EPA-650/2-74-123
NOVEMBER 1974
Environmental Protection Technology Series
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EPA-650/2-74-123
BOILER MODIFICATION
COST SURVEY FOR SULFUR OXIDES
CONTROL BY FUEL SUBSTITUTION
by
R. Schreiber, A. Davis,
J. Delacy, Y. Chang, and H. Lockwood
Aerotherm/Acurex Corporation
485 Clyde Avenue
Mountain View , California 94042
Contract No. 68-02-1318, Task 9
ROAP No. 21ADE-010
Program Element No. 1AB013
EPA Project Officer: C. J . Chatlynne
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
. November 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
11
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FOREWORD
This document presents the results of a survey of the costs of con-
verting conventional, fossil fueled, stationary combustion equipment to the
use of selected coal-derived fuels. The report provides updated information
on present-day fuel switching activity, continues with the presentation of
equipment conversion costs, and concludes with the formulation of cost models
derived from the previously collected data.
The latter four authors of this report, personnel of The Coen Co. in
Burlingame, California, performed the boiler modification cost assessments.
Aerotherm extends its appreciation for the valuable assistance pro-
vided by Mr. R. C. Carr of the Electric Power Research Institute, Palo Alto,
California, and Dr. R. M. Jimeson of the Federal Power Commission, Washington,
D.C. Special thanks is given to the diligent members of the Aerotherm Tech-
nical Publications Department.
This survey was performed for the Engineering Analysis Branch of the
Control Systems Laboratory, U.S. Environmental Protection Agency. Dr. Gary
J. Foley was the task officer until July 26, 1974. Dr. Charles Chatlynne
was the task officer for the remainder of project's duration. The Aerotherm
Project Manager was Dr. Larry W. Anderson. Dr. C. B. Moyer and Dr. H. B.
Mason acted as advisors for all phases of the study. The study was under-
taken during the months of June to September, 1974.
111
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TABLE OF CONTENTS
Section
1 INTRODUCTION 1-1
2 CURRENT FUEL SUBSTITUTION ACTIVITY: CONVENTIONAL
TO COAL-DERIVED FUELS 2-1
2.1 Introduction 2-1
2.2 Current Activities 2-2
2.3 Summary and Conclusions 2-5
3 CHARACTERIZATION OF COMBUSTION EQUIPMENT 3-1
3.1 Introduction 3-1
3.2 Industrial Boiler Types 3-2
3.2.1 Firetube Boilers 3-2
3.2.2 Watertube Boilers 3-3
3.2.3 Stoker-Fired Boilers 3-4
3.3 Utility Boilers 3-4
3.3.1 Wall-Fired Boilers 3-5
3.3.2 Tangentially- and Turbo-Fired Boilers 3-5
3.3.3 Cyclone-Fired Boilers 3-6
4 CHARACTERIZATION OF SUBSTITUTE FUELS 4-1
4.1 Introduction 4-1
4.2 Low- and Medium-Btu Gas 4-2
4.3 Solvent Refined Coal 4-4
4.4 Summary and Conclusions 4-9
5 SELECTION OF FUEL SUBSTITUTION OPTIONS 5-1
6 DOCUMENTED BOILER CONVERSION COST DATA 6-1
6.1 Introduction 6-1
6.2 Boiler Modification Considerations 6-1
6.2.1 General Equipment Modification Considerations
Applicable to All Boiler Types 6-1
6.2.2 Special Equipment Modification Considerations
for Unique Boiler Types 6-2
6.2.3 Fuel Handling Systems 6-6
6.2.4 Firing Equipment for Gases and Liquid SRC 6-8
6.3 Boiler Conversion Cost Data and Evaluation 6-12
6.3.1 Introduction 6-12
6.3.2 Boiler Conversion Cost Data 6-12
6.3.3 Cost Data Evaluation 6-13
6.3.4 Use of Cost Data for Other Locations 6-34
6.3.5 Proposed Cost Models 6-36
7 CONCLUSIONS AND RECOMMENDATIONS 7-1
REFERENCES R-l
ADDITIONAL BIBLIOGRAPHY R-5
APPENDIX A - PROCESS FOR LOW- AND INTERMEDIATE-BTU
FUEL GAS A-l
APPENDIX B - PROCESSES FOR HIGH-BTU PIPELINE GAS (SNG) B-l
APPENDIX C - BULK CONVERSION COST DATA C-l
v
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TABLE OF CONTENTS (concluded)
Section
APPENDIX D - METRIC SYSTEM CONVERSION FACTORS D-l
TECHNICAL REPORT DATA T~l
VI
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LIST OF FIGURES
Figure page
3-1 Vertical Wall-Fired Utility Boiler Shapes and
Burner Configuration 3-6
3-2 Tangentially-Fired Utility Boiler Shape and Firing
Pattern 3-7
3-3 Riley Turbo® Furnace Shape and Burner Configuration
3-4 Cyclone Furnace Firing Arrangements 3-10
4-1 Solvent Refined Coal Process 4-7
5-1 Conversion Cost Data Sheet for Coal-Fired Boilers 5-5
5-2 Conversion Cost Data Sheet for Oil-Fired Boilers 5-6
6-1 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Coal to Low-Btu Gas 6-15
6-2 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Coal to Medium-Btu Gas 6-17
6-3 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Coal to Natural Gas 6-19
6-4 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Coal to Liquid SRC 6-21
6-5 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Coal to Solid SRC 6-23
6-6 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Oil to Low-Btu Gas 6-25
6-7 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Oil to Medium-Btu Gas 6-27
6-8 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Oil to Natural Gas 6-29
6-9 Combustion Equipment Conversion Capital Costs ($)
vs. Boiler Capacity: Oil to Liquid SRC 6-31
6-10 Composite of All Conversion Cost Data vs. Capacity 6-33
VI1
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LIST OF TABLES
Table
4-1 Compositions of Selected Low- and Medium-Btu
Gasified Coal Fuels 4-5
4-2 Analysis of Kentucky No. 11 Coal, As Received 4-8
4-3 Analysis of Solvent Refined Coal 4-8
5-1 Fuel Substitution Options 5-2
6-1 Boiler Types, Capacities, and Associated Burner Quan-
tities for Gas- and Liquid SRC-Firing 6-3
6-2 Burner Supply Pressures for Gaseous and Liquid Substitute
Fuels 6-4
6-3 Gaseous Fuel Handling System Piping Lengths and Supply
Pressures 6-7
6-4 Gun Sizes for Gaseous Substitute Fuel Firing 6-10
6-5 Typical Multiple Venturi Burner Types for Liquid SRC
Firing 6-11
6-6 Equipment Conversion Capital Costs: Coal to Low-Btu Gas 6-14
6-7 Equipment Conversion Capital Costs: Coal to Medium-Btu
Gas 6-16
6-8 Equipment Conversion Capital Costs: Coal to Natural Gas 6-18
6-9 Equipment Conversion Capital Costs: Coal to Liquid SRC 6-20
6-10 Equipment Conversion Capital Costs: Coal to Solid SRC 6-22
6-11 Equipment Conversion Capital Costs: Oil to Low-Btu Gas 6-24
6-12 Equipment Conversion Capital Costs: Oil to Medium-Btu Gas 6-26
6-13 Equipment Conversion Capital Costs: Oil to Natural Gas 6-28
6-14 Equipment Conversion Capital Costs: Oil to Liquid SRC 6-30
6-15 Conversion Cost Uncertainty Factors 6-32
6-16 Location Factors for Major U.S. Cities 6-35
Vlll
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SECTION 1
INTRODUCTION
The creation of the various combustion-generated chemical species gen-
erally regarded as air pollutants can be reduced by a variety of means. Some
pollutants, such as "thermal" nitric oxide, lend themselves to reduction by
modification of the combustion process. Others, notably the oxides of sulfur,
are released in quantities directly proportional to the amount of some conta-
minant contained in the fuel. Pre- or post-combustion controls are the only
feasible means of eliminating combustion systems as sources of SO . Therefore,
the two leading strategies for controlling SO emissions from combustion equip-
A
ment firing sulfur-containing fuels are: (1) burning desulfurized fuel, or
(2) removing the SOV from the flue gas (Reference 1-1).
A
For high-sulfur coal, the former method can be effected by burning the
products from various gasification and liquefaction processes, while several
popular scrubbing techniques exist for stack gas SO removal. The choice of the
A
most viable control strategy will be based on cost, among other factors. Such
monetary considerations are to be analyzed using detailed, consistent cost
models developed by the EPA.
EPA has funded research into several stack gas scrubbing techniques,
and has detailed information on the costs of such operations for a given size
of installation. The costs associated with typical coal gasification and
liquefaction processes are also reasonably well in hand (Reference 1-2).
There is not, however, a good source of information on the costs associated
with converting oil- and coal-fired equipment to use these "synthetic" gases
and liquids as fuels. The purpose of this task order is to provide cost in-
formation on the conversion from conventional fossil fuels to selected coal-
derived gaseous and liquid fuels as a function of equipment type and firing
capacity. This study focuses on conventional stationary combustion systems,
such as industrial furnaces and utility boilers. The cost figures collected
during this study lead to the formulation of generalized equipment conversion
cost models, compatible with existing models involving production and trans-
portation of these coal-derived fuels. The results of this task will con-
tribute to EPA's on-going SOV Control Strategy Analysis.
1-1
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Specifically, the coal-derived fuels of concern in the context of the
present study include Solvent Refined Coal (SRC) and the range of low-Btu
(150 Btu/scf) to high-Btu (1000 Btu/scf) content gases. For the gaseous
fuels, an attempt is made to treat the range of gases as a continuum, and to
incorporate a heating value term in the cost models for gas. Large-scale
research and development programs aimed at determining the feasibility of usii
these materials as fuels have only recently been initiated. As a result,
very little is known about their combustion and handling properties, and cer-
tain assumptions were made in this regard in order to make the required equip-
ment modification cost estimates. It will be possible to evaluate these
assumptions as more information on these fuels' physical properties becomes
available.
The combustion systems of concern include steam-raising boilers in the
7 7
10 to 1000 x 10 Btu/hr range, encompassing all industrial and utility size
equipment. This assures inclusion of the smaller SO sources, which tend to
X
lack even intermittent controls (i.e., tall stacks) and which may have a sig-
nificant impact on local air quality.
A future use for these coal-derived fuels for electric power produc-
tion will be to fire them in combined-cycle plants, rather than solely in
converted equipment of conventional designs. Indeed, the ultimate goal of
most present-day coal-conversion power system projects is the demonstration
on a commercial scale of an economically and environmentally acceptable elec-
tric gene'rating plant that links a coal-conversion system with a combined-eyeli
plant adapted for using these exotic fuels (see References 1-3, 1-4, 1-5).
Combined-cycle power plants are not, however, treated in the present study,
but it is felt that determining the costs of converting conventional combus-
tion equipment to the use of these fuels will provide support for future
system trade-off and cost-effectiveness assessments.
The remainder of the present study is organized in the following
manner:
Section 2; Current Fuel Substitution Activity - Conventional to Coal-Derived
Fuels
This section attempts to draw together ongoing, practical experiences
and state-of-the-art knowledge on the subject of converting the combustion
equipment of concern to the use of exotic, coal-derived fuels from more con-
ventional fossil fuels. This investigation was performed in the hope of sup-
plementing the estimates of equipment conversion costs presented later in the
study.
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Section 3; Characterization of Combustion Equipment
This section presents the justification of the choice of combustion
equipment types scrutinized in the study. Brief qualitative descriptions
of the equipment are included.
Section 4; Characterization of Substitute Fuels
The study continues with brief discussions of the Solvent Refined
Coal process, the notable coal gasification schemes, and their probable im-
portance as fuels of the future. Typical chemical compositions of these
fuels are given as well.
Section 5; Selection of Fuel Substitution Options
The manner in which the conversion cost data will be collected is in-
troduced. This consists of a matrix of boiler type versus boiler capacity
for a given type of conversion. The cost estimation method involves applying
a set of cost data obtained from a similar conversion (i.e., to a lighter
fuel oil) to a postulated coal-derived fuel conversion.
Section 6; Documented Boiler Conversion Cost Data
This section contains the estimated equipment conversion cost data for
a given boiler type, original fuel and substitute fuel as set forth in the
"Equipment Conversion Cost" data sheets. Included also are plots of the
cost versus capacity data. Qualitative descriptions of the methodology of
each conversion are provided. A discussion of the possible cost models that
may be derived from these data is included as well.
Section 7; Conclusions and Recommendations
The significance of the results of the study are summed up, and recom-
mendations for their future application are provided.
The report concludes with the References and the Appendix. The latter
section contains the bulk cost data from which the final equipment conversion
cost figures were derived. Included also is a tabulation of popular coal gasi-
fication processes. The appendix concludes with a table of British to metric
conversion factors.
1-3
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SECTION 2
CURRENT FUEL SUBSTITUTION ACTIVITY:
CONVENTIONAL TO COAL-DERIVED FUELS
2.1 INTRODUCTION
Two energy source substitution strategies exist for reducing sulfur
oxide emissions from fossil-fueled steam-generation equipment. First, the
generating source itself may be replaced, such as switching from a fossil-
fueled to hydropower plant. The second option, and by far the more expedient,
is substitution of a cleaner fuel. The present study is concerned with a
specialized case of the latter method.
Fuel substitution is a common practice in the operation of most large
steam raising plants, although its motivation is most often based on fuel avail-
ability rather than on air pollution control. Most of these plants were
originally designed for dual fuels, and the actual in-plant fuel switching pro-
cess is usually quite straightforward. As a general rule, however, difficulty
in doing so increases when progressing from gaseous or liquid to solid fuels.
The material handling problems are worsened, and the possibility of additional
combustion erratics arise with reduced fuel heating value.
Among the more promising low-sulfur fossil fuels are the products from
coal conversion processes. The current clean fuel shortage has sparked wide-
spread interest in the energy generation potential of these future fuels. At
the present time, however, no existing industrial or utility boiler is firing
these fuels, due mainly to a general lack of sufficient quantities. In addi-
tion, the combustion and handling properties of these fuels are generally un-
known. The probability is high, however, that some degree of equipment modi-
fication will be necessary before these fuels can be utilized in existing
equipment. The purpose of this study is to assess the capital costs of con-
verting a variety of boiler designs and capacities to two types of coal-derived
fuels; namely, lower-BTU gas (HHV = 150-700 Btu/scf) and solvent refined coal
(SRC). Current activities in this area are reviewed in the following sub-
sections. Although for many years it has been the practice of the industrial
boiler sector to use waste gases (i.e., coke oven gas) of low heating values
as fuels, such occurrences are too varied to be included in this discussion.
The principles involved in using such fuels are, however, an integral part of
the cost estimation methodology performing during this study.
2-1
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2.2 CURRENT ACTIVITIES
For the most part, actions in the area of converting boilers to coal-
derived fuels have been limited to studies, models, and position papers by the
utility industry. This lack of actual conversion experience stems, for the
most part, from a combination of the following three factors:
• Quantities of these exotic fuels are insufficient even for
subscale test purposes, much less for full-scale steam
generation.
• Pressure to begin such programs was absent until the energy
shortage reached a severe level several years ago. This,
naturally, retarded the development of the required new
technology.
• The lead time required by the utility industry to implement
alterations in electrical generation mode is traditionally
long.
However, a discussion of germane literature as well as the current posturing
by the utility industry is of interest in the context of this study.
Conversions to Lower-BTU Gas
A recent article by Henry and Burbach of Combustion Engineering, Inc.,
(Reference 2-1) considered the factors involved when attempting to apply low-
Btu gas (130 Btu/scf) to an existing tangentially-fired boiler. The authors'
major conclusions were:
• The lower heating value of the gas requires that, compared with
natural gas, as much as 12 times the amount of fuel gas (by weight)
be handled
• This factor may require a larger combustion volume, and either
larger fuel piping or higher supply pressures.
• Operation of the on-site low-Btu gas plant may require that the
steam generator be brought on line on its backup fuel (i.e., low
sulfur oil) and then transferred to the low-Btu gas. This refers
to the "dynamic coupling" difficulties that will be discussed
later in this section.
No information on the costs associated with the required modifications were
included in the paper. The article also related that Combustion Engineering
currently has a four-phase contract with the Office of Coal Research to design
a 200 MW pilot plant in combination with 5 ton/hr low-BTU gasification plant.
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A recent paper by Frendburg (Reference 2-2) verifies much of the
information in the paper by Henry and Burbach, and contains some additional
elaborations:
• As the heating value of the fuel gas falls below 300 Btu/scf,
the fuel pipes or ducts increase in size making it more
difficult to route these pipes or ducts.
• The furnace volume of coal-fired utility boilers are inher-
ently larger than those for either oil or gas, and will, therefore,
more readily accommodate lower-Btu gas.
