EPA
TVA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/8-81-00£
Laboratory MARCH 1981
Research Triangle Park, NC 27711
Tennessee Valley
Authority
Office of Power
Division of Energy
Demonstrations
and Technology
TVA/OP/EDT-81/15
Computerized Shawnee
Lime/Limestone Scrubbing
Model Users Manual
Interagency
Energy/Environment
R&D 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 nine series. These nine broad cate-
gories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the SPECIAL REPORTS series. This series is
reserved for reports which are intended to meet the technical information needs
of specifically targeted user groups. Reports in this series include Problem Orient-
ed Reports, Research Application Reports, and Executive Summary Documents.
Typical of these reports include state-of-the-art analyses, technology assess-
ments, reports on the results of major research and development efforts, design
manuals, and user manuals.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/8-81-008
TVA/OP/EDT-81/15
MARCH 1981
Computerized Shawnee
Lime/Limestone Scrubbing
Model Users Manual
by
W. L. Anders and R. L. Torstrick
TVA, Office of Power
Division of Energy Demonstrations
and Technology
Muscle Shoals, Alabama 35660
EPA-IAG-79-D-X05 1 1
EPA Project Officer: Michael A. Maxwell
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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DISCLAIMER
The Tennessee Valley Authority makes no representation or warranty of
any kind, including, but not limited to, representation or warranties,
expressed or implied, or merchantability, fitness for use or purpose,
accuracy or completeness of processes, procedures, designs, definitions,
instructions, information, or functioning of this model and related
material; nor does TVA assume any liability, responsibility, or obliga-
tion arising from the use of the model or related materials.
11
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ABSTRACT
This manual provides a general description of the Shawnee lime-
limestone scrubbing computerized design - cost-estimate model and the
detailed procedures for using it. It is a revision of an earlier manual
(1979). All inputs and outputs are described along with the options
available. Design and economic premises are included. The model is
based on Shawnee Test Facility scrubbing data and includes a combination
of material balance subsystems provided to the Tennessee Valley Authority
(TVA) by Bechtel National, Inc., and capital investment - revenue require-
ment subsystems developed by TVA. As key features, the model provides
estimates of capital investment and operating revenue requirements for a
lime or limestone scrubbing facility. Also provided are a material
balance, equipment list, and a breakdown of costs by processing areas.
The primary uses of the model should be for projecting comparative
economics of lime or limestone flue gas desulfurization processes (on
the same basis as the model) or in the evaluation of system alternatives
prior to the development of a detailed design.
iii
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CONTENTS
Abstract iii
Figures vii
Tables viii
Introduction 1
General Information 3
Current Scope 3
Future Development 3
Availability 4
Model Description 5
Input 5
Output 5
Options 7
Print Options 8
Particulate Collection Device Option 8
Reheat Option 12
Emergency Bypass Option 12
Partial Scrubbing/Bypass Option 14
Coal-Cleaning Option 14
Input Composition Option 17
Particulate Removal Option 19
S02 Removal Option 21
Operating Parameter Calculation Option 23
Scrubbing Absorbent Option (Lime or Limestone) 25
Chemical Additive Option 25
Forced-Oxidation Option 31
Fan Option 31
Scrubbing Option 34
Redundancy Options 34
Waste Disposal Option 36
Pond Design Option 43
Pond Liner Option 45
Economic Premises Option 45
Sales Tax and Freight Option 48
Overtime Option 54
Separate Pond Construction Indirect Investment Factors Option . . 54
Pond Capacity Option 55
Operating Profile Option 55
v
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Usage of the Model 62
References 66
Appendix A: Process Flowsheets and Layouts A-l
Appendix B: Design and Economic Premises B-1
Appendix C: Detailed Descriptions of Model Input Variables C-l
Appendix D: Base Case Input and Printout D-l
VI
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FIGURES
Number Page
1 Controlled SC>2 emission requirements for 1979 NSPS. Premise
coals, shown underlined, are based on premise boiler
conditions 22
2 Pond construction configuration 44
3 Operating profile assumed for IOPSCH = 1 based on old TVA
premises 58
4 Operating profile assumed for IOPSCH = 2 based on historical
Federal Energy Regulatory Commission data 58
A- 1 Limestone scrubbing process utilizing TCA absorber A- 2
A- 2 Limestone scrubbing process utilizing a spray tower A- 3
A- 3 Limestone scrubbing process utilizing a venturi - spray
tower A- 4
A- 4 Lime handling and preparation area for lime scrubbing option . A- 5
A- 5 Plan and elevation for TCA A- 6
A- 6 Plan and elevation for spray tower A- 7
A- 7 Plan and elevation for venturi - spray tower A- 8
A- 8 Waste disposal options 1 and 2 A- 9
A- 9 Waste disposal options 3 and 4 A-10
A-10 Single tank oxidation loop A-ll
A-ll Double tank oxidation loop A-12
A-12 Plan and elevation for TCA utilizing forced-draft fans .... A-13
A-13 Plan and elevation for partial scrubbing with bypass duct . . A-14
B- 1 Rosin-Rammler plots of premise coal sizes B- 8
B- 2 Boiler flow diagram B-28
B- 3 Controlled S02 emission requirements for 1979 NSPS. Premise
coals, shown underlined, are based on premise boiler
conditions B-26
B- 4 Pond plan and dike construction details B-35
B- 5 Landfill plan and construction details B-36
B- 6 Construction schedule B-37
B- 7 Process area cost summary sheet B-42
B- 8 Area summary sheet B-42
Vll
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TABLES
Number Page
1 Variable Ranges 6
2 Example Short Form Printout 9
3 Mechanical Collector Cost Illustration 13
4 Example Results Showing Partial Scrubbing/Bypass 15
5 Example Results Showing Coal Cleaning 18
6 Example Results Showing User Input Flue Gas Composition ... 20
7 Lime Scrubbing Output Listing 26
8 Lime Option Inputs and Raw Material Preparation Area .... 27
9 Example Results Showing the Addition of Adipic Acid 29
10 Example Results Showing Forced Oxidation, Two Effluent Tanks 32
11 Example Results Showing Forced Oxidation, One Effluent Tank 33
12 Venturi - Spray Tower Absorber Cost Illustration 35
13 Example Results Showing No Redundancy 37
14 Example Equipment List for Sludge Option 2 38
15 Example Equipment List for Sludge Option 3 39
16 Example Equipment List for Sludge Option 4 40
17 Example Revenue Requirements for Sludge Fixation
Alternative (Sludge Option 3) 42
18 Example of Optimum Pond Subject to Area Limits 46
19 Synthetic Pond Liner Example 47
20 Example Revenue Requirements Using the New Economic
Premises With No Levelizing 49
21 Example Revenue Requirements Using the Old Economic Premises 51
22 Example Investment Summary Sheet With Sales Tax and
Freight Excluded 53
23 Example Investment Summary Sheet With Common Indirect
Investment Factors for Process and Pond 56
24 Example Lifetime Revenue Requirements Using the Old TVA
Premises Operating Profile 59
25 Example Lifetime Revenue Requirements Using the Historical
FERC/FPC Operating Profile 60
26 Example Lifetime Revenue Requirements Using A User-
Supplied Operating Profile 61
27 Example Procedure for Executing the Model in Batch Mode ... 64
28 Example Batch Run to Execute the Model Using a Procedure
File 64
29 Sample Procedure for Executing the Model Interactively ... 65
B- 1 Composition of Premise Coals B- 7
B- 2 Fly Ash Compositions B- 6
B- 3 Power Unit Remaining Life, Operating Time, and Heat Rate . . B-10
B- 4 Boiler Material Balance - Eastern Bituminous Coal, 5% Sulfur B-ll
B- 5 Flue Gas Composition for 5% Sulfur Eastern Bituminous Coal . B-12
viii
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TABLES (continued)
Number
B- 6 Boiler Material Balance - Eastern Bituminous Coal,
3.5% Sulfur B-13
B- 7 Flue Gas Composition for 3.5% Sulfur Eastern Bituminous Coal B-14
B- 8 Boiler Material Balance - Eastern Bituminous Coal,
2.0% Sulfur B-15
B- 9 Flue Gas Composition for 2% Sulfur Eastern Bituminous Coal . B-16
B-10 Boiler Material Balance - Eastern Bituminous Coal,
0.7% Sulfur B-17
B-ll Flue Gas Composition for 0.7% Sulfur Eastern Bituminous Coal B-18
B-12 Boiler Material Balance - Western Bituminous Coal,
0.7% Sulfur B-19
B-13 Flue Gas Composition for 0.7% Sulfur Western Bituminous Coal B-20
B-14 Boiler Material Balance - Western Subbituminous Coal,
0.7% Sulfur B-21
B-15 Flue Gas Composition for 0.7% Sulfur Western Subbituminous
Coal B-22
B-16 Boiler Material Balance - North Dakota Lignite, 0.9% Sulfur B-23
B-17 Flue Gas Composition for 0.9% Sulfur North Dakota Lignite . . B-24
B-18 1979 Revised NSPS Emission Standards B-25
B-19 Premise Coal Emission Standards B-27
B-20 Reheater Data B-32
B-21 Sample Reheater Calculations B-31
B-22 Raw Material Characteristics B-33
B-23 Cost Indexes and Projections B-37
B-24 Cost Factors B-38
B-25 Capital Cost Estimate Classification B-40
B-26 Capital Investment Sheet B-41
B-27 Range of Indirect Investments B-44
B-28 Contingency B-45
B-29 Allowance for Startup and Modifications B-45
B-30 Interest During Construction Illustration B-46
B-31 Annual Revenue Requirements Sheet B-50
B-32 Sample Electrical Requirement Calculation B-52
B-33 Maintenance Factors B-53
B-34 Maintenance Factors for Specific FGD Processes B-53
B-35 Levelized Annual Capital Charges B-54
B-36 Levelizing Factors B-58
C- 1 Model Inputs - Fortran Variable Names C- 2
C- 2 Model Input Variable Definitions C- 3
C- 3 Limestone Fineness of Grind Index Factor . C-17
D- 1 Base Case Printout D- 2
ix
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COMPUTERIZED SHAWNEE LIME/LIMESTONE SCRUBBING MODEL
USERS MANUAL
INTRODUCTION
Since 1968 the U.S. Environmental Protection Agency (EPA) has
sponsored a flue gas desulfurization (FGD) test facility at the Tennessee
Valley Authority (TVA) coal-fired Shawnee Steam Plant near Paducah, Kentucky.
TVA is the constructor and operator and Bechtel National, Inc., is the
major contractor. The test facility originally consisted of three
prototype-size scrubber units, each capable of processing about 30,000
aft-Vmin (10 MW equivalent) of flue gas. One unit, a marble-bed absorber,
was shut down in 1973 and converted to a cocurrent absorber in 1978.
The other two units, a mobile-bed absorber (Turbulent Contact Absorber,
or TCA) and a venturi - spray tower, have been operated under a variety
of conditions since 1972.
A computer model capable of projecting comparative capital investment,
and annual and lifetime revenue requirements for lime and limestone FGD
scrubbing systems based on the Shawnee results has been under development
since the mid-1970's. Only informal documentation for the model was
available until 1979 when a formal users manual was published (Stephenson
and Torstrick, 1979). Since that time the model has been expanded to
include spray tower and venturi - spray tower absorbers; forced-oxidation
systems; systems with absorber loop additives (MgO and adipic acid) ;
revised design and economic premises; and many other miscellaneous
changes reflecting process improvements and variations.
The primary purpose of the model is not to calculate the economics
of an individual system to a high degree of accuracy, but to provide
sufficient detail to allow projections of preliminary conceptual design
and costs for various lime or limestone scrubbing case variations. The
model permits the estimation of the relative economics of these systems
for variations in process design alternatives such as limestone versus
lime scrubbing, TCA versus spray tower, use of chemical additives such
as MgO or adipic acid, or alternative waste disposal methods such as
onsite ponding versus forced oxidation-landfill. The effect of variations
in the values of independent design criteria such as absorber gas velocity,
liquid-to-gas (L/G) ratio, alkali stoichiometry, slurry residence time,
and reheat temperature, may also be assessed.
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Initial development of the Shawnee computer economics model began
in 1974, with the responsibility shared by Bachtel and TVA. Bechtel's
major responsibility has been to develop models for calculating the
overall material balance flow rates and stream compositions. TVA has
been responsible for determining the sizes of the required equipment,
accumulating cost data for the major equipment items, and developing
both a subsystem for calculating equipment costs and a subsystem for
projecting capital investment costs. TVA has also developed procedures
to use the output of these models in a separate TVA subsystem that
projects annual and lifetime revenue requirements.
The combined models should be useful to utility companies as well
as architectural and engineering contractors who are involved in the
selection and design of FGD facilities. It is intended to assist in the
evaluation of system alternatives leading to the development of a detailed
design rather than to project a final detailed design. It should also
be useful for evaluating the potential effects of various process variables
on economics as a guide for planning research and development activities.
Although the model has not been validated as a method for comparing
projected lime or limestone scrubbing economics with the economics of
alternate processes, these comparisons should be valid if the assumptions
for the alternate systems are equivalent to the model assumptions for
lime or limestone systems.
The model has already been used for several applications other than
those for which it was specifically developed. These include simulated
industrial boiler applications, smelter off-gas desulfurization applica-
tions, and plant fuel optimization studies.
This revision of the users manual provides the updated information
and procedures necessary to use the Shawnee lime and limestone computer
model. It does not provide the concepts and background information
basic to the model development. Presentations related to the model have
been given at EPA industry briefings (Torstrick, 1976; and Stephenson
and Torstrick, 1978, 1979) and FGD symposiums (Torstrick et al., 1978;
and McGlamery et al., 1980). The publications associated with these
presentations discuss the model in general, describe the process and
program options, and show sample results. Copies of these publications
should be used in conjunction with the manual. Process flowsheets and
diagrams are included in Appendix A to provide the user with the equip-
ment layouts. Design and economic premises in effect since December 1979
(and expanded and amplified in March 1980), which serve as guidelines for
computer input, are described in Appendix B. These premises are used
for TVA economic studies and contain specifications beyond the scope of
the model.
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GENERAL INFORMATION
CURRENT SCOPE
The present model projects a complete conceptual design package for
either a lime or limestone scrubbing system. It is designed for a wide
range of options that are applicable to new coal-fired power units.
Currently six scrubbing options (each with either lime or limestone) and
four separate waste disposal options are provided. Several other options
are provided to allow different combinations of process variations and
improvements such as MgO or adipic acid addition or forced oxidation-
ponding. Equipment size and layout configurations are based on units
that range in size from 100 to 1300 MW and for coal sulfur contents that
range from 2% to 5%. Because extreme variations in equipment sizes and
layout configurations can result from factors other than unit size and
coal sulfur content, ranges for some of these variables have been defined
as follows:
Absorber gas velocity (TCA) 8-12.5 ft/sec
Liquor recirculation rate 25-100 gal/kft^
Slurry residence time in hold tank 2-25 minutes
Number of scrubbing trains 1-10
S02 concentration 1500-4000 ppm
The validity of results for operating conditions outside the ranges
shown above has not been determined. However, results for intermediate-
sized plants operating outside these boundaries may still be valid.
Several model runs may be required to fully analyze the combined
effects of individual input factors, especially if the specified ranges
are exceeded. The effect of variations in inputs (such as absorber gas
velocity, degree of S02 removal, reheat temperature, alkali stoichiometry,
or L/G ratio) can be assessed individually by varying one factor per
model run, or the cumulative effect can be determined by varying several
factors simultaneously.
FUTURE DEVELOPMENT
Further modifications to the model are expected to be made as test
data from Shawnee become available. Options which are currently being
considered are: (1) landfill of treated waste, including gypsum; (2) an
expanded pond model to allow input options and variables for dike width,
dike roads, diverter dikes, and pond layout; (3) multiple boiler
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applications with common feed preparation and waste disposal facilities;
(4) cocurrent scrubbing; (5) dry particulate removal costs included with
FGD capital investment and revenue requirements; (6) alternate reheating
methods such as hot air injection, flue gas recycling, and regenerative
reheat systems; (7) retrofit difficulty factors for projecting costs for
existing units; and (8) expansion of the model to validate projections for
S02 concentrations less than 1500 ppm. If future additions are made,
revisions will be made to the users manual to reflect the changes.
AVAILABILITY
The model is available to the public through TVA under an information
exchange agreement between EPA and TVA. Upon receipt of a written
request, TVA provides a copy of the model suitable for loading onto an
IBM 370 compatible computer system, along with FORTRAN program listings
and the documentation required to execute the model. Under the same
information exchange agreement, capabilities are provided for TVA to
make model runs based on user-supplied input data. This allows users to
analyze model capabilities with a minimum amount of investigation and
investment.
TVA has also loaded the Shawnee Computer Model on the Control Data
Corporation (CDC) CYBERNET system which is a nationwide, commercial data
processing network. The program can be made available on this system
after the appropriate authorization for use is cleared by TVA and billing
arrangements have been made between the user and CDC. Updated versions
of the program will be maintained on this system and made available
based on user interest.
Model options and input variables are added and modified on a
regular basis as the scrubbing facility test results become available.
The latest version is usually supplied to users and is typically the
basis for user runs made by TVA. Model and documentation availability
are subject to limitations based on available funding and the costs that
must be incurred in connection with a user request. Requests for copies
of the computer model, model runs to be made by TVA, or additional
information should be made to the authors at the following address:
Energy Design and Operations, Tennessee Valley Authority, Muscle Shoals,
Alabama 35660, telephone number (205) 386-2814 or (205) 386-2514.
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MODEL DESCRIPTION
INPUT
The overall model requires a minimum of 15 lines of input. Addi-
tional input is required when a user-specified operating profile is
chosen instead of the built-in profiles. A detailed FORTRAN variable
list of the model input is shown in Table C-l of Appendix C. The variables
are defined in Table C-2 of Appendix C. Ranges for key variables to aid
in establishing input data to the model are shown in Table 1.
As new options are incorporated, the required inputs are subject to
change. When this occurs, the list of variables and the associated
definitions will be updated and made available as necessary.
OUTPUT
The outputs of the Shawnee lime-limestone computer model provide a
complete conceptual design package for lime or limestone scrubbing,
consisting of: (1) a detailed material balance including properties of
the major streams; (2) a detailed water balance itemizing water availa-
bility and water required; (3) specifications of the scrubbing system
design; (4) a display of overall pond design and costs; (5) specifications
and costs of the process equipment by major processing area; (6) a
detailed breakdown of the projected capital investment; (7) an itemized
breakdown of the projected levelized revenue requirements by component;
(8) an optional itemized breakdown of the revenue requirements for the
first year of operation of the system; (9) an optional lifetime revenue
requirement analysis showing projected costs for each year of operation
of the plant as well as lifetime cumulative and discounted costs and
equivalent unit revenue requirements; and (10) a particulate removal
cost table which lists operating conditions and itemizes capital invest-
ment and revenue requirements costs for a cold-side electrostatic
precipitator (ESP), a hot-side ESP, a baghouse, and a wet scrubber.
However, upstream particulate removal is independent of the FGD process
and costs are not included in the FGD economic projections. These
outputs are illustrated in the base case printout shown in Appendix D
(p. D-17).
In addition to the outputs listed above, a diagnostic message file
is generated each time the model is executed. This file contains informa-
tive messages related to processing such as data case number and title,
possible conflicts between options, variable values that may be out of
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TABLE 1. VARIABLE RANGES
Item
Description
Power plant
Fuel sulfur content
Absorber gas velocity
Liquor recirculation rate
Effluent hold tank residence
time
Number of scrubbing trains
Number of spare scrubbing
trains
Sulfur to overhead as SC>2 gas
Ash to overhead as fly ash
System pressure drop (TCA
only)
Investment year
Revenue requirement year
New, 100-1300 MW
2-5%
8-12.5 ft/sec
25-100 gal/kft3
2-25 minutes
1-10
0-10
0-100%
0-100%
Should not exceed 3 inches
per stage
Midpoint of project
expenditure schedule
First year of operation of
plant
Note: The variable ranges were established for model
development purposes. Values beyond these ranges are not
necessarily invalid but the potential for error is greater
when these ranges are exceeded.
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range, and fatal conditions that terminate model execution. In typical
model runs made by TVA the message file is listed between the printed
output from the investment program and the printed output from the
revenue programs, but this depends on the control language procedures
used for execution. An example message file is shown in the base case
printout in Appendix D (p. D-23).
OPTIONS
A detailed list of all of the model inputs is included in Tables C-l
and C-2 of Appendix C. These tables include a number of options for
selecting process design and controlling model output. Types of options
are listed below:
• Print
• Particulate collection device Reheat
• Reheat
• Bypass and partial scrubbing
• Coal-cleaning and input composition
• Particulate removal
• S02 removal
• Operating parameter calculation
• Scrubbing absorbent (lime or limestone)
• Chemical additive and forced-oxidation
• Fan and absorber
• Redundancy
• Waste disposal
• Pond design
• Pond liner
• Economics
• Pond capacity
• Operating profile
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Some examples of the various options are shown on the pages that follow.
For illustration purposes the appropriate input data line is shown and
the particular option code is indicated. An explanation of each option
and sample output resulting from its usage is provided where necessary.
Values for all variables must be entered for each case even though a
variable value is being calculated by the model as a result of a user-
specified option. When this condition occurs, the calculated value will
override the input value. A value of zero will be appropriate for many
variables but the value cannot be omitted. Spaces cannot be used to
take the place of variables which have a value equal to zero.
Some user-specified input values result in the use of default
values of other variables for consistency in the calculations. For the
options that allow defaults, the option code that must be input and the
default values that are assumed are described. All model output listings
used to illustrate individual options are derived from the base case
data shown in Appendix D. Only the variables related to options being
illustrated are changed from the base case unless otherwise noted.
Print Options
Line No
1
2
3
Input data
1
1
1
111
111
1 1
1
11111111
The options on the first three lines of the input data control
printed output from the model. These options are described in the input
definition list in Appendix C, Table C-2. The only print option requiring
further explanation is the first option on line 3. This option controls
the printout of the capital investment and revenue requirement sections.
The short form printout is shown in Table 2 and may be compared with the
long printout of the base case example in Appendix D.
Particulate Collection Device Option
Line No . Input data
5 2 500 9500 11700 39 300 2 1 0 0 0 0 0 0 175 470 751
*
XESP
The particulate collection device option is controlled by the XESP
variable. The value of XESP may be 0, 1, or 2. A zero value is used if
no particular removal device is to be considered. A value of 1 is used
if a mechanical collector (33% efficient) is selected, and the code for
upstream removal (line 6, ASHUPS, see Table C-2) should have an input
value of 33 (% removal). If an XESP value of 2 is selected, a separate
particulate removal cost model (Argonne, 1979) projects the capital
8
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TABLE 2. EXAMPLE SHORT FORM PRINTOUT
RAW MATERIAL I-ANCLING AREA
NUMBER OF REDUNDANT ALKALI PREPARATION UNITS
ECONOMIC CHARACTERISTICS
1979 TVA-EPA ECONOMIC PREMISES
PROJECTED REVENUE REQUIREMENTS INCLUDE LEVELIZEO OPERATING AND MAINTENANCE COSTS
RATE = 1.886 TIMES FIRST YEAR OPERATING AND MAINTENANCE COSTS
FREIGHT INCLUDED IN TOTAL INVESTMENT
FREIGHT RATE = 3.5 *
SALES TAX INCLUDED IN TOTAL INVESTMENT
SALES TAX HATE = 4.0 S
LABOR OVERTIME INCLUDED IN TOTAL INVESTMENT
OVERTIME RATE = 1.5
INFLATION RATE = 6.0 *
PROCESS MAINTENANCE = 8.0 4
POND MAINTENANCE = 3.0 It
POND DESIGN
OPTIMIZED TO MINIMIZE TOTAL COST PLUS OVERHEAD
POND COSTS (THOUSANDS OF DOLLARS)
LABOR MATERIAL TOTAL
SUBTOTAL DIRECT
TAX AND FREIGHT
POND CONSTRUCTION
LAND COST
14920.
14980.
30Z.
23.
325.
15222.
23.
15245.
2104.
POND SITC 17349.
(continued)
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TABLE 2 (continued)
LIMESTONF SLURRY PROCESS — BASIS: 500 MW UNIT. 1*84 STARTUP
USER SHORT FORM PRINT CASE 012
PROJECTED CAPITAL INVESTMENT REQUIREMENTS
INVESTMENT, THOUSANDS OF 1982 DOLLARS
RAH MATERIAL
HANDLING AND HASTE
PREPARATION SCRUBBING DISPOSAL TOTAL
SUBTOTAL DIRECT INVESTMENT 780S. 35764. 17569. 61141.
TOTAL CAPITAL INVESTMENT 14229. 65133. 29652. 109014.
(continued)
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TABLE 2 (continued)
PROJECTED FIRST YEAR REVENUE REQUIREMENTS - USER SHORT FORM PRINT
ANNUAL OPERATION Kn-hK/rfW = 5500
HEVENUE
REQUIHtNEM, t
SUBTOTAL KAM MATERIAL 1304000
SUPTOTAL CONVERSION COSTS 7854400
SUBTOTAL IMOIRFCT COSTS 2816500
LtVELIZEO CAPITAL COSTS IbOiSOOO
FIHST YEAR ANNUAL REVENUE REQUIREMENTS 27999900
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investment and revenue requirements for particulate removal. The results
are listed in the output but are not included in the projected FGD
costs. The percentage of particulate removal required for this option
is specified by the ASHUPS variable. Example output showing the results
of specifying mechanical collectors (XESP = 1) is shown in Table 3.
Example output showing the results of using the built-in particulate
removal cost model is shown in the base case printout in Appendix D
(p. D-17).
Reheat Option
Line No . Input data
5 2 500 9500 11700 39 300 2 1 0 0 0 0 0 0 175 470 751
i i J
XRH TSTEAM HVS
The reheat option (XRH) allows for either an inline steam reheater
for the scrubbed gas or for no reheating of the scrubbed gas. The inline
steam reheater is the only type of reheater available in the current
version of the model. When a reheater is specified (XRH = 2), the TSTEAM
variable is used to specify the temperature of the reheater steam and
the HVS variable is used to specify the heat of vaporization of the
reheater steam. Example output showing the results of specifying an
inline steam reheater is shown in the base case in Appendix D (p. D-10).
When no reheating is specified (XRH = 0) the reheater section as shown
in the base case printout is omitted.
Emergency Bypass Option
Line No. Input data
5 2 500 9500 11700 39 300 2 1 0 0 0 0 0 0 175 470 751
\
KEPASS
The emergency bypass option (KEPASS) allows an emergency bypass
around the FGD system for one-half of the gas normally scrubbed as
specified in the premises used by TVA for comparative economic evalua-
tions for EPA (Appendix B). An emergency bypass is allowed by the
revised NSPS promulgated in 1979 (Federal Register, 1979) when spare FGD
modules (trains) are provided. If only one operating scrubbing train is
specified (line 9, NOTRAN) then the emergency bypass is sized for all of
the gas normally scrubbed instead of only one-half. When both emergency
bypass and partial scrubbing/bypass (line 5, KPAS02 and PSS02X) are
specified, the bypass duct is sized for 50% of the gas normally scrubbed
(100% of the gas normally scrubbed if only one operating train) plus the
partial bypass normally used for the unscrubbed gas (total cannot
exceed 100%). The following values are used for the KEPASS option:
0 - No emergency bypass
1 - Emergency bypass
12
-------
TABLE 3. MECHANICAL COLLECTOR COST ILLUSTRATION
SCRUBBING
INCLUDING 4 OPERATING AND 1 SPARE SCRUBBING TRAINS
ITEM DESCRIPTION NO. MATERIAL LABOR
MECHANICAL ASH COLLECTOR
1.0. FANS
SHELL
RUBBER LINING
MIST ELIMINATOR
SLURRY HEADER AND NOZZLES
TOTAL SPRAY SCRUBBER COSTS
HEHEATERS
SOOTBLOWERS
EFFLUFNT HOLD TANK
EKFLUFNT HOLD TANK AGITATOR
COOLING SPRAY PUMPS
ARSOHREP RECYCLE PUMPS
MAKEUP WATER PUMPS
33» PARTICULATE REMOVAL
7.SIN H20. WITH 631.
HP MOTOR AND DRIVE
40 AIM-FIXED
20 AIR-RtTRACTASLE
343449.GAL. 38.8FT OIA.
38.8FT HT, FLAKEGLASS-
LINEO CS
82.HP
13P6.GPM 100FT HEAD'
64.HP, 4 OPERATING
AND 6 SPARE
16611.6PM. 100FT HEAD.
723.HP, 8 OPERATING
AND 7 SPARE
3469.GPM, 200.FT HEAD.
292.HP, 1 OPERATING
AND 1 SPARE
1
5
5
5
60
654166.
3J41982.
1769029.
1766858.
393850.
853235.
4782970.
2647704.
294910.
112232
58581
449605
166446
162512
373173.
5 505849.
10 104732.
15 1581896.
33169.
301519.
207512.
32268.
139397.
TOTAL EQUIPMENT COST
14320518. 1655810.
-------
Example output showing an emergency bypass specified is shown in the
base case printout in Appendix D (p. D-7).
Partial Scrubbing/Bypass Option
Line No. Input data
5 2 500 9500 11700 39 300 2 1 1 90 0 0 0 0 175 470 751
/ \
KPAS02 PSS02X
The partial scrubbing/bypass option (KPAS02) allows FGD systems to
be projected for conditions where all of the flue gas does not have to
be scrubbed to meet specified emission levels. The percent removal in
the absorber is specified with the PSS02X variable and the model will
calculate the percentage of flue gas that can be bypassed (if any) and
still meet the emission limit or overall removal percentage specified
(line 7, IS02 and XS02). The appropriate ductwork and reheater adjustments
are made as required depending on the amount of bypassed gas. When both
partial scrubbing/bypass and emergency bypass (line 5, KEPASS) are
specified the bypass duct is sized for the gas normally bypassed plus
50% of the gas normally scrubbed (100% if only one operating train;
total cannot exceed 100%). Partial scrubbing/bypass is not allowed when
S02 removal is calculated from scrubber operating parameters (line 7,
XSR = 3). The following values are used for the KPAS02 option:
0 - No partial scrubbing/bypass
1 - Partial scrubbing/bypass
Example output showing partial scrubbing/bypass specified is shown in
Table 4 and is based on an emission limit of 1.2 Ib S02/MBtu.
Coal-Cleaning Option
Line No.
5 2 500 9500 11700 39 300 2 1 0 0 1 84.16 12.16 2.21 175 470 751
/I \ ^
KCLEAN WPRCVR WPPSAC WPPSRC
The coal-cleaning option (KCLEAN) allows the model to be used in
conjunction with physical coal cleaning. The model calculates the
composition and firing rate of cleaned coal to the boiler based on the
raw coal characteristics, the coal cleaning parameters, and boiler heat
rate and megawatts. The corresponding composition of the flue gas to
the scrubbing system is used for determining the degree of S02 removal
required. The variables WPRCVR, WPPSAC, and WPPSRC are used to specify
the required coal-cleaning parameters. The WPRCVR variable specifies
the percent weight recovery (Ib clean coal per Ib of raw coal); the
WPPSAC variable specifies the weight percent of pyritic sulfur plus ash
in the cleaned coal; and the WPPSRC variable specifies the weight percent
14
-------
EXAMPLE RESULTS SHOWING PARTIAL SCRUBBING/BYPASS
EMERGENCY 8Y-FOSS
EMERGENCY BY-PASS DESIGNED FOR 57.1 *
HOT GAS FROM BOILER
C02
HCL
502
02
N?
H20
MOLE PERCENT LB-MOLE/HR
H.-'ie 0 2255E*Ob
O.OOt 0
0.214 o
5.560 0
75.227 0
6.654 0
1 145E+02
3914E*03
1016E»05
1375F«06
1216E-05
LB/HR
0.9923E-06
0.4175E*03
0 • 2b08t *0b
0.3251E»06
0.3H52E*07
0.2 19 1E*06
HOT GAS FLO* KATE = ,1154E*07 SCFM ( 60. DEG F. 14.7 PSIA)
= .1687E'07 ACFM (3UO. DEG f, 14.7 PSIA)
CORRESPONDING COAL FIRING RATE = .4060E»06 LB/HR
HOT GAS HUMIDITY = 0.04? L3 H20/LS DRY GAS
WET BULfl TEMPERATURE = 124. DFG F
HOT GAS TO BY-PASS
MOLE FFWCENT LH-MOLE/HR LB/HR
C02 12.338 0.3189E.04 0.1404E*06
HCL 0.006 0.1(S20E»01 0.5S06E»02
S02 0.214 0.5537E«02 0.3547E«04
02 5.560 0.1437E«04 0.4599E*05
N2 75.227 0.194bE+Ob 0.5449E+06
H?0 6.6?4 0.1720E»04 0.3099E*Ob
HOT GAS BY-PASSED 14.1 *
HOT GAS FLO» RATE = .1633E«06 SCFM ( 60. DEG F. 14.7 PSIA)
= .2386E«06 ACFM (300. OEG F. 14.7 PSIA)
CORRESPONDING COAL FIRING RATE = .5743E«05 LB/HR
(continued)
-------
TABLE 4 (continued)
HOT GAS TO SCRUBBER
MOLE PERCENT LB-MOLE/HR LB/HR
C02
HCL
502
02
N2
H20
12.33fc
0.006
0.214
5. 56C
75.227
6.654
0.1936E-05
0.9832E*01
0.3361E«03
0.8723E»04
0.1180E»06
0.1044E«05
0.8519F«06
0.3585E«OJ
0.2153E»Ob
0.2791E*06
0.3307E»07
0.1S91E«06
S02 CONCENTRATION IN SCRUBBER INLET GAS = 2142. PPM
= 5.28 LBS / MILLION BTU
FLYASH EMISSION = 0.060 LBS/MILLION HTU
= 0.029 tHAINb/SCF (WET) OH 28b. L8/HH
SOLUBLE CAO IN FLY ASH = 0. LB/HR
SOLUBLE MGO IN FLY ASH = 0.
HOT GAS FLOW RATE = .9910E'06 SCFM ( 60. DEG F. 14.7 PSIA)
= .144fE«07 ACFM (300. DEG F. 14.7 PSIA)
CORRESPONDING COAL FIRING RATE = .3486E«06 LH/HR
HOT GAS HUMIDITY = 0.042 La H20/LB DRY GAS
WET HULB TEMPERATURE = 124. UEli F
WET GAS FROM SCPL8BER
MOLE PERCENT LB-MOLE/HH LB/HR
C02
HCL
S02
02
N2
H20
11.716
0.000
0.020
5.169
70.300
12.795
0.1967E.OS
0.491bE*00
0.3361t«02
0.8677E»04
0.1180E«06
0.2148E»05
0.8657E«06
0.1792E«02
0.2153E*04
0.2777E->06
0.3307E»07
0.3870E»06
S02 CONCENTRATION IN SCRUBBER OUTLET GAS = 200. PPM
FLYASH EMISSION = 0.030 LBS/MRLION BTU
= 0.016 C-HAINS/SCF (WET) OR 143. LB/hR
TOTAL WATER PICKLP = 40B. GP«
INCLUDING 9.7 GPM ENTRAINMENT
WFT GAS FLOW RATE = .1060E*07 SCFM ( 60. DEG F. 14.7 PSIA)
= ,1191E«07 ACFM (124. DEG F, 14.7 PSIA)
WET GAS SATURATION HUMIDITY = 0.087 Lfi H20/LB DRY GAS
-------
of pyritic sulfur in the raw coal. When the revised NSPS (Federal
Register, 1979) emission limit is automatically calculated by the model
(line 7, IS02 = 4), the appropriate credit for coal cleaning will also
be automatically calculated by the model, on a raw coal basis. In all
other cases, the emission limit or removal percentage (line 7, IS02 and
XS02) must be specified on a cleaned coal basis or must be calculated by
the model from scrubber operating parameters (line 7, XSR = 3). Coal
cleaning is not allowed when the gas composition is specified directly
(line 6, INPOPT = 2). The following values are used for the KCLEAN
option.
