ k
i
*•
,
-
\
V
CH>Sfl
^ STEAM
CHAFt AND STCAM
OXYGEN '
i
/800 r
GAS
\
SHIFT
CON
VERTER
1
HYDROGEN
SULFIDE AND
REMOVAL AND
METHANATION
\
CLFANGAS
CLAUS
PLANT
^-— v,
STf AM
SLAG QUENCH
SCRUBBER
W^
^ tVATCR
J
WATfK nil AHD
HO AT ING CHAR
FLOATING CHAR
SLAG
Figure 29
BI-GAS Process Schematic
-------
about 1700 F, and are quenched to 800 F by atomized water prior to separ-
ation in a cyclone. The synthesis gas (containing carbon monoxide, car-
bon dioxide, hydrogen, water, hydrogen sulfide, and methane) passes
through a scrubber for additional cooling and cleaning. The clean gas,
along with the desired amount of moisture, is sent to a carbon monoxide
shift converter to establish the proper ratio of carbon monoxide and hy-
drogen required in the methanation process. Three process steps follow
shift conversion: hydrogen sulfide removal, carbon dioxide removal, and
methanation.
Hydrogasification (HYGAS)
The pilot plant is located in Chicago, Illinois. With the HYGAS
process, several processing steps are required to convert coal to high-
Btu gas. A diagram of the process is provided in Figure 30. Coal prepar-
ation involves crushing the coal to -14 mesh. Caking coal is pretreated
in a fluid!zed bed at temperatures between 750°F and 850°F at an atmos-
pheric pressure to destroy caking tendencies and produce a free-flowing
coal. Non-caking coal is fed directly to the slurry tank. The coal is
slurried in this tank with an aromatic recycle oil to form a thick slur-
ry. This slurry is then pumped to 1000 psig and injected into the top
section of the gasifier (slurry dryer) which contains a fluidized bed of
hot coal particles. Oil is vaporized and removed, together with the hot
gases passing upward from the lower stages of the gasifier. Vaporized
oil is recovered for reuse by quenching the effluent from the gasifier.
Dry coal particles, at approximately 600 F from the slurry drying
section, flow by gravity through a dipI eg into a lift pipe. This lift
pipe serves as the first stage of hydrogasification. In this stage, the
heated coal comes in contact with a hot gas from the lower sections of
the reactor. This gas contains methane, carbon oxides, hydrogen, and
steam. The hydrogen chemically reacts with the more reactive part of
the incoming coal, forming additional methane. Approximately one-third
of the methane in the final product gas is produced in this step.
In the second stage hydrogasification section, the partially con-
verted coal from the first stage mixes with the rising hydrogen-rich gas
at about 1400-1700°F. Part of the hydrogen and steam react chemically
with the coal, forming methane and carbon dioxides. Approximately one-
third of the methane in the final product gas is produced in this step.
Hot residual char is then transferred to the third stage. Here the steam
and oxygen react with the char in a fluidized bed to produce a mixture of
gases rich in hydrogen. This mixture is passed upward into the hydrogas-
ification sections. Ash is removed from the bottom of the steam-oxygen
zone.
The raw product gas leaving the top of the reactor at about 600 F
is cooled and rinsed in a water quench, purified, and passed into a
129
-------
o
CO AI
Figure 30
HYGAS Process Schematic
-------
methanator. The ratio of hydrogen to carbon monoxide in the purified gas
entering the methanator is adjusted to about three to one. The purified
gas passes through a nickel catalyst at 800-900 F and is transformed to
pipeline quality gas with an average heating value of 930 to 950 Btu per
standard cubic foot.
Synthane
This DOE program is no longer being funded. The DOE pilot activi-
ties were located in Allegheny County, Pennsylvania. A key feature of the
Synthane process is that pretreatment of caking coals is integrated with
gasification. Another feature is that gas with a relatively high methane
content is produced directly. A schematic of the Synthane process is
provided in Figure 31. There are four major steps in the process: coal
pretreatment, coal gasification, shift conversion and purification, and
methanation.
Coal, crushed to -20 mesh, is dried, pressurized to approximately
40 atm., and is transferred into the fIuidized-bed pretreater by means
of high pressure steam and oxygen. Pretreatment prevents caking coals
from agglomerating in the gasifier. The coal overflows from the pre-
treater into the gasifier fluid!zed bed through an injection pipe.
Steam and oxygen enter the gasifier just below the fluid!zing gas dis-
tributor. The gasification reaction occurs within the fluidized bed.
Char flows downward into a bed fluidized and cooled with steam, and is
removed with transport steam, slurried i>n water, and depressured through
let down valves. In a commercial plant, this char can then be burned to
produce process steam. The product gas, containing methane, hydrogen,
carbon monoxide, carbon dioxide, ethane, and impurities, is passed
through a venturi scrubber and a water scrubber to remove carry-over ash,
char, and tars. The concentration of hydrogen and carbon monoxide in
the gas is adjusted to a three-to-one ratio in a shift converter. The
acid gases are absorbed in a hot-potassium carbonate (Benfield) scrubber.
Carbon dioxide is reduced to two volume percent and sulfur is reduced to
40 parts per million. Regeneration of the potassium carbonate solution
produces a hydrogen sulfide-rich gas, which is converted to elemental
sulfur by the Stretford process. The remaining traces of sulfur in the
product gas are removed by passing the gas through activated charcoal.
The purified gas must be reacted cataIyticaIly to convert the hydrogen
and carbon monoxide to methane.
Two methanation systems were installed in the pilot plant. One sys-
tem operates isothermally with no recycle in a Tube Wall Reactor (TWR)
in which the inside wall of the tube is coated with the catalyst and the
heat of reaction is transferred to boiling Dowtherm on the outside of
the tube wall. The other system is a Hot Gas Recycle (HGR) Reactor in
which temperature is controlled by using a cooled recycle side stream of
product gas. High pressure drop is avoided by coating parallel plates
with catalyst, a low pressure drop configuration. The low level of CO
131
-------
Figure 31
Synthane Process Schematic
-------
that leaves the methanation as the catalyst deactivates will be converted
in an adiabatic final methanator. The plant is currently in a protective
standby status.
As previously indicated there are a number of high-Btu gasification
processes that have received attention. Heat balance information for
such processes are not readily available due to the current developmental
and/or proprietary status of these processes. Reference 4 contains an
estimated heat balance on a proposed combination of two gasifiers (e.g.,
Lurgi/BGC and Texaco) approach. Reference 4 indicates that the proposed
combination gasifier concept is strongly synergistic in that the result-
ing balance between slurry water needs and phenolic liquor production
eliminates the cost of liquor treatment as well as other operational and
cost advantages. No claim was presented for an increase in overall sys-
tem energy efficiency.
An estimated heat balance based on reference 4 is given in Table 18.
DiagrammaticaI Iy, this can be illustrated by the heat flow diagram, Fig-
ure 32. The provided heat balance is based on a plant with an output of
over 250 billion Btu per day. The product gas has a heating value of
950 Btu/scf. The indicated design coal feed is 17,027 tons per day with
an as-received Btu value of 24.47 million Btu per ton.
8.3 AppIication
Current
Currently, there is not a single commercial high-Btu gasification
plant operating anywhere in the world. All current activities are in the
research and development categories (5).
Projected
The successful development of a high-Btu gasification (from coal)
technology would provide the means to produce a pipeline quality, pipe-
line compatible product from coal. The resulting gas would augment a
decreasing amount of available natural gas. Undoubtedly, future use of
high-Btu gasification technology would depend on a number of factors.
These include:
1) The development of a viable technology,
2) The ability to satisfy environmental concerns, and
3) The ability to produce a pipeline quality product
at an acceptable cost.
Assuming that an economic and environmentally acceptable technology
can be developed, the high-Btu gasification of coal would permit the aug-
mentation of natural gas with a synthetic product. The need for such a
capability appears to be critical 15 to 20 years hence.
133
-------
Table 18
Estimated Heat Balance for a 270 Billion Btu per day
High-Btu Gasification Plant
B±u/day
(10 Btu's)
Percent of TotaI
Energy Input
Product Gas
285.3 x 106 scfd @ 970 Btu/scf
Electric Power Export
Approximately 2400 Mwh per 24
hour period
Sensible Heat of Product Gas
276.70
8.17*
0.33
66.41
1.96*
0.08
System Losses
Heat value of sulfur product
Carbon losses
Stack and boiler losses
Steam, ash disposal, and
unaccounted
Electric motor and mechanical
Heat content of (XL waste gas
Heat Rejected
Cooling tower and air cooler
Total Energy Input
(17,027 shopt tons/day @
24.47 x 10 Btu/ton.)
5.12
4.67
4.70
5.00
2.50
2.71
106.75**
416.65
1.23
1.12
1 .13
1.20
0.60
0.65
25.62**
100.0
* Based on direct thermal eguivalent
** Approximately 16$ of total heat rejected is associated with
production of export power
134
-------
100$
Heat input from coal
Sensible heat
of product gas
5.93$
System losses
25.62$
Heat
rejected
1.96$
Electric power export
(based on direct thermal
equ ivalent)
66.41 $
Product gas
Figure 32
Estimated Heat Flow Diagram for High-Btu Gasification Plant
8.4 Environmental Considerations
As previously indicated, data applicable for environmental assess-
ments of the overall gasification cycle is very limited. Any environ-
mental assessments must be recognized as estimates until we can obtain
data from on-line operating systems. Reference 2 indicates that data
from pilot plants may not be representative of effluents that would be
produced by a commercial plant.
Approximately 10 percent of the coal input to a gasification plant
is used to generate steam. Combustion of this coal creates the environ-
mental emissions generally associated with steam generation.
135
-------
Other wastes (e.g., tar oils, phenols, solids) would be of different
composition than wastes from conventional coal fired boiler steam gener-
ators. It must be emphasized that the handling of waste from a high-Btu
coal gasification plant is an area where we have very limited information.
The following presented material must be considered accordingly.
I dent i f i ed PoI Iutants
This discussion addresses the environmental aspects associated with
the gasification process and does not cover coal extraction and trans-
portation. Reference 5 indicates that the data base for evaluating en-
vironmental, health, and safety aspects is very limited and that reported
information is frequently contradictory. Reference 5 indicates that ad-
verse health effects are particularly difficult to estimate, since no
large scale plants are operational. The only available data on emissions
and effluents are based on limited information collected at pilot plant
operations.
The provided material, based mainly on unsupported analyses, are de-
rived from the indicated referenced sources.
Air Emissions
The type and sources of potential air pollutants from coal conver-
sion are as follows (6):
Pollutant Process-Generated Combustion-Generated
Particulate matter X X
SuI fur oxides X X
Reduced sulfur compounds X
Nitrogen oxides X
Hydrocarbons X X
Carbon monoxide X X
Trace metaIs X X
Odors X
Other gases (including X
NH3, HCN, HCI)
Sulfur dioxide is emitted principally from the tailgas stream of the
sulfur recovery plant and from stack gases of auxiliary systems requiring
fuel oxidation. These include plant boilerhouse and miscellaneous fossil
fuel fired process heaters.
Particulate matter can be released as a fugitive dust and as a pro-
cess or combustion-based stack emission. Fugitive emissions have a po-
tential for occurring at receiving, handling, and storage areas for coal,
solid waste, and from leakage from process equipment elements. Process
136
-------
stack emissions would include the exhaust of pollution control equipment
(e.g., scrubbers and precipitators). Fuel combustion would provide the
potential source of particulate matter.
Nitrogen oxides emissions would result from fossil fuel firing of
boilers. Hydrocarbon emissions could occur from liquid storage areas,
system leaks, and from the evaporation of hydrocarbon liquids dissolved
in cooling systems. Reduced sulfur compounds occur in the initial prod-
uct stream of virtually all coal conversion processes.
Trace element emissions of such substances as mercury, beryllium,
arsenic, and other heavy metals which are contained in coal in small
amounts are expected in view of experience from coal fired boilers. In
addition, other gaseous emissions, especially hydrogen cyanide and ammo-
nia (as well as hydrogen chloride and gaseous odorants) may also be as-
sociated with coal conversion plants.
Liquid EffIuents
Waste waters from coal conversion processes can originate from a
number of sources. These include water of constitution, water added for
stoichiometric process requirements, and water induced for gas scrubbing
and by-product recovery. Such process waters come into contact with con-
taminants in coal and are likely to be a principal source of pollution.
Table 19, taken from reference 6, indicates expected composition of waste-
waters associated with one conversion approach (i.e., Synthane).
Table 19
Composition of Synthane By-Product Water
n ,, , , By-Product Water
Po utant , ,... ,
(mg/Iiter)
pH 7.9 - 9.3
COD 1,700 - 43,000
Ammonia 2,500 - 11,000
Cyanide 0.1 - 0.6
Thiocyanate 21 - 200
Phenols 200 - 6,000
Sulfide N/D
AIkal inity (as CaC03) N/D
Specific Conductance N/D
(as /umhos/cm)
N/D = not determined
137
-------
Sol id Waste
Past analyses have indicated the expectation that in a commercial
plant, residue from the gasifier would be burned along with tars to raise
steam for the overall process. Table 20, taken from reference 7, provides
representative analyses of coals and associated chars from the Synthane
process. The chars would contain some trace elements. It should be noted
that problems may exist with burning tars due to residence time (in flame)
and with SO stack gas cleaning when burning tar and char. Reference 2
indicated tftat in the past, consideration was given to solid waste dispo-
sal by means of burial in a mine. These waste materials would consist of
ash from the boiler plant and gasifiers, coal wash plant waste (i.e., if
wash plant is used), process sludge, and other waste. Undoubtedly, this
whole disposal area requires additional effort. It should be noted that
additional information for decision making is required so as to permit
compliance with applicable environmental, health and safety regulations.
Regulatory Impacts
Currently, there is a substantial body of legislation that directly
relates to the gasification of coal. There are Federal and state emis-
sion standards covering air, water, and solid waste. There exists legis-
lation and regulations covering toxic substances, safe drinking water, oc-
cupational health and safety, protection of fish and wildlife and others.
Any viable conversion technology would necessarily have to be consistent
with the substantial body of environmental, health and safety legislation
and regulations in being.
8.5 Performance
Current
Currently, there is not a single commercial high-Btu gasification
plant anywhere in the world. Therefore, all projections are based on a
technology still in the developmental stage.
Projected
It is difficult to provide confident estimates for coal conversion
efficiencies. In addition, the definition of efficiency can vary depend-
ing on the included factors (e.g., only input coal or coal and supple-
mentaI energy).
Reference 2 indicates an efficiency range of 56-68 percent. Refer-
ence 8 indicates that for a 900 Btu/scf gas, the limiting efficiency is
77 percent and by 1990, a 75 percent value should be achievable. This is
consistent with the estimated heat balance (Table 18) based on reference
4. In essence, we are dealing with a technology where a substantial
amount of energy will be used and lost in the conversion process.
138
-------
Table 20
Representative Proximate and Ultimate Analyses of
Coals and Chars, Weight Percent
(Synthane Process)
Coa 1 s :
Moi sture
Volati 1 e matter
Fixed carbon
Ash
Hydrogen
Oxygen
Carbon
Nitrogen
Sulfur
Chars (from above coals):
Mo i sture
Volati 1 e matter
Fixed carbon
Ash
Hydrogen
Oxygen
Carbon
N i trogen
Sulfur
1 1 1 i no i s
No. 6
Coal
8.3
37.5
43.0
11 .2
5.3
15.9
63.0
1 .1
3.5
0.8
4.0
69.9
25.3
1 .0
1 .3
70.4
0.6
1 .4
Western
Kentucky
Coal
4.3
34.6
44.5
16.6
4.7
10.9
62.7
1 .2
3.9
1 .2
4.8
63.3
30.7
1 .0
1.1
64.5
0.7
2.0
Wyomi ng
Subb i tumi nous
Coal
18.1
31 .9
32.0
18.0
5.4
30.3
45.2
0.6
0.5
0.5
5.1
38.1
56.3
1 .0
1 .2
40.6
0.4
0.5
North
Da kota
Li gn i te
20.6
32.9
38.2
8.3
5.7
32.6
5]. 5
0.7
1 .2
1 .2
10.0
50.2
38.6
0.9
0.0
58.9
0.2
2.0
Pi ttsburgh
Seam
Coal
2.5
30.9
51.5
15.1
4.7
9.3
68.4
1 .2
1 .3
1 .4
1 .6
69.3
27.7
1 .0
1.7
68.9
0.5
0.2
-------
8.6 Economics
Current
Since there is not a single high-Btu gasification plant in the world,
economics can only be projections.
Projections
As with any sophisticated developing technology, the cost to produce
a million Btu (MBtu) is, at best, an estimate. The estimated cost by DOE
to produce a synthetic pipeline gas as of mid-1977 and based on coal cost-
ing one do Ilar per mil I ion Btu was $4 - $6 per mi I I ion Btu (9). Undoubted-
ly, cost in current dollars will be high.
140
-------
References - High-Btu Gasification
1. University of Oklahoma. Energy Alternatives: A Comparative
Analysis. The Science and Public Policy Program, University
of Oklahoma, Norman, Oklahoma, May 1975.
2. Perry, H. Clean Fuels from Coal. In: Advances in Energy Sys-
tems and Technology, Vol. 1, P. Auer, Ed. Academic Press, 1978.
3. U.S. Department of Energy. Coal Gasification, Quarterly Report,
January-March 1978. Assistant Secretary for Energy Technology,
DOE/ET-0067/1, Division of Coal Conversion, Washington, D.C.,
September 1978.
4. Netzer, D., and Ellington, R. T. SNG By Fluor - Combination
Coal Gasification. Presented at the Sixth Annual International
Conference on Coal Gasification, Liquefaction and Conversion to
Electricity, University of Pittsburgh School of Engineering,
Pittsburgh, Pennsylvania, July 31 - August 2, 1979.
5. Based on unpublished data obtained from Resources of the Future
during 1979.
6. Rubin, E. S., and McMichael, F. C. Some Implications of Environ-
mental Regulatory Activities on Coal Conversion Processes. In:
Symposium Proceedings - Environmental Aspects of Fuel Conversion
Technology, St. Louis, Missouri. U.S. EPA/ORD, Washington, D.C.,
May 1974. pp. 69-90.
7. Forney, A. J., Haynes, W. P., Gasior, S. J., Johnson, G. E., and
Stakey, J. P., Jr. Analyses of Tars, Chars, Gases, and Water
Found in Effluents From the Synthane Process. In: Symposium
Proceedings - Environmental Aspects of Fuel Conversion Technology.
St. Louis, Missouri. U.S. EPA/ORD, Washington, D.C., May 1974.
pp. 107-113.
8. Monsanto Research Corporation. Efficiencies in Power Generation.
Report prepared for the U.S. EPA, NTIS PB-234-160, Washington,
D.C., March 1974.
9. Mills, G. A. Synthetic Fuels From Coal: Can Research Make
Them Competitive? Washington Coal Club, March 10, 1977.
14'
-------
9. Surface Oil Shale Processing
9.1 Overview
The oil shale resources in the United States probably exceed two
trillion barrels of petroleum and of this amount, 25 to 35 percent is
presently projected as being commercial. Most oil shale of projected
commercial grade contains 20 to 50 gallons of oil per ton of rock. A
large portion of the United States shale resource is in the range of 10
to 20 gallons per ton of rock with an insignificant amount of the re-
source base containing as much as 125 gallons per ton (1).
The most extensive high-grade deposits of domestic oil shale are
in the Rocky Mountain region in the Green River Formation primarily in
Colorado, Utah, and Wyoming, on land which is mostly in the public do-
main (1 ).
The two major routes for exploiting oil shale resources are (2):
1. Conventional mining followed by surface proces-
sing, and
2. In situ (in place processing).
In addition, there is modified in situ. Modified in situ involves
removing some of the shale (e.g., by conventional mining) to increase
the void volume in order to enhance the in situ processing. In modified
in situ, recovered shale (e.g., by conventional mining) can be surface
processed.
This section addresses convention (i.e., surface retorted) processes,
In conventional oil shale processes, the following steps are performed:
• Mi ni ng the shale,
• Crushing the mined shale,
• Retorting the crushed shale, and
• Collecting and upgrading the crude shale and
other by-products.
