Tennessee
Valley
Authority
Office of Power
Energy Research
Chattanooga, Tennessee 37401
PRS-23
EPA-600/7-77-126
Industrial Environmental Research EPA-600/7-77-"l<
Laboratory . . . . £*-*•*
Research Triangle Park, North Carolina 27711 NOVeiTlDGr l9f /
UTILITY BOILER
DESIGN/COST COMPARISON:
FLUIDIZED-BED COMBUSTION
VERSUS FLUE GAS
DESULFURIZATION
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into seven series. These sever, broad categories
were established to facilitate further development and application dTenvironmental
technology. Elimination of traditional grouping was consciously ptennod to foster
technology transfer and a maximum interface in related fields. The seven series
are:
1. Environmental Health Effects Research
2, Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Sociqeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series Reports in this series result from the effort
funded under the 17-agency Federal Energy/EnvironmentResearcffand Development
Program. These studies relate to EPA's mission to protect the public health and welfare
from adverse effects of pollutants associated with energy systems. The goal of the
Program is to assure the rapid development of dome-stic ene/gy Supplies in an environ-
mentally-compatible manner by providing the necessary environmental data and
control technology. Investigations include analyses of the transport of energy-related
pollutants and their health and ecofogjcal effects; assessments of, and development
of* control technologies for energy system^; and integrated assessments of a wide
range of energy-related environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect the
views and policies of the Government, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
This document is available to the pubiic through the National Technical Information
Service, Springfield. Virginia 22161.
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TECHNICAL REPORT DATA
(Plccse nail liinruclitau on Ilic tr.vrtf tfforc coninietinf;)
. REPORT NO.
EPA- 600/7-77-126^
i.T,TLEAN0soBT,ruEutmty Boiler Design/Cost Comparison:
Fluidized-bed Combustion vs. Flue Gas Desulfurization
. AUTHOR(S) ' "
John T. Reese, TVA Project Officer
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
Office of Power
1360 Commerce Union Bank Building
Chattanooga, Tennessee 37401
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
0. HtPO
November 1977
6. PERFORMING ORGANIZATION CODE
3. PERFORMING ORGANIZATION REPORT NO.
PRS-23
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
EPA Interagency Agreement
EPA-IAG-D5-E721
13. TYPE OF REPORT AND PERIOD COVERED
Final; 8/75-3/77
4. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES IERL-RTP project officer for this report is D. .Bruce Henschel,
Mail Drop 61, 919/541-2825. —
Reproduced from
best available copy.
.ABSTRACT Tne report gives rosults of a conceptual design, performance, and cost
comparison of utility scale (750-925 MWe) coal-burning power plants employing three
alternative technologies: conventional boiler with a stack gas scrubber (CWS), atmos-
pheric-pressure fluidized-bed combustion (AFB), and pressurized fluidized-bed com-
bustion/combined cycle (PFB). The AFB and PFB designs/estimates v.sed were com-
pleted by the General Electric Co. as part of the Energy Conversion Alternatives
Study (EGAS), funded by NASA, ERDA, a»4NSF. The CWS designs /estimates were
developed by GE for this study, using the same basis as for the EGAS. TVA-modified
the GE results to: reflect TVA costing experience, consider alternate wet scrubbing
techniques for the CWS, and include comparable solid waste disposal costs for all
three plants, considering alternative disposal options. Results suggest that AFB
offers a possible savings of 9-14% in the cost of electricity (COE) in comparison with
CWS, and PFB offers a savings of up to 7%. The estimated COE for the three alter-
natives is so close that all are considered to be within the competitive range for
further consideration.
17.
Kt v WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Cost Comparison
Fluidized Bed
Processing
Flue Gases
Desulfurization
Waste Disposal.
is. DisTR;eunoN STATEMENT
Scrubbers
Coal
Boilers
Utilities
Calcium Oxides
Limestone
Magnesium Oxides
Unlimited
b.lDENTIRERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Fluid-Bed Combustion
Flue Gas Desulfurization
19. SECUH;T > CLASS fiiut Kcponi
Unclassified
20. ELCUHirY CLAS
Unclassified
c. COSATI I idd/Group
13B
14 A 2 ID
13A
13H,07A
21B 07B
07D 08G
2i. NO. Of PAGtS
- - -3*7
22. PRICt
EPA frtrm 2220-1 (3-73)
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ATTENTION
AS NOTED IN THE NTIS ANNOUNCEMENT,
PORTIONS OF THIS REPORT-ARE NOT LEGIBLE,
HOWEVER, IT IS THE BEST REPRODUCTION
•4- •
AVAILABLE FROM THE COPY SENT TO NTIS.
-------
PRS-23
EPA-600/7-77-123
November 1977
UTILITY BOILER
DESIGN/COST COMPARISON:
VERSUS FLUE GAS
John T. Reese
(TVA Project Officer)
Tennessee Valley Authority
Office of Power
Chattanooga, Tennessee 37401
Interagency Agreement No. EPA-IAG-D5-E721
Program Element No. EHE623A
EPA Project Officer: D. Bruce Henschel
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Parn, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ABSTRACT
A conceptual design, performance and cost comparison was completed for
utility-scale (750-925 MWe) coal-burning power plants employing three alter-
native technologies: (1) conventional boiler with a stack gas scrubber (CWS);
(2) atmospheric-pressure fluidized-bed combustion (AFB); and (3) pressurized
fluidized-bed combustion; combined cycle (PFB). The AFB and PFB designs;
estimates used were those completed by the General Electric Company team as
part of the Energy Conversion Alternatives Study (EGAS), funded by NASA, ERDA
and NSF, The CWS designs/estimates were developed by the HE team for the study
reported hers, using the same basis as was used for ECAS. TVA modified and
expanded the GE results to: (1) reflect TVA costing experience and include
an uncertainty allowance for undemonstrated technology; (2) consider alternate
wet scrubbing techniques for the CWS, including lime scrubbing, limestone
scrubbing and magnesium oxide scrubbing; and (3) include solid waste disposal
costs for all three plants for a 30-year lifetime, and assess alternative dis-
posal options. The results suggest that: (1) AKB offers a possible savings
of 9 to 14 percent in the cost of electricity (COF.) in comparison with G-JS,
and PFB offers a savings of 0 to 7 percent, depending on whether or not an
uncertainty allowance is applied; (?) hot gas cleaning and pressurized polids
handling in the PFB are major contributors to the COE (the cost of these items
can vary significantly if different design conditions are assumed), offsetting
the savings resulting from PFB's greater energy efficiency; and (3) application
of alternate scrubbing techniques does not affect the economics of CWS enough
to significantly change its position relative to AFB AND PFB. When uncertainties
are included, the estimated COE for T;he three alternatives is so close that
all are considered to be within the competitive range for further consideration.
111
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CONTENTS
Page
Acknowledgements ......... .......... ......... vil
Introduction ......... ....... ...... ....... 1
Executive Summary. ........ .......... ...• ..... 5
A. Scope ....... ....... ......... ..... 5
B. Common System Parameters. . . * ...... ......... 5
*" C. Economic Evaluation Criteria. ................ 6
D. Results ........... ......... - . . .... 6
1. Comparison of Results Prepared by -3E .......... 6
2. Studies by TVA. . ... .... ^ ..... ..... . . . 11
Conclusions and Recommendations
A. Conclusions ............ . ........ . . . . . 19
B. Recommendations ..... ........ .......... 20
'
GE Conceptual Designs and Cost Estimates
A. Study Ground Rules ....... T ........ ...... 21
B. Conventional/Wet Scrubber Power Plant ............ 25
1. Introduction ...... . ..... . .......... 25
2. Cycle Description ........ ...... ....... 29
Steam Turbine-Generator Cycle . . ............ 29
Conventional Steam Generator. .............. 29
Wet Gas Scrubbers .................... 31
Lime and Sludge Systems ....... .......... 31
Stack and Reheat System ................. 31
Overview ......... .......... ...... 31
3. Major Cycle Components. .......... . ...... 32
Conventional Furnace-Steam Generator ........... 32
Steam Turbine-Generator ...... ........... 32
Stack Gas Scrubber System .............. . . 37
Scrubber Costs ............ ...... ..... 40
4. Plant Arrangement .............. . . . i . . 46
Plot Plan ......... .. . ............. 46
General Arrangement . . . ; . .......... .... 46
Electrical Schematic. .............. .... 50
iv
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CONTENTS
(Continued)
' Page
5. System Performance and Cost 52
Performance Integration 52
System Output 52
Costs-General 52
Major Component Characteristics. 52
Major Component and Subsystem Capital Cost 55
Balance of Plant Equipment List 55
Balance of Plant Capital Costs . 55
Plant Cost Estimate 70
6. Natural Resources and Environmental Intrusions ..... 73
Sensitivity to Emission Targets 73
7. Summary Performance and Cost . 76
8. Alternative Plant Considerations 79
Stack Gas Reheat to 175eF 79
Performance and Costs—175°F Stack 79
No Scrubber, 250°F Stack Alternative 101
C. Atmospheric Fluidized Bed Power Plant 105
1. Introduction , 105
2. Cycle Description 108
Steam Turbine-Generator Cycle 108
Atmospheric Fluidized Beds 108
Flue Gas and Air Supply. / 110
Spent Solids Systems 110
Coa! and Liitestone Systems Ill
OvervLiw . . Ill
3. Major Cycle Components ....... 112
Atmospheric Fluidized Bed Modules. 112
Prime Cycle 116
Materials of Construction 125
4. Plant Arrangement. ..... 127
Plot Plan 127
General Arrangement 127
Plan; Elevation. . , 127
Electrical Schematic 131
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CONTENTS
1 (Continued)
Page
.5. System Performance and Costs 133
Performance and Costs 133
Costs-General ; 133
Major Component Characteristics 133
Equipment List-Balance of Plant 138
Capital Costs-Balance of Plant .... 138
Plant Cost Estimates . 138
6. Natural Resources and Environmental Intrusions 154
Sensitivity to Emissions Targets . .... 154
Trace Element Emissions 154
7. Summary Performance and Cost 159
D. Pressurized FluiJized Bed Power Plant 163
1. Introduction 163
2. Cycle Description 166
Pressured Fluidized Beds 166
Gas Turbine Air Supply 168
Spant Solids System 168
Coal and Dolomite Systems. 168
Overview 168
3. Major Cycle Components 169
Heat Input System-PFB 169
PFB Gas Turbine and Heat Balance 174
Prime Cycle 174
Materials Considerations . 174
4. Plant Arrangement 180
Plot Plan 180
Coal and Dolomite Handling 180
Solid Wastes Handling 180
General Arrangement. ........ 182
Plant Elevation 182
Electrical Schematic 182
vi
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CONTENTS
(Continued)
Page
5. System Performance and Cost".- „• 186
Performance ........... . 186
Auxiliary Losses. ..............."..... 186
Costs-Gereral . , 186
Costs-Majcr Components. ....... 186
PFB Major Component Characteristics (1650) . „ 186
Equipment List-Balance of Plant (1650). ...... . . , 192
Capital Costs-Bailee of Plant. (1650 F) ...... ;. . 192
Plant Cost Estimate?. .................. 192
6. Natural Resources and Environmental Intrusions. ...... 209
Natural Resources 209
Environmental Intrusion .,.• 209
Trace Element Emissions • *• .,.'. . 209
7. Summary Performance and Cost. 211
^4*..
8. PFB Alternative //I (1-750 F) 214
PFB Tower Costs -. 214
Hot Gas Cleanup Costs . 214
Gas Turbine Costs 214
Steam Turbine-Generator Cost. . . 214
Gas Turbine Economizers 217
Balance of Plant Costs 217
PFB Net Generation (1750 F) 217
PFB Net Plant Cost (1750 F) 217
Cost of Electricity Comparison. ............. 217
9. PFB Alternative i?2-High Efficiency (1750 F) ....... 222
Steam Turbine Cycle and Heat Balance. . 222
Gas Tubine Economizer Cost 222
Balance of Plant Adjustments 225
Auxiliary Loss and Net Generation 225
Net Plant Cost 225
Cost of Electricity Comparison 225
vii
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CONTENTS
(Continued)
Page
Plant Conceptual Designs and Balance of Plant Costs 233
Introduction , 233
Balance of Plsnt Subsystems. 235
A. Coal and Sorbent Receiving, Handling, and Storage 235
B. Water Treatment and Disposal. 237
C. Solid Wastes Handling and Disposal 241
D. Heat Exchangers . . . 241
E. Piping , 242
F. Copling Towers and Circulating Water Systems 243
G. Exhaust Stacks. ...».' 247
H. Auxiliary'Loa;'-. - 247
I. Electrical Systems 248
Cost Engineering Methods .*..... . 249
A. Cost Engineering Objectives ....... 249
B. Capital Cost Estimates Approach 249
C. Common Balance of Plant Components 258
D. Construction Time Estimates 260
Operating and Maintenance Costs. 265
1. Introduction , . 265
2. Maintenance Costs 266
3. Operating Cost Estimates 269
4. O&M Summary , 271
GE Comparison of Alternatives, 275
TVA Modification and Expansion of GE Study 281
A. Introduction. 281
B. Modification of GE Estimates by TVA 282
C. Alternative Wet Scrubber Cases . . , . . . 291
D. Alternative Disposal Methods 305
E. Cost of Electricity (C.O.E.) Based on TVA Modifications . . . 309
viii
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CONVERSION TABLE
EPA policy is to express all measurements in Agency documents in metric
units. When implementing this policy results in undue cost or difficulty in
clarity, the Industrial Environmental Research Laboratory-Research Triangle
Park (IERL-RTP) provides conversion factors tor the particular rsonmetric
units used in the document. For this report these factors a-re:.
British
Multiply
feet
feet2
feet/sec.
3
feet /min.
gallon
inch
micron
ounce (troy)
pound
pound /in.
quart
tons/hr.
Temperature Conversion -
-•
.-, '. "& ~
3.0480 x 10"1
9.29 x 10~2
. 3.0480 x lO'1^
4^.720 x 10""1
3.785
2.5400xlO~2
1.0 x 10~6
3,1103 x 101
4.536 x Iff1
7.03 x 10~2
9.463 x 10"1
2.520 x 10"1
Farenheit (°F) to Kelvin (°K)
Metric
To. Obtain
meters
* 2 •
meters
feet/sec.
liters /sec.
liters
meters
meters
grams '
kilograms
kg/cm
liters
kg/sec.
Temp--ature
I (Tf - 32°) + .273°
IX
-------
ACKNOWLEDGEMENTS
This report Includes technical work performed by the General Electric
Company (GE) and the Tennessee Valley Authority (TVA). The "GE Conceptual
Design and Cost Estimates" information was developed by a GE team composed
of the following organizations:
(a) General Electric Company
Electric Utility Systems Engineering Department
Cotporate Research and Development
targe Steam Turbine - Generator Department
Technical Resources Planning, Turbine Operations
Technical Resources Staff
(b) Be.chtel Corporation
(c) Foster Wheeler Energy Corporation
This effort utilized fluidized bed combustion power plant designs developed
in Phase II of the Energy Conversion Alternatives Study (ECAS) (Ref. 5). The
conventional plant information was developed by the GE team under NASA contract
NAS 3-19406 on a basis consistent with the ECAS Phase II effort.
The Environmental Protection Agency (EPA) provided funding for the GE
conventional plant effort and for additional work by TVA under TV-41967A and
interagency agreement EPA-IAG-D5-E721.
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INTRODUCTION
The increasing demand for electrical power coupled with the growing concern
for environmental effects of coal-fired power plants create a special problem in
the utility industry.
The goal of near-term energy.independence requires that new fossil-fired
plants utilize our Nation'a vast coal resources. The majority of our coal,
however, is unsuitable as a conventional power plant fuel. High sulfur oxide
emissions *rora coal-fired plants have been evaluated as environmentally unacept-
able. Limitations on these emissions have been imposed requiring either removal
of coal sulfur before burning or reduction of sulfuric oxide concentration in
the stack gas. Much of the coal is unsuitable for economic sulfur removal by
conventional methods. Utilizing high sulfur coals in conventional coal-fired
plants requires stack gas cleanup. The only existing technology for adequate
sulfur oxide reduction is wet scrubbing.
Wet scrubbers are expensive, however, and have posed some operational
problems. A near term alternative to conventional/wet scrubber power plants
(CWS) is fluidized bed combustion power plants. Atmospheric fluidized bed
combustion power plants (AFB) are basically similar to conventional power plants
with the substitution of fluidized bed modules for the conventional stesm gen-
erator. Pressurized fluidized bed power plants (PFB) add an extra dimension
through utilization of a coal-fired gas turbine.
The U.S. Environmental Protection Agency (EPA) recognized the need to
evaluate the economics of near term alternatives to conventional/wet scrubber
plants. TVA, at the request of EPA, undertook the assignment of comparing the
costs of fluidized bed combustion power plants (AFB and PFB) to the costs of
conventional/wet scrubber plants (CWS). In an effort to accomplish this
economically and expeditiously, information developed in the Energy Conversion
Alternatives Study (ECAS) was utilized as a data base.
EGAS has studied viable concepts for advanced power plants fired by coal
or ccal-derived fuel. This effort combined resources of three U., S. agencies.
National Science Foundation, Energy Research and Development Administration,
and National Aeronautics and Space Administration (NSF, ERDA, and NASA),
and the contracted expertise and experience of contractor teams led by the
General Electric Company (GE) and the Westinghouse Electric Company.
ECAS included three primary tasks: parametric analysis (Task 1),
conceptual design and cost estimation (Task 2), and implementation assessment
Task 3). In Task 1, ten categories of power plant were analyzed parametrically.
On the basis of the results from that analyses, 11 -specific advanced plant
-------
types were selected for the Task 2 and Task 3 effort. GE was responsible for
seven of these including atmospheri. fluidized bed combustion ^AFB) and pres-
surized fluidized bed combustion (PFB) power plants. The GE portion of the
ECAS work was done by a GE Corporate Research and. Development team which
included the Foster Wheeler Energy Corporation and the Bechtel Corporation.
In order to facilitate a cost comparison of fluidized bed combustion to con-
ventional pulverized coal-fired power plants utilizing wet stack gas scrubbers
(CWS) it was necessary to develop comparative conceptual designs and cost
estimates for the conventional plant.
EPA provided the funding necessary for this additional CWS plant study
which was performed on the same design and economic premises as the ECAS
sJtudy.
Included in the GE study results used in this report" ^re the following
items: •*-."'
1. Study ground rules ~
2. Conventional/wet scrubber power plant (CWS) design (lime scrubber)
3. Atmospheric fluidized bed power plant (AFB) design :
- ^ v :
4. Pressurized fluidized bed power plant (PFB) design ^..
5. Balance of plant equipment necessary for the CWS, AFB, and PFB
plants n •
6. Operating and maintenance costs for the CWS, AFB, and PFB plants
7. Comparison of alternatives
The conceptual designs and cost estimates developed by the GE team pro-
Vide cost data based on common ground rules for the CWS, AFB, and PFB systems.
All three systems were assumed to be developed to a commercially available
state of art and received common treatment in the generation of design and
cost information. TVA feels that although the GE effort was guided by a
consistent evaluation basis, there are areas where modification would provide
a more comprehensive and utility representative study.
The capitcl and operating costs obtained by GE for the CWS, AFB and PFB
were modified by TVA to take into consideration a number of factors felt to be
significant. Three major factors were addressed:
1. Modification of the estimates to Include an uncertainty allowance for
those plant components not felt to be demonstrated technology; and
modification of the GE estimates for various components where such
revision is felt to be warranted based upon TVA design experience.
-------
2. Expansion of the GE estimates to take into consideration:
a. Adequate provisions for residue disposal over the full 30-year
plant lifetime, for all cases (previously GE included only 5-year
disposal provisions for the CWS case, and none for AFB and PFB).
b. Alternate disposal options.
The TVA estimates are only modifications of the GE cost figures and should
not be construed as an estimate of costs for which TVA believes these plants
could be constructed for today.
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EXECUTIVE SUMMARY -
A. SCOPE
This report presents the results from a study that has been conducted to
compare the economic and performance characteristics of three power plants,
each of which generates electricity at approximately the same net capacity and
each of which employs a different scheme for controlling the emissions of air
polluting constituents in its flue gases. The difference between the three
plants are essentially identified by the type of steam generator and the
associated provision for removal of sulfur dioxide from the products of com-
bustion. The three plants are designated as follows:
1. Conventional pulverized coal-fired steam plant with stack gas
scrubber ('JWS);
2. Atmospheric fluidized bed combustion power plant (AFB);
3. Pressurized fluidized bed combustion power plant (PFB).
The evaluation of the CWS was performed for two values of gas temperature,
namely, 250 F and 175 F to which the combustion gases were reheated after leav-
ing the wet gas scrubbers and prior to entering the stack. Also included for
comparison was the condition that assumed low sulfur coal was burned and the
scrubber system eliminated from the plant.
The study of the PFB plant included consideration of main bed operating
temperature of 1650 F and 1750 F and an alternate high-efficiency cycle for the
1750 F case that utilized a high temperature feedwater heater in addition to
those provided in the base cycle of the PFB plant.
As an extension of the performance and economic analyses performed for the
plants and conditions described above, several alternate scrubbing systems were
analyzed as were various schemes for disposal of scrubber sludge from the CWS
and disposal of solid waste from the fluidized bed plants.
B. COMMON SYSTEM PARAMETERS
As nearly as was feasible, the basic system parameters in each of the three
power plants were taken to be th>.- same. Likewise, the provisions for onsite
storage and handling of fuel and sorbent as well as requirements for the balance-
of-plant components were maintained as similar as was practical for the three
Preceding page blank
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plants. Consistent ground ruler and costing methodology were applied in evaluating
the plants. Table 1 is a list of design parameters common to the three plants.
C. ECONOMIC EVALUATION CRITERIA
The economic and performance evaluations for the study were first carried
out by the General Electric Company (GE) and then the results and studies were
modified/extended by TVA to more realistically reflect utility practice and
account for the uncertainties inherent in systems undergoing various stages of
technological development. '
*• The evaluations for each power plant conducted by GE were performed using
the methodology and criteria consistent with that used in the Energy Conversion
Alternatives Study (EGAS). Each of the three types of plantsjwas assumed to be
developed to a commercially available state-of-the-art and no consideration
was given to developmental costs.,,
A lime slurry scrubber with onsite calcination and provisions for a
five-year storage of sludge was assumed for the CWS studies performed by GE.
The AFB and PFB plants were assumed by GE to have provisions for. hauling of• the
solid wastes to an offsite location. The costs for disposing of the solid
wastes from the AFB and PFB plants were not Included by GE. *
-.••'"• *•-
TVA's modification of .the results by General Electric included the
following: *"
r;
1. Revision of some items in GE's cost estimates to more reasonably
reflect current utility practice;
2. Application of an uncertainty allowance to the cost of those items of
equipment in which unceftaincies of design and scale up of components
were not accounted for in the GE studies. These uncertainty allowances
do not take into account costs to develop the components or to start
up the process.
The previously mentioned extension of the study to include investigation
of additional scrubber systems and alternative methods of disposing of sludge
and -solid wastes was also performed by TVA. The alternative methods of scrub-
bing considered by TVA were lime w/onsite calcination, lime w/offsite calcina-
tion, limestone, and regenerable magnesium oxide. Estimates for 30-year
disposal were made for each scrubbing alternative as well as for the AFB and
PFB plants.
D. RESULTS
1. Comparison of Results Prepared by. GE
A comparison of performance and corresponding cost of electricity for the
several plants and alternatives considered is presented in Table 107 which is
reproduced here for convenience. The entries are arranged in Table 107 in
decreasing order of overall efficiency.
-------
Fuel
Steam Conditions
TABLE 1
Key Design Parameters
Illinois No. 6 Coal
Cost: Sl.00/106 Btu
HHV: 10,788 Btr./lb
3.9% Sulfur
9.6% Ash
3515 psia i'nlet pressure
1000°F inlet temperature
1000°F reheat temperature
Heat Rejection
Mechanical draft cooling towers
Ambient Air Temperatures: 59" dry bulb, 51.5°F wet bulb
Economic Factors
Base Ixtad Plant (capacity factor = 65 percent)
30 year plant lifetime
90 percent availability
Cost basis: Mid-l975$
Interest during construction: lOTi per year
Escalation during, construction: 6.5°' per year
Fixed charp.e rate: 18^ per year
Construction time: 5.5 years
Sorbent cost: $5.00/ton
Plnnt Capacity
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Table 107
EFFICIENCY ORDER OF STEAM PLANTS**
TYPE
PLANT CONDITIONS
PFB 1750F Beds
PFB 1650F Beds
CF No Scrubber
AFB 1550F Beds
CF No Scrubber
CWS Wet Scrubber***
CWS Wet Scrubber***
*3.9% S in Coal Not Permitted. These costs do not include a premium for
low—sulfur coal.
**English units are employed in tables and figures in this report, in
accordance with engineering design practice. A table of English to
metric conversion factors is given on page vi.
***Lime slurry w/onsite calcination.
STACK
3 OOF
3 OOF
250F
250F
3 OOF
175F
250F
OVERALL
EFFICIENCY
40.0%
39.2%
36.2%
35.8%
35.7%
33.8%
31.8%
ELECTRICITY
MILLS/kWh
34.1
34.1
30.5*
31.7
31.6*
37.0
39.8
-------
The overall efficiency is defined as the net station output divided by the
higher heating value of the coal fired.
The high efficiency configurations for the PFB plant with beds at 1750 F
yields the highest overall efficiency of all .the plants evaluated;
however, the combustor and gas clean up and solids handling systems for this
power plant, that includes a gas turbine, would need considerable farther develop-
ment before it could, in fact, become a reality. The AFB plant also needs
further development although its development is advanced compared to the PFB
plant. Based on available technology, the conventional furnace with wet scrubber
and 175 F stack gas is the best current solution for combustion of h,igh sulfur
fuels. There is, however, an economic incentive to develop AFB and PFB as well.
The two "no scrubber" cases would require a coal of less than 0.65 percent
sulfur for a 10,788 Btu/lb higher heating value if they are to, meet the emission
standard of 1.2 lbS02/M Btu emission standards common to all of the plants.
Premium costs for this higher quality coal were not included in the comparison
in Table 107.
Note in Table 107 that the increase in bed temperatures and the addition
of the high temperature feedwater heater for the.,PFB with beds at 1750 F
resulted in only a slight increase in the overall efficiency and no difference
in the cost of electricity when-compared with the PFB plant with 1650 F beds.
TV- f • > ,
The change in the stack temperatures from 250°F to 175 F, in the case of*^
the CWS, yielded improvements in both the overall efficiency and the cost of
electricity. •*
C;
Some insight into tine relative costs in dollars for kilowatt ($/kW) for
heat release and sulfur and particulate capture for the three plants may be
gained by considering the combination of the costs in S/kW for the furnace
modules, hot gas filtering, solids handling and stack gas scrubber are appro-
priate for each plant. This is depicted in Table 106 which is included here
for convenience. These combinations of components total S67/kW for the A^B,
$!23/kW for the PFB and $147/kW for the CWS. Data also included in this table
reveal that the total capital costs and the costs of electricity follow a
similar progression for the respective plants. As shown in Table 106, a major
contributor to the PFB capital cost is the hot gas filtering system. Estimates
of hot gas cleanup costs vary from estimator to estimator, depending.on design
assumptions (such as gas velocity thru granular bed filters). Design assumptions
different from GE's could.result in lowering the PFB plant cost.
Summaries of the environmental intrusions anticipated from operation of
the CWS, AFB, and PFB plants are presented, respectively, in Tables 22, 56, and
78. These tables have been duplicated from other portions of the report.
SOX emissions are comfortably under the current limit of 1.2 lbS02/MBtu
(0.52 kg/GJ) of heat release for all three plants, as a result of the selected
design conditions, with the PFB showing the greatest margin. In designing for
these different degrees of S02 removal (85% for AFB, 88% for CWS and 90% for
PFB), GE was attempting to ensure compliance with its emission standard (83%)
for each system. The greater degrees of control designed into each system
were to reflect GE's estimation of the uncertainty in system performance.
0 O
9
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Table 106
CAPITAL COST DISTRIBUTIONS AS $/kU
FOR 3600 PSI, 1000 F, 1000 F STEAM POWER PLANTS
Major Components
Steam Turbine-Generator
Furnace Modules
Gas Turbines
Hot Gas Filtering
Economizer
Solids Handling
Subtotal
AFB
1550 F
33.2
55.8
11.4
100.3
PFB
1650 F
27.7
16.3
28.3
71.4*
2.5
35.6**
CF
175 F
33.6
57.7
182.0
91.3
Balance of Plant
Stack Gas Scrubbers
Site Labor
All Other
Subtotal
117.8
122.1
239.9
108.4
_9_8._7
207.1
89.2
126.8
107.5
323.5
Contingency
Escalation and Interest
Total Capital Cost ($/kU)
COE (mills/kWh)
68.0
223.8
632.
31.7
77.8 84.2
255.8 273.0
723. 771.
3/..1 37.0
*Approximately two-thirds of this cost represents the high temperature/
pressure granular bed filter for particle removal from the flue gas. For
comparison, an esimate for hot gas filtering for PFB use made by Westinghouse
for the EGAS program (ref. 6 ) using diffenr-ent design assumptions amounted to
about $15/kW.
**The Westinghouse estimate for PFB solids handling was about $8/kW (ref.6 ).
10
-------
The AFB and PFB with combustion in the beds at 1550 F and 1650 F, respec-
tively, indicate low levels of NC^ in comparison with the current limit of
0.7 Ib NOx/MBtu of heat release. The CWS requires a well balanced, staged
combustion system in order to meet the current NO* limitations.
In regard to emissions of particulates, each of the plants has little or
no margin in comparison with the current limit of 0.1 Ib/MBtu of heat release.
The stack gas heaters in the case of the CWS, Table 22, place a greater
fraction of the heat rejection at the stack as compared with the corresponding
values for the AFB and PFB in Table 56 and 78, respectively.
Water usage is greatest for the CWS and smallest for the PFB plant. The
coal requirement would follow the same progression as does water conservation.
The solid waste produced is least for the CWS (on a dry basis) and greatest
for the PFB. The PFB plant uses dolomite which has only half the concentration
of available lime found in limestone. Since solid wastes from AFB arid PFB are
dry, some ease in handling may result in comparison with CWS sludge.
The above comparisons have been made using the CWS with 250 F stack gas
temperature (Table 22). The environmental intrusions for the CWS with 175 F
stack gases would be comparable to tlv values in Table 22, but these would
be a 6 percent reduction where the basis was kilowatt-hours. The vequirements
for stack gas reheat would be reduced by a factor of 2.5 for the CWS with
175 F stack gas temperature.
The implications of the impact of the sludge and solid wastes produced from
the plants can be put in better perspective by considering the quantities of waste
resulting from the burning of a ton of coal in each tyoe of plant. Calculations
show that the burning of 2000 Ib of coal would yield 1540 Ib of wet sludge fo.r
the CWS, 740 Ib of dry product for the AFB plant, and 1060 Ib of dry product
for the PFB plant.
Fjctrapolating the above quantity of sludge for the case of CVS of 1000
MU(e) capacity operating over a period of 30 years, a requirement of 800 acres
of land would be required for dispoal of sludge. Iti view of such disposal
requirements, there is a strong need to develop regenerabla systems to reduce
the volume of waste from all of the plants.
2. Studies by TVA
In order to account for uncertainties in the state of technolop. • of come
components of the AFB and PFB power plants and to better reflect sctral utility
practice regarding the costing of certain subsystems of convent- onai pnwer
plants, TVA has prepared some modified estimates for comparison vif'i the capi-
tal costs and costs of electricity obtained by GE. These results are shown in
Table 108. Shown in this table are the total capital costs in 1975 dollars
and corresponding costs accounting for escalation through the construction
period.
11
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Table 22
ENVIRONMENTAL INSTRUSION
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 F STACK
EMISSIONS
S0x
N°x
HC „
Partulates
THERMAL POLLUTION
Heat, Rejected Cooling Towers, Btu/kWh
Heat, Rejected Stack, Btu/kWh****
Heat, Rejected Total, Btu/kWh
WASTES "
Water Discharge
Dry Fly Ash
Sludge (Dry Basis)
LB/MBtu
INPUT
0.867*
0.65**
0.092***
LB/kWh
OUTPUT
0.0093
0.0070
. 0;00099
.*-
LB/kWh
1.59
0.07
0.19
4188
3130
7318
M LB/DAY
28.4
1.30
3.46
*Based on lime scrubber w/8.5 ft/sec gas velocity thru scrubber,
Ca/S ratio =1.10.
**Based on balanced staged combustion system in conventional boiler.
***Based on electrostatic precipitator upstream of the scrubber.
****Includes all system heat losses except heat rejected in the cooling
towers.
-------
Table 56
ENVIRONMENTAL INTRUSION
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
EMISSIONS
S0x
NO
X
HC
CO
ParticMlates
LB/MBtu
INPUT
1.028*
0.270**
LB/kWh
OUTPUT
0.0098
0.00253
0.040
0.099***
0.00038
0.00094
THERMAL POLLUTION , :,
Heat, Rejected Coaxing Towers, Btv/kWh
Heat, Rejected Stack, Btu/kWh
Heat, Rejected Total, Btu/kWh
4729
909
5636
WASTES
Spent Solids Congolomerate
42% Calcium Sulfate
31% Ash
24% Unreacted Lime
3% Carbon
Water Discharge
LB/kWh
0.292
1.32
M LB/OAY
5.70
25.8
*This is based on the Ca/S ratio of 2 selected for this s';udy. Data
available to EPA suggests that a Ca/S ratio of 2.5 to 3-5 may be required
to routinely achieve S02 emissions compliance.
**BaseJ apon available data, EPA Relieves that the NOX emission level will
more typically be in the range of 0.3 to 0.6 Ib/MBtu.
***Assuiaes use of EUctrostatic Precipitat.or as the final stage of flue gas
particle removal.
13
-------
Table 78
ENVIRONMENTAL INTRUSION
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
EMISSIONS
so2
Uo
x
HC
CO
Particulates
LB/MBtu
INPUT
0.688*
0.152**
LB/kWh
OUTPUT
0.0060
0;0013
0.020
0.100***
0..0002
0.0009
THERMAL POLLUTION
Heat, Rejected Cooling Towers, Btu/kWh
.Heat, Rejected Stack, Btu/kWh
Heat, Rejected Total, Btu/kWh
WASTES
Spent Solids Conglomerate
42% Ash Compounds
26% Calcium Sulfate
16% Magnesium Oxide
13% Unreacted Lime
4% Unburned Carbon
Water Discharge
LB/kWh
0.34-24
951
5300
M LB/DAY
7.43
1.19
25.9
*Based upon dolomite injection into the PFB at a Ca/S ratio of 2.
**Based upon available data, EPA believes that the NOK emission level
will typically be in the range of 0.1-0.4 Ib/KEtu.
***Assumes use of high temperature/pressure granular bed filter as final
stage of flue gas particulate removal.
14.
-------
Table 108
COST COMPARISON OF GF. STUDY VS. TVA REVIEW
Total Capital Costs (1975 dollars)
PLANT
TYPE
*CWS (? 175 F
AFB
PFB
PLANT
OUTPUT
MW
795.5
814.3
903.8
GE STUDY
TOTAL COST
($000,000)
395.96
332.45
A 21. 00
COST/KW
($)
497.75
408.26
465.81
TVA REVIEW**
TOTAL COST
($000,000)
398.03
363.14
479.45
COST/KW
($)
500.35
445.95
530.48
Total Capital Co'st Escalated (5.5 year construction to mid-1981)
CWS @ 175 F 795.5 613.74 771.5 616.95 775.6
AFB 814.3 514.70 632.0 562.87 691.2
PFB 903.8 653.10 722.8 743.15 822.3
*Scrubber is lime slurry w/8.5 ft/s Ras velocity through scrubber, onsiro
calcination.
**Estimates by TVA include an uncertainty allowance for components not-yet
demonstrated, and revision for some components based upon TVA's experience.
15
-------
For the CWS, the differences between the costs obtained by GE and the
corresponding costs prepared by TVA are small. The major differences result
from differing costs assigned to the electrical subsystem by the two
organizations.
The cost estimates prepared by TVA for the AFB and PFB plants show signi-
ficant variance from the corresponding values prepared by GE. In these cases,
TVA has assigned an "uncertainty factor" to selected components of the plant
that are assumed to have reached a mature level of technology, but have not
been applied commercially at full scale. The uncertainty factor was applied
as an added percentage of the cost of an item of equipment or system and was
assigned a value on the basis of how close to commercialization the item was
judged to be.
The allowances accounted for through application of the uncertainty factor
are to take care of design changes, addition of equipment, and technological
advances. The modifications do not incorporate development and startup costs
associated with obtaining a state-of-the-art process.
The specific items to which an uncertainty factor was applied in the
fluidized bed plants were the steam generators, fuel injection systems, spent
solids and dust coolers, and portions of the hot gas cleanup systems.
As a further extension of the study, TVA developed cost estimates for the
alternative scrubbing systems for the CWS and alternate schemes for disposal
of the sludge from the CWS and solid wastes from the AFB and PFB plants. In
conjunction with these studies, TVA took into account the cost associated
with sludge and waste disposed over a period of 30 years.
The scrubbing systens considered were as follows:
a. Lime scrubbing with onsite calcination
b. Lime scrubbing without onsite calcination
c. Limestone scrubbing
d. Magnesium oxide regenerable scrubbing (production of sulfuric acid)
The variety of disposal schemes involved combinations of treatment and
nontreatment of the -wastes from scrubbers and fluidized combustion plants in
combination with choices of clay-lined ponds or clay-lined, diked impoundments
that were located either onsite or offsite.
The total capital costs, expressed in dollars per kilowatt and the cost
of electricity expressed in mills per kilowatthour are summarized in Table 127.
Among the scrubber alternatives the cost of electricity is the lowest for the
magnesium oxide regenerable scrubbing system. This prediction, coupled with the
alleviations of waste disposal problems provides incentive for commercialization
of regenerable systems. The alternate scrubber systems with 30-year sludge
disposal showed little variation in cost of electricity.
16
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Table 127
COMPARISONS OF COSTS CONSIDERING VARIOUS TYPES OF SCRUBBERS AND
ALTERNATE METHODS OF WASTE DISPOSAL
Conventional With Scrubber
GE/CWS/250F/5 yr. disp./lime w/calcination/747 MW
GE/CWS/175F/5 yr. disp./lime w/calcination/795 MW
TVA/CWS/175/30 yr. disp./lime w/calcination/795 MW
TVA7CWS/175F/30 yr. disp./lime (purchased)/795 MW
TVA/CWS/175F/30 yr. disp./limestone/795 MW
TVA/CWS/175F/MgO/Regenerable/795 MW W/^SO*, credit
TVA/CWS/175F/MgO/Regenerable/795 MW NO H2S04 credit
TOTAL CAPITAL
$/kW
835.4
111.3
782.3
758.9
773.9
728.0
728.0
COST OF ELECTRICITY (Mills/kWh)
CAPITAL O&M FUEL TOTAL
26.40
24.38
24.73
23.99
24.47
23.01
23.01
2.61
2.45
3.74
3.92
3.41
2.37
3.55
10.73
10.10
10.10
10.10
10.10
10.10
10.1
39.83
36.93
38.57
38.00
37.99
35.48
36.66
Fluidized Bed Power Plants i
GE/AFB/onsite disposal (30 yr.) 814 MW 654.0
GE/AFB/offsit-j disposal (30 yr.) 814 MW 648.5
GE/PFB/onsite disposal (30 yr.) 904 MW 745.0
GE/PFB/offsite disposal (30 yr.) 904 MW • 739.6
TVA/AFB/uncertainties added/onsite disposal (30 yr.) 814 MW 71.2.4
TVA/AFB/uncertainties added/offsite disposal (30 yr.) 814 MW 706.4
TVA/PFB/uncertainties added/onsite disposal (30 yr.) 904 MW * 845.1
TVA/PFB/uncertainties added/offsite disposal. (30 yr.) 904 MW 839.7
GE/AFE/nb disposal/SlU MW 632
CE/PFB/no disposal/90^ KW ..723
20.67
20.50
23.55
23.38
22.52
22.33
26.72
26.55
20.00
22.90
2.61
2.77
2.98
3.16
2.61
2.77
2.98
3.16
9.50
3.70
9.53
9.53
8.71
8.71
9.53
9.53
8.71
8.71
2.20:.
2.50
32.81
32.80
35.24
35.25
34.66
34.63
38.41
38.42
31-7
3^.1
-------
The results in Table 127 also indicate that the economics of the AFB plant
are favorable in comparison with the ?FB plant. The uncertainties are greater
for PFB plants, plus additional capital outlays are reouired. These factors
contribute significantly to higher capital costs and cost of electricity in
comparison with AFB plants. Comparison of the estimated costs of electricity
indicate that AFB offers the pttential for a savings in comparison with all
of the CWS options. PFB also offers potential savings if uncertainties are
not included; if uncertainties are included, the estimated cost of electricity
is about the same for PFB and CWS. However, the estimated COE for the CWS
alternatives and the AFB and PFB alternatives (with uncertainty) are so close
(within 12%) that all are considered within the competitive range for further
consideration.
18
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CONCLUSIONS AMD RECOMMENDATIONS
A. Conclusions
Several observations become evident upon examination arid comparison of the
performance and economic results that have been generated from the study of
CWS, AFB, and PFB plants. It is important to keep in mind that developmental
and startup costs associated with obtaining a state-of-the-art process have
not been incorporated in the results. The salient conclusions are itemized
as follows:
1. The AFB power plant offers a near-term promising alternative to the
CWS. The comparison on the basis of the costs of electricity indi-
cate an approximate savings of 9 to 14 percent (depending on whether
or not an uncertainty allowance is applied) in favor of the AFB as
opposed to the CWS using lime or limestone for capture of sulfur.
2. The economics of the PFB plant fay be severely affected by stringent
hot gas cleanup requirements and high pressure (10 atmospheres)
solids handling requirements. The comparisons on the basis of cost
of electricity between the CWS using lime or limestone and a PFB
plant using dolomite for capture of sulfur indicate no savings in
using the PFB if allowances for uncertainties are considered in
evaluating the PFB plant. On the other hand, if no uncertainty
allowance is applied, the PFB plant offers a 7 percent savings in
cost of electricity in comparison with the CWS.
The superiority of the overall efficiency of 39.2 percent for the
PFB plant in comparison with, typically, 35.8 percent and 33.8 per-
cent for the AFB plant and the CWS, respectively, is offset by
large capital requirements for gas cleanup equipment for the PFB
plant. Estimates for hot gas cleanup costs vary from estimator
to estimator, depending on the design assumptions used *, use of
different assumptions from those used by GE could increase the
apparent savings for PFB.
3. The performance of the CWS is penalized by additional power require-
ments for operation of the scrubber and (much greater) by stack gas
reheat requirements. For example, the difference in the cost of
electricity for a CWS in which the gases existing from the scrubber
are reheated to 250 F instead of to 175 F amounts to a penalty of
approximately 8 percent. Thus, there are significant differences
in the economics of the CWS for different reheat temperatures of
the stack gases.
19
-------
4. Application of alternative scrubber systems now developed do not
affect the economics of the CWS enough to change its position
relative to AFB and PFB plants.
Estimates for the CWS utilizing a magnesia slurry scrubber suggest
that a reduction in the cost of electricity may be attained rela-
tive to the scrubber using lime and limestone. However, the
magnesia scrubber remains to be fully developed and regeneration
of the sorbent is unproven.
B. Recommendations
f. The following recommendations are made for extending the studies reported
herein:
1. It is recoir,mended that the study be extended i o include, intermediate
load duty since most utility power systems will in all likelihood
require this type of service from all three types of plants.
2. In view of the fact that such extensive areas of land will be required
for disposal of sludge/soliu wastes over the life of either of the
types of plant studied, it is recommended that development of systems
for sorbent regeneration be.accelerated. '
20
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GE CONCEPTUAL DESIGNS AND COST ESTIMATES
A. STUDY GROUND RULES
The methodology and ground rules used in the evaluation of a conventional
steam plant with stack gas scrubbers,for sulfur removal are identical with
those applied to steam power plants in the Energy Conversion Alternative? Study.
Those elements that are not dealt with in,the detailed text will be briefly
reviewed here.
The focus was on baseload plants with 30 years useful life and 90 percent
plant availability,. The capital costs were evaluated for mid-1975 costs, as if
all elements were fully developed. All plants were treated as mature and no
development costs were included. During construction, prices would escalate
,6.5 percent per year. Interest during construction would be at 10 percent per
year; the fixed charge rate per year of operation would be 18 percent of plant
final cost. The time for construction, 5.5 years, was determined on the basis
of the total man-hours of field labor content. The S-curve for expenditures
resulted in escalation and interest during construction 0.548 times the total
plant cost without those factors.
The fuel was a high-sulfur Illinois coal (No. 6) with the characteristics
defined in Table 1. The emission standards for flue gas are presented in
Table 2.
Several efficiencies are reported for each type of plant. The thermodynamic
efficiency was the generator output divided by the heat input to the steam cycle.
The power plant efficiency and the overall efficiency were both equal to net
station output divided by the higher heating value of the coal fired.
The heat rejection from condensers was to mechanical draft evaporative
cooling towers. Power plant operation was evaluated for a 59 F air ambient
with 60 percent relative humidity. The resulting wet-bulb temperature was
51.5 F.
Uniformity of treatment of all steam plants was assured by use of the same
team as contributors. The heat input for combustion and heat exchange to steam
were studiec by the Foster Wheeler Energy Corporation. The pressurising gas
turbines for the PFB were evaluated by the General Electric Gas Turbine Products
Division Investigations of the steam turbine and its cycle specifications were
done by the General Electric Large Steam Turbine Department. The wet lime
scrubber system, the heat rejection equipment, and all balance of plant labor
and equipment were evaluated by the Bechtel Corporation. Bechtel also provided
architect-engineer layouts of the plant site and plant arrangement. The systems
integration was done by the General Electric project tea*
21
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Operating and maintenance costs were assessed to each plant on the basis
of estimates provided by the boiler manufacturer, Foster-Wheeler, the steam
turbine manufacturer, GE, and the architect-engineer, Bechtel, for the scrubber
system and consumables such as limestone. The operation manning requirement
was evaluated by the Installation and Service Engineering Staff of General
Electric.
22
-------
Table 2
EMISSION STANDARDS
Standard
Pollutant (Lbs/MRtu Heat Input)
SO 1.2
A. •
NO 0.7
Particulates 0.1
23
-------
B. CONVENTIONAL/WET SCRUBBER POWER PLANT
1. INTRODUCTION
A steam power plant with wet gas scrubber to reduce stack gas emissions is
a distinct advance over the numerous conventional coal-burning steam power
plants that cannot meet ioday's emission standards except by burning low-sulfur
coal or converting to oil firing. There will be a direct competition between
plants with conventional furnaces with stack gas cleanup, and alternatives
such as fluidized bed furnaces that capture sulfur products during the
combustion process.
>
The simplified cycle schematic presented as Figure 1 shows the major
pieces of equipment. The coal and air are fired with staged combustion of
the pulverized coal to limit generation of thermal NOX products. The furnace
and its elements (steam turbine, condenser, and cooling towers) are all proven
conventional elements. Gas leaves the unit at 300 F after passing through
electrostatic precipitators that reduce the burden of fly ash in the flue gas.
The gas enters the scrubber and is quenched to 125 F with lime slurry sprays.
Sulfur is removed as calcium sulfite and calcium sulfate, which precipitates out
in the sludge pond. Lime is continually replenished, using an onsite calciner
for limestone.
The water-vapor-saturated flue gas at 125 F Is next reheated to either
175 F or 250 F. The means is a blending with a large quantity of air that has
been preheated above that temperature by steam extracted from the steam turbine
cycle.
The system parameters are presented in Table 3. The Illinois No. 6 coal
contains 3.9 percent sulfur. Eighty-three percent of the sulfur must be cap-
tured to meet the environmental emission limit of 1.2 pounds of sulfur dioxide
per rail lion Btu of fuel heat release. The wet scrubbers are specified to cap-
ture 90 percent of the flue gas sulfur burden when 4.5 percent sulfur was pre-
sent in the coal. With the specified margin of performance capability, the
plant operation is assured of meeting current standards for flue ga,~ emissions.
The consumption of lime is minimized by the intimate mixing in the wet scrubbers.
In addition the recirculating system provides for reuse of lime in solution in
Che-clarified water recirculated from the sludge pond.
The steam cycle uses conventional conditions for a supercritical reheat
unit with seven feedwater heaters. The large extraction of steam at the turbine
crossover pressure for stack gas reheat approaches the limit set for conven-
tional practice. The condenser back pressure was chosen to optimize the total
Preceding page blank
25
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ro
<7\
Coal
Air
Air
1
^ Steam
Reheaters k-
CF
Sludge Pond
Reheat
Steam
HP
IP
Feedwater
Feed Heaters
LP
Condenser
f-
Limestone
Figure 1. Conventional Steam Plant—with Wet Gas Scrubbing
-------
Table 3
SYSTEM PARAMETERS
CONVENTIONAL STEAM—WET GAS SCRUBBERS
PARAMETER
Fuel
Illinois No. 6
Limestone
'*-
Furnace
Radiant Section
Convection Section
Prime Cycle—Steam Plant
Working Fluid
Tuibine Inlet
Reheat
Condenser
Final Teedwater
Heat Rejection
Wet Mechanical
Draft Cooling
Towers
Stack Gas Temperature
VALUE OR DESCRIPTION
10788 Btu/LB Higher Heating Value
,l$/MBtu
For Sulfur Capture
0.16 LB/LB Coal
Pulverized Coal Fired
Superheat and- Reheat
Steam?
3500 PSI, 1000 F
659 PSI, 1000 F
2.3" Hga,. 106 F
4378 PSI, 505 F
20 Cells
?50 F
27
-------
cost of electricity with respect to turbine output and cost, heat rejection
system cost, and auxiliary power consumption.
The first case set stack gas temperature at 250 F in conformance with
forner conventional steam power plant practice. The influence of stack
gas temperature is far greater than normal for this steam plant configuration.