0 - No coal cleaning
1 - Coal cleaning
Example output showing the results of specifying coal cleaning is shown
in Table 5, and is based on 84.16% weight recovery, 12.16% pyritic
sulfur plus ash in the cleaned coal, and 2.21% pyritic sulfur in the raw
coal.
Input Composition Option
Line
No. Input data
INPOPT
/
6A 1 66.7 3.8 5.6 1.3 3.36 .1 15.1 4.0 92 80 2 .06 .03
or
6B 2 12.338 .006 .214 5.560 75.227 6.654 1154000 47500 100 100 2 .06 .03
\
INPOPT
The input composition option (INPOPT) allows the flue gas composition
to be specified directly instead of being calculated by the model from a
coal composition. This allows the model to be used to project FGD
systems for other than coal-fired boilers, such as smelter off-gas. The
variables described for line 6A (C, H, 0, N, S, Cl, ash, H20, etc. ; see
Table C-2) should be used when the coal composition is specified; the
variables described for line 6B (C02> HC1, S02, 02, N2, H20, etc.; see
Table C-2) should be used when the flue gas is specified directly. Coal
cleaning (line 5, KCLEAN = 1) and the automatic calculation of revised
NSPS emission levels (line 7, IS02 = 4) are not allowed when the flue
gas composition is specified directly. The following values are used
for the INPOPT option:
1 - Coal composition is specified (line 6A)
2 - Flue gas composition is specified (line 6B)
17
-------
TABLE 5. EXAMPLE RESULTS SHOWING COAL CLEANING
PHYSICAL COAL CLEANING
STREAM LunPOSlTIONS
COMPONENT
RAW COAL
CLEAN COAL
REFUSE
00
HEIGHT
PERCENT
18 PER LB
RAW COAL
WEIGHT
PERCENT
LB PER LB
RAW COAL
WEIGHT
PERCENT
LB PER LB
RAW CCAL
CARBON
HYDROGEN
OXYGEN
NITROGEN
SULEUR.lOi.
PURE COAL
66.7000
3.8000
3.6000
1.3000
— 1.15.00—
7B.5500
0.7013
0.0400
0.0589
0.0117
—0.0121.
0.9259
SULFUR (P> 2.2100 0.0221
ASb 1J.1000 0.15.10.
ASH £ 5 17.3100 0.1731
CHLOiltJE 0.1000 Q.OQ1Q-
TOTAL 100.0000 1.0000
74.9248
4.2498
6.2570
1.4525
-.1.28.4.9—
87.7630
1.5525
.10.6023...
12.1600
0.6272
0.0357
0.0527
0.0122
0.0108-
0.73)6
0.0131
—0.089.3-
0.1023
46.7B30
2.6653
3.9278
0.9118
..0.8066...
55.0945
9.7014
.38.9.69.2—.
44.6726
0,0741
0.0042
0.0062
0.0014
...0.0013
0.0873
0.0090
...0.0612
0.0708
...0.0710 Q.QQQ6.
100.0000 0.8416
—0.212B 0.000*
100.0000 0.1584
BTU/LB 122B2. 12292.
PERCENT ORTOINAL BTU 1.0000
13469. 11335.
0.9229
9764.
1547.
0.1299
-------
When a coal composition is specified, a "BOILER CHARACTERISTICS" section
is included in the output report. Example output showing the results of
specifying a coal composition as input (INPOPT = 1) is shown in the base
case printout in Appendix D (p. D-4). When a flue gas composition is
specified, a "HOT GAS ANALYSIS" section is provided. Example output
showing the results of specifying a flue gas composition as input is
shown in Table 6.
Particulate Removal Option
Line No. Input data
6A 1 66.7 3.8 5.6 1.3 3.36 .1 15.1 4.0 92 80 2 .06 .03
jf^^jS /
IASH ASHUPS ASHSCR
The particulate removal variables are IASH, ASHUPS, and ASHSCR.
The IASH option identifies the method for specifying particulate removal,
i.e., as percent removal or as outlet emission in Ib/MBtu. IASH may
take values of 0, 1, 2, or 3. If IASH is equal to 0, upstream particulate
removal (ASHUPS) and absorber particulate removal (ASHSCR) take default
values of 33% and 99.2% removal respectively. If IASH equals 1, ASHUPS
and ASHSCR are input as percent removal. If IASH equals 2, ASHUPS and
ASHSCR are input particulate loadings in Ib/MBtu at the outlet of the
upstream particualte collector and the absorber respectively. If IASH
equals 3, ASHUPS is input as percent removal and ASHSCR takes a default
value of 75%. Regardless of the option chosen, the output listing
provides the equivalent particulate emission as both percent removal and
Ib/MBtu. A summary of the options is shown below.
IASH = 0 ASHUPS default value = 33% removal
ASHSCR default value = 99.2% removal
IASH = 1 ASHUPS input value as percent removal
ASHSCR input value as percent removal
IASH = 2 ASHUPS input value as Ib/MBtu to absorber
ASHSCR input value as Ib/MBtu from absorber
IASH = 3 ASHUPS input value as percent removal
ASHSCR default value equals 75% removal
Example output showing the results of specifying particulate removal based
on Ib/MBtu (IASH = 2) is shown in the base case printout in Appendix D
(pp. D-8, -10).
19
-------
TABLE 6. EXAMPLE RESULTS SHOWING USER INPUT FLUE GAS COMPOSITION
«*« INPUTS «•*
HOT GAS ANALYSTS. MOLt PERCENT:
C02 CL SOS 02 N2 H20
12.3380 0.0006 0.2140 5.b600 75.2270 6.6540
SULFW OVERHEAD = 100.0 PE^CtNT
ASH OVERHEAD = 100.0 PERCENT
-------
SO? Removal Option
Line No.
Input data
7 90 0 0 10 25 4 0.0 10 1 0.0 1 0 .15 0 0 0 4.85 500
I \
IS02 XS02
The model has five methods for specifying SC>2 outlet concentrations
or removal. The controlling variables are the IS02 option and the
actual value to be removed, XS02. If IS02 = 1, XS02 is input as the
percentage of S02 to be removed. (The percentage of S02 to be removed
is used as the percent removal by the absorber except when partial
scrubbing is specified with the KPAS02 option on line 5.) If IS02 = 2,
XS02 is input as the absorber outlet emission expressed as pounds S02/MBtu.
If IS02 = 3, XS02 is input as ppm S02 in the absorber outlet stream. If
IS02 = 4, XS02 is automatically calculated by the model from the input
coal composition based on the revised NSPS (Federal Register, 1979).
Figure 1 illustrates the relationship between the SC>2 content of the raw
coal and the controlled outlet emission levels used in the model for the
revised NSPS. A fifth method for specifying S02 removal, S02 removal
calculated, is described in the operating parameter options section
(line 7, XSR = 3). Regardless of the option chosen, the equivalent S02
removal in all three units is displayed in the model output. The input
value is indicated as having been specified and the other values are
indicated as having been calculated. A summary of the input options is
shown below.
IS02 = 1 XS02 is input as percent removal
IS02 = 2 XS02 is input as pounds S02/MBtu at the absorber outlet
IS02 = 3 XS02 is input as ppm S02 in the absorber outlet stream
IS02 = 4 XS02 will be automatically calculated by the model based
on the revised NSPS (Federal Register, 1979)
Example output showing the results of specifying emission limits based
on the revised NSPS is shown in the base case printout in Appendix D.
An important concept related to S02 removal calculations in the
model should be emphasized here. The S02 removal options are based on
long-term average removals and are not to be construed as 3-hour or 24-
hour averages. When sizing an FGD facility the raw material handling,
feed preparation, and scrubbing areas should be based on the maximum
sulfur content of the coal rather than the long-term average. The waste
disposal pond, however, should be sized on the long-term average sulfur
content. This can be done by entering the weight percent sulfur as the
maximum expected and then entering the pond capacity factor (line 14,
PNDCAP) to adjust the total amount of waste generated back to the
equivalent long-term average amount.
21
-------
NJ
ro
1.2
1 .0
0.8
0.6
0. 2
removal required
70
80
I
85
I
5.0% S, 11,700 Btu/lb bit, coal
3.5% S, 11,700 Btu/lb bit, coal
2.0% S, 11,700 Btu/lb bit. coal
0.9% S, 6,600 Btu/lb lignite
0.7/: S, 8,200 Btu/lb subbit. coal
_L
_L
_L
_L
J_
A 6 8 10
EOUlVALKiMT S02 CONTEND OF RAW COAL, Ib S02/MBtu
12
Figure 1. Controlled S02 emission requirements for 1979 NSPS. Premise coals, shown
underlined, are based on premise boiler conditions.
-------
Operating Parameter Calculation Option
Line No. Input data
XLG XS02 XSR SRIN
f \ \ /
1 90 0 0 10 25 4 0.0 10 1 0.0 1 0 .15 0 0 0 4.85 500
8 15 40 .2 40 0 30 0.0 80 1.2 0.0 0 9 0 14.7 1
i
PHLIME
Four options are available in the model to allow either user input
or model calculation of the major operating parameters which include L/G
(expressed as absorber liquor recirculation rate in gallons of liquor
recirculated per 1000 actual cubic feet of gas at the absorber outlet),
stoichiometry (expressed as mols CaCC>3 or CaO added per mol of S02
absorbed), and SC>2 removal. The options differ slightly for the lime-
stone scrubbing system and the lime scrubbing system so the description
is divided into two sections.
First, for limestone scrubbing (line 7, XIALK = 1) the variables
used are XSR, XLG, SRIN, and XS02. XSR is the controlling option and
takes values from 0 to 3. If XSR has an input value of 0, the L/G
(XLG), stoichiometry (SRIN), and S02 removal (XS02, units depend on
IS02) are all user input values. Specifying XSR = 0 is referred to as
"force-through" because no program checks are made for validity or
consistency among the three input variables to ensure that specified L/G
and stoichiometry can result in the input degree of removal. If XSR is
equal to 1, XLG and XS02 are input and the model calculates stoichiometry.
If XSR is equal to 2, SRIN and XS02 are input and the model calculates
XLG. When XSR is equal to 3, XLG and SRIN are input and the model
calculates XS02. Values of 1.01 or greater should be used for SRIN when
it is specified as input. A summary of the various options for a limestone
scrubbing system is shown below.
XSR = 0 XLG is input
XS02 is input
SRIN is input
XSR = 1 XLG is input
XS02 is input
SRIN is calculated
23
-------
XSR = 2 XLG is calculated
XS02 is input
SRIN is input
XSR = 3 XLG is input
XS02 is calculated
SRIN is input
Example output showing the results of specifying XSR = 1 is shown in the
base case printout in Appendix D (pp. D-5, -12).
Similar options are available in the lime scrubbing option (line 7,
XIALK = 2). Except when XSR = 0, the variable PHLIME replaces SRIN
because for lime scrubbing the model calculates the pH of the recirculation
liquor instead of the lime stoichiometry. (When limestone is specified
the value of PHLIME is ignored. When lime is specified SRIN is ignored
except when XSR = 0 in which case PHLIME is ignored.) A summary of the
options for a lime scrubbing system is shown below.
XSR = 0 XLG is input
XS02 is input
SRIN is input
XSR = 1 XLG is input
XS02 is input
PHLIME is calculated
XSR = 2 XLG is calculated
XS02 is input
PHLIME is input
XSR = 3 XLG is input
XS02 is calculated
PHLIME is input
24
-------
The output listing for the lime scrubbing option is similar to that
for the limestone option shown in Appendix D except that the stoichiometry
is printed out for CaO instead of CaC03, as shown in Table 7. (An input
value of 7.85 is used for PHLIME in this example.) For both the lime
and limestone options, if input values are specified for the variables
that are to be calculated by the model, the input values are ignored.
Scrubbing Absorbent Option (Lime or Limestone)
Line No. Input data i
7 90 0 0 10 25 4 0.0 10 1 0.0 1 0 .15 0 0 0 4.85 500
*
XIALK
The alkali scrubbing absorbent option (XIALK) allows a choice of
either lime or limestone. If XIALK = 1, limestone slurry is selected as
the scrubbing medium. If XIALK = 2, lime slurry is selected. Example
output showing the results of specifying limestone scrubbing (XIALK = 1)
is shown in the base case printout in Appendix D. Table 8 shows how the
lime option output differs from limestone in both the input display and
the raw material preparation area equipment list.
Chemical Additive Option
Line No. Input data
7 90 0 0 10 25 4 0.0 10 1 0.0 1 0 .15 0 0 0 4.85 500
\i
IADD
The chemical additive option (IADD) provides for the addition of
either magnesium oxide (MgO) or adipic acid to the slurry stream to
improve scrubber efficiency and S02 removal rates. The following values
are used for the IADD option:
0 - No chemical additive
1 - MgO added
2 - Adipic acid added ("force-through" mode must be used for the
adipic acid option; see the operating parameter calculation
option, XSR, on line 7)
Example output showing the results of adding adipic acid is shown in
Table 9.
25
-------
TABLE 7. LIME SCRUBBING OUTPUT LISTING
SCRUBBER SYSTEM
TOTAL NUMBER OF SCRUBBING TWAINS e.6 PERCENT
PARTICULATE REMOVAL IN SCNUrtbER SYSTEM = 50.0 PERCENT
SPRAY TOWER PRESSURE DROP = 2.? IN. H<;0
TOTAL SYSTEM PRESSURE CROP = 7.5 IN. "20
SPECIFIED SPRAY TOkER L/G RATIO = APSORtED
SOLUHLE CAO FRC" FLY ASH = 0.0 WOLt HER MOLE (SOa»2HCL) ABSORBED
TOTAL SOLUBLE Mf=C = 0.00 MOLE PER MOLE (S02*«!MCLI ABSORBED
TOTAL STOIChlCVETSY
1.10 MOLE SOLOdLF (CA'MG)
PER MOLE 1S02»2HCL) ABSORBED
SCRUBBER INLET LIQUOR PH = 7.P5
MAKt UP wATtR = 720. GPM
CROSS-SECTIONAL AHtA PEH SCRUHdES = 577. SQ FT
SYSTEM SLUDSE DISCHARGE
SPECIES
CAS03 .1/2 h?C
CAS04 .2H20
CAC03
INSOLURLE s
H?0
CA+ +
MG**
S03--
S04--
CL-
LB-fOLE/f-H
0.242BE.03
0.1029E-03
0.3523£«0a
0.4440E«04
0.5i7?F«01
0.1515E-01
0.1426E»00
0.119«E»01
O.lOfSE-02
Ld/HK
0.3135E-05
0.1771E«Oi
0.3527E«04
0.79S9E«OS
0.2113E-OJ
0.36B^E»0^
0.11*lE«l)i
0.1147E»03
0.3«57E«03
3UL 1 U
COMP,
«T 1
58.23
32.90
6.55
2.32
C 1 udu 1 u
COMP,
IVM
2617.
45ft.
141.
1421.
4776.
TOTAL DISCHARGE FLOW RATE = 0.1346E»06 LB/HR
= <:03. GPM
TOTAL DISSOLVED SOLIDS IN DISCHARGE LIQUID =
DISCHARGE LIQLIH Ph = 7.37
-------
K3
—I
TABLE 8. LIME OPTION INPUTS AND RAW MATERIAL PREPARATION AREA
LIME SCRUBBING CASE 007
•«« INPUTS *••
BOILER CHARACTERISTICS
MFbAWATTS = 500.
BOILER HEAT RATf = 5500. FJTU/MIH
EXCESS AIR = 39. PERCFMT. INCLUDING LEAKAGE
HOT GAS TF.MPEI-ATLRE = 300. DE(j F
COAL ANALYSIS! *T * OS FIRED :
C H C N S CL ASH H20
66.70 3.80 5.60 1.30 3.36 0.10 IS.10 4.00
SULFUR OVERHEAD = ^2.0 PEHCENT
ASH OVERHEAD = 60.0 PKKCENT
HEATINC VALUE OF CO«L = 11700. BTU/L8
EFFICIENCY. EMISSION,
FLYASH REMOVAL * L"S/C BTU
UPSTREAM OF SCRUEBER 99.4 0.06
KITHIN SCRUBBER 50.0 O.OJ
COST OF UPSTREA1" FLYASH REMOVAL FXCLUDEO
ALKALI
CAO = 95.00 WT * DRY BASIS
SOLUBLE VGO = 0.15
INERTS * 4.H5
MOISTURE CONTENT : 5.00 LH H20/100 L8S DRY LIME
FLY ASH :
SOLUBLE CAO = 0.0 NT *
SOLUbLE MCO = 0.0
INERTS = 100.00
(continued)
-------
TABLE 8 (continued)
RA» MATEHIAL HANDLING AND PREPARATION
INCLUDING 2 OPERATING AND 1 SPARE PREPARATION UMTS
ITEM DESCRIPTION NO. MATERIAL LABOR
00
CONVEYOP FROM CALCINATION
PLANT
STORAGE SILO ELEVATOR
CONCRETE STORAGE SILO
STORAGE SILO HOPPER PCTTCM
RECLAIf VIBRATING FEECEN
RECLAIM PELT CONVEYOR
FtFD BIN FLEVaTOK
FEED REIT CONVEYOR
FEED CONVFYOR TRIPPFR
FEED BIN!
blN VIBRATING EEEOER
tlN KEKiH KtEI.it H
SLAKER
SLAKE" PRODUCT TANK
SLAKEP PRODUCT TANK AGITATOR
LIME SYSTEM OUST COLLECTORS
SLAKER PRODUCT TANK SLURRY
HUMPS
SLURRY FEED TANK
SLURRY FEED T&NK AGITATOR
SLURRY FEED TANK PUMPS
TOTAL EQUIPMENT COST
1SOOFT HORIZONTAL. 30HP
l?b.FT HIGH. 50 HP
136674.FT3.t8.8FT DIA .
73.2F1 STRAIGHT SIDF
STORAGE nT
en DEGREE, cs
3.5PP
124.FT HORIZONTAL. 5HP
bOFT HKiM. 50HP
SOFT HORIZONTAL. bHP
30FFM, 1HP
10FT 014. 15FT STRAIGHT
SIDE Hi, COVERED. CS
3.5PP
12FT. I^IN SCRE«. IMP
6.TPH. 10.HP
10HP
POLYPROPYLENE HAG TYPE
2200 CM,7.SfP
134.GP'1. 60FT HEAD.
4.HP. 2 OPERATING
AND 1 SPARES
14101S.GAL. 26.8FT DIA,
2P.8FT HT. ELAKEGLASS-
LINED CS
50.HP
67.GPM, 60 FT HEAD.
2.HP, 4 OPERATING AND
4 SPARE
1
207327.
37741.
1
1
1
1
1
1
1
1
3
3
3
3
3
3
5
3
1
1
8
62607.
177002.
22252.
3S13.
2578d.
377b4.
12076.
18940.
144<,1.
30508.
15635.
175997.
15445.
22881.
38770.
11863.
35984.
57120.
22498.
4494.
375654.
15214.
391.
3392.
2216.
)f>43.
651H.
9973.
3911.
2347.
1(1433.
12515.
5475.
14340.
3480.
25727.
4686.
7300.
550850.
-------
TABLE 9. EXAMPLE RESULTS SHOWING THE ADDITION OF ADIPIC ACID
PA* MATERIAL HANDLING AND PREPARATION
INCLUDING 2 OPERATING AND 1 SPARE PREPARATION UNITS
ITEM DESCRIPTION NO. MATERIAL LABOR
CAR SHAKER AND HOIST
CfR PULLER
UNLOADING HOPPER
UNLOADING VIBRATING FENCER
UNLOADING 9ELT CONVEYCk
l^LOAOUG INCLINE BELT
CONVFYOP
UNLOADING PIT DUST COLLFCTOB
UNLOADING KIT SUMP PUMP
STORAGE BELT CONVEYOR
STORAGE CONVEYOR TRIPPER
MOBILE EQUIPMENT
RECLAIM HOPPER
RECLAIM VIBRATINb FEECEP
hl-CLAIM BFLT CONVEYOR
RECLAIM 1MCLINF BELT CO^VFYO^
RtCLAI" PIT DUST COLLECTOR
RECLAIM PIT SUMP PUMP
RECLAIM BUCKET ELEVATOR
EEED BELT CONVEYOR
20HP SHAKER 7.5HP HOIST
25HP PULLFR. 5HP RETURN
16FT OIA, 10FT STRAIGHT
INCLUDES h IN SU GRuTING
3.5HP
20FT HORIZONTAL. 5HP
310FT, 50HP
POLYPROPYLENE oAbTYPE.
INCLUDES OUST HOOD
fcOGPM, 70FT HEAD. 3HP
200FT. 5MR
30FPM, 1HP
SCRAPPER TRACTOR
7FT xIUEi 4.25FT HT. 2FT
WIDE BOTTOM. CS
3.5HP
JOOKT. ?HP
193FT. 40HP
POLYPROPYLENE BAG TYPE
feOGPM* 70FT HEAD* 5HP
90FT HIGH. 75HP
60. FT HORIZONTAL 7.5HP
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
1
1
71916.
63050.
15508.
5466.
11440.
95295.
11186.
2415.
73092.
27203.
141862.
?415.
10932.
40931.
60253.
7754.
2415.
57838.
20466.
13037.
19555.
5932.
521.
1434.
4824.
-215.
782.
3911.
9126.
0.
1630.
1043.
2868.
3650.
2607.
782.
6649.
1434.
(continued)
-------
TABLE 9 (continued)
u>
o
FEED CONVEYOR T^IPPEP.
FEED RIN
BIN »FIf~,H FEEDER
GYRATORY CKUSHEKb
E-ALL MILL DUST COLLECTOPb
BALL MIIL
KILLS PRODUCT TANK
KILLS PPOPUCT TANK AGITATOR
KILLS PPODUCT TANK bLIRPY
ADIPIC ACID ADD STORAGE SILO
PNEUMATIC CONVEYOR SYSTFK
ADDITION FEED BIN
SCREW FFEDEH
AUDITIVE DUST COLLECTOR
SLURRY FEED TANK
SLURRY FEFO TANK AGITATOR
SLURRY FEFD TANK PUMPS
TOTAL EQUIPMENT COST
30 FPMi IMP
13FT DIA, 21FT STRAIGHT
SIDE HT. COVERED. CS
14FT PULLEY CENTERS. 2HP
75HP
POLYPHOPYLENE HAG TYPE
ctOO CFM, T.bHP
5500 GAL 10FT OIA. 10FT
HT, FLAKtGLASS LINED CS
HIHP
S3.UPM. 60FT HEAD,
J.HP. 2 OPERATING
AND 1 SP4HES
6058.KT1, 17.3ET UlA
40.3FT MT 60 DEG CONE
10. np
«UB6E« LINED
30 FT LONG. 6 IN 0. SS
POLYPHOPLE.NE BAG TYPE
4bO CFM, 1.5 HP
Sbbil.OAL. 21.2FT UIA,
21.2FT hT, ELAKEGLASS-
LINEO CS
48 .HP
26.GPC, 60 FT HE«D.
l.HP. 4 OPERATING AND
4 SPAKE
1
3
3
3
J
J
3
3
j
1
1
1
1
1
1
1
8
37203.
43283.
495/5.
297071.
23262.
1699745.
13729.
228H1.
»SU7.
242J7.
HSBO.
5520.
4703.
3305.
19361.
41832.
21553.
9126.
24052.
J347.
6453.
7822.
120659.
10951.
5475.
273H.
16264.
5345.
3044.
521.
261.
15995.
3432.
7300.
3025779.
-------
Forced-Oxidation Option
Line No. Input data
8 15 40 .2 40 0 30 0.0 80 1.2 0.0 0 9 0 14.7 1
\
IFOX
The forced-oxidation option (IFOX) provides for converting sulfite
sludge (which chemically has an oxygen demand) to gypsum (which does
not). Gypsum, in comparison with sulfite sludges, offers better disposal
options such as easier dewatering, a higher settling rate, and a higher
density of settled sludge. The following values are used for the IFOX
option:
0 - No forced oxidation
1 - Forced oxidation in a single effluent tank (within the absorber
loop)
2 - Forced oxidation in the first of two effluent tanks (within the
absorber loop)
3 - Forced oxidation in the disposal feed tank (bleedstream from the
absorber loop); the number of effluent tanks depends on the ISCRUB
variable (line 9)
The number of effluent tanks specified by the forced-oxidation option
must not conflict with the number of tanks indicated by the absorber
option (ISCRUB, line 9). Example output showing the results of specifying
forced oxidation in the first of two effluent tanks (IFOX = 2) is shown
in Table 10. An example of one tank (IFOX = 1) is shown in Table 11.
Fan Option
Line No. Input data
8 15 40 .2 40 0 30 0.0 80 1.2 0.0 0 9 0 14.7 1
\
IFAN
The fan option (IFAN) allows either induced draft (ID) fans or
forced draft (FD) fans to be specified. The following values are used:
0 - Forced draft fans
1 - Induced draft fans
Example output showing the results of specifying ID fans is shown in the
base case printout in Appendix D (pp. D-5, -20). The format of the
output is similar for the FD fan option; however, the fan costs are
different.
31
-------
TABLE 10. EXAMPLE RESULTS SHOWING FORCED OXIDATION, TWO EFFLUENT TANKS
SCRUBBING
INCLUDING 4 OPERATING AND I SPARE SCRUBBING TRAINS
ITEM DESCRIPTION NO. MATERIAL LABOR
I.D. FANS
SMFLL
MJRBFP LINING
MIST ELIMINATOR
SLURRY HEADER AND NOZZLES
TOTAL SPRAY SCRUdBEfi COSTS
REHEATERS
SOOTRLOWERS
EFFLUENT HOLD TANK
EFFLUENT HOLD TANK AGITATOR
RtCIRCULATION TANK
RECIRCULATION TANK AGITATOR
COOLING SPRAY PUMPS
RtCIRCULATION PUMPS
OXIDATION BLEED PUMPS
OMDAi.JN 6IR SLOWER
OXIDATION SPARGER
MAKEUP WATER PUMPS
7.SIN h20. WITH 630.
HH WOTOH AND DRIVE
5 3340693.
1768270.
176A030.
393580.
40 AlH-FIXEO
20 AIR-RETRACTAeLE
343220.GAL, 38.8FT DIA.
38.8FT HI. FLAKEGLASS-
LINED CS
82.HP
171610.GAL 27.4FT DIA,
38.8FT hT, FLAKEGLaSS-
LINED CS
69.HP
13B7.GPM 100FT HtAO-
64.HP, 4 OPERATING
AND 6 Sf-ARE
15601.GPM, 100FT HEAD,
7J3.HP, fl OPERATING
SNO 7 SPARE
240.6PM, 60 FT HEAD
7.HP, 4 OPERATING
AND 4 SPARE
3264.SCFM, 344.HP
19.4 FT OIA RING
3467.GPM, 200.KT HEAD,
292.HP, 1 OPERATING
AND 1 SPARE
5 4780547.
5 2646582.
60 294910.
5 37300S.
5 505611.
5 218513.
5 309612.
10 104710.
15 1581315.
6 208405.
5 95155.
2 33153.
58558.
445402.
168382.
162512.
301386.
207414.
180603.
127011.
32259.
11999.
4693.
41619.
3740.
TOTAL EQUIPMENT COST
14526781. 1SOB930.
-------
TABLE 11. EXAMPLE RESULTS SHOWING FORCED OXIDATION, ONE EFFLUENT TANK
SCRUBBING
INCLUDING 4 OPERATING AND 1 SPARE SCRUBBING TRAINS
ITEM DESCRIPTION ND. MATERIAL LABOh
(.0
OJ
I.D. FA'-S
SHELL
RUBBER LIMING
MIST ELIMINATOR
SLURRY HEADER AND NUZZLES
TOTAL SPRAY SCRUBBER CDSTS
REHEATEKS
SOnTBUOvERS
7.JIN H20, «IITH 630.
HP MOTOR AND DRIVE
EFFLUSNT-OXIDATtON
HULD TAW.
EFFLUFNT-OXIDATION
HOLD TANK AGITATPR
COOLING SPRAY PUMPS
ARSQRREK RECYCLE PUMPS
OXIOATIHN BLEED PUMPS
OXIDATI IN AIR BLOWER
OXIDATION SPARGER
MAKEUP (.'ATER PUMPS
TOTAL EQUIPMENT COST
5 3340693,
1768Z70,
1766030.
393580.
852669,
40 AIR-FIXED
20 AIR-RETRACTABLE
5
5
60
343220,GAL* J8.3FT DIA, 5
38.3FT HT, FLAKEG LASS-
LINED CS
82.HP 5
1387,GPU 100FT HEAD, 10
64.HP, 4 OPERATING
AND 6 SPARE
15601.GPM. IOOFT HEAD, 15
723,HP, 8 OPERATING
AND 7 SPARE
240,GPM, 60 FT HEAD 8
7,HP, 4 OPERATING
AND 4 SPARE
3264.SCF1, 344.HP 6
19.4 FT DIA RING 5
3467.GPM. 200,FT HEAD, 2
292,HP, 1 OPERATING
AND 1 SPARE
4780547,
2646582,
294910,
503611.
104710.
34604.
208405,
95155.
33153.
58350,
449402.
168382.
132512,
373008, 301386.
207414,
32259.
1581315. 139356,
11999.
4693.
41619.
3740.
13998669, 1601313,
-------
Scrubbing Option
Line No. Input data
9 1 0 0 0 35 .0000005 32 10 5.70 1 4 1 .1
\
ISCRUB
The scrubbing option (ISCRUB) provides six separate scrubbing
systems that can be projected. The ISCRUB values that can be used and
corresponding scrubber systems are as follows:
1 - Spray tower (one effluent tank unless two tanks are specified
by the forced-oxidation option, IFOX, on line 9)
2 - TCA (one effluent tank unless two tanks are specified by the
forced-oxidation option, IFOX, on line 9)
3 - Venturi - spray tower with two effluent tanks (if forced oxida
tion is specified by IFOX on line 9, IFOX must be equal to 2.
4 - Venturi - spray tower with one effluent tank (if forced oxida
tion is specified by IFOX on line 9, the number of tanks must
agree with the number specified here)
5 - Venturi - TCA with two effluent tanks (if forced oxidation is
specified by IFOX on line 9, IFOX must be equal to 2.
6 - Venturi - TCA with one effluent tank (if forced oxidation is
specified by IFOX on line 9, the number of tanks must agree
with the number specified here)
There are no specific material balance models for the venturi - TCA
scrubbing combination specified by options 5 and 6. These options are
provided to allow comparative cost estimates for analysis and should
normally be used only in "force-through" mode (see the operating parameter
calculation option, XSR, on line 7). Example output showing the results
of specifying a spray tower is shown in the base case printout in Appendix D.
Example output showing the results of specifying a venturi - spray tower
with two effluent tanks is shown in Table 12.
Redundancy Options
Line No. Input data __
9 1 0 0 0 35 .0000005 32 10 5.70 1 4 1 .1
/ V
NSPREP NOTRAN NOREDN
Options for redundancy in the model apply to the raw material
preparation area and the scrubbing area. The controlling input variables
are NSPREP, NOTRAN, and NOREDN. NSPREP specifies the number of spare
34
-------
TABLE 12. VENTURI - SPRAY TOWER ABSORBER COST ILLUSTRATION
SCRUBBING
INCLUDING * OPERATING AND 1 SPARE SCRUBBING TRAINS
ITEM DESCRIPTION NO. MATERIAL LABOR
01
I.D. FAnS
VENTURI
SHELL
RUBBER LINING
MIST PLIMINATOR
SLURRY HEADER AND NOZZLES
TOTAL SPRAY SCRUBBER COSTS
REHEATERS
SERS
VENTUKI HOLD TANK
VENTURI HOLD TihK AGITATOR
VENTURI RECYCLE PUPPS
EFFLUFNT HOLD TANK
EFFLUfNT HOLD T4NK AGITATOR
ABSORBER RFCYCLE PUMPS
MAKEUP WATER PUMPS
HP MOTOR AND DRIVE
it AIR-FIXED
20 tlR-RETWUBLE
85768.GAL 19.4FT DIA«
38.6FT HT/FLAKEGLASS-
LIlsEQ CS
58.HP
693S.GPM 100 FT HEAD»
321,HP
-------
preparation units (ball mills for limestone or slakers for lime) and may
be given any realistic value, 0, 1, 2, 3, .... NOTRAN specifies the
number of operating absorbers. The model automatically overrides the
value of NOTRAN if the specified number requires an absorber larger than
the maximum available size. NOREDN indicates the number of spare scrubbing
trains. The base case equipment list in Appendix D (pp. D-18-20) shows
the output for a limestone scrubbing system designed with redundancy in
both ball mills and absorbers. For comparison, Table 13 shows similar
output for a limestone system with no redundancy in the absorber area.
Waste Disposal Option
Line No. Input data
10 10 9999 5000 0 25 5280 1 12 4.75
/ X
ISLUDG SDFEE
Four waste disposal options are provided in the model. The input variables
are ISLUDG and SDFEE. ISLUDG may take the values 1, 2, 3, or 4. SDFEE
specifies the cost per dry ton to fix or treat the sludge. When ISLUDG
= 1 the model assumes an onsite ponding sludge disposal system. If
ISLUDG = 2 a disposal system consisting of a gravity thickener and an
onsite pond is assumed. For ISLUDG = 3 the disposal system includes
costs for a gravity thickener and fixation. Total fixation and disposal
costs are input at $/ton of dry waste to be fixed using the SDFEE variable.
Option 4 is similar to option 3 except that a rotary vacuum filter is
added to the system downstream from the thickener and before fixation.
The fixation fee is applied in the same manner as for ISLUDG = 3; however,
in this case the material being fixed is the filter cake. Typically,
SDFEE will be zero for options 1 and 2 but an additional fee for fixation
of the sludge in the pond can be included by setting SDFEE equal to the
desired fee value. A summary of the ISLUDG options is as follows:
1 - Onsite ponding
2 - Gravity thickener and onsite ponding
3 - Gravity thickener and fixation (the SDFEE variable is used to
specify the thickener underflow fixation fee expressed in $/ton
of dry sludge to be fixed)
4 - Same as option 3 plus a rotary vacuum filter (the SDFEE variable
is used to specify the filter cake fixation fee in $/ton of dry
sludge to be fixed)
The base case printout in Appendix D (pp. D-16, -21) is an example of
the onsite ponding option. Sample output for the other waste disposal
options are shown in Tables 14-16. Annual revenue requirements correspond-
ing to waste disposal option 3 are shown in Table 17.
36
-------
TABLE 13. EXAMPLE RESULTS SHOWING NO REDUNDANCY
ITEM
SCRUBBING
DESCRIPTION
NO. MATERIAL LABOR
I.D. FANS
SHELL
RUBBER LINING
MIST ELIMINATOR
SLURRY HEADER AND NOZZLES
TOTAL SPRAY SCRUBBER COSTS
REHEATERS
SOOTBLOMERS
EFFLUENT HOLD TANK
EFFLUENT HOLD TANK AGITATOR
COOLING SPRAY PUMPS
ABSORBER RECYCLE PUMPS
MAKEUP MATER PUMPS
7.SIN H20* WITH 631.
HP MOTOR AND DRIVE
4 2673986.
46869.
4
4
8
1415222.
1413466.
315080.
682588.
3826376.
2118163.
239928.
359684
134797
146009
12 AIR-FIXED
16 AIR-RETRACTABLE
343449.GAL* 38.8FT DIA* 4 298938. 241219.
38.8*1 HT» FLAKEGLASS-
LINED CS
82.HP 4 404679. 132807.
1388.GPM 100FT HEAD/ 8 83786. 29814.
64.HP* » OPERATING
AND 4 SPARE
19611.GPM. 100FT HEAD*
723.HP* 8 OPERATING
AND 4 SPARE
3469.GPM, 200.FT HEAD*
Z4Z.HP, 1 OPERATING
AND 1 SPARE
12 1269917. 111918.
33169.
3742.
TOTAL EOUIPMENT COST
10939738. 1202409.
