United States
Energy Research and
Development Administration
Federal
Energy
Administration
United St.itcs
Environmental Protection
Agency
Office of
Fossil Energy
Washington^ D.C. 20545
Office of
Conservation and Environment
Washington, D.C. 20461
Office of
Research and Development
Industrial Environmental Research
Laboratory
Research Triangle Park, N.C. 27711
EPA-600/7-77-011
January 1977
APPLICATION OF FLUIDIZED-
BED TECHNOLOGY TO
INDUSTRIAL BOILERS
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven 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
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 systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses 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 environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal
Agencies, and approved for publication. Approval does riot
signify that the contents necessarily reflect the views and
policies of the Government, nor does mention of trade names
or commercial products constitute endorsement or recommen-
dation for use.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-77-Oil
January 1977
APPLICATION OF
FLUIDIZED-BED TECHNOLOGY
TO INDUSTRIAL BOILERS
by
M.H. Farmer, E.M. Magee, and F. M. Spooner
Exxon Research and Engineering Company
P.O. Box 8
Linden, New Jersey 07036
Contract/IAGNos. IAG-D5-E767 (EPA), IAG-E(49.18)-1798 (ERDA),
and CO-04-50168-00 (FEA)
Program Element No. EHB536
Project Officers: B.Henschel (EPA), W.Siskind (ERDA), A.Hayes (FEA)
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
U.S. ENERGY RESEARCH AND DEVELOPMENT ADMINISTRATION
Office of Fossil Energy
Washington, DC 20545
and
U. S. FEDERAL ENERGY ADMINISTRATION
Office of Conservation and Environment
Washington, DC 20461
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TABLE OF CONTENTS
Page
SUMMARY i
HIGHLIGHTS v
1. INTRODUCTION, OBJECTIVES AND APPROACH 1
1.1 Introduction 1
1.2 Objectives 1
1.3 Approach 2
1.4 Structure of Report 2
2. INDUSTRIAL BOILER SYSTEMS 4
2.1 Characteristics of Industrial Boilers 5
2.1.1 Types of Industrial Boilers 5
2.1.2 Boilers Firing Solid Fuels 7
2.1.3 Present Population of Large Industrial Boilers. . 7
2.1.4 Description of Fluidized Bed Combustion as
Applied to Industrial Boilers 8
2.1.5 Different Versions of Fluidized Bed Combustion. . 11
2.1.6 Timetable for FBC Developments 13
2.2 Boiler System Options 15
2.2.1 Energy Needs of a Process Plant 15
2.2.2 Fuels Basis 16
2.2.3 Boiler Basis 17
2.3 Estimated Investments and Operating Costs 17
2.3.1 Basis for Comparing Alternative Technologies. . . 19
2.3.2 Overall Results for Single Boiler Addition
Cases 26
2.3.3 Overall Results for Grass-roots Boiler Plants . . 31
2.3.4 Areas of Technical Uncertainty 33
2.3.5 Significant Cost Reductions Possible for Future
FBC Designs 37
2.3.6 Revamping of Existing Boilers for FBC Service
Not Likely 38
2.4 Market Survey of Large Industrial Boiler Users 39
2.4.1 Survey Procedure 39
2.4.2 Results and Interpretation 40
2.5 Specific Technical Requirements for Representative
Industrial Fluidized Bed Boilers ..... 43
3. MANUFACTURING INDUSTRIES 47
3.1 Standard Industrial Classification 47
3.2 1972 Census of Manufactures ..... 47
3.3 Fuel Consumption of Large Industrial Boilers in 1974 . . 49
3.4 Discussion of Future Options 58
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TABLE OF CONTENTS (continued)
4. FUTURE DEMAND FOR INDUSTRIAL BOILER FUEL 68
4.1 Basis of Demand Projections 68
4.2 Quantitative Projections 69
5. PROJECTIONS OF COAL-FIRED FBC POTENTIAL 80
5.1 Basis of Projections 80
5.2 Modification of Basis 83
5.3 Regional Applicability 84
5.4 Maximum, Most Probable, and Minimum Potentials 86
5.5 Additional Applications of Coal-Fired FBC 86
5.6 Boiler Fuel Demand Where FBC is Not Applicable 88
5.7 Regionalization of Coal-Fired FBC Potential 91
6. ENERGY IMPACTS 103
6.1 Impact on National Energy Consumption 103
6.2 Potential Savings of Oil and Natural Gas 104
7. ECONOMIC IMPACTS 107
7.1 National Impacts 107
7.2 Regional Impacts 110
7.3 Boiler Manufacturing and Related Industries .110
7.4 Coal Industry 115
7.5 Limestone Industry 115
8. ENVIRONMENTAL CONSIDERATIONS J.18
8.1 Introduction 118
8.2 Fuels and Boilers Considered 118
8.2.1 Emissions Considered 121
8.2.2 General Approach to the Environmental Analysis. .121
8.3 Bases and Assumptions 121
8.3.1 Description of Operating Units 122
8.3.2 Descriptions of Fuels Considered 122
8.4 Results for Individual Installations 122
8.4.1 Estimates of Particulate Emissions 126
8.4.2 Estimates of S02 Emissions 126
8.4.3 Estimates of NOx Emissions .126
8.4.4 Estimates of Solid Wastes .130
8.5 National and Regional Emissions 130
8.6 Estimates of Emissions for Selected Air Quality
Control Regions 131
8.6.1 Current Situation: Mass Emissions .13^
8.6.2 Current Situation: Ambient Air Quality .... j.36
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TABLE OF CONTENTS (continued)
8.6.3 Future Situation:
8.6.4 Future Situation:
Page
Mass Emissions. . 142
Ambient Air Quality 143
8.7 Disposition of Solids and Sludge 146
8.7.1 Solid/Sludge Byproducts 146
8.7.2 Solids Disposal 148
8.7.3 Utilization of Solid Wastes 148
8.7.4 Regeneration of Treater Materials. . 149
8.8 Modification of Basis 149
8.9 Environmental Conclusions and Recommendations 150
9. CONCLUSIONS 155
10. REFERENCES 158
CONVERSION FACTORS - ENGLISH TO SI UNITS 165
APPENDIX 1 BASES FOR ECONOMIC EVALUATIONS OF GRASS ROOTS
INDUSTRIAL BOILER COMPARISONS Al-1
APPENDIX 2 DESCRIPTION OF SCREENING QUALITY INVESTMENT
ESTIMATES A2-1
APPENDIX 3 DETAILED TABULATION OF INVESTMENT AND OPERATING
COST ESTIMATES A3-1
APPENDIX 4 TABULATED DATA DERIVED FROM FEA's NATURAL GAS
TASK FORCE AND MFBI SURVEYS A4-1
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SUMMARY
This study is a small part of the Government's program to develop
coal-fired fluidized-bed combustion technology. The study is confined to
industrial boilers, and the purposes are to determine the potential for
applying coal-fired FBC to industrial boilers with a firing rate of at
least 100 million BTU/H and to assess the various impacts associated with
deployment of the technology through the year 2000.
A survey of operators of large industrial boiler systems shows
that the installation of coal-fired FBC boilers will be considered when:
• The reliability of FBC technology is commercially
demonstrated to achieve continuous boiler operation
of about one year duration and with effective
control of emissions.
• The economics of FBC technology are demonstrated
to be competitive with alternative ways of firing
solid coal.
The principal alternatives with which FBC must compete are:
• Use of low sulfur "compliance" coal in a conventional
boiler, with an electrostatic precipitator (ESP) to
control particulate emissions.
• Use of high sulfur coal in a conventional boiler,
with a flue gas scrubber to control S02 emissions
and particulates.
The economics of these alternatives have been developed in 1975
constant dollars, for a Gulf Coast location, on a basis excluding the cost
of coal itself, whether it is of compliance quality or high sulfur. As an
example, the results for alternative technologies are shown below for the
case of adding a single coal-fired 100 KPPH or 400 KPPH industrial boiler
system at an existing manufacturing plant that has a petroleum-fired boiler
system.
STEAM COST (EX. FUEL) IN
1975 DOLLARS PER THOUSAND POUNDS
Low Sulfur
High Sulfur Coal "Compliance" Coal
Conventional Conventional
FBC With Scrubber FBC With ESP
Single Coal-Fired Boiler System Adding to Existing 011-Fired Plant
100 KPPH 3.59 3.95 3.15 2.90
400 KPPH 2.49 2.83 2.05 2.01
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The estimates (based on current FBC costs) indicate a distinct
advantage for FBC technology over conventional coal-firing plus flue gas
scrubbing for high sulfur coal. With compliance coal, results are a
stand-off in cost at the larger size, with a moderate advantage for con-
ventional firing at the. 100 KPPH size. All FBC costs (in constant dollars)
are expected to improve significantly as this new technology matures.
FBC technology has potentially important and even decisive, advan-
tages that are not captured by the above estimates. The advantages include
flexibility to combust different coals, good control of NOx emissions, flexibility
to readily achieve higher sulfur capture if SC>2 emission regulations are tightened,
relatively unobjectionable solid wastes for which uses are under development,
and ability to be fabricated and shipped in modules for simple field assembly.
However, it is important that commercial development should occur
before the growing coal-fired industrial boiler market is pre-empted by other
coal-use technologies. Pre-emption is possible if, at the time industrial
decision-makers must make commitments to new boilers, other technologies
are commercial while FBC technology has not been fully demonstrated. It is
believed that the industrial boiler potential of FBC could be impaired if
the technology is not demonstrated to be commercially reliable by 1981.
Major Governmental funding of FBC development programs suggests that reli-
ability will be demonstrated in time. The estimates of coal-fired FBC
potential assume that this will be the case. On this basis, the most pro-
bable nationwide potential is estimated to be:
Cumulative Number of 1Q15 BTU 1000 B/D of
Year Industrial FBC Boilers Per Year Oil Equivalent
1980 7 0.01 5
1985 200 0.29 136
1990 685 0.99 462
1995 1170 1.69 793
2000 2050 2.97 1400
Most of the estimated potential is expected to be in the chemicals, petro-
chemicals, petroleum refining, paper, primary metals, and food industries.
Geographically, more than 90% of the potential is expected to be in regions
that FEA has designated Appalachian, Southeast, Great Lakes, and Gulf Coast.
The FBC potential can be related to the value of manufacturing
that is estimated to be supported by large coal-fired FBC boilers. For the
above regions, the FBC-related "Gross Product Originating" is estimated to
be:
FBC-Related GPO
in Billion 1975 $
Region 1985 1990 1995 2000
Appalachian 3.5 12 22 40
Southeast 3.1 11 19 35
Great Lakes 3.1 11 19 35
Gulf Coast 4.2 15 26 48
13.9 49 86 159
ii
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The above estimates are for the "most probable" case considered and apply
to existing manufacturing applications. Separate estimates were also made
of maximum and minimum potentials and amount, respectively, to slightly less
than double and approximately one quarter of the above figures.
Other estimates associated with the most probable potential are
that:
• The equivalent of 2000 industrial FBC boilers, with
an average capacity of 200 KPPH and a cumulative
erected cost of almost $6 billion (1975 constant $),
would be installed through the year 2000.
9 Coal requirements for the FBC boilers would approximate
140 million tons in the year 2000, and would have an
F.O.B. mine value of $2 billion.
a Associated limestone requirements would be about 50
million tons in the year 2000, with an F.O.B. quarry
value of $170 million.
a Also, in the year 2000, emissions relating to the
coal-fired FBC boilers in compliance with Federal
Standards for new point sources, would approximate
48 million tons of solid wastes, 132,000 tons of
particulates, 660,000 tons of NOX, and 1.6 million
tons of S02•
Despite the seemingly large estimates of emissions, examination of
two Air Quality Control Regions (Metropolitan Houston-Galveston and West
Central Illinois) suggests that utilization of FBC-technology industrial
boilers is likely to have a much smaller impact on ambient air quality than
(a) the impact caused by sources other than industrial boilers, and (b) the
emissions impact of existing coal-fired equipment in regions that currently
use coal to a significant degree. In the latter case and in the long run,
a net beneficial effect is possible if FBC installations replace existing
coal-fired units.
Low sulfur coals containing appreciable amounts of alkaline ash,
when used in conjunction with FBC technology, may alleviate the problem of
switching to coal from natural gas and oil. Available technical data are
inadequate, and thorough experimental investigation of this important
possibility appears desirable. Most Southwestern lignites, which also contain
appreciable amounts of alkaline ash, are not compliance coals if combusted
conventionally but may become so in fluid-bed units. This possibility is
of considerable potential importance to industry located in the Gulf Coast
area. Thorough experimental investigation appears desirable.
Compliance with New Source Performance Standards (NSPS) may not
be sufficient in some industrial areas of the country which are already at,
or beyond, the Federal or state/local limits for ambient air quality. The
Metropolitan Houston-Galveston area (AQCR 216) is an example of a highly
industrialized area, of critical economic importance to the nation, where
iii
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current levels of particulates and NC>2 are close to the primary standards
for ambient air quality. Directionally, even with excellent control
technology, coal use in new installations will make matters worse unless
the existing situation is improved.
Where FBC technology is not the technology of choice, industrial
boiler fuel demand is expected to be satisfied by a combination of:
• Conventional use of compliance coal
» Application of control technologies such as
FGDS ("scrubbers") to non-compliance coal
• Use of solvent refined coal or other forms
of cleaned coal
• Use of coal-in-oil slurries
« Continuing use of oil and natural gas
Additionally, it is speculated that some industrial plants will
purchase steam from central plants while others may substitute electricity
for steam in some industrial processes.
iv
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HIGHLIGHTS
The Highlights that follow reflect the contractor's judgment of
what are the most important points in each of the detailed sections of
the report. The pertinent section numbers are noted in parentheses.
The Highlights section is equivalent to an extended Table of
Contents, and its purpose is to help the reader to locate points of interest
quickly, and then refer to the section of the report in which the point is
discussed in the context of related issues. The reader is especially cautioned
not to draw inferences from numerical estimates that are separated from their
contexts, assumptions and other qualifications. Such qualifications are
deliberately minimized in the Highlights section.
Introduction (1.1)
• The Government is funding an intensive effort to develop coal-fired
fluidized-bed combustion technology.
• This study is a small part of this effort.
Objectives (1.2)
• Determine the potential of coal-fired FBC for industrial boilers.
• Assess the impacts of deployment of coal-fired FBC.
Approach (1.3)
• Certain factors, such as plant investments and operating costs can be
quantified, while other factors, such as coal-use legislation and the
future cost and availability of foreign oil, cannot be quantified.
The study attempts to take account of quantifiable and non-quantifiable
factors that may affect the commercial potential of coal-fired FBC.
Industrial Boiler Systems (2)
• The manufacturing industries that consume most of the industrial boiler
fuel include Chemicals, Petroleum Refining, Paper, Primary Metals, and
Food. Large process plants in these industries are usually continuously
operated and must have a reliable supply of process steam.
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Types of Industrial Boilers (2.1.1)
• Watertube boilers span the size range from less than 10,000 pounds of
steam per hour to about 7 million PPH. The very large boilers, of
over 1 million PPH, are used almost exclusively by electric utilities.
Watertube boilers are designed for a variety of fuels, steam pressures
(15 to 4,000 psi) and steam temperatures (250°F to about 1025°F).
• Package boilers are assembled at boiler manufacturers' plants. Railroad
shipping constraints limit their dimensions to about 40' long by 13'
wide by 16' high. Investment savings for a package unit may be up to
25% of the cost of a field-erected unit of similar capacity.
Present Population of Large Industrial Boilers (2.1.3)
• FEA surveys of large industrial boilers provided the following picture
for 1974:
Firing Rate Steam Rate Number of Capacity
million BTTJ/H 1000 PPH_ Boilers KPPH %
100-199 83-153 2404 284 43
200-299 154-214 802 148 22
300-499 215-333 514 141 21
>500 >334 188 91 14
3908 664 100
FBC as Applied to Industrial Boilers (2.1.4)
• FBC designs have size advantages relative to other boiler designs.
In pilot plants operating at atmospheric pressure, FBC units have
achieved heat release rates of over 100,000 BTU/H/cubic foot of expanded
bed volume. Comparable rates for typical pulverized-coal-fired boilers
are 20,000 BTU/H/cubic foot of firebox.
Timetable for FBC Developments (2.1.6)
• - Start-up of Rivesville multicell FBC boiler Jan. 1977
Start-up of industrial development units 1978
- Routine designs of industrial units offered
by several boiler manufacturers. 1981-1982
vi
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Estimated Investment and Operating Costs (2.3)
• Screening cases have been developed to compare Investment and operating
costs for:
FBC boiler firing high sulfur coal
Conventional coal-fired boiler with flue gas scrubber, firing high
sulfur coal.
- FBC boiler firing low sulfur "compliance" coal.
- Conventional coal-fired boiler firing low sulfur "compliance" coal.
- Package oil-fired boiler firing low sulfur fuel oil.
• Costs of steam (ex fuel) for 100 KPPH and 400 KPPH add-on and grass-roots
boiler projects, in 1975 constant dollars per 1000 pounds of steam and
including project contingencies, are estimated to be:
High Sulfur Coal Low Sulfur "Compliance" Coal
Conventional Conventional
FBC With Scrubber FBC With ESP
Single Coal-Fired Boiler
Addition to Existing Oil-Fired
Plant
100 KPPH 3.59
400 KPPH 2.49
Grass Roots Coal-Fired Boiler
System, With Backup
100 KPPH 4.81
400 KPPH 3.19
3.95
2.83
5.65
3.91
3.15
2.05
4.37
2.76
2.90
2.01
4.07
2.78
Comparison of investments, and steam costs (ex fuel), for a single coal-fired
boiler added to an existing oil-fired plant:
High Sulfur Coal
FBC
Conventional
With Scrubber
Steam rate, KPPH
Investment, million 1975$
Coal Handling
Boiler and Stack
Environmental and Waste
Disposal
Total, M$
100
1.8
3.1
1.3
6.2
400
2.7
7.6
3.4
13.7
Unit Cost of Steam (ex fuel), 1975$ per 1000 Ibs.
Op. costs excl. BFW
Boiler Feed Water
Capital Charges
Total (ex fuel),
c/k Ibs.
1.42
0.60
1.57
3.59
1.02
0.60
0.87
2.49
100
1.8
2.9
2.6
7.3
1.50
0.60
1.85
3.95
400
2.7
8.6
6.9
18.2
1.08
0.60
1.15
2.83
vii
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• Meeting environmental standards, while burning high sulfur fuels, is
significantly more costly than burning (compliance) fuels that are
low enough in sulfur content to meet SC>2 emission limits directly.
• Based on current FBC costs, there is a distinct advantage for burning
high sulfur coal in an FBC boiler compared with conventional burning
of the same coal plus flue gas scrubbing. Furthermore, current FBC
designs are "first generation", and significant cost reductions can
be anticipated in the future.
• Conversion of existing boilers to FBC technology (i.e. "retrofitting
FBC") is judged to be economically unattractive.
Market Survey of Large Industrial Boiler Users (2.4)
• Operators of large industrial boiler systems express readiness to consider
the installation of coal-fired FBC boilers as soon as:
- The reliability of FBC technology is commercially demonstrated by
continuous boiler operation, with effective control of emissions,
for runs approaching a year's duration.
- The economics of using FBC technology are demonstrated to be competi-
tive with conventional coal-firing.
Standard Industrial Classification (3.1)
• The SIC system of the Bureau of the Census recognizes 21 manufacturing
industries in terms of 2-digit codes, which are subdivided into 450
4-digit codes. Approximately 30 of the latter offer a potential to
coal-fired FBC, with most of the prospects concentrated within the broader
2-digit groupings of the chemicals, paper, petroleum refining, primary
metals and food industries.
1972 Census of Manufactures (3.2)
• The most recent comprehensive data for energy consumption by U.S. manu-
facturing industries are for 1971, and are published in the 1972 Census
of Manufactures.
Fuel Consumption of Large Industrial Boilers in 1974 (3.3)
• In 1975, the FEA conducted a survey of all Major Fuel Burning Installations
in the U.S. An MFBI is an installation that has, or is, a fossil-fuel
fired boiler, burner, or combustor with a design firing rate of 100
million BTU's per hour or greater.
• FEA's Office of Fuel Utilization has provided survey data for industrial
boilers for use in this study. In 1974, there were approximately 4,000
industrial boilers with a design firing rate of 100 million BTU/H or
more. These boilers were located at 1,600 industrial plants in the
lower 48 states.
viii
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• Fuel consumption of the large industrial boilers approximated 4 quads
(1015 BTTJ) , broken down as follows:
SIC % of Total Fuel Consumed by
Code Industry Large Industrial Boilers
28 Chemicals 26.2
26 Paper 16.7
29 Petroleum Refining 16.5
33 Primary Metals 12.4
20 Food 5.4
34 Fabricated Metal Products 1.7
35 Machinery, except electrical 1.4
49 Utility Services (excl. electricity generation) 1-3
32 Stone, Clay, Glass, Concrete 0.6
Other industries 17.8
100
Future Demand for Industrial Boiler Fuel (4)
• The future size and structure of the U.S. economy is a principal
determinant of industrial energy demand. The first step is to obtain
estimates of future manufacturing activity.
Basis of Demand Projections (4.1)
• A joint study by the Office of Business Economics (Dept. of Commerce)
and the Economic Research Service (Dept. of Agriculture), known as the
"1972 OBERS Projections," provides estimates of U.S. manufacturing a
activity through the year 2020 in terms of "Gross Product Originating"
(GPO).
• The projections make it possible to calculate the average fuel consump-
tion per unit of product output on an industry—by-industry basis.
Quantitative Projections (4.2)
• Starting with 1974 as a base year for which details of the fuel consump-
tion of large industrial boilers are known (from FEA surveys), it is
possible to estimate future boiler fuel consumption using the OBERS
projections to derive multipliers for the 1974 data. The multipliers
are adjusted for anticipated energy conservation per unit of manufacturing
output and for expected changes in the proportion of output supported
by the large (MFBI) boilers.
Ix
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Projections of Coal-Fired FBC Potential; Basis (5.1)
• The coal-fired FBC potential is considered to be a sub-set of coal
utilization by all large industrial boilers, and the level of coal
utilization by industrial MFBI's is assumed to be driven either by
limited availability of petroleum or by legislation (such as the
Energy Supply and Environmental Coordination Act of 1974 or the
proposed "National Petroleum and Natural Gas Conservation and Coal
Substitution Act", i.e. S.1777).
Regional Applicability (5.3)
• Estimates of maximum, most probable, and minimum potentials for coal-
fired FBC will be influenced by the regional applicability of the tech-
nology. Regional constraints, based on logistics and^economics, are
conceived to reduce the unconstrained potentials by 8%, 26% and 52%
in the minimum, most probable, and maximum cases.
Maximum, Most Probable, and Minimum Potentials (5.4l
• Coal-fired FBC potentials for large industrial boilers are estimated
to be:
1015 BTU per year
Year
1980
1985
1990
1995
2000
( ) = % of total fossil fuel demand estimated for large industrial boilers.
Boiler Fuel Demand Where FBC is not Utilized (5.6)
• Satisfaction of the fuel demand of the industrial boilers in which coal-
fired FBC is not utilized is expected to include (a) conventional
use of compliance coal, (b) non-compliance coal with control technologies
such as FGDS, (c) solvent refined coal or other forms of cleaned solid
coal, (d) coal-in-oil slurries, and the continuing use of oil and gas in
some plants. Steam purchased from central plants and/or substitution of
electricity for steam in some processes are further possbilities.
Regionalization of FBC Potential (5.7)
• More than 90% of the coal-fired FBC potential of large industrial boilers
is expected to be in four regions: Appalachian, Southeast, Great Lakes,
and Gulf Coast. (see Table 3-5 for identification of these FEA regions)
Maximum
0.02
0.62
1.97
3.20
5.52
Most Probable
0.01
0.29
0.99
1.69
2.97
(0.2)
(5.5)
(16)
(24)
(36)
Minimum
Nil
0.075
0.29
0.54
1.00
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Impact on National Energy Consumption C6.1)
• The coal firing of large industrial boilers using FBC technology is not
expected to have any marked impact on the aggregate of national energy
consumption. The overriding consideration is that industrial hoiler
fuel demand is set by a given level of manufacturing activity and not
by the technology by which the industrial boiler fuel is combusted.
Potential Savings of Oil and Natural Gas ((6.2)
• Savings of petroleum fuels will occur if solid coal is used in (large)
industrial boilers, but the level of saving achieved will be essentially
independent of the technology by which the coal is combusted.
• Conversion of the most probable estimate of coal-fired FBC potential into
1000 B/D of oil equivalent indicates the following "savings":
1000 B/D of
Year Oil Equivalent
1980 5
1985 136
1990 462
1995 793
2000 1396
Economic Impacts: National (7.1)
• Although the absolute macroeconomic impacts of coal-fired FBC are indeter-
minate, it is possible to ascribe certain levels of economic activities
to certain levels of coal-fired FBC potential.
• In the most probable case, the Gross Product Originating that is relatable
to the operation of coal-fired FBC industrial boilers is estimated to
be:
Year FBC-Eelated GPO in Billion 1975 $
1980 0.5
1985 15
1990 52
1995 93
2000 171
xi
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3.5
3.1
3.1
4.2
12
11
11
15
22
19
19
26
40
35
36
48
Regional Impacts (7.2)
• Regional impacts, in the four regions of greatest coal-fired FBC poten-
tial, in the most probable case, are estimated to be:
FBC-Related GPO in Billion 1975 $
Region 1985 1990 1995 2000
Appalachian
Southeast
Great Lakes
Gulf Coast
Boiler Manufacturing and Related Industries (7.3^
• The economic impact of coal-fired FBC on the manufacture of industrial
boilers is estimated in terms of boiler units of 200 KPPH capacity.
In the most probable case, the number of units and their erected cost
is estimated to be:
Number of Erected Cost in
200 KPPH Units Million 1975 $
FBC units added through 1980 7 20
FBC units added through 1981/1985 193 540
FBC units added through 1986/1990 485 1360
FBC units added through 1991/1995 485 1360
FBC units added through 1996/2000 880 2460
2050 5740
Coal Industry (7.4)
• For the most probable case, the estimates of coal volume and F.O.B. mine
value for conventional applications of coal-fired FBC are:
Year Million Tons Million 1975 $
1980 0.46 6
1985 13.6 190
1990 47 655
1995 80 1113
2000 140 i960
xii
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Limestone. Industry (7.5)
• The limestone requirements of coal-fired FBC industrial boilers, in the
most probable case, are estimated to be:
Year
1980
1985
1990
1995
2000
Million Tons
0.16
5
16
27
48
F.O.B. Quarry Value, M 1975 $
0.56
16
56
95
167
Environmental Considerations (8.1)
* The environmental aspects of application of coal-fired FBC technology
to industrial boilers are considered in relation to national emission
standards for new point sources:
Pollutant
particulates
so2
N0x(as N02)
Estimates of Emissions (8.4)
Emissions per million BTU's input,
not to Exceed:
0.1 Ibs
solid fuel: 1.2 Ibs
liquid fuel: 0.8 Ibs
solid fuel: 0.7
liquid fuel: 0.3
gaseous fuel: 0.2
For Illinois No. 6 coal (3.6 wt% sulfur, 10,600 BTU/lb), the emissions
from a 100 KPPH industrial FBC boiler operating at nameplate capacity
are related to a daily consumption of 144 tons of coal and 54 tons of
limestone. The daily emissions are estimated to be:
Solid Waste
Particulates
so2
N0x(as N00)
Tons/Day
55
0.15
1.85
0.75
xiii
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National and Regional Emissions (8.5)
• In the most probable case of FBC application to large industrial boilers,
the nationwide emissions are estimated to be:
1000 Tons/Year
1000 Tons/Year
Appalachian
12,400
34
422
170
Southeast
10,900
30
372
150
Gt . Lakes
11,200
31
383
154
Gulf Coast
10,100
25
344
139
Year: 1980 1990 2000
Solid Waste 160 16,000 48,000
Particulates 0.4 44 132
S02 5 547 1,640
N0x(as N02) 2 220 660
For the four regions projected to have the greatest potentials for FBC
use, the emissions in the most probable case are estimated for the year
2000 to be:
Solid Waste
Particulates
S02
N0x(as N02)
Estimates of Emissions for Selected AQCR's (8.6)
• Air Quality Control Regions were selected in Texas and Illinois to permit
comparisons between regions where, currently, (a) the industrial consumption
of coal is minimal (Texas), and (b) there is a significant use of local high
sulfur coal in industrial boilers (Illinois). The selected AQCR's were
Metropolitan Houston-Galveston (#216) and West Central Illinois (#075) .
* For the most probable case of FBC utilization, the projected emissions from
coal-fired FBC industrial boilers are not expected to add large increments
of criteria pollutants to the ambient air in AQCR 216. Nevertheless, for
both particulates and NOx, the impact may be of practical significance
because the current level of air quality is marginal. Hence, any incremental
pollution would make ambient air quality standards more difficult to achieve
and/or maintain.
• For AQCR 075, which has a much lower absolute level of industrialization than
AQCR 216, the impact of FBC industrial boilers on ambient air quality is
estimated to be minimal.
Disposition of Solid Wastes (8.7)
• Considerable quantities of solid wastes will be generated by coal-fired
industrial boilers. By the year 2000, in the most probable case, the
annual quantity of waste solids is estimated to approximate 50 million tons.
Clearly, the disposal and/or utilization of such a large volume of material
will require continued attention and development work.
xiv
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Environmental Conclusions and Recommendations (8.9)
• Using conventional technology, a change from natural gas or oil to
coal-firing would be expected to affect the environment adversely.
With FBC technology there is a potential for improvement over con-
ventional coal usage.
• The development of FBC technology will not, of itself, correct existing
problems with ambient air quality. Notwithstanding the potentially
important contributions that may be made by FBC technology to the coal-
firing of industrial boilers in environmentally acceptable ways, such
applications are likely to have a smaller impact on ambient air quality
than:
(1) the impact produced by combustion sources other than
large industrial boilers, and -
(2) the impact of emissions from existing coal-fired
equipment in regions that currently use coal to a
significant extent.
• Available technical data limit the quantitative environmental conclusions
that may be drawn about coal-fired FBC per se and in relation to other
coal use technologies. Further definition of the following is suggested:
(1) the quantity of sulfur retained in the ash from FBC and
spreader-stoker boilers . . . for representative Western
coals (bituminous, sub-bituminous, lignites) and South-
western lignites.
(2) NOx emissions . . . for the same types of equipment and
coals listed in (1).
(3) particulate emissions from (atmospheric) coal-fired FBC
boilers ... as for (1) but also including high sulfur
coals.
(4) fate of trace elements ... as for (1), but also
including high sulfur coals and FGDS systems.
xv
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1. INTRODUCTION, OBJECTIVES AND APPROACH
1.1 Introduction
The Government is funding an intensive effort to develop fluidized-
bed combustion (FBC) technology for coal firing. The purpose is to permit
coal to be utilized efficiently and with environmental acceptability. The
purposes of this study are to assess the applicability of fluidized-bed
combustion of coal in industrial boilers, and to estimate the various
consequences of utilizing coal in this way. Work under FEA Contract
CO-04-50168-00 began on 6/27/75.
1.2 Objectives
The principal contractual objectives of the study are to:
(1) assess the potential for conservation of scarce petroleum energy resources
through the use of clean, efficient, coal-fired FBC technology in industrial
boilers.*
(2) determine the extent to which national and regional consumption of oil and
gas may be reduced by future commercial use of coal-fired industrial FBC
boiler technology, both for new units and as a retrofit technology for
existing industrial boilers.
(3) assess the economic impact of widespread industrial application of the
pertinent FBC technology to segments of the economy affected by it.
(4) determine and define the demand for the pertinent technology in relation
to cost, availability of fuel, .and other relevant factors.
(5) determine and define the specific technical requirements for representative
applications of the pertinent FBC technology.
(6) assess the potential environmental impacts of the above.
*The assessment excludes electric utility boilers and industrial process heaters.
It is restricted to industrial boilers with a design firing-rate of at least
100 million BTU per hour.
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1.3 Approach
The analytical approach used in the study is predicated by the
concept that individual manufacturing companies who own and operate industrial
boilers regard such operations as essential, but subordinate, to their principal
interest which is to produce goods of various kinds efficiently and competitively.
The corollary is that industrial decision-makers will regard coal-fired FBC
as one of several approaches to satisfactory maintenance and continuation of
their manufacturing operations. Hence, their decisions to use, or not use,
FBC technology will depend on the status of FBC technology at the time that
their individual decisions must be made. A decision to use FBC technology
will depend on its having been demonstrated to be (a) reliable, and (b) economically
competitive with whatever alternatives are available.
Throughout the study, which is concerned with assessment of the
potential for, and related impacts of, coal-fired FBC, we have tried to
identify factors believed to be important to the decision-making process.
Certain factors, such as plant investments and operating costs, can be
quantified. Other factors, such as coal-use legislation and the future cost
and availability of foreign oil, cannot be quantified but may prove to be more
important than those that can. Therefore, the study attempts to make a
balanced assessment of what can affect the commercialization of coal-fired
FBC, and does not reach conclusions solely on the basis of what can be
quantified.
1.4 Structure of Report
The report is organized to permit sequential discussion of the principal
elements or topics that were studied.
Section 2 is concerned with "hardware", i.e. with industrial boilers,
their physical and other characteristics, investment and operating costs,
technical specifications, and also with a survey of users of industrial boilers
to learn their attitudes towards the use of coal and FBC technology.
Section 3 covers the users of industrial boilers from a classificational
and statistical standpoint. The statistics relate to the hardware and to the
quantities and types of fuel consumed. This part of the report also considers
the future options open to the users of industrial boilers in relation to their
anticipations of the future availability of different fuels and also coal-use
legislation that has been proposed in the expectation that there will be future
limitations on the availability of oil and natural gas.
Section 4 provides projections of the future demand for industrial
boiler fuels. The estimates are based on published projections of future
manufacturing output through the year 2000.
Section 5 derives estimates of the future potential for coal-fired
FBC, as applied to industrial boilers, by applying various criteria of
applicability to the estimates of industrial boiler demand developed in
Section 4. Estimates of potential consider three cases: maximum, "most probable"
and minimum.
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— 3 —
Section 6 utilizes the estimates of coal-fired FBC potential to
derive corresponding estimates of the impact on national energy consumption
and the potential savings of oil and natural gas that would accrue from the
commercial deployment of the pertinent coal-use technology.
Section 7 discusses a variety of economic impacts to be expected
from the commercialization of coal-fired FBC for industrial boilers. Both
national and regional economic impacts are considered. Additionally, specific
consideration is given to the boiler manufacturing, coal, and limestone
industries.
Section 8 addresses the environmental aspects of application of
industrial FBC boiler technology. This is done in terms of emissions from
point sources and the regional and national aggregates of such emissions.
The disposition of solid waste and sludge by-products is also discussed.
The principal conclusions of the study are given in Section 9.
Section 10 is a compilation of the references and additional
bibliography for each of the individual sections of the report. There
are also four Appendices that include details of cost estimating and large
amounts of statistical data that, for the convenience of readers, are
separated from the text of the report. Tables, Figures, and references
are numbered separately for each section of the report.
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- 4 -
2. INDUSTRIAL BOILER SYSTEMS
Industrial boilers range upward in size from 10 thousand pounds
steam per hour (10 KPPH) to the largest sizes used in manufacturing^industries
(not electric utility power stations), in the neighborhood of one million
pounds steam per hour. This study is focussed on the larger industrial
boilers (>100 KPPH), of which there are about 4,000 in the United States
at present.
The manufacturing industries which consume most of the industrial
boiler fuel burned in the U.S. include Chemicals, Primary Metals, Petroleum
Refining, Paper, and Food. Large process plants in these industries generally
are continuously operated and must have a reliable supply of process steam.
Thus the boiler systems in these plants normally contain several boilers, with
sufficient capacity so that a single boiler can be idled for maintenance or
inspection without interrupting the process operations of the plant. Most of
these boiler systems are capable of firing fuel oil and/or natural gas, plus
any byproduct fuels which may be produced at the plant. Presently, about a
quarter of the larger systems can fire coal as one of the fuels.
Fluidized bed combustion appears attractive as a future coal-use
technology for new industrial boilers, particularly for additions to existing
boiler systems. The principal advantages of FBC compared with conventional
coal firing of large industrial boilers include the following:
• effective direct capture of sulfur dioxide from the combustion
of high (and low) sulfur coal;
• significantly lower NOx emissions than conventional combustion,
because fluidized bed combustors in FBC boilers can be readily
designed to be operated at much lower temperatures than are
possible in stokers and pulverized-coal-fired units, thus
minimizing the formation of thermal NOx;
• reduced problems of slagging and fouling from sodium salts when lower
rank coals which contain alkaline ash are burned, because of the lower
combustion temperature;
• production of dry, granular, easily-handled solid wastes
rather than the wet, unstable sludges characteristic of
most flue gas scrubbers (throwaway type).
Operators of large industrial boiler systems have expressed their
readiness to consider the installation of FBC-fired boilers to meet their
requirements for new coal-fired boilers as soon as:
• the reliability of FBC technology is commercially demonstrated
by continuous boiler operation with effective emissions
controls for boiler runs approaching a year's duration;
and_ • the economics for using FBC technology are shown to be
competitive with those for using conventional coal firing.*
*It is understood that the .economic comparisons must be made among systems that
comply with all applicable environmental regulations during the working life Of
the boilers.
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- 5 -
The first criterion is being addressed in major FBC pilot plant and
demonstration programs carried out by ERDA and EPA in conjunction with private
industry. As shown in this report, satisfaction of the second criterion is
anticipated where high sulfur coal is the fuel of choice, and is probable
when low sulfur coals are used.
2.1 Characteristics of Industrial Boilers
Several definitions of industrial boilers are in use. The principal
distinctions are between (a) the physical nature of the equipment (boiler size
and type) and (b) the function that the equipment is intended to perform
(e.g. the disposition of the steam produced and the classification of the
user's business). The present study is focussed mainly on the assessment of
the application of fluidized bed combustion (FBC) technology to large industrial
boilers (over 100 KPPH) in the manufacturing industries — especially Chemicals,
Primary Metals, Petroleum Refining, Paper, and Foods.
Industrial boilers were originally defined for this study to be in
the size range of 10 to 500 KPPH. At the lower end of this size range (10-
100 KPPH), we concluded very early that plants currently firing oil (or gas)
in this smaller size of industrial boilers are very unlikely to be shifted
from oil or gas fuels to coal — these plants themselves are smaller, often
located in congested areas where space for coal handling is not available, and
in many cases working on a discontinuous schedule of operations (e.g. only one
or two shifts per day, or shut down over weekends, etc.). For these plants, it
is extremely unlikely that the relatively large investment associated with coal
receiving, storing, handling, and firing would be attractive. Moreover, the
few exceptions to this generalization would have no material impact on the
quantitative potential for coal-fired FBC.
At the upper end of the size range, we found that there are in the
U.S. about 200 industrial boilers (as distinguished from electrical utility
boilers) with firing capacities considerably greater than 500 M BTU/hr. This
is about 5% of the total number of large industrial boilers (over 100 M BTU/hr.)
and is considered significant in terms of projecting future fuel requirements
in the industrial sector. Since these largest industrial boilers overlap the
size range of electric utility boilers, we modified the definition for our
study so as to include very large boilers whose purpose is clearly "industrial",
while excluding all boilers operated by electric utility companies.
2.1.1 Types of Industrial Boilers
Functionally, industrial boilers are classified into two types,
firetube and watertube. In firetube boilers, the hot products of combustion
pass through tubes which are submerged in a pool of boiling water. In watertube
boilers, water flows by natural or forced circulation through tubes which are
exposed to heat transfer by both radiation from the boiler flame and convection
from the hot flue gas.
Generally, firetube boilers are used for industrial steam rates up to
about 30 KPPH of saturated steam, at pressures up to about 150 pounds per square
inch gauge (psig). In the U.S., they are generally fired with gas or oil. Because
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- 6 -
of the relatively small size of firetube boilers, and the expectation that there
is little likelihood of widespread coal firing for this type of boiler in the
United States, we conclude that the impact of FBC on plants using firetube
boilers will be small*. Hence, we have not studied them as prospective
candidates for application of FBC.
Watertube boilers span the size range from less than 10,000 pounds
steam per hour to about 7 million pounds per hour. The very large boilers
(over 1 million PPH) are almost exclusively for electric utility generation.
Watertube boilers are designed for a large variety of fuels (gaseous, liquid,
and solid), and cover a wide range of steam pressures and temperatures
(pressures from 15 to 4,500 psig, temperatures from 250°F to about 1025°F).
Another very important method of classifying boilers is by type of
boiler construction procedure, as either package or field-erected units.
A package boiler is assembled at a manufacturer's plant, and then delivered
to the operating site where it has only to be set on a foundation and piped
up to appropriate connections to be ready for operation (6). In general,
railroad shipping constraints limit the dimensions of package boilers to
about 40' long by 13' wide by 16' high. A field-erected boiler is shipped
in pieces or partial assemblies, and must be built in the field from the
ground up. The distinction between package and field-erected boilers is very
significant from a cost standpoint. Savings for a package unit compared with
the same capacity field-erected boiler may be as much as 25-30%. For this
reason, practically all oil and/or gas-fired watertube boilers up to about
250-300 KPPH are package Boilers.
Most firetube boilers are package units, regardless of fuel fired.
For conventional watertube boilers, the approximate breakpoint between package
and field-erected depends on both the steam capacity and the fuel to be used,
as indicated in the following table:
Approximate Maximum Size of Watertube Package Boilers, KPPH
Fuel Fired Natural Gas Fuel Oils Solid Fuels
Approximate maximum capacity of
package unit, KPPH 350 350 50-60 (7)
Gas or oil-fired package units have been built and shipped in two modules
which were joined together in the field, at capacities up to 500 KPPH or greater.
Coal-fired watertube package boilers are relatively rare and relatively
small. Most coal-fired watertube boilers are field-erected. One of the incentives
for development of coal-fired fluidized bed combustion technology is that larger
capacity units can meet the shipping dimension criteria and hence can be shop
assembled as package units. For example, a preliminary design has been prepared
for a 250 KPPH FBC package unit in two modules (8) . The design takes advantage
of the intense heat release per cubic foot of fluidized bed volume, and the high
rate of heat transfer to boiler tubes submerged within the bed.
*in terms of the estimated savings of gas and oil achieved by use of coal-fired
FBC. We are not suggesting that firetube boilers will be unimportant per se.
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- 7 -
2.1.2 Boilers Firing Solid Fuels
Confining attention to solid-fuel-fired watertube boilers, there are
many methods for firing the coal, lignite, or other solid fuel, and each method
requires specific details of boiler design. Solid-fuel-firing methods listed
by the American Boiler Manufacturers Association (ABMA) includes the following
(3), (4):
1974/1975 Industrial Boiler Sales
Method No. Sold ~Average Steam Capacity, KPPH
Underfeed Stoker 8 <40
Overfeed Stoker 39 62
Spreader Stoker 82 149
Pulverized Coal Firing (PCF) 11 336
Other Solid Firing (including
non-coal) 28 93
Total Non-Solid Firing 1219 97
1387 101
As illustrated by the above table, the particular "conventional" coal-firing
methods of interest for this study of large industrial boilers are (a) spreader
stokers, which are typically used for boiler capacities in the range of about
100 to 250 KPPH, and (b) pulverized coal firing, which is almost universally
used for larger coal-fired boilers (both industrial and utility).
2.1.3 Present Population of Large Industrial Boilers
In early 1976, a close approximation of a true census of large
industrial boilers became available. This tabulation resulted from the
Major Fuel Burning Installation Coal Conversion Report survey conducted by
the FEA Office of Fuel Utilization. The survey was carried out pursuant to
FEA's responsibilities under the Energy Supply and Environmental Coordination
Act of 1974, and a reply was required to be submitted by every Major Fuel
Burning Installation (MFBI). For this survey project, an MFBI was defined as
an installation, other than an electric power plant, at a single site which
has combined fossil-fuel-firing capability of 100,000,000 BTU/hr. or more in
one or more boilers, burners, or combustors (excluding gas turbine and combined
cycle or internal combustion engines) (13). For each individual combustor
with a design firing capacity of 99 million BTU/hr or higher, a large amount
of information was requested including age, combustor capacity, fuel firing
capability, actual fuel consumed in 1974, and plans for conversion to coal
firing.
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- 8 -
The following table summarizes the population of large boilers with
reported firing capacities above 99 M BTU/hr., as developed by the FEA Survey:
1974 Large Boiler Population Reported to FEA
Approximate Est'd. Total
Firing Rate, M BTU/hr Steam Rate, KPPH (*) No. of Boilers Capacity, KPPH
100 - 199 83 - 153 2404 62 28^ 43
200 - 299 154 - 214 802 20 148 22
300 - 499 215 - 333 514 13 141 21
over 500 over 334 188 _ 5 91 14
Total 3908 100 664 100
* estimated using 1200-1500 BTU fired in the boiler per pound gross steam
production.
2.1.4 Description of Fluidized Bed Combustion as Applied to
Industrial Boilers
In a fluidized bed combustion (FBC) boiler, crushed high sulfur coal
can readily be burned under conditions such that no further controls are necessary
to meet emission limits of S02 and NOx in the flue gas. Very little experimental
information is available on the combustion of low sulfur Western coals using FBC.
For the purpose of this report, it is assumed that satisfactory operation can be
obtained with this type of fuel using inert material in the fluidized bed. After
commercial experience has been gained with this newly-developing technology, the
size, initial cost, and operating cost for an FBC system are expected to be lower
than for an equivalent conventional boiler system fired with the same fuel and
meeting all environmental regulations.
For effective combustion of solid fuels, a furnace designer can manip-
ulate three major inter-related variables by which adequate contact is achieved
between solid fuel and oxygen, as follows:
(1) provide large solid fuel surface area;
(2) provide long contact time between gas
and solid particles;
(3) provide high relative speed between gas
and solid particles, so that fuel is not
shielded from oxygen by a thick layer of
stagnant burned gases.
Combustion in a spreader stoker emphasizes the second and third of
these variables, while pulverized coal firing depends chiefly on the first two
Combustion in a fluidized bed can take advantage of all three of these variables
thus achieving an unusually high intensity of heat release in a small combustion'
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- 9 -
Figure 2-1 is a schematic diagram of an atmospheric pressure
fluidized bed boiler. The bed consists of a mixture of crushed limestone,
dolomite, or inert material, and large ash particles, which is "fluidized"
by the stream of air and combustion gases rising from the supporting grid
beneath the bed. Original particle size of the bed material is about 1/8".
The gas velocity is set so that the bed particles are suspended and move
about in random motion, but do not blow away. Under these conditions, a
gas/solid mixture behaves much like a boiling liquid (e.g. seeks its own
level, can be readily moved through channels). The boiler tubes submerged
in the bed remove heat at a high rate (extremely effective heat transfer) so
that typical bed temperatures are in the range of 1400 to 1600CF.
Crushed coal (1/4" to 1/2" particles) and the required bed makeup
material are continuously added at fuel injection points. Within the bed,
the coal burns very quickly, and the bed generally contains less than 2 to
4% carbon. Most of the ash resulting from combustion of the coal is in
relatively small, light particles which are swept out of the bed by the flue
gas. If high sulfur coal is being burned, sulfated bed material is continuously
withdrawn to maintain bed volume and activity for sulfur capture. If low sulfur
fuel is being burned, it is assumed that the bed can be composed of inert
material, such as alumina or sand, and that bed makeup and withdrawal rates
will be very low or negligible.
Fluidized bed combustion (FBC) is an effective method for controlling
emissions from high-sulfur fuels. For this purpose, the sorbent bed is limestone,
dolomite, or lime. Assuming a limestone feed, the first reaction at bed tempera-
tures is calcination.
CaC03 > CaO + C02
The sulfur in the fuel burns to sulfur dioxide, S02, and bed conditions are
maintained to favor sulfation of the lime to gypsum.
CaO + S02 + 1/2 02 ~> CaS04
The limestone sorbent feed rate is set in accordance with the sulfur content of
the fuel, and sufficient cleanup of S02 is achieved so that no further treatment
is required for compliance with sulfur emission regulations. By contrast, a
stoker or pulverized-coal boiler emits most of the sulfur in the fuel as S02,
and high sulfur fuels cannot be burned in these boilers without desulfurization
of the flue gas using some sort of scrubber.
With respect to nitrogen oxide (NOx) emissions, FBC operations on high
sulfur coals exhibit inherent advantages over conventional boilers using stokers
or pulverized coal firing. This is because the bed temperature is maintained at
1400 to 1600°F, well below the 2500°F + which is characteristic of conventional
boilers. The lower FBC temperatures give correspondingly lower formation of
thermal NOx, so that most FBC operations produce NOx emissions well below the
EPA limits for NOx from new steam generators, without the necessity of any special
combustion modifications or design features.
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- 10 -
FIGURE 2-1
SCHEMATIC DIAGRAM OF ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION BOILER (8)
Convection
Section
Water
Walls
Baffle
Tubes
Evaporator
Section
Air
Primary
Cyclone
Secondary
Particulate Removal
Water
Walls
Ul/
TO
STACK
Heat Recovery
Section
Ash; Particulates
Sulfate, Ash
Preheater, Superheater
or Reheater Section
Distributor Plate
LIMESTONE
Combustion Pressure
Bed Temperature
Gas Velocity
Bed Material
Fuel
close to atmospheric (usually balanced draft)
1400 to 1600°F
2 to 12 ft/sec
limestone or dolomite, or inert material for low sulfur fuels
not requiring sulfur capture
coal, fuel oil, bark and wood wastes, coke, char, etc.
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- 11 -
Another valuable characteristic of FBC technology is its very wide
tolerance to type and quality of solid fuels. Caking and non-caking coals,
refractory cokes and chars, and solid wastes such as bark and wood wastes can
all be burned efficiently in a fluidized bed. It is anticipated that FBC
boilers will be effective burners for direct combustion of anthracite culm
and low-BTU oil shale. The principal detail requiring careful design is
to provide the capability of reasonably uniform fuel introduction at multiple
points within the bed. Generally one fuel feed point should be specified for
about 10 square feet of bed area. Not only is the average bed temperature
relatively low, but temperatures throughout the bed are quite uniform if good
fluidization is maintained. The absence of hot spots means that fuels having
low-softening-point ash can be effectively burned without serious ash fusion
or clinker formation.
A final advantage for FBC is that of size. Heat release rates have
been achieved in atmospheric FBC pilot plants over 100,000 BTU/(hr)/(cubic foot
of expanded bed volume), or perhaps 50,000 - 605000 BTU/(hr)/(cubic foot of
firebox). This can be compared with about 20,000 BTU/(hr)/(cubic foot of firebox)
for a typical pulverized-coal-fired boiler. The high intensity of heat release
plus the excellent heat transfer rates to boiler tubes submerged in the bed make
it possible that FBC boilers up to about 250,000 pounds steam per hour can be
designed for "package" shipment by rail (compared to the maximum coal-fired
package size of about 50,000 Ibs/hr currently available with conventional
firing). This package feature should help to make the future erection cost
of large sized FBC boilers significantly lower than for corresponding field-
erected stoker-fired or pulverized-coal-fired units.
2.1.5 Different Versions of Fluidized Bed Combustion
FBC operating schemes have been proposed with once-through or
regenerative sorbent usage, and with combustion at atmospheric or elevated
pressure. The atmospheric pressure FBC scheme with once-through sorbent flow,
as described in the previous section, is the simplest version of this process.
Proposed initial commercial FBC designs are all for atmospheric pressure operation
with once-through sorbent.
Considerable work is underway to develop sorbent regeneration. The
incentive for this is to reduce the requirements for fresh limestone or dolomite,
and for high disposal rates of spent stone. In the sorbent regeneration process,
the sulfur originally captured by the stone is expected to be released as a more
concentrated stream of S02> and subsequent disposition of this strem presumably
will be by conversion to sulfur (Glaus), or to sulfuric acid.
Much work also is underway to develop pressurized fluid bed combustion.
A schematic diagram of a pressurized FBC boiler (with sorbent regeneration) is
given in Figure 2-2. The objective of higher pressure operation is to achieve
higher thermodynamic efficiency for electric power generation than is possible
with an atmospheric pressure unit. This is accomplished by use of a combined
cycle, generating power both from a steam driven turbo-generator and a gas
turbine. The combustor typically operates at a pressure on the order of 10
atmospheres (approx. 135 psig). Air is compressed into the combustor, and
coal and limestone are injected through lock hoppers. Because of the higher
pressure, even higher combustion intensities are feasible than with atmospheric
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FIGURE 2-2
SCHEMATIC DIAGRAM OF PRESSURIZED FBC BOILER WITH SORBENT REGENERATION
GAS TURBINE
TO WASTE HEAT I
RECOVERY AND STACK ?