In an additional case the corrosive component dew points in the flue gas are
assumed to be at or below 125 F by the scrubbing process. As a result a lower
stack temperature was deemed to be permissible. A subsequent evaluation was
made for 175 F stack temperature. Details o:" this case will only be presented
after a complete appraisal of the 250 F stack case.
The net power from the 250 F stack plant would be 747 MW, representing a
32 percent conversion efficiency from-coal to dispatched power. The net power
from the 175 F stack plant would be 795'MW, vith a 34 percent conversion
efficiency.
28
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2. CYCLE DESCRIPTION
A more detailed plant schematic is presented in Figure 2. State points
and stream flows are shown wherein the enthalpy values are referenced to
32 F water for steam and water and to an 80 F zero reference for air, combustion
gases, and solids. The advanced feature of this power system is the use of wet
flue gas scrubbers with a conventional boiler to generate steam from high-sulf'iv
coal for a conventional steam turbine cycle with a single reheat of the stean.
Steam Turbine-Generator Cycle
The steam turbine is contained in four shells connected in t.andem with a
single 820 MW generator. The low pressure stages have four parallel flows
exhausting downward into a common condenser. The condenser coolant is wati»r
recirculated in a closed circuit to evaporative cooling towers. The regenera-
tive feedwater heating cycle has four low-pressure feedwater heaters, a deaera-
ting feedwater heater, and two high-pressure feedwater heaters. Part of the
steam exhausted from the high-pressure turbine is used in feedwater heating,
while the rest is returned to the boiler to be reheated to 1000 F. Part of the
steam from the reheat turbine exhaust is used ^f or driving the boiler feed pump.
The exhausts from those drive turbines are routed to the main condenser. All
other pump drives are electric motor driven and appear in the detailed account
of auxiliary losses. The boiler feed pump and its drive arc sn integral part of
the steam cycle and are fully accounted for in the heat balance for the steam
turbine-generator.
^ • • '
The final feedwater wouldrbe 505 F for the 100 percent operation. All
major components were specified for continuous performance capability at a
flow margin of 5 percent above the intended plant operating flow. The steam
cycle at the valves wide open (TOO) point would pass the intended flow with
margin, and the designated 510 F feed temperature would then exist. It is
important in conventional steam systems that the operations be evaluated at the
100 percent operating point, where performance is guaranteed, and not at the
specification condition for design with margin.
Conventional Steam Generator
The coal to be fired is dried by the primary air-flow at the eight ball
mill pulverizers. Between 15 and 20 percent of the total air is heated to
633 F in the hottest sector of the air preheater as primary air. This air
serves to dry the coal, to convey the pulverized coal to the burners, and to
consummate the initial combustion process. The Remainder of the air is
preheated to 585 F and delivered to the burners as secondary air.
The water circuitry in the steam generator provides water walls, radiant
energy absorption surfaces, convection and radiant surfaces for superheat!, ig
and reheating of steam, and an economizer to bring the flue gas to 740 F
as it leaves the boiler and enters the air" preheater . Slag is removed from the-.
boiler furnace beneath the firing zone, fly ash from a hopper just before the
air preheater. These solids, representing 15 and 10 percent of the total ash,
29
-------
UJ
o
SitOffl Turbine Generator (!)
3415/1000/6 O/I42I.7 ~
Generated 6I9.9MW
• Auguries 72 7MW
Mel Output747 2 MW
low Pressure reed Heaters
Boiler Feeo Kimp 13)
Tower?
20 Ceils
3600'X 3600'X 22'
fit-re-:-17 oooil
LEGEND' Prsssjre/TemperoIure/FlowRate/tnlhoipy
PSIA/"F/Mi(lion Pounds Per Hour/BTU Per Pound
"Million Fcwntfi Per Houf
Figure 2. Conventional Steam Cycle with Wet Gas Scrubbers
-------
respectively, are sluiced to the sludge pond. The electrostatic precipitators,
with an efficiency o£ 98.6 percent, collect another 75 percent of the total ash,
leaving only 0.75 percent in the gas flow to the wet scrubbers. The collected
fly ash is stored in dry silos for shipment offtiite. Induced draft fans follow
the electrostatic pre.cipitators.
Wet Gas Scrubbers
The w*?t r,as scrubbers apply a spray of recirculated hot water that is
rich in liwo in order to capture sulfur compounds. The remaining fly ash will
be washed out of the flue gas also. Following the main reactive spray there
is a demisting, spray that recirculatrs a makeup warer and captured drift
mixture. Carry ever of the slurry and lime are avoided by this means.
Lime And Sludge Systejns
A continual removal of sludge and a continual replenishment of lime and
water is required. The sludge is flushed to the sludge settling ponds in a
stream comprising 10 percent undissolved solids. The return water from the
pond is enriched with lime produced la the coal-fired calcinator from limestone
feedstock.
The makeup water moves in a counterflow mode. It is first applied iii the
mist eliminator recycle wash bleedoff replenishing the S02 absorber recycle
liquids, and ultimately becomes part of the sludge and water mixture that
accumulates in the settled portion of the sludge pond.
Stack And Reheat System
The flue gas at 125 F leaves the wet scrubber saturated with water vapor
and with many constituents at or near their dew point temperatures, It has been
determined that normal gas heaters cannot have suitable service lives when
heating such a corrosive gas mixture. The alternative to direct heating is to
blend into the flue gas a large flow of air that has been separately heated.
Figure 2 shows that 14 Mlb/h of air heated to 334 F blend with 8 Mlb/h of flue
gas to produce a 250 F stack temperature. The stack air heaters u.-,e steam
withdrawn fron the steam cycle as their heating medium. The stack and flues ire
lined, to wltttstand attack from the flue gases.
Overview
The major components of this system are conventional ami of proven relia-
bility in utility service. The wet scrubber system introduces an added need
for maintenance asid for the avoidance of corrosive attack bv Iirce and cool
flue gas. The subdivision into six parallel scrubbers and the subdivision of
critical pumping functions in the scrubber system should assure that at most
one-sixth of the capacity would be down at any time.
31
-------
3. MAJOR CYCLE COMPONENTS
Components for conventional steam plants are specified for continuous
operation with flows 5 percent greater than required for normal operation.
Insofar as Figure 2 depicts 100 percent plant operation on a 59 F day, the
individual specifications for the boiler, turbine, and scrubber will require
greater capacities at their design points. The exact matching has been
accomplished on the basis of an exact steam-turbine heat balance, which
dictates the heat to steam for the boiler, and the boiler efficiency,
which in turn dictates the fuel requirement.
This section will consider the specified performance for the steam
turbine-generator, the boiler, the scrubber system, and the heat rejection
syjstera. The latter two are furnished as balance-of-plant equipmont. All
other balance-of-plant items will be specified in a subsequent section.
Conventional Furnace-Steam Generator
The general layout of the conventional supercritical once-through
steam generator is shown in Figure 3. .Eight .jjall mill coal pulverizers
are located at the base elevation. The burners are arrayed about the radi-
ant furnace section. The combustion gas flows upward over superheater
sections, then downward in parallel paths through the reheater and tl;e
primary superheater, and finally emerges from the economizer. Figure 4 ^
presents a preliminary heat-
-------
T
4- -\> J- su»c«miTc« o^tift
T-
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LiT-Tfc.4610''«j!.«C€ DEPTH ptT~
Figure 3. Conventional Boi ler—Supercritical Once-Through Coal
Firing
33
-------
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-------
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Figure 5. Conventional Furnace with Wet Scrut?—250 F Stack
-------
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-------
The heat to the steam cycle at 100 percent operating conditions would
be 6867.4 MBtu/hr. The heat input would be 8375.54 Btu/kWh at the generator.
Stack Gas Scrubber System
Although all elements of the wet gas scrubber system would be furnished
as balance-of-plant equipment, the unique aspects of this system command
that it rank as a major cycle component and that it receive detailed attention.
The entire scrubber system is illustrated in Figure 7 along with process
flow charts appropriate for operation at the specified 5 percent flow margin,
using 4.5 percent sulfur coal. The sulfur capture would be 90 percent. The
two process flow charts do not differ in respect to the sulfur capture system;
only the reheating of stack gas to 250 F in the upper chart and 175 F in the
lower chart are different.
The lime requirement is met by calcining limestone in a rotary kiln fired
with coal. There would be onsite a 60 day supply of limestone. The coal
would be stacked in a four-day storage bin by front-end loaders. The emission
requirements for the calciner aro met by the use of a baghouse dust collector
and a separate stack. No reduction in sulfur gases is expected for the coal
fired in the calciner.
The lime product is expected to be in excess of 95 percent available
lime. It is stored in silos with a capacity sufficient for five days' opera-
tion. With the 1500 tons-per day of limestone calcining capacity, this part of
the plant need not operate continuously to support plant operations. There
should be sufficient time to accomplish all usual maintenance and refurbishment
on a scheduled basis. The entire left half of Figure 7 represents onsite capital
investment and operations that would be eliminated if lime rather than limestone
were available for purchase in suitable quantities at a suitable price.
The right half of Figure 7 is the scrubbing system that causes lime to
react with sulfur in the flue gas to fora solids that accumulate in the sludge
ponds. The lime replenishment is slaked with pond recycle water to a 16 hour
storage tank. The slaked lime and remaining pond recycle water are discharged
to the S02 absorber effluent holding tanks. Table 4 presents the major
parameters of the limestone/lime system considered to this point.
The 3-stage S02 absorbers operate on flue gas that has been quenched
from 300 F and saturated with water vapor at 125 F by the presacuracion sprays
at each absorber gas inlet. The flue gas then flows upward through the three
absorber stages, each of which comprises a 6-inch bed of spheres. The liquid-
to-gas ratio maintains 110 percent of lime-to-sulfur stoichiometric ratio. The
effluent wet gas is further washed in the mist eliminator sprays. These sprays
receive all of the fresh makeup water intended for all replenishment of the
scrubber system. This final wash captures carryover or large droplets of drift
of recycle wash liquids. Table 5 indentifies the parameters of the wet absorber
system and keys the stream functions to Figure 7.
37
-------
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-------
Table 4
LIMESTONE/LIME SYSTEM PARAMETERS
CONVENTIONAL FURNACE-STEAM CYCLE
Lime Product Quality
Limestone/Lime Product
Limestone Storage
Limestone Calciner
(Traveling Grate Kiln)
Nominal Production
Capacity
Fuel Requirements (111.
Lime Storage Capacity
Lime Slaker Capacity
Slaking Temperature
Slaked Lime Slurry Solids
(After Dilution)
Lime Slurry Surge Capacity
95% Available CaO
2 Tons/Ton
60-Day Supply
90,000 Tons
650 Tons/Day
880 Tons/Day
5 MBtu/Ton Lime
5-Day Supply
800 Tons/Day
H90 F
20% WT
16 Hours
Table 5
WET LIME ABSORBER SYSTEM PARAMETERS
CONVENTIONAL FURNACE-STEAM CYCLE
(BASIS: 90% SOX REMOVAL FOR 4.5% SULFUR COAL)
S02 ABSORBERS (6)
Ho. of Stages
Superficial Gas Velocity
Total Pressure Drop
Liquid/Gas Ratio 8
Presaturation Sprays 7
Mist Eliminator Wash Sprays 9
Lime: S02 Stoic. Ratio
Absorber Hold Tank
Residence Time
Recycle Slurry Solids 1587
Lime Makeup Slurry Solids 13
Spent Slurry Pond Solids 17
Stream Identification, Figure 7
TCA-Type
3 (6" of Spheres/Stage)
8 FT/S
9-IN. H20
72 GAL/MSCF
2.5 GAL/MSCF
2 GPM/FT2
110%
5 Min.
10% WT
20% WT
40% WT
39
-------
The flue gas at 125 F and saturated with water vapor is highly corrosive
and chemically active. Normal heat exchangers that would reheat the flue gas
to an appropriate stack temperature would not withstand the chemical attack
of the flue gas. Even the flues and stack must be lined to avoid attack.
The necessary stack temperature is achieved by steam-heating additional air
and blending the heated air with the flue gas. This requires six low head
fans and six heaters. Two alternatives of stack temperature were examined:
250 F and 175 F. Table 6 presents the parameters of the blend air and its
heat requirements for these alternatives at their 100 percent operating
point. The blending means of gas heating is increasingly inefficient as the
stack temperature is increased toward the air temperature of 333 F, account-
ing for the great differences between these two alternatives.
The wet gas scrubber arrangement shown in Figure 8 connects these several
elements with the four Induced draft fans that service the four electrostatic
precipitators. There is a total of six absorber and stack reheater trains.
The induced draft fans feed a cross-duct that is normally Isolated by dampers
from the startup bypass path. Connecting in a downward fan-like duct are the
presaturation spray ducts to each absorber. The redundancy dictated by the
size of the absorbers should produce a high level of availability for the
scrubber system.
The sludge ponds are the remaining element of the wet scrubber system.
Each pond would measure 3600 feet by 3600 feet by 22 feet deep. Six ponds
would accommodate 30 years of plant operatitns. Only one pond was accounted
for in the capital cost presentation. The accumulation rate of solids would
equal the solids delivery rate of 150,000 Ib/h of calcium sul^lce ?^u excess
unreacted lime. Because water would accumulate at a rate 50 percent greater,
in jSitti solids concentration would be 40 percent. It is important to recog-
'nize these two accumulations, because the tables on Figure 7 represent steady-
, state balances for the absorbers but nonsteady states for lime, makeup water,
and sludge accumulation.
Scrubber Costs
The direct costs for the scrubber system comprise material costs and
direct field labor costs as detailed in Table 7 for a 250 F stack and in
Table 8 for a 175 F stack. These costs are insufficient insofar as balance
of plant construction must bear a prorated share of the indirect field
expenses and additional electrical, civil, process, and yardwork must be
done. Tables 9 and 10 present the complete costs, with the first two items
on line 1.0 carried over from Tables 7 and 8. The allocations for indirect
labor, fees, contingency, and escalation will be discussed in the subsection
concerned with balance of plant in Section 5, "System Performance and Cost."
All of these items of expense will also be included in the comprehensive list
of balance-of-plant accounts. Presentation here with all elements of costing
is done to facilitate identification of the incremental cost due to the wet
scrubber system. For the 250 F stack case, a total of $51.9 million for this
major system is comparable to a steam turbine-generator cost of $26 million,
and a boiler component cost of $39.7 million. The wet scrubber is a major
addition.
-------
Table 6
FLUE GAS HEATERS
FOR WET SCRUBBER SYSTEMS
PARAMETER
Heat Duty, MBtu/HR
Steam
Air Velocity, FT/MIN
Air Rate, M LB/HR
Pressure Drop, IN. H20
Heat Transfer Rate,
Btu/ (HR SQ FT °F)
Finned Surface, SQ FT
STACK GAS REHEAT TEMPERATURE
250 F 175 F
971 217
620 -> 356 F 620 -»• 356 F
333 •*• 59 F 333 * 59 F
900 900
14.586 ?.267
1.5 J..O
5.5
645,000
86,5'00
41
-------
GROUND FUOOS PLAN FL.0'
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Figure 8. Wet Gas Scrubber Arrangement—Conventional Steam Plant
-------
TABLE 7
SCRUBBER EQUIPMENT DIRECT FIELD COSTS
(250 STACK TEMP.)
Major Mechanical
Equipment
Limestone Handling
Limestone/Lime System
S0~ Scrubber Vessels
Scrubber System Pumps
Scrubber Systfo. Tanks
Scrubber Ductwork
Scrubber Flue Gas Equipment
TOTAL
SCRUBBER
Major Mechanical
Equipment
Limestone Handling
Limestone/Lime System
S02 Scrubber Vessels
Scrubber System Pumps
Scrubber System Tanks
Scrubber Ductwork
Scrubber Flue Gas Equipment
TOTAL
Materials
M$
1.25
3.66
6.93
1.08
2.18
3.27
3.09
21.46
TABLE
Direct Labor
M$
0.25
0.73
1.01
0.12
0.05
2.43
•*• 0.3?
4.96
**•••
8
Total
M?
1.50
4 . 4<
7.94
3.20
2.23
5.70
3.41
26.42
EQUIPMENT DIRECT FIELD COSTS
(3.75 STACK TEMP.)
Materials
M$
1.25
3.66
6.93
1.08
2.18
* 1.95
* 0.90
* 17.95
Direct Labor
MS
0.25
0.73
1.01
0.12
0.05
1.41
O.OS
3.70
Total
M$
1.50
4.44
7.94
1.20
2.23
3.36
0.98
21.65
O c>
*Changed From 250 Stack Case
-------
TABLE 9
WET LIME SCRUBBER CAPITAL COST BREAKDOWN
CONVENTIONAL FURNAC2 - STEAM CYCLE
(250 F STACK TEMP.)
Direct Indirect
Materials Labor Field Total
Categories M$ M$ M$ H$
1.0 Process Mechanical Equipment 21.5 5.0 4.5 31.0
(Limestone Handling,
Line System, Absorbers,
Tanks, Pumps, Air Heaters,
F.D. Fans, Ductwork)
2.0 Electrical . 0.7 0.9 0.8 2.4
3.0 Civil and, Structural 3.7 2.1 1.8 7.6
4.0 Process Piping and
Instrumentation 4.3 2.6 2.3 9.2
5.0 Yardwork and Miscellaneous - 0.9 0.8 1.7
51.9
A/E Engineering, Home Office & Fee @ 15% 7.8
Total Plant Cost 59.7
Contingency @ 20% 11.9
Total Capital Cost 71.6
Escalation & Interest During Construction 39.2
Total Plant Investment 110.8
44
-------
TABLE 10
WET LIME SCRUBBER CAPITAL COST BREAKDOWN
CONVENTIONAL FURNACE - STEAM CYCLE
(175 F STACK TEMP.)
Direct Indirect
Materials Labor Field Total
Categories M$ M$ M$ M$
1.0 Process Mechanical Equipment 17.95 3.7 3.3 25.0
(Limestone Handling, Lime
System, Absorbers, Tanks,
Pumps, Air Heaters, F.D.
Fans, Ductwork)
2.0 Electrical 0.7 0.9 0.8 2.4
3.0 Civil and Structural 3.7 2.1 1.8 7.6
4.0 Process Piping and
Instrumentation 3.8 2.5 2.2 8.5
5.0 Yardwork and Miscellaneous - 0.9 0.8 1.7
45.2
A/E Engineering, Home Office & Fee @ 15% 6.8
Total Plant Cost 52.0
Contingency @ 20% 10.4
Total Capital Cost 62.4
Escalation & Interest During Construction 34.2
Total Plant Investment 96.6
-------
4. PLANT ARRANGEMENT ^
A group of plant arrangement drawings were prepared by the architect-
engineer as a preliminary step to evaluating constryction costs.
Plot Plan
The plant plot arrangement is based on receiving coal and limestone by
rail and shipping fly ash off site by rail. A 60 day pile of coal and lime-
stone is provided. Silos to hold 15 days' accumulation of dry fly ash are
provided adjacent to the rail terminal. A series of small ponds catch runoff
water from the site and provide for treatment of all water returned to the
North River.
Figure 9 shows the plot arrangement. The smaller overall plot layout
indicates the dominant aspect of one 3600 f ot by 360Q foot sludge pond. The
upper detail shows that at the active site naif the area will be used for coal
storage and for cooling towers. The boiler house abuts the turbine building. :
The electrostatic precipitators are of substantial size in order to achieve 98.6
percent particle removal, A single stack serves the entire plant. The land
area for the power generation plant is.92 acres; the sludge ponds must agregate
an additional 1785 acres in close proximity to the main plant. A total area of
3 square miles will be required. This requirement will severely constrain
the siting opportunities for these plants.^ ,. :
•*•
The coal feed system provides transportation by belt conveyor from the
line storage pile to the transfer tower. .-s-Tramp iron is removed and large
size frozen coal is crushed te small size. Next, the coal is conveyed to the
surge bin in the boiler house, where vibrating feeders and two conveyor belts
feed eight coal silos disposed on opposite sides of the building. The filled
•silos guarantee 8 hours of boiler output. Each silo feeds a single coal
pulverizer by a gravimetric feed. Coal drying and conveyance to the burners
is by hot primary air. For startup and warmup an oil system firing No, 2
fuel oil is provided, along with 100,000 gallons of fuel storage in two tanks.
General Arrangement
A more detailed general arrangement plan for the turbine hall and boiler
is presented in Figure 10. The eight silos on either side of the boiler each
hold an 8 hour coal supply, and all feed to one coal pulverizer. The air
preheater* and flues to the electrostatic precipitators of Figure 8 dominate
the leftside. The ground level of the turbine hall on the right indicates the
arrangement of the many support functions for the steam turbine cycle.
The general arrangement elevation view shown in Figure 11 combines the
boiler details of Figures 3 and 4 in a proper orientation to the turbine hall
and the flue gas exhaust system detailed in Figure 8. The arrangement provides
short steam lines and liberal access space for all apparatus. At the extreme
left, the gas enters the flue gas system of Figure 8 at the electrostatic
precipitators.
-------
Figure 9. Plot Plan for Conventional Steam Plant
CtCIIEl
-------
IEC1TEI
Gt/NASA
*PV*NCtD C«HEV COWCflSKX 5TUOT
OEKEftAL AAfUNGEI«M1
PLAN
IMQ7 | P-603 |0
Figure 10. Turbine and Boiler Buildings
-------
i (
;;d
I]
o
Jj«*C»>
-------
The four electrostatic precipitators shown in Figure 8 are especially
voluminous, to provide the low gas velocities essential to the capture of
98.6 percent of the entrained fly ash. Each unit is 54 feet high, 93 feet
vide, and 44 feet deep. The entry and exits are divided in two to retain normal
flue connections. Each unit is serviced by one induced draft fan working in the
cleaned gas leaving the unit. The six wet gas scrubbers and reheaters then
deliver the flue gas to a single 500 foot stack.
Electrical Schematic
Figure 12 is a single-line diagram showing major electrical equipment.
The single steam turbine-generator at. 24 kV feeds two main transformers to
500 kV and two auxiliary transformers to 13.8 kV. A startup transformer may
also feed the 13.8 kV bus from the 500 kV transmission line. Major and
subsidiary buses are identified, as.well as major auxiliary electrical loads.
50
-------
01
Figure 12. Major Electrical Equipment
S''.:L£ LINE
Reproduced from
best available copy.
-------
5. SYSTEM PERFORMANCE AND COST
Performance Integration
Evaluation was made of plant performance on the average 59 F day with all
equipment operating at 100 percent condition with respect to its design and
specification point. To adjust performance data so that a perfect integration
results, a detailed steam turbine heat balance had been made at the 100 percent
operating point, as presented in Figure 3, The required 6867.4 MBtu/h from the
boiler were deemed to be provided at the exact boiler efficiency (87.1346) that
prevails with the 5 percent margin condition detailed in the boiler heat balance
(Figure 4). Typically, boiler efficiency improves slightly at reduced firing
rates .
In addition to the coal fired at the boiler, the rate of -coal usage for
calcining was evaluated, on the basis that the mass flows of the wet gas
scrubber process flow diagram (Figure 7) represent operation at a 5 percent
margin above the required 100 percent level. Table 11 presents the basis
and results for the integration into the steam cycle of boiler and wet gas
scrubber operating flow rates. •* • '
System Output ^
For the 100 percent operating point Tgble 12 shows that the 820 MW of
generator output was reduced to 747 MW net plant output by the 73 MW required
for auxiliaries. The auxiliary loss breakdown is presented in Table 13. The
induced fan power requirement was 4 MW greater than normal as a result of the
additional 9 inch drop in water pressure in the wet gas scrubbers; the scrubber
system itself consumes 10 MW. All other values are typical of steam plants.
These auxiliary loads consume 8.9 percent of the generator output in the plant.
Costs-General
Costs were synthesized from the costs of major components, balance of
plant materials, and balance of plant labor. An equipment list of major items
in the balance of plant was made tu assure completeness and to assure that the
selected equipment ratings would match the extreme requirements for continuous
operation. A detailed breakdown of balance of plant direct labor in man-hours
and of material costs completes the identification of all items of construction
and installation costs. To these are added indirect field labor costs and
major component costs. An architect-engineering fee is added in proportion to
the engineering effort. To the sum total a contingency is applied, to be
expanded on items not counted in a preliminary appraisal such as this. Finally,
a factor of 0.548 is added to the total for escalation and interest during
construction for the 5.5 year period.
Major Component Characteristics
The steam generator characteristics are listed in Table 14. The heat-
delivered efficiency of°87.1 percent would improve approximately 1.2 percent
52
-------
Table 11
ENERGY BALANCE—100 PERCENT RATING, 59 F DAY
CONVENTIONAL STEAM PLANT—WET SCRUBBERS--250 F STACK
PARAMETER VALUE
Generated Power 819938 kW
Heat-to-Steam Cycle1 6867.4 MBtu/Hr
HHV of Fuel Fired2 7881.4 MBtu/Hr
Coal Fired at Boiler 730570 pph
Coal Fired at Calciner , 13810 pph
Total Coal Rate . 744380 pph
t •
Effective Boiler Efficiency 85.52 percent
4
Limestone Feed Rate 119050 pph
Scrubber Makeup Water Rate 917 . gpm
Notes: 1 From 100 percent steam cycle heat balance, Figure 5
2 Boiler Efficiency 0.871346 from heat balance, Figure 4
3 Based on 10788 Btu/pound higher heating value (HHV)
4 Rates proportioned 1/1.05 for wet scrubber, Figure 7
Table 12
SYSTEM OUTPUT
CONVENTIONAL STEAM PLANT-WET SCRUBBERS-250 F STACK
Steam Cycle Output 819.9 MW
Total Auxiliary Losses 72.7 MW
Net Power Plant Output 747.2 MW
(60 Hz AC-500kV)
53
-------
Table 13
AUXILIARY LOSS BREAKDOWN
CONVENTIONAL STEAM PLANT-WET CIAS SCRUBBERS-250 F STACK
ITEM
Furnace
FD Fans
PA Fans
ID Fans
ESP
Pulverizers
ASSUMPTIONS
19"
A 2"
23"
695
A P, 0.82 EFF
A P, 0.82 EFF
A P, 0.78 EFF
,000 CFM, 300 F, 0.986 EFF
NO. OF
UNITS
A
4
A
A
8
Turbine Auxiliary
Wet Scrubber
Major Pumps
Booster
Condensate
Circ. Water
Water Intake
Solids Handling
"Hotel" Loads
Cooling Tower Fans
Transformers
0.33% of Gross kW
600 PSI, 6 Million #, 757, x 90%
185 PSI, 3.9 Million #, 70% x 90%
Proportion to Cooling Heat Duty
A/E Estimate
Based on Rates and Lifts
A/E Estimate 1% of Generation
Proportional to Heat Duty
0.5% of Gross Generation
2
1
1
20
A
TOTAL
MW
7.3
2.9
8.8
5.2
7.6
31.8
2.8
10.0
3.7
1.0
A.8
9.5
0.9
3.0
8.3
2.3
A.I
TOTAL AUXILIARY POWER
72.7
-------
if the flue gas were reduced iir temperature to 250 F rather than the 300 F
level dictated by the high level of sulfur in the fuel. The radiant surfaces in
the furnace experience a heat flux four tints the average, while the more exten-
sive convection surfaces experience two-thirds the average heat flux.
The cost of $39.73 million (mid 1975) includes the air preheater, flues
and ducts, coal pulverizers, and supporting steel and platforms. Exclided are
the cost of the fans which appear as balance of plant, and the 6.15 million
dollar cost of the electrostatic precipltators with their support steel.
Table 15 shows the cost of the steam turbine-generator at $26 million
and expresses the cost per pound and per unit of energy concerned.
Major Component and Subsystem Capital Cost
A more detailed comparison of ultimate costs can be made by including
the balance of plant materials and direct and indirect labor costs. Table 16
shows such a comparison. The conventional steam generator with the coal ard
solids handling aggregate $85 million; the gas cleanup comprising electrosta-
tic precipitators and wet lime scrubber subsystem total $60 million. The
steam turbine generator is of the order of $30 million.
It is evident that comparisons based on component costs alone would.give
proportions totally different from that for theTtotally installed*item. Balance
of plant equipment and costs merit a detailed evaluation. tr~
•H--
Balance of Plant Equipment List °
Specifications for balance of plant equipment are presented in Table 17
as prepared by thp architect-engineer (Bechtcl). The specifications are based
on continuous opev ition at the valves wide open (VWO) condition for the steam
turbine flow rates. The boiler and'wet scrubbers have comparable margins.
The electric motor drives for pumps and fans are sized for additional
margins of 10 percent on flow, 20 percent on static pressure rise, and approxi-
mately 30 percent on power. All of these specifications are for equipment more
than sufficient to match the 100 percent operating condition.
Balance of Plant Capital Costs
Table 18 presents the architect-engineer's detailed breakdown of the
direct manual field labor in thousands of man-hours (MH 1000' s), and of
balance of plant material cost in thousands of dollars ($1000' s) for each
major catpgory of the balance of plant. For the reading of these data, an
average hourly field labor rate of $11.75 in mid-1975 dollars is used to
convert man-hours to dollars. Where indirect field labor is allocated to
individual items rather than the total labor for the job, it will be appor-
tioned as 90 percent of the direct field labor, which is equivalent to $10.58
per hour.
55
-------
Table 14
HEAT EXCHANGER CHARACTERISTICS
CONVENTIONAL STEAM-WET GAS SCRUBBERS-250 F STACK
VESSEL
NO. OF SIZE OR
HEAT EXCHANGER UNITS TYPE
Steam Generator 1 130' x 90' x 282'
OUTPUT OR UNIT
DUTY PER WEIGHT
UNIT (FOB)
MBtu EFFICIENCY M LB
6867 87.1% 40.35
UNIT •
COST
(FOB)
MS
39.73
SURFACE
AREA
FT2
610,000
72,000*
538,000t
HEAT FLUX
AVERAGE
Btu/CHR FT2)
11,670
44,745*
7,247t
*Radiant Furnace Surfaces
tConvection Surfaces
Table 15 . •
MAJOR CWS COMPONENT AND SUBSYSTEM WEIGHTS AND COSTS SUMMARY-2bO F STACK
MAJOR COMPONENT
OR SUBSYSTEM
Prime Cycle
Steam Turbine-Generator
(Gener<":or Alone)
Steam Generator
COMPONENT OR
WEIGHT
(FOB)
M LBS
SUBSYSTEM
COSTS
(FOB)
MS
OUTPUT
OR
DUTY
COST PER
UNIT
OUTPUT
OR DUTY
COST
PER
LB
6.5
(0.940)
40.35
26.0
39.73
819.9 MW 31.7 S/kW
e e
819.9 MW
4.0 $/LB
2013 MW 19.74 $/kW . 0.98$/LB
tn tn
-------
Table 16
MAJOR COMPONENT AND SUBSYSTEM CAPITAL COST SUMMARY
CONVENTIONAL STEAM PLANT-WET SCRIJBBERS-250 F STACK
Ul
~J
MAJOR COMPONENT OR SUBSYSTEM
—
Fuel Handling & Preparation
Coal an4 Solids Handling
Prime Cycle
Steam Turbine-Generator
Conventional Steam Generator
Electrostatic Precipitators
Cooling Towers
Pumps, Heat Exchangers, Stacks
Pipirr,, Etc.
Gas Cleanup Syste,"
Wet Lime Scrubber"
NO. OF
UNITS
—
1
1
4
20
—
COST/UNIT
(FOB)
M$
: ^
26.0
39.73 t
1.54
--
—
—
COMPONENT OR
SUBSYSTEM
COSTS
(FOB)
M$
I
26.0
39.73
6.1§
__.
r~
• . --
BOP
MATERIALS
MS
10.47
0.10
8.48
0.22
3.61
11.32
14.00
SITE
LABOR
(DIRECT -f
INDIRECT)
M$
3.21
2.68
23.1
2.34
3.17
3,48
22.33
TOTAL
INSTALLED
COST
M$
13.68
28.78
71.31
8.71
6.78
.14.80
36.33
30.36
21.54
51.90
-------
Table 17 (page 1 of 4)
BALANCE-QF-PLANT EQUIPMENT LIST
CONVENTIONAL STEAM PLANT WITH WET LIME SCRUBBERS
250 F EXHAUST GAS TEMPERATURE
Eqpt.
No.
Service Descrintion
1.0 Coal & Limestone Handling Systems
0-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-ll
C-12
C-13
Coal Conveyor Belt 60 in wide,
n n n M ii n
n ii ii - it n n
' " " . 42 in "
n n it n n n
ti ti n • it ti n
1! II II It II It
" " " (2 required) 30 in "
Limestone Conveyor Belt • 60 in "
i, „ .. 24 in "
n n it n it it
Limestone Bucket Conveyor " " "
Traveling Grate-Kiln 650 ton/day
340 ft long,
760 ft "
190 ft "
980 ft "
540 ft "
170 ft "
110 ft "
160 ft "
500 ft "
630 ft "
420 ft "
120 ft "
nominal lime
3000 tph
ii n
„ „
500 tph
ii n
ti it
„ „
300 tph
3000 tph
65 tph
II II
100 tph
producti<
C-14
C-15
C-16
Syste.T. (Package)
Coal Conveyor Belt
Lime,Bucket Conveyor (2 required)
Fly Xsh Silos (2 required)
(880 ton/day design capacity),
12 ft wide x 48 ft long traveling
grate, 13 ft I.D. x 180 ft long
rotary kiln with Niems-type cooler.
Includes coal grinding/firing equip-
ment, control panel/inscrumentation,
all refractories and drives, induced
draft fan, baghouse dust collector
and ducting.
18 in wide, 60 ft long, 20 tph
24 in wide, 140 ft long, 40 tph
Total Volume 833,184 ft, 80 ft
dia x 85 ft high
58
-------
Table 17 (page 2 of 4)
Eqpt.
No.
E-l
E-2
E-3
E-4
E-5
E-6
E-7
E-8
Service
Description
2.0 Electrical Systems
Main Transformers (2 required)
Unit Auxiliary Transformers
(2 required)
Emergency Diesel Generator
Start-up Transformer
Miscellaneous 480V
LCC Transformers (14 required)
Boiler Auxiliary Transformers
(2 required)
LCC Transformers (2 required)
Scrubber Transformers
(2 required)
468 MVA, FOA, 65 C, 24/500 kV
40/54/67 MVA, 65 C, OA/FA/FOA,
23/13.8 kV, 30, 60Hz
1000 kW, 30, 60 Hz, 480 V, 0.8 PF
28/37.5/47 MVA, OA/FA/FOA,
500/13.8 kV, FOA, 65C, 30, 60 Hz
1689 kVA, OA, 65 C, 13.8kV/
489V/277V, 30, 60 Hz
5500 kVA, OA, 65 C, 13.8/4.16 kV,
30, 60 Hz
7000 kVA, OA, 65 C, 13.8/4.16 kV,
30, 60 Hz
5000 kVA,,OA, 65 C, 13.8/4.16 kV,
30, 60 Hz
3.0 Main Fluid Systems
F-l
F-2
Main Condenser
Piping:
Circulating Water
Main Steam
Boiler Feed Water
Coal Reheat
Hot Reheat
3.31 x 10 ft of Heat Transfer Area
Std. material. In other respects
same as AFB but with # of tubes
scaled down in proportion to heat
transfer area.
I.D. = 114 in
I.D. = 15.3 in, tm = 3.97 in
I.D. = 26.53 in, tm = 0.675 in
I.D. = 32.54 in, tm = 1.57 in
I.D. = 18.1 in, tm - 2.23 in
59
-------
s- Table 17 (page 3 of 4)
Service
Description
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-10
F-ll
LP #1
LP #2
LP #3
LP #4
IP
H.P.
DFT
Caters: Shell
Press/Terap.
psia/ F
5/163
11/195
20/228
67/300
29&/416
745/510
Tube
Press/Temp.
psia/ F
210/158
210/190
210/223
210/295
1040/416
5,700/519
Flow
(100%)
Ib/hr
4.05 x 10
4.05 x 10
4.05 x 10
4.05 x 10
6.22 x 10
6.22 x 10
Heat Transfer
Area
ft
14,330
13,550
13,720
18,770
45,660
49,700
6.22x10 Ib/hr @ 353 F
Main Condensate Pumps and.
Motors (2 required)
Feedwater Booster Pumps and ,
Motors (2 required)
Main Boiler Feed Pumps and
Turbine Drivers (3 required) •
Main Circulating Pumps and
Motors (3 required) n
Cooling Towers (20 Cells)
Forced Draft Fans (2 required)
Primary Air Fans (2 requried)
Electrostatic Precipitators
(4 required)
Vertical Ccnterline, 4250 gpm,
600 hp motor, 410 ft TDH
7,,300 gpm, 3850 hp, 1510 ft TDH
4900 gpm, 12,600,hp, 8,300 ff TDH
82,000 gpm, 2250 hp, 75 ft TDH
246,000 gpm
Operating 971,000 cfm @ 80°F,
S.P. = 19 in wg
Test Block. 1,165,000 cfm I? 105eF,
S.P. - 24.7 in wg
Motor 6500 hp
Operating 161,750 cfm
-------
Table 17 (page 4 of 4)
Eqpt.
No.
F-12
F-13
F-14
F-15
F-16
Service
Scrubber - Turbulent
Contact Absorber
(6 required)
Air Heater (6 required)
Induced Draft Fans
(4 required)
Forced Craft Fans for
Reheater, Air (6 required)
Exhaust Stack
Description
Each 60 ft high x 40 ft wide x 18 ft long,
316L-S.S., neoprene lined, 3 stages,
450,000 acfra @ 312°F & 13.9 psii..
Each 4.5 ft high x 21.5 ft wide x
37.5 ft long.
Operating 660,000 cfm @ 3CO°F,
Total S.P. = 23 in wg
Test Block 800,000 cfm
-------
Table 18 (page 1 of 8)
BALANCE OF PLANT ESTIMATE DETAIL FOR
CONVENTIONAL STEAM CYCLE-WET GAS SCRUBBER
250 F STACK
Direct Manual Balance of
Field Labor Plant Material
MH 1000' s $ lOOQ's
1.0 STEAM GENERATOR (3)
1.1 Steam Generator Erection
Erect only (supply by others):
includes heat transfer surface and
pressure parts; buckstays, braces and
hangers; fuel-burning equipment; acces-
sories; soot and ash equipment; control
systems; brickwork, refractory and
insulation
— Supply and erec.:
includes support steel and access steel
for above; miscellaneous materials and
labor operations
1.2 Steam Generator Auxiliaries
Erect only (sopply by others):
includes fans; air preheater; flues and
ducts to 'jrecipitators; insulation for
flues aid ducts; pulverizers, feeders
and hoppers
Supply and erect:
includes F.D. Fans (2 @ $390,000 ea*);
I.D. Fans (4 @ $220,000 ea*)
1.3 Electrostatic Precipitators
Erect only (supply by others):
includes electrostatic precipitat'oTs
- Supply and erect:
includes support steel for precipitators
*based on suppliers' verbal budgetary quotations
544
296
6,800
185
1,680
99
1,140
220
__
8,700
62
-------
"Table 18 (page 2 of 8)
2.0 TURBINE GENERATOR (3)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ inoO's
Install only (supply'by others):
includes 835 raWe steam turbine; generator;
exciter; auxiliary equipment; integral
steair. and auxiliary piping; insulation;
miscellaneous labor operations
120
100
3.0 PROCESS MECHANICAL EQUIPMENT
3.1 Boiler Feedwater Pumps (3)
includes turbine-driven nain feedwater 10
pumps and drivers (3 @ $940,000 ea.*)^
feedwater booster pumps and motors
(2 I? $125,000 ea.*) ' ^
3.2 Main Circ. Water Pumps (3)
includes main circ. water pumps and 3
motors (3 @ $220,000 ea.*)
3.3 Other Pumps (3)
includes condensate pumps and motors 5
(2 @ $85,000 ea.*); and other pumps
and drivers not listed elsewhere
3.4 Main Condenser* (3)
includes shells; tubes; air ejectors 16
3.5 Heaters, Exchangers, Tanks and Vessels (3)
includes l.p. feedwater heaters (4): 9
i.p. feedwater heater; h.p. feedwater
heater; deaerating heater and storage
tank; miscellaneous heaters and
exchangers; tanks and vessels
3.6 Stack and Accessories (3)
includes concrete stack and liner*; 113
lights and marker painting; hoists and
platforms; stack foundation
3,220
700
650
2,120
3,060
1,570
*based on suppliers' verbal budgetary quotations
63
-------
Table 18 (page 3 of 8)
22
Direct Manual
Field Labor
MH lOOO's
3.7 Turbine Hall Crane (1)
includes crane and accessories 3
3.8 Coal Handling (2)
includes railcar dumping equipment; 61
dust collectors; primary and secon-
dary crushing equipment; belt scale;
sampling station; magnetic cleaners;
mobile equipment; conveyors to pile;
reclaiming feeders; conveyors to
coal silos; coal silos
i.9 Limestone Handling (2)
includes magnetic cleaners;'conveyor
to.limestone pile; reclaiming feeders;
belt scale; conveyors to calciner
3.10 Ash Handling (2)
includes bottom ash system; fly ash 61
handling system for precipitators and
air preheater; ash conveyors; ash
storage silos (2) with feeders,
unloaders and foundations; railcar
loading equipment
3.11 Cooling Towers* (3)
includes mechanical draft towers with 52
fans and motors
3.12 Other Mechanical Equipment (3)
includes water treatment and chemical 30
injection; air compressors and auxi-
liaries: fuel oil ignition and warm-up;
screenwell, miscellaneous plant equip-
ment; equipment insulation
Balance of
Plant Material
$ lOOO's
410
5,640
1,250
3,580
2,230
1,660
*based on suppliers' verbal budgetary quotations
64
-------
Table 18 (page 4 of 8)
Direct Itanual Balance of
Field Labor Plant Material
MH lOOQ's $ 1000's
3.13 Scrubber Ductwork (3) 207
includes flue gas duct outboard
of electrostatic precipitators; duct
lining; duct insulation; dampers and
expansion joints
3.14 Scrubber Flue Gas Equipment (3) 27
includes F.D. fans for flue gas reheat
(6 @ $200,000 ea.*); air heaters for
flue gas reheat (6 @ $280,000 ea.*)
3.15 Wet Lime SO., Scrubbers (3) 86
- includes complete SO. scrubber vessels
with presaturator ana mist eliminator
systems (6 @ $1,000,000 ea.*)
3.16 Scrubber Lime System (3) 66
- includes limestone calciner with travelling
grate kiln ($2,700,000*); Kiln stack; coal
conveyor, bucket elevator and storage bin
for kiln; lime conveyor, bucket elevator
and storage silos; lime slaker ($120,000*)
3.17 Scrubber System Pumps (3) 10
includes slurry recycle (18 @ $40,000 ea.*);
mist eliminator wash (3 @ $25,000 ea.*);
slurry storage and transfer (4 I? $4,000 ea.*);
slurry feed (3
-------
fable 18 (page 5 of 8)
Direct Manual Balance of
Field Labor Plant Material
MH 1000*s $ lOOO's
4.0 ELECTRICAL (5)
4.1 Main Transformers* .4 2,020
4.2 Other Transformers* and Main Bus 17 1,280
- includes startup transformer; station
*• service transformers including those
for scrubber system; generator main bus
4.3 Switchf>ear and Control Centers 42 3,400
- includes switchgear and load centers;
motor control centers; local control
stations; distribution panels, relay •**
and meter boards
4.4 Other Electrical Equipment *~ 363 * 2,010 ^
- includes, communications,,; grounding;^
cathodic and freeze protection;
lighting; preoperational testing
4.5 Auxiliary Diesel Generator 2 110
- includes diesel generator, batteries
and associated d.c. equipment
4.6 Conduit, Cable Trays, Wire and Cable 632
1,060
*based on suppliers* verbal budgetary quotation
066
-------
Table 18 (page 6 of 8)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ 1000's
5.0 CIVIL AND STRUCTURAL
5.1 Concrete Substructures and 340 2,800
Foundations (1)
includes turbine and boiler building
substructure; coal, limestone and ash
handling foundations, pits and tunnels;
miscellaneous equipment foundations;
auxiliary buildings substructures;
miscellaneous concrete
5.2 Superstructures (1) 275 7,960
— includes turbine building; auxiliary
yard buildings; boiler enclosure
5.3 Earthword (1) 130 . 300
- includes building excavations; coal,
limestone and ash handling excavations;
circ. water system excavations; mis-
cellaneous foundation excavarions;
dewatering and piling
5.4 Cooling Tower Basin and Circ. Water 90 1,380
System (3)
- includes circ. water pump pads, riser
and concrete envelope for pipe; cooling
tower basin; circ. water pipe; cooling
tower miscellaneous steel and fire
protection
5.5 SO- Scrubber Civil and Structural (1) 180 3,660
includes foundations, earthwork and
structures particular to scrubber
equipment
1,015 16,100
67
-------
Table 18 (page 7 of 8)
Direct Manual Balance of
1 Field Labor Plant Material
MH inOO's $ lOOQ's
6.0 PROCESSING PIPING AND INSTRUMENTATION
6.1 Steam and Feedwater Piping (3) 81 3,850
— includes main s^eam; extraction steam;
hot reheat; coL:i reheat; feedwater and
condensate large piping, valves and
fittings
6.2 SO, Grubber System Large Piping (3) 53 2,630
- includes maker-up water; resaturation
slurry water; mist eliminator wash;
absorber slurry effluent tank overflow;
pond feed; pond recycle water; lime
slurry piping; recycle slurry piping;
air heater steam supply; air heater
condensate return
6.3 Other Large Piping (3) 231 4,050
includes all piping, valves and fittings
of 2-inch diameter and less
6.5 Hangers and Misc. Labor Operations (3) 420 1,460
includes all hangers and supports;
material handling; scaffolding; misc.
labor operations
6.6 Pipe Insulation (3) 63
6.7 Instrumentation and Ccnr-ols (5) 220
1,220
68
-------
Table 18 (page 8 of 8)
.Direct Manual Balance of
Field Labor Plant Material
MH IQOO's $ 1000's
7.0 YARDWORK AND MISCELLANEOUS (1)
7.1 Site Preparation and Improvements
- includes soil testing; clearing and
grubbing; rough grading; finish
grading; landscaping
*'
7.2 Site Utilities
- includes storm and sanitary sewers;
nor.process service water-
7.3 Roads and Railroads
- includes railroad spur; roads, walks
and parkxrg areas ^
7.4 Yard Fire Protection, Fences and Gates
**•-
. 7.5 Water Treatment Pcndsr
includes earthwork; pond lining;
offsite pipeline
7.6 Lab, Machine Shop and Office Equipment
87
27
52
88
1
260
10
5Q
740
600
20
_ 280
1,700
69
-------
The seven major categories used by the architect-engineer relate to the
principal field labor skills to be applied. A modified subdivision of. costs
was made using the following categories:
1. Land improvements and structures
.2: Coal handling
;
3. Prime cycle plant equipment
A.. Bottoming cycle (not applicable to this plant)
5. Electrical plant and instrumentation
The appropriate subdivision number for each item or major category in Table 18
is indicated after its title in parentheses.
Plant Cost Estimate -
The major components from Table 16 and the ttlance of plant costs appro-
priate to each of the categories of field labor skills used in Table 18 are
combined in Table 19 to show a total of $301.62 million.
The home office and fee of 15 percent is applied only to the balance of
plait costs, A contingency of 20 percent of all prior costs is applied to
c^vc'r expected costs pot specifically included in the original estimating
process. The tatal capital cost of $403 million represents $492/kW based on
total generation, or $540/kW on ret station output.
A reallocation of casts according to equipment function is presented in
Table 20. Items 1 through 6 include everything in the preceding table. Item 7
adds the value of escalation and interest during the 5.5 year construction time.
This item is 55 percent of. the prior totsl. The result is a final plant cost
of $763/KU of total generation, or SB35/.-W of net station output.
70
-------
Table 19
PLANT CAPITAL COST BREAKDOWN
CONVENTIONAL STEAM PLANT-WET H/VS SCRUBBERS-250 F STACK
COSTS (MILLIONS OP DOLLARS)
CATEGORIES
1.0 Steam Generators
2.0 Turbina Generator
3.0 Process Mechani-.al Equipment
4.Q Electrical
5.0 Civil and Structural
6.0 Process Piping and Instrumentation
7.0 Yardwork and Miscellaneous
COMPONENTS
45
26
71
.88'
.00
a
.88
LABOR (1) FIELD (2) MATERIALS (3) TOTAL
13.
• 1.
9.
12.
1.1.
* 14.
_3_.
65.
40
41
I
22
46
93
34
06 4
82
BOP Labor, Materials
(Sum of 1 + 2
A/E Home
Total
Office
+ 3)
& Fee
12
1
8
11
10
12
2
59
&
@
Plant Cost
Contingency C
Total
Capital
20;%
Cost
.06
.27
.30
. 21"
.73
.90
.75
.22
Indirects
15%
t
8.
0.
46.
12.
16.
18.
1.
104.
70
10
30
90
10
90
70
70
80.04
28.
63.
36.
38.
46.
7.
301.
78
82
57
76
14
51
62
229.74 .
34.
336.
50
12
67,22
403.
34
-------
Table 20
PLANT CAPITAL COST ESTIMATE SUMMARY (APPROXIMATE-DISTRIBUTION)
CONVENTIONAL STEAM PLANT-WET SCRUBBERS-250 F STACK
COSTS (RILLIONS OF DOLLARS)
1.0 Land Improvements & Structures
2.0 Cool Handling
3.0 Prime Cycle Plant Equipment
4.0 Bottom Cycle Not Applicable
5.0 Electrical Plant 6 Inntrnmentation
Subtotal
6.0 A-E Service d Contingency
7.0 Escalation & Interest During
Construction
MAJOR
COMPONENTS
0
0
71.9
0
71.9
BOP
MATERIALS
. 13.2
.3.A..3'
44.3
12.9
104.7
Total
Plant
Total
SITE LABOR
(DIRECT & INDIRECT)
22.5
16.2
62.7
23.7
125.0
M$
Output MW
$/kW
TOTAL
35.7
50.5
178.9
36.6
301.6
101.7
221.0
624,3
747.2
835.4
-------
6. NATURAL RESOURCES AND ENVIRONMENTAL INTRUSIONS
The natural resources required for this plant are listed in Table 21.