-------
TABLE 14. EXAIIPLE EQUIPMENT LIST FOR SLUDGE OPTION 2
vJASTE DISPOSAL
ITEM
DESCRIPTION
ND. MATERIAL
LABOR
UJ
00
ABSORBER BLEED RECEIVING
TANK
ABSORBER BLEED TANK AGITATOR
PDND FEED SLURRY PU'lPS
PDNO SUPERNATE PUMPS
THICKFNER FEED PUMP
THICKENER
THICKENER OVERFLOW PUMPS
THICKFNER OVERFLOW TANK
85768.GAL; 19.".FT OIA/
38.8FT HT, FLA
-------
TABLE 15. EXAMPLE EQUIPMENT LIST FOR SLUDGE OPTION 3
rfASTE DISPOSAL
ITEM DESCRIPTION NO, MATERIAL LABOR
ABSORBER BLEED RECEIVING 85768. GAL* I^.^FT D:A* i 29716. 2*56».
TANK 3B,eFT HT* FLA. 60FT HEAD* Z 15815, 5195,
23, HP* 1 OPERATING
AND 1 SPARE
THICKENER 23200. SO. FT, ,172, FT OIA* 1 <(53553. *92801,
9.2TANK FT HT
11, RAKE HP
THlCKENfcR OVERFLUW PUMPS 558. GPI*, 75. OFT HEAD* 2 10337, 116ft.
IB, HP* 1 OPERATING
AND 1 SPARE
THICKENER OVERFLOW T«NK 9213. GAL* 13.1FT DIA* I 3261. 2230,
9.2FT HT
SLUDGE FIXATION FEEU PUMP 263,GPM» SOFT HEAD* 2 8717, 3121,
7, HP, I OPERATING
AND 1 SP4P.E
TOTAL EQUIPMENT CUST 555788, J31904,
-------
TABLE 16. EXAMPLE EQUIPMENT LIST FOR SLUDGE OPTION 4
*ASTE DISPOSAL
urn
DESCRIPTION
NO. MATERIAL
LABDn
BLEED RECEIVING
TANK
-P-
O
ACSJRhEK BLtED TANK AGITATPK
THICKINtR FEED PUhP
Ti-'ICKfNtR
THICKRteR UNDERFLOW SLURRY
PUMPS
THICKPNtK OVERFLOW PUMPS
THICKENtR CVFRHOW TANK
FILTER FEED TAilK
e57fc8.GAL/ 19.4FT DIA/
38.8FT HT» FLAKGLASS-
LINED CS
848. GPM, 60FT HEAD*
2
-------
TABLE 16 (continued)
FILTER FEED TANK
AGITATOR
FILTER FEED SLIPPY PUMP
FILTER
FILTRATF PUMP (PER FILTER)
FILTRATE SURGE TANK
FILTRATE SURGE TANK PUfP
FILTEK CAKE CONVEYOR
TOTAL EQUIPMENT COST
7.HP 1 3159. 4ZJ.
132.GPMi SOFT HEAD/ 3 Ild37. 3463.
4.HP, 2 OPERATING
AND 1 SPARE
350.SO FT FILTRATION 3 367249, 07579.
AREA; 44. VACUUM HP
2 OPERATING AND 1 SPARE
88.GPM/ 20.OFT HEAD/ 4 17193. 1940,
l.HP/ 2 OPERATING
AMD 2 SPARE
2891. GAL/ 7.9FT DIA/ 1 1573.
7.9FT HT
175. GPM. 85. OFT HEAD/ 2 9182.
6. HP/ 1 OPERATING
iC 1 SPARE
75 FT. HORIZONTAL 1 37108.
100 FT. INCLINE
1.5 HP
1075.
1036,
3453.
1009079.
61537s.
-------
TABLE 17. EXAMPLE REVENUE REQUIREMENTS FOR SLUDGE FIXATION ALTERNATIVE (SLUDGE OPTION 3)
LIMESTONE SLURRY PROCESS — BASIS; 500
PROJECTED REVENUE KEJUIRfcMENTS - SLUDGE
SCRJPBING UNIT - 500 KW GENERATIuG UNlTj 1984 STARTUP
CASE 004
•P-
hO
DISPLAY SHEET FDR YEAR* 1
ANNUAL OPERATION KK-HR/KW « 5500
34.89 TONS PER -4DLIR DRY
TOTAL CAPITAL INVESTMENT 131600000
OIRfcCT COSTS
RAW MATERIAL
LI'lESTONE
SUBTOTAL RAK MATERIAL
C.UMVFRSICI. CI'STS
ANNUAL QUANTITY
153.4 K TONS
UNIT COST>1
8.50/TON
SLUDGE
TOTAL
ANNUAL
COST,*
1304000
1304000
OPFRATING LABOR AND
SUPERVISILN 356ZO.O MAN-HR IS.OO/MAN-HR
UTILITIFS
STEAM 546160.0 K LB 2.51/K L8
PROCFSS '/ATER 235000.0 K GAL 0.14/K GAL
FUECTRICITV 47403380.0 KWH 0.037/KWH
.1AIMTEN4NCF
LABOR AND MATERIAL
ANALYSES 4940.0 HR 21.00/HR
SUBTC1TAL CONVERSION COSTS
SUBTOTAL DIRECT COSTS
INDIRECT COSTS
OVERHEADS
PLANT AMD ADMINISTRATIVE ( 60, 3% OF CONVERSION COSTS LESS UTILITIES)
SLUDGE DISPOSAL FEE 191900.0 TONS 10.00/TON
FIRST YEAR OPERATING AND MAINTENANCE COSTS
LEVELIZEO CAPITAL CHARGES! 14.70!! DF TOTAL CAPITAL INVESTMENT)
FIRST VEAR ANNUAL REVENUE RE6U1REMENTS
EOUIVALENT FIRST YEAR UNIT REYEMUE REQUIREMENTS* MILLS/KWH (l-'W SCRUBBED)
LtVELIZEO OPERATING AND MAINTENANCE ( 1.886 TIMES FIRST YEAR OPER. (. MAIN.)
LEVELIZED CAPITAL CHARGES! 14.70* OF TOTAL CAPITAL INVESTMENT!
LEVELUED ANNUAL REVENUE REQUIREMENTS
EQUIVALENT LEVELIZED UNIT REVENUE REQUIREMENTS, MILLS/KWH (MW SCRUBBED)
HEAT RATE 9500. BTU/KWH - HEAT VALUE DF COAL 11700 BTU/LB
534300
1365400
32900
1733900
5776300
103800
9566600
10870600
3848600
1919000
16638200
19345200
35983400
13.08
31379600
19345200
50724BOO
16,45
COAL RATE 1116500 TONS/YR
-------
Pond Design Option
Line No. Input data
10 10 9999 5000 0 25 5280 1 12 4.75
/ / \
PSAMAX PDEPTH PMXEXC
The configuration for disposal ponds used in the model and shown in
Figure 2 is assumed to be square with a diverter dike that is three-
fourths the length of the sides. Based on this configuration and the
volume of waste to be disposed of over the total life of the plant, the
pond design option provides three different options for defining the
relationships between pond land area, excavation depth, and depth of
waste in the finished pond. These options are as follows:
Fixed depth pond
Optimum pond based on minimum investment costs, subject to specified
area limits, excavation limits, or both
Optimum pond based on minimum investment costs
Three variables, PSAMAX, PDEPTH, and PMXEXC, determine which pond option
is selected by the model. The PSAMAX variable specifies the maximum
land area in acres available for the pond, the PDEPTH variable specifies
the ultimate depth of waste in the finished pond, and the PMXEXC variable
specifies the maximum depth of topsoil and subsoil (clay) that will be
excavated and used for dike construction (excavation and dike construc-
tion calculations are based on the assumption that the excavated material
compacts to 85% of the original volume). For a fixed depth pond, PSAMAX
should be set to zero, PDEPTH should be set to the desired depth, and
PMXEXC should be set to zero. For an optimum pond based on minimum
investment costs but subject to area and excavation limits, PSAMAX
should be set to the maximum area in acres available for pond construc-
tion, PDEPTH should be set to zero, and PMXEXC should be set to the
maximum excavation depth allowed. The final option, optimum pond based
on minimum investment costs (no area and excavation limits) is essentially
the same as the second option except that the values specified for the
area and excavation limits should be set high enough that they will not
realistically limit the optimized values, for example, PSAMAX = 9999 and
PMXEXC = 25. The following variable values illustrate each of the pond
design options.
PSAMAX = 0, PDEPTH = 10, PMXEXC = 0 - Fixed depth pond (pond area and
excavation depth will be calculated by the model) .
PSAMAX = 250, PDEPTH = 0, PMXEXC = 3 - Optimum pond based on minimum
investment costs, but pond area cannot exceed 250 acres and excavation
depth cannot exceed three feet (if the optimum pond does not exceed
the specified area and excavation limits, the values calculated by
the model will be used, otherwise pond depth and the optimum value
that is not exceeded will be adjusted as necessary).
43
-------
-p-
-P-
f—
r
I
t
\
I
t
t
A T
t;
*
*
i
*
t
i
*-«-
^-.^, **,»«. »-..,
GROUND LEVEL
TOPSOIL
EXCAVATION
(15 FT.JN
'0% FREE BOARD
TOTAL
EXCAVATION DEPTH
TOPSOIL '
EXCAVATION
(15 FT)
SECTION AA
POND PERIMETER DIKE
SECTION BB
POND DIVERTER DIKE
SUBSOIL
EXCAVATION
10% FREE BOARD
DEPTH OF SLUDGE
1 TOTAL
EXCAVATION DEPTH
Figure 2. Pond construction configuration.
-------
PSAMAX = 9999, PDEPTH = 0, PMXEXC = 25 - Optimum pond based on mini-
mum investment costs (pond area, depth, and excavation depth will all
be calculated by the model).
When pond design option two is used and calculations indicate that the
total waste volume cannot be contained within the specified area and
excavation limits, an error message is issued and the data case is
terminated. Example output showing the results of specifying an optimum
pond based on minimum investment costs is shown in the base case printout
in Appendix D (p. D-16). Example output showing the results of specifying
an area limitation of 270 acres is shown in Table 18.
Pond Liner Option
Line No. Input data
10 10 9999 5000 0 25 5280 1 12 4.75
/ \ \
ILINER XLINA XLINB
The pond liner option allows a choice of an unlined, clay-lined, or
synthetic-lined pond. The input variables are ILINER, XLINA, and XLINB.
ILINER specifies the type of lining in the pond as illustrated below.
1 = Clay liner
2 = Synthetic liner
3 = No liner
For a clay-lined pond (ILINER = 1), XLINA specifies the depth of
clay in inches and XLINB specifies the clay lining installation cost (or
the costs for reworking the clay subsoil into a lining) in $/yd^. For
a synthetic-lined pond (ILINER = 2), XLINA specifies the liner material
cost in $/yd2 and XLINB specifies the installation cost in $/yd2. For
no liner (ILINER = 3), XLINA and XLINB should be set to zero.
Example output showing the results of specifying a clay pond liner
is shown in the base case printout in Appendix D (p. D-16). Example
output showing the results of specifying a synthetic pond liner is shown
in Table 19. The input values for the synthetic liner were ILINER = 2,
XLINA = 4.00, and XLINB = 1.50.
Economic Premises Option
Line No. Input data
11 7 2 16 5 10 8 15.6 10 8 3 6 1 60 1.886 14.7 0.0
IECON PCTOVR XLEVEL CAPCHG PCTMKT
or or or
PCTADM UNDCAP PCTINS
45
-------
TABLE 18. EXAMPLE OF OPTIMUM POND SUBJECT TO AREA LIMITS
POND DESIGN
OPTIMIZED TO MINIMIZE TOTAL COST PLUS OVERHEAD
WITH POND SITE ACREAGE CONSTRAINT
POND DIMENSIONS
DEPTH OF PONO
DEPTH OF EXCAVATION
LENGTH OF DIVIDER DIKE
LENGTH OF PONO PERIMETER DIKE
LENGTH OF POND PERIMETER FENCE
SURFACE AREA OF BOTTOM
SUPFSCE AREA OF INSIDE WALLS
SURFACE AREA OF OUTSIDE WALLS
SURFACE AREA OF RECLAIM STORAGE
LAND AREA OF POND
LAND AREA OF PONC SITE
LAND AREA OF POND SITE
VOLUME OF EXCAVATION
VOLUME OF RECLAIM STORAGE
VOLUME OF SLUDGE TO BE
DISPOSED OVER LIFE OF PLANT
45.36
10.93
3078.
11804.
13227.
756.
217.
173.
93.
954.
1307.
270.
FT
FT
FT
FT
FT
THOUSAND
THOUSAND
THOUSAND
THOUSAND
THOUSAND
THOUSAND
ACRES
YD2
Y02
YD2
Y02
Y02
YD2
3001. THOUSAND YDS
571. THOUSAND YD3
12900. THOUSAND YD3
7996. ACRE FT
POND COSTS (THOUSANDS OF DOLLARS)
LABOR
MATERIAL TOTAL
CLEARING LAND
EXCAVATION
DIKE CONSTRUCTION
LINING! 12. IN. CLAY)
SODDING DIKE WALLS
ROAD CONSTRUCTION
PERIMETER COSTS. FENCE
RECLAMATION EXPENSE
MONITOR WELLS
SUBTOTAL DIRECT
TAX AND FREIGHT
POND CONSTRUCTION
LAND COST
POND SITE
OVERHEAD
528.
8998.
6335.
1541.
214.
27.
66.
710.
4.
18422.
18422.
135.
8.
132.
4.
279.
21.
300.
528.
8998.
6335.
1541.
349.
35.
198.
710.
8.
18701.
21.
18722.
1350.
20072.
8894.
TOTAL
28966.
-------
TABLE 19. SYNTHETIC POND LINER EXAMPLE
OPTIMIZED TO
POND DESIGN
MIZE TOTAL COST PLUS OVERHEAD
POND DIMENSIONS
OfcPTh (IF PONU
PERTH UF EXCAVATION
LF'"GTH OF DIVIDED DIKE
lOhTH OF PONU PERIMETER DIKE
LENGTH OF POND PERIMETER FENCE
SURF-ACE AREA Of tOTTOM
SURFACE AREA Of INSIDE HALLS
SURFACE APEA OF OUTSIDE .(ALLS
SURFACE AREA OF nECLAl" STORAGE
1 AND AREA OF PUNC
LAMP AREA OF POND SITE
L or.fj AREA Of- POND SITE
VOLU"E UF EXCAVATION
VOlU"t OF RECLAIM STORAGE
VClU^t OF SLUDGE TO HE
PISPOStD OVER LIFE CF PLANT
33.06
6.27
2434.
13530.
14717.
lOflO.
193.
14«.
109.
1256.
1612.
333.
FT
FT
FT
FT
FT
THOUSAND
THOUSAND
THOUSAND
THOUSAND
THOUSAND
THOUSAND
ACRES
Y02
VD2
rD2
YD2
YD2
Y02
2442. TMOUSAND YDS
712. THOUSAND YD3
12900. THOUSAND vua
7996. ACHE FT
COSTS (THOUbANCS OF DOLLARS)
LAHOP.
MATERIAL TOTAL
TLE A^ ING LAND
FXCAVAT [ON
MVF CONMK'OCTION
1 IK IKfalSrNTHtTIC)
SODDING HIKE HALLS
^?OAU CCJNSTRUCT ION
DFRI^tTER COSTS. FFNCE
RECLAMATION EXPENSE
^•0^1TOR rfFLLb
SUPTOTAL DIRECT
TAX ANU FREIGHT
P0l>0 CONSTRUCTION
LAND COST
POM) SITE
OVf RHEAf)
651.
732?.
45H.
190H.
114.
31.
74.
923.
4 .
1553H.
15531.
5089.
72.
9.
147.
4.
5321.
399.
5720.
651.
7322.
»SH.
6997.
186.
40.
2?1.
9?3.
a.
20859.
399.
21258.
1665.
22923.
10099.
330P2.
-------
The economic premises option (IECON) allows cost projections based
on either the EPA-TVA economic premises adopted December 5, 1979 (and
expanded and amplified in March 1980), or the old premises that were
used prior to December 5, 1979. Appendix B contains a description of
the revised premises. Four variables are used in conjunction with the
economic premises option, and the meaning of these variables depends on
which set of premises is selected (see Appendix B). If the revised
premises are specified (IECON = 1), the PCTOVR variable specifies the
plant administrative overhead rate, applied as a percent of conversion
costs less utilities, the XLEVEL variable specifies the levelizing
factor to be applied to first-year operating and maintenance costs to
develop levelized operating and maintenance costs for the total life of
the plant, the CAPCHG variable specifies levelized annual capital charges
applied as a percent of total capital investment, and the PCTMKT variable
specifies marketing costs applied as a percent of byproduct credit
(applies only to processes with a salable byproduct). If the levelizing
factor (XLEVEL) is set to zero then a lifetime revenue sheet is printed
showing annual revenue requirements for each year of plant operation.
If the old premises (used before December 1979) are specified (IECON = 0),
the PCTOVR variable specifies the plant overhead rate, applied as a
percent of conversion costs less utilities, the PCTADM variable specifies
the administrative research and service overhead rate, applied as a
percent of operating labor and supervision, the UNDCAP variable specifies
the annual capital charge basis for undepreciated investment, and the
PCTINS variable specifies the rate for insurance and interim replacements,
applied as a percent of total capital investment. Example output showing
the results of specifying the new economic premises (IECON = 1) and a
nonzero levelizing factor (XLEVEL = 1.886) is shown in the base case
printout in Appendix D (pp. D-22, -24). The results of specifying a
zero levelizing factor are shown in the example revenue requirements in
Table 20. The results of specifying the old economic premises are shown
in the example revenue requirements in Table 21.
Sales Tax and Freight Option
Line No. Input data
12 1 4 3.5 6 0 1 1.5 1 2 1 8 5 10 0
ITAXFR TXRATE FRRATE
The sales tax and freight option (ITAXFR) allows sales tax and
freight to be applied as a percentage of material costs. The sales tax
rate is specified with the variable TXRATE, and the freight rate is
specified with the FRRATE variable. When ITAXFR is set to 1, the speci-
fied rates are applied to material costs and included in the capital
investment summary printout; when ITAXFR is set to zero sales tax and
freight are excluded. Example output showing the results of specifying
sales tax and freight is shown on the capital investment summary sheet
in the base case printout in Appendix D (p. D-22). An example invest-
ment summary sheet showing sales tax and freight excluded is shown in
Table 22.
48
-------
TABLE 20. EXAILPLE REVENUE REQUIREMENTS USING THE NEW ECONOMIC PREMISES WITH NO LEVELIZING
LIMESTJNE SLURRY PROCESS — SASISI soo in SCRUBBING UNIT - soo MW GENERATING UNIT* 1984 STARTUP
PROJECTED REVENUE REQUIREMENTS - ZERO LE^AL
CASE ooa
DISPLAY SHEET FOR YEAR* 1
ANNUAL OPERATION KW-HR/KW « 5500
34.89 TONS fiK HOUR DRY
TOTAL CAPITAL INVESTMENT 109013000
ANNUAL QUANTITY UNIT COST,*
DIRECT COSTS
RAW ".ATERIAL
LIMESTONE
SUBTOTAL RAV> MATERIAL
CO'JVrkSIO'J COSTS
OPERATING LABOR AND
SllPERYISIlTI
UTILITIES
STEA"'
PROCESS '»ATEP
ELECTRICITY
MAINTENANCE
LABOR AND MATERIAL
ANALYSES
SUBTOTAL CONVERSION COSTS
SUBTOTAL DIRECT COSTS
INDIRECT COSTS
153.4 K TUNS 8.50/TON
30680.0 MAN-HR 15.00/MAN-HR
546160.0 K LB 2.50/K LB
E39930.0 K GAL 0.14/K GAL
47526160.0 KWH 0.037/KWH
4940,0 HR 21.00/HR
OVERHEADS
PLA.lT AND ADHrilSTRAriVE ( 60. OX OF CONVERSIuN COSTS LESS UTILITIES)
FIRST YEAK DPfcRATING AND MAINTENAMCE COSTS
LEVELIZEO CAPITAL CHARGES! 14.70X OF TOTAL CAPITAL INVESTMENT)
FIRST YEAR ANNUAL REVENUE REOUI REMENTS
EQUIVALENT FIRST YEA" UNIT REVENUE REOUIP.EMENTS/ MILLS/KWH (MW SCRUBBED)
HEAT RATE 9500. BTU/KWH
HEAT VALUE OF CUAL 11700 BTU/LB
SLUDGE
TOTAL
ANNUAL
COST/$
1304000
1304000
460200
1365400
36400
1758900
4130100
103800
7854400
9158400
2816500
1197*900
16025000
27999900
10,18
COAL HATE 1116500 TONS/YR
(continued)
-------
TABLE 20 (continued)
O
Ll'iEST.INt SLURRY PROCESS — 8ASISI 500 "I IV SCRUBBING UNIT - 500 Mw GENERATIiG UNIT/ 198*1 STARTUP
PROJECTED LIFET'l'.F RtVE'liF REQU! REI1E ill 5 " ZFAJ LEVAL
TOTAL CAPITAL INVESTMENT! » 109014000
CASE 008
ADJUSTED GROSS
YEARi
PLUE^
UNIT
START
1
3
5
7
9
I'/
1 1
12
13
14
11
17
19
20
21
22
23
2«
25
27
a
29
30
TD1
/. N 00
5iOO
5300
5300
5500
1()5.>00
LIFCTIME
KE>/E'«
SJLFUR
PEEVED
L P'MER ""IT PUhER UNIT BY
HfcAT FUEL PDILJTI3N
RKjUIPtME"T> CONSUMPTION, CuNTROL
MILLlni. BTu TONS COAL PKUCESSj
/YFAk /YEAR TJ'iS/Y6AR
26125000 1116500 30600
26125000 11165JO 30600
26125000 1116500 30600
26123000 1116500 30600
26125000 1116500 30600
26125000 1116500 3"600
26125000 1116500 30600
261250CO 1116500 30600
2612500? 1116500 30600
26125000 11165"0 30600
Z61Zi>000 1116500 30000
26125000 1116500 30600
26125000 11165-10 30600
26125000 11165'10 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 11165.)0 3D600
2612500" 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
,-6125000 11165"0 30600
26125000 1116500 31.600
26125000 11165CO 30600
26125000 1116300 30hOO
2617.5000 1116500 3O600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
7*3750001 33495000 91BOOO
AVERAGE INCRF.ASf IN UNIT REVENUE REQUIREMENT
DOLLARS PER TON OF C3AL BUdNEQ
NILLb PfR KILOWATT-H3UR
CENTi PFR MILLION 8TJ HEAT INPUT
DOLLARS PER TCN DF SJLFUR REMOVED
Uf , . U
i.. . 0
; ,o
0.0
0,0
I'.O
L..O
0.0
0.0
') , 0
L , 0
r.,u
0.0
{;, 0
0,0
J,0
U.O
(. ,0
o.o
0.0
u.t-
f. .0
U.O
y.o
t, ,0
0,0
i, ,0
0,0
0,0
0,0
REQUIREMENT
EXCLUDING
SLUDGE
FIXATION
COST,
J/YEAR
27999900
28718500
29479900
30Z87200
31142800
32050100
33011400
34030700
35110900
36256200
37470100
38756700
40120700
41566600
43099100
44723300
4644S100
48270500
50205300
52256300
54429800
56734200
59176800
61765BOO
64510200
67419300
70503100
73771700
77236500
60909400
1427458000
42.62
17.30
182.13
1554,97
351898600
LEVELtZEr* INCREASE Hi UNIT REVENUE RESUIRfcMENT EQUIVALENT TU DISCOUNTED REOUJREMENT OVER LIFE
UNIT
CHSTS
DOLLARS PER TON OF C3AL BURNED
HILLS PER KILOWATT-H3UR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
INFLATED AT 6, OCX PER YEAR
33.43
13.57
142.89
1219.75
TOTAL
ANNUAL
SLUDGE
FIXATION
COST,
*/YEAR
0
0
0
0
0
0
0
0
0
D
0
y
0
0
0
0
0
3
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
DF POKES
0.0
0,0
0.0
0,0
NET ANNUAL
INCREASE
IN TUTAL
REVENUE
RE3UIREMENT,
1
27999900
28718500
29479900
30Z37ZOO
31142800
320S0100
33011400
34030700
35110900
36256200
37470100
38756700
40120700
41566600
43099100
44723300
46445100
48270500
50205300
52256200
54429800
56734200
59176800
61765BOO
64510200
67419300
70503100
73771700
77236500
80909400
1427458000
42.62
17.30
182.13
1554.97
351898600
UNIT
33.43
13.57
142.89
1219.75
CUMULATIVE
NET INCREASE
IN TUTAL
REVENUE
REQUIREMENT/
t
Z7999900
56718400
36198300
116485500
147628300
179678400
212689800
246720500
281831400
318087600
355557700
394314400
434435100
476001700
519100800
563824100
610269200
658539700
708745000
761001200
815431000
B72165200
931342000
993107800
1057618000
1125037300
1195540400
1269312100
1346548600
1427458000
-------
TABLE 21. EXAMPLE REVENUE REQUIREMENTS USING THE OLD ECONOMIC PREMISES
LIMESTONE SLURRY PRHCESS — BASISl 500 1W SCRUBBING UNIT -
PROJECTED REVENUE REQUIREMENTS - OLD PREIISE
500 MW GENERATING UNIT* 198* STARTUP
CASE 009
DISPLAY SHEET FDR YEARn 1
ANNUAL OPERATION KW-HR/KW » 5500
34,89 TONS PER HOUR DRY
TOTAL CAPITAL INVESTMENT 99172000
DIRECT COSTS
PAW '-1ATERIAL
LIMESTONE
SUBTUTAL RAV MATERIAL
C'lNVERSIHN COSTS
ANNUAL QUANTITY
153.* K TONS
UNIT COST»»
8.SO/TON
SLUDGE
TOTAL
ANNUAL
COST,*
1304000
1304000
UPtRATIUG LABOR AND
SUPERVISION 30680.0 MAN-HR IS.CO/MAN-HR
UTILITIES
STEA" 5461&P.O K LB 2.5G/K L8
PROCESS ^.ATER 259970.0 K GAL 0.14/K GAL
ELECTRICITY 47526120.0 KWH 0.037/KKH
t'AINTENANCF
LtBOP AND MATERIAL
ANALYSES 4380.0 HR 21.00/HR
SUBTOTAL CONVERSION COSTS
SUBTUTAL DIRECT COSTS
INDIRECT COSTS
DEPPEC IATIDN
CuST JF CAPITAL AMD TAXES< 17.20* OF UNDEPRECIATED INVESTMENT
INSURANCE L INTERIM REPLACEMENTS* 1.17* OF TOTAL CAPITAL INVESTMENT
PVERHEAD
PLAUT, 50,o!i HP CONVERSION COSTS LESS UTILITIES
ADMINISTRATIVE. RESEARCH, AID SERVICE*
10. 0* OF OPERATING LABOR AND SUPERVISION
SUBTUTAL INDIRECT COSTS
TOTAL ANNUAL REVENUE REQUIREMENT
EQUIVALENT UNIT REVENUE REQUIREMENT,- MILLS/KrfH
HEAT RATE 9500. BTU/KWM - HEAT VALUE OF COAL 11700 bTU/LB
460200
1365400
36400
1758500
3299600
92000
7012100
8316100
3173700
17057700
1160300
1925900
46000
23365600
31681700
11.52
COAL RATE 1116500 TONS/YR
(continued)
-------
TABLE 21 (continued)
LHESTUN6 SLURRY PROCESS —• BAStSI 500 1H SCRJBBING UNIT - 3OO MW GENERATING UNIT/ 198* STARTUP
PROJECTED LIFETIME REVENUE REQUIREMENTS - QLO PREMISE
TOTAL CAPITAL INVESTMENTI t 99172000
CASE 009
YEARS iNIJUAL
AFTER UPERA-
POWE* TI3N,
UNIT KW-HR
START /KW
I 5500
2 5500
3 5500
4 5500
5 5JOO
6 5500
7 5300
B 5500
9 5500
10 5500
11 5500
12 5500
13 5500
14 5500
15 5500
16 5500
17 5500
15 5500
19 5500
20 5500
21 5300
22 5500
23 5500
2* 5500
25 5500
26 5500
27 5500
2tJ 5500
29 5500
30 5500
TOT 165-100
LIFETIME
ADJUSTED GROSS
SULFUR BYPRODUCT ANNUAL REVENUE
REMOVED RATE* SLUDGE REOLIREMENT TOTAL
PHWER UNIT POWER UNIT BY EQUIVALENT FIXATION FEE EXCLUDING ANNUAL
HEAT FUEL POLLUTION TONS/YEAR I/TOM SLUDGE SLUDGE
REQUIREMENT, CONSUMPTION/ CQNTRUL FIXATION FIXATION
MILLION BTU TONS COAL PROCESS* DRY DRY COST/ COST*
/YEAR /YEAR TONS/YEAR SLU06E
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
P6125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26123000 1116510 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
26125000 1116500 30600
783750000 33495000 918000
AVERAGE INCREASE IN UNIT REVENUE REQUIREMENT
DOLLARS PER TON OF C3AL BURNED
MILLS PER KILQWATT-H3UR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
REVENUE KEOUIREMENT DISCOUNTED AT 10. OX TO INITIAL YEAR*
LEVELUED
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
191900
5757000
DOLLARS
INCREASE IN UNIT REVENUE REQUIREMENT EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF C3AL BURNED
HILLS PER KILOWATT-H3UR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
SLUDGE
0.0
U.O
0,0
L.O
U.O
(J.U
nO
r ,o
0 .0
O.P
0,0
u.O
0.0
0,0
o.o
0,0
0,0
0,0
1..0
u.o
o.o
0,0
t'.O
u.O
0.0
0,0
0,0
o.o
0.0
0.0
REQUIREMENT
I/YEAR
31681700
'1133400
30989200
30043000
29496600
26950600
23404300
27858100
27311900
26763700
26219500
25673200
25127000
2*580600
24034600
23486400
22942100
22395900
21849700
21303500
20757300
20211000
19664800
19118600
18572400
16026200
17479900
16933700
16387500
15841300
712844100
21.28
8.64
90.95
776.52
256559500
OVER LIFE
24.38
9.90
104.17
889.29
t/YEAR
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
9
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
OF POWER
0.0
0.0
0.0
0.0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
IN TOTAL IN TOTAL
REVENUE REVENUE
REQUIREMENT, REQUIREMENT*
i
31681700
31135400
305H9200
300*3000
29496600
28950600
28404300
27858100
27311900
267*5700
26219500
25673200
25127000
249HC800
24034600
234X8400
22942100
22395900
21849700
21303500
20757300
20211000
19664600
19118600
18572400
18026200
17479900
16933700
16387300
13841300
712644100
21.26
8.64
90,95
776.32
256339500
UNIT
24.38
9.90
104,17
889.29
1
31681700
62817100
93406300
123449300
152946100
181896700
210301000
238159100
263471000
292236700
318436200
344129400
369256400
393837200
417871800
441360200
464302300
486698200
308547900
529851400
550608700
570819700
390484300
609603100
628175300
646201700
663681600
680615300
697002800
712844100
-------
TABLE 22. EXAMPLE INVESTMENT SUMMARY SHEET WITH SALES TAX AND FREIGHT EXCLUDED
STARTUP
Ul
PROJECTED CAPITAL INVESTMENT REQUIREMENTS - NO
EOUIPMENT
MATERIAL
LABOR
PIPING
MATERIAL
LABOR
DUCTWORK
MATERIAL
LABOR
FOUNDATIONS
MATERIAL
LABOR
STRUCTURAL
MATERIAL
LABOR
ELECTRICAL
MATERIAL
LABOR
INSTRUMENTATION
MATERIAL
LABOR
BUILDINGS
MATERIAL
LABOR
TOTAL PROCESS CAPITAL
SERVICES AND MISCELLANEOUS ( 6.0 X)
TOTAL DIRECT PROCESS INVESTMENT
POND CONSTRUCTION MATERIAL
POND CONSTRUCTION LABOR
TOTAL DIRECT ?OND INVESTMENT
TOTAL DIRECT INVESTMENT
ENGINEERING DESIGN AND SUPERVISION ( 7.0 X)
ARCHITECT AND ENGINEERING CONTRACTOR ( 2.0 X)
CONSTRUCTION EXPENSES (16.0 X)
CONTRACTOR FEES I 5.0 X)
CONTINGENCY (10.0 X)
POND INDIRECTS ! 2.0/ 1.0* 8.0* 3iO* 10.0 X)
SUBTOTAL FIXED INVESTMENT
STARTUP t MODIFICATION ALLOWANCE c t.o* o.o x>
INTEREST DURING CONSTRUCTION 113.6 X)
ROYALTIES ( 0.0 X)
LAND
WORKING CAPITAL
TAX OR FREIGHT
INVESTMENT*
RAW MATERIAL
PREPARATION
3049.
307.
416.
192.
0.
0.
341.
883.
196.
142.
262.
737.
148.
22.
147.
163.
7024.
421.
7443.
0.
0.
0.
7449.
321.
149.
1191.
372.
968.
0.
10647.
832.
1661.
0.
10.
401.
THOUSANDS OF
SCRUBBING
13666.
1544.
3132.
918.
3042.
2723.
172.
374.
372.
648.
813.
1567.
814.
131.
0.
0.
319J7.
1916.
33854.
0.
0.
0.
33834.
2370.
677.
3417.
1693.
4401.
0.
48411.
3873.
7532.
0.
4.
1825.
1912 DOLLARS
WASTE
DISPOSAL
93.
34.
1056.
352.
0.
0.
20.
42.
2.
3.
146.
318.
13.
9.
0.
0.
2092.
126.
2218.
303.
14917.
13219.
17437.
153.
44.
353.
111.
288.
4201.
22591.
254.
3924.
0.
2120.
940.
TOTAL
16810.
1884.
6627.
1461.
3042.
2723.
534.
1299.
570.
794.
1221.
2641.
975.
162.
147.
163.
41053.
2463.
43517.
303.
14917.
13219.
58736.
3046.
870.
6963.
2176.
9637.
4201.
81649.
4978.
12737.
0.
2134.
3166.
CASE 002
DISTRIBUTION
DOLLARS
PER KW
33.62
3.77
13.25
2.92
6.06
5.45
1.07
2.60
1.14
1.39
2.44
5.28
1.95
0.32
0.29
0.33
82.11
4.93
87.03
0.61
29.83
30.44
117.47
6.09
1.74
13.93
4.35
11.31
8.40
163.30
9.96
23.47
0.0
4.27
6.33
TOTAL CAPITAL INVESTMENT
13371.
61665.
29429.
104665.
209.33
-------
Overtime Option
Line No . _ Input data
12 1 4 3.5 6 0 1 1.5 1 2 1 8 5 10 0
/ \
IOTIME OTRATE
The overtime option (IOTIME) allows an overtime labor rate (OTRATE)
to be applied to 7% of total labor as defined in the new TVA-EPA premises
(Appendix B) . When IOTIME is set to 1, the specified overtime rate is
applied to 7% of all applicable labor costs; when IOTIME is set to zero
no overtime labor adjustments are made. The added costs for overtime
labor are not shown separately in the model output, but a message is
printed in the listing of the model inputs to indicate if overtime is
specified as shown in the base case printout in Appendix D (p. D-6) .
