EVALUATION OF THE
FLUIDIZED BED
COMBUSTION PROCESS
Submitted to:
Office of Air Programs
Environmental Protection Agency
Contract No. CPA 70-9
By:
Westinghouse Research Laboratories
Pittsburgh, Pennsylvania
Volume I SUMMARY REPORT
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EVALUATION OF THE FLUIDIZED BED COMBUSTION PROCESS
SUMMARY REPORT
Contract'No. CPA 70-9
November 15, 1969 - November 15, 1971
Prepared for
Office of Air Programs
Environmental Protection Agency
Research Triangle Park,
North Carolina 27711
Project Officer:
P. P. Turner
By
Westinghouse Research Laboratories
Pittsburgh, Pennsylvania 15235
Authors
D. H. Archer, "D. L. Keairns
J. R. Hamm, R. A. Newby
W. C. Yang,' L. M. Handman
1. Elikan
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TABLE OF CONTENTS
VOLUME I
ABSTRACT. . .
SUMMARY. . .
. .. .. ..
. . .. .
.. .. . .
.......
. . . . . . . .
......
.. .. .. . .. .
INTRODUCTION.
.. . . .
.. .. .. . .. .
.. . . . .. .
. . . . .
. .. .. ..
FLUIDIZED BED COMBUSTION BOILER CONCEPTS.
. .. . .
. . . . . .. .
Fuel. . . . . .. . .. . .. . . .
.. . .. ..
. .. ..
. . . ..
. .. . ..
Fluidized Bed Processing. . . . . . . .' . . . . . . .
Boiler Concepts.. . . . . . .. .. . . . . .. . . .. . . . .. . .
Design of a Fluidized Bed Boiler System. . . . . . .
PRELIMINARY SURVEYS. . .
. . .. . . . .
. .. . . . .
.. . . .
Market Surveys. . . . . . .. .. . . . .. .. . . . . . . .. .. . .
Fossil Fuel Survey; . . . . . . . . . . . . . . . . .
Survey of Alternative Means of S02
Pollution Control. . . . . . . .
Emission Standards Survey. . . . . . . . . . . . . . . . .
.. .. . .. .. . .. . .
ASSESSMENT OF FLUIDIZED BED COMBUSTION.
.
. .. .. .. .. ..
.. .. .. .. .. ..
Specifications. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
Functional Boiler Specifications. . . . . . . . . . .
Operating Specifications . . . . . . . . . . . .
Design Specifications.. . . . . . . . . .
Industrial Boiler Application. . . . . . . . . . . . . . .
Des ign .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
Controls and Instrumentation. . . . . . . . . . . . .
Operation. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
Performance Characteristics. . . . . . . . . . . . . .
Boiler Plant Costs. . . . . . . . . . . . . . . . . .
Evaluation.. .. .. .. .. .. .. .. .. .. .. .. ..
......
Electric Utility Application. . .
Pressurized Fluid, Bed Boiler
Power Plant Design. . . . . . . . . . . . . . . . .
System Concept. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
Power Cycle Conditions. . . . . . . . . . . . . .
Boiler Plant Equipment. . . . . . . . . . . . . .
Auxiliary Equipment. . . . . . . . . . . . . . .
Power Generation Equipment. . . . . .
Controls and Instrumentation. . . . . . . .
Plant Layout.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
Perf ormance .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
.. .. .. .. .. ..
.. .. .. ..
Page
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80'
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TABLE OF CONTENTS CCont'd.)
Atmospheric Pressure Fluidized Bed
Boiler Power Plant Design. . . . . . . . .. . .
Boiler Plant Equipment. . . . . . . 4 . .
Auxiliary Equipment. , , , , , " '" ,
Sulfur Removal/Recovery System, " ., ., , , , ,
P.erformance . . . . . . . . ". . ". .
"Economics. . . '. . . . . '. . . . . . '. . . ..' .
Evalua tion . . . . . . . . . . . -.
Comparison. . . . . . '. . . . . ". .. . . ,.
Potential.. '. . . . . . ~. . '. .. .8 . . . '.
ASSESSMENT OF ATMOSPHERIC PRESSURE FLUIDIZED
. BED OIL GASIFICATION, ., . . . ". , " , . , . .,
. .. .. .
.Specifications. . . . . . . . . . '. '. . . .. . . . '.
GasificationlDesulfurization Concepts " , " , .. '.
Design. ... .. . '. . . . . . . . . . . .
Economics '. .. . '. . . . . . . . .. . . . . . . '. .. . .
Evalua tion. . -. . . . . . . . . . '. '. . . . . .. '. . '. . .
Comparison Between Regeneration and
Onc'e-ThroughOperations , , , , , ., ,. .. ., ,
Comparison with Other S02
Control Methods ,.', , , ,
'. . . . .
FLUIDIZED BED FUEL PROCESSING
DEVELOPMENT PLANTS. , , "
. . '. . .e .
. . . . . '. .
Pressurized Fluidized Bed Combustion
Boiler Development Plant. , .. ,
Atmospheric Pressure Oil Gasification
Demonstration Plant, . , , , , " ,
. . . . .
. . .8 . '.
. . . . . ,8 '.
CONCLUSIONS, " , ., " , ,
. . . . . . .
. . . ..
Fluidized Bed ,Combustion Boilers, , ., ,. . .. "
Atmospheric Pressure Fluidized Bed
011 Gasification, , . , , " , . , , , . ,
.8 . . .
RECOMMENDATIONS, , , , . ., " , ., . . , ,
. . . .
. '. . .
Industrial Fluidized BedConibustion Boilers, , , '. '. , ,.
Utility Fluidized Bed Combustion Boilers", '. , " , " , .
Atmospheric Pressure Oil Gasification. , . , , , <0 ," ,
REFERENCES. , ,
. .. . -8 .. .
". . .. .
. . . .
. . . . .
. . . ~.
ACKNOWLEDGEMENTS,
. .8 . . .
. '. '. ...
. . . '.
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TABLES OF CONTENTS
FOR
VOLUMES II AND III
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VOLUME II
PREFACE
1.
ASSESSMENT OF FLUIDIZED BED COMBUSTION
PRELIMINARY SURVEYS
FLUIDIZED BED COMBUSTION DATA
Sulfur Dioxide Removal
Limestone/Dolomite Regeneration
Nitrogen Oxide Minimization
I
I -
Combustion Efficiency
Heat Transfer
Particle Carry-Over
Boiler Tube Corrosion, Erosion and Fouling
Gas Turbine Erosion and"Corrosion
INDUSTRIAL BOILER APPLICATION
Design
System Specifications
Fuel and Limestone Specifications
Design Bases
Boiler System Design
Boiler System Schematic
Energy and Material Balances
Industrial Boiler Design Concepts
Selected Steam Generator Design
Coal and Limestone Feed Systems
Particulate Removal System
Pollution Control System
Selection of Draft Equipment
Overall Design Layout
Boiler Operation and Performance
Operating Procedures
Performance Characteristics
Controls and Instrumentation
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Boiler Cost
Capital Cost of Once-Through Dry Solid and Wet Scrubbing
Industrial Fluidized Bed Boilers
Comparison of Capital Cost Between Fluidized Bed Boi+ers
and Conventional Boilers ..
Comparison of Total Cost Between Fluidized Bed Boilers
and Conventional Boilers
Effect of Operating V~riables on Cost and Design of Industrial Boilers
Recommendations
ELECTRIC UTILITY APPLICATION
Introduction
Pressurized Fluid Bed Boiler System
System Concept
Specifications
Power Cycle Analysis
Growth Evaluation
Boiler Subsystem
Regeneration and Sulfur Recovery System
Auxiliary Equipment
Power Generation Equipment
Operation and Controls.
Control and Instrumentation
Plant Layout
Plant Performance
Atmospheric Pressure Fluidized Bed Boiler Design
Specifications
Cycle Selection
Alternative Concepts
Boiler Design
Regeneration and Sulfur
Auxiliary Equipment
Control
Plant Performance
Re'covery System
Economics
Capital Costs
Energy Costs
Evaluation
Comparison
Po.tential
Recommendations
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2. ASSESSMENT OF A FLUIDIZED BED
OIL GASIFICATION-COMBUSTION POWER SYSTEM
INTRODUCTION
GASIFICATION/DESULFURIZATION CONCEPTS
DATA EVALUATION
The Esso England Program
Gasification
Carbon Deposition.
Gasifier Product Analysis
Desulfurization
Regeneration
Particle Carry-Over
Metal Retention
Burner Design
Preliminary Results of Continuous Operation
MATERIAL AND ENERGY BALANCES
Modes of Operation
Design Parameters
Temperature Control
Regenerative Operation
Once-Through Operation
Overall Material and Energy Balances
Power Requirements
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DESIGN CONCEPTS
Retrofit Concepts
Retrofit Location
Boiler Performance and Boiler Modifications
New Boilers
Burners
Turn-Down
ECONOMICS
Cost Factors
Regeneration Operation Economics--New and Retrofit
Once-through Operation Economics--New and Retrofit
TECHNICAL EVALUATION
Comparison Between Regenerative and Once-Through Operations
Comparison with Other S02 Control Methods
Preliminary Design Conclusions
RECOMMENDATIONS
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3.
FLUIDIZED BED COMBUSTION DEVELOPMENT PLANTS
DEVELOPMENT PLANT ALTERNATIVES
PRESSURIZED FLUID BED COMBUSTION BOILER DEVELOPMENT PLANT
Objectives
Plant Concept
Conceptual Design
i -
Flow Diagram and Material Balance
Equipment
Space Requirement
Power Requirement
Experimental Program
Cost Estimate
Development Plant Schedule
ATMOSPHERIC PRESSURE FLUIDIZED BED OIL GASIFICATION-COMBUSTION
DEMONSTRATION PLANT
Objectives
Plant Concept
Conceptual Design
Flow Diagrams
Equipment
Boiler Capacity
Experimental Program
Development Plant Cost
Schedule
Estimate
REFERENCES
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VOLUME III
APPENDICES
APPENDIX A . Electric Utility Market Survey
APPENDIX B - Industrial Boiler Market Survey
APPENDIX C - Development of Fluidized Bed Combustion Boilers
APPENDIX D - Industrial Boiler Design Report
APPENDIX E - Turndown Techniques for Atmospheric Fluidized B~d Boilers
APPENDIX F - Dynamics of Atmospheric Fluidized Bed Boilers
APPENDIX G - Optimization of Heat Trap System Cost
APPENDIX H - Pressurized Boiler Design Report
APPENDIX I - Regeneration/Sulfur Recovery System. Cost
APPENDIX J - Pr~ssurized Boiler Combined Cycle Plant Report
APPENDIX K - Atmosph~ric-Pressure Boiler Design Report
APPENDIX L - Burner Design Correspondence
APPENDIX M - Gas Turbine Corrosion, Erosion, and Fouling
APPENDIX N - Stack Gas Cooler Design
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ABSTRACT
The effectiveness and economics of fluidized bed combustion
boilers in pollution abatement and steam/power generation have been
evaluated.
A 250,000 lb/hr coal-fired, factory-fabricated, industrial
boiler has been designed along with all of its auxiliaries. Utility
boilers have been designed for operation at atmospheric pressure in
conventional steam power plants and for operation at 10 atm in a combined
steam and gas turbine power plant. Overall capital and operating costs
have been estimated for both 300 and 600 megawatt plants.
Of all the systems studied, the pressurized fluidized bed
combustion boiler operating in a combined cycle power plant appears most
effective in meeting projected emission standards and in reducing total
S02' NOx' and particulate emissions, and most economical in power generation.
Such a plant has an estimated capital cost 20% less and energy cost 10%
less than a conventional utility plant with a stack gas scrubber; this
plant also has the greatest potential for increased generation efficiency
and reduced costs.
A fluidized bed oil gasification-desulfurization system has
also been designed and evaluated as an add-on unit for reducing S02
emissions from utility boilers burning high-sulfur oils. The estimated
capital cost of such a unit is as much as 50% less than an add-on
wet scrubbing system.
It is recommended that a developmental pressurized fluidized
bed boiler unit of 10 to 30 megawatt capacity be designed. and constructed
to provide necessary technical information for a prototype power plant.
It is also recommended that the installation of a 100 to 200
megawatt demonstration fluidized bed oil gasifier-desulfurizer at a
utility site be pursued.
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SUMMARY
Fluidized bed processing of high-sulfur fossil fuels is
evaluated for economical steam and/or power generation within projected
pollution control limits.
Industrial steam generation and utility
power generation concepts are assessed on the basis of preliminary
design studies. Processing includes both combustion and gasification.
All of the concepts use a fluidized bed composed of a limestone or
dolomite for sulfur removal.
In fluidized bed combustion the sulfur
dioxide and nitrogen oxides are minimized duringt~e combustion process,
and the heat transfer from the burning fuel to evaporating water is
facilitated to achieve a more economical boiler system.
An atmospheric
pressure fluidized bed boiler is essentially a replacement of a conventional
boiler.
Fluidized bed combustion boilers operated at elevated pressure
utilize both gas and steam-turbine generators; the high-temperature, high-
pressure flue gas is expanded through the gas turbine to produce
approximately 20% of the power. In fluidized bed gasification a clean
fuel gas with minimal sulfur and particulates is produced which can be
utilized for power generation at atmospheric pressure in conventional
gas-fired boilers or at elevated pressures in a gas-turbine combustor.
The following tasks were performed:
. Industrial Boiler Market Survey
. Utility Boiler Market Survey
. Industrial Boiler Preliminary Design and Costs
. Utility Boiler Preliminary Designs -- Atmospheric and Pressurized --
and Costs
. Plant Layout and_Energy Generation Cost Estimates
. Fluidized Bed Combustion Boiler Development Plant Conceptual Design
and Cost Estimate
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. Atmospheric Pressure Oil Gasification Assessment
. Fluidized Bed Oil Gasification Demonstration Plant Conceptual Design
and Cost
. Technical Consultation and Program Assistance to the Office of Air
Programs.
Boiler design specifications-- capacities, steam conditions, pollutant
emission restrictions, etc. -- were based on the market surveys. The scope
of the design studies is summarized in the matrix on the following page.
Energy surveys indica~e that power generation in the United
States will increase by a factor of four; and fossil fuel usage in gen-
eration, by a factor of three in the next 20 years.
The design studies show that fluidized bed combustion can be
used to meet air pollution control regulations for S02' NOx' and parti-
culates without creating other environmental problems. The economic
projections are summarized in Table 1.
The industrial boiler design
study and evaluation indicate that the capital cost of a once-through
limestone system may be reduc~d by 20% over a conventional spreader
stoker with wet scrubbing. However, the steam costs may be competitive
for a high-sulfur coal, (4%), due to the large limestone throughput
required for the fluidized bed system.
Assessment of the fluidized bed oil gasification process for
retrofit on existing plants indicates that S02' NOx' and particulates can
be effectively and economically controlled. The process may reduce the
effective increase in fuel cost for pollution control 30 to 50% below wet
scrubbing, low-sulfur oil, or desu1furized oil for plant capacities
greater than 50%.
Research and development efforts on pressurized. fluid bed com-
bustion boilers should continue. A 10 to 30 MW development plant should
be built and operated. A utility should be sought for a 100 to 200 MW
fluidized bed oil gasification demonstration plant retrofit on an existing
plant.. Further research and development work on atmospheric pressure
systems -- industrial and utility -- should be deferred at this time.
iv
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.
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SCOPE OF FLUIDIZED BED PROCESSING DESIGN STUDIES
Coal-Fired Plants
PLANT SIZE AND DESIGN DETAIL
Oil-Fired Plants
INDUSTRIAL
Combustion
Atm. Pressure
Pressurized
UTILITY
Combustion
Atm. Pressure
Pressurized
Gasification
Atm. Pressure
Pressurized
Coal-fired 250,000 lb steam/hr
boiler with the following
alternative sulfur removal/
recovery systems: clean fuel,
limestone calcining-wet
scrubbing, dry limestone once-
through, and regenerative;
preliminary design and cost
for each system.
Concept evaluation
300 MW coal-fired boiler/
regenerator/S recovery system;
preliminary design and cost.
600 MW coal-fired boiler/
regenerator/S recovery system;
cost projected from 300 MW
system; plant and energy costs
projected.
300 MW coal-fired boiler;
preliminary design and cost.
600 MW coal-fired boiler design
and cost projected from
preliminary design, preliminary
design and cost of regeneration/
S recovery system, preliminary
design of plant layout, plant
cost, and energy cost.
10 to 30 MW development plant;
proposal design and cost.
No work conducted under contract.
Designs were not developed
under contract.
Oil-fired, 250,000 lb steam/hr; cost
projected from coal-fired preliminary
design.
600 MW oil-fired plant costs projected.
600 MW oil-fired plant costs projected.
600 MW oil-fired gasifier/regenerator/
S recovery system; conceptual design
and cost estimate; 100 to 200 MW
demonstration plant conceptual design
and cost estimate. .
No work conducted under contract.
v
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TABLE 1
FLUIDIZED BED COMBUSTION SYSTEM COST SUMMARY
UTILITY POWER PLANTS
635 MW
INDUSTRIAL BOILER 70% Load Factor
250.000 lb steam/hr Begin Construction Julv. 1971
I (a Fluidized Bed Boiler
Conventional Fluidized Bed Boiler Conventional p.f. With Sulfur Recovery System
Stoker . I Pressurized
With Wet Scrubbing Boiler With Wet Scrubbing Atmospheric
Throw-Awav System Pressure
<:
'"'"
COAL
Capital Cost
Steam cost,(b)
. ~/l06 Btu
Energy Cost (~)
mUls/kW-hr
OIL
Capital Cost
Steam cost~b)
C/106 Btti
Energy Cost(~)
mills/kW-hr
$7.60/lb steam/hr
72.00
$337/kW
$277/kW
$6.l0-7.40/lb steam/hr
71. 50-76.00
$313/kW
13.40
13.12
12.12
$4.50/lb steam/hr
$5.25-7.00/lb stearo/hr(a)
. .
$308/kW
$300/kW
$264/kW
62.70
66.50-73.50
12.59
12.78
11. 76
(a)
(b)
(c)
Two sulfur
High-Sulfur Fuel, Fuel Cost:
High-Sulfur Fuel, Fuel Cost:
at 15%.
. removal systems are considered.
6
30C/10 Btu, No Sulfur Credit.
6
45C/10 Btu over life of plant,
No Sulfur Credit; Capital Charges
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INTRODUCTION
The Office of Air Programs (OAP), of the United States Environ-
mental Protection Agency, has organized and is sponsoring a fluidized
bed fuel processing program.
Its purpose is to develop and demonstrate
new methods for utilizing fossil fuels -- particularly coal and oil --
in industrial boilers and in utility power plants.
These methods should
. Meet air pollution abatement goals for S02' NOx' ash and
smoke emissions
. Compete economically with alternative means for meeting these
abatement goals.
The following governmental and private organizations have participated
in this OAP program:
Argonne National Laboratory, Chicago
U.S. Bureau of Mines, Morgantown
Consolidation Coal, Pittsburgh
Esso Research and Engineering, Linden, New Jersey
Esso Petroleum Company, Research and Development, United Kingdom
M. W. Kellogg, Piscataway
A. M. Kinney, Cincinnati
Massachusetts Institute of Technology, Cambridge
National Coal Board, United Kingdom
Pope, Evans, and Robbins, Alexandria
Westinghouse Research Laboratories, Pittsburgh.
Westinghouse has been assigned process evaluation tasks in
the fluidized bed fuel processing program.
These tasks have included:
. Conducting studies predicting fuel availability and usage costs;
market surveys forecasting industrial boiler and utility power
1
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olant installations: and analyses ~rojecting air pollution control
improvement. The purpose of these investigations was to provide a
basis for boiler design specifications -- capacities, steam conditions,
pollutant emission restrictions, etc. -- and to determine the possible
beneficial improvements in environmental and economic impact of various
improved steam/power generation processes.
. Designing an industrial fluidized bed boiler and two' utility
boilers -- one carrying out combustion at . one atm', .the other at
10 atm pressure,. All of the boilers use a limestone/dolomite
sorbent in the fluidized bed for sulfur removal.
Systems for
regenerating and recycling the sorbent and for recovering the
sulfur in useful form have also been designed.
All necessary
auxil~~ries for the industrial boiler and complete power plant
equipment for the utility boilers have also been specified so
that a complete system can be visualized. The purpose of these'
boiler sys.tem designs is to evaluate the perf'ormance and cos.ts
of ind'ustrial boilers and utility power plants employing fluidized
bed combustion.
Promising areas for future development have been
identified.
Westinghouse has been assisted in this work by
Erie City Energy, Foster Wheeler, and United Engineers.
The
design and evaluation process. has also pointed up technical areas
where: more information is needed and further development is
required to meet. the goal of a. non-polluting, economical means of
producing steam/power from fossil fuels..
.' Conceptualizing a, fluidized bed' combustion boiler development
plant.
Preliminary designs have been produced for a development
plant, which will make possible an'attack on the remaining technical
problems; in', those, areas where fluidized combustion has grea,test
po,t.ential for reducing air pollution and for economical genera'tion
of steam/power. Preliminary estimates of the cost for such a
prant hav:e also been,made.
2.
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, _.
..
. Providing technical consultation and assistance on the OAP
fluidized bed fuel processing program, including both combustion
and gasification processes. Technical and economic comparisons
have been carried out on various fluidized bed fuel processing
systems and various conventional means of steam/power generation.
An atmospheric pressure oil gasification/desulfurization process
has been assessed in detail as an adjunct to a utility boiler.
The results of the various surveys, designs, evaluations,
and comparisons are presented in this three-volume report.
The report
identifies fluidized bed fuel processing systems which should meet
both market requirements and air pollution abatement requirements and
which are likely to be cheaper than alternative, conventional systems.
Finally, it recommends a program for commercializing promising processes.
This volume is a condensation of the complete report;
all
the technical details of the work are contained in Volumes II and III.
These details support the general conclusions and provide a sound basis
for future work.
But in this condensation only the most important
work is described.
Some of the scope and detail has been omitted to
emphasize the main themes of the work and to present clearly the most
important conclusions.
3
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FLUIDIZED BED COMBUSTION BOILER CONCEPTS
involved
tions of
The OAP-Westinghouse fluidized bed fuel processing study has
the analysis of a broad range of concepts, and the implica-
the program extend further still. This section explores the
fluidized bed combustion concepts studied.
range of
FUEL
Fuels specifically included in the Westinghouse studies are
a Pittsburgh seam coal and an Aruba oil residuum.
However, fluidized
bed combustion has been shown effective in utilizing a much wider vari-
ety of materials -- lignite, anthracite cu1m:I,2) sewage sludge, (3,4)
solid wastes, (S,6)natura1 gas, and high ash coals whose sodium and chlorine
contents make them unsuitable for use in conventional boilers. (7)
Its ability to effectively use a broad range of materials gives fluidized
bed fuel processing technology great versatility and wide applicability.
FLUIDIZED BED PROCESSING
Fuel is currently processed in three reactor types -- fixed
bed, suspended bed, and fluidized bed.
In a fixed bed reactor, gases
pass through a bed of solids at a velocity sufficiently low that the
solid particles are not blown from the bed and are not supported by
the flowing gases. The weight of the particles rests primarily on other
particles which make up the bed.
is one type of fixed bed reactor.
A boiler with a chain grate stoker
In a suspended bed reactor; gases flow at a sufficiently high
velocity that solid particles are carried along with the gases; their
weight is supported by drag forces exerted by the gases. Contact between
5
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particles is limited to occasional collisions.
is one type. of suspended bed reactor.
A pulverized fuel boiler
In a fluidized bed reactor, the gases flow through a bed of
particles at a sufficiently high velocity to support their weight, but
not high enough to carry them' out of the bed. Fluidized bed, combustion
reactors have not yet been applied commercially as boilers. But, at
least five fluidized bed gasification reactors are currently under
development to produce pipeline gas and/or liquid fuels from coal.
Other fluidized bed processing units have been developed to produce
pipeline gas from oil;
and fluidized bed reactors are now used com-
mercially in the catalytic cracking of oil, roasting of sulfide or.es,
incineration, of oily wastes and sludges, production of organic chemical
monomers, making of cement, conversion of nuclear ,materials for fuel,
elements ,. etc.'
Fluidized bed reactors provide the following features in.
processing solids and gases:
. Ease and versatility in solids flow and handling.
Solid materials
can readily be added to or removed from fluidized beds.
Gas
velocities can be chosen to promote particle mixing in the bed
or to cause separation between particles of different size and
density.
. Rapid heat transfer. The free movement of particles in a flui-
dized bed promot.es rapid heat transfer both within the bed and
between the bed and submerged surfaces. Bed temperatures are
therefore uniform and easy to control.
.' Effective gas-solid contact. Because the relative velocity
between gas and solids is high, exchange of mass,and heat is
rapid. A fluidized bed also provides a large amount of solid
surface in contact w,ith flowing gas in a. relatively small
volume.
6
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In fluidized bed combustion sufficient air is added to the
fuel to virtually complete the transformation of its carbon to C02 and
its hydrogen to H20:
C + 02 ~ C02
Oxida tion -
H2 + 1/2 02 ~ H20
Both these reactions produce large quantities of heat which can be
absorbed by generating steam-
Sulfur in the fuel is converted primarily to S02- A 1imestone/
dolomite sorbent can be utilized in fluidized bed combustion to remove
this pollutant from the combustion gases:
(caC03) . (C02)
CaD + S02 + 1/2 02 ~ CaS04 + -
The CaS04 can either be disposed of as a solid
processed to regenerate CaC03 (or CaO) sorbent
as a useful product -- elemental sulfur, S, or
waste or it can be
and to recover sulfur
sulfuric acid, H2S04-
7
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BOILER CONCEPTS
A schematic diagram of a simple coal-burning fluidized bed
combustion boiler concept is shown in Figure 1.
It is formed by an
enclosure usually consisting of waterwalls -- abutting boiler tubes in
which water ahd steam flow.
The pressure in this enclosure is. in the
1 to 25 atm range.
A flat distributor plate with holes' or bubble cap'
. devices distributes. the air flow uniformly over the base on the enclosure.
The air then passes at velocities in the range of.2 to 15 ft/sec through
a bed of particles at temperatures from 1400 to 2000°F. These partic'les,
whose top size is 1/16 to 1/4 in., comprise ash or other inert material',
lime sorbent, and small quantities (less than 1%) of unburned coal or
carbon. Coal and sorbent are fed to the bed by'pneumatic feeders
extending through the air distributor or the waterwalls. From 60 to
70% of the heat released in burning the fuel with air is' transferred
to the water/steam in the tubes surrounding and submerged in the bed.
Various tube configurations have been proposed -- horizontal tubes
extending through the bed (Figure 2), horizontal tubes with serpentine
bends in vertical platens or planes, and vertical tube walls passing up
through the distributor plate,. slicing the bed into narrow segments (Figure 3).
The air and. combustion gases passing through the bed cause
consid'erable agitation: particles are thrown from the bed into the
empty volume above -- the freeboard. Larger, heavier particles fall back
into the bed; smaller, lighter particles are carried out of the enclosure
by the gases. Much of the ash in the combustion of washed coals is
eventually carried from the bed in. the combustion. gases. . Larger ash
particles may accumulate in the bed and require periodic removal.
Splashing of the particles. into the freeboard can be minimized
by loc'ating. a screen of horizontal water/steam tubes as a baffle over
the surface' of the agitated bed (see Figure 1). The baffle tubes increase
8;
-------
Baffle
Tubes
Evaporator
Section
Air
Dwg. 2965A69
Primary
Cyclone
. Secondary
Particulate Removal
Convection
Section
Heat Recove ry
Section
Water
Walls
Water
Walls
Ash; Particulates
'Sulfate, Ash
Preheater, Superheater
or Reheater Section
Distributor Plate
Lime
Coal
. Pressure: 1 - 25 atm
Coal Size: pf - 1/4 in.
Ai r Flow: 2 - 15 fV see
Temperature: 1400 - 19000F
Surface: Water Walls, Horizontal,
and Vertical Tubes
in Bed
Sulfur removal: Ca 0 + S02 + i 02 -+ Ca SO 4
Fig. 1-FI uidized bed combustion boiler
9
-------
Dwg. 2967A72
o
o
o
o
_. - - - - - .... --
--------
Fig. 2-FI uidized bed combustion boi fer
with horizontal steam tubes
Fig. 3-FI uidizad bed combusUon boiler
with vertical steam tubes
10
-------
the heat surface exposed to the bed and reduce the height in the
freeboard required to minimize the loss of large particles from the
enclosure.