The sorbent use is low because of the highly efficient chemical system. The
poor coal use reflects a reduced generation due to steam diversion for
reheating and, in addition, added auxiliary power consumed in the wet gas
scrubber system and In the induced draft fans. The water usage is mostly
for the cooling tower and is at conventional levels.
The great land area consigned to sludge accumulation suggests that some
innovative exploitation of the sludge might reduce this element of resource
wastage. To a certain degree the sludge ponds may represent an ongoing threat
to the surroundings. Their reclamation for agriculture or their use as a
chenical resource could offset the liability of their accumulation.
The environmental intrusions are enumerated in Table 22. The sulfur
emissions are three-quarters of the allowed 1,2 Ib/MBtu. This results from
90 percent capture, whereas 83 percent capture would Just equal the limit. The
NOjj released would be held just under the current limit by the use of staged
combustion in firing the boiler. The stack gas reheaters place a greater
fraction of heat rejection at the stack as compared with other plans.
Sensitivity To Emission Targets
The chemical processes in use for wet scrubbing and for combustion do
not lend themselves to drastic changes in current emission targets. If
the sulfur emission target were to be half the current level (0.6 Ib SC>2/MBtu
rather than the current 1.2 Ib S02/MBtu), the scrubbers would increase in size
and gaseous pressure drop by a factor of 50 percent. The auxiliary power loss
in the scrubber system would tend to increase by 5 MW. Reduction in particulate
emissions would require an increase of electrostatic precipitators of 100 percent
to reach 0.05 Ib/MBtu or half the current standard.
The reduction of NO^. would be particularly difficult, since there is
already a burden of fuel-bound nitrogen to which the thermal NOjj is added.
Reduction to half the current standard is not currently deemed feasible.
73
-------
Table 21
NATURAL RESOURCE REQUIREMENTS
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS 250 F STACK
VALUE
Sorbent, Limestone Ib/kWh 0.16
Coal, Ib/kWh 0.996
Water, Total (Gal/kWh)
Cooling
Evaporation 0.56
Slowdown 0.18
Plant General Use 0.01
Sulfur Cleanup Use 0.07
Total Land, Acres/100 MW
Main Plant 12.3
Disposal Land (30 years") 239.0
-------
Table 22
ENVIRONMENTAL INTRUSION
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 P STACK
EMISSIONS
SO
x
NO
x
HC
Particulates
LB/MBtu
INPUT
0.867
0.65
0.092
LB/kWh
OUTPUT
0.0093
0.0070
0.00099
THERMAL POLLUTION ..
He-.4: Rejected Cooling Towers, Btu/kWh
Heat, Rejected Stack, Btu/kWh ,
Heat, Rejected Total, Btu/kWh
WASTES
Water Discharge
Dry Fly Ash
Sludge
LB/kWh
1.59
0.07
0.19
4188
3130
7318
M LB/DAY
28.4
1.30
3.46
75
-------
7. SUMMARY PERFORMANCE AND COST
Table 23 summarizes the performance and cost for a 747 MW steam plant
using wet gas scrubbers with 250 F stack temperature. The low overall plant
efficiency of 32 percent is due to steam diversion for stack gas reheating
and parasitic auxiliary loads imposed by the wet gas scrubbing system. The
coal rate of 1 Ib/kVh was a typical plant value 45 years ago. The high
plant costs are effected by the additional costs of the scrubber system and
the reduction of net output already noted. The net result is a cost of
electricity (COE) of 39.8 mills/kWh, or 4 cents/kWh at the power plant
boundary.
The sensitivity of the cost of electricity to these factors is presented
in Table 24.
76
-------
Table 23
SUMMARY PE270KMANCE AMD COST
CONVENTIONAL STEAM PLA5T-WET GAS SCRUBBERS-250 F STACK
ITEM
Net Power Plant Output (MW - 6a Hz - 500 kV)
Thermodynamlc Efficiency (%)
Power Plant Efficiency (%)
Overall Energy Efficiency (%}
Coal Consumption (LB/kWh)
Total Wastes (LB/kWh)
Plant Capital Cost ($ Million)
Plant Capital Cost ($/kW )
• -fr- -
Cost of Electricity, Capacity Factor = 0.65
Capital ' .4,
n
Fuel
• Maintenance & Operation
Total
Estimated Time of Construction (Years)
Approximate Date of First Comserclal Service
747.2
40.7
31.8
31.8
0.996
0.27
624.3
835.4
(MILLS/W^h)
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)
26.4
10.7
2.6
39.8
5.5
1980 - 1982
77
-------
Table 24
COST OF ELECTRICITY (COE) SENSITIVITY
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 F STACK
BASE
CAPACITY
FACTOR
0.65
COE,
COE,
Capital
Fuel
COE, O&M
TOTAL COE
26
10
2
39
.4
.7
.6
.8
FUEL
COST
INCREASE
50%
26.
16.
2.
45.
4
1
6
2
LABOR
COST
INCREASE
20%
28.
10.
2.
42.
7
7
6
0
MATERIALS
INCREASE
20%
2
-------
8. ALTERNATIVE PLANT CONSIDERATIONS
SStack Gas Reheat To 175 F
An appraisal was made for the identical boiler and scrubber configuration
wherein the stack gas was reheated to 175 F instead of 250 F. Table 25 indicates
those elements that were unchanged, those elements that were significantly
changed, and some details of the greatly reduced stack gas reheat effect. The
requirement for stack gas reheat would be reduced by a factor ef 2.5. The reheat
energy release from air heated to 335 F would increase by a factor of 1.9. The
combined effect reduces the heat duty on the steam reheaters to 23 percent of
that required heretofore.
A revised steam-turbine cycle heat balance was made to reflect these
changes. The major changes over values found on Figure 5 are tabulated
in Table 26. The overall energy balance of Table 11 would be unchanged
except for the generated power. The changes in Table 26 and the fixed values
from Table 4 were used to reassess the auxiliary power losses as presented
in Table 27.
The system output as shown in Table 28 becomes 795.5 MW, an increase of
6 percent over the previous case with 250 F stack.
The revisions to the wet scrubber system relate entirely to the reduced
steam and air flows for the stack gas reheat. The lower table on Figure 7
shows these details for the 175 F stack configuration. Tables 6, 8, and 10 show
the changes in the scrubber system cost details.
The overall plant arrangement details would not be changed. The increased
generation does change the size of electrical apparatus, as shown on Figure 13.
The balance-of-plant equipment list is presented in Table 29. The
balance-of-plant direct labor man-hours and material costs are presented in
Table 30. These combine with the major equipment costs to determine a plant
cost of $396 million as detailed in Table 31. Table 32 redistributes the
costs and adds on the escalation and interest during construction. The
result is a plant capital cost of $771 per kilowatt of net plant output.
Performance And Cost—175 F Stack
Table 33 summarizes the system performance and cost with 175 F stack reheat,
and Table 34 compares the influence of 250 F and 175 F stack reheat cases. On
every measure the 175 F stack shows advantage over the 250 F stack. The
sensitivity of the cost of electricity to the several major variables is presented
in Table 35.
Natural resource usage and environmental intrusions would be comparable
to Table 21 and 22 values, but there would be a 6 percent reduction where
the basis was kilowatt hours.
79
-------
fe Table 25
CONVENTIONAL STEAM PLANT WET GAS SCRUBBERS-175 F STACK
FOR 175 F STACK IN PLACE OF 250 F STACK
NOT CHANGED
Coal Rate, Air Rate, Gas Rate
Scrubber Configuration
Heat to Steam Cycle
CHANGED
Heat to Reheat Stack Gas
Reheat Air Flow
Steam to Stack Gas Reheaters
Steam Turbine Cycle
Generated Power
Heat to Cooling Towers
REHEAT EFFECTS
Stack Gas Reheat from 125 F
Air Heat Release fro.u 335 F
Air and Steam Flow Ratios
2 50 F
125 F
85 F
1
Table 26
STEAM TURBINE CYCLE CHANGES
FOR 175 F STACK VERSUS 250 F STACK
175JF
50 F
160 F
0.23
RATIO
2.5 ^
1/1.9
4.3
Parameter
Turbine Type
Heat to steam, cycle, MBtu/Hr
Generator output, Mv
Gross heat rate, Btu/kWh
Steara-to-gas reheater, Ib/Hr
Last stag' flow, Ib/Hr
Condersate pump flow, Ib/Hr
Heat to condenser, MBtu/Hr
Turbine cost, M$
250 F Stack
TC4F33.5
6867.4
819938
8375.54
926,000
2,888,123
3,925,037
3086
26.0
175 F Stack
TC4F33.5
6867.4
868620
7906.13
213,426
3,.472,980
4,668,000
3638
2f-.75
80
-------
Table 27
AUXILIARY LOSS BREAKDOWN
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F STACK
00
ITEM
Furnace
FD Fans
PA Fans
I1) Fans
ESP
Pulverizers
ASSUMPTIONS
19" A P, 0.82 EFF
42" A P, 0.82 EFF
23" A P, 0.78 EFF
695,000 CFM, 300 F, 0.986 EFF
NO. OF
UNITS
4
4
4
4
8
TOTAL
MW
e
7.3
2.9
8.8
5.2
7.6
Turbine Auxiliary
Wet Scrubber
Major Pumps
Booster
Condensate
Circ. Water
Water Intake
Solids Handling
"Hotel" Loads
Cooling Tower Fans
Transformers
0.33% of Cross kW
600 PSI, 6 Million //, 75% x 902
135 PSI, 4.7 Million #, 70% x 90%
Proportion to Cooling Heat Duty
A/E Estimate
Based on Rates and Lifts
A/E Estimate 1% of Generation
Proportional to Heat Duty
0.5% of Cross Generation
2
1
1
20
4
31.8
2.9
8.6
3.7
1.2
5.6
10.5
0.9
3.0
8.4
2.7
4.3
TOTAL AUXILIARY POWER
73.1
-------
Table 28
SYSTEM OUTPUT
CONVENTIONAL STEAM PLANT-WET SCRUBBERS-175 F STACK
Steam Cycle Output 868.6 MW
Total Auxiliary Losses 73.1 MW
Net Powerplant Output 795.5 MW
(60 Hz AC-500kV)
82
-------
OP 01
M
V
fS
»
1
Sea.
cat
?EM"
-------
TABLE 29 (page 1 of 4)
EQUIPMENT LIST 7OK CONVENTIONAL STEAM CYCLE-
WET SLUBBERS, 175 F STACK
EQPT.
NO.
e-r
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-ll
C-12
C-13
SERVICE
1. Coal, and Limestone
DESCRIPTION
Handling Systems
Coal Conveyor Belt 60 in wide, 340 ft long,
60 in
" " " 60 in
42 in
42 in
11 42 in
" 42 in
" (2) 30 in
Limestone Conveyor Belt ' 60 in
24 in
" " " 24 in
Limestona Bucket Conveyor 24 in
Traveling Grate Kiln 650 t
" 760 ft "
" 190 ft "
" 980 ft "
" 540 ft "
" 170 ft "
' 110 ft "
" 160 ft "
11 500 ft "
" 630 ft "
" 420 ft "
" 120 ft
on/day nominal lime
3000 t, h
3000 "
3000 "
500 "
500 "
500 "
500 "
300 "
3000 "
65 "
65 "
100 "
product!'
C-14
C-15
c-ie
System (Package)
Coal Conveyor Belt
Lime Bucket Conveyor (2;
Fly Ash Silos (2)
(880 ton; day design capacity), 12 f:_
wide x 48 ft long traveling grate,
13 ft I.D. x 180 ft long rotary kiln
with Nieras type cooler. Include coal
grinding/firing equipments control
panel/instrumentation, all refrac-
tories and drives, induced draft fan,
baghouse dust collector and ducting.
18 in wide 60 ft long 20 i ph
24 in " 140 ft " 40 "
Total volume 833, 184 fc3, 80 ft dia x
85 ft high
84
-------
TABLE 29 (page 2 of 4)
EQPT.
NO.
E-1,2
E-3,4
E-5
E-6
E-7
thru
20
E-21
& 22
E-23
& 24
E-25
& 26
SERVICE DESCRIPTION
2. Electrical Systems
Main Transformers (2)
468 MVA FOA 65°C, 24/500 kV
Unit Aux. Transformers (2) 40/54/67 MVA 65°C, OA/FA/FOA.24/13.8 kV,
30, 60 Hz
Emergency Diesel Gen.
Start-up Transformer
Miscellaneous 430 V
LCC Transformers (14)
BLR. Aux. Transformers (2)
LCC Transformers (2)
Sci'ubber Transformers (2)
1000 kW, 30, 60 Hz, 480 V, 0.8 PF
28/37.5/47 MVA, OA/FA/FOA, 500/13.8 kV
FOA 65CC, 3)0, 60 Hz
1689 kVA, OA, &5°C, 13.8 VV/480V/277V,
3(9, 60 HZ
5500 kVA, OA, 65°C, 13.8/4.16 kV,
30, 60 Hz
7000 kVA, OAS 65°C, 13.8/4,16 kV,
3d, 60 Hz
5000 kVA, OA, 65°C, 13.8/4.16 kV,
If), 60 Hz
3. Main Fluid Systems
F-l Main Condenser
F-2 Piping
Circ. Water
Main Steam
B.F.W.
Cold R.H.
Hot R.H.
3.97 :: 105 ft2 of Heat Transfer Area
I.D. = 123 in
I.D. = 15.3 in, tm = 3.97 in
I.D. = 26.52 in, tm = 0.675 in
I.D. = 32.54 in, tm = 1.57 in
I.D. = 18.1 in, '.m = 2.25 in
85
-------
TABLE 29 (page 3 of 4)
EQPT.
NO.
F-3
SERVICE
Feedwater Heaters
DESCRIPTION
Shell
Tube
Press/temp Press/Temp
F-4
F-5
LP 01
LP #2
LP #3
LP #4
IP
H.P.
DFT
psia/°F
5/163
11/195
20/228
67/300
296/416
745/510 ,
6.22 x 10 .
Main Cond. Pumps and Motors
(2)
F.U. Booster Pumps
& Motors
' psia/°F
210/158
210/190
210/223
210/295
1040/416
5700/519
Ib/hr, @ 353°
•t* •
Vert. Cent.
410 ft TDH
Flow
(100?:)
Ib/hr
4.75 x
4.75 x
4.75 x
4 . 75 x
6.22 x
6.22 x
F
5100. gpm
7,300 gpm, ~3850 hp,
Heat Transfer
Area
ft
.'ID* 17,170
10^ 16,260
10° 16,600
10? 22,710
10^ 45,660
10 49,700
, 750 hp motor,
1510 ft TDH*^
(2)
F-6 Main Boiler Feed Primps &
Turbine Drivers (3)
F-7 Main Circ. Pumps and
Motors (3)
F-8 Cooling Towers (23 Cells)
F-9 F.D. Fans (2)
F-10 P.A. Fans (2)
4900 gpm, 12,600 hp, 8,300 ft TDH
95,000 gpm 2500 hp, 75 ft TDH
242,058 gpm .
Operating 971,000 cfm @ 80°F,
S.P. = 19 in wg
Test Block 1,165,000 cfm (? 105°F,
S.P. = 24,7 in wg
Motor 6,500 hp
Operating 161,750 cfm @ 96°F,
S.P. inlet in wg
S.P. outlet = 42 in wg
Test Block 194,000 cfm @ 121°F,
S.P. inlet 19 in wg
S.P. outlet = 54.6 in wg
Motor 2250 hp
86
-------
TABLE 29 (page 4 of A)
EQPT.
_NO.
F-ll
F-12
B-13
F-14
F-15
SERVICE
Electrostatic Precipitators
(4.)
Scrubber - Turbulent
Contact Absorber (6)
Air Heaters (6)
I.D.. Fans (4)
F.D. Fans for Reheater
Air (6)
F-16 Exhaust Stack (1)
DESCRIPTION
Each 5J ft high x 92 ft wide x 44 ft long,
1,262,000 Ib, 1296 kVA, 99% particulate
removal efficiency, 695,000 acfm 0 300°F
Each 60 ft high x 40 ft wide x 18 ft long,
316L-S.S,, neoprene lined, 3 stages,
450,000 acfm @ 312°F & 13.9 psia
Each 2.5 ft high x 18.2 ft wide x
10.7 ft long
Operating 600,000 cfm I? 300°F,
Total S.P. = 23 in wg
• Test Block 800,000 cfm @ 325°F,
Total S.P. = 30 in wg
Motor 5,000 hp
Operating 123,000 cfm 0 80°F,
Total S.P. = 3.5 in wg
Test Block 147,000 cfm @ 105°F,
Total S.P. = 4.55 in wg
Motor 150 hp
27 ft I.D., 500 ft high
87
-------
TABLE 30 (page 1 of 9)
BALANCE OF PLANT ESTIMATE DETAIL CONVENTIONAL STEAM CYCLE—
WET LIME STACK GAS SCRUBBER, 175 F STACK GAS
Direct Manual Balance of
Field Labor Plant Material
MH IQOQ's $ 1000's
1.0 STEAM GENERATOR
1.1 Steam Generator Erection (3)
- Erect only (supply by others): 544
includes heat transfer surface
and pressure parts; buckstays,
braces and hangers; fuel burning
equipment; accessories; soot and
ash equipment; control systems;
brickwork; refractory and
insulation
Supply and erect: 296 6,800
includes support steel and
access steel for above;
miscellaneous materials and
labor operations
1.2 Steam Generator Auxiliaries (3)
Erect only (supply by others): 185
includes P.A. fans; air preheater;
flues and ducts to precipitators;
insulation for flues and ducts;
pulverisers, feeders and hoppers
Supply and erect: 12 1,680
includes F.D. Fans (?- @ $390,000
ea*); I.D. fans (4 @$220,000 ea.*)
1.3 Electrostatic Precipitators (3)
Erect only (supply by others): 99
includes electrostatic
precipitators
Supply and erect: 4 220
includes support steel for
precipitators .
1,140 8,700
*based on supplier's verbal budgetary quotations
88
-------
TABLE 30 (page 2 of 9)
2.0 TURBINE GENERATORS (3)
- Install only (supply by others):
includes 835 MWe steam turbine;
generator; exciter; auxiliary
equipment; integral steam and
auxiliary piping; insulation;
miscellaneous labor operations
3.0 PROCESS MECHANICAL EQUIPMENT -
3.1 Boiler Feedwater Pumps (3) :
- includes turbine-driven main
feedwater pumps and drivers
(3 @ $940,000 ea.*); feedwater
booster pumps and motors (2
(? $125,000 ea.*)
3.2 Main Circ. Water Pump's (3)
- includes main circ. water pumps
and motors (3 fl $235,000 ea.*)
3.3 Other Pumps (3)
- includes condensaf.e pumps and
motors (2 @ $95,000 ea.*); and
other pumps and drivers not
listed elsewhere
3.4 Main Condenser* (3)
includes shells; tubes; air
ejectors
Direct Manual
Field Labor
MH 1000's
120
10
17
3.5 Heaters, Exchangers, Tanks and
Vessels (3)
includes l.p. feedwater heaters 9
(4): i.p. feed water heater; h.p.
feedwater heater; deaerating
heater and storage tank;
miscellaneous heaters and exchangers;
tanks and vessels
& £J
*based on suppliers' verbal budgetary quotations
89
Balance of
Plant Material
$ 1000's
100
3,220
750
670
2,440
3,160
-------
TABLE 30 (page 3 of 9)
Direct Manual
Fie?Ld Labor
MH 1000's
86
3.6 Stack and Accessories (3)
- ' includes concrete stack and
Jiner*; lights and marker
painting; hoists and platforms;
stack foundation
3.7 Turbine Hall Crane (1)
- includes crane and accessories 3
3.8 Coal Handling (2)
includes railcar dumping 61
equipment; dust collectors;
primary and secondary
crushing equipment; belt
scale; sampling station;
magnetic cleaners; mobile
equipment; conveyors to pile;
reclaiming feeders; conveyors
to coal silos; coal silos
3.9 Limestone Handling (2)
- includes magnetic cleaners; 22
conveyor to limestone pile;
reclaiming feeders; belt scale;
conveyors to calciner
3.10 Ash Handling (2)
- includes bottom ash system; fly 61
ash handling system for
precipitators and air
preheater; ash conveyors;
ash storage silos (2) with
feeders, unloaders and
' foundations; railcar loading
equipment
*based on suppliers* verbal budgetary quotations
Balance of
Plant Material
S 1000's
1,240
410
5,640
1,250
3,580
90
-------
TABLE 30 (page 4 of 9)
Direct Manual Balan^ of
Field Labor Plant Material
MH 1000's
60
30
120
3.11 Cooling Towers* (3)
- includes mechanical draft
towers with fans and motors
3.12 Other Mechanical Equipment (3)
- includes water treatment and
chemical injection; air
compressors and auxiliaries;
fuel oil ignition and warm-up;
screenwell; miscellaneous
plant equipment; equipment
insulation
3.13 Scrubber Ductwork (3)
- includes flue gas duct
outboard of electrostatic
precipitators; duct lining;
duct insulation; dampers and
expansion joints
3.14 Scrubber Flue Gas Equipment (3)
includes F.D. fans for flue gas
reheat (6 & $85,000 ea.*); air
heaters for flue gas reheat
(6
-------
TABLE 30 (page 5 of 9)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ JOOO's
3.16 Scrubber Lime System (3) 66 3,660
- includes limestone calcincr with
travelling grate kiln ($2,700,000*);
Kiln stack; coal conveyor, bucket
elevator and storage bin for filn;
lime conveyor, bucket elevator and
storage silos; lime slaker ($120,000*)
3.17 Scrubber System Pumps, (-3) 10 1,080
- includes slurry recycle (18 @
$40,000 ea.*); mist eliminator *
wash (3 @ $25,000 ea.*); slurry
storage and transfer (4 @ $4,000
ea.*); slurry feed (3 @ $5,000V"
ea.*); pond feed tank (3 @ $10,000
ea.*); pond feed booster (21?^
$15,000 ea.*); pond water recycle
and booster (4 !? $f2,500 ea.*)
3.18 Scrubber System Tanks (3) 4 2,180
includes tanks and agitators
for absorber effluent hold,
pond feed, entrainment -
separator surge, slurry surge,
slurry storage, slurry transfer
660 43,300
*based on suppliers' verbal budgetary quotations
92
-------
TABLE 30 (page 6 of 9)
4,0 ELECTRICAL (5)
4,1 Main Transformers*
4.2 Other Transformers* and Main Bus
- includes startup transformer;
station service transformers
including those for scruhber
system; generator main bus
4.3 Switchgear and Control Centers
*
- includes switchgear and load
centers; motor control centers;
local control stations; dis-
tribution panels, relay and
meter boards
4.4 Other Electrical Equipment
- includes communications;
grounding; cathodic and
freeze protection; lighting;
pre-operational testing
4.5 Auxiliary Diesel Generator
- includes diesel generator,
batteries and associated
d.c. equipment
4.6 Conduit, Cable Trays, Wire
and Cable
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ 1000's
17
42
363
632
2,020
1,280
3,400
2,010
110
4,080
1,060
*based on suppliers' verbal budgetary quotations
12,900
93
-------
TABLE 30 (page 7 of 9)
5.0 CIVIL AND STRUCTURAL
5.1 Concrete Substructures and
Foundations (1)
- Includes turbine and boiler
building substructures; coal,
limestone and ash handling
foundations, pits and tunnels;
miscellaneous equipment
foundations; auxiliary buildings
substructures; miscellaneous
concrete
5.2 Superstructures (1)
- includes turbine building;
auxiliary yard buildings;
boiler enclosure
5.3 Earthwork (1)
includes building excavations;
coal, limestone and ash
handling excavations; circ.
water system excavations;
miscellaneous foundation
excavations; dewatering and
piling
5.4 Cooling Tower Basin and Circ.
Water System (3)
- includes circ. water pump pads,
riser and concrete envelope for
pipe; cooling tower basin; circ.
water pipe; cooling tower
miscellaneous steel and fire
protection
Direct Manual
Field Labor
MH 1000's
340
Balance of
Plant Material
$ 1000's
2,8-0
275
7,960
130
300
105
1,680
94
-------
TABLE 30 (page 8 of 9)
5,5 S02 Scrubber Civil and
Structural (1)
includes foundations, earthwork
and structures particular to
scrubber equipment
Direct Manual
Field Labor
KIT lOOO's
180
Balance of
Pin.jt Material
? 1000_'.s
3,660
6.0 PROCESS PIPING AND INSTRUMENTATION
6.1 Steam and Feedwater Piping (3) *
- includes main steam; extiaction
steam; hot reheat; cold rfehtnt;
feedwater and condensate l;:rge
piping, valves and fittings
6.2 S02 Scrubber System^Large Piping (3)
- includes make-up water; resaturation
slurry water; mist eliminator wash;
absorber slurry affluent tank
overflow; pond feed; pond recycle
water; lime slurry piping; recycle
slurry piping; air heater steam
supply; air heater condensate
return
6.3 Other Large Piping (3)
includes auxiliary steam; process
water; auxiliary systems
6.4 Small Piping (3)
includes all piping, valves and
fittings of 2-inch diameter and
less
1,030
81
51
231
152
16,400
3.S50
2,370
; 050
1,350
95
-------
TABLE 30 (page 9 of 9}
Direct Manual Balance of
Field Labor Plant Material
HH 1 OOP's $ 1OOP's
6.5 Hangers and Misc. Labor 419 1,420
Operat'..u3 (3)
- includes all hangers and supports;
material handling; scaffolding;
misc. labor operations
6.6 Pipe Insulation (3) 62 640
6.7 Instrumentation and Controls (5) 219 4,820
1,215 18,500
7.0 YARDWORK AND MISCELLANEOUS (1) ,
7.1 Site Preparation and Improvements 87 10
includes soil testing; clearing
and grubbing; rough grading;
finish grading; landscaping
7.2 Site Utilities 5 50
- includes storm and sanitary sewers;
nonprocess service water
7.3 Roads and Railroads 27 740
- includes railroad spur; roads,
walks and parking areas
7.4 Yard Fire Protection, Fences 52 600
and Gates
7.5 Water Treatment Ponds 83 20
includes earthwork; pond lining;
offsite pipeline
7.6 Lab, Machine Shop and Office Equipment 1 280
2tn 1,700
96
-------
TABLE 31
BALANCE OF PLANT CAPITAL COST BREAKDOWN
CONVENTIONAL STEAM PLANT—WET GAS SCRUBBERS—175 F STACK
Costs (Millions Of Dollars)
Dirtct Indirect
Categories
l.ft- Steam Generators
2.0 Turbine Generator
3.0 Process Mechanical
Equipment
4.0 Electrical
5.0 Civil and
Structural.
6.0 l-'jocess Piping and
Instrumentation
7.0 Yardwork and
Miscellaneous
Components
45.88
26.75
'
-
72.63 .,
Labor(l)
13.40
1.41
7.76
12.46
12.10 ^
1«.2V
3.06
64,46
Field (2)
12.06
1.27
6.98
-11,21
10.89
12.85
2.75
58.01
Materials (3)
8.70
0,10
43.30
12.90
16.10
18.50
1.70
101.30
Total
80.04
29.53
58.04
36.57
39. M9
*^
i
45.62
7.51
296.40
BOP Labor, Materials & Indirects 223.2
(Sum of 1 +• 2 + 3)
A/E Home Office & Fee @ 15% . 33.57
Total Plant Cost 329.97
Contingency
-------
Table 32
SUMMARY PERFORMANCE AND COST
CONVENTIONAL STEAM PLANT—WET fiAS SCRUBBERS--175 F STACK
ITEM
Net Power Plant Output (MW -60Hz-50QkV) 795.5
Therroodynaraic Efficiency (%,) A3.1
Power Plant Efficiency (%) 33.8
Overall Energy Efficiency (%) . • 33,8
Coal Consumption (Ib/kWh) 0.936
Total Wastes (Ib/kWh) 0.25
Plant Capital Cost ($ Million) 613.6
Plant Capital Cost ($/kW ) 771.3
Cost of Electricity, Capacity Factor = 0.65
Capital (Mills/kWh) 24.-'>
Fuel (Mills/kWh) 10.1
Maintenance and Operation (Mills/kWh) 2.5
Total (Mills/kWh) 37.0
Estimated Time of Construction (Years) 5.5
Approximate Date of First Commercial Service 1980-1982
-------
Table 33
SUMMARY PERFORMANCE AND COST
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F STACK
ITEM
Net Power Plant Output (MW - 60 Hz - 500 kV)
Thermodynamic Efficiency (%)
Power Plant Efficiency (%)
Overall Energy Efficiency (%)
Coal Consumption (LB/kWh)
Total Wastes (LB/kWh)
Plant Capital Cost ($ Million)
Plant Capital Cost ($/kW )
Cost of Electricity, Capacity Factor = 0.65
Capital
Fuel
Maintenance & Operation
Total
Estimated Time of Construction (Years)
Approximate Date of First Commercial Service
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)
795.5
43.1
33.8
33.8
0.936
0.25
613.6
771.3
99
-------
Table 34
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS
INFLUENCE OF STACK REHEAT TEMPERATURE
PARAMETER
Steam to Gas Reheater, LB/HR
Generator Output, kW
Net Plant Output, kW
Ovemll Energy Efficiency, %
Capital Cost, M$
Capital Cost, $/kW
Electricity Cost, MillsVkWh
Capital
Fuel
O&M
TOTAL
250 F. STACK
926,000
819,938
747,200
31.8
624
835
26.4
10.7
2.6
175 F STACK
213,426
868,620
795,500
33.8
614
771
24.4 *7
10.1
2.5
39.8
37.0
Table 35
COST OF ELECTRICITY (COE) SENSITIVITY
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F STACK
BASE
CAPACITY
FACTOR
COE,
COE,
COE,
Capital
Fuel
O&M
TOTAL COE
0.
24.
10.
2.
37.
65
4
1
5
.
42.1
LABOR
COST
INCREASE
20%
26.
10.
2.
39.
5
1
5
1
MATERIALS
CAPACITY
FACTOR
INCREASE
20%
27.
10.
2.
39.
2
1
5 .
8
0
31.
10.
2.
44.
CHANGE
.5 &
7
1
6
4'
0.8
19.8
10.1
2.5
32.4
100
-------
No Scrubber, 250 F Stack Alternative
It is instructive to apply the methodology of these evaluations to a
plant In which low-sulfur coal would be burned and the wet gas scrubbing system
dispensed with. An identical boiler would be used. An air preheater enlarged
62 percent would bring the stack gas to 250 F as appropriate for low-sulfur
fuel. The coal, air, and gas rates and boiler auxiliary losses would be scaled
downward 1.4 percent by the boiler efficiency improvement. The electrostatic
precipitator would precede the air preheater, to operate on the high-temperature
low-sulfur gas stream. The heat to the steam cycle would be unchanged.
The steam turbine cycle would be identical with that of another system
that has been analyzed in detail as to balance-of-plant man-hour-and material
costs. Use of the available data with the boiler and other data used with the
wet scrubber cases permitted the, synthesis of a cost breakdown and performance
on a comparable basis.
Table 36 presents the breakdown of auxiliary losses, and Table 37 compares
the performance and costs to the wet scrubber case with 175 F stack. The
overall efficiency would be 36,2 percent. The cost of electricity would be
30.5 mills/kWh if the fuel cost remained at $l/MBtu. The price of low-sulfur
coal at exact parity with the wet scrubber case (with 175 F reheat) would be
$1.68/MBtu. A dominant plant difference would be the absence of the large
sludge ponds. The reduced operating and maintenance cost reflects elimination
of the costs of limestone, maintenance of the wet scrubber system, and operators
for the wet scrubber system.
101
-------
Table 36
AUXILIARY LOSS BREAKDOWN
CONVENTIONAL STEAM PLANT-NO SCRUBBERS-250 F STACK
ITEM MW SUBTOTAL MW
Furnace 26.S5
FD Fans 3.35
PA Fans 2.81
ID Fans 7.84
ESP 5.10
Pulverizers 7.45
Turbine Auxiliary 2.90
Wet Scrubbers-None 0.00
Major Pumps 11.07
Booster 3.37
Circulating 4.70
Other " 3.00
Solids Handling 3.00
Hotel Loads 8.50
Cooling Tower Fans 2.80
Transformer Loss 4.40
TOTAL AUXILIARY POWER = 59.22 MW
102
-------
Table 37
SYSTEM OUTPUT
CONVENTIONAL SYSTEM PI.ANTS
PARAMETER
Generator Output, MW
Auxiliary Losses, MW
Net Plant Output, MW
Output Ratio
Overall Energy EFF, %
Capital Cost, M$
Capital Cost, $/kW
Electricity Cost (COE), Mills/kWh
Capital -
Fuel
O&M
TOTAL
175 F :
WET SCRUBBERS
868.6
73.1
795.5
1
33.8
"•*! •
614
771
250 F
NO SCRUBBERS
883.9
59.2
8 2 A. 7
• 1.04
36.2
511
620
24.4
lO.'l
2.5
37.0
19.6
9'5*
1.4
30.5*
*Assumes fuel cost same as for 3.9% sulfur coal ($1.00/MBtu). Low sulfur
coal at $1.68/MBtu would increase fuel cost such that the total COE for
the no-scrubber case would equal the total COE for the scrubber case with
175 F reheat.
103
-------
C. ATMOSPHERIC FLUIDIZED BSD POWER PLANT
1. INTRODUCTION
The.advanced steam cycle power plant with atmospheric fluidized beds
(AFB) achieves the functions of combustion, steam generation, and sulfur
capture in the four modular AFBs that replace a conventional steam boiler
requiring wet flue gas scrubbers to remove sulfur. A simplified cycle
schematic is presented in Figure 14 showing the major pieces of equipment.
The AFB corabusstor consists of four separate modules. Each module con-
tains seven beds stacked one on top of another as described later. Six of
the b';ds in each module will be primary combustion beds that burn coal. The
bottom bed in each .module i.s a carbon bur nup cell, fed with carbon-containing
fly ash and bed material from the primary beds in that module.
the system parameters are presented in Table 38. The Illinois No. 6
coal contains 3.9 percent sulfur. Eighty-three percent of the sulfur must
•be captured to meet the environmental emission limit of 1.2 Ib/MBtu of fuel
heat release. The capture medium is limestone fed.into each of the six
primary fluidized beds at twice the rate that would ideally capture all of
the sulfur.* The 1550 F main bed operating temperature was selected to
maximize sulfur capture at 85 percent of that present in the coal. Unburned
carbon is conveyed from the main beds in the fly ash of the gas strean, and in
.the solids tapped from each bed. The 95 percent of the fly ash recovered in
.cyclone separators and the tapped primary bed solids is recycled to a carbon
burnup cell, where a higher temperature of 2000 F and increased excess air of
30 percent produce a substantial burnup of residual combustibles. In essence,
the main beds release energy while capturing sulfur as calcium sulfate. The
carbon burnup cell releases additional energy but without the burden of sulfur
capture; the result is a high boiler efficiency.
The steam ~ycle uses conventional conditions for a supercritical reheat
steam turbine with seven feedwater heaters. The condenser back pressure was
chosen to optimize the total cost of electricity.
The heat rejection system used 24 cells of mechanical draft evaporative
cooling towers. The net power from the plant would be 814 MW representing
35.8 percent of the higher heating value (HHV) of the coal supplied to the
plant.
*i.e. a Ca/s ratio of 2:1. This parameter was selected to be consistent with
the PFB design. More recent data suggests that a Ca/S ratio of 2.^:1 to
3.5:1 may be zequired for adequate sulfur capture in AFB plants, resulting
in increased costs.
Preceding page blank
-------
Coal Limestone
L_
Solids Handling
FD Fans
Air
ID Fans
Gas
Stack
AFB
T
Reheat
Steam
[HP -HB-
IP
Feedwater
Feed Heaters
LP
-ID-
Condenser
Solids Disposal
Figure 14. Simplified Schematic Diagram of Advanced Steam
Cycle — Atmospheric Fluidized Bed.
-------
Tab.re 38
SYSTEM PARAMETERS
ADVANCED STEAM - ATMOSPHERIC FLUIDIZED BED
PARAMETER VALUE.OR DESCRIPTION
FUEL
ILLINOIS NO. 6 10788 Etu/lb HIGHER HEATING VALUE
$i/MBtu 3.9% SULFUR
LIMESTONE SULFUR CAPTURE MEDIUM
0.257 Ib/lb COAL
FURNACE .
ATMOSPHERIC FLUIDIZED BED COM3USTOR /JJD STEAM GENERATOR (4 MODULES)
MAIN BEDS (6 ?ER MODULE) ~ 1550 F, COAL AND LIMESTONE
?*- ' *
CARBON BURN-UP CELL (1 PER MODULE) ' 2000 F, FLY ASH AND SOLIDS ^
DRAIN
EXCESS AIR * . 20%
PRIME 'CYCLE - STEAM PLANT
WORKING FLUID '"' STEAM
TURBINE INLET 33500 PSI, 1000 F
REHE/.T *>44 PSI, 1000 F
CONDENSER 2'3" Hga. 106 F
FINAL FEEDWATER 4378 PSI, 505 F
HEAT REJECTION
WET MECHANICAL 2<4 CELLS
DRAFT COOLING
TOWERS
STACK GAS TEMPERATURE 25° F
107
-------
2. CYCLE DESCRIPTION
A detailed plant schematic is presented in Figure 15. State points
and stream flows are shown in which the enthalpy values are referenced to
32 F water for steam and water and to an 80 F zero reference for air, combustion
gases, and solids. The advanced feature of this power system is the use of AFB
combustion to generate steam from high sulfur coal for a conventional steam
turbine cycle with a single reheat of the steam.
Steam Turbine-Generator Cycle
The steam turbine is contained in four shells connected in tandem with
a single generator. The low-pressure stages have four parallel flows
exhausting downward into a common condenser. The condenser coolant is
water recirculated in a closed circuit to the evaporative cooling towers.
The regenerative feedwater heating cycle has four low-pressure feedwater
heaters, a deaereating feedwater heater, and two high-pressure feedwater
heaters. Part of the steam exhausted from the high-pressure turbine is
used in feedwater heating, while the rest is returned to the AFB units to
be reheated to 1000 F. Part of the steam from the reheat turbine exhaust is
used for driving the boiler feed pump. The exhausts from those drive turbines
are routed to the main condenser. All other pump drives are driven by electric
motors and appear in the detailed account of auxiliary losses. The boiler feed
pump and its drive are an integral part of the steam cycle and are fully accounted
for in the heat balance for the steam turbine-generator.
The final feedwater temperature is 505 F for operation at the 100 percent
point. It is conventional practice to reference the steam and feedwater states
when a 5 percent greater steam flow exists at the valves wide open (WC)
operating point. For that ease the feedwater would be at 510 F.
Atmospheric Fluidized Beds
The feedwater from the steam cycle passes first through the waterwalls
that surround the AFB cells and then in sequence through economizers located
in the gas flow above each fluidized bed. The hot cnrbon burnup cell is last in
this sequence since, at 2000 F, it is the hottest combustor> Next, the fluid,
which is now steam, is Touted through primary superheaters in the gas space of
the upper three main beds and then through finishing superheaters submerged in
the upper three main beds. Steam at 3500 psig and 1000 F is discharged to the
turbine. Steam returned for reheat at 716 psig follows a comparable routing
through the lower three main beds. There will be four identical AFB modules
operating in parallel to supply the steam required to the single steam turbine.
Each AFB module has six main beds rather than the two shown sche-
matically in the figure. The injection of coal and limestone is assisted by
the flow of primary air (PA) along with these solids. The main airflow (A)
enters the bed in an upward flow through a perforated distribution plate
that is the bottom of each fluidized bed. Most of the fluidized bed solids
are the residual products of the coal-air-limesrone reaction. A continual
108
-------
14 7/59/0.7I54Z5/I0786
Cool
Cyclone ,14-63/730/698/167
I (Gas 730F
Afmospher c Fluidijed
Bed Modules
Steam Turtint-Generolor Tandem Compound Four Flo* (I)
'Holfl' Loodl 8.8 M*
Tronslormtf Loss 4.4MW
Reheat I—B—©$.
VoleupondSefv
19 MW
1155/106/486/745
M 7/250/8115/41
' i ! Cooler ! '
-intnt • ' (j-, !•— Scant
I 5e!iif» ! !o!;3i ;
Ncie
; s.'.o ;zi
4.7/Z75,D 237/50
'Cooler(2) i
C:ol PA
Figure 15. Schematic Diagram of Advanced Steam Cycle—
Atmospheric Fluidized Bed
-------
tap of these solids maintains a constant bed inventory of solids. The bed
temperature of 1550 F results in maximum sulfur capture. It is also below
the ash fusion temperature. Most of the ash will be conveyed by the gas
stream as fly ash. The heat exchange surfaces within the bed material
experience high overall hpac transfer rates as a result of the localized
agitation of the bed material. In the carbon burnup cell bed the temperature
of 2000 F is too hot for use in superheating or reheating steam in conjunction
with the high heat transfer rates. Only water tubes aV_ located in the bed of
the carbon burnup cell for the purpose of in-bed fl't^d dynamic stability.
The gases leaving the beds must be cooled tc 730 F for effective fly ash
removal from the low sulfur gas streams. This cooling is done by heat transfer
to steam superheaters and reheaters and then to economizer surfaces as
described above. ::
The solids fed to the carbon burnup cells comprise the solids tapped
from the main beds and that portion (95 percent) of the fly ash collected
in the cyclone separators that receives the gas flowing from the main beds.
•** '•
Flue Gas and Air Supply
•** * •
The flue gas from the main beds and from the carbon burnup cells at
730 F flow through cyclone separators that remove 95 percent of the solids
burden in the gas streams. The hot electrostatic precipitators (ESPs) remove
the remaining fine fly ash to rhe level mandated by emission standards. The hot
flue gas next passes through the air preheater, where it is cooled to 240 F.
The induced draft (ID) fan assists in this flow and delivers .the. gas at 250 F
to the stack.
Air tor combustion passes through the forced draft (FD) fans. About
15 percent of that air is further boosted in pressure by-the primary air
fans so that it may be used to convey solids into the fluidized bed cells.
The main air (A) is heated to 675 F in the air heater and is then routed to the
fluidized bed ccl^s. The pressure rise of the forced draft fans is substan-
tially greater than conventional practice because of the flow restrictions
imposed by the fl'iidized beds, their perforated air distribution plates, and
the cyclone fly ash separators.
Spent Solids Systems
Spent solids in the form of dry hot granular material are collected from
the carbon burnup cell solids tap. Spent solids in the form of dust are
collected from the carbon burnup cell cyclone separator and from the ESP. The
composition of the spent solids aggregate is ,42 percent calcium sulfate, 24
percent unreacted lime, 31 percent ash, and 3 percent unburnod carbon. The
unreacted lime results from the 100 percent excess in the limestone feed rnte
as well as the fact that the lime is not 100 percent effective in sulfur capture.
Coolers are provided for the spent solids nnd dust to supply heated
air for the drying of c<»il and limestone. A small amount of coal is burned
110
-------
In the spent solids cooler to augment this regenerative nge of the sensible
heat in the spent solids.
Coal and timestone Systems
Hot air at 750 F from the spent solids system is drawn through the feed-
stock dryers and storage silos by the silo air fans. The dried coal and lime-
stone are crushed to size, blended, and then conveyed to the AFB main cells by
vibrating inclinod tables. Primary air is use-J to assist the flow from the
tables down through the many injection needles or tubes in the beds.
Overview
The fluidized main beds scavenge sulfur-, and the carbon burnup bed
scavenges otherwise lost combustibles from fly ash and solids discharged.
The subdivision into four modules ensures that malfunctions in a sJrgle AKB
system would not result in total plant shutdown. The steam turbine <:r.d its*
support systems are of proven high- reliability.
Ill
-------
3. MAJOR CYCLE COMPONENTS
Components for steam power plants are specified for continuous operation
With flow rates 5 percent greater than the requirement for the ICO percent
power. Figure 15 depicts the 100 percent operating point. The major compo-
nent specifications as well as the balance-of~plant (BOP) components specifi-
cations are based on continously sustaining the 5 percent margin. For the
steam turbine-generator this operation is at the WO condition of the main
steam throttle control. This customary margin in all components assures
purchasers that the entire system will not-fall below its intended pcwer
rating because of some minor inadequacy in one or more components. The
specifications for components will generally not match exactly the stated
performances shown in Figure 15.
The design and performance details of the AFB modules and the steam
turbine-generator are considered in this section. All remaining equipment
vould be specified and supplied by an architect-engineer (AE) as BOP
materials. Equipment lists for these itons are provided under'"System
Performance and Cost." • ._.
Atmospheric Fluidized Bed Modules '*" * "
*~
The major component of the heat input systems is the AFB module together
with its air supply and hot gas cleanup equipment and the solids handling
equipment. <">
In the fluidized bed combustion process, air enters a plenum at the bottom
5f the call, flows up through a grid plate that is designed.to distribute the :
air uniformly across the bed, passes through and fluidises the bed material
which envelops a tube bundle, exits from the bed, passes through a convection
pass tube bundle located above the bed, and exits from the cell. Coal and
limestone are injectsd into the bed through injection pipes that are arranged
to distribute the coal uniformly across the bed plan area. Feeding is
continuous in order to provide steady combustion conditions. Spent bed
material is continually drained to provide steady bed operating levels. The
surfaces submerged in the fluidized bed have exceptionally good heat trans-
fer characteristics. In addition there is no coal ash corrosion of the heat
exchange surfaces since the beds operate below the ash fusion temperature
and provide a continuously alkaline atmosphere. Fluidized bed combustors
require a combustion air supply syr-tem, a hot gas cleanup system for removing
particulate material entrained in the flue gas, coal and sorbent processing
and feeding systems, and a spent bed material removal system.
The spent bed material is alkaline and should be handled in a dry state.
Because of its good chemical reactiv-c/ and alkalinity, it is considered a
chemical by product of the process anu can be used in a number of ways. For
example, the use of atmospheric fluidized Bed dust has been reviewed for appli-
cation in the neutralization of acid mine runoff, the preparation of fertilizer,
in the preparation of alkaline scrubbing solutions for other conventional units.
Because of its concentrated iron (magnetite) and alumina ccntent it has
been considered as a fetdstock fof iron and aluminum manufacture. Its
112
-------
practical use as a feedstock for metallurgical processing will depend to some
extent on a better understanding of the chemical composition as a function of
size distribution in the solids products recovered from the fluidized bed
boiler. Regeneration of spent bed material was not consiJered in this study
and requires further development.
Figure 16 shows the equipment for spent bed material removal and cooling.
The spent sorbent is transported by a high-temperature vibrating conveyer to
an air fluidized bed cooler which cools the material to disposable temperatures
of 250 to 300 F. Heat recovered from the cooling of the spent sorbent is used
to dry the raw coal and limestone by ducting the coolers' hot discharge air to
the dryer units. During plant startup conditions, when hot spent sorbent is not
available, the drying units obtain their heat for drying by burning coal in
their furnace sections.
The Hot Gas Cleanup section of Figure 16 shows the conventional cyclone
separators and ESPs that strip elutriated bed material from the flue gases.
Solid material captured in the main bed cyclones is recycled to the 2000 F
carbon burnup cell. Material from the carbon burnup cell that is captured in
its cyclone separator is removed and cooled by means of an air-fines cooler.
Pa.rticu.late matter captured in the ESPs is removed from the process without
cooling since the heat content of this stream is small. It is to be noted that
"hot" precipitators at 730 F are used instead of conventional 300 F "cold"
precipitators in orde\- to ccnocusate for the low ash resistivities that are
encountered with 1ow-temperaturf, low-sulfur bearing flue gases.
The Air Supply System utilizes forced draft (FD) and induced draft (ID)
fans to "push" and "pull" the combustion air through the system. Primary
air boost fans are used to provide the high air pressures that are required
to inject the coal and limestone into the beds. Regenerative air heaters are
utilized'to recover flue gas heat and preheat the combustion air; the leakage
rate was assigned as 7 percent. This leakage rate is considered to be some-
what optimistic, but obtainable with advanced design. If air leakage rates
of less than 10 percent cannot be economically obtained in regenerative air
heaters, the use of an extended surface tubular air heater of advanced design
is indicated for further study.
A combustion control and safety interlock system is required. A more
complicated control system is required with a fluidized bed boiler consisting
of four towers with seven combustion beds in each tower and the need for
blending and controlling the steam production of four towers. Because of the
multiplicity of heat transfer circuits required in this system, a more complex
startup system and control valve arrangement is required on the water and
steam circuit, further development is required for steam circuitry and control.
Valves and controls for the modules only are included; items needed for a
four-tower steam blending system were omitted,
A process flow schematic is presented as Figure 17 which summarizes the
detailed heat and mass balances made for each item of equ^ment at the design
specification point. The schematic is for one of tour AFB modules.
113
-------
1
• | HOT GAS CLEANUP
I MATERIAL I
I FEEDING I
,&!
\ 1 «HtK»lON*1 . l_ jf
,„,..,.> t 1 I | "
v.«"iS t f —'— i
"" T J I I
»H »»••««"'»«
-J(H, ( «"«""• |-
SPENT BED MATERIAL
REMOVAL AND COOUHG
I AIR SUPPLY
Figure 16. AFB Solids Handling and Hot Gas Cleanup Equipment
Systems for Two Module Trains (Foster Wheeler)
-------
LIME
STONE
IW
j J
in ni
Y.
Figure 17. Atmospheric Fluid Bed Steanf Generator — Process Flow
Schematic (Foster Wheeler).
-------
Figure 18 shows a design concept of one AFB tower for steam generation.