• Unit efficiency may decrease when firing lower-Btu gas, due to
increasing heat loss to the stack.
Actual application of lower-Btu gas in power plants is seemingly limited
at the present time to some program planning on the part of an electrical
utility company in Illinois (References 2-3 and 2-4). Through contributions
to the Electric Power Research Institute, the electric utility industry is
supporting this development project, which is sponsored by Commonwealth Edison
Company. The project's strategy will be to use a Lurgi gasifier to equip the
120 MW Powerton Station. It was determined that using low-BTU gas as a fuel
supply possessed two major advantages over stack gas scrubbing:
• The low-Btu gas supply can generate a net excess of electric power
by passing the product stream through an unfired expander turbine;
this contrasts with the scrubber which uses from 5 to 10 percent of
the generated power (Author's comment: it should be noted, however,
that generation of low-Btu gas entails the loss of approximately
40 percent of the heating value of the feedstock coal. An overall
power generation system energy balance will favor the use of raw
coal).
• The associated gas purification process of the gasification system
effects cleanup by removing hydrogen sulfide (for which technology
exists) , and treats less than 5 percent of the volume of gas that
would be processed in a scrubbing system.
Detailed information on the present status of this project was not
available.
Conversions to Solvent Refined Coal
The practical and economical feasibilities of utilizing solvent refined
coal in existing fossil-fueled utility boilers have been analyzed in some
depth (References 2-5, 2-6, and 2-7). SRC is a relatively clean fuel, being
low in moisture, ash, and sulfur, and its heating value is fairly uniform
regardless of the feedstock coal (about 16,000 Btu/lb). On the face of it,
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this means that the refined product can be shipped on a Btu basis for propor-
tionately less than raw coal. This factor suggests the location of refining
plants near cheap sources of coal. In addition, the paper studies show signif-
icant pollution control cost savings through the use of SRC. However, the as-
sumption is made that it can be substituted for either oil or coal without dif-
ficulty. As it is the purpose of the present study to evaluate such conversion
costs, the validity of this assumption will be tested. Also, the cost of pro-
ducing SRC must be factored in when comparing costs with stack gas scrubbing.
As is described in detail in Section 4 of this report, the physical
properties of SRC are such that some controvery currently exists as to whether
it is more advantageous to burn it as a liquid or solid. The original fuel
may become a deciding factor.
There are currently two schools of thought on the subject of the applic-
ability of solid SRC to coal-fired plants. One contends that the material is
sufficiently similar to coal that existing storage facilities, pulverizers,
and fuel handling and combustion equipment can all be used, with no modifica-
tions necessary. The opposing theory states the opposite: that solid SRC will
melt unless preheat operation is discontinued and appropriate portions of the
fuel preparation and handling equipment are externally cooled (References 2-8 and
2-4). As so little is known about the actual handling and .combustion properties
of this material, considerations from both cases have to be treated. The first
would require essentially no cost, while some finite cost will be associated
with the second.
It is generally agreed that firing liquid SRC in either oil- or coal-
fired plants will require some degree of adaptation. SRC's viscosity increases
dramatically below about 500F, which will necessitate, among other factors,
external pipe- and vessel-heating apparatus. The extent and cost of the liquid
SRC handling system will depend to some degree on the location of the SRC
plant with respect to the steam generator. If the plant is located inconve-
niently far from the site of use, the SRC can be transported as a solid (molded
pellets) to the boiler and subsequently melted. If the SRC plant is adjacent
to the boiler, cooling the material to solid form will not be necessary before
combustion. In either case, the usual liquid fuel handling equipment (piping,
valves, pumps, storage tanks, etc.) will be required in addition to the special
fuel warming equipment. Such considerations will be treated at greater length
in Section 6 of this report.
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Actual experience in converting steam raising boilers to the use of
SRC has been, at present, restricted to preliminary program planning by some
electric utility/oil company consortia in the Midwest and Southeast. In Ohio,
the team of Old Ben Coal Company, Standard Oil of Ohio, and Toledo Edison are
gearing up for a pilot program in which SOHIO will supply SRC, made from coal
supplied by Old Ben, to an Edison generating station. Conversations with the
principals involved netted the following (References 2-9, 2-10, and 2-11):
• SRC will be transported like coal in existing hopper cars.
• Heated pulverizers cannot be used; Toledo Edison's operates
at about 13OF.
• What effect SRC's lower ash content will have on the plant's
existing ash collection method is unknown.
• Amount of possible boiler derating is unknown.
• SRC may not be able to be heated to a liquid state and stored
for long periods of time; in any case, the heating must be
done under pressure and an inert atmosphere, to avoid repolymeriza-
tion.
• The major advantage of SRC as a substitute fuel over lower-Btu gas
is the lessening of "dynamic-coupling" difficulties; i.e., a utility
plant's output can vary by as much as - 5 percent per "minute, while
a gasification plant's rapid turndown capabilities are far less.
SRC can be stored easily and its input rate can be modulated readily.
A detailed description of the SOHIO/Toledo Edison/Old Ben enterprise has not
yet been published or otherwise made available to the general public.
Additional activity in the area of SRC utilization in power plants is
currently taking place at Wilsonville, Alabama. A 6 ton/day SRC pilot plant,
sponsored jointly by The Southern Company system and the Electric Power
Research Institute, was completed at this location in August, 1973. Pre-
liminary plans are being made for applying the SRC obtained from this pilot
plant to a Southern Services generating plant (Reference 2-12) .
2.3 SUMMARY AND CONCLUSIONS
The motivation for fuel substitution in steam-raising boilers is based
on fuel availability and/or pollution control. The continuing shortage of
clean substitute fuels will cause reliance on alternate fossil fuels. With
the advent of coal-derived fuels, most of which require special handling and
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combustion procedures, some effort will have to be expended to convert con-
ventional combustion systems to their use. Of the various coal conversion
processes, the products from two of them are considsred in this study: solvent
refined coal and synthesis gas.
Thus far, activities aimed at converting full-scale utility boilers
to the use of either of these types of fuels has been limited to studies,
position papers, and preliminary program planning by a few electric utility/
oil company consortia in the Southeast and Midwest. For the gaseous coal-
derived fuels, a Lurgi coal gasifier will be used to supply a 120 MW gen-
erating station. Details on the present status of this project were not
available.
In another program, solid SRC will be utilized in a coal-fired power
plant. It is anticipated by the participants that little or no equipment
conversion will be necessary. An additional SRC-related project is underway
in the Southeast, where SRC from a 6 tons of coal/day pilot plant will be
supplied to an existing generating unit.
A major advantage of solid SRC over lower-Btu gas as a boiler fuel is
that, in contrast to the product from an in situ gasifier, SRC can be stored
when not in demand by the power plant, thus removing the "dynamic coupling"
difficulties prevalent in the gasifier/steam plant strategy.
There is as yet no widespread move to employ either gasified coal or
SRC in the industrial boiler sector.
The absence of cost data based on actual experiences in converting
to these exotic fuels necessitates that such costs be estimated for this study.
The estimation procedure, performed by personnel of The Coen Co., was based on
a knowledge of the fuel's physical properties as well as an extensive background
of boiler conversions to similar fuels. Section 6 of this report discusses the
estimation methods and assumptions used in deriving the cost figures.
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SECTION 3
CHARACTERIZATION OF COMBUSTION EQUIPMENT
3.1 INTRODUCTION
The previous section of this report reviewed current activities
involving the substitution of various coal-derived fuels for conventional
fossil fuels in stationary combustion equipment. The majority of such activ-
ity currently centers around full-size utility boilers, with less apparent ef-
fort being expended in the industrial boiler sector. Both sectors are, how-
ever, obvious candidates for the application of fuel switching as a SO abate-
X
ment strategy.
The choice of the combustion equipment types and their capacities ul-
timately considered in this study was based on two factors:
• Determination of the most prolific stationary SOX sources. Accor-
ding to the 1970 nationwide emission estimates given in Reference
3-1, fuel combustion in stationary sources accounts for 79 percent
of the total controllable S0x emissions. Of that amount, 73 per-
cent is contributed by steam-electric, 18 percent by industrial, 3
percent by commercial and institutional, and 5 percent by residen-
tial sources. It appeared that the greatest benefit would be de-
rived from considering only the first two source categories.
• Possible impact on the ambient air quality in the immediate vicin-
ity of the source. This consideration demanded the inclusion of
the smaller SO sources.
These criteria acted to establish the framework for the determination
of the types and capacities of combustion equipment to be considered in this
report; namely, steam-raising boilers in the 107 to 1000 x 107 Btu/hr (1-1000
MW) capacity range, which encompasses all industrial and utility size equip-
ment. Including a wide variety of boilers and capacity ranges increases the
probability of arriving at a global relationship between equipment conversion
capital cost and capacity.
3-1
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Boilers used for industrial purposes in the capacity range of interest
include the following general types:
• Firetube (packaged)
• Watertube (packaged or field-erected)
• Stoker (field-erected)
Utility boiler types, all of which are field-erected, are categorized mainly
by fuel firing mode. These include:
• Face-fired
• Tangentially-fired
• Turbo-fired
• Cyclone-fired
The remainder of this section is devoted to brief descriptions of these
types of industrial and utility boilers. Throughout the discussion, it should
be noted that the term "packaged" refers to a shop-fabricated boiler which is
shipped as a complete unit to the point of use. This fact naturally places an
upper limit on physical size; the largest packaged boilers can be transported
by barge, and most are sized for railroad flat cars. The opposite fabrication
method is described by the term "field erected," meaning the boiler is assem-
bled from its component parts at the site of eventual operation.
Additional, more detailed specifications on the design, construction,
and operation of these boilers can be obtained from the references cited.
3.2 INDUSTRIAL BOILER TYPES
3.2.1 Firetube Boilers
Firetube boilers (all of which are packaged) are used where steam
demands are relatively small, usually for heating systems, industrial process
steam, or as portable boilers. In this design, the hot combustion gases are
passed through tubes submerged in a water-containing vessel. The principal
types of firetube boilers include Horizontal Return Tubular (HRT), Scotch
Marine, and "Short Firebox," the capacities of which fall in the 107 to 25 x
10s Btu/hr range.
These three types of boilers will be lumped together under the fire-
tube boiler category, mainly because of similarities in capacities and firing
equipment. HRT boilers are not commonly built for industry at present, being
more predominant 15 to 20 years ago. The same is true of the short firebox
boiler. The Scotch Marine boiler type refers to firetube boilers in general
3-2
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use today for low pressure (15 to 20 psig) saturated steam applications with
steam flow capacities in the 300 to 25,000 Ib/hr range. Firetube boilers are
fired solely on gaseous or liquid fossil fuels. Typical manufacturers are
Cleaver Brooks, Superior, and Bryant (References 3-2, 3-3) .
3.2.2 Watertube Boilers
This category includes both field-erected as well as packaged units.
Common sizes for the former type fall between 50 x 106 and 500 x 10s Btu/hr,
while 107 to 250 x 106 is the capacity range for the latter. Larger
packaged boilers, above 450 x 106 Btu/hr, are currently being designed and
supplied, but are not yet common.
As the name implies, watertube boilers are designed to flow water
through the heat transfer tubes, instead of combustion products as in the
firetube design. Because of the smaller diameter pressurized components and
the advantage using tubes gives in accommodating expansion, they are better
able to contain the pressure and afford an inherently safer design.
Field-erected boilers are usually balanced draft and therefore require
both forced draft and induced draft fans. Field-erected boilers are commonly
fired with coal, gas and/or oil. Many such boilers exist today but very few
new applications have capacities lower than 200 x 106 Btu/hr, except for
pulverized or stoker coal-fired units. This is because of the packaged
boiler's domination of the oil- and gas-fired boiler market, which is in turn
due to their low capital cost in the sizes between 12 x 106 and 200 x 106
Btu/hr.
Packaged watertube boilers are used for gas and oil firing applications.
They are not used for coal firing because they have much smaller furnace volume
than are permissible. They are designed to be rail-shipped as a complete,
single package with minimum fieldwork. The furnaces are also designed to
operate under positive pressure versus the balanced or slightly negative
pressure found in coal-fired boilers.
Both types of boilers use similar type firing equipment. The register-
type burner is generally used, with burner capacities being between 50 x 106
and 120 x 10s Btu/hr on a field-erected boiler, and up to 350 x 106 Btu/hr on
a packaged boiler. Packaged boilers generally have one burner although older
units were fitted with multiple burners - usually two. Popular types of in-
dustrial watertube boilers, both packaged and field-erected, are manufactured
by Combustion Engineering Company, Riley Stoker, and Erie City Company (Ref-
erences 3-2, 3-4, 3-5, 3-6).
3-3
-------
3.2.3 Stoker-Fired Boilers
The two major options available for the controlled combustion of coal
are suspended firing, in which the fuel is pulverized to a fine dust prior
to being combusted in a wall-mounted burner, and bed combustion, which
causes oxidation to take place in and above a layer of raw coal. An ex-
ample of the latter method is found in the traditional hand-fired coal furnace.
Mechanical stoker-fired boilers are an improvement over this design.
The general stoker-fired boiler category includes spreader, underfeed,
vibrating grate, chain grate, and traveling grate stokers. All terms refer
to the method of coal/air introduction and mixing, as well as char and ash
removal. Firing capacities generally range from 15 x 106 to 250 x 10s Btu/hr.
It is very unusual for a stoker to be designed with less than 20 x 106Btu/hr
capacity. Units above 200 x 106 Btu/hr are also rare.
Stokers are often preferred over pulverized-fired units because of their
ability to burn a wide variety of coals and other solid fuels, greater opera-
ting range, and lower power requirements.
A major impact on the cost of converting mechanical stoker-fired boilers
to a substitute, cleaner fuel will be the required modification of the equip-
ment inside the furnace volume. Pulverized coal-fired units of the same capa-
city incur no such costs. This effect will be noted in Section 6, later in this
report.
3.3 UTILITY BOILERS
Most of the nation's combustion-derived electricity is generated in
large fossil-fueled central stations, which consist of watertube boilers op-
erating in the supercritical pressure region serving turbine-generators in
the million kilowatt range. Firing capacities of individual burners in util-
ity boilers commonly range up to as high as 125 x 106 Btu/hr. One-thousand
MW wall-fired units may require as many as sixty separate burners.
Although there are some differences among utility boiler designs in
such factors as furnace volume, operating pressure, and configuration of inter-
nal heat transfer surface, the principle distinction is firing mode. This
includes the type of firing equipment, the fuel handling system, and the
placement of the burners on the furnace walls. The major firing modes, of
which equipment conversion costs are a function, are briefly described below.
3-4
-------
3.3.1 Wall-Fired Boilers
The multiple burners in wall-fired utility boilers are usually mounted
in geometrical patterns on the vertical furnace wall, although some designs
employ roof-mounted burners. Depending on the manufacturer and firing capa-
city, the burners in vertical wall-fired boilers may be mounted either on a
single wall or on opposite walls. Figure 3-1 shows cross-sections of these twi
types of boilers. Vertical-wall burners are usually of the register type, whi:
"intertube" burners are normally used in roof-mounted applications. In any ca:
the burners are fired in a fixed direction normal to the wall. This is in con-
trast with the tangential firing method which allows some degree of burner "ti]
Individual burner firing rates lie in the 75 x 106 to 125 x 106 Btu/hr
range; the total heat release rate of wall-fired boilers normally falls be-
tween 500 x 106 and 10,000 x 106 Btu/hr, which corresponds to a generating
capacity range of 50 to 1000 MW.
The wall-fired boiler design is capable of utilizing all conventional
fossil fuels, including natural gas, fuel oil, and pulverized coal. Well-
known manufacturers of this type of boiler include The Babcock and Wilcox
and Foster Wheeler Companies (Reference 3-7).
3.3.2 Tangentially- and Turbo-Fired Boilers
Tangentially- and turbo-fired boilers are grouped together because the
burner equipment is essentially identical for both boiler types; i.e., both
use multiple burners, both fire between the boiler tubes, fuel/air mixing
takes place within the boiler furnace itself (as opposed to the burner throat
of a register type burner), and they employ a common burner capacity range -
75 x 10s to 125 x 10s Btu/hr.
The boilers are physically quite different. Tangential boilers, as show
in Figure 3-2, are fired with groups of 4 burners at the same elevation with ea
burner located in a corner of the boiler. Each burner fires along the tangent
of a small imaginary circle in the center of the boiler. The resulting spin of
the four "flames" creates high turbulence and thorough mixing of fuel and air i
the center of the furnace. Additional levels of burners at 6- to 10-foot incre
ments provide additional capacity for larger boilers.