Convection heat transfer surface can be located in the path
of the combustion products to generate more steam from the sensible heat
of these gases.
A reasonably high heat transfer coefficient from the
combustion gases to the tube surface requires high gas velocities.
These velocities can be achieved by narrowing or restricting the gas
passage in the convection section (Figure 1) or by packing tubes into
a broad gas passage with small clearances between tubes.
Particles carried from the fluidized bed enclosure by the
combustion gases can be captured by inertial separations apparatus
such as a cyclone.
These particles comprise ash, 'fragments of the
limestone/dolomite sorbent, and typically 20 to 40% by weight unburned
coal char or carbon. To obtain high combustion efficiencies, the parti- .
cles captured in this primary cyclone can be recycled to the boiler bed
or to a separate fluidized bed combustor where the burning of the char
is completed.
Additional heat can be extracted from the combustion gases
in the heat recovery section, which may be either an economizer preheat-
ing boiler feed water or an air preheater.
Final clean-up of the combustion gases is carried out in a
secondary particulate removal system, using cyclones or an electrostatic
precipitator.
DESIGN OF A FLUIDIZED BED BOILER SYSTEM
The conceptualization of a fluidized bed boile~ system involves
the choice of a number of critical process operating, system configuration,
and hardware design parameters.
11
-------
The operating variables of greatest significance are:
. Bed temperature
. Gas velocities through the bed
. Excess air flow
. Particle diameter for the coal and sorbent
. Pressure in the combustor.
The operating bed tempe.rature must be high enough to ignite.
the c9a1 (above 750°F), to obtain reasonable combustion efficiencies in
the bed (above 1400°F), to promote rapid reaction of S02 with the sorbent
(also above 1400°F), and to attain high heat transfer rates between -the
bed and the tubes. But the bed temperature must also be sufficiently
low to prevent sinte.ring (below 2000 to 21000F), to retain good sorbent
reactivity (below 1600 to 1750°F), to minimize volatilization of corrosive
alkali metal compounds (below 1600 to 1900°F), and to minimize corrosion/
erosion of tubes in the bed. A low bed temperature is also desirable since
the heat transferred by.tubes in the bed is increased, thus reducing the
heat transfer surface cost.
Bed temperatures from 1500° to 1800°F are
generally specified for fluidized bed boilers.
Gas velocity through the bed must be high enough to fluidize the
particles (above 0.5 to 2.0 ft/sec at the temperature and pressure of the
bed) and to obtain economical burning or heat release rates per unit area
of bed (above perhaps 6 ft/sec). . But gas velocities also must be low
enough to avoid the loss of too many char and sorbent particles from the
bed (below 15 to 20 ft/sec), to allow sufficient residence time of gases
for good sulfur removal by the sorbent, to prevent too rapid attrition of
the sorbent particles, and to minimize erosion of the tube surfaces.
The excess air above the stoichiometrIc quantity must be large
enough to attain reasonably complete combustion of the fuel in the bed
(5 to 10% excess air), yet small enough to minimize both the total gas
flows and heat losses in the sensible heat of the stack gases.
.
The. choice of particle. size. for coal and sorbent depends upon
the concept of operation.
One concept uses coal and sorbent with a top
diameter of 1/16 to 1/8 inch -- large enough to minimize carry-over of
12
-------
bed particles in the combustion gases. The coal fed to the bed increases
in temperature, devo1ati1izes, chars, and burns as it diffuses in the
bed from the feed point.
Some of the smaller, partially burned, char
particles are carried from the bed, (elutriated)~reducing somewhat the
combustion efficiency of the process. The sorbent particles remove S02
from the combustion gases. A shell of sulphated sorbent may prevent
complete utilization of the sorbent in the center of the particle. But
the sorbent particles can be removed, generated, and returned to the
bed; and the sulfur can be recovered in some useful form.
Another possible concept uses inert or ash particles of 1/16
to 1/4 in. diameter to constitute the bed. Both coal and sorbent are
fed to the bed as particles sufficiently fine to be carried from the
bed by the gases -- 100 mesh or smaller.
Their residence time in the
bed, however, is 10 to 100 times the gas residence time. These particles
are sufficiently fine to react completely during their passage through
the bed. The coal is completely burned to ash; and the sorbent is largely
converted to sulfate.
The ash and spent sorbent are removed from the
combustion gases and collected in particle separation apparatus.
The
advantages of this concept over one using coarse coal and sorbent are
increased combustion efficiency (no char in the carry-over from the
bed) and increased utilization of the sorbent (no unsulfated core in
the sorbent particles). But the use of fine particles increases greatly
the difficulties in distributing fuel and sorbent uniformly over the
area of the bed. The particles may well be carried from the bed or be
completely reacted before spreading out,from the feed point. Coarse
particles have a longer residence and reaction time in the bed, and
thus there is greater opportunity for achieving a uniform distribution.
The use of limestone in fine particles also increases the problems
involved in separating it from the combustion gases and the ash, regen-
erating it, and returning it to the bed.
The operating pressure of a fluidized bed combustor is a design
variable which affects significantly ,the capacity of a boiler, the depth
of the bed, and the overall power system configuration. The maximum
13
-------
1---
air or combustion gas velocity through a fluidized bed combustor is
limited to less than 15 to 20 ft/sec in order to prevent excessive loss
of particles from the bed.
The mass of air passing through the bed
at any given velocity can be increased, however, by increasing the opera-
tingpressure. Since both the fuel flow and heat release rates in the
combustor are generally proportional to the mass flow of air, the capa-
city of a boiler with a given cross-section can be increased by increas-
ing pressure.
But in order to produce more steam, more heat transfer
surface must be submerged in the bed. For this reason, deeper beds will
generally be required for higher-pressure fluidized bed boilers.
Operating at atmospheric pressure, a fluidized bed combustion
boiler essentially replaces a conventional boiler in a power plant
(see Figure 4).
The power generation and auxiliary equipment is com-
p1ete1y conventional except for the draft fans. Since the bed depth is
2 to 3 feet, the pressure loss over the fluidized bed combustor is
somewhat higher than that over a conventional boiler.
Operating at elevated pressure, a fluidized combustor requires
a compressor to pressurize the air and to overcome the pressure loss
over the fluidized bed combustor. At an "operating pressure of 10 to
15 atm and fluidizing velocity of 8 ~o 12 ft/sec, a depth of 8 to 15
feet is required to accommodate the heat transfer surface in the bed;
the pressure loss. over the bed is thus 4 to 8 times as large as that
over an atmospheric bed. The pumping energy, however, is actually less
because of the greater density of the gas at high pressure. Energy can
be recovered from the high-temperature gases by passing them directly
into a gas turbine and expanding them to atmospheric pressure as shown
in Figure 5. This expansion lowers the temperature of the gases by 600
to 80QoF, thereby reducing the amount of surface required to recover
heat from the combustion gases leaving the fluidized bed."
The pressurized fluidized bed combustion boiler functions,
therefore, in conjunction with both gas and steam turbine generators
to produce electrical energy from coal or oil. In addition to the major
14
-------
Evaporator
Superheater
Evaporator
Air
Forced Draft
Fan
. Induced Draft Fan ~
Economizer -. t
Particulate Removal~
Dwg. 29651103
Stack
Sulfate Ash
15
IV
Generator
Steam
Turbi ne
Feed Water Pump
Fig. 4 -Atmospheric fl uidized bed combustion power plant
Lime
Coal
-------
Dwg. 2920A67
Sorbent
Regenerator
Sulphate, Ash
~
I
Li me Coal :
L - - - - - ~ - ~ - --...J
Generator.
Steam
Turbi ne
Air
Compressor
Fig.5 - Pressurized fluidized combustion power plant
16
Sulfur RecO\,,,ry
Unit
I
+
. Sulfur or
Sulfuric Acid
-------
power plant equipment shown in Figure 5, additional process equipment
may be included to regenerate the sorbent utilized in removing sulfur
compounds from the combustion gases and to recover the sulfur in useful
form either as elemental sulfur or sulfuric acid.
Along with the choice of operating variables, including pres-
sure, and the implied choice of an overall power plant configuration,
the design of a fluidized bed combustion boiler system requires the
choice of a number of important hardware design parameters and features.
The heat transfer tube diameter, spacing, manifolding,and orientation
in the walls of the enclosure in the fluidized bed, and in the passages
conveying the combustion gases from the bed, must be specified. A
decision must also be made on whether baffle tubes should be incorporated
to minimize the splashing of solids into the freeboard above the bed.
At the same time, the location of tubing for the various func-
tional sections of the boiler -- pre-evaporator, evaporator, superheater,.
and reheater -- must be designated. And a decision is required on whether
the evaporator will depend on natural circulation and employ steam drums
or on forced convection; and on whether the evaporator will use
recirculation or once-through flow.
The dimensions of individual fluidized beds and the orienta-
tion of multiple beds which may be employed in a large boiler are also
critical design factors, primarily because of their effect on ducting
and manifolding for air and combustion gases; for fuel, sorbent, and
ash; and for water/steam flows.
All of these hardware parameters and features affect signifi-
cantly the boiler design, its appearance, and operation.
The cost of
the boiler, however, probably depends more on the choice of operating
variables, including pressure, than on specific hardware .design.
In addition to the boiler, a fluidized bed stearn/power genera-
tion system design requires the selection of auxiliary equipment, includ-
ing a possible sorbent regeneration and sulfur recovery process and a
layout of all plant equipment.
17
-------
This report describes the design and evaluation of three flui-
4ized bed combustion boilers.
For each of these boilers, a choice of
overall concept, operating variables, hardware configuration,' and auxiliary
equipment has been made.
These choices were based on the boiler appli-
cation -- whether industrial or utility -- on operability, on effective-
ness, and on economics.
~ith each design.
Their justification is discussed in connection
The primary potential advantages of a fluidized bed boiler
power plant are:
. Reduced volume and modular construction.
Because combustion rates
are more intense in fluidized beds than in the fire box of a pul-
verized fuel furnace, and because heat transfer surface can be
placed in the bed, fluidized bed boilers are more compact than
conventional coal-fired boilers.
Boiler modules can be fabricated
in shops and assembled at a power plant site. Considerable econo-
mies are possible in the fabrication and erection of fluidized bed
combustion boilers.
. Reduced heat transfer surface requirements.
Because heat transfer
coefficients are an order of magnitude greater in fluidized beds
than in the fire box of a conventional boiler, less heat transfer
surface is required in the boiler.
In a pressurized boiler less
heat is extracted from the combustion gases after they leave the
fluidized bed because. they are cooled by expansion in the gas tur-
bine. Further large reductions in heat transfer surface are thus
possible.
. Reduced steam tube and turbine blade corrosion/erosion and fouling.
Because the fluidized bed boiler operates at a maximum combustion
temperature far below that in a conventional boile~, volatiliza-
tion of alkali metal compounds and fusion of ash is reduced or
eliminated. Sulfur and vanadium compounds are removed from the
combustion gases by the sorbent.
The corrosion/erosion and fouling
of steam tubes and turbine blades is thus minimized.
Under these
conditions, higher steam temperatures and pressures may become
18
-------
economically feasible and greater efficiency in power generation
may be achieved. Somewhat greater efficiencies can also be achieved
in pressurized fluidized bed combustion by using gas turbines with
high inlet temperatures.
. Reduced fuel costs and increased flexibility. Because fluidized
beds can readily burn crushed coal (fine grinding is not required),
coal with a high ash content, and a variety of miscellaneous
combustibles (from sewage sludge, minicipa1 solid wastes, paper
mill liquid wastes, and oily wastes to residual oil and natural
gas), boilers using such beds can utilize cheap fuels and a wide
variety of fuels to generate power and steam.
. Reduced emissions of S02 and NOx' Because a limestone/dolomite
sorbent can be utilized in a fluidized bed combustor, S02 reductions
of 90 to 95% can be economically achieved. The low combustion tem-
perature at which the bed operates minimizes the formation of NO
x
by fixation of atmospheric nitrogen. Production of NO by oxida-
x
tion of nitrogen in the fuel can be minimized by limiting the
percent of excess air added in the bed or by operating the bed at
high pressure.
The boiler designs and performance evaluations presented in
this report and the experimental work carried out under the OAP fluidized
bed fuel processing program confirm these advantages of fluidized bed
combustion boilers.
19
-------
PRELIMINARY SURVEYS
To execute boiler designs and evaluations, market information
on boiler applications as well as technical information on fluidized
bed combustion had to be gathered.
data were needed to establish:
The market and other background
. Functional specifications as a basis for boiler (or gasifier)
designs.
Boiler capacity, steam conditions, efficiency,
operational features such as percent turndown, and dynamic
response are all established by custOmer requirements.
In
addition, fuel is chosen on the basis of availability, cost,
and convenience.
Finally, government regulations establish
maximum levels of pollutant emissions -- SO NO, and
2' x
particulates -- for the boilers employing the selected fuel.
. A basis of comparison.
The performance and cost of the
fluidized bed combustion boiler systems must be compared with
alternative systems in order to evaluate the likelihood of
their use.
. The impact of a successful fluidized bed combustion boiler on
air quality and on economical steam/power generation.
The degree
of impact is dependent upon how widely such boilers are used.
Fluidized bed combustion can be appropriately applied to new
or replacement boilers, but not to the modification of existing
boilers.
Thus, to justify the effort and expense of developing
a new boiler technology with improved pollution abatement
potential, it must be established that there is a sufficient
market for new boilers.
21
-------
The technical information necessary to boiler design specifications,
performance, evaluations, and impact determination was obtained through
the following types of surveys:
. Two market surveys:
one of industrial boilers and the other of
utility power plants.
These surveys provided information on
both past and projected boiler sales, as well as on boiler
capacities and supply pressure and temperature.
. A fuel survey.
This resulted in historical data on fuel usage
in both industrial and utility boilers.
Evidence concerning
fuel availability and estimates of present and future fuel
prices were also collected and examined.
. A survey of 502 removal systems for cleanin~ combustion
products of conventional boilers. A number of proposed systems
were evaluated as part of this survey with regard to their
effectiveness and economy.
A conventional boiler with a
limestone wet scrubber for removal of 502 and particulates
was then selected as a basis of comparison for the performance
of the fluidized bed combustion boilers to be designed in this
proj ecL
. An emission standards survey.
The government is establishing
standards for limiting 502' NOx' and particulate emissions
from boilers. Thus, projections of what these definitive
standards will be were used in setting functional specifi-
cations for the fluidized bed boiler designs.
Results of the various surveys are referenced throughout this
report, but a summary of the most significant data they yielded follows:
22
-------
MARKET SURVEYS
Industrial Boiler Installations
Historic data for the industrial water tube boiler market are
shown in Table 2 along with boiler capacity sales predictions through
1985.
Certain trends are clear:
. The total capacity of industrial boilers installed each year
is increasing by about 4%.
. The number of new coal-fired installations is sharply
decreasing and gas-fired installations are increasing.
. The average capacity of new boilers has increased from about
60,000 lb/hr to 75,000 lb/hr in the past seyen years.
fired boilers are 30% to 60% larger than the average.
Coal-
The approximate operating life of an industrial boiler is
30 years. A conservatively low estimate of the existing total industrial
. . 9
boiler capacity is 1.2 x 10 lb/hr; the accompanying total annual fuel
cost is about $2.5 billion.
The potential pollution control and economic benefits of a
successful fluidized bed combustion industrial boiler are difficult to
assess accurately.
However, a tentative picture of the advantages of
this type of boiler over other industrial boilers can be derived from
several facts and observable trends. Although purchasers of industrial
boilers are currently avoiding S02 and particulate (but not NOx)
emission problems by using natural gas or low-sulfur oil, the supplies
of such fuels are limited and their costs can be expected to rise.
(These points will be elaborated upon later.)
In fact, it has already
been announced in certain areas of the United States that there is not
enough
natural gas available for new industrial customers.
There may,
therefore, be a need for a low-cost packaged industrial boiler with a
steam capacity up to 250,000 lb/hr which will burn coal in such a way
23
-------
TABLE 2
ANNUAL ~ALES OF INDUSTRIAL WATER
TUBE BOILERS IN THE UNITED STATES
-' , PROJECTIONS (a)
1963 1964 1965 1966 1967 1968 '1969 1970 1.975 19BO 19H~
TOTAL CAPACITY SOLD, LB/HR x 10-650.5 72.3 76.9 ,81.4 57.3
Coal-fired 10.0 14.1 12.1, 5.8 4.3
Oil-fired 12.3 16.0 17.4 18.6 11.4
Gas-fired 20.2 29.6 34.6 45.2 34.8
Other(b) 8.0 12.6 12.8 11.8 6.8
67.0 78.0 68.4
4.1 2.1 2.4
15.6 13.3 17.9
'39.6 47.8 39.3
7.7 14.8 8.8
103.0
127.0 154.0
N
.j::-
. .
TOTAL NUMBER SOLD
Coal-fired
Oil-fired
Gas-fired
Other (b)
879 1033 1055 1165 839 908 1043 861
125 131 104 78 45 32 20 15
263 297 296 323 189 194 202 231
409 490 561 680 557 617 743 578
82 115 '94 84 48 65 78 37
FOB Costs of a, Packaged Industrial Boiler:
Coa1--$2.00-2.50 per Ib/hr up to 60,000 Ib/hr (above thisfie1derection
at $5.5~ per Ib/hr without 502 control system).
Oil, Gas--$2.00 per Ib/hr up to 250,000' Ib/hr for low sulfur fuel.
(a) P. .
. rOJ ect10ns by Erie City Energy. '
(b) Includes bagasse, black liquor, bark, waste, etc.
-------
as to minimize 802' NOx' and particulate emissions. Design work indicates
that the fluidized bed boiler is indeed more compact than the conventional
coal-burning boiler and thus can be packaged in sizes up to 250,000 lb/hr.
And, although the estimated capital cost does not appear significantly
lower than a conventional boiler system with wet scrubbing, the
fluidized bed boiler is effective in pollution abatement.
Emissions of 802 from a fluidized bed boiler can either be
reduced by a solid absorbent -- such as CaO or dolomite -- in the bed, .
or by using a desulfurized char fuel which may be even cheaper.
of such a fuel would eliminate (or minimize) the use of a solid
adsorbent and the problem of its disposal or regeneration.
Use
Fluidized bed combustion ~vith staged addition of air may also be
effective in reducing NO. Particulates may also pe more readily
x
removed from stack gases since they are generally larger than particles
from pulverized fuel combustion; are not sintered so wear of cyclones
and mechanical collectors should be minimized; and have a high carbon
content which may improve the operation of electrostatic precipitators.
Thus, fluidized bed industrial boilers may be effective and economical
in air pollution control if natural gas and low-sulfur oil rise in cost
and if supplies of a desulfurized char become readily available,
eliminating the need to depend on a solid absorbent for pollution
control.
Utility Boiler Installation.
Predictions regarding utility boiler generating capacity --
total as well as for new installations -- are presented in Table 3.
The new installations are further broken down into:
. Base-load plants operating with a load factor greater than
80% employing fossil fuel boilers.
. Intermediate-load plants with a load factor around 45% also
operating with fossil fuels and a boiler.
25
-------
TABLE 3
ELECTRIC UTILITY GENERATION ADDITIONS
I~ GW MARKET SUMMARY 1970~1985
1970 1971-1975 1975 1976-1980 1980 1981-1985 1985
TOTAL ADDITIONS TOTAL ADDITIONS TOTAL ADDITIONS TOTAL
BASE LOAD
Coal 87.4 10.5 97.9 30.3 128.2 2.1 130.3
Oil 21.1 1.3 22.4 4.9 27.3 27.3
Gas 45.5 3.4 48.9 48.9 48.9
Total Fossil 154.0 15.2 169.2 35.2 . 204.4 2.1 206.5
Nuclear 5.3 62.1 67.4 70.1 137.5 130.9 268.4
Hydro 25.0 25.0 25.0 25.0
N . ImE'RMEDIATE
0'\
Coal 51.7 30.4 82.1 45.7 127.8 73.7 201.5
Oil 10.4 8.7 19.1 15.2 34.3 5.3 39.6
Gas 21.3 12.8 34.1 . .7.6 41.7 41.7
Total Fossil 83.4 51.9 135.3 68.5 203.8 79..0 282.8
Nuclear 7.6 7.6 26.3 33.9
Hydro 23.6 2.5 26.1 2.5 28.6 2.5 31.1
PEAKtNG
Inter.Comb
& G'. T. 21.8 '30.9 52.7 11.4 64.1 37.8 101.9
Hydro 7.3 15.1 22.4 18.2 40.6 15.0 55.6
TOTAL
CAPACITY 320.4 177.7 489.1. 213.5 711.6 293.6 1005.2
-------
. Peaking plants operating with a load factor of less than 20%
operating with gas turbines.
The most obvious market for fluidized bed combustion boilers is the one
now predicted for the base- and intermediate-load fossil-fired plants;
this market is expected to increase by 25% from 67 gigawatts in the
period 1971 to 1975 to 81 gigawatts in 1980 to 1985. If the fluidized
bed boilers are effective in air pollution control and if their capital
and operating costs are sufficiently low, they may capture an additional
share of the generation market now ceded to nuclear base-load
plants.
Higher plant efficiencies might be possible with increased
. ,
steam temperature and with pressurized boilers with combined gas-steam
turbine cycle.
to 10 x
A gigawatt
106 lb/hr of
400 tons/hr.
of power generating capacity is roughly equivalent
steam generating capacity and a coal consumption
rate of
The present utility boiler market is therefore
larger than the industrial boiler market by a factor of 2 in terms of
capacity and by a factor of 7 in terms of money. Utility boilers
also present a more serious problem in air pollution abatement.
Pur-
chasers of the smaller industrial boilers are turning to natural gas and
low-sulfur oil fuels.
Because of coal's low cost and availability (des-
pite recent problems of mining it in sufficient quantities), coal remains
I -
a ?rime fuel for the utilities.
Most of the coal available to power
plants in the eastern United States has a sulfur content which exceeds
the limits placed by S02 abatement regulations. A 1000 megawatt
(1 gigawatt) plant burning 3.0% sulfur fuel produces 24 tons/hr of S02'
fluidized bed utility boiler which can economically absorb this pollu-
A
tant (permitting the recovery of sulfur) while minimizing the production
of NO and particulates can be greatly beneficial in reducing air pollu-
x
tion since about one half of the 502 emissions and one quarter of the
NO emissions are attributed to electric power generation by the
x
utilities.
27
-------
Functional Boiler Specifications
In addition to examining the past and future demand for
industrial and utility boilers, the market survey also considered
potential customer's requirements. Figures 6 through 10 show capacity
and steam conditions for future industrial and utility boiler markets.
The largest portion of the industrial boiler market will be
supplied by units in the capacity range of 150,000 to 250,000 lb/hr
(see Figure 6); this latter size is the largest which can be factory
assembled and shipped as a package.
A fluidized bed boiler can be
more compact than conventional pulverized fuel boilers or a boiler with
a spreader stroker.
However, it is probably no more compact than
conventional packaged gas- or oil-fired boilers.
.The steam conditions
of pressure and temperature in general show' a broad range of preference
(see Figures 7 and 8). About two-thirds of the boilers have steam
pressures below 600 psi and temperatures below 750°F.
The largest share of the fossil-fired utility boiler market
will be supplied by units in the 400 to 600 megawatt range (see
Figure 9 ); a number of waste-heat recovery boilers in the 100 to 200
megaw~tt range may also be purchased to operate in conjunction with
gas turbines in combined cycle power plants.
Both supercritical boiler
units operating around 3600 psi and subcritical units operating
around 2400 psi steam pressure will continue to be popular with
customers (see Figure 10).
Table 4 summarizes the information on functional requirements
used in establishing specifications for the industrial and utility
fluidized bed boiler designs.
The final designation of specifications
is discussed in subsequent sections dealing with the detailed boiler
designs.
28
-------
Curve 594987-A
45
~ 40
"'
"'C
-
0 35
V)
>-
+-'
u
~30 rn
CtJ
u
~
Q)
- 25
.-
0 Lt'\ 0
CO r- 00
0' 0<
CtJ r-I r-I
:J 20
c
c
o. Lt'\ 0 r-I 0
"' I 0 I ('t"\
Lt'\ r-I
N 0 I 0 0 0
o 0 0
o 0 0 0 0 0
o "' 0 "' 0 0 0
\0 0 r-I r-I"' "' ..
N .. 0 r-I r-I
r-I r-I Lt'\ Lt'\ U"\
Lt'\ r-I N ('t"\
Boiler Capacity Range, Ib steaml h r
Fig. 6 -Projected distribution of U. S. industrial
boiler sales - steam generating capacity
29
-------
~
Curve 594988-A
45
40
..
~ 35
V)
~
:; 30
co U'\O
c.. r- 00
co 0- 0-
:: 25 ~ ~
co
:::J
C
C
« 20
co
......
o
~ 15
o
c
o
=B 10
co
'-
u..
rn
5
o
~ 0-
~ 0- ~ ~
0- N
~ N U'\ 00 ~ ~
~ I I I
I
0 0 0 0 0
K) ~ U'\ U'\
o Lt'\ - 00 N
~ ~
Boiler QperatingPressure Range, psig
Fig. 7 -Projected distribution. of U. S. industrial
boiler sales" operating pressure
30
-------
Curve 594989-A
45
40
~
-0' 35
-
0
(/)
>-
- 30
u
(tJ
a.
(tJ
U 25 rn
-
(tJ
::J
c:
c: 20
« Lt'\ 0
(tJ r- co
- 0-0-
~ ..............
15
-
0
c:
0 10
.-
-
u
(tJ
"-
u..
5
o
"-
-0 q- q- ~ q- q- q- q- Q)
Q) N N r- N r- N ::>
- Lt'\ \0 0
(tJ r- r- co . co 0-
"- I , " "
::J '
- ~ K) K) K) Lt'\ K) Lt'\ B)
(tJ r- r-
V') Lt'\ \0 r- r- co co
Boiler Operating Temperature Range, of
Fig. 8 -Projected distribution of U. S. industrial boiler sales
- operating temperature
31
-------
2
o
Under 100
100
20
V)
.....
~ 18
::
~
0")
.-
0") 16
UJ
~
..
"'C
o
.~
~ 14
c-
O")
.=: 12
:....
=:J
o .
"'C 10
0'
V)
~ 8
u
~
0-
~ 6 ooga
0-. 0-
:.... ...-I ...-I
Q) I I
-. 4\0...-1
.0 r- 00
a) 0-.0-
...-I ...-I
-
~
.....
o.
t-
C,urve 594986-A
200
400 '500 600 ,700 800 900 1000 1100 1200 '1300 1400 1500
Boner Capacity,. megawatts
300
Fig. 9 -Projected U. S. utility boiler sales - steam generating capacity" :
-------
tf!. 60
"t:I
0
VI
>.
-
u 50
rtJ
c..
rtJ
U
'-
IV
0
co 40
-
rtJ
::J
c:
c:
«
rtJ
w - 30
w ~
-
0
c:
0
-
U
rtJ 20
'-
u..
70
Curve 594984-A
10
/""-./ \/ - ~OO psig . ,/"'
/ \ /\ //"""- /-'
-_I \/ \. / .
, V'
. ---., .
. .........,\ " .', /1500 - 2199 psig -.--
I \ " ....."'"
I . .
I \' \ ,;'/
. \, \ ;----.#'
I \, \ .,
I . .
I \ I "
\ I \ /
V \,.........., ./0 - 149.?_E~~~----------
--~------- -
------------
.--
...--
.--
\
\
.
\
\
\
.,...---.-
1970 71
72
73
74
83
84
75 76 77 78
Year of Installation
80
81
82
85
79
Fig. 10 -Projected distribution of U. S. utility boiler installations - steam pressure
-------
TABLE 4
FUNCTIONAL SPECIFICATIONS FOR
FLUIDIZED BED COMBUSTION BOILERS
DEVELOPED BY THE BOILER MARKET SURVEY
INDUSTRIAL BOILER
UTILITY BOILER
CAPACITY
Maximum
350-500 x 103 1b/hr
150-250 x 103 1b/hr
25 x 103 1b/hr
Most Frequent
Minimum
STEAM CONDITIONS
w
~
Size Range MW
Pressure psig
150-600
(sa t - 77 5 )
Temperature of
PERFORMANCE
Efficiency %
86
SPECIAL REQUIREMENTS
Turn~own .
1/3
Overpressure & Flow
Dynamic s
Start-up, Shut-down
Pressurized
Operation
No
TV Viewing
Packaged Construction
No
Pr ef err ed
1u . :i- 'ue1 Ca >abi .i :y
Not usua . .y demanc ed
1300 MW
500-700 MW
100 MW
< 300
1800
950/950
500-800
2400
1000/1000 .