This concept was developed to a sufficient level of detail to reveal all
najcr engineering problems and to permit realistic cost evaluations. The
unit is 12 ft x 34 ft x 180 ft tall and weighs 800 tons in operation. It
includes economizing, superheating, and reheating services in the beds and in
convection spaces above the beds. The tubes are of conventional materials, and
tube bundles were sized to be shipped by rail. Fuel is injected into the beds
through needles, each servicing about 10 square feet of main bed area. The
bottom unit is the carbon burnup cell (CBC). There are six main cells stacked
on top of the CBC. The air and flue gas duccs taper from bottom to top in pro-
portion to the local gas flow. The heat absorption in each AFB module is
shown in Figure 19. At the extreme left appear the total heat to steam for
each cell (SHS, RHS duty). The fluidized bed heat exchange surfaces have an
overall heat transfer coefficient of 40 Btu per hr ft^ F. The convection
surfaces above the bed have coefficients one-third to one-quarter those in the
bed. Table 39 details the heat exchanger surfaces shown in Figure 19. Table 40
summarizes the basic requirement for materials which lead to Item 1 in Table 41
where the selling prices of the AFB module are derived from the component
weights. The costs of module auxiliaries are presented with the major component
equipment lists under "Plant Cost Estimates."
The performance evaluation for uhe overall boiler system shows a boiler
efficiency of 87.92 percent for he.it to steam divided by the total coal
fired. If additional heat recovery from spent solids could completely dis-
place coal burned to supplement drying of coal and limestone, then a boiler
efficiency of 88.46 percent would be realised.
Prime Cycle
The major component for the prime cycle is the steam turbine-generator.
'The selected unit was a General Electric Tandem compound turbine with 4-flow
exhaust using 33.5-in. last-stage buckets. The rating wns selected to reach the
maximum allowed steam flow through the last-stage buckets at the VWO and over-
pressure condition. This selection is typical of current utility purchases.
An outline drawing, Figure 20, shows the four turbine shells and the generator
having an overall length of 173 ft. The performance of the steam turbine-
generator is inseparable from many of the BOP components that are part of the
prime cycle heat balance. Figure 21 presents the heat balance for the 100
percent operating point for the entire prime cycle. The heat-to-steam is
6286.7 MBtu/hr. The gross efficiency of the prime cycle is 43.9 percent.
The condenser back pressure of 2.3 in. Hga resulted from an economic
optimization of the turbine and heat rejection system in combination.
Although the cooling tower was not a major component, its specifications are
given in Table 42 inscfar as they impact directly on the steam turbine prime
cycle performance.
116
-------
h I
9 I
Figure 18. Advanced Steam Cycle - Atmospheric
Fluidized Bed Boiler (Foster Wheeler)
117
-------
SHS , RHS
OOTY DUTY
2M.K3
26«.l«3
212.704 | 91.439
2I2.7CH I 31.45*
44.364 . 221.79*
113.103
I4SI.34SO 3287170
Swp«rn«at * Riniai •
Total Output - 1780.0820
BTU/IB
• -Time t
m-Ftttw milliefl !b/hf
0-m,M.3n eTU/kr
Figure 19. Advanced Steara - PFS Circuit Absorption Diagram
118
-------
Table 39
AFB MODULK HEAT rxCllANfiER SURFACK DATA
Cell Bank
1 El
PSII1A
PSII1B
2 E2
PS1I2A
PS112H
3 E3
PSH3A
PSK3B
4 E4
RH4
FSH4
5 E5
RH5
FSH5
6 E6
R1I6A
RH6B
7 E7A
E7B
WW
So(ftz)
12818
2136
6409
12818
2136
6409
12818
2136
6409
7477
6836
7976
7477
6836
7976
7477
6836
6409
15131
997
15209^
t)o
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
2
1-3/4
f
1-1/4
2
1-3/4
1-1/4
2
1-3/4
1-3/4
1-3/4
1-1/4
Ns
96
96
96
96
96
96
96
96
96
96
48
64
96
48
64
96
48
64
64
64
736
St
3
3
3
3
3
3
3
3
3
3
6
4-1/2
3
6
4-1/2
3
6
4-1/2
4-1/2
4-1/2
1-1/2
SI
1-1/2
1-1/4
1-5/8
1-1/4
1-1/4
1-5/8
1-1/4
1-1/4
1-5/8
. 1-1/4
2-1/4
2-1/4
1-1/4
2-1/4
2-1/4
1-1/4
2-1/4
2-1/4
1-3/4
2-1/4
fin
BC +
31-1/4
6-1/4
20-3/4
31-1/4
6-1/4
20-3/4
31-1/4
6-1/4
20-3/4
21-1/4
3R
37-1/4
21-1/4
38
37-1/4
21-1/4
38
28-3/4
54-1/4
4
_
Nr
12
2+
6
12
2+
6
12
2+
6
8
8
8
8
8
8
8
8
6
15+
1
1
1/1
1
2
2
1
2
2
1
2
2
1
4
4
1
4
4
1
4
6
1
1
1
Loops
6
1/2
1-1/2
6
1/2
1-1/2
6
1/2
1-1/2
4
1
1
4
1
1
4
1
1/2
7-1/2
1/2
1/2
tin/flout
(2/12
14/-
-/14
12/12
14/-
-/14
12/12
14/-
-714
12/12
1R/20
20/24
12/12
18/20
20/24
12/12
1R/20
"•4/28
12/-
-/14
14/14
0,/*I/0,
12/12/12
14/14/-
2? 10/^4/20
12/12/12
14/14/-
2fl 10/24/20
12/12/12
14/14/-
23 10/24/20
12/12/12
24/18/20/24
20/24/24
12/12/12
24/1S/20/24
20/24/24
12/12/12
24/18/20/24
24/32
12/!2/-
-/14
14/24/lf. fl 6 in
16 9 6/24/14 out
Notes:
So - Installed Surface - Ft2
to - Tube O.D. - inches
Ns - No. Sections wide
St - Side spnclnfi - inches
SI - Back spacing - inches (staggered pitch)
BC - Bundle clearance - inches (includes one S,
Nr - Number runs
1/1-loop in loop
Pin/Pout - header diameter inches
0j/02/03 - Header, Tx pipe sizes - inches
extra for supports)
119
-------
Table 40
HX SURFACE
El, 2, 3
E4, 5, 6
E7A, B
WW
PSH1, 2, 3
FSH4, 5
RH4, 5, 6
E
AFB MODULE WEIGHT BREAKDOWN
RAW HEAT EXCHANGER SURFACE MATERIAL, TONS
TONS
133.3
77.9
/7.8
70.0
114.1
121.7
111.1
705.9
100
CS
133.3
77.9
72.4
283.6
40.2
T2
5.4
58.7
23.6
87.7
12.4
T22
11.3
90.5
77.9
179.7
25.5
T304
121.7
33.2
154.9
21.9
120
-------
Table 41
AFB MODUtE WEIGHT AliD COST BASIS MID-1975
1. Heat Transfer Elements and Pressure Parts
2.
3.
4.
SUMMARY
1.
2.
3.
4.
5.
6.
7.
Material Tons
CS 447.6
T2/P2 183.7
T22/P22 191.5
TP304 202.1
1N601 5.2
Hast. X 1.6
1031.6
Special FBBU Items
£•
FBBU Item
Injector needles
Fluldization grilles ...;
Solids line
Solids valves
Control System
Item
Startup, steam valves 33
Combustion elements 7
Bed air dampers 7
CC & SIS (Controls, operators,
Miscellaneous Items
Item
Flues and ducts
Flue and duct insulation
Boiler lag and sheath
Backstays and braces, etc.
Misc. v-ipe, springs, joints
262.6 tons
Surfate & Pressure ?arts
FBBU Items
Control Systems and Valves
Attached Flue and Duct
Boiler Uig and Sheath
Buckstays, Braces, Hangers
1975
$/Ton
2848
3144
3774
11771
13300
24321
Tons
32.55
35.70 •*
60.00
8
135.25
1975
Rate
@ 3960
g 11000
@ 4400
etc.)
(Unit)
or Tons
330
76.5
62.5
90.0
1R.O
577.0
on botler
Miscellaneous Piping, Small Vaives,
Supports, etc.
^b &
1975
MS
1.275
.578
.723
2.379
.069
.039
5.063
1975
S/Ton
6455
6528
3300
13750
Tons
17.4
3.5
5.6
26.50
1975
$/Ton
1430
2200
080
1100
5500
'ions
1031.6
136.3
26.5
92.1
62.5
90.0
18.0
1457.0
-Controls
-
1975
M$
.210
.233
.m
.110
.751
1975
MS
.131
.077
.031
.239
.435
.724
1975
MS
.472
.168
.055
.099
.099
.893
-rl$(7S)
5.063
.751
.724
.138
.055
.099
.099
6.930
-._724
6.206
121
-------
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lus.ctu i;iv w 2, J-ii,. AI... o": MII
t^. MID M-A ^ 7*1 I'M*. iu t'ncss. r. o.to
Figure 21. AFD Steam Cycle Heat Balance - 100% Output
-------
Table 42
COOLING TOWER PERFOR11ANCE
Design heat duty
Wet bulb
Condensing at 2.3 in. Kga
Hot water to tower
Cold water return
Range
Approach
Water flow
Fan power
Pump powor
Cells
3,$51 MBtu/hr.
51.5 F
105.9 F
100,9 F
70.2 F
30.7 F
18.7 F .
250,909 gal/min
2.78 MW
4.73 MW
Each cell: 36 feet long, 75 feet wide,
47 feet high, 1 fan
124
-------
Materials of Construction
Steam turbines operating at design steaia temperatures of 1000 F have
demonsctnted a high degree of reliability and utilize materials with
a long history of development and service.
I
Buckets are subjected to centrifugal forces, steam forces, vibratory
forces,.thermal stresses and erosion from wet steam. Alloys are chosen
on the basis of strength at operating conditions, erosion and corrosion
resistanct, damping properties, and ease of machinability. A 12 percent
Cr alloy is a typical selection.
Turbine rotors ar.J wheels arc subjected to bucket loadings and must have
high resistance to creep ,irid rupture an! good thermal stability to resist
bowing. The material is selected on the basis of yield, tensile, creep, and
rupture strenghts, translation temperature hardness and impact strength, and
its resistance to erosion and corrosion due to normal steam chemistry, <\.i.loy
stee.ls rre typically used.
Nozzle diaphragms must perform over a wide range of temperature and
pressure conditions and withstand steady-state thermal and pressure Jo«Hings,
differential expansion stresses, and cyclic thermal stresses. I- addition the
material must be fully weldable and produce sound castings. The . tterial must
also have good creep and rupture strength and be resistant to erosicn and
corrosion. A 12-percent Cr alloy choice ii, typical. The high-pressure shell
or casing must contain the high-pressure steam and resist creep in longtime
•service as well as being resistant to erosion and corrosion. Castability and
weldability are important requirements. Alloy steels are used. Materials
for valve bodies are similar to those used for shells .ind are selected on the
same bases of creep and rupture, weldaoility, stability, and resistance to
erosion and corrosion.
With periodic repair and replacement of some parts, thirty years of
operation can be expected for the turbine. For the buckets, each turbine
stage is analyzed for stresses and frequencies under the specific operating
conditions, and allowable stresses are established frori results of laboratory
testing on creep, rupture, fatigue, and erosion, corrosion resistance, and
experience. Rotors and wheels are sized on the basis of torque, plus centri-
fugal and bending stresses, and are carefully analyzed for critical speeds.
When major parameters are established, they are analyzed in detail for
fillets, grooves, balancing provisions and contours. Each turbine diaphragm
is analyzed for stresses, and the results of extensive laboratory testing are
used to establish the allowable stresses. For the shells, the analysis
starts with a pressure stress calculation and then is refined for thermal
stresses* with stress concentrations taken into account. The design procedure
for valves likewise analyzes for stress concentration points and provides
modifications to account for both steady-state and transient conditions.
The thermal stresses are limited by establishing allowable rates of heating
and cooling.
In the AFB, coal combustion occurs in a bed of limestone which operates
at 1550 F. The materials sheeted for the various temperature ranges within
125
-------
the AFB at 3500 psig are carbon steel for 850 F maximum teraperatue, 1/2 chrome-
1/2 molybdenum alloy steel (12) for °50 F maximum temperature, 2-1/4 chrome
alloy steel (T22) for 980 F maximum temperature in thick sections and 1100 F
in thin sections, and 304 stainless steel (T304) for maximura temperatures of
1200 F. At the reduced pressure of 700 psi for reheater service T22 would be
used for 1075 F maximum and T304 for 1350 F maximum.
Design lifetimes are based on the ASME Power Boiler Code to give an esti-
mated 30-year life. This involves assessment of tensile strength^, yield
strength, creep, and rupture strength. No detailed investigation was made
of corrosion, erosion, or fouling rates, and it was judged that conservative
procedures for selected boiler metals would result in the selection of metals
adequate for the projected life. The rationale was that internal corrosion
was not expected to be a problem and the small amount of external oxidation,
sulfiding, and wastage would be compensated by conservative design. External
fouling was not considered.
These judgnents are based on extensive experimental data on hot corrosion
of boiler tube materials. There is in fact goog reason to belie-c that corro-
sion in fiuidized bed combustion systems for the lower temperature .iteam tubes
will be rrurh less severe than 4.n conventional pulverised-coal-fired units.
However, there may be a serious corrosion problem in the hotter components of
the system. ._. • *"[
The ash particles formed at the relatively low fiuidized bed combustion
temperature are soft and friable compared with the fused ash particles
generated in the high-temperature pulverized coal flames of a conventional
furnace. No erosion has been reported in pilot scale tests of fiuidized bed
combustors so that this does nor appear to present a significant problem.
Fouling on boiler tubes may become a problem, depending on the ash com-
position of the coal, its reaction with the bed sorbent, ana the operating
temperature. If the problem proves to be severe, there may be ways of
reducing it by modifications in operating temperatures or by the use of
fuel additives.
The steam turbine represents a mature technology, and significant
materials problems should not be anticipated. The fiuidized bed system
does, however, have some potential problem areas. The principal one is
hot corrosion, and it will be necessary to run tests for long perioc's with
a variety of coals and tube materif.Is used over a vide range of tempera-
tures for a more complete understanding. There are several options to reduce
hot corrosion, including the development of more corrosion-resistant
materials or the use of coatings.
126
-------
A. PLANT ARRANGEMENT
£lot Plan
T" • ,
The plant arrangement on its \1ut is based on storage of a 60-day supply
of coal and a capacity to hold ash for ]5 days. A series of ponds contain
runoff water from the site and provide for treatment of all water returned
to the North River. The basic plot dimensions are one-half mile by
three-tenths of a mile.
Figure 22 shows the to..al plant area of 108 acres in the small section,
and the main, area in derail. Coal.is received by rail and is unloaded to
two conical storage piles. .The compacted dead storage coal pile is 60 ft
high with a base measuring about 1240 ft by 420 ft. This stores 424,000 tons
of coal for recovery by use of dozer tractors. Two conical live coal storage
piles are provided with a base diameter of about 315 ft. These piles contain
a total of 114,700 tons of coal .with 27,000 ton available by gravity feed
through under-pile vibrating feeders. Limestone is stored in a single storage
pile of 135,000-ton total capacity with 6,7^0 tons available as live feed by
gravity flow to the under-pile vibrating ffliers. These feeders load a conveyor
to the coal cascade. At that point magn tic separators remove tramp iron, ami
oversized coal is diverted to the crushers for size reduction prior to
distributioti. The coal and the limes tor, : are then dried, passed through
grinders, and blended. There are three trains of equipment from the cascade
to the delivery of dried and blende ' feedstock. Any one of the three sets
may be out of service without disaLtin,, i.iie plant. The feedstock is conveyed
to pairs of AFB modules on each side t..: the turbine building. The dry and
cooled spont solids are conveyed to .the 1.5-day ash storage bins at the lower
left for loading on railroad cars. Tl.o 24 cells of wet cooling towers are
set apart from the rest ot" the plant in the upper right corner.
General Arrangement
The arrangement of the four AFB modules about the turbine building
are shown in Figure 23. This arrangement followed a need to keep main
steam lines short in anticipation of use of very high steam temperatures.
The ground elevation view shows the air path through the FD fan and the air
preheater and then around the lower outside of the AFB to the end next to
the turbine building. The 51-ft elevation view shows the path of the i'lue gas
through the ESP, the air preheater, and the induced draft fan, and thence to the
stack.
Plant Elevation
The plant elevation view through the turbine building and one AFB is
presented in Figure 24. The seven-cell stack of fluidized beds stands
]92 ft high. Air is fed upward from the right, and flu.- gas flows downward
on the left side of the AFB module to the cyclone separator. The flue gas
passes through the ESPs, the air heater, and the in fan, and to the stack.
127
-------
fV>
CO
f]=:H]Tm-
FnT^T-y. ..7~1'
15 ~
O
TJ
Figure 22. riot Plan Advanced Steam Cycle — Atmospheric Fluidj.^cd Bed (Bechtel)
-------
vo
•71 (•<'
'• V
r
I i
'I AN At M
pff^",
I
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ri;
*-!
-- 1-- _!= -.
iccim
..^T*~-m* r "•«••>»
ea?|iiii./ I'H'iitf'
Figure 23. General Arrangement Plan Advanced Steam Cycle — Atmospheric
Fluidized Bed (Bechtel)
-------
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iu7| P-
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Figure 24 Electrical Diagram for Atmospheric Fluidized Bed System
-------
Electrical Schematic
A single-line diagram showing major electrical equipment is presented
in Figure 25. The steam turbine-generator feeds two main transformers
at 25 kV, and two unit transformers feeding the 13.8 kV buses. A startup
transformer also may feed the 13.8 kV buses. Major electrical loads are
indicated as well as the subsidiary bus bars and the emergency diesel
generator.
131
-------
A
f. <*.
M**»..«-.f ««
'^~P=
:2i;_-
~1r—~'
f
f
*
r
<
i
t
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tLtV
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id
n ****
' 11107
fAMCTCit »re
w*«w^
P-.I03
MI
1
Figure 25. General Arrangement Ellvation — Advanced Steam
Cycle — Atmospheric Fluidized Bed (Bechtel)
-------
5. SYSTEM PERFORMANCE AND COSTS
Performance
System performance concerns boiler efficiency, prime cycle efficiency,
and the fraction of gross generation commandeered for auxiliary services.
These evaluations are made at the 100 percent operating point and not at
the VWO specification point. Table 43 presents the gross generation, the
auxiliary power losses, and the net power transmitted from the plant. The
auxiliaries are 7.3 percent of trie gross generation. Table 44 gives a
detailed breakdown for the auxiliary losses. Half of these are attributed
to the AFB module services. The FD fan power is four times conventional
values as a result of the added flow path resistances for the fluidized
bed, the distribution grid plate, and the cyclone separators.
Costs-General
Costs were synthesized from major component costs, BOP material costs,
and BOP labor costs. Items made up of numerous smaller components are
presented by enumeration of the total cost and unit count for each of the
subcomponents. An equipment list for, BOP components identifies all major
items. A detailed breakdown of BOP labor man-hours and material costs com-
pletes identification of all material and construction and installation costs.
Thereafter these are combined with major component costs to arrive at total
plant costs.
The steam turbine-generator is purchased at a single price of $27 million.
In contrast, the steam generator comprises four AFB modules, .ijxiliary units
serving each AFB, conveyor and solids equipment serving pairs of AFB modules,
and solids preparation equipment providing three units any two of which can
service the entire plant. Equipment lists for the AFB steam generator system
are presented as Tables 45, 46, and 47.
Major Component Characteristics
Subsystem costs and weights are presented in Table 48 for the steam
turbine-generator and for the AFB modules exclusive of their solids
handling equipment and their ESP.
Table 49 presents the characteristics of the AFB module heat exchange
and pressure containment parts. The 87.92 percent efficiency represents
heat to steam divided by the HHV of all the coal that is fired in the
plant. The average heat flux is high compared to conventional boilers.
However, the peak heat flux is very much less than peak values for conven-
tional boilers. As a result of these conservative values, the AFB heat
exchange surfaces are expected to have a far longer service life than the
hottest parts of conventional furnaces and boilers.
133
-------
Table 43
SYSTEM OUTPUT
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
Total Gross Output (MW - 60 Hz AC)
Total Auxiliary Losses (MW - 60 Hz AC)
Including Transformer Losses
Net Powerplant Output
(MW - 60 Hz AC - 500 kV)
873.66
64.40
814.26
Table 44
AUXILIARY LOSS BREAKDOWN
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
ITEM
Furnace
SA Fans
FD Fans (4)
PA Fans (4)
ID Fans (4)
ESP (8)
Solids Handling
Turbine
Auxiliaries
Major Pumps
Service
Booster
Condensate
Circ. Water
Water Intake
Solids Handling
"Hotel" Loads
Cooling Tower Fans
Transformers
ASSUMPTIONS
24" A P, 0.82 EFF
65" /. P, 0.82 EFF
16" A P, 0.82 EF7
16" A P, 0.78 EFF
0.33% of Gross kW
A/E Estimate
600 PSI, 5.44 Million #, 75% x 90%
185 PSI, 4.86 Million #, 70% x 90%
Proportion to Cooling
Heat Duty
A/E Estimate
Based on Rates and Lifts
A/E Estimate 1% of
Generation
Proportional to Heat Duty
0.5% of Gross Generation
NO. OF
UNITS
4
4
4
4
8
4
TOTAL
MW
0.8
21.1
0.5
5.3
3.3
1.4
32.5
2.9
2
2
2
3
2
1
1
24
4
:ARY
0.9
3.4
1.1
4.7
10.1
1.0
1.9
8.8
2.8
4.4
POWER = 64.4
134
-------
Table 45
SOLIDS HANDLING FOR AFB EQUIPMENT LIST AND COSTS
Subsystems , "'
COAL DRYING & CRUSHING
1 - Dryer System - 189 TPH
1 - Coal Crusher & 2 Screens
1 - Distribution Box
2 - Vibrating Feeders @ 94-1/2 TPH
2 - Surge Bins @ 76000 ft3
2 - Bin Activators
2 - Weigh Belt Feeders
-------
Table 46
HOT GAS AND AIR FOR AFB EQUIPMENT LIST AND COSTS
Subsystems
Cost in Plant Requirement
HOT GAS CLEANUP AND AIR SUPPLY 1975 $ Number MS
4 - Bed Cyclone Units $ 392,391
12 - Cyclone Air Lock Valves 78,000
4 - Fines Injection Systems 260,000
2 - CBC Cyclone Units 73,060
2 - CBC Cyclone Air Lock Valves 25,480
2 - Surge Bins @ Dust Cooler 40,404
2 - Coolers for CBC Dust 260,000
4 - Cooler Air Lock Valves 50,960
4 - Electrostatic Precipitators 2,406,103
2 - Air Preheaters 2,392,621
2 - ID Fans and Motors 881,088
2 - FD Fans and Motors , 964,674
2 - PA Fans and Motors • 90,813
Section Subtotal = $7,915,594 2 15.83
Table 47
TOWER COMPONENTS FOR AFB EQUIPMENT LIST ANT) COSTS
Subsystems Plant Requirement
Items M| Number M$
Heat exchange and pressure parts 5.063
Injector and air parts of AFB 0.781
Control system 0.724
Flues, ducts, insulation, etc. 0.893
7.461 4 29.84
Total for modules without solids handling 4 45.67
Total above without electrostatic percipitator- 4 40.86
136
-------
Table 48
'MAJOR COMPONENT AND SUBSYSTEM WEIGHTS AND COSTS SUMMARY
ADVANCED STEAM-AT.IOSPHERIC FLUIDTZED BED
MAJOR COMPONENT
OR SUBSYSTEM
Prime Cycle
Steam Turbine-Generator
(Generator Alone)
AFB Module
WEIGHT
(FOB)
M LB
COMPONENT OR
SUBSYSTEM
COSTS
(FOB)
MS
OUTPUT
OR
DUTY
COST PER
UNIT
OUTPUT
OR DUTY
COST
PER
LB
6.5
(0.940)
3.54
27.0
10.2
878.66MW 30.73$/kW 4.15$/LB
878.66 MW
500.3 MW
'th
20.39S/kW , 2.88$/LB
th
Table 49
HEAT EXCHANGER CHARACTERISTICS
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
NO. OF
VT EXCHANGER UNITS
AFS Module
VESSEL
SIZE OR
TYPE
76'x33'xl78'
OUTPUT OR
DUTY PER
UNIT
MBtu EFFICIENCY
UNIT UNIT UNIT
SURFACE WEIGHT COST
AREA (FOB) (FOB)
M LB
1707
87.92% 160726 3.54
HEAT
FLUX
AVERAGE
M$ Bcu/(HR FT2)
5.1*
10620
at exchange surfaces and pressure parts only. An adc* :tional $5.1 M is required for other
dule components for a total of $10.2 M per module (see Table 48).
137
-------
Equipment List-Balance of Plant
The BOP equipment and its specifications are listed in Table 50. The
specifications are based on VWO steam turbine flow rates. In addition,
electric motor drives for fans and pumps anticipate a further margin of
10 percent flow, 20 percent pressure rise, and 30 percent power. As a
result, the motors are sized for continuous duty at levels well above the
100 percent plant operating.point.
Capital Costs-Balance of Plant .
Table 51 presents the AE's detailed breakdown of the direct nuinual field
labo*r in thousands of man-hours, and of BOP material costs in thousands of
dollars for each major category of the balance of plant. In using :these data,
an average hourly field labor rate of $11.75 in mid-1975 dollars converts man-
hours to dollars. Where field indirect labor is allocated to individual iter.;s
rather than the total labor for the job, it will be apportioned as 90 percent of
the direct field labor, which is equivalent to $10.58 per hour. .
The seven major categories used by the AE relate to the principal field
labor skills to be applied. A^modified subdivision of costs was.made using
th? following categories: ^
1. Land improvements and structures
;^--
2. Coal handling r,
3. Prime cycle plant equipment
4. Bottoming cycle (not applicable to AFB plant)
5. Electrical plant and instrumentation
Each item or major category in Table 51 has indicated after, its title in
parentheses the appropriate secciid category from the preceding list.
Plant Cost Estimates
The installed costs of major, system components are presented in Table 52.
Those elements related to heat release—th.i coal and solids handling equipment,
the AFB furnace modules, and the ESPs^-represent a total of $100 million. The
steam turbine-generator along with its feedwater heaters and pumps is half
that amount.
The total plant costs using the AE's categories are presented in Table 53.
The home office and fee of 15 percent is applied only to the BOP costs. A
contingency of 20 percent of all prior costs, is applied to cover expected costs
not specifically included in the original estimating process. The tolal plant
cost of $332 million represents $378/kW based on.total generation, or $408/kW
based on net station output.
138
-------
Table 50
BALANCE-OF-PLANT EQUIPMENT LIST
ADVANCED STEAM PLANT, ATMOSPHERIC FLUIDIZED BED
EQPT.
NO.
_,. • '
C-l
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
SERVICE
Coal Conveyor Belt
Limestone Conveyor Belt
Feed Cascade System:
2 Conveyor Belts
•j ti it
12 " "
18 Bucket Elevators
2 Conveyor Belts
3
-------
Table 50 (page 2 of
EQPT.
SO.
C-10
C-ll
C-12
C-13
C-14
C-15
C-16
C-17
C-18
C-19
C-20
C-21
SERVICE.
Ash Residue Removal System:
2 Conveyor Belts
1 " Belt
Six Vibrating Feeders ~
for Car Unloading
Coal Belt Scale
Coal and Limestone Sampling
System
Coal Lump Crusher (3 req'd)
Limestone Lump Crusher
(3 req'd)
DESCRTPTtON
24 in wide, 600 f'flcng, 64 tph
36 in " 1840 ft " 12S "
" » 420 ft . * " " "
Rating 0-750 tph
0-300t) tph, 60 in Belt
0-3-000 tph, 60 in Belt
tph, 10 in Lumps
0-10 tph, 10 in Lumps
Magnetic Coal Cleaner (3 req'd) 500 tph
125 tph
Magnetic Limestone Cleaner
(3 req'd)
Coal and Limestone Dust
Control System
C0? Fire Protection Systen
Vibrating Feeders for
Limestone Pile (4 req'd)
Vibrating Feeders for
Coal Piles (8 req'd)
C-22 Ash Storage Silos (6 req'd)
C-23 Eight Coal Silos
C-24 Two LimestonejSilos 0
4-6000 cfra Bag Type Dust Collector
Adequate to Service Item C-1S
Bag-house
0-100 tph
0-200 tph
Total Volume 2,206,300 ft
80 ft dia x 75 ft high
375 ton each
325 ton each
140
-------
Table 50 (page 3 of 4)
EQPT.
NO.
SERVICE DESCRIPTION
2. Electrical Svstems
E-l Main Transformers (2 req'd) 470 MVA, FOA 65°C, 24/500 kV, 30, 60 Hz
E-2 Unit Auxiliary Transformers
E-3 Emergency Diesel Generator
E-4 Start-up Transformer
E-5 Miscellaneous 480 V
LCC Transformers
(17 req'd)
E-6 4.16 kV Boiler Auxiliary
Transformers (2 req'd)
E-7 4.16 kV LCC Transformers
(2 req'd)
27/36/45 MVA, 65°C, OA/FA/FOA, 24/13.8 kV,
30, 60 Hz
1000 kW, 30, 60 Hz, 480 V, 0.8 PF
20/26.5/33 MVA, OA/FA/FOA, 65°C,
500/13.8 kV, 30, 60 Hz
1680 kVA, OA, 65°C, 13.8 kV/4fiOV/277V,
30, 60 Hz
4000 kVA, OA, 65°C, 13.8/4.16 kV,
30, 60 Hz
5500 kVA, OA, 65°C, 13.8/4.16 kV,
30, 60 Hz
3. Main Fluid Svptems
F-l
Main Condenser
F-2 Piping:
Circulating Water
Main Steam
Boiler Feedwater
Cold Reheat
Hot Reheat
4.05 x 10 ft heat exchange surface.
Design conditions, 2.3 in Hg, 106°F,
3.58 x 10 Ib/hr. Two shells; each
25 ft wide, 20 ft high, and 40 ft long
with 40,500 1-in tub s: straight-
through, single pass u •'sign, range of
circulating water = 30.7 v.
I.D. « 130 in
I.D. = 7.5 in, tra = 1.95 in
I.D. = 13.0 in, tm = 1.3 in
I.D. = 13.0 in, tm = 0.345 in
I.D. « 16.0 in, tm = 0.18 in
141
-------
Table 50 (page 4 of A)
EQPT.
NO.
F-3
SERVICE
DESCRIPTION
F-4
F-5
F-6
F-7
F-8
F-9
Feedwater Heaters
LP #1
LP 92
LP #3
LP #4
LP
H.P.
DFT
Shell
Press. /Temp.
psia/8F
5/163
11/195
20/228
'. 67/300
296/416
745/510 ,
6.04 x 10
Tube.
Press. /Temp.
psia/°F
210/158
210/190
210/223
210/295
1040/416
5700/519
Ib/hr,
-------
Table 51 (page 1 of 7)
BALANCE-OF-PLANT ESTIMATE DETAIL
ADVANCED STEAM PLANT, ATMOSPHERIC FLUIDIZED BED
Direct Manual
Field Labor
MH 1000's
Balance of
Plant Material
$ 1000's
14) AFB STEAM GENERATORS (3)
1.1 Steam Generator Erection
- Evect only (supply by others):
includes heat transfer surface, and
pressure parts; buckstays; braces and
hangers; attached flue and duct; ^
fluid bed components; control equip-
ment and valves; miscellaneous piping
and small valves; insulation for^above
- Supply and erect:
includes support steel for abov'e;
access steel; miscellaneous materials
and labor'operations
1.2 Steam Generator Auxiliaries
- Erect only (supply by others):
includes P.A. fans; F.D. fans; T.D.
fans; air preheators; coal and lime-
stone feed tables; pipes and air lock
valves
— Supply and erect:
includes external flue and duct; sup-
port steel for ductwork; insulation
for external ductwork
1.3 Stack Gas Cleanup:
Erect only (supply by others):
includes cyclones and electrostatic
precipitators
- Supply and erect:
includes support steel for cyclones
and precipitators
NOTE: ( ) Indicates NASA categories; seo Section 3
143
343
158
3,020
70
100
198
2,570
82
14
610
865
6,300
-------
Table 51 (page 2 of 7)
2.0 TURBINE GENERATOR (3)
Install only (supply by others):
includes 883 MWe steam turbine;
generator; exciter; auxiliary equip-
ment; integral steara and auxiliary
piping; insulation; miscellaneous
labor operations
Direct Manual Balance of
Field Labor Plant Material
MH 1000's S 1000's
130
100
3.0 PROCESS MECHANICAL EQUIPMENT (3)
t
3.1 Boiler Feedwater Pumps
Supply and install: • 10
includes turbine-driven main feedwater
pumps and drivers (3 (3 $940,000 ea.);
feedwater booster pumps and motors
(2 @ $125,000 ea.)
3.2 Main Circ. Water Pumps (3)
Supply and install: 3
includes main circ. water pumps
and motors (3
-------
Table 51 (page 3 of 7)
Direct Manual
Field Labor
MH lOOQ's
3.6 Stacks and Accessories (3)
Supply and erect: 110
includes concrete stacks and liners;
lights and marker painting; hoists
and platforms; stack foundations
3.7 Turbine Hall Crane (1)
Supply and erect: 3
includes crane and accessories
3.8 Coal Handling (2)
Erect only (supply by others): 22
includes coal dryers (3); support
and access steel f"r dryers; coal
grinders (3); screens at grinders
Supply and erect: 73
includes railcar dumping equipment; dust
collectors; primary crushing equipment;
belt scale; sampling station; magnetic
cleaners, mobile equipment; conveyors to
pile; reclaiming feeders; conveyors to
cascade; coal cascade; conveyors and
bucket elevators to dryers and grinders;
recirculating conveyors at grinders;
conveyors to blenders
3.9 Limestone Handling (2)
Erect only (supply by others): 11
includes limestone dryers (3);
support and access steel for dryers;
litnastone grinders (3); screens at
grinders; limestone surge bins at
AFB modules
- Supply and erect: 45
includes magnetic cleaners; conveyor to
limestone pile; reclaiming feeders; con-
veyers to cascade; limestone cascade;
conveyors and b-jcket elevators to dryers
and grinders; recirculating conveyors at
grinders; conveyors to blenders; pneumatic
transport feeders, hoppers, blowers and
piping to AFB modules
Balance of
Plant Material
$ 1000's
1,700
420
10
5,700
10
1,160
-------
Table 51 (page 4 of 7)
Direct Manual Balance if
Field Labor Plant Material
MH lOOO's $ 1000's
3.10 Coal and Limestone Blend Handling (2)
Erect only (supply by others):
includes blenders (3); surge bins;
*• bin unloaders and feeders
- Supply and erect:
includes conveyors and bucket elevators
to AFB modules
3.11 Spent Solids Handling (2)
..' .&
- Erect only (supply by others):
includes high temperature vibrating
feeders and conveyor to solids cooler;
solids cooler
Supply and erect: "*"'
includes fly ash handling system for
precipitators and air preheater; solids
cooler accessories and bucket elevator;
ash conveyors; ash storage silos (6) with.
feeders, unloaders and foundations; railcar
loading equipment
3.12 Cooling Towers (3)
Supply and erect:
includes mechanical draft towers with
fans and motors
3.13 Other Mechanical Equipment (3)
- Supply and install:
includes water treatment and chemical
injection; air compressors and auxiliaries;
fuel oil ignition and warm-up; screenwell;
miscellaneous plant equipment; equipment
insulation
13
93
63
30
10
920
10
4,480
2,680
1,720
29,400
146
-------
Table 51 (page 5 of 7)
Direct Manual Balance of
Field Labor Plant Material
' ' __Mti lOOO's $ IQOO's
4.0 ELECTRICAL (5)
4.1 Main Transformers 4 2,030
4.2 Other Transformers and Main Bus 15 1,160
- includes startup transformer; station
service transformers; generator main bus
4.3 Switchgear and Control Centers 37 3.020
- includes switchgear and load centers;
motor control centers; local control
stations; distribution panels, relay
and meter boards : ." '.
4.4 Other Electrical Equipment 428 2,400
- includes communications, grounding;
cathodic and freeze protection; lighting;
preoperational testing
4.5 Auxiliary Diesel Generator 2 110
includes diesel generator, batteries
and associated d.c. equipment
4.6 Conduit, Cable Trays, Wire and Cable 564
1,050
5.0 CIVIL AND STRUCTURAL
5.1 Concrete Substructures and
Foundations (1) 350 2,890
includes turbine building substructure;
"AFB base mats; coal, limestone and ash
handling foundations, pits and tunnels;
miscellaneous equipment foundations;
auxiliary buildings substructures;
miscellaneous concrete
147
-------
Table 51 (page 6 of 7)
Direct Manual Balance of
Field Labor Plant ftaterial
HH lOOO's $ 1000's
5.2 Superstructures (1)
- includes turbine building; auxiliary
yard buildings
5.3 Earthwork (1)
- includes building excavations; coal,
limestone and ash handling excavations;
circ. water system excavations; AFB
foundation excavations; miscellaneous
foundation excavations; dewatering and
piling
5.4 Cooling Tower Basin and Circ. Water
System (3)
- includes circ* water pumps pads, riser
and concrete envelope for pipe; cooling
tower basin; circ. water pipe; cooling
tcwcr miscellaneous steel and fire
protection
5.5 AFB Boiler Enclosures (1)
- includes structural steel; noninsulated
walls and roofing; building services;
elevators
230
135
6,540
300
115
1,800
55
2,170 '
885
13,700
6.0 PROCESS PIPING AND INSTRUMENTATION
6.1 Steam and Feedwater Piping (3) 55
includes main steam; extraction steam;
hot reheat; cold reheat; feedwater and
condensate large piping, valves and
fittings
6.2 Other Large Piping (3) 165
includes auxiliary steam; process
water; auxiliary systems
2,680
2,670
148
-------
Table 51 (page 7 of 7)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ lOOO's
6.3 Small Piping (3) 85 760
includes all piping, v.alves and
fittings of 2-inch diameter and less
6.4 Hangers and Misc. Labor Operations (3) 245 920
- includes all hangers and supports;
material handling; scaffolding; misc.
labor operations L. • •
6.5 Pipe Insulation (3) 40
6.6 Instrumentation and Controls (5) 115
750 '
7.0 YARDWORK AND MISCELLANEOUS (1)
7.1 Site Prepatation and Improvements 38 , 10
- includes soil testing; clearing and
grubbing; rough grading; finish
grading; landscaping
7.2 Site Utilities 5 50
includes storm and sanitary sewers;
nonprocess service water
7.3 Roads and Railroads 27 750
includes railroad spur; roads, walks
and parking areas
7.4 Yard Fire Protection, Fences, and Gates 52 600
7.5 Water Treatment Ponds 12 ' 10
includes earthwork; compacted-clay
lining; offsite pipeline
7.6 Lab, Machine Shop and Office Equipment 1 280
0, e> 135 1,700
149
-------
table 52
MAJOR COIfPONENT AND SUBSYSTEM CAPITAL COST SUMMARY
ADVANCED STEAM-ATMOSPHbRlC FLUIDIZED BED
MAJOR COMPONENT OR SUBSYSTEM
Fuel Handling & Preparation
Coal and Solids Handling
Prime Cycle
Steam Turbine-Generator
AFB Furnace Modules
Electrostatic Precipitators
Cooling Towers
Pumps, Heat Exchangers, Stacks
Piping, etc.
COST/UNIT
NO. OF (FOB)
UNITS M$
3/2
COMPONENT OR
SUBSYSTEM
COSTS BOP
(FOB) -MATERIALS
M$ MS
9.45
13.10
SITE
LABOR TOTAL
(DIRECT + INSTALLED
INDIRECT) COST
MS
5.96
M$
28.51
1
4
8
--
—
—
27.0
10.216
1.203
—
—
—
2 7.'00 •
40.815
4.81
—
—
—
0.10
5.69
0.61
4.48
11.48
9.18
2.90
17.17
2.14
3.97
3.62
11.84
30.00
63.72
7.56
8.45
15.10
23.02
-------
Table 53
BALANCE OF PLANT CAPITAL COST BREAKDOWN
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
COSTS (MILLIONS OF DOLLARS)
CATEGORIES
1.0 Steam Generators
2.0 Turbine Generator
3.0 Process Mechanical Equipment
4.0 Electrical
M
M 5.0 Civil and Structural
6.0 Process Piping and Instrumentation
7.0 Yardwork and Miscellaneous
COMPONENTS LABOR (1) FIELD (2) MATERIALS (3)
45.68 10.16 9.15 6.30
27.00 1.53
9.45 6.17
12.34
10.40
8.28
1.59
82.13 50.47
BOP Labor, Materials
(Sum of 1 + 2 + 3)
A/E Home Office & Fee
Total Plant r^st
Contingency 0 20%
Total Capital Cost
1.37
5.55
11.10
9.36
7.46
1.43
45.42
& Indlrects
0 15S
0.10
29.40
12.30
13.70
10.10
1.70
73.60
169.49
TOTAL
71.29
30.00
50.57
35.74
33.46
?5.84
4.72
251.62
25.42
277.04
55.41
332.45
-------
A reallocation of costs according to equipment functions is presented in
Table 54. Items 1 through 6 include everyj-hing in the preceding table. Item
7 adds the value or escalation and interest during the 5.5-year construction
time. This item is 55 percent of the prior total. The result is a final
plant cost of $586/kW of total generation or $632/kW of net station output.
152
-------
Table 54
PLANT CAPITAL COST ESTIMATE SUMMARY (APPROXIMATE DISTRIBUTION)
ADVANCED TTEAM CY^LE-ATMOSPHERIC FLUIDlZED BED
1.0 Land Improvements & Structures
(Land, Plant Area 108 Acres)
(Land, 30-year Dispoal 0 Acres)
2.0 Coal Handling
3.0 Prime Cycle Plant Equipment
Steam Cycle Atmospheric Fluidized Bed
878.7 MW
e
4.0 Bottom Cycle not Applicable
5.0 ^Electrical Plant & Instrumentation
Subtotal
6.0 A-E Service & Contingenty
7.0 Escalation & Interest during
Construction
MAJOR
COMPONENTS
M$
0
9.5
72.7
0.
82.2
BOP SITE LABOR
MATERIALS (DIRKCf & INDIRECT)
M$ M$
14.0 * 20.3
13.1 6.0
31.5 43.6
14.9 26.0
73.5 95.9
Total M$
Plant Output MW
Total $/kW
TOTAL
M$
34.3
28.6
147.9
40.9
251.7
80.8
182.2
514.7
814.3
632.0
-------
6. NATURAL RESOURCES & ENVIRONMENTAL INTRUSIONS
The natural resourced required for this plant are presented in. Table 55.
Total water withdrawal vould be 0.6! gal/kWh,; with 0.16/ga.l/kWh i-eturned from
cooling Cower b^wdown and plant' general use after appropriate waiter treatment.
The coaJ urage r>lates directly to bc.il efficiency, steam turbine cycle
efficiency, and cho proportion of generated power diverted for auxiliary
requirements. The-coal usage ;ould be less, and the plant could be marie
more efficient if the constraint to produce electricity at the least cost
was removed.
The environmental intrusions are enumerated in Table 56. The sulfur
*• emissions assumad by GE are comfortably under the current limit, while the
nitrogen oxide emissions are less than half the current standard. The major
heat rejection is from the cooling tower. The total heat- rejected includes
the stack loss, loss from hot spent solids, and in-plant thermal, energy from •
motors and other auxiliaries.
The spent solids contain appreciable amounts of unreacted lime as a ••
result of 100 percent excess of limestone *feed and the 15 percent of sul-
fur that is not reacted. There are economic incentives to consider on-site(
recycling of the spent solids to separate the sulfur and recycle the lime.
if-
Sensitivity to Emissions Target.i
The estimated emissions from the atmospheric fluid bed are within existing
EPA New Source Performance Standard limitations for conventional coal-fired
boilers.
One of the features expected for fluid bed combustion is verv low. wulf-v<-
trioxid* generation. Coal end corrosion problems due to sulfur trioxide
severely limit conventional furnace design and operation. The A^B po*.'er plr.nt
and its neighbors should experience reduced probability of acid rain and other
aggravations associated with conventional power planns.
Trace Element. Emissions
The experimental work needed to determine the .evels of trace element
emissions from an AFB power plant has not '.en mr.-.crV ~. to datn. Only
qualitative comparisons to conventional \. -er plants i in •;<> mad.\. The
critical factors are main bed temperature of 1550 7, the t.a.-bon burnnp cell
temperature of 2000 r, the absorbency of the porous dry soliJs of the bed
material, and the low solid fly ash emissions level of 0.1 lo/MBtu.
:h; a;h in the Illinois No. 6 coal is 8.9 percent. Therefore, trace
elements in the coal that remain with the ash would be found at a concentra-
tion in the ash approximately ten times that in the coal, if all the ele-
ments recalii in the ash. The coal feed rate is 1000 times the participate
emission rate from the stack. The total .solids discharged include ash, calciua
sulfate, and unreacted lime. The ash is 29 percent of the total solids dis-
charged and is 100«fcimes the %tack gas particulate emissions.
154
-------
Table 55
NATURAL RESOURCE REQUIREMENTS
ADVANCED STEAM CYCLE-ATMOSPHE.IIC FLUIDIZED BED
t, Limestone Ib/kWh
Co«>l, Ib/kWh
Water, Total (Gal/kWh)
Cooling
Evaporation
Slowdown
Plant General Use
Condensate Makeup
Total Land, .Acres/100 MW
Main. Plant
Disposal Land
VALUE
0.2272
. 8339
0.453
0.14
0.018
0
12.84
15
155
-------
Table 56
ENVIRONMENTAL INTRUSION
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
EMISSIONS
S°x
NO
x
HC
CO
Partieulates
LB/MBtu
INPUT
1.028*
0.270**
0.040
0.099
LB/kWh
OUTPUT
0.0098
0.00258
0.00038
0.00094
THERMAL POLLUTION
Heat, Rejected Cooling Towers, Btu/kWh
Heat, Rejected Stack, Btu/kWh
Heat, Rejected Total, 3tu/kWh
4794
994
5946
WASTES
Spent Solids Congolomerate
42% Calcium Sulfate
31% Ash
24» Unreaeted Lime
3% Carbon
Water Discharge
LB/kVh
0.292
1.32
M LB/DAY
5.70
25.8
*Based upon- available data, EPA believes that li.nestone would have to be
injected into the AFB at a Ca/S ratio of 2.5 to 3-5 to routinely achieve
this emission level, rather than the ratio of 2 used in this study.
**Based upon available data, EPA believes that the NO* emissions level will
more typically be in the range of 0.3-0.6 Ib/MBtu.
156
-------
The trace element concentrations in Illinois No. 6 coal are indicated
in Table 58. The three categories relate to the manner of their discharge
when fired in a slagging cyclone burner in a conventional furnace and
boiler. It is projected that in the AFB, the Group I trace elements will
not volatilize and will maintain their original proportion to the discharge
ash content. This would be a ten-fold concentration in ash when the coal
combustibles are removed. The upper limit en stack emission would be at a
rate one one-thousandth of their rate of introduction in the coal.
The volatile elements in Group III will likely be volatilized in the
AFB bed. Some of these may escape through the stack as gases, but much are
likely to be captured or to escape as particulates formed by condensation
in the 250 F stack (Hg) or by reaction (HgO, CaF).
The elements in Group II cannot be assigned a cistinct trajectory until
appropriate tests are made on.AFBs. The low and uniform main bed temperature
of 1550 F is below the slagging temperature. The carbon burnup cell at 2000 F
borders on the. slagging temperature range. However, the fluidized beds must
operate below slagging temperature to avoid agglomeration of-the particles In
the bed. It is probable that the least volatile elements like nickel will
react as if they were in Group I. Those elements that may partially tend to
volatilize will do so in the presence of extensive dry porous granular mate-
rial which tends to absorb volatiles that^are near their dew point temperatures.
Since the most porous material with the greatest surface area is the sonbent
and the fly ash, a selectively larger concentration should occur in spent'
sorbent and fly ash. In addition the cooling to 730 F as the gas stream
flows over the convection surfaces will result in these volatiles condensing
in the fly ash. As a result some elements in Group II may be expected to be
found in the particulate emissions in concentrations far greater than their
proportion to the ash in the coal.
157
-------
Table 58
TRACE ELEMENT CONCENTRATIONS IN ILLINOIS NO. 6 COAL*
Concentration
(ppm)
Group I.. Not volatilized during
combustion
Mn 6-181
Be 0.5-4
Group II. Volatilize at slagginR temperature
but condense on fly ash
Pb . 4-218
Sb . 0.22-8.9
Cd 0.1-65
As 1.7-93
Ni , - 8-68
Cr 4-54
Zn 10-5350
Cn 5-44
V 16-78
Group III, Volatilize and escape
as gases
HR 0.03-1.6
F 30-167
Cl 100-5400
*Grouping selected based upon trace elements emission data from a
conventional cyclone-fired coal furnace.
158
-------
7. SUMMARY PERFORMANCE AND COST
Table 59 conveniently summarizes the system performance and cost
effects. The plant overall efficiency is lower than the prime cycle
thermodynamic efficiency because of the boiler efficiency of 0.8792 and
the ratio of net station output to generation of 0.927.
Capital accounts for two-thirds the cost of electricity (COE) for a
station capacity factor of 0.65 and fuel cost accounts for under one-third.
Historically, these two components of cost have been equal.. The current
ratios favor low-cost power plants and penalize high efficiency and high
capital cost plants.
Table 60 indicates the sensitivity of the COE to changes in the base
rates of the factors that dominate electricity generating costs.
159
-------
Table 59
SUMMARY PERFOratANCE AND COST
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
ITEM
Net Power Plant Output (MW - 60 Hz - 500 kV)
Thermodynamic Efficiency (%)
Power Plant Efficiency (%)
Overall Energy Efficiency (%)
Coal Consumption (LB/kWh)
Total Wastes (LB/kWh) '
Plant Capital Cost ($ Million)-
Plant Capital Cost ($/kW )
Cost of Electricity, Capacity Factor = 0.65
Capital
Fuel
Maintenance & Operation
Total
Estimated Time of Construction (Years)
Approximate Date of First Commercial Service
(MIILS/kWh)
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)
814.3
A3.9
35.8
35.8
.0.88A
0.292
5U.6
632.0
20.0
9.5
2.2
31.7
5.5
1984 - 1986
160
-------
Table 60
COST OF ELECTRICITY (COE) SENSITIVITY
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
BASE
CAPACITY
FACTOR
COE, Capital
COE, Fuel
COE, O&M
TOTAL COE
0.