Separate Pond Construction Indirect Investment Factors Option
Line No. __ _ Input data _
12 143.56011.512185 10^
INDPND PENGIN PARCH PFLDEX PFEES PCONT PSTART
The separate pond construction indirect investment factors option
(INDPND) allows pond construction indirect investment to be calculated
separately from process indirect investment. Pond construction is in
general less complex than the scrubbing process and therefore indirect
investment factors are usually lower. Six variables are used in conjunc-
tion with the separate pond indirect investment option. They correspond
one-for-one with the process indirect investment factors (line 11:
ENGIN, ARCTEC, FLDEXP, FEES, CONT, and START). The PENGIN variable
specifies pond engineering design and supervision costs, applied as a
percentage of total direct pond investment. The PARCH variable specifies
pond architectural and engineering contractor costs, applied as a percentage
of total direct pond investment. The PFLDEX variable specifies pond con-
struction field expenses, applied as a percentage of total direct pond
investment. The PFEES variable specifies pond contractor fees, applied
as a percentage of total direct pond investment. The PCONT variable
specifies pond contingencies, but the way it is applied depends on the
economic premises option (line 11, IECON). If the new economic premises
are specified (IECON = 1) then pond contingency is applied as a percentage
of total direct pond investment plus each of the preceding four pond
indirect investment costs. If the old economic premises are specified
(IECON = 0) then pond contingency is applied as a percentage of total
direct pond investment only. The PSTART variable specifies the allowance
for pond startup and modification, applied as a percentage of total
fixed pond investment. Example output showing the results of specifying
separate indirect investment factors for pond construction (INDPND = 1)
is shown on the investment summary sheet in the base case printout in
Appendix D (p. D-22). Example output showing the results of using
54
-------
common indirect investment factors for both the FGD process and pond
construction (INDPND = 0) is shown in Table 23.
Pond Capacity Option
Line No. Input data
14 4 1 5 .8 1.0 3 .65 1 1 1.10 1982 297.9
\
PNDCAP
The pond capacity option provides the capability to design the raw
material and scrubbing areas based on maximum sulfur content of coal
(high sulfur content fluctuation) but, at the same time, to design the
pond based on an average sulfur content. For example, on a long-term
basis, the coal being used may be expected to average 2.0% sulfur.
However, at times the sulfur content may be as high as 3%. The raw
material preparation area and the scrubbing area should be sized for the
maximum coal sulfur content that is expected to be encountered. In this
case a value of 3% must be considered for design of the feed preparation
and absorber units, but the model also calculates the sludge production
rate based on the input sulfur content and sizes the pond based on that
amount. The PNDCAP option is included in the model to allow the projected
waste disposal pond size to be modified to account for the difference
between average and maximum sulfur content (ordinarily PNDCAP will be in
the range of 0.5-1.0). In the preceding example, by specifying PNDCAP
equal to 0.67, the waste disposal pond would be sized based on a 2%
sulfur coal, whereas the other facilities would be designed for fluctu-
ations in coal sulfur content of up to 3%.
If the user wishes to specify an oversized pond to cover contingencies
in sulfur content, or to specify an undersized pond for applications in
which the initial pond is not designed for the full life of the plant, an
appropriate PNDCAP factor, i.e., greater than or less than 1.0, can be
specified.
Operating Profile Option
Line No. Input data
14 3 1 5 .8 1.0 3 .65 1 1 1.10 1982 297.9
\
IOPSCH
15 30
IYRC
One of the most important variables affecting the economics of a
power plant and an associated FGD system is the operating profile (number
of years of operation and the hours of operation per year) over the life
of the unit. The effects of the year-by-year profile on investment and
55
-------
TABLE 23. EXAMPLE INVESTMENT SUMMARY SHEET WITH COMMON INDIRECT INVESTMENT FACTORS FOR PROCESS AND POND
500 MH GENERATING UNIT.. 1984 STARTUP
PROJECTED CAPITAL INVESTMENT REQUIREMENTS - COMMON INDIRECTS
EOUIPMSNT
MATERIAL
LABOR
PIPING
MATERIAL
LABOR
DUCTWORK
MATERIAL
LABOR
FOUNDATIONS
MATERIAL
LABOR
STRUCTURAL
MATERIAL
LABOR
ELECTRICAL
MATERIAL
LABOR
INSTRUMENTATION
MATERIAL
LABOR
BUILDINGS
MATERIAL
LABOR
SALES TAX ( 4.0 X) AND FREIGHT ( 3.3 X)
TOTAL PROCESS CAPITAL
SERVICES AND MISCELLANEOUS ( 6,0 X)
TOTAL DIRECT PROCESS INVESTMENT
POND CONSTRUCTION MATERIAL
POND CONSTRUCTION LABOR
POND SALBS TAX ( 4.0 X) AND FREIGHT < 3.5 X)
TOTAL DIRECT POND INVESTMENT
TOTAL DIRECT INVESTMENT
ENGINEIRING DESIGN AND SUPERVISION ( 7,0 X)
ARCHITECT AND ENGINEERING CONTRACTOR ( 2,0 X)
CONSTRUCTION EXPENSES (16.0 X)
CONTRACTOR FEES I 5.0 X)
CONTINGENCY (10.0 X>
SUBTOTAL FIXED INVESTMENT
STARTUP £ MODIFICATION ALLOWANCE ( 8.0 X)
INTEREST DURING CONSTRUCTION (15.6 X)
ROYALTIES < o.o x>
LAND
WORKING CAPITAL
INVESTMENT;
RAW MATERIAL
PREPARATION
3049.
307.
416.
192.
0.
0.
341.
883.
196.
1*2.
262.
757.
148.
22.
147.
163.
342.
7366.
442.
7808.
0.
0.
0.
0.
7808.
347.
136.
1249.
390.
1015.
U165.
893.
1742.
0.
10.
418.
THOUSANDS OF
SCRUBBING
13666.
1544.
5152.
918.
3042.
2723.
m.
374.
372.
648.
813.
1566.
814.
131.
0.
0.
1802.
33740.
2024.
35764.
0.
0.
0.
0.
35764.
2504.
715.
57Z2.
1788.
4649.
51U3.
4091.
7978.
0.
4.
1917.
1982 DOLLARS
WASTE
DISPOSAL
93.
34.
1058.
352.
0.
0.
20.
42.
2.
3.
146.
318.
13.
9.
0.
0.
loo.
2192.
132.
2324.
303.
14903.
23.
15231.
1755S.
1229.
46.
2809.
878.
2252.
Z4T6B.
1981.
3864.
0.
2137.
941.
TOTAL
16810.
1884,
6626.
1461.
3042.
2723.
534.
1299.
57o.
794.
1221.
2641.
975.
162.
1*7.
163.
2244.
43298.
2598.
43896.
303.
14905.
23.
15231.
61127.
4279.
918.
9780.
3056.
7916.
87076,
6966.
13584.
0.
2132.
1276.
CASE 003
DISTRIBUTION
DOLLARS
PER KW
33.62
3.77
13.25
2.92
6.08
5.45
1.07
2.60
1.14
1.39
2.44
5.28
1.95
0.32
0.29
0.33
4.49
86.60
5.2D
91.79
0.61
29.81
0.05
30.46
122.25
8.56
1.8*
19.36
6.11
15.83
174.13
13.93
27.17
0.0
4.30
6.35
TOTAL CAPITAL INVESTMENT
1*229.
63133.
1369Z.
11105*.
226.11
-------
revenue requirements are determined by the economic premises option
(line 11, IECON), the operating and maintenance cost levelizing factor
(line 11, XLEVEL) used with the new economic premises, and the waste
disposal option (line 10, ISLUDG). The model provides four options for
specifying this profile. The input variable for these options is IOPSCH.
If IOPSCH = 1 the program uses the TVA-developed operating schedule
shown in Figure 3 which is based on the profile assumed in Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes (G. G. McGlamery
et al., 1975). If IOPSCH = 2 the operating schedule is based on historical
Federal Energy Regulatory Commission (FERC, previously FPC) data as
shown in Figure 4. If IOPSCH = 3 the user must input the operating
profile as shown below. If IOPSCH = 4 a levelized operating profile of
5500 hours per year is used (see Appendix D). A 30-year operating life
is assumed unless a year-by-year operating profile is provided by the
user. When the operating profile is specified by the user (IOPSCH = 3),
the IYROP variable on line 15 specifies the projected operating life in
years and cannot exceed 50. Beginning on line 16, the total number of
hours-per-year entries must be equal to the value of IYROP. The number
of entries per line must not exceed 10. Less than 10 entries are allowed
on the last line only, depending on the number of years required. An
example of using 25 years is shown below.
Line No. Input data
14 3 1 5 .8 1.0 3 .65 1 1 1.10 1982 297.9
15 25
16 5000 5000 6000 6000 7000 7000 7000 7000 7000 7000
17 7000 7000 7000 7000 7000 7000 7000 7000 6000 6000
18 6000 5000 5000 5000 4000
19 END
If levelized operating and maintenance costs under the new premises are
being used, a levelizing factor (line 11, XLEVEL) that corresponds to
the operating profile should be used.
Example output resulting from the Figure 3 operating profile
(IOPSCH = 1) is shown in Table 24. Table 25 illustrates the results of
the Figure 4 FERC data operating profile (IOPSCH = 2). Example output
resulting from a user-supplied operating profile (IOPSCH =3) is shown in
Table 26. The base case printout in Appendix D (p. D-24) shows the
results of specifying a levelized operating profile of 5,500 hours per
year.
57
-------
30
O 60
H
U
PM
<
U
w
o
w
40
I
I
I
0 10
20 30 40 50
BOILER AGE, YEARS
1 I
60
70
Figure 3. Operating profile assumed for
IOPSCH = 1 based on old TVA premises.
;,o 50+ ISA 65
\fe^
& f,a 1=H N\\\v s^\ x
S 40 \\\\ sv\v>
U v\\\v v\\v
< v\\s ^ ^\SJ"
5! v::;:Ss|
PJ Qn k\S SsS "s\^
^ :^:v:^S
W s\S v\Ss\\^
5 v:::;^:;:':
o &;:;v£:;;;;
0 10
92-1 8A
m
S^^\'1J\^
xSs \xs"i r\^.^
;: >:yx;S^
"; v \v " ^
v v \s^~ " \Ss\x
;\<\>; \\;> v v
i iiii|ii.
20 30
1^'
y;
1 '
40
A = AGE
I r.
:|:nq
;>vSi R 0
\^;:^y H H
. i r | . i i i | i i i i
50 60 70
BOILER AGE, YEARS
Figure A. Operating profile assumed for
IOPSCH = 2 based on historical Federal
Energy Regulatory Commission data.
58
-------
TABLE 24. EXAMPLE LIFETIME REVENUE REQUIREMENTS USING THE OLD TVA PREMISES OPERATING PROFILE
LIMESTONE SLURRY PROCESS -- BASISl 500
PROJECTED LIFETIME REVENUE REQUIREMENTS
SCRUBBING UNIT - 500 MW GENERATING UNIT/ 198* STARTUP
FIVE PROCESS PROFILE
TOTAL CAPITAL INVESTMENT! * 10*679000
CASE 010
ADJUSTED GROSS
SULFUR
REMOVED
YEARS AN'iUAL PTWER UNIT PD/iER UNIT 8Y
AFTER UPCRA- HEAT FUEL POLLUTION
POWER TIHN, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR MILLION BTU TONS COAL PROCESS,
START /KW /YEAK /YEAR TONS/YEAR
1 7000 33250000 1420900 38900
2 7'>00 3325UOOO 1*20900 38900
3 7000 33250000 1*20900 38900
4 7uOO 33250000 1*20900 3H900
5 7'iOO 33250000 1*20900 33900
f> 7COO 33250000 1*20900 38900
7 7POO 33250000 1*20900 38900
d 7000 33250000 1*20900 38900
9 7UOO 33250000 1*20900 3B900
lu 7.JOO 33250000 1*20900 3H900
11 5000 23750000 1015000 27800
12 5000 23750000 1015000 27800
13 S-'OO 23750000 1015000 27800
14 5000 23750000 1015000 27800
15 5000 2375UOOO 1115000 27600
16 3500 16625000 710500 19*00
17 3500 16625000 710500 19*00
18 3500 16625000 710500 10*00
19 3500 16625000 710500 19*00
20 3500 16625000 710500 1.9*00
21 1500 7125000 30*500 8300
22 1500 7125000 30*500 8300
23 1500 7125000 30*500 8300
2* 1500 7125000 30*500 «300
25 IbOO 7125000 30*500 8300
26 1500 7125000 30*500 8300
27 1500 7125000 30*500 8300
28 1500 7125000 30*500 8300
29 1500 7125000 30*500 S300
30 1500 7125000 304500 «300
TOT 127500 6T5625000 25881500 708000
LIFETIME AVERAGE INCREASE IN UNIT REVENUE REQUIREMENT
DOLLARS PER TON OF C3AL BURNED
MILLS PER KILOWATT-H3UR
CENTS PER MILLION STJ HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
KEVE-IUF REQUIREMENT DISCOUNTED AT 10.0X TO INITIAL YEAR
BYPRODUCT
RATE,
EQUIVALENT
TONS/VEAR
DRY
SLUDGE
2*4200
24*200
24*200
24*200
24*200
24*200
24*200
24*200
24*200
24*200
174*00
17*400
174*00
174*00
17**00
122100
122100
122100
122100
122100
52300
52300
52300
52300
52300
52300
52300
52300
52300
52300
4*47500
, DOLLARS
ANNUAL REVENUE
SLUDGE
FIXATION FEE
i/TUN
DRY
SLUDGE
0.0
0,0
o.o
0,0
0,0
0,0
u , 0
o.o
0.0
0.0
0,0
0,0
0,0
u.O
0,0
0,0
0,0
0.0
0,0
0,0
0,0
0,0
0.0
0,0
0.0
0,0
0.0
0.0
0,0
0,0
RETIREMENT
EXCLUDING
SLUDGE
FIXATION
COST,
I/YEAR
28564600
29355300
30193*00
31081700
32023300
33021400
34079700
35201100
36389800
37649900
33631600
3*726*00
35886900
37116700
38420500
3*069700
35190600
36378600
37638300
38973100
28898000
29708*00
3C567900
31*78600
32*43900
33*67500
3*552200
35702100
36921000
38212800
10215*5000
39,47
16.02
168.68
1442.86
311206100
LEVFLIZED INCREASE IN UNIT REVENUE REQUIREMENT EQUIVALENT TO DISCOUNTED REQUIREMENT OVER LIFE
DOLLARS PER TON OF CDAL BURNED
MILLS PER KILOWATT-HDUR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
UNIT CJSTS INFLATED AT 6,00* PER YEAR
27.9*
11.34
119.41
1021.02
TOTAL
ANNUAL
SLUDGE
FIXATION
COST.
»/YEAR
0
0
0
0
0
0
Q
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
o.o
0.0
0,0
0
Of POWER
0.0
0.0
0.0
0.0
NET ANNUAL
INCREASE
IN TOTAL
REVENUE
REQUIREMENT,
>
2856*600
29355300
30193*00
31081700
32023300
33021*00
3*079700
35201100
36389800
37649900
33631600
34726*00
35866900
37116700
38*20500
3*069700
35190600
36378600
37638300
38973100
28898000
29708*00
30567900
31*78600
32443900
33467500
3*552200
35702100
36921000
38212800
10215*5000
39.47
16.02
168,68
1442.86
311206100
UNIT
27.9*
11.34
119.41
1021.02
CUMULATIVE
NET INCREASE
IN TOTAL
REVENUE
REQUIREMENT,
$
28564600
57919900
88113300
119195000
15121(300
184239700
218319400
253520500
289910300
327560200
361191800
395918200
431805100
468921600
507342300
5*1412000
576602600
612981200
650619500
689592600
718490600
748199000
778766900
610245500
842689400
876156900
910709100
946411200
983332200
1021543000
-------
TABLE 25. EXA11PLE LIFETIME REVENUE REQUIREMENTS USING THE HISTORICAL FERC/FPC OPERATING PROFILE
LIMESTONE SLURRY PROCESS — BASIS: 500 MM SCRUBBING UNIT - 500 MW GENERATING UNIT. 198* STARTUP
PROJECTED LIFETIME REVENUE REQUIREMENTS - FPC/FERC PROFILE
TOTAL CAPITAL INVESTMENT: J 106672000
CASE 010
ADJUSTED GROSS
SULFUR
REMOVED
YEARS ANNUAL PO«ER UNIT POWER UNIT BY
AFTER OPERA- HtAT FUEL POLLUTION
POfF.R TION. REQUIREMENT. CONSUMPTION. CONTROL
UNIT KV.-HR MILLION ETU TONS COAL PROCESS.
START /Kh /YEAH /YEAH TONS/YEAH
1 451? 21433000 915500 35100
2 4643 22054300 942500 25800
3 4775 22681300 569300 26500
4 4906 23303500 995500 27300
5 5037 2392580(1 1022500 28000
t. 5169 24552800 1049300 2«700
7 5300 25175000 1075900 29400
« 5432 25802000 1102600 30200
9 5563 26424300 1129200 30900
10 5694 27046500 1155800 31600
11 5695 27051300 1156000 31600
12 5695 27051300 1156000 31600
13 5695 27051300 1156000 31600
14 5695 27051300 1156000 31600
15 5695 27051300 1156000 31600
16 5537 26300800 1124000 30800
17 5379 25550300 1091900 29900
IB 5??1 24799POO 1059600 29000
19 5064 24054000 1027500 28100
cO 4906 23303500 995900 27300
21 4748 22553000 963800 26400
22 4591 21807300 931900 25500
23 4433 21056800 899900 24600
24 4275 20306300 P67800 23800
25 411« 15560500 <335500 22900
2b 3960 18810000 803800 22000
27 3P02 18059500 771800 21100
2W 3645 17313800 739900 20300
29 3487 16563300 707800 19400
30 3329 15812POO 675800 18500
TOT 146001 693505700 29636800 811100
LIFETIME AVERAGE INCREASE IN UNIT REVENUE REQUIREMENT
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOKATT-hOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
REVENUE REQUIREMENT DISCOUNTED AT 10. OS TO INITIAL YEAR
BYPRODUCT
RATE.
ANNUAL REVENUE
SLUDGE
EQUIVALENT FIXATION FEE
TONS/YEAR
DRY
SLUDGE
157400
162000
166600
171200
175700
180300
184900
189500
194100
198700
198700
198700
198700
198700
198700
193200
187700
182100
176700
171200
165600
160200
134700
149100
143700
138200
132600
127200
121 700
116100
5093900
. DOLLARS
LEVELIZEO INCREASE IN LNIT REVENUE REQUIREMENT EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL RURNED
MILLS PER KILOnATT-HOUR
CENTS PER MILLION aiu HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
UNIT COSTS INFLATED AT e.OOS PER YEAR
S/TON
DRY
SLUDGE
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
REQUIREMENT
EXCLUDING
SLUDGE
FIXATION
COST,
S/YEAR
26703200
27612300
28590900
29640600
30767900
31981300
33281200
34679500
36177800
37785500
39114800
40520900
42011500
43591100
45265600
46394100
47547000
48723200
49926200
51143500
52377900
53631900
54890400
56155100
57428000
58690100
59941700
61184600
62393200
63566400
1351717400
45.61
18.52
194.91
1666.52
346396900
REQUIREMENT OVER LIFE
35.83
14.55
153.14
1309.63
TOTAL
ANNUAL
SLUDGE
FIXATION
COST,
i/YEAR
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
OF POWER
0.0
0.0
0.0
0.0
NET ANNUAL
INCREASE
IN TOTAL
REVENUE
REQUIREMENT,
t
26703200
27612300
28590900
29640600
30767900
31981300
33281200
34679500
36177800
37785500
39114800
40520900
42011500
43591100
45265600
46394100
47547000
48723200
49926200
51143500
52377900
53631900
54690400
56155100
57428000
58690100
59941700
61184600
62393200
63566400
1351717400
45.61
18.52
194.91
1666.52
346396900
UNIT
35.83
14.55
153.14
1309.63
CUMULATIVE
NET INCREASE
IN TOTAL
REVENUE
REQUIREMENT,
$
26703200
54315500
82906400
112547000
143314900
175296200
208577400
243256900
279434700
317220200
356335000
396855900
438867400
482458500
527724100
574118200
621665200
6703«8400
720314600
771458100
823836000
877467900
932358300
988513400
1045941400
1104631500
1164573200
1225757800
1288151000
1351717400
-------
TABLE 26. EXAMPLE LIFETIME REVENUE REQUIREMENTS USING A USER-SUPPLIED OPERATING PROFILE
LIMESTONE SLURRY PROCESS -- HASIS: 500 MW SCRUBBING UNIT - 500 Ml* GENERATING UNIT. 198* STARTUP
PROJECTED LIFETIME REVENUE REQUIREMENTS - USER INPUT SCHEDULE
CASE 013
TOTAL CAPITAL INVESTMENT:
108027000
SULFUR
REMOVED
YEARS ANNUAL POWER UM T POKER UNIT BY
AFTER OPFRA- HEAT FUEL POLLUTION
POWER TION. REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR MILLION fcTu TONS CCAL PROCESS,
START /Kh /YEAR /YEAH TONS/YEAH
1 5000 23750000 1015000 27800
1 5000 33750000 1015000 27800
3 6000 28500000 1217500 33300
4 6000 28500000 1217500 33300
5 7000 33250000 1420500 3U90U
6 7000 33250000 1420500 38900
7 7000 33250000 1420500 3890U
b 7000 33250000 1420500 38900
9 7000 33250000 1420500 38900
10 7000 33250000 1420500 3B900
11 7000 33350000 1420900 38900
12 7000 33250000 14^:0500 38900
U 7000 33250000 1420900 38900
14 7000 33250000 1420900 38900
15 7000 33250000 1420900 38900
16 7000 33250000 1420900 3890U
17 7000 33250001 1420900 38900
18 7000 33250000 1420500 38900
19 6000 28500000 1217500 33300
20 6000 285000CO 1217500 33300
21 6000 28500000 1217500 33300
22 5000 23750000 1015000 27800
23 5000 23750000 1015000 27800
24 5000 23750000 1015000 27800
25 4000 19000000 812000 22200
TUT 157000 745750000 31809100 872300
LIFETIME AVFHAfaE INCREASE IN UNIT REVENUE REQUIREMENT
DOLLARS PER TON OE COAL HURNED
MILLS PER KILOKATT-hOUH
CENTS PER BILLION BTU HEAT INPUT
OOLL'RS PER TON OF SULFUR REMOVED
REVENUF REQUIREMENT DISCOUNTED AT 10.0* TO INITIAL YEAR
ADJUSTED GROSS
BYPRODUCT ANNUAL REVENUE
RATE, SLUDGE REQUIREMENT TOTAL
EQUIVALENT FIXATION FEE
TONS/YEAR
DRY
SLUDGE
174400
174400
209300
209300
244200
244200
244200
244200
244200
244200
244300
244200
244200
244200
244200
244200
244200
244200
209300
209300
209300
1 /4400
1 /4400
174400
139600
5476900
, DOLLARS
LEVELIZED INCREASE IN LNIT REVENUE REQUIREMENT EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILO»ATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PFR TON OF SULFUR REMOVED
UNIT COSTS INFLATED AT 6.00J PER YEAR
I/TON
DRY
SLUDGE
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
EXCLUDING
SLUDGE
F IXATION
COST,
S/YEAR
27379300
28069400
30678500
31566400
34548200
35668300
36855700
38114100
39448200
40862300
42361300
43950000
45634400
47419600
49312200
51318100
53444200
55697900
53473400
55729000
58120000
54973500
57319100
59S05400
55387400
1127135900
REQUIREMENT
35.37
14.36
151.14
1292.14
350801100
OVFR LIFE
30.19
12.26
129.03
1103.15
ANNUAL
SLUDGE
FIXATION
COST,
5/YEAR
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
OF POWER
0.0
0.0
0.0
0.0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
IN TOTAL
REVENUE
REQUIREMENT,
t
27379300
28069400
30678500
31566400
34548200
35668300
36855700
38114100
39448200
40862300
42361300
43950000
45634400
47419600
49312200
51318100
53444200
55697900
53473400
55729000
58120000
54973500
57319100
59805400
55387400
1127135900
35.37
14.36
151.14
1292.14
350801100
UNIT
30.19
12.26
129.03
1103.15
IN TOTAL
REVENUE
REQUIREMENT,
t
27379300
55448700
86127200
117693600
152241800
187910100
224765800
262879900
302328100
343190400
385551700
429501700
475136100
522555700
571867900
623186000
676630200
732328100
785801500
841530500
899650500
954624000
1011943100
1071748500
1127135900
-------
USAGE OF THE MODEL
As previously discussed, a copy of the model can be made available
for independent user execution; or TVA, under an information-exchange
agreement with EPA, can make specific runs of the model based on user-
supplied input data. This section is provided for potential users who
wish to obtain the model for independent use.
The model was developed for, and is executed on, the TVA in-house
IBM 370 compatible computer system. The current model consists of two
FORTRAN programs that are compiled using either the IBM Gl or H extended
compiler. The first program, which calculates investment costs, is
relatively large; it contains over 10,000 lines of source code. The
second program, which calculates revenue requirements, contains about
2,000 lines.
Core storage requirements for the first program are about 300,000
bytes; the use of overlays can reduce this requirement to about 150,000
bytes. The second program executes within 150,000 bytes of core storage
with no overlays. In addition to the core storage required for program
execution, temporary online storage (disk) is also required for inter-
mediate files and the transfer of data between the two programs. The
only input data required for model execution are the user input data;
all other data for default assumptions and option-related calculations
are assigned the necessary values internally within the program. Temporary
online storage requirements depend on the number of cases run but typically
do not exceed 200,000 bytes.
The model is executed in both interactive and batch modes. The
input data can be provided in three different ways depending on the mode
of execution. For batch execution (typically remote batch) the input
data variables are punched on cards and inserted in a model execution
run deck. The second method of providing data applies to interactive
model execution. Input is solicited at the terminal during actual model
execution and the user must respond with the appropriate values. The
third method is used for both interactive and batch execution. A data
file is created interactively (typically using a text editor); all
variable values (including the options selected) are examined and
corrected if necessary; then the model is executed (either interactively
or a batch run is submitted from the interactive terminal) and the input
is processed as a standard data file.
The third method of providing input data has been found to be
preferable in most cases. When separate but similar model runs are
required, the data file containing the input is copied to a second file,
62
-------
variables and options are modified as necessary, and a second model run
is submitted. This reduces both input preparation time and the number
of input data errors because only the variables and options that differ
from a previous run must be modified.
The job control language (JCL) required to execute the model in
batch mode is stored in a catalogued procedure file. An example procedure
file is shown in Table 27. The catalogued procedure uses a system
utility program, IEBGENER, which can be replaced if necessary by a user
program to copy from input card data to disk storage and from disk
storage to an output print file. The overall procedure consists of four
steps to (1) copy the input data to a temporary online storage file
(disk), (2) copy the input data to an output print file, (3) execute the
first program of the model, and (4) execute the second program. The
programs are executed from load modules to avoid recompiling each time
they are executed.
The remaining JCL required to execute the model in batch mode is
shown in Table 28. If the input data have been prepared on cards, a
card deck similar to example one in Table 28 would be submitted with the
data cards following the //LOAD.DATA DD * ... card. In example two, the
catalogued procedure (Table 27) is executed and the required input is
read from a previously created data file. The JCL examples shown in
Tables 27 and 28 generally apply whether the job is submitted inter-
actively or with a card deck.
Table 29 shows two example interactive procedures for model execution.
Example 1 in Table 29 shows an example procedure for directly entering
the data during model execution. Example 2 shows a procedure for inter-
active execution using a previously created data file.
The amount of computer time required for model execution is a
function of the number of cases of input data and the particular computer
system. On the TVA system (Amdahl V8 with JES3) the average CPU time
required per case is about .5 second but some cases have exceeded 2 seconds.
The model is usually distributed on magnetic tape for independent
usage. A fairly wide range of tape format options is available but
typically the tape is unlabeled, the density is 1600, the block size is
4,000 characters (50 records, 80 characters per record), and the tape
contains two files, one for each program.
63
-------
TABLE 27. EXAMPLE PROCEDURE FOR EXECUTING THE MODEL IN BATCH MODE
//SHAWNEE
//LOAD
//SYSPRINT
//SYSIN
//SYSUT1
//SYSUT2
//
//LIST
//SYSPRINT
//SYSIN
//SYSUT1
//SYSUT2
//INVEST
//STEPLIB
//FT02F001
//
//FT03F001
//FT05F001
//FT06F001
//REVENUE
//STEPLIB
//FT02F001
//FT06F001
PROC
EXEC
DD
DD
DD
DD
EXEC
DD
DD
DD
DD
EXEC
DD
DD
DD
DD
DD
EXEC
DD
DD
DD
PRTFMS=A
PGM=IEBGENER
SYSOUT=A
DUMMY
DDNAME=DATA
UNIT=SYSCR, SPACE=(TRK, (1,1) ,RLSE) ,DISP= (NEW, PASS) ,
DCB=(RECFM=FB,LRECL=80,BLKSIZE=400)
PGM=IEBGENER
SYSOUT=A
DUMMY
DSN=* . LOAD . SYSUT2 ,DISP= (OLD , PASS)
SYSOUT=&PRTFMS , DCB= (RECFM=F , LRECL=80 , BLKSIZE=80 )
PGM=INV,REGION=400
DSN=CHM. SHAWNEE . LOAD , DISP=SHR
UNIT=SYSCR,SPACE=(TRK, (1,1) ,RLSE) ,DISP= (NEW, PASS) ,
DCB=(LRECL=404,BLKSIZE=408,RECFM=VBS)
SYSOUT=A
DSN=*. LOAD. SYSUT2,DISP= (OLD, DELETE, DELETE)
SYSOUT=&PRTFMS
PGM=REV,REGION=150K,COND=(COND=(0,LT, INVEST)
DSN=CHM. SHAWNEE . LOAD , DISP=SHR
DSN=*. INVEST. FT02F001,DISP=(OLD, DELETE, DELETE)
SYSOUT=&PRTFMS
00000010
00000020
00000030
00000040
00000050
00000060
00000070
00000080
00000090
00000100
00000110
00000120
00000130
00000140
00000150
00000160
00000170
00000180
00000190
00000200
00000210
00000220
00000230
TABLE 28. EXAMPLE BATCH RUN TO EXECUTE THE MODEL USING A PROCEDURE FILE
(Example 1)
//TXSHAWNE JOB 123456,PRGMER.R501CEBM.2513,MSGLEVEL=1,CLASS=K, 00000010
// NOTIFY=CHM 00000020
/*MAIN ORG=RGROUP03 00000030
//PROCLIB DD DSN=CHM.PROCLIB,DISP=SHR 00000040
//SHAWNEE EXEC SHAWNEE,PRTFMS=A 00000050
//LOAD.DATA DD * (INPUT DATA CARDS FOLLOW THIS CARD) 00000060
// 00000070
(Example 2)
//TXSHAWNE JOB 123456,PRGMER.R501CEBM.2513,MSGLEVEL=1,CLASS=K, 00000010
// NOTIFY=CHM 00000020
/*MAIN ORG=RGROUP03 00000030
//PROCLIB DD DSN=CHM.PROCLIB,DISP=SHR 00000040
//SHAWNEE EXEC SHAWNEE,PRTFMS=A 00000050
//LOAD.DATA DD DISP=SHR,DSN=CHM.PART2.DATA 00000060
// 00000070
64
-------
TABLE 29. SAMPLE PROCEDURE FOR EXECUTING THE MODEL INTERACTIVELY
(Example 1)
00010 FREEALL
00020 TERM LINESIZE(132)
00030 FREE FILE (FT02F001,FT03F001,FT05F001,FT06F001)
00040 ALLOC FI(FT02F001) NEW BLOCK(13030) SPACE(10,5)
00050 ALLOC FI(FT03F001) DA(*)
00060 ALLOC FI(FT05F001) DA(*)
00070 ALLOC FI(FT06F001) DA(*)
00080 CALL 'CHM.SHAWNEE.LOAD(INV)'
00090 CALL 'CHM.SHAWNEE.LOAD(REV)1
00100 FREEALL
(Example 2)
00010 FREEALL
00020 TERM LINESIZE(132)
00030 FREE DA('CHM.PART2.DATA')
00040 FREE FILE(FT02F001,FT03F001,FT05F001,FT06F001)
00050 ALLOC FI(FT02F001) NEW BLOCK(13030) SPACE(10,5)
00060 ALLOC FI(FT03F001) DA(*)
00070 ALLOC FI(FT05F001) DA('CHM.PART2.DATA')
00080 ALLOC FI(FT06F001) DA(*)
00090 CALL 'CHM.SHAWNEE.LOAD(INV)'
00100 CALL 'CHM.SHAWNEE.LOAD(REV)'
00110 FREEALL
65
-------
REFERENCES
Argonne, 1979. The model that sizes and costs particulate removal
devices was provided by Paul S. Farber of Argonne National Laboratory,
Argonne, Illinois.
Federal Register, 1979. New Stationary Sources Performance Standards;
Electric Utility Steam Generating Units. Federal Register, Vol. 44,
No. 113, pp. 33580-33624.
McGlamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
L. J. Henson, S. V. Tomlinson, and J. F. Young, 1975. Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes, Bulletin Y-90,
Tennessee Valley Authority, Muscle Shoals, Alabama; EPA-600/2-75-006,
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina, 1975.
McGlamery, G. G., W. E. O'Brien, C. D. Stephenson, and J. D. Veitch,
1980. FGD Economics in 1980. Preprint, paper presented at the EPA
Symposium on Flue Gas Desulfurization, Houston, Texas, October 27-31, 1980.
Torstrick, R. L., 1976. Shawnee Limestone-Lime Scrubbing Process Compu-
terized Design Cost Estimates Program: Summary Description Report.
Prepared for presentation at Industry Briefing Conference, Raleigh,
North Carolina, October 19-21, 1976.
Torstrick, R. L., L. J. Henson, and S. V. Tomlinson, 1978. Economic
Evaluation Techniques, Results, and Computer Modeling for Flue Gas
Desulfurization. In: Proceedings, Symposium on Flue Gas Desulfurization,
Hollywood, Florida, November 1977 (Vol. 1), F. A. Ayer, ed., EPA-
600/7-78-058B, U.S. Environmental Protection Agency, Washington, D.C.,
1978, pp. 118-168.
Stephenson, C. D., and R. L. Torstrick, 1978. Current Status of Develop-
ment of the Shawnee Lime-Limestone Computer Program. Prepared for
presentation at Industry Briefing Conference, Raleigh, North Carolina,
August 29, 1978.
Stephenson, C. D., and R. L. Torstrick, 1979. The Shawnee Lime-Limestone
Computer Program. Prepared for presentation at Industry Briefing
Conference, Raleigh, North Carolina, December 5, 1979.
Stephenson, C. D., and R. L. Torstrick, 1979. Shawnee Lime/Limestone
Scrubbing Computerized Design/Cost-estimate Model Users Manual.
66
-------
Tomlinson, S. V., F. M. Kennedy, F. A. Sudhoff, and R. L. Torstrick,
1979. Definitive SOX Control Process Evaluations: Limestone, Double
Alkali, and Citrate FGD Processes. TVA ECDP B-4, Tennessee Valley
Authority, Muscle Shoals, Alabama; EPA-600/7-79-177, U.S. Environmental
Protection Agency, Washington, D.C.
67
-------
APPENDIX A
PROCESS FLOWSHEETS AND LAYOUTS
A-l
-------
TCA SCRUBBER AREA
>
N>
STEAM FROM
STEAM PLANT
m"
//////////////////.
w
0 0 0 0 0
0°0 0 0°0
O ° O O
O O O o O O
D°0 °°0°
000 0°0
ABSORBER
,
13
MAKEUP
WATER
CONDENSATE
TO STEAM PLANT
\ /
Dl
WEIGH i
BELTS [ | ^
GYRATO
CRUSHERS
KEUP
TER
'1 n
1 9
16
i'
EFHbULDNT
TANK
-£
LIQUOR RETURN
.TO WASTE DISPOSAL
Figure A-l. Limestone scrubbing process utilizing TCA absorber.
-------
BOILER
>
(ECONOMIZER1
' ELECTROSTATIC
PRECIPITATOR
(OR BAGHOUSE) (PLENUM
COMBUSTION
AIR
ASH TO
DISPOSAL
SCRUBBER AREA
SPRAY TOWER
STEAM FROM
STEAM PLANT
- LIQUOR RETURN
- TO WASTE DISPOSAL
WEIGH i
BELTS II *
GYRATORY^*/
CRUSHERS
MILLS
PRODUCT
TANK ,
SLURRY
FEED
TANK
Figure A-2. Limestone scrubbing process utilizing a spray tower.