89-92
1/4 (1/2)
5% on each
5%/minute
Automatic
Yes
Yes
< 800
3600
1050/1050
)esirec
Unfeasible at present, but desi~ed
-------
FOSSIL FUEL SURVEY
The proven recoverable fuel reserves available for possible
use in U. S. boilers are shown in Table 5. The actual economically
recoverable reserves of these fossil fuels may be as much as 2 to 3
times the proved values.
Domestic oil and gas reserves are in relatively
short supply:
their prices can be expected to increase especially if
foreign developments hinder the free flow of oil to this country.
Thus, it appears likely that industrial and utility boiler operators
will ultimately be required to utilize coal or a fuel derived from
coal.
Coal is the most plentiful source of fossil energy.
Slightly
over half of the coal energy of the United States is found in deposits
east of the Mississippi Rive~ and most of this coal has a sulfur
content of 2.5 to 4.0% by weight.
Predicted costs of fossil fuels are summarized in Table 6 and
Figure l~. These IS-year projections are highly speculative; unexpected
technological, economic~ environmental, or political developments may
invalidate them.
The price of coal has been based on estimates of
production costs for labor, materials, and equipment.
Recent health
and safety measures and labor unrest have decreased productivity in
deep mines by an estimated 20% in the past two years, and it .is difficult
to assess how productivity will fluctuate in the future.
It is equally
difficult to assess the effects of environmental concerns on the cost
of coal from strip mines.
With all these uncertainties the price of
coal is expected to double in the next 15 years.
The price of oil, residual or crude, for boiler fuel has been
based on what the utility customer will pay for oil in competition with
other fossil fuels, primarily coal.
The price of natural gas has, for many years, been based on
government regulations.
But now gas is a premium fuel in short supply;
its exploration and development costs are rising.
The production of
gas from liquid petroleum products and from coal is about to commence.
35
-------
TABLE 5
ENERGY RESERVES AND UTILIZATION
U. S. RESERVES (a)
ESTIMATED ANNUAL U. S. CONSUMPTION. 1968
Estimated Household
Total and
Proven Recoverable Commercial Industrial Electricity Transportation Total
COAL 9 265 3200 0.02 0.21 0.27 .0.50
tons x 10
. PETROLEUM 9 46 145-590 1.2 0.8 0.2 2.5 4.7
UJ
0\ bbls x 10
GAS 290 850-2400 6.3 9.0 3.1 0.6 19.0
MCF x 109
(a) .
U. S. Bureau of Mines estimate. Future consumption patterns will depend on government
regulation, which may restrict the use. of gas by utilities in order to meet household,
commercial, and industrial clean fuel needs; oil import; environmental regulations;
avai1abi1ity;and production costs.
-------
. TABLE 6
ELECTRIC UTILITY FUEL PRICE PROJECTIONS 1971-1985
STEAM COAL
DEEP-MINED MINE-MOUTH
Year ~/MMBTU Index
1968 16.7 100.00
1969 17.8 106.58
1970 21.3 127.54
1971 26.2 156.88
1972 30.0 179.64
1973 32.0 191. 61
1974 33.4 200.00
1975 34.2 204.79
1976 35.3. 211. 37
1977 36.6 219.16
1978 37.9 226.94
1979 39.2 234.73
1980 40.6 243.11
1985 48.6 291. 01
-----------------------------------------------------------------------------
RESIDUAL OIL
DEEP WATER PORT CONTRACT CARGOS
(1968 High Sulfur Resid. Price = 100.00)
High Sulfur Resid. Low (1%) Sulfur Resid. 0.3% Sulfur Resid.
Year ~/MMBTU Index ~/MMBTU Index ~/MMBTU Index
1968 32.0 100.00
1969 34.0 106.25
1970 46.0 143.75 72.0 225.00
1971 43.0 134.37 60.0 187.50 75.0 234.37
1972 43.5 135.93 . 61.0 190.62 76.0 237.50
1973 44.0 137.50 64.0 200.00 78.0 243.75
1974 44.5 139.06 67.0 209.37 82.0 256.25
1975 45.0 140.62 70.0 218.75 85.5 267.18
1976 45.5 142.18 72.0 225.00 88.5 276.56
1977 46.0 143.75 73.0 228.12 90.0 281.25
1978 46.5 145.31 74.0 231.25 91.0 284.37
1979 47.0 146.87 74.5 232.81 92.0 287.50
1980 47.5 148.43 75..0 234.37 93.0 290.62
1985 50.0 156.25 .77.0 240.62 94.5 295.31
-------------------------------------~----------------------------------------
37
-------
TABLE 6 (cont'd.)
-----------------------------------------------------------------------------
CRUDE OIL
DEEP WATER PORT CONTRACT .CARGOS
(1971 High Sulfur Crude Price = 100.00)'
High Sulfur Crude Low (1%) Sulfur Crude ,0.3% Sulfur Crude
Year ~/MMBTU Index .~/MMBTU Index ~/MMBTU Index
1968
1969
1970
J.971 50.0 100.0 56.0 112..0 72.5 .145.0
1972 51.5 103.0 . 58.0 116.0 75.\0 150.0
1973 53.0 106.0 59.5 118..0 77.0 154.0
1974 54.5 109.0 61.5 123.0 79.5 159.0
1975 55.5 111.0 63.5 127.0 82..0 164.0
1976 57..0 114.0 65.5 131.,0 84.0 168.0
1977 58..5 117..0 67.'0 134.0 86.0 172.0
1978 ,60.0 120.0 68.5 137.0 87.5 175.0
1979 61.0 122.0 69.5 139.0 88.5 177.0
1980 62.5 125.0 70.5 141. O' 89.5 179.0
1985 69.5 139.0 76.0 152.0 93..0 186.0
-----------------------------------------------------------------------------
NATURAL GAS
ELECTRIC 'UTILITY 'PRICE
~/MMBTU
Year
Index
1968
.1969
1970
1971
1972 .
1973
1974
1975
1976
1977
1978
1979
1980
1985
25.1
25.4
27.0
35.0
45..0
55.0
65.0
72.0
77.0
80..0
.83...0
:85..0
87.0
97.0
100.00
101.19
107.56
139..44
179.28
219.12
258.96
286.85
306.77
318.72
. .330.67
338.64
346.61
386.45
38
-------
Curve 645771-A
110
100
90
80
70
:::>
I--
~OO
~
~
50
40
30
20
10
0
1970 1975
Jet-Kerosene
No.2 Diesel
Natu ral Gas
0.3% 5 Resid
0.3% 5 Crude
1% 5 Resid
1% 5 Crude
High 5 Crude
High 5 Resid
Mine-Mouth Coal
1980
1985
Year
Fig. 11- Electric utility fuel price projections 1971-1985 actual dollars
39
-------
Importation of liquified natural gas is being considered.
For these
reasons gas costs are expected to rise sharply in the next 15 years,
and gas may not be available to the operators of large industrial or
utility boilers.
Transportation costs for fuels are given below in Table 7.
These indicate that coal and gas cannot be used economically in large
utility boilers distantly located from the source of supply.
TABLE 1
COMPARATIVE TRANSPORTATION COSTS
FOSSIL FUELS FOR ELECTRIC UTILITIES
COAL --
UNIT TRAIN
Under 300 Miles
Over 600 Miles
~4.00~/million Btu/lOO miles
~2 .OO~/million Btu/IOO miles
.. GAS
48" PIPELiNE
1.50~/million Btu/lOO miles
RESIDUAL OIL
Large Tankers
Large River Barges
O.30~/million Btu/lOO miles
0.60~/million Btu/lOO miles
A careful consideration of all the technical, economic, and
political factors involved in the choice of fuel supply indicates that
utilities will use fossil fuels for generating about 60% of the electric
power in 1985 as seen in Table 8. Although it is much more difficult to
predict what type of fuel will be preferred for industrial boilers,
it seems likely that most operators will continue to use clean fuels,
gas, and low-sulfur oil.
In all cases, however, a vital factor in the
choice of fuels and the economics of steam and power generation will be
pollution abatement.
40
-------
TABLE 8
PROJECTED ELECTRIC ENERGY PRODUCTION BY STEAM:
RELATIVE SHARE ACCORDING TO FUEL
RELATIVE SHARE OF ELECTRIC UTILITY STEAM GENERATION
FUEL 1969 1970 1975 1980 1985
KWH x 109 % KWH x 109 % KWH x 109 % KWH x 109 % KWH x 109 %
.I:-- COAL 793.1 60.9 858.8 60.1 1101.7 50.0 1252.5 42.3 1396.1 34.4
......
GAS 354.6 27.2 371. 5 26.0 461.7 21.0 536.0 18.1 625.4 15.4
OIL 135.3 10.4 135.7 9.5 177.6 8.1 239.5 8.1 394.5 9.7
FOSSIL 1283 98.5 1366 95.6 1741 79.1 2028 68.5 2416 59.5
NUCLEAR 19 1.5 63 4.4 461 20.9 933 31.5 1648 40.5
TOTAL 130'2 100 1429 100 2202 100 2961 100 4064 100
-------
SURVEY OF ALTERNATIVE MEANS OF S02 POLLUTION CONTROL
A number of stack gas processing systems have been proposed
for S02 removal. Current first-generation processes evaluated were
Combustion Engineering's dry lime wet scrubbing process,Chemico's
wet scrubbing process, and Monsanto's catalytic oxidation process.
Second generation processes were also considered:
Wellman Power Gas,
Esso-B&W dry adsorbent, Consolidation Coal potassium formate, Stone &
Webster-Ionics electrolysis, and Atomics International molten carbonate.
These systems have been considered for possible use in electric power
plants with conventional coal-fired boilers.
Some of these systems
are either ready, or nearly ready, for commercial application; some
require additional development and testing.
In general, the capital costs of the systems are comparable
to the cost of the utility steam generator itself -- $3S/kW.
Most of
the processes claim the 80 to 90% S02 removal required by today's air
pollution abatement goals. However, it is not clear how many of them
can economically accomplish the 90 to 98% removal which may be
required as the use of coal in power generation increases.
The lime/
limestone wet scrubbing processes have received the major
effort.
A number of units are being tested on full-scale
development
, 1 t. (8 )
power p an s.
from $40 to
Capital costs range from $20 to $50/kw for new plants and
$80/kw for retrofit on existing plants. Operating costs are projected
to be from 0.3 to greater than 1 mill/kw-hr. These costs are for
60 to 80% 802 removal. Alternative systems, e.g., Monsanto catalytic
oxidation, are reported to be more expensive.
These stack gas clean-up processes are unlikely to be
economical for industrial boilers.
Scaled down to a size corresponding
to a 250,000 lb/hr steam boiler, their cost would be in the range of
$1.50 to $3.00 per lb/hr, greater than the cost of the boiler itself.
42
-------
If fluidized bed combustion boilers are more effective in air
pollution control and lower in cost than conventional boilers plus
stack gas clean-up equipment, then they may well capture a sizeable
portion of the predicted market.
EMISSION STANDARDS SURVEY
Federal New Source Performance Standards reflect the degree of
emission reduction which (taking into account the cost of achieving such
reduction) the Administrator of EPA determines has been adequately
demonstrated.
The Standards of Performance for fossil fuel-fired steam
generators of greater than 250 million Btu per hour heat input have
been promulgated and in part are as follows:
S02
6
1.2 lb S02/l0 Btu
0.8 lb SOz/106 Btu
6
0.70 lb NOZ/lO Btu
0.30 lb NOz/l06 Btu
0.20 lb N02/l06 Btu
0.1 lb/l06 Btu
(solid fossil fuel)
(liquid fossil fuel)
NO
x
(solid fossil fuel)
(liquid fossil fuel)
(gaseous fossil fuel)
Particulate
(all fossil fuels).
However, looking to the future, the ultimate goal of control
achieved by any advanced fuel processing concept must be aimed toward
higher levels of control, which (looking to the future) will be consis-
tent with the meeting of Ambient Air, Quality Standards in all Air Quality.
Regions without necessarily restraining the growth capacity of power
required for the area. A second goal is that the advanced technology
have reduced costs so that higher levels of control can be possible at
a lower power cost than present-day power plants with present-day control.
It is reasonable that such advanced technology would be applied to enhancing
the present Federal New Source Performance Standards.
As a first basis for design of the coal-fired fluid bed
combustion power plants the following criteria were used:
43
-------
802
NO
x
<
1 lb 802/106 Btu
6
0.2 lb N02/l0 Btu
'6
down to 0.02 lb/10 Btu.
Particulate
The emission criteria include all emission sources from the
power plant:
coal drying, boiler, sorbent regeneration and sulfur
recovery.
44
-------
ASSESSMENT OF FLUIDIZED BED COMBUSTION
Specifications and design concepts were established for indus-
trial and utility fluidized bed combustion boilers. Preliminary designs,
performance projections, and cost estimates were prepared on the basis
of the specifications and compared with conventional systems..
SPECIFICATIONS
The design specifications for industria~ and utility fluidized
bed combustion boilers are based on
. Market requirements
. Environmental control requirements
. Fluidized bed combustion experimental
. Related technology experience.
data
Functional, operating, and
represent an assessment of
and a basis for reasonable
design specifications are established. They
present information to provide constraints
first-generation designs.
However, they
must be viewed flexibly since data are not available to permit optimiza-
tion of the parameters. The specifications do not incorporate advanced
functional, operating or design characteristics which are considered
feasible for more economical second-generation designs.
Functional Boiler Specifications
Functional specifications for industrial and u~ility boilers
are based on the market survey results, the projected environmental
control requirements, and power cycle studies. The functional specifi-
cations for an industrial boiler, an.atmospheric pressure utility
boiler, and a pressurized utility boiler are summarized in Table 9.
The limestone and dolomite analyses are presented in Table 10 below
45
-------
TABLE 9
FUNCTIONAL SPECIFICATIONS FOR FLUIDIZED BED COMBUSTION BOILERS
ATMOSPHERIC PRESSURE PRESSURIZED -~
INDUSTRIAL UTILIT UTILITY
CAPACITY 250,000 Ib steam/hr 300 & 600 MW 300 & 600 MW
STEAM CONDITIONS 600 psig/7500F 2400 psig/10000F/10000F 2400 psig/10000F/10000F
GAS TURBINE Simple cycle with 10:1
pressure ratio without
compressor intercoo1ing
FUEL Pgh. #8 bituminous coal Pgh. #8 bituminous coal Pgh. #8 bituminous coal
4.3%.S 4.3% S 4.3% S
S02 REMOVAL AGENT Limestone 1359 Limestone 1359 Dolomite 1337
TURNDOWN CAPABILITY > 4:1 > 4:1 > 4:1
;j::-
0' RESPONSE RATE, %/MIN > 5 5 5
POLLUTION ABATEMENT
TARGETS
Sulfur Dioxide,
1b SO/106 Btu < 1 < 1 < 1
Nitrogen Oxides,
Ib N02/l06 Btu . < 0.2 < 0.2 < 0.2
Particulate,
1b/106 Btu < 0.1 < 0.1 < 0.1
down to 0.02 down to 0.02 down to 0.02
502 REMOVAL SYSTEM Once-through' Regeneration and once- Regeneration and once-
through through
BOILER EFFICIENCY, % > 85 88-92 88-92
-------
and in the coal specification list on the following page.
TABLE 10
LIMESTONE AND DOLOMITE SPECIFICATIONS
COMPONENT
WI % AS RECEIVED*
Dolomite 1337 Limestone 1359
Ti02
SrO
Na20
K20
Mn02
0.78 0.85
0.15 0.30
0.25 0.17
45.0 1.07
53.0 97.0
0.02 <0.05
<0.03 0.07
<0.02 <0.02
<0.1 <0.1
<0.03 <0.05
Si02
A1203
Fe203
MgO
CaO
*Coutant, R. W., J. S. McNulty, R. E.
and E. H. Lougher; "Investigation of
Dolomite for Capturing S02 from Flue
Institute). .
Barrett, J. J. Carson, R. Fisher,
the Reactivity of Limestone and'
Gas," Aug. 1968 (Battelle Memorial
The capacity and steam conditions are based on the market survey
projections and technical assessments.
A high-sulfur bituminous coal was
selected as the fuel. This fuel is representative of coals used in the
fluidized bed combustion experimental program and of coal-fired power
plants, except for the high sulfur content. A limestone and a dolomite sor-
bent were selected for the designs.
The two stones have been used in the
experimental fluidized bed combustion prbgrams. The boiler turndown capa-
bility of 4:1 is specified bn the basis of the market survey. The pollu-
tion abatement targets are based on projected control requirements for S02'
NO , and particulates. Once-through limestone or dolomite throw-away and
x
regenerative/sulfur recovery processes are considered for the sulfur removal
system. The industrial boiler designs incorporate once-through processes.
Both concepts are considered for the utility boilers. Boiler efficiency
targets are specified, based on current coal-fired boiler capability.
47
-------
1,__-
COAL SPECIFICATION
OHIO PITTSBURGH NO.8 SEAM COAL*
SAMPLE:
(washed)
Run of Mine - As Received
PROXll1ATE ANALYSIS (wt %):
ULTIMATE ANALYSIS (wt %):
(includes moisture)
GROSS HEATING VALUE:
NET HEATING VALUE:
ASH ANALYSIS (wt %):
FUSIBILITY OF ASH:
PARTICLE DENSITY:
GRINDABILITY (Hardgrove):
FREE SWELLING INDEX:
Moisture
Volatile Matter
Fixed Carbon
Ash .
3.3
39.5
48.7
8.5
100.0
C
H
o
N
S
Ash
71. 2
5.4
9.3
1.3
4.3
8.5
100.0
(~60% organic; ~40% pyritic)
13000 Btu/lb
12500 Btu/lb
Si02 45.3
A1203 21. 2
Fe203 27.3
Ti02 1.0
P205 0.11
CaO 1.9
MgO 0.6
Na20 0.2
K20 1.8
S03 0.7
100.1
Initial Deformation Temperature
Softening Temperature .
Fluid Temperature
2080 of
2230°F
2420 of
Coal
Ash
~1. 4 gm/ cc
~2.8 gm/cc
50-60
5-5.5
*Source of data:
USBM, Pittsburgh, Pa.
48
-------
Operating Specifications
Operating conditions for the fluidized bed combustion boilers
were projected from available data(9). The conditions are summarized in
the following specifications list.
OPERATING SPECIFICATIONS
FOR FLUIDIZED BED COMBUSTION BOILERS
PRESSURE, ATM
BED TEMPERATURE, of
Primary beds
Carbon burn-up cell
1 and 10
GAS VELOCITY, fps
PARTICLE SIZE, INCHES
EXCESS AIR, %
Primary beds
1300-1750
1900-2000
5-15
> - 1/4
Carbon burn-up cell
BED DEPTH -- EXPANDED, FT
10
> 30
Atmospheric pressure
Pressurized
< '\,5
< '\,
Ca/S RATIO
6
Pressure:
Atmospheric pressure and pressurized operation are
considered.
Ten atmospheres is used for the pressurized system to corres-
pond to state-of-the~art gas turbine technology.
Bed Temperature: ,The range of temperature for the primary bed
is limited by sulfur dioxide removal.
The carbon burn-up cell tempera-
ture is established to achieve high carbon burn-up, ~ 90%.
Gas Velocity:
Fluidized bed combustors have operated at super-
ficial gas velocities up to 15 fps. Higher velocities are considered
feasible and desirable to achieve compactness and minimize coal distribu-
tion problems. However, .they result in higher particulate carry-over,
the need for larger particles -- which affects tube spacing design in the
bed, and lower limestone/dolomite utilization. Gas velocities greater
than 2 to 5 fps are necessary to minimize the cross-sectional area of the
beds.
Advanced concepts have been proposed to overcome these problems
49
-------
and take advantage of higher velocities to make boiler designs more com-
pact. The present concepts are based on experimental superficial velo-
cities up to 15 fps.
Particle Size: The particle size is based primarily on the
gas velocity. Limestone/dolomite utilization and particle carry-over
are also considered for each design.
Excess Air: Excess.air for the primary beds and carbon burn-up
cell is ~10% and> 30% respectively. These levels are selected to
achieve combustion efficiencies of approximately 90% in the primary bed
and> 90% in the carbon burn-up cell.
Bed Depth: Bed depth for atmospheric-pressure operation is
limited by fan technology. The maximum design pressure drop which can
be used with a forced draft fan is ~100 inches H20 for air flows near
100,000 cfm. The gas-side pressure dro?, excluding the fluidized bed and
gas distributor, is 10 to 15 inches H20. This permits an expanded bed
depth up to 5 feet with an allowance for the distributor of 30% of the
bed pressure drop.
However, the power requirement to overcome 100 inches
water back pressure is excessive (~3000 HP for 75000 cfm).
The design
bed depth depends on an assessment of fan cost, power requirements, and
boiler performance and cost as a function of bed depth.
Expanded bed
depth for pressurized operation is set at approximately 15 feet. Deep
beds can be used with the pressurized system with very little penalty
from the increased pressure drop. Deep beds minimize problems of coal
feeding, sorbent recirculation, and steam piping. Beds ~eeper than 15
feet are not consiq.ered for the present design concept in order to avoid
large height to diameter ratios, potential fuel and temperature distribu-
tion problems, and incorporation of multiple boiler functions in the same
bed.
Advanced concepts have been proposed to overcome these problems
and achieve a more economical system.
Ca/S Ratio:
A calcium to sulfur molar ratio of 6 is used for
the boiler designs burning a .4% sul~ur coal.
This includes fresh make-up
stone plus the calcium oxide from regenerated stone.
Data are not avail-
able at all the projected operating conditions.
Available data were
50
-------
reviewed and a Ca/S molar ratio projected which accounts for differences
between the experimental conditions and the proposed design conditions.
These differences include the type of operation -- regeneration vs once-
through; operating conditions -- e.g., bed temperature, bed depth, gas
velocity; and scale of operation. Lower sulfur fuels, more reactive
stones, and operating conditions selected for optimum sulfur removal will
reduce the stone requirement of six times the stoichiometric ratio.
Operat-
ing conditions for optimum sulfur removal may increase boiler cost but
reduce the solids disposal problem.
Design Specifications
Design specifications for the boiler systems were based on
available data and technical assessment under the. proposed operating con-
ditions.
The specifications are summarized on the next page.
The design philosophy for all the boiler designs is to maximize
shop fabrication and standardization of boiler components in order to
minimize cost. The industrial boiler design is such that primary
modules can be shipped by rail -- dimensions within 13 ft x 16 ft x 40 ft.
Selection
of
boiler tube materials is based on conventional practice.
Preliminary evaluation of boiler tube material test data in fluidized
bed combustors indicates that conventional tube materials can be used.
Preliminary test data on a pilot unit with a test cascade and vendor
data on particulate collection indicate that gas turbine blade erosion
and corrosion will not be a' serious problem in the pressurized utility
plant. A fluid bed to boiler tube heat transfer coefficient of
50 Btu/hr-ft2_0F is assumed for the boiler designs on the basis of data
from six experimental fluidized bed combustors. The heat transfer coef-
ficient for tubes above the bed, but still in the splash range of bed
2
material, is assumed to be 30 Btu/hr-ft ~oF. More data are required for
accurate design of heat transfer surfaces above the bed and in the free-
board.
Particle carry-over data are not available for combustion of coal
in limestone or dolomite beds operating at velocities of 10 to 15 fps with
continuous recycle of the stone.
A design basis was selected using the
51
-------
DESIGN SPECIFICATIONS
FOR FLUIDIZED BED COMBUSTION BOILERS
CONSTRUCTION
Maximum shop fabrication and stan-
dardization
BOILER TUBE MATERIALS
Conventional tube materials
GAS TURBINE (PRESSURIZED
UTJ;LITY PLANT)
Conventional. blade design and
materials
HEAT TRANSFER COEFFICIENT,
Btu/hr-ft2_0F
Tubes in Bed
Tubes above Bed in
Splash Zone
50
30-40
PARTICLE CARRY-OVER, grains/SCF
7-15
COMBUSTIBLE LOSS, %
Pressurized Boiler
1-1. 5
Atmospheric pressure
Boilers.
1-2
COAL FEED DISTRIBUTION
2
1 feed point per 10 ft
52
-------
available carry-over data on fluidized bed combustion systems and an
assessment of solid feed size distributions, attrition, and rate of
entrainment for the proposed operating conditions. Dust loadings of
7 to 15 grains/SCF are projected. Combustible losses of 1 to 2% are pro-
jected from the experimental data. The coal feed system design is based
on data obtained in a 5-foot diameter bed study. Results indicate that
coal feed points should be located one for each 10 square feet of bed area.
INDUSTRIAL BOILER APPLICATION
The application of fluidized bed combustion to industrial. steam
generation was studied in the light of the functional, operating, and
design s~ecifications and design concepts outlined. Initial boiler plant
concepts concentrated on systems which incorporated sorbent regeneration
processes(10). However, the problems of providing and operating industrial
sorbent regeneration and sulfur recovery processes for industrial users.
appear to make this concept impractical for a small industrial application.
Regeneration may be practical if a large on-site or off-site regeneration-
sulfur recovery facility is available. Two fluidized bed boiler plant
concepts were developed which incorporate once-through limestone systems.
Preliminary boiler plant designs were prepared for these two systems on
the basis of the specifications and material and energy balances for the
systems.
Operating procedures were developed and boiler plant performance
projected.
Capital and ope~ating costs are based on industrial boiler
practice and the estimates compared with conventional industrial boiler
systems.
Design
An industrial fluidized bed boiler plant preli~inary design
was prepared which includes all equipment between the following terminals:
inlets to the economizer, coal feeder, limestone feeder, and stack; out-
lets from the ash silo and superheater~ The design is based on the speci-
fications presented on pages 45-52. The components of the system are
53
-------
illustrated in Figure 12 and include:
. Steam generator
. Economizer
. Coal and limestone feed systems
. Pollution control
. Waste solids handling system
. Instrumentation and controls.
Steam Generator
The atmospheric pressure fluidized bed industrial steam genera-
tor design concept is shown in Figure 13. The steam generator comprises
two separate shipping modules:
. The primary module is the main combustion unit and consists of four
fluidized beds containing I-inch diameter horizontal tubes in the
bed with a 6-inch horizontal, 3-inch vertical diamond spacing. The
beds are not separated by water walls. Horizontal particle baffle.
screens using I-inch tubes on 3-inch centers are located above the
beds.. A recirculation pump provides the forced circulation of water
through the tubes. Tube-free volumes are located between the sub-
merged surface and grid (12 inches) and the submerged surface and
baffle screen (8 inches). Freeboard above the beds is open to. pro-
vide easy access to the boiler.
The four beds are within a water-
wall shell but are not divided by water walls.
Air is fed to each
bed from a divided plenum. A bubble cap air distributor is used with
coal feed points every 10 square feet. The primary module is
10 ft x 14 ft x 40 ft.
. The secondary module contains a carbon burn-up cell, superheater
section, and convection pass. High carbon content solids (up to
~50% carbon), which are carried over from the primary module, are
fed to the carbon burn-up .cell. . The solids are removed from the
gas leaving the primary module by cyclones.
The solids are pneu-
matically transported to the carbon burn-up cell bed, and the gases
pass over the bed, combining with flue gas from the. bed. The car-
54
-------
Air
VI
VI
Coal -
From Storage
Limestone-
F rom Storage
Superheated Steam.- - --
.
Feed
System
I
I
I
I
---+-_J
To
S tac k
Dwg. 2965A04
------
FI uidized Bed
Steam
Generator
Economizer
I
I Ash and
+ Spent Limestone
I
I
I
I Particulate
I Removal .
I . .. To
L - - .-i - ~ -. Disposal
r~
'0 - - . . . Feed W at e r
Fig. 12 -Industrial fl uidized bed boiler system
-------
111111
41'
Superheater
Area
Secondary Module
7' Primary Module
~ 9'6"
/"1
;r
13' 9"
1
Section Thru
Convection Zone
\\\\~
f\)'b~ ",
C;,\t'b~ f'
~t\
\\~
, "
15 7
f\)'b~
\\~t \\~
\ f\ ~~
~\\\~
~;~
Section Thlru
Supef'heater
Natural Circulation
At Walls & Forced
Circulation For The
Horizontal Tubes
\.