Turbo-fired furnaces, as illustrated in Figure 3-3, provide a similar
turbulent mixing of fuel and air in the furnace, but in this case, the burners
are mounted in opposing walls of a "bottle neck" type furnace. The walls are
tilted towards each other such that opposing burners fire down at a 30° angle
towards the center of the lower part of the boiler. The burner sizes mentioned
3-5
-------
urner
x-
Single wall-fired
Horizontally opposed
wall-fired
Figure 3-1. Vertical wall-fired utility boiler shapes and burner configurations
3-6
-------
Fuel and air injection
compartments
Figure 3-2. langentially-fired utility boiler shape and firing pattern
3-7
-------
Burner
Figure 3-3. Riley Turbo furnace shape and burner configuration
3-8
-------
above are the same as those commonly found in tangentially-fired boilers.
Therefore, higher boiler capacities are attained by increasing the boiler widt
and the number of burners.
Turbo-fired boilers are manufactured by Riley Stoker, while most of the
tangentially-fired utility boilers are constructed by Combustion Engineering,
Incorporated (Reference 3-8).
3.3.3 Cyclone-Fired Boilers
A cyclone boiler is composed of the combination of a watertube boiler
and a separate "cyclone" furnace (or series of furnaces) that are themselves
water-cooled. Cyclone furnace firing arrangements are depicted in Figure 3-4.
This type of furnace is capable of handling coals with high slag viscosities
(250 poise at 2600F or lower). The air-conveyed coal and secondary air are
injected into the furnace such that a highly swirling "cyclone" flame results.
The high heat release of the furnace results in the high gas temperatures that
are necessary for the formation of liquid slag. Slag taps permit continuous
removal of the molten slag. Typical single furnaces are designed for firing
capacities between 100 x 10s and 400 x 106 Btu/hr, with multiple cyclone fur-
naces being employed for loads above 400 x 106 Btu/hr. Cyclone furnaces are
designed primarily for coal-firing, with gas or oil available only for standby
operation. For gas operation, the fuel is injected horizontally with the
secondary air.
Most cyclone-type boilers are constructed by The Babcock and Wilcox
Company or its subsidiaries (Reference 3-7).
3-9
-------
Cyclone
furnace
Path of
swirling
flame
Single wall-fired
Opposed wall-fired
Figure 3-4. Cyclone furnace firing arrangements
3-10
-------
SECTION 4
CHARACTERIZATION OF SUBSTITUTE FUELS
4.1 INTRODUCTION
The preceding section provided brief descriptions of the types of SO
emitting combustion systems for which the costs of switching from conventional
fossil fuels to various coal-derived fuels were estimated in this study. The
present section attempts to characterize these exotic fuels.
Four distinct coal conversion routes are possible. These include:
pyrolysis, hydrogenation, solvation, and production of synthesis gas. The
amount, type and quality of the products from each of these methods depend
upon the coal properties and process conditions (Reference 4-1).
In pyrolysis, the coal is heated in an inert atmosphere to break it
down into solids, liquids, and gases, the amounts of which are proportional
to the heating rate.
In hydrogenation reactions, coal and hydrogen are reacted together
directly. In the presence of a catalyst at 850F and at elevated pressures,
a liquid product is made. If a catalyst is not present, the coal reacts
directly with hydrogen at higher temperatures (about 1600F) and pressures
(150-300 psi) to form methane.
During solvation, the coal is dissolved and, with the addition of hydro-
gen at modest pressure, can be filtered and converted into an essentially ash-
free and low sulfur solid or liquid.
Synthesis gas is produced by reacting coal with an oxidizing agent and
steam. The resulting low heating value gas can then be used to make a high-Btu
gas by a methanation step which reacts the purified gas over a nickel catalyst.
The present study concerns itself with the conversion of steam-raising
boilers firing conventional fossil fuels to the use of selected products from
solvation and synthesis gas coal conversion methods; namely, solvent refined
coal (SRC) and lower-Btu gas. Brief summaries of these processes and their
products are presented in the following subsections.
4-1
-------
4.2 LOW- AND MEDIUM-BTU GAS
The basic process for converting solid coal to a fuel gas comprising
principally nitrogen, carbon monoxide, hydrogen, and a certain amount of
methane is well understood. In fact, the "town gas" commonly used, especially
in Europe, before the general availability of natural gas was produced with
earlier versions of present-day equipment. In general, these gases are pro-
duced when an insufficient quantity of oxidizer is supplied to the coal at a
high temperature, thus preventing the reaction from going to completion to
form carbon dioxide and water.
Most gasification processes have in common four basic sequentially-
occurring reactions. The principal heat-producing reaction is oxidation,
which results when oxygen reacts with fuel to form water and carbon dioxide:
C + 02 -y C02
H2 + 1/2 O2 -»- H20
Next comes the gasification reaction, which is the most endothermic.
This reaction occurs when unburned carbon from the fuel reacts with steam
and carbon dioxide to form hydrogen and carbon monoxide:
C + •*• CO +
The third reaction, hydrogasification, is mildly exothermic and takes
place when hydrogen reacts with fuel carbon to give methane:
Finally, and sometimes concurrently with the preceding reactions, de-
volatilization occurs when the fuel is subjected to heating:
Coal + Heat -»• C + CH4 + HC
Among the myriad types of gasification processes either operating or
contemplated, these four basic reactions can occur simultaneously in a reactor,
or each may take place in a particular region of the reactor, or each may be
confined to a separate vessel. Most of these processes are designed so that
4-2
-------
the heat required by the highly endothermic gasification reaction is supplied
by the heat released from the other three reactions. Adjusting the amount of
oxidizer lent to the process controls this heat balance. Raw gas leaving the
gasifier consists mainly of methane, hydrogen, nitrogen, carbon oxides, and
sulfur compounds. The sulfur compounds and other impurities are removed down-
stream.
The basic gasification process described to this point delivers a pro-
duct gas whose heating value abides primarily in the carbon monoxide and
hydrogen resulting from the gasification step. This product is usually termed
"lower-Btu gas." This definition is employed because there are two fuel-gas
heating values of potential interest below the SNG level of 900 to 1000 Btu/scf,
The first of these is the range of 300 to 700 Btu/scf, which is referred to as
medium-Btu gas. The other is the range of 150 to 250 Btu/scf, which is re-
ferred to as low-Btu gas.
Two basic motives exist for converting coal to gas, depending on the
ultimate application (Reference 4-2):
• If pipeline quality, high-Btu gas is desired, the product gas must
go through an additional methanation step. This is an expensive
process, whereby additional hydrogen is produced and chemically
reacted with carbon monoxide to form methane. Current SNG costs
are in the range of $1.05 - $1.50/106 Btu.
• If the purpose of gasifying coal is solely to remove ash and sulfur
so that the fuel gas is nonpolluting when burned, the heating value
need only be high enough to maintain a stable flame, with a minimum
deleterious effect on plant efficiency. Medium- and low-Btu
gases are well suited for this purpose. In most processes, oxygen
injected into the gasification step will produce the former gas
("oxygen-blown"), while air injection will produce low-Btu gas
("air-blown"). Medium-Btu gasification saves 10 to 15 percent
in coal feed rate, 30 to 35 percent of plant investment, and 25 to
35 cents/106 Btu relative to SNG. Producing low-Btu gas provides
an additional savings of 5 to 10 cents/Btu over gases of intermediate
Btu heat content.
The attractiveness of lower-Btu gas as a boiler fuel is quite apparent.
Studies have shown that the most feasible location for lower-Btu gasification
plants is at the point of use, while the product from SNG plants can be eco-
nomically transported by pipeline over long distances (References 4-3, 4-4,
4-5, 4-21). It is therefore easy to visualize lower-Btu gasification plants
4-3
-------
constructed next to a new or existing combustion system, whether the product
is destined for the steam-electric utility or industrial boiler sector.
Combustion systems firing conventional fossil fuels, however, will re-
quire some degree of equipment modification before these new gaseous fuels
can be burned. Assessing the costs of such conversions was the objective of
the present study.
For the purposes of the study, certain simplifying assumptions are made
about the combustion characteristics of these gases. Table 4-1 shows the chemi-
cal compositions of selected lower-Btu gasified coal fuels. These gases are
representative of the products of all gasification processes, detailed descrip-
tions of which are given in Appendices A and B. The heating value of the
gases range from 170 Btu/scf for the air-blown Lurgi to 780 Btu/scf for the
Hydrane process. For the most part, heating value is directly proportional
to volume percent of methane.
It will be assumed that the combustion characteristics of these and all
lower-Btu gases will depend on heating value alone and be decoupled from spe-
cific chemical composition. This will allow the range of gas types to be
treated as a continuum. In this way, the equipment conversion costs of sub-
stituting for these gases can be related to heating value. Section 6 will
describe in more detail the method used for incorporating a heating value
term in the conversion cost equations for the gaseous substitute fuels.
4.3 SOLVENT REFINED COAL
In Section 4.2, the feasibility of using coal-derived gases of lower
heating values (<1000 Btu/scf) as low sulfur boiler fuels was discussed.
Similar advantage can be gained by using the products from coal conversion
processes that generate clean fuels that are liquids or solids at room tem-
perature. Examples of the former type are the products from the Bergius -
I.G. Farben, Fischer-Tropsch, COED, H-Coal, and Flash Pyrolysis processes.
Ample descriptions of these treatment methods, which are essentially pyroly-
sis or hydrogenation processes, appear in References 4-14, 4-15, and 4-1.
Clean solid fuels from solvation processes are exemplified by solvent refined
coal (SRC). Cost estimations for converting stationary combustion equipment
to the use of this fuel were established in the present study.
Solvent refined coal (SRC) is a name given to a reconstituted coal which
has been dissolved, filtered, and separated from its solvent. It is moisture-
free, low in sulfur and ash, and can apparently be handled in the liquid as
4-4
-------
TABLE 4-1
COMPOSITIONS OF SELECTED LOW- AND MEDIUM-BTU GASIFIED COAL FUELS
("-" denotes negligible quantity and "m" denotes missing data)
Item
Coal Type
*>
t/1
CO
co2
H2
N2
?! H2S
|£ COS
S(gm/
CH4
CmHn
H20
106Btu)
HHV(Btu/scf)
Koppers-
Totzek
(4-6)
Western
58.68
7.04
32.86
1.12
0.28
0.02
-
m
-
-
295
Koppers-
Totzek
(4-6)
Illinois
55.38
7.04
34.62
1.01
1.83
0.12
-
m
-
-
290
Koppers-
Totzek
(4-6)
Eastern
55.9
7.18
35.39
1.14
0.35
0.04
-
-
-
-
294
Synthane
(4-7)
Pgh. Seam
16.8
28.8
27.8
0.8
0.5
-
24.5
0.8
-
-
406
BCR.Inc.
(4-8)
W. Ky.
44.0
14.0
24.4
0.6
1.4
-
15.6
-
-
-
380
IGT
(4-9)
Lignite
19.5
24.6
24.5
0.6
0.4
-
28.2
2.1
m
-
467
Oxygen
Lurgi
(4-10)
Sub. Bit.
17.1
31.4
40.2
-
0.3
-
10.2
0.4
-
-
400
Hydrane
(4-11)
Pgh. Seam
4.2
1.3
21.4
1.0
3.3
-
68.5
m
-
-
780
Well man-
Gal usha
(4-12)
m
27.0
2.1
14.4
47.25
0.05
-
2.6
-
6.6
117
160.4
Commercial
Lurgi
(4-10)
m
14.1
12.5
20.9
40.0
0.1
-
5.8
-
6.6
221
172.7
Texaco
(4-13)
m
27.5
1.0
25.3
37.2
0.009
-
0.5
-
8.5
-
175.8
01
-------
well as the solid state. In the latter form, it is brittle and easily grind-
able. The process of pulverization can, however, heat the material sufficiently
to cause undesirable agglomeration. Its major advantage is that its heating
value remains at 16,000 Btu/lb regardless of the quality of the coal feedstock.
The SRC process has been under development for a number of years. Pitts-
burg & Midway Coal Mining Company, under the sponsorship of the Office of Coal
Research, demonstrated the technical feasibility of the process on a pilot
scale in 1964. In 1972, construction was begun on two additional SRC pilot
plants. The 6 ton/day Wilsonville, Alabama, facility has been completed and
is currently producing small amounts of material for experimental purposes.
The project is sponsored by the Electric Power Research Institute and Southern
Services. A larger plant, 50 ton/day, is located at Tacoma, Washington, and
will be completed in late 1974. In both facilities, emphasis is placed on
developing a utility fuel of a quality that will meet environmental standards
when burned (Reference 4-3).
The solvent refined coal process is shown schematically in Figure 4-1.
SRC is produced by first dissolving coal under pressure in a recycled solvent
containing a small quantity of hydrogen. The coal solution is then filtered
to remove virtually all of the mineral matter including the pyritic sulfur.
Small quantities of hydrocarbon gases and lighter liquids are distilled off.
The main product from the process is a heavy organic material which has a melt-
ing point of about 350F and, depending on the composition of the feedstock
coal, contains less than 0.1 percent ash and less than 0.8 percent sulfur.
The yield of solvent refined coal and other liquid products is approximately
90 percent of the original coal (References 4-16, 4-17).
The compositions of typical samples of SRC are presented in Table 4-3,
while the analysis of the coal from which they were derived is shown in Table
4-2. These analyses are associated with projects performed by the Bureau of
Mines (Reference 4-18), Combustion Engineering, Inc. (Reference 4-19), and The
Babcock and Wilcox Company (Reference 4-20), in an effort to determine the
combustion characteristics of SRC, samples of which were supplied by the Office
of Coal Research. The investigators came to the following general conclusions:
• Based on both the proximate and ultimate analyses, the solid phase
material appeared similar to a high volatile bituminous coal except
for the reduced sulfur and ash content.
• Thermogravimetric analyses indicate ignition characteristics similar
to a high volatile bituminous coal, but for burnout it appears to
more closely resemble a semianthracite.
4-6
-------
Coal
Solvent (recycle)
Preheater
Dissolver
Filter
Light
Distillation
Solvent
refined
coal
Ash
residue
Solidification
belt
Ash
^ products
Ash processing
Figure 4-1. Solvent Refined Coal Process (Reference 4-16)
4-7
-------
TABLE 4-2
ANALYSIS OF KENTUCKY NO. 11 COAL, AS RECEIVED
(References 4-18, 4-19)
Proximate Analysis, Mass %
Total
Volatile Matter
Fixed Carbon
Ash
Ultimate Analysis, Mass %
Hydrogen
Carbon
Nitrogen
Oxygen
Sulfur
Ash
Heating Value, Btu/lb
Hardgrove Grindability
5.2
40.2
48.1
6.2
5.5
70.9
1.9
12.0
3.5
6.2
12,770
61
TABLE 4-3
ANALYSIS OF SOLVENT REFINED COAL
("m" denotes missing data)
Proximate Analysis, Mass %
Total Moisture
Volatile Matter
Fixed Carbon
Ash
Sulfur
Ultimate Analysis, Mass %
Moisture
Hydrogen
Carbon
Ni trogen
Sulfur
Oxygen
Ash
High Heating Value, Btu/lb
Hardgrove Grindability
Melting Temperature, F
Pumping Temperature, F
Atomization Temperature, F
Ref. 4-18
0.0
57.6
42.3
0.1
m
0.0
5.5
88.2
1.5
1.1
3.6
0.1
15,680
m
m
m
m
Ref. 4-19
0.0
59.2
40.6
0.15
m
0.0
5.3
86.9
1.4
1.4
4.8
0.15
15,559
m
300
m
m
Ref. 4-20
0.0
57.7
40.9
0.36
1.1
0.0
5.2
88.4
1.44
1.1
3.5
0.36
15,730
164
m
500
665
4-8
-------
• The grindability index (about 160) indicated that the' solid SRC
can be pulverized with less power than nonprocessed coal (e.g.,
grindability for the Kentucky No. 11 coal was 61).
• In pulverized form, firing tests indicated that the material tended
to agglomerate in the fuel lines when the primary (coal conveying)
air was preheated.
• In the liquid phase, firing tests indicated that the material was
similar to No. 6 fuel oil in handling and combustion characteris-
tics. The preheating requirements are greater, however. For good
pumpability (viscosity <30 cp) it must be heated above 635F. Be-
cause of the expulsion of volatile matter at temperatures above 35OF,
heating should be carried out under pressure in a closed system.
• When firing in the liquid phase, all fuel handling equipment in
contact with the SRC must be heated to above 350F. In addition,
steam-atomizing, heavy oil guns are recommended to eliminate the
need for heating the gun components with an external heat source.
As implied by these conclusions, there remains some question as to the
most advantageous phase in which to handle and burn the SRC. If applied in
the solid form to conventional pulverized coal-fired combustion equipment,
the retrofit procedure may be straightforward and inexpensive if most of the
original equipment can be used and if the fuel handling equipment need not be
externally cooled. When heated, by all indications, this material can be fired
as an oil. In both cases, however, unforeseen retrofit difficulties may arise.