DISCARD
STEAM TURBINE
CONDENSER
COAL AND —""
MAKEUP SORBENT
AIR
COMPRESSOR
SOLIDS
TRANSFER
SYSTEM
SEPARATOR
TO SULFUR
RECOVERY
DISCARD
FUEL
BOILER
REGENERATOR
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- 13 -
FBC, and deeper fluidized beds can be used. Hot effluent flue gas from the
boiler is cleaned to reduce particulate loading to a very low level, and then
expanded through the gas turbine to generate supplemental electricity. Pres-
surized FBC when burning high sulfur coal gives significantly lower NOx
emissions than the atmospheric version. From an overall standpoint, pressurized
FBC is of interest to utilities, and possibly to operators of large industrial
boilers who generate a significant portion of their own electric power needs.
It is not of interest to those who generate steam directly at the relatively
low pressure levels required for process uses.
The above discussion shows that there are four possible configurations
of FBC which a future large industrial boiler purchaser might consider, as
follows:
Fluidized Bed Combustion Pressure
Sorbent Cycle Atmospheric Pressurized
Once-through Sorbent X X
Sorbent Regeneration X X
The technical and economic assessments of FBC in industrial boilers presented
later in this report are entirely based on atmospheric FBC with once-through
sorbent. This is not because we believe there will be no industrial interest
in the other combinations. It is rather because we conclude that the availability
(or lack of availability) of sorbent regeneration and pressurized FBC technologies
will not have a major effect on the overall penetration of FBC into the industrial
boiler business. In other words, we believe it is unlikely (between now and
year 2000) that the incremental return for pressurized FBC or for sorbent
regeneration over atmospheric FBC with once-through sorbent will ever be so high
as to increase significantly the overall industrial use of FBC. In addition,
there is the very practical problem that usable cost estimates for pressurized
FBC and sorbent regeneration facilities in the industrial size range are nowhere
available at this time.
2.1.6 Timetable for FBC Developments
Table 2-1 shows our estimates of the probable timing for the availability
of FBC-fired industrial boilers. We expect that atmospheric pressure, once-
through sorbent designs will be regularly available from the boiler-making
industry by 1981 or 1982. It should be noted that Fluidized Bed Combustion
Company of Livingston, N.J. already has completed preliminary designs and would
consider commercial sales of FBC-fired industrial boilers now. Other boiler
manufacturers are gearing up to do so. Pressurized FBC and sorbent regeneration
are several years behind the atmospheric once-through version and are not expected
to be commercialized before 1985.
The first large-scale U.S. application of fluidized bed combustion is
in a multicell FBC boiler at the Monongahela Power Company's plant in Rivesville,
West Virginia, which is scheduled to start up in late 1976. It is designed to
generate 300,000 pounds steam per hour, at 1270 psig and 925°F. Although directed
towards electric utility operations, the unit is in the size range of greatest
-------
- 14 -
TABLE 2-1
PROBABLE TIMING FOR FBC-FIRED
INDUSTRIAL BOILER AVAILABILITY
o Startup of Rivesville Atmospheric Pressure
Multicell FBC Boiler late 1976
it Development Projects for
Atmospheric Pressure Industrial Boilers
- ERDA Contracts Awarded
- Startup late 1978
o Atmospheric Pressure Industrial FBC Boilers
Offered by Boiler Manufacturers .
- Initial Commercial Unit Award 1979 '•
- Routine Designs by Several
Boiler Manufacturers 1981-82
«. Pressurized FBC Utility Boiler Pilot Plant
- ERDA Contract Awarded (3) Jan. 1976
- Startup 1980
e Pressurized FBC Industrial Boiler Projects
- Pioneer Commercial Unit Award 1983
- Routine Designs 1986-87
e Lime Regeneration Commercialized 1985 or later
Notes: (1) Eight contracts for the development of commercial-sized projects
involving all uses of FBC (boilers, direct and indirect process
heaters) are being negotiated by ERDA. Of these, five involve
atmospheric pressure industrial boilers, the earliest of which
is scheduled to start operating in late 1978.
(2) These dates might be somewhat earlier if a sales contract is
awarded shortly after initial successful operation of the
Rivesville demonstration unit.
(3) Curtiss-Wright Company Contract.
-------
- 15 -
industrial interest. Rivesville is an atmospheric pressure FBC unit which
will operate initially with once-through limestone. Regeneration of sulfated
stone will be investigated later. Successful extended operation at Rivesville,
plus additional demonstrations via the ERDA Development Program, could lead to
commercial status for atmospheric FBC as early as 1981-82.
Time is of the essence to FBC developments. The needs to utilize
coal in large industrial boilers, and to do this with environmental accept-
ability, are apparent now. The "time window" for responding to these needs
is narrow. If the atmospheric pressure, industrial version of coal-fired
FBC technology is adequately demonstrated for general commercial use by 1981/82,
then the market potential for this technology seems assured. But the schedule
in Table 2-1 is tight. Any slippage would reduce FBC's market potential because
it is probable that other technology would have to be deployed instead.
2.2 Boiler System Options
This section describes the framework within which basic decisions
are make when a new or modified industrial boiler system is being specified.
These decisions include the following:
• how many boilers, and what size
• what fuels will be burned
• at what pressures will steam be generated and used
• will steam use include "byproduct" electric power generation
or steam turbine drivers for compressors and large pumps.
2.2.1 Energy Needs of a Process Plant
Manufacturing industries which account for major percentages of energy
consumption include:
Chemicals and Allied Products
Primary Metals
Petroleum Refining
Paper and Paper Products
Food and Kindred Products
Large process plants in these industries use energy continuously in at least
three forms:
• direct fired heat, as to a high temperature reactor
• process steam, as to a steam stripper, autoclave, or steam-
heated drier
• electric power, or steam or gas turbines, to drive pumps,
compressors, and other machinery.
-------
- 16 -
Direct fired heat is generally supplied to the process via furnace, kiln,
drier, etc., located right at the process unit. Process steam, generally
distributed at varying pressure levels from about 450 psig down to 5-10
psig, is usually generated in a central boiler plant consisting of two or
more boilers, and distributed through one or more grids at appropriate
pressure levels to the individual sites of use. The number and size of
the individual boilers are generally selected so that the continuous process
needs for steam can be met without interruption even though one boiler is
off the line for inspection or maintenance. For energy efficiency, sensible
heat from hot streams leaving a process unit is often recovered by unfired
steam generators, thus reducing the firing load at the central boiler plant.
The amount of electric power purchased from the local utility and
the amount generated within the plant vary widely. A few plants are completely
self-sufficient, generating their own power in electric-utility-type power
plants. Others generate no power at all. A large number produce what may be
termed "by-product" power, by operating steam boilers at a significantly higher
pressure than required by the process steam level, and expanding this high
pressure steam through topping turbines down to the pressure levels of use.
This power increment is generally less than total electric requirements, and
the balance is purchased. By-product power produced in this way is always
costed out at considerably lower levels than purchased power, because the
incremental fuel to generate steam at the higher pressure is of the order
of 4,000 to 6,000 BTU/kwh, while a modern, highly efficient utility power
station operating a normal condensing steam cycle requires about 9,000 BTU/kwh
(9), (10).
2.2.2 Fuels Basis
Most large industrial boilers are located in plants in which by-
product fuels are produced in variable quantities. Typical by-product fuels
would include refinery and coke oven gases, low BTU gas such as derived from
blast furnaces, bark and wood waste, bagasse, process tars and sludges, etc.
It is fundamental to the fuel balance of these plants that the available and
varying quantities of by-product fuels should always be burned first, prefer-
entially, since these are the lowest-value BTUs which are available. This task
often is borne wholly or partially by the boiler plant. Then, as required by
overall boiler output requirements, additional fuels are burned. The overall
fuel mix is controlled to meet several constraints simultaneously:
• provide the required energy release
• meet all environmental restrictions (e.g. by appropriate
mixture of high and low sulfur fuels)
• incur lowest overall cost
Purchased fuels may be selected from the following types:
• natural gas
• fuel oils, either residual or distillate
• solid fuels, such as bituminous coal or lignite; and in the future,
• "synthetic fuels", such as high or low BTU gas,
coal liquefaction products, and chars
-------
- 17 -
The above discussion implies that industrial boilers are usually
designed to burn two or more fuels. To illustrate this conclusion it is
noted that of 1387 industrial watertube boilers solid in 1974 and 1975 by
members of the American Boiler Manufacturers Association, 852 or 61% were
designed to burn more than one fuel (3), (4). Many of these were designed
to fire purchased oil and gas, but the larger ones in the process industries,
such as those in the MFBI size range, are likely to have alternate capability
for byproduct fuels.
2.2.3 Boiler Basis
There are two general situations in which a company installs one or
more new boilers. One is at a grass-roots location, where a new process plant
is built from scratch, and a complete boiler system must be included to supply
the corresponding steam requirements. The other is at an existing location,
when expansion of steam requirements and/or retirement of worn-out boiler^s)
necessitate the addition of new steam generation capacity to the existing
system.
Selection of particular boiler type and fuel basis for the above
boiler projects will be the result of many overall economic, technical,
environmental and logistic studies. It should be emphasized that the overall
boiler system should be studied for all appropriate alternatives.
A third situation in which a company might consider installation
of new boilers would be for a change from gas or oil to coal fuel. Gas/oil
package boilers conceivably could be converted to conventional coal firing
(e.g. stoker or pulverized coal) with significant revamping, plus major
downrating of capacity - downrating by as much as 40 to 80 percent (11).
Such conversion in general is considered impractical. Under these circum-
stances, if a company perceives an incentive or need to switch from gas or
oil to coal, it is extremely likely that installation of new coal-fired
boilers would be selected rather than revamping of the existing ones. This
will be discussed in more detail in a later section of this report.
2.3 Estimated Investments and Operating Costs
Consistent screening cases have been developed to compare investments
and operating costs for the following boiler/fuel combinations:
• FBC boiler firing high sulfur coal;
• Conventional coal-fired boiler and flue gas scrubber,
firing high sulfur coal;
• Conventional coal-fired boiler firing low sulfur
"compliance" coal (low enough sulfur so that no
further S02 control is required);
• FBC boiler firing low sulfur "compliance" coal;
• Package oil-fired boiler firing low sulfur fuel oil.
-------
- 18 -
The cases cover both complete grass roots boiler systems and addition of
single boilers to existing plants.
Investments are presented in terms of 1975 dollars — no estimate
of future inflation has been included. Operating costs include all cost
components except fuel. Future f.o.b. and transportation costs for various
sources of coal, as well as for industrial fuel oils are so uncertain that
it was decided to exclude fuels from the general comparisons of this study.
When making a cost comparison for a particular boiler project, an analyst
will know which fuels are available and at what prices, so that a direct
comparison can be developed.
Results of our economic comparisons for industrial boilers indicate
that the level of environmental control required for 862 and/or NOx, and the
relative prices for high and low sulfur fuels are fully as significant as the
investments and other direct operating costs for each case. When working
to current EPA New Source Performance Standards For Steam Generating Units,
we conclude that:
• When firing high sulfur coals, steam can be produced
in industrial boilers by fluidized bed combustion at
a cost (ex fuel) of about 85% of that for conventional
coal firing followed by flue gas scrubbing.
• If low sulfur "compliance" coal is used, fluidized bed
combustion and conventional firing are basically break-
even for large boiler sizes.
• As FBC technology matures, FBC boiler investments (in
constant 1975 dollars) are expected to decrease, making
future cost comparisons relatively more favorable for
fluidized bed boilers versus conventional coal firing
which is considered to be already "mature".
• If low sulfur fuel oil (LSFO) is available, its use in
package boilers may be an attractive alternative. The
possible advantage for LSFO (depending or relative fuel
prices) decreases as boiler capacity is increased.
The following table illustrates these conclusions:
Cost of Steam (ex Fuel Cost) From 100 KPPH and
400 KPPH Single Boiler Addition and Grass-Roots Boiler Systems
Fuel
Boiler Type
High
FBC
Sulfur Coal
Conventional
With Scrubber
Low Sulfur
"Compliance" Coal
Conventional
FBC With ESP
Low Sulfur
Fuel Oil
Package
Cost of Steam (ex Fuel Cost), c/k lb.*
Single Boiler Addition to Oil-Fired Boiler Plant
100 KPPH 359 395 315 290 147
400 KPPH 249 283 205 201 116
Grass-Roots Boiler System
100 KPPH 481 565 437 407 ois
400 KPPH 319 391 276 278 153
*FBC costs based on current fluidized bed combustion technology
-------
- 19 -
2.3.1 Basis for Comparing Alternative Technologies
This section describes the screening designs for boiler systems
which were developed to evaluate the comparative investments and operating
costs associated with both grass roots and boiler addition projects as
described in the previous section (2.2.3). The following table summarizes
the combination of fuel, boiler type, and environmental provisions which
are considered for steam generation rates between 50 and 400 KPPH.
Provision for
Environmental Controls
_ Fuel _ Boiler Description SO? Particulates
High Sulfur Coal Fluidized Bed Combustion FBC Electrostatic
using Package Modules Precipitator (ESP)
High Sulfur Coal Spreader Stoker*, --- Limestone Scrubber ---
Field Erected
Low Sulfur Coal Fluidized Bed Combustion ** ESP
Using Package Modules
Low Sulfur Coal Spreader Stoker*, - ESP
Field Erected
Low Sulfur Oil Package, Watertube
* For boilers of 200 KPPH or greater, conventional coal cases are assumed
to use pulverized coal firing.
** No S02 control is needed for low sulfur "compliance" coal; however, the alkaline
ash of low sulfur Western coal is expected to give appreciable sulfur capture
when the coal is burned in an FBC unit.
In all cases, it is assumed that the NOx level in the flue gas will meet ^
New Source Standards for Steam Generating Equipment of 0.7 Ibs. N02/M BTU fired
for solid fuels and 0.3 Ibs. N02/M BTU fired for liquid fuels, without provision
of major additional facilities specifically for NOx control. FBC systems using
high sulfur coals give significantly lower NOx levels in the flue gas than
conventional coal firing. For conventional firing, design provision for staged
firing or similar combustion modifications, at relatively low cost, may be
necessary; even then, emissions may be only marginally within the EPA NOx emission
standards. For low sulfur coals and lignites, it is assumed in this report that
FBC systems will at least meet the EPA standards. Extensive experimental work
on fluidized bed combustion of these fuels has not been carried out.
A. Grass Roots Comparisons
Design of a large coal-firing FBC industrial boiler system involves
much more than the boiler itself. Facilities must be provided for coal and
limestone receiving, storing and handling; coal preparation for burning; fly
-------
- 20 -
ash collection; bed ash and spent stone withdrawal; and waste solids disposal.
In the general grass roots case, these ancillary facilities may cost several
times as much as the boiler itself. Compared with this complex system, the
requirements for oil and gas firing are much simpler, less costly, and more
convenient. On the other hand, a conventional coal-fired boiler using high
sulfur coal will be even more complex because of the necessity for providing
flue gas scrubbing for control of SC>2 emissions. For example, the overall
screening investment for a grass roots project to build a conventional high-
sulfur-coal-fired industrial boiler system might be put together as follows:
Component
Two stoker-fired boilers
Coal receiving, storing, handling
Flue gas scrubbers, solid waste
collection/storage, stack, etc.
Sub-total
Project Contingency
Total system cost
M$
4.2
1.5
% of Total Investment
35.5
13
11.8
100
Figures 2-3, 2-4, and 2-5 show schematically the grass roots systems
for the above cases, including fuel receipt, transfer, and storage; boilers
and all associated facilities; environmental controls; and waste collection,
storage, and disposal. These plants are sized to supply a continuous overall
steam rate of 100 KPPH. Economic comparison of FBC , conventional coal, and
low sulfur oil cases for this size will demonstrate the ease or difficulty
with which coal can penetrate the market in which oil and/or gas are currently
predominant, and the possible advantage which developing FBC technology may
have over conventional coal firing. Below the capacity of about 100 KPPH,
we expect the investment cost, space requirements, and general inconvenience
of coal-fired systems relative to oil firing will be sufficiently higher that
coal is not likely to be widely used. Hence we consider 100 KPPH as the
approximate minimum size boiler plant in which FBC could have a significant
impact on the choice of coal vs. scarce fuels.
Appendix 1 presents the complete detailed investment and operating
cost bases for economic comparison of these grass roots boiler systems.
The manufacturing plants of interest in this study are all energy
intensive. Almost universally, large plants in the chemicals, petroleum,
paper and other energy intensive industries have multiple boilers with
adequate backup capacity such that one of the boilers in the system can
be shut down, for annual inspection, scheduled, or unscheduled maintenance,
without limiting the plant's throughput. For our comparison of grass roots
systems, we have included 2 x 100 KPPH boilers in order to insure an output
of 100 KPPH steam even if one boiler is off the line. Alternatively, we
could have included 3 x 50 KPPH boilers and still met this backup criterion.
Three 50 KPPH boilers would cost a few percent less than 2 x 100 KPPH units,
but directionally would require more space, more operating labor, and more
maintenance. We decided arbitrarily to base the grass roots comparisons on
a two-boiler system, and all of the cases have been handled in the same manner.
-------
BOILER SIZE
BOILER TYPE
FUEL
FUELPREP'N
FIGURE 2-3
FLUIDIZED BED BOILER SYSTEM
FIRED WITH HIGH SULFUR COAL
100 k Ib./H rating, 125 psig, saturated steam
Fluidized bed, watertube, atmospheric pressure, shop fabricated and assembled
High sulfur (3.6 wt. %) Illinois coal, %" nominal size
No further prep'n required
ENVIRONMENTAL PROVISIONS:
SO2 Fluidized bed system meets sulfur dioxide emission criteria
NOX Fluidized bed system meets nitrogen oxides emission criteria
Particulates Electrostatic precipitator (ESP)
OVERALL RATES
Coal 12,000 Ib/H = 144 T/D
Limestone 4,500 Ib/H = 54 T/D
Total Dry Solids to Disposal
(Ash & Spent Stone) 2.28 T/H = 55 T/D
Goal Receipt
O^**1-O
Solids Disposal Truck
Note: Limestone may not be required when low sulfur "compliance" coal is burned in a fluidized bed.
In this case, provision is made for receipt, storage, and handling of small quantities of
inert makeup material (e.g. crushed cinder, alumina) for the bed.
-------
FIGURE 2-4
CONVENTIONAL BOILER SYSTEM FIRED WITH HIGH SULFUR COAL
BOILER SIZE 100 k Ib./H rating, 125 psig, saturated steam
BOILER TYPE Watertube, spreader stoker fired, field assembled
FUEL High sulfur (3.6 wt. %) Illinois coal, 1%" nominal size for stoker firing
FUEL PREP'N No further prep'n required
ENVIRONMENTAL PROVISIONS:
SO2 Limestone throwaway — wet scrubber
NOX Hopefully, spreader stoker will just about meet 0.7 Ib. NOj/M Btu (which is emission
> 250 M Btu/H)
OVERALL RATES
Coal 12,000 Ib/H = 144 T/D
Limestone 1,800 Ib/H H 22 T
Boiler Ash 0.24 T/H s 6 T/D
Scrubber Sludge 2.5 T/H = 6
Total Solid Waste 66T/D
limit for
Particulates Multiclone dust collector for bulk fly ash; scrubber for final cleanup
Coal Receipt
i j Eimator r
T Covered Conveyor
() { J
ClJ
NOTES: Low sulfur coal case has electrostatic
precipitator and dry ash silo instead
of limestone scrubber, reheater, and
ash/slud£e pit
Limestone makeup circuit should be
revised to include wet grinding of
ID
Coal
Silo
X
Ash
Stoker Fired
_^^. Watertube
100 KPPH Each
)| 1
!—
BFW J
Slowdown
Dust Collector
Cr^l
Flyash Re-injection y^
FD Fan
*Q — Air
£ i
100 KPPH
"^^" Steam
to Process
drO
trr) TT "O
Limestone
Truck
Silo
X
^^
Scrubber
1
rj
L.
^
^^••MBBB
n
L ' '
~P
\
I f. \ si"^
Water \ Circulation
* y
. ^-f~
1 • "W
1
Sludge
Settler
"• and
Filter
Ash | Sludge (50% Moisture)
if • "[""Kb
pit 1 ^^ SolidTDis Val T u
^^^^ s re
•^ To Ash /Sludge
-------
FIGURE 2-5
CONVENTIONAL PACKAGE BOILER SYSTEM
FIRED WITH LOW SULFUR FUEL OIL
BOILER SIZE 100klb./h rating, 125 psig, saturated steam
BOILER TYPE Watertube, package (shop fabricated and assembled)
FUEL No. 6 Oil ( -15° API), low sulfur (0.7 wt %)
FUEL PREP'N Preheated, no further prep'n required
ENVIRONMENTAL PROVISIONS:
SO2 Not required
NOX Combustion modifications — include small investment allowance in cost of
grass roots package boiler
Particulates Not required
OVERALL RATES
Fuel Oil 485 B/SD = 6820 Ib/H s 82 T/D
Wn K ^~*^~^~^
Oil
r
Fuel Oil
Tank
(Heated)
trac«, insulate
%JULf T - - - - - - -r
2
Package
Watertube
Rnllorc fa
100 KPPH Each
t
nc
FDFan
*^^^^ii^^^ »•"•• Air
7*A STack
II 100 KPPH
1 fc Steam
to Process
-------
- 24 -
Table 2-2 presents the overall Input and output streams for each
of the comparable cases, corresponding to a gross steam demand of 100 KPPH.
Using the bases of Appendix 1, consistent screening investment
estimates were developed for each case. For facilities for which Exxon has
direct cost experience, such as oil-fired package boilers, oil tanks, pumps,
piping, ducting, stack, etc., our normal investment estimating procedure
was followed. For flue gas scrubbers, vendor quotes were obtained and checked,
and indirect costs were added as applicable for Field Labor Overheads, Contractor
Engineering, Freight, etc. Care was taken to define clearly the vendor's basis
for each quotation, so as to obtain meaningful and consistent estimates for
each hypothetical project. ERDA provided cost estimates for fluidized bed
boilers and coal-fired stoker boilers, based on project costs reported in
proposals submitted to ERDA as part of the FBC technology development program.
In the case of the coal receiving and storage facilities, Appendix 1
includes provision of equipment for direct receipt of coal by rail in shipments
of 10 cars at a time, and storage capacity for about 16 days coal supply. The
facilities actually provided for a real project at any given location can vary
over a very wide range, from almost continuous receipt by truck and minimum
onsite storage to large bulk receipt by rail or barge, possible coal processing
facilities, and much longer coal storage capability. Hence we did not carry
out a complete screening estimate for these specific facilities, but instead
used an order-of-magnitude allowance of 1 1/2 million dollars (which was agreed
by ERDA and MITRE to be within a reasonable cost range for the receiving and
storage system described in Appendix 1). It should be noted that as the
receiving/storing system increases in complexity and cost, some offsetting
reductions in delivered coal price are likely so that the overall cost of steam
production may not be markedly changed in the general case.
Following development of cost estimates for these 100 KPPH systems,
we extended the estimates to cover the range of 50 to 400 KPPH by exponential
"prorating" in order to evaluate the "economy of size" effects as applied to
boiler plants. It is well known that a general relation between investment
and capacity for process facilities can be expressed over reasonable ranges
of size as:
I = KCn
where I is investment, C is capacity in any convenient units of throughput,
and K and n are constants characteristic of the particular process under study.
This general relationship has been used to estimate investments for
plants of 50, 200, and 400 KPPH capacity relative to the basic 100 KPPH
investments. A table included in Appendix 1 presents the exponents which were
used for this purpose for each increment of size.
Costs of steam (ex fuel) from the grass-roots boiler systems were
built up by estimating direct operating costs and capital charges for each
case. Bases for evaluation of these items are contained in Appendix 1
-------
TABLE 2-2
COMPARATIVE INDUSTRIAL GRASS-ROOTS BOILER SYSTEMS
AND OVERALL INPUT/OUTPUT RATES
Bases: Steam Demand - 100 KPPH, 125 psig, saturated
Boiler Capacity Provided - 2 x 100 KPPH watertube boilers
Fuel
Fuel Rate, T/D
Boiler Type
S02 Control
Ca/S Ratio
Limestone Rate, T/D
Particulate Control
Solid Waste
Waste Solid
Rate, T/D
Approximate Space
Required for Grass-
Roots Boiler Plant,
Acres
High Sulfur Coal
144
FBC
Package Modules
FBC
Dry Sulfated
Stone/Ash Mix.
55
144
Conventional
Spreader Stoker
Field Assembled
Once-through
Limestone Scrubber
3.0
54
Cyclones and
ESP
1.2
22
Cyclones and
Scrubber
Scrubber Sludge/
Ash Mixture
66
Low Sulfur Coal*
187
Conventional
Spreader Stoker
Field Assembled, or
FBC Package Modules
Not
Needed
Cyclones and
ESP
Ash
11
Low Sulfur
82
(485 B/D)
Package
Not
Needed
Not
Needed
None
ro
Ul
1 1/2
* Fuel sulfur content low enough that stack S02 emissions comply with Federal EPA New Source Performance
Standards for SO- from Steam Generators (>250 M Btu/hr) without additional SO- controls.
Note that NOX emissions from FBC-fired boilers are below Federal EPA New Source Performance Standards for
NOX from Steam Generators (>250 M Btu/hr). In all other cases, inclusions of design features for combustion
modifications may be necessary in order to meet these standards.
-------
- 26 -
B. Comparisons of Single Boiler Addition Projects
When a single boiler is to be added to an existing boiler system,
all of the facilities shown in Figures 2-3 to 2-5 may not be required. In
general, the backup capability discussed in the previous section already
exists in the system, so that additional backup is usually not required
provided the new boiler is fairly close in size to the existing ones. Usually
the same fuel is used for the new and existing boilers. It is likely that
the increased fuel receipts will be taken care of by increased use of the
existing unloading facilities and somewhat shorter average days fuel storage,
thus making maximum use of the existing facilities with minor outlays for
tie-ins to service the new boiler.
Table 2-3 summarizes the assumptions made in each investment area in
deriving cost estimates for single boiler addition projects from the basic
estimates for complete grass-roots systems. Parallel procedures were used
to estimate unit operating costs of steam generation in "add-on" boilers
consistent with those used for the complete grass-roots cases.
2.3.2 Overall Results for Single Boiler Addition Cases
Based on experience, we believe that most sales of large new boilers
are for addition of single boilers to existing plants. Therefore, in this
report, we will first present comparisons for the different cases of boiler
add-on projects, and then proceed to comparisons of grass-roots boiler plants
at new plant sites (although this is the reverse of the sequence in which the
results were developed).
The simplest case of addition of a coal-fired boiler (either FBC or
conventional) is to a boiler plant which already uses coal. In this case,
most of the facilities for coal receiving and handling are already in place.
However, because of the difference in coal particle size for FBC and conventional
firing, we have.arbitrarily assumed that precrushed FBC coal is received segregated
from the fuel for the rest of the plant, and stored in a new silo. Alternatively,
the FBC case could include onsite facilities for coal preparation, with corres-
ponding increases in manning, maintenance, and utilities costs, but no need to
segregate coal storage. Table 2-4 summarizes the comparisons for additions of
100 and 400 KPPH boilers. More details are presented in Appendix 3, Tables 12-
20. In analyzing these cases, we have assumed that the newly-added boilers will
be base-loaded, with an overall availability of 90%.
When burning high sulfur coal, the investment required for an added
FBC boiler with electrostatic precipitator is less than for a conventional
boiler plus flue gas desulfurization. This advantage increases as boiler
capacity goes up. Direct operating costs are estimated to be closely comparable.
Capital charges directly reflect the investments, and so the combined operating
costs show a small advantage for FBC at the 100 KPPH size, increasing as boiler
size goes up (20 to 30 c/k Ibs.). The cost of steam is quite sensitive to changes
in investment — at the 100 KPPH size an overall change of 0.5 M$ in investment
(roughly 10%) results in a change in unit steam cost of 13 c/k pounds.
-------
TABLE 2-3
FACILITIES BASIS FOR SINGLE BOILER ADDITION PROJECTS
Fuel for New Boiler
New Boiler Type
A. When Existing System Is Oil-Fired .
Provision in Addition Project For:
Fuel Receiving, Storing, Feeding
Limestone Receiving, Storing, Feeding
Boiler
Stack
ESP
Flue Gas Scrubber System
Solid Waste Collection, Storage, Disposal
B. When Existing System is Coal-Fired,
Provision in Addition Project For:
Fuel Receiving
Fuel Storing, Feeding
Limestone Receiving, Storing, Feeding
Boiler
Stack
ESP
Flue Gas Scrubber System
Solid Waste Collection, Storage, Disposal
High Sulfur Coal
Low Sulfur "Compliance" Coal
FBC
Conventional
FBC
Conventional
Low Sulfur Fuel Oil
Package
Complete
Complete
Single, Complete
Single
None
Complete
Tie-ins
New Silo and Conveyors
Tie-ins
Single, Complete
Complete Complete Complete Incremental Tie-ins
Complete None* None None
Single, Complete Single, Complete Single, Complete Single, Complete
Single New Stack, No Tie-ins
None Single Single None
Single None None None
Complete Complete Complete
Tie-Ins Tie-ins ,Tie-ins
Tie-ins New Silo and Conveyors Tie-ins
Tie-ins None* None
Single, Complete Single, Complete Single, Complete
Single New Stack, No Tie-ins
Single
None
Complete
None
Single
Tie-ins
Single
None
Tie-ins
Single
None
Tie-ins
None
THIS
CASE
NOT
CONSIDERED
* However, FBC firing compliance coal does require facilities to receive, store, and feed whatever small quantity of bed makeup material is needed.
-------
- 28 -
TABLE 2-4
COMPARISON OF INVESTMENTS, AND COST OF STEAM (EX FUEL),
FOR SINGLE BOILER ADDED TO COAL-FIRED PLANT
Fuel (1)
High Sulfur Coal
Low Sulfur Coal (2)
Boiler Type
Steam Rate, KPPH
Investment, M.$ (3)
Fuel Handling Additions
Boiler and Stack
Envtl. and Waste Disp.
Fluidized
Bed
Combustion
100
0.6
3.1
1.1
Total, M$ 4.8
Unit Cost of Steam (ex Fuel) ,
Direct Op. Costs (ex
Fuel and BFW)
Boiler Feed Water
Capital Charges
Total, C/k Ib. (ex fuel)
125
60
122
307
400
0.9
7.6
2.9
11.4
C/k Ib.
95
60
72
227
Conventional
With
Scrubber
100
0.2
2.9
2.3
5.4
(3)
131
60
137
328
400
0.3
8.6
6.1
15.0
100
60
95
255
Fluidized
Bed
Combustion
100
0.6
3.1
0.9
83
60
117
260
0.9
7.6
2.4
Conventional
With
ESP
400 100
0.2
2.9
0.7
4.6 10.9 3.8
53 64
60 60
69 96
182 220
400
0.3
8.6
1.8
10.7
45
60
68
173
(1) The same type fuel is assumed to be fired in the existing boilers as in the
new boiler, i.e., no cases are considered in which low sulfur coal and high
sulfur coal are fired simultaneously to different boilers of the same plant.
(2) Low sulfur coal by definition for these cases is assumed to be sufficiently
low in sulfur so that no S02 controls are needed to meet whatever environmental
limits are applicable.
°peratln8 costs are presented in Appendix 3,
-------
- 29 -
Comparing cases using low sulfur compliance coal, the conventional
arrangement of stoker (or PCF unit) plus ESP is indicated to have a slight
investment advantage over the FBC system. This investment difference con-
ceivably could be turned around in the future as FBC technology matures,
especially for the larger sized boilers. As regards operating costs, the
pressure drop across the FBC system is significantly higher than for the
conventional system, and the fan power costs reflect this factor. Overall
the conventional case shows a moderate advantage over FBC at the 100 KPPH
size, shrinking to breakeven at 400 KPPH. We conclude from these
estimates that if low sulfur coal is available at a competitive price, boiler
operators already firing low sulfur coal in conventional units will not be
likely to change to FBC in the early years of FBC application. However,
the future relationship between price and availability of high and low sulfur
coals is extremely uncertain - it would be expected that low sulfur coal in
the future might command a significant premium over high sulfur coal if SC>2
environmental limits are held at the levels used for this study.
In the situation where an existing boiler plant is oil-fired, the
cost of introducing the first coal-fired boiler into such a plant will be
considerably higher than the cases considered above. The investments for the
boiler itself and for its environmental controls will be basically the same,
but to this will be added a significant increment for new coal receiving,
storing, and handling facilities. Table 2-5 presents the overall results of
our comparisons for the addition of 100 and 400 KPPH coal-fired boilers, as
well as a comparative case for addition of another 100 or 400 KPPH low sulfur
oil-fired unit. Details of these cases are tabulated in Appendix 3, Tables 21-
31.
Again for this situation, when high sulfur coal is the fuel of choice
FBC has a nominal investment advantage over conventional combustion plus flue
gas scrubbing at the 100 KPPH size. This advantage increases as the boiler
size goes up to 400 KPPH. Direct operating costs are very similar for the
two cases. Overall, FBC is estimated to have about a 35
-------
TABLE 2-5
Fuel
Boiler Type
Steam Rate, KPPH
Investments, M$ (3)
Fuel Handling Allowance(2)
Boiler and Stack
Envtl and Waste Disp.
Total, M$
Direct Op. Costs (ex
Fuel and BFW)
Boiler Feed Water
Capital Charges
Total, C/k lb. (ex Fuel)
COMPARISON OF INVESTMENTS, AND COST OF STEAM (EX
FOR SINGLE BOILER ADDED TO OIL-FIRED PLANT
High Sulfur Coal
Fluidized
Bed
Combustion
100
) 1.8
3.1
1.3
6.2
el), C/k lb.
142
60
157
400
2.7
7.6
3.4
13.7
(3)
102
60
87
Conventional
With
Scrubber
100
1.8
2.9
2.6
7.3
150
60
185
400
2.7
8.6
6.9
18.2
108
60
115
FUEL) ,
Low Sulfur Coal
Fluidized
Bed
Combustion
100
1.9
3.1
1.1
6.1
100
60
155
400
2.9
7.6
2.9
13.4
60
60
85
(1)
Conventional
With ESP
100
1.9
2.9
1.0
5.8
83
60
147
400
2.9
8.6
2.6
14.1
52
60
89
Low Sulfur
Fuel Oil(l)
Package
100
0.1
1.5
1.6
46
60
41
400
0.2
3.7
3.9
31
60
25
u>
o
359
249 395
283
315
205 290
201
147
116
(1) Low sulfur coal and fuel oil by definition are sufficiently low in sulfur that no S02 controls are
needed to meet whatever environmental limits are applicable.
(2) In some cases where coal is reliably available by truck delivery, the capital costs for fuel receipt
and storage could be significantly reduced. In such cases, however, the delivered price of coal would
rise more-or-less correspondingly so that the overall cost of steam would not be changed markedly.
(3) Details of investments and operating costs are presented in Appendix 3, Tables 21-31.
-------
31 -
It should be noted that an FBC boiler has inherent flexibility to
handle a tightened S(>2 emission regulation if such a requirement is imposed
after the boiler is built. This could be done simply by initiating or increasing
the limestone rate charged to the bed and the withdrawal rate of spent bed
material. In contrast, reduction of SC>2 emissions from a conventional boiler
might require retrofit addition of a flue gas scrubber system.
A case is included in Table 2-5 for addition of a low-sulfur-oil-
fired package boiler to an existing oil-fired plant. As would be expected,
the investment and operating costs for this case are much below those for
coal firing. If fuel oil is permitted for use in new MFBI units, a large
boiler operator would be willing to pay a substantial premium — up to the
neighborhood of $1.10/M BTU — for low sulfur fuel oil over high sulfur coal.
2.3.3 Overall Results for Grass-Roots Boiler Plants
Investments and operating costs for grass-roots boiler systems
supplying 100 and 400 KPPH steam are summarized in Table 2-6. More complete
details for these cases are given in Appendix 3, Tables 1-11. These results
cover the complete grass-roots systems, with 100% boiler and scrubber backup,
as described in Figures 2-3 to 2-5 and text of Section 2.3.2. Since they
include complete fuels receiving, storing, and handling facilities, plus two
boilers such as might be installed in a new, grass-roots location, the invest-
ments and operating costs are higher than for the previous cases. The same
relative results are obtained, however. Fluidized bed combustion of high
sulfur coal shows an advantage of about 70-80 c/k lb. steam over conventional
combustion of the same coal plus flue gas scrubbing. Note that these results
are for current FBC technology; further improvements are anticipated for
second-generation and subsequent units, as discussed in a later section (2.3.5).
Low sulfur compliance coal fired using conventional technology enjoys
capital and direct operating cost advantages corresponding to the lack of a
flue gas scrubber. However, burning of the same low sulfur coal in an FBC
system is not far behind at 100 KPPH O 30
-------
TABLE 2-6
COMPARISON OF INVESTMENTS, AND COST OF STEAM (EX FUEL),
FOR GRASS ROOTS BOILER PLANTS WITH BACKUP
Fuel
Boiler Type
Steam Rate, KPPH
Investment, M$(3)
Fuel Handling Allowance (2)
2 Boilers and Stack
Envtl. and Waste Disp.
Total, M$
Unit Cost of Steam (ex Fuel),
Direct Op. Costs (ex
Fuel and BFW)
Boiler Feed Water
Capital Charges
Total, C/k Ib. (ex Fuel)
High Sulfur Coal
Fluidized
Bed
Combustion
100 400
1.8 2.7
5.8 14.3
1.9 5.0
9.5 22.0
C/k lb.(3)
180 119
60 60
241 140
481 319
Conventional
With
Scrubber
100 400
1.8 2.7
5.4 16.0
4.6 12.2
11.8 30.9
206 135
60 60
299 196
565 391
Low Sulfur Coal(l)
Fluidized
Bed
Combustion
100 400
1.9 2.9
5.8 14.3
1.7 4.5
9.4 21.7
139 79
60 60
238 137
437 276
Conventional
With ESP
100
1.9
5.4
1.6
8.9
121
60
226
407
400
2.9
16.0
4.2
23.1
71
60
147
278
Low Sulfur
Fuel Oil(l)
Package
100
0.6
2.6
3.2
77
60
81
218
400
1.4
6.4
7.8
44
60
49
153
I
N5
(1) Low sulfur coal and fuel oil by definition are sufficiently low in sulfur that no S02 controls are
needed to meet whatever environmental limits are applicable.
(2) In some cases where coal is reliably available by truck delivery, the capital costs for fuel receipt
and storage could be significantly reduced. In such cases, however, the delivered price of coal would
rise more-or-less correspondingly so that the overall cost of steam would not be changed markedly.
(3) Details of investments and operating costs are presented in Appendix 3, Tables 1-11.
-------
- 33 -
(3) Generation of steam in industrial boilers using fluidized
bed combustion of high sulfur coal is predicted to be
economically attractive (by about 35-75 C/k Ibs. steam)
compared with conventional burning of the same coal in
conjunction with flue gas scrubbing. This comparison
is based on current FBC designs ("first generation").
Cost reduction in FBC designs is anticipated in the
future, as FBC technology matures. In a subsequent
section (2.3.5), we have discussed the overall order-
of-magnitude improvement which is likely.
(4) FBC appears to be fairly close to breakeven with
conventional coal-firing for burning low sulfur
compliance coal (low enough sulfur content to meet
emission criteria without SC>2 removal). In this
connection, FBC may well be the only practical
technology for burning many slagging coals and high
ash lignites which are difficult to use in conventional
boilers.
(5) In all cases, capital charges comprise from 43 to 67%
of the total controllable operating costs (ex fuel and
boiler feed water).
2.3.4 Areas of Technical Uncertainty
Several areas of FBC technology have been identified in which
there are real or apparent problems. Resolution of these uncertainties will
be needed before widespread application of coal-fired FBC can be expected.
The principal uncertainties concern:
(1) availability of suitable limestone (without excessive
transportation costs from distant locations)
(2) disposal of waste solids
(3) maintenance of desired particle size distribution
in the fluidized bed.
A. Availability of Suitable Limestone
The limestone characteristics which are desired for effective use
in once-through FBC systems are high reactivity with S02 at bed conditions;
particle strength and attrition resistance at bed conditions so that stable
fluidized bed behavior can be achieved; resistance to thermal degradation
(spalling, fragmentation) as boilers are started up and shut down.
Although limestone deposits are widely distributed, there is no
certainty that all stones are suitable for FBC use. Performance data are
available for only a few of the many limestone sources, and widely differing
behavior is observed from one limestone to another. Unfortunately, there
are no simple analytical laboratory methods by which to determine the limestone
properties. Each stone has to be tested in an FBC laboratory unit.
-------
- 34 -
In the 30 MWe FBC demonstration utility boiler being installed in
Rivesville, West Virginia, local Greer limestone will be used. This stone
was initially tested by Pope, Evans and Robbins using conditions under which
the Grove limestone used most widely in FBC development work had performed
well. The Greer stone could not be retained in the bed during initial cal-
cination under these conditions and appeared unsuitable for use. However,
experiments with modified operating conditions successfully identified a
suitable working range in which satisfactory initial calcination of the
Greer stone could be achieved, and this stone has met the other requirements
of reactivity, attrition resistance, and thermal stability (15).
The above discussion pertains to FBC operations in which sorbents
(mostly limestones) are used "once-through" with discard of the spent stone.
If effective regeneration technology is developed, the regeneration characteristics
of the limestones are also significant.
B. Disposal of Waste Solids
The problem of disposing of sulfated, dry granular limestone is
quite different from that of wet limestone sludges from once-through flue
gas scrubbers, although both are products of control operations to meet
environmental criteria for sulfur emissions. Another related problem,
if a large increase in coal consumption is to occur, is the disposal of
the correspondingly large quantities of ash.
Much work is underway at various locations to characterize more
definitively the waste products resulting from different methods of use of
a wide variety of coals (e.g. conventional and FBC fly ash, bottom ash,
scrubber sludges, FBC bed material, etc.) as regards physical form, particle
size, bulk and trace chemical composition, leachability, etc. Work is also
underway to identify general and specific possible uses for these materials
rather than simply throwing them away. In the-future, the decisions in
connection with installation of one or more coal-fired industrial boilers at
a specific location may be influenced by results from much of this work.
Our aim here has been to make reasonable assumptions as a working basis for
these generalized screening comparisons.
(1) Ash. Only a small percentage of the fly ash and bottom
ash resulting from current coal burning operations is used
to manufacture some other product (e.g. cinder block). The
largest portion of the ash is directly (or indirectly after
storage in ash retention ponds) disposed of in landfill
operations. Unless major byproduct outlets for ash are
developed, eventual expanded disposition may be in the
direction of sending it back to exhausted mines after the
coal has been removed. Work by DOT (Department of Trans-
portation) and others is directed toward large scale
utilization of fly ash in road construction.
Fly ash from fluidized bed combustion has been exposed
to maximum bed temperatures of the magnitude of 1600-
1700°F. Hence, it is quite different in physical form
from fly ash from conventional combustion, which has
been heated to incipient or complete fusion. In this
report, we have assumed that capture by ESP and handling
-------
- 35 -
of FBC fly ash will not be significantly more costly
than in conventional boiler operations.
(2) Wet Sludge. Disposal of scrubber sludge is one of the
most perplexing problems and obstacles to widespread
adoption of limestone (or lime) throwaway flue gas
scrubbing to meet sulfur emission limits. Ponding and
eventual landfill disposition is almost the only disposal
outlet. Even after long-time settling, a sludge composed
predominantly of calcium sulfite is not very compact and
does not have high load-bearing capability- One expanding
sub-option is to condition or treat the sludge to improve
its load-bearing strength. This can be accomplished by
oxidizing sulfite to sulfate, and/or by mixing the sludge
with ash and additives. If the high calcium ash from some
western coals is added to a slurry scrubber, this also has
been observed to promote sulfate formation (16).
Large industrial plants may have adequate acreage for
building sludge ponds to hold several years' sludge
production. Most industrial plants do not have this
capability. In our economic studies, the preliminary
assumption is that the filtered sludge (mixed with ash
in the case of conventional coal firing) is disposed of
by truck, at a cost of $8 per ton. Each $2/ton variation
from this cost changes the cost of steam by 5.5 C/k Ib.
(3) Dry Waste from FB Combustion of High Sulfur Coal. In the
limestone fluidized bed, the CaC03 of the fresh stone is
first calcined
CaC03 t=$ CaO + C02
At bed conditions, the lime reacts with S02 (from the
sulfur in the coal) and excess 02 to form calcium sulfate
CaO + S02 + 1/2 02 ^~) CaSO^
To achieve adequate sulfur removal, excess limestone is fed
to the bed — feed Ca/S ratios up to 6 have been used in FBC
development work. The 30 MW Rivesville demonstration unit is
designed for a Ca/S ratio of 2. In our industrial boiler
calculations, we have assumed a Ca/S ratio of 3 for high sulfur
coal. In the range of Ca/S ratios of 2 to 3, spent waste from
an impure limestone has a composition something like the following:
wt%
CaS04 30 - 45
CaO (excess) 25 - 35
Other (MgO, Si02, A1203,
iron oxide, ash, etc.) 30 - 35
-------
- 36 -
Considerable preliminary work has been done on possible uses
for spent stone co-mingled with ash. These uses include
production of building materials such as gypsum or aggregate,
agricultural use as lime/fertilizer, and neutralization of
acid mine drainage. The high free CaO content may make this
material unsuitable for direct landfill except in lined cavities .
However, the dry granular nature of the waste mixture makes it
easily handled and stored.
In our economic calculations, our preliminary assumption is
that the dry stone/ash mixture will be carted away be truck,
at a selected range of $/ton cost, without designating the
eventual disposition of the material.
For initial evaluation, we have used the same disposal cost of
$8 per ton as was used for the sludge/ash mixture in the stoker
case. Any reduction in cost because of the easier handling
characteristics of the granular FBC material will represent
a corresponding additional advantage for the FBC case. A change
of + $2 per ton in disposal cost results in a change in steam
cost of + 4.6 e/k Ibs.
Our general basis has been to mix in a single dry waste silo
the fine particulate material collected by the electrostatic
precipitator with the much coarser spent bed material withdrawn
from the FBC combustor. There is some indication that the material
collected in the ESP is mostly fly ash f-rom the coal. As such
the concentrations of trace components which originated in the
coal would be much higher in this ESP stream than in the bed
material. If there is an economic incentive to segregate these
two streams for separate dispositions, this can readily be
done by providing an additional separate storage facility for
the small particulate stream collected by the ESP.
(4) Bed Material and Ash from FB Combustion of Low Sulfur Western Coals.
Very little information is available on this version of fluidized
bed combustion. Unlike Eastern coals, Montana/Wyoming sub-bituminous
coals typically have alkaline ash which contains relatively high
percentages of sodium and calcium. For this study, we have assumed
that the bed material for FB combustion of these coals would be a
relatively hard inert granular material (e.g. crushed cinder, alumina).
Very low makeup rates of bed material are assumed necessary to replace
depletion of the bed by attrition. Most of the ash from the coal is
assumed to leave the bed as fly ash, eventually recovered by the ESP.
If the feed coal contains very much inert matter itself (slate, etc.),
some purging of the bed may be necessary. Much experimental information
is required before this case is clearly defined.
-------
- 37 -
C. Maintenance of Optimum Particle Size Distribution in Fluidized Bed
For effective operation of a fluidized bed, it is essential that
neither very fine nor very coarse particles accumulate within the bed. In
fluidized bed combustors, careful design of the air-distributing grid and
maintenance of adequate gas velocity through the bed are sufficient to
sweep out the fine particles, so that accumulation of fines does not appear
to be a problem. Considering the other end of the particle size range, FBC
investigators on occasion have observed the accumulation of oversized particles
in the bed. The cause or causes of this build-up are not yet completely under-
stood. Because such accumulations could lead to ever poorer fluidization, early
designs of proposed commercial units made provision for removal of large
particles from the bed. This feature is included in the design of the
Rivesville unit where bed material withdrawn from the cells of the boiler will
undergo continuous hot screening. A large number of those actively engaged
in development of FBC technology expect that the need for hot screening might
be avoided by choice of coal, cleaning of coal, or specification of a certain
maximum size of coal. A higher limestone makeup rate and bed withdrawal rate
to purge large particles might also reduce or eliminate the need for hot bed
screening.
Recent FBC designs, such as those included in proposals being
negotiated with ERDA as FBC development projects, do not include provision
for continuous hot screening capability. Hence, the cost estimates used for
the preceding economic analyses do not include this provision. However, as
explained in detail in Appendix 2, we have included a "process development
allowance" of 0.3 M$ per boiler (100 KPPH size) in the cost estimate. This
was evaluated as about 20% of that part of the boiler investment which is
considered part of the new FBC technology- We believe this allowance is
adequate to cover the cost of hot screening if demonstration proves that
this is necessary.
2.3.5 Significant Cost Reductions Possible for Future FBC Designs
As stated earlier, fluidized bed combustion of coal in boilers is a
newly-developing technology. No commercial-sized boilers have yet been built
in the U.S., either for industrial or utility service. The basic cost estimates
for the boiler sections of the FBC systems we have studied represent a current
FBC process design similar to those being developed by the Fluidized Bed
Combustion Company, Livingston, N.J., in response to commercial inquiries.
We have communicated closely with engineers of this company during preparation
and analysis of these estimates for FBC boilers.
Our estimates include the provision, associated with current FBC
designs, of a "process development allowance" as the FBC process is commercialized
(as discussed in Appendix 2). Despite the historic need for investment additions
during early process development and commercialization, the history of technical
processes also clearly demonstrates that major cost improvements are normally
achieved as a process matures. Hirschmann (18) presents a general analysis of
this "learning curve" experience, which is very similar to what Exxon has found
through past studies. Stated simply, after we have built the first commercial
-------
- 38 -
plant, and if there is developmental effort to learn from the first plant's
actual performance, then subsequent plants cost less. Experiences with many
processes could be cited as examples of this learning curve, e.g. fluid
catalytic cracking and ethylene manufacture.
In the case of FBC, we expect that reductions of 15-20% are likely
in the boiler portion of total project costs for "mature" fluidized bed
boilers, based on typical application of the learning curve. Expressed in
terms of steam costs, the above investment reduction corresponds to about
20-30 C/k Ibs. steam for a 100 KPPH grass roots FBC boiler plant.
Note that the conventional technology cases are also subject to
the same learning curve effects, but because stokers, pulverized coal units,
and oil-fired package boilers are already mature, the likelihood is far
smaller for significant cost reductions in these technologies. On the same
basis as used for FBC costs, we expect that some improvements will be made
for the flue gas scrubbers of the conventional high sulfur coal cases. However,
these scrubbers are smaller investment pieces than the FBC boilers, and they are
essentially already commercialized, compared to the much earlier demonstration
stage for FBC technology. We estimate that the reduction of steam costs
resulting from scrubber improvements will be in the magnitude of 5-10 c/k Ibs.
for 100 KPPH grass roots plants.
2.3.6 Revamping of Existing Boilers for FBC Service Not Likely
We have analyzed the likelihood of "retrofitting" fluidized bed
combustors to existing industrial boilers, as well as to study the installation
of completely new fluidized bed industrial boilers. The term "retrofitting" is
subject to a rather wide range of interpretations. Our initial concept of
retrofitting was that of fitting a new components (e.g. a flue gas scrubber)
into or onto an existing piece of equipment. Using this narrow definition,
we conclude that retrofitting of an FBC system to an existing boiler is
infeasible. However, we have become aware that a much broader interpretation
of retrofitting may be used by others, to cover what we would think of variously
as conversion, substitution, rebuilding (revamping), modernization, etc. With
this broader usage in mind, we judge that retrofitting is likely to be economically
unattractive. In making this judgment, we have taken into account the boiler
size range of interest in this study, and apply the following reasoning: Heat
release rates in a fluidized bed (BTU/hr/cubic foot) are several times as intense
as in a conventional boiler. Furthermore, much of the heat transfer surface in
an FBC unit is submerged within the bed, whereas in a conventional boiler the
tubes surround the firebox but are located with care so as to avoid flame
impingement. A likely way in which an existing oil- or gas-fired package boiler
could be "converted" to FBC service would be to remove the burner (s), cut out
some or all of the existing tubes and drums and install the fluidized bed with
its submerged heat transfer surface within the old boiler shell. Addition of
the required solids handling facilities to inject fuel and limestone, recycle
bed material, and withdraw ash and sulfated stone, while conforming with the
dimensions of the old unit would involve additional constraints. To accomplish
the above work, the boiler would be out of service for a very considerable
period of time. The likelihood that such a complicated revamp procedure could
be economically attractive is remote.