- '.' .;:~.~-;~~. i\: ~!.,' ;~", ,
..~~.;.., 'i...:,,£:;,..,.,.,~.;..:,...,
!...~ . ,- - - .- .-~'~~~- 7.7*' j'L,,:"
----- - --..-
--
Fig. 13-Industrial FI uidized Bed Boiler Design
-------
bon burn-up cell is sectioned into four water-walled beds to
provide for boiler turn-doWn.
These beds are operated parallel
to the fuel burning beds in the primary module. Flue gas from
the carbon burn-up cell and primary cyclones pass through the
'superheater section, which is a conventional design. The super-
heat represents ~ 15% of the heat output in the steam.
Heat from
the flue gas is then recovered in a convection pass to a level
where only one heat trap (economizer) is needed.
module is 8 ft x 15 ft x 40 ft.
The secondary
The steam generator design and operating characteristics are
summarized in the next matrix.
Economizer
An extended surface economizer (or feed water heater) is used
to recover sensible heat in the gas leaving the convection pass. This
selection is based on a study of heat trap costs which included tubular
and regenerative air heaters and bare and extended surface economizers.
Coal and Limestone Feed Systems
Coal and limestone are received from storage, crushed to
-1/4 inch, mixed, and fed to 32 solids feed points in the primary module.
Commercial equipment is available to feed coarse coal against the 50 to
70 inches water design pressure and to monitor the feed rate. The prob-
lem is to achieve a uniform feed rate to a large number of feed points.
A schematic of the coal feed system selected is shown in Figure 14.
The crushed coal is transferred to a feeding hopper and then
to a moving belt gravimetric feeder with adjustable belt speed for
different feed rate control.
Limestone flow is controlled prior to
mixing with the coal on the gravimetric feeder.
The coal and limestone
from the gravimetric feeder drop into a four-way splitter to divide the
coal into four equal streams, one for each bed, with an individual shut-
off valve for each stream.
However, no individual control of coal feed
59
-------
FLUIDIZED BEb BOILER DESIGN AND OPERATING CHARACTERISTICS
Industrial
CAPACITY
Steam, 1b/hr
Conditions
250,000
600 psig, 750°F.
DESIGN FEATURES
Wa.ter Circulation
For<:ed~ & natural circ~lation'
MODULES
Number/unit
Beds/unit (inc. CBC)
Bed Orientation
2
5
Horizontal, in-line
HEAT TRANSFBR SURFACE
MRANGmENT
Horizontal
Tube Size" in.
BED DEPTH, ft
1
2.5
10-12.5
GAS VELOCITY, fps
BED TEMPERATURE, of
Design Point
Part Load
1650
> 13 00
CBC
PARTICLE SIZE, in.
1900-2000
- 1/4
EXCESS AIR, %
Primary Beds
CBC
10
50
23.6
Total
CONTROL METHOD
SULFUR REMOVAL STONE
Scheme and Ca/S Ratio
Bed temperature and bed shut-off
Limestone
1.
2.
wet scrubbing, 1.2
once-through, ~ 6
60
-------
Dwg. 2963A25
Li mestone
Bu nker
Vibrati ng .
Li mestone
Feeder ,/
Bu nker for
Crus hed
Coal
Coal Feeder
Primary Splitter /
(split into 4 streams)
......
Boi I er
/
I
4 Seconda ry Splitters......"
(s plit into 32 strea ms) - --
32 Coal Injectors
(one for each stream)
/' "-
.!
y
~--/
Air
Fig. 14 -Coal feed system
61
-------
rate for each stream is possible.
Each stream of coal is again equally
split into eight separate portions, one for every coal feed point, by
using a vibrating table.
bed.
The coal is then fed
pneumatically into the
Coal drying is also accomplished in the coal feeding system
by using preheated sealing air. No condensation of moisture in the coal
feeding lines is expected.
The tight enclosure in the feeding system
will prevent venting of sulfur dioxide or particulates into the atmos-
phere during this,drying operation.
Each individual coal feeder is a "straight-in", replaceable,
design forming a 300 angle with the distributor plate to facilitate the
maintenance and replacement of a coal feede~ even during partial boiler
operation.
Pollution Control Systems
Two sulfur dioxide-particulate control systems were developed.
Both systems use the same steam generator design, but incorporate
different sulfur dioxide and particulate control concepts. Flow schema-
tics of the two concepts -- once-through dry limestone and wet scrubbing
-- are shown in Figures 15 and ~16.
The once-through dry limestone system has fresh limestone fed
to the fluidized bed boiler. The sulfur dioxide is removed in the boiler
and the spent stone withdrawn for dry disposal. The system is designed
to handle limestone at six times the stoichiometric calcium to sulfur
feed ratio. This is to provide S02 removal with a 4% S coal. Final
particulate removal is achieved by an electrostatic precipitator designed
for 99.5% efficiency.
The wet scrubbing system provides an alternative sulfur dioxide
control scheme which avoids the use of large quantities of limestone.
The limestone is fed to the fluidized bed boiler, where the stone is
calcined. Some sulfur removal occurs in the bed. The calcined stone,
CaD, is mixed with water to form a slurry and pumped to a wet scrubber.
The wet scrubber is designed to remove the S02 and particulates from
62
-------
r.-'----
I
I
I
I
i
Dwg. 2957A32
"..
Stack
Legend
---------
.0'\
<...>
-- -
,
L_____-
Convection
Zone
-.--
Ash To
Disposal
Super-
Heater
r--
I
I
I
t
I
i
I
I
I
!
-L
Gas
----
Sol ids
Li mes tone
J I , ,
, , , ,
Carbon
Burnup
Cell
Fluid-Bed
Combustor
----
------
Fresh Limestone Feed
. To Di sposal
Fig. 15 - System Schematic - Once Through Scheme
-------
'"
.p-
Gas
Solids
Li mes ton e
Slurry
I
...
I
I
I
I
Stack I
,
-------
Stack Gas
Heater
r----------------
I
I
i
I
,
I
J
L ~'----- --
Legend
----
~ ~ , , , , ,
/,/,/,/
-----
----
Convection
Zone
-----
------------,
- - - - - -,.- - - --,
I
L___-
Super-
Heater
r--
i
i
(
J
I
...
I
I
I
j
i
-1-,
Make-Up Water &
Recyc led Li quo r
Dwg. 2957A31
.K- °1
.
J
.
I
.
f
.
I
.
I
.
1
.
I
~
.
I
.
f
.
1
"
r
..
'.~'.f1
Scrubber
~
..
To Waste
Pond or
Vacuum Filter
Carbon
Bu rnup
Cell
Fluid-bed
Combustor
-----
Mix
Tank
Fig. 16 - System Schematic - Wet Scrubbi ng Scheme
-------
the gas. A stack gas reheater may be required, depending on the tempera-
ture, emission levels, and necessity of avoiding a water vapor plume.
The limestone requirement for the wet scrubbing system is projected
to be only 1.2 times the stoichiometric calcium to sulfur ratio to achieve
the same S02 control.
Water Solids Handling System
There are two solids handling systems in the dry solids system:
one for transporting carbon-rich solids from the primary cyclones to
the carbon burn-up cell, and the other for transporting solids from the
fluidized beds from underneath the superheater and from the electro~
static precipitator to disposal. A pneumatic transport system is used
in all cases. The wet scrubbing system has to provide for the disposal of
a filter cake containing about 50% water.
Controls and Instrumentation
The overall boiler control is divided into three subdivisions
-- the combustion control, the feedwater flow control, and the steam
temperature control. The basic control principles for the fluidized bed
boiler are similar to those for any subcritical recirculating boiler.
Combustion Control System
Steam drum pressure is the load-sensitive control element and
is used to initiate the fuel feed.
Combustion air is fed to a common
plenum by the forced draft fan with the plenum air pressure kept con-
stant by the inlet vanes which are positioned by the signal from the
fuel/air ratio setter. Individual dampers control the combustion air
flow to each individual primary bed and each individual section of the
carbon burn-up cell.
Feedwater Flow Control System
Feedwater and steam flow signals are compared. If a difference
occurs, a signal is sent to the feedwater flow control. The steam drum
65
-------
level is compared to a set point., If a difference exis:ts,. a; signal is.
sent to the feedwater control. system.
Steam Temperature Control System
The outlet. steam' temperature signal- is' compared: to a set p,oint.
The'resulting error signal is' combined with', the steam' flow signal. The.
combined.. signal is. passed through" a steam' temperature. attemperator. hand~
auto st'atibn:., to. a spray flow cont,rol. valve.
Operation~
Start-Up.
The. boiler, is. started: up fIrst by.. firing. an auxiliary' gas. burner
above the' bed to raise' boiler' pressure to. on":,,line. conditions (i'. e. ,
600 psig and 489'?F). Then the bed material: is~ heated' up, to. minimum"
coal inj eC.tion temp.erature (I\, 800°Fi) by inJection! of' auxili.ary' gas.. fuel'
into the minimally fluidized bed. Only the. first~ofthe,four. beds and the
first; of the four' sections' in the carbon, burn-up; cell. (CBC) are. start'ed.
this way.. The start-:-up,' of the other beds and the other sec.t,ions can
rely on solid recirculation. from the adjacent operating" bed.. to. rais,e
the bed temperature., Once the bed reaches. the. minimum coarinjection.
temperature,. the coal feed is started, and. the load is ihcreased~
Load Control
Load. control. in die industrial. boiler, is, achieved' by adjl,lstment'.
of the bed.. temp.erature and turning- on' and off the fluidized.: beds. Change
of bed. temperature alone can, provide: up, .to 30% or.. 50% load:, reduct.ion in
a. single b'ed.~. depending' on whether: the once"" through . dry.- solid;, or,' wet
scrubbing system is employed'~. Turning: b'eds of,f- can" provide, a, turn-:-down
ratio. of at, least. 4: 1'. for: the entire, boiler:~.
The' b.ed. temperature:. in the. CBC: is.. kept'. constant~ during. turn"7'
down for. efficient. carbon burn:-up.., The proposed" design, divides the
GBC into four. separate. sections,;, each, corresponding.:. to. a; p,rimary. bed.
66'.
-------
Turn-down by shutting down a bed would require shutting down the corres-
ponding section in the CBC. The bed temperature in the CBC is kept
constant during turn-down by decreasing the excess air.
Normal Shut-Down
When removing one bed from service, the coal feed is shut off
first while fluidizing air is maintained to burn the residual coal in
the bed and to prevent the deposit of coal in the pneumatic transport
lines.
After the residual coal is burned out, the bed temperature starts
to drop,and the fluidizing air can be shut off. However, the recircula-
tion water flow through the immersed horizontal tubes will be maintained
throughout the operation.
For shutting down the entire boiler, one fuel-burning bed
section is shut down at a time. The cooling rate is limited to avoid
undue thermal stresses. A cooling rate of 100°F per hour, the same as
the heating rate, is recommended. The recirculating pump is kept running
until the steam generator is cooled to below 200°F and is ready for
draining.
Emergency Shut-Down
Emergency situations such as loss of combustion air flow, loss
of recirculation pump, loss of fuel feed, loss of steam drum water level,
sudden burn-out of bed tubes, and loss of bed fluidization, and their
remedial procedures are discussed in Volume II.
Performance Characteristics
Overall Boiler Efficiency
The comparison of total boiler efficiency between once-through
dry solid and wet scrubbing systems is presented in Table 11 .
The wet
scrubbing system has higher boiler efficiency because the stack gas
temperature in the present design is 132°F, compared to 350°F in the dry
67
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TABLE 11
COMPARISON OF BOILER PERFORMANCE BETWEEN ONCE-THROUGH
DRY SOLID AND WET SCRUBBING SYSTEMS
Loss due to calcination and S02 absorption
Loss due to water and hydrogen in fuel
Loss due to unburned carbon
Dry Solid (%)
2.74
3.80
1.93
1.50
Loss due to radiation and unaccounted for
Loss due to evaporation in wet scrubber
0-
00
Loss due to flue gas sensible heat
6.61 (350°F
Flue Gas)
Total Loss
Overall Boiler Efficiency
16.58
83.42
Wet Scrubbing (%)
0.56
3.83
2.05
1.50
4.84
1.30 (132°F Flue
Gas)
14.08
85.92
-------
solid system. An additional efficiency loss of about 5% in the wet
scrubbing system is expected if the flue gas is to be heated up from
132°F to 350°F.
Draft Losses
A summary of draft losses for both the once-through dry solid
system and the wet scrubbing system is presented in Table 12 and a
comparison of corresponding power requirements for both systems is
estimated in Table 13 .
Air Pollution Abatement Capability
The projected control capability of the industrial fluidized
bed boiler for NOx' 802' and particulate is summarized in Table 14.
NO emissions from the industrial boiler are expected to be in the ,range
x . 6 6
of Z5~ ppm (0.40 lb NOZ/lO Btu) to 500 ppm (0.81 lb NOZ/lO Btu) ,
compared to ~550 ppm from a conventional spreader stoker. 80Z removal
depends primarily on the amount of limestone fed and is expected to
be >90% for the once-through dry solids system. For a wet scrubbing
system, the 80Z removal efficiency is expected to be ~85%. For a coal
containing 4.3 wt % sulfur, the 80Z emission is in the range of 350 to
500 ppm (0.80-1.13 lb/106 Btu). For the once-through dry solids system,
the particulate loading in flue gas is expected to be less than O.OZ
gr/8CF. The particulate removal efficiency of the present wet scrubber
design is ~98%.
~oiler Plant Costs
The capital costs for the two industrial boiler plant designs
are summarized in Table 15. The costs were prepared by Erie City
Energy using their standard boiler pricing procedures and vendor quotes
on auxiliary equipment. Operating costs are summarized in Table 16.
69
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TABLE 12
DRAFT LOSSES
Dry Solids System
Inches W.G.
Wet Scrubber System
Inches W.G. .
Fluidized Bed & Forced
Draft Ducts 26.7 26.7
Mechanical Collector 5.0 5.0
Convection Pass, Economizer,
and Flues 10.9 10.9
Precipitator 0.7
Scrubber 16.2
TOTAL 43.3 58.8
TABLE 13
COMPARISON OF POWER REQUIREMENTS(a)
Dry Solids Wet Scrubber
System System
Forced Draft Fan, HP 700 950
Recirculating Pump, HP 200 200
Coal Crusher, HP 60 60
Slurry Pumps, HP 150
Total Power Requirements, HP g60 1360
Power Requirements % of Output(b) 0.86 1.21
(a) Only major operating horsepower
(b)Where a horsepower hour is 2544
Btu per hour.
requirements are shown.
Btu and output is 289 million
70
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TABLE 14
AIR POLLUTION CONTROL CAPABILITY
OF INDUSTRIAL FLUIDIZED BED BOILER
Dry Solid System
Wet Scrubbing System
NO Emission
x
ppm
Ib/l06 Btu (as N02)
250-500
0.40-0.81
250-500
0.40-0.81
S02 Emission
ppm
1b/106 Btu
350 (90% removal)
0.80
350-500
0.80-1.13
Particulate Emission
gr/SCF
1b/106 Btu
0.01-0.05
0.02-0.08
0.01-0.05
0.02-0.08
71
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TABLE 15
CAPITAL COSTS FOR INDUSTRIAL FLUIDIZED BED STEAM GENERATION
Crusher
Fuel System (Not including bunkers
and system upstream of bunkers)
Forced Draft Fan
Fuel System Sealing Fan & Heater System
"-I
N
Steam Generator System, Recirculating
Pump and Economizer
Ash Handling System
Mechanical Dust Collector
Wet Scrubber System
Dewatering
Electro-Static Precipitator
. Controls
TOTAL
SPECIFIC COST $/lb steam/hr
18,000
99,000
1.18
6.50
Once-Through
Wet Scrubber S stem
Total Installed % of Total
Cost Cost
18,000 0.96
99,000 5.35
59,000 3.19
22,000 1.19
848,000 45.79
150,000 8.10
45,000 2.43
400,000 21.60
120,000 6.48
91,000 4.91
1,852,000
7.40
40,000
22,000
848,000
2.62
1.44
55.64
255,000
45,000
16.73
2.95
106,000
91,000
6.96
5.98
1,524,000
6.10
-------
TABLE 16
OPERATING COSTS FOR INDUSTRIAL
FLUIDIZED BED STEAM GENERATION
Once-Through Once -Through
Dry Solids System Wet Scrubbing System
~/106 Btu ~/106 Btu
Capital Charg~9 (a) 12.70 15.40
Fuel Cost 30.00 30.00
Labor 9.00 9.00
Limestone (b) 9.70 2.10
Power 1.10 1.50
Solids/Slurry Disposal (c) 13.50 13.50
TOTAL
76.00
71. 50
(a) Capital
(b) $3/ton.
(c) $5/ton.
charges at 16.7% per year, 70% load factor.
73
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Evaluation
Industrial fluidized bed combustion boilers were evaluated
by assessing their effectiveness for economy of steam generation, effec-
tiveness for pollution abatement, market projection and the status of
technology. Capital and operating costs were projected for alternative
fluidized bed combustion systems based on the two preliminary designs.
The costs for three alternative coal-fired fluidized bed combustion sys-
tems and for gas-and oil-fired fluidized bed combustion systems are pro-
jected in addition to the once-through wet scrubbing and dry limestone
systems. Costs for the two coal-fired systems are projected to include
regeneration of the limestone, and costs are projected for using low~sul-
fur coal or char in the fluidized bed boiler.
The cost estimates for the
coal-fired fluidized bed boiler were used to project the costs for gas-
and oil-fired fluidized bed combustion boilers. The costs of these sys-
tems are compared with the cost of conventional coal-and oil-fired indus-
trial boiler alternatives in Tables 17 and 18.
All of the systems burning
high-sulfur fuel are based on similar air pollution abatement: 70 to 90%
removal of 802' 0.02-0.1 lb particulates/l06 Btu, 0.4-1.0 lb N02/l06 Btu.
The steam costs presented in Table 18 are very dependent on fuel, lime-
stone, and waste disposal costs. These costs for each system will depend
on plant location, fuel policies, environmental regulations, fuel sulfur
content, limestone activity, and politics. The steam costs presented
serve to illustrate the various component costs.
The cost estimates show:
. Capital cost of a once-through dry limestone fluidized bed boiler
is 20% less than a conventional spreader stoker with wet scrubbing
or the fluidized bed limestone scrubbing scheme.
. The fluidized bed limestone scrubbing scheme and once-through dry
solid scheme are comparable to each other in total steam cost and
competitive with a spreader stoker with wet scrubbing, with costs
varying less than 10%.
74
-------
. Limestone regeneration schemes have an approximately 15% cost
advantage over the other systems, if a large sulfur recovery
facility is available on-site or off-site.
. A spreader stoker burning low-sulfur coal is more expensive than
one burning high-sulfur coal with wet scrubbing for S02 removal
because of the high cost of low-sulfur coal.
. Although the capital cost of the field-erected oil- or gas-fired
boiler is substantially less than other systems, the total cost
is competitive with other systems, again, because of the high
fuel cost currently quoted for the Northeastern United States.
. The capital cost of oil- and gas-fired boilers is 55 to 70% less
than coal-fired boilers.
. Gas- or oil-fired fluidized bed boilers are not economical.
The
::-
gas-or oil-fired fluidized bed boiler modules, excluding the fuel
feed system and carbon burn-up cell, are basically unchanged from
a coal-fired unit. Thus, significant cost reductions in going from
coal to gas or oil, which are realized in conventional boilers, are
not projected for fluidized bed boilers.
. A fluidized bed boiler burning the desulfurized char is the most
economical case, if the desulfurized char is available at a cost
per Btu equal to that of high-sulfur coal.
cannot effectively burn char.
Conventional boilers
75
-------
TABLE 17
CAPITAL COST OF COAL- AND GAS/OIL-FIRED INDUSTRIAL BOILER
POLLUTION CONTROL ALTERNATIVES ($/lb/hr)
COAL-FIRED (a)
FLUIDIZED BED COMBUSTION BOILER
(Shop Fabricated)
Desulfurized Char
Low-sulfur Coal
Limestone Scrubbing
Once-through Dry Limestone
Limestone Regeneration
On-site facility
Off-site central facility
5.25
5.25(b)
7.40
6.10
7.75
6.10
GAS/OIL-FIRED
'-I
'"
Clean Fuel
High-sulfur Oil
Once-through limestone
Wet scrubbing
4.00-5.00
. (d)
5.25-5.50(f)
7.00-7.50
CONVENTIONAL BOILER
(Field-Erected)
5.50
7.60
2.44(c)
3.l0(e)
4.50
(a) Costs do not include cost of equipment before coal feeding system, e.g., railhead, bunkers. This
cost is $.25-l.00/lb/hr.
(b) Cost is identical for two processes: calcine stone in boiler and then once-through a wet scrubber;
or remove S02 in bed, externally regenerate stone, and scrub effluent.
(c) Cost for a packaged system would be $2.00/1b/hr.
(d) Either once-through limestone or off-site regeneration.
(e) The percentage sulfur removal in this case will be low.
(f) Limestone calcining in the bed followed by wet scrubbing.
-------
TABLE 18
INDUSTRIAL FLUIDIZED BED BOILER COST SUMMARY
<;/106 Btu
CAPITAL() FUEL LABOR SORBENT(b) POWER SOLIDS/SLURRY TOTAL
CHARGES a COST DISPOSAL(c)
COAL-FIRED
Fluidized Bed Combustion
Desu1furized Char 10.95 (30) 9 1.1 1.90 52.96
Limestone Scrubbing 15.40 30 9 2.08 1.5 13.50 71.5
Once-through Dry Limestone 12.70 30 9 9.69 1.1 13.50 76.0
Limestone Regeneration
On-site 16.20 30 9 1.15 1.5 5.80 63.67
'-J
'-J Off-site 17..70 30 9 3.45 1.5 1.90 58.57
Spreader Stoker
Low- Sulfur Coal 11.50 60 9 1.1 1.90 83.51
High-Sulfur Coal -- Wet Scrubbing 15.90 30 9 2.08 1.5 13.50 72.00
GAS/OIL FIRED
Conventional Field Erected
Clean Fuel 5.10 65 4 0.4 74.50
(a) Capital charge 16.7%
(b) Raw stone $3.00/ton;
(c) $5/ton disposal cost
per yeart 70% load factor; fuel cost $7.50/ton ~ 30~/106 Btu.
regenerated stone $9.00/ton. .
(cost information has varied from $0-10/ton).
-------
The steam cost is highly dependent on fuel cost.
Thus the
relative advantage of the alternative systems will depend on cost and
availability of fuels. The present market indicates that industrial
boilers will probably burn clean fuels. Gas- and low-sulfur oil-fired
boilers provide low capital cost, high reliability, and lowS02' NOx'
and particulate emissions. .
Significant cost reductions do not appear attainable for
industrial fluidized bed boiler designs.
even result in an increase in cost.
The need for NO control may
x
The potential for the application
of fluidized bed boilers for industrial steam generation is not attrac-
tive a~ this time unless:
. Low-cost, low-sulfur char is available
. Clean fuels are not available and the removal of sulfur from
the fuel prior to combustion and/or removal of sulfur as sulfur
oxides from the flue gas proves uneconomical.
ELECTRIC UTILITY APPLICATION
Preliminary designs of two utility boilers were developed:
one carries out combustion at one atmosphere; the other, at ten atmos-
rheres.
52,
and an
The designs are based on the specifications outlined on pages 45-
material and energy balances for the respective power systems,
evaluation of the. alternative concepts.
The steam system used as a basis for the boiler designs is
that from the Hammond No.4 unit of Georgia Power and Light:
Condenser Pressure,. in. Hg
Feedwater Heater Stages
240.0
1000
.1000
3
6
Boiler Pressure, psia
Superheat Temperature, of
Reheat Temperature, of
The heat rate of this plant as a function of its power output is shown
in Figure 17 ; at full load the overall efficiency of Hammond No.4 is 37%.
78
-------
10,000
9800
~ 9600
~
~
--
::1
......
co
~ 9400
......
"'
e::::
......
"'
-------
'-
Pressurized Fluid Bed Boiler Power Plant Design
System Concept
The pressurized fluid bed boiler power plant design is based on
an evaluation of boiler concepts (11-15) , experimental data(13\ and
power cycles(ll~
The system concept for the high-pressure fluidized bed boiler
in a combined cycle plant is shown schematically in Figure 18. Combus-
tion air is supplied by the gas turbine compressor. Coal is crushed and
dried prior to feeding into the bed. The bed material is a sorbent
which removes the sulfur from the products of combustion as the coal
is burned. The bed is maintained at a temperature below the agglomera-
tion point by heat transfer to the steam cycle. The spent dolomite is
regenerated and recycled.
The sulfur released in the sorbent regenera-
tion process is converted to sulfur in a subsequent sulfur recovery
process.
Make-up dolomite is fed in with the coal.
All of the ash from the coal is elutriated from the bed along
with a significant amount of unburned carbon and attrited sorbent.' A
high percentage of the particulates from the primary bed are collected
. . . .., . ." . ,. .. . ..
in the primary separation and fed to a fluidized bed carbon burn-up cell
which operates at a higher temperature and with greater percent excess
than the primary bed. The effluents from the primary bed and the
carbon burn-up cell are blended and passed through a secondary particu-
late removal device to reduce the solids content to the level required
to attain a low erosion rate in the gas turbine.
After expansion through
the gas turbine, the exha~st gases are cooled by two stages of stack
gas coolers. A third-atage particulate removal device may be necessary
to meet stack emission standards. The steam cycle has one stage of reheat
and regenerative feed water heating which is partially in parallel with
the stack gas cooler.
Power Cycle Conditions
Nominal plant capacities of 300 MW and 600 MW are considered.
The design point conditions are summarized in Table 19.
80
-------
- Gas Flow
Solids Flow
+~ Steam Cycle
SuI fur
Rich Gas
Desulfurizing
Agent
Regenerator
~
Ai r
Spent
Desul furizing
Agent
Regenerated
Stone
Waste
Stone
Hake-Up
Stone
Compressor
----- - - -- - -..- ----
P r i mary
Part i cui ate
Remova 1
Fluidized
Bed
Combus tor-
Desul furizer
Carbon
Bu rn-U p
Cel1
Coal
(Oi 1)
Hake-Up
Feedwater
Compressor
Turbine
PQ\olcr
Tur i ne
-EJ
F eed-
water
Heaters
Fig. 18 -Pressurized flu id bed boiler power system
Upper
Stack
Gas
Cooler
- ----G
lower
Stack
Gas
Coo 1 er
0"9. 722B868
Waste
Sol ids
Fi na!
Particulat
Removal
Stack
-------
TABLE 19
POWER CYCLE CONDITIONS
._-~--
Capacity - MW
318 635
Boiler Pressure, psia
Initial Steam Flow, lb/hr
Steam Temperature, of
lnit ial
Reheat
Condenser Pressure, in. Hg
Final Feedwater Tempera-
ture, of
Compressor Air Flow, lb/sec
Gas Turbine Temperature, of
Gas Turbine Pressure Ratio
Turbine Cooling Air
Gas Turbine Pressure Drop
.Excess Air
Stack Temperature, of
Gas Turbine Power, kW
Steam Turbine Power, kW
Net Plant Power, kW
Plant Heat Rate, Btu/kWh
2,400
1,727,020
1,000
1,000
3
578
650
1,600
10:1
5%
3%
10%
275
56,557
270,029
318,485
8,953
2,400
3,454,040
1,000
1,000
3
578
1,300
1,600
10:1
5%
3%
10%
275
113,113
538,400
635,362
8.974
82
-------
,.
Boiler Plant Equipment
A schematic of the boiler plant equipment is shown in
Figure 19 .
Boiler Design:
The boiler design consists of four modules;
the modularized design provides for a maximum of shop fabrication
and assists in meeting the turn-down requirements for the plant. Each
module includes four primary fluidized bed combustors, each containing
a separate boiler function -- one bed for the pre-evaporator, two beds
for the superheater, and one bed for the reheater. Evaporation takes
place in the water walls.
All of the boiler heat transfer surface is
immersed in the beds, except for the water walls.
There is no convec-
tion heat transfer surface since the maximum allowable bed temperature is
less than the state-of-the-art gas turbine temperature. The fluidized
bed combustors are stacked vertically because of advantages in gas cir-
cuitry, steam circuitry, and pressure vessel design to achieve deep
beds. Each module contains a separate fluidized bed or carbon burn-up
cell to complete the combustion of carbon elutriated from the primary
beds.
A-simplified drawing of a module is shown in Figure 20 .
The
318 MW plant module is rail-shippable and can be shop-fabricated. The
635 MW plant module is designed to be shipped in sections, each shop-
fabricated.