To date, a number of above ground retorting processes are in the
advanced development stage. Even though shale oil has been produced
commercially (on a small scale) for various periods of time since 1838,
the future viability of an oil shale technology depends on many factors
i ncIud i ng:
• The demonstration of a modern commercial scale
techno logy,
142
-------
• The ability to satisfy environmental concerns, and
• The ability to produce an acceptable product at an
acceptable price.
In this regard, there are many unknowns. These range from the abil-
ity to satisfy environmental concerns to the commercial scale cost to
produce a barrel of oil from oil shale.
9.2 Process Description
Concept
Oil shale is a marl, a variety of limestone laced with organic mat-
ter (hydrocarbon) known as kerogen. Kerogen is a complex material com-
posed mainly of carbon, hydrogen, oxygen, sulfur, and nitrogen. The
kerogen molecule is large and heavy. Heating breaks the chemical network
holding the heavy kerogen molecules together and "cracks" the individual
large molecules into smaller molecules. This releases a liquid hydrocar-
bon mixture, the shale oil, that is the most valuable (3).
In conventional processes, the heating (retorting) takes place above
ground. The conventional process is composed of four basic steps: min-
ing the shale; crushing it to the proper size for the retort vessel; re-
torting the shale to release the oil; and refining the oil to bring it up
to a high-quality product. The shale can be mined underground or on the
surface depending on the nature of the deposit. The minimum thickness
of a shale seam for commercial utilization is considered to be about 30
feet, but thicker seams are preferred (3).
After the shale is crushed to the right topsize, it is fed into a
retorting vessel and heated to between 800 F and 1000 F to decompose the
kerogen. In practice, on the order of 75 percent of the kerogen is sep-
arated from the rock at these temperatures (3).
Different retorting processes apply heat to the shale in different
ways. The heat carrier can be either a gas or noncombustible solid such
as sand or ceramic balls. The oily vapor produced as the kerogen decom-
poses during the retorting is condensed to form the raw shale oil. This
raw shale oil is subsequently upgraded to produce a more marketable prod-
uct. If gas is produced in the retorting operation, it can be used for
process purposes (e.g., to produce electric power) and/or a pipeline
qua Iity gas.
Deta i I
Conventional (above ground retorting) oil shale processes basically
provide for the following (2, 3):
143
-------
1 . Mi ni ng the shale,
2. Crushing the mined shale,
3. Retorting the crushed shale,
4. Collecting the crude shale oil and other by-
products, and
5. Upgrading the crude oil and possibly other by-
products.
Currently, there are several above ground retorting processes that
are in the advanced development stage. These include:
• The Union Oil Company Retort B process that employs
a vertical gas-recycle retort.
• The Paraho Development Corporation hot gas process
that employs a vertical gas combustion kiln based
on a design used for many years to process limestone.
• The Superior Oil hot gas method that employs a cir-
cular gas-combustion retort.
• The Lurgi-Ruhrgas modified coal carbonization tech-
nique that uses sand or recycled shale ash heated to
above 900 F to retort the shale.
• The TOSCO II process that uses i-inch ceramic balls
heated to above 1000 F to transfer heat to the crushed
shale.
The Oil Shale Corporation (TOSCO), in conjunction with other joint
venture participants (called the Colony group), have demonstrated their
retort process technology at Parachute Creek, Colorado, in a 1000 tons/
day semi-works plant. TOSCO has designed a full-scale 66,000 tons/stream
day commercial plant that would produce 47,000 barrels per day of low
sulfur fuel oil and 4,300 barrels per day of LPG. The plant (TOSCO II)
would be located on the Dow West property of the Middle Fork of Parachute
Creek, with spent shale disposal in the nearby Davis Gulch. Current
plans are for construction of full-scale commercial plant to commence in
early 1984 with completion early in 1987. Details of the TOSCO II pro-
cess foI low (4, 5) .
The TOSCO II retort is an externally-heated reactor that uses hot
ceramic balls to heat the shale to pyrolysis temperature in a horizontal,
rotating kiln. The shale, crushed to less than one-half inch size, is
fed into a fIuidized-bed where it is preheated by hot combustion gases
from a separate ball heater. After preheating, the shale is moved into
the reactor and mixed with half-inch diameter heated ceramic bails from
the ball heater. The heat in these balls transfers to the sha e, effect-
ing pyrolysis. The oil, steam, and gases are given off as a mist, which
I 44
-------
is fed to a fractionator for product recovery. The spent shale and cer-
amic balls are discharged from the pyrolysis drum and separated by a
trommel screen. The balls are returned to the ball heater, and the spent
shale is removed for disposal (6).
A fractionator separates the oil from gas and waste contained with
the hydrocarbon vapors feeding the fractionator; some of the gas from the
fractionator is burned to heat the balls in the ball heater. Since no
combustion takes place in the reactor vessel, the resulting gas has a
higher energy content and the oil a lower viscosity than that from an in-
ternally heated retort. These features, and the reactor's ability to
handle fine particles, are advantages of the TOSCO II process (6).
The TOSCO II commercial plant will include a conventional under-
ground room-and-pi Ilar mine. Primary crushing of the run-of-mine shale
will be carried out at the mine portal bench. The coarse ore product
will be transported by conveyor to the final crusher at the plant site.
The product on final crushing will be ^-inch topsize and fed to the TOSCO
II retort unit and oil recovery equipment. The flowsheet for a single
unit (one of six) is shown in Figure 33 (5).
As previously indicated, the minus i-inch oil shale is first pre-
heated to about 500 F with flue gas from the ball heater. The preheated
shale is fed to a horizontal rotating retort (pyrolysis drum), together
with approximately 1.5 times its weight in hot ceramic balls from a ball
heater. This raises the temperature of the shale to pyrolysis tempera-
ture (900 F) and converts its contained organic matter to shale oil vapor.
The shale oil vapors are fed to a fractionator for hydrocarbon recovery.
The mixture of balls and denuded shale are discharged through a trommel,
in order to separate the balls from the shale. The warm balls are purged
of dust with flue gases from a steam preheater (5).
The dust-free warm balls are returned to the ball heater via a ball
elevator. They are then reheated to about 1300 F using in-plant fuel and
then recirculated to the pyrolysis drum (5).
The hot processed shale is cooled, moisturized and deposited in a
disposal site. The shale oil hydrocarbon vapors from the pyrolysis drum
are separated into water, gas, naptha, and gas oil, and bottom oil in a
fractionator. The foul water is stripped of hLS and NHL and reused and
the other products are upgraded prior to shipping or used for process
purposes (5).
An estimated energy balance for a -commercial scale TOSCO II facility
is contained in reference 7. The reference 7 energy balance assessment
covers both the retorting process and the resulting product upgrading
facilities. An estimated heat balance based on reference 7 is given in
145
-------
FLUE c«s
TO ATMOSPHERE
MEHEAT SYSTEM
STUCK
PREHEAT SYSTEM
(INCLUDES INCINERATOR!
* ALL SCRUBBER SLUOSE STREAMS
TO PROCESSED SH4LE DISPOSAL
** TO GAS RECOVERY AND
TREATINS UNIT
MOISTURIZED PROCESSED
SHALE TO DISPOSAL
COVERED PROCESSED
SHALE CONVEYOR
Figure 33
Pyrolysis and Oil Recovery Unit TOSCO II Process
-------
Table 21. DiagrammaticaI Iy this can be illustrated by Figure 34. It
should be noted that the provided heat balance is an estimate, there
being uncertainty as to the exact composition of the input stream and the
yields and composition of the output stream. The provided energy balance
is in terms of energy flow per hour of plant operation.
Table 21
Estimated Energy Balance For a TOSCO II Plant
Producing 47,000 BPSD* Upgraded Shale Oil
From 35 Gallons Per Ton Oil Shale
B±u/hour
(10 Btu's)
Percent of TotaI
Energy Input
Product Output
Product oiI
LPG
Diesel fuel
System Losses
Spent shale and moisture
Residual carbon (coke)
Ammonia
Sulfur
Cooli ng water
Water evaporation on shale
Losses (including flue gas
heat)
I 0.30
0.70
0.1 1
1 .78
0.93
0.11
0.06
1 .07
0.25
2.45
58.00
3.94
0.62
10.02
5.24
0.62
0.34
6.02
1.41
13.79
Energy Input
Raw shale
Steam
Electrical energy
17.76
17.00
0.53
0.23
100.0
95.72
2.98
1 .30
BPSD = barrels per stream day
147
-------
100$ Energy input
95.72$
From raw shale
10.02$
Spent
sha le
6.20$ (
Resi dua
carbon,
and sul
ammonia,
fur
58.0$
Product oi I
-4.28$
From 'steam
and electricity
6.02$
Cooli ng water
1.41$
Water
evaporation
13.79$
Misc. losses
(i nc I ud i ng
fIue gas)
4.56$
LPG and diesel fuel
62.5$
Total energy out
Figure 34
Estimated Heat Flow Diagram For TOSCO II Plant
9.3 AppIications
Current
Shale oil has been produced commercially for various periods of
time in eleven countries since the initiation of shale oil operations in
France in 1838. In Canada and the Eastern United States, a very small
industry was operating in 1860 but disappeared when petroleum became
plentiful. Currently, the only commercial production is in Russia (Es-
tonia) and China with a combined production of approximately 150,000
barrels per day. AM other shale industries (i.e., in other countries)
148
-------
succumbed because of the inability to compete with petroleum fuels. All
production to date has generally occurred in retorts that would not be
considered of commercial size for U. S. operations (2, 8).
Projected
The successful development and demonstration of a commercial scale
shale oil production technology would provide a valuable alternative for
the acquisition of I iquid fuels. The abiI ity to produce oiI from oi I
shale would provide the potential means to produce liquid fuels from our
vast oil shale resources and thereby reduce our dependence on imported
and domestic petroleum products. The commercial scale development and
future use of an oil shale technology are dependent on many factors.
These include:
• The demonstration on a commercial scale of a
viable technology,
• The ability to satisfy environmental concerns, and
• The ability to produce a commercially acceptable
product at an acceptable cost.
9.4 Environmental Considerations (3, 8)
The Environmental Protection Agency, the Department of Energy, other
governmental agencies, and other groups are studying the environmental
aspects of shale oil development. Currently, there remain a number of
unanswered environmental questions. It may not be possible to provide a
meaningful environmental determination until experience with one or pos-
sibly more operating plants are acquired. The technologies are just too
new, the effected ecologies are not well understood, and the scale of
operation is too massive to be able to predict (with a reasonable degree
of confidence) the effect of an oil shale industry. In addition, envi-
sioned environmental controls for the oil shale industry are subject to
large uncertainties.
The most significant problems and uncertainties are associated with
impacts on air and water quality, waste management and occupational
health and safety aspects.
I dent i f i ed PoI Iutants
Air Emi ss ions
Atmospheric emissions can arise from several activities or opera-
tions during oil shale processing. The major source of SO,-,, NO , and
CO is fuel combustion for process heat; SO^ is also emitted in The tail
149
-------
gases of sulfur recovery operations. The use of fuel oils in mobile
equipment and in explosives will result in emissions of CO and N0x-
Hydrocarbons are present in both combustion emissions and in product
storage tank vapors. Emissions of particulate matter can result from
blasting, raw and spent shale handling and disposal, raw and spent shale
dust in process gas stream, fuel combustion, and site activities which
generate fugitive dust.
Particulate emissions from fuel combustion and fugitive dust from
spent shale handling and disposal can contain polycyclic organic mater-
ial (POM) and certain trace metals. Gaseous ammonia, hydrogen sulfide,
and volatile organics may be released during moisturizing and subsequent
cooling of retorted shale. Catalyst materials may release particulate
matter containing trace metals to the atmosphere during regeneration,
handling, or final disposal.
Actual S0? emission associated with individual retorting processes
will depend upon the degree of sulfur removal accomplished for in-plant
fuels, the extent of on-site shale oil processing, and the degree of
control applied to sulfur recovery tail gases. Combustion of any hydro-
carbon fuel will produce oxides of nitrogen when air containing nitro-
gen is used as the source of oxygen. In addition, organic nitrogen
contained in the fuel can be partially oxidized to NO and N0~. In gen-
eral, those processes which require small-size shale feed (e.g., TOSCO
II) will have more uncontrolled particulate emission during crushing
and raw shale operations than processes which require large feed.
Site use activities which may generate fugitive dust generally are
not process specific. The use of open pit versus underground mining
will be the largest factor determining total fugitive emissions associ-
ated with extraction of oil shale. Overall fugitive dust emissions may
present more of a problem for the TOSCO II process than for some other
processes. Ore storage and handling and disposal of the fine TOSCO II
retorted shale are potential fugitive sources.
The largest source of CO in an oil shale operation is mobile equip-
ment used for mining and transport. The quantity of such emissions is
a function of mining method and haul distances rather than retorting
process.
The pyrolysis of essentially any type of organic material produces
a certain amount of POM, and oil shale kerogen is no exception. Gen-
erally. POM compounds have a low volatility and will be associated with
high boiling liquid or solid products or particulate matter. And, al-
though POM is known to be present in carbonaceous retorted shales, the
biological availability and potential hazard of such material is not
accurately known at present.
50
-------
Release of POM to the atmosphere during oil shale processing can
occur via three major pathways:
(1) Handling and disposal of retorted shale - fugitive
particulates and possible volatilization of hydro-
carbons.
(2) Combustion of shale derived oils containing POM.
(3) Flue gases containing entrained retorted shale
particulates, along with retort gas or spent
shale coke combustion products.
Oil shale contains trace amounts of many elements. However, for
elements other than Si, Fe, Al, Ca, Mg, and K, the concentrations in oil
shale are less than generally found in coal. In addition, conditions
during retorting are not severe enough to volatilize most metallic and
heavy elements. With notable exceptions such as arsenic (As) and possi-
bly antimony (Sb), most trace elements (e.g., nickel (Ni), vanadium (V),
molybdenum (Mo)) remain with the spent shale, or are found as components
of raw and spent shale solids entrained in retort gases and in raw shale
oil. Arsenic in raw shale apparently forms a range of volatile oil sol-
uble compounds (perhaps organic arsines) during retorting, and appears
in raw shale oil and all condensible oil fractions. If not removed dur-
ing upgrading, arsenic will be present in shale oil combustion products.
Metals and their compounds are used as catalysts (Ni, Co, Mo, Cr,
Fe, Zn) for hydrotreating, de-arsenating, sulfur recovery, and trace
sulfur removal. Emissions of particulate matters containing catalyst
metals can occur either during on-site regeneration or during handling
and disposal. Catalyst use is not unique to shale oil processing, and
much information and experience in preventing hazardous emissions can be
borrowed from the petroleum and related industries.
Solid and Liquid Effluents
Construction, mining, and site use activities may potentially
result in increased sediment and dissolved solids loading in surface
run-off and receiving streams. This indirect source of potential water
pollution is not unique to oil shale extraction and processing but may
require careful control due to the magnitude of site activities. Col-
lection and impoundment of run-off may be necessary.
The need to process 1 to 3 tons of shale per barrel of oil results
in a major solid waste disposal problem regardless of whether surface or
in situ retorting is employed. A principal impact will be the necessary
storage of overburden on refuse from open pit and room-and-piIlar mining.
Large volumes of waste material must be disposed of in a satisfactory
151
-------
manner. If the overburden and refuse have properties toxic to the ex-
isting surroundings, vegetation and ecosystem, then the technology must
include control of these effects.
Aqueous wastes from oil shale processing can be broadly categorized
as originating from direct or indirect sources. Direct sources are waste-
waters generated from unit operations and/or processes, including waste-
water from retorting operations; wastewater from upgrading operations;
water from air emission control and gas cleaning systems; cooling water
and boiler water blowdowns; water treatment systems; mine dewatering
wastewater; and sanitary wastewaters. Indirect sources include: leach-
ate from retorted shale disposal areas; run-off and erosion resulting
from construction and site use activities; and run-off from mining and
transport activities.
Water is a direct product of oil shale retorting, resulting from
the step in the release of free and inorganically bound water from raw
shale, and combustion of organic material in shale. From 1 to 8 gallons
of water are commonly produced per ton of input shale feed to a surface
retort, depending on the retorting process and the composition of the
shale processes.
This water can separate partially from crude shale oil during stor-
age, and/or can appear in aqueous waste streams of shale oil upgrading
operations. Water remaining in retort gases after oil separation can be
condensed during cooling or gas cleaning operations, or can appear in
the flue gas stream from retort gas combustion. Water separated from
crude shale oil contains mainly ammonia, carbonate and bicarbonate,
sodium, sulfate, chloride, and dissolved or suspended organic compounds
(phenolics, amines, organic acids, hydrocarbons, mercaptans). Smaller
quantities of calcium, magnesium sulfides, and trace elements may also
be present, along with suspended shale fines. Water condensed from
retort gases contains primarily ammonia and carbonates, with traces of
organic substances and sulfur containing compounds.
The quality of wastewaters from an upgrading operation varies with
the level of on-site upgrading or refining utilized. In general, a full-
scale refining operation may include any of the following wastewater
streams: oily cooling water, process water, and wash water.
Wastewaters are also collected during retort gas cleaning, tailgas
cleanup, and foul water stripping. Major constituents in such waters
are shale dust particulates, hydrocarbons, hLS, NHL, phenols, organic
acids, and amines. Other constituents such as thiosulfate and thiocyan-
ate may also be present.
Approximately 45 to 50 percent of the water required for an oil
shale plant is expected to be used for moisturizing of retorted shale.
Much of this water requirement will be supplied by minewater and process
52
-------
wastewaters. Because of the large quantities of water utilized and the
exposure of retorted shale to rain and snowfall, a source of indirect
water pollution may occur via leaching or run-off from retorted shale
piles. However, the bulk of the water applied to retorted shale is ex-
pected to be held in capillarity or to be bound as simple hydrates. The
suspended and dissolved constituents of wastewaters applied to retorted
shale are expected to be partially immobilized by physical adsorption
and/or chemical reaction with retorted shale. Leaching experiments in
the laboratory and with small plots indicate that inorganic salts - Na,
Mg, SO., Cl - may be leached from retorted shales. Small quantities of
organic substances and trace elements are also water soluble.
Regulatory Impacts
Each oil shale technology and resulting commercial implementation
will have to be evaluated separately as to regulatory impacts. Because
of the differences in technologies and in state and local regulations,
siting of a major oil shale facility must be addressed on a case-by-case
basi s.
The oil shale industry must comply with regulations and standards in-
cluding requirements of the Clean Air Act, the Clean Water Act, the Safe
Drinking Water Act, the Resource Conservation and Recovery Act, the Toxic
Substances Control Act, the Federal Nonnuclear Energy Research and Devel-
opment Act, and the National Environmental Policy Act as well as applic-
able State laws.
Undoubtedly, the oil shale industry will benefit from the experience
of the petroleum industry in dealing with complex organic substances and
new processes while complying with governing statutes.
9.5 Performance
Current
Even though an estimated heat balance (for a given process) and
thereby an efficiency value is provided, it should be recognized that,
currently, there are no commercial scale shale oil extraction and proces-
sing facilities in the United States. There have been some small scale
experimental efforts and small scale demonstration of some process ele-
ments (e.g., a specific retort). Therefore, there are no performance
values that can be applied to a commercial scale plant.
Projected
It is difficult to provide confident estimates of operating efficien-
cies of future shale oil facilities. In this regard, a given shale oil
project could have various efficiency values depending on the specific
53
-------
definition. Efficiency values could be based on energy contained in re-
sources in place or on the energy content of the shale into the retort-
ing facility. In addition, efficiency values will depend on what system
input and product output energy components are considered.
9.6 Economics
Current
There are no commercial scale oil shale processing facilities cur-
rently in operation in the United States.
Projected
The oil shale companies themselves are aware of the technological
and economic uncertainties. One company recently stated that no one
really knows what any of the available oil shale technologies will do or
what they will cost in dollars per barrel until plants are built and
operating and cost data collected (1). Even though there is consider-
able uncertainty, reference 10 does contain an assessment of economic
and financial considerations.
I 54
-------
References - Surface Oil Shale Processing
1. State of Colorado. Colorado Oil Shale: The Current Status,
October, 1979. Department of Natural Resources for the U.S.
Department of Energy, 1979.
2. U.S. Department of Interior. Shale OiI - A Chapter from Mineral
Facts and Problems, 1975 Edition. Bureau of Mines, preprint
from Bui let in 667, 1975.
3. U.S. Environmental Protection Agency. Oil Shale and the Envi-
ronment. Office of Research and Development, EPA-600/9-77-033,
Washington, D.C., October 1977.