20.
9.
2.
31.
65
0
5
2
7
FUEL
COST
INCREASE
50%
20.
14.
2.
36.
0
3
2.
5
LABOR
COST
INCREASE
20%
21.
9.
2.
33,.
6
5
2
3
MATERIALS
INCREASE
CAPACITY
FACTOR
CHANGE
20%
22.
9.
2.
34.
4
5
2
1
26
9
2
37
0.5 & 0.8
.0
.5
.4
.9
16.2
9.5
2.2
27.9
161
-------
D. PRESSURIZED FLUIDIZED BEE POWER PLANT
1. INTRODUCTION
The advanced steam cycle power plant with pressurized fluldized beds
(FFBs) performs the functions of combustion, steam generation, and sulfur
capture in four modular PFBs that use gas turbines to achieve a substantial
supercharged pressure level. A simplified cycle schematic, Figure 26, indi-
cates the arrangement of the major equipment. The gas leaving the ?FB must
be highly filtered before its expansion through the gas turbine. The gas
turbine exhaust must be cooled in economizers to utilize its thermal poten-
tial fully. This feature substitutes in part, or fully, for the high-
pressure feedwater heaters of the steam turbine cycle. The steam turbine
and the heat rejection equipment are exactly comparable to units selected
for the atmospheric fluidized bed (AFB) plant evaluation.
The system parameters are presented in Table 61. The Illinois No. 6
coal contains 3.9 percent sulfur. Eighty-three percent of the sulfur must
be captured to meet the environmental emission limit of 1.2 Ib/MBtu of fuel
hf>at release. The capture medium is dolomite fed into each of the six main
fluldized beds at twice the rate that would ideally capture all of the sulfur.
The 1650 F main bed operating temperature was selected to maximize sulfur
capture at 90 percent of that present in the coal.
Unburned carbon is conveyed from the main beds in the fly ash of the
gas stream and in the solids tapped from each bed. Tb^ 95 percent of the
fly ash recovered in the cyclone separators and the tapped solids from the
main beds are recycled to a carbon burnup cell (CBC), where a higher tem-
perature of 2000 F and increased excess air of 30 percent produce a substantial
burnup of residual combustibles. The net result is both a high combustion
efficiency and a high sulfur capture effectiveness.
The pressurizing gas turbine sets provide a supercharge level of 10
for the PFB. The inlet temperature of 1600 F is modest for contemporary
gas turbines.
The steam conditions are conventional and correspond to chose used for
the AFB. The steam cycle has a low final feedwater tempera-ture of 254 F
to match the economizer outlet gas temperature of 300 F. Only three feedwater
heaters are used.
The net power from ,-.he plant would be 904 MW representing 39.2 percent
of the higher heating value (HHV) of the coal fired. The steam turbine
produces 78 percent of the power and the four gas turbines 22 percent.
Preceding page blank
163
-------
Coal Dolomite
_] L
Solids Handling
Spent Solids
Handling
L
Air-
•/ Stacks
Gas Turbines
Figure 26. Simplified Schematic Diagram for Advanced
Steam Cycle-—Pressurized Pluidized Bed
-------
Table 61
SYSTEM PARAMETERS
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
PARAMETER
VALUE OR DESCRIPTION
FUEL
ILLINOIS NO. 6 COAL
DOLOMITE
10788 Btu/LB HIGHER HEATING VALUI
$1/MILLION Btu
SULFUR CAPTURE MEDIUM
0.45 LB/LB COAL
•FURNACE
PRESSURIZED FLUIDIZED BED - COHBUSTOR AND STEAM GENERATORS (4 MODULES)
MAIN BEDS (6 PER MODULE)
CARBON BUttNUP BED (1 PER MODULE) ' .
GAS TURBINE
EXHAUST GAS
PRIME CYCLE - STEAM PLANT
WORRIES FLUID
TURBINE INLET
REHEAT
CONDENSER
FINAL' FEEDWATER
HEAT EXCHANGERS
GAS TURBINE EXHAUST
ECONOMIZER
HEAT REJECTION
1650 F. COAL AND DOLOMITE, 20% XS AIR
2000 F. FLY ASH AND SOLIDS DRAIN, 30% XS AIR
1600 F INLET. 10 PRESSURE RATIO
ECONOMIZER HEAT TO FEEDWATER
STEAM .
3500 psi, 1000 F
676 psi, 1000 F
2.3" Hga, 106 F
4378 psi, 254 F
GAS 850 F IN/300 F OUT
WATER 533 F OUT/254 F IN
WET MECHANICAL DRAFT COOLING TOWERS 22 CELLS
STACK GAS TEMPERATURE 300 F
165
-------
2. CYCLE DESCRIPTION
A more detailed plant schematic is presented in Figure 27. State points
and stream flows are shown in which the enthalpy values are referenced to
32 F water for steam and water, and to an 80 F zero references for air, com-
bustion gases, and solids. This power plant uses four PFB boiler modules to
convert the energy from high sulfur coal into steam for a conventional 3515
psia/1000 F/1000 F steam turbine cycle with single reheat of steara. One tardera
compound four-flow steam turbine-generator produces 738.63 MV gros? electric
energy output. Incorporated with each PFB boiler is an open cycle gas turbine
that supplies the air from its compressor to the PFB boiler. Thjs pressurized
air stream fluidizes the bed and reacts with injected coal to develop the heat
for steam generation. The resulting hot gases return to the turbine for expan-
sion to atmospneric pressure. This expansion in the turbine develops sufficient
shaft power to drive the compressor and an electric power generator that also
delivers 51.25 MW gross electric energy output. Thus, the combined plant output
from the steam turbine-generator and four gas turbine-generators is 943.63 MW
gross.
The regenerative feedwater heating cycle has two low-pressure feedwater
heaters, a deaerator, and a high-pressure feedwater economizer that extracts
heat from the gas turbine exhaust gases. A portion of the exhaust steam
from the intermediate pressure turbine is extracted for powering con-
densing steam turbines that drive the boiler feedpumps. All other najor
pumps are driven with Rlectric motors.
The sulfur present in the coal combines with dolomite injected into the
PFB boilers with the coal to form calcium sulfate, which is removed along
with coal ash and dolomite residue from the PFB boilers. Hot gases from the
PFB boilero are cleaned in cyclone separators followed by granular bed fil-
ters. After the particulates in the flue gas are filtered and the energy
from the ho;, gases recovered in the gas turbine ano! the economizer, the flue
gas at 300 F is discharged to the atmosphere. The clean flue gas will meet
the national standards for emissions from new coal-fired power plants.
Pressurized Fluidized Beds
The feedwater to each PFB would be at 533 F after being heated in the gas
turbine exhaust economizer. Within the PFB unit this water is heated to steam
turbine throttle conditions of 3500 psig, 1000 F. After expansion in the high
pressure turbine, the steam returns to the PFB at 767 psia, 604 F to be reheated
to 1000 F. There are six main beds and one carbon burnup cell in each PFB
pressure container or module. The heat exchange surfaces are mainly submerged
in the fluidiztd bed and its containing waterwalls. Convection surfaces are
not used since the intent is to provide a high gas turbine inlet temperature of
1600 F in conjunction with high temperatures of 1650 F in the main fluidized
beds. The CBC operates at 2000 F, using recycled solids from the main bed taps
and from the cyclone separators.
166
-------
1850 F MAINBEDS
I Stebfl> Turbine-Gtnerotor Set
Tondem Compound Four Flow, 33.5" Ust Slog* Bucktt
'Hotel* Load 8.3 M*
TronsformtrU»*4.7UW
Solids Handling
2.2UW
4 Modules ol
PFB.Goi
Tin Sines,
Economizers
Steom Turbine Au« 2.4 MW
Cos Turbine Aui. 2.2 MW
mCondensate
^ Pump
IMW
15.42/850/8.224/204.5
4200/533/4.281/526
.4393/254/4.281/231
Spent Solids
250 F
0.310*
4lh
General™ 9 4 3,630 KW
Auxiliaries 39,860 KW
Net Station 903,770 KW
Note
Makeup ond Service Pumps
1.8 MW
Prtssurt ( psia) / Temperature i'F 1 / Flo« Rote 1 1 w'i.b/hrl / tntholpn I8»u/l b I
Boiler
Feed , ^
Pimpll! 0 ©
106'.GH
» Flo» WUI.on Pounds Per. How
.r H, tnlholpy Btr Per Pound t
Figure 27. Schematic Diagram of Advanced Steam Cycle - Pressurized
Fluidized Bed (1650 F Main Beds)
-------
Gas Turbine Air Supply
Each gas turbine i's of a basic conventional design using a pressure
ratio of 10. A fraction of the delivered air from the compressor is
pressurized an additional 100 psi in the Petrocarb air compressor (PAG) to
convey the coal and dolomite into the main beds through the injection feed
pipes. The cooling '••>•• the PAC heats air for coal and dolomite drying along
with heat reclaimed from the spent solids cooler. The bulk of the air supply
goes directly to the PFB unit. In addition 22 MBtu/hr are added to boiler
feedwater in the portion of the PAC cooler serving as an economizer.
The gas from the PFB contains fly ash particulates. Cyclone separators
remove 95 percent of this solid burden. Tnen the fine filters remove the
rest to the level of cleanliness required for gas turbine durability. The
fine filters are granular bed units that are periodically backflushed vitli
fluidizing air to purge them of accumulated solids.
The inlet flue gas to the turbine is at 1600 F and 138 psia, a loss of
7.5 psi relative to the compressor discharge. The 350 F turbine exhaust serves
a heat recovery ecorioinizer in the steam cycle, producing 300 F stack gas.
Spent Solids System
The CBC solids tap and the cyclone filter tap for the CBC and the solids
and carryover sand from the granular fine filter purge are accumulated in
the solids cooler. Their temperature is reduced to 250 F while producing
790 F air for drying feedstock. These spent solids comprise 42 percent ash,
26 percent calcium sulfate,. 13 percent unreacted lime, 16 percent magnasiuia
oxide and 4 percent unburned carbon.
Coal and Dolomite Systems
Hot air for drying is drawn through the active dryers and then the feed
storage silos. Coal and dolomite are crushed to size and then pressurized
for distribution and injection using the Petrocarb high pressure solids
injection s/stera. Recycled fly ash and tapped solids art- fed to the CBC by
a combined gravity and air assisted transport.
Overview
The overall system for using PFBs achieves sulfur capture during com-
bustion, and a high combustion efficiency by recycle of air-borne solids
containing unburned carbon. The four self-contained modules of PFB and gas
turbine assure that only one-quarter of capacity would be lost during out-
ages of a single module. The plant aggregates 944 MW of generation, of
which 22 percent is from gas turbines. The net station output would be
904 MW.
168
-------
3. MAJOR CYCLE COMPONENTS
The usual spe.cificaticn for steam pqwer plants add a 5 percent margin
of flow and capacity to every major corapon*:u. Sucir an approach would .upset
the close integral ..on cf the many components of a PFB system. To assure per-
fect etching of ail pieces of the system, the fuel and air and heat absorp-
tion Oil the PFB were fixed as the common parameters for the gas turbine,
compressor, PfB module, and .s*u>.on turbine heat supply. The phyVcal tize
limitation on the PFB tower cics-ely r.atjhed the airflow rate for current gas
turbines. From these considerations the sir for combustion, fuel for com-
bustion, dolomite rate, and gas flow ' .> tr.fi £as turbine were fixed. The
coal rat.^ so established -was 1.4 percent. BT'er.ter than the coal rate for the
AFJ3 plane at its 100-percent rating p.:>ins ,
The design and performance details nf the PFB modules, the pressurizing
gas turbine and economizer, and the sterr.a turbine-generato-?. are considered
in this section on major components. All remaining equipment would be speci-
fied and supplied as balance-of-plant (BOP) materials. Equipment lists for
all items are provided in a subseqveTiC section, "System Performance and
Cost."
Heat Input System-PFB
»~
The PFB heat input major components comprise the PFB tower module-, the
solids handling for coal, '-dolomite, and spent solids, fie hot gas filtering
system, the fuel and dolomite^ inject ion systems, and the ;;:ir; turh'-ne ;y* ' •• ft '
supply with its exhaust heat economizer. Conceptually the -functions e're
similar to those described for the AFB. The solids handling requires; lock
' hoppers to pressurize the feed solids and to depressurize the spent solids.
The hot gas filtration requires :wo stages of cyclone f iltfers followed by
the fine granular bed filter. The PFB beds operate in an alkaline environ-
mant at low-temperature levels relative to conventional boilers and at a
very low sulfuric acid dewpoint. The ash products are soft and dry and will
not adhere to heat transfer surfaces. As a result of these favorable con-
ditions, no coal ash corrosion problems within the PFB beds are expected.
Emissions of sulfur dioxide will be under the current limits as a result of
the 90 percent sulfur capture in the main beds. Nitrogen oxide emissions
will be one-third the current limits; practically all ninrogen oxides result
from fuel-bound nitrogen since the low bed temperatures form very little
thermal NOX. The effect on gas turbine nozzle and burket life will be an
important determination for pilot and demonstration units. The flow of mate-
rials and the temperature levels throughout one" PFB module are presented in
the process flow schematic, Figure 28. The interior arrangement of the PFB
tower module is shown in Figure 29. The identity of each heat exchange
element i? shown in that figure, and the Jetailed heat exchange and tempera-
tures appear on the heat absorption layout in Figure 30. Table 62 presents
the resulting surface requirements and selected cubing to satisfy the
requirements for each PFB module.
The heat exchange surfaces selected tend to take advantage of the great-
est heat transfer temperature differences and thv.s minimize surface area
169
-------
$fKt#M FLOWS ntfff»t
COil-
STOME
SOilC.$
d>s
Alfl"
iCTir
/ i 5 .11
l»l I
_ 7
Mi»4-
7* 7B
"•»'
»»2
8 , * 10
34114
-
"'"
""'
1| (^
~ r - —
»S»| „«
*>
met
it
MIJS ~
l»_
~ii6T"
29
llttl' *
ti>»i.
ii
'
•tz
25
..", I „'.'.
I
Z6
"
27
za
" j
i
j 10 I Jl I 52 33 I 14 i 35 | 16
I />Jr<>4 I f^i>2*< r«»47« f^rtrfib] .4r«^ft&] MMJVJ [ 134^*!
J_.__L__l _ _^y'''L _ii;y_± • -I s?»
III i,»(«*»sri*>i.;i*T««t.'»» I w».»sj
«rnCAH$ *MllftAU.V 5UAU, NOT CUNSiOfNtD
Figure 28. Process Flow Schematic (Foster Wheeler)
-------
Reproduced from
besl available copy*
d&j&syK
SSSLCOiJVH
ifiiT^j
Figure 29. Advanced Steam Cycle — Pressurized Fluidized
Bed — Boiler (Foster Wheeler)
171
-------
«45-
SMS RNS 1
OUTY DUTY . , • • ' «i M
i 3420 ' i C PSHIA 14550 *•*[? tx> ,
j S4a.
1 ' " "' " " ""• ~" I
! 14.953 | C PSMI8 1882430 n 750*
108.073 : l».375a! ... , _| V
|«3S- .
3.420 [ C PSHJA 14550. °P ^
• 1!«48*
- , ... Jl i
14935 i i PSH2B 1882*30 <-.[ 1
Mli.073 |I».375Q .
«25- r~ - -*>->i;
i . . 1 75^ 690,799 If/Kt
• 3420 ! C PSH3A I45SO '^
_... ..H ,u — ~4i T8i'
14955 C. PSH3B I8S24JO -. »73«
206.073 18.3730 -J
t .
|tio* f -.- -* -- - r
1 1 "• vi
; - • • : Oj «7s- i . '
3.420 C FSH 4A W350 ° 1 ' "
11 880- |V | 'I •
C FSH IB SI 1170 , '°OS'»
I495S ' -li r<
•0947 127126 ' |lT?750 ^ 3H 4 !27l26fl T,XJ-.
J603' K "J
1 . V
1 3.42O f FSH 5A . i.«S3 Vj- "i
j | . }J - |
j C FSH5B 61.1180 . Q_J 1 . J"
80946 12*127 JI6 3750 > '. ; ^ RH ^ }27.l27q Or>^-( '
590'
| , ETA 1 PSH6A ,| 750- '
| • t f' — — " — H 1 i
I7l»g 319490^1 CI03.J320 , 875* 379.929 IO/TW
172.016 i 21.7440 ! ! ' •
A^ 370- 1 ' ]' '
JO - ! EX Il9,l49!l>/tir
313.194 ECON- 315.194 f S 5 C |!
1273.323 234.253 428.8130 1 iso^^Tsa^aB/v jt% * 1 1 j»i*
Telfll Outout -1527.5760 ' • ' ^« « S^ « £'•".
S| III gp
h-EntMlpy 8TU/lb ..J.. , — ! 1 1
- -T.mp *F .. fifW! .RHiiv RHowt. SMout
0 -fflilho* STU/hf ' f ^
— i < r-
^ V-, \" v-
!
' "Wf
'|H
• U
H
& i
; — i
0
m
^ ^i
U
80
«v
T
- 5- I !
t 1 I J
Figure 30. Advanced Steam - PFB Circuit Absorption Diagram
-------
Table 62
PFB MODULE HEAT KXCllANCE SlUFACE DETAILS
BANK
SERVICE
E7A
E7B
VU
PSH1.2A
PS111.2B
PSH3A
PSH3B
PSH6A
PSH6B.
FSH4. 5A
FS1I4.5B
RIM, 5
EX
EY
Size
EX
EY
Beds 1-5
6
7
Q MBcu/hr
13.992
31.949
113.619
1.455
188.243
1.455
188.243
..799
103.532
1.455
61.117
127.127
5.637
309.557
H x D
B'O x 24
_
So ft
617
463
4450
95
4539
95
4540
52
2497
95
1892
3026
5220
179326
x U
1 Lg x -
r»odn)
1-3/4
1-3/4
1-1/4"
+ Fin
1-1/4"
1-1/2"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1
2" Fin
N
s
22
22
270
68
68
68
68
68
68
68
68
68
44
68
St(in)
4-1/2
4-1/2
1-1/2
3
3
3
3
3
3
3
3
3
1-1/2
4
23' x 38' x 10'
8 '-6" x 8'
4 '-8" x 8'
3'10" x 8'
-6" x 8'
-6" x 8'
-6" x 61
2-1/4
2-1/4
Fin
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
3 sq.
6
*loops
Qn
S°
0°
N
s!
-t
aT
BC
NR
L/L
1 BC(in) NR
71" 16
53" 12
270
2-7/8" I/?
77-5/8" 24
9-3/8 1/2
77-5/8 24
9-3/8 1/2
• 77-5/8 24
15-7/R" 1/2
32-1/B" 10
51-5/8" 16
64" 12
81-1/2 14
7./L Loops
2 8
2 6
270 1/2
1 1/4
1 12*
3 1/4
3 4*
3 1/4
3 4
5 1/4
5 1*
2 4*
1
1 7
«yf>2 On/In)
io-in/-
-/10-10
10-5/5-10
8 F+R
8-8/-
_/8-8
8-8 /-
-/10-10
6-6/-
-/8-8
10-10/-
-/10-10
10-10/12-12
3/3
10/10
are half IcnRth with central outlet headers.
- Duty - mm Btu/hr
- Surface - ft"
- Tube O.I), (in.)
- No. Sections
- Side spacing (in
- Back spacing (in
- Bundle clearance
- No. runs/section
- loop In loop
.)
.)
(In.)
173
-------
requirements. Staggered in-bed tube pitches were selected with spacing that
promotes a good uniformity of bed fluidization.
I
PFB Gas Turbine and Heat Balance
Each PFB unit has a gas turbine with an exhaust economizer. Perform-
ance specifications are presented in Figure 31 and Table 63 for the units
serving the 16jQ F PFBs. The state points and heat duties integrate exactly
with the flow rates and heat duties of Figure 28 and of the steam turbine heat
balance Figure 32. The basic fixed parameters were the air for combustion at
state 2 of Figure 30 and the coal rate per module of 182, 462 Ib/hr.
The gas turbine compressor has 17 stages and the turbine has 3. The
design, except for modification to the normal combustor section, is char-
acteristic of current 3600-rpra designs. It is anticipated that blade coat-
ings and claddings may be required to counter any chemical or particulate
attack on the nozzles or buckets.
Prime Cycle
The major component for the prime cycle is the steam turbine-generator.
The selected unit was a General Electric tandem compound turbine with four-
flow exhaust using 33,5-in. last-stage buckets. The 3500 psig/1000 F
high-pressure turbine and 691 psig/1000 F reheat turbines are comparable to
units supplied for the AFB prime cycle. The heat balance of Figure 31 was
based on exactly matching the 6.105 MBtu/hr heat to steam cycle produced by
the four FFBs, their gas turbine economizers, and their Petrocarb compressor
economizers. The high-pressure feedwater heaters have been eliminated since
feedwater at 533.3 F will be produced by the economizers with a pinchpoint
temperature of 46.5 F. The elimination of high-pressure steam feed heaters
in the steam cycle reduces its cycle efficiency to 41.3 percent. The heat
rejection system is identical to that presented in Table 65 except that flows,
power, and number of cells are porportional to condenser heat duty. (See
table 64.)
Materials Considerations
Concern with the pressurized fluidized bed with a bed temperature of
1650 centers mainly on the problems created by hot corrosion. Apart from the
use of some higher temperature alloys, the problems are qualitatively similar
co those for the AFBs. Critical temperature ranges will depend on the alloy
selected and the nature of the chemicals formed, which in turn will depend on
the coal composition.
There may be a severe hot corrosion problem in the pressurizing gas tur-
bine and also erosion and fouling of critical components. The problem of hot
corrosion in the turbine can be essentially rationalized in terms of the con-
taminant level in the gas stream. The limits for materials in current use
are well documented. If these limits cannot be maintained through hot gas
174
-------
Water
LI-
Boiler
Feed water
PCC
Station
Gas flow, Ib/hr
Water flow, Ib/hr
Pressure, psia
Temperature, °F
Enthalpy, Btu/lb
Heat duty, HBtu/hr
Unit
•Gas turbine limits
Constituent
Sodium and pot.
Lead
Vanadium
Calcium
Trace - others
Solids except I
Solids over 10
Solids over 13
1
1888924
0
14.7
59
-S
for gas
i . 3* 4 5_ £ I £ 1
1317000 1984159 2056083 2056083 0 0 ' 0 0
0 0 -0 ^,.0 105131 105131 19145 19145
145.5 138.0 15.42 14.7 4393 4200 4393 4200
59T 1600 850 300 253.5 533.3 253.5 533.5
123 426.4 204/S .54 231.2 525.65 231.2 525.65
1211.13 309.56 309.56 5.64 *"[
PFS Ey Ey Ex
stream 3 •*
Concentration opm bv Weight
issiura
IC's, total
microns
microns
Ur.der 0.02
tinder 0,02
Under 0.01
Under 0.04
Under 0.01
1
0.01
0.001
Figure 31. 1650 F Pressurized Fluidized Bed Module Gas
Turbine, Economizer Ey, and Petrocarb Com-
pressor Cooler Economizer Ex
175
-------
Table 63
GAS TURBINE SPECIFICATIONS FOR PRESSURIZED FLUIDIZED P-ELs
Ambient - ISO 59F, 14.7 psla
Compressor - Stages 17
Pressure ratio 10:1
Inlet pressure, drop 4" H.O
Combustor pressure drop - 5%
Turbine - Stages 3
Inlet temperature 1600°, 1700°
t Turbine inlet Mach number 1.0
Turbine nozzle flow coefficient 1.0
Diffuser inlet Mach number 0.5
Diffuser exit Mach number 0,05
Diffuser pressure loss coefficient 0.46
Exhaust^ pressure drop 20'1 H_0
176
-------
StiiJiHSi.' •«•*»• i U/KW tin.
Ill.ilJKWMj V MM. Al>(.
If.1** J) V I.MI JbOOIII'M
ll HVA *• IV I^H: 111 l-Hf'.'i, K •. » ITII.K
Reproducee! from
best available copy.
*>« Id/Mm
*4t III! MS
Figure 32. Steam Turbine Cycle Heat Balance PFB - 1650 F
-------
Table 64
COOLING TOWER PERFORMANCE
Design heat duuy 3600 MBtu/hr
Wet bulb 51.5 F
Condensing at 2.3 in. Hga 105.9 F
Hot water to tower 100.9 F
*••
Cold watsr return 70.3 F
Range 30.7 F
c- :
Approach 18.7 F
Water flow •* • 234,555 gsl/min
Fan power 2.53 MW
Pump power 4,40 MW
Cells ^ *~ 22
Each cell: 36 feet long, 75 fefct wide,
47 feet high, 1 fan
Table 65
SYSTEM OUTPUT
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZEn.BED
1650 F
STEAM CYCLE OUTPUT (MW )
(MW - 60 Hz AC) e 738.63
TOTAL'TRESSURIZING TURBINE OUTPUT (MW ) 205.00
TOTAL GROSS OUTPUT (MW ) e 943.63
TOTAL AUXILIARY LCCSES6(MW )
INCLUDING TRANSFORMER LO§SES 39.86
NET POWER PLANT OUTPUT (MW - 60 Hz AC - 500 kV) 903.77
e
o
178
-------
cleanup or turbine design, it will be necessary to employ alloys that are
more corrosion resistant or apply coatings to surfaces in the hot gas stream.
The steam turbine represents a mature technology, and significant
materials problems are not anticipated.
179
-------
4. PLANT ARRANGEMENT
Plot Plan
The plant arrangement on its plot is based on storage of a 60-day sup-
ply of coal and a capacity to hold ash for 15 days. A series of ponds con-
tain run off water from the site and provide for treatment of all water
returned to the North River. The basic plot dimensions are one-half mile
by three-tenths of a mile.
Figure 33 shows the total plant area of 108 acres in the small section,
and the main area in detail.
Coal and Dolomite Handling
Coal is received by rail and is unloaded to two conical storage piles.
The compacted dead storage coal pile is 60 ft high with a base measuring about
1240 ft by 416 feet. This stores 412,000 tons of coal for recovery by use of
dozer tractors. The two conical live storage piles have a base diameter of
about 312 ft, and contain a total of 114,700 tons of coal, with 26,000 tons
available by gravity feed through under-pile vibrating feeders. Dolomite is
stored in a single storage pile of 235,000-ton .total capacity with 11,800 tons
available by gravity flow through under-pile vibrating feeders.
The coal from the active storage pile is fed at 365 tons/hr to a conveyor
belt by vibrating feeders located under the active storage pile. Magnetic
separators at tha distribution bid remove the tramp iron. Oversize coal is
screened out, crushed, and then fed back to the distribution bin. The dis-
tribution bin is equipped with four coal outlets, which feed the coal to four
conveyor belts; each belt feeds the coal to two silos. A set of four silos
feed the coal to an associated conveyor belt for the transport and distribution
of coal to any two of the three parallel sets .of half plant capacity dryers and
crushers. This provides one redundant set of dryer and crusher for reliability
and maintenance purposes. During startup, and under upeet operations, coal can
also be supplied to combustors for drying the coal and limestone in place of
hot air from the spent solids cooler. Dolomite is handled similarly at a rate
of 168 tons/hr.
The coal and dolomite are delivered separately to bins at each boiler
module. The coa!. and dolomite are not premixed for injection to the fluid
bed. For these PFB boilers the two materials are injected separately by
Petrocarb injection systems that are part of the PFB boiler modules.
Solid Wastes Handling
Spant dolomite and ash are collected at the PFB boiler modules at a
noirir.ai rate of 155 tons/hr. This residue leaves the boilers at 1600 F and
is air-cooled to 250 F prior to being conveyed to storage bins at the rail
spur. A solid waste dry storage capacity of 55,800 tons is provided by six
storage silos.
180
-------
M4MMM, I4vt*t
(Jj4.lt.LM
i |*Trt~"l
!5-ii
|Ri
in!
!o'
x!
_
Figure 33. Plot; Plan Advanced Steam Cycle •—" Pressurized Fluidized Bed (Dechtel)
-------
General Arrangement
The arrangement of the four PFB modules about the turbine building is
shown in Figure 34. The ground floor plant indicates the small size of the
No. 3 PFB furnace as conpared to Its cyclones and granular bed fine filters.
Plant Elevation
The- plant elevation View through the turbine building and cne PFB mod-
ule is presented in Figure 35. The stack of fluidizeJ beds is contained in
the 13-ft diameter pressurized tower, which stands 130 ft high. Four of
eight cyclone separators and eight of sixteen granular bed filters are shown.
Ihe gas turbine is located at giv -ric1 Ir.vel between the two rows of fil-
ters. The exhaust passep thrcugh ti.; economizer en route to a stack on each
side of the power plant.
Electrical Schematic
A single line electric, diagram showing major electrical equipment :* =
presented in Figure 36. Four 51.25 J-fW gas turbine-generators feed the 25 kV
bus through step-up transformers. The 738.6 MW steam turbine-generators
feeds the 25 kB bus directly. Two main transformers feed the 500 kV
transmission ling.
Two 13.8 kV auxiliary buses may be connected to the. main bus through
a transformer or to the start-up transformer. Subsidiary buses operate at
4.16 kV and A80 kV. The emergency diesel feeds the 480 kV critical service
bus.
132
-------
I-1
CO
n
•-*
"*i"
®
mil -i .
_Jl
rA'i^f'-L'J.f:
.;... .—~,)r
00
o c>
-til,
L'^_,
..J
n
mm
TI ff_ i , TIM.
O^:
i i i i,^,,,_, ' '
4 ^p^lnut •»« { ' I' ' •
7? f-,".>!t;
. . ! - [C<"
»•* »j 11 I
"rf—",""-" i ii uui.9t»tt' i
](•)(•)
/JOO
'50
0.1. 4
IL
;^r
c'i
r:i*4,yM,lftffr
%,
SIM.
ClKHtflD MOOf^ ft AN Ci-O' ;
u i»r M
Figure 34. General Arrangement Plan Advanced Steam Cycle — Pressurized
Fluidized Bed (Bechtel)
-------
TMC PULL ftfACC
IMP n-QOH Ct-.O*
SECTION A-A
«<
UECFKIO
.
COMfARTMlMT
—. i% if^^^c IQwt
n
ISCBTEl
GE/NASA
AOVAHCEQ CHCRCr COH)/£fe.(ONCTUO(
CEfiHAl. A
EtCVATION
ADVANCED STEAM CTCLE PFB
11:07
P-203
Figure 35. General Arrangement Elevation Advanced Steam
Cycle — Pressurized Fluidized Bed (Bechtel)
-------
Gt XtlASA
-id D lufK,) crrivfVJ(V< it»
UNf OlACHAM
*cv*«c»o sri *u c * citron
—-^--f——>
1 1 ;o?
Figure 36. Electrical Diagram for Advanced Steam - PFD System (Bechtel)
-------
5. SYSTEM PERFORMANCE ASP COSTS
Performance
The performance margins commonly applied to steam power plants cannot
be tolerated in a closely integrated plant such as this. The heat balances
presented for PFB, gas turbine, and steam turbine must all be guaranteed per-
formance points. Table 65 presents the resulting gross generation, auxil-
iary power loss, and ne". station output for plant configurations with 1650
F mainbeds. The auxiliaries are of the order of 4 percent of generation as
compared to 7 percent for AFB power plants.
Auxiliary Losses
The detailed auxiliary losses are presented ir; Table 66. By virture
of the gas turbines supplying the energy to force gas through the PFB and
hot gas cleanup system, there is no electrical auxiliary loss attributed to
that service; this factor accounts for the markedly reduced electrical ':
auxiliary loads for PFBs as compared to the AFB power plant.
^- *
»~
Costs—General
.*••
Costs were synthesized €rom major components costs, BOP material costs,
and BOP labor costs. Items made up of numerous smaller components are pre-
sented by enumeration of the total cost and unit count for each of the sub-
components. An equipment list for BOP components identifies all..major items.
A detailed breakdown of BOP labor man-hours and material costs completes
identification of all material'-and construction and installation costs.
Thereafter these costs were combined with major component costs to arrive
at total plant costs.
Costs—Major Components
The steam turbine-generator would be purchased at a price of $25 mil-
lion, and each gas turbine would be purchased as a complete unit for $6.41
million. In contrast, the steam generator comprises four PFB modules, auxil-
iary units serving each PFB, conveyor and solids equipment serving pairs of
PFB modules, and solids preparation equipment providing three units where
any two can service the entire plant. Equipment lists for the PFB steam
generator system are presented as Tables 67, 68, and 69.
PFB Major Component Characteristics (1650)
Subsystems costs and weights are presented in Table 70 for the steam
turbine-generator and for the PFB modules exclusive of their solids handling
equipment. The gas turbine, its economizer, and the hot gas filtering
system are also enumerated. o
186
-------
Table 66
AUXILIARY LOSS BR&.KDOWN
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
1650 F
ITEM
FURNACE
FANS FOR DRYERS
(COAL DOLOMITE, SOLIDS)
. COAL CRUSHER
DOLOMITE CRUSHER
INJECTOR COMPRESSOR
FILTER -
TURBINES
ASSUMPTIONS
PUMPS
CONDENSATE
CIRC. WATER
SERVICE WATER
INTAKE WATER
SOLIDS HANDLING
"HOTEL" LOAD
COOLING TOWER FANS
TRANSFORMER LOSS
0.33% OF STEAM TURBINE, kW
1% OF CAS TURBINE, kW
A P = 185 PSIA
PROPORTION TO COOLING DUTY
A/E ESTIMATE
A/E ESTIMATE.
BASED ON RATES AND LIFTS
0.88% OF GENERATED kW
VENDORS VALUE
0.5% OF GENERATED kW
TOTAL AUXILIARY POWER =
NO. OF
UNITS
2
2
2
8
8
1
4
2
3
2
2
1
1
22
.2
TOTAL
MW
e
4.18
0.74
0.33
4.03
1.11
2.37
2.16
9.95
4.40
0.89
0.94
2.17
8.34
2.53
4.72
39.86
187
-------
Table 67
SOLIDS HANDLING EQUIPMENT LIST AND COSTS--PFB
Subsystems
COAL PROCESSING & FEEDING
1 - Dryer System @ 182-1/2 TPH
1 - Crusher & 2 Screens
1 - Distribution Bin @ Crusher
2 - Vibrating Feeders ® 92 TPH
2 - Surge Bins @ 7600 ft3
2 - Bin Activators
2 - Feeders (Vibrating) (§365 TPH
2 - Coal Distribution Boxes
2 - Petrocarb Coal Injector System
Section Subtotal =
DOLOMITE PROCESSING & FEEDING
1 - Dryer System @ 84 TPH
1 - Crusher & 2 Screens
1 - Distribution Bin @ Crusher
2 - Vibrating Feeders @ 42 TPH
2 - Surge Bins
-------
Table 68
HOT GAS CLEANUP AND AIR EQUIPMENT LIST AND COSTS—PFB
HOT GAS CLEANUP
16 - Two in One Cyclones for Beds
4 -145 ft3 Collecting Hoppers
32 - Trickle Valves & Dip Legs
8 - Lock Hopper Seal Valves
4 - 290 ft3 Lock Hoppers
4 - Fines Injection Systems
4 - Injection System Valves
2 - Two in One Cyclones for CBC
2 - 290 ft3 Collecting Hoppers
4 - Trickle Valves & Dip Legs
4 - Lock Hopper Seal Valves
2 - 580 ft3 Lock Hoppers
2 - High Temp. Feeders (Vibrating)
2 - Surge Bins for Dust Coolers
4 - Airlock Valves for Dust Coolers
2 - CBC Dust Coolers
32 - Granular Bed Filters
4.- Fines Letdown & Removal Systems
for Granular Beds
Section Subtotal =
Cost in Plant Requirement
1975 $ Number M$
$ 8,127,592
106,781
228,880
137,278 -
173,161
519,999
68,639
532,011
86,579
i8,860
68,639
170,301 ' '-.
31,200 >
40,404
57,200
260,000
20,893,579
721,499 _
$32,252,522 2 64.51
HIGH PRESSURE AIR
2 - Air Dryer Precoolers
4 - Air Dryers
4 - Booster Compressors
4 - 400 ft3 Receivers 300#
4 - Air Compressors for Granular Beds
2 - 400 ft3 Receivers 400//
1 - Booster Compressor Spare
1 - Air Compressor Spare
Section Subtotal =
174,200
349,80.3
416,000
50,897
193,533
28,628
104,000
48,383
2
2
2
2
2
2
1
1
1,365,444
2.58
189
-------
Table 69
, HEAT EXCHANGE EQUIPMENT LIST AND COSTS - PFB
M$ per Module MS Plant
PFB heat exchange and pressure parts 2.213
PFB containment shell and nozzles 0.566
PFB fuel Injection and air parts 0.237
PFB controls . 0.567
PFB petrocarb cooler economizer E 0.089
X
PFB module ' . 3.67 14.68
.Gas turbine economizers 0.627 2.51
190
-------
Table 70
MAJOR COMPONENT AND SUBSYSTEM WEIGHTS AND COSTS
SUMMARY
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
Major Component or Subsystem
PRIME CYCLE
STEAM TURBINE-GENERATOR
(GENERATOR ALONE)
PFB MODULE
ECONOMIZER
PRESSURIZING SYSTEM
GAS TURBINE-GENERATOR
(GENERATOR ALONE)
Weight
(FOB)
M LB
6.5
(0.94)
0.57
0.44
0.49
(0.18)
Component or
Subsystem
Costs
(FOB)
M$
25
-
3.67
0.63
6.41
Output
Or
Duty
738.6 MW
e
244.1 MW,.
th
90.9 MW.,
th
51.25 MW
e
Cost Per
Unit
Output
Or Duty
33.85 $/kW
e
15.03 $/kW^.
tn
6.9 $/kW ,
125 $/kW
_ e
Cost
Per
LB
3.85
-
6.44
1.43
13.22
-
HOT GAS FILTERING
16.13
-------
Table 71 presents the characteristics of the PFB module heat exchange
and pressure containment parts and the gas turbine exhaust economizer. The
average heat flux is high compared to conventional boilers and is three times
the average for the AFB unit. However, the peak heat flux is very much less
than peak values for conventional boilers. As a result of these conserva-
tive values the PFB heat exchange surfaces are expected to have service life
far greater than the hottest parts of conventional furnaces and boilers-;.
The economizer operates with low heat exchange temperature differences
that require very great surface area because of the low heat flux.
Equipment List-Balance of Plant (1650)
The specifications for the BOP equipment are listed in Table 72. Elec-
tric motor drives for fans and pumps anticipate a margin of 10 percent flow,
20 percent pressure rise, and 30 percent power. As a result these motors
are sized for continuous duty at levels above the 100 percent plant operating
point.
.' •** -
Capital Costs-Balance of Plant (1650 ?) ^.
tr~
Table 73 presents the AE's detailed breakdown of the direct manual field
labor in thousands of man-hours, and of BOR.material cost in thousands of
dollars for each major category of the balance of plant. In using these data
an average hourly field labor rate of $11.75 in mid-1975 dollars converts
man-hours to dollars. Where field indirect labor is allocated to individual
items r. ..sr than the total labor for the job, it will be apportioned as 90
percent of the direct field labor cost or at a rate of $10.58 per direct
labor hour. All material and labor costs are based on mid-1975 costs.
The seven major categories used by the AE relate to the principal field
labor skills to be applied. A modified subdivision of costs was made using
the following categories:
1. Land improvements and structures
2. Coal handling
3. Prime cycle plant equipment
4. Bottoming cycle (not applicable to PFB plant)
5. Electrical plant and instrumentation
After the title of each item or major category in Table 73^ the
appropriate second category is given in parenthesis.
Plant Cost Estimates
The installed costs of major system components are presented in Table
74. Those elements related to heat release cost a total of $75 million.
They are the coal and solids handling equipment, the PFB furnace modules,
and the economizers. TU,e steam turbine-generator along with its feedwater
heaters and pumps costs half that amount. The gas turbines with hot gas
filter system cost $95 million.
192
-------
Table 71
HEAT EXCHANGER CHARACTERISTICS
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
Heat Exchanger
PFB MODULE
ECONOMIZER
Output or Unit Unit Unit Heat .
Vessel Duty Per Efficiency 'Surface Weight Cost Flux
No. of Size or Unit or Area (FOB) (FOB) Average
Units Type M Btu Effectiveness Ft2 LB x 10~3 M$ Btu HE^Ft"2
4 13' dia x 116' 833 -, 22361 568.6 2.213* 37252
4 23' x 38' x 10' 310 0.92 179326 440 0.627 1726
*HEAT EXCHANGE AND PRESSURE PARTS ONLY
vo
-------
Tabli-,72 (page 1 of 4)
BALANCE OF PLANT EQUIPMENT LIST
ADVAl,'CEi) STEAK PLANT, PRESSURIZED FLUIDIZED BED, 1650 F
EQPT.
NO.
01
C-2
C-3
C-4
C-5
C-6
C-7
C-c
C-ll
C-12
C-13
C-14
C-15
C-16
C-17
C-18
O19
SERVICE
DESCRIPTION
1, Coal, Dolomite and Ash Handling Systems
Coal Conveyor Belt
Dolomite Conveyor Belt
Vibrating Feeders for Car
Unloading (6 req'd)
Coal Belt Scale
Coal and Dolomite
Sampling System
Coal Lump Crusher (3 req'd)
Dolomite Lump Crusher
(3 req'd)
Magnetic Coal Cleaner
(3 req'd)
Magnetic Dolomite Cleaner
(3 req'd)
Coal and Dolomite Dust
Control System
C0? Fire Protection System
60 in wide, 344 ft long, 3000 tph, 365 hp
" " " 575 ft " " " 642 hp
" " " 190 ft " " " 420 hp
42 in " 1000 ft " 500 tph, 144 hp
" " " 610 fr " " " ill hp
60 in " 375 ft " 3000 tph, 163 hp
36 in " 1035 ft " 220 tph, 46 hp
830 ft " " " 36 hp
it ii ii
Rating 0-750 tph
Dimension from Layout
0-3000 tph, 60 in Belt
0-3000 tph, 60 In Belt
0-10 tph, 10 in Lumps
0-10 tph, 10 in Lumps
500 tph
125 tph
4-6000 cfra Bag Type Dust Collector
Adequate to Service Item C-18 Bag-houses
194
-------
Table 72 (page 2 of 4)
EQPT.
NO.
SERVICE
C-20 Vibrating Feeders for
Dolomite Pile (4 req'd)
C-21 Vibrating Feeders for
Coal Piles (8 req'd)
C-22 Coal Silos (8 req'd)
C-23 DoloTBite Silos (2 req'd)
C-24 Ash Storage Silos
(6 req'd)
DESCRIPTION
0-220 tph
0-200 tph
375 ton each
650 ton each
Total Volume 2,800,800 ft:
80 ft dia., 95 ft high
2.. Electrical Systems
E-l
E-2
E-3
E-4
E-5
E-6
E-7
Main Transformers
(2 req'd)
Unit Aux Transformer
Start-up Transformer
Auxiliary Diesel Generator
Miscellaneous 480/277 V
LCC Transformers (14 req'd)
4.16 kV LCC Transformers
(2 req'd)
Gas-Turbine Output
Transformers (4 req'd)
510 MVA, FOA 65°C
24/500 kV, 30, 60 Hz
24/13.8 kV, 30, 60 Hz
Double Secondary 24/24 MVA, FOA 65°C
500/13.8 kV, 30, 60 Hz Split Secondary
Tertiary Winding at 24 MVA, FOA 65°C
1000 kW, 30, 60 Hz,
480 V, 0.8PF, 1250 kVA
13.8 kV / 480/277 V, 30, 60
1680 kVA, FOA, 65°C
13.8 / 4.16 kV, 30, 60 Hz
8,000 kVA, 65°C
13.8 / 25 kV, 30, 60 Hz, 60 MVA,
FOA, 65°C, 54 MW
195
-------
Table 72 (page 3 of 4)
EQPT.
NO.
F-l
SERVICE
Main Condenser
DESCRIPTION
3. Main Fluid Systems
F-2 Piping:
Circulating Water
Main Steam*
Boiler Feedwater*
Cold Reheater RHI*
Hot Reheater RHO*
5 2
3.81 x 10 ft of heat transfer area:
Std Materials in other respects same as
AFB but with 9 of tubes scaled down in
proportion to heat transfer area.
I.D. = 123 in
I.D. = 6.31 in, tm = 1.628 in
I.D. = 6.73 in, tm = 1.077 in
I.D. = 11.59 in, tm = 0.29 in
I.D. = 14.2 in, tm = 0.631 in
F-3
F-4
F-5
F-6
F-7
Shell
Feedwater Heaters psia/°F
L.P. #1 6/171
UP. #2 13/205
D.F.T. 4.3 x
Main Condenser Pumps and
Motors (2 req'd)
Boiler Feed Pumps (3 req'd)
Turbine Driven
Main Circulation Pumps
and Motors (3 req'd)
Cooling Towers (22 cells)
Tube
psia/°F
160/166
160/200
106 Ibs/hr
640 hp,
9,850 hp
1920 hp,
234,200
Flow
Ib/hr
4. 06x1 O6
4. 06x1 O6
@ 250°F
Heat Tranj
Area ft4
17,315
13,928
jfer
4,300 gpm, 410 ft TDK
, 3,450 gpm,
90,000 gpm,
gpm
10,070 ft TDH
75 ft TDH
*Size based on flow at each boiler
196
-------
Table 72 (page 4 of
EQPT.
SO.
F-8
F-9
SERVICE
Air Duct, Compressor to
PFB combustor, (one/PFB)
DESCRIPTION
30 In I.D.
Gas Duccs Steel Pipe with 9 in Refractory lining
Manifold to PFB (one/PFB) 36 in I.D.
Manifold to Cyclone (8/PFB) 20 in I.D.
Cyclones to Granular
B. F. (8/PFB)
Granular Bed Filter
to Turbine (16/PFB)
(20/PFB)
( 2/PFB)
F-10 Exhaust Stacks (2 req'd)
20 in I.D.
14 in I.D.
10 in I.D.
28 in I.D.
;+17.5 ft dia x 400 ft high
197
-------
Table 7.3 (page 1 of 7)
BALANCE OF PLANT ESTIMATE DETAIL
ADVANCED STEAM PLANT, PRESSURIZED FLUIDIZED BED, 1650 F
Direct Manual
Field Labor
MH 1000's
Balance of
Plant Material
$ 1000's
1.0 PFB STEAM GENERATORS C3)
1.1 Steam Generator Erection
Erect only (supply by others):
includes PFB tower skirt; PFB towers;
piping connections at tower; insulation
Supply and erect: .
includes tower access steel; miscel-
laneous materials and labor operations
1.2 Steam Generator Auxiliaries
- Erect only (supply by others):
includes coal and dolomite Petrocarb
injection systems with injection air
compressors and auxiliaries
- Supply and erect:
includes support steel for Petrocarb
systems; coal and dolomite piping
from Petrocarb systems to PFB towers
1.3 Hot Gas Cleanup
- Erect only (supply by others):
includes cyclones; hoppers and surge
bins; valves; feeders and injection
systems; dust coolers; granular bed
filters; granular bed blowback air
compressors and auxiliaries
-- Supply and erect:
includes support steel for hot gas
cleanup equipment; access steel
22
70
22
221
100
890
38
100
61
370
1,940
3,100
198
-------
Table 73 (page 2 of 7)
2.0 TURBINE GENERATORS (3)
2.1 Steam Turbine Generator
- Erect only (supply by others):
includes 732 MWe steam turbine:
generator; exciter; auxiliary equip-
ment; integral steam and auxiliary
piping; insulation; miscellaneous
labor operations
2.2 Gas Turbine/Compressor/Geno.rators
- Erect only (supply by others):
includes gas turbine compressors
with 50 MWe generators (4)
Direct Manual Balance of
Field Labor Plant Material
MH 1000's $ 1000's
105
100
40
100
145
200
3.0 PROCESS MECHANICAL EQUIPMENT
3.1 Boiler Feedwater Pumps (3)
- Supply and install:
includes turbine-driven main feed-
water pumps and drivers
(3 9 $770,000 ea.)
3.2 Main Circ. Water Pumps (3)
Supply and install:
includes main circ. water pumps
and motors (3 @ $265,000 ea.)