-------
- 39 -
2.4 Market Survey of Large Industrial Boiler Users
The Market Survey part of this study was planned to obtain responses
from leading, knowledgable companies in energy-intensive manufacturing industries,
in order to
• reinforce (or contradict) the conclusions of
our technical and engineering assessments of
FBC bailers, and
• collect reactions of potential FBC users to
the application of this new technology in their
own specific circumstances.
Thirty-two companies were contacted, and their responses covered a
wide span of opinions. Most of these companies already burn coal at some
locations. They recognize that natural gas will rapidly become unavailable
for their use as fuel for steam generation. In general, they expressed a
desire to continue to burn fuel oil in boilers as long as possible because
of its convenience, lower capital requirements, and lower environmental
problems; a few feel that the price differential between oil and low sulfur
coal already makes coal a competative fuel for very large boilers. They expect to
broaden their use of coal long range, and would prefer to use "compliance" low
sulfur coal wherever it is available. All expressed an interest in FBC, and
those who expect problems with S02 and/or NOx emissions will be ready (over a
fairly wide range of enthusiasm from cool to warm) to consider the use of FBC
in their own operations when it is demonstrated to be "commercially reliable
and economically attractive".
2.4.1 Survey Procedure
The survey was limited to large manufacturers in industries which use
large quantities of boiler fuels for continuous steam generation. We contacted:
14 Chemical Companies
6 Paper Companies
2 Petroleum Refiners
3 Food and Kindred Products
3 Primary Metals
_4 Other
32
In each of these companies, we located a staff official, usually in
corporate headquarters, with the function of "Energy Coordinator/Long-Range
Planner". All contacts were made by telephone. In each case, we assured the
company representative that his responses would be kept anonymous, and that
neither he nor his company would be identified in our survey reports.
-------
- 40 -
In practically all cases we first outlined the objectives of the
telephone discussions and then sent the company a brief summary of the current
state of development of FBC. The final phone discussion, about 2 weeks after
the initial contact, usually took 30 minutes to an hour. The following outline
summarizes the content of the final conversation.
Outline of Discussion With Corporate Energy Coordinator
FBC Market Survey
• Description of typical boiler plant of subject company.
• Technical characteristics of future boilers (FBC or conventional) anticipated
by company.
• Expectations for supplying company's future boiler fuel requirements -
(a) short range
(b) long range
Plans for moving from present situation to short range future to long range
future.
« Specific problems cited by company which restrict or slow down company's
use of coal.
• Company's perception of advantages, disadvantages, and overall outlook for
its use of Fluidized Bed Combustion in boilers.
« At what point of FBC's technical development will company be ready to consider
installation of FBC boiler?
• Company's suggestions for effective Government actions to promote increased
use of coal, and rapid adoption of FBC if demonstrations are successful.
2.4.2 Results and Interpretation
The intent of the "market survey" was to collect reactions and
plans of potential users of FBC to their use of coal as industrial boiler
fuel and to their possible application of this new technology in their own
particular situations. There was no intent to make a statistical analysis
of the information collected in this survey, since the companies were not
selected to be a representative sample of their industries. Most of the
questions asked were not really subject to quantitative interpretation.
The following summary gives the broad general positions taken by most of
the responders, along with comments pertinent to some of the individual
industries.
-------
- 41 -
General Feedback From FBC Market Survey
• Typical large boiler plant may have 4 or 5 good-sized boilers (>150 KPPH).
Generates steam at "high" pressure (e.g. 600 psig), expands steam through
turbine(s), down to lower pressure level set by process requirements.
This configuration produces an increment of low cost "byproduct" power, as
well as added reliability or flexibility (motor plus turbine) for driving
large pumps, compressors, etc.
• Future boilers will probably be going up in pressure to generate a
larger increment of in-plant power. In many cases, respondents expect
future individual boiler capacity to remain pretty much at current levels,
although a few companies expect significant increases in boiler sizes.
• Few plants burn coal, most burn gas or oil.
• A number of plants burned coal formerly, but have converted more-or-less
irreversibly to gas/oil.
• Some companies have already started activities to re-introduce coal at
locations where it was previously burned, and to consider coal at new
large locations. Many other companies recognize that boilers will be
coal-fired long range, but have not yet started to consider how that
situation will be reached, starting with present package oil/gas-fired
boilers. Coal may be impractical at even relatively large plants if
adequate space is not available.
• "Low sulfur" coal — meaning in the context of the conversation that such
coal would meet applicable 862 emission limits — was noted repeatedly as
the preferred fuel when coal is introduced at a new location. We found
reluctant acceptance, but no enthusiasm for the use of flue gas desulfurization
as a sulfur emissions control technology from industrial boilers.
« Converting (or revamping) package gas/oil-fired boilers to coal service
is almost certainly impractical, because of:
+ serious downrating
+ high cost
+ long outage time
Conversion to FBC might result in a lower degree of downrating than conversion
to a stoker or pulverized coal unit, but neither conversion alternative is likely
to be used to any significant degree.
• Principal government action to stimulate coal use is clear, consistent
energy policy, firm guidelines; avoid frequent changes. Stimulate coal
production, and make sure adequate transportation capability is developed.
Provide tax incentives or $ subsidy, although these actions mentioned
less often. Several companies recommended relaxation of environmental
standards.
• Fluidized bed combustion looks attractive if it is demonstrated to be
+ reliable
+ economical
• FBC features of significant interest:
+ effective SC>2/NOx control
+ fuel flexibility
+ less severe solid waste disposal problems
-------
- 42 -
Particular concerns with FBC were noted by representatives of
industries which burn large quantities of internally-generated by-product
fuels. For instance, paper companies expect that FBC in power boilers will
have flexibility to burn waste wood, bark, and "hogged" fuel. They are
certain that black liquor will continue to be fired in recovery boilers,
which are designed specifically to recover and purify sodium chemicals. This
service would not be suitable either for conventional or FBC coal firing
because of contamination of the recovered sodium salts with ash or sorbent.
Steel companies state that their heat balances are subject to wide fluctuations
boiler fuel may vary from almost all purchased fuel to almost all low BTU blast
furnace gas, so it is desirable long range for FBC boilers to have this
flexibility. Petroleum refineries burn high viscosity residua, cracked tars
and hydrocarbon sludge from high sulfur crudes, as well as refinery gas
containing low molecular weight hydrocarbons (containing one to four carbon
atoms - methane through butane and butenes). Flexibility to burn these fuels
is desirable for FBC boilers in refineries, and somewhat similarly in certain
chemicals plants.
Boiler operators expect that FBC boilers will be somewhat more
complicated to control than conventional coal-fired units. This is not
expected to interfere with initial FBC boiler designs, however, since most
of them will be single boiler additions to existing boiler plants. Under
these conditions, the new FBC boiler likely will be base loaded, so as to
have relatively little need for dynamic response to continual load shifts.
As would be expected, we found wide variations in the level of
enthusiasm for FBC. The following excerpts of comments from respondents
illustrate the level of expectant support which FBC already has, as well
as the lack of interest shown by others.
"We have a 25-year supply of low sulfur coal lined up, and
do not foresee any interest in FBC."
"We are opposed to flue gas scrubbers as a matter of company
policy. If FBC is proved to be an effective and economically competitive
method of sulfur control, we will be glad to use it."
"Do not expect to be in a position to use FBC. Looking at
municipal and county solid wastes as our next source of BTU."
"Our company is very conservative as regards technology. We will
not be ready to look at FBC seriously until it is thoroughly proven as regards
reliability - to level of one emergency outage per year."
"Company has extensive high sulfur coal reserves, and is very
interested in FBC. Ready to take reasonable risks in pioneer project, jointly
with reputable boiler manufacturer."
Overall, we found the companies which we contacted to be aware and
concerned regarding their own energy outlook, generally supportive of a
national policy to shift away from scarce fuels to coal, but very concerned
-------
- 43 -
about the capital requirements and the environmental constraints which confront
such a shift. We conclude that they will welcome the successful technical
demonstrations of fluidized bed combustion as applied to industrial boilers,
and will be ready to use FBC when it is shown to be economically attractive.
2.5 Specific Technical Requirements for Representative Industrial
Fluidized Bed Boilers
Desired performance requirements for industrial fluidized bed boilers
do not differ significantly from those for conventional coal-fired boilers. The
ideal industrial boiler (regardless of fuel fired) is safe to operate over its
entire range of performance, gives high thermal efficiency, requires minimum
maintenance and has a high percent availability, can be easily and smoothly
shifted from base fuel to alternate fuel or to simultaneous burning of two
fuels (or more), has adequate turndown capability, responds quickly to changes
in load, and meets all environmental requirements. The final design of a real
boiler requires compromises to balance the degree to which each of the above
features is achieved against cost. The owner must provide the designer with
economic values (e.g. identity and expected value of marginal fuel, incentive
for avoiding emergency outages, etc.) so that decisions on these compromises
can be reached wisely.
No attempt has been made in this generalized screening study to carry
out such economic optimization. It is assumed that the "standard" conventional
and FBC boilers provided by boiler manufacturers are designed to be reasonably
in agreement with such economic criteria. Optimization is normally carried out
during the definitive planning and design stages of a specific project, when
the purchase specifications for one or more boilers are being developed.
Practically all participants in our market survey indicated very
little or no interest in paying a premium for unusually high turndown or
unusually rapid response to changing loads.
Table 2-7 summarizes typical performance requirements for a 250 KPPH
industrial fluidized bed boiler in petroleum refinery service. Performance
requirements for FBC boilers in chemical plant service would be similar to
those in petroleum refining except that in many cases no gaseous fuel would
be available as an alternate energy source. In steel plants, alternate fuel
could well be low BTU gas (e.g. excess blast furnace gas, providing 90-100
BTU/cubic foot). In paper plants, boiler size could be somewhat larger,
possibly limited by the maximum module capacity which can be shop assembled
and shipped as a package. Alternate fuels in paper and pulp plants may include
bark, wood chips, sawdust, and other waste fuels, but will not include black
liquor since recovery of the sodium values would be impractical in admixture
with the FBC sorbent. In food processing plants, typical boiler capacity is
likely to be smaller than 250 KPPH, and steam pressure will be significantly
lower in locations where the owner does not require byproduct power generation.
-------
TABLE 2-7
TYPICAL DUTY SPECIFICATION FOR INDUSTRIAL FLUIDIZED BED
BOILER FOR USE IN PETROLEUM REFINERY BOILER SERVICE
Boiler shall be designed in accordance with ASME Boiler and Pressure Vessel Code, Section 1, and
with additional local and state requirements as applicable.
Continuous steam generation rate, Ibs/hr 250,000
(Maximum Continuous Rating, MCR)
Peak steam generation rate, Ibs/hr 275,000
(110% of MCR, peak capacity for 1 hour in 24)
Steam pressure at superheater outlet, psig 650
(1)
Steam Temperature at Superheater Outlet, °F 750
(at continuous steam generation rate)
Feedwater temperature from water treating unit, °F 240
Continuous blowdown rate, percent of feedwater rate To be reported, based
on Boiler Feed Water composition.
Maximum solids carryover in steam, wppm 1
(at drum outlet with 2000 ppm Total Dissolved Solids in drum)
Turndown ratio 4:1
Boiler shall be capable of smooth, safe operation
with reasonable efficiency at 25% of MCR, and at
any higher rate up to 110% of MCR (peak capacity)
-------
TABLE 2-7 (continued)
(2)
Desired speed of response
Boiler and control system shall be capable of moving smoothly and under
continuous control from 30% of MCR to 100% of MCR in a period of
20 minutes (maximum).
Thermal efficiency (based on HHV of fuel, at MCR)
Base fuel fired
Sorbent
Alternate fuel fired
Design range for ratio of coal to refinery gas, %• of heat release
Startup fuel
Design availability
Boiler shall be designed for continuous runs of one year duration.
Scheduled annual outage for inspection and maintenance
Unscheduled outage
Maximum emission of contaminants in flue gas at boiler exit, Ibs/M Btu fired
Sulfur Dioxide
Nitrogen Oxides (as N02)
Maximum effective noise level
82% (minimum)
Illinois No. 6 Coal
Grove Limestone
Refinery Gas ^
100/0 to 0/100
Refinery Gas or No. 2
Fuel Oil
92% (minimum)
3% (maximum)
5% (maximum)
1.2
0.7
per OSHA limits
4>
Ul
-------
TABLE 2-7 (continued)
Safety Safety valves shall be provided in
accordance with ASME Boiler and
and Pressure Vessel Code, Section 1.
Emergency response controls shall be
included for loss of steam pressure,
loss of drum level, loss of feed water,
loss of fluidization air, loss • of ID
fan, and high bed temperature. Provision
shall also be made to prevent injection
of coal feed on startup until bed is
preheated to safe ignition temperature.
ON
I
Notes: (1) 650 psig and 750°F are typical design conditions for current industrial boilers. Future
conditions are likely to be more severe (e.g. 900 psig, 900°F, or even higher).
(2) Initial single FBC boilers added to an existing system will probably be base loaded, so
this desired response will not become critical until entire boiler systems are comprised
of FBC boilers.
(3) Alternate liquid fuels (e.g. No. 2, No. 4, and No. 6 fuel oils and/or high viscosity
residual stocks) may also be specified. Typical refinery gas composition is:
Hydrogen 62 vol.% C4's 2
Methane 14 Water 1
Ethane and Ethylene 12 Nitrogen 4
Propane and Propylene 4 CC>2 1
Total 100 vol.%
-------
- 47 -
3. MANUFACTURING INDUSTRIES
This section begins defining what is meant by "manufacturing
industries" for the purposes of the study. Some industries use a great
deal of fuel while others do not. Four industry groups (Chemicals,
Primary Metals, Petroleum Refining, Paper) account for about two thirds of
the purchased, commercial fuels used by manufacturing industry. In general,
the industries that have the highest total fuel consumption also use the
largest amounts of boiler fuel, but there are exceptions. These points are
discussed, first, in relation to fuel data collected for the 1972 Census of
Manufactures (1) and, then, in more detail, by reference to survey data obtained
by the Federal Energy Administration in 1975. These statistics are used as
background for consideration of how boiler fuel demand may develop in the
future.
3.1 Standard Industrial Classification
The Standard Industrial Classification system of the Bureau of the
Census (U.S. Department of Commerce) recognizes twenty-one manufacturing
industries in terms of 2-digit SIC codes (19 through 39). There is further
subdivision to take account of different operations within a given industry.
The subdivisions comprise 450 4-digit SIC codes. The current level of fuel
consumption and the nature of the pertinent manufacturing operation indicates
that about 30 of the 450 4-digit categories may offer a potential to coal-
fired FBC. Most of these prospects are concentrated in the broader (2-digit)
groupings of the chemicals, paper, petroleum refining, primary metals and food
industries.
3.2 1972 Census of Manufactures
The most recent comprehensive data for energy consumption by the
manufacturing industries are for 1971, and are published in the 1972 Census
of Manufactures (1), (2). These data have the advantage of providing a
detailed breakdown by SIC code of fuel purchased by each industry. However,
the data have several disadvantages:
(1) by now, they are somewhat out of date.
(2) they deal with purchased fuels, but not with the
by-product fuels that are utilized to a significant
degree by some industries.
(3) they do not distinguish between fuels consumed in
boilers and in a variety of other equipment such as
process heaters and kilns.
In spite of these shortcomings, the Census data in Table 3-1 show
that a small number of industries is responsible for most of the consumption
of purchased fuels. Primary Metals (SIC 33), Petroleum Refining (SIC 29) and
the Paper Industires (SIC 26) account for most of the by-product fuels that
are used captively but are not included in the Census data. Inclusion of
by-product fuels would further increase the fraction of total fuel consumption
attributable to the most energy-consuming industries.
-------
TABLE 3-1
PURCHASES OF FUEL BY INDUSTRY GROUP IN 1971
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
SIC
Code
28
33
29
26
32
20
37
35
34
22
24
36
30
19/39
27
38
25
23
31
21
Description of Industry Group
Chemicals and Allied Products
Primary Metal Industries
Petroleum Refining and Related Industries
Paper and Allied Products
Stone, Clay, Glass and Concrete Products
Food and Kindred Products
Transportation Equipment
Machinery, except Electrical
Fabricated Metal Products
Textile Mill Products
Lumber and Wood Products, except Furniture
Electrical Machinery, Equipment, and Supplies
Rubber and Miscellaneous Plastic Products
Ordnance and Accessories/Miscellaneous
Manufactures
Printing, Publishing and Allied Industries
Instruments and Related Products
Furniture and Fixtures
Apparel and Other Finished Products
Leather and Leather Products
Tobacco Manufactures
All Manufacturing Industries
Billion
BTU's
2421
2018
1500
1188
1186
905
294
289
281
276
195
192
174
83
71
55
48
47
28
16
11270
% of Total
Purchased Fuel
21.5
17.9
13.3
10.6
10.5
8.0
2.6
2.6
2.5
2.5
1.7
1.7
1.6
0.7
0.6
0.5
0.4
0.4
0.3
0.1
100.
Cumulative
%
21.5
39.4
52.7
63.3
73.8
81.8
84.4
87.0
89.5
92.0
93.7
95.4
97.0
97.7
98.3
98.8
99.2
99.6
99.9
100.
co
i
-------
- 49 -
3.3 Fuel Consumption of Large Industrial Boilers in 1974
In 1975, the Federal Energy Administration conducted a survey of
all Major Fuel Burning Installations in the U.S. An MFBI is an installation
that has, or is, a fossil-fuel fired boiler, burner or combustor with a
design firing rate of 100 million BTU's per hour or greater. The precise
definition of MFBI and other pertinent information, such as the purpose of
the survey, are given in Chart 1. FEA's Office of Fuel Utilization has
provided data from this survey and from a related Natural Gas Task Force
(NGTF) survey for use in this study. All of the data apply to industrial
boilers having a designed heat input capability of 100 million BTU/H or more.
In 1974, there were approximately 4,000 of such boilers at 1,600 industrial
installations in the lower 48 states.
From Table 3-2, it will be seen that the population of large
industrial boilers had the following breakdown by size and fuel consumption:
Size Range
106 BTU/H
> 500
> 350
> 250
> 200
% of Number
of Large Boilers
5.0
13.2
26.5
38.6
of 1974 Fuel Consumption
of Large Boilers
16.8
32.9
51.6
64.0
The average consumption of commercial fuels (coal, oil, natural gas)
of the entire population of large industrial boilers was 1.0 trillion BTU per
boiler in 1974. Total fuel consumption was somewhat higher because "other"
fuels, such as black liqudtr, coke oven gas, and bagasse are excluded from
the computation. The reported total consumption of commercial fuels (coal,
oil, natural gas) was 4 quads* or 166 million tons of coal equivalent. In
fact, 76% of the fuel consumption was in the form of oil (mostly residual
fuel) and natural gas.
Similar data are available with a further breakdown by SIC Code,
as follows:
sie
Code
20
26
28
29
32
33
34
35
49
Industry
1012 BTU in 1974
Food
Paper
Chemicals
Petroleum Refining
Stone, Clay, Glass,
Concrete
Primary Metals
Fabricated Metal Products
Machinery, except Electrical
Utility Services**
Other Industries
SIC Code not specified
193
593
926
587
19
443
61
50
99
681
362
( 45)
(633)
4014(3912)
Average per Boiler
1Q12 BTU in 1974
0.62
1.07
1.14
1.61
0.51
1.16
0.60
0.49
0.93
0.80
1.23
1.00
*one quad = 1015 BTU
**except electricity generation
-------
CHART 1
- 50 -
FEDERAL ENERGY ADMINISTRATION
WASHINGTON, D.C. 20-161
APPROVED BY GAO
Jt-1X1251 (57502^)
EXPIRES 6-30-75
[THISi~KEPOHT IS MANDATORY UNDER P.L. 93-275
MAJOR FUEL BURNING INSTALLATION COAL CONVERSION REPORT
FKA C-602-S-0
INSTRUCTIONS
!. I'liHPOSK
Form FEA C-602-S-0 is a request for information from "major
fuel binning installations" to aid FEA in carrying out its respon-
sibilities under the Energy Supply and Environmental Coordination
Act of 1974 (P.L. 93-319). (A major fuel burning installation will
be referred to in this form as "MFB1".) The survey is designed
to obtain data required by FEA to examine the feasibility and
effect of issuing orders to specified major fuel burning installations
prohibiting them from burning oil or natural gas as their primary
energy source.
If. WHO SHOULD SUBMIT
Form FEA C-602-S-0 must be submitted by every MFB1.
MFBI is defined on'page 3 of this form. The form may be filled
out by a responsible official at either the installation or, if appli-
cable, the parent organization.
III. TO WHOM
Two copies of the Form FEA C-602-S-0 must be filed with:
Federal Energy Administration
ATTN: OFU/CRB Room 6117
Washington, D.C. 20461
IV. WHEN
Form FEA C-602-S-0 must be submitted cm or before May 21.
1975.
V. GENERAL INSTRUCTIONS
This report is mandatory, and is being required pursuant to the
authorities granted to FEA by the Federal Energy Administration
Act of 1974 (P.L. 93-275).
A single Section 1 shall be filed for each facility, even if it is
comprised of more than one combustor of fuel. Sections II and
III shall be filed for each separate combustor with an individual
capacity of 100 million Btu's/hr or greater.
Fill in the combustor number and installation name at the top
of each applicable page in order to facilitate handling should the
pages be inadvertently separated in mailing.
For all questions which can be answered by a "Yes" or "No",
"1" (for "Yes") or "0" (for "No") shall be entered in the appropriate
block unless otherwise stated.
A blank page has been provided at the end of this questionnaire
to permit comments to be continued where inadequate space is
provided on the form.
VI. SPECIFIC INSTRUCTIONS
Section I
Item No.
4, 5
Limit responses to (he number of blocks provided, using
standard abbreviations where appropriate.
Air Quality Control Region: As designated by the Envi-
ronmental Protection Agency. Do not fill in the line if
the AQCR is unknown.
Includes all boilers arid other combustprs regardless of
design firing rate. If there are more than 99 in either of
these categories insert the number 99.
Place the 4-digit primary Standard Industrial Classi-
fication Code (SIC) in the first column anil the percent
of ioiu! sii;p;;-;iiits c; sei'viCvi (by va'ue) :r> the second.
Three entries are available for multi-commodity installa-
tions. If it is possible to enter more than three SIC entries,
list the three with the highest percentage of total ship-
ments. If the SIC is unknown, describe the products or
services on the line provided.
Section II
Item No.
I Assign each combustor a two-digit identification number
if it dues not alieauy have CHIC.
7a Fill in the blank with 1, 2, or 3.
19b The term "rank" of coal refers to anthracite, bituminous,
sub-bituminous, or lignite.
19g The term "other unique characteristics" refers to % mois-
ture, hardness, fusion, temperature, and all other applicable
coal parameters which must be maintained to insure proper
operation of the combustor.
21, 22 Fill in the estimated "average" Btu content.
Section IH
Item No.
I Assign each stack a one-digit identification number.
3b The "% Availability" refers to the percentage of time
the FGD equipment is available for operation (regardless
wheiher or not it is actually operated).
4c, d & If it would be necessary to either install FGD or obtain
5c, d conforming coal, please complete both item (c), assuming
FGD is used, and item (d), assuming conforming coal is
used.
VII. DEFINITIONS
I. "Major Fuel Burning Installation". An installation or unit
other than a powerplant that has or is a fossil-fuel fired boiler,
burner, or other combustor of fuel, or an;' combination thereof
at a single site, that has individually or in combination, a design
firing rate of 100 million BTU's per hour or greater, and includes
any person who owns, leases, operates, controls or supervises, any
such installation or unit. Gas turbines and combined cycle or
internal combustion engines are excluded from this classification.
2. "Powerplant". A fossil-fuel fired steam electric generating
unit that produces electric power for purposes of sale or exchange,
and includes any person who owns, leases, operates, controls or
supervises any such unit.
3. "Total Designed Firing Rate". The sum total of all design
firing rates of all combusting devices located at the facility.
expressed as [(A)x 10" Btu/hr].
4. "Combustor". An individual fossil-fuel boiler, burner, or other
combustor of fuel.
5. "Combustor Capacity". The design firing rate of a combustor
expressed as [(A) x 10" Btu/hrj.
6. "Topping Turbine". This refers to either steam driven electric
generating sets or gas turbine electric generatini; sets associated
with a process steam generating boiler.
7. "Primary Energy Source". That amount of fuel used for all
purposes except for the minimum amounts required for start-up,
testing, flame stabilization, control uses, and fuel preparation.
-------
TABLE 3-2
1974 CAPACITY AND FUEL CONSUMPTION PROFILES OF LARGE INDUSTRIAL BOILERS
Size Range
of Boiler
106 BTU/H
1000+
900-999
800-899
700-799
600-699
500-599
450-499
400-449
350-399
300-349
250-299
200-249
150-199
100-149
Units
20
5
17
31
47
77
71
98
152
191
327
473
917
1487
Number of Boilers
% of
Total
0.5
0.1
0.4
0.8
1.2
2.0
1.8
2.5
3.9
4.9
8.4
12.1
23.4
38.0
%
0.5
0.6
1.0
1.8
3.0
5.0
6.8
9.3
13.2
18.1
26.5
38.6
62.0
100.
1974
1012 BTU
110
14.4
64.3
105
142
227
160
213
263
310
428
493
651
111
Fuel Consumption*
% of
Total
2.8
0.4
1.6
2.7
3.6
5.7
4.0
5.4
6.7
7.9
10.8
12.4
16.4
19.6
%
2.8
3.2
4.8
7.5
11.1
16.8
20.8
26.2
32.9
40.8
51.6
64.0
80.4
100.
Av. -Fuel
Consumption
Per Boiler
1Q12 BTU
5.50
2.88
3.78
3.38
3.06
2.95
2.25
2.18
1.73
1.62
1.31
1.04
0.71
0.52
I-1
i
3913
100.
3960
100.
1.01
*Coal, oil and natural gas; excludes "other" fuels such as black liquor, bagasse, coke oven gas, etc.
Note: Data for Alaska, Hawaii, Puerto Rico, and Virgin Islands are included.
Source: FEA, MFBI Survey, Report No. 22.
-------
- 52 -
The numbers in parentheses in the above table are our corrections
of the raw FEA data to take account of nine very large boilers, believed to
be electric utility boilers, that appear to have been included in the industrial
boiler statistics. After making this correction, and also prorating the "SIC
Code not specified" data to the specified categories, the following breakdown
was estimated for 1974:
Sic % of Total Fuel Consumed Approx. Utilization
Code Industry by Large Industrial Boilers of Boiler Capacity, I
28 Chemicals 26.2 66
26 Paper 16.7 47
29 Petroleum Refining 16.5 66
33 Primary Metals 12.4 46
20 Food 5.4 40
34 Fabricated Metal Products 1.7 32
35 Machinery, except Electrical 1.4 43
49 Utility Services 1.3 28
32 Stone, Clay, Glass, Concrete 0.6 32
Other Industrial 17.8 53
100. 54_
The relatively high boiler capacity utilization reported for the
chemicals and petroleum refining industries is in line with prior expectations.
An estimated breakdown of the 17.8% of boiler fuel consumption
attributed to "Other Industries" is given in Table 3-3. The estimate is
based on disaggregation of purchased fuels data from the 1972 Census of
Manufactures.*
Data obtained in FEA's Natural Gas Task Force survey were used to
derive the estimates of 1974 fuel consumption by large industrial boilers that
are reported in Table 3-4. These estimates give a breakdown both by fuel type
and SIC Code. The figures listed in parentheses in the final column are those
obtained from the MFBI survey. It will be seen that the differences between
the two sets of survey data are not large, and that the largest discrepancy
is in the "other SIC's" category. Although the two surveys corroborate each
other, it is believed that the MFBI survey data are somewhat more accurate and
complete. However, the Natural Gas Task Force survey provides some information
that is not available from the MFBI Survey. Pooling of the survey data yielded
the maximum information.
The Natural Gas Task Force survey provides a breakdown by the regions
listed in Table 3-5. The regional statistics may be disaggregated further by
using the number of large industrial boilers reported in the MFBI survey as a
multiplier. The number of large boilers in each state may be expressed as a
percentage of the regional total. These percentages are shown in column (A)
of Table 3-6. In addition, the state boiler totals may be expressed as a
percentage of the national total, as shown in column (B). However, for the
purpose of disaggregation of other statistics from a regional to a state basis
only the percentages in column (A) are needed.
*Since more recent survey data were not made available by FEA's Office of Fuel
Utilization.
-------
- 53 -
TABLE 3-3
ESTIMATED BREAKDOWN OF PERCENTAGE OF TOTAL FUEL
CONSUMED BY LARGE INDUSTRIAL BOILERS ATTRIBUTABLE TO
"OTHER INDUSTRIES"
SIC
Code
37
22
24
36
30
19/39
27
38
25
23
31
21
Industry
Transportation Equipment
Textile Mill Products
Lumber and Wood Products
Electrical Equipment
Rubber and Plastics Products
Ordnance/Miscellan eous Manufacturing
Printing and Publishing
Instruments and Related Products
Furniture and Fixtures
Apparel and Other Textiles
Leather and Leather Products
Tobacco Manufactures
% of Total Fuel Consumed
by Large Industrial Boilers in 1974
3.5
3.3
2.3
2.3
2.1
1.0
0.9
0.7
0.6
0.6
0.3
0.2
17.8
-------
TABLE 3-4
1974 FUEL CONSUMPTION BY TYPE AND
SIC
Code
20
26
28
29
32
331/332
333/339
Other SICs
Total
Coal
46
136
234
13.5
1.4
236
1.0
298
966
1974
Res id
27
221
111
75
11
8
9
287
749
Fuel Consumption
Distillate
8
6
12
nil
negl.
2
nil
39
67
By Large Boilers,
Nat. Gas
106
206
596
493
7
50
74
286
1818
BY SIC CODE
1012 BTU
Other
1
89
27
20
1.4
100
14
35
288
Total
188
658
980
602
21
396
98
945
3888
% of
Total
Ln
-P-
100
Notes: (1) Fuel consumption in Alaska, Hawaii, Puerto Rico and Virgin Islands is excluded
(2) Fuel consumption of large boilers for which no SIC Code was reported has been
prorated to other SIC Codes.
(3) Figures in parentheses are estimated based on MFBI survey data.
Source: Natural Gas Task Force Survey
-------
TABLE 3-5
REGIONAL BASIS OF NATURAL GAS TASK FORCE DATA
Region
No.
1
2
3
4
5
6
7
8
9
10
11
12
Description
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S.W.
Pacific N.W.
Pacific
Territories
States and Territories Included in Region
Conn., Me., Mass., N.H., R.I., Vt.
Del., D.C., Ky., Md., N.J., N.Y., Ohio, Penna., Va., W. Va;
Ala., Fla., Ga., N.C., S.C., Tenn.
111., Ind., Mich., Wis.
Iowa, Minn., Neb., N.D., S.D.
Kan., Mo., Okla.
Ark., La., Miss., Tex.
Col., Mont., Utah, Wyo.
Ariz., Ca., Nev., N.M.
Ida., Ore., Wash.
Alaska, Hawaii
Puerto Rico, Virgin Islands
National Totals
Lower 48
Regions 1-12
Regions 1 - 10, i.e. National Totals Minus (Regions 11 & 12)
-------
- 56 -
TABLE 3-6
NUMBER OF LARGE INDUSTRIAL BOILERS BY STATE AND FRACTION
OF REGIONAL AND LOWER 48 TOTALS
New England
Conn.
Me.
Mass.
N.H.
R.I.
Vt.
Appalachian
Del.
B.C.
Ky.
Md.
N.J.
N.Y.
Ohio
Pa.
Va.
W. Va.
Southeast
Ala.
Fla.
Ga.
N.C.
s.c.
Tenn.
Great Lakes
111.
Ind.
Mich.
Wis.
No.
54
39
45
13
3
nil
134
14
19
61
55
135
160
270
231
124
82
1151
89
89
81
122
93
124
598
201
166
227
89
683
(A)
25.4
29.1
33.6
9.7
2.2
nil
100.
1.
1.
5.
4.
11.
13.
23.
20.
10.
7.
100.
14.
14.
13.
20.
15.
20.
100.
29.
24.
33.
13.
100.
2
7
3
8
7
9
4
1
8
1
9
9
5
4
6
7
4
3
3
0
00...
0.82
0.95
1.09
0.32
0.07
nil
3
0
0
1
1
3
3
6
5
3
1
27
2
2
1
2
2
3
14
4
4
5
2
16
.25
.34
.46
.48
.33
.28
.88
.55
.60
.01
.99
.92
.16
.16
.97
.96
.26
.01
.51
.88
.03
.51
.16
.57
Northern Plains
Iowa
Minn.
Neb.
N.D.
S.D.
Midcontinent
Kan.
Mo.
Okla.
Gulf Coast
Ark.
La. .
Miss.
Tex.
Rocky Mountains
Col.
Mont.
Utah
Wyo.
Pacific S.W.
Ariz.
Ca.
Nev.
N.M.
No.
42
44
10
4
7
107
32
42
42
116
48
267
44
513
872
63
15
16
29
123
6
161
6
8
181
(A)
39.3
41.2
9.3
3.7
6.5
100.
27.
36.
36.
100.
5.
30.
5.
58.
100.
51.
12.
13.
23.
100.
3.
89.
3.
4.
100.
6
2
2
5
6
0
9
2
2
0
6
3
0
3
4
(B)
1.
1.
0.
0.
0.
2.
0.
1.
1.
2.
1.
6.
1.
12.
21.
1.
0.
0.
0.
2.
0.
3.
0.
0.
4.
02
07
24
10
17
60
78
02
02
82
16
48
07
45
15
53
36
39
70
98
15
91
15
19
39
Notes: No. = Number of Large Industrial Boilers
(A) = % of Regional Total
(B) = % of Lower 48 States Total
Source: FEA MFBI Survey
-------
- 57 -
TABLE 3-6 (continued)
Pacific N.W.
No.
Ida.
Ore.
Wash.
17
31
109
157
10.8
19.8
57.4
100.
0.41
0.75
2.64
3.81
Pacific
Alaska
Hawaii
46
12.
58
Extra Continental No. (A) (B)
Pacific
Territories
National Total
58
16.
74
4196
Extra Continental 74
Lower 48 4122
Territories
Puerto Rico
Virgin Is.
13
_^
16
REGIONAL SUMMARY
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S.W;
Pacific N.W.
No. of Large Boilers
134
1151
598
683
107
116
872
123
181
157
% of Lower 48 Total
3.25
27.92
14.51
16.57
,60
.82
2.
2.
21.15
98
39
2.
4.
3.81
Notes: No. = Number of Large Industrial Boilers
(A) = % of Regional Total
(B) = % of Lower 48 States Total
Source: FEA MFBI Survey
-------
- 58 -
Fuel consumption, by SIC Code, was obtained on a regional basis
in the NGTF survey. Similar statistics for boiler capacity were also
obtained. The overall results are reported in Tables 3-7, 3-8, and 3-9 on
a percentage basis. Estimates of the absolute levels of fuel consumption by
large industrial boilers, state by state, could be calculated from the
regional totals using the percentages in column (A) of Table 3-6 as a
multiplier.*
FEA's survey data for 1974, which are presented in detail in
Appendix 4, form the basis from which projections of future industrial
boiler fuel consumption were made. The methods of projection and the
quantitative estimates are discussed in Section 4.
3.4 Discussion of Future Options
In 1974, the large industrial boilers, as a group, used approximately
2.9 quads of oil and gas, with gas accounting for two thirds of this quantity.
If coal were to be used wherever petroleum was used in 1974, the theoretical
annual saving of oil and gas would be the above 2.9 quads. However, the
operators of the boilers reported to the FEA that only about 0.65 quads could
have been saved by converting to coal. The explanation is that many companies
responding to the MFBI survey took the position that most of their oil or
gas fired boilers cannot be converted to coal-firing. The implication is that
the only way by which the petroleum consumption associated with these boilers
could be saved would be by installation of new coal-fired boilers. The reported
potential savings of 0.65 quads relates primarily to reconversion (from oil or
gas to coal) of boilers that were originally designed for coal-firing.
A boiler originally designed for coal has the physical dimensions
for reconversion to coal-firing, without downrating of steam generating
capacity, even if the boiler is now firing oil or gas. In contrast, a
substantial majority of boilers originally designed to fire oil or gas
would undergo severe downrating if revamped for coal-firing.** We have been
advised 'that the expected downrating would be in the range of 40% to 70%.
In a literal sense, conversion to coal would be possible but, in practice,
such a loss of steam-generating capability would be economically intolerable.
*FEA's Office of Fuel Utilization has these data on a plant-by-plant basis
since the information was obtained in the 1975 MFBI survey. However, this
and other information is considered to be proprietary by FEA and, therefore,
not releasable. It is not essential to have this level of detail for the
present study.
**In testimony to the Senate Public Works Committee, Mr. William B. Marx,
executive director of the American Boiler Manufacturers Association, stated:
"Factory assembled package units have been installed by the thousands during
the past 20 years and have been almost exclusively engineered for non-coal
firing. In fact, well under ten percent of these units have the capability
for coal-firing." Reference 3, page 1719.
-------
- 59 -
TABLE 3-7
REGIONAL FUEL CONSUMPTION IN
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S.W.
Pacific N.W.
Lower 48 States
LARGE
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S.W.
Pacific N.W.
Coal
—
43.6
34.3
42.5
35.3
8.9
2.8
29.5
2.0
8.7
24.8
BOILER
Coal
_
34.7
24.1
35.9
30.6
10.4
1.9
31.0
4.5
12.4
21.3
Resid
90.9
32.3
28.7
10.5
4.3
negl.
6.3
21.2
8.4
12.3
19.2
TABLE
CAPACITY:
Resid
86.2
30.8
24.5
12.9
6.0
1.5
6.0
9.9
6.2
11.1
19.0
1974: PERCENTAGE
Distillate
_
0.8
0.7
8.2
2.7
2.2
0.1
1.2
0.7
0.1
1.8
3-8
REGIONAL % BASIS
Distillate
-
2.0
1.5
4.3
6.0
2.0
0.1
2.5
1.1
0.3
1.8
BASIS
Nat. Gas
3.2
16.1
20.4
29.0
54.6
86.9
86.7
47.8
80.7
73.1
46.8
Nat. Gas
3.8
17.8
19.4
30.2
55.2
72.2
80.2
52.9
75.0
50.0
41.4
Other
5.9
7.2
15.9
9.8
3.1
2.0
4.1
0.3
8.2
5.8
7.4
Other
10.0
14.7
30.5
16.7
2.2
13.9
11.8
3.7
13.2
26.2
16.5
Note: The fuels noted above are the primary fuels reported in FEA's
Natural Gas Task Force survey.
-------
- 60 -
TABLE 3-9
COMPARISON OF REGIONAL PERCENTAGES OF LARGE
INDUSTRIAL BOILERS BY NUMBER, 1974 FUEL
CONSUMPTION AND BOILER CAPACITY
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific N.W.
Pacific S.W.
c
/
No.
3.25
27.92
14.51
16.57
2.60
2.82
21.15
2.98
4.39
3.81
I of Lower 48 States
1974 Fuel
2.67
24.32
14.27
15.01
2.00
1.79
31.10
3.21
3.16
2.47
Total By
Capacity
2.85
26.17
16.03
15.98
1.99
2.19
24.98
2.63
3.86
3.32
Note: Above percentages are derived from statistics reported in FEA's
Natural Gas Task Force Survey.
-------
- 61 -
The MFBI survey revealed that 40% of the large boilers that were
originally designed to fire coal have been converted to oil- or gas-firing.
Analysis of fuel consumption data suggests that conversions of smaller
boilers has been even more extensive but, as will be apparent from subsequent
discussion, reconversion of the smaller boilers to coal-firing is unlikely.
Four general inferences may be drawn:
(1) Boilers that once fired coal may be reconvertible to coal-firing
without loss of steam-generating capacity.
(2) Only the large boilers (>100 million BTU/H) in (1) are likely
candidates for reconversion.*
(3) The majority of oil/gas-fired package boilers do not appear to be
practical candidates for conversion to conventional coal-firing.
(4) Economic considerations, inclusive of the general need to maintain
boiler availability, suggest that the majority of additional coal-
fired boilers will be new (grass-roots) units, even though many
would be installed at existing manufacturing plants.
The above inferences apply to conventional coal-fired boilers, including
those with scrubbers or other emission control equipment. The question arises
whether conversions, or reconversions, to coal-firing might be relatively more
advantageous if FBC technology were to be utilized. This possibility arises
primarily because the greater intensity of heat release in the fluid-bed might
make it possible to convert a package oil-fired boiler to coal-fired FBC with-
out downrating of the boiler steam generation capacity. Investigation of this
question reveals that the actual dimensions of the package boiler and the
configuration of its internals are not well suited to substitution of a fluid-
bed design. Nevertheless, rough estimates have been made using the assumption
that no downrating would be experienced, i.e. that conversion would be
practicable from an operational point of view. The rough estimates indicate
that the direct cost of conversion would be only slightly less than the cost
of a new coal-fired FBC unit. Part of the explanation for the smallness of
the estimated cost differential lies in the fact that the design and configur-
ation of the FB boiler could be optimized in a new unit. Moreover, this
comparison does not take into account the economic penalty that might have
to be assessed against the conversion approach to cover potential loss of
manufacturing capacity while the conversion was in progress. Nor does it
take account of the likelihood that an existing package boiler might have to
be raised in order to make room beneath it for withdrawal of ash, etc.
The conversion to FBC of a boiler that had once fired coal, or
still fires coal, would seem somewhat easier. However, the saving in
direct costs relative to a new FBC unit also appears small. Moreover,
there is evidence that such industrial boilers are beginning to be equipped
with scrubbers. Hence, by the time that coal-fired FBC is thoroughly
*Even within this category, reconversion may not be practicable for a
variety of reasons, e.g. coal and ash handling facilities may have been
dismantled and space may no longer be available for reinstallation of
such facilities.
-------
- 62 -
demonstrated for industrial use, some of what may now appear as an FBC
potential may have already selected scrubbing as the control technology.
If this inference is correct, a corollary is that the time by which
FBC is fully demonstrated for industrial use will be an important deter-
minant of the market potential of the technology. Electric utilities
were the first to confront S02 control in commercial coal-burning equipment
in the U.S. Manufacturing industry, in general, has found an answer to the
problem by using natural gas, low sulfur fuel oil and, in some cases, low
sulfur coal. To be sure, high sulfur coal has been used too, and it is
precisely the need for bringing such operations into environmental compliance
that, currently, is generating interest in:
• Scrubbers
• Low Sulfur Coal
The market survey, discussed in Section 2.4, revealed that FBC
could be of at least comparable interest once this technology is demonstrated
as being commercially reliable.
In June, 1974, Congress passed the Energy Supply and Coordination
Act of 1974 (ESECA) (4). The Act authorized FEA to prohibit certain power
plants and major fuel burning installations from burning oil or gas as a
primary fuel, and to order certain power plants, then in the planning
stage, to be built with coal-burning capability. ESECA was passed as an
emergency measure (shortly after the Arab oil boycott, and undoubtedly
influenced by it), and conferred only limited powers of short duration on
FEA. Subsequently, however, proposed legislation was introduced in the
Senate Public Works Committee. The bill, S.1777, in its 1975 revised
version, was tentatively called the "Natural Gas and Petroleum and Coal
Utilization Act of 1975" (5). If passed, it would have extended the
coal-use provisions of ESECA. In fact, certain provisions of ESECA have
already been extended by the Energy Policy and Conservation Act of 1975
(EPCA) (6).
S.1777, as revised, provides for a phased conversion to coal of
all existing gas and oil-fired boilers of 100 million BTU/H firing rate
or larger. In the first phase, all new or existing gas-fired boilers
unable to burn coal would be required to convert to oil by 1/1/79 (except
those scheduled to be retired by 1/1/85).
In the second phase, all new or existing oil-fired boilers
(except those scheduled for retirement by 1/1/90) would be required to
acquire the capability to use coal, and be using it by 1985.
The revised bill provides FEA with authority to extend deadlines
for oil and coal use under certain conditions:
• The required fuel is not available.
• Conversion to coal is not practicable.
-------
- 63 -
Several conditions could create non-practicability:
(1) Low capacity factor (less than 3000 hours of
operation per year)
(2) Physical and legal factors (site specific limitations)
(3) Capital requirements relative to net current investment
(4) Reliability of electric service (in the case of electric
utilities)
(5) Impact on employment and economic activity, both
regionally and nationally
(6) Impact on profitability of the fuel user due to
diversion of gas or oil to others.
Civil penalties (fines) are proposed for illegal use of
oil beyond the deadlines prescribed for conversion.
Extensive testimony was received by the Senate Public Works
Committee prior to its revision in July 1975 (3). A substantial majority
of the testimoney was aimed at improving the practicability of the proposed
legislation by increasing the minimum boiler size to which the legislation
would apply (from 50 million BTU/H to 100 million BTU/H) and by specifying
criteria for non-practicability (see above). However, some witnesses were
opposed to coal-use legislation per se. For example, Donald G. Allen, Vice
President of New England Electric System remarked:
". . . we suggest that, in general, it is better policy
to encourage rather than to force conversion to coal,
particularly at a time when market forces are already
bringing about the preferential use of coal as boiler
fuel."
Naturally, we cannot predict if S.1777 will be enacted and,
if so, when. Nor can we predict whether and what further revisions may
be made before the Senate, as a whole, takes action on the bill. However,
we believe that the passage of the Energy Policy and Conservation Act in
December 1975 signifies that further Congressional action is likely, and
that legislation similar to, if not identical with, S.1777 will be passed.
Our judgment is that such legislation is more likely than it is unlikely-
Therefore, two of the key assumptions made in connection with estimation of
the most probable potential for coal-fired FBC are that S.1777 type legislation
will be enacted, and that this will occur somewhat before the reliability of
the coal-fired FBC technology has been fully demonstrated for industrial use.
As discussed later, estimation of the minimum potential may also be related
to S.1777-type legislation via assumptions that practicability criteria and
deadlines for coal substitution will permit a greater usage of petroleum
fuel for a longer time than in the "most likely" case.
-------
- 64 -
One of S.1777's provisions, that was retained in the revised
version, states:
". . . by 1/1/79, any electric powerplant and any major
industrial installation which utilizes natural gas or
petroleum as its primary energy source and has the
capability to utilize coal as its primary energy source
(and is not scheduled for retirement prior to 1/1/85)
shall, to the extent practicable, utilize coal as its
primary energy source, in conformance with applicable
environmental requirements."
This provision may apply to boilers reconverted to coal during the next
few years. Because of the 1/1/79 deadline, such equipment is likely to
meet environmental requirements with either low sulfur coal or scrubbers.
We believe that the stepwise impacts of legislation similar to
S.1777 would be reflected in a stepwise or incremental approach to the
installation of coal-fired boilers at industrial plants. One *of the most
probable first steps involves reconversion to coal-firing as discussed
above. A parallel step might involve the addition of new coal-fired
boilers at existing plants and, in a few cases, as the complete boiler
system of a grass-roots plant. Before 1979, such additions are not likely
to incorporate FBC technology except as demonstration units. Instead, the
major commercial alternatives will be low sulfur coal with an electrostatic
precipitator or high sulfur coal with a scrubber. However, by 1979/80, we
will assume that FBC technology has been commercially demonstrated to be
reliable, and that individual boilers incorporating this technology will
start to be added at existing plants in the early 1980's.
There would be advantages for adding a new coal-fired FBC boiler
to an existing plant which already has several oil-fired boilers. Initially,
the oil-fired boilers could serve as a complete backup system in the event
that teething problems were experienced with operation of the new coal-fired
boiler. Subsequently, the existence of an oil-fired back-up system would
mean that a large inventory of coal would not be needed to protect against
possible disruptions in coal supply.* Avoidance of a large inventory of coal
would be a considerable advantage to plants that do not have adequate space
for the addition of manufacturing units.
If a coal-fired FBC boiler is added at a major plant in one of the
process industries, it is probable that the plant will already have a number
of oil-fired boilers of varying age and size.** Thus, normal expansion and
*Eventually, we see the need for a more comprehensive coal delivery system
than exists at present. The present system may be adequate in areas where
coal is used extensively, but is not adequate in areas such as the Gulf
Coast where oil and natural gas are still the predominant industrial boiler
fuels.
**Most of the largest petroleum refineries and chemical plants are the result
of many years of growth at the same location. The boiler system at these
plants will have grown along with expansion of the manufacturing activities,
-------
- 65 -
retirements might be expected to provide the basis for progressive addition
of coal-fired boilers. Such addition might continue until the entire
installation would be in compliance with S.1777 by 1990 or, possibly, a
little later if practicability should require it. In such plants, once
confidence is gained with the new FBC technology, it might be expected that
the new coal-fired units would be of at least the same steam-generating
capacity as the package oil-fired boilers that, otherwise, would be
installed. Hence, industrial coal-fired FBC units in the range of 100-400
KPPH should be expected. Even larger units might be installed through use of
the modular assembly principle that is being developed for FBC.
The size of the target for industrial use of coal, whether by
legislation or if left to market forces, may be inferred from Tables 3-10
and 3-11. Purchased electricity and coking coal are excluded from the
estimates of industrial fuel consumption in 1974. It will be seen that:
(1) the split between fuel consumption by boilers and by other industrial
combustors was about 54:46.
(2) within the boiler category, those with a capacity of 100 million
BTU/H or more accounted for two fifths of the boiler fuel consumed
or one fifth of total industrial fuel consumption.
(3) oil and gas were responsible for two thirds of the fuel used by
large industrial boilers, however this quantity (2.7 quads in
1974) was only one seventh of total industrial fuel consumption.
Thus, the potential for coal-fired FBC in industrial boilers should
be considered, primarily, as a sub-set of coal use within a population of
large boilers that will be built after 1980. Significant as this potential
may be, it can only be a fraction of the total demand for industrial fuels.
-------
- 66 -
TABLE 3-10
ESTIMATES OF INDUSTRIAL FUEL CONSUMPTION IN 1974
1012 BTU % of % of Total
Coal in 1974 Subtotal Ind. Fuel
Large Boilers (> 100 MBTU/H) 978 63.1 5.2
Smaller Boilers (< 100 MBTU/H) 75 4.8 0.4
Other Large Combustors 462 29.8 2.4
Other Smaller Combustors 35_ 2.3 0-1
1550 100 8.2
Oil
Large Boilers 838 22.6 4.4
Smaller Boilers 1462 39.5 7.7
Other Large Combustors 510 13.8 2.7
Other Smaller Combustors 890 24.1 4.7
3700 100 19.5
Gas
Large Boilers 1830 14.5 9.7
Smaller Boilers 4360 34.6 23.1
Other Large Combustors 1900 15.1 10.1
Other Smaller Combustors 4510 35.8 23.9
12600 100 66.7
Other Fuels
Large Boilers 311 29.6 1.6
Smaller Boilers 400 38.1 2.1
Other Large Combustors 149 14.2 0.8
Other Smaller Combustors 190 18.1 l.Q
1050 100 J~6
All Fuels
Large Boilers 3957 20.9 20.9
Smaller Boilers 6297 33.3 33.3
Other Large Combustors 3021 16.0 16.0
Other Smaller Combustors 5625 29.8 29.8
18900 TOO100
Notes: (1) Above estimates exclude purchased electricity and coking coal.
(2) Estimates for Alaska, Hawaii, Puerto Rico and Virgin Islands
are included.
Source: ERE estimates based on FEA, BOM and other data.
-------
- 67 -
TABLE 3-11
ESTIMATES OF 1974 INDUSTRIAL FUEL CONSUMPTION BY FUEL
TYPE, COMBUSTOR TYPE, AND COMBUSTOR SIZE
Industrial Boilers
Fuel:
Coal
Oil
Gas
Other
of Subtotal
Large
(>100 MBTU/H)
978
838
1830
311
3957
38.6
Smaller
(<100 MBTU/H)
75
1462
4360
400
6297
61.4
All Indust.
Boilers
1053
2300
6190
711
10254
100
Other Industrial Combustors
Fuel:
Coal
Oil
Gas
Other
% of Subtotal
3021
34.9
Smaller
35
890
4510
190
_
65.1
All
497
1400
6410
339
8646
100
Industrial Boilers and
Other Combustors
Fuel:
Coal
Oil
Gas
Other
% of Total
36.9
Smaller
110
2352
8870
590
11922
63.1
All
1550
3700
12600
1050
18900
100
Notes: (1) Above estimates exclude purchased electricity and coking coal.
(2) Industrial fuel consumption in Alaska, Hawaii, Puerto Rico,
and Virgin Islands is included.