4. U.S. Department of Energy. Candidate Shale Oil Projects. As-
sistant Secretary for Energy Technology, Washington, D.C.,
January
5. U.S. Environmental Protection Agency. Technological Overview
Reports for Eight Shale Oil Recovery Processes. Industrial
Environmental Research Laboratory, EPA-600/7-79-075, Cincinnati,
Ohio, March 1979.
6. University of Oklahoma. Energy Alternatives: A Comparative
Analysis. The Science and Public Policy Program, University of
Oklahoma, Norman, Oklahoma, May 1975.
7. Denver Research Institute, et al. Material and Energy Balance
for the Retorting Section of the Colony Development Operation.
Prepared for the U.S. EPA/ORD-IERL, Cincinnati, Ohio, March 1980
8. U.S. Department of Energy. Commercialization Strategy Report
for Oil Shale. Prepared by U.S. DOE Task Force on Oil Shale,
Washington, D.C., 1979.
9. U.S. Department of Energy. Environmental Readiness Document -
Oil Shale. Assistant Secretary for Environment, DOE/ERD-0016,
Washington, D.C., September 1978.
10. Chevron Research Company. An Assessment of Oil Shale Tech-
nologies. Prepared for the Office of Technology Assessment,
Congress of the United States, OTA-M-118, Washington, D.C.,
June 1980.
155
-------
10. In Situ Oil Shale Processing
10.1 Overview
The oil shale resources in the United States probably exceed two
trillion barrels of petroleum and of this amount 25 to 35 percent is pres-
ently projected as being commercial. Most oil shale of projected commer-
cial grade contain 20 to 50 gallons of oil per ton of rock. A large por-
tion of the United States shale resource is in the 10 to 20 gallons of
oil per ton of rock range. An insignificant amount of the resource base
contains as much as 125 gallons per ton (1).
The most extensive high-grade deposits of domestic oil shale are in
the Rocky Mountain Region in the Green River Formation primarily in Color-
ado, Utah, and Wyoming, on land which is mostly in the public domain (2).
The two major routes for exploiting oil shale resources are:
1) Conventional mining followed by surface proces-
sing, and
2) In situ (in place processing).
In addition, there is modified in situ. Modified in situ involves remov-
ing some of the shale (e.g., by conventional mining) to increase the void
volume in order to enhance the in situ processing. In modified in situ,
recovered shale (i.e., via conventional mining) can be surface processed.
This section addresses in situ retorting (including modified in
situ). True in situ processes involve (1) formation fracturing via ver-
tical well bores to create permeability without mining or removal of
material followed by undergound retorting and (2) underground retorting
via well bores utilizing natural permeability where it may exist. No
underground material is removed by any means to create additional void
space for fracturing or rubbling except by the driI Iing/underreaming
process (3).
The modified in situ process involves mining or removing by some
other means (such as leaching or underreaming) up to 40 percent of the
shale (i.e., in the retorting sector) so the void volume and permeabil-
ity can be increased before retorting. The remaining oil shale is then
explosively fractured into the void volume and combustion or hot-gas
retorted. In the case of leached shale, the shale is not fractured,
but hot-gas retorted. The mined shale fraction can be surface retorted
(3, 4).
Currently, a number of in situ processes are receiving attention
with a goal of demonstrating a viable commercial capability. The com-
mercial scale development and degree of product market penetration will
depend on numerous factors. These include:
156
-------
1) The demonstration of a modern, viable commercia
sea e technology^
2) The ability to satisfy environmental concerns, and
3) The ability to produce an acceptable product at
an acceptable price.
In this regard there are many unknowns. These range from the abi
ity to acquire a viable in situ technology to achieving an acceptable
environmental status. It is expected that the cost to produce a barre
of shale oil from an in situ process would be less than for a surface
retorted process (i.e., assuming the achieving of a viable technology)
10.2 Process Description
Concept
Oil shale is a marl, a variety of limestone laced with organic mat-
ter (hydrocarbon) known as kerogen. Kerogen is a complex material com-
posed mainly of carbon, hydrogen, oxygen, sulfur, and nitrogen. The
kerogen molecule is large and heavy. Heating breaks the chemical network
holding the heavy kerogen molecules together and "cracks" the individual
large molecules into smaller molecules. This releases liquid hydrocarbon,
some combustible gases, and a coke-like residue. It is the liquid hydro-
carbon mixture, the shale oil, that is the most valuable (4).
the
In "true" in situ processing, a central well is first
bed of shale. Several other wells are then drilled in
drilled into
a pattern
around the central well. Explosive charges are placed in the we
detonated to fracture the surrounding shale. Sometimes the shale is
Is and
fractured by pumping water into the we I s under
This
fracturing process is necessary to create pathways (void spaces) in the
impermeable shale so as to permit heat transfer. For a given
about 50 o of the shale volume has to contain void spaces
take place to decompose the kerogen
norma
in situ site,
for enough combustion to
very high pressure.
(void spaces)
(4)
Once the shale is fractured, it is ignited by a flame from compressed
air and a combustible qas pumped into the central well. The hot combus-
tion gases circulate along the pathways in the fractured shale, heating
it to retorting temperatures and releasing the gas and oil from the kero-
gen. After a few hours, the external ly-fed gas is shut off, but com-
pressed air continues to be fed to the burn zone where combustion is
sustained by the carbon residue that remains as the shale is retorted (4).
The gas produced in the retorting process is withdrawn from a well
down-stream from the central injection well. Some of this gas is recir-
culated to the central well to aid combustion. The vapor produced in
-------
in situ retorting condenses to liquid in a sump at the base of the shale
area and is pumped to the surface.
In a "modified" version of in situ recovery, 20 to 40% of the lower
portion of the shale bed is first mined (by conventional methods) or
otherwise removed. This leaves a void space beneath the shale. The
shale is then fractured with explosives, filling the mined-out space with
shale rubble. The rubble column is ignited, retorting the shale in place,
as in the "true" in situ method, to produce gas and oil. The shale ex-
tracted (e.g., by conventional methods) can be retorted by conventional
surface processes.
The oil from in situ processing has essentially the same character-
istics as the oil retorted on the surface and has to be processed to re-
move impurities before being used as refinery feedstock (4).
Deta i I s
True In Situ (5)
The true in situ shale oil recovery process is characterized by
fracturing techniques that require no mining or removal of major amounts
of oil shale. The fractured oil shale bed can be retorted by two general
methods. The shale can be ignited at the bottom of the injection well
and combustion sustained by air injection, in which case hot combustion
gases retort the shale. In some cases, it is advantageous to supplement
the air supply by injecting propane, recycled gas or some other fuel to
enhance combustion. In the second method, energy for retorting the shale
can be supplied by injecting heated gases. The gases considered for use
in this process are steam, natural gas, nitrogen, and others.
In either method, products of retorting are recovered from the pro-
duction well. Liquid products collected in the bottom of the well can be
pumped to the surface. Liquid entrained in the exit gas stream can be
separated and collected on the surface. Depending on the heating value
of the gas stream, it can be used as recycle gas, burned as a source of
fuel on the surface, or discarded through a flare to prevent pollution.
The true in situ concept is indicated by Figure 35. This concept of pro-
cessing oil shale is most likely to be applied to shales deposited in
thin beds, possibly interspersed with barren rock.
Mod if led In Situ
The difference between these processes and true in situ retorting
methods is that between 20 and 40 percent of the oil shale or other min-
erals are mined or otherwise removed from within the retort to provide
the void space for enhanced permeability when the remaining shale is
rubblized, as previously discussed. If mined shale is oil rich, it will
158
-------
r
COMPRESSED AIR
INJECTION WELL
OIL. WATER. AND GAS -«-.
PRODUCTION WELL h.
OVERBURDEN
u.
— "W —
0
w" 2000-r
cc
D
h-
I 1500-
UJ
a.
5
H 1000-
UJ
1-
<
1 500-
X
O
CC
i 0-
FRACTURED
SHALE ZONE
.^4
1
I
\
/
V
/
*
~^- TXJ-
1 1
' ^ - - . -
^".~ ' ^ ' . ' ^-_~T
- — - - . ^ — -^_ "f~ — ^~f—
~-~_^--^~- . '
— *- ^^| '^|\ .' CFRONT MOVEMENT ^ '^" » -'
/ ' , \ -'r^ :.^f 7"
/ 1 ' i ' Y" ^--~":: -i^-~
- —^7; ." ^^^ — ' _ -
'-^"-^ ^r^r*"-
— *• / | 1 VCOMBUSTION GASES, OIL. AND WATER
- / ! • ! ; -^ "•?^^M- "^
/EXPECTED ' | r^^'.-.-^V-"^"-
X TEMPERATURE , 1 ^ -~- •'" ^ - r_ ^I-
' PROFILE | ^CT^; V ^r C-_
^^- ' I | ^^^ ^.^1~- Xt— '
1 Ll^~— ^^ "" — "" ~^>1~™"
I ^ —
1 ^~~ -^~~~
BURNED-OUT ZONE ^Jo^ljBU^
ZONE
< . .Jd . — ».
RETORTING ZONE
'^r^-^-r7- -:
"~ •~-''^X.~ - •• ^ .. • - - ^
" — ~—"-^-^— -" — — S-"
^.__^ — - — " ~ —
~^~-~^ — — ^ — " ^"
^___^~'^I^^^^-r_^ '^^
^ ^ ' -~^~- —
OIL. WATER. AND
GAS DRIVE ZONE
KX
»
'
\
i
4
^
^
-^^^
—
•— —
—
Jl
^
-
*"
_;
— ^
-^
—
Figure 35
True In Situ Retorting
be sent to surface retorting; but if it is low-grade shale, it will prob-
ably be discarded. This can greatly influence mine designs and detailed
development plans. Wells are drilled and prepared prior to fracturing
the shale. After the oil shale is fractured through explosive techniques,
a porous medium remains and retorting is begun.
Four general concepts of modified
ified (5):
in situ techniques can be ident-
1) Vertical modified in situ with partial mining in
which the relative dimensions of the retort are
larger in the vertical direction than in the hori-
zontal, such as a column.
2) Horizontal modified in situ with partial mining in
which the relative dimensions are larger in the
horizontal direction than in the vertical, such as
a bed.
3) Modified in situ retorting of a zone in which min-
erals contained in the shale have been removed by
naturally occurring groundwater (leached zone in
Colorado) or by solution mining.
159
-------
4) Horizontal modified in situ retorting of a rubblized
oil shale bed that has been prepared by explosive
detonation resulting in noticeable surface uplift.
Modified techniques that require partial mining followed by massive
rubblization are believed to offer the most promise for deeper and very
thick shale deposits. In these deposits the vertical configuration is
most useful. A horizontal technique will be more useful in somewhat thin-
ner deposits or as a secondary recovery method in a previously worked
mi ne (5).
Collected crude oil must be processed to remove water and other con-
taminants and then further upgrading (e.g., removal of deleterious mate-
rials and viscosity alteration) before pipelining and before entering
conventional refinery streams.
A number of modified in situ processes are currently receiving sub-
stantial attention with a goal of demonstrating a viable commercial capa-
bility. These include (4, 6):
1) The Occidental Oil Company's "modified" vertical
in situ process in which a rubbled column of broken
shale is retorted to produce oil and a combustible
gas.
2) The Rio Blanco modified in situ method involves
mining out a relatively large underground retort
void space. After removal of the material from
underground, the retort is rubblized and burned to
produce oil. The mined-out material is surface
retorted.
3) The Geokinetics process in which oil shale is
extracted possibly from oil shale beds under rel-
atively thin overburden using a horizontal modified
in situ technique.
Details on the Occidental modified in situ process follow (7):
The Occidental modified in situ shale oil recovery scheme is covered
by a U. S. Patent. The system was tested in excess of one year in a com-
mercial size in situ retort with a total production in excess of 27,000
barrel s of crude oil.
The modified in situ process for shale oil recovery consists of re-
torting a rubblized column of broken shale, formed by expansion of the
oil shale into a previously mined out void volume. The process involves
three basic steps. The first step is the mining out of approximately 20
to 25% of the oil shale deposits (preferably low grade shale or barren
160
-------
rock), either at the upper and/or lower level of the shale layer. This
is followed by the drilling of vertical longholes from the mined-out room
into the shale layer, loading these holes with an ammonium nitrate-fuel
oil (ANFO) explosive, and detonating it with appropriate time delays so
that the broken shale will fill both the volume of the room and the volume
of the shale column after blasting. Finally, connections are made to both
the top and bottom and retorting is carried out (Figure 36).
i OIL RECOVERY
RECYCLE GAS '
COMPRESSOR
, FUTURE RETORT
' CENTER SHAFT
AIR MAKEUP*
COMPRESSOR
iOo-«-.--^
.°A ..".OIL SHALE RUBBLE,
-
SOIL SUMP AND PUMP
Figure 36
Occidental Oil Shale Process Retort Operation
In the Occidental scheme, both the size of the retorting chamber and
the thickness of the walls have an important impact on the fraction of
the cross section of the shale formation available for retorting. With
161
-------
40 feet thick walls, the cross section of the shale formation available
for retorting would be 56$ for 120-ft square retorting chambers and
for 160-ft square retorting chambers. With 20 feet thick walls, the
cross section of the shale formation available for retorting would be
for 120-ft square retorting chambers and 19% for 160-ft square retorting
chambers. Thus large retorting chambers and thin walls are necessary for
the optimum recovery of oil shale resources (i.e., for the Occidental
concept).
Assuming that 20$ of the rock is mined-out to create the void volume
necessary for subsequent rubbl ization, a 120 ft x 120 ft x 250 ft commer-
cial size retort could yield 50,584 barrels of crude shale oil, at 65%
retorting efficiency and for 15 gpt shale. The results from the Occiden-
tal experiments indicated a retort burn rate of 0.54 in/hr, thus the
production period of a 250 ft high retort is 232 days and the production
rate of crude shale oil from a commercial size retort is 218.5 barrels
per day CBPD). Two hundred and twenty-nine retorts would be required to
operate simultaneously to produce 50,000 BPD of crude shale oil if the
average Fischer assay of the shale zone is 15 gallons per ton (gpt). For
a shale zone with an average Fischer assay of 25 gpt, a minimum of 149
retorts would be required if the production goal of 50,000 BPD of crude
shale oil were to be realized.
In the construction of the commercial size retort, Occidental plans
mining at two levels. The upper mining level will be a complete heading
at or near the top of the retort, and wi I I serve as.a base from which
vertical longholes will be drilled for the loading of explosives. In the
retorting process, combustion air will be supplied through the heading.
In the Occidental modified in situ process, retorting is initiated
by heating the top of the rubblized shale column with the flame formed
from compressed air and an external heat source, such as propane or nat-
ural gas. After several hours, the external heat source is removed and
the compressed air flow is maintained, utilizing the carbonaceous residue
in the retorted shale as fuel to sustain air combustion. In this verti-
cal retorting process, the hot gases from the combustion zone move down-
wards to pyrolyze the kerogen in the shale below that zone, producing
gases, water vapor, and shale oil mist which condense in the trenches at
the bottom of the rubblized column (Figure 37). The oil production pre-
cedes the advancing combustion front by 30 to 40 ft. The crude shale
oil and by-product water are collected in a sump and pumped to storage.
The off-gas is composed of gases from shale pyrolysis, carbon dioxide
and water vapor from the combustion of carbonaceous residue and carbon
dioxide from the decomposition of inorganic carbonate (primarily dolo-
mite and calcite). Part of this off-gas is recirculated to control the
oxygen level in the incoming air and the retorting temperature. The
off-gas has a heating value of approximately 65 Btu/scf. The part of
the off-gas not recycled will be burned in a turbine for electric power
generation after hydrogen sulfide removal by the Stretford process.
162
-------
AIR AND RECYCLE GAS
BURNED OUT ZONE
GAS
-- ^'• xl~"p •- —
'^-^COMBUSTION ZONE^RONT .
*--^- v,- .<----.-"-MOVEMENT
RETORTING AND VAPORIZATION ZONE
VAPOR CONDENSATION ZONE
GASES, OIL, AND WATERi
I I i I J
PILLAR
PILLAR -
OIL AND WATER
Figure 37
Flame Front Movement in the Occidental Modified In Situ Process
According to Occidental's estimate, only 20 to 25% of the electric
power produced from the low-Btu gas is required for operating the modi-
fied in situ process. The minimum treatment required for the crude shale
oil produced from the retorting process will include phase separation of
the oil from the by-product water and the stabilization of the oil prod-
uct. The wastewater effluent from the phase separator may be used for
steam generation after appropriate treatment.
the Occidental process has
25 ), a pour point of 70 F,
'
The crude shale oil produced from
cific gravity of 0.904 (API gravity of
sulfur content of 0.71 weight percent and a nitrogen content of 1
weight percent. The crude shale oil is reportedly free of solids
may be used directly as boiler fuel.
a spe-
a
50
and
163
-------
Reference 8 contains an estimated energy balance for the retorting
sections of an Occidental modified in situ plant. The provided energy
balance covers both in situ and Lurgi surface retorting. The Lurgi
retorts handle the approximate 20 percent of the oil shale removal from
the modified in situ retorts before rubblization by explosives. In addi-
tion, a few additional percent of oil shale from development passageways
will also be sent to the Lurgi retorts. The shale oil retorted both
ways will be 25 gallons per ton average grade. Low-Btu gas produced by
retorting will be used to generate steam and to produce electricity by
gas turbine driven generators. An estimated heat balance based on ref-
erence 8 for both in situ and Lurgi retorting is given by Table 22.
This can be represented diagrammaticaI Iy by Figure 38. As indicated,
Table 22 and Figure 38 cover the retorting sections of the plant only.
The energy balance is for a plant producing 111,111 barrels of shale oil
per stream day (BPSD). This results from 68,000 BPSD from in situ re-
torting and 32,000 BPSD from conventional (i.e., surface) retorting.
10.3 Applications
Current
Shale oil has been produced commercially for various periods of
time in eleven countries since the initiation of shale oil operations
in France in 1838. In Canada and the Eastern United States, a very small
industry was operating in 1860 but disappeared when petroleum became plen-
tiful. Currently, the only commercial production is in Russia (Estonia)
and China with a combined production of approximately 150,000 barrels per
day. All other shale industries (i.e., in other countries) succumbed be-
cause of the inability to compete with petroleum fuels. All production
to date has generally occurred in retorts that would be considered of
commercial size for U. S. operations (9).
Projected
The successful development and demonstration of a commercial scale
shale oil production technology would provide a valuable alternative for
the acquisition of liquid fuels. The ability to produce oil from oil
shale would provide the potential means to produce liquid fuels from our
vast shale oil resources and thereby reduce our dependence on imported
and domestic petroleum products. The commercial scale development and
future use of an oil shale technology are dependent on many factors.
These incIude:
1) The demonstration on a commercial scale of a
viable technology,
2) The ability to satisfy environmental concerns, and
3) The ability to produce a commercial product at
an acceptable cost.
164
-------
Table 22
Estimated Energy Balance for the Retorting
Sections of an Occidental Modified In Situ
Plant from 35 Gallons Per Ton Oil Shale
(68,000 BPSD* In Situ and
32,000 BPSD Surface Retorted)
10
MIS
Product Output
Product oi I 16.91
Retort gas** 10.56
Recovered heat
System Losses
Retorted shale 8.78
Fl ue gas
Miscellaneous losses 1.34
Energy Input 37.59
Raw shale 35.44
Steam 1.94
Electrical energy 0.21
9
Btu per
Surface
7
0
0
0
0
0
10
10
0
.82
.97
.44
.43
.15
.21
.02
.01
—
.01
hour
Comb
24
11
0
9
0
1
47
45
1
0
Percent of Tota I
i ned
.73
.53
.44
.21
.15
.55
.61
.45
.94
.22
Energy
51 .
24.
0.
19.
0.
3.
100.
95.
4.
0.
i nput
94
22
92
34
32
26
0
46
08
46
* BPSD = barrels per stream day
** Low-Btu gas that can be used at site (e.g., to generate
eIectric i ty)
I 65
-------
•100? Energy input
94.46?
From raw shale
19.34?
Retortedx
sha le
51.94? —
Product oi
•4.54?
From steam
and electricity
'3.26?
Misc. losses
= 0.32?