-------
\^
BOILER
|- E
[ECONOMIZER) p
-^ i'
AIR HEATER
1- ^
COMBUSTION
_ECTROSTAT
RECIPITATO
vw
AIR
ASH TO
DISPOSAL
POND SUPERNATE
RETURN
TO WASTE
DISPOSAL POND
Figure A-3. Limestone scrubbing process utilizing a venturi - spray tower.
-------
T
Ul
ENCLOSED CONVEYOR
SLURRY FEED
TO ABSORBER
ELEVATOR NO. I
Figure A-4. Lime handling and preparation area for lime scrubbing option.
-------
STACK PLENUM
PRESATURATOR
PUMPS
TO SPARE FROM SPARE
SCRUBBING TRAIN SCRUBBING TRAI
PLAN
(SEE NOTES)
NOTES
I EMERGENCY BYPASS ON EACH SIDE
2 SPARE SCRUBBING TRAIN ON ONE SIDE ONLY
Figure A-5. Plan and elevation for TCA.
A-6
-------
ELECTROSTATIC
PRECIPITATORS
WASTE DISPOSAL AREA
FEED TANK
EFFLUENT
HOLD TANK
PRESATURATOR A '
r PUMPS -
ABSORBER
, , SYSTEM
WASTE ' ° FAN
- PRESATURATOR
' '"PUMPS '
ABSORBER
SYSTEM
I D FAN
POWER PLANT
I D FAN
FROM
T0 SPARE SCRUBBING
SPARE SCRUBBING TRAIN
TRAIN
EXPANSION JOINT
(TYP WHERE SHOWN)
INDIRECT STEAM
REHEATER
ENTRAINMENT
SEPARATOR
ABSORBER
(SPRAY TOWER)
PRESATURATOR
DAMPER
(TYP WHERE SHOWN
ELECTROSTATIC
PRECIPITATOR ~l
POWER PLANT
I D FAN
EFFLUENTJ ABSORBER
HOLD TANK SYSTEM
PRESATURATOR^ \ SLURRY l D FAN
PUMP ^RECIRCULATION
PUMP
ELEVATION
I EMERGENCY BYPASS ON EACH SIDE
2 SPARE SCRUBBING TRAIN ON ONE SIDE ONLY
Figure A-6. Plan and elevation for spray tower.
A-7
-------
V
>
^
S*
<&
e
V'
A'
-------
SETTLING POND
Onsite ponding (Option 1)
Thickener ponding (Option 2)
Figure A-8. Waste disposal options 1 and 2.
-------
ABSORBED
SLURRY
BLEED
ABSORBER
BLEED
RECEIVING
>
I
ABSORBER
SLURRY
BLEED
ABSORBE
BLEED
RECEIVING
Thickener - Fixation (Option 3)
Thickener - Filter - Fixation (Option 4)
Figure A-9. Waste disposal options 3 and 4.
-------
COAL _J
SCRUBBER AREA STEAM FROM
SPRAY TOWER STEAM PLANT
FORCED OXIDATION i'°
— , e JREHEATER[ S) — *\
BOILER T ~ J S4 !
i— - [ T 1 D FAN
1" "~ ~1 j CONDENSATE 9
ECONOMIZER i / k MAKEUP T0 STEAM PI-ANT
ELECTROSTATIC
L 3 5 PRECIPITATOR
-•) ,-i -1 , (OR BAGHOUSE) 1PLENUM »i
|_AIR HEATER ' | ' 1 '
COMBUSTION \/Wl» «N '?
1
ASH TO ^
DISPOSAL LJ^^-
L
i//m//mnm//n/!>.
* * A A
S02
ABSORBER
ii WATER
• i
1
* »
• — i
[PLENUM
S.
_i^J
OXIDATION
AND
RECIRCULATION
TANK
— LIQUOR RETURN
« TO WASTE DISPOSAL
LIMESTONE\ * ' WEISH i
PILE \ , _ BELTS 1" " ¥ „
*-« ^^ \ GYRATORY "^' BALL r'8 - n t
O' CRUSHERS \ MILLS/ , U '
ly \ / - ~|
MILLS
PRODUCT
TANK
; "i n
SLURRY
FEED
TANK
Figure A-10. Single tank oxidation loop.
-------
LIQUOR RETURN
TO WASTE DISPOSAL
Figure A--11. Double tank oxidation loop.
-------
D OQwASTE DISPOSAL
FEED PUMPS
ELEVATION
NOTES
I EMERGENCY BYPASS ON EACH SIDE
2. SPARE SCRUBBING TRAIN ON ONE SIDE ONLY
Figure A-12. Plan and elevation for TCA utilizing forced-draft fans.
A-13
-------
ELECTROSTATIC
PRECIPITATORS
WASTE DISPOSAL AREA
FEED TANK "7
EFFLUENT
HOLD TANK
PRESATURATOR "
PUMPS , 7
, ABSORBER
SYSTEM
I D FAN T~~**-~.
FROM J
T0 SPARE SCRUBBING —» \
SPARE SCRUBBING TRAIN [ ^^
^_
COMBINED PARTIAL
AND
EMERGENCY BYPASS
PLAN
(SPRAY TOWER)
PRESATURATOR
DAMPER
(TYP WHERE SHOWN
ELEVATION
I EMERGENCY BYPASS ON EACH SIDE
2 SPARE SCRUBBING TRAIN ON ONE SIDE ONLY
Figure A-13. Plan and elevation for partial scrubbing with bypass duct,
A-14
-------
APPENDIX B
DESIGN AND ECONOMIC PREMISES
B-l
-------
INTRODUCTION
In December 1979, new design and economic premises for comparative
economic evaluations of emission control processes were adopted for
emission control studies done by TVA for EPA. These premises were
expanded and amplified in March 1980 and applicable portions have been
incorporated into the Shawnee model. The economic premises can be
selected by the economic premises option, IECON, on line 11 of the model
input data. Separate options were established for the design premises
to allow them to be selected independently. The old premises used for
earlier versions of the model (Tomlinson et al., 1979, and Stephenson
and Torstrick, 1979) can still be selected if required. The referenced
publications provide complete details on the old economic premises so
only a brief overview is presented here.
Separate input options are used to provide for differences between
the old and new premises in the calculation of total capital investment
except for working capital and contingency. Under the old premises,
working capital is calculated as three weeks of raw material costs,
seven weeks of direct costs, and seven weeks of overhead costs. Con-
tingency is calculated as a percentage of direct investment. Under the
new premises working capital is calculated as one month of raw material
costs, one and one-half months of conversion costs, one and one-half
months of plant and administrative overhead costs, and three percent of
total direct investment to cover spare parts, accounts receivable, and
monies on deposit for taxes and accounts payable. Contingency under the
new premises is calculated as a percentage of the sum of direct investment,
engineering design and supervision, architectural and engineering con-
tractor costs, construction field expenses, and contractor fees. The
remaining differences between the old and new premises in the calculation
of capital investment are controlled by separate input options and
variables. They include separate indirect investment factors for pond
construction, sales tax and freight on materials, overtime labor, emergency
bypass, inflation, royalties, and a constant lifetime operating profile.
There are also differences between the old and new premises in the
calculation of both indirect costs for annual revenue requirements and
in lifetime revenue requirements. Under the old premises, indirect
costs are based on depreciation, cost of capital and taxes as a percentage
of undepreciated investment, insurance and interim replacements as a
percentage of total capital investment, plant overhead as a percentage
of conversion costs less utilities, and administrative, research, and
service overheads as a percentage of operating labor and supervision.
Under the new premises, indirect costs are based on plant and administrative
overheads as a percentage of conversion costs less utilities, and levelized
B-3
-------
capital charges as a percentage of total capital investment. For processes
that result in a salable byproduct, marketing costs are applied as a per-
centage of byproduct credit under the new premises.
Lifetime revenue requirements under the old premises are based on
annual revenue requirements calculated for each individual year of the
projected plant life. A lifetime revenue requirements report is printed
showing year-by-year projections. Under the new premises, a levelized
operating and maintenance factor is applied to first-year operating and
maintenance instead of calculating year-by-year requirements. However,
for comparative analysis and flexibility, if a levelizing factor of zero
is used in conjunction with the new premises, a year-by-year revenue
requirements report based on the lifetime operating profile that is
specified can still be generated.
Example output from the model illustrating the differences between
the old and new premises are shown in the model description section and
in the base case printout in Appendix D. Additional comparisons between
the old and new premises that illustrate the individual effects of the
changes are described in a paper presented at the 1980 EPA FGD symposium
(McGlamery et al., 1980). The descriptions of the individual input
options in the model description section provide additional information.
However, the references cited previously for the old premises and the
remainder of this appendix for the new premises must be used for compre-
hensive details and background information. The same cost indexes and
projections are used for both the old and new premises. It should be
noted that the new premises that follow contain specifications beyond
the scope of the model.
5-4
-------
DESIGN AND ECONOMIC PREMISES EFFECTIVE DECEMBER 1979
INTRODUCTION
These premises provide criteria for comparative economic evaluations
of emission control processes for electric utility coal-fired power
plants. The design premises define representative coal and power unit
conditions and standard design practices for emission control systems.
The economic premises are based on regulated utility economics. They
prescribe procedures for determining capital investment and annual
revenue requirements. The premises are directly applicable to economic
evaluations of coal cleaning, flue gas desulfurization (FGD), nitrogen
oxides (NOX) emission control, waste disposal, and particulate matter
emission control.
The economic evaluations are always based on a conceptual design
developed from the design premises and engineering data such as flow
diagrams, material balances, and equipment costs. Depending on the
specified degree of accuracy of the cost estimate, some costs are either
scaled or developed from detailed design and operating data.
Normally a base-case new 500-MW power unit burning 3.5% sulfur, 16%
ash bituminous coal, and complying with 1979 new source performance
standards (NSPS) (1) is used as the basis of comparison. Case variations
are developed as necessary to illustrate their effects on the economics
of the processes evaluated. For FGD evaluations a limestone scrubbing
process using a spray tower, forced oxidation, and gypsum landfill
disposal serves as the standard of comparison.
The current premises are based on 1982 costs for capital investment
and 1984 costs for annual revenue requirements. These and other premise
criteria are updated as necessary. Established criteria are not usually
revised on a piecemeal basis, however, as this would complicate their
use and reduce the comparability and applicability of evaluations made
over a period of time. All necessary premise changes are made at one
time, usually every one to three years.
DESIGN PREMISES
Coal Premises
The premise coals consist of four eastern bituminous coals containing
5.0%, 3.5%, 2.0%, and 0.7% sulfur; a 0.7% sulfur western bituminous
coal; a 0.7% sulfur western subbituminous coal; and a 0.9% sulfur North
B-5
-------
Dakota lignite. They are based on analyses of U.S. steam coals repre-
sentative of the types in current use (2,3). The analysis data for each
of these coals are summarized in Table B-l and a fly ash analysis for
each coal is shown in Table B-2.
TABLE B-2. FLY ASH COMPOSITIONS
Component
Si02
A1203
Ti02
Fe2°3
CaO
MgO
Na20
K20
so3
P2°5
Other
Bituminous
fly ash,
wt %
50.8
20.6
2.5
16.9
2.0
1.0
0.4
2.6
2.4
-
0.8
Subbituminous
fly ash,
wt %
39.7
21.5
1.1
7.4
20.0
4.7
1.7
0.5
2.3
1.0
0.1
Lignite
fly ash,
wt %
23.0
11.5
0.5
8.6
21.6
6.0
5.9
0.5
19.2
0.4
2.8
Total 100.0 100.0 100.0
As-fired coal refers to the coal entering the coal-cleaning plant
or power plant. This coal is supplied in a 3- inch top size after large
rocks and trash have been removed from the run-of-mine coal. Broken
coal is assumed to have the particle size distributions represented by
the Bennett form of the Rosin and Rammler equation,
R=
which can be plotted on special graph paper devised by the U.S. Bureau
of Mines (4) as shown in Figure B-l. In the equation,
x = particle diameter or width of screen aperture in millimeters. It
is the abscissa in Figure B-l.
x = a size constant, in millimeters, that is specific to each distri-
bution line of particle size. In Figure B-l, it is the value of
x when R = 36.79%; in turn R = 36.79% when x = x in the Rosin and
Rammler equation.
n = a size distribution constant. In Figure B-l, it is the arith-
metical slope of a distribution line. Parallel distribution
lines have the same value of n.
B-6
-------
TABLE B-l. COMPOSITION OF PREMISE COALS
(As-Fired Basis)
Sulfur
Coal
Eastern bituminous, 5.0% S
Eastern bituminous, 3.5% S
Eastern bituminous, 2.0% S
Eastern bituminous, 0.7% S
Western bituminous, 0.7% S
Western subbituminous, 0.7% S
(Powder River Basin)
North Dakota lignite, 0.9% S
Total,
%
4.80
3.36
1.92
0.67
0.59
0.48
0.57
Pyritic ,
%
3.
2.
1.
0.
0.
0.
0.
17
21
25
44
20
16
19
Sulfatic,
%
0.05
0.05
0.04
0.01
0.01
0.01
0.01
Organic ,
%
1.58
1.10
0.63
0.22
0.38
0.31
0.37
(Moisture-Free
Eastern bituminous, 5.0% S
Eastern bituminous, 3.5% S
Eastern bituminous, 2.0% S
Eastern bituminous, 0.7% S
Western bituminous, 0.7% S
Western subbituminous, 0.7% S
(Powder River Basin)
North Dakota lignite, 0.9% S
5.00
3.50
2.00
0.70
0.70
0.68
0.89
3.
2.
1.
0.
0.
0.
0.
30
30
31
46
24
23
30
0.05
0.05
0.04
0.01
0.01
0.01
0.01
1.65
1.15
0.65
0.23
0.45
0.44
0.58
Ash, Moisture,
15
15
15
15
9
6
7
% %
.10 4.0
.14 4.0
.08 4.0
.13 4.0
.71 16.0
.30 29.3
.22 36.3
Heat
content, C,
Btu/lb %
11,700 65.
11,700 66.
11,700 67.
11,700 68.
9,700 57.
8,200 49.
6,600 40.
Ultimate analysis
2
7
8
8
0
0
1
H,
%
4.0
3.8
3.7
3.6
3.9
3.5
2.8
o,
**/
5.5
5.6
6.0
6.3
11.5
10.7
12.4
N,
%
1.3
1.3
1.4
1.4
1.2
0.7
0.6
Cl,
%
0.1
0.1
0.1
0.1
0.1
0.02
0.01
Basis)
L5
15
15
15
11
8
11
.7
.7
.7
. 7
.6
.9
.3
67.
69.
70.
71.
67.
69.
63.
9
5
6
7
9
3
0
4.2
4.0
3.9
3.8
4.6
5.0
4.4
5.7
5.8
6.3
6.6
13.7
15.1
19.5
1.4
1.4
1.4
1.4
1.4
1.0
0.9
0.1
0.1
0.1
0.1
0.1
0.02
0.01
-------
I.MdnMlnuLnLlJ.J.MUJJJ
SCREEN OPENING
I
00
*00 325 270 100 140 100 80 60 M 40 30 10 18 16 14 II 10 8 J. t>
US STANDARD SIEVE DESIGNATION
II! ! ' I : ' ! i i I I i ' I I i
400 321 in XO 150 100 BO 60 48 35 28 20 16 H 1? 10 9 £ 6
TYLER SIEVE DESIGNATION
5 I ! I != I
SCREEN OPENING INCHES
GRAPHICAL FORM FOR REPRESENTING DISTRIBUTION OF SIZES OF BROKEN COAL
Figure B-l. Rosin-Rammler plots of premise coal sizes.
-------
e = the base of the natural logarithm.
R = the weight percentage of coal retained on a screen whose aperture
is x. R expresses cumulative oversize and is the ordinate in
Figure B-l.
For all distribution lines in Figure B-l, the value of n is 0.8840.
Values of x for selected size distributions are given below.
Actual aperture size
Nominal
top sizes
3 in.
2 in.
1-1/2 in.
3/4 in.
3/8 in.
3 mesh
14 mesh
28 mesh
(Tyler /
in.
2.970
2.100
1.485
0.742
0.371
0.093
0.046
0.023
2 Series)
mm
75.43
53.34
37.71
18.86
9.429
2.357
1.179
0.589
x
mm
13.40
9.478
6.702
3.351
1.676
0.4189
0.2094
0.1047
Power Plant
The power plant site is assumed to be in the north-central region
(Illinois, Indiana, Ohio, Michigan, Kentucky, and Wisconsin). The
location represents an area in which coal-fired power plants burning
coals of diverse type and source are situated (5,6). The design is
based on standard design practices (7,8) and current trends in utility
boiler construction (9,10). The base-case power unit is a new, single
500-MW, balanced-draft, horizontally fired, dry-bottom boiler burning
pulverized coal. The steam pressure is 2,400 psi. The superheat and
reheat temperatures are 1,000°F.
Power unit size case variations consist of similar 200-MW and
1,000-MW units. For new units the systems being evaluated are assumed
to be installed during construction of the power plant. New units are
assumed to have a 30-year life and to operate at full load for 5,500
hours a year. For case variations, identical existing units with 20
years of remaining life at 5,500 hours/year of full-load operation are
used. Heat rates are based on coal type, unit size, and unit age.
Power plant heat rates are shown in Table B-3. To provide for equitable
comparisons, the power units are not derated for energy consumption by
the systems evaluated. Instead the energy requirements are charged as
independently purchased commodities. Normally cost estimates are based
on a single power unit independent of other units at the site. In cases
in which a plant-wide process or system is evaluated, a plant capacity
of 2,000 MW is used.
B-9
-------
TABLE B-3. POWER UNIT REMAINING LIFE, OPERATING TIME, AND HEAT RATE
New
Power unit size, MW:
Remaining life, years
Full load, hr/yr
Heat rate, Btu/kWh
Bituminous coal
Subbituminous coal
Lignite
200
5,
9,
10,
11,
30
500
700
700
200
500
5,
9,
10,
11,
30
500
500
500
000
1,
5,
9,
10,
10,
000
30
500
200
200
700
200
5,
9,
11,
11,
20
500
900
000
400
Existing
500
5,
9,
10,
11,
20
500
700
700
200
1,000
20
5,500
9,500
10,500
11,000
Flue Gas Compositions
Flue gas compositions are based on combustion of pulverized coal
assuming a total air rate equivalent to 139% of the stoichiometric
requirement (defined as air for combustion of carbon, hydrogen, and
sulfur). This includes 20% excess air to the boiler and 19% additional
air leakage to the flue gas in the air heater. It is assumed that 80%
of the ash present in all coals is emitted as fly ash. Sulfur emitted
as SOX is dependent on the coal type; 92% of the sulfur in all eastern
coals and 85% of the sulfur in all western coals and lignite is emitted
as SOX. The remaining sulfur is removed in the bottom ash and fly ash.
No loss of sulfur in the pulverizers is assumed. Three percent of the
sulfur emitted as SOX is 803 and the remainder is S02-
A flow diagram around the boiler is shown in Figure B-2 and detailed
boiler material balances and flue gas composition summaries for stream 8,
for each premise coal, are shown in Tables B-4 through B-17. The streams
shown in the material balances have excess significant digits for cases
in which higher accuracy is needed. All streams balance to a net of +10
Ib/hr. These numbers are not to be published without rounding to four
significant digits, no more - no less.
Environmental Regulations
Emissions from new coal-fired utility plants are regulated by the
new source performance standards, which are issued under authority of
Section 111 of the Clean Air Act as amended in 1970 and 1977. This
section requires the Environmental Protection Agency (EPA) to set Federal
emission limitations which reflect the degree of control that can be
achieved by using the best available control technology (BACT). On
December 23, 1971, EPA issued NSPS to limit emissions of S02, NOX, and
particulate matter from utility power plants (11). In 1979 EPA chose
to revise the NSPS (1) which are shown in Table B-18. The controlled
outlet S02 emission and S02 removal efficiencies for premise coals are
shown in Figure B-3 and tabulated in Table B-19.
B-10
-------
TABLE B-4. BOILER MATERIAL BALANCE
EASTERN BITUMINOUS COAL, 5% SULFUR
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sftj/min @ 6Qop
Temperature, °F
N£ (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
405,983
(264,701)
(16,239)
(22,329)
(5,278)
(406)
(19,487)
16,239
61,303
2
Total air
to air heater
5,047,807
1,115,166
80
3,829,456
1,153,571
64,799
3
Combustion
air to
boiler
4,357,819
962,733
3,306,006
995,888
55,925
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
303 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
12,572
12.572
5
Gas to
economizer
4,75)^230
999,502
3,310,415
164,941
969,982
34, 748
1,343
1,766
142
418
217,184
50,291
6
Gas to air
heater
4,751,230
999,502
3,310,415
164,941
969,982
34,748
1,343
1,766
142
418
217,184
50,291
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
503 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
7
Air
inleakage
689,988
152,433
523,451
157,682
8,855
8
Gas to
electrostatic
precipitator
5,441,218
1,151,935
3,833,866
322,623
969,982
34,748
1,343
1,766
142
418
226,039
50,291
B-ll
-------
TABLE B-5. FLUE GAS COMPOSITION
FOR 5% SULFUR EASTERN BITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
C02
S02
503
NO
N02
HC1
H20
Fly asha
Total
Volume, %
75.13
5.53
12.10
0.30
0.01
0.03
0.00
0.01
6.89
100.00
(2,976 ppm)
( 93 ppm)
( 324 ppm)
( 16 ppm)
( 66 ppm)
Lb-mol/hr
136,900
10,080
22,040
542
17
59
3
12
12,550
182,200
Lb/hr
3,834,000
322,600
970,000
34,750
1,343
1,766
142
418
226,000
5,391,000
50,290
5,441,000
Sft3/mln ( 60°F) = 1,152,000
Aft3/min (300°F) = 1,684,000
Fly Ash Loading
Gr/sft3
Wet 5.09
Dry 5.47
Sulfuric acid dew point temperature: 316°F
a. See Table B-2 for fly ash composition.
B-12
-------
3-6. BOILER MATERIAL BALANCE
EASTERN BITUMINOUS COAL, 3.5% SULFUR
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sftj/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
405,983
(270,791)
(15,427)
(22,735)
(5,278)
(406)
(13,641)
16,239
61,466
2
Total air
to air heater
5,071,690
1,120,442
80
3,847,575
1,159,029
65,086
3
Combustion
air to
boiler
4,378,438
967,288
3,321,648
1,000,601
56,189
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
Oa (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
12,511
12,511
5
Gas to
economizer
4,771,910
1,002,880
3,326,058
165,726
992,298
24,324
940
1,766
142
418
210,192
50,046
6
Gas to air
heater
4,771,910
1,002,880
3,326,058
165,726
992,298
24,324
940
1,766
142
418
210,192
50,046
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
Total stream, Ib/hr
Flow rate, sft^/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
13| Ash Ib/hr
7
Air
inleakage
693,252
153,154
525,927
158,428
8,879
8
Gas to
electrostatic
precipitator
5.465,162
1,156,034
3,851,985
324.154
992,298
24,324
940
1.766
142
418
219,089
50.046
B-13
-------
TABLE B-7. FLUE GAS COMPOSITION
FOR 3.5% SULFUR EASTERN BITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
C02
S02
503
NO
N02
HC1
H20
Fly asha
Total
Volume, %
75.22
5.54
12.33
0.21
0.01
0.03
0.00
0.01
6.65
100.00
(2,079 ppm)
( 66 ppm)
( 323 ppm)
( 16 ppm)
( 66 ppm)
Lb-mol/hr
137,500
10,130
22,550
380
12
59
3
12
12,160
182,800
Lb/hr
3,852,000
324,200
992,300
24,320
940
1,766
142
418
219,100
5,415,000
50,050
5,465,000
Sft3/min ( 60°F) = 1,156,000
Aft3/min (300°F) = 1,690,000
Fly Ash Loading
Gr/sft3
Wet 5.05
Dry 5.41
Sulfuric acid dew point temperature: 308°F
a. See Table B-2 for fly ash composition.
B-14
-------
TABLE B-8. BOILER MATERIAL BALANCE
EASTERN BITUMINOUS COAL, 2.0% SULFUR
Stream No.
Description
1
2
3
4
S
6
7
8
9
in
11
1?
13
Total stream, Ib/hr
Flow rate, sftj/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
303 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
405,983
f275I2S6')
(15,021)
(24,359)
(5,684)
(406)
(7,795)
16.239
61.223
2
Total air
to air heater
5,081,446
1,122,597
80
3,854,977
1,161,258
65.211
3
Combustion
air to
boiler
4,386,860
969,149
3,328,038
1,002,525
56.297
Stream No.
Description
1
7
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60UF
Temperature, °F
N2 (C) Ib/hr
02 (H) ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
803 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
12,369
12,36Q
5
Gas to
economizer
4,780,474
1.004,532
800
3,332,,854
166,047
1,008,662
13,899
537
1,766
142
418
206,672
49 ,477
6
Gas to air
heater
4,780,474
1.004,532
705
3,332^854
166,047
1,008,662
13,899
537
1 ,766
142
418
206,672
49 ,477
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
1 1
12
n
Total stream, Ib/hr
Flow rate, sft-Vmin @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
503 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
7
Air
inleakage
694,586
153,449
535
526,939
158,733
8,914
8
Gas to
electrostatic
precipitator
5,475,060
1,157,981
300
3,859,793
324.780
1,008,662
13,899
537
1.766
142
418
215,586
49,477
B-15
-------
TABLE B-9. FLUE GAS COMPOSITION
FOR 2% SULFUR EASTERN BITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
CO 2
so2
so3
NO
NO 2
HC1
H20
Fly asha
Total
Volume
75.24
5.54
12.52
0.12 (1,
0.00 (
0.03 (
0.00 (
0.01 (
6.54
100.00
7
, /o
185 ppm)
38 ppm)
322 ppm)
16 ppm)
66 ppm)
Lb-mol/hr
137,800
10,100
22,920
217
7
59
3
12
11,970
183,100
Lb/hr
3,860,000
324,800
1,009,000
13,900
537
1,766
142
418
215,600
5,426,000
49,480
5,475,000
Sft3/min ( 60°F) = 1,158,000
Aft3/min (300°F) = 1,692,000
Fly Ash Loading
Gr/sff"
Wet 4.98
Dry 5.33
Sulfuric acid dew point temperature: 297°F
a. See Table B-2 for fly ash composition.
B-16
-------
TABLE B-10. BOILER MATERIAL BALANCE
EASTERN BITUMINOUS COAL, 0.7% SULFUR
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sftj/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
SOs (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
405,983
(279,316)
(14,616)
(25,577)
(5,684)
(406)
(2,720)
16,239
61,425
2
Total air
to air heater
5,091,465
1,124,811
80
3,862,577
1,163,548
65,340
3
Combustion
air to
boiler
4,395,510
971,060
3,334,599
1,004,502
56,409
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
12,329
12,329
5
Gas to
economizer
4,789,164
1,006,060
800
3,339,415
166,376
1,023,540
4,850
188
1,766
142
418
203,155
49,314
6
Gas to air
heater
4,780,164
1,006,060
705
3,339,415
166,376
1,023,540
4,850
188
1,766
142
418
203,155
4Q,314
Stream No.
Description
1
2
3
4
5
6
/
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft^/min (? 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H90 Ib/hr
Ash Ib/hr
7
Air
inleakage
695,955
153,751
535
527,978
159,046
8,931
8
Gas to
electrostatic
precipitator
5,485,1 19
1,159,811
300
1,023,540
4,850
188
1.766
142
418
212.086
40,314
-------
TABLE B-ll. FLUE GAS COMPOSITION
FOR 0.7% SULFUR EASTERN BITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
C02
S02
S03
NO
N02
HC1
H20
Fly asha
Total
Volume, %
75.27
5.55
12.68
0.04
0.00
0.03
0.00
0.01
6.42
100.00
(414 ppm)
( 11 ppm)
(322 ppm)
( 16 ppm)
( 65 ppm)
Lb-mol/hr
138,100
10,170
23,260
76
2
59
3
12
11,770
183,400
Lb/hr
3,867,000
325,400
1,024,000
4,850
188
1,766
142
418
212,100
5,436,000
49,310
5,485,000
Sft3/min ( 60°F) = 1,160,000
Aft3/min (300°F) = 1,695,000
Fly Ash Loading
Gr/sft3
Wet 4.96
Dry 5.30
Sulfuric acid dew point temperature: 273°F
a. See Table B-2 for fly ash composition.
B-18
-------
TABLE B-12. BOILER MATERIAL BALANCE
WESTERN BITUMINOUS COAL, 0.7% SULFUR
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft^/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
489,691
(279,124)
(19,098)
(56,314)
(5,876)
(490)
(2,889)
(78,351)
(47,549)
2
Total air
to air heater
5,117,371
1,130,534
80
3,882,231
1,169,468
65,672
3
Combustion
air to
boiler
4,417,874
976,000
3,351,566
1,009,613
56,695
Stream No.
Description
1
2
3
4
5
6
7
8
9
1U
11
12
13
Total stream, Ib/hr
Flow rate, sft-Vmin @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
CC>2 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
9,596
9,596
5
Gas to
economizer
4,897,968
1,045,965
3,356,574
167,228
1,022,834
4,760
184
1,766
142
504
305,590
38,386
6
Gas to air
heater
4,897,968
1,045,965
3,356,574
167,228
1,022,834
4,760
184
1,766
142
504
305,590
38,386
Stream No.
Description
1
2
3
4
5
6
/
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft^/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
503 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
7
Air
inleakage
699,498
154,534
530,666
159,855
8,977
8
Gas to
electrostatic
precipitator
5,597,466
1,200,499
3,887,240
327,083
1,022,834
4,760
184
1,766
142
504
314,567
38,386
B-19
-------
TABLE B-13. FLUE GAS COMPOSITION
FOR 0.7% SULFUR WESTERN BITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
CO 2
S02
S03
NO
NO 2
HC1
H20
Fly asha
Total
Volume , %
73.10
5.38
12.24
0.04
0.00
0.03
0.00
0.01
9.20
100.00
(390 ppm)
( 10 ppm)
(311 ppm)
( 16 ppm)
( 74 ppm)
Lb-mol/hr
138,800
10,220
23,240
74
2
59
3
14
17,460
189,800
Lb/hr
3,887,000
327,100
1,023,000
4,760
184
1,766
142
504
314,600
5,559,000
38,390
5,597,000
Sft3/min ( 60°F) = 1,200,000
Aft3/min (300°F) = 1,755,000
Fly Ash Loading
Gr/sft3
Wet 3.73
Dry 4.11
Sulfuric acid dew point temperature: 278°F
a. See Table B-2 for fly ash composition.
B-20
-------
TABLE B-14. BOILER MATERIAL BALANCE
WESTERN SUBBITUMINOUS COAL, 0.7% SULFUR
Stream No.
Description
1
?
3
4
5
6
7
8
9
10
11
1?
n
Total stream, Ib/hr
Flow rate, sftj/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
640,244
(313,720)
(22,409)
(68,506)
(4,482)
(128)
(3,073)
187,591
40,335
2
Total air
to air heater
5,765,154
1,273,643
80
4,373,663
1,317,506
73,985
3
Combustion
air to
boiler
4,977,111
1,099,548
3,775,824
1,137,415
63,872
Stream No.
Description
1
?
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
8,159
8,159
5
Gas to
economizer
5,609,196
1,215,098
3,779,506
188,611
1,149,608
5,063
196
1,627
131
132
451,685
32,637
6
Gas to air
heater
5,609,196
1,215,098
3,779,506
188,611
1,^149,608
5,063
196
1,627
131
132
451,685
32,637
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
503 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
7
Air
inleakage
788,043
174,095
597,839
180,091
10,113
8
Gas to
electrostatic
precinitator
6,397,239
1,389,193
4,377,345
368.702
1,149,608
5,063
196
1.627
131
132
461,798
32,637
B-21
-------
TABLE B-15. FLUE GAS COMPOSITION
FOR 0.7% SULFUR WESTERN SUBBITUMINOUS COAL
(Stream 8; gas to electrostatic precipitator)
Component
N2
°2
C02
so2
so3
NO
NO 2
HC1
H20
Fly asha
Total
Volume, %
71
5
11
0
0
0
0
0
11
100
.13
.25
.89
.04
.00
.02
.00
.00
.67
.00
(360
( 9
(246
( 14
( 18
ppm)
ppm)
ppm)
ppm)
ppm)
Lb-mol/hr
156,300
11,520
26,120
79
2
54
3
4
25,630
219,700
Lb/hr
4,377
368
1,150
5
1
461
6,365
32
6,397
,000
,700
,000
,063
196
,627
131
132
,800
,000
,640
,000
Sft3/min ( 60°F)
Aft3/min (300°F)
1,389,000
2,030,000
Fly Ash Loading
Wet
Dry
Gr/sft3
2.74
3.10
Sulfuric acid dew point temperature: 280°F
a. See Table B-2 for fly ash composition.
B-22
-------
TABLE B-16. BOILER MATERIAL BALANCE
NORTH DAKOTA LIGNITE, 0.9% SULFUR
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sftj/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
303 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
1
Coal to
boiler
833,333
(334,167)
(23,333)
(103,333)
(5,000)
(83)
(4,750)
302,500
60,167
2
Total air
to air heater
5,938,178
1,311,867
80
4,504,926
1,357,047
76,205
3
Combustion
air to
boiler
5,126,485
1,132,547
3,889,145
1,171,551
65,789
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
Q2 (H) Ib/hr
C02 (0) Ib/hr
SC>2 (N) Ib/hr
S03 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
4
Bottom
ash
12,176
12,176
5
Gas to
economizer
5,947,642
1,296,872
800
3,893,140
194,053
1,224,537
7,825
302
2,045
165
86
576,786
48,703
6
Gas to air
heater
5,Q47,642
1,296,872
3,893,140
194,053
1,224,537
7,825
302
2,045
165
86
576,786
48,703
Stream No.
Description
1
2
3
4
5
6
7
H
9
10
11
12
13
Total stream, Ib/hr
Flow rate, sft3/min @ 60°F
Temperature, °F
N2 (C) Ib/hr
02 (H) Ib/hr
C02 (0) Ib/hr
S02 (N) Ib/hr
303 (Cl) Ib/hr
NO (S) Ib/hr
N02 Ib/hr
HC1 Ib/hr
H20 Ib/hr
Ash Ib/hr
7
Air
inleakage
811,693
179,320
615,780
185,496
10,417
8
Gas to
electrostatic
precipitator
6,759,335
1,476,192
4,508,920
379,549
1,224,537
7,825
302
2,045
165
86
587,203
48,703
B-23
-------
TABLE B-17. FLUE GAS COMPOSITION
FOR 0.9% SULFUR NORTH DAKOTA LIGNITE
(Stream 8; gas to electrostatic precipitator)
Component
N2
02
C02
S02
S03
NO
N02
HC1
H20
Fly
68.
5.
11.
0.
0.
0.
0.
0.
13.
100.
asha
Total
Volume, %
95
08
92
05
00
03
00
00
97
00
(524
(
17
(291
(
(
17
9
ppm)
ppm)
ppm)
ppm)
ppm)
Lb-mol/hr
161,000
11,860
27,820
122
4
68
4
2
32,600
233,400
Lb/hr
4,509
379
1,225
7
2
587
6,711
48
6,759
,000
,500
,000
,825
302
,045
165
86
,200
,000
,700
,000
Sft3/min ( 60°F)
Aft3/min (300°F)
1,476,000
2,158,000
Fly Ash Loading
Wet
Dry
Gr/sft3
3.85
4.47
Sulfuric acid dew point temperature: 295°F
a. See Table B-2 for fly ash composition.