Source: ERE estimates based on FEA, BOM, and other data.
-------
- 68 -
4. FUTURE DEMAND FOR INDUSTRIAL BOILER FUEL
The future size and structure of the U.S. economy will be a
principal determinant of industrial energy demand. As discussed in
Section 3, it is necessary to distinguish between boiler fuel demand and
fuel used for other purposes (e.g. in process furnaces, cement kilns, etc.).
Projection of the future demand for industrial boiler fuel is a prerequisite
to estimation of the fraction of this demand that may utilize coal-fired
FBC. The first step in the series of necessary projections is to obtain
estimates of future manufacturing activity.
4.1 Basis of Demand Projections
A joint study by the Office of Business Economics (QBE) of the
Department of Commerce and the Economic Research Service (ERS) of the Department
of Agriculture was made for the Water Resources Council (WRC)* and was published
in seven volumes in April 1974 (1). The OBERS projections, which extend to the
year 2020, involve the concept of Gross Product Originating.** Knowledge of
the GPO for each industry in a particular year, and also the fuel consumption
for each industry in the same year, makes it possible to calculate the average
fuel consumption per unit of product output on an industry by industry basis.
*The United States Water Resources Council, an independent Executive Agency
of the U.S. Government, is composed of the Secretaries of Interior; Agriculture;
Army; Health, Education, and Welfare; Transportation; Chairman, Federal Power
Commission; with participation by the Secretaries of Commerce; Housing and
Urban Development; Administrator, Environmental Protection Agency; Attorney
General; Director, Office of Management and Budget; Chairman, Council on
Environmental Quality; and the Chairmen, River Basin Commissions. Council
activities encourage the conservation, development and utilization of water
and related land resources on a comprehensive and coordinated basis by Federal,
State, local government and private enterprise.
**GPO is defined as follows:
"Constant dollar GPO is a measure of the volume of real output
in each industry. Because of industry variations in the quantity
and the price of imports used, each industry has its unique
implicit deflator for GPO. In contrast, earnings of persons
represent factor returns to labor, and the translation of
earnings into constant dollars is conceptually different from
the expression of GPO in real terms. The price change that is
removed from the current dollar earnings series in :the deflation
process is the change that has occurred in the purchasing power
of the dollar rather than the price change per unit of physical
output. The purchasing power of the dollar earned in each
industry is assumed to have changed by the same amount. Consequently,
the relationship between constant and current dollar earnings is the
same in each industry."
-------
- 69 -
4.2 Quantitative Projections
The starting point for the industrial boiler fuel projections was
the estimated fuel consumption in 1974. The breakdown by SIC Code (i.e. by
industry) is given in Table 4-1. These estimates apply to the population of
large industrial boilers (>100 M BTU/H) and are derived from a pooling of data
collected in FEA's MFBI and NGTF surveys.
Next, using the OBERS projections, ratios of future industrial fuel
consumption by each industry (SIC Code) were calculated relative to the fuel
consumption of the industry in 1974 (i.e. 1974 = 1.000 for each industry).
The results are shown in Tables 4-2 and 4-3. The latter takes account of
energy conservation per unit of manufacturing output anticipated in the future.
Multiplication of the fuel consumption in the 1974 base year (Table 4-1) by the
conservation corrected ratios for future years (Table 4-3) yields the estimates
recorded in Table 4-4. These estimates, however, do not make provision for the
probability that, progressively, the larger boilers will account for an
increasing fraction of total industrial boiler fuel demand. The reported
statistics indicate that the large boilers were responsible for 38.6% of
total industrial boiler fuel consumption in 1974. By the year 2000, it is
assumed that the percentage will be 50%. This assumption is equivalent to
the following increments to the projected fuel demand of the large industrial
boiler population:
% Increase over
Year Table 4-4 Estimate
1980 7.0
1985 12.7
1990 18.4
1995 23.8
2000 29.5
The result of incroporating these percentage increases is shown in
Table 4-5. As noted, these projections include consumption of by-product
fuels, i.e. fuels other than coal, oil, and natural gas. With insignificant
exceptions, by-product fuels are consumed within the plant where they are
produced and, therefore, do not represent any potential for substitution by
coal.
Using FEA survey data for by-product* ("other") fuel consumption by
large boilers in 1974, and assuming that the ratio of by-product to commercial
fuel will not change in the future, it is possible to convert the projections
in Table 4-5 to estimates of coal, oil, and natural gas that will be consumed.
The consequence of "backing out" the by-product fuels is shown in Table 4-6.
The same estimates are presented in a different format in Table 4-7 for the
*FEA data for the Paper industry (SIC 26) are appreciably at variance with
by-product fuel statistics supplied by the American Paper Institute (see
Appendix 4, Table 38). The basis of the difference appears to be that
statistics for the industry's "recovery boilers" (which recover sodium
values from black liquor) are substantially excluded from the FEA surveys.
While this is important to an overall understanding of industrial_energy
consumption, it does not affect the projections discussed above since they
are made on an internally consistent basis.
-------
- 70 -
TABLE 4-1
1974 FUEL CONSUMPTION OF LARGE INDUSTRIAL BOILERS BY SIC CODE
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Industry
Chemicals and Allied Products
Paper and Allied Products
Petroleum Refining and Related Ind.
Primary Metals Industries
Food and Kindred Products
Fabricated Metal Products
Machinery, except Electrical
Utility Services*
Stone, Clay, Glass and Concrete Products
Transportation Equipment
Textile Mill Products
Lumber and Wood Products
Electrical Equipment
Rubber and Plastics Products
Ordnance/Miscellaneous Manufacturing
Printing and Publishing
Instruments and Related Products
Furniture and Fixtures
Apparel and Other Textiles
Leather and Leather Products
Tobacco Manufactures
% of 1974
Total
26.2
16.7
16.5
12.4
5.4
1.7
1.4
1.3
0.6
3.5
3.3
2.3
2.3
2.1
1.0
0.9
0.7
0.6
0.6
0.3
0.2
100
1012 BTU's
in 1974
1025
653
645
485
211
67
55
51
23
137
130
91
90
82
39
35
27
23
23
12
8
3912
*except electricity generation.
Notes: (1) Above estimates are based on a pooling of data from MFBI and
NGTF surveys.
(2) Data for Alaska, Hawaii, Puerto Rico, and Virgin Islands are
excluded.
(3) Numbers in lower half of Table are estimated by disaggregation
of purchased fuel statistics for each SIC Code.
-------
~ 71 -
TABLE 4-2
INDUSTRIAL FUEL CONSUMPTION RATIOS, RELATIVE TO
BASED ON OBERS PROJECTIONS
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Industry
Chemicals
Paper
Petroleum Refining
Primary Metals
Food
Fabricated Metals
Machinery, except Electrical
Utility Services
Stone, Clay, Glass, Concrete
Transportation Equipment
Textile Mill Products
Lumber and Wood
Electrical Equipment
Rubber and Plastics
Ordnance/Miscellaneous
Printing and Publishing
Instruments
Furniture and Fixtures
Apparel
Leather and Leather Products
Tobacco Manufactures
1974=1.000,
Fuel Consumption Ratios
1980
1.286
1.266
1.164
1.127
1.114
1.324
1.252
1.290
1.290
1.249
1.152
1.224
1.363
1.286
1.324
1.244
1.290
1.224
1.221
1.290
1.290
1985
1.575
1.463
1.343
1.180
1.220
1.534
1.422
1.523
1.523
1.450
1.303
1.396
1.686
1.575
1.534
1.461
1.523
1.396
1.395
1.523
1.523
1990
1.923
1.690
1.540
1.225
1.337
1.774
1.618
1.797
1.797
1.681
1.463
1.592
2.088
1.923
1.774
1.703
1.797
1.592
1.591
1.797
1.797
2000
2.815
2.259
2.018
1.331
1.621
2.375
2.100
2.490
2.490
2.269
1.857
2.078
3.120
2.815
2.375
1.810
2.490
2.078
2.082
2.490
2.490
Note: Above projections do not take account of anticipated energy conservation
per unit of manufacturing output.
-------
- 72
TABLE 4-3
PROJECTED INDUSTRIAL FUEL CONSUMPTION RATIOS, RELATIVE TO 1974=1.000,
MAKING ALLOWANCE FOR ENERGY CONSERVATION
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Conservation Corrected Ratios
Industry
Chemicals
Paper
Petroleum Refining
Primary Metals
Food
Fabricated Metals
Machinery, except Electrical
Utility Services
Stone, Clay, Glass, Concrete
Transportation Equipment
Textile Mill Products
Lumber and Wood
Electrical Equipment
Rubber and Plastics
Ordnance/Miscellaneous
Printing and Publishing
Instruments
Furniture and Fixtures
Apparel
Leather and Leather Products
Tobacco Manufactures
1980
1.162
1.198
1.080
1.054
1.035
1.246
1.178
1.166
1.166
1.175
1.084
1.151
1.282
1.162
1.246
1.170
1.166
1.151
1.149
1.166
1.166
1985
1.340
1.357
1.202
1.072
1.094
1.407
1.305
1.397
1.397
1.330
1.195
1.281
1.547
1.340
1.407
1.340
1.397
1.281
1.280
1.397
1.397
1990
1.542
1.523
1.322
1.079
1.159
1.588
1.449
1.609
1.609
1.505
1.310
1.425
1.869
1.542
1.588
1.525
1.609
1.425
1.424
1.609
1.609
2000
2.004
1.973
1.588
1.105
1.310
2.021
1.787
2.119
2.119
1.931
1.580
1.769
2.655
2.004
2.021
1.540
2.119
1.769
1.772
2.119
2.119
-------
- 73 -
TABLE 4-4
PROJECTED FUEL CONSUMPTION OF LARGE INDUSTRIAL BOILERS
UNCORRECTED FOR CHANGES IN SIZE DISTRIBUTION
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Boiler Fuel Consumption, 1C
Industry
Chemicals
Paper
Petroleum Refining
Primary Metals
Food
Fabricated Metals
Machinery, except Electrical
Utility Services
Stone, Clay, Glass, Concrete
Transportation Equipment
Textile Mill Products
Lumber and Wood
Electrical Equipment
Rubber and Plastics
Ordnance/Miscellaneous
Printing and Publishing
Instruments
Furniture and Fixtures
Apparel
Leather and Leather Products
Tobacco Manufactures
1980
1191
782
697
511
218
83
65
59
27
161
141
105
115
95
49
41
31
26
26
14
9
1985
1374
886
775
520
231
94
72
71
32
182
155
116
139
110
55
47
38
29
29
17
11
1990
1581
995
853
523
245
106
80
82
37
206
170
130
168
126
62
53
43
33
33
19
13
) BTU's
2000
2054
1288
1024
536
276
135
98
108
49
265
205
161
239
164
78
57
57
40
41
25
17
4446
4983
5558
6914
-------
TABLE 4-5
PROJECTED FUEL CONSUMPTION OF LARGE INDUSTRIAL BOILERS
ASSUMING THAT THERE WILL BE A PROGRESSIVE INCREASE IN THE
FRACTION OF TOTAL INDUSTRIAL BOILER FUEL CONSUMED BY
LARGE BOILERS (>100 M BTU/H)
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Boiler Fuel Consumption, 1012 BTU's
Industry
Chemicals
Paper
Petroleum Refining
Primary Metals
Food
Fabricated Metals
Machinery, except Electrical
Utility Services
Stone, Clay, Glass, Concrete
Transportation Equipment
Textile Mill Products
Lumber and Wood
Electrical Equipment
Rubber and Plastics
Ordnance/Miscellaneous
Printing and Publishing
Instruments
Furniture and Fixtures
Apparel
Leather and Leather Products
Tobacco Manufactures
1980
1274
837
746
547
233
89
69
63
29
172
151
112
123
102
52
44
33
28
28
15
9
4756
1985
1548
999
873
586
260
106
81
80
36
205
175
130
157
124
62
53
43
33
33
19
12
5615
1990
1872
1178
1010
619
290
125
95
97
44
244
201
154
199
149
73
63
51
39
37
22
15
6579
2000
2660
1668
1326
694
357
175
127
140
63
343
265
208
309
212
101
70
74
51
53
32
22
8950
Note:
Above projections include consumption of by-product (i.e. "Other") fuels.
-------
- 75 -
TABLE 4-6
PROJECTIONS OF COAL, OIL, AND NATURAL GAS CONSUMPTION
OF LARGE INDUSTRIAL BOILERS
SIC
Code
28
26
29
33
20
34
35
49
32
37
22
24
36
30
19/39
27
38
25
23
31
21
Industry
Chemicals
Paper
Petroleum Refining
Primary Metals
Food
Fabricated Metals
Machinery, except Electrical
Utility Services
Stone, Clay, Glass, Concrete
Transportation Equipment
Textile Mill Products
Lumber and Wood
Electrical Equipment
Rubber and Plastics
Ordnance/Miscellaneous
Printing and Publishing
Instruments
Furniture and Fixtures
Apparel
Leather and Leather Products
Tobacco Manufactures
Fuel
1980
1236
720
716
421
227
85
68
62
28
169
149
96
120
99
51
42
33
27
27
15
9
4400
Consumption
1985
1501
859
838
451
257
102
79
78
35
201
173
112
167
120
61
51
42
32
32
19
12
5222
, 1012
1990
1816
1013
970
477
287
120
95
95
43
239
199
132
195
145
71
60
50
37
38
22
14
6118
BTU
2000
2580
1434
1273
534
353
168
124
137
62
336
262
179
303
206
99
67
73
49
51
31
21
8342
-------
TABLE 4-7
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL BOILERS
BY SIC CODE AND INDUSTRY TYPE
SIC
Type of
Code Industry
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Process
Process
Process
Process
Process
Process
Process
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Miscellaneous
Miscellaneous
Miscellaneous
Miscellaneous
Miscellaneous
Miscellaneous
Miscellaneous
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber and Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Subtotal
Transportation Equipment
Electrical Equipment
Textile Mill Products
Apparel
Fabricated Metals
Machinery, except Electrical
Instruments
Subtotal
Utility Services
Ordnance/Miscellaneous
Lumber and Wood
Furniture
Printing and Publishing
Leather
Tobacco Manufactures
Subtotal
1980
1236
99
716
720
421
227
28
3447
169
120
149
27
85
68
33
651
62
51
96
27
42
15
9
302
1985
1501
120
838
859
451
257
35
4061
201
167
173
32
102
79
42
796
78
61
112
32
51
19
12
365
1990
1816
145
970
1013
477
287
43
4751
239
195
199
38
120
95
50
936
95
71
132
37
60
22
14
431
1012 BTU'
1995
2165
173
1111
1205
505
318
52
5529
283
243
228
44
142
109
60
1109
114
84
154
43
63
26
17
501
s
2000
2580
206
1273
1434
534
353
62
6442
336
303
262
51
168
124
73
1317
137
99
179
49
67
31
21
583
% of
2000
Total
30
2
15
17
6
4
0
77
4
3
3
0
2
1
0
15
1
1
2
0
0
0
0
7
.9
.4
.3
.2
.4
.2
.7
.2
.0
.6
.1
.6
.0
.5
.9
.8
.6
.2
.2
.6
.8
.4
.2
.0
-------
- 77 -
purpose of illustrating that the consumption of boiler fuel by large industrial
boilers is concentrated in the process industries, as distinguished from general
manufacturing (of equipment, etc.) and a variety of other industrial activities
that are labeled "Miscellaneous" in Table 4-7.
The estimates in Table 4-7 are shown in Table 4-8 as increments over
boiler fuel consumption in 1974. The final column of this Table expresses
the increments for each industry as percentages of the total 1974/2000 increment
estimated for the large industrial boilers. These figures indicate the projected
degree of concentration of incremental demand for coal, oil and natural gas
in the leading process industries:
% of Total 1974/2000
Industry Increment
Chemicals and Allied Products 33.6
Rubber and Plastics Products 2.7
Subtotal 36.3
Petroleum Refining and Related Ind. 13.9
Paper and Allied Products 18.5
Total 68.7
The projected increment for Primary Metals (SIC 33) is only 3.4%,
which appears low. However, it is derived on the same basis as the other
projections, and can be rationalized in terms of factors such as:
- relatively slow growth in primary metals production
- some shifts in product mix, e.g. a higher ratio of
aluminum to steel
- anticipated savings in energy consumption per unit
of output
- greater use of (purchased) electricity in the production
of primary metals.
Our judgment is that the additional boiler fuel potential in Primary Metals is
significant on an absolute basis but is far less than in the industries cited
above. On the other hand, we believe that there may be a major potential for
non-boiler applications* of FBC within the Primary Metals industries.
The increments estimated in Table 4-8 understate the potential for
new boiler capacity associated with future levels of boiler fuel demand. This
is because many of the large boilers that are now in operation will be retired
by the year 2000. If oil and natural gas were to remain available a retirement
rate of about 3% per year could be expected. However, a significant switching
*e.g. soaking pits, melting, reheating, etc. All such applications are outside
the scope of the present study.
-------
TABLE 4-8
PROJECTED INCREMENTS IN CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY
LARGE INDUSTRIAL BOILERS BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
Type of
Industry
Process
Process
Process
Process
Process
Process
Process
37
36
22
23
34
35
38
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
Gen. Mfg.
49 Miscellaneous
19/39 Miscellaneous
24 Miscellaneous
25 Miscellaneous
27 Miscellaneous
31 Miscellaneous
21 Miscellaneous
Increment in
Coal, Oil, and Nat
Industry
Chemicals
Rubber and Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Subtotal
Transportation Equipment
Electrical Equipment
Textile Mill Products
Apparel
Fabricated Metals
Machinery, except Electrical
Instruments
Subtotal
Utility Services
Ordnance/Miscellaneous
Lumber and Wood
Furniture
Printing and Publishing
Leather
Tobacco Manufactures
Subtotal
TOTAL
Increment over 1980 Total
1980
242
19
97
158
48
18
5
587
35
32
20
5
21
14
6
133
12
13
18
5
8
3
1
60
780
-
1985
507
40
219
297
78
48
12
1201
67
79
44
10
38
25
15
278
28
23
34
10
17
7
4
123
1602
822
. Gas Over
1990
822
65
351
451
104
78
20
1891
105
107
70
16
56
41
23
418
45
33
54
15
26
10
6
189
2498
1718
1974, 1012 BTU's
1995
1171
93
492
643
132
109
29
2669
149
155
99
22
78
55
33
591
64
46
76
21
29
14
9
259
3519
2739
2000
1586
126
654
872
161
144
39
3582
202
215
133
29
104
70
46
799
87
61
101
27
33
19
13
341
4722
3942
% of 2000
Total
33.6
2.7
13.9
18.5
3.4
3.0
0.8
75.9
4.3
4.6
2.8
0.6
2.2
1.5
1.0
16.9
1.8
1.3
2.1
0.6
0.7
0.4
Q.3
7.2
100
--j
c»
-------
- 79 -
to coal by the large boilers is expected to accelerate the rate at which
existing oil/gas-fired capacity is retired, particularly in the period after
1980 when some form of coal-use legislation may be in effect. This expectation
was examined at (accelerated) retirement rates of 4% per year and 5% per year,
using 1980 as a base year. By definition, 100% of the large boiler capacity
operating in 1980 will be in place in that year. In subsequent years, the
boilers operating in 1980 will represent a declining percentage of the total
capacity of large boilers:
Boilers Operating in 1980 as % of Total
Assumed Boiler Capacity in Subsequent Years
Retirement Rate 1988 1990 1995 2QQO
4% per year 67 43 25 11
5% per year 63 36 15
The 5% per year retirement schedule would be reasonably consistent
with the present provisions of proposed coal-use legislation (i.e. S.1777 in
its revised form), making the assumption that the "practicability" criteria
of the legislation will permit some large oil/gas-fired boilers to remain in
operation beyond 1995. In addition, a relatively small number of existing
(large) coal-fired boilers could also be in operation beyond 1995. For
practical purposes, the 5% per year retirement schedule would permit almost
all large industrial boilers still operating on oil or gas in 1980 to be
retired by the year 2000. This possibility provides a scenario in which the
market penetration rate of coal-fired FBC may be considered.
-------
- 80 -
5. PROJECTIONS OF COAL-FIRED FBC POTENTIAL
5.1 Basis of Projections
Projections of the potential for coal-fired FBC industrial boilers
are made from a base year of 1974, after dividing the industrial boiler
population into:
• industrial boilers with a design firing-rate of more than 99 million
BTU/H, i.e. MFBl's or "large boilers".
• smaller industrial boilers, i.e. those with a design firing rate of
less than 99 million BTU/H.
The 1974 fuel consumption of the large boilers has been discussed
in Section 4. For subsequent years, the principal options open to these
boilers may be classified in relation to the fuel that they used in 1974
and taking account of the boilers that were originally designed for coal.
Fuel Used in 1974
Principal Future Options
(a) "Other"
(b) Natural Gas
(c) Oil
(d) Gas or oil-fired, but
converted from coal
(e) Coal
Continue use of by-product fuels
(1) Near term: continue use of gas if
available, or substitute oil-firing
(2) Longer term: consider replacement
of gas-fired boiler with a new coal-
fired boiler
(1) Near term: continue use of oil
(2) Longer term: consider replacement of
oil-fired boiler with a new coal-fired
boiler
Consider re-conversion to coal-firing. Also
consider "compliance coal"* versus flue gas
desulfurization (FGDS), i.e. the retrofitting
of a flue gas scrubber system.
(1) Near term: consider compliance coal
versus FGDS
(2) Longer term: consider compliance coal
versus other control technologies, and
also the combination of compliance coal
and FBC.
*i.e. coal that has a sufficiently low sulfur content to meet Federal emission
standards for new point sources without additional control technology for sulfur
oxides.
-------
- 81 -
By 1980, the situation for the large boilers is expected to chanse
as follows: 5
(1) Fuel demand relative to 1974 will change:
- in proportion to projected increases in industrial output, but
corrected for energy conservation per unit of output.
- in relation to projected changes in the fractions of total output
supported by large and smaller boilers.
(2) The steam generating capacity of coal-fired boilers will be equal to
that in 1974 minus retirements, and plus:
- additions of capacity at plants using coal in 1974.
- reconversions from oil/gas to coal.
- additions of coal-fired capacity at plants using oil/gas in 1974.
- capacity of coal-fired boilers at grass-roots plants that did not
exist in 1974.
All of the large industrial boilers that fired oil and/or gas in 1974
are considered to be part of the coal potential, except in areas where coal
logistics are unfavorable. Where coal is used, the compliance choices by
1980 will be:
- compliance coal (used in conjunction with an electrostatic precipitator)
- FGDS
- nominal use of FBC, e.g. in demonstration units.
Clearly, the coal-fired FBC potential is a sub-set of coal utilization
by all large industrial boilers. The level of coal utilization by industrial
MFBI's is assumed to be driven by S.1777-type legislation.* Different assumptions
are used to derive maximum, most probable, and minimum estimates of coal-fired FBC
potential. The principal assumptions relate to:
(1) the split between (a) compliance coal, and (b) non-compliance coal used
with control technology.
(2) the rate of market penetration of FBC technology after being demonstrated
to be commercially reliable.
(3) local deviations from Federal emission standards, particularly the
standards for new point sources.
*S.1777 refers to the proposed "National Petroleum and Natural Gas Conservation
and Coal Substitution Act", see Reference (5), Section 3.
-------
- 82 -
The consumption of fuel by industrial boilers in the year 2000 is
conceptualized in the following diagrams (not to scale):
TOTAL FUEL CONSUMPTION OF INDUSTRIAL BOILERS
Smaller Boilers
Large Boilers
FUEL CONSUMPTION OF LARGE INDUSTRIAL BOILERS
"Other"
Fuels
Oil
or
Gas
Coal
Non-FBC
Technology
FBC
Technology
The AB segment in the lower diagram represents the consumption of
by-product fuels such as bagasse and bark. Utilization of such fuels will
continue, and they will not be displaced by coal-fired FBC even though their
combustion in fluidized beds is a possibility.
The BC segment represents the anticipation that coal use will be
impractical in some large industrial boilers for logistical or other reasons.
The CD segment represents coal use by any technology other than FBC. In the
main, the non-FBC "technology" is expected to be compliance coal although, not
necessarily, untreated low sulfur coal. While outside the scope of the present
study, it seems likely that coal cleaning technology will develop significantly
during the next two decades so as to augment the availability of compliance coal.
For the purposes of the present study, it does not make any difference whether
synthetic fuels* are considered to be within the BC or CD elements. The critical
boundary is fixed by the position of D. In this study, D has three locations
within the segment CE which correspond to the estimates of maximum, most probable,
and minimum potentials for coal-fired FBC. If the three locations of D are
denoted D max., D prob. and D min., then:
• the segment D max. E represents the maximum potential
• the (alternative) segment D prob. E represents the most probable
potential
• the (alternative) segment D min. E represents the minimum potential
for coal-fired FBC.
*that may be derived from coal and/or oil shale, and may be liquids or gases.
-------
5.2 Modification of Basis
Some important new information was provided by ERDA early in September
1976. This subsection summarizes the nature and original source of the informa-
tion, and also its implications.
The contract became effective on 6/27/75, and most of the basic cost
estimates were made in September 1975. These estimates related to the "state
of the art" of atmospheric FBC technology as we appraised it in August/Sept ember
1975. During the past year (i.e. September 1975/1976), industrial FBC boiler
technology has been developing. One way in which this has become apparent
is through the proposals received by ERDA from a number of contractors in
response to ERDA's Program Opportunity Notice program for FBC developments.
These proposals have contained cost estimates for industrial FBC boilers which
are confidential and, hence, not available to us. We were informed that the
estimates were numerically lower than those we had made in September 1975, but
we could not utilize the information because we did not know either the details
of the estimates or the bases upon which they were made. However, in September
1976, ERDA was able to provide us with sufficient detail and quantification to
make possible the recalculation of various coal-fired boiler comparisons. The
immediate results of these recalculations were that:
(1) for high sulfur coal, a boiler system using FBC technology was indicated
to be lower in cost than a system incorporating flue gas desulfurization
(i.e. scrubbers).
(2) for low sulfur (compliance) coal, a boiler system using FBC technology was
indicated to be a standoff in cost with a conventional spreader-stoker
system (not incorporating flue gas desulfurization because of the sulfur
compliance quality of the coal).
The first of these results did not affect previously made estimates
of FBC potential because we had already judged FBC to be a more attractive
technology than scrubbing, even though the previous cost estimates were a
stand-off. This judgment was based on a number of potential advantages of
FBC that were not "captured" in the cost estimates.
The second result, however, introduces significantly new and different
considerations. Because of the potential advantages of FBC, a cost standoff
with a conventional spreader-stoker suggests that FBC could be the preferred
technology for burning compliance coals (as well as high sulfur coals). Thus,
a possible implication is that FBC may be the preferred industrial boiler
technology for all coals. Essentially, this implication, in the form of an
assumption, was used to generate estimates of the maximum potential for coal-
fired, industrial FBC boilers. However, estimates of the most probable potential
were less optimistic with respect to domination of the large industrial boiler
market by FBC technology where compliance coal is the fuel of choice. Therefore,
consequent upon the cost estimates provided by ERDA in September 1976, it has
been necessary to make a significant upward revision of the estimates_ot most
probable potential. In making this change, we have retained the previously
made assumption of a somewhat slower rate of market penetration in the most
-------
- 84 -
probable case that for the maximum case. Also, as detailed later, we did not
assume that all compliance coal used in industrial boilers would eventually
be burned using FBC technology.
5.3 Regional Applicability
The regional applicability of coal-fired FBC is estimated in Table 5-1.
For the estimate of maximum potential, the New England region is excluded on the
basis of logistics and because electric utilities in this area are projecting a
percentage decrease in their future use of coal (1). Exclusion of New England
reduces the potential for coal-fired FBC in the Lower 48 states by 2.76%.
Additionally, it is assumed that half of the potential in four other regions
(Northern Plains, Rocky Mountain, Pacific Northwest, and Pacific Southwest)
will not be secured by coal-fired FBC because these regions will either have
access to compliance coal* produced in the West or, in the case of certain
areas (e.g. Los Angeles county) will avoid the use of coal for environmental
reasons. The combined effect of the assumptions used to exclude part or all
of the potential in the above five regions is to reduce the overall potential
for coal-fired FBC by 8.4%.
For the most probable case, additional regional exclusions are assumed
as indicated in the center portion of Table 5-1. The single most significant
increment over the exclusions assumed for the maximum case concerns the potential
of the Gulf Coast region. The assumption is based on:
(1) anticipated availability of local lignites many of which will not be
"compliance coals".
(2) anticipated need to begin a shift to coal-firing before FBC technology
is fully demonstrated.
In total, the regional assumptions in the most probable case reduce
the overall potential by about 26%.
Similar but more severe regional limitations are assumed in order to
estimate the minimum potential for coal-fired FBC. Details are shown in the
bottom section of Table 5-1, and it is estimated that regional constraints would
reduce the national potential by 52% in the minimum case.
*see Table 3-5 for identification of FEA regions.
**taking the discussion in Section 5.2 into consideration.
-------
- 85 -
TABLE 5-1
ESTIMATES OF REGIONAL APPLICABILITY OF COAL-FIRED FBC
• Maximum Potential
Regions Partially or Wholly
Excluded from Potential
New England
Northern Plains
Rocky Mountain
Pacific Northwest
Pacific Southwest
Fraction Exclusion as % of Total
Excluded Potential in Lower 48 States*
1.0 2.76
0.5 1.00
0.5 1.46
0.5 1.76
0.5 1.45
8.43
• Most Probable Potential
New England
D.C., Md., N.J., N.Y.
Northern Plains
Rocky Mountain
Pacific Northwest
Pacific Southwest
Gulf Coast
0.25
,76
,09
,40
,04
.45
.03
.01
• Minimum Potential
New England
D.C., Md., N.J., N.Y.
Pennsylvania
Northern Plains
Oklahoma
Rocky Mountain
Pacific Northwest
Pacific Southwest
Gulf Coast
0.25
1.0
2.76
8.09
1.27
2.00
0.72
92
51
89
28.04
52.20
* Based on 1974 fuel consumption and capacity percentages reported in Table 3-9.
See Table 3-5 for identification of FEA regions.
-------
Coal-Fired
Maximum
0.02
0.62
1.97
3.20
5.52
FBC Potential,
Most Likely
0.01
0.29
0.99
1.69
2.97
10 BTU
Minimum
nil
0.075
0.29
0.54
1.00
- 86 -
5.4 Maximum, Most Probable, and Minimum Potentials
The above regional factors are combined with factors estimated for
market penetration and functional applicability in order to derive the combined
factors shown in Table 5-2. Multiplication of the total fossil fuel demand
estimated for large industrial boilers by the pertinent combined factor yields
the estimate of the coal-fired FBC potential (in 1015 BTU's per year) for a
given year and for each of the cases. The results are summarized below:
Year
1980
1985
1990
1995
2000
5.5 Additional Applications of Coal-Fired FBC
The above estimates do not include possible increments to the overall
potential for coal-fired FBC at industrial MFBl's due to:
(1) a reversal of the long term decline trend in the captive generation
of electricity.
(2) applications of coal-fired FBC to new industries.
Currently, the captive generation of electricity at manufacturing
plants is equivalent to slightly less than 9% of the energy purchased by the
plants. The corresponding figure for 1950 was 18%. The reasons for the steady
decline in captive generation of electricity are that, in general, it has been
cheaper for manufacturing plants to purchase electricity from electric utilities
and also that manufacturing industry has preferred to invest its capital in
production facilities rather than in supporting services. While the latter
condition still applies, the constant dollar cost of electricity has reversed
its long-term downtrend. Moreover, rate structures are being revised in ways
that are less favorable to the purchase of large blocs of power by industrial
customers. Finally, captive generation of electricity is energy-efficient at
plants which have a large requirement for process steam and, hence, are able
to generate "by-product" electricity through the simple expedient of generating
steam at a higher pressure than required for process applications. Letting down
the steam pressure through a turbo-generator enables "by-product" electricity to
be generated with only a small increment in fuel consumption over what would be
required if no electricity were generated. By the same token, the incremental
coal-fired FBC potential is relatively small when estimated in terms of fuel
consumption. As a sensitivity, it is assumed that a reversal to the downtrend
in captive generation of electricity will occur in 1977 and, thereafter, there
will be a cumulative increase of 1% per year in the percentage of electricity
generated captively relatively to the energy purchased by manufacturing plants.
The assumption of 1% per year applies to the maximum case. The corresponding
-------
- 85 -
TABLE 5-1
ESTIMATES OF REGIONAL APPLICABILITY OF COAL-FIRED FBC
* Maximum Potential
Regions Partially or Wholly
Excluded from Potential
New England
Northern Plains
Rocky Mountain
Pacific Northwest
Pacific Southwest
Fraction Exclusion as % of Total
Excluded Potential in Lower 48 States*
1.0 2.76
0.5 1.00
0.5 1.46
0.5 1.76
0.5 1.45
8.43
• Most Probable Potential
New England
B.C., Md., N.J., N.Y.
Northern Plains
Rocky Mountain
Pacific Northwest
Pacific Southwest
Gulf Coast
0.25
76
09
40
04
45
03
01
• Minimum Potential
New England
D.C., Md., N.J., N.Y.
Pennsylvania
Northern Plains
Oklahoma
Rocky Mountain
Pacific Northwest
Pacific Southwest
Gulf Coast
.0
.0
0.25
1.0
* Based on 1974 fuel consumption and capacity percentages reported in Table 3-9.
See Table 3-5 for identification of FEA regions.
-------
Maximum
0.02
0.62
1.97
3.20
5.52
Most Likely
0.01
0.29
0.99
1.69
2.97
Minimum
nil
0.075
0.29
0.54
1.00
- 86 -
5.4 Maximum, Most Probable, and Minimum Potentials
The above regional factors are combined with factors estimated for
market penetration and functional applicability in order to derive the combined
factors shown in Table 5-2. Multiplication of the total fossil fuel demand
estimated for large industrial boilers by the pertinent combined factor yields
the estimate of the coal-fired FBC potential (in 1015 BTU's per year) for a
given year and for each of the cases. The results are summarized below:
Coal-Fired FBC Potential. 1Q15 BTU
Year
1980
1985
1990
1995
2000
5.5 Additional Applications of Coal-Fired FBC
The above estimates do not include possible increments to the overall
potential for coal-fired FBC at industrial MFBI's due to:
(1) a reversal of the long term decline trend in the captive generation
of electricity.
(2) applications of coal-fired FBC to new industries.
Currently, the captive generation of electricity at manufacturing
plants is equivalent to slightly less than 9% of the energy purchased by the
plants. The corresponding figure for 1950 was 18%. The reasons for the steady
decline in captive generation of electricity are that, in general, it has been
cheaper for manufacturing plants to purchase electricity from electric utilities
and also that manufacturing industry has preferred to invest its capital in
production facilities rather than in supporting services. While the latter
condition still applies, the constant dollar cost of electricity has reversed
its long-term downtrend. Moreover, rate structures are being revised in ways
that are less favorable to the purchase of large blocs of power by industrial
customers. Finally, captive generation of electricity is energy-efficient at
plants which have a large requirement for process steam and, hence, are able
to generate "by-product" electricity through the simple expedient of generating
steam at a higher pressure than required for process applications. Letting down
the steam pressure through a turbo-generator enables "by-product" electricity to
be generated with only a small increment in fuel consumption over what would be
required if no electricity were generated. By the same token, the incremental
coal-fired FBC potential is relatively small when estimated in terms of fuel
consumption. As a sensitivity, it is assumed that a reversal to the downtrend
in captive generation of electricity will occur in 1977 and, thereafter, there
will be a cumulative increase of 1% per year in the percentage of electricity
generated captively relatively to the energy purchased by manufacturing plants.
The assumption of 1% per year applies to the maximum case. The corresponding
-------
TABLE 5-2
ESTIMATES OF NATIONAL POTENTIAL FOR COAL-FIRED FBC
• Maximum Potential
Year
1980
1985
1990
1995
2000
• Most
1980
1985
1990
1995
2000
Total Fossil Fuel for
Large Boilers, 1015 BTU*
4.40
5.22
6.12
7.14
8.34
Probable Potential
4.40
5.22
6.12
7.14
8.34
• Minimum Potential
1980
1985
1990
1995
2000
4.40
5.22
6.12
7.14
8.34
Regional Applicability Penetration
Factor** Factor Factor
0.92
0.92
0.92
0.92
0.92
0.48
0.48
0.48
0.48
0.48
0.50
0.65
0.70
0.75
0.80
0. 74
0. 74
0. 74
0. 74
0. 74
0.30
0.50
0.55
0.58
0.60
nil
0.3
0.4
0.45
0.5
0.01
0.2
0.5
0.65
0.9
0.01
0.15
0.4
0.55
0.8
nil
0.1
0.25
0...35
0.5
Combined
Factor
0.0046
0.1196
0.322
0.449
0.662
0.0022
0.0556
0.162
0-236
0.356
nil
0.0144
0.048
0.076
0.120
Coal-Fired
FBC Potential
1015 BTU i i
0.02
0.62
1.97
3.20
5.52
0.01
0.29
0.99
1.69
2.97
nil
0.075
0.294
0.543
1.00
>
% of Max.
Potential
-
47
50
53
54
nil
12
15
17
18
CO
•-J
*From Table 4-6
**From Table 5-1
Regional Factor x Applicability Factor x Penetration Factor
Total Fossil Fuel for Large Boilers x Combined Factor
-------
- 88 -
assumptions for the most likely and minimum cases are 0.5% per year and 0.2%
per year respectively. Estimates based on these assumptions are shown in
Table 5-3. Also included are estimates derived from the assumption that coal-
fired FBC technology may be applicable to:
(1) the generation of process steam at synthetic fuels plants.
(2) the utilization of by-product coal fractions, e.g. fines, from coal
beneficiation plants.
It is further assumed that, only nominal applications will be in
operation in 1985, but that growth may be quite rapid post-1990.
The final columns of Table 5-3 combine the estimates of coal-fired
FBC potential in existing manufacturing applications with the additional
potentials estimated as "sensitivities" in relation to higher levels of
captive generation of electricity and novel applications of coal-fired FBC.
The estimates discussed above are presented in a different form in
Table 5-4. In each case, the maximum, most probable, and minimum coal-fired
FBC potentials are presented as percentages of the estimated total fossil fuel
demand of large industrial boilers. This is done excluding, and also including,
the "sensitivities" relating to higher levels of captive generation of electricity
and novel applications of coal-fired FBC. The following percentages are estimated
for the most probable case:
% of Total Fossil Fuel Demand
of Large Industrial Boilers
Year Excluding Sensitivities Including Sensitivities
1980 0.2 0.2
1985 5,5 6
1990 16 20
1995 24 30
2000 36 42
5.6 Boiler Fuel Demand Where FBC is Not Applicable
If the above estimates are of the right order of magnitude, two
important questions arise:
(1) What fuels will be used in industrial boilers with a design firing-rate
of less than 99 million BTU/H?
(2) What fuels will be used in the large industrial boilers that do not
employ coal-fired FBC technology?
The first of these questions is outside the scope of the present
study. Nevertheless, it may be inferred that (a) there will be a contingency
demand for oil and gas as industrial fuels, whether these fuels are petroleum-
derived or "synthetic", and (b) that some manufacturing operations may stop
-------
TABLE 5-3
ESTIMATES OF POSSIBLE ADDITIONS TO NATIONAL POTENTIAL FOR COAL-FIRED FBC
ATTRIBUTABLE TO HIGHER LEVEL OF CAPTIVE GENERATION OF ELECTRICITY AND NEW APPLICATIONS
• Maximum Potential
Year
1980
1985
1990
1995
2000
• Most
1980
1985
1990
1995
2000
Higher Level of _
Captive Elect., 10 BTU
nominal
0.06
0.24
0.84
1.80
Likely Potential
nominal
0.03
0.12
0.42
0.90
New
Applications, 1015 BTU
nil
nominal
0.42
1.02
1.92
nil
nominal
0.28
0.68
1.30
Subtotal
1015 BTU
nominal
0.06
0.66
1.86
3.72
nominal
0.03
0.40
1.10
2.20
Table 5-2
Potential
1015 BTU
0.02
0.62
1.97
3.20
5.52
0.01
0.29
0.99
1.69
2.97
Combined
Potential
10 BTU
0.02
0.68
2.63
5.06
9.24
0.01
0.32
1.39
2,79
5.17
Comb. Pot.
in 106
B/D O.E.*
0.009 (9,000
B/D)
0.32
1.24
2.38
4.3
i
G
^-
0.005 (4,500 '
B/D)
0.15
0.65
1.31
2.4
• Minimum Potential
1980
1985
1990
1995
2000
nil
0.012
0.048
0.168
0.360
nil
nominal
0.084
0.204
0.384
nil
0.012
0.132
0.372
0.744
nil
0.075
0.294
0.543
1.00
nil
0.087
0.43
0.91
1.74
nil
0.04 (40,000
B/D)
0.20
0.43
0.82
*10 BTU per year = 0.47 x 10 barrels of oil equivalent per day.
-------
TABLE 5-4
ESTIMATES OF COAL-FIRED FBC POTENTIAL AS PERCENTAGE OF TOTAL FOSSIL FUEL
CONSUMPTION OF LARGE INDUSTRIAL BOILERS
• Excluding
Higher Level of
Total Fossil Fuel
Year Large Boilers, 1Q15
1980
1985
1990
1995
2000
• Including
4.40
5.22
6.12
7.14
8.34
Higher Level of
Total Fossil Fuel
Year Large Boilers, 1Q15
1980
1985
1990
1995
2000
4.40
5.29
6.84
9.16
12.38
Captive Generation
for Maximum FBC
BTU* 1015 BTU
0.02
0.62
1.97
3.20
5.52
Captive Generation
for Maximum FBC
BTU** 1015 BTU
0.02
0.68
2.63
5.06
9.24
of Electricity
and Novel
Potential i Most Prob.
% of Total
0.5
12
32
45
66
of Electricity
1Q15 BTU
0.01
0.29
0.99
1.69
2.97
and Novel
Potential Most Prob.
% of Total
0.5
13
38
55
75
1015 BTU
0.01
0.32
1.39
2.79
5.17
Applications
Potential -j5
% of Total
0.2
5.5
16
24
3'6
Applications
FBC Potential
% of Total
0.2
6
20
30
42
Minimum FBC Potential
lO1^ BTU
nil
0.075
0.294
0.543
1.000
% of Total
nil
1.4
5
8
12
Minimum FBC Potential
1015 BTU % of Total
o
I
nil
0.087
0.43
0.91
1.74
nil
1.6
6
10
14
ftfrom Table 4-6 or 5-2
**including increment due to electricity generation etc.
«5from Table 5-2
-------
- 91 -
generating their own steam and, instead, may purchase steam from electric
utilities or central steam-generating plants or may substitute purchased
electricity in processes that now use steam.
The second question is at the boundary of the present study
Various answers seem possible. Indeed, the most likely outcome is a
combination of conventional use of compliance coal, coal-in-oil slurries non-
compliance coal with control technologies such as FGDS, solvent refined '
coal or other forms of cleaned solid coal, and also the continuing use of
oil and gas in some plants. Moreover, as in the case of smaller manufacturing
plants, some MFBI's may be able to purchase steam from central plants and/or
substitute electricity for steam in some processes.
The suggestions of (a) higher levels of captive generation of
electricity, and (b) substitution of electricity for steam may appear
mutually incompatible. However, it is believed that each can occur, although
in different types of manufacturing operation. The former is believed best
suited to an activity that requires large quantities of process steam and
relatively smaller amounts of electricity, as in petroleum refining (or
synfuels manufacture) and segments of the chemicals industry. The latter
seems compatible with manufacturing operations that require a relatively high
ratio of electricity to steam.
5.7 Regionalization of Coal-fired FBC Potential
The future consumption of fossil fuels by large industrial boilers is
projected on a regional basis in Tables 5-5 through 5-14. The regionalization
is based on the data presented in Section 3 and the quantification accords with
the national aggregates of boiler fuel consumption projected in Section 4.
The estimates of coal-fired FBC potential discussed in Section 5.4
are disaggregated to a regional basis using the estimates of regional partici-
pation in Table 5-1 and the estimates of nationwide potential given in Table 5-2.
The results are shown in Table 5-15. Sensitivities that consider a higher level
of captive generation of electricity and novel applications of coal-fired FBC
are not included in Table 5-15**- No regionalized estimates of potential are
made for 1980 since the national aggregates are expected to be minimal at that
time. It should be noted that the estimates in Table 5-15 are in trillions of
BTU's not quads (1015 BTU), and also that the boiler system in a "small" MFBI
might consume slightly less than one trillion BTU's per year. Hence, some of
the smaller figures in Table 5-15 represent operations of a practical size.
Nevertheless, it must be pointed out that the precision of the individual^
estimates is very low. The estimates are intended only as semi-quantitative
indications of where the potential for coal-fired FBC may develop on a regional
basis. These estimates, used in conjunction with those for the total fossil
fuel demand of large industrial boilers in Tables 5-6 through 5-14, provide a
basis for conceptualizing which industries within each region offer the best
prospects for coal-fired FBC.
*See Table 3-5 for identification of FEA regions.
**If these sensitivities are desired on a regional basis, approximate estimates
may be made by proration using the estimates in Table 5-4.
-------
TABLE 5-5
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN NEW ENGLAND REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
11
ir
n
if
it
n
General
Manufacturing
ii
n
n
n
it
Miscellaneous
n
n
n
n
M
n
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
17
5
-
32
5
4
5
~6~5~
9
6
8
2
5
4
2
3
3
5
1
2
1
1
52
117
1985
21
6
—
38
6
4
6
-TT
11
9
9
2
6
4
2
4
3
6
2
3
1
1
T2~~
139
1990
25
7
—
45
6
5
6
~8T~
12
10
11
2
6
5
3
5
4
7
2
3
1
1
~TT
163
1012 BTU's
1995
30
9
—
53
7
5
7
137^
14
13
12
2
8
6
3
6
5
8
2
3
1
1
•"84-
191
2000
36
10
—
63
7
6
7
I2F~
15
15
14
3
9
7
4
7
5
9
3
4
1
1
~ToT~
223
(S3
I
-------
TABLE 5-6
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN APPALACHIAN REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
ti
Tl
11
II
II
II
General
Manufacturing
ii
n
ir
n
11
Miscellaneous
it
it
n
n
ii
ii
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
308
25
97
139
190
34
21
814
46
32
40
7
23
18
9
17
14
26
7
11
4
2
256
1070
1985
374
30
113
166
204
38
26
951
55
46
47
9
28
22
12
21
17
31
9
14
5
3
319
1270
1990
452
36
131
195
216
43
32
1105
67
55
55
10
34
27
14
27
20
37
10
17
6
4
383
1488
, 1012 BTU
1995
539
43
150
233
228
47
38
1278
81
70
65
12
40
31
17
32
24
44
12
18
7
5
458
1736
fs
2000
642
51
172
277
250
53
45
1490
95
86
74
14
48
35
21
39
28
51
14
19
9
6
539
2029
-------
TABLE 5-7
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN SOUTHEAST REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
n
it
it
n
M
II
General
Manufacturing
I!
II
n
n
1!
Miscellaneous
it
ti
n
it
n
ti
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
1980
218
17
-
258
8
12
-
513
20
15
18
3
10
8
4
8
6
12
3
5
2
1
~TT5
Coal, Oil,
1985
264
21
-
308
9
13
-
615
23
18
19
4
11
9
5
9
7
13
3
6
2
1
TIU
Natural Gas ,
1990
320
26
-
363
9
15
-
733
25
20
20
4
12
10
5
10
7
14
4
6
2
1
"140"
1012 BTU's
1995
381
30
-
431
10
17
-
869
26
23
21
4
13
10
6
11
8
14
4
6
2
2
"T5TT
2000
454
36
-
513
10
18
-
1031
28
25
22
4
14
10
6
12
8
15
4
6
3
2
~159
I
VD
Total
628
745
873
1019
1190
-------
TABLE 5-8
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN GREAT LAKES REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
11
it
11
it
n
11
General
Manuf a c tur ing
n
11
ii
n
n
Miscellaneous
n
n
ii
11
M
n
Coal, Oil, Natural Gas
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prod's.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
57
5
100
60
152
43
5
422
43
30
37
7
21
17
8
15
13
24
7
10
4
2
238
660
1985
69
6
116
72
163
49
6
481
53
44
45
8
27
21
11
20
16
29
8
13
5
3
303
784
1990
84
7
135
85
172
54
7
544
66
54
54
10
33
26
14
26
19
36
10
16
6
4
374
918
, 1012 BTU's
1995
100
8
154
101
182
60
9
614
81
70
65
12
40
31
17
32
24
44
12
18
7
5
458
1072
2000
120
9
177
120
194
67
10
697
98
89
77
15
49
36
21
40
29
52
14
20
9
6
555
1252
-------
TABLE 5-9
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN NORTHERN PLAINS REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry; Industry
Process Chemicals
" Rubber & Plastics
" Petroleum Refining
" Paper
" Primary Metals
" Food
" Stone, Clay, Glass, Concrete
General Transportation Equipment
Manufacturing Electrical Equipment
" Textile Mill Prods.
" Apparel
" Fabricated Metals
" Machinery, ex. Elect.
" Instruments
Miscellaneous Utility Services
" Ordnance/Miscellaneous
" Lumber & Wood
" Furniture
" Printing & Publishing
" Leather
" Tobacco Manufactures
Total
Coal, Oil, Natural Gas,
1980
2
-
4
19
30
—
55
6
4
5
1
3
2
1
2
2
3
1
2
1
negl
33
88
1985
3
-
5
22
34
—
64
7
6
6
1
3
3
1
3
2
4
1
2
1
negl
40
104
1990
4
—
6
26
39
—
75
8
7
7
1
4
3
2
3
3
5
1
2
1
negl
47
122
1012 BTU's
1995
4
—
7
31
43
—
85
10
8
8
2
5
4
2
4
3
6
2
2
1
1
"58-
143
2000
5
—
8
37
47
^
97
12
11
10
2
6
4
3
5
4
7
2
2
1
1
— 7TT
167
CTv
I
-------
TABLE 5-10
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN MIDCONTINENT REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
11
1!
ii
IT
ii
11
General
Manufacturing
11
11
H
11
11
Miscellaneous
n
ii
n
M
n
n
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
16
1
33
11
1
8
-
~TQ~
2
1
1
negl
1
1
negl
1
1
1
negl
negl
negl
negl
9
79
1985
20
1
38
12
1
10
-
82
2
2
2
negl
1
1
negl
1
1
1
negl
1
negl
negl
11
93
1990
25
2
43
13
1
12
-
96
2
2
2
negl
1
1
1
1
1
1
negl
1
negl
negl
14
110
1012 BTU
1995
30
2
50
14
1
13
-
mT~
3
3
2
negl
2
1
1
1
1
2
negl
1
negl
negl
~T3
128
's
2000
35
3
55
16
1
16
—
TI5~
4
4
3
1
2
1
1
2
1
2
1
1
negl
negl
TS~
149
1
vD
-------
TABLE 5-11
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN GULF COAST REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
it
1!
II
II
II
II
General
Manufacturing
ii
ii
it
ii
ii
Miscellaneous
ii
M
ii
ii
ir
M
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
577
46
395
130
23
24
—
1195
31
22
27
5
15
12
6
11
9
17
5
8
3
2
173
1368
1985
702
56
463
155
24
27
—
1427
34
29
30
5
17
14
7
13
10
19
5
9
3
2
197
1624
1990
848
68
535
182
26
30
—
1689
37
31
31
6
19
15
8
15
11
21
6
9
3
2
214
1903
1012 BTU'
1995
1010
70
613
217
27
34
—
1980
42
36
34
7
21
16
9
17
13
23
6
9
4
3
240
2220
s
2000
1205
96
703
258
29
38
~"
2329
47
42
37
7
24
17
10
19
14
25
7
9
4
3
2l)5
2594
00
I
-------
TABLE 5-12
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN ROCKY MOUNTAIN REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
11
(i
11
11
11
11
General
Manuf ac tur ing
!1
It
It
11
11
Miscellaneous
ti
Tl
II
U
11
11
-
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
25
2
5
2
26
20
-
80
11
8
9
2
5
4
2
4
3
6
2
3
1
1
61
141
1985
31
2
6
3
28
23
-
93
13
11
11
2
7
5
3
5
4
7
2
3
1
1
75
168
1990
38
3
8
3
31
26
-
109
16
12
13
2
8
6
3
6
5
8
2
4
1
1
87
196
1 ?