Flue gas
-25.14?-*-j—Retort gas and
heat
Total
77.08?
energy out
Figure 38
Estimated Energy Balance Schematic for the Retorting
Sections of an Occidental Modified In Situ Plant
The most significant problems and uncertainties are associated with
impacts on air and water quality, waste management, occupational health
and safety aspects, and the cost to produce a marketable commodity.
10.4 Environmental Considerations
The Environmental Protection Agency, the Department of Energy, other
governmental agencies, and other groups are studying environmental as-
pects of producing oil from shale. Currently, there remain a number of
unanswered environmental questions. It may not be possible to provide
166
-------
a meaningful environmental determination until experience with one or
possibly more operating plants is acquired. The technologies are just
too new, the affected ecologies are not well understood, and the scale of
operation is too massive to be able to predict (with a reasonable degree
of confidence) the effect of an oil shale industry. In addition, envi-
sioned environmental controls for the oil shale industry are subject to
large uncertainties.
The most significant problems and uncertainties are associated with
impacts on air and water quality, waste management, and occupational
health and safety aspects.
Identified Pollutants (9)
Air Emissions
Atmospheric emissions can arise from several activities or oper-
ations during oil shale processing. The major source of SO,,, NO , and
CO is fuel combustion for process heat; S0? is also emitted in tne tail
gases of sulfur recovery operations. The use of fuel oils in mobile
equipment and in explosives will result in emissions of CO and NO .
Hydrocarbons are present in both combustion emissions and in product
storage tank vapors. Emissions of particulate matter can result from
blasting, raw and spent shale handling and disposal, raw and spent shale
dust in process gas stream, fuel combustion, and site activities which
generate fugitive dust.
Emissions of potentially hazardous substances may occur during the
extraction and processing of oil shale. Silica (quartz) may be present
in dust derived from oil shale and associated rocks and in fugitive dust.
Particulate emissions from fuel combustion and fugitive dust from spent
shale handling and disposal can contain' polycyclic organic material (POM)
and certain trace metals. Gaseous ammonia, hydrogen sulfide, and vola-
tile organics may be released during moisturizing and subsequent cooling
of retorted shale. Catalyst materials may release particulate matters
containing trace metals to the atmosphere during regeneration, handling,
or f i naI d isposaI.
Generally, the retorting operation itself does not involve atmos-
pheric emissions; gaseous, liquid, and solid streams leaving the retort
are handled by downstream systems before reaching an atmospheric inter-
face. However, certain features inherent in the retorting method influ-
ence the nature and magnitude of emissions from other sources in the
associated shale oil plant.
Sulfur in raw oil shale amounts to about 0.7 percent by weight, ap-
proximately one-third associated with the organic fraction; and two-
thirds as pyrite (Fe~S). During kerogen pyrolysis, about 40 percent of
the organic sulfur in shale appears as H-S in the produced gases, and
167
-------
the other 60 percent as heavier sulfur compounds in raw shale oil and in
the spent shale carbonaceous residue. Pyritic shale sulfur does not
decompose under nonoxidizing retorting conditions.
Actual S0? emissions associated with individual retorting processes
will depend upon the degree of sulfur removal accomplished for in-plant
fuels, the extent of on-site shale oil processing, and the degree of con-
trol applied to sulfur recovery tail gases. Combustion of any hydrocar-
bon fuel will produce oxides of nitrogen when air containing nitrogen is
used as the source of oxygen. In addition, organic nitrogen contained
in fuel can be partially oxidized to NO and NO--
The feed to a surface retorting plant always presents a particulate
control problem. Run-of-mine raw shale commonly contains about five
weight percent of ore of less than ^-inch size. A sizable percentage of
this segment will become minus 100-micron particulate as a result of pri-
mary crush i ng.
Emissions of HCs and CO occur during incomplete combustion of fuels
in process heaters and in mobile equipment. Hydrocarbons may also be
vaporized during product storage. Equipment use and evaporative hydro-
carbon emissions are not expected to be process specific.
The largest source of CO in an oil shale operation is mobile equip-
ment used for mining and transport. The quantity of such emissions is
a function of mining method and haul distances rather than retorti.ng
process.
The pyrolysis of essentially any type of organic material produces
a certain amount of POM, and oil shale kerogen is no exception. Gen-
erally, POM compounds have a low volatility and will be associated with
high boiling liquid or solid products of particulate matter. It should
be noted, that although POM is known to be present in carbonaceous re-
torted shales, the biological availability and potential hazard of such
material is not accurately known at present.
Release of POM to the atmosphere during oil shale processing can
occur via three major pathways:
(1) Handling and disposal of retorted shale,
fugitive particulates and possible volatil-
ization of hydrocarbons;
(2) Combustion of shale derived oils containing
POM; and
(3) Flue gases containing entrained retorted
shale particulates, along with retort gas or
spent shale coke combustion products.
-------
Oil shale contains trace amounts of many elements. However, for
elements other than Si, Fe, Al, Ca, Mg, Na, and K, the concentrations in
oil shale are less than generally found in coal. In addition, conditions
during retorting are not severe enough to volatilize most metallic and
heavy elements. With notable exceptions such as arsenic (As) and possi-
bly antimony (Sb), most trace elements (e.g., nickel (Ni), vanadium (V),
molybdenum (Mo)) remain with the spent shale, or are found as components
of raw and spent shale solids entrained in retort gases and in raw shale
oil. Arsenic in raw shale apparently forms a range of volatile oil sol-
uble compounds (perhaps organic arsines) during retorting, and appears
in raw shale oil and all condensible oil fractions. If not removed dur-
ing upgrading, arsenic will be present in shale oil combustion products.
Actual emissions of nonvolatile trace elements are anticipated in
approximate proportion to raw and retorted shale particulate emissions
for an oil shale extraction and retorting operation. Such emissions may
not be different in nature or magnitude from those associated with the
extraction and processing of other fuel and nonfuel minerals (coal, lime-
stone, phosphate rock, etc.). Further, the dolomitic and/or alkaline
nature of shale immobilized many elements as relatively inert oxide,
carbonate, or silicate salts.
Metals (Ni, Co, Mo, Cr, Fe, Zn) and their compounds are used as cata-
lysts for hydrotreating, de-arsenating, sulfur recovery, and trace sulfur
removal. Emissions of particulate matters containing catalyst metals can
occur either during on-site regeneration of during handling and disposal.
Cata yst use is not unique to shale oil processing, and much information
and experience in preventing hazardous emissions can be borrowed from the
petroleum and related industries.
Solid and Liquid Effluents
The surface retorted shale from a modified in situ process can be a
major problem. Surface retorted shale occupies a greater volume than the
original shale and contains varying quantities of organic and inorganic
residuals. The nature of these are dependent on many factors including
process, site and climatic variables.
Aqueous wastes from oil shale processing can be broadly categorized
as originating from direct or indirect sources. Direct sources are waste-
waters generated from unit operations and/or processes, including waste-
water from retorting operations; wastewater from upgrading operations;
water from air emission control and gas cleaning systems; cooling water
and boiler water blowdowns; water treatment systems; mine dewatering
wastewater; and sanitary wastewaters. Indirect sources include: leach-
ate from retorted shale disposal areas; run-off and erosion resulting
from construction and site use activities; and run-off from mining and
transport activities.
169
-------
Water is a direct product of oil shale retorting, resulting trom the
release of free and inorganically bound water from raw shale, and combus-
tion of organic material in shale. From 1 to 8 gallons of water are com-
monly produced per ton of input shale feed to a surface retort, depending
on the retorting process and the composition of the shale processes. In
situ process demonstrations have reportedly produced even greater amounts
of water. Some water condenses with crude shale oil during separation of
the oil from retort gases. This water can separate partially from crude
shale oil during storage, or can appear in aqueous waste streams of shale
oil upgrading operations. Water remaining in retort gases after oil sep-
aration can be condensed during cooling or gas cleaning operations, or
can appear in the flue gas stream from retort gas combustion. Water
separated from crude shale oil contains mainly ammonia, carbonate and bi-
carbonate, sodium, sulfate, chloride, and dissolved or suspended organic
compounds (phenolics, amines, organic acids, hydrocarbons, mercaptans).
Smaller quantities of calcium, magnesium sulfides, and trace elements may
also be present, along with suspended shale fines. Water condensed from
retort gases contains primarily ammonia and carbonates, with traces of
organic substances and sulfur containing compounds. In particular, it
should be noted that in situ and modified in situ retorting will result
in various liquid, solid, and gaseous products being left in the retort
zone. Their effect on aquifiers due to disruption and leaching is not
known.
The quality of wastewater from an upgrading operation varies with
the level of on-site upgrading or refining utilized. In general, a full-
scale refining operation may include any of the following wastewater
streams: oily cooling water, process water, and wash water.
Wastewaters are also collected during retort gas cleaning, tailgas
cleanup, and foul water stripping. Major constituents in such waters
are shale dust particulates, hydrocarbons, HLS, NH,, phenols, organic
acids, and amines. Other constituents such as thiosulfate and thiocyan-
ates may also be present.
Cooling water is used in retorting and oil upgrading to absorb heat
which cannot be economically recovered for use in the complex or absorbed
by air fan coolers. Cooling water is generally circulated through a wet
cooling tower system to release this heat to the atmosphere. Because of
evaporative losses, there is a constant buildup of dissolved solids which
requires a portion of this recirculated water to be discharged as a blow-
down from the cooling water system. Similarly, a fraction of the boiler
water must be discharged as blowdown to minimize scaling of boilers.
Both the cooling water and the boiler blowdown waters contain a high con-
centration of dissolved solids, and substances such as hexavalent chro-
mium used for corrosion control.
Good quality water is needed to supply processing, cooling tower,
steam generation, and other miscellaneous process uses. Wastes from
170
-------
water treatment systems generally consist of chemical sludges, backwash
water from filtration system and blowdown from zeolite softening systems.
The largest quantity of waste is lime sludge which is characterized by
high hardness and dissolved salts content.
An appreciable amount of the water required for an oil shale plant
is used for moisturizing of retorted shale. Much of this water require-
ment will be supplied by minewater and process wastewaters. Because of
the large quantities of water utilized and the exposure of retorted shale
to rain and snowfall, a source of indirect water pollution may occur via
leaching or run-off from retorted shale piles.
Construction, mining, and site use activities may potentially result
in increased sediment and dissolved solids loading in surface run-off and
receiving streams. This indirect source of potential water pollution is
not unique to oil shale extraction and processing but may require careful
control due to the magnitude of site activities.
Regulatory Impacts
Each oil shale technology and resulting commercial implementation
will have to be evaluated separately as to regulatory impacts. For exam-
ple, the nitrogen content of the product shale oil will be higher than in
coal or petroleum derived fuels and may result in unattractive NO levels
upon combustion. Because of the differences in technologies and in state
and I oca regulations, siting of a major oil shale facility must be ad-
dressed on a case-by-case basis.
The oil shale industry must comply with regulations and standards
including requirements of the Clean Air Act, the Clean Water Act, the
Safe Drinking Water Act, the Resource Conservation and Recovery Act, the
Toxic Substances Control Act, the Federal Nonnuclear Energy Research and
Development Act, and the National Environmental Policy Act as well as
applicable State laws. Failure to comply has the potential of halting
all progress toward commercialization (10).
Undoubtedly, the oil shale industry will benefit from the experience
of the petroleum industry in dealing with complex organic substances and
new processes while complying with governing statutes.
10.5 Performance
Current
Even though an estimated heat balance (for a given process) and
thereby an efficiency value is provided, it should be recognized that,
currently, there are no commercial scale shale oil extraction and proces-
sing facilities in the United States. There have been some small scale
171
-------
experimental efforts and small scale demonstrations of some process ele-
ments (e.g., a specific retort). Therefore, there are no performance
values that can be applied to a commercial scale plant.
Projected
It is difficult to provide confident estimates of operating efficien-
cies of future shale oil facilities. In this regard a given shale oil
project could have various efficiency values depending on the specific
definition. Efficiency values could be based on energy contained in re-
sources in place or on the energy content of the shale into the retorting
facility. In addition, efficiency values will depend on what system in-
put and product output energy components are considered.
10.6 Economics
Current
There are no commercial scale oil shale processing facilities cur-
rently in operation in the United States.
Projected
The oil shale companies themselves are aware of the technological
and economic uncertainties. One company recently stated that'no one
really knows what any of the available oil shale technologies will do or
what they will cost in dollars per barrel until plants are built and
operating and cost data collected (1). Even though there is consider-
able uncertainty; reference 11 does contain an assessment of economic
and financial considerations.
172
-------
References - In Situ Oil Shale Processing
1. State of Colorado. Colorado Oil Shale: The Current Status,
October, 1979. Department of Natural Resources for the U.S.
Department of Energy, 1979.
2. U.S. Department of Interior. Shale Oi I - A Chapter from Mineral
Facts and Problems, 1975 Edition. Bureau of Mines, preprint
from Bui let in 667, 1975.
3. U.S. Department of Energy. Environmental Development Plan
(EDP) - Oil Shale. Assistant Secretary for Environment, DOE/
EDP-0051, Washington, D.C., November 1979.
4. U.S. Environmental Protection Agency. Oil Shale and the Envi-
ronment. Office of Research and Development, EPA-600/9-77-033,
Washington, D.C., October 1977.
5. U.S. Department of Energy. Fossil Energy Program Summary
Document. Assistant Secretary for Energy Technology, DOE/ET-
0087, Washington, D.C., March 1979.
6. U.S. Department of Energy. Candidate Shale Oil Projects. As-
sistant Secretary for Energy Technology, Washington, D.C.,
January 1980.
7. U.S. Environmental Protection Agency. Technological Overview
Reports for Eight Shale Oil Recovery Processes. Industrial
Environmental Research Laboratory, EPA-600/7-79-075, Cincinnati,
Ohio, March 1979.
8. Denver Research Institute, et al. Material and Energy Balance
for the Retorting Sections of the OXY In Situ System with Lurgi
Surface Retorts. Prepared for the U.S. EPA/ORD-IERL, Cincinnati,
Ohio, Apri I 1980.
9. U.S. Department of Energy. Commercialization Strategy Report
for Oil Shale. Prepared by U.S. DOE Task Force on Oil Shale,
Washington, D.C., 1979.
10. U.S. Department of Energy. Environmental Readiness Document -
Oil Shale. Assistant Secretary for Environment, DOE/ERD-0016,
Washington, D.C., September 1978.
11. Chevron Research Company. An Assessment of Oil Shale Tech-
nologies. Prepared for the Office of Technology Assessment,
Congress of the United States, OTA-M-118, Washington, D.C.,
June 1980.
73
-------
11. Direct Coal Liquefaction
11.1 Overview
Coal liquefaction is an emerging coal conversion alternative that
holds promise for near-term commercialization allowing greater utiliza-
tion of the nation's coal reserves. The liquid products that are pro-
duced vary with the type of process and the rank of the coal that is
utiI ized.
Coal liquefaction processes can be classified into four types -
direct hydrogenation, solvent extraction, pyrolysis, and indirect lique-
faction. In direct hydrogenation, hydrogen is added cataIyticaI Iy to
coal in a reactor under high pressure and temperature resulting in vapor
and liquid phases which are cooled to separate the products, refined to
remove by-products and, depending on the fuel product desired, further
processed. In solvent extraction, a solvent is used as a hydrogen carry-
ing agent to promote liquefaction under high temperature and pressure to
produce the liquid fuels, after purification. In pyrolysis, crushed
coal, thermally decomposed in the absence of oxygen, yields solids (char),
liquids and gases. In indirect liquefaction, the coal is first gasified
to make a synthesis gas and then passed over a catalyst to produce alco-
hols (methanol) or paraffinic hydrocarbons.
Direct hydrogenation, solvent extraction, and pyrolysis are classi-
fied as direct liquefaction processes. In the United States, some of the
direct liquefaction processes receiving attention as having a potential
for commercialization are H-CoaI (direct hydrogenation), and Solvent
Refined Coal and Donor Solvent (solvent extraction).
Research and development of coal liquefaction processes has been
underway for many years. The first practical uses of coal-derived
liquid fuels were about 1790 when the fuels were used for experimental
lighting, heating, and cooking. During World War II, Germany produced
liquid fuels from coal in industrial amounts via both direct and indirect
liquefaction. Since then, coal liquefaction plants have been constructed
in a number of countries but only one plant in Sasol, South Africa is
still producing liquids from coal (via indirect liquefaction). Commer-
cial demonstration of coal liquefaction has never been accomplished in
the United States. Current U. S. activities are limited to research and
development and pilot plant programs.
Environmental problems common to fossil energy facilities will also
apply to coal liquefaction facilities. Liquefaction facilities do pre-
sent some unique problems due to incomplete combustion resulting in a
wide variety of organic compounds, reducing conditions resulting in H?S
and other reduced sulfur compounds and catalytic processes producing
spent catalyst with associated environmental concerns. These problems
are generally common to all liquefaction processes, however, since no
74
-------
large scale plants are in operation in the U. S., the only available data
on emissions and effluents are estimates from pilot plant operations and
cannot be quantified for a commercial operation.
Projected efficiencies for direct coal liquefaction facilities are
in the 60 to 70 percent range. Exact values for coal conversion effi-
ciencies are difficult to estimate and thus an exact value cannot be
given until commercial demonstration takes place. In 1977, DOE esti-
mated the cost to produce a synthetic crude to be $4 - 6 per million Btu.
Although there remain unanswered questions relating to coal lique-
faction (e.g., commercial demonstration, environmental impacts, costs),
the successful development of a technology would provide a valuable
energy alternative and allow greater utilization of our nation's coal
reserves. Additionally, liquid fuels are easier to store, transport,
and utilize than solid fuels, and during liquefaction, impurities (e.g.,
sulfur) can be removed. It appears that environmentally acceptable
liquid fuels can be produced from our various ranks of coal.
11.2 Process Description
Concept
The basic objective of coal liquefaction is to convert coal to
liquid fuels with minimal production of gases, liquids, and organic solid
residues. All ranks of coal can be liquefied although some are more
attractive than others. The liquid products vary both with the type of
coal used and the particular process applied.
There are several methods for producing a liquid fuel from coal.
As with gasification, either hydrogen has to be added or carbon removed
from the compounds in the coal. In bituminous coal, for example, the
carbon-to-hydrogen ratio by weight is about 16 to 1; in fuel oil the
ratio is about 6 to 1. Although liquefaction is a complex process, it
can be viewed as a change in the carbon-to-hydrogen ratio that can be
accomplished by one of several reactions (e.g., pyrolysis) (1). The
chemical structure of the coal influences the chemical reactions that
will take place during the liquefaction process. The chemical structure
of different coals show significant variance.
Deta i I
Coal liquefaction processes can be grouped into four distinct cate-
gories (2, 3):
• Direct hydrogenation (e.g., H-CoaI )
• Solvent extraction (e.g., Solvent Refined Coal)
175
-------
• Pyrolysis (e.g., Clean Coke)
« Indirect Liquefaction (e.g., Fischer-Tropsch)
In indirect hydrogenation, hydrogen is added cataIyticaI Iy to coal
in a reactor under high pressure and temperature resulting in vapor and
liquid phases which are cooled to separate the products, refined to re-
move by-products and, depending on the fuel product desired, further pro-
cessed. The process conditions (temperature, pressure and amount of
hydrogen added) determine the fuel produced. Processes and products in
this category include:
• H-Coal produces boiler fuel or synthetic crude
• SynthoiI produces synthetic crude or fuel oil
The solvent extraction process liquefies coal through indirect trans-
fer of hydrogen to the coal using a process-derived solvent and a hydro-
gen atmosphere. Processes and products in this category include:
• Solvent Refined Coal produces boiler fuel or low
suI fur sol id fuel
• CO-Steam produces fuel oi I
• Donor Solvent produces liquid and gas products
In pyrolysis, crushed coal, thermally decomposed in the absence of
oxygen, yields solids (char), liquids and gases. These products, via
the same process have been produced from coal for well over 100 years
as the by-product of coking operations. Processes and products in this
category include:
• Hydrocarbon i zation produces fuel oi I
• Clean Coke produces coke and liquid fuels
• Flash Pyrolysis produces fuel oiI, coke,
and gas
Indirect liquefaction involves the initial gasification of coal to
produce a mixture of CO and hL (synthesis gas), which is purified and
converted to liquid fuels by reaction over appropriate catalysts to pro-
duce alcohols (methanol) or paraffinic hydrocarbons. A particular advan-
tage of indirect I iquefaction is that essentially alI of the sulfur and
nitrogen present in the coal can be separated in the gaseous phase and
thus eliminated from the iquid products. These materials are difficult
and expensive to remove to a very low concentration with direct processes.