Fluidized Bed Combustors:
The primary beds for the 318 MW
plant are approximately 5 ft x 7 ft. The bed depths are approximately
12 feet -- sufficient for the required heat transfer surface. The carbon
burn-up cell (CBC) is approximately 2 ft x 7 ft. The CBC contains
no submerged surface in the bed.
Heat Transfer Surface: The submerged tube bundles are formed
by vertical tube platens or planes, each platen a continuous boiler tube in
a serpentine arrangement. A platen is schematically represented in
Figure 20. The heat transfer surface can be viewed as horizontal tubes.
The pre-evaporator and reheater contain l-1/2-inch diameter tubes; the
evaporator water walls and reheater bed contain 2-inch diameter tubes.
83
-------
Gas Turbine Inlet
Claus
Plant
C02 Sc r ubbe r
. System
00
~
Dwg. 2965A06
[spent Dolomite Hold Vessel s
I 0
~
Pressurized Coal and Make-Up
Dolomite Feed System
...- Dolomite Regeneration
System
.
Pressurized Coal and Make-Up
Feed System
o
4
\ '-- Boiler Modules
~ Primary Cyclones
Gas Turbine Inlet 'J
Secondary Particulate Removal
Fig. 19 -Pressurized fl uidized bed boiler plant equipment layout
-------
~
.
Reheated Steam
Reheater Bed
..
..
Superheated Steam
Superheater Bed
Superheater Bed
Pre.evaporator Bed
Feed Water.
Grade Elevation
D
~
A
110 Ft.
PLANT YJlSEL
SIZE DlA' TER, 0
-
320 mw 12 Ft.
635 mw 17 Ft.
r
10 Ft.
I
,
Fig. 20-Pressurized Fluidized Red Steam Generator Module
- .- --
ELEVATION
-------
i
The horizontal tube rows are 1-1/2 inches apart, in the pre-evaporator and
superheater, 2 inches apart in the reheater, and the tubes are alternately
spaced 7 inches in each row.
Steam Circulation:
Once-through water circulation is employed
to permit the use of horizontal boiler tubes in the beds.
Feedwater
enters the module near the bottom and flows upward through the pre-
evaporator tube bank.
Evaporation starts in the uppermost loops of
this bank, and the mixture of water and steam flows into the first of
four tube wall circuits.
After each circuit the mixture is transported
to the bottom of the next through unheated downcomers.
Thus, the two-
phase flow in heated tubes is always upwards, which prevents phase
separation.
Saturated steam leaves the fourth wall circuit and flows
through the two superheater beds in series and then to the high-pressure
steam turbine.
The steam returns to the reheat bed between the high-
and low-pressure steam turbines.
Air Circuits:
Combustion air is taken from the gas turbine
compressor exit to the pressure vessel and is distributed to the various
beds in the module by an internal manifold formed by the volume between
the water tube walls and the pressure vessel. Air dampers are provided
to control the flow to the plenum chamber below each of the fluidized-
bed distributor plates. The carbon burn-up cell has a separate, direct
air supply connection to the plenum below the bed.
Products of Combustion: The products of combustion from the
primary beds leave the tube wall enclosure through tube screens located
near the top of the freeboard volume.
The flue gases are collected in
a 2 ft x 7 ft exhaust mainfold formed by tube walls with one side common
with the bed enclosure.
in the boiler module.
This is the only convection heat transfer surface
Near the middle of the module, an insulated pipe
carries the flue gases from the water wall passage through the pressure
vessel to the first-stage particulate separator located outside the module.
The flue gases from the carbon burn-up cell are segregated
from those from the primary beds.
A separate insulated pipe leads
87
-------
from the carbon burn-up overhead out through the pressure vessel to
join the primary flue gas pipe downstream of the first-stage particulate
separator.
Solids Handling:
Each primary bed has four injection
points for pneumatically feeding coal into a tube-free space above the
distributor plate. Make-up dolomite is fed in along with coal.
Each bed is equipped with one nearly vertical pipe, at a
point about four feet below the top of the tube bank, which removes the
spent dolomite from the bed for regeneration. Each bed also has one inlet
pipe located about four feet above the air distributor plate for pneu-
matically injecting the regenerated dolomite.
The carbon burn-up cell is similar to the primary beds in that
it has four injection points for the carbon-rich solids collected in
the primary cyclones, one withdrawal pipe for spent dolomite, and one
return pipe for regenerated dolomite.
Dolomite Regeneration/Sulfur Recovery System: A two-step,
reduction/steam - C02 oxidation reaction scheme was selected for
regenerating the sulfated dolomite from the boiler modules. A flow
diagram of the system is shown in Figure 21 .
The spent dolomite from the pressurized fluidized bed boiler
is regenerated to half calcined dolomite, [CaC03+MgO]. Sulfur, recovered
as H2S, is sent ~o a Claus plant where elemental sulfur is produced.
Three main process vessels are required: a coal combustor or gas pro-
ducer, a calcium sulfate reducer, and a hydrogen sulfate generator.
Primary reactions occurring in the coal combustor are:
(1)
C + 1/2 02 + CO
C + H20 ~ CO + H2.
(2)
88
-------
00
\D
Sulfated Stone
from Boiler
Coal
Ai r
Steam
Sol id
Surge
Tank
1st Stage
Regenerator
1/4 CaS04 + (~~)~
1/4 CaS + (C02)
H20
Gas
Producer
Ash
2nd Stage
Regenerator
CaS + C02" H20
- CaCO 3 + H 2S
Regenerated
Stone to Boi ler
Waste
Waste
HZS Ri ch Gas
To Claus Recovery
Compressor
Fig. 21-Pressurized regeneration schematic
Dwgu 6161A03
To Final Particulate
Removal
Turbine Expander
To Stack
CO
2
Enri cher
Flue Gas
-------
The coal combustor can be replaced by a fuel oil or gas-fired burner
operated under reducing conditions.
Calcium sulfate is converted to calcium sulfide in the CaS04
reducer vessel. This vessel operates at 800°C (~1500°F) and ~8 atmos-
pheres pressure.
Reactions occurring in this vessel are:
(3) [CaS04 + MgO] + 4CO -+ [CaS + MgO] + 4COZ
(4) [CaS04 + MgO] + 4HZ -+ [CaS + MgO] + 4HZO
(5) [CaO + MgO] + COz -+ [CaC03 + MgO]
(6) CO + HZO -+ COz + HZ'
Reduced solids flow through a stand pipe leg into the HZS
generator vessel, where steam and carbon dioxide convert calcium sulfide
to calcium carbonate. This vessel, operating at 600°C (llOO°F) and
~lZ atmospheres pressure produces a gas 23% HZS (dry basis). High
hydrogen sulfide in the reactor effluent is thermodynamically favored
by high pressure.
Primary reactions occurring in this vessel are:
(7)
(8)
[CaS + MgO]
[CaO + MgO]
+ HZ0-fC02 -+ [CaC03 + MgO]
+ COz -+ [CaC03 + MgO] .
+ HZS
In addition to the process vessels, two auxiliary systems
are required. Carbon dioxide feed to t~e HZS generator is obtained
by stripping a flue gas side stream in a conventional hot carbonate or
monoethanolamine (MEA) absorber system and regenerating the absorbent by
steam stripping the COZ from it. A conventional Claus plant converts
hydrogen sulfide produced in the HZS generator to elemental sulfur.
Auxiliary Equipment
Solids Handling:
The coal and dolomite handling system includes
conventional receiving, storage and conveying facilities.
Coal and,
make-up dolomite are dried to < 3% moisture in a fluidized bed dryer
and crushed to -1/4 inch in a reversible hammermill. The drying opera-
tion is required for operation of the press~rized feed system.
90
-------
Solids Feeding:
The coal and dolomite pressurizing and feeding
system includes surge bins, lock hoppers, fuel injectors, and pneumatic
transport lines to each bed.
The coal feed system is illustrated in
Figure 22 . A fluidized bed fuel distributor is used to feed and meter
the coal and dolomite to each bed.
Particulate Removal:
The particulate removal system in the
combined-cycle plant with fluidized-bed boilers has three functions:
to recover most of the unburned fuel in the solids elutriated from the
primary beds for recycle to the carbon burn-up cell; to reduce the con-
centration of particulates in the gas stream going to the gas turbine
to a level below that at which turbine blade erosion is a problem; and
to control the emission of particulates to the atmosphere.
The first-stage collector is a conventional cyclone separator.
Four cyclones in parallel are used for each boiler module and are enclosed
in a single pressure vessel.
The second stage collector is a tornado separator of the type
shown in Figure 23 All particles larger than five microns are removed
in this collector.
Two of these collectors are used in parallel for each
boiler module.
Each unit has its own pressure vessel.
The arrangement
of the boiler modules with the first and second-stage particulate
separators is shown in Figure 24 .
Power Generation Equipment
Gas Turbine - Generator:
with the four-module boiler system.
Two gas turbine modules are used
The high-pressure fluidized bed boiler is the combustor for
the gas turbine, so provision must be made in the gas turbine design for
removing the air from the compressor discharge and returning the hot
gases to the turbine inlet.
No industrial and utility gas turbines
manufactured in the United States have external combustors.
In this study of combined cycle plants using fluidized bed
boilers, two Westinghouse gas turbine models have been specified.
In
91
-------
Dwg. 2965A05
B y- Pass to Dead
Storage
Dead Storage'
Coal Bi n
/Belt Scale
Belt Conveyor
Dust Collector
\.D
N
Surge
Bin
--
Storage Injector ~
Pri maryI njector
-
. Fig. 22 -Coal handli ng and feed system schematic
-------
Dwg. 6164A12
Exhaust (Clean Gas)
Inlet ( Di rtyGas)
::::~.::.::::::::
"" " '......
""" '.......
..., .. '.......
~~ ~~~ ~: ~ ~ ~ ~ ~~ ~ ~;::.: ~~:: liii!
Secondary Air Pressure
Maintains High
Centrifugal Action
Secondary Air Flow
Creates Downward
Spiral of Dust and
Protects Outer Walls
From Abrasion
Secondary
Gas Inlet
Dust is Separated From
Gas By Centrifugal
Force, is Thrown
Toward Outer Wall and
into Downward Spi ral
"""""'" ""'"
. . . . . . . . . . . . . . . . . . . .
""'" .
. . . . . . . . . . . . . . . . . .. """'"
Falling Dust is
Deposited in Hopper
. . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
""""" '......,
Fig. 23 - Operation of Aerodyne particulate separator
93.
-------
Dwg. 2965A02
FI ue Gas From
Primary Beds
o
To +-
Turbi ne
I
I
P . I
n mary I
Cyclone9
I
J
I
I
eJ
.r FI uidized
Bed
Boiler
Module
.eJ
1
8
Second
Stage
Tornado
Unit (2)
Fly Ash
Return to C.B.C.
Fig. 24 -Particle collection equipment
94
-------
the preliminary design of a high-pressure boiler for a 318 MW plant,
two Westinghouse W25lA gas turbines are used. In the 635 MW plant, for
which plant layout and cost estimates were made, two Westinghouse W50lA
gas turbines are used. The Westinghouse Small Steam and Gas Turbine
Division made a preliminary design of a modified W50lA gas turbine for
use with a high-pressure fluidized bed boiler and estimated the cost of
manufacturing and developing this modified gas turbine design. The
design is shown in Figures 25 and 26. The gas manifold system has
16 concentric air and hot gas pipes which lead from the unit housing
between the compressor exit and the turbine inlet to two vertical external
manifolds.
Separate connections for the air and the hot gas are provided
at these external manifolds.
A crossover pipe between the two manifolds
is provided for the hot gas. The hot gas pipes terminate at the turbine
inlet in 16 sectors which completely fill the turbine inlet annulus,
thus eliminating the need for an internal hot gas manifold.
An internal manifold with one or more connections may be feasi-
ble for use at turbine inlet temperatures over l600°F.
Such a transition
system could be less complex and possibly less expensive 'than the one
proposed~
However, a substantial amount of development effort would be
required to obtain an adequate internal manifold design for this tempera-
ture level, whereas the external manifold design presented herein is more
nearly a state-of-the-art design.
Stearn Turbines:
The stearn conditions assumed are 2400 psig/
1000°F/lOOO°F and 3 in. Hg back pressure. The stearn turbine for this
plant would be a 3600 rpm tandem compound unit with high-pressure, inter-
mediate-pressure, and low-pressure components.
The low-pressure end
would be four flow exhaust with 28-l/2-inch last stage blades for a 635 MW
plant.
All four boiler modules would serve one stearn turbine with a
rating of 530 MW - 600 MVA.
Stack Gas Coolers:
A conventional heat recovery system is
used to recover the sensible heat from the gas leaving the gas turbine.
The stack gas coolers are used to preheat the feedwater.
95
-------
r-
I=-
$TA~TlNG PACKAGE"
ENCLOSUI
-------
'------
-------
....so- ~I ----.-----------
_--!l/"'I,r . -;{',t. _
-------
Controls and Instrumentation
boiler
plant
A composite flow diagram for the high-pressure fluidized bed
system is shown in Figure 27. The control system for this
is designed to perform the following functions:
. Maintain steam header pressure to the turbine at the desired
value by regulation of the turbine governor valve
. Maintain steam header temperature at the turbine at the desired
value by regulation of the fuel input to the beds
. The boiler feedwater flow is set by the load demand from the dis-
patcher.
Many of the plant subsystems
solid levels in feeder bins.
are automated, e.g., the maintenance of
Other functions are manually controlled,
e.g., the sorbent recycling rate to the beds wherein a monitor sounds
an alarm when the recycle rate is too low or too high.
Details on the
controls for the boiler, boiler auxiliaries, power equip~ent, and lists
of the instrumentation required for control and monitoring are presented
in Volume II.
Plant Layout
United Engineers and Constructors was subcontracted to prepare
a plant layout for a 635 MW pressurized fluidized bed boiler power plant.
A hypothetical site on a large river in the Eastern United States was
assumed. A plot plan and plant elevation are shown in Figures 28
and 29.
A temperature-enthalpy diagram for the pressurized boiler
combined cycle power system is shown in Figure 30. Gas temperatures,
bed temperatures, steam temperatures and tube wall temperatures throughout
the system at full load are shown on this diagram.
It also shows how
heat from the fuel is distributed among each of the boiler functions,
the gas turbine expander, and the heat recovery exchangers.
101
-------
RAil
RAIL
DOLO,"" ITE
RECEIVING
HOPPERS
COAL
5 TOA"GE
61LO
';P00 ToN
oOL.OMITE
SILO
IZpOO TON
r-- TO STACK
Ir~Ul.~'-1~
b~
GAS TUR""... "l
.c'
::t
VI
0/
o
'"
V)
Iu
ii'
3
~
2
ii
~i
I
1
I
-_.!22!&t'.!T~__J
PARTICULAT&.
COL.LECTOR
2:
~I
~ta
I~ITIAL CHARGE
of DOLOMITE
FROM ::
BOILER"'4 ~
-
FROM BOlLE R . 3---
F'RoJw1 SOlLER. 2
-
FROM e.OlL..ER.I-....
SURGE
VESSEL
r---I
SOLI05
I
I REDUCING
I GAS
I
I
GAS
PRODUCE
~3
"oil
8:J
"'a:
2:~
02:
,,0
~U
"0:
<~
~
~ ~
U 1-0
oil..
0..
0...
"'"
>on
0'"
e:8
",0:
,c:~
-,
t
I
I
I
I
I
I
I
----....I
AI
-a
CO,
SCRUBBER
SYSTEM
'{]
HOLDING
VESSEL
FLUE GoAS
FROM
STACK GAS COOLERS
ONr.U)PtR.
BOILER
MODULE.
LIGHT
OIL
"lANK
SOUO~ FROM hT
SlA.4E 5EP1\RATOR
..
MODULE'" 4
TO MODULE ',c>~ 3
TO GAS TURBINE:'
AIR
>
0:
'"
:to)
-a:
0:0
0.1-
g~
0: !
:;;
r------r---------~
I I I
I I ,
I I I
I I I
~
...
0:1
'"
a:
~
0)
6
z
o
u
~
GENERA"TOR
'8"
B"
BO\LER FE EO PUMPS
(TURBINE OfO'lvEN)
l'
~
...J
&Y.PA&S
"e."
l'
~
..J
8.F. PUMPS
"p..o
l'
~
BOOSTER AI R
COM PRE 5S0R
..J
~
'" '"
:!: a:
~ ~
o w
I- "
0: ;!
"
- - - -., uPPeR
Fig. 27
LEGEND
MA.IN~R[HEAl' STM(.E.X~
---- EJl:TfOIACl10M ST[ItI.M .
- ~EEDWATE.R ~ CONO.
- ORAINS
AIR
COltl.L IFP..e'50H DOLOMITE
GAS<'O\L
FLUE "AS
INSTRUMENTATION
REGENERATED DOLOMITE
SPun DOLOMITE
co3S MW FLUIDIZED BED
)01 LER COMBINE.D CYC L£ PLANT
COMPOSITE FLOW DIAGRAM
11 U1IIBd ...l81li8 .--'"
"B'
BOOSTER AIR
COMPRESSOR
B
D
I 0
L- - - ---~I
II
u
u:G~F"LUIi. GA. ro
t
TO C O~
.s c A:u66"E.R.
103
5r,e.c.K
-------
@
z--...
$ '-------->
@
, "
,II
~
':'
o BOilER!> @ CLAUS PLANT & SULFUR LOADING
@ TURBINE BAY @ COl A~50R&EIZS
(}) HE ATE R IlAY @ REGENERATOll5 & .sUR60E VESSE l
38 0 STORAGE 511'15 @ DEAERATOR
0 ADM'NISTRATIO N BLOG;. @ AS~ & DOLOMITE. SILO
I @ F'A2TICULATE REMOYAL EQUIPT @
~ WATER STORAGE TAo.JKS
CD GAS TURBINE GEI.IERATOI?S @ LlG~T OIL TAN I<.
@ ~TACK6ASCOOLER5 @ L'GUTOIL U..LOADINC; PUMP
G) STACI:: @ CII?CULATING WATER INTAIN5) @ CULOlZlNAT'OrJ EQuIPMENT
@ WATER l12EATMENT @ YA121A5LE WOIRS
@ DIESEL GENEIi'ATOI? RCx:>M @ SWITCII VAI2D
@ CONTI?OL 200M @ CONVEYOIIS
@ MACUINE SHOP @) DOLOMITE S'LO ('2,000 TONS)
@ TlZANSFOIi!'MEIZS @ MILL
@
!lOAP
Fig. 28
NOICIH I2\VEe
FLOW.
635 MvY. FLUID/ZED BED
BOILER COMBINED CYCLE
PL.RNT
SITE PLOT PLAN
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fa
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Balance of Boiler I
System Losses:
I Adiabatic Flame
I Temperature
I
I
I
I
I
I
I
I
1750 (FBCD)
I
I
ITubeWall Temp.
: Steam Temp.
I
I
I
Piping
Losses
Stack
Losses
1000
o
1
2
5 6 7 8 9 10 II
Energy from MAF Fuel - 1000 Btu/lb
Fig. 30 -Temperature-energy diagram for pressurized utility boiler
Cu rye 645595-A
-------
Performance
Boiler Performance:
Steam generator efficiency calculations
are misleading in a combined cycle plant if the gas temperature leaving
the steam generator is used to calculate the stack gas losses.
The
stack gas temperature should be used to calculate a combination boiler
and gas turbine combustor efficiency. The calculated and estimated losses
for the high-pressure fluidized bed boiler on this basis are as follows:
Component
L05S - %
Dry gas loss @ 275°F
Loss due to hydrogen and moisture in coal
Loss due to moisture to air @ 275°F
Radiation loss
Incomplete combustion
3.88
4.14
D.08
0.15
1.51
0.11
Solids sensible heat
Unaccounted for and manufacturer's margin
TOTAL
1.50
11.37
This gives a combustion efficiency of 88.6%
Gas Turbine Pressure Loss Effect:
Boiler plant pressure drop
has a small effect on plant capacity and heat rate.
A change of one
percent in pressure loss betWeen the gas turbine compressor exit and the
turbine inlet causes a 0.1% decrease in plant power and a 0.1% increase
in plant heat rate.
The reasons for this are:
. Only the gas turb.ine is directly affected, and it contributes
only 17.5% of the plant power.
. A decrease in the gas turbine power results in higher gas
turbine exit temperature and increased steam power.
I .
110
-------
Steam Turbine Condenser Pressure Effect:
The steam turbine
condenser pressure affects the plant capacity and heat rate. The con-
denser pressure will be determined by the heat rejection system. A
power plant with cooling towers typically has a steam condenser pressure
of 3 in. Hg. If the heat is rejected to a body of water, the pressure
is typically 1-1/2 in. Hg. The plant performance for these two cases
with a boiler efficiency of 88.6% is:
Condenser pressure - inches Hg
Plant power, MW
1-1/2
325.7
8853
3
317.7
9076
Plant heat rate, Btu/kWh
Part-Load Performance:
It has been shown that the energy input
to the boiler, the steam cycle power, and the gas turbine power in the
combined cycle fluidized bed boiler are a function of the following four
parameters:
. Air flow rate
. Fuel/air ratio
. Bed temperature
. Bed depth.
Three possible modes of load control for the combined cycle
system with a fluidized bed boiler using different combinations of these
parameters were identified.
The char~cteristics of these modes,used
singly or in combination, were determined and a preferred mode was
selected.
In the preferred control mode, the depth of the fluidized
beds and the gas turbine compressor air flow are held constant, while
the fuel/air ratio to the beds and the bed temperatures are varied.
Steam power decreases due to lower bed temperature, and gas turbine
power decreases due to lower gas temperature. With a minimum bed
temperature of 1300°F, a turn-down of approximately 50% is possible;
and by using two gas turbine modules with one or more boiler modules
111
-------
per gas turbine module, the specified plant turn-down of 75% can be
attained with no discontinuities in load.
Pollution Abatement:
Emissions are considered for the total
power plant.
This includes potential emissions from coal drying, dolo-
mite regeneration, and sulfur recovery, as well as the boiler modules.
Emission projections from the plant are summarized in Table .20.
Overall regeneration performance, particularly wit~ respect
to sulfur removal efficienCy, is difficult to predict precisely. The
Claus plant, without tail gas clean-up, will recover 94 to 96% of the
sulfur fed to it.
Losses from the regenerator should amount to approxi-
mately 2 to 5% of the total sulfur (assuming gas leaving the reducer
vessel has the equilibrium 802 concentration). Therefore, the overall
sulfur recovery efficiency should be around 90% without tail gas clean-up
from the Claus plant and 94 to 99% with tail gas clean-up.
The cost estimates for the various components of this regenera-
tion system were obtained from the following sources.
information is given in Volume III.
Detailed design
solids feed system
Claus plant
C02 scrubber
process vessels
Petrocarb
Ford, Bacon and Davis
Benfield Corporation
Westinghouse Heat Transfer Division
Plant Performance:
The full load heat rate for the site chosen
is 8853 Btu/kW-hr.
This corresponds to a back pressure of 1-1/2 in. Hg.,
112
-------
TABLE 20
AIR EMISSIONS SUMMARY
SULFUR DIOXIDE NITROGEN OXIDES PARTICULATE
1b SO/106 Btu 6 6
1b N02/10 Btu 1b/10 Btu
BOILER PLANT (a)
(Boilers and Coal 0.02-0.16(c)
Drying) 0.7 0.07-0.22
DOLOMITE REGENERATION 0.1
SULFUR RECOVERY 0.1-0.2(b)
TOTAL 0.9-1. 0 0.07-0.22 0.02-0.16
(a)Does not consider fugitive dust.
(b) Includes tail gas sulfur recovery processes (e.g., Ford, Bacon,
and Davis' IFP Process) at a cost of $3/kW.
(c) The data indicate that uncontrolled fluidized bed boilers will emit
significantly less fine «10~m) material: -10wt% vs 30 wt% for conventional
plants. Thus, for a 8.5% ash coal, a conventional plant would emit
~ 40 1b particulates < 10~m/ton coal and a FBB is projected to emit
~ 30 1b ash and stone particulates <10~m/ton coal, without any
particulate control.
113
-------
combustion efficiency of 88.6%, and pressure losses in the gas turbine
combustor loop of 7.5% of the total. The overall plant efficiency is
38.4% under these conditions.
Atmospheric Pressure Fluidized Bed Boiler Power Plant Design
The atmospheric pressure fluidized bed boiler is a potential
replacement for conventional boilers. The power generation and electric
equipment of a conventional power plant are not altered by using the new
boiler concept. The preliminary design includes the boiler, solids
handling, draft system, sulfur removal/recovery system, and instrumen-
tation and control.
Boiler Plant Equipment
Boiler Design: The preliminary boiler design consists of an
in-line arrangement of four separate modules of vertically stacked fluid-
ized bed combustors. Each module contains six beds including a carbon
burn-up cell, as illustrated in Figure 31 .
Each bed performs a single
boiler function -- two beds for evaporation, two for superheating, and
one for reheating.
The water walls used for enclosing the beds are used
for evaporation.
The feedwater is preheated in a convective surface above
each bed.
Horizontal tube bundles are used in all beds and for the con-
vection passes.
of four inches.
The submerged tubes have vertical and horizontal pitches
Two-inch tubes are used in the reheater bed and the
convection passes.
One- and one-half-inch tubes are used in the super-
heater and evaporator beds.
An internal common duct collects the flue gas with carbon-rich
ash from the five primary fluidized beds and carries it to the primary
cyclone separator. A separate duct located within the main flue gas duct
carries the flue gas from the carbon burn-up cell to another dust col-
lector.
Coal is pneumatically transported through 16 separate
feed lines to each bed as a dilute phase of dried coal in 250°F air.
114
-------
,
BED AREA
300MW 160Ft.2 PER.BED
112Ft.x13Ft.j
600MW 320Ft. 2 PER. BED
AIR HEATER
HALF PLAN VIEW
,
,
,
,
,
. ,
, TUBULAR
", - DUST
, COLLECTOR,
"i1- - - - - - - - - -
II
II
II
II
..
rn
REHEATED.
STEAM]
.
SUPERMEATED ~
S8PfRHEAJER STEAM
REFlUTER
,.
I
I
, I
, I
'{
I'
I..
I
I
I
I
I
I
I
- - - - - - - - - 25'
'-
,
(2) TUBULAR
AIR HEATER
- - - - - - - - - - 25'
J
sur&RHEATER
loa' a-
\
h.
DUST
HOPPER
/
IYANMTOR
AIR 1
IN
.. 25'
,I
CBC FUEL
INJECTOR
/
EVAPORATOR
----------
,
cae
25'
-I
I
12 '
, GRADE Elevation
1
ELEVATION
Fig. 31-Atmosphere - Pressure Fluidized Bed Steam <:enerator Module
-------
The coal feed lines enter the gas duct from either side of
pass through the flue gas exit openings in the water wall,
the plenum chambers and through the grid plates. The coal
horizontally into a volume of the bed free of tube bundles.
the module,
then up into
is injected
One coal
injector is provided for each ten square feet of fluid bed surface.
The recycle ash feed lines are brought into the module at a point below
the carbon burn-up cell.
Limestone feeding into the fluidized beds falls into two cate-
gories: make-up feed and recycled limestone feed. The make-up limestone
is fed into the beds along with the coal. Each bed is provided with
one injection point for the regenerated limestone and one withdrawal
point for the spent limestone.
Auxiliary Equipment
Solids Handling and Crushing:
The coal and limestone handling
system includes receiving, storage, crushing, and conveying facilities.
Coal is crushed into 1/4 inch x 0 in a reversible hammermi11 and fed
to 16 hoppers for injection to the boiler modules. Limestone may be
purchased crushed to 1/4 inch xO or may be crushed on-site. The crushed
make-up limestone is combined with the coal on the conveyor to the
hoppers.
Solids Drying and Feeding: The coal and limestone feeding system
includes hoppers for receiving coal from the coal handling systems, volu-
metric feeders, combination fluid bed dryers and distributors, dust
collectors for the fluidizing air, primary air fans, and dilute phase
coal transport lines to the individual coal injection points.
The high carbon content particulates e1utriated from the primary
beds are recovered by cyclones, collected in a dust hopper, and transferred
to a fluid bed injector which meters the flow of solids to the carbon
burn-up cell.
Draft Fans and Air Preheater:
The secondary air enters the
system at the forced draft fan and is heated to 735°F in the air preheater
117
-------
from which it is fed into the internal air distribution duct.
Air is
metered by dampers into plenum chambers below each fluidized bed.
A
separate cool stream is taken off ahead of the air heater for the carbon
burn-up cell.