10 BTU
1995
46
3
10
4
34
29
—
126
18
16
14
3
9
7
4
7
5
10
3
4
2
1
103
229
's
2000
56
4
14
4
37
32
—
147
22
19
17
3
11
8
5
9
6
11
3
4
2
1
121
268
VO
VO
-------
TABLE 5-13
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN PACIFIC NORTHWEST REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
I!
II
1!
ir
11
ii
General
Manufacturing
ii
ii
ii
it
ii
Miscellaneous
ii
it
ii
ii
ii
ii
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
Total
1980
1
negl
8
55
-
18
-
82
5
3
4
1
2
2
1
2
1
3
1
1
negl
negl
26
108
1985
2
negl
9
65
-
20
-
96
5
5
5
1
3
2
1
2
2
3
1
1
1
negl
32
128
1990
2
negl
11
77
—
23
-
113
7
5
5
1
3
3
1
3
2
4
1
2
1
negl
38
151
1012 BTU's
1995
2
negl
13
92
—
25
-
132
8
7
6
1
4
3
2
3
2
4
1
2
1
negl
~^T
176
2000
3
negl
14
109
—
28
-
154
9
8
7
1
4
3
2
4
3
5
1
2
1
1
5T~
205
o
o
-------
TABLE 5-14
PROJECTED CONSUMPTION OF COAL, OIL, AND NATURAL GAS BY LARGE INDUSTRIAL
BOILERS IN PACIFIC SOUTHWEST REGION, BY SIC CODE AND INDUSTRY TYPE
SIC
Code
28
30
29
26
33
20
32
37
36
22
23
34
35
38
49
19/39
24
25
27
31
21
Type of
Industry
Process
11
11
11
it
n
ii
General
Manufacturing
u
M
II
11
11
Miscellaneous
n
n
n
M
11
IT
Coal, Oil, Natural Gas,
Industry
Chemicals
Rubber & Plastics
Petroleum Refining
Paper
Primary Metals
Food
Stone, Clay, Glass, Concrete
Transportation Equipment
Electrical Equipment
Textile Mill Prods.
Apparel
Fabricated Metals
Machinery, ex. Elect.
Instruments
Utility Services
Ordnance/Miscellaneous
Lumber & Wood
Furniture
Printing & Publishing
Leather
Tobacco Manufactures
1980
12
1
54
11
15
23
1
117
4
3
3
1
2
2
1
1
1
2
1
1
negl
negl
22
1985
15
1
64
13
16
26
1
136
5
4
4
1
3
2
1
2
2
3
1
1
negl
negl
29
1990
20
1
76
15
17
29
2
160
6
5
5
1
3
2
1
2
2
3
1
2
negl
negl
33
1012 BTU's
1995
24
2
90
18
18
32
2
~W
7
6
6
1
3
3
1
3
2
4
1
2
1
negl
4~0"
2000
28
2
107
20
20'
35
2
216
8
8
7
1
4
3
2
4
2
4
1
2
1
1
5B"
I
!-•
O
H>
I
Total
139
165
193
226
264-
-------
- 102 -
TABLE 5-15
REGIONALIZED ESTIMATES OF COAL-FIRED FBC POTENTIAL
• Maximum Potential
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
1012 BTU of Coal
1985
171
103
105
7
13
189
10
12
10
620
1990
543
326
334
21
43
603
31
38
31
1970
1995
882
529
542
35
69
981
51
61
50
3200
2000
1522
913
934
60
120
1691
88
105
87
5520
* Most Probable Potential
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
68
59
61
2
8
82
3
4
3
290
229
202
207
8
27
280
12
13
12
990
686
606
621
24
80
840
36
41
_^6_
2970
* Minimum Potential
Appalachian
Southeast
Great Lakes
Mid-Continent
25
24
24
_2
75
98
93
96
8
294
181
172
176
14
543
332
317
324
27
1000
See Table 3-5 for identification of regions listed above.
Note: A "small" MFBI, having two coal-fired FBC boilers of 100 M BTU/H
capacity, operated at an average annual loading of 50%, would consume
2 x 100 x 106 x 8760 x 0.5 = 876 x 10$ BTU's per year, i.e. slightly
less than one trillion BTU's per year.
-------
- 103 -
6. ENERGY IMPACTS
6.1 Impact on National Energy Consumption
A consistent application of the assumptions made elsewhere in this
study leads to the conclusion that coal-firing of large industrial boilers
using FBC technology will have an insignificant impact on national energy
consumption in aggregate. The simplistic explanation is that the aggregate
will not be affected greatly by:
(1) the technology by which solid coal is fired in boilers
(2) whether coal or oil is used as boiler fuel, as long as the pertinent
fuel is available.
These points will be discussed separately. The first is relatively
straightforward, while the second involves exceedingly complex issues. The
first point may be explained by considering a hypothetical base case in which
all large industrial boilers are fired with solid coal without the use of any
control technology. An alternative to the base case would be to have some, or
all, of the boilers equipped with flue gas scrubbers. This would increase coal
consumption marginally for the same level of steam output because the scrubbing
operation consumes some energy. This is an important practical consideration
for electric utility boilers, particularly in the case of retrofitting, because
some loss of generating capacity occurs when a scrubber is installed. For
industrial boilers, however, the long term effect would be small because the
capacity loss could be offset by new capacity added during plant expansions.
Nominally, energy consumption would be higher, but even this is not a certainty
since the boiler efficiency loss might be offset by savings of transportation
energy in cases where locally available high sulfur coal was substituted
(hypothetically) for compliance coal obtained from a distant location. Addition-
ally, new boilers could be designed to give slightly higher thermal efficiency
than the average of the existing boiler population.
If atmospheric FBC technology were to be used instead of FGDS, the
net effect on coal consumption would be almost zero. There is a possibility
of marginally higher combustion efficiency with FBC but this would be offset
by the differential in transportation energy associated with a larger quantity
of sorbent required for FBC versus FGDS. The overriding consideration is that
industrial boiler fuel demand is set by a given level of manufacturing activity
not by the technology by which the industrial boiler fuel is combusted.
For point (2), the overriding considerations are (a) the future
availabilities of coal and oil, and (b) the nature of the oil: whether it
domestically refined from domestic crude oil, domestically refined from
imported crude oil, or imported fuel oil. On a relative basis, national
energy consumption is lower if imported fuel oil is used because the energy
consumption associated with production and refining takes place outside the
U.S. Long range, however, the availability and cost of imported oil is a
-------
104 -
far more important consideration than energy consumption differentials
attributable to petroleum extraction and refining processes. Ronald Kutscher,
Assistant Commissioner for Economic Growth, Bureau of Labor Statistics,
has remarked(1), (2):
"With regard to energy, the key question is: will scarcities
and much higher prices cause a slower rate of growth in the
economy? Related issues are possible disruptions of supply,
investment requirements for energy-conserving machinery or plant,
search for new energy sources or larger supplies from existing
sources, alternative means of transportation, and more efficient
energy usage in houses and apartment buildings. Each of these
issues could have important effects on the future rate and pattern
of growth in the economy."
"Several factors underlie the lowering, at least through 1980, of
the expected rate of growth of productivity. . . there is the
expected cost of meeting pollution control and industrial safety
requirements, a long period of less than full utilization of
resources, and higher energy prices, all of which are expected
to slow productivity advances in the near term. Investment in
energy-saving equipment could also dampen the growth of productivity-"
"The new projections, unlike the 1973 set, do not assume the
availability of relatively cheap, nearly unlimited energy
supplies. The effects of the changed energy outlook on
labor productivity, capital requirements, and prices, as
well as the relationship of these changes to economic
growth are complex issues. Although a great deal of
effort was devoted to these questions, BLS has not developed
a satisfactory method of dealing with them in the industry
and employment projections. Research by others is also
just beginning to address the effect of changes in energy
supplies and costs on the economy. Clearly, further
research and analysis are needed."
The purpose of these citations is to suggest that there are important
variables, exogenous to the present study, that can drown out the differential
effects of applying coal-fired FBC, versus another, technology to industrial
boilers. Directionally, such technology might be expected to permit a net
increase in national energy consumption relative to an uncertain alternative
of relying on imported oil, primarily because of a higher level of domestic
economic activity attributable to a secure, domestic energy supply. However,
essentially the same outcome would be expected for any effective technology for
using solid coal as an industrial boiler fuel.
6.2 Potential Savings of Oil and Natural Gas
It seems more reasonable to consider the impact of coal-fired FBC
in terms of oil alone, rather than in terms of oil and natural gas. This is
because the availability of natural gas is declining, and it is not possible to
save what is not available. However, it is questionable whether any oil will
-------
- 105 -
be saved by coal-fired FBC per se. A saving will occur if solid coal is
used instead of oil in large industrial boilers, but the level of saving
achieved will be essentially independent of the technology by which the coal
is combusted for the reasons given in Section 6.1. Nevertheless, the estimates
of coal-fired FBC potential in Tables 5-2, 5-3 and 5-15 may be converted from
BTU's to barrels of oil equivalent. The results of these conversions are shown
in Table 6-1, and suggest that if coal-fired, atmospheric pressure, FBC
technology is demonstrated as reliable for large industrial boilers by 1981
or 1982, then there could be significant "savings" of oil equivalent by 1990.
Considering conventional and additional applications, "savings" of 1 million
B/D O.E. appear possible shortly thereafter. By the year 2000, the combined
"savings" may be in the range of two to four million B/D O.E. These "savings"
are not incremental to analegous "savings" achievable with other technologies
for utilizing solid coal; the various coal-use technologies are potential
alternatives.
-------
- 106 -
TABLE 6-1
ESTIMATES OF COAL-FIRED FBC POTENTIAL EXPRESSED AS BARRELS
OF OIL EQUIVALENT
* Maximum Potential
Lower 48 states,
conventional uses
Lower 48 states,
additional uses
1000 B/D of Oil Equivalent
1980
319
1990
926
310
1236
1995
1504
874
2378
2000
2594
1748
4342
Most Likely Potential
Lower 48 states,
conventional uses
Lower 48 states,
additional uses
136
14
150
462
188
650
793
JL17_
1310
1396
1034
2430
Minimum Potential
Lower 48 states,
conventional uses
Lower 48 states,
additional uses
nil
nil
nil
35
_6
41
138
62
200
Most Likely Potential (Regional basis, conventional uses)
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
1
1
1
*
A
*
*
32
28
29
1
4
38
1
2
1
13F
107
95
96
4
13
131
5
6
5
4~6T
255
175
430
183
162
166
6
23
224
9
11
7
793
470
350
820
321
284
292
11
38
394
17
22
17
1396
* =
-------
- 107 -
7. ECONOMIC IMPACTS
7.1 National Impacts
For the reasons given in Section 6.1, the absolute economic impacts
of coal-fired FBC are indeterminate. The fundamental reason for this indeter-
minateness is that there are controlling exogenous variables that cannot be
precisely forecast because of their political and other complexities.* However,
it is possible to ascribe certain levels of economic activities to certain
levels of coal-fired FBC potential. The approach described below does not
remove the possibility that a similar level of economic activity could apply
to other technologies of using solid coal in industrial boilers.
The 1972 OBERS Projections discussed in Section 4.1 include estimates
of the value of goods produced by manufacturing industries in terms of Gross
Product Originating.** The original projections were made in 1967 constant
dollars. For consistency with other estimates in this study, the GPO projections
in Table 7-1 have been converted to 1975 constant dollars,*** The total GPO for
all manufacturing industries is summarized below:
Year Manufacturing GPO, billion 1975 $
1980 564.6
1985 656.3
1990 761.4
1995 886.2
2000 1031.6
*The complexities are orders of magnitude beyond the scope of the Present study.
Nevertheless, Professor Jay Forrester and the System Dynamics group at M.I.I.
have already spent three years on the development of a computer simulation model
that may, eventually, be able to provide answers of the kind that would be needed
for aboslute assessments of economic impact. Professor Forrester s model may be
completed during the next three years. Professor Roger Naill, of the Thayer School
of Engineering at Dartmouth College, has constructed a simpler SD model that may
be developed further to permit economic assessments of energy technologies At
present, neither of the SD models can provide the required answers. (1), (2), (3)
**See Section 4.1 for definition of GPO.
***using a multiplier of 1.573 derived from Bureau of Economic Analysis data.
-------
TABLE 7-1
BEA Industry Classification
Food and Kindred Products
Textile Mill Products
Apparel and Other Fab. Prods.
Lumber and Furniture
Paper and Allied Products
Printing and Publishing
Chemicals and Allied Products
Petroleum Refining
Primary Metlas
Fabricated Metals/Ordnance
Machinery excl. Electrical
Electrical Equipment
Motor Vehicles and Equipment
Transportation Equipment excl. M.V.
Other Manufacturing
All Manufacturing
OF GROSS PRODUCT ORIGINATING (GPO)
SIC
Equivalent
20
22
23
24,25
26
27
28
29
33
34,19
35
36
371
37*
**
GPO in Billions
1980
45.1
17.4
17.6
19.8
21.5
26.2
60.5
13.2
29.5
40.1
52.9
73.0
51.5
22.0
74.3
564.6
1985
49.4
19.7
20.1
22.6
24.8
30.8
74.1
15.2
30.9
46.5
60.1
90.4
59.8
24.2
87.7
656.3
of 1975 Constant Dollars i
1990
54.1
22.2
22.9
25.8
28.6
34.5
90.5
17.4
32.0
53.8
68.4
111.7
69.4
26.5
103.6
761.4
1995
59.5
25.0
26.2
29.4
33.1
41.2
110.1
19.9
33.4
62.2
77.9
136.6
80.6
29.1
122.0
886.2
2000
65.6
28.1
30.0
33.6
38.3
49.2
132.4
22.8
34.8
72.0
88.0
167.0
93.6
31.9
143.5
1031.6
O
CO
i converted from 1967 constant dollars in source document
* excluding SIC 371
** sum of SIC 21, 30, 31, 32, 38 and 39
Source: 1972 OBERS Projections, Vol. 1, Table 5 of Part 3 and Table 1 of Part 4.
for discussion of the OBERS projections, and Reference 1.)
(See Section 4.1
-------
- 109 -
As a first approximation, it is assumed that a unit of GPO is
proportional to the quantity of industrial boiler fuel consumed but is
independent of boiler size per se. This assumption makes it possible to
estimate the GPO that is relatable to the operation of large industrial
boilers:
Year Large Boiler GPO. billion 1975 6
1980 233.2
1985 285.5
1990 348.0
1995 423.6
2000 515.8
Next, the estimated most probable potential for coal-fired FBC
(Table 5-2) is related to the estimated total fuel consumption of large
industrial boilers (Table 4-5):
(A) (B)
Most Probable FBC Fuel Demand of Large (A) as %
Year Potential, 1Q12 BTU Industrial Boilers, ipl2 BTU of (B)
1980 10 4756 0.2
1985 290 5615 5.2
1990 990 6579 15.0
1995 1690 7674 22.0
2000 2970 8950 33.2
The percentages in the last column of the above table can then be
applied to the estimates of manufacturing GPO associated with the operation
of the large industrial boilers.
Manufacturing GPO in Billions of 1975 $
Year associated with Most Probable FBC Potential
1980 0.5
1985 15
1990 52
1995 93
2000 171
The above estimates, in billions of constant 1975 dollars, are not a
direct and unique measure of the economic value of coal-fired FBC, rather they
are estimates of the economic value of the manufacturing activity imputed to
the operation of large coal-fired FBC industrial boilers. As discussed above,
it is possible that the same levels of economic activity could be achieved
with other coal use technologies.
-------
- 110 -
Comparable estimates of imputed GPO are given below for the maximum
and minimum coal-fired FBC cases:
Manufacturing GPO in Billions of 1975 $
Year Maximum Potential Minimum Potential
1980 1 nil
1985 31 4
1990 104 16
1995 177 30
2000 318 57
In addition to estimating, or imputing, economic levels of manufac-
turing activity to coal-fired FBC, it is also possible to estimate the economic
value of the oil that may be "saved" via the use of this technology. The
estimates are based on Table 6-1, which projects coal-fired FBC potential
in terms of daily barrels of oil equivalent. The conversions are made using
a factor of $12 per barrel of low sulfur fuel oil (in constant 1975 dollars)
or $4.38 million per year per 1000 B/D of oil equivalent. The results of
these calculations are shown in Table 7-2.
7.2 Regional Impacts
As with national economic impacts, regional impacts may also be
considered in terms of:
(1) the economic value of the manufacturing activity imputed to the operation
of large coal-fired FBC industrial boilers within the region.
(2) "savings" of oil equivalent associated with FBC coal-use technology.
In 1980, for the most probable case, it is estimated that each of four
regions may have imputed manufacturing activity in the range of $100-125 million
(1975 constant dollars). The four regions are Appalachian, Southeast, Great
Lakes, and Gulf Coast. Similar estimates for subsequent years are reported in
Table 7-3. Comparable estimates of "savings" of oil equivalent on a regional
basis are reported in Table 7-4.
7.3 Boiler Manufacturing and Related Industries
The economic impact of industrial boiler use of coal-fired FBC
technology may be estimated in terms of the number of FBC boiler units of
some average size that is projected to be installed during a given time period.
For this purpose, it was assumed that the size of the average large boiler unit
would be 200 KPPH. It was assumed, further, that .the manufacturer of the FBC
steam generator (i.e. "boiler") would be responsible for manufacture or procure-
ment of other equipment that is directly a part of the boiler "system". Coal
and limestone receiving and storage facilities are not included in this system.
Additionally, it was assumed that the 200 KPPH boiler would operate with an
average annual capacity utilization of 65%, which is typical for large boilers
used by the petroleum refining, petrochemical, and chemical industries. These
assumptions, and the estimates of coal-fired FBC potential in Table 5-2, yield
the results recorded in Table 7-5. It is a common practice for the boiler
-------
TABLE 7-2
Maximum Potential
Lower 48 states, conventional uses
Lower 48 states, additional uses
Most Probable Potential
Lower 48 states, conventional uses
Lower 48 states, additional uses
Minimum Potential
Lower 48 states, conventional uses
Lower 48 states, additional uses
:L EQUIVALENT
"SAVED
Billions
1980
0.04
0.04
0.02
0.02
nil
nil
nil
1985
1.27
0.12
1.4
0.60
0.06
0.66
0.15
0.03
0.2
" BY COAL-FIRED
FBC
of 1975 Constant Dollars
1990
4.06
1.36
5.4
2.02
0.82
2.8
0.60
0.27
0.9
1995
6.59
3.83
10.4
3.47
2.26
1.12
0.77
1.9
2000
11.36
7.66
19.0
6.11
4.53
2.06
1.53
3.6
-------
TABLE 7-3.
Region
ESTIMATED REGIONAL VALUES OF MANUFACTURING ACTIVITY IMPUTED TO
USE OF COAL-FIRED FBC TECHNOLOGY IN INDUSTRIAL BOILERS
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
Billions of 1975 Constant Dollars in Most Probable Case
1985
3.5
3.1
3.1
0.1
0.4
4.2
0.2
0.2
0.2
1990
12.0
10.6
10.9
0.4
1.4
14.7
0.6
0.7
0.6
1995
21.5
19.0
19.4
0.7
2.5
26.3
1.1
1.3
1.1
2000
39.5
34.9
35.7
1.4
4.6
48.4
2.0
2.4
2.0
NJ
I
Possible additional uses, such as a higher level of captive generation of electricity at manufacturing
plants, are excluded from above estimates.
-------
TABLE 7-4
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
ESTIMATED REGIONAL VALUES OF OIL EQUIVALENT "SAVED" BY
COAL-FIRED FBC IN
1980
0.14
0.12
0.13
0.005
0.02
0.17
0.007
0.008
0.007
MOST PROBABLE
Billions of
1985
0.47
0.41
0.42
0.02
0.05
0.57
0.02
0.03
0.02
CASE*
1975 Constant
1990
0.80
0.71
0.73
0.03
0.09
0.98
0.04
0.05
0.04
Dollars
1995
1.39
1.23
1.25
0.04
0.17
1.13
0.06
0.07
0.06
2000
1.41
1.25
1.28
0.05
0.17
1.73
0.07
0.09
0.07
^excluding possible additional uses such as a higher level of captive generation of electricity
at manufacturing plants.
-------
TABLE 7-5
ESTIMATES OF NUMBER OF INDUSTRIAL FBC BOILERS AND RELATED
ERECTED VALUES OF THE BOILER SYSTEMS
Maximum Potential, Conventional Uses
FBC units added through 1980
FBC units added 1981/1985
FBC units added 1986/1990
FBC units added 1991/1995
FBC units added 1996/2000
Number
of Units*
14
413
890
890
1600
3807
Erected Equipment Cost in
Millions of 1975 $ **
39
1156
2490
2490
4480
10,655
i
* Most Probable Potential, Conventional Uses
FBC units added through 1980
FBC units added 1981/1985
FBC units added 1986/1990
FBC units added 1991/1995
FBC units added 1996/2000
7
193
485
485
880
2050
20
540
1360
1360
2460
5,740
-P-
I
• Minimum Potential, Conventional Uses
FBC units added through 1980
FBC units added 1981/1985
FBC units added 1986/1990
FBC units added 1991/1995
FBC units added 1996/2000
nil
51
152
172
315
690
145
425
480
880
1,930
*based on an average steam generating capability of 200 KPPH.
**boiler system includes coal/limestone metering and fuel injection, fans and drivers, steam generator,
waste solids handling equipment, control instruments, flues and ducts; excludes all contingencies.and
costs of work not normally performed by a boiler manufacturer/erector.
<{> estimates are probably unrealistically low for "pioneer" units.
-------
- 115 -
manufacturer to be responsible for the on site erection of large industrial
boilers. However, a rough estimate of the equipment cost, F.O.B. the
manufacturer's plant, is 55% of the corresponding erected cost.
Table 7-5 depicts a situation where, in the most probable case the
equivalent of seven 200 KPPH industrial boilers are estimated to be in operation
by the end of 1980. In practice, it is expected that the average size of the
initial commercial units will be less than 200 KPPH. For this reason and
because the initial boilers will be "pioneer" and demonstration units, the
unit erected costs are probably understated. Subsequent to 1980, however, the
estimates of equipment costs are believed to be in reasonable correspondence
with the fuel potentials estimated in Table 5-2 and the numbers of large FBC
industrial boiler units listed in the first column of Table 7-5. The latter
figures may be compared with those from FEA's MFBI survey which reported
approximately 4,000 large industrial boilers to be in operation in 1974. As
reported in Table 20 of Appendix 4, the average steam generating capacity of
the MFBI boiler population was 223 million BTU/H or approximately 190 KPPH.
Hence, the assumption of an average size of 200 KPPH for large coal-fired FBC
boilers appears reasonable.
7.4 Coal Industry
Estimates of the volumes of coal associated with different levels of
FBC potential are reported in Table 7-6. Numerically, the estimates are based
on Illinois No. 6 coal, with a heating value of 10,600 BTU/lb. However, this
does not imply that coal-fired FBC will be limited to a single type of coal.
Estimates of the F.O.B. mine value of the coal shipped for FBC
industrial boiler use are also given in Table 7-6. In the most probable case,
assuming a combination of conventional and additional uses of FBC, the quantity
and F.O.B. value of the coal in the year 2000 are estimated to be 244 million
tons and $3.4 billion (constant 1975 dollars) respectively. Considering
conventional uses only, the corresponding estimates are 140 million tons and
approximately $2 billion dollars.
7.5 Limestone Industry
The limestone requirements associated with coal-fired FBC also assume
the use of Illinois No. 6 coal which has an average sulfur content of 3.6 wt/..
Clearly, the use of non-compliance coals of lower sulfur content would require
lesser quantities of limestone than are estimated in Table 7-7. On the ottieT
hand, no provision has been made for some use of limestone when Compliance coals
are used with FBC technology, thereby offsetting the overestimates of limestone
usage with non-compliance coals.
The average, or representative, cost of limestone F.O.B. quarry is
assumed to be $3.50%^ ton (in 1975 dollars). This price includes whatever
crushing or other treatments at the quarry are needed to prepare the limestone
for use in coal-fired FBC boilers.
In the most probable case, the year 2000 requirements »f I
are estimated to be 87 million tons, with a corresponding F.O.B. value
$300 million.
-------
TABLE 7-6
ESTIMATES OF COAL VOLUMES REQUIRED FOR APPLICATION OF FBC TO INDUSTRIAL BOILERS
Conventional Uses
Maximum Potential
1980
1985
1990
1995
2000
10 Tons
0.94
29.2
90.6
150.9
260.4
F.O.B. Mine
Million 1975 $*
13
409
1268
2110
3640
10 Tons
2.8
31.1
87.7
175.5
Additional Uses**
F.O.B. Mine
Million 1975 $*
39
435
1228
2460
Combined Potential **
, F.O.B. Mine
Million 1975$*
10 Tons
0.94
22
122
239
436
13
308
1700
3300
6100
Most Probable Potential
1980
1985
1990
1995
2000
0.46
13.6
46.8
79.7
140.1
6
190
655
1113
1960
1.4
18.9
51.9
103.8
20
265
727
1450
0.46
15
66
132
244
6
210
920
1840
3410
Ol
I
• Minimum Potential
1980 nil
1985 3.5
1990 13.9
1995 25.6
2000 47.2
nil
49
195
358
660
0.6
6.2
17.5
35.1
87
245
491
nil
4.1
20
43
82
nil
57
280
600
1150
Note: Coal volumes are estimated in terms of millions of short tons of Illinois No. 6 coal.
*long run price for high sulfur coal estimated by Sobotka, and considering other information presented
in "A Study of Coal Prices", Council on Wage and Price Stability, Executive Office of the President,
March 1976. (4)
**see Table 5-3.
-------
TABLE 7-7
ESTIMATES OF
Maximum Potential
1980
1985
1990
1995
2000
LIMESTONE VOLUMES
Conventional
REQUIRED FOR
Uses
Limestone F.O.B. Quarry
106 Tons Million 1975 $
0.35
11.0
34.0
56.6
97.7
1.2
39
119
198
342
APPLICATION
OF FBC TO INDUSTR:
Additional Uses*
Limestone
106 Tons
«,
1.05
11.7
32.9
65.8
F.O.B. Quarry
Million 1975 $
_
3.7
41
115
230
Most Probable Potential
1980
1985
1990
1995
2000
1 Minimum Potential
1980
1985
1990
1995
2000
0.16
4.6
15.9
27.1
47.6
nil
1.3
5.2
9.6
17.7
0.56
16
56
95
167
nil
4.6
18
34
62
_
0.53
7.1
19.5
38.9
0.23
2.3
6.6
13.2
_
1.9
25
68
136
0.8
8
23
46
Combined Potential*
Limestone
106 Tons
0.35
11
46
89
163
0.16
5
23
47
87
nil
1.5
7.5
16
31
E. 0.. B,. Quarry
Million 1975 $
1.2
43
160
310
570
0.56
18
80
140
300
nil
6
26
57
108
*see Table 5-3.
-------
- 118 -
8. ENVIRONMENTAL CONSIDERATIONS
i.l Introduction
The application of any new technology should be considered from
the viewpoint of its possible benefits/debits to the environment, especially
when alternatives exist for meeting the same needs in other ways. The
possible application of fluidized bed coal combustion technology (FBC) to
industrial steam generation raises the question of what implications this
would have from an environmental standpoint. This section discusses and,
where possible, quantifies these impi-.cations.
The environmental component of the present study is a small part
of a much larger program of FBC environmental assessment and development of
control technology sponsored by i'he Environmental Protection Agency-
For convenience, when words such as "meeting (not meeting) EPA
regulations" are used, it should be understood that this means New Source
Performance Standards (NSPS) applicable only to (large) installations of
250 x 106 BTU/hr. or greater input. These standards are shown in Table 8-1.
At present, there are no comparable regulations for the 100 to 250 x 106 BTU/hr.
units considered in this study, although it is possible that NSPS will be
promulgated for the smaller units. Also, as discussed later, it is possible
that National Ambient Air Quality Standards (NAAQS) will override NSPS in
some Air Quality Control Regions. Pertinent air quality standards are
listed in Table 8-2.
8.2 Fuels and Boilers Considered
The industrial boiler systems and fuels considered are those
discussed in Section 2 and Appendices 1-3. Comparisons were made of FBC
and a spreader stoker boiler because the latter represents a likely option
for industrial application. A high sulfur coal was chosen for comparison
in the two systems since such coals are abundant in the highly industrialized
areas of the east and midwestern sections of the country where effluents
would be a major concern. A low sulfur western coal not meeting EPA standards
for sulfur emissions was compared in the two systems since large quantities
of such coals exist and their price might be attractive compared to lower sulfur
western coals. Furthermore, it was felt that undesirable effluents could be
significantly different for such coals than for high sulfur coals. A low
sulfur western coal meeting EPA regulations for sulfur emissions was included
in the study for the spreader stoker boiler to give a base point for a fuel
in ample supply offering desirable environmental qualities. Finally, a
boiler utilizing a low-sulfur fuel oil was included because this type fuel
could be replaced by boilers using coal. Thus the low sulfur fuel oil
represents a base case for environmental comparisons. Natural gas was
assumed not to be available at new installations.
-------
- 119 -
TABLE 8^1
SELECTED NEW SOURCE PERFORMANCE
STANDARDS (NSPS) FOR AIR POLLUTION SOURCES (Ref. 1)
Source Pollutant Emissions Not to Exceed
STEM GENERATORS
Fossil-fuel fired Particulate Matter 0.1 lb/106 Btu input
>, 250 x 10^ Btu/hr input 20% opacity
Sulfur Dioxide 1.2 lb/106 Btu
(Solid Fuel)
0.8 lb/106 Btu
(Liquid Fuel)
Nitrogen Oxides 0.7 lb/106 Btu
(as N02) (Solid Fuel)
0.3 lb/106 Btu
(Liquid Fuel)
0.2 lb/106 Btu
(gaseous fuel)
-------
TABLE 8-2
SUMMARY OF NATIONAL AMBIENT AIR QUALITY STANDARDS'
Pollutant
Averaging
time
Primary
standards
Secondary
standards
Comments
Particulate
matter
Sulfur oxides
Nitrogen
dioxide
Annual (Geometric
mean) ,
24-hour
Annual (Arith-
metic mean)
24-hourb
3-hourb
Annual (Arith-
metic mean)
75 yg/m~
260 yg/nf
80 yg/m
(0.03 ppm)
365 yg/m3
(0.14 ppm)
100 yg/m
(0.05 ppm)
60 yg/m
150 yg/m2
1300yg/mJ
(0.5 ppm)
(Same as
primary)
The secondary annual stand-
ard (60 yg/m3) is a guide
for assessing SIP's to
achieve the 24-hour secondary
standard.
The continuous Saltzman," Sodi-
um Arsenite (Christie), TGS,
and Chemiluminescence have
been proposed as replacements
for the J-H method. New FRM*
will be forthcoming in the
near future.
I
I—
o
)
The air quality standards and a description of the Federal Reference Methods *(FRM) were published on
April 30, 1971 in 42 CFR 410, recodified to 40 CFR 50 on November 25, 1972.
Not to be exceeded more than once per year.
-------
- 121 -
8.2.1 Emissions Considered
The principal emissions considered were participate matter, sulfur
dioxide and nitrogen dioxide, in relation to the standards listed in Tables 8-1
and 8-2. Some consideration was also given to solid or sludge wastes and
to the trace metals present in different coals.
Waste heat emitted to the environment was not considered since the
major heat losses resulted from thermal inefficiencies in steam generation
and these were assumed equal for all units. Coal preparation and drying
can vary considerably from coal to coal and generate considerable thermal
losses vis-a-vis direct use of fuel oil. These losses were not considered
because (1) it was assumed in the economic study that coal arrived at the
plant ground and dried, (2) the specific coals chosen for study represent
only a few of a multitude of coals and estimation of heat losses associated
with preparation and drying these particular coals would have little general
usefulness, and (3) when comparing coal preparation with the direct use of
fuel oil it must be remembered that there are heat losses associated with
the refinery where the oil was refined.
Water consumption and aqueous effluents (other than sludge), which
in many cases are of major environmental concern, were not considered. Water
consumption would consist of evaporation, drift loss, and blowdown from
cooling towers and boilers, and scrubber consumption while aqueous effluents
would consist of blowdown and drift losses. Since steam production is the
same in all cases considered, water consumption and major water effluents
would be the same except for that water used in the flue gas scrubber systems.
The water consumption in these systems was not estimated.
8.2.2 General Approach to the Environmental Analysis
The designs and fuels used in the economic analysis of steam
production were also used for the environmental assessment. The environmental
emission factors to be considered were then determined as reported in^8.A.
Available information was collected concerning emissions from the various
units studied. "Best" estimates were then made of the quantity of each
pollutant emitted on a Ib/MBTU basis and on total pounds per day.
Use was then made of the comparative quantity of each pollutant
emitted to determine the relative differential impacts of the various
technologies and fuels in two Air Quality Control Regions (AQCR s) based on
the "most probable" degree of FBC applications. The differential impact
approach was selected as being more meaningful than an absolute basis due
to the large masking effects of mobile sources and power plant emissions.
Possible environmental consequences of regeneration and the
environmental aspects of solids waste utilization were then addressed
and other environmental aspects of FBC were discussed. Finally,
conclusions and recommendations were given.
8.3 Bases and Assumptions
In this section, the bases used in the evaluation are discussed
in more detail, the assumptions that had to be made are pointed out and
discussed, and qualifications of the results are given.
-------
- 122 -
8.3.1 Description of Operating Units
As indicated previously, the environmental analysis was carried out
assuming the same operating units and fuels used in the economic studies.
Also, the same steam producing capacity, 100 KPPH, was assumed. The
design of the FBC boiler is, of course, conceptual (atmospheric pressure
operation) and the data used to estimate emissions was obtained from varioifs
sources which may or may not be exactly compatible with the present design.
This is unavoidable since all required information was not available from a
single source. It is felt, however, that the pertinent data are sufficiently
insensitive to operating parameters that the conclusions would not be signifi-
cantly changed with a different design. In a couple of cases this may not
be true and these will be pointed out.
8.3.2 Descriptions of Fuels Considered
As previously indicated, the fuels assumed for use were the same
in the economic and environmental studies. The rationale for choosing the
particular types of fuels was given in Section 8.2. The choice of the
actual fuel with each type was made on the basis of ready availability of
data on the fuel or availability of data on the use of the fuel in a particular
operating unit. The fuels selected are described below.
High Sulfur Coal
The high sulfur coal chosen was a commercially available Illinois
No. 6 coal. Its analyses and properties as well as those for the ash are
given in Table 8-3.
Low Sulfur Western Coals
The low sulfur western coal chosen that meets current EPA regulations
was a typical low sulfur, Wyoming coal. Its properties as well as those of its
ash are given in Table 8-4.
The lower sulfur western coal chosen was San Juan sub-bituminous coal,
used previously by Argonne National Laboratory (ANL) in an FBC experiment (2).
The sulfur content of this San Juan coal was lower than that required to meet
EPA regulations for SOx emissions. The analysis, as reported by ANL, is
reproduced in Table 8-5.
Low Sulfur Fuel Oil
The low sulfur fuel oil was assumed to be a typical residual fuel of
about 20° API gravity with an HHV of 18,600 BTU/lb. No nitrogen or sulfur
content was specified since in the -.environmental studies it was assumed that
sufficient furnace modifications could be effected to allow the NOx emissions
to meet current EPA standards, and that the sulfur content would be sufficiently
low to meet existing standards without further treatment.
8.4 Results for Individual Installations
The base levels of emissions assumed for this study were those that
would just meet present EPA regulations for new point sources (NSPS), as listed
-------
- 123 -
TABLE 8-3
ANALYSIS OF HIGH SULFUR COAL
Cojiljry_p_e_
Total Coal Comp., Wt.%
Carbon
Hydrogen
Oxygen-
Nitrogen
Chlorine
Sulfur
Ash
Moisture
Total
Illinois No. 6
57.
4.
7.
1.5
0.2
3.6
8.0
16.9
100.0
HHV (Btu/ff)
Ash Properties
Ash Fusion Temperatures, °F
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid Temp.
Ash Composition, Wt.%
P205
Si02
Fe203
A1203
Ti02
CaO
MgO
so3
K20
Na20
Undetermined
10600
Reducing
2016
2200
2227
2352
Oxidizing
2292
2445
2469
2588
-------
- 124 -
TABLE 8-4
ANALYSIS OF LOW SULFUR
COAL MEETING EPA REGULATIONS
Coal Type
Total Coal Composition, Wt.%
Carbon
Hydrogen
Oxygen
Nitrogen
Chlorine
Sulfur
Ash
Moisture
Total
HHV (Btu/#)
Ash Properties
Ash Fusion Temperatures, °F
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid Temp.
Ash Composition, Wt.%
Si02
Fe203
A1203
Ti02
CaO
MgO
so3
K20
Na20
Undetermined
Wyoming
47.7
3.3
12.1
0.7
0.4
5.8
30.0
100.0
8150
Reducing
2100
2110
2120
2130
Oxidizing
2175
2180
2185
2190
0.60
34.63
5.99
14.90
1.01
19.96
4.49
16.92
0.18
1.04
0.28
100.00
-------
- 125 -
TABLE 8^5
ANALYSIS OF LOW SULFUR WESTERN COAL WITH SULFUR CONTENT
EXCEEDING EPA REGULATIONS (FROM RfiF'.' 4)
Coal Tyjae
Moisture
Ash
Volatile Matter
Fixed Carbon
Sulfur, wt%
Heating Value, Btu/lb
San Juan Sub-bituminous
Proximate Analysis, wt%
As Received Dry Basis
9.28
16.96
33.28
40.48
100.00
0.78
9,621
18.70
36.68
44.62
100.00
0.86
10,605
Ultimate Analysis, wt%
As Received Dry Basis
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen, by diff.
9.28
55.82
3.96
1.14
0.10
0.78
16.96
11.96
100.00
-------
- 126 -
in Table 8-6. The assumption is that all systems will be operated with
emissions up to the levels permitted by the NSPS (except in cases where
emissions would be inherently lower due to coal composition). However,
such compliance would result in differences in emissions relative to
operation with low sulfur fuel oil. These points are illustrated on an
absolute and on a relative basis in Tables 8-7 and 8-8 respectively.
8.4.1 Estimates of Particulate Emissions
It was assumed in this study that appropriate means (e.g. enclosed
storage, proper wetting of solids, bag houses where necessary, etc.) would be
taken to prevent fugitive emissions of particulates. Therefore the values given
in Tables 8-7 and 8-8 represent stack emissions. The value for the spreader
stoker/Illinois No. 6 case was estimated from data contained in reference 3.
Since this data is from a commercial size plant, the value calculated is
assumed to be fairly accurate. No data was available for the spreader
stoker/San Juan case so it was assumed that this value would be the same
as for the Illinois No. 6 case. It is recognized that this assumption is
questionable, because it is the scrubber that is controlling both SOx and
particulate emissions in the Illinois No. 6 case whereas the low sulfur
San Juan coal might be burned without the need for a scrubber. In this
case particulate control would probably be provided by an electrostatic
precipitator, and emissions would be the maximum permitted by EPA's New
Source Performance Standards (NSPS).
For the Illinois No. 6, Wyoming, and San Juan sub-bituminous coals,
fired in the FBC, the particulate level was controlled by an electrostatic
precipitator and was set by economic considerations, i.e. at the maximum
permissible emission level provided by NSPS.
8.4.2 Estimates of S02 Emissions
The values of S02 emissions were calculated as previously indicated.
The S02 from the Wyoming coal represents that from the sulfur in the coal. No
attempt was made to correct the value for ash retention since the value is
significantly below 1.2 Ib S02/M BTU and there is no scrubber effluent that
is affected.
For Illinois No. 6 coal, fired in the FBC, the level of SC>2 emissions
is determined by the Ca/S atomic ratio fed to the bed and was set at the
maximum level permitted by NSPS in order to minimize costs. For the spreader-
stoker, the S02 level was also set at the maximum value to minimize costs. As
discussed in Section 2.3.1 and reported in Table 2-2, the Ca/S ratios assumed
were 3 for FBC and 1.2 for the spreader-stoker/scrubber case.
8.^ 3 Estimates of NOx Emissions
For the FBC/Illinois No. 6 case the NOx emissions were estimated
from the Pope, Evans and Robbins data in Figure 7 of reference 4. The
other values of NOx emissions were assumed as discussed below.
For the spreader stoker, the level of NOx is determined by furnace
design and was set at the maximum allowable; this is a reasonable goal as
determined by recent studies of such furnaces for steam generation using
coals similar to Illinois No. 6 (5), (6).
-------
TABLE 8-6
Fuel
Boiler Type
NOx, Ib/M Btu
S02, Ib/M Btu
Particulates, Ib/M Btu
QUANTITIES OF EMISSIONS ARBITRARILY
Illinois
FBC
<0.7
1.2
0.1
No. 6 Coal
Spreader Stoker
0.7
1.2
0.1*
SET (100
San Juan
FBC
<0.7
Low
o.i
KPPH steam)
Sub-bituminous Coal
Spreader Stoker
0.7
Low
0.1**
Wyoming Coal
Spreader Stoker
0.7
-
0.1
Low S
Fuel Oil
Package
0.3
0.8
nil
actual emission likely to be lower due to ability of scrubber system to reduce particulates (see Footnote to
Table 8-7).
**would be lower than 0.1 Ibs/M BTU if a scrubber is used, as assumed in Table 8-7. Otherwise, with an
electrostatic precipitator, the 0.1 Ibs/M BTU figure would apply since the design objective would be to
meet EPA's New Source Performance Standards at minimum cost.
-------
TABLE 8-7
Fuel
Fuel Rate (t/d)
Boiler Type
S02 Control
Partlculate Control
Solid Waste Type
Solid Waste, t/d
Stack Emissions
Particulates
Emission Standard,
Ib/MBTU
Actoal Level, Ib/MBTU
Actual Level, Ib/day
NOx (as N02)
Emission Standard,
Ib/MBTU
Actual Level, Ib/MBTU
Actual Level, Ib/day
S02
Emission Standard,
Ib/MBTU
Actual Level, Ib/MBTU
Actual Level, Ib/day
ESTIMATED EMISSIONS
FOR INDIVIDUAL INSTALLATIONS AND FUELS
(Basis: 100,000 Ib/hr, 125 psig saturated steam)
Illinois
144
FBC
FBC
cyclones/ESP
sulfated stone/ash
55
0.1
300
6.5
1500
1.2
3700
No. 6 Coal
144
Spreader Stoker
Limestone Scrubber
eye lones / scrubber
sludge/ash
66
0.05*
150
0.7
2100
1.2
3700
San Juan Sub-bituminous Coal
156
FBC
FBC
cyclones/ESP
sulfated stone/ash
30
0.1
300
<0.5**
<1500
— _ 1 9 __ ,_. —
0.8***
2400
156
Spreader Stoker
Limestone Scrubber
cyclones /scrubber
sludge/ash
44
0.05*
150
0.7
2100
1.0***
3000
Wyoming Coal
187
Spreader Stoker
Not Needed
cyclones/ESP
ash
11
0.1
300
0.7
2100
0.65***
2000
Low S Fuel Oil
82
Package
Not Needed
None
nil
Oil
nil
nil
0.3
900
00
0.8
2400
*Below NSPS due to inherent ability of limestone scrubber to reduce particulate level.
**Below NSPS due to inherent ability of FBC system to minimize NOx emissions.
***Below NSPS due to low sulfur content of coal.
-------
TABLE 8-8
Fuel
Boiler Type
Increase in
Emissions
Solid Waste, t/d
NOx, Ib/d (as N02)
S02, Ib/d
INCREASED EMISSIONS
(Basis:
Illinois No. 6 Coal
CAUSED BY SHIFTING FROM LOW-SULFUR
100,000 Ib/hr
San Juan
FBC Spreader Stoker FBC
55 66
600 1,200
1,300 1,300
30
<600
0
saturated steam)
Sub-bituminous Coal
Spreader Stoker
44
1,200
600
FUEL OIL
Wyoming Coal
Spreader Stoker
11
1,200
(400)*
Particulates,
Ib/d
300
150
300
150
J
N3
I
300
*Numbers in parenthesis indicate a reduction in emissions relative to emissions with LSFO. (The base-case,
low-sulfur fuel oil was assumed to contain levels of sulfur and nitrogen that would meet present EPA
standards. The quantities of particulates are negligible.)
-------
- 130 -
For the low sulfur coals, the NOx level for the spreader stoker
was assumed at 0.7, as in the case of the Illinois No. 6 coal, although no
data is now available on NOx levels when sub-bituminous coals *i-e used in
boilers of the size considered here.
8.4.4 Estimates of Solid Wastes
For the high-sulfur Illinois No. 6 coal, considerable information
is available from numerous sources as to the Ca/S ratio required to hold
the S02 exit concentration to 1.2 Ib/M Btu. (See, for example, references 2
and 7.) Thus, it is believed that the estimate of the quantity of solid
waste is fairly accurate. Similarly, considerable commercial operating
experience allowed an accurate estimate of the solid waste from the spreader
stoker.
For the cases where San Juan sub-bituminous coal was used as fuel,
the quantities of solid waste are less certain. For the FBC, one experiment
on this coal has been reported (2), showing that the addition of a Ca/S
ratio of 1.1 gave a sulfur retention of 72%. For this particular coal,
assuming the percent retention is proportioned to the Ca/S ratio, only a
ratio of 0.4 is necessary to meet the 1.2 Ib S02/M BTU. It was felt,
however, that the FBC would not be operable with this low ratio, but that
the bed could be maintained at a Ca/S ratio of about 0.8. This would,
again assuming the proportionality of percent retention and Ca/S ratio,
give a retention of about 50%. This results in the emissions of about
0.8 Ib S02/MM BTU which is lower than present standards, and is comparable
to the use of low sulfur fuel oil.
Similarly, little information exists as to the operation of a
spreader stoker of the size assumed in this study with a limestone scrubber.
It is generally recognized that burning high calcium western coals in larger
boilers at higher temperatures can result in the retention of part of the
sulfur in the ash. A nominal value of 5% is accepted by some people. No
such information is available for smaller spreader stoker boilers. It would
be expected that the lower temperatures in these units would result in a
greater sulfur retention. For this study the figure of 5% was used for
lack of a better number. For scrubbing the stack gas it was assumed that,
for proper operation of the scrubber, a 20% excess of CaC03 over the stoichio-
metric requirement would be used and that the emission of 862 would be reduced to
1.0 Ib/MM Btu. This resulted in the quantity of ash/sludge given in Table 8-7.
For the case of the Wyoming coal, the solids effluent consists
only of the ash in the coal since no scrubber is necessary. The solids
from the low sulfur fuel oil reference case are negligible.
8.5 National and Regional Emissions
Estimates of the emissions associated with the use of coal-fired FBC
technology in industrial boilers are based on:
(1) the unit emissions for point sources (see Table 8-7)
(2) the market potential estimated for coal-fired FBC (see Table 5-2).
-------
131 -
Calculation of unit emissions is based on the assumed use of high
sulfur coal, with Illinois No. 6 taken as a representative coal. The emissions
are also estimated on an incremental basis relative to low sulfur fuel oil
(LSFO), where the sulfur content just meets the Federal standard for new
point sources. When LSFO is used, the solid waste and particulate emissions
are neglible. Hence, the incremental and absolute estimates of solid waste
and particulate emissions are the same.
Estimates of nationwide emissions are presented in Table 8-9 for
maximum, most probable, and minimum cases. Corresponding estimates of emissions
on a regional basis, for the most probable case, are presented in Table 8-10.
These estimates pertain only to the use of high sulfur coal in industrial FBC
boilers. They do not include estimates of emissions associated with the use
of compliance coal in FBC boilers, since insufficient technical data are
available for such estimates.
8.6 Estimates of Emissions for Selected Air Quality Control Regions
8.6.1 Current Situation: Mass Emissions
Air Quality Control Regions (AQCR's) were selected in Texas and
Illinois in order to obtain comparisons between regions where currently:
(1) the industrial consumption of coal is minimum (Texas)
(2) there is a significant use of high sulfur (local) coal in industrial
boilers (Illinois).
Current data for the state of Texas and the Metropolitan Houston-
Galveston area (AQCR 216) are presented in Tables 8-11 and 8-12 . The data are
from EPA's National Emissions Data System.* It will be seen that industrial
boilers were minor contributors to the total emissions of the state of Texas
relative to similar emissions from other sources such as industrial processes
and land vehicles. On a relative basis, the percentage levels were slightly
higher for the Houston-Calveston AQCR, particularly with respect to NOx. In
general, however, it is apparent that industrial_boilers are not the principal
source of emissions that affect ambient air quality.
Initially, it was not known which of the AQCR's in Illinois would
yield the most meaningful information. Accordingly, NEDS data were obtained
for three of the intrastate regions:
- West Central Illinois (AQCR 075; selected for further study)
- Southeast Illinois (AQCR 074)
- North Central Illinois (AQCR 071)
hT^rTinent state emissions and AQCR.eMssions reports were computer-generated
by EPA on 3/1/76 specifically for use in the present £g*' ™ dat£ back
estimates for individual sources of emissions in the NtUb aa
as far as 1970,'
-------
TABLE 8-9
ESTIMATES OF EMISSIONS ASSOCIATED WITH USE OF COAL-FIRED FBC IN INDUSTRIAL BOILERS
Emissions in Million Tons per Year Incremental Emissions Versus LSFO*
• Maximum Potential
1980
1985
1990
1995
2000
Sol. Waste
0.36
11.1
34.4
57.3
99.0
Partic.
0.001
0.030
0.094
0.157
0.271
NOx
0.005
0.152
0.471
0.784
1.35
SO?
0.012
0.377
1.17
1.95
3.36
Sol. Waste
0.36
11.1
34.4
57.3
99.0
Partic.
0.001
0.030
0.094
0.157
0.271
NOx
0.002
0.061
0.189
0.315
0.544
SO?
0.004
0.132
0.41
0.68
1.18
• Most Probable Potential
1980
1985
1990
1995
2000
• Minimum Potential
1980
1985
1990
1995
2000
0.16
4.7
16.1
27.4
48.2
nil
1.3
5.3
9.7
17.9
0.0004
0.013
0.044
0.075
0.132
nil
0.004
0.014
0.027
0.052
0.002
0.064
0.220
0.375
0.660
nil
0.018
0.072
0.133
0.245
0.005
0.157
0.547
0.931
1.64
nil
0.045
0.179
0.330
0.609
0.16
4.7
16.1
27.4
48.2
nil
1.3
5.3
9.7
17.9
0.0004
0.013
0.044
0.075
0.132
nil
0.004
0.014
0.027
0.052
0.0009
0.026
0.089
0.151
0.265
nil
0.007
0.029
0.053
0.099
0.002
0.056
0.192
0.326
0.574
nil
0.016
0.063
0.116
0.213
I
M
LO
1
*Low Sulfur Fuel Oil. The increment in "environmental insult" vs. LSFO may be overstated since some
FBC units would probably replace conventional coal-fired boilers.
Possible additional uses, such as a higher level of captive generation of electricity at manufacturing
plants, are excluded from the above estimates.
Also excluded are estimates of emissions associated with the use of compliance coal in industrial
FBC boilers, since insufficient technical data are available. As a rough approximation, the estimates
for the most probable case may be increased by 10% to account for such use.
-------
- 133 -
TABLE 8-10
ESTIMATES OF EMISSIONS ASSOCIATED WITH USE OF COAL-FIRED FBC IN
INDUSTRIAL BOILERS ON REGIONAL BASIS (MOST PROBABLE CASE. CONVENTIONAL US
1990, Most Probable Case. 1000 T/yr of Emissions
Appalachian
Southeast
Great Lakes
Northern Plains
Mid-Continent
Gulf Coast
Rocky Mountain
Pacific Northwest
Pacific Southwest
Sol. Waste Partic.
4150
3650
3740
110
500
3430
150
220
150
NOx
SOi
11.3
10.0
10.2
0.3
1.4
9.4
0.4
0.6
0.4
56.8
49.9
51.0
1.5
6.8
46.9
2.0
3.1
2.0
£,
141
124
127
4
17
116
5
8
5
• 1995, Most Probable Case, 1000 T/yr of Emissions
Appalachian 7040 19.3 46 239
Southeast 6250 17.1 85 212
Great Lakes 6360 17.4 87 216
Northern Plains 190 0.5 3 7
Mid-Continent 850 2.3 12 29
Gulf Coast 5750 15.8 79 196
Rocky Mountain 300 0.8 4 10
Pacific Northwest 360 1.0 5 12
Pacific Southwest 300 0.8 4 10
2000, Most Probable Case. 1000 T/yr of Emissions
Appalachian 12400
Southeast 10900
Great Lakes 11200
Northern Plains 300
Mid-Continent 1500
Gulf Coast 10100
Rocky Mountain 600
Pacific Northwest 600
Pacific Southwest 600
33.9
30.0
30.7
0.9
4.1
27.7
1.5
1.7
1.5
170
150
154
5
20
139
7
8
7
422
372
383
11
51
344
18
21
18
Increment over LSFO
NOx
23.0
SO
20.