Processes and products in this category include:
176
-------
• the MobiI produces gasoline
• Fischer-Tropsch produces liquid and gaseous fuels and
chemical products
The Fischer-Tropsch process is significant in that it is the only
large commercial coal liquefaction plant in operation. The plant is
located in Sasol, South Africa.
In the United States, the direct liquefaction processes receiving
DOE support that are closest to near-term commercial demonstration are
H-Coal, Solvent Refined Coal, and Donor Solvent. Detailed descriptions
summarized from DOE publications of these processes follow (4, 5, 6, 7).
H-CoaI
The H-Coal pilot plant is located in Catlettsburg, Kentucky. This
600-ton of coal per day test facility recently commenced operation. The
process is a catalytic hydroliquefaction process that converts high sul-
fur content coal to boiler fuels and to syncrude. A schematic of the
process is provided in Figure 39. Coal is crushed to minus 60 mesh,
dried, and then slurried with recycled oil and pumped to a pressure of
about 200 atm. Compressed hydrogen is added to the slurry, and the mix-
ture is preheated and charged continuously to the bottom of the ebullient-
bed catalytic reactor. The upward passage of the internally recycled
reaction mixture maintains the catalyst in a fluidized state. (Catalyst
activity is maintained by the semi-continuous addition of fresh catalyst
and the withdrawal of spent catalyst.) The temperature of the ebullient-
bed catalytic reactor is controlled by adjusting the temperature of the
reactants entering from the preheater. Typically, the temperature of the
mixture entering the reactor is 650-700 F.
Vapor product leaving the top of the reactor is cooled to separate
the heavier components as a liquid. Light hydrocarbons, ammonia, and
hydrogen sulfide are absorbed from the gas stream and sent to a separator
and a sulfur recovery unit. The remaining hydrogen-rich gas is recom-
pressed and combined with the input slurry. The liquid from the conden-
ser is fed to an atmospheric distillation unit. The liquid-solid produd
from the reactor, containing unconverted coal, ash, and oil, is fed into
a flash separator. The material that boils off is passed to the atmos-
pheric distillation unit that yields light and heavy distillate products.
The bottoms product from the flash separator (solids and heavy oil) is
further separated with a hydro-cyclone,, a liquid-solid separator, and by
vacuum distillation.
The gas and liquid products, composed of hydrocarbon gas, hydrogen
sulfide, ammonia, light distillate, heavy distillate, and residual fuel,
may be further refined as necessary. A portion of the heavy distillate
177
-------
\ / HVDROCLONES
1
3O6
T/D
ASH
FUEL OIL
Figure 39
H-CoaI Process
is recycled as the slurry medium. The stream containing the unreacted
carbon and some liquid will eventually be processed in a commercial
installation to produce additional hydrogen needed for the process.
The specific operating conditions of the H-CoaI process affect the
type of fuel produced. For example, to produce synthetic crude, more
hydrogen is required and there is a
In this mode, the separation of the
yield of residual fuel oil
(unconverted carbon and ash)
lower
from the liquid can be accomplished by vacuum distillation, and a spe-
cial liquid-solid separation unit is not required. To produce clean
low-sulfur residual oil as major products, the temperature
in the ebullient-bed reactor are lowered, and less hydro-
fuel gas and
and pressure
gen is required.
178
-------
Solvent Refined Coal (SRC)
The product from the original SRC mode (SRC-I) is a nearly ash-free
low-sulfur solid fuel at ambient conditions. In a modification of the
process (SRC-II) a distilled liquid product results. The SRC-I product
is projected to serve as a clean fuel substitute for high sulfur coal.
The SRC-II product can be used directly as a boiler fuel or, with further
hydrogenation, as a refinery feed for conversion to conventional fuels.
A 50-ton per day pilot plant is located at Fort Lewis, Washington. A
demonstration plant for SRC-II (6000 tons of coal per day - 2000 barrels
of oil per day) is currently planned to be constructed in Morgantown,
West Virginia, with startup in 1984.
Figure 40 is a schematic of the SRC-I process. The coal is first
pulverized and mixed with a coal-derived solvent in a slurry mix tank.
The slurry is mixed with hydrogen, which is produced by other steps in
the process, and is then pumped through a fired preheater and passed into
a dissolver where about 90 percent of the moisture- and ash-free coal is
dissolved. Several other reactions also occur in the dissolver: the
coal is depolymerized and hydrogenated, which results in an overall de-
drease in product molecular weight; the solvent is hydrocracked to form
lower-molecular-weight hydrocarbons that range from light oil to methane;
and much of the organic sulfur is removed by hydrogenation in the form of
hydrogen sulfide.
COAL
SOLID
FUEL
ISRCI
Figure 40
SRC-I Process
179
-------
From the dissolver, the mixture passes to a separator where the
gases are separated from the slurry of undissolved solids and coal solu-
tion. Raw gas is sent to a hydrogen recovery and gas desuIfurization
unit. Hydrogen recovered is recycled with the slurry coming from the
slurry mix tank. Hydrocarbon gases are given off and hydrogen sulfide
is converted to elemental sulfur.
The slurry of undissolved solids and the coal solution pass to a
filtration unit where undissolved solids are separated from the coal solu-
tion. In the commercial-scale process, the solids are sent to a gasifier-
converter where they react with supplemental coal, steam, and oxygen to
produce hydrogen for use in the process. The coal solution passes to the
solvent recovery unit and the final liquid product, solvent refined coal,
is produced. The solvent-refined coal has a solidification point of
350 to 400° and a heating value of about 16,000 Btu/lb.
As previously indicated, modification of the SRC process (SRC-II)
produces an a I I-disti I late liquid instead of a solid residual fuel as the
principal product. Figure 41 is a schematic of the SRC-II process. In
COAL
LIGHT DISTILLATE
OIL
Figure 41
SRC-I I Process
-------
this modification, part of the product slurry is recycled as solvent for
the pulverized coal feed instead of 450 F-plus boiling-range distillate.
As a result of increased severity of reaction conditions, the hydrogen
reaction is greater and a major part of the coal is converted to a liquid
distillate product. The quantity of unconverted coal and vacuum residue
is controlled so it is in balance with the requirements for gasifier feed
to produce the process hydrogen requirements. This eliminates the solid/
liquid separation step (filtration) required for production of fuel in
so I i d form.
Donor Solvent
The chief features of the Exxon Donor Solvent (EDS) Process are
illustrated in the process schematic, Figure 42. A pilot plant (250 tons
of coal per day) is located in Baytown, Texas, next to an Exxon refinery.
Crushed coal is liquefied in a non-catalytic reactor in the presence of
molecular hydrogen and the hydrogen-donor solvent. The liquefaction re-
actor operates at 800-880 F and 1500-2000 pounds per square inch.
HYDROGENATED
DONOR
SOLVENT
c
Figure 42
Donor Solvent Liquefaction Process
181
-------
The hydrogen-donor solvent is a 400 -850 F boiling range material.
The solvent is a cataIyticaIly hydrogenated recycle stream fractionated
from the middle boiling range of the liquid product. After hydrogen-
ation, the solvent is mixed with fresh coal feed and pumped through a
preheat furnace into the liquefaction reactor. Slurry leaving the lique-
faction reactor is separated by distillation into gas, naptha, distill-
ates, and a vacuum bottoms slurry. The vacuum slurry is coked to produce
add itionaI I iqu ids.
The plant is "balanced" in that
cess fuel and hydrogen requirements.
produced by gasifying the coke and by
liquefaction process.
it is self-sufficient in both pro-
Process fuel and hydrogen are
reforming C.-C0 gases from the
The process is simple, and critical processing steps are adaptations
of Exxon's base in petroleum refinery technology. Distinguishing fea-
tures are the decoupled configuration of the liquefaction and catalytic
hydrogenation sections and the use of vacuum distillation for solids/
liquid separation. The catalyst does not contact coal minerals or high-
boiling liquids, thereby leading to longer catalyst life at high activity,
Use of hydrogenated rather than unhydrogenated recycle solvent produces
a very significant improvement in process operability, particularly in
down-stream processing vessels. Also, hydrogenated solvent produces
higher distillate product yields than unhydrogenated solvent. The use of
mechanical separation devices for solids/I iquids separation is avoided.
The process gives high yields of low-sulfur liquids from bituminous
or subbituminous coals or lignites. For Illinois bituminous coal, the
liquid yield is 2.6 barrels of C + liquid per ton of dry coal. Ammonia
and elemental sulfur are the only by-products of significance. By vary-
ing liquefaction conditions or adjusting solvent properties, product
distribution may be varied over a wide range.
An estimated heat balance as derived from reference 8 is given by
Table 23. DiagrammaticaI Iy, this is illustrated by the heat flow dia-
gram, Figure 43.
11.3 AppIications
Current
During World War II, Germany produced liquids from
ate scale. The conversion of coal to liquids has never
commercially in the United States. n
constructed in a number of countries.
in South Africa producing liquids from
ploys an indirect liquefaction process
coaI on a moder-
been accomplished
the past, coal-to-oil plants were
Currently there is only one plant
coal. This plant, SASOL I, em-
182
-------
Table 23
Estimated Heat Balance for a Commercial Scale EDS Plant
Btu/day Percent of TotaI
(10 Btu's) Energy Input
System Products
Liquids 323,071 61.72
Sulfur, ammonia 8,309 1.59
System Losses
Ash, combustibles and sensible
heat 26,882 5.13
Stack losses 20,039 3.83
Energy losses via water and air 136,853 26.14
Liquefaction and solvent
hydrogenation (9.80$)
FI exicoking (6.44$)
Hydrogenation and recovery
(6.72?)
By-product recovery, offsites,
and misce laneous (3.18$)
Other miscellaneous 8,309 1.59
Energy Input
Coal (cleaned)* 488,761 93.37
Electrical power** 34,702 6.63
* CoaI - I I I i noi s No. 6; 10,574 Btu/Ib as received prior to cleaning
** Power based on 8,500 Btu/kwh to generate
I 83
-------
100$
Energy Input
93.37$ from Coal
5. I
Ash combustibles
and sensible heat
3.:
Stack losses
I .59$
Mi see I Ianeous
61.72$
_Li qul ds
6.63$ from
Electrical Power
\ 26.14$
/ Energy tosses via
a i r and water
,59$ S,NH3 (by-products)
63.31$
System products out
Figure 43
Energy Flow Diagram for a Commercial Scale EDS Plant
Projected
The successful development and commercial demonstration of a coal
liquefaction technology would provide a valuable energy alternative and
would allow greater utilization of the nation's coal resources. There
are many advantages to liquefying coal. Liquid fuels are generally more
attractive than solid fuels in that they are easier to store, transport,
and utilize. Also, during the liquefaction process, impurities found in
coal (e.g., sulfur, metals, and ash) can be removed or their concentra-
tions greatly reduced. Thus, it is possible to produce clean, environ-
mentally acceptable liquid fuels from various ranks of coal. The devel-
opment and future commercial use of coal liquefaction technology are
dependent on many factors. Some of the more important include:
184
-------
• The demonstration (large scale) of a viable technology,.
• The ability to satisfy environmental concerns, and
• The abiIity to produce a commerc ially usable liquid
fuel at an acceptable market price.
11.4 Environmental Considerations
Although many of the environmental issues associated with conven-
tional fossil fuel utilization are common to coal conversion processes,
liquefaction technology presents some unique problems (2). These include:
the identification of materials with carcinogenic, mutagenic, and related
effects; characterization and treatment of wastes, fugitive emissions,
and effluents; and disposal of sludges and solid wastes. These problems
are generally common to all liquefaction technologies; however, particu-
lar processes may have to be evaluated individually. Liquefaction does
have the inherent advantage of separating the processing of the coal from
the ultimate utilization. Since impurities can be removed from the coal
during liquefaction, a "clean" fuel can be delivered to the utilization
site (possibly an urban area) and thus the power generation facility will
not have to cope with the impurities. A major environmental consideration
in direct coal liquefaction is product toxicity due to the presence of
high molecular weight organic compounds.
Identified Pollutants
Air Emi ss ions
Development and commercialization of a coal liquefaction industry
creates a concern with regard to the introduction of air pollutants into
the atmospheric environment (2). The typical materials produced in a
coal liquefaction facility which could have a detrimental impact on air
quality include: hydrogen su fide, ammonia, particulate matter (e.g.,
coal dust and process fines), hydrocarbons, sulfur dioxide, hydrogen
cyanide, and small amounts of nitrogen dioxide, polycyclic hydrocarbons,
and heavy metals. These emissions result from such activities as fuel
combustion, coal preparation, sulfur recovery, ammonia storage, petroleum
storage and miscellaneous hydrocarbon losses.
The major air emissions from liquefaction facilities are generally
known and conventional control techniques may be applicable. The Dravo
Corporation, in a 1976 handbook produced for the U. S. government, pro-
vides information on a number of industrial sulfur removal systems (Hand-
book of Gasifiers and Gas Treatment Systems, FE-1772-11, February 1976).
The majority of the proprietary systems described are for removing H?S
from industrial gases. Some systems in addition to removing H^S also
remove other gaseous effluents (e.g., CO,-,, NhL, HCN). Almost a I I of the
185
-------
addressed systems have been in existence for many years with signifi-
cant industrial usage. Such systems include the Selexol and the Stret-
ford processes that have been used for selectively cleaning up gaseous
impurities from processes used to convert oil or coal to other fuel
form(s). Liquefaction air emission streams may contain impurities which
could reduce the capabilities of commercially available control tech-
nologies.
However, in some instances, advanced controls may have to be devel-
oped before such plants are constructed on a commercial scale. In addi-
tion, airborne pollutants will be transported into the general environ-
ment and possibly transformed into other compounds after emission from
coal liquefaction facilities. Conventional models are generally adequate
to predict atmospheric dispersion for a high stack and flat land scenario.
However, more detailed atmospheric transformation and dispersion informa-
tion wi I I be requi red to fully utiIize these models.
The 1977 Clean Air Act amendments mandate that fossil energy facil-
ities, including coal conversion plants, utilize the "best available
technology" to control pollutants. Coal liquefaction (and other process
facilities) constructed in nonattainment areas will be subject to emis-
sion trade-off policies. The energy and cost penalties of applicable
air pollution controls must be characterized as well as the secondary
pollutants which may be emitted by the controls.
Liquid Effluents
Coal liquefaction processes may produce waste effluents which have
broad temperature and pH ranges and may contain a variety of materials
such as: suspended particles, ammonia, toxic trace metals, phenols,
aromatic hydrocarbons, thiophenes, aromatic amines, and other organic
compounds (2). Conventional control and wastewater treatment techniques
possibly could be applied to some of these materials. However, particu-
larly troublesome areas requiring more study include: phenols, trace
metals and the final disposal of the effluents (2).
Water quality may also be affected by gaseous streams, fugitive
effluents and air emissions which may settle or be washed into water
bodies by rain. Improper handling or disposal of solid wastes may also
release dissolved and suspended solids and organics. Control and treat-
ment options compatible with water discharge standards should be identi-
fied and their effects evaluated. Ultimate discharges (after treatment)
can generally be projected for each coal liquefaction process. The
general effects of these discharges at specific locations on indigenous
aquatic organisms and communities can also be predicted.
Effluent constituents may accumulate and/or be transformed in the
water column and biotic sediment or aquatic ecosystems. Current methods
186
-------
for predicting the movement of waste contaminants through surface and
groundwater systems must be evaluated for locations where liquefaction
facilities may be located.
Sol id Waste
Solid wastes generated by coal liquefaction processes consist pri-
marily of ash and refuse removed from the coal and sludges and solids
recovered from waste treatment processes. The major solid waste streams,
as well as minor ones such as spent catalyst, must be characterized and
appropriate disposal techniques determined. Where appropriate, new treat-
ment and disposal techniques may need to be developed.
Conventional disposal of solid wastes (especially ash) in offsite
landfills will require transport and handling equipment and relatively
large areas of land. The handling, transportation and disposal of wastes
must be controlled to prevent fugitive dust emissions and accidental dis-
charges, Groundwater leaching is another concern which must be evaluated
if landfills are used as disposal areas for coal liquefaction wastes.
Physical and chemical reactions involved, effects of various methods of
disposal upon IeachabiI ity, effective control and contrainment techniques,
and compliance with new State hazardous waste disposal regulations should
all be evaIuated.
A DOE publication has estimated that the total solid wastes to be
disposed of by a large-scale facility would be about 1200 to 2800 tons
per day for a coal liquefaction plant, and 1000 to 2500 tons per day for
an SRC-I plant (2). Most of these wastes will be in the form of ash.
Disposal of these wastes would cover approximately 300 to 700 acres to a
depth of 10 feet over a 20-year period. Approximately 250 to 525 acres
would be needed to dispose of wastes from an SRC plant.
Regulatory Impacts
Each liquefaction technology will have to be evaluated separately
as to regulatory impacts. Because of the difference in technologies and
also varying state and local regulations, siting of a major coal lique-
faction facility must be approached on a case-by-case basis.
A coal conversion industry must comply with regulations and stand-
ards including requirements of the Clean Air Act, the Clean Water Act,
the Safe Drinking Water Act, the Resource Conservation and Recovery Act,
the Toxic Substances Control Act, the Federal Nonnuclear Energy Research
and Development Act, and the National Environmental Policy Act as well
as applicable State laws. Failure to comply has the potential of halting
all progress toward commercialization.
187
-------
Current standards for hazardous air pollutants limit mercury, beryl-
lium, and lead emissions. These standards conceivably could put a limit
on coal types than can be utilized in future demonstration plants.
Since effluent guidelines have not been developed for most fossil en-
ergy technologies, permit requirements are determined on a case-by-case
basis by States or by EPA (2).
Disposal of specific materials used in coal liquefaction may be
regulated in the future. Currently, solid waste disposal must comply
with stringent standards. Monitoring is required and State or EPA per-
mits for all landfiI Is wiI I be requi red by ApriI 1, 1988.
The Resource Conservation and Recovery Act of 1976 (RCRA) has guide-
lines for the land disposal of solid wastes (40 CFR 241). These stand-
ards set minimum levels of performance for any solid waste land disposal
site. Additional standards have been proposed for disposal of solid
wastes that contain hazardous pollutants. All future coal liquefaction
facilities may have to abide by these solid waste standards (9).
Undoubtedly, a coal conversion industry would benefit from the ex-
perience of the petroleum industry in dealing with complex organic sub-
stances and new processes while complying with governing statutes.
11.5 Performance
Current
Currently, there are no coal liquefaction facilities operating in
the United States. Therefore, all projections are based on technology
still in the development stage. Reference 10 indicates an estimated
efficiency range of 60-70 percent for direct liquefaction processes.
Projected
It is difficult to provide realistic and confident estimates for
coal conversion efficiencies. Also, efficiencies reported often do not
indicate whether the value is for a plant that purchases all, part, or
none of the supplemental energy needed in the conversion. (These- pur-
chases include electricity; steam, and other utilities.)
Reference 10 indicates an efficiency range of 60-70 percent for
Direct Hydrogenation (H-Coal). Reference 1 stated overall energy effi-
ciencies for various coal liquefaction processes to be in the 62 to 69
percent range. This is consistent with the provided estimated heat
balance based on reference 8. Limiting factors that can reduce efficien-
cies significantly are specific to each process and output mix and must
be separately computed.
-------
11.6 Economi cs
Current
Since there are no coal liquefaction processes currently in opera-
tion in the United States, the economics must be projected.
Projected
As with all complicated and unproved energy technologies, the cost
to produce a million Btu is, at best, an estimate. The estimated cost by
DOE to produce a synthetic refined crude oil as of mid-1977 was $4-6
per mi I I ion Btu (11). Undoubted Iy, the actuaI cost wiI I be high. In
general, the estimated cost from a direct liquefaction process is less
than for indirect liquefaction.
-------
References - Direct Coal Liquefaction
1. University of Oklahoma. Energy Alternatives: A Comparative
Analysis. The Science and Public Policy Program, University of
Oklahoma, Norman, Oklahoma, May 1975.
2. U.S. Department of Energy. Environmental Development Plan
(EDP) - Coal Liquefaction Program FY 1977. DOE/EDP-0012, U.S.