A tubular type of air preheater was selected over the
somewhat less expensive regenerative type because of the severe leakage
problem which could result from the use of a regenerative air preheater
in combination with
the high pressure drop fluidized bed and the forced
draft fan.
Particulate Removal: The particulate removal system in the
fluidized bed boiler has two functions: to recover most of the unburned
fuel in the solids e1utriated from the primary beds for recycle to the
carbon burn-up cell, and to control the emission of particulates to
the atmosphere.
There are two stages of particulate removal for the products
of combustion from both the primary beds and the carbon burn-up cell.
Mu1ticlone collectors were selected for the first stage of both streams.
These two collectors are physically integrated with the two gas and
solids streams isolated so that the carbon-riCh ash from the primary
beds is not mixed with the spent ash from the carbon burn-up cell.
The two gas streams are mixed after the mu1ticlones, and an electrostatic
precipitator is used to reduce the particulate concentration to meet
emission standards.
Sulfur RemovaljRecoverv System
Sulfated limestone from the fluidized beds is regenerated 'by
a direct reduction process.
The calcium sulfate is converted back to CaO
by reaction with a reducing gas:
CO (C02)
CaS04 + (H2) ~ CaO + S02+ H20 .
The regenerated limestone is returned to the boiler modules. The off-gas
from the regenerator has a high S02 concentration (4 'to 10% by volume) and
is used, to produce sulfur. A flow diagram of the process is shown in
Figure 32 .
118
-------
......
......
\0
Steam
Sulfated Stone
from Boi 1 er
Sol i d
Surge
Coal
Ai r
Regenerated
Stone to Boil er
Regeneration
CaS04 +(~~ ) -
(C02
aO + S02 + H 0
2
. SO
Rich Gas,
CaO
S pen t
Stone
Dwg. 6161A04
S02 Rich Gas
to Sulfur Plane
Gas
Clean
Up
Waste
Fig. 32 -Atmospheric pressure regeneration schematic
Stone Fines
Distributor
-------
Spent stone discharges from each bed into a hold vessel -- one
hold vessel per boiler module. The stone is then pneumatically trans-
ported to the regenerator vessel using air as the carrier gas.
The regenerator vessel is a fluid bed reactor operating at
one to two atmospheres and 2000°F. Coal is charged into the reactor bed.
An air-stream mixture fluidizes the reactor bed and combusts coal to
provide reducing gas for reduction of the CaS04.
Regenerated stone flows from the reactor vessel to adistribu-
tor vessel. Twenty-four lines return regenerated stone from the di~tri-
butor to each bed in the boiler modules.
The hot regenerator top ,gas passes through a gas cooler and
cleaner and then to a sulfur recovery process. The S02 concentration
will be enriched to 90% by volume by a dimethylamine, DMA, absorber-
stripper process. The concentration S02 stream is reduced to sulfur
by the Asarco process using natural gas as the fuel.
Performance
fluidized
A temperature-enthalpy diagram for the atmospheric pressure
shown in Figure 33. The theoretical gas temperature, the
bed temperature, and the cold-side fluid temperatures are shown
boiler is
for the full load conditions.
This plot graphically describes the allo-
cation of boiler function and illustrates the heat transfer situation
in each of the boiler components.
Boiler Performance:
The losses for the atmospheric pressure
fluidized bed boiler are as follows:
Losses
Percent
Dry gas loss (stack temp -- 275°F)
Loss due to hydrogen and moisture in coal
TOTAL
4.28
5.05
0.10
0.18
1.0 - 2.39
1.50
12.49-13.88
Loss due to moisture in air
Radiation loss
Incomplete combustion
Unaccounted for and manufacturer" s margin
120
-------
Dwg. 6161A83
LL.
o
Preheater
*'"
",."""
,,"
."".. .
."".."
"",,"""
.""..
,,/
,.,.
,.,.
"'"
"",'"
"
",
Adiabatic
Flame
Tern p.
4000
3000
......
N
......
..
Q,)
~
.a LUOO
ro
~
Q,)
Q.
E
Q,)
I-
1000
Stack Gas
Losses
I
eBe 19000
~
I I . FBe 16000
Economizer
Superheater v)
Evaporator
V)
Q,)
-V)
o V)
o
Q,) -J
U ~
C Q,)
ro -
-.-
ro 0
co co
6 8 10
Energy in MAF Coal - 1000 B tu/Lb
Fig. 33 - Temperature-energy diagram for the atmospheric utility boiler design
4
12
14
16
-------
Part-Load Performance:
A maximum primary bed temperature
of l600°F was chosen on the .basis of ash characteristics and sulfur
recovery considerations.
A lower limit of l3000F for continuous operation
was chosen on the basis of sulfur recovery and combustion efficiency
considerations. At part loa~ the gas-side heat transfer coefficient is
nearly constant and there is only a small reduction in steam-side coeffi-
cient due to Reynolds number effect.
Therefore, the heat transferred
from the beds is primarily a function of the bed temperature. Because of
the constraints on bed temperatures discussed above, the turn-down
capability of a boiler module is only 35% of boiler flow, which is equiva-
lent to about 40% reduction in plant power. To attain 4:1 turn-down
capability for the plant, it is necessary to use four boiler modules
which can be shut down individually. This gives the plant load profile
shown in Figure 34.
Pressure Losses:
are as follows:
The gas-side pressure losses at full load
Component
Pressure Los~ in H20
Bed
1.43
10.8
27.5
0.1
3.0
Ducts
Distribution Plate
Convection Bank
Dust Collector
Air Heaters
TOTAL
3.0
1.5
47.33
Air-Side
Gas-Side
Since the bed pressure loss is predominant
the overall gas-side pressure drop will be
The stea~side pressure losses are 545 psi.
and independent of load,
relatively unchanged with load.
122
-------
100 (1)
"'C
ro
0
.....J
::J 80
u..
-
0
~
,
V)
Q)
::J ro
"'C
0
~
ro
::J
"'C
.~ 40
"'C
C
-
0
C")
c
- LU
ro
e:::
o
o
Curve 645614-A
t
t
(1, 2): Boiler Module No.1
and 2 Operating
(1,2,3): Boiler Module No.1,
2, and 3 Operating
!U L10 ro 80
Total Boiler Load, % of Full Load
100
Fig. 34 - Boi Ie r load reduction
123
-------
Pollution Abatement:
summarized in Table 21.
Projected emissions from the plant are
The sulfur loss in the generator is by the carrier &as, for
the spent and regenerated stone.
The expected sulfur recovery efficiency
for the DMA process is 98 to 99%. This process consumes soda ash and
dilute sulfuric acid. Vented gas from the DMA scrubber should contain
450 ppm S02' The Asarco process is expected to recover approximately
92% of the sulfur fed to it. Adding a third Claus reactor to the two
planned should improve the performance. The overall sulfur recovery
efficiency for the regenerator-sulfur recovery plant should be around 85%.
Sulfur recovery as sulfuric acid was also considered.
Emis-
sions from an acid plant would contain 500 ppm or less S02' corresponding
to sulfur recovery efficiency in excess of 99%. The overall plant sulfur
recovery should be approximately 95%.
Cost estimates for the various components of this regeneration
system were obtained from the following sources.
mation is given in Volume III.
Detailed design infor-
. Solids feed system:
Westinghouse, Petrocarb, and Foster Wheeler
. Sulfur plant:
Allied Chemical Corporation
. Process vessels:
Westinghouse.
Plant Performance:
The full load heat rate for the site
chosen is 9440 Btu/kWh.
This corresponds to a back pressure of 1-1/2 in.
Hg and a combustion efficiency of 86.1%.
Economics
Capital and energy costs were prepared for pressurized and
atmospheric pressure fluidized bed boiler power plants burning high-
sulfur coal based on the preliminary designs. Capital and energy costs
were also estimated for fluidized bed boiler power plants burning high-
124
-------
TABLE 21
AIR EMISSIONS SUMMARY
SULFUR DIOXIDE NITROGEN OXIDE PARTICULATES
lb 502/106 Btu lb NO/lOb Btu 1L/:.06 Btu
BOILER PLANT( a)
(Boilers Including 0.02-0.08 (c)
Coal Drying) 0.7 0.4-0.8
LIMESTONE REGENEP~TION
SULFUR RECOVERY 0.3-0.5(b)
TOTAL 1. 0-1. 2 0.4-0.8 0.02-0.08
(a) Does not consider fugitive dust.
(b) Includes tail gas sulfur recovery process for C1aas plant.
(C)The data indicate that uncontrolled fluidized bed boilers will emit
significantly less fine «lO~m) material: -lOwt% vs 30 wt% for
conventional plants. Thus, for a 8.5% ash coal, a conventional
plant would emit ~ 40 1b particulates <10~m/ton coal and a FBB is
projected to emit ~ 30 lb ash and stone particulates <10~m/ton
coal, without any particulate control.
125
-------
sulfur oil. Costs are projected for plants with once-through limestone/
dolomite and with stone regeneration and sulfur recovery. These costs
are compared with the cost for conventional coal- and oil-fired plants
with stack gas cleaning.
Assumptions common to all plants are:
. Northeast site
. January 1970 costs
. Begin construction July 1971
. Supplementary cooling
. Contingency of 6%
. Escalation at 7-1/2%
. Interest during construction at 7-1/2%
not included
. 70% capacity factor
. 15% fixed level charge
. No credit taken for sulfur recovery
. 45~/106 Btu high-sulfur coal (~ 4% sulfur)
. 45~/106 Btu high-sulfur oil (~ 3% sulfur)
. $2/ton limestone or dolomite.
The heat rates for each coal-fired plant are:
Conventional
9230 Btu/kWh
9550 Btu/kWh
Atmospheric pressure fluidized
bed boiler
Pressurized fluidized bed
boiler combined cycle
(Heat rates are for 3 in. Hg turbine
8967 Btu/kWh
back pressure to allow for a cool-
ing tower.)
Capital costs for coal-fired plants are summarized in Table 22.
These costs are b~sed on data from Westinghouse, Foster Wheeler, United
Engineers and Constructors, and equipment vendor quotes. Air pollution
control costs, which are included with the boiler plant equipment cost,
are summarized in Table 23.
The cost of the pressurized plant is
18 to 21% less than a conventional plant, while the cost of the atmos-
pheric pressure plant is 7 to 12% less.
Capital cost as a function of plant
126
-------
TABLE 22
COAL-FIRED POWER PLANT COST BREAKDOWN
635 MW Plant
(Sulfur Removal Process(es) Designated Under Concept)
Conventional
p. f. Boiler (a)
$/kW
Once-Through
Atmospheric-Pressure
Fluid Bed BOiler(b)
$/kW
Regenerative Once-Through
Pressurized
Fluid Bed Boil~r)
Combined Cycle C
$/kW
Regenerative Once-Through
Land & Land Rights 1.13 1.13 1.13 1.13 1.13
Structures & Improvements 27.28 25.80 24.80 19.57 18.52
Gasification Plant Equipment
30i1er Plant Equipment 82.23 71.79 60.80 60.36 52.68
Gas Turbine-Generator Equipment 14.80 14.80
Stea~ Turbine-Generator Plant Equipment 55.76 54.96 54.96 44.14 44.14
Electric Plant Equipment 14.99 14.99 14.99 15.91 15:91
Misc. Plant Equipment 4.21 4.21 4.21 3.56 3.56
Undistributed Costs(d) 30.01 29.20 29.20 28.35 28.35
Other Plant Costs(e) 2.91 2.91 2.91 2.91 2.91
- - - -
Sub Total 218.52 204.99 193.00 190.73 182.00
~orma1 Contingency 13.11 12.30 11. 58 11.44 10.92
- - - -
Sub Total 231.63 217.29 204.58 202.17 192.92
Escalation 52.12 48.08 45.26 37.60 36.17
- - -
Sub" Total 283.75 265.37 249.84 239.77 229.09
Interest During Construction 47.88 41.80 39.35 31.30 30.07
General Items & Engineering 5.5 5.5 5.5 5.5 5.5
- - -
TOTAL CAPITAL COST 337.13 312.67 294.69 276.57 264.66
---------------------------------------------------------------------------------------------------------------------
CONSTRUCTION TIME
Type of Plant
No. of Years
Conventional Plant
Atmospheric Pressure Fluid Bed Boiler
Pressurized Fluid Bed Boiler Plant
Fluidized Bed Gasification
Plant
4.5 (f)
4.2(g)
3.5(h)
3.5
(a)
Conventional plant cost data provided by United Engineers and Constructors.
wet scrubbing system and NOx control.
Cost estimate prepared by Westinghouse on component data supplied by Westinghouse, Foster Wheeler, and
United Engineers and Constructors. Plant includes sorbent regeneration and sulfur recovery system.
Plant includes throw-away
(b)
(c)
Cost estimate prepared by United Engineers and Constructors based on component data supplied by Westinghouse,
Foster Wheeler, and United Engineers and Constructors. Plant includes sorbent regeneration and sulfur
recovery.
Cd)
(e)
Engineering and construction management and supervision, temporary facilities, construction services, etc.
Operator training, spare parts, etc.
(f)
Source -- United Engineers and Constructors.
(g)
(h)
Construction time reduction for boiler projected by Foster Wheeler assumed for total plant.
Construction schedule prepared by United Engineers and Constructors.
127
-------
TABLE 23
AIR POLLUTION CONTROL EQUIPMENT COST
S02 Removal
Sulfur Recovery
Conventional
p.f. Boiler
$/kW
20(a)
Atmospheric Pressure
Fluid Bed Boiler
$/kW
Regenerative Once-Through
Pressurized
Fluid Bed Boiler
$/kW
Regenerative Once-Through
(b)
(b)
(b)
(b)
15.2
12.68
Particulate Contro1(c)
Minimization
(a)
3.50
23.50
5.0
5.0
(d)
(d)
NO
x
l&..
20.2
ill
5.0
12.68
t-'
tV
00
(a)
The wet scrubber is assumed to achieve adequate particulate removal.
cate the cost for S02 and particulate control by wet scrubbing for a
$40/kW. .
Recent cost data ( 8) indi-
new plant can be as high as
(b)
Sulfur dioxide is removed in the boiler.
(c)
Ash handling cost is not included.
(d)
Particulate removal is required for gas turbine operation.
pollution control.
This cost is not attributed to
(e)
Additional NO . control maybe required to meet proposed regulations.
x .
-------
capacity for a conventional coal-fired plant and fluidized bed boiler
plants with sulfur recovery is shown in Figure 35. Capital costs
projected for oil-fired plants are summarized in Table 24. The cost
estimate for the atmospheric-pressure fluidized bed boiler plant is only
2% less than a conventional plant, while the estimate for the pressurized
combined cycle plant is 14% less.
Energy costs for coal- and oil-fired plants are summarized in
Tables 25 and 26 . Energy cost reductions for pressurized fluidized
bed combustion combined cycle coal-fired plants with sulfur recovery
may be ~lO% or 1-1/4 to 1-1/2 mills/kW-hr below conventional plant energy
costs. The reduction in energy costs for atmospheric pressure fluidized
bed combustion with sulfur recovery is estimated to be ~2%. Energy cost
reductions for pressurized fluidized bed combustion combined cycle
oil-fired plants with sulfur recovery may be ~7% below conventional plant
energy costs. Atmospheric pressure fluidized bed oil gasification with
sulfur recovery does not show energy cost reductions over new conventional
plants if the $20/kW capital cost for S02 flue gas cleaning systems is
achieved.
Evaluation
Atmospheric and pressurized fluidized bed combustion power
systems were evaluated on the basis of:
. Design characteristics
. Effectiveness for pollution abatement
. Effectiveness for fuel utilization
. Economy of power generation
. Status of technology
. Development requirements.
The fluidized bed combustion systems are compared with each other and
with a conventional p.f. coal-fired plant with stack gas cleaning.
Comparison
In making comparisons of technology, the state of development
and the economics must be considered, and a balanced assessment
129
-------
500
~ 400
.........
-tA-
--
V)
o
U
t:; ~ 300
o c..
ro
U
ro
--
o
I-
200
100
200
Curve 645592-A
Fuel: Coal
Conventional Plant I ncl udes Wet Scrubbi ng
FI uidized Bed Plants I ncl ude Sulfur Recovery
Conventional P.1. Boiler
1976 Operation
Pressurized.
Fluidized Bed Combustion
1975 Operation
300
400
600 700
Plant Capacity, MW
Fig. 35 - New Plant Cost vs. Capacity
500
800
Atmospheric-Pressure.
FI uidized Bed Boiler
1976 Operation
900
1000
1100
-------
TABLE 24
OIL-FIRED POWER PLANT COST BREAKDOWN
635 MW Plant
I-'
W
I-'
Land & Land Rights
Structures & Improvements
Boiler Plant Equipment
Sulfur Removal Equipment
Gas Turbine-Generator Equipment
Steam Turbine-Generator Equipment
Electric Plant Equipment
Misc. Plant Equipment
Undistributed Costs
Other Plant Costs
Sub Total
Normal Contingency
Sub Total
Escalation
Sub Total
Interest During Construction
General Items of Engineering
TOTAL CAPITAL COST
(a) Assumes stack gas scrubbing systemt
over alternates. No by-pass around
Same as coal-fired plant.
Once-through throw-away system.
Estimated by assuming same percent
plant over conventional coal-fired
(b)
(c)
(d)
Conventional (a)
$/kW
1.13
24.95
47.3l( )
20.00 c
55.76
14.40
4.08
28.55
2.91
199.09
11.95
211.04
47.78
258.52
43.63
5.5
307.65
no particulate control
the scrub~er system is
Atmospheric Pressure
Fluid Bed Combustion
$/kW
Regenerative
1.13 (b)
25.80
51. 76
14.10
54.96
14.40
4.08(d)
27 .80
2.91
196.94
11. 82
208.76
46.19
254.95
40.14
5.5
300.60
beyond scrubbert
provided.
Pressurized
Fluid Bed Combustion
$/kW
Regenerative
1.13 (b)
19.57
40.89
12.68
14.80
44.14(d)
15.30(d)
3.45(d)
27.00
2.91
181. 87
10.91
192.78
36.15
228.93
30.05
. 5.5
264.48
no additional stack
height
reduction for oil-fired plant as was assumed with coal-fired
plant.
-------
TABLE 25
ENERGY GENERATION COSTS FOR COAL-FIRED POWER PLANTS(a)
Sulfur Removal System
Conventional
p. f. Boiler
Once-Through
Atmospheric-Pressure
Fluidized Bed Boiler
Regenerative Once-Through
Pressurized
Fluidized Bed Boiler
Combined Cycle
Regenerative Once-Through
Fuel,
4.11
7.61 7.20 6.75 6.44
4.60(b) 4.30 4.35(b) 4.04
0.05 0.29 0.12 0.52
0.86 0.67 0.90 0.71
13.12 12.46 12.12 11. 71
Fixed Charges
8.25
Operating and Maintenance
0.05
0.99(c)
Dolomite or Limestone
TOTAL. mills/kWh
13.40
~
v.>
N
(il)
Basis:
.,635 MWplant capacity
. High-sulfur coal - 4.3%
. 70% load factor
. Begin construction July 1971
. Costs in mills/kWh
(b)
Includes fuel for regeneration process.
(c)
O&M for wet scrubbing was estimatedto'be 0.32 mills/kWh.
is low, and the cost may approach 1 mill/kWh.
Recent data indicate that this
-------
TABLE 26
ENERGY GENERATION COSTS FOR OIL-FIRED POWER PLANTS
635 MW PLANT
Pressurized
Sulfur Removal System Conventional Atmospheric Pressure Fluidized Bed Boiler
Boiler Fluidized Bed Boiler Combined Cycle
(Once-Through) (Regene r a ti ve) (Regenerative)
Fixed Charges 7.52 7.35 6.47
Fuel 4.11 4.60 4.35
~
w
w Dolomite 0.05 0.05 0.12
or Limestone
Operating and Maintenance 0.91 0.78 0.82
TOTAL. mills/kWh 12.59 12.78 11. 76
-------
rendered.
Demonstration installations of wet scrubbers are well under-
way: 70 to 90% removal of 802 may be achieved; some operating problems --
corrosion and deposition -- must be solved. 'Costs of new scrubber in-
stallations are estimated to be $20 to $25/kilowatt. This cost may be as
high as $40 to $50/kilowatt. (8) Combustion modification techniques on large
conventional boilers have been under investigation. It appears that NO
. x
emissions may be reduced appreciably by two-stage combustion, low excess
air, or flue gas recycle.
Atmospheric fluidized bed combustion is still in a develop-
mental stage. Demonstrated 802 removal is 80 to 90%; NOx reduction may
not be adequate to meet emission standards. The technology of sorbent
. .
regeneration and sulfur recovery is not sufficiently developed for
accurate systems design and economic evaluation. With reasonably opti-
mistic assumptions, energy costs. from atmospheric fluidized bed boiler
power plants are estimated to be 2 to 3% less than from conventional
plants equipped with wet scrubbers. This cost advantage might well
disappear as further technical data are developed on the atmospheric
system.
Pressurized fluidized bed combustion is also in the development
stage. Demonstrated 502 and ,NO x reductions are adequate to meet emission
standards. Energy costs are projected to be 8 to 9% -- and potentially
24% -- less than conventional power plants. There is thus a much larger
economic margin for solving technological problems.
System evaluation and experimental test results indicate that
the pressurized system is.more attractive for pollut~on abatement and in
economy of operation. A summary of the plant comparisons is presented
in Table 27. The commercialization of either the atmospheric or the
pressurized system would require 9 to 11 years and $65 to 75 x 106,
primarily because the construction of the demonstration plant dominates
the time and cost estimates.
134
-------
TABLE 27
SUMMARY OF PLANT COMPARISONS(a)
COST
Installed Capital Cost, $/kW
.Energy Cost, mills/kWh
w/o sulfur credit
ENVIRONMENTAL FACTORS
I-'
W
V1
Plant Heat Rate (exclusive of
sulfur recovery or removal
systems) Btu/kWh
6
S02' (lb/lO Btu)
NOx' (lb N02/l06 Btu)
Particulate, (lb/l06 Btu)
POTENTIAL FOR ADVANCED CONCEPTS
Cost
Cost
Efficiency
FLUIDIZED BED BOILER SYSTEMS
Relative Advantages (Technical)
Technical Problem Areas
Conventional With
Scrubbing System
337
13.40
9230
1.5
1.2-1.4 w/o recir.
0.05-0.15
No reduction projected
No reduction projected
No increase projected
Atm. Press. FBB
Regenerative Once-Through
313
13.12
295
12.46
Pressurized FBB
Regenerative Once-Through
277
12.12
264
11. 71
9550
0.70
0.4-0.8
0.05
290
11. 90
40%
Less stringent
removal
More expo data
tion
particulate
8967
0.70
0.1-0.2
0.05-0.15
240
10.30
47%
Coal feeding
NOx removal
Control
Higher efficiency
Reduced size, reduced heat
transfer surface, greater
potential, reduced construc-
tion time
Deep beds, gas turbine
blade erosion, S02 removal,
solids handling
(a) Basis:
600 MW Capacity
4.3% Coal
on opera-
Coal feeding, NOx emis-
sion, control, S02
removal
-------
The number of common technical problems remaining in atmos~
pheric and pressurized systems appears very small. The order of magni-
tude difference in pressure, in mass flow per unit of bed area, an~ in
bed depth make it difficult to transfer technical information and design
procedures.
In conclusion, the conventional power plant with combustion
modification and wet scrubbers is the most highly developed technology.
Pressurized fluidized bed combustion is the most promising fluidized bed
combustion technology from the point of view of effective pollution
abatement, efficient fuel utilization, and economical power generation.
. .
Atmospheric fluidized bed combustion may be better than conventional
systems, but further development is required.
Pot;~nti'a:J.
Potential energy cost reductions for fluidized bed power genera-
tion systems are projected as the result of:
. ~odification of the present design concepts
. Advanced boiler-regeneration-sulfur recovery designs and
power cycles
. Utilization of low grade fuels.
Modification of Present Concepts:
Potential simplifications and improvements in the present
pressurized fluidized bed boiler combined cycle plant
may reduce the $276/kW capital cost by $20/kW~9)This corresponds to an
energy cost reduction of 4% in the present: pressurized plant design.
If the gas turbine temperature is increased by burning above the bed or
lowering projected heat losses between the boiler and the gas turbine,
the plant heat rate would increase I to 2%. This would result in
additional energy cost reduction.
The potential energy cost reduction
. .
with the pressurized combined cycle plant wi~h sulfur recovery may be 14%
less than a conventional plant with wet scrubbing. Modification in the
136
-------
present atmospheric pressure boiler plant design concept does not appear
to result in significant cost reductions.
Advanced Concepts: Advanced designs have the potential for
reducing capital costs and reducing the plant heat rate over the present
design concepts. Three areas have been considered: boiler design,
regeneration-sulfur recovery processes, and power cycle conditions.
. Advanced boiler design concepts have been conceived which have
potential advantages in maintaining uniform bed temperature,
in feeding reactants to the bed, in separating ash, and in power
plant control.
. Regeneration-sulfur recovery processes have been assessed in order
to develop a process with reduced capital cost and improved
operability.
. The power cycle operating conditions can be advanced to improve
the plant heat rate -- increased gas turbine temperature and increased
steam temperature and pressure.
In the high-pressure combined cycle system the bed temperature,
rather than the gas turbine inlet temperature, is limiting. If a
way is found to decrease the temperature difference between the bed and
the gas turbine, or if a supply of gaseous fuel is produced*for heating
the exhaust products from the beds to the current limiting level for
the gas turbine, i.e., l800-1900op, the plant heat rate would decrease
2 to 3% and the plant capacity would increase 5 to 8%. The effect on
specific plant cost would be somewhat. less than the capacity change.
Gas turbine temperatures of 25000p are projected for 10 to 15 years
from now, so the potential for growth in this area is substantial. No
significant improvements are expected in gas turbine aerodynamic effi-
ciencies in the foreseeable future.
However, there is a definite trend
in gas turbine design toward higher mass flows on an area basis.
This
*This may be achieved by gasifying the carbon carry-over from the primary
beds.
137
-------
will bring about further reduction in specific plant cost. Reduced
corrosion in fluidized bed boilers could result in increasing steam tem-
peratures to l200°F or higher. Both the plant capacity and the plant
heat rate would change about 4% per 100°F increase. Near improvements
in gas turbine and steam turbine utilization could result in heat rate
improvements on the order of 10% and in specific plant cost reduction on
the order of 10 to 15%.
Longer term advances in gas and steam turbine
temperatures and pressure .would bring about further improvements..
The potential energy cost reductions for the atmospheric
pressure and pressurized fluidized bed boiler plants based on suc'cessful
development of the advanced concepts 'are summarized in Table 28. The
energy costs for the atmospheric pressure and pressurized systems repre-
sent reductions of 10% and 22% respectively over a conventional plant
with stack gas cleaning.
TABLE 28.
ADVANCED FLUIDIZED BED COMBUSTION POWER
PLANT COSTS WITH SULFUR RECOVERy(a)
Atmospheric Pressure
Plant
Pressurized
Plant
Capital Cost, $/kW
Heat Rate, Btu/kWh
Energy Cost, mills/kWh
290
8300
11. 90
240
7600
10.30
(a) Basis:
600 MW
Fuel Utilization:
Fluidized bed combustion boilers offer a
means of burning low-grade fuels which cannot be effectively burned in
conventional boilers.
Two advantages can be realized:
effective utili-
zation of fuel resources, and reduction in energy cost as the result of
low-cost fuel supplies.
138
-------
ASSESSMENT OF ATMOSPHERIC PRESSURE FLUIDIZED BED OIL GASIFICATION
Specifications and design concepts were established for
atmospheric pressure fluidized bed oil gasification systems for retrofit
on existing utility boilers and for new plants.
Conceptual designs,
performance, and costs were prepared and compared with conventional
alternatives -- low-sulfur oil, desulfurized oil, and stack gas cleaning.
SPECIFICATIONS
Process specifications of importance in oil gasification/
desulfurization are listed on the following page. The four factors which
are listed as functional variables (geographic location, fuel oil, lime-
stone, and sulfur removal) are determined by the market outlook, by
residual oil and limestone availability, and by the expected S02
emission standards, respectively.
The design variables listed on page 140 refer to the broad
design factors which will determine the feasibility of preliminary
design concepts. The design considered may be that of a new boiler or a
boiler retrofit, and the three factors -- boiler size, boiler load factor,
and boiler turn-down ratio -- are important in determining the design
for either a new system or a retrofit system.