20.
0.
2.
19.0
0.8
1.2
0.8
39
34
35
1
5
31
2
2
2
68
60
62
2
8
56
3
3
3
•2-
49
43
45
1
6
41
2
3
2
84
74
76
2
10
68
4
4
4
148
130
134
4
18
121
6
7
6
Notes: (1) The estimates of solid waste and particulate emissions apply to both
absolute levels of emissions and to the increment relative to low
sulfur fuel oil.
(2) The estimates do not include the use of compliance coal in industrial
FBC boilers, because insufficient technical data are available. As
a rough approximation, the national estimates may be increased by
10% to account for this use. Much of this use could occur in the
Gulf Coast region.
-------
TABLE 8-11
Source of Emission
Residential
Commercial/Institutional
Land Vehicles
Other Transportation
Solid Waste Disposal
Electric Utilities
Miscellaneous
Industrial Processes
Industrial Boilers
Total
ANNUAL EMISSIONS ESTIMATED FOR STATE OF
TEXAS
1000 Tons Per Year
SOx
0.3
11.1
35.3
18.0
14.3
53.8
7.3
620.3
40.3
800.6
NOx
11.6
20.1
624.1
56.9
4.9
372.4
167.3
130.0
200.5
1587.9
Particulates
1.5
4.1
61.3
63.9
17.1
20.0
14.1
406.8
19.5
608.3
SOx
negl.
1.4
4.4
2.2
1.8
6.7
0.9
77.6
5.0
100
% of
NOx
0.7
1.3
39.3
3.6
0.3
23.5
10.5
8.2
12.6
100
Total
Particulates
0.2
0.7
10.1
10.5
2.8
3.3
2.3
66.9
3.2
100
I
t—
Source: National Emissions Data System, State Emissions Report, Emissions as of 3/1/76.
-------
TABLE 8-12
Source of Emission
Residential
Commercial/Institutional
Land Vehicles
Other Transportation
Solid Waste Disposal
Electric Utilities
Miscellaneous
Industrial Processes
Industrial Boilers
Total
AQCR as % of Texas
All Sources
Land Vehicles
Industrial Boilers
ESTIMATED FOR METROPOLITAN HOUS:
SOx
0.03
2.0
5.7
3.3
3.5
8.2
0.1
148.0
18.5
189.4
24
16
46
1000 Tons
NOx
1.2
4.0
104.7
12.7
1.1
113.5
3.1
63.4
84.4
388.1
24
17
42
Per Year
Particulates
0.2
0.6
10.6
2.3
3.5
2.3
3.2
81.3
3.8
107.7
18
17
20
% of Total
SQx NOx Particulates
negl. 0.3 0.2
1.1 1.0 0.6
3.0 27.0 9.8
1.7 3.3 2.1
1.8 0.3 3.2
4.3 29.2 2.1
0.1 0.8 3.0
78.2 16.3 75.5
9.8 21.8 3.5
100 100 100
Un
!
Source: National Emissions Data System, AQCR Emissions Report, Emissions as of 3/1/76.
-------
- 136 -
Of these three AQCR's, West Central Illinois appeared the best
choice for the present study because of its mix of industrial plants and
other emission sources.* NEDS data for the state of Illinois and for
AQCR 075 are presented in Tables 8-13 and 8-14. As in the cases of the
state of Texas and the Houston-Galveston AQCR, it will be seen that
industrial boilers are a relatively minor factor in ambient air quality
in Illinois. Particulate emissions are somewhat higher than expected in the
West Central Illinois AQCR (#075). The explanation is not known, but it is
possible that the current situation reflects an insufficient use of
electrostatic precipitators, i.e. there may be a number of existing
industrial boiler installations that do not meet Federal standards for
new point sources. This may also be the case for NOx and S02 emissions,
although no supporting data are available. If this is so, it seems possible
that application of coal-fired FBC to industrial boilers could reduce the
total emissions of particulates, NOx and S02 as facilities complying with
Federal standards gradually replace installations that are not in compliance
now.
The counties included in the selected AQCR's are listed in Table 8-15,
while their geographical location is shown in Figures 8-1 and 8-2.
8.6.2 Current Situation: Ambient Air Quality
In accordance with requirements of the Clean Air Act and EPA
Regulations for State Implementation Plans (SIP's), (13), ambient air quality
data resulting from air monitoring operations of State, local, and Federal
networks must be reported each calendar quarter to the Environmental
Protection Agency. The EPA Storage and Retrieval of Aerometric Data (SAROAD)
format, (14), is the established medium for transmittal of air data to EPA
Regional Offices within 45 days after each reporting period. EPA Regional
Offices must, within an additional 30 days, forward data they have received
to the EPA National Aerometric Data Bank (NADB), of which the SAROAD system is
an operational part. The NADB is managed by the National Air Data Branch,
Monitoring and Data Analysis Division of the OAQPS. In a continuing effort
to provide these data to participating agencies as well as to the public,
EPA periodically publishes a summary of all data submitted, e.g. references
(15) and (16). Statistics drawn from these references were used as an
indication of current ambient air quality i'r AQCR 216 and AQCR 075. In fact,
the analytical measurements were made in 1973 and 1974. The data relate to
sampling and analysis performed at two locations. Three laboratories are
housed at the Houston location.
• AQCR 216 810 Bagby Street, Houston, Texas
- EPA Regional Office (001 P01)
- EPA Atmospheric Surveillance Office (001 A01)
- Houston Health Department (001 HOI)
• AQCR 075 224 West Adams Street, Springfield, Illinois
- State of Illinois EPA (003 F01)
*However, substantially the same conclusions would have been reached if either
of the other two Illinois AQCR's had been selected.
-------
TABLE 8-B
Source of Emission
Residential
Commercial/Institutional
Land Vehicles
Other Transportation
Solid Waste Disposal
Electric Utilities
Industrial Processes
Industrial Boilers
Total
ANNUAL EMISSIONS ESTIMATED FOR STATE OF ILLINOIS
1000 Tons
SOx
68.1
44.7
23.8
2.3
6.3
1998.2
91.4
383.6
2618.5
NOx
25.5
35.5
436.2
11.5
12.7
631.1
29.1
129.9
1311.6
Per Year
Particulates
16.2
19.9
44.7
2.4
53.7
232.5
409.4
152.3
931.1
SOx
2.6
1.7
0.9
0.1
0.2
76.3
3.5
14.7
100
% of
NOx
1.9
2.7
33.3
0.8
1.0
48.2
2.2
9.9
100
Total
Particulates
1.7
2.1
4.8
0.2
5.8
25.0
44.0
16.4
100
U)
—J
Source: National Emissions Data System, State Emissions Report, Emissions as of 3/1/76.
-------
TABLE 8-14
ANNUAL
EMISSIONS ESTIMATED
FOR WEST CENTRAL ILLINOIS (AQCR 075)
1000 Tons Per Year
Source of Emission
Residential
Commercial/ Institutional
Land Vehicles
Other Transportation
Solid Waste Disposal
Electric Utilities
Miscellaneous
Industrial Processes
Industrial Boilers
Total
ACQR as % of Illinois
All Sources
Land Vehicles
Industrial Boilers
SOx
4.2
4.9
1.6
0.2
0.3
399.1
-
negl.
33.6
444.0
17
7
9
NOx
1.2
1.9
32.5
1.0
0.9
139.4
-
negl.
8.0
184.9
14
7
6
Particulates
1.0
2.6
3.4
0.2
3.5
22.8
-
32.1
26.1
91.7
10
8
17
SOx
1.0
1.1
0.4
negl.
0.1
89.8
-
negl.
7.6
100
% of
NOx
0.6
1.0
17.6
0.5
0.5
75.5
-
negl.
4.3
100
Total
Particulates
1.1
2.8
3.7
0.2
3.8
24.9
-
35.0
28.5
100
H-1
U>
CO
Source: National Emissions Data System, AQCR Emissions Report, Emissions as of 3/1/76.
-------
- 139 -
TABLE 8-15
COUNTIES INCLUDED IN SELECTED AQCR's
West Central Illinois Intrastate (AQCR 075)
Counties:
Adams
Brown
Calhoun
Cass
Christian
Greene
Jersey
Logan
Macon
Macoupin
Menara
Montgomery
Morgan
Pike
Sangaraon
Schuyler
Scott
Metropolitan Houston-Calveston Intrastate (AQCR 216)
Counties: Austin Galveston Walker
Brazonia Harris Waller
Chambers Liberty Wharton
Colorado Matagorda
Fort Bend Montgomery
-------
AMARILLO
LUBBOCK
INTRASTATE
METROPOLITAN
DALLAS-
FORT WORTH
1NTRASTATE
SHREVEPORT-
TEXARKANA-
TYLER
INTERSTATE
(ARKANSAS-
LOUISIANA-
OKLAHOMA-
TEXAS)
ABILENE-
WICHITA FALLS
INTRASTATE
MIDLAND-
ODESSA-
SAN ANGELO
IHTRASTATE
EL PASO-
LAS CRUCES-
ALAMOGORDO
INTERSTATE
(TEXAS-
NEW MEXICO)
SOUTHERN
LOUISIANA-
SOUTHEAST
TEXAS
INTERSTATE
AUSTIN-
WACO
INTRASTATE
M
00
I
I-1
I
I-1
o
I
METROPOLITAN
SAN ANTONIO
INTRASTATE
METROPOLITAN
HOUSTON-
GALVESTON
INTRASTATE
BROWNSVILLE'
LAREDO
INTRASTATE
CORPUS-CHRIST! •
VICTORIA
INTRASTATE
T-E.P
Air Quality Control Regions In Texas.
-------
- 141 -
FIGURE 8-2
METROPOLITAN
DUBUQUE
INTERSTATE
(IOWA-
ILLINOIS-
WISCONSIN)
METROPOLITAN
QUAD
CITIES
INTERSTATE
(ILLINOIS-
IOWA)
BURLINGTON
KEOKUK
INTERSTATE
(IOWA-
ILLINOIS)
ROCKFORD-
JAfoESVILLE-
BELOIT
INTERSTATE
(ILLINOIS-
WISCONSIN)
METROPOLITAN
CHICAGO
INTERSTATE
(ILLINOIS-
INDIANA)
NORTH
CENTRAL
WEST CENTRAL-
ILLINOIS
INTRASTATE
ILLINOIS
INTRASTATE
•EAST
CENTRAL
ILLINOIS
INTRASTATE
METROPOLITAN
ST. LOUIS
INTERSTATE
(LLINOIS-
IKISSOUR!)
SOUTHEAST
ILLINOIS *"
INTRASTATE
PADUCAH-
CAIRO
INTERSTATE
(KENTUCKY-
ILLINOIS)
Air Quality Control Regions in Illinois.
-------
- 142 -
Pertinent measurements of ambient air quality were:
Micrograms per Cubic Meter, yg/cu.m., Annual Basis
Particulates SC>2 N02
(Geometric Mean) (Arithmetic Mean) (Arithmetic Mean)
AQCR 216 81* 4** 75***
AQCR 075 65* 25** 21***
NAAQS Primary Std. 75 80 100
Detailed discussion of the reported ambient air quality measurements
is beyond the scope of this study. However, it should be pointed out that the
nationwide reports exhibit variability among test methods, evidence of statistical
or analytical errors, and problems associated with computer generated reports.
While effort was made to extract statistics representative of the air quality
conditions in AQCR's 216 and 075, the numbers reported should be taken as
illustrative rather than as precise. For example, the reported particulate
level of 81 yg/cu.m. for AQCR 216 exceeds the primary standard of 75 yg/cu.m.
Other sample points within the AQCR report both higher and lower values.
Hence, the geometric mean of 81 yg/cu.m. should probably be taken as an
indication that the Houston-Galveston area has a potential problem with
particulates rather than as categorical evidence that the area is not in
compliance with an NAAQS primary standard. Analogously, even though the
arithmetic mean of 75 yg/cu.m. N02 is below the primary standard of 100 yg/cu.m.
the relatively high observed level may be taken as an indication of an
incipient problem. On the other hand, reported sulfur dioxide levels in
AQCR 216's ambient air are at the very low level of 4 yg/cu.m. which is
appreciably below the primary standard of 80 yg/cu.m. Undoubtedly, the low
level reflects the extensive use of natural gas in the Houston area.
Corresponding measurements for AQCR 075 indicate a borderline situation for
particulates and comfortable margins below the primary standards for both
S02 and N02.
8.6.3 Future Situation: Mass Emissions
Estimates of emissions, related to coal-fired FBC industrial boiler
technology, for Metropolitan Houston-Galveston (AQCR 216) and West Central
Illinois (AQCR 075) may be derived from:
(1) Table 3-6 which indicates that the states of Texas and Illinois account,
respectively, for 58.9% and 29.4% of the pertinent industrial boiler
capacity in the Gulf Coast and Great Lakes regions.
(2) Tables 8-12 and 8-14 which indicate that AQCR 216 and AQCR 075 account
respectively, for about 45% and 8% of the pertinent state totals of
industrial boiler emissions.****
(3) Table 8-10 which provides regional estimates of emissions associated
with the most probable coal-fired FBC potential.
*Test Method: Hi-Vol Gravimetric, 24 hours.
**Test Method: Gas Bubbler para-rosaniline sulfamic acid, 24 hours.
***Test Method: Gas Bubbler sodium arsenite, frit, 24 hours.
****based on S02 and N02 emissions.
-------
- 143 -
Applying the appropriate percentages for (1) and m =
factors to the pertinent numbers in Table 8-10 yields estiJtl o
associated with the potential future use of coal-fired ?Bc"n!0CR
AQCR 075. These estimates are recorded in Table 8-16* Presenflev of
Unfortunately, no estimates of future mass emissions from all**
sources are available for AQCR's 216 and 075. Hence, it is necessary to
relate the estimates of incremental emissions from coal-fired FBC boilers
with the current levels of particulate, S02 and NO- emissions in the
selected AQCR's: L
Estimated Increment to Mass Emissions
Attributable to Coal-Fired FBC Industrial Boilers
as a % of Current Emissions from All Sources _
AQCR 216 Particulates S02 NO?
1980 negligible negligible negligible
1990 223
2000 7 5 10
AQCR 075
1980 negligible negligible negligible
1990 0.3 0.7 0.7
2000 0.8 2 2
The above estimates suggest that coal-fired FBC industrial boilers
will not be major contributors to air emissions in either of the selected
AQCR's. On the other hand, any increment to emissions would be expected
to exacerbate the situation in a region such as Houston-Galveston where
current emission levels are approaching the NAAQS primary standards (for
particulates and N02) . This is discussed further below.
8.6.4 Future Situation: Ambient Air Quality
The previously discussed mass emissions projected for coal-fired FBC
industrial boilers were converted by proration to absolute increments to pollutants
in the ambient air in the selected AQCR's. The simple proration procedure has the
effect of assuming that all of the incremental mass emissions stay within the
AQCR in which they are generated. Because some dispersion will occur, the assumption
leads to what may be considered as a "worst increment" to degradation of ambient
air quality.
'excluding the emissions associated with the use of compliance coal in
AQCR 216, since insufficient technical data are available to make such
estimates.
**i.e. for all sources other than large industrial boilers.
-------
.- 144 -
TABLE 8-16
ESTIMATES OF EMISSIONS IN AQCR 216 AND AQCR 075 ASSOCIATED
WITH POTENTIAL USE OF COAL-FIRED FBC IN INDUSTRIAL BOILERS
Metropolitan Houston-Galveston (AQCR 216), Most Probable Case
1000 Tons Per Year of Emissions from FBC Industrial Boilers
Solid Waste
9
262
909
1520
2680
Particulates
0.02
0.72
2.5
4.2
7.3
S02
0.28
9
31
52
91
N0?
0.11
3.6
12
21
37
Solid Waste
0.9
26
88
149
260
Particulates
0.002
0.07
0.24
0.41
0.72
S02
0.03
0.87
3.0
5
9
NOo
0.01
0.35
1.2
2.Q
3.6
1980
1985
1990
1995
2000
* West Central Illinois (AQCR 075), Most Probable Case
1000 Tons Per Year of Emissions from FBC Industrial Boilers
1980
1985
1990
1995
2000
• Present Emission Levels* (see Tables 8-11 and 8-13)
- From Industrial Boilers
1000 Tons Per Year of Emissions
Solid Waste Particulates S02
AQCR 216 not applic.** 3.8 18.5
AQCR 075 not applic.** 26.1 33.6
- From All Sources Within AQCR
AQCR 216 not applic.** 107.7 189.4 388.1
AQCR 075 not applic.** 91.7 444.0 184^9
*NEDS estimates
**solid waste disposal in current NEDS system does not apply to FBC solid wastes
since FBC technology is not in use.
i excluding use of compliance coal.
-------
- 145
TABLE 8-17
ESTIMATED INCREMENTS TO AMBIENT AIR POLLUTION ASSOCIATED
WITH COAL-FIRED FBC INDUSTRIAL BOILERS
• Metropolitan
1985
1990
1995
2000
Current Level
AQCR
Houston-Galveston (AQCR
Estimated FBC
Particulates
0.6
1.8
3.2
5.5
in
81
Primary Standard 75
216)
Increment,
SO 2
0.2
0.6
1.1
1.9
4
80
Ug/cu.m.
NQ2
0.7
2.3
4.1
7.1
75
100
West Central Illinois (AQCR 075)
1985
1990
1995
2000
Current Level in
AQCR
Primary Standard
0.1
0.2
0.3
0.5
65
75
0.1
0.2
0.3
0.5
25
80
negligible
0.1
0.2
0.4
21
100
-------
- 146 -
For the Houston-Galveston region, the projected emissions from coal-
fired FBC industrial boilers are not expected to add large increments of
participates, S02 or N02 to the ambient air. Nevertheless, in the case of
both particulates and N02, the impact may be of practical significance because
the current level of air quality is marginal and, hence, any incremental
pollution will make NAAQS more difficult to achieve and/or maintain. However,
the increments associated with FBC industrial boilers assume further industrial-
ization of AQCR 216. If this industrialization occurs, there will be problems
in meeting current NAAQS regardless of the technology applied to industrial
boilers. The difficulty lies in the current emission levels not with FBC
as a control technology. In fact, other technologies for combusting coal
in industrial boilers might well produce larger detrimental increments to
ambient air pollution levels than those estimated for FBC. This is probable
for NOx emissions, but not necessarily the case for particulates. A possible
inference is that to derive maximum environmental advantage from FBC, it may
be necessary to develop extremely effective particulate removal technology.
West Central Illinois has a moderate industrial base but, industrially,
cannot be compared with Houston-Galveston which is the nation's leading
petroleum refining/petrochemical region. The difference in degree of
industrialization is the principal reason why the ambient air quality impacts
associated with FBC industrial boilers are projected to be minimal in AQCR 075.
The increments projected In Table 8-17 are all within the current accuracy of
the test methods for the pollutants in question.
8.7 Disposition of Solids and Sludge
The greatest incremental volumes of emissions on conversion from
natural gas or low sulfur fuel oil to coal will be the solid and/or sludge
streams. From an environmental viewpoint, however, these streams may be of
less concern than other increased emissions such as NOx and S02.
A number of studies have been carried out for EPA covering the
environmental problems connected with solids disposal; among these are
references 8, 9, 10 and 11. Reports in reference 11 were more concerned
with disposal of ash chars and sludges from coal gasification and lique-
faction plants, although in many cases coal fired boilers were assumed.
Reference 8 devotes 19 pages to limestone regeneration as a method of
reducing solids disposal and to a discussion of the environmental problems,
and also five pages to solids disposal and possible environmental problems.
Reference 9 contains 6 pages and twelve further references devoted to these
subjects. Reference 10 contains 35 pertinent pages, eighteen additional
references, and includes original experimental work related to the environment.
Although, as discussed below, conclusions from these references are applicable
to the present study, they do not accurately reflect the on-going efforts on
disposal of solid and sludge wastes. Such efforts include laboratory leaching/
lysimeter tests, low temperature fixation of wastes, and assessment of ocean
disposal.
8.7.1 Solid/Sludge Byproducts
Table 8-18 shows the calculated compositions of the solid waste
streams produced when Illinois No. 6 coal is burned under the conditions
assumed in 8.3 and 8.4.
-------
- 147 -
TABLE 8-18
COMPOSITION OF SOLIDS/SLUDGE FROM
BURNING ILLINOIS NO. 6 COAL
• Basis: 100 KPPH industrial boiler
% in Solids/Sludge
CaO
CaS0
FBC
33
36
Spreader Stoker
10
21
Inert from limestone
Ash
H20
Form of
waste stream
Quantity of waste
stream, T/D
*Sludge will contain small amount of CaS04 oxidized from CaS03, but oxidation rate
at scrubber/settler/filter conditions is low.
Dry, granular
stone/ash mixture
55
24
9
3
18
46
Mixture of wet
scrubber sludge
with boiler ash
66
-------
- 148 -
The quantity of sludge from the spreader stoker/scrubber is somewhat
greater than the solids from the FBC (66 t/d vs. 55 t/d) but the difference in
quantity is not significant from an environmental standpoint. The difference
in form (solid vs. sludge) and composition may be significant depending on
ultimate disposition.
8.7.2 Solids Disposal
The environmental problems of solids disposal from burning coal for
industrial heat generation can be quite different from those connected with
large coal conversion plants (11) or large power generation plants utilizing
coal (12). In the latter two cases, disposal of solids is of such importance
in the original plant design that it may be a factor in determining the
location of the plant. Frequently the solids from such plants can be
returned to the coal mine. Usually the locations of such plants would be
in areas with sufficient available land to allow impoundment of sludges. On
the other hand, the locations of industries that may utilize coal for heating
purposes would probably be determined by other factors. Oil refineries, for
example, are placed in locations where crude oil is easily accessible and
markets are close. Frequently these industries are in areas where land
availability is limited. Solids disposal can then only be effected by carting
the materials away. Thus the immediate environmental problem is solved.
The question then arises as to ultimate disposal of the solids/sludges.
Assuming that dusting problems can be adequately handled the main environ-
mental problems connected with storing the materials in some remote area is
that of leaching of harmful materials and use of land. These problems have
been discussed in a number of references (8-11) . Leaching does occur as
reported in reference 11. However, the problem may be no worse than leaching
of gypsum itself. By proper site selection and mechanical design, both sludges
and solids may be storable indefinitely in landfill sites without representing
a hazard to water supplies. Availability of nearby landfill sites may be a
problem in some locations, and would surely become a general problem if total
U.S. consumption of solid coal increases two to three-fold. Hence, utilization,
rather than disposal, of the "wastes" would appear to be a desirable and necessary
long term goal.
Ocean dumping is another possible solution, although one that
would require very careful control.
8.7.3 Utilization of Solid Wastes
The use of the solids for road fill material has been suggested but
the problem of leaching would have to be examined on a larger scale than has
been done to date to determine the consequences of sulfate and calcium con-
tamination of water supplies.
About 13 percent of the ash produced in 1971 found use in various
applications (9) and some possibilities for the use of FBC solids have been
suggested (9) (10). However, looked at differently, 87% of the ash produced
in 1971 was not utilized — in spite of many years of effort made by the
National Ash Association to find commercial outlets for ash. It appears
that there are institutional as well as technological barriers to ash
utilization and, hence, that utilization efforts will have to be sustained
for a long time.
-------
- 149 -
8.7.4 Regeneration of Treater Material^
Regeneration of the calcium sulfate (sulfites) has been considered
as a method of reducing the quantities of solids to be disposed of and research
work is in progress (8). Insufficient information is available to determine
that regeneration is economically viable. The environmental problems connected
with regeneration will have to be examined to determine if regeneration affects
the environment to a greater extent than impoundment of the total solid wastes.
8.8 Modification of Basis^
As discussed in Section 5.2, new information provided by ERDA in
September 1976 has required re-estimation of the most probable potential for
application of coal-fired FBC technology to industrial boilers. The re-
estimation introduces quantitative uncertainties in the area of "environmental
impacts" and with respect to the combustion of compliance coal in industrial
FBC boilers. The major problem, with respect _to_ this study, is that insufficient
technical data are available for quantification of the emissions associated with
the use of a variety of low sulfur bituminous, sub-bituminous, and lignite
coals in FB boilers.
Qualitatively, we visualize considerable practical advantages in
being able to apply FBC technology to low sulfur coals, as discussed below.
However, with existing technical information, it is not possible to quantify
these advantages. From economic and practical standpoints, FBC technology
may permit:
(1) coals with significant content of alkaline ash to become compliance
coals (whereas they would not be compliance coals if combusted by
conventional technology).
(2) lower emissions of sulfur oxides and, possibly, nitrogen oxides than
would be achievable at comparable cost using conventional technology.
The first of the above possibilities requires at least four factors
to be taken into account in determination of whether a particular coal is
"compliant":
• the sulfur content of the coal
• the ash content of the coal
• the composition of the ash
• the technology by which the coal will be combusted.
The second possibility introduces a fifth factor, namely that the
definition of "compliance" may vary with location and with time. Put dit-
ferently, compliance with New Source Performance Standards (NSPS) may jot be
sufficient in some industrial areas of country which are already at or beyond
ambient air quality standards (NAAQS). Thus, "compliance" may become a variable
that depends'cm the interaction of other f actors. Current informat ion about
these factors is inadequate. Moreover, the ways in which NMQ* a^ °*^
attained (or not attained) are being affected 1* Illative and regulatory
changes, i.e. by non-technological and essentially unpredictable factors.
-------
- 150 -
Available data on sulfur content, ash content, ash composition, and
source of coal are summarized in Figure 8-3 and Tables 8-19 and 8-20. The
stoichiometric ratios of alkali metals to sulfur appear to be most important
because the alkali metals present in the coal can capture sulfur during
combustion — particularly if the coal is combusted in a fluid bed. The
point is made in terms of Ca/S ratio in the last horizontal row of Table 8-20.
8.9 Environmental Conclusions and Recommendations
Using conventional technology, a change from natural gas or oil to
coal-firing would be expected to affect the environment adversely. With FBC
technology, there is a potential for improvement over conventional coal use
technology. Industrial FBC boilers should be able to meet and improve upon
New Source Performance Standards. However, it is improbable that coal-fired
FBC will ever achieve the degree of control possible with natural gas or low
sulfur fuel oil. This is not to the detriment of FBC because it is expected
that natural gas and LSFO will become supply limited before synthetic fuels
are available.
The development of FBC technology will not, of itself, correct
existing problems with ambient air quality. Notwithstanding the potentially
important contributions that may be made by FBC technology to the coal-firing
of industrial boilers in environmentally acceptable ways, such applications
are likely to have a smaller impact on ambient air quality than:
(a) the impact produced by combustion sources other than large
industrial boilers, and -
(b) the impact of emissions from existing coal-fired
equipment in regions that currently use coal to a
significant extent.
The Metropolitan Houston-Galveston Air Quality Control Region
contains the most important industrial area in the nation.* By the year
2000, projected use of FBC technology in large industrial boilers in AQCR 216
could raise levels of ambient air pollution from particulates and NOx by
an increment equal to about 7% of the Primary Ambient Air Quality Standard
for each of these criteria pollutants. The practical significance of this
increment will depend on the general level of ambient air quality that exists
in the year 2000 in AQCR 216. Currently, ambient air quality is marginal.
Hence, any increment could be significant unless the aggregate of existing
sources of air emissions is brought under better control.
*important in the sense-that the area contains the greatest industrial
concentration in the U.S. Moreover, chemicals and petrochemicals plants
are responsible for a large element of this concentration. Demand for
petrochemical products is growing about twice as fast as demand for industrial
products in general. Hence, constraint of industrial expansion in AQCR 216
might be expected to have significant national repercussions.
-------
- 151 -
FIGURE 8-3
DISTRIBUTION OF SULFUR AND ALKALI CONSTITUENTS
OF COAL BY REGION
EASTERN COAL
0 05 10 1.5 JO 2.5 30 J.5 40 45 5.0 5.5 CO
SULFUR, percent of coal
0 05 1.0 15 20 25 30 33 4.0 4.5 50 55 6.0
SUl.Fun, pcrcpp.l cf cool
WESTERN COAL
0 05 10 !5 2.O 25 3.0 35 40 45 50 5.5 6.0
SULFUR, percent cf cool
t'remi?r,cv disLr.hution of coal reserves by sulfur
conVir.it and ref.lon.
cor.leviL aoel region.
Source: Reference (17)
-------
- 152 -
TABLE 8-19
ALKALI ELEMENTS IN COAL ASH BY REGION
Region
East
Central
West
Alkali Oxides, % of Ash
CaO
3.15
9.38
13.74
MgO
0.86
1.07
3.71
Na?0
0.91
0.74
3.44
K?0
1.48
1.45
0.86
Stoichiometric ratio of alkali metals to sulfur
Percent of Coal
av. alkali av. sulfur
East
Central
West
0.43
1.27
1.54
1.95
3.43
0.70
Stoichiometric Ratio
Alkali/Sulfur
0.12
0.21
1.31
Source: E. A. Sondreal and P. H. Tufte, "Comparison of Flue Gas Desulfurization
for Eastern vs. Western U.S. Coals", U.S. Bureau of Mines, Grand Forks,
North Dakota, September 1974 (17). (Source refers to U.S. Bureau of
Mines Bulletin 567 and unpublished data.)
-------
TABLE 8-20
Lignite
State N.D.
Mine
No. of Samples 212
Ash, wt.%
Oxide constituents
Si02
A1203
Fe203
Ti02
S03
CaO
MgO
Na20
K20
P205
Ca/S ratio
6.2
of ash, %
19.7
11.1
30.8
9.1
0.4
9.5
19.5
24.6
6.9
31.5
6.5
0.4
6.9
0.3
2.2
SELECTED
ANALYSES OF ASH IN WESTERN COALS
Sub-b i tuminou s
Mont.
125
9.3
35.5
18.7
54.2
7.8
0.7
8.5
13.4
15.6
4.4
20.0
1.7
0.4
2.1
0.3
2.1
Wyo.
Big Horn
12
4.8
27.4
12.7
40.1
13.9
0.6
14.5
17.0
16.6
5.5
22.1
2.2
0.5
2.7
0.5
1.7
Ariz.
Black Mesa
1
7.5
42.0
18.1
60.1
5.7
0.8
6.5
8.2
17.8
2.4
20.2
1.4
0.3
1.7
0.6
3.8
Bituminous
N.M.
Nava j o
2
20.2
55.6
26.2
81.8
6.1
0.6
6.7
3.2
3.9
0.8
4.7
1.5
0.6
2.1
0.5
2.2
N.M.
McKinley
1
8.0
54.7
21.6
76.3
7.0
1.0
8.0
5.8
6.5
1.2
7.7
1.6
0.8
2.4
nil
2.0
Col.
Hawks Nest
3
5.4
44.8
28.3
73.1
11.5
0.8
12.3
4.0
5.6
1.9
7.5
0.6
0.5
1.1
0.7
2.5
Ui
to
Source: ERDA Open File Report: "Survey of Coal and Ash Composition and Characteristics of Western Coals and
Lignite", Grand Forks, North Dakota, 1975 (18).
-------
- 154 -
At present, available technical data limit the quantitative
environmental conclusions that may be drawn about coal-fired FBC, per
se,and in relation to other coal use technologies. Further definition
of the following is suggested:
(1) the quantity of sulfur retained in the ash from FBC and
spreader-stoker boilers . . . for representative Western
coals (bituminous, sub-bituininous, lignites) and South-
western lignites.
(2) NOx emissions . . . for the same types of equipment* and
coals listed in (1).
(3) particulate emissions from (atmospheric) coal-fired FBC
boilers ... as for (1) but also including high sulfur
coals.
(4) fate of trace elements ... as for (1), but also
including high sulfur coals and FGDS systems.
*there is some evidence, not sufficiently reliable to cite here, that different
designs of atmospheric fluidized bed combustors have different NOx control
potentialities. This possibility warrants further investigation.
-------
- 155 -
9. CONCLUSIONS
The conclusions of any forecasting study are conditioned by the
assumptions used and by the judgment of the investigator. The conclusions
below are accompanied by the letters (a), (b) and (c) which signify:
(a) high probability: the evidence and logic appear so persuasive that
the conclusion may be taken as objectively valid.
(b) dependent on assumptions used: the conclusion is valid only if the
assumptions are valid, e.g. that limited availability or very high
cost of imported oil will force the use of greatly increased quantities
of coal as industrial boiler fuel within the timeframe of interest.
(c) dependent on contractor's judgment; many factors affecting long range
projections are not forecastable in a rigorous way and must be dealt
with by judgment.
(1) Parity price calculations indicate that fuel price alone is not likely
to provide a sufficient incentive for conversion of industrial boilers
from oil/gas-firing to coal-firing during the next decade. (a)
(2) Aside from mandated switching, a decision to use coal is apt to be
induced by the perception that, during the life of a particular plant,
the supply of oil may become unreliable (e.g. interrupted, rationed,
or unavailable) . ^c^
(3) Capital-intensive manufacturing operations cannot tolerate unreliability
or unavailability of energy supply. (a'
(4) A survey of operators of large industrial boiler systems revealed that
almost all are considering the use of coal and are expecting that,
eventually, such use will be unavoidable. Once a decision to use coal
is made, consideration will be given to whatever coal-use technologies
have been demonstrated to be commercially reliable at the time the decision
is made. Installation of coal-fired FBC boilers will be considered if
commercial reliability has been demonstrated to be competitive with
environmentally acceptable alternatives.
(5) An increasing shortage of -tural gas, a growing compliance with
environmental regulations (to achieve "clean air ) , and re "^ "
economic recession are expected to result in de"sf n
to install new industrial boilers du ^8 the -x f w
it appears important for coal-fired FBC technology to (b)
strated for industrial use as soon as possible.
-------
- 156 -
(6) Erosion of the potentials estimated in this study may be expected
if the demonstration of commercial reliability of FBC technology
occurs after 1981, or 1982 at the latest. (c)
(7) The use of compliance coal is widely perceived to be a more economic
choice than the use of high sulfur coal plus flue gas desulfurization
(i.e. "scrubbers"). (a) (<0
(8) The cost of using compliance coal with FBC technology is estimated to
be a stand-off with using the same compliance coal in conventional
coal-fired industrial boilers. (b)
(9) The major resources of compliance coal are in the Western states,
hence transportation costs to many industrial plants will be high. (a)
(10) The combined demand for compliance coal by electric utilities and
manufacturing plants may constrain its availability in the 1980's
and, eventually, will do so. (c)
(11) Southwestern lignites, which contain appreciable amounts of alkaline
ash, are not compliance coals if combusted conventionally but may become
so in fluid-bed units. This possibility is of considerable potential
importance to industry located in the Gulf Coast area. (c)
(12) In general, Western coals of all ranks contain alkaline ash that can
effect sulfur capture when the coals are combusted. A much higher
level of sulfur capture is likely via FBC than with conventional
combustion. (a) (c)
(13) The foregoing points, taken together, give qualitative backing to
this study's estimates of coal-fired FBC potential provided that
timely demonstration of commercial reliability is achieved. (c)
(14) FBC technology has important advantages that, currently, cannot be
quantified. The advantages include flexibility to combust different
types of coal, good control of NOx emissions, relatively unobjection-
able solid wastes for which uses are under development, and ability to
be fabricated and shipped in modules for simple field assembly. Hence,
a decisive advantage in new boilers is possible for FBC over scrubber
technology provided that commercial reliability of FBC technology is
demonstrated in time. (c)
(15) Conversion of existing boilers to FBC technology (i.e. "retrofitting
FBC") is judged to be economically unattractive. (a) (c)
(16) The potential for coal-fired FBC is concentrated in the chemicals,
petrochemicals, petroleum refining, paper, primary metals, and food
industries. (a) (c)
-------
- 157 -
(17) The coal-fired FBC potential is considered to be a sub-set of coal
utilization by all large industrial boilers, and the level of coal
utilization by industrial MFBl's may be influenced strongly by the
existence, or absence, of coal-use legislation such is now under
Congressional consideration. /^\ / •>
(18) Over 90% of the coal-fired FBC potential is in four regions:
Appalachian, Southeast, Great Lakes, and Gulf Coast. ' (c)
(19) The coal firing of large industrial boilers, employing FBC technology,
is not expected to have much impact on the aggregate of national
energy consumption. (c)
(20) Estimated potentials for coal-fired FBC may be converted to "savings"
of oil equivalent ranging from 150,000 B/D in 1985 to 2.4 million B/D
in the year 2000. (b) (c)
(21) Realization of the estimated coal-fired FBC potentials would have
significant economic impacts in the boiler manufacturing, coal, and
limestone industries. However, essentially the same impacts would
be expected if the same level of coal utilization is achieved with
alternative coal-use technologies. (c)
(22) This study assumes (with much supporting evidence) that coal-fired
FBC will be an environmentally acceptable technology. On this basis,
the deployment of the technology is likely to have a net beneficial
impact on ambient air quality as it replaces existing coal-fired
equipment in regions that currently use coal to a significant extent, (c)
(23) The environmental impact of coal-fired FBC industrial boilers will be
small by comparison with the impact caused by sources other than
industrial boilers. (a'
(24) Compliance with New Source Performance Standards (NSPS) may not be
sufficient in some industrial areas of the country which are already
at or beyond ambient air quality standards (NAAQS). The Houston-
Galvestor area (AQCR 216), which is the leading petroleum refining/
petrochemical area in the U.S., has particulate and N02 levels in
ambient air that are close to the primary standards. (a) U)
(25) Directionallv, even with excellent control technology, coal use in
new installations would worsen the quality of the ambient air unless
the existing situation is improved.
-------
- 158 -
10. REFERENCES
Section 2
1. J. R. Ehrenfeld et al, "Systematic Study Of Air Pollution From
Intermediate Size Fossil-Fuel Combustion Equipment," Walden
Research Corporation, July 1971. PB-207 110 (avail. NTIS)
2. D. W. Locklin et al, "Design Trends And Operating Problems
in Combustion Modification Of Industrial Boilers," Battelle-
Columbus Laboratories, April 1974. EPA-650/2-74-032
3. American Boiler Manufacturers Association, "Stationary Watertube
Steam And Hot Water Generation Sales - 1974".
4. American Boiler Manufacturers Association, "Stationary Watertube
Steam And Hot Water Generation Sales - 1975".
5. R. Wood, Process Engineering (London), December 1975, page 55,
"Getting Steamed Up Over a Fluid-Bed Burner". Also personal
communication from Energy Equipment Company Limited, 19th
February, 1976.
6. M. A. Buffington, Chemical Engineering (New York), 82no.23,
98-106, October 27, 1975, "How to Select Package Boilers".
7. Pope, Evans and Robbins, "Coal-Fired Heating Plant Package -
Phase II Report", November 1963. PB 181585
8. D. H. Archer, D. L. Keairns, et al, "Evaluation of the Fluidized
Bed Combustion Process, Summary Report", Volume I, Westinghouse
Research Laboratories, 1972, Contract No. CPA 70-9.
9. J. C. Petkovsek and B. J. Mangione, Combustion, 47no.6, 10-15,
December 1975, "Economics Favor Industrial Power Generation With
Steam From High Pressure Boilers".
10. G. A. Vogt and M. J. Walters, American Institute of Chemical Engineers
68th Annual Meeting, Los Angeles, November 1975, Paper No. 76-B,
"Steam Balance As A Working Tool".
11. American Boiler Manufacturers Association, Personal Communication,
July 1975.
12. R. E. Barrett et al, "Assessment of Industrial Boiler Toxic and
Hazardous Control Needs", Battelle-Columbus Laboratories, October 1974,
EPA Contract 68-02-1323, Task 8.
13. Federal Energy Administration, "Major Fuel Burning Installation Coal
Conversion Report", Form FEA C-602-S-0, required to be submitted by
May 21, 1975.
-------
- 159 -
14. P. S. K. Choi et al, "S02 Reduction in Non-Utility Combustion
Sources — Technical and Economic. Comparison of Alternatives"
Battelle-Columbus Laboratories, October 1975, EPA Contract 68 '
02-1323, Task 13. KPA-600/2-75-073
15. J. E. Mesko, S. Ehrlich and R. A. Gamble, "Multicell Fluidized-
Bed Boiler Design, Construction and Test Program", Pope Evans
and Robbins, Inc., August 1974. PB 236 254'(avail. NTIS)
16. E. A. Sondreal and P. H. Tufte, "Comparison of Flue Gas
Desulfurization for Eastern Versus Western U.S. Coals",
U.S. Bureau of Mines, Grand Forks Energy Research Laboratory,
September 1974. (Presented at SHE Fall Meeting, Acapulco,
Mexico, September 22-25, 1974.)
17. J. S. Wilson and D. W. Gillmore, "Conceptual Design of an
Atmospheric Fluid-Bed Component Test and Integration Facility",
U.S. ERDA, Morgantown Energy Research Center, December 1975.
(Presented at Fourth International Fluidized-Bed Combustion
Conference, McLean, Virginia, December 9-11, 1975.)
18. W. B. Hirschmann, Harvard Business Review 42, 125-139, January/
February 1964, "Profit From the Learning Curve".
19. D. H. Ar.cher, D. L. Keairns, et al, "Evaluation of the Fluidized
Bed Combustion Process", Volume II, Westinghouse Research Laboratories,
1972, Contract No. CPA 70-9.
Section 3
1. "Fuels and Electricity Consumed", 1972 Census of Manufacturers, Social
and Economic Statistics Administration, Bureau of the Census, U.S.
Department of Commerce, MC72(SR)-6, July 1973.
2. "Fuels and Electricity Consumed (Supplement)", 1972 Census of Manufactures,
MC72(SR)-6S, September 1974.
3. "Greater Coal Utilization", Joint Hearings before the Committees on
Interior and Insular Affairs and Public Works, United States Senate,
pursuant to S. Res. 45, The National Fuels and Energy Policy Study,
94th Congress, First Session on S.1777, 1975.
4. Public Law 93-319, "Energy Policy and Conservation Act", (EPCA),
December 22, 1975.
5. S.1777, Staff Working Print No. 1, September 26, 1975.
-------
- 160 -
Additional Bibliography (Section 3)
• "Brief Industrial Descriptions", 1967 Standard Industrial Classification
Manual, Office of Statistical Standards, Bureau of the Budget, Executive
Office of the President, 1967 (i.e. the SIC Codes).
• Paul Averitt, "Coal Resources of the United States", U.S.G.S. Bulletin 1412,
1974.
• N. A. Parker and B. C. Thompson, "U.S. Coal Resources and Reserves", Office
of Coal, Nuclear, and Electric Power Analysis, Data and Analysis, Federal
Energy Administration, May 1976.
« Richard L. Gordon, "Economic Analysis of Coal Supply: An Assessment of
Existing Studies", Pennsylvania State University, February 1976.
« "Short-Term Coal Forecast, 1975-1980", ICF, Inc., submitted to Office
of Coal, Federal Energy Administration, August 1975.
• Commerce Technical Advisory Board (CTAB), "Sulfur Oxide Control Technology",
September 1975.
• "Keystone Coal Industry Manual", (revised annually).
Section 4
1. "1972 OBERS Projections, Regional Economic Activity in the U.S.", Series E
Population, Regional Economic Analysis Division, Bureau of Economic Analysis,
Social and Economic Statistics Administration, U.S. Department of Commerce
and Natural Resources Economics Division, Economic Research Service, U.S.
Department of Agriculture, April 1974.
Additional Bibliography (Section 4)
• John G. Myers, et al, "Energy Consumption in Manufacturing", The Conference
Board, Bellinger Publishing, 1974. (study supported jointly by NSF, the
Energy Policy Project of the Ford Foundation, and the Energy Information
Center of the Conference Board).
• John T. Reding and Burchard P. Shepherd, "Energy Consumption: the Chemical
Industry", Dow Chemical, U.S.A., Texas Division, Freeport, Texas, April 1975.
(PB-241-927)
« John T. Reding and Burchard P. Shepherd, "Energy Consumption: Paper, Stone/
Clay/Glass/Concrete, and Food Industries," April 1975. (PB-241-926)
-------
- 161 -
* M°hniT' Rf P^ ^ BUTC^^ P' |*ePherd> "Ene^y Consumption: the Primary
Metals and Petroleum Industries", April 1975. (PB-241^990)
• John T. Reding and Burchard P. Shepherd, "Energy Consumption- Fuel
Utilization and Conservation in Industry", September 1975. (PB-246-888)
• James R. Burroughs, "The Technical Aspects of the Conservation of Energy
for Industrial Processes", Dow Chemical Company, Midland, Michigan, May 1973.
• Dow Chemical Company and Environmental Research Institute of Michigan,
"Evaluation of New Energy Sources for Process Heat", prepared for the'
Office of Energy R&D Policy, National Science Foundation, September 1975.
• Battelle Columbus Laboratories, "Energy Use Patterns in Metallurgical and
Nonmetallic Mineral Processing", September 1975.
• "The Pace Slows in Saving Energy", special report, Business Week, pp 40D-40X,
August 30, 1976.
• Communication from Jeffrey Duke, Manager, Raw Materials and Energy Division,
American Paper Institute, New York, March 1976. (fuel consumption statistics;
see Appendix 4, Table 38)
• Office of Technology Assessment, U.S. Congress, "An Analysis of the Impacts
of the Projected Natural Gas Curtailments for the Winter 1975-76",
November 1975.
• J. C. Petkovsek and B. J. Margione, "Economics Favor Industrial Power
Generation with Steam from High Pressure Boilers", Combustion, pp 10-15,
December 1975.
• "Survey of Current Business", Bureau of Economic Analysis, U.S. Department of
Commerce, various issues. (used for prorating certain estimates via FRB Index
of Manufacturing Production, and also for constant dollar calculations).
Section 5
1. "Review of Overall Reliability and Adequacy of the North American Bulk
Power Systems (5th Annual Review)", report by Interregional Review Subcommittee
of the Technical Advisory Committee, National Electric Reliability Council,
July 1975.
Section 6
1. Ronald Kutscher, "Revised BLS Projections to 1980 and 1985: an Overview",
Monthly Labor Review, Volume 99, No. 3, March 1976.
2. "The Structure of the U.S. Economy in 1980 and 1985", Bulletin 1831, Bureau
of Labor Statistics, U.S. Department of Labor, 19/i.
(Note that Reference 1 is a revision of Reference 2.)
-------
- 162 -
Section 7
1. Robert P. Greene, Editor, "System Dynamics Newsletter", Volume 13,
pp. 1-2, December 1975.
2. Ibid, p. 21.
3. Jay W. Forrester, "Business Structure, Economic Cycles, and National
Policy", Futures, Volume 8, No. 3, pp. 195-214, June 1976.
4. "A Study of Coal Prices", Council on Wage and Price Stability, Executive
Office of the President, March 1976.
Section 8
1. E. S. Rubin, and F. C. McMichael, "Some Implications of Environmental
Activities on Coal Conversion Processes", Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology, May 1974,
St. Louis, Missouri, EPA Report No. EPA-650/2-74-118, October 1974,
p. 69-Quoting from "Standard of Performance for New Stationary Sources,"
Part II, Federal Register, Volume 39, No. 47, (March 8, 1974).
2. A. A. Jonke, et al, "Reduction of Atmospheric Pollution by the Application
of Fluidized-Bed Combustion," Argonne National Laboratory for EPA, EPA
Report No. EPA-650/2-74-104, September 1974.
3. D. C. Gifford, Chem. Eng. Progress, 69 (No. 6) 1973, p. 86.
4. S. Ehrlich, "A Coal Fired Fluidized-Bed Boiler", from "Fluidized Combustion
Conference", London, September 1975, Institute of Fuel Symposium Series
No. 1 (1975) Proceedings Volume 1, p. C4-1.
5. G. A. Cato, et al, "Field Testing: Applications of Combustion Modifications
to Control Pollutant Emissions from Industrial Boilers - Phase 1", KVB
Engineering, Inc. for EPA, EPA Report No. EPA-650/2-74-078-a, October 1974.
6. EPA, "Compilation of Air Pollutant Emission Factors "(Second Edition), EPA
Report No. AP-42, April 1973.
7. G. J. Vogel, et al, "Bench-Scale Development of Combustion and Additive
Regeneration in Fluidized Beds," in Proceedings of Third International
Conference on Fluidized-Bed Combustion, EPA Report No. EPA-650/2-73-053.
8. P. F. Fennelly, et al, "Preliminary Environmental Assessment of Coal-
Fired Fluidized-Bed Combustion-Summary Task 2 Report: Specification
of Important Pollutants", Prepared for EPA by GCA Corporation,
November 1975.
9. P. F. Fennelly, et al, "Preliminary Environmental Assessment of Coal-
Fired Fluidized Bed Combustion, Summary Task 3 Report: Suggested
Techniques for Control Technology" Prepared by GCA Corporation for
EPA, January 1976.
-------
- 163 -
11. Series of reports prepared by Exxon Research and Engineering
for EPA. General title: "Evaluation of Pollution Control
Fuel Conversion Processes," EPA Report Nos. EPA-650/2-74-009a through
EPA-650/2-74-009m and dated January 1974 through October ^.thr°Ugh
12. Anon., Environmental Science & Technology. 8, 516 (1974).
13. Federal Register, Vol. 38, No. 149, Friday, August 3, 1973, pp. 20834
and 20835.
14. SAROAD Users Manual, APTD-0663. Environmental Protection Agency,
Office of Air and Water Programs, Office of Air Quality Planning and
Standards, Research Triangle Park, N. C. July 1971.
15. EPA Office of Air Quality Planning and Standards, "Air Quality Data,
1973 Annual Statistics,"EPA-450/2-74-015, November 1974.
16. EPA Office of Air Quality Planning and Standards, "Air Quality Data,
1974 First Quarter Statistics," EPA-450/2-75-002, April 1975.
17. E. A. Sondreal and P. H. Tufte, "Comparison of Flue Gas Desulfurization
for Eastern vs. Western U.S. Coals", U.S. Bureau of Mines, Grand Forks,
North Dakota, September 1974.
18. ERDA Open File Report: "Survey of Coal and Ash Composition and Character-
istics of Western Coals and Lignite", Grand Forks, North Dakota, 1975.
Additional Bibliography (Section 8)
• D. B. Henschel, "The Environmental Control Potential of Fluidized Bed
Coal Combustion Systems", presented at the Second Seminar on Desulfur-
ization of Fuels and Combustion Gases, U.N. Economic Commission for
Europe, Washington, November 1975.
• John C. Bosch, Jr., "Aerometric and Emissions Reporting System" (AEROS),
Environmental Protection Agency, Durham, North Carolina, February 19/5.
• Richard C. Haws, "Presentation of NEDS Emission Data for Air *?"utJ°J b
Studies", Environmental Protection Agency, Durham, North Carolina, November
1974.
• "National Emissions Data System" (NEDS)
s a c
Durham, North Carolina (progressively upd
. "Environment Reporter", The Bureau of National Affairs, Inc., (progressively
updated) .
-------
- 164 -
Charanjit Rai and Richard D. Siegel, Editors, "Air: II. Control of NOx and
SOx Emissions", American Institute of Chemical Engineers, New York, 1975.
Wallace H. Johnson, "Social Impact of Pollution Control Legislation", Science,
Volume 192, pp. 629-631, May 14, 1976.
-------
- 165 -
CONVERSION FACTORS - ENGLISH TO SI UNITS
English System
Length
Area
Volume
Mass
Pressure
Temperature
Energy
Power
in
ft
. 3
in.,
B or bbl (barrel)
oz
Ib
ton
lb/in2
in H0
°R
BTU
1015 BTU or "quad
BTU/hr or BTU/H
SI Equivalent
2.54 cm
0.305 m
6.45 cm 2
0.0930 m
16.39 cnu
28.32 dm
159 dm3
28.35 gm
453.6 gm
907.2 kg
6.89 kPa
0.249 kPa
1.8 (°C) + 32
1.8 °K
1.06 kJ
33450 MWt
0.293 W
ABMA
AQCR
C/K Ibs
FB
GPO
HHV
KPPH
LSFO
M$
MFBI
MWe
MWt
NAAQS
NGTF
NSPS
OE
OSHA
PCF
SIC
American Boiler Manufacturers Association
Air Quality Control Region
cents per thousand pounds (of steam)
fluid-bed or fluidized bed
Gross Product Originating
higher heating value
thousand pounds (of steam) per hour
low sulfur fuel oil
million dollars
Major Fuel Burning Installation
megawatts electric
megawatts thermal
National Ambient Air Quality Standards
Natural Gas Task Force (FEA)
New Source Performance Standards
oil equivalent (B.O.E. - barrels of oil equivalent)
Occupational Safety and Health Act (or Administration)
pulverized coal fired (boiler)
Standard Industrial Classification
-------
APPENDIX 1
BASES FOR ECONOMIC EVALUATIONS OF
GRASS ROOTS INDUSTRIAL BOILER COMPARISONS
1. INVESTMENT BASES
A. GENERAL PROJECT OUTLINE
Location - U.S. Gulf Coast
Time - 1st quarter 1975
Final cost is a "Total Erected Cost" for the entire boiler system
(exclusions as noted).