B-24
-------
TABLE B-18. 1979 REVISED NSPS EMISSION STANDARDS
S02
70% S02 removal (minimum) to a maximum SC>2
emission of 0.6 Ib S02/MBtu
0.6 Ib S02/MBtu maximum emission up to 90% S02
removal
90% S02 removal (minimum) to a maximum SC>2
emission of 1.2 Ib S02/MBtu
1.2 Ib S02/MBtu maximum emission
NOX
Bituminous coal - 0.6 equivalent Ib N02/MBtu
Subbituminous coal - 0.5 equivalent Ib NC^/MBtu
Lignite - 0.6 equivalent Ib N02/MBtu
Particulate
0.03 lb/106 Btu
Reference 1
B-25
-------
1 .2
1 .0
0.8
removal reauired
80
I
85
I
I
5.0% S, 11,700 Btu/lb bit, coal
3.5% S, 11,700 Btu/lb bit, coal
2.0? S, 11,700 Btu/lb bit, coal
0.9% S, 6,600 Btu/lb lignite
_7%_S,_ 9,700 Btu/lb bit, coal
0^. 7% S, 9_,_700 Btu/lb subbit. coal
0.7% S, 8,200 Btu/lb subbit. coal
I
I
4 6 8 10
EQUIVALENT S()2 COMTEN'" OF RAW COAL, Ib S02/MBtu
12
Figure B-3. Controlled S02 emission requirements for 1979 NSPS. Premise coals, shown
underlined, are based on premise boiler conditions.
-------
TABLE B-19. PREMISE COAL EMISSION STANDARDS
Equivalent
Equivalent
Eastern
Eastern
Eastern
Eastern
Western
Western
Coal
bit. ,
bit.,
bit.,
bit.,
bit. ,
subbit
N.D. lignite,
so2
of
content
coal,
Ib S02/MBtu
5
3
2
0
0
.
0
.0%
.5%
.0%
.7%
.7%
, o.
.9%
S
S
S
S
S
7% S
S
8
5
3
1
1
1
1
.21
.74
.28
.15
.22
.17
.73
Overall
equivalent S02
removal
efficiency, %
90.0
89.6
81.7
70.0
70.0
70.0
70.0
SO 2 removal
required
in
FGD
system, %a
89
88
80
67
64
64
64
.1
.7
.1
.4
.7
.7
.7
Controlled
outlet
emission
Ib S02/MBtu
0.82
0.60
0.60
0.34
0.36
0.35
0.52
a. Based on FGD system as the only S02 control device and the previously
defined sulfur retention in the ash.
Equation to determine equivalent S02 content of coal:
E = (S/H)(2 x 104)
where: S = % sulfur in coal, as fired
H = heat content of coal, as fired
E = equivalent S02 content of coal as fired, Ib equivalent
S02/MBtu
Equations to determine overall % sulfur removal required:
E < 2.0
70% equivalent SOj removal required
2.0 < E < 6.0
% equivalent S02 removal required = ((E - 0.6)/E)(100)
6.0 < E < 12.0
90% equivalent S02 removal required
E > 12.0
% equivalent S02 removal required = ((E - 1.2)/E)(100)
Equation to determine equivalent S02 removal required in FGD system:
% equivalent S02 removal required = ((A - B)/(1.0 - B))(100)
where: A = overall removal efficiency, decimal fraction
B = decimal fraction of S removed with ash: (1.0 - decimal
fraction of sulfur emitted as SO)
X
B-27
-------
COAL
BOILER
IECONOMIZER]
1 i
TOTAL
AIR
AIR HEATER
FLUE
'GAS
BOTTOM ASH
Figure B-2. Boiler flow diagram.
Particulate Matter
Cold-side (post-air heater) ESP's sized to meet the 0.03 Ib/MBtu
standard are normally assumed for particulate matter control. In some
evaluations cyclones, fabric filter baghouses, or hot-side (pre-air
heater) ESP's may be required. The costs for ash collection and disposal
may or may not be included in the economic evaluations, depending on the
particular processes being evaluated. In some processes ash may be an
intrinsic part of the process. In such processes, or in evaluations in
which comparison with such processes may be anticipated, provisions for
ash control costs are included.
Flue Gas Desulfurization
The conceptual design of the FGD system meets applicable emission
standards and reflects a practical operating approach. FGD systems are
close-coupled to the power unit by a plenum into which the power plant
ID fans discharge. The plenum allows the scrubbing systems to be designed
for a different number of trains than the number of power plant ducts
(to account for limitations in the available size of individual scrubbing
B-28
-------
units), and it facilitates the use of redundant scrubbing trains. To
minimize flow control problems which can result from this design, separate
fans are provided on each side of the plenum. Conventional power plant
ID fans operating balanced draft in respect to the boiler are used
upstream from the plenum to overcome the pressure drop of the boiler and
associated downstream flue gas ductwork. These fans are generally
designed to overcome a static head of about 15 in. H20. Since they are
required even if FGD units are not installed, the installation and
resulting operating costs are not included in the costs of the FGD
system. Separate fans are provided downstream from the plenum to over-
come the pressure drop attributed to the scrubber and the ductwork which
is required solely as a result of installing FGD facilities.
The FGD costs include FGD-related ductwork and associated equipment
between the power plant ID fans and the stack plenum. All ductwork
between the power plant ID fan and the stack plenum is charged to the
flue gas treatment system. This is done on the assumption that without
the flue gas treatment system the boiler ID fan would discharge directly
into the stack plenum. Unless specific process requirements dictate
otherwise, scrubbing trains are sized for a maximum of 125 MW of flue
gas up to a maximum of 513,000 sft3/min (60°F). Thus, the 500-MW base
case requires four operating trains and the 200-MW and 1,000-MW case
variations require two (100-MW) and eight (125-MW) operating trains
respectively. Furthermore, any boiler generating more than 340,000
aft /min (about 100 MW) is provided with a minimum of two operating
scrubber trains. It is assumed that the annual availability of a
scrubbing train is 85% and that no scrubbing time is lost during startup.
Spare scrubbing trains are provided as described below.
Emergency Bypass—
Because the 1979 NSPS allow emergency bypass around the FGD system
under some conditions if spare scrubbing capacity is provided, redundancy
in the form of spare scrubbing trains and provision for bypass of 50% of
the gas that would normally be scrubbed are included in all FGD economic
evaluations. The 1,000-MW case variation with eight operating scrubbing
trains is provided with two spare trains. Units on smaller boilers are
provided with one spare train. An emergency bypass of 50% of the scrubbed
gas is assumed to be an economic balance between the higher cost of
providing additional bypass and the small likelihood of multiple scrubbing
train failures making higher bypass rates necessary. The bypass is
installed as two identical ducts from each end of the inlet plenum to
the plenum downstream from the scrubbing trains. Particulate collection
equipment is not bypassed.
Partial Scrubbing—
In some cases, depending on the sulfur content of the coal and SOX
removal requirements, scrubbing a portion of the flue gas at a high SOX
removal efficiency and combining it with the remaining flue gas may be
more economical than scrubbing all of the flue gas at a lower SOX removal
efficiency. In such cases the bypassed gas duct requirements and the
emergency bypass capability are combined in the same duct. The ducts
are sized to handle both the flue gas normally bypassed and the emergency
B-29
-------
bypass of 50% of the gas normally scrubbed. Depending on sulfur in the
coal for the 500-MW power unit, partial scrubbing could involve scrubbing
as little as 375 MW of flue gas. Three operating scrubbing trains and
one spare scrubbing train are provided for this case.
Ductwork—
Square ductwork with 2-inch insulation (in standard cases) is used
for the inlet plenum and scrubbing trains. To prevent ash settling, a
gas velocity of 50 ft/sec is used for the inlet plenum, all ductwork,
and the emergency bypass. A gas velocity of 25 ft/sec is used for the
reheater section. Duct material is usually 3/16-inch Cor-Ten® steel
when the gas temperature is higher than 150°F and 3/16-inch stainless
steel when the gas temperature is lower than 150°F.
Removal Efficiencies—
It is assumed that 50% of the S03, 95% of the HC1, 0% of the NOX,
and 50% of the remaining fly ash in the flue gas are removed in the FGD
system. For systems requiring a presaturator or humidifier, it is
assumed that 5% of the SC>2 is removed in the presaturator and that the
remaining S02 removal takes place in the FGD absorber.
Spare Equipment—
Equipment is spared in accordance to general field practice. For
most processes the following equipment is spared:
• Crushing and grinding equipment: A spare train of crushing and
grinding equipment
• Slakers
• Sludge filters
• Pumps
• Scrubbing trains: A spare scrubbing train or trains
Mist Eliminator—
The mist eliminator is a zigzag-chevron-baffle type. The mist
eliminator reduces entrained moisture to a maximum level of 0.1% (by
weight) of the flue gas. This maximum level is assumed for calculation
of the amount of stack gas reheat required.
Stack Gas Reheat—
Indirect steam reheat is provided for processes that cool the flue
gas below 175°F. This stack gas reheat is considered necessary both to
evaporate entrained water droplets not removed by the mist eliminator
and to increase plume buoyancy. Necessary information for calculating
the steam requirement and reheater surface area is given in Table B-20
and a sample calculation is shown in Table B-21.
One-half of the reheater tubes are made of Inconel 625 and one-half
of Cor-Ten. Inconel 625 is highly resistant to corrosion and is used
B-30
-------
TABLE B-21. SAMPLE REHEATER CALCULATIONS
Gas to Reheater
co2
HC1
S02
°2
N2
H20 (vapor)
Total gas
H20 (liquid entrainment)
Total
Reheater Heat Duty
co2
HC1
S02
02
N2
H90 (vapor)
Ib/hr
1,008,000
21
2,850
319,800
3,852,000
444,873
5,627,544
5,627
5,633,171
Ib/hr x Cpm(Btu/lb)b =
1,008,000 x 10.8
21 x 9.5
2,850 x 7.9
319,800 x 11.2
3,852,000 x 12.5
444,873 x 22.6
Btu/hr
10,886,400
200
22,515
3,581,760
48,150,000
10,054,130
Total
HoO (liquid entrainment)
Total
5,627 x l,043.2t
72,695,005
5,870,090
78,565,095 Btu/hr
Steam Requirement
78,565,095 Btu/hr v 751.9 Btu/lb = 104,489 Ib/hr
Reheater Area
78,565,095 Btu/hr T 4 operating reheaters 4- 20.8 Btu/ft -hr-°F T
3igoFa,b = 2,960 ft2
a. Log mean temperature difference (ATL) = (T^ - T2) /(ln(TL/T2))
TI = Tsteam - Tgas in = 470 - 125 = 345
T2 = Tsteam - Tgas out = 470 - 175 = 295
ATL = (345 - 295)/(ln(345/295))
b. For a temperature change from 125°F to 175°F qn_
B-31
-------
TABLE B-20. REHEATER DATA
- - : . - _ , _ : :
Compound
C02
HC1
S02
803
02
N2
NO
N02
H20 (vapor)
Cpm (Btu/lb)a
10.8
9.5
7.9
8.2
11.2
12.5
12.0
10.2
22.6
Steam:
sa
vaporization 751.9 Btu/lb
saturated at 470°F (500 psig), heat of
Reheater overall heat transfer coefficient:
20.8 Btu/ft2-hr-°F
Entrained water enthalpy:
liquid at T = 125°F: 92.9 Btu/lb
vapor at T = 175°F: 1136.1 Btu/lb
•*• AHa = 1043.2 Btu/lb
a. For a temperature change from 125°F to
175°F only.
for the first bank of tubes, which increases the flue gas temperature to
150 F. The Cor-Ten tubes follow directly after, raising the temperature
of the gas at the exit to 175°F. For the partial bypass case, the gas
may not be heated to 175°F because of the smaller percentage of scrubbed
(cool) gas. In these cases, the percentage of Inconel 625 tubes increases
to as much as 100% (for reheat to 150°F or less).
Raw Materials and Byproducts—
Raw materials and byproduct storage capacity is normally 30 days
unless process or industry practice differ. Standard raw material
characteristics are shown in Table B-22.
NO,, Control
Processes that remove only NOX are combined with a limestone spray
tower, forced-oxidation FGD system with landfill waste disposal for
comparison with processes that remove both NOX and S02-
Redundancy is included in the NOX control processes to ensure that
removal efficiencies used in each particular economic study are met.
For wet NOX control processes the availability is the same as for FGD
B-32
-------
TABLE B-22. RAW MATERIAL CHARACTERISTICS
Limestone
Size as received
0 x 1-1/2 inch
Ground
size
90% to pass
325 mesh
Analysis3
95% CaC03
0.15% MgO
Bulk
density, Ib/ft"1
95
Fineness of grind
index factor = 5.7
Hardness of work
index factor = 10
4.85% inerts
5 Ib H20/100 Ib
dry limestone
Lime 3/4 x 1-1/4 inch
(pebble)
MgO
Crystalline
powder
Soda ash 100% to pass
100 mesh
Adipic
acid
Crystalline
powder
95% CaO 55
0.15% MgO
4.85% inerts
5 Ib H20/100 Ib
dry lime
98% MgO
2% inerts
99.8% Na2C03
(58.4% Na20)
0.15% NaCl
0.02% inerts
0.03% H20
99.8% (CH2)4 49
(COOH)2
0.2% inerts
30 (virgin)
15 (regenerated)
35
a. Limestone and lime analysis on a dry basis. H20 is based on pounds of dry
limestone or lime.
B-33
-------
systems. When the number of trains is the same as FGD for the same
boiler size, the redundancy for wet NOX control process trains is the
same as for an FGD system.
For dry catalytic processes, catalyst replacement occurs during
boiler outages and does not affect boiler on-stream time. A sufficient
quantity of catalyst is included to ensure that the desired removal
efficiency is maintained during the entire guaranteed life of the catalyst
load. Redundancy and the number of trains for all dry processes are
based on NOX removal system module availability and the required NOX
removal efficiency. Redundancy is achieved through sparing NOX removal
system trains or sparing vital equipment such as NH3 vaporization and
injection equipment.
Solids Disposal
For FGD processes producing a solid waste, either ponding or
landfill disposal at a site one mile from the FGD facilities is used.
Sufficient land is provided for disposal during the remaining life of
the FGD facility. Fly ash disposal is not included unless fly ash
collection or use is an integral part of the FGD process. The disposal
site is assumed to be an area of low relief with sufficient soil for
dike construction or landfill requirements.
Pond-
Disposal ponds are square, earthen-diked enclosures with a median
diverter dike. Dikes are constructed from material removed from the
impoundment area as shown in Figure B-4. The entire impoundment area is
lined with 12 inches of clay (assumed available onsite). Pond size and
depth are adjusted to minimize the sum of land and construction costs.
Pond costs include a 6-foot security fence around the perimeter dike,
security lighting, a topsoil storage area, and one upstream and three
downstream ground water monitoring wells.
Landfill-
Landfills are an area-type landfill having a square configuration
with a single 20-foot lift and a 2-degree cap, as shown in Figure B-5,
After topsoil removal the landfill area is lined with 12 inches of clay
(assumed available onsite) and 24 inches of bottom ash. This bottom ash
layer allows the water to drain into a catchment ditch around the
perimeter. The ditch drains into a catchment basin for pH adjustment
before discharging into the river. Land requirements include the landfill,
catchment basin, equipment storage area, topsoil storage area, and a 50-
foot perimeter of undisturbed land. Costs for access roads, a 6-foot
security fence around the total landfill area, security lighting, and
topsoil stripping, replacement, and revegetation are included. One
upstream and three downstream ground water monitoring wells are also
included.
B-34
-------
i_n
WASTE DISPOSAL
POND
t_
J
OUTER BOUNDRY
X OF POND AREA
10% FREE BOARD
DEPTH OF SLUDGE
GROUND LEVEL
TOPSOIL
EXCAVATION
(15 FT)\
SUBSOIL '
EXCAVATION
SECTION AA
POND PERIMETER DIKE
NAL GROUND LEVEL —^
ORIGINAL GROUND
TOTAL
EXCAVATION DEPTH
SUBSOIL
EXCAVATION
10% FREE BOARD
DEPTH OF SLUDGE
1 TOTAL
EXCAVATION DEPTH
SUPERNATE SLURRY
IN
SECTION BB
POND DIVERTER DIKE
Figure B-4. Pond plan and dike construction details.
-------
w
LO
N
)
Topsoil Equipment Office -i Catchment
Storage~\ Storages / Basin ~7
* v A v x ^ x — V^f x — /-x * tx >
e
— »
P-^: — i-J. \ / r^ *^
•k . ^
D
/,
\*
Landfill
Area
/
/
^
X XX X)( V X X X X
Ditch -/ ^- 6' Fence
-] — 50'
E 24'
— 40'
, ~ , * ~ .
>
/*
>
*i
, t
24'
Ditch
' Clay
^
2' Bottom Ash
Figure B-5. Landfill plan and construction details.
-------
ECONOMIC PREMISES
Schedule and Cost Factors
The construction schedule used as a cost basis is shown in Figure B-6.
A three-year construction period, from early 1981 to late 1983, is used.
Mid-1982 costs are used for capital investment. Mid-1984 costs are used
for annual revenue requirements. These costs represent the midpoint of
construction expenditures in 1982 and the midpoint of the first-year of
operation in 1984. Costs are projected from Chemical Engineering cost
indexes (12), as shown in Table B-23. Frequently used costs are shown
in Table B-24.
3
u
-2
1
period
1981 1982
-101
, Operating year
1983
1 .tol
1
1984
1 to.
Begin
construction
(early 1981)
1
Midpoint of
construction
expenditure
(mid-1982)
End of
construction
(late 1983)
Begin operation
in early 1984
Figure B-6. Construction schedule.
Year:
TABLE B-23. COST INDEXES AND PROJECTIONS
1978
1979 1980a 1981£
1982'
1983C
1984
Plant
Material13
Laborc
218.8
240.6
185.9
238.7
264.4
194.9
257.8
288.2
210.5
277.1
311.2
227.3
297.9
336.1
245.5
320.2
363.0
265.2
342.6
388.4
283.7
a. TVA projections.
b. Same as "equipment, machinery, supports" Chemical Engineering
index.
c. Same as "construction labor" Chemical Engineering index.
B-37
-------
TABLE B-24. COST FACTORS
Project Timing
Start
End
Midpoint
First-year operation
January 1981
December 1983
Mid-1982
1984
1984 Utility Costs
Electricity
Steam
Eastern bit. coal (<1% S)
Eastern bit. coal (>1% S)
Western bit. coal (0.7% S)
Western subbit. coal (0.7% S)
N.D. lignite (0.9% S)
Fuel oil No. 6
Diesel fuel3
Natural gas
Filtered river water
$0.037/kWh
$2.50/klb;
$53.35/ton;
$43.30/ton;
$55.70/ton;
$30.00/ton;
$15.00/ton;
$8.33/MBtu
$1.60/gal
$4.29/MBtu
$0.14/kgal
$0.12/kgal
$0.10/kgal
$0.08/kgal
$3.30/MBtu
$2.30/MBtu
$1.85/MBtu
$2.90/MBtu
$1.80/MBtu
$1.15/MBtu
(up to 0.6 Ggal)
(0.6 - 2 Ggal)
(2-5 Ggal)
(over 5 Ggal)
1984 Labor Costs
FGD
Waste disposal
Analysis
$15.00/man-hr
$21.00/man-hr
$21.00/man-hr
1984 Raw Material Costs
Limestone
Lime
Ammonia
Soda ash
Adipic acid
MgO
$8.50/ton (95% CaC03, dry basis)
$75.00/ton (pebble,95% CaO, dry basis)
$155.00/ton
$160.00/ton (99.8% Na2C03)
$l,200.00/ton
$460.00/ton
1982 Land Cost
$5,000/acre
These cost factors are based on a north-central plant location.
a. Cost is based on wholesale price of barge-load quantities. Road
taxes are not included.
B-38
-------
Capital Cost Estimates
Four grades of capital cost estimates are prepared depending upon
the intended use and the amount of information available. The grades,
in increasing order of accuracy, are (1) order of magnitude, (2) study,
(3) preliminary, and (4) definitive. The two grades normally used are
the study and preliminary grades. The purpose, information required,
and predicted accuracy are listed in Table B-25.
A typical capital investment sheet is shown in Table B-26. The
capital investment sheet is divided into three major sections: direct
investment, indirect investment, and other capital investment.
Direct Investment—
Direct investment consists of total process capital; services,
utilities, and miscellaneous; and waste disposal investment. Total
process capital can be determined when an equipment list has been
organized. Using standard estimating techniques (13,14) and the average
annual Chemical Engineering cost indexes and projections shown in Table B-23,
the equipment cost and installation costs of each area are estimated.
These installation costs include charges for all piping, foundations,
excavations, structural steel, electrical equipment, instruments, ductwork
(all included in gas handling area), paint, buildings, taxes, freight,
and a premium for 7% overtime construction labor as shown in Figure B-7.
The total process area costs are summed on the Area Summary Sheet shown
in Figure B-8 to give the total process capital.
Service facilities such as maintenance shops, stores, communications,
security, offices, and road and railroad facilities are estimated or
allocated on the basis of process requirements. Included in the utilities
investment are necessary electrical substations, conduit, steam, process
water, fire and service water, instrument air, chilled water, inert gas,
and compressed air distribution facilities. Services, utilities, and
miscellaneous are estimated to be in the range of 4% to 8% of the total
process capital. For most cases 6% is to be used, higher for processes
only and lower for ponds only. The base case limestone and lime scrubbing
processes are charged 6% for services, utilities, and miscellaneous.
All equipment and direct construction costs associated with waste
disposal are included in waste disposal costs. For ponds, this includes
pond construction costs from the computer pond model. For landfills,
mobile equipment and construction costs are included. All mobile equip-
ment involved in loading and transporting the waste from the in-process
storage area, as well as working the landfill, are included in solids
disposal equipment. The landfill construction cost, as calculated from
the landfill model, is listed separately from the solids disposal
equipment. The sum of total process capital; services, utilities, and
miscellaneous; and the waste disposal cost is the total direct investment.
Indirect Investment—
Indirect capital costs cover fees for engineering design and super-
vision, architect and engineering contractor, construction expense,
B-39
-------
TABLE B-25. CAPITAL COST ESTIMATE CLASSIFICATION
Grade
Purpose
Minimum information required
Predicted
accuracy
ttf
Order of magnitude
(ratio estimate)
Study
(factored estimate)
Preliminary
(initial budget or
scope estimate)
Definitive
(project control
estimate)
Preliminary feasibility study to deter-
mine whether continued investigation is
merited. Rough comparison of alterna-
tives.
Comparison of alternatives. Prelimi-
nary screening. Preliminary budget
preparation. Authorization for funding
for an engineering study or for develop-
ment of additional information.
Preliminary budget approval. More
accurate comparison of alternatives.
Followup of an order of magnitude or
study estimate.
Final capital authorization. Project
cost control. Followup on order of
magnitude, study, or preliminary esti-
mates for more accurate information.
Generally reserved for a real construc-
tion project with a known site.
General design basis, flowsheet and
material balance, heat and energy
balance. For the order of magnitude
estimates this information is of a tena-
tive nature, developed from a preliminary
process concept.
All of the above on a firm rather than
tentative basis plus overall layout of
manufacturing and nonmanufacturing
facilities, sized equipment and instru-
ment lists, and performance data sheets.
All of the study estimate requirements
plus process control diagrams, process
piping sketches with sizes, plan and
elevation drawings, offsite descriptions
including sizes and capacities.
All of the preliminary estimate require-
ments plus piping plan and elevation
drawings integrated with the equipment
plan and elevation drawings, electrical
layout single line drawings, detailed
piping and instrumentation flowsheets,
layout of nonmanufacturing facilities,
design sketches for unusual equipment
items, and specific site data including
utilities and transportation availa-
bility, soil bearing, wind and snow
loads.
40 20
30
15
20 10
General design basis includes product, product specifications, plant capacity, storage requirements, operating
stream time, provisions for expansion, raw materials and their storage requirements.
-------
TABLE B-26. CAPITAL INVESTMENT SHEET
TABLE ADVANCED LIMESTONE PROCESS CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% S in coal;
88.6% S02 removal; onsite solids disposal)
Investment, k$
Direct Investment
Materials handling
Feed preparation
Gas handling
S02 absorption
Stack gas reheat
Oxidation
Solids separation
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding landfill
Solids disposal equipment
Landfill construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Disposal area indirects
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Tctal capital investment
Dollars of total capital per kW of generating capacity
Basis: North-central plant location represents project beginning early 1981,
ending late 1983; average cost basis for scaling, mid-1982.
Redundant scrubber train, 50% emergency bypass, spare pumps.
Landfill located one mile from power plant.
FGD process investment begins at power plant ID fans. Stack plenum and stack
excluded.
B-41
-------
w
I
% of pro cess equipment
Process equipment
Piping and insulation
Concrete foundations
Excavations , site prepa-
ration, roads, etc.
Structural
Electrical
Instrumentation
Ducts, chutes, expansion
joints , etc .
Paint and miscellaneous
Bui Idings
Trucks and earthmoving
equipment
Subtotal
Freight (3.57 of process
equipment material)
Tax (4% of material
subtota 1 )
Total process
area cost
X
Material
Labor3
">
-------
contractor fees, and contingency. Listed in Table B-27 are the ranges
to be used to calculate the process and waste disposal indirect investments.
The base percentages are normally used while the low and high ranges are
used in cases where the process being studied is either much more complex
than the typical system (the higher percentage factors are used) or much
less complex (the lower percentage factors are used). Under most conditions
the base values are used for typical systems. The limestone and lime
scrubbing processes use the low percentages for a 1,000-MW unit, base
percentages for a 500-MW unit, and the high percentages for a 200-MW
unit. Contingency is included to compensate for unforeseen expenses.
The contingency varies depending on the process and the waste disposal
method, as shown in Table B-28. The limestone and lime scrubbing processes
are assessed a contingency of 10% for the process and 20% for the landfill.
Other Capital Investment—
The allowance for startup and modifications is applied as a percentage
of the total fixed investment. Since the startup and modification costs
for the waste disposal area are assumed to be negligible, this allowance
is calculated as a percentage of the total process fixed investment
only. The values used are shown in Table B-29. The limestone and lime
scrubbing processes are assessed at a rate of 8% for this charge.
The cost of borrowed funds (interest) during construction is 15.6%
of the total fixed investment (both process and waste disposal). This
factor is based on an assumed three-year construction schedule and is
calculated with a 10% weighted cost of capital with 25% of the construction
expenditures in the first year, 50% in the second year, and 25% in the
third year of the project construction schedule. Expenditures in a
given year are assumed uniform over that year. Startup costs are assumed
to occur late enough in the project schedule that there are no charges
for the use of money to pay startup costs. Table B-30 illustrates the
calculation of the interest during construction for three- through six-
year construction schedules.
Most processes will include a one-time royalty charge using either
an actual royalty obtained from the vendor or 1% of the total process
capital involved. Processes exempt from royalties due to their generic
design are limestone and lime processes, including those with forced
oxidation or adipic acid or both, and the magnesia process.
Land—
All land associated with the process and waste disposal area is
charged to the process. The cost of land is $5,000 per acre.
Working Capital—
Working capital is the total amount of money invested in raw
materials, supplies, finished products, accounts receivable, and money
on deposit for payment of operating expenses. For these premises,
working capital is defined as the equivalent cost of 1 month's raw
material cost, 1.5 months' conversion cost, 1.5 months' plant and adminis-
trative overhead costs (all of the above are found on the annual revenue
B-43
-------
TABLE B-27. RANGE OF INDIRECT INVESTMENTS
Indirect Investment, Process
% of total direct investment
excluding waste disposal investment
Low Base High
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
6
1
14
7
2
16
3
18
6
Total
25
30
35
Waste Disposal Indirects FGD Pond,
FGD Landfill, or Ash Pond
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total
% of total direct waste
disposal investment3
Low
14
Base
2
1
8
16
High
2
1
9
18
Ash Landfill
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total
% of total direct waste
disposal investment5
Base
6
3
10
25
a. Pond (or landfill construction) only.
B-44
-------
TABLE B-28. CONTINGENCY
Process Contingency
Limestone and lime slurry
Limestone and lime - forced oxidation
Limestone and lime - forced oxidation
with adipic acid
All others
% of total direct investment
excluding waste disposal plus
process indirect investment
10
10
10
20
Waste Disposal Contingency
FGD pond
Ash pond
FGD landfill
Ash landfill
% of total waste disposal direct
investment plus waste
disposal indirect investment
10
10
20
10
TABLE B-29. ALLOWANCE FOR STARTUP AND MODIFICATIONS
Process
Limestone and lime (generic3)
All other processes
% of total fixed investment
for process only
10
Waste Disposal
Ponds and landfills
% of total fixed investment
for waste disposal only
0
a. Excludes Chiyoda, double alkali, etc., which have
unique designs and are not as yet proven technology.
B-45
-------
TABLE B-30. INTEREST DURING CONSTRUCTION ILLUSTRATION
Three-Year Construction Schedule
Years from
startup
3-2
2-1
1-0
Total fixed
Compound amount
factor3
1.2686
1.1533
1.0484
Fraction of total
plant investment
x 0.250
x 0.500
x 0.250
investment plus interest during construction:
Interest during construction =
1.156 - 1.000 = 0.156 or 15
0.317
0.577
0.262
1.156
.6%
Four-Year Construction Schedule
Years from
startup
4-3
3-2
2-1
1-0
Total fixed
Compound amount
factor3
1.3955
1.2686
1.1533
1.0484
Fraction of total
plant investment
x 0.150
x 0.300
x 0.350
x 0.200
investment plus interest during construction:
Interest during construction =
1.204 - 1.000 = 0.204 or 20
0.209
0.381
0.404
0.210
1.204
.4%
Five- Year Construction Schedule
Years from
startup
5-4
4-3
3-2
2-1
1-0
Compound amount
factor3
1.5349
1.3955
1.2686
1.1533
1.0484
Fraction of total
plant investment
x 0.10
x 0.20
x 0.30
x 0.25
x 0.15
0.154
0.279
0.381
0.288
0.157
Total fixed investment plus interest during construction: 1.259
Interest during construction = 1.259 - 1.000 = 0.259 or 25.9%
(continued)
B-46
-------
TABLE B-30 (continued)
Six-Year Construction Schedule
Years from
startup
6-5
5-4
4-3
3-2
2-1
1-0
Compound amount Fraction of total
factor3 plant investment
1.6886
1.5349
1.3955
1.2686
1.1533
1.0484
X
X
X
X
X
X
0.10
0.15
0.25
0.25
0.15
0.10
0.169
0.230
0.349
0.317
0.173
0.105
Total fixed investment plus interest during construction: 1.343
Interest during construction = 1.343 - 1.000 = 0.343 or 34.3%
Present worth and compound amount factor using the 10% cost of
capital with continuous compounding (13).
a.
Years from
startup
Uniform expenditure
present worth (13)
Compound amount
factor (13)
7-6
6-5
5-4
4-3
3-2
2-1
1-0
0.5384
0.5922
0.6515
0.7166
0.7883
0.8671
0.9538
8574
6886
5349
3955
2686
1.1533
1.0484
B-47
-------
requirements sheet), and 3% of the total direct capital investment (from
the capital investment sheet). One month is defined as 1/12 of annual
costs. The equation is shown below:
Working capital = 1/12 (total raw materials cost) +
(1.5) (1/12) (total conversion cost) +
(1.5) (1/12) (plant and administrative overhead) +
0.03 (total direct investment)
Battery Limits—
Since battery limits costs typically include most of the associated
indirect investments, battery limits costs have their own indirect invest-
ment factors as shown below:
% of battery
limits cost
Engineering design and supervision 6
Architect and engineering contractor 1
Construction expense 14
Contractor fees 0
Contingency 10
Retrofit Factor—
For existing plant cases a retrofit factor is assigned to cover the
additional investment required. Each of the area investments (i.e.,
material handling, etc.) is multiplied by the retrofit factor. Retrofit
factors vary widely depending on the process and the site involved. For
emission control processes which are close coupled to the boiler, the
following retrofit factors are used:
Process
Retrofit
factor
Reason
Limestone scrubbing 1.3
Spray dryer
1.5
These scrubbing systems are add-on in that
they require no boiler modifications. This
factor for the retrofit cases is due to the
need to fit the equipment into available space,
These scrubbing systems require relatively
minor modifications to the boiler and ESP
ductwork. This factor also includes the
expense of fitting the equipment into the
available space.
These control systems require extensive modi-
fications to the boiler economizers and air
heaters and the associated ductwork. This
factor also includes the expense of locating
the equipment in the available space.
It is assumed that most FGD systems will be of the add-on type and therefore
use the 1.3 retrofit factor.
B-48
NOX FGT (SCR)
1.7
-------
Annual Revenue Requirements
Annual revenue requirements in these premises consist of various
direct and indirect operating and maintenance costs and capital charges.
Annual revenue requirements normally vary from year to year as operating
and maintenance costs change and capital charges decline. Thus no
single year is necessarily representative of the lifetime costs, nor can
single-year undistorted comparisons be made among processes with different
ratios of operating costs to capital charges. In addition it is necessary
to take into account the effect of time on the value of money (i.e., for
inflation, the future earning power of money spent, and other factors).
Frequently these factors are accounted for by levelizing (15).
Levelization converts all the varying annual revenue requirements to a
constant annual value, such that the sum of the present worths of the
levelized annual revenue requirements equals the sum of the present
worths of the actual annual revenue requirements. The levelized value
is calculated by multiplying the revenue requirements for each year by
the appropriate present worth factor and summing the present worth
values. Then the single present worth value is converted to equal
annual values by multiplying the result by the capital recovery factor.
In these premises the operating and maintenance costs are levelized
by multiplying the first-year operating and maintenance cost by a levelizing
factor. The levelized capital charges are determined by levelizing the
percentage of capital investment applied yearly as capital charges. The
levelizing factor includes a discount factor reflecting the time-value
of money and an inflation factor reflecting the effects of inflation
during the operating life of the system. The discount rate used is 10%
and the inflation rate used is 6%. The levelizing factor produced
varies with the remaining life of the system. Calculation of the levelizing
factor for operating and maintenance costs and of levelized capital
charges is discussed below.
A typical annual revenue requirement tabulation is shown in Table B-31.
Direct costs consist of raw material and conversion costs. These,
combined with overheads, are the operating and maintenance costs. For
processes that produce a salable byproduct, byproduct sales are applied
as a credit to the operating and maintenance costs. Levelized capital
charges are calculated as a percentage of the capital investment and
added to the operating and maintenance costs to provide the first-year
annual revenue requirements. The levelized annual revenue requirements
are determined by multiplying the operating and maintenance costs by the
levelizing factor and adding the product to the same levelized capital
charges used in the first-year annual revenue requirements.
Operating and Maintenance Costs—
Frequently used raw material costs and standard conversion costs
were shown previously in Table B-24. Other costs are obtained from
vendors or published information. These costs are converted to 1984
costs using the cost indexes in Table B-23 or industry projections.
B-49
-------
TABLE B-31. ANNUAL REVENUE REQUIREMENTS SHEET
TABLE ADVANCED LIMESTONE PROCESS ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% S in coal;
88.6% S02 removal; onsite solids disposal)
Direct Costs - First-Year
Raw materials
Limestone
Annual
quantity
tons
Unit
cost, $
/ton
Total annual
cost, k$
Total raw materials cost
Conversion Costs
Operating labor and supervision
FGD
Solids disposal
Utilities
Process water
Electricity
Steam
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First-Year
Overheads
Plant and administrative
Marketing (10% of byproduct sales)
Byproduct Credit
man-hr
man-hr
kgal
kWh
klb
/man-hr
/man-hr
/kgal
/kWh
/klb
man-hr
/man-hr
tons
$/ton
Total first-year operating and maintenance costs
Levelized Capital Charges ( % of
total capital investment)
Total first-year annual revenue requirements
Levelized First—Year Operating and Maintenance
Costs ( first-year 0 and M)
Levelized Capital Charges ( % of total capital
investment)
Levelized annual revenue requirements
M$ Mills/kWh
First-year annual revenue requirements
Levelized annual revenue requirements
Basis: One-year, 5,500-hour operation of the system described in the
capital investment sheet; 1984 cost basis.