In the retrofit case, the
type of boiler being retrofit is important because coal- and oil-fired
boilers differ in retrofit characteristics. The location of the gasi-
fication system relative to the boiler structure (internal to the boiler
or external to the boiler) and the configuration of the gasification
system (singular or modular) are basic considerations in both new and
retrofit designs. The other important design variable considered in the
preliminary design is the mode of operation (regenerative or once-through).
139
-------
SPECIFICATIONS
FUNCTIONAL VARIABLES:
Geographic Location
Fuel Oil
Limestone
Sulfur Removal
Boiler Size
Load Factor
Turn-down Ratio
DESIGN VARIABLES:
New Boiler Design
Retrofit Design - (Coal- or
Oil-Fired)
Gasification System Location
Internal to Boiler
External to Boiler
Gasification System Operational
Mode
Regenerative or Once-Through
Gasification System Configuration
Unit Design or Modular, etc.
TEMPERATURE CONTROL:
Gasifier Temperature Control
Stack Gas Recycle
Water Injection
Steam Injection
Heat Transfer Surface
Air/Fuel Ratio
Regenerator Temperature Control
Stone Circulation Rate
Addition of Make-up Stone
Heat Transfer Surface
Sulfate Generator Temperature
Control .
Excess Air Circulation
Heat Transfer Surface
OPERATING VARIABLES:
Fluidization Velocity
Particle Sizes
Air/Fuel Ratio
Limes tone Make-up Rate.
Limestone Utilization
Bed Depth
Bed Temperature - Gasifier and
Regenerator
140
-------
The operating variables listed were found to be important in
the Esso, England, batch studies.
In addition, the schemes proposed
to control the temperatures of the gasifier, regenerator, and sulfate
generator are listed.
Possible methods for gasifier temperature control
are the recycle of stack gas (presently being used with the Esso,
England, continuous pilot unit); water or steam injection; the use of
heat transfer surface in the gasifier to preheat boiler water; or possi-
bly reducing the air/fuel ratio to the point of thermal balance.
In
the regenerative operation, the regenerator temperature might be
controlled by regulating the time circulation rate (as is presently
being done with the Esso, England, continuous pilot unit), by adding
fresh make-up limestone to the regenerator, or by including heat
transfer surface in the regenerator vessel.
Methods proposed for
control of the sulfate generator in the once-through operation are the
circulation of excess air through the sulfate generator or the inclusion
of heat transfer surface in the vessel.
The specifications assumed for the conceptual design are pre-
sented On the following page.
The process specifications include a
geographic location for the commercial development of the atmospheric
pressure residual oil gasification/desulfurization process in the
Eastern United States, based on market predictions.
Preliminary designs
are based on a residual oil containing 3 wt % sulfur with a low heating
value of 17,700 Btu/lb, a limestone with the composition of the U.K.
limestone investigated by Esso, England, and a sulfur removal efficiency
of 90 to 95% to meet present and future pollution standards.
For the purpose of cost estimates, a boiler capacity of 600 MW
and load factors of 40% and 80% were considered.
In general, capacities
of 100 MW and greater are of interest in the preliminary designs.
A
turn-down ratio of 4:1 was of interest with both new and retrofit designs.
The operating variables are specified according to the Esso,
England, batch data. The gasifier temperature of l600°F, for both
regenerative and once-through operations, is chosen from the Esso, Eng-
land, data as optimum from the standpoint of sulfur removal.
From
141
-------
CONCEPTUAL DESIGN SPECIFICATIONS
PROCESS SPECIFICATIONS
Geographic Location:
Eastern U.S.
Fuel Oil:
3 wt % Sulfur; LHV = 17,700 Btu/lb
U.K. Limestone
Limestone:
Sulfur Removal:
90:-95%
DESIGN VARIABLES
Boiler Size':
600 MW
Load Factor:
40%, 80%
4/1
Turn-down:
OPERATING VARIABLES
Gasifier Temperature
. Regenerator (Sulfate
Generator) Temperature
Stone Make-up Rate
Air/Fuel Ratio
Limestone Utilization
Fluidization Velocity
Particle Sizes (Avg.)
Gasifier Bed Depth
(Static)
PROJECTED PERFORMANCE
Regenerative
Once-Through.
1600°F
1900°F
1600°F
1500°F
1 mole CaO/mole sulfur
20% of stoichiometric
3 moles CaO/mole sulfur
20% of stoichiometric
~ 5 wt % sulfur in bed
8 ft/sec
~ 19 wt % sulfur in bed
8 ft see
~ 2000 J.l
2.5-3.5 ft
~ 1000 J.l
3.5-4.0 ft
Regenerative Once-Through
Sulfur Removal 90-95% 90-95%
Thermal Efficiency 90-98 90-98
Elutriation ~ 2-5% of bed/hr ~ 2-5% of bed/hr
Vanadium Retention ~ 100% ~ 100%
Sodium Retention ~ 20% ~ 20%
142
-------
the standpoint of lime regeneration, the data indicate 1900°F for the
regenerator temperature. A temperature of l500°F was chosen for the
sulfate generator based on chemical equilibrium to give an 502 partial
pressure of less than 0.01 atmospheres coming off the sulfate generator
and a high conversion of calcium sulfide to calcium sulfate, though
the kinetics of the reaction have not been investigated.
The Esso,
England, cyclic batch tests indicate that a limestone make-up rate
of 1 mole CaO per mole of sulfur fed is specific for 90 to 95% sulfur
removal in the regenerative operation with 5 wt % sulfur on the gasifier
lime, an average stone diameter of 2000 ~, a velocity of 8 ft/sec,
and a gasifier bed depth of 2.5 to 3.5 ft. A feed rate of 3 moles of CaO
per mole of sulfur fed is specified from the fresh bed data for once-
through operation to give 90 to 95% sulfur removal~ with 19 wt % sulfur on
the gasifier lime, an average stone diameter of 1000 ~, a velocity of
8 ft/sec in the gasifier, and a gasifier bed depth of 3.5 to 4.0 feet.
air:fuel ratio of 20% of stoichiometric is specified from the Esso data
An
in order to assure reasonable carbon deposition rates in the regenerative
and once-through operations.
GASIFICATION/DESULFURIZATION CONCEPTS
Fundamentally, oil gasification/desulfurization consists of a
complex cracking-partial combustion phenomenon in a fluidized bed (the
gasifier) of lime. H25 evolved during this complex operation is simul-
taneously absorbed by the lime bed to yield a clean fuel gas and a sul-
fided lime at a control temperature of l600°F. The hot, low-sulfur,
fuel gas from the gasifier is transported directly to the boiler where
combustion is completed.
This is schematically represented in Figure 36.
Two possible modes for the gasification/desulfurization operation
are the regenerative mode and the once-through mode. Figure 37 illus-
trates the major process streams and identifies the basic elements of
the two operational modes, without reference to the specific system
configuration or specific retrofit concepts. The operating variables
and temperature control schemes differ slightly for the two modes.
143
-------
.....
.po
.po
Li mestone
FI uid Bed
Gasifier
\'
Oil
----
20%
Fig. 36 -At
Conventional Boiler and
steam Turbi ne-Generator
Clean Fuel Gas
Particulates
80%
CaS to
Regenerator or '
Sulfate Generator
and Di s sat
Ai r Preheat
Dwg.2967A73
St ac k
Forced
Draft
Fan
spheric fl uidized bed oil gasification power plant
I nd uced
Draft
Fan
Ai r
-------
REGENERATIVE OPERATION
COMBUSTION AIR
60 I L E R
CLEAN fUEL
502 RICH
STREAM
SULfUR
RECOVERY
LIMESTONE
,\:E-UP
GAS I FIE R
DE5UlFURIZER
SULFIDED
LIME
REGENERATED REGENERATOR
LIME
FUel
Oil
SULFATED LIME
DISPOSAL
TEMPERATURE
CONTROL
AIR
ONCE-THROUGH OPE~AT'ON
COMBUSTION AIR
60 I L E R
CLEAN fUEL
PRE.DISPOSAL
GASifiER -
DESULfURIZER
..
fUEl OIL
TEMPERATURE
CONTROL
FIG. 37-0PERATING MODES roo flUIDIZED BED Oil GASIFICATlONIDESUlFllHZATION
-------
The basic elements of the regenerative operation are
the gasifier vessel and the regenerator vessel, as shown in Figure 37.
In the regenerative operation, residual oil is injected into the gasifier
vessel, an air-fluidized bed of lime at 1600°F operated with substoichi-
ometric air (~ ZO% of stoichiometric). The processes of
combustion, an~ HZ5 absorption by the lime, yield a hot,
gas and a su1fided lime. The fuel gas is transported to
cracking, partial
low-sulfur, fuel
the boiler burners,
where combustion is completed, and the su1fided lime is sent to the
regenera tor.
The regenerator is an air-fluidized vessel operated with
a slight excess of air at 1900°F.
Regeneration takes place by reaction
of oxygen with the utilized lime to give an 50Z rich stream (of about
10 mole % 50Z) and a regenerated lime with a decreased activity com-
pared to .that of fresh lime. The 50Z stream is transported to a sulfur
recovery system, and the regenerated lime is returned to the gasifier
along with a nearly stoichiometric amount of fresh make-up limestone.
A variety of temperature control schemes may be useful
. .
in controlling the temperature of the gasifier and the regen-
erator.
The temperature control scheme used in the gasifier must con-
serve the energy of the fuel in a form usable in the boiler.
For this
reason water injection, steam injection, and stack gas recycle are con-
sidered for temperature control of the gasifier
by the storage of sen-
sible heat.
The use of heat transfer surface in the gasifier to
preheat boiler water is also an attractive possibility.
A fifth possi-
bi1ity exists in the air/fuel ratio, which might be lowered to a value
low enough (~ 14% of stoichiometric) that the gasifier is thermally
balanced and no further temperature control need be .considered.
Because of the high cost of sulfur recovery, temperature
control of the regenerator is best accomplished in a way that avoids
diluting the 50Z stream produc.ed by regeneration. For this reason,
temperature control by heat transfer surface in the regenerator, by
the addition of fresh make-up stone to the regenerator, or by controlling
the rate of lime circulation between the gasifier and regenerator
is investigated.
146
-------
The important operating variables in the regenerative operation
are the air/fuel ratio, the gasifier and regenerator temperatures, the
limestone particle size,
the gasifier and regenerator fluidization
velocities and bed depths, the stone residence times in both the gasifier
and regenerator, and the limestone make-up rate.
The effects of these
variables are interrelated with the temperature control schemes used and
the fuel and limestone properties.
An important phenomenon which takes place in the gasifier
during the cracking-partial oxidation is the deposition of carbon, or
coking, on the gasifier lime.
Carbon deposition affects the sulfur
removal efficiency, the thermal efficiency of the system, and the overall
operation of the gasifier and regenerator when in the regenerative mode.
Minimizing the rate of carbon deposition is, then, an important design
consideration.
Figure
vessel.
The elements of the once-through operation, shown in
37 , are a gasifier vessel and a sulfate generator, or pre-disposal
The operation of the once-through gasifier is the same as
that of the regenerative operation gasifier. The sulfate generator
operates similarly to the regenerator but at a lower temperature (~1500°F)
so the sulfated lime from the gasifier is converted to calcium sulfate
rather than calcium oxide.
The calcium sulfate may be disposed of while
the gas stream from the sulfate generator is sent to the gasifier.
A
limestone addition rate of three to four times that used in the regenera-
tive operation is necessary in the once-through operation.
The same five temperature control methods proposed for the
regenerative gasifier are considered for the once-through gasifier,
while the sulfate generator temperature is controlled by one of two pro-
posed schemes: heat transfer surface or excess air circulation.
The same operating variables are important in the once-through
operation as in the regenerative operation, and carbon deposition is
again an important factor in determining the sulfur removal efficiency
and the overall system operation. However, in the once-through operation,
147
-------
the carbon deposition rate does not'affect the system I.S thermal efficiency
because the thermal energy of the deposited carbon is recycled as sensi-
ble heat from the sulfate generator back to the gasifier.
DESIGN
Energy and material balances provide basic informationwi.th
which the feasibility of applying ,the gasifi,cationl desulfuriza tion 'con-
~ept as an add-on to an existing boiler, or as a new plant design
feature, may be examined.
The 'feasibili,tyofthe retrofit concept is
examined in terms of the availability of space in an exis.tingpower .
plant, the modifications necessary .to retrofit ,an existing boiler, 'and
the performance of a modified boiler.
Plant Layout::
Figures 38
and 39
show .plant layouts for.
200 MW regenerative and once-through gasification/desulturization systems.
The plants consist of two gasification modules, each utilizing air
from one of the two 'power plant forced draft£anspresent in the
existing. boiler.
Equipment: Gasification/desulfurization equipment .necessary
for a retrofit boiler isiisted below. However, .the .equipment w.ill
vary from one retrofi tto another, depending on the type of boiler being
retrofi t.
Both once-through and regenerative modes are considered in
the table, and boiler modifica.tion is included as a factor' in the
following equipment list':
PLANT EQUIPMENT
Regenerative
Gasifier Vessel
Regenerator Vessel
Limestone Handling Equip.
Sulfur Recovery Plant
Fans, Compressors
Storage
Particulate Clean-up Equip.
Burners
Boiler Modification
Once-through
Gasifier Vessel
.Sulfate Generator Vessel
Limestone Handling Equip.
Fans" Cbmpres'so'rs
Storage
'Particulate Clean-up Equip.
Burners
Boiler "Modification
148
-------
" /
\. /
8 6
5
12 7
~ ..
20 Ft
Fig. 38
......
~
\D
200 MW Boiler Retrofit-
External Regenerative Design
1. Gasifier-Desulfurizer
2. Regenerator
3. Sulfated-Lime Bunker
4. Limestone Bunker, Feeder
5. Forced Draft Fan
6. Gasifier Fan
7. Regenerator Fan
8. Oil Feed Li ne
9. Fuel Gas Line
10. Regenerator Product Li ne
II. Li me Ci rculation Li ne
12. Sulfated-Lime Di sposal Li ne
13. Burners
- Solids Transport
lZZ& Gas Transport
10
-----
/'
c~
,
Fu rnace
4
Dwg. 2960A96
-------
200 MW Boiler Retrofit-
External Once-Through Desi[!!
I. Gasifier-Desulfurizer
2. Sulfate Generator ./
3. Sulfated-Li me Bunker ,/
,
4. Limestone Bunker, Feeder ,
5. High -Efficiency Cyclone "
6. Forced Draft Fan Furnace
7. Gasifier Fan
8. Sulfate Generator Fan
9. Oil Feed Li ne
10. Fuel Gas Li ne ------
I-' II. Lime Ci rculation Li ne 4
VI
0
12. Sulfated-Lime Disposal Line ---_/
13. Burners /
- Solids Transport /
?ZZZZ Gas Transport /
9 7
6
12
-C
..
20 Ft
Fig. 39
Dwg. 2960A97
-------
Retrofit Concepts:
The feasibility of converting an existing
boiler to one which utilizes the fuel from a gasification/desulfuriza-
tion system depends on a number of factors, many of which will differ
from one boiler to the next. The space available for a gasification/
desulfurization system in an existing power plant, the modifications
necessary to retrofit an existing boiler, and the performance of a
retrofit boiler will depend on the specific gasification/desulfurization
system design and choice of operating conditions, the location of the
gasification/desulfurization system in the plant, the type of boiler
(coal- or oil-fired), size of boiler, the turn-~own needed, the boiler
load factor, and the specific design features of the boiler. These'
factors are discussed with respect to the location of the gasification/
desulfurization system relative to the boiler, and the importance of
boiler performance in a retrofit boiler.
The gasification system may be placed internal to the boiler
(directly beneath) or external to the boiler (as close as possible with-
out carrying out major boiler modifications in order to locate the
system).. These concepts are illustrated in Figure 40.
Using the criterion that the internal design is feasible if
the boiler cross-section is larger than the gasifier cross-section leads
to the conclusions in the following list of retrofit design factors:
Critical Factors in Determining Feasibility of Internal Retrofit Design
-- Regenerative or Once-through
Superficial Velocity
Air/Fuel Ratio
Temperature Control Method
Boiler Type (Coal or Oil) and Size
Feasibility Limits on the Internal Retrofit -- Based on Boiler Capacity
> 100 MW
Superficial Velocity> 8 ft/sec
Air/Fuel Ratio < 20% of Stoichiometric
Temperature Control by Minimum Air/Fuel Ratio and Heat Transfer
Surface Feasible for Boilers> 100 MW
Temperature Control by Stack Gas Recycle, Steam and Water In-
jection Feasible for Boilers < 200 MW
Internal Design More Probable With Coal- than with Oil-fired
Boilers
151
-------
Dwg. 2947A66
Boiler
Boiler
Boiler
Normal.
Bu rner
. Locat io n
-- f Air Regenerator
Gasifier 25 Ft Gasifier
Fuel __1 Fuel Fuel
I +
I
t-' I Air Air
V1 Air
N I I
f4- 30 Ft------i Internal Unit
Air
Burners
Regenerator
.. Boiler
Gas ifier
Fuel
Air Air
External Unit
Fig. 40-Boiler add-on concepts
-------
The lists of retrofit factors on the next two pages summarize
the points affecting the feasibility of boiler retrofits. The first
compares the internal and the external location of the gasification/
desu1furization system, while the second compares the modifications
and boiler performance probable with coa1- and oil-fired retrofits.
The factors presented in both lists seem to favor the
external retrofit design over the internal retrofit design, and the
feasibility of retrofitting a coal-fired boiler over the feasibility of
retrofitting an oil-fired boiler. However, these preliminary investiga-
tions do not eliminate the possibility of the internal retrofit design
or the retrofit of oil-fired bci1ers.
In contrast to boiler retrofit considerations, the feasibility
of incorporating a gasification/desu1furization system into a new boiler
design will be limited only by the overall economics of the system and the
market potential for new oil-fired boilers.
The total space occupied by
the gasification/desu1furization system will be a small percentage of
the total plant volume. Also, because of the flexibility in boiler design,
boiler performance will not be affected by the presence of the gasifica-
tion/desulfurization system.
Market studies indicate that the number of new oil-fired boilers
which will be constructed will decrease, with practically no new oi1-
fired boilers being constructed after 1980(16~ Based on this projection,
the gasification/desulfurization of residual oil will be limited to the
retrofit of existing boilers, regardless of the system economics.
Fur-
ther investigation of the market potential of the new boiler system is
needed.
ECONOMICS
Table 29 lists the preliminary cost breakdown for the major
equipment included in a 600 MW regenerative retrofit and a new system.
Total investment is indicated for each of the five proposed temperature
control methods in $/kW.
The cases of boiler retrofit with and without
153
-------
Internal Location
GASIFIER RETROFIT LOCATION FACTORS
Space Requirements
Under suitable operating conditions space avail-
able beneath the boiler may be utilized (Table
6-16).
The cross-sectional area needed to place
burners in the upshot position at the base of
the boiler may limit the concept (new burners
may be 1.5-3 times the size of normal oil or
coal burners).
Design if limited by the available overhead
space if particulate control is needed before
burners.
~
Un
~
Probably not feasible with modular design in
large boilers (> 500 MW) except at velocities
» 8 ft/sec.
Modification Factor
More extensive modifications required, more
down time, involved in removal of ash pit,
auxiliary equipment, alterations to water walls
and foundations.
Construction more expensive in comfined quar-
ters beneath boiler.
The amount of piping and manifolding may be
minimized with burners placed in the base of
the boiler.
Each boiler retrofit design may need to be
treated as a unique case.
External Location
Space must be found or provided as near to the
boiler as possible.
More flexibility which is present in the external
design may allow operating with maximum fuel heat-
ing value to minimize burner sizes.
Feasibility not as limited by the space required
for modular design, overhead space, or other
spatial considerations.
Modifications consist of removal of auxiliary
equipment, such as pulverizers, and addition of
new burners.
Prefabrication of vessels possible.
Relatively great amount of high temperature, non-
corrosive, piping and manifolding necessary,
though the same may be true with internal design.
More uniformity in design from one retrofit to
another.
-------
~
In
In
GASIFIER RETROFIT LOCATION FACTORS (Continued)
Internal Location
Performance Factor
The need for operating conditions giving maximum
gasifier compactness may be detrimental to the
system performance.
External Location
Greater flexibility in the operating conditions
which is present with external design may allow
operation at under optimum conditions.
-------
RETROFIT OF COAL-AND OIL-FIRED BOILERS
Space Requirements
Coal-fired boilers have larger cross-sections than
large capacity (> 100 MW)
Cross-sections are comparable for smaller capacity boilers « 100 MW)
oil-fired boilers at
Headroom is nearly the same in coal-and oil-fired boilers at 12-25 feet.
More potential space exists near a coal-fired boiler than near
fired boiler - pulverizers and other auxiliary equipment
removed - especially advantageous if the coal boiler has
viously converted to operate with low-sulfur oil..
an oil-
may be
been pre-
Modification Factors
Normal coal and oil burners are nearly the same size (200 MW Btu/hr
burner is 10-11 ft2 in port cross-section).
Much solid handling equipment and particulate clean-up equipment may
already exist with a coal-fired boiler. Increased particulate
control would probably be needed with an oil-fired boiler.
Performance Factors
Coal-fired boilers are designed to operate with slag on the boiler heat
transfer surface, which may make boiler derate negligible with coal-
fired boilers. Boiler derate may be important with oil-fired
boilers depending on the gasifier temperature control method.
156
-------
TABLE 29
REGENERATIVE OPERATION CAPITAL COSTS - 600 MW
EQUIPMENT x 10-3 $ TEMPERATURE CONTROL METHOD
Heat Transfer Minimum
Surface Air/Fuel
Gasifier 1,020(a) 310 850 870 560
Reg ener a tor (b) 135 135 138 144 140
Limestone Handling 1,225 1,225 1,235 1,315 1,260
Fans 300 200 400 400 300
Burners 720 610 900 890 780
Particulate C1ean-up(c) 1,620 1,510 2,030 1,980 1,760
Boiler Modifications 900 900 900 900 900
Equipment 5,920 4,890 6,453 6,499 5,700
Installation 2,960 2,445 3,227 3,250 2,850
Direct Cost 8,880 7,335 9,680 9,749 8,550
Eng., Cont., Const. 2,660 2,200 2,910 2,930 2,570
I-' Sulfur Recovery 3,300 3,300 3,340 3,540 3,440
VI
-....J
Total Investment 14,840 12,835 15,930 16,219 14,560
Retrofit $/kW 24.7 21.4 26.6 27.0 24.2
Retrofit $/kW
(without particulate control) 19.5 16.5 20.0 20.6 18.6
New $/kW
(without particulate control) 14.3 11.6 14.2 14.8 13.1
(a) Gasifier cost doubled to include heat transfer requirement.
(b) Regenerator temp. control by heat transfer surface - doubles vessel cost.
(c) Particulate clean-up includes cyclones prior to burners and electrostatic
clean-up.
precipitator final
-------
the cost of particulate control equipment (cyclones prior to combustion
and electrostatic precipitator final clean-up) .are included, along with
the estimated cost for the regene~ative gasifier/desulfurization system
when combined with a new boiler design.
Table 30 summarizes operating costs for a 600 MW regenerative
operation (new and retrofit) with an 80% load factor.
The case of
retrofit with a 40% load factor is included to show the effect of this
important variable on the system operating cost.
The three most important factors in determining the economics
of the'~egenerative operation are:
the carbon deposition rate; the
air/fuel ratio; and the overall system efficiency.
The capital cost breakdown for 600 MW once-through operation,
new and retrofit, is summarized in Table 31. Temperature control :.
by heat transfer surface, minimum air/fuel ratio, and stack gas recycle
are considered, and the total capital investment in $/kW is shown for
retrofits with and without particulate control, and for a new boiler
excluding the cost of particulate control.
Operating costs, in ~/l06 Btu, are shown in Table 32 for the
three temperature control schemes.
Both 8~ and 40% load factors are
considered in the table,and the results for retrofits and new designs
are shown.
With once-through operatio~ the air/fuel ratio controls the
equipment sizes and the particulate clean-up costs and affects the sys-
tem efficiency. The overall efficiency determines the direct fuel adder
cost, but the rate of carbon deposition plays a much less important part
in the system economics.
EVALUATION
The regenerative and once-through modes of operation have been
compared, and the merits and disadvantages of each mode have been
considered.
The costs and pollution control potential of residual oil
158
-------
TABLE 30
OPERATING COSTS FOR REGENERATIVE OPERATION - 600 MW, 80% LOAD FACTOR
Heat Transfer Minimum Stack Gas Steam Water
Surface Air/Fuel Recycle Injection Injection
3 (a) 1620 1340
Capital Charges 10 $/yr 1770 1780 1560
Maintenance (a) 580 480 630 640 560
Overhead (a) 460 380 510 510 450
Limestone (2.5/ton) 278 278 280 296 284
Disposal ($1.30/ton) 145 145 146 154 148
Sulfur Recovery (b) 1210 1210 1210 1270 1240
Fuel Adder ($3/bb1) 928 855 1010 2940 1580
5221 4688 5556 7590 5822
..... Retrofit Fuel Adder;c)
VI ~/106 Btu (80% Load Factor) 12.4 11.2 13.2 18.1 13.9
~
(40% Load Factor) 18.8 16.4 20.1 25.0 20.0
New Design Fuel Adder,
~/106 Btu (80% Load Factor) 10.7 9.5 11.1 16.0 12.0
(a) Includes particulate control.
(b) Based on overall efficiency. 6
(c) No sulfur credit - credit would amount to about 1.5~/10 Btu at $15/ton of sulfur.
-------
TABLE 31
ONCE-THROUGH OPERATION CAPITAL COSTS - 600 MW
-3
EQU IPMENT x 10
$
TEMPERATURE CONTROL METHOD
Heat Transfer Minimum Stack Gas
Surface Air/Fuel Recvc1e
Gasifier 1,020 310 850
Sulfate Generator 188 188 188
Limestone Handling 1,320 1,320 1,330
Fans 300 300 400
Burners 720 610 .900
Particulate Clean-up 1,820 1,710 2,230
Boiler Modifications 900 900 900
Equipment 6,268 5,338 6,798
Installation 3 ,134 2,669 3,399
Direct Cost 9,402 8,007 10,197
Eng., Cont., Const. 2,820 2,400 3,060
Total Investment 12,222 10,407 13,257
Retrofit, $/kW 20.4 17.3 22.1
Retrofit, $/kW
(Without Particulate Control) 15.2 12.4 15.5
New, $/kW
(Without Particulate Control) 10.0 7.5 9.7
160
-------
TABLE 32
OPERATING COSTS FOR ONCE-THROUGH OPERATION - 600 MW, 80% LOAD FACTOR
Heat Transfer
Surface
Minimum
Air/Fuel
103 $/yr (a)
1710
610
490
835
435
830
1460
520
420
835
435
740
Capital Charges
Maintenance (a)
Overhead (a)
Limestone ($2.50/ton)
Disposal ($1.30/ton)
Fuel Adder ($3/bb1) (b)
4910
4410
Retrofit Fuel Adder
~/106 Btu (80% Load Factor)
(40% Load Factor)
New Design Fuel Adder
~/106 Btu (80% Load Factor)
11. 7
18.4
10.5
16.2
9.9
8.9
Stack Gas
Recycle
1855
665
530
840
435
928
5253
12.5
19.7
10.4
(a) Includes particulate control.
(b) Based on overall efficiency.
161
-------
gasification/desulfurization are compared with the low-sulfur oil and
stack gas cleaning alternatives.
In addition, preliminary design
conclusions are listed to summarize the results of the technical
feasibility studies.
Comparison Between Regenerative. and Once-Through Operations
The relative merits of the two modes of operation are summarized
.. .
on the following page. Preliminary investigations indicate that, overa~l,
the once-through operations may be somewhat more. attractive to a utility
customer than the regeneratiyeoperation. Further research into the
areas of sulfur recovery and system dynamics may alter this outlook.
Comparison With Other S02 Control Methods
A comparison is made in Table 33 between atmospheric
pressure oil gasification/desulfurization and the alternative schemes
of low-sulfur oil and stack gas cleaning. Capital costs and operating
costs are compared for new and retrofit systems. OiJ,.gasification/
desulfurization
compares favorably with low-sulfur oil and stack gas
on the preliminary cost estimates presented in Tables
A reduction of about 40% in the capital costs involv~d
cleaning, based
29 through 32.
in stack gas cleaning is estimated for new and retrofit gasification/
desulfurization systems. Operating costs appear to be about the same
for once-through stack gas cleaning and regenerative gasification/
desulfurization with sulfur recovery. Once~through gasification/
desulfurization may reduce the operating. costs 30 to 50% as compared to
stack gas cleaning. The cost estimate indicates that the operating cost
with low-sulfur fuel oil will be about 20% greater than the operating
cost for gasification/desulfurization.