3.3 Other Pumps (3)
Supply and install:
includes condensate pumps and motors
(2 @ $100,000 ea.); and other pumps
and drivers not listed elsewhere
2,430
830
590
199
-------
Table 73 (page 3 of 7}
Direct Manual Balance of
Field Labor Plant Material
MH. 1.000'a $ 1000's
3.8 Coal Handling
Supply and erect: 80 6,150
includes railcar dumping equipment;
dust collectors; primary crushing
equipment; belt scale; sampling station;
magnetic cleaners; mobile equipment;
conveyors to pile; reclaiming feeders;
conveyors and bucket elevators to dryers
and grinders; recirculating conveyors at
grinders; conveyors to Petrocarb; bucket
elevators at Petrocarb •*
3.10 Dolomite Handling (2) *- ,
tf
Erect only (supply by others): 13 10
includes dolomite dryers (3); support
and access steel for dryers; dolomite
grinders (3); screens at grinders
Supply and erect: 43 2,240
includes magnetic cleaners; conveyor to
dolomite pile; reclaiming feeders; con-
veyors to cascade; dolomite cascade; con-
veyors and bucket elevators to dryers;
conveyors and bucket elevators to
grinders; conveyors and bucket elevators
to Petrocarb :
3.11 Spent Solids Handling (2)
Erect only (supply by others): 11 30
includes spent solids valves; hoppers;
feeders; fans; cyclones; conveyor to
coolers; ash coolers (2)
- Supply and erect: 85 3,540
includes ash cooler accessories and
bucket elevators; ash conveyors; ash
storage silos (6) with feeders; unloaders
and foundations; railcar loading equipment
200
-------
Table 73 (page 4 of 7)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ 1000's
3.12 Cooling Towers (3)
Supply and erect: 57 2,450
includes mechanical draft towers
with fans and motors
3.13 Other Mechanical Equipment (3)
Supply and install: 34 1,820
iijcludes water treatment and chemical
injection; air compressors and auxi-
liaries; fuel oil ignition and warm-up;
screenwell; miscellaneous plant equip-
ment; equipment ins.ulation
535 26,200
4,0 ELECTRICAL (5)
4.1 Main Transformers 11 2,960
- includes main power transformers and
transformers at gas turbine generators
4.2 Other Transformers and Main Bus 18 1,240
includes startup transformer; station
service transformers; generator main bus
4.3 Switchgear and Control Centers 25 2,050
- includes switchgear and load centers;
motor control centers; local control
stations; distribution panels, relay
and meter boards
4.4 Other Electrical Equipment 373 2,140
includes communications; grounding;
cathodic and freeze protection; light-
ing; preoperational testing
201
-------
Table 73 (page 5 of 7)
Direct Manual Balance of
Field Labor Plant Material
MH lOOO's $ IQOO's
4.5 Auxiliary Diesel Generator 2 110
- includes diesel generator, batteries
and associated d.c. equipment
4.6 Conduit, Cable Trays, Wire and Cable
5.0 CIVIL AND STRUCTURAL
5.1 Concrete Substructures and
and Foundations (1) 395 3,260
includes turbine building substructure;
PFB base mats; coal, dolomite and ash
handling foundations, pits and tunnels;
miscellaneous equipment foundations;
auxiliary buildings substructures;
miscellaneous concrete
5.2 Superstructures (1) 220 6,"130
- includes turbine building; auxiliary
yard buildings
5.3 Earthwork (1) 135 300
includes building excavations; coal,
dolomite and ash handling excavations;
circ. water system excavations; PFB
foundation excavations; miscellaneous
foundtion excavations; dewatering and
piling
5.4 Cooling Tower Basin and Circ.
Water System (3) 100 1,510
includes circ. water pump pads, riser and
concrete envelope for pipe; cooling tower
basin; circ. water pipe; cooling tower
miscellaneous steel and fire protection
850 11.20P
202
-------
Table 73 (page 6 of 7)
Direct Manual Balance of
Field Labor Plant Material
MR lOOO's $ lOOO's
6.0 PROCESS PIPING AND INSTRUMENTATION
6.1 Steam and Feedwater Piping (3) 50 2,400
*• - includes main steam; extraction steam;
hot reheat; cold reheat; feedwater and
condensate large piping, valves and
fittings
6.2 Hot Gas Large Pipe (3) 120 .5,700
- includes PFB compressed air feed; PFB
hot gas discharge; cyclone and granular
bed filter piping;" gas turbine inlet
piping . ^
6.3 Other Large Piping (3) ^ 195 3,350
- includes auxiliary steam; process water;
auxiliary systems; spent solids piping
6.4 Small Piping (3) 125 1,100
includes all piping, valves and fittings
of 2-inch diameter and less
6.5 Hangers and Misc. Labor Operations (3) 390 1,000
includes all hangers and supports;
materials handling; scaffolding;
misc. labor operations
6.6 Pipe Insulation (3) 40
6.7 Instrumentation and Controls (5) 230
1,150
203
-------
Table 73 (page 7 of 7)
Direct Manual Balance of
Field Labor Plant Material
7.0 YARDWORK AND MISCELLANEOUS (1)
7.1 Site Preparation and Improvements
- includes soil testing; clearing and
grubbing; rough grading; finish
grading; landscaping
7.2 Site Utilities
- includes storm and sanitary sewers;
nonprocess service water
7.3 Roads and Railroads
include railroad spur; roads, walks,
and parking areas
7.4 Yard Fire Protection, Fences and Gates
7.5 Water Treatment Ponds
- includes earthwork; compacted-clay
lining; offsite pipeline
7.6 Lab, Machine Shop and Office Equipment
MH 1000's
38
$ 1000's
27
52
12
1
135
10
50
750
600
10
280
1,700
204
-------
Table 74
MAJOR COMPONENT AND SUBSYSTEM CAPITAL COST SUMMARY
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
1650 F
Major Component or Subsystem
• FUEL HANDLING & PREPARATION
COAL AND SOLIDS HANDLING
PRIME CYCLE
S3
01 STEAM TURBINE-GENERATOR
PFB MODULES
ECONOMIZER
PRESSURIZING SYSTEM
HOT GAS FILTERING
GAS TURBINE
No. of
Units
3/2
1
4
4
4
4
Cost/Unit
(FOB)
M3
25.00
3.67
0.63
16.13
6.41
Component or
Subsystem
Costs
• (FOB)
M$
32.23
25.00
14.68
2.51
64.51
25.62
BOP+
Materials
M$
11.98
0.10
1.06
0.18
2.04
0.10
Site+
Labor
(Direct +
Indirect
MS
5.67
2.34
6.05
0.45
2.21
0.89
Total
Installed
Cost
M$
49.88
27.44
21.79
3.14
68.76
26.61
-------
The total costs using t:he AE's categories ate presented In Table 75.
The home office and fee of 15 percent is applied only to the BOP costs.
A contingency of 20 percent of all prior costs is applied to coyer
expected costs not specifically included in the original estimating pro-
cess. The total plant cost of $421 million represents $446/kW based on
total generation, or S466/kW based on net station output.
A reconstruction of'costs according to equipment function is pre-
sented in Table 76. Items 1 through 6 include everything in the preced-
ing table. I:em 7 adds the value of escalation and interest during the
5.5-year construction time. This iteis. is 54.8 percent of the prior total.
The result is a final plant cost of $693/kW of total generation or $723/kW
of net station output.
6 e
206
-------
Table 75
BALANCE OF PLANT CAPITAL COST.BREAKDOWN
ADVANCED STEAM CYCLE-PRESSURIZED FLIUDIZED BED
1650 F
Categories* Components
1.0 PFB STEAM GENERATORS & HOT GAS FILTERS
2.0 TURBINE GENERATORS
3.0 PROCESS MECHANICAL EQUIPMENT
4.0 ELECTRICAL
5.0 CIVIL AND STRUCTURAL
6.0 PROCESS PIPING AND INSTRUMENTATION
7.0 YARDWORK AND MISCELLANEOUS
Costs (Millions of Dollars)
Direct Labor (1) Indirect Field (2) Materials (3) Total
to
o
79.19
50.62
34.74
164.55
4.35 . 3.91
1.70 1.53
6.29 ' 5.66
9.52 8. :7
9.99 . 8.99
13.51 12.16
1.59 1.43
46.95 42.25
B.O.P. LABOR, MATERIALS & INDIRECTS 162.70
(SUM OF 1 -f 2 + 3)
A/E HOME OFFICE & FEE @ 15%
TOTAL PLANT COST
CONTINGENCY @ 20%
TOTAL CAPITAL COST
3.10
.20
26.20
11.00
11.30
20.10
1.70
73.50
90.55
54.05
72.89
29.09
30.18
45.77
4.72
327.25
24.41
351.66
70.33
421.00
-------
Table 76
PLANT CAPITAL COST ESTIMATE SUMMARY
(APPROXIMATE DISTRIBUTION)
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
1650 F
Major
Components
Materials
M$
1.0 LAND IMPROVEMENTS & STRUCTURES
(LAND, PLANT AREA 108 ACRES)
(LAND, 30-YEAR DISPOSAL 0 ACRES)
2.0 COAL HANDLING 32.2
3.0 PRIME CYCLE PLANT EQUIPMENT 132.3
STEAM CYCLE/PRESSURIZED FLUIDIZED
BED
738.6 MWe
PRESSURIZING GAS TURBINE -
205.0 MWg
4.0 BOTTOM CYCLE NOT APPLICABLE
5.0 ELECTRICAL PLANT & INSTRUMENTATION 0
SUBTOTAL 164.5
6.0 A-E SERVICE & CONTINGENCY
7.0 ESCALATION & INTEREST DURING
CONSTRUCTION
Balance
Of Plant Site Labor
Materials (Direct & Indirect) Total
H$
M$
11.8
12.0
33.4
16.2
74.4
M$
19.8
5.7
39.6
23.2
88.3
TOTAL M$
PLANT OUTPUT MW
TOTAL $/kW
31.6
49.9
205.4
39.4
327.2
94.7
231.2
653.1
903.3
722.S
208
-------
6. NATURAL RESOURCES AND ENVIRONMENTAL INTRUSIONS
Natural Resources
Table 77 shows the natural resource requirements for the PFB plant. The
consumption of coal for the PFB advanced steam power plant was 10 percent
less than that for the AFB power plant, but the substitution of dolomite for
limestone increased the sorber.t requirement by 63 percent. The PFB requires
6 percent more pounds of material than the AFB per kilowatthour delivered
when fuel and sorbent are totaled.
Water usage would be reduced for the PFB by 10 percent as compared to
the AFB. This results from the procuction of gas turbine power that
requires no coolant. Land area was comparable for the plants.
Environmental Intrusion
t
Table 78 enumerates the environmental intrusions of the PFB power plant.
The sulfur emission is well below the mandated new Source Performance Standards
for coal-fired boilers limit of 1.2 Ib/MBtu of heat input; the nitrogen
oxides are one-third of current- limits. The major heat rejection is from the
cooling tower. The stack heat rejection is greater than that for the AFB
because the stack temperature was 300 F rather than 250 F.
The composition of the dry granular spent solids shows the effect of
use of twice the ideal requirement for dolomite.
Trace Elements
To data experimental determination of trace element emissions from PFB
combustion has not been made. Critical factors are the low bed temperature
of 1650 F in the main beds and 2000 F in the CBC. These temperatures are
below slagging temperature and are close to those found in the AFB. The dis-
cussion of trace elements for the AFB would be fully applicable to expectations
for the PFB. Some differentiation should be expected when appropriate tests
are made on each type.
One important differentiation is that the gases from the PFB are held
at high temperature and then abruptly dropped to 912 F by expansion through
the gas turbine followed by cooling to 300 F in the gas turbine economizer.
Volatile trace elements with dewpoints above 300 F should condense out in the
gas turbina and its economizer.
209
-------
Table 77
NATURAL RESOURCE REQUIREMENTS
ADVANCED STEAM CYCLE - PRESSURIZED FLUIDIZED BED
SORBENT OR SEED, LB/kWh
DOLOMITE
COAL, LB/kWh
WATER, TOTAL (GAL/kWh)
COOLING
EVAPORATION
BLOVDOWN
PLANT GENERAL USE
CONDCNSATE MAKEUP
TOTAL LAND, ACRES/100 MW
MAIN PLANT e
DISPOSAL LAND
Table 78
VALUE
0.3715
0.8076
0.405
0.127
0.016
0
12
14
ENVIRONMENTAL INTRUSION
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
EMISSIONS
S02
Ox
1C
CO
PARTICULATES
THERMAL POLLUTION
LB/MBtu
INPUT
0.688
0.152*
0.020
0.100
HEAT REJECTED, COOLING TOWERS, Btu/kWh
HEAT REJECTED, STACK, Btu/kWh
HEAT REJECTED, TOTAL, Btu/kWh
WASTED
SPENT SOLIDS CONGLOMERATE
42% ASH COMPOUNDS
26% CALCIUM SULFVT.
16% MAGNESIUM 0X1' /
13% UNREACTED LIME
4% UNBURNED CARBON
WATER DISCHARGE' l.lq
*3ased upon available data, EPA believes that the NOX emission
more typically be in the range of 0.1-0.4 LB/MBtu.
LB/kWh
OUTPUT
0.0060
0.0013
0.0002
0.0009
951
5300
MLR,/DAY
7.43
25.9
level will
210
-------
7. SUMMARY PERFORMANCE AND COST
Table 79 summarizes the system performance and cost for the PFB—
Advanced Steam plant with 1650 F main beds. The overall energy efficiency
of 39.2 percent is appreciably above the level of 35.8 percent for the AFB
plant. However, the plant cost per kilowatt of $723 is $100 greater than
the AFB value. It should be noted that major contributors to the PFB capital
cost are the granular bed filters for cleaning the hot pressurized flue gas
($64.5 M uninstalled) and the high pressure solids handling system ($32.2 M
uninstalled). The resulting increase in the capital portion of the cost of
electricity (COE) is greater than the reduction in the fuel portion. The
total result is an increase of 2 mills/kWh over the COE for the AFB.
The sensitivity of the cost of electricity to variation of major cost
factors is presented in Table 80.
211
-------
Table 79
SUMMARY PERFORMANCE AND COST
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
1650 F
ITEM
NET POWER PLANT OUTPUT (MW - 60Hz - 500 kV) 903.8
e
THERMODYNAMIC EFFICIENCY (%) 41.3
POWER PLANT EFFICIENCY (%) 39.2
OVERALL ENERGY EFFICIENCY (%) 39.2
COAL CONSUMPTION (LB/UWH) o.sos
TOTAL WASTES (LB'/kWH) 0.343
PLANT CAPITAL COST ($ MILLION) 6653.3
PLANT CAPITAL COST ($/kW ) 722.9
e
COST CF ELECTRICITY, CAPACITY FACTOR = 0.65
CAPITAL (MILLS/kWH) 22.9
FUEL (MILLS/kWH) 8.7
MAINTENANCE & OPERATION (MILLS/kWH) 2.5
TOTAL (MILLS/kWH) 34.1
ESTIMATED TIME OF CONSTRUCTION (YEARS) 5.5
APPROXIMATE DATE OF FIRST COMMERCIAL SERVICE 1987 - 1989
212
-------
Table 80
COST OF ELECTRICITY (COE) SENSITIVITY
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
COE,
COE,
CAPITAL
FUEL
COE, O&M
TOTAL COE
Base
Capacity
Factor
0.65
22.9
8.7
2.5
34. 1
Fuel
Cot*;
Increase
50%
22.9
13.1
2.5
38.4
Labor
Cost
Increase
20%
24.2
8.7
2.5
35.5
Materials
Increase
20%
26.1
8.7
2.5
37.3
Capacity
Factor
Change
0.5 & 0.8
29.7 18.6
8.7 8.7
2.6 2.4
41.0 29.7
213
-------
8. PFB ALTERNATIVE ffl (1750 F)
In addition to the basic plant of Figure 27 with 1650 F beds, a PFB
power plant with 1750 F main beds was evaluated. The intent was to minimize
the changes from the basic plant concept so that the differences in performance
and cost could be sharply defined. The PFB, gas turbines, hot gas filters,
feedwater heaters and economizers, and steam turbine cycle were components
subject to major variations.
The specifications for the PFB module retained the identical fuel rate
and the identical air flow for combustion at the PFB as in the base case.
*Ihe gas flow into the gas turbine was identical to the former cise; only
the inlet temperature was increased from 1600"F to 1700 F. •.
PFB Tower Costs ,_. ••
The PFB tower would increase from 13 ft diameter to 13.5 ft diameter;
The height of 116 ft would be unchanged. T-fee bed dimensions would increase
from 8.5 ft on each side to 8.75 ft on each side. These changes would .
increase the cost of the FFB towers by $250,000 for the total plant.
Hot Gas Cleanup Costs
* AC
The ducting and cyclonfe separators for the hot gas flow would be
unchanged. The granular bed filters must increase in size and cost to
experience the same face velocity with the greater volume of gas flow.
This ratio is 1.0485. As a result the granular bed filters and the air
compressors that service them will have an added cost of $2,040,000. An
audit of pressure loss from compressor outlet to gas turbine inlet shows
that the 7.5 psi loss would then become 7.35 psi.
Gas Turbine Cost
The gas turbine flows and power were derived by scaling up the 1700 F
gas turbine applicable to the PFB for the ECAS potassium topping cycle so
as to match exactly the air required by the PFB in this instance. The gas
turbine generation became 55.682 MW. The cost for the gas turbines was
scaled at $125/kW to arrive at an added cost of $2,216,000 for the four gas
turbines required by each plant. Table 81 gives a comparison of gas turbine
characteristics. The configurations would have the same general dimensions
as the base case. Pressures at each station would be identical, as would
the air delivery temperature of 597 F to the PFB.
Steam Turbine-Generator Cost
A heat balance on the PFB towers, the Petrocarb cooler economizers,
and the gas turbine economizers shows a total heat input to the steam cycle
of 5984 MBtu/hr; th
-------
Table 81
GAS TURBINE PERFORMANCE AND COST COMPARISON
PFB main bed temperature 1650 F 1750 F
Gas turbine inlet temperature 1600 F 1700 F
Compressor inlet air flow, Ib/s 525.75 530.19
Air flow to PFB, J.b/s 504.72 504.72
Gas flow back to turbine, Ib/s 551.16 551.16
Exhaust gas flow, Ib/s 571.13 576.58
Exhaust temperature 849.9 F 912.4 F
Generator output, MW 51.25 55.682
Unit cost, M$ 6.41 6.74
Number per plant 4 4
Exhaust heat to 300 F, MBtu/hr 309.56 335.33
215
-------
i Table 82
PFB HEAT SOURCES FOR STEAM CYCLE
Source MBtu/hr
PFB main bad temperature 1650 F 175Q F
4 Petrocarb cooler economizers, E 22 22
A
4 Gas turbine economizers, E 1238 1341
4 PFB towers 4844 4621
Total heat to steam cycle 6105 5984
Total heat ratio to 1650 F case 1.0 0.980
216
-------
For a 1750 F PFB cycle as described by Figure 27, the steam turbine
output would become 723,960 kW. The difference of 14,673 kW less would
reduce steam turbine~generator cost by $210,000 at the rate of $14.3/kW.
Gas Turbine Economizers
The gas turbine economizers will receive hotter gas and deliver hotter
water. A heat balance was made to determine these resulting temperatures
and to arrive at the log mean temperature difference for.heat exchange.
The heat exchanger cost was then proportioned directly with heat duty and
inversely with log mean temperature difference. The assumption of the same
heat transfer coefficient and a constant ratio of cost per unit area are
justified for such a modest change in conditions. Table 83 details this
evaluation.
The cost difference for the total plant for gas turbine economizers
would be an increase of $145,000.
Balance-of-Plant Costs
>*"
BOP cost items may be affected by any of the following ratios:
Hot gas cleanup size ratio *•• 1.0485
Steam turbine size ratio 0.980135
Total and net generation ratio 1.0034
Economizer size ratio 1.0581
The BOP items were adjusted by these ratios as shown in Table 84.
PFB Net Generation (1750 F)
A detailed auxiliary loss breakdown was made with no change it: PFB
auxiliary losses, steam turbine and heat rejection elenents'scaled by a 0.98
factor, and generation-related factors scaled by 1.00V' relative to losses
shown in Table 31. The total loss was 39.87 as compared to 39.86 formerly.
Net station output could then be evaluated as indicated in Tabl1? 85.
PFB Net Plant Cost (1750 F)
Table 86 summarizes the several changes in major component and BOP
costs, applied fee, contingency, and other factors to arrive at the net
station dollars per kilowatt.
Cost of Electricity Comparison
Table 87 compares the COE for the two cases. The efficiency, coal
consumption, and fuel cost of electricity will be virtually the same. The
major change was due to increased capital cost.
217
-------
Table 83
ECONOMIZER DESIGN AND COST BASIS
Bed temperature
Heat duty^ MBtu/hr
Gas T in/T out
Water T in/T out
Difference in temperatures
Log means temperature difference
Cost per unit, M$
1650 F 1750 F
309.56 335.25
865 F/300 F 912.4 F/300 F
537 F/250 F 559.2 F/253.5 F
328 F/50 F 353.2 F/46.5 F
H7.79 F 151.26 F
0.627 0.66346
Table 84
BOP ADJUSTMENTS FOR 1750' PFB FROM 1650 PFB BASE CASE
BOP Items
1.3 Hot gas cleanup (a)
(b)
3.2 Main circulating pumps
3.4 Main condensers
3.5 Heaters, Exchangers
3.12 Cooling towers
4.0 Electrical
5.4 Cooling tower basins
6.1 Steam and feedwater piping
6.3 Other large pipes
Total difference in MH 1000's
Total difference BOP Mat
Direct labor at 11.75 $/hr
Indirect labor at 10.58 $/hr
Total BOP change
Former BOP cost
New BOP cost
Changes
-1
-149
- 12
- 10
-171
162 700
162 529
Factor
MH 1000's
+1.84
+2.96
_
-0.54
-
-1.13
+2.73
-1.99
-0.99
-3.87
Mat. $1000's
+ 4.85
+94.09
-16.49
-47.08
-28.80
-48.67
+37.16
-30.00
-47.68
-66.53
1.0485
1.0485
0.9801
0.9801
0.9801
0.9801
1.0034
0.9801
0.9801
0.9801
218
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Table 85
POWER GENERATED BY PFB POWER PLANTS
Gas turbine generation
Steam turbine generation
Gross generation
Auxiliary power loss
Net station output
Power Generated at
2 Main Bed Temperatures (HW)
1650 F
205.0
738.6
943.6
39.9
903.8
1750 F
222.7
724.0
946.7
39.9
906.8
219
-------
Table 86
SUMMARY COSTS FOR 1750 F PFB
Item Changed
Balance-of-plant cost
Steam turbine generator
Gas turbine generators
PFB towers
Hot gas filters
Gas turbine economizers
Subtotal, all changes
1650 F Case total
*~
1750 F Case total
AE home office & fee
-------
Table 87
COMPARISON OF COST OF ELECTRICITY - PFB
I
Main be
-------
9. PFB ALTERNATIVE //2-HIGH EFFICIENCY (1750 F)
A greater efficiency may be gained from the PFB cycle If the steam tur-
bine cycle has high-temperature £eedwater heaters that operate on part of
the feedwater flow. The balance of the flow would be heated by a gas feed
heater (GFH) which is truly the low-temperature portion of the gas turbine
economizer. Then the total feedwater flow would enter the high-temperature
portion of the gas turbine economizer. This arrangement is Identical to
that used for the EGAS potassium topping steam PFB and gas turbine cycle.
The economizers must have increased surface area and cost as a result of
their lowered mean effective temperature difference. The total heat avail-
able to the steam cycle is unchanged. The PFB would have altered propor-
tions of heat exchange surfaces because of increased feedwater temperature
of 640 F. The PFB configuration, size, and cost are not expected to differ
from the 1750 F case discussed previously. Major changes are found in the
economizers, the steam turbine cycle, and parts of the balance of plant. These
changes are most readily understood by examining the steam turbine cycle first
and then the gas turbine economizers.
Steam Turbine Cycle and Heat Balance
The steam curbine heat balance presented in Figure 37 is more nearly
like the APB turbine cycle than it is like the PFB turbine cycle of Figures
26, 27, and 31. The feedwater flow is split after the third low-temperature
heater. Four high-pressure feedwater heaters pass 56.5 percent of the total
feed-water flow. The Petrocarb compressor cooler (PCC) h°fts 1.6 percent of
the total feedwater flow. The gas feedwater heater (GFH) cools the gis tu>--
bine exhaust from 560 F to 300 F while heating 41.9 percent of the total
feedwater flow. All of these heaters deliver feedwater at 505 F. The total
feedwater flow then passes through the gas turbine economizer where the gas
cools from 912.4 F tc 560 F as the feedwater is heated from 505 F to 640 F.
The distribution of feedvater flow and heat duty are detailed in Table 88.
The increase in steam turbine output results in an increased component
cost of $22,000 at $14.28/kW.
The cost of the feedheater train must be derived from the AFB steam
cycle, which was similar. It was determined that feed-heater surface aiea
varied linearly with heat duty for both high-pressure and low-pressure
units. The heat duty for the seven-feedwater heaters using extraction
steam in Figure 37 is 0.5534 of the heat duty for the A7B steam turbine
cycle. The. flows and duties of the low-pressure feedwater heaters of the
steam cycle bear a ratio of 0.9027 to the AFB cycle. The cooling duty is
a ratio of 0.945 to the base PFB steam turbine cycle. Other significant
ratios were derived from the appropriate flows, powers, and heat duties
of the steam cycles.
Gas Turbine Economizer Cost
Economizer size and cost were estimated on a preliminary basis by the
Foster Wheeler Energy Company, When final values for heat duty and log
222
-------
ro
U)
If. li - Kn*l.*l|ir •
vBiir*. PiU
F - Temperature. F d«|r«at
GKNERAIOII OUTPUT
740,153 M
Tl PSIC II2 PR CSS.
0. It PF
1 |(W I. 2. )•• llc. AI.>. 0% MU
TC-IK. »*. '/' I.SH luuu ttl'M
IMIO I'.'illi lUUU/IOUil-r'
Figure 37. High Efficiency 1750 F PFB Plant Steam Turbine Cycle Heat Balance
-------
Table 88
HEATING DUTY FOR HIGH EFFICIENCY
PFB PLANT STEAM CYCLE
Heat Duty Flow
Heat Exchanger (MEtu/hr) (% of feed)
PFB to reheater 1071.0 94.1
PFB to superheat 3549.73 100.0
Gas turbine economizer 787.8 100.0
Gas turbine gas feed heater 535.55 41.90
Petrocarb compressor cooler . 21.65 1.64
Steam turbine high-pressure feed heaters - 56.46
Total heat to steam cycle 5983.73
224
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mean temperature difference (LMTD) were available, the preliminary size
and cost were scaled up or down appropriately, as shown in Table 89.
The plant economizer component cost difference would be $4.41 million
which is four times the per unit difference of Table 4,2-29. The erection
man-hours and BOP materials related to the economizers were scaled'from the
1650 F PFB case using the total heat exchange surface area ratio of 2.58 as
the scaling factor..
Balance of Plant Adjustments
BOP cost items were proportioned to comparable heat duty, flow rate,
or power level for the 1650 F PFB or the 1550 F AFB as was deemed most
appropriate. The comparison source, AFB or PFB, and the ratio used are
indicated in Table 90 along with the changes in man-hours of .direct labor
and materials cost. Item 6.3, "Other large pipe," was scaled to the steam
turbine cycle flows after the reheat turbine at pressure levels below 200
psia. Item 3.5, "Heaters, exchangers; Economizer erection,11 was subdivided
into economizer-related costs, and steam turbine cycle steam-heated feedwater
costs. The scaling factor for the latter was 0.553 based on the ratio of the
heat duty of the feedheater trains.
T*~ *' •
<>~
Auxiliary Loss and Net Generation
- ^i* •
The auxiliary losses of Table 66 were reapportioned using the same
basic ratios as were used- for the BOP adjustments. Since all ratios must
be referred to the 1650 F PFB case and not to an AFB, items related to flows
or condenser heat duty in the low-pressure portion of the plant used the ratio
0.945. The furnace items have been grouped in Table 91 sirce they are identical
to the values of Table 66. The closeness of the final results is due to the
offsetting effects of the many changes.
The net generation and efficiency improvement shown in Table 92 result
from the increased steam turbine output resulting from the more elaborate
feedwater heating system.
Net Plant Cost
Table 93 summarizes the several changes in major component and BOP
costs. The fee and contingency and escalation and interest during construc-
tion are added to find the total expenditure for the plant. Division by
the net station output gives the cost of $728/kW.
Cost of Electricity Comparison
Table 94 summarizes the effect on the cost of electricity for the sev-
eral alternatives of PFB power plants. The 1750 F cases entail greater cost
for the gas turbine and the hot gas filters. The output change is minimal for
e o
225
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Table 89
PFB GAS TURBINE ECONOMIZERS COST BASIS
Heat Duty LMTD Area Cost
Heat Exchanger (MBtu/hr) (°F) (ft2)
1650 F PFB economizer 309.6 147.8 179,326 0.627
1750 F PFB economizer preliminary 197.5 145.3 135,946
1.724
GFH preliminary 138.8 135.8 304,357
1750 F PFB economizer "• - 197.0 57.0 145,080
1.730
GFH final '138.4 58.4 296,230
226
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Table 90
BOP ADJUSTMENTS FOR 1750 F PFB HIGH EFFICIENCY PLANT
FROM 1650 F PFB BASE CASE
Labor Material
Source Item Ratio (MH:lOOP's) ($ 1OOP's)
PFB 1.3 Hot gas cleanup 1.0485 (a) 4- 1.84 + 4.85
(b) + 2.96 + 94.09
AFB 3.1 Boiler feedpumps 0.786 - -f 100
AFB 3.2 Main circulating punips 0.903 - - 117
AFB 3.4 Main condenser 0.903 - 3 - 95
AFB 3.5 Heaters, exchangers 0.553 (Part only) - 22
PFB 3.12 Cooling towers 0.945 - 3 - 134
PFB 5.4 Cooling tower basins 0.945 - 5.5 - 83
PFB 4.0 Electrical 1.020 +16.5 + 224
PFB 6.1 Steam & feed piping 1.091 +4.6 + 217
PFB 6.3 Other large pipe 0.945 -10.7 - 184
PFB 6.5 Economizer erection 2.58 (Part only) +31.6 + 284.4
Total difference, MH 1000's +35.3
Total difference, BOP materials + 289
Direct labor at $11.75/hr + 415
Indirect labor at $10.58/hr of direct labor + 373
Total BOP change from 1650 F to 1750 F, high efficiency + 1,078
Former BOP cost 162,700
New BOP cost, 1750 PFB, high efficiency 163,778
227
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Table 91
ADVANCED STEAM—PRESSURIZED FLUTDIZED BEDS
Plant Configuration
Furnace auxiliaries
**
Solids handling
Steam turbine auxiliaries
Gas turbine auxiliaries
Pumps
Condensate
Circulating water
Service water
Intake water
"Hotel" loads
Cooling tower fans
Transformer loss :,
Total auxiliary power
Auxiliary Loads at 3
Main Bed Temperatures (MW)
1650 F 1750 F 1750 F
Base Base High eff
10.39
2.17
2.37
2.16
0.95
4.40
0.89
0.94
8.34
2.53
4.72
39.86
10.39 10.39
2.17 2,17
,.2.32 2.37
2.35
0.93
4.31
0.89
0.92
8.37
2.48
4.73
39.87
2.35
0.90
4.16
0.89
*~
0.88
8.51
2.39
4.82
39.83
228
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Table 92
POWER GENERATED BY PFB POWER PLANTS—SUMMARY
Plant Configuration
Gas.turbine generation
Steam turbine generation
Gross generation
Auxiliary power consumption
Net station output
Overall tnergy efficiency
Power Generated at 3
Main PFB Bed Temperatures (MW)
1650 F 1750 F 1750 F
Rase Base High eff
205.0 222.7 222.7
738.6 724.0 740.2
943.6 946.7 962.9
39.9 39.9 39.8
903.8 906.8 923.1
39.2%
39.3%
40.0%
229
-------
Table 93
SUMMARY COSTS FOR 1750 F PFB HIGH EFFICIENCY PLANT
Item Changed Change (M$)
Balance of plant cost +1.078
Steam turbine-generators +0.022
Gas turbine-generators 2.216
PFB towers .25
Hot gas filters 2.04
Gas turbine economizers 4.41
Subtotal all changes 10.02
1650 F case total 327.25
1750 F high efficiency total 337.3
AE office and fee @ 0.15 x 163,8 24.6
Total plant cost without contingency 361.8
Contingency at 20% 72.4
Total capital cost 434.2
Escalation and interest during construction 237.9
Total expenditure for plant 672.1 M$
Plant net output 923 MW
Specific cost 728 $/kW
230
-------
Table 94
COMPARISON OF COST OF ELECTRICITY FOR PFB PLANT ALTERNATIVES
Cost of Electricity at 3
Main Bed Temperatures
PFB Plant Configuration !Lf ° F "^ F ™ !f
° !— Base Base High eft
Plant capital cost $kW 723 729 728
Overall energy efficiency 39.2 ,39.3 40,0
Cost of electricity, mills/kWh
Capital 22.3 23.1 23.0
Fuel ,..: .«- 8.7 8.7 8.6
Operation and maintenance 2.5 2.5 2.5
7*- *• : ' '
Total 34.1 34.3 34.T[
Basis: 5.5 Years to Construct; 0.65 Capacity Factor
231
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a fixed steam turbine cycle configuration. The more complex plant cycle with a
gas feedheater operating in parallel with steam feedheaters gains in efficiency
and reduces the total cost of electricity at 1750 F. A similar finding would
be expected at 1650 F. The differences in cost of electricity are small as is
.the 2-percent savings in fuel at the extreme. Other factors should dictate the
plant configuration and design specifications vhen the impact of appreciable
changes in temperature level and complexity bring such small changes in
efficiency and cost of electricity.
232
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E. PLANT CONCEPTUAL DESIGN AND BALANCE-OF~PLANT COST
1. TOTRODUCTION
The primary objective of the balance of plant portion was the achieve-
ment of a consistent level of detail and the development of compatible
capital cost projections. In order to achieve this objective, similar
subsystems were employed for the common cycle elements and consistent ground-
rules and costing methodology were used.
In an attempt to itemize balance-of-plant capital costs, symmetrical
arrangements were used for the major components. This permitted employment
of the shortest runs of high-temperature piping. To the greatest possible
extent, existing technology was utilized for the common subsystems.
The groundrule criterion which had a significant influence on the plant
layout was a requirement for a 60 day on-site storage of fuel. The fuel was
assumed to be delivered.to the plant site by unit train.
Off-site solid waste disposal was assumed with removal fro™, the plant
site by train or track. A 15-day interim on-site storage was provided for
the solid waste.
The "North River" was available for obtaining the plant makeup water
supply. Waste w?ter was treated before returning to the river for discharge.
There was no thermal rejection into the river.
In most respects, the balance-of-plant requirements for the fluidized
bed plant concepts are similar to those for conventional power plants. The
balance-of-plant items which were considered were:
' Fuel storage and handling involves the receiving, storage, and
delivery to the combustion system of coal and limestone additives.
* Equipment installation includes installation of the combustion and
primary energy conversion equipment as well as erection of the entire
plant facility.
" Thermal cycle heat rejection includes cooling towers, circulating
water pumps, and piping.
• Plant enclosure includes buildings for plant administration, control,
turbomachinery, and furnace systems. (The geographic location of
the plants in this study necessitates enclosure of most of the plant
equipment.)
233
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* Electric energy output provisions include bus bar, switchgear,
transformers, and wira to conduct the generated electric energy to
the plant high voltage switchyard. -;,.-
" Plant control includes instruments, recorders, computers, and all
other equipment necessary to monitor and control the power.plant:.
Site preparation includes excavation, roads, fences, and landscaping.
The variety of energy conversion systems included in this study resulted
in many plant support subsystems which required definition.and cost.esti-
mate!?. The subsystems unique to the individual energy conversion systems
are described in each individual conversion system section end plant layout
drawings, equipment lists and cost breakdowns are presented. The balance-
of-plant subsystems which are common to several conversions systems are
discussed in this section. These subsystems were appropriately scaled to.
adjust for difficult capacity requirements.
234
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2. BALANCE-OF-PLANT SUBSYSTEMS
Coal and Sorbent Receiving, Handling, and Storage
• All coal is delivered by unit trains to the plant. The plant coal-
handling .system must unload the trains, move the coal to outside storage
piles, reclaim the coal from storage as needed by the plant, and deliver
the reclaimed coal to hoppers at the combustor feed system. Coal storage
capacity of each plant is 60 days at rated energy output.
For the AFB and PFB plants dolomite or limestoi;° sorbent material is
mixed and injected with the coal. Thus a receiving, storage, and handling
system similar to that for coal is provided for this material. This also
requires provision for 60-days of storage capacity.
Plant requirements that significantly influence the selection, sizing,
and arrangement of equipment for receiving, handling, and storage of coal
and solid sorbent material are the following:
»
Live storage of sufficient fuel to supply the plant for 3 days nt
rated capacity.
Dormant storage of sufficient fuel to supply the plant for 60 days
at rated capacity.
Rail delivery by unit train of coal and/or sorbent material with
motor truck access as an alternate.
Coal
Figure 38 shows the general arrangement of coal receiving, handling,
and storage facilities for all plants. This concept includes two conLcal
active storage coal piles and a 60-ft high dead storage.
Coal will be transported from the mine in unit trains consisting of
bottom discharge cars. Cars will discharge the coal into under-track
hoppers; the coal from these hoppers vlll be fed to two horizontal collecting
belts for feeding thr coal to the main 60-in.t 3000 ton/hr belt conveyor.
This high capacity belt will rapidly unload the unit train contents to the
active storage piles. Train unloading time is less than four hours. To
account for the coal received at the plant, the coal vill be weighed in the
scale house and representative samples of "as received" coal will be collected
In the sampling station. The sampling station tower, houses the coal sampling
equipment, transfer hoppers, and drive equipment for the Inclined conveyor to
the active storage piles.
The two active, storage conical piles are formed by discharging the coal
into the lowering wells at each pile. The lowering well tubes also serve as
support structures for the conveyor belts. Coal from the active storage is
fed to a 500-ton/hr conveyor by hopper feeders under the coal pile. A tunnel
has been provided for personnel emergency exit from the Installation under the
coal pile.
235
-------
ro
iv*w o'a* ^—.-r.
T'-^'U^' 1
. j- I -»^ 3; >*!>—V -
S~^T"~"^r*T
| • »S.>tV-0"
A
A_
A
A
REC1TEI
GE/NASA
ADVANCED CYCLES STUDY
PHASE!
COAL HANDLING SYSTEM
SK-OM1
Figure 38. Coal-Handling System (Bechtel)
-------
Dead storage of coal for each of the plants is based on the 60-day
full-load requirement; and the active storage is for three days, without the
need for bulldozing. In an emergency, coal can be bulldozed from the dead
storage pile and transported by the emergency reclaim conveyor to meet the
plant requirements.
In anticipation of probable future needs to thaw frozen incoming coal,
space has been provided for the thaw and soak sheds for railroad cars. Coal
lump crushers have been provided between the active and the emergency coal
reclaim systems and the boiler plant, to break up the oversize frozen coal.
It is expected that coal falling on the grizzly will also aid in breaking
up the frozen coal lumps.
The coal handling, storage and processing capacities as required for
each plant are included in the discussion of each plant.
Sorbent Material
The sorben? material will be delivered in bottom discharge railroad
cars. The general arrangement of the limestone or dolomite receiving,
handling, and storage equipment is similar to the corresponding coal systems.
Sorbent material is unloaded into the same under-track hoopers as the
coal,-and discharged to the main coal conveyor belt for transport up to the
first lowering well structure of the coal pile. At this point the sorbent
material is diverted to the 3000-ton/hr conveyor supplying the lovpvin^ woil
of the active sorbent material storage pile. Sorhent material is weighed in
the scale house and samples o.btained using the coal sampling equipment, after
taking necessary precautions not to contaminate the sample with coal remains.
Sorbent material from the active pile is transported to the distribu-
tion bin by a 36-in., 125-ton/hr conveyor. The dead storage is adjacent to
the active'^storage and is built up by moving material from the active storage
with mobile equipment such as 3 bulldozer or a scraper.
Water Treatment and Disposal
Water for each plant will be withdrawn from the North River (Middletown,
U.S.A.) and treated for distribution to the plant water systems. It is
assumed that the river water is of moderate hardness, is somewhat turbid,
and has a total dissolved solids (TDS) level of about 250 mg/1. A raw water
Storage pond is provided to settle out suspended solids and to serve as a
surge volume during period of high turbidity or low flow in the river.
The-river intake pumps supply water to maintain a sufficient level in
the storage pond for about 3 days' makeup requirements/ Suspended solids in
the river water settle out in the pond, which will be dredged periodically
to remove accumulated silt.
Water is treated to meet the various water use quality requirements.
Wastewaters are treated to meet EPA new source standards for the steam
237
-------
electric power generating category. There will be no waatewater discharge
from ash handling.
Water Treatment
Figure 39 presents a generalized water treatment flow diagram. Raw
water from the storage pond is used directly for water makeup where appli-
cable. Water is pumped from the pond into the supply header and distributed
to the plant water systems.
Makeup to the recirculating cooling water system replaces evaporation,
drift, and blowdown losses. The recirculating water is treated with sulfuric
acid for scale control and, periodically, with chlorine for control of
fouling organises.
Raw water used in the potable, utility, and boiler feedwater systems
(general plant use) is cold lime softened and filtered. A storage tank
provides an assured source of fire water in the process area. Sludges from
softening and filtration are pumped to the sludge handling system.
The potable water supply is disinfected with sodium hypochlorite using
a conventional contact system. Utility water is usually used without
further treatment for such purposes as bearing, gland and sample cooling,
fire extinguishing water, and general washdowns. Special uses include fuel
gas cleanup (combined cycle gas turbine-air cooled) and liquid fuel washing
and NOX suppression (combined cycle gas turbine-water cooled).
Boiler feedwater is demineralined in SA ion-exchange system consisting
of parallel trains, each having a cation (H) bed, an anion (OH) bed, and a
mixed resin bed in series. The ion-exchange beds are regenerated periodi-
cally with sulfuric acid and caustic. Spent regenerates and rinse waters
are routed to waste treatment facilities. Demineralized water from the
storage tank and polished condensate are deaerated before being pumped to
the boiler drum. Chemicals are added to t.he water in the deaerator to
control scaling and corrosion in the boiler system (ammonia, hydrazine, and
trisodium phosphate). Water treatment equipment, except for the storage
ponds, is treated as a package unit for cost estimating.
Wastewater Treatment and Disposal
In general, wastewater from various sources are segregated and treated
to meet the applicable discharge limitations. Treated wastewaters are then
combined in a final holding pond for gravity discharge to the North River
downstream of the plant intake system. Figure 39 illustrates generalized
wastewater treatment systems, sense or all of which are applicable to each
power plant cycle.
Wastewaters are treated to innet the EPA new source standards for the
steam electric power generating category.
238
-------
— — w » c t R TBt»TMi:nT
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Figure 39. Water and Wastewater Management
-------
Cooling Tower Blowdown. Corrosion resistant materials are used In the
recirculating water system to eliminate the need for corrosion inhibitors.
Blowdown is taken from the cool side of the recirculating water system to
meet the thermal discharge requirement. The pH of the recirculating water
is maintained above 6.0 so that no adjustment is needed. The. available
chlorine specification limit in the blowdown stream is met by careful
control of the residual chlorine in the recirculating water and by tempo-
rarily shutting off the blowdown if the chlorine residual is too high. The
blowdown, therefore, is discharged directly to the final effluent pond
without any need for treatment. The final holding pond provides holding
time for decay of any residual chlorine.
Boiler Blowdown. Blowdown from the boiler drums is moderately alkaline
and of very high quality, oil-free, and low in TDS and TSS. No treatment
is needed other than blending this otream with other wastewaters to lower
its pH before discharge.
Metal Cleaning Wastes. Wastewaters are generated periodically by
routine maintenance cleaning-of heat transfer surfaces and cleaning of
miscellaneous equipment. Cleaning wastes, both acidic and basicr contain
dissolved chemicals and metals. The wastes from cleanouts are collected in
storage tanks and worked off at a low rate over several weeks in a reactor-
clarifier system in which lime is used to maintain a moderately alkaline pH
of 8.5-9.0. Metal hydroxides -are precipitated and removed as an underflow
sludge stream. Clarifier overflow is routed for final pH adjustment to the
surge basin that accepts other process wastes.
Low Volume Wastes. Low volume wastes include demineralizer brines and
rinses, lab end sample wastewaters, floor drainage, and other utility water
blowdowns. These are collected in a surge pond, skimmed of oil, neutralized,
and settled before discharge to the final holding pond.
Area Runoff. Yard drainage and runoff from material storage areas are
collected in settling basins sized to impound the runoff from a worst case
10-year storm of 24-hr duration (4-in. rainfall assumed).
Provisions are included to neutralize the runoff prior to discharge to
the final holding pond. Settled runoff is expected to meet the 50 mg/1 TSS
discharge limitation.
Sanitary Wastewater. Sanitary wastewater is treated in a conventional
extended aeration biological system to meet biochemical oxygen demand (BOD)
and TSS discharge requirements. Treated effluent is disinfected with
chlorine.
Fina . Holding Pond. This pond receives treated wastewater from all
sources and provides about a 2-day holding capacity. Wastewater is dis-
charged through a gravity line to the North River downstream of the intake
pumphouse. Final effluent quality is expected to be:
240
-------
PH 6.0-9.0
Temperature, K 294
TSS, mg/1 30
i 0 & G, mg/1 15
Copper, mp,/l I
Iron, mg/1 i
C. SOLID WASTES HANDLING AND DISPOSAL
The various power plants produce a variety of solid vaste residues
that must be collected and removed from the combustion systems. These
residues range from slag and fly ash from the direct coal-fired MHD system
to the mixed ash and calcium sulfates from the fluid bed combustion systems.
The nature of the collected residue is a function of the combustion system
that generates the residue or of the equipment that separates the residue
from a flow stream. Likewise the residue transport means employed in a
plant design will be dependent on the combustion process and/or separation
equipment.
Fluidized Bed Combustion Systems
The approach to collecting the fluidized bed combustion systems resi-
dues is to consider them as being dry and relatively cool for transport by
covered conveyor belt.to surge bins at the rail spur. These surge bins
unload normally into covered rail cars, or alternatively into motor trucks,
for residue removal off site for disposal. In order to allow for plant
operation in event of temporary transportation disruptions, on-site residue
storage silos are also provided near the rail spur. These storage silos
are sized to hold up to 15 days of plant residue production at plant rated
operating conditions. The silo storage system would be used intermittently
and is not part of the active conveyor system that continuously removes
solid residues from the plant's combustion system equipment.
Maintaining the fluidized bed residues in a dry condition while trans-
porting to a final disposal area is most important. These residues are
mixtures of ash, noncombusted particles from the feed coal and calcined
lime. Should the mixture become wet, it will harden. Therefore, the
fluidized bed residues must be kept dry until final disposal.
D. HEAT EXCHANGERS
Condenser
All steam condensers are sized to provide a condensing pressure of
2.3-in. Hga under standard day design conditions in which circulating water
temperatures are 70.5 F at the condenser inlet and 100.5 F at the outlet.
Tubes in all steam condensers are assumed to be 1-in. outside diameter BWG
#18 a wall thickness of 0.049-in. Tubes are assumed to occupy 22.5 percent
of the tube sheet cross-sectional area. The overall heat transfer coefficient
for these condensers is assumed to be 600 Btu/hr ft^°F.
241
-------
c.
Deaerating Heater and Tank
The deaerating feedwater heaters are assumed to have an overall heat
transfer coefficient of 600 Btu/hr ft2°F, The storage tank capacity is sized
to contain five minutes of the total boiler feedwater flow.
Feedwater Heaters ;
Heat transfer tube surface requirements for closed feedwater heaters
in the study are calculated by assuming an overall heat transfer coefficient
of 600 Btu/hr ft2°F. •
E. PIPING
Pipe Siring
Piping diameters were selected on the basis 01 'von mass flow rates
and velocities v;hich are representatively selected from power plant design
experience for the classes of flows under consideration. Approximate
velocities assumed in the study for conventional flows are:
Fuel oil "- 5 ft/s
Service water 8 ft/s *7
Boiler feedwater 20 ft/s
Saturated steam *"" 150 ft/s
Superheated steam 300 ft/s
Once the internal pipe diameter is determined, pipe wall thickness is
calculated based upon the ANSI B 31.1 Power Piping Code for minimum wall
thickness.
The allowable material stress, is taken from the-ASME Code for
pressure piping and depends on both the pipe material and the design
temperature.
Pipe Materials
Following conventional steam-electric plant practice, pipe material is
A106 carbon steel for water and steam lines under 850 F (for example, boiler
feedwater, cold reheat, condensate, process water) and 1-1/4 chromium — 1/2
molybdenum for steam lines from 850 F to 1100 F (for example, main steam and
reheat). Mid-1975 costs for fabricated carbon steel and chrome-moly piping
are estimated at $1.10/lb and $2.00/lb, respectively. Additional allowances
for fittings, hangers and supports, installation labor operations, and
insulation were developed from power plant construction cost reports and are
included in the piping estimates.
For the PFB, hot gas piping is carbon steel with internal refractory
lining. Refractories were selected on the basis of temperatures and fluid
242
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conditions at the hot surface. Double-layer linings are employed in very
high temperature applications and use a high-temperature refractory at the
hot surface backed up by a more highly insulating low-temperature refractory
adjacent to the carbon steel shell. Characteristics of refractories used
in hot gas piping are given in Table 95.
An internal liner of Incoloy 800 is included in the PFB gas turbine
inlet piping to prevent refractory particles from entering the turbine £as
path. The fabricated liner (usually 0.125 in. thick) is estimated at
$16.00/lb.
As in the conventional piping estimates, additional allowances are
included in the unconventional piping estimates for fittings, hangers and
supports, installation labor operations, and anchors for refractory linings
where applicable.
F. COOLING TOWERS AND CIRCULATING WATER SYSTEMS
f
All plants used cooling systems employing evaporative, mechanical draft
cooling towers. This type of tower was selected because of its minimum
capital cost features and its ease of application to a wide range of thermal
load requirements by use of multiple tower cells operating in parallel.
The Middletown, U.S.A., site is near a river which can supply suffi-
cient quantities of cooling water makeup as well as receive treated blow-
down water. The following atmospheric conditions at Middletown have been
used as the design conditions:
Wet bulb temperature - 51.5 F
Dry bulb temperature - 59 F
Relative Humidity - 60%
Design Conditions. To achieve an absolute pressure of 2.3 in. Hga
in the steam condensers requires that the equilibrium condensing temperature
be maintained at 105.85 F. This is the heat source design temperature for the
cooling water system.
The heat sink design temperature is the design wet bulb temperature
of 51.5 F. An approximate minimum cost cooling system is achieved by using the
following working temperature differences for the cooling system components:
a. Terminal Temperature Difference (TTD) is the difference between
steam condensing temperature and the hot cooling water temperature
leaving the condenser. The TTD used was 5.35 F.
b. Range is the temperature difference between the hot cooling water
to the cooling towers and the evaporatively cooled water in the
cooling tower basins. The Range used was 30 F.
c« Approach is the temperature difference between cooling tower basin
water and the ambient wet bulb temperature. The approach used was
19 F.
243
-------
Table 95
REFRACTORY MATERIALS
Type
Brick
Cas table
Cas table
Brick
Cas table
Brick
Block*
Cas table
Max. Temp.
at Hot Surface
3300 F
3300 F
2800 F
2600 F
2300 F
2000 F
1900 F
1800 F
Thermal Conductivity
(Btu in /hr ft2 °F)
5.3 @ 2500 F
5.5 @ 2500 F
4.9 @ 2000 F
2.8 @ 2000 F
2.1 @ 1500 F
2.1 @ 1500 F
0.7 @ 1000 F
1.7 @ 1000 F
Cost per
Linear Ft
$41.80
41.00
40.00
11.20
9.55
8.60
6.00
7.00
*For second-layer, backup insulation use only
244
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These temperature relationships for the cooling system are Illustrated
by the Figure 40.