More light will be cast on the situation when the results of additional EPRI-
funded combustion tests, currently being performed by Combustion Engineering
and Babcock & Wilcox, become available early in 1975.
As was related in Section 2 of the present study, no actual conversions
of conventional steam-raising boilers of any capacity to the use of solvent
refined coal have yet taken place. This is partially due to a general lack of
sufficient quantities of this fuel at the present time. For the purposes of
this study, the conversion cost estimation methods described in Section 5 will
necessarily be based on past conversion experience involving similar substitute
fuels.
4.4 SUMMARY AND CONCLUSIONS
Of the four basic coal conversion routes, pyrolysis, hydrogenation,
solvation, and synthesis gas formation, representative products from the
latter two processes have been considered in this study.
4-9
-------
Solvent refined coal, in its solid state, is brittle and readily grind-
able into a fine powder. It is low in ash and sulfur, moisture free, and can
be melted and handled as a fluid. Its heating value is about 16,000 Btu/lb,
regardless (theoretically) of the type of feedstock coal. If its application
as a boiler fuel is proven feasible, the major advantages afforded by SRC are:
• Use of plentiful high-sulfur coal reserves would be permitted
• The uniformity of the SRC product would permit power plants to use
one "off-the-shelf" boiler design
The production of synthesis gas from coal has a lengthy history, and
the technology is currently being revived. Most coal gasification processes
have in common four basic reaction steps, ultimately producing a gas of heat-
ing value below that of natural gas (150-700 Btu/scf). To produce synthetic
natural gas (SNG), the products from most of the gasification processes can
be exposed to additional methanation steps. Economics demand that lower-Btu
gasification plants be located on the site of use, while it is feasible to
pipe SNG over long distances. As lower-Btu gas is less expensive than SNG to
produce, is sulfur and ash free, and by all indications is able to produce a
stable, trouble-free flame, it shows promise as a boiler fuel.
In order to use either lower-Btu gas or SRC in existing stationary
boilers, it will be necessary to convert the combustion equipment from the
use of conventional fossil fuels. As this has yet to occur on a large scale
for any of these exotic fuels, the conversion costs appearing in this report
are necessarily estimations, based on past conversion experience to similar
substitute fuels.
4-10
-------
SECTION 5
SELECTION OF FUEL SUBSTITUTION OPTIONS
Section 3 of this report described the types of combustion equipment
that will be considered as candidates for conversion to cleaner fuels. These
consist of all major types of industrial and utility boilers, encompassing a
boiler capacity range from 107 Btu/hr to 1000 x 107 Btu/hr. For an estimated
35% thermal efficiency, these heat release rates correspond to an electric
generating capacity range of 1 to 1000 MW. Section 4 of this report dis-
cussed the various types of clean fuels considered as subsitutes for conven-
tional, high sulfur fossil fuels. These included solvent refined coal, low-
Btu gas, medium-Btu gas, and natural gas. The first three are of interest in
that they are the products of promising coal-conversion processes. The costs
of equipment conversions to natural gas, an operation for which ample exper-
ience has already been gained, will act as a reference point for the conver-
sions to the other fuels.
The information contained in Sections 3 and 4 helped to define the lo-
gical fuel substitution options available for a given type of boiler firing a
given type of original fuel. These options are compiled in Table 5-1. The
major points to be gained from this table are the following:
• The initial assumption is that all boiler types are capable of
being converted to all of the substituted fuels.
• This number is reduced by the exclusion of certain illogical con-
versions, based on the following reasons:
Nonexistence of coal-fired firetube and packaged watertube
boilers
Exorbitant cost associated with converting oil-fired combustion
equipment to solid SRC (only conversions from solids to liquids
or gases, and from liquids to gases are judged practical)
Nonexistence of oil-fired stoker and cyclone furnaces
5-1
-------
TABLE 5-1
FUEL SUBSTITUTION OPTIONS
Original
Fuel
Coal
Oil
Boiler
Category
Industrial Types:
• Firetube
• Packaged
watertube
• Field-erected
watertube
• Stoker
Utility Types:
• Cyclone-fired
• Tangentially-
fired
• Wall -fired
• Turbo-fired
Industrial Types:
• Firetube
• Packaged
watertube
Applicable
Substitute
Fuels
None
None
LBG, MBG, NG
LSRC, SSRC
LBG, MBG, NG
LSRC, SSRC
LBG, MBG, NG
LSRC, SSRC
LBG, MBG, NG,
LSRC, SSRC
LBG, MBG, NG
LSRC, SSRC
LBG, MBG, NG
LSRC, SSRC
LBG, MBG, NG
LSRC
LBG, MBG, NG
LSRC
Comments
No coal -fired boilers of this type
Essentially no coal -fired boilers of
this type
Equipment conversion will necessitate
modification of equipment internal to
the boiler; solid SRC cannot be burned
like coal (on the grates) due to its
low melting point.
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Notation: LBG = low-Btu gas
MBG = tnedium-Btu gas
N6 = natural gas
LSRC = liquid SRC
SSRC = solid SRC
5-2
-------
TABLE 5-1 (Concluded)
Original
Fuel
Boiler
Category
Applicable
Substitute
Fuels
Comments
• Field-erected
watertube
• Stoker
Utility Types:
• Cyclone-fired
• Tangentially-
fired
• Wall-fired
Turbo-fired
LBG, MBG, NG,
LSRC
None
None
LBG, MBG, NG
LSRC
LBG, MBG, NG
LSRC
LBG, MBG, NG,
LSRC
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Stokers are fired solely with solid
fuel
Essentially no oil-fired cyclone
furnaces; designed mainly for coal
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Solid SRC is considered an illogical
substitute fuel for boilers originally
firing oil
Notation: LBG = low-Btu gas
MBG - medium-Btu gas
NG = natural gas
LSRC = liquid SRC
SSRC = solid SRC
5-3
-------
These options were instrumental in the determination of the required
equipment conversion cost data, as indicated by the space enclosed within the
bold lines in Figures 5-1 and 5-2. These figures are the forms of the master
data sheets that were ultimately used to tabulate the cost figures. The two
extreme left-hand columns contain the delineation of industrial and utility
boiler types, an indication of whether the boiler is packaged or field-
erected, and its normal capacity range in units of 10s Btu/hr. The columns
between the double vertical lines serve to space out the increments in boiler
capacity range. The letters in the rows contained in the extreme right-hand
column indentify the cost category entered in the row; "E" denotes equipment
cost, "I" denotes installation expense, and "T" is the sum of E and I, or,
total capital investment.
Five sheets of the form of Figure 5-1 will contain the costs for con-
verting the appropriate boilers from coal to the use of the five substitute
fuels. Similarly, Figure 5-2 indicates that four data sheets will be com-
pleted for conversions of oil to the four applicable substitute fuels.
The equipment conversion cost estimations and associated documentation
are contained in the following section of this report.
5-4
-------
Ul
I
en
3
».
J O
A O.
3 >>
3 H-
•4
n
j
i
»-,
^
3
,.
SUBSTITUTE FUEL: 0 LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: g| COAL jjg MEOIUH-BTU GAS (400 BTU/SCF)
[J OIL 0 NATURAL GAS (1000 BTU/SCF)
0 LIQUID SRC (16,000 BTU/L8)
[3 SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WA7ERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P » PACKAGED
E ' FIELD-
ERECTED
/CAPACITY \
RANGE:
\10S BTU/HR/
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
f
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 10« BTU/HR
(Mote: { } denotes capacity for which costs beneath apply)
. TnHur -fr 4 ji 1 "Mio -• -
1
10-15
{ )
16-25
{ )
26-50
{ }
51-100
{ }
101-150
{ }
151-250
{ }
251-500
{ }
Utility
size '
501-2000
{ }
2001-5000
{ )
5000-10000+
{ )
Lu
2T
bU
>
Z ',3
O ^
»— h- O
E: <: LU
jj _j «
s; -j
= ^5*
t -- tyu
CONVERSION COST: I = INS
r - TOI
C
I
T
E
I
T
E
I
E
I
T
E
I
T
c
I
7
I
T
E
I
T
Figure 5-1. Conversion Cost Data Sheet for Coal-Fired Boilers
-------
Figure 5-1. Conversion Cost Data Sheet for Coal-Fired Boilers
3
_ V!
18.
= >»
y H-
n
j
X
»»
•?
j
3
-
BOILER -
CATEGORY
FIRETUBE
KATERTUBE
ST'JKER
CYCLONE
TANGENTIAUY-
flKtb
WALL-FIRED
TURBO-FIRED
SUBSTITUTE FUEL: 03 LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: Q COAL gj HEDIUM.BTU GAS (400 BTU/SCF)
03 OIL (X] NATURAL GAS (1000 BTU/SCF)
H LIQUID SRC (16,000 BTU/L-6)
Q SOLID SRC (16,000 BT'J/LB)
SUB-
CATEGORY
P • PACKAGED
E « FIELD-
ERECTED
/CAPACITY N
RANGE:
\106 BTU/HRy
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
(500-10000+)
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs ben
10-15
{ }
16-25
{ }
26-50
{ }
51-100
{ }
' ' "
101-150
{ }
1
1
l_
151-250
{ }
251-500
{ )
•••••••
sath apply)
Utility
size *
501-2000
{ )
1
r-J
2001 -5000
{ }
5COO-1000C*
{ )
1
U'_
2C
?*•
ar —
Cr z. o
H r- n
UJ i-« t—
I —
•>-)
O
u
^
O
•^
ce
^»
zr
o
cj
E
T
T
C.
I
1
c
1
T
t
I
T
£
I
i
c
I
T
E
I
T
L__
I
T
Cn
I
Figure 5-2. Conversion Cost Data Sheet for Oil-Fired Boilers
-------
SECTION 6
DOCUMENTED BOILER CONVERSION
COST DATA
6.1 INTRODUCTION
The preceding section served to define the available fuel substitution
options for a given type of boiler. The techniques used to compile the cost
data were introduced as well. This section begins with a brief discussion of
the major considerations associated with the various types of boiler conversion
procedures, continues with the actual cost figures presented in both tabular
and graphical form, and concludes with a presentation of the proposed cost
models that can be derived from the cost data.
6.2 BOILER MODIFICATION CONSIDERATIONS
This subsection is organized into four portions:
• The general equipment modification considerations prevailing for all
of the boiler types
• Some specific points pertaining to certain unique boiler types
• A general discussion of the proposed substitute fuel handling
systems
• Descriptions of the firing equipment required for the gaseous and
liquid substitute fuels.
6.2.1 General Equipment Modification Considerations Applicable to All Boiler
Types
The following are general considerations applicable to all boilers of
the indicated type:
• The conversion to the new fuel was planned and implemented in such
a manner as not to effect boiler efficiency.
• Existing burner registers can be reused; for coal-fired boilers,
the coal nozzles are removed to such a position as to allow adequate
working space for installation of new burners.
6-1
-------
• The burners selected for gas firing are termed "center-fired" gas
guns. Each burner assembly includes a burner gun, guide pipe, shield,
flame stabilizing device, flex hose, hand valve, and mounting adapt-
er plate.
• Burners for liquid SRC firing are steam atomizing oil burners of
the internal mixing type. (Refer to Table 6-1 for the determination
of the number of burners required for the individual boiler capaci-
ties chosen for the cost estimations.)
• For converting coal-fired boilers to any of the substitute fuels,
a burner management system will be required. The type recommended
by the NFPA Supervisory Manual was used. The system includes a logic
cabinet, safety interlocks, and all interconnecting piping and wiring.
Reference 6-1 supplies additional information on this system. For
oil-fired equipment, the existing burner management system can be
used, but with new limit and safety interlock settings.
• Existing combustion controls can be reused. Each conversion requires a
new fuel flow transmitter, fuel flow rate control valve, and mis-
cellaneous relays and valves to be interfaced with the existing panel.
• It was assumed that no modifications to the boilers' wall-mounted
heat transfer surfaces, superheaters, or economizers were required.
Indeed, one industrial-size boiler manufacturer stated that their
boilers' interior designs for the coal-derived fuels would not differ
appreciably from designs presently used for more conventional fossil
fuels.
• Existing forced draft and induced draft fans can be reused for the
new fuels.
• The assumed gas and liquid SRC supply pressures at the burners are
given in Table 6-2. In an existing plant, of course, the supply
pressures must be chosen on the basis of practical line size and
physical space considerations.
6.2.2 Special Equipment Modification Considerations for Unique Boiler Types
The following are some additional fuel substitution program considerations
for five unique categories of boilers.
6-2
-------
TABLE 6-1
BOILER TYPES, CAPACITIES, AND ASSOCIATED
BURNER QUANTITIES FOR GAS- AND LIQUID SRC-
FIRING
Boiler Category
Fire Tube
Watertube (field-erect.)
Watertube (packaged)
Stoker
Cyclone
Tangenti ally-fired
Wall -fired
Turbo-fired
Capacity Burner
(106Btu/hr) Quantity
12 1
75 1
25 1
25 1
250 2
250 2
1,000 8
250 2
Capacity Burner
(10*Btu/hr) Quantity
20 1
150 2
75 1
75 1
1 ,000 8
1 ,000 8
3,500 2«
1 ,000 8
Capacity Burner
(106Btu/hr) Quantity
35 1
350 4
150 2
150 2
7500 60
7500 60
7500 6P
7500 60
6-3
-------
TABLE 6-2
BURNER SUPPLY PRESSURES FOR GASEOUS
AND LIQUID SUBSTITUTE FUELS
Substitute
Fuel Type
Low-Btu gas
Medium-Btu gas
Natural gas
Liquid SRC
Burner Supply
Pressure (psig)
35 - 40
30
15
125
6-4
-------
6.2.2.1 Firetube Boilers
It was assumed that an industrial-type flame safeguard system exists
and is reusable. Gas safety interlocks and a fuel selector switch are added.
In addition, it was assumed that the existing burner guns are steam- or high
pressure air-atomized, and not mechanical atomized.
6.2.2.2 Stoker-Fired Boilers
For the purposes of this study, it was assumed that the mechanical
stoker and internal grates would be removed and a new twelve inch-thick refract
ory floor would be installed. A completely new windbox-burner assembly would
be installed in the lower front wall. The actual number of burners needed
depends on the furnace capacity.
In some cases, the more economical approach would be to install the
refractory directly on the existing grates, and mount the windbox burner in
the boiler's sidewall. However, this would require bending of the heat trans-
fer tubes in the vicinity of the burner to afford clearance for the burner
throat. The disadvantages of this approach are operator inconvenience, possibl
water circulation problems due to the unusual tube bends, and minor problems
in adjusting the flame shape to retain a uniform temperature profile across
the boiler tube bank or superheater (if employed).
As a general rule, the retrofitted burner can be supplied with an inte-
gral fan rather than attempting to reuse the existing combustion air fan. This
is because the fan cost is offset by the labor, materials, and engineering re-
quired for the installation of a duct from the existing fan to the new burner.
For solid SRC, the only practical conversion strategy would be to in-
stall a suspended firing system as is described above. Due to its rather low
melting temperature (260F), the SRC would be incompatible with the stoker's
grates, which are designed for bed-type combustion with concurrent removal of
incombustible ash and char.
6.2.2.3 Cyclone-Fired Utility Boilers
For retrofitting this class of boiler to the gaseous or liquid coal-
derived fuels, the new burner guns can be installed through the existing coal
burner. It was assumed that the average cyclone furnace heat release rate was
250 x 10s Btu/hr. Capacities of larger boilers would be multiples of this
figure, and would require a correspondingly larger number of individual cy-
clone furnaces. It was assumed that on liquid SRC firing above 200 x 106
Btu/hr, two simultaneously-firing oil atomizers will be used, because this
heat release quantity is currently the upper limit of a single atomizer as
currently designed.
6-5
-------
The existing combustion control system can be used, but will require
the addition of a fuel flow control valve for each cyclone furnace.
6.2.2.4 Turbo- or Tangentially-Fired Utility Boilers
For oil-fired boilers of these types, retrofit of the gases and liquid
SRC will involve the installation of the burners ("gun" design) either in a
parallel (tangentially-fired) or an adjacent (turbo-fired) configuration. In
coal-fired units, the guns can be substituted in place of the existing coal
burner tubes and nozzles.
There may occur a small difference in piping installation costs between
the tangentially- and turbo-fired boilers due to running the piping vertically
versus horizontally. This variation, however, was considered insignificant
in light of the other plumbing costs, such as valve installation.