Design and erection of boiler project by contractor under a
reimbursable cost contract.
Investment estimates are of initial screening quality, considered
suitable for general comparison of alternatives but not developed
to a definitive level suitable as a basis for allocation of funds.
Fluidized bed combustion has not been demonstrated commercially.
As such the FBC portion of the FBC package boiler estimate is
increased by a process development allowance of 20%. A small
process development allowance is also applied to industrial-sized
flue gas scrubbers.
Investment estimates exclude the purchase of any land. It is assumed
that adequate space for the required facilities is already
available, and that extensive site clearance (e.g. blasting or
draining and filling) is not required.
All cases are planned to meet appropriate environmental requirements.
Investment estimates include 20% project contingency. This is
considered necessary at the screening stage of any project, because
of the incomplete project definition which is characteristic of
this stage of project development. For ease of use, this contingency
is broken out so that the estimates can be readily worked with on
a non-contingency basis if desired.
The "Total Erected Cost" for each screening case of this study is
built up including the following components:
Direct Materials Cost, delivered to project location (including
freight, delivery charges, sales taxes, etc.)
Direct Labor Cost at Location
Field Labor Overheads
Construction Supervision
Construction Tools
Temporary Construction Facilities and Consumables
-------
Al - 2
Contractor's Field Payroll Burden
Insurance, Union Welfare Funds, Indirect Labor Costs,
and any other contractor overheads
Contractor Engineering
Contractor Fees for Engineering and Erection
Process Development Allowance for New Technology Components
Sub-Contracts for Civil and Tankage Items
Escalation to later project time (if desired)
Contingency - @ 20% of all above components except Process
Development Allowance
B. FUEL AND LIMESTONE RECEIVING AND STORING FACILITIES
• Fuel Oil Receiving and Storing
No. 6 Fuel Oil (high or low sulfur) received in 5,000-barrel
parcels, delivered by barge.
Oil storage: two steam-heated cone roof tanks with combined
capacity sized for 10 days requirement plus parcel size
(i.e. 10,000 barrels combined storage. Facilities include:
8" fuel receiving line, steam-traced and insulated
from existing barge dock to storage tanks (approx.
1000 feet)
Two 5,000 barrel cone-roof tanks, approximately
30' x 40'. Tanks are heated with low-pressure
steam coils (~125 psig), and insulated with foam
sprayed insulation
Two fuel oil pumps, pumping approx. 20 gpm @ 150 psig
Transfer line (2", traced and insulated), from tanks
to boiler area and return.
» Coal Receiving and Storing
Coal received in 10-car lots (100 tons/car); bottom-hopper cars
Coal as received is fully prepared for FBC charging (screened to
approx. 1/4-inch top size) or for use in stoker (1 1/4" nominal
size), and sprayed with oil to minimize dust and facilitate
unloading in freezing weather
-------
Al - 3
Coal storage: two silos with combined capacity sized for 10 days
requirement plus parcel size (i.e. 2400 tons combined storage)
Facilities include:
Railroad track extension (approx. 1400 feet)
Covered car-unloading dump hopper and pit
Car puller
Feeders and covered conveyor from pit to elevator
Elevator to top level of silos
Transfer conveyor from elevator to silo charging hopper
Two 30' x 80' silos with mass flow hoppers
Vibrating pan feeders and covered conveyors from silos
to fuel distribution facilities of boilers
• Limestone Receiving and Storing
Screened granular limestone, fully prepared for FBC
charging (approximately 1/8" particle size), is received
by truck and pneumatically unleaded to silo
Limestone storage: single silo with 10-days storage capacity
Facilities include:
Pneumatic unloading system
Single silo - 500 tons capacity with twin cone bottom
Silo is provided with conventional dust-prevention system
for pneumatic receipt of solids.
Vibrating pan feeders and covered conveyors from silo to
fuel distribution facilities of boilers.
Limestone for slurry flue gas scrubbing use is received and
stored as crushed stone (2 1/2" maximum size), and wet-
milled to 325 mesh en route to the scrubber system.
C. BOILERS AND STACK
Steam demand is assumed at 100 k Ibs/onstream iiour to industrial
process, with year-round 90% load factor. Steam conditions 125 psig,
saturated.
Condensate collection/feed water treating system supplies deaerated
feed water at 2QO°F.
To assure continuity of steam supply, two 100 KPPH boilers are
installed (alternatively could provide 3 x 50 KPPH units, at some-
what lower investment cost but with higher space requirements,
piping, manning and maintenance costs).
Efficiency of all boilers is assumed to be 82%. Flue gas temperature
from economizer outlet is assumed at 350°F. No air preheaters.
-------
Al - 4
Oil-Fired Boilers
Two 100 KPPH complete package watertube boilers
Conventional Coal-Fired Boilers
Two 100 KPPH complete spreader stoker field-erected
watertube boilers, with fly ash reinjection
Coal-Fired Fluidized Bed Boilers
Two 100 KPPH FBC shop-assembled watertube boilers, with
complete facilities as follows:
Coal and limestone metering and feeding systems to
multiple fuel injection points of boilers
FD/ID fans and drivers
Steam generators (with main combustor cells, carbon
burnup cell (CBC), water wall and submerged steam
tubing, economizer sections, plenum and air
distribution grid, cyclone-type dust collectors
on flue gas streams from main combustor cells and
carbon burnup cell, oil-fired ignition system, bed
drain system).
Controls, flues, ducts
• Stack
Common stack, ground-supported, carbon steel,
8' diameter x 75' high with self-supporting
liner of regular firebrick
As noted, the investment comparisons are based on boiler outlet
conditions of 125 psig, saturated. Many industrial boilers generate
steam at significantly higher pressures and temperatures. We
estimate that the boiler portion of project investments should be
multiplied by the following factors to reflect the increased capital
requirement for generating steam at higher pressures:
Steam Conditions 125 psig 600 psig 1300 psig
Saturated 750 F 900°F
Oil-Fired Package Boilers 1.0 1.15 1.33
Coal-Fired Conventional Boilers 1.0 1.12 1.27
Coal-Fired FBC Boilers 1.0 1.07 1.16
D. ENVIRONMENTAL CONTROLS
Firing rate in all cases is lower than 250 M Btu/hr., so no Federal
emission standards are currently applicable. Nevertheless, each case
is designed to meet EPA New Source Standards For Steam Generating
-------
Al - 5
Equipment of 250 M Btu/hr. or greater, as follows:
Oil Fuel Solid Fuel
Particulates
Opacity No. 1 Ringelmann (20% opacity)- -
Emissions, Ib/M Btu 0.1 0.1
S02, lb/M Btu 0.8 1.2
NOx, lb/M Btu (as N02) 0.3 0.7
Low sulfur fuel oil requires no controls.
If high sulfur fuel oil is used, it requires flue gas
desulfurization (FGDS). For this study, we would assume use of
once-through limestone slurry scrubbing, producing scrubber sludge
dewatered to 50% solids.
Low sulfur coal fired in a spreader stoker requires an electrostatic
precipitator (ESP) to meet particulate standards.
High sulfur coal fired in a spreader stoker requires flue gas
desulfurization. For this study, we assume once-through limestone
slurry scrubbing, producing scrubber sludge dewatered to 50%
solids. The scrubber effluent exhibits better than standard
particulate loading (estimated at .05 Ibs/M Btu vs. standard
of 0.1 Ibs/M Btu).
For all the above conventional boilers, NOx emissions will be
close to the limiting standard. To insure meeting the standard,
boiler design modifications may be required so as to carry out
combustion in a mode which minimizes NOx formation.
High sulfur coal fired in an FBC boiler only requires adjustment
of the limestone/coal ratio to meet the S02 emission standard.
Effluent from the FBC boiler is comfortably better than standard
with respect to NOx. An electrostatic precipitator (ESP) is
provided to meet the particulate emission standard.
In each grass roots case, required environmental control facilities
are provided with each of the two 100 KPPH boilers, so that each
"train" of equipment can be operated independently -
E. SOLID WASTE COLLECTION, STORAGE, DISPOSAL
Sludge from scrubbers, dewatered to 50% solids via rotary vacuum
filter, is dumped via conveyor to covered sludge pit (assuming
that plant does not have land for long-term ponding of sludge
and ash). Sludge is hauled away by truck.
In high sulfur coal case with stoker, ash is also sent via conveyor
to sludge pit and mixed with sludge.
In FBC and low sulfur coal cases, where no sludge is produced,
dry wastes (fly ash from ESP's, and pit ash from stoker or ash/
sulfated stone mixture from FBC) are pneumatically transferred
to dry waste silo and hauled away by truck. Silo has seven days
storage capacity, and is elevated,with "Hydromix" loader for
loading to disposal trucks.
In all cases, solids handling systems are designed to minimize
discharge of contaminants (dust, sump drains, etc.).
-------
Al - 6
F. EXCLUSIONS
Land
Unusual site preparation (clear, level site assumed)
Boiler feed water (BFW) treating facilities
BFW pumps
Slowdown system
Steam distribution system
These facilities are common to all cases, and are not included in
any of the investment estimates.
Allowances for Boiler Feed Water costs have been included in the
operating cost calculations, and these allowances include a typical
capital charge for a boiler feed water system.
2. OPERATING COST BASES
Manpower cost (salaries/wages and benefits) is 20 k$/yr/man
Electric power cost is 4c/KWH
Limestone cost, delivered, Is $12 per ton for FBC use. It
is assumed that the total cost of coarse crushed stone plus
wet grinding for use in the flue gas scrubber cases is also
approximately $12 per ton.
Waste solids disposal cost (sludge, ash, sulfated limestone
from FBC) is $8/ton
Annual repair materials cost is 1 1/2% of investment
Annual cost for supplies, local taxes, administrative expense,
general expense is 3% of investment
Annual capital charges, covering cost of capital invested in
these facilities (including interest, effect of depreciation
on income taxes, and other investment-related charges) is taken
at 20% of investment.*
Treated and deaerated boiler feed water cost (at 200°F),
including 50% purchased makeup water and 50% condensate return
from process operations, is assumed at $0.60 per k Ibs. steam
(includes effect of about 10% blowdown).
When a new boiler is added to an existing boiler system, it
is assumed that the new boiler is base-loaded and operates
at capacity with an overall availability of 90%.
* Pope Evans & Robbins in their 1970 comparison of conventional and
FBC economics used a 20% capital charge; Westinghouse in 1971 and
Battelle in 1974 used 16.7%.
-------
Al - 7
3. CHARACTERISTICS OF ASSUMED FUELS
Fuel Fuel Characteristics
Low Sulfur Fuel Oil 15°API(0.966 spec, gr.)
18,600 Btu/lb. HHV
Sulfur content just meets
0.8 Ib S02/M Btu O0.7 wt%S)
High Sulfur Coal Illinois No. 6
3.6 wt%S
8.0 wt% ash
16.9 wt% moisture
10,600 Btu/lb HHV
Low Sulfur Coal Wyoming
0.4 wt%S
5.8 wt% ash
30.0 wt% moisture
8,150 Btu/lb HHV
4. EXPONENTS USED TO ESTIMATE INDUSTRIAL BOILER PLANT INVESTMENTS
BASED ON 100 KPPH BASE CASES
I = KCn
Type of Facility Capacity Range, Exponent "n1
KPPH Steam
Oil-Fired Fuel Receiving/ \ 50-100 0.6
Storing/Feeding J 100-400 0.6
Coal-Fired Fuel Receiving/A 50-100 0.3
Storing/Feeding / 100-400 0.3
Packaged Oil-Fired Boilers 50-100 0.65
100-400 0.65
Coal-Fired Spreader Stoker Boilers 50-100 0.75
100-200 0.75
Pulverized-Coal-Fired Boilers 200-400 0.75
FBC Boilers 50-100 0.65
100-400 0.65
Solids Waste Collection/Disposal -\ 50-100 0.7
including Electrostatic Precipitators/100-400 0.7
Limestone Slurry Flue Gas Scrubbers 50-100 0.65
100-400 0.7
-------
APPENDIX 2
DESCRIPTION OF SCREENING QUALITY INVESTMENT ESTIMATES
The investments we have developed for use in the economic com-
parison of alternative boiler systems are of "screening quality." In
putting together these screening numbers, our aim is to develop the cost
level for a system which will meet the overall process objectives, making
reasonable general engineering assumptions as we go along. The usual pur-
poses of such screening estimates are:
• to analyze alternatives on a consistent basis, and
• to quickly eliminate those which are clearly unattractive;
• to lay the groundwork for more definitive comparison
of the remaining alternatives;
• to establish a reasonable order-of-magnitude for the
absolute cost of a real project; and
• to identify major areas of concern (technical or
economic) which should be studied in depth in subsequent
R&D and/or project planning.
Screening estimates for new technologies or processes are widely used for
guidance of Research and Development activities, although they are not of
adequate quality to be used as a basis for making final investment decisions
for specific projects.
The main objective of this part of the work is to compare the
economics of fluidized bed combustion with alternative industrial boiler
cases. Since fluidized bed combustion is as yet uncommercialized, we could
only obtain this type of screening estimate by working with boiler manu-
facturers who are engaged in exploratory FBC studies themselves. The same
approach was used for estimates involving conventional boiler technology.
Appendix 1 shows the components which were included in building
up these estimates. We believe all are self explanatory except for brief
discussions regarding contingency level, and inclusion of a process development
allowance for new technology.
For screening estimates at this very early stage of project
definition, we recommend, and have used, a contingency level of 20%. As
project activities continue and the basis for a cost estimate becomes
more detailed and defined, the contingency level is correspondingly reduced,
eventually to the level of 8-10% (just prior to construction of a real
project).
-------
A2 - 2
Fluidized bed combustion is a developing, as yet non-commercialized
technology. A process development allowance, based on prior general
experience with such new process applications, represents additional hard-
ware/equipment/materials of construction which may become necessary as pro-
blems are identified during detailed design, construction, and startup of
a project utilizing the newly-developing technology. Experience has taught
that costs are usually underestimated at this early stage in the develop-
ment of new technologies. Generally the pattern has been that estimates
of costs increase as the estimates become progressively more detailed prior
to construction of the first, full-scale commercial plant that incorporates
the new technology. In an attempt to take this pattern into account for the
fluidized bed boiler, we have included in our screening estimates a process
development allowance of 20% of the portion of the FBC system which is
considered to be susceptible to these developmental problems. In similar
fashion, in the case of conventional combustion of high sulfur fuels, a
smaller allowance of 10% is included for appropriate sections of the industrial-
sized flue gas scrubber systems which are just now becoming commercialized.
As a real project proceeds from initial screening to a definitive cost estimate
and then to detailed design, the process development allowance becomes progres-
sively smaller while identified costs increase.
In Appendix 3, which presents the screening estimates for the
cases we have developed, the amounts ascribed to "contingency" and "process
development allowance" are specifically broken out and identified for the
convenience of the user.
The question of the possible range (optimistic or pessimistic)
around such screening estimates has been raised. Very little actual statistical
experience can be brought to bear on this question, because of the many
basis changes which occur in practically all real project histories. However,
we have tried to estimate the span of optimism/pessimism we would expect
could be applied to Exxon's typical screening estimates, and conclude that
the optimistic level is not likely to be more than 10% below the quoted
level; conversely, the pessimistic range is likely to be as much as 20-25%
above the quoted figure.
-------
APPENDIX 3
DETAILED TABULATION OF INVESTMENT AND OPERATING COST ESTIMATES
Tables 1-6 Breakdown and Comparison of Investments
for Grass Roots Industrial Boiler Systems
Tables 7-11 Unit Operating Costs for Grass Roots Boiler
Systems
Tables 12-16 Breakdown and Comparison of Investments for
Adding Single Boilers to Existing Coal-Fired
Plants
Tables 17-20 Unit Operating Costs for Adding Single Boilers
to Existing Coal-Fired Plants
Tables 21-26 Breakdown and Comparison of Investments for
Adding Single Boilers to Existing Oil-Fired
Plants
Tables 27-31 Unit Operating Costs for Adding Single Boilers
to Existing Oil-Fired Plants
-------
Fuel
Fired in
External S02 Control
Particulate Control
INVESTMENTS, MS (1)
Fuel Receiving, Storing,
Fedding Allowance
Limestone Receiving, Storing,
Feeding
Boilers (2 @ 100 k Ib/hr) (2)
Stack
Electrostatic Precipitators
Flue Gas Scrubber Systems
Solid Waste Collection,
Storage, Disposal
Sub-Total (Before Contingency)
Contingency @ 20%
Process Development Allowance
For Scrubbers
For FBC Boilers
TOTAL INVESTMENT, M$
APPENDIX 3
TABLE 1
BREAKDOWN AND COMPARISON OF INVESTMENTS FOR
GRASS-ROOTS INDUSTRIAL BOILER SYSTEMS (STEAM DEMAND <=• 100 KPPH)
High Sulfur Coal
Fluidized Bed
Not Needed
Electrostatic
2 @ 2.0
2 @ 0.45
Silo
Boiler
Precip.
1.5
0.3
4.0
0.3
0.9
0.4
7.4
1.5
Conventional Stoker
Limestone Scrubber
Scrubber
1.5
0.3
2 @ 2.1 4.2
0.3
2 S 1.6 3.2
Pit 0.2
9.7
1.9
Low Sulfur "Compliance" Coal Low Sulfur Fuel Oil
Fluidized Bed Boiler
Not Needed
Electrostatic Precip.
1.6
0.1(3)
2 @ 2.0 4.0
0.3
2 @ 0.45 0.9
Silo 0.4
7.3
1.5
Conventional Stoker Package Boiler
Not Needed Not Needed
Electrostatic Precip* Not Needed
1.6 0.5
-
2 @ 2.1 4.2 2 @ 0.95 1.9
0.3 0.3
2 @ 0.45 0.9 - ^
~~ "" K>
Silo 0.4
7.4 2.7
1.5 0.5
0.6
9.5
0.2
11.8
0.6
9.4
8.9
3.2
(1) Investments expressed in 1st Q 1975 Dollars for project located at U.S. Gulf Coast.
(2) Boiler pressure is 125 psig, saturated steam. See Appendix 1 for approximate variation of boiler cost with steam generation pressure.
(3) Limestone may not be used in an FBC boiler firing low sulfur compliance coal, but some facilities will be required to receive, store, and
feed the bed makeup material.
-------
A3 - 3
APPENDIX 3
TABLE 2
SCREENING INVESTMENTS FOR GRASS ROOTS
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER SYSTEMS .(D
Base Case
Steam Requirement, 100
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, Storing,
Feeding Allowance 1.8
2 FBC Boilers,
Common Stack (3) 5.8
Precipitators, Ash/
Sulfated Stone
Collection, Storage,
Loading 1-9
Total 9-5
Derivative Cases
50
1.5
3-7
1.2
6T
200
400
2.2
9.1
3.1
14-4
2.7
14 .3
.5-0
22-0
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 207o contingency.
(3) FBC Boiler investments represent current state of technology;
investments also include 20% "process development" allowance
(2 x 0.3 M $ for base case) on commercially-undemonstrated sections.
-------
A3 - 4
APPENDIX 3
TABLE 3
SCREENING INVESTMENTS FOR GRASS-ROOTS
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER SYSTEMS WITH FLUE GAS DESULFURIZATION'(1)
Base Case
Steam Requirement, 100
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, Storing,
Feeding Allowance 1.8
2 Boilers, Common Stack 5.4
2 Flue Gas Scrubbers (3),
Sludge and Ash Storage/
Loading 4.6
Total 11.8
Derivative Cases
50
1.5
3.2
2.9
776"
200
400
2.2 2.7
9.5 (4) 16.0 (4)
12.2
3079"
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) Scrubber investments include 1070 "process-development" allowance
(2 x 0.1 M $ for base case) on critical sections.
(4) Boilers for 200 KPPH and higher are assumed to be Pulverized
Coal Fired (PCF) units. At 200 KPPH size, PCF boiler investment
is assumed 5% higher than for corresponding stoker boiler.
-------
A3 - 5
APPENDIX 3
TABLE 4
SCREENING INVESTMENTS FOR GRASS ROOTS
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER SYSTEMS (1)
Base Case
Steam Requirement, 100
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, Storing,
Feeding Allowance 1.9
2 FBC Boilers,
Common Stack (3) 5.8
Precipitators, Ash
Collection, Storage,
Loading (A) 1.7
Total 9.4
Derivative Cases
50
1.5
3.7
1.0
6.2
200
2.3
9.1
2.8
14.2
400
2.9
14.3
4.5
21.7
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) FBC Boiler investments represent current state of technology;
investments also include 20% "process development" allowance _
(2 x 0.3 M $ for base case) on commercially undemonstrated sections,
(4) Includes small allowance for facilities to store and handle
inert bed material.
-------
A3 - 6
APPENDIX 3
TABLE 5
SCREENING INVESTMENTS FOR GRASS-ROOTS
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER SYSTEMS_(1) (2)
Base Case
Steam Requirement, 100
k Ibs/hr.
Investments, M$ (3)
Fuel Receiving, Storing,
Feeding Allowance 1«9
2 Boilers, Common Stack 5.4
Precipitators, Ash
Collection, Storage,
Loading 1.6
Total 8.9
Derivative Cases
50
1.5
3.2
1.0
5.7
200
2.6
14.4
400
2.3 2.9
9.5(4) 16.0(4)
4.2
23.1
(1) 1975 level, U.S. Gulf Coast location.
(2) Sulfur content of coal assumed sufficiently low that flue gas
desulfurization is not required.
(3) Investments include 20% contingency.
Boilers for 200 KPPH and higher are assumed to be Pulverized
Coal Fired (PCF) units. At 200 KPPH size, PCF boiler investment
is assumed to be 5% higher than for corresponding stoker boiler.
-------
A3 - 7
APPENDIX 3
TABLE 6
SCREENING INVESTMENTS FOR GRASS-ROOTS
LOW-SULFUR-OIL-FIRED PACKAGE BOILER SYSTEMS (1)
Base Case
Steam Requirement,
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving,
Storing, Feeding
2 Boilers, Common Stack
100
Derivative Cases
50
0.4
1.7
200
400
0.9
4.1
1.4
6.4
Total
3.2
2.1
5.0
7.8
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
-------
A3 - 8
APPENDIX 3
TABLE 7
UNIT OPERATING COSTS (EX FUEL.) FOR GRASS ROOTS
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER SYSTEMS
Base Case
Steam Requirement,
k Ibs/hr.
Costs, c/k Ibs. steam (ex
Wages, Salaries, Benefits
Repair Materials
Utilities
Limestone
Supplies, Local Taxes,
Admin. Exp., etc.
Ash/Sulfated Stone
Disposal
Sub- total Direct Op. costs
Capital Charges
BFW
Total Cost, c/k Ibs.
100
fuel)
56
18
25
27
36
18
180
241
60
481
Derivative Cases
50
103
24
25
27
49
18
246
325
60
631
200
31
14
25
27
27
18
142
183
60
385
400
18
10
25
27
21
18
119
140
60
319
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A3 - 9
APPENDIX 3
TABLE 8
UNIT OPERATING COSTS (EX FUEL) FOR GRASS ROOTS
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER SYSTEMS WITH FLUE GAS DESULFURIZATION
Steam Requirement,
k Ibs/hr.
Base Case
100
Derivative Cases
Costs, c/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits 76
Repair Materials 22
Utilities 30
Limestone 11
Supplies, Local Taxes
Admin. Exp., etc. 45
Ash/Sludge Disposal 22
Sub-total Direct Op. costs 206
Capital Charges 299
BFW .60
Total Cost, C/k Ibs. 565
(ex fuel)
50
200
400
141
29
30
11
58
22
291
385
60
736
42
18
34
H
36
22
163
243
60
466
24
15
34
11
29
22
135
196
60
391
-------
A3 - 10
APPENDIX 3
TABLE 9
UNIT OPERATING COSTS (EX FUEL) FOR GRASS ROOTS
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER SYSTEMS (1)
Base Case Derivative Cases
Steam Requirement,
k Ibs/hr.
Costs, £/k Ibs. steam (ex
Wages, Salaries, Benefits
Repair Materials
Utilities
Limestone
Bed Makeup Material
Supplies, Local Taxes,
Admin. Exp. , etc.
Ash Disposal
Sub-total Direct Op. Costs
Capital Charges
BFW
100 50 200
fuel)
56 101 31
18 24 13
25 25 25
36 47 27
4 44
139 201 100
238 314 180
60 60 60
400
19
10
25
-
21
4
79
137
60
Total Cost,
-------
A3 -11
APPENDIX 3
TABLE 10
UNIT OPERATING COSTS (EX FUEL) FOR GRASS ROOTS
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER SYSTEMS (1)
Steam Requirement,
k Ibs/hr.
Base Case
100
Derivative Cases
Costs, Q/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits 53
Repair Materials
Utilities
BFW
Total Cost, C/k Ibs.
(ex fuel)
17
13
Supplies, Local Taxes,
Admin. Exp., etc. 34
Ash Disposal 4
Sub-total Direct Op. costs 121
Capital Charges 226
60
407
50
60
529
200
60
335
400
98
22
13
43
4
180
289
30
14
17
27
4
92
183
17
11
17
22
4
71
147
60
278
(1) Sulfur content of coal assumed sufficiently low that flue gas
desulfurization is not required.
-------
A3 - 12
APPENDIX 3
TABLE 11
UNIT OPERATING COSTS (EX FUEL) FOR GRASS ROOTS
LOW-SULFUR-OIL-FIRED PACKAGE BOILER SYSTEMS
Base Case
Steam Requirement,
k Ibs/hr.
Costs, c/k Ibs. steam (ex
Wages, Salaries, Benefits
Repair Materials
Utilities
Supplies, Local Taxes,
Admin. Exp. , etc.
Sub-total Direct Op., costs
Capital Charges
BFW
Total cost, c/k Ibs.
(ex fuel)
100
fuel)
38
6
21
12
77
81
60
218
Derivative Cases
50 200
71 21
8 5
21 21
16 9
116 56
106 63
60 60
282 179
400
12
4
21
7
44
49
60
153
-------
APPENDIX 3
TABLE 12
BREAKDOWN AND COMPARISON OF INVESTMENTS FOR
ADDING A SINGLE 100 KPPH BOILER TO EXISTING COAL-FIRED BOILER PLANT
Fuel
Fired in
External S02 Control
Particulate Control
INVESTMENTS, M$ (1)
Fuel Receiving, Storing,
Feeding Additions
Limestone Receiving, Storing,
Feeding Additions
Boiler
Stack
Electrostatic Precipitator
Flue Gas Scrubber System
Solid Waste Collection,
Storage, Disposal
Sub-Total (Before Contingency)
Contingency @ 20%
Process Development Allowance
For Scrubber
For FBC Boiler
TOTAL INVESTMENT, M$
High Sulfur Coal (2)
Fluidized Bed Boiler
Not Needed
Electrostatic Precip.
0.5
0.1
2.0
0.3
0.45
Silo
0.4
1771
0.75
0.3
471"
Conventional Stoker
Limestone Scrubber
Scrubber
0.2
0.1
2.1
0.3
1.6
0.1
Low Sulfur "Compliance" Coal (3) Low Sulfur Fuel Oil
Fluidized Bed Boiler Conventional Stoker Package Boiler
Not Needed Not Needed
Electrostatic Precip. Electrostatic Precip.
Not Needed
Not Needed
4.4
0.9
0.1
174"
0.5
0.1 (4)
2.0
0.3
0.45
0.2
3.55
0.75
0.3
476
0.2
2.1
0.3
0.45
0.1
OJ
0.65
3.8
THIS
OJ
CASE ,
NOT £
CONSIDERED
APPLICABLE
(1) Investments expressed in 1st Q 1975 Dollars for project located at U.S. Gulf Coast.
(2) These cases are based on the assumption that high sulfur coal is being fired in the existing boilers.
(3) These cases are based on the assumption that low sulfur compliance coal is being fired in the existing boilers.
(4) Limestone may not be used in an FBC boiler firing low sulfur compliance coal, but some facilities will be required to receive,
store, and feed the bad makeup material.
-------
A3 - 14
APPENDIX 3
TABLE 13
SCREENING INVESTMENTS FOR ADDING A SINGLE
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER TO EXISTING COAL-FIRED BOILER PLANT (1) (4)_
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, 0.6 0.7 0-9
Storing, Feeding Additions
FBC Boiler, Stack (3) 3.1 4.9 7.6
Precipitator, Ash/ 1.1 1.8 2.9
Sulfated Stone
Collection, Storage,
Loading
Total 4.8 7.4 11.4
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) FBC Boiler investment represents current stats of technology;
investment also includes 20% "process development" allowance
(0.3 M $ for base case) on commercially-undemonstrated
sections.
(4) Large-size high sulfur coal assumed to be fired in existing boilers.
-------
A3 - 15
APPENDIX 3
TABLE 14
SCREENING INVESTMENTS FOR ADDING A SINGLE
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER WITH FLUE GAS DESULFURIZATION
TO EXISTING COAL-FIRED BOILER PLANT (1) (5)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, 0.2 0.2 0.3
Storing, Feeding Additions
Boiler, Stack 2.9 5.1 (4) 8.6 (4)
Fluei Gas Scrubber (3), 2.3 3.7 6.1
Sludge and Ash Storage/
Loading
Total 5.4 9.0 15.0
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) Scrubber investment includes 10% "process development" allowance
(0.1 M $ for base case) on critical sections.
(4) Boilers for 200 KPPH and higher are assumed to be Pulverized
Coal Fired (PCF) units. At 200 KPPH size, PCF boiler investment
is assumed 5% higher than for corresponding stoker boiler.
(5) High sulfur coal assumed to be fired in existing boilers.
-------
A3 - 16
APPENDIX 3
TABLE 15
SCREENING INVESTMENTS FOR ADDING A SINGLE
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER TO EXISTING
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER PLANT (1)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, 0.6 0.7 0.9
Storing, Feeding Additions
FBC Boiler, Stack (3) 3.1 4.9 7.6
Precipitator, Ash/Inert 0.9 1.5 2.4
Bed Material Handling
and Storage
Total 4.6 7.1 10.9
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) FBC Boiler investment represents current state of technology;
investment also includes 20% "process development" allowance
(0.3 M $ for base case) on commercially-undemonstrated sections.
(4) Large-size low sulfur compliance coal assumed to be fired in
existing boilers.
-------
A3 - 17
APPENDIX 3
TABLE 16
SCREENING INVESTMENTS FOR ADDING A SINGLE
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER
TO EXISTING COAL-FIRED BOILER PLANT (1) (2)(5)
Steam Requirement,
k Ibs/hr.
Investments, M$ (3)
Fuel Receiving,
Storing, Feeding Additions
Boiler, Stack
Precipitator, Ash
Collection, Storage,
Loading
Total
Base Case
100
0.2
2.9
0.7
Derivative Cases
3.8
200
0.2
6.4
400
0.3
5.1 (4) 8.6 (4)
1.1 1.8
10.7
(1) 1975 level, U.S. Gulf Coast location.
(2) Sulfur content of coal assumed sufficiently low that flue gas
desulfurization is not required.
(3) Investments include 20% contingency.
(4) Boilers for 200 KPPH and higher are assumed to be Pulverized
Coal Fired (PCF) units. At 200 KPPH size, PCF boiler investment
is assumed to be 5% higher than for corresponding stoker boiler.
(5) Low sulfur coal assumed to be fired in existing boilers.
-------
A3 - 18
APPENDIX 3
TABLE 17
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER TO EXISTING COAL-FIRED BOILER PLANT
Base Case
Steam Requirement,
k Ibs/hr.
Costs, c/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits
Repair Materials
Utilities
Limestone
Supplies, Local Taxes,
Admin. Exp., etc.
Ash/Sulfated Stone Disposal
Sub-Total Direct Op. Costs
Capital Charges
BFW
Total Cost, c/k Ibs.
(ex fuel)
100
28
9
25
27
18
18
125
122
60
307
Derivative Cases
200
15
7
25
27
14
18
106
94
60
260
400
9
5
25
27
11
18
95
72
60
227
-------
A3 - 19
APPENDIX 3
TABLE 18
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER WITH FLUE GAS DESULFURIZATION
TO EXISTING COAL-FIRED BOILER PLANT
Base Case
Steam Requirement,
k Ibs/hr.
Costs, c/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits
Repair Materials
Utilities
Limestone
Supplies, Local Taxes,
Admin. Exp., etc.
Ash/Sludge Disposal
Sub-Total Direct Op. Costs
Capital Charges
BFW
Total Cost, C/k Ibs.
100
38
10
30
11
20
22
131
137
60
328
Derivative Cases
200
21
9
34
11
17
22
114
114
60
288
400
12
7
34
11
14
22
100
95
60
255
(ex fuel)
-------
A3 - 20
APPENDIX 3
TABLE 19
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER TO
EXISTING CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER PLANT (1)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Costs, c/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits 28 15 9
Repair Materials 9 75
Utilities 25 25 25
Limestone - - -
Bed Makeup Material _______
Supplies, Local Taxes, 17 14 10
Admin. Exp., etc.
Ash Disposal _4 4 4
Sub-Total Direct Op. Costs 83 65 53
Capital Charges 117 90 69
BFW 60 60 60
Total Cost, c/k Ibs. 260 215 182
(ex fuel)
(1) Sulfur content of coal assumed sufficiently low that flue gas desulfurieation
is not required.
-------
A3 - 21
APPENDIX 3
TABLE 20
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER TO EXISTING COAL-FIRED BOILER PLANT(1)
Base Case
Steam Requirement,
k Ibs/hr.
Costs, C/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits
Repair Materials
Utilities
Supplies, Local Taxes,
Admin. Exp., etc.
Ash Disposal
Sub-Total Direct Op. Costs
Capital Charges
BFW
Total Cost,
-------
Fuel
Fired in
External 803 Control
Particulate Control
INVESTMENTS, M $ (1)
Fuel Receiving, Storing,
Feeding Additions
Limestone Receiving, Storing,
Fedding Additions
Boiler
Stack
Electrostatic Precipitator
Flue Gas Scrubber System
Solid Waste Collection, Storage,
Disposal
Sub-Total (Before Contingency)
Contingency @ 20%
Process Development Allowance
For Scrubber
For FBC Boiler
TOTAL INVESTMENT, M $
ADDING A
Fluidized Bed
APPENDIX 3
TABLE 21
BREAKDOWN AND COMPARISON OF INVESTMENTS FOR
SINGLE 100 KPPH BOILER TO EXISTING OIL-FIRED BOILER PLANT
High Sulfur Coal
Boiler Conventional Stoker
Not Needed Limestone Scrubber
Electrostatic Precip. Scrubber
1.5
0.3
2.0
0.3
0.45
0.4
4.95
0.95
0.3
6.2
1.5
0.3
2.1
0.3
1.6
0.2
6.0
1.2
0.1
7.3
Low Sulfur "Compliance" Coal Low Sulfur Fuel Oil
Fluidized Bed Boiler
Not Needed
Electrostatic Precip.
1.6
0.1 (2)
2.0
0.3
0.45
0.4
4.85
0.95
0.3
6.1
Conventional Stoker Package Boiler
Not Needed Not Needed
Electrostatic Precip. Not Needed
1.6 0.1
-
fc
2.1 0.95 |
0.3 0.3 K,
0.45
0.4
4.85 1.35
0.95 0.25
-
5.8 1.6
(1) Investments expressed in 1st Q 1975 Dollars for project located at U.S. Gulf Coast.
(2) Limestone may not be used in an FBC boiler firing low sulfur compliance coal, but some facilities will be required to receive, store, and
feed the bed makeup material.
-------
A3 - 23
APPENDIX 3
TABLE 22
SCREENING INVESTMENTS FOR ADDING A SINGLE
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER TO EXISTING OIL-FIRED BOILER PLANT (1)
Base Case Derivative Cases
Steam Requirement, 1QQ 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, 1.8 2.2 2.7
Storing, Feeding Allowance
FBC Boiler, Stack (3) 3.1 4.9 7.6
Precipitator, Ash/ 1.3 2.1 3.4
Sulfated Stone
Collection, Storage,
Loading
Total 6.2 9.2 13.7
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) FBC Boiler investment represents current state of technology;
investment also includes 20% "process development" allowance
(0 3 M $ for base case) on commercially-undemonstrated sections.
-------
A3 - 24
APPENDIX 3
TABLE 23
SCREENING INVESTMENTS FOR ADDING A SINGLE
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER WITH FLUE GAS DESULFURIZATION
TO EXISTING OIL-FIRED BOILER PLANT (1)
Steam Requirement,
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving,
Storing, Feeding Allowance
Boiler, Stack
Flue Gas Scrubber (3),
Sludge and Ash Storage/
Loading
Total
Base Case
100
Derivative Cases
1.8
2.9
2.6
7.3
200
2.2
11.5
400
2.7
5.1 (4) 8.6 (4)
4.2 6.9
18.2
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) Scrubber investment includes 10% "process development" allowance
(0.1 M $ for base case) on critical sections.
(4) Boilers for 200 KPPH and higher are assumed to be Pulverized Coal
Fired (PCF) units. At 200 KPPH size, PCF boiler investment is
assumed 5% higher than for corresponding stoker boiler.
-------
A3 - 25
APPENDIX 3
TABLE 24
SCREENING INVESTMENTS FOR ADDING A SINGLE
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER TO EXISTING
OIL-FIRED BOILER PLANT (l->
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, Storing, 1.9 2.3 2.9
Feeding Allowance
FBC Boiler, Stack (3) 3.1 4.9 7.6
Precipitator, Ash/Inert 1.1 1.8 2.9
Bed Material Handling
and Storage
Total 6.1 9.0 13.4
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
(3) FBC Boiler investment represents current state of technology;
investment also includes 20% "process development" allowance
(0.3 M $ for base case) on commercially-undemonstrated sections.
-------
A3 - 26
APPENDIX 3
TABLE 25
SCREENING INVESTMENTS FOR ADDING A SINGLE
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER
TO EXISTING OIL-FIRED BOILER PLANT (1) (2)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (3)
Fuel Receiving, 1.9 2.3 2.9
Storing, Feeding Allowance
Boiler, Stack 2.9 5.1 (4) 8.6 (4)
Precipitator, Ash 1.0 1.6 2.6
Collection, Storage,
Loading
Total 5.8 9.0 14.1
(1) 1975 level, U.S. Gulf Coast location.
(2) Sulfur content of coal assumed sufficiently low that flue gas
desulfurization is not required.
(3) Investments include 20% contingency.
(4) Boilers for 200 KPPH and higher are assumed to be Pulverized
Coal Fired (PCF) units. At 200 KPPH size, PCF boiler investment
is assumed to be 5% higher than for corresponding stoker boiler.
-------
A3 - 27
APPENDIX 3
TABLE 26
SCREENING INVESTMENTS FOR ADDING A SINGLE
LOW-SULFUR-OIL-FIRED PACKAGE BOILER
TO EXISTING OIL-FIRED BOILER PLANT (1)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Investments, M$ (2)
Fuel Receiving, 0.1 0.1 0.2
Storing, Feeding Additions
Boiler, Stack
1.5 2.4 3.7
Total 1.6 2.5 3.9
(1) 1975 level, U.S. Gulf Coast location.
(2) Investments include 20% contingency.
-------
A3 - 28
APPENDIX 3
TABLE 27
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
FLUIDIZED BED HIGH-SULFUR-COAL-FIRED BOILER TO EXISTING OIL-FIRED BOILER PLANT
Base Case
Steam Requirement,
k Ibs/hr.
Costs, £/k Ibs. steam
-------
A3 - 29
APPENDIX 3
TABLE 28
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
CONVENTIONAL HIGH-SULFUR-COAL-FIRED BOILER WITH FLUE GAS DESULFURIZATION
TO EXISTING OIL-FIRED BOILER PLANT
Base Case
Steam Requirement,
k Ibs/hr.
Costs, C/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits
Repair Materials
Utilities
Limestone
Supplies, Local Taxes
Admin. Exp., etc.
Ash/Sludge Dispsoal
Sub-Total Direct Op. Costs
Capital Charges
BFW
Total Cost, C/k Ibs.
(ex fuel)
100
45
14
30
11
28
22
150
185
60
395
Derivative Cases
200
25
11
34
11
22
22
125
146
60
331
400
15
9
34
11
17
22
108
115
60
283
-------
A3 - 30
APPENDIX 3
TABLE 29
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
FLUIDIZED BED LOW-SULFUR-COAL-FIRED BOILER TO
EXISTING OIL-FIRED BOILER PLANT (1)
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Costs, <:/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits 36 21 12
Repair Materials 12 96
Utilities 25 25 25
Limestone - -
Bed Makeup Material -- ____ neglible ------
Supplies, Local Taxes, 23 17 13
Admin. Exp., etc.
Ash Disposal 4_ 4 4
Sub-Total Direct Op. Costs 100 76 60
Capital Charges 155 114 85
BFW 60 60 60
Total Cost, c/k Ibs. 315 250 205
'(ex fuel)
(1) Sulfur content of coal assumed sufficiently low that flue gas desulfurization
is not required.
-------
A3 - 31
APPENDIX 3
TABLE 30
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
CONVENTIONAL LOW-SULFUR-COAL-FIRED BOILER TO EXISTING OIL-FIRED BOILER PLANT(1)
Steam Requirement,
k Ibs/hr.
Costs, £/k Ibs. steam (ex
Wages, Salaries, Benefits
Repair Materials
Utilities
Supplies, Local Taxes,
Admin. Exp., etc.
Ash Disposal
Sub-Total Direct Op. Costs
Capital Charges
BFW
Total Cost,
-------
A3 - 32
APPENDIX 3
TABLE 31
UNIT OPERATING COSTS (EX FUEL) FOR ADDING A SINGLE
LOW-SULFUR-OIL-FIRED PACKAGE BOILER TO EXISTING OIL-FIRED BOILER PLANT
Base Case Derivative Cases
Steam Requirement, 100 200 400
k Ibs/hr.
Costs, C/k Ibs. steam (ex fuel)
Wages, Salaries, Benefits 18 10 6
Repair Materials 3 22
Utilities 19 19 19
Supplies, Local Taxes, 6 54
Admin. Exp., etc.
Sub-Total Direct Op. Costs 46 36 31
Capital Charges 41 32 25
BFW 60 60 60
Total Cost,
-------
APPENDIX 4
TABULATED DATA DERIVED FROM FEA'S NATURAL GAS
TASK FORCE AND MFBI SURVEYS
Index of Tables
Table No. Title
1 Capacity and Fuel Consumption Profiles of Large Industrial Boilers
£ Number and Fuel Consumption of Large Boilers used by the
following industries:
2 Food (SIC 20)
3 Paper (SIC 26)
4 Chemicals (SIC 28)
5 Petroleum Refining (SIC 29)
6 Stone, Clay, Glass, and Concrete (SIC 32)
7 Primary Metals (SIC 33)
8 Fabricated Metals Products (SIC 34)
9 Machinery, except Electrical (SIC 35)
10 Electricity, Gas and Sanitary Services (SIC 49)
11 Other Industries (i.e. not SIC 20, 26, 28, 29, 32, 33, 34, 35,
and 49)
12 No SIC Code specified in MFBI Survey
13 Number and Fuel Consumption of All Large Industrial Boilers
included in MFBI survey
14 Apparent Utilization of Large Boilers in 1974
15* 1974 Fuel Consumption of Large Industrial Boilers by Size Range
and SIC Code
16* Total Capacity of Large Industrial Boilers by Size Range and SIC Code
17* Number of Large Industrial Boilers by Size Range and SIC Code
18* 1974 Fuel Consumption of Large Industrial Boilers by Region and
Type of Fuel Used
19* Aggregate Capacity of Large Industrial Boilers by Region and
Primary Fuel Used
Q Installed Capacity of Large Industrial Boilers by Region, SIC Code,
and Primary Fuel Used in 1974:
20* Lower 48 States
21* New England
22* Appalachian
23* Southeast
24* Great Lakes
25* Northern Plains
26* Midcontinent
27* Gulf Coast
*based on data from Natural Gas Task Force survey.
-------
A4 - 2
Table No. Title
28* Rocky Mountain
29* Pacific Southwest
30* Pacific Northwest
31* Alaska, Hawaii, Puerto Rico, Virgin Islands
32* Regional Variations in Average Size of Large Industrial Boilers
by SIC Code
0 Number of Large Industrial Boilers by Size Range and 1974 Fuel
Consumption for Elements of:
33 Food and Kindred Products (SIC 201, 202, 203, 204, 205)
34 Chemicals (SIC 281, 282)
35 Stone, Clay, Glass, and Concrete Products (SIC 321/2,
324, 325, 327)
36 Primary Ferrous Metals (SIC 331, 332)
37 Non-Ferrous Metals and Miscellaneous (SIC 333/5, 339)
38 Fuel Consumption of Pulp, Paper and Paperboard Industry
39* Fuel Consumption of Large Industrial Boilers by Fuel Type and
SIC Code in 1974
40 Regional Fuel Consumption of Large Industrial Combustors by
Commercial Fuel Type in 1974
41* Coal Consumption, by Region, of All Large Industrial Combustors
(including Boilers) in 1974
*based on data from Natural Gas Task Force survey.
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
APPENDIX 4
TABLE 1
CAPACITY AND FUEL CONSUMPTION PROFILES OF LARGE INDUSTRIAL BOILERS
Number of Boilers
Units
20
5
17
31
47
77
71
98
152
191
327
473
917
1487
3913
% of Total
0.5
0.1
0.4
0.8
1.2
2.0
1.8
2.5
3.9
4.9
8.4
12.1
23.4
38.0
100.
z:%
0.5
0.6
1.0
1.8
3.0
5.0
6.8
9.3
13.2
18.1
26.5
38.6
62.0
100.
Fuel Consumption* in 1974
1014 BTU
1.10
0.144
0.643
1.05
1.42
2.27
1.60
2.13
2.63
3.10
4.28
4.93
6.51
7.77
39.6
% of Total
2.8
0.4
1.6
2.7
3.6
5.7
4.0
5.4
6.7
7.9
10.8
12.4
16.4
19.6
100.
21%
2.8
3.2
4.8
7.5
11.1
16.8
20.8
26.2
32.9
40.8
51.6
64.0
80.4
100.
Per Boiler
1012 BTU
5,
2,
3,
3.
3.
2.
50
88
78
38
06
95
2.25
2.18
1.73
1.62
1.31
1.04
0.71
0.52
1.01
fc
i
10
Summary
Slightly more than half of the capacity is in the 200+ million BTU/H size range.
Approximately one third of the capacity is in the 350+ million BTU/H size range.
Approximately 17% of the capacity is in the 500+ million BTU/H size range.
*Coal, oil, and natural gas; does not include "other" fuels such as black liquor.
Source: FEA MFBI Survey, Report No. 22
-------
APPENDIX 4
TABLE 2
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS USED BY FOOD INDUSTRY (SIC 20)
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Fuel Consumption* in 1974
Number of
Boilers
1
-
_
—
—
—
—
-
5
11
14
29
75
175
Coal
1000 Tons
-
_
_
-
-
_
-
107
478
209
344
343
407
Oil
1000 BBLS
_
_
_
-
_
-
-
55
275
3208
307
1251
4137
Gas
Billion CF
1.95
-
-
-
-
-
-
-
7.1
4.1
9.2
6.2
26.0
37.1
Total
Trillion BTU
2.0
-
-
-
-
-
-
-
10.0
16.7
34.2
15.9
42.0
72.7
% of
Total
1.0
-
-
-
-
-
-
-
5.2
8.6
17.7
8.2
21.7
37.6
S%
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
6.2
14.8
32.5
40.7
62.4
100.
310
1888
9233
91.6
193.
100.
*Coal, oil and natural gas; does not include "other" fuels such as bagasse.
Source: FEA MFBI Survey, Report No. 24A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
NUMBER AND FUEL
CONSUMPTION OF
APPENDIX 4
TABLE 3
LARGE BOILERS
USED BY PAPER INDUSTRY (SIC 26)
Fuel Consumption* in
Number of
Boilers
3
6
10
15
21
11
22
19
37
43
67
115
184
553
Coal
1000 Tons
134
_
284
180
438
198
658
535
467
541
160
1116
811
5522
Oil
1000 BBLS
54
1424
2234
3198
2685
2151
1183
2526
2142
4598
6128
5918
8315
42556
Gas
Billion CF
0.08
2.3
10.5
5.7
16.0
5.4
15.3
5.2
26.7
15.7
36.7
25.5
33.0
198.1
1974
Total
Trillion BTU
3.4
11.3
31.2
30.0
43.0
23.5
37.8
33.2
51.2
56.6
79.5
88.3
103.0
593.
% of
Total
0.6
1.9
5.3
5.0
7.3
4.0
6.4
5.6
8.6
9.6
13.4
14.9
17.4
100.
0.6
0.6
2.5
7.8
12.
20.
24.
30.
36.
44.
54.
67.
82.
100.
*Coal, oil and natural gas; does not include "other" fuel such as black liquor and bark.
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Number of
Boilers
3
1
3
1
1
17
10
19
31
46
97
143
187
255
814
[SUMPTION OF
Coal
1000 Tons
_
-
268
230
-
1048
269
197
455
908
1248
1876
1470
863
8832
TABLE 4
LARGE BOILERS
Fuel
Oil
1000 BBLS
40
150
-
-
-
1237
7
273
2228
1421
2286
3285
6401
5863
23191
USED BY CHEMICALS INDUSTRY (SIC
Consumption* in
Gas
Billion CF
10.5
-
12.2
-
4.4
23.7
23.9
35.5
35.2
43.7
84.5
113.8
88.4
95.4
571.4
1974
Total
Trillion BTU
10.9
0.9
18.5
5.2
4.5
55.4
30.5
42.3
60.2
73.9
128.0
179.0
163.0
153.0
926.
28)
% of
Total
1.2
0.1
2.0
0.6
0.5
6.0
3.2
4.6
6.5
8.0
13.8
19.4
17.6
16.5
100.
1.2
1.3
3.3
3.4
4.4
10.4
13.6
18.2
24.7
32.7
46.5
65.9
83.5
100.
*Coal, oil and natural gas; does not include "other" fuels (such as black liquor in paper industry).
Source: FEA MFBI Survey, Report No. 24 A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
APPENDIX 4
TABLE 5
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS
PETROLEUM REFINING
Number of
Boilers
2
3
22
11
17
14
31
25
43
61
59
76
364
Coal
1000 Tons
-
-
-
-
-
-
-
-
528
-
228
28
784
AND COAL PRODUCTS INDUSTRY
Fuel
Oil
1000 BBLS
-
309
2810
273
541
1187
95
867
1552
2537
1747
1940
13858
Consump t ion*
Gas
Billion CF
10.4
8.8
74.3
44.3
36.7
23.7
70.1
44.1
39.9
47.6
36.4
37.1
473.4
USED BY
(SIC 29)
in 1974
Total
Trillion BTU
10.6
10.9
93.3
46.9
40.7
31.6
72.0
50.3
62.3
64.5
53.2
50.3
587.
% of
Total
1.8
1.9
15.9
8.0
6.9
5.4
12.3
8.6
10.6
11.0
9.0
8.6
100.
-SL7,
1.8
3.7
19.6
27.6
34.
39.
52.
60.8
71.4
82.4
91.4
100.
,5
,9
,2
*Coal, oil and natural gas; does not include "other fuels" (such as black liquor in the paper industry)
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
TABLE 6
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS USED BY STONE, CLAY,
GLASS, AND CONCRETE PRODUCTS INDUSTRY (SIC 32)
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Number of
Boilers
Coal
1000 Tons
Oil
1000 BBLS
Fuel Consumption* in 1974
1
2
4
12
12
38
49
_2
51
53
40
109
750
872
1824
Gas
Billion CF
0.34
1.16
1.44
1.60
2.05
6.6
Total % of
Trillion BTU Total
I
00
0.07
1.43
2.15
7.45
7.60
3.5
7.4
11.1
38.6
39.4
3.5
10.9
22.0
60.6
100.
19.3
100.
*Coal, oil and natural gas; does not include "other" fuels (e.g. black liquor in paper industry).