These conclusions are based on
the desulfurization of high-sulfur residual oil (3 wt. % sulfur) and may
be altered when a lower sulfur oil is considered (1 to 1.5 wt. % sulfur).
Environmental factors are also compared in Table 23. The low-sulfur oil
is advantageous in that capital costs are limited to possible boiler
162
-------
COMPARISON BETWEEN MODES OF OPERATION
ECONOMICS
Once-through operation requires lowest capital investment.
Operating costs are nearly identical for once-through and regenerative
operations (mainly because of the high cost associated with sulfur
recovery).
Sulfur credit does not greatly reduce the operating cost of a regenera-
tive operation.
SPACE REQUIREMENTS
Both modes have the same potential equipment sizes, though the regenera-
tive operation requires a large space for sulfur recovery making the
once-through more compact in an overall sense.
Once-through may require deeper gasifier bed depth and larger limestone
handling equipment.
PERFORMANCE
Both modes have same potential for sulfur removal.
Once-through may be slightly more efficient than regenerative.
Once-through has higher power requirements.
Once-through thermal efficiency is independent of carbon deposition rate.
Regenerative operation minimizes stone disposal rate.
Once-through presently has fewer technical problems.
UTILITY REACTION FACTORS
Regenerative mode puts utility in the chemical business.
Once-through is the simplest mode of operation, but may increase
. - . . - . .
waste problem unless high stone utilization can be achieved.
solid
163
-------
TABLE 33
Basis:
ASSESSMENT OF FLUIDIZED BED OIL GASIFICATION-DESULFURIZATION
3% Sulfur, 90% Sulfur Removal, 600 MW Capacity
COST
Capital, $/kW
New
Retrofit
Fuel Adder, ~/106 Btu
New
Retrofit
.....
'"
~
EFFICIENCY
ENVIRONMENTAL FACTORS
S02' ppm (lb/106 Btu)
NOx, ppm (lb N02/106 ~tu)
Particulates, gr/SCF
(lb/106 Btu)
Solid Waste, ft3/MW-day
S REMOVAL
Stone
Ca/S
Make-up Ca/S
Low-Sulfur
Oil
Stack Gas
Cleaning
011 Gasification
Regenerative Once-Through
Operation Operation
(a)
25 12-15 (b) , 8-10(b)
40-75 22-27 (b) 18-22 (b)
11 9.5-16.0(b) 9-10.5(b)
14-20 11-18 (b) 10.5~12.5(b)
0.95-0.98 0.89-0.96(c) 0.96-0.97(c)
100-110 80-100 80-100
(0.45) (0.35) (0.35)
400-700 100~150 100-150
(0.8) (0.16) (0.16)
0.03 0.01-0.10(d) 0.01-0.10(d)
(0.05) (0.02-0.2) (0.02-0.2)
25 15 45
17-23
17-23(a)
80-100
(0.35)
200-400
(0.40)
0.03
(0.06)
NA
NA
NA
Limestone
'" 15 (e)
1.0
, Limestone
3.0
NA
(a) Equipment modifications are required when converting from gas or coal to low' sulfur oil.
(b) See Tables 29 through 32 for details.
(c) Overall efficiency is dependent on mode of temperature control.
(d) 0.01 figure based on installing electrostatic precipitator (ESP).
0.1 figure based on installing high efficiency cyclone before burners and no ESP.
(e) Ca/S rated dependent on regenerator temperature control scheme.
-------
modifications necessary when changing from gas or coal to low-sulfur oil.
On the other hand, operating costs are higher than those for stack gas
cleaning or oil gasification/desulfurization. Capital costs are
extremely high with stack gas cleaning, especially in the retrofit case,
while operating costs are very near those estimated for oil gasification/
desulfurization.
Preliminary design conclusions based on the technical investi-
gations carried out are listed below.
Though the analysis has raised
many technical questions, the preliminary investigation, coupled with
the experimental work of Esso, England, points out the general feasibility
of oil gasification/desulfurization as a retrofit S02 control system for
utility boilers.
PRELIMINARY DESIGN CONCLUSIONS
TECHNICAL PROBLEM AREAS
Sulfur recovery
Boiler derate and boiler modifications
Calcium sulfate generation
Temperature control
Lime circulation
CURRENT OUTLOOK
Overall, once-through
stone utilization can
(Table 33).
operation appears superior to regenerative if high
be achieved though this is not definite
Gasifier temperature control by means of the minimum air/fuel ratio
appears superior to other methods, if it can be achieved in prac-
tice. Temperature control with heat transfer surface also may be
attractive if high air/fuel ratios (~ 20%) must be used in opera-
tion.
165
-------
The regenerator temperature control is
lation if carbon deposition is small.
then heat transfer surface is the most
. . .
best carried out by stone circu-
If carbon deposition is large,
efficient method.
Sulfate generator temperature control is most easily carried out by
circulating excess air through the generator.
The situation concerning the internal and external design concept is not
clear (page 154) with the number of variable factors which are involved.
It seems reasonable to strive to minimize the expense and .time involved
in boiler modifications.
The greatest market for oil gasification/desulfurization appears to be
in. retrofits at the present time. The problems involved with retrofits
should be examined in more detail.
Oil gasification/desulfurization concepts appear highly competitive with
other retrofit or new S02 control methods based on preliminary designs
(Table 33), and should be investigated in greater detail (see Recommendations).
166
-------
FLUIDIZED BED FUEL PROCESSING DEVELOPMENT PLANTS
Conceptual designs, costs, and schedules for a 10 to 30 MW
pressurized fluidized bed combustion boiler development plant and a
100 to 200 MW retrofit atmospheric pressure oil gasification demonstration
plant have been prepared.
PRESSURIZED FLUID BED COMBUSTION BOILER DEVELOPMENT PLANT
The development plant is designed to provide information which
will permit the construction of a 150 to 300 MW demonstration power plant.
The development plant. is required to provide information on the
performance of the proposed boiler plant equipment design:
. Operation of deep beds (10 to 20 ft) with horizontal tube
bundles
. Particulate removal
. Coal and sorbent handling and feeding systems
. Materials and component life - boiler tubes and gas turbine
blades
. Operation - start-up, shut-down, load follow
. Regeneration/sulfur recovery process demonstration.
A flow diagram of the pressurized fluid bed combination boiler
development plant is shown in Figure 41. The plant is located adjacent
to a large power plant and has access to the power plant to provide
interfaces with the coal, water, steam, waste stone, and utilities.
The
facility is designed to operate over the following range of operating
conditions:
Pressure
up to 20 atm
l30Q-2000°F
Bed Temperature
Gas Velocity
Bed Depth
6-15 fps
10-30 ft
167
-------
Dolomite Receiviny
Hopper
(!)
Coal from
Power Plant
Storage
f-'
0\
00
Crusher
Storage
Bin
Storage
I nj ector
Coal
I nj ector
Transport
Ai r from
C:ompressor
To Stack or
Scrubber
Storage
Silo
Natu ra 1
Gas
Pressurized
Fluid Bed
Boiler
&
Water from
Plant
ranspor
Ai r
Q)
Primary
CoIl ector
....---c;@
@
Secondary
Collector
Lock
Hopper
~mpressor
@
Steam
to Plant
@
Spent
Stone
CD
Regenerated
Stone
Ai r
@
Regenerator 10ck
System Hopper
Gas
Generator
Waste
Stone
Location: Existing Powe r Plant
Fig.41 -Flow diagram for development plant facility
Dwg. 2949A35
Turbine
Blade Test
Cascade
Waste
Sol ids
@
To Plant
Stack
-------
The boiler is designed to handle up to 500,000 lb/hr of steam flow.
The
unit would function as either a pre-evaporator, superheater, or reheater.
Water evaporation in the walls could also be studied.
The boiler is a single fluidized bed with a carbon burn-up
cell. The design is based on the proposed design by Westinghouse and
Foster Wheeler. The water-walled, fluidized bed boiler would be placed
in a pressure shell which would be larger than required for commercial
operation. A vessel 15 to 20 feet in diameter and 50 to 70 feet high
is projected. This will permit easy access, flexibility for modifica-
tions, and functioning over a wide range of operating conditions.
Coal receiving equipment and storage is assumed to be available
from the power plant. Coal and dolomite handling equipment specified
for the development plant include a dolomite receiving hopper, dolomite
storage silo, dolomite crusher, coal dryer, and coal crusher.
The coal
feed system and particulate removal equipment are the same as the pro-
posed design. The air compressor is independent of the gas turbine test
system. Initial gas turbine tests will be carried out with a turbine
blade test cascade. The second phase of operation includes a rotating
gas turbine unit. The two-step regeneration process is specified in the
present design concept.
The development plant program is broken down into three phases
of operation:
Phase I - Operation of fluid bed boiler with turbine blade test
cascade and without sorbent regeneration process
Phase II - Operation of integrated syste~including gas turbine
and regeneration process
Phase III - Operation to evaluate alternative concepts, e.g., regen-
eration processes, bed design, steam conditions.
The first phase would provide information to assess the proposed
design concept -- boiler and carbon burn-up cell.
The second-phase operation would incorporate design modifica-
tions recommended from the analysis of Phase I data, and the parallel
169.
-------
research and development efforts include a regeneration process and a
small gas turbine unit. A sulfur recovery process should also be'
considered if development effort is required.
The third-phase operation would be used to assess alternative
concepts. Development of the third-phase program will rely on the
results of the analysis of data from Phases I and II, results of pilot
and bench scale experimental programs, and recommendations from systems
evaluation and advanced concept studies. This phase might include the
evaluation of higher gas turbine temperatures, higher steam. temperatures
and pressures, alternative regeneration/sulfur recovery processes, and
circulating bed boiler concepts.
The estimate for the development plant equipment, installed
out-of-doors adjacent to a large central station power plan~ is
$7,000,000.
A development plant schedule has been prepared and is presented
in Figure 42. The. proiected time required to assess the combustor
design, develop a regenerator process, and obtain data on turbine blade
performance is four years. The plant could then be used to study
alternative boiler and regeneration system concepts.
ATMOSPHERIC PRESSURE OIL GASIFICATION DEMONSTRATION PLANT
The economics of a utility boiler retrofit system appear
competitive with wet scrubbing systems and with the purchase of clean
fuel.
Demonstration plant concept designs were reviewed in a previous
section.
A demonstration plant with a capacity of 100 to 200 MW is the
best size from the standpoint of being representative of the boiler
retrofit market while minimizing the scale-up factor. For boiler sizes
less than about 80 MW, the overall boiler design differs greatly from
that of boilers in the 100 to 800 MW range.
The 100 to 200 MW capacity boiler
170
-------
1972
Jan
I I I I I
Preliminary Design
Detail Design
,...
.....
,...
Construction
Start-Up
Phase I Operation-Combustor/Turbine Blade Cascade
Modifications
1973
Jan
I I I I I
I
1974
Jan
I I I I
Phase II Operation -Combustor/Regeneration! Gas Tu rbi ne
Modifications
Phase III Operation-Alternate Concepts
1975
Jan
I I I I I I I I
t
f--f
I
Fig. 42 -10-30 MW pressurized fl uid bed boiler development plant schedule
Dwg. 723B399
1976
Jan
I I I I
I.
J---i
1977.
Jan
I I I I I
I------t
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may. also be more ava,ilable. than a smaller capacity., uni..t-. Although the
scale-up from the 'VI MW pilot plant unit. of Esso,. England, to' a
100 to 200 MW system is considerable.. this repres.ents. the' minimum s.cal~-up'
factor which will give meaningful demonstrati.on results. within the
nex.t five years..
The. cost of. the' installed< equipment for' a, 200: MW demons;t.ra.tion
plant is; es timated to' be. $6,.000,,000. If' the plant :i:nclud>es. a sulfur;'
recovery' sys.tem',. the cost would~ be approximately' $'8',,000',,000...
The schedule for an atmospheric' pressuI.'e o:i::1!, gasification:
demonstration pI ant' fs' shown; in FigU1!.e 43..
Ji72
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0"9. 7238675
FIG. 43-DEMONSTRATION PLANT SCHEDULE
Atmospheric Oil Gasification/Desulfurization Process for Existing Steam PONer Plants
1972 1973 1974 1975
Jan. April July Oct. Jan. April July Oct. Jan. April July Oct. Jan. Cost
I I I I I I I I I I I I I
Contact Uti I iti es ~
Select Engineering Firm 3
Preliminary Design I\¥ $ 30,000 a
Detailed Design and Installation $ . b
6,000,000
W '0/ $ 24, OOO/day c
Developmental Operation
Conti nuous Operation 6 d
. ..... 6. 5~/10 Btu fuel adder
""
Milestones
W Cooperating utility identified
VI Engineering firm contract signed for preliminary design
W Decision on construction; agreement between OAP - utility - @ - AE
W Shake down complete
W Engi neeri ng and economic data for future operations complete
Footnotes
a Cost estimate for preliminary design
b Assumes complete 100 MW gasifier module, once-through limestone system
c Maxi mu m cost per day assu mes conti nuous oil feed, 0 & M for gasifier development, and no power generation
d Based on conceptual design
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CONCLUSIONS
FLUIDIZED BED COMBUSTION BOILERS
Boiler Design
The following operating and design characteristics are required
for economical design:
. Standardized modules with maximum shop fabrication
. High gas velocities, 8 to 15 fps
. Large coal and limestone/dolomite, 1/8-1/4 inch top size
Boiler Performance
Laboratory and pilot scale tests have produced essential
information in a number of critical subject areas:
. Sulfur dioxide:
80 to 95% sulfur removal has been demonstrated
with limestone and dolomite.
. Nitrogen oxides: atmospheric pressure two-stage combustion has
reduced NO to about 70 ppm; pressurized single-stage combustion
x
has reduced NO to 50-150 ppm.
x
. Particulates: particulate loading is comparable with conventional
plants. Fine particulate « 10 ~m) emissions may be significantly
reduced compared with p.f. coal-fired plants.
. Combustible losses:
combustible losses can be minimized by
collecting high carbon content solids from primary beds and
recovering the energy in a carbon burn-up cell.
. Ash fouling:
reduced ash corrosion, erosion, and fouling may
increase boiler availability.
175
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Industrial Fluidized Bed Combustion Boilers
Market
. Industrial boilers will probably continue to use clean fuels as
long as these are available.
. Limestone regeneration/sulfur recovery on-site is not considered
practical.
Economics
. Fluidized bed industrial boiler cost estimates do not show
significant (> 10%) cost advantages over conventional coal-
fired boilers with 502 control.
. Gas- or oil-fired fluidized bed boilers are not economical in
comparison with conventional packaged boilers.
. Fluidized bed boilers are economical for burning low-sulfur
char or other low-grade fuels.
Utility Fluidized Bed Combustion Boilers
Market
. The market for fossil fuel power plants is ~30 gigawatts/yr; the
most frequently installed plant capacity is about 600 megawatts.
. Coal reserves provide a 200 to 500 year supply.
. Both plants with once-through operation and those with sulfur
recovery have potential markets, depending on plant capacity,
fuel, and location.
Economics Compared with a Conventional Pulverized
Fuel Power Plant with Stack Gas Cleaning
. Capital cost savings for atmospheric pressure plants may be 7%
for a sulfur recovery system, 12% for a once-through system.
. Capital cost savings for pressurized combined cycle plants may
be 18% for a sulfur recovery system, 21% for a once-through system.
17.6
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. Energy cost reduction for atmospheric pressure plants may be
2 to 7%.
. Energy cost reduction for pressurized combined cycle plants
may be 10 to 12%.
Performance
. Pressurized combined cycle plants show greater pollution abatement.
. Pressurized combined cycle plants have greater efficiency.
Development Status
. The time and effort devoted to atmospheric pressure fluidized'
bed combustion has been an order of magnitude greater than that
devoted to pressurized. However, the technical accomplishments
appear comparab1e~
. Both atmospheric and pressurized fluidized bed power systems
require further development effort. Data can be most rapidly
and economically acquired on development-scale equipment --
e.8., coal feeding, NO minimization, and control for both
x
atmospheric and pressure operation; deep beds, particulate removal,
gas turbine blade performance for pressurized operation.
Potential
. No problems have been identified which would preclude the
development of fluidized bed combustion boilers.
. Potential improvements in a second generation of boilers for
utility applications include
raising steam temperature and pressure
above the present maximums -- 1050°F, 3500 psi.
Pressurized
combined cycle plants have the potential for further reduction of
heat rate by going to higher gas turbine temperatures.
. Low-grade fuels can be burned.
177 .
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ATMOSPHERIC PRESSURE FLUIDIZED BED OIL GASIFICATION
Market
. New oil-fired electric utility installations during 1971 through
1980 are projected to be 6.2 gigawatts.
. Oil utilization by electric utilities beyond 1980 should
be surveyed.
. Initial market is expected to be small boilers « 600 MW) on the
East Coast, in the Southwest where gas may be limited, or on the
West Coast. Once-through operation is favored over operation
with sulfur recovery for these plants.
Economics for Comparable Pollution Abatement
. Capital cost of a retrofit, once-through gasification system
may be 50 to 70% less than a retrofit wet scrubbing system.
. Capital cost of new gasification systems (once-through or sulfur
recovery) may be 20 to 50% less than a new wet scrubbing system.
To'tal plant cost savings may be 1 to 4%.
. Fuel adder cost for a retrofit, once-through gasification
system may be 30 to 50%* less than wet scrubbing, low-sulfur
oil, or desulfurized oil.
. Fuel adder cost for new gasification systems (once-through or
sulfur recovery, without a sulfur credit) may be 20 to 30% less
than wet scrubbing, low-sulfur oil, or desu1furized oil.
energy cost savings may be 1 to 3%.
Total
. Calcium oxide produced in the gasification concept may be a
valuable by-product for use in wet scrubbing systems, which may
be used in near-by plants.
Performance
. Sulfur removal up to 95% can be achieved.
. Nitrogen oxide emissions of 150 ppm appear possible.
*
Based on,$2.50/ton limestone.
178
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L
. Particulate emissions will be higher than conventional oil-
fired systems but can easily be removed to achieve proposed
standards.
. Solid waste will be dry and comparable in quantity to wet
scrubbing waste.
. Overall efficiency is comparable to wet scrubbing.
. Reliability of plant may be increased with the gasification system
due to reduction in S03' vanadium, and sodium before the boiler.
Development Status
. The concept has been technically demonstrated with a 750 kW
development gasification plant.
. No problems have been identified which preclude the development
of atmospheric pressure oil gasification.
. Further development effort is required in key areas -- e.g.,
calcium sulfate generation for once-through operation,
temperature control, sulfur recovery.
179.
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RECOMMENDATIONS
INDUSTRIAL FLUIDIZED BED COMBUSTION BOILERS
Fluidized boilers for industrial application do not have
significant overall cost and performance advantages over conventional
coal-fired boilers with pollution control. Based on the market projec-
tions for clean fuel for industrial boilers and the technical assessment,
we recommend that
. Further development work on industrial fluidized bed boilers be
deferred until future availability of clean fuel can be assessed.
. Fuel usage for industrial boilers be monitored to determine
any change from the use of clean fuels
. Deye10pment of industrial fluidized bed boilers be reassessed
if low-sulfur char or alternate low-sulfur, low-grade fuels
become available.
UTILITY FLUIDIZED BED COMBUSTION BOILERS
Pressurized fluidized bed power plants show greater pollution
abatement, lower costs, and greater development potential than atmos-
pheric pressure fluidized bed or conventional pulverized fuel plants.
Based on the projected market for coal and the technical assessment, we
recommend that
. Emphasis be placed on the development of pressurized fluidized
bed power plants
. Advanced concepts, generation, and evaluation be conducted to
produce improved power plant designs
181
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. Detail design of a 10 to 30 MW pressurized fluidized bed boiler
development plant be initiated, based on bench and pilot plant data.
. Laboratory research and development on pressurized fluidized
bed combustion be continued in key areas -- sulfur removal, NO
x
reduction, stone regeneration, sulfur recovery, materials
evaluation, advanced concepts.
ATMOSPHERIC PRESSURE OIL GASIFICATION
The performance and cost for a utility boiler add-on system
are competitive with stack gas cleaning and with the purchase of clean
oil.
Based on this technical assessment, we recommend that
. The market for oil beyond 1975-1980 for power generation be
scrutinized in order to assess the market potential for
atmospheric and pressurized oil gasification
. Utilities be contacted and a utility partner be identified for
a demonstration installation of an add-on oil gasification unit
. A preliminary design of the demonstration plant be prepared
. Research and development work be continued in key areas -- e.g.,
carbon deposition, temperature control, load range, sulfur
recovery, pressurized operation.
182
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REFERENCES
1.
Godel, A.
System to
ing, Nov.
1971) .
and P. Cosar, "The Scale-up of a Fluidized Bed Combustion
Utility Boilers", paper presented at Chicago AIChE Meet-
1970 (CEP Fluidization Sym. Series Vol. 67, No. 116,
2.
Demmy, R. H., "Ignifluid Boilers for an Electric Utility", paper
presented at Second Iqternational Conference on Fluidized Bed Com-
bustion, Hueston Woods, Ohio, Oct. 4-7, 1970.
3.
Hanway, J. E., "The Use of Fluidized Bed Technology in Pollution
Control", paper presented at Chicago AIChE Meeting, Nov., 1970
(CEP Fluidization Sym. Series Vol. 67, No. 116, 1971).
4.
Blanc, H. and M. Maulaz, "Sludge Press Cake Incineration in a
Fluosolid Oven", Proceedings of 1970 National Incinerator Conference,
p. 107.
5.
Bailie, R. C., D. M. Donner, and A. S. Galli, "Potential Advantages
of Incineration in Fluidized Beds", Proceedings of 1968 National
Incinerator Conference, p. 12.
6.
"Combustion Power Unit-400", Interim Progress Report on Contract
No. Ph 86-67-259, BSWM, 1969.
7.
Reid, W. T., "External Corrosion and Deposits-Boilers and Gas
Turbines", Elsevier, New York, 1971.
8.
Second Annual Lime/Limestone Wet Scrubbing Symposium, New Orleans,
La., Nov. 8-12, 1971.
9.
See Volume II.
10.
Archer, D. H., D. L. Keairns, and w. C. Yang, "Marketable Designs
for Fluidized Combustion Boilers", paper presented at Second
International Conference on Fluidized Bed Combustion, Hueston
Woods, Ohio, October 1970. .
11.
Volumes II and III.
12.
Keairns, D. L. and D. H. Archer, "Fluidized Bed
and Comparisons", paper presented at Second
Conference on Fluidized Bed Combustion, Hueston
October, 1970.
Boilers - Concepts
International
Woods, Ohio,
183
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13.
Hoy, H. R. andJ. E. Stantan, American Chemical Society, Div. of
Fuel Chem. Prepr. 14, (2), 59 (May 1970).
Bryers, R. W., "Design Features of a Pressurized Fluidized Bed
Boiler", paper presented at Second International Conference
on Fluidized Bed Combustion, Hueston Woods, Ohio, October, 1970.
14.
15.
Discussions with the British National Coal Board.
16.
Hauser, L. G., "Optimum Uses of Energy Sources", paper
at Spring Conference, Southeastern Electric Exchange,
Orleans, La., April 1971.
184 .
presented
New
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'-
ACKNOWLEDGMENTS
The results, conclusions, and recommendations presented in
this report represent the combined work and thought of many persons at
Westinghouse, at the Office of Air Programs (OAP), and elsewhere.
Westinghouse personnel in many divisions throughout the Corporation have
contributed. Our subcontractors -- Erie City, Foster Wheeler, and
United Engineers and Constructors -- have added their expertise in
boiler and power plant designs.
Other OAP contractors have freely
shared with us their ideas and the results of their research and
development effort. Suppliers of boiler and power plant auxiliary
equipment have discussed with us their products and provided cost
estimates. Other commercial firms with background in fluidized bed
technology have received us, shown us their work, and commented on ours.
We have attempted to recollect all these contributions and what is
undoubtedly (and regrettably) a partial list of organizations and
persons is presented on the following pages.
In particular, however, we want here to express our high
regard for and acknowledge the contribution of the personnel at OAP who
conceived the overall fluidized bed combustion boiler effort and who have
defined, monitored, and supported the efforts of Westinghouse and others
on the program. Mr. P. P. Turner, Chief of the Advanced Process Section,
has served as project officer on our work.
Numerous enlightening and
helpful discussions have been held with Mr. Turner; with section members
D. Bruce Henschel and Sam Rakes; and with R. P. Hangebrauck, Chief of
the Demonstration Projects Branch.
185
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The following organizations and groups acted as subcontractors:
Foster Wheeler
Corporation
United Engineers
and Constructors
Inc.
Erie City Energy,
Division of Zurn
Industries
Westinghouse Divisions
Heat Transfer
Small Steam and
Gas Turbine
Power Systems
Generation Planning
Computer and
Instrumentation
. Assisted in evaluating
utility fluidized bed boiler
design concepts
. Prepared preliminary designs
of preferred concepts
. Prepared cost estimates
. Prepared plant layout,
operating procedure, and
plant cost for a
pressurized fluidized
bed combined cycle plant
. Compiled industrial boiler
market survey
. Assisted in evaluating
industrial fluidized bed
boiler design concepts
. Prepared preliminary,.
design of preferred concept
. Prepared cost estimate
. Prepared cost estimates for
regeneration system
vessels and stack gas coolers
. Prepared design
and cost estimate
for external combustor
gas turbine
. Prepared utility
market survey
. Provided power
system cycle
analyses
. Prepared control system
design and cost for
industrial boiler
186
R. W. Bryers
J. D. Shenker
R. Zoschak
M. Casapis
E. Berman
W. Craig
J. Crowley
R. V. Seibel
W. Schwinden
R. Giardina
S. Jamison
R. E. Strong
B. Hugoson
S. J. Jack
R. R. Boyle
R. J. Budenholzer
H. L. Smith
N. Weeks
R. Gessford
-------
Sturtevant
Large Turbine
. Supplied design and cost
data for forced and
induced draft fans
. Supplied cost information
on steam turbines
R. Mercer
W. F. Courtney
The following vendors supplied information and cost
estimates:
Aerodyne Development
Corporation
Petrocarbt Inc.
McNally-Pittsburg
Manufacturing
Corporation
Struthers Nuclear
and Process Company
Ducon CompanYt Inc.
Fordt Bacont and
Davist Inc.
Ralph M. Parsons
Company
Wheelabrator
Corporation
Buell Engineering
Com'panYt Inc.
Koppers CompanYt Inc.
. Supplied design and cost
information for high
efficiency particulate
removal equipment
. Supplied design and cost
information for pressurized
solids feeding systems
. Supplied design and cost
information for solids
handling systems
. Submitted proposal for
stack gas coolers
. Supplied cost information
for particulate removal
. Supplied cost estimates for
sulfur recovery processes
. Supplied cost estimates
for sulfur recovery
proc~sses
. Supplied electrostatic
precipitator cost
. Supplied electrostatic
precipitator cost
. Supplied design information
on solids feeding systems
187
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The following facilities were visited by Westinghouse
personnel:
Argonne National Laboratory
Chicago, Illinois
The Badger Company, Inc.
Boston, Massachusetts
NAPCA/NCB Fluidized Bed Combustion Program
Second Information Exchange Meeting
Hobart House, London
BCURA, Leatherhead
CRE, Che1tenham
Battelle Memorial Institute
Columbus, Ohio
National Coal Board
United Kingdom
Bituminous Coal Research
Monroeville, Pennsylvania
Pope, Evans & Robbins
Alexandria, Virginia
Chicago Bridge & Iron Company
Research Center
Plainfield, Illinois
Consolidation Coal Company
Pittsburgh, Pennsylvania
St. Joseph Lead Company
Monaca, Pennsylvania
Tennessee Valley Authority
Chattanooga, Tennessee
Dorr-01iver Fluidized Bed
Sludge Incinerator
Liberty, New York
UGI Corporation
Kingston, Pennsylvania
Esso Research and Engineering
Linden, New Jersey
Union Electric
St. Louis, Missouri
Esso Petroleum Company
United Kingdom
U.S. Bureau of Mines
Bruceton, Pennsylvania
Fluidized Bed Course
University of Birmingham, England
U.S. Bureau of Mines
Morgantown, West Virginia
West Virginia University
Fuller Company
Catasauqua, Pennsylvania
Kansas Power & Light
T9peka, Kansas
188
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