6.2.3 Fuel Handling Systems
In the determination of piping costs for the gaseous substitute fuels,
it was assumed that the amount of piping installed could be grouped into
three categories, the length being an arbitrary function of the boiler capa-
city. Therefore, the piping to the boiler is essentially independent of
boiler type. The capacities and respective pipe runs are given in Table 6-3
(A) .
The second general assumption made for the gaseous fuel handling systems
was that the piping supplied a single boiler. The third and possibly most
important assumption was made in regard to the pressures of each type of gas
as supplied to the steam plant boundary. This information is given in Table
6-3(B). These pressures were selected because they appeared to be commercially
practical, and because the line sizes more closely match existing industrial
standards. It is obvious that the variation in the main gas supply pressure
could effect the validity of the cost estimates; this is especially true in
the case of low-Btu gas.
For solvent refined coal (SRC) in the hot liquid state, complete heat-
ing systems are required for both the SRC storage facilities and the burner
supply piping system. A liquid heat transfer system using Therminol 77 was
selected for these purposes (see Reference 6-2 for Therminol"s properties).
This heat transfer fluid is heated by firing No. 2 fuel oil in a firetube boiler
on the plant premises. The hot Therminol is then used to warm the storage tanks
and the day tanks, to supply the suction heaters, and to heat trace all piping
and valves. It was assumed that the SRC would be delivered at 450F, all pump-
ing would be done at 1100 centistokes, and that the SRC would arrive at the
6-6
-------
TABLE 6-3
GASEOUS FUEL HANDLING SYSTEM PIPING LENGTHS AND
SUPPLY PRESSURES
(A) Piping Length, All Gases
Boiler Capacity Range
(10s Btu/hr)
10-65
75-350
500-7500
Piping Length
(ft)
500
1000
2000
(B) Supply Pressure to Plant Boundary
Gaseous Fuel Type
Supply Pressure
(psig)
Low-Btu
Medium-Btu
Natural
350
130
50
6-7
-------
burner at 66 centistokes (640F). Each system includes the following features:
• An unloading pump set of capacity equal to six times the firing
rate
• Insulated bulk storage tank(s) for the liquid SRC and No. 2 fuel
oil, with an estimated thirty day storage capacity
• Tank foundations and firewalls
• Tank suction heater(s)
• Therminol heaters and circulation pumps
• No. 2 oil pump sets
• SRC transfer pump set
• Insulated SRC day tank (two day storage capacity)
• Day tank suction heater
• Final pump and heater set
• All necessary interconnecting piping and valves
For solid SRC, the costs of converting coal-fired boilers will reflect
the requirement that various portions of the fuel handling system be externally
cooled, by either water or air. It was assumed that the existing coal handling
and preparation equipment could be used with no major modifications necessary.
Air preheat operation would be discontinued and replaced by a system supplying
ambient or chilled air for coal conveying purposes. It was also assumed that
the coal supply pipe at the burner would be water-cooled.
6.2.4 Firing Equipment For Gases and Liquid SRC
This subsection contains more detailed information on the replacement
firing equipment for the gaseous and liquid substitute fuels, including:
• Burner types
• Burner fuel supply valving
• Burner management systems
For conversions of coal-fired combustion systems to the use of solid
SRC, it was assumed that the existing firing equipment with the retrofits de-
scribed previously would be adequate for the purpose. For these boilers, major
modification costs will be associated only with the fuel handling system.
6-8
-------
6.2.4.1 Burner Types
For gaseous substitute fuel firing, the burner selected was the center-
fired gas gun. Table 6-4 shows the gun sizes chosen for the various gases.
To burn liquid SRC, a burner of the multiple venturi design was deemed
practical. This is a steam-atomized burner normally used for heavy fuel oil
(No. 6) combustion applications. Table 6-5 lists the model numbers and corres-
ponding heat release rates of a typical commercially-available multiple venturi
burner. Similarly-designed burners are available from a number of manufacturei
6.2.4.2 Burner Fuel Supply Valving
The following are typical valve requirements for single and multiple
burner applications:
Single Burner, Gas-Fired
Pilot gas cock, pilot gas PRV, two pilot safety shut-offs, one pilot
gas vent, main gas safety shut-off, supervisory gas plug cock, and main gas
fuel flow control valve.
Single Burner, Liquid SRC-Fired
Main oil safety shut-off, main oil check, supervisory oil cock, steam
purge, steam check, manual oil shut-off, manual steam shut-off, oil strainer
steam drain, steam trap, steam-oil pressure differential control, and main oil
flow control valve; pilot valves are the same as for gas.
Multiple Burners, Gas-Fired
The following valves are required at the header: main gas strainer,
manual shut-off, main gas PRV, bypass PRV, main safety shut-off, main gas
header vent, two manual gas vent valves, main gas reliefs, pilot gas manual
shut-off, pilot gas PRV, and one main gas control valve.
The following valves are required at each burner: burner safety shut-
off, supervisory shut-off cock, two pilot gas safety shut-offs, and one pilot
gas vent valve.
Multiple Burners, Liquid SRC-Fired
The following header valves are required: manual oil shut off, oil
strainer, main oil safety shut-off, oil by-pass PRV, oil return check valve,
oil recirculating valve, steam manual shut-off, steam strainer, steam trap,
steam PRV, steam bleed check, steam-oil differential pressure, oil flow control
valve, manual pilot gas valve, and pilot gas PRV.
6-9
-------
TABLE 6-4
GUN SIZES FOR GASEOUS SUBSTITUTE FUEL FIRING
(NOMINAL PIPE SIZE, INCHES)
^s. Burner Firing
^X. Rate
Gaseous\J10*Btu/hr)
Fuel ^\
Type \^^
Low-Btu gas
Medium-Btu gas
Natural gas
25
4
3
2
75
6
4
3
125
8
6
4
6-10
-------
TABLE 6-5
TYPICAL MULTIPLE VENTURI BURNER TYPES
FOR LIQUID SRC FIRING
(MANUFACTURER: THE COEN CO..REFERENCE 6-3)
Coen Co.
Model Number
Maximum Heat
Release Rate
(106Btu/hr)
1 MV
2 MV
3 MV
3-1/2 MV
Dual 3 MV or
3-1/2 MV
35
75
150
350
> 350
6-11
-------
The following valves are required at each individual burner: burner
safety shut-off, oil check, supervisory oil cock, steam purge, steam check,
steam manual shut-off, two pilot gas safety shut-offs, and one pilot gas vent
valve.
6.2.4.3 Burner Management System
Converting from coal to gaseous substitute fuels requires the addition
of at least the following safety interlocks: high gas pressure, low gas
pressure, forced draft air, purge air, instrument air, fan starter interlocks,
damper position switches for the forced and induced draft fans (if used), and
steam over-pressure. Converting from coal to liquid SRC requires basically
the same except for low oil pressure and temperature limit switches. Atomizing
steam pressure and flow switches are also required. For multiple burner appli-
cations, such as in utility boilers, header switches are included in addition
to the individual burner fuel interlocks.
6.3 BOILER CONVERSION COST DATA AND EVALUATION
6.3.1 Introduction
The previous subsection presented the basic assumptions on which the
boiler conversion cost estimations were based. The present subsection contains
these cost figures, tabulated on the data sheet first introduced in Section 5
of this report. In order to visualize more clearly the functional relationship
between conversion cost and capacity for a given boiler, these data are plotted
for each original fuel-to-substitute fuel conversion. A discussion of the data
and their concomitant uncertainty factors is given as well.
6.3.2 Boiler Conversion Cost Data
Tables 6-6 through 6-14 are the completed data sheets for all nine pos-
sible conversions: coal-fired equipment modified to burn all five coal-derived
fuels, and the oil-fired equipment modified to burn four out of the five sub-
stitute fuels (excluding solid SRC) . It should be remembered that "liquid SRC"
refers to the melted solid SRC material. The installation costs are based on
1974 San Francisco Bay Area labor rates. The total capital costs, or required
plant investment, indicated on the tables are therefore specific for that
metropolitan area. These numbers must be modified by a location factor if the
installation costs for another site are desired. This point will be discussed
further in subsection 6.3.4. All of these cost figures were reduced from the
bulk cost data included in the Appendix of this report. These figures are
6-12
-------
sums of numbers from individual modification considerations; the last three
digits are not significant.
Associated with each of these tables are the corresponding data plots,
Figures 6-1 through 6-9. Table 6-15 presents the uncertainty factors for the
conversion costs. These confidence limits are indicated on the plots by the
vertical bars on each point. Some error bars, however, are not included since
they would have been of insignificant length when drawn on the log-log graph.
Figure 6-10 is the composite of all the data. Superimposed on these
points are straight lines showing cost as a function of capacity for all boile
types. The overall significance of the conversion cost data is discussed in
the following subsection.
6.3.3 Cost Data Evaluation
Within the scatter of the data plotted in Figures 6-1 to 6-9 there is a
correspondence between conversion cost and capacity for individual boiler types
In addition, a general correspondence between conversion cost and capacity
exists for all boiler types for a given original fuel to substitute fuel convej
sion. The data appear to be described by power law functional relationships.
The following are some additional significant items that require amplification
• For the gaseous substitute fuels, boiler conversion costs increase
in proportion to a decrease in heating value of the fuel (Figures
6-1 through 6-3, 6-6 through 6-8). The greatest cost differential
exists for 750 MW equipment, for which a 45% cost variance exists.
• In some of the plots, the data points for stoker-fired equipment
lie above the correspondence defined by the remaining points
(Figures 6-1 through 6-3). This reflects the additional cost in-
curred as a result of the required internal modifications, a pro-
cedure unique to this type of boiler.
• The data points for oil-fired, firetube boilers (Figures 6-6 through
6-9) indicate a slightly different trend than that defined by the
remaining points. This reflects certain fixed costs, such as pip-
ing common to all types of boilers, which become more noticeable
as the boiler's physical size and capacity decrease.
• For all of the original fuel-to-substitute fuel conversions, the
costs required to modify the utility boilers differ among the vari-
ous types of boilers only slightly. This is at variance with the
notion conceived previous to compiling the data that conversion cost
would be a strong function of utility boiler type. The costs asso-
ciated with the individual conversion considerations for each type
of boiler are contained in the Appendix of this report.
6-13
-------
TABLE 6-6
EQUIPMENT CONVERSION CAPITAL COSTS ($)
0
- Ul
J QJ
ft CX
P
o
u
i
»»
>
j
3
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIREO
WALL-FIRED
TURBO-FIRED
SUBSTITUTE FUEL: [J3 LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: £j COAL Q MEDIUM-BTU GAS (400 BTU/SCF)
n OIL D NATURAL GAS (1000 BTU/SCF)
d LIQUID SRC (16,000 BTU/LB)
[3 SOLID SRC (16,000 BTU/LB)
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY\
RANGE:
\106 BTU/HR/
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000-)-)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs bene
"• - --inuuiliiai bi/e — •
10-15
{ }
16-25
{ 25 }
26250
34780
61030
26-50
{ }
51-100
{ 75 }
22870
18130
41000
26800
58470
95270
101-150
{ 150 }
49085
43970
93055
75435
101430
1 76865
151-250
{ 250 }
599_85 . _
69460
129445
59985
69380
129365
R9985
69380
129365
251-500
{350 }
83040
68270
151310
ath apply)
Utility
size
501-2000
(1000 }
. 204205
241890
446095
206205
241990
448195
206375
241630
448005
206205 .
241990
448195
2001-5000
(3500 }
526655
411350
938005
5000-10000+
{ 7500 }
1Q6835Q
811690
1880040
1073850
798230
1872080
1073850
798030
1871880
1073850
798230
1872080
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Figure
6-1. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-15
-------
TABLE 6-7
EQUIPMENT CONVERSION CAPITAL COSTS ($)
T)
t- (/)
P OJ
/I 0.
3 >>
Oh-*
I/)
(U
a.
>i
&
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Z>
SUBSTITUTE FUEL: F] LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: ffl COAL jg MEDI(JM.BTU GAS (400 BTU/SCF)
C3 OIL Q NATURAL GAS (1000 BTU/SCF)
Q LIQUID SRC {16,000 BT17LB)
Q SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\106 BTU/HR/
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
f
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 10s 6TU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ }
16-25
{ 25 }
23240
34180
57420
26-50
{ }
51-100
{ 75 }
18850
16960
35810
32500
57460
89960
101-150
{ 150 }
44710
42685
87395
69060
100580
169640
151-250
{ 250 }
54660
64280
118940
54760
64830
119590
54760
64830
119590
251-500
{ 350 }
69415
67230
136645
Utility
size J
501-2000
{ 1000 }
163875
213870
377745
163475
214500
377975
163675
214500
378175
163475
214500
377975
2001-5000
{ 3500 >
436660
369010
805670
5000-10000+
{7500 }
858245
610640
1468885
842725
561940
1404665
842725
561940
1404665
842725
561940
1404665
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D Liquid SRC
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Figure 6-2. Combustion Equipment Conversion Capital Costs (Total S)
vs. Boiler Capacity
6-17
-------
TABLE 6-8
EQUIPMENT CONVERSION CAPITAL COSTS ($)
a
w VI
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3 >>
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P
D
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUBSTITUTE FUEL: PI LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: ffl COAL p MEOIUM.BTU Gfts (400 BTU/SCF)
D OIL JJ| NATURAL GAS (1000 BTU/SCF)
O LIQUID SRC (16,000 BTU/LB)
Q SOLID SRC (16,000 BTU/LB)
SUB-
CATEGORY
P - PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\106 BTU/HRy
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ }
16-25
{ 25 }
22045
33860
55905
26-50
{ }
51-100
{ 75 }
15570
16430
32000
30370
57070
87440
101-150
{ 150 }
34025
42175
76200
56875
99430
158105
151-250
{ 250 }
41165
59590
100755
40915
58640
$9555
40915
58640
99555
251-500
{ 350 }
52795
65930
118725
Utility
Size *
501-2000
{ 1000 }
143665
209870
353535
143855
207430
351285
104055
207730
311785
143755
207430
351185
2001-5000
{3500 }
364890
315390
680280
5000-10000+
{ 7500 }
733525
562470
1295995
813285
558030
1371315
813285
558030
1371315
813285
558030
1371315
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-------
TABLE 6-9
EQUIPMENT CONVERSION CAPITAL COSTS ($)
3
- 1/1
l-> 0)
yi 0.
3 >)
OH-
C
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3.
s-
r—
J
ID
SUBSTITUTE FUEL: d LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: QQ COAL Q MEDIUM.BTU 6AS (400 BTU/SCF)
O OIL n NATURAL GAS (1000 BTU/SCF)
00 LIQUID SRC (16,000 BTU/LB)
n SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\^0B BTU/HRy
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs be.ieath apply)
10-15
16-25
{ 25 }
160930
247870
408800
26-50
51-100
{ 75 }
299425
414350
713775
310375
438880
749255
101-150
{ 150 }
386630
599255
985885
407880
636755
1044636
151-250
{ 250 }
499905
881430
1381353
496505
884540
1381045
496505
684540
1381045
251-500
{ 350 }
750120
1473650
2223770
Utility
5i/e *
501-2000
{ 1000}
1668000
3526700
5194700
1722480
3716030
5438510
1716320
3716030
5432350
1668000
3526700
5194700
2001-5000
{ 3500 }
5762020
11131680
16893700
5000-10000+
{ 7500 }
14723020
23691480
38414500
15107200
2406-5480
39172680
15128200
24284380
39412580
14723020
23691480
38414500
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I igure 6-4. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-21
-------
TABLE 6-10
EQUIPMENT CONVERSION CAPITAL COSTS ($)
o
j Q)
fl CL
3 >>
3 h-
-t
ft
01
3.