B-50
-------
Raw materials—Consumables required for their chemical or physical
properties, other than fuel for the production of heat, are classified
as raw materials. Raw material costs are determined as necessary from
vendor quotations or published sources and escalated to 1984 costs. All
costs are delivered costs.
Operating labor and supervision—Unit labor costs for 1984 were shown
in Table B-24. The allocation of operating labor and supervision
depends on the process complexity, number of process areas, labor intensity
of the process, and operating experience.
Utilities—Services used, such as steam, electricity, process
water, fuel oil, and heat credits, are charged under the utilities
heading. Unit 1984 costs were shown in Table B-24. Costs for steam and
electricity are based on the assumption that the required energy is
purchased from another source. This simplifying assumption eliminates
the need to derate the utility plant. Process water requirements are
defined as any water used by the process being evaluated and are usually
determined by the material balance. Steam requirements are for stack
gas steam reheat and process requirements. Electrical power requirements
are determined from the installed horsepower of operating electrical
equipment (excluding the horsepower of spared equipment). Each motor in
operation is assumed to be operating at rated capacity although this
results in higher power consumptions than would actually occur. Electrical
requirements are obtained from the equipment list where the motor horsepower
is identified, plus an additional amount for functions such as lighting.
A sample calculation is shown in Table B-32.
Maintenance—Process maintenance costs are 3% to 10% of the total
direct process investment depending on process complexity, process
equipment, materials handled, process areas, and unit size. The per-
centages shown in Table B-33 are used under most circumstances. For
specific FGD processes the maintenance percentages shown in Table B-34
are used. For example, a 500-MW limestone and lime scrubbing process
normally has a maintenance factor of 8%.
Waste disposal maintenance costs are estimated from the appropriate
model and are typically 3% of the waste disposal site construction
costs. Maintenance costs for waste disposal are not shown separately.
If, and only if, it is required and no other information is available,
the maintenance material-to-labor ratio is 60:40.
Analysis—Analysis costs are based on process complexity and are
listed as a single entry.
Plant and administrative overhead—Plant and administrative overheads
include plant services such as safety, cafeteria, and medical facilities;
plant protection and personnel; general engineering (excluding maintenance),
interplant communications and transportation; and the expenses connected
with management activities. Plant and administrative overheads for the
FGD process are 60% of the total conversion costs less utilities.
Marketing overhead—This is calculated as 10% of byproduct sales
income.
-------
TABLE B-32. SAMPLE ELECTRICAL REQUIREMENT CALCULATION
Electricity requirements are determined by summing the horsepower of
all operating electrical equipment and multiplying by a factor of 0.7457
kW/hp. It is assumed that the instantaneous load factor and the power
load factor are equal and thus cancel out. Additional electricity is
added for functions such as lighting. For the limestone and lime
processes 100 kW is added. For other processes more or less electricity,
depending on the process type, size, and complexity, may be necessary.
Sample Calculation
Area Total operating hp
1 Materials handling 70.5
2 Feed preparation 797.5
3 Gas handling 3,580.0
4 SC-2 absorption 6,189.0
5 Stack gas reheat 0.0
6 Oxidation 4,903.0
7 Solids disposal 71.0
Total 15,611.0
15,611 hp x 0.7457 kW/hp = 11,641 kW
+ 100 kW
11,741 kW
11,741 kW x 5,500 hr = 64,575,500 kWh
B-52
-------
TABLE B-33. MAINTENANCE FACTORS
% of total direct investment
excluding waste disposal
Process conditions Low Base High
Corrosive or abrasive slurry 6 8 10
Solids, high pressure, or high
temperature 456
Liquids and gases 345
TABLE B-34. MAINTENANCE FACTORS FOR SPECIFIC FGD PROCESSES
Maintenance, % of total
direct investment
FGD system
200 500 1000 Waste
MW MW MW disposal
Limestone and lime (generic) 987 3
Double alkali 765 3
Wellman-Lord 765
Magnesia 876
Lime spray dryer (including
baghouse) 765 3
B-53
-------
Byproduct sales—Total revenue from the sale of byproducts is
applied as a credit to processes in which a byproduct is salable.
Capital Charges—
Capital charges are those costs incurred by construction of the
facility that must be recovered during its life. They consist of returns
on equity and debt (discount rate), depreciation, income taxes, and
other costs such as insurance and local taxes. In keeping with common
practice for investor-owned utilities the weighted cost of capital is
used as the discount rate (16). Depreciation is stated as a sinking
fund factor to simplify calculations. An allowance for interim replacement
is included to compensate for possible early retirement of the facility.
Credits are also included for tax preference allowances. The capital
charges are shown in Table B-35 and discussed below. In keeping with
standard practice, book, tax, and economic lives are used in the following
calculations. In these premises, however, all three are assumed to be
equal.
TABLE B-35. LEVELIZED ANNUAL CAPITAL CHARGES
% of total capital investment
remaining life, years
20 30
(existing (new
15 plant) 25 jplanjt)
Weighted cost of capital 10.00 10.00 10.00 10.00
Depreciation (sinking fund factor) 3.15 1.75 1.02 0.61
Annual interim replacement 0.72 0.67 0.62 0.56
Levelized accelerated tax depreciation (1.44) (1.43) (1.40) (1.36)
Levelized investment tax credit (2.39) (2.14) (2.00) (1.93)
Levelized income tax 3.96 4.08 4.20 4.31
Insurance and property taxes 2.50 2.50 2.50 2.50
Levelized annual capital charge 16.5a 15.4a 14.9a 14.7
a. Rounded to three significant figures.
The capital structure is assumed to be 35% common stock, 15% pre-
ferred stock, and 50% long-term debt. The cost of capital is assumed to
be 11.4% for common stock, 10.0% for preferred stock, and 9.0% for long-
term debt. The weighted cost of capital (WCC) is 10.0%. The discount
rate (r) is equal to the weighted cost of capital.
Other economic factors used in financial calculations are a 10%
investment tax credit rate, 50% State plus Federal income taxes, 2.5%
property tax and insurance, and an annual inflation rate of 6%. Salvage
value is assumed to be less than 10% and equal to removal cost.
B-54
a
-------
Weighted cost of capital is calculated as follows:
WCC = (fraction long-term debt)(long-term debt cost, %) +
(fraction preferred stock) (preferred stock cost, %) +
(fraction common stock)(common stock cost, %)
The sinking fund factor method of depreciation is used since it is
equivalent to straight line depreciation levelized for the economic life
of the facility using the weighted cost of capital. The use of the
sinking fund factor does not suggest that regulated utilities commonly
use sinking fund depreciation. All factors and rates are expressed as
decimals. The equation is:
SFF = (WCC)/((I + WCC)Ne -1)
where: SFF = sinking fund factor
WCC = weighted cost of capital
Ne = economic life in years
An annual interim replacement (retirement dispersion) allowance of
0.56% for new plants and 0.67% for existing plants is also included as
an adjustment to the depreciation account to ensure that the initial
investment will be recovered within the actual rather than the forecasted
life of the facility. Since power plant retirements occur at different
ages, an average service life is estimated. The type S-l Iowa State
(17) retirement dispersion pattern is used in these premises. The S-l
pattern is symmetrical with respect to the average-life axis and the
retirements are represented to occur at a low rate over many years. The
interim replacement allowance does not cover replacement of individual
items of equipment since these are covered by the maintenance charge.
Tax preference allowances are incentives designed to encourage
investment as a stimulus to the overall economy. The basic accounting
method used is the flow through method which passes the tax advantage to
revenue requirements as soon as they occur.
Using the sum of the years digits method, which allocates costs
early in the life of the facility, the accelerated tax depreciation
(ATD) is calculated as follows:
ATD = (2)(CRFe)(Nt - (l/CRFt))/(Nt)(Nt + 1)(WCC)
where: CRFe = capital recovery factor (WCC + SFF) for the economic life
CRFt = capital recovery factor (WCC + SFF) for the tax life
Nj. = tax life in years
B-55
-------
Levelized accelerated tax depreciation is calculated as follows:
LAID = (AID - SLD)(ITR)/(1 - ITR)
where: SLD = straight line depreciation
N^ = book life in years
ITR = income tax rate
The levelized investment tax credit is calculated as follows :
LITC = (CRFe) (investment tax credit rate) /(I + WCC) (1 - ITR)
The levelized income tax is calculated as follows:
LIT = (CRFb + AIR - SLD)(1 - ((debt ratio x debt cost) /WCC))
(ITR) /(I - ITR)
where: LIT = levelized income tax
AIR = annual interim replacement
The capital charges are applied as a percentage of the total capital
investment, including land and working capital. Although land and most
of working capital cannot be depreciated and are not subject to investment
tax credit, their inclusion has an insignificant effect on capital
charges.
Levelized Operating and Maintenance Costs —
Assuming a constant inflation rate, the levelized operating and
maintenance costs are determined by multiplying the first-year operating
and maintenance costs by an appropriate levelizing factor, Lf. The
levelizing factor is calculated as follows:
Lf = CRFe (K + K2 + K3 + --- + KN)
= CRFe (K(l - K))/(1 - K)
where: CRFe = capital recovery factor (WCC + SFF) for the economic
life (see the discussion of capital charges)
K = (1 + i)/(l + r); present worth of an inflationary value
i = inflation rate
r = discount rate
N^ = book life in years
B-56
-------
An inflation rate of 6% (i = 0.06) and a discount rate of 10% (d = 0.10)
are used for new units. Values of Lf for power units with a remaining
life of 15, 20, 25, and 30 (new unit) years are shown in Table B-36.
The first-year operating and maintanance costs are multiplied by the
appropriate Lf to obtain the levelized operating and maintenance costs.
TABLE 36. LEVELIZING FACTORS
1
a.
b.
c.
Book3
.ife, NK
15
20
25
30C
K =
0.
0.
0.
0.
Same as economic
Discount rate (r)
New units.
1 + i K
1 + r
96364
96364
96364
96364
life (Ne)
of 10%.
(1
1
11
13
16
17
and
_KNb)
- K
.2965
.8669
.0028
.7775
tax life
CRFBb
(r, Nb)
0.
0.
0.
0.
(N
13147
11746
11017
10608
t>-
Levelizing
factor, Lf
1
1
1
1
.485
.629
.763
.886
SI SYSTEM NOTATION
The SI system of metric units is not used as the primary numerical
system in these premises because of the widespread use of traditional
units in correlative and supportive literature and general practice.
Use of the SI system is not standardized in the utility industry although
steps in this direction are being made (18). The SI system specifies a
number of rules of usage, form, and style in addition to the numerical
standards. These too are part of the SI system and should be followed
when using it. Detailed procedures for use of SI conventions in the
primary data or conversion to SI convention are readily available in the
literature. A detailed general guide to SI convention is available in
ASTM E 380 79 (19). To provide uniformity in the comparison of data
developed from these premises such a guide should be consulted in using
the SI system.
B-57
-------
REFERENCES
1. Federal Register, 1979, New Stationary Sources Performance Standards;
Electric Utility Steam Generating Units, Vol. 44, No. 113, June 11,
pp. 33580-33624.
2. J. A. Cavallaro, M. J. Johnson, and A. W. Deubrouck, 1976, Sulfur
Reduction Potential of the Coals of the United States, Bureau of
Mines Report of Investigation RI 8118, U.S. Bureau of Mines,
Washington, B.C.
3. J. W. Hamersima and M. L. Kraft, 1975, Applicability of the Meyers
Process for Chemical Desulfurization of Coal: Survey of Thirty-
Five Coals. EPA-650/2-74-025-A, U.S. Environmental Protection
Agency, Washington, B.C.
4. Bureau of Mines, 1946, Bureau of Mines Information Circular 7346,
Bepartment of the Interior, Washington, B.C. Bescribes Rosin and
Rammler chart.
5. National Electric Reliability Council, 1980, 1980 Summary of Projected
Peak Bemand, Generating Capability, and Fossil Fuel Requirements,
National Electric Reliability Council, Princeton, New Jersey.
6. National Coal Association, 1979, Steam-Electric Plant Factors, 1979,
National Coal Association, Washington, B.C.
7. G. R. Fryling, 1966, Combustion Engineering, Second Edition,
Combustion Engineering, Inc., New York.
8. Babcock & Wilcox, Steam/Its Generation and Use, Babcock & Wilcox
Co., New York, 1975.
9. G. D. Friedlander, 1980, Sixteenth Steam Station Design Survey,
Electrical World, Vol. 194, No. 8, Nov. 1980, pp. 67-82.
10. Bepartment of Energy, 1978, Steam-Electric Plant Construction Cost
and Annual Production Expenses 1977, BOE/EIA-0033/3 (77), U.S.
Bepartment of Energy, Washington, B.C., BOE, 1979, Steam-Electric
Plant Air and Water Quality Control Bata, for the Year Ended
Becember 31, 1976, BOE/FERC 0036, U.S. Bepartment of Energy,
Washington, B.C. These are issued annually.
11. Federal Register, 1971, Standards of Performance for New Stationary
Sources, Vol. 36, No. 247, Bee. 23, pp. 24876-24895.
12. Chemical Engineering, 1976, 1977, 1978, 1979, Economic Indicators,
Volumes 83, 84, 85, and 86.
13. V. W. Uhl, 1979, A Standard Procedure for Cost Analysis of Pollution
Control Operations, Volumes I and II, EPA-600/8-79-018a and EPA-
600/8-79-018b, Research Triangle Park, North Carolina.
B-58
-------
14. The Richardson Rapid System, Process Plant Estimation Standards,
Volumes I, III, IV, 1978-1979 Edition. Richardson Engineering
Services, Inc., Solano Beach, California.
15. EPRI, 1978, Technical Assessment Guide, EPRI PS-866-SR, Special
Report, June 1978, Electric Power Research Institute, Palo Alto,
California.
16. E. L. Grant and W. G. Ireson, 1970, Principles of Engineering
Economy, Ronald Press, New York.
17. P. H. Jeynes, 1968, Profitability and Economic Choice, First
Edition, The Iowa State University Press, Ames, Iowa.
18. M. G. McGraw, 1980, Metrication in the Electric Utility Industry,
Electrical World, Vol. 194, No. 7, October 1980, pp. 69-100.
19. ASTM E 380 79, 1980, Annual Book of ASTM Standards, Part 41,
American Society for Testing and Materials, Philadelphia,
Pennsylvania.
B-59
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-------
APPENDIX C
DETAILED DESCRIPTIONS OF MODEL INPUT VARIABLES
C-l
-------
TABLE C-l. MODEL INPUTS - FORTRAN VARIABLE NAMES
Line
1 XINPUT XBC XALK XSSV XSRHT
2 OUTPUT XHGAS XWGAS XRAIR XRGAS XSRHO XSKGAS XSSO XDIS XSTR XGPM XIT
3 IRPT IEQPR IWTBAL
A Case identification (up to 72 alphanumeric characters)
5 XESP MW BHR HVC EXSAIR THG XRH KEPASS KPAS02 PSS02X KCLEAN WPRCVR WPPSAC WPPSRC TSK TSTEAM HVS
6A INPOPT WPC WPH WPO WPN WPSUL WPCL WPASH WPH20 SULO ASHO IASH ASHUPS ASHSCR
6B INPOPT VC02 VHCL VS02 V02 VN2 VH20 SCFM WASH SULO ASHO IASH ASHUPS ASHSCR
7 XLG VLG VTR V VRH IS02 XS02 TR XSR SRIN XIALK IADD WPMGO XMGOAD AD ADDC WPI WPM ASHCAO ASHMGO
8 WPS PSD RS PSC IFOX OX SRAIR PSF FILRAT PHLIME IVPD VPD DELTAP PRES IFAN
o 9 ISCRUB XNS XNG HS RAIN SEEPRT EVAPRT WINDEX HPTONW NSPREP NOTRAN NOREDN PCNTRN
^ 10 ISLUDG SDFEE PSAMAX ACRE$ PDEPTH PMXEXC DISTPD ILINER XLINA XLINB
11 ENGIN ARCTEC FLDEXP FEES CONT START CONINT XINT PCTMNT PDMNTP XINFLA IECON PCTOVR XLEVEL/PCTADM
CAPCHG/UNDCAP PCTMKT/PCTINS
12 ITAXFR TXRATE FRRATE SERVRT ROYALT IOTIME OTRATE INDPND PENGIN PARCH PFLDEX PFEES PCONT PSTART
13 UC(1) - UC(9) MINDEX LINDEX YRINV YRREV
14 IOPSCH PNDCAP BAGDLP BAGRAT BGCOST BGLIFE EFFPS ESPDLP RESIST SCARAT ICEPYE CHPIOX
15 IYROP
16 IA(1) - IA(10)
17 IA(11) - IA(20)
18 IA(21) - IA(30)
19 END or NEXT
Note: Lines 15-18 are needed only if IOPSCH = 3. The number of entries required on lines 16-18 depends on the
number of years specified with the IYROP variable on line 15. Although 30 years is normally used as a
maximum plant life, up to 50 years are allowed and up to two additional lines may be used for IA(31) - IA(50) .
-------
TABLE C-2. MODEL INPUT VARIABLE DEFINITIONS
Line No. Variable
1 XINPUT
1 XBC
1 XALK
1 XSSV
1 XSRHT
2 OUTPUT
2 XHGAS
2 XWGAS
2 XRAIR
2 XRGAS
2 XSRHO
2 XSKGAS
Definition
Option to control the printing of input data
variables. If a value of zero is selected,
no input data variables are printed; the
options to individually control the printing
of input variables are ignored.
Controls the printing of boiler characteristics
input variables.
Controls the printing of alkali input
variables.
Controls the printing of scrubber system input
variables .
Controls the printing of steam reheater input
variables.
Option to control the printing of model output.
If a value of zero is selected, no output
listings are printed and the options to
individually control the printing of output
listings are ignored.
Controls the printing of calculated properties
of hot gas to scrubber.
Controls the printing of calculated properties
of wet gas from scrubber.
Controls the printing of calculated properties
of reheater air.
Controls the printing of calculated properties
of reheater gas (oil-fired reheater only) .
Controls the printing of calculated properties
of inline steam reheater.
Controls the printing of calculated properties
of stack gas.
Units or values
0 = no input
data printed
1 = print input
variables accord-
ing to individual
input print options
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = :io print
1 = print
0 = no output data
printed
1 = print output
listings according
to individual
output print options
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
(continued)
C-3
-------
TABLE C-2 (continued)
Line No.
2
2
2
2
2
3
3
3
4
5
5
5
5
5
5
Variable
XSSO
XDIS
XSTR
XGPM
XIT
IKPT
IEQPR
IWTBAL
CAS BID
XESP
MW
BHR
HVC
EXSAIR
THG
Definition
Controls the printing of calculated scrubber
system parameters.
Controls the printing of calculated properties
of system discharge stream.
Controls the printing of calculated properties
of scrubber system internal streams (excluding
sludge discharge and makeup water) . This
option does not affect the printout of total
stream flow rate.
Controls printing of total flow rates (gpm
and Ib/hr) of internal streams (excluding
sludge discharge and makeup water) .
For the iterative calculation of stoichiometry ,
this option controls the printing of the
iteration number and of the current and the
preceding stoichiometry values.
Option to select either a short-form printout
(totals only) or a long-form printout.
Controls the printing of the equipment list.
Controls the printing of calculated properties
of water balance.
Case identification - this field is free form
and may be up to 72 characters in length.
Particulate collection option
No mechanical collector available
Mechanical collector available
Print internal model examples (costs are not
included in FGD costs)
Electric power output
Boiler heat rate
Heating value of coal
Excess air
Temperature of hot gas to scrubber
Units or values
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = no print
1 = print
0 = short print
1 = long print
0 = no print
1 = print
0 = no print
1 = print
n
1
2
megawatts
Btu/kWh
Btu/lb
percent
°F
(continued)
C-4
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
6A
XRH Reheat option
No reheat
Inline steam reheater (XRH value = 2)
is the only type of reheat available at
this time.
KEPASS Emergency bypass option
No emergency bypass
Emergency bypass
KPAS02 Partial scrubbing/bypass option
No partial scrubbing/bypass
Partial scrubbing/bypass
PSS02X Percent SC>2 removal in the scrubber when
partial scrubbing/bypass is specified
KCLEAN Coal cleaning option
No coal cleaning
Coal cleaning
WPRCVR Percent weight recovery (Ib clean coal per
Ib raw coal) when coal cleaning is specified
WPPSAC Weight percent of pyritic sulfur plus ash in
cleaned coal when coal cleaning is specified
WPPSRC Weight percent of pyritic sulfur in raw coal
when coal cleaning is specified
TSK Temperature of stack gas
TSTEAM Temperature of reheater steam
HVS Heat of vaporization of reheater steam
The composition input specified on either line
6A or 6B depends on the composition option,
INPOPT. If a coal composition will be input
(INPOPT = 1) then line 6A is used. If a flue
gas composition will be input
(INPOPT = 2) then line 6B is used.
INPOPT Composition input option
Coal composition will be input using line 6A
(continued)
0
2
0
1
percent removal
0
1
percent
weight percent
weight percent
F
Btu/lb
C-5
-------
TABLE C-2 (continued)
Line "No. Variable
Definition
Units or values
6A WPC }
6A WPH }
6A WPO }
6A WPN }
6A
6A
6A
6A
6A
6A
6A
6A
6A
WPSUL }
WPCL }
WPASH }
WPH20 }
SULO
ASHO
IASH
ASHUPS
ASHSCR
Amount of component (C, H, 0, N, S, Cl, ash,
H20) in coal. WPSUL is the total of both
organic sulfur and pyritic sulfur.
Sulfur to overhead as SC>2 gas (remainder goes
to bottom ash).
Ash to overhead as particulates (remainder goes
to bottom ash).
Unit of measure option for particulate removal
Default to model assumptions
Percent removal
Pounds particulates per MBtu
Upstream removal (percent) with scrubber
default
(The actual values for particulate removal are
provided by the ASHUPS and ASHSCR variables that
immediately follow.)
Value for particulate removal upstream from
scrubber (Unit of measure is indicated by the
IASH option above.)
Value for particulate removal within scrubber
(Unit of measure is indicated by the IASH
option above.)
weight percent
weight percent
weight percent
(continued)
C-6
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
6B
6B
6B
6B
6B
6B
6B
6B
6B
6B
6B
INPOPT
VC02 1
VHCL 1
VS02) •
V02 }
VN2 }
VH20}
SCFM
WASH
SULO
AS HO
Composition input option
Flue gas composition will be input using
line 6B
Amount of component (C02 , HC1, SC>2, 02, N
and H20) in flue gas
Standard cubic feet per minute (60 F), gas
from boiler
Pounds of ash per hour in hot gas from boiler
Should be set to 100 when flue gas composition
is input
Should be set to 100 when flue gas composition
is input
6B
6B
6B
7
IASH
ASHUPS
ASHSCR
XLG
See line 6A
See line 6A
See line 6A
L/G ratio ii
(Refer to the XSR option on the following
page.)
7 VLG L/G ratio in venturi
7 VTR Venturi/oxidation hold tank residence time.
This variable is used to specify residence time
in the second effluent tank when two tanks are
specified. Two tanks may be specified by the
forced oxidation option (IFOX, line 8), the
scrubber option (ISCRUB, line 9), or both. VTR
should be set to zero when only one effluent
tank is used (see the TR variable below).
(continued)
volume percent
scfm
Ib/hr
gal /kft
gal /kft
minute
07
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
7
7
V
VRH
Scrubber gas velocity (superficial)
Superficial gas velocity through reheater
ft/sec
ft/sec
(face velocity)
IS02 Unit of measure option for S0_ removal
SC>2 to be removed is a percent value
S02 emission concentration is a pounds
S02/MBtu value
S02 emission concentration is a ppm value
(The actual value for 862 removal is provided
by the XS02 variable that immediately follows.)
Revised NSPS (1978 Federal Register)
XS02 Value for S02 to be removed. Unit of measure
is indicated by the IS02 option above; refer
to the XSR option below for additional require-
ments. The value for XS02 is automatically
calculated when IS02 = 4 and any input value
will be ignored.
TR Recirculation/oxidation hold tank residence
time. This variable is used to specify
residence time in the effluent tank when only
one tank is specified. If two tanks are
specified, TR specifies residence time in
the first tank (see the VTR variable above).
XSR Stoichiometry, L/G in scrubber, and S02 removal
option. This option controls model processing
of the Stoichiometry value, SRIN, below; the
L/G ratio in the scrubber, XLG, on the preceding
page; and the S02 to be removed, XS02, above
(if XS02 is required then IS02 is also required).
SRIN, XLG, and XS02 (also IS02) will be processed
as input variables. (No checks are made for
validity or consistency among the specified
values.)
XLG and XS02 (also IS02) will be processed as
input variables and SRIN will be calculated
by the model.
(coninued)
minute
C-8
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
SRIN
XIALK
SRIN and XS02 (also IS02) will be processed
as input variables and XLG will be calculated
by the model.
SRIN and XLG will be processed as input
variables; the value for SC>2 to be removed
(XS02) will be calculated by the model; and
all three units of measure (IS02) will be
provided in the calculated results. Any user
input values for IS02 and XS02 will be ignored.
Value for stoichiometry (refer to the XSR
option above)
Alkali addition option
Limestone
Lime
IADD Chemical additive option
No chemical additive
MgO added
Adipic acid added
WPMGO Soluble MgO in limestone or lime
XMGOAD Soluble MgO added to system (used only when
MgO added, see IADD above)
AD Adipic acid added to system (used only when
adipic acid added, see IADD above)
ADDC Adipic acid degradation constant (used only
when adipic acid added, see IADD above)
WPI Insolubles in limestone-lime additive
WPM Moisture in limestone-lime additive
ASHCAO Soluble CaO in particulates
(continued)
mols CaC03 added
as limestone per
mol S02 absorbed
0
1
2
weight percent
dry basis
pound soluble MgO/
100 pound limestone
ppm
weight percent
dry basis
lb/100 pound dry
additive
weight percent
C-9
-------
TABLE C-2 (continued)
Line No.
7
8
8
8
8
8
Variable
ASHMGO
WPS
PSD
RS
PSC
IFOX
Definition
Soluble MgO in particulates
Solids in recycle slurry to scrubber
Solids in sludge discharge
Clarifier solids settling rate
Percent solids in clarifier underflow
Forced oxidation option
No forced oxidation
Forced oxidation in a single effluent tank
Forced oxidation in the first of two
Units
weight
weight
weight
ft/hr
weight
0
1
2
or values
percent
percent
percent
percent
effluent tanks
Forced oxidation in the disposal feed tank
OX Oxidation of sulfite in scrubber system
SRAIR Air stoichiometry value
PSF Percent solids in filter cake
FILRAT Filtration rate
PHLIME Recirculation liquor pH for lime system (value
is ignored for limestone system)
IVPD Venturi AP option
AP is input in inches HnO
Throat velocity (ft/sec) is input and the
corresponding VPD is calculated
VPD Value for either AP or throat velocity
indicated by the IVPD option above
DELTAP Override AP for entire system
PRES Scrubber pressure
IFAN Fan option
Forced draft fans
Induced draft fans
mol percent
g-atoms 0/g-mol
S02 absorbed
percent
tons/ft^/day
inch H20 or (ft/sec)
inch
psia
(continued)
C-10
-------
TABLE C-2 (continued)
Line No.
9
9
9
9
9
9
9
9
9
9
9
9
9
10
Variable
ISCRUB
XNS
XNG
HS
RAIN
SEEPRT
EVAPRT
WINDEX
HPTONW
NSPREP
NOTRAN
NOREDN
PCNTRN
ISLUDG
Definition
Scrubbing option
Spray tower
TCA
Venturi-spray tower, two effluent tanks
Venturi-spray tower, one effluent tank
Venturi-TCA, two effluent tanks
Venturi-TCA, one effluent tank
Number of TCA stages
Number of TCA grids
Height of spheres per stage
Annual rainfall
Seepage rate
Annual evaporation
Limestone hardness work index factor value
5-15. (Example: 10)
Fineness of grind index factor (see Table C-3)
Number of spare preparation units
Number of operating scrubber trains
Number of spare scrubber trains
Entrainment level as percentage of wet gas
from scrubber. (Example: 0.1)
Sludge disposal option
Onsite ponding
Thickener - ponding
Thickener - fixation (fee)
Thickener - filter - fixation (fee)
Units or values
1
2
3
4
5
6
inch
in . /yr
cm/sec
in . /yr
wi
hp/ton
(0-9)
weight percent
1
2
3
4
10 SDFEE Sludge disposal fee. (Either an actual
value or a zero value must be provided;
refer to the ISLUDG option above.)
$/ton dry sludge
(continued)
Oil
-------
TABLE C-2 (continued)
Line No.
10
10
10
10
10
10
10
10
11
11
11
11
11
11
11
11
Variable
PSAMAX
ACRE$
PDEPTH
PMXEXC
DISTPD
ILINER
XLINA
XLINB
ENGIN
ARCTEC
FLDEXP
FEES
CONT
START
CONINT
XINT
Definition
Total available land for construction of pond
Land cost
Final depth of sludge in pond
Maximum excavation depth
Distance from scrubber area to pond
Pond lining option
Clay liner
Synthetic liner
No liner
(Refer to the XLINA and XLINB variables that
immediately follow.)
If ILINER = 1 , XLINA = clay depth
If ILINER = 2, XLINA = material unit cost
If ILINER = 3, XLINA = 0
If ILINER = 1, XLINB = clay cost
If ILINER = 2, XLINB = labor unit cost
If ILINER = 3, XLINB = 0
Engineering design and supervision
Architect and engineering contractor
Construction field expenses
Contractor fees
Contingency
Allowance for startup and modifications
Interest during construction
Cost of capital
(continued)
Units or values
acres
$/acre
feet
feet
feet
1
2
3
inch
$/yd2
$/yd2
percent
percent
percent
percent
percent
percent
percent
percent
C-12
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
11 PCTMNT Maintenance rate, applied as percent of direct percent
investment excluding pond cost
11 PDMNTP Pond maintenance rate, applied as percent of percent
direct pond investment
11 XINFLA Inflation factor (used only when unlevelized percent
lifetime revenue requirements are calculated,
see Appendix B)
11 IECON Economic premises option (see the Model Descrip-
tion Section and Appendix B)
TVA/EPA economic premises beginning 12/5/79 1
TVA/EPA economic premises prior to 12/5/79 0
11 PCTOVR Plant overhead rate, applied as percent of percent
conversion costs less utilities
11 XLEVEL/ The use of this variable depends on the economic percent
PCTADM premises specified (IECON, line 11). If new
premises are specified (IECON = 1), XLEVEL spec-
ifies the levelizing factor to be applied to first-
year operating and maintenance costs to obtain
levelized lifetime costs. If XLEVEL is set to zero
there is no levelizing and a lifetime revenue sheet
is generated. If old premises are specified (IECON
= 0), PCTADM specifies the administrative research
and service overhead rate, applied as a percent of
operating labor and supervision.
11 CAPCHG/ If new premises are specified (IECON = 1) CAPCHG percent
UNDCAP specifies levelized annual capital charges applied
as a percent of total capital investment. If old
economic premises are specified (IECON =0) UNDCAP
specifies the annual capital charge basis for
undepreciated investment.
11 PCTMKT/ If new premises are specified (IECON = 1) PCTMKT percent
PCTINS specifies marketing costs applied as a percent of
byproduct credit (applies only to processes with
a salable byproduct). If old economic premises
are specified (IECON =0) PCTINS specifies the
rate for insurance and interim replacements
applied as a percent of total capital investment.
12 ITAXFR Sales tax and freight option
No sales tax or freight 0
Sales tax and freight rates applied based 1
on TXRATE and FRRATE below
(continued)
C-13
-------
TABLE C-2 (continued)
Line No. Variable
Definition
Units or values
12 TXRATE Sales tax rate (applied only when ITAXFR percent
above set to 1)
12 FRRATE Freight rate (applied only when ITAXFR percent
above set to 1)
12 SERVRT Services, utilities, and miscellaneous, applied percent
as a percent of total process capital
12 ROYALT Royalties, applied as a percent of total percent
process capital
12 IOTIME Overtime labor option
No overtime labor 0
Overtime labor on 7% of total labor based on 1
the OTRATE rate below
12 OTRATE Overtime labor rate (applied to 7% of total
labor) Example: 1.5
12 INDPND Separate indirect investment factors option for
pond construction
No separate indirect factors for pond construe- 0
tion (same as process indirects)
Separate indirects for pond construction speci- 1
fied by PENGIN, PARCH, PFLDEX, PFEES, PCONT,
and PSTART below
12 PENGIN Pond construction engineering design and percent
supervision (applied only when INDPND above
set to 1)
12 PARCH Pond construction architect and engineering percent
contractor (applied only when INDPND above
set to 1)
12 PFLDEX Pond construction field expenses (applied only
when INDPND above set to 1)
percent
12 PFEES Pond construction contractor fees (applied percent
only when INDPND above set to 1)
12 PCONT Pond construction contingency (applied percent
only when INDPND above set to I)
12 PSTART Allowance for pond startup and modification percent
(applied only when INDPND above set to 1)
(continued)
C-14
-------
TABLE C-2 (continued)
Line No.
13
13
13
13
13
13
13
13
13
13
13
13
13
14
14
14
14
14
Variable
UC (1)
UC (2)
UC (3)
UC (4)
UC (5)
UC (6)
UC (7)
UC (8)
UC (9)
MINDEX
LINDEX
YRINV
YRREV
IOPSCH
PNDCAP
BAGDLP
BAGRAT
BGCOST
Definition
Limestone unit cost
Lime unit cost
MgO unit cost
Adipic acid unit cost
Operating labor and supervision unit cost
Steam unit cost
Process water unit cost
Electricity unit cost
Analyses unit cost
Chemical Engineering material cost index
(see Table B-23)
Chemical Engineering labor cost index (see
Table B-23)
Investment year cost basis
Revenue requirement year cost basis
Operating profile option
TVA profile
FERC profile
User input profile (Refer to the IYROP and
IA(n) options on lines 15-18.)
Levelized operating profile, 5500 hr/yr
Expected pond capacity (controls pond design
capacity; if 100% of sludge is to be ponded
over the life of the unit, input 1.0; if 80%
of sludge is to be ponded, input 0.80.)
Baghouse pressure drop
Baghouse ratio (typically = 0.8)
Bag cost
(continued)
C-15
Units or values
$/ton
$/ton
$/ton
$/ton
$/man-hr
$/klb
$/kgal
$/kWh
$/hr
year
year
1
2
3
4
inches H20
open ft2
actual ft2
$/ft2
-------
TABLE C-2 (continued)
Line No .
14
14
14
14
Variable
BGLIFE
EFFPS
ESPDLP
RESIST
Definition
Bag life
ESP rectification efficiency (Example - .65)
ESP pressure drop
Resistivity option (high or low)
Assume u = 20 ft/min
Assume a) = 30
Units or values
years
decimal
inches t^O
1
2
14 SCARAT SCA ratio
Contingency or safety factor (fractional)
to apply to calculated collected area
14 ICEPYE Chemical Engineering plant index year
14 CHPIOX Chemical Engineering plant index (see
Table B-l)
15 IYROP Years remaining life (lines 15 through 18 are
needed only if the 10PSCH variable, line 14,
is set to 3. Although only 30 years are
shown, up to 50 years may be used and up
to two additional lines are used for
- IA(50)
year
16
17
18
19
IA(20)
IA(30)
END or
NEXT
Operating hr/yr (input only 10 years per line)
Operating hr/yr (input only 10 years per line)
Operating hr/yr (input only 10 years per line)
"END" terminates further execution. "NEXT" execu-
tion will continue with the next group of input
variables. (If variable IOPSCH on line 14 is not
equal to 3, line 15 will be the "END" or "NEXT"
line.)
a. Required for sizing hot ESP. Drift velocity (w) is related to percent sulfur in the
cold ESP model, but is an input for the hot ESP model.