DOE, Washington, D.C., March 1978. 52 pp.
3. U.S. Department of Energy. Environmental Readiness Document -
Coal Liquefaction, Commercialization Phase III Planning.
Assistant Secretary for Environment, DOE/ERD-0015, Washington,
D.C., September 1979.
4. U.S. Department of Energy. Coal Liquefaction Quarterly Report,
January-March 1978. Assistant Secretary for Energy Technology,
DOE/ET-0068/1, Washington, D.C., September 1978. 64 pp.
5. U.S. Department of Energy. Coal Liquefaction Quarterly Report,
July-September 1978. Assistant Secretary for Energy Technology,
DOE/ET-0068/3, Washington, D.C., May 1979
6. U.S. Department of Energy. Fossil Energy Program Summary Docu-
ment. Assistant Secretary for Energy Technology,- DOE/ET-0087,
Washington, D.C., March 1979.
7. U.S. Department of Energy. Fossil Energy Research and Develop-
ment Program. Assistant Secretary for Energy Technology,
DOE/ET-0013(78), Washington, D.C., March 1978.
8. Exxon Research and Engineering Company. EDS Coal Liquefaction
Process Development - Phase IMA, Interim Report. Synthetic
Fuels Engineering Division, FE-2353-13, Florham Park, New Jer-
sey, 1978.
9. Gibson, E. D., and Page, G. C. Low/Medium Btu Gasification:
A Summary of Applicable EPA Regulations. DCN #79-218-143-92,
Radian Corporation, Austin, Texas, February 1979. 33 pp.
10. Perry, H. Clean Fuels from Coal. In: Advances in Energy
Systems and Technology, Vol. 1, P. Auer, Ed. Academic Press,
1978. pp. 244-324.
11. Mills, G. A. Synthetic Fuels From Coal: Can Research Make
Them Competitive? Washington Coal Club, March 16, 1977-
190
-------
12. Fuel Cel
12.1 Overview
The fuel cell, by converting chemical energy directly to electric-
ity, can efficiently use fuels without a mechanical intermediate step.
Fuel cell power plants offer many attractive characteristics such as
modular construction, low environmental emissions, high efficiency and
rapid response to load-demand fluctuations. Because of their modular
construction, fuel cells are easily transported and installation times
and costs reduced.
The fuel cell concept itself is not new: such cells have already
provided power for moon landings and, between 1971 and 1973, provided
electric power to 50 apartment houses, commercial establishments, and
small industrial buildings. What is new is an effort to capitalize on
the fuel cell's inherent flexibility, safety, and efficiency by putting
together a generator system that can use a variety of fuels to economic-
ally meet today's utility-scale power needs.
A fuel cell is a sandwich consisting of an anode, electrolyte, and
cathode, much like a battery. Hydrogen-rich fuel is fed down the anode
side of the cell, where the hydrogen loses its electrons, leaving the
anode with a negative charge. Air is fed down the cathode side, where
its oxygen picks up electrons, leaving the cathode with a positive charge
The excess electrons at the anode flow towards the cathode, creating
electric power. Meanwhile, hydrogen ions produced at the anode (when
electrons are lost) and oxygen ions from the cathode migrate together in
the electrolyte. When these ions combine, they form water, which leaves
the cell as steam because of the heat of the electrochemical process.
The inclusion of fuel cell power plants in utility systems conceiv-
ably would yield a number of benefits. Reduced resource consumption
would result from high full-load and part-load efficiency. Because of
their modular construction they could be installed at substations on
transmission and distribution systems if constant fuel supply is avail-
able (1). This modularity could mean lower cost, shorter plant construc-
tion lead time, and greater flexibility in plant size. Fuel cell systems
have been identified as candidates for power generation in a variety of
utility applications. These are:
• Upgrading old urban plants by using existing sites more
efficiently with decreased environmental impact.
• Supplying new generating capacity where environmental
considerations restrict combustion plants (especially
when transmission right-of-way is limited and plants
must be sited close to population areas).
191
-------
• Complementing existing power systems' peak load
capacity, where quick response and part-power
efficiency are required.
• Supplying power for small and medium sized
municipal and rural utilities under 100 MW, a
range in which other power plant types cannot
operate as efficiently.
Low water requirements, limited emissions, and quiet operation help
make fuel cell plants an attractive power option. An advanced fuel cell
plant would produce less waste heat than a comparable capacity conven-
tional or nuclear plant and thereby require less cooling. Because fuel
cell plants can use a variety of hydrocarbon fuels, they share with con-
ventional generating processes the environmental problems currently
associated with extracting and processing fossil fuels. However, since
the fuel cell portion of the plant does not involve a combustion process,
emissions from overall operations are significantly lower than emissions
from conventional power plants. The fact that fuel cell plants operate
with very little noise also helps to make them attractive for a number
of use situations.
Projected electricity generating efficiencies for hydrogen fuel
cells are estimated between 54 and 61 percent. The Energy Conversion
Alternatives Study (EGAS) team estimated an overall efficiency of 50
percent for their conceptual molten carbonate fuel cell power plant con-
taining an advanced coal gasifier.
Although still in conceptual and prototype stages, fuel cell plants
offer the potential to produce electricity efficently on both small and
large scales. These systems could be used to complement existing facil-
ities or supply new generating capacity where environmental considera-
tions restrict conventional combustion plants.
12.2 Process Description
Concept
The fuel eel (Figure 44) is a device that produces electrical en-
ergy from the controlled electrochemical oxidation of fuels (2). The
basic components of a simple hydrogen-oxygen fuel cell are the electrodes
(anode and cathode) and the electrolyte, which can be either acidic or
basic. The reactants are normally consumed only when the external cir-
cuit is completed, allowing electrons to flow and the electrochemical
reaction to occur. When the external circuit is completed, an oxidation
reaction, yielding electrons, takes place at the anode and a reduction
reaction, requiring electrons, occurs at the cathode. The electrodes
provide electrochemical-reaction sites and also act as conductors for
electron flow to the external circuit.
192
-------
FUEL (H,)
POROUS
ANODE
POROUS
CATHODE
SPENT FUEL AND
WATER VAPOR
ELECTRON FLOW-
OX IDA NT (02)
Figure 44
Typical Fuel Cel
Fuel cells make efficient use of fuels by converting chemical en-
ergy directly to electricity and heat without going through a mechanical
intermediate step.
The basic components of a fuel cell are the inlets to the anode and
cathode, the electrodes, and an electrolyte. The individual cells can
be aligned in series to build up voltage. When the external circuit is
193
-------
closed, the electrochemical reaction initiates electron flow and the
reactants are consumed resulting in good fuel efficiency even at low
loads. By utilizing the cell's waste heat (e.g., in the reforming reac-
tion), overall efficiencies above 75 percent are theoretically possible
(3).
There are three basic designs under active consideration:
• In acid cells employing acid electrolyte, hydrogen
ionizes at the anode, releasing two electrons per
molecule, and oxygen reacts with hydrogen ion and
electrons at the cathode to produce water. The
electron release at the anode provides an electric
current.
• In molten carbonate cells, hydrogen combines with
carbonate ion at the anode to yield water, carbon
dioxide and electrons. At the cathode, meanwhile,
oxygen and carbon dioxide combine with the returning
electrons to regenerate carbonate ions.
« In solid oxide cells, oxygen ionizes at the cathode,
consuming electrons, and then migrates to the anode,
where it combines with hydrogen and releases the
electrons for the flow of current.
A fuel cell power plant would include a fuel conditioner, a fuel
cell power section, and an inverter to convert the direct current (d.c.)
fuel cell output to alternating current (a.c.) power. Several types of
fuel cells could be used in the fuel cell power section, Table 24 pre-
sents the types which have received significant attention for aerospace,
military, and utility use (4).
Deta i I
A fuel cell power plant generates electricity from naturally occur-
ring fuels (e.g.; petroleum products, natural gas, coal), or synthetic
fuels (e.g., hydrogen, synthesis gas). The power plant has three major
subsystems: the fuel conditioner, the fuel cell power section, and the
inverter. The typical configuration is shown in Figure 45 (5).
The fuel conditioner generates a hydrogen-rich gas for use in the
fuel cell power section. With light distillates, natural gas or methyl
fuel, the fuel conditioner is a catalytic steam reformer of the type used
in the petrochemical industry. Heavier liquid fuels can be conditioned
in partial oxidizers or in advanced fuel processors presently being in-
vestigated. Coal must be processed in a coal gasifier of the same type
as proposed for use with combined-cycle power plants.
194
-------
Table 24
Comparison of Fuel-Cell Types
Cel 1
Type
Aqueous
Acid
Molten
Carbon-
ate
Operati ng
Temper-
ature
80-205°C
Gas Dif-
fusion
650-760°C
Typica 1
Elec-
trodes
Tef Ion
bonded
acid in
matrix
Si ntered
nickel
oxide &
coba It
Typica 1
Elec-
tro lyte
Phosphoric
acid
A 1 ka 1 i meta 1
carbonates
i n a f i ber
rei nforced
partic 1 e
matrix
Typica 1
Structure 1
Mater i a 1 s
Bonded
graphite
Sta in 1 ess
steel
System
Considerations
Waste heat
used for steam
production
Requi res addi-
tion of CCL to
2
air supply;
waste heat
used to reform
process heat
Solid 815-1095 C Metallic Doped metaI
Oxide and semi- Oxides
conductor
f i rms
Ceramic
Highest tem-
perature for
i ntegration
with fuel
cond itioner
NaturaI
Gas, Dis-
tiIlates, -
Residuals,
Methanol
Hydrogen-
rich
Fuel
Condi -
t ioners
t
l>
Gas
Water
Heat
Fuel -eel I
Power
Section
DC
Power ^
I nverter
AC Power
Figure 45
Fuel CelI Power Plant
195
-------
The fuel cell power section is composed of single cells having three
basic components: a fuel electrode (anode), an air electrode (cathode),
and an electrolyte to form an ion conductor between them. The process in
the cell is the reverse of the well-known process of water electrolysis
in which electricity is passed through water to produce hydrogen and oxy-
gen. A fue cell combines the hydrogen from the processed fuel with the
oxygen from the air to produce water and d-c electricity. Aside from
some waste heat, the only by-products are water and carbon dioxide. No
pollution is generated by the electrochemical reaction.
A single cell generates approximately one volt of d-c power. In
a fuel cell power section, stacks of such cells are connected in series
to permit generation of hundreds to thousands of volts. At present
technology levels, a single fuel cell generates roughly 100 to 200 watts
of electricity for each square foot of electrode area. Connecting a num-
ber of assemblies in parallel permits power evels from kilowatts to
megawatts.
The third subsystem of the fuel cell power plant, the inverter,
converts the d~c electrica output of the fuel cell power plant to a-c
electricity. Inverters are presently used in applications ranging from
small consumer devices to large-scale electric utility equipment. The
development of inverters for fue! cell power plants has been directed
toward technological improvements that reduce unit cost and improve
eff i c i ency.
In the Energy Conversion A ternatives Study (EGAS) (4) conceptual
design power plant, coal is gasified in an air blown, ash agglomerating,
fIuidized-bed gasifier operating at 200 psia. Sulfur is removed from
the product gas in iron oxide beds. The clean gas is fed to molten
carbonate fuel cells that operate at 150 psia and a nominal temperature
of 650 C. Direct current power from the fuel eel Is is converted to alter-
nating current in solid-state inverters. Fuel cell exhaust gases drive
turbocompressors that pressurize the fuel cells and gasifiers. Waste
heat from the fuel eel I and the gasifier is used to drive a steam turbine
bottoming cycle. Bottoming cycle throttle conditions were 2400 psig and
540 C with single reheat to 540 C. Bottoming cycle heat is rejected in
wet forced-draft cooling towers, The gasifier vessels, fuel cell modules,
inverters, and turbocompressors are designed for factory fabrication with
rail transport to the p ant site. This resulted in a rating of 108 MW
for the gasifier and fuel cell islands. The steam turbine bottoming
cycle rating of 203 MW was selected to provide reasonable economies of
scale for the steam plant. Four gasifier and fuel cell islands are re-
quired to provide sufficient waste heat for the steam turbine; conse-
quently, total net output from the plant is 635 MW. Two-thirds of the
plant output is furnished by the fuel cells, with the remainder being
from the steam plant.
Reference 4 contains thermal emission data for the conceptual fuel
cell power plant described above. Based on reference 4, an estimated
I 96
-------
heat balance for a 500 MWe fuel cell power plant was developed (Table
25). DiagrammaticaI Iy, this can be represented by Figure 46. The pro-
vided values are for fuel cell power plant with a steam turbine bottom-
ing cycle. If a gas turbine bottoming cycle were to be utilized, the
overall efficiency would drop to 45 percent because the gas turbine bot-
toming cycle can not utilize fuel cell waste heat as effectively.
Table 25
Heat Balance for 500 MWe Fuel Cell Power Plant
Btu/hour
(10 Btu's)
Percent of Tota
Energy Input
Net Electrical Energy Output
Losses
Cooling tower heat reject
Stack heat losses
Miscellaneous heat losses
TotaI Energy nput
1706.5
866.0
437.5
412.5
3422.5
49.9
25.3
12.8
12.0
100.0
I 2.3 AppI i cations
Current
Presently, there are only experimental/feasibility fuel cell power
plant related activities in this country. The outcome of these efforts
and such unsolved questions as fuel acceptability, reliability, and costs
will contribute to defining the proper application of this technology.
Projected
While features of fuel cell power plants appear attractive for cen-
tral station applications, the low pollution potential of the fuel cell
and its effectiveness at small sizes also suggest that fuel cell power
plants be used where the characteristics of conventional power plants
would prohibit their use (4). For example, when the generating facility
is located close to or at the load, the amount of energy lost in trans-
mission is reduced, and the need for additional transmission investment
197
-------
100$
Energy input from fuel
\2.8%
Stack
heat losses
12.0?
Mi seel Ianeous
heat loss
25.3$
Coo Ii ng tower
heat reject
49.
Net electrical energy output
Figure 46
Heat Flow Diagram for Fuel Cell Power Plant
is deferred. In addition, the waste heat from a fuel cell plant can be
recovered and used. Thus, a fuel cell power plant can offer significant
economic advantages in certain situations.
The fuel cell may provide an alternative method for meeting new load
requirements in congested urban or suburban areas having restrictive pol-
lution standards and limitations on new transmission rights-of-way. Use
of the fuel cell to feed power into an electric utility's distribution
system at points near the load to be served would eliminate the energy
losses (approximately 3 to 6 percent) in transmitting power from a re-
mote central plant to the substation and afford the opportunity to recap-
ture waste heat (4).
98
-------
The fuel cell also offers a more fuel-efficient approach to supply-
ing a utility system's spinning reserve requirements. Spinning reserve
refers to power plants kept on line either at idle or part power to per-
mit rapid system repsonse to demand changes and to provide continuity of
service in the event of a plant outage. In this type of operation, low
part-power heat rate and fast response to load change are important
generator features. Combining conventional units at rated load with
fuel cell units at part load could prove to be an efficient, economic
mix. The use of fuel cells to provide spinning reserve capacity could
permit up to 15 percent reduction in overall utility system fossil fuel
consumption (4).
Pratt & Whitney has a major program for dispersed generation using
natural gas reformers and low-temperature (<250°F) fuel cells of the
phosphoric acid and potassium hydroxide electrolyte types. The Insti-
tute of Gas Technology has been doing complementary work using low-
temperature phosphoric acid and high-temperature (2200 F) molten carbon-
ate electrolyte cells.
In the Pratt & Whitney system, the cells operate at about 230°F.
This system burns the effluent from the fuel cells to provide heat to
reform hydrocarbons, such as natural gas, yielding a hydrogen/carbon
dioxide mixture. (Heat produced in the cells is also used to preheat
the water used in the reforming reaction.) Given proper pretreatment,
hydrogen can be used directly in the cells as can the fuel gas from coal
gasification. Thermal and electrical output from nuclear reactors can
be used to produce hydrogen and oxygen via the electrolysis of water.
In this manner, fuel cells have the potential to become an integral part
of electrical systems for the dispersion of electrical power. However,
if is not known at this time if this approach is being seriously inves-
tigated.
Testing on a 4.8 MWe demonstration fuel cell power plant at Con-
solidated Edison (New York City) should begin in 1980. This electric
utility fuel cell utilizes a phosphoric-acid electrolyte and generates
approximately two thirds of a volt d-c per cell. This effort was under-
taken to demonstrate not only technological feasibility, but also the
social acceptability of locating a power plant in a densely populated
area. (3, 6).
United Technology Corporation is currently working on the develop-
ment of second generation fuel cell models employing molten carbonate
electrolyte. Advantages of this system are a reduction in the by-product
heat rate and operation at high temperature such that a catalyst is not
required in the electrodes. Argonne National Laboratories and General
Electric Company also are conducting ongoing research into molten carbon-
ate systems.
A third approach to fuel cell development has been initiated by
Westinghouse Electric Company. This system employs a high temperature
199
-------
cell with a solid oxide electrolyte. Westinghouse feels this type of
fuel cell could be employed in central power generation plants.
In 1976, DOE sponsored a study to examine industrial applications
of fuel cells. Twelve major industries were selected on the basis of
intensity of energy use, availability of waste gases to fuel the cells,
type of power consumed (i.e., a-c or d-c), and compatibility with cogen-
eration of heat. The best matchings were in the rubber, styrene, and
ethylene industries where the utilization of waste heat from the cells
could reach 100 percent. A chlorine plant was shown to be only capable
of utilizing 30 percent of the waste heat but, nevertheless, is an
attractive candidate because it consumes d-c power and produces hydrogen
fue (3). In the spring of 1978, DOE requested proposals for a feasi-
bility study for the construction, installation, and operation of a 4.8
MW fuel cell power plant in industrial cogeneration applications similar
to the utility trial already in progress but this time involving industry
However, acceptable these feasibility studies prove to be, the
widespread use of fuel cells is presently limited by high equipment
costs and the narrow range of acceptable primary fuels (currently nat-
ural gas or naphtha)(3).
12.4 Environmental Considerations
Identified Pollutants
Central station systems using fuel cells will produce the same
chemical pollutants as those created by conventional utilization of the
same fuels (2). That is, a fuel cell power plant which utilizes coal
for its natural fuel will require coal preparation facilities similar to
conventional coal fired steam plants. For example, there may be dust
nuisance from wind action on the pile and leaks and spills during hand-
I i ng operations.
The proposed commercialization concept for the phosphoric acid fuel
cell anticipates using natural gas or naphtha as fuels. This type of
operation is not expected to create a major environmental concern. How-
ever, future development anticipates utilizing a coal derived gas or high
hydrogen industrial waste gas as a fuel and this operation may create
environmental worker health and safety concerns inherent in coal gasifi-
cation and by-product handling operations.
The fuel cell, however, is particularly sensitive to conventional
combustion pollutants, primarily sulfur (2). This sensitivity will
require extensive fuel pretreatment to eliminate contaminants prior to
electrochemical oxidation. For an equivalent electrica power output,
the higher operating efficiency of an advanced fuel cell system will
200
-------
result in reductions in the quantity of fuel required and effluents along
with a reduction in the emission of nitrogen oxides due to reduced tem-
peratures to which the air streams are exposed. Waste heat rejection is
not a significant problem with fuel cell power systems since much of the
waste heat is used in the fuel gasification or reforming process. The
excess heat is rejected to the atmosphere, and cooling water may not be
requ i red.
An environmental study performed by Exxon for the EPA estimated
emissions from a 638 MWe molten carbonate fuel cell power plant (7).
The NO^ level in the stack gas was estimated at 0.013 /ug/J (0.03 Ib/
MBtu). This level apparently reflects the low temperature of combustion
in the fuel cell catalytic burner. However, NO levels may prove higher
than the thermal NO values reported, due to combustion of ammonia and
other nitrogen compounds present in the coal gasifier product (7).
Hydrocarbon emissions in stack gas were estimated to be negligibly
small. Similarly, particulate emissions in the stack gas should be at
a very low level, since the fuel cell electrolyte system serves to trap
whatever solids appear in the effluent gases. The sulfur level in fuel
cell exhaust was estimated to be about 0.086 jug/J (0.2 Ib/MBtu), due to
thermodynamic limitation on the efficiency of the iron oxide desulfuri-
zation process (7).
For a coal fueled fuel eel I power plant, there wiI I also be sol id
and liquid effluents from the coal storage piles and handling area.