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SUBSTITUTE FUEL: Q LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: [Jj COAL Q MEDIUM-BTU GAS (400 BTU/SCF)
Q OIL Q NATURAL GAS (1000 BTU/SCF)
D LIQUID SRC (16,000 BTU/LB)
(X] SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
UO6 BTU/HR/
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-2BO)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
16-25
26-50
51-100
{ 75 }
16825
10000
26825
16825
10000
26825
101-150
{ 150 }
28000
15800
43800
28000
15800
43800
151-250
{ 250 }
31000
18800
49800
31000
18800
49800
31000
18800
49800
251-500
{ 350 }
43400
26400
69800
Utility
Size *
501-2000
{ .000 }
86740
56000
142740
86740
56000
142740
86740
56000
142740
86740
56000
142740
2001-5000
{3500 }
186000
114000
300000
5000-10000+
{ 7500 }
345000
215000
560000
345000
215000
560000
345000
215000
560000
345000
215000
560000
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CAPACITY:
TO6 Btu/hr
( MW )
Original Fuel: 0 Coal
Q Oil
Substitute Fuel:D Low Btu Gas
D Medium Btu Gas
j Natural Gas
D Liquid SRC
0 Solid SRC
Figure 6-5. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-23
-------
TABLE 6-11
EQUIPMENT CONVERSION CAPITAL COSTS ($)
BOILER
CATEGORY
FIRETUBb
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUBSTITUTE FUEL: (TI LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: Q COAL g MEDIUM-BTU GAS (400 BTU/SCF)
El OIL Q NATURAL GAS (1000 BTU/SCF)
[H LIQUID SRC (16,000 BTU/LB)
Q SOLID SRC (16,000 BTU/LB)
SUB-
CATEGORY
F = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\106 BTU/HRy
P
(10-50)
P
(10-250)
f
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+,
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ 12 )
11425
7575
19000
16-25
{ 20 )
13175
8275
21450
14000
8300
22300
26-50
{ 35 }
14975
8825
23600
51-100
{ 75 }
17750
16910
34660
16850
16910
33760
101-150
{ 150 )
41035
42330
83365
39035
42330
81365
151-250
(250 }
47120
65765
112885
47120
65765
112885
251-500
{ 350 }
68290
65055
133345
Utility
size *
501-2000
{1000 }
167005
226490
393495
169175
226130
395305
167005
226490
393495
2001-5000
(3500 }
389070
358015
747085
5000-10000+
{7500 }
789570
685945
1475515
789570
685745
1475315
789570
685945
1475515
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— P
W nil"
ISyii
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lb
1C
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.-: :
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11
jy:
iube
-tube (Pack<
-tube (Fieli
;r
3ne
;ntially-Fi
-Fired
J Turbo-Fired
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.
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.:
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iged)
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103
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; . . .
v~ ^;
rj i MJ
; .
•• ' • •
102 K
(10) (1
CAPACITY:
106 Btu/hr
(1) ( MW )
Original Fuel: D Coal
El Oil
Substitute Fuel: El Low Btu Gas
O Medi urn Btu Gas
Q Natural Gas
D Liquid SRC
O Solid SRC
Figure 6-6. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-25
-------
TABLE 6-12
EQUIPMENT CONVERSION CAPITAL COSTS ($)
o
J HI
n CL
3 >>
3 (—
ft
1)
D.
>>
_)
hi
3
SUBSTITUTE FUEL: ("] LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: Q COAL jg MEDIUM.BTU GAS (40Q BTU/SCF)
00 OIL Q NATURAL GAS (1000 BTU/SCF)
D LIQUID SRC (16,000 BTU/LB)
Q SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P * PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
VlO6 BTU/HRy
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
( 100- 10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ 12 }
7425
6475
1390Q
16-25
{ 20 }
8725
6625
15350
9000
6650
15650
26-50
{ 35 }
9875
6725
16000
51-100
{ 75 }
14080
15675
29755
13280
15675
28955
101-150
{ 150 }
37860
41095
78955
35360
41095
76455
151-250
{250 }
41895
61215
103110
41895
61215
103110
251-500
{ 350 }
54265
58950
113215
Utility
Size *
501-2000
(1000 }
124275
199000
323275
124470
199000
323470
124275
199000
323275
2001-5000
{3500 }
293075
315675
608750
5000-10000+
{ 7500 }
555445
449655
1005100
588443
449655
1008098
558445
449655
1008100
u.
UJ
<-> OL
t— H- O
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Ul _l —
= I/I 1—
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LU •-< h-
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Ul •— I—
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LU
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I
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O <£
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I—I LU
=> 00
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LU CD
10
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io6-
105-
104-
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Key:
Firetube
Watertube (Pack
-
i
nn
ttt1~3
— FT!
r!"""'^.-
--•::. SpZp -I IflS
!
E
aged)
Watertube (Field Erected):
Stoker
Cyclone
Tangentially-Fi
Wall-Fired
J Turbo- Fired
1<
(1000)
red
--
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~
(100)
.
10
(10
.
'I
_• - -
- -
y
2 K
) (1
CAPACITY:
10 106 Btu/ht
(1) ( MW )
Original Fuel: O Coal
HI Oil
Substitute Fuel:Q Low Btu Gas
(3 Kedi urn Btu Gas
3 Natural Gas
Q Liquid SRC
D Solid SRC
Figure 6-7. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-27
-------
TABLE 6-13
EQUIPMENT CONVERSION CAPITAL COSTS ($)
T3
- a\
P 01
t/i CL
3 >>
3h?
-t
t/>
cu
CL
>>
£
P
ID
SUBSTITUTE FUEL: Q LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: Q ™AL D MEDIUM.BTU GAS (400 BTU/SCF)
1X1 OIL (3 NATURAL GAS (1000 BTU/SCF)
O LIQUID SRC (16,1100 BTU/LB)
[] SOLID SRC (16,000 BTU/LB)
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\106 BTU/HR/
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 106 BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ 12 }
6075
6350
12425
16-25
{ 20 }
7125
6450
13575
8000
6500
14500
26-50
{ 35 }
8525
6575
15100
51-100
{ 75 }
10320
15150
25470
9720
15150
24870
101-150
{ 150 }
24775
40370
65145
23175
40370
63545
151-250
{ 250 }
28050
55025
83075
28050
55025
83075
251-500
{ 350 }
37445
57290
94735
Utility
Size *
501-2000
{ 1000}
104655
191930
296585
104855
192230
297085
10465
191930
296585
2001-5000
{ 3500}
227305
262055
489360
5000-10000+
{ 7500 }
529000
445745
974745
529005
445745
974750
529000
445745
974745
U-
TS.
UJ
>
zo
o
•—4 Q£
t— 1— O
Z< U-
UJ _l^-'
^^_,
t-< 1— c£
z? *s> t—
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UJ >-. 1-
II II II
UJM I—
1^
in
o
CJ
z
o
t/>
0£
UJ
>
z
o
o
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
-------
o
• CD
in et
O =C
O LU
>— •=£
Q- CO
<-> O
Z to
o — •
in z
o: «s
LU cz:
LU O
JC
o. o
I—I LiJ
3 UO
O- «:
LU 03
Symbol Key:
I Q Firetube
Watertube (Packaged]
[\ Watertube (Field Erected)
Stoker
Cyclone
/\ Tangentially-Fired
I VWa11-F1red
I Turbo-Fired
10°
10
(1000)
Original Fuel : D Coal
[3 Oil
Substitute Fuel: D Low Btu Gas
D Medi urn Btu Gas
CO Natural Gas
D Liquid SRC
D Solid SRC
Figure 6-8. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-29
CAPACITY:
106 Btu/hr
( MW )
-------
TABLE 6-W
EQUIPMENT CONVERSION CAPITAL COSTS ($)
0
- irt
J 0)
n CL
|£
-«
n
u
n_
>>
5
_>
D
BOILER
CATEGORY
FIRETUBE
WATERTUBE
STOKER
CYCLONE
TANGENTIALLY-
FIRED
WALL-FIRED
TURBO-FIRED
SUBSTITUTE FUEL: ["] LOW-BTU GAS (170 BTU/SCF)
ORIGINAL FUEL: Q COAL g HEDIUH-BTU GAS (400 BTU/SCF)
CD OIL Q NATURAL GAS (1000 BTU/SCF)
DO LIQUID SRC (16,000 BTU/LB)
Q SOLID SRC (16,000 BTU/LB)
SUB-
CATEGORY
P = PACKAGED
E = FIELD-
ERECTED
/CAPACITY \
RANGE:
\J06 BTU/HRy
P
(10-50)
P
(10-250)
F
(50-500)
P or F
(10-250)
F
(100-10000+)
F
(100-10000+)
F
(500-10000+)
F
(100-10000+)
BOILER CAPACITY, 10s BTU/HR
(Note: { } denotes capacity for which costs beneath apply)
10-15
{ 12 }
123000
175000
298000
16-25
{ 20 }
1 34000
212000
346000
140000
220000
360000
26-50
{ 35 }
145000
231000
376000
51-100
{ 75 }
298075
412440
710515
296075
412940
70901 5
101-150
{ 150 }
383655
597195
980850
379655
597195
976850
151-250
(250 }
484905
880500
1 365405
484905
880500
1365405
251-500
{350 }
735620
1489270
2204890
Utility
Size *
501-2000
{1000 }
1679730
3694020
5373750
1680230
3700720
5380950
1679730
3694020
5373750
2001-5000
{3500 }
5627520
11074680
16702200
5000-10000+
{7500 }
14981950
25500250
40482200
14849950
24175995
39025945
14981950
25500250
40482200
u_
z
UJ
=>
Z CD
O
I— i DC
I— 1— O
z< u.
LU _J
£<^
E = EQUI
CONVERSION COST: I = INST
T = TOT/i
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
E
I
T
-------
107-
LU
i— ce
o
o
• CD
GO ec
0 -
Q_ CD
0 O
Z 00
GO 2T
en to
O- «£
LU CO
104-
103-
10
(IOC
- — -- ----- - - -- — *--- i
PI
v.~
-
• j:
3 __.
-.3B7 Lt^-::":
,-1^*' - q
i : .- — ~ '. - :
--
- - : - :
' KM : :
' ' '
^fit
l*s
,. . | :-..'-
i;:!":-: :
p
1 j r'j
• •• :;l:
;3S 2E
-
t' :
:•
..:.. . I
r - , . .
: fe+j!
E
.-;•= • • - i
s&L
»;
!." '
; ; • ; i :
i : 1 ! i - j ':' 1 ! i . • •
i ! I I 1
- Symbol Key:
0
VI
\J
L\
|o
-
Firetube
watertube (Packaged)
Watertube (Field Erected):
Stoker
Cyclone
Tanaentiallv-Firpd
M V7
V
n
Wall -Fired
.
Turbo- Fired
: : ESS
103
0) (100)
i
^
.
^N
Bffi^fflj^
pp« u
-1 i i
i !-| t- i . i I" 0
~S3M
-. -:-,- -
i
i i ; ; ; ;- '
rfcr±±±±±±j
. .
:
t-
•
-
-i:^il. :
j :
102 K
(10) (1
CAPACITY:
10 TO6 Btu/hr
I) ( MW )
Ori ginal Fuel: D Coal
13 Oil
Substitute Fuel: D Low Btu Gas
D Medium Btu Gas
3 Natural Gas
GQ Liquid SRC
D Solid SRC
Figure 6-9. Combustion Equipment Conversion Capital Costs (Total $)
vs. Boiler Capacity
6-31
-------
TABLE 6-15
CONVERSION COST UNCERTAINTY FACTORS
Original Fuel
Substitute Fuel
Boiler Category
Uncertainty
Basis
Coal
Coal and Oil
Coal and Oil
Coal
Oil
Oil
Low-, medium-Btu gas
and natural gas
Low-, medium-Btu gas
and natural gas
Liquid SRC
Solid SRC
Low-, medium-Btu gas
and natural gas
Low-, medium-Btu gas
and natural gas
Stoker and watertube
(F)
Cyclone, tangentially-
fired, wall-fired, and
turbo-fired
±15%
+50%
-10%
All boilers
All boilers
±10%
±25%
Firetube
Watertube (P)
±10%
±15%
Uncertainty in required number of
burners for the furnace and length
of fuel piping
Upper limit due to uncertainty in
required number of burners for fur-
nace and length of fuel piping;
lower limit based mostly on possible
decrease in required piping lengths
(also, probability is low that the
original number of burners will be
reduced upon conversion to a
different fuel)
The uncertainty in the cost of the
fuel handling system dominates all
other factors
Due to uncertainty in: amount of
required cooling water, ductwork
required to bypass preheater, pip-
ing to bring water from source to
boiler front, cost of materials
for stainless steel nozzle, plus
general lack of knowledge of solid
SRC's handling and combustion
properties
Uncertainty in piping installation
costs
Uncertainty in required number of
burners for the furnace and length
of fuel piping
-------
*f^ in
LU
_J I—
•=£ CC
O
CQ
oo
o <:
O. CC
o
00 Z
ce <:
LU or
LU O
X
CL O
o-
-------
• The differences in conversion costs for the field-erected and
packaged watertube boilers are slight. An incrementally higher
engineering cost for the latter type accounts for this differ-
ence.
Figure 6-10 is the composite of all cost data previously shown in Figures
6-1 through 6-9. Three lines, again appearing to conform to power law func-
tional relationships, have been fared in to illustrate the correspondence between
cost and capacity for all boiler types for the three major fuel switching stra-
tegies. These are:
• Conversion to Liquid SRC
Enabling all coal- or oil-fired boiler types to use liquid SRC
is clearly the most expensive fuel substitution option. This
cost is dominated by the elaborate fuel handling system that is
required.
• Conversion to solid SRC
This appears to be the least expensive strategy for abating SO
emissions by way of fuel switching. It does, of course, apply
only to boilers that were originally burning coal. The low cost
reflects the savings realized through the reuse of existing fuel
handling and firing equipment.
• Conversion to the Coal-Derived Gases and Natural Gas
These costs fall between those for liquid and solid SRC. The
option for conversion to gas is open for all boiler types firing
either original fuel. Due to the data scatter, the straight
line in Figure 6-10 representing the costs for this operation is
only one of many that could have been drawn in. It serves, how-
ever, to identify the overall trend. A more accurate placement
of the line can be obtained by performing a regression analysis.
6.3.4 Use of Cost Data for Other Locations
As was mentioned previously, the installation costs associated with each
type of conversion were based on San Francisco Bay Area labor rates. Therefore,
the total plant investment as shown on the data sheets is specific for that
metropolitan area. To determine installation costs for other areas, it will be
necessary to modify the Bay Area figures by some labor rate factor.
M. W. Kellogg Co. presented location factors for the major U.S. cities
in Reference 6-4. These are repeated in Table 6-16. Adjacent to each of these
numbers is a corresponding factor as normalized to the Bay Area figure (1.45).
With these factors, the installation cost estimates contained in this report can
be used to calculate total equipment conversion capital costs for other major
cities.
6-34
-------
TABLE 6-16
LOCATION FACTORS FOR MAJOR U.S. CITIES
Location
Atlanta
Baltimore
Birmingham
Boston
Chicago
Cincinnati
Cleveland
Dallas
Denver
Detroit
Kansas City
Los Angeles
Minneapolis
New Orleans
New York
Philadelphia
Pittsburgh
St. Louis
San Francisco
Seattle
Houston
M. W. Kellogg
Location Factor
(Reference 6-4)
1.10
1.41
1.16
1.23
1.52
1.53
1.86
1.07
1.03
1.73
1.37
1.44
1.54
1.16
2.08
1.82
1.52
2.01
1.45
1.21
1.00
Location Factor
Normalized to
San Francisco
0.76
0.97
0.80
0.85
1.05
1.06
1.28
0.74
0.71
1.19
0.95
0.99
1.06
0.80
1.43
1.25
1.05
1.39
1.00
0.83
0.69
6-35
-------
6.3.5 Proposed Cost Models
Interpolation and regression will allow the formulation of the functional
relationships suggested by the correspondences between cost and capacity for
each type of fuel-to-fuel conversion for each boiler category, as shown in
Figures 6-1 through 6-9. Therefore, the most specific cost models would take
the following forms:
{Equipment Cost = (K ) (Capacity) e
6 n-
Installation Cost = (F)(K.) (Capacity) x
Equipment Cost = (K ) (Capacity) °e (HHV)Pe
e n «•
Installation Cost = (F) (1) (Capacity)"1 (HHV)Fl
where
HHV = high heating value for substitute fuel gas (Btu/scf)
F = location factor
and n's, p's and K's are calculated by the regression
analysis.
Due to the lack of more than three data points for each boiler type, and
the overall scatter of the data, the creation of these elaborate cost models may
not be justified. More simplistic cost models can be obtained from the compo-
site of all the data, illustrated previously in Figure 6-10. Thus, the general
form of these functions would be the same for the three principal fuel substi-
tution options for all boiler types:
Equipment Cost = (K )(Capacity)e
Installation Cost = (F)(1^)(Capacity)"1
The total plant investment is the sum of the equipment and installation costs,
6-36
-------
SECTION 7
CONCLUSIONS AND RECOMMENDATIONS
The following are this study's major conclusions:
• On the basis of the estimated equipment modification cost data,
there appear to be three basic fuel switching options for the
abatement of oxides of sulfur emissions from industrial and
utility boilers. These include conversions to melted solvent
refined coal, solid solvent refined coal, and the gaseous fuels
of any heating value.
• Based on the engineering assumptions made during the cost esti-
mation procedure, conversions to hot liquid SRC seem to be the
most expensive of the investigated alternatives. The fuel hand-
ling system cost is the major portion of the total plant invest-
ment. This strategy is open to applicable boiler types firing
either oil or coal.
• Converting coal-fired boilers to the use of solid SRC is the
least expensive alternative. Considerable cost savings result
from the reuse of the existing fuel handling and firing sytems.