Applying the Reference cooling tower design techniques with the above
conditions of wet bulb temperature, range, and approach provides a tower
unit raring factor (RF) of 1.473. Under these service conditions, large
mechanical draft cooling tower cells are rated at a recommended 15,750 tower
units (TU) per cell, and each cooling tower cell has a rated water flow
capacity of 10,692 gpm.
The standard dimension of each cooling tower cell was 75 ft (6.97 ra)
wide by 36 ft long by 47 ft high. Each cell contains one circulating fan and
motor of 150 fan horsepower which induces the air draft through the two opposite
sides"of the cell.
The heat dissipation capacity per cell is 1.6 x 108 Btu/hr-cell.
Fan motor power per cell, assuming 97.5 percent motor efficiency, is
115 kWe/cell.
Water consumption rate per cell consists oft wo components: (1) water
evaporation to the atmosphere and (2) basin blowdown water to prevent an
excess accumulation of dissolved solids in the*cooling-water system. The
water evaporation rate, based on prior experience, is approximately 2.1
percent of the rated water circulating rate. Water loss allowance for
blowdown is 0.5 percent of the water circulating rate.
f>
Water Consumption Allowance is therefore*
. Evaporation 220 gpm/cell
Blowdown 53 gpm/cell
Total Consumption 273 gpra/cell
Circulating Water System Design
Circulating water systems serve to pump water from the cooling tower
basins through condensers and other heat exchangers and back to the cooling
towers. Water quantity is determined by each plant's requirements but is
related linearly to the number of cooling tower cells required for each
plant. Large diameter underground piping from the cooling towers to the
pumps and on to the plant, as well as from the plant back to the cooling
towers, is required to achieve a nominal water velocity in the piping
system of 7 ft/s. This velocity minimizes the net cost of the circulating
water system considering installed capital costs and ongoing pumping costs
associated with velocity-sensitive line pressure losses.
Pump sizing for the circulating water systems is based on using a
minimum of three pumps at one-third of plant water flow requirements. This
use of parallel pumps ensures that in the event of a single pump failure,
sufficient cooling water flow is available to permit near normal plant load
adjustment followed by continued part load operation, if needed. The
redundancy also facilitates pump and^motor servicing. Circulating water
245
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Heat Source Temperature = I05.85F (2.3inHga)
Available
Temperature
Difference
54.35F
5.35 F Condenser TTD
t
49 F
30 F Range
19 F Approach
100.5 F Hot Water
Cooling
Towers
70.5 F Cold Water
Heat Sink Wet Bulb Temperature = 51.5 F
Figure 40. Cooling Tower Temperature Differences
2U6
-------
system capacity ±3 related to the number of cooling towers installed in
each plant; thus pump and pipe design parameters are defined per unit
cooling tower cell. Each cooling tower rell requires a nominal water flow
of 10,692 gpra. Pump motor power required per cell is based on these assumptions:
* 15 percent additional capacity allowance
* 80 percent pump efficiency
97.5 percent motor efficiency
* 62 ft of total pressure head
These criteria result in per cell pump power requirements 240 hp/cell
and a motor capacity of 184 kW/cell.
G. EXHAUST STACKS
The exhaust stacks were assumed to be concrete, tapered at 4 percent
with an acid resistant steel liner and stainless steel rain hood. The
liner is insulated on the outer surface. The top 25 feet of the liner and
the rain hood are stainless steel.
Stack foundations are site sensitive depending on local wind loading,
soil conditions, and so on. For cost estimating purposes, all stack
foundations are assumed to be concrete pads 8 ft deep, which exceed the stack
base diameter by 40 feet.
Stack liner diameters are sized by assuming a gas velocity of 90 ft/s
at the exit of all stacks. Stack heights are determined as a function of tons
per day of sulfur dioxide emission per stack. The sizing of stack heights
depends on specific site conditions including prevailing weather patterns, soil
conditions, composition of emissions, and so on.
H. AUXILIARY LOADS
For each plant two basic types of electrical loads are involved. The
first type is associated with major power cycle equipment and is generated
by the equipment suppliers. These loads include furnace auxiliaries and
gas and/or steam turbine auxiliaries.
The second type of electrical load includes all specific equipment
loads and general plant loads associated with balance-of-plant systems.
Electrical loads included in this category and estimating methods for these
loads are:
1. Fan loads, based on required flow rates and pressure differences.
The fan efficiency range is 75 to 82 percent, and the motor
efficiency is 90 percent.
247
-------
2. Pump loads, also based on required flow rates and pressure
differences. The pump efficiency range is 75 to 82 percent and
the motor efficiency is 90 percent.
I. ELECTRICAL SYSTEMS
Systems Description ,
The electrical system for each of the plants is defined by the study
groundrules to include all electrical equipment and associated bulk mate-
rials for both in-plant auxiliary loads and plant output power up to the
500 kV transmission voltage terminals of the main power transformers.
Switchyards are excluded from the plant scope,
The electrical system concepts are illustrated in the form of single-
line diagrams included with the drawings for each energy conversion system.
Specifications for all significant transformers (for example, main,
startup, auxiliary, station service) and the standby diesel generator, sets
are given in the equipment list for each of these systems.
Transformers
• 7"*- ' *
»
The main transformer capacity provided for each plant is based on the
total power generating capacity of the station less the in-plant auxiliary
load. Two one-half capacity transformers are provided.
The capacities of the startup and auxiliary transformers are based on
the expected in—plant startup and operating loads, respectively. Station
service transformers are provided as required so that 13.8 kV power is
supplied to motors greater than 10,000 hp (7457 kWe), 4.16 kV power is
supplied to motors between 250 hp (186 kWe), and 10,000 hp (7457 kWe), and
840 V power is supplied to motors less than 250 hp (186 fcWe).
Standby Power :
Uninterruptible electric power systems for critical a-c and il--c loads
are provided for each plant. A 1,000-kWe diesel generator supplies emer-
gency a-c power to a 480-V critical equipment bus. A 125-V d-c system
consisting of storage batteries and battery chargers are also provided to
supply emergency power through an inverter circuit for a limited time.
This will supply critical loads which may receive emergency power and
include turbine lube oil equipment, lighting, instrumentation, and control
equipment.
Ci
248
-------
COST ENGINEERING METHODS
A. COST ENGINEERING OBJECTIVES
f
The cost engineering objectives for the balance of plant are defined
as providing the following:
Conceptual balance-of-plant construction cost estimates
Balance-of-plant maintenance cost estimates
Estimates of time required for construction
Balance-of-plant costs include: installation costs for major compo-
nents; both purchase and installation costs for all balance-of-plant
material; arid indirect field costs, engineering, home office costs, fees,
and a contingency allowance. Escalation and interest during construction
are excluded from ,the balance-of-plant construction cost estimates.
B. CAPITAL COST ESTIMATE APPROACH
Basis of Estimates
The balance-of-plant construction cost estimates are based on the
following inputs:
Energy conversion system data (for example, cycle diagrams, working
fluids, flow rates, temperatures, pressures, and power ratings).
* Specifications for major components (for example, descriptions.
dimensions, weights, extent of field assembly required, and ancillary
equipment requirements).
" Balance-of-plant data generated in the stut'y (for example, plant
subsystems descriptions, solids-handling daLa, effluents, and water
requirements).
* Balance-of-plant equipment lists generated in the study (for
example, specifications for major pumps, transformers, condenser,
feedwater heaters, main pipe sizes, fans, and stack dimensions) .
" Conceptual plant layout drawings generated in the study including
a plot plan, equipment arrangement plan and elevation, and a
single-line electrical diagram.
An information flow diagram is shown in Figure 41 which indicates
the above inputs, subsequent cost engineering activities working from
these inputs to develop plant estimates, and reference items which were
employed.
249
-------
4.
ro
\ji
o
CYCLE
DATA
(GO
MAJOR
COMPONENTS
SPECIFICATIONS
PLANT
DATA
EQUIPMENT
LISTS
PLANT
DRAWINGS
COORDINATE
ADDITIONAL
DETAIL
B.O.P
c MATERIAL
o LABOR
• SUBCONTRACTS'
1 T
I
I
MAJOR
COMPONENTS
INSTALLATION
ADO
•arrvftFfT
COSTS
--.- ,. . !-. . -...-..-..I *.j
Rrtf>
COST
ESTIMATES
TIME FOU
ENGINEERING AND
CONSTRUCTION
REFERENCES
PROCUREMENT
DEPARTMENT
DATA
VENDORS
« EQUIPMENT
» SUBCONTRACTS
COMPUTERIZED
REGRESSION
ANALYSES
MANHOUR
STANDARDS
CONSULTATIONS
« CONSTRUCTION
• FIELD COSTS
« INDIRECT COSTS
COMPUTERIZED
ESTIMATING
PROGRAMS
CODE OF
ACCOUNTS
PROJECT
FIELD COST
REPORTS
REVIEWS
Figure 41. Cost Engineering Task Flow Diagram
-------
Direct Field Costs
Balance-of-plant (BOP) cost estimate; summaries are presented according
to the format shown in Table 96 and are accompanied by detailed itemized
breakdowns of each direct field cost account. Seven direct field cost
accounts are utilized. The use of the^e accounts facilitated the develop-
ment and cross-checking of results with tecent construction experience in
fossil-fired power plants.
Two of the seven direct field cost accounts (1.0 Steam Generators/
Furnaces and 2.0 Turbine Generators) include major components for which
BOP estimates include only installation labor costs. One account (3.0
Mechanical Equipment) includes both major components in which BOP installa-
tion costs are supplied and BOP items that include component costs and
installations. The remaining four accounts (4.0 Electrical, 5.0 Civil and
Structural, 6.0 Piping and Instrumentation, and 7.0 Yardwork and
Miscellaneous) include primarily BOP items — both component costs and
installation costs. Details of . these direct costs pertaining to particular
energy conversion systems are presented In Section 4 of this report.
Details of direct costs pertaining to BOP items that are common to all
plants are discussed below under "Common Balance-of-Plant Components."
Table 97 gives an approximate division of items which are included
in each account.
The BOP direct field costs are developed on the following basis:
1. All prices are at mid-1975 dollar value.
2. A composite labor rate of $11. 75/MH is applied to all manual
field labor.
3. Material and equipment costs are determined from L-urr^nt data,
from vendors' oral budgetary quotations, and Ciom recent power
plant construction field cost reports.
4. Manuel field labor man-hours are determined from man-hour stan-
dards, from computerized estimating programs, and from recent
power plant construction field labor cost reports.
5. Productivity of manual field labor is assuned to be equivalent
to the current national average for fos «=i.'-f ired power plants.
6. Availability of manual field labor if. i ssiar.ed to be sufficient
at the Middletown, U.S.A., site for construction of each plant.
Subcontracts
Subcontracts are not included P.O -uch in the cost estimates. BOP
components that normally would be estimated as single subcontract cost
entries (for example, cooling towers, stacks, and pipe insulation) are
divided into, and entered as, direct material and direct labor costs.
251
-------
Table 96
6ALANCE-OF-PLANT COST SUMMARY FORMAT
l
Labor Material Total
(MHs) ($) ($)
1...0 ^Steam Generators/furnaces XX XX
2.0 Turbine Generators XX XX
3.0 Mechanical Equipment XX XX
4.0 Electrical XX XX
5.0 Civil and Structural XX XX
6.0 Piping and Instrumentation XX XX
7.0 Yardwork and Miscellaneous XX XX
Direct Materials XX XX
Direct Labor XX
-------
Table 97
ACCOUNT CATEGORY DIVISIONS
1.0 STEAM GENERATORS/FURNACES
Steara Generators* and Economizers*
Coal Injection Systems*
Combustion Air Preheaters*
»• FD, PA, and ID Fans*
Flues and Ductwork
Precipitators,* Cyclones,* and
Granular Bed Filters*
2.0 TURBINE-GENERATORS
Steam Turbine Generators*
Gas Turbine Generators*
3.0 MECHANICAL EQUIPMENT
f.
Pumps and Drivers**
Condensers**
Heaters, Exchangers, Tanks, and
Vessels**
Compressors and Drivers**
Stacks and Draft Ducts
Turbine Hall Cranes
Coal, Other Solids, and Ash
Handling**
Cooling Towers
Water Treatment
Fuel Oil Ignition
Screenwell
Miscellaneous Plant Equipment
« a ,
Equipment Insulation
253
-------
Table 97 (continued)
4.0 ELECTRICAL
Transformers
Generator Main Bus
Switchgear and Control Centers
Communications and Lighting
Grounding, Cathodic, and Freeze
Protection
Auxiliary Diesel Generator
Conduit,(Trays, Wire, and Cable
5.0 CIVIL AND STRUCTURAL.
Concrete Substructures and foundations
Superstructures and Building Services
Earthwork, Dewatering, and Iiling
Cooling Tower Basin „
Circulating Water Pipe and Pump Pads
6.0 PIPING AND INSTRUMENTATION
Steam and Feedwater Piping
Hot Gas Piping
Auxiliary Piping
All Small Piping (2 in. and under)
Hangers and Supports
Miscellaneous Labor Operations
Pipe Insulation
Instrumentation and Controls
254
-------
Table 97 (continued)
7.0 ;YARDWORK AND MISCELLANEOUS
Site Preparation an<\ Improvements
Site Utilities
Railroad Spurs
Roads, Walks, and Parking Areas
Yard Fire Protection
Fences and Gates
Ponds and Dikes
Lab, Shop, and Office Equipment
*Install only
**Some installed only
255
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-•
This procedure is adopted to ensure a comprehensive accounting of all field
labor man-hours. In effect, this method assumes that all field labor is
performed by the prime contractor's work forces,
Distributable Field Costs
Distributable, that is, indirect, costs include field costs thac can-
not be directly identified with any specific direct account item. In a.
sense, the coats are "distributed" over all direct items. Construction
experience demonstrates that distributable field costs can be estimated as
a percentage of direct field labor costs. For each system, distributable
costs are estimated at 90 percent of direct field labor cost—a percentage
^that is consistent with recent fossil-fired power plant construction
experience. The items included in the distributable account and the typical
percentages are given in Table 98.
Engineering, Home Office Costs', and Fees
Recent fossil-fired power plant Construction experience demonstrates
that engineering, home office costs, and fees are equal to approximately 15
percent of total (that isr direct plus indirect) field costs. Included in
these costs are: " >
n-^
Design engineering
^f-
' Estimating, scheduling, and cost control
" Purchasing, expediting, and inspection '
" Construction management and administration
* Engineering, procurement, and construction management fees
Fees typically amount to about 2 percent of total field costs. About
two-thirds of the remaining 13 percent ara for engineering services and the
remaining third is for other home office costs.
Contingency
Estimates predict the cost of a project but predictions contain
uncertainties. Contingency is the amount of money that construction experi-
ence has demonstrated must be added to an estimate to provide for uncertain-
ties within the design detail in quantity, pricing, and productivity.
Contingency minimizes the risk of these uncertainties and reflects a
selected risk of overrun. The contingency is expected to be spent during
the construction and is selected to yield the most probable total project
cost. Contingency does not provide for changes in the defined scope of a
project or for unforeseeable circumstances beyond the contractor's normal
experience or control.
« o
256
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Table 98
DISTRIBUTABLE FIELD COSTS
Temporary construction facilities including sheds,
temporary fences and paving, temporary utility
connections 12%
.Miscellaneous construction services including
surveying, material handling, watchmen and clean up 12%
Construction equipment and tools 10%
Consumables including fuel, oxygen, acetylene and
welding rod 5%
Field office costs including field supervision, field
engineering, field administration, medical and field
office overhead expenses 20%
Preliminary operations and testing including alignment,
balancing, tasting and adjusting of all equipment to
ensure that warranties are met and that all subsystems
function properly prior to customer acceptance and
plant startup 11%
Payroll expenses including federal and state payroll
taxes and workmen's compensation 14%
Project insurance 4%
State and local sales and use taxes 2%
90%
257
-------
A contingency of 20 percent applied to all costs has been selected
with consideration of the conceptual nature of the designs. The limited
conceptual level of detail in these plant designs increases the risk of
underestimating costs. To compensate, a contingency is selected that is
near the high end of the range of values currently used in the construction
industry.
A common contingency factor (20 percent) is applied to all three plant
types studied. A common percentage is justified because, by definition, con-
tingency reflects a level of uncertainty consistent with the design detail, and
all plants are estimated at a common conceptual level of available detail. By
definition, contingency does not reflect technological risks which may be
associated with the more advanced systems.
Design Allowances
Design allowances are also built into estimates to cover costs that
experience indicates are expected but not explicitly identifiable. However,
unlike contingency, which is an indirect cost applied to a total estimate,
design allowances are direct costs applied to specific equipment or bulk
material items. For example a 5-percent design allowance may be added to
the purchase price of a pump to cover expected miscellaneous field purchases
required to facilitate installation of that pump. Design allowances typical
to current fossil-fired power plant estimates are included in the estimates.
C. COMMON BALANCE-OF-PLANT COMPONENTS
Certain significant BOP components are common to all or many of the
energy conversion systems.
Stacks and Accessories
In actual plant construction, stacks are usually subcontracted.
Budgetary direct material costs and labor requirements were estimated
through consultation with a stack contractor. An additional allowance for
accessories, including lifts, marker lights, and paint is estimatad from
recent construction experience. Budgetary direct material coses for a
stack with accessories (excluding stack foundation) are estimated from the
relation:
1.05 0.55
Stack height (ft) x Liner diameter (ft) x $1>000>000 + Sl5>00f)
470 40
Corresponding direct labor man-hour requirements are:
1.35 0.75
Stack height (ft) x Liner diameter (ft) x 48,000 MH +1,100
470 40
258
-------
Concrete for stack foundations is estimated using reinforcing bar,
formwork, and embedded metal quantities per cubic yard as experienced in
recent field construction.
Cooling Towers
Cooling towers are defined as wood, mechanical draft, wet towers
operating at the design conditions detailed earlier in this Section.
Cooling towers are usually subcontracted, though, budgetary estimates
on direct material costs and labor requirements were estimated through
consultation with a cooling tower contractor. Cooling tower costs are
estimated on the basis of tower units (TU) which, for the tower design
specified are:
At raid-1975 dollar values, direct material costs for the towers are
$6.13/TU.
The corresponding direct field labor requirements are 0.14 man/hours/TU.
"Sft
Concrete for the cooling tower basin and foundations is estimated using
275 cubic yards (210 ra^) per cell and using reinforcing bar, formwork, and
embedded metal quantities per cubic yard as experienced in recent fijld
construction.
An allowance of $6,000/cell and 100 MH/cell is also estimated for
miscellaneous structural steel and fire-protection equipment based on recent
construction experience.
Dewatering and Piling
Dewatering and piling requirements are site sensitive-and dependent on
soil conditions, groundwater, rainfall, and so on. For all plants, an
allowance of $300,000 for material costs and 100,000 man-hours is included
for dewatering and piling based on recent field construction experience.
Auxiliary Buildings
Administration, warehouse, and minor yard buildings are, in large part,
dependent upon the plant owner's particular needs. Based on typical costs
for these buildings extracted from recent coal-fired power plant construc-
tion projects, the following allowances are included for auxiliary buildings
in all plants:
Direct Field Direct Field
Labor Material Cost
Earthwork 600 MH
Substructures 5,400 MH $ 36,000
Building Services 84,000 MH $-1,250,000
O o
259
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Railroad Spur
All plants Include four miles of railroad trackage for unit-train
delivery of coal and sorbent material and for removal of solid waste. Based
on recent construction experience, $632,000 for material costs and 21,500
man-hours are allocated for the railroad spurs.
Other Common Equipment
All plants include costs for the following equipment items:
Laboratory and office equipment (@ $285,000 equipment cost and 1,000
man-hours allowed for handling and installation)
Mobile coal-handling equipment including two bulldozers with coal
blades and two scraper? (@ $908,000 for the lot)
1,000 kW, 480 V, 3-phase auxiliary diesel generator with startup
batteries and associated equipment (@ $115,000 equipment cost and
1,500 man-hours for installation)
Several additional balance-of-plant components are common to all plants
but vary in cost according to capacity or other scaling parameters. These
components are listed in Table 99 along with the scaling parameter used in
deriving their costs.
Plant equipment and material not discussed in this section are parti-
cular components required by specific energy conversion systems. These
components (for example, boilers, corabustors, turbine generators;, feedwater
heaters, pumps, fans, large piping, and boiler enclosures) are r»* imated on
an item-by-item basis and discussed in the CVS, AFB, and PFB p- ^ons of
the report.
D. CONSTRUCTION TIME ESTIMATES
For large fossil-fired power plants of the type included in this study,
a relationship exists between the total number of field manual man-hours and
the number of months required from start of plant engineering to construc-
tion completion. This relationship is presented in Figure 3-6, which is
plotted using data from actual power plant construction experience. Data
points represent coal- and oil-fired, single- and double-unit plants of
500 MWe and 800 MWe unit-capacity. The line drawn between points is the
result of a least-squares regression analysis and indicates the following
exponential relation:
260
-------
Construction Time* (Months) - 47.5 x Manual Labor (MH) °'20
i
Using the above relationship, a construction time is estimated for
each of the plants included in this study and presented in Table 3-6.
*From start of engineering to commercial plant operation
261
-------
Table 99
COMMON BAL>.NCE-OF-PtANT COST ITEMS
Balance-of-Plant Item
Turbine hall crane
Solids-handling equipment (Includes
rallcar dumping, dust collectors,
primary crushing, belc scale, sampling
station, magnetic cleaners,, conveyors,
hoppers, feeders, foundations, pits,
"and tunnels)
Water treatment and chemical Injection
Instrument air compressors and auxiliaries
Fuel oil ignition and warmup
Screen well
Miscellaneous mechanical equipment
Equipment insult eit ion
Mala transformer and generator main bus
Station service transformers
Startup transformer
Plant electrical equipment (includes
Evitchgear and load centers, motor
control centers, local control stations.
distribution panels, relay and meter
boards, communications, grounding, cathodlc
and freeze protection, preoperational
testing)
Plant lighting
Electrical bulk, materials (Includes
conduit, cable trays, wire, and cable)
Turbine halls (Include substructure
and building services)
Circulating vtter system (includes
concrete and pipe)
Miscellaneous equip*asnt foundations
and other concrete
Common large piping (includes auxiliary
steam, condensate, process water, fuel
and Ignition oil, water treatment,
compressed air, lube oil, H-, CO.,
miscellaneous)
Snail piping, valves, and fittings
2 Inches or less in dianater
All pipe hangers and supports &
Miscellaneous piping labor
operations (Includes material
handling, scaffolding, clean up)
262
Cost Scaling Parameter(a)
Turbine rating (MWe)
Solids-flow (TPH) and
conveyor lengths
Cross plant rating (MWe)
Cross plant rating (MWe)
•Cross plant rating (MWe)
Cross plant rating (MWe)
••*
Cross plant rating (MWe)
Cress plaut rating (MUe) .
Voltages (kV) and capacity (MVA)
Voltages (kV) and capacity (MVA)
Valtages (kV) and capacity (MVA)
Section service transformer cost
Lighted plant area (ft )
Station service transformer cost
Building plant area (ft )
Circulating water flow
(gal/mln)
Cross plant rating (MUe)
Cross plant rating (MVA)
Linear feet of large pipe (ft)
Piping cost (S)
Piping man-hours (MH)
-------
100
X
H
O
tlT
90-
80
70
z
2 60
o
D
oc
£
O
o
50
40
3 456
106 FIELD MANUAL MANHOURS
10
Figure 42. Construction Time (from Start of Engineering)
to Commercial Operation) Variation with Field
Manual Labor Man-Hours
263
-------
Table 100
ESTIMATED PLANT CONSTRUCTION TIMES
Manual Labor Construction
(MHs) Time (Months)
Convertional/Wet Scrubber 5,602,000 66
Atmospheric Fluidized Bed 4,295,000 64
Pressurized Fluidized Bed 3,995,000 64
264
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F. OPERATING AND MAINTENANCE COSTS
1. INTRODUCTION
The analysis of operating and maint nance (O&M) costs was a joint effort
of several organizations.
General Electric Installation and Service Engineering Business Division
was responsible for bringing together estimates on tri maintenance costs asso-
ciated with conventional types of- power plant equipment and for estimates of
the operating labor costs associated with each system. This Division also
played a major role in the study of operating consumable costs. Foster
Wheeler Energy Corporation supplied n..jir.tenance data and information on the
atmospheric and pressurized fluidizeu b-^d concepts. The Bechtel Corporation
supplied listings of balance-of-plant equipment which have served as the basis
for maintenance estimates on this equipment.
General Electric Corporate Research and Development performed the following
activities:
Provided detailed information on the characteristics of the
energy conversion ct-acepts.
Investigated maintenance requirements associated with advanced
components.
Carried out analyses of operating consumables costs for the
advanced concepts.
Integrated the several efforts into a single analytic package.
O&M costs have beet, estimated for the CWS, AFB, and Prr> power pl.-Uits. For
each of these plants, total operating and maintenance costs are computed in
mills per kilowatt hour. Each total is the sum of estimated maintenance costs
on cycle equipment, the operating labor required for the plant, and the cost of
operating consumables.
All costs are based on raid-1975 cost estimates, without provision for
inflation in costs over system life. Differential costs of "makeup" purchases
of power-are not included.
Costs of such items as auxiliary power purchases, outside steam purchap .-s,
other utilities, taxes, and insurance are not estimated in O&M cot;ts. Iteais
usually handled by applying a fixed charge rate to the total capitil invest-
ment (for example, cost of working capital and capital charges) are not
included in O&M costs.
265
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2. MAINTENANCE COSTS
The maintenance costs include the costs during planned outages (preventive
maintenance, inspections), and forced outages (breakdowns, repairs). The costs
include any unusual supplies, replacement parts, equipment rentals, outside
maintenance consultants, and the salaried of the employees required in provid-
ing the necessary maintenance. The salaries of these maintenance men are the
major component of the maintenance costs of power plant equipment. No costs
are estimated to provide a contingency for major repairs that might be required
in the event of a long forced outage caused by severe parts failure damage.
Plant maintenance is broken down into the following areas for cost estimation:
a. Turbine-generator
b. Steam generator
c. Makeup water treatment
d. Electrostatic precipitator
e. Water intake structure
f. Balance of plant (BOP)
This cost breakdown is shown in Table 101.
a. Turbine-Generator Units
The estimated maintenance cost for an entire steam turbine generating unit
included supervision and engineering as well as maintenance of structures, boiler
plant and electric plant.
The PFB plant required maintenance of a gas turbine generator as well as
an addition to it also.
Gas turbine-generator maintenance costs include the maintenance of an
industrial continuous service baseloaded gas turbine-generator only and
excludes any associated equipment.
b. Steam Generators
The Foster Wheeler Energy Corporation has supplied estimates for the
atmospheric (AFB) and pressurized (PFB) Eluidized bed systems, Each system
has been broken down in terms of four maintenance-sensitive areas: pressure
parts, special fluidized bed items, control components, and auxiliary equip-
ment. Separate maintenance burdens were then applied to each of the four,
these burdens ranging from 0.2 percent to 5.0 percent annual maintenance
costs as a percentage of equipment cost. These analyses have resulted in
the estimation of annual maintenance costs of roughly $l,kW for the AFB to
about $1.70/kU for the PFB.
266
-------
Foster Wheeler also supplied estimates for the conventional pulverized
coal-fired furnace for the Conventional/Wet Scrubber plant design.
c. Makeup Water Treatment System ; ;
Makeup water treatment costs were based on makeup water flow. The system
was assumed to be two stage: CD pretreatment solids removal incorporating
flocculation and filtration using carbon and sand aad (2) a deraineralization
stage composed of a dual-bed demineralizer, atmospheric degasifier, and a dual
mixed-bed demineralizer as major components.
The maintenance cost for water treatment does not include Chemicals costs,
'"which are treated as consumables.
d. Electrostatic Precipitator
The CWS and AFB plants utilized electrostatic precipitators. The ESP
efficiencies for the plants were 95 percent for the AFB and 98.5 for the CVS.
On the basis of these efficiencies maintenance costs were calculated based
on gas flow. .
e. Water Intake Structures
Water intake structures were assumed to be a bar screen and traveling
screen system. Maintenance~costs ware based on equipment replacement costs
with magnitudes proportionally determined by makeup water flows.
f . Balance-of-Plant Maintenance Cost.^
Maintenance costs, as well as being estimates for conventional and advanced
cycle equipment, have been separately calculated for balance-of~plant, (BOP)
equipment .
The rationale for these calculations may be briefly described as follows:
Bechtel Corporation has supplied detailed estimates of BOP material costs
associated with major equipment categories for each cycle: that is, .steam
generators, turbine generators, process- mechanical equipment, electrical,
civil and structural, process piping and instrumentation, and yard work and
miscellaneous. Within each category, maintenance costs as a fraction of
the material costs per year have been estimated. For example, the mainte-
nance burden on miscellaneous support steel is taken to be 0.2 percent
per annum, whereas those for forced draft fans, pu^ips, etc., are taken at 5
percent per year. Other categories of equipment have been similarly assigned
maintenance burdens in accordance with good engineering judgment and field
experience.
These maintenance burden factors are then multiplied by the associated
BOP materials costs for each equipment class, with all su;h products then
0 to
267
-------
summed to create a maintenance cost for the entire cycle In $M/yr. These
cost figures are in turn (based upon the cycle's net output In MW and a 65%
capacity factor) converted to BOP maintenance costs in mills/kVh for each cycle.
268
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3. OPERATING COST ESTIMATES
The operating cost estimates for the three plants studied are broken
down into operational labor costs and Into costs of consumables and supplies.
a. Operational Labor Costs
Estimates of the manpower required to operate the three power plants were
based upon available information contained in the references and upon extra-
polations of such estimates to cover the advanced technology aspects of the
various plants. Basic categories of labor considered as operating personnel
include supervisors, engineers, operators, technicians, fuel handling specialists,
chemical technicians, clerical workers, laborers, guards, and others. These
categories were consolidated into:
a. Supervisors
b. Operators
c. Technicians
d. Laborers, clerks, guards, others
Once the number of employees for each power plant was established, the
annual payroll including fringe benefits and overhead was calculated assuming
an average salary of $20,000/year:
Composed of: 14,286 base salary
4,285 fringe benefits
1,429 overhead
$20,000 Total
The estimated manpower requirements and associated costs are found in
Table 102.
b. Consumables and Supplies
The major portion of consumable costs is that required for the purchase
of sulfur dioxide sorbents. The AFB and CWS plants both require llaestone
while the PFB utilizes dolomite. A charge of $5.00/ton is assumed for both
limestone and dolomite. An average cost for water, lubricants, and supplies
was calculated from existing coal-fired plant data resulting in an average
1975 cost of 0.20 mill/kWh. It was then assumed that these consumables apply
to that portion of the plants which is considered conventional equipment. The
cost for consumable is assumed to cover the cost of water where it must be
purchased for makeup, and for the necessary water treatment chemicals; water
treatment was estimated to cost $2.11/1000 gal of water treated.
c. Solids Disposal
No disposal costs are included in the GE estimates for AFB and PFB. CWS
solids disposal costs are included in the form of disposal pond and sludge
handling costs.
269
-------
Table 101
MAINTENANCE COSTS
CWS (747 MW)
Steam Turbine-Generator
Conventional Furnace
Makeup Water Treatment
Electrostatic Precipitators
Water Intake Structure
BOP
Wet Scrubber System
AFB (814 MW)
Steam Turbine Generator
AFB Units
Makeup Water Treatment
ESP
Water Intake Structure
BOP
PFB (904 MW)
Steam Turbine Generator
Gas Turbine Generator
PFB Units
Makeup Water Treatment
Water Intake Structure
BOP
$M/Yr.
Total
1.20
0.88
0.04
0.11
0.04
l^.Sj
Total 4.12
Total
Plant
AFB
CWS
PFB
Super-
vision
17
14
17
Opera-
tors
50
42
50
Table
OPERATING
Fuel Syst
Tech Chera
Tech
18
15
18
102
LABOR
Laborers,
Clerks,
Guards,
etc.
25
20 -
25
Total
Operating
Personnel
110
91
110
M$/Yr
2.20
1.82
2.20
Net Mills/
Output kWh
814
747
904
0.47
.43
0.43
270
-------
Table 103 contains costs associated with consumables and supplies for
each of the three power plants.
4. O&M: SUMMARY
The number of personnel required to operate and maintain a power plant
will be partly dependent on the staffing practices of the particular utility
operating the plant. Some utilities account for those employees not directly
applicable to power plant O&M, while others Hire some of their services from
outside subcontractors.
If the utility operating a plant had several other large plants nearby
so that certain of the maintenance personnel, engineers, and technicians could
be shared, their staffing would be accounted in a different way. Our manpower
estimates represent judgment as to the average number of employees for each of
the plant types. Other factors influencing staff sizes are site-related or
region-related or effects, such as specific anion negotiated manpower requirements
by job classifications and labor productivity..
>
The values selected for maintenance costs on the major equipment items
also depend on the specific practices for routine preventative maintenance
and on the forced outage experience on each equipment item. Maintenance costs
will depend on achieved equipment reliability. An additional complication
causing a range of values for maintenance costs in varioi'c survey reports is
that of accounting practices, by which one may keep track of maintenance expenses
on each individual item of equipment while others may group the expenses by sys-
tems or other categories. The estimated values for maintenance costs are to be
taken as representative of a wide range of data reported by the various utilities.
Table 104 gives a detailed breakdown of all G&M costs. These costs are
summarized in Table 105.
271
-------
Table 103
1 OPERATING CONSUMABLES
cws
Convent- ional; 0.91 x 10 $/yr.
a $5b ft
Limestone; 125,000 x -j~j x 8760 x .65 = 1.78 x 10° $/yr.
Total! 0.91 + 1.78 = 2.69 x 106 $/yr.
$2.69 x 106 x 1000 raills/dol ,„ ,.., „ ,.
747 MW x 1000 kW/MW x 8760 x .65 ~ *63 mllls'kwh
AFB
Conventional; 1.05 x 106 $/yr
Limestone; (48,564.8 x 4 x 1..0626 lb/hr)a x ~jfi x 8760 x .65
= 2.94 x 106 $/yr
Total; 2.94 -f 1.05"= 3.99 x 106 $/yr
$3.99 x 106 x 1000 mills/dol _ ., .,,,,,-
814 MW x 1000 kW/Minr8760TT65 -86mills/kwh
PFB
Conventional : .82 x 10 $/yr
Dolomite; (83,963 x 4)a x- - x 8760 x .65 = 4.78 x 106 $/yr
Total; .82 + 4.78 = $5.60 x 106 $/yr
$5.60 x 106 x 1000 - I OQ
904 MW x 1000 x 8760 x .65 ~ 1'-°-9
a. Hourly throughout, total plant
b. Cost of .loloiitite or limestone per pound
272
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Table 104
DETAILED O&M COSTS
1. CWS (747 MW)
Maintenance Costs
Steam turbine generator
Conventional boiler
Makeup water treatment
Electrostatic precipitators
Water intake structure
Scrubber system
Balance of plant (BOP)
Operational Coats
Labor (91 Men)
Consumables
Total O&M Costs n
2. AFB (814 MW)
Maintenance Costs
Steam turbine generator
AFB
Makeup water treatment
Electrostatic precipitators
Water intake structure
BOP
Operational Costs
Labor (110 Hen)
Consumables
Total O&M Costs
Total
Total
Total
Total
(Mills/kWh)
0.43
0.63
1.06
2.61
(Mills/kWh)
0.47
0.86
1.33
2.22
273
-------
Table 104 (continued)
3, PFB (904 MW)
Maintenance Costs (Mills/kWh)
Steam turbine generator 0.19
Gas turbine generator 0.14
PFB 0.29
Makeup water treatment 0.01
Water intake structure 0.01
BOP 0.37
Total 1.01
Operational Costs , . '
LaboE (110 Men)
Consumables -
.. - Total
.. Total O&H Costs ' 2.53
Table 105
OPERATING AND MAINTENANCE COSTS
SUMMARY TABLE
Plant Maintenance Operation
CWS 1.55 1.06
AFB 0.89 1.33
PFB 1.01 1.52
274
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G. GE COMPARISON OF ALTERNATIVES
Future steam power plants may use atmospheric fluidized beds (AFB) for
burning coal in the presence of limestone, to provide sulfur capture during
combustion, A more advanced concept would be the use of pressurized fluidized
beds (PFB) with dolomite for sulfur capture and gas turbines for pressurizing.
Such plants have been evaluated in the Energy Conversion Alternatives Study
(ECAS)3 on the identical basis and to the same degree of detail as the steam
plants of this evaluation.
Table 106 compares these alternatives to the conventional steam plants
with 175 F stack temperature (CWS 175). The basis for all table entries is
$/kW of net plant output. The combination of Furnace Modules, Hot Gas Filtering,
Solids Handling, and Stack Gas Scrubbers expresses much of the cost of heat
release and sulfur and particulate capture. These accounts aggregate S67/kW
for the AFB, $123/kW for the PFB, and $147/kW for the CWS. The total capital
cost and the cost of electricity (COE) follow a similar progression.
The consumption of coal relates directly to the overall efficiency of a
power plant. A number of alternatives were evaluated and are presented in
Table 107 in the order of decreasing efficiency. The two "no scrubber" cases
would require a coal with less than 0.65 percent sulfur for a 10,788 Btu/lb
(25.1 MJ/kg) higher heating value if they were to meet the emission standards
common to all of these plants. The boiler efficiency follows the same pro-.
gression as the overall efficiency. The steam turbine cycle efficiency equal
to 3412 divided by the heat rate also decreases toward the bottom of the table.
The conventional furnace with wet scrubber and 175 F is the best current solu-
tion for combustion of high-sulfur fuels. The penalty in efficiency and cost
of electricity are direct results of the environmental constraints, which
are fully met.
The comparative amounts of sorbent required for sulfure capture are pre-
sented in Figure 43. Both the conventional steam plant with wet scrubbers
and the AFB plant use limestone. The excess applied is 10 percent for the
former and 100 percent for the latter. The PFB plant uses dolomite, which
has only half the concentration of available lime found in limestone. The
conventional plant consumes the least sorbent material. The solid wastes
combine the ash and the solid products from sorbent reactions.
The major water usage is evaporation from the cooling towers. The major
water waste that must be treated would be the cooling tower blowdown. Figure 44
shows the same progression in water conservation that would be found in coal
requirement.
275
-------
Table 106
CAPITAL COST DISTRIBUTIONS AS $/kW
FOR 3500 PSI, 1000 F, 1000 F STEAM POWER PLANTS
AFB PFB CWS CWS
: 1550 F 1650 F 175 F 250F
Major Components
Steam Turbine-Generator 33.2 27.7 33.6 34.8
Furnace Modules 55.8 16.3 57.7 61.A
Gas Turbines 28.3
J3ot Gas Filtering 71.4*
Economizer 2.5
Solids Handling 11.4 35.6 JL5.Q 15.9
Subtotal 100.3 182.0 106.2 112.2
Balance of Plant
••*••
Stack Gas Scrubbers - - 56.8 69.5
Site Labor - 117.8 108.4 126.8 134.9
All Other 122/1 98.7 107.5 133.3
Subtotal 239.9 207.1 307.5 337.7
- • J-ii •
Contingency n 68.0 77.8 82.9 90.0
Escalation and Interest 223.8 255.8 273.0 295.8
Total Capital Cost 632. 723 770 835
COE Mills/kWh 31.7 34.1. 3/.0 39.8
*Estimate of hot gas filtering costs for PFB, prepared by Westinghouse for EGAS
was approximately $15/kW.
Table 107
EFFICIENCY ORDER OF STEAM PLANTS
Type
Plant
PFB
PFB
CF
AFB
CF
CWS
CWS
Conditions
1750 F Beds
1650 F Beds
No Scrubber
1550 F Beds
No Scrubber
Wet Scrubber
Wet Scrubber
Stack
3 OOF
3 OOF
250F
250F
3 OOF
175F
250F
Overall
Efficiency
40.0%
39.2%
36.2%
35.8%
35.7%
33.8%
31.8%
Electricity
Mills/kWh
34.1
34.1
30.5*
31.7
31.6*
37.0
39.8
*3.9% in coal not permitted
276
-------
Sorbent Required 1/kWh Solid Waste f/KWh
0.4 0.3 0.2 0.1
i i i i
i i i _ . |. .. .. -
I1?-'. '.-..',;•-•; Conventional
Ste
(:;;:>•:::• :••;.:•: -.'.'V.--: .-.-. AfmrKp^pr
Be
am
ic Fluid
d
I:':'.'. :. -V;.V: ::'.•:•:•:•::..•••':•';:'::•.'•:••:•'.:•.•.•:•:•:'-•.: Prp
-------
Water "Waste" Gal/kWh Total Water Requirement GalfrWh
0.6 0.4 0.2 0.2 0.4 0.6 0.8
1 H 1 1 1 1 1 1
Conventional
Sleam
Atmospheric Fluid
Pressurheu Fluid
Figure 44. Water Requirement
278
-------
The gaseous emissions of SOX and Nfl^ are compared in Figure 45. The AFB
and PFB, with combustion in beds at 1550 F and 1650 F respectively, have
produced notably low levels of NOx. The conventional furnace requires a well
balanced, staged combustion system in order to meet current NOX limitations.
•All plants satisfy the SOX limits, with the PFB showing the greatest raarg:'T.
279
-------
ro
8
Cycles
Advanced Steam -- AFB
Conventional Steam
Advanced Steam — PFB
Caseous Emissions (ib'10 Btu Input)
) .2 .4 .6
1 i I
/ZS//////S///////J2'j////'//y/St'/////'//±
,'
.".••-•••-• •.-.••: ::::.-:\ :.
&////////// ////./////////// ' ////s
•:•
y.'.'v^ •'-••;.- ••:;'. .•.-•' ..••* ••:•,".••."••.'"•-,-"." | ;
'.•////////s/////'////'//^////.-'////}
"
I:--.":-. \ :•
.8 1.0 1.2 1.
1 1 1 - - -r. 1
1 1. * 1
S
8
X
1
•§
^v
^
V-
\
1
Code:
NOX Solid Fuel Spec
so
'NO
o
01
o
3
SO Solid Fuel Spec
Fiaure 45. Gaseous Emission Characteristics (Lb/10 Btii Input)
-------
TVA MODIFICATION AND EXPANSION OF'GE STUDY
A. INTRODUCTION . :
The capital and operating costs prepared by GE for the CWS,: AFB, and PFB
were modified by TVA to take into consideration a number of factors felt by
TVA to be significant. Three major factors were addressed:
1. Modification of the estimates to include an uncertainty allow-i.ire
allowance for plant components considered to be undembnstrated
technology; and modification of the GE estimates for .various com-
ponents where such revision is felt to be warranted based ;.pon TVA
experience.
2. Expansion of the GE estimates to take into consideration alternate
wet scrubbing techniques for the CWS case, in addition to the lime
scrubber with on-site calcination used by GE.
•fir- *
3. Modification and expansion of the GE esti-ntes of residue disposal
costs, to take into consideration: (a) adequate provision for dis-
posal over the full 30 year plstit lifetime for all cases and (b)
alternate disposalcoptions. Previously, GE included only 5-year
disposal provisions for the CWS case, and none for AFB and PFB.
281
-------
B. MODIFICATION OF GE ESTIMATES BY TVA
Shovn in Table 108 are the GE study cost comparison and TVA's modified
cost estimates of the three types of steam plants. Both the GE and the TVA
figures in Table 108 are based on the assumption that all three type plants
are of a mature technology; they attempt to compare the costs of the three
types of plants after they have been developed to a point of commercially
acceptable risk for construction and operation^ The TVA estimates include
uncertainty allowances reflecting the fact that some of the plant components
are not truly "mature technology" today. These allowanr.es include items such
as design changes, addition of equipment, and technological changes, and are
an attempt to reflect what the costs for as yet underaonsLrated components may
actually turn out to be. These cost modifications do not incorporate develop-
ment costs or startup costs associated with obtaining a state-of-art process.
TVA estimates in Table 108 also include increases in equipment costs and
associated labor and material costs because the GE costs differed greatly
from cost estimates based on quotations received by TVA. TVA cost figures
for equipment were obtained from data presently on file, tost of the com-
ponents presently in an 800-MW and a 1200-MW coal-fired unit on the TVA system
was escalated to mid 1975 dollars. Information from a recent cost estimate
for three 867-MW coal-fired units was also used. These values were used to
modify the GI study estimates.
These estimates should not be construed as an estimate of costs for which
TVA believes these plants could be constructed today. TVA cost figures are
only modifications of the GE study cost figures.
Uncertainty Allowance
TVA has assigned an uncertainty factor (unc.) to those items in the
two fluidized bed concepts which are considered mature technology but on
which full-scale development has not taken place. Those items are stean
generators, fuel injection systems, spent solids and dust coolers, and
portions of hot gas cleanup systems. This factor was applied for uncer-
tainties of design and scale-up of components and not for costs to develop
the components or to start up the process.
The amount of contingency added by EN DES was based on the following
conditions:
Uncertainty
20% Development is currently at a point to provide
reasonable confidence of commercial success.
40% Development is currently at a point of reasonable
definition of detailed technical problems to be
solved.
282
-------
Table 108
COST COMPARISON OF GE STUDY VS. TVA REVIEW
Total Capital Costs (1975 dollars)
PLA1
-------
60% Major technical breakthrough required to demon-
strate acceptability of a system for commercial
operation.
These uncertainty factors are in addition to the 20 percent contingency
adf'.ed to the total plant costs of each plant evaluated by General Electric.
These factors were considered in the evaluation of the GK study cost estimates
and the estimates were adjusted accordingly. The resulting estimates for the
items of equipment that pertain to the above categories are as follows:
Atmospheric fluidized bed
(Process mechanical equipment)
Equipment BOP
1. Spent bed coolers
Solids Cooler & Cyclones
(add 20 percent unc.)
Equipment cost: $312,000 x 2 x 1.2 .749M
Other equipment of spent bed cooling = ' .276
1.025M
2. Coal and limestone blending & feeding
(add 20 percent unc.) '*••
All equipment $2.74M x 1.2 = 3.288
BOP materials .930 x l*-2 = 1.116
r,
Other process mechanical equipment
Cost '•*
Other BOP material costs = u 28.394
Subtotal $10.1211 $29.51M
(Component)
3. Hot gas cleanup air supply
Most items state of art except
fines injection (add 20 percent unc.)
Equipment cost
$260,000 x 2 x 1.20 = .624M
Other hot gas cleanup equipment = 15.31
Total equipment * 15.93M
BOP materials - 0.61M
4. AFB module
(add 20 percent unc.)
Tower components, controls, ducts
29.72 x 1.2 = 35-66
BOP materials 5.%9 x 1.2 = 6.83.
Subtotal $51.59M $7.44M
284
-------
These are capital cost adjustments only. TVA cost estimates also adjusted
labor as needed for both AFB and PFB.
Equipment BOP
Pressurized fluidized bed
Process Mechanical Equipment
1. Coal processing and feeding
2 Petrocarb coal injection system
(add 20 percent unc.)
Equipment cost
7*198,354 x 2 x 1.20 = 17.28
Remaining equipment = 3.64
Total coal process 20.92M
»
2. Dolomite processing and feeding
2 petrocarb injection system
(add 20 percent unc.)
Equipment cost
3,851,375 x 2 x 1.20 = 9.24
Remaining equipment = 2.03
Total dolomite process 11.27M
3. Spent bed material (add 40 percent unc.)
to equipment, 20 percent to labor and
materials)
Equipment 1.58 x 1.40 = 2.21M
BOP materials 3.57 x 1.2 4.28
Other process mechanical
equipment component costs = 5.39
i
Other process mechanical
equipment BOP material costs = 22.63
Subtotal $39.79M $26.91M
Components '
4. Hot gas cleanup (add 20 percent unc.)
Equipment 64.51 x 1.20 =77.41
BOP material 2.04 x 1.20 = 2.45
285
-------
Equipment BOP
1 5. PFB module cost (add 40 percent unc.)
Equipment 14.68 x 1.40 = 20.55
BOP material 1.06 x 1.40 = 1.48
' Subtotal $9/.96M $3.91M
f
In addition to the uncertainty factors, modification of the following
areas was involved in arriving at the TVA estimates.
i
i
Boiler Enclosure for PIB
To be consistent with the other to plants and TVA's practice to enclose
its boilers, the following boiler enclosure costs were added to the pressurized
fluidized bed costs.
Direct manual field labor - 41,000 MH
Material costs - $1.63M
Electrical Subsystems
TVA feels that the GE study estimate did not provide enough manpower and
money for electrical subsystems. The largest difference in electrical costs
between the GE study and TVA cost estimate is the cost of materials and labor
for instrumentation and controls with TVA costs being much greater than allo-
cated by the GE study estimate. The estimate for the remaining electrical
equipment by TVA was actually less than the GE study. Although TVA uses an
elaborate instrumentation and control system for its plants, this would only
account for a small amount of the cost difference between EN DES and the GE
study estimate.
Tables 109, 110, and 111 show the capital cost breakdown as modified
by TVA for the CWS, AFB, and PFB plants.
The GE study estimate was reviewed for technical accuracy and suggested
modifications were made for good utility design. The GE designs were con-
sidered technically accurate for equipment sizing, auxiliary losses, conditions
of operation, and overall efficiencies.
The uncertainty factor had a major impact on the AFB and PFB cost
estimates with very little impact on the conventional plant (CWS). In a
cost comparison of CWS prime cycle and electrical equipment, the GE cost
figures and TVA's recent cost figures for the 867-MW units were
approximately the same.
There is no information available on utility wide accounting methods;
therefore, no efforts to recommend changes in defining indirect cost is
included. Therefore, the GE cost estimate for the conventional plant with
scrubber is assumed to be reasonable and certainly attainable.