Rain runoff will contain suspended solids and may also contain soluble
sulfur and iron compounds.
The production of leachate from the fuel cells and sludge disposal
from the electrolysis process offer the potential for water pollution.
However, with established technology, these waste streams can be effec-
tively treated and the pollution controlled.
Until commercialization of fuel cell power plants is realized and
the fuel(s) for the plant known, it is difficult to identify specific
pollutants associated with the operation. The experimentaI/feasibi I ity
activities thus far, have not indicated any unique environmental prob-
lems.
Regulatory Impacts
Since large scale commercialization for fuel cell power plants
will probably not take place until after 1990, the regulatory impacts
are unknown. Estimates of emissions from naphtha-phosphoric acid
systems are under current NSPS standards for fossil fueled power plants
(8).
201
-------
12.5 Performance
Current
Since there are no full scale fuel cell power plants currently oper-
ating, no performance efficiencies can be given.
Projected
The fuel cell has the potential for high fuel efficiency over a full
operating range from minimum to maximum power. The theoretical maximum
efficiency of the fuel cell is a function of the fuel and oxidant used.
These theoretical cell efficiencies range between 80 and 100 percent.
Gross efficiency is the product of the theoretical maximum efficiency and
the ratio of the operating voltage to the theoretical voltage. For hydro-
gen fuel cells, this efficiency is estimated between 54 to 61 percent (2).
The EGAS conceptual design of an integrated coal gasifier and molten
carbonate fuel cell power plant estimates the overall efficiency to be
50 percent. The high efficiency of the fuel cell prime cycle, the avail-
ability of high-temperature waste heat for the steam turbine bottoming
cycle, and the availability of high-pressure, high-temperature fuel cell
exhaust for driving turbocompressors. combine to provide this relatively
high overall efficiency. An alternate design utilizing a gas turbine
bottoming cycle has an estimated efficiency of 45 percent (4, 5).
12.6 Economics
Current
Since there are no large fuel cell power systems presently operating,
a current figure for the costs per kilowatt hour is unavailable. Costs
have been calculated for a coal fueled, high temperature system. However,
unresolved problems in any of the fuel cell processing steps could re-
quire significant process additions and add significantly to capital
costs and thus the cost of energy.
The major cost items relating to the fuel cell are the cell itself,
power converters and the spare parts. The key item is the cost of the
fuel eel I.
Projected
Costs have been projected for a coal-fueled, high-temperature sys-
tem by considering research and development progress to date and com-
paring unit costs of various elements with similar items in a coal fired
steam turbine power plant (2). By assuming that the cost of electricity
produced by a coal-fueled fuel cell system is equal to that from a steam
turbine system, the allowable capital costs for the fuel cell system can
202
-------
be projected. The result of these assumptions and calculations is to sug-
gest that a coal-fueled fuel cell system can produce competitively priced
electricity if it can be built for a total capital cost of $294 to $374
per kilowatt electrical (2). As previously indicated, the three critical
items are the fuel eel I, power inverter and spare parts. Each of these
has projected cost ranges that will allow reaching the cost target.
An essential factor is the cost of the fuel cells. The cost range
allocated. $60 to $80 per kilowatt electrical, corresponds to a manufac-
tured cost of $7.00 to $9.50 per pound based on the materials require-
ments. Total material costs for these thin-film, solid-electrolyte
fuel cell assemblies have been estimated to be about $21 per kilowatt
electrical ($2.45 per pound), leaving an allowable margin for manufac-
turing and assembly of $39 to $59 per kilowatt electrical ($4.55 to
$6.85 per pound). These allowable manufacturing costs show reasonably
good agreement with independent direct estimates (4).
The National Academy of Sciences (NAS) estimated the total installed
cost for a 635 MWe integrated coal gasifier fuel cell power plant to be
$595 million or $937/kW, as indicated in Table 26 (4). The power plant
cost is based on an estimated five-year lead time. A high degree of fac-
tory fabrication and low coal handling, gasification, and heat rejection
requirements associated with the high power plant efficiency help mini-
mize the cost of this power plant.
Table 26
1975 Capital Cost Estimate Summary for Integrated Coal
Gasifier Fuel Cell Power Plant (635-MW Plant)
I tern $ Mi I I ions
Land, improvements and structures 48
Coal handling, gasification, gas cleanup,
and ash hand I i ng 79
Fuel cell system equipment 94
Steam plant bottoming cycle equipment 50
Electrical plant equipment 51
A&E services and contingency 78
Escalation and interest during construc-
t;on (at 48.7?) 195
TOTAL 595
203
-------
References - Fuel Cel
1. U.S. Department of Energy. Additions to Generating Capacity
1978-1987 for the Contiguous United States. DOE/ERA-0020,
U.S. DOE, Economic Regulatory Administration, Washington, D.C.,
October 1978.
2. Penny, M. M. and Bourgeois, S. V. Development Status and
Environmental hazards of Several Candidate Advanced Energy
Systems. EPA-600/7-77-062, U.S. Environmental Protection
Agency, Cincinnati, Ohio, June 1977.
3. Davis, J. C. Fuel Cell Trials: Utilities Now, CPI Next?
Chemical Engineering, August 14, 1978. pp. 79-81.
4. National Academy of Sciences. Assessment of Technology for
Advanced Power Cycles. Washington, D.C., 1977. pp. 127-144.
5. Barry, P. B., Fernandes, L. A., and Messner, W. A. A Giant
Step Planned in Fuel Cell Plant Test. IEEE Spectrum, Novem-
ber 1978. pp. 47-53.
6. U.S. Department of Energy. Fossil Energy Program Summary
Document. Assistant Secretary for Energy Technology, DOE/ET-
0087, Washington, D.C., March 1979.
7. Shaw, H. Environmental Assessment of a 638 MWe Molten Carbon-
ate Fuel Cell Power Plant. Government Research Laboratories,
Exxon Research and Engineering Company, Linden, New Jersey,
December 1976.
8. U.S. Department of Energy. Environmental Readiness Document -
Advanced Electric Generation - Commercialization Phase IN
Planning. DOE/ERD-0014, U.S. DOE, Washington, D.C., Septem-
ber 1978. p. 25.
204
-------
13. Magnetohydrodynamics (MHD)
13.1 Overview
Magnetohydrodynamics (MHD) is a potential energy alternative in
which electricity is generated directly from thermal energy, thus elim-
inating the conversion step of thermal to mechanical energy encountered
in conventional steam electric generators. However, due to the nature
of the process, it would be inefficient to apply MHD by itself to the
large scale generation of electricity. Therefore, its eventual imple-
mentation is being planned around combining MHD with a conventional
steam plant to make use of the waste heat from the MHD generator. The
efficiency of such a combined MHD/steam plant is predicted to be about
50 percent or greater (1), as compared to 32 to 35 percent for conven-
tional coal-fired power plants with flue gas desuIfurization (FGD) sys-
tems. Much of this increase in efficiency is attributed to the fact that,
unlike the case of rotating machines, all the rigid structures in MHD
generators are stationary, thus permitting operation at elevated temp-
eratures approaching 5000 F. These temperatures are much higher than
even the most advanced contemporary plants, resulting in much higher
efficiencies throughout the entire thermal cycle than are attainable in
conventional plants (2).
There are three types of MHD systems: open-cycle, closed-cycle
plasma, and closed-cycle liquid metal. In all of these sytems, an
electrically conductive fluid (either gaseous or liquid) is passed
through a magnetic field, thereby inducing a voltage drop across the
gas stream. Electrodes convey the electricity to an inverter where the
direct current naturally produced by the system is transformed to alter-
nating current, which can be transmitted directly into an electric power
grid. Of the three major types being considered, a combined open-cycle
MHD/steam generator system offers the greatest potential to improve
electricity generation plant efficiency and cost performance.
Initial development of MHD began during the late 1950's. Programs
exist both in this country and abroad, notably in Japan and the U.S.S.R.
The basic distinction between the United States and foreign programs is
the emphasis abroad on "clean" fuels usage; that is, natural gas in the
U.S.S.R. and fuel oils in Japan. In the United States, emphasis is on
coal as the primary fuel. The abundance of domestic coal and its ability
to be used directly in an environmentally acceptable manner, make it an
attractive candidate fuel for MHD power generation (1).
MHD could be commercially available in the I ate,twentieth century.
The Department of Energy (DOE) has the lead in MHD development in the
U.S., but other government agencies such as the Environmental Protection
Agency, the National Science Foundation, the National Aeronautics and
Space Administration, and the Office of Naval Research, as well as the
Electric Power Research Institute in the private sector, also fund
research on various aspects of MHD development and impacts.
205
-------
Although much work remains before the widespread application of the
magnetohydrodynamic energy conversion process to electric utility power
generation, there is experimental evidence that MHD can significantly
improve overall power plant efficiencies. Another promising aspect of
this rapidly developing technology is the ability to remove, during the
process, pollutants such as SO , NO , and particulates generated in the
combustion of coal, thereby eliminating the need for external flue gas
scrubbing to meet environmental standards (3).
13.2 Process Description
Concept
MHD is an application of a simple law of physics that has been prac-
ticed for over 150 years to generate electricity. This law states that a
conductor moving across a magnetic field produces an electrical current.
In the case of MHD, electricity is generated by the interaction of a
conductive fluid moving through a magnetic field. Such an application
is not new. MHD began to evolve over a century ago, but now the attempt
to translate it into a viable, commercially acceptable energy-conversion
technology is intensifying (2).
The principle of MHD can best be explained by examining the simplest
type of MHD generator, named after the English physicist Michael Faraday,
depicted in Figure 47. As shown in Figure 47, the basic MHO generator
consists of a channel, suspended in a magnetic field, consisting of a
cathode, anode, and insulating walls. The flow of the conducting fluid
(jj_) across the magnetic field (B) results in an induced electromotive
Load
Magnetic field
Cathode
insulati ng walIs
Fluid flow
Anode Electric field
Current
Figure 47
Faraday MHD Generator
206
-------
force (EMF) and a current in an external load. This particular generator
configuration can operate efficiently only when the fluid is a liquid
metal as opposed to a conductive gas. However, other generator configur-
ations and power takeoff schemes have and are continuing to be developed
which permit the use of the more practical gaseous conductive fluid.
As would be expected from the discussion above, the key element in
the systems now under development is the MHD generator. Essentially,
this is an expansion engine that converts super-hot gases from the
burning coal directly into electricity. In order to accomplish this, the
coal is first pulverized and then burned in a highly efficient combustor.
A small amount of an alkali metal salt (usually potassium carbonate) is
added to the combustion gases to produce a plasma. This super-hot swarm-
ing mass of electrically charged gas then passes at high velocity through
a strong magnetic field between two electrodes. The positive and negative
ions separate and collect at opposing electrodes. The difference in
potential between the electrode plates drives a current through an exter-
nal circuit.
The heart of the MHD generator is the channel which is suspended
between the poles of a powerful magnet. This is comprised of a multitude
of hollow rectangular metal frames stacked horizontally and insulated
from each other to form a long corridor through which the hot gases flow.
Electrodes are mounted on opposite sides of each frame through which
water circulates to prevent overheating.
By seeding the combustion gas with easily ionized materials such as
potassium or cesium, the electrical conductivity sufficient for the pro-
cess can be obtained at somewhat lower temperatures (4500 to 5000 F)
than would be required otherwise. From an economic as well as environ-
mental standpoint, potassium—in the form of potassium carbonate (K^CO-,)
or potassium hydroxide (KOH) — is the preferred seed material for open-
cycle MHD. The potassium seed not only enhances the conductivity of the
combustion gas, but also provides a unique built-in capability for re-
moving sulfur products released during the combustion of sulfur-bearing
fuels (in particular, high-sulfur coal). The potassium seed reacts pref-
erentially with the sulfur at high temperatures and later precipitates
out as potassium sulfate (K~SO.) when the combustion gas cools. The
potassium sulfate can be removed from the system along with the ash by
particulate control devices and then be regenerated to yield potassium
carbonate or potassium hydroxide, which is recycled (1).
Deta iI
Much of the early work with MHD was performed with liquid and gas-
eous fuels. As stated earlier, MHD developmental programs in both Japan
and Russia are designed for gas and oil firing. Although there is some
limited research in closed-cycle systems, the high temperatures achieved
in open-cycle operation with resultant improvements in efficiency and
their applicability to coal utilization favor this latter type (3).
207
-------
Open-Cycle MHD
A simplified schematic of a complete open-cycle MHD/steam plant is
presented in Figure 48. This possible configuration is representative
of the types of integrated designs being developed. It should be noted
that it is presently conceptual, and testing of such a system has yet
to be accomplished (4). In the system outlined in Figure 48, coal is
dried and crushed before being fed to the combustor. The water-cooled
combustor operating with preheated air produces combustion gas products
at temperatures in excess of 4600°F. Eighty-five percent of the coal
slag is rejected from the combustor. The combustion gas is seeded with
potassium carbonate (K-CO ) to increase its electrical conductivity.
This product is then expanded in an MHD generator producing a d-c elec-
trical output. The expanded gases are reduced in velocity in a diffuser
section to recover the remaining kinetic energy before entering the first
heat exchange state—the radiant furnace—at temperatures in excess of
3660 F. A two-second residence time is provided i-n this furnace at
approximately 2900 F to permit decomposition of NO as an emission con-
trol step. Combustion is completed by the addition of air at the exit
of this heat exchange section. The gases then enter a series of regen-
erative high-temperature air pre-heaters. These cyclic, refractory heat
exchangers are utilized to preheat the combustion air to 2500 F. The
exhaust gas then enters a secondary furnace containing a steam generator
and low-temperature air preheater section (the combustion air exits from
this heat exchanger at approximately 1400 F). The combustion gas then
enters an economizer section where its temperature is reduced to approxi-
mately 250 F before passing through an electrostatic precipitator and
discharged out the stack. The seed material, KJDO-,, is used to increase
the electrical conductivity of the gas as well as To tie up the sulfur
in the coal as potassium suIfate (HLSO.) (5). Experimental tests have
achieved better than a 99 percent removal of the S0?from the effluent
gas (6). This potassium sulfate is collected from the heat exchange
components and the electrostatic precipitator and returned to a seed
recovery system where an intermediate-Btu gas reduces the K?SO. to K?CO,
seed material and hydrogen sulfide (I-LS). Elemental sulfur is recovered
from the H2S in an integral Claus plant. Feedwater is used to cool the
combustor and MHD channeI/diffuser. Steam is generated at 3500 psi/
1000 F/1000 F in the heat exchange equipment. This steam is utilized
in two steam turbines: one provides mechanical drive to the air compres-
sor which supplies air at approximately 10 atmospheres for the combustor/
MHD channel. The other steam turbine drives an a-c generator. The d-c
output of the MHD channel is converted to a-c in solid-state inverters (5)
Closed-Cycle MHD
In the closed-cycle MHD processes, the basic energy conversion pro-
cess is the same as that for open-cycle MHD (i.e. motional electromag-
netic induction). However, in the closed-cycle processes, the working
208
-------
Reducing Go*
Sulfur
Raw
Cool'
Air Preheoterj
and Steam Generators
o
VO
Cooling
Water
Makeup
Figure 48
Open-Cycle MHD/Steam Plant - Schematic of Possible Configuration
-------
fluid is in a closed-loop system and receives the heat energy indirectly
from a primary source through a heat exchanger. The primary heat source
can be from the combustion of coal, other fossil fuels, or from a nuclear
reactor. Because the working fluid is recycled in closed-cycle systems,
there is more latitude available in choosing the working fluid and in
obtaining electron densities that give sufficient conductivity. As a
result, somewhat lower temperatures than those required in open-cycle
systems are necessary to obtain sufficient conductivity for the MHD
process. The extraction of thermal energy from the working fluid and
its conversion to electricity in an MHD channel and conventional steam-
bottoming plant are similar for open- and closed-cycle systems. There
are two major approaches to closed-cycle MHD technology: plasma systems
and liquid metal systems (1).
In a closed-cycle plasma MHD system, the working fluid is a noble
gas, such as argon, which is seeded with an easily ionized material such
as cesium. Figure 49 is a schematic diagram of a closed-cycle plasma
MHD system (7). Air is preheated prior to entering the combustor. The
hot combustion gas is ducted to heat exchangers which transfer heat to
the argon working fluid. After leaving the heat exchangers, the com-
bustion gas passes through an air preheater prior to being exhausted out
the stack. The argon gas is expanded through a nozzle where it is seeded
with cesium. The argon/cesium gas passes through the MHD generator which,
as in open-cycle MHD, produces d-c power. After passing through a diffu-
ser, the gas flows through an unfired steam generator. The cesium is
condensed into liquid in the precooler, purified, and then reinjected at
the nozzle. The argon is compressed, purified, and recycled to the high-
temperature heat exchanger. The steam turbine plant produces substantial
electric power and drives the argon compressor (1).
Liquid metal systems are very similar to closed-cycle plasma systems,
with one major exception: a gas-liquid metal froth is used as the work-
ing fluid rather than a noble gas. Liquid metal systems have high elec-
trical conductivities compared to totally gaseous systems, the potential
for lower temperatures, and the applicability of lower magnetic fields.
As a result, a smaller plant and higher extraction efficiencies may be
possible. Figure 50 is a schematic diagram of a liquid metal MHD system
(7). The pressurized liquid metal (usually sodium) is heated to peak
cycle temperature in an externally heated exchanger fired by a fluid!zed-
bed coal combustor and then flows to a mixer where heated helium is in-
jected as a uniform dispersion of bubbles. Heat is transferred from the
liquid to the gas, resulting in nearly isothermal expansion as the fluid
passes through the MHD generator. After leaving the generator, the gas
and liquid are separated and the liquid is recirculated back to the
mixer. The gas passes through the diffuser to a steam bottoming plant
where its heat is utilized. The helium then is compressed and recycled
to the heat exchanger and the mixer (1).
As previously indicated, the emphasis in the United States is on
the combined open-cycle MHD/steam generator system approach. Since all
no
-------
HCAT CXCHAMOIR AKOAYI
•CHEAT
THAlt
FLUI
CAJ
ruKCI
PMAJC
INCUT
Gil
ruitcc
fMAJC
•LOW
com
rn*jc
L»*«Ti \ OXX.IMC
I ii'.«T~' \To»my
Figure 49
Simplified Schematic of Closed-Cycle Inert Gas MHD Topping Cycle
-------
M
TO
HACK
r
LO« TIMP.
TO
COAL
TULA!
• BIT
V
I LMIITOBI
uectno
TATO«
Figure 50
Simplified Schematic of Closed-Cycle Liquid Metal MHD
Topping Cycle Fired by Fluidized Combustor
-------
efforts are in early R&D stages, any energy balances are at best projec-
tions. Table 27 based on reference 5 provides a considered heat balance
for an open-cycle MHD/steam generator plant. Diagrammatically, this can
be illustrated by the heat flow diagram, Figure 51. It should be noted
that both Table 27 and Figure 51 present overall system values and do not
indicate intra-system energy transfers (e.g. employment of recovered
heat). The overall heat balance assumes that electrical energy generated
via steam would be produced at 1 kWh per 8160 Btu (reference 5). This
is not an unreasonable projection when compared to the projection for the
conventional steam-electric plant and taking into account differences in
component makeup with associated energy loss values.
Table 27
Projected Heat Balance for Nominal 2000 MWe Open-Cycle MHD/Steam Plant
Btu/hour Percent of Total
(10 Btu's) Energy Input
Net Electrical Energy Output 6,593.92 48.30
(MHD power 1420 MWe plus steam
power 587 MWe less losses)
Heat Rejected
Cooling tower 4,589.80 33.62
Stack 1,171.34 8.58
Energy Consumed or Loss
Additional energy input (for
precipitator, seed recovery, 853.25 6.25
Claus un it, etc.)
Coal ash and K9SO. (sensible and
latent) 109.22 0.80
Coal heating and miscellaneous 79.18 0.58
MHD inversion loss and auxiliary
power requirements for coal 255.29 1.87
handling, transformer loss, etc.
Total Energy Input 13,652.0 100.0
(Coal supplied 98.45?, correction
for SO —> K?SO. (G) condensation
and solidification of K SO 1.6$)
213
-------
\00%
Total Energy Input
6.25?
Energy consumed
by precipitator, for
seed recovery, claus
unit, etc.