Modifying oil-fired boilers to enable the use of solid SRC is
considered impractical. The costs of such an operation would
exceed the costs for converting to liquid SRC.
• Between the costs for converting to SRC in either phase lie
those for converting to the gaseous fuels. These costs are
generally inversely proportional to the heating value of the
substituted gas. This fuel switching option is available for
all boiler types firing either oil or coal originally. The
sulfur oxide reduction benefit is greater for the gaseous fuels
since, unlike SRC, they contain no sulfur.
• There appears to be a correspondence between conversion cost and
capacity for the three basic fuel switching options; a power law
functional relationship probably best describes this correspon-
dence .
7-1
-------
The following are the principal recommendations made in light of the
results of this study:
• A regression analysis should be performed for each of the corres-
pondences between conversion cost and boiler capacity for each
of the three major fuel substitution options. This procedure
will result in the formulation of generalized equipment conver-
sion cost models.
• The results of the ongoing experimental and practical activities
in handling and burning solvent refined coal and the lower-Btu
gases should be used to periodically update the cost estimations
contained in this report.
• The cost estimation methodology used in this study should be em-
ployed to evaluate the costs of converting boilers to other coal-
derived fuels, especially the products from the more promising
coal liquefaction processes.
7-2
-------
REFERENCES
Section 1
1-1 National Air Pollution Control Administration, "Control Techniques for
Sulfur Oxide Emission from Stationary Sources," AP-52, 1969.
1-2 M. W. Kellogg, Inc., "General Cost Model," draft report, prepared for
the U.S. Environmental Protection Agency, 1974.
1-3 Office of Coal Research, R&D Report No. 81, "Advanced Coal Gasification
System for Electric Power Generation," prepared by Westinghouse for OCR,
June 1973.
1-4 Office of Coal Research, R&D Report No. 66, "Production of Electricity
Air Coal and Coal-Char Gasification," prepared by West Virginia University
for OCR, June 1973.
1-5 Office of Coal Research, R&D Report No. 79, "Low Btu Gasification; High
Temperature - Low Temperature H2S removal Comparison Effect on Overall
Thermal Efficiency in a Combined Cycle Power Plant," prepared by Gilbert
Associates, Inc., for OCR, September, 1973.
Section 2
2-1 Henry, I. W., H. E. Burbach, "What About Boilers for Low Btu Gas?"
Electric Light and Power, May 1974.
2-2 Frendburg, A., "Performance Characteristics of Existing Utility Boilers
When Fired with Low Btu Gas," EPRI Conference Proceedings, Power Genera-
tion - Clean Fuels Today, April 1974.
2-3 Agosta, J., et al., "Status of Low Btu Gas as a Strategy for Power Station
Emission Control," Presented at the 65th Annual Meeting of the American
Institute of Chemical Engineering, November, 1972.
2-4 Telephone interview of Mr. R. M. Lundberg, Commonwealth Edison Company,
Chicago, Illinois, June 15, 1974.
2-5 Jimeson, R. M., "Utilizing Solvent Refined Coal in Power Plants," Chemical
Engineering Progress, 62, 10, p. 53, October, 1966.
2-6 Jimeson, R. M., R. R. Maddocks, "Refined Coal: An Energy Source of the
Future," Presented at the ACS Symposium - Fuels of the Future, April, 1973.
2-7 Jimeson, R. M., J. M. Grout, "Solvent Refined Coal: Its Merits and Market
Potential," Society of Mining Engineers, Transactions, Vol. 250, September,
1971.
2-8 Telephone interview of Dr. R. M. Jimeson, Federal Power Commission,
Washington, D.C., July 15, 1974.
R-l
-------
2-9 Telephone interview of Mr. James Grant, Toledo Edison, Toledo, Ohio,
July 17, 1974.
2-10 Telephone interview of Mr. H. Williams, Old Ben Coal Company, Chicago,
Illinois, July 17, 1974.
2-11 Telephone interview of Mr. K. Kunchal, Standard Oil of Ohio, Cleveland,
Ohio, July 19, 1974.
2-12 Harrison, W. B., "Solvent Refined Coal for Power Generation," presented
at the 9th Intersociety Energy Conversion Engineering Conference,
August, 1974.
Section 3
3-1 Cavender, J. H., et al., "Nationwide Air Pollutant Emission Trends,
1940-1970," EPA, AP-115, January, 1973.
3-2 Thompson, 0. F., et al., "Survey of Domestic, Commercial and Industrial
Heating Equipment and Fuel Usage," prepared by Catalytic, Inc., for EPA,
Contract No. 68-02-0241, August, 1972.
3-3 Cleaver Brooks Co,, "Progress and Monitor Steam Generators," product
brochure, 1972.
3-4 Erie City, Energy Division, "Steam Generating Systems," product brochure,
1973.
3-5 Combustion Engineering Co., "C. E. Shop Assembled VP Boilers," product
brochure No. SP-1046A, circa 1970.
3-6 Combustion Engineering Co., "C. E. Modular Design VU-60 Boilers," product
brochure No. SP 1053, circa 1970.
3-7 Babcock and Wilcox Company, "Steam - Its Generation and Use," 1972.
3-8 Fryling, Glenn R., Editor, "Combustion Engineering," Combustion Engineer-
ing, Inc., New York, New York, 1967.
R-2
-------
Section 4
4-1 Perry, H., "Coal Conversion Techology," Chemical Engineering, July 22,
1974.
4-2 Siegel, H. M., T. Kalina, "Technology and Cost of Coal Gasification,"
Mechanical Engineering, May, 1973.
4-3 Office of Coal Research, "Coal Technology: Key to Clean Energy," OCR
Annual Report, 1973-1974.
4-4 Hottel, H. C., J. B. Howard, "New Energy Technology," Massachusetts
Institute of Technology Press, 1971.
4-5 Hammond, A. L., et al., "Energy and the Future," American Association
for the Advancement of Science, 1973.
4-6 Farnsworth, F. J., "The Production of Gas from Coal through a Commer-
cially Proven Process," Koppers Company, Inc., Pittsburgh, Pennsylvania,
August, 1973.
4-7 Mills, G. A., "Gas from Coal, Fuel of the Future," Environmental Science
and Technology, December, 1971.
4-8 Forney, A. J., W. P. Haynes, R. C. Corey, "Present Status of the
Synthane Coal-to Gas Process," Paper 3586, AIME Meeting, New Orleans,
Louisiana, October, 1971.
4-9 Forney, A. J., W. P. Haynes, "Clean Fluid Fuels from Coal and Wastes,"
ASME, Journal of Engineering for Power, 95, 3, July, 1973.
4-10 Robson, F. L., A. J. Giramonti, "An Advanced-Cycle Power System Burning
Gasified and Desulfurized Coal," Seminar on the Desulfurization of Fuels
and Combustion Gases, Geneva, Switzerland, November, 1968.
4-11 Feldman, H. F., et al., "Supplemental Pipeline Gas from Coal by the
Hydrane Process," 71st National Meeting, AIChE, Dallas, Texas, February,
1972.
4-12 Conn, A. L., "Low-Btu Gas for Power Plants," Chemical Engineering Pro-
gress, 69, 12, December 1973.
4-13 Robson, F. L., et al., "Technological and Economic Feasibility of
Advanced Power Cycles and Methods of Producing Non-Polluting Fuels for
Utility Power Stations," NTIS PB 198392, December, 1970.
4-14 American Gas Association, "A Survey of R&D Projects Directed Toward the
Conversion of Coal to Gaseous and Liquid Fuels," November, 1972.
R-3
-------
4-15 Gary, J. H., "Liquid Fuels and Chemicals from Coal," Colorado School of
Mine, Mineral Industries Bulletin, 12, 5, September, 1969.
4-16 Jimeson, R. M., "Utilizing Solvent Refined Coal in Power Plants,"
Chemical Engineering Progress, 62, 10, p. 53, October, 1966.
4-17 Jimeson, R. M., R. R. Maddocks, "Refined Coal: An Energy Source of the
Future," presented at the ACS Simiposium - Fuels of the Future, April,
1973.
4-18 McCann, et al. , "Report on Combustion Trials on Spencer Low-Ash Coal,"
U.S. Department of the Interior, Bureau of Mines, Pittsburgh, Pennsyl-
vania, January, 1965.
4-19 Frey, D. J., "De-Ashed Coal Combustion Study," Combustion Engineering,
Inc., October 1964.
4-20 Sage, W. L. , "Combustion Tests on a Specially Processed Low-Ash Low-
Sulfur Coal," Babcok and Wilcox Co., July, 1964.
4-21 Chopey, N. P., "Gas from Coal: An Update," Chemical Engineering, March
4, 1974.
Section 5
(No References)
Section 6
6-1 National Fire Prevention Association, Bulletin 85D.
6-2 Monsanto Company, "Technical Bulletin T-77," St. Louis, Mo., circa
1970.
6-3 The Coen Company, Burlingame, California, "Gas and Oil Burning Equip-
ment," Product-line Brochure, circa 1970.
6-4 M. W. Kellogg, Inc., "General Cost Model," draft report, prepared for
the U.S. Environmental Protection Agency, 1974.
Section 7
(No References)
R-4
-------
ADDITIONAL BIBLIOGRAPHY
American Gas Association, "Synthetic Fuel Research: A Bibliography," AGA
Catalog No. HO 1974, August 1973.
Benson, R. E., "Costs of Air Cleaning with Electrostatic Precipitators at TVA
Steam Plants," Journal of the Air Pollution Control Association, Vol. 24, No.
4, April 1974.
Bernstein, R. H., et al., "Cost Effectiveness Measurements of Emission Control
Equipment for Intermediate-Size Boilers," presented at the 66th Annual Meeting
of the APCA, June 1972.
Brashears, D. F., "Industrial Boiler Design for Nitric Oxide Emissions Control,"
prepared by B&W, presented at the Western Gas Processors and Oil Refiners As-
sociation Meeting, March 1973.
Colorado School of Mines, "Synthetic Liquid Fuels from Oil Shale, Tar Sands,
and Coal," Vol. 65, No. 4, October 1970.
Crouch, W. B., et al., "Partial Combustion of High-Sulfur Fuels for Electric
Power Generation," EPRI Conference Proceedings, Power Generation-Clean Fuels
Today, April 1974.
Ehrenfeld, J. R., et al., "Systematic Study of Air Pollution from Intermediate-
Size Fossil Fuel Combustion Equipment," prepared by Walden Research Corporation
for EPA, Contract No. CPA 22-69-85, July 1971.
Ertel, C. W., J. T. Metcalf, "New Fuels, Old Coal," Mechanical Engineering,
Vol. 94, No. 3, March 1972.
Executive Office of the President, Office of Emergency Preparedness, "The
Potential for Energy Conservation-Substitution for Scarce Fuels," A Staff
Study, January 1973.
Federal Power Commission, "The Potential for Conversion of Oil-Fired and Gas-
Fired Electric Generating Units to Use of Coal," September 1973.
Fraser, M. D., G. J. Foley, "Cost Models for Fabric Filter Systems," APCA
67th Annual Meeting, June 1974.
Harris, D. A., "Effect of Various Fuels on Furnace Design," prepared by Combus-
tion Engineering, Inc., presented at REA Generating Conference, June 1972.
Harrison, J. S., "Coal as a Raw Material for the Future," Energy World, March
1974.
Hittman Associates, "Assessment of SO2 Control Alternatives and Implementation
Patterns for the Electric Utility Industry," NTIS PB-224 119, March 1973.
R-5
-------
ADDITIONAL BIBLIOGRAPHY (Continued)
Jenkins, R. E., "Air Pollution Control System Investment and Operating Cost
Analysis: Fabric Filters and Venturi Scrubbers for Asphalt Batching Plants
and Electric Arc Furnace," presented to AIChE 77th National Meeting, June 1974.
Jimeson, R. M. , Shaver, R. G., "Credits Applicable to Solvent Refined Coal for
Pollution Control Evaluations," Paper 25C, presented at the Symposium on Syn-
thetic Hydrocarbon Fuels from Western Coals, Third Joint Meeting of the AIChE,
August 1970.
Jimeson, R. M. , L. W. Richardson, "Census of Oil Desulfurization to Achieve
Environmental Goals," Paper No. 19-C, presented at the AIChE 4th Joint Meeting
with the Canadian Society of Chemical Engineers, September 1973.
Jimeson, R. M., L. W. Richardson, "Potential Abatement Sulfur Resulting
from Environmental Regulations," presented at the 4th Phosphate-Sulfur Symposi-
um, January 1974.
Jimeson, R. M., L. W. Richardson, "Fossil Fuels and Their Environmental
Impact," presented at the Symposium on Energy and Environmental Quality, Mid-
western Universities Consortium for Environmental Education and Research,
May 1974.
National Petroleum Council, "U.S. Energy Outlook - Coal Availability," A Report
by the Coal Task Group of the Other Energy Resources Subcommittee of the NPC's
Committee on U.S. Energy Outlook, 1973.
National Petroleum Council, "Energy Conservation in the United States: Short
Term Potential 1974-1978," March 1974.
National Petroleum Council, "Emergency Fuel Convertibility," July 1965.
National Public Hearings on Power Plant Compliance with Sulfur Oxide Air
Pollution Regulations, conducted by EPA, October 1973 - November 1973, January
1974.
North American Manufacturing Co., "Atlas Generator," Bulletin 90.00, 1970.
O'Connor, J. R., J. R. Citarella, "An Air Pollution Control Cost Study of
the Steam Electric Power Generation Industry," Journal of the Air Pollution
Control Association, Vol. 20, No. 5, May 1970.
Office of Coal Research, R&D Report No. 22, Interim Report No. 7, "Estimation
of Coal and Gas Properties for Gasification Design Calculations," prepared for
OCR by Institute of Gas Technology, January 1971.
Office of Coal Research, R&D Report No. 53, Interim Report No. 5, "Development
of a Process for Producing an Ashless, Low Sulfur Fuel from Coal; Volume 1,
Part 4 - Impact of the Solvent Refined Coal Process," prepared by Carnegie
Mellon University for OCR, November 1973.
Office of Coal Research, R&D Report No. 66, interim Report No. 1, Vols. 1 and
2, "Optimization of Coal Gasification Processes," prepared by West Virginia
University for OCR, April 1972.
Office of Coal Research, R&D Report No. 66, Interim Report No. 2, "Optimization
of Coal Gasification Processes," prepared by West Virginia University for OCR,
April 1973.
R-6
-------
ADDITIONAL BIBLIOGRAPHY (Concluded)
Office of Coal Research, R&D Report No. 72, "Economic Evaluation of COED
Process Plus Char Gasification," prepared by American Oil Company for OCR,
April 1972.
Office of Coal Research, R&D Report No. 82, Interim Report No. 1, "Demonstra-
tion Plant, Clean Boiler Fuels from Coal - Preliminary Design/Capital Cost
Estimate," prepared by the Ralph M. Parsons Company for OCR, June 1973.
Office of Coal Research, R&D Report No. 84, "Clean Power Generation from Coal,"
prepared by Westinghouse R&D Center, January 1973.
Perry, Harry, "The Gasification of Coal," Scientific American, Vol. 230, No. 3,
March 1974.
Radian Corporation, "Factors Affecting Ability to Retrofit Flue Gas Desulfuri-
zation Systems," NTIS PB-232 376/4WP, December 1973.
Riley Stoker Corporation, "Riley-Union Packaged Steam Generators," product
brochure, 1973.
Robson, F. L. and Giramonti, A. L., "The Use of Combined-Cycle Power Systems
in Nonpolluting Central Stations," Journal of the Air Pollution Control Asso-
ciation, Vol. 22, No. 3, March 1972.
Shaver, R. G., "A Solvent-Refined Coal Process for Clean Utility Fuel," Ad-
vance in Chemistry Series No. 127, AIChE, 1973.
Zawadski, E. A., "Availability of Coal Gasification and Coal Liquefaction for
Providing Clean Fuels," prepared for EPA by PEDCo, Inc., EPA-450/3-74-025,
March 1974.
R-7
-------
APPENDIX A
PROCESSES FOR LOW AND INTERMEDIATE BTU FUEL GAS
(From Reference 4-21 except where noted)
A-l
-------
PROCESSES FOR LOW AND INTERMEDIATE BTU FUEL GAS
Developed or Offered by
(and Process Name if any)
Applied Technology Corp.
Applied Technology Corp.
(Patgas)
Babcock & Wilcox Co.
Bituminous Coal Research, Inc.
Process Comments
Status and Remarks
to
Columbia University
Combustion Engineering, Inc.
Davy Powergas, Inc.
(Winkler)
Coal is continuously gasified by
air (without steam) in a molten-
iron bath. Reaction with limestone
takes out sulfur.