C-16
-------
TABLE C-3. LIMESTONE FINENESS OF GRIND INDEX FACTOR
Ground limestone product size distribution Index factor (HPTONW)
80%- micron
129
113
98
85
74
62
58
51
44
40
37
31
24
% -200 mesh
60
65
70
75
80
85
86
90
93
95
% -325 mesh
70
75
80
85
90
95
hp/ton
1.11
1.22
1.35
1.51
1.72
2.04
2.19
2.54
3.04
3.40
3.64
4.44
5.70 Base
Data from KVS Rock Talk Manual, Kennedy Van Saun Corporation,
Danville, Pennsylvania, 1974. Total ballmill horsepower is
calculated using the limestone hardness work index factor, wi,
and the fineness of grind index factor as follows: hp = (tons/hr
limestone)(wi)(fineness of grind index factor).
C-17
-------
APPENDIX D
BASE CASE INPUT AND PRINTOUT
D-l
-------
o
I
TABLE D-l. BASE CASE PRINTOUT
11111
111111111111
111
BASE MANUAL
2 500 9500 11700 39 300 2 1 0 0 0 0 0 0 175 470 751
1 66.7 3.8 5.6 1.3 3.36 0.1 15.1 4.0 92 80 2 .06 .03
90 0 0 10 25 4 0.0 10 1 0.0 1 0 0.15 000 4.85 500
15 40 0.2 40 0 30 0.0 80 1.2 0.0 090 14.7 1
1 0 0 0 35 .0000005 32 10 5.70 1 4 1 .1
1 0 9999 5000 0 25 5280 1 12 4.75
7 2 16 5 10 8 15.6 10 8 3 6 1 60 1.886 14.7 0.0
1 4 3.5 6 0 1 1.5 1 2 1 8 5 10 0
8.50 75.00 460 1200 15 2.5 0.14 0.037 21.00 336.1 245.5 1982 1984
4 1 5 .8 1.0 3 .65 1 1 1.1 1982 297.9
END
(continued)
-------
TABLE D-l (continued)
TENNESSEE VALLEY AUTHORITY
SHAMNEE LIMESTONE OR LIME SCRUBBING PROCESS
COMPUTERIZED DESIGN-COST ESTIMATE MODEL
REVISION DATE DECEMBER 10, 1980
G
OJ
(continued)
-------
TABLE D-l (continued)
BASE MANUAL CASE 1
*** INPUTS ***
BDILtR CHARACTERISTICS
I'EGiKATTS • 500,
BOILER HEAT RATE • 9500, BTU/MH
EXCESS AIR » 39. PERCF.'IT, INCLJD1NG LEAKAGE
HUT OAS TEMPERATURE • 300. DEG F
COAL Al.ALYSIS.. ,-,-r 1. AS FIRED I
C H Q N 5 CL ASH H20
66.70 3.80 5.60 1.30 3.36 0,10 15,10 4.00
SULFUR OVERHEAD . 92,0 PERCENT
ASH 'JVEKHEAD = 30.C PERCENT
HFATINC VALUE PF CGAL * ll'OO, STJ/LB
EFFICIEMCY/ EMISSION,
FLY.'liH SsEMCVAL '/. LBS/M BTIJ
UF SCRUBBER 99,4 0.06
WITHIN SCRUBBER 50.0 0.03
COST OF UPSTREAi FLYASH REMOVAL EXCLUDED
ALKALI
LIMESTONE I
CAC03 • 95,00 WT * DRY BASIS
SOLUBLE HOD • 0,15
INERTS « *.B5
MOISTURE CONTENT • 5.00 LB H20/100 LBS DRY LIMESTONE
LIMESTONE HARDNESS UORK INDEX FACTOR • 10.00
LIMESTONE DEGREE OF GRIND FACT3R • 5,70
f-LY ASH 1
SOLUBLE CAD • 0,0, WT
SOLUBLE IGLI • 0,0
INERT5 • 100,00
(continued)
-------
TABLE D-l (continued)
PA* MAT1RIAL HAiDLMG ARfcA
DUMBER JF REDUNDANT ALKALI PREPARATION UNITS
SCFUBBcR SYiTtt- VARIABLES
ClirdER UF L'l-ERATINC, SCRUBBING T^AI'.S » 4
!U"BFR IF BcDUNUANT SCRU63ING TRAILS • 1
SPPAY TjwER LlfloIB-Tn-GAS RATIO • 90, GAL/1000 ACFISaTL,)
SPRA/ TilV.ER GAS VELOCITY = 10. C FT/SEC
IIIPUCES DRJlFT SCRUBBER FAN OPTI3N
SCSUijB'P PRFSSUi <• • U.7 P5IA
St'2 CJI-CE'lTkftTlL."! II! SCRUBBER DJTLET GAS TU BE CALCULATED FDR NSPS
STnICHI.lMET".Y 8,\Tln TD BE CMCOLATEU
EMTPAMMEUT LEVtL « 0.10 WT %
EHT KEMDEKE TIME > 10.0 HIN
SUJ JXIUlZfu T SYSTEM > 30.0 PERCENT
SfLIOS IN RECI&UJLATED SLURRY • 15,0 WT X
SI'LIOS ^ISPI'SAL SYSTEii
CC'ST 'IF LAT'I' = 5000,00 DOLLARS/ACRE
SPLICS IN SYSTEI' SLUDGE DISCHARGE • *0.0 »T %
"AXIl'U" PL'KJ APEA m 9999. ACRES
riAXIMU" EXCAVATJUN s 25,00 FT
DISTANCE TO PG'.r » 5280. FT
POND LINED :. ITH 12.0 INCHcS CLAY
(continued)
-------
TABLE D-l (continued)
STEAM RE-HEATER (IN-LINE)
SATURATED STEAfi TEMPERATURE • 470. DEC F
HEAT nf VAPHRIZATinN OF STEAM • 751. BTU/LB
nuTLET FLUE GAS TEMPERATURE • 175. DbG F
SUPERFICIAL GAS VELOCITY (FACE VELOCITY) = 25.0 FT/SEC
ECONOMIC CHARACTERISTICS
1979 TVA-EPA ECONOMIC PRECISES
PROJECTED REVEfuE KEOU IKEMENTS INCLUDE LEVELIZEO OPERATING AND MAINTENANCE COSTS
RATE . 1.Sat TIMES FIRST YEAR DERATING AMD MAINTENANCE COSTS
I—| FREIGHT INCLUDED III TOTAL INVESTMENT
| FREIGHT RATc - 3.5 X
ON
SALES TAX II.CLUUED IN TOTAL INVESTMENT
SALtS TAX RATE » 4,0 %
LABOP rivERTIME INCLUDED IN TOTAL INVESTMENT
QVFRTIi'E RATE • 1,5
INFLATION OOTE • 6,0 x
PROCESS MAINTENANCE • 8.0 %
POI U MAINTENANCE • 3.0 X
IT SR SROLD
1 1.S1 1.50
2 1.51 1.51
(continued)
-------
o
TABLE D-l (continued)
BASt MANUAL
*** OUTPUTS ***
EMERGENCY BY.PASS
EMERGENCY BY-PASS DESIGNED FOR 50.0 *
HOT GAS TO SCRU9BEP
CASE 1
HOLE PERCENT
LB-MOLE/HP.
LB/HR
CD2
HCL
S02
02
N2
H20
12.338
0.00*
0,21*
5.560
75.227
6.654
0.2255E*05
0.1145E+02
0.3914E+03
0.1016E+05
0.1375E+06
0.1216E+05
0.9923£*0b
0.4175E+03
0.2508E+05
0.3251E+06
0.3852E+07
0.2191E+06
SD2 COi>ICENTRAT!UN IN SCRUBBER IMLET GAS • 2142, PPM
• 5.28 LBS / MILLION BTU
FLYASH EMISSION • 0.060 LBS/MILLION BTU
• 0,029 GRAINS/SCF (WfT) OR
285. LB/HR
SOLUBLE CAG IN FLY ASH
SOLUBLE MGO IN FLY ASH
0. LB/HR
U.
HOT GAS FLOh RATE • ,1154E*07 SCF^ ( ftO. DEG Fj 14.7 PSIA)
« ,1687E*07 ACFM (300. DEG f, 14.7 PSIA)
CBRReSPUNDIwG COAL FIRING RATE « ,*060t+06 LB/HR
HOT GAS HUMIDITY • 0.042 LB H23/LB DRY GAS
WET BULB TEliPEkaTURE » 124. DEC F
(continued)
-------
TABLE D-l (continued)
WET GAS FROM SCRUBBER
MOLE PERCENT LB-MQLE/HR LB/HR
CD?
HCL
02
M2
H20
11.713
0.000
0.023
5.169
70.300
12.795
0.2291E+05
0.5726E+OQ
0.4449E+02
0.10UE+05
0.1375E+06
0.2502E+05
0.1008E+07
0.2088E+02
0.2B50E+04
0.3E35E+06
0.3852E+07
502 CONCENTRATION IN SCRUBBER OJTLET GAS • 228. PPH
FLYASH EMISSION • 0,030 LBS/MILLION 8TU
• 0.013 GRAINS/SCF (WET) OR 1*3. LB/HR
TOTAL 'JATER PICKUP • *75, GPM
INCLUDING 11.3 GPM ENTRAINMENT
^ WET GAS FLO.! RATE • ,1235E*07 SCFH ( 60. DEC ft U.7 PSIA)
O . ,1388E*07 ACF« HZ*. DEC f, U.7 PSIA)
00 WET GAS SATURATION HUMIDITY « 3.087 LB H2D/L8 DRY CAS
(continued)
-------
TABLE D-l (continued)
FLUE GAS TO STACK
MOLE PERCENT L8-MOLE/HR LB/HR
C02
HCL
S02
02
N2
H20
11.695
0.000
0.023
5,161
70.187
12.934
0.2291E+05
0.5726E+00
0 , 4449E+02
0.1011E+35
0.1375E+06
0.2533E+35
0.1008E+07
0.2088E+02
0.2B50E*04
0.3235E+06
0.3852E+07
0.4564E+06
CALCULATED SD2 REMOVAL EFFICIENCY • 88.7 X
CALCULATED S02 tHISSIUN • 0.60 POUND* PER MILLION BTU
CALCULATED S02 CONCENTRATION IN STACK GAS • 227. PPM
CALCULATED HCL CONCENTRATION IN STACK <5AS • 3. PPM
S02 REMOVAL CALCULATED FROM SCRJBBER OPERATING
PARAMETERS ANY SPECIFIED REMOVAL/EMISSION VALUES ARE IGNORED
FLYASH EMISSION • 0.030 L8S/MILLION BTU
• 0.013 GRAINS/SCF <*F.T) OR 143. LB/HR
STACK GAS FLOW KATE • ,1237E*07 SCFM ( 60. DEG Ft 1*,7 PSIA)
• ,1511E*07 ACFM (175, DbG ft 14,7 PSIA)
(continued)
-------
TABLE D-l (continued)
a
i
STEAM REHEATER (IN-LINE)
SUPERFICIAL GAS VELOCITY (FACE VELOCITY) • 25.0 f-T/SEC
SQUARE PIPE PITCH . 2 TIMES ACTJAL PIPE O.D.
SATURATED STEAM TEMPERATURE • «70. DEG F
OUTLET FLUF GAS TEMPERATURE " 175. DEG F
REOUIRID HEAT INPUT TO REHEATER • 0.7H58E+08 BTU/HR
STEAM CUNSUMPTION • 0.9930E+05 LBS/HR
GUTSIDE PIPE
DIAMETER/ I'l.
1.00
INCCINEL
COPTEN
TOTAL
PRESSURE DROP
IN. H2a
0.75
REHEATER
OUTSIDE PIPE
ARF.A^ SQ FT
PE^ TRAIN
0.1533E+0*
0.1235E+04
0.?768E+0
-------
•:iiTc? :mlA';CF I PUTS
TABLE D-l (continued)
iAinFALL(IN/VcAR)
pu.lD SEEPAGE: (C 1/StC ]*10**8
PlilD S-VAPtiPATlOM IN/YEAR)
35.
5".
,.'ATr;o SALA'-ICE OUTPUTS
4TLK .WAI L<'-tJLfc
a
I
h AIMrALL !-l<\ GPl!
ALKALI t) , G p ^
T :TAL '^25. G<>M
i. M T L R K OU I * t LJ
i.'j'nrjFirufir;. <.•><.. G?«
FMRAINMF ,T 11. GC'J
r, ISP'^'L ' AT' H 20P. GP^l
i'Y3RAT!fl" -ATED 1?. GPM
CLAPIFIFR E J APGRAT I D'- n. GPs
P" 1U S-VflPHPATIJI f.30. GPM
?t£PAC,E 11"'. GPf
T JTAL WATbK PtOuIRED I^IA, GP^i
,tT "ATEf PLSbUE^ 7i>',. G"".
30^769,
^789 .
3U579.
231707.
i630.
103836.
5876.
n.
30-.255.
5<,947.
70C7.51.
39J672.
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
(continued)
-------
TABLE D-l (continued)
SCRUBBER SYSTEM
THTAL MUMBFR OF SCRUBBING TRAIMS (HPfcRATiNG+REOUNuANTI • 5
SDE RE'iljVAL « 88.fc PERCENT
PARTICIPATE REMOVAL IN SCRUBBER SYSTEM • 50.0 PERCENT
SPRAY TCJWEP PRESSUPi: DROP m 2.Z IN. H20
TOTAL SYSTEM PRESSURE DROP « 7.5 M. M2Q
SPtCIFlED SPRAY TDWER L/G RATIO « 90, liAL/1000 ACHSATB)
LI"t"STGljE AHDIT1DM « 0.5579t+05 L8/HR DRY LIMESTONE
CALCULATED LIKESTOJE STQICHIOHETRY *
1.50 HOLE CAC03 ADDED AS LIMESTONE
PER MOLE (SQ2+2HCL) ASSOk^ED
SOLUBLE CAO FRH, FLY ASrt
TOTAL SOLUBLE M(,0
TOTAL
0.0 MOLE PER M3LE (SU2+2HCL) ABSORBED
O.C1 WLE PER MULE (SU2+2HCL) ABSORBED
1.5L 1PLE SOLUBLE (CA*MG)
PER 10LE (S02*2HCL> ABSORBED
SCPUBBSR I'''LET L I1UUR PH • 5.68
I'A> i UP W4T6R • 7B8. GPM
CROSS-SECTICNAL ARFA PER SCRUBBER
SYST5I1 SLUD&E DISCHARGE
578. SO FT
SPECIES
CASU3 .1/2 H20
CAST> .2H20
CACU3
H20
CA-H.
MG++
SU3--
S04--
CL-
LB-MOLE/HR
0,2*28E»03
0,lOe«E+03
0.1795E+03
0.5764E+04
0.5287E+01
0.2075E+01
0.1934E+00
0. 17256+01
0.1088E+OZ
L3/HR
0.313»E»05
0.17626*05
0.17'66*05
0.1033E«06
0.2119E+03
0.50**E+02
C.154DE*02
0.1657E+03
0.3857E+03
bULJP
COMP,
HT %
44.92
29.25
25.75
LIUU1D
CQMP,
PPM
202*.
082.
US.
1583.
3685.
TOTAL DISCHARGE FLHW RATE « 0.17*4E*06 LB/HR
• 263, C-PM
TOTAL DISSHLi/ED SULIDS IN DISCHARGE LIOUID »
LIOUIu PM • 7,*2
7905. PPM
(continued)
-------
SCFUB6ER SLJRKY BLEED
SPECIES
TABLE D-l (continued)
LP-MOLE/HR L3/HR
CASU3 .1/2 H2C
CASC14 ,?H20
CACQ3
Hzrj
CA++
KG+*
Sfj3--
SIK--
CL-
AD«
TUTAL F|_Un KATE
0.2428E+03
0.102*E+03
0.1795E+03
0.2177E»05
0.1997E+02
0.7839E+01
0.7305E+OC
0.6515E+01
0,4110t+02
0.0
• 0.4652E+06
> 645,
0.313*E*05
0.17o2t+05
0.1796E+CI5
o!3923E*06
0.80"SE*n3
0.190dt*03
0.58«9E+n2
0 ,625flE+03
0.1»57E+C4
0.0
LB/HR
GP1
I
M
U>
TOTAL 5JPERI.ATE RETURN
SPECIES
503—
SO".—
CL-
AU>
TOTAL FLOW KATE
LB-NOLE/HR
0.1219E+02
0.478
-------
LIf-'ESTONE SLURRY FEEP
TABLE D-l (continued)
SPECIES
CAC03
SOLUBLE MOD
INSOLU1LES
H2C1
CA++
MG+ +
SI13—
SU4--
CL-
A0>
TI1TAL
LB-MQLE/HR L3/HR
0.5294E+03
0.2076E+01
0.2048E+04
0.1752E+01
0.6878E+00
0.6409E-01
0.5716E+00
0.3606E+01
0.0
0.5300E+n5
0.8368E+02
0.2706E+04
0.3690E+05
0.7023E+02
O.U72E+02
0.5131E+01
0.127Bt+03
0.0
PATE
0.9297E+05 LB/HR
117. GP1
SUPERNATE RbTURti TO SCRUBBER OR EHT
I
M
-P-
SPfCIES
H2H
CA + +
SU3 —
504 —
CL-
A0<
THTAL FLOW RATE
LB-MDLE/IIO L3/HR
0.1138E+03
0.1044E+02
0.4097E+01
0.3818E+00
0.3405E+01
0.2148E+02
0,0
0.2050E+06
oi9959E+n2
0.3056E+02
0.3270E+03
0.7f>l4E+03
0.0
0.2066E+06 LB/HR
413. GP-I
RECYCLE SLUhRY TO SPRAY TONER
SPECIES
LR-MOLE/HR LB/HR
CAS03 .1/2 H2D
CASQ4 .2H2D
CACD3
INSULUBLES
H20
HG++
S03--
S04—
CL-
AD«
TOTAL FLOU KATE
0.3589E+03
0. 15146+05
0.2A53E+03
0.3219E+07
0.2952E+04
0.1139E+04
0.1080E+03
0.9631E+03
0.6076E+04
0.0
» 0.6876E+08
• 124890,
0.4»33E+07
0.2605E+07
0.2656E+07
0 1 42 1 OE +06
0.3799E+08
0.1183E+06
0.2817E+03
o!925lE+05
o!o
LB/HR
GP1
(continued)
-------
FLUE GAS CODLIHC SLURRV
SPECIES
TABLE D-l (continued)
LB-HDLE/HR L8/HR
C1S03 .1/2 H2D
CASD4 .2H20
CACD3
IMS OLUB L E s
H2D
CA+ +
I16+ +
503 —
S
TI1TAL FLDK hATE
0.1595E*04
0.6727E+03
0.1179E*04
0.1431E*06
0.1312E+03
0.5150E+02
0.4800E+01
0.4280E+02
0.2700E+03
0.0
• 0.3056E+07
• 5551,
0.2059E*06
0.115oE*06
0.11806*06
01 R7 1 £ 4-T "5
• 1 o f i c *L 3
0.2577E*07
0.^2596*04
0 . 1 252E *04
0.3843E+03
0.411ZE*n4
0 ,95736+04
0.0
IB/Hd
GP1
u
I
(continued)
-------
TABLE D-l (continued)
POND DESIGN
OPTIMIZED TO MINIMIZE TOTAL COST PLUS OVERHEAD
POND DIMENSIONS
O
I
DEPTH DF POND 24.41 FT
OEPTH OF EXCAVATION 4.0t> FT
LENGTH OF DIVIDER DIKE Z833, FT
LENGTH OF POND PERIMETER DIKE 15S37. FT
LENGTH OF POND PERIMETER FENCE 1S572. FT
SURFACE AREA OF BOTTOM 1497. THOUSAND YD2
SURFACE AREA OF INSIDE WALLS 174. THOUSAND YD2
SURFACE AREA OF OUTSIDE WALLS 133. THOUSAND YD2
SURFACE AREA OF RECLAIM STORAGE 131, THOUSAND YD2
LAND AREA nF POND 1659, THOUSAND YD2
LA'»D AREA OF POND SITE 2037, THOUSAND Y02
LA'iD AREA UF PUND SITE 421. ACRES
VOLUME DF EXCAVATION 2193, THOUSAND YD3
VOLUME DF RECLAIM STORAGE 908. THOUSAND YD3
VOLUME OF SLUDGE TO BE 12900. THOUSAND YD3
DISPOSED OVER LIFE OF PLANT 7996. ACRE FT
POKD COSTS (THOUSANDS DF DOLLARS!
LABOR
MATERIAL TOTAL
CLEARING LAND
EXCAVATION
HIKE CONSTRUCTION
LI JINGI 12. IN. CLAY)
SODDING DIKE WALLS
ROAD CONSTRUCTION
PERIMETER COSTS/ FENCE
RECLAMATION EXPENSE
MONITOR WELLS
SUBTOTAL DIRECT
TAX AND FREIGHT
POND CONSTRUCTION
LAND COST
POND SITE
OVERHEAD
TOTAL
823,
6576,
3350.
2647,
194.
35.
83.
1200,
4,
14920.
14920,
122.
10.
166,
4.
302,
23,
325,
823.
6576,
3350.
2647.
316.
46.
249,
1208,
8.
15222.
23,
15245,
2104,
17349,
7242,
24591.
(continued)
-------
TABLE D-l (continued)
BASE MANUAL
CASE 1
WPSUL CONTENT (X)I
ASH CONTENT (X)I
BTU RATINGl
BOILER TYPEl
ND. OF SCRUBBERSi
SCRUBBER VELOCITY (FT/MJI
PLANT SIZE (MW)i
OPERATING HRS/YRI
PUMPING RATE (SAL/1000 ACFM
SCA RATIOI
(ACTUAL SQ.FT./CALC. SO.FT.)
PARTICULATE REMOVAL
3.36
15.10
11700
DRY PULVERIZED COAL
4
600,0
300
5500
0.0
1.100
INVESTMENT AND OPERATING COST
PARTICULATE EMISSION REGULATION UB ASH/MILLION BTU)I 0,06
FLUE GAS TEMPERATURE (COLD)
-------
TABLE D-l (continued)
f-i.. -iTERIAL HANTLllS A^D PREPARATION
I'.CLUflNG 2 [VERATI\G AN'< 1 5P4RE PREPARATION UNITS
ITC.'1 DESCRIPTION NO. MATERIAL LAuOx
U
I
I—1
C»
CAR S'A'>I i& I..CLINF RHT
20HP SHAKEK 7.5HP HOIST
25HP PULLER. ^HP RETURN
16FT DIA< 10fT STrtAIGHT
I'iCLjDES b I' S3 GRATING
2JFT HDRIZUJTAL/ 5HP
310FT, 50HP
U'lLJA, I G PIT MIST C.)LLKTnk "
Ur.L~A>I.G PIT SJMP PU.'IP
STORAGE 3ELT C I'.VfcYuR
STORAGE CUf'VFYr'k TRIPPEa
MLIBILT KllJIPi't .T
RECLAIM HflFPEH
RcCLAI" VIBRATING F6EOEK
RECLAIM BELT CC1NVEYJR
RECLAIM I-JCLINF BELT ccr VEYJR
RECLAIM PIT DUST COLLECTHR
RtCLAIM PIT SU'P PU P
RLClAI"' Bl.CKtlT ^LtViTUi,
OLYPROPYLENE 8AGTYPE,
I'lCt 'DES JUST M3DD
hOGPi < 7CFT HtAO, 5HP
20'^FT. 5HP
30FP-J IMP
SCRAPPER
••'IDE BOTT3M, CS
3.5HP
20.TFT. 5HP
2FT
PJLYPKDPYLE-IE HAG TYPE
oOf.P". 70FT ., t.T, i.,11
TOFT nijM, ?s.,t'
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
1
71916.
63u50.
15508.
5466.
11440.
85295.
11186.
2415.
73092.
27203.
141862,
2415,
10932.
40931,
60253,
7754,
2415,
5^3-J,
13037,
19555,
593,..
521.
1434.
4B24.
5213.
3911,
912t>,
1630.
1043.
2B6o.
365*.
2607.
(continued)
-------
TABLE D-l (continued)
I
I—'
vO
FEED BELT CONVEYOR
FEEO CONVtYUR TRIPPER
FEEO BIN
BIN WFII.H FEEDER
GVRATHRY CRUSHERS
BALL HILL OUST COLLECTORS
BALL -'UL
MILLS PRODUCT TANK
MILLS PRODUCT TANK AGITATOR
MILLS PRUOL'CT TANK iLURRY
PUMP
SLU»RY FEED TA''K
SLURRY FEED TAI-'K AGITATDR
SLURRY FEED TANK PUMPS
TUTAL ECUIP.IFNT COST
60.PT HORIZONTAL 7.3HP
30 FPM, HP
13FT DIA. 21FT STRAIGHT
SIDE HTj COVERED/ CS
UFT PULLEY CENTERS. ZHP
73HP
POLYPROPYLENE BAG TYPE
2200 CFM> 7.5HP
793.HP
!500 GAL 10FT OIA. 10FT
HT. FLAKE3LASS LINED CS
10HP
59.GPM. 60FT >HEADj
2.HP. 2 OPERATING
A.JO 1 SPARES
61977.GAL. 21.9FT DIA/
21.9FT HT/ FLA
-------
TABLE D-l (continued)
SCRUBBINS
INCLUDING 4 OPERATING AND 1 SPARE SCRUBBING TRAINS
ITEM DESCRIPTION NO. MATERIAL LABOR
KJ
o
I.D. PANS
SHELL
RUBBER LINING
MIST ELIMINATOR
SLURRY HEADER AMD NOZZLES
TOTAL SPRAY SCRUBBER COSTS
REHEATEkS
SUOTBL01.ERS
EFFLUFNT HOLD TANK
7.3IN H20» WITH 631.
HP MOTOR AND DRIVE
5 33*1982.
58581.
EFFLUFNT HOLD TANK AGITATOR
COOLING SPRAY PUMPS
ABSORBER RECYCLE PUMPS
MAKEUP WATER PUMPS
TOTAL EOUIPMENT COST
40 AIR-FIXED
ZO AIR-RETRACTABLE
3*3449.GAL/ 38.8FT DIA/
38.8FT HT/ FLAKEGLASS-
LINED CS
82.HP
13B8.GPM 10DFT HEAD,
64,HP/ I. OPERATING
AND 6 SPARE
13611.GPM» 100FT HEAD/
723.HP/ 8 OPERATING
AND 7 SPARE
s
s
0
1769029.
1766838.
393830,
853239.
4782970,
264770*.
29*910.
449605,
168446,
182312.
10
3469.GPMi 200,FT HEAD/ 2
292.HP/ 1 OPERATING
AND 1 SPARE
373173. 301319,
5058*9.
10*732,
33169,
207312.
32268,
13 1561896, 139397.
37*2.
1366637*. 13*3578,
(continued)
-------
TABLE D-l (continued)
HASTE DISPOSAL
ITEM
DESCRIPTION
NO. MATERIAL
LABOR
a
I
ABS3RRER BLEED RECEIVING
T4N<
ABSORBER BLEED TANK AGITATOR
POND FEED SLURPY PU''PS
POND SUPERNATt PUMPS
TC1TAL EQUIPMENT COST
85766. GAL/ 19.4FT OIA<
38.8FT HT/ FLA«GLASS-
LINEO CS
47. HP
845.GPM. 130.FT HEAD
Sl.HPj 1 OPERATING
AMD 1 SPARE
*83.GPM» 192.FT
39.HPj I OPERATING
AND 1 SPARE
Z9716.
34390.
18550.
12053,
24569.
2821,
5195.
136C.
94708.
33946,
(continued)
-------
TABLE D-l (continued)
STARTUP
PROJECTED CAPITAL INVESTMENT REOUIREMENTS - BASE MANUAL
INVESTMENT* THOUSANDS OF 1982 DOLLARS
O
1
ho
to
EQUIPMENT
MATERIAL
LABOR
PIPING
MATERIAL
LABOR
DUCTWORK
MATERIAL
LABOR
FQUNOATIUNS
MATERIAL
LABOR
STRUCTURAL
MATERIAL
LABOR
ELECTRICAL
MATERIAL
LABOR
INSTRUMENTATION
MATERIAL
LABOR
BUILDINGS
MATERIAL
LABOR
SALES TAX ( 4.0 X) AND FREIGHT ( 3,5 * )
TOTAL PROCESS CAPITAL
SERVICES AND MISCELLANEOUS < 6,0 X)
TOTAL DIRECT PROCESS INVESTMENT
POND CONSTRUCTION MATERIAL
POND CONSTRUCTION LABOR
POND SALES TAX ( 4.0 X) AND FREIGHT ( 3.5 X!
TOTAL DIRECT POND INVESTMENT
TOTAL DIRECT INVESTMENT
ENGINEfRING DESIGN AND SUPERVISION I 7.0 X)
ARCHITECT AND ENGINEERING CONTRACTOR ( 2,0 X)
CONSTRUCTION EXPENSES (16,0 XI
CONTRACTOR FEES ( 5,0 X)
CONTINGENCY (10,0 X)
POND 1ND1RECTS ( 2.0,1 1,0; 8.0* 3.0* 10, D X)
SUBTOTAL FIXED INVESTMENT
STARTUP C. MODIFICATION ALLOWANCE I 8.0, 3,0 *)
INTEREST DURING CONSTRUCTION 115, 6 X)
ROYALTIES ( 0.0 X)
LAND
WORKING CAPITAL
RAW MATERIAL
PREPARATION
3049.
307.
416.
192,
0.
0.
341,
883.
196.
142,
262.
757.
146.
22.
147,
163,
342.
7366,
442.
7808.
0,
0.
0.
0.
7808.
547.
156.
1249.
390,
1015.
0,
11165,
893.
1742.
0.
10,
418.
SCRUBBING
13666.
1544.
5152.
918.
3042.
2723.
172.
37*.
37Z.
648.
813.
1567,
814.
131,
0.
0.
1802.
33740.
2024.
35764.
0.
0.
0.
0.
35764.
2504.
715.
9722.
1788.
4649.
0.
51143,
4091,
7978,
0,
4.
1917,
WASTE
DISPOSAL
95.
34,
1058,
352,
0.
0.
20,
42,
2.
3.
146,
318.
13.
9.
o.
0.
100,
2192,
132,
2324,
302,
14920,
23,
15245,
17569,
163,
46,
372.
116,
302.
4208,
22775,
266,
3553,
0,
2116,
»*2,
TOTAL
16810,
1884,
6627,
146U
3042,
2723.
534.
1299.
570.
794.
1221.
2641,
975.
162.
147.
163,
2244,
43298.
2598.
45896,
302.
14920,
23,
15245,
61141,
3213,
918,
73*3.
2295.
5966,
420».
850(3,
5250,
13273,
0,
2130,
3277,
CASE
DISTRIBUTION
DOLLARS
PER KW
33.62
3.77
13.25
2.92
6.08
3.45
1.07
2.60
1.14
1.59
2.44
5.28
1.93
0.32
0.29
0.33
4.49
86.60
3.20
91.79
0.60
29.84
0,05
30.49
122.26
6.43
1.84
14.69
4.J9
11.93
8.42
170.17
10.50
26.33
0.0
4.26
6,53
.--t-— -..-.-.-
TOTAL CAPITAL INVESTMENT
14229. 65133. 29632,
(continued)
109014,
218.03
-------
TABLE D-l (continued)
TENNESSEE VALLEY AUTHORITY
SHAkHEE LIMESTONE OR LIME SCRUBBING PROCESS
COMPUTERIZED DESIGN-COST ESTIMATE MODEL
REVISION DATE DECEMBER 10/ 1980
MESSAGE FILE
BASE MANUAL
CASE
O
K3
(continued)
-------
TABLE D-l (continued)
LIMESTuNfc SLURRY PROCESS -- BASISl 500 1H SCRUBBING UNIT - 500 MW GENERATING UNIT; 1984 STARTUP
PROJECTED REVENUE REQUIREMENTS • BASE MANUAL
DISPLAY SHEET FDR YEAR* 1
ANNUAL OPERATION KW-HR/KW > 5500
34,89 TONS PE* HOUR DRY
TOTAL CAPITAL INVESTMENT 109013000
CASE 1
O
Isi
DIRECT COSTS
RAW MATERIAL
LIMESTONE
SUBTOTAL RAW MATERIAL
CONVERSION COSTS
ANNUAL QUANTITY
153.4 K TONS
UNIT COST/t
8.50/TDN
SLUDGE
TOTAL
ANNUAL
COST,*
1304000
1304000
OPERATING LABOR AND
SUPERVISIUN 30680.0 MAN-HR 15,00/MAN-HR
UTILITIES
STEAM 546160.0 K LB 2,50/K LB
PROCESS WATER 259930.0 K GAL 0,14/K GAL
ELECTRICITY 47526160.0 KWH 0.037/KWH
MAINTENANCE
LABOR AND MATERIAL
ANALYSES 4940.0 HR 21.00/HR
SUBTOTAL CONVERSION COSTS
SUBTOTAL DIRECT COSTS
INDIRECT COSTS
OVERHEADS
PLANT AND ADMINISTRATIVE ( 60.0* OF CONVERSION COSTS LESS UTILITIES)
FIRST YEAR OPERATING AND MAINTENANCE COSTS
LEVELIZED CAPITAL CHARGESl 14.70* OF TOTAL CAPITAL INVESTMENT)
FIRST YEAR ANNUAL REVENUE REQUIREMENTS
EQUIVALENT FIRST YEAR UNIT REVENUE REQUIREMENTS* MILLS/KWH (MW SCRUBBED)
LEVELIZED OPERATING AND MAINTENANCE ( 1,886 TIMES FIRST YEAR OPER. C MAIN.)
LEVELIZEO CAPITAL CHARGES! 14.70* DF TOTAL CAPITAL INVESTMENT)
LEVELIZED ANNUAL REVENUE REQUIREMENTS
EQUIVALENT LEVELIZED UNIT REVENUE REQUIREMENTS, MILLS/KMH (MW SCRUBBED)
460200
1365400
36400
1758500
4130100
103800
7854400
9158400
2816500
11974900
16025000
27999900
10,18
22584700
16025000
38609700
14,04
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/8-81-008
2.
3. RECIPIENT'S ACCESSION" NO.
4. TITLE AND SUBTITLE
Computerized Shawnee Lime/Limestone Scrubbing
Model Users Manual
5. REPORT DATE
March 1981
6. PERFORMING ORGANIZATION CODE
7. AUTHORIS)
W. L. Anders and R. L. Torstrick
8. PERFORMING ORGANIZATION REPORT NO.
TVA/OP/EDT-81/15
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Office of Power
Division of Energy Demonstrations and Technology
Muscle Shoals, Alabama 35660
10. PROGRAM ELEMENT NO.
CAAN1D
11. CONTRACT/GRANT NO.
EPA-IAG-79-D-X0511
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Users Manual; 1979-80
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES IERL-RTP project officer is Michael A. Maxwell, Mail Drop 61,
919/541-2578. This manual supplements EPA-600/7-79-210.
16. ABSTRACT
The manual gives a general description of a computerized model for esti-
mating design and cost of lime or limestone scrubber systems for flue gas desulfur-
ization (FGD). It supplements EPA-600/7-79-210 by extending the number of scrub-
ber options which can be evaluated. It includes spray tower and venturi/spray-tower
absorbers, forced oxidation systems, systems with absorber loop additives (MgO or
adipic acid), revised design and economic premises, and other changes reflecting
process improvements and variations. It describes all inputs and outputs, along with
detailed procedures for using the model and all its options. The model is based on
prototype scrubber data from the EPA/Shawnee test facility and should be useful to
utility companies, as well as to architectural and engineering contractors who are
involved in selecting and designing FGD facilities. As key features, the model pro-
vides estimates of capital investment and operating revenue requirements. It also
provides a material balance, equipment list, and a breakdown of costs by processing
areas. The primary uses of the model are to project comparative economics of lime
and limestone FGD processes and to evaluate system alternatives prior to the devel-
opment of a detailed design.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Pollution
Desulfurization
Gas Scrubbing
Flue Gases
Calcium Oxides
Calcium Carbonates
Mathematical Models
Engineering Costs
Material Balance
Equipment
Industrial Processes
Pollution Control
Stationary Sources
13B
07A,07D
13H
21B
07B
12A
14A
14G
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
195
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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