3.25?
due to
ash,
Losses due to coa
K-SO (sensible &
latent), coal heating,
MHD inversion loss,
auxi Ii ary power
requirements for coal
handling, transformer
losses, misc.
33.62?
Energy
rejected by
cooli ng tower
8.58?
Stack loss
48.30?
Net electric power output
(approx. 70? from MHD & 30?
from conventional)
Figure 51
Projected Heat Balance For Nominal 2000 MWe
Open-Cycle MHD/Steam Plant
214
-------
13.3 AppI ications
Current
At present, there are only experimental MHD working models in this
country. The life expectancy of these models has been limited by the
combined effects of current leakage, arcing between the electrodes, and
the corrosive effects of high-temperature combustion gases and residues.
Presently, there are major research, development, and testing programs
at the component and subsystems level to alleviate these problems. This
work is being sponsored by the Department of Energy with additional sup-
port from the Electric Power Research Institute and several utility
compan ies.
The U.S.S.R. and Japan have also been quite active in the further-
ance of this technology. In the U.S.S.R., an MHD pilot installation
designated U-25, has been constructed and operated. The U-25 generator
is rated at 20 MW nominal, and is gas fired. A smaller facility desig-
nated U-25B, which uses the same feed supplies and utilities as the U-25,
has been used for joint U.S.-U.S.S.R. channel testing. The U.S.S.R. has
announced the planning and design of the first large-scale commercial
MHD/steam power plant of nominal 500 MW total capacity, with oil-firing.
In Japan, an experimental oil-burning MHD generator with a 4 Tesla super-
conducting magnet has been tested at power levels of close to 500 kW,
and other MHD system componenets have been studied on a small scale in
an integrated component test facility. Other MHD development programs
are currently in progress in Poland, Germany and India (3).
Projected
It is difficult to specify the role MHD will play in the future of
domestic power generation. However, there has been a significant commit-
ment of resources toward near-term goals (Fiscal 1979 DOE-MHD Budget
was $80 mill ion).
Specifically, the United States plans to have an operational pilot
plant as early as 1985 and a base-load commercial demonstration before
1995 (2). Current plans call for this to be achieved in three phases (8)
as follows:
1. Ongoing thru mid-1980's - development of engineering
data and experience to design and build a 250 MW pilot
plant—the Engineering Test Facility (ETF).
2. Running parallel with Phase I and on thru the 1980's -
design, construction and operation of the ETF, a fully
integrated combined cycle MHD/steam system operating
at 250 MW, the minimum scale that can demonstrate the
concept and still be of interest to utilities, and
215
-------
3. During the mid- to late 1990's - demonstration of
baseload power plant performance at several hundred
megawatts using Commercial Demonstration Plants (CDPs).
Any large-scale commercial implementation of MHD combined-cycle power
generation facilities will be in the post 2000 period.
13.4 Environmental Considerations
Because open-cycle MHD technology has been developed further than
the closed-cycle plasma or liquid metal MHD technologies and since the
DOE MHD program emphasizes open-cycle MHD, this discussion focuses pri-
marily on the environmental concerns associated with open-cycle MHD. For
closed-cycle systems under normal operating conditions, the effluents
(e.g., S07, NO , hydrocarbons, CO, trace elements, particulates, ash
residue, etc.)xmay be similar to those produced by conventional boilers
and will not be discussed further (1).
Identified Pollutants
The range of pollutants from an MHD system is expected to be similar
to the range of those associated with direct combustion processes. How-
ever, due to the extremely high temperatures required in the MHD process
as compared to the relatively low temperatures of direct combustion tech-
nologies, significantly different relative amounts of the various efflu-
ents will be emitted. Due to the higher overall plant efficiencies of
MHD power generation, less coal input is needed per unit of electrical
output; therefore, pollutants (such as S0~ emissions), thermal discharges,
solid wastes, and their associated environmental impacts are expected to
be less than those from a conventional coal-fired power plant of compar-
able generating capacity. However, sufficient experimental data are not
available to verify this (1).
Air Emissions
Although fugitive emissions are a potential hazard to worker health
and safety, the air emissions of primary concern are stack emissions.
At the high temperatures intrinsic to MHD power generation, nitrogen
oxide (NO ) production is increased while the production of organic
effluents, particularly the condensed polycyclic organic molecules (POM's)
is decreased. The high temperatures also may alter radically the physi-
cal and chemical formation and the selective enrichment of various trace
element compounds found in the fly ash particles. Because of the nature
of sulfur-seed reactions unique to MHD processes, quantities of sulfur
oxide (SO ) are likely to be much lower in the effluents of an MHD facil-
ity than in those of a standard, commercial, coal-fired power plant (1).
216
-------
An anticipated feature of the MHD power generator is a self-contained
sulfur removal system inherent in its design. The potassium carbonate
(KLCO,) seed used to increase the conductivity of the working fluid will
combine with the SCL to form a sulfate or sulfite, which will be removed
with the slag in the seed condenser and/or by particulate control devices.
As stated earlier, experimental work has demonstrated S09 removal effi-
ciencies from such seeding can exceed 99 percent for coaf containing 2.2
percent sulfur by weight (6). Further studies have shown that the S0?
content of emissions can be almost eliminated by increasing the seed
rate, even using high sulfur coal which is environmentally unsuitable
for use in conventional power generating plants (9).
The high-combustion temperatures of open-cycle MHD could produce up
to ten times the nitrogen oxide (NO ) emissions produced by conventional
coal combustion (10, 11, 12). NO is a significant pollutant because
of its direct effect on plants anS animals and its role in the photo-
chemical oxidant cycle. Thus, NO potentially presents the principal
emission problem to be found in tfte MHD system.
Two methods of NO control have been identified: minimization of
NO in the effluent gas, or maximization of NO in the effluent to recov-
er nitrogen compounds (e.g., fertilizer). Presently, it appears that
NO emissions will be controlled by the first technique through combus-
tion modification. Combustion modification includes techniques such as
initial fuel-rich combustion, down-stream adjustment of the fuel-air
mixture to make it air rich (sometimes referred to as "two-stage air com-
bustion"), and regulation of exhaust gas residence times in down-stream
components to enhance decomposition of NO formation. According to data
from the University of Tennessee Space Institute (UTS I) MHD test facility,
NO emissions can be kept well below applicable standards by controlling
the stoichiometric ratio and radiant boiler residence times (11). These
data agree with data from earlier studies by others at Avco-Everett
Laboratory (13). However, these data are in conflict with the Exxon
computer modeling work. Their computer modeling of NO formation and
decomposition in open-cycle MHD indicates that NO emissions may be near
or above currently allowable limits (12).
It is expected that particulate matter existing in the exhaust gases
will consist primarily of fly ash, with some unrecovered seed material
(potassium carbonate and potassium sulfate). Due to the very high com-
bustion temperatures characteristic of MHD, and possibly due to the ef-
fects of NO controls (14, 15), fly ash emissions from MHD are expected
to consist of a greater proportion of fine particulate matter than those
produced by conventional coal-fired power plants. These fine particles
(<3 microns) may present a hazard to human health because they can enter
and be retained in the lungs.
Emission of particulate sulfates, especially spent seed material,
is a potential problem associated with MHD. Atmospheric sulfates have
217
-------
been implicated in such adverse environmental effects as acid rains, the
modification of weather, visibility, and climate (.1).
The environmental impacts of trace element emissions from a coa I -
fired MHD facility depend on coal quality, method of burning coal, power
plant size and location, emission control technologies, and weather con-
ditions (16). When coal is burned, the trace elements will 1) be trap-
ped in bottom slag; 2) be collected in the emission control device as
particulate ash; 3) escape through the stack as a gas or by adhering to
effluent particles; or 4) escape as fugitive emissions within the facility
environment. While a substantial fraction of trace elements present in
the coal is retained with the fly ash and slag removed by control devices,
significant quantities of trace elements still may be emitted as or on
submicron-size particles because of collection inefficiencies in the
small particle range characteristic of these devices. Potassium and
radioactive compounds, as well as trace elements, adhere to the surfaces
of particulates. Volatization of some trace elements during coal com-
bustion and their release to the atmosphere in the gaseous phase also
occur. Because of its characteristically high temperatures, this may be
of particular concern in MHD.
Liquid Effluents
Effluents will result from boiler cleaning, cooling systems, and
feedwater treatment processes which are not unique to the MHD technol-
ogies themselves, but exist in conventional boilers as well. Secondary
water pollution can result from runoff and leaching from solid waste
disposal sites if appropriate control measures are not taken. No data
are currently available on the leachability of specific compounds and
trace elements contained in MHD slag and fly ash. It is expected that
the trace elements potentially found in MHD effluent streams and solid
waste leachate will be similar to those identified for air emissions.
Effluents resulting from MHD processes, seed regeneration, and solid
waste disposal need to be characterized and assessed to ensure that they
do not contain any unexpected hazardous pollutants or excessively high
potassium levels, and that they will meet applicable water quality
standards (17).
Sol id Waste
A MHD faciI ity, I ike any conventionaI coaI-fired power plant, will
produce solid waste. MHD-generated solid waste will be unique in several
respects: 1) it will contain potassium compounds (K»CO,, K?SO., and/or
KOH) resulting from the injection of the seed material; 2) the slag col-
lected from the combustor and other components will have different prop-
erties than bottom ash collected in conventional coal-fired systems;
3) fly ash collected in the emission control device probably will contain
218
-------
a greater proportion of fine particles; and 4) trace elements adhering
to the surface of these fine particles may be more toxic to biological
systems through leaching and fugitive dust emissions.
In order for open-cycle MHD to be acceptable both environmentally
and economically, it is expected that the seed material must be recovered,
probably regenerated, and recycled. The method has not been defined yet
but the decision will affect both the quality and quantity of the solid
waste generated from an MHD facility (1).
Regulatory Impacts
Since large-scale commercialization of MHD is planned for after the
turn of the century, it is difficult to conjecture what the environmental
regulatory climate will be for utility plants. In spite of the uncertain
regulatory future and the final measurement and characterization of pol-
lutants from MHD systems, it is generally agreed that because of its
higher thermal efficiency, there will be less coal consumption per unit
of electrical output and therefore, reduced emissions per Btu output
than from conventional coal-fired generating facilities.
13.5 Performance
Current
Since there has yet to be a fully integrated MHD power generating
facility, no actual performance efficiency has been measured.
Projected
Of all the emerging power generation technologies, MHD offers one
of the most promising performance efficiency. Overall efficiencies of
MHD-based systems (coal pile to electrical bus-bar) may exceed 50 percent
as compared to 34 to 37 percent projected for conventional coal-fired
plants with FGD now scheduled for construction (2). In practice, the
coal-fired MHD generator will be installed as a topping system at the
front end of a conventional steam turbine power plant, where it will draw
off twenty percent of the coal's total energy. The hot exhaust gases
will then be used to power the steam turbines, which will extract an
additional 30 to 40 percent of the available energy. The total combined
output (50 to 60 percent) is half again as much electrical power as that
produced by today's conventional steam or nuclear power plants. Since
coal-fired steam power plants currently supply about half of the nation's
electrical energy (19), merely adding MHD as a topping system to exist-
ing plants could conceivably increase the nation's generating capacity
by as much as 25 percent with the same fuel consumption.
219
-------
13.6 Economics
Current
Since there are no commercial generation plants presently employing
an MHD system in this country, a current figure for the cost per kilowatt
hour of electricity is unavailable. However, detailed projections have
been made of MHD costs and their behavior relative to conventional coal-
fired plants beginning around 2000 when wide-scale implementation should
occur.
Projected
Obviously, there is some measure of uncertainty associated with cost
estimates for an emerging technology which is not even scheduled to go
on-line until 1990. However, preliminary estimates indicate that in the
1990's, MHD-generated electricity will sell for around 32 mills/kwh as
compared to about 45 mills/kwh for that from conventional coal-fired
plants at that time (2). These estimates were based on theoretical
plant configurations covered by the EGAS. Under their ground rules,
capital costs were escalated by a combination of factors to the year
construction would be completed if it had been started in mid-1975. The
O&M cost component was based upon mid-1975 dollars and the fuel cost was
based upon specified prices intended to project the period of consump-
tion. Although many factors such as inflation rates and the period of
implementation have changed substantially since that time, the relative
cost advantage appears to be supported by more contemporary estimates.
Indications are that capital cost per kilowatt of installed capacity
for an MHD topping system will be about the same as that for a conven-
tional steam power plant in the latter 1990's. However, the operating
costs per kilowatt may be significantly lower due principally to a more
efficient utilization of fuel.
220
-------
References - Magnetohydrodynamics (MHD)
1. U.S. Department of Energy (DOE). Environmental Development
Plan (EDP) - Magnetohydrodynamics Program FY 1977. DOE/EDP-
0009, U.S. DOE, Washington, D.C., March 1978.
2. MHD's Target: Payoff by 2000. IEEE Spectrum, May 1978. pp.
46-51.
3. Hals, F. A., et a I, Avco Everett Research Laboratory, Inc.
MHD Power Generation. Paper presented at Coal Technology '78
Meeting in Houston, Texas, October 17-19, 1978.
4. MHD: More Money for Promising Technology. Coal Industry News.
August 7, 1978. p. 17.
5. Energy Conversion Alternatives Study (EGAS). General Electric
Phase II Final Report. NASA-CR 134949. December 1976.
6. Bienstock, D., Bergman, P. D., Henry, J. M., Demski, R. J.,
Demeter, J. J., and Plants, K. D. Air Pollution Aspects of
MHD Power Generation. Proceedings of the 13th Symposium on
Engineering Aspects of Magnetohydrodynamics, Stanford Univer-
sity, March 25-28, 1973. pp. V11-1.10.
7. Jackson, W. D. MHD Electrical Power Generation: Prospects
and Issues. AIAA Paper No. 76-309, AIAA 9th Fluid and Plasma
Dynamics Conference, San Diego, California. July 14-16, 1976.
8. Breakthrough in MHD Testing Told. Coal Industry News.
August 7, 1978. p. 1 .
9. Bergman, P. D., Gyorke, D., and Bienstock, J. J. Economic and
Energy Considerations in MHD Seed Regeneration. 16th Symposium
on Engineering Aspects of Magnetohydrodynamics, Pittsburgh,
Pennsylvania, 1977.
10. Bienstock, D., Demski, R. J., and Demeter, J. J. Environmental
Aspects of MHD Power Generation. Proceedings of the 1971 Inter-
society Energy Conversion Engineering Conference, Boston, Mass-
achusetts, August 3-5, 1971. pp. 1210-1217.
11. Strom, S. S., Chapman, J. N., Meuhlauser, J. W., and Lanier,
J. H. Controlling NO from a Coal-Fin
Intersociety Energy Conversion Engineei
Diego, California, August 20-25, 1978.
J. H. Controlling NO from a Coal-Fired MHD Process. 13th
Intersociety Energy Conversion Engineering Conference, San
22:
-------
12. Shaw, H. Environmental Assessment of Advanced Energy Conver-
sion Technologies, Government Research Laboratories, Exxon
Research and Engineering Company, Linden, New Jersey, Febru-
ary 9, 1978.
13. Hals, F. A., and Lewis, P. F. Control Techniques for Nitrogen
Oxides in MHD Power Plants. ASME Paper 72-WA/ENER-5, 1972.
14. Nadar, J. S. Field Measurements and Characterization of Emis-
sions from Coal-Fired Combustion Sources. 71st APCA Annual
Meeting, Houston, Texas, June 25-30, 1978.
15. Schmidt, E. W., Dieske, J. A., and Allen, J. M. Size Distrib-
ution of Fine Particulate Emissions from a Coal-Fired Power
Plant. Atmospheric Environment. 1976. Vol. 10, pp. 1065-1069
16. Matray, P- The BioenvironmentaI Impact of Trace Element Emis-
sion From A Magnetohydrodynamics (MHD) Facility: A Literature
Review and Recommendations. Montana Energy and MHD Research
and Development Institute In-House Document, No. 3F19:76N9.
September 1976.
17. Barret, B. R. Controlling the Entrance of Toxic Pollutants
Into U.S. Waters. Environmental Science and Technology. 1978.
Vol. 12(2). pp. 154-162.
18. Balzhiser, R. E. Energy Options to the Year 2000. Chemical
Engineering. January 3, 1977- Vol. 84 (1), pp. 73-90.
19. Coal Facts 1978-1979. National Coal Association. Washington,
D.C., 1979.
222
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-80-173
2.
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE
Environmental, Operational and Economic Aspects of
Thirteen Selected Energy Technologies
5. REPORT DATE
September I960
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
Lawrence Hoffman, Stephen E. Noren & Elmer C. Holt, Jr.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
The Hoffman-Muntner Corporation
8750 Georgia Avenue
Silver Spring, Maryland 20910
10. PROGRAM ELEMENT NO.
1NE825
11. CONTRACT/GRANT NO.
68-01-4999
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Environmental Engineering
and Technology, Headquarters
U.S. Environmental Protection Agency
Washington. D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Task Report
14. SPONSORING AGENCY CODE
EPA/600/17
15. SUPPLEMENTARY NOTES
EPA Contacts:
Mr. William N. McCarthy, Jr.
Mr. Morris H. Altschuler
Mr. Robert M. Statnick
202/755-2737
202/755-0205
202/755-0205
16. ABSTRACT
This report covers the environmental, operational, and economic aspects of thirteen (13) current
and developing technologies as applied to the generation of electric power, steam generation, and the
conversion of fossil energy Into alternative forms. The following technologies are addressed: I) Con-
ventional Boiler; 2) Diesel Engine; 3) Fluidized-Bed Combustion; 4) Combined Cycle Systems; 5) Low/
Medium-Btu Gasification; 6) Chemically Active Fluid Bed; 7) Indirect Coal Liquefaction; 8) High-Btu
Gasification; 9) Surface Shale Oil Processing; 10) In Situ Shafe Oil Processing; II) Direct Coal Lique-
faction; 12) Fuel Cells; and 13) Magnetohydrodynamics (MHD). The present status of each technology is
discussed along with prospects for commercial implementation.
Some of these processes such as conventional coal-fired boilers and combined cycle electrical
utility systems are currently being applied to varying degrees for base, intermediate, and peaking ser-
vices at power plants. When using cleaner fuels (distillate oil and gas), some addressed processes re-
quire only limited environmental controls. Due to the shortages associated with currently utilized
cleaner fuels, greater emphasis is being placed upon the rapid development of alternative technologies
capable of using the Nation's more abundant reserves of coal, oil shale, and heavy crude oil in an
environmentally acceptable fashion. One such technology, permitting the direct use of high-sulfur coal,
is fIuidlzed-bed combustion which is currently being demonstrated in industria I-sized units. Other
technologies involve the conversion of coal to a suitable liquid or gaseous fuel for use in existing
equipment and for advanced technologies under development, and the conversion of oil shale to a com-
mercial grade oil product. Also discussed are some of the more remote processes, such as fuel cells and
MHD, which offer the prospect, when substantial technical hurdles are overcome, for improved efficiencies
while maintaining environmental compliance.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI F-ield/Group
Air Emission!
Chemical ly
Active FB
Contained Cycle
ConventlonaI
Boller
Oiesel Generators
Efficiency
Energy Conversion
Energy Efficiencies
EnvIronment
Fluldlzed-Bed
Fuel Cell
Fuel Conversion
Fuel Processing
Techno log Ies
Hlgh-Btu Gasification
Liquefaction
Liquid Effluent!
Lo--Btu Gasification
Magnetohydrodynamlcs
Oil Shale
Performance
Power Generation
Shale Oil
Sol Id Waste
Thermodynamlc
Efficiencies
BI-GAS
CO-Acceptor
Combustion
EngIneerlng.
Inc.
Fi scher-
Tropsch
M-Coal
HYGAS
Kbppers-Totzek
Lurgl
MobiI Process
Occidental Modified
In Situ
Solvent Refined Coal
SRC
Synthone
SynthoiI
TOSCO I I
Westinghouse Electric
Corporotion
10A 97F
10B 97G
43E 971
43F 97K
680 97L
97B 97R
18. DISTRIBUTION STATEMENT
Re lease UnIimited
19. SECURITY CLASS (This Report/
UNCLASSIFIED
21. NO. OF PAGES
20. SECURITY CLASS (This page)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1
v. 4-77)
PREVIOUS EDITION IS OBSOLETE
223
{[U.S. GOVERNMENT PRINTING OFFICE: 1 980-341 - 085/46 1 ;
------- |