Similar to company's Atgas process
(see Appendix B) but without shift
conversion or methanation.
Coal is entrained in air for
feeding to gasifier, which uses no
steam. Char is recycled.
Gasification in multiple fluidized
beds yields a gas stream free of
liquids. Btu content of gas de-
pends on whether air or oxygen is
fed.
Coal's carbon reacts with steam in
electric arc at about 10,000°C.
Depending on reaction and subse-
quent quench conditions, process
can be used to make low- or high-
Btu gas.
Pulverized coal is entrained in air
and steam for feeding to gasifier.
Fluidized-bed gasification accommo-
dates wide range of particle sizes.
Some installations use oxygen in-
stead of air, to obtain higher-Btu
gas.
Tested in pre-pilot reactor
equivalent to 10 bl/min of
coal. Aiming for funding
for bigger unit.
Gas intended for, e.g., iron
and steel industry
Tested in experimental unit.
Construction of 100-lb/h
unit to begin at Monroeville,
PA, this year.
As of May 1973, had been
tested on batch basis ac
about 30 kw. Sponsored by
Consolidated Natural Gas Co.
Preliminary tests completed;
await funding for 5-ton/h
unit.
Developed in Germany; widely
commercial in Europe and
Asia; no contracts in U.S.
yet.
-------
Developed or Offered by
(and Process Name if any)
Garrett Research & Develop-
ment Co. (GRD Coal Gasifi-
cation Process)
General Electric Co. (Gegas)
Process Comments
Status and Remarks
CJ
Hydrocarbon Research, Inc.
Institute of Gas Technology
(U-Gas)
M. W. Kellogg Co.
Koppers Co. (Koppers-Totzek)
Gasifier output of pipline-gas pro-
cess described in Appendix B is
also offered (after cleanup) for
industrial fuel, at about 600°F
650 Btu/ft3F).
Employs a moving fixed bed of coal
and ash in gasifier. Under study
are: feeding of coal fines by
mixing with tar and then extruding;
use of solid diluents to increase
mass-flow through gasifier; use of
liquid membrane for H_S removal.
Conical fludized-bed gasifier.
High superficial velocity permits
bed to operate at above ash soften-
ing point (e.g., 2200°F to 2300°F).
Mild air-oxidation pretreats coal
to avoid caking and produces a por-
tion of the gas product. Fluidized-
bed gasifier includes conical
internals; ash is agglomerated with-
in the cones.
Gasification step similar to that in
firm's pipeline-gas process (see
Appendix B); but it employs air in-
stead of oxygen, and no steam.
Oxygen employed instead of air.
Gasification occurs at very high
temperatures around 3000°F, yielding
an effluent free of tars and similar
condensables. Raw gas is about
300 Btu/ft3.
See Appendix B.
Tested at 50-lb/h rate.
Seeking partners for erect-
ing a demonstration unit at
a utility plant.
Concept developed by Arthur
Squires, of City University
of New York. HRI proposes
a 10-ton/d unit.
Design study underway for
pilot plant (10 to 35
tons/h).
Investigating formation of
concortium for demonstra-
tion project at a utility
plant.
Sixteen commercial plants
in Europe and Afica, making
ammonia-synthesis gas. U.S.
inquiries also involve fuel
gas and pipeline gas.
-------
Developed of Offered by
(and Process Name if any)
Lurgi Gesellschaft fiir War-
meund Chemotechnik mbH.
Process Comments
Status and Remarks
North American Rockwell,
Corp.
Riley Co.
U.S. Bureau of Mines
Wellman-Galusha
(Reference 4-12)
Westinghous Electric, Corp.
Westinghouse Electric Corp.
Woodall-Duckham Ltd. (IGI
Two-stage Coal-Gasification
Process)
Gasifier at about 300 psi receives
coal through a lock hopper. Re-
volving grate at bottom removes ash
and allows air and steam to enter.
Oxygen replaces air to manufacture
town gas (or a precursor for pipe-
line gas; see Appendix B).
Coal is contacted with air (but no
steam) in molten Na_CO.,, at about
1800°F and 5 to 10 atmf Sulfur and
ash removed externally, from a re-
circulating bleed stream of the
salt.
Low-pressure gasification; fixed
bed of coal. Btu content of gas
depends on whether air or oxygen is
fed.
Gasification reactor's stirrer
moves horizontally and vertically,
providing uniform gasification con-
ditions with caking or noncaking of
any size.
Atmospheric, fixed-bed process;
similar to Lurgi
Gasifier has fluidized bed of recir-
culated char. Insensitive to coal's
size distribution, caking properties
and sulfur content.
Gasifier at around 1850°F produces
gas to energize solid-electrolyte
fuel cells immersed in gasifier bed
itself. Water vapor and carbon di-
oxide from fuel cell react with coal
during gasification.
Gasifier, operating a 1 atm, is di-
vided into compartments by vertical
walls, to aid distribution of rising
gas through descending bed of coal.
Process has been widely used
outside U.S. to make town
gas, synthesis gas and fuel
gas.
Has been tested (at 1 atm)
in 200-lb/h unit. A 5-ton/h
pilot plant with Northeast
Utilities Service Co. is
planned for Norwalk, Conn.
Fuel-gas manufacturers are
offered an updated version
of Morgan Construction Co.
gasifiers.
Successfully tested at
Morgantown, W. VA, in 12-
ton/d unit having a 3-ft-dia
reactor.
Unknown
A 1200-lb/h pilot plant due
onstream at Waltz Mill, PA
Commercial unit to be built
at a Terre Haute, Ind.,
utility plant by 1978.
Concept studied between 1962
and 1970 and found to be at-
tractive; but no active pro-
ject underway now.
Developed by Italy's II Gas
Integrale in 1940's. Being
offered anew by Woodall-
Duckham.
-------
APPENDIX B
PROCESSES FOR HIGH BTU PIPELINE GAS (SNG)
(From Reference 4-21)
B-l
-------
PROCESSES FOR HIGH BTU PIPELINE GAS (SNG)
Processes Developed With Their Own Technology for Methanation
Developed or Offered by
(and Process Name if any)
Bituminous Coal Research, Inc.
(Bi-Gas)
Columbia University
Institue of Gas Technology
(Hygas)
Lurgi Gesellschaft fur Warme-
und Chemotechnik mbH. (Lurgi
Pressure Gasification)
Process Comments
Gasifier, at 1000 to 1500 psi, has
two stages. Char is gasified with
oxygen and steam in lower stage;
the gas rises, picking up and en-
training incoming coal; this
stream goes to upper stage, which
makes char and enriches the gas.
Methanator has fluidized catalyst
bed, with imbedded heat-transfer
surfaces.
Coal's carbon reacts with steam in
electric arc at about 10,000°C.
Proper reaction and quench condi-
tions enable production of SNG
without additional methanation
step.
After pretreatment by air oxida-
tion or by dilution with char, coal
is oil-slurried and fed to top of
1000 - 1500 psi two-stage hydro-
gasifier, while mixture of steam
and hydrogen (generated externally,
from leaving hydrogasification)
enters at the bottom. Heat in
gasifier is supplied by carbon-
hydrogen reaction. Methanator
downstream uses multiple packed-
catalyst-bed reactors.
In pipeline-gas projects, gasifier
with lock hopper and grate (see
Appendix A) employs oxygen for
gasification, producing a raw gas
of about 400 Btu/ft=
A hetero-
Status and Remarks
geneous nickel catalyst is used in
the downstream methanation step.
Gasification tested in
100-lb/h continuous unit;
methanation likewise sucess-
fully tested. A 5-ton/h
pilot plant for overall pro-
cess being built at Homer
City, PA.
As of May 1973, had been
tested on batch basis at
about 30 kw.
Three-ton/h pilot plant corn-
pleated at Chicago in 1971 has
operated on lignite, with hy-
drogen produced from char
electrothermally. Now, IGT
will run caking bituminous
coal, and produce hydrogen
via oxygen-combustion as
source of heat.
Gasification well established
(see Appendix A). Methanation
being groomed in demonstration
plants. First SNG-from-coal
plants in U.S. will use Lurgi
technology.
-------
PROCESSES FOR HIGH BTU PIPELINE GAS (SNG) (Continued)
Processes Developed With Their Own Technology for Methanation (Concluded)
Developed or Offered by
(and Process Name if any)
Stone & Webster Engineering
Corp. (Solution/Gasification)
Process Comments
Status and Remarks
U.S. Bureau of Mines (Synthane)
w
u>
Coal is slurried in a solvent;
then a two-step treatment with hy-
drogen solubilizes the coal and
produces pipeline-quality gas
without an explicit methanation
step. Process does not entail ox-
ygen or steam.
Coal is pretreated with steam and
oxygen in fluidized-bed reactor
that is integral part of gasifica-
tion system. The system operates
at high pressures (e.g., 1000 psi).
Of methane contained in final gas,
60 percent is made during gasifi-
cation step. Two variants of down-
stream methanation with Raney
nickel catalyst are under study.
Processes That Will be Combined with "Outside" Methanation Technology
Tested on bench scale. Under
new joint venture with General
Atomic, nuclear reactors will
provide heat for hydrogen gen-
eration. Demonstration plant
planned.
Tested in continuous unit rated
at 10 to 20 Ib/h. A 75-ton/d
pilot plant due completed at
Bruceton, PA, in August 1974.
Applied Technology Corp.
Babcock & Wilcox Co.
Babcock & Wilcox Co.
Coal is injected into 2500°F molten-
iron bath; reaction with steam and
oxygen produces sulfur-free gas for
shift conversion and methanation.
Sulfur removed as slag by limestone
addition.
Entrained-coal gasifier; char re-
cycled. Methane content of gasifier
output can be regulated by selecting
pressure and temperature.
Gasifier employs sulfur dioxide in-
stead of oxygen for blowing.
Gasification step has been
tested in 2-ft-dia. reactor,
equivalent to 10 Ib/min of
coal. Company seeks funds to
build 15-ton/h unit.
Technology commercial in
1950"s for making synthesis
gas. Now soliciting cuto-
mers for fuel production
(including SNG) as well.
Conceptual.
testing.
Seeking Funds for
-------
PROCESSES FOR HIGH BTU PIPELINE GAS (SNG) (Continued)
Processes That Will be Combined with "Outside" Methanation Technology (Continued)
Developed or Offered by
(and Process Name if any)
Cogas Development Co. (Cogas)
Consolidation Coal Co.
(CO_ Acceptor)
w
*>.
Davy Powergas, Inc. (Winkler)
Exxon Corp.
Garrett Research & Development
Co. (GRD Coal Gasification
Process)
Process Comments
Multistage pyrolysis of coal
yields gas, oil and char. More
gas comes from reacting char
with steam, at under 100 psi.
Heat for gasification supplied
by burning some char in air, in
a combustor external to the
gasifier. No oxygen needed.
Lignite is gasified with steam
in presence of hot, calcined
dolomite. This reacts exother-
mally with the gasification-
generated carbon dioxide, re-
moving it while providing heat
for gasification. Dolomite re-
generated by heating.
Oxygen-feeding version of pro-
cess outlined in Appendix A
serves as gasification step to
precede shift conversion, puri-
fication, and methanation.
Air burns char outside of gasi-
fier, to provide heat for gasi-
fication reactions involving
steam. System does not require
oxygen.
A low-pressure (30 to 50 psi)
step pyrolyzes coal quickly in
the presence of some steam and
recycled gas. The pyrolyzer
also receives partially burned
char (produced externally by
air combustion), which supplies
the needed heat.
Status and Remarks
Pyrolysis step demonstrated in
COED-Process work of FMC Corp.,
one of the partners in Cogas
Development Co. Two pilot
plants will test char-gasification
step.
Runs have been made in a 30-ton/d
pilot plant completed in South
Dakota in 1972.
Developed in Germany; widely com-
mercial in Europe and Asia; no
U.S. contracts yet.
Tested in 1/2-ton/d unit at
Baytown, Tex. Design of proposed
500-ton/d plant nearly completed.
Tested in a 50-lb/h unit (a highly
similar liquefaction process has
been tested in a 300-lb unit).
Now seeking support for a 250-ton/d
pilot plant.
-------
PROCESSES FOR HIGH BTU PIPELINE GAS (SNG) (Concluded)
Processes That Will be Combined with "Outside" Methanation Technology (Concluded)
Status and Remarks
Developed or Offered by
(and Process Name if any)
M. W. Kellogg Co.
CD
U1
Koppers Co. (Koppers-Totzek)
Union Carbide/Battelle/Chemico
U.S. Bureau of Mines
(Hydrane)
Process Comments
Coal is contacted with oxygen
and steam in a molten-sodium-
carbonate bath at about 1700°F.
and 1200 psi. The salt serves
as catalyst and heat-transfer
agent; all operations involving
salt take place in the one ves-
sel. Raw gas from gasification
is tar-free. Of methane in the
final gas, 55 percent to 60
percent is made during this
gasification step.
Effluent from gasification des-
cribed in Appendix A is suitable
for shift conversion, and
methanat?on.
Two fluidized-bed systems, a com-
bustor and a gasifier, are linked
by an agglomerated-ash circuit
that transfers heat. Gasifier,
at 1800°f and 250-350 psi, is fed
coal and steam; the combustor is
fed char and air. No oxygen
required.
In a first, "dilute" stage, coal
particles are heated through their
plastic-transition temperature
range in a stream of hydrogen and
methane from fluidized-bed second
stage. Devolatilized coal, mean-
while, falls into second stage,
where it contacts hydrogen gerner-
ated externally from char, steam
and oxygen. Gas leaving dilute
stage, at 2000 psi, is 75 percent
or more methane.
Process development, underway
for several years, has included
studies in a 5-1/4-in-dia.
reactor. Next step will employ
a 30-in reactor. Funding sought
for building a large continuous
pilot plant.
Sixteen commercial plants in
Europe and Africa, making
ammonia-syntesis gas.
Components of process tested
during 1960's by Union Carbide
and Battelle. Chemico complet-
ing design, for Battelle, for
25-ton/d pilot unit.
The two stages have been tested
separately at Bruceton, PA. A
pilot unit to demonstrate them
together has just been built
but is not likely to start up
during this fiscal year.
-------
APPENDIX C
BULK CONVERSION COST DATA
C-l
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APPENDIX D
METRIC SYSTEM CONVERSION FACTORS
Although EPA's policy is to use the metric system in all of its docu-
mentation, certain non-metric units are used in this report for convenience.
Readers more familiar with the metric system may use the following to convert
to that system:
Non-Metric Unit
in
ft
ft2
ft3
gal.
Ib.
ton
centistoke
OF
Btu
Btu/ft3
Multiplied By
2.540
0.3048
9.3 x 10~2
28.317
3.785
0.454
907.185
10-s
5/9(°F-32)
1.055 x 103
37.256
Yields Metric Unit
cm
m
m2
liter
liter
kg
kg
m2/sec
°C
joule
joule/liter
D-l
-------
TECHNICAL REPORT DATA
(Please read laumctiom on the reverse before completing)
\. REPORT NO.
EPA-650/2-74-123
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Boiler Modif i cation Cost Survey for Sulfur Oxides
Control by Fuel Substitution
5. REPORT DATE
November 1974
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S),
R. J.Schreiber, A.W.Davis, J.M.Delacy,
Y. H. Chang, and H. N. Lockwood
8. PERFORMING ORGANIZATION REPORT NO.
74-113
9. PERFORMING ORG \NIZATION NAME AND ADDRESS
Aerotherm/Acurex Corporation
485 Clyde Avenue
Mountain View, CA 94042
1O. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADE-010
11. CONTRACT/GRANT NO.
68-02-1318, Task 9
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; through 10/74
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a study to identify capital costs associated with
converting industrial and utility boilers from conventional high-sulfur fossil fuels
to low-sulfur products from selected coal conversion processes. The boilers of
concern include all industrial and utility size equipment in the 10 to the 7th power
to 10 to the 10th power Btu/hr capacity range. The substitute fuels include solvent
refined coal (SRC) in the solid and hot liquid (melted) phases as well as lower-Btu
gas. The cost assessment methods used in the study showed that conversion to
liquid SRC is the most expensive alternative. Converting coal-fired boilers to
solid SRC is the least expensive alternative for these types of boilers. Between the
costs of converting to SRC in either phase lie those costs for converting to the
gaseous fuels. A significant result of the study is that the costs of all conversion
strategies increase exponentially with boiler capacity: cost appears to be a weak
function of boiler design.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Boilers
Engineering Costs
Capitalized Costs
Sulfur Oxides
Fossil Fuels
Coal
Air Pollution Control
Stationary Sources
Boiler Modification
Fuel Substitution
Coal Conversion
Low-Btu Gas
13B
ISA
14A
07B
21D, 08G
8. DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
113
Unlimited
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
T-l
------- |