Source: FEA MFBI Survey, Report No. 24A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
APPENDIX 4
TABLE 7
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS USED BY
PRIMARY METALS INDUSTRY (SIC 33)
Fuel Consumption* in
Number of
Boilers
4
3
6
8
5
10
17
20
23
33
21
58
74
99
381
Coal
1000 Tons
269
145
832
527
189
324
1179
1511
270
414
68
638
640
1247
8253
Oil
1000 BBLS
65
272
-
246
19
214
42
679
875
247
502
840
1053
1741
6795
Gas
Billion CF
5.15
6.74
5.63
7.61
7.62
1.90
8.44
5.70
7.59
49.03
12.68
39.64
34.87
17.93
210.5
1974
Total
Trillion BTU
11.7
il.8
24.5
21.1
12.2
10.6
35.5
44.2
19.3
60.9
17.6
60.0
56.5
57.4
443.
% of
Total
2.6
2.7
5.5
4.8
2.8
2.4
8.0
10.0
4.3
13.7
4.0
13.5
12.8
12.9
100.
2.6
5.3
10.8
15.6
18.4
20.8
28.8
38.8
43.1
56.8
60.8
74.3
87.1
100.
i
vO
*Coal, oil and natural gas; does not include "other" fuels (such as black liquor in paper industry).
Source: FEA MFBI Survey, Report No. 24A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Number of
Boilers
1
1
1
4
4
18
3
14
55
101
NUMBER AND FUEL
USED BY FABRICATED
Coal
1000 Tons
_
_
12
448
-
300
23
192
297
1272
APPENDIX 4
TABLE 8
CONSUMPTION
OF LARGE BOILERS
METAL PRODUCTS INDUSTRY (SIC
Fuel
Oil
100 BBLS
150
208
-
68
24
144
-
418
2117
3129
Consumption* in
Gas
Billion CF
-
0.05
-
-
0.4
2.8
-
2.6
6.2
12.1
34)
1974
Total
Trillion BTU
0.94
1.36
0.27
10.5
0.56
10.5
0.52
9.6
26.1
60.5
% of
Total
1.6
2.3
0.4
17.4
0.9
17.4
0.9
15.9
43.2
100.
1.6
1.6
3.9
4.3
21.7
22.6
40.0
40.9
56.8
100.
*Coal, oil and natural gas; does not include "other" fuels (such as blast furnace gas in steel industry).
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
TABLE 9
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS USED BY
MACHINERY (NON-ELECTRICAL) INDUSTRY (SIC 35)
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Fuel Consumption* in 1974
Number of
Boilers
1
6
6
22
63
101
Coal
1000 Tons
Oil
1000 BBLS
Gas
Billion CF
34
106
82
92
314
58
328
164
842
1392
8.4
9.0
1.5
5.8
8.7
33.4
Total
Trillion
BTU
8.6
0.3
9.9
5.9
8.8
16.1
49.7
% of
Total
17.3
-
0.7
20.0
12.0
17.6
32.4
17.3
17.3
18-. 0
38.0
50.0
67.0
100.
100.
*Coal, oil and natural gas; does not include "other" fuels (such as blast furnace gas in steel industry).
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
TABLE 10
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS USED BY
ELECTRICITY, GAS, AND SANITARY SERVICES INDUSTRY (SIC 49)
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Fuel Consumption* in 1974
Number of
Boilers
5**
-
-
-
-
1
1
3
4
2
-
10
41
39
Coal
1000 Tons
2343
-
-
-
-
-
-
-
-
31
-
14
49
76
Oil
1000 BBLS
238
-
-
-
-
159
-
357
664
-
-
152
2037
830
Gas
Billion CF
-
-
-
-
-
0.04
-
-
3.23
-
5.34
3.88
4.02
Total
Trillion BTU
54.4
-
-
-
-
1.0
0.04
2.2
4.2
4.0
-
4.7
17.6
11.0
% of
Total
54.9
-
-
-
-
1.0
negl.
2.3
4.2
4.0
-
4.7
17.8
11.1
21%
54.9
54.9
54.9
54.9
54.9
55.9
55.9
58.2
62.4
66.4
66.4
71.1
88.9
100.
>
i
i— >
1-0
106
2513
4437
14.6
99.1
100.
*Coal, oil and natural gas; does not include "other" fuels (such as carbon monoxide in petroleum refining industry).
**it is possible that these 5 boilers are electric utility, not industrial, boilers. Note that 93% of the,«oal
consumption by SIC 49 is attributable to these 5 boilers.
Source: FEA MFBI Survey, Report No. 24A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
NUMBER AND FUEL CONSUMPTION
INDUSTRIES
Number of
Boilers
4**
3
3
7
8
8
26
21
46
63
254
412
855
OTHER THAN SIC
Coal
1000 Tons
2100
_
110
286
377
475
903
386
657
402
2230
1548
9474
APPENDIX 4
TABLE 11
OF LARGE BOILERS USED BY
20, 26, 28
Fuel
Oil
1000 BBLS
57
1397
765
1065
371
1757
3576
1491
3786
3640
7201
12665
37771
, 29, 32, 33,
Consumption*
Gas
Billion CF
0.07
0.65
0.41
5.37
7.68
4.10
6.55
11.46
11.30
25.64
50.56
102.30
226.1
MANUFACTURING
34, 35 and 49
in 1974
Total
Trillion BTU
47.8
9.4
7.7
18.6
18.6
25.9
49.5
29.7
50.1
57.4
146.0
218.0
681.
% of
Total
7.0
1.4
1.1
2.7
2.7
3.8
7.3
4.4
7.4
8.5
21.5
32.2
100.
7.0
7.0
7.0
8.4
9.5
12.2
14.9
18.7
26.0
30.4
37.8
46.3
67.8
100.
*Coal, oil and natural gas; does not include "other" fuels (such as acid sludge in chemicals industry).
**it is questionable whether these 4 boilers are actually industrial boilers. The 1974 fuel consumption
data indicate that these 4 boilers have an average steam generation capacity equivalent to a heat
input of at least 1.3 billion BTU/H, which would be more typical of electric utility boilers.
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
TABLE 12
NUMBER AND FUEL CONSUMPTION OF LARGE BOILERS FOR WHICH NO
SIC CODE WAS SPECIFIED IN FEA'S MFBI SURVEY
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
70Q - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
Fuel Consumption* in 1974
Number of
Boilers
Coal
1000 Tons
Oil
1000 BBLS
3223
6**
7
9
13
12
37
31
64
110
-
-
-
145
376
491
542
763
1002
Gas
Billion CF
3.8
294
3319
5156
457
925
266
708
2651
890
2771
2792
19839
7.8
8.0
11.3
11.5
13.7
42.2
18.7
22.1
22.9
162.1
Total
Trillion BTU
24.0
% of
Total
6.6
6.6
37.8
11.0
17.3
16.6
26.9
70.7
36.7
57.2
63.5
362.
10.5
3.0
4.8
4.6
7.4
19.5
10.1
15.9
17.6
100.
17.1
20.1
24.9
29.5
36.9
56.4
66.5
82.4
100.
>
i
>-*
-P>
*Coal, oil and natural gas; does not include "other fuels" (such as waste heat derived from combustion of
catalyst coke in petroleum refining).
**the fuel consumption data imply that these 6 boilers were operated at 120% capacity throughout 1974 — or
else that the fuel consumption data are in error.
Source: FEA MFBI Survey, Report No. 24A
-------
Size Range
Million BTU/H
1000 +
900 - 999
800 - 899
700 - 799
600 - 699
500 - 599
450 - 499
400 - 449
350 - 399
300 - 349
250 - 299
200 - 249
150 - 199
100 - 149
Total
APPENDIX 4
TABLE 13
NUMBER AND FUEL CONSUMPTION OF ALL* LARGE INDUSTRIAL
BOILERS
INCLUDED IN FEA'S MFBI SURVEY
Fuel Consumption** in
Number of
Boilers
11
5
17
31
47
77
71
98
152
193
327
475
917
1487
3908
Coal
1000 Tons
403
145
1100
1041
491
2544
2023
2841
2415
3060
4076
4105
7162
6378
37779
Oil
1000 BBLS
159
572
1417
7617
6792
10857
3569
6361
10285
7286
18767
18216
29711
42114
163730
Gas
Billion CF
17.6
6.7
30.6
31.5
92.5
99.1
90.2
104.2
143.3
196.7
228.5
294.7
297.7
366.7
2000.
1974
Total
Trillion BTU
28.0
13.7
64.5
103.3
148.0
224.0
160.0
210.0
265.0
315.0
442.0
506.0
651.0
780.0
3908.
% of
Total
0.7
0.4
1.7
2.6
3.8
5.7
4.1
5.4
6.8
8.1
11.3
12.9
16.6
19.9
100.
0.7
1.1
2.8
5.4
9.2
14.9
19.0
24.
31.
39.
50.
63.
80.
100.
.4
.2
.3
,6
.5
.1
*except for 5 boilers in SIC 49 and 4 boilers in "other SIC's" that appear to be wrongly coded electric utility
boilers.
**coal, oil and natural gas; does not include "other" fuels (such as black liquor in the paper industry).
Source: FEA MFBI Survey, Report No. 24A
-------
APPENDIX 4
TABLE 14
APPARENT UTILIZATION OF LARGE BOILERS IN 1974
Size Food
Range SIC
M BTU/H 20
1000 + 22
900-999
800-899
700-799
600-699
500-599
450-499
400-449
350-399 61
300-349 53
250-299 60
200-249 28
150-199 37
100-149 39
% of
Paper
SIC
26
12
-
25
48
35
43
52
46
52
49
55
61
51
52
Theoretical
Chemicals
SIC
28
40
11
83
79
79
68
73
60
59
57
55
64
57
56
Boiler
Pet. Ref
SIC
29
_
-
71
55
75
91
58
61
71
71
61
54
59
62
Utilization in
Ceramics
SIC
32
-
-
-
-
-
-
-
-
24
30
28
41
37
1974 Based
P. Metals
SIC
33
32
47
55
40
43
22
50
60
26
65
35
53
50
54
on Consumption
of Coal,
F. Metals Equip. U
SIC
34
11
-
21
48
55
-
-
-
5
24
9
45
45
SIC
35
_
-
-
-
-
-
77
-
12
69
51
26
24
Oil &
Natural Gas*
. Services
SIC
49
119«5
-
-
-
_
21
1
20
32
71
-
24
28
26
Other
SIC's
130j$
_
-
48
45
55
56
87
58
50
46
47
38
50
Not
Specif.
-
-
73
-
131?$
38
52
39
79
80
61
59
54
Total
28«4«S
33
51
51
55
61
54
58
53
58 a
56 3
55
47 J
49
Arithmetic average utilization of all boilers in 100-899 Million BTU/H size range
46 47 66 66 32 46 32 43
Fuel Consumption (coal, oil and natural gas; does not include "other" fuels)
1012
BTU's 193 593 926 587 19 443 61 50
% of
Total
4.9 15.2
23.7
15.0
0.5
11.3
1.5
1.3
28
45
1.2
53
633
16.2
54**
362
9.2
54
3912
100.
*does not include the consumption of "other" fuels (by-product fuels) such as black liquor, bagasse, catalyst coke, etc.
tdata appear questionable
(^excluding questionable data in SIC 49 and "other SIC's"
**correcting for questionable data in "SIC not specified"
-------
APPENDIX 4
TABLE 15
1974 FUEL CONSUMPTION OF LARGE INDUSTRIAL
BOILERS BY SIZE RANGE AND SIC CODE
Size Range 10 BTU/H
SIC 20
SIC 26
SIC 28
SIC 29
SIC 32
SIC 331/2
SIC 333/9
Other SIC's
Not Spec.
Total
Aggregate 1974
100/149
70.2
105.0
152 .0
47 .9
7.3
44.3
8.2
280.0
62 .3
778
150/199
41.4
91.5
166.0
46.5
7.4
49.5
5.7
181.0
57.2
647
200/299
49.2
137.0
299.0
118.0
3.6
67.4
10.6
134.0
104.0
926
12
Fuel Consumption, 10 BTU
300/399
26.4
86.1
140.0
112.0
0.6
34.1
49.2
83.7
41.0
573
400/499
NIL
62 .9
59.9
82.2
NIL
72 .9
10.3
57.0
28.3
373
500+
2.1
120.0
93.0
156.0
NIL
96.1
6.5
127.0
63
664
Total
189
604
912
563
19
364
91
864
356
3962
Source: Natural Gas Task Force Survey
-------
Size Range, 10 BTU/H
20
26
28
29
32
SIC Code/Industry
Food
Paper
Chemica Is
Petroleum Refining
Stone, Clay, Glass, Concrete
331/332 Blast Furnaces/I & S Foundries
333/339 Other Primary Metals
Other SlC's
No SIC Code Specified
Subtotal as % of Total
APPENDIX 4
TABLE 16
TOTAL CAPACITY OF LARGE INDUSTRIAL
BOILERS BY SIZE RANGE AND SIC CODE
9
Aggregate Boiler Capacity, 10 BTU/H
100/
21
23
33
9
2
9
2
73
14
190
20
149
.7
.4
.7
.8
.3
.7
.0
.0
.9
.6
.4
150/
12
20
33
9
2
12
1
60
12
165
17
199
.8
.4
.8
.5
.3
.6
.4
.0
.4
.2
.7
200/299
11
31
59
26
1
17
2
40
19
209
22
.0
.6
.7
.1
.5
.5
.6
.2
.6
.5
.4
300/399
5
21
30
20
0
14
6
20
9
127
18
.4
.0
.1
.0
.3
.0
.3
.9
.5
.5
.6
400/499
--
16.7
10.9
15-4
--
13.0
1.8
11.9
7.9
77 .7
8.3
500+
3
49
19
24
-
26
0
31
7
164
17
.1
.8
.5
.8
-
.9
.7
.5
.8
.1
.6
Total
53.9
162.8
187.8
105.7
6.4
93.7
14.7
237.5
72.0
934.7
100
I
oo
Source: Natural Gas Task Force Survey
-------
Size Range, 10 BTU/H
SIC 20 Number
% of Subtotal
SIC 26 Number
% of Subtotal
SIC 28 Number
1 of Subtotal
SIC 29 Number
% of Subtotal
SIC 32 Number
% of Subtotal
SIC 331/332 Number
% of Subtotal
j>IC 333/339 Number
7, of Subtotal
Other SIC's Number
% of Subtotal
Not Spec . Number
70 of Subtotal
Totals Number
7= of Subtotal
APPENDIX
4
TABLE 17
NUMBER OF LARGE INDUSTRIAL
BOILERS BY SIZE RANGE AND SIC CODE
100/149
184
56.5
194
31.7
272
31.6
81
21.5
19
48.7
79
23.6
17
28.8
611
48.8
126
37 .5
1583
37.8
150/199
76
23.3
119
19.4
197
23.0
55
14.6
13
33.3
73
21.7
8
13.6
352
28.1
73
21.7
966
23.0
200/299
47
14.4
132
21.5
247
28.8
108
28.8
6
15.4
76
22.6
10
16.9
168
13.4
79
23.5
873
20.8
300/399
16
4.9
62
10.1
89
10.4
58
15.4
1
2.6
40
11.9
19
32.2
60
4.8
28
8.3
373
8.9
400/499
--
38
6.2
25
2.9
35
9 .3
—
30
8.9
4
6.8
27
2.1
18
5.4
177
4.2
500+
3
0.9
68
11.1
28
3.3
39
10.4
—
38
11.3
1
1.7
35
2.8
12
3.6
224
5.3
70 of Grand
Subtotal Total
326 7.8
100
6 13 14 . 6
100
858 20.4
100
376 9.0 £
100 ,
39 0.9 *>
100
336 8.0
100
59 1.4
100
1253 29.9
100
336 8.0
100
4196 100
100
Source; Natural Gas Task Force Survey
-------
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountains
Pacific S.W.
Pacific N.W.
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountains
Pacific S .W.
Pacific N.W.
Lower 48 States
APPENDIX 4
TABLE 18
1974 FUEL CONSUMPTION OF LARGE INDUSTRIAL
BOILERS BY REGION AND TYPE OF FUEL USED
1974 Fuel
Coal
NIL
412
190
248
27 .6
6.2
34.1
36.9
2.5
8.3
966
Percent
NIL
43.6
34.3
42.5
35.3
8.9
2 .8
29.5
2.0
8.7
24.8
Res id
95.1
305
159
61.4
3.4
0.03
76.2
26.5
10.3
11.8
747
Breakdown
90.9
32.3
28.7
10.5
4.3
negl
6.3
21.2
8.4
12.3
19.2
12
Consumption, 10 BTU
Dist .
NIL
8
4
.
,
48.
2
1
1
1
0
0
.
,
M
,
.
0
1
1
1
5
2
5
9
1
68
of Fuel
Consumption
NIL
0
0
8
2
2
0
1
0
0
1
.
,
.
.
.
.
.
.
.
8
7
2
7
2
1
2
7
1
8
Gas
3.4
152
113
169
42.7
60.5
1050
59.6
99.5
70.0
1820
Within
3.2
16.1
20.4
29.0
54.6
86.9
86.7
47.8
80.7
73.1
46.8
Other
6
67
88
57
2
1
49
0
10
5
.2
.7
.4
.3
.4
.4
.5
.4
.1
.6
289
Regions
5
7
15
9
3
2
4
0
8
5
7
.9
.2
.9
.8
.1
.0
.1
.3
.2
.8
.4
Total
104
946
555
584
78
69
1210
125
123
95
3890
.1
.6
.9
% of
Lower 48
2.67
24.32
14.27
15.01
.00
.79
31.10
3.21
3.16
2.47
100
2
1
N>
o
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 19
AGGREGATE CAPACITY OF LARGE INDUSTRIAL
BOILERS BY REGION AND BY PRIMARY FUEL FIRED
g
Aggregate Boiler Capacity^ 10 BTU/H
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S .W.
Pacific N.W.
Coal
NIL
83.3
35.6
52 .7
5.6
2 .1
4.3
7.5
1.6
3.8
196.5
Res id
22.6
74.3
36.1
19.0
1.1
0.3
13.7
2.4
2 .2
3.4
175.1
Percentage Distribution of Capacity
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific S.W.
Pacific N.W.
Lower 48 States
NIL
34.7
24.1
35.9
30.6
10.4
1.9
31.0
4.5
12.4
21.3
86.2
30.8
24.5
12.9
6.0
1.5
6.0
9.9
6.2
11.1
19.0
Dist.
NIL
4.9
2.2
6.4
1.1
0.4
0.2
0.6
0.4
0.1
16.3
Within Regions
NIL
2.0
1.5
4.3
6.0
2.0
0.1
2.5
1.0
0.3
1.8
Gas
1.0
43.0
28.5
44.5
10.1
14.6
184.7
12.8
26.7
15.3
381.3
by Primary
3.8
17.8
19.4
30.2
55.2
72.2
80.2
52.9
75.0
50.0
41.4
Other
2.6
35.5
45.1
24.6
0.4
2.8
27.1
0.9
4.7
8.0
151.7
Fuel Used
10.0
14.7
30.5
16.7
2.2
13.9
11.8
3.7
13.2
26.2
16.4
Total
26.2
241.0
147.6
147.2
18.3
20.2
230.0
24.2
35.6
30.6
920.9
in 1974
% Of
Lower 48
I
ho
Source: Natural Gas Task Force Summary
-------
Coal
Total
No.
69
93
182
7
4
127
6
306
78
872
Cap .
12.6
21.2
41.7
1.7
0.6
38.2
1.1
66.4
13.2
196.7
APPENDIX 4
TABLE 20
IN
INSTALLED CAPACITY
LOWER 48 STATES BY SIC
Res id
No.
46
169
140
62
13
15
15
331
71
862
Cap
6
42
25
16
2
2
2
61
15
175
.
.3
.4
.4
.4
.1
.4
.8
.6
.8
.1
OF LARGE INDUSTRIAL BOILERS
CODE AND PRIMARY FUEL USED IN 1974
Dist .
No.
11
8
11
--
1
3
--
43
13
90
Cap .
1
1
1
-
0
0
-
7
3
16
.5
.3
.8
-
.1
.5
-
.3
.8
.3
Nat.
No.
190
174
472
273
17
38
32
458
130
1784
. Gas
Cap
31
37
105
78
2
10
9
76
29
381
Other
.
.4
.5
.3
.5
.9
.8
.2
.4
.3
.4
No.
6
167
42
22
4
153
6
76
38
514
Cap
1
60
10
7
0
41
1
19
9
151
.3
.2
.3
.2
.6
.8
.6
.5
.0
.5
Total
No.
322
611
847
364
39
336
59
1214
330
4122
Cap
921.1
223 ^>
NOTES: "No." refers to the number of large industrial boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers, expressed in 10 BTU/H.
"N.S." denotes SIC Code not specified.
Data for Alaska, Hawaii, Puerto Rico and Virgin Islands are tabulated separately and are not included above.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 21
INSTALLED CAPACITY OF LARGE INDUSTRIAL
BOILERS IN NEW ENGLAND BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Coal Res id Dist .
No. Cap. No.
6
27
14
__
2
3
4
52
7
Cap . No . Cap .
830
6178
2556
__
398
375
722
10471
1107
Nat
No.
1
1
—
--
--
—
2
3
--
. Gas
Cap.
105
101
--
--
--
--
390
398
—
Other
No.
__
4
--
--
-_
--
--
5
3
Cap .
..
951
—
--
--
--
—
1032
600
Total
No.
7
32
14
--
2
3
2
60
10
Cap.
935
7230
2556
--
398
375
1112
11901
1707
Aver.
Size
134
226
183
--
199
128
185
198
171
Total
115
22637
12
12
2583
134
26214
196
NJ
U>
NOTES: "No." refers to the number of large industrial boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 106 BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 22
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN
APPALACHIAN REGION BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Coal
No.
5
41
99
2
4
72
2
109
36
Cap.
539
10336
21736
211
633
21993
370
21462
6061
Res id
No.
23
51
80
23
9
4
9
163
38
Cap .
3553
10219
14468
4569
1399
650
1433
30855
7195
Dist .
No.
3
8
2
-
1
-
-
17
2
Cap .
436
1251
255
--
121
--
--
2484
310
Nat
No.
28
16
51
21
12
13
3
61
13
. Gas
Cap.
3496
2717
9628
7393
1918
2025
300
12842
2701
Other
No.
__
20
3
7
4
87
--
9
—
Cap.
•• «.
780
368
2027
648
23068
--
2344
--
Total
No.
59
136
235
53
30
176
14
359
89
Cap .
8024
31603
46455
14200
4719
47736
2103
69987
16267
Aver .
Size
136
232
198
218
157
271
150
195
183
Total
370
83341
400
74341
33
4857
218
43020
130
35535
1151
241094
209
NOTES: "No." refers to the number of large industrial boilers in each category.
"Cap1.1 refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10" BTU/H.
"N.S." denotes SIC Code not specified.
Source;
Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 23
INSTALLED CAPACITY OF
SOUTHEAST BY SIC CODE AND
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Total
Coal
No.
..
23
60
--
__
8
__
58
4
153
Cap.
..
5985
14376
--
--
1672
--
12991
898
35622
Res id
No.
8
56
31
--
__
--
--
60
9
164
Cap .
866
17639
5170
—
--
--
--
10140
2328
36143
Sist .
No , Cap .
..
__
2 560
__
__
__
__
8 1619
__
10 2179
LARGE INDUSTRIAL BOILERS
PRIMARY FUEL USED IN 1974
Nat
No.
6
27
45
.__
_.
__
--
49
15
142
. Gas
Cap.
869
7193
8803
--
._
_.
. —
7750
3936
28551
Other
No.
5
73
13
—
--
3
--
26
9
129
Cap.
1052
27932
4063
--
__
469
--
8995
2590
45101
Total
No.
19
179
151
—
--
11
—
201
37
598
Cap .
2787
58749
32972
--
__
2141
--
41495
9452
147596
Aver.
Size
147
328
218
__
__
195
—
206
255
247
NOTES: "No." refers to the number of large industrial boilers in each category.
,-.6
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10" BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10^ BTU/H,
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 25
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN NORTHERN
PLAINS REGION BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Total
Coal
No.
20
5
--
--
--
--
—
9
--
34
Cap.
3504
694
--
--
--
--
—
1446
--
5644
Res id
No.
_.
2
-
3
-
-
-
1
-
6
Cap.
— —
388
--
625
--
—
--
115
—
1128
Dist ,
No.
5
-
-
-
-
-
-
1
1
7
Cap .
748
--
--
--
--
—
--
150
173
1071
Nat
No.
19
17
3
-
-
-
-
18
2
59
. Gas
Cap.
2983
3362
330
--
--
--
--
3050
394
10119
Other Total
No. Cap. No.
44
24
3
3
_
-
-
1 360 30
3
1 360 107
Cap.
7235
4444
330
625
--
.-
--
5121
567
18322
Aver .
Size
164
185
110
208
--
--
-_
171
189
171
>
.p-
NOTES: "No." refers to the number of large individual boilers in each category. ,
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10° BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 26
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN
MIDCONTINENT REGION BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Total
Coal Res id
No.
4
-
5
-
_
-
-
4
-
13
Cap . No . Cap .
600 1 107
__
921 1 235
__
__
__
__
614
__
2 135 2 342
Dist .
No.
1
-
2
-
_
_
-
-
-
3
Cap .
144
--
275
--
__
__
--
--
--
419
Nat
No.
9
2
9
27
_
2
-
39
5
98
. Gas
Cap .
1687
246
1367
4851
—
212
--
5609
650
14622
Other
No.
3
-
1
_
_
-
1
-
5
Cap.
..
2249
--
364
__
_-
--
138
--
2751
Total
No.
15
5
17
28
__
2
__
44
5
116
Cap.
2538
2495
2798
5215
__
212
--
6361
650
20269
Aver.
Size
169
499
165
186
--
106
--
145
130
175
>
i
00
NOTES: "No." refers to the number of large individual boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10^ BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 27
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN GULF COAST
REGION BY SIC CODE AND BY PRIMARY FUEL USED IN 1974
SIC Coal Resid Dist.
Code No. Cap. No. Cap. No. Cap.
20 - -
26 - - 20 5834
28 - - 6 1461
29 - - 6 2708
32 - -
331/2 - - - -
333/9 - - -
Other 4 3644 8 1524
N. S. 3 636 3 2124 1 243
Total 7 4280 43 13651 1 243
Nat.
No.
21
33
325
169
-
18
110
42
725
Gas .
Cap.
5404
8136
79164
53736
-
5430
19894
12921
184685
No.
1
41
23
2
-
2
16
11
96
Other
Cap .
215
15069
5035
619
-
450
2946
2734
27068
No.
22
94
354
177
-
2
18
138
67
872
Total
Cap.
5619
29039
85660
57063
-
450
5430
28008
18658
229927
Av.
Size
255
309
242
322
-
225
*-
302 i
NJ
203 *°
278
264
NOTES: "No." refers to the number of large individual boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aw Size" refers to the aggregate capacity divided by the number of boilers in 106 BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 28
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN ROCKY
MOUNTAIN REGION BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Total
Coal
No.
7
—
4
--
__
16
--
4
1
32
Cap .
1178
--
1916
—
__
3453
--
757
240
7544
Res id
No.
1
__
--
--
—
--
9
4
14
Cap.
100
--
--
--
__
—
--
1351
905
2356
Dist .
No.
-
1
-
_
_
-
2
1
4
Cap .
--
152
__
—
319
102
573
Nat
No.
16
1
7
3
7
23
11
68
. Gas
Cap.
3022
280
1186
615
__
__
2649
2947
2112
12811
Other
No.
.
1
-
-
_
_
-
1
3
5
Cap.
..
190
--
--
__
—
-_
100
565
855
Total
No.
24
2
12
3
—
16
7
39
20
123
Cap.
4300
470
3254
615
—
3453
2649
5474
3920
24139
Aver .
Size
179
235
271
205
__
216
378
140 *•
196 "
196 °
NOTES: "No." refers to the number of large individual boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10^ BTU/H.
"N.S." denotes SIC Code not specified.
Source; Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 29
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN PACIFIC SOUTHWEST REGION
BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N. S.
Total
Coal Resid Dist. Nat.
No. Cap. No. Cap. No. Cap. No.
48
12
3 1024 2 472 3 416 1
45
2
_.---__
3 619 2 651 2
3 888 - 33
1 180 8
6 1643 8 2191 3 416 151
Gas Other
Cap. No. Cap.
7684
2212 2 396
160
9599 2 1260
236
7 2500
438
4802 1 304
1549 1 300
266680 13 4740
No.
48
14
9
47
2
7
7
37
10
181
Total
Cap.
7684
2608
2070
10839
236
2500
1708
5994
2029
35668
Av.
Size
160
186
230
231
118
357
244
162
203
197
u>
NOTES: "No." refers to the number of large individual boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Av. Size" refers to the aggregate capacity divided by the number of boilers in 10^ BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Survey
-------
SIC
Code
20
26
28
29
32
331/2
333/9
Other
N.S.
Total
APPENDIX 4
TABLE 30
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN
PACIFIC NORTHWEST REGION BY SIC CODE AND PRIMARY FUEL USED IN 1974
Coal
No.
15
9
24
Cap .
2932
900
3832
Res id
No. Cap.
6 1195
10 2104
1 100
17 3399
Dist. Nat
No . Cap . No .
10
31
- - - 2
4
1 112 26
8
1 112 81
. Gas
Cap .
1181
7259
216
1020
4307
1352
15335
Other
No.
14
1
13
6
34
Cap.
4211
112
2837
820
7980
Total
No.
25
51
2
5
50
24
157
Cap.
4113
12665
216
1132
9360
3172
30658
Aver .
Size
165
248
108
226
187
132
195
fc
w
10
NOTES: "No." refers to the number of large individual boilers in each category.
"Cap." refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
"Aver. Size" refers to the aggregate capacity divided by the number of boilers in 10^ BTU/H.
"N.S." denotes SIC Code not specified.
Source: Natural Gas Task Force Survey
-------
APPENDIX 4
TABLE 31
INSTALLED CAPACITY OF LARGE INDUSTRIAL BOILERS IN ALASKA, HAWAII, PUERTO RICO,
AND VIRGIN ISLANDS BY SIC CODE AND PRIMARY FUEL USED IN 1974
SIC Coal Resid Dist.
Code No. Cap. No. Cap. No. Cap.
20 - - 1 220
26 -
28 - - 8 2783
29 - 4 685 4 525
32 ...
331/2 ... _
333/9 - ...
Other 27 3960 -
N. S. - - 2 266
Total 27 3960 15 3954 4 525
Nat. Gas
No . Cap .
-
-
3 433
4 815
_
_
-
8 1180
4 621
19 3049
Other
No. Cap. No.
3 671 4
2 340 2
11
12
_
_
_
4 1125 39
6
9 2136 74
Total
891
340
3216
2025
-
-
-
6265
887
13624
Av.
Size
223
170
292
169
-
-
-
161
148
184
NOTES: ^No."^refers to the number of large individual boilers in each category. fi
()Cap. refers to the aggregate capacity of the pertinent group of boilers in 10 BTU/H.
Av. Size" refers to the aggregate capacity divided by the number of boilers in 106 BTU/H.
N.S." denotes SIC Code not specified.
Source: Natural Gas Task Survey
I
OJ
-------
APPENDIX 4
TABLE 32
REGIONAL VARIATIONS IN AVERAGE SIZE OF LARGE INDUSTRIAL BOILERS BY SIC CODE
Average Boiler Size, 106 BTU/H
Region
New England
Appalachian
Southeast
Great Lakes
Northern Plains
Midcontinent
Gulf Coast
Rocky Mountain
Pacific Southwest
Pacific Northwest
Lower 48 States
20
134
136
147
166
164
169
255
179
160
165
165
26
226
232
328
178
185
499
309
235
186
248
266
28
183
198
218
166
110
165
242
271
230
108
218
29 32
199
268 157
292 210
208
186
322
205
231 118
226
285 164
331/2
128
271
195
310
106
225
216
357
___
279
333/9
185
150
241
302
378
244
___
249
Other
198
195
206
186
171
145
203
140
162
187
191
All
196
209
247
215
171
175
264
196
197
195
223
Number of
Large Boilers
134
1151
598
683
107
116
872
123
181
157
4122
OJ
-p-
Source: Calculated from data reported in Natural Gas Task Force Survey
-------
A4 - 35
APPENDIX 4
TABLE 33
NUMBER OF LARGE INDUSTRIAL BOILERS BY SIZE RANGE AND
1974 FUEL CONSUMPTION FOR ELEMENTS OF THE FOOT)
SIC 201 Meat Products
Size Range
10° BTU/H
100-149
150-199
Number of
Boilers
8
_4
12
Fuel Consumed
1012 BTU
3.4
2.8
6.2
SIC 202 Dairy Products
Size Range
106 BTU/H
100-149
Number of
Boilers
Fuel Consumed
1012 BTU
0.5
SIC 203 Canned, Cured, and Frozen Foods
Size Range
106 BTU/H
100-149
150-199
200-249
Number of
Boilers
39
8
_2
49
Fuel Consumed
1012 BTU
12
1.5
0.4
14
SIC 204 Grain Mill Products
Size Range
10 BTU/H
100-149
150-199
200-249
250-299
300-349
350-399
Number of
Boilers
23
21
6
2
7
_2
61
Fuel Qpnsumed
10 BTU
9
20
6
3
12
_5.
54
SIC 205 Bakery Products
No large boilers
un *.«M.,t:tc8 for SIC 206 (Sugar), SIC 207 (Confectionery and
Note: Comparable statist"S tor b J, } and SIC 209 (Miscellaneous,
Xelated Products), SIC^ 208 JBeverag^;^^ ^ ^ ^ ^^ ^^ ^
_ £ 1 J 1 ^^ f..rt 1 O "[0
Ln 1974
e-ts listed above.
Source: FEA's MFBI survey, Report No. 25
-------
A4 - 36
APPENDIX 4
TABLE 34
NUMBER OF LARGE INDUSTRIAL BOILERS BY
CONSUMPTION FOR SEGMENTS OF THE
SIC 281 Industrial
Size Range
106 BTU/H
100-149
150-199
200-249
250-299
300-349
350-399
400-449
450-499
500-599
600-699
700-799
800-899
900-999
1000+
Chemicals
Number of Fuel
Boilers 10
83
58
58
32
13
9
5
4
4
1
1
3
-
2
273
SIZE RANGE
CHEMICALS
Consumed
12 BTUs
58
52
85
43
28
20
14
12
15
4
5
19
-
7
361
AND 1974 FUEL
INDUSTRY
% of Fuel
Consumed
16.1
14.2
23.5
11.8
7.7
5.6
3.9
3.2
4.2
1.2
1.4
5.1
-
1.9
100
SIC 282 Plastics Materials and Synthetics
Size Range
106 BTU/H
100-149
150-199
200-249
250-299
300-349
350-399
400-449
500-599
900-999
Number of Fuel
Consumed
Boilers 10iz BTUs
57
52
54
32
15
9
3
2
1
225
29
45
59
40
21
18
5
5
1
224
% of Fuel
Consumed
12.9
20.3
26.3
17.7
9.6
8.1
2.3
2.4
0.4
100
Source: FEA's MFBI Survey, Report No. 25
-------
A4 - 37
APPENDIX 4
TABLE 35
NUMBER OF LARGE INDUSTRIAL BOILERS BY SIZE RANGE AND 1974 FUEL
CONSUMPTION FOR STONE. CLAY. GLASS, AND CONCRETE PRODUCTS INDUSTRIES (SIC 32)
SIC 321/2 Glass
Size Range
106 BTU/H
Number of
Boilers
Fuel Consumed
1012 BTUs
100-149
150-199
200-249
250-299
300-349
5
1
3
2
J.
12
1.2
0.6
1.2
1.4
0.7
5.1
SIC 324 Cement
Size Range
1Q6 BTU/H
150-199
Number of
Boilers
Fuel Consumed
1Q12 BTUs
1.0
SIC 325 Clay Products
Size Range
106 BTU/H
Number of
Boilers
No large boilers
Fuel Consumed
1Q12 BTUs
SIC 327 Concrete
Size Range
106 BTU/H,
100-149
Number of
Boilers
Fuel Consumed
1QJ2 BTUs
2.5
Source:
FEA's MFBI Survey, Report No.
25
-------
A4 - 38
APPENDIX 4
TABLE 36
NUMBER OF LARGE INDUSTRIAL BOILERS BY SIZE RANGE AND 1974 FUEL
CONSUMPTION FOR SIC 331 '(BLAST FURNACES, BLAST STEEL PRODUCTS)
Size Range
106 BTU/H
100-149
150-199
200-249
250-299
300-349
350=399
400-449
450-499
500-599
600-699
700-799
800-899
900-999
1000+
Number of
Boilers
73
64
48
18
16
22
19
11
8
5
7
6
1
4
302
Fuel Consumed
1012 BTUs
41
50
50
15
13
18
43
25
9
12
15
25
4
14
334
% of Fuel
Consumed
12.2
15.1
15.1
4.4
3.8
5.5
12.8
7.4
2.8
3.6
4.4
7.3
1.3
4.3
100
SIMILAR DATA FOR SIC 332 (IRON AND STEEL FOUNDRIES)
Size Range
106 BTU/H
100-149
150-199
200-249
350-399
500-599
Number of
Boilers
4
2
1
1
I
9
Fuel Consumed
1012 BTUs
0.9
0.5
1.5
1.2
0.2
4.4
Source: FEA's MFBI Survey, Report No. 25
-------
A4 - 39
APPENDIX 4
TABLE 37
NUMBER OF LARGE INDUSTRIAL BOILERS BY SIZE RANGE AND 1974 FUEL
CONSUMPTION FOR SIC 333/5 (PRIMARY NON-FERROUS METALS)
Size Range
106 BTU/H
100-149
150-199
200-249
250-299
300-349
400-449
450-499
700-799
Number of
Boilers
16
5
5
3
15
1
3
_1
49
Fuel Consumed
1012 BTUs
5.6
1.8
2.4
2.9
42.8
1.2
9.0
6.4
72.0
% of Fuel
Consumed
7.7
2.6
3.3
4.0
59.4
1.7
12.4
8.9
100
SIMILAR DATA FOR SIC 339 (MISCELLANEOUS PRIMARY METALS PRODUCTS)
Size Range
1Q6 BTU/H
100-149
200-249
300-349
Number of
Boilers
1
2
_2
11
Fuel Consumed
_ 1012 BTUs
2.7
5.5
5.5
13.7
Source: FEA's MFBI Survey, Report No.
25
-------
A4 - 40
APPENDIX 4
TABLE 38
FUEL CONSUMPTION OF PULP, PAPER AND PAPERBOAKD INDUSTRY
7o of Total Fuel
Fuel Consumption in 1975
Purchased Fuels
Electricity
Steam
Residual fuel
Distillate fuel
LPG
Natural Gas
Coal
1972
3.5
0.8
22.4
1.2
0.1
19.3
10.9
58.2
1975
4.6
0.8
23.8
0.8
0.1
18.3
9.1
57.5
10 12 BTU*
86.1
14.2
463.0
14.9
1.2
340.0
169.6
1068.9
By-Product/Captive Fuels
Hogged fuel (507o moisture)
Bark (50% moisture)
Spent liquor
Self-generated hydro.
Other
TOTAL
1.7
4.9
34.6
0.4
0.2
41.8
100
2.6
4.2
34.8
0.5
0.4
42.5
100
48.0
79.2
646.6
9.2
7.6
790.6
1859.5**
or
1.86 quads
* based on data for first six months, annualized
-* in addition to the above consumption, the industry sold 16 x 10 BTUs
(0.97o of total)
Source: American Paper Institute, based on 787o coverage of industry
-------
APPENDIX 4
TABLE 39
FUEL CONSUMPTION OF LARGE INDUSTRIAL BOILERS BY FUEL TYPE AND BY SIC CODE IN 1974
SIC 20 Food and Kindred Products
SIC 29 Petroleum Refining
Coal
Resid.
Dist.
Nat . Gas
Other
Total
SIC 26 Paper
Coal
Resid.
Dist.
Nat. Gas
Other
Total
1012 BTU
42.4
24.4
3.4
97.6
1.0
168.8
%
25.1
14.5
2.0
57.8
0.6
100
and Allied Products
12
10 BTU
125.0
201.0
2.3
190.0
83.1
601.4
SIC 28 Chemicals and Allied
Coal
Resid.
Dist.
Nat. Gas
Other
Total
12
10 BTU
215.0
101.0
4.8
550.6
25.3
896.7
7o
20.8
33.4
0.4
31.6
13.8
100
Products
%
24.0
11.3
0.5
61.4
2.8
100
Coal
Resid.
Dist.
Nat. Gas
Other
Total
12
10 BTU
12.4
67.8
nil
456.2
18.2
554.6
SIC 32 Stone, Clay, Glass,
Coal
Resid.
Dist.
Nat. Gas
Other
Total
SIC 331/2
Coal
Resid.
Dist.
Nat. Gas
Other
Total
12
10 BTU
1.3
10.1
negl.
6.2
1.3
19.0
Primary Ferrous
12
10 BTU
217.0
7.2
0.8
46.2
93.2
364.6
7,
2.2
12.2
nil
82.3
3.3
100
Concrete
7,
7.0
53.2
0.1
32.7
7.0
100
Metals
%
59.5
2.0
0.2
12.7
25.6
100
SIC 333/9 Non-Ferrous Metals/Misc^
Coal
Resid.
Dist.
Nat. Gas
Other
Total
Coal
Resid.
Dist.
Nat. Gas
Other
Total
All
Coal
Resid.
Dist.
Nat. Gas
Other
Total
12
10 BTU
0.9
8.1
nil
68.1
13.4
90.5
Other SIC Codes
12
10 BTU
274.0
261.0
16.1
264.5
32.9
848.5
Manufacturing SIC
12
10 BTU
96.7
749
67
1822
288
3893
7<.
1.0
9.0
nil
75.2
14.8
100
7.
32.3
30.7
1.9
31.2
3.9
100
Codes
7,
24.8
19.3
1.7
46.8
7.4
100
Source: based on data reported by Natural Gas Task Force Survey
-------
A4 - 42
New England
Maine
Massachusetts
Connecticut
New Hampshire
Rhode Island
Vermont
Appalachian
Pennsylvania
Ohio
New York
Maryland
New Jersey
West Virginia
Virginia
Kentucky
Delaware
D. C.
Southeast
Alabama
Tennessee
S. Carolina
N. Carolina
Florida
Georgia
Great Lakes
Indiana
Michigan
Illinois
Wisconsin
APPENDIX 4
TABLE 40
REGIONAL FUEL
7o of
Region
48.5
21.5
19.9
8.2
1.6
0.3
100
28.2
28.1
8.8
8.7
7.6
7.0
6.9
2.1
1.0
0.7
100
25.8
19.8
13.8
13.7
13.7
13.2
100
36.5
29.5
27.4
6.6
100
CONSUMPTION
COMMERCIAL
- - 1 7
10" BTU
54.3
24.1
22.3
9.2
1.8
0.3
112.0
465.0
463.0
145.0
143.0
125.0
116.0
114.0
34.9
31.6
10.9
1648.4
180.0
138.0
96.2
95.7
95.7
92.4
698.0
372.0
301.0
279.0
66.8
1018.8
OF LARGE INDUSTRIAL
FUEL TYPE IN 1974
1974 Fuel
10 T Coal
0.028
0.008
0.002
nil
nil
nil
0.038
9.998
9.022
1.895
3.340
0.004
3.602
2.018
0.957
nil
0.294
31.030
2.627
3.386
1.628
1.074
nil
0.456
9.171
9.728
4.215
2.792
1.097
17.832
COMBUSTORS* BY
Consumption
10 Bbl Oil
8.5
3.1
3.2
1.3
0.3
negl.
16.4
16.1
9.8
14.8
5.4
14.8
2.0
9.1
0.3
2.8
0.7
75.8
7.2
1.7
5.1
9.4
10.8
7.5
41.7
8.8
9.6
10.1
1.7
30.2
Q
10 " CF Gas
nil
3.8
2.1
0.7
nil
<0.1
6.7
125.4
180.4
9.0
32.6
29.8
20.3
10.8
12.5
13.1
nil
433.9
68.6
47.4
25.1
11.6
25.6
32.2
210.5
88.5
135.6
138.8
28.6
391.5
* boilers and other combustors, such as process furnaces, with a rated heat input of
100 M BTU/H or more
-------
A4 - 43
APPENDIX 4
TABLE 40 (con't.)
Midcontinent
Oklahoma
Missouri
Kansas
Gulf Coast
Rocky Mountain
Colorado
Utah
Wyoming
Montana
Pacific
California
Arizona
New Mexico
Nevada
Texas
Louisiana
Mississippi
Arkansas
63.7
27.6
5.7
3.0
100
1270.0
551.0
114.0
59.3
1994.3
10 ll- BTU
58.5
46.3
16.3
7.2
5.5
131.8
72.5
57.3
46.5
176.3
1270.0
551.0
114.0
59.3
1994 3
80.2
64.6
60.7
18.8
224.3
295.0
37.4
10.7
_5.4
•w. o cf
10° T Coal
0.955
0.337
0.152
0.281
0.108
1.833
nil
1.399
0.071
1.470
2.320
0.010
0.107
nil
2.437
1.216
1.191
0.624
nil
3.031
0.110
0.021
nil
0.081
0.212
10 Bbl Oil
0.6
0.8
0.1
negl.
0.3
1.8
3.3
0.7
0.6
4.6
6.0
3.7
5.2
2.6
17.5
2.5
0.9
2.5
0.4
6.3
5.6
1.3
0.3
0.2
7.4
10y CF Gas
30.2
28.9
11.1
0.6
0.9
71.7
46.8
19.5
37.3
103.6
1078.8
478.6
72.0
39.2
1668.6
33.8
29.0
28.3
15.0
106.1
234.6
26.3
7.8
2.1
270.8
-------
A4 - 44
APPENDIX 4
TABLE 40 (con't.)
Pacific
Northwest
Washington
Oregon
Idaho
70.5
18.5
11.-0
100
—12
10 BTU
105.0
27.5
16.4
148
1974 Fuel Consumption
10 T Coal
10 Bbl Oil
4.3
1.4
neg 1.
5.7
10 CF Gas
68.6
14.7
9.2
92.5
Lower 48
States
6512
67.6
207.6
3356
Alaska/
Hawaii/
P. R./ V. I.
* = entirely in Alaska
Notes
107.6
0.588*
9-1
(1)
(2)
34.7
(3)
By-product and "Other" fuels are excluded
FEA appears to have used a BTU conversion factor of 1100 BTU/CF for "Gas/1
possibly to take account of LPG etc. Thus, the following BTU balance applies
to the Lower 48 States total:
67.6 million tons of coal at 22.6 million BTU/ton = 1528 x
207.6 million barrels of oil at 6.22 million BTU/bbl
3356 billion CF of gas at 1100 BTU/CF
BTU
1291 x lo" BTU
3692 x 10 BTU
6511
The consumption of 67.6 million tons of coal, reported by FEA, by the large
industrial combustors appears high in relation to the total of 64.0 million
tons of coal consumption, for all general industrial uses, reported by the
Bureau of Mines. Furthermore, the average heat content of the industrial
coal assumed by FEA, appears low (22.6 x 10 BTU per ton) and to be more
applicable to electric utility coal then to industrial coal (excluding
metallurgical coal). While the basis on which the statistics were collected
may be slightly different, it is obvious that the coal consumption of the
large coal-fired combustors can not have exceeded the total consumption by all
sizes of coal-fired industrial combustors. It is believed that part of the
discrepancy is due to inclusion of the coal consumption (4.4 million tons) of
nine large coal-fired electric utility boilers in FEA's survey of industrial
MFBI boilers. Making this correction would reduce the above figure of 67.6
million tons to 63.2 million tons. If the heat content of this coal were to
have averaged 24 x 106 BTU per ton, instead of the 22.6 x 10^ BTU per ton
assumed by FEA, the corrected total tonnage would be about 59.4 million tons
(including 40.2 million for large industrial boilers and 19.2 million for other
large industrial combustors). Thus, the implied coal consumption of the
smaller industrial combustors (less than 100 million BTU/H) would be 64.0 - 59.4
4.6 million tons, of which about 3.1 million tons may have been used by the
smaller boilers. This rationalization of the reported coal consumption
statistics for 1974 suggests that coal use by industrial boilers approximated:
-------
A4 - 45
APPENDIX 4
TABLE 40 (con't.)
Notes (con't.)
Million Tons 7, of Total
100 million BTU/H or larger 40.2 93
Smaller than 100 million BTU/H 3.1 7
43.3 100
Although the estimate for the smaller coal-fired boilers is approximate, it is
the best available. It tends to confirm that the potential for coal-firing in
new industrial boilers is likely to be almost entirely in units with a
designed heat rate of 100 million BTU/H or more.
Source: based on pooling of statistics from FEA's Natural Gas Task Force and MFBI
surveys, with additional information from Bureau of Mines reports
-------
A4 - 46
APPENDIX 4
TABLE 41
COAL CONSUMPTION BY REGION OF ALL LARGE INDUSTRIAL
COMBUSTORS (INCLUDING BOILERS) IN 1974
New England
Maine
Massachusetts
Connecticut
New Hampshire
Rhode Island
Vermont
Appalachian
Pennsylvania
Ohio
West Virginia
Maryland
Virginia
New York
Kentucky
D. C.
New Jersey
Delaware
10 Tons
28
8
9998
9002
3602
3340
2018
1895
857
294
4
Northern
Plains
Iowa
Minnesota
South Dakota
Nebraska
North Dakota
Mideontinent
Missouri
Kansas
Oklahoma
Gulf Coast
Texas
Mississippi
Louisiana
Arkansas
10 Tons
955
337
281
152
108
1399
71
2320
107
10
Southeast
Tennessee 3386
Alabama 2627
S. Carolina 1628
N. Carolina 1074
Georgia 456
Florida
Great Lakes
Indiana 9728
Michigan 4215
Illinois 2792
Wisconsin 1097
Rocky Mountain
Colorado
Utah
Wyoming
Montana
Pacific
Southwest
California
Nevada
Arizona
New Mexico
1216
1191
624
110
81
21
Pacific
Northwest
Idaho
Washington
Oregon
271
145
115
Source: Natural Gas Task Force survey
-------
- 166 -
. REPORT NO.
EPA-600/7-77-011
DEPORT DATA ^^
3. RECIPIENT'S ACCESSION NO.
Application of Fluidized-Bed Technology to Industrial
Boilers
5. REPORT DATE
January 1977
6. PERFORMING ORGANIZATION CODE
. AUTHORIS) ~ —
M.H. Farmer, E.M. Magee, andF.M. Spooner
8. PERFORMING ORGANIZATION REPORT NO.
EXXON/GRU.1DJAR.77
'ERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P.O. Box 8
Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
EHB536
11. CONTRACT/GRANT NO.
EPA-IAG-D5-E767
12. SPONSORING AGENCY NAME AND ADDRESS * "
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final: 7/75-9/76
14. SPONSORING AGENCY CODE
EPA-ORD, ERDA, FEA
15. SUPPLEMENTARY NOTI
(*) This report was cosponsored by EPA, ERDA, and FEA. EPA
project officer is D. B. Henschel; ERDA, is W. Siskind; and FEA, is A. J. Hayes.
16. ABSTRACT The report gives results of a paper study of the application potential of coal-
fired fluidized-bed boilers (FBB's) in the industrial use sector. It considers: the
ability of coal-fired FBB's to meet the requirements of industrial users, including
cost, reliability, maintainability, design, and performance requirements; the maxi-
mum, minimum, and most likely demand for such boilers in the industrial sector;
the application effect of such boilers on the national fuel demand; the economic
impact of industrial application of such boilers; and the environmental aspects of
industrial FBB application. Study results suggest that industrial FBB's burning high-
sulfur coal offer a cost advantage over equivalent conventional coal-fired boilers with
flue gas desulfurization; with low-sulfur coals capable of meeting emission standards
without SO2 controls, the costs of FBB's and conventional boilers are comparable.
On this basis, the most likely projected degree of application of FBB's in the indus-
trial sector in the year 2000 is 2.97 x 10 to the 15th power Btu/year. SO2, NOx, and
particulate emissions from industrial coal-fired FBB's can be reduced to levels below
those specified in current Federal emission standards for large coal-fired boilers.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution Flue Gases
Fluidized Bed Processors
Combustion Industrial Processes
Boilers Cost Effectiveness
Coal Maintainability
Desulfurization
8. DISTRIBUTION STATEMENT
Unlimited
b.IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Fluidized-Bed Combus-
tion
Industrial Boilers
Environmental Impact
19. SECURITY CLASS (Tins Report)
Unclassified
20. SECURITY CLASS (This page/
Unclassified
Field/Group
13B
21B 13H
13A 14A
2ID 14A
07A,07D
21. NO. OF PAGES
22. PRICE
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