286
-------
Table 109
TVA - CAPITAL COST BREAKDOWN
CONVENTIONAL STEAM PLANT - WET CAS SCRUBBERS - 175 F STACK (CWS 175)
CATEGORIES
1.0 Steam Generators
2.0 Turbine Generator
3.0 Proces§ Mechanical Equipment
4.0 Electrical(a)
5.0 Civil and Structural
t>
6,0 Process Piping and Instrumentation
7.0 Yardwork and Miscellaneous
COSTS (MILLIONS OF DOLLARS)
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD(2)
45.88 13.40 •
26.75 1.41
7.76
: 8.59
12. If?
(3) 16.40
3.06
72.63 63.12 f ^
BOP LABOR, MATERIALS
(SUM OF 1+2+3)
A/E HOME OFFICE & FEE
12.06
1.27
6.98
8.09
10.89
14.76
2.75
56.80
1, INDIRECTS
(9.15%.
MATERIALS (3) TOTAL
8.70
0.10
43:30
11.77
16.10,.
23.68
1.70
• 105.35
225.27
TOTAL PLANT COST
. CONTINGENCY @ 20%
TOTAL CAPITAL COST (BOP) >
ESCALATION & INTEREST ''
TOTAL COST
80.04
29.53
58.04
28.85
39.09
54.84
7.51
297.90
33.79
331.69
66 54
398.03
218; 92
616.95
(a) Revised by TVA to reflect reasonableness
On
-------
TABLE 110 - AFB
TVA - EN DES - CAPITAL COST BREAKDOWN
ADVANCED STEAM CYCLE - ATMOSPHERIC FLUIDIZED BED
COSTS (MILLIONS OF DOLLARS)
CATEGORIES
1.0 Steam Generators
2.0 Turbine Generator
3.0 Process Mechanical Equipment
(0
(b)
4.0 Electrical
5.0 Civil and Structural
6.0 Process Piping and Instrumentation
7.0 Yardwork and Miscellaneous
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD (2)
51.74 11.97
27.00 1.53
10.12 6.27
10.90
10.40
(C) 11.63
1.59
88.86 54.29
ROP LABOR, MATERIALS &
(SUM OF 1 + 2 + 3)
A/E HOME OFFICE & FEE
-------
Table 111 - PFB
TVA - EN DES - CAPITAL COST"BREAKDOWN
ADVANCED STEAM CYCLE - PRESSURIZED FUHDIZED BED
1650 F
COSTS (MILLIONS OF DOLLARS)
CATEGORIES
1.0 PFB Steam Generators
2.0 Turbine Generators
(b)
(b)
3.0 Process Mechanical Equipment
(el
4.0 Electrical^ '
5.0 Civil and Structural
6.0 Process Piping and Instrumentation
7.0 Yardwork and Miscellaneous
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD(2)
97.96 5.86
50.62 1.70
39.79 6.51
10.14
10.48
(C) 16.10
1.59
18S.37 52.38
BOP LABOR, MATERIALS &
(SUM OF 1 + 2 -*- 3)
A/E HOME OFFICE & FEE @
5.27
1.53
5.86
9.12
9.42
14.49
1.41
47.12
INDIRECTS
157.
MATERIALS (3) TOTAL
2.93
0.20
26.91
11.66
12.83
26.90
1.70
84.13
183.63
TOTAL PLANT COST
CONTINGENCY £ 20%
TOTAL CAPITAL COST (BOP)
ESCALATION i, INTEREST
TOTAL COST
113.02
54.05
79.07
30.92
32.73
57.49
4.72
372.00
27.54
399.54
79.91
479.45
263.70
743.15
(b) Contingency added by EN DES.
(c) Revised for reasonableness by EN DES.
(d) Boiler enclosure addition.
CD
-------
Ir. the TVA review of rhe plant plans providsd with the study, it was
apparent that all plants were compacted into a small area. Some areas
would be iracsessible for maintenance of heavy equipment if required. It
should be a utility's obligation to determine its own site layouts in accor-
dance with their own design, land use, and equipment requirements.
Although modification to some equipment and to the site layout may be
desirable, these changes were not added to the cost comparisons since they
had negligible p'r^t on costs.
TVA selected the GE 175BF stack gas. temperature design as the CWS "base
case." Considering lime scrubbers for 100 MW and larger units in the United
States, none of the nine in operation reheat to ovr 175°F. Information
available to TVA indicates that there are no benefits derived frcro: reheating
above 175°F. As added assurance of .corrosion prevention at I75°F, budget
cost figures for fiberglass ductwork and chimney liner are presented fot
information although not included In the TVA estimate for CWS.
Scrubbers with 175°F stack gas temperature could cause corrosion of
the duct after the reheater and the steel chimney liners if the.mist ells
tors do not operate with maximum eff.-ciency. To combat corrosion, the u'&e
of fiberglass ductwork and chimney liters capable of continuous, 3°5SF stack-
temperature is proposed. The cost of fiberglass chimney liners 30 feet in »~
diameter, 500 feet high is $1,100,000 for materials and installation. The
cost of fiberglass ductwork llrora the mist eliminators to the stack is esti-^
mated at $1,700,000 for materials and installation. These cost figures
should ba substituted in the GE study for the respective chimney liner and
ductwork, but, as stated above, these iigures have not been included in the
TVA estimates presented in this report.
290
-------
C. ALTKRTATIVEJWET SCRUBBER CASES
The scrubber costs of the GE study were deemed reasonable for the six
train lime scrubber using TVA Widows Creek unit No, 8 retrofit as a reference.
However, cost estimates of a new plant indicate lower scruM.er cost may
be achieved when included in a total project cost. Costs could be reduced
if the unit had four scrubber trains instead of six as provided by the fiE
study. Technology developments which permit an increase in scrubber thru-
gas velocity from 8 ft/s to 12.5 ft/s make this possible.
Summarized in Table 112 are estimates of direct capital investment
and direct operating costs in mid-1975 dollars for the following scrubbing
systems:
• Lime scrubbing with onsite calcination
• Lime scrubbing without onsite calcination
• Limestone scrubbing
• Magnesium oxide regenerable scrubbing (production of sulfuric acid)
The scrubbers are preceded by a 99 percent efficient electrostatic pre-
cipitator. Onsite untreated ponding of scrubber we -.tes for a 30-year period
is included in the lime and limestone scrubbing syrterns.
The estimates were prepared on the same general ground rules and assump-
tions as the GE study. The major design and economic premises are Us ted in
Table 113. The operating conditions for the lime and limestone scrubbers are
based on test results at Shawnee. The operating conditions for the m;u;nesla
process are essentially the same as reported by McGlsmery, et al.— with some
adjustments r;ade based on the operating experience of Koehler and Burns ..I'' The
hot air injection reheat used for all processors is based on the Widows Creek
limestone process design.
Sucmaries of the direct investment by process area are shown for the four
scrubbing systems in Tables 114 through 117. To obtain the total cnntt.tl
cost (in raid-1975 dollars) of the scru'^ber system, it is necessary to add
indirect construction costs, A&E service costs, and a contingency for expendi-
tures expected though not accounted for. These costs are accounted for in the
following manner:
Total direct investment 1.00
Indirect construction costs @ 25% 0. 25
Subtotal 1.25
A&E services
-------
Table 112
SUMMARY OF DIRECT COSTS
SCRUBBING SYSTEM
Lime slurry process with
onsite calcination
Line slurry process without
onsite calcination
Limestone slurry process
Magnesia slurry-regeneration
process
DIRECT CAPITAL DIRECT OPERATING
INVESTMENT. $ COSTS, $/YR.
39,157,000
32,190,000
36,745,000
32,899,000
5,409,700
5,971,000
4,267,500
6,271,900
a. Basis:
865* MM gross new coal-fir'id power tfnit, 3.9% S in fuel; 83% S02
removal. Stack gas reheat: to 175°F by heated air injection.
Disposal pond (if required) located one mile from power plant.
Pond sized for 30 year operation-at 65% capacity.
Coat basis: mid-1975=;
Minisaum in-process storage; only pumps are spared.
292
-------
Table 113
GENERAL DESIGN AND ECONOMIC PREMISES
FOR TVA ESTIMATE OF WET SCRUBBING SYSTEMS
f
I. Design Premises
A. The power plant has a gross generating capacity of 869 MW. It has
a 30 year life, operating at 0.65 capacity or 5694 hr/yr.
B. Coal composition is the same as ECAS.
C. Flue gas rate and composition are the same as ECAS.
D. Reheat is hy heated air injection to reheat flue gas to 175°F.
E. 83% of the S0_ is to be removed.
F. Bypass ducts are provided. No redundant scrubbers are present.
G. 99% of the particulates are removed with an ESP. The costs for
particulate removal:and ash handling are not included in this
estimate.
H. Chevron vane mist eliiranators with intermittent wash are included.
I. Raw material storage is provided for 30 days operation.
J. Cnsite untreated ponding of solids wastes is provided.
II. Economic Premises
A. All investment and operating costs are in mid-3975 dollars.
Investment costs are scaled to mid-1975 by using Chemical
Engineering material and labor indicts.
B. Working capital is not considered.
C. Capital -narges are at 18%/yr.
Til.'"'Additional Design Premises for Wet Lime Scrubbing
A. Four S0_ absorber units are required.
B. 3 stage TCA type is required.
C. Superficial gas velocity is 12.5 ft/sec.
293
-------
Table 113 (continued)
D- Total pressure drop is 6" HjO in the scrubber.
E. Liquid/gas ratio is 50 gal/MSCF.
F. Presaturation spray is 2.5 gal/MSCF.
G. Lime/S02 absorbed stoichiometry is 1.05.
H. Absorber hold tank residence time is 10 min.
I. Recycle slurry solids is 8% by weight.
J. Lime makeup slurry solids are 20% by weight.
K. Spent slurry pond solids is 40% by weight.
L. Calcination offgas meets S0_ emission requirements.
TV. Additional Design Premises for Wet Limestone Scrubbing
A. Four SO- .absorber units are required.
B. 3 stage TCA type is required.
C. Superficial gas velocity is 12.5 ft/sec.
D. Total pressure drop is 7" H-0 in the scrubber.
E. Liquid/gas ratio is 40 gal/MSCF.
F. Presaturation spray is 2.5 gal/MSCF.
G. Limestone/S07 absorbed stoichiometry is 1.50.
H. Absorber hold tank residence time is 10 min.
I. Recycle slurry solids is 10% by weight.
J. Limestone makeup slurry solids are 60% by weight.
K. Spent slurry pond solids is 402 by weight.
294
-------
Table 113 (continued)
V. Additional Design Premises for Magnesium Oxide Scrubbing
A. Four S02 absorber units are provided.
B. One stage venturi is provided.
C. Superficial gas velocity is 75 ft/sec.
D. Total pressure drop is 6" H20 in the scrubber.
E. Liquid/gas ratio is 20 gal/MSCF.
F. Presaturation spray is 2.5 gal/MSCF.
G. Magnesia/S02 absorbed stoichiometry is 1.05.
295
-------
Table 114 - Lime slurry (onsite calcination)
Table 115 - Lime slurry (offsite calcination)
T.ible 116 - Limestone slurry
Table 11? - Magnesia slurry (regenerable MgO)
Direct annual operating costs for these systems were estimated and are
included in the following tables:
Table 118 - Lime slurry (onsit°. calcination)
Table 119 - Lime slurry (offsite calcination)
Table 120 - Limestone slurry
Table 121 - Magnesia slurry (regenerable MgO)
To obtain total operating costs, it is necessary to add overhead charges.
TVA feels that an appropriate factor for scrubber O&M overhead is 50 percent
of total direct costs.
The magnesia slurry process makes a saleable product, 37.5 tons/h of
sulfuric acid. To obtain the net revenue required for this process a credit
for byproduct sales needs to be considered. A conservative estimate for sales
revenue is $25/ton of sulfuric acid. Table 321 does not include any acid
sales credit.
The GE cost estimate provides for only 5 years of ponding at a direct
cost of $490,000 for an unlined pond. Additional ponds will be required over
the life of the plant but provision is not made for them in the GE cost
estimate. It is granted that in actual practice disposal ponds may be con-
structed at intervals as required. However, in comparing alternatives these
future expenditures need to be recognized. The TVA estimate does this by
providing for a clay-lined disposal pond adequate for 30-year operation at a
cost of $7,099,000.
The difference ($4.2 million) between the GE and TVA estimates of direct
costs of the lime scrubbing systems, excluding the disposal pond, is concen-
trated in the scrubbing area costs. This is because the GE design premises
specify 8 ft/s superficial gas velocity with rix scrubbers, while the TVA
design premises specify 12.5 ft/s superficial gas velocity with four scrubbers.
The sludge disposal pond requirement specified in the EGAS report,
39,270 acre ft (1780 acres x 22 ft deep) for 5 years, is excessive. The GE
material balance shows a settled used slurry rate of 573 gpm, which corresponds
to a settling pond requirement of about 20,000 acre ft. for 5 years. This
difference in disposal pond requirements is significant when the cost of
disposal ponds and land is considered.
296
-------
Table 114
LIME SLURRY PROCESS WITH ONSITE CALCINATION
ONSITE UNTREATED POND STORAGE
SUMMARY OF TOTAL DIRECT INVESTMENT3
(869 MW gross new coal-fired power unit, 3.9% S in fuel;
83% S02 removal)
Direct Percent of
investment, $ direct investment
Materials handling (limestone receiving area,
coal receiving area, hoppers, feeders, con-
veyors, elevators, bins, front-end loader
and lime storage bin)
Limestone calcination (complete rotary kiln
including coal grinding, control system,
drives, fans, baghouse dust collector,
ducting and stack)
Feed preparation (feeders, conveyors, slakers
pumps, tank and agitator)
Sulfur dioxide scruobers (4 mobile bed
scrubbers, including feed plenum, pumps, mist
eliminators, soot blowers, and tanks)
Stack gas reheat (4 heated air injection
raheaters, fans and ductwork)
Gas handling (fans, and flue ductwork)
Calcium solids disposal (onsite disposal
pond, clsy liner, tank, and pumps)
Utilities (instrument air generation and
supply, system, distribution systen for
process steam, water and electricity)
Service facilities (buildings, shops, stores,
site development, roads, railroads, and
walkways)
Construction facilities
Subtotal direct investment excluding land
Lend (622 acres)
Total direct investment
1,242,000
6,644,000
778,000
8,794,000
1,313,000
6,786,000
8,097,000
129,000
1,232,000
1,776,000
37,291,000
1,866,000
39,157,000
3.17
16.97
1.97
22.46
4.63
17.33
20.68
0.33
3.15
4.54
95.23
4.77
100.00
a. Basis:
869 MW gro.'js new coal-fired power unit, 3.9% S in fuel; 83% SO- removal.
Stack gas reheat to 175°F by heated air injection.
Disposal pond located one mile from power plant. Pond sized for 30 yr
operation at 65% capacity.
Cost basis: mid-1975.
Minimum in-process storage; only pumps are spared.
297
-------
Table 115
LIME SLURRY PROCESS
ONSITE UNTREATED POND STORAGE
SUMMARY OF TOTAL DIRECT INVESTMENT3
(869 MW gross new coal-fired pover unit, 3.9% 5 in fuel;
83% S02 removal)
Direct Percent of
investment, $ direct -investment
Materials handling (lime bins, feeders,
conveyors, elevators)
Feed preparation (feeders, conveyors, slakers,
pumps, tank and agitator) ~'
Sulfur dioxide scrubbers (4 mobile bed
scrubbers, including feed plenum, pumps, mis£
eliminators, soot blowers, and tanks)
Stack gas reheat (4 heated air injection
reheaters, fans and ductwork) *
Gas handling (fans, and flue ductwork)
Calcium solids disposal (onsite disposal
pond, cla.y liner, tank, and pumps) «•••
Utilities (instrument air generation and
supply system, distribution system for
process steam, water and electricity)
Service facilities (buildings, shops, stores,
site development, roads, railroads, and
walkways)
Construction facilities
Subtotal direct investment excluding land
Land (616 acres)
Total direct investment
1,529,000
778,000
8,794,000
1,813,000 >
6,786,000
8,097,000
118,000
969,000
1,458,000
30,342,000
1,848,000
32,190,000
4.75
2.42
27.32
5.63
21.08*:
25.15
0.37
3.01
4.53
94.26
5.74
, 100.00
a. Basis:
869 MW gross new coal-fired power unit, 3.9% S in fuel; 83% S02 removal.
Stack gas reheat to 175°F by heated air injection.
Disposal pond located one mile from power plant. Pond sized Cor 30 yr
operation at 65% capacity.
Cost basis: mid-1975.
Minimum in-process storage; only pumps are spared.
298
-------
Table 116
LIMESTONE SLURRY PROCESS
ONSITE UNTREATED POND STORAGE
. ' SUMMARY OF TOTAL DIRECT INVESTMENT3
(869 MW gross new coal-fired power unit, 3.9% S in fuel;
83% S02 removal)
Direct Percent of
investment, $ direct investment
Materials handling (limestone receiving area,
hoppers, feeders, conveyors, elevators,
and bins) 1,139,000 3.10
Feed preparation (feeders, crushers, eleva-
tors, ball mills, tanks, and pumps) 2,362,000 6.43
Sulfur dioxide scrubbers (4 mobile bed
scrubbers, including feed plenum, pumps, mist
eliminators, soot blowers, and tanks) 9,140,000 24.87
Stack gas reheat (4 heated air injection
reheaters, fans and ductwork) 1,813,000 4.93
Gas handling (fans, and flue ductwork) 6,913,000 18.82
Calcium solids disposal (onsite disposal
pond, clay liner, tank, and pumps) 10,156,000 27.64
Utilities (instrument air generation and
supply system, distribution system for
process steam, water and electricity) 118,000 0.32
Service racilities (buildings, shops, stores,
site development, roads, railroads, and
walkways) 1,120,000 3.05
Construction facilities 1,638,000 4.46
Subtotal direct investment excluding land 34,399,000 93.62
Land (782 acres) 2,346,000
Total direct investment 36,745,000
a. Basis:
869 MW gross new coa.r-fired power unit, 3.9% S in fuel; 83% S02 removal.
Stack gas reheat to 175°F by heated air injection.
Disposal pond located one mile from power plant. Pond sized for 30 yr
operation at 65% capacity.
Cost basis: mid-1975.
Minimum in-process storage; only pumps are spared.
299
-------
Table 117
MAGNESIA SLURRY—REGENERATION PROCESS
SUMMARY OF TOTAL DIRECT INVESTMENT3
(869 MW gross new coal-fired power unit, 3.9% S in fuel;
83% S02 removal; 37.5 tons/hr 100% H-SO.)
Direct Percent of
investment , $ direct investment
Magnesium oxide and coke receiving and storage
(pneumatic conveyor and blower, hoppers, con-
veyors, elevators, and storage silos) 427,000 1.30
Feed preparation (feeders, conveyors, eleva-
tors, tank, agitator and pump) 505,000 1.54
Sulfur dioxide scrubbers! (4 ^anturi scrubbers
including feed plenum, pumps, mist eliminators,
soot blowers, and tanks) 5,102,000 15.51
Stack gas reheat (4 heated air injection
reheaters, fans and ductwork) 1,687,000 5.13
Gas handling (fans, ?nd flue ductwork) 8,276,000 25.15
Slurry processing (screens, tanks, pumps,
agitators and heating coils, centrifuges,
conveyors, and elevators 1,580,000 4.80
Drying (fluid bed dryer, fans, combustion
chamber, dust collectors, conveyors, eleva-
tors, and MgSO storage silo) 2,182,000 6.63
Calcining (fluid bed calciner, fans, feeders,
conveyors, elevators, waste heat boiler,
dust collectors, and recycle MgO storage silo) 2,466,000 7.50
Sulfuric acid plant (complete contact unit
for sulfuric acid production including dry
gas purification system) 6,666,000 20.26
Sulf'iric acid storage (storage and shipping
facilities for 30 days production of H-SO^) 585,000 1.78
Utilities (instrument air generation ana
supply system, fuel oil storage and supply
system, and distribution system for obtain-
ing process steam, water and electricity
from power plant) 472,000 1.43
Service facilities (buildings, shops, stores,
site development, roa;(s, railroads, and
walkways) 1,350,000 4.10
Construction facilities 1,565,000 4.76
Subtotal direct investment excluding land 32,863,000 99.89
Land (12 acres) 36,000 0.11
Total direct investment 32,899,000 100.00
a. Basis:
869 MW gross new coal-fired power unit, 3.9% S in fuel; 83% S02 removal.
Stack gss reheat to 175°F by heated air injection.
300 cost basis: mid-1975.
Minimum in-process storage; only pumps are spared.
-------
Table 118
LIME SLURRY PROCESS WITH ONSITE CALCINATION
ONSITE UNTREATED POND SlOKAfili
AVERAGE ANNUAL ntRECT OrERAflNf. COS^S*
(869 1HW gross coal-fired power unit, 3.'K S In fuel;
83Z S02 removal)
Total annual
Anmi.il quantity Unit cost, S cost, 5 o
Delivered raw material
Lines tone
Coal
Subtotal taw material
Conversion costs
Operating labor and supervision
Utilities
Process water
Maintenance
tabor and material - .06 x 37,291,000
Analyses
Subtotal conversion costs
Total direct costs
Equivalent unit direct operating cost
267.4 M ton 5.00/ton 1.337.000
31.3 M ton 21.58/ton 675,300
2,012/500
88,570 man-hr 11.75/nan-hr 1.0407700
282,900 M gal 0.10/M gal 28,300
2,237,500
6.045 man-hr 15.00/man-hr 90,700
Percent of
total direct
peratinp. cost
24.71
12.49
37.20
19.24
Q.52
41.36
1 . 68
* 3,397,200 62.80
5,049.700 .100.00
Dollars/ton b Cents/million Dollars/ton
coal hurried .' Mllls'/kKh Btu he.it input sulfur re-moved
2.5). 1.19 11.63 77
••f •
.49
a. Basis:
Life of power plant, 30 yr. at 651 capacity or 5694 hrs/yr.
Coal burned 2,156,550 tons/yr, 9404 Btu/kWh (f?ross>.
Stack gas 1 cheat to 175'F.
Direct investment, $39,157,000.
Investment and o|crating cost for removal and disposal of fly ash excluded.
Steam required from power plant 112,860 !i Ib (620'F, 130.3 psig).
b. Net electricity generated:
Steaa cycle output 868.6 MW
less: Scrubber 5.9 MW
ID fan 8-8
Other (from EGAS Fhase II, p. 7*!> 5J>.J
Total auxiliary losses _70.4 tW
Net output 798.2'WW
301
-------
Table 119
L1MF. SLURRY PROCESS
ONSITE I'NTRFATED I'OS'I) STOW/IE
AVERAGE ASNL'AL DIRECT OPERATING COSTS3
(869 MK gross coal-fired j>owr unit, 3.9" 3 In fuel;
832 SO removal)
Delivered raw material
Line
Subtotal raw material
Conversion costs
'Operating labor and supervision
Utilities
Process water
Maintenance
tabor and material - .06 x 30,342,000
Analyses ,
Subtotal conversion costs
Total direct costs
Percent of
Total annual total direct
Annu.il quantity Unit cost, $ cost, S op?ratlm! cost
134.9 M tons 28.03/ton
24,210 nan-hr 11.75/wan-lir
282,900 M gal 0.10/M gal
4,030 raan-hr 15.00/raan-hr
3,777,200
3,777,200
3. 26
63.26
284,500
28,300
1,820,500
60,500
2,193,800
5,971,000
4.76
0.48
30.* 9
1.01
36.74
100.00
Equivalent unit, direct operating cost
Dollars/ton Cents/million Dollars/ton
coal burned Mtlls/kMi Btn heat Input sulfur rrnovod
2.77 1.31 12.83 ' 85.53
a. Basis:
Life of power plant, 30 yr. at 65% capacity or 5694 hrs/yr*
:-'•: Coal burned 2,156,550 tons/yr, 9404 Btu/kUh (gross). .
Stack g^s reheat to 175°F.
Direct investment, 532,190,000.
Investment and operating cost for rcinoval and disposal of fly ash excluded.
Steam required frorc powur plant 112,860 M Ib (620°F, 130.3 psip).
b. Net electricity genorated:
Steam cycle output 868.6 MU
less: Scrubber 5.2 HH
ID fan 8.8
Other (from EGAS Phase II, p. 72) 55.7
Total auxiliary losses 69.7 W.3
Ket cutpot 798.9 MW
302
-------
Table 120
LIMESTONE SLURRY PROCESS
ONSITE UNTREATED t'OSD STORAGE
AVERAttE ANNUAL DIRECT OPERATING COSTS3
(869 KM gross coal-fired power unit, 3.9," S in fuel;
83X S02 removal)
Delivered raw material
Llrccs tone
Subtotal raw material
Conversion costs
Operating labor and supervision
Utilities
Process water
Maintenance
La.^or and material - .06 x 34,399,000
Analyses
Subtotal conversion costs
Total direct costs
Equivalent unit direct operating cost
Percent of
Total annual total direct
cost, $ opfr.-itlnp. cost
336.8 M tons
35,040 tnan-hr
403,200 H gal
5,040 tnan-hr
5.00'i.on
11.75/nan-hr
0.08/K gal
15.00/roan-hr
Dollars/'-on . Cents/mil
ccal burned Mllls/kWh Btu heat
1,684,000 39.46
1.6K4.000 39.46
411,700 9.65
32,300 P. 76
2,063,900 48.36
75,600 1.77
2,583,500 60.54
4,267,500 100.00
Mon Dollars/con
input sulfur renewed
a. Basis:
Life of power plant, 30 yr. at 65% capacity or 5694 hrs/yr.
Coal burned 2,156,550 tons/yr, 9404 Btu/kVh (Rross).
Stack gas reheat to 175°F.
Direct investment, $36,745,000.
Investment and operating cost for removal and disposal of fly ash excluded.
StcjiD required from power plant 112,860 M Ib (620°F, 130.3 pslfi).
b. Net electricity Reneratcd:
Stcara cycle output 868.6 MW
less: Scrubber 5.6 HW
ID fan 9.2
Other (from EGAS Phnse II, p. 72) 55.7
Total aaxlllary losses 70.5 MW
Net output 798.1 >!W
303
-------
Table 121
MAT.HESIA SLURRY PROCESS
AVERAGE ANNUAL DIRKCT OPERATING COSTS"
(669 IIU' gross coal-flrod power un;
83X S02reraovai; 37.5 tons/hr
Annual quantity
Delivered raw material
Haf.nc=Ium oxide (9£2)
Coke,.,
Catalyst
Subtotal raw material
Converrion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process vater
Maintenance
Labor and material - .06 x 32,863,000
Analyses
Subtotal conversion costs
Total direct costs
Dollars/ton
100% H2SO,,
Equivalent unit direct
operating cost 29.37
2,075 tons
1,473 tons
4,137 liters
?9,000 man-hr
10,340 M gal
4,118,900 H gal
11,390 raan-hr
Dollars/ton
coal burned Ml^l
r
2.91 ;
t, 3.92 S in fuel;
.:o-ir. • n2so4>
Percent jf
Total annjul total d'rect
I'nlt cost, $ cost^ 5 oi>«ratlrr cost
155.00/ton
2 j.SiVton
1.65/litcr
11.75/man-hr
0.30/M gal
0.05/M gal.
•<•
15.00/man-hr
.321,600
34,600
6,800
36i,000
•"•
458.300
3.102.0T.O
205,900
1,971,800
1 70^900
5,908,900
6,271,900
Cents/million Dollars
p/kWi Btu heat
.36 13.
input sulfur, r
48 . 89.
5.13
0.55
O.li
5.79
7.31
-
49.46
" 3.28
31.44
2.72
•94.21
100.00 j~
tr.n
i-r.aved
85
a. Basis:
life of power plar.t, 30 yr. at 65% capacity or 5694 hrs/yr.
Coal burned 2,156,550 tons/yr, 9404 Btu/kV.1i {gross).
Stack gas reheat to 175°F.
Direct investment, 532,£99, "X)!).
Investment and operatinj cost for removal and disposal of fly ash excluded.
Stean required froa povcr plant, 967,980 M Ib (620"F, 130.3 psig).
Sttam credit to power plant, 42,840 Ib (366°F, 165 psig).
b. Set electricity generated:
Steam cycle output
less: Scrubber 8.2
ID fan 8.8
Other (from EGAS Phase II, p. 72) 55.7
Total auxiliary losses
Kct output
868.6 KW
-------
D. ALTERNATIVE DISPOSAL METHODS
Alternative solids disposal methods wore considered for the CWS, AFB,
and PFB plants. The AFB and PFB plants were desip,ned under EGAS premises
which provided only for facilities to haul all solid wastes offsite. The
CWS plants costs included a pond for 5-year storage of sludge. To place
the three plants on a more comparable basis, capital and O&M costs were
examined for alternative methods for 30-year disposal.
Scrubber Sludge
Fling, et al.,— compares three sludge fixation systems: Chemfix,
Dravo, and IUCS. In the present study, the Drnvo process has been selected
for estimating the cost of sludge fixation because Fling reports Chemfix
is more expensive and IUCS requires fly ash. The following methods of
disposal were considered for cost estimation:
1. Store untreated in clay-lined pond.
The spent scrubber slurry is pumped to a clay-lined
settling pond located one mile from the power plant.
The supernatant is recycled to the scrubbing area.
It was assumed that the sludge would settle to
40 percent solids.
2a. Store ''ixed in clay-lined pond.
Spent slurry id concentrated to about 32-38 percent
solids in a thickener, then mixed with a fixing agent.
The sli^jge is then pumped to .1 settling pond where
it settles to about A3 percent solids and cures under
water. The supernatant is recycled to the scrubbing
area. This design is based on the system that Dravo
is installing for Pennsylvania Power Company's Bruce-
Mansfield station. The cost per ton of scrubber
sl-irry solids is significantly higher, primarily
because the disposal pond is more expensive than
damming a ravine.
2b. Fix, store onsite in clay-lined diked impoundment.
Spent slurry is concentrated to about 32-38 percent
solids in a thickener, then mixed with a fixing
agent. The sludge IB pumped to one of three 30-day
capacity settling ponds. The sludge settles to about
40 percent solids and cures in 30 days. The super-
natant is drained from the pond and the fixed sludge
is dredged and conveyed to a diked impoundment. A
collecting basin is included in the diked impoundment
to catch any runoff. The fixed sludge is piled to an
average depth of 30 ft.
305
-------
3. Haul offsite, store fixed in clay-lined diked impoundment
This is similar to the previous case, 2b., except
the conveyor is eliminated and instead the fixed
solids are trucked offsite to the impoundment.
The cost estimates for these waste disposal systems arc shown in Table 122.
Fluidized Bed Combustion Solid Wastes
General Electrici' states that the fluidized bed combustion solid wastes
have the following components:
a. Atmospheric fluidized bed.
42% calcium sulfate
31% ash
24% unreacted linie
3% carbon
b. Pressurized fluidized bed
42% ash
26% calcium sulfate *
16% magnesium oxide :
13% unreacted lime ,». ,
4% unburned carbon *~
The costs for disposinp of these wastes are not included in the GE study.
In making an objective evaluation of fluidized bed combustion the disposal
costs must be considered. The following three methods have been identified as
viable options in disposing of AFB and FFB wastes:
1. Store untreated in clay-lined pond.
The solids are slurried ?nd sluiced to a clay-lined pond
where the solids are allowed to settle and the supernatant
is recycled. The solids as received are water free. When
they are slurried, some of the constituents will take on
water of hydration. It was assumed that after hydrating,
the sludge fron the atmospheric fluidized bed process
would settle to 45 percent solids and the sludge from
the pressr.rizec. fluidized bed process woult* settle to
43 percent solids.
2. Store onsite, treated in clay-lined diked impoundment.
The solids are transported to the disposal sire with a
mile-long enclosed conveyor. Tr fix this material all
that is needed is a moderat-. f i nrt (10 kWh/ton) and
addition of water (10 percent _•> weight). The lime
present should earner.* .he. solids into a dense concrete-
like material. A clay-lined diked impoundment with a
collection basin to catch any runoff is included
A o 306
-------
al'-hough the need for an impoundment is questionable.
The treated solids are piled to an average depth of
30 ft.
3. Haul offsite, store treated in clay-lined diked
impoundment.
/
This is similar to the previous case except the conveyor
is eliminated and instead the solids are trucked offsite
to the impoundment.
The cost estimates for these waste disposal systems are shown along with the
CWS disposal systems in Table 122.
307
-------
E. COST OF ELECTRICITY (C.O.E.) BASED ON TVA MODIFICATIONS
The GE study modifications suggested by TVA may be used to calculate the
C.O.E. associated with the plant types studied. The C.O.E. for the PFB and
AFB plants reflect the increase in capital costs due to uncertainty allowances
in equipment estimates and to solids disposal costs. The C.O.E. for different
CWS .alternatives reflects similar influences with additional sensitivity to
the type of wet scrubber used.
The GE study cost estimates included capital and O&M charges for a lime
slurry scrubber with onsite calcination. To determine the sensitivity of
the CWS plants to the alternative scrubber cases, it is necessary to substi-
tute the TVA scrubber estimates for the costs estimated for the GE scrubber.
Table 123 is a calculation breakdown of alternative scrubber costs. Utiliza-
tion of these results with the TVA modifications previously discussed yield
the breakdown as seen in Table 124. The GE plane costs are identical tc
those presented in the GE study with no TVA modifications. The 1VA alterna-
tive scrubber estimates shown include TVA modifications to the GE conventional
plant and reflect both capital and O&M differences due to the different scrubber
types.
The C.O.E. for the AFB and PFB plants includes differences in solids
disposal requirements. Table 125 presents calculations for both onsite and
offsite disposal costs for tha two plant types. The result of these, calcula-
tions incorporated with estimates discussed in previous sections yields the
C.O.E. calculations found in Table 126. Both the GE study estimates and
those estimates as modified by TVA include the additional solids disposal
requirements to calculate C.O.E. for the AFB and PFB plant types.
Combination of the results found in Tables 123 through 126 yields Table
127. Table 127 gives a C.O.E. breakdown for the plants utilizing both the GE
and the TVA estimates. All estimates in Table 127 incorporate solids disposal
costs. Changes in the C.O.E. calculated by GE for the CVS, AFR, and PFR are
reflected in the capital and O&M requirements, but not in fuel requitements
as no change in plant efficiency resulted from TVA modifications.
Cost of Electricity Sensitivity
The costs of electricity presented in Table 127 are based on the guide-
lines set forth in EGAS. Certain parameters were selected to reflect utility
practice. Among these parameters are cost of fuel, fixed charge rate, and
capacity factor. The costs of electricity for all power plants are sensitive
to changes in these parameters. The cost of fuel was assumed to be $1.00/
106Btu. Variations in this parameter directly affect the fuel portion of
C.O.E. The capacity factor was set at 65 percent. This is reasonable but
actual utility practice may find the capacity factor much different, changing
both the O&M and capital portions of C.O.E. The fixed charge rate, set at
18 percent per year, also varies within the utility industry and relates
directly to the capital portion of C.O.E.
The C.O.E. for CWS, AFB, and PFB are all affected by the parameter
changes mentioned. Representative plant estimates as modified by TVA were
309
Preceding page blank
-------
Table 122
SOLIDS DISPOSAL D KECT INVESTMENT AXD:OPERATING COSTS3
Direct Investment Cost of Annual direct Dry solid'
excluding land, S land, $ oper.it ins costs, S . ton; -'hr
I.
II.
a.
Fluldir.ed bed combustion
A. Atmospheric fluidized bed combustion
1. Store untreated in 'clay-lined pond
2. Store onslte, treated in clay-lined,
diked impoundment
*" 3, Haul off site, store treated in clay-
lined diked impoundment
R. Pressurized fluidized bed combustion
1. Store untreated In clay-lined pond
2. Store onsitc treated in clay-lined,
diked Impoundment
3. Haul of. site, store treated in 'clay-
lined, (.iked impoundment
Scrubber sludge
A. Lime vet scrubber
1. Store untreated in clay-lined pond
2. a. Store fixed in clay-lined"" pond
b. Fix, store onsite Jn clay-lined,
diked impoundment
3. Fix, haul offsite, store in clay-
lliic-it, diked impoundment
B. Limestone wet scrubber
1. Store untreated In clay-lined pond
2. a. Store fixed in -clay-1 ined pond
b. Fix. itore, onsite in clay-lined,
diked impoundment
3. Fix, haul offsite, store in clay-
lined, diked impoundment
Basis:
Ke« coal-fired power unit, onstream time 5694
IU.545,000
3,785,000
2,686,000
17,673,000
4,612,400
3,420,000
.-. ! -*•*
8,097,000
8,969,000
-,•*•
5,322,000
4,364,000
A -
10,156,000
11. 156,001
6,722,900
5,694,400
3,348,400
1,104,000
1,114,000
4,101,000 .: .
"*•
1,425,000
1,425,000
1,806,000
1, 806,000
*•
1,359,001
1,359,000
2,104,000
2,304,000
1,845,900-
1,845,900
983.400
1,191,200
1,729,600
1,157,600
1,524,900
2,174,500
564.100
2,149.400
2,010.400C
•>• (^
2,294,900
694,700 •
2,840;900
X
2,727.100
ft
3.131.000
119
11?
11?
1.54
154
.154
5-1.6
•• 54.6
54.6
54.6
74.9
74.9
74; 9
74.9
hr/yr 1975, operating costs.
3.9? S in fuel, S02 emitted <1.2 lb/106 Btu heat input.
b.
c.
A.
Dry solids composition:
I. A. Atmospheric I.B. Pressurized
42Z CaSOu «* Ash
31* Ash 267. CaSO,,
24% CaO 16? MgO
3Z C 13Z CaO
«Z C
Included is raw material costing SI ,078,800/yr.
Included is raw material costing Sl,478,700/yr.
II. A. Lime
76% CaS03
18% CaSO^
5X CaO
•1/2 H^O
•2 H20'
1% Insolubles
U.K. Limestone
46i CaSOi-
26Z CaSCV
261 CaCOj
1/2 R. •
2 H;0'
2Z Insolubles
310a
-------
Table 123
ALTERNATE SCRUBBER COSTS (EXCLUDING DISPOSAL)
CAPITAL AND O&M COSTS,FOR SCRUBBER ALTERNATIVES
(NO DISPOSAL COSTS ARE INCLUDED)
LIME WITH
ONSITE CALCINATION
LIME WITH
OFFSITE CALCINATION
CAPITAL COSTS ($M) ..
Direct investment for scrubber
Less direct investment for disposal
Less land costs for disposal(b)
Net scrubber directs
Indirect field costs @ 25%
Total direct construction
A&E (? 15%
Contingency @ 20%
Total 1975 1/2 Cost ($M)
O&M COSTS (MILLS/kWh)
Direct operating costs
Direct nonfixed disposal costs
Net O&M directs
Overhead @ 50%
Total O&M
(b)
36.57
5.49
R. 41
50.47
27.85
4.18
6.41
38.44
1.31
-0.12
LIMESTONE
36.75
-10.16
-2.30
1.60
0.94
-Q.15
0.69
0.34
1.03
MAGNESIA
W/REGENERATIOB
9.46
56.75
2.07*
*Sale of sulfuric acid would yield additional credit of 1.18 mill/kWh.
(a) From Table 112.
(b) From Table 122.
o
cr
-------
UaMe 124
CONVENTIONAL/WET SCRUBBER PLAMTS
CAPITAL
CE
TVA (1975) '
CE Scrubber & Disp.
TVA Scrubber^)
TVA Disposal
Total 1975
ESC & I.D.C.
Total 1980 (SM)
Cast/Ml (S/kW)
Total Capital
CE CWS
250 F/LIME
5 YR. DISPOSAL
8 FT/SEC
747.2 MU
331.7
71.6
403.3
221.0
624.3
835.4
CE CWS
175 F/LIME
5 YR, DISPOSAL
8 FT/ SEC
795.5 HH
334.0
62.4
396.4
217.2
613.5
771.3
TVA CMS
175 F/LIKE
30 YR. DISPOSAL
12.5 FT/SEC
W/CALCINATION
398.03
-62.40
50.47
15.91
402.0
220.3
622.3
782.3
TVA CBS
175 F/LIME
30 YR. DISPOSAL
12.5 FT/SEC
OFFSITE
CALCINATION
398.03
-62.40
38.45
' 15.91
390.0
213.7
603.7
758.9
TVA CWS
175 F/L1MF.STOME
30 YR. DISPOSAL
12.5 FT/SEC
398.03
-62.40
41.89
20.18
397.7
217.9
615.6
771.9
TVA CWS
175 F/MRO
REfiEKERABLE 12.5 Fl/SEC
W/H,SO, CREDIT
£, **
398.03
-62.40
56.75
0.00
392.4
215.0
607.4
763.6
TVA rws
175 F/MfcO
REGENERABLE 12.5 FT/SEC
NO H,S04 CREDIT
•
398.03
-62.40
56.75
0.00
391.4
215.0
607.4
736.6
26.40
24.38
24.73
23.99
24.47
24.15
24.15
04M
GE
CE Scrubber
TVA Scrubber
TVA IH3pos.il
Total O&M
2.61
2.61
2.45
2.45
2.45
-0.97
1.60
0.66
3.74
2.45
-0.97
1.78
0.66
3.92
2.45
-0.97
1.03
C.90
3.41
2.45
-0.97
0.89
0.00
2.37
2.45
-0.97
2.07
0.00
3.55
FUEL
•n * v,,f*
Total FUEL
10.10
10.10
10.10
10.10
10.10
10.10
10.10
C.O.E._
39.83
36.93
38.57
38.00
37.99
36.62
37.80
(a) rxchitii-n scrubber and dinpo>,al cone.
(t>) Includes GE'a scrubber and disposal cost.
(c) CE estimate of tin* scrubber and '. /ear disposal cost.
(d) Fron Table 123.
-------
table 125
AFB
PFB
SOLIDS DISPOSAL COSTS FOR FLUIDIZED BED
COMBUSTION PLANTS (ADDITIONAL TO GE ESTIMATES)
CAPITAL COSTS ($M)
Direct investment
Indirect field expense @ 90%
Land
Total direct construction
A&E @ 15%
© Contingency @ 20%
Total 1975 1/2 cost ($M)
O&M COSTS
Direct operating costs
Overheads @ 50%
Total operating costs
ONSITE
3.78
3.41
1.10
8.29
1.24
1.91
11.44
0.26
0.13
0.39
OFFSITE
2.69
2.42
1.10
6.21
0.93
1.41
8.57
0.37
0.18
0.55
OMSITE
4.61
4.15
1.43
10.19
1.53
2.34
14.06
0.30
0.15
0.45
OFF SITE
3.42
3.08
1.42
7.92
1.19
1.82
10.93
0.42
0.21
0.63
-------
Table 126
FLUIDIZED BED COMBUSTION POWERPLANTS
TOTAL COST OF ELECTRICITY (C.O.E.)
(INCLUDING SOLIDS DISPOSAL COSTS)
CAPITAL
Powerplant cost
Disposal cost
Total 1975 cost
ESC & I.D.C.
Total 1981 cost ($M)
Cost/kW ($/kW)
Capital C.O.E. (
AFB
GE TVA
PFB
TVA
ON
332.5
11.4*
343.9
188.5
5 32. A
654.0
OFF
332.5
8.6*
341.1
186.8
527. C
648.5
ON
363.1
11.4
374.5
205.3
579.9
.712.4
OFF
363.1
8.6
371.7
203.3
575.0
.706.4
ON
421.0
14.1
435.1
238.4
673.5
745.0
OFF
421.0
10.9
431.9
236.7
668.6
739.6
ON
479.5
14.1
493.5
270.4
793.9
845.1
OFF
479.5
10.9
490.4
268.73
759.1
839.7
20.67 20.50 22.52 22.33 23.55 23.38 26.72 26.55
CO
I-1
to
O&M
Plant O&M
Disposal
O&M C.O.E. (;
(GE)
.Mills,
kWh
2.22
0.39
2.61
2.22
0.55
2.77
2.22
0.39
2.61
2.22
0.55
2.77
2.53
0.45
2,98
2.53
0.63
3.16
2.53
0.45
2.98
2.53
0.63
3.16
FUEL
FUEL C.O.E.
.Hills.
* kWh '
9.53
9.53 9.53
9.53
8.71
8.71
8.71
8.71
*From TVA estimates.
-------
Table 127
COMPARISONS OF COSTS CONSIDERING VARIOUS TYPES OF SCRUBBERS AND
ALTERNATE METHODS OF WASTE DISPOSAL
u>
cr
TOTAL CAPITAL
$/kW
Conventional With Scrubber
GE/CWS/250F/5 yr. disp./lime w/calcination/747 KW 835.4
GE/CWS/175F/5 yr. disp./lime w/calcination/795 MW 771.3
TVA/CWS/175/30 yr. disp./lime w/calcination/795 MW • 782.3
TVA/CWS/175F/30 yr. disp./lime (purchased)/795 MW 753,9
TVA/CWS/175F/30 yr. disp./limestone/795 MW 773.9
TVA/CWS/175F/MgO/Regenerable/795 MW W/l^SO^ credit 728.0
TVA/CWS/175F/MgO/Regenerable/795 MW NO H2S04 credit 728.0
Fluidized Bed Power Plants
GE/AFB/onsite disposal (30 yr.) 814 MW 654.0
GE/AFB/offsite disposal (30 yr.) 814 MW 648.5
GE/PFB/onsite disposal (30 yr.) 904 MW 745.0
GE/PFB/offsite disposal (30 yr.) 904 MW 739.6
TVA/AFB/uncertainties added/onsite disposal (30 yr.) 814 MW 712.4
TVA/AFB/uncertainties added/offsite disposal (30 yr.) 814 MW 706.4
TVA/PFB/uncertainties added/onsite disposal (30 yr.) 904 MW 845.1
TVA/PFB/uncertainties added/offsite disposal (30 yr.) 904 MW 839.7
GE/AFB/no disposal/Si^ MW 632
GE/PFE/no disposal/9Ck MW 723
COST OF ELECTRICITY (Mills/kWhJ
CAPITAL O&M FUEL TOTAL
26.40
24.38
24.73
23.99
24.47
23.01
2.3.01
2.61
2.45
3.74
3.92
3.41
2.37
3.55
10.73
10.10
10.10
10.10
10.10
10.10
10.1 ;
39.83
36.93
38.57
38,00
37.99
35.48
36.66
20.67
20.50
23.55
23.38
22.52
22.3'J
26.72
26.55
20.00
22.90
2.61
2.77
2.98
3.16
2.61
2.77
2.98
3.16
9.50
8.70
9.53
9.53
8.71
8.71
9.53
9.53
8.71
8.71
2.20
2.50
32.81
32.80
35.24
35.25
34.66
34.63
38.41
38.42
31.7
3^.1
-------
'~
used to develop the C.O.E. sensitivity plots as seen in Figures 46 through AS.
These plants are:
(1) CWS - CWS with TVA modifications
(Lime w/offsite calcination)
(2) AFB - AFB with TVA modifications (including solids disposal)
(3) PFB - PFB with TVA modifications (including solids disposal)
The sensitivity of C.O.E. to cost of fuel is seen in Figure 46. The attractive-
ness of PFB is seen to increase with rising fuel costs due to its higher
efficiency. Figure 47 shows the sensitivity of" the three plant types to
changes in the fixed charge rate. Here the PFB becomes less attractive with
increasing fixed charge rate because of its higher capital cost. Changes in
capacity factor affect C.O.E. as shown in Figure 48. Increasing the
capacity factor makes the cost of PFB lower relative to the CWS, again
reflecting higher PFB efficiency.
In all three plots of C.O.E. sensitivity, the AFB shows lower C.O.E.
than the CWS and PFB.
§14
-------
80J.
40
.as
>%
V,
lu
q
6
2 30.
35.
4-
PFB
AFB
EC. RATE =18%
CAR FAC. =.65
.90 1.00 1.50 2.00
COST OF FUEL (S/IO6 Btu)
2.50
Figure 46. Effect of Fuel Cost on Total Cost of
Electricity
315
-------
49..
40.,
3
uj
o
d
39..
o ••
30..
RC.RATE« 18%
FUEL COST*$l.OO/lO* Btu
PWS
AFB
-f-
-f-
.50
.60 .70 .80
CAPACITY FACTOR
Figure 47. Effect of Capacity Factor on Total Cost
of Electricity
316
-------
454.
PFE
40..
CO
2
30..
AFB
FUEL COST =31.00/10* Btu
CARFAC.».65
-4-
12 13 tS 21
FIXED CHARGE RATE (%)
Figure 48. Effect of Fixed Charge Rate on Total Cost
of Electricity
o
317
-------
References
1. General Electric Company. "Study of Advanced Steam Cycles for Utility
Application." Oral briefing, March 24, 1976, updated April 8, 1976,
Knoxville, Tennessee.
2. McGiamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
L. J. Henson, S. V. Tomlinson, and J. F. Young. "Detailed Cost
Estimates for Advanced Effluent Desuifurization Processes." Prepared
for the U.S. Environmental Protection Agency. TVA Bulletin Y-90,
January 1975.
3. Koehler, George, and James A. Burns. "The Magnesia Scrubbing Process
as Applied to an Oil-Fired Power Plant." Prepared for the U.S.
Environmental Protection Agency. October 1975.
4. Fling, 'A. B., W. M. Graven, F. D. Hess, P. P. Leo, R. C. Rossi, and
J. Rossoff. "Disposal of Flue Gas Cleaning Wastes: EPA Shawnee Field
Evaluation—Initial Report." Prepared for the U.S. Environmental
Protection Agency. March 1976.
5. Connan, J. C., et al., Energy Conversion Alternatives Study (EGAS),
General Electric Phase II Final Report, NASA CR-134949, 3 vols., NASA
Lewis Research Center Contract NAS3-19406, GE Corporate Research and
Development, Schenectady, N.Y., December 1976.
6. Beecher, D. T., et al., Energy Conversion Alternatives g'tudy (FCAP),
Westinghouse Phase II Final Report, NAL-A CR-13^9^, vol. Ill, KAt'A
'"'• Lewis -Research Center Contract HAS3-19^06, Westinghouse Electric.
Corporation, Pittsburgh, PA, November 1976.-
313
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